Alternative Fuels Monitor:
Coal Gasification and
Indirect Liquefaction
Prepared for
Energy Processes Division
Environmental Protection Agency
4C1 M Street, M.W.
Wasnington, DC 20460
August 1980
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Contents
CHAPTER
PAGE
TITLE
FOREWORD
CHAPTER 1
CHAPTER 2
CHAPTER 3
CHAPTER 4
CHAPTER 5
CHAPTER 6
1.1 TECHNOLOGY DESCRIPTION
1.1 Coal Gasification
1.4 Indirect Liquefaction
2.1 PROJECTED OUTPUTS
2.5 Production Capacity
2.7 Production Costs
2.10 Capacity Utilization Rate
3.1 .PROJECTED INPUTS
3.1 Capital
3.1 Coal as Feedstock
3.1 Land
3 . 5 Manpower
3. 5 Water
3.8 Equipment
4 . 1 COLLATERAL ACTIVITIES
4.1 Financial Initiatives
4.5 Pending Legislation
4.5 Existing Regulations
4.5 Institutional Participants
5.1 SITES
5.4 USGS
5.4 BOM
5.7 SRI
6.1 PROJECT LIST
6.3' Commercial
6.7 Demonstration
6.10 Pilot
Hauler. Baillv &. Company
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FOREWORD
The Energy Processes Division (EPD) of the Environmental
Protection Agency (EPA) will be coordinating the effort
to develop pollution control guidance documents for the
various synfuels technologies. To establish priorities,
the EPD needs to know the commercialization status of
various alternative fuel technologies. To support this
effort, the EPD has commissioned monitoring reports on
various strategic aspects of the four major technology
groups most likely to benefit the United States: coal
gasification and indirect liquefaction; oil from shale;
direct coal liquefaction; and ethanol from biomass and
waste. These Alternative Fuel Technology Monitors will
screen the information on and provide an internally
consistent and logically ordered view of activities in
the relevant alternative fuel industries.
The first monitor is on coal gasification and indirect
liquefaction. Although the guidance document on indirect
coal liquefaction will cover only the Lurgi, Koppers-
Totzek, Texaco, Fischer-Tropsch, methanol production,
and M-gasoline processes, the monitor considers
additional technologies in order to provide a compre-
hensive view of the emerging industry. Specific topics
covered include the technologies under consideration;
current projects in the United States and abroad;
production capacity and projected output to the end of
the century; estimated inputs necessary to achieve these
levels; potential plant sites; and supporting activities
in the public and private sectors.
The production capacity and output estimates presented
in the monitor reflect our judgment on the deployment of
various facilities. This judgment, expressed as ranges
to acknowledge uncertainty, is based on estimates made
by a variety of organizations, on announced plans be de-
velopers, and on our conclusions regarding several fac-
tors influencing production capacity. These output
estimates cannot be directly compared with other esti-
mates for three reasons. First, no source has provided
estimates as comprehensive as ours; second, assumptions
vary widely among studies; and third, most sources do
not distinguish between actual production and production
capacity.
Hagler, Bailly &. Company
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1
TECHNOLOGY DESCRIPTION
Coal gasification involves the chemical reaction of coal
with steam or hydrogen and oxygen or air to produce
gaseous fuels. Low-Btu (90-200 Btu/scf)' gas is formed
by reacting coal with steam and air. To produce high-Btu
gas (970-1000 Btu/scf) with a heating value equivalent
to pipeline-quality natural gas, coal is reacted with
steam and oxygen, producing a medium-Btu gas (.300-650 Btu/
scf). The medium-Btu gas is then upgraded by increasing
the proportion of hydrogen in the gas mixture during
catalytic methanation, resulting in high-Btu gas ('see
Exhibit 1) .
Indirect liquefaction is an extension of coal gasifica-
tion. In indirect liquefaction processes, coal is
gasified to produce a mixture of hydrogen and carbon
monoxide. These gases are then recombined with the
aid of catalysts to produce liquid compounds (see
Exhibit 1) . '
COAL GASIFICATION
Coal gasification processes include: Wellman-Galusha,
Slagging Lurgi, Hydrane Process, Bi-Gas , Synthane, Stoic,
Two-Stage Entrainment Gasification System, KILNGAS,
In-situ, IGT-HYGAS, and IGT-U-Gas. 'Two third-generation
processes, which produce more methane in the initial
gasifier, are flash hydropyrolysis, developed by Rockwell
International and Cities Service, and catalytic
gasification, under development by Exxon Research
and Engineering.
These technologies are at different stages of market
readiness (.see Exhibit 21. The Lurgi, Koppers-Totzek,
and Texaco processes are available for commercial
licensing.
Lurgi Process. Coal enters a high-pressure gasifier,
covering a fixed bed at temperatures averaging about
800 C. As oxygen and steam flow past the coal, it
combines with hydrogen in the steam, resulting in
medium-Btu gas.
Hagler, Bailly &. Company
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Exhibit 1
Block Diagram of Coal Gasification and
Indirect Liquefaction
Fines
Removal
Low-to Medium-Btu
Synthesis Gas
High-3tu
Pipeline
Gas
Clean
Liquids
Methanol
Gasoline
LPG
Source: The Coal Gasification and Liquefaction Manual, Volume I
and Chemical and Engineering News, August 27, 1979
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Exhibit 2
Market Readiness of Various Technologies
Gasification
L'jrgi*
Koppers- Totzek *
Texaco*
In-situ
Wellman-Galusha*
Ri ley-Morgan*
Chapman-Willputte*
Slagging Lurgi
Syntnane
Hydrane
3i-Gas
Stoic Fosier Wheeler
Two-stage Entrainment
Flastc hydropyrolysis
Catalytic gasification
KILNGAS
TOSCOAL
COED-COGAS
iGT-HYGAS
IGT-UGAS
Indirect Liquefaction
Fischer-Tropsch *
Methancl*
M-gasoline*
Status
9
9
7
5
9
9
9
7
6
5
6
9
6
1
1
5
4
7
7
7
9
9
6
Key
0: proposed process
1: successful laboratory ooeration
2: economic studies completed
3: competitive cost established
4: pilot plant designed
5: pilot olan: operating
5: successful pilot runs
7: demonstration plant design begun
8. demonstration plant operating
9: proven demonstration plant
SOURCE: Engineering Societies Commission
on Energy. Inc., Hagier. Bailly & Company.
Processes for which pollution control guidance documents will be issued.
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TECHNOLOGY DESCRIPTION 14
Koppers-Totzek Process. This process is based on the en-
trained bed concurrent flow principle and uses the partial
combustion of pulverized coal in oxygen and steam. (Other
processes use fixed or fluidized bed gasifiers.)
Entrained ash is solidified and removed by scrubbers,
resulting in a medium-3tu gas.
Texaco Process. In this process, a concentrated slurry
of ground coal in water is pumped to a pressurized
entrained bed downflow gasifier, where it is mixed with
oxygen. The slag is then quenched in water and the hot
gases directed through a heat recovery section, where the
raw synthesis gas is cooled and scrubbed to remove
entrained particulates and flyash.
In-situ Process. In this process, coal is gasified
underground by the injection of air or oxygen and steam
into the underground reaction zone through boreholes
drilled into the seam. The partially oxidized coal
produces low- or medium-Btu gas, which leaves through the
borehole and is cleaned and upgraded on the surface.
INDIRECT LIQUEFACTION
The commercially proven liquefaction processess are the
Fischer-Tropsch and methanol production processes. The
M-gasoline process is also important but not yet ready
for the market (see Exhibit 2).
Fischer-Tropsch Process. After coal is converted to
synthesis gas, the hydrogen-carbon monoxide mixture is
reacted over an iron catalyst, yielding a variety of
liquids and gases that must be sorted out before use.
Operating conditions can be varied within limits to
increase yields of certain products.
Methanol Production Process. This is a specialized
application of a Fischer-Tropsch reaction, favoring pro-
duction of methanol from the synthesis gas.
M-gasoline Process. Developed by Mobil Oil Co., this
process involves converting methanol directly to high-
octane gasoline. The process uses a separate catalytic
conversion applied to any alcohol (in this case,
methanol) to produce a gasoline equivalent.
Hagler, Baiily &. Company
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2
PROJECTED OUTPUTS
The main outputs of the gasification and indirect
liquefaction technologies will be high-Btu gas (i.e.,
pipeline quality) , low- to medium-3tu gas (jnostly
medium-Btu), and a variety of liquid fuels, including
gasoline, jet fuel, and middle distillates, which will
be produced in accordance with the projected demand
pattern for refined petroleum products.
In addition, coal conversion technologies yield a variety
of co-products such as tars, sulfur, ammonia, and phenols
(see Exhibit 3).
To determine the product mix from indirect liquefaction
plants, producers had first projected the overall pattern
of demand for petroleum products with a view towards
producing products whose market share was likely to grow
fastest. Initially, their plans had called for a higher
percentage of heavier products to meet the need for
boiler fuel. Now, however, companies intend to produce
more light premium products and relatively little heavy
products. This switch reflects chang'ed expectations
about the future growth rates in demand for various
petroleum products.
The high-Btu gas will be used to supplement natural gas
in its traditional uses. The low- to medium-Btu gas will
be used in industrial applications such as baking and
glass making where clean process heat is important.
Liquid fuels will be used mostly in transportation and
premium petrochemicals manufacture. The co-products will
be used in a wide range of petrochemical applications.
In most cases, the output from an alternative fuels plant
will be used as a captive source of supply for the firm
or consortium operating the facility.
Commercial coal gasification and indirect liquefaction
facilities will not produce alternative fuel until 1985
and not in significant quantities until 1990 (see Exhibit 4)
*Gasoline, -Jst fuel, and middle distillates (chiefly
diesel) will be in greatest demand, while demand for
Number 6 fuel oil, which is used mostly by utilities
is likely to drop as government regulations reduce
utility oil consumption by 80 percent by 1990.
Hagler, Bailly &. Company
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F.xh.i.bi.t 3
COAL GASIFICATION AND INDIRECT LIQUEFACTION PRODUCTS AND THEIR USI::S
Process
Products
Co-Products
Uses
Coal gasifleahion
Lurgi
Koppers-Totzek
Texaco
Fischer-Tropsch
( f :i. xed bed/fierman)
Low- to medium-Btu gas,
pipeline quality gas
Medium-Dtu gas, pipe-
line-quality gas
Medium-Btu gas, pipe-
line-quality gas
Indirect liquefaction
Diesel oil, parafin
waxes
Sulfur, tars, phenols',
heavy hydrocarbons
(e.g., diesel oil,
parafin waxes)
Sulfur
Sulfur, ammonia,
hydrogen
Gasoline, LPG, SNG,
ammonia, oxygenated
compounds (e.g.,
alcohols, ketones,
organic acids)
Industrial process heat for
low-temperature application
(e.g., baking); petrochemical
feedstock; methanol production;
residential cooking and space
heating; electric power generation
for peak load shaving,- industrial
and commercial space heating; as
a source of direct combustion in
all processes requiring clean
heating.
