United States
Environmental Protection
Agency
Office of
Research and Development
Washington, D.C. 20460
EPA-600/7-77-102
JULY 1977
EPA PROGRAM STATUS REPORT:
SYNTHETIC FUELS FROM COAL
INCLUDING PROCESS OVERVIEW WITH EMPHASIS
ON ENVIRONMENTAL CONSIDERATIONS
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental Protection Agency,
have been grouped into seven series. These seven broad categories were established to facilitate
further development and application of environmental technology. Elimination of traditional grouping
was consciously planned to foster technology transfer and a maximum interface in related fields. The
seven series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERACENCY ENERGY-ENVIRONMENT RESEARCH AND DE-
VELOPMENT series. Reports in this series result from the effort funded under the 17-agency Federal
Energy/Environment Research and Development Program. These studies relate to EPA's mission to
protect the public health and welfare from adverse effects of pollutants associated with energy
systems. The goal of the Program is to assure the rapid development of domestic energy supplies in an
environmentally-compatible manner by providing the necessary environmental data and control
technology. Investigations include analyses of the transport of energy-related pollutants and their
health and ecological effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environmental issues.
This document is available to the public through the National Technical Information Service,
Springfield, Virginia 22151.
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EPA-600/7-77-102
|uly1977
EPA PROGRAM STATUS REPORT:
SYNTHETIC FUELS FROM COAL
INCLUDING PROCESS OVERVIEW WITH EMPHASIS
ON ENVIRONMENTAL CONSIDERATIONS
prepared by
Linda Eckstein
Charles Hook
Donald Roe
Joseph Zalkind
Cameron Engineers, Inc.
1315 South Clarkson Street
Denver, Colorado 80210
Morris Altschuler
Office of Energy, Minerals, and Industry
Environmental Protection Agency
Washington, D.C. 20460
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EPA REVIEW NOTICE
This report has been reviewed by the Office of Research and Development, EPA, and approved for pub-
lication. Approval does not signify that the contents necessarily reflect the views and policies of the En-
vironmental Protection Agency, nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
This document is available to the public through the National Technical Information Service, Springfield,
VA.22151
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FOREWORD
This report is both a status report on EPA projects related to synthetic fuels from coal, and an overview
of a number of significant processes for coal conversion. Together, they provide under a single editorial
umbrella a comprehensive, detailed review of EPA's expanding program in this important area of fossil
fuels.
in
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ACKNOWLEDGMENTS
The authors wish to thank Mr. William N. McCarthy, Jr., U.S. Environmental Protection Agency, Office
of Energy, Minerals, and Industry, and Mr. A. C. Pocius, Cameron Engineers, Department of Management
Services, for their invaluable help in coordinating the many facets of this report.
Thanks also go to Mr. William ). Rhodes and Mr. T. Kelly Janes at the Environmental Protection Agency's
Research Triangle Park Laboratory in North Carolina for their indispensable assistance in providing data
and review comments; to Mr. Gene Jojola and his able assistants in the Cameron Engineers Illustration and
Printing Department - Jerry Medford, Al Valverde and Jerry Mills - for their quick response to graphics needs;
to Jolene Webb, Shirley Johnson, Pearl Richardson, and Becky Pryor for their patience in typing and proof-
ing; and to Thayer Masoner, Tom Hendrickson, Ted Borer, Agnes Dubberly, Andy Karr and Craig Moseley,
all of Cameron Engineers, for their all-around knowledge and on-the-spot help.
IV
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TABLE OF CONTENTS
Page
PART I EPA PROGRAM STATUS REPORT
1. Introduction and Summary 1
2. Program Background and Overview 3
3. Current Program Status 5
PART II PROCESS OVERVIEWS
GASIFICATION PROCESSES
1. BI-GAS .' 13
2. CO2 Acceptor 19
3. Coalcon 25
4. HYGAS 29
5. Koppers-Totzek 35
6. Lurgi 41
7. Slagging/Lurgi 51
8. Synthane 57
9. Wellman-Galusha 63
10. Winkler 67
LIQUEFACTION PROCESSES
11. Char-Oil Energy Development (COED) 73
12. Donor Solvent 79
13. Fischer-Tropsch 81
14. H-Coal 83
15. Solvent Refined Coal (SRC) 87
APPENDICES
A Auxiliary Facilities 95
B Coal Storage and Preparation 97
C Summary of Processes 99
D List of Abbreviations 101
E Conversion Factors 103
F General References 105
G EPA Reports on Synthetic Fuels from Coal 107
H Glossary 111
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LIST OF FIGURES
Page
1 -1. BI-GAS Process Schematic 13
1-2. BI-GAS Process - Effluents Summary 16
2-1. CO2 Acceptor Process Schematic 19
2-2. CC>2 Acceptor Process - Effluents Summary 22
3-1. Coalcon Process Schematic 25
4-1. HYCAS Process Schematic 29
4-2. HYCAS Process - Effluents Summary 32
5-1. Koppers-Totzek Process Schematic 36
5-2. Koppers-Totzek Process - Effluents Summary 38
6-1. Lurgi Process Schematic 42
6-2. Lurgi Process - Effluents Summary 44
7-1. Grand Forks Slagging Gasification Pilot Plant
Process Schematic 52
7-2. Slagging/Lurgi Process - Effluents Summary 55
8-1. Synthane Process Schematic 58
8-2. Synthane Process - Effluents Summary 60
9-1. Wellman-Galusha Process Schematic 64
10-1. Winkler Process Schematic 68
10-2. Winkler Process-Effluents Summary 70
11-1. COED Process Schematic 74
11-2. COED Process - Effluents Summary 76
12-1. Donor Solvent Process Schematic 79
13-1. Fischer-Tropsch Process Schematic 81
14-1. H-Coal Process Schematic 83
15-1. SRC Process Schematic 87
15-2. SRC Process - Effluents Summary 90
vi
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LIST OF TABLES
Page
PART I EPA PROGRAM STATUS REPORT
1. Level of Funding-Fiscal Year 1977 9
PART II PROCESS OVERVIEWS
1-1. BI-CAS Process Sulfur Balance 17
2-1. CO2 Acceptor Process Sulfur Balance 24
3-1. Coalcon Process Sulfur Balance : 27
4-1. HYCAS Process Sulfur Balance 34
6-1. Lurgi Process Sulfur Balance 49
7-1. United States Companies Sponsoring the Westfield
Slagging Gasifier Project 53
8-1. Synthane Process Sulfur Balance 62
10-1. Winkler Process Sulfur Balance 72
11-1. COED Process Sulfur Balance 77
14-1. H-Coal Process Sulfur Balance 85
15-1. SRC Process Sulfur Balance 91
VII
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PART I
EPA PROGRAM STATUS REPORT
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PAGE NOT
AVAILABLE
DIGITALLY
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1. INTRODUCTION AND SUMMARY
As domestic supplies of natural gas and oil
dwindle, the nation is being forced to seek out al-
ternatives. A significant alternative is coal, and
in The National Energy Plan, presented by Pres-
ident Carter on April 29,1977, an expansion in the
Government's coal research and development
program is strongly encouraged:
"Coal will meet the greatest portion of in-
creased U.S. energy needs. A comprehensive
coal research and development program is a
high priority. The program should focus on
meeting environmental requirements more
effectively and economically, and should seek
to expand the substitution of coal for natural
gas and petroleum products."
Included among the highest priorities are pro-
grams to develop environmentally sound and ec-
onomically viable processes for converting coal
into gas and oil, or synthetic fuels as they are
called. Synthetic fuels are especially important
in that they can be used in such urgent areas as
transportation and residential heating. A secondary
factor simulating interest has been the difficulty
of converting oil- and gas-burning power units
to coal. A large number of industrial boilers can-
not be switched to coal because of design consid-
erations, while plants technically capable of
making the change have the economic problem
of purchasing unloading, conveying, storage, ash-
handling and air-cleaning equipment. A better
option may be to replace natural gas and oil with
synthetics extracted from coal.
Whatever options are chosen, they must meet
energy goals without damaging the environment.
As the Energy Plan notes:
"Attainment and maintenance of the en-
vironmental goals set out in the Clean Air
Act, the Federal Water Pollution Control Act,
and the National Environmental Policy Act
are high national priorities. The Admin-
istration intends to achieve its energy goals
without endangering the public health or
degrading the environment."
Processes for extracting gas and oil from coal
may produce substances harmful to health and the
environment. Present data characterizing the various
technologies have been too limited to make judg-
ments as to their acceptability or to set regulatory
standards.
As a result, the Environmental Protection Agen-
cy (EPA) and the Energy Research and Develop-
ment Administration (ERDA) have been directed to
establish a thorough, ongoing joint effort aimed at
parallel ERDA energy development and EPA con-
trol of environmental impact. EPA will set up pro-
cedures for determining environmental standards,
and is to make certain that standards and pollution
controls are in effect before the new technologies
are ready for commercial use.
EPA's main goal is to see to it that any needed
add-on control measures are developed. If in-pro-
cess technology is required to control pollution,
first responsibility for developing it rests with
those organizations (government and private) de-
veloping the basic conversion process. However,
if this responsibility is not met, EPA is required to
pursue in-process development in specific areas.
EPA has also undertaken the coordination of all
governmental research and development efforts
for environmental control of synthetic fuel pro-
duction and use.
Basically, EPA's roles are to assess the environ-
mental impacts from synthetic fuels processes and
to determine appropriate pollution control tech-
nology. The work involves an assessment of pro-
cesses already in use and an estimation of which
processes in various stages of development are
most likely to reach commercial application. Con-
sidering the many technologies that are in the ex-
perimental state and the technical and economic
variables attendant to them, EPA's task is quite com-
plex.
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There must be a continual review of the state-of- Part 11 of this report should in no way be viewed as
the-art in synthetic fuels technology. Unfeasible final. Constant updating will be required, and future
processes must be dropped and new ones added as reports on synthetic fuels from coal may cover a
technical, cost, and pollution factors become evi- different selection of processes.
dent. For these reasons, the processes described in
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2. PROGRAM BACKGROUND AND OVERVIEW
The production of synthetic fuels from coal is
not new. In the early part of the 1800's, street
lamps used gas from coal. In this century many
American and European cities had "gasworks" that
manufactured gas from coal for use in homes
and industry. The coat gas used was high in car-
bon monoxide content and would not be permitted
in households today. During World War tl a fuel oil
suitable for military use was produced from coal in
Germany. More recently, coal-to-gas conversion has
been performed on a commercial scale in Europe
and South Africa. In the U.S., several Wellman-
Galusha Gasifiers, manufactured by McDowell-
Wellman Engineering Company of Cleveland, Ohio,
are serving industrial plants.
EPA's Synthetic Fuels from Coal Program began
in 1972. The program was expanded for many rea-
sons: the impetus of the 1973 oil embargo, the re-
sulting increases in the price of petroleum, and the
subsequent need to find alternatives to oil. Justifi-
cation for EPA's increased role comes from the re-
alization that chemicals with adverse, health-related
effects might be generated when coal, the primary
alternative, has its chemical matrix torn apart during
conversion.
To put the problem in perspective, a coal gasifi-
cation plant producing 250 million standard cubic
feet per day of pipeline gas from eastern U.S. bitu-
minous coal will require about 52 million pounds
per day of coal input. Assuming 3.5 percent by
weight sulfur content in the feed, a typical value
for eastern bituminous coal, 1,820,000 pounds of
sulfur compounds per day will flow through the
plant.
Hundreds of compounds are among the products
of reactions involved in the process of converting
coal to synthetic fuels. With this in mind, EPA's ini-
tial emphasis was on pollutant evaluation and re-
lated data collection. Work was also started on
more complex environmental assessments and
control technology developments (which incor-
porate economic analyses) and on bench-scale
demonstrations. Early accomplishments included:
• Chemical and physical characterization of
the pollution potential of over 100 U.S. coals
likely to be used for conversion to oil and gas;
• A symposium on the health and environmental
effects and control technology of energy use,
which provided a status of activities;
• Identification of the pollution potential and
evaluation of available pollution control in
seven processes for gasification; Koppers-
Totzek, Synthane, etc., and three for lique-
faction; Char-Oil Energy Development (COED),
Solvent Refined Coal (SRC), and H-Coal;
• Analysis of the problems and opportunities
of retrofitting industrial processes to use low-
Btu synthetic gas;
• Bench-scale demonstration of an effective
method for desulfurization of high tempera-
ture acidic gases.
Recent efforts have expanded on the work begun
earlier. Projects, conducted by private contractors,
are now underway in the areas of environmental
assessment and control technology development,
including pilot, demonstration, and test projects.
Funding comes directly from EPA or in some cases
from money passed by EPA through ERDA, so-called
pass-through funds,
Environmental assessment: All potential pollu-
tants are being identified and characterized. Infor-
mation generated by sources outside EPA is being
collected and assimilated. Each major category
within synthetic fuels from coal technology is under
study: low-Btu and high-Btu gasification, and lique-
faction. Emphasis is on commercial or near com-
mercial processes but also includes just develop-
ing processes. Assessment will determine what pol-
lutants can be controlled or disposed of in an en-
vironmentally sound manner and the costs of vari-
ous control or disposal options. Best control prac-
tices will be identified and standards of practice
manuals published. Research and development
needs will be defined, as will siting criteria for syn-
thetic fuel manufacturing plants.
Control technology development: To facilitate ef-
forts the work has been divided into three areas
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common to all processes: (1) pretreatment, water,
and waste management, (2) converter output
streams, and (3) products and by-products. All areas
involve the evaluation of control technology for
ensuring that effluents meet environmental stan-
dards, and, where necessary, the development of
controls to meet requirements. The first area is con-
cerned with crushing, grinding, and other treat-
ment necessary before the coal can be converted
to oil or gas. It also deals with water and waste
streams, not only for pre-treatment, but for conver-
sion and auxiliary steps. The second area is concern-
ed with effluents from the conversion reactor itself,
while the third area is to ensure that products and
by-products are environmentally sound in their
utilization.
One contractor is working in each of the three
areas. Contractors use other organizations as nec-
essary, but make themselves the focal point for ac-
complishing the required work. Studies are being
conducted to develop, evaluate, and, where needed,
demonstrate control technology for air and water
pollution, solid residues, and other environmental
problems associated with each of the three phases.
Transfer of pollution control technology from petro-
leum refining and processing, metallurgical coal pro-
cessing, and coking will be considered. Efforts are
being coordinated with other government agencies
as well as foreign countries to reduce costs and
avoid duplication of efforts.
Pilot, demonstration, and test projects are an
extension of environmental assessment and control
technology development. Specifically, the charac-
terization of air and water pollution, solid residues,
and other environmental problems will be continued
through tests on operating units. A selected num-
ber of air, water, and solid samples will be compre-
hensively analyzed and submitted for biological
screening tests. Evaluation of the Yugoslavian Lurgi
plant will be expanded to whatever extent negoti-
ations, technology, and funds will permit. Work on
the Slagging/Lurgi Gasifier and similar units will
also be initiated. Emphasis on joint EPA/ERDA
testing of low-Btu industrial gasifiers will be
continued as appropriate. The bulk of fiscal
year (FY) '75-77 pass-through funds to ERDA
($1.4 million) were for the Grand Forks Energy
Research Center, Grand Forks, North Dakota,
and the Morgantown Energy Research Center, Mor-
gantown. West Virginia. The former is operating a
pilot plant in slagging, fixed-bed gasification, while
the latter is running a low-Btu pilot plant (a fixed-
bed gasifier similar to the Wellman-Galusha and
Lurgi). These and other programs are described with
more detail in "Current Program Status."
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3.CURRENT PROGRAM STATUS
Each EPA-funded program relates to more than
one of the processes described in Part II of this
report. The same is true for programs supported by
pass-through funds.
In this chapter, each program is summarized.
Abbreviated titles used to identify programs at
EPA's Industrial Environmental Research Labora-
tory, Research Triangle Park, North Carolina, are
given in parentheses. Goals are presented, as are
the latest accomplishments. Processes covered by
a program are noted. A pie chart showing overall
funding and funding breakdown then follows.
3.1 ENVIRONMENTAL ASSESSMENT (EA)
The Illinois State Geological Survey, Urbana, Il-
linois, has been characterizing the chemical nature
of coal and coal residues (Characterization of Coal
and Residues). Current work is an extension of pre-
vious studies in which over 100 coals and their geo-
chemical significance were analyzed. Complete
chemical, physical, and mineralogical evaluations
of slags, ashes, chars, cleaning wastes, and resi-
dues are being conducted. These chemical and
mineralogical characteristics are being related to
chemical solubilities at several pH's and to bio-
logical toxicity of aqueous extracts of the solid
waste residues. Term of the present contract is
from November 1976 to November 1978. Overall
progress has involved completing the chemical
characterization of eleven coal solid waste samples.
Insofar as the research concerns coal that can be
used in the production of synthetic fuels, the pro-
ject affects all processes.
The Energy and Environmental Research Division
of the Research Triangle Institute (RTI), Research
Triangle Park, North Carolina, is investigating fac-
tors and conditions which cause the production of
pollutants from synthetic fuel processes (Non-Iso-
thermal Pollutant Identification). Emphasis is on
pollutant production, an area that has been gener-
ally neglected in other research and development
efforts. The five-year project, lasting from November
1976 to October 1981, will touch on areas involving
all processes for producing synthetic fuels from coal.
The kinetics of pollutant formation is of major con-
cern. Construction of the batch gasifiers and as-
sembly of the sampling and analytical equipment
is nearly complete. In the meantime, tar samples
from operating synthetic fuels processes are being
used to develop methods for organic fractionation
to identify specific compounds. Specifications have
been written for a computerized data acquisition
system to allow testing for the numerous, complex
substances formed by coal conversion.
Two separate programs being conducted by the
same company involve (1) characterizing and treat-
ing wastewater, and (2) reducing the usage of water
in coal conversion systems. Water Purification As-
sociates (WPA), Cambridge, Massachusetts, is
conducting the related projects, the first of which
is an ERDA Program supported by pass-through
funds from EPA, and the second of which is financed
directly by EPA.
The ERDA project is a paper study in which six
sites have been selected for conceptual designs of
integrated water treatment plants for coal conver-
sion (Wastewater Characterization Study). The Pro-
gram, which began in April 1977, will last for 18
months. Specific processes, as yet undetermined,
will be studied. Initial work is reviewing phenol re-
moval and recovery.
The second program is a study of water require-
ments, availability, conservation, and pollution
controls for certain coal conversion processes at
various sites in three western states (Water Usage
in Coal Conversion). The project runs from Septem-
ber 1976 to September 1978. Work is on schedule,
with a report being issued. The study describes var-
ious processes, such as Lurgi, BI-GAS, SRC, and Syn-
thane, with emphasis related to their water, heating,
and cooling requirements for some of the processes,
including electrical power generation from coal.
Processes that have been addressed by the program
are Lurgi, BI-GAS, CO2 Acceptor, HYGAS, Winkler,
Koppers-Totzek, SRC, and H-Coal.
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Battelle Columbus Laboratories, Columbus, Ohio,
has a program underway related to the removal of
contaminants from fuel (Fuel Contaminants, Phase
Il-Screening Studies of Removal Techniques). The
program is examining certain exploratory methods
of pollutant removal that have warranted further
attention. Term of the contract is from April 1977
to April 1978. This project overlaps with the Fuel
Cleaning Program.
The Radian Corporation, Austin, Texas, is eval-
uating environmental impacts from technology for
converting coal into low- and medium-Btu gas (EA,
Low-Btu Gasification). The utilization of the resulting
gases by combustion processes will also be envi-
ronmentally analyzed. Technologies covered under
the program are several in number, including the
Lurgi, Wellman-Galusha, and Koppers-Totzek for
processes described in Part II of this report. Collec-
tion and interpretation of the existing data base
are nearing completion. Preparation for further
data acquisition is taking place through test manual
preparation, site visits, trial analytical runs, and
equipment purchases. A report has been issued on
in-situ coal gasification. Environmental assessment
methodologies are being developed and evaluated.
Term of the contract is from March 1976 to March
1979.
Also part of the effort to assess low-Btu gasifica-
tion is a cooperative effort between EPA and ERDA.
The two agencies are cooperating to evaluate small-
sized, individual, environmentally compatible gasi-
fiers in ERDA's Industrial Program which use up to
200 tons of coal per day (ERDA Industrial Gasifiers).
The gasifiers will serve as a practical energy source,
as a basis for obtaining data to make improvements
in technology, and as a source of environmental
data. Potential users of the low-Btu gas to be pro-
duced include metal treating, processing, and form-
ing plants; brick, lime or ceramic production facil-
ities, and chemical plants.
The ERDA gasifier program began in early 1976.
Agreements have been signed by ERDA with:
• ACUREX Aerotherm, to produce fuel for use in
a brick kiln at the Glen-Gery Company plant
in York, Pennsylvania;
• The University of Minnesota, Minneapolis, to
produce boiler fuel for space heating of the
Duluth Campus;
• Pike County, Kentucky, to provide boiler fuel
for heating and cooling of housing, a fire sta-
tion, school, shopping center, and fuel for an
industrial park near Pikeville.
TRW, Inc., Redondo Beach, California, will assess
environmental impacts from technology for con-
verting coal into high-Btu gas (EA, High-Btu Gas-
ification). Term of the contract is from May 1977
to May 1980. Processes to be covered include Bl-
GAS, Synthane, HYGAS, CC»2 Acceptor, Slagging/
Lurgi Gasifier, and others as appropriate. The goal
is to determine the environmental degradation that
would occur from the operation of commercial in-
stallations and to identify control technology re-
quired to reduce or eliminate the adverse environ-
mental impact.
Hittman Associates, Columbia, Maryland, is as-
sessing environmental impacts of technologies for
converting coal into liquid fuels (EA, Liquefaction).
The utilization of these liquid fuels in stationary
sources will also be environmentally analyzed. Pro-
cesses covered by this program include Coalcon,
COED, SRC, H-Coal, Donor Solvent, and Fischer-
Tropsch. Term of the contract is from July 1976 to
July 1979. Collection and interpretation of the ex-
isting data base are proceeding. An overview report
is being prepared. Site visits have been made to ex-
plore further data acquisition potential. Suggestions
are under formulation for a test program on the SRC
Process at Fort Lewis, Washington. Data acqui-
sition has also been conducted on the SRC com-
bustion tests at Plant Mitchell, Georgia.
United Technologies Research Center, East Hart-
ford, Connecticut, is conducting an analytical study
to define the performance and cost of power conver-
sion systems, including those for coal gasification.
This contract began in September 1976 and contin-
ues until January 1978. Emphasis is on a process
similar to BI-GAS, supplying fuel to combined gas
turbine and steam cycles. Other gasifiers are exam-
ined. High temperature gas cleaning as well as liq-
uid scrubbing techniques are included in the sulfur
removal options considered in the work. The final
task of the work plan now being addressed is an
overview of the environmental effects of these inte-
grated systems.
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EPA is involved in a cooperative program with
Yugoslavia, which has Lurgi Gasif iers to produce
low-Btu gas (Kosovo Gasifier). The program involves
sampling and analysis of plant streams to evaluate
the potential environmental impact and the envi-
ronmental control effectiveness of the plant. The
multi-year agreement consists of two phases which
progress from major pollutant evaluation to trace
and minor constituents.
ERDA's Grand Forks Energy Research Center
(GFERC), Grand Forks, North Dakota, is operating
a pilot plant (P.P.) for slagging, fixed-bed gasification
(GFERC Slagging P.P. Gasifier). EPA pass-through
funds are involved. Goals of the program include
establishment of a data base on characteristics and
investigation of processes for treating the effluents.
Of the systems described in this report the Slagging/
Lurgi Gasifier most relates to the project. The pro-
gram began in April 1977 and will run two years.
ERDA's Lawrence Livermore Laboratory (LLL),
Livermore, California, is conducting tests with joint
funding from EPA pass-through money on what is
essentially a new process for in-situ or underground
coal gasification (LLL Coal In-Situ). EPA's involve-
ment is through its Industrial Environmental Re-
search Laboratory in Cincinnati, Ohio. The po-
tential environmental advantages of in-situ over
surface processes include lower water require-
ments and lesser land disturbance. Major en-
vironmental concerns are possible surface and
aquifer water contamination, safety problems
and land subsidence problems. The technical
feasibility of in-situ gasification has been proven
both overseas and at home. The LLL project
which began in July 1974 and is expected to contin-
ue until 1985, is developing a steam/oxygen, under-
ground process to produce commercially available,
medium-Btu gas. Currently, experimentation has
been done with air in preparation for testing with
steam and oxygen.
3.2 CONTROL TECHNOLOGY DEVELOPMENT
(CTD)
Hydrocarbon Research, Inc., Trenton, New Jersey,
is working on development and evaluation of tech-
nology for controlling pollution from the converter
in fuel treatment, processing, and conversion (CTD,
Converter Output). All technologies for converting
coal to synthetic fuels will be covered. The scope
of work includes operations that treat the converter
output streams through the point that they either
go to by-product recovery operations, product-form-
ing operations, or environmentally sound on-site or
off-site disposal. Term of the contract is from Jan-
uary 1977 to January 1980. Work is continuing with
evaluations for acid gas cleanup having been com-
pleted.
Catalytic, Inc., Philadelphia, Pennsylvania, has
a program underway that will result in technology
to control pollution from the use of products and
by-products created in synthetic fuel processes, in-
cluding those described in this report (CTD, Pro-
ducts/By-Products). Term of the contract is from
September 1976 to September 1979. A draft copy
of a report concerning field sampling and analysis
has been completed. A preliminary outline of a
standards of practice manual for Koppers-Totzek
with ammonia and methanol production has been
reviewed with EPA.
Pullman Kellogg, Houston, Texas, is conducting
a program that will result in the development of
systems for treating water and solid waste (CTD,
Water/Waste Management). Technology for coal
storage, preparation, and feeding is also a part of
the program. Term of the contract is from March
1977 to March 1980. A work plan has been submit-
ted and approved by EPA. Data acquisition via lit-
erature search and contacts has begun. Wastes and
effluents are being categorized for all processes
according to type, quantity, and concentration.
North Carolina State University at Raleigh will
operate and test a small pilot facility for raw and
acid gas cleanup from coal gasification to deter-
mine environmental effects (Raw/Acid Gas Cleanup
Test Facility). The principal goal will be the eval-
uation of operations used to clean the raw gasif ier
product gas and the subsequent operation for acid
gas removal. Processes related to this project are
BI-GAS, Synthane, CO2 Acceptor, Lurgi, Slagging/
Lurgi Gasifier, Wellman-Galusha, and HYGAS. Term
of the contract is from October 1976 to September
1981. Design of the facility is by ACUREX Corpora-
tion, Aerotherm Division, Mountain View, California.
