EPA-450/3-74-025
March 1974
AVAILABILITY OF COAL
GASIFICATION
AND COAL LIQUIFICATION
FOR PROVIDING CLEAN FUELS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Water Programs
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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EPA-450/3-74-025
AVAILABILITY OF COAL
GASIFICATION
AND COAL LIQUIFICATION
FOR PROVIDING CLEAN FUELS
by
Edward A. Zawadzki
PEDCo - Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
Contract No. 68-02-0044
Task 15
EPA Project Officer: Rayburn M. Morrison
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Water Programs
Office of Air Quality Planning and Standards
Research Triangle Park, N. C. 27711
March 1974
-------
This report is issued by the Environmental Protection Agency to report technical
data of interest to a limited number of readers. Copies are available free of charge
to Federal employees, current contractors and grantees, and nonprofit organizations -
as supplies permit - from the Air Pollution Technical Information Center, .Environ-
mental Protection Agency, Research Triangle Park, North Carolina 27711, or from
the National Technical Information Service, 5285 Port Royal Road, Springfield,
Virginia 22151.
This report was furnished to the Environmental Protection Agency by the PEDCo -
Environmental Specialists, Inc., Cincinnati, Ohio 45246, in fulfillment of Contract
No. 68-02-0044. The contents of this report are reproduced herein as received from
the PEDCo - Environmental Specialists, Inc. The opinions, findings, and conclusions
expressed are those of the author and not necessarily those of the Environmental
Protection Agency. Mention of company or product names is not to be considered
as an endorsement by the Environmental Protection Agency.
Publication No. EPA-450/3-74-025
11
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PEDCo-ENVIRONMENTAL
SUITE 13 • ATKINSON SQUARE
CINCINNATI. OHIO 45246
513/77 1-433O
COAL CONVERSION PROCESSES
Prepared by
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
Contract No. 68-02-0044
Task No. 17
EPA Project Officer: Rayburn Morrison
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
March 1974
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TABLE OF CONTENTS
ACKNOWLEDGMENT
1.0 SUMMARY
2.0 APPLICATION OF COAL CONVERSION TECHNOLOGY
TO UTILITY PLANTS 2-1
2.1 PRODUCTION OF LOW-BTU GAS 2-1
2.2 COMBINED-CYCLE OPERATION WITH LOW-
BTU GAS 2-5
2.3 COAL LIQUEFACTION 2-6
3.0 GASIFICATION OF COAL 3-1
3.1 INTRODUCTION 3-1
3.2 THE COAL GASIFICATION PROCESS 3-1
3.3 STATE OF THE ART: COAL GASIFICATION 3-7
3.4 ECONOMICS OF HIGH-BTU COAL GASIFICATION 3-9
3.5 ECONOMICS OF LOW-BTU COAL GASIFICATION 3-14
3.6 ECONOMICS OF COMBINED-CYCLE OPERATION 3-14
3.7 APPLICATION OF COAL GASIFICATION
PROCESSES TO POWER GENERATION 3-14
4.0 LIQUEFACTION OF COAL 4-1
4.1 INTRODUCTION 4-1
4.2 HYDROGENATION PROCESS 4-4
4.3 PROCESS DESCRIPTIONS 4-10
4.3.1 Solvent Refined Coal (SRC) 4-10
4.3.2 H Coal Process 4-14
4.3.3 Project COED 4-14
4.3.4 USBM - Coal Liquefaction Process 4-19
REFERENCES
A-l LURGI GASIFIER A-l
A-2 KOPPERS-TOTZEK GASIFIER A-7
A-3 WELLMAN-GALUSHA GASIFIER A-ll
A-4 ADVANCED GASIFIERS A-l4
BIBLIOGRAPHY
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LIST OF TABLES
Table Number Page
1 SUMMARY OF STATUS OF HIGH-BTU GASIFICATION
SYSTEMS 3-10
2 SUMMARY OF STATUS OF LOW-BTU GASIFICATION
SYSTEMS 3-12
3 PUBLISHED ESTIMATED CAPITAL AND OPERATING
COSTS, HIGH-BTU GAS PRODUCTION (250 MM SCFD
PLANT, 1000 MW) 3-13
4 ENVIRONMENTAL PROBLEMS AND WASTE LOADING FOR A
250-MM-SCFD SYNTHANE PLANT 3-15
5 PUBLISHED ESTIMATED CAPITAL AND OPERATING
COSTS, LOW-BTU GAS PRODUCTION (65 BTU/Day) 3-15
6 ESTIMATED COST OF COMBINED-CYCLE OPERATION:
CLEAN LOW-BTU GAS + GAS TURBINE + CONVENTIONAL
POWER PLANT 3-16
7 TYPICAL THERMAL EFFICIENCY OF LIQUEFACTION
PROCESS 4-6
8 CAPITAL AND OPERATING COST, TYPICAL
LIQUEFACTION '(Plant Size - 20,000 TPD) 4-7
9 POSSIBLE SOURCES OF ENVIRONMENTAL PROBLEMS AT
COAL LIQUEFACTION PLANTS 4-8
10 TYPICAL ANALYSIS OF FEED AND SRC PRODUCT 4-13
11 CAPITAL AND OPERATING COST, SRC PROCESS 4-15
12 TYPICAL MATERIAL BALANCE, H-COAL PROCESS 4-17
13 TYPICAL MATERIAL BALANCE, COED PROCESS 4-21
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LIST OF FIGURES
Figure Number Page
1 High BTU gas production - schematic diagram 3-2
2 Low BTU gas production - schematic diagram 3-3
3 Typical gasifier - gas turbine - steam
generator system 3-17
4 Simplified process flow, coal hydrogenation 4-5
5 Solvent refined coal (SRC) process 4-11
6 H-coal process 4-18
7 COED process 4-20
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This report was furnished to the Environmental Protection
Agency by PEDCo-Environmental Specialists, Inc. of Cincinnati,
Ohio, in fulfillment of Contract No. 68-02-0044, Task No.
17. The contents of this report are reproduced herein as
received from the contractor. The opinions, findings, and
conclusions expressed are those of the author and not nec-
essarily those of the Environmental Protection Agency.
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ACKNOWLEDGMENT
The principal technical author of this report was Mr.
Edward A. Zawadzki, Consultant. The project managers were Messrs
T. Devitt and R. Gerstle of PEDCo-Environmental, and the EPA
Project Officer was Rayburn Morrison.
11
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1. 0 SUMMARY
Increasingly stringent environmental legislation presents
problems to utility companies who are required to reduce
emissions of sulfur oxides. Coal conversion processes offer
one potential solution. In these processes 'dirty1 (high
sulfur content) coal is converted to clean gaseous, liquid, or
solid products by reaction with steam, oxygen and/or hydrogen
at high pressure and temperature.
Commercial coal gasification processes for production of
low-BTU gas are available in this country from Lurgi and
Koppers Co., which also has installations in foreign countries.
These gasifiers have been used primarily to produce synthesis
gas from coal and other carbonaceous raw materials for use in
the production of ammonia and methanol. Lurgi has built five
pressure gasifiers to supply 1400 MM BTU/hour of fuel gas for
combined-cycle operation at the Kellerman Power Station, Lunene,
Germany. This plant, which was built to demonstrate the
feasibility of combined-cycle operation, is currently (mid-1974)
in shakedown operation. The plant is designed to attain an
overall thermal efficiency of 36 percent. Discussions are
underway with a utility company to build an 800-MW unit.
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The Wellman Engineering Company of Cleveland offers the
Wellman-Galusha gasifier for production of producer or
synthesis gas.
These commercially available gasifiers have potential
for providing clean low-BTU gas for utility use. Potential
barriers to widespread use of these gasifiers by the utility
industry include the following:
a) None of these gasifiers has been demonstrated at a
utility plant in this country. Factors associated with
utility plant operation such as turndown ratio, surge
in demand, reliability, availability, and compatibility
with available fuels remain to be studied.
b) Thermal efficiencies of these gasifiers, including the
loss in sensible heat due to gas cleaning, are in the
range of 65 to 75 percent. Utilities therefore would
require a significant increase in fuel consumption.
c) High capital investment. Vendor estimates of
capital required for low-BTU gas production at a
large utility plant are in the range of $150 to
$200/KW. Capital costs for plants producing low-
and intermediate-BTU gas are very uncertain; these
values, which must be considered approximations, may
be low.
d) High fuel cost. Gas selling price may range from
$1.00 to $1.50/MM BTU or higher, depending on the
cost of coal and the size of the plant.
e) Use of clean, low-BTU gas in a combined cycle to
improve overall efficiency of power generating plants
is a long-term development. Use of low-BTU gas in
conventional steam generators produces overall
efficiency less than is currently achieved. Develop-
ment of high-temperature gas cleaning systems and
reliable high-temperature, high-pressure gas turbines
for utility use are long-term developments needed to
achieve the desired 40 to 50 percent overall power
generating efficiency in combined cycles.
f) Use of low-BTU gas production to solve environmental
problems before the mid-1980's is not possible. Even
if the utility industry accepted that the commercial
gasifiers could be used, installation of gasifiers to
control a significant portion of the SO emissions
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from Ohio utility plants would require long-term
commitments of 15 to 20 years because of engineering,
installation, and fuel availability considerations.
Low-BTU gas production is the most promising of the
coal conversion systems for utility plant use. High-BTU gas
production, although technically applicable to utility operation,
will not be used because of higher costs and longer development
times. In addition, high-BTU gas is not needed for utility
use.2'3
Coal liquefaction also is potentially attractive to
utilities. The coal is converted to clean liquid or solid
products that are low in sulfur but high in heating value.
Production of clean liquid or solid products from coal
is technically feasible; demonstration of these processes,
however, is not expected before the mid-19801s. Vendors'
estimates of the cost of so-called liquefaction plants range
from $85 to $120 per kilowatt, depending on plant size, with
a product cost of $0.80 to $1.10 per million BTU, depending
2
on fuel cost and plant size.
