United States Industrial Environmental Research EPA-600 7-78-186a
Environmental Protection Laboratory September 1978
Agency Research Triangle Park IMC 2771 1
Environmental Assessment
Data Base for High-Btu
Gasification Technology:
Volume I.
Technical Discussion
nteragency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, US Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine 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
8 'Special' Reports
9 Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT 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 sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses 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 environ-
mental issues.
REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect the
views and policies of the Government, 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 Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-186a
September 1978
Environmental Assessment Data
Base for High-Btu
Gasification Technology:
Volume I. Technical Discussion
by
M. Ghassemi, K. Crawford, and S. Quinlivan
TRW Environmental Engineering Division
One Space Park
Redondo Beach, California 90278
Contract No. 68-02-2635
Program Element No. EHE623A
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
This report has been prepared as part of a comprehensive program for the
environmental assessment of high Btu gasification technology. The program is
being directed by the Fuel Process Branch of EPA's Industrial Environmental
Research Laboratory, Research Triangle Park, N.C. This document summarizes
and analyzes the existing data base for the environmental assessment of the
subject technology and identifies limitations of the available data.
To enable systematic data analysis, high Btu gasification technology was
divided into a number of operations and auxiliary processes. These were fur-
ther subdivided/grouped into a number of process modules. Data sheets were
prepared for individual processes in a module presenting key process informa-
tion, input and waste stream characteristics and gaps in the existing data.
Where applicable, the data sheets were sent to process developers/licensors
and technical experts for review. Each process was evaluated for applicability
to high Btu gasification. Gas treatment and pollution control options in
integrated commercial SNG facilities were examined.
The results of the data base analysis indicate that there currently are
insufficient data for comprehensive environmental assessment. The data are
limited since (1) there are no integrated plants, (2) some of the pilot plant
data are not applicable to commercial operations, (3) the available pilot
plant data are generally not very comprehensive in that not all streams and
constituents/parameters of environmental interest are addressed, (4) there is
a lack of experience with control processes/equipment in high Btu gasification
service, and (5) toxicological and ecological implications of constituents in
high Btu gasification waste streams are not established. A number of programs
are currently under way or planned which should generate some of the needed
data.
This report consists of three volumes. Volume I presents the summary
and analysis of the data base; Volumes II and III contain the "data sheets."
ii
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CONTENTS
Abstract ii
Figures xj
Tables - xi1
Acknowledgment xiv
1.0 Introduction 1
1.1 Background 1
1.2 EPA Synthetic Fuels Environmental Assessment/Control
Technology Development Program 2
1.3 Methodology for the Preparation of the Data Base Document 3
1.4 Organization of the Report 10
2.0 Gasification Operation 11
2.1 General Principles of and Approaches to High Btu
Gasification 11
2.2 Key Features of High Btu Gasification Processes 15
2.3 Status of High Btu Gasification Technology 21
2.3.1 Existing and Proposed Commercial Projects 22
2.3.2 Proposed Demonstration Projects 24
2.3.3 Pilot Projects 25
2.3.4 Bench/PDU Scale Projects 28
2.4 Discharge Streams 29
2.4.1 Product Gases 29
2.4.2 Dusts, Tars and Oils, and Aqueous Condensates ... 31
2.4.3 Char/Ash 33
2.4.4 Lockhopper Vent Gases 33
2.4.5 Flue or Off-Gases 35
2.5 Data Gaps and Limitations 36
iii
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CONTENTS (Continued)
2.6 Related Programs 41
2.6.1 EPA-Sponsored Programs 41
2.6.2 DOE-Sponsored Programs - Pilot Plants 42
2.6.3 DDE-Sponsored Programs - National Laboratories and
Other Programs 44
3.0 Gas Purification Operation 46
3.1 Requirements for Acid Gas Removal 46
3.2 Acid Gas Removal Processes 49
3.2.1 Hot Gas H2S Removal 49
3.2.2 Solvent Processes for Acid Gas Removal 49
3.2.3 Methanation Guards 53
3.3 Discharge Streams 55
3.4 Data Gaps and Limitations 56
3.5 Related Programs 56
4.0 Gas Upgrading Operation 58
4.1 Shift Conversion 58
4.1.1 Shift Conversion Catalysts 58
4.1.2 Discharge Streams 59
4.1.3 Data Gaps and Limitations and Related Programs . . 60
4.2 Methanation and Drying 61
4.2.1 Process Principles 61
4.2.2 Discharge Streams 62
4.2.3 Data Gaps and Limitations and Related Programs . . 63
5.0 Air Pollution Control Operation 64
5.1 Sources and Characteristics of Gaseous Emissions 64
5.1.1 Pretreatment Off-Gases 66
5.1.2 Lockhopper Vent Gases 66
5.1.3 Concentrated Acid Gases 68
5.1.4 Catalyst Regeneration/Decommissioning Off-Gas ... 69
5.1.5 Char Combustion, Incineration and Transient Waste
Gases 69
5.1.6 Depressurization, Stripping, and Vent Gases .... 70
IV
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CONTENTS (Continued)
5.2 Air Pollution Control Processes 71
5.2.1 Sulfur Recovery 74
5.2.2 Tail Gas Treatment 76
5.2.3 SOg Control and/or Recovery 79
5.2.4 Incineration 82
5.2.5 CO, Hydrocarbon and Odor Control 82
5.2.6 Particulate Control 83
5.2.7 Gas Compression and Recycling 85
5.2.8 NO Control 86
A
5.3 Air Pollution Control in Integrated Facilities 86
5.3.1 Control of Sulfur Emissions 87
•
5.3.2 Control of Particulate Emissions 89
5.3.3 Control of Carbon Monoxide, Hydrocarbons and
Odorous Emissions 90
5.3.4 Control of Non-Criteria Pollutant Emissions .... 92
5.4 Data Gaps and Limitations 93
5.5 Related Programs 95
6.0 Water Pollution Control Operation 96
6.1 Sources and Characteristics of Aqueous Wastes 96
6.1.1 Particulate Scrubber Waters 99
6.1.2 Raw Gas Quench Waters 99
6.1.3 Ash Quench Waters 101
6.1.4 Shift Condensate 102
6.1.5 Methanation Condensate 103
6.1.6 Waste Sorbents and Reagents 103
6.1.7 Miscellaneous Wastewaters 103
6.2 Water Pollution Control Processes 104
6.2.1 Oil and Suspended Solids Removal 106
6.2.2 Dissolved Gases Removal 108
6.2.3 Dissolved/Parti oil ate Organic Removal 109
6.2.4 Separated Tar/Oil and Sludge Treatment 115
6.2.5 Dissolved Inorganics Removal 116
6.2.6 Evaporation/Retention Ponds 117
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CONTENTS (Continued)
6.3 Wastewater Management at Integrated Facilities ...... 119
6.3.1 Wastewater Segregation and By-Product Recovery . . 120
6.3.2 Wastewater Treatment ............... 120
6.3.3 Water Reuse and Recycling and Good Housekeeping
Practices ....................
6.4 Data Gaps and Limitations ................ 124
6.5 Related Programs ..................... 126
7.0 Solid Waste Management .................... 128
7.1 Sources and Characteristics of Solid Wastes ....... 128
7.1.1 Char and Ash ................... 130
7.1.2 Spent Catalysts .................. 130
7.1.3 Inorganic Solids and Sludges ........... 131
7.1.4 Tar and Oil Sludges ................ 132
7.1.5 Biosludges .................... 132
7.2 Solid Waste Disposal Processes .............. 133
7.2.1 Resource Recovery ................. 135
7.2.2 Incineration ................... 136
7.2.3 Soil Application ................. 137
7.2.4 Land Burial /Landfil ling (Including Pretreatment) . . 137
7.3 Solid Waste Management at Integrated Facilities ..... 137
7.4 Data Gaps and Limitations ................ 140
7.5 Related Programs ..................... 140
8.0 Summary of Data Gaps and Limitations and Related Programs ... 142
8.1 Major Factors Responsible for Data Gaps and Limitations . . 142
8.2 Specific Data Gaps and Limitations ............ 143
8.3 Related Programs ..................... 147
9.0 References .......................... 151
Appendices
Appendix A - Gasification Operation .............. Vol. II
Appendix B - Gas Purification Operation ............ Vol. II
Appendix C - Gas Upgrading Operation ............. Vol. II
Appendix D Air Pollution Control .............. Vol. Ill
Appendix E - Water Pollution Control ............. Vol. Ill
Appendix F - Solid Waste Management .............. Vol. Ill
vi
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CONTENTS FOR VOLUME II
APPENDIX A - GASIFICATION OPERATION A-l
Dry Ash Lurgi Process A-2
Slagging Gasification Process A-25
Cogas Process A-41
Hygas (Steam Oxygen) Process A-63
C02-Acceptor Process A-88
Synthane Process A-l18
Bigas Process A-l37
Battelle-Carbide (Self-Agglomerating Ash) Process .... A-l52
Hydrogasification (Hydrane) Process A-162
Koppers-Totzek Process A-l78
Texaco Process A-196
APPENDIX B - GAS PURIFICATION OPERATION B-l
Acid Gas Removal Module
Physical Solvents
Rectisol Process B-2
Rectisol (Dual Absorption Mode) Process B-14
Selexol Process B-21
Purisol Process B-29
Estasolvan Process B-35
Fluor Solvent Process B-41
Amines
Sulfiban (MEA) Process B-48
MDEA Process B-54
SNPA-DEA Process B-60
ADIP Process B-66
Fluor Econamine (DGA) Process B-73
Alkazid (Alkacid) Process B-80
vii
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CONTENTS FOR VOLUME II (Continued)
Mixed Solvents
Sulfinol Process B-86
Amisol Process B-95
Carbonate Processes
Benfield (Hot Carbonate) Process B-100
Redox Processes
Giammarco-Vetrocoke (G-V) Process B-113
Stretford Process B-121
Methanation Guard Module
Zinc Oxide Adsorption Process B-130
Iron Oxide Adsorption Process B-137
Metal Oxide Impregnated Carbon Process B-146
Activated Carbon Process (Organics Removal from
Gases) B-152
Molecular Sieves Process B-158
APPENDIX C - GAS UPGRADING OPERATION C-l
Shift Conversion Module
Cobalt Molybdate Process C-2
Methanation and Drying Module
Fixed-Bed Methanation Process C-ll
Fluidized-Bed Methanation Process C-25
Liquid Phase Methanation/Shift (LPM/S) Process .... C-31
viii
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CONTENTS FOR VOLUME III
Page
APPENDIX D - AIR POLLUTION CONTROL D-l
Hydrogen Sulfide Control Module
Claus Process D-2
Stretford Process (See Acid Gas Removal Module,
Appendix B)
Giammarco-Vetrocoke Process (See Acid Gas Removal
Module, Appendix A)
Tail Gas Treatment Module
SCOT Process D-13
Beavon Process D-20
IFP Process D-30
Sulfreen Process D-40
Cleanair Process D-46
Sulfur Oxides Control Module
Wellman-Lord Process D-51
Chiyoda Thoroughbred 101 Process D-61
Shell Copper Oxide Process D-70
Lime-Limestone Slurry Scrubbing Process D-77
Double Alkali Process D-92
Magnesium Oxide Scrubbing Process D-108
Particulate Control Module
Fabric Filtration Process D-123
Electrostatic Precipitation Process D-l30
Venturi Scrubbing Process D-l36
Cyclones D-142
ix
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CONTENTS FOR VOLUME III (Continued)
Hydrocarbon and Carbon Monoxide Control Module
Thermal Oxidation Process D-148
Catalytic Oxidation Process D-154
Activated Carbon Adsorption Process (see
Methanation Guard Module, Appendix 6}
APPENDIX E - WATER POLLUTION CONTROL E-l
Oil and Suspended Solids Removal Module
Gravity Separation Process (API Separators) E-2
Flotation Process E-10
Filtration Process E-18
Coagulation-Flocculation Process E-24
Dissolved Gases Removal Module
Steam Stripping Process E-36
USS Phosam W Process E-45
Chevron WWT Process E-52
Dissolved/Particulate Orgam'cs Removal Module
Biological Oxidation Process E-60
Evaporation/Retention Pond Process E-77
Chemical Oxidation Process E-80
Phenosolvan Process E-93
Activated Carbon Adsorption Process E-100
Sludge Treatment Module
Gravity Thickening Process E-l18
Centrifugation Process E-l23
Vacuum Filtration Process E-132
Drying Beds E-140
Emulsion Breaking Process E-l45
APPENDIX F - SOLID WASTE MANAGEMENT F-l
Incineration Process F-2
Land Disposal Process F-9
Chemical Fixation/Encapsulation Process F-18
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FIGURES
Number Page
1-1 High Btu Gasification Operations and Process Modules 4
2-1 Process Modules for Gasification Operation 13
2-2 Hygas Pilot Plant Sampling Point Diagram 28
3-1 Process Module for Gas Purification Operation 47
5-1 Process Modules Generating Gaseous Wastes in a Typical High
High Btu Gasification Plant 65
5-2 Process Module for Air Pollution Control •. . 73
6-1 Major Process Modules Generating Aqueous Wastes in a Typical
High Btu Gasification Plant 97
6-2 Process Module for Water Pollution Control 105
6-3 Proposed El Paso Burnham Gasification Plant Water Management
System 121
7-1 Process Modules Generating Solid Wastes in an Integrated High
Btu Gasification Facility 129
7-2 Process Module for Solid Waste Management 134
x1
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TABLES
Number Page
1-1 List of Process Developers/Licensors to Whom Data Sheets
Were Sent for Review and the Status of Responses Received . 6
2-1 Gasification Processes Evaluated 12
2-2 Key Features of High Btu Gasification Processes 16
2-3 Advantages and Disadvantages of High Btu Gasification
Processes 19
2-4 Proposed High Btu Gasification Commercial and Demonstration
Projects, and Pilot and Bench PDU Programs 23
2-5 Typical Sulfur and Nitrogen Species Composition of Raw
Product Gas 30
2-6 Summary of Normalized Constituents Production for Gasification
Process (kg/1000 kg Moisture and Ash Free Coal) 32
2-7 Percentages of Selected Feed Coal Trace Elements Retained
With Char or Ash in Gasification Processes 34
2-8 Hygas Pilot Plant Stream Characterization Data Collected or
Planned to be Collected by IGT and Additional Data Needed
by EPA for Discharge Stream Characterization 39
3-1 O>2 to H2S Ratios in the Shifted Product Gas for Various
Gasification Processes 48
3-2 Hot Gas H-S Removal Processes Under Development 49
3-3 Key Features of Solvent Processes for Acid Gas Removal ... 51
3-4 Features of Methanation Guards 54
5-1 Composition of Gaseous Waste Streams 67
5-2 Air Pollution Control Processes Reviewed for Application to
High Btu Gasification 72
5-3 General Characteristics of Sulfur Recovery Processes .... 75
5-4 Key Features of Sulfur Recovery Tail Gas Treatment Processes 77
5-5 Key Features of Lime/Limestone Slurry and Dual Alkali
Scrubbing Processes 81
5-6 Key Features of Particulate Control Equipment 84
5-7 Options for the Management of Sulfur-Bearing Waste Gases in
Integrated Facilities 88
xii
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TABLES (Continued)
Number
6-1 Aqueous Waste Streams Associated with Different High Btu
Gasification Processes
6-2 Surrmary of the Reported Characteristics of Wastewaters from
High Btu Gasification Processes .............. TOO
6-3 Trace Elements Reported in Product Gas Quench Waters .... 102
6-4 Wastewater Treatment Processes Reviewed for Application to
High Btu Gasification ................... 106
6-5 Efficiency of Biological Treatment for Petroleum Refinery
Effluents ......................... Ill
6-6 Solids Concentration Obtained by Various Sludge Concentrating
Processes .........................
6-7 Features of Dissolved Inorganics Removal Processes ..... 118
6-8 Wastewater Treatment Processes Used at the Sasol Plant and
Those Proposed for Use at Commercial Facilities in the U.S. 123
8-1 Summary of Data Gaps and Limitations for the Gasification
Operation ......................... 145
8-2 Summary of Data Gaps and Limitations for Gas Purification and
Upgrading Operations ................... 146
8-3 Summary of Some EPA-Sponsored Programs ........... 148
8-4 Summary of Some DDE-Sponsored Programs ........... 147
xiil
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ACKNOWLEDGEMENT
This document has been prepared by TRW under the technical direction of
Dr. Masood Ghassemi. The following individuals have participated in the pre-
paration of the document.
Data Evaluation and Final Report Preparation
M. Ghassemi
K. Crawford
S. Quinlivan
Data Sheet Preparation
K. Crawford S. Quinlivan
J. Col ton K. Scheyer
M. Ghassemi D. Strehler
J. Gordon C. Thome
G. Houser R. Tobias
B. Jackson S. Unger
P. LaRosa
The project is deeply indebted to the EPA Project Officer, Mr. William
J. Rhodes, for his continuing advice and guidance during the course of the
effort. Those on the project staff wish to express their gratitude to the
process developers/licensors listed in Table 1-1 who supplied data for the
preparation of data sheets and who reviewed and provided constructive criticism
of the data sheets. Thanks are due to Mr. Jesse Cohen of EPA Municipal Environ-
mental Research Laboratory (Cincinnati), Dr. Kirk Willard of EPA Industrial
Environmental Research Laboratory (Cincinnati)and the technical staff of EPA
Industrial Environmental Research Laboratory (Research Triangle Park) who re-
viewed certain data sheets and portions of the draft final report.
Thanks are due to Mr. Charles F. Murray, the TRW Program Manager, for
interfacing with EPAandDOE and for providing project support. The authors
wish to express their gratitude to Mrs. Maxine Engen for her editorial review
and secretarial services, and to Ms. Marilyn Jennings and Ms. Alexandra Saur
for their editorial review.
xiv
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1.0 INTRODUCTION
1.1 BACKGROUND
The recognition of the limited availability of the domestic supplies of
natural gas and crude oil and the desire to reduce the country's dependence
on foreign sources of energy have promoted considerable interest in this
country in developing alternative domestic sources of fuel. Because of the
abundance of mineable coal reserves in the U.S., the greater use of coal,
directly or after conversion to substitute natural gas (S'JG) or oil products,
is receiving increasing emphasis. Although coal can be substituted for
natural gas and petroleum for industrial and utility steam and power genera-
tion, for technical and economic reasons coal cannot replace oil and gas in
applications such as residential heating and transportation. Even if coal
could be substituted for oil and gas, in certain applications such substitu-
tion ca.n present enormous pollution control problems. For example, it would
be very difficult and costly to install, operate and maintain pollution con-
trol systems on large numbers of small and scattered residential and commer-
cial furnaces. Coal can be converted to clean liquid and gaseous fuel which
can then be conveniently substituted for natural gas and petroleum products
without requiring end use equipment modification or pollution control. From
the standpoint of storage and transportation, the use of SNG and coal-derived
liquid fuels also offers advantages over direct coal utilization since the
existing gas and oil pipeline and truck and rail distribution systems can be
utilized without major modifications. Because of the potential benefits
associated with the conversion of coal to synthetic fuels, a number of pro-
grams, sponsored by both the government and private industry and aimed at
developing new conversion technologies and improving and/or commercializing
the existing ones for domestic use, are currently under way.
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1.2 EPA SYNTHETIC FUELS ENVIRONMENTAL ASSESSMENT/CONTROL TECHNOLOGY
DEVELOPMENT PROGRAM
Although coal conversion processes can produce clean-burning fuels,
unless properly designed and operated, large scale facilities for the con-
version of coal to gaseous or liquid fuels can by themselves constitute
major sources of environmental pollution. In response to the increasing
activities related to synthetic fuels, the Environmental Protection Agency
has initiated a comprehensive assessment program to evaluate the environ-
mental impacts of synthetic fuels from coal processes having a high potential
for eventual commercial application. This overall assessment program is
being directed by the Fuel Process Branch of EPA's Industrial Environmental
Research Laboratory, Research Triangle Park (IERL-RTP). The primary objec-
tives of the EPA synthetic fuels from coal program are to define the environ-
mental effects of synthetic fuel technologies with respect to their multi-
media discharge streams and their health and environmental impacts and to
define control technology needs for an environmentally sound synthetic fuel
industry. The synthetic fuel technologies being addressed in the EPA pro-
gram include high Btu gasification, low/medium Btu gasification and coal
liquefaction. To achieve the program's overall objectives, the EPA has de-
fined six major tasks areas, each being supported through contract services.
These six task areas are Environmental Assessment of High Btu Gasification,
Environmental Assessment of Coal Liquefaction, Control Technology Develop-
ment, Waste Stream Disposal and Utilization, and General Support. TRW is the
EPA contractor for the Environmental Assessment of High Btu Gasification.
The specific objectives of the TRW program are (a) to characterize waste
streams associated with the operation of commercial high Btu gasification
facilities which use current and developmental technologies; (b) to identify
control technologies required to reduce emissions to acceptable levels; and
(c) to estimate environmental impacts. The study will provide input to the
EPA effort for assessing the environmental impact, providing background for
regulatory agencies and evaluating control technologies for the emerging
coal gasification industry. The TRW effort consists of: (a) evaluation of
existing process and environmental data and the data which are being generated
by other EPA/DOE contractors and process developers working in related areas;
(b) acquisition of supplementary data through sampling and analysis of process/
2
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waste streams at selected gasification facilities; and (c) environmental
assessment and necessary process engineering support studies.
As the first step toward detailed environmental assessment, TRW has
reviewed the existing data on coal gasification and related operations and
has identified gaps in and limitations of the existing data. The effort has
included a preliminary impact assessment of high Btu gasification technologies.
The findings are presented in this document.
1.3 METHODOLOGY FOR THE PREPARATION OF THE DATA BASE DOCUMENT
The data used in the preparation of this document have been obtained
from several sources,including (a) published and unpublished EPA documents,
(b) open literature, (c) process developers and EPA/DOE contractors, and
(c) authorities in industry and academic institutions. Based on the prelim-
inary review of the collected data, a number of gasification and related pro-
cesses which were judged to have a greater likelihood of being employed in
commercial SNG facilities were selected and analyzed in more detail.
To enable a systematic data analysis, the high Btu gasification tech-
nology was divided into the following four "operations" (see Figure 1-1):
coal preparation, gasification, gas purification, and gas upgrading. In addi-
tion, for the purpose of analysis, the auxiliary processes which would be used
in commercial SNG facilities for pollution control were grouped into air pol-
lution control processes, water pollution control processes and solid waste
management processes. Except for coal pretreatment, which would be necessary
with certain gasification systems when caking coals are to be handled, the
processes employed for preparation of coal for high Btu gasification are not
unique to gasification and are widely used in the utility and other industries.
Accordingly, except for the coal pretreatment which was reviewed in connection
with gasification, the coal preparation operation was not addressed in this
study. Since with some gasification systems the quenching and removal of
dust from the raw product gas are accomplished within the gasifier or are
integrated with the gasification operation, for discussion purposes, the re-
view of the quench and dust removal portion of the gas purification operation
was also included in the discussion of the gasification operation.
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• COAL PREPARATION OPERATION
GASIFICATION
' OPERATION
- OAS PURIFICATION OPi RATION-
-GAS UPGRADING
OPERATION
OtftMOiliO OH TVPt Of OOAi MB HAIrt OtMM
or mmuunON nm MAT u
—
QUENCH
AMD
W1TOUS1
REMOVAL
OHYDUVT
REMOVAL
,
• • •» *v
REMOVAL
1 * ] PHACI SLILFUP^
|—
CO,
REMOVAL
»US AW CO.
-^
L
FHACI SLILfuR
MDOHGANICS
HIUOVAL
UETHAMATtO*
CUAflOl
Figure 1-1 High Btu Gasification Operations and Process Modules
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For analysis purposes, the operations and the auxiliary processes were
subdivided into a number of process modules, with each module being com-
prised of a number of nearly interchangeable processes or processes appli-
cable to different operating conditions and input requirements. For example,
the auxiliary processes for air pollution control were grouped into sulfur
recovery; tail gas treatment; SCL control and/or recovery; incineration; CO,
hydrocarbon and odor control; particulate control; gas compression and recy-
cling; and NO control. For each process in a module, a data sheet was pre-
/\
pared presenting key information items, thereby imparting high visibility to
engineering "facts and figures," allowing ready comparison between alternate
processes in a given module, and underlining specific areas where significant
gaps existed in the available data. To assure the completeness and accuracy
of the information, where applicable the data sheets on the processes reviewed
were forwarded to the process developers/licensors and, in some cases, to
technical experts in various EPA laboratories/program offices for review and
comment. Lists of process developers/licensors to whom the data sheets were
submitted for review and whether to date a response has been received or not
are presented in Table 1-1. The comments received from the reviewers have
been incorporated in this document.
The various processes in a module were compared from the standpoint of
developmental status, suitability for use in SNG facilities, process princi-
ple, raw material and utility requirements, costs (where data are available),
process efficiency and reliability, discharge stream characteristics, and
other advantages and disadvantages. The gasification, gas purification, gas
upgrading and pollution control processes which were judged to be promising
were then examined from the standpoint of their integration into a commercial
SNG production facility. The various options for gas treatment and upgrading
and for pollution control in an integrated facility were then examined and
gaps and limitations of the available data were summarized. In reviewing the
process and pollution control unit operations and waste discharge character-
istics in an integrated facility, only those unit operations and waste streams
which were judged to be specific to high Btu gasification and related opera-
tions were addressed. Thus, individual operations such as coal storage,
cleaning and drying; on-site power generation; oxygen production; and raw
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TABLE 1-1. LIST OF PROCESS DEVELOPERS/LICENSORS TO WHOM DATA SHEETS WERE
SENT FOR REVIEW AND THE STATUS OF RESPONSES RECEIVED
Process
61 gas
Cogas
CO^-Acceptor
Hydra ne
Hygas
Koppers-Totzek
Lurgi (dry ash)
Synthane
Texaco
Addressee
Lowell Miller
DOE, Washington DC
T. Eddinger
Cogas Development Co.
Princeton, N. J.
E. L. Clark
DOE, Washington DC
John Sudbury
Consolidated Coal Co.
Library, Pa.
L. Jablansky
DOE, Washington DC
S. Verikios
DOE, Washington DC
Louis B. Anastasia
Institute of Gas Tech.
Chicago, 111.
J. Anderson
American Koppers Inc.
Pittsburgh, Pa.
J. Pollaert
American Lurgi Corp.
Hasbrouck Heights, N.J.
E. L. Clark
DOE, Washington DC
W. Sen linger
Texaco, Inc.
New York, N.Y.
Date
Sent
11/22/77
12/14/77
10/24/77
10/24/77
11/16/77
10/26/77
10/26/77
10/4/77
10/18/77
10/20/77
10/28/77
Response
Recei ved
(as of 8/78)
*
Yes
*
Yes
*
*
Yes
t
*
—
Yes§
(continued)
-------
TABLE 1-1. CONTINUED
Process
Addressee
Response
Date Received
Sent (as of 8/78)
Battelle
Slagging Gasifier
Rectisol
Purisol
Ami sol
Selexol
Estasolvan
ADIP
Sulfinol
Fluor Econamine
W. Corder
Battelle
Columbus, Ohio
R. Ellman
Grand Forks Energy Research
Center
Grand Forks, S.D.
T. Pollaert
American Lurgi Corp.
Hasbrouck Heights, N.J.
T. Pollaert
American Lurgi Corp.
Hasbrouck Heights, N.J.
T. Pollaert
American Lurgi Corp.
Hasbrouck Heights, N.J.
J. P. Vallentine
Allied Chemical Corp.
Morristown, N.J.
M. E. Mauss
Institut Francais du
Petrole
France
H. J. McNamara
Shell Oil Co.
Houston, Texas
H. J. McNamara
Shell Oil Co.
Houston, Texas
R. Schaaf
Fluor Engineers &
Contractors
Irvine, Ca.
1/16/78
1/20/78
11/11/77
11/11/77
11/11/77
10/26/77
11/16/77
11/29/77
10/24/77
12/8/77
Yes
Yes
Yes
Yes
Yes
Yes
(continued)
-------
TABLE 1-1. CONTINUED
Process
Addressee
Date
Sent
Response
Recei ved
(as of 8/78)
Fluor Solvent
SNPA-DEA
MDEA
Sulfiban
Alkazid
Benfield Hot
Carbonate
IFP
Sulfreen
Claus
Cleanair
Stretford
R. Schaaf
Fluor Engineers &
Contractors
Irvine, Ca.
E. J. Jirus
Ralph M. Parsons Co.
Pasadena, Ca.
R. L. Pearce
Dow Chemical Co.
Freeport, Texas
M. Peters
Applied Technology Corp.
Houston, Texas
L. Greives
Davy Powergas Inc.
Lakeland, Fla.
D. McCrea
Benfield Corp.
Pittsburgh, Pa.
M. F. Mauss
Institute Francais du
Petrole
France
Y. M. Philardeau
Aquatine of Canada Ltd.
Calgary, Canada
E. J. Jirus
Ralph M. Parsons Co.
Pasadena, Ca.
Art Holms
J. F. Pritchard Co.
Kansas City, Mo.
A. Grant
Woodhall-Duckham, Ltd.
Pittsburgh. Pa.
12/8/77
1/24/78
1/24/78
1/24/78
12/8/77
12/20/77
12/2/77
1/24/78
1/24/78
5/17/78
11/28/77
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
(continued)
8
-------
TABLE 1-1. CONTINUED
Process
Addressee
Data
Sent
Response
Received
(as of 8/78)
Giammarco-
Vetrocoke
Beavon
SCOT
Well man- Lord
Chiyoda
Thoroughbred 101
Shell Copper
Oxide
Phosam W
Chevron WWT
Phenosolvan
Vetrocoke Cokapuania, SPA
Milano, Italy
W. J. Baral
Union Oil Co.
Brea, Ca.
H. J. McNamara
Shell Oil Co.
Houston, Texas
Davy Powergas Inc.
Lakeland, Fla.
R. Dakan
Chiyoda International Corp.
Seattle, Wash.
H. J. McNamara
Shell Oil Co.
Houston, Texas
R. Rice
USS Engineers & Consultants
Pittsburgh, Pa.
J. D. Knapp
Chevron Research Corp.
San Francisco, Ca.
T. Pollaert
American Lurgi Corp.
Hasbrouck Heights, N.J.
6/23/78
12/21/77
11/29/77
4/28/78
2/17/78
11/29/77
11/28/77
11/30/77
Yes
Yes
Yes
Yes
Yes
*Although no formal review comments were received, DOE did supply a number of
recent documents on the operation of the Hygas and Synthane pilot plants;
the information in these documents has been incorporated in the data sheets
for these processes.
tKoppers Co. will review the Kopper-Totzek data sheet as soon as an agreement
is finalized.
tLurgi has indicated that it will not respond to TRW's request for the review
of data sheets.
§Texaco indicated that it could not comment on the technical content of the
data sheet without revealing information it considers confidential.
-------
water and sanitary waste treatment were not considered. Some of these were
addressed in Environmental Assessment Data Base for Low/Medium Btu Gasifica-
tion Technology, EPA 600/7-77-125a and b, November 1977.
The information and the discussion presented in this report are based on
the data available to TRW as of August 1978. TRW is aware of the plans by
certain process developers to publish important updated information in the
near future. Such information and other data which may become available in
the future should be incorporated in any updated version of the present
document.
1.4 ORGANIZATION OF REPORT
This data base document consists of three volumes: Volume I, Technical
Discussion; and Volumes II and III, Appendices. The Appendices contain "data
sheets" prepared on various processes reviewed and consist of: Appendix A,
Gasification Operation; Appendix B, Gas Purification Operation; Appendix C,
Gas Upgrading Operation; Appendix D, Air Pollution Control; Appendix E, Water
Pollution Control; and Appendix F, Solid Waste Management. The technical dis-
cussion in Volume I represents a summary and analysis of the information pre-
sented in the data sheets including an examination of the pollution control
options in commercial SNG facilities. Additionally, the major gaps and limi-
tations of the available data are identified and the more relevant programs
which could supply some of the needed data are highlighted. In the discussion
in Volume I, a separate chapter has been devoted to each of the major opera-
tions (i.e., Gasification, Gas Purification, and Gas Upgrading) and auxiliary
processes (i.e., Air Pollution Control, Water Pollution Control, and Solid
Waste Management). The sources of data used in the preparation of the data
sheets contained in the Appendices have been identified separately in each
individual data sheet. Since much of the discussion in Volume I is based on
the information in the data sheets, the reference sources for the information
in the data sheets have not been repeated in Volume I.
10
-------
2.0 GASIFICATION OPERATION
Based on preliminary analysis of various commercial and developmental
gasification processes for use in SNG production, eleven processes were
selected for detailed analysis. These processes, which utilize five types of
gasifier designs, are listed in Table 2-1. Figure 2-1 is a schematic pre-
sentation of the gasification operation. Three of the processes listed in the
table (Koppers-Totzek, Texaco, and Self-Agglomerating Ash) may not be likely
candidates for SNG production (see Section 2.1) but were reviewed in this
program at the request of the EPA.
The data sheets prepared for the eleven gasification processes are con-
tained in Appendix A. This chapter summarizes the information contained in
the data sheets. The general principles of high Btu gas production are
reviewed and the key features of the promising gasification processes are
presented. In addition, the status of various developmental and commercial
high Btu gasification projects is summarized. Data relating to the properties
of major discharge/waste streams from gasification and related operations
are presented and analyzed from the standpoint of emission/effluent potential
and impact on downstream processes or treatment systems. Finally, the data
gaps and limitations are identified, along with ongoing or planned programs
which should supply some of the needed data.
2.1 GENERAL PRINCIPLES OF AND APPROACHES TO HIGH BTU GASIFICATION
The conversion of coal to gaseous products generally involves four types
of chemical reactions:
• Devolatilization/Pyrolysis
Coal—heat . CH4 + H20 + CxHy (1)
11
-------
TABLE 2-1. GASIFICATION PROCESSES EVALUATED
Lurgi (dry ash)
Lurgi Slagging Gasifier
Hygas (steam-oxygen)
Cogas
CO^-Acceptor
Hydrane (Hydrogasification)
Synthane
Self-Agglomerating Ash
Bigas
Koppers-Totzek
Texaco
Fixed bed (dry ash)
Fixed bed (slagging)
Fluidized bed (internal char gasification)
Fluidized bed (external char gasification)
Entrained bed (slagging)
• Gasification
t Combustion
C + 2H2-
C + 1/2 0,
heat
C + 0
• Water-Gas Shift
CO
—CH4 + heat
-CO + heat
+ heat
(2)
(3)
(4)
(5)
CO + H20
+ H2 + heat
(6)
12
-------
DRY
SIZED
COAL
RAW GAS
WITH
TAR/OIL
DRY
PRETREATE
SiZED
COAL
RAWGA
WITH
TAR/OIL
PRETREATED
ULVERIZED
COAL
DRY
PULVERIZED
COAL
AWG
WITHOUT
JAR/OIL
GASSIFIER NUMBER CODES:
1. FIXED BED (DRY ASH)
2. FIXED BED (SLAGGING)
3. FLUIDIZED BED, INTERNAL CHAR GASIFICATION
4. FLUIDIZED BED. EXTERNAL CHAR GASIFICATION
S. ENTRAINED BED. SLAGGING
Figure 2-1. Process Modules for Gasification Operation
13
-------
In all gasification processes, heat must be supplied directly or indirectly
to promote reactions 1 and 2. Commonly, such heat is supplied by injecting
air or oxygen into the gasifier to combust a portion of the feed coal (or
into a separate system to combust residual char). In the coal flow sequence
of most processes, three general zones of progressively higher temperatures
are encountered. These are the devolatilization/pyrolysis zone, the gasifica-
tion zone and the combustion zone. Depending on the process design, these
zones may be encountered in a single reaction vessel or in separate vessels.
Production of SNG from coal-derived gases requires a methanation step
to increase the methane content and hence the heating value of the gas (in
most gasification processes, only a portion of feed coal is directly converted
to methane in the gasifier via reaction 3). The methanation reactions are:
3H2 + CO -CH4 + H20 + heat (7)
4H2 + C02 -CH4 + 2H20 + heat (8)
To convert all the CO to methane in the methanation step, the molar ratio of
hydrogen to carbon monoxide prior to methanation should be greater than 3.
The conditions in many gasifiers do not favor production of enough hydrogen
to achieve the required FL/CO ratio. Accordingly, a supplementary catalytic
shift conversion step (reaction 6) should precede methanation. In order to
minimize shift and methanation requirements, processes for the production of
high Btu gas feature conditions which are aimed at maximizing the formation
of both methane and hydrogen directly in the gasifier. A common approach is
to keep initial temperatures and residence times as low as possible in the
devolatilization/pyrolysis zone. The direct reaction of carbon with hydrogen
to form methane (reaction 3) is favored at relatively low temperatures (and
high pressures) as is the shift reaction (reaction 6) to produce hydrogen.
Thus, most processes are operated at high pressure and low to moderate tem-
perature to maximize methane and hydrogen formation in the gasification zone.
To generate the hydrogen required for reaction 3, sufficient quantities of
steam and oxygen are added in the combustion zone to promote reactions
2 and 6.
