Ikelic - Alliance Digital Repository

OIL SHALE
COAL
OIL SANDS
NATURAL GAS
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e siirior
VOLUME 2 NUMBER 1
quarterly
J.E. SINOR CONSULTANTS INC.
SHELF
Ikelic "Ttiels
JANUARY 1995
HErO Repository
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OIL SHALE
COAL
OIL SANDS
NATURAL GAS
tLe simor
synItkeltic
report
1 meis
VOLUME 2 NUMBER 1 JANUARY 1995
quarterly
J.E. SINOR CONSULTANTS INC.

THE SINOR SYNTHETIC FUELS REPORT is published by J.E. Sinor
Consultants Inc. as a multi-client service and is intended for the sole use
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THETIC FUELS REPORT is protected by the copyright laws of the United
States. No part of the report may be copied, stored in an electronic data
retrieval system, or transmitted to third parties unless expressly
authorized by J.E. Sinor Consultants Inc.
We welcome your comments concerning THE SINOR SYNTHETIC
FUELS REPORT.
J. E. Sinor Consultants Inc. has provided alternative energy consulting
and reporting services since 1985. The company's experience includes
resource evaluation, process development and design,
tions, expert witness testimony, marketing studies,
ning, and economic analysis.
technical evalua
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80544, (303) 652 2632.

CONTENTS
HIGHLIGHTS A-l
ENERGY POLICY AND FORECASTS
ECONOMICS
TECHNOLOGY
ENVIRONMENT
Alternative Fuels Will be Needed Says MITRE
I. GENERAL
Two Different Futures For Oil and Alternative Fuels Described
Clean-Air Rules May Cause Gasoline Imports to Rise Sharply By 2000
Fischer-Tropsch Derived Transportation Fuels Would Have High Market Value 1-5
MTCI Indirect Gasifier Suited for Both IGCC and Chemicals Production 1-8
Vermont Biomass Gasifier Will Use Battelle Design 1-12
Carbon Dioxide Enrichment Not Always Beneficial to Plants 1-14
COMING EVENTS 1-17
PROJECT ACTIVITIES
II. OIL SHALE
SPP/CPM Continue Negotiations for Financing of Stuart Project 2-1
LLNL Converts Oil Shale Retort for Waste Treatment Studies 2-2
Studies Under Way on Cocombustion of Oil Shale and Municipal Waste 2-5
CORPORATIONS
ECONOMICS
TECHNOLOGY
Sodium Bicarbonate From Oil Shale Attracts Attention 2-7
LLNL Finds Enhanced Economics Possible for Small-Scale Plant 2-8
KENTORT Runs Illustrate Retort Scaleup Problems 2-9
Nitrogen Compounds Removed From Shale Oil By Adsorption on Zeolite 2-12
GE Patents Radio Frequency In Situ Recovery Method 2-15
IGT Patents Oil Shale Pretreating Process 2-17
1-1
1-3
1-5
SYNTHETIC FUELS REPORT, JANUARY 1995

INTERNATIONAL
Oil Shale to Play Role in Israel's Energy Balance
Oil Shales of Morocco are Subject of Doctoral Thesis
STATUS OF OIL SHALE PROJECTS 2-25
INDEX OF COMPANY INTERESTS 2-41
PROJECT ACTIVITIES
CORPORATIONS
GOVERNMENT
III. OIL SANDS
Amoco Primrose Lake Project Gets Green Light 3-1
Suncor Announces Production Record and Big New Expansion Plans 3-1
Syncrude Improvement Project Approved 3-2
Crown Energy Plans Oil Sands Plant in Utah 3-7
Solv-Ex and United Tri-Star Resources Team Up
3-8
Murphy Oil Sees Favorable Prospects For Canadian Heavy Oil and Oil Sands 3-8
Oil Sands Orders and Approvals Listed 3-8
ENERGY POLICY AND FORECASTS
TECHNOLOGY
Bitumen From Tar Sands Seen as Hydrocarbon for the 21st Century
Combined HSC ROSE Process Offers New Route for Upgrading Heavy Feedstocks 3-14
Production Problems in Cold Lake Shaley Oil Sands Analyzed 3-16
INTERNATIONAL
Interest Building in China's Tar Sands 3-18
Natural Bitumens of Timan-Pechora Province in Russia Show Promise 3-19
Prospecting for Bitumen in Mongolia Could be Profitable 3-21
Environmental Problems Seen for Bitumen Deposits of Tatarstan 3-21
Fourteen In Situ Combustion Projects Active Worldwide 3-22
Venezuela In Situ Combustion Projects Reviewed 3-26
In Situ Combustion Experience in Romania Reaches 30 Years 3-29
STATUS OF OIL SANDS PROJECTS
INDEX OF COMPANY INTERESTS
2-19
2-21
3-10
3-33
3-59
SYNTHETIC FUELS REPORT, JANUARY 1995

PROJECT ACTIVITIES
IV. COAL
Point of Ayr Liquefaction Plant Beginning Tenth Run
4-1
ENCOAL Plant Enters Production Stage
Buggenum Startup Detailed
NEDOL 150 Ton/Day Liquefaction Pilot Plant to be Completed in 1996
4-5
Construction Begins on TECO's Polk IGCC Plant
CORPORATIONS
GOVERNMENT
Final EIS Issued for Pinon Pine Project
Rosebud SynCoal Considers Commercial Ventures
DGC Continues Byproducts Development at Great Plains Plant
Sasol Made Major Moves Into Chemicals in 1994
IGT Notes Progress in Coal Conversion Technologies
DOE Issues Request for Expressions of Interest in Disseminating CCTs
ENERGY POLICY AND FORECASTS
TECHNOLOGY
China Seen as Major Market for Clean Coal Technologies 4-22
IEA Survey Reveals Industry
Caution on Clean Coal Technologies 4-23
Co-Gasification of Wastes and Coal Addressed by EC Research 4-25
Fossil Resin is a Potential Value-Added Product from Western U.S. Coals 4-28
INTERNATIONAL
ENVIRONMENT
British Gas/Osaka Gas Hydrogenator Ready for Scaleup
Russian/Czech Coal Gasification Technology Looking for a Buyer 4-32
U.S./Russia Joint IGCC Project Possible 4-32
Lignite Gasification Project Planned for India 4-32
Coal Gasification Projects Increase in China 4-32
Three-Ton/Day Gasifier Test Unit Under Construction in South Korea 4-34
HYCOL Pilot Plant Completes Operations 4-35
National Coal Association Addresses Issue of Sustainable Development 4-38
IEA Greenhouse Gas Program Computes Cost of Carbon Dioxide Capture 4-39
Manufactured Gas Plant Site Remediation Draws Variety of Solutions 4-42
STATUS OF COAL PROJECTS 4-47
INDEX OF COMPANY INTERESTS 4-93
iii
4-1
4-3
4-7
4-8
4-1 1
4-15
4-16
4-18
4-20
4-30
SYNTHETIC FUELS REPORT. JANUARY 1995

project AcnvrriES
Shell MDS Product Qualities Exceed Expectations
V. NATURAL GAS
American Methanol Building New Methanol Plant in Wyoming ~
Taiwanese May Invest in Mossgas Complex
CORPORATIONS
GOVERNMENT
TECHNOLOGY
RESOURCE
Rentech Raises Money to Help Development Efforts
New Zealand Reforms Affect Synfuel Plant
BNL Liquid Phase Methanol Synthesis Found Promising
Sulfur Processing Provides New Route for Natural Gas to Gasoline
Fullerenes Catalyze Methane Conversion to Higher Hydrocarbons
Potential Seen for 25 Percent Increase in Natural Gas Reserves 5-9
STATUS OF NATURAL GAS PROJECTS
iv
5-1
5-3
5-3
5-4
5-4
5-5
5-7
5-7
5-1 1
SYNTHETIC FUELS REPORT, JANUARY 1995

HIGHLIGHTS
Capsule Summaries of the More Significant Articles in this Issue
KENTORT Runs Illustrate Retort Sealeu p Problems
Experimental results from the first runs of the KENTORT II Process Demonstration Unit (PDU)
are discussed on page 2-9. In comparison to laboratory-scale experiments,
the PDU, the reason for which appears to be increased secondary oil-loss reactions.
Oil Shale to Play Role in Israel's Energy Balance
oil yields were lower for
An overview of the history, reserves, properties and research status of the oil shales of Israel is
given on page 2-19. It is speculated that by the year 2000 some 22 percent of Israel's alternative
and indigenous domestic energy production will be from oil shales.
LLNL Converts Oil Shale Retort for Waste Treatment Studies
The Hot-Recycled-Solid (HRS) retorting process, developed by LLNL for processing oil shale, is
now being adapted for potential applications in decomposing or treating harmful chemicals and
compounds in hazardous liquid waste, sludges and contaminated soils. As discussed on page 2-2,
specific applications include using the HRS process with hot ceramic spheres to decompose
sodium nitrate and destroy liquid gun propellant.
Nitrogen Compounds Removed From Shale Oil By
Adsorption on Zeolite
A new approach to removing organic nitrogen compounds from shale oil using ultrastable zeolite-
Y (US-Y)
for adsorption is described on page 2-12. Data is presented on the percentage uptake of
different nitrogen compounds versus zeolite dose, revealing the compound's respective adsorption
affinities.
LLNL Finds Enhanced Economics Possible for Small-Scale Plant
Economic projections for a 10,000 barrel per day and 50,000 barrel per day
commercial Hot-
Recycle-Solid retort operation have been made by Lawrence Livermore National Laboratory and
are presented on page 2-8. A breakdown of cost and revenue items on a per capacity basis is dis
cussed for both sizes of plants.
Oil Shales of Morocco Are Subject of Doctoral Thesis
Data on the oil shale deposits of Morocco are given on page 2-21. Included are geological settings
of deposits, estimates of recoverable reserves of oil and their response to different retorting tech
niques.
Suncor Announces Production Record and Big
New Expansion Plans
Suncor Inc. has reported a production record for its oil sands operations over the first 9 months of
1994. Earnings are reported up in 1994 for the Oil Sands Group and major expansion plans have
been announced for the oil sands operations. See details on page 3-1.
A-l

Amoco Primrose Lake Project Gets Green Light
Amoco Canada Petroleum Ltd., which owns the Primrose Lake commercial project, has received
approval to proceed with the project. Maximum production rate is estimated at 50,000 barrels per
day, as noted on page 3-1.
Prospecting
for Bitumen in Mongolia Could Be Profitable
A brief look at the energy situation in Mongolia may be found on page 3-21. Information known
on bitumen sands is summarized.
Combined HSC ROSE Process Offers New Route for Upgrading Heavy Feedstocks
A description of the High conversion Soaker Cracking (HSC) process, a modern upgrading tech
nology for heavy feedstocks, is given on page 3-14. One of the highlights of the process is cokefree
operation at high conversion levels. A combination of the HSC and ROSE processes maxi
mizes the assets of the HSC process for extra high liquid yield.
Fourteen In Situ Combustion Projects Active Worldwide
A review of In Situ Combustion (ISC)
ways of applying the ISC process are discussed with a comparison of relative advantages. Horizon
tal well assisted ISC is also reviewed. World incremental daily oil production due to ISC processes
in 1992 was 32,000 barrels of oil per day.
Syncrude Improvement Project Approved
projects around the world is given on page 3-22. Different
Syncrude Canada Ltd. has received approval from ERCB for an expansion/improvement project
of the Mildred Lake Oil Sands Plant that will allow increased synthetic crude oil production, off-
lease processing and tailings reclamation. The production limit for the expansion will be
17.6 million cubic meters per year. The background of the Mildred Lake plant and details of the
expansion project, including design, bitumen supply, atmospheric emissions, health impacts,
reclamation, and socioeconomic issues, are presented on page 3-2.
Bitumen From Tar Sands Seen as Hydrocarbon for the 21st Century
It has been speculated that tar sand resources could play a major role in the next century for the
production of hydrocarbons. Worldwide resources are estimated at 3,000 billion barrels. The
potential for the development of U.S. tar sands is outlined on page 3-10.
Interest Building in China's Tar Sands
Presented on page 3-18 are data on tar sand deposits in China. Thickness, porosity, bitumen con
tent, and geological reserves are given for several deposits. Little exploration has been carried out
to date.
NEDOL 150-Ton/Day Liquefaction Pilot Plant to Be Completed in 1996
Work has begun on Japan's first coal liquefaction pilot plant. The plant will utilize the NEDOL
process. Details are on page 4-5.
A-2

HYCOL Pilot Plant Completes Operations
A review of 3 years of operating experience at the HYCOL advanced coal gasification pilot plant
in Japan is reported on page 4-35. The plant completed its operations in April 1994. A review of
the HYCOL process and its technological features is also presented.
Buggenum Startup Detailed
Operation of a 250-megawatt IGCC plant in Buggenum, The Netherlands began in early 1994.
Twenty-five gasification runs had been recorded as of August 1994. Details of the project are
given on page 4-3.
Sasol Made Major Moves Into Chemicals in 1994
Sasol is looking for chemicals from coal to contribute 50 percent of the company's profit
operating
by the end of this decade. Current and planned chemicals production is summarized on page 4-16.
National Coal Association Addresses Issue of Sustainable Development
A summary of a National Coal Association "Issue in Brief on the subject of sustainable develop
ment is presented on page 4-38. U.S. coal resources are estimated at a 250-year supply.
Fossil Resin is a Potential Value-Added Product From Western U.S. Coals
An overview of research on fossil resin is given on page 4-28. Solvent-purified resins can have a
market value of $1.00 per kilogram as a chemical commodity. New resin separation and solvent
refining technologies are being developed and tested.
ENCOAL Plant Enters Production Stage
Activities involving the LFC Process (Liquids From Coal) are described on page 4-1. The process
is currently being used in ENCOAL's Clean Coal Technology demonstration plant in Wyoming.
International applications are being sought.
Point of Ayr Liquefaction Plant Beginning
Tenth Run
Operation of the Liquid Solvent Extraction pilot plant at Point of Ayr is detailed on page 4-1. A
3,000-hour tenth run is scheduled for January 1995.
DGC Continues Byproducts Development at Great Plains Plant
Recent activities of the Dakota Gasification Company (DGC) are summarized on page 4-15.
Several new projects are under consideration or construction.
Final EIS Issued for Pinon Pine Project
The way has been cleared for construction of the Pinon Pine Power Project with the issuance of
the Final Environmental Impact Statement. Details of the environmental analysis are given on
page 4-8. A description of the Pinon Pine Project is also presented.
A-3

Construction Begins on TECO's Polk IGCC Plant
The official groundbreaking ceremony for the TECO IGCC project in Polk County, Florida was
held in November 1994. A review of the project can be found on page 4-7. The 250-megawatt
plant is expected to be in service by October 1996.
British Gas/Osaka Gas Hydrogenation Ready for Scaleup
The current status of development of a clean and flexible coal hydrogenation process, using a novel
entrained-flow reactor, is the subject of an article on page 4-30. A pilot plant has carried out six
runs; a full-size commercial plant is now being considered.
Rosebud SynCoal Considers Commercial Ventures
An overview of the Rosebud SynCoal Demonstration in Montana, which utilizes the Advanced
Coal Conversion Process, is given on page 4-11. Success in the 300,000-ton per year demonstra
tion project has led the Rosebud SynCoal partnership to look towards commercializing the
process. Low-rank coal upgraded by the process can have heating values up
pound.
China Seen as Major Market for Clean Coal Technologies
Coal prospects in China over the next 2.5 decades are discussed on page 4-22. Energy
China, in million tonnes coal equivalent, is projected at 2,375 by the year 2010.
Shell MDS Product Qualities Exceed Expectations
to 12,000 BTU per
demand in
Data on the products produced from the Shell Middle Distillate Synthesis plant in Malaysia are
reviewed on page 5-1. Quality has exceeded, in some respects,
tests.
BNL Liquid Phase Methanol Synthesis Found Promising
predictions based on pilot plant
Catalytic activities of two low-temperature methanol synthesis processes have been examined and
are outlined on page 5-5. The Brookhaven National Laboratory low-temperature methanol
process has shown a space time yield higher than conventional methanol processes.
Sulfur Processing Provides New Route for Natural Gas to Gasoline
A new synthesis route for natural gas to gasoline utilizing H^S, which is fully recycled, is being ex
plored by the Institute of Gas Technology. See page 5-7 for details.
New Zealand Reforms Affect Synfuel Plant
With the decline of the giant Maui gas/condensate field, New Zealand's Government has made
major changes in energy
page 5-4.
policy. A review of the current situation in New Zealand is provided on
A-4

ENERGY POLICY AND FORECASTS
ALTERNATIVE FUELS WILL BE NEEDED
SAYS MITRE
At the American Chemical Society's Symposium
on Alternative Routes for the Production of Fuels,
held in Washington, D.C. in August, a paper by
D. Gray et al. of the MITRE Corporation reviewed
some of the salient facts regarding alternative
fuels today.
Studies at MITRE have examined potential world
energy supply
and demand scenarios until the
year 2100. These hypothetical scenarios show
that total world energy demand increases from
the current annual use of 360 exajoules to about
1,100 exajoules by
2100. This projection as
sumes that energy conversion and end-use ef
ficiency
increase. Recoverable oil and gas
resources are assumed to be 10,000 exajoules
each, and they will be essentially depleted by
2100. According to Gray et al., this demonstrates
that after 2030 oil production will be in decline
and an alternative to petroleum-based fuels will
have to be found.
Coal as an Alternative Feedstock for
Transportation Fuels
The key to converting solid coal to liquid fuel is
hydrogen. Liquid fuels typically contain about
14 percent hydrogen whereas coal contains
around 5 percent. This hydrogen deficit can be
made up by forcing
hydrogen into the coal under
pressure (direct liquefaction), or by gasifying the
coal with oxygen and steam to a synthesis gas
hydrogen and carbon monoxide that
containing
is then passed over catalysts to form hydrocar
bons (indirect liquefaction). For direct liquefac
tion,
coai is slurried with a recycle oil and heated
under a high pressure of hydrogen to produce a
synthetic crude oil that can be upgraded into
specification transport fuels by existing
petroleum refinery processes. The hydrogen is
produced gasification of coal by and residue or
natural gas steam reforming. For indirect li
by
quefaction, the synthesis gas produced is passed
GENERAL
1-1
over Fischer-Tropsch (F-T) catalysts where a
series of hydrocarbons ranging from to about
C1
are produced. These can also be refined to
C200
produce specification liquid fuels by using mild
refinery operations.
Direct liquefaction, invented in the early
20th cen
tury by Bergius, was used extensively by the Ger
mans in World War II to produce high octane avia
tion fuel, and since that time research and
development have completely transformed the
technology. Research over the last 15 years has
led to the development of a catalytic two-stage
liquefaction process that uses two high pressure
ebullating bed reactors in series to solubilize coal
and upgrade it at an overall thermal efficiency of
about 66 percent. Liquid distillate yields of over
70 percent on a Moisture Ash-Free (MAF) coal
basis are regularly
obtained with bituminous
coals, and yields of 60 to 65 percent are usually
obtained with low-rank coals as feedstock. This
translates into oil yields of over 3.5 barrels per
tonne of MAF coal.
Indirect liquefaction technology is commercial
ized in South Africa and produces about a third
of that country's gasoline and diesel fuel. The
South African Synthetic Oil Company (SASOL)
plants produce together over 100,000 barrels per
day
of fuels. Research and development in coal
gasification has resulted in the commercialization
of highly efficient entrained gasifiers such as
Shell and Texaco. These entrained gasifiers that
have net efficiencies for synthesis gas production
of about 80 percent greatly improve the overall
efficiency, hence the economics, of indirect li
quefaction.
The other area that has led to significant improve
ments in the efficiency and economics of indirect
liquefaction is the development of advanced F-T
synthesis technology. Shell has developed ad
vanced fixed-bed reactor technology for F-T syn
thesis and is currently operating a plant in
Malaysia for the production of diesel fuel and
waxes from off-shore natural gas. SASOL has
developed an advanced Synthol reactor that
uses a fixed-fluid bed concept. SASOL has also
developed a slurry F-T reactor that promises to
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
be even more cost-effective. The United States
Department of Energy is also funding research
aimed at developing both an advanced slurry F-T
reactor system and an effective F-T catalyst to
use in the advanced reactor.
Natural Gas for Production of Liquid Fuels
As an alternative to using natural gas in its
gaseous state as a transportation fuel, it can be
converted to specification gasoline and diesel
fuel so that the existing liquid fuels infrastructure
can be utilized. This is commercialized in New
Zealand where natural gas is converted into
methanol and the methanol is converted into
gasoline using the Mobil methanol-to-gasoline
technology. Shell is converting remote natural
gas in Malaysia into liquids that can be
transported by tanker to market.
For indirect liquefaction, natural gas can be
steam reformed or partially oxidized to synthesis
gas. This gas is then processed in the same man
ner as the coal-derived synthesis gas described
above. Thus, improvements In F-T technology
are applicable to natural gas processing. In addi
tion, there have been recent advances in catalytic
partial oxidation that can produce synthesis gas
at lower cost. For direct liquefaction, natural gas
can be used as the source of hydrogen instead
of coal, so that coal is only sent to the liquefac
tion reactors. This results in elimination of the
coal gasification plant from the direct plant. In
addition, the coal handling units can be reduced
in size and the plant electric power required is
reduced. Thus, using natural gas for this applica
tion lowers capital investment of the direct coal
liquefaction plant and, depending on the cost of
the natural gas, can result in a lower required sell
price of the coal-derived transportation fuels.
ing
A sensitivity
analysis of the equivalent crude price
versus natural gas price for this case, where gas
is used to produce hydrogen in the direct coal li
quefaction plant, shows that using natural gas
can result in lower costs for coal liquids up to a
natural gas price of about $4 per million BTU
($4.22 per gigajoule). Using natural gas for
1-2
hydrogen production also has a significant posi
tive impact on the carbon dioxide produced per
product barrel. This quantity can be reduced
from about 0.42 tonnes per product barrel when
coal is used for hydrogen to 0.21 tonnes in the
natural gas case.
Quality
and Environmental Impact of
Coal-Derived Transportation Fuels
Direct coal liquefaction produces an all distillate
product that can be refined using conventional
hydrotreating, hydrocracking, fluid catalytic
cracking, and reforming to yield high octane
gasoline, high density jet fuel and 45 cetane
diesel. Indirect liquefaction produces a paraffinic
gasoline whose octane can be adjusted by
reforming or by adding octane enhancers like al
cohols or ethers. The diesel fraction is excellent,
has a cetane of over 70 and zero aromatics and
sulfur. These refined products can exceed cur
rent transportation fuel specifications and their
use will have a positive effect on air quality. The
paraffinic indirect naphtha can be blended with
the aromatic direct naphtha to minimize the
amount of refining required. Similarly, the
aromatic diesel from direct liquefaction can be
blended with the paraffinic diesel from indirect.
Thus a hybrid plant concept where both direct
and indirect technologies are sited at the same
location may have considerable merit.
Conclusion
Gray
et al. conclude that coal and natural gas
can be used as resources to produce specifica
tion liquid transportation fuels that make use of
the existing liquid fuels refining, distribution and
end-use infrastructure. Although the costs of
these fuels are higher than current crude prices,
they
can be competitive with crude oil at about
$30 to $35 per barrel. The United States Energy
Information Agency has published its latest
World Oil Price (WOP) projections. In their
reference scenario, the WOP is expected to
reach $35 per barrel by the year 2015.
####
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
TWO DIFFERENT FUTURES FOR OIL AND
ALTERNATIVE FUELS DESCRIBED
Royal Dutch/Shell's P. Kassler reminded last
fall's "Oil and Money"
conference that the 1980s
were a period of profound, even revolutionary
change in many parts of the world. The end of
the cold war and the disintegration of the Soviet
Union has created entirely new relationships all
over the world. Political liberalization has
resulted in free elections and civilian govern
ments in much of Latin America, parts of East
Asia and in South Africa.
Equally
profound changes have occurred in the
world of economies and markets. Liberalization
of markets, to varying degrees, is now being
adopted as the received economic wisdom al
most everywhere and has become the basis of
economic policies.
Kassler points out that these major political and
economic reforms are going on against a back
ground of an inexorably increasing
world popula
tion and growing concern for the environment,
both of which will strongly influence the future
demand for oil.
Shell companies have developed two alternative
scenarios as to how the world could respond to
these global reforms. Some will see liberalization
as providing promising opportunities leading to
success and rewards which in turn will reinforce
the process--a "New Frontier"
scenario. Others
will see it as a threat to their position and will
resist It a "Barricades"
In "New Frontiers,"
scenario.
liberalization continues and
spreads as many seize the considerable oppor
tunities to be taken. Economic and political
reforms are expected to work, in the sense of
improving
societies'
ability
to create wealth for
their members. Fast economic growth is sus
tained in the developing countries. As a result,
business is stretched in an environment of relent
less competition and innovation. To fuel this
growth, the demand for energy is high.
1-3
In "Barricades,"
liberalization is resisted and
restricted because people fear they might lose
what they value most-jobs, power, autonomy,
religious traditions and cultural identities. This
creates a world of regional, economic, cultural
and religious division, in which international
businesses cannot so easily operate. A new
crisis in the Middle East gives governments the
opportunity to implement drastic and irreversible
measures, heavily taxing and regulating the use
of energy.
World Population and GDP per Head
The difference in economic growth patterns be
tween these two scenarios leads, by 2020, to two
very
different pictures of the world when ex
pressed in gross domestic product per head.
In "New Frontiers,"
liberalization leads to growth
rates of 5-6 percent in non-OECD countries,
similar to those of the 1960s. By 2020, more than
half of the world's population enjoy "middle"
comes. As a result of this wider economic
development and better education, population
growth begins to slow down.
By contrast, under "Barricades,"
the economic
growth rate in developing countries remains at
some 3 percent per year, similar to the 1980s. By
2020, almost 90 percent of the world population-
some 8 billion people by then-have low incomes,
and restricted access to basic amenities (clean
water, electricity, etc.) while the remaining
10 percent is split evenly between middle and
high income groups.
World Energy Consumption 1960-2020
For developing countries, the difference in the
rate of economic development leads to contrast
ing energy demand between "Barricades"
"New Frontiers."
in
and
In the latter scenario, by 2020,
developing countries in Southeast Asia, including
China, will have reached similar per capita levels
of energy use to that of Italy in 1960. In spite of
the improvements in energy efficiency which are
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
assumed to occur, the supply challenge to satisfy
this demand is considerable.
In "Barricades,"
governments are faced with
acute energy problems, particularly after the oil
shock. Different countries adopt different
policies, strongly influenced by their domestic
resources. Everywhere demand reduction is an
important policy objective and regulation is the
preferred instrument because it is quick, clear
and specifically focused. In the process,
privatization slows and eventually stops-in some
countries, privatized assets are renationalized.
"New Frontiers"
In "New Frontiers"
Oil Markets
the demand for oil continues
to grow and supplying the quantities involved will
be a formidable challenge. In this world, transpor
tation will be the main consumer of oil products-
there will be millions of new motorists in develop
ing countries enjoying the benefit of mobility and
for whom transport fuel has to be provided-and
the total demand for liquid fuels could increase
by some 40 million barrels per day to more than
100 million barrels per day by 2020.
To sustain acceptable reserves/production ratios
during the later part of this scenario, while provid
ing energy at an acceptable price, the industry
will be faced with the task of tackling the more
costly
part of its resource portfolio-frontier or
heavy oil, and conversion from gas to liquids.
This could well require a modest increase in the
oil price, says Kassler, but if prices are allowed to
rise too high the competitive position of oil fuels
will be eroded compared with alternative energy
supplies, and they will lose their place in the
market.
"Barricades"
Oil Markets
In the 1990s economic output and energy
demand in much of the "Barricades"
world will
grow at about the same rates as in the 1980s.
The net effect is that world energy demand grows
quite slowly through the 1990s. Military expendi
ture takes precedence over oil investment in the
1-4
increasingly cash-starved and insecure Gulf
producing states.
In the early years of the 21 st century, the world
passes rapidly from a situation of excessive com
placency about energy supplies to one of poten
tial danger.
In the "Barricades"
scenario, it is imagined that at
some time after 2000 one or more of the many
Middle East disputes leads to an oil crisis.
The crisis itself is probably short-lived. The oil
price shoots up over $40 per barrel briefly, but
supply
shortages can be dealt with in a few
weeks or months, given the high state of
flexibility of the world's oil industry after many
years of political uncertainty. It is, nevertheless,
another nasty shock for the oil-consuming world.
The reaction is swift and dramatic.
importingc
Energy-
countries scramble to free themselves
from dependence on imports, egged on by their
own "green"
constituencies. The response is
largely by way of regulation, such as:
- Laws
- Regulations
- Support
- Encouragement
- Higher
mandating strictly regulated energy
conservation
encouraging
vehicles
use of electric
for nuclear plant construction
of biofuel production
taxation of oil and gas fuels, espe
cially if imported
The result of these policies is that the growth of
oil (and gas) demand in OECD countries is
severely limited, and oil consumption may even
decrease. Overall oil demand does not recover,
despite the price falling back to its preshock
level, and by 2020 may be no more than three-
quarters of that under the "New Frontiers"
scenario. The "Barricades"
scenario is not good
news for international oil companies, but be-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
cause of low-demand growth, the world manages
to muddle along, says Kassler.
####
CLEAN-AIR RULES MAY CAUSE GASOLINE
IMPORTS TO RISE SHARPLY BY 2000
Under recent and evolving United States environ
mental regulations, gross gasoline imports
should reach 2 million barrels per day (bpd) by
the turn of the century, according to a study
released in September.
The study, sponsored by the Department of
Energy (DOE) and conducted by New Jersey
consultants EnSys Energy & Systems Inc., found
that U.S.
refiners'
market share of the domestic
petroleum product market should decline to
around 80 percent by 2000 from 90.4 percent in
1992.
Alternative year-2000 scenarios were applied for
U.S. and global supply and demand, based on
Energy Information Agency
forecasts. U.S. year-
2000 demand was varied from 16.75 to
20.4 million bpd, with central cases based on
18.5 million bpd. Other primary sensitivities in
cluded: quality and penetration of reformulated
fuels in the U.S., United States and world regional
costs for new refinery process investments,
crude and product shipping rates. The study gen
erated a range of insights into the potential shape
of the U.S. and world regional petroleum supply
industry.
A central insight was that U.S. environmental
refiners'
regulations-particulariy those impacting
facilities costs and mandating reformulated
gasoline-will have far-reaching international ef
fects on market economics, refining and trade
patterns. They will affect the balance of U.S. and
foreign refining investment and-together with
other clean fuels mandates in the U.S. and
elsewhere-will alter the structure of international
petroleum product marginal costs and prices.
Foreign refiners are likely to have cost ad
vantages relative to U.S. refiners. Continuing
1-5
loss of domestic crude production will also ex
acerbate U.S.
refiners'
competitive position.
Associated with the decline in U.S.
refiners'
market share, there is a projected rise in product
import dependency, from 1.5 million bpd net in
1989 to 2.5 to 3 million bpd net in 2000. Product
import-export patterns are projected to become
more complex. Assuming
no major U.S. port
constraints, gross finished and unfinished
product imports are projected to rise to over
4 million bpd, partially offset by a 1 million bpd
increase to 1.7 million bpd in product exports.
Imports will comprise mainly high-quality fuels,
notably reformulated gasoline, U.S. "regulated"
conventional gasoline, jet fuel/ultra-low-sulfur
diesel and low-sulfur residual fuels. Exports will
consist principally
of medium to lower grade
gasolines, distillates and residual fuels. Most of
the changes versus today will surround gasoline.
Gross imports of this product could approach or
exceed 2 million bpd and exports 400,000 bpd.
Crude oil imports are projected to increase by
close to 2 million bpd to over 8 million bpd total.
Dependency
on Persian Gulf crudes could rise
sharply, to 4 million bpd (from 1 .68 million bpd in
1992).
Overall, U.S. dependency on foreign sources of
crude and product are both projected to increase
by 2000.
####
ECONOMICS
FISCHER-TROPSCH DERIVED
TRANSPORTATION FUELS WOULD HAVE
HIGH MARKET VALUE
The Clean Air Act Amendments (CAAA) of 1990
have placed stringent requirements on the quality
of transportation fuels. Petroleum refiners have
to meet new fuel composition provisions of the
Amendments to be implemented between 1995
and 2000. These requirements will also have sig-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
nfflcant implications for any production of alterna
tive fuels. These implications were examined for
Fischer-Tropsch (F-T) derived fuels in a paper by
J. Marano et al. presented at the American Chemi
cal Society National Meeting in Washington, D.C.
In August.
This analysis was conducted in conjunction with
the United States Department of Energy (DOE)
sponsored project, Baseline Design/Economics
for Advanced Fischer-Tropsch Technology, con
ducted by Bechtel and Amoco. The goal of this
study was to develop a baseline design for in
direct liquefaction of Illinois No. 6 coal using
gasification, syngas conversion in slurry reactors
with iron catalysts, and conventional refinery
of the F-T derived hydrocarbon li
upgrading
quids.
To perform economic analyses for the different
design cases, the products from the liquefaction
plant had to be valued relative to conventional
transportation fuels. This task was accomplished
by developing a Linear Programming (LP) model
for a typical midwest refinery, and then feeding
the F-T liquids to the refinery. The breakeven
value determined for these materials is indicative
of the price they could command if available in
the marketplace.
The model was set up to be representative of con
ditions anticipated for the turn of the century.
CAAA Fuel Specifications
The ultimate goal of the CAAA fuels program is
the reduction of gasoline vehicle emissions, in
cluding volatility, toxicity, and to below
NOx
1990 levels. These reduction goals are to be
phased-in between 1995 and the year 2000 under
the federal Phase II reformulation program.
In addition to the federally mandated programs,
California Air Resources Board (CARB), has
promulgated Its own Phase I and Phase II
programs. In general, the requirements of the
CARB programs are more strict than the federal
programs. Fuels marketed in California will need
1-6
to satisfy both the federal and CARB require
ments.
LP Modeling
The crude capacity of the typical midwest
refinery was set at 150.000 barrels per day for
this study. A composite crude with an API
gravity
of 32.9
and total sulfur content of
1 .30 weight percent was used as the basis for the
comparisons with F-T liquids. These properties
were projected by extrapolating historical crude
quality trends. The crude oil was given a nominal
price of $18 per barrel.
F-T Product Description
In the baseline design, conventional upgrading of
F-T liquids produces about 1 barrel of gasoline
for every barrel of diesel. The components of the
gasoline are alkylate, isomerate and reformate.
These materials are essentially equivalent to their
petroleum counterparts produced in a typical
refinery. All of the gasoline blending components
have zero sulfur and olefins,
which is of con
siderable benefit when manufacturing CAAA man
dated fuels.
Diesel produced from conventional upgrading of
F-T products consists of hydrotreated straight-
run distillate blended with distillate from wax
hydrocracking. The F-T diesel has rather unique
properties relative to petroleum-derived diesels.
It is sulfur free, almost completely paraffinic, and
has an extremely high cetane rating.
The alternative upgrading case using ZSM-5
produces a gasoline-to-diesel ratio of about 1 .8,
which is more typical of the U.S. transportation
fuels market. The components of the gasoline
are alkylate, ZSM-5 gasoline, and hydrocracker
gasoline.
F-T Product Valuation
The results of the product valuation are shown in
Table 1 for two different scenarios for future
transportation fuel specifications. This table
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
Crude Oil & Refinery Products1
Crude Oil
Composite Gasoline
Conventional Diesel Fuel
Low Sulfur Diesel Fuel
F-T Conventional Upgrading
F-T Gasoline Blendstocks
F-T Diesel Blendstock
Composite for Conv. Upgrading
F-T Alternative Upgrading
F-T Gasoline Blendstocks
F-T Diesel Blendstock
Composite for Alt. Upgrading
shows that the F-T derived gasolines always com
mand a premium over F-T derived diesel. Con
ventional wisdom has been that F-T derived
gasoline is of low quality and F-T diesel produc
tion is preferable to gasoline production. This
study
wrong
suggests that this conventional wisdom is
for the U.S. fuels market. There are two
explanations for this result. First, the U.S. market
is skewed toward the production of gasoline
which commands a higher price than diesel.
Second, after upgrading, F-T gasoline blending
stocks are high quality components for blending
to meet the CAAA gasoline specifications.
While the F-T gasoline from the alternative case
is of lower value due to its low octane rating, the
composite values for the gasoline and diesel are
much closer due to the higher gasoline-to-diesel
ratio for the alternative upgrading
TABLE 1
FISCHER-TROPSCH PRODUCT VALUES
(Dollars per Barrel)
case. For
Scenario II, the composite value for the alterna
1-7
Scenario Scenario II
18.00 18.00
26.00 26.70
22.70 22.70
24.80 24.80
27.02 28.07
24.90 25.19
25.95 26.61
25.62 28.17
24.91 25.19
25.36 27.10
tive upgrading case is actually higher. This is a
result of both the higher gasoline-to-diesel ratio
and the negative effect of the high aromatics con
tent of the F-T gasoline from the conventional
upgrading case.
The high cetane and zero sulfur content of the
F-T diesel blending stock was not found to have
a significant effect on its value, which was only
slightly higher than the price used for low-sulfur,
diesel. This is because the CAAA al
on-highway
ready force the refiners to invest heavily in
hydrotreating capacity both for gasoline and
diesel sulfur reduction. For these reasons, the
refinery did not receive much benefit from the
superior F-T diesel properties.
According to the authors, results from the study
indicate that F-T synthesis could be an important
technology for satisfying transportation fuel
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
needs in the next century. The potential benefits
of F-T derived fuels for meeting the environmen
tal requirements of the CAAA have been quan
tified. Further work is necessary to optimize the
production of transportation fuels from F-T syn
thesis.
####
TECHNOLOGY
MTCI INDIRECT GASIFIER SUITED FOR BOTH
IGCC AND CHEMICALS PRODUCTION
Manufacturing and Technology Conversion Inter
national, Inc. (MTCI) and ThermoChem, Inc. have
developed an indirect heated, fluid-bed steam
reformer for biomass gasification which can be
used either for Integrated Gasification Combined
Cycle (IGCC) or for methanol production. The
system was described by M. Mansour and
K. Durai-Swamy
at the 13th EPRI Conference on
Gasification Power Plants held in San Francisco,
California in October.
The MTCI process uses pulse combustion
heaters immersed in the fluidized-bed reformer
for producing medium-BTU synthesis gas (see
Figure 1). The MTCI reformer-based system
does not need a secondary hydrocarbon
reformer, converts about 10 percent more of the
feed carbon to methanol and produces about
30 percent less C02 than oxygen-blown gasrfierbased
systems. The capital and operating costs
are said to be significantly
reformer-based system.
lower for the MTCI
MTCI has tested many biomass feedstocks in its
Pilot Demonstration Unit (PDU). MTCI has a
100 ton per day pilot plant steam reformer in
operation for black liquor at a Weyerhaeuser
Paper Company pulp mill in New Bern, North
Carolina and another small commercial unit for
125 tons per day of distillery spent wash in opera
tion in India.
1-8
Biomass
FIGURE 1
MTCI INDIRECTLY HEATED
Heat Exchange
Tubes
GASIFIER
7/n r\T
Steam
t
Ash
SOURCE: MANSOUR AND DURAI-SWAMY
Gas
ThermoChem has been developing a 450- to 900-
ton per day
coal gasification project under the
Clean Coal Technology Program.
Methanol Production
Instead of burning some of the product gas in the
pulse combustor (which would be the configura
tion for power production), the heat available
from the purge gas from methanol synthesis is a
good match for the heat load of the pulse com
bustor. This lowers overall capital costs, with no
loss in fuel output. As well, due to the low
methane content of the product gas (8 percent
by volume on a dry basis), a separate secondary
reformer is not needed. In the MTCI process the
residual char and tars could be burned in the
pulse combustor to augment the heat available
from the purge gas.
Although pressurized operation is likely to be pos
sible with this gasifier (up to 1.5 MPa)
it has not
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
yet been demonstrated. MTCI is currently build
ing
a pressurized pilot-scale reactor in Santa Fe
Springs, California.
Comparisons between several different types of
biomass gasifiers are given in Table 1 .
TABLE 1
OPERATING CHARACTERISTICS OF GASIFIERS
The C02 removed is 0.75 mole per mole of
methanol produced for the MTCI Steam
Reformer compared with 1.2 moles/mole for the
Oxygen-Blown IGT gasifier. The output of
methanol from the MTCI steam reformer-based
system is about 10 percent higher than for the
Oxygen-Blown
Directlv Heated Gasifiers Indirectlv Heated Gasifiers
Bed Type Bubbling Entrained Bubbling Fast
Fluidized Fluidized Fluidized
Company IGT Shell-Bis MTCI Battelle-
Columbus
Feedstock Wood Wood Wood Wood
Inputs
Steam (kg/kg dry feed) 0.3 0.03 1.37 0.314
Oxygen (kg/kg dry feed) 0.3 0.45 0 0
Air (kg/kg dry feed) 0 0 2.10 1.46
Reactor Characteristics
Exit Temperature (C) 982 1,085 697 927
Pressure (MPa) 3.45 2.43 0.101 0.101
Throughput (dry kg/m2-s) 1.9 n/a 0.07 2.7
Solids Residence Time minutes 1 second minutes 1 second
Product Gas Characteristics
Yield (kmoi/dry tonne) 82.0 79.3 138.6 58.3
HHV (MJ/kg wet) 8.67 10.33 9.35 14.22
Gas Composition (mole %)
H20 31.8 18.4 49.5 30.8
20.8 30.7 25.3 14.6
&
15.0 39.0 11.2 32.4
CO, 23.9 11.8 9.9 7.8
CH4 8.2 0.1 4.0 10.3
V 0.3 0.2 4.2
Carbon Conversion (%) 96.2 100 83.5 80.3
Cold Gas Efficiency (%) 83.0 85.3 87.8 87.4
1-9
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
IGT oxygen-blown system based on the evalua
tion by Katofsky (1993).
The MTCI gasifier costs are also relatively low
because inexpensive material can be used at the
low peak temperatures. Furthermore, because
there is no secondary reformer and because feed
preparation costs are lower (less drying
required), the MTCI system has the lowest capital
requirements (Table 2).
IGCC Applications
For the IGCC case, the MTCI steam reformer sys
tem should be applicable for retrofitting to many
natural gas-based combined cycle power genera
tion or cogeneration facilities from small to
Conversion Technology
TABLE 2
medium sizes (1 to 50 megawatts). For example,
the MTCI steam reformer can produce medium-
BTU gas from biomass residues from a paper mill
including sludge rejects that are currently
landfilled.
Figure 2 (next page) depicts one case for IGCC
application of the MTCI steam reformer.
In future developments, MTCI anticipates pres
surized operation of the primary steam reformer
and the pulse combustor. The hot flue gas from
the pressurized pulse combustor may be sent to
a turbo-expander for power recovery. In this
way, the "topping
ESTIMATED PRODUCTION COSTS
FOR METHANOL FROM BIOMASS
Dry Tonnes per Day, Feedstock
Tonnes per Day, Methanol Output
Capital Costs (106$)
Feed Preparation
Gasifier
Oxygen Plant
Reformer Feed Compressor
Reformer, Secondary
Vesseis/Exchangers/Pumps/Filters
CO, Removal
Methanol Synthesis & Purification
Utilities/Auxiliaries
Contingencies
Start-up
Operating
and Other Costs
Costs (106
$/hr)
Variable Costs (feed, etc.)
Fixed Costs (labor, OH, etc.)
Levelized Costs ($/liter)
####
1-10
cycle"
becomes the supply of
endothermic heat of the steam-carbon reactors.
Ifil
MTCI
1,650 1,650
794 868
291.4 185.6
16.44 13.69
28.23 15.16
41.67 0.00
0.00 12.4
17.70 0.00
9.40 9.40
20.20 15.38
41.42 43.93
43.77 27.49
43.77 27.49
28.79 20.66
37.70 34.36
24.79 25.08
12.91 9.28
0.26 0.18
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
FIGURE 2
IGCC APPLICATION OF THE MTCI STEAM REFORMER
H -RICH GAS
PROCESS
STEAM
SOURCE: MANSOUR AND DURAI-SWAMY
GAS
CLEANUP
STEAM REFORMER
FIRETUBES
STEAM
TURBINE
1-11
ORGANIC
FEED
H2- RICH
FUEL GAS
WATER
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
VERMONT BIOMASS GASIFIER WILL USE
BATTELLE DESIGN
A 200-ton per day biomass gasification plant is
under construction at the McNeil generating sta
tion in Burlington, Vermont. Potential feedstocks
for the gasifier include wood waste, crop
residues, yard wastes and energy crops. The
project will be carried out in two phases. In the
first phase, a 200-ton per day gasifier based on
Battelle technology will be constructed and
operated at the McNeil site. The product gas will
be used in the existing McNeil power boilers. In
the second phase, a gas combustion turbine will
be installed to accept the product gas from the
gasifier and form an integrated combined cycle
system.
The design and development of the Battelle
biomass gasifier was described by M. Paisley of
Battelle and R. Overend of the National Renew
able Energy Laboratory at the 13th EPRI Con
ference on Gasification Power Plants, held in San
Francisco, California in October.
The development of the indirectly-heated Battelle
High Throughput Gasification Process was in
itiated in 1977. Detailed process development
activities began in 1980 with the construction and
startup of a Process Research Unit (PRU) at
Battelle's West Jefferson, Ohio Laboratory.
Process Description
The Battelle biomass gasification process
produces a medium-BTU product gas without the
need for an oxygen plant. The process
schematic in Figure 1 shows the two reactors
and their integration into the overall gasification
process. This process uses two physically
separate reactors: 1) a gasification reactor in
which the biomass is converted into a medium-
BTU gas and residual char and 2) a combustion
reactor that burns the residual char to provide
heat for gasification. Heat transfer between reac
tors is accomplished by circulating sand between
the gasifier and the combustor.
1-12
The gasification process utilizes circulating
fluidized-bed reactors to take advantage of the
inherently high reactivity of biomass feedstocks.
The reactivity of biomass is such that through
puts in excess of 3,000 pounds per hour per
square foot can be achieved. In other gasifica
tion systems throughput is generally limited to
less than 200 pounds per hour per square foot.
As an added benefit, the high heatup rates pos
sible through indirect heating with a circulating
sand phase along with the short residence times
in the gasification reactor effectively reduce the
tendency to form condensable tar-like materials
which results in an environmentally simpler
process.
According to Paisley and Overend, the basic
uniqueness of the Battelle process compared to
other biomass gasification processes is that it
was designed to exploit the unique properties of
biomass while the other processes were either
developed for coal gasification or were heavily in
fluenced by coal gasification technology.
Several characteristics of the process and the
resulting benefits are:
- Constant
High Throughput-ln excess of
3,000 Ib/hr-ft2. A 200-dry-ton per day
facility
will have a "footprint,"
excluding
biomass storage, of approximately
20 feet by 30 feet and will utilize a gasifier
less than 3 feet in diameter.
Fuel Flexibility-The process has been
demonstrated with a wide range of
biomass fuels including sawdust, wood
chips, shredded bark, hog fuel, refusederived
fuel, and energy plantation crops
such as hybrid poplar and switch grass.
Gas Heating Value-By cir
culating
hot solids between the gasifier
and combustion reactors, it is possible to
produce a medium-BTU gas without re
quiring
oxygen in the gasifier. The cir-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
FIGURE 1
BATTELLE HIGH THROUGHPUT GASIFICATION PROCESS
1 1 i.l.ll'WWll .III
UWI^
m^^T Flue Gas
1 1 f
Dally
Storage
Feed
SOURCE: PAISLEY AND OVEREND
culating
Ash Emir tk b ' " zszs
Recovery mm
Cyclone Ef
sand phase provides the heat
for gasification rather than the combus
tion of a portion of the feedstock itself.
Changes in feedstock moisture or
process operating conditions have no ef
fect on the product gas heating value,
because the separate combustor can
rapidly adjust to the changes.
No Byproduct Production-Char is com
pletely
consumed in the combustor.
Condensates in the product gas are
either removed by a water scrubber and
used as additional fuel for the combustor
or catalytically modified using a hot-gas
conditioning catalyst.
1-13
- Improved
Medium BTU
Product Gas
Water
Wastewater
oduct
;Recover
HeafB^
Economics Compared to
Direct Combustion -The compact size
of the gasification reactors and the over
all simplicity of the process result in
favorable economics.
Projected Economics of a Combined Cycle
System
The production of gas in the indirectly heated
gasifier coupled with the relatively high efficiency
of gas turbine power production provides the
potential for a combined cycle cogeneration sys
tem. A conceptual process design was
developed and based on the following criteria: 1 )
electrical production of approximately
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
50 megawatts; 2) basing the design on an in
dustrial gas turbine system; 3) using a dual pres
sure steam cycle; 4) using steam generator ex
haust gas for chip drying. Overall power produc
tion performance of the system is summarized in
Table 1.
Based on the flowsheet shown in Figure 2 (next
page), gasifier designs were developed for the
gasifier system and the gas/steam turbine sys
tem.
Total installed equipment costs on a dollars per
installed kilowatt basis, were calculated to be less
than projections for a new central power station.
These costs are shown in Table 2 (next page).
The total calculated cost of electricity is
$0.0563 per kilowatt-hour for a capital charge
rate of 20 percent, which is equivalent to a
10 percent return on investment.
McNeil Station Project Participants
Key participants in the project are Future Energy
Resources, Battelle's licensee for the gasification
technology; the McNeil joint owners, Burlington
Electric Department, Central Vermont Public Serv
ice Corporation, Green Mountain Power, and the
Vermont Public Power Supply Authority; Zurn
TABLE 1
WOOD GASIFICATION
PLANT PERFORMANCE
Power Summarv MW
Gas Turbine 38.0
Steam Turbine
High Pressure 22.8
Low Pressure
Total Gross
Total Net
Gross Plant Efficiency (%)
2.1
62.9
56.0
36.4
1-14
NEPCO, the architectural and engineering firm;
Battelle; and the United States Department of
Energy. Additionally,
who will be evaluating the technology
other program participants
and inves
tigating future applications are: Weyerhaeuser,
Sauder Woodworking, Centerior Energy, the
State of Iowa, New York State ERDA, General
Electric, the United States Environmental Protec
tion Agency, and others.
Zurn will have exclusive rights to engineering,
procurement and construction for the technology
in North America for 10 years.
####
ENVIRONMENT
CARBON DIOXIDE ENRICHMENT NOT
ALWAYS BENEFICIAL TO PLANTS
The United States Department of Energy's
Brookhaven National Laboratory (BNL) has
reported on a 2-year experimental program that
studied carbon-dioxide enrichment in cotton
plants. The program was conducted using a
BNL-developed system that exposes plants to
elevated concentrations of carbon dioxide under
natural conditions. The system is called FACE,
for Free-Air Carbon-dioxide Enrichment. It is
designed to assess the biological consequences
of global change.
Results of the experimental program, which was
carried out in Maricopa, Arizona, from 1989 to
1991, were recently published in a special edition
of Agricultural and Forest Meteorology.
Among the findings, according to BNL, is that the
more carbon dioxide a plant gets, the more it is
able to tolerate drought and to use water effi
ciently. But that does not necessarily mean that
carbon-dioxide enrichment is all good. Experi
ments with wheat show that food or animal fod
der grown under higher carbon-dioxide condi
tions may be of lower quality, due to a decrease
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
Wood
Handling
Wood
Drying
SOURCE: PAISLEY AND OVEREND
FIGURE 2
WOOD GASIFICATION COGENERATION SYSTEM
Product
Gas
Air
_L
Air Heater
Heat
Rue Recovery
Gas
m
Combustor l I
Recycle Product Gas
Rue Gas
TABLE 2
Scrubber
**-^
-
Co
CAPTIAL COST SUMMARY
Cost ComDonents Cost $x1 06
Gasifier System 16.8
Gas/Steam Turbine System 61 .5
Total 78.3
1-15
hQ
Super Heated
Steam
Power
Product
< Compression
^^J Steam
Condensing
Turbine
Steam
islngf
Heat
Recovery
Gas Combustion
Turbine
^**w Power
Cost$/kW
267
978
1,245
Boiler
Feed Water
THE SYNTHETIC FUELS REPORT, JANUARY 1995

GENERAL
in the amount of nitrogen in plant tissue grown at to Arizona, FACE is also being used in North
elevated carbon-dioxide concentrations. Carolina, in a study of a maturing forest, and in
Switzerland, where researchers are studying
The FACE program in Arizona is one of three in plant nutrients in managed grasslands.
the world, all of them established by BNL and
operated under its general direction. In addition ####
1-16
THE SYNTHETIC FUELS REPORT, JANUARY 1995

1995
COMING EVENTS
JANUARY 15-19, ORLANDO. FLORIDA-11th International Symposium on jjsj and Management of oaJ
Combustion Byproducts, phone 703 31 7 2400
FEBRUARY 1-2, HOUSTON, TEXAS-18th Annual Energy Sources Technology Conference.
phone 214 746 4901
FEBRUARY 12-17, HOUSTON, TEXAS-Sixth Unitar International Conference on Heavy Crude ana! Isi
Sands, phone 403 427 8382
FEBRUARY 12-19. NEW DELHI. INDIA-1 1th Indian Engineering Trade Fair, fax 91 11 463 3168
FEBRUARY 13-16, WASHINGTON, D.C. -Energy and the Environment: Application of Geosciences to Deci-
sjpn Making, phone 303 236 5769
MARCH 7-9, ALEXANDRIA, VIRGINIA-The National Hvdrooen Association's Sixth Annual U.S. Hvdrooen
Meeting, phone 202 223 5547
MARCH 13-14, CALGARY, ALBERTA, CANADA-North American Natural Gas Conference, fax 403 289 2344
MARCH 20-22, SINGAPORE-1995 Asia Coal Conference, fax 65 226 3264
MARCH 20-23, CLEARWATER, FLORIDA-20th International Conference pn Coal Utilization and Fuel Sys
tems, phone 202 296 1 133
MARCH 26-28, DALLAS, TEXAS--37th Hydrocarbon Economics and Evaluation Symposium, fax 214 952
9435
APRIL 3-6, SAN FRANCISCO, CALIFORNIA-The Sixth Global Warming
phone 708 910 1551
International Conference and Expo.
APRIL 30-MAY 4, NORMAN, OKLAHOMA-The Third International Conference pn Carbon Dioxide Utiliza
tion, phone 405 325 3696
MAY 1-4, VANCOUVER, BRITISH COLUMBIA, CANADA--puncjl on Alternate Fuels. Alternate Energy 195,
phone 703 276 6655
MAY 8-12, HOUSTON, TEXAS-International Energy Agency Conference on Strategic Value pf Fossil Fuels.
phone 202 331 0415
MAY 14-17, BANFF, ALBERTA, CANADA-Ihe Petroleum Society of CIM 46th Annual Technical Meeting.
phone 403 237 51 12
MAY 15-19, TUSCALOOSA, ALABAMA-lnternational Unconventional Gas Symposium, fax 205 348 6614
MAY 16-18, AMSTERDAM, THE NETHERLANDS-Power-Gen Europe, phone 713 963 6237
JUNE 4-6, QUEBEC CITY, CANADAevgnth Canadian Hydrogen Workshop, fax 416 978 0787
1-17
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COMING EVENTS
JUNE 19-21 , CALGARY, ALBERTA, CANADA-International Heavy Qil Symposium
JUNE 20-22, LAXENBURG. AUSTRIA-lnternational Energy Workshop, fax 43 22 367 1313
JUNE 27-29, WASHINGTON, D.C.-Symposium pn Greenhouse Gas Emissions and Mitigation Research.
phone 919 541 7979
JULY 31 -AUGUST 4, ORLANDO, FLORIDA-30th Intersocietv Energy Conversion Engineering Conference.
fax 509 375 3614
AUGUST 22-25, LONDON, UNITED KINGDOM-Greenhouse Gases: Mitigation Potions, phone 44 242 680
753
SEPTEMBER 10-15. OVIEDO, SPAIN-Eighth International Conference pn paj Science, fax 348 529 7662
SEPTEMBER 11-15, PITTSBURGH, PENNSYLVANIA- 12th Annual Pittsburgh Coal Conference.
phone 412 624 7440
SEPTEMBER 27-29, SINGAPORE-Power-Gen Asia, phone 713 963 6237
OCTOBER 8-12, MINNEAPOLIS, MINNESOTA-lntemational Joint Power Generation Conference.
fax 201 882 1717
OCTOBER 16-18, REGINA, SASKATCHEWAN, CANADA-Sixth Saskatchewan Petroleum Conference.
phone 306 787 9328
NOVEMBER 6-9, CANNES, FRANCE--International Gas Research Conference, fax 312 399 8170
NOVEMBER 6-11, CARACAS, VENEZUELA-Third International Congress pn Energy. Environment and
Technological Innovations, fax 582 693 0629
NOVEMBER 20-24, VICTORIA, AUSTRALIA-lntemational Symposium pn Energy. Environment and
Economics
DECEMBER 5-7, ANAHEIM, CALIFORNIA-Power-Gen Americas, phone 713 963 6237
1-18
THE SYNTHETIC FUELS REPORT, JANUARY 1995

PROJECT ACTIVITIES
SPP/CPM CONTINUE NEGOTIATIONS FOR
FINANCING OF STUART PROJECT
In its quarterly report for the period ending
September 30, 1994 Southern Pacific Petroleum
(SPP) and Central Pacific Minerals (CPM) say
that technical and economic evaluation by poten
tial coventurers of Stages 1, 2 and 3 of the Stuart
OH Shale Project near Gladstone, Queensland,
Australia continued during the quarter. While the
companies are focusing on financing arrange
ments for Stage 1, the expansion envisaged in
Stages 2 and 3 are integral parts of this process.
Bechtel Corporation of San Francisco, who un
dertook a major study of the project and the tech
nology involved, continue to play an important
role in these discussions and the information ex
change involved.
OIL SHALE
TABLE 1
During the period, Bechtel completed the task of
costing a number of different options in relation
to expanding Stage 3 to produce, directly, a slate
of refinery products including gasoline, liquefied
petroleum gas, kerosene (jet fuel)
cuts.
and diesel oil
In its 1993 annual report, SPP presented the
economics for the Stuart project as shown in
Table 1 . Stage
1 , the commercial demonstration,
would use 6,000 tons per day of high-grade oil
shale. Stage 2, the commercial module, would
use 25,000 tons per day of intermediate-grade oil
shale. Stage 3, the full commercial plant, would
use 125,000 tons per day
shale.
of average-grade oil
To date, SPP/CPM have expended in excess of
$30 million in exploration, research, evaluation
and development of the Stuart project including
the cost of obtaining surface rights for the mining
lease.
STUART PROJECT PRELIMINARY COST FIGURES
Output (bpsd)
Estimated Initial Plant Cost
Estimated Average Cash
Operating
Cost per Barrel
Stage 1
4,500
$125M
$11.50
Stage 2
14,800
$225M
$8.50
Stage 3
64,900
$1,300M
All amounts are expressed in $US at 1993 value and are based on an
exchange rate of $A1 =$US0.675
$6.50
Estimated operating costs are based on 1993 estimates and levels with
no increment for inflation
2-1
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
A December 1994 stock analyst's report by Stires
and Company points out that, at current stock
prices, the combined SPP and CPM companies
are capitalized at just under US$100 million. Con
sidering the
companies'
other assets, this means
that their Queensland oil shale reserves are being
valued by the market at a mere $0,005 per barrel.
####
LLNL CONVERTS OIL SHALE RETORT FOR
WASTE TREATMENT STUDIES
Lawrence Livermore National Laboratory (LLNL)
developed the LLNL Hot-Recycied-Soiid (HRS)
retorting process, a rapid retorting
system that
uses hot recycled oil shale as the solid heat car
rier (see Figure 1). LLNL is now adapting the
HRS process to address pressing problems in
the field of waste treatment.
During the course of the oil-shale work, LLNL real
ized that the HRS process, if modified and ex
tended, can be applied to several important
problems in the field of waste treatment and en
vironmental cleanup. For example, a preliminary
laboratory study showed that the HRS process
might be suitable for removing organic com
pounds and for decomposing sodium nitrate
(NaN03). Organic compounds and sodium
nitrate are major constituents of the mixed waste
stored in underground tanks at the Hanford,
Washington facility. (Mixed waste is both radioac
tive and chemically hazardous.)
In 1993 LLNL began to modify the pilot plant that
was built for processing oil shale. They have
now adapted this pilot plant and are collaborat
ing
with researchers elsewhere to demonstrate
the feasibility of pretreating Hanford tank wastes
using a circulating bed of hot ceramic spheres.
This work was described in a recent issue of
Energy and Technology Review. At the same
time. LLNL is pursuing
several other applications
of an HRS retort process for treating a variety of
substances of environmental concern. They are
demonstrating that the HRS process has poten
tial applications for decomposing or treating
2-2
FIGURE 1
LLNL
HOT-RECYCLED-SOLID
SOURCE: LLML
PROCESS
L-valve
Combustor
exit
Product
oil and gas
THE SYNTHETIC FUELS REPORT, JANUARY 1995
>

OIL SHALE
many of the harmful chemicals and compounds
found throughout and beyond the United States
Department of Energy (DOE) complex.
The modified HRS process applies heat to con
vert waste in a liquid state into non-toxic
products. In thermal treatment, a high-
temperature reducing atmosphere (that is, one
with no oxygen present) is used to convert or
ganic matter and other hazardous waste
materials into a volatile vapor phase. Following
thermal treatment, the volatiles are subjected to
steam reforming, a process in which high-
temperature ( up to 1,000C) steam is applied to
break down the volatiles into simpler, non-toxic
species. After thermal treatment is applied to a
large volume of waste sludge, all that remains is
a small amount of ash. The volume reduction is
considerable, ranging
volume than the starting material.
from 50-70 times less
Thermal treatment in the absence of oxygen has
several other advantages beyond a large
decrease in waste volume. For example,
pyrolysis processes do not produce such highly
undesirable products as dioxins and furans.
The HRS waste treatment process uses a circulat
ing bed of heated ceramic spheres, shown in
Figure 2, as the heat carrier. The ceramic
spheres are heated (using electric heat) until they
reach a temperature that can vaporize and
process the liquid sludge fed into the system.
This technique-spreading
out the liquid waste
over the large surface area afforded by the hot
ceramic spheres-provides sufficient time for ther
mal treatment and avoids the problems of clump
ing
and agglomeration that can occur when
waste is treated alone.
LLNL's goal is to develop the HRS system using
hot ceramic spheres into a robust and highly reli
able process for decomposing hazardous liquid
waste, sludges, and contaminated soils. The
HRS process can then be used to pretreat mixed
waste (decomposing the chemically hazardous
components, so the waste can be disposed of as
radioactive-only waste).
2-3
HRS Process for Decomposing Sodium Nitrate
The 177 underground storage tanks at the Han
ford facility contain various mixed wastes in the
form of radioactive isotopes, organic chemicals,
and sodium nitrate. The sodium nitrate in the
tanks is a result of using the Purex process
(which involves adding nitric acid) for extracting
uranium from ore. When the waste materials
were prepared for underground storage, sodium
hydroxide was added to neutralize and buffer the
acid solution and thereby reduce the likelihood
that the storage tanks would leak over time.
Nitric acid and sodium hydroxide,
which are
each highly corrosive, react to produce sodium
nitrate. Despite the precautions taken to mini
mize risk, the tanks are now leaking, and there is
concern that the contents will eventually con
taminate the Columbia River.
To solve this problem, the hazardous waste
material-the organic wastes and sodium nrtrate-
must first be separated from the radioactive
material. Once the tanks are rid of organics and
sodium nitrate, the radioactive waste stream-in
the form of a solid residue-can be processed in
a vitrification plant to yield a glass waste product.
In the fall of 1993, in collaboration with
researchers at Sandia National Laboratories,
LLNL adapted the on-site oil shale pilot plant to
demonstrate the feasibility of decomposing
sodium nitrate in a small working-model system.
Figure 2 shows the simplified HRS system used
to demonstrate sodium nitrate decomposition.
This modified system differs in several important
ways from the system developed earlier for oil
shale processing (compare Figure 2 with
Figure 1). To extract oil from shale, air (oxygen)
is used to bum the residual carbon and to lift the
spent shale up around the loop to the top of the
tower. In addition, oil shale retorting is a solid
process (with no added water). In contrast, the
waste processing takes place in a reducing at
mosphere (no oxygen) and involves liquids, not
solids, because the waste in the Hanford drums
is already in liquid form.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
FIGURE 2
HRS PILOT PLANT
USED TO DEMONSTRATE THE DECOMPOSITION OF SODIUM NITRATE
SOURCE: LLNL
Other Waste Treatment Applications of the
HRS Process
The DOE is in the process of dismantling a large
fraction of the nation's nuclear stockpile. One
2-4
waste component from the dismantlement effort
is chemical high explosives. The current method
for disposing of high explosives is by open burn
ing and open detonation. Regulatory agencies
may soon greatly restrict or eliminate open burn-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
ing and open detonation as ways to dispose of
propellants, explosives, and pyrotechnics (also
called PEPs). The DOE uses primarily plastic
bonded explosives, or PBX for short. Although
much of this material--as much as
90 percent-may be sold to industry, a certain
amount will have to be destroyed. (Many other
materials, such as solvents and wipes that come
into contact with the high explosives, become
classified as hazardous waste and will also have
to be destroyed.) Some high explosives can be
pretreated with sodium hydroxide in a process
called base (or alkaline) hydrolysis. This process
destroys that material's explosive nature, but the
resulting liquid and gaseous products are still haz
ardous and thus require additional treatment.
New regulations require the military to examine
the life-cycle of any new PEP developed. The
Army is currently evaluating disposal methods for
a new liquid gun propellant, LP XM46, which is
used as a conventional propellant for field ar
tillery. This material is a mixture of hydroxylam-
monium nitrate and triethanolammonium nitrate
in 20 percent water. Liquid gun propellant is not
detonaole, and once diluted in a ratio of 1 to 3
with water, it is neither explosive nor flammable.
Nevertheless, the material is chemically hazard
ous and a suitable method, other than incinera
tion, is needed to dispose of the liquid material.
LLNL is exploring
the use of the HRS process
with hot ceramic spheres to destroy liquid gun
propellant and the products from base hydrolysis
of high explosives as an alternative to open burn
ing
and incineration. Runs have been completed
with each of the two materials in the modified
HRS pilot plant to determine the gas products,
condensable liquids, and solid products of
decomposition.
####
STUDIES UNDER WAY ON COCOMBUSTION
OF OIL SHALE AND MUNICIPAL WASTE
H. McCarthy
and R. Ciayson of Synfuels En
gineering and Development, Inc. have proposed
2-5
a process that mixes and burns municipal solid
waste and crushed calciferous oil shale to gener
ate electricity and minimize emission of acid
gases. The resulting cementitious ash would be
environmentally benign for waste disposal and
may be suitable for the manufacture of construc
tion materials such as lightweight concrete. Their
proposal won a funding grant of $95,000 from the
U.S. Department of Energy. Tests will be carried
out at the Advanced Combustion Engineering
Research Center located at Brigham Young
University in Utah.
There are numerous plants that burn Municipal
Solid Wastes (MSW) as a fuel for generating
electricity. Analysts anticipate that several dozen
more such plants will be operational within the
next few years (Figure 1). In order to meet air
quality requirements, these plants (as well as
most coal-fired powerplants)
sive pollution control equipment.
must have expen
In the past few years, it has been demonstrated
that fluidized-bed combustors can be effectively
used for power generation in coal-fired
powerplants. As a result, several fluidized-bed
coal-fired powerplants operate with a satisfactory
level of performance. In such plants, crushed
limestone in the fluidized bed adsorbs sulfur com
pounds, obviating the need for much of the ex
pensive stack gas cleanup
fired powerplants normally require.
equipment that coal-
Based on limited laboratory work and engineer
ing analysis the inventors say that "Combustion
of Municipal Solid Wastes with Oil Shale in a Cir
culating Fluidized Bed"
appears to be a techni
cally acceptable process that economically util
izes the energy of oil shale and reduces the cost
of pollution control equipment in an MSW-fired
powerplant.
The inventors'
process mixes and bums roughly
75 percent MSW and 25 percent crushed oil
shale in a fluidized-bed boiler to generate
electricity. The resulting ash from the process
will have cement-like properties which may make
it suitable for the manufacture of some construc
tion materials. The ash can also be mixed with
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
200
g 150
v
a
i
a 100
10
2
1 50
SOURCE: EM
FIGURE 1
SOLID WASTE FLOW PROJECTIONS
17.0
29.9
44.1
1986 1991 1996
V77A Landfilllng j Materials Recovery evwn Combustion
water and placed in a landfill, where the mixture
would form a concrete mass that would seal in
environmentally
hazardous chemicals.
Coburning the oil shale with the MSW would ac
complish two purposes. The calciferous com
ponents of the fired oil shale would absorb and
react with any sulfur oxides and other acid gases
formed during combustion, removing or greatly
reducing
the requirement for expensive pollution
control equipment. Also, shale reserves that can
not now be economically used could be used to
generate electricity. (The oil shales must have
adequate calciferous content to satisfactorily ab
sorb and react with the sulfur oxide compounds
and other acid gases, thereby removing them
from the flue gas stream. Some Eastern shales
2-6
may not have the necessary properties.
However, other oil shales such as the New
Brunswick shales do have the needed
constituents.)
Operational Benefits
The inventors say their process would make it
possible to economically use much of the West-
em oil shale reserves. Conservative estimates
indicate that utilizing oil shale reserves can save
about 12 to 16 million barrels of crude oil equiv
alent per year. No incremental energy savings
can be attributed to the MSW that is burned be
cause it can be burned by conventional technol
if environmental regulations do not prohibit
ogy
such practice.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
In addition, it is possible that the process could
be used to cocombust medium to high sulfur
coal and oil shale to generate electricity. If the cir
culating fluidized-bed resulting from the oil shale
In the combustor could clean up the stack gas
adequately to eliminate a large part of the pollu
tion control equipment, this would make the
process attractive. Commercially it would be pos
sible to utilize not only the oil shale but some part
of the coal reserves that cannot now be economi
cally utilized because of the cost of cleaning up
stack gas. It appears that this may be technically
feasible. This capability has been demonstrated
in previous work performed by the inventors.
Such a development would significantly multiply
the potential energy savings of the process. The
process could also be used in any part of the
country
be economically transported.
where the coal and oil shale could both
Market Potential and Status
If successful, the process could become widely
used, at least in the Western and most North
eastern United States, in new MSW plants. This
would depend on the circulating fluidized-bed
combustor unit cleaning up the stack gas stream
and eliminating the normal heavy
investment in
stack gas cleanup equipment. If the process
proves to be a superior stack gas cleaner, its
savings in initial capital investment and in ash dis
posal costs would likely give most municipalities
a powerful economic incentive to prefer it over
other MSW combustion processes.
Inventors'
Goals
The inventors'
long-range goals are to bring
about the widespread use of MSW to generate
electricity while recycling all usable components
of the MSW, and to minimize environmental
problems associated with MSW and its waste
streams. The current project is designed to con
firm the technical feasibility and economic poten
tial of the process.
####
2-7
CORPORATIONS
SODIUM BICARBONATE FROM OIL SHALE
ATTRACTS ATTENTION
NaTec Resources
NaTec Resources Inc. appears to be winding
down its operations. The company was formed
to market natural sodium bicarbonate obtained
from in situ leaching of nahcolite in the oil shale
deposits of the Piceance Basin in Colorado.
NaTec planned to sell the sodium bicarbonate to
the flue gas desulfurization market,
failed to develop as expected.
which has
In 1992, NaTec entered into a joint venture with
North American Chemical Company (NACC) for
the operation of White River Nahcolite Minerals.
In 1994, NaTec filed a lawsuit against NACC alleg
ing that NACC had failed to pay $625,000 as part
of their nahcolite joint-venture agreement.
NaTec said the $625,000 was part of a
$3.5 million balance remaining
on a $10 million
payment NACC agreed to make when the ven
ture was formed in 1992.
NACC alleges that the nahcolite production
facility has not yet demonstrated a capacity of
106,000 tons of sodium bicarbonate per year as
required by the joint-venture agreement.
In addition, NaTec alleges that NACC, as
manager of the joint venture and owner of the
facility, has prevented it from achieving full
capacity by refusing to utilize additional recovery
equipment already located at the facility, and to
implement certain process modifications.
NaTec's primary source of cash since
November 1992 has been payments by NACC
from the White River venture.
Also, NaTec's major creditor, CRSS Inc., has indi
cated it will not infuse any additional cash into
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
the company. Earlier in 1994, CRSS signed a
non-binding
letter of intent to sell its holdings in
NaTec to AmerAlia Inc. for about $15 million.
AmerAlia says It wants to conclude that deal and
take control of NaTec.
NaTec's primary asset remains the interest
owned in the White River venture, and the com
pany says that existing
to be supplied.
AmerAlia Inc. traditionally
customers will continue
provides sodium bicar
bonate for use in the preparation of animal feed
mixes for dairy cows and other animals. But now
the Colorado Springs, Colorado, company will
pursue acid rain cleanup markets for the nah
colite product.
Natrona Resources
Natrona Resources Inc. of Glenwood Springs,
Colorado has awarded a design contract to
Raytheon Engineers and Constructors to build a
sodium bicarbonate and soda ash plant between
Meeker and Rangeiy in northwestern Colorado.
The contract, for an unspecified amount, is the
first stage of Natrona's plan to build the plant by
1996 to produce sodium bicarbonate and soda
ash in large volume by 1998. Natrona currently is
seeking financing for commercial development.
Natrona's property is adjacent to that owned by
NaTec Resources Inc.
Natrona and its partners-including Spelling Enter
tainment Group Inc.-were awarded three leases
7,151 acres in the Piceance Creek Basin
covering
in 1992. The area is thought to contain 3 billion
tons of nahcolite.
The Piceance Creek Basin contains an estimated
30 billion tons of nahcolite and is the only sub
stantial source of natural sodium bicarbonate in
the world. Because sodium bicarbonate can be
converted to sodium carbonate (soda
easily
2-8
ash), It is also recognized as the second-largest
deposit of sodium carbonate.
####
ECONOMICS
LLNL FINDS ENHANCED ECONOMICS
POSSIBLE FOR SMALL-SCALE PLANT
Lawrence Livermore National Laboratory (LLNL)
has made economic projections for two different
sizes of oil shale retorting operations using the
LLNL HRS (Hot-Recycled-Solid) process. Some
results were presented by R. Cena at the 208th
American Chemical Society Meeting held in
Washington, D.C. in August.
One of the crucial challenges in beginning an oil
shale industry is how to overcome the high capi
tal cost and long lead time needed to make
process improvements which would enable shale
oil to compete as a fuel feed stock. LLNL has
chosen to focus on an initial plant that converts a
large fraction of its production into high-valued
specialty products to gain an initial market entry.
LLNL determined the economics for a plant
producing 10,000 barrels per day of oil from
shale. The plant converts the raw shale oil into a
slate of high-valued products including specialty
chemicals, a shale oil modified asphalt binder
and transportation fuels, while coproducing
electric power. According to Cena, this small-
scale venture appears to be competitive in
today's market with a 15 percent internal rate of
return on a capital investment of $725 million.
Once in operation, expansion to 50,000 barrels
per day has the potential to become economic
through economies-of-scale and cost reductions
based on operating experience and plant innova
tion. This small beginning would provide the
operating experience prerequisite for a larger in
dustry, if and when appropriate, that could
supply
transportation fuel needs.
a significant fraction of the U.S. liquid
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
The heart of the 10,000 bbl/day commercial HRS
similar to a combined-cycle
process is very
circulating-bed boiler for power production. In
this plant, raw shale would first be pyrolyzed to
produce oil, followed by combustion of residual
carbon to produce thermal energy to drive the
process and electric power for on-site use and
off-site sale. The power cycle provides a means
for spent shale cooling and fuel gas utilization
while providing enough revenue to offset the cost
of mining the raw shale.
The produced shale oil is split into three frac
tions. Ten percent is converted into specialty
chemicals, unique to shale oil, which could com
mand a sale price of $100 per barrel. The
heaviest 50 percent is converted into an asphalt
binder (SOMAT) for road paving, with a projected
sale price of $100 per parrel. The lightest
50 percent is then hydrotreated/refined produc
ing a slate of transportation fuel products ranging
from diesel to aviation fuel. The wholesale
market price for this transportation fuel mix,
averaged in 1993, is $0.73 per gallon or $31 per
barrel.
The economics of this 10,000 bbl/day plant are
shown in Table 1 (next page). Cost and revenue
Items are reported on per capacity basis, assum
ing a 330 day operating
year. The capital cost on
the $725 million plant with a 15 percent Internal
Rate of Return (IRR) on investment equals a capi
tal charge of $37 per barrel. Operating costs in
cluding mining, disposal, plant operations and
maintenance are estimated by direct comparison
experience at Parachute
with Unocal's operating
Creek. These costs are estimated at $23 per bar
rel. Hydrotreating/refining costs of $10 per bar
rel are also based on Unocal's experience. With
50 percent of the product needing hydrotreating
in the current plant configuration, this equates to
a $5 per barrel cost. The next two operating
costs involve conversion of 40 percent of the
product into a shale oil modified asphalt binder
SOMAT and 10 percent into specialty chemicals.
Next in the table are the four products from the
plant. The first is excess electrical production
capacity obtained from the cooling
and waste
2-9
shale and on-site combusting
of produced fuel
gas. Off-site electrical sales amount to a $5 per
barrel credit. The sale of SOMAT and specialty
chemicals, each assumed to have a value of
$100 per barrel bring in an additional $50 per bar
rel revenue, leaving a $15 per barrel gap between
costs and revenues, with 50 percent of the
product left. Here the table deviates from the
heading by reporting the required price of the
transportation fuel products needed to achieve
the 15 percent rate of return desired. As shown,
the required price is about equal to the wholesale
price of these fuels during 1993. Thus, the
economics for a 10,000 bbl/day plant provide a
15 percent rate of return on investment in today's
market.
Table 2 (page 2-11) shows the impact of scaleup
on economics. As more capacity is added, the
capital and operating costs per parrel decline,
while revenues from the production of high-
valued specialty products decline also. The re
quired motor fuel price increases to $39 per bar
rel or $0.93 per gallon to achieve the desired
15 percent rate of return. This is a not un
reasonable rise in fuel price over the next
1-2 decades. In addition, process improvements
and innovation based on experience will aid in
lowering
plant.
the overall cost projections for this
####
TECHNOLOGY
KENTORT RUNS ILLUSTRATE RETORT
SCALEUP PROBLEMS
The first runs in the KENTORT II Process
Demonstration Unit (PDU) at the University of
Kentucky Center for Applied Energy Research
(CAER)
were described in the October issue of
Ih Sinor Synthetic Fuels Report (page 26). Dif
ferences between the results obtained in this
22.7 kilogram/hour unit and earlier results ob
tained in laboratory-scale experiments were dis
cussed by S. Carter et al. at the 208th American
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
TABLE 1
ECONOMICS OF A 10,000 BBL/DAY PLANT
Description
Capital cost @ 15% IRR -
725 Million
Unocal's projected operating costs (full
production excluding hydrotreating)
Hydrotreat/refine 50% into transpor
tation fuel (cost $10/Bbl)
Convert 40% to SOMAT (seasonal
- average cost $5/Bbl)
Convert 10% to specialty chemicals
(cost $25/BpI)
Subtotal -
Capital & Operating Costs
Off-site electricity sales @ $0.03/kWh
SOMAT asphalt additive @ $100/Bbl
Specialty chemicals @ $100/Bbl
Required transportation fuel price
for 15% rate of return
Transportation fuel wholesale price
in 1993
Chemical Society meeting
Washington, D.C. last August.
held in
Fluidized bed pyrolysis of oil shale in a non-
hydrogen atmosphere has been shown to sig
nificantly increase oil yield in laboratory-scale
reactors compared to the Fischer Assay. The
enhancement in oil yield by this relatively simple
and efficient thermal technique has led to the
2-10
Cost&
Revenue
$37
$23
$5
$2
$3
$70
($5)
($40)
($10)
$30
$31
development of several oil shale retorting
processes based on fluidized bed and related
technologies over the past 15 years. Since 1986,
the CAER has been developing one such
process, KENTORT II, which is mainly tailored for
the Devonian oil shales that occur in the Eastern
U.S. The process contains three main fluidized
bed zones to pyrolyze, gasify, and combust the
oil shale. A fourth fluidized bed zone serves to
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
TABLE 2
ECONOMICS OF A 50,000 BBL/DAY PLANT
Description
Capital Cost @ 15% IRR -
Cost&
Revenue
$/Bbl
2,225
Million $23
Operating costs including hydrotreating/refining
Subtotal -
$25
Capital & Operating Costs $48
Off-site electricity sales @ $0.03/kWh ($5)
SOMAT asphalt additive 15% @
$60/Bbl ($9)
Specialty chemicals 5% @ $60/Bbl ($3)
Required transportation fuel price
cool the spent shale prior to exiting the system.
The autothermal process utilizes processed shale
recirculation to transfer heat from the combus
tion to the gasification and pyrolysis zones.
Background
Fluidized bed pyrolysis increases oil yield by
reducing the extent of secondary coking and
cracking
deposition and gas production. The fluidizing
gas dilutes the shale oil vapors and sweeps them
for 15% rate of return $39
reactions which result in carbonaceous
quickly out of the bed of pyrolyzing shale to
reduce both thermal cracking and solids-induced
coking and cracking. Fluidized beds, in the case
of oil shale retorting,
offer an advantage over
gas-swept fixed-bed reactors because there is
little gas/solid contact in the bubble phase of a
fluidized bed.
2-11
Assuming similar fluidization characteristics, the
extent of secondary reaction (i.e., oil loss) is af
fected by bed depth, solid type, and temperature,
as it is in any gas/solid reaction. For small
fluidized beds the bed depth is shallow, so secon
dary
reactions are minimal. Because it is imprac
tical to increase a fluidized bed to commercial
scale by only increasing the cross-sectional area
without also increasing the height, an un
avoidable increase in secondary reactions will
occur with scaleup. The extent of this increase
can only be determined by experiment because
of the difficulty in modeling fluidized bed contact
ing. Even at the laboratory scale, significant dif
ferences in oil yield have been observed as a
result of retort size. In earlier work at CAER oil
yields from a 7.6-centimeter diameter fluidized-
bed pyrolyzer were approximately 13 percent
less than the oil yields from an otherwise similar
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
3.8-centimeter diameter fluidized-bed retort. In
creased gas production in the larger retort con
firmed that secondary reactions had increased in
this study.
According to Carter et al., another factor that con
tributes to high oil yield in small laboratory-scale
retorts is that the heat for pyrolysis is provided by
preheated gas and/or through the walls by an
external furnace. In these retorts the nascent
shale oil vapors experience contact with an
isothermal and homogeneous mixture of pyrolyz
ing
shale. Because processed shale is recycled
in commercial-scale retorting schemes, however,
the particles in the pyrolysis zone are not
homogeneous and may potentially contribute to
greater rates of secondary oil-loss reactions. It
has been found that carbon deposition from
shale oil vapors is more rapid on combusted
shale than on pyrolyzed shale. Therefore, the oil
yield potential of large-scale fluidized-bed retorts
is potentially affected not only by their size but
also by the concentration and composition of
recycled shale in the pyrolysis zone.
Experimental Results
A 7.6-centimeter diameter, 2.3-kilogram per hour
fluidized-bed reactor system has been used ex
tensively
at the CAER as a small prototype of the
KENTORT II process. In almost all respects the
oil collection systems of the prototype and the
PDU are similar. The temperature is reduced in
stages which results in a crude fractionation of
the oil product. The oil collected in the air-cooled
heat exchanger and Electrostatic Precipitator
(ESP) is heavy and viscous and is termed "heavy
oil."
The oU condensed downstream in the water-
cooled condenser is low boiling
light
oil."
In the gas-heating
and is termed
mode of operation for the
prototype, oH yields averaged 129 percent of the
Fischer Assay oil yield by weight. Under the
most severe solid-recycle conditions (i.e., high
recycle rate and temperature) in the second
mode of operation, less than 15 percent oil loss
was recorded. Under these conditions ap
2-12
proximately 60 percent of the heat required for
pyrolysis was supplied by recirculating shale
from the gasification zone. The study was incon
clusive In determining whether solid-recycle rate
or temperature was the more influential
parameter; however, it appeared that higher
recycle-solid temperatures caused greater oil
yield loss.
The composite oil produced in the prototype is a
heavy, viscous and aromatic material which is
oil."
comprised of 70 percent "heavy The charac
ter of the oil indicates that minimal secondary
has occurred as compared
cracking and coking
to the oils produced from Fischer Assay.
By comparison, say the authors, oil yields from
the KENTORT II PDU, on a carbon conversion
basis, are lower than the prototype. A shift to a
lighter composite oil is evident because ap
60 percent of the total has been col
proximately
oil."
oil"
lected as "heavy The loss of "heavy is
consistent with increased secondary oil-loss reac
tions because the heaviest and most aromatic
fractions are most susceptible to carbon deposi
tion and gas production.
These results indicate some of the problems in
volved in scaleup of oil shale retorting processes.
####
NITROGEN COMPOUNDS REMOVED FROM
SHALE OIL BY ADSORPTION ON ZEOLITE
Shale oils typically contain substantial concentra
tions of organic sulfur, oxygen and nitrogen com
pounds. These must be removed in order to con
vert shale oil to a feedstock suitable for a conven
tional petroleum refinery. This is normally ac
complished by hydrotreating.
In the case of nitrogen, hydrogenation increases
the basicity of the heterocyclic N atom as well as
non-basic N compounds to basic N
converting
compounds. With indole, hydrogenation leads to
polymerization reactions.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
Residual N heterocycles are of particular concern
because they
poison the acidic catalysts used in
refinery hydrocracking reactions. Unfortunately,
complete removal of N requires vigorous
hydrotreatment. For a typical shale oil distillate,
the conditions needed to reduce N from 140 to