Chemical manufacturing; auto-
motive, aircraft, and marine
fuels; solvents; illumination;
cooking; space heating; elec-
tricity generation
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Exhibit 3 cont'd
COAT. GASIFICATION AND INDIRECT LIQUEFACTION PRODUCTS AND THEIR USES
Process
Products
Co-Products
Uses
Fischer-Tropseh
(fluidized bed/
\inori.can Synthol)
Methanol
M-gasoline
I..PG, gasoline
Methyl Fuel., methanol
Gasoline, LPG, butanes
'Diesel oil, furnace oil,
waxy oil, alcohols and
ketones, parafins,
aroniciti.es, carbonyls
Sulfur, tars, heavy oils,
tar acids, ammonia
SNG, sulfur, ammonia
Chemical manufacturing; auto-
motive, aircraft, and marine
fuels; solvents; illumination,-
cooking; space heating; elec-
tricity generation
Automotive and aircraft fuels;
chemical manufacturing; lubri-
cants; solvents
Automotive and aircraft fuels;
chemical manufacturing; solvents;
illuminants; cooking and space
heating fuel
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Exhiliit 4
Production, 1985 2000
(thousand bpdoe)
Fuel Type
Hi(|h-Glu G;is
Low - 10 Medium - Blu Gas"
Liquids
Total
1985 1990
20-33.5 14f>-
100 -
125-
20 - 33.5 370 -
225
260
175
650
1995
275
300
175
1.050
425
-550
-600
1.575
2000
550
400
675 -
1 ,625
-000
-700
1 ,000
2,500
Picdomiiinnlly Medium-Bui
S< MjnOI:: I t;ii|li:r, liiiilly 81 CmniKiny, b;is«cl on capncity projiidions
hy (JOE; |j<»:lil
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PROJECTED OUTPUTS 2.5
In 1990, total production using these technologies could
range from 0.37 million barrels per day of oil equivalent
(mbdoe) to 0.65 mbdoe, with liquids accounting for
between 27 percent and 33 percent of total output. By
2000, total production could be 1.6-2.5 mbdoe, with
liquids providing about 40 percent and high-Btu gas
32-34 percent of the output.
It is somewhat difficult to directly compare our estimates
with those made by others. Other estimates have tended to
be either less comprehensive or very aggregate. In
general, we are within the range of other estimates.
Booz'-Allen estimates medium-Btu gas output of 0.3 mbdoe
by 1990, which is well above our upper estimate. Bechtel's
estimate of high-Btu gas production is well within the
range we project through 2000. ESCOE projects gas from
coal output at 0.15 mbdoe by 1990, which is considerably
below our lower estimate. ESCOE's coal liquids projection
of 1.35 mbdoe by 1990 is much greater than our estimate
even if direct coal liquefaction were considered. The
CEQ foresees total coal-derived alternative fuels pro-
duction at 1.25 mbdoe by 1990, which is again consider-
ably above our optimistic estimate even if direct coal
liquefaction were factored in. DOE expects methanol from
coal to range from 0.68 to 1.03 mbdoe by 2000, compared
with our estimate of 0.275 - 0.35 mbdoe.
In the absence of firm and consistent information, we
speculate that the Lurgi and Texaco processes will dominate
the high-Btu gasification industry until the mid 1990s.
We expect these two processes to account for all high-
Btu gas production through 1990. Even by 2000, either
process may account for 25-30 percent of the high-Btu
gasification industry's output. Other processes could
account for 15-20 percent of the output by 1995 and
40-50 percent of the output by 2000 (see Exhibit 5).
*These estimates reflect our judgment based on projections
made by a variety of organizations including Department
of Energy (DOE), Bechtel National, Inc., consulting firms,
and energy companies.
Hagler, Bailly &. Company
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Exhibit 5
Estimated Production of High-Btu Gas and Liquids by Technology
(thousand bpdoe)
1985
High-Btu Gasification
Lurgi 20 - 33.5
Koppers-Totzek /Texaco
Other
Indirect Liquefaction
Fischer-Tropsch
M-gasoline
Meihanol processes
Other
1990
60
60
25
50
0
- 100
- 100
25
50
- 35
- 65
-25
1995
100-
100-
75-
75-
100-
200-
2000
150
150
125
100
150
250
100
140-
140-
270
100-
150-
275-
15C-
235
235
330
150
300
350
200
SOU3CE: Hagier. Bailly & Company based on announced
projects and coroorate inten;ions and teleohone conversations
wiir, potential producers.
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PROJECTED OUTPUTS 2.7
In the indirect liquefaction industry, we expect the
methanol processes to make the greatest contribution
through the end of this century. Their relative share
of output, however, could decline from 40-60 percent in
1990 to 35-40 percent in 2000. The Fischer-Tropsch
processes, similar to those used by Sasol, may have as
much as 40 percent of the market share by 1990, but we
suspect their share could fall to 15 percent by 2000 as
the M-gasoline and other processes are deployed (see
Exhibit 5).
The level of output in the period between 1985 and 2000
will depend upon installed capacity and the capacity
utilization rate.
PRODUCTION CAPACITY
The installed production capacity will be a function of
total production costs (feedstock plus process) ,
technological uncertainties, equipment availability,.
regulations, resource ownership, and the availability
of capital. On the basis of these factors, total
installed capacity will not'exceed 0.81 mbdoe by 1990
and 2.8 mbdoe by 2000 (see Exhibit -6).
PRODUCTION COSTS
With the prices of alternative fuels influenced by world
fossil fuel market conditions, the ability of alternative
fuel technologies to compete will be critically dependent
on the ability of alternative fuels plants to generate
economic returns for their owners, which in turn depends
on production costs. Production costs will vary by
technology, the cost of coal, and the costs of trans-
porting coal from the mine mouth to the production
facility. Actual costs confronting a producer will also
depend on subsidies that the federal government may make
available.
Total costs are generally expected to average around $40
per barrel of oil equivalent (boe), although specific
processes are likely to vary considerably. DOE recently
estimated total costs for high-3tu gas production at
?44/boe while Cameron Engineers estimated costs at
$35-53/boe. DOE estimated indirect liquefaction costs
at $30-35/boe while Cameron Engineers estimated these
costs at $48-53/boe.
Hagler, Bailly &. Company
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Exhibit 6
Production Capacity, 1985 2000
(thousand hp(Jo(-0
Fuel Type
Hi(|li-Blu G.-is
Low- lo Mt!cliuin-I3lu G;is
Liquids
Total
1985 1990
27.0 -45.0 100
- 125
1 55
27.0 45.0 460
- 280
-310
220
-810
1995
230
350-
560-
1,140-
500
650
705
1.855
2000
GIO
445
750
1,805
- 090
- 7HO
1.100
2.770
SUUHCk: f l;M»h;r, Bailly and Compi'iny, l.i;is(xJ oit csliniiitcs
hy I iifjiiuMnii)i( Si»:i<:t'-':; Commission on t;i»er(|V IIM:.. DOE,
iJcchli!), N.iiioniil, IIM".*.. Bon/ Allun, Atiuico, Council on
I nt/iioii(ni!ntal Quality.
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PROJECTED OUTPUTS 2 . 9
These cost estimates imply that the liquid alternative
fuels will be competitive with light distillates and
petrochemical feedstocks derived from crude oil in the
1985-2000 period. Gaseous alternative fuels are likely
to compete well with imported LNG, Canadian and Mexican
pipeline gas imports, and free market domestic gas
production after 1990. Prior to 1990, alternative
gaseous fuels will probably be only marginally competitive
with conventional natural gas but fairly competitive with
Algerian LNG. After 1990, economic returns'from alternative
fuels production are likely to be enough to promote rapid
deployment of alternative fuels facilities.
Technological Uncertainties
Technological uncertainties could easily prevent a rapid
build up of capacity. Except for the Lurgi and Fischer-
Tropsch processes, the technology of coal gasification and
indirect liquefaction is not completely proven on a commer-
cial scale. According to an estimate by Mechanical Tech-
nologies, Inc., 19 necessary pieces of equipment (4 percent
of the required items) need significant additional work before
they can be used with confidence in full-scale commer-
cial plants. Another 68 pieces of equipment (15 percent
of the required items) need some work.
Equipment Availability
Distillation towers, heat exchangers, compressors, large
pumps, thick wall pressure vessels, and air separation
plants could generally be in short supply for at least
the next 10-15 years.
U.S. dependence on imports of such critical minerals as
chromium, cobalt, and the platinum group could prevent
significant increases in the production capacity of
certain nickel and iron alloys needed for fabricating
gasification and liquefaction equipment.
Regulations
Five factors make the regulatory system critical to
success. First, rules to implement legislation frequently
go beyond the intent of the original law. Second,
Hagler, Baiily &. Company
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PROJECTED OUTPUTS 2 .10
jurisdictional disputes arise among state, local, and
federal agencies. Third, frequently only conditional
permits are granted. Fourth, the period for public
hearings can be extended almost indefinitely, and fifth,
there is enormous uncertainty about new regulations and
rules that could later halt or change the economics of
a project.
Resource Ownership
Although physical resources are large enough to support a
huge United States coal-based alternative fuels industry,
there are only limited available sites capable of sus-
taining a large alternative fuels plant. Additional
federal leases will be necessary to make available mining
sites on attractive coal properties. These sites must
become available in time for firms to acquire water and
access rights as needed.
Availability of Capital
Investment requirements for a 50,000 barrel per day (bpd)
facility could be as much as $2.25 billion in 1980 dollars.
Only a few large companies or consortia can undertake such
massive investment. 'Banks will be wary of lending unless
the government provides an array of guarantees and incen-
tives to alternative fuels producers since government
policy and regulation can drastically influence the pro-
fitability of a project. Large capital market financing
will be forthcoming only if rolled-in gas pricing, loan
guarantees, tax credits, accelerated depreciation, and
price and purchase commitments are provided.
CAPACITY UTILIZATION RATE
In the initial phases of development, the coal-based alter-
native fuels industry is likely to be plagued by a low
capacity utilization rate. The reasons for this low rate
are likely to be equipment failure and the need for frequent
maintenance of parts subject to high pressure and tempera-
ture. In the early years of Sasol I, valves wore out in
a matter of days and the plant had -to be shut down several
times a year for major maintenance, equipment cleaning,
and parts replacement.
Projected output is based on capacity utilization rates
of 0.75 in 1985, 0.80 by 1990, 0.85 by 1995, and a steady
state 0:9 by 2000. The 0.9 rate is only a few points below
the utilization rate of a complex refinery. The 0.75
rate assumes a plant shutdown at least once a month for
repair, cleaning, and parts replacement.
Hagler, Bailly &. Company
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3
PROJECTED INPUTS
The major factors of production in the coal gasification
and indirect liquefaction industry will be capital, coal
as feedstock, land, manpower, water, and equipment.
CAPITAL
We expect cumulative investments in the fuel production
plants through the end of this century will be $67-$117
billion in 1980 dollars. Of these amounts, about 45
percent would be for indirect liquefaction and about 35
percent for high-Btu gasification (see Exhibit 7). We
estimated capital costs on the basis of capacity pro-
jections shown in Exhibit ~6 and an investment of $40,000-
$45,000 per daily barrel of installed capacity.
COAL AS FEEDSTOCK
To'tal feedstock coal requirements are expected, to be
710,000-1,090,000 short tons per day in 2000 (see
Exhibit 8). The maximum projected feedstock coal require-
ments will rise from about 0.5 percent of projected U.S.
coal output in 1985 to over 25 percent in 2000. In
calculating the requirements for coal, we assumed a
thermal conversion efficiency of 67 percent for gasifi-
cation and 55 percent for indirect liquefaction, an
average coal energy content of 21.6 million Btu/short ton,
and the production estimates in Exhibit 4.
LAND
About 6,300-11,600 acres of land should be disturbed by
mining of feedstock coal through the year 2000 (see
Exhibit 9). Starting from insignificant amounts in
1985, cumulative land disturbed will increase appreciably
with the growth of the industry.
In computing land disturbed from coal mining to meet
feedstock requirements, we used the production figures
in Exhibit 4 and made four assumptions:
Two-thirds of feedstock coal needs will be met
by surface-mined coal
Hagler, Bailly &. Company
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Exhibit 7
Investment Costs, 1985 2000
($ billion)
Fuel Type
Mi(|h-Biii G;is
Low- lo MoJiurn-Biu Gas
l..i<|tli(IS
Total
1985 1986
1 .0 - 2.0 6.5 -
5.0 -
6.0-
1.0-2.0 17.5
1990
10.5
11.5
10.0
34.5
1991 1995
6.0
1.0
16.0
26.0
10.0
- 6.5
-22.0
-38.5
1996-2000
1 1 .5 - 1 7.5
3.5 - 6.0
7.5- 10.0
22.5-41.5
SI MJHCIi: I Mll'.T. I5;iil|y X. Coiii(>'1|iY-
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Exhibit 8
Feedstock Coal Requirements. 1985-2000
shot I ions per day)
Fuel Type
1 Iii|h-I3lu Gas
Low- lo MecJiuiii-Blii G;is
1 i(|imls
Total
1985 1990
8- 13.!) 58-
40-
GO -
8-13.5 158-
90
100
85
275
1995
110-
120-
230-
460-
170
220
290
680
2000
220-
1 GO -
330
710
320
280
190
1.090
SOUFICR: H;ii|lnr. H.-iilly & Compimy.