14
-------
Many gasification processes, especially those which employ fluidized
beds, cannot directly handle a caking coal unless the coal is pretreated to
destroy its caking tendencies. Particles of caking coals tend to agglomerate,
thus preventing proper fluidization or, in the case of fixed bed processes,
interfering with normal gas flow through the gasifier. The most common pre-
treatment method for destruction of the caking properties involve heating,
(at temperatures up to 700°K or 800°F, depending on the coal) in the presence
of small amounts of oxygen and steam. In some gasification processes (e.g.,
Hygas), coal pretreatment is carried out in a separate vessel ahead of the
gasifier. In other processes (e.g., Cogas), pretreatment is accomplished
directly in the gasifier/pyrolyzers. In these processes, the pretreatment
operation is an integral part of the gasification.
All high Btu gasification processes require (1) a bulk particulate removal
step(s) to remove ash, char and oil/tar particulates, and (2) a quench step to
cool raw product gas, remove moisture and condensible organics, and to
achieve additional particulate removal. The bulk particulate removal is
commonly accomplished using cyclones. In certain processes such as C02~
Acceptor and Synthane, the cyclone is located inside the gasifier. In the
case of Hygas and Bigas the cyclone is located outside the gasifier, but it is
an integral part of the gasifier design. Spray systems using water or oil
(e.g., in the Synthane process) are used for gas quenching. In the case of
processes such as Hygas which use an oil slurry system for coal feeding, the
oil is recovered in the quenching operation. For these processes the quench
operation is process-specific and is considered an integral part of the
gasifier design.
2.2 KEY FEATURES OF HIGH BTU GASIFICATION PROCESSES
As was indicated above, of the eleven gasification processes reviewed
in this program, eight are considered candidates for use in SNG production.
These eight processes are Lurgi (dry ash), Lurgi (slagging gasifier), Hygas
(steam-oxygen), Cogas, C02-Acceptor, Synthane, Bigas and Hydrane. Table 2-2
summarizes the key features of these processes, based on the detailed
information contained in the data sheets in Appendix A. The eight processes
15
-------
TABLE 2-2. KEY FEATURES OF HIGH BTU GASIFICATION PROCESSES
Process
Lurgl (dry ash)
Lurgl (Slagging
Gaslfier)
Hygas
(steam-oxygen)
Co gas
C0,-Accc>tor
c
Syn thane
Blgac
Hydra ne
Development
Status
Commercial for
fuel and syn-
thesis gas
production
Pilot scale,
demonstration
plant under
design
Pilot scale.
demonstration
plant under
design
Pilot scale;
demonstration
plant under
design
Pilot scale:
no denon-
stration or
commercial
project
planned
Pilot scale
Pilot scale
Bench scale
Coal Feed and
Pretreatment
Limited to non-
caking coals.
Fine coal sizes
must be
briquetted
Limited to non-
caking coals.
Fine coal sizes
may be utilized
by injection
Into center of
gaslfier bed
Can use all
domestic coals.
Caking coals
are pretreated
with air and
steam in
fluidized bed
at 315-400°K
Can use all
domestic coals.
Pretreatment
for caking
coals Is
accomplished in
first stage
p'yrolyzer
Limited to more
reactive coals
(e.g., lignite
and sub-bitum-
inous coal)
Can use all
domestic coals.
Caking coals
are pretreated
with Og and
steam within
the gaslfier
1n a free fall
fluidlzed bed
zone
Can use all
domestic coals.
No p re treat-
ment is
required
Caking coal
permitted with-
out pre treat-
ment.
Coal
Feeding
Method
Pressurized lock-
hopper
Pressurized lock-
hopper
Coal is slurrled
with light
aromatic oil and
charged to gasi-
fler by high
pressure slurry
pump
Pneumatic feed-
ing with recycle
product gas
Pressurized lock-
hopper
Pressurized lock-
hopper
Coal is slurried
with water and
Injected into
pressurized drier
before entering
gaslfier
Injection nozzle
Gasifier Design
Fixed bed, counter -current
gas/solids flow, tempera-
ture Increases downward to
effect pyrolysls and
gasification
Same as dry ash Lurgl
Two stage, fluidlzed bed
hydrogasifl cation.
Fluidlzed steam-oxygen
gasification stage pro-
vides heat and gas for
hydrogasificatlon
Coal 1s pyrolyzed in four
fluidlzed stages with
progressively higher
temperatures. Char pro-
duced from pyrolysls of
coal is sent to gaslfler.
Crude gas Is produced
from the reaction of char
and steam, obtaining heat
indirectly from the com-
bustion of char with air.
Gaslfler gas flow counter-
current to coal and char
In tiie gaslfier, calcined
dolomite supplies heat foi
Stean gasification of
Coal. Carbonated dolo-
•1te 1s recalclned in a
regenerator by burning
char with air. Both
vessels fluidlzed
Steam and oxygen used
to gasify coal In
fluidized bed gaslfler
Coal 1s gasified in an
entrained bed with a
steam/ synthesis gas
mixture. Char is
gasified in an
entrained bed using
Oz and steam to gener-
ate synthesis gas
Direct hydrogasificatlon
of coal with hydrogen 1n
a fluidlzed bed. Hydro-
gen would be produced by
char gasification with
subsequent purification
Gaslfler
Temperature
°K(°F)
Max. bed temp.
1255-1644
(1800-2500)
Max. bed temp.
1255-1644
(1800-2500)
Hydrogasifica-
tlon
750-1000
(900-1350)
Steam-oxygen
gasification:
1100 (1600)
Pyrolyzers
500-1000
(450-1500)
Gaslfler:
1200 (1700)
Gaslfler:
1090 (1500)
Regenerator:
1280 (I860)
960-1090
(1280-1500)
Upper stage:
1200 (170)
Lower stage:
1755 (2700)
-6000 (-1500)
Gaslfler
Pressure
HPa(psia)
2.1 - 3.2
(300-465)
0.7-3
(95 - 415)
6.2 - 7.1
(911-1040)
0.13 (20)
0.20 (29)
1.0 (150)
1.0 (150)
4.2 - 6.8
(600-1000)
8 (117b)
7.0 (1015)
(continued)
16
-------
TABLE 2-2. CONTINUED
Process
Lurgl (dry ash)
Lurgl (Slagging
Gasifler)
Hygas
(steam-oxygen)
Cogas
C0,-Acceptor
Synthane
B1gas
Hydrant
Quench and
Dust Removal
Water spray cooler
to condense tars/
oils and remove
bulk partlculates
Same as dry ash
Lurgl
Cyclone followed
by water quench
for oil and parti-
culate removal
Cyclone followed
by venturl scrub-
ber for removal
of char fines and
for recovery of
oil
Internal gaslfler
cyclone, external
water spray tower
for paniculate
removal
Internal gaslfler
cyclone, venturi
scrubber
Cyclone, water
spray tower for
participate
removal
No Information
Ash/Char
Removal
Lockhopper
water quench.
water slurry
transport
Lockhopper,
followed by
water quench
of slag
Water quench
at gaslfler
pressure.
water slurry
transport
Slag quenched.
transport not
known
Coal ash
leaves regen-
erator with
flue gas and
is collected
by cyclone
and scrubbing
systems
Lockhopper,
water quench.
steam trans-
port
Slag quenched
followed by
lock hopper
No Information,
char utiliza-
tion has not
been determined
Typical Product Gas
Composition* (vol I)
CM,
8-11
5-8
13-28
8-15
14
7-13
5-8
57-79
H2
40
28-30
26-37
5-40
56-59
23-35
32-38
21-28
CO
15-20
57-61
8-10
4-19
15
3-12
15-19
1-6
co2
28-31
3-7
28-35
22-29
9-11
*
37-64*
21-23
1
Tar/011
Production
Yes
Yes
Yes
Yes
No
Yess
NO
•>
Gas Yield*
Nm3/kg
(scf/lb) of
Dry Feed Coal
0.9-1.7 (16-30)
2.0-2.1 (34-36)
1.0-1.2 (17-20)
Gas: 0.12-.60
(2-12)
011: 0.04--0.2 I/kg
(0.005-0.025 gat/
lb) coal
1.35 (23)
1.2-1.5 (20-25)
2.0-4.0 (32-68)*
0.6-1.0 (10-17)
•Based upon data for actual operation for the most advanced stage of development
1N2 free basis
* Includes COj used to pressurize the lockhopper
!H1th "free-fall" mode of coal Injection; recent pilot plant runs involving "deep-bed1
Indicated Uttle tar production
injection of coals have
17
-------
use fixed beds (Lurgi and slagging gasifier), fluidized beds (Hygas, Cogas,
C02-Acceptor, Hydrane, Synthane and Self-Agglomerating Ash) and entrained
beds (Bigas). With the exception of Lurgi (dry ash), which is comnercially
available, the processes listed in Table 2-2 are in various stages of bench-
scale and pilot plant development. With the exception of Bigas and Hydrane,
all processes require some degree of pretreatment when handling caking coals.
The coal feeding methods include use of lockhoppers (Lurgi and Synthane), oil
slurry (Hygas), water slurry (Bigas) and pneumatic (Cogas). Operating
temperatures in the gasifiers range from 500°K to 1640°K (450°F to 2500°F)
and the operating pressures from slightly above atmospheric for Cogas to
over 7 MPa (1000 psia) for Synthane and Bigas. Except for Cogas, Hydrane,
and C02-Acceptor, the processes use lockhopper or slurry pressure letdown
systems for ash/char discharge.
A slurry transport system is usually used for the transport of ash/char
from the gasifier. Except for Lurgi (dry ash and slagging), cyclones are
employed for the removal.of the bulk of the particulates from raw product
gas and (in the case of Cogas and C02-Acceptor) from flue gas from combustion
of char. Water spray systems are employed for product gas cooling and con-
densation of tar/oil and moisture in all processes. Quenching of the product
gas with an oil spray before the water quench has been suggested for the
commercial design of some processes (e.g., Hygas).
As indicated in Table 2-2, there is a wide variation in the composition
of the product gas from different processes. In general, higher temperature
processes such as slagging gasification and Bigas tend to produce product
gases with lower methane and C02 percentages and lower hydrogen/carbon mon-
oxide ratios than low temperature processes such as ^-Acceptor, Hygas,
Cogas, and Hydrane. Processes such as C02-Acceptor, Cogas and Hydrane which
incorporate external char gasification tend to produce product gas with a
lower C02 content than other processes which employ internal char gasification.
The reported gas yields vary from 0.1 to 0.7 Nm3/kg (2 to 12 scf/lb) of coal
for Cogas to 2 to 4 Nm3/kg (32 to 68 scf/lb) of coal for the Bigas. The
ranges of gas yields for different processes and for a given process reflect
differences in (1) feed coals, (2) degree of carbon conversion, (3) product
gas compositions and (4) production of tars/oil in addition to gas.
18
-------
In principle, product gases from essentially any gasification process
can be converted to high Btu gas by shifting and methanation. The overall
thermal and economic efficiency of such conversion is generally low when pro-
duct gases contain essentially no methane and have low hydrogen to carbon
monoxide ratios. Examples of processes whose product gas is unsuitable for
economical conversion to SNG are Koppers-Totzek, Self-Agglomerating Ash, and
Texaco. The product gases from these processes contain no methane and require
extensive shift conversion and methanation for SNG production. Since only a
portion of the heat generated during methanation and shifting can be usefully
recovered, shifting and methanation represent a thermal penalty in addition
to imposing higher capital and operating costs for these gasification proc-
esses. Furthermore, the product gas from these processes is at high tempera-
tures, presenting a potentially high thermal loss. In the case of Koppers-
Totzek and Self-Agglomerating Ash, the product gas is also produced at a low
pressure, thus requiring an energy input for compression during processing
and for pipelining. Finally, since shifting results in the production of
COg. the greater the requirement for shifting is, the greater is the require-
ment for subsequent CCL removal and hence the higher the cost associated with
acid gas treatment.
Table 2-3 is a summary of the major advantages and limitations of the
eight high Btu gasification processes reviewed. As indicated in the table,
the processes vary in their status of development (see Section 2.3); ability
to use different coal types and sizes; methane, hydrogen and higher organics
production; utility requirements; throughput rates and turndown ability;
carbon conversion efficiency; and C02 removal requirements. Generally, a com-
parison of processes reveals inherent tradeoffs which must be made in order
to take advantage of certain process features. For example, low pressure
operation of the Cogas process simplifies vessel design and construction in
exchange for higher compression costs (when compared to high pressure proc-
esses such as Hygas). Similarly, with the slagging Lurgi gasification proc-
ess, lower steam consumption and higher throughput rates are realized at the
expense of lower methane and hydrogen content of the product gas (when com-
pared to the dry ash Lurgi).
19
-------
TABLE 2-3. ADVANTAGES AND DISADVANTAGES OF HIGH BTU GASIFICATION PROCESSES
Process
Lurgl (dry ash)
Lurgl
(Slagging Gaslfle
Hygas
(steam- oxygen)
Cogas
COg-Acceptor
Synthane
Bloas
U i *£Q»
Hydrane
>.
13 1>
TJ£
C a
P
sst
Yes
NO
•)
No
No
No
No
No
No
P
|I
V O
> w—
A) •*—
cSa.
Yes
Yes
Yes
Yes
Yes
No
No
No
W>
I
V
C
No
No
Yes
.
Yes
No
Yes
Yes
Yes
c
1
p
O)
£.£
1?
Yes
Yes
Yes
No
Yes
Yes
No
Yes
N
5
ai
N
11
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No
No
Yes
Yes
Yes
Yes
Yes
Yes
0) n-^
r— I/I
.O ^~
X**O
C ^K
«c
s£
in i/t
« u
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IS
Yes
Yes
Yes
Yes
No
Yes*
No
Yes
Throughput
H
z3
No
Yes
No
No
No
No
Yes
Yes
|
5
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at —
c in
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Low
High
Moderate
High
High
Low
Very
High
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Low
High
High
Very
High
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Moderate
Very
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S
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Low
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Low
High
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Yes
Yes
Yes
Yes
Yes
No
Yes
No
**
ii
1
High
High
Low
Low
Low
Low
Moderate
Low
n
JTI
1
CM CT
O 01
UK
Yes
Yes
Yes
Yes
No
Yes
Yes
Yes
**
c
n
cT
s-g
S.-S
tl
Yes
Yes
Yes
No
No
Yes
Yes
7
Comments
Commercial operations not for
high Btu gas production at
present. Basis for several
proposed commercial SNG projects
Extensive tests at a modified
dry ash Lurgl plant. Basis
for a DDE-sponsored demonstra-
tion plant.
Pilot plant has demonstrated
operations with several coals.
High carbon utilization has not
been attained to date. Basis
for DDE-sponsored demonstration
program.
Integrated pyrolysls and gasi-
fication/combustion operations
not demonstrated. Basis for
DOE-sponsored demonstration
program.
Successful demonstration at
pilot plant stage. High cost
of acceptor 1s a major obsta-
cle to further demonstration
of process.
.Jllgh pressure lockhopper
feeding not demonstrated.
Pilot plant has limited steady
state operating time.
Ability to control slag flow at
a pilot plant has not been
demonstrated.
Small scale test only. Char
utilization and hydrogen pro-
duction not tested.
•With "fret-fall" mode of coal Injection; recent pilot plant runs Involving "deep-bed" Injection of coal have Indicated little tar production.
-------
2.3 STATUS OF HIGH BTU GASIFICATION TECHNOLOGY
Processes for gasifying coal in a manner suitable for subsequent conver-
sion to SNG are in varying stages of development. The only commercially
available process which has been proposed for SNG application is the Lurgi
(dry ash) process. At least three processes (Slagging Lurgi, Cogas, and Hygas)
are apparently sufficiently well along in their development to serve as the
basis for DOE-sponsored demonstration plants. The CO^-Acceptor process has
been demonstrated at the pilot plant stage, although no immediate plans are
known for further scale up. The synthane process has been operated at pilot
plant stage and steady-state operation has been achieved with non-caking
coals. The Bigas process is at the pilot plant stage but has not yet
attained representative steady state operation. A number of other processes
(most importantly, Hydrane, Garrett and Exxon processes) have been evaluated
at the Bench or laboratory scale.
Even though there are currently a number of proposed projects for the
commercial production of SNG (see Section 2.3.1 below), no actual construction
has been initiated on any of these facilities. The actual construction has
been delayed by a number of factors, the most important of which is the
inability to secure adequate private or public financing. The estimates of
capital investment for a 7 MM Nm3/day (250 MMSCFD) SNG facility using the
Lurgi (dry ash) gasification process vary from $800 million to $1,400 million,
(1 2)
with annual operating costs ranging from $120 million to $150 million/ ' '
These estimates indicate a product gas costing at least $2.70 per 10 Btu
(based on utility financing method) and $3.70 per 10b Btu (based on private
financing method). With most intra- and interstate natural gas currently
selling for $2 per 10 Btu or less, SNG would not be cost competitive with
natural gas (at least at the current regulated prices) and hence construction
of conmercial SNG facilities could not be economically justified. Although
some cost reductions may eventually be realized with the development and use
of "second generation" gasification processes, the comparative economics
to date do not indicate that overall SNG costs associated with commercial
use of such processes will be significantly lower (if at all) than those for
Lurgi based plants. The development of a commercial SNG industry has also
been impeded by the lack of agreement on the best energy policy for the U.S.
21
-------
It has been argued, for example, that an energy resource allocation policy
which would restrict or forbid the use of natural gas for such industrial
activities as ammonia production and power and steam generation (which can
use coal directly) can postpone, if not eliminate, the necessity for commer-
cial SNG production. Furthermore, for these applications which can use coal
directly, the direct use of coal represents a more efficient use of this
resource when compared to conversion of coal to SNG and use of SNG for these
applications.
Table 2-4 lists the existing and proposed commercial projects, planned
demonstration programs, pilot projects and bench/laboratory projects utilizing
high Btu gasification processes. A brief description of the projects
listed in Table 2-4 follows.
2.3.1 Existing and Proposed Commercial Projects
At the present time, there are no commercial-scale facilities producing
substitute natural gas in the U.S. or abroad. There are, however, 18 major
commercial-scale facilities located abroad which use dry ash Lurgi process
for production of low/medium Btu gas for a variety of applications, including
hydrocarbon and ammonia synthesis. The Lurgi facilities include the 725 tpd
(800 ton/day) SASOL plant in South Africa, the 0.84 Ml Nm3/D (30 M1SCFD)
Westfield plant in Westfield, Scotland, and the 1.3 MM Nm3/D (47 MMSCFD)
facility in Kosovo, Yugoslavia(3). The existing SASOL facility (SASOL I)
has been operational since 1958 and utilizes the gas produced from 13 Lurgi
gasifiers for the production of hydrocarbons via Fischer-Tropsch synthesis.
A second SASOL facility (SASOL II) is currently being constructed, which will
I A]
expand the present plant capacityv '. The Westfield plant was constructed in
1958-59 for the production of medium Btu gas; in 1963 a water gas shift
section was added to the facility, and in 1973 a methanation unit was teste'd
for a brief period by a consortium of U.S. companies under the direction of
Conoco Coal Development Co.^5'6' The Kosovo Plant has been in operation
since 1971, and uses Lurgi gasifiers to convert lignite from adjacent mines
to fuel gas and ammonia.
22
-------
TABLE 2-4. PROPOSED HIGH BTU GASIFICATION COMMERCIAL AND DEMONSTRATION
PROJECTS, AND PILOT AND BENCH PDU PROGRAMS
Process
Sponsor/Developer
1. Proposal Coswerclal Project!
Burnhaat Project
Dunn Center Project
MESCO Project
Mercer County
Project
2. Proposed Devons tratl on
Slugging lurj)
Cogas
Hygas
3. Pilot Projects
Hygas
Synthane
S»lf-Aggloa«retlng
Ash
Slagging Gaslfler
COj-Acceptor
Hydrant
Garrett Proem
El Paso Natural Gat Co.,
Pacific Gat 1 Electric,
and an ufnaaed third
partner
natural Cat Pipeline
Co. of taerlcan (NGPCA)
Tixat Eattern Trans-
•Illlon and Pacific
lighting Corp. (TET-PLC)
American Natural
Resources Co. (we) and
Peoples Gas Co. (PGC)
Projects
DOE and COWCO Coal
Developnent Co.
DOE and Illinois Coal
Gasification Group
DDE-Institute of Eat
Technology
DOE, Institute of Gas
Technology and American
Gas Association
DOE (PEXC)
DOE. Baltelle Keaorlal
Institute and American
Gas Association
DOE (GFERC)
Conoco, BGC. etc.
DOE and CONOCO Coal
Development Co.
i
DOE (PERC) and
Rocketdyne
Occidental Research
1 Development Co.
Designer/
Operator
El Paio Natural
Gas Co.
NGPCA
TET-PIC
ANG. PGC
Location
Northwest New r>«lro
Capacity
2MH h»3/D (72 M-.SCFO)
Dunn County. Ho. Dakota 7W (W/n, (250 HKSCFO)
northwest Hex Heilco
7W I*3/D (2SO WSCFD)
Herctr Co.. No. Dakota "f hr!/C (250 NKSCFD)
Foster-VheaJer
Energy Corp.
Oravo Corp.
Procon, Inc.
Institute of
Gas Technology
Luamus Co.
Smell e Neannal
Institute
Steams-Roger,
Inc.
BGC
CONOCO
Dravo Corp.;
Rocketdyne
Occidental Research
4 Dtvelocawjnt Co.
Exxon
Noble County, Onto 3450 tpd (1800 ton/
sj>)
Perry County, 111.
..
Chicago, Illinois
Bruceton. Pa,
Vest Jefferson,
Ohio
Grand Forks.
No. Dakota
Wei tf If Id, Scotland
Rapid City,
So. Dakota
Bruceton, Pa.
LaVeme. Ca.
-
2000 tpd (2200 ton/
day)
„
73 tpd (80 tons/day)
65 tpd (72 ton/day)
23 tpd (25 ton/day)
0.91 tpd (1.0 ton/day)
-
36 tpd (40 ton/day)
9.1 tpd (lONton/day)
Hydrane POU; 0.23 tpd
(0.2S ton/hr) bench-
scale hjrdrogasiflca-
tlon reactor
3.2 tpd (3.6 ton/day)
0.45 tpd (0.5 ton/day)
Status
FERC application pending. slant
site lease under negotiation
uater peralt application denied
In June 1976; new application
under development
Project pending per FERC certifi-
cation, project financing and
plant site lease
Plans tentative due to lack of
Federal approvals and loan
guarantee to finance construction
22-aonth contract for engineering
and technical support awarded oy
DOE In rtd-1977. Construction
phase (30 BOS) and operation phase
(42 mot). Contracts to be aoarded
at later date
21-aenth contract for conceptual
design axarded .Id- 1977 by DOE
17.5m contract 1s 'or con;.;
tual design of 7»t4 »3 D ::;"j
K4SCFD) coaaaerclal ')-• ".. : us
a smaller single-train deaunstra-
tlon facility
Operational since 1973. Kill con-
tinue through 1978. Successfully
tested non-caking Montana lignite
and subbltunlnous and caking
Illinois blbaalnous coals
Operational since Bld-1976.
Operation to continue through
Sept. 1978. Non-aggloavratlng
coals successfully tested.
Operations plagued by i nuiber
of xcnanlcal probleaK
Recently constructed. Milted
testing conducted to date Includ-
ing Independent operation of the
burner and gaslflcr up to 130 hrt.
ApproilHtely tvo years additional
testing needed for complete pro-
cess evaluation
Us operated fro> 1958-65 under
Bureau of Nines. DOE contract
awarded to Steams-Roger 1 n Oct .
1977 Involves codification and
operation of ttte pilot plant
using bltuaitnous coals
The 3-year program has involved
and Its operation under slagging
conditions. Ohio No. 9 and
Pittsburgh No. 8 coals have been
tested
Constructed 1n 1972: 42 runs
conducted to date on a variety
of coals and tw> typn of accep-
tors. Testing was coai^letatf In
fall 1977. having deaunstrated
technical feasibility of the
process
Hydrane POU recently built by
Dravo for DOE; a bench-scale
Rocketdyne hydrooaslflcatlon
reactor 1t also being tested
for DOE and appears to be super-
ior to the Hydrane unit. Rocket-
dyne contract to eiplrt In 1978
Plant hat operated with Vest
Kentucky coals to produce 229x
106kcal/N»3 (700 Btu/scf) gas
Sayjll-scale testing Is continuing
23
-------
There are currently several proposals for the construction of commercial-
scale (7MM Nm3/day or 250 MM scf/day) facilities for SNG production in the
United States based on the dry ash Lurgi process. The furthest along in
planning of these proposals are: (a) the Burnham, New Mexico project, spon-
sored by the El Paso Natural Gas Co.(7); (b) the Dunn Center project for
Dunn County, North Dakota, sponsored by the Natural Gas Pipeline Co. of
America* '; (c) the WESCO Project sponsored by Texas Eastern Transmission
(9}
and Pacific Lighting Corporation to be located in northern New Mexicov ';
and (d) the Mercer County, North Dakota Project sponsored by the American
Natural Resources Co., the Peoples Gas Company, and the Natural Gas Pipeline
Company of America' . Although environmental impact statements or assess-
ments have been completed for each of these proposed projects, legal, regula-
tory and funding matters are stalling initiation of construction. For exam-
ple, the Federal Energy Regulatory Commission is currently withholding ap-
proval of the Burnham facility pending resolution of matters pertaining to
the acquisition of satisfactory commitments for coar . The WESCO pro-
ject is also pending FERC certification enactment of a federal loan guarantee
program and plant site leasing from the Navajo Indians* ' .A water permit
application was denied in June 1976 for the Dunn Center facility, and hence
a new water permit application is currently being developed. The Mercer
County project is currently scheduled for initial construction in 1979; how-
ever, plans are still tentative due to need for federal approval of the
recently devised "all events tariff" plan to finance plant construction*13'14'
Other proposed Lurgi-based commercial-scale gasification projects which
are in early planning stages are* >15': the Watkins, Colorado, project spon-
sored by Cameron Engineers, Inc.; the Douglas, Wyoming facility sponsored by
the Panhandle Eastern Pipeline Co. and the Peabody Coal Co.; and the Cities
Service Gas and Northern Natural Gas Companies' facility planned for northern
Wyoming.
2.3.2 Proposed Demonstration Projects
There are currently no operating domestic high Btu coal gasification
demonstration projects. Contracts, however, have recently been awarded by
24
-------
the U.S. Department of Energy for the conceptual design of 3 major high Btu
gasification demonstration plants. These are the Conoco Coal Development
Company's slagging Lurgi facility to be located in Noble County, Ohio'16^;
the Illinois Coal Gasification Group's Cogas facility to be built in Perry
County, Illinois^ '; and a HYGAS demonstration plant to be designed by
Procon, Inc. ' The Conoco design for the Noble County project incorporates
four slagging Lurgi gasifiers producing 1.7 m Nm3/D (59 MMSCFD) of SNG from
3,450 tonnes/day (3,800 tons per day) of coal. The selection of the slagging
Lurgi process was based on the favorable results obtained in tests with
American coals at a Lurgi gasifier in Westfield, Scotland modified to operate
in the slagging mode.
The Perry County facility is to integrate COED fluidized bed pyrolysis
technology, as developed by DOE and the FMC Corporation, with the Cogas
process of steam gasification of COED char. The Cogas char gasification step
was recently piloted in England at the facilities of the British Coal Utili-
zation Research Association, Ltd. under the sponsorship of a consortium of
U.S. firms. The 2,000-tpd (2,200-ton/day) facility isto produce 0.50MMNm3/D
(18 MMSCFD) of SNG and 285,000 1/D (2,400 Bbls/day) of syncrude. Procon Inc.
has initiated the conceptual design of a commercial-scale facility for the
Hygas process developed by the Institute of Gas Technology in Chicago,
Illinois. The current Procon design is for 7 MM Nm3/D (250 MMSCFD) facility,
and the conceptual design of a smaller single train demonstration facility
is to follow.
2.3.3 Pilot Projects
Several high Btu gasification processes are presently at the pilot plant
stage of development. These processes are Hygas, Synthane, Bigas, Self-
Agglomerating Ash, C02-Acceptor, and the slagging Lurgi gasifier. The
following is a brief history and status of each of these pilot plant
programs.
t Hygas - A 73-tonne/day (80-ton/day) Hygas pilot plant has been
operated in Chicago since 1973 by the Institute of Gas Technology
(IGT) under joint sponsorship of DOE and the American Gas
Association (AGA). The plant has successfully tested non-caking
Montana lignite and subbituminous coals and caking Illinois
bituminous coals, using the steam-oxygen process for hydrogen
25
-------
generation. The steam-iron process is also currently being 3
tested in a pilot plant at IGT designed to produce 0.29 MM Nm /D
(1.1 MMSCFD) of hydrogen; the plant was completed in July 1976,
and start-up operations began in October 1976. A third process
for hydrogen generation, the electrothermal gasification process,
was also tested at the Hygas facility from 1972 to 1974, when the
Hygas reactor was converted to accept hydrogen from steam-
oxygen gasification. Tests conducted at the Hygas pilot plant
to date have demonstrated the very high carbon conversion neces-
sary for commercial operation. Pilot plant operations are to
continue through 1978 with the testing of bituminous coals.
t Synthane A 65 tonne/day (72 tpd) Synthane pilot plant has been
operated by Lummus Company for the Pittsburgh Energy Research Center
since mid-1976 in Bruceton, Pa. The plant includes gas purification
(Benfield and Stretford), as well as methanation units. Operational
testing with nonagglomerating coals began in early 1977; no
agglomerating coals have been tested to date. The plant was oper-
ated in the "free-fall" mode of coal injection during July-
December 1976. This mode of operation resulted in the production
of significant quantities of tar, frequent plugging of the internal
cyclone "dip-leg" and overloading of quench and gas purification
systems. Since February 1977 which the plant has been operated
in the "deep bed" mode of coal injection, significantly fewer
operational problems have been experienced and a total of several
hundred hours of steady state operation has been achieved. A
Coal Pretreatment System has now been installed for testing
caking coals.
t Bigas - The Bigas gasifier has been under development since 1965
by Bituminous Coal Research, Inc. Under DOE and AGA sponsorship,
a nO-tonne/day (120-ton/day) integrated pilot plant was constructed
and operated by Phillips Petroleum Co. beginning in late 1976 in
Homer City, Pennsylvania, based on operating data obtained from
a 45-kg/hr (100-lb/hr) PDU operation. (The original DOE/AGA
contract with Phillips has expired, but has been extended
through December 1978.) The plant incorporates a Selexol system
for removal of H2$ and C02 from gas from the shift conversion
unit. The pilot plant has had continuing difficulties with slag
removal from the gasifier. Various unsuccessful attempts have
been made to prevent slag solidification and plugging of the
slag tap-hole, including the addition of limestone as a fluxing
agent to reduce slag viscosity. Problems have also been encountered
in the measurement of solids feed to the gasifier and measurement
of temperature in Stage 1 of the gasifier. Steady state coal
and char gasification have not yet been demonstrated at the pilot
plant. Further pilot tests will include increasing the operating
pressure to the optimum level (10 MPa or 1500 psia). The life of
various metals and refractory materials in the gasifier and in the
coal conveying system will also be tested in future runs.
26
-------
Self-Agglomerating Ash - A 23-tonne/day (25-ton/day) process
development unit was very recently constructed at West Jefferson,
Ohio under the sponsorship of DOE and AGA using the Battelle self-
agglomerating ash burner gasification process. (The Battelle
technique is an outgrowth of a Union Carbide process for gasifying
low-sulfur Western coal, and is designed to produce medium-Btu syn-
thesis gas to be used as feedstock to chemical plants.) To date, only
limited testing has been conducted, including independent operation
of the burner and gasifier for varying times up to 130 hours.
Subsequent testing is to include operating the burner while con-
tinuously circulating the solids and feeding coal into the gasifier.
It is expected that an additional 2 years are needed for complete
process evaluation.
Lurgi (Slagging Gasifier) - A small (0.4-m diameter) slagging
gasifier is currently being tested by DOE at its Grand Forks
Enqrgy Research Center (GFERC) pilot plant in Grand Fords, North
Dakota. The plant has a capacity of 0.907 tonne/hour (1.0 ton/hour)
and has performed successfully with bituminous char, lignite and
lignite char. Stearns-Roger, Inc. received a $1.5 million DOE
contract in October 1977 for design, modification and operation of
the pilot plant, to permit studies leading to the goal of extended
continuous operating periods and operation on selected bituminous
coals. Operational improvements will include the addition of a
second coal lock to stabilize operation and the installation of a
stirrer in the upper portion of the gasifier bed to permit operation
on agglomerating coals.
Under DOE sponsorship, CONOCO and British Gas Corporation (BGC) have
conducted tests with American coals (Pittsburgh No. 8 and Ohio No. 9)
at a Lurgi gasifier in Westfield, Scotland, modified tjb operate
under slagging conditions. These tests, which have bqen aimed
primarily at collecting engineering data for the desicjn of a demon-
stration plant in the U.S., have included 48-hr duration runs with
(a) Ohio No. 9 premixed with coke; (b) Pittsburgh No. 8 premixed with
coke; and (c) Pittsburgh No. 8 alone. While the runs with Pittsburgh
No. 8 have been very successful, limited success has been obtained
with the Ohio No. 9. Except for one additional "exploratory" run
which is planned for August-September 1978 with Pittsburgh No. 8,
the DOE/CONOCO slagging gasification test program at Westfield is
considered complete.
C02-Acceptor - Testing at the 36-tonne/day (40-ton/day) pilot plant
constructed in Rapid City, South Dakota in 1972 for the Consolidated
Coal Company's (CONSOL, now CONOCO) C02-Acceptor process was
completed in September 1977. Since 1972, over 42 runs have been
conducted using a variety of coal types, including North Dakota
lignites, Texas lignite, and Montana and Wyoming subbituminous
coals. Two types of acceptors (Ohio dolomite and South Dakota
limestone) were also tested, and methanation of the product gas was
also successfully demonstrated in 1975. CONOCO has prepared con-
ceptual designs for a demonstration or commercial plant based on the
27
-------
the C02-Acceptor process, although no commercial facility is
currently planned. The pilot plant has been modified for
testing of the Westinghouse Electric Corp. gasification
process.
2.3.4 Bench/PDU Scale Projects
Among the current bench-scale projects are those aimed at the development
of the Hydrane, the Garrett, and the Exxon processes. The Hydrane process
has primarily been tested in a special two-stage bench-scale reactor at the
Pittsburgh Energy Research Center in Bruceton, Pennsylvania. Based on this
work, a 9.1-tonne/day (10-ton/day) PDU and a 27.2-tonne/day (30 ton/day)
hydrogasification process using the Hydrane reactor design were recently
prepared by Dravo Corporation for DOE. In March of 1977 DOE awarded the
Rocketdyne Division of Rockwell International Corporation a contract to test
a 0.23-tonne/hour (0.25 ton/hour) short residence time-high throughput hydro-
gasification reactor. This design currently appears to be superior to the
Hydrane process design, which was judged by DOE in 1975 to be unfeasible for
commercialization. Upon expiration of the Rocketdyne contract in FY 1978,
the effort may be followed by the design, construction and testing of a
9- to 18-tonne/day (10- to 20-ton/day) process development unit.
The Garrett process is being tested in a 3.2-tonne/day (3.6-ton/day)
plant in operation at the Occidental Research and Development Company
laboratory in LaVerne, California/ ' The plant has successfully operated
with West Kentucky coals to produce gas with a heating value of
5900 kcal/Nm3 (700 Btu/scf).
The Exxon process, which utilizes fluidized-bed gasification at
846°K-921°K (1000°F-1200°F), has been tested at a 0.45-tonne/day (0.5-ton/day)
(1 4)
unit.* ' ' Char which is withdrawn from the gasifier is partially burned
with air in a char heater, then separated from the remaining flue gas and
returned to the gasifier as a direct-contact, heat transfer medium. The
construction of a 458-tonne/day (500-ton/day) gasifier has been deferred.
Smaller scale research and engineering studies are continuing.
28
-------
2.4 DISCHARGE STREAMS
All gasification processes generate a product gas stream and a char/ash
stream. In addition, dust removal and quench systems will generate solids/
slurries and quench waters or oils. Processes which have coal pretreatment
steps will generate flue or off-gases. Lockhopper feeding systems may
involve the discharge of pressurization gases. Finally, combustion flue
gases will be generated by processes such as CCk-Acceptor and Cogas which
gasify/combust char externally to the main coal gasifier. In this section,
data relating to the characteristics of the discharge streams from gasifica-
tion operations are reviewed from the standpoint of potential pollutant emis-
sions/hazards and impacts on downstream gas treatment and pollution control
operations.
2.4.1 Product Gases
The major components of product gases from high Btu gasification pro-
cesses are listed in Table 2-2 and were discussed in Section 2.2. In addition
to methane, carbon oxides and hydrogen, raw product gases contain sulfur
and nitrogen species, dust (tar, ash and partially gasified coal partlculates)
and in many cases condensible organics. (The data on dust and condensible
organics removed by the quench and dust removal systems are presented in
Section 2.4.2.) The sulfur- and nitrogen-containing compounds originate from
the organic or pyritic sulfur and organic nitrogen in the feed coal. The
amounts and nature of such compounds depend on the feed coal composition and
the gasification conditions. Table 2-5 is a summary of the available quanti-
tative data on the sulfur and nitrogen species present in raw gases from
C02-Acceptor, Hygas, Lurgi (dry ash and slagging), Cogas and Synthane.
(Similar data are not available for the Bigas and Hydrane.) Hydrogen sulfide
Is the major sulfur containing component and is found in concentration ranging
from 400 to 32,000 ppmv. Other sulfur compounds (COS, CS2, mercaptans and
thiophenes) constitute from 1% to 15% of the total gaseous sulfur. Gaseous
nitrogen compounds in product gases are primarily ammonia (200 to 13,000 ppmv)
and hydrogen cyanide (less than 1 to 77 ppmv).