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Final review of the design is complete. Construc-
tion has EPA approval and site preparation is well
underway.
The University of North Carolina at Chapel Hill
is assessing the environmental impact of waste-
water contaminants from the production of syn-
thetic fuels (Wastewater Treatment Test Facility).
Alternative wastewater treatment technologies
will also be examined. All processes for producing
synthetic fuels from coal relate to this project Term
of the contract is from November 1976 to October
1981. A literature review and survey of coal conver-
sion facilities are complete enough to allow iden-
tification of specific contaminants in wastewaters
from such facilities. Equipment is being assembled
and procedures developed to assess biodegradation
of such substances as phenol, cresols, xylenols, and
other substituted phenols, pyridines, quinolines, and
polynuclear aromatics. Organisms from municipal
sewage are to be used as seeds to begin the biode-
gradation. A parallel effort is underway to use phy-
sical/chemical methods to accelerate treatment of
biodegradable compounds or to handle compounds
which are not biodegradable.
The Morgantown Energy Research Center (MERC),
Morgantown, West Virginia, is operating a low-Btu
pilot plant gasif ier (MERC Low-Btu P.P. Gasif ier).
The facility, in which pass-through funds are in-
volved, is a fixed-bed gasif ier similar to the Wellman-
Galusha and Lurgi. The program, which began in
April 1977 and will last 18 months, will evaluate
effluents from and design control systems for the
facility.
-------
Table 1
U.S. EPA ONGOING EFFORTS
IN THE SYNTHETIC FUELS FROM COAL PROGRAM
Fiscal Year 1977 Committed Funds
(in thousands of dollars)
Raw/Acid Gas Cleanup Test Facility
Wastewater Characterization Study
Fuel Contaminants. Phase 11 Screening Studies of
Removal Techniques
I
Characterization of Coal and Residues
Fuel Gas Environmental Impact
Liquefaction
Low-Btu Gasification
Water Usage in Coal Conversion
Kosovo Gasifier
High-Btu Gasification
Morgantown Energy Research Center
Low-Btu P.P. Gasifier
Water/Waste Management
Products/Bv-Products
Converter Output
Wastewater Treatment Test Facility
Grand Forks Energy Research Center
!•:•:/ Slagging P.P. Gasifier
Non-Isothermal Pollutant Identification
Lawrence Livermore Laboratory Coal In-Situ
%M Pass-Through Funds
Total Funding: 6,114
-------
PART II
PROCESS OVERVIEWS
-------
1. BI-GAS PROCESS
The BI-GAS Process for generation of pipeline
gas from coal is currently being developed by Bitu-
minous Coal Research, Inc. (BCR) under con-
tract to ERDA and the American Gas Association
(AGA). ERDA is providing two-thirds of the $66
million project funding, AGA one-third. The pilot
plant project which is located near Homer City,
Pennsylvania, is being managed by the Phillips
Petroleum Company.
1.1 PROCESS DESCRIPTION
The BI-GAS Process is a two-stage, high-pressure,
oxygen-blown system using pulverized coal, oxy-
gen, and steam in an entrained flow. A diagram of
the BI-GAS Process is provided in Figure 1-1.
Raw coal is first pulverized so that approximately
70 percent will pass through 200-mesh. The coal,
mixed with water, is fed to a cyclone, where the fine
solids are concentrated into a slurry. Coarse under-
flow from the cyclone is sent to a wet grinding mill
for further crushing. The slurry is further concen-
trated in a thickener and a centrifuge and is then
repulped and mixed with flux to provide the desired
concentration to be fed to the downstream high-
pressure feed system.
A high pressure slurry pump picks up the blended
slurry and transports it under pressure to a steam
preheater. The hot slurry then contacts the recycle
gas in a spray dryer for nearly instantaneous vapor-
ization of the surface moisture. The coal is con-
HIGHBTUCAS
K f CYCLED
CAS FROM
MCTHAHATOK
RCCYCLCGAS
TO OASIFIfR
—^SCRUBBER
• WATER
FLOATING CHAft
T
WATCH. OIL AND
FLOATING CHAD
Figure 1 -1
BI-GAS PROCESS SCHEMATIC
13
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BI-GAS
veyed to a cyclone at the top of the gasifier ves-
sel by the stream of water vapor and inert recycle
gas, as well as additional recycled gas from the
methanator. The coal is separated from the hot
recycled gas in the cyclone, and the coal flows
by gravity to the gasifier.
The coal enters the gasifier through injector noz-
zles near the throat separating the stages. Steam is
introduced through a separate annulus in the injec-
tor. The two streams combine at the tip and join the
hot synthesis gas rising from Stage 1. A mixing tem-
perature of about 2,2008F is attained rapidly, and
the coal is converted to methane, synthesis gas, and
char. The raw gas and char rise through Stage 2,
the gasifier, at about 1,700° F, and are quenched to
800° F by atomized water prior to separation in a
cyclone. The synthesis gas, containing carbon mon-
oxide, carbon dioxide, hydrogen, water, hydrogen
sulfide, and methane, passes through a scrubber for
additional cooling and cleaning. The clean gas,
along with the desired amount of moisture, is sent
to a carbon'monoxide shift converter to establish
the proper ratio of carbon monoxide and hydrogen
required in methanation process.
1.2 PROCESS ADVANTAGES
• Gasifier can accept all types of coal;
• Gasifier can be operated with air or oxygen;
• No by-products which require additional pro-
cessing are produced;
• The absence of tars, oils, naphthas, and phe-
nols in the raw gas simplifies control techno-
logy requirements;
• Pressurized operation will be an advantage
for gas transmission by pipeline and utiliza-
tion as a synthesis gas or combined-cycle fuel;
• Cyclone char recycle system permits almost
100 percent carbon conversion;
• Gasifier uses pulverized fuel, which elimi-
nates rejection of fine coal particles.
1.3 PROCESS LIMITATIONS
• Coals with low ash content or high percent-
age of refractory type ash may require addi-
tion of ash fluxing agents;
• Pressurized operation with air has not been
demonstrated;
• Gasifier is designed to maximize methane for-
mation in the gasifier which may not be ad-
vantageous for all utilization applications;
• The fuel-rich, high-pressure environment in the
gasifier will require start-up using pyrophoric
materials;
• The low system heat capacity and small reac-
tion zone will necessitate sensitive feed control
and automatic, interlocked shutdown control.
• Separation of large amounts of high temper-
ature char from the high-pressure gas stream
and metering of the recycled char feed may
present operating problems.
1.4 PROJECT HISTORY
This project was initiated in December 1963.
BCR's first experiments confirmed the basic assump-
tion that a high yield of methane could be obtained
directly from coal by reaction with steam at ele-
vated temperatures and pressures. BCR next con-
ducted continuous flow experiments in an externally
heated reactor that used 5 pounds of coal per hour.
The data were extrapolated to design a process de-
velopment unit that would simulate the conditions
of Stage 2 of the BI-GAS Process. The unit was in-
ternally fired and could process 100 pounds of coal
per hour. Experiments were designed to determine
the optimum residence time, coal rank, and pro-
cessing conditions, such as pressure, temperature,
and hydrogen partial pressure, that would produce
the largest yield of methane. North Dakota lignite.
Wyoming subbituminous C coal, and Pennsylvania
high volatile A bituminous coal were used in the
experiments. During these experiments, BCR found
that the physical design of the Stage 2 process de-
velopment unit influenced methane yield. There-
fore, a cold flow model of Stage 1 and the bottom
of Stage 2 was developed to investigate methods for
improving the flow patterns in Stage 2 and to estab-
lish design criteria for the slagging section of the
gasifier.
Next BCR developed the design criteria for a
large, fully integrated pilot plant that would pro-
cess 5 tons of coal per hour and produce 100,000
cubic feet of clean pipeline gas per hour. Respon-
sibility for constructing and operating the $34 mil-
lion plant was awarded to Steams-Roger, Inc., on
July 11,1972. The systems management contract
was awarded to Phillips Petroleum Company in
14
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BI-GAS
November 1974. The BI-GAS Casifier to be used in
the pilot plant was designed and built by Babcock
and Wilcox, a Stearns-Roger subcontractor.
Presently, the construction of the pilot plant has
been completed and equipment start-up has been
initiated. However, various equipment problems
have been encountered, and some time will be
needed to allow modifications. Pilot plant test-
ing will begin as soon as equipment problems have
been rectified.
1.5 ENVIRONMENTAL CONSIDERATIONS
Downstream processing for the BI-GAS Process
is identical to that in other second generation, high-
Btu processes. The product gas-processing steps are
identical to those serving the Synthane plant, and,
therefore, the effluents generated are the same.
Figure 1-2 illustrates these discharges.
A critical point in the gas processing involves gas
clean-up. This step follows shift conversion and re-
moves hydrogen sulfide, carbon dioxide, carbonvl
sulfide, and mercaptans from the product stream.
There are a number of processes commercially
available that assure that product gas will
contain as little as 1 ppm hydrogen sulfide. Each
developer has decided on various cleanup processes
using criteria set up by their engineering team. In
most cases, the hydrogen sulfide in the product
gas is recovered and sent to a Claus unit for ele-
mental sulfur generation. The carbon dioxide is re-
moved and vented to the atmosphere. This stream
is generally 99,5 percent plus carbon dioxide and
does not constitute a pollution problem. However,
some studies have stated that the carbon dioxide
vent may contain as much as 3,400 ppm sulfur and,
depending on the acid gas removal process, may
contain up to 1 percent combustibles such as ethane
and ethylene. These statements are contrary to
experiences from operation of these processes in
the refining industry. The BI-GAS pilot plant will
use a Selexol^ unit for acid gas removal and will
vent the carbon dioxide directly to the atmosphere.
Coal Preparation and Drying
See the generalized discussion in Appendix B.
Gasification
Effluents to the Air - During pilot operation, there
have been no effluents to the air from the
gasification section since all the gas streams are
contained and processed in downstream equip-
ment. This particular process does not use lock
hoppers for coal feeding so that vent gases are not
involved. The slurry feed system utilized is closed
so that no vapor escape is possible.
liquid and Solid Effluents - The only solid efflu-
ent from the gasifier is the slag formed. The molt-
en slag, about 3,000°F, is quenched in water, a
process which fractures the slag sufficiently that
an appropriate slurry is formed. In commercial
operation, the slurry would be dewatered and the
solids sent to the mine site for disposal. The slag
is relatively sulfur free and unreactive and poses
no particular disposal problem. The water used
in the quenching process is collected and reused
and is not discharged.
Quench and Dust Removal
Effluents to the Air - The raw gas leaving the gas-
if ier passes through cyclones to recover the en-
trained char, which is returned to the lower stage
of the gasif ier. This system is totally contained so
that there are no emissions to the air.
Liquid and Solid Effluents - There are no dis-
charges.
Shift Conversion
Effluents to the Air- None are generated.
Liquid and Solid Effluents - Following the shift re-
actor, the gas is cooled to condense out water.
A large amount of sour condensate will be gener-
ated. Although this water is recycled, it does con-
tain a varying amount of such compounds as am-
monia, cyanides, phenols, etc. These particular
materials must either be destroyed in recycling
operations or removed from the system. This can
be accomplished using various water treatment
systems. The solids discharge generated in the unit
is the spent catalyst. This material can be easily
disposed of in a landfill.
15
-------
Figure 1-2
BI-GAS PROCESS-EFFLUENTS SUMMARY
2
>
FROM COAL .^
^_^v ^x_xv^^x^
HtH
COAL CLEANING
PREPARATION
COAL
x_>
1
6ASIFIER
QUENCH &
DUST REMOVAL
SHIFT &
COOLING
ACID GAS
REMOVAL
METH. &
DRYING
-^-PRODUCT GAS
-------
BI-GAS
BI-GAS PROCESS-EFFLUENTS
SUMMARY FOR FIGURE 1-2
Stream # Description
1 Wind-generated dust
2 Refuse
3 Wash water
4 Flue gas
5 Spent limestone
6 Gasifierslag
7 Chemical purge
8 Carbon dioxide vent stream
9 Water reject
Acid Gas Removal
Effluents to the Air - The BI-CAS pilot plant is
currently investigating the use of the SelexolR
solvent process for acid gas removal. This par-
ticular method vents the carbon dioxide re-
moved from the product gas. This vent stream
is relatively free of impurities and does not re-
quire further processing.
Liquid and Solid Effluents - The SelexolR Pro-
cess does not create any liquid or solid dis-
charges. If other types of processes are used,
spent solution would be generated and dis-
posal techniques would need to be devised.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given in
Appendix A.
Sulfur Balance
A typical sulfur balance breakdown is given in
Table 1-1.
Table 1-1
BI-GAS PROCESS SULFUR BALANCE
Claus plant
Claus plant tail gas
Flue gas coal dryer
Flue gas boiler
Flue gas superheater
percent
83.4
0.8
1.0
12.2
2.6
17
-------
2. CO2 ACCEPTOR PROCESS
The CO2 Acceptor Process, located at Rapid City,
South Dakota, is being developed by the Conoco
Coal Development Company (CCDC) under the joint
sponsorship of ERDA and ACA. ERDA is providing
two-thirds of the funding and AGA, one-third. The
initial contract for $27 million expired in June of
1976. Since that time another $3 million has been
funded for plant operation.
2.1 PROCESS DESCRIPTION
A diagram of the CO2 Acceptor Process is shown
in Figure 2-1. In this process, raw coal is crushed
to 8x100-mesh in hot, gas-swept impact mills, where
the moisture content is reduced from approximately
38 weight percent to about 16 weight percent. The
hot gas, at approximately 850°F, is supplied by the
combustion of coal fines recovered from mill off-
gas. The temperature of the furnace flue gas injected
into the mills is moderated with recycle of mill off-
gas.
The crushed and partially dried coal is dried to
0-5 weight percent moisture in flash driers operating
about 240°F. The dried coal is conveyed to fluid-
ized-bed preheaters where the temperature is raised
to approximately 500° F. The preheated coal is then
fed into the gasifier near the bottom of a f luidized-
bed of char. Rapid devolatilization occurs, followed
by gasification of the fixed carbon with steam.
The gasif ier temperature ranges between 1,480°F
and 1,550° F. Heat for the gasification reactions is
supplied by a circulating stream of acceptor mate-
rial. This acceptor, which can be either limestone
or dolomite, supplies the heat needed for gasifica-
tion, primarily through the exothermic carbon di-
oxide acceptor reaction:
CaO + CO2 — CaCC>3 + heat
Figure 2-1
CO2 ACCEPTOR PROCESS SCHEMATIC
19
-------
C(>2 Acceptor
The acceptor, reduced to the desired size distri-
bution (generally 6 x14-mesh) enters the gasifiers
above the f luidized char bed, showers through the
bed, and collects in the gasifier boot. Steam needed
for hydrogasification enters through the gasifier
boot and the distributor ring. Spent dolomite, used
during start-up to avoid plugging, is replaced by
fresh acceptor after circulation rates are established
and the system is at process temperature and pres-
sure. Product gas from the gasifier passes through
a steam-generating heat exchanger, then goes to the
gas cleanup section.
The regenerator is used for calcining the accep-
tor. Carbonated acceptor from the gasifier flows
through a standleg and is conveyed pneuma-
tically by air or recycle gas to the bottom of the
regenerator. Char from the gasifier is sent to the
regenerator where it is burned with air, thus raising
the temperature of the regenerator to 1,850°F. The
acceptor is calcined by reversal of the carbon dio-
xide acceptor reaction. The calcined acceptor is
returned to the gasifier through a standleg. Flue gas
from the regenerator passes through a heat ex-
changer to generate steam for the gasifier and the
air compressor.
Both the flue gas from the regenerator and the pro-
duct gas are cleaned, the clean flue gas is either re-
turned to the regenerator or flared, and the clean
synthesis gas is sent to the methanation unit to
raise the heating value of the gas to pipeline qual-
ity, approximately 1,000 Btu/SCF. The gas-processing
facilities include a shift converter, carbon dioxide
absorber, hydrodesulfurizer, zinc oxide sulfur guard,
and a packed-tube methanator. A DOWTHERMR
system is used to remove the heat generated by the
strongly exothermic methanation reaction.
2.2 PROCESS ADVANTAGES
• An oxygen plant is not needed because the
acceptor is heated and calcined in a separate
reactor where air can supply oxygen for com-
bustion without contaminating product gas;
• The circulation rate is lower than that required
in other high-Btu gasification processes that
circulate solids for heat transfer, because the
acceptor supplies heat through chemical re-
action with carbon dioxide;
Product gas cleanup requirements are mini-
mized because the acceptor reacts with both
hydrogen sulfide and carbon dioxide, the
principal impurities in gasifier product gas;
Raw gasifier product gas may contain enough
hydrogen to methanate all of the carbon mon-
oxide and part of the carbon dioxide without
requiring water-gas shift conversion prior to
methanation.
2.3 PROCESS LIMITATIONS
• Operating difficulties have been encountered
in the area of solids circulation.
2.4 PROJECT HISTORY
Bench-scale development of the CO2 Acceptor
Process was completed in 1968. Feasibility studies
indicated that the process had commercial poten-
tial. Construction of a pilot plant to test the process
was completed, except for the gas-processing fa-
cility, in October 1971. Construction of the gas-pro-
cessing facilities was completed in late 1974. The
pilot plant is designed to use 40 tons of coal and 3
tons of dolomite per day to produce 500,000 SCF
of high-Btu gas.
Pilot plant shakedown operations began in Jan-
uary 1972 and were completed in April 1972. A
series of start-up attempts were initiated followed
by the experimental run program. Along with the
operation of the pilot plant, CCDC has been con-
tinuing its laboratory research to resolve problems
and improve the overall process design.
During 1975, runs were made in the pilot plant.
Most of the runs were instrumental in locating op-
erational problems. As these problems were solved,
progressively longer and more trouble-free runs were
made. During one of the successful runs, the system
operated for 232 consecutive hours without air to
the gasifier and 87.5 hours with 100 percent steam
to the gasifier. The unit also operated 72 hours with
20
-------
CO2 Acceptor
no air or recycle gas and all steam. The packed-tube
methanation unit was also successfully operated
for 48 hours without mechanical difficulty. The
heating value of the synthesis gas was upgraded
from 373 to 787 Btu/SCF. It is expected that this
will be increased to 900 Btu/SCF when the newly
installed hot potassium carbonate acid gas cleanup
system is fine-tuned.
2.5 ENVIRONMENTAL CONSIDERATIONS
This process generally meets the emissions stan-
dards set for major pollutants. However, there is one
unique area of concern about exceeding standards.
This uniqueness involves the lignite feedstock
(as opposed to bituminous feedstock for other pro-
cesses) which has a high moisture content and must
be dried prior to gasification. Initially, raw lignite
containing approximately 33 percent moisture is fed
to a grinder which is swept with hot recirculating
gas to dry the lignite down to 16 percent moisture.
The coal is then fed through a drier and a preheater
before being fed to the gasifier. The three furnaces
used to supply heat to the grinder/drier/preheater
system are required to use a mixture of 25 percent
raw fuel gas, derived from the process, and 75 per-
cent lignite as fuel in order to achieve the limit
of 1.2 Ib/MM Btu sulfer dioxide emissions. This
particular mixture will vary, depending on the
sulfur content of the lignite feed, and is an impor-
tant parameter since an error in mixing could
throw the furnaces out of compliance. In addition,
combustion of lignite fuels generates ash which
needs to be separated and rejected. Slagging type
furnaces are used where an estimated 70 percent
of the ash is removed in the reject slag. Hot gas
leaving the furnace is cooled and passed through
cyclones to remove rearly all of the remaining ash.
If the final ash content of the hot gas is com-
parable to the 0.1 Ibs/MM Btu required on sta-
tionary boilers, then overall separation of the
ash must be 99 percent effective. This degree of
separation has been difficult to achieve with con-
ventional cyclones in power plant boilers using
as fuel.
When the hot gas contacts lignite in the grinder,
some of the lignite fines are entrained in the gas
stream and need to be recovered. In order to meet
the comparable dust loading of 0.1 Ibs/MM Btu, the
dust remaining in the vent gas after final cleanup
can only be 155 Ibs/hr. This requirement represents
a difficult cleanup problem since it corresponds to
only 0.1 weight percent of the lignite charge on a
dry basis. A number of dust removal systems will
need to be examined and tested in order to meet
dust-loading standards.
Another concern with emissions from the coal
preparation area involves odors. Lignite is a rela-
tively reactive material, and when dried and pre-
heated to 500°F small amounts of vapors are
evolved. These vapors may have undesirable odors;
incineration of the effluent gas may be necessary.
The process effluents summaries described later
relate to a future commercial-sized plant and are
either estimated from current pilot plant data or,
if necessary, from design data. The process effluents
summary is shown in Figure 2-2.
Coal Preparation and Drying
Various pollutants are discharged from this area.
Since coal preparation is common to all coal conver-
sion plants, a generalized discussion is given in Ap-
pendix B.
Gasification
Effluents to the Air -There will be no gaseous
streams released directly to the atmosphere from
the gasif ier. However, a stream of spent dolomite
acceptor, MgO CaCX^, will be removed from the
gasifier to maintain acceptor activity. The pos-
sibility of a dust problem may exist if proper
handling procedures are not followed. If dusting
problems are encountered, an enclosed fluid-bed
cooler could be used to cool the acceptor and
control any resulting dust.
Liquid and Solid Effluents • The only discharge
stream from the gasifier will be the reject accep-
tor which is replaced at the rate of 2 percent per
day of dolomite circulation. The reject acceptor
is expected to be low in sulfur, 0.084 percent from
pilot plant data, and is not expected to pose a
secondary pollution problem if used as landfill
material.
21
-------
n
O
n
n
COAL
FEED
ACCEPTOR
-v
KJ
KJ
CHAR
— ACCEPTOR
REGENERATOR
FLUE GAS
HEAT RECOVERY
CO BURN UP
DUST REMOVAL
FLUE GAS
GAS
TURBINE
ASH
DESULFURIZATION
Figure 2-2
CO2 ACCEPTOR PROCESS-EFFLUENTS SUMMARY
-------
CC>2 Acceptor
CO2 ACCEPTOR PROCESS-EFFLUENTS
SUMMARY FOR FIGURE 2-2
Stream # Description
1 Rain runoff
2 Vent gas from dryer
3 Ash from dryer fuel
4 Reject acceptor
5 Warm air
6 Chemical purge
7 Ash slurry
8 Flue gas from turbine
9 Dust
Raw Gas Cleaning/Acid Gas Removal
Effluents to the Air - There will be no streams
discharged directly to the environment from
these units. However, there are various waste
streams that will be created here which must
be treated before disposal or use as a make-up
stream.
As raw gas leaves the gasifier, it is initially
cleaned by an internal cyclone. The gas is then
cooled by a water stream in a wash cooler
which removes the residual dust and ammonia.
, The water stream will also contain sulfur com-
pounds since the gas stream could contain as
much as 3,300 ppm of hydrogen sulfide. The
water will be required to be treated in a clar-
ifier to remove solids; processed in a sour
water stripper to remove ammonia and hydrogen
sulfide; and then finally processed in a biox
(biological oxidation) unit to remove the traces
of phenols, tar, and naphthalene. A retention
pond would also be required to reduce contam-
inants to allow use as recycle stream. This
water should not be allowed to become an
effluent from the plant.
A small purge stream of amine used for acid
gas removal will be periodically removed from
the system. This stream must be treated and is
usually dumped into a holding vessel for further
disposal with other chemical effluent streams.
Liquid and Solid Effluents - No effluents will be
discharged.
Methanation
Effluents to Air- No effluents will be discharged.
Liquid and Solid Effluents - In general, there
will be no liquids discharged from the unit. The
spent nickel catalyst discharge will be returned
to the processor for metals recovery.
Regenerator
Effluents to the Air - In pilot plant operation
the circulating dolomite acceptor is calcined
at 1,850°F to remove carbon dioxide. Heat is
supplied by burning the char contained in the
acceptor from the gasifier with air in the fluid-
bed regenerator operating at 150 psig. The flue
gas from the process is cleaned of dust in cy-
clone separators and then goes to an expansion
turbine to recover power. The flue gas is dis-
charged to the atmosphere at this point. It
contains 470 ppm of total sulfur and acceptable
levels of nitrogen oxides and dust. Various
operating parameters require close attention,
however, in order to assure proper nitrogen
oxide levels. Several combustion stages are
present where excessive nitrogen oxide forma-
tion could take place. This procedure will be
the same for a commercial operation with
similar emission levels expected.
Liquid and Solid Effluents - There will be no
liquid effluents from the unit, and the only
solid stream is an ash stream which is recovered
in the flue gas cyclones. For a 27,500 TPD plant,
this ash would amount to 177,000 Ib/hr. How-
ever, disposal problems do exist since the ash
has a 5.0 weight percent sulfur content (carbon
is only 3.5 weight percent) which is in the form
of compounds such as calcium sulfide that
would release hydrogen sulfide. This particular
material will require desulfurization before
disposal.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
23
-------
C(>2 Acceptor
Sulfur Balance
The distribution of the sulfur in the lignite feed
to plant is broken down as shown in Table 2-1.
Table 2-1
CO2 ACCEPTOR PROCESS SULFUR BALANCE
By-product sulfur
Reject acceptor
Spent ash
Regenerator flue gas
Dryer vent gas
Claus tail gas
24
-------
3. COALCON HYDROCARBONIZATION PROCESS
Coalcon Company, Inc., an affiliate of Union
Carbide, is to verify, through a demonstration-
sized plant, the commercial economics, technical
scale-up potential, and the physical and chemical
feasibility of a process for producing clean boiler
fuels from high-sulfur coal and pipeline gas and
other useful products in a commercial-sized
plant. The design phase is estimated to cost near
$20 million. Construction costs were expected
to be $142.3 million (1974 dollars), and the oper-
ating phase $72.5 million. However, due to a
number of technical and management problems,
a "go-slow" approach has been taken.
The plant was designed to convert 3,901 TPD
of high-sulfur coal into 2,990 BPD of heavy oil,
1,192 BPD of gasoline fraction, 1,088 MMSCFD
of SPG, and 28.93 MMSCFD of high-Btu pipeline
quality gas. Some 125.6 TPD of elemental sulfur
will also be produced. The plant was to be built
on a site just outside New Athens, Illinois.