OIL SHALE
TABLE 1
ADSORPTION (MOL%) OF INORGANIC NITROGEN COMPOUNDS
ON US-Y ZEOLITE*
Pgse fmo) N Compound
Naph
Zeolite thalene Py An Oil i-Qu ing; Acr Phen Carb
50 81 35 78 97 20 65 68 23
100 98 66 >99 >99 44 99 94 56
100 98 60 >99 >99 60 >99 99 75
200 97 95 >99 >99 >99 >99 99 87
200 50 >99 >99 >99 >99 63 >99 >99 91
200 100 >99 >99 >99 >99 76 >99 >99 93
200 200 >99 >99 >99 >99 94 >99 >99 68
?Using 10 ml of hexane solution of eight bases (1 mg each)
Py= pyridine; An = aniline; Qu = quinoiine; i-Qu= isoquinoline; lnd = indole; Acr = acridine; Phen = phenan
thridine; Carb = carbazole
In a further experiment, increasing amounts of an
aromatic hydrocarbon (naphthalene) were added
to see how selectively the zeolite would adsorb
small concentrations of N heterocycles in the
presence of larger concentrations of aromatic
hydrocarbons, as would occur in a hydrotreated
shale oil. All except indole and carbazole were
still adsorbed efficiently. Table 1 also shows that
N compounds have a much higher affinity for the
zeolite cavities than do aromatic hydrocarbons.
This reflects the high acidity of these cavities. In
accord with this, the more basic N compounds
were more strongly adsorbed. The tendency for
stronger bases to be adsorbed more strongly is
relevant to the expected performance with
hydrotreated oil. During hydrotreatment, the ring
containing the N atom is reduced more easily
than are other aromatic rings in a pdycyciic
molecule, and the reduction of the heterocyclic
ring precedes hydrogenolysis of the N atom. As
a result, much of the residual N in a hydrotreated
shale oil should be more basic than the N in the
2-14
fully
aromatic precursors and therefore should be
more strongly adsorbed by the zeolite.
Finally, a shale oil from Stuart (Queensland)
which had been subjected to mild hydrotreat
ment (380C, 7 MPa, 0.4 h; residual
N = 2,000 ppmw)
was diluted with hexane (to
reduce viscosity) and treated with zeolite. The
total removal of g.c.-volatile, acid-extractable
compounds was >99 percent.
The N compounds recovered from the zeolite
contained only small amounts of alkanes. Hence
only minor losses of hydrocarbons would occur
in heating the zeolite to burn off the adsorbed N
compounds before recycling. The adsorption ef
ficiency
times was the same as fresh zeolite (Table 1).
Conclusions
of zeolite which had been recycled five
Based on their results, the authors suggest that
zeolite adsorption could provide an efficient alter-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
native to severe hydrotreatment for the removal
of refractory aromatic nitrogen compounds from
hydrotreated shale oils. The US-Y zeolite shows
high selectivity toward amines and N
heterocycles and adsorbs them efficiently even in
the presence of large concentrations of saturated
and aromatic hydrocarbons.
The zeolite containing the adsorbed N
heterocycles is readily separated by gravitational
settling and regenerated for reuse by burning off
the adsorbed organics. The high nitrogen con
tent of the adsorbed organics may cause some
combustion of the
NO to be formed during
zeolite, so appropriate stack gas scrubbing may
be required (as it is for the ammonia and
hydrogen sulfide produced by hydrotreatment).
Because the N compounds constitute a very
small proportion of a mildly hydrotreated oil, it
would be more economic to sacrifice these com
pounds by zeolite adsorption and combustion
rather than to use the alternative procedure of
very severe hydrotreatment, which substantially
lowers the value and yield of total liquid products
through loss of aromaticity, cracking and coking.
####
GE PATENTS RADIO FREQUENCY IN SITU
RECOVERY METHOD
United States Patent 5,236,039 issued to
W. Edeistein et al., and assigned to General
Electric Company, describes a new method of
arranging electrodes for a radio-frequency, in situ
recovery
method for oil shale.
A system for extracting oil in situ from a deep
hydrocarbon bearing layer employs a master os
cillator for producing a fundamental frequency, a
plurality of radiofrequency (RF) heating
electrodes, and a matching network. The con
ductive electrodes are situated in a rectangular
pattern. Production wells are provided at the cen
ter of each rectangular pattern for collecting the
oU and producing it at the surface. The currents
among the electrode array uniformly
heat the oil-
2-15
rich layer in situ to pyrolysis. Oil reaches the
production wells by fracturing the hydrocarbon
bearing layer and creating permeable paths to
the production wells.
Figure 1 is a plan view showing the placement of
electrodes and producer wells as they appear in
situ, according to the tripiate pattern and a pat
tern according to the present invention.
Figure 2 is a graphical comparison of cumulative
oil recovery over time using a Thermal Conduc
tion (TC) apparatus versus using the RF process
to the present invention.
according
Figure 1 represents electrodes 19, 29 as solid
circles and producer wells 81 as open circles, in
a top plan view. The electrode rows are posi
tioned substantially
closer than a wavelength
apart, and the electrodes within each row are
positioned substantially
closer than the row-to-
row spacing. Typical values for distances within
FIGURE 1
WELL PATTERNS FOR
TRIPLATE CONFIGURATION
AND GE CONFIGURATION
TRI-PLATE DEVICE
+2V 0 +2V
o
of
J...I.
M
PRESENT INVENTION
?V -V +V -V
0 0 Q
I
,
o t
|
j
f
o I
1
o
"
o j o | e
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
UJ
oc
o
CD
2
>
CC
tu
>
o Oat
rr
2
o
1000
800
600
FIGURE 2
ENERGY INJECTION RATES AND OIL RECOVERY RATES
400 Cum. recovery RF
ODD D
a row or between rows are 79 feet between
electrodes in a row and 125 feet between rows.
All the electrodes within each row are excited in-
phase and the excitations in the rows alternate
from in-phase to anti-phase to in-phase to anti
phase, etc. For example, electrodes 29, 89 and
91 in the center row receive a 0
excitation signal
while electrodes 19, 83 and 85 receive a
180
excitation. This electrode pattern is referred
to as a "balanced-line"
pattern.
With this arrangement, the rows act ap
proximately as sheet sources and the heating of
the region between rows is uniform.
Figure 1 also illustrates a prior art triplate pattern.
A ground is illustrated by a shaded circle, an
10
TIME (YR)
2-16
- Cum. recovery TC
eB- Inj. rate-RF
-?- Inj. rate TC
15 20
-
1000
800
600
400
m
cc
o <
?
CO
2
2
- 200 2
electrode by a solid circle, and a producer well
by an open circle.
As compared with the triplate pattern, the
balanced-line RF pattern of this invention allows
producer wells 81, 87 to be located midway be
tween electrode rows at the plane of zero poten
tial in the electric field created by electrodes 19,
83 and 85 in one row and 29, 89, and 91 in the
adjacent row, and enables the collection pipes
81, 87 to be at a safe electrical potential even if
they are of metallic construction. Moreover, this
location of the collection pipes 81, 87 is the
coolest spot in the pattern, which prevents over
heating and thermally wasting the liquid hydrocar
bons. By separating the RF electrode wells from
collection pipes, the electric field lines do not con-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
verge at the collection pipes so that the wells
stay cooler.
Simulations for typical Colorado oil shales were
performed using a finite difference simulator to
simulate the present invention. Figure 2 com
pares the cumulative recovery versus time with
the balanced-line RF pattern (RF) of the present
invention arranged according to Figure 1, com
pared with a 7-spot pattern shown in a thermal
conduction (TC) patent with 50 feet between
wells. The axis on the right side of Figure 2 indi
cates the injection rate in millions of BTU per day
per acre. The injection rate for the thermal con
duction 7-spot pattern is indicated by the broken-
TC."
line having solid dots and labeled The injec
tion rate for the balanced-line device according
to the present invention is indicated by the
broken-line having open squares and labeled
"RF."
For the simulation it is assumed that the repeat
ing
pattern is 0.226 acres in area. The original oil
in place is 255.2 thousand barrels per pattern.
The working portion of the wells, known as the
completion interval, extends from 762 feet to
1,560 feet for both production wells and
electrodes. The total well depth is 1,560 feet.
Radiofrequency
power at 1 MHz is utilized and
standing waves on the electrodes have been sup
pressed using distributed capacitive loading.
In Table 1 (next page), the production of a single
pattern of wells according to the present inven
tion Is shown over the life of the wells. Also
shown is the cumulative power required to
produce the oil.
In the RF process, heat can be injected at twice
the rate of the thermal conduction process, as
shown in Figure 2 leading to a speeding up of the
halfway
The balanced-line radiofrequency
point of the process from 12 to 6 years.
pattern of the
present invention would require roughly half as
many wells as would the thermal conduction heat
ing process.
2-17
In comparing
the triplate pattern with the
balanced-line RF array, the advantages of the
present invention are:
- The
- The
- The
- There
voltage relative to ground for the
balanced-line is half that of the triplate
device.
required power per well for the
triplate device is twice that of the
balanced-line.
maximum temperature at the produc
tion wells is significantly hotter for the
triplate device (460C versus 350C).
can be RF leakage outside the
triplate device to distant grounds. This
leakage will not occur with the balanced-
line.
####
IGT PATENTS OIL SHALE PRETREATING
PROCESS
United States Patent 5,277,796, issued to
S. Chao and assigned to the Institute of Gas
Technology, reveals a process for contacting par
ticles of oil shale prior to retorting with organic
acids, such as formic acid or acetic acid, at am
bient temperatures or temperatures below about
100C for a time sufficient to react with at least a
portion of the mineral carbonates in the shale.
The organic acid is separated from the shale
prior to retorting by decantation, centrifugation or
filtration resulting in shale for retorting which has
a decreased carbonates content. Upon subse
quent retorting, the oil shale pretreated accord
ing to the process of this invention results in
higher carbon conversion and increased liquid
and aromatic product fraction recovery, as com
pared to untreated shale.
In another embodiment, high carbonate content
oil shale, such as Western United States oil shale,
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
TABLE 1
OIL SHALE RF HEATING FORECASTS
(Without Standing Waves and Current Decay)
Time Cum Oil Recovery Cum Water Cum Gas Fluid Cum Elec.
(Years) (kbbis) f%OOIP> (kt?bl?) (Mscf) Temo. rF) (kW-hr)
1 0.15 0.06 12.35 0.17 112 7.20E+06
2 1.40 0.55 24.79 1.68 151 1.44E + 07
3 14.44 5.66 26.01 17.32 204 2.16E + 07
4 45.22 17.72 28.87 54.27 267 2.88E + 07
5 75.92 29.75 31.72 91.11 336 3.60E + 07
6 107.46 42.11 34.66 128.86 409 4.21E + 07
7 131.73 51.62 36.92 158.08 466 4.32E + 07
8 150.31 58.90 38.64 180.38 506 4.32E + 07
9 163.99 64.26 39.92 196.79 533 4.32E + 07
10 171.49 67.20 40.61 205.79 550 4.32E + 07
11 176.57 69.19 41.09 211.89 561 4.32E + 07
12 179.89 70.49 41.39 215.87 568 4.32E + 07
13 181.98 71.31 41.59 218.38 571 4.32E + 07
14 183.90 72.06 41.77 220.68 573 4.32E + 07
15 185.63 72.74 41.93 222.76 575 4.32E + 07
16 187.21 73.36 42.07 224.66 575 4.32E + 07
17 188.64 73.92 42.21 226.37 575 4.32E + 07
18 189.95 74.43 42.33 227.93 575 4.32E + 07
19 191.12 74.89 42.44 229.34 574 4.32E + 07
20 191.12 74.89 42.44 229.34 574 4.32E + 07
is additionally contacted with a strong inorganic
acid, such as hydrochloric acid, in the pretreat
ment.
In the preferred embodiment, the reaction water
and organic acid leachate is reacted with sulfuric
acid and distilled to produce a liquid containing
the corresponding organic acid which may be
recycled to contact fresh oil shale.
Carbon dioxide liberated during the organic acid
pretreatment can be reduced to carbon
monoxide which can be absorbed into a
hydroxide solution and subsequently distilled
2-18
with sulfuric acid to produce formic acid for use
in the pretreatment process.
Oil shale subjected to the pretreatment process
of this invention has reduced mineral carbonates
content, increased porosity and increased sur
face area providing increased permeability and
potential reaction surface area for further reac
tion. The process requires little energy, thermal
or mechanical, and is claimed to be economical
because the principal treating agent, an organic
acid such as formic acid or acetic acid, can be
readily and efficiently
recovered for recycle.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
To carry out the process, oil shale is ground to a
size desired for retorting, under about one-
eighth-inch average largest dimension. The
ground shale may be added to any suitable
means of good liquid/solid contact for contact
ing with an organic acid.
The low molecular weight organic acid,
preferably formic acid, acetic acid and mixtures
of formic and acetic acids, is used in liquid form
and is preferably in an aqueous solution having a
pH value of less than 3. Formic acid and acetic
acid are relatively strong organic acids which
readily react with oil shale carbonates to form car
bon dioxide and water-soluble formate and
acetate salts, respectively. Preferred amounts of
organic acid are about 2 to about 20 weight per
cent of the oil shale pretreated.
Contacting
times of about 1 to 3 hours are
preferred, depending upon the type of mixing
reactor employed. At least periodic agitation is
necessary to obtain effective pretreatment within
a reasonable time period.
Pretreatment of oil shale prior to retorting by the
process of this invention is said to provide oil
shale for subsequent retorting or hydroretorting
which results in higher carbon conversion, par
ticularly
in oil shales which are recalcitrant to
retorting, and increased total liquid recovery with
higher aromatic and heavy fractions, as com
pared to retorting the same non-pretreated shale.
Example
One hundred thirty
grams of Tennessee Gas-
saway (Eastern U.S.) oil shale, previously riffled
and ground to 8-20 mesh was contacted with
100 milliliters of 5 percent aqueous formic acid
solution for 2 hours at ambient temperatures with
occasional stirring. The oil shale was separated
from the liquid and air dried following which
100 grams of the pretreated oil shale was
hydroretorted under a hydrogen pressure of
1,000 psig and temperature to 1,000F. The total
recovery
of organic carbon from the formic acid
pretreated oil shale was 76.9 percent compared
to 67.9 percent for the same oil shale subjected
2-19
to the same hydroretorting without any pretreat
ment.
The same oil shale was also pretreated using
acetic acid instead of formic acid under the same
conditions followed by hydroretorting
under the
same conditions and resulted in total recovery of
organic carbon of 78.2 percent as compared to
67.9 percent for the same oil shale subjected to
the same hydroretorting without any pretreat
ment.
####
INTERNATIONAL
OIL SHALE TO PLAY ROLE IN ISRAEL'S
ENERGY BALANCE
History
An article in Energia by T. Minster of the Geologi
cal Survey of Israel discusses the oil shales of Is
rael. As most of the oil shale deposits are lo
cated in the subsurface, their historical impact
can be supposed to be marginal. However, it is
accepted by most scientists that the asphalts
found in the Dead Sea region are related to the
oil shale sequences which frequently outcrop
along the basin perimeter and are believed to
underlie the region at great depths (Figure 1).
Asphalt shows in the Dead Sea area are both in
surface seepages (also penetrated in boreholes)
and as pure floating blocks (less dense than the
salt saturated waters) found on the shores. This
raw material is known to have been used by
mankind for at least 10,000 years. Archaeologi
cal findings revealed its use in decoration, cult
objects, cementing, waterproofing and
adhesives. Roman and Medieval literature indi
cate other applications, e.g., agriculture, boat
crafting, medicine and mummification. It was
even used in the early days of photography. In
1822 Joseph Niepce took the first photograph of
nature using Dead Sea asphalt, by exposing a
metal plate (containing an image) covered with
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
,
FIGURE 1
MAP OF MAIN OIL SHALE
OCCURRENCES IN ISRAEL
Haifa
0* Stab Dapoaa
S\ CM Shale Dapoa/t f>
v' Unda> kwaatigalian J
j
p ' *1
JL
% I
1
a CM Snafc Occurences
Preliminary Data /
l\
y
10 ( * J
CO / "
/
* / C Te' AwI
/& Yato/J
*
r
.*? j
$ / V* /
j
1
1
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I
1
J
/
\
i a 5'A
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j
/
W'
/ / '
/6 / / / / z
/ 1 i
/ \ ! f <
J ) Q
\ 1 tt
Beef Sneva'
A^
i
V 12
\
soURCE: MMSTER
*9
ii/10
Jl?0
/A O
"*
W
1 yf\ 4 I 1 Shalar-am
*\ A 14(Y #V >9 j 2 **'
i
~7"~
\
\
,J
l
II /
4 MaOera
S Natx-Muu
/V / 6 ShalalaKartuv
I ^
''J).'
^/
t Nevatim
V Aroar
)
0,B;
181,
10 MmmRaMm
11 Miahoi Yamm
12 Varoham
\ 13 Oon
A i
14 BiqalZin
10/ IS Shrvta
\
* 16 NanalZin
\ V
\
\
i
/
17. NahaiAnva
16 HarNisnpe
IS Paran
20 Zemfim
bitumen to sunlight. The Dead Sea asphalts are
the "oil"
probably
thought to have had a significant economical and
of the Bible. The commodity is
political role in the days of the Nabataean
Kingdom (4-1 centuries B.C.) and its contact with
Egypt, the Greeks and the Romans.
Quarrying activity
signs in the Nabi-Musa
deposit, traced also in old air photos, represent
some uses of in situ oH shales in the past. Ex
posed material was and is stiil used in limited
2-20
domestic nomads and as
a soft building stone. 01 shales from Ein Boqeq
amounts for heating by
were successfully applied as a construction
material for potash evaporation ponds in the
southern part of the Dead Sea. A domestically
metamorphosed derivative of the oil shale host
rocks is used as an ornamental building stone,
especially
in terrazzo making.
Israel's Energy Scene
Israel's 1993 total energy consumption was es
timated to be around 12,500 TTOE (= x 1,000
Tons of Oil Equivalent). Most of the energy is
produced from imported crude oil and coal.
The main revolution which has occurred in the Is
raeli energy market since 1980 is the diversifica
tion of electricity generation from a complete de
pendence on crude oil to more than 60 percent
utilization of coal last year. This change was due
to a concerted effort to secure energy resources
from a host of geographical areas. The domestic
energy policy of diversification is aimed at
guaranteeing energy resources in the future.
The proven and estimated reserves of oil shale
are significant. Oil shale sequences may underlie
10-15 percent of the country's area. This equates
to hundreds of billions of tons of organic-
enriched material. Potential oil equivalent of
these reserves could meet domestic energy re
quirements for many centuries.
Potentially negative properties of the Israeli oil
shales, from an industrial point of view are-a low
to medium organic carbon content
(6-17 percent) and thus substantial amounts of
ash generated; relatively high moisture
(approximately 20 percent); significant carbonate
content (45-70 percent calcite) and a relatively
high sulfur content. However, a positive and cru
cial point is the low mining costs estimated for
some of the deposits.
Research
The energy crisis brought about by the 1973 oil
embargo served to focus attention on domestic
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
oil shale research. Energy-related activities since
then include: a producing 12 megawatt combus
tion plant; an active research center (in Mishor
Rotem); an experimental oil shale retorting unit;
and initiating construction on a 75 megawatt
power station. It is speculated that by the
year 2000, some 22 percent of the alternative and
indigenous domestic energy production will be
from oH shales. One almost certain outcome of
wide-scale oil shale mining and processing will
be the development and utilization of bituminous
phosphorite deposits which are associated with
the oH shales. In certain locales, these deposits
are both high grade and extensive.
According to Minster, there is still a great amount
of applied research which needs to be done on
Israel's oil shale resources, especially concerning
their distribution, processing behavior and grade.
There are indications of bituminous sequences
from boreholes which were never examined for
energy content, such as the recent finding in the
I) COTC
FIGURE 1
Kineret (Sea of Galilee) basin. Further plans for
oil shale research and for utilization include: com
bustion, retorting, cement production, paving as
phalts, light-weight construction materials, ash
utilization and bituminous phosphorites beneficia
tion.
####
OIL SHALES OF MOROCCO ARE SUBJECT
OF DOCTORAL THESIS
A 1994 dissertation by 0. Bekri for the degree
Docteur Es Sciences at Morocco's Unfversite
Mohammed V is a study of the oil shale deposits
at Timahdit and Tarfaya. The geological setting
for these deposits is illustrated in Figure 1 .
An estimate of recoverable reserves of oil is given
in Table 1 .
GEOLOGY OF THE OIL SHALE DEPOSITS OF TIMAHDIT AND TARFAYA
SYNCLINAL D ANCUEUR ANTICLINAL DC MAYANE
[timahdit |
SYNCLINAL OE HOUBBAT
[V7>ASAITS J23 eOHGMCS ^CALCUMACMELOl*^ ALTER. CAICAKCS-WCS EC """ "0ES B.TUM.NEUSES
WH M0GHRE8IEN CRAIES ]JJ BITOMINEUSES CARBONATES
SOURCE: BEKRI
2-21
[tarfaya )
SteKHA*
HOUIStlCUA
DUNES DC SABLE
^*l
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
Timahdit
TABLE 1
RESERVE ESTIMATES
Medium High Total
G^de Grade Deposit
Thickness, meters 85 30 150
Tons of Shale, million 3,250 620 42,000
Oil Yield, liters/ton 70 85 62.5
Oil Reserves, million tons 215 50 2,495
Tarfaya
Thickness, meters 13 13 33
Tons of Shale, million 8,850 6,236 80,000
Oil Yield, liters/ton 65 72 55
Oil Reserves, million tons 656 371 3,690
An item of special significance, pointed out in the in Figure 2, these shales respond especially well
doctoral study, is the response of Morocco oil to retorting in a fluidized bed retort. ap- Yields
shales to different retorting techniques. As seen preciably above Fischer Assay can be achieved.
2-22
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
14
12
10
CO
2 8
o>
CL
5=
SOURCE: BEKRI
FIGURE 2
OIL YIELDS BY DIFFERENT RETORTING METHODS
E3 Fischer Assay Q Nitrogen Sweep ^
Z=7^
Tarfaya R3
dm^m-
Bed Fluidized
ZS7
lA
?
Tarfaya R4 Timahdit M
####
2-23
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SHALE
2-24
THE SYNTHETIC FUELS REPORT, JANUARY 1995

- ACORN PROJECT (See
STATUS OF OIL SHALE PROJECTS
COMMERCIAL PROJECTS (Underline denotes changes since June 1994)
Stuart Oil Shale Project)
- CHATHAM CO-COMBUSTION BOILER New
Brunswick Electric Power Commission (S-30)
Construction on the Chatham circulating bed demonstration project was completed in 1986 with commissioning of the new
boiler. A joint venture of Energy, Mines and Resources Canada and the New Brunswick Electric Power Commission, this
project consists of a circulating fluidized-bed boiler of Lurgi design that supplies steam to an existing 22-MW turbine genera
tor. High-sulfur coal was co-combusted with carbonate oil shales and also with limestone to compare the power generation and
economics of the two cocombustants in the reduction of sulfur emissions. A full capacity performance-guarantee test was
carried out in May 1987, on coal, lime and oil shale. Testing with oil shale in 1988 showed shale to be as effective as limestone
per unit of calcium contained. However, bulk quantities of oil shale were found to have a lower calcium content than had been
expected from early samples. No further oil shale testing is planned until further evaluations are completed.
Since January 1993, the unit has been operated as a stand-by unit on coal and limestone. It is also available for co-combustion
tests if desired.
- CLEAR CREEK PROJECT Chevron
Shale Oil Company (70 percent) and Conoco, Inc. (30 percent) (S-40)
Chevron and Conoco successfully completed the operation of their 350 tons per day semi-works plant during 1985. This facility,
which was constructed on property adjacent to the Chevron Refinery in Salt Lake City, Utah, was designed to test Chevron
Research Company's Staged Turbulent Bed (STB) retort process. Information obtained from the semi-works project would al
low Chevron and Conoco to proceed with developing a commercial shale oil operation in the future when economic conditions
so dictate.
Chevron and Conoco have joined with Lawrence Livermore National Laboratory (LLNL), DOE and other industrial parties to
participate in a 3 year R&D project involving LLNL's Hot Recycled Solids oil shale process. Information obtained from this
project may result in refinements to the STB process.
Chevron is continuing to develop and protect its conditional water rights for use in future shale oil operations at its Clear
Creek and Parachute Creek properties.
- Project Cost: Semi-Works Estimated at $130 million
- CONDOR PROJECT Central
- - Pacific Minerals 50 percent; Southern Pacific Petroleum 50 percent (S-60)
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.
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 consists of the Japan National Oil Corporation and 40 major Japanese
companies. The 28 month was study conducted by an engineering team staffed equally by the Japanese and Australian par
ticipants 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 indicated that such a plant would have involved a capital cost of US$2,300 million
and an annual average operating cost of US$265 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.
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 bar
rels, 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 en
visages four retort modules, each processing 50,000 tons per day of shale, to give a total capacity of 200,000 tons per day and a
sweet shale oil output, after upgrading, of 82,100 barrels per day.
2-25
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
Raw shale oil from the retort would require further treatment to produce a compatible oil refinery feedstock. Two
41,000 barrels per day upgrading plants are incorporated into the project design.
All aspects of infrastructure supporting such a project were studied, including water and power supplies, work force accom
modation, community services and product transportation. A 110 kilometer pipeline to the port of Mackay is favored for trans
fer of product oil from the plant site to marine tankers. The study indicated that there were no foreseeable infrastructure or
environmental issues which would impede development.
Market studies suggested that refiners in both Australia and Japan would place a premium on Condor shale oil of about US$4
per barrel over Arabian Light crude. Average cash operating cost at full production was estimated at US$20 per barrel of
which more than US$9 per barrel represents corporation taxes and royalty.
During July 1984 SPP, CPM, and JAOSCO signed an agreement with Japan Oil Shale Engineering Corporation (JOSECO).
JOSECO is a separate consortium of thirty-six Japanese companies established with the purpose of studying oil shale and
developing oil shale processing technology. Under the agreement, SPP/CPM mined 39,000 tons of oil shale from the Condor
deposit, crushed it to produce 20,000 tons and shipped it to Japan in late 1984.
JOSECO commissioned a 250 tonne per day pilot plant in Kyushu in early 1987. The Condor shale sample was processed satis
factorily in the pilot unit.
In 1988 SPP/CPM began studies to assess the feasibility of establishing a semi-commercial demonstration plant at
retorting
Condor similar to that being designed for the Stuart deposit. Samples of Condor shale were shipped to Canada for testing in
the Taciuk process.
Project Cost: $2.3 billion (mid-1983 U.S. dollars)
- ESPERANCE OIL SHALE PROJECT Esperance
Minerals NL and Greenvale Mining NL (S-70)
In 1991 Esperance Minerals and Greenvale Mining announced they are planning to produce 200,000 tons per year of
"asphaltine"
for bitumen from the Alpha torbanite deposit in Queensland, Australia. The two companies believe they can
produce bitumen that will sell for more than US$80 per barrel.
The Alpha field contains about 90 million barrels of reserves, but the shale in this deposit has a high yield of 88 to 132 gallons
of oil per ton of shale.
Recent studies have concluded that using new technologies to produce a bitumen-based product mix would be the most
economically beneficial. Byproducts could include diesel fuel and aromatics.
ESTONIA POWERPLANTS - Estonian
Republic (S-80)
Two oil shale-fueled powerplants, the Baltic with a capacity of 1,435 megawatts and the Estonian with a capacity of
1,600 megawatts, are in operation in the Estonia. These were the first of their kind to be put into operation.
About 95 percent of the oil shale output from the former USSR comes from Estonia and the Leningrad districts of Russia.
Half of the extracted oil shale comes from surface mines, the other half from underground workings. Each of the nine under
ground mines outputs 3,000 to 17,000 tons per day, each of the surface mines outputs 8,000 to 14,000 tons per day.
Exploitation of kukersite (Baltic oil shale) resources was begun by the Estonian government in 1918. In 1980, annual produc
tion of oil shale in the USSR reached 37 million tons of which 36 million tons come from the Baltic region. Recovered energy
from oil shale was equivalent to the energy in 49 million barrels of oil. Most extracted oil shale is used for power production
rather than oil recovery. In 1989, annual production of oil shale in the Baltic region was as low as 28 million tons. In 1993. an
nual production of oil shale in Estonia was 16.5 million tons. About 10 million tons were extracted from six underground
mines and about 9 million tons from three open pit mines. The annual output from the underground mines ranged from
600,000 to 4.3 million tons, while the output from the surface mines ranged from 2.0 to 4.3 million tons. The recovered energy
from this oil shale was the energy equivalent of 25 million barrels of oil.
Most extracted oil shale (85 percent) is used for power production rather than oil recovery. More than 60 percent of Estonia's
thermal energy demand is met by the use of oil shale. Fuel gas production was terminated in 1987.
Pulverized oil shale ash is being used in the cement industry and for acid soil melioration.
2-26
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
FUSHUN COMMERCIAL SHALE OIL PLANT- Fushun Petrochemical Corporation, SINOPEC, Fushun, China (S-90)
The oil shale retorting industry in Fushun, China began in 1928 and has been operating for 60 years. Annual production of
shale oil topped 780,000 tons in 1959. In that period, shale oil accounted for 30-50 percent of total oil production in China.
At Fushun, oil shale overlies a coal bed which is mined. being Because the oil shale must be stripped in order to reach the
coal, it is economical to retort the shale even though it is of low grade. Fischer yield Assay is about 5.5 percent oil, on average.
Currently, only 40 retorts are operating, each retort processing 200 tons of oil shale per day. Other retorts have been shut
down because of site problems not related to the operation of the retorts. Shale oil production is on the order of 100,000 tons
per year.
Direct combustion of oil shale fines in an ebullated bed boiler has been tested at Fushun Refinery No. 2.
Shale oil is currently being used only as a boiler fuel, but a new scheme for upgrading Fushun shale oil has been studied. In the
proposed scheme, shale oil is first treated by exhaustive delayed coking to make light fractions which are then treated succes
sively
with dilute alkali and sulfuric acid to recover the acidic and basic non-hydrocarbon components as fine chemicals. The
remaining hydrocarbons, containing about 0.4 percent N can then be readily hydrotreated to obtain naphtha, jet fuel and light
diesel fuel. This scheme is said to be profitable and can be conveniently coupled into an existing petroleum refinery.
- ISRAELI RETORTING DEVELOPMENT (See
- JORDAN OIL SHALE PROJECT Natural
PAMA Oil Shale-Fired Powerplant Project)
Resources Authority of Jordan (S-110)
Jordan's oil shale deposits are the country's major hydrocarbon resource. Near-surface deposits of Cretaceous oil shale in the
Iribid, Karak, and Ma'an districts contain an estimated 44 million barrels of oil equivalent.
In 1986, a cooperative project with Romania was initiated to investigate the development of a direct-combustion oil-shale-fired
powerplant. Jordan has also investigated jointly with China the applicability of a Fushun-type plant to process 200 tons per day
of oil shale. A test shipment of 1,200 tons of Jordanian shale was sent to China for retort testing. Large-scale combustion tests
have been carried out at Kloeckner in West Germany and in New Brunswick, Canada.
A consortium of Lurgi and Kloeckner completed in 1988 a study concerning a 50,000 barrel per day shale oil plant operating on
El Lajjun oil shale. Pilot plant retorting tests were performed in Lurgi's LR pilot plant in Frankfurt, Germany.
The final results showed a required sales revenue of $19.10 per barrel in order to generate an internal rate of return on total
investment of 10 percent. The mean value of the petroleum products ex El Lajjun complex was calculated to be $21.40 per bar
rel. At that time a world oil price of $15.60 per barrel was needed to meet an internal rate of return on total investment of 10
percent.
In 1988, the Natural Resources Authority announced that it was postponing for 5 years the consideration of any commercial oil
shale project.
- KIVrTER PROCESS Estonian Republic (S-120)
The majority of oil shale (kukersite) found in Estonia is used for power generation. However. 2.3 to 2.6 million tons have been
retorted to produce shale oil and gas. The Kiviter process, continuous operating vertical retorts with crosscurrent flow of heat
carrier gas and traditionally referred to as 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. Retorting is performed in a single retorting (semi-
coking) chamber. In the generators, low temperature carbonization of kukersite yields 75 to 80 percent of Fischer assay oil.
The yield of low calorific gas (3,350 to 4,200 KJ/cubic meters) is 450 to 500 cubic meters per ton of shale.
To meet the needs of re-equipping of the oil shale processing industry, a new generator was developed. The first 1,000 ton-
per-day (TPD) generator of this type was constructed at Kohtla-Jarve, Estonia 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 semicoking
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. The outside diameter of the retort is 9.6 meters, and its height is 21 meters. The operation
of the 1,000 ton per day generator revealed a problem of carry-over of finely divided solid particles with oil vapors (about 8 to
10 kilograms per ton of shale).
2-27
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
The experience of the 1,000 TPD unit was taken into consideration to design two new units. In January, 1987, two new 1,000
TPD retorts were put in operation also at Kohtla-Jarve. Alongside these units, a new battery of four 1,500 TPD retorts, with a
new circular chamber design, is under construction. Oil yield of 85 percent of Fischer Assay is expected. The construction of
an installation comprising four 1,500 ton per day prototype generators with a circular chamber started at
semicoking Kohtla-
Jarve in 1988. At present, however, the construction has been suspended due to investment problems.
Oil from kukersite has a high content of oxygen compounds, mostly resorcinol series phenols. Over 50 shale oil products
(predominantly non-fuel) are currently produced. These products are more attractive economically than traditional fuel oil.
The low calorific gas produced as byproduct in the gas generators has a hydrogen sulfide content of 8 to 10 grams per cubic
meter. After desulfurization, it is utilized as a local fuel for the production of thermal and electric power.
Pulverized oil shale ash is also finding extensive use in the fertilizer and cement industries.
Project Cost: Not disclosed
MAOMING COMMERCIAL SHALE OIL PLANT -
(S-130)
Maoming Petroleum Industrial Corporation, SINOPEC, Maoming, China
Construction of the Maoming processing center began in 1955. Oil shale is mined by open pit means with power-driven
shovels, and electric locomotives and dump-cars. Current mining rates are 35 million tons of oil shale per year. Ap
proximately one-half is suitable for retort feed. The Fischer Assay of the oil shale averages 65 percent oil yield.
Two types of retort are used: a cylindrical retort with a gasification section, and a rectangular gas combustion retort. Oil shale
throughput is 150 and 185 tons per day per retort, respectively. The present facility consists of two batteries containing a total
of 48 rectangular gas combustion retorts and two batteries with a total of 64 cylindrical retorts.
Production at Maoming has been approximately 100,000 tons of shale oil per year. Although the crude shale oil was formerly
refined, it is now sold directly as fuel oil. The shale ash is also used in making cement and building blocks.
A 50 megawatt powerplant burning oil shale fines in three fluidized bed boilers has been planned and detailed compositional
studies of the Maoming shale oil have been completed. These studies can be used to improve the utilization of shale oil in the
chemical industry.
- MOBIL PARACHUTE SHALE OIL PROJECT Mobil
Oil Corporation (S-140)
Mobil has indefinitely deferred development plans for its shale property located on 12.000 acres five miles north of Parachute.
The United States Bureau of Land Management completed the Environmental Impact Statement for the project in 1986.
- MOROCCO OIL SHALE PROJECT ONAREP,
Royal Dutch/Shell (S-150)
During 1975 a drilling and mining survey revealed 13 oil shale deposits in Morocco, including three major deposits at Timahdit,
Tangier, and Tarfaya from which the name T3 for the Moroccan oil shale retorting process was derived.
In February 1982, the Moroccan Government concluded a $45 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 faced constraints of low oil prices and the relatively low grade of oil shale.
Construction of a pilot plant at Timahdit was completed with funding from the World Bank in 1984. During the first quarter
of 1985, the plant went 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 were conducted to prove the process feasibility as well as to optimize the process conditions. The pilot plant
utilizes the T3 process developed jointly by Science Applications, Inc., and the Office National de Recherche et d'Exploitation
Petrolieres (ONAREP) of Morocco. The 73 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 gallons per ton 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. A commercial scale mine development at study Timahdit was 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 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.
2-28
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
The project, inactive for some time, began being reconsidered in 1990 by the equal partners. The viability of a 50,000 barrel
per day plant that would process 60 million tonnes of shale is under examination. ONAREP expects the cost of development
to be around $24-25 a barrel.
Project Cost: $25 billion (estimated)
- OCCIDENTAL MIS PROJECT Occidental
Oil Shale, Inc. (S-20)
Federal Oil Shale Lease Tract C-b, located in Rio Blanco County in the Piceance Creek Basin of northwestern Colorado, is
managed by Occidental Oil Shale, Inc. A modified detailed development plan for a 57,000 barrels per modified day in situ
plant was submitted in March 1977 and subsequently approved in April 1977. The EPA issued a conditional Prevention of Sig
nificant 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 in
terest 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 an
nounced 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.
Three headframes-two concrete and one steel-have been erected. Four new structures were completed in 1982: control room.
east and west airlocks, and mechanical/electrical rooms. The power substation on-tract became operational in 1982. The
ventilation/escape, service, and production shafts were completed in Fall 1983. An interim monitoring program was approved
in July 1982 to reflect the reduced level of activity.
Water management in 1984 was achieved via direct discharge from on-tract holding ponds under the NPDES permit. Environ
mental monitoring has continued since completion of the two-year baseline period (1974-1976).
On April 1, 1987, the Bureau of Land Management, United States Department of the Interior, granted Cathedral Bluffs Shale
Oil Company a suspension of operation and production for a minimum of five years. Meanwhile, of pumping the mine inflow
water continued in order to keep the shaft from being flooded.
Although Congress appropriated $8 million in fiscal year 1991, Occidental declined to proceed with the $225 million "proof-
of-concept"
modified in situ (MIS) demonstration project to be located on the C-b tract. In January 1991 Occidental an
nounced its intention to shelve the demonstration project in an effort to reduce company debt. The announcement came only
a month after the death of Oxy chairman, Armand Hammmer, a long-time supporter of oil shale.
The project was to be a 1,200 barrel per day demonstration of the modified in situ (MIS) retorting process. Estimates indicate
that there are more than 4.5 billion barrels of recoverable oil at the site. Also included in the project were plans for a
33 megawatt oil shale fired powerplant to be built at the C-b tract. Such a powerplant would be the largest of its kind in the
world.
At the end of the demonstration period, Occidental had hoped to bring the plant up to full scale commercial production of
2500 barrels of oil per day.
Project Cost: $225 million for demonstration
- PAMA OIL SHALE-FIRED POWERPLANT PROJECT PAMA (Energy Resources Development) Inc. (S-270)
PAMA, an organization founded by several major Israeli corporations with the support of the government, has completed ex
tensive studies, lasting several years, which show that the production of power by direct combustion of oil shale is technically
feasible. Furthermore, the production of power still appears economically viable, despite the uncertainties regarding the
economics of production of oil from shale.
PAMA has, therefore begun a direct shale-fired demonstration program. A demo plant has been built that is in fact a commer
cial plant, co-producing electricity to the grid and low pressure steam for process application at a factory adjacent to the Rotem
oil shale deposit. The oil-shale-fired boiler, supplied by Ahlstrom, Finland, is based on a circulating fluid bed technology.
The 41 megawatt plant is a cogeneration unit that delivers 50 tons per hour of steam at high pressure. Low-pressure steam is
sold to process application in a chemical plant, and electricity produced in a back-pressure turbine is sold to the grid. Commis
sioning was begun in August 1989 and oil shale firing began in October. Process steam sales began in November 1989 and
electricity production started in February, 1990.
PAMA and Israel Electric (the sole utility of Israel) have also embarked on a project to build a full scale oil shale-fired com
mercial powerplant. The first 75 megawatt unit is scheduled to go into operation in 1999.
2-29
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
PAMA has been developing a Fast-Heating Retorting Process, using hot recycled ash as the heat carrier. Tests have been
carried out in a 50 kilogram per hour experimental unit. Work has been started on a 6 ton per hour pilot plant, with startup
scheduled for mid-1996.
Project Cost: $30 million for combustion demonstration plant
$8 million for retorting pilot plant
PARACHUTE CREEK - SHALE OIL PROJECT UNOCAL
Corporation (S-160)
In 1920 Unocal began acquiring oil shale properties in the Parachute Creek area of Garfield County, Colorado. The
49,000 acres of oil shale lands Unocal owns contain over three 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 I 10,000 barrel per day project in March 1978. All federal, state, and local
permits were received by early 1981. Necessary road work began in the Fall 1980. Construction of a 12,500 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. After several years of test
operations and resulting modifications, Unocal began shipping upgraded syncrude on December 23, 1986.
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. The price was to be the market price or a contract floor
price. If the market price is below the DOE contract floor price, indexed for inflation, Unocal would receive a payment from
DOE to equal the difference. The total amount of DOE price supports Unocal could receive was $400 million. Unocal began
billing the U.S. Treasury Department in January, 1987 under its Phase I support contract.
In a 1985 amendment to the DOE Phase I contract, Unocal agreed to explore using fluidized bed combustion (FBC) technol
ogy at its shale plant. In June 1987, Unocal informed the U.S. Treasury Department that it would not proceed with the FBC
technology. A key reason for the decision, the company said, was the unexpectedly high cost of the FBC facility.
In 1989, a new crusher system was installed which produces a smaller and more uniform particle size to the retort. Also, retort
operations were modified and the retorting temperature increased. As a result, production in November and December
reached approximately 7,000 barrels per day.
At year-end 1990, Unocal had shipped over 4.5 million barrels of syncrude from its Parachute Creek Project. Unocal an
nounced the shale project booked its first profitable quarter for the first calendar quarter of 1990. Positive cash flow had been
achieved previously for select monthly periods; however, this quarter's profit was the first sustained period of profitability.
Cost cutting efforts further lowered the breakeven point on operating costs approximately 20 percent.
In 1990, the United States Department of Treasury found no significant environmental, health or safety impacts related to the
operations of Parachute Creek. Monitoring will continue through 1992.
On March 26, 1991, Unocal announced that production operations at the facility would be suspended because of failure to con
sistently reach the financial break-even point. Production ended June 1, 1991 and the project has been terminated.
-
Project Cost: Phase I Approximately $1.2 billion
- PETROSIX Petrobras
(Petroleo Brasileiro, SA.) (S-170)
A 6 foot inside diameter retort, called the demonstration plant, has been in continuous operation since 1984. The plant is used
for optimization of the Petrosix technology. Oil shales from other mines can be processed in this plant to obtain data for the
basic design of new commercial plants.
A Petrosix pilot plant, having an 8 inch inside diameter retort, has been in operation since 1982. The plant is used for oil shale
characterization and retorting tests and developing data for economic evaluation of new commercial plants.
An entrained bed pilot plant has been in operation since 1980. It is used to develop a process for the oil shale fines. The plant
uses a 6 inch inside diameter pipe (reactor) externally heated. Studies at the pilot scale have been concluded.
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SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
A spouted bed pilot plant having a 12-inch diameter reactor, has been in operation since January, 1988. It processes oil shale
fines coarser than that used in the entrained bed reactor. Studies at the pilot scale have been concluded.
A multistaged fluidized bed pilot plant having an 8x8 inch square section was operated at Centec. Studies at this scale have
been concluded.
A circulating fluidized bed pilot scale boiler was started up in July, 1988. The combustor will be tested on both spent shale
and oil shale fines to produce process steam for the Petrosix commercial plants. Studies at the pilot plant have been con
cluded.
In the present days the efforts of R&D have been directed to some studies in environmental areas and mainly to increase value
to oil shale products and byproducts. The main studies are:
- Asphalts
- Retort
- Retort
and asphalts additives
water for agriculture
shale for ceramic, cement, glass, etc.
- Solvent
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, produced 850 barrels per day
of crude oil. 40 tons per day of fuel gas, and 18 tons per day of sulfur. The operating factor since 1981 until present has been
93 percent.
As of December 31, 1994, the plant records were as follows:
Operations time, hrs 151.800
Oil Produced, Bbl 4.122.544
Processed Oil Shale, tons 9.141.895
Sulfur Produced, tons 78.813
High BTU Gas, tons 162,146
A 36-foot inside diameter retort, called the industrial module M-l. has been constructed at Sao Mateus do Sul. Startup began in
December 1991. Total investment was US$93 million with an annual cost estimated operating to be US$39 million. Since start-up,
retorting rate has reached 100% of projected capacity.
With the 36-foot (11-meter) diameter commercial plant, the daily production of the two plants will be:
Shale Oil 3,870 Bbl
Processed Shale 7,800 tons
LPG 50 tons
High BTU Gas 132 tons
Sulfur 70 tons
The technologies developed to reduce environmental impacts of the oil shale mining operations have been applied to reclaim about
200 ha of mined areas. Disposition of oil shale residues involves its placement in-pit followed by immediate surface reclamation
using stripped overburden materials. Rehabilitation comprises revegetation. using native forest species or local forage plants, and
reintegration of wild life, bringing back the local conditions for farming and preservation. Monitoring programs have been carried
out collecting data on amhiental air and waters (surface and groundwater). Results indicate that no significant environmental im
pact has occurred, according to the federal and state regulations.
Treatment of the shale oil involves centrifuging and filtering to remove solids and water. The oil product is then fractionated in
two fractions: naphtha and bottoms. The naphtha fraction is sent by truck to a refinery where it is processed in a FCC Unit. The
bottoms are also processed in a refinery, to dilute the fuel oil, or is sold as the fuel oil directly to the industries. The fuel gas has
been sold to Ceramic Industry, four kilometers away from the Petrosix Plant. LPG production is sold directly to industries or to
retailing distributor. Sulfur production is sold directly to clients from local paper mill and sugar industries.
Project Installed Costs: $120 (US) million
RAMEX OIL SHALE GASIFICATION PROCESS-Greenway Corporation and Ramex Synfuels International, Inc. (S-180)
On May 6, 1985 Ramex began construction of a pilot plant near Rock Springs, Wyoming. The pilot plant consisted of two specially
designed burners to burn continuously in an underground oil shale bed at a depth of 70 feet. These burners produce an industry
gas quality (greater than 800 BTUs per standard cubic foot).
2-31
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
In November 1986, Ramex announced that Greenway Corporation had become the controlling shareholder in the company.
On November 24, 1987, Ramex announced the completion of the Rock Springs pilot project. The formation was heated to ap
a high-BTU gas with little or no liquid condensate. The wells sustained 75 Mcf a day, for a
proximately 1200 degrees F creating
period of 3 months, then were shut down to evaluate the heaters and the metals used in the manufacturing of the heaters. The test
results indicated a 5 year life in a 10 foot section of the shale with a product gas of 800 BTU, or higher, per standard cubic foot.
Ramex also announced in November 1987 the start of a commercial production program in the devonian shale in the eastern states
of Kentucky and Tennessee. In April 1988, however, Ramex moved the project to Indiana. A total of 7 wells were drilled. Gas
tests resulted in ratings of 1,034 and 968 BTU. Two production volume tests showed 14,000 and 24,000 cubic feet per day.
In late July, 1988 a letter agreement was signed between Tri-Gas Technology, Inc., the licensee of the Ramex process in Indiana,
and J. M. Slaughter Oil Company of Ft. Worth, Texas to provide funding for drilling a minimum of 20 gas wells, using the Ramex
oil shale gasification process, on the leases near Henryville, Indiana. Arrangements were made with Midwest Natural Gas to hook
up the Ramex gas production to the Midwest Pipeline near Henryville.
As of May, 1989 Ramex had been unsuccessful in sustaining long-term burns. They therefore redesigned the burner and built a
much larger model (600,000 BTU per hour vs 40,000 BTU per hour) for installation at the Henryville site. In November, 1989
Ramex completed its field test of the Devonian Shales in Indiana. The test showed a gas analysis of 47 percent hydrogen,
30 percent methane and little or no sulfur. Ramex contracted with a major research firm to complete the design and material
selection of its commercial burners which they say are 40 to 50 percent more fuel efficient than most similar industrial units and
also to develop flow measurement equipment for the project. Ramex received a patent on its process on May 29, 1990.
In 1990, Ramex also began investigating potential applications in Israel.
Ramex contracted with the Institute of Gas Technology in 1990 for controlled testing of its in situ process because the company's
field tests of the process in wells in Indiana have been thwarted by ground water incursion problems. Questions that still need to
be answered before the Ramex process can be commercialized are:
How fast does the heat front move through the shale?
How far will the reaction go from the heat source and how much heat is necessary on an incremental basis to keep
the reaction zone moving outward from the source of heat?
What is the exact chemical composition of the gas that is produced from the process over a period of time and does
the composition change with varying amounts of heat and if so, what is the ideal amount of heat to produce the most
desirable chemical composition of gas?
Once these questions are answered, the will company be able to calculate the actual cost per unit of gas production.
In 1992 Ramex announced a company reorganization and said that new laboratory tests were being arranged to improve its technol
ogy.
On September 30, 1993, Ramex Synfuels International, Inc., as sponsor of a private placement of limited partnership interests in
Ramex Research Partners, Ltd. successfully closed an offering at the minimum amount intended to be sold of $110,000. Subse
quently, a contract to conduct Phase I laboratory was signed testing between Ramex and Southwest Research Institute of San An
tonio. Texas. These tests have been ongoing during 1994. with the final Phase I test to be conducted in December 1994. A final
report on all Phase I tests will be issued by SwRJ in January or February 1995.
Project Cost: Approximately $1 million for the pilot tests.
RIO BLANCO OIL SHALE PROJECT - Rio Blanco Oil Shale Company (wholly owned by Amoco Corporation) (S-190)
The proposed project is on federal Tract C-a in Piceance Creek Basin, Colorado. A bonus bid of $210.3 million was submitted to
acquire rights to the tract which was leased in March 1974. A 4-year modified in situ (MIS) demonstration program was completed
at the end of 1981. The program burned two successful retorts. The first retort was 30 feet by 30 feet by 166 feet high and
produced 1,907 barrels of shale oil. It burned between October and late December 1980. The second retort was 60 feet by 60 feet
by 400 feet high and produced 24,790 barrels while burning from June through most of December 1981. Open pit mining-surface
retorting development is still preferred, however, because of much greater resource recovery of 5 versus 2 billion barrels over the
life of the project. Rio Blanco, however, could not develop the tract efficiently in this manner without additional federal land for
disposal purposes and siting of processing facilities, so 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. In August 1987, the suspen
sion was renewed.
2-32
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
Federal legislation was enacted to allow procurement of off-tract land that is necessary if the lease is to be developed by surface
mining. 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 has been
prepared by the Bureau of Land Management. However, a Record of Decision was never issued due to a suit filed the National
by
Wildlife Federation.
Rio Blanco submitted a MIS retort abandonment plan to the Department of Interior in Fall 1983. Partial approval for the aban
donment plan was received in Spring 1984. The mine and retort were flooded but were pumped out in May 1985 and June 1986 in
accordance with plans approved by the Department of the Interior.
Rio Blanco operated a $29 million, 1 to 5 TPD Lurgi pilot plant at Gulfs Research Center in Harmarville, Pennsylvania until late
1984 when it was shut down. This $29 million represents the capital and estimated cost operating for up to 5 years of operation.
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.
In 1992, Rio Blanco closed its Denver office and moved all activities to the site.
Project Cost: Four-year process development program cost $132 million
- RUNDLE PROJECT Central
No cost estimate available for commercial facility.
Pacific Minerals/Southern Pacific Petroleum (50 percent) and Esso Exploration and Production
Australia (50 percent) (S-200)
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 develop
ment. 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 discussions about amendments to the Rundle Joint Venture Agreement signed in
1982. Those discussions were completed by March 1985. Revisions to the Joint Venture Agreement provide for:
Payment by Esso to SPP/CPM of A$30 million in 1985 and A$12.5 in 1987.
Each partner to have a 50 percent interest in the project.
Continuation of a Work Program to progress development of the resource.
Esso funding all work program expenditures for a maximum of 10 years, and possible funding of SPP/CPM's share of subse
quent development expenditures. If Esso provides disproportionate funding, it would be entitled to additional offtake to
cover that funding.
The project is at a continuing low level with work in 1992 focusing on environmental land and resource management and further
shale upgrading and processing studies.
Project Cost: US$2.65 billion total estimated
- - SHC 3000 RETORTING PROCESS Estonian
Republic (S-230)
The SHC-3000 process, otherwise known as the Galoter retort, is a rotary kiln type retort which can accept oil shale fines.
Processing of the kukersite shale in SHC-3000 retorts makes it possible to build units of large scale, to process shale particle sizes
of 25 millimeters and less including shale dust, to produce liquid fuels for large thermal electric power stations, to improve operat
ing conditions at the shale-burning electric power stations, to increase (thermal) efficiency up to 86-87 percent, to improve sulfur
removal from shale fuel, to produce sulfur and other sulfur containing products (such as thiophene) by utilizing hydrogen sulfide of
the semicoke gas, and to extract valuable phenols from the shale oil water. Overall the air pollution (compared to direct oil shale
combustion) decreases.
2-33
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
The two SHC-3000 units built in 1980 at the Estonian Powerplant, Narva, Estonia, with a capacity of 3,000 tons of shale per day are
among the largest in the world and unique in their technological principles. However, these units have been slow in reaching full
design productivity.
A redesign and reconstruction of particular pans of the units was done in 1984 to improve the process of production and to in
crease the period of continuous operation.
As a result of these changes, the functioning of the SHC-3000 improved dramatically in 1984 in comparison with the period of
1980-1983. For instance, the tout amount of shale processed in the period 1980-1983 was almost the same as for only 1984, i.e.
79,100 tons versus 80,100 in 1984. The tout shale oil production for the period 1980-1983 was 10500 tons and approximately the
same amount was produced only in 1984. The average output of shale oil per run increased from 27 tons in 1980 to 970 tons in
1984. The output of electric energy for Estonia-Energo continued constant in 1983 and 1984, by burning part of the shale oil in the
boilers of Estonia GRES.
By the end of 1984, 159,200 tons of shale was processed and 20,000 tons of shale oil was produced at SHC-3000.
In 1985, the third test of the reconstructed boiler TP-101 was carried out by using the shale oil produced at the SHC-3000. The im
provement of the working characteristics of SHC-3000 has continued.
LO VGNIPII (the name of the Research Institute) has designed for Estonia an electric power station that would use shale oil and
produce 2,600 megawatts. A comparison of its technical-economical characteristics with the corresponding ones of the 2500
megawatts power station with direct burning of raw shales was made. It was found that the station on shale oil would be more
economical than the station with direct burning of shale.
In 1990, 374,000 tons of shale was used for processing and 43,600 tons of shale oil was produced. In 1994. 600.000 tons of shale
were used to produce 79.000 tons of oil (in 1993. 502500 tons of shale and 65.900 tons of oil). At present, shale with an organic
content of 28 percent is used for processing, the oil yield being about 12 percent per shale. The oil obtained contains 14 to
15 percent of gasoline fraction. Export of the oil produced is growing steadily-from 8,900 tons in 1990 to 24,300 tons in 1991.
Bv the end of 1994. 3.245.000 tons of shale had been processed and 403500 tons oil oil had been produced by the SHC-3000
process.
- STUART OIL SHALE PROJECT Southern
Pacific Petroleum NL and Central Pacific Minerals NL (S-210)
In 1985 Southern Pacific Petroleum NL and Central Pacific Minerals NL (SPP/CPM) studied the potential for developing a
demonstration retort based upon mining the Kerosene Creek Member of the Stuart oil shale deposit in Queensland, Australia.
This study utilized data from a number of previous studies and evaluated different retorting processes. It showed potential
economic advantages for utilizing the Taciuk Process developed by Umatac and AOSTRA (Alberta Oil Sands Technology and
Research Authority) of Alberta, Canada. Batch studies were carried out in 1985, followed by engineering design work and es
timates later the same year. As a consequence of these promising studies a second phase of batch testing at a larger scale was
carried out in 1986. A series of 68 pyrolysis tests were carried out using a small batch unit. A number of these tests achieved oil
yields of 105 percent of Modified Fischer Assay.
As a result of the Phase 2 batch tests, SPP updated their cost estimates and reassessed the feasibility of the Taciuk Processor for
demonstration plant use. The economics continued to favor this process so the decision was made to proceed with tests in the 100
tonne per day pilot plant in 1987. A sample of 2,000 tonnes of dried Stuart oil shale was prepared in late 1986 and early 1987. The
pilot plant program was carried out between June and October 1987.
During the last quarter of 1987, SPP carried out a short drilling program of 10 holes at the Stuart deposit in order to increase infor
mation on the high grade Kerosene Creek member. This is a very high grade seam (134 liters per tonne) with 150 million barrels of
reserves.
SPP/CPM engaged two engineering firms-Bechtel and Davy-to make independent, detailed studies of the shale oil project. The
purpose of the studies is to provide potential financial backers with verifiable information on which to base technical judgment of
the project. These studies were completed in early 1991. Both groups confirmed SPP/CPM's own numbers and endorsed the
AOSTRA Taciuk Processor as the most effective retort for Queensland oil shale.
The overall SPP development plan includes three stages, commencing with a low capital cost, semi-commercial plant at 6,000 tonnes
per day of high grade shale feed producing 4,250 barrels per day of oil. Bechtel Engineering has offered to build the first stage on a
fixed price time certain contract with performance guarantees subject to liquidated damages. Once the retorting technology is
proven the second stage plant at 25,000 tons per day of shale producing 14,000 barrels per day of syncrude from an intermediate
grade will be constructed. Stage three is a replication step with five 25,000 ton per day units producing 60,000 barrels per day of
syncrude from average grade shale, or approximately 15 percent of the projected Australian oil import requirement in the year
2000.
2-34
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
proven the second stage plant at 25,000 tons per day of shale producing 14,000 barrels per day
of syncrude from an intermediate
grade will be constructed. Stage three is a replication step with five 25,000 ton per day units producing 60,000 barrels per day of
syncrude from average grade shale, or approximately 15 percent of the projected Australian oil import requirement in the year
2000.
The latest estimated cost for the first stage demonstration plant is US$132 million. Because the semi-commercial Demonstration
plant cannot offer economics of scale, the Australian government is encouraging the project by offering to exempt all gasoline
derived therefrom (about 40% of production) from excise tax (US$0.19/liter) through the year 2005. Legislation to this effect was
passed by the Australian Parliament in December 1993. In December 1992, Stuart Stage 1 received formal government approval as
a research and development project, making it eligible for a write-off of 150 percent of 90 percent of capital expenditures
(50 percent in each of the first 3 years) plus the same 150 percent write-off for nearly all operating costs, including interest on debt,
for six years.
With both these government supports the excise tax benefit alone covers all operating costsStage 1 is profitable at any oil price
above $5 per barrel as notionally suggested below:
WIS1993 $15 $20 $25
Project after tax IRA 10.0% 15.2% 19.1%
Investor after tax IRA 145% 20.0% 25.2%
According to conceptual SPP calculations neither Stage 2 or 3, the subsequent full size commercial plants, require any government
subsidies to be economic.
In parallel with these matters, environmental impact studies have been completed and the Stuart partners were granted a mining
lease for the term of 24 years in October 1993.
Project Cost: For semi-commercial demonstration module US$132 million
- YAAMBA PROJECT Yaamba
Joint Venture [Beloba Pty. Ltd. (10 percent), Central Pacific Minerals N.L. (3.3 percent), Southern
Pacific Petroleum N.L. (3.3 percent), Shell Company of Australia Limited (41.66 percent), and Peabody Australia Pty. Ltd.
(41.66 percent)] (S-240)
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 4.8 billion
barrels in situ extending over an area of 32 square kilometers within the basin.
The oil shales which have a combined aggregate thickness of over 300 meters in places occur in 12 main seams extending through
the lower half of a Tertiary sequence which is up to 800 meters thick toward the center of the basin. The oil shales subcrop along
the southern and southwestern margins of the basin and dip gently basinward. Several seams of lignite occur in the upper part of
the Tertiary sequence above the main oil shale sequences. The Tertiary sediments are covered by approximately 40 meters of un
consolidated sands, gravels, and clays.
During 1988, activities in the field included the extraction of samples for small scale testing and the drilling of four holes for further
resource delineation.
In December, 1988 Shell Australia purchased a part interest in the project. Peabody Australia manages the Joint Venture which
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. 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 Her
bert Creek Basin is 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 been completed. Environmental baseline investigations were carried out
concurrently with this study. Further investigations 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, and collection of additional data on
the existing environment were undertaken.
During 1990,
exploration and development studies at the Yaamba and Herbert Creek deposits continued. A program of three
holes (644 meters) was undertaken in the Block Creek area at the southeast of the Herbert Creek deposit.
Project Cost: Not disclosed
2-35
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes sine* June 1994)
R&D PROJECTS (Continued)
R&D PROJECTS
KENTORT II PDU-University of Kentucky Center for Applied Energy Research (CAER) (S-290)
CAER has completed a 50-pound per hour Process Development Unit (PDU) in 1993 to test the KENTORT II process. The KEN
TORT II process is a fully-integrated, four-stage, fluidized-bed oil shale retort. The pyrolysis, gasification and zones are
cooling
aligned vertically and share a common fluidizing gas. The combustion zone is adjacent to the gasification section, and a separate
gas stream (air) is used for fluidization.
Three major shakedown runs were completed during 1993. The 50-pound per hour PDU has been shown to be functional when
nitrogen is used for fluidization. To be considered completely operational, however, steam must be used for fluidization. Steam is
crucial to the KENTORT II PDU for two reasons. First, steam is a necessary reactant for the gasification zone, and, second, the oil
collection system was designed around the use of steam. Shakedown runs using steam for fluidization are planned for early 1994.
During 1994. a successful series of runs was completed in the 50 Ib/hr KENTORT II Process Development Unit. All design condi
tions for the unit were achieved including raw shale feedrate. run duration, autothermal operation, solid-recycle rates, and bed tem
peratures. Oil yield of at least 109% of Fischer Assay was achieved for the run with the longest duration.
Currently, the PDU is not being operated. In 1995. the unit will be available for contract research with any type of fluidizable solid
fuel where heat transfer bv solids would be beneficial. Because of the modular design, pyrolysis. gasification, combustion or any
combination of the three can be studied in the integrated unit.
LLNL HOT RECYCLED-SOLIDS (HRS) RETORT - Lawrence Livermore National Laboratory, U. S. Department of Energy (S-300)
Lawrence Livermore National Laboratory (LLNL) has, for over the last 5 years, been studying hot-solid recycle retorting in the
laboratory and in a 1 tonne per day pilot facility and have developed the LLNL Hot Recycled-Solids Retort (HRS) process as a
generic second generation oil shale retorting system. Much progress has been made in understanding the basic chemistry and
physics of retorting processes and LLNL believes they are ready to proceed to answer important questions to scale the process to
commercial sizes. LLNL hopes to conduct field pilot plant tests at 100 and 1,000 tonnes per day at a mine site in western Colorado.
In this process, raw shale is rapidly heated in a gravity bed pyrolyzer to produce oil vapor and gas. Residual carbon (char), which
remains on the spent shale after oil extraction, is burned in a fluid bed combustor, providing heat for the entire process. The heat
is transferred from the combustion process to the retorting process by recycling the hot solid, which is mixed with the raw shale in a
fluid bed prior to entering the pyrolyzer. The combined raw and burned shale (at a temperature near 500 degrees C) pass through
a moving, packed-bed retort containing vents for quick removal and condensation of product vapors, minimizing losses caused by
cracking (chemical breakdown to less valuable species). Leaving the retort, the solid is pneumatically lifted to the top of a
cascading-bed burner, where the char is burned during impeded-gravity fall, which raises the temperature to nearly 650 degrees C.
Below the cascading-bed burner is a final fluid bed burner, where a portion of the solid is discharged to a shale cooler for final dis
posal.
In 1990, LLNL upgraded the facility to process 4 tonnes per day of raw shale, working with the full particle size (0.25 inch). Key
components of the process are being studied at this scale in an integrated facility with no moving parts using air actuated valves and
a pneumatic transport, suitable for scaleup. In April 1991, the first full system run on the 4 tonne per day pilot plant was com
pleted. Since that time, the retort has successfully operated on both lean and rich shale (22-38 gallons per ton) from western
Colorado. LLNL plans to continue to operate the facility and continue conceptual design of the 100 tonne per day pilot-scale test
facility. LLNL has joined with a consortium of industrial sponsors for its current operations in a 3 year contract to develop the
HRS process.
The ultimate goal is a 1,000-tonne-per-day field pilot plant, followed by a commercially-sized demonstration module (12,000 tonnes
per day) which could be constructed by private industry within a 10 year time frame. Each scale represents a factor of three in
crease in vessel diameter over the previous scale, which is not unreasonable for solid-handling equipment, according to LLNL.
DOE approved a Cooperative Research and Development Agreement (CRADA^ between LLNL and Amoco. Unocal, and a
Chevron-Conocco partnership. Each company contributed $100,000 and technical expertise to match DOE funding. Pilot plant
runs tested hot-gas filtering and heavy-ends recycle as ways to eliminate dust in the oil. DOE funding ended October 1. 1993. due
to an unfavorable Congressional vote. The CRADA has been inactive and will terminate February 1995.
Project Cost: - Phase I $15 million
Phase II $35 million
2-36
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
NEW PARAHO ASPHALT FROM SHALE OIL PROJECT-New Paraho Corporation (S-310)
New Paraho Corporation is a wholly owned subsidiary of Energy Resources Technology Land, Inc. New Paraho Corporation plans
to develop a commercial process for making shale-oil-modified road asphalt. Researchers at Western Research Institute (WRJ)
and elsewhere have discovered that certain types of chemical compounds present in shale oil cause a significant reduction in mois
ture damage and a potential reduction in binder embrittlement when added to asphalt. This is particularly true for shale oil
produced by direct-heated retorting processes, such as Paraho's.
In order to develop this potential market for shale oil modified asphalts, New Paraho has created an initial plan which is to result in
(1) proven market performance of shale oil modified asphalt under actual climatic and road use conditions and completion of a
(2)
comprehensive commercial feasibility study and business plan as the basis for subsequent
securing financing for a Colorado-based
commercial production facility.
The cost of carrying out the initial market development phase of the commercial development plan was approximately $25 million,
all of which was funded by Paraho. The major portion of the work conducted during this initial phase consisted of producing suffi
cient quantities of shale oil to accommodate the construction and evaluation of several test strips of shale oil-modified asphalt
pavement. Mining of 3,900 tons of shale for these strips occurred in September 1987. The shale oil was produced in Paraho's pilot
plant facilities, located near Rifle, Colorado in August, 1988. The retort was operated at mass velocities of 418 to 538 pounds per
hour per square foot on 23 to 35 gallon per ton shale and achieved an average oil yield of 96.5 percent of Fischer Assay. In 1988,
New Paraho installed a vacuum still at the pilot plant site to produce shale oil asphalt from crude shale oil.
Eight test strips were constructed in Colorado, Utah and Wyoming. The test strips are being evaluated over a period of five years.
during which time Paraho will complete site selection, engineering and cost estimates, and financing plans for a commercial produc
tion facility. Test strips were also completed on 1-20 east of Pecos, Texas, in Michigan for a test section of 1-75 near Flint, and US-
59, northeast of Houston, Texas, and US-287 in Jackson Hole. Wyoming.
Paraho has proposed a $J>4 million commercial scale plant capable of producing 555 barrels of crude oil per day, of which
440 barrels would be shale oil modifier (SOM) and 110 barrels would be light oil to be marketed to refineries.
An economic analysis has determined that SOM could be marketed at a price of $140 per barrel if tests show that SOMAT can af
fect at least a 10 percent improvement in pavement life. A feasibility study suggests that Paraho can expect a 25 percent rate of
return on SOMAT production.
Approximately 1500 acres of the Mahogany Block, controlled by the Tell Ertl Family Trust, are available to New Paraho. New
Paraho also maintains control of approximately 11,000 acres of oil shale leases on state lands in Utah. In addition. Paraho is
evaluating other sites where the facility may be located.
In December 1992 New Paraho announced that its pilot plant in Rifle, Colorado was currently producing 15 barrels of shale oil
daily as part of a new SOMAT test marketing program started in September. This program has been completed and the product
has been successfully marketed.
The first phase of the new test market program for SOMAT is expected to cost $3.0 million through 1994. and produce enough
SOMAT for 50 to 60 miles of asphalt roads and employ 15 people.
The test strip results have been encouraging and SOMAT is proving to be a superior road paving material, with distinct life-cycle
cost advantages.
The oil shale asphalt, as a 10 percent additive to conventional asphalt, is far more resistant to water damage and aging than conven
tional asphalt. It adds about 10 to 15 percent to the cost of asphalt, but is a bargain compared to other asphalt modifiers that ac
complish the same tasks and increase costs by 30 to 35 percent.
New Paraho has proposed a 7-month, $500,000 commercial evaluation program to assess the economic benefits of coprocessing
used tires with oil shale. Initial experiments have demonstrated that retort operations can be sustained with used tires as 5 percent
of the feedstock.
Research Project Cost: $7.0 million
Estimated Commercial Project Capital Cost: $54.0 million
- SHALE OIL VALUE ENHANCEMENT VENTURE J.W.
Bunger & Associates. Inc. (JWBA1 (S-325^
Shale oil produced from Western U.S. Green River Formation contains high concentrations of potentially valuable products-
particularly nitrogen compounds-pyridines. pyrroles, and their benzologs which possess market values of $800 per barrel or more.
JWBA estimates that 10 percent of the raw shale oil could be manufactured into products commanding these values and is planning
a venture to examine commercial production of these value-added products.
2-37
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
Economic projections show that a $30 per barrel transfer price for raw shale oil could be paid bv a value-added venture, creating an
economic incentive for the production of the raw shale oil. The venture plans to purchase 5.000 barrels/day of raw shale oil and
produce a suite of marketable products averaging at least $78 per barrel. A 30 percent 1RR is projected on a $77 million invest
ment.
Proposed schedule includes feasibility R&D, pilot plant studies, and commercial production. The $2.25 million feasibility study
research will continue through mid-1996 and will include technical and market assurances of the conceptual plant. The $5 million
larger-scale pilot plant work and commercial venture planning will be completed by mid-1998. Commercial production is an
ticipated to begin in 2000.
Funding from the DOE. Occidental Oil Shale Company, the State of Utah, and internal sources have been received to pursue tech
nology and product development of the value-added products.
YUGOSLAVIA COMBINED UNDERGROUND COAL GASIFICATION AND MODIFIED IN SrTU OIL SHALE RETORT -
United Nations (S-335)
Exceptional geological occurrence of oil shale and brown coal in the Aleksinac basin has allowed an underground coal gasification
(UCG) combined with in situ oil shale retorting. Previous mining activities of Aleksinac brown coal and development of oil shale
utilization (see Yugoslavia Modified In Situ Retort-S-330, Synthetic Fuels Report, December 1990) served as principal support in
establishing a development project aimed towards application of a new process, i.e. combination of UCG and in situ oil shale
retorting to be tested for feasibility in a pilot UCG modulus. The project is a joint scientific and technological undertaking per
formed by Yugoslavian and American staff.
The objective of the approach is to develop a program to exploit the total Aleksinac energy resources to provide regional power
and heating for Aleksinac and surrounding area using UCG technology and combining it with modified in situ retorting of oil shale
as the immediate roof of the brown coal seam.
The development objectives arc also to recover energy from residual coal left after conventional coal mining and to develop UCG
technology and modified in situ oil shale retorting for Yugoslavian resources in general.
Project Cost: US$725,000
2-38
SYNTHETIC FUELS REPORT, JANUARY 1995