29
-------
TABLE 2-5. TYPICAL SULFUR AND NITROGEN SPECIES COMPOSITION OF RAW PRODUCT GAS
Process
(X^-Acceptor
HYGAS
Lurgl
(dry ash)
Slagging
6as1f1er
Cogas
Synthanei
Feed Coal Type
Lignite; N.D.
Lignite; Montana
Subbltunrinous; Montana
Bituminous; 111.16
Subb1tum1nous; Montana
Bituminous; 111. #6
Bituminous; 111.15
Bituminous;
Pittsburgh 18
Bituminous; So.
Africa
Lignite; N.D.
Bituminous; 111.
Bituminous; 111.
Subbituminous; Wyoming
Coal Sulfur,
%
0.5 - 0.7
0.'9
0.9
2.8
4.3
1.5
3.1
3.6
2.6
0.4
-
2.1
3.6
0.5 - 0.9
Gas Composition (ppmv)
H2S
400-1300
2300
-
7000
14000-17000
2170
11,200
10,600
7500
3000
-
32,000
9800
1000-8000
COS
15-40
-
-
-
-
-
-
150
32
CS2
-*
-
-
-
-
315
180
232
122
-
-
-
10
-
RSH
-
-
-
-
-
t
-
-
no
10
HCN
-
-
-
-
-
2.4
25
77
4.4
-
-
-
-
-------
2.4.2 Dusts, Tars and Oils, and Aqueous Condensates
Available data on the composition of cyclone dusts from various
processes indicate that the dust usually contains large percentages of ungasi-
fied carbon, sulfur and nitrogen compounds. The quantity of dust entrained
in the raw product gas depends upon the feed coal particle size and the
type of the gasifier bed, and ranges from less than 0.1% by weight of the
feed coal (e.g., in the case of Lurgi) to a few percent by weight of the
feed coal (e.g., in the case of C02-Acceptor). The bulk of the dust and
condensible organics are removed by the quench and dust removal systems. In
commercial application of processes such as C02-Acceptor and Hygas, which
generate large quantities of high carbon dust, the carbon value of the
collected dust would be recovered by reinjection of dust into the gasifier or
by separate gasification or combustion.
Tars and oils are produced in several gasification processes (see
Section 2.2). Table 2-6 presents typical tar and oil production rates for
six gasification processes. Bigas, C02-Acceptor and Synthane ("deep-bed" coal
injection mode of operation) produce little or no tars and oils; no data are
available on tars and/or oil production, if any, in the Hydrane process. As
indicated in Table 2-6, from essentially zero to 16% by weight of coal
(moisture and ash free basis) is converted to condensible organics, depending
on the process. Such organics tend to be highly aromatic in character (e.g.,
Synthane tar contains about 50% 3-ring aromatic hydrocarbons and 20%
heterocyclic aromatic compounds).
Aqueous condensates/scrubber waters contain suspended solids, organic
substances (such as phenols), ammonia, sulfide, cyanide and thiocyanate. The
"normalized" production rates for these "key" substances and of TOC (total
organic carbon) and COD (chemical oxygen demand) are listed1 in Table 2-6 for
six gasification processes. (No data are available for Bigas and Hydrane.)
The quantity of ammonia found in the condensate varies from 4 to 15 kg/1000 kg
of coal and accounts for most of the nitrogen present in the feed coal. The
reported production ranges for sulfide and thiocyanate are 0.1 to 4 kg/1000 kg
of coal and 0.06 to 5 kg/1000 kg of coal, respectively. For the processes
listed, very little cyanide is found in the quench water, presumably due to
the reaction of cyanide with sulfide in the presence of oxygen to produce
thiocyanate.
31
-------
TABLE 2-6. SUMMARY OF NORMALIZED CONSTITUENTS PRODUCTION FOR GASIFICATION PROCESS
(KG/1000 KG MOISTURE AND ASH FREE COAL)
Process
COj-Acceptor
Hygas
Lurgi
(dry ash)
Slagging
Gaslfler
Cogas
Synthane
Data Source
Pilot Plant
Pilot Plant
Commercial
gaslfler.
tests with
American
coals
Pilot plant
Pilot plant
Bench-scale
Pilot plant
"free-fall"
"deep-bed"
Coal Type
Lignite; N.D.
Lignite; Montana
Subbl luminous;
Montana
Bituminous, 111.16
Subb1tum1nous.
Montana
Bituminous; 11 1.16
Bituminous; 111. 15
Bituminous;
Pittsburgh 18
Lignite; N.D.
Bttuminous;in.l6
B1tum1nous;I)l.*6
Subbl luminous,
Montana
Subbltuminous.
Montana
Condensable
Organlcs
Tar 011
None None
None M)S
None 1.125
None --•
30 30
30 5
40 7
40 9
{ »}*
{^160|
I 34
— 1
— S
Sum Total of Components In Quench, Scrub and/or Condensate Waters
TOC
2 :0.1
20 i 7
5 l 1.5
14 t 3
--
~
8 t 3
--
--
COD
1.5 i0.4
--*
--
—
28 i 7
26 ; 1
22 • 1
15 t 1
--
8
3.5-17
0.05-6
Phenol
0.025 ±0.01
7 • 1
8 i 2
6 j 2
8 .- 2
6 • 1
6 • 1
4 i 1
-
-20
1
0.2-2.4
<0.004
CN"
0.014 t 0.003
<0.001
<0.001
<0.001
vO.005
1.0.02
xO.Ol
•vd.Ol
--
None
~~
SCN"
0.06 10.07
1.2 ±0.4
0.5 iO.l
5 • 1
0.06 ±0.07
0.15 ±0.04
0.18 i0.02
0.26 ±0.06
--
0.1
~"
NH3
12 t 7
15 • 8
7 • 2
9 t 4
6 t 3
8 • 1
8 t 2
8 i 1
4 ±0.1
8
0.06-2.3
0.03-3.3
S'
0.2 ±0.1
0.1 tO.S
0.3 ±0.1
4 t 1
0.2 iO.l
0.2 iO.l
0.2 ±0.1
0.1 i0.05
2 ±0.1
0.2
0-0.2
0-0.3
TSS
23 l 13
61 l 30
187 i 56
75 ± 50
-
—
•-
60 - 90t
15 **
7.5-60f
0-150
u»
ro
*0ata not available (see text)
*Does not Include suspended solids associated with char/ash quenching
^Values 1n the brackets represent the sum total of tars and oils
•Although no quantitative data are available. It has been shown that very little tars/oils are produced with the "deep-bed"
Injection mode of operation, whereas significant quantities of tars/oils are produced with the "free-fall" mode of operation.
**Does not Include paniculate* collected prior to quenching.
-------
As indicated in Table 2-6, the C02-Acceptor and the Synthane ("deep-bed"
injection mode of operation), which produce essentially no tars and oils,
show low levels of TOC, COD and phenol in the quench water. In contrast,
processes such as Hygas, Lurgi (dry ash and slagging) which produce apprecia-
ble quantities of condensible organics show high levels of TOC (5 to 20 kg/
kg of coal), COD (15 to 30 kg/kg of coal), and phenols (4 to 20 kg/kg of
coal). Data from dry ash Lurgi and Synthane operations (not contained in
the table) indicate that tars contain small amounts of As, Pb, Hg, and Cd
and that condensate/quench waters contain F, Se, B, Hg, Sb, Cd, and As in
measurable quantities.
2.4.3 Char/Ash
Limited data are available on the characteristics of residual chars or
ashes produced in various high Btu gasification processes. Reported values
for the residual carbon in char/ash varied from a few percent for the slagging
Lurgi and Bigas processes to over 50% for Synthane. Chars and ashes also
retain some of the original coal sulfur and nitrogen and contain the bulk of
the original inorganic component of the feed coal.
The trace element composition of several chars/ashes has been determined
and can be compared to the composition of feed coals for potential losses
during gasification. Table 2-7 summarizes the available information regarding
retention of feed coal trace elements by chars produced by four gasification
processes. As indicated in the table, Hg, As, Sb, and F are generally vola-
tilized to a large extent during gasification and would appear in the raw
product gas; Cd, B, Se, and Be are only partially volatilized. Other elements
tend to be retained by chars/ashes. The sampling and analytical uncertainties
involved in trace element determinations to date have generally precluded
accurate material balance closure around gasification operations.
2.4.4 Lockhopper Vent Gases
As discussed in Section 2.2, some high pressure gasification processes
(e.g., Lurgi and Synthane) use lockhoppers for feeding coal to and removing
ash from the gasifier. Essentially no operating data are available on the
composition of lockhopper vent gases. In the case of feed coal vent gases,
33
-------
TABLE 2-7. PRECENTAGES OF SELECTED FEED COAL TRACE ELEMENTS RETAINED WITH
CHAR OR ASH IN GASIFICATION PROCESSES
El ement
Be
Hg
Cd
Sb
Se.._
Mo
Co
N1
Pb -
As
Cr
Cu
B
Zn
V ^.
Mn
F
Lurgi
(dry ash)
Bituminous
So. African
_ ^ •- - I
40
40
40
—
--
--
154
180.
36
--
--
36
—
72
154
54
Lurgi
(dry ash)
Bituminous
Illinois #6
80
1
--
10
--
10
100
125
80
1
300
200
40
90
90
90
<1
Hygas
Bituminous
Illinois #6
--
13
40
--
--
--
63
100
100
--
100
90
60
—
54
>100
—
Synthane
Bituminous
Illinois #6
50-90
16
100
—
100
--
—
20-80
100
60-100
30-70
—
60-100
40-100
40-60
20-65
10-20
C02-Acceptor*
Lignite; N.D.
R
L
_ R
1
PL.
--
--
R
R
PL
R
--
—
—
R
--
--
*Prelim1nary qualitative results based on limited
L = lost, PL = Partially lost
information; R = retained,
34
-------
the vent gas composition would depend primarily upon the gas used for
pressurization. The vent gas is also expected to contain coal devolatiliza-
tion products, particulate matter and components of the gas in the gasifier
(e.g.. HgS, COS and NH3). Two options that are available for feed lock-
hopper pressurization are: (1) use of raw or cleaned product gas and (2) use
of carbon dioxide from acid gas treatment. In the former case, the heating
value of vented gases can be recovered by recycling the gas (after compres-
sion) or by using the gas as plant fuel. When the latter option is used,
the C02 vent gas can be discharged to the atmosphere (after pollution control).
In either case, a small volume of gas (nearly equal to the volume of the
coal charge) would have to be discharged to the atmosphere (after pollution
control).
Ash lockhoppers are usually pressurized with steam. The vent gases from
depressurization would be expected to contain particulate matter and some of
the components of the gasifier gas. The ash lockhopper vent gas has no fuel
value and would be discharged to the atmosphere (after treatment). The vent
gas from both the ash and feed lockhoppers is likely to contain odorous
substances such as mercaptans and HpS. Treatment for odor control may be
necessary before these vent gases are discharged to the atmosphere.
2.4.5 Flue or Off-Gases
Flue or off-gases can arise from coal pretreatment and from the external
gasification/combustion of char (see Section 2.2). Limited data are avail-
able relating to the composition of pretreatment off-gases. Pretreatment
operations at the Hygas pilot plant have indicated that about 25% of the
original coal sulfur may be released during the process. Off-gases will also
contain particulates, carbon monoxide and organics. The disposition of such
gases depends upon-the plant design. At the Hygas pilot plant, off-gases
are scrubbed before atmospheric discharge. At the Synthane pilot plant,
pretreatment is integral with gasification and hence the off-gas becomes
a component of raw product gas. In a commercial facility, off-gases may be
directly flared or fed to the utility boiler (for recovery of fuel value
and/or for pollution control).
35
-------
In the C02-Acceptor, Synthane and Cogas processes, the char generated in
the gasifier would be combusted in a separate operation to recover heat
value. The combustion of such chars would generate a flue gas containing
particulate matter and carbon, sulfur, and nitrogen oxides. Only limited
data are available for the combustion of the CO^-Acceptor char; no data are
available on the flue gas generated from the combustion of char from Synthane
and Cogas processes.
2.5 DATA GAPS AND LIMITATIONS
With the exception of the dry ash Lurgi, the high Btu gasification
processes discussed in this chapter have only been tested in the pilot plant
or bench scale units. Even though some process/waste stream data have been
•generated as the result of these developmental programs, in many cases such
data are not comprehensive in that all streams are not addressed and all
potential pollutants and toxicological and ecological properties are not
identified. Even though much of the bench-scale/pilot plant data may have
the limitations of not necessarily representing conditions encountered in
large-scale facilities, the collection of environmental data during bench-
scale/pilot plant testing is important since such data can provide the basis
for comparison of processes and operational modes from the standpoint of
pollutant generation, downstream pollution control requirements and overall
environmental impacts.
The assessment of the environmental data collected in small-scale
facilities should take into account the possible differences which may
exist between experimental and commercial operations. For example, the
quench systems for pilot plant facilities have not been generally designed
for optimum performance and for minimizing water use and maximizing overall
plant thermal efficiency. In most pilot plant facilities, relatively high
grade water is used for raw product gas and ash quenching. In a commercial
facility, "lower grade" process waters from elsewhere in the plant would be
used for such purposes. Based on the experience gained in the pilot plant
tests, the quench systems designed for full scale operation would most
likely incorporate certain modifications to the smaller units.
36
-------
Several of the high Btu gasification processes (e.g., Bigas and Hydrane)
are in early developmental stages. To date, most of the operating effort
at the bench-scale/pilot facilities has involved equipment shakedown and
"debugging" and very limited or no steady-state operation has been achieved.
The very limited data which are available for some of these processes (e.g.,
Synthane) do not reflect steady state conditions projected for large-scale
operation. To date, the Synthane process, which is being developed to use
caking coals, has only been tested with non-caking coals at the pilot plant
level.
Two of the high Btu gasification processes (Cogas and slagging
gasification) have been extensively tested by private developers. Detailed
technical data on process performance and process/waste stream characteristics,
however, have not been released for these processes. Of all the high Btu
gasification processes reviewed in this chapter, the most extensive amount
of data are available for the dry ash Lurgi. A major limitation of these
data, however, relates to the fact that most of the operation has been with
foreign coals. Under DOE sponsorship, tests have been carried out with four
American coals at the Westfield, Scotland, Lurgi gasification facilities.
The data generated in these tests which account for much of the available
data suffer from the limitation that the coals used are generally not those
which are to be used in the proposed commercial Lurgi facilities in the U.S.
These data, however, do provide a basis for predicting process performance and
stream characteristics associated with the use of different coals.
As noted earlier, the limited data which are available on the composition
of the discharge streams from various high Btu gasification processes suffer
from a general limitation of not being very comprehensive. In many cases,
the characterization of a waste stream is in terms of gross parameters such
as COD and TOC rather than specific constituents. Table 2-8 summarizes the
available data for the Hygas pilot plant (Figure 2-2) and identifies additional
analytical data which are needed for a comprehensive discharge stream
characterization. The data needs identified in the table are those which
can be obtained through the implementation of a sampling and analysis plan
using the EPA's phased approach beginning with "Environmental Assessment
Sampling and Analysis: Phased Approach and Techniques for Level 1"
37
-------
• CUtKNTSAMPUNO POINTS
> STKAMS NOT CUMENTIY SAMMD
IOTHMMAI
0X10
cum
PIANT
(OKINO COALS)
TOTHUMAl
oxinzu
(NON-OW NO
COA15)
H,0
SLUMV TO
' ,TH TKATMENT
( «£TttATA«NT \
«• ^Og
Figure 2-2. Hygas Pilot Plant Sampling Point Diagram
-------
TABLE 2-8. HYGAS PILOT PLANT STREAM CHARACTERIZATION DATA COLLECTED OR PLANNED TO BE COLLECTED BY IGT AND
ADDITIONAL DATA NEEDED BY EPA FOR DISCHARGE STREAM CHARACTERIZATION
Streams
No.*
1
Z
3
*
5
6
7
6
9
10
11
12
13
1«"
IS
16
17
Description
Crushed/Dried Coal
Pre treated Coal
Pretreatment Quench
Mater
Pretreatment Quench
Off-Gas
Spent Char Slurry
Cyclone Slurry
Prequench Slowdown
Gross Parameters
Quenched Product
Gas
Clean Product Gas
Spent Caustic
Methanator Feed
Methanator Gas
Acid Gas
Settling Basin Effluent
Stripper Bottoms
Stripper Vent Gas
Stripped Oil
Lignite
Ultlute Analysis'
N/A'
N/A
N/A
Ultlute Analysis.
Major Constituents and
Gross Parameters
Utllute Analysis
Major Constituents and
Gross Parameters
Major Gas Components
Major Gas Components,
Trace Sulfur Gases
Major Gas Components,
Total Sulfur
Major Gas Components,
Total Sulfur
Major Gas Components
Trace Sulfur Gases
Major Constituents and
Gross Parameters
Major Constituents and
Gross Parameters
Major Gas Cori'jrn.-nM
Ultimate Analysis.
Organic Compounds
Published Data for Various Coals Tested
Subbl luminous
Ultlute Analysis. Trace
Elements?
N/A
N/A
N/A
Major Constituents and
Gross Parameters, Trace
Elements
elements
Major Constituents and
Elements
-
-
-
-
-
Major Constituents and
f 1 erents
Major Constituents and
Gross Parameters, Trace
Elements
-
Organic Compounds
Medium Sulfur
Bituminous
Ultlute Analysis
Ultlute Analysis
Major Constituents and
Gross Parameters*
•
Ultimate Analysis,
Major Constituents and
Gross Parameters
Major Constituents and
Major Constituents and
Major Gas Components
Major Gas Components,
Trace Sulfur Gases
-
Major Gas Components
Total Sulfur
Major Gas Components,
Total Sulfur
Major Gas Components.
Trace Sul fur Gases
•
Ultimate Analysis. Major
Parameters
-
tlMte Analysis
High Sulfur
Bituminous
Utllute Analysis
-••
Major Constituents and
Gross Parameters
Total Sulfur
Major Constituents and
Gross Parameters,
Sulfur Species
Major Constituents and
Gross Parameters
Major Constituents and
Gross Parameters
•
-
Additional Data Expected
To Become Available As
Part of Ongoing
IGT/DOE Program?
Ultlute Analysis, Trace
Elements. Sulfur Species^
Utllute Analysis
Major Constituents and
Gross Parameters
Major Gas Components,'
Total Sulfur
Major Constituents and
Gross Parameters, Sulfur
Species, Trace Elements
Major Constituents and
Gross Parameters, Trace
Elements
Major Constituents and
Gross Parameters, Trace
Elements
Major Gas Components,
Trace Sulfur and
Nitrogen Gases
Major Gas Component;
Trace Sulfur Gases
-
•
-
Major lunstituentl and
Gross Parameters
Major Constituents and
-
•
Major Gas Components,
Total Sulfur
Major Gas Components,
Total Sulfur
Major Gas exponents
Trace Sul'ur f.ases
Major Constituents and
Gross Parameters, Trace
Elements
Major -orncituents and
Elements
-
•
Data Heeded But Not Generated By
Known Existing or Planned
Sampling/Analysis Programs!
(ton, tt.tt
None"
Organic Compounds. 5 Trace Element
Trea lability'. Radioactivity
Trace Sulfur and Nitrogen Gases'
PartlculateB, Organic Compounds,
Radioactivity"
Organic Compounds. Treatabil i ty ,
Radioactivity
Organic Compounds, Treatabil itr,
Radioactivity
Organic Compounds, Treatabil uy.
Radioactivity
Partlculate. Organic Compounds,
Radioactivity
None
None
None
None
None
Organic Compounds. Treatabil Hy,
Radioactivity
Organic Compounds. Treatablll ty ,
Radioactivity
Major Gas Components, Organic
Compounds
Organic Compounds
U)
to
(continued)
-------
TABLE 2-8. CONTINUED
Streams
No.«
IB
19
20
21
22
23
24
25
26 »
27
28
Dttcrlptlon
Slurry Preparation
Vent Gas
Coal/011 Slurry
Make-up Mater
Ran Product Cat
Separated Solids/
Sludge
Separated Oil
Pond Influent
Filter Solids
Pond Solids
Reflux Condensate
Fugitive Emissions
Published Data for Various Coals Tested
t
Lignite Subbttiaalous
•
Only Flow Rate
Major Constituents and
Gross Parameters
-
•
-
-
•
-
-
-
Major Constituents and
Elements
Major Gas Constituents
•
'
"
*
•
Medium Sulfur
Bituminous
-
Flow Rate
Major Constituents and
Gross Parameters
Major Gas Constituents
•
'
'
"
•
High Sulfur
Bituminous
-
-
Major Constituent! and
Gross Parameters
-
•
'
"
•
-
Additional Data Expected
To Become Available As
Part of Ongoing
IGT/OOE Program T
-
-
Major Constituents and
Gross Parameters, Trace
Elements
Major Gas Constituents
Trace Sulfur and
Nitrogen Gases
'
~
'
'
•
Data Needed But Not Generated By
Known Existing or Planned
Sampling/Analysts Programs!
Major Gas Components, Organic
Compounds
None
None
Participate, Organic Compounds
Ultimate Analysis, Organic
Compounds, Trace Elements,
Treatablllty, Leochate Analysis,"
Bloassay, Radioactivity
Ultimate Analysis, Trace
Elements. Organic Compounds,
Bloassay'O
Major Constituents and Gross
Parameters, Trace Elements.
Organic Compounds,
Treatablllty
Ultimate Analysis, Organic
Compounds. Trace Elements
Treatablllty, Leochate Analysis,'1
Bloassay, Radioactivity
Ultimate Analysis, Organic
Compounds, Trace Elements, .,
Treatablllty, Leach* te Analysis.
Bloassay, Radioactivity
Major Constituents and Gross
Parameters, Organic
Compounds
None
•See Pilot Plant Sampling Point Diagram (Fig. 2-2)
TThese additional data pertain to tests wltt different coals and/or different operating conditions.
^Provided that the Information listed 1n the proceeding columns .111 be obtained by IGT/OOE as assuned.
IN/A • Not Applicable
••NO data available to TRH on any sampling (previous or planned) of these streams
"None Indicates that either the existing data and/or the data planned for acquisition are adequate or that the specific streams are not of interest because they are not scalable to co
ttSelected time-specific sampling of coals may be necessary for Interpretation of data on other stream and for material balance calcuatlons.
11 Pond receives MStes from the Kygas plJot plant as Mil as from other sources at the site; accordingly, streams Nos. 14 and 26 are not solely reflective of the Hygas pilot plant.
DESCRIPTION OF ANALYSES
trctal operations.
Ultimate Analysis
Trace Elements
Sulfur Species
Mejor Constituents and Gross Parameters
Organic Compound!
Major Gas Constituents
Trace Sulfur and Nitrogen Gases
Partlculate
TreatablHty
Bloassay
Leachate Analysis
Radioactivity
C. H, N, S, Ajh. volatile material, moisture
Fe. Ba, Mn, Na, Zn. La. Cr. Cu. Cd, Pb, Hg, Mo, B, Be, f. T1. V. Ca, Hg, Na, Al, K, r
Organic, Pyrlttc, Sulfate .
TO, TS5, TOC, pH, Phenol. CN", SCN", S , NH3, cr, 011, Total S
Specific Compounds Including environmentally Important members of the following classes: oleflns; aromatlcs; POMi N, S, and 0 Compounds, Etc.
COj, CO, H20, HZ, CH4, C2*. «2 <• Ar). H?S
NH3, HCH. COS. CS2. R-SH
Total mass loading, size fractions, trace element*.
Includes blodegridablllty, settlelbUHy. fllterablHty. dewaterabllUy. etc.
Ames type tests, acute/chronic toilclty, etc.
Water leaching and leachate analysis for major and trace tlef-wnti, gross parameters, ind organic compounds.
Grois -». fl count! and u. Th concentration!
-------
(Rpt. No. EPA-600/2-77-115, June 1977) in combination with the ongoing DOE
program.
2.6 RELATED PROGRAMS
A number of programs are currently being sponsored by the EPA and DOE
which would generate some of the needed data identified above. Among the
EPA-sponsored programs are those conducted by: (a) the Research Triangle
Institute for experimental studies of pollutant production during gasification;
(b) Illinois State Geological Survey for characterization of coal and coal
residues; and (c) the Radian Corporation for environmental assessment of low/
medium Btu gasification. Programs sponsored by DOE include: (a) the high
Btu coal gasification pilot plant environmental assessment program coordinated
by Carnegie-Mellon University; and (b) programs being conducted by the
DOE national laboratories. Many of these programs are broad in scope and
are expected to generate data pertaining to all operations in an integrated
commercial plant and not only to the gasification operation reviewed in this
chapter. A brief review of the EPA- and DOE-sponsored programs follows.
2.6.1 EPA-Sponsored Programs
t Research Triangle Institute (RTIr ' - In November 1976 the Research
Triangle Institute began a 5-year program to identify and semi-
quantitatively determine the specific chemical species present in
various effluents from gasification and other synfuels processes.
The pollutants are to be ranked in order of their potential environ-
mental hazard, based on such factors as concentration; amenability
to treatment; disposition, dispersion , and dilution of the effluent
stream; and ultimate pathways to human exposure. In addition, a „
tabulation of kinetic data pertaining to the rates of formation of
environmentally significant pollutants will be generated.
The RTI program includes the design, construction and operation of a
laboratory-scale gasification reactor of sufficient flexibility to
simulate the operating conditions of candidate commercial processes.
To date, the gasifier has been operated with coke and Illinois No. 6
bituminous coal. In addition, a sampling train is under design for
the acquisition of char, tar, oil, water and gas samples from the
reactor. Multimedia analytical techniques are also currently being
developed, calibrated, and tested for the determination of pollutants
generated by the gasifier.
t Illinois State Geological Survey (ISGS)^18'19^ - The ISGS is con-
tinuing a multi-year program which has 3 primary objectives: (a) to
41
-------
characterize the chemical, physical and mineral properties of coals,
coal by-products and coal wastes; (b) to investigate the effects of
pyrolysis on the distribution of trace elements between the volatile
components and the residue; and (c) to provide data on the solubil-
ities and toxicities of potential pollutants contained in solid coal
wastes. To date, significant data have been generated on the
chemical form of minor and trace elements in coal and coal char,
and correlations are currently being developed for various elements
to determine their association with coal minerals and organic
matter. Recent pyrolysis studies have determined that certain
elements are more volatile in lignites than in bituminous coals, based
on data obtained on a continuously-fed coal char furnace constructed as
part of the program. Toxicity and bioassay studies of leachates from
solid coal wastes have been conducted. Other pyrolysis, leaching
and toxicity studies are in progress.
(20 21]
• Radian Corporationv ' ' - As part of EPA's comprehensive Synthetic
Fuels Environmental Assessment/Control Technology Development
Program, the Radian Corporation is currently conducting a 3-year pro-
gram (March 1976 to March 1979) for the comprehensive environmental
sampling/analysis tests at 4 low/medium Btu gasification facilities,
including the Kosovo Kombinat plant in Pristina, Yugoslavia, which
uses Lurgi gasifiers to convert lignite to fuel gas and fertilizer
plant feedstocks. An environmental test plan for the Kosovo plant
has been developed jointly by the Rudarski Institute (Belgrade,
Yugoslavia), EPA, and Radian as part of a cooperative environmental
research program. Radian is providing on-site technical assistance
during the tests.
• University of North Carolina (UNC) and North Carolina State
University (NCSU) - The UNC program on wastewater treatability and
the NCSU program on raw/acid gas clean-up are discussed in
Sections 5.5 and 3.2.5, respectively.
2.6.2 DOE-Sponsored Programs - Pilot Plants
Five contractors and two DOE national laboratories are currently involved
in environmental assessment of five DOE high Btu gasification pilot plants.
The five pilot plants and the environmental assessment coordinators for
each plant are as follows:
Pilot Plant Environmental Assessment Coordinator
Hygas Institute of Gas Technology (I6T)
C02-Acceptor Radian Corporation
Synthane Pittsburgh Energy Research Center (PERC)
Slagging Fixed Bed Grand Forks Energy Research Center (GFERC),
Steams-Roger, Inc.
Bigas Phillips Petroleum, Penn. Environmental
Consultants (PEC)
42
-------
Carnegie-Mellon University (CMU) is providing overall coordination and
evaluation for the entire DOE pilot plant assessment program. The status of
the environmental assessments at each of the plants is summarized below:
(22 23)
• Hygasv ' - The DOE environmental assessment program at the Hygas
pilot plant has been in effect since mid-1976 and a considerable
amount of environmental data has been generated. Three on-line ana-
lytical instruments - a sulfur chromatograph, a total organic carbon
(TOC) analyzer, and a total oxygen demand (TOD) analyzer for water
streams - have been installed and operated in recent runs. A heated
and insulated gas sampling line has been installed between the gasi-
fier cyclone and pre-quench tower, for the sampling of raw product
gas before water quench. Laboratory experiments to determine the
effects of shift catalysts on trace constituents in the product gas
are continuing. Batch and continuous leach tests have been performed
on Hygas char. As the operation of the Hygas pilot plant continues,
additional data are expected to be generated for the gasification of
very high sulfur coals and for operating conditions aimed at achiev-
ing high carbon conversions.
(24 25)
• C02-Acceptorv ' ' - Radian Corporation and CMU prepared and executed
a comprehensive test program for the C02~Acceptor pilot plant prior
to plant shutdown in 1977. Extensive gas phase analyses, particularly
for sulfur species such as H2S, COS and CSo, were conducted at the
plant. Numerous analyses and time variability studies were also con-
ducted on selected wastewater streams and constituents. Limited gas
phase sulfur species data have also been collected by Steams-Roger,
Inc. (the plant operations contractor) during the last few plant runs.
Results of both the Radian and the Stearns-Roger tests are soon to be
published.
• Synthane' ' ' - Preliminary field work has been performed at the
Synthane pilot plant as part of a comprehensive environmental assess-
ment of the process. An ambient sampling program has been undertaken
to determine baseline conditions as well as impacts caused by the
operation of the plant. A process/waste stream sampling and analysis
program is currently under way at the pilot plant. In a parallel
effort, PERC is operating a bench-scale Synthane unit to generate
supplementary data. Studies have been conducted on the biotreatabil-
ity of the quench waters from the bench-scale unit and on the mech-
anism of tar and oil formation and decomposition.
• Slagging Gasified25'27) - At the Grand Forks Energy Research Center
(GFERC) in Grand Forks, North Dakota, a preliminary comprehensive
test plan for the slagging gasifier was developed by GFERC and
Stearns-Roger, Inc. Analyses have been performed and results re-
ported on the composition of product gases, condensates and slag
produced when lignite was utilized as feed. Similar data are to be
collected for other coals and under a variety of operating conditions.
43
-------
t Biqas^ ' - Penn. Environmental Consultants have developed a multimedia
environmental sampling and analysis plan for the Bigas pilot plant.
Limited sampling and analysis of selected Bigas condensates have
been performed but the results have not yet been published. Testing
under steady state conditions has been hampered by the continual
operating difficulties encountered with the gasifier operation (see
Section 2.3.3).
2.6.3 DOE-Sponsored Programs - National Laboratories and Other Programs
• Oak Ridge National Laboratory (ORNL)*28'29* - The DOE's Biomedical
and Environmental Research Division (BERD) is currently conducting
research to determine potential environmental/health problems stemming
from coal conversion. In connection with the dry ash Lurgi process,
a number of studies have been proposed and some are being implemented
bv BERD/ORNL relating to industrial hygiene and safety, epidemiologi-
cal studies and procedures, pollutant monitoring techniques, and other
environmental information. One such program which is currently
underway involves characterization of the solid wastes generated at
a Lurgi facility from the standpoint of trace element and organics
composition. Another current program at ORNL involves the development
of short-term genetic bioassay for characterization of complex
effluents and the identification of chemical mutagens.
• BatteH e-Paci fie Northwest Laboratories (BNWL)*30) - BNWL is currently
conducting a program to characterize products and waste streams from
synfuels processes, including gasification processes. Although
most of the effort to date has been directed toward the analysis of
oil shale and coal liquefaction effluents, BNWL has conducted limited
sampling and analysis at the C02-Acceptor pilot plant in Rapid City,
South Dakota, and has analyzed effluents from the Laramie Energy
Research Center in-situ coal gasification facility in Hanna, Wyoming.
Data for the ^-Acceptor and in-situ testing have not yet been
made public.
(31 ]
• Argonne National Laboratory (ANL)V ' - ANL has recently initiated
a 5-year program to analyze trace organics in process streams at
coal gasification pilot plants by means of gas chromatography-mass
spectrometry (GC/MS). Effluents from high and low/medium Btu
gasification operations are to be analyzed, beginning with condensates
from the Hygas pilot plant in Chicago, Illinois. A parallel effort is
being conducted for the biological characterization of various
sample fractions to determine which fractions are carcinogenic or
mutagenic using Ames cell tests.
• Slagging gasification tests at the Lurgi facility in Westfield,
Scotland(6,32) - DOE has been sponsoring tests at the commercial-
scale Lurgi plant in Westfield, Scotland, where a gasifier has been
operated in the slagging mode. The project is being conducted by
a consortium of companies headed by Conoco, Inc., in cooperation
with the British Gas Corporation. Sampling and analysis of major
process streams have been performed at the Westfield site.
44
-------
The results of the Westfield tests are to serve as the basis for the Conoco
design of a DDE-funded slagging Lurgi demonstration plant to be constructed
in the U.S. A site at Noble County, Ohio has been proposed for the demonstra-
tion plant.
45
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3.0 GAS PURIFICATION OPERATION
Figure 3-1 presents the process modules for the gas purification opera-
tion. As shown in this figure, the gas purification operation consists of
two process modules: quench and dust removal and acid gas treatment. The
quench and dust removal, which for many high Btu gasification systems is
integrated into the design and operation of the gasifier, was reviewed in
Section 2.0 in connection with the gasification operation. This section
reviews the acid gas treatment module of the gas purification operation and
discusses the various processes in this module.
3.1 REQUIREMENTS FOR ACID GAS REMOVAL
The removal of HpS and trace sulfur species from raw product gas is nec-
essary to prevent methanation catalyst poisoning. The removal of C02 is
almost always necessary to obtain a product gas with heating value equivalent
to that of natural gas. (In this respect, the acid gas treatment for CO* re-
moval may also be considered an element of the gas upgrading operation -
see Chapter 4.0.) Depending on the hydrogen to carbon monoxide ratio of the
raw product gas, which determines whether or not shifting of the gas
is necessary prior to methanation, the acid gas treatment may immediately
follow quench and dust removal or it may follow gas shifting. H«S and C02* may
be removed either simultaneously ("non-selectively") or separately ("selec-
tively"), depending on the specific acid gas removal process chosen and its de-
sign. The specific acid gas treatment process (selective or non-selective) to
be used in a high Btu coal gasification plant should be chosen with due con-
sideration to the integration of the process with sulfur recovery and/or tail
gas treatment and the overall economics of the sulfur management scheme (see
below.)
After shift conversion, the product gas from most gasification processes
(dry ash Lurgi, Hygas steam-oxygen, Cogas, Synthane, and Bigas) contains about
46
-------
GAS PURIFICATION OPERATION
GAS UPGRADING
OPERATION
QUENCH ANC(
WET DUST
REMOVAL
I
I I
METHANATIONj_
|AND DRYING ,
'
1 SNG
Figure 3-1. Process Modules for Gas Purification and Gas Upgrading Operations
-------
30 to 35% C02,depending on the feed coal. (Considerably higher levels of C02,
about 53 to 57%, are found in shifted product gas from the slagging Lurgi and
considerably lower levels, about 10%, are found in C0,,-Acceptor product gas.)
The H2S content of shifted gases is determined mainly by the sulfur content
of the feed coal and is also affected by the gasification process. Except
in the case of the C02-Acceptor process, shifted product gas contains about
0.2 to 0.4% H2S when western subbituminous coals (0.7% sulfur) are gasified
and about 1 to 2% when eastern bituminous coals (2 to 4% sulfur) are gasified.
The C02-Acceptor product gas contains only about 0.03 to 0.06% H2$ (and about
10% C02) due to sulfur (and (XL) removal by dolomite during gasification.
As shown in Table 3-1, C02 to H2$ ratios in the shifted product gas vary
from about 100 to 275 for the gasification of low sulfur coal and are in the
30 to 40 range for the gasification of high sulfur coal. As will be dis-
cussed in Chapter 5.0, processing of acid gases in a Claus sulfur recovery
plant is inefficient and uneconomical when the acid gases contain less than
10-15% H2S (corresponding to a C02 to H2$ ratio of 7). Non-selective acid
gas treatment of shifted gases will generate a stream containing less than
10% HgS and will hence require treatment by processes other than Claus (e.g.,
Stretford, which can handle dilute H^S levels). Selective acid gas treat-
ment processes, while generating an H2S stream concentrated enough for use as
Claus plant feed, may also generate a C02 stream having a residual H2$ too
large for atmospheric discharge. Thus, additional treatment would also be
required with selective hLS removal.
TABLE 3-1. C02 TO H2S RATIOS IN THE SHIFTED PRODUCT GAS FOR VARIOUS
GASIFICATION PROCESSES
Feed
Process Coal Sulfur (%) C02/H2S Ratio
Dry Ash Lurgi, Hygas Steam- 0.7 -100
Oxygen, Cogas, Synthane, and -3 -30
Bi gas
Slagging Lurgi 0.7 275
-3 -40
C02-Acceptor 0.7 >200
48
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3.2 ACID GAS REMOVAL PROCESSES
This section summarizes the available information relating to candidate
acid gas removal processes and their applicability to high Btu gasification.