3.1 PROCESS DESCRIPTION
The method selected by Coalcon for producing
clean boiler fuel in the demonstration plant is
Union Carbide's Hydrocarbonization Process. The
conceptual design of the plant using this process
is divided into five main areas: (1) coal preparation,
(2) the hydrocarbonization reactor, (3) reactor
product cooling and liquids separation, (4) gas
processing, and (5) hydrogen generation. , The
process flow diagram is shown in Figure 3-1.
Initially, the coal is crushed, milled, and classi-
fied, then fed to the coal preheater. The heating
scheme involves entraining the coal in a hot,
oxygen-free flue gas and separating the solids from
the gas in a cyclone. This heating process helps
maintain the reactor heat balance and also drives
off some volatiles and moisture. After heating to
about 617°F, the coal is held in the coal feed
Sulfldt
l« Claut Plant
Flat Sat
Carton DIotMtt
•of onrf Got I
. Synlhtiit So*
Te McfAonaffon
Figure 3-1
COALCON PROCESS SCHEMATIC
25
-------
Coalcon
hopper before it is pressurized to the operating
pressure of the system, approximately 51 atm.
The coal is dropped from the lock hoppers into
another coal holding vessel. From there, it is
gravity fed into an injection vessel where it is f luid-
ized with hydrogen at 1,040°F and 53 atm. This
mixture enters the hydrocarbonization reactor
which operates at 37 atm and 1,040°F. The solid
residence time in the reactor is approximately 25
minutes. The solids not gasified are removed from
the reactor through an agglomerate removal
system at the bottom of the reactor. This char is
used to manufacture hydrogen and also may be
used to generate steam.
The gas residence time in the bed is approxi-
mately 25 seconds. These gases are heavily laden
with solids which subsequently are removed by
two cyclones. The cleaned gas/vapor from the
cyclones is sent downstream to the fractionator
for cooling and separation. The basic purpose of
the fractionator is to split the reactor product into
four basic streams:
• Overhead gas (hydrogen, carbon monoxide,
carbon dioxide, methane)
• Light liquid (#2 fuel oil)
• Heavy liquid (#5 or #6 fuel oil)
• Waste water
The heavy oil from the bottom of the fraction-
ator is partially cooled and recycled to a venturi
where it mixes with the hot reactor product gas.
This mixture is fed to the fractionator and split
into a hot heavy fuel oil and a moderately hot
(350°F) fractionator overhead stream. The heavy
oil product is cooled to about 104°F and pumped
to storage. The fractionator overhead is con-
densed and the liquid/vapor mixture is fed to a
decanter where the light fuel oil, overhead gas,
and waste water are separated. Some of the light
oil is sent to the fractionator as reflux and the re-
mainder is sent to storage as product. The remain-
ing gas is sent through a series of separation and
purification systems which include ammonia re-
moval and recovery, acid gas removal (hydrogen
sulfide, carbon dioxide), and a cryogenic gas-
producing system. The cryogenic system manu-
factures LP fuel gas, synthesis gas, and a hydrogen-
rich stream. The hydrogen stream is recycled back
to the hydrocarbonization reactor while the syn-
thesis gas is sent to a methanation reactor for up-
grading to high-Btu pipeline gas. The LP fuel gas
may be either burned on-site or sold.
3.2 PROCESS ADVANTAGES
• The plant will be fully integrated in all phases
of processing, from receipt of coal to delivery
of a finished product;
• The process yields a multiple product.
3.3 PROCESS LIMITATIONS
• ERDA has reported that the process econom-
ics are marginal and technical problems with
the fluid-bed are greater than first believed.
3.4 PROJECT HISTORY
Work under this ERDA contract was initiated
in January 1975. Union Carbide was selected to
design, construct, and operate a demonstration
plant for producing clean boiler fuels from high-
sulfur coal.
During 1975, work on the Clean Boiler Fuel De-
monstration Plant involved preliminary process
design and engineering of a commercial plant.
This effort included review and evaluation of all
hydrocarbonization subsystems to minimize
capital investment and maximize subsystem op-
erability and reliability. By the end of 1975, design
and engineering for the commercial plant were
near completion. A process evaluation report
was prepared and submitted to ERDA. This report
includes preliminary data on plant design and
provides a basis for starting the design of the de-
monstration plant.
Work toward establishing the definition and
design basis for the demonstration plant began
late in 1975. The plant will be one-fifth the size
of a commercial-scale plant and will be capable
of utilizing three different types of coal. Prelim-
inary performance specifications were issued, and
26
-------
Coalcon
work on the overall process design of the demon-
stration plant, analysis of the three coal types to
be tested, and development of process designs
of plant subsystems were started.
Design of the demonstration plant was continued
in 1976. However, about midyear, a number of
technical and management problems began to
plague the project. ERDA, later in the year, order-
ed a "go-slow" approach to design and procure-
ment activities. At this time, ERDA and Coalcon
are negotiating a continuance of design phase
activities, and Coalcon has made a proposal to
ERDA to fund a pilot plant to generate gasifier
data on caking eastern coals. This is probably
necessary due to a data gap that became apparent
due to design activites using old laboratory data
generated by Union Carbide in the 1960's and
results obtained by current laboratory testing of
eastern coals in a bench-scale reactor.
The initial plant design is 100 percent funded
by ERDA while the construction and operation is
on a 50-50 cost sharing basis with government and
industry. At present, the potential participants
include: Atlantic Richfield Company, Ashland Oil,
Mobil Research and Development Corp., Du Pont,
Reynolds Metals, Consolidated Gas, State of Ill-
inois, Northern Natural Gas, Ohio Power, Pacific
Gas and Electric, Electric Power Research Institute
(EPRI), and Celanese Corporation.
duct recovery is the same as the other processes
covered. Very little public data exists on the en-
vironmental aspects of this process since much
of the development work was done in the 1960's
on a laboratory scale. There have been some
evaluations made by the Coalcon design team
but the information has not yet been made public.
From all indications, pollution problems or plant
effluents resemble those of refineries and should
be handled by existing technology.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
A typical sulfur balance breakdown is given in
Table 3-1.
Table 3-1
COALCON PROCESS SULFUR BALANCE
Heavy fuel oil
Gasoline fraction
Elemental sulfur
Atmospheric vents
Ash
3.5 ENVIRONMENTAL CONSIDERATIONS
The Coalcon Process produces both liquid and
gaseous products. However, the basic down-
stream processing for gas cleanup and liquid pro-
27
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4. HYCAS PROCESS
The HYGAS Process is being developed by the
Institute of Gas Technology (IGT) as part of the
joint program of ERDA and the AGA. ERDA is
providing two-thirds and AGA one-third of the $8
million contract funding. The HYGAS pilot plant
is located in Chicago, Illinois.
4.1 PROCESS DESCRIPTION
Several processing steps are required to convert
coal to high-Btu gas with the HYGAS Process. A
key feature is the use of hydrogen and steam in
hydrogasification. A diagram of the process is
provided in Figure 4-1. Coal preparation involves
crushing the coal to -8-mesh. Caking coal is pre-
treated in a fluidized-bed at 660°F to 7508F and
at atmospheric pressure to destroy caking ten-
dencies and produce a free-flowing coal. Non-
caking coal is fed directly into the slurry tank.
PRE
TREATER
. COAL
AROMATIC
Oil
CAKING NOHCAKINC
COAL
SLURRY
TANK
The coal is mixed in this tank with an aromatic
recycle oil to form a thick slurry and is pressurized
to 1,000 psig. The slurry is then sprayed into the
drying section of the gasif ier.
In the drying section, oil is vaporized and re-
moved, together with the hot gases passing up-
ward from the first stage of the gasif ier. Vaporized
oil is recovered for reuse by quenching the effluent
of the gasif ier.
The dried coal drops into the first stage of the
gasifier where it is heated rapidly by internally
recycled hot char and hot reaction gases rising
from the second-stage reactor. The relatively low
temperature environment of the first stage pro-
vides for conversion of approximately 20 percent
of the feed coal to methane. At the top of the first
stage the diameter of the reactor increases rapidly
thus reducing the velocity of the upward-flowing
gases and solids. At these lower velocities, the
HIGH 1TUGAS
Figure 4-1
HYGAS PROCESS SCHEMATIC
29
-------
HYGAS
partially spent char is separated from the gas and
channeled downward. Part of this hot char is re-
cycled to provide heat to the first stage, and the
remainder is sent to the second hydrogasification
stage, a high-temperature fluidized-bed reactor.
An additional 25 percent of the raw coal feed is
converted to methane in the hydrogen-rich en-
vironment of this stage. Hot residual char moves
from this stage into the steam-oxygen section in
the bottom of the reactor. Here, the steam, oxygen,
and char react in a fluidized-bed, producing a hy-
drogen-rich gas. This gas is transferred up into the
hydrogasification sections as a source of hydrogen
for methanation reactions. Ash is removed from
the bottom of the stream-oxygen stage.
The product gas, containing methane, carbon
monoxide, carbon dioxide, hydrogen, and other
raw gases, particulates, trace elements, and water
and oil vapors, is quenched, purified, and passed
to the methanator. The mole ratio of hydrogen
to carbon monoxide in the gas is adjusted to a
ratio of about 3:1 prior to entering the methan-
ator. In the methanator, the gas passes through a
nickel catalyst at 800°F to 900°F and is trans-
formed to methane, providing a pipeline quality
gas with an average heating value of 1,000 Btu/SCF.
4.2 PROCESS ADVANTAGES
• Use of a steam-iron reactor eliminates the
need for a large oxygen or power-plant, re-
duces the amount of carbon dioxide scrub-
bing required, and eliminates downstream
shift reactors by proper adjustment of the
steam-hydrogen ratio;
• Energy recovery and sale of by-product
electricity may lead to an overall coal-to-
energy conversion of greater than 70 percent.
continued under joint sponsorship with the Office
of Coal Research (OCR, now a part of ERDA) in
1964. The pilot plant was designed and built to
convert 75 tons of coal per day to 1.5 million
cubic feet of clean high-Btu gas. During 1973,
the plant produced pipeline-quality gas from coal
in sustained test operations. Since then, the dur-
ation of the test runs has increased, and longer,
more stable operating periods have been achieved.
During 1975, 11 test runs were made in the
HYCAS pilot plant. The longest run was 363
hours, during which 575 tons of lignite were fed
to the gasifier. Based on the success of this test,
authorization was given to begin testing with Ill-
inois No. 6 bituminous coal.
Also during 1975, 26 runs were made with the
ash-agglomerating gasifier. Process parameters
were varied to determine the optimum operating
conditions. During one run, agglomerates were
successfully produced for a 200-hour steady-state
period, and full dust recycle was maintained.
In 1977 IGT achieved 92 percent carbon con-
version efficiency in tests with Illinois No. 6 coal.
The conversion was achieved at 1,000 psig with-
out slagging and was attained in the steam-oxygen
gasification stage of the reactor at a temperature
of 1,700°F. This was significantly lower than the
expected reaction temperature of around 1,800°F.
Concurrent laboratory research was directed
toward the study of the penetration of slurry liquid
into coal pores, effects of acidic condensing at-
mospheres on castable insulations, lock hopper
design, and methanation catalyst evaluation.
4.3 PROCESS LIMITATIONS
• Supplemental hydrogen is required;
• Some feed coal types require pretreatment.
4.4 PROJECT HISTORY
Development of the HYGAS Process by IGT
under the sponsorship of AC A began in 1946 and
4.5 ENVIRONMENTAL CONSIDERATIONS
The use of caking coal requires pretreatment
without which agglomeration in the fluid-bed
occurs causing plugging. The environmental
effects would be altered by such pretreatment.
The IGT is currently extending the environmental
assessment to cover the pretreatment step. This
report addresses itself to the use of non-caking
coal. The process effluents summary is given in
Figure 4-2.
30
-------
HYGAS
Coal Preparation
In addition to pretreatment effects previously
mentioned, various other pollutants are discharged
from this area. Since coal preparation is common
to all coal conversion plants, a generalized dis-
cussion is given in Appendix B.
Slurry Preparation
Effluents to the Air - Any flash gas released
during slurry formation of hot recycle oil and
coal must be recovered and used, or incinerated.
Liquid and Solid Effluents - No effluents are
'discharged.
Gasification
Effluents to the Air - The major effluent from
gasification during normal operation is the
residual char that contains ash that enters
with the coal feed. This char, containing 10 to
30 percent carbon, is quenched with water, de-
pressured by lock hoppers, and sent to an ash-
settling pond. Steam formed by this quenching
operation may contain particulates and other con-
taminants; it can be returned to the process
or collected for disposal. The amount of steam
is approximately 50,000 Ib/hr. In the operation
there should be no serious emissions to the
atmosphere.
Ash in the water slurry is recovered in a
settling pond, which is drained so that semi-
dry ash can be removed for burial.
Attrition of particles in the HYCAS reactor
will generate fines that are carried up with the
gas stream. These fines will be removed rather
completely by the oil quench system, thus
tending to build up in concentration in the re-
cycle oil unless they are removed by agglomer-
ation, filtration, or other means. Similarity,
volatile trace elements may accumulate in
the recycle oil.
Liquid and Solid Effluents - The major effluent
from the gasification area of the plant is spent
char, which serves to reject ash brought in with
the coal feed. Some unreacted carbon is also
rejected in the char. Hot char from the gas-
if ier is handled by quenching in water, forming
steam which is presumably returned to the
gasifier, and a water slurry, 25 percent solids,
which is depressured across an oil-field type
choke. The slurry goes to a settling pond from
which water is recycled to the quench system.
At intervals, the pond is drained so that wet
ash can be reclaimed for ultimate disposal
off-site.
Quench and Dust Removal
Effluents to the Air - Gas from the gasifier, to-
gether with slurry oil evaporated in the dry-
ing zone is quenched to 400° F by direct contact
with recirculated oil, the heat being used to
generate steam in waste heat boilers. Most
of the oil vapor in the entering gas is condensed
and recycled to slurry preparation, while at the
same time particulates and condensibles such
as trace elements will be removed from the gas
and will accumulate in the oil. While most of the
oil is recycled, part of it must be withdrawn as
product and can be expected to contain toxic
elements such as arsenic, lead, and cadmium, as
well as particulates, phenols, and sulfur and ni-
trogen compounds. Therefore the properties of
this oil and its projected secondary use need
further evaluation to define what treatment may
be required to make it suitable for use as fuel
or as a raw material for refining.
Liquid and Solid Effluents • In this area of the
process, raw gas is cooled by direct contact
with product oil which is recirculated and
cooled. At the same time, particulates in the '
raw gas are removed. While most of the oil is
used as a slurry for the coal feed, a stream of
by-product oil is also withdrawn corresponding
to the net yield of oil from the coal gasification
reaction. This by-product oil, amounting to 338
TPD is the only major effluent from this section
of the process. One possibility is to use it for
fuel, but more information is required to deter-
mine whether it can be burned directly, or if it
will first need further treatments to remove
contaminants.
When the oil is condensed upon cooling,
most of the dust in the raw gas leaving the
31
-------
I
COAL
FEED
COAL
PREPARATION
DRY
COAL
SLURRY
PREPARATION
COAL
SLURRY
GASIFI-
CATION
RAW
GAS
OIL
QUENCH
COOLED
GAS _
U)
K)
SULFUR
SHIFT
SHIFTED
GAS
SCRUB
CLEAN
GAS
ACID
GAS
TREAT
FREE
GAS
METHANE
Figure 4-2
HYGAS PROCESS-EFFLUENTS SUMMARY
-------
HYGAS
HYGAS PROCESS-EFFLUENTS
SUMMARY FOR FIGURE 4-2
Sf ream # Description
1 Dust
2 Water
3 Flue gas
4 Char slurry
*5 By-product oil
6 Fine sol ids
7 Carbon dioxide vent gas
*8 By-product oil
9 Chemical purge
10 Water purge
"Product, not an effluent
drying bed will also be removed. The con-
densed oil is recycled and used for coal feed
slurry.
Shi ft Conversion
Effluents to the Air- In this process the carbon
monoxide is shifted by reaction with steam to
to produce hydrogen. This catalytic operation
may also give some hydrogenation to help re-
move ofefins, cyanides, and oil vapor. It may
also be possible to modify the shift reactor to hy-
drolize carbonyl sulfide and other compounds
to form hydrogen sulfide which is removed more
easily in acid gas treatment Some trace elements
and coke are expected to be deposited on the
shift catalyst; reprocessing or proper disposal will
be undertaken periodically.
When the gas liquor is depressured, gases are
released that will be recovered or incinerated. In
addition, sour water stripping produces by-prod-
duct ammonia and hydrogen sulfide which can
be sent to sulfur recovery.
If there is residual dust in the gas that leaves.
the oil quench system, it will be removed in the
scrubber.
Liquid and Solid Effluents • Shift conversion does
not involve primary emissions or effluents, al-
though some trace elements and tarry materials
may accumulate on the fixed-bed of catalyst used
in this operation. Subsequent cooling and scrub-
bing of the gas, however, condenses a large
amount of sour water which will be cleaned and
reused or properly removed. Some oil is also con-
densed; it is returned to the oil quench system
after separation from the water layer.
Phenols can be separated by extraction (e.g.,
Phenosolvan" Process), while sour water strip-
ping will remove ammonia and hydrogen sulfide
for recovery. Biological oxidation may then be
used for further cleanup of waste water, followed
by filtration or activated carbon processing as
required
Acid Gas Removal
Effluents to the Air- In this process the bulk of
contaminants remaining in the gas are removed.
Major constituents are acid gases, hydrogen
sulfide, 1.44 percent by volume, and carbon
dioxide, 30.85 percent by volume, while minor
contaminants include hydrogen cyanide, am-
monia, light hydrocarbons, and naphtha. Acid gas
treatment will remove all contaminants to a low
level while providing a concentrated sulfur-con-
taining stream to the sulfur plant with a carbon
dioxide waste stream, which is pure enough to be
vented directly to the atmosphere without
further treatment.
The IGT design uses a Lurgi RectisolR system
for acid gas treatment based on scrubbing with
refrigerated methanol. The desfgn shows 30 per-
cent by volume concentration of sulfur com-
pounds in the gas fed to the Claus plant. This
amount represents a desirably high concentration
to allow efficient sulfur recovery.
The carbon dioxide rejected to the atmosphere
is a very large stream, the TPD exceeding the
daily total of coal used by the plant It will there-
fore be particularly free of contaminants in a
concentrated form. Sulfur content at 300 ppm is
moderate, amounting to less than 1 percent of
the sulfur in the coal to gasification.
This content would appear acceptable in some
cases depending on standards that apply for a
33
-------
HYCAS
specific location, at least if it were in a less ob-
jectionable form such as sulfur dioxide.
Liquid and Solid Effluents - The primary liquid
effluent from acid gas treatment is a naphtha and
oil mixture which is recovered from the gas by
scrubbing with refrigerated methanol. This oil is
returned to the oil quench system and is even-
tually withdrawn as a by-product. As a result of
the high cracking severity to which the oil has
been exposed in the gasification reactor, it will
consist mainly of aromatics such as benzene and
should be useful as a raw material for making
chemicals or gasoline. Benzene is toxic so pro-
per handling and storage precautions are needed.
There is also a small amount of water rejected
from acid gas treatment, which can be combined
with sour water from scrubbing for treatment.
There should be no significant solid effluents
from acid gas treatment since char and ash par-
ticles will be removed in the scrubber.
Methanalion and Drying
Effluents to the Air- Methanation and drying are
carried out in a closed system with no streams
normally emitted to the atmosphere. Proper de-
sign and operation will control leaks from this
system. Gas released when depressuring water,
or when depressuring equipment for maintenance,
will be collected and recovered or incinerated.
Liquid and Solid Effluents - The methanation re-
action produces a large amount of water which
is condensed and used for makeup to steam
boilers. The amount is large relative to the net
waste water effluent and thus makes an impor-
tant contribution in the overall water balance.
It is a very clean condensate, free of sulfur and
dissolved solids, so little or no treating is required.
Auxiliary Facilities
A general discussion of auxiliary facilities com-
mon to most coal conversion plants is given in Ap-
pendix A.
Sulfur Balance
A typical sulfur balance breakdown is given in
Table 4-1.
Table 4-1
HYGAS PROCESS SULFUR BALANCE
Dryer vent gas
Carbon dioxide
Tail gas
Sulfur
Flue gas
Char
Other
34
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5. KOPPERS-TOTZEK GASIFICATION PROCESS
The licensors/developers of the Koppers-Totzek
Gasification Process are Heinrich Koppers GmbH,
Essen, Germany, and the Koppers Company, Inc.,
Pittsburgh, Pennsylvania. The process function in-
volves atmospheric pressure coal gasification in
an entrained-bed by injection of coal plus steam
plus oxygen with co-current gas/solid flow. The
process has been commercially available since
the early 1950's. There are currently 20 plants in
operation with 52 gasifier units, none operating
in the U.S. However, Air Products and Chemicals,
Inc., Allentown, Pennsylvania, has been selected
by ERDA to negotiate for the design, construction,
and operation of a facility for use in industrial
processes. To be located at Cedar Bayou, Texas,
the facility is expected to cost around $100 million.
5.1 PROCESS DESCRIPTION
The Koppers-Totzek Gasification Process em-
ploys the partial oxidation of a carbonaceous
feed in suspension with oxygen and steam to pro-
duce a clean, medium-Btu gas which can be
readily desulfurized. The product gas is high in
carbon monoxide and hydrogen with a negligible
amount of methane. By-products are elemental
sulfur and a granulated sulfur-free slag. A schem-
atic of the Koppers-Totzek Process is provided
in Figure 5-1. There are four major steps in the
process: (1)feed preparation, (2] gasification, (3)
heat recovery and gas cleaning, and (4) hydrogen
sulfide removal and sulfur recovery.
Raw coal is dried and pulverized so that approx-
imately 70 percent will pass through 200-mesh.
The coal is conveyed with nitrogen from storage
to the gasifier service bins. Controls regulate inter-
mittent feeding of coal to the feed bins. The bins
are connected to twin variable-speed coal screw
feeders. The coal is discharged into a mixing noz-
zle where it is entrained in oxygen and low-pres-
sure steam. The mixture is then delivered through
a transfer pipe to the burner head of the gasifier
The oxygen, steam, and coal react in the re-
fractory-lined steel shell gasifier at a slight positive
pressure, 5 to 7 psig. Reaction temperature at the
burner discharge is 3,300°F to 3,500°F. Gasific-
ation of the coal is almost complete and instanta-
neous. Carbon conversion is a function of the re-
activity of the coal, approaching 100 percent for
lignites. Low-pressure process steam for the gas-
ifier reaction is produced in the gasifier jacket
from the heat passing through the refractory
lining.
Ash in the coal feed is liquefied in the high
temperature zone. Approximately 50 to 70 per-
cent of the molten slag drops out of the gasifier
into a slag quench tank and is recovered for
disposal as a granular solid. The remainder of
the slag and all the unreacted carbon are en-
trained in the gas exiting the gasifier. Water sprays
quench the gas to drop the temperature below
the ash fusion temperature to prevent slag part-
icles from adhering to the tubes of the waste heat
boiler mounted atop the gasifier.
The raw gas from the gasifier passes through
the waste heat boiler where high-pressure steam,
up to 1,500 psig, is produced. After leaving the
waste heat boiler, the gas at 350°F is cleaned and
cooled in a high energy scrubbing system. The
system consists of a fixed venturi-type scrubber,
for removing the largest particles, 95 percent of
total, and a variable venturi-type scrubber for re-
moving more than 99 percent of the remaining
particles. The entrained solids in the gas are thus
reduced to 0.002 to 0.003 grains per SCF. Fol-
lowing scrubbing, the gas is cooled with water to
about 95°F in a packed cooler. If the gas is to be
compressed to high pressure for chemical syn-
thesis, electrostatic precipitators are used for
further cleaning. Several gasifiers can share
common cleaning and cooling equipment.
Particulate-laden water from the gas cleaning
and cooling system is piped to a clarifier. Clari-
fied water is recirculated through the venturi
35
-------
I
*LAO OUIMCM T/UM
Figure 5-1
KOPPERS-TOTZEK PROCESS SCHEMATIC
-------
Koppers-Totzek
scrubbers and the excess overflows into the cool-
ing tower system at the gas cooler. Sludge from
the clarifier is pumped either to a filter or to the
plant disposal area.
The cool, clean gas leaving the gas cleaning
system contains sulfur compounds which must
be removed. The type of system chosen depends
upon the end uses and desired pressure of the
product gas. For low pressures, up to 150 psig,
and industrial fuel gas applications, there are the
chemical reaction processes such as amine and
carbonate systems. At higher pressures, the
physical absorption processes such as Rectisol*,
PurisolR, and Selexol^ are used. The choice of
the process is also dependent upon the desired
purity of the product gas and the desired select-
ivity with respect to the concentrations of car-
bon dioxide and sulfides.
5.2 PROCESS ADVANTAGES
• Gasifier can accept all types of coal;
• No by-products, except sulfur, which require
additional processing are produced;
• The absence of tars, oils, naphthas, and phen-
ols in the raw gas simplifies control tech-
nology requirements;
• Gasifier can be started in 30 minutes and
can be shut down instantly, and restarted
in 10 minutes;
• Gasifier uses pulverized fuel, which elim-
inates rejection of fine coal particles;
• Gasifier has been reliably operated com-
mercially for many years.
5.3 PROCESS LIMITATIONS
• Operation with steam plus air requires high
air preheat and dilutes the product gas with
nitrogen; thus, this mode of operation is not
economical;
• Low operating pressure may be a disadvan-
tage for transmission of the product gas or
utilization in combined-cycle applications;
• Separation of high-temperature slag par-
ticles from the raw gas stream may be an
operating problem.
5.4 PROJECT HISTORY
The Koppers-Totzek Process was developed
commercially by Friedrich Totzek of Essen and
the Koppers Company, Inc. of Pittsburgh in 1949 fol-
lowing the successful operation of a 36 TPD coal
gasifier for the U.S. Bureau of Mines coal-to-oil
demonstration plant at Louisiana, Missouri, in
1948.
There are approximately 20 Koppers-Totzek
plants commercially operating around the world,
none of which are in the U.S. These plants pro-
duce a carbon monoxide/hydrogen synthesis
gas which is used in the synthesis of ammonia.
Of all coal-based synthetic ammonia plants
erected since 1945, more than 80 percent are
based on Koppers-Totzek Gasifiers. A pressur-
ized, single stage version of the Koppers-Totzek
gasifier is currently being planned for construction
in Hamburg, West Germany. The 150 TPD, 500
psi plant is scheduled for completion in 1977
followed by two to three years of testing. The
project cost is estimated at $25 million. The pro-
ject is a joint venture of Shell International Pet-
roleum Company, and Krupp Koppers GmbH.