The costs cited above and in the text that follows are
based upon information supplied by vendors of coal conversion
systems. Recent studies conducted by the National Academy
of Engineers and other knowledgeable groups have concluded
that costs for coal conversion systems will be substantially
higher. For example, on March 6, 1974, the Department of the
Interior estimated the cost of their liquefaction demonstration
plant at $270 million (approximately $430/KW equivalent). This
plant will have the capacity to process 10,000 tons of coal per
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day and to produce approximately 25,000 barrels of liquid
products. Primary products consist of two grades of clean
boiler fuels; secondary products are high-grade naphtha and
4
sulfur. Additionally, a large coal producer stated that
progress in developing coal gasification processes is so slow
that it appears unlikely that any plant will be built before
1980. Probable gas cost would be $1.80 per million BTU in a
plant producing 250 million cubic feet per day. Capital costs
for this plant would be about $600 million, and construction
would require 5 to 6 years; the cost of developing mines to
supply coal for the gasification plant is not included.
Coal conversion systems will be used by utility companies
only after successful demonstrations. All of the products
of these systems can be processed to produce clean fuels that
will meet the most stringent of the Ohio and Federal regulations,
Availability of these systems on a commercial scale is estimated
to be in the mid-1980's provided that enough funds are committed
for development and investment. Engineering and installation of
a significant number of plants in Ohio would require an
additional 15 to 20 years.
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2.0 APPLICATION OF COAL CONVERSION TECHNOLOGY
TO UTILITY PLANTS
Some of the coal conversion systems offer to utility
companies a potential solution to the SO pollution problem.
X
These systems, however, have not yet been demonstrated on a
utility scale, and consequently must be considered as long-
term solutions.
Among the coal conversion systems to be considered for
application to utilities are production of low-BTU gas and
liquefaction of coal to produce clean solid or liquid products.
Production of high-BTU gas is not applicable for electric
power generating plants, since high-BTU gas plants will not be
available by the mid-1980's and will require significantly
higher capital and operating costs than do some of the alter-
native means of SO control; further, conversion of coal to
H
high-BTU gas is not necessary to provide a clean fuel to the
utility companies.
2.1 PRODUCTION OF LOW-BTU GAS
Technologies for production of low-BTU gas from coal
have been demonstrated and reasonable cost estimates are
available. Utility plants can use low-BTU gas either by direct
firing of the clean gas or by firing of clean low-BTU gas in a
2-1
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gas turbine in combination with a conventional steam turbine
cycle.
Clean low-BTU gas can be produced by any of the commer-
cially available systems, including the Lurgi and Koppers-
Totzek processes. These processes produce a hot, "dirty"
low-BTU gas at a thermal efficiency of about 80 to 85 percent.
For combined-cycle operation, the gas must be cooled to remove
sulfur compounds and dust, and thermal efficiency is reduced
to 70 to 75 percent.
Production of low-BTU gas requires about 20 to 25 percent more
fuel than is used in a conventional utility boiler. Combined-
cycle operation, using low-BTU gas as a fuel, may improve the
overall efficiency of the utility plant. When the combined
cycle uses low-BTU gas from coal, however, the problems of
cleaning hot gases must be overcome.
Use by utilities of either currently available gasifiers
or gasifiers under development will depend on a) capital and
operating costs of low-BTU gas processes, b) availability of
land at the power plants, c) demonstration of the technology on
a utility scale, and d) favorable comparison of factors a, b,
and c with control alternatives, such as flue gas cleaning.
All of the currently available gasification processes require
approximately the same capital investment to produce low-BTU
gas. It is unlikely that costs of new or second-generation
gasifiers will differ significantly, even though cost reductions
are a common goal in all development work. Following is a
summary of current costs of coal gasification systems for the
production of low-BTU gas:
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PUBLISHED ESTIMATED CAPITAL AND OPERATING
COSTS FOR LOW-BTU GAS PRODUCTION6'7
(65,000,000,000 BTU/D)
Process
Lurgi
Koppers-
Totzek a
Gas Heating
Value, BTU/SCF
125
300
Capital Investment,
MM $
16.5
40
Gas Price
$/MM BTU
0.60-0.70
0.95-1.05
Coal Cost
VMM BTU
0?30
0.31
a) Costs include gas cleaning and oxygen plant.
Production of low-BTU gas could supply utility plants
with clean, essentially sulfur-free fuel. Utility plants
could meet all of the Federal and State air pollution codes
with currently available gasification technology. The
Koppers-Totzek (K-T) system, claims applicability to all
coals, and thus eliminates certain problems in use of caking
coals, such as those found in Ohio. The K-T system is a
pulverized-fuel-fired high-temperature gasifier, whereas the
Lurgi system entails a fixed or moving bed. The Lurgi system
has been modified when required to handle caking coals.
Conventional gas-cleaning processes are used to remove H S
and dust.
The cost of low-BTU coal gasification ranges from $150
to $200/KW for conversion plants that would service utility
plants of 650 MW higher capacities. The overall cost of
providing low-BTU gas to all Ohio utility plants is estimated
to be between $3.0 and 3.5 billion (1973 base). This
estimate includes the cost of gas cleaning and oxygen plants.
The cost is reduced somewhat if oxygen-blown gasifiers are
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replaced by air-blown gasifiers.
Design, engineering, and construction of a large
gasification plant requires 4 to 6 years. These plants can
service existing or new utility stations.
Sampling gasifiers for all the Ohio utilities at a rate
of about 5 to 7 percent of the requirement per year would
require about 15 to 20 years.
Low-BTU gasification produces fewer environmental problems
than do the high-BTU gasification schemes. For example, the
K-T process should eliminate problems of water contamination
due to tars and oils, since the manufacturers claim that
high-temperature, oxygen-blown gasifiers produce essentially
no tars. Both high-BTU and low-BTU systems produce sulfur
and solid residues, which require disposal. Temperature and
gas residence time determine the extent of water elimination.
Dust from the fluidized-bed K-T gasifier must be controlled.
Siting problems for low-BTU gas production can be mini-
mized if gas is produced at a site adjacent to a utility
plant then pumped by pipeline to the combustors. On-site
production of low-BTU gas requires considerably less land than
production of high-BTU gas, since it requires only the gas has
producers and low-BTU cleaning systems. Existing facilities
for coal storage and handling could be used or easily modified.
The technology and cost of low-BTU gas production
been demonstrated on an industrial scale, and the systems
should be considered as commercially available. Widespread
use by utility plants, however, will be forthcoming only after
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a commercial-size gasifier has been built at a utility site
and operated successfully to generate power. Several utility
companies are conducting engineering studies of on-site low-BTU
gas production. Demonstration of this technology on a utility
scale is not expected to begin before 1978 to 1980.
2.2 COMBINED-CYCLE OPERATION WITH LOW-BTU GAS
Combined cycles for high-efficiency generation of
electricity have been proposed. The simplest system involves
direct firing of clean fuel in a gas turbine followed by a
conventional steam cycle. The principal advantage of combined
cycle operation is increased efficiency. This increase in
efficiency theoretically offsets the decrease in efficiency
due to the production of low-BTU gas from coal. The combined
efficiency of low-BTU gas production plus combined cycle
operation for first-generation systems is about equivalent to
that of a conventional steam plant, approximately 36 percent.
A combined-cycle system consisting of advanced high-
pressure gasifiers, using hot gas cleanup, and advanced high-
pressure, high-temperature gas turbines would provide overall
efficiencies of 45 to 50 percent. These developments are 15
to 20 years from being commercially available.
The principal barriers to use of combined-cycle operation
by utilities are the need for 1) a high-temperature, high-
pressure gas turbine, 2) an advanced high-pressure gasifier,
and 3) a high-temperature gas cleanup system. The long-term
development of an advanced gasifier-gas turbine system is
justified, and if these systems are successfully developed
they would become the preferred method of producing energy
from fossil fuels.
2-5 .
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2.3 COAL LIQUEFACTION
Methods of producing clean liquid and/or solid fuel from
coal are of interest to utility companies. The advantages of
these processes include production of a low-ash, low-sulfur
fuel that can be stored and transported by conventional
carriers and that can use lower-cost, high-sulfur coals as
feedstock. The improved combustion characteristics of these
fuels should reduce utility maintenance costs and increase
utility availability. Unlike the gas conversion system,
which may be interconnected with the utility plant (e.g.,
combined cycle), the liquefaction processes will operate
independently of the utility plant. This is an attractive
feature.
Coal requirements for Ohio utilities in 1978 are estimated
to be 56.7 million tons. Current liquefaction plant designs
are concerned with processing 55,000 to 60,000 TPD. At this
design rate, three centrally located coal liquefaction plants
could process the 1978 coal requirement for Ohio utilities.
The current estimated cost of these plants would be between
$1.8 and 2.0 billion, equivalent to $85 to $95/KW. These plants
would produce clean fuel at a current estimated cost of $0.80
to $1.00/MM BTU. Several significant problems associated with
the concept of large central fuel conversion plants include
siting, fuel supply, and fuel distribution.
Smaller plants built to accommodate the specific needs
of a single utility plant or smaller groups of utility plants
will cost more per KW of output. A 20,000 ton-per-day (TPD)
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coal liquefaction plant will cost approximately $250 million,
equivalent to $115 to $120/KW. This plant will produce clean
products at a cost of $1.00 to $1.10/MM BTU.
Coal liquefaction processes under development include
the SRC process of Pittsburgh and Midway Coal Co. (funded by
OCR) and the COED process of PMC (also funded by OCR). Details
of these processes are presented later.