The processes discussed fall into three general categories: hot gas H2S re-
moval processes, physical and chemical solvent processes, and methanation
guards.
3.2.1 Hot Gas H2$ Removal
Potentially high overall thermal efficiencies are possible with hot gas
H2$ removal between shift conversion and methanation. Several processes are
currently under development for the removal of H2S and other sulfur compounds
from raw, hot gasifier gas (see Table 3-2). These processes generally use
either a solid material or a molten salt to capture H2S as sulfides. The
spent sorbent may or may not be regenerable. None of these processes have
yet reached the commercial stage and only limited data are available on their
performance. Data sheets were not prepared for these processes because of
the limited data availability and the fact that these processes are not ex-
pected to be commercially available on time for incorporation in the first
generation of SNG plants in the United States.
TABLE 3-2. HOT GAS HgS REMOVAL PROCESSES UNDER DEVELOPMENT
Removal Agent Process Developer
Iron oxide Morgantown Energy Research Center
(Fe^O-XFe-O.) Appleby-Frodingham
* * J * Battelle-Columbus
Babcock & Wilcox
Coal Ash University of Kentucky
Molten Carbonate Battelle-Northwest
HaIf-Calcined Dolomite Conoco
(CaO-CaC03)
3.2.2 Solvent Processes for Acid Gas Removal
A variety of solvent processes are commercially available or under de-
velopment for the removal of C02 and H2S from gas streams. These processes
use solvents or solutions for the removal of acid gases. Depending on the
49
-------
process, the spent solution is regenerated by heating, depressurization or
oxidation. The regeneration results in the production of a concentrated by-
product gas stream which can be processed for sulfur removal and/or recovery.
Compared to the hot gas removal processes which can handle shifted product
gas without cooling, solvent processes cannot be operated at high temperatures
(about 400°K or 250°F) due to sorbent volatility. The solvent processes can
either be selective or non-selective (see Section 3.1). Through modification
in design, some processes (e.g., Benfield) can be operated in either mode.
Many of the solvent processes have been used in the purification of
natural gas and (to a lesser extent) refinery and coke oven gases. A few
processes have been used for the treatment of coal gasification product gas.
The operating data for these processes, however, are very limited. For appli-
cation to high Btu gasification, the most important characteristics of a
given process are (1) operability at high pressures, (2) the levels of resi-
dual sulfur compounds and CO- obtainable in treated gas, (3) the ability to
remove trace constituents, (4) capital and operating (utility) costs, (5)
constraints which the process imposes on upstream and downstream processing,
and (6) generation of hazardous wastes and waste disposal requirements.
Solvent processes for acid gas treatment may be broadly classified as
physical solvent processes, chemical solvent processes (amine based and car-
bonate based), mixed solvent processes, and oxidation/reduction (redox) pro-
cesses. A listing of important representative processes in each category
and their key features is presented in Table 3-3 (data sheets for these pro-
cesses are included in Appendix B), As shown in the table, physical solvents
offer good selectivity for removal of H«S over f02 and can remove other
sulfur and nitrogen compounds, water vapor, and some organics. Physical sol-
vents are most effective and economical when high partial pressures of acid
gases are encountered. Amine solvents are generally less selective than
physical solvents and have higher energy requirements for regeneration. As
the partial pressure of acid gas in the gas stream increases, the economy of
amine systems declines. Carbonate systems can be partially selective toward
H«S, are not degraded by sulfur and nitrogen compounds, and do not absorb
organics to any appreciable extent. Moderate to high pressure is generally
required for economical operation of carbonate systems. Mixed solvents show
50
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TABLE 3-3. KEY FEATURES OF SOLVENT PROCESSES FOR ACID GAS REMOVAL
Process Ham
PHYSICAL SOLVENTS
Rectlsol
Purl sol
Fluor solvent
ESUtOlvln
CHEMICAL SOLVENTS
taint Solvent!
Sulflban
HOEA
?EA
ADIP
Alkazld
Carbonate Solvents
Benfleld
Catacarb
MIXED SOLVENTS
Sulftnol
Aalsol
REOOX PROCESSES
Glaimarco-
Vetrocoke
Stretford
Solvent/ Reagent
Mettanol
polyethylene glycol
N-uthyl
2- pyrrol I done
Propylene
carbonate
Trl-n-butyl
phosphate
Honoefiarolanine (MIA)
Methyl-dletnanol-
ulne
Dlethanolamne
Dllsopropanolamlne
Dfglycolanlne (OCA)
tHMthyl or die thy 1
glyclne
Poiasslun carbonate
and dletnanft'amlne
Potassium carbonate
and amlne borates
Cyclotetranethylene
sulfone and dllsopro-
panolanlne
Hethanol and rano- or
d1ethanolan1ne
Potassluti carbonate
and arsenate/arsenlte
and anthraqulnone dl
sulfonlc acid
Operating Pressure
add gas partial
pressure)
High
High
High
High
Low
Lou
Lo»
LOW
Moderate
Moderate
Moderate
Moderate
H2s/coj eoj/Ht
Good Poor
Good Moderate
Moderate Moderate
Moderate Moderate
Poor Good
Poor Good
Moderate Good
Moderate E.cellcnt
Moderate Excellent
Poor Moderate
Poor Moderate
1
""
CMponent Distribution*
„ Higher Hiter
t | it • t » t » «
• ,b «,b e.d a.d a.c.d a.b.c.d d
a.b «,b a.d a.d a.c.d «,b.d d
i,b a,b a id «,d a.c.d a.b.d d
a.b a.b a. . , 9
a.b a.b a.b.d a.d e a .d d»g
a.b a.b a.b.d a.d e a.d d.g
f.9 f.g d.g a.d e a.d d.g
r.g '.9 '.9 •<•<< '•»•" 9 9
f.g '.i '>9 *.d '•••d 9 9
a.b a.b a.d a.d a.d a.b.d d.g
Solvent Losses
(Replacement
High
Lou
Lou
Loo
High
High
Moderate
Low
L(M
Low
Low
High
Low
Low
Utility t
Moderate/Ion
Loo
low
Low
Very high
Very high
High
High
High
Moderate
Moderate
Moderate
Moderate
Moderate
Moderate
with add gas strean after slnultaneous C02 and MjS remval
«1th CO; stream after separate CO; and H;S removal
xlth HjS stream after separate COz and H^S removal
with aqueous or organic liquid phase prior to or Integral »Uh process
degrades solvent
hydrolyies
remains with treated gas
'Depends nac.do.s.rt., pressure, selective ,s non-se.ect.,, design. ,M residua, su.fur .Lowed; r.ti.g H for »d,r.te to hi* pressure appUc.t.on
with .10 ppn residual MjS 1n treated gas.
•Selectivity good, but high CO., lowers H?S absorption rate and requires Urge system for efficient H?S rcno.al.
-------
low selectivity for hLS over CCL. Redox processes offer the potential for
H2S removal and sulfur recovery in a single operation. They, however, suffer
from certain disadvantages such as solution degradation (e.g., via thiocyanate
formation in Stretford solution), the use of hazardous solvents (e.g., arsenic
compounds in the Giammarco-Vetrocoke process), and inefficient HgS absorption
from high COp content gases (e.g., Stretford).
The selection of an acid gas treatment process for SNG application should
take into account subsequent tail gas treating and/or for sulfur recovery pro-
cesses. In addition, factors such as residual sulfur, CC^, organics, and
moisture levels in the treated gas influence the design of methanation and
associated guard systems. Based on the detailed data presented in Appendix B
and the results of several other studies evaluating acid gas treatment systems
for coal gasification application,^ " ' the following conclusions can be
drawn:
0 Physical solvents are likely candidates for high pressure selective
acid gas removal. Processes such as Rectisol and Selexol offer high
selectivity toward HgS and would be economical for high pressure
operation. Residual sulfur and COg levels obtained are consistent
with methanation catalyst protection requirements (i.e., only small
sulfur guard beds would be required). Also, water vapor and organics
which can deactivate either the sulfur guard or the methanation
catalyst are largely removed.
• Amine based processes are not likely to be commercially employed
for bulk acid gas removal in SNG production. MEA and DEA suffer
both excessive degradation and vaporization losses. Even the more
stable and less volatile solvents (e.g., DIPA, DGA) are uneconomical
at high pressures and are not selective enough toward H2S. The use
of such processes would result in an acid gas stream containing as
low as 0.3% H2$ and the remainder C0£. This presents a major pro-
blem for subsequent sulfur recovery/removal. One amine solvent
ADIP) has been proposed for use in a commercial SNG facility for the
purpose of recovery of hydrocarbons and concentration of h^S from
the concentrated acid gas stream from a physical solvent process
(Rectisol)(9»3');
Carbonate systems may have application for both selective and non-
selective acid gas removal from product gases at moderate pressures.
Carbonate systems can be more economical than physical solvent
systems for moderate pressure applications. Carbonate systems are
ineffective in removing organics and produce a gas which is satu-
rated with moisture. The high moisture and organics content of
treated gases may necessitate additional treatment prior to
methanation.
52
-------
0 Mixed solvents (Sulfinol and Amisol) are not likely to be employed
in SNG application, due to their relatively low H2S removal effici-
ency (e.g., compared to the carbonate system), lack of selectivity
and high solvent costs.
• Redox systems which would be suitable for "tail" gas treatment are
not likely to be employed for acid gas removal from product gas in
high Btu gasification. Capital and operating costs for Redox systems
would be significantly higher than for amine, physical solvent, and
carbonate systems handling the same volume of gas. This is despite
the fact that separate recovery of sulfur is not required with Redox
systems. Other disadvantages of the Redox system include excessive
solution degradation when treating gases containing HCN (e.g., in
the case of the Stretford process), inability to remove trace sulfur
compounds (COS, CS2> mercaptans) and organics (in the case of Stret-
ford and Giammarco-Vetrocoke processes), and the use of hazardous
solvents (e.g., use of arsenic in the Giammarco-Vetrocoke process
solvent). It should be emphasized, however, that processes such as
Stretford may find applications to the concentrated acid gas stream
generated by other acid gas removal systems (see Chapter 5.0).
3.2.3 Methanation Guards
Although most processes for acid gas treatment remove sulfur compounds
to ppm levels or lower, additional measures to protect the methanation cata-
lyst against sulfur poisoning and carbon formation are required. Methanation
guards are fixed beds of adsorbents which, when used ahead of the methanation
catalyst bed, can provide the necessary protection by (1) removing traces of
sulfur compounds under normal operating conditions, (2) providing for "stand-
by" bulk sulfur removal capacity in case of the malfunction of the acid gas
removal systems, and (3) removing olefins and aromatic hydrocarbons which can
lead to carbon formation on-the methanation catalyst.
Methanation guards are of four general types: metal oxide beds (zinc,
iron or nickel), metal oxide impregnated activated carbon, activated carbon,
and molecular sieves. Data sheets for these types of methanation guards
(processes) are included in Appendix B. Table 3-4 summarizes the key features
of each process. As indicated in the table, a ZnO bed can achieve the lowest
H2S (and COS) levels. The zinc oxide bed, however, is not regenerate and is
deactivated by the presence of the moisture in the feed gas. Spent methana-
tion catalyst (NiO), although deactivated as far as catalytic activity for
methanation is concerned, has a considerable capacity for adsorption of sul-
fur compounds and can potentially be used as guard bed material.
53
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TABLE 3-4. FEATURES OF METHANATION GUARDS
Process
Metal Oxides
ZnO
Fe2°3/Fe3°4
N10*
Metal Oxide
Impregnated Carbon
Activated Carbon
Molecular Sieves
Efficiency
H2S
Removal
Very high
High
High
High
Low
Moderate
COS
Removal
High
?
High
High
Low
Incomplete
Organlcs
Removal
Low
Low
Low
High
High
Moderate
Moisture
Removal
Low
Low
Low
Low
Low
High
Applicable
at High
Temperature
Yes
Yes
Yes
Yes*
Yes*
No*
Is Bed
Regenerable?
No
Yes
No
Yes
Yes
Yes
Relative
Cost
Low
Moderate
Low
High
High
High
*Assumes the use of spent methanation catalyst as methanatlon guard.
1"0rgan1cs may not be completely removed at high temperatures.
*H«S not completely removed at high temperature; moisture only partially removed at high temperature.
-------
Metal oxide Impregnated carbon offers capability for both organlcs and
H2S removal and can also be regenerated. The cost of the system, however,
would be higher than the cost of the throw-away zinc oxide system. Activated
carbon is Ineffective for the removal of low molecular weight sulfur compounds
(H2S and COS) but is very effective in removing aromatics and olefins. Mole-
cular sieves are ineffective for H2S removal at high temperatures, but are
effective for removing moisture.
In summary, ZnO appears to be the most likely candidate for trace sulfur
removal applications, whereas the activated carbon and molecular sieve are
suitable for the removal of organics and moisture, respectively.
3.3 DISCHARGE STREAMS
Acid gas treatment systems have three general types of discharge streams:
treated gas, by-product concentrated acid gas(es), and waste sorbent. Treated
gas composition will depend upon the process chosen, the particular design of
the process, and the properties of the feed gas. Many of the candidate pro-
cesses listed in Table 3-3 can achieve H2S levels of a few ppmv or lower and
C02 levels less than 1000 ppmv. Levels of other constituents in treated gas
are process dependent (see Table 3-3 for the fates of various species). Non-
selective removal processes result in the production of a by-product acid gas
stream which contains less than about 3% HgS; selective removal processes can
produce an acid gas stream containing over 152 H^S. The C02 stream from
selective removal often contains some H^S and other sulfur compounds.
Waste or spent sorbent is produced in many processes due to the require-
ment for periodic or continuous purging of the sorbent to maintain high re-
moval efficiency. Sorbent waste streams are also generated as a result of
leaks and accidental spills. During normal operation, certain constituents
removed from the feed gas (e.g., partlculates, moisture and organics) accumu-
late in the system, thus requiring periodic purging. Some of the trapped
material can also cause direct sorbent degradation (e.g., in the Sulflban
process, carbonyl sulfide and mercaptans can bring about sorbent degradation
by forming gums and sludges). In the case of certain solid bed systems, the
entire bed must be replaced periodically due to the exhaustion of the sulfur
absorbing capacity (e.g., formation of zinc sulfide in the case of zinc oxide
beds).
55
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3.4 DATA GAPS AND LIMITATIONS
Although considerable data are available for many acid gas treatment
processes, in the majority of cases such data are for applications to natural
gas, petroleum refinery and miscellaneous industrial processes other than
coal gasification. Even in the very limited cases where the available data
pertain to coal gasification, the specific designs used would not necessarily
be employed in SN6 applications. For example, the Rectisol unit in use at
the Sasol gasification facility in South Africa is designed for maximum acid
gas removal with no consideration for sulfur recovery or tail gas treatment.
At this facility, by-product acid gas is incinerated. In contrast, .in a com-
mercial facility in the U.S. the by-product gas stream must be processed for
sulfur recovery/pollution control and the Rectisol design must be modified
accordingly. The estimated characteristics of discharge streams associated
with acid gas treatment processes incorporated in the proposed designs for
commercial gasification facilities in the U.S. are based largely upon concep-
tual design and not on actual operating experience. Further, since the
specific design of a given system would be influenced by cost, utility, and
overall efficiency considerations and hence would vary from plant to plant,
the exact stream compositions are also expected to vary from plant to plant.
Since no commercial SN6 facility is in operation in the U.S., actual
data on the composition and properties of waste streams from acid gas treat-
ment are currently unavailable. Any waste characterization program should
place special emphasis on elucidating the fate of trace constituents (e.g.,
COS, mercaptans, HCN, trace elements) in the acid gas treatment processes.
3.5 RELATED PROGRAMS
A limited number of programs are under way or planned which could provide
additional data relating to gas purification operations. Under an EPA grant,
North Carolina State University will operate a general purpose coal gasifica-
tion/gas cleaning facility. As part of the overall program, at least four
absorption solvents for acid gas removal will be tested (cold methanol, hot
potassium carbonate, monoethanolamine, and dimethylether of polyethylene
glycol). The results of these tests are expected to generate useful data
relating to the performance of acid gas removal systems in coal gasification
56
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applications and the characteristics of process/discharge streams. The
Synthane pilot plant (see Sections 2.2 and 2.3) incorporates both Benfield
and Stretford units. The Bigas pilot plant features a Selexol unit. Texaco,
Inc. and the Electric Power Research Institute are currently involved in a
pilot plant program to evaluate entrained, coal gasification-combined cycle
gas turbine systems for electric power generation. The pilot plant, which
is located at the Texaco's Montebello Research Laboratory, Montebello, Ca.,
features a Selexol unit for removal of H«S from product gas. Operation of
this unit should result in the generation of important data pertaining to
process performance in SNG applications. Finally, a commercial scale Stret-
ford unit has been recently constructed at the Sasol plant in South Africa
which offers the opportunity to assess the performance of Stretford process
in handling low F^S, high COp gases.
57
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4.0 GAS UPGRADING OPERATION
The processing of quenched product gases to produce SNG generally re-
quires a shift conversion step, an acid gas removal step, and a methanation
and drying step. Figure 3-1 depicts the generalized process modules for these
treatment steps. As shown in the figure, quenched product gas may or may not
require shift conversion, depending on the hydrogen to carbon monoxide ratio.
After shift conversion, acid gas removal is required to protect the methana-
tion catalyst from sulfur poisoning and to remove carbon dioxide which would
dilute the final product gas. Finally, hydrogen and carbon oxides are cata-
lytically reacted to form methane and water, with subsequent moisture removal.
(See Section 2.1 for the cnemistry of shift and methanation.)
Processes for acid gas treatment were discussed in Section 3.0 in connec-
tion with the gas purification operations. Shift conversion and methanation
which constitute the gas upgrading operation are reviewed in this section.
4.1 SHIFT CONVERSION
4.1.1 Shift Conversion Catalysts
Although shift conversion can follow acid gas treatment, in SNG produc-
tion it is desirable to have the shift before the acid gas treatment to avoid
an additional acid gas treatment step for the removal of the C0~ generated'
in the shift reaction.
The reaction of carbon monoxide and water vapor to form hydrogen and
carbon dioxide is a mildly exothermic reaction which can be promoted by a
variety of catalysts. For application to SNG production, the shift reaction
is best conducted at moderate to high temperatures (greater than 500°K). Con-
ventional copper-based low temperature shift catalysts used in petrochemical
applications are generally deactivated by sulfur compounds in feed gases.
"Sulfided" cobalt molybdate based catalysts, which are active at temperatures
close to 500°K (441T), are not affected by the presence of gaseous sulfur
58
-------
compounds (indeed, some HgS is required to maintain the catalyst in the active
state) . These high temperature catalysts have been proposed for SN6
application.
To achieve the required minimum 3:1 hydrogen to carbon monoxide ratio
using catalytic shifting, two approaches are possible: (1) sending the entire
gas flow through the catalytic reactor and (2) sending a portion of the flow
through the catalyst bed and combining the shifted and unshifted gases after-
ward to obtain the proper ratio. Based on equilibrium calculations (and actual
operating experience), a hydrogen to carbon monoxide ratio of up to 10:1 can
be obtained at about 550°K. To take advantage of such a high conversion ratio,
the second approach, which entails cost savings associated with a smaller re-
actor size, is preferred. (The proposed commercial Lurgi SNG plant designs
for the U.S. feature split-flow shift conversion.) Considerable work is cur-
rently under way to develop processes which would enable shift conversion and
methanation to be carried out in a single processing step. These approaches
to joint shift conversion/methanation are discussed in connection with meth-
anation in Section 4.2.
4.1.2 Discharge Streams
The shift conversion operation produces three types of discharge streams:
(1) product gas, (2) condensate and (3) spent catalyst. From an environmental
standpoint, the effect of the shift catalyst on the minor constituents .in
feed gas is of special importance. Most cobalt molybdate-based catalysts are
active for the hydrolysis of carbonyl sulfide and carbon disulfide.
COS + H20 = H2S + C02
CS2 + 2H20 = 2H2S + C02
Quenched product gases from high Btu gasification processes contain COS in
the 15 to 150 ppmv range (Section 2.3), with COS to H2S ratios ranging from
0.02 to 0.15. Under equilibrium conditions and at a temperature close to
550°K (530°F) the COS to H2S ratio in such gases would be about 0.002 (CS2 to
H«S ratio would be very much lower), hence indicating that near complete
conversion of COS to H2S could be achieved with the use of proper catalyst.
Tests with relatively "clean" simulated coal gases and using fresh sulfided
59
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Co-Mo shift catalyst have indeed indicated that essentially complete conversion
of COS (and CSJ to H^S can be realized. This degree of conversion, however,
has not been realized in pilot plant tests with actual coal gases. In a com-
mercial facility, the actual COS level in the shift conversion product would
depend upon how closely the equilibrium is approached in the shift reaction
and the fraction of the feed sent through the reactor. For example, in a
split-flow configuration whereby only about 55% of the quenched product gas
is passed through the shift reactor, reduction in the total COS concentration
would be less than 55%.
Cobalt molybdate-based catalysts are also active for many hydrogenation
reactions and thus olefins and aromatics may be partially converted to sat-
urated organics in a shift reactor. As far as is known, shift catalysts do
not affect other trace constituents such as ammonia and HCN. A catalyst bed
may serve as a physical trap for suspended particulate matter (coal dust,
char ash) and as a chemical trap for certain trace elements (e.g., Hg, As, Cd).
Accumulated material may lead to eventual catalyst deactivation.
A process condensate may be formed when the shifted gas is cooled. This
aqueous stream would contain small quantities of dissolved gases originally
present in the gas phase (H2, CH^, CO, C02, H,,S) and possibly higher molecular
weight organic compounds. However, no actual operating data are available on
the composition and the quantity of the process condensate. Depending on the
facility design, a shift reactor may actually be a net consumer of foul waters
produced elsewhere in a gasification plant. Hot feed gas may be passed
through foul waters to generate the steam required for the shift reaction.
The shift catalyst will eventually become deactivated and require re-
placement. The spent catalyst will likely contain char, ash, high molecular
weight organics, and coal-derived trace elements. Due to the proprietary
nature of catalysts, essentially no Information is publicly available relating
to the properties of the spent catalyst.
4.1.3 Data Gaps and Limitations and Related Programs
The data base for shift conversion in SNG applications is limited pri-
marily because there are currently no commercial facilities. Bench and pilot
scale operations have provided some data, but these are limited 1n scope.
60
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Some specific data gaps relate to:
0 The effect of the shift catalyst oh trace constituents (COS, CS2,
mercaptans, thiophenes, NH3> HCN)
• The composition of process condensate(s)
• The catalyst life and properties of spent catalyst
The fate of minor gas constituents in shift conversion is currently being
investigated by the Institute of Gas Technology (Chicago) in bench-scale
studies of the performance of various shift catalysts.
4.2 METHANATION AND DRYING
4.2.1 Process Principles
Methanation and drying are the final steps in the production of SNG from
coal derived gases (see Section 2.1). Methanation involves the catalytic
reaction of carbon oxides and hydrogen to form methane (and water). The re-
action is usually carried out at a temperature between 590 to 760°K (600 to
900°F) and under high pressures (approximately 7 MPa or 1000 psia). The most
effective catalysts used for methanation contain nickel, usually in the reduced
state. Three types of catalyst bed designs which have been tested are (1)
fixed bed of pellets containing catalyst or a catalyst coating on tube walls,
(2) catalyst bed fluidized by feed gas, (3) catalyst solids suspended in a
high temperature boiling liquid through which the feed gas is passed.
Fixed bed methanation technology is widely employed in applications
other than SNG production and has also been demonstrated in one commercial
SNG plant (Westfield, Scotland) and in two high Btu gasification pilot plants
(Hygas and CO^-Acceptor). Fluidized bed and liquid phase methanation are cur-
rently in the development and testing stage for application to SNG production.
Appendix C contains data sheets on these approaches to catalytic methanation.
As noted in Section 4.1.1, a number of processes which combine shift con-
version and methanation in a single step are currently under development.
Two of these processes which have reached the pilot plant stage are the
Thyssengas GmbH (West Germany) process and the Ralph M. Parson RM process.
The Thyssengas process uses a fluidized bed of nickel-based catalyst and has
been tested on feed gases having H to CO ratios of 2:1 to 3:1. Near-
61
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equilibrium production of methane and carbon dioxide has been demonstrated.
The catalyst bed is generally operated at a temperature in the 620°K to 700°K
(660°F tp 930°F) range which is about the same as those used in conventional
methanation.
The RM process uses a series of fixed beds, each operated at a progres-
sively lower outlet temperature (1000°K to 713°K or 1350°F to 760°F). The
processes which use a proprietary nickel based catalyst have been shown to
be capable of a high degree of conversion of H- and CO to CH^ and COg. Com-
pared to separate shift conversion and methanation, the combination shift-
methanation processes have the advantages of eliminating the separate shift
conversion step and reducing the volume of gas from which CC^ is to be removed.
Since it is operated at higher temperatures, the following additional advan-
tages have been claimed for the RM process: (1) elimination of recycle flows
for the control of temperature across methanation catalyst; (2) production of
more steam and at higher pressures; (3) reduction in carbon formation in the
bed; and (4) less sensitivity of catalyst to sulfur and easier catalyst
regeneration.
Drying of the methanated gas is usually accomplished in two stages:
condensation for bulk moisture removal and sorption for the removal of resi-
dual moisture^ ~10'. The bulk moisture removal is achieved by cooling and
heat recovery. Molecular sieves or solvents (e.g., ethylene glycol) are used
for the removal of trace moisture which remains after cooling; the exhausted
molecular sieves and the spent solvents are regenerated. The gas drying
operations (condensation and trace moisture removal) are not unique to SN6
production and are widely used in a number of other industries (e.g., nat'ural
gas purification).
4.2.2 Discharge Streams
In all methanation processes, four types of discharge streams are en-
countered: (1) product gas, (2) condensed moisture, (3) emissions from
catalyst decommissioning, and (4) spent catalyst. Product gas will be essen-
tially free of particulate matter and sulfur and nitrogen compounds but will
contain traces of carbon monoxide and hydrogen and possibly of nickel carbonyl
and parti oil ate nickel. Condensates formed by cooling of methanator product
62
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gas are generally free of dissolved and suspended solids and gases such as
H«S and NHL, and are therefore suitable for boiler feed water or other uses
where high quality water is required.
From an environmental standpoint, the major hazards associated with
catalytic methanation arise during transient operations. At temperatures less
than 480*K (400°F), carbon monoxide can react with reduced nickel catalyst to
form nickel carbonyl. Methanation is ordinarily conducted at temperatures
above 590°K (600°F); however, temperatures of less than 480°K (400°F) are en-
countered during start-up and shut-down. Inert gas (e.g., N2, C(L) must be
used during heating and cooling to exclude carbon monoxide from the bed.
Since reduced nickel catalyst is pyrophoric, a spent bed is commonly decom-
missioned by slowly adding air or oxygen to the cooled catalyst to initiate
oxidation. The controlled oxidation of spent catalyst may result in an off-
gas containing particulate matter, sulfur compounds, organometallic compounds,
and carbon monoxide. "Burned" catalyst, although chemically more stable,
still presents a hazard due to the potential toxicity of nickel. One likely
use of oxidized spent catalyst is as methanation guards for sulfur removal
(see Section 3.2.3). The disposal of spent catalyst is discussed in Section
7.1.2,
4.2.3 Data Gaps and Limitations and Related Programs
The operating experience with methanators in SNG applications is very
limited. Essentially no data are available on emissions from decommissioning
spent catalyst and on the properties of the spent catalysts. It is antici-
pated that additional engineering performance data will become available as
a result of ongoing tests at the Hygas pilot plant (fixed and liquid phase
methanation) and at the Bigas plant (fluidized bed methanation). The contin-
uation of developmental work on combined shift conversion-methanation is ex-
pected to generate additional engineering and environmental data on this
promising approach. The proprietary nature of methanation catalysts is a
major roadblock to a more thorough investigation of emissions and hazards
associated with the technology.
63
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5.0 AIR POLLUTION CONTROL
This section reviews the sources and characteristics of gaseous waste
streams associated with (a) the gasification, gas purification and gas upgrad-
ing operations described in Sections 2, 3 and 4; (b) water pollution control
and solid waste management discussed in Sections 6 and 7; and (c) other aux-
iliary processes which are unique to the operation of integrated commercial
high Btu gasification facilities. Processes which have been used for or may
have application to the control of gaseous emissions in gasification facilities
are reviewed and alternative control strategies for integrated facilities are
discussed. Finally, the limitations of the existing data which prevent ade-
quate definition of the applicability of available control technologies to
gasification sources and the related programs which may supply some of the
needed data are discussed. Detailed information on the individual air pollu-
tion control processes reviewed are presented in the "data sheets" contained
in Appendix D.
5.1 SOURCES AND CHARACTERISTICS OF GASEOUS EMISSIONS
Figure 5-1 identifies the general sources of air pollution in a high Btu
gasification plant. As indicated in this figure, six types of gaseous waste
streams might be identified in a commercial gasification facility. These are:
(1) pretreatment off-gases, (2) lockhopper vent gases, (3) concentrated acid
gases, (4) catalyst regeneration/decommissioning off-gases, (5) char combus-
tion, incineration and transient waste gases, and (6) depressurization, strip-
ping and vent gases. As noted below, not all of these waste stream types are
associated with all high Btu gasification processes and very limited data are
available on the composition of these gas streams. Table 5-1 presents some
composition data which have been reported for six stream types from the
COg-Acceptor, Hygas and Lurgi processes based on actual operation. A discus-
sion of these data and the limited available information (mostly qualitative
in nature) on other gaseous waste streams follows.
64
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Ol
en
PREPARED
COAL
COAL
PRETREATMENT
— te
GASI-
FICATION
QUENCH
& DUST
REMOVAL
SHIFT
CONVERSION
CONCEN-
TRATED
ACID
GASES
CATALYST
/REGENERATION
(DECOMMISSIONING]
OFF-GASES
(INTERMITTENT
SOURCE)
ACID
GAS
REMOVAL
METHANATION
& DRYING
SNG
CHAR
COMBUSTION
INCINERATION,
AND TRANSIENT ]
WASTE GASES
DEPRESSURI-
ZATION,
STRIPPING
AND-VENT
GASES
CHAR
COMBUSTION
INCINERATION/
AND TRANSIENT
GASES
MATER
POLLUTION
CONTROL &
BYPRODUCT
RECOVERY
Figure 5-1. Process Modules Generating Gaseous Wastes 1n a Typical High Btu Gasification Plant
-------
5.1.1 Pretreatment Off-Gases
Except for Bigas and Hydrane processes, high Btu gasification processes
cannot directly handle strongly caking coals. For these processes, caking
coals must be pretreated, usually with steam and air to destroy caking ten-
dencies. When caking coals are to be gasified and the coal pretreatment is
carried out in a vessel external to the gasifier (e.g., in the Hygas pilot
plant in Chicago), a flue gas is generated which contains coal pyrolysis and
partial oxidation products as well as particulate matter. It should be noted,
however, that all the proposed commercial facilities are designed to handle
subbituminous or lignitic coals which are essentially noncaking. To date, the
only available data on pretreatment off-gas are for the Hygas pilot plant.
Even for this plant, the available data are limited to the concentration of
major constituents (see Table 5-1) and to sulfur mass balance around the pre-
treatment unit. The mass balance data indicate that up to 25% of the sulfur
in feed coal may be volatilized as a result of pretreatment. The volatilized
sulfur is discharged in the pretreatment off-gas. In a commercial facility
the fuel value of such off-gas would likely be recovered by combustion and
the resulting flue gas treated for S0« and particulate removal.
5.1.2 Lockhopper Vent Gases
This waste stream is associated with those processes which use lock-
hoppers for coal feeding and ash discharge. Essentially no actual operating
data are available on the composition of this waste stream.
As noted in Section 2.4.1, the feed lockhopper may be pressurized with
either the product gas or with the C02 stream from acid gas treatment. In the
former case, the lockhopper vent gas would contain components of the product
gas plus coal devolatilization products and particulates. In the latter case,
the vent gas would contain coal devolatilization products, some gasifier gas
components and components originally present in the CCL gas stream (e.g., COS,
H2S). In both cases, the vent gas requires treatment for particulate, sulfur
and hydrocarbon control.
The ash lockhopper, commonly pressurized with steam, generates an off-gas
which would contain particulates and components of the gasifier gas. This off-
gas would require treatment for particulates and odor control before discharge.
66
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TABLE 5-1. COMPOSITION OF GASEOUS WASTE STREAMS
Constituents
H2S
COS
cs2
NH3
so2
co2
CO
H2
N2+Ar
CH4
C2H6
C3H8
C4H10
V
Pretreatment
Off-Gas*
-
-
-
-
-
3.8-5.0
1.5-4.0
0.06-0.4
2-2.5
0.16-0.55
-
-"
-
-
Concentrated Acid Gases
SelectlveT
HpS Stream
31Xv
O.SXv
—
—
--
68Xv
--
--
—
—
—
--
—
—
CO- Stream
5 ppmv
8 ppmv
—
--
—
SOXv
0.14Xv
0. 33Xv
19Xv
--
—
—
—
--
Non-Select1veJ
0.9Xv
30 ppmv
2 ppmv
—
--
97Xv
—
0.14Xv
0.03Xv
0.9Xv
--
--
--
—
Char Combustion
Gas§
28-320 ppmv
46-150 ppmv
--
--
92-121 ppmv
28-29XV
2.0-2.2%v
68Xv
—
--
--
—
--
-~
Depressurlzatlon
Off -Gas**
Tar Sep.
3.8-6.2XV
--
—
1.0-6.3XV
--
63-85XV
1.5-5.9XV
2.9-11.7XV
1.0-S.OXv
1.8-5.3XV
--
—
--
™ ™
Oil Sep.
5.5-8.6XV
—
--
1.8-12XV
--
59-86XV
0.8-4.7Xv
2.3-9.6Xv
1.0-6.4XV
1.2-4.2Xv
--
--
--
"~
Stripper
Off-Gastr
O.lXv
—
--
—
—
SS.lXv
0.7Xv
10.9XV
20Xv
8Xv
0.64Xv
0.23Xv
0.17Xv
™"
011 Storaqe
Vent Gas44
0.6Xv
—
--
--
--
67.3Xv
1.4Xv
9.0Xv
5.3Xv
10.9Xv
l.lXv
0.44Xv
0.43Xv
0.3*v
*Pretreatment of 111. #6 coal at Hygas pilot plant; see data sheet In Appendix A.
^Selective Rectlsol unit used In conjunction with an oil gasification plant using the Texaco partial oxidation process; see
Appendix B.
$Non-select1ve Rectlsol unit used 1n Lurgl coal gasification facility 1n Sasol, South Africa; see Appendix B.
'Scrubbed flue gas from char combustion In the COg-Acceptor process; see data sheet 1n Appendix A.
**011-water separator flash gas for dry ash Lurgl process; see data sheet In Appendix A.
ItVent gas from the oil stripper at the Hygas pilot plant; see data sheet 1n Appendix A.
#Hygas product oil at the pilot plant, see data sheet 1n Appendix A.
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5.1.3 Concentrated Acid Gases
As discussed in Section 3.1, concentrated acid gas streams result from
the processing of the raw or shifted product gas to remove H2S and/or COg.
The composition of acid gas(es) in a high Btu gasification plant will depend
upon raw product gas composition and the type of acid gas treatment process
employed. Although a large number of processes are available for the removal
of acid gas, and many of them are in commercial use in industries such as
natural gas, petroleum refining and by-product coke, only a few processes
have been used for the treatment of raw product gas from coal gasification.
Examples of processes which have been used on coal gasification raw product
gas are Rectisol, Benfield and Sulfinol, For these applications, the recov-
ered concentrated acid gases have been flared, and the acid gas treatment
systems have not been tailored for sulfur recovery/removal which would be
required in an operating commercial facility in the U.S. While a limited
amount of data is available on the Rectisol process, no composition data
have been reported on the concentrated acid gas streams from Benfield and
Sulfinol processes in a coal gasification application.
Table 5-1 presents representative data on the concentrated acid gas
streams from the Rectisol process operated in selective (separate H«S and
C02 removal) and nonselective (combined H^S and CO* removal) modes. The
data for the nonselective system are for an actual application to coal gasi-
fication raw product gas processing. The indicated levels of H2S and C02
(0.5% and 97%v, respectively) are probably representative of the levels which
would be expected in the concentrated acid gas stream from application of
nonselective acid gas treatment systems to the processing of raw product, gas
from the gasification of low to medium sulfur coals. The data for the selec-
tive Rectisol process shown in Table 5-1 are for an oil gasification applica-
tion and probably give an approximate indication of the degree of separation
of HgS and C02 which can be achieved in a selective acid gas removal system.
The levels of constituents other than H2S and C02 in the concentrated acid
gas stream(s), however, would most likely vary greatly depending upon the
specific acid gas treatment process used. For example, the data in Table 5-1
indicate a relatively large COS concentration in the concentrated hLS stream
for the selective Rectisol process. In the Benfield process the COS is
68
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largely destroyed (hydrolyzed) in the sorbent solution, and in the Selexol
process the COS which is removed is discharged in the CC^-rich stream. De-
pending on the process used, concentrated acid gas streams may contain hydro-
carbons, traces of sorbents, carbon disulfide, mercaptans, hydrogen cyanide
and ammonia". Little quantitative data are available for these constituents.