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Exhibit U
Cumulative Land Disturbance From Coal Mining,
1985 2000
Aries
12.000
11,000
10.000
9.000
8.000
7.000
6.000
5,000
'1.000
3.000
2,000
1.000
22
10
11 ,!jUO
fi.290
i i r
19il!3 I'JOfi 1007 19I1U 19U9 1990
I I I I I I I
1991 1992 1993 1991 1990 1990 1997 1998 1999 2000
Ci:: ll.iijlci, Uiiilly Ki Cd
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PROJECTED INPUTS 3 . 5
The average seam thickness will be 100 feet
Bituminous coal will have a distribution of
75-94 pounds per cubic foot (Ib/ft^) and sub-
bituminous coal 65-80 lb/ft-3
There will be an average 153,000-190,000 shorl
tons of coal per surface acre of mine.
MANPOWER
Manpower needs will include home office and field staff
for plant design, construction, and startup as well as
engineering and technical staff for operations and
maintenance once the plant is functioning. Assuming
0.12 design and construction person-years per daily
barrel of installed capacity* and the capacity projection
in Exhibit 6, preoperations manpower needs should increase
dramatically from 3,200-5,400 person-years in 1985 to
60,000-100,000 person-years annually in the 1990s (.see
Exhibit 10). Assuming 0.0175 operating and maintenance
person-years per daily barrel of installed capacity,''
operations manpower needs by 1985 are less than 1,000
person-years but will grow steadily to 30,000-50,000
person-years by 2000 as capacity is built up (see
Exhibit 11).
WATER
The water requirements of the alternative fuel plants
can easily be satisfied in most regions of the United
States as far as physical resources are concerned.
However, political and regulatory concerns could limit
the availability of water to alternative fuel facilities.**
Estimates of person-year required developed by Bechtel
National, Inc.
**Resource availability confirmed by a telephone con-
versation with Dr. Ronald Probstein'of Massachusetts
Institute of Technology who agreed that perceptions of
water scarcity in the west, rather than a physical shoart-
age, are the cause of co"'*">"rNverstr =X^MI-*- -f-x^i r.ra-f-gv- v./-*/^^?-
of alternative fuel plants.
Hagler, Bailly 5i Company
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Exhibit 10
Design. Construction and Start Up, 1985-2000
(purson-ytiiiis)
Fuel Type
Hii|h-Glu G;is
Low- lu Mudium-Blu Gus
Liquids
Total
1985
3.200 - b.400
3,200 5,400
SOIJflCL. H:ii|lur. Biiilly & Conipany; Ui:chlul Naiioiiiil. Inc.
1990
1995
1H.700- 20.600
16.100 - 37.700
HI.900 - 26.100
53,700 - 84,700
17,200- 26.400
12.400- 1 7.000
48.600 - !iU,900
78,200- 103,100
2000
34.700- 47.000
11.000- 1(3,800
23.100 - 40.000
68.700 111.800
-------
Exhibit 11
Labor Requirements (or Operation and Maintenance. 1985-2000
(per soii-yours)
Fuel Type 1985
1 Iii.|h-Bui Gas 4GO-780 3.
1 <>w- 10 Mctliuin-Biu Giis 2.
Liquids - 2,
Total 460 - 780 8,
1990
1 80 -
190-
740 -
110-
4.930
13.480
3.830
14.240
5
6.
9,
21
1995
i.670
190-
UOO
,660
-8,
11
12
770
.340
,380
- 32,490
10
7.
13
31
2000
.710-
790 -
.HiO-
.650-
1 b.580
13.fi40
19.480
48.700
li:l N.Hioiuil. Inc.
-------
PROJECTED INPUTS
In a coal-based alternative fuel facility, the major
uses of water are for hydrogen, cooling, waste disposal,
and environmental control. According to Professor
Ronald Probstein, a typical coal gasification plant will
consume 15.6-25 gallons of water per million 3tu of out-
put. The needs of an indirect liquefaction plant are
similar. These estimates assume that all effluent water
is recycled or reused and none is discharged.*
J. Harte and M. El-Gassier, writing in Science (1973) ,
also estimated water use by gasification plants. Their
estimates range from 25 to 173 gallons per million 3tu.
ERDA, too, developed estimates in 1977 and concluded that
27-126 gallons per million Btu would be needed.
The upper level of the Harte-Sl-Gassier and ERDA estimates
appear excessive by an order of magnitude. We have used
the Probstein estimates.
Total water requirements will be an insignificant 1.8-4.9
million, gallons per day (mgd) in 1985. Water needs will
grow steadily during the 1990s and reach 140-330 mgd by
2000 (see Exhibit 12).
EQUIPMENT
The equipment needed by the alternative fuels industry
can be classified as process engineering and other.
Within the process engineering category, the largest
items by value will be fabricated vessels and within the
other category, instruments and controls will account for
more than half the value of equipment installed (see
Exhibit 13).
On the basis of a recent marketing study by Frost &
Sullivan, Inc. and our capacity projections, we estimate
that the annual value of process equipment installed by
the industry will rise from well under $1 billion in
1985 to $12-$21 billion by 2000. Other equipment, which
will have an annual value of less than $250 million in
1935, will rise to $4-$3 billion by 2000. (See
Exhibit 14).
*In certain instances, the assumption of zero discharge
may not be economically valid. Consequently, water
requirements may be somewhat higher than forecast in
Exhibit 12.
Hagler, Bailly &. Company
-------
Exhibit 12
Water Requirements, 1985-2000
(million ijiilloiii; pfir diiy)
Fuel Type
1985 1990 1995
lluih-liiu G;is 1.0-4.9 13.1-32.6 24.9-61.6
Low lo Mciliuin-Blii G;is
Liquids
Total
9.0 - 36.0 27
10.0-19.7 30
1.8 4.9 32.1-88.3 90.
.2 - 79.0
.0-67.5
1 208.9
2000
49.0- 116.0
36.2- 101.fi
M.O- 112.!)
140.0-330.0
liOUHCd. I liujl^r. Liailly & Cotiifiany. ha^uij uit Roiialil I*. fjtiil>st
-------
Exhibit 13
Equipment Requirements,1985-2000
Process Engineering Equipment Percent of Value
Fabricated vessels 33.7
Heat exchanger 13.0
Rotating machinery 9.7
Materials handling equipment ' 2.2
Packaged plants 16.2
Turbine generator sets 2.6
Pollution control devices 1.5
Miscellaneous other 21.0
100
Other Equipment
Piping 26.0
Valves 20.0
Instruments and Controls 54.0
100
-------
Exhibit 14
Equipment Requirements, 1985-2000
($ million)
Hh|h Klu (..,>:,
l.uw ID MiHli./ni Dm GM
I.,,.,,,,,,*
Total
1985 1990
Process Process
Engineering Other Engineering
320 640 120 240 2,0/0 3.310
liiOO 1440
/.HiO - I3.UHO
320 640 120-240 10,820-21.460
Oilier
/lit) 1 .230
!581i 1650
2.<540 - '.J.040
3.985 7.920
1995
Process
Engineering
I.'.HO 3.1 HO
1.2/0 2.0 VO
8.2UO I2.2GO
11.460 - 17.510
Other
/DO -
4/0
3.01,0
4.220
I.I /I)
/GO
4.1)10
- 6.440
2000
Process
Engineering Oilier
3.UGO lj.!i/l) I.3M) 2,ll!,O
I.I 10 I.'JIO 410 /OO
/.IliO 13.210 2,(>4O 4.111)1)
11.930 20.690 4.400 7.610
l S ll.njl>:r. H.iillv & Oumii.inv I loil & Siilliu.in. Ini:
-------
4
COLLATERAL ACTIVITIES
Collateral activities as used in this document refer to
those actions that occur in parallel to and in support of
alternative fuels development. The term encompasses
federal financial initiatives, pending legislation,
existing regulations, and institutional participants.
FINANCIAL INITIATIVES
Developers of commercial projects can select from several
financing methods: project financing, self-financing,
and corporate financing. Project financing involves
securing debt against the cash flows of a specific
project; self-financing involves a corporation's use of
internally generated cash; corporate financing involves
borrowing against the entire assets of a firm or con-
sortium undertaking a venture. Alternative fuels pro-
ducers can combine the three financing options, although
potential producers are'reluctant to use the latter two
because of the large, long-term investment needs and the
high capital exposure involved. The massive investment
needs of a coal gasification or indirect liquefaction
plant would preclude financing from corporate cash flow
and the project risk would make firms reluctant to use
corporate financing. With project financing, long-term
contracts for the sale of a project's output (e.g., high-
Btu gas) serve as the collateral against which a lender
provides funds. An even more secure form of collateral
is a debt guarantee by which lenders would be protected
even if the project failed to produce any fuel. The
preference for project financing implies the need for
external financing, including assistance from the federal
government.
The Energy Security Act of 1980 calls for the establish-
ment of a Synthetic Fuels Corporation (SFC) to provide
such financial assistance for commercial alternative fuels
projects. These incentives, which are designed to reduce
the financial risk of building and operating an alterna-
tive fuels plant, include the following:
1. Purchase agreements, price guarantees, and loan
guarantees covering up to 75 percent of the project
costs
Hagler, Bailly &. Company
-------
COLLATERAL ACTIVITIES 42
2. Loans covering up to 49 percent of initially estima-
ted project costs (unless this limits the financial
viability of the proposed project, in which case up
to 75 percent would be authorized)
3. Minority (i.e., less than 50 percent) equity interest
in a joint venture in which the government could
provide up to 75 percent of projected costs.
This order reflects the government's ranking according to
preferred incentive. Multiple forms of financial assist-
ance are authorized only if required for the success of
a project and necessary to satisfy the goals and purposes
of the Act.
Rulings by the Federal Energy Regulatory Commission (FERC)
could also be considered federal financial incentives.
Specifically, rulings that permit gas utilities to build
into their rate base provisions for indemnifying the debt
for a coal gasification plant could effectively reduce
the risk of the project to the utility. However, this
FERC ruling may not necessarily be available to all gas
utilities who may be interested in gasification plants
and at this time does not apply to liquid fuels plants.
Moreover, one FERC ruling indemnifying debt has been
challenged by consumers. Consequently, FERC provisions
are, at best, a supplement to SFC initiatives.
The success of the various SFC initiatives will depend on
how useful they are considered by the parties with highest
financial risk in alternative fuels production, that is,
by financial lending institutions. These institutions will
want to minimize losses in the event a project fails and
will therefore prefer the incentive that leads to the
lowest net present value of exposure. Lenders will con-
tinue to select their first preferred incentive until it
is no longer available, then move on to their next
preference, and so on down to the threshold at which the
incentive does not make the project attractive enough to
induce any investment.
For those financial lending institutions involved in
alternative fuels development, loan guarantees are the
preferred incentive. We believe minority equity parti-
cipation by the government would be the next in preference.
Purchase guarantees and price commitments would probably
be employed least. These incentives are less desirable
because if a project fails to produce or to operate at
anticipated levels,the lenders carry the full financial
risk.
Hagier, Bailly &. Company
-------
COLLATERAL ACTIVITIES 4 3
The precise effect of all these financial incentives on
the coal gasification and indirect liquefaction industry
is difficult to estimate owing to uncertainty about the
share of available funds allocated to a particular in-
centive or technology. If there are no restrictions on
the amount available for a technology, then most of the
incentives (from the first $20 billion at any rate) will
probably be exhausted by assistance for oil shale projects,
which seem to be the most financially viable at present.