The commercial availability of these systems is not
expected before the mid-1980's, although a number of pilot and
2 3
demonstration plants will be operational in the mid-19701s. '
2-7
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3.0 GASIFICATION OF COAL
3.1 INTRODUCTION
This portion of the report describes the basic process
steps of coal gasification, the development status of several
gasification systems, and the potential of gasification for
control of SO- emissions from utility plants to meet Ohio SIP
regulations. Appendix A presents detailed information on
process descriptions, status of technology, and estimated
process costs. Data on these processes were obtained primarily
from published information, including reports from U.S. Environ-
mental Protection Agency, U.S. Bureau of Mines, Office of Coal
Research, and others.
3.2 THE COAL GASIFICATION PROCESS
Gasification of coal involves the reaction of coal, steam,
and air (oxygen) under controlled conditions to produce a gas
containing carbon dioxide, carbon monoxide* hydrogen, methane,
and impurities. This product gas is further processed to
remove carbon dioxide and impurities, including dust and sulfur
compounds. The clean gas may then be burned as a pollutant-free
low-BTU fuel or may be further processed to produce a high-BTU
gas of pipeline quality.
Figures 1 and 2 show the basic coal gasification schemes
for producing high- and low-BTU gas.
3-1
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U)
I
PROCESS
»_ MAKEUP H20
AIR-*
COAL—»
STEAM
SUPPLY
r
(HH4)2S04
STEAM
HEAT RECOVERY .
GAS COMPRESSION
Figure 1. High BTU-gas production - schematic diagram.
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STEAM
COAL
u>
I
U)
COAL
PREPARATION
1
HEAT
.RECOVERY
GASIFIER
ASH
AIR OR
STEAM OXYGEN
H2S AND
TAR
REMOVAL
TAR
GAS
SOLVENT
REGENERATOR
CLAUS
PLANT
TREATMENT
SULFUR
Figure 2. Low BTU gas production - schematic diagram.
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High-BTU Gas
Gasification of coal to produce high-BTU gas involves
the following steps.
0 Pretreatment of Coal - Pretreatment involves normal
operations such as crushing, pulverizing, and cleaning, and
possibly special operations such as thermal treatment in air.
The latter operation is required so that gasifiers can handle
"swelling coals" such as those found in Ohio, Pennsylvania,
West Virginia, and Kentucky. Swelling and caking cause the
coal particle to expand and agglomerate, often producing
operational problems in the gasifier.
0 Devolatilization - Coal is composed of many types of
compounds, some of which are volatile when heated; others tend
to coke when heated. Since the volatile constituents are the
hydrogen-rich fractions, an attempt is made to devolatilize
the coal and to recover these hydrogen-rich fractions.
Devolatilization can be conducted in a separate vessel or in
a zone of the gasifier. The products of devolatilization are
char and gas. (The char consists primarily of carbon and ash.)
0 Gasification - The gasifier vessel consists of zones
in which the various gasification reactions take place. Heat
for the reactions is supplied by burning part of the char
(the oxidation zone). The product gases (carbon monoxide and
hydrogen) are produced by reacting carbon dioxide (the principal
combustion product) and steam (H2
-------
gasifier is in the range of 150 to 350 BTU/standard cubic
foot (SCP) depending on whether the feed gas is air or oxygen.
0 Gas Purification - The gasifier product gas is cleaned
by conventional techniques to remove H2S, CO_, H-O, dust, and
tars. The processes for H S and C02 removal include various
commercially available, organic and inorganic alkali scrubbing
systems. The H?S is further processed in a standard Claus
plant to produce elemental sulfur as a by-product. Recovered
tars are usually recycled to the gasifier as fuel. The gas
purification system produces a clean gas with a heating value
ranging from 250 to 500 BTU/SCF. Because conventional gas
purification systems operate at lower temperatures than those
of the gasifier, the gases must be cooled before purification.
New technology is being developed to permit hot gas
cleanup, and thereby to improve the thermal efficiency of the
gasification process.
0 Catalytic Shift Conversion - As a means of meeting the
hydrogen requirements for the methanation step, part of. the
gas stream is processed by catalytic conversion of carbon
monoxide and water to hydrogen and C02.
0 Methanation - The balance of the gas stream together
with the methane-rich fraction from the shift converter is
catalytically reacted to produce a hydrogen-rich gas.
0 Final Gas Purification - To meet the specifications for
high-BTU gas, final gas cleaning is conducted to remove water
and carbon dioxide.
3-5
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More detailed discussions of high-BTU gas production are
presented in the appendices.
Low-BTU Gas
Production of low-BTU gas is based on more conventional
technology that yields gas with heating value of 100 to 500 BTU/
SCF from coal, coke, chars, refuse, and practically any other
organic material. In this discussion, consideration is given
only to production of hot or cold, low-BTU gas from the
gasification of coal and direct firing of this gas in a boiler
or gas turbine.
Gasification of coal to produce low-BTU gas involves the
following steps.
Coal is gasified with air and steam or oxygen and steam.
In the gasifier, part of the fuel is consumed as heat. The
gasification produces a gas with a heating value in the range
of 100 to 500 BTU/SCF depending on operating conditions and type
of gasifier.
The hot, dirty gas is cleaned, then used as a fuel or raw
material. Current processes for cleaning of the gas require
cooling, in which 15 to 20 percent of the fuel heat is lost.
Production of low-BTU gas is simpler than producing high-
BTU gas and requires considerably lower capital investment.
The process does not require complex gas purification systems
(only H^S is removed), shift converters, or methanators. In
addition, use of air-blown gasifiers eliminates the need for
an oxygen plant. The use of oxygen increases the heating value
of the gas by eliminating the dilution effect of nitrogen in
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the air. Justification for the oxygen-blown system depends
on results of a cost/benefit analysis of the planned installation.
3.3 STATE OF THE ART: COAL GASIFICATION
The gas utility industry had its start by supplying manu-
factured gas for domestic and industrial consumption. Gas was
produced by gasifying coal or coke in producer or water gas
machines. Heating value of the gas was about 150 BTU/SCF.
The early gas producers were relatively small. Production
of manufactured gas dropped off markedly in the U.S. with the
advent of gas pipelines to supply natural gas. For the most
part the supply of natural gas was and is directed to domestic
consumption.
The early gasifiers were simple machines, consisting
basically of a retort, burners, and air and steam blast devices.
Gas cleaning consisted of water sprays for tar removal and
iron boxes for H?S removal. Developments in gasifiers led to a
wide variety of designs, many of which found commercial application.
Advances in gasifier technology entailed increased thermal
efficiency, use of higher pressures and temperatures, and use of
oxygen instead of air. Mechanical devices such as moving rabble
arms and stirrers were applied to allow the gasification of
"caking" coals.
Gasifiers currently available in the U.S. are the Lurgi
Pressure Gasifier, the Koppers-Totzek, and the Wellman-Galusha
gasifiers. These systems are described in detail in the appendix.
These gasifiers produce a low-BTU gas; each, however, can be
incorporated into a system that will produce a high-BTU gas
by use of gas cleaning, shift conversion, and methanation steps.
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None of these gasifiers has been applied commercially
to production of high-BTU gas. Only the Lurgi system has
been used in combined-cycle operation for utility power
generation. Two planned projects in Western America will use
Lurgi systems with low-sulfur non-caking western coals as fuel.
These systems are scheduled for startup during the period 1976
to 1980.
Recognition of current and potential future shortages of
high-BTU pipeline-quality gas, has led to a major R&D effort,
primarily by the Office of Coal Research, U.S. Dept. of the
Interior, to develop highly efficient coal gasification systems
for production of high-BTU pipeline-quality gas.
On August 3, 1971, the U.S. Dept. of the Interior and the
American Gas Association signed an agreement to jointly finance
an ongoing OCR-AGA program over a 4-year period, costing $120
g
million. OCR is administering the operation.
Three pilot plants will demonstrate three different
processes for producing pipeline-quality gas. Each process is
based on advanced technology and is designed to achieve optimum
efficiency with minimum capital investment. One plant has been
built and is under test, one plant is nearing completion, and
the third is in the design and site preparation stage.
In addition to the OCR-AGA program, OCR is investing in
small (1-100 Ib/hr) pilot plants to determine technical
feasibility of various second-generation processes, such as the
ATGAS molten-iron gasification process.
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-------
The U.S. Dept. of the Interior also is funding a pilot
plant gasification process developed by the U.S. Bureau of Mines.
The plant is under construction and will be in operation during
1975.
Developments in low-BTU gas production are currently
centered on commercialization of the Lurgi, K-T, and W-G
gasifiers, and on development of advanced gas producers by
OCR, AGA, and private companies. A number of utilities are
participating in these projects by supplying development funds.
Summaries of current high- and low-BTU gasification
projects are given in Tables 1 and 2.
3.4 ECONOMICS OF HIGH-BTU COAL GASIFICATION
Costs of gasification processes for the production of high-
BTU gas must be evaluated in terms of the status of each system.
Only the Lurgi, K-T, and W-G systems are commercial at this time
and only the Lurgi system has reported costs for a high-BTU gas
system. The costs of the systems under development are often
based on pilot-plant or lab-scale data and therefore must be
considered as approximations until large-scale plants have been
designed and built.
Comparative costs for the systems under development,
based on published information, are shown in Table 3.
The operating costs of these gasification plants are fuel-
sensitive as well as capital-sensitive. Labor force, maintenance,
and all other plant, financial, and tax charges are approximately
equal for all of the processes. The overall cost of high-BTU
gas production from coal ranges from $1 to $2/MM BTU.
3-9
-------
Table 1. SUMMARY OF STATUS OF HIGH~BTU
GASIFICATION SYSTEMS
PROCESS
Lurgi
STATUS
Lurgi gasifiers have been
used for 4 decades for the
production of synthesis and
producer gas. Two utility
companies have submitted to
FPC requests for approval
to build high-BTU plants.