An interesting new development of Heinrich
Koppers and Imperial Chemical Industries (I.C.I.),
Billingham, U.K., is a combined carbon monoxide
shift conversion and methanation unit. This unit's
reactor uses a nickel catalyst which simultaneous-
ly promotes both the shift and methanation re-
actions. Testing of this reactor on a pilot scale
has indicated that commercially acceptable life-
times for the catalysts can be expected. This
reactor will be installed in a Koppers-Totzek
demonstration plant in Germany to produce 2.6
MMSCFD of SNG from a coal feed of 145 TPD.
In the U.S., Northern Illinois Gas Company and
the State of Illinois are reportedly studying the Kop-
pers-Totzek Process for application at their pro-
posed 80 to 90 MMSCFD SNG demonstration plant
to be completed in Illinois in the early 1980's.
5.5 ENVIRONMENTAL CONSIDERATIONS
The effluents summary is presented in Figure
5-2.
37
-------
Koppers-Totzek
v,—
1
COAL
HOPPER
GASIFIER
AND
WASTE
HEAT
BOILER
WASH
COOLER
SLAG
QUENCH
CHAMBER
SETTLER
Figure 5-2
KOPPERS-TOTZEK PROCESS-EFFLUENTS SUMMARY
KOPPERS-TOTZEK PROCESS-EFFLUENTS
SUMMARY FOR FIGURE 5-2
Stream #
1
2
3
4
Description
Nitrogen vent
Slag
Slag slurry
Condensate
Coal Hopper
Effluents to the Air - The nitrogen vent stream
contains the nitrogen which is used to blanket
the coal feed bins in order to prevent explosions
of the fine coal particles. This stream will also
contain entrained coal dust participates, which
can be removed with filters, cyclones, or scrub-
bers prior to venting the nitrogen to the atmo-
sphere.
Liquid and Solid Effluents • No effluents are
discharged.
Casifier and Waste Heat Boiler
Effluents to the Air- No effluents are discharged.
Liquid and Solid Effluents - No effluents are
discharged.
Slag Quench Chamber
Effluents to the Air- No effluents are discharged.
Liquid and Solid Effluents - The slag stream is
composed of the larger slag particles formed
in the gasifier which were heavy enough to fall
to the bottom of the gasifier and into the slag
quench tank. The slag particles will consist of
the mineral matter present in the feed coal with
5 to 55 percent unreacted carbon. The slag
38
-------
Koppers-Totzek
may also contain any components present
in the slag quench water or in the raw gas. The
exact composition of the slag is dependent on
the composition of the feed coal and the gas-
ifier operating conditions. The slag is a solid
waste product which requires ultimate disposal.
In some instances, the granular slag may be
a salable by-product. Solid waste treatment
processes can be used for slag disposal.
Settler
Effluents to the Air- No effluents are discharged.
Liquid and Solid Effluents - The process con-
densate and gas-quenching liquor stream is
composed of the raw gas-scrubbing liquor plus
raw gas condensate from waste heat boilers
and indirect gas coolers. The overflow from
the slag quench tank is also added to this stream.
The slag particles which are removed from the
raw gas stream in the wash cooler are separated
from the process condensate in a settling tank,
but some slag particles may be carried along in
the process condensate stream. The other com-
ponents in this stream are the constituents of
raw gas which condense or dissolve in the quench
liquor. The components most likely to be pre-
sent in this stream are water, particulates,
ammonia, hydrogen sulfide, and trace ele-
ments. Water pollution control processes
can be used to remove these contaminants.
ifier in the raw gas. The slag particles are re-
moved from the product gas stream in the
direct quench wash cooler. The slag slurry is
separated from the process condensate and
gas-quenching liquor in a settling tank. The
slag particles in this stream have approximately
the same composition as the slag previously
described. The slag slurry may also contain
any of the components present in the raw gas,
the process condensate and gas-quenching
liquor, or the slag quench overflow. Solid
waste treatment processes can be used for
slag slurry disposal.
Wash Cooler
Effluents to the Air- Noeffluentsaredischarged.
Liquid and Solid Effluents - No effluents are
discharged.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
Sulfur recovery of about 97 percent can be
achieved with three stages in "straight through"
flow.
The slag slurry stream contains the smaller
slag particles which are carried out of the gas-
39
-------
6. LURGI PROCESS FOR COAL GASIFICATION
The Lurgi Process is a commercially proven,
high pressure dry ash gasification process for
manufacturing fuel gas and other by-products
from coal. The first gasification plant was de-
veloped in Germany in 1936.
6.1 PROCESS DESCRIPTION
The Lurgi Gasifier is a fixed-bed type gasifier
with a vertical cylindrical construction. It is a
high pressure gasifier, operating at 350 to 450 psig.
The main gasifier shell is surrounded by a water
jacket. Boiler feed water is circulated through
the jacket to recover heat escaping from the gas-
ifier shell. A coal lock hopper is mounted on top
of the gasifier to feed the coal, while a motor-
driven distributor is used to spread the incoming
coal evenly over the coal bed. A motor-driven
grate at the bottom of the gasifier is used to with-
draw the ash formed. The ash drops into an ash
lock hopper which is an integral part of the gas-
ifier.
Coal received from the stockpiles is crushed
and screened. The coal is transported to the gas-
ifier lock hopper by a system of belt conveyors.
Fines generated during the crushing and screening
must be removed to maintain bed porosity. They
are available for use in the plant or for export.
Steam and oxygen are introduced at the bottom
of the gasifier to effect the coal gasification re-
actions. The steam and oxygen are distributed
into the coal bed through the rotating grate. The
grate supports the coal bed and is continuously
rotated to assure a constant and even withdrawal
of the ash formed.
An alternative to oxygen is air, as shown in the
bottom half of Figure 6-1. When gasifying with
air, nitrogen in the air accompanies and dilutes
the final product. Because nitrogen does not
burn, the result is a gasifier product with a lower
Btu value than one produced by the oxygenated
Lurgi.
The following paragraphs describe the Lurgi
Process as it operated with oxygen. Most of the
steps which purify the gas to produce a higher
quality product (shift reaction, acid gas removal,
methanation), are not used with blown gasifiers.
With the latter, the gasifier product gas, after
minimal cleanup, goes directly to a power or
steam plant.
As the steam and oxygen pass upward, four
different zones in the coal bed can be identified
by the prevailing reactions and temperatures.
They are, from bottom to top, carbon combustion,
gasification, devolatilization, and drying. As the
coal descends through the bed, some volatile
matter in the coal is first removed, and the re-
maining carbon is then gasified and combusted.
The ash is withdrawn from the bottom of the
gasifier into the lock hopper and eventually sent
to disposal. Excess steam is added to the ash layer
just above the grate to prevent slagging of the ash.
Raw gas formed in the gasifier leaves from the
top and flows through a scrubber cooler, where
it is washed by circulating gas liquor. The gas
then passes through a waste heat boiler, where it
is cooled and low pressure steam is generated.
Condensate formed is subcooled and sent to a
tar/liquor separator. Gas leaving the waste heat
boiler is further cooled by three water-cooled
heat exchangers in series. A part of the condensate
recovered from this cooling is sent to the tar/
liquor separator, and the remainder is sent to an
oil/liquor separator.
Tar and the aqueous tar liquor are decanted in
the tar/liquor separator. Similarly, tar oil and the
aqueous oil liquor are decanted in the oil/liquor
separator. The tar liquor and oil liquor are then
combined and fed to a PhenosolvanR unit and
Chemie Linz-Lurgi (CLL) ammonia plant, where
crude phenols and anhydrous ammonia are re-
covered.
Gas from the final cooler is desulfurized in an
acid gas removal unit. By-product naphtha will
41
-------
Lurgi
SULFUR
PLANT
INCINERATOR
ELEMENTAL
ATMOSPHE
1
RAW ^i
WATER p
MAKE-UP WATER
-C> TO IN-PLANT
USERS
Figure 6-1
LURGI PROCESS SCHEMATIC
be recovered from the condensate collected in
a cooling step prior to acid gas removal. The
final product gas is a desulfurized medium-Btu
gas.
6.2 PROCESS ADVANTAGES
• Slagging operation increases process effi-
ciency and throughput rate over fixed-bed
nonslagging operation;
• Lower steam consumption reduces the vol-
ume of liquid wastes requiring treatment;
• High-pressure operation favors the formation
of methane in the gasifier and reduces gas
transmission cost. High pressure is advan-
tageous for utilization of the gas as a syn-
thesis gas or in a combined cycle;
6.3 PROCESS LIMITATIONS
• Coals with low ash content or with a high
percentage of refractory type ash may
require addition of ash fluxing agents;
• By-products require additional processing
for recovery;
• Process condensate and by-products require
additional processing for environmental
acceptability;
• Limited reactor size may necessitate use of
multiple units in parallel for large instal-
lations.
6.4 PROJECT HISTORY
The first full-scale Lurgi coal gasification plant
was constructed at Hirschfelde, Germany, in 1936.
42
-------
Lurgi
Since then, 19 commercial plants have been in-
stalled worldwide. Various bench and pilot scale
units have been erected to test various types of
coal and alternate gasifier designs. In 1946, bench
scale Lurgi Gasifiers of 4 inch, 6 inch, and 13.5 inch
I.D. were built at the Central Experimental Station.
of the U.S. Bureau of Mines to test Alabama
caking coals. Various other pilot plants have
been built in Germany over the years. A170 MW
combined cycle plant utilizing the Lurgi pressure
gasification system was tested in Lunen, Germany,
in 1973. A commercial 800 MW plant is planned
for start-up in 1980.
A number of American firms have announced
plans to use the Lurgi Process in proposed SNG
from coal plants. These include the El Paso Nat-
ural Gas Burnham project, ANG Coal Gasification
Company's North Dakota project, Western Gas-
ification Company (WESCO), Panhandle Eastern
Natural Gas Pipeline, Northern Natural Gas/Cities
Service Gas and a utility power gas project by
Commonwealth Edison. The licensor in the U.S.
is the American Lurgi Corporation, Hasbrouck
Heights, New Jersey.
6.5 ENVIRONMENTAL CONSIDERATIONS
Since there are no Lurgi installations presently
operating in the U.S., detailed information on
operating procedures is often incomplete. Where
operating procedures could affect the generation
of effluents, it is necessary either to use engi-
neering judgment in assuming a'particular mode
of operation or to consider more than one alter-
native procedure. EPA has proposed New Source
Performance Standards for sulfur dioxide and
non-methane hydrocarbon emissions from Lurgi
high-Btu gasification processes. The effluents
summary is given in Figure 6.2.
Coal preparation
Since coal preparation is common to all coal
conversion plants, a general discussion is given
in Appendix B.
Gasification
Effluents to the Air - There will be no direct
discharge to the environment from the gasifier
section which might suggest modifications to
the actual process equipment. The most ef-
fective form of emission reduction would in-
volve the improvement of "downstream"
pollution control equipment.
Liquid and Solid Effluents - No effluents will
be discharged.
Fuel gas production
The fuel gas burned to provide steam, elec-
tric power, and air compression for the plant
will be obtained from a process train consist-
ing of 10 air-blown Lurgi Gasifiers.
Effluents to the Air - All process streams and
major waste streams will exit the area for pro-
cessing and separation; none will be discharged
to the environment at this point.
The steam-ash stream generated by the ash
quench will initially be routed to a wet cyclone
for removal of larger clinkers carried by the
stream. The remaining material will be sent
to a cooling-water condenser where stream
will be condensed and returned to the ash trans-
fer sluiceway. It is expected that almost all of
the fine ash particles wilt remain in the con-
densate. The fate of the non-condensable gases
is not known.
Liquid and Solid Effluents - No effluents will
be discharged.
Feed lock hoppers
In the Lurgi Process, coal is fed to the gasifier
in a cyclic operation using a pressurized hopper.
The pressurizing gas must be vented each time
the feed lock hopper is recharged. Normal charg-
ing frequency is 15 to 30 minutes.
43
-------
Lurgi
11 ?
COAL
PREPARATION
_ COAL LOCK
HOPPERS
\ i
FIIFI GAS ^
PRODUCERS
?-
POWER & STEAM
PLANT
Tj
OXYGEN
PLANT
ri
1 '
BY-PRODUCT
STORAGE
i
(?) VARIOUS
SOURCES
ASH WATER -»-(TT)
DISPOSAL, TREATMENT ^
M - j
(J2) * * ©
^ ASH BY-PRODUCTS
Figure 6-2
LURGI PROCESS-EFFLUEh
^^
-^ SHIFT
GASIFIERS REACTION
1 ' '
GAS LIQUOR , GAS
TREATMENT COOLING
1
r
SULFUR ACID GAS
RECOVERY REMOVAL
i { \
© © ® VARIOUS
SOURCES
)
_ , , MCTIIAI
PLANT
HARE ' '
(j^) PRODU
4TS SUMMARY
NATION
1
CT GAS
44
-------
Lurgi
LURGI PROCESS-EFFLUENTS SUMMARY
FOR FIGURE 6-2
Stream #
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Description
Fugitive dust
Coal refuse
Hopper vent
Exhaust stack
Nitrogen
Sluice vent
Tank vents
Stretford
Off-gas
Incinerator
Evaporation
Ash
Cooling loss
Flare gas
Effluents to the Air - Since the major control
methods for feed lock hopper vent gases will
consist of variations in process design which
have not been tried, it is perhaps misleading
to talk about proven methods. The discussion
in this section, however, will address design
variations which are believed to have no known
technical problems. Several choices are avail-
able both for the source of the pressurizing
gas and for the disposition of the gas when
venting the lock hopper.
Among the choices which might be considered
for a gas source are (1) raw crude gas, (2) clean
crude gas, (3) product gas, (4) RectisolR vent
gas, and (5) nitrogen from air plant. Any of these
sources could provide sufficient quantities of
gas chemically compatible with the coal in the
lock hopper. Use of nitrogen or incinerator
tail gas can probably be disqualified because
it would introduce nitrogen into the product
gas stream. The use of any slip-stream from the
product gas flow, whether raw crude, clean
crude, or final product gas, will result in some
emission of this gas, even if most of it is recycled.
On the other hand, if carbon dioxide from the
RectisolR vent is used, this is a stream which
is vented anyway, so total emissions may not
be changed appreciably. All process equipment
between the gasif ier and the bleed point must
be sized to handle the approximately 30 per-
cent of lock gas which will pass into the gas-
if ier with the coal feed. Therefore there is an
economic incentive to locate the bleed point
as close to the gasif ier as possible. If RectisolR
vent gas is used, then all equipment through
the carbon dioxide absorption train must be
oversized. Another economic factor is that
bleeding from a high pressure stream rather
than a low pressure stream will reduce compres-
sion costs.
In disposing of the feed lock hopper vent
gases, at least four alternatives are available:
(1) recycling, (2) venting to atmosphere, (3) use
as plant fuel gas, and (4) incineration. Not all
disposal options could be combined with every
source option. For instance, if the source is
carbon dioxide vent gas, it would obviously be
impossible to dispose by burning as fuel. The
ultimate choice must be based on considerations
involving the rest of the plant design. For
instance, if gas is being burned as a plant fuel
then passing a slip-stream through the lock
hopper before burning will not increase overall
plant emissions. In this case, recycle compres-
sors are not needed. If fuel gas, either crude or
cleaned, is chosen to pressurize the lock hopper,
there will be an economic incentive to recover
the majority of the gas by either recycling or
using as fuel, so that direct venting is unlikely.
If carbon dioxide is used, then direct venting
may be acceptable because this gas would be
vented anyway. In the El Paso design, (250
billion Btu/day), the low-Btu lock hopper vent
gas will be injected into the low pressure Stret-
ford unit which processes acid gas from the
RectisolR unit. This will automatically provide
a clean fuel to fire the off-gas incinerator.
Although most of the feed lock hopper gas
can be collected and disposed of by one of the
options discussed, there will be a residuum of
gas in the hopper when it is opened to receive
a new coal charge (the hopper cannot be evac-
uated, it can only be bled down to some pressure
slightly above atmospheric). During the coal
transfer this residual gas will be displaced
equal to the volume of coal being loaded.
45
-------
Lurgi
Several plant designs have discussed the use of
exhaust hoods and vent fans on the gasifier
to prevent local escape of these gases. This
type of control does not affect the net release
to the environment unless the collected gases
are then incinerated. The amount of gas escap-
ing in this way should be only about 3 percent
of the pressurant requirements. In the WESCO
design (also a 250 billion Btu/day), it was stated
that these gases would be collected by exhaust
fans and vented from stacks, 150 to 300 feet
high. The flow would be 99.5 percent air at a
rate of 2,935 TPD. Estimated hydrogen sulfide
concentraion was 5 to 10 ppm. If either clean
crude gas or carbon dioxide from the Rectisol*
vent is used, the hydrogen sulfide level should
be much lower. There may be some hydrogen
sulfide in the vent stream. The amount of any
such blowback is impossible to estimate.
Localized control of vent gases from the ash
lock quenching and ash-dumping operations
can be accomplished also by hoods and exhaust
fans. The exhaust fans for both the coal lock
and the ash lock can be equipped with wet cy-
clone scrubbers to reduce particulate concen-
trations before being vented from stacks. The
WESCO Environmental Impact Statement (EIS)
contained an estimate of particulate emissions
from the lock exhaust fans with cyclone scrub-
bers which amounted to only 0.1 Ib/hr for the
the coal lock and 0.2 Ib/hr for the ash lock.
Most of the control methods discussed are
actually process modifications rather than end-
of-pipe methods of treatment. Additional mod-
ifications which could be developed would in-
clude the feeding of the exhaust vent streams
to the intake air for air-blown gasif iers, gas tur-
bines, or steam boilers. Since the potential
emissions involved are so small to begin with,
there is little incentive to spend effort in inves-
tigating such modifications.
It is apparent that total venting of lock hop-
per gases could be a significant source of
emissions if the gas is obtained from an internal
process stream. All designs utilizing such inter-
nal streams should require either recycling or
routing to a pollution control unit.
Liquid and Solid Effluents - No effluents will
be discharged.
Ash Lock Hoppers
Ash will be discharged from the bottom of the
gasifier through a lock hopper which must be
vented. Ash hopper discharge cycles will take
about 20 minutes.
Effluents to the Air- Ash will be discharged from
the bottom of the gasifier in a sequence of
operations similar to that for the feed lock
hopper. First the top ash lock cone valve is
closed, isolating the ash lock chamber. High
pressure gases in the ash lock at this point
are mainly steam. The chamber is vented to a
close-coupled direct contact condenser, where
the steam is condensed with a water spray. The
bottom ash lock valve is then opened, and the
ash falls out. After the ash is dumped, both
cone valves are closed, and the ash lock cham-
ber is repressurized with steam. The top ash
lock valve is opened, and ash flow from the pro-
ducer is re-established.
As in the case of the coal feed lock hopper,
it is possible that a different operating proce-
dure could be used in which the ash lock cham-
ber is not repressurized before reopening the
valve to the gasifier vessel. In that case gases
from the gasifier would flow into the ash lock
hopper. Venting of the ash hopper on the next
cycle could then result in the emission of some
of these gasifier gases.
Liquid and So//d Effluents - Several variations
are possible in handling the ash as it drops from
the ash lock chamber. In one design, the ash
drops into circulating "mud water" in an ash
quench chamber directly below the ash lock.
In the El Paso design the ash will apparently be
discharged dry at about 360°F into a sluice
launder where it will be completely quenched
and flushed away by a water stream. Since the
gasifier bottom temperature will be around
900°F, it is assumed that partial cooling is
accomplished by water spray before dropping
into the sluice launder. Steam generated in the
quenching will be condensed either in the direct
46
-------
Lurgi
contact condenser coupled to the ash lock
valve or in a condensing vessel above the sluice
launder. To cool the ash from 900°F to 360°F,
assuming a specific heat of 0.2, would require
approximately 49,000 Ibs of water per hour.
During the ash quenching, large amounts of
ash dust will be generated and entrained in the
steam passing to the condensers. Some non-
condensable gases may be generated also by
reaction between unburned char and steam or
by thermal cracking of organic contaminants
in the quenching water. The water spray in the
condenser will provide a wet scrubbing action
to remove most of the ash dust from the non-
condensable gas which must be vented. Esti-
mated flow rate is 477,000 Ib/hr as ash. Approx-
imately 64,000 Ib/hr of water will be flashed to
steam in the two-step quench process. No
information is available for estimating the
amount of non-condensable gases formed or
the amount of particulates carried by this stream.
Shift Conversion
Effluents to the Air - Fugitive air emissions are
inevitable in any process which contains fit-
tings, valves, flanges, etc. The high pressure en-
countered in the shift reaction section tends to
increase the likelihood of having fugitive
emissions. While fugitive emissions cannot be
completely eliminated, the use of best avail-
able technology coupled with good mainten-
ance practices will help to minimize these
emissions.
The shifted gas will be processed in other
sections to remove tars, tar oils, phenols, am-
monia, and sulfur compounds. These processing
areas will provide adequate control for this
stream.
Liquid and Solid Effluents - The process con-
densate stream will be recycled to the gas
production section where it will be combined
with other condensate streams for use as gas-
ifier effluents quench liquor.
The blowdown stream from the waste heat
boiler will be used as makeup water to the plant
cooling system. Since the boiler will operate
at a relatively low number of cycles of con-
centration, the dissolved solids content of the
blowdown stream will be relatively low and
will not represent an environmental problem.
The control methods for spent catalyst are
not fully developed at this time because of the
lack of knowledge about its makeup. If the
catalyst does not have value sufficient to
justify regeneration, the most likely disposal
method will be as landfill. However, if the
catalyst is sufficiently toxic to warrant more
elaborate treatment, some of the methods em-
ployed for nuclear or hazardous solid waste
disposal could be adopted.
Gas Cooling
The gas-cooling section of the Lurgi Coal Gas-
ification Process takes shift-reactor effluent gas
and crude gas from the gas production section
and cools them in separate but similar cooling
trains. The system of coolers is designed to re-
cover a significant portion of the useful energy
content of the gas streams.
The gas-cooling section will not discharge any
effluent stream, with the exception of fugitive
emissions, directly to the environment. Instead,
these streams will be directed to other processing
areas for treatment or reuse.
Effluents to the Air - Fugitive air emissions are
inevitable in any process which contains fit-
tings, valves, flanges, etc. The high pressures
encountered in the gas-cooling section tend to
increase the likelihood of having fugitive
emissions. While fugitive emissions cannot be
completely eliminated, the use of best avail-
able technology, such as mechanical seaJs on
pumps, and good maintenance practices can
help to minimize these emissions.
Uquid and Solid Effluents -""The blowdown
streams from the waste heat boilers will be
collected and used as makeup water to the
pilot cooling system. Since the boilers will
operate at a relatively low number of cycles
of concentration, the dissolved solids content
of these blowdown streams will be relatively
47
-------
Lurgi
low and will not constitute an environmental
problem.
Acid Gas Removal
In the gas purification section the Rectisol IR
Process will be used to remove acid gases such
as carbon dioxide, hydrogen sulfide, carbonyl
sulfide, carbon sulfide, mercaptans, etc., from
inlet gas streams by physical absorption of these
acid gases in a methanol solvent.
Effluents to the Air - Fugitive air emissions from
the Rectisol IR acid gas removal process arise
from leaks around pump seals, valves, flanges,
etc High pressures in this process enhance
fugitive leaks from equipment. The compositions
of these fugitive emissions would be a mixture
of any of the various components found in the
process streams.
The gas streams generated in the prewash
flash and in the main flash regenerators will
comprise primarily carbon dioxide, about 98
percent by volume, with smaller amounts of
carbon monoxide, hydrogen, methane, ethylene,
ethane, hydrogen sulfide, and carbonyl sulfide.
The amounts of these compounds present will
depend upon the composition of the raw gas
from the gasifier and the operating parameters
of the Rectisol IR Process, such as absorber
temperature and pressure. The presence of
sulfur compounds necessitates further treat-
ment of this stream. The method will depend
upon several factors, including the amounts
and types of sulfur compounds present.
The off-gases from the hot regenerator will
comprise carbon dioxide, carbon monoxide,
hydrogen, methane, hydrogen sulfide, and
carbonyl sulfide. The concentration of hydro-
gen sulfide will be higher in this stream, about
13 percent by volume, than in the flash gases.
The concentration of the other components
will depend primarily upon operating para-
meters such as the flash regeneration pressure.
This stream may also contain substantial amounts
of methanol, depending upon the product gas
(overhead) temperature and the pressure of the
hot regenerator. This gas stream is sent to the
sulfur recovery section.
The gases released during the first stage of
flash regeneration will comprise carbon di-
oxide, carbon monoxide, methane, ethylene,
ethane, hydrogen, and some nitrogen and argon.
Since this stream will contain high concen-
trations of desirable gases, it will be recombined
with the cooling section product gas upstream
of the acid gas removal section.
The product gas exiting the RectisolR Process
will comprise carbon monoxide, hydrogen,
methane, ethylene, ethane, and, depending
upon the required product specification, pos-
sibly small enough amounts of carbon dioxide,
hydrogen sulfide, and carbonyl sulfide and
organic sulfur. This gas stream will be sent to
the methanation section for conversion into
substitute natural gas (SNC).
The by-product naphtha stream will comprise
C^-Cg (predominantly aromatic) hydrocarbons
removed in the prewash. This stream, which
may also contain small amounts of dissolved
acid gases, ammonia, and phenols, will be sent
to a by-product storage facility.
Liquid and Solid Effluents - The process con-
densate, from the methanol/water still, will
comprise primarily the water in the feed gas
and the water used in the naphtha extraction
operation. This stream will be sent to the
wastewater treatment section.
Methanation
The only important stream leaving this area
will be the 629 gpm of water produced in
methanation.
Effluents to the Air - This water stream will con-
tain a total of 69 Ibs/hr of methane and carbon
dioxide. Release of this gas to the atmosphere
should not cause any problem.
Catalyst dust can be controlled by dumping
the catalyst into water and using a bag filter
at vent locations. In some catalyst systems, it
may be possible to regenerate catalyst without
removing it. In that case, absorbed impurities
will be released to the atmosphere. However,
48
-------
Lurgi
the amount and frequency of discharge of
these pollutants are going to be very small.
Start-up and shut-down will require special
precautions so the carbon monoxide does not
come in contact with nickel below 300° F, thus
avoiding the formation of highly toxic nickel
carbonyl. During shut-down, vent gases will
either be recompressed for later use in process
or be sent to the fuel-burning section of the
plant to be used as fuel.