5.1.4 Catalyst Regeneration/Decommissioning Off-Gas
As discussed in Section 4.2.2, off-gases would arise from the decommis-
sioning of spent methanation catalyst prior to direct reuse (as methanation
guard), regeneration or disposal. The decommissioning involves controlled
oxidation with air; the resulting off-gas contains sulfur compounds, particu-
late matter, carbon monoxide and (perhaps) traces of organometallic compounds.
Because of the proprietary nature of the methanation catalyst and its handling
procedure, no data have been published on the characteristics of such off-gases.
Also, little information is available on the regeneration procedures (if
any) for the catalyst, on any emission which might be associated with such
regeneration, and on whether in a commercial facility the regeneration will be
performed on-site or off-site. The emissions associated with catalyst decom-
missioning and regeneration (or reclamation) are expected to be small in
volume and of infrequent nature.
5.1.5 Char Combustion, Incineration and Transient Waste Gases
Several potential sources of combustion emissions may be associated with
coal gasification facilities. Those processes which feature external char
combustion (e.g., CO^-Acceptor, Synthane and Cogas) generate a flue gas from
this source. Typical data which have been reported for the (XL-Acceptor char
combustion flue gas after alkaline scrubbing are presented in Table 5-1. The
data indicate that the treated flue gas contains significant quantities of
CO (about 2%) and relatively high concentrations of reduced sulfur compounds.
No data are available on the composition of the untreated flue gas from this
process or on the composition of flue gases from the combustion of chars from
other gasification processes. These flue gases are expected to contain SO ,
A
particulates, NO and trace elements (both in particulate and gaseous forms).
rt
69
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Many of the carbonaceous wastes generated in a coal gasification facility
may be disposed of by incineration. Examples of such wastes are tars and oils
from quench systems, sludges from wastewater treatment operation and waste
gases from thermal regeneration of activated carbons (used for hydrocarbon
removal from process and waste gases and in water pollution control). At the
present time, there are no known applications of incineration for the disposal
of carbonaceous wastes (other than tars and oils) generated in a gasification
facility. The composition of incineration flue gas would vary with the waste
and the incineration design.
Raw product gas and gases from other operations (e.g., acid gas treatment
and gas stripping) which are produced during the start-up and shut-down opera-
tions and as a result of "upset" conditions are waste gases requiring treat-
ment and disposal. The compositions and volumes of these gases would be highly
variable depending on the source and the transient conditions. These gases
would generally be expected to contain at least some of the components which
are present in the gases produced during steady state operation.
5.1.6 Depressurization, Stripping, and Vent Gases
When aqueous or organic condensates have been produced under pressure
(e.g., as a result of raw product gas quenching) and are subsequently depres-
surized (e.g., for the separation and recovery of tars and oils and for waste-
water treatment), an off-gas is generated which contains some of the volatile
components and gases originally dissolved or contained in the liquid phase(s).
The major components of such off-gases are carbon dioxide, carbon monoxide,
hydrogen sulfide, ammonia, hydrogen and low molecular weight organics (e.g.,
methane). Table 5-1 contains data on the composition of depressurization
gases associated with tar and oil separation from dry ash Lurgi quench conden-
sates. The data indicate that these particular off-gases contain significant
quantities of H2$ and NH3- No information is available on the minor constitu-
ents (e.g., COS and HCN) which may be present in these off-gases. Also, no
data are available on the composition of depressurization gases from processes
other than Lurgi,
In the treatment of aqueous or oily condensates for the recovery of hydro-
gen sulfide, ammonia and/or organics by distillation or gas stripping, an
70
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off-gas is generated which contains these and other volatile and gaseous
compounds (e.g., HCN, CO, C02, CH* and COS). Aqueous condensates ("sour"
waters) are commonly stripped with steam to remove both H2S and NHg. Depending
upon the concentrations in the feed and the stripper design, relatively con-
centrated separate H2S and NH- streams can be obtained. Steam stripping can
generally result in the removal of greater than 99% of the H2S and 95% of the
ammonia in the sour water feed. No data are available on the actual composi-
tion of the stripper off-gas in applications to sour waters from coal gasifica-
tion. Data on the composition of the off-gas from the nitrogen stripping of
condensed oils at the Hygas pilot plant are presented in Table 5-1. At this
pilot plant the stripping is aimed at the recovery of the light oil fraction,
some of which is used to prepare coal slurries for feeding to the gasifier.
As indicated in the table, the stripping off-gas from this particular applica-
tion contains C02, small amounts of CO, H2S, an<^ l°w molecular weight
hydrocarbons.
For those processes which generate tars and/or oils during gasification
and which recover such materials for sale or recycle, evaporative emissions
may be associated with storage of such materials. Such evaporative emissions
are usually in the form of vent gases from storage facilities. The vent gases
generally contain the same constituents asrare present in the stored material.
The concentrations of these constituents in the gas phase are determined by the
corresponding concentrations in the liquid phase, their volatility and the
temperature. Table 5-1 presents data on the composition of the oil storage
vent gas for the Hygas process. As noted in the table, this particular vent
gas contains significant concentrations of C02, CH. (and other low molecular
weight hydrocarbons), CO, and H2S.
5.2 AIR POLLUTION CONTROL PROCESSES
Since no commercial high Btu gasification facility currently exists and
many of the gasification and gas purification and upgrading processes are in
early developmental stages, with very few exceptions the processes which may
be applicable to the control of gaseous emissions from coal conversion facili-
ties have not been tested in such applications. Even though many of the con-
trol processes have been used in similar applications in other industries
(primarily in the petroleum refining, coke and natural gas industries),
71
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essentially little or no engineering and operating data are available on such
processes for applications to coal gasification. In this section, the air
pollution control processes which have been tested in coal gasification appli-
cations or which may be potentially suitable for such applications are reviewed.
The air pollution control options and strategies for integrated facilities are
reviewed in Section 5.3.
Figure 5-2 presents the process modules for the control of gaseous waste
streams discussed in Section 5-1. The process modules shown in the figure are
for sulfur recovery; tail gas treatment for additional H2S or sulfur recovery;
SOg control and/or recovery; incineration; particulate control; CO, hydrocarbon
and odor control; gas compression and recycling; and NO control. Each module
A
consists of a number of interchangeable processes or processes which would be
applicable to a range of conditions. The processes which are discussed in con-
nection with each module are listed in Table 5-2.
TABLE 5-2. AIR POLLUTION CONTROL PROCESSES REVIEWED FOR
APPLICATION TO HIGH BTU GASIFICATION
Sulfur Recovery
Tail Gas Treatment
S02 Control and/or Recovery
Incineration
CO, Hydrocarbon and Odor
Control
Particulate Control
Compression and Recycling
NO^ Control
Claus, Stretford, Giammarco-Vetrocoke
SCOT, Beavon, IFP-1, IFP-2, Sulfreen,
Cleanair
Wellman-Lord, Chiyoda Thoroughbred 101,
Shell copper oxide, lime/limestone
slurry scrubbing, double alkali, and
magnesium oxide scrubbing
Thermal oxidation, catalytic oxidation,
Thermal oxidation, catalytic oxidation,
activated carbon absorption
Fabric filter, electrostatic precipita-
tion, venturi scrubbing, cyclones
Compression and recycling
Combustion modification and dry and wet
processes
72
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CHAR
COMBUSTION.
MCINERATION.
AND TRANSIENT
GASES
SO, CONTROL
AND/OR
RECOVERY
CATALYST
REGENERATION/
KCOMMWONINO
OFFGAS
INCINERATION
(OXIDATION OF
CO, MC. SULFUR
CtNVOUNMI
GAS COMPRESSION
AND RECYCLING
TAIL GAS
TREATMENT
FOR ADDI-
TIONAL MjS
OR SULFUR
RECOVERY
Figure 5-2. Process Module for Air Pollution Control
(see Figure 5-1 for sources of gaseous wastes)
73
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5.2.1 Sulfur Recovery
Two gaseous streams which contain sufficiently high concentrations of
H2S and other sulfur compounds to justify sulfur recovery are concentrated
acid gases from acid gas treatment units and gases from depressurization and
stripping operations. The characteristics of these two streams are determined
by the sulfur content of the coal feed, the gasification process used, and
the acid gas removal process employed (in the case of the concentrated acid
gas stream). Sulfur recovery generally involves the conversion of sulfur
compounds to elemental sulfur. Of a number of processes which are available
for sulfur recovery, three are considered to be most promising for applica-
tion to coal gasification. These three are Claus, Stretford and Giammarco-
Vetrocoke (6-V), and have been widely used in natural gas, petroleum refinery
and/or by-product coke industry. Table 5-3 summarizes the key features of
these three processes, based on the detailed information presented in Appen-
dices B and D.
As indicated in Table 5-3, the Claus process is generally applicable to
feed streams containing a minimum of 10% - 15% FLS, whereas the Stretford and
G-V processes are applicable to feeds containing around 1% H2S. (Some Claus
plants have been designed and are operating on feeds containing as low as
5% H2S. The Stretford process has also been used with feeds containing more
than 10% H2S. At these high concentration levels, however, the Stretford
process is not economically competitive with the Claus process.) The treated
gas from the Claus process generally contains several thousand ppm of sulfur
compounds (primarily H2S), whereas the treated gas from the Stretford and G-V
contains only a few ppm of H2S. The Claus process is a dry high temperature
process in which HgS is catalytically reacted with S02 (produced by air oxi-
dation of the HgS) to form elemental sulfur. The Stretford and G-V processes
are liquid-phase oxidation systems using aqueous solutions of alkaline meta-
vanadate/anthraquinone disulfonic acid and arsenite, respectively. While
other reduced forms of sulfur (e.g., CS2 and COS) are partially removed by
the Claus and G-V processes, they are not removed by the Stretford process.
Since the Claus process operates at a relatively high temperature it is also
capable of oxidizing some of the hydrocarbons.
74
-------
TABLE 5-3. GENERAL CHARACTERISTICS OF SULFUR RECOVERY PROCESSES
Process
Claus
Stretford
Glamwrco-
Vetrocoke
(6-V)
Process
Principle
Catalytic
oxidation
of HzS to
elemental
sulfur
Liquid phase
oxidation of
H2S to ele-
mental sul-
fur In an
alkaline
solution of
metavanadate
and anthra-
qulnone d1-
sulfonlc acid
(ADA) salts.
Liquid phase
oxidation of
HjS to ele-
mental sul-
fur In po-
tassium car-
bonate and
arsenate/
arsenic
alkaline
solution. A
concentrated
CO? stream
with very
low H2S con-
centration
Is produced.
Limits of
Applicability
Straight-through
system utilized
for higher H2$
concentrations.
Split-stream
system utilized
for HjS concentra-
tions of 10X-15X.
Sulfur-burning
node used for HjS
levels down to 51.
Present applica-
tions are gen-
erally for IX
sulfur or less.
Maximum of 1.5X
H2S (n feed
stream.
Control Efficiencies (X)
H2S
90 - 95
99.9 or
greater
99.99
COS/CS2
90
0
Partially
removed
R-SH
95
0
Partially
renoved
HCN
Partially
oxidized
-100
(converted
to SOT 1n
Stretford
solution)
7
NH3
Partially
oxidized
0
0
HC
90
0
0
By- Product
Elemental
liquid
sulfur
Elemental
sulfur
Elemental
sulfur
which may
require
arsenic
removal
Effect of COz
Can adversely
affect sulfur
removal ability
and therefore
Increase plant
size. If COj
exceeds 301 and
Nl<3 exceeds 500
ppmv. catalyst
plugging pro-
blems may occur.
High CO? concen-
trations will
decrease absorp-
tion efficiency
by lowering solu-
tion alkalinity.
Increasing absorb-
er tower height
and base addition
are required.
Little or no effect.
Process can be de-
signed to selective-
ly remove HjS with
low C02 absorption.
t
Commercial
Applications
Widely employed In
petroleum refinery.
natural gas, and
by-product coke
Industry. One known
application to coal
gasification 1n
South Africa.
Primarily natural
gas service, a few
applications to pe-
troleum refining and
by-product coke In-
dustries. A unit
has been constructed
at the Lurgl gasifi-
cation facility at
Sasol, So. Africa.
Primarily natural
gas service; a few
applications for
hydrogen purifica-
tion 1n petroleum
refining and
ammonia production.
in
-------
Unlike natural gas and refinery acid gases which do not usually contain
high levels of COp, concentrated acid gases and depressurization and stripping
gases from coal gasification will contain high levels of C02- In the Claus
process, high C02 concentration levels in the feed gas (greater than 30%v)
would not create a major problem unless the gas also contained more than
500 ppmv of ammonia. In the Stretford process, high levels of C02 in the feed
gas would reduce the alkalinity of the sorbent and, hence, reduce the system
efficiency. Thus, where high C02 levels are encountered, larger absorption
towers would be required to obtain high H2$ removal efficiency. In the G-V
process, C02 is partially removed by the sorbent, but the absorption of C02
does not significantly impair the H2$ removal efficiency.
5.2.2 Tail Gas Treatment
Depending on the influent gas characteristics and the specific sulfur
recovery process employed, the treated gas from a sulfur recovery system may
require additional treatment before discharge to the atmosphere. Such addi-
tional ("tail gas") treatment may be necessary to achieve a higher level of
hLS removal (e.g., when the Claus process is used for sulfur recovery) and/or
for the removal of hydrocarbon and other forms of sulfur (e.g., COS, CS,,
etc.). As with most of the sulfur recovery processes, the tail gas removal
systems have not been used in connection with coal gasification, but many of
them have been used in other industries (primarily in the petroleum refining
industry).
Table 5-4 summarizes the key features of the sulfur recovery tail gas
treatment processes. The processes listed in this table fall into three gen-
eral categories: (1) processes such as IFP-1 and Sulfreen which are essen-
tially extensions of the Claus process, (2) processes such as Beavon, Cleanair
and SCOT which catalytically reduce the more oxidized sulfur compounds (e.g.,
S02, CSg and COS) to hydrogen sulfide which is recycled to the sulfur recovery
systems, and (3) processes such as Chiyoda Thoroughbred 101, Wellman-Lord,
IFP-2 and Shell CuO which involve the removal of S02 by scrubbing and require
that the input gas be incinerated to convert all sulfur compounds to S02>
The processes In the first category have been employed exclusively for
Claus plant tail gas treatment and are capable of reducing the sulfur level
76
-------
TABLE 5-4. KEY FEATURES OF SULFUR RECOVERY TAIL GAS TREATMENT PRQCESSE1.
Tall Gas
Removal
Process
Chlyoda
Thoroughbred
101
Beavon
Cleanalr
IFP-1
IFP-2
Process Principle
Thermal oxidation
of sulfur com-
pounds to SO?,
followed by liquid
absorption
Catalytic reduction
of sulfur compounds
to HgS, followed
by Stretford
process
Catalytic reduction
of sulfur com-
pounds to H2$.
followed by a con-
tinuation of the
Claus reaction and
Stretford process
Liquid phase con-
tinuation of Claus
reaction at a low
temperature
Incineration of
tall gas. followed
by aranonla scrub-
bing. Solution Is
evaporated to pro-
duce a concentra-
ted SO? strean
which is returned
to the Claus plant.
Feed Stream
Requirements/
Restrictions
Incinerated Claus tall
gas; no specific
requirement on H,S:SO,
ratio z z
Sulfur recovery pro-
cess tall gas 1s
heated upstream of
catalytic reactor; no
specific H2$:S02
ratio required
1^5:502 ratio can
vary up to 8:1 with-
out affecting effi-
ciency; designed
specifically for
Claus tall gas
H2$:S02 ratio main-
tained 1n the range
of 2.0 to 2.4
H2S:S02 ratio main-
tained 1n the range
of 2.0 to 2.4
Sorbents/
Solvents
21 (by wt.)
sulfurlc acid
solution
Stretford
Process
solution
Unknown aque-
ous solution
and Stretford
process
solution
Polyalkallne
glycol
Aqueous
ammonia solu-
tion
Product
Gypsum
(CaS04-2H,0)
5 to 20J f
moisture
content
Elemental
sulfur
Elemental
sulfur
Elemental
liquid
sulfur
Elemental
liquid
sulfur
Utility
Requirements
Very high
Low
Very low
Very low
High
COS and C$2
Removal
Largely oxidized
by Incineration,
not absorbed by
solution
Catalytlcally
converted to
H2S
Catalytlcally
converted to
H2S
Not removed 1n
catalytic reactor
Oxidized by In-
cineration, not
removed 1n cata-
lytic reactor
Efficiency
95% 502 or less
than 300 ppmv
99.81 removal
for Claus tall
gas containing
41 equivalent
H2S
Plant effluent
normally guar-
anteed to con-
tain less than
250 to 300 ppm
S02 equivalent
Capable of re-
ducing sulfur
species in Claus
tall gas to 2000
ppm as 502
Capable of re-
ducing sulfur
species in Claus
tail gas to less
than 500 ppm
Effect of COZ
1n Feed Gas
No effect
Reduces conversion
efficiency by
catalyst; decreases
H2S absorption by
Stretford solution
Reduces conversion
efficiency of
catalyst; decreases
12S absorption by
Stretford solution
No effect
No effect
(continued)
-------
TABLE 5-4. CONTINUED
Tall Gas
Removal
Process
Sul f reen
Shell
Copper
Oxide
Wei Iman-
Lord
SCOT
Process Principle
Solid phase con-
tinuation of Claus
reaction at a low
temperature
Thermal oxidation
of sulfur com-
pounds to SOz.
followed by adsorp-
tion by CuOi a con-
centrated S02
stream 1s produced
by desorptlon with
a reducing gas (Hz)
Thermal oxidation
of sulfur com-
pounds to 502,
followed by liquid
absorption; concen-
trated SOz Is pro-
duced and recycled
to Claus plant
Sulfur species are
catalytlcally re-
duced to HpS; H2S
Is scrubbed 1n a
regenerabl e anlne
systen
Feed Stream
Requirements/
Restrictions
Optimum performance
requires HjS:S02
ratio of 2:1
Incinerated Claus
tall gas ; no specific
requirement on H?S:
SOo ratio
Incinerated Claus
tall gas; process can
handle SO? concentra-
tions well over
10.000 ppm
Applicable to Claus
tall gas
Sorbents/
Solvents
Hone; sulfur
vapor conden-
sation process
utilized
Copper oxide
Concentrated
sodium
sulflte, bi-
sulfite
solution
Alkanolamlne
solution
Product
Elemental
liquid
sulfur
Concentrated
S02 stream
Concentrated
S02 stream
(up to 90S
SOz content)
Concentrated
H;>S stream
Utility
Requirements
Very low
No data
available
High
Moderate
COS and CS?
Removal
Not appreciably
removed
Oxidized by
Incineration
Oxidized by
Incineration,
not removed
by process
Catalytlcally
reduced to
H2S
Efficiency
Capable of re-
moving 80 to
85X of sulfur
In the tall gas
901 S02 removal
Can remove In
excess of 951
Of SOo
Can remove 971
of sulfur
species
Effect of CO-
ln Feed Gas
No effect
t
No effect
Reduces conversion
efficiency by
catalyst; high COj
levels reduce
efficiency of
alkanolamlne
system
-------
to less than 500 ppmv. As with the Claus process, these processes can toler-
ate high concentrations of C02 in the feed gas. In the Beavon and SCOT pro-
cesses, hydrogen or synthesis gas is used for the reduction of oxidized sul-
fur; the reduction is carried out over a cobalt-molybdate catalyst. In exist-
ing commercial applications, the tail gas from the Beavon and SCOT processes
is treated for hLS removal/sulfur recovery by the Stretford and alkanolamine
processes, respectively. Total sulfur levels of less than 100 ppmv have been
achieved by the application of Beavon-Stretford and SCOT-alkanolamine systems.
In contrast to the first category of processes (processes which extend the
Claus reaction), Beavon-Stretford and the SCOT-alkanolamine systems are
adversely affected by high levels of C0? in the feed gas. The C0? in the feed
gas reduces the efficiency of the catalytic reduction of COS and CS2 and
impairs the effectiveness of the Stretford and alkanolamine absorption systems.
The third category of processes which involve incineration followed by S02
recovery have been applied to Claus plant tail gas and to utility boiler flue
gases. These processes are capable of removing over 90% of the total sulfur
in the feed gas. The Chiyoda Thoroughbred 101 and the Shell-CuO processes
which employ sulfuric acid and CuO as sorbents, respectively, are not affected
by high levels of C02 in the feed gas. In the Wellman-Lord process the sorbent
is an alkaline solution of sodium sulfite/bisulfite. whose capacity for S02
absorption may be affected by very high levels of C02 in the feed gas. (The
use of the Wellman-Lord process for S02 removal has been successfully demon-
strated on flue gases from coal-fired utility boilers which contain over 10%v
co2).
5.2.3 S02 Control and/or Recovery
As indicated in Figure 5-2, S02~bearing gaseous streams which may require
control are flue gases primarily originating from the incineration of gas
streams containing reduced sulfur and from combustion related sources (e.g.,
char combustion, coal pretreatment, etc.). Of a wide variety of processes
which have been proposed for removal of S02 from combustion gases, only a few
have reached a commercial stage of development. Processes which may be con-
sidered commercially available at the present time are Wellman-Lord, Chiyoda
Thoroughbred 101 and Shell copper oxide which were discussed in Section 5.2.2
79
-------
and the lime/limestone slurry and the dual-alkali scrubbing processes which
are discussed below. Data sheets for these processes are presented in Appen-
dix D. A number of other scrubbing processes were reviewed in this program
but eliminated from further consideration primarily due to the fact that they
are not commercially developed, are not sufficiently reliable, and/or have
relatively low S02 removal efficiencies. The nahcolite and the citrate pro-
cesses, for example, have not been demonstrated on a commercial scale. The
magnesium oxide scrubbing process which has been tested on a medium size
utility boiler suffers from low on-line "availability." The fly ash slurry
scrubbing which is proposed for low sulfur western coals has achieved sulfur
removal efficiencies which only sometimes meet the New Source Performance
Standards.
Table 5-5 presents the key features of the lime/limestone slurry and
dual alkali scrubbing processes. Both processes have been developed and used
for the removal of S02 from utility and industrial boiler flue gases. In the
lime/limestone process, the flue gas is scrubbed with a lime or limestone
slurry (6% - 12%) to remove the S02- Where used, initial scrubbing may be
carried out in a venturi scrubber which is designed to remove most of the
residual particulate matter. The bulk of the S02 removal is accomplished
downstream in an absorption tower. The resulting spent calcium sulfite/
sulfate sludge may be discharged to a thickener/settling pond with the clari-
fied liquid returned to the process. Being a "throw-away" process, the pro-
cess generates a relatively large volume of sludge which requires processing
C
-------
TABLE 5-5. KEY FEATURES OF LIME/LIMESTONE SLURRY AND DUAL ALKALI SCRUBBING PROCESSES
Process Feature
Lime/Limestone Slurry Scrubbing
Dual Alkali Scrubbing
Principle
00
Feed Stream
Requirements
Absorbent
Product
Efficiency
Advantages
Disadvantages
Liquid phase absorption of S02 in a lime
or limestone slurry.
Particulates must be primarily removed in
a venturi scrubber.
6 to 12% lime or limestone slurry.
Calcium sulfite and calcium sulfate.
Generally 70 to 90% for utility firing
of high sulfur coal. 95-99% can be
obtained. Removal efficiency will vary
according to scrubber type and gas pres-
sure drop. Over 99% removal efficiency
can be achieved.
Low capital and O&M costs. S02 and parti-
culates are removed. Fairly simple pro-
cess. Conventional process equipment.
On line reliability may be low (70 to 85%);
in a typical power plant, produces -2 times
(dry weight basis) as much waste sludge as
collected ash\38). For low sulfur coals,
SO? removal efficiency should be as low as
50%.
Liquid phase absorption of SO? in a sodium
hydroxide, sodium sulfite, sodium sulfate and
sodium carbonate solution. A dilute mode
process is used for S02 concentrations of 250
to 1500 ppm and a concentrated mode is used
for S02 concentrations of 1800 to 8000 ppm
and where less than 25% oxidation of col-
lected S02 is encountered
02 must be less than 7% for concentrated
mode. Excessive particulates must be re-
moved in a venturi scrubber.
Sodium hydroxide, sodium sulfite, sodium
sulfate and small amount of sodium carbonate.
Primarily calcium sulfite and calcium
sulfate.
Capable of over 99% removal for typical coal
fired utility flue gas and a concentrated mode
process. A General Motors demonstration
(dilute mode) and an FMC pilot plant (con-
centrated mode) operate at approximately
90% S02 removal.
Low capital and O&M costs. S02 and parti -
culates are removed. Conventional process
equipment.
In a typical power plant, produces -1.5 times
(dry weight basis) as much calcium sulfite/
sulfate waste sludge as collected ash(38).
Corrosion and pitting problems may require
specific materials of construction.
-------
sodium sulfite and precipitate calcium sulfite. The calcium sulfite sludge
is concentrated by filtration prior to disposal. The dual alkali process can
achieve 99% S02 removal efficiency when treating relatively concentrated S(L
streams (e.g., 1800-8000 ppmv) and 90% S02 removal when treating more dilute
S02 streams (e.g., 250-1500 ppmv). Like the lime/limestone slurry process,
the dual alkali process generates large amounts of waste CaSO^/CaSO^ sludge
(in a power plant application, typically about 1.5 times as much as the amount
of ash generated in the plant^38').
5.2.4 Incineration
Incineration (oxidation with air) is used to (a) convert the reduced
sulfur species to S02 for direct discharge to the atmosphere or for subsequent
S02 recovery, and/or (b) oxidize residual organics (gaseous and particulate)
and carbon monoxide to carbon dioxide and water. When the product gas is to
be discharged directly to the atmosphere, the incineration may consist of
flaring, diversion of the gas to the industry/utility boiler, or combustion in
a separate incinerator (afterburner) with or without the use of supplemental
fuel. The latter type of incineration would also be used when the product gas
is to be further treated for S02 removal. To achieve complete oxidation at a
lower temperature, the separate incineration of the raw gas may be carried out
over a catalyst bed (catalytic oxidation).
Depending on the incinerator design and the operating conditions, incin-
eration can result in oxidation of over 90% of hydrocarbons, CO and reduced
sulfur compounds. Incineration is generally a simple and reliable operation.
•
However, in the presence of high sulfur loadings, some corrosion problems may
occur. The use of supplemental fuels with feed gases containing low heating
values can represent a significant operating cost.
5.2.5 CO, Hydrocarbon and Odor Control
The gaseous streams which may require hydrocarbon, CO and odor control
are tail gases from sulfur recovery, vent gases from storage facilities, pre-
treatment off-gases, lockhopper vent gases, catalyst regeneration/decommission-
ing off-gases, and transient gases. Hydrocarbons, carbon monoxide and odor
emissions,can be controlled by incineration. Hydrocarbon emissions can also
82
-------
be controlled by gas processing" using activated carbon adsorption. The use
of thermal and catalytic incineration for emission control was discussed in
Section 5.2.4.
Activated carbon adsorption is utilized for removal of hydrocarbons and
other organics, particularly odor-producing compounds. Impurities are ad-
sorbed on a solid bed of activated carbon by cohesion or chemical reaction.
Spent carbon is regenerated by application of heat or chemical treatment.
Efficiencies of up to 99% may be obtained depending upon the type of carbon
used, the carbon loading and the nature of material to be adsorbed.
5.2.6 Particulate Control
As indicated in Figure 5-2, gaseous waste streams which may require
treatment for particulate control include char combustion, incineration and
transient gases; catalyst regeneration/decommissioning off-gases; lockhopper
vent gases and pretreatment off-gases. The particulate control devices which
may be applicable to these streams are cyclones, fabric filters (baghouses),
venturi scrubbers* and electrostatic precipitators. The key features of these
devices including the advantages and disadvantages of each are presented in
Table 5-6. Although some of the equipment (e.g., cyclones and venturi scrub-
bers) will be used for the removal of particulates from process gases, the dis-
cussion in this section addresses only their application to waste gas treatment.
As indicated in Table 5-6, the four control devices considered vary in
their operating principle, effectiveness in removing particles in different
size fractions, temperature applicability, particulate loading limitation and
energy requirements. Cyclones are generally employed for the removal of bulk
particulates (generally greater than 5n in size) and, in many cases, ahead of
other control devices. The capital and operating costs for cyclones are
relatively low. Baghouses have very high particulate removal efficiency, and
can lend themselves to applications involving small or intermittent gas flows.
Baghouses, however, have high pressure drops (e.g., in comparison to electro-
static precipitators) and cannot ordinarily handle wet gases, gases containing
*0ther types of wet scrubbers, which are commonly used for quenching and
absorption/desorption of gases can effect some degree of particulate removal.
Relative to venturi scrubbers, however, the particulate removal efficiencies
of these devices are very low, specially for small size particles.
83
-------
TABLE 5-6. KEY FEATURES OF PARTICULATE CONTROL EQUIPMENT
Control
Device
Cyclone
Fabric Filter
(Baghouse)
Venturl
Scrubber
Electrostatic
Preclpltator
Operating Principle
Removal of parti-
culates from a gas
by Imparting a cen-
trifugal force to
the gas stream.
The Inertia of the
partlculates carries
them to the cylin-
drical walls where
they fall to the
bottom of the
cyclone for removal.
Removal of partl-
culates from a gas
stream by impactlon
or Interception on
a fabric filter
(generally tubular
shape). Partlcu-
lates can be re-
moved from filter
media by mechanical
shaking or a pres-
surized reverse
air flow.
Removal of partl-
culates from a gas
stream by Impinge-
ment with atomized
scrubbent droplets.
The agglomerated
particles are sub-
sequently removed
in a centrifugal
collector.
Removal of partl-
culates from a gas
stream by imposing
an electrical charge
and collecting the
charged particles
on oppositely
charged collector
plates. Collected
solids are normally
removed by mechani-
cal rapping with
hanmers or vibrators.
Efficiency
Range, wt %
50 to 80%
for 5 urn
80 to 95 1.
for 5 to
20 Mm
98.5 to 99. 5T,
for 0.25 to
0.5 urn
99.0 to 99.5%
for 0.75 to
V
99.9% for
100 Mm
60 to 92.5%
for 0.25 vm
DC *n 07 ?*
O J IU 3 f • C •
for 0.5 wn
92 to 99%
for 0.75 urn
oc «~ no cv
yj tO 7:7 . D »
for 1 0 urn
90 to 99.4%
for 0. 1 urn
90 to 98.7%
for 0. b urn
95 to 99.6%
for 1.0 urn
QO f>A OQ Q£
TO Lv 77 • J*
TOP D • 0 uni
Particle
Size
Removal
Range
>5 urn
>0.2 urn
>0.5 urn
>0.1 urn
Partlculate
Loading
Limitation
>2.4 g/m3
(^1 9r /ft3)
>0.24 g/m3
(>0.1 gr/ft3)
>0.24 g/m3
(>0.1 gr/ft3)
>0.24 g/m3
(>0.1 gr/ft3)
Pressure
Drop
1.3-10.2 cm
(0.5 to 0.4 1n.)
W.G.
5.1-25 cm
(2 to 10 1n.)
W.G.
25-250 cm
(10 to 1UO 1n.)
W.G.
0.51-2.5 a
{0.2 to 1 1n.)
W.G.
Advantages
High reliability due
to a simple collection
system. Low energy
requirements.
High partlculate
collection efficiency.
High partlculate
collection efficiency
capable of treating
streams with wide
temperature, pressure
and gas composition
ranges.
Suitable for high tem-
perature applications.
Low pressure drop, can
treat large volumes of
gas. Highly efficient
for small partlculates.
Disadvantages
Cannot efficiently
remove partlculates
below 5 urn
High capital and
operating costs. Plug-
ging problems will re-
sult If feed stream 1s
saturated or wet. Tem-
perature limit varies
with type of filter
media utilized. Generally
limited to 560°K (550°F)
maximum temperature.
Liquid scrubbing wastes
are producted which may
require treatment. High
efficiencies require high
energy consumption. Some
potentially valuable dry
material cannot be directly
recovered .
High capital costs. Gen-
erally applied at pressures
near atmospheric. Collected
parti cul at* must have a
suitable electrical resis-
tivity to facilitate effi-
cient collection. Not
applicable to explosive
gates.
00
-------
oily materials or gases having temperatures in excess of 560°K (550°F).
Venturi scrubbers can generally handle gases having temperatures higher than
those which can be handled by fabric filters, can operate at high pressures,
can tolerate wet and tarry gases,.and can be very efficient for the removal of
submicron particles. High removal efficiencies, however, have an associated
high energy penalty. In contrast to other devices in which the particulates
are collected in dry form, venturi scrubbers generate a scrubbing liquid blow-
down and hence a wet sludge which is more voluminous and generally more diffi-
cult to dispose of. When hot gases are to be handled, use of venturi scrubbers
would result in gas cooling and the addition of moisture to the product gas.
This would represent an energy penalty if the gas is to be subsequently incin-
erated (e.g., for CO and hydrocarbon control or used as fuel). Electrostatic
precipitators are high efficiency particulate removal devices, have low pres-
sure drops, are capable of handling large volumes of gases and can tolerate
high feed gas temperatures. Electrostatic precipitators, however, are not
economical for treating small or intermittent gas flows.and have not been
applied commercially to gases above atmospheric pressure.
5.2.7 Gas Compression and Recycling
Three of the gas streams shown in Figure 5-2 can potentially be recycled
to various streams in the gasification plant for material/energy recovery and
pollution control. These streams are: (1) feed lockhopper vent gases, (2) pre-
treatment off-gases, and (3) depressurization, stripping and vent gases. If
raw product gas is used for pressurization of the feed lockhopper, the feed
lockhopper vent gases can be compressed and added to the raw product gas or
reused for lockhopper pressurization. Alternatively, this gas may be used as
plant fuel. If the concentrated C(L stream from acid gas treatment is used
for lockhopper pressurization, the vent gases may be compressed for reuse or
recycling to the acid gas treatment system. The pretreatment off-gases may
be compressed and added to raw or quenched product gas or injected into the
gasifier. Depressurization, stripping and vent gases may be compressed and
added to the raw or quenched product gas. The vent gases which generally
contain little or no sulfur compounds may also be directly used as fuel.
Because of the relatively small volumes of the waste gases generated at
the pilot gasification facilities in the U.S., and because most of these
85
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pilot plant operations have been aimed primarily at the development of gasi-
fication technology, the above-listed compression and recycling options have
not been tested at the U.S. facilities. These options have also not been
employed at commercial gasification facilities abroad because of cost con-
siderations and the less stringent emission restrictions. At these facilities
the waste gases are generally disposed of by flaring or direct discharge to
the atmosphere.
5.2.8 NOX Control
The flue gases generated in the combustion of char and waste gases will
contain varying amounts of NO depending on the fuel type and combustion con-
ditions. Control of NO emissions can be achieved through combustion modifi-
n
cation and/or by use of add-on processes. Combustion modification which may
include staged-combustion, use of low excess air, reduction of air preheating,
steam or water injection and reduced heat release rate may result in as much
as 60% reduction in NO emissions. Somewhat lower efficiencies are obtained
when the fuel (e.g., coal and char) contains nitrogen. Add-on processes gen-
erally fall into two categories: dry processes and wet processes. Most dry
processes involve catalytic reduction of NO with ammonia which is added to
J\
the flue gas. Wet processes involve a combination of absorption and oxida-
tion or reduction for NOV removal. Removal efficiencies greater than SQ% can
/\
be obtained with dry or wet processes.
Only a few of the add-on NO control processes have been developed com-
rt
mercially. Applications of the few processes which have attained commercial
status have been limited to facilities in Japan and to oil-fired utility and
industrial boilers. Except in connection with on-site steam and power genera-
tion and/or in those gasification processes which incorporate external char
combustion, NOV control would not be a major concern in a commercial high Btu
A
gasification facility.
5.3 AIR POLLUTION CONTROL IN INTEGRATED FACILITIES
This section discusses the alternative approaches to control of air pol-
lution emissions in integrated coal gasification facilities. The discussion
does not include emission controls from conventional sources associated with
coal preparation (crushing, screening, drying) and coal combustion for steam
86
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and power generation. Based on the relative volumes and characteristics of
various waste gases generated in a gasification plant and the relative magni-
tude of the environmental impacts associated with potential emissions of
"criteria" and other pollutants contained in such gases, sulfur-bearing waste
gases would appear to be of primary concern for emission control. Depending
on the specific gasification process and plant design, control of hydrocarbons,
carbon monoxide and odor may also be important. Control of particulates and
NO would generally be of less importance in a gasification plant since
A
process-related large volume gaseous wastes generally do not contain high
levels of these constituents. Processes such as Cogas, (XL-Acceptor and
Synthane which employ external char combustion, however, generate a relatively
large volume of flue gas which contains high levels of particulates and, like
all other combustion gases, some NO .
/\
5.3.1 Control of Sulfur Emissions
The sulfur-bearing streams in a high Btu gasification plant would fall
into two general categories, those containing reduced sulfur compounds (pri-
marily HpS) and those containing oxidized sulfur compounds (primarily S0?).
The first category consists of concentrated acid gases, depressurization and
stripping gases, lockhopper vent gases, and pretreatment off-gases. The second
category consists of char combustion and incineration gases and catalyst
regeneration/decommissioning off-gases. In terms of total volume and concen-
tration, the concentrated acid gases and the char combustion and incineration
gases are by far the most important.