Project
American Syncrude Indiana Project
Baytown Pilot Plant
BX In Situ Oil Shale
Project
Colony Shale Oil Project
Cottonwood Wash Project
Direct Gasification Tests
Duo-Ex Solvent Extraction Pilot
Eastern Oil Shale In Situ Project
Edwards Engineering Company
Exxon Colorado Shale
Fruita Refinery
Gelsenkirchen-Scholven
Cyclone Retort
Japanese Retorting Processes
Julia Creek Project
Laramie Energy
Technology Center
Logan Wash Project
Means Oil Shale Project
Nahcolite Mine #1
Naval Oil Shale Reserve
of Energy
Northlake Shale Oil Processing Pilot
Oil Shale Gasification
Pacific Project
Paraho Oil Shale Full Size
Module Program
COMPLETED AND SUSPENDED PROJECTS
Sponsors
American Syncrude Corp.
Stone & Webster Engineering
Exxon Research and Engineering
Equity Oil Company
Exxon Company USA
American Mine Service
Cives Corporation
Deseret Generation &
Transmission Coop.
Foster Wheeler Corporation
Davy McKee
Magic Circle Energy
Corporation
Tosco Corporation
Solv-Ex Corporation
Eastern Shale Research Corporation
Edwards Engineering
Exxon Company USA
Landmark Petroleum Inc.
Veba Oel
Japan Oil Shale Engineering Company
Placer Exploration Limited
Laramie and Rocky Mountain
Energy Company
Occidental Oil Shale Inc.
Central Pacific Minerals
Dravo Corporation
Southern Pacific Petroleum
Multi-Mineral Corporation
United States Department
Northlake Industries, Inc.
Uintah Basin Minerals, Inc.
Institute of Gas Technology,
American Gas Association
Cleveland-Cliffs
Standard Oil (Ohio)
Superior
Paraho Development Corporation
2-39
Last Appearance in SFR
September 1987; page 2-53
September 1987; page 2-60
March 1984; page 2-52
June 1994; page 2-10
March 1985; page 2-73
September 1978; page B^t
September 1989; page 2-55
September 1989; page 2-55
March 1990; page 2-42
March 1985; page 2-73
March 1991; page 2-23
June 1987; page 2-52
September 1989; page 2-56
March 1991; page 2-32
June 1980; page 2-34
September 1984; page S-3
June 1987; page 2-47
September 1982; page 2-40
June 1987; page 2-53
June 1993; page 2-30
December 1978; page B-3
June 1987; page 2-48
December 1979; page 2-35
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SHALE PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Paraho-Ute Shale Oil
Facility
RAPAD Shale Oil Upgrading Project
Seep Ridge
Silmon Smith
Tosco Sand Wash Project
Trans Natal T-Project
Triad Donor Solvent Project
United States Bureau of Mines Shaft
United States Shale
Unnamed In Situ Test
Unnamed Fracture Test
White River Shale Project
Paraho Development Corporation
Japanese Ministry of International Trade
and Industry
Geokinetics Inc.
Peter Kiewit Sons'
Inc.
Kellogg Corporation
Shale Energy Corporation of America
Tosco Corporation
Trans Natal, Gencor, Republic of
South Africa
Triad Research Inc.
Multi-Mineral Corporation; United States
Bureau of Mines
United States Shale Inc.
Mecco, Inc.
Talley Energy Systems
Phillips Petroleum Company
Standard Oil Company (Ohio)
Sun Oil Company
Yugoslavia Inclined Modified In Situ Retort United Nations
2-40
December 1986; page 2-47
March 1990; page 2-52
March 1986; page 2-54
March 1985; page 2-72
March 1990; page 2^8
March 1991; page 2-30
December 1988; page 2-48
December 1983; page 2-52
March 1985, page 2-72
September 1978; page B-3
September 1978; page B-4
March 1985; page 2-72
December 1990; page 2-43
SYNTHETIC FUELS REPORT, JANUARY 1995

Company or Organization
Amoco Corporation
Beloba Pty. Ltd.
Central Pacific Minerals
Chevron Shale Oil Company
Conoco Inc.
Esperance Minerals NL
Esso Exploration and Production Australia Ltd.
Estonian Republic
Fushun Petrochemical Corporation
Greenvale Mining NL
Greenway Corporation
J. W. Bunger & Associates, Inc.
Jordan Natural Resources
Kentucky Center for Applied Energy Research
Lawrence Livermore National Laboratory
Maoming Petroleum Industrial Corporation
Marathon Oil Company
Mobil Oil Corporation
New Brunswick Electric Power Commission
New Paraho Corporation
Occidental Oil Shale, Inc.
Office National de Recherche et
d'Exploitation Petrolieres
(ONAREP)
PAMA Inc.
Peabody Australia Pty. Ltd.
Petrobras
Ramex Synfuels International
Rio Blanco Oil Shale Company
Royal Dutch/Shell
INDEX OF COMPANY INTERESTS
Project Name
Rio Blanco Oil Shale Project (C-a)
Yaamba Project
Stuart Oil Shale Project
Condor Project
Rundle Project
Yaamba Project
Clear Creek Project
Clear Creek Project
Esperance Oil Shale Project
Rundle Project
Estonia Power Plants
Kiviter Process
SHC-3000 Retorting Process
Fushun Commercial Shale Oil Plant
Esperance Oil Shale Project
RAMEX Oil Shale Gasification Process
Shale Oil Value Enhancement Venture
Jordan Oil Shale Project
KENTORT II PDU
LLNL Hot Recycled-Solids (HRS) Retort
Maoming Commercial Shale Oil Plant
New Paraho Asphalt From Shale Oil
Mobil Parachute Oil Shale Project
Chatham Co-Combustion Boiler
New Paraho Asphalt From Shale Oil
Occidental MIS Project
Morocco Oil Shale Project
PAMA Oil Shale-Fired Power Plant Project
Yaamba Project
Petrosix
Ramex Oil Shale Gasification Process
Rio Blanco Oil Shale Project (C-a)
Morocco Oil Shale Project
2-41
Page
2-32
2-35
2-34
2-25
2-33
2-35
2-25
2-25
2-26
2-33
2-26
2-27
2-33
2-27
2-26
2-31
2-37
2-27
2-36
2-36
2-28
2-37
2-28
2-25
2-37
2-29
2-28
2-29
2-35
2-30
2-31
2-32
2-28
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF OIL SHALE PROJECTS
INDEX OF COMPANY INTERESTS (Continued)
Company or Organization Project Name
SINOPEC
Southern Pacific Petroleum
Unocal Corporation
United Nations
Yaamba Joint Venture
Fushun Commercial Shale Oil Plant
Maoming Commercial Shale Oil Plant
Stuart Oil Shale Project
Condor Project
Rundle Project
Yaamba Project
Parachute Creek Shale Oil Program
Yugoslavia Combined Underground Coal Gasification and
In Situ Oil Shale Retort
Yaamba Project
2^2
Page
2-27
2-28
2-34
2-25
2-33
2-35
2-30
2-38
2-35
SYNTHETIC FUELS REPORT, JANUARY 1995

PROJECT ACTIVITIES
AMOCO PRIMROSE LAKE PROJECT GETS
GREEN UGHT
Amoco Canada Petroleum Ltd. has received ap
proval from the Alberta Energy Resources Con
servation Board to proceed with the Primrose
Lake commercial in situ heavy oil recovery
project. The project was originally conceived as
a 50,000 barrel per day cyclic steam stimulation
operation by Dome Petroleum Ltd. before the
company was acquired by Amoco in 1988.
The project, as revised by Amoco, now calls for
the use of horizontal wells, and a combination of
primary recovery operations followed by thermal
recovery. Approximately 20 horizontal wells per
section will be required, and ultimate recovery of
50 percent of the oil in place is projected.
Maximum production rate is still estimated at
50,000 barrels per day. This rate would not be
reached until 2010, but operations could then be
sustained at that rate until 2050.
The Primrose Lake project will be linked by
pipeline to the processing facilities at the ad
jacent Wolf Lake project, also owned by Amoco.
Amoco now holds more than 360 sections of
land in the Primrose area. The company ob
tained most of these holdings in 1993 when it
traded its 3.75 percent interest in Syncrude
Canada to Alberta Energy Company for that
company's Primrose properties.
Construction at Primrose Lake was expected to
begin in late 1994 or early 1995.
####
SUNCOR ANNOUNCES PRODUCTION
RECORD AND BIG NEW EXPANSION PLANS
For the third quarter of 1994, Suncor Inc. said
that its oil sands operation averaged
OIL SANDS
3-1
69,200 barrels per day over the first 9 months of
1994 and was the highest in the 27-year history
of the plant. The increase in production is at
tributable to modifications to the upgrader and
the conversion to a more flexible and reliable min
ing
technology. The year-to-date cash costs per
barrel were C$13.50, on target for an annual cash
cost of C$14.00.
Suncor's Oil Sands Group
recorded earnings of
C$33 million in the third quarter compared with
C$30 million in the same period of 1993. The in
crease was primarily due to higher prices and
sales volumes, partially offset by higher expendi
tures. The Group's quarterly cash costs per bar
rel averaged C$13.25.
During the quarter, the Group
stallation of "Superclaus,"
completed the in
a $14-million environ
mental improvement that will reduce sulfur
dioxide emissions from the upgrading facility by
50 percent.
In November, Suncor said it plans to spend
about C$250 million to expand the oil sands
operations, and boost oil production to more
than 80,000 barrels per day over the next 3 years
while positioning the plant for even further expan
sion.
That announcement was followed in December
by
a statement that Suncor will also spend
C$100 million over the next 5 years to develop a
new oil sands mining site. Suncor noted that con
version from bucketwheel to shovel operation
and use of 240-metric ton trucks have helped cut
recovery
costs to US$10 per barrel and made
synthetic crude competitive with conventional
crude.
The mine expansion was made possible earlier in
1994 when Suncor acquired an oil sands lease
for an undisclosed price from Petro-Canada.
Lease 97 adjoins Suncor's Fort McMurray oil
sands leases and plant. Suncor acquired two
other leases in late 1992 with an estimated life of
40 years. Suncor plans to start developing the
first of these leases in 1 997.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
The company said the largest part of the produc
tion Increase is likely to occur in 1997, after a
scheduled maintenance turnaround. The expan
sion plans are subject to regulatory approvals.
####
SYNCRUDE IMPROVEMENT PROJECT
APPROVED
In September 1992, Syncrude Canada Ltd.
(Syncrude) applied to amend its existing Ap
proval No. 5641 for the Mildred Lake Oil Sands
Plant. In its application Syncrude sought ap
proval for:
- An
- An
- An
- Conceptual
increase in Its current Synthetic
Crude Oil (SCO) production limit from
10.0 to 12.6 million cubic meters per year
(m3/yr)
extension, to December 31, 1997, of
the lapse date for an approval to expand
the plant to produce an additional
5.0 million m3/yr of SCO
extension of its approval expiration
date from December 31, 2018 to
December 31 , 2025
The processing of bitumen from off-lease
sources at its Mildred Lake facility and
for shipping of bitumen to other process
ing facilities
mining, lease development,
and reclamation plans, including fine tail
Background
ings reclamation
The Syncrude project was first approved by the
Energy
Board)
Resources Conservation Board (the
in 1968 and commenced production in
1977. The project comprises an open-pit mine
utilizing draglines, bucketwheel reclaimers and
conveyers to transport bituminous sands to an
3-2
extraction plant where the bitumen is separated
from the sand using a modified hot water
process. Wastes from the extraction plant, which
include coarse sand, fine tailings and water, are
currently directed to two large tailings sites for
temporary
storage. The produced bitumen is
hydrocrack-
upgraded to SCO using fluid coking,
ing and hydrotreating processes. Byproduct sul
fur and petroleum coke are also produced.
The Syncrude facility currently
produce up
1988,
has approval to
to 10.0 million m3/yr of SCO. In
approval was granted to add facilities to
produce an additional 5.0 million cubic meters of
SCO annually. The approval stipulated that ex
pansion was to commence by the end of 1992.
Interim amendments to the lapse date were
granted in both 1992 and 1993. These interim
amendments also approved increases in the an
nual SCO production limit and authorized
Syncrude to process off-lease bitumen in the
1992 and 1993 calendar years.
The 1987 Expansion Project application was
reviewed through a consultative process which
included representatives of Syncrude, the Fort
McKay First Nation, and various regulatory
agencies. This group, which became known as
the Syncrude Expansion Review Group or SERG,
was able to address the issues and concerns of
the Fort McKay First Nation without the need for
a public hearing process.
A somewhat different approach was used by
Syncrude during the preparation of this applica
tion. Syncrude identified key stakeholder groups
with which it intended to individually consult in
order to identify and, if possible, address areas of
concern. The key stakeholder groups identified
were: the Fort McKay First Nation, the City of
Fort McMurray, and various environmental as
sociations. In order to simplify Its dealing with
the environmental associations, Syncrude ap
proached the Alberta Environmental Network and
asked it to set up a committee of interested or
ganizations. The Syncrude Environmental As
sessment Coalition (SEAC) was formed as a
result. Separate consultation processes were in
itiated with each of these three stakeholder
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
groups prior to the filing of the application and
continued up to (and in some cases, during) the
hearing.
Syncrude filed the first volume of its application
with the Board in September 1992. Syncrude's
application was considered by a division of the
Board (the panel) at a public hearing in Fort
McMurray, Alberta commencing on
September 8, 1993. At the outset of the hearing
a motion to adjourn was made by the Fort McKay
First Nation and SEAC. Arguments on the
Board's jurisdiction to hear Syncrude's applica
tion were heard by the Court on March 3, 1994,
and the Court confirmed the Board's jurisdiction
to proceed with the hearing.
Production Capability
The most recent application proposes to use the
existing facilities to increase SCO production to a
maximum of 12.6 million cubic meters per year
(the staged development). This increase is
separate from the previously
approved expan
sion project. By undertaking that project,
Syncrude could further increase production by
up to another 5.0 million m3/yr.
To achieve the 12.6 million m3/yr level of SCO
production, Syncrude proposed two operating
modes for its bitumen upgrading facilities which it
referred to as the "Base"
and "Once-through"
modes. The Base mode would achieve higher
production by improving service factors and in
feedrates to the cokers and
creasing
hydrocracker. The Once-through mode would
also incorporate a higher SCO yield in addition to
the foregoing
improvements. To achieve this
maximum level of production would require
hydrocracking feedrates significantly higher than
service factors
the original design and upgrading
of 100.0 percent. Service factors this high would
only
be achieved in years that do not require
scheduled maintenance shutdowns. Syncrude
expected that typical years would see service fac
tors in the 95.0 percent range which would be suf
ficient to sustain SCO production near the
12.0 million m3/yr level.
3-3
Expansion Project Design
In 1988, Syncrude received Board approval for
an expansion project that would increase SCO
production by 5.0 million m3/yr beyond the ap
proved limit of 10.0 million m3/yr. The approval
was conditional on the construction for the
project commencing by December 31, 1992.
The expansion project design was based on:
- Truck-and-shovel
- Expanded
mining and warm
slurry
production
extraction for incremental bitumen
catalyst bed hydrocracking
for the incremental bitumen conversion
(primary upgrading) capacity
In its most recent application, Syncrude
proposed to modify its original design to include
the hydraulic transport (hydrotransport) of oil
sand which it believed was an improvement over
the original design.
The original expansion project approval was
based on a maximum level of SCO production
after expansion of 15.0 million m3/yr. Syncrude
requested that the approved SCO production
limit now be amended to specify 17.6 million
m3/yr to reflect the full capability of the expan
sion project when added to the requested new
limit of 12.6 million m3/yr for the existing
facilities. The specific capacity
of the expansion
project could ultimately be anywhere from 14.5
to a maximum of 17.6 million nrr/yr.
Syncrude also applied for a 5-year extension (to
December 1997) to the date by which construc
tion of the expansion project must proceed. It
argued that the business climate, to this point in
time, had not favored proceeding with a major
expansion and current conditions continued to
remain unfavorable.
Bitumen Supply
Syncrude's bitumen production forecasts con
tained in the application were based on a
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
12.0 million m3/yr level of SCO production with
an expansion to 15.0 million m3/yr in 1998. To
achieve this higher level of production over the
requested project duration would require addi
tional oH sands mining areas beyond those
described by Syncrude in previous applications
to the Board. Syncrude was therefore seeking
approval for additional mining areas within the
approved project boundary (Figure 1). Bitumen
supply
profiles in the application also identified
some bitumen from sources other than the cur
rent Syncrude mine. Syncrude did not, however,
request approval for specific off-lease sources at
this time.
Atmospheric Emissions
Syncrude provided estimates of the mass of at
mospheric emissions resulting from its Mildred
Lake operations. The specific emissions that
were identified include sulfur dioxide (S02), car
bon dioxide (COJ, oxides of nitrogen NOx),
hydrogen sulfide (HS), particulates (including
heavy metals), and hydrocarbons Including
Volatile Organic Compounds (VOCs).
Table 1 summarizes Syncrude's evidence regard
ing the actual and predicted emissions from its
facility for some of the major pollutants that are
released on a continuous basis from the main
stack.
Syncrude also acknowledged that indirect emis
sions from on-site and off-site generation of
electricity used for its project would add in the
order of 640 tonnes of per C02 day for the
10.0 million m3/yr design case and 778 tonnes
per day for the 12.6 million m3/yr case.
Syncrude acknowledged that the diverter stacks
and flare stacks emit S02, HS, particulates, and
other emissions on an intermittent basis and can
contribute significant volumes during individual
flaring and diverting
events. Current use of the
diverter stacks appears to occasionally result in
off-site odors and exceedances of ambient air
quality objectives, but Syncrude argued that this
would not become any
development proposal.
worse with its staged
34
Health Impacts
Syncrude commissioned a study which at
tempted to evaluate the potential health risks to
people living in Fort McKay and Fort McMurray
as a result of exposure to only atmospheric emis
sions from the Syncrude facility (i.e., excluding
other sources, including Suncor emissions). The
study considered potential risks from both longand
short-term exposures based on predicted
average and 1-hour maximum emission levels. In
both cases the study
attempted to determine
whether the predicted level of exposure would
exceed a level believed to produce a measurable
hearth effect (the exposure limit). The study
found that none of the predicted long-term ex
posures resulting
from the Syncrude emissions
alone were greater than the accepted exposure
limits.
Reclamation
Syncrude's application requested approval by
the Energy Resources Conservation Board
(ERCB)
of its lease development and reclamation
plans with specific reference to plans for the fine
tails reclamation. Syncrude argued the Oil Sands
Conservation Act provided the Board with clear
jurisdiction to deal with reclamation matters in
the context of an oil sands mining operation.
Syncrude argued that, based on its research and
development work, it was satisfied that it could
reclaim its accumulated volume of fine tails in an
environmentally acceptable manner. It also con
cluded, however, that there was no single ap
proach available to manage the fine tails volumes
that was technically, environmentally, and
economically acceptable. Syncrude believed
that the optimal approach should integrate
volume management techniques with water cap
ping of fine tails (water-capped fine tails) as the
preferred reclamation approach.
To carry out the water-capped technique, mature
fine tails would be placed into the mined-out pit.
A layer of capping water would then be placed
on top of the fine tails to form a fresh water lake.
The capping layer would be of sufficient depth to
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
SOURCE: ERCB
FIGURE 1
SYNCRUDE OIL SANDS PROJECTMILDRED LAKE AREA
I FGEND
R.12 R.11 R.10 W.4M.
Approved Mine Outline
Proposed Mine Outline
Approved Woste Areos
Proposed Woste Areos
3-5
Approved Project Area
Proposed Project Areo
Approved Tailings Areos
Proposed Tailings Areos
T.94
T.92
T.91
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
TABLE 1
ACTUAL AND PREDICTED SYNCRUDE EMISSIONS
Historical Data 1986-1991
10.0 x106m3/yr (design)
12.6x106m3/yr
15.0x106m3/yr*
17.6x106m3/yr
(Tonnes per Day)
SO, CO, NS, Particulates
206.0 16,725 28.4 9.79
258.2 20,313 39.4 11.81
260.0 23,466 45.5 13.92
222.0 29,140 51.4 2.57
< 258.0 33,045 53.5 < 13.92
Based on the operations and facilities described in the 1987 expansion
application.
prevent mixing of the fine tails and water. At the
interface between the fine tails and capping water
a detrital layer is expected to form which would
also serve to prevent resuspension of the fine
tails and would act as the primary zone for bac
terial decay of the naphthenic acids and other
organics released from the fine tails. The metabo
lism of these organics by bacteria would in turn
reduce the toxicity of the pore water to aquatic
organisms. After allowing sufficient time to en
sure the capping layer was non-toxic (estimated
to be 5 to 10 years), local surface run-off would
be Introduced to the lake with a discharge estab
lished to complete the connection to the local
site drainage system.
Syncrude argued the environmental significance
of Syncrude's fine tails was primarily a result of
the large volume rather than any associated
toxicity, which Syncrude believed to be relatively
short-lived. In Syncrude's view, the main environ
mental impact associated with the fine tails
volume was the additional land disturbance
which resulted from disposing
of coarse sand
tails outside of the mine pit in order to retain ade
quate space for fine tails in-pit. Recognizing this,
Syncrude proposed to continue to develop fine
tails volume reduction initiatives which were
economic.
3S
Socioeconomic Issues
Syncrude advised that its aboriginal
socioeconomic program had existed since the
beginning
of its Mildred Lake operations. It ex
plained that its current aboriginal program was
based on a loose integration of three com
ponents: community development; business
development; and training, education, and
employment.
Syncrude noted that since 1984 it had done more
than $98.0 million in business with aboriginal
companies. In 1993, approximately $20.0 million
of Syncrude's $150.0 million contract budget
went to these companies. Syncrude was target
ing for this value to reach $30.0 million by 1997.
Its commitment to aboriginal businesses has
been achieved through both soie-sourcing con
tracts and on occasion restricting bids to only
aboriginal contractors.
Syncrude reported that it currently directly
employs 284 aboriginals which was an increase
of 59 over the last 5 years. It noted also that the
turnover rate for aboriginal workers had
decreased from a high of 160 percent in 1980 to
a current level that is comparable or less than
that for its entire workforce. Syncrude targeted
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
to achieve, by 1997, a level of aboriginal employ
ment in Its direct workforce that was representa
tive of the proportion of aboriginals in the local
region. Syncrude suggested this would amount
to about 10 percent of its workforce or about
400 employees. In 1992 Syncrude implemented
a hiring policy that, in effect, required all entry
level positions to be filled by aboriginals.
ERCB Approval
In July 1994 the ERCB made the following rulings
with respect to Syncrude's application:
The request to increase the current SCO produc
tion limit from 10.0 to 12.6 million m3/yr, includ
ing the use of hydrotransport, is approved sub
ject to:
- Syncrude
- Syncrude
- Syncrude
maintaining atmospheric emis
sions from its facility at or below existing
limits and maintaining flare and diverter
emissions below an annual average of
5 tonnes per day of S02
pursuing appropriate oppor
tunities to further reduce its emissions
and reporting on its progress annually
developing ambient air quality,
sulfur deposition and biomonitoring
programs through consultation with
regional stakeholders and periodically
reporting
to the Board and other
stakeholders on the results of these
programs to assist in determining if cir
cumstances warrant changes to emis
sion limits for the plant
The request to extend the expansion approval
construction start date from December 31, 1994
to December 31, 1997 is approved subject to
Syncrude reviewing any significant modifications
to the project with Board staff prior to the com
mencement of construction. The production limit
for expansion will be increased to 17.6 million
m3/yr.
3-7
The request to extend the overall project ap
proval expiration date from December 31, 2018
to December 31, 2025 is approved essentially
without condition. The approval remains subject
to the Board's broad mandate to review and
modify any approval issued by it if sufficient jus
tification exists.
The request to import or export crude bitumen to
or from the Mildred Lake facility is approved.
The conceptual mining, lease development and
reclamation plans, including
the proposed water-
capped lakes technique for fine tails reclamation,
are endorsed subject to:
- Syncrude
- Syncrude
developing
a "base mine lake"
with a suitable monitoring program and
successfully demonstrating the as
sociated reclamation technique
continuing research and
development efforts into alternative
reclamation and tailings management
technologies
The mine and associated overburden dump west
of the McKay River is not approved at this time
and will require a separate application to the
Board once more definitive plans are in place.
The development of the base mine demonstra
tion lake is specifically approved subject to
Syncrude developing associated comprehensive
monitoring and scientific investigation programs
in consultation with its stakeholders.
####
CROWN ENERGY PLANS OIL SANDS PLANT
IN UTAH
Crown Energy Corporation of Salt Lake City,
Utah says it is completing the process of obtain
ing permits and arranging the financing
for con
struction of a commercial oil sands plant at As-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

0/L SANDS
phalt Ridge, near Vernal, Utah. The plant is
planned to process 6,400 tons per day, with an
output of 3,750 barrels per day.
Cost of the plant is estimated at $24 million and
production costs are expected to be $9 per bar
rel.
####
CORPORATIONS
SOLV-EX AND UNITED TRI-STAR
RESOURCES TEAM UP
Solv-Ex Corporation of Albuquerque, New
Mexico and United Tri-Star Resources Ltd. of Cal
gary, Alberta, Canada have agreed on a joint ef
fort to develop Solv-Ex's oil sands lease in Al
berta, Canada.
Terms of the agreement call for United to con
tribute $3 million to complete preconstruction re
quirements for a 5,000 barrel per day demonstra
tion plant. Also included in the agreement is the
formation of a joint venture to sell Solv-Ex's
recovery technology in Australia. The Solv-Ex
technology involves recovery of both bitumen
and metals (primarily aluminum oxide) from the
oil sands.
In return for its capital contribution, United will
receive a 10 percent working interest in the lease
and the exclusive right to arrange financing for
the demonstration plant, estimated to cost
$65 million.
Separately, Solv-Ex announced an agreement
with Suncor Inc. to obtain access to Suncor's tail
ings from its Fort McMurray oil sands plant.
Solv-Ex plans to process the Suncor tailings to
recover metal values.
####
3-8
MURPHY OIL SEES FAVORABLE PROSPECTS
FOR CANADIAN HEAVY OIL AND OIL SANDS
In remarks made by C. Demlng, President of Mur
phy Oil Corporation, to security
analysts in New
York City, New York in October 1994, he noted
that Murphy's efforts in Canada are dominated
by Its unique holdings of heavy oil. The advent of
intensive horizontal drilling, many times assisted
by steam, has substantially lowered per-barrel
capital and lifting costs. As a result, this resource
now provides good returns at current prices of
US$11.00 per barrel. Murphy's production is
7,300 barrels per day and will increase to
9,500 barrels per day by the end of 1995.
In addition, Murphy's 5 percent stake in
Syncrude is now an important part of the produc
tion mix in Canada. This asset is performing bet
ter than forecast in the all-important areas of
production volume and mining, extraction, and
upgrading costs, which respectively are forecast
for 1995 at 9,000 barrels per day (Murphy's
share) and US$11.50 per barrel. As North
American oil slowly but inevitably declines, this ir
replaceable asset, already
the largest single
source of crude in Canada, increases in value.
####
GOVERNMENT
OIL SANDS ORDERS AND APPROVALS
USTED
The recent orders and approvals in the oil sands
area issued by Alberta, Canada's Energy
Resources Conservation Board are listed in
Table 1 (next page).
####
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
Order Number
App 5641 E
App 571 8D
App6984B
App7164D
App 7515
App 7407
App6984C
App7306A
App
701 6C
TABLE 1
SUMMARY OF OIL SANDS ORDERS AND APPROVALS
Date DescriDtion
3 Feb 94 Commercial Oil Sands Schemes
Syncrude Canada Ltd.
27 Jun 94 Commercial Oil Sands Schemes
Consolidates App 4775
Amoco Canada Resources Ltd.
Primrose Sector
9 Jun 94 Primary Recovery Schemes
PanCanadian Petroleum Ltd.
Frog
Lake Sector
9 Jun 94 Primary Recovery Schemes
AEC Oil and Gas Co.
Frog Lake Sector
10 Jun 94 Primary Recovery Schemes
Purchase Oil and Gas Inc.
Lindbergh Sector
Expires/
Rescinds
31 Dec 2018
30 Jun 2018
1 8 Jul 94 Commercial Oil Sands Schemes 30 Jun 201 8
Consolidates App 5718
Amoco Canada Resources Ltd.
Primrose Sector
1 1 Aug 94 Primary Recovery Schemes
PanCanadian Petroleum Ltd.
Frog Lake Sector
31 Aug 94 Primary Recovery Schemes
Koch Exploration Canada, Ltd.
Cold Lake Area
27 Oct 94 Experimental Oil Sands Schemes 31 Jan 95
C.S. Resources Ltd.
Pelican Lake Area
3-9
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
ENERGY POLICY & FORECASTS
BITUMEN FROM TAR SANDS SEEN AS
HYDROCARBON FOR THE 21ST CENTURY
The long-awaited development of the world's
large resources of heavy oil and tar sands never
materialized in the 1980s and is not likely to be
harnessed in the 1990s. There is good evidence,
however, that these resources will play a
prominent role early in the coming century. That
is the conclusion reached by G. Stosur, of the
U.S. Department of Energy, and S. Karla, of
AGIO Oil and Gas Corporation, in a paper
prepared for the International Conference on
Problems of Complex Development and Produc
tion of Hard-Accessible Oils and Natural
Bitumens, held in Kazan, Tatarstan last fall.
Worldwide resources of bitumen are estimated at
over 3,000 billion barrels, with 62 billion barrels of
in situ bitumen in the United States. This com
pares with a worldwide estimate of conventional
crude oil reserves of 997 billion barrels, of which
25 billion barrels are in the U.S.
U.S. tar sand resources are separated into two
categories, depending on the degree of certainty
about the extent and nature of the resource:
- The
- The
measured resource, defined as the
bitumen resource defined with core and
log analyses
speculative resource, defined as the
bitumen that is presumed to exist from
reported tar shows on drillers'
lithological
logs and/or geological interpretations
The total U.S. tar sand resource is estimated at
61 .9 billion barrels of bitumen in situ. One-third
of this resource is well defined and is in the
measured category, while the remaining
resource is in the speculative range. Measured
resources are concentrated in Utah and Texas,
with over 70 percent occurring in those two
states (Figure 1).
3-10
The physical and chemical characteristics of U.S.
tar sand resources vary widely from deposit to
deposit. Most deposits occur in sandstone and
limestone formations, with the former having
a higher concentration of bitumen.
generally
Some of the minerals and metals that tend to ac
cumulate with bitumen include barium, nickel,
vanadium, titanium and zirconium. For illustra
tive purposes, some characteristics of the richest
U.S. tar sand deposits are shown in Table 1 .
The world's largest tar sand deposits are found in
the Athabasca area of Alberta, Canada. The
measured Canadian resource has been es
timated at 1.7 trillion barrels of bitumen in place,
or about 65 percent of the world's total. In addi
tion to being vastly larger than the U.S. tar sand
prospects, Athabasca deposits are significantly
richer and more concentrated than those found
in the United States. This makes them better can
didates for development.
Technical and Economic Potential for the
Development of U.S. Tar Sands
In response to the requirement by the U.S. Con
gress to evaluate the development potential of tar
sands in the U.S., a major evaluation of the U.S.
tar sand prospects was completed in 1994, in
cluding economic assessment of 26 projects. In
this study, potential bitumen recovery from tar
sands was estimated, assuming two distinct con
ventional recovery processes: surface mining
and steam soak.
The total technically recoverable bitumen from
surface mining methods in the U.S. was es
timated to be approximately 4.9 billion barrels.
Although this process technically can recover as
much as 80 percent of bitumen-in-place, it is also
more costly than the alternative process of steam
soaking. Economic analysis shows that the
threshold price for the most favorable surface
mineable tar sand deposit is approximately
$25 per barrel and that almost one-half of the
technically recoverable target can be produced
as liquid fuel at a price of around $45 per barrel
(Table 2). A significant portion of the production
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
FIGURE 1
SIZE AND DISTRIBUTION OF U.S. TAR SAND RESOURCES
c
E
3
m
o
CO
m
CD
20
10
SOURCE: ST0SUR AND KARLA
cost for mined tar sand is the cost of bitumen
upgrading~on average, $9.50 per barrel. This
cost is included in the analysis of the
price/supply relationship for surface mining
recoverable bitumen for liquid fuel, but is ex
cluded in the economic recovery
bitumen for the domestic asphalt market.
analysis of
The total technically recoverable bitumen from
the application of steam soak technology is es
timated to be on the order of 1 .0 billion barrels.
Although this process results in lower oil
recovery efficiency
of about 20 percent of
bitumen in place, it shows greater economic
promise for bitumen recovery at lower prices.
Economic analysis of steam soak prospects
shows that 0.4 billion barrels of bitumen could be
3-11
(1.3)
recovered at $20 per barrel and that one-half of
the technically recoverable target can be
produced at prices of about $25 per barrel.
Table 2 summarizes the result of the assessment
of technical and economic potential of bitumen
recovery from surface mining and steam soak
processes in the United States. The results of
this study indicate that with conventional extrac
tion technologies, bitumen from U.S. tar sands
can make a significant contribution to the domes
tic need for hydrocarbons, but at higher oil
prices. More efficient technologies for advanced
extraction, upgrading, and in situ recovery are
necessary before bitumen extraction can be a
commercially viable future source of hydrocar
bons in the U.S.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
Reservoir/
Bitumen Properties
TABLE 1
CHARACTERISTICS OF THE RICHEST TAR SAND DEPOSITS IN THE U.S.
Resource In-Place (million bbls)
Avg. Richness (bbls of bitu
men/acre-foot)
Depth (feet)
Viscosity (cp)
Gravity (API)
Recovery Option
1,900 1,110 4,370 6,100 1,730
1,070 1,394 860 953 1,235
400-3,500 2,160-3,500 0-300 0-500 50-400
47,000 15,000 +
400,000-
1,000.000
100,000
9.6 6 9 8 (-7)-2
in situ in situ surface surface surface
TABLE 2
RECOVERABLE TAR SAND RESOURCES IN THE U.S.
Crude Oil Price Surface Minina
mining and mining and mining and
in situ in situ in situ
Total
fcl985/Bbh Liauid Fuel Asohalt Steam Soak Liauid Fuel Asohalt
20 1.1 0.4 0.4 1.5
25 0.4 1.4 0.5 0.9 1.9
30 0.9 2.0 0.6 1.5 2.6
35 1.4 2.1 0.8 2.2 2.9
40 1.6 4.2 0.8 2.4 5.0
45 2.1 4.3 0.8 2.9 5.1
50 4.2 4.3 0.9 5.1 5.2
Total (Technically
Recoverable Target) 4.9 4.9 1.0 5.9 5.9
3-12
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
The conclusions based on the recovery potential
of the U.S. tar sand resource may not apply to
the exploitation of the massive and richer
deposits of tar sands found in other parts of the
world, particularly in Canada and Venezuela. In
fact, a study of worldwide crude oil supply shows
that this source of hydrocarbons may contribute
over one-half of the world's energy supply by mid
21st century (Figure 2). This figure is particularly
Interesting for its depiction of sequential contribu
tion of various hydrocarbon resources to the
world crude oil supply. Following the contribu
tion of enhanced oil recovery, which is shown to
peak at around 2025, the extra heavy oil and
bitumen contribution continues to rise until about
2075.
FIGURE 2
Conclusions
Stosur and Karia conclude that large-scale
development of the world tar sand resources will
not materialize in this,
or even the next decade;
but it will likely be harnessed early in the coming
century.
WORLD CRUDE OIL SUPPLY AND
U.S.-based tar sand resources, while significant
on a worldwide scale, are still much smaller than
those found in Canada and Venezuela, geographi
cally less concentrated, generally not as rich, and
located in environmentally sensitive areas. A
large-scale commercial development of U.S. tar
sand resources will require a higher level of tech
nology than available today, combined with im-
THE RELATIVE CONTRIBUTION OF EXTRA HEAVY OIL AND TAR SANDS
Million Barrels Per Day
60
SOURCE: STOSUR AND KARLA
-
1900 1925 1950 1975 2000 2025 2050 2075 2100
3-13
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
proved environmental mitigation techniques and
significantly
higher oil prices.
However, the authors suggest that certain small
deposits of tar sands which also contain a high
concentration of certain metals may be
developed first; coproduction of metals could
provide sufficient synergy to make these deposits
commercial.
####
TECHNOLOGY
COMBINED HSC ROSE PROCESS OFFERS
NEW ROUTE FOR UPGRADING HEAVY
FEEDSTOCKS
The High conversion Soaker Cracking (HSC)
process is one of the latest upgrading tech
nologies for bottom-of-the-barrel, licensed by
Toyo Engineering Corporation (TEC), Japan.
The HSC process is an advanced continuous
thermal cracking technology, featuring a wide
range of conversion levels between visbreaking
and coking while producing pumpable liquid
residue at process temperature.
A broad range of heavy feedstocks such as
heavy crude, oil sand bitumen, long and short
residue and visbroken residue can be charged to
the HSC process.
The cracked distillates from the HSC process are
mostly light and heavy gas oils with fewer un
saturates than coker distillates.
The process uses no hydrogen, no catalyst and
no high pressure equipment. The investment
cost and utilities consumptions are only slightly
higher than those of the conventional visbreaker
with vacuum gas oil recovery.
3-14
Process Description
Feedstock is first charged to a charge heater
achieving temperatures of 440 to 460C, depend
ing
(Figure 1). Cracking
on the desired conversion in the soaker drum
in the heater tube is mini
mized by employing high liquid velocity and
steam injection.
The heater effluent passes into a soaking drum,
where sufficient residence time is provided to
crack to the desired conversion. The soaking
drum is operated under atmospheric pressure
with steam injection for stripping at the bottom of
the drum.
In the soaking drum, liquid flows downward pass
ing
through a number of perforated plates to the
bottom. Steam with cracked gas and distillate
vapors flows upward through the perforated
plates, countercurrent to liquid flow, up to a free
board in the top of the drum where they are
separated from the liquid.
Temperature in the drum decreases from top to
bottom due to adiabatic reaction and stripping of
cracked distillate. The liquid from the bottom is
pumped out and quenched by heat exchange to
temperatures below 350C.
Vapors from the soaking drum are transferred to
a single combination tower, where the distillates
are fractionated into desired product oil streams
including a heavy (vacuum) gas oil fraction.
Coke-Free Operation
Conversion by conventional visbreakers is limited
by the stability of the visbroken residue. High
conversion operation of the conventional
visbreaker tends to produce unstable residue
with excessive precipitation of asphaltene ag
gregates which eventually leads to coking in the
plant.
In the HSC process, however, a homogeneous
stable dispersion of asphaltene in the residue is
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
SOURCE: TOYO
FIGURE 1
HSC PROCESS FLOW DIAGRAM
CHARGE HEATER SOAKMQ DRUM FRACTIONATOR LOO STABILIZER GAS COMPRESSOR
STM
ft
z rr=
Feed Stock
STM
maintained in the soaker and throughout the
process even at a much higher conversion levels
than conventional visbreaking.
Coke-free operation at high conversion is made
possible by the following technical innovations to
conventional visbreaker concepts:
- Thermal
- High
- The
cracking takes place in a rela
tively large soaking drum under deep
steam stripping conditions.
turbulence in the liquid phase is
maintained by steam bubbles in the soak
ing drum.
multi-stage structure of the drum
minimizes back-mixing of the axial flow
of liquid.
The stability of the liquid in the soaker is sig
nificantly improved by deep steam stripping
3-15
Sour Gas
Crude Naphtha
HGO
LGO
HSC Residue
which minimizes the heavy
ponent remaining in the liquid phase.
cracked oil com
With these advantages, the HSC process has ver
satility in selecting cracking severity. The maxi
mum attainable severity of cracking, however, is
limited by viscosity of the cracked residue. When
the residue is to be utilized as liquid fuel oil, it is
generally recommended that the R&B softening
point of the residue be limited to under 100C.
Where a solidified residue is acceptable, such as
for burning in coal-fired boilers, the cracking
severity may be increased up to the limit where
the R&B softening point of the residue reaches
150C. At this cracking severity, the viscosity of
the residue at the HSC process temperature is
acceptable as a feedstock for gasification by par
tial oxidation process.
HSC-ROSE Combination
For more complete recovery of valuable oil
products from the bottom-of-the-barrel, an op-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
timized combination of the HSC and the ROSE
(Residuum Oil Super-Critical Extraction) Process
has been developed and offered jointly by TEC
and Kerr-McGee Corporation, the licensor of the
ROSE process.
In this combination, HSC residue is further deas-
phalted by the ROSE process to recover asphal
tene free oil (DAO), which is utilized after
hydrotreating, as an additional feedstock to an
FCC or hydrocracker (Figure 2).
An innovative concept in this process combina
tion is to optimize the thermal cracking conver
sion in the HSC process and the depth of extrac
tion in the ROSE process so that the total liquid
product yield is maximized. The flexibility af
forded by the HSC process in selecting thermal
conversion levels is a prerequisite for this op
timization because optimal conversion by ther
mal cracking for most feedstocks is higher than
conventional visbreaking. Hydrotreating also
plays an important role in completing this
primary upgrading scheme.
The advantage of this system is an extra high liq
uid yield by a combination of relatively simple
and inexpensive processes.
FIGURE 2
HSC-ROSE PROCESS
riwidm
"-
1
""d
Cend*n*d AtphaltenM
SOURCE: TOYO
HSC Di!ill!
OAO
Hy*o-
... taatw, ,
3-16
The residue from the HSC-ROSE process is a
condensed asphaltene with a high softening
point (R&B 200C) which Is produced as solid
flakes.
This residue is used as solid fuel in coal-fired
boilers. Due to its relatively high volatile matter
content (35-45 weight percent), combustibility is
much better than petroleum cokes from the con
ventional coking process (volatile matter content
is less than 10 weight percent).
In addition to its use as a quality fuel, the HSC-
ROSE residue is an effective coking binder for
production of high-quality cokes from low-grade
carbon materials such as non-coking coals, lig
nites and even from peats, bagasse and waste
products of the forestry industry.
Some examples of product yields from the HSC
and the HSC-ROSE process, in comparison with
conventional processes, are shown in Table 1
(next page).
Relative investment costs for each process are
also given in Table 1 for a quick comparison in
order of magnitude.
####
PRODUCTION PROBLEMS IN COLD LAKE
SHALEY OIL SANDS ANALYZED
The highly viscous bitumen from the Cold Lake
reservoir in Alberta, Canada is produced by the
Cyclic Steam Stimulation (CSS) process. The
clean oil sands of the Cold Lake reservoir
generally produce well, but the shaley oil sands
with imbedded clasts have experienced lower
bitumen production and lower steam injectivity.
A paper by T. Chakrabarty of Imperial Oil
Resources Limited and J. Longo of Exxon
Production Research Company in the December
issue of The Journal of Canadian Petroleum Tech
nology presents an analysis of the problem.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
TABLE 1
COMPARISON OF PRODUCT YIELDS AND INVESTMENT COST
(Feedstock: Arabian Light Vacuum Residue)
Process Pro Delayed HSC-
duct Yields fWMU Visbreaker H$C Coker RQSE Flexicoker
Gas 1.7 2.5 -
Distillate 16.5 37.5 -
3.0 10.7 3.0 10.0
57.0 56.5
71.0*
- Residue 81.8 60.0 40.0 32.8 26.0
Relative Invest
68.0
15.5**
(Heavy Fuel Oil) (Pitch) (Coke) (Solid Pitch) (Low-BTU Gas)
0.5 (Coke)
ment Cost 35 50-65 100 105 125
?Includes DAO
**Fuei oil equivalent
Operations
Cold Lake reservoir bitumen has a viscosity of
about 100,000 centipoise at reservoir tempera
ture. Imperial Oil Resources Limited is using the
CSS process to recover the bitumen. The wells
are drilled directionally from one surface location
and there are 20 wells in one pad. In one cycle,
steam is injected over a period of 30 to 40 days,
and a hot bitumen and water mixture is produced
over several months. Each well goes through
several cycles of injection and production until
steam injection becomes uneconomic.
Since 1964, Imperial Oil has been piloting the
CSS process at Cold Lake. Piloting operations
have been expanded leading to the startup of
commercial production, known as CLPP (Cold
Lake Production Project), in 1985. Cold Lake
operations have the capacity to produce
14,000 cubic meters per day of bitumen.
Most of Cold Lake's production prior to CLPP
has been from clean oil sands in the Clearwater
formation. Variable reservoir quality
and in
3-17
creased heterogeneities were encountered in
CLPP. Although the current Cold Lake opera
tions are, in general, in good quality oil sands,
the future development will have to deal with oil
sands with lower bitumen saturation, top gas, top
water and bottom water. In addition, there are oil
sands with varying amounts of shale interbeds
and clasts, which are relatively consolidated and
are imbedded in the clean oil sands. The part of
the Cold Lake reservoir with shaley oil sands is
referred to as the "complex"
reservoir.
Production from some of the pads of the com
plex reservoir has not been satisfactory. For ex
ample, steam injectivity in one pad in the first
cycle was normal, but the production rate was
one-quarter to one-third of that of a normal first
cycle at Cold Lake. The second cycle steam in
jectivity was very low and the production rate
was so tow that the pad was shut-in. Because of
the significant size of the reserve in the complex
reservoir, it is important to determine the cause
of the production problems in order to develop
appropriate remediation and prevention
methods.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
Chakrabarty and Longo present laboratory and
field data that support the hypothesis that the
minerals in the ciasts play a role in the produc
tion problems of the shaley oil sands. Laboratory
tests reveal that ciasts in the shaley oil sands
have an abundance of carbonate minerals such
as sWerite (iron carbonate) and aluminosilicate
minerals such as kaolinite and feldspar.
Laboratory
studies under steam stimulation con
ditions show that the mineral reactions between
carbonates and aluminosilicates can generate for
mation damaging products such as swelling clay
and carbon dioxide.
Swelling clay can damage the formation by plug
ging the pore throats, whereas carbon dioxide
can lead to near-well-bore scaling. Calcium car
bonate scales have been observed in downhole
pumps and liners in Cold Lake wells. The field
bitumen production appears to be inversely corre
lated with the carbonate content of the ciasts.
The field bitumen production is also inversely
correlated with the amount of carbon dioxide gen
erated in the laboratory by
tions of ciasts.
Chakrabarty
hydrothermal reac
and Longo conclude that the
bitumen production potential of a well can be pre
dicted from the carbonate content of the ciasts
and the amount of CO, generated in the
laboratory by
mineral reactions. The higher the
carbonate content and the higher the C02 gener
ated, the lower is the bitumen production poten
tial.
Possible remediation methods for the production
problems in the complex reservoir include HCI
and EDTA to dissolve calcite scales, and mud
acid to dissolve clays and silica.
Possible prevention methods for the production
problems in the complex reservoir include 1)
avoidance of the potentially troublesome part of
priori"
the complex reservoir by "a assessment of
the reservoir quality, and 2) changes in the
operating conditions of the cyclic steam stimula
tion process.
####
3-18
INTERNATIONAL
INTEREST BUILDING IN CHINA'S TAR SANDS
In China, tar sands deposits have been found in
Xinjiang Autonomous Region, in Inner Mongolia
Autonomous Region, and in Qinghai and Sichuan
Provinces. However, only a little work on the
geological exploration of tar sands has been
carried out to date.
Zhun GeEr Basin in Xinjiang Autonomous
Region
Tar sands are widely distributed in the
northwestern part of the Zhun GeEr Basin of Xin
jiang
Examples include Hong San Zui District,
Karamay-Hei You San District, Bei Jian Tan Dis
Autonomous Region in northwestern China.
trict, and Wu Er He District. Only preliminary in
vestigations have been completed.
Tar sands in the Hong San Zui District belong
geologically to the Cretaceous Period; in
Karamay-Hei You San they belong to the Triassic
and lower Jurassic Periods; in Bei Jian Tan they
belong to the Jurassic and Cretaceous Periods;
and in Wu Er He District they belong to the
Cretaceous Period.
Hong San Zui tar sands have been found in an
area of about 70 square kilometers, with an effec
tive thickness of about 6 meters, near the ground
surface. The porosity of the deposit is
28 percent, the bitumen content is about
7.7 percent, and geological reserves are es
timated at 20 x 106
tons of bitumen.
Karamay-Hei You San tar sands have been found
over an area of about 45 square kilometers, with
an effective thickness of about 8 meters, near the
ground surface. The porosity of the deposit is
25 percent, the bitumen content is about
8.3 percent, and geological reserves are believed
to be 25 x 106
tons of bitumen.
Bei Jian Tan tar sands have been found over an
area of 40 square kilometers, with a thickness of
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
8 meters. The porosity is 28 percent, the
bitumen content about 7.7 percent, and the
geological reserves are estimated to be 10 x 106
tons of bitumen.
Wu Er He tar sands occur in an area of about
20 square kilometers, with a thickness of
10 meters. The porosity of the deposit is
25 percent, the bitumen content is about
7.8 percent, and the geological reserves are
believed to be 1 5 x 1 06
tons.
In total the known geological reserves of bitumen
from tar sands in the Zhun GeEr Basin in Xinjiang
is about 60
x106
tons.
Erlian Basin in Inner-Mongolia Autonomous
Region
The Gilgerantao depression of the Erlian Basin is
located northwest of Xilinhaote City in Inner-
Mongolia Autonomous Region, with an area of
1,000 square kilometers (from east to west,
70 kilometers long, from north to south,
14 kilometers in width). Tar sands reserves have
been found in the eastern and western parts of
the depression, with a total area of about
28 square kilometers.
The tar sand in this depression belongs to the
lower Cretaceous Period. Three layers of tar
sands have been found from the outcrop
to a
burial depth of 200 meters. The total thickness of
the tar sand layers ranges from 4 to 20 meters.
The porosity
of the tar sand is about 27 to
36 percent, its saturation being about 35 to
70 percent, with bitumen content of 9 to
15 percent.
Proven reserves of bitumen in these layers ac
counts for about 20 x 106
tons totally.
Tar Sands and Bitumen Characteristics
The contents of bitumen,
water and solids in
several Chinese tar sands samples were deter
mined by using toluene as extraction agent and
using the modified Dean-Stark Soxhlet extraction
3-19
method. The elemental analysis, group analysis
and distillation range of bitumen extracted were
also determined. The results are listed in Table 1
(next page). Data for Canadian Athabasca tar
sands are also listed for comparison. The
properties of Karamay bitumen are better than
the Erlian bitumen. The atomic ratio of H/C is
1.56, slightly higher than for Athabasca bitumen.
The distillation temperatures are not high. Sulfur
and asphaltene contents are low. This indicates
that Karamay bitumen is somewhat easier to
process into a synfuel than Athabasca bitumen.
Extraction Techniques
It has been found that hot water extraction is not
effective for Erlian tar sands even at a high tem
perature of above 90C. However, it is effective
for Karamay tar sands, and the bitumen recovery
reaches 78 percent at a temperature of 93C.
According to Professor J.L Qian of Petroleum
University in Beijing, the study of Chinese tar
sands reserves and characteristics has just
begun.
####
NATURAL BITUMENS OF TIMAN-PECHORA
PROVINCE IN RUSSIA SHOW PROMISE
A paper titled "Perspectives of Natural Bitumens
of the Timan-Pechora Province Development"
was presented by B. Bezrukov of the All-Russian
Petroleum Scientific Research Geological Ex
ploration Institute, St. Petersburg, Russia, at a
conference held in Kazan, Tatarstan in October.
He notes that the major oil and gas develop
ments of the Timan-Pechora Province have taken
place in the territory of the Komi Republic, where
a steady decline in production over the last
10 years has been observed. This problem may
be partially solved by exploitation of new pools or
intensification of production in old areas.
However, Bezrukov says that the development of
the known natural bitumens and heavy oils also
has a great significance because they account
for a considerable part of the total balance of
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
Contents, Wt% of Tar Sands
Bitumen
Water
Solid
Bitumen Properties
Elemental Analysis, Wt%
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
C/H Molal Ratio
Hydrocarbon Group, Wt%
Saturate
Aromatic
Resins
Asphaltenes
Distillation Temperature, C
Initial Boiling Point
5Vol%
10Vol%
20Vol%
30Vol%
50Vol%

OIL SANDS
In addition to using these natural bitumens to ob
tain hydrocarbons, they also can be used as a
high quality source for chemicals for the
electrotechnical industry, lacquer industry, road
building, extraction of vanadium, nickel and other
accompanying components, etc. The develop
ment of natural bitumens in the future would
make it possible to reduce the volume of oil
needed for the production of technical bitumens.
####
PROSPECTING FOR BITUMEN IN MONGOUA
COULD BE PROFITABLE
A perspective on the Mongolia energy situation
was provided by V. Isayev of Irkutsk State Univer
sity, Russia, at the International Conference on
Problems of Complex Development and Produc
tion of Hard-Accessible Oils and Natural
Bitumens held in Kazan, Tatarstan in
October 1994.
According to Isayev, the Mongolia energy
economy is based on coal. That is why they con
sider the prospecting for, and exploitation of, oil
deposits to be the most important economic,
energy
and environmental problem.
The first (and to date, only) deposit of highly vis
cous oils was discovered by Soviet geologists in
the 1950s in the Eastern Gobi. Heavy, resinous
oils occur at depths of over 1,000 meters. A
sample of oil selected by the author at the Dzun-
Bayan oil deposit has the following characteris
tics:
- Kinematic
- Resin
- Asphaltene
- Hard
Density 0.885
viscosity 46.7 millimeters per
second at 50C
content 20.75 percent
content 1 .37 percent
paraffins content 22.43 percent
3-21
- Sulfur
Prospecting
content 0.3 percent
for new occurrences of these oils
must be carried out at greater depths. The
development of these occurrences will then take
place by injection of steam for lowering the vis
cosity. This will increase the completeness of oil
extraction from the layer.
Isayev believes that, for the present economic
situation of Mongolia, a more profitable course
would be the study and exploitation of natural
bitumen occurrences which are not deeply
buried or which outcrop on the earth's surface
and do not require large expenditures for
prospecting.
Bitumen sands at Bayan-Erchet and Dzun-Bayan
were examined by an Irkutsk University expedi
tion. They contain 13-16 percent bitumen, in
which 24-36 percent are hydrocarbons. The
bitumens contain 7.4 to 8.5 percent heavy paraf
fins. Elemental composition of bitumen shows
carbon = 84.3 to 85.8 percent, and
hydrogen 11.7 percent. The exploitation of the
occurrences is possible by opencast mining
methods. After the extraction of hydrocarbons,
the remainder is useful for production of road as
phalt and bitumen for construction materials.
Isayev says there are all the necessary geological
conditions for the discovery of new occurrences
in Mongolia. Modern technologies for develop
ing the heavy oil accumulations and natural
bitumen would allow Mongolia to create its own
base of hydrocarbon raw materials.
####
ENVIRONMENTAL PROBLEMS SEEN FOR
BITUMEN DEPOSITS OF TATARSTAN
At an international conference held in Kazan,
Tatarstan in October, a paper by
B. Anisimov et al. of TatNIPIneft Institute,
Bugulma, Tatarstan, states that the development
of bitumen deposits compared with oil reservoirs
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
results In increased pollution hazards for the en
vironment.
First, the bitumens and associated mineralized
waters which are brought to the surface contain
hydrogen sulfide and such other harmful inclu
sions as metals.
Second, bitumens occur close to the surface, at
the lower boundary of fresh ground waters.
Therefore, any
thermal or physical-chemical
stimulation of the producing formation can
directly influence the air, fresh subsurface and
surface waters.
The most explored Tatarstan bitumen deposits in
the sandstones of the Sheshminski horizon occur
at depths of 50-70 meters and 100-130 meters.
They are covered by clay cap rock (argillites)
6-12 meters thick. An overlying water-bearing for
mation of limestone is used for household-utility
purposes in the nearby inhabited areas. Even
under natural conditions,
"traces"
of bitumen
manifest themselves in this water-bearing forma
tion by hydrogen sulfide content, increased
mineralization of water, etc. This is due to poor
isolating properties of the clay cap rocks due to
the presence of tectonic fissures. Therefore,
there are already a number of inhabited areas
that suffer from a deficit of fresh subsurface
waters.
Development experience in the Mordovo-
Karmalskaya deposit of bitumen, using in situ
thermal methods, shows increases in the tem
perature and pressure of the overlying water
bearing formation, changes of chemical composi
tion of the water and a worsening of its quality.
The presence of hydrogen sulfide and mercap-
tans in the air has been observed.
The development of bitumen deposits by under
ground and surface mining methods will require
water drainage and the reclamation of wastes. It
can lead to dewatering of upper water-bearing
layers, and as a result the nearby inhabited areas
will remain without water.
3-22
Due to the shallow depth of burial of the
bitumens, any
certain negative consequences for the environ
method of development can cause
ment. Therefore, say the authors, prior to prepar
projects for the development of bitumen
ing
deposits it is necessary to study
in detail the
hydrogedogic conditions; carry out analyses;
and forecast the ecologic consequences of the
recommended technologies of application.
Conductance of pilot projects should include,
together with the try-out of bitumen recovery
technology, the development of environment
protection methods.
####
FOURTEEN IN SITU COMBUSTION
PROJECTS ACTIVE WORLDWIDE
In 1994 there were at least 14 active commercial
In Situ Combustion (ISC) projects worldwide,
says A. Turta of the Petroleum Recovery Institute
in Calgary, Alberta, Canada. More than 160 ISC
pilot projects have been carried out since the
1930s. Turta spoke at last year's Symposium on
Field Applications of In Situ Combustion.
A review of ISC projects was carried out in order
to emphasize the important factors which con
tributed to the success of the processes. Accord
ing to Turta, success in developing an ISC pilot
into a commercial ISC project is strongly con
nected with two factors: 1) starting the operation
from the uppermost part of the structure and ex
tending the process downward and 2) applica
tion of the line drive well configuration instead of
patterns, whenever it is possible. An effective,
peripheral line drive operation requires pool
unitization.
Background
Patented in 1920 in the United States, the first
short-term field pilot took place in the former
Soviet Union in 1933-1934, while the true testing
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
of an ISC process occurred in the United States
in 1950-1951.
The process has been extensively studied both in
laboratory
and in field pilots. Although there has
been a great deal of work in this area, the general
acceptance of the process is still debated. Ac
cording to Turta, the causes for this situation in
clude:
- The
extreme complexity of the process,
coupled with difficulties in understanding
how ISC works as a displacement
process
Field. Country
W. Newport, USA
Lost Hills, USA
Midway Sunset, USA
Midway Sunset, USA
S. Belridge, USA
Bellevue, USA
W. Heidelberg, USA
Forest Hill, USA
Buffalo, USA
Brea Olinda, USA
Karajanbas, Kazakhstan
Balahani, Azerbaijan
Battrum, Canada
Morgan, Canada
Suplacu de Barcau, Romania
W. VkJele, Romania
E. Videle, Romania
W. Balaria, Romania
E. Balaria, Romania
TABLE 1
- Labor
- Difficulties
intensive character of the process
in evaluation of the pilot, due
to the fact that the pilots were conducted
in a pattern or patterns which did not
form a confined zone
Lack of vision in the design of the ISC
pilots for further development of the field
process
COMMERCIAL ISC PROCESSES
Commercial In Situ Combustion Projects
Table 1 presents the main information on com
mercial ISC processes. The oldest process is
Daily
Oil Air/Oil
Viscosity Prod. Prod, by Ratio
DeDth. Ft. GE Inj. Wells Wells ISC BOPD SCF/Bbl
1,600 750 36 139 980 10,700
300 410 7 45 520 6,200
2,700 110 3/up 31 900 6,700
1,700 5,000 10 40 700
1,100 1,600 2 ? 900 6,000
400 660 15 85 420 16,300
11,300 6 3/up 9 400 10,000
5,000 1,060 21 100 400
7,650 2 9 26 930 7,000
3,300 20 2/up 20 650 7,700
1,100 450 78/LD 364 6,000
910 140 6/up 35 600 6,700
2,900 70 25 151 6,900 10,000
1,940 8,100 9 35 940
400 2,000 132/u-L 527 9,000 12,300
2,500 100 19/u-L 50 610 17,000
2,100 100 33/u-L 89 660 21,000
2,200 116 22 60 820 24,500
1,500 416 15/u-L 47 550 22,500
3-23
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
West Newport, USA at 33 years, while the
youngest is Karajanbas, in West Kazakhstan near
the Caspian Sea, at 1 1 years. Fourteen out of
these nineteen projects are currently active. As
of April 1992, the incremental daily oil production
due to ISC was approximately 4,700 barrels of oil
per day (bbl/d) (from 8 processes) in the United
States, 8,000 bbl/d (from 10 processes) in the
former Soviet Union, 7,300 bbl/d (from
3 processes) in Canada and 12,000 bbl/d (from
5 processes) in Romania. Therefore, the 1992
world incremental daily oil production due to ISC
was about 32,000 bbl/d (from 26 reported
processes). The number of processes reported-
26~includes not only commercial but also some
semi-industrial processes, so that the oil produc
tion figure does not coincide with the Table 1
reported oil production.
Limited information is available on the commer
cial ISC projects. There is a chance that there
are other ISC commercial processes which have
been operated quietly for years.
For the commercial processes listed, the vis
cosity is in the range 5-8,000 centipoise.
The process can be applied in a wide range of
depths, from shallow to very deep reservoirs
(11,000 feet), and a wide range of permeability,
the lowest being 20 millidarcy.
The most important parameters, indicative of
economic efficiency, are AOR (Air/Oil Ratio) and
injection pressure. The AOR is in the range of
6,000 to 25,000 standard cubic feet per barrel for
Injection pressures of 200 to 3,700 psi.
Ways to Apply Commercial ISC Processes
Different types of well flooding networks may be
used for ISC applications. An idealized reservoir
with the lower zone (water/oil contact) and upper
zone distinctively marked, are shown in Figure 1.
There are two ways of applying ISC: in well pat
terns and line drive well configuration. The first
system could be applied as contiguous patterns
or isolated patterns. The location of patterns
3-24
may be upstructure or downstructure. All three
configurations have been tried, but most applica
tions used contiguous patterns and peripheral
line drive configurations. Isolated patterns were
only
process.
used in the West Newport commercial
As shown, the line drive is possible to be applied
only starting
from the upper part of the reservoir.
For this reason it is extremely important to place
the pilot upstructure. In this way, after the test is
finished, one can have both options of develop
ing to the commercial phase, that is, either line
drive or patterns.
The main advantages of the line drive over the
well pattern configuration are:
- The
- Full
- Evaluation
- Fewer
- Easier
line drive takes advantage of gravity
because the oil displacement is more
gravity stable.
avoidance of oil resaturation of the
burned area is possible.
of the process is easier
(mainly
recovery).
with respect to ultimate oil
Each producer is intercepted by the ISC
front only once. For the patterns system
as many as four ISC fronts may intercept
the producer, and the risks of damaging
the wells are higher.
artificial ignition operations are
needed with the line drive system, giving
the possibility just to make an air transfer
to the new row.
and more reliable tracking of the
ISC front is possible.
On the other hand, the main advantages of the
pattern configuration over the line drive system
are the use of different completions for injectors
and producers (including perforating different in
tervals in injectors and producers), and the
liberty to select any rate of oil production, by
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
LEGEND
$ COMBUSTION WELL
O PRODUCTION WELL
WOC WATER OIL CONTACT
SOURCE: TURTA
UNE DRIVE WELL NETWORK
(PERIPHERAL LINB DRIVE)
ISOLATED PATTERNS
CONTIGOUS PATTERNS
FIGURE 1
THREE WAYS OF APPLYING FIREFLOODING
(Idealized Oil Reservoirs)
DOWN ^
UP Kjt|JlJJ'J'J'J'f
DOWN P 9 9
UP
DOWN
UP fe
9 >
3 i-L
D-
i a a a
(X-
*
operating simultaneously as many patterns as
the operator wants. When several companies
are operating on the same reservoir, the applica
tion of the line drive requires unitization of the
pool, while the patterns system does not.
Turta's paper discusses cases where the location
of the field pilot had an important effect on the
ability to evaluate the pilot.
*
rf
rf
3
t
y
>
3-25
a
t
>
2
a_
D
*
9
n i a ii
*
(>
EL
JL
*
*
*
6
*
*
*r
i*.
*
*
Q.
*
f~
^WOC
9 o
o

OIL SANDS
was shown that the volumetric sweep efficiency
Increased from 59 percent for vertical wells to
70 percent for horizontal wells. The oil recovery
increased accordingly.
So far, horizontal wells-ln conjunction with an In
situ combustion process in the field-have been
drilled in two Canadian projects. In both cases
the horizontal wells were used as producers.
In the first project, Eyehill, Saskatchewan, three
horizontal wells with a horizontal leg of
1 ,000-1 ,2000 meters were drilled.
Of these three wells, the first one had a very
good production performance. This well
produced for a long time with oil rates of
55-60 cubic meters per day. The second horizon
tal well was situated on the other side of the first
horizontal well, too far from the project area and
probably it was screened by the first one. The
third horizontal well intercepted a portion of the
previously burned area and it had a mediocre per
formance.
In the second project, Battrum, Saskatchewan,
one horizontal well was drilled in conjunction with
the commercial wet combustion process which
has been in progress on this reservoir since
1964. This process takes place in a reservoir
having a relatively low oil viscosity. The horizon
tal well was drilled in December 1993 and it has a
horizontal leg of 610 meters. It was positioned
between the gas tongue and the water tongue in
an exploitation using the patterns system. The
performance of this well was very good as the oil
rate increased by 5-10 times (from 3 to 15 cubic
meters per day for a vertical well, to 35 to
75 cubic meters per day for the horizontal well).
So far, horizontal wells have been used only as
producers. However, the utilization of horizontal
wells could be extremely useful as injectors in
low injectivity reservoirs where they can open the
door for the application of wet combustion in
more cases. It is expected that horizontal well in
jectors will be used first in the reservoirs where
spontaneous ignition is easily achieved.
3-26
Possible Improvement of the Process
For ISC projects applied to heavy oil reservoirs
the volumetric sweep efficiency usually is poor,
less than 25-35 percent.
Given the ability of foams to achieve high resis
tance factors in oil-free rocks it appears that ac
tually the foam could have high efficiency when
applied with ISC processes. In this case the
other positive element for the foam use is that
after 6-7 months from the beginning of the
process, the temperature around the air
(air/water) injector is low, close to the reservoir
temperature. This creates favorable conditions
for foam application. Injected in the combustion
wells, the foam can significantly decrease gas
channelings.
The first foam field testing in the Karajanbas field
gave promising results.
It is expected that the greatest future progress in
application of ISC will be due to the use of
horizontal wells. The only
problem which still
remains when using a horizontal well as a
producer is that the combustion front can inter
sect the horizontal leg close to the heel and can
damage the whole horizontal portion
prematurely
of the well.
####
VENEZUELA IN SITU COMBUSTION
PROJECTS REVIEWED
At the Symposium on In Situ Combustion Prac
tices held in Tulsa, Oklahoma last year, a paper
by
M. Villalba et al. of INTEVEP presented a litera
ture review of four In Situ Combustion (ISC)
projects: in Miga, Tia Juana, Melones and
Morichal fields in Venezuela.
The behavior of the four field tests can be sum
marized as follows:
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
- The
- The
- For
The problems most often encountered
were corrosion and high temperature
producing wells.
direction in which the burning front
moved was guided essentially by reser
voir characteristics.
produced oil was upgraded by
about 4API, and viscosity was substan
tially reduced.
Morichal and Miga fields, the
analyses indicated that the process had
been successful in the affected region.
In Venezuela, the first ISC projects started at the
beginning
of the 1960s. Their impact was over
shadowed, at that time, by operation problems
(oil emulsification, corrosion of well equipment,
etc.) and the discovery of the cyclic steam injec
tion process. Cyclic steam has since become
the most successful and economic technique
used in Venezuela heavy oil fields. In spite of all
the disadvantages of the in situ combustion tech
nique, the authors believe it still has a high poten
tial for application to tar sand and heavy oil reser
voirs. Among its advantages are high thermal ef
ficiency, low impact on the environment, and it
uses less fuel than cyclic steam injection.
Morichal Test
The Morichal field test was located in Monagas
State in Eastern Venezuela, approximately
150 kilometers south of the City of Maturin (see
Figure 1).
An ISC pilot test was conducted in 1960 in an
unconsolidated reservoir to investigate the pos
sibility of recovering heavy (9
to 12
API)
oil at a
depth of 3,500-4,000 feet. Primary recovery from
these flat reservoirs is low (2-7 percent), and oil
viscosities range from 400-1,850 centipoise at
reservoir temperature.
An Isolated two-spot pattern with 329-foot spac
ing
was selected for this test. Air injection began
on June 8, 1960, and the pressure stabilized at
3-27
1,425 psi. Air injection was terminated on
May 17, 1962. Injection production history after
air injection termination can be followed in
Figure 2. The oil production rate rose gradually,
peaking at 365 barrels of oil per day in July 1963,
and thereafter declining to 100 barrels of oil per
day in June 1964 when the test was terminated.
Miga Test
The Miga field test was located approximately
25 kilometers south of San Tome, Anzoategui
State in the Northeastern part of Venezuela (see
Figure 1). From 1964 to 1985 a fireflood project
was carried out in the P2-3 sand reservoir in the
Miga field to stimulate production of 13
14
API heavy oil.
The original-oil-in-place was estimated at
22 million barrels. Only 1 .2 million, or 5 percent,
was expected to be produced by primary deple
tion. Up to April 1983, about 5 million barrels of
oil or 25 percent of the original-oil-in-place were
recovered by the use of the in situ combustion
process, and about 50 billion standard cubic feet
of air had been injected. The air/oil ratio
averaged 12 thousand cubic feet per barrel.
Based on this air/oil ratio, the project was con
sidered to be a technical and economic success.
Melones Field Test
A single injection well pilot test was carried out in
2.06 acres of the Melones field from 1977 to
1978. The purpose of the test was to evaluate
the combination of forward combustion and
water injection in an Orinoco heavy oil reservoir.
Figure 1 shows the location of the Melones field
in the Northeastern part of Venezuela.
The pattern consisted of an inverted five-spot pat
tern with a well spacing of 212 feet and two obser
vation wells.
This project encountered many difficulties in the
oil production wells. Plugging of the wellbore by
sand caused the productivity to decrease, and
workovers were necessary in August 1977.
During this period, the loss of large amounts of
THE SYNTHETIC FUELS REPORT, JANUARY 1995
to

OIL SANDS
FIGURE 1
LOCATION OF THE MIGA, MORICHAL, MELONES, AND TIA JUANA FIELDS
Ti'o Juono
SOURCE: VtLLALBA ET AL.
Injected air through the casing to the overburden
was observed, leading to the suspension of air in
jection. Once this problem was overcome, the
test was reinitiated from January 14 until 31 of
1978. At this time, an increase in C02 concentra
tion was observed, as well as a temperature rise
in the injector well, confirming combustion by
spontaneous ignition. However, failure in the
compression units along
with high temperature in
the injection well caused severe operational
Caribbean Sea
3-28
MELONES
MORICHAL
MIGA
problems leading to the suspension of the pilot
test.
Tia Juana Field Test
From November 1959 until February 1962, an
ISC field test was carried out in Block K-7 east of
Tia Juana. The test consisted of one inverted
seven-spot pattern with one injection well and six
producers with 438-foot spacing between injec
tor and producer.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
FIGURE 2
CUMULATIVE AIR/OIL RATIO VERSUS TIME, MORICHAL FIELD
< 200\STI HATED
NET DAILY OIL MATE
1960
SOURCE: VH.LALBA ET AL.
il*jti sit
i>iiiiieo
1961
Only four wells clearly responded to combustion
the first year of the test.
Only
one well of the pattern exhibited a major
production response from the main air flow chan
nel. Most of the air escaped outside of the test
pattern as did the oil displaced by combustion.
Conclusions
From the literature review of four ISC field tests
done in Venezuela, it can be concluded that the
two most frequent problems encountered were:
- Operational
- Controlling
problems due to the high
temperatures and corrosion problems in
producing wells.
the direction and rate of the
front. Combustion front
burning
breakthrough was often observed early
in wells which were located in the direc
tion of preferential air flow. This problem
emphasizes the need for a good descrip
tion of reservoir characteristics which is
critical in designing a successful in situ
combustion project.
####
3-29
1962 1963 1964
IN SITU COMBUSTION EXPERIENCE IN
ROMANIA REACHES 30 YEARS
In Situ Combustion (ISC) field experience in
Romania goes back to 1963. This experience
was summarized by V. Machedon et al. of the
Romanian Research and Design Institute for Oil
and Gas at last year's Symposium on In Situ
Combustion Practices, held in Tulsa, Oklahoma.
Starting with 1963, simultaneous pilot and semicommercial
steam flooding and in situ combus
tion tests were carried out at Suplacu de Barcau
(16
heavy oil field API). The performance of in
situ combustion was by far better and as a result,
the entire reservoir was designed to produce by
this method, by abandoning the "patterns"
con
cept and introducing the "continuous front"
con
cept. Under primary production, the ultimate
recovery factor would have been 9.2 percent,
while an ultimate recovery factor of at least
50 percent is expected by in situ combustion.
The authors note that after a fast increase-
between 1950 and 1970-of the number of ap
plied ISC projects, the numbers for this method
recorded an equally fast decrease and the prevail
ing trend became Steam Injection (SI).
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
As compared to SI, ISC requires a more exten
sive engineering effort, more difficult technical,
operating and control problems, more complex
monitoring, more people, more equipment and
hence more money; but all these could be com
pensated for by a higher recovery.
The authors believe the basic reason for the cur
rent lack of attraction of ISC is to be found in:
the low current oil price, the discouragement of
operators after the failure of some projects
carried out on improperly selected reservoirs,
and the higher overall effort necessary.
Suplacu de Barcau
Suplacu de Barcau oil field was discovered in
1958 and commercial production started in 1961.
The predicted production calculations showed
that under primary depletion the ultimate
recovery could amount to at most 9.2 percent
during a very long time interval, with reduced
daily production rates and involving high costs.
Steam Drive (SD) and ISC were concurrently
tested in the period between 1963 and 1970. The
response of the reservoir was more favorable in
the case of ISC:
- The
Total oil production from the pattern was
14,812 tons during 696 days by SD and
20,000 tons, during 670 days by ISC.
The average daily production of the en
tire pattern was 21.3 tons by SD and
29.9 tons by ISC.
average daily oil rate per well was
5.3 tons by SD and 7.5 tons by ISC.
semi-
The better performance of ISC during the
commercial stage led to the decision, in 1970, to
design the entire reservoir exploitation using this
method. The "pattern"
concept was replaced by
a "linear front"
or "continuous front"
concept.
The production increase as a result of switching
from patterns to continuous front was obvious
3-30
during the interval 1975-1976. By the end of
1993:
- Length
- Total
- There
- Oil
- Average
- Oil
- Incremental
of the combustion front was
8,900 meters
air injection rate was
106,650,280 standard cubic feet per day
were 457 producers in the combus
tion affected area
production rate from the combustion
affected area was 9,074 barrels per day
air/oil ratio was 1 1 ,620 standard
cubic feet per barrel
recovery
reached 33 percent
for the entire reservoir
production obtained by ISC
was 64,241 ,241 barrels
An ultimate recovery of at least 50 percent is ex
pected.
Balaria Field
The Balaria structure was discovered in 1960 and
put into production in 1963. In 1975 an ISC ex
periment started at West Balaria, in a direct five-
spot pattern, surrounded by four inverted five-
spot patterns. In 1979, two other patterns were
added. The experiment lasted until 1982. The
final evaluation, in 1983, led to the decision to
design a full-scale project for this reservoir.
Commercial production at West Balaria started in
1984 by extension of the area of the previous ex
periment to adjacent blocks. Twenty-two ISC in
verted patterns were designed and earned out on
three tectonic blocks.
By the end of 1993 the production in this area
reached its final stage; four patterns are still
operating, yielding 21 1 barrels per day through
36 wells. On the same date the recovery was
31.8 percent.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
Starting with 1987, ISC was also applied to East
Balaria. Due to the geometry specific to this area
a linear front was preferred, started at the upper
most part of the reservoir, according to the
model conceived for Suplacu de Barcau. The
favorable effect of ISC soon became obvious,
and the method proved to be efficient.
By the end of 1993, at East Balaria there were
12 air injection wells, and 66 production wells
yielding 402 barrels per day. An ultimate
factor of at least 33.1 percent is es
recovery
timated.
East Videle Field
The Videle oil structure, one of the most impor
tant in Romania, was discovered in 1959 and put
into production in 1961.
An In situ combustion experiment was initiated in
1979.
The oil production of the A1 pattern increased
from 1.8 tons per day to 10 tons per day, for
about 6 years.
The favorable results of the experiments carried
out at Balaria, East Videle and West Videle en
couraged a decision to proceed to the design of
an ISC project for the entire Sarmatian reservoir.
In July 1986, commercial production by ISC
started at the Sarmatian reservoir, with the opera
tions for chemical ignition being performed in a
progressive sequence from East toward the
West, in the entire initially designed length of the
combustion front.
&-31
By the end of 1993, the oil production obtained
from the ISC affected zone was 530 barrels per
day from 85 wells.
West Videle Field
The heavy
oil reservoirs in this zone were dis
covered in 1959 and put into commercial produc
tion in 1961.
It has been estimated that primary depletion
could yield an ultimate recovery
factor of
9-10 percent over a period of about 30 years.
In 1980 an ISC experiment began in an inverted
five-spot pattern. This pattern was operated un
der moderate wet combustion and production
results were good.
In 1984, an ISC pilot test started on the Sar
matian 3c. The results were equally good, which
led to the decision to design commercial opera
tion of both reservoirs by ISC.
Conclusions
In Romania, four major heavy oil reservoirs are
currently being exploited by ISC. Their total daily
oil production averages 10,987 barrels.
Oil recovery increases from 9 percent to over
50 percent are being
achieved in respect to
primary production at Suplacu de Barcau, where
ISC stands for secondary recovery, and from
10 percent to at least 35 percent at Balaria, East
Videle and West Videle fields, where ISC stands
for tertiary recovery.
####
THE SYNTHETIC FUELS REPORT, JANUARY 1995