AVAILABILITY
Commercially avail-
able. Current status
of high-BTU gas
project depends on
FPC approval.
Engineering, con-
struction and start
up will require 3
years from date of
approval.
Hygas
Consol CO,
Acceptor
Institute of Gas Technology,
using OCR-AGA funds
($10 million), has built a
75 TPD pilot plant in
Chicago. Process, including
all unit operations com-
pleted first successful 100
hour run 8/73. Construc-
tion of more economical and
efficient hydrogen system
is due to start soon.
Consolidation Coal Co. using
OCR funds completed a $9
million pilot plant late in
1971. A gas purification
process including a methana-
tion step was added and a
test program is under way.
The process is designed to
operate on lignite.
Test program is to
be completed by the
end of 1975. Full
scale design will
require 12-18 months.
If successful,process
will be available for
full scale demo by
early 1980.
As the process now
stands it is not
available for use of
eastern coals. The
pilot plant tests are
to be completed by
1975. If successful
a demonstration plant
could be operational
by early 1980.
3-10
-------
Table 1 (continued). SUMMARY OF STATUS OF
HIGH-BTU GASIFICATION SYSTEMS
PROCESS
BCR Bi Gas
Synthane
Process
STATUS
Bituminous Coal Research Inc.
has developed a process under
OCR-AGA funding. A pilot
plant is to be built in
Central Pennsylvania. Plant
construction, testing, and
evaluation will be completed
by the end of 1975.
The Department of Interior
is constructing a pilot plant
at the Bruceton site of the
USBM. Startup is due in
late 1974, early 1975.
AVAILABILITY
The process requires
considerable develop-
ment time before a
demonstration project
is built. Develop-
ment is 2-3 years
behind IGT and
Acceptor systems
Demonstration on a
large scale will not
take place before
early to mid 1980.
3-11
-------
Table 2. SUMMARY OF STATUS OF LOW BTU
GASIFICATION SYSTEMS
PROGRESS
Lurgi
Koppers Totzek
Wellman
Galusha
CO2 Acceptor
Westinghouse
STATUS
Many commercial installations,
except in the USA. Have an
agreement with GE for develop-
ment of combined-cycle system.
AVAILABILITY
Commercially avail-
able to produce
cold clean low BTU
gas. Not yet
demonstrated on
caking coals.
Koppers Co. Inc. has obtained
license to build K-T process
in U.S. Have 65 inquiries as
of 7/73, most of which are
industrial. No commitments.
Are contacting boiler and
turbine manufacturers. Many
installations in Europe and Asia.
Commercially avail-
able. Process
requires 2-1/2 to 3
years for design,
construction,and
demonstration.
Wellman Engineering Co.,
Cleveland, Ohio, built gas
producers for process use.
During the period 1960 to
present no business activity.
Currently significant inter-
est in marketing process.
Seeking OCR funds to
demonstrate large scale
process
Consol, under an EPA grant,
has conducted lab and
technical and economic paper
studies relative to modify-
ing the CO,, Acceptor process
for use with bituminous coal.
Pretreatment would be
required.
Recently initiated a long
term, 7-10 year, development
and demonstration project.
Commercially avail-
able; however,
Wellman has not
marketed process in
recent years. Need
to scale up gasifi-
cation size to be
of interest to
utilities.
Significant develop-
ment required.
Future development
3-12
_
-------
Table 3. PUBLISHED ESTIMATED CAPITAL AND OPERATING COSTS,
HIGH-BTU GAS PRODUCTION (250 MM SCFD PLANT, 1000 MW)9
1. Basis - Gasification processes are commercial, full-
scale integrated high-BTU plants near final
demonstration
Capital Investment,MM$ Gas Price,$/MM BTU Coal Source
A. Lurgi 330 1.35-1.45 Western U.S.
2. Basis - Gasification process at pilot plant status
Capital Investment,MM$ Gas Price,$/MM BTU Coal Source
A. Hygas
B. Synthane 0.95 Western U.S,
C. Bi Gas 250-275 ^3Q Eastern U.S,
D. CO- Acceptor
Other Factors Affecting High-BTU Plant Costs
Siting - AGA and OCR have evaluated the potential
siting problems for production of high-BTU gas from coal.
The principal considerations are availability of fuel and
water. Fuel reserves for a 250 MM CFD, high-BTU gas plant
range from 90 million to 180 million tons for a 20-year
plant life, depending on the heat content (quality) of the
fuel. In addition, a typical 250 MM CFD gas plant will
require about 1 billion gallons per day of cooling water.
Actual makeup will depend on efficiency and use of cooling
towers or ponds. Estimated site requirement is 100 acres,
which includes areas for coal storage, oxygen plant, gas
9
plant, compressors, auxiliaries, and buffer zone.
3-13
-------
Environmental Problems - Little is said of the environ-
mental problems associated with gasification plants. Table 4
lists projected waste loadings and other environmental factors
affecting a Synthane Type (USBM) coal gasification plant. All
high-BTU coal gasification plants are faced with similar
problems, the most serious of which are disposal of wastes and
treatment of contaminated water.
3.5 ECONOMICS OF LOW-BTU COAL GASIFICATION
Detailed capital and operating costs for producing low-BTU
gas have been estimated for several processes. Only the Lurgi
and Koppers-Totzek system are commercial. Data for other
systems are target prices whose validity depends on successful
development and on accuracy of the estimate. Capital and
operating costs for these systems are given in Table 5.
3.6 ECONOMICS OF COMBINED-CYCLE OPERATION
Although cost projections for combined-cycle plants are
available, all are based on assumptions that reduce the estimates
to goals. Many of the estimates have already proved low because
of rising costs of money, fuel, and labor and consequent rise
in cost of capital equipment. The published costs presented
in Table 6 therefore should be regarded as approximations.
Figure 3 illustrates the combined-cycle operation.
3.7 APPLICATION OF COAL GASIFICATION PROCESSES TO POWER
GENERATION
Optimum efficiency of conversion of energy in the form of
fuels to electrical energy in conventional fossil-fuel-burning
plants is 37 percent, although the average is significantly
lower.
3-14
-------
Table 4. ENVIRONMENTAL PROBLEMS AND
WASTE LOADING FOR A 250-MM-SCFD SYNTHANE PLANT10
Mining
1. Reclamation of strip-mined land (where applicable)
2. Disposal of 6500 TPD of coal refuse
3. Treatment of acid mine water and associated sludge
disposal
Coal Storage and Handling
1. Fugitive dust
2. Treatment of contaminated water runoff
Gasifier, Gas Cleaning and Related Processes
1. Contaminated condensate and scrubber water (4 - 10
million gpd) containing suspended solids, phenols,
thiocyanate, ammonium compounds, carbonates, and
sulfur compounds.
2. Solid wastes:
Dust, slag, and/or grit 500-1000 TPD
Sulfur 200- 600 TPD
Sludge from waste water
treatment plants 0.5-3 million gpd
Table 5. PUBLISHED ESTIMATED CAPITAL AND OPERATING
COSTS, LOW-BTU GAS PRODUCTION (65 BTU/Day)6'7'11
Basis: Commercial status; full-scale plants in operation.
Lurgi
Koppers-
Totzek
Wellman-
Galusha
Heating
value ,
BTU/SCF
125
300
158
Capital
investment,
MM $
16.5
40b
15-20°
Gas price,
$/MM BTU
0.60-0.70
0.95-1.05
0.60-0.75
Fuel
$/MM
0
0
0
cost,
BTU
.30
.31
.31
a) Includes gas cleaning.
b) Includes oxygen plant and gas cleaning.
c) 1963 estimate updated to include gas cleaning.
3-15
-------
Table 6. ESTIMATED COST OF
CLEAN LOW-BTU GAS
CONVENTIONAL
Capital Investment
Plant size
Gasifier (includes
gas cleaning)
Gas turbine
Conventional power plant
$/KW
Annual Operating Cost
Capital charges
Labor and maintenance
Fuel
Utilities
Total
Mills/KWH
(6000 hours)
COMBINED-CYCLE OPERATION:
+ GAS TURBINE +
POWER PLANT
LURGI
330 MW
$16,500,000
11,500,000
41,500,000
70,500,000
235
10,652,400
3,960,000
5,544,000
5,860,800
26,017,200
C02 ACCEPTOR
1000 MW
$130,500,000
19,900,000
101,900,000
252,300,000
252
28,330,000
13,920,000
17,415,000
59,665,000
Mills/KWH
10.34 (6132 hours) 9.73
Both cases include wet gas cleaning. With hot gas cleaning
C02 Acceptor process would cost 9.14 mills/KWH.
3-16
-------
u>
I
COAL
STEAM
AIR
TO STACK
Figure 3. Typical gasifier - gas turbine - steam generator system,
-------
Efficiency for conversion of coal to high-BTU gas is about
70 percent. The fuel is clean and is easily combusted in
existing boilers. The overall efficiency of converting coal
to high-BTU gas to electrical energy is 26 percent. The
overall efficiency of converting coal to low-BTU gas to electrical
energy is 30 percent. Therefore, the high-BTU process would
require 30 percent more fuel consumption than conventional
fossil fuel burning plants; the low-BTU process would require
19 percent more fuel consumption.
As a solution to these serious problems of fuel consumption,
various combined-cycle systems have been proposed to replace
direct firing of high- or low-BTU manufactured gas. Combined-
cycle operations (shown typically in Figure 3) involve the
combustion of gas in a gas turbine with production of
electricity and hot gas, followed by heat recovery in a steam
generator equipped with a steam turbine for power generation.
The combined-cycle approach is of interest to the utility
industry if a workable system, i.e., gasifier plus gas turbine,
can be developed. The efficiency of a first-generation
combined-cycle system is estimated as follows:
Gasifier (low-BTU gas), 76.8 percent efficiency; plus gas
turbine plus steam turbine, 47.0 percent efficiency; overall
efficiency, 36.1 percent. This is approximately 1 percent
lower than optimum efficiency of conventional fossil-fuel plants.