Table 5-7 presents a number of options available for the management of the
sulfur-bearing gas streams and highlights some major advantages and disadvan-
tages of each option. Some options (e.g., incineration of concentrated acid
gases and atmospheric discharge) would be technically unattractive and environ-
mentally unacceptable for use in the U.S. The applicability of certain options
(e.g., those using Claus, Stretford or G-V processes for sulfur recovery) is
dependent on the sulfur concentration in the gas stream which is in turn
determined by the sulfur content of the feed coal, the specific gasification
processes used and the acid gas treatment processes employed. Accordingly,
the selection of the best option for the management of a specific sulfur-
bearing stream should be based on a case-by-case analysis. This is also
87
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TABLE 5-7. OPTIONS FOR THE MANAGEMENT OF SULFUR-BEARING WASTE GASES IN INTEGRATED FACILITIES
Haste Gas
Concentrated Acid Gases
Depressurization
and Stripping
Gases
Pretreatment
Off -Gases
Lockhopper Vent
Gases
Catalyst R*gtn«r«t1on/
OtccMri»1on1ng
Off-Gates
Char Combustion.
Incineration and
Treatment Gases
Control Options*
t.
2.
3.
4.
5.
6.
7.
8.
9.
10.
1
2.
3.
4.
5.
1.
2.
3.
4.
5.
1.
2.
3.
4.
1.
2.
1.
2.
Claus plant sulfur recovery
Claus plant sulfur recovery and
tall gas incineration
Claus plant sulfur recovery and tall
gas treatment
Same as 1 plus SO? control and/or
recovery
Stretford or G-v sulfur recovery
Same as 5 plus tall gas treatment
Same as 6 plus Incineration
Incineration
Same as 8 plus SO? control and/or
recovery
Incineration, treatment for
control and/or recovery 1n combi-
nation with flue gases from
utility boilers or char combustion
Combining with concentrated add
gas streams and use of any of the
treatment options listed above
Compression and addition to product
gas stream
Use as fuel
Incineration
Same as 4 plus SO; control and/or
recovery
Combining with product gas
Injection Into gastfler
Use as fuel
Incineration
Same as 4 plus SO? control and/or
recovery
Compression and recycling
Incineration
Sane as 2 plus S02 control and/or
recovery
Use as fuel
Incineration
Saae as 1 plus SOj control and/or
recovery
Incineration (for transient gases)
SaM as 1 plus SO. control and/or
recovery
Comment',
1.
2.
3.
4.
5.
6.
7.
8.
9.
0.
1.
2.
3.
4.
5.
1.
2.
3.
4.
5.
1.
2.
3.
4.
1.
2.
1.
2.
Probably unacceptable because of high concentration of total sulfur
In the tail gas; only applicable to streams containing more than 1$: HjS.
Probably unacceptable because of high levels of SO? 1n the tall gas; only
applicable to streams containing norc than 15' HpS.
Tail gas treatment not highly effective wh«n fool gases contain high levels
Of (0?; only .applicable tn stream*, containing irore than IV H?S.
Reasonable option when feed gases contain more than 1551 H^S; total sulfur
removal efficiency may be less than option 5.
Inapplicable to waste gases containing high levels of H?S; may not be
economical for gases containing high COi levels, discharge may contain
high COS and HC levels.
Same as for Option 5.
Same as for Option 5 except for o»1dation of CO and HC compounds
Unacceptable because of high 502 emissions.
Many SO? recovery processes generate sludges requiring disposal ;no by-product
sulfur is recovered: regenerable SCb removal processes must be operated in
conjunction with sulfur recovery units.
Same as for Option 9; some economy of scale may be realized if flue gas
desulfurization 1s required on utility boilers.
See Individual options above; may have considerable dilution effect on the
concentrated acid gas streams.
Permits material recovery; some energy Input required for compression.
Stripping gases may have limited fuel value; may have high SO; emissions.
High levels of SO? emissions.
See comments for Options 9 and 10 for Concentrated Acid Gases.
Product gas dilution and energy requirement for compression; permits
material and energy recovery.
Permits material and energy recovery; will require gaslfler design modifi-
cation and energy input for compression.
May have high SO? emissions.
See comment for Option 4, Depressurization and Stripping Gases.
See comment (or Option 5, Depressurization and Stripping Gases.
See comment for Option 2. Pretreatnent Off-Oases.
See comment for Option 4, Depressurization and Stripping Gases
See comments for Options 9 and 10, Concentrated Add Gases.
See comment for Option 3, Depressurization and Stripping Gases.
See comment for Option 4, Depressurization and Stripping Gases.
See cements for Options 9 and 10, Concentrated Acid Gases.
See cement for Option 4, Oepressur1zat1on and Stripping Gases.
See coMMnts for Options 9 and 10. Concentrated Acid Gases.
•Except wtwr* g«*
>r*ls1an wxl recycling l» us«d. all options culnlnat* 1" d1»ch«ro« of the tr««t»d g** to tfi«-
-------
complicated by the lack of data on (1) the detailed composition of gas streams
from applicable facilities and (2) performance, costs and environmental aspects
of actual application of control processes to coal gasification gas streams.
For example, the Stretford process has been demonstrated to be highly effec-
tive for H2S removal for refinery and coke oven gases which contain low to
moderate levels of C02; however, insufficient data exist for commercial appli-
cations to coal gasification acid gases which in some cases may contain 90% or
more C02- (A small Stretford unit is being tested at the Fort Lewis SRC pilot
plant handling concentrated acid gases from a DEA unit. Satisfactory perfor-
(391
mance of the unit has not been achieved to datev '.) For the 6-V process,
which is capable of handling acid gases containing high levels of C02 and uses
an arsenic-based sorbent, the hazardous characteristics are not known for com-
mercial applications.
Some of the options listed in Table 5-7 have not appeared in the designs
for proposed commercial high Btu gasification facilities. Most possibly this
is due to the lack of engineering data for such options. For example, all con-
ceptual designs include Claus or Stretford processes for the recovery of hUS
from concentrated acid gases. Due to some of the shortcomings associated with
these processes for handling gases containing high.levels of C(L, it is possible
that gas incineration followed by SO,, recovery (in a Wellman-Lord or wet lime-
stone unit) alone or in conjunction with flue gas from utility boilers may be
technically and economically superior.
5.3.2 Control of Particulate Emissions
In an integrated gasification facility which employs processes such as
Lurgi which do not generate chars requiring combustion/gasification in an
external vessel, the particulate emissions directly associated with the main
gasification operation, gas purification and gas upgrading operations are
generally very small when compared to emissions from other areas such as coal
preparation and on-site coal combustion for power generation and process heat-
ing. In integrated facilities employing processes such as Cogas, CCL-Acceptor
and Synthane which incorporate char gasification/combustion external to the
main gasifier, the combustion flue gas from the burning of char and/or supple-
mental fuel will also be the major source of particulate emissions. When
combustion of char and/or coal is carried out in a conventional boiler, control
89
-------
devices such as electrostatic precipitators and fabric filters which are widely
used in the utility industry would be applicable. In processes such as COg-
Acceptor which combust/gasify char under pressure, a combination of cyclone
and venturi scrubbers would probably be most applicable. The removal of
particulates from such flue gases would probably be required for protection
of downstream gas turbines used to recover energy from the flue gas whether
or not emission control would be necessary.
Process-related potential sources of particulate emissions in an inte-
grated gasification facility which are less important (if equipment is properly
working and operating) than char gasification/combustion flue gases are pre-
treatment off-gases, lockhopper vent gases and catalyst regeneration/
decommissioning off-gases. The possible options involving compression and
recycling of the pretreatment off-gases and lockhopper vent gases were dis-
cussed in Section 5.3.1. When these gases are not recycled, the most suitable
device for the control of particulate emissions from these two sources would
be the venturi scrubber. Fabric filters would generally be inapplicable to
these gases, which normally contain tarry materials and high moisture levels.
Fabric filters, however, would probably be applicable to the catalyst
regeneration/decommissioning off-gases since these gases would normally con-
tain low levels of moisture, are generally devoid of tarry materials, and are
generated intermittently and in small volumes.
5.3.3 Control of Carbon Monoxide, Hydrocarbons and Odorous Emissions
No large sources of hydrocarbons and carbon monoxide emissions are
expected in a commercial coal gasification facility. The sources and magni-
tudes of these emissions would generally depend upon the gasification process
used, and the gas purification and upgrading operations employed. When the
COg-Acceptor process is used for coal gasification, emissions of non-methane
hydrocarbons are very low since no hydrocarbons other than methane are pro-
duced in the gasifier. Some carbon monoxide emissions, however, may be assoc-
iated with this process as a result of fluidized bed combustion of the char
which has to be carried out with very low excess air. The Hygas process would
have several potential sources of hydrocarbon emissions due to the use of coal-
derived oil for slurry feeding and the net production of such oil in the pro-
cess. For coals requiring pretreatment, the Hygas process also will generate
90
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a hydrocarbon- and CO-bearing off-gas. The level of hydrocarbons in the con-
centrated acid gas stream produced in product gas purification operations
depends on the specific gas treatment process employed. For example, when
handling feed gases containing nonmethane hydrocarbons, concentrated acid
gases produced by "physical solvent" processes, such as Rectisol, will also
contain some nonmethane hydrocarbons, thus requiring hydrocarbon control in
conjunction with or subsequent to sulfur recovery. On the other hand, processes
such as Benfield and Catacarb will produce a concentrated acid gas stream
which is essentially devoid of all hydrocarbons, thus eliminating the hydro-
carbon control requirements. Options for the control of hydrocarbons and CO
are essentially limited to control at the source (e.g., recycling of the
pretreatment off-gases or combustion modifications), use of incineration and,
in the case of hydrocarbons, use of activated carbon adsorption. Flaring of
process and waste gases would most likely be employed at all commercial gasi-
fication facilities for the control of hydrocarbons, CO, odors, H^S, etc. dur-
ing transient operations. Although at the existing gasification pilot plants
the product gas and waste gases are disposed of by flaring (even during steady
state operation), little data are available on the effectiveness of these
flaring operations. At commercial facilities flaring of the waste gases would
be of intermittent nature. The composition of the flare off-gas would be
highly variable, depending primarily on the nature and volume of the gases
being flared.
Production of odorous compounds (e.g., H,,S, mercaptans and heterocyclic
aromatics such as pyridine and thiophene) would be associated with the opera-
tion of almost all gasification plants. Their release to the atmosphere,
even in very small quantities, can present significant odor problems. As with
the hydrocarbon emissions, options for the control of odor are limited to
source control, incineration and carbon adsorption. Since in an integrated
facility, fugitive emissions (e.g., from spills and leaks) and emissions
from non-process sources (e.g., cooling towers and wastewater treatment units)
can contribute significantly to the total odor emissions, good housekeeping
practices, proper operating procedures and routine maintenance are essential
to minimize the odor problem.
91
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5.3.4 Control of Non-Criteria'Pollutant Emissions
In addition to the criteria pollutant (SO^, participates, hydrocarbons,
CO and NO ) and HLS, gaseous waste streams in an integrated gasification
A £
facility may contain a number of other constituents which even though present
in relatively small concentrations may be of environmental concern due to their
hazardous characteristics. These pollutants fall into two general categories:
trace elements (and their compounds) and trace organics. Trace elements such
as Hg, As, Sb, F, Cd, B, Se, and Be which are originally present in the coal
are volatilized to varying degrees during coal pretreatment and gasification
(see Section 2.4.3). Trace elements may also be present in the gas stream in
the form of particulate matter. Some of the trace elements contained in the
raw product gas are removed during subsequent gas processing (e.g., quench and
dust removal); others may become components of the waste gases produced in gas
purification and upgrading and lockhopper operations. In processes which
employ char combustion/gasification, the resulting flue gases would also con-
tain trace elements (in particulate and gaseous forms). In addition to coal
as a source of trace element emissions, the off-gases from the regeneration and
decommissioning of methanation catalysts can be a source of trace element
emissions. These emissions are usually in the form of particulate nickel or
nickel carbonyl.
As discussed previously, some high Btu gasification processes (e.g., Lurgi
and Hygas) produce significant quantities of tars and/or oils containing a
range of organics, some of which may be hazardous because of toxicity, carci-
nogenicity, teratogenicity, etc. Examples of classes of such hazardous
organics are polynuclear aromatic hydrocarbons (e.g., cholanthrenes and benzo-
pyrenes), heterocyclic aromatics (e.g., thiophenes, pyridines and dibenzo-
carbozoles) and polyhydric phenols. The more volatile of these compounds
(e.g., pyridines and thiophenes) may become components of the concentrated
acid gases; depressurization, stripping and vent gases; lockhopper vent gases
and pretreatment off-gases. The less volatile compounds would tend to become
components of the aqueous and organic condensates and may be present in certain
gas streams (e.g., pretreatment off-gases) in the particulate form.
Many of the processes and devices used for the control of criteria pol-
lutants are also effective to varying degrees in removing trace elements and
92
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organics from gaseous waste streams. For example, particulate trace elements
and organics are largely removed by participate control devices. When venturi
scrubbers are used for particulate control, the cooling of the gas also results
in the condensation and removal of some of the volatile components. Under
proper operating conditions, incineration of waste gases can bring about nearly
complete destruction of trace organics. Some of the highly volatile substances
such as mercury, arsine.and nickel carbonyl may not be totally removed by some
of the conventional controls such as incineration and venturi scrubbing. At
the present time, adequate technical data are not available to estimate the
levels of these substances in various waste gases in an integrated gasifica-
tion facility and the effectiveness of the existing controls for their removal.
Furthermore, inadequate environmental and toxicological data prevent estimation
of acceptable emission levels for many of these substances.
5.4 DATA GAPS AND LIMITATIONS
The data gaps and limitations relate primarily to the composition of the
waste gases which would require processing for air pollution control in a com-
mercial gasification facility, the toxicological properties of trace constitu-
ents and the ecological implications of various substances in gaseous emis-
sions, the applicability and cost of various control technologies and waste
management options, energy use and water and solid waste pollution control
requirements. The limited data available on waste gases are from pilot plant
operation in the United States, a few tests of American coals in the Westfield
Lurgi plant and the operation of other foreign commercial facilities. The
limitations of the available data on operation at foreign gasification sites
were discussed in Section 3.4.
As was discussed in Sections 2.5 and 3.4, the pilot plant operations in
the U.S. have been primarily aimed at the development of the gasification
technology. These pilot plants do not incorporate all the peripheral opera-
tions which would be employed in an integrated facility and which would con-
stitute additional sources of discharges in such a facility. For example, the
Synthane pilot plant does not incorporate char gasification/combustion which
would be employed in a commercial facility. The gasifiers and the limited
peripheral units which are being tested in the pilot plant programs do not
necessarily represent full-scale units because of anticipated scale-up design
93
-------
changes and equipment/process modification and substitution. At the COg-
Acceptor pilot plant, for example, the regenerator flue gas has been scrubbed
with a sodium hydroxide solution for S02-removal and all reported gas composi-
tion data have been obtained on the scrubbed gas. In a large-scale facility,
flue gas desulfurization would most likely employ one of the commercially
developed processes which uses reagents other than sodium hydroxide. Essen-
tially no composition data are available for some of the gas streams (e.g.,
the lockhopper vent gases). The composition data which have been reported for
some of the gaseous wastes are not very comprehensive and in general do not
address environmentally important trace constituents. For example, quantita-
tive data are not available on trace elements and trace organic sulfur and
nitrogen compounds for all gas streams. Information is lacking on the toxico-
logical, ecological and synergistic properties of most trace substances pre-
sent in gaseous emissions. Very little information is available on the trans-
portability, atmospheric residence time and ultimate fates of such constitu-
ents. For these reasons and the fact that accurate engineering estimates have
not been made of the levels of many environmentally important constituents in
gasification plant emissions, the anticipated ambient levels of such constitu-
ents cannot be predicted at this time.
Nearly all the engineering and cost data which are available for air pol-
lution control processes and devices are for applications to waste and process
gases in industries other than coal gasification. Moreover, the energy require-
ments and the liquid and solid wastes generated by air pollution control pro-
cesses/devices in applications to coal gasification gases are not accurately
known and hence the impact that the use of such technologies would have on
overall facility energy requirements and pollution control are not well de-.
fined. In some cases where control technology developers/licensors might have
generated data on applicability of a control technology to coal gasification
gases and on the costs, energy requirements and waste generation characteris-
tics associated with such applications, such data are generally considered
proprietary and hence not publicly available. Because of (a) the lack of de-
tailed composition data for coal gasification waste gases, (b) known differ-
ences between coal gasification waste gases and process/waste gases in other
industries, and (c) very limited testing of the control processes/devices on
coal gasification waste gases, there is a very limited technical data base to
94
-------
establish applicability of the existing control technologies to coal gasvfica-
tion waste gases. Such data would also be needed to determine necessary
process/equipment modifications, to conduct comparative evaluation of various
air pollution control options for commercial facilities, and to estimate costs
associated with the control technologies and options. Because of the data
limitations mentioned above, accurate estimation of the magnitude of emissions
from commercial high Btu gasification facilities and the environmental impacts
associated with such emissions cannot be made at this time.
5.5 RELATED PROGRAMS
Many of the programs discussed in Sections 2.6, 3.4, 4.1.3 and 4.2.3 are
expected to generate some data on the characteristics of waste gases from
integrated facilities. Under an EPA contract, Cameron Engineers (Denver,
Colorado) is preparing an outline and an example section for a "Multimedia
Environmental Control Engineering Handbook" (MECEH). MECEH will include a
detailed description of environmental control technologies applicable to coal
conversion and will provide information on commercially available pollution
control equipment. The objectives of the handbook are to: (a) categorize
all commercially available control technologies into a systematic format,
which can be easily assessed; (b) provide technical data for each process,
including process descriptions, ranges of applications, efficiencies, and
capital and operating costs; and (c) provide a list of those who supply (the
specific equipment and/or license the technology. C. F. Braun and Company
(Alhambra, CA) is the "Evaluation Contractor" for a joint DOE-AGA coal gasi-
fication program. The company has been conducting a number of engineering
studies, some of which relate to the management of sulfur emissions in com-
mercial gasification facilities. As part of these studies, engineering and
cost data have been and are being solicited for various process vendors. EPA
has recently published guidelines on control of emissions from Lurgi coal gasi-
fication plants(37).
9,5
-------
6.0 WATER POLLUTION CONTROL
Several process and air and solid waste pollution control modules in an
integrated SNG facility would generate aqueous wastes requiring treatment.
This section is a summary of the available information about the sources and
characteristics of these wastewaters and the treatment processes/equipment
which have been or could be used for the treatment of such wastewaters. Only
those aqueous wastes which are specific to high Btu gasification and related
operations are considered. Thus, wastewaters associated with coal storage
(e.g., coal pile runoff) and preparation, raw water treatment, on-site steam
and power generation and sanitary facilities are not addressed. (Some of
these have been addressed in "Environmental Assessment Data Base for Low- and
Medium-Btu Gasification", EPA 60017-77-125a and b, November 1977.) Detailed
information on the individual wastewater treatment processes reviewed are pre-
sented in the "data sheets" contained in Appendix E.
6.1 SOURCES AND CHARACTERISTICS OF AQUEOUS WASTES
Figure 6-1 identifies the major sources and types of aqueous wastes in an
integrated coal gasification facility. As indicated in this figure, seven
general types of aqueous wastes may be produced in a gasification plant. These
are; (1) particulate scrubber waters, (2) raw gas quench waters, (3) ash quench
waters, (4) waste sorbents and reagents, (5) shift condensate, (6) methanation
condensate, and (7) miscellaneous wastewaters (e.g., blowdowns, storm runoff
from plant areas, accidental discharges, etc.). Not all of these aqueous
wastes may be generated in all gasification plants. Table 6-1 identifies waste
stream categories associated with each of the eight high Btu gasification
processes evaluated. The composition of wastewater varies from plant to plant,
depending on the process used, coal feed, operating conditions, water conser-
vation and reuse practices incorporated in the plant design and "housekeeping"
procedures. Most of the available wastewater composition data are for pilot
plants which, although very useful, may not be entirely representative of
96
-------
PREPARED
COAL
vo
WASTE
SORBENTS
AND
REAGENT
AIR POLLUTION
(PARTICULATE)
CONTROL
AIR POLLUTION
( SULFUR)
CONTROL
METHANATION
AND
DRYING
QUENCH
AND
DUST
REMOVAL
COAL
PRETREATMENT
SHIFT
CONVERSION
GASIFICATION
RAW
GAS
QUENCH
WATERS
ASH
QUENCH
WATERS
PARTICULAT
SCRUBBER
WATERS
SHIFT
CONDENSATE
•SNG
CHAR COMBUSTION,
INCINERATION, AND
TRANSIENT
GASES
AIR
POLLUTION
CONTROL
WASTE
SORBENTS
AND
AGENTS
MISCELLANEOUS
PROCESS/PLANT
RELATED
SOURCES
SLOWDOWNS,
STORM RUNOFF
AND
ACCIDENTAL
DISCHARGES
Figure 6-1. Major Process Modules Generating Aqueous Wastes in a Typical High Btu Gasification Plant
-------
TABLE 6-1. AQUEOUS WASTE STREAMS ASSOCIATED WITH DIFFERENT HIGH BTU GASIFICATION PROCESSES
Wastewater Category
Parti oil ate scrubber waters
from treatment of:
Pretreater Flue Gas
Lockhopper Vent Gas
Char Combustion Flue Gas
Raw Gas Quench Waters
Cyclone Slurry
Quench Slowdown
Ash Quench Water
Shift Condensate
Methanation Condensate
Waste Sorbents & Reagents
Miscellaneous Wastewaters
Gasification Process
ro
•r—
3-0
Yes
Yes
No
No
Yes
Yes
Yes
Yes
*
Yes
o>
5>
O» ro
3 I/)
—!•«—*
Yes
Yes
No
No
Yes
Yes
Yes
Yes
*
Yes
?
in ro
ro 0>
0>4->
Yes
No
No
Yes
Yes
Yes
Yest
Yes
*
Yes
ro
O
O
No
No
Yes
*
Yes
Yes
Yest
Yes
*
Yes
o
Q.
0)
0
o
1
Yes
Yes
Yes
No
Yes
Yes
No
Yes
*
Yes
Synthane
No
Yes
Yes
No
Yes
Yes
Yes
Yes
*
Yes
to
ro
C7>
•r-
CO
No
No
No
No
Yes
Yes
Yes
Yes
*
Yes
-------
commercial scale operations. Furthermore, since in most pilot plant operations,
only the coal gasification has been emphasized, data are not available for all
the waste streams listed in Table 6-1. For some streams where data are avail-
able, the data are not generally comprehensive in that not all environmental
properties of interest have been addressed. Composite values or ranges of val-
ues reported for various parameters and constituents in wastewaters from selec-
ted gasification processes are presented in Table 6-2. The data in this table
(and the "normalized" constituent/parameter production rates presented in
Table 2-6) are based upon the information in Appendix A. A discussion of the
available data by wastewater category follows.
6.1.1 Particulate Scrubber Waters
Depending on the gasification process used, the most likely sources of
particulate scrubber waters are: pretreatment, lockhopper operation and char
combustion. Coal pretreatment scrubber waters generally contain high levels
of suspended and dissolved solids, and moderate levels of organics, as reflec-
ted by the TOC, phenol and oil and grease values shown in Table 6-2. The rela-
tively high level of thiocyanate and the low levels of sulfide and cyanide can
be attributed to the reaction between sulfide and cyanide under mildly oxidiz-
ing conditions. As discussed in Section 5.3.4, some of the more volatile of
the trace elements in coal may be removed by scrubbing and thus become compo-
nents of the scrubber water. If lockhopper vent gases are scrubbed in a ven-
turi scrubber, the resulting scrubber water would be expected to contain high
levels of suspended solids. When raw or quenched product gas is used for feed
lockhopper pressurization, the scrubber water may also contain organics, ammo-
nia, sulfide and thiocyanate. In gasification processes such as Synthane,
^-Acceptor and Cogas where the char is combusted/gasified, the scrubbing of
the resulting flue gas will generate a scrubber water containing high levels;
of dissolved and suspended solids. As noted in Table 6-2, the reported scrub-
ber water production rates vary from 6 to 8.5 A/kg of coal, based on the pilot
plant operation.
6.1.2 Raw Gas Quench Waters
In gasification facilities which use fluidized or entrained bed gasifi-
cation (e.g., C02-Acceptor, Hygas, Cogas and Bigas) the scrubber water from
99
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TABLE 6-2. SUMMARY OF THE REPORTED CHARACTERISTICS OF WASTEWATERS FROM HIGH BTU GASIFICATION PROCESSES
(EXCEPT- FOR pH AND AS OTHERWISE NOTED, ALL VALUES ARE IN MG/1)
Hastewitar Categories
Pirtlcultte Scrubber Haters
Pretreataent Flu* 6«t
Locknopper Vent 6as*
Char Combustion Flue Gas
Raw Gat Quench Haters
Quench Slowdown
Cycloni Slurries
Ash Quench Haters
Shift Condensatel
Mthanatlon Condendatel
Production Rate
t/kg (gal/lb) Coal
7.9-0.5 (0.97-1.04)
6 (0.75)
0.031-4.4 (0.004-0.56)
1.4-4.1 (0.18-0.5)
2.9-6.1 (0.36-0.75)
T
-0.18 (0.022)**
TSS
700-1060
150-1630
23-15800
13100-26000
4700-68000
LOW
Very low
TOC
670-1200
-
863-lOOOOt
490-1518
78-243
T
Very low
COO
-
5-70
100-43000*
-
135-290
Moderate
Very low
Phenols
1330
<0.004
0.001-6600t
1B9-2455
<0. 004-7.8
7
Very low
NH3
23-26
33-292
665-17800
67-439
3.7-200
Low
Very low
s-
2-3
<0.01-3.2
0.01-1030
34-99
< 0.01-230
Moderate/
low
Very low
CH-
0.003-0.024
«0.02
< 0.001 -14
<0. 004-1.0
< 0.001-0. 019
Very low
Very low
SCH-
209-316
-
6-360
34-198
1.5-6.8
Low
Very low
IDS*
2600-4850
912-1300
426-4000
432-669
54-6244
Low
Very low
Oil 1
Grease
159-239
<0.004
34-5000
190-2190
8-50
Low
Very Low
pH
6.1-6.2
6.6-8.0
7.2-9.8
7.1-8.0
7.4-12.3
7
Neutral
o
o
•Heavily dependent upon TOS levels In make-up water.
*Low values represent COj-Acceptor process, which generates essentially no non-Mthane hydrocarbons 1n the gaslfler.
So actual data available; scrubber water composition would depend upon the composition at gas used to pressurize lockhoppers.
'Estimated; no actual operating data available for shift and •thanatlon condensate.
Calculated based on 1 «ole HjO produced per mole of product nethane.
-------
gas quenching can be one of the most particulate-laden wastewater streams in
the gasification complex. As noted in Table 6-2i- TSS values of over 15,000
mg/l have been reported for the Hygas quench water. In fixed bed processes
such as Lurgi, the particulate loading in the raw product gas is generally
lower and this is reflected in the lower suspended solids concentrations in the
quench and organic condensates. The data in Tab.le 6-2 indicate that the raw
gas quench waters contain high levels of ammonia, sulfide and thiocyanate and
are relatively low in cyanide. The low level of cyanide has been attributed
to its reaction with sulfide to produce thiocyanate. The quench waters from
processes such as Lurgi, Synthane and Hygas which produce tars and/or oils also
contain high levels of organics (e.g., up to 6,600 mg/1 of phenols and up to
10,000 mg/1 of TOC). These quench waters also contain varying concentrations
of trace organics such as carbazoles, benzofurans and benzopyrenes which can
be hazardous. In addition to trace organics, the quench waters can also con-
tain significant levels of certain trace elements originally present in the
coal. Table 6-3 presents the trace element concentrations in Synthane and
Hygas quench waters and on the percentages of the trace elements originally
present in the coal which are found in the aqueous condensate from the Lurgi
facility at SASOL, South Africa. As noted in the table, for the Lurgi facil-
ity, close to 90% of the arsenic, 42% of the fluoride, 35% of the cadmium and
32% of the mercury are present in the raw product gas quench water. The quench
waters are usually slightly alkaline (due to the high ammonia levels) and the
amount produced depends upon the gasification process and the design of the
quench system.
Somewhat related to the gas quench water is the slurry water used to
transport particulates collected by cyclones. Cyclones are employed in proc-
esses such as Hygas ahead of the quench system for bulk particulate removal.
This stream can contain a very high concentration of particulates (reported
values of up to 26,000 mg/£) and somewhat lower levels of other constituents
found in the raw product gas.
6.1.3 Ash Quench Maters
All gasification processes reviewed use water for ash quenching and
transport. The ash quench waters are characteristically high in both sus-
pended and dissolved solids and can have a very high pH (especially when high
101
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TABLE 6-3. TRACE ELEMENTS REPORTED IN PRODUCT GAS QUENCH WATERS
Element
Hg
As
Zn
Mn
Cr
F
B
Be
Cd
Pb
V
Sb
mg/1 Concentration
Synthane
PDU (mg/1)
0.027
0.001
0.13
0.2
0.043
39
43
-
-
-
-
-
Hygas
Pilot Plant (mg/1)
-
-
37-63
40-206
<24
-
251-12000
<2
<20
<60
<200
-
% of Element
Originally
Present in Coal
Lurgi (at Sasol)
32
90
-
36
-
42
3.5
1.6
35
3.2
0.06
36
sodium lignites are gasified). The concentrations of ammonia, sulfides and
organics are generally low in these waters. Although little quantitative data
are available on the trace element composition of the ash quench waters,
because of the high pH environment these waters are expected to contain low
levels of most heavy metals (e.g., Zn, Cd, Pb, Cr, V) in dissolved form.
Certain trace elements such as boron, selenium, arsenic and fluorine, which
can exist as anions under alkaline conditions, may be present in significant
quantities in these waters.
6.1.4 Shift Condensate
As discussed in Section 4.1.2, the cooling of the product gas after shift
conversion results in the condensation of moisture. No actual analytical
data are available on the composition of this condensate. Since shifting
follows quench and dust removal, the condensate stream is expected to be
relatively "clean", containing only small amounts of ammonia, sulfide and
low molecular weight organics as major pollutants.
102
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6.1.5 Methanation Condensate
As noted in Section 4.2.2, methanation is the final step in the produc-
tion of SNG and is preceded by trace sulfur and heavy hydrocarbons removal
steps. Accordingly, the methanation condensate is expected to contain very
low levels of sulfur- and nitrogen-containing compounds and nonmethane
organics. One mole of water is produced per mole of methane produced. No
actual composition data have been reported for the methanation condensate.
6.1.6 Waste Sorbents and Reagents
Waste sorbents and reagents include routine solvent or solution blow-
downs from acid gas treatment and air pollution control and wastes resulting
from these systems in cases of upsets and transient conditions. Continuous
or periodic discharges of blowdowns from these systems are necessary to avoid
contaminant build-up and maintain sorbent activity. The nature of these
wastewaters and the quantities discharged would depend on the specific process
used and its design, the characteristics of the gas treated and the frequency
and nature of the upsets and transient conditions. Since no commercial SNG
facilities currently exist, data are not available on the characteristics of
waste sorbents from acid gas treatment and air pollution control in such appli-
cations. The conceptual design of the proposed El Paso Natural Gas Company
fi o
Burnham SNG facility assumes a solution blowdown rate of 24.7 kg/10 Nm (1.46
lb/10 scf) of treated gas for the Stretford unit handling a concentrated C09
(7)
gas stream from the Rectisol unit. ' The major pollutant constituents of the
stream are estimated to include sodium thiosulfite (11%), sodium thiocyanate
(4.4%), sodium vanadate (0.7%), anthraquinone disulfonic acid (1.1%) and sodium
carbonate and bicarbonate (3%). As discussed in Section 5.2.3, some S02
removal processes generate aqueous wastes containing high levels of dissolved
salts (sodium sulfate and sulfite in the case of the Wellman-Lord process).
6.1.7 Miscellaneous Wastewaters
In addition to the sources of wastewaters discussed above, there are a
number of miscellaneous wastewaters in a high Btu gasification plant whose
characteristics may be unique to this type of coal conversion and related
operations. These wastewaters may originate from clean-up of spills and
leaks, runoff from process areas, plant cleanup and maintenance. When process
103
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wastewaters are used as cooling tower make-up, the cooling tower blowdowns are
expected to contain some of the pollutants In the make-up water. Although
these miscellaneous wastes are not unique to coal gasification, the wastewater
characteristics will reflect the processes and chemicals used in such a plant.
6.2 WATER POLLUTION CONTROL PROCESSES
Figure 6-2 presents the wastewater treatment process modules for use in
integrated high Btu gasification plants. These process modules are for oil
and suspended solids removal, dissolved gases removal, dissolved/particulate
organics removal, separated tar/oil and sludge treatment and dissolved inor-
ganics removal. Each module consists of interchangeable processes which would
be applicable to different ranges of wastewater concentrations and operating
conditions. The processes which are reviewed in this section are listed in
Table 6-4. Except for the processes for the removal of dissolved inorganics
and the absorptive resin process for organics removal, data sheets were pre-
pared for each of the processes reviewed (see Appendix E). The use of dis-
solved inorganics removal processes such as ion exchange, reverse osmosis and
electrodialysis is not expected to be unique to high Btu gasification since at
least the inorganic composition of these wastewaters would be similar to those
encountered in other industries. Sorptive resins have been used in a "polish-
ing" step for the removal of refractory organics from wastewaters after the
wastewater has been treated by more conventional techniques (e.g., biological
treatment). Compared to other advanced waste treatment processes such as
activated carbon adsorption, sorptive resins and dissolved inorganic removal
processes are also presently less developed and their potential use and cost
for large-scale applications have not been evaluated.
Since no commercial SNG facility currently exists and wastewater treat-
ment efforts at the domestic pilot plants have been very limited, very little
data exist on the application of the various wastewater treatment processes
to high Btu gasification wastes. All of the processes reviewed, however,
have been widely used in other industries and some (e.g., biological oxida-
tion and sludge treatment) are extensively used for the treatment of domestic
wastewaters. The wastewater treatment systems at the high Btu gasification
pilot plants have generally been designed to serve a "temporary" need, in some
cases are "package" type systems, and in no case reflect the choice of
104
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o
C71
SEPARATED
TAN/OIL t
SLUDGE
TREATMENT
WASTE
SLUDGES
SOLIDS
SEPARATED
HATER
DISSOLVED/
P ARTICULATE
ORGANICS
REMOVAL
/ SHIF: )
I CONDENSATE
Figure 6-2. Process Module for Water Pollution Control (See Figure 6-1 for sources of aqueous wastes)
-------
treatment processes required on a commercial scale. A few of the processes
(e.g., flocculation, biological treatment, and sand filtration) have, however,
been used in low/medium Btu coal gasification facilities, and some data for
these applications are available. A brief description of the processes listed
in Table 6-4 and of evaporation ponds which have some features of all process
modules reviewed follows.
TABLE 6-4. WASTEWATER TREATMENT PROCESSES REVIEWED FOR APPLICATION
TO HIGH BTU GASIFICATION
Oil and Suspended Solids Removal: gravity separation (API separatorsX flota-
tion, coagulation-flocculation, filtration
Dissolved Gases Removal: conventional steam stripping, Chevron WWT, Phosam-W
Dissolved/Particulate Organics Removal: Phenosolvan process, biological oxida-
tion, chemical oxidation, activated carbon adsorption, adsorptive resins
Separated Tar/011 and Sludge Treatment: emulsion breaking, gravity thickening,
centrifugation, vacuum filtration, drying beds
Dissolved Inorganics Removal: ion exchange, reverse osmosis, electrodialysis,
freezing, electrochemical treatment and distillation
6.2.1 Oil and Suspended Solids Removal
Gravity separation is usually the first step in the treatment of most
wastewaters for the removal of bulk separable oil and suspended solids. "API
Separators", which are gravity separators designed in accordance with the cri-
teria suggested by the American Petroleum Institute (API), are widely used in
petroleum refineries for the treatment of oily wastewaters. Gravity separation
is also used following biological or chemical treatment for the removal of bio-
logical and chemical floes. In gravity separation, the wastewater is allowed
to undergo "quiescent settling" in a basin. The oil globules, which are
lighter than water, float to and are collected at the surface; the settleable
solids settle to the bottom and are removed as sludge. The settling basins are
usually rectangular or circular in shape with "accessories" for the introduc-
tion of raw wastewater and collection of effluent, sludge and/or oil. To max-
imize space utilization, the settling basin design may incorporate use of
106
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inclined parallel plates/tubes, each representing a "mini basin" within which
solid-liquid separation takes place. The efficiency of gravity separation
depends on the wastewater characteristics and the hydraulic surface area load-
ing of the basin. The following ranges of removal efficiencies have been
reported for the API separators in refinery oil-water separation applications:
10-50% suspended solids, 50-99% free oil, 5-35% BOD, and 5-30% COD.
The wastewater treatment at the SASOL, South Africa, coal conversion
plant uses (a) API separators for the treatment of the gas refining plant
condensate, (b) tar/oil separators operating on the flotation principle, (c)
flocculation of oily wastewaters from the Fischer-Tropsch oil production and
refining units, and (d) sand filtration for the treatment of the trickling
(5)
filter effluent/ ' No data are currently available on the composition of the
wastewaters handled at the SASOL plant and the performance of the treatment
units.