OIL SANDS
3-32
THE SYNTHETIC FUELS REPORT, JANUARY 1995

- ASPHALT FROM TAR SANDS James
STATUS OF OIL SANDS PROJECTS
COMMERCIAL PROJECTS (Underline denotes changes since June 1994)
W. Bunger and Associates, Inc. (T-5)
J. W. Bunger and Associates, Inc. (JWBA) is developing a project for commercialization of Utah Tar Sands. The product of
the venture will be asphalts and high value commodity products. The project contemplates a surface mine and water extraction
of bitumen followed by clean-up and treatment of bitumen to manufacture specification asphaltic products. JWBA has secured
rights to patented technology developed at the University of Utah for extraction and recovery of bitumen from mined ore.
In 1990, JWBA completed a $550,000 R&D program for development of technology and assessment of markets, resources and
economics for asphalt production. Later in 1990 JWBA initiated a program for value-added research to extract high value
commodity and specialty products from tar sand bitumen. This program was initiated with an additional $50,000 in funding
from DOE.
Under this program funded by the U.S. DOE SBIR program, a 300 pound per hour PDU was designed and constructed. The
unit has been operated to determine the effect of process variables and kinetic parameters. Recoveries of greater than
97 percent have been experienced. The unit has been operated to produce gallon quantities of asphalt for testing and inspec
tion. A field demonstration unit of 200 barrels per day has been designed and costed.
Conceptual design and project economics for a 5.000 barrel/day commercial facility has been examined. Results show a strong
potential for profitability at 1994 prices and costs.
The commercialization plan calls for completion of research in 1995, construction and operation of a field demonstration plant
by 1997 and commercial operations by 1999. The schedule is both technically realistic and financially feasible, says JWBA.
Project Cost: Research and Development: $1.5 million
Demonstration project: $10 million
Commercial Facility: $135 million
- BITUMOUNT PROJECT Solv-Ex Corp. (T-20)
The Solv-Ex Bitumount Project will be a phased development of an open pit mine and an extraction plant using Solv-Ex's
process for recovery of bitumen and metals.
Solv-Ex will use a naphtha solvent to boost the power of hot water to separate oil from sand. The increased efficiency of the
process increases oil yield and also allows metals such as gold, silver and titanium to be extracted from the very clean sand.
Analyses of the pilot plant tailings (after bitumen extraction) showed that these minerals are readily recoverable.
A Solv-Ex pilot plant, located in Albuquerque, New Mexico, can process up to 72 tons of oil sands per day. It can also produce
up to 25 barrels of bitumen per day, depending on the grade of oil sands processed. The quantity of bitumen recoverable from
tar sands depends on its bitumen content, which typically ranges from 4 to 12 percent.
In an 8-month test program, Solv-Ex processed approximately 1,000 tons of Athabasca tar sands material in process runs of low
(6 percent of bitumen), average (8 to 10 percent), and high (12 to 14 percent) grade oil sands through the pilot plant. The test
material was procured from a pit centrally located in the oil sands deposit on which the Bitumount Lease is located. Average
percentage of bitumen recovered for the low, average and high grade sands were 75, 90 and 95 percent, respectively.
In February, 1989, a viable processing flowsheet was finalized which not only recovers the originally targeted gold, silver and
titanium values but also the alumina values contained in the resource. Synthetic crude oil would represent about 25 percent of
the potential mineral values recoverable from the Bitumount Lease.
The results of this work indicate that the first module could be a single-train plant, much smaller than the 10,000 barrels per
calendar day plant originally envisaged. The optimum size will be determined in the preconstruction feasibility study and this
module is estimated to cost not more than C$200 million.
The Bitumount lease covers 5,874 acres north of Fort McMurray, Alberta. Bitumen reserves on the lease are estimated at
1.4 billion barrels.
Solv-Ex is looking for potential financial partners to expand the project. The company plans to construct a modular Lease
Evaluation Unit in Alberta at an estimated cost of $12 million.
3-33
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
- BURNT LAKE PROJECT Suncor Inc., Amoco Canada Petroleum Company Ltd. (T-30)
The Burnt Lake in situ heavy oil project is located on the Burnt Lake property in the southern portion of the Primrose Range
in northeast Alberta. Initial production levels will average 12,500 barrels per day.
According to the companies, the Burnt Lake project is a milestone because it will be the first commercial development of these
heavy oil resources on the Primrose Range. This will require close cooperation with Canada's military.
The multi-phase Burnt Lake project, which was proposed to use cyclic steaming, was put on hold in 1986 due to low oil prices,
then revived in 1987. The project was again halted in early 1989. By then, 44 wells in two clusters and 7 delineation wells had
been drilled and cased.
A pilot was initiated at these wells in 1990 to test the cold flow production technique whereby the bitumen is produced together
with some sand using a progressive pump. cavity Initial results were encouraging. Since then, twelve wells have been put on
production. Production rates of 30 cubic meters per day have been achieved in some wells and the appears productivity to be
limited by the capacity of the pumps. However, some wells produced at rates of 5 to 8 cubic meters per day. The productivity
appears to be controlled by the geological structure and the sand quality of the reservoir. Operation problems necessitated
revisions of well operation procedure and well completion program.
Deterioration of the shale caprock near the wellbore of some wells caused the influx of water from the water sand above the
shale caprock to the oil sands zone. producing Attempts to shut off the water were not successful, and in time, this water com
municated with the adjacent producers. As a result, the project was suspended in November 1993.
As of December 1994, an alternative process for the commercial development of the Burnt Lake property is under evaluation.
The steam-assisted gravity drainage process (SAGD) using horizontal wells appears to have great potential.
Burnt Lake is estimated to contain over 300 million barrels of recoverable heavy oil.
- COLD LAKE PROJECT Imperial
Oil Resources Limited (T-50)
In September 1983 the Alberta Energy Resources Conservation Board (AERCB) granted Esso Resources Canada Ltd. (now
Imperial Oil Resources approval Limited) 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.
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.
Shipments of diluted bitumen from Phases 1 and 2 started in July 1985, augmented by Phases 3 and 4 in October, 1985 and
Phases 5 and 6 in May, 1986. During 1987, commercial bitumen production at Cold Lake averaged 60,000 barrels per day.
Production in early 1988 reached 85,000 barrels per day. A debottlenecking of the first six phases added 19,000 barrels per day
in 1988, at a cost of $45 million. Production in 1990 from Phases 1-6 was 78,000 barrels per day, production from the pilots was
8,000 barrels per day.
The AERCB approved Imperial's application to add Phases 7 through 10, which could eventually add another 44,000 barrels
per day. Phases 7 and 8, which include about 240 wells, a steam-generating and distribution system, a bitumen collection
pipeline and a central processing facility, were put into operation in 1993.
In late 1994. Imperial announced it will spend $240 million over the next two years to advance work associated with the start-up
of Phases 9 and 10. as well as other development work to enhance bitumen recovery and sustain productivity in Phases 1
through 8. This work will involve the drilling of about 400 new wells, as well as the start-up of plant facilities for Phases 9 and
10. These facilities were completed in tandem with the Phases 7 and 8 plant-
Cold Lake currently produces between 90.000 and 100.000 barrels of bitumen per day. Development work scheduled for 1995
and 1996 is expected to increase production to about 127.000 barrels per day bv 1997.
Project Cost: Approximately $1.1 billion for the first 10 phases.
- CONOCO-MARAVEN TARSAND PROJECT Conoco
and Maraven. SA CT-S2)
The Venezuelan government approved the joint venture between Conoco. Inc. and Maraven SA for a 35-year venture to
develop a 55.000-acre tract in the Orinoco oilsands belt in Venezuela. Agreements are expected to be completed in early 1995:
drilling is planned to be started in 1996 with initial production in 1997.
3-34
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
The Conoco-Maraven Project will be conducted in two phases. Phase 1. expected to last three years, should produce about
6.500 barrels/day of heavy oil. The final phase, lasting during the remainder of the 35 year agreement, is designed to produce
about 120.000 barrels/day.
Maraven had drilled about 200 wells to define the reserves and has conducted a pilot production operation. About
200 additional wells will be drilled during Phase 1 and about LOOP more wells to attain the 120.000 barrel /day rate planned for
Phase 2. Horizontal wells are being considered: steam injection and periodic well workovers are expected. Fuel for steam gen
eration will be derived initially from a nearby Maraven gas field and, during Phase 2. from gas production associated with the
project heavy oil production-
Construction of a $1 billion upgrader. designed to convert the 9.5API heavy oil into, is scheduled to be constructed on the
Venezuelan coast in 1997. During the targeted Phase 2 operations, the upgrader will produce about 102.000 barrels/day of
syncrude and 3.300 tons/day of coke-
Most of the syncrude will be refined at the Conoco Lake Charles refinery, located in Louisiana on the Gulf coast. Since this
refinery is designed to process the 20-23 API syncrude so that the costs in upgrading the Orinoco heavy oil into 33 API
syncrude are obviated. The coke produced by the upgrader will be sold to Louisiana Carbon, a subsidiary of Conoco, as fuel
for electrical power generation.
Conoco expected that the costs of upgrading and refining the Orinoco heavy oil will be about the same as developing and refin
ing conventional crude into similar refined products.
Project Cost: $1.7 billion
- CROWN OIL SANDS PROJECT Crown
Energy Corporation fT-55)
Crown Energy Corporation announced plans to construct a 6.400 tons/day plant to produce 3.700 barrels/day of oil from oil
sands situated on Asphalt ridge near Vernal. Utah. Production, based on Crown's proprietary extraction technology, is es
timated to be $9 per barrel.
Project Cost: $24 million
- DAPHNE PROJECT Petro-Canada
(T-60)
Petro-Canada is studying the possibility of a tar sands mining/surface extraction project to be located on the Daphne leases 65
kilometers north of Fort McMurray, Alberta. To date over 350 core holes have been drilled at the site to better define the
resource. The project may involve farmout and/or sales of the property.
Currently, the project has been suspended pending further notice.
The Daphne mineable oil sands leases were sold to Syncrude Canada Ltd. effective September 15. 1994. This permanently
closes the Daphne Project as Petro-Canada envisioned it.
- DIATOMACEOUS EARTH PROJECT Texaco
Inc. (T-70)
Texaco placed its Diatomite Project, located at McKittrick in California's Kern County, in a standby condition in 1985, to be
reactivated when conditions in the industry dictate. In 1991 the company is initiating steps to re-evaluate the technology
needed to recover the oil and to evaluate the environmental compliance requirements for a commercial plant. Consideration
will be given to restarting the Lurgi pilot unit.
The Company
estimates that the Project could yield in excess of 300 million barrels of 21 to 23 degrees API 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 fill
ing techniques.
Project Cost: Undetermined
3-35
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
- ELK POINT PROJECT Amoco
Canada Petroleum Company, Limited. (T-90)
The Elk Point Project area is located approximately 165 kilometers east of Edmonton, Alberta. Amoco Canada holds a
100 percent working interest in 6,600 hectares of oil sands leases in the area. The Phase 1 Thermal Project is located in the
NW 1/4 of Section 28, Township 55, Range 6 West of the 4th Meridian. The primary oil sands targets in the area are the
Lower Cummings and Clearwater sands of the Mannville Group. Additional oil sands potential is indicated in other Mannville
zones including the Colony and the Sparky.
Oil production from current wells at Amoco's Elk Point field totals 970 cubic meters per day.
Amoco Canada has several development phases of the Elk Point Project. Phase 1 of the project, which is now complete, in
voked the drilling, construction, and operation of a 13-well Thermal Project (one, totally enclosed 5-spot pattern), a continua
tion 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 during Phase 1.
Construction of the Phase 1 Thermal Project and cleaning facility was initiated in May 1985. The cleaning facility
has been
operational since October 1985. Cyclic Steam injection into the 13-well project was initiated in July, 1987 with continuous
steam injection commencing on April 20, 1989. Continuous steam injection was discontinued in May 1990 and the pilot was
shut in.
In February, 1987, Amoco Canada received approval from the Energy Conservation Board to expand the development of sec
tions 28 and 29. To begin this expansion, Amoco drilled 34 wells in the north half of section 29 in 1987-88, using conventional
and slant methods. drilling Pad facilities construction occurred in 1988. A further 24 delineation wells were drilled in 1989 and
22 wells were drilled in 1990.
Phase 2 will continue to focus on primary production development and will allow for further infill drilling in the entire project
area in all zones within the Mannville group. Some limited cyclic steaming may be planned in future years. Phase 2 was ap
proved in 1993, however, no new developmnet is expected. Existing wells will be produced on a primary basis.
Project Cost: Phase 1 $50 Million (Canadian)
- ELK POINT OIL SANDS PROJECT PanCanadian
Petroleum Limited (T-100)
PanCanadian received approval from the Alberta Energy Resources Conservation Board for Phase I of a proposed three phase
commercial bitumen recover) project in August 1986.
The Phase I project was to involve development of primary and thermal recovery operations in the Lindbergh and Frog Lake
sectors near Elk Point in east-central Alberta. Phase I operations were to include development of 16 sections of land. By the
end of 1990, 148 wells were drilled.
PanCanadian expected Phase I recovery to average 3,000 barrels per day of bitumen, with peak production at 4,000 barrels per
day. Tentative plans called for Phase II operations to start up in the mid 1990's with production to increase to 6,000 barrels
per day. Phase III was to go into operation in the late 1990's, and production was to increase to 12.000 barrels per day.
Experimental steam stimulation (50 cycles) and steamflood (one pattern) lasted until mid-1990. Results were not encouraging
and therefore all operations steaming have been canceled. Another steaming process such as SAGD (Steam Assisted Gravity
Drainage) may be attempted in the future but no plans are currently in place.
Although steaming has proved unsuccessful, primary production rates and cumulative recoveries are much better than
originally anticipated. Recoveries as high as 12 to 20 percent on 20-acre and 10-acre spacing are expected utilizing slant wells
from pads. Consequently, the focus is now on primary production.
Current production is estimated to be 16300 barrels per day from 290 wells.
Project Cost: Phase I = C$62 Million to date
3-36
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
- LINDBERGH COMMERCIAL PROJECT Amoco
Canada Petroleum Company Ltd. (T-120)
Amoco (formerly Dome Petroleum) began a commercial project in the Lindbergh area that would cover initially five sections
and was planned to be developed at a rate of one section per year for five years. It was to employ
"huff-and-puff steaming of
wells drilled on 10 acre spacing, and would require capital investment of approximately $158 million (Canadian). The project
was expected to encompass a period of 12 years. Due to the dramatic decline of oil prices, drilling on the first phase of the
commercial project was halted, and has forced a delay in the proposed commercial thermal development.
The company has no immediate plans for steaming the wells to increase production because this process is uneconomic at cur
rent prices.
The current focus has been development and optimizing of primary production. In 1990, 26 wells on 40-acre spacing were
drilled for primary production. Again, due to low heavy oil prices, some limited drilling will take place in 1991. Primary
production from the project is now averaging 6,200 barrels per day.
Project Cost: $158 Million
LINDBERGH COMMERCIAL THERMAL RECOVERY PROJECT -
Murphy Oil Company Ltd. (T-130)
Murphy Oil Company Ltd., has completed construction and startup of a 2,500 barrel per day commercial thermal recovery
project in the Lindbergh area of Alberta. Project expansion to 10,000 barrels per day is planned 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 con
struction of an oil plant, water plant, and water source intake and line from the North Saskatchewan River.
Murphy has beer) 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.
The project uses a huff-and-puff process with about two cycles per year on each well. Production is from the Lower Grand
Rapids zone at a depth of 1,650 feet. Oil gravity is 11 degrees API, and oil viscosity at the reservoir temperature is
85,000 centipoise. The wells are directionally drilled outward from common pads, reducing the number of surface leases and
roads required for the project.
The project was suspended for a year from September 1988 to August 1989 when three wells were steamed. The project
returned to production on a limited basis in the last quarter of 1989. Initial results were encouraging, says Murphy, but an ex
pansion to full capacity depends on heavy oil prices, market assessment, and operating costs.
The project was shut-in in late 1991. reviews Engineering of current and alternate technologies are under way.
In late 1993 a horizontal well was drilled, offsetting eight of the directionally drilled cyclic wells. Five of these were converted
to injection wells and a steam drive process using the horizontal well as a producer was tested until January 1994, when the
project was again shut down due to low oil prices. Restart of the project will be dependent on oil price projections.
Project Cost: $30 million (Canadian) initial capital cost
- MOBIL-ORINOCO HEAVY OIL PROJECT Mobil
and Lagoven (T-1351
Mobil and Lagoven have signed an agreement to conduct feasibility studies to develop and upgrade 100.000 barrels/day of
heavy oil from the Orinoco belt in Venezuela. If the study, focusing on technology, markets and economics, shows the
proposed heavy oil project to be feasible. Mobil and Lagoven plan to submit an association agreement to the Venezuelan
government in late 1995.
Project Cost: Unknown
-
NEWGRADE HEAVY OIL UPGRADER (THE CO-OP UPGRADER) NewGrade
Co-Operative Refineries Ltd. and the Saskatchewan Government (T-140)
Energy, Inc., a partnership of Consumers
Construction and commissioning of the upgrader was completed in October, 1988. The official opening was held
November 9, 1988.
3-37
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
The refinery/crude unit has been at running well over 50,000 barrels per day of heavy/medium crude. From that,
32,000 barrels per day of heavy resid bottoms are sent to the Atmospheric Residual Desulfurization unit which per
(ARDS)
forms primary upgrading. From there 15,000 barrels per day is run being through the Distillate Hydrotreater (DHU) which
improves the quality of the distillate fuel oil streams by adding hydrogen.
The 50,000 barrels per day heavy oil upgrading project was originally announced in August 1983.
Consumers'
Co-Operative Refineries contributed their existing refinery to the project, while the provincial government
provided 20 percent equity funds. The federal government and the Saskatchewan government provided loan guarantees for
80 percent of the costs as debt.
NewGrade selected process technology licensed by Union Oil of California for the ARDS and DHU. The integrated facility is
capable of producing a full slate of refined products or alternately 50,000 barrels per day of upgraded crude oil or any com
bination of these two scenarios.
Operations include the processing of over 50,000 barrels per day of heavy and medium Saskatchewan crude with approximately
80 percent (40.000 barrels per day) being converted to a full range of refined petroleum products and the remaining 20 percent
(10.000 barrels per day) being sold as synthetic crude.
Operations in 1994 have experienced a heavy crude oil charge ratio of up to 55.000 barrels per day, and the Atmospheric
Residual Desulfurization (ARDS) unit has had a charge rate of 32,000 barrels per day. The Distillate
Hydrotreater/Hydrocracker routinely operates at up to 15,000 barrels per day.
The plant design capacities are: crude unit, 50,000 barrels per day, ARDS, 30,000 barrels per day, DH, 12,000 barrels per day.
Financial restructuring took place in October 1994. Saskatchewan and Consumers'
Cooperative each contributed $75 million
dollars and will share cash flow deficiencies equally up to $4 million each per year. Canada contributed $125 million and Sas
katchewan assumed all remaining guarantor committments.
Project Cost: $700 million
- ORIMULSION PROJECT Petroleos
de Venezuela SA (PDVSA) and Veba Oel AG (T-145)
Venezuela's state-owned oil company, Petroleos de Venezuela SA (PDVSA), and Germany's Veba Oel AG are developing the
heavy crude and bitumen reserves in the Orinoco Belt in eastern Venezuela. The two companies conducted a feasibility study
to construct a facility capable of upgrading 80,000 barrels per day of extra heavy crude. Development plans for the next 5 years
call for production of 1 million barrels per day.
About 60 percent of this production would be Orimulsion, a bitumen based boiler fuel. The remainder would be converted to
light synthetic crude oil. PDVSA can produce and distribute 50,000 barrels of Orimulsion per day, with capacity in hand to
double that.
Orimulsion has been produced from the Morichal Field in Eastern Venezuela since May 1988.
PDVSA joined forces with Mobil Corporation in 1992 to explore other options for marketing heavy crude in addition to
Orimulsion.
In October 1991, the Kashima-Kita Electric Power Corporation of Japan began firing their generators with 700 tons per day of
Orimulsion. Another Japanese utility, Mitsubishi Kasei Corporation, began working with Orimulsion in February 1992. Other
markets for Orimulsion now include Power Gen, Great Britian and New Brunswick Power Company in Canada.
PDVSA's research institute, Intevep, is developing EVC Orimulsion, an 80 percent bitumen, controlled viscosity, emulsion fuel
with improved stability. EVC Orimulsion has been tested at pilot plants in Morichal, Venezuela, according to Intevep, and the
fuel is expected to reduce land and marine transportation costs, while delivering higher energy content per pound. The new
and improved fuel is scheduled to enter the market sometime in 1994.
Project Cost: $2.5 billion
PEACE RIVER COMPLEX -
Shell
Canada Limited (T-160)
Shell Canada Limited expanded the original Peace River In Situ Pilot Project to an average production rate of 10,000 barrels
per day. The Peace River Expansion Project, or PREP I, is located adjacent to the existing pilot project, approximately
55 kilometers northeast of the town of Peace River, on leases held by Shell Canada Limited.
3-38
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
The expansion, at a cost of $200 million, required the drilling of an additional 213 wells for steam injection and bitumen
production, plus an expanded distribution and gathering system. Wells for the expansion were drilled directionally from eight
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 is diluted and marketed as a blended heavy oil. The diluted bitumen is transported by
pipeline to the northern tier refineries in the United States and the Canadian west coast for asphalt production.
An application to the Energy Resources Conservation Board received approval in early November 1984. Drilling began in
February 1985. Construction began June 1985. The expansion was on stream October 1986.
In 1989 production was increased to the design capacity of 1,600 cubic meters of oil per day. The Peace River complex com
pleted its first full year of operating at capacity in 1990. Its 10 millionth barrel of bitumen was produced in March. Through a
combination of increased bitumen production and reduced energy requirements, the unit bitumen production cost has been
reduced to 30 percent of that averaged during the first full year of operation. The operation was producing about
10.000 barrels/day of bitumen. However, in 1994 production declined to 7.000 barrels/day. Changes to the recovery process to
restore production were implemented late 1994 and results to date have been encouraging. Ultimate recovery is projected at
55 percent of the bitumen in place.
On January 25, 1988 the ERCB approved Shell Canada's application to expand the Peace River project from 10,000 barrels per
day to approximately 50,000 barrels per day. PREP II, as it will be called, entails the construction of a stand-alone processing
plant, located about 4 km south of PREP I. PREP II would be developed in four annual construction stages, each capable of
producing 1,600 cubic meters per day. However, due to low world oil prices and continual with uncertainty along the lack of
improved fiscal terms the expansion project has been postponed indefinitely. Some preparatory site work was completed in
1988 consisting of the main access road and drilling pads for PREP II. The ERCB approval for PREP II was allowed to lapse,
however, in December 1990. Continued world oil price contributed uncertainty largely to the decision not to seek an expan
sion.
Research into the application of a steam drainage process has led to the design of a two-well horizontal well demonstration
project. The project is testing the technical and economic feasibility of bitumen recovery utilizing surface-accessed horizontal
wells, employing an enhanced steam assisted gravity drainage process. The estimated lifetime of the project is 12 years during
which 80% of the bitumen initially in place is thought to be recoverable. The project is tied into existing Peace River complex
facilities and began operating in November 1993. After steam injection for two months, production was expected to be about
1,000 barrels per day.
Project Cost: $200 million for PREP I
$570 million for PREP II
- PRIMROSE LAKE COMMERCIAL PROJECT Amoco Canada Petroleum Company and Alberta Energy Company (T-170)
Amoco (formerly Dome) proposed a 25,000 barrels per day commercial project in the Primrose area of northeastern Alberta.
extensive explora
Amoco is earning a working interest in certain oil sands leases from Alberta Energy Company. Following
tion, 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 degrees API oil in 1984.
The agreement with Alberta Energy allows Amoco to earn an interest in an additional 194,280 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 section will contain four 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. A subsequent amendment to the original scheme was approved on August
18, 1988. The 12,800 acre project will be developed in three phases. Four 6,500 barrel per day modules will be used to meet
the 25,000 barrel per day target.
In 1989, Amoco undertook some additional work at the site by drilling a horizontal well. In 1990 Amoco announced it would
drill two more wells to assist in engineering design work. Six hundred thousand dollars was planned to be spent on this effort
in 1990.
A new steam injection heavy oil pilot was placed in production in early 1991. By the end of 1991, AEC expected to be testing
more than 80 wells various using techniques, including a cold technique which employs specialized pumps.
In 1991, ERCB gave approval for seven horizontal wells to maximize bitumen recovery under a steam stimulation/gravity
drainage process.
3-39
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
AEC expects its share of Primrose heavy oil production to grow to about 10,000 barrels per day
double by the late 1990s.
over the next 5 years and
Using a newly developed "cold
140 barrels per day per well. This technique significantly reduces capital and costs operating as compared to steam injection
production"
technique, four wells have been producing for more than a year at rates averaging
techniques. Further testing of this technology continues in 1992.
AEC estimates that cold production technology could yield 6,000 barrels per day by 1993,
12,500 barrels per day in 1995.
Project Cost: $1.2 billion (Canadian) capital cost
$140 million (Canadian) annual operating cost
- SCOTFORD SYNTHETIC CRUDE REFINERY Shell Canada Limited (T-180)
with a planned expansion to
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 was 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, Syncrude and Suncor. The refinery's petroleum products are gasoline, diesel, jet
fuel and stove oil. Byproducts include butane, propane, and sulfur. Sufficient benzene is produced to feed a 300,000
tonne/year styrene plant. The refinery and petrochemical plant officially opened September 1984.
Project Cost: $1.4 billion (Canadian) total final cost for all (refinery, benzene, styrene) plants
- SOLV-EX/UNITED TRI-STAR OILSAND AGREEMENT Solv-Ex
Corporation and United Tri-Star Resources. Ltd. (T-185)
Solv-Ex Corporation and United Tri-Star Resource. Ltd. have agreed to form a joint venture in oil sands development. Part of
this agreement involves the development of a 5.000 barrel /day test plant at the Solv-Ex oilsands lease in Alberta. Canada.
About one-half year is estimated for the preconstruction work of the test plant. The joint venture also plans to market the
Solv-Ex oilsand technology in Australia.
Project Cost: $3 million (Canadian) (United Tri-Star contribution of the preconstruction costs')
- SUNCOR, INC., OIL SANDS GROUP Sun
Company, Inc. 55 percent, 25 percent by public shareholders (T-190)
Suncor Inc. was formed in August 1979, by the amalgamation of Great Canadian Oil Sands and Sun Oil Co, Ltd.
Suncor Inc. operates a commercial oil sands plant located in the Athabasca oilsands 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, overbur
den is removed to expose the oil-bearing sand. Second, the sand is mined and transported by conveyors to the extraction plant.
Third, hot water and steam are used to extract the bitumen from the sand. Fourth, the bitumen goes to upgrading where ther
mal cracking produces coke, and cooled vapors form distillates. The distillates are desulfurized and blended to form high-
quality synthetic crude oil which is shipped to Edmonton for distribution.
The plant achieved record production levels in 1994. averaging 70.700 barrels per day for the year. Cash operating costs in 1994
were C$14.00 per barrel. In 1994. cash flow from operations increased 75%.
Reliability improvements and conversion to a more flexible mining technology contributed to higher levels of productivity.
Suncor is also enhancing shareholder value by diversifying its product and customer base.
Suncor plans to spend $250 million over the next three years to increase production to more than 80.000 barrels per day in
1998. At the same time, this investment is expected to lower unit costs and create the infrastructure for subsequent growth.
Production increases will be staged to ensure the operation remains safe, reliable and environmentally sound. In 1994. they in
vested $40 million in improvements in the upgrader to reduce sulfur dioxide emissions. An additional $150 million will be
spent in the utility plant over the next two years to achieve a cumulative 75% plant-wide reduction in SO emissions-
Over the next five years. Suncor plans to spend approximately $200 million to develop a new mine site on a recently acquired
lease and conduct an environmental impact assessment. Work will proceed when final approval from the board of directors
and provincial regulatory agencies is received.
Project Cost: Not disclosed
40
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
- SUNNYSIDE PROJECT Amoco
Production Company (T-200)
Amoco Corporation is studying the feasibility of a commercial project on 1,120 acres of fee property and 9,600 acres of com
bined 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 geologic field study was completed in September 1986; additional field work was completed in 1987. In response to Mono
Power Company's solicitation to sell their (federal) lease interests in Sunnyside tar sands, Amoco Production acquired Mono
Power's Combined Hydrocarbon Leases effective August 14, 1986. Amoco continued due diligence efforts in the field in 1988.
This work includes a tar sand coring program to better define the resource in the Combined Hydrocarbon Lease.
Project Cost: Not disclosed
- SYNCO SUNNYSIDE PROJECT Synco Energy Corporation (T-220)
Synco Energy Corporation of Orem, Utah is seeking to raise capita] to construct a plant at Sunnyside in Utah's Carbon County
to produce oil and electricity from coal and tar sands.
The Synco process to extract oil from tar sands uses coal gasification to make a synthetic gas. The gas is cooled to 2,000 de
grees F by making steam and then mixed with the tar sands in a variable speed rotary kiln. The hot synthetic gas vaporizes the
oil out of the tar sands and this is then fractionated into a mixture of kerosene (jet fuel), diesel fuel, gasoline, other gases, and
heavy ends.
The syngas from the gasifier is separated from the oil product, the sulfur and CO removed and the gas is burned in a gas tur
bine to produce electricity. The hot exhaust gases are then used to make steam and cogenerated electricity. Testing indicates
that the hydrogen-rich syngas from the gasified coal lends to good cracking and hydrogen upgrading in the kiln.
The plant would be built at Sunnyside, Utah, near the City of Price.
There is a reserve of four billion barrels of oil in the tar sands and 230 million tons of coal at the Sunnyside site. Both raw
materials could be conveyed to the plant by conveyor belt.
The demonstration size plant would produce 8,000 barrels of refined oil, 330 megawatts of electricity, and various other
products including marketable amounts of sulfur.
An application has been filed by Synco with the Utah Division of State Lands for an industrial special use lease containing the
entire Section 36 of State land bordering the town of Sunnyside, Utah. Synco holds process patents in the U.S., Canada and
Venezuela and is looking for a company to joint venture with on this project.
Project is on hold.
- SYNCRUDE CANADA, LTD. Imperial
Oil Resources (25.0%); Petro-Canada (12.0%); Province of Alberta (11.74%); Alberta
Energy Company Ltd. (10.0%); PanCanadian Gas Products Limited (10.0%); Gulf Canada Resources Limited (9.03%); Canadian
Occidental Petroleum Ltd. (7.23%); AEC Oil Sands Ltd. Partnership (5.0%); Murphy Oil Company (5.0%); Mocal Energy Limited
(5.0%)
(T-230)
Located near Fort McMurray, the Syncrude surface mining, extraction and upgrading plant produces 190.000 barrels per calen
dar day. The original plant with a capacity of 108,000 barrels was based upon: oil sand mining and ore delivery with four
dragline-bucketwheel reclaimer-conveyor systems; oil extraction with hot water flotation of the ore followed by dilution
centrifuging; and upgrading by fluid coking followed by hydrotreating. During 1988, a 6-year $1.5 billion investment program
in plant capacity was completed to bring the production capability to over 155,000 barrels per calendar day. Included in this in
vestment program were a 40,000 barrel per day L-C Fining hydrocracker, additional hydrotreating and sulfur recovery capacity,
and auxiliary mine feed systems as well as debottlenecking of the original processes.
In 1992 production operating costs were about C$15.39 per barrel. Syncrude Canada Ltd. produced 12 percent of Canada's
crude oil requirements in 1992. In 1993 operating costs were $15.47 per barrel.
In 1992, Syncrude announced that it is seeking approval from the Alberta Energy Resources Board (ERCB) to increase output
by 28 percent. This was approved in 1994.
3-41
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
In September 1994. the Syncrude owners acquired two additional surface mineable leases. These leases are estimated to con
tain 2.2 billion barrels of high-quality, low-cost recoverable bitumen resources. When added to the existing 2.1 billion barrels
of remaining resources, the plant has feedstock for 54 years of production at the 1993 production rate.
A major project in 1995-96 will be debottlenecking the upgrader and hydrotreating facility to reach production targets.
help
Capital will be allocated to relocate tailings and develop a salt-water removal technology to mitigate corrosion of plant equip
ment and facilities. In addition, the eastern section of the mine will be expanded to recover an additional 80 million barrels of
bitumen over the next 2 years.
Syncrude is also studying alternative methods for site reclamation. During 1993, Syncrude reclaimed 178 acres of land.
In 1994. Syncrude shipped a record 69.8 million barrels of its product, now called Syncrude Sweet Blend. This was the fifth
year in a row that the company has set a production record.
Project Cost: Original base plant cost C$2.3 billion
Additional capital C$2.0 billion
- TOTAL-ORINOCO HEAVY OIL PROJECT Total
and Maraven SA (T-235)
Approval was made bv the Venezuelan government for a joint venture to produce heavy oil from the Zuata region of the
Orinoco belt. Partners in the joint venture are Total (407r). Maraven (35%). and Itochu Corporation /Marubeni Corporation
(25%).
The project plans to produce 114.000 barrels/day of 9API high-sulfur crude and, using delayed coking and hvdrodesulfuriza-
tion. process it into 100.000 barrels/day of syncrude having 31 API and 0.06 weight percent sulfur and 3.000 tons/day of
petroleum coke. The coking plant will be situated near Jose and the Caribbean, about 210 kilometers from the Zuata region.
Project Cost: $3.1 billion
- THREE STAR OIL MINING PROJECT Three Star Drilling and Producing Corp. (T-240)
Three Star Drilling and Producing Corporation has sunk a 426 foot deep vertical shaft into the Upper Siggins sandstone of the
Siggins oil field in Illinois and drilled over 34,000 feet of horizontal boreholes up to 2,000 feet long through the reservoir. The
original drilling pattern was planned to allow the borehole to wander up and down through the producing interval in a "snake"
pattern. However, only straight upward slanting holes are being drilled. Three Star estimates the Upper Siggins still contains
some 35 million barrels of oil across the field.
The initial plans call for drilling one to four levels of horizontal boreholes. The Upper Siggins presently has 34 horizontal wells
which compose the 34,000 feet of drilling.
Sixty percent of the horizontal drilling was completed by late 1990. Production was put on hold pending an administrative
to determine whether the mine is to be classified as gaseous or non-gaseous. The project was later classified as a
hearing
gaseous mine due to the fact that the shaft penetrated the oil reservoir. As a result of the ruling, Three Star then drilled a ver-
ticle well to the underground sump room and began producing the mine conventionally with all the horizontals open. In 1992,
Three Star will begin reworking the surface wells for injection purposes in order to pressure up the Upper Siggins.
Project Cost: Three Star budgeted $3.5 million for the first shaft.
WOLF LAKE PROJECT - Amoco Canada Petroleum (T-260)
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.
An estimated 720 wells will be 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 degrees 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.
3-42
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
By mid-1988 production had dropped 22 percent below 1987 levels. Following a change of strategy
in operation of the reser
voir, however, production had increased to 1,030 cubic meters per day in 1989 and 1,147 cubic meters per day in 1990. Continu
ing the trend, 1991 will see an average production rate of 1,167 cubic meters per day.
In 1987, a program designed to expand production by 2,400 cubic meters per day to 3,700 cubic meters per day, total bitumen
production was initiated. Wolf Lake 2 was originally expected to be completed in mid-1989.
In early 1989, BP Canada and Petro-Canada delayed by 1 year the decision to start up the second phase. While the Wolf Lake
2 plant was commissioned in 1990, full capacity utilization of the combined project is not likely before the late 1990s when it is
expected that higher bitumen prices will support the expanded operation and further development.
The new water recycle facilities and the Wolf Lake 2 generators are operational. Production levels will be maintained at 600 to
700 cubic meters per day until bitumen netbacks have improved. The Wolf Lake 2 oil processing plant and Wolf Lake 1 steam
generating facilities have been suspended.
In September 1989, Wolf Lake production costs were reported to be almost C$22 per barrel, while bitumen prices fell to a low
of C$8.19 per barrel in 1988. BP initiated a program to reduce Wolf Lake costs, which included laying off 120 workers, making
improvements in process efficiency, and operating the plant at about 50 percent of capacity.
operating costs to C$10 to 12 per barrel.
These economic measures cut
In 1991, Wolf Lake production costs were less than $9 per barrel, and bitumen production averaged 4,225 barrels a day.
In early 1992, BP Canada and Petro-Canada sold their entire interests in the project to Amoco Canada Petroleum. No price
was disclosed but both companies have written off their total $370 million investment in the project.
Project 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
YAREGA MINE-ASSISTED PROJECT- Union of Soviet Socialist Republics (T-265)
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 . Tem
perature ranges from 279 to 281 degrees K; porosity is 26 degrees; 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. In 15 years, 10 million tons of steam have
been injected into the reservoir.
Three mines have been operated since 1975. An area of the deposit covering 225 hectares is under thermal stimulation. It in
cludes 15 underground slant blocks, where 4,192 production wells and 11,795 steam-injection wells are operated. In three un
derground slant production blocks, oil recovery of 60 percent and higher has been reached. Construction of 4 new shafts is ex
pected to bring production to over 30,000 barrels per day. Forty-one million barrels of oil were produced during the period
1975-1987. A local refinery produces lubricating oils from this crude.
Project Cost: Not Disclosed
3-43
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
ATHABASCA IN SITU PILOT PROJECT (Kearl Lake)
Operations Ltd., Imperial Oil Ltd. (T-270)
R&D PROJECTS
- Alberta Oil Sands Technology and Research Authority, Husky Oil
The pilot project began operation in December, 1981. The pilot was developed with the objectives following in mind: Evaluate
the use of horizontal hydraulic fractures to develop injector to producer communication; optimize steam injection rates; maxi
mize bitumen recovery,
assess the areal and vertical distribution of heat in the reservoir, evaluate the performance of wellbore
and surface equipment; and determine key performance parameters.
The operator of the Athabasca In Situ Pilot Project is Husky Oil Operations Ltd. In 1990 three patterns were being operated:
one 9-spot and two 5-spots. The central well of each pattern was an injector. Eight observations wells were located in and
around the three patterns. The 9-spot pattern was started up in 1985. The two 5-spot patterns were started up in 1987.
Results from all three patterns were technically encouraging, according to Husky.
In 1990 the project passed the one million barrel production mark and at the end of January 1991 the project entered its final,
winddown phase. The winddown phase consists of reducing the central steam injection to zero and continuing to produce until
the end of April 1991. The project was shut down at the end of April 1991, after a majority of the technical objectives had been
met.
In July 1991, all production, injection and observation wells were abandoned and the central facilities mothballed.
In the fall of 1994 the central facilities were dismantled and the equipment salvaged. Final site restoration should commence in
1995.
Project Cost: Capital $54 million, operating $73 million
BATTRUM IN SITU WET COMBUSTION - Mobil
280)
Oil Canada, Unocal Canada Limited, Saskoil, Hudson's Bay Oil and Gas (T-
Mobil Oil Canada initiated dry combustion in the Battrum field, near Swift Current, Saskatchewan, in 1964 and converted to
wet combustion in 1978. The combustion scheme, which Mobil operates in three Battrum units, was expanded during 1987-88.
The expansion included drilling 46 wells, adding 12 new burns, a workover program and upgrading surface production and air
injection facilities. There are presently 17 burns in operation.
All burns were converted to wet combustion in 1993. Current air injection rate is 25 million cubic feet per day. In 1988, studies
were initiated to determine the feasibility of oxygen enrichment for the EOR scheme. Due to increased capital requirements
for the oxygen case in 1991, application of horizontal well technology was considered as an alternative. In late 1992, Mobil and
partners drilled the first horizontal well to take advantage of gravity drainage. Encouraged by the production performance of
the first well, a second horizontal well was drilled in 1993. Also a 3-D seismic survey was shot to better understand the reser
voir extent. As a result, three edge wells in Unit #1 will be drilled in 1995. Also two water injection wells will be drilled in
Unit #3 to restore pressure fence, with the waterflood Unit #4 operated by Sceptre Resources Limited. Due to insufficient air
injection, reservoir pressure is gradually declining. Consequently, beyond 1995. the plan is to increase reservoir pressure with
increased water injection and to begin injecting oxygen to maximize the effectiveness of the wet combustion scheme.
- BUENAVENTURA COLD PROCESS PILOT Buenaventura
Resource Corp. (T-287)
Buenaventura Resource Corporation owns the exclusive license to use a patented process to extract oil from tar sands in the
United States and Canada. The cold process was invented by Park Guymon of Weber State University.
The two step process uses no heat in extracting heavy oil from tar sands. Asphalt can be made from the oil, or it can be refined
for use as a motor oil. The company is currently assessing the market for these products.
The process will be developed in three phases. The first phase involves testing the technology in a small pilot plant installed
near Weber State University. The plant was built in Texas and was shipped to Utah in the fall of 1990 for installation. This
was begun successfully in 1992. The project's second phase will be a larger pilot plant and the third phase will be a
commercial-scale plant.
Buenaventura has been working on developing the new process in Uintah County, Utah since 1986. Funding for the project is
sought being from the State of Utah and the United States Department of Energy.
S44
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
- CELTIC HEAVY OIL PILOT PROJECT Mobil
Oil Canada (T-320)
Mobil's heavy oil project is located in T52 and R23, W3M in the Celtic Field, northeast of Lloydminster. The pilot consisted of
25 wells drilled on 5-acre spacing, with twenty producers and five injectors. There is one nine-
fully developed central inverted
spot surrounded by four partially developed nine-spots. The pilot was to field test a wet combustion scheme with
recovery
steam stimulation of the production wells.
Air injection, which was commenced in October 1980, was discontinued in January 1982 due to operational problems. An inter
mittent steam process was initiated in August 1982. The seventh steam injection cycle commenced in January, 1987. Opera
tions were suspended in 1988-89.
Production in the Celtic Multizone Test, an expansion of the Heavy Oil Pilot, consisting of 16 wells on 20 acre spacing, com
menced with primary production in September, 1988. First cycle steam injection commenced May, 1989. Steam operations
continued until April 1991, and there after, wells were put on production. primary This test operation is now part of the total
Celtic field operation.
Project Cost: $21 million (Canadian) (Capital)
- C-H SYNFUELS DREDGING PROJECT C-H Synfuels Ltd. (T-330)
C-H Synfuels Ltd. plans to construct an oil sands dredging project in Section 8, Township 89, Range 9,
meridian.
west of the 4th
The scheme would involve dredging of a cutoff meander in the Horse River some 900 meters from the Fort McMurray subdivi
sion of Abasand Heights. Extraction of the dredged bitumen would take place on a floating modular process barge employing
a modified version of the Clark Hot Water Process. The resulting bitumen would be stored in tanks, allowed to cool and
solidify, then transported, via truck and barge, to either Suncor or the City of Fort McMurray. Tailings treatment would
employ a novel method combining the sand and sludge, thus eliminating the need for a large conventional tailings pond.
C-H proposes to add lime and a non-toxic polyacrylamide polymer to the tailings stream. This would cause the fines to attach
to the sand eliminating the need for a sludge pond.
Project Cost: Not disclosed
- CIRCLE CLIFFS PROJECT Kirkwood
Oil and Gas (T-340)
Kirkwood Oil and Gas is 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.
Work on this project was suspended in 1990 until an Environmental Impact Statement can be completed.
Project Cost: Not disclosed
- COLD LAKE STEAM STIMULATION PROGRAM Mobil Oil Canada (T-350)
A stratigraphic test program conducted on Mobil's 75,000 hectares of heavy oil leases in the Cold Lake area resulted in ap
proximately 150 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 20 meters.
Single well steam stimulations began in 1982 to evaluate the production potential of these zones. Steam stimulation testing was
subsequently expanded from three single wells to a total of fourteen single wells in 1988. Various zones have been tested in the
Upper and Lower Grand Rapids formation. The test well locations are distributed throughout Mobil's leases in Townships 63
and 64 and Ranges 6 and 7 W4M. Based on encouraging results, the Iron River Pilot (see Iron River Pilot Project (T-440)].
was constructed with operations beginning in March, 1988. To date, steam stimulation tests have been conducted in a total of
14 vertical wells.
Single well tests were suspended at the end of 1991. No further steaming of the single wells is planned. A single zone, conduc
tion assisted steam stimulation in a horizontal well began in mid-1989. This test was successfully completed in 1991. As of
August 1993, the wells are suspended.
Project Cost: Not disclosed
3-45
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
- EYEHILL IN SITU COMBUSTION PROJECT Canadian
pany Ltd. (T-390)
Occidental Petroleum, Ltd., C.S. Resources Ltd. and Murphy Oil Com
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
14.3 degrees API, viscosity 2,750 Cp at 70 degrees F, porosity 34 percent, and permeability 6,000 md.
Cumulative production reached one million barrels in 1988. This represents about 6 percent of the oil originally in place in the
project area. Another four million barrels is expected to be recovered in the project's remaining 10 years of life after 1988.
Production in 1990 continued at 500 barrels per day. The air compressors supplying combustion air were shut-in in June 1990.
Three horizontal wells were drilled in 1992, with one inside the fireflood boundaries. Production from the project peaked at
1,300 barrels per day. One additional horizontal well was drilled in 1993 and two more in 1994 to maintain production levels.
Project Cost: $15.2 million
- FORT KENT THERMAL PROJECT Bow
River Pipelines Ltd. (T^00)
Canadian Worldwide Energy Ltd. and Suncor, Inc. began development of a heavy oil deposit on a 5.960 acre lease in the Fort
Kent area of Alberta in 1978. This oil has an average gravity of 12.5 degrees API, and a sulfur content of 3.5 percent. The
project consisted of 126 wells utilizing huff and puff, with steamdrive as an additional recovery mechanism. The first
steamdrive pattern was commenced in 1980. with additional patterns converted from 1984 through 1986. In 1988. the project
was suspended.
At the time of suspension, the project was averaging 1.600 barrels of oil per day from 59 wells.
In 1989. Bow River Pipelines acquired the interests of both Canadian Worldwide and Suncor and combined the project with an
adjacent thermal operation. Currently, there are 24 operating wells producing 375 barrels of oil per day. The project continues
to operate as a huff and puff and steamdrive process. Ultimate recoveries are expected to reach 18 percent by huff and puff
and 24 percent with steamdrive.
In 1993. Bow River drilled a horizontal well within an area that had been cyclically steamed in an effort to increase recoveries
beyond 35 percent.
Project Cost: Unknown
FROG LAKE PILOT PROJECT-Texaco Canada Petroleum (T-405)
The Frog Lake Lease is located about 50 miles northwest of Lloydminster, Alberta in the southeastern portion of the Cold
Lake Oil Sands deposit. The lease contains a number of heavy oil producing horizons, but primary production rates are
generally restricted to less than 5 cubic meters per day per well due in large part to the high viscosity of the oil.
During the 1960s steam stimulation treatments were carried out on several wells on the Frog
Lake lease but based on these
tests it was concluded that conventional thermal recovery methods using steam are hampered by the thermal inefficiency as
sociated with the thin sands.
In 1991 Texaco began preparing to apply electromagnetic heating to stimulate three Lower Waseca wells at Frog Lake. The
wells were placed on production in late November 1990 and electromagnetic heating was scheduled to commence by mid-1991.
Upon completion of the tests in 1993 it is expected there will be sufficient data available to develop reliable economics for a
commercial project. A reservoir simulator will be used to history-match test results and make predictions of production rates
and ultimate recovery for various well patterns and spacing.
3-46
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
- GLISP PROJECT Amoco
Canada Petroleum Company Ltd. (14.29 percent) and AOSTRA (85.71 percent) (T-420)
The Gregoire Lake In-Situ Steam Pilot (GLISP) was an experimental steam pilot located at Section Z-86-7W. Phase B opera
tions were terminated in July 1991 due to financial limitations. Petro-Canada had participated in Phase A of the project, but
declined to participate in Phase B which was initiated in 1990. The lease is shared jointly by Amoco and Petro-Canada.
Amoco is the operator.
The GLISP production pattern consisted of a four spot geometry with an enclosed area of 0.28 hectacres (0.68 acres). The
process tested the use of steam and steam additives in the recovery of high viscous bitumen (1x10 million eP at virgin reservoir
temperature). Special fracturing techniques were tested. Three temperature observation wells and seismic methods were used
to monitor the in-situ process.
The project began operation in September 1985. Steaming operations were initiated in October 1986 to heat the production
wellbores. A production cycle was initiated in January 1987 and steam foam flooding began in October 1988. Foam injection
was terminated in February 1991. Steam diversion using low temperature oxidation was tested between April and July 1991.
Operations at GLISP were suspended July 18, 1991.
Project Cost: $26 million (Canadian)
- HANGINGSTONE PROJECT Petro-Canada,
Limited (T-430)
Canadian Occidental Petroleum Ltd., Imperial Oil Ltd. and Japan Canada Oil Sands
Construction of a 13 well cyclic steam pilot with 4 observation wells was completed and operation began on May 1, 1990. On
September 4, 1990, Petro-Canada announced the official opening of the Hangingstone Steam Pilot Plant.
The production performance of the first two cycles was said to be below expectations because of severe steam override. Cold
bitumen influx into the wellbore also caused severe rodfall problems and pump seizure. In May 1992, Petro-Canada, Canadian
Occidental and Imperial Oil withdrew from further testing of the Cyclic Steam Simulation (CSS) process at Hangingstone.
Japan Canada Oil Sands Limited (JACOS) assumed the piloting with Petro-Canada contract operating for JACOS.
Some of the pilot wells are now in their fourth production cycle.
Further testing of other in situ recovery processes by JACOS, alone or with jointly other Hangingstone owners, is possible fol
lowing the current CSS test.
The Group owns 34 leases in the Athabasca oil sands, covering 500,000 hectares. Most of the bitumen is found between 200
and 500 meters below the surface, with total oil in place estimated at 24 billion cubic meters.
The Hangingstone operations are expected to continue until the end of 1994. According to JACOS, total expenditures will
reach $160 million by 1994. Expansion to an enlarged pilot operation or a semi-commercial demonstration project could result
if the current project is deemed successful. The independent test phase by JACOS at Hangingstone completed operations
November 30. 1994. The project is suspended until further notice.
- IMPERIAL COLD LAKE PILOT PROJECTS Imperial
Oil Resources Limited. (T^35)
Imperial 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 Lease
No. 40. Imperial has sold data from these tests to several companies. The Leming pilot is located in Sections 4 through 8-65-
3W4. The Leming pilot uses several different patterns and processes to test future recovery potential. Imperial expanded its
Leming field and plant facilities in 1980 to increase the capacity to 14,000 barrels per day at a cost $60 million. A further ex
pansion, costing $40 million, debottlenecked the existing facilities and increased the capacity to 16,000 barrels per day. By 1986.
the pilots had 500 wells. operating Approved capacity for all pilot projects is 3,100 cubic meters (about 19,500 barrels) per day
of bitumen.
The pilots have been used for testing a variety of recovery, production and facilities technologies.
They continue to serve as a testing area for optimizing the parameters of cyclic steam stimulation as well as on follow-up
recovery methods, such as steam displacement and horizontal wells.
(Also see Cold Lake in commercial projects listing)
Project Cost: $260 million
3-47
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
IRON - RIVER PILOT PROJECT Mobil Oil Canada (T-440)
The Iron River Pilot Project commenced steam stimulation operations in March 1988. It consists of a four hectare pad
development with 23 slant and directional wells and 3 observation wells on 3.2 and 1.6 hectare spacing within a 65 hectare
drainage area. The project is 100 percent owned by Mobil Oil. It is located in the northwest quarter of Section 6-64-6W4 ad
jacent to the Iron River battery facility located on the southwest corner of the quarter section. The project is expected to
produce up to 200 cubic meters of oil per day. The was battery expanded to handle the expected oil and water volumes. The
produced oil is transported by underground pipeline to the battery. Pad facilities consist of 105 million U/hr steam generation
facility, test separation equipment, piping for steam and produced fluids, and a flare system for casing gas.
To obtain water for the steam operation, ground water source wells were drilled on the pad site. Prior to use, the water is
treated. Produced water is injected into a deep water disposal well. Fuel for steam generation is supplied from Mobil's fuel
gas supply system and the treated oil is trucked to the nearby Husky facility at Tucker Lake.
The pilot project was successfully operated until mid-1991. The pilot is still suspended as of August 1993.
Project Cost: $14 million
- KEARL LAKE PROJECT See
Athabasca In Situ Pilot Project (T-270)
LINDBERGH STEAM PROJECT- Murphy Oil Company, Ltd. (T-470)
This experimental in situ recovery project is 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 1650 feet. The pilot began with one inverted seven spot pattern enclos
ing 20 acres. Each well has been steam stimulated and produced roughly eleven times. A steam drive from the center well was
tested from 1980 to 1983 but has been terminated. Huff-and-puff continued. Production rates from the seven-spot area were
encouraging, and a 9 well expansion was completed August 1, 1984, adding two more seven spots to the pilot. Oil gravity is 11
degrees API and has a viscosity of 85,000 Cp at reservoir temperature F. Porosity is 33 percent and permeability is 2500 md.
This pilot is currently suspended due to low oil prices.
(Refer to the Lindbergh Commercial Thermal Recovery Project (T-33) listed in commercial projects.)
Project Cost: $7 million capital, $2.5 million per year operating
- LINDBERGH THERMAL PROJECT Amoco
Canada Petroleum Company Ltd. (T-480)
Amoco (formerly Dome) drilled 56 wells 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 combina
tion thermal drive process. The enriched air scheme included three 10 acre patterns. Currently only one 10 acre enriched air
pattern is operational.
Air was injected into one 10 acre pattern to facilitate sufficient burn volume around the wellbore prior to switching over to en
riched 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. Initial injection rate was 200,000 cubic feet
per day of 100 percent pure oxygen. Early oxygen breakthrough was controlled in the first year of Combination Thermal Drive
(CTD) by reducing enrichment to 80 percent oxygen.
In the second year of CTD, further oxygen breakthrough was controlled by stopping injection, then injecting air followed by
50 percent O . Lack of production response and corrosion caused the pilot to be shut in in mid-1990.
Project Cost: $22 million
- MINE-ASSISTED PILOT PROJECT (see
Underground Test Facility Project)
3-48
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
MORGAN - COMBINATION THERMAL DRIVE PROJECT Amoco
Canada Petroleum Company Ltd. (T-490)
Amoco (formerly Dome) completed a 46 well drilling program (7 injection wells, 39 production wells) 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. All wells have been steam stimulated. The producers in these patterns have received multiple steam and air/steam
stimulations to provide for production enhancements and oil depletion prior to the initiation of with burning air as the injec
tion medium. All of the nine patterns have been ignited and are being pressure cycled using air injection.
A change of strategy with more frequent pressure cycles and lower injection pressure targets was successful for pressure cycle
four. This strategy will be continued with pressure cycle five scheduled for this year. A conversion to combination thermal
drive is still planned after pressure cycling becomes unfeasible due to longer repressuring time requirements.
The project started up in 1981 and is scheduled for completion in 1995.
Project Cost: $20 million
ORINOCO BELT STEAM SOAK PILOT-Maraven (T-500)
The Orinoco Belt of 54,000 km was divided into four areas in 1979 to effect an accelerated exploration program by the operat
ing affiliates (Corpoven, Lagoven, Maraven and Meneven) of the holding company Petroleos de Venezuela (PDVSA).
Maraven has implemented a pilot project in the Zuata area of the Orinoco Belt to evaluate performance of slant wells, produc
tivity of the Puff"
area, and well response to "Huff and steam injection in relation to a commercial development.
Twelve inclined wells (7 producers and 5 observers) have been drilled in a cluster configuration, using a slant rig with a well
spacing at surface of 15 meters and 300 meters in the reservoir.
The 7 production wells, completed with openhole gravel packs, have been tested prior to steam injection at rates between
30 BPD and 200 BPD using conventional pumping equipment. Five wells have been injected, each with 10,000 tons of steam
distributed selectively over two zones. After an initial flowing period, stabilized production on the pump averaged 1,400 BPD
per well with a water cut of less than 3 percent.
With the information derived from the exploration phase, it was possible to establish an oil-in-place for the Zuata area of
487 billion STB.
PELICAN LAKE PROJECT- CS Resources Limited and Devran Petroleum Ltd. (T-510)
CS Resources acquired from Gulf Canada, the original operator, the Pelican Lake Project comprised of some 89 sections of oil
sand leases.
The Pelican Lake program is designed to initially test the applicability of horizontal production systems under primary produc
tion methods, with a view to ultimately introducing thermal recovery methods.
Eight horizontal wells have been successfully drilled at the project site in north central Alberta. The Group utilizes an innova
tive horizontal drilling technique which allows for the penetration of about 1,500 feet of oil sands in each well. With this tech
nique, a much higher production rate is expected to be achieved without the use of expensive secondary recovery processes.
Drilling was commenced on the first horizontal well on January 30, 1988 and drilling of the eighth well was completed in June
1988. Drilling of five more horizontal wells with horizontal sections of 3,635 feet (a horizontal record) was accomplished in
December 1989 and January 1990. Four more horizontal wells were drilled in 1991 for a total of 17 horizontal wells.
All four 1991 wells contacted almost 100 percent of good quality reservoir throughout the horizontal section. The horizontal
section of one well was 1,321 meters from intermediate casing point to total depth. A 496 meter lateral arm was completed off
the horizontal section of a 1,137 meter main hole section. One "J"
907 meters.
well was a limited success with a horizontal section of
The average drill, case and completion cost of the 1991 wells was $540,000. The wells took an average of 15 days to drill with
the average horizontal section being 1,290 meters. The cost per horizontal meter has dropped from $1,240 per meter in 1988 to
$420 per meter in 1991.
Special effort was made to keep the drilling program simple and cost-effective. A surface casing was set vertically at
110 meters, then the wells were kicked off and inclination was built gradually to 90 degrees at a rate of two degrees/10 meters.
An intermediate casing was run and cemented before horizontal drilling commenced in the sand reservoir. Early production
rates averaged 15 to 20 cubic meters per day, three to six times average vertical well figures. Four wells, drilled in 1988, rapidly
W9
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
produced with a disappointing, and unexpected high water cut, whereas no bottom water is known to exist in this particular
area. However, the two subsequent horizontal wells have not had any free water problems. Sand production has not been a
major problem and the production sand content is lower than in surrounding vertical wells.
An additional six horizontal wells were drilled in 1993. To increase reservoir exposure, one of the 1993 wells was drilled and
completed using the lateral tie-back system developed by CS Resources and Sperry-Sun Services. Drilling This system provides
for the complex interconnection of individual production liners, thereby creating total wellbore integrity. The 1993 well drilled
using this system has a total of 2,798 meters of horizontal section. The cost per horizontal meter for this well was $374. The
average drill, case and completion cost of the 1993 wells was $670,000. The wells took an average of 10 days to drill with an
average horizontal section of 1,702 meters. The average cost per horizontal meter for the 1993 wells was $416.
Project Cost: Not disclosed
- PELICAN-WABASCA PROJECT CS
Resources (T-520)
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. The
remaining wells stayed on production. In January/February 1986, 18 new wells were drilled and put on production.
primary
Cyclic was undertaken steaming in February 1987. The waterflood on the pilot ceased operation in April, 1987. Cyclic steam
ing of the wells producing on the 7-spot steamflood project south of the pilot was converted to steamflood in fall 1987.
In May 1989 all thermal operations had been terminated. The wells were abandoned with the exception of 13 wells that remain
producing on primary production.
The use of horizontal wells is being tested. In 1991, an additional eight horizontal wells were drilled to about 1,000 meters in
length.
Project Cost: Not Specified
- PR SPRING PROJECT Enercor
and Solv-Ex Corporation, (T-540)
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 weight by bitumen.
The proprietary oil extraction process to be used in the project was developed by Solv-Ex in its laboratories and pilot plant and
claims the advantages of high recovery of bitumen, low water requirements, acceptable environmental effects and low economi
cal capital and costs. operating 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.
In August 1985 the sponsors requested loan and price guarantees totaling $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 deter
mined 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)
3-50
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
SOARS LAKE HEAVY OIL PILOT - Bow River Pipelines Ltd. (T-590)
Amoco Canada in July, 1988 officially opened the company's 16-well heavy oil pilot facilities located on the Elizabeth Metis
Settlement south of Cold Lake. The project is designed to test cyclic steam simulation process.
Amoco Canada had been actively evaluating the heavy oil potential of its Soars Lake leases since 1965 when the company
drilled two successful wells. The heavy oil reservoir at Soars Lake is located in the Sparky formation at a depth of 1,500 feet.
In the summer of 1987, Amoco began drilling 15 slant wells for the project. One vertical well already drilled at the site was in
cluded in the plans. The wells are oriented in a square 10 acre/well pattern along NE-SW rows.
The injection scheme initially called for steaming two wells simultaneously with the project's two 25 MMBTU/hr generators.
However, severe communication developed immediately along the NE-SW direction resulting in production problems. Al
wells'
bot-
though this fracture trend was known to exist, communication was not expected over the 660 feet between the
tomhole locations. Steam splitters were installed to allow steaming of 4 wells simultaneously along the NE-SW direction. Four
cycles of steam injection have been completed and although production problems have decreased,
reservoir performance
remains poor. The short-term strategy for the pilot calls for an extended production cycle to create some voidage in the reser
voir prior to any further steam stimulations.
In 1988 Amoco Canada begqn operating a 16-well cyclic steam project located on the Elizabeth Metis Settlement south of Cold
Lake. Alberta. The project operated until June. 1991 when it was suspended due to poor reservoir performance.
Further to extending the production cycle of the original pilot wells, Amoco Canada began testing the primary production
potential of Soars Lake with six new wells drilled in June 1991.
In 1992 Bow River Pipelines Ltd. acquired all of Amoco's interest in the Soars Lake area and began development of the
property by primary production. The cyclic steam project remains indefinitely suspended.
Project Cost: $40 million
- SOLV-EX MINERALS FROM TAR SANDS RESEARCH Solv-Ex, AOSTRA (T-593)
Solv-Ex was originally organized for the purpose of developing a process to extract bitumen from oil sands. During the 1980s
the company developed and continuously improved a patented process for bitumen extraction. A joint venture with Shell
Canada Limited during 1987 and 1988 successfully processed approximately 1,000 tons of oil sands for bitumen recovery.
Following the joint venture with Shell, Solv-Ex undertook a research and test program for commerical recovery of metals,
primarily aluminum, titanium, and iron, from both oil sands and tailings in an effort to improve the overall economics of
production operations. As a result of such efforts, the company has developed patented process technology which it believes
can be used in commercial operations for recovery of metals, either from tailings generated by others or from primary produc
tion of bitumen from the oil sands.
During 1992 and 1993, the modified company its Albuquerque pilot plant to incorporate the latest improvements in its bitumen
extraction process and to add a circuit for production of minerals from oil sands tailings. Following such work, the company
conducted a pilot program to demonstrate both bitumen extraction and production of minerals from oil sands and tailings.
Approximately 100 tons of tailings and 100 tons of oil sands crude ore were processed during the program, all of which wre ob
tained from the Athabasca region. Work is continuing at the pilot plant, primarily for the purpose of testing further improve
ments which have been made in the process, confirming product purity and evaluating the possibility of producing upgraded
products for specialty markets.
The 1992-1993 pilot program was conducted with the assistance of the Alberta Oil Sands Technology and Research Authority,
which committed to provide $300,000 for the program. The company believes the pilot program has been successful and is now
directing its efforts towards establishing a commercial operation in the Athabasca region for production of bitumen and metals
from existing tailings.
- STEEPBANK PILOT PROJECT Chevron
Canada Resources (T-600)
Chevron Canada Resources'
Steepbank pilot project utilizes the HASDrive (Heated Annulus Steam Drive) process to recover
bitumen from the Athabasca Oil Sands. The pilot plant is located on Chevron's Steepbank oil sands lease located about
30 miles northeast to Fort McMurray, Alberta, Canada.
3-51
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
In the HASDrive process, a horizontal wellbore is drilled into the oil sands formation. Steam is circulated in the cased
wellbore thereby transferring heat into the oil sand. Two vertical injection wells are used to inject steam into the formation at
points along the heated horizontal channel (annulus), driving the heated bitumen toward a production well placed between the
injection wells.
The pilot includes two steam injection wells, one producing well, one horizontal HASDrive well, six temperature observation
wells and four crosshole seismic wells.
Operations commenced November 1, 1991 with steam circulation in the horizontal well. Steam injection and production were
both under way by March 1992. The project operations were suspended in March 1993.
Project Cost: $12.7 million
- TACIUK PROCESSOR PILOT Alberta
Department of Energy and The UMA Group Ltd. (T-610)
UMATAC Industrial Processes (UMATAC) of Calgary, Canada developed the AOSTRA Taciuk Process (ATP) technology
which is a patented, unique, thermal desorption system for separating and extracting water and organics from host solids. It
was developed as a dry, thermal process to produce oil from natural resource oil sands and oil shales.
The technology is owned by the Alberta Department of Energy. Oil Sands and Research Division (OSRD. formerly
AOSTRA). which funded the development since 1977, investing approximately $25 million. UMATAC is the developer and
supplier, and also the licensee for use of the ATP System in waste treatment applications.
In 1992. AOSTRA convened an oil industry Task Force to re-assess the ATP for commercial production of oil from Alberta oil
sand. The study included demonstration operation of a new, 5 tph portable capacity ATP plant operated by UMATAC in Cal
gary. Successful conclusions will lead to consideration of a large scale demonstration ATP plant installation in the Fort
McMurray oil sands area of Alberta.
UMATAC has completed preliminary design of a 250 tph capacity ATP Processor and associated plant for an oil shale
development project in Australia. Study and development of the ATP for this project included pilot scale testing of a 2,000
tonne bulk sample of oil shale shipped from Australia to the ATP pilot plant in Calgary. Testing was completed in 1987.
The ATP is also suited for use in treating contaminated soils, sludges and wastes in environmental remediation work. Typical
applications are:
Cleaning and recovering oil from wastes produced in oil field production and operations of oil refineries and
petrochemical plants;
Clean up of soils or other materials which are contaminated with PCBs or other heavy organic compounds, such
as coal tars and industrial chemicals.
Organics and water are separated by anaerobic thermal desorption as vapors which are condensed to liquids in a second step of the
system. The oil fraction is potentially recyclable, depending on the type of contaminant.
UMATAC supplies the ATP technology under license for use in waste treatment and also manufactures and supplies the ATP
plant equipment. The ATP has been used commercially on soils remediation in the United States since 1990 by the U.S. licensee,
SoilTech ATP Systems, Inc. A 10 tph capacity plant has successfully completed PCB clean up of four Superfund sites.
Project Cost To Date: C$25 million (ADOE-OSRD^
TANGLEFLAGS NORTH -
Sceptre
Resources Limited and Murphy Oil Canada Ltd. (T-620)
The project, located some 35 kilometers northeast of Lloydminster, Saskatchewan, near Paradise Hill, involves the first horizontal
heavy oil well in Saskatchewan. Production from horizontal oil wells is expected to dramatically improve the recovery of heavy oil
in the Lloydminster region.
The Tangleflags North Pilot Project is employing drilling methods similar to those used by Esso Resources Canada Ltd. in the Nor
man Wells oil field of the Northwest Territories and at Cold Lake, Alberta. The combination of the 500-meter horizontal produc
tion well and steamflood technology is expected to increase recovery at the Tangleflags North Pilot Project from less than one per
cent of the oil in place to up to 50 percent.
The governments of Canada and Saskatchewan provided $3.8 million in under funding the terms of the Canada-Saskatchewan
Heavy Oil Fossil Fuels Research Program.
3-52
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
Estimates indicate sufficient reserves exist in the vicinity of the pilot to support commercial development with a peak gross produc
tion rate of 6,200 barrels of oil per day. Remaining project life is estimated at 15 years with ultimate recovery about 25 million bar
rels.
The Tangleflags pilot has advanced to the continuous steam injection phase. With one horizontal well and four vertical steam injec
tion wells in place, the project was producing at rates in excess of 1,000 barrels of oil per mid day by 1990. Cumulative production
to the middle of 1990 was 425,000 barrels.
The strong performance of the initial well prompted Sceptre to initiate a project expansion which was completed during 1992. For
this purpose a second horizontal producer well and an additional vertical injector well were drilled in the fourth quarter of 1990.
Facilities were expanded to generate more steam and handle increased production volumes in early 1991. During 1992, two steam
injectors were added and a third steam generator was brought into service. In 1993, an additional steam injector and another
horizontal well had been drilled. Three horizontal producers, two vertical wells and a heat recovery system, were added during
1994. The project now includes six horizontal producers and ten vertical steam injectors. A peak project rate of 2,800 barrels per
day was achieved in January 1993, and cumulative oil production reached 2,257 million barrels.
Project Cost: $_20 million invested by end of 1994
- 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 Tri
angle Special Tar Sand Area (STSA).
Kirkwood is also active in three other STSAs as follows:
Raven Ridge-Rimrock-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.
The project has been put on temporary hold.
Project Cost: Unknown
- UNDERGROUND TEST FACILITY Alberta Department of Energy Oil Sands and Research Division (OSRD). Federal Depart
ment of Energy, Mines and Resources (CANMET), Chevron Canada Resources Limited, Imperial Oil Ltd., Conoco Canada Limited,
Suncor, Inc., Petro-Canada Inc., Shell Canada Ltd., Amoco Canada Petroleum Company, Ltd., Japex Oil Sands Ltd., China National
Petroleum Corporation (T-650)
The Underground Test Facility (UTF) was constructed by AOSTRA during 1984-1987, for the purpose of testing novel in situ
recovery technologies based on horizontal wells, in the Athabasca oil sands. The facility is located 70 kilometers northwest of Fort
McMurray, and consists of two access/ventilation shafts, three meters in diameter and 185 meters deep, plus a network of tunnels
driven in the Devonian limestone that underlies the McMurray pay. A custom drilling system has been developed to drill wells up
ward from the tunnels, starting at a shallow angle, and then horizontally through the pay, to lengths of up to 600 meters.
Two processes were selected for initial testing: steam assisted gravity drainage (SAGD), and Chevron's proprietary HASDrive
process. Steaming of both test patterns commenced in December 1987 and continued up to early 1990. HASDrive was shut in
April 1990 and the SAGD was to continue producing in a blowdown phase until the fall of 1990.
Both tests were technical successes. In the case of the Phase A SAGD test, a commercially viable combination of production rates,
steam/oil ratios, and ultimate recovery was achieved. Complete sand control was demonstrated, and production flowed to surface
for most of the test.
Construction of the Phase B SAGD test commenced in the spring of 1990 with the drivage of 550 meters of additional tunnel, for a
total of about 1,500 meters. Phase B is a direct scale up of the Phase A test, using what is currently thought to be the economic op
timum well length and spacing. The test consists of three pairs of horizontal wells, with completed lengths of 600 meters and
70 meter spacing between pairs. Each well pair consists of a producer placed near the base of the pay, and an injector about
3-53
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1994)
R&D PROJECTS (Continued)
5 meters above the producer. All six wells were successfully drilled in 1990/1991. The contractual obligations for Phase B opera
tions will be completed by 1994. Phase B will continue operation at least until 1996. Phase A produced over 130,000 barrels of
bitumen.
Phase B steaming commenced in September 1991, then was shut-in temporarily to construct larger facilities. Production was
started up in early 1993. A decision regarding expansion to commercial production will be made after evaluation. Two thousand
barrels per day of bitumen are currently being produced by this method. Plans are underway for expansion to over 4.000 barrels
per day.
OSRD states that this new method of bitumen production is a major technological breakthrough and that bitumen may eventually
be produced for under C$7 per barrel, which would be less costly than most current in situ bitumen production.
Project Cost: $150 million
3-54
SYNTHETIC FUELS REPORT, JANUARY 1995

Project
Aberfeldy Project
A.D.I. Chemical Extraction
Alsands Project
Aqueous Recovery Process
Ardmore Thermal Pilot Plant
Asphalt Ridge Tar Sands Pilot
Asphalt Ridge Pilot Plant
Athabasca Project
Beaver Crossing Thermal Recovery Pilot
Bi-Provincial Upgrader
Block One Project
Burnt Hollow Tar Sand Project
Burnt Lake
BVI Cold Lake Pilot
California Tar Sands Development Project
Calsyn Project
CANMET Hydrocracking Process
Canstar
Caribou Lake Pilot Project
COMPLETED AND SUSPENDED PROJECTS
Sponsor
Husky Oil Operations, Ltd.
Aarian Development, Inc.
Shell Canada Resources, Ltd.
Petro-Canada
Gulf Canada
Globus Resources, Ltd.
United-Guardian, Inc.
Union Texas of Canada, Ltd.
Sohio
Enercor
Mobil
University of Utah
Shell Canada Limited
Solv-Ex Corp.
Chevron Canada Resources
Husky Oil Operations Ltd.
Government of Canada
Province of Alberta
Province of Saskatchewan
Amoco Canada Petroleum Company Ltd.
AOSTRA
Petro-Canada Ltd.
Shell Canada Resources
Suncor, Inc.
Glenda Exploration & Development Corp.
Kirkwood Oil & Gas Company
Suncor
AOSTRA
Bow Valley Industries, Ltd.
California Tar Sands Development Company
California Synfuels Research Corporation
AOSTRA
Dynalectron Corporation
Ralph M. Parsons Company
Tenneco Oil Company
Petro-Canada
SNC-Lavalin, Inc.
Nova
Petro-Canada
Husky Oil Operations Ltd.
Alberta Energy Company
3-55
Last Appearance in SFR
March 1983;
page 3-33
December 1983; page 3-56
September 1982; page 3-35
December 1984; page 3-44
September 1989; page 3-9
December 1986; page 3-51
September 1984; page T-7
September 1988; page 3-50
December 1988; page 3-67
June 1994; page 3-35
September 1984; page T-8
September 1984; page T-8
December 1986; page 3-43
March 1991; page 3-44
September 1989; page 3-42
March 1984; page 3-34
March 1992; page 3-50
March 1987; page 3-29
June 1994; page 3^*8
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Cat Canyon Steamflood Project
Cedar Camp Tar Sand Project
Chaparrosa Ranch Tar Sand Project
Charlotte Lake Project
Chemech Project
Chetopa Project
Cold Lake Pilot Project
Deepsteam Project
Donor Refined Bitumen Process
Electromagnetic Well Stimulation Process
Enpex Syntaro Project
Falcon Sciences Project
Forest Hill Project
Fostern N. W. In Situ Wet Combustion
Grossmont Thermal Recovery Project
HOP Kern River Commercial
Development Project
Ipiaitk East Project
Ipiatik Lake Project
Jet Leaching Project
Kenoco Project
Kentucky Tar Sands Project
Lloydminster Fireflood
Manatokan Project
Marguerite Lake 'B'
Unit
Getty Oil Company
United States Department of Energy
Enercor
Mono Power
Chaparrosa Oil Company
Canadian Worldwide Energy Ltd.
Chemech
EOR Petroleum Company
Tetra Systems
Gulf Canada Resources
Sandia Laboratories
United States Department of Energy
December 1983; page 3-58
June 1987; page 3-55
March 1985; page 3-42
September 1988; page 3-61
December 1985; page 3-51
December 1983; page 3-59
December 1979; page 3-31
March 1984; page 341
Gulf Canada Resources Ltd.
Alberta Oil Sands Technology & Research June 1994; page 3-49
Authority
L'
Association pour la Valorization des Hiules Lourdes
Uentech Corporation
Enpex Corporation
Texas Tar Sands Ltd.
Getty Oil Company
Superior Oil Company
M. H. Whittier Corporation
Ray M. Southworth
Falcon Sciences, Inc.
Greenwich Oil Corporation
Mobil Oil Canada, Ltd.
Unocal Canada Ltd.
Ladd Petroleum Corporation
Alberta Energy Company
Amoco Canada Petroleum Company, Ltd.
Deminex Canada
Alberta Energy Company and
Petro-Canada
BP Resources Canada Ltd.
Kenoco
Texas Gas Development
Murphy Oil Company, Ltd.
Canada Cities Service
Westcoast Petroleum
AOSTRA
BP Resources Canada
Petro-Canada
3-56
June 1994; page 3-37
March 1989; page 3-63
December 1985; page 3-38
June 1994; page 3-39
December 1989; page 3-
December 1988; page 3-71
June 1985; page 3-51
March 1992; page 3-54
December 1986; page 3-63
June 1991; page 3-57
December 1991; page 3-52
June 1985; page 3-52
December 1983; page 3-63
September 1982; page 3-43
December 1988; page 3-72
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Meota Steam Drive Project
Mine-Assisted In Situ Project
MRL Solvent Process
Muriel Lake
North Kinsella Heavy Oil
OSLO Project
Peace River In Situ Pilot
Porta-Plants Project
Primrose Project
Primrose-Kirby Project
Provost Upper Mannville Heavy Oil
Steam Pilot
RAPAD Bitumen Upgrading
Ras Gharib Thermal Pilot
Resdeln Project
R. F. Heating Project
Rio Verde Energy Project
RTR Pilot Project
Sandalta
Santa Fe Tar Sand Triangle
Santa Rosa Oil Sands Project
Conterra Energy Ltd
Saskatchewan Oil & Gas
Total Petroleum Canada
Canada Cities Service
Esso Resources Canada Ltd.
Gulf Canada Resources, Inc.
Husky Oil Corporations, Ltd.
Petro-Canada
C & A Companies
Minerals Research Ltd.
Canadian Worldwide Energy
Petro-Canada
Imperial Oil Ltd.
Canadian Occidental
Gulf Canada
Petro-Canada
PanCanadian Petroleum
Alberta Oil Sands Equity
Amoco Canada Petroleum
AOSTRA
Shell Canada Limited
Shell Explorer Limited
Porta-Plants Inc.
Japan Oil Sands Company
Norcen Energy Resources Ltd.
Petro-Canada
AOSTRA
Canadian Occidental Petroleum Ltd.
Imperial Oil Ltd.
Murphy Oil
Norcen Energy Resources Ltd.
Research Association for Petroleum Alternatives
General Petroleum Company of Egypt
Gulf Canada Resources Inc.
1IT Research Institute
Halliburton Services
United States Department of Energy
Rio Verde Energy Corporation
RTR Oil Sands (Alberta) Ltd.
Gulf Canada Resources Ltd.
Home Oil Company, Ltd.
Mobil Oil Canada Ltd.
Altex Oil Corporation
Santa Fe Energy Company
Solv-Ex Corporation
Samia-London Road Mining Assisted Project Devran Petroleum
3-57
June 1987; page 3-60
December 1983; page 3-64
March 1983; page 3-41
June 1987; page 3-61
June 1985; page 3-58
June 1994; page 3-41
June 1987; page 3-61
September 1986; page 3-50
September 1984; page T-16
June 1986; page 3-56
June 1994; page 3-54
December 1991; page 3-55
March 1990; page 3-54
March 1983; page 3-43
March 1983; page 343
June 1984; page 3-58
March 1991; page 3-53
March 1992; page 3-58
December 1986;
page 3-60
March 1985; page 345
December 1988; page 3-62
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
South Kinsella (Kinsella B)
South Texas Tar Sands
Sunnyside Tar Sands Project
Texaco Athabasca Pilot
Tucker Lake Pilot Project
Ultrasonic Wave Extraction
Vaca Tar Sand Project
Wabasca Fireflood Project
Whiterocks Oil Sand Project
Wolf Lake Oxygen Project
"200"
Sand Steamflood Demon
stration Project
Shell Canada
Dome Petroleum
Conoco
GNC Energy Corporation
Texaco Canada Resources
Husky Oil Operations Ltd.
Western Tar Sands
Santa Fe Energy Company
Gulf Canada Resources, Inc.
Enercor
Hinge-line Overthrust Oil & Gas Corp.
Rocky Mountain Exploration Company
BP Canada Resources
Petro Canada
Santa Fe Energy Company
United States Department of Energy
3-58
December 1988; page 3-76
June 1987; page 3-64
June 1994; 3-44
June 1987; page 3-66
December 1991; page 3-57
June 1987; page 3-66
March 1982; page 3-43
September 1980; page 3-61
December 1983; page 3-55
September 1988; page 3-70
June 1986; page 3-62
SYNTHETIC FUELS REPORT, JANUARY 1995