Hope for the future of combined-cycle operation lies in
the following developments:
3-18
-------
1. High-temperature cleanup of synthetic gas.
2. Availability of a high-temperature, high-pressure
gas turbine.
3. Availability of a high-pressure gasifier.
The efficiency of a power station using an advanced
high-pressure gasifier; an advanced high-pressure, high-
temperature gas cleanup system; and an advanced high-pressure,
high-temperature gas turbine is as follows:
Gasifier, 86.6 percent efficiency; gas turbine plus
steam turbine, 57.7 percent efficiency; overall
efficiency, 49.9 percent. This is approximately
13 percent higher than optimum efficiency of current
conventional fossil-fuel power stations, a significant
gain.
The technology of gasification and gas turbines has not
yet reached the level of demonstration to assure that the
currently available gasifier - gas turbine systems could achieve
36 percent efficiency. The principal unknowns entail the
operating characteristics of available gas turbines and the degree
of cleanup (dust removal) achievable by current methods. Long-
term development of advanced gasifier - gas turbine systems
is justified; if development of these systems is successful
they should become the preferred method of producing energy
from fossil fuels.
3-19
-------
4.0 LIQUEFACTION OF COAL
4.1 INTRODUCTION
The use of coal liquefaction processes to abate sulfur
dioxide pollution from utility plants will be at best a long-
term development. Factors that lead to this conclusion are:
1) development status of the process has reached only pilot-
plant or laboratory scale, (2) costs are significantly higher
than those of flue gas scrubbing processes, and 3) for
existing plants and many new plants, siting and fuel require-
ments are stringent. It appears that coal liquefaction tech-
nology will not be available for commercial use before approxi-
mately the mid-19801s.
From a technical standpoint coal liquefaction is an
attractive route to providing a wide range of liquid and solid
fuels for use as relatively clean fuel and chemical feedstocks.
The technology consists of altering the structure of solid coal
by adding hydrogen under high pressures and temperatures. This
alteration causes a portion of the solid coal to become liquid,
similar to a crude oil. This liquified portion, usually
extremely low in sulfur and ash, can then be upgraded to yield
various oils, gasoline, and chemical feedstocks.
4-1
-------
In some cases, the liquefaction process is an interim step
in which the coal is only partially hydrogenated, such as in
the solvent refined coal (SRC) process. The product of all of
the hydrogenation processes is a high-quality fuel, enriched
by hydrogen, in a solid or liquid form that can be used as
low-sulfur fuel or synthetic crude oil.
The technology of coal hydrogenation and liquefaction is
not new. In 1869, Berthelot reported the liquefaction of coal
by treatment of hydriodic acid. Fischer and Tropsch used
hydriodic acid and phosphorous for hydrogenating coal. Fischer
used sodium formate to study the effects of coal rank on degree
of liquefaction. Coal hydrogenation was used industrially in
the mid-1920's. By 1938, large-scale hydrogenation plants were
operating in Germany and England, primarily for the production
of motor fuel. The most modern hydrogenation plant, built during
the 1950's, is located in Sassol at the University of South
Africa.
Current work on coal hydrogenation is focused on providing
a process with high yields and large tonnages of products
including synthetic crude oil and low-ash, high-grade fuels.
Most of the current effort is supported by the Dept. of the
Interior, although several industrial projects were undertaken
recently. Current projects sponsored by OCR are summarized in
the following paragraphs; process details are presented later.
Colorado School of Mines is conducting a laboratory study
of variables affecting the removal of sulfur from coal by
hydrogen treatment. The study is in its early stages.
4-2
-------
Consolidation Coal Co. built a large-scale pilot plant
at Cresap, W. Va. as part of a $20 million program designed
to produce gasoline from coal. Because of technical and other
problems the pilot plant has been shut down. The plant has
never run as an integrated system.
The FMC Corporation has built and is operating a coal
hydrogenation plant (Project COED). Illinois No. 6 coal is
the feedstock. The plant has been run since 1971 and signifi-
cant progress was made during 1972 and 1973. Typical COED
yields per ton of coal are 1 to 1.5 barrels of synthetic crude
oil, 9000 SCF of 650-BTU/SCF gas, and char. Current work is
concerned with optimizing yields and evaluation of end use
characteristics of the product.
The Pittsburgh and Midway Coal Mining Co. is building a
50-TPD plant to produce an ashless low-sulfur fuel by dissolution
of coal in an organic solvent under moderate hydrogen pressure.
The solution is filtered to remove ash and insoluble organic
material. The solvent is recovered. The product is a heavy
organic material called solvent refined coal, which has a
heating value of 16,000 BTU/lb, sulfur content of less than
1 percent, and ash content of about 0.1 percent. Total project
cost has been $28.5 million. The pilot plant will be operational
g
in early 1974.
Several design projects being conducted under OCR funding
include work by Ralph M. Parsons Co., University of North Dakota,
Washington State University, Chem Systems Inc., and American
Oil Co.
4-3
-------
Private programs for research and development of hydro-
genation include the work of Hydrocarbon Research Inc. and the
Rust Engineering Co. for a southern utility. Information on
the details of these projects is not generally available.
4.2 HYDROGENATION PROCESS
A simple coal hydrogenation flow diagram with typical feed
and products is shown in Figure 4. Hydrogenation systems are
generally more efficient than coal gasification processes and
their hydrogen requirements are less than those of high-BTU
gasification systems. Table 7 summarizes the thermal performance
of a typical liquefaction process.
The costs of coal liquefaction process have been studied
in detail; cost estimates, however, are based on laboratory and
limited pilot data and consequently must be considered pre-
liminary. Table 8 summarizes costs for an overall coal lique-
faction system including coal preparation, hydrogen production,
gas purification, and liquid purification.
As plant size increases, the costs decrease somewhat.
For example, a 55,000 to 60,000 TPD (coal) liquefaction plant
yields products at a net cost of 80 to 85C/MM BTU. Cost
estimates should be upgraded as data from pilot operations
become available.
Site and Environmental Considerations
The environmental problems associated with coal liquefaction
plants are typical of those occurring in mining and petrochemical
plants, as indicated in Table 9.
4-4
-------
HYDROGEN
I
Ul
COAL
PREPARATION
1
HYDROGENATION
PRESSURE AND
TEMPERATURE
1
SYNTHETIC
PROCESSING
GASOLINE
HEAVY FUEL OIL
DOMESTIC FUEL OIL
RESIDUE (CHAR)
Figure 4. Simplified process flow, coal hydrogenation.
-------
Table 7. TYPICAL THERMAL EFFICIENCY OF LIQUEFACTION PROCESS
Extraction
Input
Coal
H2
Hydro-feed
Char
Process heat
Steam
Power
89.2
1.1
7.0
1.9
0.8
100.0
Hydrogenation Hydrogen Mfg.
% of BTU input
21.7
75.0
2.1
0.7
0.5
100.0
64.8
30.9
4.3
100.0
Output
H2
Hydro-feed
Char
Low-BTU gas
High-BTU gas
Light oil
Heavy oil
Hydro-re s idue
% of BTU Output
_
61.0
20.8
2.7
1.5
0.7
1.1
-
1.3
-
-
-
14.3
12.9
45.2
18.2
55.0
-
-
-
0.9
-
-
-
87.8
91.9
55.9
Overall BTU efficiency 90% (includes process heat, steam
and power) Net BTU in products 70%
4-6
-------
Table 8. CAPITAL AND OPERATING COST, TYPICAL
2
LIQUEFACTION (Plant Size - 20,000 TPD)
Capital Investment - $230,800,000
Annual operating costs
Labor $ 4,540,000
Coal 58,400,000
Utilities and supplies 11,100,000
Maintenance 7,620,000
Overhead 4,520,000
Taxes and insurance 5,008,000
Capital charges 32,500,000
$123,688,000
Byproduct credits 2,710,000
Net cost of products $120,978,000
4-7
-------
Table 9. POSSIBLE SOURCES OF ENVIRONMENTAL
PROBLEMS AT COAL LIQUEFACTION PLANTS
Coal Mining, Handling and Preparation -
Coal refuse, fugitive dust, acid mine
drainage, sludge from clarifiers.
Liquefaction Process - Disposal of char
or ash; disposal or treatment of sulfur or
H2S; odors; hydrocarbon emissions.
Utilities - Large steam and power require-
ments could entail significant point sources
of SO , NO , and particulate emissions.
A. Jt
4-8
-------
A coal liquefaction process requires a large site. An
equivalent sized plant probably requires a site as large as
that needed for a coal gasification plant; estimates for a
1000 MW coal gasification plant for utility use are 50 to 100
acres. Coal liquefaction plants could be significantly larger,
with the possibility of a single plant providing high-grade
fuel to many utility or petrochemical customers.
Characteristics of High-Grade Fuel for Utility Use
The products of coal liquefaction include low-sulfur
distillates, synthetic crude oil, high- and low-BTU gas, by-
product char, and in the SRC process, high-BTU refined coal.
The end use of these products will depend on cost and avail-
ability. Solvent refined coal, char, and synthetic fuel oil
are candidates for use by utilities.
The value of these products is significantly higher than
that of currently used utility fuels; some small percentage
of current utility fuels could, however, be displaced by the
hydrogenated fuels. The problems of burning these enriched
fuels are not significant. Combustion of synthetic fuel would
be identical to combustion of currently available fuel oil.
Solvent refined coal has good combustion characteristics. It
can be handled in storage like a solid fuel. Before combustion,
it is "melted" by heating with relatively low cost equipment,
then fed as a preheated liquid to the combustor. Since the
sulfur and ash composition of SRC are 1 percent and 0.1 percent
respectively, the coal will meet most air pollution control
regulations. At 1 percent and 16,000 BTU/lb, however, the
SRC would emit 1.25 Ib SO2/MM BTU input; this level of uncon-
trolled emissions is not low enough to meet the most stringent
4-9
-------
of the current air pollution control regulations without some
type of flue gas cleaning.