Although also applicable to and used for the separation of solids heavier
than water, dissolved gas flotation is more widely used in lieu of or as a
supplement to plain gravity separation for the removal of separable oils from
oily wastewaters. Air is dissolved under pressure in a portion of the raw or
treated wastewater or in the entire volume of the raw wastewater. In both
cases, the total wastewater volume is subsequently discharged to an open
basin (the flotation basin) where minute air bubbles which are released
attach themselves to the oil particles and float them to the surface at a
faster rise rate than would be achieved otherwise. The reported data indicate
that without the addition of chemicals, flotation can result in the removal of
70-90% separable oils, 5-25% BOD, 5-20% COD and 10-40% suspended solids. In
designs for the gasification of coal using the Lurgi process, the tar/oil
separators operate on the flotation principle in that the reduction in pres-
sure results in the release of dissolved gases which float oil to the surface
for recovery.
Chemicals such as iron and aluminum salts and polymeric organics are
often added as coagulant aids to improve the efficiency of gravity separation
and flotation operations. When added to wastewaters, these chemical can de-
stabilize colloidal particles and agglomerate fine particles into larger
floes which settle or rise at a faster rate. Particle growth is often
107
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facilitated by gentle mechanical mixing (flocculation). When used in con-
junction with API separators or air flotation units, coagulation-flocculation
can increase removal efficiencies and/or enable higher throughput rates.
When very high levels of oil and suspended solids removal is desired
(e.g., for certain reuse applications), the conventional treatment such as
gravity separation, chemical treatment or biological oxidation may be followed
by filtration through a bed of inert solids such as sand, diatomaceous earth
or anthracite. The suspended solids trapped in the filter are periodically
removed through filter backwashing. As a polishing step for the API separator
effluent, sand filtration has been reported to achieve the following removal
efficiencies: 70-75% suspended solids, 52-83% free oil, 25-44% COD and 36%
BOD.
6.2.2 Dissolved Gases Removal
Certain aqueous wastes (e.g., raw gas quench waters and particulate
scrubber waters) contain high concentrations of dissolved gases such as
ammonia and hydrogen sulfide. Some of these streams would contain smaller
quantities of hydrogen cyanide and carbonyl sulfide. The removal of these
gases (ammonia and hydrogen sulfide) by stripping is the most appropriate
treatment step since it enables recovery of valuable by-products and signifi-
cantly reduces the waste loading on downstream treatment units. Stripping of
dissolved gases can be effected by contacting the wastewater with a stripping
medium such as steam, flue gas, nitrogen, air and carbon dioxide. The most
common stripping medium is steam and the stripping operation is usually con-
ducted in a tower (packed or trays). Acid (for sulfide) or alkali (for
ammonia) may be added to the raw wastewater to improve stripping efficiency.
Steam stripping is widely used in refineries for the treatment of sour waters
containing ammonia and/or hydrogen sulfide. In these applications the stripped
gases are either disposed of by flaring or processed for the recovery of ele-
mental sulfur (in a Claus plant), sulfuric acid, anhydrous or aqueous ammonia
or ammonium sulfate. In many cases, the flaring of stripper off-gases is
being phased out due to S0« and NO limitations. Conventional steam strip-
£ X
ping of the refinery sour water can achieve greater than 99% removal of hLS
and up to 95% removal of NhL. Since low molecular weight phenols are some-
what volatile, sour water stripping can also result in the partial removal
of phenols (up to 70% in refinery applications).
108
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Two patented applications of steam stripping which generate separate con-
centrated H2S and NH3 streams are the Chevron WWT and the USS Phosam W pro-
cesses. In the Chevron process separate towers which operate under different
pressures and temperatures are used for H2$ and NH3 stripping. The residual
H£$ contained in the product ammonia stream is removed by scrubbing the gas
stream with liquid ammonia. The treated gas is then processed to convert the
gaseous ammonia to anhydrous or aqueous ammonia or to ammonium sulfate. The
treated wastewaters from the Chevron process can have residual H2S and ammonia
as low as 5 and 50 mg/1, respectively. The USS Phosam W process which has
been designed for application to coke oven gases, features the circulation of
an ammonium phosphate solution in the upper portion of the stripper to absorb
the ammonia from the product stripping gases, leaving an H«S stream containing
low levels of ammonia. The ammonia rich phosphate solution is steam stripped
in a separate vessel at elevated pressure and temperature, producing an
ammonia rich stream which is subsequently condensed in a fractionating column
to produce anhydrous ammonia. Removal efficiencies of over 99% for both HpS
and NH- are claimed for this process.
The Chevron WWT and USS Phosam W processes have not been employed at
pilot or commercial gasification facilities to date. Conventional steam
stripping with ammonium sulfate recovery, however, has been used at the SASOL
gasification complex.^ ' The USS Phosam W process has been incorporated into
the design of the proposed ANG (North Dakota) SNG plant.' ' A recent engi-
neering study by C. F. Braun and Company^ ' comparing various stripping pro-
cesses for application to coal gasification wastewaters indicate that both
USS Phosam W and the Chevron WWT processes have higher capital and operating
costs than conventional sour water stripping without by-product recovery.
The value of the recovered ammonia, however, significantly offsets the added
cost.
6.2.3 Dissolved/Particulate Orqanics Removal
Depending on the type and strength of a wastewater, a number of processes
are available for dissolved and/or particulate organics removal. These are
Phenosolvan for the extraction of phenols, biological oxidation for the re-
moval of biodegradable organics, chemical oxidation for the destruction of
refractory organics, and carbon adsorption (and adsorptive resins) for the
109
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removal of refractory organlcs. (Coagulation/flocculation for the removal
of inorganic and organic participate matter was discussed in Section 6.2.1.)
Phenosolvan has been developed by Lurgi Mineraloltechnik GmbH specifically
for the recovery of phenols from coal gasification wastewaters. This process
features solvent extraction of the wastewater using butyl acetate, isopropyl
ether or light aromatic oil and subsequent recovery of crude phenol via dis-
tillation of the solvent. To minimize solvent losses to the wastewater, the
"raffinate" is further treated by stripping with nitrogen gas. The process
has been used for the treatment of raw gas quench water (after tar/oil
separation) at several foreign Lurgi gasification facilities. The following
removal efficiencies have been reported for the Phenosolvan process; monohydric
phenols 99.5%, polyhydric phenols 60%, other organics 15%. The sale value
of the recovered phenols has been reported to offset the capital and operating
cost of the process.
In a coal gasification plant, biological oxidation would most likely be
used after the bulk of the organics, reduced inorganics (e.g., H«S, NH3) and
particulate matter have been removed by processes such as gravity separation,
coagulation/flocculation, flotation, Phenosolvan and stripping. In biological
oxidation, the dissolved and/or collodial organics are converted to inorganic
end products and microbial cells by the action of microorganisms. The
resulting biomass (sludge) is subsequently removed by gravity separation.
Although biological oxidation can be conducted under anaerobic (absence of
oxygen) conditions, for most applications aerobic (in the presence of oxygen)
treatment is preferred because of the higher efficiency and lower costs.
(Anaerobic treatment is usually used for concentrated organic wastewaters
and sludges.) Biological treatment is employed widely for the treatment of
industrial wastes and municipal sewage. Table 6-5 lists the most commonly
used biological treatment systems including reported efficiency ranges for the
removal of BOD, COD, SS, oil, phenols and sulfide from refinery wastewaters.
As noted in the table, biological treatment can result in up to 90% removal
of the biologically oxidizable compounds. As will be discussed in Section
6.2.6, although not classified strictly as waste stabilization ponds, evapora-
tion and retention ponds are widely used In industry for ultimate disposal of
110
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TABLE 6-5. EFFICIENCY OF BIOLOGICAL TREATMENT FOR PETROLEUM
REFINERY EFFLUENTS*
Biological Treatment
Method
Activated sludge
Trickling filters
Waste stabilization
pond (aerobic)
Aerated lagoons
Cooling tower
oxidation
Spray Irrigation
BOD
88-90
60-85
40-95
75-95
90+
95+
Parameter"1"
(% Removal )
COD
60-85
30-70
30-65
60-85
90+
90+
Suspended
Solids
_
50-80
2-70
40-65
-
99+
Oil
_
50-80
50-90
70-90
-
70-90
Phenol s
95-99+
-
-
90-99
99.9
99.9
S"
97-100
-
-
95-100
-
99+
*The ranges of values reflect differences in wastewater characteristics and
system design and operating conditions.
+Approximately 70 percent of thiocyanates are removed by these processes.
raw or treated wastewaters, as tertiary treatment basins following biological
treatment or as temporary storage ponds for controlled effluent discharge.
Some biodegradation of organics is achieved in these ponds.
The use of pure oxygen (in place of air) in the biological treatment of
wastewaters by the activated sludge process has received considerable atten-
tion in recent years and a number of pure oxygen activated sludge plants are
currently handling municipal sewage and a variety of industrial wastewaters.
Compared to conventional air activated sludge process, the pure oxygen process
is claimed to have several advantages, including higher efficiency and load-
ing rate, less sludge production, superior settling/thickening characteris-
tics of the sludge, and lower overall costs. The use of the oxygen activated
111
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sludge process in coal gasification plants is especially attractive since such
plants will employ on-site oxygen production and hence a source of oxygen
would be available for wastewater treatment.
Although not specifically designed for biological wastewater treatment,
cooling towers have been used at several refineries for biological treatment
of selected waste streams. The use of cooling towers for biological treatment
has also been demonstrated at the SASOL, South Africa, gasification plant
Cooling towers provide ideal temperatures and surfaces for biological activity.
The oxygen required by microorganisms is provided by the extensive aeration
which accompanies the cooling process. In refinery applications, phenolic
wastewaters have been used as cooling water make-up and more than 99% destruc-
tion of phenols has been reported. In a demonstration program at the Sasol
plant, the ammonia stripper bottoms have been used as cooling tower make-up.
In this program the bio-activity, foaming, fouling and corrosion which may be
expected from the use of this wastewater for cooling water make-up have been
evaluated and the results have been used as a basis for the design of a cool-
ing/oxidation tower system for the proposed El Paso Burnham plant in New
Mexico.'41'
Where soil, climate and hydrological conditions are favorable, biological
treatment may also be accomplished by the application of partially treated
wastewaters to soils. Microbiological processes in the soil can result in
the degradation of most biodegradable organics and the oxidation of ammonia,
sulfide, and other pollutants. In addition, physical adsorption and filtra-
tion can result in the removal and phosphorus and some metallic elements.
Depending on the particular soil, the geographic location, and the rate of
wastewater application, net runoff or percolation may or may not be generated.
Continued application of wastewaters containing high levels of dissolved
solids to soils can result in salinity and/or alkalinity buildup to the point
of adversely affecting plant growth. The accumulation of certain trace ele-
ments and organics in soils may also present toxicity problems for plants or
herbivores. When improperly sited, designed and operated, land application
of wastewaters may present odor problems or result in the contamination of
surface waters and groundwater.
112
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Several factors which affect the applicability and performance of biolog-
ical oxidation for the processing of coal gasification wastewaters are: waste-
water constituent biodegradability, toxicity, pH, nutrient content and
fluctuations in characteristics. As noted previously, organics in coal con-
version wastewaters tend to be highly aromatic. While certain aromatic com-
pounds such as simple phenols are readily degradable (at relatively dilute
levels), the more complex and substituted phenols, polycyclic hydrocarbons
and heterocyclic organics are generally less readily degradable or essentially
non-biodegradable (e.g., pyridine). The biodegradability of the organics in
coal conversion wastewaters is currently under study (see Section 6.5). Some
of the organics (e.g., phenols), trace elements (e.g., arsenic and mercury)
and inorganic anions (e.g., cyanide and thiocyanate) can be toxic to micro-
organisms at high concentration levels. Biological processes are generally
most efficient when the pH of the wastewater is in the 6-8 range. The pH of
the wastewater also affects toxicity of certain wastewater constituents. For
example, the toxicity of sulfide increases with decreasing pH. Nutrients such
as nitrogen (N) and phosphorus (P) compounds are necessary for microbiological
growth. A BOD:N:P ratio of approximately 100:5:1 is generally necessary for
the biological treatment of most industrial wastewaters. When a wastewater
is deficient in nutrients, they must be added to the raw wastewater prior to
biological treatment. Coal gasification wastewaters are expected to have a
sufficient amount of nitrogen (in the form of arrmonia) but be deficient in
phosphorus content. At the SASOL, South Africa, plant where trickling filters
are used for biological wastewater treatment, phosphate is added to the raw
wastewater to allow efficient biological treatment.
In comparison to chemical and physical treatment processes (e.g., acti-
vated carbon adsorption, stripping, etc.), biological processes are signifi-
cantly more sensitive to wide fluctuations in wastewater characteristics.
When such fluctuations are anticipated (e.g., discharge from batch and tran-
sient operations), the biological treatment should be preceded by storage/
mixing facilities for equalization of flow and strength. Certain biological
treatment processes such as the waste stabilization pond, aerated lagoon, and
completely mixed activated sludge process can tolerate limited and short dura-
tion variations in wastewater characteristics since they feature near complete
mixing, or large volume and retention time.
113
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Chemical oxidation processes using oxidants such as ozone and chlorine
compounds have been used in industry for the treatment of cyanide, sulfide
and thiocyanate wastes. Under proper conditions, ozonization may also effect
destruction of biologically refractory organics (or their conversion into
biologically degradable substances). The potential application of chemical
treatment in coal gasification would probably be limited to wastewater polish-
ing after biological treatment. Even for polishing applications, the required
ozone dosage can be high and ozonization may not be cost competitive with the
more conventional treatment processes. Bench scale ozone treatment of Synthane
raw gas quench condensate indicates that complex organics (e.g., quinolines
and indanols) and inorganics (e.g., SCfT) can be largely removed with adequate
ozone dosage.
Both granular and powdered activated carbon have been used for the treat-
ment of industrial and municipal'wastewaters. Being a physical process,
carbon adsorption is unaffected by the presence of toxic constitutents in the
wastewater and the fluctuations in wastewater characteristics.* Granular
carbon is used in fixed or moving columnar beds with either upward or downward
wastewater flow. Powdered carbon is generally mixed with the wastewater and
is subsequently removed by settling and/or filtration. Because of its rela-
tively high cost, the use of activated carbon adsorption for wastewater treat-
ment would generally be limited to (1) removal of residual organics from the
biologically treated effluents, when such removal is necessary; (2) treat-
ment of wastewaters containing high levels of refractory organics or toxic
chemicals; (3) in combination with chemical coagulation and filtration in a
"physical-chemical" combination treatment scheme in lieu of biological treat-
ment; and (4) recovery of by-products (e.g., phenols) from the wastewaters.
Except when used for by-product recovery, the spent carbon is usually regen-
erated by thermal treatment. In polishing of biologically treated refinery
*When granular carbon is used in beds, some biological growth becomes estab-
lished in the bed which contributes to the overall organic removal efficiency
(via biodegradation). In this case the treatment efficiency would be affected
by the presence of toxic chemicals or by wide fluctuations in wastewater
characteristics.
114
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and coke plant wastes, removal efficiencies of up to 80% COD, 90% TOC, and
over 99% phenols have been reported for granular carbon adsorption. Similar
removal efficiencies would be expected for polishing applications to coal
gasification wastewaters. In some gasification processes such as Synthane,
a char is produced which is subsequently gasified/combusted. The Synthane
char has been shown to have adsorption properties similar to that of com-
mercial activated carbons. Even though the char may have a much lower
adsorption capacity than activated carbon, it may provide an economic source
of carbon for wastewater treatment at gasification plants. The spent char
can then be combusted/gasified in the normal manner.
Even though at the present time powdered and granular carbon is the
sorbent of choice for removal of organics, other methods are being developed
as alternatives to carbon or for specialized applications. One of the more
promising of these methods involves the use of macroretricular polymeric
adsorbents such as the Amberlite XAD-8 synthetic resin which have the ability
to sorb organics without any substantial inorganic exchange capacity. The
XAD-8 and similar resins have been successfully used for the decolorization of
Kraft pulp bleaching effluent. The sorptive resins are usually regenerated
by elution with aqueous solutions of proper pH or with organic solvents. The
economics of using sorptive resins for large scale applications have not yet
been demonstrated.
6.2.4 Separated Tar/Oil and Sludge Treatment
The tars and oils separated from wastewaters by gravity separation and/or
flotation still contain a large amount of water (mostly in emulsified form)
which may require removal prior to incineration or processing for by-product
recovery. Emulsions can be "broken" by a number of methods including heating
with or without chemical addition, precoat filtration, distrillation, centri-
fugation, and electrolytic coagulation. It is expected that some of these
methods, particularly heat treatment and distillation, will find application
in commercial SNG facilities for the treatment of tars and oil separated from
raw gas quench waters.
115
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Sludges generated as a result of physical, chemical or biological treat-
ment require further treatment for concentration and volume reduction (dewater-
ing) prior to disposal. In a coal gasification plant, sludges which may re-
quire such treatment include ash quench sludges, sludges from air pollution
control systems and chemical and biosludges from wastewater treatment. Sludge
dewatering is necessary to enable economic land disposal or incineration.
Sludge concentration methods include gravity thickening, centrifugation, vac-
uum filtration, and use of filter presses and drying beds. These methods have
been widely used in municipal and industrial wastewater treatment practice
and considerable experience is available on them in a variety of applications.
Table 6-6 presents reported data on solids concentration levels obtained by use
of various sludge concentrating processes handling chemical and biological
sludges. Chemicals such as lime, ferric salts and synthetic organic polymers
may be added to sludges to improve dewaterability. In general, biological
sludges tend to be more difficult to dewater than inorganic sludges. Biologi-
cal sludges and some concentrated organic wastes can also be further concen-
trated by use of anaerobic digestion whereby a portion of the organic material
is converted to methane, carbon dioxide and soluble by-products. In addition
to the reduction in sludge volume, anaerobic digestion improves sludge
dewaterability and filterability.
6.2.5 Dissolved Inorganics Removal
Several processes are under development for the removal of dissolved
inorganics from wastewaters. These include ion exchange, reverse osmosis,
distillation, electrodialysis, freezing, and electrochemical treatment. These
processes are in varying stages of development and only the first four men-
tioned are given serious consideration as practical processes for large scale
application to wastewater treatment. Key features of these four processes are
listed in Table 6-7. As noted in the table, the ion exchange and membrane
processes (reverse osmosis and electrodialysis) are subject to fouling by
organics. Accordingly, the applicability of these processes for wastewater
processing would be limited to effluent polishing and to wastewater containing
very low levels of organics. For large applications, these processes would
be energy intensive and generate waste brines requiring disposal. Of the
116
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processes listed in the table, distillation would probably be most applicable
to coal gasification wastewaters for recovering water low in total dissolved
solids for use as process or boiler feed water. Some or all of the heat re-
quired for wastewater distillation may be derived from various waste heat
sources within a gasification facility. Some volatile substances in the
wastewater may appear in the distillate and/or the condenser off-gas. Pre-
treatment for the removal of volatiles may thus be necessary.
6.2.6 Evaporation/Retention Ponds
Ponds for temporary or permanent retention of raw or treated wastewaters
(and sludges) are widely used for disposal of industrial and municipal waste-
waters. These ponds, which are referred to as "evaporation ponds," "holding
basins," "lagoons," "oxidation ponds," "settling basins," etc. are usually
natural or man-made earthen reservoirs into which wastewaters are discharged.
TABLE 6-6. SOLIDS CONCENTRATION OBTAINED BY VARIOUS
SLUDGE CONCENTRATING PROCESSES*
Type of Sludge Solids Concentration
Process Processed Obtained (%)
Gravity thickening
Centrifugation
Vacuum Filtration
Drying beds
Activated sludge
Activated sludge
Lime softening sludge
Activated sludge
Primary and activated
sludge
5
6
53
15
•^i
- 8
- 11
- 57
- 20
,Qt
*The ranges of values reflect differences in sludge properties, system
design and operating conditions.
•fAfter 15 days of drying, for one specific application.
117
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TABLE 6-7. FEATURES OF DISSOLVED INORGANICS REMOVAL PROCESSES^42»43»44)
Process
Operating Principle
Major
Existing Application
Advantages
Disadvantages
Ion Exchange
Exchange of nonobjection-
able Ions (e.g., H+, OH")
with objectionable species
(e.g., Ca+2, Mg+2,and F~ In
boiler feed water); resins
are regenerated with acids,
bases or salt solutions
Mater softening.demin-
erallzatlon boiler
water treatment, puri-
fication of chemicals,
material recovery
Efficient and reli-
able process; can
be automated; rela-
tively low operat-
ing cost
Generates waste
brine; most resins
subject to fouling
by organlcs
Reverse Osmosis
Use of semi-permeable mem-
branes and application of <•
pressure to separate water
from dissolved constituents
oo
Dem1neral1zat1on of
brackish waters;
purification of In-
dustrial chemicals
and Pharmaceuticals;
material recovery
Removal of most
wastewater compon-
ents In a single
operation
Generates a concen-
trated waste; mem-
brane subject to
fouling and degrada-
tion; relatively
high energy require-
ments
Electrod1alys1s
Use of anlon- and cation-
permeabable membranes and
an electric field to effect
separation of mineral Ions
from water
Industrial applica-
tions; pilot scale
testing for waste-
water treatment;
dem1neral1zation of
brackish waters
40*50% of the dis-
solved salts can be
removed In a single
pass
Generates a concen-
trated waste; membranes
subject to organic
fouling; limited
experience with
wastewater treatment
Distillation
Application of heat to
evaporate water for
recovery
Brackish and sea
water desallniza-
tlon; industrial
wastewater treat-
ment
Recovered water
low in IDS
Generates a waste brine;
scaling problem; high
energy requirement;
distillate may become
contaminated with vola-
tile substances
-------
These ponds may be lined with impermeable materials (plastic, clay, asphalt,
etc.) to prevent infiltration of the contents into surroundings. Although
liners have been used for industrial waste ponds, the ability of the liner
to retain its integrity over long periods of time has not been established.
The retention of the wastewater in the pond provides for natural evaporation,
settling of solids, biological decomposition of organics and loss of the more
voltaile components of the waste. In geographic regions where annual evapora-
tion exceeds precipitation, the ponds are generally designed to have no efflu-
ent discharge. Ponds can also be used for temporary waste storage and con-
trolled discharge during high flows in the receiving waters. Evaporation/
retention ponds require minimum maintenance and when large land areas are
available, can be the most economical method for wastewater disposal. The
Sasol gasification complex in South Africa uses a settling pond for polishing
treatment of the total plant effluent before discharge into a river. Ponds are
also used at all U.S. coal gasification pilot plants and have been featured
in all proposed designs for commercial SNG facilities in the U.S. Because
of solids accumulation, provisions must be made for periodic removal and
disposal of solids from ponds and/or for ultimate decommissioning of ponds.
6.3 WASTEWATER MANAGEMENT AT INTEGRATED FACILITIES
The types and characteristics of the wastewaters generated in an inte-
grated gasification plant and hence the available options for wastewater
management are determined by a number of factors, the most important of which
are: (a) the specific gasification, gas purification and upgrading operations
employed; (b) the type of coal gasified; (c) the air pollution control and
sludge/solid waste management practices used; (d) the availability and cost
of raw water; (e) the climate, geographical location of the plant and land
availability; and (f) the discharge regulations. Wastewater management in
large industrial facilities such as integrated commercial gasification plants
would provide for wastewater segregation, by-product recovery, wastewater
treatment, water reuse and recycling, and good housekeeping practices. A
brief review of these approaches to wastewater volume and concentration reduc-
tion follows.
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6.3.1 Wastewater Segregation and By-Product Recovery
Separation of dilute and concentrated wastewaters and wastewaters of
significantly different composition can often provide for more effective and
economical treatment and, in some cases, enable cost-effective by-product
recovery (and water reuse/recycle). Most refineries use a system of segregated
sewers for separate collection, transportation and treatment of sour waters,
oily waters, relatively "clean" process waters and storm runoff. Similar
systems of waste segregation are used in existing coal gasification plants
abroad, and are included in the designs for the proposed high Btu commercial
gasification facilities in the U.S. Figure 6-3 is the schematic presentation
of the wastewater management system for the proposed Burnham SNG facility.
The system allows for the separation and separate treatment of the following
streams: tar-rich aqueous condensates, oil-rich aqueous condensate, methana-
tion condensate, and raw water treatment brines, sludges and ash quench water.
The segregation of condensates containing large quantities of organics from
other wastewaters in a gasification plant is especially important in those
facilities which use processes which generate significant quantities of tars
and oils, such as Lurgi. In these facilities, the waste separation enables
recovery of tars and oils from relatively small wastewater volumes and reduces
the load on the downstream processing units. The separated tars and oils may
be incinerated on site as fuel, injected into the gasifier, used for briquet-
ting of coal fines, or sold for chemical recovery or fuel use. In many Lurgi
facilities, wastewater treatment for tars and oils is followed by the Phensol-
van process for the removal of crude phenols. Recovery of tars, oils and
phenols from condensates generates an effluent which can be steam stripped,
alone or in combination with other plant sour waters (e.g., shift condensate),
for the recovery of NH- and H0S. Another example of by-product recovery at a
3 c. •
gasification plant which would be possible through waste segregation and sep-
arate treatment is the recovery of char fines from raw gas quench condensates
(e.g., in the COg-Acceptor process) and/or cyclone slurries (e.g., in the
Hygas process) via settling and dewatering.
6.3.2 Wastewater Treatment
Effluents from by-product recovery operations and raw wastewaters not
suitable for by-product recovery require treatment for the reduction of
120
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EVAPORATION
STEAM STEAM
raoeucr MC.IV
>TIW
FINE ASH POND
LINED EVAPORATION PONDS
Figure 6-3. Proposed El Paso Burnham Gasification Plant Water Management System
(41)
-------
organic content (BOD, COD), suspended solids, reduced inorganic species (SCN~,
S~, NH3), toxic materials (e.g., heavy metals) and dissolved salts. The vari-
ous wastewater treatment processes and their capabilities were reviewed in
Section 6.2. The processes which are in use at the SASOL plant in South Africa
and those which have been proposed for use in the commercial SNG facilities in
the United States are listed in Table 6-8. These processes are generally those
which have been widely employed in the treatment of municipal and industrial
wastewaters and have proved to be economical and reliable. All wastewater
management plans proposed for U.S. commercial gasification facilities are aimed
at achieving zero discharge to surface waters. Accordingly, these plans do
not incorporate the use of advanced wastewater treatment systems such as
activated carbon adsorption, ion exchange and membrane processes for the
removal of potentially troublesome organics and inorganic salts and for the
reduction of total dissolved solids. The use of such processes may be required
if the plant effluents are to be disposed of into natural waters, applied to
soils, or used for certain in-plant uses.
6.3.3 Water Reuse and Recycling and Good Housekeeping Practices
Most of the currently proposed commercial SNG facilities would be located
in the western United States where water is relatively scarce and expensive.
Moreover, to avoid extensive add-on wastewater treatment which may be required
as a result of possibly very stringent effluent limitation guidelines which
may be established in the future, the wastewater management plans for proposed
SNG facilities incorporate a zero discharge concept. To achieve the goal of
zero effluent discharge and to minimize raw water requirements, proposed
designs for these plants provide maximum reuse and recycling of the wastewaters.
Examples of multiple water usage in these facilities are: use of boiler blow-
down, steam and knock-out drum condensates and ammonia stripper bottoms as
cooling water make-up; use of methanation condesates for boiler feedwater; use
of cooling tower blowdown and raw water softening brines as ash quench water
make-up; recycling of the settled raw gas quench water to the quench tower;
recycling of the settled ash quench tower blowdown to the ash transport systems;
and treatment of waste brine by distillation and use of the distillate as
boiler feed water. That portion of the wastewater not reused and recycled
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TABLE 6-8. WASTEWATER TREATMENT PROCESSES USED AT THE SASOL PLANT
AND THOSE PROPOSED FOR USE AT COMMERCIAL FACILITIES IN
THE U.S.
Plant/Process
Wastewater Handled
Sasol Plant
API separation
Flocculation of oil
Trickling filtration
Sand filtration
Settling ponds
Neutralization
Drying beds
El Paso (Burnham, New Mexico
Oxidation tower (cooling
tower)
Gravity Settling
Evaporation pond
WESCO (New Mexico)^
API separation
Air flotation
Biological treatment
Gravity settling
Evaporation pond
Oxidation tower (cooling
tower)
ANG (North Dakota)^10^
Oxidation tower (cooling
tower)
Settling pond
MuHi-effect evaporator
(distillation)
Gravity oil separator
with flocculation
Gas-oil refining condensate
Petrochemical and oil refinery wastes
Combined plant and municipal wastewater
Trickling filter effluent
Ash quench water
Fischer-Tropsch acids
Digested biological effluent
Ammonia stripper bottoms
Ash quench water
Combined plant effluent
Raw gas quench water
API separator effluent
Air flotation effluent
Ash quench water
Combined effluent
Biological treatment effluent
Stripped gas liquor
Ash quench water
Cooling tower blowdown
Runoff from plant areas
123
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would either be disposed of with waste solids or lost as vapor in the cooling
tower or from the evaporation pond. To minimize water wastage and wastewater
generation, it is essential that good housekeeping and water conservation
measures be incorporated in the design of integrated facilities and be observed
during the operation of such plants. Such measures may include elimination
of leaks, routine equipment maintenance and personnel education.
6.4 DATA GAPS AND LIMITATIONS
The data gaps and limitations relate primarily to the characteristics
and treatability of wastewaters from all units in an integrated gasification
facility and to the health and environmental impacts associated with such
wastewaters. The data which are available have been derived from pilot plant
operations in the U.S. and from commercial gasification facilities abroad
which produce fuel gas or chemical feedstocks. Some of the limitations of
the data from domestic pilot plants and from the operation of foreign com-
mercial facilities were discussed in Section 5.4 in connection with air
pollution control. Compared to gaseous waste streams, gasification aqueous
wastes are generally characterized to a greater extent. However, most of these
characterizations are in terms of major constitutents (e.g., phenols, ammonia,
sulfide, etc.) and gross properties (TOC, COD, TSS, TDS, etc.); less data
are available on trace elements, organics and environmental and health
effects.
Waste streams from gasification plants are expected to contain some poten-
tially hazardous substances. Very little data are currently available on the
specific nature and concentration of such substances and on the hazardous
characteristics of effluents containing them. Even though some toxiclty data
are available for some of the substances which are likely to be present in
gasification plant effluents, in many cases such data are for pure substances
and have been obtained in experiments with laboratory test organisms under
controlled conditions. Accordingly, the data generally relate to acute
toxicity and do not reflect potential effects of long-term exposure to low
levels or the synergestic effects which may be associated with a very complex
wastewater. The specific ecological information which appear to be lacking
at the present relate to the biodegradability, bioaccumulability, and the
environmental persistence of the constitutents in the gasification plant
124
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effluents and the potential for the intermedia transfer of such pollutants
(e.g., contamination of soil and water environments by the leachate formed
at land sites used for the disposal of gasification plant ash and sludges).
The major information gaps related to water pollution control pertain
to the effectiveness of the wastewater treatment technologies discussed in
Section 6.2 for the removal of specific pollutants, particularly environmen-
tally important trace elements, orgam'cs and other substances. Although some
processes such as steam stripping and biological treatment have been used for
the removal of bulk volatile orgam'cs, these systems have not been adequately
studied to determine the fate of specific substances and the quality of the
effluent from the standpoint of composition and aquatic toxicity. Many of
the advanced waste treatment processes (such as activated carbon adsorption,
chemical oxidation, ion exchange, chemical precipitation and membrane processes)
which would be suitable for the removal of certain troublesome orgam'cs, trace
elements and inorganic ions have not been tested on coal gasification waste-
waters. . Some of these treatment processes may have to be employed if a very
high effluent quality is dictated by discharge requirements. To date, all
proposed commercial SNG facilities are to be located in areas where evaporation
ponds can be used to eliminate discharge to surface waters. Evaporation ponds
are probably unsuitable for use in facilities located in the eastern U.S. and
hence polishing of the effluent from conventional treatment systems or use
of other treatment alternatives (e.g., distillation) may be required.
The effect of various water reuse and recycling schemes on the fate of
various wastewater constituents has not been investigated. For example, in
cases where treated process waters are used as cooling tower make-up, the
possible losses of volatile orgam'cs and inorganics originally present in the
wastewater or generated as the result of biodegradation of orgam'cs to the
atmosphere are not known. When process wastes (e.g., cooling tower blowdown)
are used for ash quenching, some of the components of the ash may be solu-
bilized. Certain constituents of the input water may also precipitate or
adsorb on the ash/char particles and be partially or totally removed with the
settled ash sludge. The alkaline environment may also induce hydrolysis and
degradation of substances such as cyanide and thiocyanate. These physio-
chemical changes associated with ash quenching and their impact on wastewater
characteristics have not been evaluated.
125
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Because of the lack of knowledge on the effectiveness of various treatment
processes for the removal of specific pollutants, the various possible
sequences of unit treatment processes and reuse/recycling schemes for gasifi-
cation plants cannot be evaluated at this time to determine the overall
treatment efficiencies achievable and associated costs.
6.5 RELATED PROGRAMS
Many of the related programs discussed in Sections 2, 3, 4, and 5 are
expected to generate data on characteristics of wastewaters produced in a
coal gasification facility. One of these program is the DOE coal gasification
environmental assessment programs for pilot plants which is being coordinated
by the Carnegie-Mellon University (CMU). This program has generated and is
expected to generate significant data on the characteristics of various
wastewaters in the DOE pilot plants and on the treatability of such waste-
waters. The program also includes the development and validation of protocols
for effluent sampling and analysis and long-term tests of the performance
characteristics of activated sludge in the processing of Hygas pilot plant
quench condensate samples. In a separate DOE program, the Pittsburgh Energy
Research Center (PERC) is currently conducting biotreatability studies on the
Synthane process raw gas quench condensate samples from the Synthane PDU
at its Pittsburgh facility. A bench-scale activated sludge unit is used for
the biotreatability studies. The use of Synthane char for the adsorption of
organics for the Synthane wastewaters is also being investigated by PERC.
Under a joint DOE-EPA sponsorship, the DOE's Oak Ridge National Laboratory
is working on development and testing of methods for chemical and biological
characterization of effluents from emerging fossil fuel conversion processes.
Several on-going EPA-sponsored programs are aimed at the characterization
of coal gasification effluents and evaluation of waste treatment systems for
application to such effluents. These studies are conducted by the University
of North Carolina at Chapel Hill, Catalytic Inc., Research Triangle Institute
(RTI) and Rudarski Institute (Yugoslavia). The objectives of the University
of North Carolina study are to assess the effectiveness of biological and
chemical processes for the treatment of synfuel wastewaters and to determine
126
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She environmental impacts and health effects of treated effluents. Bench-scale
studies are to be conducted to establish criteria for the design of large-scale
jnits and assessment of performance. The Catalytic Inc. study involves develop-
ment and testing of a methodology for "quick screening" of treatment processes
for coal conversion wastewaters. The program is aimed at shortening the period
of time between problem identification through Level I assessment and final
recommendations for application of control technology. As discussed in
Section 2.6, the RTI study is aimed primarily at gasifier effluent character-
ization and the correlation of gasification conditions with effluent char-
acteristics. The Rudarski Institute program involves environmental sampling
of a Lurgi gasification plant in Pristina, Yugoslavia (the Kosovo plant) -
see Section 2.6.1.
127
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7.0 SOLID WASTE MANAGEMENT
Several process and air and water pollution control modules in an
integrated coal gasification plant generate solid wastes (including sludges)
requiring treatment and ultimate disposal. This section reviews the sources
and characteristics of such wastes and presents a discussion of various
applicable solid waste treatment and disposal methods and waste management
options for use in integrated facilities.
7.1 SOURCES AND CHARACTERISTICS OF SOLID WASTES
Figure 7-1 depicts the process modules generating solid wastes in an
integrated coal gasification facility. There are five major categories of
solid wastes: (1) chars and ashes from the gasification operation and air
pollution control, (2) spent catalysts from shift conversion and methanation,
(3) inorganic solids and sludges from acid gas removal and air and water
pollution control (4) tar and oil sludges, and (5) biosludges from water
pollution control. Of these only ash, spent catalyst and inorganic solids
and sludges would be generated in almost all integrated facilities. The
other types of wastes may or may not be generated in a gasification facility
depending on the gasification process used and wastewater treatment processes
employed. The characteristics of solid waste streams are also expected to
vary from plant to plant depending on the type of coal used, specific pro-
cesses employed and plant design. Since no integrated commercial SNG faci-
lity currently exists, practically no data are available on the quantities
and characteristics of wastes which would be generated in large-scale faci-
lities. The general anticipated characteristics of these and the very
limited data which have been reported for pilot plant and foreign facilities
are reviewed below.
128
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PREPARED
COAL
ro
to
HETHANATION
AND
DRYING
SNG
Figure 7-1. Process Modules Generating Solid Wastes 1n an Integrated High Btu Gasification Facility
-------
7.1.1 Char and Ash
Processes such as Synthane, CO^-Acceptor, Cogas and Hydrane produce a
char which is gasified or combusted externally to the main gasifier. Dusts
containing a significantly high char fraction are also generated in fluidized
and entrained bed processes (e.g., Hygas and Bigas). These dusts are collected
by cyclones (as dry ash) or by venturi scrubbers (as wet sludge). The ashes
which are removed from the bottom of the gasifier (e.g., Lurgi) or the external
char combustor/gasifier (e.g., Cogas gasifier) are quenched with water; the
subsequent settling of the quench slurry produces a wet sludge containing the
bulk of the ash. Except for their wet form, loss of some soluble components,
and contamination with constitutents of the quench water make-up, the char-
acteristics of the solids present in the ash sludge should be essentially the
same as that of dry ash.