Company or Organization
Alberta Energy Company
Alberta Oil Sands Equity
Alberta Oil Sands Technology
and Research Authority (AOSTRA)
Amoco Canada Petroleum Company, Ltd.
Amoco Production Company
Buenaventura Resource Corp.
Canada Centre For Mineral & Energy
Technology
Canadian Hunter Exploration
Canadian Occidental Petroleum, Ltd.
Canadian Worldwide Energy Corp.
CANMET
C-H Synfuels Ltd.
Chevron Canada Resources Ltd.
China National Petroleum Corporation
Conoco
Conoco Canada Ltd.
Consumers Cooperative Refineries Ltd.
Crown Energy Corporation
CS Resources
Devran Petroleum Ltd.
Enercor
Gulf Canada Resources Ltd.
INDEX OF COMPANY INTERESTS
Project Name
Burnt Lake Project
Primrose Lake Commercial Project
Syncrude Canada Ltd.
Syncrude Canada Ltd.
Athabasca In Situ Pilot Plant
GLISP Project
Solv-Ex Minerals from Tar Sands
Taciuk Processor Pilot
Underground Test Facility Project
Elk Point
GLISP Project
Lindbergh Commercial Project
Lindbergh Thermal Project
Morgan Combination Thermal Drive Project
Primrose Lake Commercial Project
Underground Test Facility
Wolf Lake Project
Sunnyside Project
Buenaventura Cold Process Pilot
Underground Test Facility
Burnt Lake Project
Eyehill In Situ Combustion Project
Hangingstone Project
Syncrude Canada Ltd.
Fort Kent Thermal Project
Underground Test Facility
C-H Synfuels Dredging Project
Steepbank HASDrive Pilot Project
Underground Test Facility
Underground Test Facility
Conoco-Maraven Tarsand Project
Underground Test Facility
NewGrade Heavy Oil Upgrader
Crown Oil Sands Project
Eyehill In Situ Combustion Project
Pelican-Wabasca Project
Pelican Lake Project
Pelican Lake Project
PR Spring Project
Syncrude Canada Ltd.
3-59
Page
3-34
3-39
3-41
3-41
3-44
347
3-51
3-52
3-53
3-36
347
3-37
348
349
3-39
3-53
342
341
344
3-53
3-34
346
347
341
346
3-53
345
3-51
3-53
3-53
3-34
3-53
3-37
3-35
346
3-50
349
349
3-50
341
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF OIL SANDS PROJECTS
INDEX OF COMPANY INTERESTS (Continued)
Company or Organization
HBOG Oil Sands Partnership
Hudson's Bay Oil and Gas
Husky Oil Operations, Ltd.
Imperial Resources Oil Ltd.
James W. Bunger and Assoc. Inc.
Japan Canadian Oil Sands Ltd.
Japax Oil Sands Ltd.
Kirkwood Oil and Gas Company
Koch Exploration Canada
Lagoven
Maraven
Mitsubishi Oil Company
Mobil Oil Canada Ltd.
Murphy Oil Canada Ltd.
NewGrade Energy Inc.
Ontario Energy Resources Ltd.
PanCanadian Petroleum
Petro-Canada
Petroleos de Venezuela SA
Saskatchewan Government
Saskoil
Project Name
Syncrude Canada Ltd.
Battrum In Situ Wet Combustion Project
Athabasca In Situ Pilot Project
Athabasca In Situ Pilot Project
Cold Lake Project
Hanging Stone Project
Imperial Cold Lake Pilot Projects
Syncrude Canada Ltd.
Underground Test Facility
Asphalt From Tar Sands
Hangingstone Project
Underground Test Facility
Circle Cliffs Project
Tar Sand Triangle
Fort Kent Thermal Project
Soars Lake Heavy Oil Pilot
Mobil-Orinoco Heavy Oil Project
Conoco-Maraven Tarsand Project
Orinoco Belt Steam Soak Pilot
Total-Orinoco Heavy Oil Project
Syncrude Canada Ltd.
Battrum In Situ Wet Combustion Project
Celtic Heavy Oil Pilot Project
Cold Lake Steam Stimulation Program
Iron River Pilot Project
Mobil-Orinoco Heavy Oil Project
Eyehill In Situ Combustion Project
Lindbergh Commercial Thermal Recovery Project
Lindbergh Steam Project
Tangleflags North
NewGrade Heavy Oil Upgrader
Suncor, Inc. Oil Sands Group
Elk Point Oil Sands Project
Syncrude Canada Ltd.
Daphne Project
Hangingstone Project
Syncrude Canada Ltd.
Underground Test Facility
Orimulsion Project
NewGrade Heavy Oil Upgrader
Battrum In Situ Wet Combustion Project
3-60
Page
341
344
344
344
3-34
347
347
341
3-53
3-33
347
3-53
345
3-53
346
3-51
3-37
3-34
349
342
341
344
345
345
348
3-37
346
3-37
348
3-52
3-37
340
3-36
341
3-35
347
341
3-53
3-38
3-37
344
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF OIL SANDS PROJECTS
INDEX OF COMPANY INTERESTS (Continued)
Company or Organization
Sceptre Resources Ltd.
Shell Canada, Ltd.
Solv-Ex Corporation
Suncor, Inc.
Sun Company, Inc.
Synco Energy Corporation
Texaco Canada Petroleum
Texaco Inc.
Three Star Drilling and Producing Corp.
Total
Underwood McLellan & Associates
(UMA Group)
United Tri-Star Resources, Ltd.
Unocal Canada, Ld.
Union of Soviet Socialist Republics
Veba Oel AG
Project Name
Tangleflags North
Peace River Complex
Scotford Synthetic Crude Refinery
Underground Test Facility
Bitumount Project
PR Spring Project
Solv-Ex Minerals from Tar Sands
Solv-Ex/United Tri-Star Oilsand Agreement
Burnt Lake Project
Suncor, Inc. Oil Sands Group
Underground Test Facility
Suncor, Inc. Oil Sands Group
Synco Sunnyside Project
Frog Lake Project
Diatomaceous Earth Project
Three Star Oil Mining Project
Total-Orinoco Heavy Oil Project
Taciuk Processor Pilot
Solv-Ex/United Tri-Star Oilsand Agreement
Battrum In Situ Wet Combustion Project
Yarega Mine-Assisted Project
Orimulsion Project
3-61
Page
3-52
3-38
340
3-53
3-33
3-50
3-51
340
3-34
340
3-53
340
341
346
3-35
342
342
3-52
340
344
343
3-38
SYNTHETIC FUELS REPORT, JANUARY 1995

3-62
SYNTHETIC FUELS REPORT, JANUARY 1995

PROJECT ACTIVITIES
POINT OF AYR LIQUEFACTION PLANT
BEGINNING TENTH RUN
British Coal's 2.5-ton per day Liquid Solvent Ex
traction pilot plant at Point of Ayr, North Wales,
United Kingdom has completed nine runs, with
up to 2,000 hours of operating time available for
each run. Run 10, scheduled for 3,000 hours,
was to start in January 1995. H. Williams and
R. Hughes of British Coal gave the pilot plant
results to the 11th Annual Pittsburgh Coal Con
ference last fall. A companion paper by
S. Walton and M. Pudifoot gave some findings
regarding the importance of good coal feed
analysis, because they found that segregation
could occur in the feedhopper.
During the nine runs made to date, there have
been some equipment-related problems, but
these have been overcome as the runs have
progressed. The main problem areas have been
compressors, ebullating pumps and magnetic
drive pumps. Liquid yields of above 60 percent
based on the dry ash free coal feed have been
achieved.
The process involves feeding pulverized coal
which is first slurried with solvent to a digester
where up to 95 percent of the coal is dissolved.
Filtration is used to remove solids (mineral matter
and undissolved coal) and the valuable "coal ex
solution"
tract enters the ebullating bed
hydrocracking reactors. Here, catalytic reactions
carried out at 200 bar and 400-450C change the
structure of the coal by introducing hydrogen.
Final distillation recovers the solvent for recycling
and yields three main products:
- LPG
- Middle
(propane and butane)
Naphtha
distillate
The naphtha and middle distillate are subse
quently upgraded, using conventional oil industry
techniques, to gasoline and diesel.
COAL
4-1
Exxon Joins Project
Early
in 1994 it was announced that Exxon
Research and Engineering had joined the Point
of Ayr project. Exxon is the second oil company
(in addition to Amoco) to participate in the
project. Exxon will invest 630,000 pounds in the
project. This should lend considerable weight to
the successful development of the process. The
agreement gives Exxon the right to increase their
participation in the future and to license the tech
nology.
####
ENCOAL PLANT ENTERS PRODUCTION
STAGE
Last June, SGI International reported that the
ENCOAL Clean Coal demonstration plant located
next to Triton Coal Company's Buckskin Mine
near Gillette, Wyoming, is in production. The
plant uses the LFC (Liquids From Coal) Process
Technology developed by SGI.
The plant, which completed a 24-month
demonstration and test phase, now processes
500 tons of coal per day from the Powder River
Basin of Wyoming. The low-sulfur, low-moisture,
high-BTU clean coal product is being success
fully produced and stockpiled for shipment to
utilities for test burns. The low-sulfur coal oil also
produced by the plant has been shipped and suc
cessfully used by industrial customers.
ENCOAL Corporation owns the plant and
licenses the LFC Process from the TEK-KOL
Partnership, jointly owned by SMC Mining Com
pany and SGI International. ENCOAL is a sub
sidiary of SMC Mining Company, which is owned
by Zeigler Coal Holding Company, a major U.S.
coal producer.
While coal mined from Wyoming's Powder River
Basin has some of the naturally lowest levels of
sulfur available, it is relatively high in moisture,
increasing transportation costs while decreasing
its energy value.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
Removing
that moisture is the main point of the
process, in order to reduce transportation costs.
During a 68-day period of sustained operation,
ENCOAL's plant processed over 24,000 tons of
Powder River Basin subbituminous coal, produc
ing marketable coproducts of approximately
11,000 tons of Process Derived Fuel (PDF) and
more than 600,000 gallons of Coal Derived Liquid
(CDL). The PDF and CDL, both clean fuel
products of the LFC process, are expected to as
sist Industry in meeting
ments of the Clean Air Act standards.
the long-term require
The 500-ton feedrate is expected to reach
1,000 tons per day after additional capacity
modifications are completed.
The first product was shipped to Western
Farmers'
Hugo powerplant in Oklahoma in Sep
tember. That first shipment was blended at ap
15 percent upgraded clean coal to
proximately
85 percent unprocessed Powder River Basin
coal; subsequent shipments are to be at a higher
percentage of upgraded clean coal.
After a successful test burn, a second blended
shipment was shipped to the same utility.
In October, the United States Department of
Energy (DOE)
and the ENCOAL Corporation
agreed to an extension of their Cooperative
Agreement. The extension will provide additional
funding of up to $18 million for two more years of
operations of ENCOAL's demonstration plant.
DOE and ENCOAL will each contribute one-half
of the additional funding under the extension.
Railroad tank cars of coal liquids are being
shipped on a regular basis to several customers
in the midwest, including the Dakota Gasification
Plant In Beulah, North Dakota, where tests have
successfully demonstrated use of the fuel in in
dustrial boilers.
Utilities which are planning to test the coal in addi
tion to Western Farmers'
in Oklahoma, include
Muscatine Power in Iowa, and Wisconsin Power
and Light. Muscatine Power in Eastern Iowa
4-2
received Its first shipment as a 40 percent blend
of the PDF with Western coal under a contract
that calls for shipments of 10,000-20,000 tons of
PDF. Future shipments will include blends of
70 percent and 90 percent PDF.
Technology Licensing Activities
SGI continues marketing activities for the LFC
process worldwide. The company says It is
evaluating funding alternatives for a project in
Alaska which would site a Clean Coal Refinery on
tribal land located in the Cook Inlet region. Un
der the 1992 National Energy Policy Act, Native
American tribes can obtain grants for energy
project development.
In Indonesia, SGI has submitted proposals for
two Indonesian Clean Coal Refinery Projects.
The clean coal and oil from Indonesian coal
refineries could earn badly needed foreign ex
change and could also meet domestic energy
requirements.
In Poland, a testing program was recently com
pleted with positive recommendations for Clean
Coal Refinery processing of high-sulfur coals
from the Belchatow Mine in South-Central
Poland. The mine produces about 40 million
tonnes per year that is dedicated to a nearby
4,320 megawatt power station. The powerplant's
sulfur dioxide emissions are a significant environ
mental problem. SGI has reported that refining
of the lignite would result in significantly lower
powerplant S02 emissions.
In China, SGI has signed Letters of Intent and
has evaluated candidate coals received from coal
producers in Shandong, Shanxi, and Uaoning
Provinces.
In September, it was announced that SGI and Mit
subishi Heavy Industries (MHI) have agreed to
proceed with an engineering and economic
feasibility program for a 6,000-tonne per day
Clean Coal Refinery to be located at Longkou
Harbor in Shandong Province, China. SGI and
MHI will work with the Comprehensive Utilization
Corporation of Shandong Coal Industry, which is
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
expected to become a partner in the project and
to assist in plant construction and operation.
Feedstock coal for the plant will come from the
Uangjia Mine located near Longkou Harbor.
In full operation the plant, called China One,
would be expected to annually produce more
than 1 million tonnes of low-sulfur clean coal and
1.5 million barrels of oil.
SGI and MHI expect to complete the engineering
and economic feasibility work for China One in
the first half of 1995. A new venture, China Clean
Coal Refineries Ltd. (CCCR), is planned to carry
out LFC plant development activities in China.
CCCR would receive, for due consideration, an
exclusive territorial LFC technology license for
China.
####
BUGGENUM STARTUP DETAILED
At the 13th EPRI Conference on Gasification
Power Plants, held in October in San Francisco,
California a paper by H. de Winter and
W. Willeboer presented a review of the design,
construction and startup of Demkolec's 250megawatt
IGCC plant in Buggenum, The Nether
lands.
In 1989, the Dutch Electricity Generating Board,
N.V. Sep, announced plans for a 250 megawatt
Integrated Gasification Combined Cycle (IGCC)
demonstration plant. The plant was built and is
operated by Demkolec B.V., a fully owned
development partnership of N.V. Sep. The plant,
officially was
constructed at the existing power station site in
Buggenum, municipality of Haelen, and was
started up early 1994. The demonstration period
is defined as a 3-year period, after which the
named "Willem-Alexander Centrale,"
plant will be used as a commercial production
unit for the rest of its lifetime.
Project Description
The plant consists of the following main sections:
4-3
- 2,000
- Gas
- Air
- Combined
- Water
tons coal per day gasification unit,
a single Shell gasifier with syn
including
gas cooling and solids removal facilities
treating
the coal gas
unit for the desulfurization of
separation plant of approximately
1,700 tons per day oxygen production
capacity (purity 95 percent)
cycle unit, including one
Siemens V94.2 gas turbine
(156 megawatts) mounted on one shaft
with the steam turbine (128 megawatts)
treatment unit, designed for zero
effluent discharge
The project also comprises additional plant sec
tions for utilities, infrastructure, control systems
and power distribution. For the existing conven
tional power station at Buggenum only the coal
storage and handling facilities and cooling water
intake and outlet facilities could be used.
Total capital investment
HFL 850 million (1989 basis).
required was
Proven technology was selected to the largest
possible extent. This applies, for instance, to the
gas turbine, steam turbine and waste heat boiler
unit, the air separation plant and the gas and
water treatment systems. Consequently, the net
efficiency of the plant, 43 percent, is not the
highest figure one can calculate today. On the
other hand, after demonstrating the integration
concept at this scale, further improvements by
new generation components can be
applying
achieved without fundamental uncertainties.
Environmental Aspects
The environmental aspects of the plant can be
summarized as follows:
- Overall
desulfurization efficiency: better
than 97.85 percent
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
-
NOx
production: lower than 75 grams
per gigajoule of coal (permit values)
Dust emissions: negligible
The maximum emission levels are as follows:
j
- NOx:
- Dust:
SO : 0.22 g/kWh (0.062 Ib/MMBTU)
0.62 g/kWh (0.17 Ib/MMBTU)
0.007 g/kWh (0.002 Ib/MMBTU)
NO control is mainly achieved by suppressing
the flame temperature in the gas-turbine combus
tor. For this purpose the coal gas is diluted with
nitrogen and saturated with water vapor prior to
combustion.
cod
MW"*"
585
feed water
LP steam
QXyQCMTI
I
gasffcaDon
Qas treating
1
FIGURE 1
Integration Concept
The Integration concept (Figure 1) Is charac
terized by two main elements: gas side integra
tion and steam side integration.
BUGGENUM INTEGRATED CONCEPT
nRiogen
Jr
COS Q83
40 MW.
separation
own electricity consumption : 31 MWe
various heat losses : 80 MW
SOURCE: da W1KTERAWILLEBQER
i
Hp steam 64 MW
saturation
dilution
T
79kg/s
o o
i 1 ! feed i >
The gas turbine, the air separation plant and the
coal gasification unit are interconnected. The
gas turbine supplies part of its compressed air to
the air separation plant, which in turn supplies
oxygen to the coal gasification unit, and nitrogen
for coal pressurization and dilution of the coal
gas. The amount of air required for air separa
tion will, as such, not be in balance with the op
timum (diluted) coal gas flow to the gas turbine.
The mass flow through the expansion part of the
diluted
coal gas
501 MW
gasturbins
Ir atecstridy
495 kg/9 284 MWe
stack
50 MW
A
, ieeu water
LP steam
32 MW
ooodng water
171 MW
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
turbine is optimized, by replenishing the mass
deficit by saturating the diluted coal gas with
water vapor. In order to be able to start the air
separation unit independent from the gas turbine,
a separate startup booster compressor for air
was installed.
Steam side integration means that the steam sys
tems of the gasification and gas cooling sections,
including those of the gas treating etc. were fully
integrated with the steam systems of the com
bined cycle unit and the auxiliary boiler.
Status of the Integrated Operation
As of August 1994 the following had been
achieved:
- 25
- Satisfactory
- More
- More
-
- Integrated
- Several
gasification runs recorded
coal gasification process
performance of the Shell
than 6,000 operating hours for the
air separation plant
than 4,000 hours combined cycle
operation with natural gas
Satisfactory operation of all units and sys
tems on a stand-alone basis
operation tested and validated
successful test runs with coal
gas to gas turbine at 50-75 percent load
The original startup schedule was stretched out,
mainly due to unavailability and operating
problems in the combined cycle plant, by about
6 months.
####
4-5
NEDOL 150 TON/DAY UQUEFACTION PILOT
PLANT TO BE COMPLETED IN 1996
Nippon Coal Oil Company, Ltd. (NCOL) has been
commissioned by Japan's New Energy and In
dustrial Technology Development Organization
(NEDO) to design, construct and operate a
150 ton per day bituminous coal liquefaction pilot
plant based on the NEDOL process. This work is
being undertaken as a project of the New Sun
shine Program-sponsored by the Ministry of In
ternational Trade and Industry.
A progress report on the project was given by
NCOL's H. Ishibashi et al. at the 1 1th Annual Pitts
burgh Coal Conference last fall. This will be the
first coal liquefaction pilot plant built in Japan.
The civil engineering and foundation work at
Kashima, Ibaraki Prefecture was initiated in 1991,
and the installation of equipment commenced in
1993. Construction is scheduled for completion
by June 1996.
The NEDOL Process
Figure 1 gives a schematic flow chart of the
NEDOL process. This process is characterized
by a wide applicability to various coal grades,
such as low-rank bituminous coal, subbituminous
coal and low-rank subbituminous coal. It is a
single-stage liquefaction method that combines
the advantages of a hydrogen-donor solvent and
a fine iron catalyst. A vacuum distillation system
for solid-liquid separation is used to improve
reliability. The simplicity
ensure a high degree of stability.
of this process is said to
Typical conditions for liquefaction are as follows:
- Pressure:
- Temperature:
- Catalyst:
16.7 MPa
450C
fine particles of iron compound
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
lav eotl
ii -
l!
FIGURE 1
NEDOL PILOT PLANT FLOW DIAGRAM
-
B/togu HfM2P
8hCT7 ]tUBp
lr*roin-dopor tofrnt
SOURCE: ISMBASM ET AL.
- Catalyst
- Slurry
- Residence
- Gas
-
pnhMUai furuct
ft
UUevs nin
-Bydnfu
quantity: 3 wt% (dry ash free
coal basis)
concentration: 40 wt% (dry coal
basis)
time: 60 minutes
solvent ratio: 700Nm3/t
H2
concentration in recycle gas: 85 vol%
Typical conditions for hydrogenation are as fol
lows:
J',
^T
Ijdnfca
Sofral prtfcctU&g funuec
AS
- Pressure:
- Temperature:
- Catalyst:
- LHSV:
- Gas
-
T
BmUbi furatet I
!
laidu
9.8 MPa
320C
Ni-Mo-AI 0
1 hour1
slurry
H2
Operating Plans
h>Cm
Ufkt oU
ratio: 5O0Nm3/t
M*diuiBAMT7
concentration in recycle gas: 90 voi%
After mechanical completion of the pilot plant,
nine test runs are planned to be carried out by
1998.
####
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
CONSTRUCTION BEGINS ON TECO's POLK
IGCC PLANT
Tampa Electric Company's (TECO) Integrated
Gasification Combined Cycle (IGCC) project in
Polk County, Florida was kicked off with an offi
cial groundbreaking ceremony the first of Novem
ber. The environmental impact assessment for
the project was approved in July, and a final
financing
Department of Energy (DOE)
August.
agreement with the United States
was concluded in
According to TECO's D. Pless, this project was
originally conceived to respond to the Round III
solicitation as part of the Clean Coal Technology
Program. The project was 1 of the 13 selected
from 49 applicants. Notification of award was
received in January 1990. The originally
proposed project was a 120-megawatt air-blown
fixed-bed gasifier supplying a GE 6EA combus
tion turbine/combined cycle powerplant, and in
cluded an in-line zinc ferrite Hot Gas Clean-Up
system. The general objective of this
(HGCU)
project was to demonstrate cost competitive in
tegrated gasification combined cycle with hot
gas clean-up.
Due to difficulties encountered with finalizing the
power sales agreement with the originally in
tended power purchaser, TECO had to search for
other purchasers for the unit's output. It then
became obvious that a more efficient, more reli
able, and more cost-effective arrangement would
be necessary.
To meet these needs, TECO altered the project's
arrangement to include a General Electric 7F(A)
combustion turbine (CT)/combined cycle (CC)
system to significantly increase the power island
efficiency and output. They added a Texaco
oxygen-blown entrained-flow gasifier to increase
the project's reliability due to the Texaco
gasifier's proven track record at Cool Water.
They
also added an air separation unit and
coupled the excess nitrogen to the inlet of the CT
to increase system output, reduce NOx emis
sions and increase overall plant efficiency. In or
4-7
der to enhance the HGCU performance, the sor-
bent will be changed to either zinc titanate or a
patented sorbent from Phillips Petroleum called
Z-Sorb. Finally, to ensure system reliability,
TECO opted to install a conventional 100 percent
cold gas clean-up system in parallel with a
50 percent HGCU system to insure that the IGCC
system would be able to operate regardless of
the status of the HGCU system.
According to TECO's C. Shelnut, the most novel
integration concept in this project is the intended
use of the air separation unit. This system
provides oxygen to the gasifier in the traditional
arrangement, while simultaneously using what is
normally excess or wasted nitrogen to increase
power output and improve cycle efficiency and
also lower NOx formation.
To be more commercially and economically ac
ceptable, a size of 250 megawatts was selected.
The Florida Public Service Commission acknow
ledged that with the DOE partial funding, this unit
would become a least cost power option.
The originally
proposed project called for a
50/50 cost shared arrangement between the par
ticipant and DOE. DOE would provide
$100 million for capital expenses and $20 million
for support during the 2-year demonstration
period. Because the DOE funds were fixed, the
project's support from DOE for the 250-megawatt
unit, on a percentage basis, changed from
50 percent to about 20 percent.
Project Site
The Polk Power site will be built on a Central
Florida inland site in southwestern Polk County,
Florida. The site, about 1 1 miles south of Mul
berry, is a tract previously mined for phosphate
and is basically unreclaimed.
The selected site is about 4,300 acres. About
one-third of it will be used for the generating
facilities. As part of this overall plan, the existing
mine cuts will be modified and used to form an
850 acre cooling reservoir.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
Another one-third of the site will be used for creat
ing
a complete ecosystem. It will include
uplands, wetlands, and a wildlife corridor. This
wHI provide a protected area for native plants and
animals. The final one-third of the site will be
unused, and will be maintained for site access
and will provide a visual buffer.
Cost
The current expected cost for this unit is about
500 million dollars. This results in about
$2,000 per kilowatt for this first-of-its-kind project.
Pless says that TECO's economic justification for
this project has been, in large part, dependent
upon the $120 million (now $130 million due to
design changes and project enhancements) fund
ing from the DOE Clean Coal Technology
Program.
Schedule
The total IGCC project is expected to be put into
service between July and October 1996.
Most of the equipment is scheduled for delivery
in early 1995 which will provide for flexibility in
construction sequencing. Specifically, the major
CT components are scheduled for
March/April 1995 delivery, with the radiant syn
gas cooler expected to arrive at the site in
May 1995.
The Cooperative Agreement requires testing four
different fuels during the first 2 years after com
mercial operation. These coals will be classic
Eastern coals such as Pittsburgh #8, Illinois #6,
Kentucky #9, Elkhom #3, etc. The results of
these tests will provide data for utilities in many
coal producing areas to be able to determine
operating characteristics and economics related
to using IGCC in their areas.
####
AS
FINAL EIS ISSUED FOR PINON PINE
PROJECT
The Final Environmental Impact Statement (FEIS)
for the Pinon Pine Power Project, to be located at
Sierra Pacific Power Company's (SPPC) Tracy
Station, Nevada (Figure 1) was issued in Septem
ber. This clears the way for construction to begin
(nearly 1995.
This project will be a nominal 800-ton per day
(104 megawatt gross Ingeneration)
air-blown,
Tnickee f
River Vv
Watershed I
Boundary
111*''*!!*!''
FIGURE 1
LOCATION OF
TRACY POWER STATION
RENO-SJ3,
' TRUCKEE
MEADOWS
Mount Rose
Wildern
rea
SOURCE: DOE
Steamboat / 0
Cnp^y. Miles
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
tegrated Gasification Combined-Cycle (IGCC)
plant. SPPC has entered into a contract agree
ment with Foster Wheeler USA Corporation for
constructing the project. In addition, The MW Kel
logg Company will be a subcontractor for the
design of a key part of the IGCC system (i.e., the
KRW fluidized-bed gasification process).
Environmental Analysis
The FEIS contains a detailed description of exist
ing
conditions at the proposed site and the sur
rounding area. Potential impacts to aesthetics,
air quality, geology and soils, surface water and
groundwater, land use, socioeconomic
resources and environmental justice, threatened
and endangered species, aquatic and terrestrial
habitats, biodiversity, cultural resources, health
and safety, hazardous and toxic materials/waste
management, pollution prevention, and noise are
analyzed. During the scoping process, specific
key issues were identified, including
the impact
from increasing water withdrawals from the
Truckee River at the Tracy Station site; the im
pact to the Cui-ui, an endangered species of
sucker fish; and the impact to air quality from
coal-fired plant emissions.
Following
the issuance of the Draft EIS to the
public in May 1994, several changes were intro
duced by SPPC. Most of the changes are as
sociated with air emissions from the proposed
project. The primary
change is a decrease in
height of the primary stack from 91 meters to
68.5 meters. The coal storage initial design of
two silos that were 61 meters high was changed
to a revised design of a single domed silo that
would be only 23 meters high. Other changes
include decreasing
the exit temperature of the
exhaust gas streams in the two flues of the
primary stack, modifying the exit velocity of the
two flue gas streams, decreasing particulate emis
sions from the cooling tower, reconfiguring the
sources of particulate emissions in the coal
preparation area, and relocating several of the
proposed ancillary facilities.
Modeling
results indicated that pollutant emission
levels would be in compliance with the National
4-9
Ambient Air Quality Standards and would not
have a significant impact on nonattainment areas
in the Truckee Meadows. Emissions of sulfur
oxides and NOx would be below foliar threshold
values. Both the Class I and Class II Prevention
of Significant Deterioration (PSD) increment
analyses indicate that the proposed project
would not result in significant degradation of air
quality.
Mitigation measures that have been identified as
necessary
for the proposed action include:
vegetative plants on the south bank of the
Truckee River to screen portions of the proposed
facility; use of earth-tone painting of structures;
suppression of fugitive dust emissions during
construction; coordination with the Nevada
Department of Transportation to lessen safety
impacts during fog episodes; preparation of a
geotechnical report to identify mitigation
measures that may be necessary to ensure
proper foundation stability; implementation of a
soil resistivity program for use in the design of
underground features; water quality testing of the
evaporation pond to indicate the need for mitiga
tion; habitat enhancement for Mule deer through
the planting of food sources; protection of un
tested archaeological sites by chain-link fences;
and notification and temporary relocation on a
voluntary basis of people residing in the area
who are potentially affected by
short noise
episodes related to steam blowing during the con
struction phase.
Project Description
SPPC's Pinon Pine Project was one of nine suc
cessful proposals selected by the United States
Department of Energy (DOE) from 33 submitted
in response to the Program Opportunity Notice
for Round IV of the Clean Coal Technology
Program.
The heart of the Pinon Pine Power Project
(Figure 2) will be the KRW fluidized-bed ash ag
glomerating coal gasifier operating in the air
blown mode. Cleanup of the hot gases involves
the use of a calcium-based sulfur sorbent in the
gasifier and an external regenerate desulfurizing
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
v.v
C
SOURCE: DOE
Solid
Waste
(LASH)
Coal&
Limestone
Handling
^
\i
ator
FIGURE 2
PINON PINE PROCESS DIAGRAM
Gasifier
sorbent which removes most of the sulfur from
the produced gas. A ceramic barrier filter
removes all but a trace of particulates. Because
the fuel gas is cleaned at high temperature, ther
mal inefficiencies associated with cold gas
cleanup are avoided. The cleaned coal gas is
burned in a gas turbine which produces about
60 percent of the plant power output. The rest of
the power is produced in a steam-turbine genera
tor operated on steam generated from gas tur
bine exhaust.
The gasifier vessel is expected to be ap
proximately 15 feet in diameter and 74 feet in
length, with a shipping weight of 1 70 tons. Desul
furization will be accomplished by a combination
of limestone fed to the gasifier and treatment of
Steam to HRSG
1
vf
Cyclone
On HotGu f*>
U| 4^Cpola;j_-H Cleanup
Air
Particulate
and Sulfur
Removal
p^ i^ir^e^
__ Siem
Water I Genenlor
Steam
4-10
Steam
Stack
Alternate Fuels:
Natural Gas
Propane
Geo.
Geo.
r
the gas in desulfurization vessels using
based sulfur sorbent such as Phillips'
Z-Sorb III.
43 MW
a zinc-
proprietary
The General Electric 6FA combustion turbine
selected is a scaled model of GE's 7FA machine.
The 6FA with its 2,350F firing temperature and
1,100F exhaust temperature enables SPPC to
use a 950F/950 psia steam cycle design. This
Improves overall plant cycle efficiency sig
nificantly.
Cost and Schedule
The project is currently scheduled to start up late
in 1996, and be in commercial operation by
early
1997. The total project cost is ap-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
proximately $270 million shared equally between
SPPC and DOE, including a 42-month demonstra
tion operation phase.
####
ROSEBUD SYNCOAL CONSIDERS
COMMERCIAL VENTURES
Rosebud Syncoal Process
An update on Rosebud SynCoal Partnership's
SynCoal Demonstration in Montana was given by
R. Sheldon of Rosebud SynCoal Company and
S. Heintz of the United States Department of
Energy Pittsburgh Energy Technology Center, at
the Third Annual Clean Coal Technology Con
ference held in September in Chicago, Illinois.
Rosebud SynCoal Partnership's Advanced Coal
Conversion Process (ACCP) is an advanced ther
mal coal upgrading process coupled with physi
cal cleaning techniques to upgrade high-
moisture, low-rank coals to produce a high-
quality, low-sulfur fuel.
The coal is processed through two vibrating
fluidized-bed reactors where oxygen functional
groups are destroyed, removing chemically
bound water, carboxyl and carbonyl groups, and
volatile sulfur compounds (Figure 1). After ther
mal upgrading, the SynCoal is cleaned using a
deep-bed stratrfier process to effectively separate
the pyrite-rich ash.
The SynCoal process enhances low-rank West
ern coals with moisture contents ranging from
25-55 percent, sulfur contents between 0.5 and
1.5 percent, and heating values between 5,500
and 9,000 BTU per pound. The upgraded stable
coal product has moisture contents as low as
1 percent, sulfur contents as low as 0.3 percent,
and heating values up to 12,000 BTU per pound.
Construction of the 300,000 ton per year
demonstration project adjacent to Western
Energy Company's Rosebud mine near the town
of Colstrip in southeastern Montana was com
4-11
pleted in 1992. The facility has produced at
nearly design capacity since January 1994.
Rosebud SynCoal's demonstration plant is sized
at about one-tenth the projected throughput of a
multiple processing train commercial facility. The
next generation of facilities is expected to consist
of standardized 100-ton per hour process trains.
As operational testing has proceeded, the
product quality issues that have emerged are dus
tiness and stability. The SynCoal product has
met the BTU, moisture and sulfur specifications.
The project team is continuing process testing
and is working toward resolution of the opera
tional and process issues in response to market
requirements.
The ACCP Demonstration Facility is a United
States Department of Energy (DOE) Clean Coal
Technology Program with 50 percent funding
from the DOE and 50 percent from the Rosebud
SynCoal Partnership through the end of the
original $69 million project. DOE and Rosebud
recently
agreed to extend the project until
November 1997 with total funding increasing to
$105.7 million and DOE's contribution increased
to a total of $43,125 million.
The Rosebud SynCoal Partnership is a venture
involving Western SynCoal Company and Scoria
Inc. Western SynCoal is a subsidiary of Western
Energy Company (WECo) which is a subsidiary
of Entech Inc., Montana Power Company's non-
utility group. Scoria Inc. is a subsidiary
Energy Inc., Northern States Power's non-utility
group.
of NRG
The nominal throughput of the demonstration
plant is 1 ,640 tons per day of raw coal, providing
886 tons per day of coarse SynCoal product and
240 tons per day of SynCoal fines (minus
20 mesh). The fines are to be collected and sold,
giving a combined product rate of 1 ,126 tons per
day of high-quality, clean SynCoal product.
The coal conversion is performed in two parallel
processing
trains. Each consists of two 5-feet
wide by 30-feet long vibratory fluidized-
bed/reactors in series, followed by a water spray
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
Re* Cetl In
Flrod
Heater
Exehangar
SOURCE: SHELDON AND HEMTZ
FIGURE 1
ROSEBUD SYNCOAL PROCESS
agrioa**
Dryer 1
ar
Vent
Combustion
Gn
Procaaa Gaa
'
| Cytiona II
3 8
8
Dryer 2
quench section and a 5-feet wide by 25-feet long
vibratory cooler.
In the first-stage dryer/reactors, the coal is
heated using recirculated combustion gases,
removing primarily surface water from the coal.
The coal exits the first-stage dryer/reactors, at a
temperature slightly
above that required to
evaporate water, and is gravity fed into the
second-stage reactors. Here the coal is heated
further using a superheated gas stream, remov
ing
water trapped in the pore structure of the
coal, and promoting the thermal destruction of
the oxygen functional groups, such as hydroxyis,
carbonyts and carboxytate that are normally
prevalent in lower rank coals. The superheated
r
[Cyrt
Cooler
Process Slack
4-12
Briquetter mh
Separator
i k Product
Out
Slurry
Tniek Slurry
Dallvary To Pn
gases used in the second stage are actually
produced from the coal. The make-gas from the
second-stage system is used as an additional
fuel source in the process furnace, incinerating
all the hydrocarbon gases produced in the
process. The particle shrinkage that liberates
ash minerals and imparts a unique cleaning
characteristic to the SynCoal also occurs in the
second stage. As the coal exits the second-
stage reactors, it falls through vertical quench
coolers where process water is sprayed onto the
coal to reduce the temperature. The water
vaporized during this operation is drawn back
into the second-stage exhaust gas. After quench
ing, the SynCoal enters the vibratory coolers
where the SynCoal is contacted by cool inert
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
gas. The SynCoal exits the cooler at less than
150F and is conveyed to the pneumatic cleaning
system.
The SynCoal entering the cleaning system is
screened into four size fractions. These streams
are fed in parallel to four deep-bed stratifiers
(stoners), where a rough specific gravity separa
tion is made using fluidizing air and a vibratory
conveying action. The light (lower specific
gravity) streams from the stoners are sent to the
product conveyer; the heavy streams from all but
the minus 6-mesh stream are sent to gravity
separators. The heavy fraction of the minus
6-mesh stream goes directly to the waste con
veyor. The gravity separators, again using air
and vibration to effect a separation, each split the
coal into light and heavy fractions. The light
stream is considered product; the heavy or waste
stream is sent to a 300-ton storage bin to await
transport to an off-site user or, alternately, back
to a mined-out pit disposal site.
The ACCP changes the chemical composition
and structure of the coal feedstock. The
changes include:
- Increased
- Increased
- Increased
- Increased
- Increased
- Decreased
- Decreased
- Decreased
- Decreased
higher heating value
aromaticity
fixed carbon
carbon to hydrogen ratios
(C + H) to oxygen ratios
moisture content
sulfur content per million BTU
ash content per million BTU
oxygen function groups
Typical product properties are shown in Table 1.
According to Sheldon and Heintz, the SynCoal
self-
product has displayed a tendency toward
heating
that was not expected. The project's
technical and operating team has conducted an
extensive process testing program in order to
determine the cause of the product's lack of
stability. A number of approaches have been par
tially successful; however, to date, the demonstra
4-13
tion product has not met the level of resistance to
spontaneous combustion that was apparent in
the earlier pilot plant work.
A test burn program was initiated in March 1994
at Montana Power's J.E. Corette powerplant
using a 50/50 blend of raw subbituminous coal
and SynCoal. Initial results include significantly
improved boiler cleanliness, efficiency and opera
tions capacity while the SO, emissions
decreased with no noticeable effect on NOx.
With the higher SynCoal blends S02 emissions
decrease by as much as 43 percent. The boiler
efficiency increased from 84.9 to 85.7 percent
with the 50/50 blend.
Commercial Projections
The Rosebud SynCoal partnership intends to
commercialize the process by both preparing
coal in their own plants and by licensing to other
firms. The target markets are primarily U.S.
utilities, the U.S. industrial sector and Pacific Rim
export market. Current projections suggest that
the utility market for this quality coal is ap
60 million tons per year with poten
proximately
tial industrial markets of 38 million tons per year.
The Partnership is currently working
on three
potential semi-commercial projects tentatively
located in Wyoming, North Dakota and Montana.
The Wyoming
mouth design. The North Dakota project is in
project is a stand-alone mine-
tegrated into a mine-mouth powerplant with the
product sales offsite to regional markets. The
Montana project is designed either as an integra
tion into a powerplant and fuel user or an expan
sion of the existing demonstration facility.
In North Dakota, Rosebud, along with partners
Minnkota Power, BNI Coal Ltd., Center SynCoal
Partnership and Transystems Inc., is asking
North Dakota to contribute part of the
$43.2 million cost for that project. The coal
upgrading plant would cost $35 million, the
partners estimate, while the truck-to-rail transloading
system would cost $8.2 million.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
Proximate Analysis
SYNCOAL QUALITY COMPARISONS -
TABLE 1
RAW FEEDSTOCKS VS. PRODUCTS
Rosebud Mine (Montana) Center Mine (North Dakota) Powder River (Wyoming)
Feedstock and Coal Feedstock and Coal Feedstock and Coal
Product Analysis Product Analvsis Product Analvsis
Raw Coal Rosebud Raw Coal Center Raw Coal Powder River
Feedstock SvnCoal Feedstock SvnCoal Feedstock SvnCoal
% Moisture 25.24 2.21 36.17 7.35 28.11 4.51
% Volatile Matter 29.16 36.98 27.13 39.39 31.78 41.4
% Fixed Carbon 36.69 51.19 30.16 46.74 35.25 47.48
%Ash 8.92 9.2 6.54 6.52 4.86 6.61
% Sulfur 0.74 0.56 1.07 0.77 0.34 0.45
BTU/lb 8,634 11,785 7,064 10,799 8,727 11,805
lb S02/MMBTU 1.71 0.95 3.03 1.43 0.78 0.76
IbAsh/MMBTU 10.3 7.8 9.3 6.0 5.6 5.6
% Equilibrium Moisture 24.9 14.7 34.98 20.12 28.38 14.04
Ultimate Analysis
% Carbon 50.54 68.16 42.25 64.15 49.7 66.96
% Hydrogen 3.33 4.7 2.62 4.11 3.69 4.93
% Oxygen 10.47 13.52 10.76 16.22 12.52 15.39
% Nitrogen 0.76 1.23 0.59 0.88 0.78 1.15
C:H Ratio 15.18 14.50 16.13 15.61 13.47 13.58
(C+H):0 Ratio 5.15 5.39 4.17 4.21 4.26 4.67
Carboxyl Concentration
Analysis
%COOH 0.85 0.26 0.53 0.17 1.02 0.15
Classification Subbit. High Vol C Lignite High Vol C Subbit. High Vol C
ASTM C Bituminous A Bituminous C Bituminous
The upgrading
plant would be adjacent to the
BNI Center Mine and the Milton R. Young
powerplant in Center, North Dakota.
For potential users of the technology, Rosebud
SynCoal Partnership is offering to test low-rank
coal at the demonstration plant in Montana free
4-14
of charge. The partnership also will provide a
written report and bulk samples of the cleaned
coal. A sample of at least 1,000 tons of coal
must be provided.
####
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
DGC CONTINUES BYPRODUCTS
DEVELOPMENT AT GREAT PLAINS PLANT
The biggest news of the past year for Dakota
Gasification Company (DGC) came in April. That
was when DGC's settlements with four pipeline
companies, as well as the United States Depart
ment of Energy (DOE), were announced (see
Pace Synthetic Fuels Report. June 1994,
page 4-8 for details).
However, the settlements must receive the ap
proval of the Federal Energy Regulatory Commis
sion (FERC). The Public Service Commissions of
the States of Michigan, New York and Wisconsin
have intervened in these proceedings attempting
to convince FERC that the settlements are not in
the best interests of their
states'
Flue Gas Desulfurization Project
consumers.
A unique flue gas desulfurization system that
produces a valuable fertilizer rather than a waste
product is being installed at the synfuels plant.
The scrubber will remove sulfur dioxide from flue
gas in the plant's main stack and produce a pure,
granulated ammonium sulfate fertilizer. It will be
the first commercial application of this technol
ogy.
DGC received approval from the North Dakota
State Department of Health to use anhydrous
ammonia instead of the lime or limestone reagent
that is usually used in such systems.
The technology belongs to General Electric En
vironmental Systems Inc. DGC will receive a por
tion of any worldwide sales of additional systems
over the next 15 years.
DGC expects to have the system on line by
late 1996.
A conventional limestone system costs less ini
tially, but would have operating costs of about
$10 million a year. By purchasing a scrubber
using
anhydrous ammonia, the sale of am
monium sulfate should offset the operating cost
4-15
of the scrubber. DGC will produce about
200,000 tons of fertilizer annually.
DGC has hired a marketing firm, H.J. Baker &
Brothers of Stamford, Connecticut, to handle the
byproduct sales. Plans are to market the am
monium sulfate in the Pacific Northwest, the Mid
west and Great Lakes region, and the Canadian
Provinces of Manitoba, Saskatchewan and On
tario.
A new railroad spur was prepared to handle ship
ments of ammonium sulfate from the new scrub
ber system. A 100-foot by 200-foot storage
dome for the fertilizer also was constructed.
Upgrade for Phenol Facility
DGC approved a project last summer to upgrade
the facilities that produce phenol and cresylic
acids.
The odor related to the neutral oil content had
made marketing phenol difficult.
Work on finding the best technological process
to reduce neutral oils led to focusing on extrac
tive distillation. DGC's process is being used by
one of its customers to purify DGC's cresylic
acid. The $4.6 million project involves adding a
new recovery column for the process.
Naphthol Production
DGC continues to work on the potential produc
tion of naphthol from the tar oil stream. Initial
testing
too complex.
produced naphthol materials that were
Naphthols are used as chemical feedstock for
dyes and pigments, insecticides and phar
maceuticals.
Additional tests were scheduled to be completed
by 1994 year-end. If the second round of testing
is successful, DGC could undertake a pilot-scale,
then a commercial-scale test.
####
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
CORPORATIONS
SASOL MADE MAJOR MOVES INTO
CHEMICALS IN 1994
South Africa's Sasol made major advances into
world chemical markets in 1994 with chemicals
from coal. Expansions of a number of units have
taken place at the company's facilities in the last
few years, with the major focus on chemicals
rather than fuels as the final products. In 1992, a
significant rejuvenation of Sasol One provided a
substantial expansion of higher value wax, paraf
fin and ammonia production in place of synthetic
gasoline, which is no longer manufactured at that
site.
Sasol One began the production of liquid fuels
and chemicals from coal in 1955, and the Sasol
Two and Three coal liquefaction plants were
brought into operation in 1976 and 1979, respec
Coal.
mina
FIGURE 1
tively, after the oil crises of that decade. The
plants are supplied by the company's own col
lieries at Secunda and Sasolburg, which between
them produce 42 million tons per year.
Sasol manufactures and markets more than
130 non-fuel products (see Figure 1).
Sasol has been receiving
based on prevailing internal crude prices, calcu
some tariff protection
lated to give Sasol a 10 percent return on capital.
Originally, this meant that Sasol received a crude
equivalent price of $23 per barrel for synthetic
crude oil.
Oil companies have been required to buy all of
Sasol's output, in return for which Sasol agreed
not to sell its synfuels on the open market.
With a healthy cash flow, Sasol has talked of its
plans to invest over $550 million in new chemi
cals projects. These "commercially sensitive
SASOL PRODUCTION OF CHEMICAL PRODUCTS
Phenosotvan
7.\ unit
SOURCE: CHEMICAL * FMG1EEFMNG NEWS
4-16
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
projects"
will tend toward high-value chemicals
and specialties such as the hexene, pentene, cer
tain waxes and phenolics already being
produced.
Joint ventures have been used by the firm to
tackle petrochemical overcapacity and to im
prove international competitiveness. The most
significant venture is with AECI (called Polifin)
which combines key monomers and plastics inter-
Excluding its venture with AECI, and its ex
plosives, fertilizer and motor alcohols
businesses, Sasol exports 40 percent by value of
70 percent by volume of its petrochemicals
production.
At home, competition will increase with the
government's agreement to abide by GATT and
phase down production levels over the next
5 years. Domestic tariff rates on chemicals are
expected to drop from 10-25 percent to
10-15 percent.
The successes of the chemical side of the group
are often clouded by the historically rigid govern
ment control over the petroleum industry and the
complex financial formulae used to determine
equity among
country.
the petroleum multinationals in the
The government currently owns only around
12 percent of Sasol stock.
Sasol's current primary
products include diesel,
gasoline, aviation fuel, jet fuel, liquefied
petroleum gas, automotive lubricants and
bitumen. Chemical products consist of ethylene,
propylene, solvents, phenols, noble gases
(argon, krypton and xenon), ammonia, fertilizers,
explosives, anode coke, alpha-olefins,
acrylonitrile (from early 1995), acrylic fibers,
speciality hard waxes, paraffin waxes and normal
paraffins.
Sasol processes and produces synfuels to
supply about 35 percent of South Africa's liquid
fuel requirements.
4-17
With the 1994 commissioning
of its
100,000 tonne per year alpha-olefins facility, the
company has now become the world's largest
single supplier of hexene and pentene.
New facilities at Sasolburg to produce higher
phenols make Sasol a leading supplier in Europe
of o-cresols, and the supply of m-cresol, p-cresol
and xylenols is rising rapidly.
Last winter, Sasol Chemical Industries'
phenolics
division signed a contract with Sumitomo Cor
poration to distribute and market meta- and para-
cresols and xylenol blends to Japan and other
East Asian countries. Sasol is the world's largest
producer of cresols, recovering them from
depitched tar acids obtained in its coal gasifica
tion process. The company
85 percent of its phenolic products.
exports about
Also in 1994, Sasol's fertilizers division entered
the liquid-fertilizers market by acquiring a
50 percent stake in Delmas Fertilizers, an inde
pendent producer based at Delmas, in the East
ern Transvaal Province. The agreement includes
a new liquid-fertilizers plant at Secunda, with
production expected to start September 1994.
According to Sasol, all raw materials, particularly
liquid ammonium nitrate, are available at its coal
gasification complexes in Secunda and Sasol
burg.
Sasol's first shipments of coal-based alpha-
olefins arrived in Europe in October. Sasol's
declared plan is to export 50,000 tonnes per year
each of hexene-1 and pentene-1 to the world
market, which is 90 percent of the new plant's
capacity.
Sasol's biggest potential chemical outlet is in
alpha-olefins, said to be 1.2 million tons of poten
tial output, in comparison to the 100,000 tons
now recovered. Sasol technology to recover
alpha-olefins up to C_ is fully developed, with
purities exceeding international standards.
However, while progress has been made on the
more lucrative Ce to C cuts, the purity is not up
to world levels yet.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
Unlike traditional ethylene oligomerization, the
Fischer Tropsch process also yields odd carbon
number alpha-olefins, such as C_, C7 and C9 for
which there is said to be "considerable market
interest."
In addition to these areas under active develop
ment, many other lines of chemistry are being
explored, including propylene to acrylic acid and
acryiates, acetic acid to acetates, phenol and
acetone to bisphenol-A, acetone to methyl
methacrylate, olefins and syngas to oxo alcohols,
and alpha-olefins to polyalpha-olefins.
Sasol plans to recover other olefins, including
decene, which is in strong demand for producing
lubricants. A project is under way that will use
C10 and to make about C 90,000 tonnes per
year of polyalpha-olefins (PAO). The total world
demand for PAO is about 200,000 tonnes per
year.
A world-scale methanol plant is also on Sasol's
shopping
sumes only
list. The local South Africa market con
50,000-60,000 tonnes of methanol
per year; the rest would be exported. Sasol is al
ready converting an ammonia plant at Sasolburg
to produce 20,000 tonnes per year of methanol.
Methyl tert-butyl ether (MTBE) is also being
looked at. The company says that by the end of
the decade chemicals will contribute 50 percent
of the company's operating profits, compared
with about 17 percent at present.
Sasol supplies virtually all feedstocks for the
country's petrochemical industry. By the end of
the decade, however, South Africa will need
another ethylene plant. But the extra capacity
will be used by Polifin in its vinyl chloride
monomer plant, which is being converted to
ethylene feedstock. Sasol produces
320,000 tonnes per year of ethylene and could
increase that to a maximum of 420,000 tonnes
per year.
In December, Sasol and the German company
Schumann agreed to merge their wax and wax-
related activities into a joint venture that would be
4-18
the biggest worldwide supplier in the sector with
the widest range of applications.
Sasol's $75 million per year waxes business con
sists of high-value, low-cost Fischer Tropsch
paraffin waxes.
Family-owned Schumann is one of the top three
manufacturers of crude oil-derived paraffin
waxes, with more than 300,000 tonnes per year
of capacity at two refineries in Hamburg.
####
IGT NOTES PROGRESS IN COAL
CONVERSION TECHNOLOGIES
The 1994 Annual Report for the Institute of Gas
Technology (IGT) reviews progress in several
coal conversion areas.
After more than 50 years on the campus of the Il
linois Institute of Technology in Chicago, in 1994
IGT moved to facilities in Des Plaines, Illinois.
According to IGT chairman R. Cash, this move
will help IGT attain a major part of its mission and
vision statements and allow IGT to adapt to a
rapidly changing world economy. The next
25 years will see a dramatic global shift in
economic strength as countries in the developing
world and the former Soviet bloc introduce
market-oriented reforms and open up their
economies to trade and investment. While the
newly rich countries have many resources, includ
ing a large labor base, they will be unable to main
tain long-term growth or provide their citizens
with a desirable standard of living without the ap
plication of advanced technologies. The need for
technologies that improve the efficiency of
energy use, produce new energy sources, and
clean and protect the environment will become
as critical in the developing world as it already
has in the industrialized countries.
With a worldwide reputation for its international
consulting and educational programs, IGT is now
actively and successfully involved in marketing its
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
products abroad and developing advanced
energy and environmental technologies for the
21st century marketplace.
Molten Carbonate Fuel Cell (MCFC)
IGT's molten carbonate fuel cell technology took
another step toward commercialization. IGT's
majority-owned subsidiary M-C Power Corpora
tion assembled a 250-kilowatt stack and dedi
cated the first integrated demonstration facility in
December 1994, at Unocal's Fred L Hartley
Research Center in Brea, California. A series of
tests will allow industry representatives to ob
serve and understand the effectiveness and ef
ficiency of environmentally friendly MCFC dis
tributed power generation. The Unocal plant is
one of several planned that will lead to the com
mercial offering of fully integrated, skid-mounted
MW-class MCFC powerplants in 1998.
Bioremediation of MGP Sites
The enhanced bioremediation of Manufactured
Gas Plant (MGP) sites is an area where IGT
developed an integrated chemical/biological
process called MGP-REM that can reduce or
ganic contaminants in soils and sediments. The
process, which can be used in either the
landfarming, slurry-phase, or in situ mode,
degrades contaminants using environmentally
acceptable chemicals and nutrients,
biodegradable surfactants, and native and
benign soil micro-organisms.
MILDGAS Process
IGT has been investigating the production of
high-value products from coal by mild gasifica
tion since 1987. In the MILDGAS process, coal is
gasified at the relatively low-severity conditions of
1,100-1,300F temperature and 25 psi pressure
to yield a slate of solid, liquid, and gaseous
products.
The char produced by MILDGAS can be further
processed into formcoke briquettes, which can
be used as a cost-effective substitute for tradi
tional coke in blast furnaces and foundries.
4-19
The liquid products of MILDGAS should be
marketable with minimal processing to com
panies that manufacture such materials as roof
ing and road binders, electrode binder pitch and
coke, and various chemicals (e.g., BTX, phenols,
cresois, xylenols, naphthalene and indene).
A team headed by Kerr-McGee Coal Corporation
was the successful bidder on a United States
Department of Energy request for proposals to
design, construct, and operate a 24-ton per day
MILDGAS Process Development Unit (PDU).
Other team members include IGT, originator of
the MILDGAS technology; Southern Illinois
University at Carbondale, which operates the Il
linois Coal Development Park at Craterville, Il
linois, where the PDU will be built; and Bechtel
Corporation, which will design and construct the
PDU.
Ground was broken for the PDU in April 1994,
and construction and unit shakedown are
scheduled for completion by June 1995. At that
time, researchers will begin a 1-year testing
program to obtain scaleup and product-
evaluation data.
U-GAS Process
IGT developed the U-GAS gasification process to
meet the needs of utilities and other industries for
a low- or medium-BTU fuel gas. The process
provides a simple and efficient means of produc
ing
such gas in a single-stage fluidized-bed
gasifier (Figure 1). U-GAS can use a wide variety
of feedstocks, including all ranks of coal.
The U-GAS process is based on work that began
in the 1970s when IGT constructed and operated
a fuel-gas pilot plant.
The process operates on coal with either air and
steam, enriched air and steam, or oxygen and
steam to produce either low- or medium-BTU
gas. The solid residue is formed into ash ag
glomerates which are continually removed.
Fines leaving the gasifier are recycled and
gasified, which, together with ash agglomeration,
enhances coal utilization and process efficiency.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
SOURCE: IGT
IGT is actively participating
FIGURE 1
SCHEMATIC OF U-GAS PROCESS
in several programs
with companies in the United States and abroad
to demonstrate and commercialize the U-GAS
process. In 1992, IGT signed an agreement with
a company in China to design and build the first
commercial U-GAS plant in China. The 800-ton
per day
plant will produce 120 million standard
cubic feet of low-BTU fuel gas daily. This gas will
be used to generate heat for coke ovens, thereby
freeing the coke oven gas for use as town gas.
That plant is nearing completion in Shanghai,
People's Republic of China, and is about to un
dergo shakedown. The facility involves eight
2.3-
meter diameter U-GAS gasifiers.
Licensing Agreements
In 1994, IGT entered a joint venture with the Shan
ghai Coking and Chemical Plant General, of Shan
ghai Pacific Chemical Group Company, to own
and operate Shanghai Zhihai Gasification Tech
nology Development Ltd. (SGT). The company
will make advanced technologies in gasification,
u ^,
4-20
SULn/M
RKSVEMT
3^ OITCCN
POWW OCMCHATION
INOU5TRIAL FUQ. CAS
coal-gas purification, and the enhancement of
fuel-gas heating value. The agreement makes
SGT the sole licensee of IGT's U-GAS coal
gasification technology in China. The company
will provide customers in China and other
regions of Asia with technical consultation, tech
nology transfer, and process design services.
The Finnish company Enviropower Inc. is also a
licensee of U-GAS. The company is now in
volved in negotiations for use of the process for
the Eurotherme Project in Denmark.
####
GOVERNMENT
DOE ISSUES REQUEST FOR EXPRESSIONS
OF INTEREST IN DISSEMINATING CCTs
The United States Department of Energy (DOE),
Office of Fossil Energy (FE), issued in November
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
a request for Expressions of Interest in Commer
cial Clean Coal Technology Projects in Foreign
Countries in accordance with the guidance
provided by the Congress. DOE is directed to
make the international dissemination of Clean
Coal Technologies (CCTs) an integral part of its
policy
to reduce greenhouse gas emissions in
developing countries. Accordingly, DOE is re
quired to solicit Statements of Interest in commer
cial projects employing CCTs in countries
projected to have significant growth in
greenhouse gas emissions.
Additionally, DOE must submit to the Congress,
by April 15, 1995, a report that analyzes the infor
mation contained in the Statements of Interest,
and that identifies the extent to which various
types of federal incentives would accelerate the
commercial availability of these technologies in
an international context.
The deadline for receipt of submittals was
January 13, 1995.
Potential respondents were advised that DOE
has no monies or wherewithal to fund, or to other
wise provide any incentive in support of, any of
the projects that may be proposed; does not an
ticipate endorsing or supporting any proposals
pursuant to this Announcement; and cannot reim
burse submitters for any expenses they may in
cur in responding to this Announcement. This
solicitation is being conducted, as requested by
the Congressional guidance, so that Congress
may
have the information it requires in order to
consider the technical, economic, and environ
mental aspects of various incentives to support
international CCTs, and their merits for potential
future support.
The Future of DOE's CCT Program
With the announcement of the results of the fifth
competitive CCT solicitation in May 1993, the
goals of the CCT Program as originally envi
4-21
sioned by the U.S. and Canadian "Special En
voys on Acid Rain"
have been largely met, as in
novative pollution control technologies are begin
ning to move into the marketplace. By the
completion of the fifth "round,"
the Program will
have laid the basis for a new generation of ad
vanced industrial and electric power tech
nologies. In the course of evaluating future
prospects for DOE's CCT Program, in its
May 1994 report to the Congress entitled, "CCT
Program:
Mission,"
Completing the DOE found
that "an expansion of the current demonstration
program in the form of an additional round of
completion is not
recommended."
However, the
report conjectured a likelihood that, by virtue of
possible termination of one or two CCT projects
prior to completion, "$150 million would be avail
able both to fund new initiatives and provide
program direction in the out
years."
Thus, DOE
recommended "that Congress initially establish
Program."
an International Technology Transfer
In its Fiscal Year 1995 Congressional Budget Re
quest for the CCT Program, DOE proposed a
new initiative for CCTs that would substantially
reduce environmental pollutants, including
greenhouse gases, in developing countries or
countries with economies in transition. The ob
jective of the program is to increase trade ex
ports and U.S. jobs by increasing the market
share for U.S. energy and environmental technol
ogy services in developing countries and to im
prove environmental performance of existing and
new power generating facilities in these
countries. The Program would finance a portion
of the differential cost (when compared to con
ventional technology currently
used in the host
country) of using high efficiency and environmen
tally sound U.S. technology
in two "showcase"
projects-one in China, another in Eastern
Europe-for the generation of power from new
facilities or the improvement of performance of
existing facilities.
####
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
ENERGY POLICY & FORECASTS
CHINA SEEN AS MAJOR MARKET FOR
CLEAN COAL TECHNOLOGIES
IEA Coal Research has published "Chinese Coal
Prospects to 2010."
IEA notes that over the past
16 years Chinese coal production has more than
doubled-fueling
the country's spectacular
economic growth. China is now the world's lead
ing coal producer, and is dependent on coal for
three-quarters of its total energy requirements.
The report analyzes coal prospects in China over
the period to 2010.
The study begins by assessing the likely impact
of trends in population and economic growth,
and of changes in fuel prices on energy and
electricity
needs. The potential for fuels other
than coal to meet these needs is analyzed, and a
projection of future coal demand established.
The report goes on to assess whether the
projected coal demand can be met.
TABLE 1
Changes in the structure, pricing
and cost of
Chinese coal production are analyzed. So too
are infrastructure! constraints on coal transport
and utilization. The potential for coal imports and
exports, and the environmental implications of
likely developments in coal production and use,
are also covered. The report concludes that the
projected coal demand could In theory be met.
However, a significant part of the demand may
need to be met by imports. Moreover, meeting
the projected demand would require a for
midable level of annual capital investment in coal
production, transportation and utilization
facilities-approaching 10 percent of the
country's gross national product in 1993. This
may prove very
difficult to achieve.
The author's projection of future Chinese energy
demand by sector is presented in Table 1 . This is
based on a simple model of the Chinese
economy. The key assumptions are overall GNP
growth of 8.5 percent per year and substantially
increased real energy prices.
PROJECTED CHINESE ENERGY DEMAND BY SECTOR
%/Yr. 1990-2010
(Author's Estimate)
Sectoral Energy Million Tonnes Coal Eauivalent
Growth Rate Growth Rate 1390 2000 2010
Agriculture 5.0 3.1 48.5 65.8 89.3
Industry 9.2 3.3 675.8 929.4 1,278.1
Construction 9.0 4.5 12.0 18.8 29.2
Transport 12.0 6.0 45.4 81.3 145.6
Commerce, etc. 10.0 12.0 17.0 52.8 163.9
Residential 6.8 158.0 305.0 588.9
Other 5.0 30.2 49.2 80.1
Total 8.5 4.3 987.0 1,502.3 2,375.1
4-22
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
Electricity Demand
It Is a well established characteristic of rapidly
developing economies that much of the growth
in energy requirements takes the form of
electricity. Power consumption in China in
creased more than 3-fold between 1978 and
1993, reaching 815 terawatt-hours (tWh) in the lat
ter year.
Rapid growth in electricity demand is expected to
continue. Projected electricity demand of just
over 1,400 tWh in 2000 is lower than some recent
Chinese estimates. For instance the Ministry of
Electric Power has projected potential demand in
2000 at 1,540-1,580 tWh, although actual genera
tion in that year is projected at only
1,400-1,440 tWh.
China's ability to satisfy the projected growth in
electricity demand will depend on the evolving
structure of electricity supply and the rate of
power station construction. Responsibility for the
sector at national level lies with the Min
electricity
istry of Electric Power, which was established in
April 1993.
It is officially envisaged that a quarter of the capi
tal will come from overseas sources, compared
with a tenth in recent years.
A large part of the capacity will have to be based
on imported technology. Part of the capacity will
consist of advanced generating technology such
as commercial-scale integrated gasification com
bined cycle plants.
Environmental Implications
On a relatively conservative estimate Chinese
C02 emissions in 2010 will rise to almost 5 giga
tonnes per year. The country will then be respon
sible for around 16 percent of global emis C02
sions. The increase in annual Chinese C02 emis
sions over the period will be little lower than that
from all of the OECD countries combined.
There are substantial environmental problems
associated with coal being used at relatively low
4-23
in over 400,000 industrial boilers,
efficiency
140,000 industrial kilns and innumerable domes
tic stoves.
China unveiled a plan to harmonize economic
growth with environmental protection (see Sinor
Synthetic Fuels Report. October 1994, page 56).
The plan, known as Agenda 21, encompasses a
first group of 63 projects within 9 priority areas,
including many
related to coal production and
use. Implementation will cost around
US$3.8 billion, of which it is hoped that two-fifths
will come from abroad. While coal prices
remained artifically
low and subsidies were in
place, the incentive to utilize energy
more effi
ciently and cleanly was low. As these conditions
change, and as the country's environmental
regulations are tightened, the scope for clean
coal technologies being
greater.
adopted will be much
This will remain the case even if the projected
rate of increase in coal and energy supply, and
thus overall economic growth, have to be scaled
down because of capital investment constraints.
Those constraints would, however, suggest that
a substantial part of the cost of environmental
measures may have to be met by outside bodies,
given the competition for capital resources within
China.
####
IEA SURVEY REVEALS INDUSTRY CAUTION
ON CLEAN COAL TECHNOLOGIES
The International Energy Agency (IEA) published
in November, a survey conducted by its Coal In
dustry Advisory Board (CIAB)
on the status of
combined cycle Clean Coal Technologies (CCT),
the first in a series of three on emerging clean
coal technologies. The Board solicited views on
their applicability and future prospects from
power utilities, manufacturers and others in the
coal business.
The survey, entitled "Industry Attitudes to Com
bined Cycle Clean Coal Technologies,"
indicates
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
utilities are prepared to install CCT only if the re
lated costs are competitive, particularly with
natural gas, and if the technological advantages
have been demonstrated.
All respondents to the CIAB questionnaire
believed that coal was an important long-term ele
ment of a balanced, secure, fuel supply portfolio
for power generation. The use of coal for power
generation was considered essential to the con
tinued economic growth of many countries.
There is considerable power utility interest in ad
vanced CCTs which potentially provide a sig
nificant commercial opportunity. However, a key
concern was the high capital cost of CCT-as
defined for the purposes of this report. CCT was
currently
seen as too expensive and hence a
major barrier to its commercial application.
Several respondents emphasized the substantial
environmental benefits that can be achieved by
the wider application of currently available state-
of-the-art pulverized coal generating tech
nologies combined with flue gas desulfurization,
and low NOx burner technology.
Most power utilities indicated that they will utilize
CCT when the technologies are adequately
demonstrated, the economics are attractive and
the environmental performance needs have been
proved to be needed. But, because these tech
nologies are currently too expensive, caution is
needed in raising
commercial realities.
expectations in advance of
In this regard, several power utilities wish to see
substantial operating experience (several years)
with CCTs from a number of commercial
demonstration plants before being satisfied on
commercial aspects, in particular, their long-term
performance. Others would accept a much
shorter probationary period. It is clear however
that, at the moment, many utilities are concerned
by the lack of a proven track record of truly
commercial-scale operation from which the
operational reliability
could be established.
and overall performance
4-24
Barriers to the commercial deployment of CCT
were regarded as being a function of the per
ceived risk-which would be minimized by the
demonstration plants under construction in
various countries. Figure 1 shows the develop
ment status of IGCC. Most power utilities saw
the Buggenum plant in The Netherlands as a cru
cial test of IGCC, particularly
with respect to
reliability, availability and maintenance aspects.
Some utilities believed that the global wanning
Issue damages the prospects for CCT. While
higher efficiency is the most immediately avail
able option for controlling emissions of C02 from
coal-fired generation-paradoxically, the global
warming discussion hinders the introduction of
higher efficiency, environmentally friendly CCTs
as long as sufficient natural gas is available.
It was suggested that all new technology of sig
nificance requires considerable government sup
port in its early formative years. Examples in
clude nuclear power, the space and aircraft in
dustry, electronics and communications. So far,
most of the development of CCTs had been un
dertaken by private industry. It was felt, by the
majority, the governments could be doing more
to hasten the commercial introduction of CCTs.
Encouragement and assistance with commercial
demonstration projects, "fast
track"
regulatory
conditions and some form of risk sharing were
areas where governments could play an impor
tant future role. A minority of respondents were
opposed to government involvement.
It was considered that manufacturers had
marketed their products effectively but that it was
too early for aggressive marketing of products
still considered to be in their infancy.
In noting the negative image of coal, particularly
with the general public, many respondents felt
that considerable effort was now required to rec
tify this by all participants in the coal chain. In
particular, it was believed that the public and
governments should be made aware not only of
the considerable potential of new technologies
capable of improving the environmental perfor-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
FIGURE 1
STATUS OF ADVANCED COAL GASIFICATION TECHNOLOGY PROJECTS
Electrical Output MW
6OO-1
500-
400-
300-
200-
100-
1980
SOURCE: IEA
Westfield rx
(BG/Lurgi)
^
Plaquemine (Dow)
Cool | Pennsylvania (KRW)
Water0 \ 0Berrenrath 0 0 Virginia (U Gas)
(Texaco) 0 (HTW)
(^^Deer Park
Furs^enhausen (Prenflo) 0 (Shell) 0Nakoso(NEDO)
1985
mance of coal combustion, but also of the practi
cal issues impeding its early implementation.
This was seen as an important element in promot
ing CCT.
Overall, based on the responses to the question
naire, it was concluded that advanced CCTs
such as IGCC show considerable potential but
that further commercial demonstration and
development are essential. Power utilities clearly
see the potential benefits of enhanced environ
mental and efficiency performance as advances
over existing technology, however they are not
prepared to pay extra for it, and are reluctant,
indeed in most cases unwilling, to take the full
commercial risks of early deployment.
####
Puertollano (Prenflo)
o
O
Borssele
Kobra (H
PSI
0 (Dow) Tampa (Texaco)
{-J
Buggenum (Shell)
o
w O Delaware (Texaco)
Pilot Commercial Commercial
Rant under planned
~
r
1990 1995
Year of Startup
4-25
construction
0 o 0
; ) Gasification Technology Developer
2000 2005
TECHNOLOGY
CO-GASIFICATION OF WASTES AND COAL
ADDRESSED BY EC RESEARCH
The European Commission (EC)
established a
short duration (1993/1994) multipartner col
laborative program to evaluate the use of
biomass, sewage sludge and other wastes as
gasification co-feedstocks with coal. The
program was outlined by A. Minchener of CRE
Ltd. at the 13th EPRI Conference on
Group
Gasification Power Plants, held in San Francisco
in October.
Minchener states that, within the European union,
there is a desire to ensure that coal utilization can
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
be maintained on a sustainable basis and to Im
prove the eco-acceptabllity of coal-fired power
production. In part this will be achieved through
improvements to cycle efficiency, as this con
tributes to both the environmental and security-
of-supply constraints. A complementary solution
is to replace some coal by fuels which reduce
C02
phere.
and other pollutants released into the atmos
An example of this approach is the initiative that
has been established by the European Commis
sion within the APAS Program. A short duration
multipartner collaborative program has been set
up, to determine and evaluate the impact on
gasification processes of utilizing biomass,
sewage sludge and other wastes as co-
feedstocks with coal. The intention is to provide
a link between the application of regenerative
energy sources and the utilization of coal, so of
fering improvements in the economical use of fos
sil fuels with a reduction in environmental impact
and the utilization of associated waste materials.
The co-gasification applied research and develop
ment project was undertaken by industry, in
dustrial research organizations and appropriate
universities. CRE Group Ltd., is the overall coor
dinator for the project.
Several types of gasification technology have
been evaluated, namely fluidized-bed, moving-
bed and entrained-flow. In terms of capacity, the
test equipment ranges from small laboratory
scale rigs to a large scale (150 megawatt) unit.
The use of sewage sludge in combination with
both brown and hard coals is being examined by
Rheinbraun and British Coal Corporation respec
tively. Trials have been undertaken by
Rheinbraun on a process demonstration unit
(PDU) at the Technical University of Aachen and
on the High Temperature Winkler demonstration
plant. Apart from sewage sludge, other waste
materials such as loaded brown coal cokes, have
been processed at Rheinbraun. At British Coal,
preliminary
test work with hard coal and pei-
letized sludge in an atmospheric fluidized-bed
gasifier rig has been followed by more extensive
4-26
trials in a pressurized unit. This has a thermal in
put of 2 megawatts and comprises a spouted
bed gasifier, a cyclone, hot gas filtration unit and
fuel gas combustor.
The use of biomass-derived fuel sources such as
straw, wood and miscanthus, and the impact of
the different feedstocks with coal on gasifier per
formance and operability are being investigated
several partners. The Technical Research
by
Center of Finland (VTT) has carried out tests on
their pressurized fluidized-bed gasifier, using
Polish coal and Finnish pine sawdust and various
woody biofuels. They have also undertaken
some preliminary trials for Elkraft using Danish
wheat straw. Elkraft has also subcontracted test
work on the entrained flow gasifier at Noell-DBI.
Their studies have shown that pulverized straw
can be gasified in an entrained-flow gasifier,
either alone or in mixtures with coal, to give a
high carbon conversion. The gas, after purifica
tion, can be fired in a gas turbine. In contrast,
gasification of straw alone in a fluidized-bed
gasifier is extremely
difficult due to ash sintering.
Co-gasification of straw and coal appears to be a
promising possibility in the immediate future.
A program to examine the feasibility of using
fluidized-bed gasification technology to utilize
low grade Spanish coal/wastes and biomass
blends, has been established by CIEMAT in con
junction with Union Fenosa, CENET, Lurgi and
TPS. Test work at the University of Cataluna will
be followed by pilot plant studies at Lurgi and
TPS, and modeling activities. Preliminary results
from the Lurgi circulating fluidized-bed gasifier tri
als suggest that the addition of high volatile
biomass enhances the gasification of low reac
tivity coal processing wastes.
Fuel Gas Contaminants
A key issue for co-gasification is the release and
control of fuel gas contaminants such as tars, sul
fur and nitrogen species, halldes and alkali met
als. At VTT the emphasis of the work was on the
formation of different gas impurities in the
gasification of wood, coal and straw. Their work
showed that the gasification and hot gas clean-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
ing
Combined Cycle (IGCC)
steps of the simplified Integrated Gasification
process were techni
cally feasible when gasifying both wood and coal
alone, and in wood and coal co-gasification. The
total amount of tars in sawdust gasification was
two orders of magnitude higher than in coal
gasification (Figure 1). During wood gasification,
the tars represent a significant part of the gas
heating
value and total carbon conversion.
However, the tar concentrations were reduced at
the co-gasification set point, an approximate
50/50 weight percent mixture of wood and coal.
The formation of the most harmful high molecular
weight polyaromatic compounds was almost neg
ligible at the co-gasification set point.
FIGURE 1
Linked to this is the work of The Netherlands
Energy Research Foundation (ECN) who have
examined the use of pelletized wood waste
and/or straw as a co-feedstock in a moving bed
gasifier.
In parallel to the apparatus based programs,
there are several complementary research
studies to improve the understanding of the fun
damentals of the processes.
Techno-Economic Assessment Studies
In addition to the experimental studies, a key
component of this multipartner program is the
HEAVY TAR CONCENTRATIONS IN DIFFERENT GASIFICATION CONDITIONS
c
e
S
o
2,000
1,500
H 1,000
H
as
w
Z 500
o
u
0
SOURCE: MINCHENER
;.;.
,U\,
(SD = Pine Sawdust, PC = Bituminous Coal)
SD 100%
PC 0%
970C
SD 100%
PC 0%
1010eC
c
SD75%
PC 25%
9806C STRAW
SD58%
PC 42%
960C
SD 0%
PC 100%
950C
100%
880"C
=. \y
4-27
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
associated techno-economic studies. British
Coal has undertaken an extensive study compar
ing
several IGCC and partial gasification
combined-cycle systems based on a number of
gasification technologies and utilizing various
biomass/sewage sludge/coal co-firing ratios.
Future Research Prospects
The European Commission has drafted the basis
for the Fourth Framework Program. In effect, this
is the next 5-year plan covering a wide range of
issues including coal utilization research, develop
ment and demonstration. This program, which is
likely to commence in 1996, aims to build on the
ongoing initiatives. Thus there will be more op
portunities to study
co-utilization of coal with
either biomass or waste. In particular, there will
be an examination of the use of advanced coal
technologies for enhanced disposal of chemical
wastes and associated toxic compounds.
####
FOSSIL RESIN IS A POTENTIAL
VALUE-ADDED PRODUCT FROM WESTERN
U.S. COALS
The University of Utah has established a
Coal/Fossil Resin Surface Chemistry Laboratory
to study the fossil resin (resinite) found in certain
coals in the Western United States. Such
resinous coals are found, for example in the
States of Arizona, Colorado, New Mexico, Utah,
Washington, and Wyoming. Among these, the
Wasatch Plateau coal field in central Utah is of
great value because of its particularly
high con
tent of macroscopic fossil resin. Many seams in
this coal field have been reported to contain as
much as 5 percent resin by weight. Fossil resin
liberated from other coal
is friable and easily
macerals. Consequently, the resin particles tend
to concentrate into the fine sizes during coal
preparation and handling. Because of this
property, it is not unusual to find that the minus
28-mesh coal streams in a coal preparation plant
contain more than 10 percent hexane-soluble
4-28
resin, even when the run-of-mine coal contains
only 3 percent resin.
Research on the fossil resin has been described
by
J. Miller et al. in papers published in Enerpeia
and at the 11th Annual Pittsburgh Coal Con
ference.
According to Miller et al. fossil resin from Utah
coal generally exhibits low density, a range of
colors, and good solubility in hexane and/or hep
tane. It has been recovered intermittently from
the Utah coal field since 1929 by gravity and/or
flotation processes. The production, neverthe
less, has been on a very small scale and the tech
nologies used have limited the development of a
viable fossil resin industry. Of the four coal
preparation plants in the Wasatch Plateau coal
field (King, Plateau, Beaver Creek, and Price
River), resin has been recovered only intermit
tently from the U.S. Fuel plant, where a small
amount of this valuable resource was separated
by flotation (50 percent recovery from the fines)
as an impure concentrate containing about
50 percent resin. However, operations at the
U.S. Fuel plant have been terminated. The resin
flotation concentrates thus produced are refined
by
solvent extraction. Solvent-purified resins
from the Wasatch Plateau coal field typically have
a molecular weight of about 1 ,200 and a soften
ing point of about 170C.
This product, at the present time, has a market
value of at least $1 .00 per kilogram as a chemical
commodity and can be used in the adhesives,
rubber, varnish, paints, coatings, and thermoplas
tics industries, and particularly in the ink industry.
Selective flotation of resin from coal is difficult
with conventional flotation reagents and a multi
stage flotation process is usually required to
produce a resin concentrate of modest quality.
Unfortunately, process technology for the
recovery
and utilization of fossil resins from coal
has not received much attention. Because of the
lack of technology and the competition from syn
thetic resins, the valuable fossil resin resource
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
from Western coal has been wasted, being
burned together with coal for electric power gen
eration. Based on coal production data from the
Utah region, it is estimated that at least
200 million pounds per year of fossil resin from
the Wasatch Plateau coal field is being used as
fuel ($0.01 per pound) for electric power genera
tion rather than being used as a chemical com
modity ($0.50 per pound). This practice repre
sents an inappropriate use of a valuable
resource. Improved process technology for the
recovery
the University
of fossil resin is under development at
of Utah and includes selective flota
tion of fossil resin from fine coal streams and sol
vent refining
of the fossil resin concentrate to
produce a premium resin product.
Selective Flotation
Several new flotation technologies have been
developed and a number of papers and research
reports have been published. Three United
States patents which describe the new flotation
technologies have been granted. Of these, selec
tive resin flotation by pH control appears to be
the most economical and practical process. This
resin separation technology is based on the find
ings that the heterocoagulation between resin
and coal particles, which contributes to the inef
ficiency of resin separation from coal, can be con
trolled by pH adjustment. In this regard, the state
of dispersion and coal hydrophobicity can be
controlled for selective resin flotation if the pH is
adjusted to an appropriate level, between pH 8
and 12, depending on the resinous coal type and
previous treatment.
The results from pilot-plant testing of two Utah
resinous coal samples (CO-OP Mines and UP&L
Mines)
have demonstrated the success of this
new flotation technology. Specifically, the proof-
of-concept continuous flotation circuit (about
0.1 tons per hour) resulted In fossil resin recovery
with the same separation efficiency as was ob
tained in laboratory bench-scale testing (more
than 80 percent recovery at about 80 percent
concentrate grade). Secondly, the testing of this
technology
has proved that the selective resin
flotation process is sufficiently profitable to justify
4-29
the development of a fossil resin industry based
on this new flotation process.
Another approach is based on the discovery that
controlled surface oxidation can be used to ac
centuate the difference in hydrophobicity be
tween resin and the parent coal.
Finally, the selective fossil resin flotation can be
accomplished in both a multistage conventional
flotation circuit and in a flotation column. Of par
ticular interest in column flotation is the oppor
tunity to control the chemistry of the system with
the wash water; under these conditions excellent
separation efficiencies can be achieved.
Solvent Refining of Fossil Resin Concentrates
Because light-colored or yellow resin is
preferable and of greater commercial value than
the dark-colored resins, particularly in the ink in
dustry, solvent refining is a necessary step to
purify
resin concentrates and produce a light-
colored resin product.
A detailed study of batch solvent refining of resin
concentrates from the Wasatch Plateau coal is in
progress at the University of Utah to evaluate the
effect of refining conditions on the extraction
yield and product quality during various solvent
extraction processes. These solvent-refined
products are being characterized with respect to
their physical/chemical properties.
Solvent extraction studies indicate that two major
factors contribute to the natural color variation of
the fossil resin:
- Relative
-
abundance of chromophores
(mostly
pounds)
polar and unsaturated com
Finely dispersed inclusions of coal col
loids (< 100 microns)
The hexane-, heptane-, and ethyl acetate-
extracted resins appear light-yellow in color while
the toluene-extracted resin exhibits a significantly
darker color. Of the four solvents, the resin con-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
centrate has the highest solubility in toluene and
the lowest solubility in ethyl acetate.
The rate of resin extraction from the resin con
centrate is significantly affected by both particle
size and extraction temperature. The finer the
particle size the higher the extraction rate. The
rate for heptane extraction significantly increases
with an increase in extraction temperature (from
0C to 60C). Therefore, a moderate extraction
temperature (about 60C) should be considered
for the continuous extraction circuit in order to
maximize yield and minimize extraction time.
In summary, improved process technology is
under development for the differential solvent
refining
of fossil resin concentrates in order to
produce a premium resin product and enhance
the commercial value of these wasted fossil resin
resources.
####
INTERNATIONAL
BRITISH GAS/OSAKA GAS HYDROGENATOR
READY FOR SCALEUP
A highly efficient, clean, and flexible coal
hydrogenation process is being developed jointly
by British Gas pic and Osaka Gas Company of
Japan. At the heart of the process is a novel
entrained-flow reactor capable of accepting a
wide range of coals (Figure 1). The current
status of development of the process was
reviewed at the 1 1th Annual Pittsburgh Coal Con
ference by D. Brown and H. Gray of British Gas
and F. Noguchi of Osaka Gas.
The concept of this form of coal hydrogenation
reactor originated at British Gas in the
early 1980s. In 1986 British Gas and Osaka Gas
entered into a development agreement on coal
hydrogenation. Three phases of work have since
taken place. The first phase comprised a
program of physical modeling and pilot plant
work which successfully demonstrated the reac
4-30
Hydrogen
FIGURE 1
BRITISH GAS/OSAKA GAS
COAL HYDROGENATOR
Coal--=
SOURCE: BROWN ETAL.
Char
Char catch
Product gas
tor design concept at a scale of 5 tonnes per day
coal. A number of coals were tested in the pilot
plant over a wide range of operating conditions
providing high yields of both methane and high
value liquids such as benzene. Product distribu
tions were easily varied by simple manipulation
of the reactor operating conditions.
During
the second phase the pilot plant was
operated for an extended period suggesting that
commercial reactors should be able to operate
without difficulty.
The third phase comprised a program of large-
scale physical modeling providing information
toward the design of a 50-tonne per day
demonstration reactor. This is the next logical
development step. In addition, an independent
contractor's study of the commercial viability of
the process has been carried out and a mathe
matical model has been developed for process
optimization and scaleup.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
The Coal Hydrogenator
A reactor for coal hydrogenation must provide
rapid heating of the coal to promote devolatiliza-
tion and avoid agglomeration of the particles.
The reactor (Figure 1) achieves this using a spe
cial high velocity injector which subjects the pul
verized coal and hot hydrogen to intense mixing
as they
enter the reactor. The injector also
provides the driving force to recirculate the hot
product gases which further raises the tempera
ture of the inlet reactants. This feature of internal
recirculation and reactant preheating avoids the
need for oxygen addition and for high hydrogen
preheat temperatures. This leads to a high over
all process thermal efficiency.
The coal reacts within the central draught tube
yielding a char, which can then be used to
produce the hydrogen.
At reactor temperatures above 900C the
products are mostly methane and char while at
temperatures between 800 and 900C significant
quantities of hydrocarbon liquids can be
produced.
Coal
Temperature (C)
Pressure (bar)
H2/Coal Ratio (wt/wt)
Gas Residence Time (s)
%Carbon Conversion to
Methane
Other Gases
Benzene
Heavy Aromatics
Total
TABLE 1
Pilot Plant Trials
Six runs were carried out during 1990-1991.
Three coals, two United Kingdom bituminous
(Kiveton Park and Markham Main) and a
Japanese subbituminous coal (Taiheiyo), were
gasified. A total of 53 tonnes of coal were fed to
the reactor over a cumulative coal feeding time of
429 hours.
Taiheiyo coal gave the highest total conversion.
Selected results are given in Table 1 .
The relative yields of benzene and higher
aromatics varied with coal type and operating
conditions. Liquid yields were highest at lower
temperatures with up to 18 percent liquids yield
being achieved. In all cases, benzene has com
prised the major proportion of the total liquid
yield. The sulfur content in the liquids ranged
from only 0.01 to 0.26 weight percent.
Commercial Plant
PILOT PLANT PERFORMANCE
An engineering design and costing study was
carried out for a full-size commercial plant
Manvers Taiheivo Pittsburgh 8
865
62
4-31
0.4
12
27.0
3.0
8.6
4.6
43.2
846
62
0.4
12
35.7
6.6
12.3
3.8
58.4
872
62
11
0.4
29.6
1.9
6.8
8.2
46.5
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
producing 250 million standard cubic feet per
day of SNG (Substitute Natural Gas). According
to the authors, the study confirmed the feasibility
of the scheme and indicated the cost advantages
of coproducing aromatic liquids. The overall
process thermal efficiency with the coproduction
was 80.5 percent.
####
RUSSIAN/CZECH COAL GASIFICATION
TECHNOLOGY LOOKING FOR A BUYER
A news item in Chemical Engineering states that
ZVU A.S. (Hradec Kralove, Czech Republic) has
been trying to find Western buyers for its coal
gasification technology. The 300-500 kilogram
per hour pilot plant was shut down for several
months, starting early last year. However, the
company had hoped to restart It sometime late
last year.
The plant was built with the assistance of
Russia's Ivtan Research Institute (Moscow) in
1989. Until there is a commercial demonstration
plant, there is thought to be little chance of sell
ing the technology in the West.
####
U.S./RUSSIA JOINT IGCC PROJECT
POSSIBLE
A report in Coal & Svnfuels Technology says that
the United States Environmental Protection
Agency, Battelle Corporation and United Tech
nologies Inc. are teaming up in a 7-year project
to help the Russian Academy of Sciences (RAS)
develop in Integrated Gasification Combined
Cycle (IGCC) plant. It was reported that the
group recently completed preliminary analyses
for the project, paving the way for a feasibility
study. A RAS spokesman was quoted as saying
construction on the Russian IGCC will almost
immediately begin after the feasibility study is
completed.
4-32
IGCC is being considered in Russia as a retrofit
option for the nation's aging, dirty, coal-fired
powerplants. IGCC Is attractive to Russian
power generators because of Its efficiency and
the potential to reduce SOx and NOx emissions
to 20 ppm. Current SOx and NOx levels from Rus
sian powerplants are 10 times that high.
####
LIGNITE GASIFICATION PROJECT PLANNED
FOR INDIA
According to a report In Chemical Engineering.
Oswal Agro Ltd. of India and Sasol of South
Africa are in the early stages of planning a joint-
venture lignite gasification project to produce syn
thetic natural gas, methanol and acetic acid.
Further announcements are expected this year.
The plant would be built in the Kutch region of
Gujarat State in India. Sasol would provide the
process technology
capital required.
and 20-25 percent of the
####
COAL GASIFICATION PROJECTS INCREASE
IN CHINA
Clean coal technology
projects continue to
proliferate in China (see Figure 1). Some recent
announcements include the following.
Shanxi Province
According
to China Daily air and water pollution
in the industrialized regions of Shanxi Province
will be lowered with construction of five new
projects involving heat generation and coal gas.
Using loans from international financial organiza
tions and governments, the province hopes to
reduce annual pollution of sulfur dioxide gases
by 21,000 tons and dust and smoke by
51,000 tons.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
FIGURE 1
CHINESE CLEAN COAL TECHNOLOGY PROJECTS
Shanxi is one of the most important centers in
China for coal mining and electricity.
With the approval of the State Council, the
province plans to construct the five projects with
the help of loans requested from the Asian
Development Bank.
The projects involve three large industrial cities in
the province-Taiyuan, Datong and Yangquan,
where they will provide residents with heating
and coal gas while improving local air conditions.
Shanxi is rich in coal but suffers from a severe
shortage of unpolluted water. Reducing water
pollution is a key goal in seeking foreign invest
ments.
* Baotou coal to chemicals comple
-
* Datong towngas ) [f
Jr ~ * Tfinosnan^Mramics fuel gas
r^ ^\ fuel gas
Taiyuantt gas*
- S*ljjogkou HquWs from coal
Xining Yangquan mm ga&/
4-33
* Weihe fertilizer
- *w