If there are restrictions on how the first ?20 billion is
allocated, and assuming about $7 billion will be avail-
able for coal gasification and indirect liquefaction
projects, $5 billion may be available for loans covering
up to.50 percent of project costs. Since a 50,000 b/d
plant requires approximately a $2 billion investment, the
first round of federal financial incentives could support
five plants, or 250,000 b/d of production. These federal
financial incentives could therefore substantially help
the fledgling industry reach production levels at about
the middle of the range of production forecasts presented
in this Monitor.
The Great Plains gasification project by American Natural
Resources (ANR) provides an interesting case study of the
complexity of federal incentive initiatives for alternative
fuels development. In fact, this project will be the
first test of the effectiveness of federal financial
initiatives. The ANR project suggests that small federal
loan guarantees (in this case, only 20 percent of total
project costs) may not be enough to induce banks to lend.
The four participating companies, led by ANR, had received
Federal Energy Regulatory Commission (FERC) approval of
a financing plan for the $1.5 billion plant. Under this
plan, gas customers of the four participating companies
would guarantee project debt in the event of failure.
However, four groups representing the customers of the
participating gas companies opposed the plan on the
grounds that they should not assume the risk of an
untried project. These groups claim that the risks should
be assumed by all taxpayers. Under the FERC proposal,
ratepayers alone assume the burden if the ANR gasifi-
cation plant does not operate successfully (.i.e., at
least 70 percent of the time).
DOE agreed to consider guaranteeing the first-year debt
of $225 million if the four opposing groups withdrew
objections. This DOE guarantee would allow ground-
breaking this summer, although consumer protest could
postpone start-up for a year. Despite DOE assurances,
Hagler, Bailly SL Company
-------
COLLATERAL ACTIVITIES
two of the groups refuse to drop the suit because the
FERC order would set a precedent allowing ratepayers to
assume the burden of debt coverage in future plants.
Moreover, DOE's 1-year guarantee would cover no more
than 20 percent of the project's cost. If litigation
continues, DOE's loan guarantee will not be forthcoming
and construction will be delayed for a full year. The
Ohio Consumer's Council, one of the opposing groups,
officially refused to drop its court challenge, and
Michigan and New York will probably reject the DOE loan.
guarantee. The fourth member in the opposition group,
General Motors, has not yet determined its position on
the proposal.
Nonetheless, ANR may continue its request for DOE funding
because FERC had ordered it to seek federal financial
backing as an alternative to risks and costs to be
assumed by ratepayers. If so, DOE must continue process-
ing the application, although approval is unlikely.
Financial institutions have refused to back the plant
unless the court challenges are dropped, and unless DOE
is assured of future financial support for the AMR
facility, DOE officials will be unable to approve the
loan guarantee.
If the courts rule in favor of consumer groups and the
federal government provides no financing guarantee, the
Great Plains consortium will have great difficulty in
finding financial backing. Specifically, if Canadian
gas prices decline in real terms, the Great Plains'
high-priced gas will have no market. The project will
most likely be terminated. However, should the
courts uphold the pass-through of costs to consumers,
the Great Plains project would continue and encourage
rapid development of other alternative fuel plants.
Earlier rulings may set conflicting precedents for the
current case. The court ruled that if the Northwest
Alaskan Pipeline was not completed by the announced
date, the project partners must absorb the loss.
However, the chance of failure in the Alaskan Pipeline
Project was minimal. In another jurisdiction, it was
ruled that consumers would not pay for a nonfunctioning
Three Mile Island Power plant.
Hngler, Baillv &. Compan\
-------
COLLATERAL ACTIVITIES
PENDING LEGISLATION
Several pieces of legislation that could affect alter-
native fuels projects are under consideration. Many-
pertain to environmental impacts, while some are aimed
at organizational and funding mechanisms. Exhibit 15
lists some relevant pending congressional bills.
The most important piece of pending legislation affecting
alternative fuels development is the Energy Security Act.
The Act was passed by the Senate during the week of
June 16, and by the House during the week of June 23.
The bill will provide 520 billion in financial incen-
tives for developing alternative fuels. The bill does
not provide for minimizing the effects of environmental
laws and regulations; all projects are still subject to
federal, state, and local environmental land use and
siting laws.
EXISTING REGULATIONS
Various existing government regulations will influence
alternative fuel development. The environmental regula-
tions listed in Exhibit 16, which are subject to yearly-
review, will continue to affect the costs and site deter-
mination of coal gasification and indirect liquefaction
projects.
INSTITUTIONAL PARTICIPANTS
The institutional participants who have assisted or will
assist in developing or organizing an alternative fuels
industry are organized into three divisions: legislative
participants, executive participants, and associations
and industry.
Legislative
Participants
In drafting the Energy Security Act, a conference
committee resolved the differences between the House
and Senate version of synfuels legislation. This
committee was composed of members of the committees
with Synfuels Jurisdiction from both branches of
Congress. Their structures are as follows:
Hagler, Bailly &. Company
-------
Exhibit J5
PENDING LEGISLATION
LEGISLATION
PURPOSE
STATUS
ENERGY
Underground Coal Gasifica-
tion and Uncoventional Gas
Research and Development
Act (S. 2774)
Establish a 10-year program to
Easter production and commercia-
lization of uncoventional gas
resources and underground coal
gasification.
Referred to the Senate Energy
Committee and awaiting hearing.
(Chances for enactment are good.)
ENVIRONMENTAL
Authorization and Amendment
the Solid Waste Disposal
Act (S.1156)
Re-authorize the Solid Waste
Disposal Act and exempt
certain high-volume, low-risk
wastes (e.g., mining wastes
and wastes generated by the
combustion of fossil fuels)
from regulation as hazardous
waste.
Passed in lieu of H.R. 3994.
Conferees have been appointed
but no action taken since.
RARE II
Legislation (II.R. 6607,
5586, 370, 6607; S.Q12,
2007, 2031, 2560, 2741)
Recommend inclusion roadless areas
of national forest lands into the
Wilderness System. Of the 33
states with pending legislation,
Colorado and South Dakota are the
only states with high (potential
for alternative fuels development.
5 of 33 states have initiated
legislation. The South Dakota
bill would set aside only a
small area in the Dlack Hills.
Action on Colorado wilderness
lands is stalled because of
disagreement among the
senators about, which lands to
set aside.
-------
Exhibit 15 con ' I:
PENDING LEGISLATION
LEGISLATION
PURPOSE
STATUS
SUPERFUND AND R'EIATEP
LEGISLATION
Environmental Emergency
Response Act (S.1480)
Oil, Hazardous Substances,
and Hazardous Waste
Response Liability, and
Compensation Act (S.1431)
Hazardous Waste
Post-Closure Liability
Act (S.I 325)
Provide for liability,
compensation, cleanup, and
emergency response for hazardous
substances and mandate cleanup
of inactive hazardous waste
disposal sites.
Original super fund proposal
(committee-generated). This
Act differs from S.14BO in that
it contains provisions for oil
spills.
Amend Solid Waste Disposal Act
by requiring accumulation of
funds during the operating lives
of hazardous waste management
facilities to allow payment of
damages and liability claims
Forwarded to Senate Environment
and Public Works Committee in
May, referred to Subcommittees
on Environmental Pollution and
Resource Protection; marked up
June 4 and June 10.
Referred to Senate Environment
and Public Works Committee and
Subcommittees on Environmental
Pollution and Resource Protection;
considered September 28. Senate
is mainly considering S.1480,
which was requested after S.1341
was submitted. No action current-
ly being taken on S.1341.
Same as S.1341
.£.
-------
Exhibit 15 con't
PENDING LEGISLATION
LEGISLATION
PURPOSE
STATUS
SUPERi-'UND AND RELATED
LEGISLATION con't
Amendment to Solid Waste
Disposal Act (S.1046J
Oil, Hazardous
Substances, and Hazardous
Response, Liability,
Compensation Act of
1979 (I1R 4566)
Hazardous Waste Containment
(HR 7020)
Establish a program for identi-
fication and reclamation of
abandoned hazardous waste sites.
Provide response, liability, and
compensation for oil, hazardous
substances, and wastes and
establish a liability fund.
Establish guidelines for the
release of hazardous wastes
form inactive waste sites that
endanger public health and
environment.
Pending in Senate Committee on
Environmental and Public Works.
Hearings held in House Committee
on Interstate and foreign Waste
Commerce, Subcommittee on and
Transportation and Commerce
October 11, 1979. Pending
since June 1979 in Merchant
Marine and fisher Committee,
Subcommittee on Coast Guard and
Navigation. Referred in July
1979 to Committee on Public
Works and Transportation,
Subcommittee on Water Resources.
Reported out of Commerce Act
Committee May 16, 1980, and out
of Ways and Means Committee
June }ti, 1980.
-------
Exhibit 16 con't
ENVIRONMENTAL REGUCATIONS
Regulation
Sponsoring
Agency
Purpose
Under Revision
Hazardous Emission Standards
for Carcinogens
EPA
Increase regulation of airborne carcinogens
through the establishment of additional
hazardous air pollutant emission standard for
suspect carcinogens. If many people faced
exposure to airborne emissions,. EPA would
institute stringent technology-based standards
on specific sources. This regulation would
affect coal mining and combustion.
Prevention of Significant
Deterioration and Nonattain-
ment Area Requirements
EPA Revise EPA' s procedures for review of new and
modified stationary sources of pollution.
The revised regulations will affect which
alternative fuel facilities will be subject
to EPA or state review, which pollutants will
be subject to control, and what level of
control will be imposed on a facility.
Approval of State Implementa-
tion Plan Revisions
EPA Strengthen emission limitations on existing,
new, or modified sources. The revisions were
needed because of the failure <->t many state
plans to achieve ambient air quality standards
for certain pollutants within the time
specified by Congre;
-------
Exhibit 16 con' I;
ENVIRONMENTAL REGULATIONS
Regula t.ion
Sponsoring
Agency
Purpose
Under Revision con't
Regulation of Underground
Injection Wells
EPA
Existing
National Ambient Air
Quality Standards
EPA
Fteprqpose minimum procedural requirements for
issuance of permits and minimum operating,
monitoring, and reporting requirements for
underground injection wells that could
endanger drinking water supplies. This
requirement would significantly affect in-situ
coal gasification.
Establish maximum levels of pollutants
compatible with the protection of public
health and welfare and be included in state
implementation plans to control pollutants for
which there are ambient air quality standards.
Requirements for State
Tinp.lemcntcit.ion Plans
EPA
1. Establish state and local emission control
requirements on existing and new sources;
2. Establish review procedures for new fcic.il i-
ties; 3. Impose criteria for technology-based
control requirements on new and modified
existing facilities to prevent sigificant
deterioration of a.ir quality or to allow
qrowtli in nonaLtciinincnt areas.
-------
Exhibit 16 con't
ENVIRONMENTAL REGULATIONS
Regulation
-i
Sponsoring
Agency
Purpose
(Jnder Revision con't
Noncompliance Penalties
EPA
Establish a formula for determining
noncompliance with the Clean Air Act and for
assessing required .penalties. With few
except ions, sources riot in compliance with
state implementation plan requirements as of
July 30, 3979, would be assessed penalties
equal to the economic benefit derived from
noncompli ance.
Establishment of Significant
Deterioration of Air Quality
Increments
EPA
Consolidated Permit
Regulations
EPA
Develop increments for prevention of signifi-
cant deterioration of air quality for four
additional pollutants: hydrocarbons, ozone,
carbon monoxide, and oxides of nitrogen. If
accepted, this regulation would .limit the
amount of new emissions of such pollutants
permitted in clean air areas.
Combine procedures for issuing federal permits
under the Clean Air, Solid Waste Disposal,
Safe Drinking Water, and Clean Water Acts.