To minimize leakage, a tight system must be
specified and then maintained properly. Pump
and compressor seals are potential sources of
leakage and need special attention.
Liquid and So//d Effluents - After the atmosphere
strips methane and carbon dioxide from the
main water stream, the clean water can be used
as soft water in the plant.
Two other small streams of water, about 1
gpm each, containing traces of methane and
glycol can be dumped into the ash system.
Gas Liquor Treatment
The streams leaving the main Lurgi Gasifier and
the fuel gas gasifier will be produced at a rate of
100 TPH. The chemicals contained therein can be
treated or recovered and subsequently utilized.
Some of the streams will require primary and
secondary treatment. Primary treatment will
control or recover pollutants; it will not be re-
quired in the production of SNC. Secondary treat-
ment will control pollutants resulting from the
primary treatment.
Effluents to the Air - Flashed gases containing
mostly carbon dioxide, hydrogen sulfide, water,
and small amounts of tar products will be sent
to the sulfur recovery section after having
been scrubbed with water.
Liquid and Solid Effluents - Gas liquors will be
sent to phenol extraction and then to ammonia
recovery.
Tar and oil streams will be sent to the stor-
age area.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
Sulfur balance is given in Table 6-T.
Table 6-1
LURGI PROCESS SULFUR BALANCE
Sulfur product
Tar and tar oil naphtha
Naphtha
Ash
Incineration
Power plant
percent
89.4
1.7
0.1
1.4
5.8
1.6
100.0
49
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7. SLAGGING/LURGI GASIF1ER
The Slagging/Lurgi Gasifier is being developed
by the British Gas Corporation, London, England,
and the Lurgi MineralO technik GmbH, Frankfurt,
Germany. The process function is high pressure
coal gasification in a gravitating bed by injection
of steam plus oxygen with countercurrent gas/
solid flow. The Slagging/Lurgi Gasifier Process
offers higher operating capacity than does the
"dry bottom" version of the Lurgi Process. De-
velopment work is currently being conducted at
the Westfield Development Centre, Westfield,
Scotland. A demonstration plant in Westfield has
been in operation since 1976.
In the U.S., a test plant in slagging, fixed-bed
gasification is being operated by ERDA's Grand
Forks Research Center, Grand Forks, North Dakota.
ERDA has also awarded $24 million to Continental
Oil Company, Stamford, Connecticut, for design
of a high-Btu gas plant in Noble County, Ohio.
7.1 PROCESS DESCRIPTION
7.2 PROCESS ADVANTAGES
• Process efficiency: Slagging operation in-
creases process efficiency and throughput
rate (by two to four times) over fixed-bed
nonslagging operation;
» Steam consumption/conversion: Operation
at slagging temperatures reduces steam con-
sumption and increases steam conversion;
• Environmental considerations: Lower steam
consumption reduces the volume of liquid
wastes requiring treatment;
• Operating pressure: High pressure operation
favors the formation of methane in the gas-
ifier and reduces gas transmission cost. High
pressure is advantageous for utilization of
the gas as a synthesis gas or in a combined
cycle;
• Fuel size: Coal fines may be injected into
the gasif ier through the steam/oxygen tuyeres;
• Reactor size: Small reactor size may be ad-
vantageous for small-scale industrial ap-
plications,
Fixed-bed gasification, as exemplified by the
Lurgi Process, is basically a thermally efficient
system. The feed coal is heated by heat exchange
with the exit product gases and vapors which
are cooled and leave the system at moderate
temperatures, see Figure 7-1. Similarly, the enter-
ing gasifying agents (steam and oxygen) are pre-
heated by heat exchange with the ash which, on
leaving the combustion zone stripped of carbon,
is cooled from the high temperature which pre-
vails in the gasification zone. Essentially, 90
percent of the potential heat in the coal supplied
leaves as potential heat in the gas and liquid
products of gasification.
The chief differences between the "dry bottom"
Lurgi and the slagging gasif ier are higher operating
temperatures and operation under slagging con-
ditions.
7.3 PROCESS LIMITATIONS
• Coal type: Coals with low ash content or
with a high percentage of refractory-type
ash may require addition of ash-fluxing
agents;
• Gasification media: Operation with steam
plus air will not provide hot enough temp-
eratures for slagging operation;
• By-products: By-products require additional
processing for recovery;
• Environmental considerations: Process
condensate and by-products require addi-
tional processing for environmental ac-
ceptability;
• Reactor size: Limited reactor size may
necessitate use of multiple units in paral-
lel for large installations;
• Development status: Gasifier has only been
operated on a pilot-plant scale.
51
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ro
Ft t a water
4-Stage
condensor
-o
T
Meter Liquid
effluent samples
Oxygen
Steam
Quench water In
JO
B.
90
Flare stack
Ga» liquor receiver
(mm pressure)
Go; mfier
Condensale receiver
Slag
Figure 7-1
GRAND FORKS SLAGGING GASIFICATION PILOT PLANT PROCESS SCHEMATIC
-------
Slagging/Lurgi
7.4 PROJECT HISTORY
A pilot slagging gasif ier was developed at the
British Gas Midlands Research Station (MRS) at
Solihull, England, during the period 1955-1964
and followed a detailed study of the reactions
occurring at a pilot Lurgi-type gasifier. All this
work is well documented. The work was suspend-
ed at a stage at which further useful development
could only be continued on a larger scale under
conditions which allowed continuous operation
of several months rather than several days duration.
At that time, in 1963-1964, Westfield had been
mentioned as a possible site but any chance of
following this up was overtaken by the discovery
of natural gas under the North Sea. Research and
development programs on coal were terminated
and eventually the MRS pilot plant was dismantled.
The gasifier was still of interest in the U.S.
because it is a fixed-bed type and represented
continued development of the Lurgi Gasifier.
The Westfield Lurgi gasification plant of the
British Gas Corporation has been used by a con-
sortium of U.S. gas, oil, and pipeline companies
led by the Continental Oil Company. Their pur-
pose was to demonstrate the production of SNG
from coal-based synthesis gas. The plant was
also used by the AGA to test the gasification of
a series of U.S. coals in the Lurgi Gasifier. The
two programs were successfully completed.
On the initiative of the Continental Oil Company
and with the full support of British Gas, who re-
cognized the potential international value of the
Westfield plant as a gasification development
and demonstration center, a program for the
development of the slagging gasifier to com-
mercial status was.put up for sponsorship. As a
result, a project to convert one of the Westfield
Gasif iers to slagging operation and undertake its
development according to a three-year program
was initiated under the sponsorship of the 15
American companies listed in Table 7-1. In addition,
by agreements signed with British Gas, the Lurgi
Company of Frankfurt joined the project and is
collaborating fully in the development work.
A gasifier incorporating British Gas and Lurgi
technology will be licensed by British Gas on be-
half of the sponsors who will receive a share in
the license fees.
Table 7-1
UNITED STATES COMPANIES
SPONSORING THE WESTFIELD SLAGGING
GASIFIER PROIECT
Cities Service Gas Company/Northern
Natural Gas
Continental Oil
Electric Power Research Institute
El Paso Natural Gas
Gulf Energy and Minerals
Michigan Wisconsin Pipe Line
Natural Gas Pipeline
Panhandle Eastern Pipe Line
Southern Natural Gas
Standard Oil of Indiana
Sun Oil
Tennessee Gas Pipeline
Texas Eastern Transmission
Transcontinental Gas Pipeline
This new gasifier will complement the "dry bot-
tom" Lurgi Casifier by making the less reactive
coal with low fusion point ash suitable for fixed-
bed steam and oxygen gasification at high pres-
sure. The standard Lurgi Gasifier is better suited
to handle the high fusion point, high ash content,
high reactivity coals which can be gasified at high
load with low steam-oxygen ration.
Coals with refractory ash present in quantities
in excess of 15 percent, particularly if accompanied
by high moisture contents, are less suitable for
slagging conditions. While the advantages of high
output from a slagging gasifier remain unimpaired
and refractory ash can be accommodated by the
addition of fluxes, high ash, high moisture coals
can lead to problems in the top of a slagging gas-
ifier. The top of the gasifier may be insufficient
in heat to drive off the moisture and distill the tar.
Much product gas with low heat capacity is present
as a consequence of the inherent high gasification
efficiency of slagging operation. These problems
can be overcome by injecting fuel (such as coal
fines or tar, etc.) at the tuyeres but at some cost
in lower efficiency and higher oxygen consump-
tion.
53
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Slagging/Lurgi
Highly suited to slagging operation are coals
of low or high reactivity if they have the following
properties: either less refractory ash or refractory
ash present in quantities less than about 15 per-
cent by weight; and moisture contents not in
excess of about 20 percent by weight. Full bene-
fit can be derived from increased gasifier output,
low steam consumption, low aqueous liquor pro-
duction, and higher gasification efficiency leading
to lower gas production costs. Thus, one sees a
future of both.gasifiers complementing each other.
The Grand Forks Energy Research Center oper-
ation has as its goals the establishment of a data
base and investigation of processes for treating
effluents. The program began in April 1977 and
will run two years.
ERDA's $24 million award to Continental Oil
Company for design of a facility in Noble County,
Ohio, will also involve a consortium of pipe-
line companies, monitoring the 22-month design
phase. The consortium will then decide on par-
ticipation in construction and operating costs.
7.5 ENVIRONMENTAL CONSIDERATIONS
Since the Slagging/Lurgi Casifier closely re-
sembles "dry bottom" Lurgis, the only unique
characteristic is slag removal and treatment. The
actual operation of the slag tap is proprietary.
The effluents summary is presented in Figure 7-2.
Coal Preparation
Since coal preparation is common to all coal
conversion plants, a general discussion is given
in Appendix B.
Coal Lock Hopper
Effluents to the Air - The composition of the
coal lock gas stream will be determined by the
mode of pressurizing the coal lock. Various
operating procedures and sources of pres-
surizing could be used. Prior to dumping the
coal from the lock into the gasifier, the lock
may be pressurized to the gasifier operating
pressure with a stream of cooled raw gas or
with a vent stream from an acid gas removal
process. If the pressurizing gas is added con-
tinuously as the coal dumps into the gasifier,
the gas remaining in the lock will have approx-
imately the same composition as the pressuriz-
ing gas. If no gas is added as the coal is dumped,
raw gas from the gasifier will back-flow into
the lock as the coal falls into the gasifier, and
the gas remaining in the lock will be composed
of pressurizing gas and raw gas from the gas-
ifier. If no pressurizing gas is used, the lock
will fill with raw gas as the coal is dumped into
the gasifier, and the gas remaining in the lock
will be composed of raw gas. For any of these
cases, as raw gases pass countercurrently
through the incoming coal and into the lock,
some tars, oils, water and other constituents
of the raw gas may condense or be adsorbed
on the coal feed. In addition to the components
in the raw gas and the lock-filling gases, the
coal lock gas stream may also contain en-
trained coal fines. In order to prevent the
release of these contaminants to the atmosphere,
this stream may be recycled to the raw gas
stream, or it may be incinerated in a flare or
boiler If gaseous contaminants in this stream
are relatively low in concentration, the stream
may be passed through wet cyclones to remove
particulates, and then vented to the atmosphere.
The gas which remains in the lock after de-
pressurization will be displaced by the incoming
coal charge. This gas can be controlled by the
same methods described previously, but hoods
and vent fans would be required to collect
the gas.
Liqu/d and Solid Effluents - No effluents will
be discharged.
Gasifier
Effluents to the Air - No effluents will be dis-
charged.
Liquid and Solid Effluents - No effluents will
be discharged.
Slag Lock Hopper
Effluents to the Air - No effluents will be dis-
charged.
54
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Slagging/Lurgi
Figure 7-2
SLAGGING/LURGI PROCESS-EFFLUENTS SUMMARY
SLAGGING/LURGI PROCESS-EFFLUENTS
SUMMARY FOR FIGURE 7-2
Stream # Description
1 Lock hopper vent gas
2 Slag and water
3 Vent gas
4 Slowdown
5 Vent gas
6 Steam
7 Condensate
Liquid and Solid Effluents - The slag slurry con-
tains slag particles and slag quench water. The
slag quench water in the slurry will have the
same composition as the slag quench blow-
down. The slag is composed of the mineral
matter in the feed coal with approximately 1
percent unreacted carbon plus any ash-fluxing
agents added to the feed coal. The exact
composition of the slag is dependent on the
composition of the feed coal and fluxing agents
(if used) and the gasif ier operating conditions.
Suspended solids removal processes can be
used to dewater the slag slurry. The recovered
water could be recycled to the process con-
55
-------
Slagging/Lurgi
densate and the gas-quenching liquor. The
dewatered slag or slag slurry is a solid waste
product which requires ultimate disposal using
known techniques.
Separator
Effluents to the Air- The slag lock gas stream is
created when the slag lock is depressurized in
order to discharge the slag slurry. This stream
may contain components in the raw gas from
the gasifier which have dissolved in the slag
quench water, steam, entrained slag particles,
and any volatile components in the slag quench
makeup water. Depending on the composition
of the slag lock gas, it may first be passed
through a cyclone to remove particulates and
then vented to the atmosphere, or it may be
incinerated in a flare or boiler.
Liquid and Solid Effluents - The slag quench
blowdown stream will be composed of the slag
quench water which is removed from the slag
lock prior to removal of the slag slurry. This
stream will also contain condensate from the
slag quench vent gas/liquor separator. The slag
quench blowdown may contain any of the com-
ponents present in the raw gas from the gas-
ifier or in the quench water makeup. This stream
may also contain entrained slag particles. The
concentrations of contaminants in this stream
will determine the control technology used.
It may also be sent to disposal in evaporation
ponds which will result in emissions to the
atmosphere of all volatile components in the
stream. This stream may also be treated by
water pollution processes.
Gas/Water Separator
Effluents to the Air - The composition of the
slag quench vent gas stream will be determined
by the mode of operation of the slag tap. If the
slag is tapped intermittently by preventing slag
flow with a slag burner, the slag quench vent
stream will be created when slag is removed
from the gasifier by swinging the slag burner
aside and by opening the slag quench vent to
create a positive pressure differential across
the slag tap hole. For this case, the slag quench
vent stream will be composed of combustion
products, raw gas from the gasifier, steam, en-
trained slag particles, and any volatile com-
ponents in the slag quench makeup water.
This gas stream may first be passed through a
cyclone to remove particulates, or it may be
incinerated directly in a flare or boiler. If the
slag is tapped continuously, a slag quench vent
stream will not be present.
Liquid and Solid Effluents - No effluents will
be discharged.
Wash Cooler
Effluents to the Air - No effluents will be dis-
charged.
Liquid and Solid Effluents - The raw gas scrub-
bing liquor is combined with raw gas conden-
sate from the waste heat boiler.
Waste Heat Boiler
Effluents to the Air - The only effluent released
to the air is steam.
Liquid and Solid Effluents - The process con-
densate and the gas quenching liquor will be
composed of water plus the constituents of
the raw gas which condense or dissolve in the
quench water. The components most likely
to be present in this stream are water, tar,
tar oil, naphthas, crude phenols, coal fines and
ash, ammonia, hydrogen sulfide, organic sulfur
compounds, cyanide, thiocyanates, and trace
elements. The amounts of these components
will depend on the raw gas composition and the
gas quenching and cooling processes used.
Water pollution control processes exist that
can be used to remove these contaminants.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given in
Appendix A.
Sulfur Balance
Sulfur balance data are not available.
56
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8. SYNTHANE PROCESS
The Synthane Process, developed by the U.S.
Bureau of Mines, is being tested on a pilot plant
scale by ERDA. The government-owned plant is
being operated by the Lummus Company and is
located in Allegheny County, Pennsylvania.
Funding for the project is set at $24 million.
8.1 PROCESS DESCRIPTION
A key feature of the Synthane Process is that
pretreatment of caking coals is integrated with
gasification. Another feature is that gas with a
high methane content is produced directly. A
schematic of the Synthane Process is provided
in Figure 8-1. There are four major steps in the
process: (1)coal pretreatment, (2) coal gasification,
(3) shift conversion and purification, and (4) meth-
anation.
Coal, crushed to -20-mesh, is dried, pressurized
to approximately 70 atm, and transferred into the
fluidized-bed pretreater by means of high pressure
steam and oxygen. Pretreament provides a mild
oxidation of the coal particle surface so that cak-
ing coals will not agglomerate in the gasifier. The
coal overflows from the pretreater into the top
of the fluidized-bed gasifier about 10 feet above
the bed level, falls through hot gases rising from
the fluidized-bed, and is devolatilized. This
devolatilization contributes significantly to the
methane yield. Steam and oxygen enter the gas-
ifier just below the fluidizing gas distributor. The
gasification reaction occurs within the fluidized-
bed. Unreacted char flows downward into a bed
fluidized with steam and water sprays and is
removed through lock hoppers. This char can then
be burned to produce process steam. This product
gas, containing methane, hydrogen, carbon mon-
oxide, carbon dioxide, ethane, and impurities, is
passed through a venturi scrubber and a water
scrubber to remove carryover ash, char, and tars.
The concentration of hydrogen and carbon mon-
oxide in the gas is then adjusted to a 3:1 mole
ratio in a shift converter. The acid gases are
adsorbed in a hot potassium carbonate scrubber.
Carbon dioxide is reduced to 2 percent volume,
and sulfur is reduced to 40 ppm. Regeneration
of the potassium carbonate solution produces a
hydrogen sulfide-rich gas which is converted to
elemental sulfur by the Stretford Process. The
remaining traces of sulfur in the product gas are
removed by passing the gas through activated
charcoal. The purified gas must then be reacted
catalytically to convert the hydrogen and carbon
monoxide to methane.
8.2 PROCESS ADVANTAGES
• Caking coals .can be used directly as can a
wide range of other coals, including lignite;
• Hydrocarbons released during pretreatment
are used within the system, thereby maxi-
mizing the efficiency of coal conversion to
gas;
• More than half of the methane is produced
directly in the gasifier. By maximizing meth-
ane production in the gasifier, oxygen re-
quirements are reduced. Therefore, the
investment for an oxygen plant is lower, and
the sizes of all process vessels downstream
from the gasifier are reduced by 30 to 50 per-
cent, compared to processes in which the
raw gas from the gasifier contains little or no
methane. The process flow system and
equipment are relatively simple.
8.3 PROCESS LIMITATIONS
Char is produced which must be utilized for
steam production in an environmentally
acceptable manner;
Some tars and oils are produced which must
be disposed of or utilized;
More economical feeding methods than
the currently used lock hopper must be de-
veloped.
57
-------
Figure 8-1
SYNTHANE PROCESS SCHEMATIC
-------
Synthane
8.4 PROJECT HISTORY
The Synthane Process was developed by the
U.S. Bureau of Mines at the Pittsburgh Energy
Research Center, Bruceton, Pennsylvania. De-
velopment work started with scattered research
in several areas. In 1961, work was started on
methods of pretreating caking coals in fluidized
beds. A preliminary design contract was awarded
to M. W. Kellogg Company in August 1970 to de-
termine if the data were sufficiently complete to
proceed with design of the pilot plant. The con-
tract was extended for additional gasifier tests and
further evaluation of the Synthane project. Based
on the results of the gasifier tests and the eval-
uation, the U.S. Bureau of Mines concluded that
the process was feasible and the design could
begin.
In June of 1971, a contract was awarded to
Lummus for obtaining process information and
designing the pilot plant. The contract was mod-
ified several times to increase its scope to in-
clude rating and sizing heat exchangers, purchasing
equipment, preparing a bid package, preparing a
final report, additional engineering, inspecting,
and control monitoring. Rust Engineering was
awarded a contract to construct a pilot plant from
design information obtained by Lummus.
Construction of the Synthane pilot plant was
completed in March of 1975, and all areas and
systems operations were transferred from the
construction contractor to ERDA. Through 1975
work concentrated on installation of auxiliary
equipment and the repair and modification of the
plant due to faulty equipment and design changes.
During the first quarter of 1976 these repairs and
changes were made and initial testing began. A
number of runs were made; however, most of them
were of relatively short duration. At present, oper-
ational and equipment problems continue to plague
the pilot plant, but new solutions are being found,
and valuable experience is being gained.
8.5 ENVIRONMENTAL CONSIDERATIONS
Characterization of plant effluents and dis-
charges has not been possible, because the Syn-
thane pilot plant has encountered numerous
equipment and operational problems since it went
on stream in early 1976. It is expected, however,
that containment and treatment of discharges
will neither require special techniques nor create
a health hazard. This process differs from the
other gasification processes in the gasifier unit
only. Downstream processing will be similar.
When the pilot plant achieves the ability to op-
erate at steady state for long periods of time,
effluent characterization studies can be con-
ducted. This phase will allow determination of
problem areas, if any exist, and also create design
data to produce a totally environmentally ac-
ceptable plant when scaled up to commercial
size. The process effluents summary is given in
Figure 8-2.
Coal Preparation and Drying
The coal preparation and drying systems used
for this process are very similar in design and op-
eration to that of other coal conversion processes.
The areas of environmental concern are generally
the same; therefore, coal preparation is covered
in Appendix B in a generalized fashion.
Gasification
Effluents to the Air - In the coal feed system,
coal is charged to the gasifiers in the Synthane
design through pressurized lock hoppers. In
the design, each gasifier is provided with one
lock hopper which discharges alternately into
two feed hoppers from which coal is passed to
the gasifier using a steam-oxygen mix as the
transport medium. The gasifier charging se-
quence involves filling the vented lock hopper
from pulverized coal storage bins, pressurizing
the filled lock hopper, and then discharging
into the feed hopper. The pressurized lock
hopper must be vented to essentially atmo-
spheric pressure when empty of coal in order to
be refilled. The main volume of gas from the
hopper could be contained in gas holders for
recycle. However, various amounts of residual
gas will remain and will be displaced to the
atmosphere when fresh coal is fed into the
hopper. The extent of the pollution problem
depends on the pressurizing gas. Where this
parameter has been determined in the design,
the composition of the gases can be estimated.
59
-------
3
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COAL
FEED
1 1 1
COAL
STORAGE &
PREPARATION
LOCK
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GASIFIER
CHAR
LETDOWN
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SCRUBBER
AQUEOUS
SCRUBBER
I
SHIFT
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HEAT
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Figure 8-2
SYNTHANE PROCESS-EFFLUENTS SUMMARY
-------
Synthane
SYNTHANE PROCESS-EFFLUENTS
SUMMARY FOR FIGURE 8-2
Stream # Description
1 Participates due to wind
2 Precipitation runoff
3 Particulates due to grinding
operation
4 Char to utility boiler
5 Spent catalyst
6 Condensate to waste water
treatment
7 Condensate to waste water
treatment
8 Spent Benfield solution
9 Regeneration gas vent
10 Spent bed media
11 Spent catalyst
12 Condensate to water treatment
The lock hopper system for the new Synthane
pilot plant will use carbon dioxide as the pres-
surizing medium. This will be vented directly
to the atmosphere. Some contaminants may
enter into the vent stream since the system will
be heated and will cause some devolatilization
of the coal. This particular problem will need
to be evaluated during actual operation of the
system.
Liquid and Solid Effluents - The char formed in
the char letdown system, in the gasifier, is dis-
charged down through the center of the dis-
tributor and into the char cooler attached to the
gasifier. Spray water quenches the char, which
is at 1,700°F, and high pressure steam is pro-
duced. The steam is filtered for fines removal
and is used in the shift converter. The char is
discharged into lock hoppers and picked up by
low pressure steam. In a commercial plant
the char would be used to generate steam
for the process. In the pilot plant, it will be
used as landfill material. This is not expected
to pose a problem, but a component analysis
should be made and a teachability study
conducted.
Quench and Dust Removal
Effluents to the Air - This system is contained,
so there will be no emissions to the air.
Liquid and Solid Effluents - The quench and
dust removal segment of the process does not
itself emit any pollutants directly to the en-
vironment.
Shift Conversion
Effluents to the Air - The shift conversion
process is a totally contained procedure, so no
effluents are emitted to the atmosphere.
Liquid and Solid Effluents - There are no pro-
cess streams discharged from this unit. How-
ever, spent catalyst used in the conversion
process will require periodic removal and re-
placement. The catalyst can be disposed of in
a landfill or reprocessed for metals recovery.
Gas Purification
Effluents to the Air- There will be no discharges
to the atmosphere for the purification plant.
Liquid and Solid Effluents - The gas purification
or acid gas removal process used is the Ben-
field or hot potassium carbonate system. In
the process, carbon dioxide and hydrogen sul-
fide absorption takes place in a concentrated
aqueous solution of potassium carbonate which
is maintained above the atmospheric boiling
point of the solution. After the hydrogen
sulfide and carbon dioxide are removed from
the main product gas stream, they are removed
from the Benfield solution and further pro-
cessed to obtain elemental sulfur. The Benfield
Process itself does not produce effluents due
to solvent degradation. There are no contam-
ination problems and solvent loss is by mech-
anical losses only.
Methanation
Effluents to the Air - No effluents are discharged.
Liquid and Solid Effluents - No effluents are
discharged.
61
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Synthane
Auxiliary Facilities Table 8-1
SYNTHANE PROCESS SULFUR BALANCE
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given in percent
Appendix A. Hydrogen sulfide converted
to sulfur product 60.0
Sulfur Balance Char 28.6
Organic sulfur in raw gas 0.9
A typical sulfur balance breakdown is given in Sulfur in aqueous condensate 4.9
Table 8-1. Tar 5.6
100.0
62
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9. WELLMAN-GALUSHA GASIFICATION PROCESS
The Wellman-Galusha Process, developed by
McDowell-Wellman Engineering Company of
Cleveland, Ohio, has been in commercial use for
more than 35 years. The Wellman Engineering
Company has been making various types of gas-
ifiers since 1896. Over 150 of the more recent
Wellman-Galusha Gasifiers have been installed
worldwide for different industrial applications.
Feedstocks such as anthracite, coke, and bitu-
minous coals have been used in the gasifiers. Glen-
Gery Brick Company, Reading, Pennsylvania,
operates six gasifiers with anthracite coal and air.
Bituminous coal gasification with oxygen has
not been done commercially.
9.1 PROCESS DESCRIPTION
There are two types of Wellman-Galusha Gas-
ifiers, the standard type and the agitated type. The
rated capacity of an agitated gasifier is about 25
percent higher than that of the standard gasifier
of the same size, and, unlike the standard gasifier,
it can handle volatile caking bituminous coals.
The agitated gasifier, as shown schematically in
Figure 9-1 will be described in the following
discussion.