The char produced as a byproduct is low in volatile
constituents and contains about the same amounts of ash and
sulfur as the original coal. Although its low volatile content
causes some combustion problems, it can be burned in con-
ventional furnaces. Char offers no advantages over conventional
fuels with regard to environmental effects. It will probably
be used as a fuel to raise steam and provide process heat for
the liquefaction processes, and it is an acceptable feedstock
for gas producers and hydrogen producers. Use of char as a
fuel or feedstock is necessary to prevent large BTU losses from
liquefaction processes. Use of char as a fuel for general
utility consumption will depend on its cost to the utilities;
if the cost is not low, the plants will use conventional fuels.
4.3 PROCESS DESCRIPTIONS
4.3.1 Solvent Refined Coal (SRC)
Pittsburgh and Midway Coal Mining Company is building a
50-TPD pilot plant for production of solvent refined coal under
OCR sponsorship. A schematic flow diagram of the SRC process
is shown in Figure 5.
Most types of coal except anthracite can be used in the
SRC process. The yield of soluble material is highest with
highly volatile bituminous coals.
Coal is washed to remove extraneous ash and associated
impurities. The clean coal is crushed to minus 1/8-inch size.
Extraneous moisture is removed by flash drying with hot flue
gas from the process. Fine coal entrained in the flue gas is
recovered by cyclones and returned to the process.
4-10
-------
COAL
HANDLING
AND
PREPARATION
WASTE WATER
HYDROGEN
PLANT
ORGANIC
RECOVERY
COAL
SLURRY
AND
PUMPING
WATER
PHASE
DISSOLVER
ASH
— VARIOUS CHEMICAL PRODUCTS
FILTER
BOILER
so2
LADEN
STACK
GAS
SOLVENT
RECOVERY
PRODUCT
SOLIDIFICATION
-^PRODUCT
ACID GAS
REMOVAL
FUEL GAS
CLAUS
PLANT
MINERAL
RECOVERY
Figure 5. Solvent refined coal (SRC) process.
-------
The dried coal is slurried with hot solvent, an enriched
coal tar fraction, and pumped to the dissolver section. The
coal slurry is preheated and then mixed with hot, hydrogen-
rich gas from the recycle gas stream. This mixture is further
preheated, then passed into the dissolver, where most of the
organic matter is solubilized at 825°F and 1000 psig.
The dissolved coal solution is then sent to a flash vessel
to separate liquids and gases at 995 psig and 625°F. The
gas stream is split; one fraction is combined with make-up
hydrogen for process use, and the other fraction is passed through
an expansion turbine, then to the acid gas removal system for
purification.
The liquid fraction from the flash vessel is further
flashed at 150 psig and 600°F. The liquid is sent to a rotary
precoat type filter. The filter cake, consisting of minerals
and insoluble organics, is washed with a solvent and then further
processed as described later.
The solvent is recovered from the filtrate and various
process fractions. Solvent recovery steps include fractionation,
distillation, and condensation. Separation of solvent from
various off-gas streams and the product is essential for
economics of the process.
The filter cake from the filters is further processed
by drying in a rotary drier at 800°F. The dried filter cake
still contains organic material, and it is burned for power
generation.
The solvent refined coal may be transported as a liquid
or a solid. Typical feed and product (SRC) analysis are
shown in Table 10. Capital and operating cost estimates are
4-12
-------
Table 10. TYPICAL ANALYSIS OF FEED AND SRC PRODUCT
Kentucky No. 11 Coal Wyoming Lignite
Moisture
Ash
Vol . matter
Fixed carbon
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Heat output, BTU/lb
Coal
2.7
7.13
38.67
51.50
70.75
4.69
1.07
3.38
10.28
12,821
SRC
0.48
36.6
62.98
88.16
5.23
1.54
1.17
3.42
15,768
Coal
9.9
4.2
36.46
49.43
64.20
4.58
1.49
0.81
14.82
11,112
SRC
0.17
25.91
73.92
88.21
4.98
2.06
-, 0.45
4.16
15,477
Melting point, °C 220 260
4-13
-------
presented in Table 11.
4.3.2 H Coal Process
H Coal is a development of Hydrocarbon Research, Inc.
In this process, coal is hydrogenated catalytically under
pressure in an ebullated bed reactor. The product is a synthetic
crude oil, which is then processed in a conventional petroleum
refinery.
Coal is prepared to reduce ash and to provide a clean
1 1/4-inch feed, then pulverized in ball mills to minus 40 mesh.
The coal is slurried with an equal weight of oil produced from
the hydrogenation section.
The slurried coal is mixed with hydrogen and a catalyst
and reacted in the ebullated bed reactor at 850°F and 2700 psig.
The synthetic crude oil is depressurized and passed through
liquid cyclones. The bottom fraction is vacuum-distilled and
the vacuum bottoms, including unreacted coal are coked in a
fluid bed coker. The overhead from the cyclones is recycled
to the coal preparation plant for slurry oil.
Hydrogen for the process can be generated via absorption
from refinery gas in mono ethanolamine or via reaction of
refinery gas and char.
Hydrocarbon Research, Inc. is operating a 3-TPD pilot plant.
A process flow sheet is shown in Figure 6, and a typical material
balance is shown in Table 12.
4.3.3 Project COED
FMC Corporation, developing a process under funding from
OCR, has built a 36-TPD pilot plant and operated it since early
4-14
-------
Table 11. CAPITAL AND OPERATING COST, SRC PROCESS
(57,700 tons of coal feed/day)
Capital Investment
Coal preparation
Extraction, separation,
and distillation
Extract hydrogenation
Hydrogen manufacturing
Pollution control
Offsites and utilities
Total
Operating Costs
Coal
Operating supplies
Operating labor and supervision
Maintenance
Overhead
Taxes and insurance
Capital charges (14.1%)
Total
Byproduct credits
Net cost of fuel
Net cost of fuel, C/MM BTU
MM $
16.7
103.5
158.0
246.5
16.7
63.6
605.0
MM$/yr.
171
10.89
3.02
16.0
3.05
12.10
85.46
301.52
10.06
291.46
80.7
4-15
-------
COAL
FUEL G
AND CH
PREPARATION
0]
AS h
AR F
SLURRY
[L
FUEL
GAS
IYDROGEN
>RODUCTION
COAL
HYDRO-
GENATION
COKING
1
NAPHTHA
PROCESSING
H2
\
MIDDLE
DISTILLATE
PROCESSING
H2
\
HEAVY GAS
OIL
PROCESSING
UMOUL1MC.
DOMESTIC
FUEL OIL
NO. 6 FUEL
OIL
SULFUR
RECOVERY
CHAR
Figure 6. H-coal process.
-------
Table 12. TYPICAL MATERIAL BALANCE, H-COAL PROCESS3
(100,000 barrel PSD Refinery)
Tons/Hour
Input Output
1. Coal preparation
Coal feed 1,197
Slurry oil and recycle coal 1,347
Coal slurry - 2,544
2. Hydrogenation
Coal slurry 2,544
Hydrogen 112
Heavy gas oil 24
Naphtha . 164
Middle distillate 284
Oil-coal residue 504
Vent gas 193
H2S, H20, NH 139
Recycle slurry oil 1,252
3. Fluid coking
Oil coal residue 504
Vent gas 0 .6
Coke residue 316
Coke burned 21
Middle and heavy oils 161
4. Oil hydrotreating and distillation
Feed oils 469
Hydrogen 92 74
No. 6 fuel oil 17
Domestic fuel oil 214
Vent gas 23
H9S, H90, NH- 7
Naphtha J 226
5. Naphtha treating and reforming
Feed 404
H-0, H9S, NH 4
Gasoline J 364
Hydrogen 10
Vent gas 25
Losses 0.7
4-17
-------
Table 12 (Continued)
Tons/Hour
Input Output
6. Sulfur and ammonia production
Feed 160
Ammonia product 14
Sulfur product 27
Waste water 118
Waste gas 1
7. Hydrogen production
Feed 207
HO
Waste gas
HO, H S, NH 10
HydrogSn 122
4-18
-------
1971. In the COED process, coal is crushed, dried, and then
heated to successively higher temperatures in a series of
fluidized bed reactors. In each fluidized bed a fraction of
the volatile matter of the coal is released.
The volatile materials are processed to recover oil. The
oil is filtered to remove solids, pressurized, and mixed with
hydrogen and a catalyst to produce a synthetic crude oil. Non-
condensible gas can be sold or used as a fuel. Resultant char
is used as process fuel, and excess char can be used as power
plant fuel and as fuel for hydrogen generators.
The process is shown schematically in Figure 7. Clean coal
crushed to minus 1 inch, dried, fed to the first fluidized bed,
then heated to 600°F. From the first fluidized bed, the partially
devolatilized char passes to the second, third, and fourth
fluid beds, operating at 850, 1000 and 1600°F, respectively.
Combustion of the char in stage 4 provides process heat for
stages 1, 2 and 3.
Product recovery is accomplished by condensing and scrubbing.
Oil mist in the product gas is removed in ESP and spray towers.
Synthetic crude oil is fed to a conventional hydrotreating
plant operating at 750°F and 3000 psig. Products from a plant
processing 3.5 MM tons of coal per year include 14,200 barrels
of oil/day, 5620 tons of char/day, and 90.5 MM SCF of hydrogen/
day. A material balance is shown in Table 13.
4.3.4 USBM - Coal Liquefaction Process
The USBM has been conducting laboratory-scale studies in
a fixed bed reactor. The reactions are carried out using pul-
verized coal in a slurry of recycle oil at 2000-4000 psig.