This regulation would allow for joint applica-
tion and dat£i submission, as well as joint
permit review by federal and state officials.
Permit Kegu 11\ ti ons for
Water Pollutant Discharge
EPA
Stipulate more stringent requirements for
issuance of permits regulating discharges of
toxic water pollutants.
-------
Exhibit J6 con't
ENVIRONMENTAL REGULATIONS
Re ij ulation
Sponsoring
Agency
Purpose
Existing con't
New Source Performance
Standards
EPA
Create technology-based operating standards
for air pollutant emissions from new and
modified sources. These standards for fossil-
fuel fired power plctnts have special applica-
tions for facilities using certain alternative
fuels.
National Emission Standards
for Hazardous Air Pollutants
EPA
Establish strict emission limitations for
specific pollutants not covered by ambient air
quality standards.
Requirements for Issuance of
National Pollutant Discharge
Elimination System Permits
EPA Establish procedures and requirements for
issuance of permits to allow discharges of
pollutants into navigable waters. Permit
conditions will include technology-based
standards required by the Clean Water Act and
any additional limitations necessary to
protect water quality standards.
Toxic Water Quality Standards
EPA
Establish health or environmental requirements
for specific pollutants imposed on a category-
by-category basis on stationary sources.
-------
Exhibit -16 eon'I;
ENVIRONMENTAL REGULATIONS
Regulation
Sponsoring
Agency
Purpose
Exist i IK) con' t
Hazardous Substances
EPA
Designate hazardous substances subject to
Clean Water Act regulations and identify which
harmful quantities must be reported if spilled
in navigable waters and for which liability
for cleanup expenses will exist.
Requirements of Issuance of
Corps of Engineers Permits
for Construction in Navigable
Waters or Discharge of Dredged
or Fill Material
DOD
Establish procedures and requirement;
issuance of such permits.
for
Surface Mining Regulations
DOI
Establish policies and environmental standards
for control of surface mining activities
pursuant to the Surface Mining Control and
Reclamation Act of 3977.
Procedures for Environmental
Impact Statements
CEQ
Regu lilt ions Governing
Issuance of Environmental
Tmp.'iet Sta tcinonls
CEO
Set forth CEO's requirements for federal
agencies' issuance of environmental impact
statements on major federal, actions signifi-
cantly affecting the environment. The legis-
lation wcis established pursuant to NEPA.
Establish individual agency requirements for
issuance of environmental impact statements,
which must conform with CEO regulations.
t-*
CO
-------
COLLATERAL ACTIVITIES 4.14
House of Representatives Committee with Synfuels
Jurisdiction. Most legislation dealing with government
financial aid to commerce and industry is the responsi-
bility of the Banking Committee, as is any matter dealing
with the control of prices of commodities, rents, or
services. The Interstate & Foreign Commerce (to be
re-named Energy & Commerce in January 1981) Committee
has jurisdiction over all petroleum, natural gas, and
electrical power issues. The Science £ Technology
Committee is responsible for scientific, environmental,
and energy R&D, while the Agriculture Committee will
contribute to any biomass-based energy development.
Other committees that are not participating directly but
will influence synfuels developments include the
Appropriations Committee, which approves all spending
of federal funds; Government Operations, which could have
oversight responsibility for SFC and parts of DOE and
SPA involved with synfuels; and the Interior and Insular
Affairs Committee, which is responsible for water issues,
public lands, and environmental issues.
Senate Committee with Synfuels Jurisdiction. This arcup
includes the. Committee on Energy & Natural Resources,
which has responsibility for all energy matters, and the
Banking and Agriculture committees, whose responsibili-
ties, are similar to those for their colleagues in the
House. Other Senate committees involved include the
Appropriations and Intergovernmental Affairs committees,
whose responsibilities are also comparable to the
corresponding House committees. Finally, the Environ-
mental & Public Works Committee is responsible for
environmental policy and R&D and for water resources.
Executive
Participants
Executive participants in the alternative fuels industry
consist of the Department of Energy (DOE) and the
Synthetic Fuels Corporation (SFC). The SFC is part of
the Energy Security Act.
DOE. Within DOE, Resource Applications and Fossil
Energy are responsible for managing the development of
alternative fuels. The Office of the Assistant Secretary
for Environment is responsible for effectively addressinc
the environmental research, assessment, and control
issues related to current and developing -energy technologies
Within Resource Applications, the alternative fuels
H.igler., Bailly >&L Company
-------
COLLATERAL ACTIVITIES 4. 15
program is largely carried out in the Office of Coal
Resource Management, which is responsible for encouraging
commercialization of specific technologies. There are
divisions foe coal liquids, low- and rnedium-3tu coal
gasification. The Office of Coal Resource Management
issues solicitations for feasibility studies and
cooperative agreements. The feasibility studies program
is designed to accelerate the design and planning efforts
leading to the construction and operation of commercial-
scale alternative fuel production facilities by non-
federal entities. Cooperative agreements are targeted
to projects that are in the advanced development stage.
Alternative fuels commercialization is the responsibility
of the Office of Project Management. This office is
currently determining which high-3tu synthetic gas plant
to fund in ?Y 1981: the Illinois Coal Gasification
Group's COGAS project or Conoco Coal Development's Noble
County, Ohio project. At least six other projects may
come under the auspices of the Project Management office.
The Office of the Assistant Secretary for Environment
(A5EV) formulates and manages specific environmental
responsibilities and functions mandated by the National
Environmental Policy Act and'other environmental
legislation. Responsibilities entail overviewing the
energy technology RD&D activities to assure the
environmental, health, and safety (EH&S) acceptability
of those developments, and conducting R&D necessary
for DOE to resolve EH&S uncertainties and conflicts.
Environment's Technology Assessment program in FY 1980
will include substantial progress on alternative fuels
assessment. ASEV is supported by the Environmental
and Safety Engineering program to make independent
evaluations on environmental control aspects of DOE's
energy research program and national energy policies.
In FY 1981, emphasis will be placed on technologies
that convert coal from a solid to a premium liquid or
gas. The Biological and Environmental Research
Program has initiated a series of site-specific research
projects to evaluate potential health and environmental
problems associated with coal gasification and
liquefaction process developments. The overall objective
of these projects is to develop a data base for evaluating
health and environmental effects of commercializing an
alternative fuel technology.
Hagler, Bailly >Si. Company
-------
COLLATERAL ACTIVITIES 4.16
Overall coordination of the DOE alternative fuels program
will be provided by an Oversight Committee, composed of
the Assistant Secretaries of Resource Applications and
Fossil Energy, with representatives of the Assistant
Secretaries for Conservation and Solar, and Policy and
Evaluation. If Congress establishes the SFC, the DOE
organization will be readjusted. The Fossil Energy
program will probably continue to manage an alternative
fuels RD&D program to do the research to prove existing
technologies and bring forth future technologies. The
role of Resource Applications in future alternative fuels
policy is uncertain.
SFC. The key provision of the Energy Security Act
establishes the SFC for a 12-year period, with, an initial
budget of $20 billion. Within 4 years, the corporation
will submit a comprehensive strategy covering future
investment plans, which Congress will review and vote
on within 90 days.
Before this comprehensive strategy is adopted, the SFC
may assist three projects of its own if the projects
demonstrate needed technologies and no private financial
backer can be found. These plants would be constructed
and operated by private contractors. The SFC could also
purchase or lease a limited number of existing private
plants on a temporary 5-year basis, subject to
congressional veto. SFC must offer such purchase agree-
ments first to the Defense Department. SFC funding will
come from a special Energy Security Reserve, which the
Treasury Department will control.
Until the SFC begins operation, the President may offer
up to $3 billion in industry purchase agreements, loans,
and loan guarantees through existing agencies. Once
the SFC is functioning, the President may intervene in
an emergency when the SFC is unable to meet defense fuel
needs on its own. Specifically, he may build or acquire
government plants, or mandate supply from private alter-
native fuels producers.
Associations
and Industry
Many trade associations and private industry organizations
are involved in promotion of alternative fuels: the Gas
Research Institute, Electric Power Research Institute,
and most major petroleum companies. The Fluor Corporation
is playing a major role in developing indirect liquefaction
Hagler, Bailly &. Company
-------
COLLATERAL ACTIVITIES 4.17
in the United States. In conjunction with SASOL (South
Africa's energy company), Fluor reached an agreement with
Texas Eastern Transmission Corporation to evaluate the
costs of a Sasol-type plant in the United States. The
Fluor study considers the Ohio River Valley for potential
sites, estimates costs, and determines ways to tailor
SASOL technology to U.S. coal product specifications and
environmental standards.
The National Council on Synthetic Fuels Production is a
nonprofit corporation to promote the commercial production
of alternative fuels from domestic resources. It is the
only private participant entirely devoted to alternative
fuels developments. The Council will provide a forum
to define and develop industry opinions and positions on
critical issues and will serve as an advocate for its
members before Congress and other government entities.
Hagler, Bailly &. Company
-------
COLLATERAL ACTIVITIES 4.13
Members of the National Council on Synthetic Fuels
Production (as of June 9, 1980), include:
Airco Energy Co.
Air Products & Chemicals
Amerigas
Arco Coal Co.
Ashland Synthetic Fuels
The Badger Co.
The BDM Co.
Bechtel National
Burns & Roe - Humphreys & Glasgow
Cities Service Co.
Combustion Engineering
Conoco Coal Development
Consolidated Natural Gas
' Davy Inc. (formerly Davy McXee)
Dow Chemical'
Dynalectron
Fluor
General Electric
George Hyman Construction
Gulf Oil"
Institute of Gas Technology
Mobil Oil .
Multi-Mineral Corp.
Northern Natural Gas
Occidental Petroleum
Panhandle Eastern Pipeline
Phillips Petroleum
Pullman-Kellogg
Southern California Gas
Standard Oil of California (Chevron)
Standard Oil of Indiana (Amoco)
Standard Oil of Ohio
Stone & Webster Engineering
Sunoco Energy Development
Texaco
TOSCO
Union Oil Company of California
QOP, Inc.
Wheelabrator-Frve
Hagler, Bailly Si. Company
-------
5
SITES
Only the ANR Great Plains gasification project has
reached a stage where actual plant construction can
begin (completion scheduled for 1984). However, as
mentioned in section 4, construction at that site may
be delayed until financing is assured. However, the
United States is identifying potential sites for
planned coal conversion facilities. Most coal
gasification and indirect liquefaction production will
be in EPA Regions 3, 4, and 8. Estimated gas and
liquid fuel production for the ten EPA regions from
1985-1995 is'listed in Exhibit 17.
The most important criteria for identifying potential
sites for coal gasification and indirect liquefaction
are the availability of coal reserves and water resources
and the existence of favorable environmental conditions.
Other factors considered include the existence of an
in-place transportation system, coal mining infrastruc-
ture, and labor supply, all of which affect the cost of
the project. The previous level of coal production
activity will also influence the cost of siting: for
example, reclamation costs may be higher in the eastern
states because the area is more densely populated and
has already undergone extensive mining.
The most prominent site selection studies have been
conducted by three organizations: SRI International,
the Bureau of Mines (.BOM), and the U.S. Geological Survey
(USGS). No one study considered all the above criteria.
The USGS and BOM studies based siting on the availability
of coal and water reserves. Both identified the same
eight regions as having high potential for siting a coal
conversion facility. The one difference between the two
sets of results is that the USGS study included fewer
counties in the Appalachian region because it
considered the level of previous coal mining. The SRI
study focused on the environmental aspects of site
selection. However, SRI did not consider such factors
as resource availability, transportation of resources
and products, availability of markets, or choice of
conversion technology.
In all, 120 counties were identified in common by the
three studies as potentially suitable for siting coal
gasification and indirect liquefaction facilities.