The gasifier itself is water-jacketed. Water in the
jacket completely surrounds the gasifier and also
covers the top. The inner wall of the gasifier is
steel plate and does not require a refractory lining.
The agitator has a revolving horizontal arm which
also spirals vertically below the surface of the
coal bed to retard channeling and to maintain a
uniform fuel bed. The agitator arm and its vertical
drive shaft are made of water-cooled heavy steel
tubing. The arm can be revolved at varying speeds,
and its position within the fuel bed may be changed
as desired for different feedstocks and operating
rates. A revolving step-type grate is mounted
eccentrically at the bottom of the gasifier on a
center post. It distributes the air-steam blast into
the coal bed and forces the ash formed into the
ash bin.
Crushed coal is fed into the coal bin and flows
into the feeding compartment by gravity. The
feeding compartment continuously feeds the coal
into the gasifier by gravity through the vertical
feed pipes. Four slide valves control the flow of
coal in and out of the feeding compartment. The
upper valves are always open except when re-
filling. The continuous flow of coal into the gas-
ifier is highly desirable because it assists in main-
taining the coal bed and gas quality in a stabilized
condition.
A fan supplies the air required for gasification.
The air is passed over the top of the water in the
jacket and picks up steam required for the blast.
Saturation of the blast is regulated by adjusting
the jacket water temperature. Normally, the
temperature is between 150QF and 180°F. A ther-
mostat controls the water supply to the jacket.
Blast mixtures of air and carbon dioxide, oxygen
and carbon dioxide, or oxygen and steam can also
be used.
The blast is introduced through the saturation
pipe into the ash bin section underneath the
grate. It is distributed through the grate into the
coal bed, and it passes upward through the ash,
combustion, and gasification zones. Combustion
and gasification reactions occur, resulting in a gas
containing mainly carbon monoxide, carbon
dioxide, hydrogen, and nitrogen. The hot gas pro-
duced dries and preheats the incoming coal and
then leaves the gasifier. Ash is withdrawn con-
tinuously through the eccentric grate, collected
in the ash bin, and later sent to disposal.
Gas leaving the gasifier is passed through a
cyclone, where the heavy dust particles, mainly
ash and char, are removed. The cyclone can also
be flooded with water during a shutdown to an
elevation a few inches above the internal gas-out-
let, thus using the water seal to eliminate a me-
chanical valve.
The gas leaving the cyclone can be used hot if
its sulfur content is acceptable. Otherwise, it
63
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Wellman-Galusha
VENT
ELEVATOR
AGITATOR
COUNTERWEIGHT
CRUSHED
FEEDING
COMPARTMENT
SLIDE VALVES
PRODUCT GAS
TO GAS
COOLER
CYCLONE &
WATER SEAL
SHUT-OFF
VALVE
ASH FINES
AGITATOR
SATURATION PIPE
WATER JACKET
GASIFICATION ZONE
COMBUSTION ZONE
REVOLVING GRATE
ASH BIN
Figure 9-1
WELLMAN-GALUSHA PROCESS SCHEMATIC
-------
Wellman-Galusha
can be scrubbed and cooled in a direct contact
countercurrent water cooler and then sent for
sulfur removal. If the gas contains tar, the tar may
be separated from the cooled gas by mechanical
or electrical precipitation methods. The resulting
gas is a low-Btu product gas. A medium-Btu gas
can be produced by using oxygen instead of air.
Cooling-water-overflow from the jacket and the
agitator is not contaminated and can be cooled
and recirculated. Slowdown from the gas cooler
is sent to waste water treatment.
9.2 PROCESS ADVANTAGES
• Gasifier can be operated with anthracite,
bituminous, charcoal or coke. The use of an
optional coal bed agitator allows gasification
of caking coals;
• Gasifier can be operated with air or oxygen;
• Casifier can be started up in about four
hours; gasifier can be maintained in a stand-
by condition with a few minutes of air blowing
once a day;
• Small reactor size may be advantageous for
small scale industrial application;
• Gasifier has been operated commercially
and reliably for many years.
9.3 PROCESS LIMITATIONS
Maintaining the coal bed temperature below
the ash fusion temperature limits the maxi-
mum process efficiency;
By-products require additional processing
for recovery;
Process condensate and by-products require
additional processing for environmental
acceptability;
Low operating pressure may limit utilization
possibilities;
Limited reactor size may necessitate use of
multiple units in parallel for large installations.
9.4 PROJECT HISTORY
The Wellman-Galusha Process has been com-
mercial for over 35 years. Six units are operating
in the U.S. at the Glen-Gery Brick Company, in
Reading, Pennsylvania. The units can produce
low-Btu gas for industrial use, using air instead of
oxygen, or synthesis gas, using oxygen. The plants
in use are small gasification units serving single
large industrial plants. The gasifier could serve a
complex of smaller plants requiring a high-Btu
gas as a substitute natural gas in special cases.
In 1974, the OCR awarded a $95,000 contract
to McDowell-Wellman to determine the feasibility
of constructing a fixed-bed gasifier for operation
on caking coals. Under the contract, the firm
supported its findings with a preliminary engi-
neering design of the gasifier. It would operate at
300 psi on highly-caking coals with air to produce
a low-Btu product or oxygen moderated with
either carbon dioxide or steam to produce a
medium-Btu product suitable for methane synthesis.
In February 1975, Applied Technology Corpo-
ration announced it had reached agreement in
London with Wellman Incandescent Ltd. for ex-
clusive rights in North and South America to Well-
man's coal gasification technology.
More recently, EPA and ERDA began coop-
erating to evaluate small-sized gasifiers in ERDA's
Industrial Program. The gasifiers utilize up to 200
tons of coal per day. They will serve as a practical
energy source, as a basis for obtaining data to
make improvements in technology, and as a source
of environmental information. The ERDA phase
of the program began in early 1976. The agency
has signed agreements with:
• ACUREX Corporation, Aerotherm Division,
Mountain View, California, to produce fuel
for use in a brick kiln at the Glen-Gery Co-
pany plant in York, Pennsylvania;
• The University of Minnesota, Minneapolis,
to produce boiler fuel for space heating of
the Duluth campus;
65
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Wellman-Galusha
Pike County, Kentucky, to provide boiler
fuel for heating and cooling of housing, a
fire station, school, shopping center, and
fuel for an industrial park near Pikeville
9.5 ENVIRONMENTAL CONSIDERATIONS
A small amount of tar is produced with bitu-
minous coal, 0.001 Ib/SCF of gas, and carried with
the product gas. If it is removed from the gas
before use, final disposition of this material would
have to be ascertained for each installation.
Exit gasifier jacket water and cooling water for
the agitator arm are relatively uncontaminated
and can be recirculated after cooling. However,
water discharged from the combination cyclone
and water seal shutoff valve and the gas scrubber
require treatment before disposal.
The ash produced from the Wellman-Galusha
Casifier contains about 0.1 percent carbon and
can be disposed of by landfill.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
Sulfur balance data are not available.
66
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10. WINKLER PROCESS
The Winkler Process developers are Davy
Powergas, Inc., Lakeland, Florida, a subsidiary of
Davy International Ltd., London, and its affiliate,
Bamag Verfahren-Stecknik GmbH, West Germany.
This process was developed in Europe over 50
years ago. The process was constructed commer-
cially at 16 plants in a number of countries, using
a total of 36 generators. These plants are still
operating with the largest having an output of 1.1
MMSCFD. The plants produce low-Btu fuel gas,
with air instead of oxygen, and synthesis gas for
the production of methanol, ammonia, and oil by
Fischer-Tropsch synthesis.
10.1 PROCESS DESCRIPTION
In the Winkler Process coal is gasified at about
1,700°F and 2 atm in a turbulent bed of particles
using oxygen and steam, to make medium-Btu gas
for fuel or synthesis. Most of the residual char is
blown overhead as a result of the high gas velocity
of 5 to 10 ft/sec. Most of the gas is then cooled and
cleaned to remove dust and sulfur. The process
diagram is shown in Figure 10-1. There are four
major steps in the process: (1) coal preparation,
(2) gasification, (3) cooling and scrubbing, and (4)
sulfur removal.
Coal drying is not always needed, because it is
only necessary to avoid surface moisture which
would cause difficulties in handling and crushing.
Rotating tray dryers are used when drying is
necessary. Cool stack gas, 350° F to 400° F, is
recycled to control gas inlet temperature so as
not to drive off volatiles. Coal is crushed to -8-
mesh and sent to the gasif ier feed hopper.
Coal from the feed hopper is fed to the gasifier
by means of screw feeders. Steam and oxygen are
added near the bottom of the reactor, maintaining
the particulates in the turbulent bed where reaction
takes place without reaching temperatures that
would fuse the ash. The bed may be about 1,700° F
so that tar and heavy hydrocarbons are destroyed
by gasification reactions.
Considerable fines are entrained from the bed,
and supplemental oxygen and steam are added
to help consume them. The heat exchange surface
in the dilute phase about the bed removes heat to
protect refractories and for temperature control,
generating useful steam. The raw gas is cooled
to about 1,300°F before the gas leaves the boiler.
The gas then passes through an exchanger to
superheat steam, followed by a waste heat boiler
and a cyclone to remove entrained char. The gas
then goes to a scrubbing tower where it is cooled
by direct contact with recirculated water.
Most of the particulates are removed by scrub-
bing and are separated from the water in a settler.
They are included with the char for disposal.
Clarified water is cooled by indirect exchange
with cooling water before it is recirculated to the
scrubber. Net production of this water or gas liquor
constitutes sour water containing hydrogen sulfide,
ammonia, cyanides, etc., present in the raw gas.
The sour water is processed in waste water treat-
ing so that it can be reused.
The scrubbed gas will still contain a small
amount of dust and is passed through an electro-
static precipitator for final cleanup. Traces of
contaminants may remain in the gas after scrub-
bing, such as ammonia, sulfur, oil, etc.
The next processing step on the gas is sulfur
removal by scrubbing with a suitable solution
such as amine, hot carbonate, or a glycol type
solvent. These can be regenerated by stripping to
give a concentrated hydrogen sulfide stream that
is sent to sulfur recovery.
10.2 PROCESS ADVANTAGES
• Gasifier can be operated with air or oxygen;
• The absence of tars, oils, and naphthas in
the raw gas simplifies control technology
requirements;
• The gasifier can be shut down in a few min-
utes; even after several days the gasifier can
be re-started instantly;
67
-------
3
5"
o
Figure 10-1
WINKLER PROCESS SCHEMATIC
-------
Winkler
• The uniform temperature and composition
of the fluidized-bed provide stable operating
conditions;
• Casifier has been operated commercially
and reliably for many years.
10.3 PROCESS LIMITATIONS
• Strongly caking coals may require partial
oxidation pretreatment; less reactive coals
decrease thermal efficiency and carbon
conversion;
• Efficiency is limited due to large amount of
unconverted coal which leaves the gasifier;
higher temperatures decrease efficiency due
to sensible heat losses;
• The large amount of unreacted coal in the
char can be burned as a by-product, but if a
suitable use is not available, the efficiency
of the overall process is greatly reduced;
• Low operating pressure may be a disadvantage
for transmission of the product gas or utili-
zation in combined cycle applications;
• Separation of high temperature char particles
from the raw gas stream may be an operating
problem.
10.4 PROJECT HISTORY
In 1922, Dr. Fritz Winkler conceived the idea
of using a fluid-bed for gasifying coal while work-
ing on processes for the production of activated
carbon in a BASF AC plant. A patent was applied
for in September 1922, and development work
directed toward making power gas was carried
out at Oppau, near Mannheim, in the following
years. The first commercial Winkler plant was
put into operation at Leuna in 1926. Since then
36 producers in 16 installations have been designed,
engineered, and constructed, all by Bamag Ver-
fahren-Stecknik GmbH.
The Winkler Process has provided gas for fuel
or power, for synthesis of methanol and ammonia,
for Berguis-Hydrogenation, and for the production
of hydrogen in Europe and Asia when coal was
the only raw material available. All of those
commercial plants were designed and operated
so that after cooling and particulate removal.
the product gas would be delivered at nominally
atmospheric pressure.
In mid-1972, Davy Powergas undertook a study
to determine if a Winkler Gasifier operating under
these proven conditions would be competitive
with other available technology. Within the
accuracy of the estimates made, none of the
commercial processes appeared decisively better
than any of the others, and therefore, review was
begun of the Winkler Process to determine what
its limitations were for current U.S. conditions.
It became obvious that the biggest deficit was
the low pressure of operations because of (1) large
size equipment to handle large volumes of gas,
(2) high capital costs because of the product
compression station, and (3) high daily operating
costs of power for product compression.
Process economic studies were conducted to
find the optimum pressure ranges and to assess
the magnitude of savings attributable to pressure
operations. Conclusions clearly showed that
improvements in capital and operating costs
would result from pressurization.
10.5 ENVIRONMENTAL CONSIDERATIONS
An advantage of the Winkler Process is that
the absence of tars, oils, and naphthas in the
raw gas simplifies control technology requirements.
The process effluents are summarized in Figure
10-2.
Coal Hopper
Effluents to the Air - The nitrogen vent stream
contains the nitrogen which is used to blanket
the coal dust feed bins in order to prevent
explosions of the fine coal particles. These
particles can be removed with filters, cyclones,
or scrubbers prior to venting the nitrogen to
the atmosphere.
Liquid and Solid Effluents - No effluents are
discharged.
Gasifier
Effluents to the Air- No effluents are discharged.
69
-------
3
?r
Figure 10-2
WINKLER PROCESS-EFFLUENTS SUMMARY
-------
Winkler
WINKLER PROCESS-EFFLUENTS
SUMMARY FOR FIGURE 10-2
Stream #
1
2
3
4
5
6
7
Description
Nitrogen vent
Steam
Nitrogen vent
Dry ash
Ash slurry
Condensate
Vent
Liquid and Solid Effluents - No effluents are
discharged.
Waste Heat Boiler
Effluents to the Air - The only effluent to the
air is steam.
Liquid and Solid Effluents - No effluents are
discharged.
Ash Hopper
Effluents to the Air • This nitrogen vent stream
contains the nitrogen which is used to blanket
the dry ash bin in order to prevent further re-
action or combustion of the char in the ash.
This stream will also contain entrained ash
particulates plus some raw product gas or gases
evolved from the hot char. The entrained ash
particulates in this gas stream can be removed
with filters, cyclones, or scrubbers. If there are
significant concentrations of raw gas or gas
evolved from the hot char in this stream, these
contaminants may be controlled by recycling
the stream to the raw gas or by incinerating
the stream in a flare or boiler, although the ni-
trogen content of the stream may eliminate this
option due to nitrogen oxides formation or
non-flammability.
Liquid and Solid Effluents - The dry ash stream
is composed of larger ash particles formed
in the gasifier which were heavy enough to fall
to the bottom of the gasifier and into the screw
conveyor plus the ash particles which were re-
moved from the raw gas in the waste heat boiler
and in the cyclone. The ash will consist of the
mineral matter present in the coal feed with
10 to 30 percent unreacted carbon. The exact
composition of the ash is dependent on the
composition of the feed coal and the gasifier
operating conditions. The dry ash may contain
enough unreacted carbon to be utilized as a
salable by-product. The char in the ash may be
burned as a fuel or may be used as an adsorbent
similar to activated charcoal. If the dry ash is
a solid waste product, it may be combined with
the ash slurry prior to ultimate disposal. Solid
treatment processes can be used for ash dis-
posal.
Wash Cooler
Effluents to the Air- No effluents are discharged.
Liquid and Solid Effluents - No effluents are
discharged.
Settler
Effluents to the Air - The settler vent stream
may contain any of the components in the raw
gas which dissolve or condense in the direct
contact scrubber/cooler. The ash which is
washed out of the raw gas stream is separated
from the quench liquor in a settler. The dis-
solved or condensed components from the raw
gas stream that evaporate from the quenching
liquor are removed from the settler through the
vent. This vent stream may also contain en-
trained droplets of gas-quenching liquor or ash
slurry. The solid and liquid contaminants in
this stream can be removed with filters, cyclones,
or scrubbers. If there are significant concen-
trations of contaminants from the raw gas in
this stream, they may be controlled by re-
cycling the stream to the raw gas or by incin-
erating the stream in a flare or boiler.
Liquid and Solid Effluents - The condensate
stream is composed of the raw gas-scrubbing
liquor plus raw gas condensate from the direct
contact scrubber/cooler. The ash which is
washed out of the raw gas stream is separated
from the quench liquor in a settler, but some
71
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Winkler
ash particles may be carried along in this blow-
down stream. The other components in this
stream are the constituents of the raw gas
which condense or dissolve in the quench
liquor. The components most likely to be
present in this stream are water, particulates,
ammonia, hydrogen sulfide, and trace elements.
Water pollution control processes can be used
to remove these contaminants.
The ash slurry stream contains the ash par-
ticles which were not removed from the raw
gas in the waste heat boiler or in the cyclone.
The ash particles are washed out of the raw gas
stream in the direct contact scrubber/cooler,
and the ash is separated from the quench liquor
in a settler. The bottom product removed from
the settler is the ash slurry which contains
approximately 25 to 35 percent solids. The liquid
portion of the slurry is composed of the process
condensate and gas-quenching liquor. The
ash in the slurry consists of the mineral matter
present in the feed coal with 10 to 30 percent
unreacted carbon. Suspended solids removal
processes can be used to dewater the ash slurry.
The recovered water could be recycled to the
process condensate and gas-quenching liquor.
The dewatered ash or ash slurry is a waste pro-
duct which requires ultimate disposal. The
ash slurry may be combined with the dry ash
prior to disposal. Solid waste treatment pro-
cesses can be used for ash slurry disposal.
Electrostatic Precipitator
Effluents to the Air -None.
Liquid and Solid Effluents - No effluents are
discharged.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
A typical sulfur balance breakdown is given in
Table10-1.
Table 10-1
WINKLER PROCESS SULFUR BALANCE
Product gas
Fuel gas
Glaus plant
Tail gas
Char and ash
percent
4.7
0.2
91.2
0.9
3.0
100.0
72
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11. CHAR-OIL ENERGY DEVELOPMENT (COED) PROCESS
The COED project was conducted by the FMC
Corporation under government sponsorship from
September 1966 through December 1975. At that
time, the process had been successfully dem-
onstrated, and ERDA funding was discontinued.
No further experimental work has been done since
that date.
The COED Process produces huge quantities
of un-wanted char. At one time, the sponsors
thought electric utility companies would buy the
char to burn in boilers. No market at all was
found for char.
11.1 PROCESS DESCRIPTION
The COED Process converts coal to gas, oil, and
char through heating in multistage fluidized-beds,
as shown in Figure 11-1. In this process, the coal
is first crushed and dried, then is pyrolyzed in a
series of four fluidized-bed reactors with succes-
sively higher temperatures. The temperature of
each fluidized-bed reactor is just below the max-
imum temperature to which the coal can be heated
without agglomerating. The number of stages and
the operating temperature vary with the agglom-
erating properties of the coal. Heat for pyrolysis
is provided primarily by burning a portion of the
char with oxygen in the presence of steam in the
fourth stage of pyrolysis. Nitrogen is used for
start-up to fluidize the first stage until enough
flue gas is available. Hot gases from the fourth
stage flow countercurrent to the char. These
gases, which provide the fluidizing medium for the
second and third stages of pyrolysis, are then
passed to a product recovery system where the
gas and oil are produced.
Gas and oil are recovered from vapors coming
off from the second pyrolysis stage. These vapors
pass into a cyclone which removes the fines. The
vapors leaving the cyclone are then quenched
directly with water in a venturi scrubber to con-
dense the oil. The gases and oils are separated in
a decanter.
The gas is desulfurized in the gas-cleaning plant,
then it is enriched with steam by a steam reformer.
Part of the product gas is converted to hydrogen
and used in the process; the balance of the pro-
duct gas can either be scrubbed and sold as fuel
gas or be converted to pipeline gas or hydrogen.
The oil from the decanter is dehydrated and
filtered in a rotary pressure precoat filter. The
solids-free oil is-then pressurized and mixed with
hydrogen in a fixed-bed catalytic reactor (hydro-
treater). The hydrotreater removes nitrogen, sulfur,
and oxygen, which are reacted with hydrogen to
form ammonia, hydrogen sulfide, and water, and
produces a heavy synthetic crude oil with a spe-
cific gravity of 0.9.
The char produced by the process is desulfur-
ized in a shaft kiln. In the kiln, hydrogen is added
to the char, which produces hydrogen sulfide; the
hydrogen sulfide is then absorbed by an acceptor,
such as calcined limestone or dolomite. After
desulfurization, the char and spent acceptor, which
can be regenerated, are separated in the contin-
uous fluidized-bed separator. Product char can
be reacted with steam and oxygen in a gasifier to
generate low-Btu gas. The rank of coal processed
and the marketability of the end product deter-
mine the final use of the char and gas.
11.2 PROCESS ADVANTAGES
• The process can handle caking coals without
the preoxidation or recirculation of char
usually necessary to prevent agglomeration
in the system;
• The process achieves high yields of oil with
minimum-sized equipment;
• The process operates at low pressure (less
than 10 psia) which permits the use of con-
ventional oil processing equipment.
11.3 PROCESS LIMITATIONS
• The process has comparatively low thermal
efficiency, a limitation common to all pyro-
73
-------
o
o
FLUC CAS
IOOO F
FLUIDIZED BED REACTORS
SPf NT ACCF PTOR
Figure 11-1
COED PROCESS SCHEMATIC
-------
COED
lysis and hydrocarbonization processes;
Carbon conversion is low; research is being
done to investigate gasification of the large
amount of char produced.
11.4 PROJECT HISTORY
The COED project, initiated in 1962 under the
auspices of the OCR, was tested for several years
in bench-scale research studies. In 1965, FMC in-
stalled a process development unit at its Chemical
Research and Development Center in Princeton,
New Jersey, capable of processing 100 pounds of
coal per day, Twelve different kinds of coal were
evaluated.
FMC Corporation entered into a second con-
tract with OCR in September 1966. This contract
was to (1) continue the investigation of the pyrol-
ysis of coal using the existing process development
unit and (2) design, construct, and operate a pilot
plant capable of converting 36 TPD of coal to a
low-sulfur synthetic crude oil. The plant, located
in Princeton, New Jersey, was completed in July
1970. The pyrolysis section of the pilot plant has
been in operation since then and the hydrotreating
section since June 1971.
FMC entered into its last contract with OCR in
1971. Through 1974, the COED pilot plant pro-
cessed about 21,000 tons of coal from seven dif-
ferent geographic sources, ranging in rank from
lignite to high volatile A bituminous coal. In 1974,
high volatile B bituminous coal from western
Kentucky and high volatile A bituminous coal
from West Virginia were processed. These are the
most highly agglomerating coals to be processed
in the pilot plant. The circulation of solids be-
tween multiple fluidized-bed reactors, the filtra-
tion of coal oil, and the upgrading of the coal oil
to synthetic crude oil through fixed-bed hydro-
treating have been demonstrated successfully.
The plant was also operated to test new equip-
ment and provide char and oil for further evalu-
ations. The pilot plant operated successfully at
design capacity and several 30-day runs were
made.
Current plans are to incorporate the COED
Process into the Illinois Coal Gasification Group
(ICGG) in Perry County, Illinois. ICGG's COCAS
Process will gasify the char that is produced from
the COED Process. To that end, ERDA has awarded
ICGG a $24 million contract.
11.5 ENVIRONMENTAL CONSIDERATIONS
The COED Process has demonstrated its ability
to convert practically any type of coal into very
low-sulfur synthetic crude oil, clean fuel gas, and
char in an environmentally acceptable manner.
Essentially all of the sulfur in the coal is converted
into hydrogen sulfide which is subsequently con-
verted into elemental sulfur. Since the initial op-
eration of the plant in July of 1970, over 18,000
tons of various agglomerating and nonagglom-
erating coals were processed. During this time
a large amount of experience has been gained
with respect to characterization and handling of
waste streams. A process effluents summary is
given in Figure 11 -2. As can be seen, these methods
are the same as those used in other processes.
None of the streams that are finally vented to the
atmosphere exceeds current allowable emission
standards.
Because of the long-term pilot operation,
various tests have been made to determine the
compatibility of COED syncrude with existing com-
bustion equipment and the environmental effects
of the product usage.
Studies have been conducted on syncrude by
the Atlantic Richfield Company to define those .
refinery processes where the syncrude could best
be used. A subsequent study has been carried out
by Chem Systems in which their refinery model
showed syncrude to have the same value, to a
refinery, as sweet crude. A promising use of the
product is to distill it into naphtha and No. 4
fuel oil. The sulfur content of the syncrude is
generally about 0.1 percent. In addition to the
refinery test, about 17,000 gallons of COED syn-
crude were used to power the Navy destroyer USS
Johnston. The successful test was made during
a 30-hour period in November of 1973. The syn-
crude was also tested as a fuel for a small indus-
trial boiler firing 1.5 million Btu/hr. All emissions
from syncrude combustion were significantly
lower than those from a typical No. 4 residual fuel.
75
-------
COAL
FEED
Figure 11-2
COED PROCESS-EFFLUENTS SUMMARY
o
O
-------
COED
COED PROCESS-EFFLUENTS SUMMARY
FOR FIGURE 11-2
Stream # Description
1 Dust due to wind
2 Runoff due to precipitation
3 Purge gas to boiler stack
4 Oily wet char fines to coal feed
5 Aqueous condensate to stage
four pyrolyze
6 Product char stream
7 Char fines and filter aids to coal
feed
8 Spent Benfield solution
Coal Drying and First Stage Pyrolysis
Effluents to the Air - In the FMC design, clean
natural gas is burned sub-stoichiometrically
both to dry the feed coal and to heat the f luid-
izing gas for the first stage of pyrolysis. A cas-
cade of two internal gas cycfones is provided for
both the coal dryer and first pyrolysis reactor.
Gas from the pyrolyzer is circulated through
fluidized-bed heater for use in the coal dryer.
The gas from the coal dryer passes through an
external cyclone and is then scrubbed in a
venturi scrubber-cooler which removes coal
and char fines and traces of coal liquids. The
fines are recycled back to the first stage pyro-
lyzer
The scrubber effluent passes into a gas-liquid
separator, where the liquor stream is decanted
to remove solids. The solids are recycled
back to the coal feed and the water is recycled
back to the venturi scrubber. The gas is com-
pressed and recirculated back to the gas heaters
except for a purge stream which is vented to
the atmosphere. The stream will contain about
3.7 percent carbon monoxide. The stream will
need to be treated by injection into boiler
stacks. The purge vent is expected to be sulfur
free.