COAL
a final feasibility study into a coal-based chemi
cals complex at Baotou. The project, which
would use coal reserves from Shenmu, Shanxi
Province and Dongsheng, Inner Mongolia, would
have annual capacities for 330,000 metric tonnes
of ammonia, 570,000 metric tonnes of urea,
330,000 metric tonnes of methanol, and
220,000 metric tons of acetic acid and acetic acid
derivatives. It would cost about $1 billion and
come onstream in year 2000.
####
THREE-TON/DAY GASIFIER TEST UNIT
UNDER CONSTRUCTION IN SOUTH KOREA
A 3-ton per day Bench-Scale Unit (BSU) In
tegrated Gasification Combined Cycle (IGCC)
gasifier is under construction in South Korea as
part of a strategy to develop a complete engineer
ing package for IGCC key components. The test
SOURCE: MMETAL.
FIGURE 1
unit was described by H. Kim et al. of Ajou Univer
sity, Suwon, Korea and the Institute for Advanced
Engineering (IAE), Seoul, at the 1 1th Annual Pitts
burgh Coal Conference last fall.
The project is sponsored by the Korea Govern
ment through a grant to the Energy System
Research Center of Ajou University, with the par
ticipation of IAE, Daewoo Corporation, DSHM
(Daewoo Shipbuilding and Heavy Machinaries)
and United Pacific Technologies.
An oxygen-blown, entrained gasification process
was chosen because of its higher thermal ef
ficiency
and mature demonstration of technol
ogy. A schematic diagram of the IGCC BSU is
shown in Figure 1. Pulverized coal is dried to
less than 5 percent surface moisture for
flowability through the feeding system. Fluxing
agents are required with certain coals to allow
slagging
temperatures and to reduce slag
DIAGRAM OF THE IGCC BENCH SCALE UNIT
PULVERIZED
COAL*
|
?
RAWfcOAL
COAL
FEEDING
SYSTEM
STEAM
J
COIL
PREPARATION
J SYSTEM
0XYCEN
IAE's GASIFIER
GAS COOLER
4-34
SLAG
of the coal ash at reasonable gasifier
CAS TREATMENT
SULFUR
CIZA.N CAS
viscosity. The
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
coal/flux feeding system uses nitrogen to pres
surize the coal in lockhoppers. The lockhoppers
discharge the coal to pressurized injection hop
pers, from which it is discharged by metering
screws into the coal injection lines. Coal, oxygen
or air, and steam enter the gasifier through tan
gential injection burners located in a common
horizontal plane. The gasifier operates at pres
sure up to 30 bar and temperature up to 1 ,650C.
Alaskan Usibelli coat is the first choice for the
3-ton per day gasifier design.
####
HYCOL PILOT PLANT COMPLETES
OPERATIONS
HYCOL, an advanced coal gasification pilot plant
located in Sodegaura, Chiba, Japan, successfully
completed its 3-year operation program on
SOURCE: MATSU0KA ET AL.
FIGURE 1
April 15, 1994. This unit, sponsored by New
Energy and Industrial Technology Development
Organization (NEDO), as a part of the
governmental new energy program called the
Sunshine Project, operated by Research Associa
tion for Hydrogen-from-Coal Process Develop
ment (HYCOL), was based on an entrained-flow,
oxygen-blown, single gasification chamber with
two-step, spiral-flow, multi-burners (Figure 1).
The HYCOL pilot plant was designed to gasify
50 tons per day of coal. During the program,
four different coals were gasified. The plant
logged 2,164 hours of operation, including a
1,149-hour long, uninterrupted run on Taiheiyo
coal.
The program has been summarized recently in
papers presented at the 11th Annual Pittsburgh
Coal Conference in September and the 13th
EPRI Conference on Gasification Power Plants in
October.
CONCEPTUAL FLOW IN THE HYCOL GASIFICATION ZONE
Product Gas
1
^y 7
Dry
Slag* Hot Gas
Ash Coated
Zone
Wet Ash Coated
Zone
...J
Circulation
4-35
Coal-
1.200 1.600
Temperature('C)
Reactive Char
Reactive Char
+ C02+H20
Coal+02
-CO+ Hj
-C02+H20
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
Process Description
In the HYCOL process, powdered coal is
pneumatically conveyed using nitrogen, and intro
duced with oxygen into the gasifier through two
stages of tangential multi-burners; four burners
arranged in each stage. The gasifier, operating
at 3 MPa and up to 1,800C, converts the coal to
a synthesis gas. Most of the ash in the coal
melts and circulates down along the wall of the
gasifier as molten slag, and eventually exits the
gasifier mainly through the outer slag tap holes in
the bottom. The slag is quenched, solidified in a
water bath, and crushed by the slag crusher,
then removed via lockhoppers. When the hot
gas exits the gasifier, recycle cooled gas and
steam are mixed to quench the gas so that the
solids in the hot gas are no longer sticky
(Figure 2).
The solids in the synthesis gas, termed recycle
char, are removed from the gas in double hot
Heat Recovery
Zone
FIGURE 2
cyclones. The recovered char, at about 300C, is
circulated to the gasifier via lockhoppers and a
pneumatic conveying system. This achieves
higher carbon conversion and allows a greater
recovery
of the coal ash as slag.
Technological Features
To achieve high gasification efficiency and ap
plicability to a wide range of coals, the HYCOL
gasifier has the following features:
- The
oxygen-blown one-chamber with
two-step
HYCOL PLANT CONFIGURATION
.Water.
(Quench)
Radiant"
Boiler
f CoaVOxygen
Gasification (Upper Burners)
Zone
CoaVOxygen
4 (Lower Burners)
Slag Quenching
Zone
HYCOL Reactor
SOURCE: MATSUOKA ET AL.
<
O
Oil Burner V Crusher
spiral flow concept lengthens
the residence time of coal particles in the
gasification zone, and thus enables a
higher gasification efficiency with com
pact reactor size. In addition, a wide
range of split ratios of coal and oxygen
fed to upper and lower burners can be
chosen independently to obtain optimum
gasification efficiency with a wide
Recycte (Quench)
Hot CyctoneJ nel i Convectj
1 r> Boiler
g &
Y
on Shifter
Steam
(Quench)
' Char/Oxygen/Steam
(Char Burner)
Slag
4-36
r\
E
Cooled Gas
Scrubber
| Wash Water
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
- The
- The
- A
- A
spectrum of coals. Also, spiral flow
produces hot gas circulation through the
slag tap holes, which enhances better
slag release.
pneumatic dry coal feed system
reduces oxygen consumption, therefore
increasing the efficiency. It also
eliminates any limitation of coal
properties imposed on a slurry or wet
system.
multi-burner system with a specially
equipped coal distributor makes it pos
sible to gasify a large amount of coal in a
small but easy to scaleup gasifier.
slag self-coating refractory with water
cooled tubes increases refractory wall
life of the gasification zone and its
reliability.
hot direct char recycle system directly
increases total gasification efficiency
while simplifying the process configura
tion.
Operating Experience
The initial 2 years were a shakedown phase,
during which the objectives were to verify the
equipment and process configurations, and to
make any necessary modifications.
HYCOL's first full-capacity
operation occurred in
July 1993. The highlight of the 3-year operating
term was a continuous 49-day run from Decem
ber 14, 1993 to January 31, 1994. By
January 25, 1994, a 1,000-hour, uninterrupted
and full-capacity operation with total direct
recycle of hot char was completed.
Carbon conversion efficiency reached
80-100 percent and the cold gas efficiency of
Taiheiyo coal with char recycle was in the range
of 65-79 percent at a 0.64-0.92 oxygen/coal
weight ratio. Char recycle increased both carbon
conversion and cold gas efficiency. Cold gas ef-
ficiency
reached a maximum at the
AST
0.78 oxygen/coal ratio targeted in the gasifier
design.
Additional runs were made to demonstrate
operability
of the process with a wide spectrum
of feed coals. Muswellbrook (Australia), Datong
(China) and Blair Athol (Australia) coals were
tested. On-the-fly feed switching from Mus
wellbrook to Datong was carried out successfully
in March 1994.
years'
Through the 3 activity, operational knowhow
was accumulated in such aspects as initial
and continuous coal feeding technique, changing
coal feed rate, control techniques for gasification
temperature, several emergency measures,
safety
Summary
shut down sequence and so on.
of Results
Plant runs and inspections have validated the
original design concept and features of the
HYCOL technology. Substantial progress was
made by the research activity at the pilot plant in
the last 6 months of operation.
- Operations
-
- Targeted
- Four
- Problems
at several oxygen/coal ratios
confirmed favorable temperature profiles
in the gasification section as envisioned
in the design concept.
Reliability was verified.
carbon conversion rates and
cold gas efficiencies were obtained.
on-
coals were gasified including an
the-fly feed coal switching. Addition of a
fluxing
fully.
agent was demonstrated success
due to ash components which
were experienced during the shakedown
phase were successfully overcome.
Overall plant performance closely matched
projections before startup. According to the
project sponsors, the test results confirmed that
the HYCOL process has a great potential to con-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
tribute to the economical utilization of coal in
IGCC power generation as well as for synthesis
gas and hydrogen production.
####
ENVIRONMENT
NATIONAL COAL ASSOCIATION ADDRESSES
ISSUE OF SUSTAINABLE DEVELOPMENT
Since the 1992 Earth Summit in Rio de Janeiro,
there has been a greatly increased awareness of
practices leading to the "sustainability"
of natural
resources. Many nations are now in the process
of preparing recommendations on activities that
may be adopted to support the philosophy of sus
tainable development-meeting the needs of
present generations without compromising the
ability
of future generations to meet their own
needs. The National Coal Association (NCA) has
published an "Issue in Brief on the subject.
The President's Council on Sustainable Develop
ment is formulating recommendations on initia
tives the United States might undertake. Among
the key elements of this White House initiative are
respect for the environment and an economy
"that equitably provides opportunities for satisfy
both
ing livelihoods and a safe, high quality life,"
now and in the years ahead.
Without a doubt, says NCA, the catalyst for the
type of economy envisioned for a sustainable
United States of America is an abundant, secure
and affordable energy supply. And the stability
and foundation of this energy supply is built on
the availability and cost of domestic resources,
particularly coal.
Energy is what makes the increasingly electrified
economy
environmentally sound manner. A steadily in
of the nation operate in an efficient and
creasing reliance on coal has played a significant
role in helping the U.S. sustain economic growth
while simultaneously achieving environmental
improvements over the past 20 years. During
4-38
this period, coal has become the nation's primary
source of domestic energy production.
America's 250-year supply of coal makes it the
only domestic source of energy that meets the
definition of "sustainability."
The country can
safely and confidently use coal without com
promising the aspirations and needs of future
generations.
CoaJ has become a vital source of both direct
and indirect positive impacts on the U.S.
economy. Beyond the energy it provides, coal
mining, transportation and use results in creation
of millions of jobs directly and in allied industries;
the production of goods and services throughout
the economy; and the generation of capital and
tax payments.
Driving these contributions are technological
achievements second to none. The continuous
introduction of new technologies has changed vir
tually every aspect of the industry, including the
way coal is explored, mined, loaded, marketed,
shipped and used. Technological advances have
made the processes of coal extraction, move
ment and combustion more efficient, productive,
safe and environmentally compatible. This has
important ramifications for a future of clean, abun
dant and affordable energy-the building block of
sustainable development-both at home and
abroad.
Electricity, Coal and the Economy
Since 1971, America's use of coal has risen
85 percent, with most of the increase devoted to
electricity production. Each percentage increase
of real GDP in general results in nearly a
1 percent rise in the demand for
electriclty-57 percent of which is provided by
coal.
Environment
Although coal use has risen dramatically over the
past 2 decades, the U.S. has experienced a
steady improvement in air quality. This is a testa
ment to a number of factors, including more effi-
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
cient combustion and pollution control tech
nologies, more effective coal cleaning, and the
proper use of the complete spectrum of available
U.S. coals.
The United States has the world's strictest air
quality standards. Under previous clean air laws,
the U.S. has reduced its emissions of sulfur
dioxide to one-half the level of the European
Community, per unit of GDP. This performance
argues persuasively for the ability of industry to
use technology to attain progress in this area.
The need for more coal has been accompanied
by a significant increase in mining activity. But
because comprehensive and effective reclama
tion is a common and integral part of coal mining
operations, the resulting land impacts have been
positive, rather than negative, says NCA.
The coal industry supports the voluntary aspects
of President Clinton's program to reduce U.S.
greenhouse gas emissions to 1990 levels by the
year 2000. Many coal producers are participat
in such activities as the Department of
ing
Energy's Motor Challenge; the Environmental
Protection Agency's "Green Lights"
program; the
Coalbed Methane program; "Cool Communities";
and other federal energy conservation and ef
ficiency efforts.
To date, research has indicated that global
climate activity is proceeding much more slowly
than originally forecast, if at all. Study results
document that there is time to carefully analyze
environmental questions and develop the tech
nologies and procedures necessary to accom
modate goals identified research. by Economic
constraints, arbitrary ceilings or hastily con
ceived, expensive programs which negatively
impact economic growth are not consistent with
the goals of a sustainable future.
In many areas, the coal industry believes It has
already
one of the key
achieved-and will continue to expand--
components of sustainable
development: the simultaneous attainment of sig
nificant environmental improvement, a healthy
4-39
economy and adequate and secure energy sup
plies.
Coal and the Future
Many
of the objectives outlined in the federal
government's "Vision Statement on Sustainable
Development and Draft Principles"
balancing
hinge on
economic growth, environmental
protection and social equity. Coal has already
demonstrated it can be mined, transported and
used in a manner consistent with these goals.
Coal represents 95 percent of all U.S. fossil
energy
reserves and 33 percent of all present fos
sil fuel production. Because the U.S. coal
resource is sufficient to last more than 250 years
at current rates of use, it represents a vast source
of energy capable of meeting growing domestic
energy needs.
Significant and ongoing industry productivity
increases-- 104 percent over the past decade
alone-have enabled the price of coal to decline,
even in current dollars. The continual introduc
tion of new mining technologies in the years
ahead suggest this trend will continue, further
emphasizing
security
of supply.
U.S. coal's cost-effectiveness and
To allow the U.S. and the world to take full ad
vantage of coal's many advantages, the NCA
says that America's leaders must develop and
implement policies and research programs that
will encourage the full, cost-effective utilization of
coal's potential, in a manner compatible with the
nation's environmental objectives.
####
IEA GREENHOUSE GAS PROGRAM
COMPUTES COST OF CARBON DIOXIDE
CAPTURE
In the second in a series of public summaries of
work carried out by the International Energy
Agency (IEA) Greenhouse Gas R&D Programme,
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
selected power generation, C02 capture options,
and C02 disposal options were evaluated. The
most promising options will be selected for more
detailed appraisal as components of a number of
Full Fuel Cycles for power generation.
Four power generation schemes were studied:
- A
- A
- An
modern pulverized coal-fired plant
equipped with flue gas desulfurization
facilities and operating with a subcritical
high temperature steam cycle
(PF+FGD).
modern natural gas-fired combined
cycle in which gas is fired into gas tur
bines with a steam turbine also incor
porated into the cycle (GTCC).
Integrated Gasification Combined
Cycle (IGCC) in which a coal slurry is fed
to an oxygen-blown gasifier of the
entrained-flow type.
TABLE 1
- Power
generation based on a scheme of
burning pulverized coal in oxygen using
recycled to moderate the combus
C02
tion temperature (CO, Recycle). The
technology has not been extensively
demonstrated and must therefore be
regarded as Long Term.
The four schemes were selected to represent a
wide range of C02 concentrations and conditions
in the exhaust gas.
The studies concentrate on the overall impact of
capture processes (for specifically removing or
isolating C02)
on power generation. The com
bined power generation and scrubbing plant
should have a net output of 500 megawatts (e).
Using solvent absorption of from the flue
C02
gas, figures arrived at for the cost incurred per
tonne of C02 release to atmosphere avoided,
range from $16 to $87 per tonne (Table 1). They
do not include the cost of C02 liquefaction and
disposal.
CARBON DIOXIDE RELEASES AND COST OF AVOIDANCE
(Efficiencies as %LHV)
CO, IGCC
PF+FGD GTCC IQQC Recvcle Selexol
Reference Efficiency 40 52 42 33 42
Efficiency After Capture 29 42 28 30 36
CO Captured (%) 90 85 90 99 82
C02 in Product (%)
Cost Avoided C02 ($/tonne)
Power Cost (ref . mills/kWh)
99.2
35
49
99.4
55
35
99.8
87
53
99.9
16
78
96
23
53
Power cost (mills/kWh)
Specific Investment Cost ($/kW)
74 53 112 94 63
Reference Case 1,058 702 1,561 2,044 1,561
Removal Case 1,842 1,367 3,254 3,102 2,400
4-40
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
The dramatic increase in cost for the IGCC case
shows that using absorption on the gas turbine
exhaust is not an effective way to capture C02.
Hence alternative schemes are based on treating
the gasifier product gas to concentrate the car
bon before combustion and take advantage of
the operating pressure. Therefore an additional
exercise looked at an IGCC system where the
fuel gas was shifted in a high and a low tempera
ture shift reactor and then cleaned in a Selexol
unit (IGCC Selexol). The H2S and C02 leave the
unit in separate streams. The cleaned fuel gas is
burned in the gas turbines. Results are shown in
the last column of Table 1 .
Physical absorption using Selexol is the most
appropriate technique to remove C02 from IGCC
fuel gases. A higher gasification pressure will
facilitate the C02 removal and increase the over
all power production efficiency. The use of more
advanced gas turbines could result in an in
crease in the overall efficiency.
Comparing the Capture Options
Processing techniques for the capture of C02 are
predominantly influenced by the concentration or
partial pressure of the gas to be captured.
Table 2 illustrates some results for several CO
Power System
PF+FGD Base Case
+ Membrane
+ Membrane & MEA
+ Absorption (MEA)
+ Cryogenics
+ Adsorption PSA
+ Adsorption TSA
TABLE 2
capture alternatives as applied to just the
PF+FGD option. It illustrates how the cost of
C02 avoided relates to cost of C02 captured i.e.,
it incorporates the extra C02 produced as a
result of generating the power required of the
capture process. The cost of C02 avoided is not
the complete story. It is only of value as a
measure when comparing capture results for the
same fuel and power generation technology.
None of the alternative capture processes
(membrane separation, cryogenic distillation,
pressure swing adsorption, and temperature
swing adsorption)
proved more economical than
monoethanolamine (MEA) absorption.
Conclusions
At the moment the conventional approach to cap
ture CO from a PF+FGD, or GTCC plant is to
"scrub"
the flue gas using absorption technology.
Currently, MEA is the absorption technology of
choice for capturing from powerplants. It is
C02
a fully proven technology bearing no technical
risk.
When analyzing short- to medium-term tech
nologies associated with IGCC, the Selexol
process itself requires relatively
CAPTURE DATA FOR THE PF+FGD SYSTEM
Efficiency
m
40
31
30
29
28
29
4-41
Power Cost
(mills/kWm
49.0
77.6
74.7
74.0
114
179
Cost C02
Avoided
($/tonne)
45.0
42.3
35.0
84
264
Emission Rate
ofC02
(oCOa/KWTi)
829
194
222
116
57
335
little energy.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
Some similar solvents are already available
(Purisol, Rectisol. Sepasolv, etc.). However, use
of a physical solvent does require that the syngas
be shifted. For IGCC powerplants in the medium
term, membrane separation technology may be
able to replace Selexol separation technology (in
conventional packed absorber columns). The
biggest energy savings would be realized
through reduced compression requirements.
While membrane technology looks promising,
and in particular gas absorption membranes, it is
Impossible to say
whether their potential can be
fully achieved. Also in the longer term, high per
formance fuel cells may replace gas turbines.
IEA says research is needed on how best to take
advantage of this development.
####
MANUFACTURED GAS PLANT SITE
REMEDIATION DRAWS VARIETY OF
SOLUTIONS
Prior to the widespread use of natural gas, com
bustible gas manufactured from coke, coal, and
oil served as the major gaseous fuel for urban
heating, cooking, and lighting in the United
States for nearly 100 years. This manufactured
gas, or town gas, was produced at some 1 ,000 to
2,000 plants. Pipeline distribution of natural gas
following World War II replaced manufactured
gas as the major gaseous fuel, and as a result
manufactured gas production came to an end in
the 1950s.
Today, soil and groundwater contamination
problems exist at many
Gas Plant (MGP)
former Manufactured
sites because of prior process
operations and management practices.
Residuals that were produced in MGP processes
are summarized in Table 1 for the three primary
gas production methods:
- Coal
- Oil
carbonization
Carbureted water gas production
gas production
442
These process residuals are dominated by six
primary
Aromatic Hydrocarbons (PAHs),
classes of chemicals: Polycyclic
volatile aromatic
compounds, phenolics, inorganic compounds of
sulfur and nitrogen, and metals. Tar residuals
were produced from the volatile component of
bituminous coals in coal carbonization, from the
residue of gasifying oils in oil gas processes, and
from the cracking of enriching
oils used to in
crease gas BTU content in carbureted water gas
production.
MGP tars are organic liquids that typically are
denser than water,
with a range of physical and
chemical properties dependent on the feedstock
and operating
conditions of the production
process. Although some MGP tar was used on
site or sold, during certain periods there was in
sufficient demand for all the tar that was
produced. Further, because of changes in tar
composition owing to changes in feedstock,
problems with tar-water emulsions, and other fac
tors, the intrinsic value of MGP tars was often
considered marginal. Consequently, MGP tars
were sometimes managed off-site or were
deposited on-site in tar wells, sewers, nearby
pits, or streams. Nuisances associated with the
disposal of tarry gas-plant wastes to streams and
sewers were recognized early in this century.
Total remediation costs for individual MGP sites
are in the range of tens of millions of dollars, and
the Gas Research Institute has estimated that
nearly 70 percent of such costs may be at
tributed to the management of tar-contaminated
soils and sediments.
Techniques for remediation are discussed in a
number of recent sources, including
R. Luthy et al., Environmental Science & Technol-
Qgy, Volume 28, Number 4, 1994; A. Hatfield,
American Gas Association Operations
Conference 1994; EPRI Journal. December 1994;
IGT Technology Spotlight. 1994.
Recovering Tar
Today, the tar from manufactured gas plants is
being recovered. Even ff the tar is buried in the
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
TABLE 1
CHEMICAL CLASSES PRESENT IN PROCESS RESIDUALS
FROM MANUFACTURED GAS PLANTS*
Chemial Class
Ught Inorg. Inorg.
Process Residual PAH? Aromatics Phenols N Metals
Coal Carbonization Process:
Coal Tar X X X
Hydrocarbon Sludges**
X X X
Wastewater Treatment Sludges X X X X X X
Coke X X X X
Ash X
Spent Oxide/Lime and Liquid
Scrubber Blowdowns X X X
Carburetted Water Gas Process:
Coal Tar and Oil Tar X X
Tar/Oil/Water Emulsion X X
Wastewater Treatment Sludges X X X X
Ash X
Spent Oxide/Lime and Liquid
Scrubber Blowdowns X X X
Oil Gas Process:
Oil Tar X X
Lampblack X
Tar/Oil/Water Emulsion X X
Wasterwater Treatment Sludges X X X X
Ash
Spent Oxide/Lime and Liquid
Scrubber Blowdowns X X
*"X"
means chemical class is expected to be present in the process residual.
**Tar decanter, ammonia saturator, and acid/caustic treatment sludges
soil, if it is in high concentration it often can be
recovered.
When the MGPs were operating, their byproduct
tars were processed by AlliedSignal, called the
Barrett Company at the time, to produce
creosote oil, roofing pitch, naphthalene and road
443
tars. AlliedSignal and its Environmental Systems
and Services group is still accepting and process
ing
the tar from these abandoned facilities. Al
though other sources of coal tar have been used
since the closing of the last MGP facility, it is still
possible to recover and reuse this material from
MGP facilities undergoing remediation.
THE SYNTHETIC FUELS REPORT, JANUARY 1995
X

COAL
Cofiring MGP Wastes In Utility Boilers
One possibility is to cofire tar-contaminated soil
with coal In utility boilers. However, only non-
hazardous solid wastes can be cofired in in
dustrial boilers without extensive regulatory per
mits. Thus this option can be considered only for
tar-contaminated material determined to be nonhazardous
upon excavation from an MGP site or
for excavated material that can be rendered nonhazardous
on-site within a 90-day accumulation
period (as required by United States Environmen
tal Protection Agency regulations).
According to previous research by EPRI and test
ing by individual utilities, a high benzene con
centration is the primary reason that MGP site
remediation wastes exhibit a hazardous charac
teristic in TCLP (Toxicity Characteristic Leaching
Procedure) testing. Tarry MGP wastes seldom
fail TCLP testing for any other parameter. If ex
cavated MGP material can be managed on-site
to reduce its TCLP benzene concentration, then
the material is a candidate for cofiring in a utility
or similar boiler.
In one EPRI-sponsored study,
coal and tar were
mixed in various proportions, and the mixtures
were analyzed for total benzene and TCLP ben
zene. It was found that a mixture containing
4.45 percent tar would have a 97.5 percent proba
bility of being found non-hazardous in TCLP test
ing.
Chemical Extraction Methods
Removal of subsurface tars at or near residual
saturation by injection and recovery of aqueous
solutions of surfactants or solvents to enhance
solubilization of constituents may be possible,
but could be performed only at sites where the
flow and recovery of the solutions can be control
led with confidence. Moreover, it is clear from
bench-scale experiments that large concentra
tions of solvent or surfactant would be required
to achieve substantial recoveries of tar mass by
dissolution. Fairly large doses of surfactant are
required to promote enhanced solubility of PAH
compounds In the presence of soil because of
sorption of surfactant on the soil. In the
presence of an organic liquid phase, partitioning
of the surfactant to the organic liquid could oc
cur, possibly resulting in even higher required sur
factant doses.
MGP-REM Process
IGT has developed and demonstrated a remedia
tion technology, known as the MGP-REM
process,
which is based on the enhancement
and acceleration of indigenous biological activity
and the application of chemical treatment. The
chemical treatment uses hydrogen peroxide and
iron salt (Fenton's reagent) to oxidize
polynuclear aromatic hydrocarbons, making
them more amenable to biological treatment.
The MGP-REM process is faster and achieves a
significantly higher degree of cleanup
than the
conventional biological process alone.
Moreover, it costs no more than conventional
bioremediation and is considerably less expen
sive than incineration. IGT successfully field
tested the technology in the landfarming mode
from 1991 to 1993 and in the soil-slurry mode in
1993-1994. In situ field tests are expected to
start in 1995.
IGT and its commercial partners operated a pilot-
scale bioslurry reactor system based on the
MGP-REM process at an MGP site in New Jer
sey.
Figure 1 depicts the pilot-scale bioslurry reactor
system.
The treatment process starts with the excavation
of the soil, which is screened before being mixed
with water in the attrition scrubber. Slurry from
the attrition scrubber is then pumped to the
respective reactors for either biological or chemi
cal treatment. After treatment, the slurry is
pumped to a thickener where the water is
removed. The water is stored for reuse, and the
thickened solids are made available for backfill at
the site.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
SOURCE: IGT
CONTAMINATED
SOIL
TREATED
SOIL
In Situ Solidification
FIGURE 1
BIOSLURRY REMEDIATION PROCESS
2'
Water
Tank
m
SCREEN
THICKENER
At an MGP site in Columbus, Georgia, gas was
produced from 1854 to 1931. In 1992 this site
became the target of an environmental cleanup
effort.
The analysis of ground water flow across the site
indicated a southwesterly flow of water and MGP
coal tar.
Boring and sampling activity indicated that a
bedrock layer identified as "saprolite,"
a
weathered granite material, underlay the site in
an undulating manner at a depth of ap
proximately
45 feet below the ground surface.
Due to the coal tar having a specific gravity
CHEMICALS
AIR-I
01
do
PEED HOPPER
& CONVEYOR
INOCULUM.
NUTRIENTS
AIR-i
ia Aim
f"l ATTRITION
SHAKER r\^'
SCREEN
CO do
BIO-
CHEMICAL SLURRY
REACTOR REACTOR REACTOR
4-45
SCRUBBER
? 20 fresh
OVERSIZE
greater than water, bore samples identified quan
tities of coal tar pooled at the surface of the
saprolite.
A containment plume of MGP waste was iden
tified in the groundwater in a prevailing southwes
terly
point area.
direction and downstream of the source
The selected strategy involved in situ stabilization
using a large vertical auger to directly treat and
immobilize 15 to 20 feet of MGP-affected soil
both above and below the water table (Figure 2).
Existing
clean fill above the water table was ex
cavated and stockpiled for reuse; pockets of
MGP-affected materials within the fill were stabi
lized by mixing with 10 percent portland cement.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