These counties are listed bv state in Exhibit 18. All
Hagler, Bailly &. Company
-------
Exhibit 17
Estimated Gas and Liquid Fuel Production by EPA Region, 1985-1995
(thousand bpdoe)
EPA Region
1. Mainu, Vermont, New Hampshire.
Massachusetts. Hhodu Island.
ComiL'cticut
2. Now Yoik. Now Jersey. Puerto Rico,
Virgin Islands
3. Delaware. Maryland. Pennsylvania,
Virginia. West Virginia, District
ol Columbia
A. Alahama. Goorijia, Florida.
Mississippi, North Carolina,
South Carolina. Tennessee,
Kentucky
!>. Illinois, Indiana. Ohio.
Michigan, Minnesota. Wisconsin
(i. Arkansas, Louisiana, Oklahoma,
Tuxas. New Moxico
/. Iowa. Kansas, Missonii.
Ncliiaska
U Coloiado. lllah. Wyoininij,
Montana, North l)akota,
!:J)inli [)akota
9. Ari/ona. Caliloinia,
Nevada. 1 lawaii
10. Alaska, Idaho. On^on,
Washington
19B5
Low- to
Medium-Qtu
Gas
Iliyh-Utu
Gas
20 33.!.)
Liquids
1900
Low- to
Medium Utu
Gas
20- -10
20 50
20-00
20 - '10
20 - 10
0 - 40
Hicjli Bui
Gas
20 - 2'5
60 - 75
Xli- 125
Liquids
50
0 - 25
75
0 25
1995
Low- to
Modinm Bin
Gas
40 - 70
20 - 35
40- 100
50- 100
50 - 70
20- 35
40 - 70
20 - 35
20 - 35
High Dtu
Gas
20 - 40
40 - 50
75- 115
20 - 40
100- 140
20 - 40
Liquids
50 - 75
100- 125
75
50 - 75
150 175
2'.')
25 - 50
SOUIiCII. H.ii|li:i. U;iilly K. Company.
-------
Exhibit 18
Overlapping Counties with Potential for Coal
Gasification and Indirect Liquefaction Development
Colorado:
Gariald
La Plata
Jackson
Routt
Illinois:
3ond
Bureau
Ciinton
Crawford
Dcugias
Edgar
Fayette
Franklin
Fulton
Gallatin
Greene
Grundy
Hamilton
Henry
Jackson
Jefferson
Knox
La Sslle
Lawrence
Livingston
Logan
McLean
Macon
Macoucin
Madison
Marion
Wenard
Montgomery
Perry
Putnam
Randolph
St. Clair
Saiine
Sangamon
Washington
White
Indiana:
Gibson
Knox
Posey
Sullivan
Vanderourch
Verm ill ion
Vigo
Warrick
Kentucky:
Henderson
Hopkins
Me Lean
Muhlenberg
Ohio
Pike
Union
Webster
Montana:
3ig Horn
Custer
Dawson
Musselshell
Richland
Rosebud
Sheridan
Treasure
Yellowstone
New Mexico:
Me Kin ley
San Juan
North Dakota:
Hettinger
McLean
Mercer
Oliver
Stark
Ward
Williams
Ohio:
Athens
Belmont
Carroll
Columbiana
Harrison
Jefferson
Meigs
Monroe
Morgan
Muskingum
Noble
Perry
Stark
Tuscarawas
Pennsylvania :
Armstrong
Sutler
Camcria
Clarion
Clearfield
Fayette
Greene
Indiana
Somerset
Washington
Westmoreland
Utah:
Carbon
West Virginia:
Sarbour
Socne
Harrison
Lewis
Logan
Marion
Marshall
Monongalia
Ohio
Preston
Taylor
Upshur
Wester
Wetzel
Wyoming:
Cambell
Carbon
Converse
Johnson
Lincoln
Sheridan
-------
SITES 5.4
three studies were in almost complete agreement on poten-
tial sites in Kentucky, Ohio, Pennsylvania, West Virginia,
and Wyoming. Overlapping sites are also scattered in
Colorado, Montana, New Mexico, North Dakota, and Utah.
Assuming that each county can support only one
50,000 bdoe coal conversion plant, a conservative
assumption, all three studies would agree that potential
sites could support 6 mbd of alternative fuels produc-
tion.
In the following sections, we briefly discuss the USGS,
30M, and SRI studies.
USGS
The USGS study primarily considered proximity to coal
reserves when determining potential sites. These sites
were then studied to determine adequacy of water
resources. The resulting potential sites are mapped in
Exhibit 19. (USGS noted that siting is further con-
strained by federal, state, and local government guide-
lines, although this factor was not part of the USGS
siting criteria.) USGS found only a few areas with water
supplies inadequate to support alternative fuels develop-
ment; however, the water supply in many areas is fully
appropriated. Using geological criteria, USGS character-
ized the potential of the eastern and western regions
for alternative fuels development. The eastern regions
of the United States will be constrained by environmental
problems and large existing populations, which would
greatly increase costs. In the West, some coal -beds may
prove difficult for underground mining techniques,
although site-specific geologic knowledge is lacking for
several regions. As in the East, the major constraint
to coal-based alternative fuels development will be prior
commitment of coal reserves, particularly to steel and
power industries.
BOM
BOM used adequacy of coal reserves, availability of water
supplies, and existence of an in-place coal mining
industry or the possibility of expansion as its siting
criteria. Existence of an in-place industry is important,
as otherwise the need for start-up activities will delay
the project. Once 30M had identified sites according to
these criteria (indicated in Exhibit 20), it narrowed
down suitable sites by considering factors'such as owner-
ship, commitment of the reserves to other uses, bed
Hagler, Bailly &. Company
-------
Exhihil 19
U.S. Coal Sources for Alternative Fuels Production
-------
Exhibit 20
Sites (or Coal Gasification and Indirect Liquefaction Plants
l'itli;nll.il loi iro.it <|;r..llii:n development
SI >I)HCI Hun:.ii, ul Mi.ic-:;
-------
SITES
thickness, number of beds constituting the reserves, and
feasibility of underground and strip mining. 'Some
potential sites may be unattractive because of differing
ownership of coal reserve beds or blocks. Thin coal beds
may provide adequate reserves, but mining would entail
acquisition and use of large land areas. Again,
reserves could be located among several townships or
several beds, which requires consideration of trans-
portation costs, feasibility of multiple-bed mining, and
larger capital-investment requirements.
However-, any or all of these disadvantages may be out-
weighed by proximity of the site to markets or existing
transmission lines. Although BOM could not determine
the impact of all these considerations, it did use the
factors to narrow down sites with high potential to the
eight regions noted in Exhibit 20. The BOM methodology
succeeded in narrowing down potential sites more than the
USGS or SRI studies.
SRI
The SRI study was the narrowest in scope of the
studies. Siting potential was based on the relative
ease of locating alternative fuel plants as determined
from earlier environmental impact statements. SRI made
three assumptions: only environmental aspects of plant
siting will be considered; environmental laws and regula-
tions will not be relaxed in the foreseeable future; and
producers will be most interested in alternative liquid
fuels. Given these assumptions and other related
factors, the Illinois Basin area appears to offer the
most significant opportunities, although numerous other
regions could be acceptable given investment of time and
money to overcome conflicts and mitigate impacts
(see Exhibit 21). However, the SRI study overstates the
potential for locating alternative fuel plants because
much of the available coal in many areas is already
committed to other uses.
Hagler, Bailly & Company
-------
Exhihil 21
Sites for Coal Gasification and Indirect Liquefaction Plants
I'oli.-nli.il lul <|I:VI:|CI|>IM
-------
PROJECT LIST
commercial, demonstration, or pilot plants
^ wiiuuc; j. ^ -L a j. , *-*^-iiwiio'- giu-LWii, w .L. ^ -L .L w L. y -L c* i I u s . .j e v e.i_ d x
of the projects listed on the ' following pages are of
special significance. The TVA medium-Btu project,
listed on page 6.5, will be the first large-scale
medium-Btu commercial project. This plant will also
use a technology other than the Lurgi, with the choice
being among the Texaco, Koppers-Totzek, and Babcock &
Wilcox processes.
Southern California Gas (SCO is planning a gasification
process in conjunction with the Navajo Indians. This
cooperation with Indians could prove important because
much of available western coal lies on Indian reserva-
tions. SCG is conducting a feasibility study of a
gasification project with the Crow Indians.
Several plants are advanced R&D projects, many sponsored
by DOE. DOE's program is made up of four field projects
1) low-Btu gasification of low-rank coal, directed by
the Laramie Energy Technology Center; 2} rnedium-Btu
gasification of low-rank coal, directed by Lawrence
Livermore Laboratory (LLL); 3) underground gasification
of eastern swelling bituminous coal, direct by Morgan-
town Energy Technology Center; and 4) underground
gasification of steeply dipping coal beds, directed by-
Gulf RS.D Company.
LLL at the University of California has studied the tech-
nical and economic feasibility of employing solar power
in coal conversion. After two years of research,
laboratory officials conclude the process is sound.
Solar application uses less coal in the conversion
process: one-half as much coal as the Lurgi process.
Additionally, the process requires only 35 percent of
the oxygen needed in the Lurgi method. Solar conver-
sion does not need a separate oxygen plant to provide
oxygen for the process since the coal is gasified with
carbon dioxide in the focal range of a solar central
receiver olant.
Hagler, Bailly &. Company
-------
PROJECT LIST 6.2
Chem Systems and Union Carbide submitted proposals for
funding of development of two indirect coal liquefaction
processes. The Chem Systems process produces methanol
from synthetic gas at a cost 10-15 percent lower than
currently known processes, and the Union Carbide research
involves a new catalyst that would convert synthesis gas
directly to high-quality liquids. Under the Chem
Systems proposal, DOE would finance 80-90 percent of
a 35 barrel per day pilot plant to produce methanol from
synthesis gas. The cost savings would result from
improved heat recovery. Union Carbide's new catalyst
circumvents the need for product upgrading before
conversion to methanol.
Mobil is exploring a new coal gasification process that
requires smaller quantities of hydrogen than existing
gasifiers. Reducing the hydrogen volumes would
significantly lower the costs of Mobil's coal-to-methanol
process. Lurgi U.S., the U.S. branch of the German firm,
is also researching Mobil's M-gasoline process.
Hagler, Bailly 'St. Company
-------
U.S. CoAI. CAS U'LCATJOU AND
lUDIKKCT MOUhM-'ACTION PROJECTS --
COMMERCIAL
Project/
lyocti Lion
Car-Mox Low-fltu
Gasification
Nitro, WV
Low-litu Gasifiers
for Commercial Use
York, I'A
l.ow-lilti Gasifiers
tor" Commercial Use
Uuluth, MN
C.i terpi. 1 \ ft i. Ti: at: tor
York, I'A
Operator/
Subtechnology Product Size Contact
Car-Mox gasifier Steam, 2.3-3.5 t'.ike Chemicals, Inc.
carbon MMSCE/day (304) 755-3336
monoxide
Wellman-Galusha Low-Utu gas 2.0 Glen-Gery Corp.
MMSCl-'/day R. W. Oamniann
(215) 777-6570
Luryi-SUoic Low-Utu gas 0.3 University of
(Poster-Wheeler) MMSCiyday Minnesota; DOE
Warren Soderburg
(G12) 373-4521
We 1 1 .man-lncan- l-ow-btu gas 15 Caterpillar Tractor,-
descent MMSCP/day Ulack, Si. vails &
Source of
Status l-'unding
Began operating Fike Chemicals
late 1970;
currently not
operating
because of
technical
difficulties
in feeding coal
Start-up in 50% Acurex-
October ].977 Aero therm Corp.
50% DOE
Start-up 50% DOE; 50%
October 1978; University of
periodic shut- Minnesota
downs for
equipment
modification
Construction
comp 1 e ted J'u no
Hyson, Inc. 1979; start-up
Stan Curtis August 19/9
(717) 757-0520
-------
U.S. COAL GASIFICATION AND
INDIRECT uniiEFACTiON PRO.IECTS
COMMERCIAL (con'U)
Pi 0 jl.-Ct/
txicd t ion
En recon Coal
Gasif ier
Golden, CO
I.ow-Btu Gasi tiers
for Commercial Use
Pike County, KY
Forest City Coal
Gas if ication
Forest City, 1A
Coal Casifier
Wood River
(East Al ton) , If.