LiqM and Solid Effluents - All the liquid and
solid streams are recycled back into the process.
Pyrolysis Stages Two, Three, and Four
The next three pyrolysis stages are closed
systems, and as with the first stage, gaseous
liquid effluent will be recycled toother stages of
the process.
The char produced in this section will be sent
to a gasifier for hydrogen production in a com-
mercial plant.
Product Recovery
There are no effluents generated in this section
that are discharged to the environment. The waste
liquor purge from the scrubbing circuit is returned
to the last pyrolysis stage.
COED Oil Filtration
There will be no gaseous or liquid effluents
generated in this process. The filter cake which,
from pilot plant data, contains about 38 percent
oil, 52 percent char, and 10 percent filter aid is
recycled to the coal feed stream.
Hydrotreating
The spent catalyst from the hydrotreating
reactors will be the only discharge from this
section.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
A typical sulfur balance breakdown is given in
Table 11-1.
Table 11-1
COED PROCESS SULFUR BALANCE
Svncrude
Elemental sulfur
Sulfur emissions
Char
Other
100.0
77
-------
12. DONOR SOLVENT LIQUEFACTION PROCESS
The Donor Solvent Process for coal liquefac-
tion is being developed by the Exxon Research
and Engineering Company, Baytown, Texas.
A $12 million contract between ERDA and Exxon
was initiated in January 1976. However, under
the terms of the contract, details of prior devel-
opment work on the process conducted between
1966 and January 1976 are confidential.
12.1 PROCESS DESCRIPTION
Steps in the Donor Solvent Process involve
engineering and design technology similar to that
practiced in the petroleum industry. The process
was designed to permit process control, allow for
feeding different coals, and allow product dis-
tribution to vary based on market demand. In
this process, the donor solvent provides a mech-
anism to allow intimate contact between hydrogen
and dispersed coal fragments. The donor hydro-
gen content of the spent solvent is restored after
liquefaction in the solvent hydrogenation reactor.
This step also reduces the sulfur, nitrogen, and
oxygen contents of the recycle solvent. The
donor hydrogen content is the major parameter
used to evaluate the effectiveness of various
catalysts and processing conditions to produce
good quality donor solvent. A schematic of the
process is provided in Figure 12-1.
SOLVENT
HYDROTREATING
SOLVENT
FRACTIONATION
NAPHTHA
Figure 12-1
DONOR SOLVENT PROCESS SCHEMATIC
79
-------
Donor Solvent
The coal is dried and ground to -30-mesh and
mixed with recycle solvent to form a slurry. Hy-
drogen is normally preheated separately and
combined with preheated slurry at the reactor
inJet. An alternate mode of operation is to com-
bine the hydrogen with the slurry before pre-
heating.
After liquefaction, the product goes to the first
stage of separation. Water is removed, hydrogen
is recycled, and heavy liquid products are sent
to the vacuum separation section.
The primary vacuum flash tower removes the
mineral matter and unreacted coal. The second-
ary vacuum tower is used to remove a heavy
distillate which becomes the endpoint of the
recycle solvent. This overhead from the secondary
vacuum flash tower is then combined with the
lighter liquid stream recovered from the lique-
faction reactor separator system and fed to the
solvent hydrotreating section, consisting of fixed-
bed catalytic reactors. The solvent and naphtha
from the solvent hydrotreating section are then
separated by fractionation. Most of the solvent
is recycled, as is the hydrogen, after undergoing
cleanup in a monoethanolamine scrubbing system.
12.2 PROCESS ADVANTAGES
• The process is designed to permit use of
different coal feeds and to produce a variety
of products;
• Gas generated in the liquefaction area is
used as fuel or for high purity hydrogen
manufacture;
* The solvent carries the coal into trie re-
actor, helps to dissolve the coal particles,
and improves operabrlity as compared to
unhydrogenated solvent.
12.3 PROCESS LIMITATIONS
• Information is not available.
12.4 PROJECT HISTORY
Exxon's research on the Donor Solvent Process
began in 1966 and has resulted in a commercial
study design. A semi-empirical kinetic model
of liquefaction yields from Illinois coal has been
expanded to include recent results from high-
severity liquefaction experiments. Progress has
been made in the development of a computer
model of the entire integrated Donor Solvent
Process. The model will simulate, and link to-
gether in a single interfacing package, the six
major processing sections: (1) liquefaction, (2) sol-
vent hydrotreating, (3) coking, (4) cryogenic hydro-
gen recovery, (5) steam/methane reforming, and
(6) final product separation.
Evaluations of several process alternatives
have begun, including development of a com-
puterized process alternative model to be used
as a basic tool for the process engineering and
economic studies which are planned. Engineering
studies have been initiated to identify and develop
equipment and engineering data needed for a
safe, operable, and reliable Donor Solvent com-
mercial plant.
12.5 ENVIRONMENTAL CONSIDERATIONS
Environmental quality data for the Donor
Solvent Process are not available because a plant
has not yet been constructed, and because of the
proprietary nature of the contract.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
Sulfur balance data are not available.
80
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13. FISCHER-TROPSCH SYNTHESIS PROCESS
In 1974, the OCR (now a part of ERDA), awarded
the Ralph M. Parson's Company of Pasadena,
California a $2.99 million contract to evaluate the
coal-oil-gas refinery concept. The contract en-
tails preliminary design work on a Fischer-Tropsch
synthesis plant to produce substitute natural
gas and motor fuels as the main products.
13.1 PROCESS DESCRIPTION
The only commercial Fischer-Tropsch plant
currently in operation is The South African Coal,
Oil and Gas Corporation Ltd. (SASOL) plant in
South Africa. The process schematic is shown in
Figure 13-1. In the SASOL plant design, coal is
gasified in a battery of 13 Lurgi high pressure,
steam-oxygen gasif iers to produce a gas consisting
essentially of carbon monoxide and hydrogen,
tars and oil. The gas stream from the gasifier is
quenched to remove tars and oil. The scrubbed
gas is then sent to a Rectisol" (Lurgi) Process
which uses a methanol solvent to remove the re-
maining tar and oil, carbon dioxide, hydrogen
sulfide, ammonia, and phenols. The purified gas
stream is then sent to the Fischer-Tropsch syn-
thesis reactor for polymerization. Initially, the
gas is split, and part of it is sent through a fixed-
bed, catalytic reactor, using an iron/colbalt cata-
COAL
COAL
PREPARATION
STEAM
OXYGEN
GASIFICATION
GAS
PURIFICATION
&
SULFUR
RECOVERY
•*- SULFUR
FISCHER-
TROPSCH
SYNTHESIS
PRODUCT
SEPARATION
HYDROCARBON
PRODUCTS
PRODUCT
SNG
Figure 13-1
FISCHER-TROPSCH PROCESS SCHEMATIC
81
-------
Fischer Tropsch
lyst. The feed gas has a hydrogen/carbon mon-
oxide mole ratio of about 2:1, and synthesis
occurs under conditions of 430° F and 360 psi.
The products of this synthesis are straight chain,
high-boiling hydrocarbons, with some medium
boiling oils, diesel oil, LPC, and oxygenated com-
pounds such as alcohols.
The other part of the gas stream is sent to a
fluidized-bed catalytic reactor which uses powder-
ed iron as the catalyst. In this reactor, gas and
catalyst are circulated along with the synthesis
gas. The catalyst is removed by cyclones. Oper-
ating conditions are 600°F to 625°F and 330 psi.
This process yields petroleum products, alcohol,
oil, and gas. A list of typical products obtained
from the process includes:
• Fuel gas
• Propane/propylene
• Butane/butylene
• Methylethyl ketone
• Light furnace oil
• Waxy oil
• Methanol
• Ethanol
• Propanol
• Butanol
• Gasoline
Pentanol
Acetone
Naphtha
Waste acids
Benzol
Toluol
Diesel oil
Tar
Creosote
Ammonium sulfate
Sulfur
13.2 PROCESS ADVANTAGES
• The product is a mixture of relatively simple
hydrocarbons in a semi-refined state and is
completely free of sulfur and nitrogen com-
pounds;
• Commercial plants have been developed in
Germany, other parts of Europe, and the
Union of South Africa.
13.3 PROCESS LIMITATIONS
• Plants are difficult to operate because
they typically require much maintenance.
13.4 PROCESS HISTORY
Development of the Fischer-Tropsch Process
dates back to the period of 1923 to 1933 when
Fischer and Tropsch made extensive studies of
the catalytic reduction of carbon monoxide to
various hydrocarbon liquids. Following pilot plant
operations in 1932, a 1,000 TPY plant was con-
structed by Ruhrchemie in 1933 and a 30,000 TPY
plant in 1936. By 1939, nine plants had been
erected in Germany and one in France. In 1950,
SASOL was formed and the decision was made to
construct a coal conversion plant using the Fischer-
Tropsch Synthesis Process. The first barrel of
oil was produced in 1954.
Activities related to Fischer-Tropsch synthesis
in the U.S. date from the time when the Office of
Synthetic Liquid Fuels was set up in 1944. Fischer-
Tropsch synthesis has been evaluated from a tech-
nical standpoint by the Pittsburgh Energy Research
Center. At Louisiana, Missouri, a goverment
ammonia plant was converted into a coal lique-
faction plant. It used the Fischer-Tropsch syn-
thesis to produce about 100 barrels per day of
gasoline and chemicals.
13.5 ENVIRONMENTAL CONSIDERATIONS
Environmental quality data for a Fischer-Tropsch
synthesis operation is very sketchy SASOL has
not released information in this area and has
been reluctant to provide requested data. Since
the front end of the process is basically a Lurgi
gasification plant, the effluents for that section
are fully defined. Effluents from the Fischer-
Tropsch reactors should be limited to spent cata-
lyst and process condensate, both of which can
be easily handled. It is possible that future test
agreements with SASOL and the U.S. EPA will
allow for characterization of effluent streams
from the Fischer-Tropsch plant. In addition, The
Ralph M. Parsons Company work will include
environmental aspects of its conceptual plant
and should serve as a good source of information
on this matter when the report is finished and re-
leased.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
Sulfur balance data are not available.
82
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14. H-COAL PROCESS
The H-Coal Process is being developed by
Hydrocarbon Research, Inc. (HRI) under the
joint sponsorship of (1) ERDA; (2) a private industry
consortium composed of EPRI, Ashland Oil, Inc.,
Atlantic Richfield Company, Shell Oil Company,
Standard Oil Company (Indiana), Sun Oil Company;
and (3) the Commonwealth of Kentucky. The
plant site is located at Catlettsburg, Kentucky.
The total project funding is $44.4 million with
ERDA supplying $32.7 million and industry $11.7
million.
14.1 PROCESS DESCRIPTION
The H-Coal Process is a catalytic hydro-
liquefaction process that converts high-sulfur
coat to boiler fuels and synthetic crude. A sche-
matic of the process is provided in Figure 14-1.
Coal is crushed to -60-mesh, dried, slurried with
recycled oil, and is then pressurized to about 200
atm. Compressed hydrogen is added to the slurry,
and the mixture is preheated and charged con-
tinuously to the bottom of the ebullated-bed
Figure 14-1
H-COAL PROCESS SCHEMATIC
83
-------
H-Coal
catalytic reactor. The upward passage of inter-
nally recycled reaction mixture maintains the
catalyst in a fluidized state. Catalyst activity is
maintained by the periodic addition of fresh
catalyst and the withdrawal of spent catalyst.
The temperature of the ebullated-bed catalytic
reactor is controlled by adjusting the preheater
outlet temperature. Typically, the temperature
of the mixture entering the reactor is 650°F to
700° F.
Vapor product leaving the top of the reactor
is cooled to separate the heavier components
as a liquid. Light hydrocarbons, ammonia, and
hydrogen sulf ide are absorbed from the gas stream
and sent to a separator and a sulfur recovery unit.
The remaining hydrogen-rich gas is recompressed
and combined with the input slurry The liquid from
the condenser is fed to an atmospheric distil-
lation unit. The liquid-solid product from the re-
actor, containing unconverted coal, gas, and oil,
is fed into a flash separator. The material that is
flashed off is passed to the atmospheric distillation
unit which yields light and heavy distillate pro-
ducts. The bottoms product from the flash sep-
arator, solids and heavy oil, is further separated
with a hydroclone, a liquid-solid separator, and
by vacuum distillation.
The gas and liquid products, composed of hydro-
carbon gases, hydrogen sulfide, ammonia, light dis-
tillate, heavy distillate, and residual fuel, may be
further refined as necessary. A portion of the heavy
distillate is recycled as the slurry medium. The
stream containing the unreacted carbon and some
liquid will eventually be processed in a commer-
cial installation to produce additional hydrogen
needed for the process.
Before the H-Coal Process can become com-
mercially and economically competitive, a meth-
od for generating an adequate supply of hydro-
gen from the process itself must be developed.
This is an unsolved problem. The H-Coal Process
requires between 14,000 and 20,000 standard
cubic feet of hydrogen for each ton of coal pro-
cessed, depending on the type of oil produced.
In the pilot plant some of the hydrogen required
has been obtained from the gas produced by the
ebullated-bed reactor. Additional hydrogen has
been purchased to meet processing demands. In a
commercial operation,hydrogen demand will be
met by manufacture on-site. Because the H-Coal
Process converts about 90 percent of the carbon
contained in the coal to a liquid, the feed to the
hydrogen plant could be liquid rather than solid.
This suggests that commercial hydrogen manu-
facturing processes could be adapted. The solid
cake char could also be used to produce hydrogen.
Another of the principal unsolved problems in
the H-Coal Process (and in other liquefaction pro-
cesses) is the effective separation of the solids
from the fuel products. In the H-Coal Process,
hydroclones are capable of removing about
two-thirds of the solids so that the liquids can be
recycled for slurrying the coal. HRI has also
been investigating other methods of separating
solids from liquids, such as magnetic separation,
filtration, centrifugation, and solvent precipi-
tation. Magnetic separation has shown only
limited effectiveness. Separation of the solids by
filtration has not been conclusive, although
filtration rates of 150 Ib/hr/sq ft and relatively
dry filter cakes have been achieved by using con-
tinuous drum pressure filters.
14.2 PROCESS ADVANTAGES
• Direct catalytic processes use less hydrogen
in converting coal to liquids than do non-
catalytic or indirect catalytic hydrogenation
processes;
• The ebullating bed catalytic reactor con-
verts about 90 percent of carbon contained
in coal to a liquid;
• The solids residue can be used for hydrogen
manufacture;
• The reactor configuration offers good tem-
perature control, constant catalyst activity,
and a consistent quality of liquid product.
14.3 PROCESS LIMITATIONS
• An external hydrogen source is required;
• Before the H-Coa! Process can become
commercially and economically competitive,
an adequate supply of hydrogen must be
generated from the process itself;
84
-------
H-Coal
• As in other liquefaction processes, effective
separation of solids from the fuel products
must be developed.
14.4 PROCESS HISTORY
The H-Coal Process was developed by HRI as
a further application of the ebullated-bed pro-
cessing technology originally used to convert
heavy oil residues from petroleum into lighter
fractions (H-Oil Process). Early development of
the H-Coal Process, beginning in 1964, involved
research with a bench-scale unit and a process
development unit and preparation of a conceptual
process design. An independent evaluation in
1968 confirmed the technical and economic
feasibility of the H-Coal Process.
Based on the data obtained from the bench-
scale and process development units, design and
engineering of the pilot plant began under the
current contract in December 1973. During 1974,
design of the coal preparation section of the pilot
plant was completed to the extent that engineering
and plant layout could begin. HRI concentrated,
however, on the design and engineering for the
ebullated-bed reactor, since the equipment needed
for this section requires long lead times. Engineer-
ing for other sections of the pilot plant was started
in late 1974. Also during 1974, three possible sites
for construction of a pilot plant were evaluated.
Based on detailed environmental assessments,
it was decided during the second quarter of 1975
to locate the plant adjacent to the Ashland Oil,
Inc. refinery in Cattettsburg, Kentucky. Except
for the steam supply, this arrangement would
allow the utility system of the pilot plant to be
shared with that of the refinery. All process
descriptions, equipment specifications, and
planning drawings were completed for the coal
preparation section. Work in the hydrogenation
area involved the modification and rearrangement
of major equipment to conform to the physical
characteristics of the new plant site. Preliminary
process designs were also completed for the
solid-liquid separation techniques of filtration,
centrifugation, and solvent precipitation.
14.5 ENVIRONMENTAL CONSIDERATIONS
Studies are being conducted to identify all
product and waste streams to be produced by
the pilot plant. The probable quantity and com-
position of each of these streams will also be
estimated. A final report is expected to be issued
in the near future.
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
A typical sulfur balance breakdown is given in
Table 14-1.
Table 14-1
H-COAL PROCESS SULFUR BALANCE
Synthetic crude
By-product sulfur
from Claus plant
Tail gas
Flue gas
percent
1.8
87.2
0.9
10.1
100.0
85
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15. SOLVENT REFINED COAL (SRC) PROCESS
The SRC Process is being developed by Pittsburgh
& Midway Coal Mining Company (PAMCO), a
subsidiary of Gulf Oil Corporation, under the
sponsorship of ERDA. A 50 TPD pilot plant is
located in Ft. Lewis, Washington, and current
funding, 100 percent supplied by ERDA, is set at
$82 million. The operation and evaluation of the
modified pilot plant is scheduled to run through
1980. A 6 TPD pilot plant, sponsored by ERDA,
EPRI, and Southern Company Services is operating
at the Gaston steam power plant located near
Wilsonville, Alabama.
15.1 PROCESS DESCRIPTION
There are really two SRC processes - SRC I and
SRC II. SRC I creates a solid fuel as its final pro-
duct, while SRC II produces a liquid.
The SRC I Process converts high-sulfur, high-
ash coals to low-sulfur, low-ash solid fuel. Figure
15-1 shows a schematic of the process. The coal
is first pulverized and mixed with a coal-derived
solvent in a slurry mix tank. The slurry is combined
with hydrogen and is then pumped through a fired
SLURRY MIX TANK
» HYDROCARBON GAS
LIQUID fUCI. TO iOLIOIfKATIOH
Figure 15-1
SRC PROCESS SCHEMATIC
87
-------
SRC
preheater and passed into a dissolver. In this unit,
the coal is hydrogenated and thereby depolymer-
ized, leading to an overall decrease in product
molecular weight and dissolution of the coal.
The solvent is also hydrocracked in the dissolver
unit, yielding lower molecular weight hydrocar-
bons ranging from light oil to methane. Yet another
reaction occurring in the dissolver is the hydro-
genation of the organic sulfur in the coal, thus
producing hydrogen sulf ide.
From the dissolver, the mixture passes to a
separator where the gases are separated from the
slurry of undissolved solids and coal solution. The
raw gas is sent to a hydrogen recovery and gas
desulfurization unit. The recovered hydrogen
is then recycled and combined with the slurry
coming from the slurry mix tank. Hydrocarbon
cases are released and recovered, and the hydro-
gen sulfide is converted to elemental sulfur.
The slurry of undissolved solids and the coal
solution is then separated in a filtration unit, tn
a commercial-scale process, the solids would be
sent to a gasifier-converter where they would
react with supplemental coal, steam, and oxygen
to produce hydrogen for use in the process. The
coal solution passes to the solvent recovery unit,
and the product, solvent-refined coal, is produced.
This material has a heating value of approximately
16,000 Btu/lb.
A modification to the process, SRC II, also
called "slurry recycle", creates a final, liquid
product and also leads to greater yields. The
modification, which is still being tested, recycles
a portion of the slurry to the front end of the plant
so that it can be used to slurry fresh coal. More
time in the reactor and higher hydrogen pressure
help to increase the amount of liquid produced.
Information on SRC II is limited because of its
recent development.
15.2 PROCESS ADVANTAGES
SRC I:
• The process requires no catalyst and low
amounts of hydrogen relative to most alter-
native processes;
• The solid product is low in sulfur (less than
1 percent) and ash (0.2 percent or less);
• The product has a high heating value (16,000
Btu/lb).
SRC II:
• Liquid fuel produced instead of a solid;
• Results in greater yields of the final product;
Lowers the sulfur content of the fuel;
• Eliminates the solids separation step and
further solids treatment.
15.3 PROCESS LIMITATIONS
SRC I:
• Operating costs for filtration are high;
• Handling methods for the solid product
need further development.
SRC II:
• Hydrogen consumption is higher.
15.4 PROJECT HISTORY
The SRC project began in 1962 when Spencer
Chemical Company was awarded a research con-
tract by the OCR (now a part of ERDA] to study
the technical feasibility of a coal de-ashing pro-
cess, now called the SRC Process. In 1965, the
process was successfully demonstrated in a 50-
pound-per-hour continuous-flow unit, and the
work on the contract was therefore completed.
During the term of the contract, Gulf Oil Cor-
poration acquired Spencer Chemical Company.
After reorganization, the contract was assigned
to the research department of PAMCO.
To develop the SRC Process further, a contract
was awarded to PAMCO to design, construct, and
operate a pilot plant that would be capable of
processing 50 tons of coal per day. In 1968, Steams-
Roger Corporation completed the design for the
pilot plant, but funds to begin construction were
not available until late 1971. In June 1972, OCR
extended its contract with PAMCO to construct
and operate the pilot plant. Rust Engineering
Company began constructing the pilot plant in
July 1972 at Ft. Lewis, Washington, near Tacoma.
As units were completed, preliminary tests of
88
-------
SRC
process equipment and instrumentation were
performed. The pilot plant became fully oper-
ational in October 1974.
Eleven material balance runs were made on the
SRC pilot plant in the distillate solvent mode
during 1975. Five successful runs were also made
during 1975 in the slurry recycle mode. Overall,
the 50 TPD pilot plant operated smoothly through-
out 1975.
The laboratory unit was also run in both the
distillate solvent and slurry recycle mode during
1975. The variables investigated included filtra-
tion rate, solvent recycling, slurry residence time,
concentration of coal in the slurry, and temper-
ature.
The pilot plant was modified in 1977 to incor-
porate SRC II. Operations with the modifications
began in May 1977, with test runs on process
variables in progress.
15.5 ENVIRONMENTAL CONSIDERATIONS
The environmental aspects of an SRC plant are
similar to those encountered in power plants
(coal dust, flue gases), coke plants (coal tar hydro-
carbons), and petroleum refineries (solvents, tars,
and residues).
No unique problems and no greater difficulty
in meeting the environmental standards of these
industries are anticipated for a commercial SRC
plant. The effluents summary is presented in
Figure15-2.
Fugitive participates (dust) and vapors can
originate in several areas throughout the plant.
Dust emissions are imminent when the coal is
pulverized, the filter aid precoat slurry is prepared,
or the mineral residue is dried and discharged.
These emissions are controlled by using covered
conveyors and induced draft vents with the vent
gas being filtered to remove particulates. Coal is
pulverized in a gas-swept grinding mill. As the
coal is pulverized, it is dried by a hot, inert gas
and carried into a bag house. Here the dried,
powdered coal is collected for discharge into
the slurry blend tank. This operation is in a closed
system. The slurry is filtered. Diatomaceous
earth, with or without asbestos, is used as a filter
aid on the rotary filters.
In order to reduce vapors from the solvent tanks
and other vessels, they are filled with inert gas.
As the inert gas blanket is purged when a vessel
is filled, the gas and vapors are discharged into an
inert gas flow. This flow, as well as all of the other
gases purged from the plant, goes into the flare
piping system to be carried to the flare stack. All
safety relief valves are also connected to the
flare piping system. Flare burning is, supplemented,
if necessary, with natural gas.
Most of the sulfur liberated from the coal during
processing appears as hydrogen sulf ide in various
gas streams. Hydrogen sulfide and carbon di-
oxide, the acid gases, are separated from the
gas stream by an amine absorption unit. This
concentrated hydrogen sulfide stream is converted
to elemental sulfur as a by-product. In a com-
mercial plant, a Claus sulfur plant would probably
be used with an appropriate tail gas cleanup
unit.
Liquid waste.streams from the plant are com-
bined and treated in a waste treatment plant by
clarification, biological treatment, sand filtration,
and carbon filtration. No unusual or unexpected
problems have been encountered in the operation
of this equipment.
The disposal of residue raises a primarily econ-
omic question. In a commercial plant, utilization
of byproducts instead of disposal would make the
process more economical. One method is to
gasify the char. By an alternate method, a slag-
ging gasifier would convert the residue into a
relatively clean slag and synthesis gas (hydrogen
and carbon monoxide). The sulfur in the residue
would be converted into hydrogen sulfide which
would appear in the synthesis gas and could be
removed by usual acid gas removal methods.
A program has been developed for the applica-
tion of instrumental neutron activation analysis
to determine trace elements throughout the SRC
plant.
89
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. SHTFT > MrruBuATinu
RECO¥ERy » REMOVAL REMOVAL jHIFT METHANATION
t
OXYGEN
PLANT
Figure 15-2
SRC PROCESS-EFFLUENTS SUMMARY
£7\
»(ri)
/C7S
— ^0=)
(f?)
V)
99
n
-------
SRC
SRC PROCESS-EFFLUENTS SUMMARY
FOR FIGURE 15-2
Stream tt , Description
1 Cangue
2 Rain runoff
3 Dryer vent gas
4 Dust
5 Water vapor
6 Flue gas
7 Chemical purge
8 Sulfur product
9 Tail gas
10 Chemical purge
*11 Gas produced
12 Flue gas
13 Airfromairfins
*14 Naphtha product
*15 Light fuel oil
*16 Heavy fuel oil
17 Heavy fuel oil to plant fuel
18 Nitrogen
19 Slag
20 Flue gas
21 Chemical purge
22 Flue gas
23 Carbon dioxide
24 Chemical purge
25 Condensate to waste water
treatment
'Product, not an effluent
Auxiliary Facilities
A generalized discussion of auxiliary facilities
common to most coal conversion plants is given
in Appendix A.
Sulfur Balance
The SRC Process removes essentially all of the
inorganic sulfur, 60 to 70 percent of the organic
sulfur, and 98 percent of the ash in the coal. A
typical sulfur balance is given in Table 15-1.
Table 15-1
SRC PROCESS SULFUR BALANCE
Liquid products
Byproducts sulfur
Tail gas
91
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APPENDICES
-------
Appendix A
AUXILIARY FACILITIES
In addition to the gasification and liquefaction
systems, auxiliary facilities are needed to make
by-product sulfur, supply oxygen, and generate
steam and electricity. These facilities are common
to all conversion plants even though they may
differ in size and demand load and may use dif-
ferent fuels in the power generation area.