COAL
uuc
stomace
TANKS
SOURCE: HATTELD
FIGURE 2
IN SITU STABILIZATION SYSTEM SCHEMATIC
TAIATMCNT
TAAMSFIA
TANK
Along the west side of the site, parallel to the
river, an in situ wall was constructed using an
extra-rich soil/cement mixture. This extra-rich
4-46
ACTTVATII)
CAAIOM
OUST TREATMENT CXMAUST
COUCCTOM TANKS FAK
UNSOUDtriEO SLUOCE
mixture provided an added barrier to
groundwater flow.
####
THE SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMMERCIAL AND R&D PROJECTS (Underline denotes changes since June 1994)
ADVANCED COAL CONVERSION PROCESS DEMONSTRATION -
United States Department of Energy (C-5)
Rosebud
SynCoal Partnership, Western Energy Company,
The United States Department of Energy (DOE) signed an agreement with Western Energy Company for funding as a re
placement project in Round 1 of the Department's Clean Coal Technology Program. DOE will fund half of the $69 million
project and the partners will provide the other half of the funding. Western Energy Company has entered a partnership with
Scoria Inc., a subsidiary of NRG, Northern States Powers'
nonutility group. The new entity, Rosebud SynCoal Partnership will
be the project owner. Western Energy Company has retained a contract to build and operate the facility.
The Svncoal process is a novel coal cleaning and upgrading process to improve the heating value and reduce the sulfur content
of western coals. Typical western coals may contain moisture as much as 25 to 35 percent of their weight. The high moisture
and mineral content of the coals reduces their heating value to less than 9,000 BTU per pound.
The Svncoal process would upgrade the coals, reducing their moisture content to as low as 1 percent and produce a heating
value of up to 12,000 BTU per pound. The process also reduces sulfur content of the coals, which can be as high as 1.5 percent,
to as low as 0A percent. The project will be conducted at a 50 ton per hour unit adjacent to a Western Energy subbituminous
coal mine in Colstrip, Montana.
"turnover"
Construction of the ACCP demonstration facility is complete and initial of equipment started in December 1991.
The DOE agreement calls for a 3-year operation demonstrating the ability to produce a clean, high quality, upgraded product
and testing the product in utility and industrial applications.
Initial startup was achieved in early 1992; however, due to mechanical problems, reliable operation was not achieved until
August 1993. The plant produces 1,000 tons per day, or 300,000 tons per year of upgraded solid fuel at full production.
Rosebud SynCoal Partnership successfully worked with Montana Power Company's Corette plant to conduct 7 months of tests
using a SynCoal/raw coal blend. Several industrial facilities are currently using SynCoal.
Based on the successful demonstration, Rosebud SvnCoal hopes to build a privately financed commercial-scale plant process
ing 1 to 3 million tons of coal per year by 1997.
In late December 1993, Minnkota Power Cooperative signed a letter of intent with Rosebud SynCoal Partnership for a
$2 million study to examine the merits of scaling up the tatter's technology to an $80 million commercial plant.
The SynCoal plant would be sited next to Minnkota's Milton R. Young power station near Center, North Dakota, northwest of
Bismarck. The engineering and design was study completed in mid-1994. The proposed project is technically feasible;
however, the markets and project financing are still pending.
Project Cost: $69 million
-- ADVANCED POWER GENERATION SYSTEM British Coal Corporation, United Kingdom Department of Trade and Industry,
European Commission, PowerGen, GEC/Alsthom (C-15)
A consortium involving British Coal Corporation, United Kingdom Department of Trade and Industry, European Commission,
PowerGen, and GEC/Alsthom is carrying out a research program to develop an advanced coal fired power generation system,
known as the Air Blown Gasification Cycle. In this system coal is gasified in a spouted bed gasifier to produce a fuel gas which
is used to drive a gas turbine. The waste heat recovery from the gas turbine is then integrated with a circulating fluidized bed
char combustor.
The integrated system is expected to have an efficiency of about 48 percent.
A 12 tonne per day, air blown, pressurized, spouted bed gasifier developed at the Coal Research Establishment (CRE).
Gloucestershire, started operating in 1990. This provides gas to a hot gas cleaning plant and a gas turbine combustor. The
Grimethorpe experimental pressurized fluidized bed combustion (PFBC) facility was used to investigate lifetime issues in gas
turbine operations. The program at Grimethorpe was successfully concluded in 1993, and the site closed that year.
Work is continuing at Coal Technology Development Division (CTDD'). formerly part of CRE, on the operation of the gasifier
supplying gas to downstream components.
The research program is funded by the United Kingdom Department of Trade and Industry, and the European Community.
4-47
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes sinee June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
BHEL IGCC AND COAL - GASIFICATION PROJECT Bharat
Heavy Electricals Ltd (C-45)
BHEL's involvement in the development of coal gasification concerns the belter and wider utilization of high ash, low grade
Indian coals.
As a first step, BHEL has set up a 6.2 MWe Integrated Gasification Combined Cycle (IGCC) plant with an in-house 150 ton
per day moving bed gasifier integrated to a 4 MWe gas turbine and a 2.2 MWe steam turbine combined cycle plant. The plant
was commissioned in 1986 and has been operated for more than 5,000 hours with the longest run of 30 days.
BHEL considers fluidized bed gasification as a long term prospective for IGCC for high ash coals. An 18 ton per day coal pilot
scale Process and Equipment Development Unit (PEDU) was commissioned in 1989 for performance evaluation. In the
PEDU, coal is gasified by a mixture of air and steam at around 1,173^K and a pressure of 1.013 MPa.
The PEDU has been operated for more than 2300 hours with the longest continuous run of 168 hours. Th process and subsys
tem has been stabilized. The PEDU has been modified to improve carbon conversion and cold gas efficiency by recycling of
cyclone ash and redesigning the distributor section of the gasifier for partial bum-up of bottom ash.
BHEL has taken up a project to retrofit a 150 ton per day fluidized bed gasifier to its existing
6.2 MWe IGCC plant in 1994.
An advanced pressurized fluidized bed gasification rig incorporating gravity feeding of coal and cyclone char and integrated
bed ash carbon burn-up system is in the final stage of erection.
Project Cost: Estimated $4 million for retrofitting fluidized bed gasifier.
- BOTTROP DIRECT COAL LIQUEFACTION PILOT PLANT PROJECT Ruhrkohle
AG, Veba Oel AG, Minister of
Economics, Small Business and Technology of the State of North-Rhine Westphalia, and Federal Minister of Research and Technol
ogy of Germany (C-60)
During operation of the pilot plant the process improvements and equipment components have been tested. The last improve
ment made being the operation of an integrated refining step in the liquefaction process. It worked successfully between late
1986 and the end of April 1987. Approximately 11,000 tons raffinate oil were produced from 20,000 tons of coal in more than
2,000 operating hours.
By
this new mode of operation, the oil yield is increased to 58 percent. The formation of hydrocarbon gases is as low as 19 per
cent. The specific coal throughput was raised up to 0.6 tons per cubic meter per hour. Furthermore high grade refined
products are produced instead of crude oil. The integrated refining step causes the nitrogen and oxygen content in the total
product oil to drop to approximately 100 ppm and the sulfur content to less than 10 ppm.
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 development program of the Coal Oil Plant Bottrop was temporarily suspended in April 1987. Reconstruction work for a
bivalent coal/heavy oil process was finished at the end of 1987. The plant capacity is 9 tons/hour of coal or alternatively
24 tons/hour of heavy vacuum residual oil. The first "oil-in"
took place at the end of January 1988. Since then approximately
325,000 tons of heavy oil have been processed. A conversion rate over 90 percent and an oil yield of 85 percent have been
confirmed.
The project was 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: DM830 million (by end-1987)
- BRITISH COAL LIQUID SOLVENT EXTRACTION PROJECT British
Economic Community, Ruhrkohle AG, Amoco,
Exxon (C-70)
Department of Trade and Industry, European
British Coal is operating a 2.5 tons per day pilot plant facility at its Point of Ayr site, near Holywell in North Wales utilizing its
Liquid Solvent Extraction Process, a two-stage system for the production of gasoline and diesel from coal. 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 degrees C as a precursor for transport fuels and chemical feedstocks.
The process dries and pulverizes the coal, then slurries it with a hydrogen donor solvent. The coal slurry is pressurized and
heated, then fed to a digester that dissolves up to 95 percent of the coal. The digest is cooled, depressurized and filtered to
remove mineral matter and undissolved coal. A fraction of the solvent washes the filter cake to displace the coal extract solu-
4-48
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
tion; residual wash oil is recovered by a vacuum that dries the filter cake. The coal extract solution is then pressurized, mixed
with hydrogen and heated before being fed to the ebullating bed hydrocracking reactors. The product from this stage is dis
tilled to recover the recyclable solvent and produce LPG (propane and butane), naphtha and mid-distillate. A byproduct pitch
stream is siphoned off although material in this boiling range is primarily returned to the digestion stage as part of the solvent.
The remaining streams consist of light hydrocarbon gases and heterogases formed from the nitrogen and sulfur in the coal.
Studies have confirmed that the process can produce high yields of gasoline and diesel very efficiently-work on world-wide
coals has shown that it can liquefy economically most coals and lignite and can handle high ash feedstocks. The program is
progressing to mid-1995.
Project Cost: 20 million British pounds (1989 prices) construction cost plus 18 million British pounds (1989 prices) operating
costs.
BUGGENUM IGCC POWER PLANT -
(C-91)
A commercial prototype IGCC plant has been built at Buggenum in the Netherlands, and was started up at the end of 1993.
The first electricity from coal was produced in April, 1994. The system was designed as one process train with a combined cycle
of270MW.
The Shell system being used is an oxygen-blown, entrained flow, slagging gasifier which uses a dry pulverized coal feed. Coal
and oxygen are fed into a pressure vessel. The reaction product is a medium BTU gas consisting mainly of carbon monoxide
and hydrogen, together with ammonia, hydrogen cyanide, hydrogen sulfide, and carbonyl sulfide. The downstream process
consists of cooling and cleaning the gas of these toxic trace compounds. The clean synthetic gas is 62 percent CO, 32 percent
H , and 5.5 percent inert gas. The residual sulfur content, mainly unconverted carbonyl sulfide, is less than 100 ppm by
volume.
In the Shell IGCC project the gas turbine is used as a source of oxygen for the process, and nitrogen to pressurize the coal feed
system. Air is bled from the compressor discharge and sent to a cryogenic air separation unit which yields oxygen to the
process and makeup nitrogen to pressurize the coal transfer system.
After startup, a 3-year demonstration program (1994-1996) will be conducted. The unit will then operate as a commercial
powerplant.
- CALDERON ENERGY GASIFICATION PROJECT Calderon
(C-95)
Energy Company, United States Department of Energy
Calderon Energy Company is constructing a coal gasification process development unit. The Calderon process targets the
clean production of electrical power with coproduction of fuel methanol.
Phase I activity and Phase II. detailed design, have been completed. Construction of the process development unit (PDU) was
completed in 1990. Test operation began in October 1990 and ran at 50 percent capacity during the early stages.
The PDU will demonstrate the Calderon gasification process. In the process, run-of-mine high sulfur coal is first pyrolyzed to
recover a rich gas (medium BTU), after which the resulting char is subjected to airblown gasification to yield a lean gas (low
BTU gas). The process incorporates an integrated system of hot gas cleanup which removes both particulate and sulfur com
ponents of the gas products, and which cracks the rich gas to yield a syngas (CO and H mix) suitable for further conversion
(e.g., to methanol). The lean gas is suitable to fuel the combustion turbine of a combined cycle power generation plant. The
PDU is specified for an pressure operating of 350 as psig would be required to support combined cycle power production.
The pilot project, designed to process 25 tons of coal per day, is expected to operate for six to twelve months while operating
in the system are worked out.
data is gathered and any "bugs"
The federal government has contributed $12 million toward project costs, with another $1.5 million coming from the Ohio Coal
Development Office.
for a
commercial site in Bowling Green, Ohio. Calderon filed a proposal under the Clean Coal Technology program Round V to
build a cogeneration facility supplying 87 megawatts of electricity and 613 tons of methanol per day. The project did not
receive funding, however, in Round III or IV. A preliminary design and cost estimate has been prepared by Bechtel. Calderon
Calderon Energy has obtained certification from the Federal Energy Regulatory Commission as a Qualifying Facility
is negotiating with Toledo Edison to sell the electricity which would be produced.
Project Cost: Total Cost $242 million, PDU $20 million
4-49
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
CAMDEN CLEAN ENERGY PROJECT- Camden Clean Energy Partners Ltd. Partnership, made up of Duke Energy Corp.,
General Electric Co., and Air Products and Chemicals, Inc. (C-100)
A 484 megawatt advanced CGCC power plant is planned for Camden, NJ. Power from the plant will be sold to Public Service
Electric and Gas Co. through an anticipated power sales agreement.
The project will demonstrate the British Gas/Lurgi (BGL) fixed-bed oxygen-blown gasifier technology in which 3,700 tons per
day of Pittsburgh No. 8 high-sulfur coal from West Virginia is gasified to produce a clean gas that is combusted in advanced gas
turbines. Turbine exhaust will be used to produce steam to drive a steam turbine in a second cycle. These two combined cycles
are expected to make the CGCC plant 20 percent more efficient than a conventional coal plant, while reducing levels of SO ,
and particulates to meet the most stringent environmental standards.
NO^
The CGCC component will use four BGL fixed-bed slagging gasifiers, two General Electric 7FA advanced combustion turbines
and a 2,000 ton per day air separation unit. The project will also include a demonstration of a 25 MW molten carbonate fuel
cell, which will be operated with a portion of the clean coal gases.
The project was selected under the United States Department of Energy Clean Coal Technology Demonstration Round 5. The
estimated total project cost is $780 million, of which DOE will provide 25 percent.
- CARBON COUNTY UNDERGROUND COAL GASIFICATION (L'CG^ PROJECT Carbon
of Williams Energy Ventures and Energy International Corporation) (C-105)
County UCG. Inc. (a joint venture
A two-year demonstration project is designed to determine the commercial feasibility of gas produced bv UCG. The project
will be located in a steeply-dipping seam of coal located about 8 miles west of Rawlins. Wyoming. This UCG technology can be
used to develop coal seams that cannot be mined using conventional mining techniques. Air quality and other permits were
obtained in 1994. Depending on the success of the demonstration project, commercial operations could be started as early as
1996.
Project Cost: Unknown
CHARFUEL PROJECT Coal Refining Corporation of American, a subsidiary of Carbon Fuels Corporation (C-110)
Coal Refining Corporation has completed the design phase and has purchased most of the equipment for an 18 ton per day In
tegrated Process Demonstration Unit (IPDU) which will integrate the Charfuel hydrocracker with commercially available
processes to optimize the operating conditions for commercial coal refineries. Coal Refining Corporation is seeking funds to
complete the 18 ton per day IPDU project.
The 18 ton per day IPDU involved demonstrating the patented Charfuel coal refining process. The first step is
"hvdrodisproportionation"
which is accomplished by short residence time flash volatilization. Resulting char may be mixed
back with process-derived liquid hydrocarbons to make a stable, compliance. high-BTU. pipelineable fiuidic fuel. This com
pliance fuel could be burned in a coal-fired or modified oil-fired burners. The char can also he used as a feedstock for in
tegrated combined cycle gasification (IGCC). as a feedstock for pressurized fluidized bed combustion, or as a source of fixed
carbon for direct iron ore reduction (DRI). Additional products manufactured during the refining process include ammonia
and/or urea, sulfur, methanol. MTBE. BTX. naphtha, and fuel oil.
The company's affiliate has completed a program which verified the design of the proprietary coal injector/mixer system. This
work, at a design scale of 150 tons per day, was co-funded by the Department of Energy and conducted at the Western
Research Institute in Laramie. Wyoming. The system operated successfully at over 240 tons per day, or more than 1.5 times
the design scale.
Carbon Fuels Corporation has signed a license agreement with Zia Metallurgical Processes. Inc. for a commercial Charfuel coal
refinery integrated with a Zia steel production facility using Zia's proprietary DRI process to be located in Puerto Rico. The
coal refinery will produce char, fuel gas and liquid hydrocarbons. The char and fuel gas will be used in the steel production
facility. Liquid hydrocarbon products will be sold locally. Zia has agreed to construct five additional Charfuel plants over the
next ten years under the license-
Carbon Fuels has also entered into a Memorandum of Understanding with the Chinese Academy of Sciences to complete the
IPDU and commence commercialization of the Charfuel process in China. The Chinese Ministry of Science and Technolog
ies added the Charfuel project to the list of projects which are to be funded under the Memorandum of Understanding be
tween the U.S. Department of Energy and the Chinese government.
Additionally, the Charfuel hydrocracking process is included as one of the technologies to he evaluated and supported in accor
dance with Section 1305 of the Energy Policy Act.
4-50
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
IPDU Project Cost: $4.5 million
- CHEMICALS FROM COAL Tennessee
Eastman Division (C-120)
Tennessee Eastman Division, a manufacturing unit of Eastman Chemical Company, operates its chemicals from coal complex
at Kingsport, Tennessee at the design rate of 1,100 short tons per day. The Texaco coal gasification process is used to produce
the synthesis gas for manufacture of 1.2 billion pounds per year of acetic anhydride. Methyl alcohol and methyl acetate are
produced as intermediate chemicals, and sulfur is recovered and sold.
The completion of a $200 million expansion program in October 1991 added two new chemical plants to the original complex,
doubling its output of acetyl chemicals from coal.
Project Cost: Unavailable
CHINA ASH AGGLOMERATING - GASIFIER PROJECT The
Institute of Coal Chemistry, China (C-123)
The Institute of Coal Chemistry (ICC) of the Chinese Academy of Sciences is developing an ash agglomerating coal gasification
process. The process is applicable to a wide range of coals including those with high ash content and high ash fusion tempera
ture.
In 1983, a small scale pilot gasifier, or PDU, was set up. At first, different coals were gasified with air/steam as gasifying agents
to make low heating value gas for industry. Later, coals were gasified with oxygen/steam to make synthetic gas for chemical
synthesis. A pilot scale gasification system of 24 tons per day coal throughput was scheduled for startup in late 1990.
The gasifier is a cylindrical column of 0.3 meter inside diameter with a conical gas distributor and central jet tube on the bot
tom. The enlarged upper section is 0.45 meter inside diameter in order to settle out the gas-entrained coarse particles. The to
tal height of the gasifier is about 7.5 meters.
Predried coal is blown into the gasifier after passing through the lockhopper and weighing system. Preheated air/steam (or
oxygen/steam) enters the gasifier separately through a gas distributor and central jet tube. The coal particles are mixed with
hot bed materials and decomposed to gas and char. Because of the central jet, there is high temperature zone in the dense bed
in which the ash is agglomerated into larger and heavier particles. The product gas passes through two cyclones in series to
separate the entrained fine particles. Then the gas is scrubbed and collected particles are recycled into the gasifier through
standpipes. The fines recycle and ash agglomeration make the process efficiency very high.
Based on the PDU data and cold model data, a 1 meter inside diameter gasifier system was designed and constructed. It is to
be operated at atmospheric pressure to 0.5 MPa with a coal feed rate of 1 ton per hour.
CHINA ONE CLEAN COAL PROJECT- SGI International and Mitsubishi Heavy Industries (MHn (C-125^1
SGI and MHI are proceeding with an engineering and economic feasibility study to construct a clean coal refinery in Longku
Harbor, Shandong Province. China. It is expected that the Comprehensive Utilization Corporation of Shandong Coal Industry
will become a partner and arrange for the shipment of 500 kg of Liangjia Mine coal, located near Longku Harbor, to the U.S.
for large-scale testing.
The refinery would use the LFC Technology, currently being demonstrated at the ENCOAL project, near Laramie. Wyoming.
The planned operations include processing 6.000 metric tonnes of Liangjia coal per day for a projected annual production of
more than one million tons of low-sulfur PDF coal and 1.5 million barrels of CDL oil.
The feasibility study is expected to be completed in mid-1995; if the study is favorable, construction of the China One Clean
Coal Refinery would be started shortly.
CIGAS GASIFICATION PROCESS PROJECT - Fundacao
de Ciencia e Tecnologia-CIENTEC (C-130)
The CIGAS Process for the generation of medium BTU gas is aimed at efficient technological alternatives suitable for
Brazilian mineral coals of high ash content. No gasification techniques are known to be available and commercially tested for
Brazilian coals.
4-51
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
The CIGAS Process research and development program has been planned for the interval from 1976 to 1998. In 1977 an at
mospheric bench scale reactor was built, from which were obtained the first gasification data for Brazilian coals in a fluidized
bed reactor. In 1978 a feasibility study was completed for the utilization of gas generated as industrial fuel. Next the first pres
surized reactor in Latin America was built in bench scale, and the first results for pressurized coal gasification were obtained.
In 1979 the first atmospheric fluidized bed pilot scale unit was assembled (with a throughput of 7.2 tons per day of coal). In
1980 a project involving a pressurized unit for oxygen and steam began (20 atmospheres and 05 tons per of coal). day The
plant was fully operational in 1982. In 1984 the pressurized plant was enlarged to
capacity
25 tons per day of processed coal
and at the same time air was replaced by oxygen in the atmospheric plant. This unit started processing
17 tons per day of coal.
In 1986 a unit was built to treat the liquid effluents generated throughout the process and studies on hot gas desulfurization
were started in bench scale. By the end of 1988 pilot scale studies were finished. As the result of this stage, a conceptual
design for a prototype unit will be made. This prototype plant will be operational in 1994 and in 1996 the basic project for the
demonstration unit will be started. The demonstration unit is planned to be operational in 2001.
Project Cost: US$6.0 million up to the end of 1988. The next stage of development will require US$8 million.
- CTVOGAS ATMOSPHERIC GASIFICATION PILOT PLANT Fundacao
- de Ciencia e Technolgia CIENTEC (C-133)
The CIVOGAS process pilot plant is an atmospheric coal gasification plant with air and steam in a fluidized-bed reactor with a
capacity of five gigajoules per hour of low-BTU gas. It was designed to process Brazilian coals at temperatures up to 1,000 C.
The pilot gasifier is about six meters high and 0.9 meters inner diameter. The bed height is usually 1.6 meters (maximum 2.0
meters).
The CIVOGAS pilot plant has been successfully operating for approximately 10,000 hours since mid 1984 and has been work
ing mainly with subbituminous coals with ash content between 35 to 55 percent weight (moisture-free). Cold gas yields for
both coals are typically 65 and 50 percent respectively with a carbon conversion rate of 68 and 60 weight percent respectively.
The best conditions operating to gasify low-rank coals in the fluidized bed have been found to be 1,000 degrees C, with the
steam making up around 20 percent by weight of the air-steam mixture.
Two different coals have been processed in the plant. The results obtained with Leao coal are significantly better than those
for Candiota coal, the differences being mostly due to the relative contents of ash and moisture in the feedstock.
CIENTEC expects that in commercial plants or in larger gasifiers, better results will be obtained, regarding coal conversion
rate and cold gas yield due to greater major residence time, and greater heat recovery from the hot raw gas.
According to the CIENTEC researchers, the fluidized-bed distributor and the bottom char withdrawal system have been their
main concerns, and much progress has been made.
- COALPLEX PROJECT AECI
(C-140)
The Coalplex Project is an operation of AECI Chlor-Alkali and Plastics, Ltd. The plant manufactures poly-vinyl chloride
(PVC) and caustic soda from anthracite, lime, and salt. The plant is fully independent of imported oil. Because only a limited
of ethylene was available
supply
from domestic sources, the carbide-acetylene process was selected. The plant has been operat
since 1977. The five processes include calcium carbide manufacture from coal and calcium oxide; acetylene production
ing
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.
This plant, which is now part of Polifin. a 60 percent Sasol. 40 percent AECI joint venture, will be shut down in 1996. being re
placed bv a conventional (vhole-HoechsO balanced oxvchlorination VCM plant using ethylene from Polifin's own facilities
which produce 400.000 tpa ethylene from ethane/ethvlene byproduct from Sasol's coal-based synthetic fuels plants at Secunda.
Project Cost: Not disclosed
- COGA-1 PROJECT Coal
Gasification, Inc. (C-150)
The COGA-1 project has been under development since 1983. The proposed project in Macoupin County, Illinois will con
sume 1 million tons of coal per year and will produce 675,000 tons of urea ammonia and 840,000 tons of urea per year. It will
use a high-temperature, high-pressure slagging gasification technology. When completed, the COGA-1 plant would be the
largest facility of its kind in the world.
4-52
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
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 Gover
nor James R. Thompson announced a $26 million state and local incentive package for COGA-1 in an attempt to move the
$690 million project forward. The project sponsor is continuing with engineering and financing efforts, but the project itself
has not moved forward significantly since 1986.
Project Cost: $690 million
COLOMBIA COAL - GASIFICATION PROJECT Carbocol
(C-160)
The Colombian state coal company, Carbocol plans for a coal gasification plant in the town of Amaga in the mountainous in
land department of Antioquia.
Japan Consulting Institute is working on a feasibility study
on the gasification plant and current plans are to build a US$10 to
20 million pilot plant initially. This plant would produce what Carbocol calls "a clean gas fuel"
for certain big industries in An
tioquia involved in the manufacture of food products, ceramics and glass goods. According to recommendations in the
Japanese study, this plant would be expanded in the 1990s to produce urea if financing is found.
Project Cost: $20 million initial
$200 million eventual
CORDERO - COAL UPGRADING DEMONSTRATION PROJECT Cordero
Mining Company (C-170)
Cordero Mining Company will demonstrate the Carbontec Syncoal process at a plant to be built near its mine in Gillette,
Wyoming. The demonstration will produce 250,000 tons per year of upgraded coal product from high-moisture, low-sulfur,
low-rank coals.
The project was selected by the United States Department of Energy (DOE) in 1991 for a Clean Coal Technology Program
award. DOE will fund 50 percent of the $34.3 million project cost. In August 1992. Cordero Mining Company withdrew from
negotiations.
Project Cost: $34.3 million
- CORDERO FORMCOKE PLANT Kennecott
Energy and PURON (C-172)
A coal enhancement plant, using the PURON process, is planned to be constructed adjacent to the Kennecott Energy Company Cor
dero Mine, located about 20 miles east of Gillette. Wyoming. The PURON process represents an adaptation of the FMC formcoke
process that has been processing subbituminous coal at Kemmerer, Wyoming for three decades. The PURON enhancement plant is
designed to produce about 6 million tons of high-quality (12.500 BTU/lb) formcoke briquettes per year by drying, devolatilizing. and
briquetting the subbituminous (8,300 BTU/lhl. low-sulfur Powder River Basin coal mined at Cordero. These briquettes are designed
to meet the criteria of the U.S. Clean Air Act.
An air quality permit application had been submitted in late 1994. Decision by the Wyoming Department of Environmental Quality
is expected in early 1995. Construction of the enhancement plant, estimated to require a labor force of 1.200 workers, is scheduled to
be started by March 1995. The plant should be operational bv mid-1997.
Project Cost: $500 million
- COREX-CPICOR INTEGRATED STEEL/POWER PLANT Centerior
Products and Chemicals (C-175)
Energy Corporation, Geneva Steel Company. Air
Selected under the United States Department of Energy (DOE) Clean Coal Technology Demonstration Round 5, this project
will demonstrate the combined production of hot iron via the COREX process and a combined cycle power plant fueled by the
export gas from the COREX process. The proposed plant, producing 1.17 million tons of hot metal per year and 181 MW of
power, will be integrated into the existing steelmaking facility at LTV Steel Company's Cleveland works. In 1994. LTV
withdrew from participation. The participants are meeting with DOE to negotiate a cooperative agreement and obtain ap
proval for relocation of the project to Geneva Steel plant at Vineyard. Utah.
The project will demonstrate the integrated production of liquid iron using the COREX direct iron making process developed
bv Deutsche Voest-Alpine Industrienlagenbau GmbH and the production of electric power from a combined cycle facility
fueled bv a byproduct fuel gas stream from the COREX process. The project, anticipated to start up in 1999, will produce ap
proximately 3.000 tons per day of liquid iron for use in Geneva's steel making process and 250 megawatts of electricity.
4-53
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
Geneva Steel will own and operate the COREX iron making plant, while Air Products will design, build and operate the com
bined cycle power plant as well as an air separation unit which will provide oxygen for the COREX process. The latter two
units will be jointly owned by Air Products and Centerior. The participants are currently discussing with PacifiCoro and others
the potential sale of electrical power generated bv the project.
CRE - SPOUTED BED GASIFIER British
Coal, Otto-Simon Carves (C-190)
A spouted fluidized bed process for making low-BTU fuel gas from coal has been developed by British Coal at the Coal
Research Establishment (CRE). This project was sponsored by the European Economic Community (EEC) originally under
demonstration grants. The results obtained established the basis of a simple yet flexible process for making a gaseous fuel low
in sulfur, tar and dust.
The CRE gasification process is based on the use of a submerged spouted bed. A significant proportion of the gas fluidizing is
introduced as a jet at the apex of a conical base. This promotes rapid recirculation within the bed coals enabling caking to be
processed without agglomeration problems. Coals with swelling numbers up to 65 were processed successfully. The remainder
of the fluidizing gas is added through a series of jets in the cone wall to promote good particle mobility throughout the base
section of the reactor.
An atmospheric pressure process was developed for the production of fuel gas for industrial applications. A 12 tonnes per day
(tpd) atmospheric pressure plant was constructed at CRE during this period. Work on the pilot plant was directed towards
providing design information for a commercial scale plant. A range of commercial gasifiers with a coal throughput typically of
24 to 100 tonnes per day have been developed. To this end a license agreement was signed by OSC Process Engineering Ltd.
(OSC) to exploit the technology for industrial application.
Although OSC has yet to build the first commercial unit, interest has been shown from a large number of potential clients
worldwide.
The application of the process for power generation is now being developed. Various cycles incorporating a pressurized ver
sion of the spouted bed technology have been studied and power station efficiencies up to 50 percent (lower heating value
basis) are predicted. A contract with the EEC to develop a pressurized version commenced in January 1989. A 12 tonne/day
pilot plant capable of operating at pressures up to 20 bar has been constructed and commissioned at CRE. Commissioning of
the plant was completed in June 1990. Since that time over 3000 hours of operation have been completed successfully with a
series of indigenous UK coals reflecting the range of composition available currently to the UK power station market. In addi
tion, an extensive program of cold flow modeling studies have been completed. These and the pilot plant operational data are
now being used to develop designs for commercial scale gasifiers.
The 12 tpd gasifier is now operating with a gas cooler, a ceramic candle filter unit and a gas combustor. Operations on the
modified and extended plant started in 1993 and are continuing on a range of fuels and sorbents. A side stream investigating
hot gas cleansing was commissioned in 1994.
The recent work is supported bv the DTI and EEC, with British Coal partners GEC/Alsham. PowerGen. and Babcock Energy
Ltd. (BEL). BEL has recently taken out a license on the pressurized gasifier.
- CRIEPI ENTRAINED FLOW GASIFIER PROJECT Central Research Institute of Electric Power Industry (Japan), New Energy
and Industrial Technology Development Organization (C-200)
Japan's CRIEPI (Central Research Institute of Electric Power Industry) has been engaged in research and development on
gasification, hot gas cleanup, gas turbines, and their integration into an IGCC (Integrated Gasification Combined Cycle) sys
tem.
An air-blown pressurized two-stage entrained-flow gasifier (2.4 ton per day process development unit) adopting a dry coal feed
system has been developed and successfully operated. This gasifier design will be employed as the prototype of the national
200 ton per day pilot plant. As of late 1994, the gasifier had been operated for 2.179 hours, and tested on 21 different coals.
Research and development on a 200 ton per day entrained-flow coal gasification pilot plant equipped with hot gas cleanup
facility and gas turbine has been carried out extensively from 1986 and will be completed in 1996.
CRIEPI executed a feasibility study of entrained-flow coal gasification combined cycle, supported by the Ministry of Interna
tional Trade and Industry (Mm) and New Energy Development Organization (NEDO). They evaluated eight systems com
bining different methods of coal feed (dry/slurry), oxidizer (air/oxygen) and gas cleanup methods (hot-gas/cold-gas). The op
timal plant system, from the standpoint of thermal efficiency, was determined to be composed of dry coal feed, airblown and
hot-gas cleanup methods. This is in contrast to the Cool Water demonstration plant, which is composed of coal slurry feed,
oxygen-blown and hot-gas cleanup systems.
4-54
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
For the project to build a 200 ton per entrained-flow day coal gasification combined cycle pilot plant, the electric utilities have
organized the "Engineering Research Association for Integrated Coal Gasification Combined Cycle Power Systems (IGC)"
with
10 major electric power companies and CRIEPI to carry out this project supported by MITI and NEDO.
Basic design and engineering of the pilot plant was started in 1986 and manufacturing and construction started in 1988 at the
Nakoso Coal Gasification Power Generation Pilot Plant site. Coal Gasification Tests began in June 1991 with the air blown
pressurized entrained-flow gasifier. Tests also began in 1991 for the hot gas clean-up system and a high temperature gas tur
bine of 1,260C combustor outlet temperature.
Project Cost: 53 billion yen
CTC CONTINUOUS MILD - GASIFICATION PROCESS Coal
Technology Corporation. U.S. Department of Energy (C-202)
CTC. under a cost-shared contract with the U.S. Department of Energy has developed the CTC/CLC process through
laboratory, batch, and 10 ton/day continuous pilot plant operations. The pilot plant operations, begun in 1991. were completed
in 1994. Tests indicate that the unique CTC system, using a wide variety of coal feedstocks, can meet the environmental
criteria of the U.S. Clean Air Act for 1995 and beyond bv using off-gases as heat for the reactors and can produce high quality
coke and char that meets all current quality specifications.
Construction of a commercial CTC/CLC plant is expected to begin in late 1995.
Project Cost: Unknown
- DELAWARE CLEAN ENERGY PROJECT Texaco
208)
Syngas Inc., Star Enterprise, Delmarva Power & Light, Mission Energy (C-
Texaco Syngas Inc., Star Enterprise, a partnership between Texaco and Saudi Refining, Inc., Delmarva Power and Light Co.
and Mission Energy have begun joint engineering and environmental studies for an integrated gasification combined cycle
(IGCC) electrical generating facility. The project calls for the expansion of an powerplant existing adjacent to the Star En
terprise refinery in Delaware City, Delaware. The facility would convert over 2,000 tons per day of high sulfur petroleum coke,
a byproduct of the Star refinery, into clean, gaseous fuel to be used to produce about 200 MW of electrical power in both exist
ing and new power generating equipment.
Completion is planned for mid-1996. The project has the potential to reduce substantially overall emissions at the Delaware
more than double the current electric output and make use of the coke byproduct from the oil refinery. The
City facilities,
Phase I studies will require approximately one year to complete (in 1991) at an estimated cost of $6 million.
The existing powerplant would be upgraded and expanded and would continue to operate as a cogeneration facility.
Project Cost: $400 million
- DESTEC SYNGAS PROJECT Louisiana
Gasification Technology, Inc. a subsidiary of Destec Energy, Inc. (C-210)
The Destec Syngas Project, located in Plaquemine, Louisiana, began commercial operations in April, 1987, operating at rates
up to 105 percent of capacity. As of December 1994 the project has produced 42.1 trillion BTU of on-spec syngas and has
reached 3.369.1 14 tons of coal processed. It has operated for 37.817 hours on coal. A 90-day consecutive production record of
71.2 percent capacity was reached in October 1990. A 30-day consecutive production record of 99 percent availability and
89 percent capacity factor was reached in February 1992.
At full capacity, the plant consumes 2,400 tons of coal per day providing 30 billion BTU per day of medium BTU gas. The
process uses Dow-developed coal gasification technology to convert coal or lignite into medium BTU synthetic gas.
The process uses a pressurized, entrained flow, slagging, slurry-fed gasifier with a continuous slag removal system. Dow's
GAS/SPEC ST-1 acid gas removal system and Unocal's Selectox sulfur conversion unit are also used. Oxygen is supplied by
Air Products.
Construction of the plant was completed in 1987 by Dow Engineering Company. Each gasification module is sized to produce
syngas to power 150-200 megawatt combustion turbines. The project is owned and operated by Louisiana Gasification Tech
nology Incorporated, a wholly owned subsidiary of Houston-based Destec Energy, Inc., a subsidiary of The Dow Chemical
Company.
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SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
In this application, the Destec Syngas Process and the associated process units have been optimized for the production of syn
thetic gas for use as a combustion gas turbine fuel. The project received a price guarantee from the United States Synthetic
Fuels Corporation (now the Treasury Department) which is subject to the amount of gas produced by the project. The amount
of the price guarantee is based on the market price of the natural gas and the production of the project. Maximum amount of
the guarantee is $620 million.
A 30-kilowatt carbonate fuel cell pilot plant has been tested successfully at the Destec site, and has achieved 2.000 hours of
operation during endurance tests on syngas produced at Destec's coal gasification plant.
Project Cost: $72.8 million
DUNN - NOKOTA METHANOL PROJECT The
Nokota Company (C-215)
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, in
cluding carbon dioxide for enhanced oil recovery in the Williston and Powder River Basins. $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 released the final En
vironmental Statement on February 26, 1988.
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. 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 plans to work with closely lo
cal community leaders, informing them of the types and timing of socioeconomic impact associated with this project.
Dunn-Nokota would produce approximately 81,000 barrels of chemical grade methanol, 2,400 barrels of gasoline blending stock
(naphtha) and 300 million standard cubic feet of pipeline quality, compressed carbon dioxide per day from 40,000 tons of lig
nite (Beulah-Zap bed).
Additional market studies will determine if methanol production will be reduced and gasoline or substitute natural gas
coproduced.
product Existing pipelines and rail facilities are available to provide 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 com
plete and in commercial operation, employment would be about 1,600 personnel at the plant and 500 personnel in the adjacent
coal mine.
Nokota's schedule for the project 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: $2.6 billion (Phase I and II)
$0.2 billion (C02 compression)
$0.1 billion (Pipeline interconnection)
$0.4 billion (Mine)
-
ELSAM GASIFICATION COMBINED CYCLE PROJECT Elsam
(C-218)
Elsam, the Danish utility for the western part of Denmark is now working on two new 400-megawatt units, with 285 bar live steam
pressure and a live-steam, reheat, and double reheat of 580C.
4-56
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
- ENCOAL LFC DEMONSTRATION PLANT ENCOAL
Corporation, United States Department of Energy (C-221)
ENCOAL Corporation, a wholly owned subsidiary of Zeigler Coal Holding Company of Fairview Heights. Illinois, received funding
from the Department of Energy's Clean Coal Technology Round 3 Program for a 1,000 ton per day mild gasification plant at the
Buckskin Mine in Northeastern Wyoming. The government funded 50 percent of the original $72.6 million total cost. The
demonstration plant utilizes the LFC technology developed by SGI International.
The plant is designed to be operated as a small commercial facility and produce sufficient quantities of process derived fuel and
coal derived liquids to conduct full scale test burns of the products in industrial and utility boilers. Feed coal for the plant js pur
chased from the Buckskin Mine which is owned and operated by Triton Coal Company (a wholly owned subsidiary of SMC Mining
Company, also a Zeigler subsidiary"). Other United States coals may be shipped to the demonstration plant from time to time for
test processing, since the process appears to work well on lignites and some Eastern bituminous coals.
A Permit to Construct was received from the Wyoming Department of Environmental Quality, Air Quality
Division for the
demonstration plant. It was approved on the basis of the use of best available technology for the control of SO , NO , CO,
hydrocarbons and particulates. The plant is designed to have no solid or liquid wastes and source water requirements are very
small.
Ground was broken at the Buckskin mine site for the commercial process demonstration unit in late 1990. Construction was com
pleted by mid-1992. The plant, built to process 1,000 tons of coal per day and produce 150,000 barrels of liquids per year plus
180,000 tons of upgraded solid fuel, completed the first 24 hour integrated test run in June 1992. During this run it operated at
about 70 percent of its capacity and made specification solid and liquid fuels. Following this initial run, the plant was operated in a
test mode through June 1993. completing 15 runs of increasing duration.
The plant was closed down for a period in 1993 for the completion of plant improvements and the installation of additional equip
ment. In January 1994. the new equipment was commissioned and the operations and testing programs resumed. These programs
culminated in a 68 day continuous run in April through June 1994. The plant was then declared operational, although it is now
limited to 50 percent of its design capacity due to the capacity of the new equipment.
Since that time the plant has been operating in a production mode. More than 4.200 hours of operation were logged in 1994.
Seven unit trains, containing up to 90 percent PDF, the solid fuel, have been shipped to utilities in Hugo. Oklahoma and Mus-
cateen. Iowa. Both customers were very satisfied with their test burns. Nearly 1,000.000 gallons of CDL. the liquid product, have
been shipeed to various industrial customers. Some blending problems have surfaced, but the test burns were largely successful.
ENCOAL received approval from the DOE for a two year extension of the operating phase of the project in October 1994. The
$18,100.000 extension, shared equally by ENCOAL and the government, provides funds for the completion of the test bum
program, processing of alternate coals, development of cost and design data for commercial application of the technology and
achieving full capacity operation.
A contract is in place with Wisconsin Power and Light for delivery of 30.000 tons of high-BTU. low-sulfur PDF for test burns at its
coal-fired powerplants. Texpar Energy Inc. has agreed to buy up to 135.000 barrels of the CDL industrial fuel each year-
Total Project Cost: $90.7 million
- FIFE IGCC POWER STATION Fife
Energy Ltd. (C-224)
Fife Energy Ltd., a Scottish power company, is developing the United Kingdom's first integrated gasification combined cycle power
station in Fife, Scotland. The IGCC to be employed at the facility is based on British Gas/Lurgi's slagging gasification technology,
which converts up to 94 percent of the coal input into clean syngas. The IGCC will produce less than 10 percent of the U.S. stan
dard for emissions in new power sources, said a Fife spokesperson.
4-57
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
FRONTIER - ENERGY COPROCESSING PROJECT Canadian
Energy Developments, Kilborn International (C-225)
The Frontier Energy project is a commercial demonstration of a state-of-the-art technology for the simultaneous conversion of
high sulfur coal and heavy oil (bitumen) to low sulfur, lean burning, liquid hydrocarbon fuels plus the cogeneration of electricity for
export. Two main liquid hydrocarbon products are produced, a naphtha fraction which can be used as a high value petrochemical
feedstock or can be processed further into high octane motor fuel and low sulfur fuel oil that can be used to replace high sulfur coal
in thermal powerplants. Cogenerated electricity, surplus to the requirements of the demonstration plant, is exported to the utility
electrical system.
Frontier Energy is a venture involving Canadian Energy Developments of Edmonton, Alberta, Canada and Kilborn International
Ltd. of Tucson, Arizona.
The technology being demonstrated is the CCLC Coprocessing technology in which a slurry of coal and heavy oil are simul
taneously hydrogenated at moderate severity conditions (temperature, pressure, residence time) to yield a low boiling range
(C -975 degrees F) distillate product.
The CCLC Coprocessing technology is being developed by Canadian Energy Developments Inc. in association with the Alberta Of
fice of Coal Research and Technology (AOCRT) and Gesellschaft fur Kohleverflussigung GmbH (GfK) of Saarbrucken, West
Germany.
Two integrated and computerized process development units (PDUs), 18-22 pounds per hour feed rate, are currently being
operated to confirm the technology in long duration runs, to generate operating data for the design of larger scale facilities and to
produce sufficient quantities of clean distillate product for secondary hydrotreating studies and market assessment studies.
Canadian Energy and GfK are planning to modify an existing 10 ton/day coal hydrogenation pilot plant to the CCLC Coprocessing
configuration and to use it to confirm the coprocessing technology in large pilot scale facilities while feeding North American coals
and heavy oils. Data from this large pilot scale facility will form the basis of the design specification for the Frontier Energy
Demonstration Project. Frontier expects the coprocessing plant to be under way in the spring of 1994.
The demonstration project will process 1,128 tons per day of Ohio No. 6 coal and 20,000 barrels per day of Alberta heavy oil. An
unsuccessful application was made for Clean Coal Technology (CCT) funds in Round III. The project intends to file an application
for CCT funds in Round V.
- GE HOT GAS DESULFURIZATION GE
Environmental Services Inc. and Morgantown Energy Technology Center (C-228)
This project was designed to demonstrate the operation of regenerable metal oxide hot gas desulfurization and particulate removal
system integrated with the GE air blown, coal gasifier at the GE Corporate Research and Development Center in Schenectady,
New York.
Construction of the demonstration facility was completed by 1990 and several short duration runs were done to allow a long dura
tion (100 hour) run to be completed in 1991. The facility gasifies 1700 pounds per hour of coal at 280 psig. Outlet gas temperature
ranges from 830-1 150F.
During a 4.5 hour period in a 60 hour run the hot gas cleanup system achieved an overall sulfur removal of 95.5 percent.
- GREAT PLAINS SYNFUELS PLANT Dakota
Gasification Company (C-240)
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 applications were many filed with the Federal Power Commission (now FERC). The original plans called
for a plant designed to produce 250 million cubic feet per day to be constructed by late 1981. However, problems in financing the
plant delayed the project and in 1976 the plant design 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 synthetic natural gas (SNG) sold on
an unregulated basis. In April 1981, an agreement was reached whereby the SNG would be sold under a formula that would esca
late quarterly according to increases in the Producer Price Index with a cap during the first 5 years of operation equal to the
energy-equivalent price of No. 2 Fuel Oil, a cap during the fifth through tenth year of operation equal to the pipelines highest
10 percent gas purchases or the average border price paid by the pipelines and after the tenth year, the only remaining price cap
4-58
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
would be the highest 10 percent price cap. 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; 15 percent
from ANR's interest and 25 percent from Transco.
Full-scale construction did not commence until August 6, 1981 when the United States Department of Energy (DOE) announced
the approval of a S2.02 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 con
nect the plant to the interstate natural gas system, and a contingency for overruns. Final approval of the loan guarantee was
received on January 29, 1982. The project sponsors were generally committed to providing one dollar of funding for each three dol
lars received under the loan guarantee up to a maximum of $740 million of equity funds. The project's final cost was approximately
$2 billion with a %\5 billion provided pursuant to the DOE guarantee and $500 million by the five partners.
The project was designed to produce an average of 125 million cubic feet per day (based on a 91 percent onstream factor, i.e., a
1373 million cubic foot per day design capacity) of high BTU pipeline quality SNG, 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 16,000 tons per day of North Dakota lignite were ex
pected to be required as feedstock.
In August, 1985 the sponsors withdrew from the project and defaulted on the loan, and DOE began operating the plant under a
contract with the ANG Coal Gasification Company. The plant successfully operated throughout this period and earned revenues in
excess of operating costs. The SNG is marketed through a 34 mile long pipeline connecting the plant with the Northern Border
pipeline which in turn transports the SNG to Ventura, Iowa.
In parallel with the above events, DOE and the Department of Justice (DOJ) filed suit in the District Court 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 the gas purchase agreements valid, that state law was not applicable and that plain
tiffs (DOE/DOJ) were entitled to a summary judgment for foreclosure. A foreclosure sale was held and DOE obtained legal title
to the plant and its assets on July 16, 1986. This decision was upheld by the United States Court of Appeals for the Eighth Circuit
on January 14, 1987. On November 3, 1987, the Supreme Court denied a petition for a writ of certiorari.
The North Dakota District Court also held that the defendant pipeline companies were liable to the plaintiffs (DOE/DOJ) for the
difference between the contract price and the market value price. This decision was upheld by the United States Court of Appeals
for the Eighth Circuit on May 19, 1987. No further opportunity for appeal exists and the decisions of the lower court stands.
In early 1987, the Department of Energy hired Shearson Lehman Bros, to help sell the Great Plains plant. In August, 1988 it was
announced the Basin Electric Power Cooperative had submitted the winning bid for approximately $85 million up-front plus future
with profit-sharing the government and a waiver of production tax credits. Two new Basin subsidiaries, Dakota Gasification Com
pany (DGC) and Dakota Coal Company, operate the plant and manage the mine respectively. Ownership of the plant was trans
ferred on October 31, 1988.
Under Dakota Gasification ownership, the plant has been producing SNG at over 125 percent of design capacity on an annual
basis.
In 1989, DGC began concentrating on developing revenue from byproducts. On February 15, 1991, a phenol recovery facility was
completed. This project produces over 2 million gallons of phenol annually, providing manufacturers an ingredient for plywood
and chipboard resins. The first railcar of phenol was shipped in January 1991. DGC has signed contracts with three firms to sell
all of its output of crude cresylic acids, which it produces from its phenol recovery project.
Construction of a facility to extract krypton/xenon from the synfuel plant's oxygen plant was completed in March 1991. DGC
signed a 15-year agreement in 1989 with Praxair (formerly Linde Division of Union Carbide Industrial Gases Inc.) to sell all of the
plant's production of the krypton/xenon mixture. The first shipment of the product occurred on March 15, 1991. In March 1993,
DGC installed a hydrotreater which enabled it to commence the sale of the plant's naphtha production. Other byproducts being
sold from the plant include anhydrous ammonia, sulfur and liquid nitrogen. Argon, carbon dioxide, ammonium sulfate and cresote
are also potential byproducts.
In late 1990 DGC filed with the North Dakota State Health Department a revision to the applications to amend the Air Pollution
Control Permit to Construct. The revised application defines the best available control technology to lower SO and other emis
sions at the plant. In 1993, the North Dakota Department of Health approved the permit for the flue gas desulfurization system at
the Great Plains Synfuels Plant. In March 1994, DGC announced it would install a flue gas scrubber which will use anhydrous am
monia as the reagent, a process that will produce ammonium sulfate, a commercial fertilizer, which DGC intends to market.
DGC has 4 years to complete construction of the main stack scrubber. The estimated cost of this environmental improvement is
$100 million.
4-59
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
In late 1990, DGC and DOE initiated a lawsuit against the four pipeline company purchasers contracted to buy SNG. The issues in
these proceedings involve: the extent of the pipeline firms'
obligations to take or pay for SNG; whether the sales price of SNG has
been understated; and whether the adjustment made by DGC to the rate the plant charges the pipeline companies to transport
their SNG to a point of interconnection on the Northern Border Pipeline system is in accordance with contract terms. An October
1994 trial date had been set. In April 1994, DGC, DOE and the pipelines announced out-of-court settlements of the litigation.
Pursuant to the settlements, which are subject to a final, non-appealable FERC approval, the pipelines paid DGC $37 million in
past due amounts, upon final FERC approval will pay DGC the market price for its synthetic gas and will make monthly demand
payments over a seven-year period, with a present value (discounted at 10 percent) of approximately $360 million as of August
1994. After these monthly payments have been made, DGC will only be paid the market price through the remaining term of the
gas purchase agreements which expire on July 31, 2009. Pending FERC approval DGC is being paid $3.70 per MMBTU. Until
receipt of a final, nonappealable FERC approval, the difference between $3.70 and the market price is being credited, on a formula
basis, against the $360 million demand payment obligation. As part of the settlement arrangements, DGC will pay DOE
$25 million over this seven-year period and has agreed to enhanced revenue sharing with DOE. As a result of these settlement
agreements, the lawsuit has been stayed pending final FERC approval and the payment of the 84-monthly demand payments.
Project Cost: $2.1 billion overall
HOT GAS - DESULFURIZATION IN A TRANSPORT REACTOR The
MW. Kellogg Company (MWK) and U.S. Department of
Energy. Morgantown Energy Technology Center (DOE/METC) (C-260)
Successful proof-of-concept tests of the MWK Transport Reactor Test Unit in HDG have been completed at the Kellogg Technol
ogy Development Center. HDG is a key process step in IGCC which avoids costs of gas cooling and production of difficult-to-treat
liquid waste streams. The use of a transport reactor results in lower capital and operating costs that the fixed and fluid bed reac
tors generally employed in HGD.
DOE/METC plans to incorporate the MWK Transport Reactor in their state-of-the-art Hot Gas Desulfurization Unit.
Demonstration tests are scheduled to begin in late 1996.
- HUMBOLT ENERGY CENTER PROJECT Continental
Energy Associates and Pennsylvania Energy Development Authority (C-265)
Greater Hazleton Community Area New Development Organization, Inc. (CAN DO, Incorporated) built a facility in Hazle
Township, Pennsylvania to produce low BTU gas from anthracite. Under the third general solicitation, CAN DO requested price
and loan guarantees from the United States Synthetic Fuels Corporation (SFC) to enhance the facility. However, the SFC turned
down the request, and the Department of Energy stopped support on April 30, 1983. The plant was shut down and CAN DO
solicited for private investors to take over the facility.
The facility has been converted into a 135 megawatt anthracite refuse-fueled integrated gasification combined cycle cogeneration
plant. Gas produced from anthracite coal in both the original facility and in new gasifiers is being used to fuel the cogeneration
facility in conjunction with turbines to produce electricity. One hundred megawatts of power per hour will be purchased by the
Pennsylvania Power & Light Company over a 20-year period and the remainder of the power purhcased by Con-Edison. Steam is
also produced which is available to industries within Humboldt Industrial Park at a cost well below the cost of in-house steam
production. The combined cycle cogeneration plant has been in operation since 1990.
Project Cost: over $100 million
- HYCOL HYDROGEN FROM COAL PILOT PLANT Research
(C-270)
Association for Hydrogen from Coal Process Development (Japan)
In Japan, the New Energy and Industrial Technology Development Organization (NEDO)
has promoted coal gasification tech
nologies based on the entrained bed. These include the HYCOL process for hydrogen making and the IGC process for integrated
combined cycle power generation.
The HYCOL gasifier was evaluated as a key technology for hydrogen production, since hydrogen is the most valuable among coal
gasification products. NEDO decided to start the coal-based hydrogen production program at a pilot plant beginning in fiscal year
1986. Construction of the pilot plant in Sodegaura, Chiba was completed in August, 1990. Operational research was to begin in
1991 after a trial run.
The key technology of this gasification process is a two-stage spiral flow system. In this system, coal travels along with the spiral
flow from the upper part towards the bottom because the four burner nozzles of each stage are equipped in a tangential direction
to each other and generate a downward spiral flow. As a result of this spiral flow, coal can stay for a longer period of time in the
chamber and be more completely gasified.
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SYNTHETIC FUELS REPORT JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
In order to obtain a higher gasification efficiency, it is necessary to optimize the oxygen/coal ratio provided to each burner. That
is, the upper stage burners produce reactive char and the lower stage burners generate high temperature gas. High temperature
gas keeps the bottom of the gasifier at high temperature, so molten slag falls fluently.
The specifications and target of the pilot plant are as follows:
Coal feed
Pressure
Temperature
50 ton per day
30 kg/cm g
About 1,800C
Oxidant Oxygen
Coal Feed
Slag
Dry
Discharge Slag Lock Hopper
Refractory Lining
Water-cooled slag coating
Dimensions Outer Pressure Vessel 2 Meters Diameter, 133 Meters Height
Carbon Conversion 98 Percent and more (target)
Cold Gas Efficiency
78 Percent and more (target)
Continuous Operation 1.000 Hours and more (target)
The execution of this project is being carried out by the Research Association for Hydrogen from Coal Process Development, a
joint undertaking by nine private companies, and is organized by NEDO. Additional research is also being conducted by several
private companies to support research and development at the pilot plant. The nine member companies are:
Idemitsu Kosan Co., Ltd.
Osaka Gas Co., Ltd.
Electric Power Development Company
Tokyo Gas Co., Ltd.
Japan Energy Corporation
Toho Gas Co., Ltd.
The Japan Steel Works, Ltd.
Hitachi, Ltd.
Mitsui SRC Development Co., Ltd.
NEDO succeeded in maintaining 1,149 hours of continuous operation and achieved the target gasification efficiencies of the
HYCOL pilot plant in January 1994.
- IGT MILD GASIFICATION PROJECT Institute
ment Board (C-272)
of Gas Technology (IGT), Kerr-McGee Coal Corporation, Illinois Coal Develop
Kerr-McGee Coal Corporation is heading a team whose goal is to develop the Institute of Gas Technology's (IGT) MILDGAS ad
vanced mild gasification concept to produce solid and liquid products from coal. The process uses a combined fluidized-
bed/entrained-bed reactor designed to handle Eastern caking and Western noncaking coals.
The 24 ton per day facility will be built at the Illinois Coal Development Park near Carterville, Illinois. The 3-year program will
provide data for scaleup production, coproducts for testing, preparation of a preliminary design for a larger demonstration unit,
and the development of commercialization plans.
Kerr-McGee Coal Corporation will provide the coal and oversee the project. Bechtel Corporation will design and construct the
process development unit, and Southern Illinois University at Carbondale will operate the facility. IGT will supply the technology
expertise and supervise the activities of the team members.
The technology will produce a solid char that can be further processed into form coke to be used in blast furnaces as a substitute
for traditional coke. Liquids produced by the process could be used to manufacture such materials as roofing and road binders,
electrode binders, and various chemicals.
- IMHEX MOLTEN CARBONATE FUEL CELL DEMONSTRATION M-C
son Services, Institute of Gas Technology (C-273)
Power Corporation, Bechtel Group, Stewart and Steven
M-C Power has a goal of bringing a market-responsive, natural gas fueled IMHEX molten carbonate fuel cell (MCFC) to the
power generation industry by the end of the 1990s. The technology for this MW-Class (1 MW nominal capacity) power plant for
use in distributed generation and cogeneration applications is being developed through a step-wise demonstration program which
began in 1990 and will continue through 1998. M-C Power leads a team which consists of M-C Power, the Bechtel Group. Stewart
and Stevenson Services, Inc. and the Institute of Gas Technology. This team provides both the market and power plant expertise
for this commercialization effort.
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SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
M-C Power's IMHEX stack technology will be demonstrated in commercial-scale hardware over the next two years. A process
development power plant was installed at Unocal's Fred L Hartley Research Center in Brca. California and operation will begin in
early 1995. This unit will be followed by a second 250 kW integrated MCFC power plant scheduled for delivery in 1995. San Deigo
Gas & Electric will host this unit at the Naval Air Station Miramar. These demonstrations, in combination with the initial year ac
tivities under the Product Design and Improvement award, will verify the technology and design concepts. During early 1996 the
IMHEX team will solicit commercial orders for power plant deliveries beginning in 1999.
The U.S. Department of Energy recently announced a $103.9 million five-year cooperative agreement with M-C Power. In addition
to funding provided bv DOE ($70.6 million), the team and the site host, support is being provided bv the Electric Power Research
Institute (EPRJ). the Gas Research Institute (GRI) and several electric and/or gas utilities.
ISCOR - MELTER-GASIFIER PROCESS ISCOR,
Voest-Alpine Industrieanlagenbau (VAI) (C-275)
An alternative steel process that does not use coke has been commercialized at ISCOR's Pretoria works (South Africa). Designed
and built by VAI (Linz, Austria), the plant converts iron ore and coal directly into 300,000 tons per year of pig iron in a meltergasifier,
referred to as the COREX process. Conventional techniques require use of a coke oven to make coke, which is then
reacted with iron ore in a blast furnace. Production costs at the Pretoria plant are said to be 30 percent lower than conventional
method costs.
Startup of the plant was in November 1989. Two separate streams of materials are gravity fed into the melter-gasifier. One stream
is coal (03-0.7 tons of carbon per ton of pig iron produced) with ash, water and sulfur contents of up to 20 percent, 12 percent and
13 percent, respectively. Lime is fed together with the coal to absorb sulfur. The second stream-iron ore in lump, sinter or pellet
form-is first fed to a reduction furnace at 850-900 degrees C and contacted with reducing gas (65-70 percent CO and 20-25 percent
H,,) from the melter-gasifier. This step reduces the ore to 95 percent metal sponge iron. The metallization degree of the sponge
ir6n where it comes into contact with the 850-900 degree C hot reducing gas produced in the reduction furnace, is 95 percent on
average.
High plant availability, low maintenance and cost savings led to blast furnace production at ISCOR. Pretoria Works, being totally
replaced by the COREX Process. The last blast furnace was shut down in March 1992. making it the first steel plant world-wide to
produce hot metal exclusively by the COREX Process.
The sponge iron proceeds to final reduction and melting in the melter-gasifier, where temperatures range from 1,100 degrees C
near the top of the unit to 1300-1,700 degrees C at the oxygen inlets near the bottom. Molten metal and slag are tapped from the
bottom. As a byproduct of the hot metal production export gas is obtained, which is a high quality gas with a caloric value of ap
2000 kcal/Nm Voest-Alpine says the pig iron quality matches that from blast furnaces, and that costs were $150 per
proximately .
ton in 1990.
Other VAI COREX plants have been ordered world-wide. POSCO. Korea, is planning a 2.000 ton/day plant to begin operations
in 1995. JINDAL, India, has contracted for a COREX plant with a 600.000 ton annual production. In late 1994. HANBO. Korea
has ordered two COREX plants.
VAI is also collaborating with Geneva Steel to demonstrate the technology in the United States. Geneva Steel's Utah Vineyard
site is to be the location for the COREX plant, the first facility in the USA. Air Products and Centerior Energy are consortial
partners of Geneva Steel.
- K-FUEL COMMERCIAL FACILITY KFx Inc. (C-290)
The K-Fuel process was invented by Edward Koppelman and developed further at SRI International between 1976 and 1984. In
1984, K-Fuel Partnership, the predecessor to KFx Inc. (KFx), was formed to commercialize the process. KFx owns the worldwide
patents and international licensing rights to the process in the United States and 37 foreign countries.
KFx is currently commercializing two of the principal methods to produce its clean fuel: a steam-based technology known as Series
"B,"
and a nitrogen-based Series "C"
technology. Both technologies physically and chemically transform high-moisture, low-energy,
low-grade coal, lignite, peat or other organic feedstocks (e.g., bagasse, biomass, municipal solid waste, sludge, wood waste) into a
low-moisture, high-energy fuel product. K-Fuel from a low-rank coal feedstock has a pound-for-pound heating value 60 percent
higher than that of the raw coal. When burned, this fuel produces less than 0.8 pounds of SO /MMBTU. Additionally, lab tests
indicate that fuel NO emissions can be up to 80 percent less than those generated when burning conventional bituminous coals.
KFx, headquartered in Denver, Colorado, owns and operates a full demonstration facility, research center, and a Class A
laboratory at the Fort Union Coal Mine near Gillette, Wyoming. The Series "A"
(hot-gas based) pilot facility, which can produce
25 tons of K-Fuel per day, has been in operation since July 1988. The Series "B"
pilot unit demonstrates the technology at bench-
scale. The Series "C scale-up facility, completed and successfully proven for commercial operation in late 1993, produces two tons
per hour. Harris Group, a Denver-based engineering firm, and Western Research Institute of Laramie, Wyoming, have completed
an engineering and "C"
feasibility study on the Series process that proved the technology both feasible and economical.
4-62
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
In September 1994. KFx signed a Memorandum of Understanding with Thermo Energy Systems Corporation (a subsidiary of
Thermo Electron) and SDS Petroleum. Inc.. to finance, construct, own and operate a 500.000 ton per year commercial plant to be
built near Gillette. Wyoming utilizing the Koppelman Series "C technology. Sales agreements with selected customers are being
negotiated.
""' " "
KFx has identified three specific international opportunities in the Czech Republic. Turkey, and Indonesia, and is investigating
other potential international projects -
Project Cost: $32 million Wyoming Series "C"
especially in India. Russia. China. Korea, and Taiwan.
KOBRA HIGH - TEMPERATURE WINKLER IGCC DEMONSTRATION PLANT RWE
Energie AG (C-294)
In 1992 RWE Energie AG, a sister company of Rheinbraun AG, has decided to build a combined-cycle power station with in
tegrated gasification based on the High Temperature Winkler (HTW) technology. Raw brown coal with 50 to 60 percent moisture
will be dried down to 12 percent, gasified and dedusted with ceramic filters after passing the waste heat boiler. After the conven
tional scrubber unit, the gas will be desulphurized and fed to the combined cycle process with an unfired heat recovery steam gen
erator. This project is referred to as KOBRA (in German: Kombikraftwerk mit Braunkohlenvergasung, i.e. combined-cycle power
station with integrated brown coal gasification).
The capacity of the KOBRA plant slightly exceeded 300 MWe. The fuel gas was produced in this demonstration plant by one air-
blown gasifier. having a throughput of 3.800 tons per day of dried lignite. The gas turbine had a rated capacity of about 200 MWe,
and the overall plant reached a net efficiency of 45 percent.
To implement this project, a task force comprising staff members of both RWE Energie AG and Rheinbraun AG started working
in 1992. Permit engineering was completed in late 1993. Building and operating permits are expected to be issued in 1995.
Of crucial importance for reaching a high overall efficiency is the coal drying system which reduces the moisture content of the raw
brown coal to 12 percent. For this step, Rheinbraun's WTA process was employed (WTA means fluidized-bed drying with internal
waste heat utilization).
To demonstrate the technology, a plant having a capacity of 20 tons per hour of dried lignite was started up in 1992 for testing pur
poses. Engineering of this project was handled by Lurgi GmbH.
By the end of 1992, all process engineering criteria had been determined. The commissioning of the demonstration plant was ex
pected to begin in mid-1996.
In 1994. RWE Energie AG decided to postpone the KOBRA demonstration project and start a three-year R&D program to deter
mine reliability of components and processes, to reduce operational and investment costs, and to increase efficiency.
- LAKESIDE REPOWERING GASIFICATION PROJECT Combustion
(DOE)(C-320)
Engineering, Inc. and United States Department of Energy
The project will demonstrate Combustion Engineering's pressurized, airblown, entrained-flow coal gasification repowering technol
ogy on a commercial scale. The syngas will be cleaned of sulfur and particulates and then combusted in a gas turbine (40 MWe)
from which heat will be recovered in a heat recovery steam generator (HRSG). Steam from the gasification process and the HRSG
will be used to power an existing steam turbine (25 MWe).
The project was selected under Round II of the Clean Coal Technology Program for demonstration at the Lakeside Generating
Station of City Water, Light and Power, Springfield, Illinois. The project demonstrates airblown gasification at high efficiency with
99 percent sulfur capture and 90 percent NO reduction. A new zinc titanate hot gas cleanup system is incorporated to provide
even lower sulfur emissions.
Preliminary plant design and definitive cost estimates have been developed for DOE and project review. ABB is focusing on the
requirement of the electric power generation market in the design of this plant.
Due to increased costs for the procurement and construction of the plant, the project is on hold while alternate sites are being con
sidered.
Project Cost: To be determined
4-63
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
LAPORTE ALTERNATIVE FUELS DEVELOPMENT PROGRAM -
stitute, and United States Department of Energy (DOE) (C-330)
Air
Products & Chemicals. Inc., Electric Power Research In
Air Products and Chemicals, Inc. is proposing a 36-month program to develop technologies for the conversion of coal-derived syn
thesis gas to oxygenated hydrocarbon fuels, fuel intermediates, and octane enhancers, and to demonstrate the most promising tech
nologies in DOE's Slurry Phase Alternative Fuels Development Unit (AFDU) at LaPorte, Texas. With emphasis on slurry phase
processing, the program will initially draw on the experiences of the successful Liquid Phase Methanol program. (LPMEOH) See
completed project "LaPorte Liquid Phase Methanol Synthesis"
in December 1991 Synthetic Fuels Report for details on the
LPMEOH project.
In the spring of 1992, methanol produced using the LaPorte Liquid Phase Methanol Synthesis Process out performed commercial
chemical-grade methanol in diesel engine runs. In a standard 100 hour test, 2300 gallons of raw methanol from the LaPorte Plant
were run through a typical bus cycle simulation.
The alternative fuels development program aims to continue the investigations initiated in the above research program, with the
principal objective being demonstration of attractive fuel technologies in the LaPorte AFDU. The focus is continued in pilot plant
operations after a 12-18 month period of plant modifications. Certain process concepts such as steam injection, and providing H
via in situ water-gas shift, will assist in higher conversions of feedstocks which are necessary, particularly for higher alcohol syn
thesis.
Four operating campaigns are currently envisaged. The first will focus on increased syngas conversion to methanol using steam in
jection and staged operation. The second will demonstrate production of dimethyl ether/methanol mixtures to (1) give optimum
syngas conversion to storable liquid fuels, (2) produce mixtures for both stationary and mobile fuel applications, and (3) produce
the maximum amount of DME, which would then be stored as a fuel intermediate for further processing to higher molecular-
weight oxygenates. Economic, process, and market analyses will provide guidance as to which of these scenarios should be em
phasized. The third and fourth campaigns will address higher alcohols or mixed ether production.
In the laboratory, the principal effort will be developing oxygenated fuel technologies from slurry-phase processing of coal-derived
syngas using two approaches, (1) fuels from syngas directly, and (2) fuels from DME/methanol mixtures. In fiscal year 1993, Air
Products will demonstrate, at DOE's LaPorte Alternative Fuels Development Unit, the synthesis of methanol/isobutanol mixtures,
which can be subsequently converted to MTBE. Preliminary economic analyses have indicated that isobutanol and MTBE from
coal could be cost competitive with conventional sources by the mid- to late-1990s.
Air Products has already demonstrated the unique ability of DME to act as a chemical building-block to higher molecular-weight
oxygenated hydrocarbons. Air Products has also successfully developed and demonstrated a one-step process for synthesizing
dimethyl ether (DME) from coal-derived synthesis gas. In this process, the reactions are carried out in a three-phase system with
the catalyst suspended in an inert liquid medium. The liquid absorbs the heat that is released as the chemical reactions occur, al
lowing the reactions to take place at higher, more efficient rates and protecting the heat-sensitive catalysts necessary for the con
version process. This results in a 30 to 40 percent increase in the rate of methanol production.
Project Cost: $20.5 million FY91-FY93
- LIQUID PHASE METHANOL PROCESS DEMONSTRATION Air
U.S. Department of Energy (C-335)
Products and Chemicals, Inc., Eastman Chemical Company, and
Air Products and Chemicals, Inc. and Eastman Chemical Co. plan to demonstrate the production of liquid phase methanol
Round 3 award. The liquid phase methanol synthesis
(LPMEOH) under a U.S. Department of Energy Clean Coal Technology
process is more efficient than the conventional gas phase process and is better suited for processing the gases produced by modern
coal gasifiers. Producing methanol as a coproduct in combined cycle coal gasification facilities has distinct advantages. The gasifier
can be run continuously at its most efficient level. During periods of low power demand, synthesis gas made by the gasifier would
be converted to methanol for storage. At peak power demand, this methanol could be used to supplement the combustion turbine,
thus lowering the size of the gasifier that would be required if the gasifier alone had to meet peak electrical demand.
The project was originally slated for location at the Texaco Cool Water plant in Dagget, California, but was moved to Eastman
Chemical Company's coal gasification facility in Kingsport, Tennessee. The Eastman Chemical site offers the advantage of the use
of existing coal gasifiers with little modification. The unit will produce at least 200 tons of methanol per day at the Kingsport loca
tion.
Project Cost: $213.7 million; $92 million provided by U.S. Department of Energy
LUBECK IGCC DEMONSTRATION PLANT- PreussenElektra (C-339)
The project of PreussenElektra/Germany has a capacity of 320 MWe net based on hard coal and a net efficiency of 45 percent.
PRENFLO gasification technology has been chosen for the gasifier.
4-64
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
- LU NAN AMMON1A-FROM-COAL PROJECT China
National Technical Import Corporation (C-360)
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 375 tons per day Texaco
gasifier at the 200 metric tons per day Lu Nan Ammonia Complex in Tengxian, Shandong Province. The gasifier was completed in
1991, and has replaced an obsolete coal gasification facility with the more efficient Texaco process.
Project Cost: Not Disclosed
- MILD GASIFICATION PROCESS DEMONSTRATION UNIT Coal
Energy (DOE) (C-370)
Technology Corporation and United States Department of
Since the mid-1980s, Coal Technology Corporation (CTC), formerly UCC Research Corporation, has been investigating the
pyrolysis of coal under sponsorship of DOE's Morgantown Energy Technology Center. This work initially was the development of
a batch process demonstration unit having a coal feed capacity of 120 pounds per batch. The process produced coal liquids to be
used for motor fuels and char to be potentially used for blast furnace coke and offgas.
In January 1988, DOE and CTC cost shared a $3,300,000 three-year program to develop a process demonstration unit for the
pyrolysis of 1,000 pounds/hour of coal by a continuous process. This work involved a literature search to seek the best possible
process; and then after small scale work, a proprietary process was designed and constructed. The unit began operating in
February 1991. Test runs have been made with a variety of caking bituminous coals and no major differences in coke making were
observed.
In the CTC mild gasification process, coal is heated from ambient temperature to around 400F in the first heat zone of the reac
tor, and then to 800 to 900F in the second heat zone. Lump char discharged from the reactor is cooled in a water jacketed auger
to 300F. At present, the char is stored, but in an integrated facility, the cooled char would then be crushed, mixed with binder
material and briquetted in preparation for conversion to coke in a continuous rotary hearth coker. The moisture and volatile
hydrocarbons produced in the reactor are recovered and separated in scrubber/condensers into noncondensibles gases and liquids.
The coal liquid, char, and coke (CTC/CLC) mild gasification technology to be demonstrated involves the production of three
products from bituminous caking type coals: coal liquids for further refining into transportation fuels, char for ferro-alloy produc
tion, and formed coke for foundry and blast furnace application in the steel industry. The CTC/CLC process will continuously
produce blast furnace quality coke within a 2-hour duration in a completely enclosed system. The coal liquids will be recovered at
less than 1,000F for further refining into transportation fuel blend stock.
The processing involves feeding coal into CTC's proprietary mild gasification retort reactors at operating about 1,000F to extract
the liquids from the coal and produce a devolatized char. The hot char is fed directly into a hot briquette system along with addi
tional coking coal to form "green"
briquettes. The green briquettes will directly feed into the specially designed rotary hearth con
tinuous coking process for final calcining at 2,000*r to produce blast furnace formed coke. The small amount of uncondensed
gases will be recirculated back through the system to provide a balanced heat source for the mild gasification retorts and the rotary
hearth coking process.
Research work on the pilot plant is continuing with emphasis on the production of 4"x5"x6"
briquettes for the foundry industry.
The process is now ready for commercial use. Several major companies are in negotiations with CTC for licensing and building
commercial coke plants using the CTC/CLC process. The first demonstration plant, planned to be build in West Virginia, is per
mitted to process 250.000 tons of coal per year.
- MONGOLIAN ENERGY CENTER People's
Republic of China (C-390)
One of China's largest energy and chemical materials centers is under construction in the southwestern part of Inner Mongolia.
The first-phase construction of the Jungar Coal Mine, China's potential largest open-pit coal mine with a reserve of 25.9 billion
tons, is in full swing and will have an annual capacity of 15 million tons by 1995.
The Ih Je League (Prefecture) authorities have made a comprehensive development plan including a 1.1 billion yuan complex which
will use coal to produce chemical fertilizers. A Japanese company has completed a feasibility report.
The region may be China's most important center of the coal-chemical industry and the ceramic industry in the next century.
4-65
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
MRS COAL HYDROGENATOR PROCESS PROJECT - British Gas pic and Osaka Gas Company Ltd. (C-400)
Work is being carried out jointly by British Gas pic and the Osaka Gas Company
Ltd. of Japan, to produce methane and valuable
liquid hydrocarbon coproducts by the direct thermal reaction of hydrogen with coal. A novel reactor, the MRS (for Midlands
Research Station) coal hydrogenator incorporating internal gas recirculation in an entrained flow system has been developed to
provide a means of carrying out the process without the problems of coal agglomeration, having to deal with excessive coal fines, or
excessive hydrogenation gas preheat as found in earlier work.
A 200 kilogram per hour pilot plant was built to prove the reactor concept and to determine the overall process economics. The
process uses an entrained flow reactor with internal gas recirculation based on the Gas Recycle Hydrogenator (GRH) reactor that
British Gas developed to full commercial application for oil gasification.
Following commissioning of the plant in October 1987, a test program designed to establish the operability of the reactor and to
of the commercial process concept confirmed
obtain process data was successfully completed. An Engineering and Costing Study
overall technical feasibility and exceptionally high overall efficiency giving attractive economics.
In December 1988, the sponsors went ahead with the second stage of the joint research program to carry out a further two year
development program of runs at more extended conditions and to expand the pilot plant facilities to enable more advanced testing
to be carried out.
Through 1989, performance tests have been conducted at over 43 different operating conditions. Four different coals have been
tested, and a total of 10 tonnes have been gasified at temperatures of between 780 degrees centigrade and 1,000 degrees centigrade.
The initial plant design only allowed tests of up to a few hours duration to be carried out. The plant was modified in early 1990 to
provide continuous feeding of powdered coal and continuous cooling and discharge of the char byproduct. Over 50 tonnes of coal
was successfully gasified during 21 performance tests with a cumulative feeding time of 18 days. Continuous operation for periods
of up to 67 hours was achieved.
A full-scale physical model of a 50 tonne per day development-scale Coal Hydrogenator was commissioned in 1992. This has
enabled the scaleup of the hydrogenator to be studied. A range of coal injectors at feedrates of up to 50 tonnes per day have been
successfully tested.
The next stage of development is expected to be at 50 tonnes per day and consideration is being given for this to be built in Japan.
- MW. KELLOGG UPGRADING OF REFINERY OIL AND PETROLEUM COKE PROJECT MW.
States Department of Energy (C-404)
Kellogg Company and United
In September 1993, the Department of Energy (DOE) selected the M.W. Kellogg Company, Houston, TX, to study a technology
that could increase the efficiency of U.S. refineries by converting the heavy, difficult-to-process "bottom of the barrel"
into commer
cially
useful products.
As part of the $1.4 million, 3-year project, Kellogg will adapt a process originally developed for gasifying coal. The company will
apply the technology to processing heavy slurry oil and the solid, coal-like petroleum coke often left after refineries extract lighter
fuels such as gasoline, diesel and heating oil.
Kellogg has been working with the Energy Department since the early 1980s to develop a fluid bed coal gasification and combus
tion processes. During the testing of the KRW fluid bed gasification process, petroleum coke was successfully gasified. More
recently, a high-velocity Transport reactor design has successfully been piloted in an effort to reduce the capital cost of the coal
gasification reactor.
Kellogg was able to demonstrate gasification of paraffinic and aromatic naphthas in the Transport reactor and proposed to extend
this technology to gasification of heavier refinery residua. Initial testing under the DOE contract was with a heavy crude emulsion-
Results indicated that the quality of the gas produced depended significantly on the type of solids circulated in the Transport reac
tor. An inert material resulted in low hydrogen yields and high olefinic content of the product gas. With a more active solid, high
hydrogen yield was obtained and the gas contained essentially no hydrocarbons heavier than methane. Of significance, all of the
metals in the crude feed were deposited on the circulating solid.
Development will continue in 1995 on other refinery residua and on petroleum coke.
- NEDO IGCC PROJECT New
Energy and Industrial Technology Development Organization (NEDO) (C-408)
NEDO is studying integrated gasification combined cycle technology as part of a national energy program. A 200 ton per day pilot
plant has been constructed at the Nakoso power station site in Iwaki City, Fukushima Prefecture. The pilot began operating in ^
March 1991.
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"
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (UnderUne denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
The plant, which is designed to produce 40.600 cubic meters of synthetic gas per hour, is expected to operate for about 4 years
using a different kind of coal. The gasifier is an air blown, two stage entrained flow type with a dry-feeding system.
Target for technical development is to develop a 250 megawatt demonstration plant by the year 2000 that has a net thermal ef
ficiency greater than 43 percent and better operability than pulverized coal-fired existing plants.
NEDOL BITUMINOUS COAL LIQUEFACTION PROCESS - New Energy Development Organization (NEDO) (C-410)
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 tech
nology. NEDO maintains a continuing high level of investment for coal liquefaction R&D, involving two large pilot plants. The
construction of a 50 tons per day brown coal liquefaction plant was completed in December 1986 in Australia, and a 150 tons per
day bituminous coal liquefaction plant is under construction in Japan.
The pilot plant in Australia which was operated 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 utiliza
tion. 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 (PDUs) 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 150 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 (-538 degrees C) from the vacuum tower will be hydrotreated at about
350 degrees C and 100-150 atm in the presence of catalysts to produce hydrotreated solvent for recycle.
products will be light oil. Residue-containing ash will be separated by vacuum distillation.
Consequently, the major
Construction of the new pilot plant is underway. It is expected that the pilot plant will start operation in 1996.
Project Cost: 70 billion yen, not including the supporting research
- P-CIG PROCESS Interproject
Service AB (Sweden) and Nippon Steel Corporation, Japan (C-455)
The Pressurized-Coal Iron Gasification process (P-CIG) is based on the injection of pulverized coal and oxygen into an iron melt at
overatmospheric pressure. The development started at the Royal Institute of Technology in Stockholm in the beginning of the
1970s with the nonpressurized CIG Process. Over the years work had been done on ironmaking, coal gasification and ferroalloy
production in laboratory and pilot plant scale.
In 1984, Interproject Service AB of Sweden and Nippon Steel Corporation of Japan signed an agreement to develop the P-CIG
Process in pilot plant scale. The pilot plant system was built at the Metallurgical Research Station in Lulea, Sweden. The P-CIG
Process utilizes the bottom blowing process for injection of coal and oxygen in the iron melt. The first tests started in 1985 and
several test campaigns were carried out through 1986. The results were then used for the design of a demonstration plant with a
gasification capacity of 500 tons of coal per day.
According to project sponsors, the P-CIG Process is highly suitable for integration with combined cycle electric power generation.
This application might be of special interest for the future in Sweden.
For the 500 tons of coal per day demonstration plant design, the gasification system consisted of a reactor with a charge weight of
40 tons of iron. Twenty-two tons of raw coal per hour would be crushed, dried and mixed with five tons of flux and injected
together with 9,000 cubic meters of oxygen gas.
- PINON PINE IGCC POWERPLANT Sierra
Pacific Power Company, M.W. Kellogg Company (C-458)
Sierra Pacific Power Company is planning to build an 80 MW integrated gasification combined cycle plant at its Tracy Powerplant
site, east of Reno, Nevada. The plant will incorporate an air-blown KRW fluidized bed gasifier producing a low-BTU gas for the
combined cycle powerplant.
Dried and crushed coal is introduced into a pressurized, air-blown, fluidized-bed gasifier through a lockhopper system. The bed is
fluidized by the injection of air and steam through special nozzles into the combustion zone. Crushed limestone is added to the
gasifier to capture a portion of the sulfur introduced with the coal as well as to inhibit conversion of fuel nitrogen to ammonia. The
sulfur reacts with the limestone to form calcium sulfide which, after oxidation, exits along with the coal ash in the form of ag
glomerated particles suitable for landfill.
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STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
Hot, low-BTU coal gas leaving the gasifier passes through cyclones which return most of the entrained particulate matter to the
gasifier. The gas, which leaves the gasifier at about 1.700T, is cooled to 1,050T^ before entering the hot gas cleanup system
During cleanup, virtually all of the remaining particulates are removed by ceramic candle filters, and final traces of sulfur are
removed in a fixed bed of zinc ferrite sorbent.
In the demonstration project, a nominal 800 tons per day of coal is converted into 86 megawatts; support facilities for the plant re
quire 6 megawatts, leaving 80 megawatts for export to the grid. The plant has a calculated heat rate of 9,082 BTU per kilowatthour
(HHV). The project will be designed to run on Western subbituminous coal from Utah; operation with higher sulfur and
lower rank coals also is being considered.
The U.S. Department of Energy (DOE) has agreed to fund half of the $270 million project cost. The project is funded by DOE
through the Clean Coal Technology Program, Round 4. Sierra Pacific Power will fund the remaining 50 percent.
Foster Wheeler USA Corp. has been contracted to provide design, engineering, construction, manufacturing and environmental
services for the project.
The permitting process was initiated in 1992. Completion is estimated for 1996-1997. The Public Service Commission of Nevada
approved the project on October 25, 1993. A draft EIS is being prepared by DOE.
Project Cost: $270 million for four year operating demonstration project
- POLISH DIRECT LIQUEFACTION PROCESS Coal
Conversion Institute, Poland (C^*60)
In 1975, Polish research on efficient coal liquefaction technology was advanced to a rank of Government Program PR-1 "Complex
Coal Processing,"
and in 1986 to a Central Research and Development Program under the same title. The leading and coordinating
unit for the coal liquefaction research has been the Coal Conversion Institute, part of the Central Mining Institute.
Initial work was concentrated on the two-stage extraction method of coal liquefaction. The investigations were carried out up to
the bench scale unit (120 kilograms of coal per day). The next steptests on a Process Development Unit (PDU)-met serious
problems with the mechanical separation of solids (unreacted coal and ash) from the coal extract, and continuous operation was
not achieved. In the early eighties a decision was made to start investigations on direct coal hydrogenation under medium pressure.
Investigations of the new technology were first carried out on a bench-scale unit of five kilograms of coal per hour. The coal con
version and liquid products yields obtained as well as the operational reliability of the unit made it possible to design and construct
a PDU scaled for two tonnes of coal per day.
The construction of the direct hydrogenation PDU at the Central Mining Institute was finished in the middle of 1986. In Novem
ber 1986 the first integrated run of the entire unit was carried out.
The significant, original feature of this direct, non-catalytic, middle-pressure coal hydrogenation process is the recycle of part of the
product heavy from the hot separator through the preheater to the reaction zone without pressure release. Thanks to that, a good
distribution of residence times for different fractions of products is obtained, the proper hydrodynamics of a three-phase reactor is
provided and the content of mineral matter (which acts as a catalyst) in the reactants is increased. From 1987 systematic tests on
low rank coal type 31 have been carried out, with over 100 tons of coal processed in steady-state parameters.
The results from the operation of the PDU will be used in the design of a pilot plant with a capacity of 200 tonnes coal per day.
- POWER SYSTEMS DEVELOPMENT FACILITY (PSDF) Southern
(DOE) (C^65)
Company Services (SCS) and U.S. Department of Energy
The PSDF is a flexible test facility designed to evaluate particulate control devices for advanced coal-based power plants. The test
facility, located at the SCS Clean Coal Research Center in Wilsonville. Alabama, will utilize a project team from SCS. DOE.
Electric Power Research Institute. The MW. Kellogg Company (MWKCo). Foster-Wheeler (FW). Westinghouse (WH). SOuthern
Research Institute. Industrial Filter Pump, and Combustion Power Company.
The PSDF facility consists of a limestone-coal preparation facility and can pulverize and blend 102 tons/day of various sub
bituminous and bituminous coals with limestone for testing in the two trains-an Advanced Gasifier Train and an Advanced Pres
surized Fluid-Bed Combustion (APFBC) Train.
The Advanced Gasifier Train consists of a MWKCo reactor capable of processing 2 tons of coal per hour to produce 1.000 cfm of
particulate-laden gas as 1.000-1.800F and 300 psig to various particulate control devices being tested.
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STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
The APFBC consists of a second-generation FW pressurized fluid bed combustor and WH combustion system to perform larger-
scale tests of pollution control devices. Up to 6.500 cfm of combustion gas at 1.600"F and 150 psia can be tested in the APFBC
train.
Project Cost: $150 million (20% DOE. 80% industry)
PRENFLO GASIFICATION PILOT PLANT -
Krupp Koppers GmbH (KK) (C-470)
Krupp Koppers (KK) of Essen, West Germany (in United States known under the name of GKT Gesellschaft fuer Kohle-
Technologie) are presently operating a 48 ton per day demonstration plant and designing a 2,400 ton per day module for the
PRENFLO process. The PRENFLO process is KK's pressurized version of the Koppers-Totzek (KT) flow gasifier. Detailed en
gineering has been completed for a 1,200 ton per day module.
In 1973, KK started experiments using a pilot KT gasifier with elevated pressure. In 1974, an agreement was signed between Shell
Internationale Petroleum Maatschappij BV and KK 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 KK agreed to continue further
development separately, with each partner having access to the data gained up to that date. KK'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 at an operating pressure
of 30 bar. The plant was located at Fuerstenhausen, West Germany. In over 10,000 hours of test operation 12 different fuels with
ash contents of up to 40 percent were successfully used. All fuels used are converted to more than 98 percent, and in the case of fly
ash recycled to more than 99 percent.
Project Cost: Not disclosed
- PRESSURIZED FLUID BED COMBUSTION ADVANCED CONCEPTS M.
W. Kellogg Company (C^473)
In September of 1988, Kellogg was awarded a contract by the DOE to study the application of transport mode gasification and
combustion of coal in an Advanced Hybrid power cycle. The study was completed in 1990 and demonstrated that the cycle can
reduce the cost of electricity by 20-30 percent (compared to a PC/FGD system) and raise plant efficiency to 45 percent or more.
The Hybrid system combines the advantages of a pressurized coal gasifier and a pressurized combustor which are used to drive a
high efficiency gas turbine generator to produce electricity. The proprietary Kellogg system processes pulverized coal and lime
stone and relies on high velocity transport reactors to achieve high conversion and low emissions.
DOE, in late 1990, awarded a contract to Southern Company Services, Inc. for addition of a Hot Gas Cleanup Test Facility to their
Wilsonville test facility. The new unit will test particulate removal devices for advanced combined cycle systems and Kellogg's
Transport gasifier and combustor technology will be used to produce the fuel gas and flue gas for the program. testing The reactor
system is expected to process up to 48 tons per day of coal. [See Hot Gas Cleanup Process (C-257)].
Kellogg has built a bench scale test unit to verify the kinetic data for the transport reactor system and has completed testing in both
gasification and combustion modes, using bituminous and subbituminous coals. The results in both modes have verified the con
cept that reactors designed to process pulverized coal and limestone can achieve commercial conversion levels while operating at
high velocities and short contact times. The test data have been used to support the design of the Wilsonville test gas generator,
and another unit at UND/EERC.
The gasifier converts part of the coal to a low-BTU gas that is filtered and sent to the gas turbine. The remaining char is com
busted and the flue gas is filtered and also goes to the gas turbine. The advantages of the system in addition to high efficiency are
lower capital cost and greatly reduced SO and NO emissions.
DOE has also approved the design, fabrication, installation and operation of a Process Development Unit (PDU) based upon
Kellogg's Transport gasification process at the University of North Dakota, Energy and Environmental Research Center
(UND/EERC). The unit will process 2.4 tons per day of pulverized bituminous coal. The PDU was successfully operated in
gasification and combustion modes on Wyodak subbituminous coal in December 1993.
DOE's Morgantown Energy Technology Center has awarded Kellogg
a contract for experimental studies to investigate in-situ
desulfurization with calcium-based sorbents. The testing, conducted at Kellogg's Houston Technology Development Center, inves
tigates the effects of the sorbents on sulfur capture kinetics and carbon conversion kinetics, and the mechanism for conversion of
calcium sulfide to calcium sulfate in second generation (hybrid) pressurized fluid bed combustion systems. The final report has
been approved bv DOE and will be available shortly.
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STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
PUERTOLLANO - IGCC DEMONSTRATION PLANT ELCOGAS,
SA. (C-476)
Under the corporation ELCOGAS. SA.. the Spanish utility company ENDESA together with EDF/France. IBERDROLA /Spain.
Hidroelectrica del Cantabrico/Spain. SEVILLANA/Spain. EDP/Portugal. EN'EL/ltalv and National Power/England are involved
in the Puertollano Project. The project also has the European Economic Commission support, under the Thermie Program.
The proposed project has a capacity of 300 MWe (net). The PRENFLO gasification technology has been chosen for the gasifier.
The plant configuration is single-train throughout. Using oxygen and steam, about 100 tons of coal per hour will be gasified. The
required oxygen, approximately 90 tons per hour, will be produced in a single-train air separation unit. The resulting coal gas will
be dedusted, desulfurized and saturated in a single-train configuration and then combusted in a single Siemens combustion turbine.
A 50/50 mixture of Puertollano coal and petroleum coke from the Puertollano Petroleum Refinery is intended to be the main
feedstock for this project. Coals from Spain and other European countries will also be tested over the 3-year demonstration
period.
SO Emission values of 10 mg/m n and NO values of 60 mg/m n are expected in the exhaust gas (based on 15 volume percent
oxygen).
*
The combined cycle power plant at Puertollano will be switched into the grid in the second half of 1995, fueled initially with natural
gas. Conversion to coal gas will take place by the end of 1996. A 3-year demonstration period is planned.
Project Cost: ECU600 million
- PYGAS DEMONSTRATION PROJECT Morgantown
Energy Technology Center (METC), CRS Sirrine Engineers, Inc. (C-477)
METC and CRS Sirrine have been working on the development of a gasifier which uses carbonizer tubes as a means to drive off
coal volatiles and tar prior to the conventional fixed-bed gasifier process. The combination of carbonizer (pyrolysis) tube and
fixed-bed gasifier results in coal "Pyrolysis"
and "Gasification,"
hence the name PyGas.
A gasification facility will be built at METC's Gasification Product Improvement Facility (GPIF) located at Monongahela Power's
Fort Martin site. The gasifier will be rated at 6 tons per hour coal throughput. Operating pressure is 600 psi. It is expected to be
5 feet in diameter and 34 feet high.
The concept of the facility is to meter feed coal alone or with limestone through a crusher/dryer and pressure lock pneumatically to
the pryolyzer section of the gasifier. Porous devolatilized char and pyrolysis gas exit the top of the pyrolyzer. Air is injected into
the upper dome of the gasifier to raise the temperature high enough to crack tar vapors in the pyrolysis gas. The char separates
from the gas by gravity and forms the fixed bed.
The gases pass cocurrently downward with the char into the conventional fixed-bed gasification section. The porous char is further
gasified by the countercurrent admittance or air and steam through a rotating grate.
QINGDAO GASIFICATION PLANT (C^78)
China is building a coal gasification plant in the northern city of Qingdao in the Shandong province. The plant, which will produce
263 million cf per day of gas, involves two coke-making batteries, a coal preparation plant, a thermal power station and 14 gas
retorts. The plant will provide a district heating network for the 6.7 million person city, eliminating hundreds of coal-fired boilers
and stoves.
The gasification project is part of a $210 million environmental cleanup program in Qingdao. The Asian Development Bank will
finance $103 million of the total cost, with China providing the balance.
-
RHEINBRAUN HIGH-TEMPERATURE WINKLER PROJECT Rheinbraun
Federal Ministry for Research & Technology (C-480)
AG, Uhde GmbH, Lurgi GmbH, German
Rheinbraun and Uhde have been cooperating since 1975 on development of the High-Temperature Winkler fluidized bed gasifica
tion process. In 1990 Lurgi joined the commercialization effort.
Based on operational experience with various coal gasification processes, especially with ambient pressure Winkler gasifiers,
Rheinische Braunkohlcnwerke AG (Rheinbraun) in the 1960s decided to develop pressurized fluidized bed gasification, the High-
Temperature Winkler (HTW) process. The engineering contractor for this process is Uhde GmbH.
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STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
The development was started at the "Institut fur Eisenhuttenkunde"
of Aachen Technical University in an ambient pressure process
development unit (PDU) of about 50 kilograms per hour coal throughput.
Based on the results of pre-tests with this PDU a pilot plant, operating at pressure of 10 bar was built 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.
end of June 1985 the test program was finished and the plant was shut down. From 1978 until June 1985 about 21,000 tons of
By
dried brown coal were processed in about 38,000 hours of operation. The specific synthesis gas yield reached 1380 standard cubic
meters per ton of brown coal (MAF) corresponding to 96 percent of the calculated value. thermodynamically 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. The pilot plant was shut down in mid-1985.
After gasification tests with Finnish peat in the HTW pilot plant in the spring of 1984 the Kemira Oy Company of Finland decided
to convert an existing ammonia production plant at Oulu from heavy oil to peat gasification according to the HTW process. The
plant was designed to gasify approximately 650 tons per day of peat at 10 bar and process it to 280 tons per day of ammonia. This
plant started up in 1988.
Rheinbraun constructed a 30 ton per hour demonstration plant for the production of 300 million cubic meters of 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 produced at the site of Rheinbraun's
Ville/Berrenrath briquetting plant is pipelined to DEA-Union Kraftstoff for methanol production. From startup in January 1986
until November 1994 about 1.2 billion tons of dried brown coal were processed in about 54.600 hours of operation. During this
time, about 1.6 billion cubic meters of synthesis gas were produced.
A new pilot plant, called pressurized HTW gasification plant, for pressures up to 25 bar and throughputs up to 63 tons per hour
was erected on the site of the former pilot plant of hydrogasification and started up in November 1989. From mid-November 1989
to early July 1990, the plant was operated at pressures between 10 and 25 bar, using oxygen as the gasifying agent. Significant fea
tures of the 25 bar gasification are the high specific coal throughput and, consequently, the high specific fuel gas flow of almost
100 MW per square meter. In mid-1990, the 25 bar HTW plant was modified to permit tests using air as the gasifying agent. Until
the end of January 1992 the plant was operated for 8,753 hours at pressures of up to 25 bar, oxygen blown as well as air blown.
Under all test and operating conditions gasification was uniform and trouble free.
Typical results obtained are: up to 95 percent coal conversion, over 70 percent cold-gas efficiency and 50 MW specific fuel gas
flow per square meter air blown and 79 percent cold-gas efficiency and 105 MW specific fuel gas flow per square meter oxygen
*
blown.
From February to September 1992 tests with a German hard coal and with Pittsburgh No. 8 coal were successfully performed in the
pressurized HTW gasification plant using oxygen and air as gasification agents as well. Within 543 hours of operation 728 tons of
hard coal were processed. The pressurized HTW gasification plant was shut down in November 1992.
This work is performed in close co-ordination with Rheinbraun's sister company, RWE Energie AG. which operates power stations
of a capacity of some 9,300 megawatts on the basis of lignite. Since this generating capacity will have to be renewed after the turn
of the century, it is intended to develop the IGCC technology so as to have a process available for the new powerplants. Based on
the results of these tests and on the experience gained with operating the HTW pressurized plant, a demonstration plant for in
tegrated HTW gasification combined cycle (HTW-IGCC) power generation is planned with a capacity of 300 MW of electric power.
The gas will be produced in one air-blown gasifier. See KOBRA HTW-IGCC Project (C-294).
Project Cost: Not disclosed
- SASOL Sasol Limited (C-490)
Sasol Limited is the holding company of the multi divisional Sasol Group of Companies. Sasol is a world leader in the commercial
production of coal based synthetic fuels. The Synthol oil-from-coal process was developed by Sasol in South Africa in the course of
more than 30 years. A unique process in the field, its commercial-scale viability has been fully proven and its economic viability
conclusively demonstrated.
The first Sasol plant was established in Sasolburg in the early fifties. The much larger Sasol Two and Three plants, at Secunda-
situated on the Eastern Highveld of Transvaal, came on-stream in 1980 and 1982, respectively.
The two Secunda plants are virtually identical and both are much larger than Sasol One, which served as their prototype. Enor
mous quantities of feedstock are produced at these plants. At full production, their daily consumption of coal is almost
100,000 tons, of oxygen, 28,000 tons; and of water, 250 megaliters. Sasol's facilities at Secunda for the production of oxygen are by
far the largest in the world.
Facilities at the fuel plants include boiler houses, Lurgi coal gasifiers, oxygen plants, Rectisol gas purification units, synthol reac
tors, gas reformers and refineries. Hydrocarbon synthesis takes place means by of the Sasol licensed Synthol process.
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STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
The products of Sasol Two and Three, other than liquid fuels, include ethylene, alcohols, acetone, methyl ethyl ketone, pitch, tar
acids, and sulfur, produced for Sasol's Chemical Division, ammonia for the group's Fertilizer and Explosives Divisions, and
propylene for the Polymer Division. The primary fuels produced by Sasol at Secunda are probably among the most environmen
tally acceptable in the world. The gasoline that is produced has zero sulfur content, is low in aromatics and the level of oxygenates
means a relatively high octane number. An oxygenate-containing fuel, as a result of the lower combustion temperature, results in a
generally lower level of reactive exhaust constituents.
The blending of synthetic gasoline with alcohols (ethanol as well as high fuel alcohols) presented a particular challenge to Sasol.
Sasol erected research and development facilities to optimize and characterize fuel additives. Whereas carburetor corrosion with
alcohol-containing gasoline occurs with certain alloys used for carburetors, Sasol has now developed its own package of additives to
the point where a formal guarantee is issued to clients who use Sasol fuel.
The diesel fuel is a zero sulfur fuel with a high cetane number and a paraffin content that will result in a lower particulate emission
level than normal refinery fuel.
Sasol's Mining Division manages the six Sasol-owned collieries, which have an annual production in excess of 43 million tons of
coal. The collieries comprised of the three Secunda Collieries (including the new open cast mines, Syferfontein and Wonderwater),
which form the largest single underground coal mining complex in the world, and the Sigma Colliery in Sasolburg.
A technology company, Sastech, is responsible for the Group's entire research and development program, process design, engineer
ing, project management, and transfer of technology.
Sasol approved in 1990 six new projects costing $451 million as part of an overall $3.5 billion program over the next five years. The
first three projects are scheduled for completion by January 1993.
Sasol has increased its production of ethylene by 55,000 tons per year, to a current level of 400,000 tons per year, by expanding its
ethylene recovery plant at Secunda.
The company's total wax producing capacity will be doubled from its current level of 64,000 tons per year to 120,000 tons per year.
The 70,000 ton per year Sasol One ammonia plant is to be replaced by a 240,000 ton per year plant, which is expected to supply
South Africa's current ammonia supply shortfall.
A new facility, Sasol One, to manufacture paraffinic products for detergents was commissioned in March 1993.
An n-butanol plant to recover acetaldehyde from the Secunda facilities and to produce 17300 tons per year of n-butanol was com
missioned during 1992.
Sasol will construct a delayed coker facility to produce green coke, and a calciner to calcinate the green coke to anode coke and
needle coke. The anode coke is suitable for use in the aluminum smelting industry. They are scheduled to be in production by July
1993.
A flexible plant to recover 100,000 tons per year of 1-hexane or 1-pentone will be built to come online in January 1994. The tech
nology was developed in-house by Sasol.
A krypton/xenon gas recovery plant adjacent to Secunda oxygen units was commissioned in 1993.
A major renewal project at Sasol One includes the replacement of the fixed bed Fischer-Tropsch plant with the new Sasol Slurry
Bed Reactor. The renewal also includes shutting down much of the synthetic fuels capability at this plant.
Project Cost': SASOL Two $2.9 Billion
SASOL Three $3.8 Billion
*At exchange rates ruling at construction
- SCOTIA COAL SYNFUELS PROJECT DEVCO; Alastair Gillespie* Associates Limited; Gulf Canada Products Company;
NOVA; Nova Scotia Resources Limited; and Petro-Canada (C-500)
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 Point Tupper Refinery or near the coal mines. The
25,000 barrels per day production goal would require approximately 23 million tonnes of coal per year. A contract was completed
with Chevron Research Inc. to test the coals in their two-stage direct liquefaction process (CCLP). A feasibility report was com
pleted and options financeability discussed with governments concerned and other parties.
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STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
Scotia Synfuels Limited has been incorporated to carry on the work of the consortium. Scotia Synfuels has down-sized the project
to 12300 barrels per day based on a coprocessing concept and purchased the Point Tupper site from Ultramar Canada Inc. Recent
developments in coprocessing technology have reduced the capital cost estimates to US$375 million. Net operating costs are es
timated at less than US$20 per barrel.
In late 1988 Hydrocarbon Research Inc. (HRI) was commissioned by Scotia Synfuel Ltd. to perform microautoclave and bench
scale tests to demonstrate the feasibility of their co-processing technology using Harbour seam coal and several oil feedstocks. In
early 1989, Bantrel Inc. (a Canadian engineering firm affiliated with Bechtel Inc.), was commissioned to develop a preliminary
process design.
Scotia Synfuels and partners have concluded an agreement with the Nova Scotia government supported by the. federal government
for financial assistance on a $23 million coprocessing feasibility study. The study was completed in 1990.
In 1992 Scotia Synfuels Limited arranged with partners to finance the reactivation of the oil storage and ocean terminal facilities at
the Point Tupper. Nova Scotia site. Total investment in this reactivation project has been about C$100 million. This project was
developed with the view towards supporting the development of a commercial Synfuels Project at the site.
In 1993. Scotia Synfuels Limited formed a partnership with CORPOVEN. SA. to evaluate coprocessing of Boscan residuum (with
high sulfur and high metals content) and Nova Scotia coal. This program was supported by the Nova Scotia government.
Hydrocarbon Research Inc. was again contracted for a bench test program. Hydrotreatment tests of the hydrocarbons from the
HRI coprocessing program were contracted to the CANMET laboratories. Bantrel Inc. was engaged to modify the process design
developed in the 1989 program to reflect the new feedstocks. Economic analvsis indicated that a coprocessing plant based on Bos
can Crude and Nova Scotia coal would be attractive at oil prices of about $US18 per barrel-
In the recent program two plant cases of 14,000 barrels/day and 19.000 barrels per day of petroleum products were developed. The
products consisted of high quality naphtha (34%); #2 diesel fuel (56%) and low sulfur heavy distillate (10%). Coal conversion in
the coprocessing tests was in excess of 90 percent and residuum conversion was in excess of 85 percent-
Scotia Synfuels Limited is currently developing financing for the next phase of the project which is estimated to be C$133 to
C$15 million.
Project Cost: Approximately $23 million for the feasibility study
Approximately C$500 million for the plant
- SEP IGCC POWERPLANT Demkolec
BV. (SEP) (C-520)
In 1989, Demkolec, a wholly owned subsidiary of Samenwerkende Elektriciteits-Produktiebedrijven (SEP), the Central Dutch
electricity generating board, started to build a 253 megawatt integrated coal gasification combined cycle (IGCC) powerplant, to be
ready in 1993.
SEP gave Comprimo Engineering Consultants in Amsterdam an order to study the gasification technologies of Shell, Texaco and
British Gas/Lurgi. In April 1989 it was announced that the Shell process had been chosen. The location of the coal
gasification/combined cycle demonstration station is Buggenum, in the province of Limburg, The Netherlands.
The coal gasification facility will employ a single 2,000 ton per day gasifier designed on the basis of Shell technology. The clean gas
will fuel a single shaft Siemens V94.2 gas turbine (156 MWe) coupled with steam turbine (128 MWe) and generator. The coal
gasification plant will be fully integrated with the combined cycle plant, including the boiler feed water and steam systems; addition
ally the compressed air for the air separation plant will be provided as a bleed stream from the compressor of the gas turbine. The
design heat rate on internationally traded Australian coal (Drayton) is 8,240 BTU/kWh based on coal higher value heating (HHV).
Environmental permits based on NO emissions of 0.17 Ib/MMBTU and SO emissions of 0.06 lb/MMBTU were obtained in April
1990. Construction began in July 1990 and start of operation is scheduled for September 1993. When operation begins, the Dem
kolec plant will be the largest coal gasification combined cycle powerplant in the world. Commissioning of the main plant system is
scheduled to take place in January through July 1993.
After three years of demonstration (1994 to 1996), the plant will be handed over to the Electricity Generating Company of South
Netherlands (N.V. EPZ).
Project Cost: Dfl. 880 million (1989)
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STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
SHANGHAI - CHEMICALS FROM COAL PLANT People's
Republic of China (C-525)
The Chinese government has approved construction of a new methanol complex. Using coal as raw material, the Shanghai-based
plant is expected to produce 100,000 tons per year of methanol and 15,000 tons per year of acetate fiber. Completion is due in
1992.
SHOUGANG COAL - GASIFICATION PROJECT People's
Republic of China (C-527)
The Shougang plant will gasify 1,170 tons per day of Chinese anthracite using the Texaco coal gasification process. The gasification
plant will produce fuel gas for an existing steel mill and town gas. The detailed design is being completed and equipment fabrica
tion is underway. The plant is expected to be operational in late 1992.
SLAGGING - GASIFIER PROJECT British
Gas fjc (C-540)
British Gas Pic, with the cooperation of Lurgi. constructed a prototype high pressure slagging fixed bed gasifier (the BGL gasifier)
in 1974 at Westfield, Scotland. (This gasifier has a 6 foot diameter and a throughput of 300 tons per day.) The plant successfully
operated 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. Byproduct 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 was
carried out successfully between 1975 and 1983. Total operating time was over one year and over 100,000 tons of coal were gasified.
A second phase, started in November 1984, was the demonstration of a 500 ton per day (equivalent to 70 megawatts) gasifier with a
nominal inside diameter of 7.5 feet. Power generation tests were carried out with an SK 30 Rolls Royce Olympus turbine to gener
ate power for the grid. The turbine is supplied with product gas from the plant. By 1989 this gasifier had operated for ap
proximately 1,300 hours and had gasified over 26,000 tons of British and American (Pittsburgh No. 8 and Illinois No. 6) coals.
The 500-ton per day gasifier was operated at 25 bar until the end of 1990.
An experimental gasifier designed to operate in the fixed bed slagger mode at pressure up to 70 atmospheres was constructed in
1988. It was designed for a throughput of 200 tons per day. This unit was operated through 1991. Operation of the gasifier was ex
cellent over the entire pressure range; the slag was discharged automatically, and the product gas was of a consistent quality. At
corresponding pressures and loadings the performance of the 200-ton per day gasifier was similar to that of the 500-ton per day
unit previously used.
As the pressure rises, the gas composition shows a progressive increase in methane and a decrease in hydrogen and ethtylene, while
the ethane remains fairly constant. The tar yield as a percentage of the dry ash free coal decreases with pressure. The cold gas ef
ficiency, i.e., the proportion of the fuel input converted to potential heat in the output gas, was above 90 percent. The throughput
increased approximately with the square root of the ratio of the operating pressures.
BGL is now cooperating with Duke Energy and other partners in the USA to develop a first commercial IGCC project based upon
the BGC gasifier under the U.S. Department of Energy's Clean Coal Technology V Program.
Project Cost: Not available
SYNTHESEGASANLAGE RUHR (SAR)
- Ruhrkohle
Oel and Gas GmbH and Hoechst AG (C-560)
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.
The 800 tons per day coal gasification plant has been in operation since August 1986. The coal gases produced have the quality to
be fed into the Ruhrchemie's oxosynthesis plants. The gasification plant has been modified to allow for input of either hard coal or
heavy oil residues. The initial investment was subsidized by the Federal Minister of Economics of the Federal Republic of Ger
many. The Minister of Economics, Small Business and Technology of the State of North-Rhine Westphalia participates in the coal
costs.
Project Costs: DM220 million (Investment)
4-74
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
- TAMPELLA IGCC PROCESS DEMONSTRATION Tampella
Power (C-565)
After having obtained the rights to the Institute of Gas Technology's fluidized bed gasification technology in 1989, Tampella Keeler
began to design and initiate construction of a 10 MW thermal pilot plant at their research facilities in Tampere, Finland. The pilot
plant is considered essential for determining operating parameters for specific coals and for continuing process development in the
areas of in-gasifier sulfur capture and hot gas cleanup. The pilot plant will be operational in early 1991.
The pilot plant is designed so that alternative hot gas filters and zinc ferrite absorber/regenerator design concepts can be
evaluated. The gasifier is 66 foot tall, with an inside diameter ranging from 2 to 4 feet. The gasifier will be capable of operating at
pressures up to 425 psig.
After the pilot plant construction was underway, Tampella turned its attention towards locating a demonstration project in Finland
and one in the U.S. A cogeneration project to be located at an existing papermill has been selected as the basis for the demonstra
tion in Finland. The gasifier will have a capacity of 150 MW thermal which is equal to about 500 tons per day of coal consumption.
The plant will produce about 60 MW of electricity and about 60 MW equivalent of district heating.
In September, 1991 Tampella received support from the U.S. Department of Energy (DOE) to build an integrated gasification
combined-cycle demonstration facility, known as the Toms Creek IGCC Demonstration Project, in Coeburn, Wise County, Virginia
(see project C-580, below). The Toms Creek Project will utilize Tampella Power's advanced coal gasification technology to
demonstrate improved efficiency for conversion of coal to electric power while significantly reducing SO and NO emissions.
- TECO IGCC PLANT Teco
Power Services, U.S. Department of Energy (C-567)
Tampa Electric Company's new (TEC) Polk Power Station Unit #1 will be the first unit at a new site and will use Integrated
Gasification Combined Cycle (IGCC) Technology. The project is partially funded by the U.S. Department of Energy (DOE) under
Round III of its Clean Coal Technology Program. In addition to the TEC and DOE, TECO Power Services (TPS), a subsidiary a
TECO Energy, Inc., and an affiliate of TEC, is also participating in the project. TPS is responsible for the overall project manage
ment for the DOE portion of this IGCC project.
The Polk Power Station IGCC Project will be constructed in two phases. TEC's operation needs called for 150 MW of peaking
capacity in mid-1995, becoming part of the 260 MW of total IGCC capacity in mid-1996. The first phase will be the installation of
an advanced combustion turbine (CT) scheduled for commercial operation in July 1995. This CT will fire No. 2 oil during its first
year while in peaking service. During that year, TEC will complete installation of the gasification and combined cycle facilities
which will be in commercial operation in July 1996.
In addition, part of this DOE CCT project will be to test and demonstrate a new hot gas clean-up (HGCU) technology.
The Texaco Gasification Process has been selected for integration with a combined cycle power block.
Part of the Cooperative Agreement for this project is the two-year demonstration phase. During this period it is planned that
about four to six different types of coal will be tested in the operating IGCC power plant. The results of these tests will compare
this unit's efficiency, operability, and costs, and report on each of these test coals specified against the design basis coal. These
results should identify operating parameters and costs which can be used by utilities in the future as they make their selection on
methods for meeting both their generation needs and environmental regulations.
Project Cost: $600 million
TEXACO COOL WATER PROJECT - Texaco
Syngas Inc. (C-569)
Original Cool Water participants built a 1,000-1,200 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, was integrated with a General
Electric combined cycle unit to produce approximately 122 megawatts of gross power. Plant construction, which began in Decem
ber 1981, was completed on April 30, 1984, within the projected $300 million budget. A 5-year demonstration period was com
Project"
pleted in January 1989. See "Cool Water in the December 1991 issue of the Synthetic Fuels Report, Status of Projects sec
tion for details of the original completed project.
Texaco plans to modify and reactivate the existing facilities to demonstrate new activities which include the addition of sewage
sludge into the coal feedstock, production of methanol, and carbon dioxide recovery.
Texaco intends to use a new application of Texaco's technology which will allow the Cool Water plant to convert municipal sewage
sludge to useful energy by mixing it with the coal feedstock. Texaco has demonstrated in pilot runs that sludge can be mixed with
coal and, under high temperatures and pressures, gasified to produce a clean synthesis gas. The plant will produce no harmful
byproducts.
4-75
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
Texaco Syngas Inc. has initiated efforts to restructure the financing of the Texaco Cool Water Project and continues to negotiate
with Southern California Edison Company for the power purchase agreement based on the California Energy Commission Com
mittee Order dated November 2, 1992. Successful negotiation of the power purchase agreement, with necessary State of California
approvals, would allow the acquisition of the Cool Water Gasification Facility, by Texaco Syngas Inc. from Southern California
Edison Company, to be completed.
Project Cost: $263 million for original Cool Water Coal Gasification Program
$213.7 million for the commerical demonstration of the liquid-phase methanol process
THERMOCHEM PULSE COMBUSTION DEMONSTRATION - ThermoChem,
Energy (C-577)
Inc., Northshore Mining, and U.S. Department of
ThermoChem is implementing a Cooperative Agreement with the Department of Energy's Clean Coal Program for the demonstra
tion of steam-reforming, low-rank coak at full scale (720 ton/day). This $37.3 million Cooperative Agreement will provide for the
design, construction and two-year operation of a unit to produce char and synthesis gas for Northshore Mining's Direct Reduction
Iron project in Silver Bay. Minnesota. ThermoChem is the prime contractor in this effort having won a DOE competitive award in
1991. Stone & Webster Engineering and Ogden Environmental Services are subcontractors and partners in this effort. This
demonstration project will supply the char for the first of three Direct Reduced Iron (DRI) units planned by Northshore Mining.
An expansion of the ThermoChem unit would he expected to provide char for the two additional DRI units.
The heat required for the gasification will be supplied by the combustion of cleaned gasification fuel gas in numerous pulsed com
bustion tubes. The products of pulsed combustion are separated from the gasification products. Since no dilution of the
byproducts of combustion or of gasified fuel gas occurs, a medium BTU content fuel (300-400 BTU/scf) gas will be produced. The
turbulent nature of the pulsed combustor contributes to a high combustion heat release and density high heat transfer rates to the
gasifier bed. The fluidized bed coal gasifier also offers high turbulence and heat transfer rates.
In this project, design and permitting will be completed in 1996. with the operation beginning by the end of 1997.
- TOM'S CREEK IGCC DEMONSTRATION PLANT TAMCO
Power Partners and U.S. Department of Energy (C-580)
TAMCO Power Partners, a partnership between Tampella Power Corporation and Coastal Power Production Company will build
an integrated gasification combined cycle powerplant in Coeburn, Virginia. The U.S. Department of Energy will fund 48.3 percent
of the $197 million project under Round 4 of its Clean Coal Technology Program.
The project will demonstrate a single air blown fluidized bed gasifier, based on the U-GAS technology developed by the Institute of
Gas Technology. The plant will burn 430 tons per day of local bituminous coal and produce a net 55 MWe. Power will be genera
ted by firing low-BTU product gas in a gas turbine generator and by a steam turbine generator supplied by the waste heat from the
gas turbine.
A cooperative agreement was signed with the DOE in October 1992. A power sales agreement has yet to be signed.
Project Cost: $196.6 million
- UBE AMMONIA-FROM-COAL PLANT Ube
Industries, Ltd. (C-590)
Ube Industries, Ltd., of Tokyo completed the world's first large scale ammonia plant based on the Texaco coal gasification process
(TCGP) in 1984. There are four complete trains of quench mode gasifiers in the plant. In normal operation three trains are used
with one for stand-by. Ube began with a comparative study of available coal gasification processes in 1980. In October of that
year, the Texaco process was selected. 1981 saw pilot tests run at Texaco's Montebello Research Laboratory, and a process design
package was prepared in 1982. Detailed design started in early 1983, and site preparation in the middle of that year. Construction
was completed in just over one year. The plant was commissioned in July 1984, and the 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 En
Division. Ube installed the new coal gasification process as an alternative "front
end"
gineering 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 1,650 short tons per day gasification plant has operated using four kinds of coal-Canadian, Australian, Chinese, and South
African, and about twenty kinds of petroleum coke.
Over 43 million tons of feed including 1.6 million tons of petroleum coke, had been gasified by June 1994. The overall cost of am
monia 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.
4-76
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
Ube was awarded the same scale of coal gasification plant in 1992 bv Peoples Republic of China which is scheduled to be commis
sioned near the end of 1995.
- Project Cost Not disclosed
- VARTAN DISTRICT HEATING PLANT Energie
Verk (C-595)
In 1990, a gas turbine PFBC system went into operation at the Vartan district heating plant in Stockholm, Sweden. The gas turbine
is a two-shaft, intercooled machine with the compressor providing the combustion air for the fluidized bed, which is then returned
through a cyclone system to clean the gas before it enters the turbine. In a combined cycle the gas turbine exhaust heat is captured
in the usual way, but the heat recovery boiler acts only as an evaporator, because the superheater stage is formed by a tube bundle
embedded in the fluidized bed.
The Vartan plant has an output of 135 MW of electric capacity and 210 MW thermal (MWt). The coal used has about 1 percent
sulfur and is fed to the combustor as a coal-water paste. Efficiency is about 42 percent.
- VICTORIAN BROWN COAL LIQUEFACTION PROJECT Brown
Coal Liquefaction (Victoria) Pty. Ltd. (C-610)
BCLV was operating a pilot plant at Morwell in southeastern Victoria to process the equivalent of 50 tonnes per day of moist ash
free coal until October 1990. BCLV is a subsidiary of the Japanese-owned Nippon Brown Coal Liquefaction Company (NBCL), a
consortium involving Kobe Steel, Mitsubishi Kasei Corporation, Nissho Iwai, Idemitsu Kosan, and Cosmo 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 and Industrial Technology Development Organization (NEDO). NBCL is entrusted with implementation of the
entire program, and BCLV is carrying 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. The remaining sections, consisting of solvent deashing and secondary hydrogenation, were completed during
1986. The pilot plant was operated until October 1990, and shut down at that point.
The pilot plant is located adjacent to the Morwell open cut brown coal mine. Davy McKee Pacific Pty. Ltd.,
provided the
Australian portion of engineering design procurement and construction management of the pilot plant. The aim of the pilot plant
was to prove the effectiveness of the BCL Process which had been developed since 1971 by the consortium.
Work at the BCLV plant was moved in 1990 to a Japanese laboratory, starting a three-year study that will determine whether a
demonstration plant should be built. NBCL is developing a small laboratory in Kobe, Japan, specifically to study the Morwell
project.
Part of the plant will be demolished and the Coal Corporation of Victoria is a considering using part of the plant for an R&D
program aimed at developing more efficient brown coal technologies. The possibility of building a demonstration unit capable of
producing 16,000 barrels per day from 5,000 tonnes per day of dry coal will be examined in Japan.
If a commercial plant were to be constructed, it would be capable of producing 100,000 barrels of synthetic oil, consisting of six
lines of plant capable of producing 16,000 barrels from 5,000 tonnes per day dry coal. For this future stage, Australian companies
will be called for equity participation for the project.
Project Cost: Approximately $700 million
- WEIHE CHEMICAL FERTILIZER PLANT Texaco
Development Corporation (C-613)
The Weihe Chemical Fertilizer Plant, located in the Shaanxi Province of China, will operate under a license from the Texaco
Development Corporation. This gasification plant in the agricultural province of Shaanxi will utilize China's most abundant energy
source, coal, and convert it into much needed fertilizer. The Weihe plant is among eight plants operating in China using Texaco
gasification technology. The first Texaco gasification plant was licensed in 1978.
The Weihe plant will gasify 1300 tons of coal per day to produce ammonia. The ammonia will be used to produce an estimated
520.000 tons per year of urea fertilizer. Fertilizer production is scheduled to begin in 1996.
4-77
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
WABASH RIVER COAL GASIFICATION REPOWERING PROJECT - Destec Energy, Inc. and PSI Energy Inc. (C-614)
Located in West Terre Haute, Indiana, the project will repower one of the six units at PSI Energy's Wabash River power station.
The repowering scheme will use a single train, oxygen-blown Destec gasification plant and the existing steam turbine in a new in
tegrated gasification combined cycle configuration to produce 262 megawatts of electricity from 2353 tons per day of high sulfur Il
linois basin bituminous coal. The plant will be designed to substantially out-perform the standards established in the Clean Air Act
Amendments for the year 2000. The demonstration period for the project will be 3 years after plant startup.
The CGCC system will consist of Destec's two-stage, entrained-flow coal gasifier, a gas conditioning system for removing sulfur
compounds and particulates; systems or mechanical devices for improved coal feed; a combined-cycle power generation system.
wherein the conditioned synthetic fuel gas is combusted in a combustion turbine generator, a gas cleanup system; a heat recovery
steam generator, all necessary coal handling equipment; and an existing plant steam turbine and associated equipment.
The demonstration will result in a combined-cycle powerplant with low emissions and high net plant efficiency. The net plant heat
rate for the new, repowered unit will be 9,030 BTU per kilowatt-hour, representing a 20 percent improvement over the existing unit
while cutting SO by greater than 98 percent and NO emissions by greater than 85 percent.
The project was selected for funding under Round IV of the U.S. Department of Energy's (DOE) Clean Coal Technology
Program, and is slated to operate commercially following the demonstration period. DOE has agreed to provide funding of up to
$198 million under the Cooperative Agreement.
Construction began in September 1993. As of January 1995. the project is 80 percent complete in the construction phase. It is
scheduled for commercial operation to begin August 15. 1995.
Project Cost: $368 million
WILSONVILLE POWER SYSTEMS DEVELOPMENT FACILITY (PSDF) PROJECT - Southern
States Department of Energy (C-617)
Company Services, Inc. and United
The PSDF will consist of five modules for systems and component testing. These modules include an Advanced Pressurized
Fluidized Bed Combustion (APFBC) Module, and Advance Gasifier Module, Hot Gas Cleanup Module, Compressor/Turbine
Module, and a Fuel Cell Module.
The intent of the PSDF is to provide a flexible test facility that can be used to develop advanced power system components,
evaluate advanced turbine and fuel cell system configurations,
and assess the integration and control issues of these advanced
power systems. The facility would provide a resource for rigorous, long-term testing and performance assessment of hot stream
cleanup devices in an integrated environment, permitting evaluation of not only the cleanup devices but also other components in
an integrated operation.
The facility will be located at the Southern Company's Clean Coal Research Center in Wilsonville. AL. It will be sized to feed
104 tons per day of Illinois No. 6 bituminous coal with a Powder River subbituminous coal as an alternate coal.
The advanced gasifier module involves M.W. Kellogg's transport technology for pressurized combustion and gasification to provide
either an oxidizing or reducing gas for parametric testing of hot particulate control devices. The transport reactor is sized to
process nominally 2 tons per hour of coal to deliver 1,000 ACFM of particulate laden gas to the PCD inlet over the temperature
range of 1,000 to 1,800F at 300 psig.
The second-generation APFBC system is capable of achieving 45 percent net plant efficiency. The APFBC system designed for the
PSDF consists of a high pressure (170 psia), medium temperature (1,600F) carbonizer to generate 1300 ACFM of low-BTU fuel
gas and a circulating PFBC (operating at 150 psia, 1.600T) generating 7300 ACFM combustion gas. The coal feed rate to car
bonizer willbe 2.75 tons per hour, and with the Longview limestone, a Ca/S molar ratio of 1.75 is required to capture 90 percent of
the sulfur in the carbonizer/CPFBC. The gas exiting from the carbonizer and the CPFBC is filtered hot to remove particulates
prior to the topping combustor.
A Multi-Annular Swirl Burner (MASB) is chosen to combust the gases from the carbonizer and increase the temperature of the
CPFBC flue gases to 2,350F. The exit gases are, however, cooled to 1,970F in order to meet the temperature limitation on the
gas turbine.
The hot gas is expanded through a gas turbine (Allison Model 501-KM), powering both the electric generator and air compressor.
The hot gases coming off the transport reactor, carbonizer and CPFBC will be cleaned by different PCDs. PCDs from Combustion
Power Company. Industrial Filter and Pump and Westinghouse will be tested at the PSDF. The list includes ceramic cross-flow,
candle and tube filters and screenless granular bed filters.
4-78
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL AND R&D PROJECTS (Continued)
Plans are being made to eventually integrate a fuel cell module with the transport gasifier during the second year of operation. The
capacity of the fuel cell to be tested initially is set at 100 kW. Provision has been made in the site layout of the PSDF to phase in a
multi-MW fuel cell module with commercial stacks utilizing more than 80 percent of gases from the transport gasifier.
Installation is scheduled to be completed by fall of 1995 for the transport reactor and March 1996 for the APFBC. Two years of
operation are planned.
Project Cost: $157 million 80% by U.S. Department of Energy
WUJING - TRIGENERATION PROJECT Shanghai
Coking and Chemical Plant (C-620)
Shanghai Coking and Chemical Plant (SCCP) is planning 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 Shan
ghai. SCCP contracted with Bechtel on June 6, 1986 to conduct a technical and economic feasibility study of the project.
The 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 1.7 million cubic meters per day of 3,800 Kcal per cubic
meter of town gas; 60,000 kilowatt-hours of electricity per year; 100 metric tons per hour of low pressure steam; and 200,000 metric
tons per year of 99.85 percent purity chemical grade methanol, 50,000 metric tons per year of acetic anhydride, and 50,000 metric
tons per year of cellulose acetate. The project will be constructed in three phases.
In Phase 1, the production plan is further divided into 2 stages. In the first stage, L7 million cubic meters per day of town gas will
be produced. The second stage will produce 200.000 tons per year of methanol.
In November 1991, SCCP and Texaco Development Corporation signed an agreement for Texaco to furnish the gasifier, coal slurry
and methanol systems. SCCP will import other advanced technologies and create foreign joint ventures at later stages for the
production of acetic anhydride, formic acid, cellulose acetate and combined cycle power generation.
In March 1992, a foundation stone laying ceremony was performed at the plant site. In December of 1993, three sets of Air
Separation units, each producing 11,000 cubic meters per hour of 99.6% oxygen, were started up.
pleted by June 1995.
Phase 1 is scheduled to be com
Project Cost: 2 billion yuan
- YIMA CrTY COAL GASIFICATION PROJECT Future
China (C-622)
Fuels. Pty. Ltd.. Henan Provincial Government, and Central Government of
Future Fuels, a wholly-owned subsidiary of Rentech. Inc., has signed a contract to provide engineering design and equipment for a
gas conversion plant to be located near Yima City in Henan Province, China. Funding has been provided by the Australian govern
ment, the Henan Provincial Government, and Central Government of China.
The plant will use Rentech's proprietary technology to convert low-grade coal to gas for more than 03 million homes and a waste
gas as feedstock for a Rentech gas conversion plant designed to produce 545 barrels/day of diesel fuel and waxes. Work under the
contract is expected to be started in early 1995.
YUNNAN LURGI CHEMICAL FERTILIZERS PLANT- Yunnan Province, China (C-625)
In the 1970s, a chemical fertilizer plant was set up in Yunnan province by using Lurgi pressurized gasifiers of 2.7 meter diameter.
The pressurized gasification of a coal water slurry has completed a model test with a coal throughput of 20 kilograms per hour and
achieved success in a pilot unit of 13 tons per hour. The carbon conversion reached 95 percent, with a cold gas efficiency of
66 percent.
For water-gas generation, coke was first used as feedstock. In the 1950s, experiments of using anthracite to replace coke were suc
cessful, thus reducing the production cost of ammonia by 25 to 30 percent. In order to substitute coal briquettes for lump
anthracite, the Beijing Research Institute of Coal Chemistry developed a coal briquetting process in which humate was used as a
binder to produce synthetic gas for chemical fertilizer production. This process has been applied to production.
- YUNNAN PROVINCE COAL GASIFICATION PLANT People's
Republic of China (C-630)
China is building a coal gasification plant in Kunming, Yunnan Province, that will produce about 220,000 cubic meters of coalgas
per day. Joe Ng Engineering of Ontario, Canada has been contracted to design and equip the plant with the help of a $5 million
loan from the Canadian Export Development Corporation.
4-79
SYNTHETIC FUELS REPORT, JANUARY 1995