Subtechnology Product Size
Fluidized bed, Medium-etu 3.5
medium-Btu gas MMSCF/day
process
Wellman-Galusha Low-Btu gas 8-3
MMSCF/day
Entrained or Hydrogen
fluidized bed 34.6 MMSCF/
day
KILNGAS Low-Btu 69.2
gas MMSCF/day ,
increasing
to 461.1-
576.4
MMSCF/day
by 1 904
Operator/
Contact
En recon. Inc.
(303) 534-3653
DOE; Appalachian
Regional Commission
Commonwealth of
Kentucky
Mi.ke Newton or
Dave Maneval (ARC)
(202) 673-7904
Billings Energy
Corp.
Al 1 is -Chalmers
Gerald Peterson
(414) 475-2004
Status
Start-up began
in December
1979, full
operation in
spring 1900
Construction
, began October
1970, 90*
complete
today; fully
operational
by spring 1981
Groundbreaking
by ."January 1,
1902
Engi.iec.rjny
design in
p r o c e : j s ; ground-
breaking sched-
uled for fall
19HO; operation-
al by 1903
Source of
Fund illy
En recon. Inc.
50% DOE; 25*
Kentucky
DOE; 25%
Appalachian
Regional
Commission
State of Iowa;
Forest: City;
funding
request through
DOE
Al.lis-Chalmers ,
State of
T.I lino is ;
request pending
at DOE and
participate ng
ut i litres
-------
U.S. COM, GASIFICATION All!)
INDIRECT LIOIIEI'ACTION PRO.'JECTS COMMERCIAL (con't)
Project/
l^uCu L i on
Chemicals from
Coal
King sport, TN
Great lM.ai.ns
Gasification
Mercer County, ND
Uurnham Coal
Gasification
OpeiuLor/
Subtechnology Product Size Contact;
Partial oxida- Industrial Tennessee Eastman
tion (Texaco) chemicals Co.
(615) 246-2111
Lurgi fixed bed High-Btu gas 125 MMSCP/ Great Plains Gasi-
day fication Associates
Al Browning, Mgr.
(313) 965-8300
Lurgi Pipeline gas 72 MMSCP/ El Paso Natural Gas;
day Ruhrgas AG; Pacific
Status
Construction
to begin in
late 1980;
start-up in
mid-1983
Construction
to begin in
1980; sched-
ul ed for
completion in
1901
Project being
restructured as
fiource of
l-'uiid ing
Tennessee
Eastman Co.
Great Plains
seeking loan
guarantee;
opposition to
passing plant
costs on to
customers
Request in to
DOE for proce
l-'our Corners Area
Ntivet jo reservation
Gas £ Electric
Mr. Yungert
(915) 543-3140
private indus-
try consortium,
wi.tli start-up in
f.i rst quarter of
1905
engineering
completion by
fall 19HO; to
be privately
operated after
September 1980
cr>
Ul
-------
U.S. COAI. GASIFICATION AMD
ItlOlKIX'T I.. I 011KK ACT JON PROJECTS
COMMERCIAL (con ' t:)
Pro )uc t/
l-octi t ion
Nokota
Bismark, ND
Sou t lie r n Ca 1 i f o r n ia
Gas Co. (with
Navajo Indians)
Navajo reservation
Mo u 1 1 1 a i 1 1 F u e 1 S u pp 1 y
Company (MFSC) SNG
Emery, U')'
Gas if i cat ion
Easter, Wyomi rig
Subtochnology Product Si.ze
Lurgi gasifi- Methanol, 05,000
cation with Natural gas barrels/day
methanol + 3,000
synthesis units barrels/day
gasoline
blending
stock
Lurgi Iligh-Btu 125 MMSCF/
Methane gas day, j n_
creasing to
250 MMSCF/
day
Slagging Lurgi Pipeline 125 MMSCF/
or MFSC concept gas day; in-
creasing to
250 MMSCF/
day
Lurgi with Pipeline 137.5
methana tion gas MMSCF/day
Operator/
Contact
Nokot.a Co./
Fluor Engineering,
San Francisco,
California
Galen Andersen
(Nokot.a)
(.701) 223-6180
Southern Calif.
Gas Co.
Robert Rudzik
Project Manager
(213) 609-3506
MFSC
Ralph Coats, .
Director of Research
(OOJ) 534-5463
Panhandle lias tern
Pipeline Co.
Dan /.owe 11
(713) 520-1190
source of
Status Funding
Construction to Request for
begin in 1902; DOE funding
start-up in fall pending
1985, with
commercial
operations in
1906
Construction to DOE request
begin mid-1902; pending
completed and
operating in
1 906
Start-up pi tinned MFSC, Inc.
for 1908, with
facility in
operation by
1990
In holding stage
en
-------
U.£i. CMAI. GASIFICATION ANO
KI.:CT I,.IOIII::FACTION PKO.JF.CTS
DEMONSTRATION
I'l O juCt/
lx)Cci L ion
industrial Fuel Gas
Demonstration Plant
Basket t, KY
TVA Ammonia From
Coal Muscle Shoals,
AT,
Industrial Fuel Gas
Demons trail ion Plant
Memphis, 'I'M
Subtechnology Product Size
Texaco Industrial ga MMSCF/
fuel gas,- day
ammonia
Texaco partial Ammonia; Casififtr-
oxidation SNG .1 MMSCF/
process hour
retrofitted
to existing
225 tpd
ammonia
plant
IGT-U-Gas Medium- 175
(Foster-Wheeler) ntu MMSCF/day
with methanation industrial
fue 1
-------
U.li. COM. GASiL-M CATION AND
INDIRECT I.10IJEEACTJON PROJECTS DEMONSTRATION (con't)
I'n) ject. /
lerat ioiial by
1907
will split con-
struction and
i >pe ra t i ng cos ts
f>n/50 wi l h
(X)
-------
U.S. COAL, CAS LT1CATIOU AND
MIDI KtX.T LinUhlKACTlON PKO.'JECTS DEMONSTRATION (cont'd)
I'l u ject/
location Subteehnology Product
Iligh-litu Gas (con't)
fuel Gas Utility Combustion Utility
l.iike Charles, La Engineering fuel gcis
Iligh-Btu Gas 1GT-IIYGAS Iligh-utu
Western Kentucky (Bechtel) gas
Operator/
Size Contact Status
150 MW Gull: States Not yet
Utilities, determined
Combustion
Engineering, Inc.
John Money
296-1240
83 MMSCC'/ 1GT, Texas Gas Site-specific
day Transmission Co., plans not yet
Source o 1:
l-'uiid i. ug
industry J f
project wins
competition
with Illinois
coal project
DOE funded 100%
of design, will
fund 50% of
construction
and ope retting
costs
DOI-: funded 1.00%
of desi gn , but
State of Kentucky
I'aul. f'edde
(502) 926-H6B6
defined
didn't select
for hi.gh-i'Jtu
d e mo u a t r a t :i. o rt
-------
I)'. S. COAL CAS.11-'[CATION AND
IIJDlkKCT LinilEFACTIOH PROJECTS --
PILOT
Project./
Local, ion
Subtechnology
Product
Opel .1 tor/
Co 11111 c t
Status
Source- of
Fund Ing
Synthane Pilot Test
Allegheny, PA
Synthane
Iligh-Utu
Lummus Co., DOE
Start-up in
1976; presently
deactivated and
in stand-by
status
1979 DOE review:
decision to
deactivate
Medium-Mtu gasi-
fication of low-
rank coal
Gillette:, Wyoming
In-situ
Mediuin-Btu
cjas
Undei'yround yasi
fi.cation of
Eastern coal
Princtiton,
West Vii.cj.inia
In-situ
Low- to-mecl i um-
Utu gciS
DOE, Lawrence
Livermore Labora-
tories (T..LL)
l.LI. Washiington
office
631-2400
IIYCAS 1'i.lot Plant
Chic-ayo, IL
IGT-IIYGAS
Iligh-Btu gas 1.3 MMSCF/
dciy
IX)E, Morgan town
Energy Technol.oyy
Center (METC)
(304) 599-7764
Completed two DOE
underground coal
gasification
tests
DUE, Gas Research
Institute, IGT
Fred 'Zerkle (HJT)
(202) 705-3511
Abner Flowers (
-------
U.S. (MM. CAS IP I CATION AND
i Mill UECT i,inm:i-'AC'i'iON PROJECTS --
PILOT (con't)
Pro )cct/
Loca L ion
Low-litu Gasifi-
cation of Low-
rank Coal
llanna, Wyoming
Texaco Coal Gasifi-
cation Process
Development
Montebel. lo Research
Labora tory , CA
IGT U-Gas
Chicago, Illinois
A d v a n c e d Co a 1
Gasification System
for Electric Power
Operator/
Subtechnology Product Size Contact
In-situ Low-Ctu gas DOE, Laramie Energy
Technology Center
(LETC)
(307) 721-2011
Texaco SNG 3 MMSCF/ Texaco
day James L. Dunlap
Vice Pres.
Alternative Energy
(914) 253-4000
U-Gas Medium-Utu 1-3 MMSCF/ IGT, DOE
gas day
Westimjhouse Low- and 1. MMSCF/ Wes tinghouse
Process (Fluid- medinm-Btn day Electric Corp.
iiied bed gasi-
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U.S. COAI, GAiUFl CATION All!)
I Ml.) I KKCT I.KHIKI-'ACTIUl-l I'RCJ.J KCTS --
PILOT (con't)
I'I'O ji.'C t/
Loc
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U.S. COAI, GASIFICATION AND
IIIDIKKCT LiniJKl'ACTlON PROJECTS -
- PILOT (con't)
I'i'O jec t/
1 x>cii L J on
Tr i -Gas
Monroeville, PA
Firing of Iron Ore
Pelletiizinq Furnace
with Low-Btu
Furnace Gas
Twin Cities, MN
Subtechnoloyy Product Si/.e
BCR fluidized Low-Btu yas . .1. MMSCF/
bed day (plant
operated
for 40-hour
period once
every 3
weeks)
Wellman-Galusha Low-btu yas 4.2 MMSCF/
day
Ope r n tor/
Co n t a c t
Bituminous Coal
Research, Inc.
(OCR)
fcarle Diehl, Myr.
(412) 327-1600
Twin Cities
Research Center
John C. Niyro
Project Supervisor
BOM
(6.12) 735-4630
Mr- Dunham
UOM-D.C.
(202) 634-1004
Status
Start-up
October 31,
1977; in
operation
through
October 1980
Teal: performed
November 1978;
operations
bey an December
1970
Source or
Fundiny
oon:; BCR
U.S. Bureau of
Mines/DOF/IJPA
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U.S. COAI, GASIFICATION AND
1 ML) I UKCT 1.1 0111:: I-' ACT JON PROJECTS -
- PILOT (con't)
I'ru jt-:cL/
l/)C'iltion
l-'ast Fluid! zed Bed
Gasification
Lawrence Township,
NJ
llowinet Aliiiainuia
Lancaster:, PA
Chemically Active
Fluid Bed '
San uerii to, TX
llnderg round Gas i.
fication of
Steeply Dipping Beds
KawJins, Wyornjinj
Op CM a tor/
Bubtechno.logy Product Si.zu Contact
FasU fluidized Low- or .6 MMSCF/ Hydrocarbon
bed gasif ication medium- Li tu day Research, Inc.
process gas (111(1)
Marvin Rakow
(609) 096-1300
Wellman-Galusha Low-Btu gas 3.3 MMSCF/ llowmet Aluminum
day Corp.