4-19
-------
PRODUCT
HYDROTREATING
AND RECOVERY
I
NJ
O
COAL —
COAL
PREPARATION
AND
DRIER
1ST
STAGE
REACTOR
PRODUCTS
GAS
GAS
GAS
CLEANING
CHAR
FLUIDIZING
GAS
STAGE 2
STAGE 3
CHAR
STAGE 4
REACTOR
CHAR
FLUIDIZING
GAS
CHAR COOLER
AND RECOVERY
I
CHAR
Figure 7. COED process.
-------
Table 13. TYPICAL MATERIAL BALANCE COED PROCESS
Tons/Hour
Stage 1 reactor
a. Coal feed
b. Fluidizing gas
c. Char
d. H20
e. Oil
f. Gas
Input
416
257
29
Output
404
34
8
257
Stage 2 and 3 reactors
a. Char (from 1 and 4) 534
b. H20 2
5
c. Oil
d. Gas
121
448
23
90
150
Stage 4
a. Char
b. H20
c. Oil
d. Gas
448 203 Product/180 recycle
to 2 and 3
49 114 recycle to 2 and 3
4-21
-------
No conceptual process design is available. A 5-TPD pilot
plant is planned.
4-22
-------
REFERENCES
1. Private communication, American Lurgi Corp.
2. Chemical Systems, Inc. Economic Report on SRC Process
to Office of Coal Research.
3. Foster Wheeler Corp. Engineering Evaluation and Review
of Consolidated Synthetic Fuel Process for Office of
Coal Research.
4. U.S. Department of the Interior. Office of Coal Research.
News Release Dated March 6, 1974.
5. Weekly Energy Report, March 4, 1974. Page 6.
6. American Lurgi Corp. Clean Fuel Gas from Coal.
7. Farnsworth, J., et al. The Production of Gas through a
Commercially Proven Process. Koppers Co. August 1973,
8. Office of Coal Research Annual Report, 1973. Clean
Energy from Coal - a National Priority.
9. Evaluation of Coal-Gasification Technology, Part I
Pipeline Quality Gas. R and D Report No. 74, Office
of Coal Research. 1973.
10. United States Bureau of Mines.
11. Hamilton, G.W. Gasification of Solid Fuels. Cost
Engineering. July 1973.
L
-------
A-l
LURGI GASIFIER
A-l
-------
COAL
7T\
COAL LOCK
HOPPER
y i
>
jy GAS
X
DISTRIBUTOR
GRATE
STEAM
AND
OXYGEN
ASH LOCK
HOPPER
LURGI GASIFIER
The Lurgi Gasifier is based on countercurrent gasification.
Coal is fed through a pressurized lock hopper to the reactor.
The distributor feeds coal uniformly into the reactor. When
caking coals are fed, blades are mounted on the distributor and
are rotated within the feed bed. Oxygen and steam are fed
through the rotating grate. Ash drops through the grate and
is discharged through the ash lock hopper. The steps of the
process are as follows: Coal is devolatilized as it drops to
the bed. The volatile matter and gasification products react.
The char is gasified in the fuel bed. Pressure is about
300 psig. When producing low-BTU gas for utility use air is
used in place of steam.
The first Lurgi pressure gasifier was built in 1936 at the
HIRSCHFELDE Gas Works. In 1940 improved gasifiers were
supplied to produce town gas from lignite. These gasifiers
having a 54 sq. ft. reactor cross-section were built through
1949. In 1950 a pilot plant was built at Hollen to develop
a large-capacity gasifier for manufacture of synthesis gas.
This pilot work led to the construction of 39 gasifiers for
production of synthesis and town gas in Sasolburg, South
Africa; Doston, Germany; Melbourne, Australia; Daud Khel,
Pakistan; Westfield, Scotland; Coleshill, England; and Najin,
Korea. These plants were built during the period 1954-1966.
In 1969, Lurgi began construction of five pressure gasifiers
at the Kellerman Power Station, Steag at Lunen, Germany, for
use in a combined power cycle.
The Lurgi technology is currently being applied in the U.S.
to the production of synthetic natural gas. Texas Eastern
Transmission Corp., Utah International Inc., and Pacific
Lighting Corp. have joined to build a 250-MM-CFD gas plant.
El Paso Natural Gas Co. applied to FPC in November 1972 for
approval to build a 250-MM-CFD plant. Both plants would use
western coals. FPC has not approved either plant as of 8/73.
An important program, sponsored by Continental Oil Co. and
others, is construction of a methanation unit at the Westfield,
Scotland, gas plant to produce 2.6 MM-CFD of SNG. This would
be the first commercial SNG from a coal plant; the system is
due to be tested by the end of 1974.
-------
Estimated cost of each of the 250 MM CFD plants is about
$330 million.
References:
1) Otto W. Tadei, Vice-President Sales, Lurgi.
2) "The Lurgi Process - The Route to SNG from Coal" presented
at the 4th Syn. Pipeline Gas Symp. October 1972.
3) "Lurgi Pressure Gasification" Lurgi Bulletin 01018/12-71.
4) "Clean Fuel Gas from Coal" Lurgi Bulletin 01007/10-71.
-------
LURGI SNG PLANT, 250 MM SCFD
(Date of cost basis: 1971)
Capital Cost, Millions of dollars
Coal storage and preparation 23.80
Coal gasification 39.24
Gas cooling 9.71
Shift conversion included in gas cooling
Methanation 13.97
Compression 5.04
91.76
Oxygen plant 35.95
Sulfur recovery 7.40
Water pollution control 8.91
Steam and power plant 27.45
General utilities 10.96
General offsites 16.97
107.64
Total plant investment 199.40
Contingency 25.43
Total 224.83
Interest during construction 35.00
Startup costs 13.00
Working capital 12.00
284.83
Cost Estimate from The Final Report of the Supply - Technical
Adv. Task Force Synthetic Gas - Coal, FPC.
A-4
-------
LURGI LOW-BTU GAS PRODUCER, 330 MW PLANT
(Date of cost basis: 1971)
Fuel rate
HHV, fuel
Efficiency
Labor
Water
Process
Cooling
Power
Capital costs
Daily operating costs
Labor
Utilities
Maintenance
Fixed costs
Fuel
Total daily cost
179 TPH
9500 BTU/lb
80%
14,000 gph
2,500,000 gph
$16,500,000
3,500
1,425
3,500
4,217
24,473
$37,115
= 57C/MM BTU
Source "Clean Fuel Gas from Coal" Lurgi. Bulletin 0.1007/10.71
These costs are derived from cost analysis of combined cycle
plant. Cost could easily exceed 60C/MM BTU. Fuel cost is
30C/MM BTU.
A-5
-------
CO
o
.0
•LU
o
-CM
2.60
2.40
2.20
2.00
1 .80
1.60
1 .40
.1.20
1.00
0.80
0.60
I
1
I
1975 1980 1985
YEAR OF PLANT STARTUP
1990
Cost of High BTU Gas Produced by Lurgi Process
Reference: RPC - Final Report "The Supply-Technical
Advisory Task Force-Synthetic Gas-Coal
A-6
-------
A-2
KOPPERS - TOTZEK GASIFIER
A-7
-------
GAS
COAL
00
COAL
OXYGEN
STEAM
ASH OR
SLAG
The Koppers-Totzek gasifier is an oxygen-blown
pressure gasifier, operating in concurrent flow.
Concurrent gasification produces no tars and
therefore eliminates the need for cleanup of
oils and tars. Each gasifier has four burners.
Pulverized coal is fed into each burner. The
gasifier operates at high temperature. Gasifi-
cation products are 300-BTU gas at 2 psig.
From 1949 to 1972, 56 Koppers-Totzek gasifiers
units have been installed in France, Finland,
Japan, Spain, Belgium, Portugal, Greece, URA,
Thailand, Turkey, Germany, Zambia, India, and
South Africa.
Koppers Co., Pittsburgh, Pennsylvania, is
marketing Koppers-Totzek gasifiers in the U.S.
Reference: Koppers Co. (U.S.) Literature.
KOPPERS-TOTZEK GASIFICATION
-------
KOPPERS-TOTZEK PROCESS
LOW-BTU GAS, 300 MW PLANT
(Date of cost basis, 1971-72; basis is amount per 1000 NCM
of CO,, and H0)
Plant capacity
Fuel rate
Fuel HHV
Efficiency
Labor
Water
Power
Published
620 Kg
6,480 KCal
90%
236 Kg
32 KWH
Capital investment including oxygen plant
160
to
o
•o
0 120
-------
1.20
1.10
CO
Ll_
O
2: i.oo
CO
UJ CO
to
• s:
UJ3E
CO "-^
*f •*>•
oe.
0.90
f?; 0.80
o
CM
0.70
KOPPERS-TOTZEK PROCESS, LOW-BTU GAS
Operating Cost - $72,150 per day
70
140
210
280
Output, billions of BTU/day
Koppers-Totzek Average Operating Costs at $72,150 Per Day
300 BTU/SCF at 2 psig
A-10
-------
A-3
WELLMAN-GALUSHA GASIFIER
A-H
-------
COAL STORAGE
LOCK HOPPER
I
GAS
AIR
The Wellman-Galusha gasifier is built in two standard
types, agitated and nonagitated. Coal is fed into a lock
hopper and then by gravity into the gasifier. The ash
removal and fuel feed rate are synchronized. In the
agitated producer, the agitator is slow moving and is
located below the surface of the fuel bed. The agitator
increases the production rate of the unit. Although the
blast is typically air-steam, oxygen-steam units have
been operated on coke. Operation with all types of fuel,
including bituminous, is claimed.