A.1 SULFUR PLANT
The most common type of sulfur recovery
plant utilizes the Claus Process. With this
process, acid gas entering the plant passes
through a knock-out vessel to remove en-
trained liquids. Gas is then blown into the
sulfur burner, where it is mixed with sufficient
air to oxidize one-third of the hydrogen sulfide
to sulfur dioxide. The combustion products
enter the reaction furnace where enough re-
sidence time is provided for the Claus reactions
to come to equilibrium. The sulfur produced
is condensed. The remaining hydrogen sulfide
is converted to sulfur through a 3-stage cata-
lytic reactor.
Since the basic Claus reaction is limited by
chemical equilibrium, the tail gas from the
Claus unit will normally have sulfur values
corresponding to 15,000 ppm of sulfur dioxide.
These sulfur values are usually present in the
form of hydrogen sulfide, sulfur dioxide, as
well as unconverted carbonyl sulfide and
carbon disulfide. A number of processes exist
to clean up this stream. One of the more com-
mon ones is the SCOTR Process or Shell-Claus
Off gas Treatment System. In most instances,
Claus offgas treatment systems will bring
sulfur levels down to acceptable limits.
One other common process for sulfur re-
covery is the Stretford Process. This process
removes hydrogen sulfide from gas streams
and recovers the sulfur in elemental form.
There are two variations of the Stretford Pro-
cess based upon where the hydrogen cyanide
is removed. In the first variation, the hydrogen
cyanide is removed from the gas in a separate
column before the removal of hydrogen sul-
fide. In the second variation, the hydrogen
sulfide and hydrogen cyanide are removed in
the same absorber. The first variation will be
higher in capital cost but lower in operating
cost, especially with respect to chemical
usage. The processing scheme selected for a
given application depends primarily on the
concentration of hydrogen cyanide in the gas.
Operating pressures of Stretford plants vary
from near atmospheric to 100 psig in the
absorber. The solution oxidizer and sulfur re-
covery systems operate at atmospheric pres-
sure. Feed gas temperatures are in the range
of80°Fto120°F.
Inlet hydrogen sulfide concentrations as low
as 300 ppm and as high as 95 percent can be
processed. The process can tolerate carbon
dioxide in any amount and hydrogen cyanide
concentrations as high as 2,000 ppm can be
handled.
A.2 UTILITIES
Perhaps the major source of contaminants
emitted to the air is the utilities system which
includes steam generation, power generation,
cooling water, treatment of make-up water and
wastewater.
The choice of fuel for the generation of the
power and steam required by the conversion
plants markedly affects the overall process
thermal efficiency and the effluents from the
utilities system. It is generally less efficient,
but much cleaner, to burn the clean product
gas for this purpose. Coal-fired boilers would
95
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require flue gas desulfurization and additional
solids handling. The effluents would be the
same as those for current coal-fired installations.
In the proposed WESCO gasification plant, an
air blown gasifier was included to make fuel
gas for the utilities system. This area, as men-
tioned earlier, does emit the largest amount of
pollutants but they can be easily contained
with current technologies.
solids in the cooling water. Consideration
should also be given to the potential fog problem
or plume associated with cooling towers due
to condensation under unfavorable atmos-
pheric conditions. These adverse environmental
impacts may be reduced by the use of a com-
mercial design which maximizes air-cooled
heat exchanges reserving the use of water for
trim cooling.
A.3 COOLING WATER
The largest effluent to the air is from the
utility cooling tower. Flow of air through the
tower may be as high as 85,000 MMSCFD.
In addition, there is a drift loss due to mist
carried out by the air. A typical estimate of
this would be 263,000 Ib/hr, although it could
be reduced considerably by using some of the
new techniques developed to control drift
loss from cooling towers. Drift can cause
deposits in the nearby area due to dissolved
A.4 WASTEWATER TREATMENT
Water streams that are directed to the water-
treating facilities will contain traces of am-
monia, phenols, and hydrocarbons. There will
be evaporation and the possibility of odors
from retention ponds and water treatment
facilities. Control of emissions in wastewater
streams is a well developed art in the pet-
roleum refining industry so that no new tech-
nologies will need to be developed. Each
treatment system will be site specific.
96
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Appendix B
COAL STORAGE AND PREPARATION
Common to all coal conversion processes
are the operations of coal cleaning, grinding,
and storage. In some instances, a drying step is
also included.
On-site storage will be required for all plants
to provide backup for continuous conversion
operations. For a commercial sized plant, thirty
days' worth of storage would require four piles,
each about 200 feet wide, 20 feet high, and 1,000
feet long. Containment of airborne dusts is gen-
erally the only air pollution control required for
transport and storage operations although odor
may be a problem in sbme instances. A covered
or enclosed conveyance system with dust removal
equipment (baghouses) may be necessary. Care-
ful management and planning will minimize
dusting and wind loss and the hazard of com-
bustion in storage facilities.
Liquid discharges from coal storage piles will
result from rain or other forms of precipitation.
The runoff from the 20 to 25 acre area during a
rainstorm could be as large as 5,000 gpm. Such
runoff would be acidic in nature and contain
a large amount of participate matter. Accordingly,
this runoff must be contained and treated to
prevent a major pollution problem. If properly
designed, this water, after treatment, may be of
sufficient purity to be used in the plant's water
system.
Coal-grinding operations associated with the
preparation operations create large amounts of
dust. During processing, air is aspirated into the
ball mill grinding operation. The air stream is
heated in a circulation system and passed through
the mills, where it serves both to control mois-
ture in the pulverizing process and transport
medium for the pulverized material. The coal/
air mixture passes through cyclones where coal
separation occurs, and the air stream is dis-
charged into the atmosphere through bag filters.
This arrangement is commercially proven, with
acceptable particulate emissions, even though
the load on the filters for a commercial plant
could amount to 60 TPD. Only trace quantities
of hydrocarbons have been detected in such
commercial streams, and odor is not considered
a problem. Collected fines from the filters are
recycled to the mill product. There should be no
solid effluent from the coal-grinding plant.
Coal drying may be required in some instances,
especially when western coal is involved. The
moisture content of western bituminous coals
averages 18 to 20 percent and lignite may contain
as much as 30 percent moisture. The majority of
the coal drying processes involve entraining sized
coal in a hot gas stream. This gas stream may be
generated through the burning of natural gas, coal
or using hot process gas generated during the
gasifying operation. Where coal is burned as a
heat source or hot process gas is used, various
sulfur, nitrogen, and organic compounds are
introduced into the dryer stack which require re-
moval or reduction in concentration in order to
meet EPA emission standards. To this end, pilot
plants have tested the use of limestone or other
suitable acceptors for reduction of sulfur com-
pounds. Depending on the size of the drying
operation, varying amounts of spent acceptor will
require disposal. In addition, if coal is burned,
coal ash will represent a solid waste which will
require handling. As with any combustion process,
chemical waste will require handling. Likewise,
with combustion processes, chemical compounds
will be released to the atmosphere in varying
amounts and must be considered in the overall
emission picture.
In addition to the proceeding processes, other
operations may be part of the plant environment
and may include coal mining, laundering, and
screening. These processes have been studied
very thoroughly and can be predicted for any
mine capacity. With proper design and main-
tenance, coal preparation areas of coal con-
version plants will not create any effluent problems.
97
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PAGE NOT
AVAILABLE
DIGITALLY
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Appendix D
LIST OF ABBREVIATIONS
AC Aktiengeselschaft - A joint stock
company under German law;
corporation
atm atmosphere(s)
BPD Barrels per day
Btu British thermal unit
Btu/hr British thermal units per hour
Btu/lb British thermal units per pound
Btu/SCF British thermal units per standard
cubic foot
COED Char-Oil Energy Development
CTD control technology development
EA environmental assessment
Eis environmental impact statement
EPA Environmental Protection Agency
ERDA Energy Research and Development
Administration
ft/sec feet per second
GmbH Gesellschaft mit beschrSnkter
Haftung • A closed corporation
under German law; Ltd.
gpm gallons per minute
Ib/cu ft pounds per cubic foot
Ib/hr pounds per hour
Ib/MM Btu .. pounds per million British thermal
units
Ibs pounds
LP liquid propane
LPG liquefied petroleum gas
MM million
MMSCFD ... million standard cubic feet per day
MW megawatt
OCR
.... Office of Coal Research; now
part of ERDA
ppm parts per million
psi pounds per square inch
psig pounds per square inch gauge
SNG substitute natural gas
SRC Solvent Refined Coal
TPD tons per day
TPH tons per hour
TPY tons per year
101
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Appendix E
CONVERSION FACTORS
To Convert From:
Btu/hour
Btu
calorie
cent! meter of Hg
centipoise
degree centigrade
degree Fahrenheit
foot
ft'/sec
gallon/min
inch
kWh
month
psi
ton (assay)
tonne
year (calendar)
To:
watt(W)
joule (J)
joule ())
pascal (Pa)
pascal (Pa • s)
degree kelvin (k)
degree celsiu»
meter(m)
meterj/sec
meter'/sec
meter (m)
joule (J)
seconds (s)
kilogram/meter1
kilogram/meter1
pascal (Pa)
kilogram (kg)
kilogram (kg)
second s(s)
Multiply by:
2.93077 E-01
1. 055056 E + 03
4.19002 E + 00
1. 33322 E +03
1.000 E — 03
tc = (tf-32)/1.8
3.048 E-01
2.831 665 E- 02
6.309020 E- 05
2.54 E- 02
3.6E+06
2.628 E + 06
2.926397 E- 04
2.76799 E 4- 04
6.894757 E +03
2.91 6667 E- 02
1.0000 E +03
3,1 536 E+ 07
103
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Appendix F
GENERAL REFERENCES
Akhtar, Seyeed, "Environmental Aspects of the
Synthoil Process for Converting Coal to
Liquid Fuels," presented at Environmental
Aspects of Fuel Conversion Technology II,
Hollywood, Florida (December 1975)
Cameron Engineers, "Synthetic Fuels Quarterly
Report," Denver, Colorado () une 1977)
Dravo Corporation, "Handbook of Casif iers and
Gas Treatment Systems," ERDA FE-1772-11.
(A summary of gas treatment systems is
contained in this document such as Claus,
Benfield, Rectisol, >Purisol, Selexol and Stret-
ford. February 1976)
ERDA, "Quarterly Report: Coal Gasification,"
ERDA 76-93/2 (April-lune 1976)'
ERDA, "Quarterly Report: Coal Liquefaction/'
ERDA 76-95/2 (April-June 1976)
ERDA, "Quarterly Report: Demonstration Plants,"
ERDA 76-96/2 (April-June1976)
Fink, Carl, "CC>2 Acceptor Process," presented
at Environmental Aspects of Fuel Conversion
Technology II, Hollywood, Florida (Decem-
ber 1975)
Green, M. I., L. J. Scotti and ). F. Jones, "Low
Sulfur Synthetic Crude Oil from Coal," pre-
sented at meeting of ACS Division of Fuel
Chemistry, Los Angeles, California (April 1974)
Hamshar, J. A., H. D. Terizian and L. J. Scotti,
"Clean Fuels from Coal by the COED Process,"
St. Louis, Missouri (May 1974)
Hebden, D., "High Pressure Gasification Under
Slagging Conditions," Proceedings of the
Seventh Synthetic Pipeline Gas Symposium,
American Gas Association, Chicago (Oct-
ober 1975)
Hendrickson, T. A., "Synthetic Fuels Data Hand-
book," Cameron Engineers, Inc. Denver
(1975)
Hoogendoorn, Jan C., "New Applications of the
Fischer-Tropsch Process," presented at the
Clean Fuels from Coal Symposium II, Chicago,
Illinois (June1975)
Howard-Smith, I. and G. j. Werner, "Coal Con-
version Technology: A Review," Millmerran
Coal Pty., Ltd., Brisbane, Australia (May 1975)
Kliewer, V., "Bi-Gas Process/' presented at Environ-
mental Aspects of Fuel Conversion Technology
II, Hollywood, Florida (December 1975)
Schora, Frank C., "Effluent Considerations in
Coal Gasification," presented at Environ-
mental Aspects of Fuel Conversion Tech-
nology II, Hollywood, Florida (December 1975)
University of Oklahoma, Science and Public Policy
Program, "Energy Alternatives: A Com-
parative Analysis," Prepared for CEQ, ERDA,
EPA, FEA, FPC, DOI, NSF, Norman, Okla-
homa (May 1975)
Wall Street Journal, "Pragmatic Planners: Firms
Put Off Energy Steps Pending U.S. Action,"
New York, New York (May 1977)
105
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Appendix G
EPA REPORTS ON SYNTHETIC FUELS FROM COAL
The following reports were published before October 1976.
EPA No.* NTISNo.** Title and Date
EPA-600/2-76-177b PB 260-475/AS "Fuel Contaminants: Volume 2. Removal Technology Eval-
uation," Battelle Columbus Labs (September 1976)
EPA-600/2-76-259 PB261-916/AS "Initial Environmental Test Plant for Source Assessment of
Coal Gasification," Institute of Gas Technology (September 1976)
EPA-600/2-76-177a PB 256-020/AS "Fuel Contaminants: Volumel. Chemistry," Battelle Columbus
Labs (July 1976)
EPA-600/2-76-149 PB257-182/AS "Symposium Proceedings: Environmental Aspects of Fuel
Conversion Technology, II (December 1975, Hollywood, Florida),"
Research Triangle Park (June 1976)
EPA-600/2-76-153 PB257-134/AS "Fuel Gas Environmental Impact," United Technologies Re-
search Center (June 1976)
EPA-600/2-76-102 PB 253-946/AS "Environmental Aspects of Retrofitting Two Industries to Low
and Intermediate Energy Gas from Coal," Battelle Columbus
Labs (April 1976)
EPA-600/2-76-101 PB255-842/AS "Evaluation of Pollution Control in Fossil Fuel Conversion
Processes: Final Report," Exxon Research and Engineering
(April 1976)
EPA-600/2-75-078 PB 249-454/AS
EPA-650/2-74-O09m PB 249-847/AS
"Fuel Gas Environmental Impact: Phase Report," United Tech-
nologies Research Center (November 1975)
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Liquefaction: Section 3. H-Coal Process," Exxon
Research and Engineering (October 1975)
* Available through U.S. EPA, National Environment Research Center, Research Triangle Park, North
Carolina 27711, (919) 549-8411.
** Available through the National Technical Information Service, U.S. Department of Commerce, 5285
Port Royal Road, Springfield, Virginia 22151, (703)321-8654.
107
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EPA No.
NTIS No.
EPA-650/2-74-0091 PB249-845/AS
E PA-650/2-74-009k PB 246-311 /AS
E PA-650/2-74-009j P B 249-846/AS
EPA-650/2-74-0091 PB 247-226/AS
EPA-650/2-74-009h PB 247-225/AS
EPA-650/2-74-009g PB 243-694/AS
EPA-650/2-74-009f PB241-792/AS
E PA-650/2-74-0096 PB 240-371 /AS
Title and Date
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Analytical Test Plan," Exxon Research and Engi-
neering (October 1975)
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Coal Treatment: Section 1. Meyers Process," Exxon
Research and Engineering (September 1975)
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Gasification: Section 8. Winkler Process," Exxon
Research and Engineering (September 1975)
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Gasification: Section 7. U-Gas Process," Exxon
Research and Engineering (September 1975)
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Gasification: Section 6. Hygas Process," Exxon
Research and Engineering (August 1975)
"Evaluation of Pollution Control in Fossil Fuel Conversion Pro-
cesses-Gasification: Section 5. Bi-Gas Process," Exxon Research
and Engineering (March 1975)
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Liquefaction: Section 2: SRC Process," Exxon Re-
search and Engineering (March 1975)
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Liquefaction: Section 1: COED Process," Exxon
Research and Engineering (January 1975)
E PA-650/2-74X)09d PB 241 -141 /AS
EPA-650/2-74-009C PB237-694/AS
E PA-650/2-74-009b PB 237-113/AS
EPA-650/2-74-118
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Gasification: Section 1, CO2 Acceptor Process,"
Exxon Research and Engineering(December1974)
"Evaluation of Pollution Control in Fossil Fuel Conversion Pro-
cesses - Gasification: Section 1: Lurgi Process," Exxon Research
and Engineering (July 1974)
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Gasification: Section 1: Synthane Process," Esso
Research and Engineering (June1974)
PB238-304/AS "Symposium Proceedings: Environmental Aspects of Fuel
Conversion Technology," Research Triangle Park (May 1974)
108
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EPA No.
NTIS No.
EPA-650/2-74-052 PB237-116/AS
EPA-650/2-74-009a PB231-675/AS
Title and Date
"Study of Potential Problems and Optimum Opportunities in
Retrofitting Industrial Processes to Low and Intermediate
Energy Gas from Coal," Battelle Columbus Labs (May 1974)
"Evaluation of Pollution Control in Fossil Fuel Conversion
Processes - Gasification: Section 1. Koppers-Totzek Process,"
Esso Research and Engineering (January 1974)
EPA-R2-73-249 PB 225-O39/AS "Potential Pollutants in Fossil Fuels," Esso Research and Engi-
neering (J u ne 1973)
109
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Appendix H
GLOSSARY
Acceptor - Calcined carbonate that absorbs carbon
dioxide evolved during gasification, liberating
heat.
Acid gas - The hydrogen sulfide and carbon dioxide
found in a gas stream.
Agglomerates - Assemblages of ash particles
rigidly joined together, as by partial fusion
(sintering).
Annulus - The void space between two concentric
pipes of different diameter.
Ash - Solid residue remaining after the combustion
of coal.
Bench-scale testing - Testing of materials, methods,
or processes on a small scale such as on a
laboratory worktable.
Benfield Process - The Benfield hot potassium
carbonate process was developed at the U.S.
Bureau of Mines, Bruceton, Pennsylvania,
in the early 1950's. Their work has since
been widely used for scrubbing of CC>2 and
H2S from industrial gases at moderate to
high temperatures.
Calcine - To heat to a high temperature with-
out fusing; to heat ores, precipitates, concen-
trates or residues so that hydrates, carbon-
ates, or other compounds are decomposed
and volatile matter is expelled.
Catalytic cracking - The partial decomposition
of high molecular weight organic compounds
into lower molecular weight compounds, as
the result of catalytic reaction.
Char - To reduce to charcoal or carbon by ex-
posure to heat; coke made by the low-temp-
erature carbonization of lignite.
Claus Process - Industrial method of obtaining
elemental sulfur through the partial oxidation
of gaseous hydrogen sulfide in the air fol-
lowed by catalytic conversion to molten sulfur.
Coke - Strong porous residue consisting of carbon
and mineral ash formed when bituminous
coal is heated in a limited air supply or in
the absence of air. Coke may also be formed
by thermal decomposition of petroleum
residues.
Condenser - A heat-transfer device that reduces
a thermodynamic fluid from its vapor phase
to its liquid phase.
Cresols - A combination of isomers, derived from
coal tar; a yellowish liquid with a phenolic
odor; used as a disinfectant; used in the
manufacture of resins, and flotation of ore.
Cyclone - Essentially a settling chamber to sep-
arate solid particles from a gas, in which
gravitational acceleration is replaced by
centrifugal acceleration.
Diatomaceous earth - A yellow, white, or light
gray, siliceous, porous deposit made of the
opaline shells of diatoms; used as a filter
aid, absorbent, and thermal insulator.
Dowtherm - A trade name for any of several
eutectic mixtures of diphenyl oxide and
diphenyl; used in liquid and vapor form as
a heat-transfer fluid.
Ebullated-bed - Gas, containing a relatively small
proportion of suspended solids, bubbles
through a higher density f luidized phase with
the result that the system takes on the
appearance of a boiling liquid.
Effluent - A liquid, gas, or solid waste that has
passed through a processing operation.
111
-------
Feed - Process or act of supplying material to a
processing unit for treatment; the material
supplied to a processing unit for treatment.
Fixed-bed - A process in which the additive mat-
erial (catalyst, absorbent, filter media) re-
mains stationary in the chemical reactor.
Fluidized-bed (Fluid-bed) - Assemblage of small
solid particles maintained in balanced sus-
pension against gravity by the upward mo-
tion of a gas.
Casifier - Apparatus which converts coal to gas-
eous fuel.
Hopper - A funnel-shaped receptacle with an
opening at the top for loading and a dis-
charge opening at the bottom for bulk-
delivering material such as coal.
Hydroclone - A cone shaped liquid-cleaning
apparatus operated by centrifugal separation
that is used for separating solid particles from
a liquid.
Mercaptans - A descriptive name for most organic
compounds containing the sulfhydryl group.
Moving-bed - A process whereby granulated
solids are circulated (moved) either mech-
anically or by gravity flow. Used in catalytic
and absorption processes.
Naphthalene - White, volatile crystals with coal
tar aroma; insoluble in water, soluble in or-
ganic solvents; used for fungicides, lubricants,
and resins, and as a solvent.
pH - A measurement of the acidic or basic char-
acter of a substance.
Phenols - Aromatic ring compounds which possess
one or more hydroxyl radicals as the pri-
mary group.
Preheater - A device for preliminary heating of
a process stream that will undergo further
use or treatment.
Pulverization - Breaking up or grinding into small
fragments.
Purisol Process - Developed by Lurgi Mineraloe-
technik GmbH in West Germany for removal
of acid gases from natural gas, hydrogen and
synthesis gas by physical absorption in N-
Methyl-2-Pyrrolidone (NMP or M-Pyrol).
The process is used for reduction of high
CC»2 concentrations, bulk removal of acidic
components, and selective ^S removal.
Pyridine - Organic base; flammable, toxic yellow-
ish liquid, with penetrating aroma and burn-
ing taste; used as a solvent.
Pyrolysis - The breaking apart of complex mole-
cules into simpler units by the use of heat.
Quinoline - Water-soluble, aromatic nitrogen
compound; colorless, hygroscopic liquid;
used as a chemical intermediate.
Raw gas - Gas which has not been purified.
Reactor - Device or process vessel in which chem-
ical reactions take place during a chemical
conversion type of process.
Rectisol Process - Developed and licensed by
American Lurgi Corporation. The process
utilizes methanol for removal of acid gases
by physical absorption at relatively low
temperatures. The process is used for removal
of H2S, CO2, HCN, NH3, gum-forming hydro-
carbons, and other impurities from coal or
oil gasification processes that produce fuel
gas, synthesis gas or methanol.
Refractories - Materials of very high melting
points with properties that make them suitable
for such uses as furnace linings.
Regenerator - Device or system designed to re-
store a chemical to its original level of activity.
Residue - The product remaining after separation.
112
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Selexol Solvent Process - Developed by Allied
Chemical Corporation in the early 1960's.*
The process utilizes dimethyl ether of poly-
ethylene glycol to remove h^S, CC>2, and
other acidic and non-acidic components from
industrial gases by physical absorption.
Applications include sour natural gas, syn-
thesis gas. and refinery gases.
Slag - Molten coal ash composed primarily of
silica, alumina, iron oxides, and calcium and
magnesium oxides.
Slurry - A suspension of pulverized solid in a
liquid.
Stream - A body of flowing liquid or gas carrying
various input or discharge materials to and
from the process apparatus.
Stretford Process - Originally developed by the
North Western Gas Board of the British Gas
Corporation, this process primarily removes
hydrogen sulfide from gas streams by chem-
ical absorption. Elemental sulfur is produced
by the process.
Sweet crude - Crude petroleum oil containing
little sulfur.
Syncrude-Synthetic crude-Oil produced by the
processing of coal, coal extracts, oil sands,
or oil shale.
Tail gas - A gas issuing from a gas-treatment
unit which may be recycled to the process
or exhausted.
Tuyere - An opening in the shell and refractory
lining of a furnace through which air is forced.
Xylenols - Highly toxic, combustible crystals;
slightly soluble in water, soluble in most
organic solvents; used as a chemical inter-
mediate, disinfectant, solvent and fungicide.
113
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-102
3. RECIPIENT'S ACCESSION'NO.
4. TITLE AND SUBTITLE
EPA Program Status Report:
Synthetic Fuels from Coal
Including Process Overview with Emphasis
on Environmental Considerations
S. REPORT DATE
July 1977
6. PERFORMING ORGANIZATION CODE
7.AUTHORS Altschuler, Morris
Eckstein, Linda
Hook, Charles 0.
Roe, Donald E.
Zalkind, Joseph
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Cameron Engineers, Inc.
1315 South Clarkson Street
Denver, Colorado 80210
10. PROGRAM ELEMENT NO.
INE-623
11. CONTRACT/GRANT NO.
68-01-4337
17. SPONSORING AGENCY NAME AND ADDRESS
Office of Energy, Minerals and Industry
U.S. Environmental Protection Agency
Washington, DC 20460
13. TYPE OF REPORT AND PERIOD COVERED
•Program Status: As of July 1977
14. SPONSORING AGENCY CODE
EPA/600/17
T5. SUPPLEMENTARY NOTES
EPA Contact:
Mr. Morris Altschuler
Mr. WII I jam N. McCarthy,
Jr.
(202)
(202)
426-2683
755-2737
16. ABSTRACT
The status of EPA's Synthetic Fuels from Coal Program as of
July 1977 is presented. Processes with emphasis on environ-
mental considerations are also described. This program is a
part of EPA's interagency energy-related environmental re-
search program directed toward providing the necessary tech-
nology for meeting near-term and long-term energy require-
ments in an environmentally acceptable manner. The objective
of the program is to assess the environmental impacts from
processes for producing synthetic fuels from coal, and develop
appropriate pollution-control technology.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollutlon
Coal Gasification
Coal Liquefaction
Control Technology Development
CTD
EA
Env i ronmentaI Assessment
Environmental Impacts
Gasification
High-Btu Gasification
Liquefaction
Low-3tu Gasification
Medium-8tu Gasification
Sol Id Waste
Synthetic Fuels
Water Pollution
31-GAS 'Koppers-Totzek
Coal con Lurg! Process
COED. Slagging/Lurgl Gasifler
Solvent Refined Coal
SRC
ri scner-Tropscht Synthane
H-Coal Xellman-Galusha
HYGAS Winkler
C02 Acceptor
Donor Solvent
07A
07B
07D
08D
08G
IOA
I4A
I4B
18. DISTRIBUTION STATEMENT
Release UnIimited
Aval. I able free from OEM I/EPA
while the supply lasts.
19. SECURITY CLASS (ThisReport)
Unclass i f ied
21. NO. OF PAGES
2O. SECURITY CLASS (This page)
Unclassi f ied
22. PRICE
EPA Form 2220-1 (9-73)
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