William Klaide
(717) 393-9641
Chemically Sulfur free 23 MSCF/day Central and South-
active fluidized Low-Btu gas (based on a weat Corp. ,
bed (Kxxon) 24-hour day) Foster-Wheeler (l;i-W)
Energy Corp. , EPA
Roland Fridell (F-W)
29U-7750
Tn-situ Low- to DO)-:, Gulf R&D Co.
medium- Uf.u
gas
Source of
Stiitiui L-'und i.ng
Construction DOE; IIRI
and initial
operations
completed
Construction
started in
1979
Start-up in Design and
.1979 engineer.! ng
funded by EL'A
first test DOE
began October
1979; tests to
be conducted
over a 5-year
period
t-'
.1-
-------
U.S. COAI. GASIFlCATJON AND
1111)1 Ki:CT 1.1 HOF FACT ION PKOJFCTS PILOT (con't)
Product/
l/jca t.ion
General Motors Coal
Gasification
Saginaw, MN
Slagging Gasifier
Development
Grand Forks, ND
TOSCOA).. Process
Development
Golden, CO
Mountain Fuel Supply
Company (MFSC) Coal
Gas i i: iccition Process
Sal t Lake Ci t:y , UT
Subtechnology Product Si^e
Stoic (Foster- Low-Btu .3 MMSCF/
Wheeler) yas day
Slagging fixed Low-Utu
bed gas
TOSCOAL process Medium- to .7 MMSCF/
high-Btu day
gas, char;
oil
Fntrained flow, Medium-I3tu 1.7 MMSCF/
oxygen-blown gas day
gas. if i er/
slagging (MFSC &
Ford, liac-oii &
Davis)
Operator/
Contact
General Motors
Grand Forks Knergy
Technology Center
(701) 795-8000
TOSCO Corp.
Robert: Mall
Research Division
(303) 425-6021
MFSC; Ford,
Uacon & Davis
Ralph Coats
(HOI) 534-5463
Status
Start-up in
March 1900
Relocated in
October 1979;
steady-state
operations
scheduled to
begin second
quarter FY 80
Development
continuing w:i th
pilot plant
program
Detailed
eng ineeri ng
design 00%
complete
Source of
Fund i ng
General Motors
DOF; Grand
Forks lirmrgy
Technology
Center ;
Stearns-
Roger, Inc.
TOSCO Corn.
Seeking DOF
funding
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7
INTERNATIONAL ACTIVITIES
The most important operating alternative fuels plant in.
the world is the Sascl complex in South Africa, which
is based on indirect liquefaction technology. The first
plant, Sasol One, has been operating for 25 years.
Sasol One uses the Lurgi gasification process and both
the German Arge (fixed bed) and American Synthol
(fluidized bed) types of Fischer-Tropsch reactor.
Sasol Two, which will begin operating in 1930, will use
only the fluidized bed reaction (see Exhibit 22 for a
diagram describing the Sasol Two process).. The Lurgi
gasifiers produce raw synthesis gas as well as tar,
oils, and gas liquids. Upon gasification, the raw gas
is purified in a Rectisol unit, common to all Sasol
plants. The purified gas is then reacted with an
iron-based catalyst in a Fischer-Tropsch fluidized bed
reactor. Hydrogen and light hydrocarbons are recycled
into the synthesis gas stream used as feedstock for
the Synthol unit.
A product refinery then produces L?G, gasoline, diesel
fuel, fuel oil, jet fuel, and a variety of chemicals.
The Sasol Two unit, a $2.8 billion complex, will
consume 40,000 tons per day of coal to produce 20
commercial products, in particular gasoline and diesel
fuel. 3y varying the catalysts in the Fischer-Tropsch
reactors and adjusting primary processing facilities,
primary product mix can be altered from 30 percent
gasoline/20 percent diesel fuel to a 50/50 mixture.
In combination, Sasol One and Sasol Two will produce
enough gasoline to meet 30-40 percent of South Africa's
gasoline needs.
Upon completion of the Sasol Two project, construction
will begin on Sasol Three, which is almost a duplicate
of the Sasol Two plant. Sasol Three will require an
investment of $3.3 billion. When Sasol Three begins
scheduled production in 1934, the entire Sasol complex
will produce about 112,000 bpdoe, half of South Africa's
needs.
There are multilateral, bilateral, and single-nation
alternative fuels projects worldwide.
The three multilateral activities are the Tokyo and
Venice summit conferences and the International Energy
Agency (ISA) annual review.
Hagler, Bailly &. Company
-------
Exhibit 22
Sasol Two Indirect Liquefaction Process
Mine
Coal
-nenois
Power Station
Phenosolvan
Lurgi Gasification
Gas liquor
i o errluaru treatment
Methane Reforming
CHj
02 Steam
i ar OHS
,, Raw gas
Lurgi Gas Purification
(Rec:isol)
Air Separation
Oxyaen
Fluid Bed Synthol
Product Recovery
Product Refinery
Tar Refining
i ar orocuccs
°'jr9 aas
35%H2-CO
} 3% CH4
2% N2 * C02
Ethylene
LPG
Gasoline
Diesel
Fuel oil
Je: rue!
Chemicals
SOURCE Oil and Gas Journal.
-------
INTERNATIONAL ACTIVITIES 7.3
At the Tokyo Summit Conference in June 1979, representa-
tives of the United States, France, Great Britain,
Canada, Italy, Germany, and Japan formed the Internation-
al Energy Technology Group (IETG). The objective of the
group was to define goals for alternative fuels develop-
ment as a means of (.1) encouraging a worldwide effort
and (2) highlighting the desire and capabilities of
members to cooperate in development programs. Specifical-
ly, the IETG was to draw up a commission of OECD and ISA
members to carry on the purpose of the IETG. Following
preparation of a report of recommendations, the IETC-
disbanded in March 1930.
The ISA, in its 1979 review, recommended that alternative
fuels be developed as quickly as possible in member
countries and that public support for the commercial
demonstration of alternative fuels technologies be
increased where necessary, In addition, the IEA
recommenced that vigorous efforts be made to pursue
President Carter's proposal to expedite the development
of alternative fuels.
The seven major industrial democracies just completed
their 1980 summit meeting in Venice. The nations
agreed to produce the energy equivalent of 15-20 million
barrels of oil per day from nonoil sources by 1990. Half
of this increase will come from greater use of coal, with
the remainder coming from increased use of nuclear power,
natural gas, renewable energy sources, and alternative
fuels, some of which would be derived from coal. The
summit representatives ratified several of the IEA
oil-use reduction goals.
Bilateral and single-nation alternative' fuels projects
are presented in charts on the following pages. Of
the single-nation projects, West Germany has more, and
more varied, coal gasification and indirect liquefaction
plants than any country besides the United States. Most
use the Lurgi-fLxed bed technology for oroduction
of synthesis gas, but a large pilot plant uses the
Texaco-entrained bed process and two other pilot plants
(one under consideration) will use the winkler process.
The Netherlands also has a major alternative fuels
project: a large gasification plant based on Texaco
technology will produce electricity for Rotterdam
beginning in 1986.
Hauler, Baillv &. Company
-------
HI. LATERAL COAL GASIFICATION PROJECTS
Countr i es Snbtechnology
U.S. Department of
Energy (DOE)/ West Germany
LudwJ gsha fon , West Germany Metluinol
synthesis
DOE/Wesl Germany
Wesseling, West Germany M-gasoline
lie 1
-------
COAL, GASIFICATION AND
I ND.I KI::CT L inUEKACTION I'KOJECTS
UY INDIVIDUAL COUNTRIES
Country Subteohnoloqy Product
South Af i ica
S.isol bury* l.urqi /iMscher- Oil, solid
Tropsch waxes, d i ese 1 ,
|u i.d
fuel s
40,000 bbl Sasol 11
of 1 ic|ii.i d
fuels per
day
More than Sasol li I
50,000 bbl
t'if 1. i> |u i d
fuels
Ull MMSCI-'/day , Atrii.'iin l-!xp 1 os.i vo
1,000 tpd Chemicals Industry;
Status
Started-up in
1.955
^u 1 1 production
in 19H2
F'u 1 1 produi;ti on
in 1.904
Analys i a of
technoloyy near
Krupp-Kopptir'ii, Cmhli
(lessen, Wei;!: Germany)
Mcl.achlan K l.tujin'.
Ltd. (Soulh Africa);
'L'KVJ, IIK;.
compj etion.
Ivuln ,j.i:; A(:
Knhi Uoh li> Ai;/SI'c.Mi| AC
ip i n
-j
Ul
-------
COAI, GAS IT 1 CATION AND
I'NUJ KliCT I.IOUEI'1 ACTION PIi:r'd i 'jk
She I I.-Koppers
Synthesis g
I,000 tpd Royal Dutch/Shell
Start-up in
late 1903
To x.i co
!: I ect r ic i ty
One qas i fier
and one ?'.>
MW tjcis
tnrbi ne,
T.. I low
second ijasi -
I i er and i in
City of Rotterdam,
!"> Rotterdam linei.'cjy
Ut i 1 i ty (Gl'ili) ,
Ari'ihc i m I:! I ecl rica.1
by a Test i ni'j baborat'.oi y
si- (KKMA)
l>es i cjn
scheduled Tor
completion by
end ot" 19!iO;
first iitacie ol:
project to
be<|.in o|iet a I. i n<|
in I'JilG. second
:;l.i.|e in
-------
co/u, :.;ASI KI CATION AND
i NDiKiiCT i..igut:i-'AC'!-:i ON PKOJUCTS
BY TNDLVI IJUAI, COUNTK I 1.0S
( '< unit'. i y
He 1 1 1 i IHII
lions i.us
Snbi oulino logy Product Size
in-ai tu Synthesis or Pilot plant
combustion gas
(,'ompan i es Invo 1 ved
Institi.it pour l.e
Development de la
StatUS
Start -up
late I9BI
j n
Caze i. f. ica t ion Son ter-
raine; S.A. (Co|>[>ee-
Kust N.V. (Leiije
di vis ion)
In MX. i 1
Sao ,'jeron imu Koppers-Totzek Gas for pro-
duction of
ammonia and
later for
home use
Will even- Petrobras, Krupp- Start-up in
tually become Koppers 1902
a large
chemical
com pi ex
l.i I) i ax.
(DIit y i ilu Kn low i i;o )
Jlapan lilectric Power
Deve I opinent Compcuiy
Kopper.s-Tot'/.ek Mod i uin-litn
r I i f'<.-.)
Construct]on
began December
1979
Construction to
begin in 19M2;
start-up in
I 984
-J
-------
c< >Ai, ( ;A:; i r i CAT i ON AND
I NUI IUM try
Ct I Hilda
MariaIta Coal, l.tcl. ,
Ve:;tc.t ini.ne (90 mi .
southeast Edmonton,
Alberta)
Great Mr i ta i n
Yugos1 civi .ft
Sub tecli no locjy
Product
Size
Companies Involved
in-si LLI
Entrained flow
gasi f. ier coupled
wi i:li bcise of
r i xocl bud cja a i. f i e i:
(coni| iosi te
cjas i r'ior)
Pilot plant
(100 tpd)
CJernuniy)
Mediuin-MLu
cjcis ( for com-
bust: i on) ;
hyi'lrogen (for
dilution i a syu-
dtiy
Alberta Resecircli
Council, '1 cjoveirmnent
acjencies, 11. industry
participants
Ivritisli Giis Corpora-
tion (MCC) , liri tish
Department of: Knergy
Kosovo coiubi ne/
Ljaa.L f: icat i on plcint,
Kosovo Institute;
Mining Institute
of Belgrade;
Uadium Corp. of
Toxcis; Institute
of Applied Nuclear
linoryy of Melgr.Kle
Status
5-year test is
planned, but
details are
still being
negot.i a ted
To be designed
constructed, and
operated over a
6-year period
Phases II and III
(analytical work)
being finalized;
Phase IV !study
of fugitive emis-
sions) on-going
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