Project Sponsors
COMPLETED AND SUSPENDED PROJECTS
A-C Valley Corporation Project A-C Valley Corporation
ACME Coal Gasification Desulfuring Process ACME Power Company
Acurex-Aerotherm Low-BTU Gasifier
for Commercial Use
ADL Extractive Coking Process
Development
Advanced Coal Liquefaction Pilot Plant -
at Wilsonville
Advanced Flash Hydropyrolysis
AECI Ammonia/Methanol Operations
Agglomerating Burner Project
Air Products Slagging Gasifier
Project
Alabama Synthetic Fuels Project
Amax/EERC Mild Gasification
Demonstration
Amax Coal Gasification Plant
Appalachian Project
Aqua Black Coal-Water Fuel
Arkansas Lignite Conversion
Project
Australian SRC Project
Beach-Wibaux Project
Beacon Process
Bell High Mass Flux Gasifier
Beluga Methanol Project
BEWAG GCC Project
Acurex-Aerotherm Corporation
Glen-Gery Corporation
United States Department of Energy
Arthur D. Little, Inc.
Foster-Wheeler
United States Department of Energy
Amoco, Inc.
Electric Power Research Institute
United States Department of Energy
Rockwell International
U.S. Department of Energy
AECI Ltd.
Battelle Memorial Institute
United States Department of Energy
Air Products and Chemicals, Inc.
AMTAR Inc.
Applied Energetics Inc.
Amax, Inc.
North Dakota Energy & Environment Research Center
AMAX, Inc.
M. W. Kellogg Co.
United States Department of Energy
Gallagher Asphalt Company,
Standard Havens, Inc.
Dow Chemical Company,
Electee Inc.
International Paper Company
CSR Ltd.
Mitsui Coal Development Pty, Ltd.
See Tenneco SNG from Coal
Standard Oil Company (Ohio)
TRW, Inc.
Bell Aerospace Textron
Gas Research Institute
United States Department of Energy
Cook Inlet Region, Inc.
Placer U. S. Inc.
BEWAG AG
Energie-Anlagen Berlin GmbH
Lurgi GmbH
4-80
Last Appearance in SFR
June 1984; page 4-59
June 1994, page 4-52
September 1981; page 4-52
March 1978; page B-23
March 1994; page 4-56
June 1987; page 4-47
June 1994; page 4-52
September 1978; page B-22
September 1985; page 4-61
June 1984; page 4-60
March 1994; page 4-57
March 1983; page 4-85
September 1989; page 4-53
December 1986;
page 4-35
December 1984; page 4-64
September 1985; page 4-62
March 1985; page 4-62
December 1981; page 4-72
December 1983; page 4-77
June 1994; page 4-53
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project
BI-GAS Project
Breckinridge Project
BRICC Coal Liquefaction Program
Broken Hill Project
Brookhaven Mild Gasification of Coal
Burnham Coal Gasification
Project
Byrne Creek Underground Coal
Gasification
Calderon Fixed-Bed Slagging Project
Car-Mox Low-BTU Gasification
Project
Catalytic Coal Liquefaction
Caterpillar Low BTU Gas From Coal
Celanese Coastal Bend Project
Celanese East Texas Project
Central Arkansas Energy Project
Central Maine Power Company
Sears Island Project
Chemically Active Fluid Bed
Project
Chemicals from Coal
Cherokee Clean Fuels Project
Chesapeake Coal-Water Fuel
Project
Chiriqui Grande Project
Chokecherry Project
Sponsors
Ruhrkohle Oel und Gas GmbH
United States Department of Energy
Bechtel Petroleum, Inc.
Beijing Research Institute of Coal Chemistry
Broken Hill Proprietary Company Ltd.
Brookhaven National Laboratory
United States Department of Energy
El Paso Natural Gas Company
Dravo Constructors
World Energy Inc.
Calderon Energy Company
Fike Chemicals, Inc.
Gulf Research and Development
Caterpillar Tractor Company
Celanese Corporation
Celanese Corporation
Arkansas Power & Light Company
Central Maine Power Company
General Electric Company
Stone & Webster Engineering
Texaco Inc.
Central & Southwest Corporation (four
utility companies)
Environmental Protection Agency (EPA)
Foster Wheeler Energy Corporation
Dow Chemical USA
United States Department of Energy
Bechtel Corporation
Mono Power Company
Pacific Gas & Electric Company
Rocky Mountain Energy
ARC-COAL, Inc.
Bechtel Power Corporation
COMCO of America, Inc.
Dominion Resources, Inc.
Ebasco Services, Inc.
United States State Department (Trade & Development)
Energy Transition Corporation
4-81
Last Appearance in SFR
March 1985; page 4-63
December 1983; page 4-78
March 1992; page 4-50
June 1994; page 4-54
June 1994; page 4-55
September 1983; page 4-62
March 1987; page 4-90
December 1985; page 4-73
March 1980; page 4-53
December 1978; page B-25
September 1988; page 4-55
December 1982;
page 4-83
December 1982; page 4-83
June 1984; page 4-63
June 1984; page 4-63
December 1983: page 4-80
March 1978; page B-24
September 1981; page 4-55
March 1985; page 4-64
June 1987; page 4-51
December 1983; page 4-81
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project Sponsors Last Appearance in SFR
Circle West Project
Clark Synthesis Gas Project
Clean Coke Project
Coalcon Project
Coalex Process Development
COGAS Process Development
Colstrip Cogeneration Project
Columbia Coal Gasification
Project
Combined Cycle Coal Gasification
Energy Centers
Composite Gasifier Project
Conoco Pipeline Gas Demonstra
tion Plant Project
Cool Water Gasification Program
Corex Iron Making Process
Cresap
Liquid Fuels Plant
Crow Indian Coal Gasification
Project
Meridian Minerals Company
Clark Oil and Refining Corporation
United States Department of Energy
U.S. Steel
USS Engineers and Consultants, Inc.
Union Carbide Corporation
Coalex Energy
COGAS Development Company, a joint
venture of:
Consolidated Gas Supply Corporation
FMC Corporation
Panhandle Eastern Pipeline Company
Tennessee Gas Pipeline Company
Bechtel Development Company
Colstrip Energy Limited Partnership
Pacific Gas and Electric Company
Rosebud Energy Corporation
Columbia Gas System, Inc.
Consumer Energy Corporation
British Gas Corporation
British Department of Energy
Conoco Coal Development Company
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
Bechtel Power Corporation
Empire State Electric Energy Research Corporation
Electric Power Research Institute
General Electric Company
Japan Cool Water Program Partnership
Sohio Alternate Energy
Southern California Edison
Korf Engineering
Fluor Engineers and Constructors
United States Department of Energy
Crow Indian Tribe
United States Department of Energy
4-82
September 1986; page 4-58
December 1982; page 4-85
December 1978; page B-26
December 1978; page B-26
December 1978; page B-26
December 1982; page 4-86
December 1990; page 4-59
September 1982; page 4-72
December 1982; page 4-86
September 1981; page 4-56
September 1981; page 4-57
September 1989; page 4-58
March 1990; page 4-51
December 1979; page 4-67
December 1983; page 4-84
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project Sponsors Last Appearance in SFR
Crow Indian Coal-to-Gasoline
Project
Danish Gasification Combined
Cycle Project
DeSota County, Mississippi
Coal Project
Dow Coal Liquefaction Process
Development
Dow Gasification Process Development
EDS Process
Elmwood Coal-Water-Fuel Project
Emery Coal Conversion Project
Enrecon Coal Gasifier
Escrick Cyclone Gasifier Test
Exxon Catalytic Gasification
Process Development
Fairmont Lamp Division Project
Fast Fluid Bed Gasification
Fiat/Ansaldo Project
Flash Pyrolysis Coal
Conversion
Flash Pyrolysis of Coal
Florida Power Combined Cycle
Project
Freetown IGCC Project
Fuel Gas Demonstration Plant
Program
Crow Indian Tribe
TransWorld Resources
Elkraft
Mississippi Power and Light
Mississippi, State of
Ralph M. Parsons Company
Dow Chemical Company
Dow Chemical Company
Anaconda Minerals Company
ENI
Electric Power Research Institute
Exxon Company USA
Japan Coal Liquefaction Development Co.
Phillips Coal Company
Ruhrkohle A.G.
United States Department of Energy
Foster Wheeler Tennessee
Emery Synfuels Associates:
Mountain Fuel Supply Company
Mono Power Company
Enrecon, Inc.
Oaklands Limited
Exxon Company USA
Westinghouse Electric Corporation
Hydrocarbon Research, Inc.
United States Department of Energy
Ansaldo
Fiat TTG
KRW Energy Systems, Inc.
Occidental Research Corporation
United States Department of Energy
Brookhaven National Laboratory
Florida Power Corporation
United States Department of Energy
Texaco Syngas Inc.
Commonwealth Energy
General Electric Co.
Foster-Wheeler Energy Corporation
United States Department of Energy
4-83
September 1984; page C-8
December 1991; page 4-75
September 1981; page 4-58
December 1984; page 4-70
June; 1987 page 4-53
June 1985; page 4-63
March 1987; page 4-66
December 1983; page 4-84
September 1985; page 4-66
March 1991; page 4-81
December 1984; page 4-73
September 1982; page 4-76
December 1982; page 4-90
March 1985; page 4-66
December 1982; page 4-91
June 1988; page 4-69
December 1983; page 4-87
December 1993; page 4-73
September 1980; page 4-68
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project
Fularji Low-BTU Gasifier
Gas Turbine Systems Development
GFK Direct Liquefaction Project
Grants Coal to Methanol Project
Greek Lignite Gasification Project
Grefco Low-BTU Project
Gresik IGCC Plant
GSP Pilot Plant Project
Gulf States Utilities Project
Hampshire Gasoline Project
Hanover Energy Doswell Project
H-Coal Pilot Plant
Hillsborough Bay Coal-Water
Fuel Project
Howmet Aluminum
H-R International Syngas Project
Huenxe CGT Coal Gasification Pilot Plant
Hydrogen from Coal
HYGAS Pilot Plant Project
ICGG Pipeline Gas Demonstra
tion Plant Project
Sponsors
MW. Kellogg Company
People's Republic of China
Curtiss-Wright Corporation
United States Department of Energy
General Electric Company
German Federal Ministry for Research & Technology
Saarbergwerke AG
GFK Gesellschaft fur Kohleverflussiqung
Energy Transition Corporation
Nitrogenous Fertilizer Industry (AEVAL)
General Refractories Company
United States Department of Energy
Perusahaan Umum Listrik Negara
German Democratic Republic
KRW Energy Systems
Gulf States Utilities
Kaneb Services
Koppers Company
Metropolitan Life Insurance Company
Northwestern Mutual Life Insurance
Doswell Limited Partnership
Ashland Synthetic Fuels, Inc.
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
ARC-Coal Inc.
Bechtel Power Corporation
COMCO of America, Inc.
Howmet Aluminum Corporation
H-R International, Inc.
The Slagging Gasification Consortium
Carbon Gas Technology (CGT) GmbH
Air Products and Chemicals, Inc.
United States Department of Energy
Gas Research Institute
Institute of Gas Technology
United States Department of Energy
Illinois Coal Gasification Group
United States Department of Energy
4-84
Last Appearance in SFR
December 1988; page 4-59
December 1983; page 4-87
March 1994; page 4-69
December 1983; page 4-89
September 1988; page 4-61
December 1983;
June 1994; page 4-65
page 4-91
December 1991; page 4-80
March 1985. page 4-74
December 1983; page 4-91
March 1991; page 4-84
December 1983; page 4-92
September 1985; page 4-69
March 1985, page 4-74
December 1985, page 4-80
March 1991; page 4-85
December 1978; page B-31
December 1980; page 4-86
September 1981; page 4-66
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project Sponsors Last Appearance in SFR
Integrated Two-Stage Liquefaction
ITT Coal to Gasoline Plant
Kaiparowits Project
Kansk-Achinsk Basin Coal Liquefaction
Pilot Plant
Kennedy Space Center Polygeneration
Project
Ken-Tex Project
Keystone Project
King-Wilkinson/Hoffman Project
KILnGAS Project
Klockner Coal Gasifier
Kohle Iron Reduction Process
KRW Energy Systems Inc. Advanced
Coal Gasification System for
Electric Power Generation
Lake DeSmet SNG from Coal
Project
LaPorte Liquid Phase Methanol
Synthesis
Latrobe Valley Coal Lique
faction Project
LC-Fining Processing of SRC
LIBIAZ Coal-To-Methanol Project
Liquefaction of Alberta
Subbituminous Coals, Canada
Low-BTU Gasifiers for Corn-
Cities Service/Lummus
International Telephone & Telegraph
J.W.Miller
United States Department of Energy
Arizona Public Service
San Diego Gas and Electric
Southern California Edison
Union of Soviet Socialist Republics
National Aeronautics & Space
Administration
Texas Gas Transmission Corporation
The Signal Companies
E. J. Hoffman
King-Wilkinson, Inc.
Allis-Chalmers
State of Illinois
United States Department of Energy
Central Illinois Light Company
Electric Power Research Institute
Illinois Power Company
Ohio Edison Company
Klockner Kohlegas
CRA (Australia)
Weirton Steel Corp
U.S. Department of Energy
M.W. Kellogg Company
U.S. Department of Energy
Westinghouse Electric
Texaco Inc.
Transwestem Coal Gasification Company
Air Products and Chemicals Inc.
Chem Systems Inc.
Electric Power Research Institute
U.S. Department of Energy
Rheinische Braunkohlwerke AG
Cities Service Company
United States Department of Energy
Krupp Koppers, KOPEX
Alberta/Canada Energy Resources
Research Fund
Alberta Research Council
Irvin Industrial Development, Inc.
4-85
September 1986; page 4-69
December 1981; page 4-93
March 1978; page B-18
March 1992; page 4-82
June 1986; page 4-85
December 1983; page 4-95
September 1986; page 4-71
March 1985; page 4-80
December 1988; page 4-65
March 1987; page 4-74
December 1987; page 4-75
December 1991; page 4-84
December 1982; page 4-98
December 1991; page 4-85
December 1983; page 4-96
December 1983; page 4-96
December 1988; page 4-65
March 1985, page 4-81
June 1979; page 4-89
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project Sponsors Last Appearance in SFR
mercial Use-Irvin Industries
Project
Low/Medium-BTU Gas for Multi-
Company Steel Complex
Low-Rank Coal Liquefaction
Project
Lulea Molten Iron Gasification Pilot Plant
Lummus Coal Liquefaction
Development
Mapco Coal-to-Methanol Project
Mazingarbe Coal Gasification Project
Medium-BTU Gas Project
4-107
Medium-BTU Gasification Project
Memphis Industrial Fuel Gas
Project
Methanol from Coal
Methanol from Coal
Midrex Electrothermal Direct
Reduction Process
Mild Gasification of Western Coal
Millmerran Coal Liquefaction
and Mining Industrial Fuel Gas
Group Gasifier
Kentucky, Commonwealth of
United States Department of Energy
Bethlehem Steel Company
United States Department of Energy
Inland Steel Company
Jones & Laughiin Steel Company
National Steel Company
Northern Indiana Public Service Company
Union Carbide Corporation
United States Department of Energy
University of North Dakota
KHD Humbolt Wedag AG and
Sumitomo Metal Industries, Ltd.
Lummus Company
United States Department of Energy
Mapco Synfuels
Cerchar (France)
European Economic Community
Gas Development Corporation
Institute of Gas Technology
Columbia Coal Gasification
Houston Natural Gas Corporation
Texaco Inc.
CBI Industries Inc.
Cives Corporation
Foster Wheeler Corporation
Great Lakes International
Houston Natural Gas Corporation
Ingersoll-Rand Company
Memphis Light, Gas & Water Division
UGI Corporation
Wentworth Brothers, Inc.
(19 utility and industrial sponsors)
Georgetown Texas Steel Corporation
Midrex Corporation
Amax
Western Research Institute
Australian Coal Corporation
American Natural Service Co.
Amerigas
Bechtel
Black, Sivalls & Bryson
Burlington Northern
Cleveland-Cliffs
Davy McKee
Dravo
EPRI
4-86
December 1983; page 4-98
March 1984; page 4-49
March 1991; page 4-90
June 1981; page 4-74
December 1983; page 4-98
September 1985, page 4-73
September 1979; page
December 1983; page 4-99
June 1984; page 4-79
March 1978; page B-22
March 1980; page 4-58
September 1982; page 4-87
March 1994; page 4-76
March 1985; page 4-82
March 1987; page 4-78
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project Sponsors Last Appearance in SFR
Minnegasco High-BTU Gas
from Peat
Minnegasco Peat Biogasification
Project
Minnegasco Peat Gasification
Project
Minnesota Power ELFUEL Project
Mobil-M Project
Molten Salt Process Development
Monash Hydroliquefaction Project
Mountain Fuel Coal Gasification Process
Mulberry Coal-Water Fuel Project
NASA Lewis Research Center Coal-to-
Gas Polygeneration Power Plant
National Synfuels Project
New England Energy Park
New Jersey Coal-Water Fuel
Project
Hanna Mining Co.
Peoples Natural Gas
Pickands Mather
Reserve Mining
Riley Stoker
Rocky Mountain Energy
Stone & Webster
U.S. Bureau of Mines
U.S. Department of Energy
U.S. Steel Corporation
Western Energy Co.
Weyerhaeuser
Minnesota Gas Company
United States Department of Energy
Minnesota Gas Company
Northern Natural Gas Company
United States Department of Energy
Gas Research Institute
Institute of Gas Technology
Minnesota Gas Company
Northern Natural Gas Company
United States Department of Energy
Minnesota Power & Light
BNI Coal
Institute of Gas Technology
Electric Power Research Institute
Bechtel Corporation
Mobil Oil Company
Rockwell International
United States Department of Energy
Coal Corporation of Victoria
Monash University
Mountain Fuel Resources
Ford Bacon & Davis
CoaLiquid, Inc.
NASA Lewis Research Center
Elgin Butler Brick Company
National Synfuels Inc.
Bechtel Power Corporation
Brooklyn Union Gas Company
Eastern Gas & Fuel Associates
EG&G
Westinghouse Corporation
United States Department of Energy
Ashland Oil, Inc.
Babcock & Wilcox Company
Slurrytech, Inc.
4-87
March 1983; page 4-108
December 1981; page 4-88
December 1983; page 4-101
June 1991; page 4-82
September 1982; page 4-88
December 1983; page 4-101
June 1994; page 4-70
September 1988: page 4-67
March 1985; page 4-85
December 1983; page 4-102
September 1988; page 4067
December 1983; page 4-104
March 1985; page 4-86
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project Sponsors Last Appearance in SFR
New Mexico Coal Pyrolysis Project
Nices Project
North Alabama Coal to Methanol
Project
North Dakota Synthetic Fuels
Project
NYNAS Energy Chemicals Complex
Oberhausen Coal Gasification
Project
Ohio I Coal Conversion
Ohio I Coal Conversion Project
Ohio Coal/Oil Coprocessing Project
Ohio Valley Synthetic Fuels
Project
Ostrava District Heating Plant
Ott Hydrogeneration Process
Project
Peat-by-Wire Project
Peat Methanol Associates Project
Penn/Sharon/Klockner Project
Philadelphia Gas Works Synthesis
Gas Plant
Phillips Coal Gasification
Project
Energy Transition Corporation
Northwest Pipeline Corporation
Air Products & Chemicals Company
Raymond International Inc.
Tennessee Valley Authority
InterNorth
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
AGA
A. Johnson & Company
Swedish Investment Bank
Ruhrchemie AG
Ruhrkohle Oel & Gas GmbH
Alberta Gas Chemicals, Inc.
North American Coal Corporation
Wentworth Brothers
Energy Adaptors Corporation
Ohio Clean Fuels, Inc.
Stone and Webster Engineering Corp.
HRI Inc.
Ohio Coal Development Office
United States Department of Energy
Consolidated Natural Gas System
Standard Oil Company of Ohio
ABB Carbon
Carl A. Ott Engineering Company
PBW Corporation
ETCO Methanol Inc.
J. B. Sunderland
Peat Methanol Associates
Transco Peat Methanol Company
Klockner Kohlegas GmbH
Pennsylvania Engineering Corporation
Sharon Steel Corporation
Philadelphia Gas Works
United States Department of Energy
Phillips Coal Company
4-88
September 1988; page 4-67
December 1983; page 4-104
March 1985; page 4-86
December 1983; page 4-106
December 1990; page 4-76
September 1986; page 4-79
March 1985; page 4-88
March 1990; page 4-65
June 1991; page 4-84
March 1982; page 4-68
June 1994; page 4-73
December 1983; page 4-107
March 1985; page 4-89
June 1984; page 4-85
March 1985; page 4-72
December 1983; page 4-108
September 1984; page C-28
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project
Pike County Low-BTU Gasifier
for Commercial Use
Plasma Arc Torch
Corporation
Port Sutton Coal-Water Fuel Project
Powerton Project
Purged Carbons Project
Pyrolysis Demonstration Plant
Pyrolysis of Alberta Thermal Coals,
Canada
Riser Cracking of Coal
RUHR100 Project
Rheinbraun Hydrogasification of Coal
Saarbergwerke-Otto Gasification
Process
Savannah Coal-Water Fuel Projects
Scrubgrass Project
Sesco Project
Sharon Steel
Shell Coal Gasification Project
Simplified IGCC Demonstration Project
Sponsors
Appalachian Regional Commission
Kentucky, Commonwealth of
United States Department of Energy
Swindell-Dresser Company
Technology Application Service
ARC-Coal, Inc.
COMCO of America, Inc.
Commonwealth Edison
Electric Power Research Institute
Fluor Engineers and Constructors
Illinois, State of
United States Department of Energy
Integrated Carbons Corporation
Kentucky, Commonwealth of
Occidental Research Corporation
Tennessee Valley Authority
Alberta/Canada Energy Resource
Research Fund
Alberta Research Council
Institute of Gas Technology
United Sates Department of Energy
Ruhrgas AG
Ruhrkohle AG
Steag AG
West German Ministry of Research
and Technology
Reinische Braunkohlenwerke
Lurgi GmbH
Ministry of Research & Technology
Saarbergwerke AG
Dr. C. Otto & Company
Foster Wheeler Corporation
Scrubgrass Associates
Solid Energy Systems Corporation
Klockner Kohlegas GmbH
Pennsylvania Engineering Corporation
Sharon Steel Corporation
Shell Oil Company
Royal Dutch/Shell Group
General Electric Company sep
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
4-89
Last Appearance in SFR
June 1981; page 4-78
December 1978; page B-33
December 1985; page 4-86
March 1979; page 4-86
December 1983; page 4-108
December 1978; page B-34
March 1985; page 4-90
December 1981;
page 4-93
September 1984: page C-29
December 1987; page 4-80
June 1984; page 4-86
September 1985; page 4-77
March 1990; page 4-69
December 1983; page 4-110
March 1985; page 4-92
June 1991; page 4-89
September 1986; page 4-71
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project Sponsors Last Appearance in SFR
Slagging Gasification Consortium
Project
Sohio Lima Coal Gasification/
Ammonia Plant Retrofit Project
Solution-Hydrogasification
Process Development
South Australian Coal Gasification
Project
Southern California Synthetic
Fuels Energy System
Solvent Refined Coal Demonstration
Plant
Steam-Iron Project
Synthane Project
Synthoil Project
Sweeny Coal-to-Fuel Gas Project
Tenneco SNG From Coal
Tennessee Synfuels Associates
Mobil-M Plant
Toscoal Process Development
Transco Coal Gas Plant
Tri-State Project
TRW Coal Gasification Process
TVA Ammonia From Coal Project
Two-Stage Entrained Gasification
System
United States Department of Energy
Babcock Woodall-Duckham Ltd.
Big Three Industries, Inc.
The BOC Group pic
British Gas Corporation
Consolidation Coal Company
Sohio Alternate Energy Development
Company
General Atomic Company
Stone & Webster Engineering Company
Government of South Australia
C. F. Braun
Pacific Lighting Corporation
Southern California Edison Company
Texaco Inc.
International Coal Refining Company
Air Products and Chemicals Inc.
Kentucky Energy Cabinet
United States Department of Energy
Wheelabrator-Frye Inc.
Gas Research Institute
Institute of Gas Technology
United States Department of Energy
United States Department of Energy
Foster Wheeler Energy Corporation
United States Department of Energy
The Signal Companies, Inc.
Tenneco Coal Company
Koppers Company, Inc.
TOSCO Corporation
Transco Energy Company
United States Department of Energy
Kentucky Department of Energy
Texas Eastern Corporation
Texas Gas Transmission Corporation
United States Department of Energy
TRW, Inc.
Tennessee Valley Authority
Combustion Engineering Inc.
Electric Power Research Institute
United States Department of Energy
4-90
September 1985; page 4-78
March 1985; page 4-93
September 1978; page B-31
December 1992; page 4-75
March 1981; page 4-99
September 1986; page 4-83
December 1978; page B-35
December 1978; page B-35
December 1978; page B-36
March 1985; page 4-94
March 1987; page 4-85
December 1983; page 4-112
September 1988; page 4-72
December 1983;
page 4-113
December 1983; page 4-113
December 1983; page 4-114
September 1989; page 4-77
June 1984; page 4-91
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project Sponsors Last Appearance in SFR
Underground Bituminous Coal
Gasification
Underground Coal Gasification
Underground Coal Gasification,
Ammonia/Urea Project
Underground Gasification of Anthracite,
Spruce Creek
Underground Coal Gasification, Joint
Belgo-German Project
UCG Brazil
UCG Brazil
Underground Coal Gasification,
Canada
Underground Coal Gasification,
English Midlands Pilot Project
Underground Coal Gasification,
Hanna Project
Morgantown Energy Technology Center
United States Department of Energy
University of Texas
Energy International
Spruce Creek Energy Company
Government of Belgium
Compannia Auxiliar de Empresas Electricas Brasileriras
Companhia Auxiliar de Empresas Electricas Brasileiras
U.S. DOE
Alberta Research Council
British Coal
Rocky Mountain Energy Company
United States Department of Energy
Underground Coal Gasification, Leigh Creek Government of South Australia
Underground Coal Gasification
Hoe Creek Project
Underground Coal Gasification LLNL
Studies
Underground Coal Gasification
Underground Coal Gasification
Rocky Hill Project
Underground Coal Gasification, Rocky
Mountain 1 Test
Underground Gasification of Deep Seams
Underground Gasification of
Texas Lignite, Tennessee
Colony Project
Underground Gasification of
Texas Lignite
Underground Coal Gasification, India
Underground Coal Gasification,
Thunderbird II Project
Lawrence Livermore National Laboratory
United States Department of Energy
Lawrence Livermore National Laboratory
Mitchell Energy
Republic of Texas Coal Company
ARCO
Amoco Production Company
Groupe d'Etudes de la Gazeification Souterraine
Charbonnages de France
Gaz de France
Institut Francais du Petrole
Basic Resources, Inc.
Texas A & M University
Oil and Natural Gas Commission
In Situ Technology
Wold-Jenkins
4-91
March 1987; page 4-93
June 1985; page 4-75
March 1990; page 4-76
March 1990; page 4-76
March 1990; page 4-74
September 1988; Page 4-75
December 1988; page 4-25
September 1984; page C-37
September 1987; page 4-76
June 1985; page 4-75
September 1989; page 4-81
December 1983; page 4-119
December 1990; page 4-84
March 1985; page 4-98
December 1983; page 4-120
March 1990; page 4-76
December 1987; page 4-86
December 1983; page 4-121
December 1983; page 4-121
March 1991; page 4-104
March 1985; page 4-102
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
COMPLETED AND SUSPENDED PROJECTS (Continued)
Project Sponsors Last Appearance in SFR
Underground Coal Gasification,
Washington State
Underground Gasification of
Texas Lignite, Lee County Project
Union Carbide Coal Conversion
Project
University of Minnesota
Low-BTU Gasifier for Commer
cial Use
Utah Methanol Project
Verdigris
VEW Gasification Process
Virginia Iron Corex Project
Virginia Power Combined Cycle Project
Watkins Project
Western Canada IGCC Demonstration Plant
Westinghouse Advanced Coal
Gasification System for
Electric Power Generation
Whitethorne Coal Gasification
Wyoming Coal Conversion Project
Zinc Halide Hydrocracking
Process Development
Sandia National Laboratories
Basic Resources, Inc.
Union Carbide/Linde Division
United States Department of Energy
University of Minnesota
United States Department of Energy
Questar Synfuels Corporation
Agrico Chemical Company
Vereinigte Elektrizitatswerke Westfalen AG
Virginia Iron Industries Corp.
Consolidation Coal
Electric Power Research Institute
Slagging Gasification Consortium
Virginia Electric and Power Company
Cameron Engineers, Inc.
Coal Association of Canada
Canadian Federal Government
KRW Energy Systems Inc.
United Synfuels Inc.
WyCoalGas, Inc. (a Panhandle Eastern
Company)
Conoco Coal Development Company
Shell Development Company
4-92
March 1983; page 4-124
March 1985; page 4-101
June 1984; page 4-92
March 1983; page 4-119
December 1985; page 4-90
September 1984; page C-35
June 1994; page 4-82
March 1992; page 4-78
December 1985; page 4-90
March 1978; page B-22
June 1994; page 4-84
September 1985; page 4-80
September 1984;
page C-36
December 1982; page 4-112
June 1981; page 4-86
SYNTHETIC FUELS REPORT, JANUARY 1995

Company or Organization
AECI Ltd.
Air Products and Chemicals, Inc.
Alastair Gillespie & Associates Ltd.
Amoco
Asian Development Bank
Bechtel Group
Beijing Research Institute of Coal Chemistry
Bharat Heavy Electricals Ltd.
British Coal Corporation
British Department of Energy
British Gas Corporation
Brown Coal Liquefaction Pty. Ltd.
Calderon Energy Company
Camden Clean Energy Partners Ltd.
Canadian Energy Developments
Carbocol
Carbon County UCG, Inc.
Carbon Fuels Corp.
Centerior Energy Corp.
Central Research Institute of Electric Power
Industry
CharFuels of Wyoming
China National Technical Import
Corporation
Coal Conversion Institute, Poland
Coal Gasification, Inc.
Coal Technology Corporation
Combustion Engineering
Continental Energy Associates
Cordero Mining Company
INDEX OF COMPANY INTERESTS
Project Name
Coalplex Project
Camden Clean Energy Project
COREX-CPICOR Integrated Steel/Power Plant
Laporte Alternative Fuels Development Program
Liquid Phase Methanol Process Demonstration
Scotia Synfuels Project
British Solvent Liquid Extraction Project
Qingdao Gasification Project
IMHEX Molten Carbonate Fuel Cell Demonstration
China Ash Agglomerating Gasifier Project
BHEL IGCC and Coal Gasification Project
Advanced Power Generation System
CRE Spouted Bed Gasifier
British Coal Liquid Solvent Extraction Project
MRS Coal Hydrogenator Process Project
Slagging Gasifier Project
Victorian Brown Coal Liquefaction Project
Calderon Energy Gasification Project
Camden Clean Energy Project
Frontier Energy Coprocessing Project
Colombia Gasification Project
Carbon County Underground Coal Gasification Project
CharFuels Project
COREX-CPICOR Integrated Steel/Power Plant
CRIEPI Entrained Flow Gasifier
CharFuels Project
Lu Nan Ammonia-from-Coal Project
Polish Direct Liquefaction Process
COGA-1 Project
CTC Continuous Mild Gasification Process
Mild Gasification Process Demonstration Unit
Lakeside Repowering Gasification Project
Humbolt Energy Center
Cordero Coal Upgrading Demonstration Project
4-93
Page
4-52
4-50
4-53
4-64
4-64
4-72
448
470
4-61
4-51
4-48
4-47
4-54
4-48
4-66
4-74
4-77
4^9
4-50
4-58
4-53
4-50
4-50
4-53
4-54
450
4-65
4-68
4-52
455
4-65
4-63
4-60
453
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
INDEX OF COMPANY INTERESTS (Continued)
Company or Organization Project Name Page
CRS Sirrine
Dakota Gasification Company
Delmarva Power & Light
Demkolec BV.
Destec Energy, Inc.
DEVCO
Duke Energy Corp.
Eastman Chemical Company
Electric Power Research Institute
ELCOGAS
Elsam
Encoal Corporation
ENDESA
Energie Verk
European Economic Community
Exxon
Fife Energy Ltd.
Fundacao de Ciencia e Technologia (CIENTEC)
Future Fuels, Pty. Ltd.
GE Environmental Services, Inc.
GEC/Alsthom
General Electric Company
German Federal Ministry of
Gulf Canada Products Company
Henan Provincial Government
HOECHSTAG
Institute of Gas Technology
Interproject Service AB
ISCOR
PyGas Demonstration Project
Great Plains Synfuels Plant
Delaware Clean Energy Project
SEP IGCC Power Plant
Wabash River Coal Gasification Repowering Project
Scotia Coal Synfuels Project
Camden Clean Energy Project
Liquid Phase Methanol Process Demonstration
Laporte Alternative Fuels Development Program
Puertollano IGCC Demonstration Plant
Elsam Gasification Combined Cycle Project
Encoal LFC Demonstration Plant
Puertollano IGCC Demonstration Plant
Vartan District Heating Plant
British Coal Liquid Solvent Extraction Project
British Coal Liquid Solvent Extraction Project
Fife IGCC Power Station
CIGAS Gasification Process Project
CIVOGAS Atmospheric Gasification Pilot Plant
Yima City Coal Gasification Project
GE Hot Gas Desulfurization
Advanced Power Generation System
Camden Clean Energy Project
Bottrop Direct Coal Liquefaction Pilot Plant Project
Rheinbraun High-Temperature Winkler Project
Scotia Coal Synfuels Project
Yima City Coal Gasification Project
Synthesegasanlage Rurh
IGT Mild Gasification Project
IMHEX Molten Carbonate Fuel Cell Demonstration
P-CIG Process
ISCOR Melter-Gasifier Process
494
470
458
455
473
478
472
450
4-64
4-64
4-70
456
4-56
470
4-77
4-48
4-48
457
4-51
4-52
4-79
4-58
447
4-50
448
470
4-72
479
474
4-61
4-61
4-67
4-62
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
INDEX OF COMPANY INTERESTS (Continued)
Company or Organization
K-Fuel Partners
The M.W. Kellogg Company
Kennecott Energy
Kerr-McGee Coal Corporation
Kilborn International
Krupp Koppers GmbH
Louisiana Gasification Technology, Inc.
LTV Steel Company Inc.
Lurgi GmbH
M-C Power Corporation
Minister of Economics, Small Business and
Technology of the State of North-Rhine,
Westphalia
Mission Energy
Mitsubishi Heavy Industries
Morgantown Energy Technology Center
New Energy and Industrial Technology
Development Organization
Nippon Steel Corporation
Nokota Company
NOVA
Nova Scotia Resources Limited
Osaka Gas Company
Otto-Simon Carves
Pennsylvania Energy Development Authority
People's Republic of China
Petro-Canada
PowerGen
Project Name
K-Fuel Commercial Facility
Page
4-62
Hot Gas Desulfurization in a Transport Reactor 4-60
M.W. Kellogg Upgrading of Refinery Oil and Petroleum Coke Project 4-66
Pinon Pine IGCC Powerplant
4-67
Pressurized Fluid Bed Combustion Advanced Concepts
4-69
Cordero Formcoke Plant
IGT Mild Gasification Project
Frontier Energy Coprocessing Project
PRENFLO Gasification Pilot Plant
Destec Syngas Project
COREX-CPICOR Integrated Steel/Power Plant
Rheinbraun High-Temperature Winkler Project
IMHEX Molten Carbonate Fuel Cell Demonstration
Bottrop
Direct Coal Liquefaction Pilot Plant
Synthesegasanlage Ruhr (SAR)
Delaware Clean Energy Project
China One Clean Coal Project
GE Hot Gas Desulfurization
CRIEPI Entrained Flow Gasifier Project
NEDO IGCC Demonstration Project
Nedol Bituminous Coal Liquefaction Project
P-CIG Process
Dunn Nokota Methanol Project
Scotia Coal Synfuels Project
Scotia Coal Synfuels Project
MRS Coal Hydrogenator Process Project
CRE Spouted Bed Gasifier
Humbolt Energy Center Project
Mongolian Energy Center
Qingdao Gasification Plant
Shanghai Chemicals from Coal Plant
Shougang Coal Gasification Project
Yima City Coal Gasification Project
Yunnan Province Coal Gasification Plant
Scotia Coal Synfuels Project
Advanced Power Generation System
4-95
453
4-61
458
4-69
4-55
4-53
4-70
461
448
4-74
4-55
4-51
4-58
454
4-66
4-67
4-67
4-56
472
472
4-66
4-54
4-60
4-65
4-70
4-74
474
479
479
4-72
447
SYNTHETIC FUELS REPORT. JANUARY 1995

STATUS OF COAL PROJECTS
INDEX OF COMPANY INTERESTS (Continued)
Company or Organization
PreussenElektra
PSI Energy Inc.
PURON
Research Ass'n For Hydrogen From Coal Process
Development, Japan
Rheinische Braunkohhverke AG
Rosebud SynCoal Partnership
Ruhrkohle AG
RWE Energie AG
Sasol Limited
SEP
SGI International
Shanghai Coking & Chemical Corporation
Shell
Sierra Pacific Power Company
Southern Company Services, Inc.
Star Enterprise
Stewart and Stevenson Services Inc.
TAMCO Power Partners
Tampella Power
TECO Power Services
Tennessee Eastman Company
Texaco Inc.
Texaco Development Corporation
Texaco Syngas Inc.
ThermoChem, Inc.
TAMCO Power Partners
Ube Industries, Ltd.
Uhde GmbH
United Kingdom Department of Energy
Project Name
Lubeck IGCC Demonstration Plant
4-64
Wabash River Coal Gasification Repowering Project 478
Cordero Formcoke Plant
Hycol Hydrogen From Coal Pilot Plant
4-53
4-60
Rheinbraun High-Temperature Winkler Project 470
Advanced Coal Conversion Process Demonstration 447
Bottrop Direct Coal Liquefaction Pilot Plant Project 448
British Coal Liquid Solvent Extraction Project 4-48
Synthesegasanlage Ruhr (SAR)
4-74
KoBra High-Temperature Winkler IGCC Demonstration Plant 4-63
Sasol 4-71
SEP IGCC Power Plant 4-73
China One Clean Coal Project 4-51
Wujing Trigeneration Project 4-79
Buggenum IGCC Power Plant 4-49
Pinon Pine IGCC Power Plant 4-67
Wilsonville Power Systems Development Facility
4-78
Delaware Clean Energy Project 4-55
IMHEX Molten Carbonate Fuel Cell Demonstration 4-61
Tom's Creek IGCC Demonstration Project 476
Tampella IGCC Process Demonstration 4-75
TECO IGCC Plant 4-75
Chemicals From Coal 4.51
Liquid Phase Methanol Process Demonstration 4-64
Delaware Clean Energy Project 4.55
Weihe Chemical Fertilizer Plant 4.77
Delaware Gean Energy Project 4.55
Texaco Cool Water Project 4.75
ThermoChem Pulse Combustion Demonstration 476
Tom's Creek IGCC Demonstration Plant 4.7$
Ube Ammonia-From-Coal Plant 4.75
Rheinbraun High-Temperature Winkler Project 4.70
Advanced Power Generation System 4.47
496
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF COAL PROJECTS
INDEX OF COMPANY INTERESTS (Continued)
Company or Organization Project Name Page
United Kingdom Department of Energy
United States Department of Energy
University of North Dakota Energy and
Environmental Research Center
Veba Oel GmbH
Victoria, State Government of
Voest-Alpine Industrieanlagenbau
Western Energy Company
Weyerhauser
Wyoming Coal Refining Systems, Inc.
Yunnan Province, China
Advanced Power Generation System
Advanced Coal Conversion Process Demonstration
Calderon Energy Gasification Project
CTC Continuous Mild Gasification Process
Encoal LFC Demonstration Plant
Frontier Energy Coprocessing Project
Hot Gas Desulfurization in a Transport Reactor
Lakeside Repowering Gasification Project
Laporte Alternative Fuels Development Program
Mild Gasification Process Demonstration Unit
4^7
447
449
455
456
458
4-60
4-63
4-64
4-65
M.W. Kellogg Upgrading of Refinery Oil and Petroleum Coke Project 466
Pinon Pine IGCC Power Plant 4-67
Power Systems Development Facility
4-68
PyGas Demonstration Project 4-70
TECO IGCC Plant 475
ThermoChem Pulse Combustion Demonstration 476
Tom's Creek IGCC Demonstration Plant 4-76
Wilsonville Power Systems Development Facility Project 478
Pressurized Fluidized Bed Combustion Advanced Concepts
Bottrop
Direct Coal Liquefaction Pilot Plant Project
Victorian Brown Coal Liquefaction Project
ISCOR Melter Gasifier Process
Advanced Coal Conversion Process Demonstration
ThermoChem Pulse Combustion Demonstration
CharFuel Project
Yunnan Lurgi Chemical Fertilizer Plant
4-97
4-69
4-48
4-77
4-62
4-47
4-76
4-50
4-79
SYNTHETIC FUELS REPORT, JANUARY 1995

4-98
SYNTHETIC FUELS REPORT, JANUARY 1995

PROJECT ACTIVITIES
SHELL MDS PRODUCT QUALITIES EXCEED
EXPECTATIONS
The 12,500 barrel per day Middle Distillate Syn
thesis (MDS) plant at Bintulu, Sarawak, Malaysia
has been in operation for over a year. According
to T. van Herwijnen of Shell MDS (Malaysia) Sdn
Bhd, speaking at a liquefied natural gas con
ference in Kuala Lumpur, Malaysia in October,
the project startup proved to be slow. Only after
1 year, did plant output approach design
capacity. The problems that had to be resolved
ranged from the interference of lightning strikes
on the electronic safeguarding systems to
development problems which were connected
with first-of-its-kind applications. The latter ap
plied not so much to the new technology itself
but to other units in the plant like the conven
tional air separation plant which is the world's
largest at 2,500 tons per day oxygen.
NATURAL GAS
TABLE 1
Shell MDS Products
By their nature, products from carbon monoxide
and hydrogen are extremely clean. They are al
most completely paraffinic and contain few con
taminants such as sulfur or nitrogen. In fact, in
dustrial analytical methods established for such
contaminants in refined crude oil-derived
products have lower cut-off levels for their
measurement ranges that are higher than the
levels of such impurities in the MDS products.
The quality
MIDDLE DISTILLATE FUEL PROPERTIES
of the products from the commercial
plant is equal to and in several respects better
than predicted on the basis of the pilot plant
tests. Table 1 shows some properties for the
middle distillate fuels. Given their exceptional
quality, they are ideal, high-value blending com
ponents for upgrading traditional products to
meet high product quality standards. At

NATURAL GAS
regulations of the California Air Resources Board.
SMDS fuels can obtain high premiums in un
diluted applications, provided that risks resulting
from the low lubricity are mitigated.
By the hydrogenation of raw waxes, specialty
hydrocarbons with high paraffinicity are
produced. Not only are these streams the basis
for clean solvents but also their applicability as
detergent feedstocks has been demonstrated.
The biodegradability, which is critical in such ap
plications, has been demonstrated to be fully ade
TABLE 2
PROPERTIES OF SMDS SPECIALTY CHEMICALS
quate because the limited amount of branching
present is mostly biodegradable methyl groups.
Table 2 shows some properties of the chemicals.
Heavy specialties from the plant consist of waxy
raffinate and food quality waxes. The pure paraf
finic hydrocarbons with well controlled properties
(Table 3) are value-
eminently suitable for high
added applications like hot melt adhesives. MDS
waxes conform to the regulations of the Food
and Drug Administration for food applications.
Units LDF HDF
Sayboit Color +30 +30
Bromine Index mgBr/100g 5.0 5.5
Sulfur ppm 1 1
Carbon Distribution
C8
C13
C14
C18
and Lighter %m 0.0
and Lighter %m 99.3 0.8
and Heavier %m 0.7 99.05
and Heavier %m 0.15
N-paraffins Content %m 96.1 95.4
Congealing Point
Sayboit Color
Odor
Oil Content @-32C
UV Absorptivity
TABLE 3
PROPERTIES OF SYNTHETIC WAX GRADES
Units SX30 SX50 SX70
%m
31
+30
2.5
6.2

NATURAL GAS
Prospects for Shell MDS Technology
The economics of the $850 million Bintulu project
could not be based on the production of middle
distillates alone. Even with significant premiums
resulting from the high quality of those materials,
production at the small 12,500-barrel per day
plant carries too much capital charge to be
profitable. For that reason, the scope of the
project was extended to include the production
of a number of specialty hydrocarbons, often at
production capacities that are large compared to
regional or world market demand.
This production of specialty products cannot be
repeated without flooding the markets for these
materials. Future commercial applications will
have to focus entirely on production of middle dis
tillates. The key to economic viability will be
larger and more capital-efficient manufacturing
facilities. In combination with new technological
developments, the specific capital cost for a
50,000 barrel per day complex is projected to be
reduced by some 40 percent to US$30,000 per
daily barrel of product. At that level, commercial
applications can become feasible at crude oil
prices of US$20 per barrel.
####
AMERICAN METHANOL BUILDING NEW
METHANOL PLANT IN WYOMING
American Methanol Ltd. has requested bids for
constructing
a new $30 million methanol plant
located about 15 miles west of Green River,
Wyoming. Construction should begin early this
year with production beginning in early 1996.
The anticipated construction workforce will peak
at 200 to 300 next summer. The permanent
workforce should be between 25 and 30.
A spokesman for the company said the low price
of natural gas, access to a cheap supply of car
bon dioxide from Exxon's Shute Creek plant, and
5-3
a local market for methanol were major factors in
locating the plant near Green River.
####
TAIWANESE MAY INVEST IN MOSSGAS
COMPLEX
According
News, the South African Government is consider
to a report in European Chemical
ing Taiwanese proposals to invest $8 billion in
the Mossgas project into a
developing
petrochemical refinery.
The Taiwanese plans include a plant for olefins, a
plant for aromatics, downstream plastics, and
fiber and textile production. The products would
be competitive in world markets.
A joint South African/Taiwanese task force has
been set up to evaluate the proposals. It will be
assessing whether or not to site the project at
Richards Bay or Mossel Bay.
The difference between the Taiwanese plan and
previous proposals is the focus on downstream
activities which dramatically increase the capital
requirements.
Previously, the Industrial Development Corpora
tion and Sentrachem had been considering in
vesting in the future of Mossgas.
The IDC/Sentrachem venture was thinking of a
far smaller investment project, worth $1.1 billion.
The South African Government has been seeking
a solution to Mossgas ever since it discovered
that the gas supplies are not as extensive as
originally thought.
The Taiwanese plans are long-term and do not
solve the government's immediate problem
about whether or not to continue investing in
Mossgas and prolong the life of the operation un
til the year 2001 .
THE SYNTHETIC FUELS REPORT, JANUARY 1995

NATURAL GAS
The South African Parliamentary Joint Committee
of Public Accounts Is said to be considering
several possibilities including pressuring existing
wells and drawing gas from satellite wells.
####
CORPORATIONS
RENTECH RAISES MONEY TO HELP
DEVELOPMENT EFFORTS
Rentech Inc. of Denver, Colorado raised about
$1 .3 million in a public stock offering in Septem
ber. The money will enable the company to fur
ther its commercialization of the Synhytech
process for converting synthesis gas to diesel
fuel and waxes.
Rentech has a project in Henan Province of
China under way to convert low-grade coal gas
into town gas, a cheaper alternative to heat build
ings in several cities.
Two other projects are slated for the states of
Gujarat and Arunachal Pradesh in India.
In the past 11 years, the company has lost
$3.4 million as it developed and finally brought
the technology, a variation on Fischer-Tropsch
Chemistry, to market.
For the Chinese project at Yima City, Lurgi
Australia is providing
tion and gas purification technology,
the fixed-bed coal gasifica
which con
verts the coal into synthesis gas. Some of that
gas will be sent to a byproducts plant, where
Rentech-developed technology will convert It into
naphtha, waxes and diesel fuel.
Rentech is part-owned by an Australia engineer
ing consultant group. CMPS&F, which has
teamed with another Australian company, Energy
Equipment, to build the facility in Yima City under
an A$90 million contract.
####
5-4
GOVERNMENT
NEW ZEALAND REFORMS AFFECT SYNFUEL
PLANT
A September article in the Qji & &S Journal
(O&GJ) notes that, on the 25th anniversary of the
discovery of its key source of hydrocarbon
production, offshore super-giant Maui
gas/condensate field, New Zealand faces some
critical choices in its energy future.
Maui, which supplies about 32 percent of New
Zealand's primary energy demand, is expected
to enter into decline after the turn of the century.
Discovered in 1969, Maui reserves then were es
timated at 5 trillion cubic feet of gas and
130 million barrels of condensate.
The field accommodates three-fourths of New
Zealand's natural gas demand. Its production
not only provides most of the natural gas con
sumed in the residential sector, it also feeds the
Motonui methanol-to-gasoline synfuels plant and
several petrochemical plants as well as two
electrical powerplants.
According to O&GJ the New Zealand Govern
ment has undergone a dramatic turnaround in its
approach to energy policy.
When oil import dependence became a concern
in the early 1970s, the New Zealand Government
intervened to make Maui the cornerstone of ef
forts to minimize dependence on foreign oil by
converting Maui gas to gasoline and creating a
new petroleum product export industry.
The country almost doubled total energy self-
sufficiency to 81 percent during 1975-1990 and
increased liquid fuels self-sufficiency from
4 percent in 1 975 to 51 percent in 1 990.
With Maui decline looming and a dearth of ex
ploration activity, the New Zealand Government
recently implemented steps designed to spark in
terest in oil and gas drilling by foreign com
panies.
THE SYNTHETIC FUELS REPORT, JANUARY 1995

NATURAL GAS
In addition to fiscal reforms, the government has
taken aggressive steps toward privatization.
One prediction is that New Zealand's domestic
hydrocarbon production, which now accounts
for 85 percent of its gas and transportation fuels
requirements, will account for only a 50 percent
share by 2000.
That forecast hinges on expectations for Maui.
New Zealand's synthetic fuels, methanol,
ammonia/urea, and electrical power industry es
sentially
were developed to take advantage of
low cost, abundant Maui gas. Accordingly, not
Maui production could see some of
replacing
those projects phase out or undertake costly
switches to more polluting fuels.
Of Maui production, 36 percent goes to
Electricity Corporation of New Zealand,
32 percent to the Motonui gas-to-gasoline plant,
19 percent to Natural Gas Corporation (NGC),
10 percent to the Petralgas methanol pant, and
3 percent to the Petrochem ammonia/urea plant.
The take or pay supply agreements for Maui gas
all will expire during 2003-2009. The Motonui con
tract expires in 2003 and the ammonia/urea and
methanol
plants'
contract in 2005.
Gas price increases could therefore make the
synthetic fuels and methanol plants uneconomic
by about 2009.
Retcher Challenge owns 68.75 percent of Maui
and notes that the giant field and its environs will
continue to play
Zealand's energy
voir has begun to decline.
an important role in New
sector even after the main reser
Remaining Maui interests are held by Shell
Petroleum Mining Ltd. (18.75 percent) and Todd
Petroleum Mining Ltd. (12.5 percent).
Maui production currently averages about
400-435 million cubic feet per day of gas.
5-5
New Zealand's government has reversed direc
tion on energy policy, changing from investing
heavily in energy projects to privatization and
deregulation.
In 1990, the government sold its interest in the
Motonui synfuels plant to Fletcher, which in turn
spun off its methanol and synfuels business and
NGC. Canada's Methanex New Zealand now
owns and operates both of New Zealand's
methanol plants and the synfuels plant.
####
TECHNOLOGY
BNL LIQUID PHASE METHANOL SYNTHESIS
FOUND PROMISING
Conventionally, methanol is produced in the gas
phase over copper-zinc-based oxide catalysts
according to the following reaction, which is
highly exothermic:
CO + 2 H2
= CH3OH
Recently, low-temperature methanol synthesis in
the liquid phase has received considerable atten
tion because it has the potential to overcome
problems found in the conventional methanol
processes. Two processes have been proposed:
- The
- The
Brookhaven National Laboratory
(BNL) low-temperature methanol
process
process through Methyl Formate
(MF) formation
Methanol synthesis via MF is supposed to
proceed by the following two reactions occurring
concurrently:
CH3OH + CO = HCOOCH
HCOOCH3 + 2H2 = 2 CH3OH
THE SYNTHETIC FUELS REPORT, JANUARY 1995

NATURAL GAS
The BNL process employs a homogeneous Ni
catalyst and alkoxide in an organic solvent, while
methanol synthesis via MF employs a mixture of
copper-based oxide and alkoxide as a catalyst.
Both processes are operated at around 373 K,
where high equilibrium conversion of carbon
monoxide to methanol is expected. The
processes have been reported to show excellent
activity even at such low temperatures.
S. Ohyama of the Central Research Institute of
Electric Power Industry in Tokyo, Japan has ex
amined the catalytic activities of these two
processes and assessed their possibilities as in
dustrial processes in terms of Space Time Yield
(STY). He discussed his findings at the Sym
posium on Alternative Routes for the Production
of Fuels, held as part of the 208th American
Chemical Society National Meeting held in
Washington, D.C. in August.
BNL Methanol Process
Methanol was formed quite selectively
over the
BNL catalysts at 353-433 K and 1 .1-5.0 MPa of ini
tial pressure. The STY with the BNL catalysts
varied with Ni concentration in the catalyst sys
tem and reached 0.89 kilograms per liter per hour
at the optimum concentration. At 433 K, the BNL
catalysts yielded almost 90 percent for CO con
version and over 99 percent for selectivity to
methanol. Because the catalyst is highly active
even at temperatures much lower than the operat
ing
temperature of the conventional methanol
process (503-543 K), it should be possible to
eliminate recycling facilities for unconverted gas,
which would reduce the production cost of
methanol.
Methanol Synthesis via MF
Methanol was formed rapidly
using
at around 373 K
a mixture of copper-based oxide and
alkoxide. Using catalyst N203SD and potassium
methoxkJe, CO conversion was 87-94 percent,
to methanol was 87-98 percent.
selectivity
Higher temperatures and higher initial pressures
enhanced methanol productivity, while lower tem-
5-6
peratures and higher pressures Increased methyl
formate formation.
STY Evaluation of Low-Temperature Methanol
Synthesis
The STY of low-temperature methanol synthesis
and that of the conventional methanol production
process are compared in Figure 1. In the conven
tional process, copper-zinc-based oxide
catalysts or (CuO/ZnO/AI203 CuO/ZnO/Cr203)
are employed under the conditions of tempera
ture of 505-573 K, pressure of 5-20 MPA, and
space velocity
of 10,000-40,000 h*\ In the ICI
process, a typical methanol process, the STY of
0.66 kilograms per liter per hour is obtained un
der the conditions of 500-523 K and 5-10 MPa.
The BNL process showed a STY of
0.89 kilograms per liter per hour at 433 K and
5 MPa. Thus, the BNL process has the possibility
of producing methanol more efficiently than the
FIGURE 1
SPACE TIME YIELD OF METHANOL
SYNTHESIS TECHNOLOGIES
Conventional
methanol process
(ICI process)
BVL km-temperature
methanol process
Lo -temperahire
methanoi process ria
methyl formate
SOURCE: OHYAMA
CuCVZnOAl2Oj
500-523 K, 5-10 MPa
- SV 10.000 40.000
0.66
-
Ni(CH3CCX))2 KaH -
trn-vay\ alcohol
433K.5MP1
0.13 -
Batrt Reaction
CuCyCr20yMnOB40 ? CH,OK
423 K. 5 MPa
Baicb lUaoioo
0.0 0.1 0.2 0.3 04 05 06 07 0 09
Space Urne yield (kf-MeOH r1
r1)
0J9
THE SYNTHETIC FUELS REPORT, JANUARY 1995

NATURAL GAS
conventional process. On the other hand,
methanol synthesis via MF showed a STY of
0.13 kilograms per liter per hour at 423 K and
5 MPa (feed: H2/CO =1), which is only one-fifth
of the STY in the ICI process. However, the STY
is expected to be improved by optimizing reac
tion conditions and catalyst concentration in the
liquid phase, and by searching for a more active
catalyst system.
Ohyama points out, however, that questions on
extension and stability of the catalyst life are im
portant subjects in the BNL process.
####
SULFUR PROCESSING PROVIDES NEW
ROUTE FOR NATURAL GAS TO GASOLINE
The Institute of Gas Technology (IGT) has been
working
on a new synthesis route for natural gas
to gasoline. The IGT approach, as described by
E. Erekson and F. Miao at a Symposium on Alter
native Routes for the Production of Fuels, con
sists of two steps that each utilize catalysts and
sulfur containing intermediates:
- Convert
- Convert
natural gas to CS2
to CS2 liquid hydrocarbons
The general equations for the two steps are:
CH4
+ 2 H S =
CS,
+ 4 H_
CS2 + 3H2=[-CH2-f+2H2S
The H2S is recycled, and the overall process is a
net hydrogen producer.
A catalyst is being developed at IGT for the first
step. The second step has been patented by
Mobil.
Sulfur, which has been considered as a poison, is
used as a reactant in the proposed process. This
method of methane conversion utilizes HS to
catalytically convert methane to CS2. Then CS2
plus hydrogen can be catalytically converted to
gasoline range hydrocarbons. All of the HS gen-
5-7
erated during the to gasoline reaction is
CS2
recycled. This process does not require steam
reforming
nor the manufacture of hydrogen.
IGT is studying the process as part of a 3-year
laboratory-scale research project sponsored, in
part, by the United States Department of Energy.
IGT has already found a catalyst for the first step
that is active above 900C at 1 atm and achieves
better than 90 percent conversion of methane.
The researchers now plan to carry out
laboratory-scale studies to improve conversion of
carbon disulfide in the second step
tegrate the two steps into one process.
####
FULLERENES CATALYZE METHANE
and to in
CONVERSION TO HIGHER HYDROCARBONS
At SRI International, H. Wu et al. have been study
ing
the use of fullerenes and fullerene soot as
catalysts for methane conversion. A progress
report was given at the Symposium on Alterna
tive Routes for the Production of Fuels, held in
Washington, D.C. last August.
Wu et al. note that the main difficulty in convert
ing
methane is the production of undesirable side
products. Oxidative methods easily convert
methane to higher hydrocarbons, but over-
oxidation to C02 makes it an uneconomical
method. Alternatively, simple thermal decomposi
tion of methane also makes higher hydrocar
bons; but the production of liquid fuels from
methane by this method is not yet economically
feasible because of the high C-H bond strength
of methane compared with that of reaction
products. At the high temperatures required to
activate methane, the C products formed will fur
ther decompose and produce still higher
hydrocarbons, aromatics, and coke.
Direct coupling of methane can be achieved ther
mally without catalyst. The key to these pyrolysis
reactions is to generate methyl radicals, which
then polymerize into higher hydrocarbons.
However, current methods are thought to
THE SYNTHETIC FUELS REPORT, JANUARY 1995

NATURAL GAS
produce the radicals In the gas phase, which
may lead to indiscriminate reactions and coke for
mation. In contrast, fullerenes, which have a
great affinity for radicals, are expected to add
methyl radicals and thereby provide for more
selective reactions. Another attribute of these ful
lerenes is that they can easily incorporate metals
either inside or outside the cage structure. Some
of these metals may
impart to the fullerenes
properties that will aid in producing methyl radi
cals.
A second reason why fullerenes may be effective
catalysts for methane activation is their strong
electrophilic character. C^ and C70 fullerenes
display
remarkable electrophilic characteristics
including direct amination with primary and
secondary amines. The full scope of the reac
tivity of these novel materials is not yet known,
but SRI believes that catalysts based on and C^
other fullerenes will provide a facile pathway to
convert methane into higher hydrocarbons.
In the arc process for preparing fullerenes, one
obtains C^, and other extractable fullerenes
C70
along with a much larger amount of an insoluble
soot. This soot most likely results from carbon
clusters that did not close into fullerenes, but in
stead continued to grow into large particles with
a fullerene-like structure. Wu et al. reported
preliminary
results on methane activation
catalyzed by this arc-generated soot containing
C^ and and compared the results with those
C70
obtained with activated carbon (Norit A).
During
the thermal pyrolysis of methane without
catalysis, the formation of tar in addition to coke
and gaseous products was observed. However,
in the case of fullerene soot or Norit catalyzed
methane activation, no tar was observed.
Figure 1 shows the extent of methane conversion
for the soot, Norit A, and the thermal case (no
catalyst) when subjected to flowing methane gas.
As seen in this figure, when induced by thermal
pyrolysis without catalyst, the onset of the
methane activation was 900C, while the onset
was observed to be approximately 800C for the
Norit A and as low as 600C for the fullerene
soot. It is interesting
to note that the fullerene
5-8
# so
1
FIGURE 1
METHANE CONVERSION
AS A FUNCTION OF CATALYST
00
SOURCE: WUETAL.
KoriiCarboo
J
No CaulyM
soot with a substantially lower surface area (ca.
120 square meters per gram compared to
750 square meters per gram for Norit A carbon)
lowered the onset temperature for methane con
version over that found for Norit A. Hence, the
surface area of the carbon is not the discriminat
ing factor.
The selectivities of C2 hydrocarbon observed for
methane activation at 950C under different reac
tion conditions are summarized in Table 1 . In
or
der to alter the selectivities SRI conducted the
methane activation experiments in the presence
of hydrogen, and for comparison, the presence
of an inert gas, helium. The effect of hydrogen
dilution is generally recognized to increase the
yield and selectivity of C2 hydrocarbons. These
trends are consistent with the observation for the
methane activation conducted without catalyst or
with Norit carbon as catalyst. In contrast, with
the fullerene soot, there appears to be only a
minor effect with hydrogen, but a much more
pronounced and positive effect with helium. This
THE SYNTHETIC FUELS REPORT, JANUARY 1995

NATURAL GAS
TABLE 1
THE PYROLYSIS OF METHANE AT 950C
Co-Feed CH4
Catalyst Gas Conversion
EmDloved (Vol%) m

NATURAL GAS
5-10
THE SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF NATURAL GAS PROJECTS
COMMERCIAL PROJECTS (Underline denotes changes since June 1994)
ARUNACHAL PRADESH NATURAL GAS CONVERSION PROJECT- Rentech Inc.. Esouire Gujarat Petrochemicals Corpora
tion Ltd.. Donyi-Polo Petrochemical Ltd.. Stale of Arunachal Pradesh, and Oil India. Ltd. (G-05)
Rentech. Inc. is designing a gas conversion plant to be located in Arunachal Pradesh in northwest India. The plant, using
Rentech's proprietary technology, will produce 350 barrels per dav of liauid hydrocarbons from flared natural gas.
Project Cost: $10 Million
- FUELCO SYNHYTECH PLANT (G-10)
Fuel Resources Development Company (FuelCo) held ground breaking ceremonies in May 1990 for their Synhytech Plant at
the Pueblo, Colorado landfill. The Synhytech Plant, short for synthetic hydrocarbon technology, will convert landfill methane
and carbon dioxide gas into clean burning diesel fuel as well as naphtha and a high grade industrial wax.
The technology is said to be the world's first to convert landfill gases into diesel motor fuel. It was developed by FuelCo, a
wholly owned subsidiary of Public Service Company of Colorado, and Rentech Inc. of Denver, Colorado. Fuelco is planning to
invest up to $16 million in the project with Rentech having the option to purchase 15 percent of the plant. Ultrasystems En
gineers and Constructors is designing and building the project.
The plant is expected to produce 100 barrels of diesel, plus 50 barrels of naphtha and 80 barrels of high grade wax per day. It
is estimated that the Pueblo site will sustain a 235 barrel per day production rate for about 20 years. FuelCo estimates that
diesel fuel can be produced for about $18 per barrel.
The process takes the landfill gas-which is about 52 percent methane and 40 percent carbon dioxide-breaks it down and
passes it through an iron-based slurry-phase catalyst, and extracts diesel fuel, naphtha and wax.
According to vehicle test results at high altitude, the Synhytech diesel was 35 percent lower in particulate emissions and
produced 53 percent fewer hydrocarbons and 41 percent less carbon monoxide in the vehicle exhaust. It contains no sulfur and
low levels of aromatics, and no engine modifications are required. Plant construction was complete in December 1991 and
only
the first crude product was produced in January 1992.
In early 1993 Public Service Company of Colorado sold its Fuel Resources Development Company subsidiary, with along the
Synhytech pilot plant to Rentech.
The demonstration tests are complete. In 1995, the Pueblo plant is available for tests using other feedstocks.
Project Cost: $16 million
MOSSGAS SYNFUELS PLANT -
South
African Central Energy Fund (G-20)
In 1988 the South African government approved a plan for a synthetic fuels from offshore natural gas plant to be located near
the town of Mossel Bay off the southeast coast. Gas for the synthesis plant will be taken from an offshore platform which was
completed in 1991. The SASOL Synthol technology was selected for the project.
Construction of the onshore plant was completed in mid-1992. Commercial production was achieved in January 1993 at
80 percent of design capacity.
Based on the original design, the Mossgas complex was to produce only automotive fuels and the license from Sasol for the
synthesis units reads accordingly. Chemicals such as aldehydes and ketones are hydrogenated to alcohol and the entire alcohol
production, with the exception of the heavy alcohols, was to be blended into gasoline. In 1993 automotive fuels are not the
most valuable products. Mossgas has been investigating the scope for increased production and opportunities to produce value
added products.
Increasing the syngas production capacity is also being investigated, because the synthesis units have considerable spare
capacity and only an additional reforming train will be required. In addition, the refinery gas condensate processing capacitycould
be increased significantly for a relatively minor investment.
Gas reserves, located in 350 feet of water, 55 miles off the Southeast coast of South Africa, are sufficient to operate the syn
thesis facility for 13 years at design rate.
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SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF NATURAL GAS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
Gas and condensate arrive onshore in separate pipelines. In the Natural Gas Liquid Recovery plant any hydrocarbons heavier
than propane are removed from the gas stream yielding lean natural gas. The lean gas is fed to a two-stage methane reforming
plant. The first stage consists of a tubular reforming plant which is followed by a secondary oxygen blown reforming reactor
plant. The capacity of the three-train reforming plant would be sufficient for the production of 7,000 tons per of methanol.
day
Using an iron-based catalyst, the synthesis gas from the natural gas reforming plant is catalytically converted to predominantly
light olefinic hydrocarbons. The tailgas from Synthol is sent to the Tailgas Treatment plant where products (propylene,
butylene and C + condensate) are cryogenically removed before the gas is recycled back to a natural gas plant.
reforming
Hydrocarbons from Synthol are refined by conventional methods to produce the final fuels.
Final Project Cost: Onshore and offshore $3.15 billion
Commissioning Costs $0.47 billion
Synthesis Complex $0.60 billion
$0.45 billion
Refinery
Offsites and Utilities $0.86 billion
NEW ZEALAND SYNFUELS PLANT - Methanex New Zealand Limited (G-30)
The New Zealand Synthetic Fuels Corporation Limited (Synfuel) Motunui plant was the first in the world to convert natural
gas to gasoline using Mobil's methanol-to-gasoline (MTG) process. Construction began in early 1982 and the first gallon of
gasoline was produced in October 1985. In the first 8 months of commercial production the plant produced 448,000 tonnes of
gasoline or about 35 percent of New Zealand's total demand for that period.
During the first two years of operation, the Synfuel plant suffered several shutdowns in the methanol units thus causing
production shortfalls despite reaching the one million tons of gasoline mark in 1988. A successful maintenance turnaround and
several improvements to the MTG waste water plant have improved efficiency considerably. In 1990 the plant produced about
12,000 barrels of gasoline per day. This is about 34 percent of New Zealand's gasoline needs.
The plant is located on the west coast of New Zealand's North Island in Taranaki. It is supplied by the offshore Maui and
Kapuni gas fields. The synthetic gasoline produced at the plant is blended at the Marsden Point refinery in Whangarei. The
plant is a tolling operation, processing natural gas owned by the government into gasoline for a fee. Synfuels, thus does not
own the refined product.
Synfuel was owned 75 percent by the New Zealand government and 25 percent by Mobil Oil of New Zealand Ltd. However,
the Petroleum Corporation of New Zealand (Petrocorp) entered an agreement with the New Zealand government to assume
its 75 percent interest in the corporation. The New Zealand government had been carrying a debt of approximately
$700 million on the plant up to that point. Petrocorp is owned by Fletcher Challenge, Ltd.
Since the change in ownership, a pipeline has been built between the Synfuel plant and the Petralgas methanol plant in the
Waitara Valley. This addition means that, when the price of distilled methanol is high, a percentage of Synfuel crude methanol
can be sent via the pipeline to Petralgas for distillation. When the price of gasoline is high, Petralgas methanol can be sent via
the pipeline to Synfuel and be converted into gasoline.
The synfuel plant produced a record 562,000 tonnes of gasoline in the first 6 months of 1991. A percentage of crude methanol
was pipelined to Fletcher's Petralgas plant to produce 186,000 tonnes of chemical grade methanol.
The plant was designed to produce 4,400 tonnes of methanol per day. Due to plant modifications, Synfuel is capable of produc
ing 5,000 tonnes of crude methanol per day. Equally, the plant was designed to produce 570,000 tonnes of gasoline per year.
Synfuel can produce over 630,000 tonnes of gasoline, or 34 percent of New Zealand's gasoline needs.
In February 1993, Methanex Corporation of Canada said it would buy the methanol assets from Fletcher Challenge Ltd., in a
transaction with an indicated value of US$730 million.
Fletcher Challenge would receive $250 million in cash and about 74 million common shares of Methanex in the proposed deal.
The transaction would make Methanex the world's largest producer and marketer of methanol, and would make Fletcher Chal
lenge the largest shareholder in the petrochemicals concern.
Following completion of the asset purchase and a share issue, Fletcher Challenge would hold about 43 percent of Methanex's
shares. The stake held by current leading shareholder Metallgescllschaft would fall to about 10 percent from its current
32 percent.
Fletcher Challenge, which owns the Cape Horn methanol plant in Chile, is the world's largest methanol producer, just ahead of
Saudi Arabian Basic Industries Corporation.
5-12
SYNTHETIC FUELS REPORT, JANUARY 1995

STATUS OF NATURAL GAS PROJECTS (Underline denotes changes since June 1994)
COMMERCIAL PROJECTS (Continued)
- SHELL MALAYSIA MIDDLE DISTILLATES SYNTHESIS PLANT Shell
(10 percent), Sarawak State Government (G-50)
MDS (60 percent), Mitsubishi (20 percent), Petronas
The world's first commercial plant to produce middle distillates from natural gas in Malaysia, started in April 1993.
up
The
$660 million unit is built next to the Bintulu LNG plant in the state of Sarawak. The plant will produce approximately
500,000 metric tons of products per year from 100 million cubic feet per day of natural gas feedstock. Daily output is ap
proximately 12,500 barrels per day.
The operator for the project is Shell MDS. The Shell middle distillates synthesis process (SMDS) is based on modernized
Fischer-Tropsch technology which reacts an intermediate synthesis gas with a active and selective catalyst. 1 Tie:&nen
highly
catalyst minimizes coproduction of light hydrocarbons unlike classical Fischer-Tropsch catalysts. Middle distillates will be the
main product, but the plant will have operating flexibility so that while maximum
maintaining output, the composition of the
product package, which will contain low molecular weight paraffins and waxes, can be varied to match market demand. Shell
will use its own gasification technology to produce the synthesis gas. The plant has 6 gasifier trains and 2 synthesis reactors.
In 1994, due to low prices for distillate fuels, Shell has shifted production toward higher-valued wax products.
Project Cost: $660 million
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SYNTHETIC FUELS REPORT, JANUARY 1995

5-14
SYNTHETIC FUELS REPORT, JANUARY 1995