Maximum size of units is 10-foot diameter, producing
80 MM BTU/hour. Wellman has sold a 10-foot-diameter
unit to gasify anthracite coal ^ 1 TPH. Sale was supply
only, $135,000. Output 25 MM BTU/hr. Unit was sold to
Glen Gerry Brick Corp., Reading, Pennsylvania. W-G
built a high-pressure gasifier for USBM at Morgantown.
They have applied to OCR for funds to build a prototype
25-foot-diameter gasifier using oxygen at high pressure
to compete with Lurgi for production of high-BTU gas.
Reference:
1) George Hamilton, W-G.
2) Gasification of Solid Fuels, Cost Eng.
July 1963 pp 4-11.
STEAM
ASH
WELLMAN-GALUSHA GASIFIER
-------
WELLMAN-GALUSHA LOW-BTU GAS PRODUCER, 50 MM BTU/hr
(Date of cost basis: 1963)
Fuel rate
Fuel HHV
Efficiency
Labor
Water
Process
Cooling
Power
Capital costs (installed)
Daily operating costs
Labor @ 2.50/hr
Water @ 10C/M
Power § 1C/KWH
Maintenance @ 3%
Fixed costs, 10 yr.
Interest
Fuel $8.5/T
Published
4116 Ib/hr
13,500 BTU/lb
90%
1/3 man per shift
3/4 gal/lb fuel
7200 gpd
18 KWH/T of fuel
$140,000
20
8.13
8.89
11.50
38.35
419.90
TOTAL
Cost of gas
506.77
42C/MM
A-13
-------
A-4
ADVANCED GASIFIERS
A-14
-------
-»• GAS
COAL
i
M
U1
\ /
SLURRY
LIGHT
OIL
CHAR
STEAM
AND CO
ELECTRIC
"POWER
ELECTRO
GASIFIER
-*- CHAR
Hygas-Institute of Gas Technology is operating
a pilot plant at their facility near Chicago.
Among three conceptual Hygas processes the
differences are primarily in the methods of
generating hydrogen and CO. The Electrothermal
Hygas system is included in the pilot plant. A
Steam Oxygen Hygas is under construction. In
the Electrothermal Hygas process, gasification
takes place in fluidized bed reactors. Coal
is dried, pulverized, and pretreated (caking
coals) with air. It is then slurried with a
light oil, pumped to a vessel at 1500 psi and
600 degrees F, where solvent is recovered. The
coal is devolatilized at 1300-1500°F, then
gasified at 1700°F. Some of the char is fed
to the Electrothermal gasifiers and is reacted
with steam at 1900°F to produce H2 for the
methanation step.
Since 1964 a total of about $38.2 million has
been committed to Hygas coal gasification
by its sponsors.
HYGAS SYSTEM, ELECTROTHERMAL MODE
-------
COAL
JL
STEAM
OXYGEN
The Synthane Process, USBM, entails a
fluidized bed, pressure gasification system
with pretreatment for caking coals. A 75-TPD
plant is under construction and is scheduled
to operate in 1974. The process operates
at 1000 psig at 1400°F.
GAS
STEAM
OXYGEN
ASH
AND
CHAR
SYNTHANE PROCESS USBM
-------
GAS
CYCLONE
COAL'
STAGE 2
>
t
STEAM
STEAM-
STAGE 1
V
RECYCLE
OXYGEN
In the Bi Gas process (Bituminous Coal Research
Inc.)/ pulverized coal is fed to the bottom of the
upper section of a two-stage unit and is carried
concurrently with a stream of hot synthesis gas
produced in the lower section by the action of
oxygen and steam on the residual char. The
gasifier operates at 50-100 atmospheres and
produces gas at 700°F. Char from Stage 2
is gasified with steam and oxygen in Stage 1.
This process has been developed only on a
small scale (100 Ib/hr). Construction of a
5-TPH plant is to be completed by late 1974 or
early 1975.
SLAG
B! GAS PROCESS
-------
GAS
COAL
DEVOLATIZ^
H
00
CHAR
AND
SORBENT
FRESH
SORBENT
GASIFIER
SORBENT
REGENERATOR
SORBENT
AIR
CHAR AND
SORBENT
The CO_ Acceptor Process (Consolidation Coal Co.)
was designed to operate on lignite and Western
coals. The unique feature of this process is
circulation of calcined dolomite through a
fluidized bed of char. Reaction of the dolomite
with carbon dioxide liberates sufficient heat
to sustain the energy-requiring carbon-steam
reaction. The product gas is enriched in methane
A 1.5-TPD pilot plant has been built in North
Dakota and is under test. Work is funded by AGA-OCR.
Work is being conducted on a laboratory scale to
enable the use of pretreated bituminous coals in
the CO~ acceptor system.
STEAM
C02 ACCEPTOR PROCESS
-------
CAPITAL COSTS OF ADVANCED GASIFIERS:
HY GAS, BI GAS, CO2 ACCEPTOR, AND SYNTHANE (250 MM CFD plant)
Typical Capital Cost, millions
of dollars
Plant investment
Investment during
construction
Startup costs
Working capital
2.20
2.00
1.80
s K6°
oo
CJJ
LjJ
C3
<£
LU
>-
O
CO
1 .40
1 .20
1 .00
0.80
0.70
210.0
35.4
12.0
12.0
269.4
I
I
I
1990
1975 1980 1985
Year of plant startup
Cost of High-BTU Gas from Advanced Gasification Processes
A-19
-------
CO2 ACCEPTOR - COST OF LOW-BTU GAS
(Date of cost basis:
Plant capacity
Fuel rate
HHV
Efficiency
Water
Process
Cooling
Power
Capital cost, installed
(includes off sites
and utilities)
Operating cost, annual
TOTAL
Gas cost
Fuel - 30C/MM BTU
1971)
Published
10,286.6 MM BTU/hr
578.5 TPH
11,940
75%
731,300 #/hr
1,000,000 gph
$112,400,000
$35,290,000
60C/MM BTU
A-20
-------
BIBLIOGRAPHY
Cochran, N.P. Conversion of Coal to Oil and Gas, 12th Annual
Institute on Petroleum Exploration and Economics. (Dallas)
March 15-16, 1972.
Davies, H.E., et.al, Processes for the Manufacture of Natural
Gas Substitutes. Gas Council Research Communication GC155,
Research Meeting of the Institute of Gas Engineers (London).
November 1968.
Office of Coal Research Annual Report, 1972.
Engineering Study and Technical Evaluation of the Bituminous
Coal Research, Inc., Two-Stage Super Pressure Gasification
Process. Air Products and Chemicals, Inc., G.P.O., No.
I 63:10:60.
Katel, S. et.al., An Economic Evaluation of Synthane
Gasification for the Production of Pipeline Gas from Coal.
Trans AACE, 1972.
Calancy, J.T. and Marwig, U.D. Pipeline Gas from Lignite
Gasification - Current Commercial Economics. G.P.O. Catalog
No. I 63:10:16/INT 4, 1970.
Long, G. Why Methanate SNG? Hydrocarbon Processing. August
1972.
Review of U.S. Bureau of Mines Coal Program, 1969. U.S.
Bureau of Mines 1C.8479. July 1970.
Office of Coal Research Annual Report, 1971.
Clancey, J.T. An Interim Study of the Economics of Pipeline
Gas from Lignite. Consolidation Coal Co. (Presented at
AISE Meeting. May 1969.)
Energy: 2000 AD. Power Engineering. August 1972. p. 24-29.
LNG: A Sulfur-Free Fuel for Power Generation. Institute of
Gas Technology. May 1969.
Squires, A.M. Clean Power from Coal. Science. August 1970.
Vol. 169, No. 3948. p. 821-828.
-------
Robson, F.L., et.al., Technological and Economic Feasibility
of Advanced Power Cycles and Methods of Producing Non-Polluting
Fuels for Utility Power Stations, United Aircraft Research Lab,
Final Report, NAPCA Contract No. CPA-22-69-114.
Linden, H.R. Coal Gasification and the Coal Mining Industry.
(Presented at SME Meeting. February 1969.)
Henry, J.P., Jr., et.al. An Economical Study of Pipeline Gas
Production from Coal. Chemical Technology. April 1971.
p. 238-247.
Squires, A.M. Clean power from Coal, At a Profit. (Presented
at the Meeting of the American Association for the Advancement
of Science. Boston. December 1969.)
Coal Gasification - One Company's View. Colorado Interstate
Gas Co. (Presented at AIChE Meeting. March 1973.)
Lowry, H.H., Ed. Coal Gasification, Chemistry of Coal Utility
Vol II.
Klingman, G.E., et.al. Make SNG from Coal. Fluor Corp.
Hydrocarbon Processing. April 1972. p. 97-101.
Gas from Coal, Power Engineering, February 1973. p. 32-39.
Coal Gasification - A Progress Report. Coal Mining and
Processing. August 1972.
Lurgi, O. Lurgi Pressure Gasification Performance Record.
Lurgi 0-1018/12.71.
Lurgi, O. The Lurgi Process. The Route to S.N.G. from Coal.
List of Plants for the Gasification of All Kinds of Fuels
by Koppers-Totzek. Koppers Co. Germany. 1973.
Synthesis of Gas through Gasification of All Kinds of Fuel
by the Koppers-Totzek Process, Koppers. 1973.
Coal Gasification for Clean Energy. Koppers Bulletin. 1973.
Wellman-Galusha. Gas Equipment. The McDowell-Wellman
Companies. Bulletin 147.
Annual Report. Consolidated Coal Co. to EPA, GAP, Contract
No. EHSD-71-15, November 1971.
Cover, A.E., et.al. The Kellogg Coal Gasification Process.
M.W. Kellogg Co., Houston, Texas.
-------
Bi Gas Program Enters Pilot Plant Stage. BCR Report. 1972.
Cost Estimate of a 500 Billion BTU/Day Pipeline Gas Plant
via HG and ET Gasification of Lignite. IGT Report to Office
of Coal Research, Contract 14-01-0001-381.
------- |