As discussed in Section 2.4.3, chars and ashes contain nearly all the
inorganic constituents present in the feed coal. The reported ash and char
carbon content values vary from a few percent to over 50%. Data on elemental
analysis of samples of chars from Lurgi, Synthane, Hygas, Cogas and CCL-
Acceptor processes are contained in the gasification data sheets presented in
Appendix A. When compared to the composition of the feed coals, the char/ash
composition data indicate that the more volatile elements are partially or
totally lost during gasification (see Table 2-7). The carbonaceous material
in chars and ashes is primarily elemental carbon with smaller amounts of highly
polymeric aromatic and heterocyclic orgam'cs. The sulfur species include
pyritic, organic and sulfate sulfur. The residual nitrogen is expected to be
organically bound.
7.1.2 Spent Catalysts
Catalysts used for shift conversion and methanation eventually become
deactivated and require disposal. The design for the proposed commercial SNG
facilities in the U.S. assumes a catalyst life of 6 months to 2 years. In
addition to bulk spent catalyst, dusts containing catalyst particles may be
generated during catalyst decommissioning. Such dusts are collected in the air
130
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pollution control systems used to treat the catalyst decommissioning off-gas.
The shift catalysts are generally cobalt molybdate-based and the methanation
catalysts are nickel-based materials supported on an inert substance such
as alumina or silica. The spent catalysts from both shift conversion and
methanation operations are highly sulfided and contain coal-derived trace
elements (e.g., arsenic, cadmium) and elemental carbon and highly polymeric
organic materials. As discussed in Chapter 4, limited shift and methanation
tests have been conducted on coal-derived gases. Because of the proprietary
nature of the catalysts used in these tests, very little data have been pub-
lished on the detailed composition of the fresh or spent catalyst. Some
data which have been released pertain to catalyst activity rather than to its
composition.
7.1.3 Inorganic Solids and Sludges
Major inorganic solids and sludges include: sludges from S02 emission
control processes, solids (e.g., spent methanation catalyst) and bottom sludges
from acid gas treatment processes, sludges from chemical treatment of the
wastewaters, and perhaps sulfur.
Except for the nature and levels of trace constitutents, the sludges
from SO- emission control at gasification plants are expected to be similar
to those generated in flue gas desulfurization of coal-fired utility and
industrial boiler flue gas or Claus plant tail gas in refineries. The com-
position of a sludge from a specific application is determined primarily by
the control processes used (e.g., lime/limestone slurry scrubbing vs. Chiyoda
Thoroughbred 101). Some reported data on the characteristics of sludges •
from lime/limestone scrubbing, Chiyoda Thoroughbred 101 and magnesium oxide
scrubbing are contained in the data sheets for these processes presented in
Appendix D. Depending on the characteristics of the acid gas and the acid
gas treatment process employed, a sorbent blowdown containing a high concentra-
tion of solids (including possibly some organics) may be produced. The treat-
ment of this stream may generate a sludge requiring disposal. Such a sludge
would most likely contain coal-derived particulate matter, sorbent, and
sorbent degradation products. As currently envisioned, most SNG facilities
would use zinc oxide as methanation guards. The spent guard which essentially
131
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consists of sulfided zinc oxide would constitute a solid waste stream.
Chemicals such as lime or iron and aluminum salts may be used for chemical
precipitation (e.g., of heavy metals) or for coagulation of particulates from
process wastewaters. Such chemical treatments generate a sludge containing
precipitated inorganics (e.g., ferric and aluminum hydrolysis products, other
metal hydroxides, calcium carbonate, etc.) and inorganic and organic particu-
late matter removed from the wastewater.
Elemental sulfur would likely be produced as a by-product in commercial
gasification facilities. Depending on the market conditions, sulfur purity
and location of the plant, the recovered sulfur may not be marketable and
hence would constitute a solid waste requiring disposal. The degree of purity
of the by-product sulfur would depend on feed gas composition and the sulfur
recovery process. When the feed gas contains relatively high levels of hydro-
carbons, the by-product sulfur from the Claus process may contain elemental
carbon. The by-product sulfur from the Stretford and Giammarco-Vetrocoke
processes may be contaminated with vanadium and arsenic compounds, respectively.
7.1.4 Tar and Oil Sludges
Tar and oily sludges are produced in the treatment of oily wastewaters by
gravity separation and/or flotation and in emulsion breaking. Depending on the
system design and the nature of the raw wastewater and emulsions, these
sludges can contain a substantial amount of water. Sludges from the API
separators in petroleum refineries have been reported to contain from 7% to
as much as 98% oil. The characteristics of the organic fraction of the sludge
would be similar to the bulk tars and oils produced in the gasifier (see
Section 2.4.2). Because tars and oils are removed from the raw gas in a
quenching operation, tar and oily sludge would contain high levels of coal-
derived organic and inorganic particulate matter.
7.1.5 Biosludges
When biological processes are employed for the treatment of aqueous
wastes, the degradation of organics and the physical entrapment and settling
of suspended particles produce a "biosludge". Sludges produced in the
activated sludge and trickling filtration processes are settled in the "final"
132
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clarifiers which follow the aeration tank or the filter. In the activated
sludge process a portion of the settled sludge is recycled to the aeration tank
or the filter. In the activated sludge process a portion of the settled
sludge is recycled to the aeration tank and the "excess" sludge is "wasted".
Sludges removed from final clarifiers typically contain 2 to 5% solids with the
solids generally containing 50 to 70% "volatile" matter. When lagoons and
stabilization basins are used for biological treatment, the biological sludge
which is produced, and the settleable matter in the raw wastewater, settle
to the bottom; the degradable material in the settled sludge undergoes aerobic
and/or anaerobic decomposition. Depending on the nature and quantity of the
solids in the raw wastewater and the lagoon design, periodic cleaning of the
lagoons to remove the settled sludge may be necessary. Certain elements (e.g.,
heavy metals) and refractory organics which may be present in the raw waste-
water at relatively low concentration levels tend to concentrate in the
biosludges. High concentrations of such substances in the sludge may eliminate
certain options for sludge disposal (e.g., use as fertilizer on agricultural
soils). Biosludges from refineries have been reported to contain Cr and Zn
values of 540 and 200 mg/kg of dry sludge, respectively.^^ Heavy metal
concentration is specially pronounced when anaerobic digestion is used forthe
stabilization and thickening of "primary" and "secondary" sludges.
7.2 SOLID WASTE DISPOSAL PROCESSES
Figure 7-2 identifies five solid waste management modules/processes for
treatment/ultimate disposal of the major process-related solid wastes in a
coal gasification plant. These are resource recovery, incineration/fuel use,
soil application, land burial/landfilling, and use of evaporation/retention
ponds. A number of other methods, such as ocean disposal and deep well
injection, have been and are being used for the disposal of municipal and
certain industrial sludges. It is very unlikely, however, that these methods
would be used for the disposal of sludges from commercial SNG plants, because
of environmental regulations or geographic factors. The use of evaporation/
retention basins for the containment of industrial wastewaters and sludges
was discussed in Section 6.2.6. The following is a brief discussion of
133
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INORGANIC
SOLIDS
AND
SLUDGES
INCINERATION/
FUEL USE
SOIL
APPLICATION
LAND
BURIAL/
LANDFILLING
(INCLUDING „
PRETREATHEHT)
EVAPORATION/
RETENTION
POND
RESOURCE
RECOVERY
Figure 7-2. Process Module for Solid Waste Management
134
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resource recovery, incineration/fuel use, soil application and land
burial/landfill ing as they may be applied to the disposal of the various types
of solid wastes in a commercial SNG facility.
7.2.1 Resource Recovery
From an environmental standpoint and when applicable, recovery of by-
products from a waste or use of the waste as feedstocks in other processes
would be the most desirable solid waste disposal option. In certain cases the
value of the recovered material offsets the cost of the resource recovery
operation. Examples of resource recovery applications for the management of
waste solids and sludges in a gasification facility include: reclamation of
spent catalysts and solvents; combustion/gasification of chars, tars and oils;
use of ash and inert solids in the production of bricks and glass; and use of
chars as "activated carbon" for wastewater treatment or as fillers in synthetic
rubber.
Processing of spent catalysts (specially those containing precious metals
and chromium, nickel, and zinc) for catalyst rejuvenation or recovery of
metals for reuse is commonly performed in a number of industries (including the
petroleum refinery), and catalyst reclamation is currently an established
industry. Waste solvents can also be processed (e.g., by distillation) for
solvent recovery or incinerated for heat recovery.
Chars with high carbon content (e.g., Synthane char) can be combusted
directly for heat recovery or gasified. The gasification may be carried out in
a separate gasifier (e.g., aKoppers-Totzek or Texaco gasifier) or in the main
gasifier. Depending on the type of gasifier used, chars (as well as coal
fines) may have to be briquetted before feeding into the gasifier. Tars and
oils (and possibly certain process waste solvents and sludges) may also be
used in the production of such briquettes.
When containing little carbon residue, ash can be utilized in a number
of ways which take advantage of its inorganic, inert composition. It can be
used as an ingredient of building bricks, and as mineral filler in the
production of glass and ceramic products. Several processes have been
developed for the use of fly ash in the production of brick. One process
(developed by the U.S. Bureau of Mines) uses approximately 75% fly ash, with
135
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25% slag and 3% sodium silicate as binder. Another process (developed by
Technology Corporation) is reported to be able to use virtually any inorganic
waste material to the extent of 90% to 97%; the balance is Portland cement
and a proprietary "chemical accelerator." High carbon ashes (chars) can be
used in asphalt, as fillers for synthetic rubber, and as a substitute for
commercial activated carbon (see Sections 6.2.3 and 6.5).
Use of coal gasification ash for the production of building and construc-
tion material may be economically unattractive. Gasification plants would
most likely be located away from population centers and hence from major con-
struction activities. Furthermore, if the present supply and demand picture
continues to hold true in the future, an overabundance of such ashes (e.g.,
from power plants) would exist which would exceed the potential demand.
7.2.2 Incineration
Carbonaceous wastes such as tars, oils, chars and dewatered biosludges
can be disposed of by incineration. Depending on the water content of the
feed, the combustion may be self-sustaining and also allow for heat recovery.
Experience with the incineration of refinery wastes indicates that a heating
value of 4000 kcal/1 (30,000 Btu/gal) is necessary for self-sustaining combus-
tion. The operation can be combined with on-site power generation or be
carried out in a separate waste disposal incinerator. Incineration can reduce
the waste to an ash, which because of its small volume and inertness can be
more conveniently disposed of (e.g., in landfills). Incineration has proven
to be very reliable and efficient and has been widely used for the disposal
of a variety of industrial sludges and solids, municipal refuse and biosludges
from the treatment of sanitary sewage. Nearly complete destruction of organics
can be achieved in properly designed and operated incinerators. The operating
temperature and the residence time in the combustion chamber are the two most
important factors affecting destruction efficiency. Depending on the incinera-
tor design and the type of waste to be incinerated, residence time and combus-
tion chamber temperatures may vary from a few seconds to several hours and from
810°K (1000°F) to 1920°K (3000°F), respectively. Compared to land disposal
methods, incineration requires very little space. Except for potential air
136
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pollution problems, which can be controlled by use of good design, afterburners,
and particulate control devices, incineration is the most desirable disposal
option (when resource recovery is inapplicable), especially for the destruction
of hazardous organics. Major types of incinerators which are in commercial
use are rotary kiln, multiple hearth furnace, fluidized bed and multiple
chamber- A "data sheet" on waste incineration is presented in Appendix F.
7.2.3 Soil Application
When large land areas are available and the climate (rainfall, evapora-
tion) and hydrogeological conditions (distance to groundwater; groundwater
flow, type of soil and geological formation) are favorable, some organic and
inorganic sludges may be disposed of by application to soil. The sludge is
applied to the soil by "spreading" or "flooding", is disked under and worked
into the top soil. The organic component of the sludge undergoes biodegrada-
tion in the soil and eventually becomes part of the soil humus. Sludge
disposal by application to soils has been used for the disposal of oily sludges
from production and refining of crude oil and for the disposal of biosludges
from municipal sewage treatment plants. Land disposal of sludge can be used
in conjunction with crop production or as part of a program for the reclamation/
revegetation of lands disturbed by surface mining. Inorganic sludges and
ashes can also be disposed of on land and incorporated into the top soil.
Depending on the soil type, such sludges and ashes can improve soil structure,
reduce acidity, provide plant nutrients, and decrease the availability and
hence toxicity of certain cations. Although tar and oil sludges from
petroleum refineries have been shown to be degradable when applied to soils,
such sludges from coal gasification plants may be more resistant to degradation
in the soil environment due to the highly aromatic nature of the organics in
these sludges. As with the application of wastewaters to soils (see Sec-
tion 6*2*3)-; sites for land disposal of sludges can present an odor problem
or result in the contamination of surface waters and groundwaters, unless
such sites are properly located, designed and operated.
7.2.4 Land Burial/Landfilling (Including Pretreatment)
As discussed here, land burial/landfilling includes both conventional
landfill ing and disposal of wastes in surface and underground mines. The
137
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general pretreatment steps for sludge dewatering and concentration were
—discussed in Section 6.2.4f Pretreatment involving chemical fixation and
encapsulation of sludges prior to disposal in landfills is discussed in this
section.
Chemical fixation (also referred to as cementation, waste passification
or waste immobilization) has been used for the solidification of highly
hazardous industrial wastes prior to disposal by landfilling or land burial.
The objective of chemical fixation is to reduce solubility and chemical reac-
tivity of the waste and hence reduce the potential for the contamination of
ground and surface waters via leachate formation and runoff. Both organic and
inorganic materials have been used as fixing agents. The fixing agents include
asphalt, epoxies, tars, Portland and other lime-based cements, and proprietary
formulations (e.g., in the Chem-fix process). Raw or chemically fixed sludges
can also be encapsulated in plastic, metal or concrete containers or coated
with self-setting resins prior to disposal. Considerable effort is currently
in progress on the amenability of various wastes to chemical fixation and on
the effectiveness of various chemical fixation processes to reduce the leach-
ability of the waste. The chemical fixation processes are generally expensive
and their applications limited to small-volume high-toxicity wastes. An
engineering estimate for the chemical fixation of flue gas desulfurization
sludge including final disposal indicates a cost of $8 to, $13/tonne ($9 to
$14/ton). In coal gasification, the most likely candidate waste stream for
fixation would be the spent catalysts.
In conventional landfill ing (i.e., use of sanitary landfills) the waste
is deposited in layers on land, compacted and covered with a layer of dirt
(see data sheet in Appendix F). JajiitaigLJUjTdfiV^s are widely used for the
disposal of municipal and industrial refuse. Co-disposal of biological waste-
water treatment sludges and municipal refuse is also practiced at a number
of landfills. Provided that adequate measures are taken to reduce potential
for the contamination of ground and surface waters and to minimize nuisance
associated with landfill operation, sanitary landfilling can be an environ-
mentally acceptable and cost-effective method for solid waste disposal. To
minimize the potential for the contamination of groundwater and surface
waters, landfills must be located in areas where the subsurface formation is
relatively impervious to infiltration (e.g., dense clays) and where the
138
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distance to the groundwater table is significantly large. The landfill surface
area should also be properly contoured to divert surface runoff from the site.
When the subsurface formations do not provide adequate barriers against leachate
infiltration, the use of artificial barriers such as plastic, asphalt, concrete
or clay materials for lining the landfill may be necessary. The intercepted
leachate would be pumped to a surface facility for treatment. Observation
wells should also be installed downstream of the landfill site (in the direc-
tion of groundwater flow) to detect leachate migration. When a gasification
plant is located at some distance from the coal mine (see below) and suitable
land is available, conventional landfilling would likely be employed for the
disposal of bulk or chemically fixed solid wastes and sludges.
When transportatinn^n^t«; are not excessive, return of the coal gasifica-
d wastes and sludgesto the coal mines would be an attractive means
for the disposal of such wastes, specially when area surface mining is
practiced. Disposal in surface mines would essentially~be~one form of land-
filling where the overburden material would be used as the cover material.
The operation would be subject to the same restrictions cited above for
sanitary landfills. When coal is mined by deep mining, there would be a
greater time delay before the waste can be deposited in the mine. In the case
of deep mining, the physical operation of returning the waste to the mine
would also be more difficult, requiring certain changes in mine design and
operation to accommodate the space and equipment for returning the wastes.
The return of ash and flue gas desulfurization sludges to the mines would
have the potential benefit of reducing acid mine drainage formation. This
would specially be the case in eastern mines where acid mine drainage is a
major pollution problem.
7.3 SOLID WASTE MANAGEMENT AT INTEGRATED FACILITIES
In comparison with air and water pollution control operations, solid
waste management options in an integrated commercial gasification facility are
more limited and also more plant and site specific. The options for solid
waste disposal are essentially limited to resource recovery, incineration and
land disposal (soil application, landfilling, return to the mine and use of
evaporation/retention ponds). Only a few of the wastes in a gasification
139
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facility (e.g., spent catalysts) lend themselves to resource recovery and it
is very unlikely that this option would eliminate the bulk solid waste dis-
posal requirement. The thermal destruction of wastes at an integrated gasifi-
cation plant should be integrated with the design and operation of the gasifier
and the utility boilers for on-site power generation to maximize energy recov-
ery and minimize overall costs. The land disposal option is by far the most
site-specific option and the selection of specific processes in this option
would depend upon the plant location, transportation cost, hydrogeological
conditions at the site and local environmental regulations. The solid waste
management at an integrated plant is not an isolated problem but rather an
element in the total program for pollution control. The choice of solid waste
disposal methods is affected by the specific processes and options selected
for air and water pollution control.
7.4 DATA GAPS AND LIMITATIONS
In comparison with aqueous and gaseous wastes-for which some composition
and treatability data are available for certain streams, the composition of
solid wastes and hazards associated with the disposal of such wastes are essen-
tially unknown. Some of the operations which would generate solid wastes or
sludges (e.g., biooxidation of aqueous wastes) have never been used in SNG
applications. Even though methanation has been tested for SNG production,
little data are available on the composition of spent catalyst (see Section
7.1.2). The optimum design and operation of incinerators for the combustion
of gasification solid wastes have not been established and the requirements
for the control of emissions from such facilities are unknown. Although some
data have been published on the composition of gasification ash, little is
known about the potential Teachability of such ash when discharged on land
or in landfills.
7.5 RELATED PROGRAMS
Many of the related programs discussed in connection with gasification,
gas purification and upgrading and air and water pollution control are ex-
pected to generate some data on the characteristics of solid wastes in a coal
gasification plant. The most relevant of these programs are (a) an EPA-
funded program for the characterization of coal and coal residue, conducted
140
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by the Illinois State Geological Survey (see Section 2.6.1); (b) DOE's coal
gasification environmental assessment program coordinated by Carnegie-MelIon
University (see Section 2.6.2); and (c) the EPA-DOE program conducted by Oak
Ridge National Laboratory for the chemical and biological characterization of
by-products and aqueous and solid wastes from coal conversion processes (see
Sections 2.6.3 and 6.5).
141
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8.0 SUMMARY OF DATA GAPS AND LIMITATIONS AND RELATED PROGRAMS
As noted In Section 1.0, the first step In the present program for the
assessment of the high Btu coal gasification has consisted of collection and
detailed analysis of the available relevant Information In order to identify
(a) gaps In and limitations of the existing data, (b) additional data required
for the preparation of detailed environmental impact assessments and (c) on-
going and planned programs which might generate some of the needed data. The
data collected on various processes and control technologies which may be
potentially used in an Integrated gasification facility are presented in
Volumes II and III (Appendices) in "data sheet" format and were discussed in
the preceding chapters in this volume. This section summarizes the major gaps
identified in the available data and the most relevant on-going or planned
programs which are expected to generate some of the needed data.
8.1 MAJOR FACTORS RESPONSIBLE FOR DATA GAPS AND LIMITATIONS
The limitations of the available data stem from a number of factors,
most important of which are the following:
• Even though a number of gasification pilot plants have been in
operation in the United States, the operation of these pilot plants
has been aimed primarily at the development of the gasification
process with little emphasis on process and waste stream char-
acterization from an environmental standpoint. The test and eval-
uation of the developmental processes have not generally included
process optimization to minimize pollutant generation or to assess
control technology needs. Even though the final design and
operating practices at commercial facilities and the type of coal
which would be used in such facilities may be different than those
represented by the pilot plant operations, the pilot plant opera-
tions currently provide the best and the only means of acquiring
meaningful environmental data in the United States.
a Except for the Lurgi (dry ash) process which has been used com-
mercially abroad, the high Btu gasification processes are in the
pilot plant or bench-scale development stage. The commercial Lurgi
facilities do not incorporate the downstream processes which would
be employed in a commercial SNG plant.
142
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• Commercial gasification facilities which are in operation in foreign
countries do not generally incorporate design and operating features
which would likely be employed in an SNG facility in the U.S. to
minimize waste generation and to control discharge. Moreover, the
coals used at these facilities differ from those which will be
employed at commercial SNG plants in the U.S.
• Although many of the unit operations for gas processing and pollu-
tion control which may have applications in commercial SNG produc-
tion have been tested or used commercially in other industries,
their performance in SNG service has often not been evaluated.
a Some of the gasification, gas processing and pollution control
processes have been or are being developed by private industry.
Much of the data which may exist for these processes are consid-
ered proprietary and hence not publicly available.
• For many of the unit operations where some discharge stream char-
acterization data are available, such data are not comprehensive
in that not all streams are addressed and not all potential pollu-
tants and toxiciological and ecological properties are defined.
• Even though there has been a long-standing interest in the conver-
sion of coal to liquid and gaseous fuels and a number of coal con-
version facilities have been in operation for some time in other
countries, it is only very recently that there has been a very
strong interest in assessing the environmental aspects of the coal
conversion technologies. This interest stems primarily from two
factors: (1) a growing public concern for environmental protection
as reflected in enactment of environmental laws, and (2) an in-
creased sense of urgency for developing a synthetic fuels industry.
8.2 SPECIFIC DATA GAPS AND LIMITATIONS
Because of the reasons stated above, it is not very surprising to find
a large number of gaps and limitations in the available data. In general,
these data gaps and limitations fall into two categories: (1) total non-
existence or unavailability of the data, and (2) data which are available
lack comprehensiveness or have been obtained under conditions significantly
different than those anticipated in an integrated commercial SNG plant in the
U.S. Examples of data gaps in the first category are the lack of detailed
characteristics data on emissions associated with decommissioning of spent
methanation catalyst, on combined effluent in an SNG plant, and on sludges
resulting from the treatment of such effluent or from the treatment of tar
and oily condensates. Since no integrated SNG facility currently exists, this
type of data is not available from actual operation. Even though environmental
143
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characteristics of SNG plant wastes can be estimated through engineering
studies, to date only a limited number of such studies have been conducted.
In the case of emissions from catalyst decommissioning, even though some data
might exist, such data are not publicly available due to proprietary
considerations.
Examples of the second category of data gaps and limitations are the lack
of trace element and organics data and toxicological and ecological character-
istics data for various waste streams in a gasification plant and data on the
performance of various control systems in SNG service. In comparison with the
very limited amount of data which are available on most gasification processes,
considerable data are available on the characteristics of aqueous wastes from
the Hygas and dry ash Lurgi processes. These data, however, do not cover
organic and trace element constituents, bioassay information, waste treat-
ability and hazardous characteristics such as biodegradability, health effects
and potential for bioaccumulation and environmental persistence. For the
Stretford process, which has been used in refinery and by-product coke applica-
tions for H2S removal from acid gases containing relatively low levels of C02,
limited commercial experience exists with acid gases containing high levels of
C02 which would be encountered in an SNG plant. With the exception of a few
pollution control processes (e.g., flaring for hydrocarbon and H«S control,
venturi scrubbing for particulate removal, Phenosolvan for recovery of
phenols from wastewaters, sour water stripping for NH3/H2S removal and trick-
ling filters for biological treatment), the various air, water and solid
Ataste control processes which would be potentially employed at commercial
facilities have not been used in coal gasification applications. Even for
the few processes which have been used for coal gasification, very little
data are available on the characteristics of the treated streams and on the
jerformance and costs of these applications. Tables 8-1 and 8-2 list the
najor data gaps relating to coal gasification and gas purification and up-
jrading, respectively.
The first category of data gaps can only partially be filled (e.g.,
through engineering analysis) at the present time since SNG facilities do not
jxist and the existing pilot plants do not incorporate all the units or design
:eatures of a large scale facility. Many of the gaps in the second category,
144
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TABLE 8-1. SUMMARY OF DATA GAPS AND LIMITATIONS FOR THE GASIFICATION OPERATION
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TABLE 8-2. SUJWARY OF DATA GAPS AND LIMITATIONS FOR GAS PURIFICATION AND UPGRADING OPERATIONS
Nodule/Process
Shift Conversion
Acid Has Renoval
• Hot ?as H;S ret oval
• Physical solvents
t Chemical solvents (mines)
t Carbonate tolventt
• Nlitd solvents
• Rtdn processes
Methanatlon Guards
Nethanatlon
Feed Gas
Mtjor components
Mil knotm. Addi-
tional data needed
for COS. CS». NNj.
MCN. trace elewnti.
orjantcs and
pa.rtlcv.Utii
Saw is above
Saw as above
Saw as above
Saw as above
Saw as above
Saw as above
Saw as above
Major constituents
well known; no data
on trace sulfur and
nitrogen compounds
1
Treated Gas
aw as t gai
Very Malted data for
H?S. No other data
available
Considerable data on
H,iS and CU; content
tn various applications.
United data available
for trace gases and
organic*, no trace
elewnt data
Sane as above
Considerable data on
H;S and C02 content In
various applications.
United data for trace
oases
1 1*1 ted data on H2S and
CO;. No data on
trace gases
United data on HjS and
CO?. Very little data
on trace gases
United data available
on total suUur and
najor components. No
data available on
trace gases
Major constituents
wel 1 known. Little
known about wtal
carbonyls which nay
be forwd
meets/Discharge Stream
Concentrated Acid Gas
lot applicable
No data available
Sane as treated -ias
Sane as treated <;.i .
Saw as treated -ia-.
Sane as treated
gas
Saw as treated
qas
Not applicable
Not applicable
Aqueous
Condenvale/Blowdowns
Ho data available
Not applicable
NO data .i.oi'jt Ir
No data available
limited data t"
available on com-
position of Benfleld
solution after pro-
longed service In
coal gasl f ualion.
Ouantltle-. of Jn.1 vr-H-1
constituents 1n blow-
down (If any) Are not
known
No data available
no actual operating
c
No data available.
(Not applicant if'
sow processes )
No data available;
clean condensate
Solid u.itf.
Sludges/By- >'r, • •„ t .
for spent 'atalysls
No data available
Do data available
No data available
'10 data available
No data available
No actual operating
a a ava a e
Ho data available
physical properties of
spent catalyst. No
data on trace elewnts.
orqanlcs or toilclty
Coinents
rr> r-lnor -us constituents
"M tnown
MM IMS H^S r«r.l,vJll IS In
stai^
•tnl i th* ^ectisnl ! rrt f.'.
*&'. littn e^l'-'''' In ioa'
'la^ 1 f teat lo" i !'' ' i '• ' ' "•
to latf
inly toe O'J nrwe'.-.
ha-, been te^tfl 'n crdt
gasification service
The Benfleld process has
been comwrclally used
for add las removal 1n
cojl qaslflcatlon service
A Sulflnol unit has been
used In a gasification
facility In Turkey, but no
operating data ire available
Available data for the
nalnly fro* conceptual designs
rather than actual operation.
Neither the Stratford nor the
CU'rarco-vetrocoke
process has been used In coal
qaslf Icat Ion
Hethanatlon guards have not
been employed in coal gasifi-
cation applications to date
Only flied bed ^ethanatlon
Is sufficiently well tested
for SNG production at present.
Essentially nothing Is known
about emissions resulting
from catalyst deconlsslonlnq
-------
however, can be and should be filled through multimedia environmental sampling
and analysis of the process/discharge streams at pilot plants and foreign
gasification facilities, through bench-scale studies and through engineering
analysis. Even though some ot the unit operations and conditions in the
gasification pilot plants are not scalable to or representative of commercial
facilities, and in the absence of such comnercial facilities, sampling at the
pilot plants represents the best and the only means of acquiring meaningful
data on process and waste stream characteristics and on the performance of
various processes. Such sampling and analysis programs, coupled with related
engineering studies and bench-scale testing, can provide valuable and timely
input to the evolution of the SNG industry and would assure that (1) environ-
mental considerations are included in the selection of processes, equipment
and waste management options for commercial SNG plants and (2) the drafting
of New Source Performance Standards for SNG facilities are based on sound
technical and engineering data. Several programs are currently under way or
planned which Involve testing/sampling at pilot plants, bench scale units, or
foreign commercial facilities. The more Important of these and related engi-
neering studies are summarized below.
8.3 RELATED PROGRAMS
Major programs which are expected to generate some of the data needed
for high Btu gasification environmental assessment fall into three categories:
EPA-sponsored programs, DOE-sponsored programs, and miscellaneous programs.
The EPA- and DOE-sponsored programs are listed in Tables 8-3 and 8-4, respec-
tively. Very limited data are available on the programs in the miscellaneous
category which are primarily carried out under private funding. Of the EPA
programs, the one most directly related to the high Btu gasification is the
TRW environmental assessment effort for which the preparation of this docu-
ment has been the first step. As mentioned in Section 1.0, the TRW program
includes the acquisition of data through sampling and analysis of process/
waste streams at selected gasification facilities. In this connection, TRW
contacted DOE, private process developers in the U.S., and commercial facili-
ties overseas. Initial steps have been taken to develop test programs for
these facilities. TRW has also been in contact with DOE to obtain unpublished
environmental data and to obtain access to DOE facilities for sampling and
147
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TABLE 8-3. SUMMARY OF SOME ERA-SPONSORED PROGRAMS
Project Title
Contractor
Objective
Status and Future Activities
oo
Environmental Assessment
of High Btu Gasification
Environmental Assessment
of Low/Medium Btu
Gasification
Environmental Assessment
of Coal Liquefaction
Control Technology for
Products/By-Products
Pollutants Identification
from a Bench-Scale Unit
Haste Stream Disposal
and Utilization
Characterization of Coal
and Coal Residues
Water Treating Bench
Scale Unit
Acid Gas Cleaning
Bench Scale Unit
General Support
Control Technology for
Participates and Tar
Emissions
TRM. Inc.
Redondo Beach, Ca.
Radian Corporation
Austin, Texas
Hlttmn Associates
Columbia, Hd.
Catalytic. Inc.
Philadelphia. Pa.
Research Triangle Institute
Research Triangle Park
No. Carolina
Pullman-Kellogg
Houston, Texas
Illinois State Geological
Survey
Urbana. 111.
University of No. Carolina
Chapel Hill, No. Carolina
No. Carolina State Univ.
Raleigh. No. Carolina
Cameron Engineers, Inc.
Denver, Colo.
Hydrocarbon Research, Inc.
ftorrlstown, N. J.
Environmental assessment of high Btu gasification.
Including Identification of control technology
needs.
Environmental assessment of low/medium Btu gasi-
fication, Its utilization, and definition of
control technology needs.
Environmental assessment of coal liquefaction
technology and definition of control technology
needs.
Development and testing of methodology for "quick-
screening* of treatment processes for synfuels
wasteMaters.
Semi-quantitative determination of chemical
species In gasification effluents as a function
of gasification conditions and kinetic data on
rates of species formation.
Identification and assessment of control tech-
nologies for waste utilization and disposal
associated with fuel conversion technologies.
Characterization of the chemical, physical and
mineral properties of coals, coal by-products
and wastes; Investigation of the effects of
pyrolysls on trace element distribution and
providing data on solubilities and toxldtles of
species In coal wastes.
Assessnent of the effectiveness of various
biological/chemical treatment processes, and
detemlnatlon of the environmental Impacts and
health effects of treated effluents.
Construction and operation of a general purpose
coal gasification/gas cleaning facility-
Preparation of -Multi-media Environmental Control
Engineering Handbook."
Determination of ultimate fate of particulates and
tars, estimation of costs of alternate control
technologies, and development of a prlorltlzation
R&D plan for particulates and tar control tech-
nology.
Data base document prepared. Prepara-
tions for sampling/analyses at domestic and
foreign facilities underway.
Data base document has been prepared; Radian
is providing technical assistance during
environmental testing currently being con-
ducted at 4 gasification facilities.
Data base document prepared, summarizing data
on 14 liquefaction processes and discussing
four processes (SRC, H-Coal, Exxon Donor Solvent
and Syntholl) more thoroughly.
Preliminary evaluation of mobile test facility
housing bench-scale equipment for studying coal
conversion systems completed.
Lab-scale gasification reactor designed and
operated with coke and 111. No. 6 bituminous
coal. Sampling train for gaseous and liquid
samples, and analytical techniques under
development.
As a first step, general definition of all
potential environmental problems associated
with synfuels processes has been performed,
and Information on the composition and quantity
of typical discharge streams gathered. Waste
treatment technologies currently being studied.
Data generated on chemical form of trace ele-
ments In coal, char; pyrolysls studies con-
ducted; toxlclty and bloassay studies of coal
solid wastes conducted. Additional pyrolysls,
toxlclty and leaching studies planned.
Bench-scale studies being Initiated 1n order
to establish criteria for design of large-
scale biological/chemical treatment units.
Activated sludge reactors recently tested.
Program is 1n Initial stages. Evaluation of
4 absorption solvents for add gas removal
processes (e.g., Rectlsol, Benfleld, HEA and
Selexol) to be conducted.
Approximately 35 device-specific data sheets
completed.
Literature search 1n progress to characterize
particulates and tar emissions from various
coal converters.
-------
TABLE 8-4. SUMMARY OF SOME DOE-SPONSORED PROGRAMS
Contractor
Objective
Status and Future Activities
Carnegie-Mellon University
Pittsburgh, Pa.
Pilot Plants Environmental
Sampling and Analysis Programs
• Hygas, Institute of Gas
Technology
• C0,-Acceptor, Radian
Corporation
Synthane, Pittsburgh
Energy Research Center
Slagging gaslfler,
Grand Forks Energy
Research Center and
Sterns-Roger, Inc.
Bigas, Phillips Petroleum
and Penn Environmental
Consultants
Pittsburgh Energy Research
Center
Pittsburgh. Pa.
Oak Ridge National Laboratory.
Oak Ridge, Tenn.
Argonne National Laboratory
Argonne, Illinois
Battelle-Paclflc Northwest
Laboratories, Richmond, Va.
C. F. Braun 4 Co.
Alhambra. Ca.
Consortium of companies
headed by Conoco. Inc.
in cooperation with British
Gas Corporation
To provide overall coordination and
evaluation for DOE pilot plant
environmental assessment program;
to develop sampling and analysts
protocols.
Sampling and analyses of various
process/waste streams; development
of sampling and analysis protocols.
Sampling and analysis of various
process/waste streams.
Sampling and analysis of various
process/waste streams.
Sampling and analysis of various
process/waste streams.
Sampling and analysis of various
process/waste streams.
To determine blotreatabllHy of
Synthane wastewaters.
To determine and assess potential
environmental/health problems
associated with coal conversion.
To analyze trace organlcs at pilot
plants using gc/ms; also, to per-
form biological characterization of
various sample fractions from pilot
plants.
To characterize products/wastes
from synfuels processes.
To serve as evaluation contractor
for joint DOE-AM gasification
assessment program.
Slagging gasifier testing at
Hestfleld. Scotland. Results of
tests to serve as basis for the
design of a slagging Lurgi gasi-
fication demonstration plant in
the U.S.
Ten specific program tasks. Including
development/validation of sampling and
analytical procedures, and studies on
treatabillty of process effluents, are
under way.
Sampling and analysis perfor»ed sine* mid-
1976; extensive data generated. Sampling
and analysis planned for raw product gas.
Batch and continuous leaching tests to be
performed on Hygas char. Additional data
to be generated for high carbon conversion.
Testing to continue through 1978.
Comprehensive test program prepared and
executed prior to shutdown 1n 1977.
Numerous gas phase and wastewater analyses
performed. Results soon to be published.
A process/waste stream sampling and analysis
program 1s under way. Performance of Benfleld
and Stretford process units to be assessed.
Analyses performed and results reported on
the composition of product gases, conden-
sates and slag produced with lignite feed.
Similar data to be collected for other coils.
Limited sampling/analysis of selected
Bigas condensates performed. Testing
under steady state conditions has been
hampered by operating difficulties with
the gasifier.
A bench-scale activated sludge unit has been
constructed and operated. Use of Synthane
process char as adsorbent for wastewater
organics also being Investigated. Testing
to continue.
A number of studies have been proposed and
some Implemented relating to Industrial"
hygiene/safety, epidemiologlcal studies,
and pollutant monitoring techniques. Pro-
gram to characterize trace element and
organic composition of solid wastes at a
Lurgi facility under way. Also, program for
the development of short-ter* genettc bio-
assay for characterization of complex efflu-
ents and chealcal mutagen Identification 1s
under way.
Programs recently Initiated. Effluents
from high and low/medium Btu gasification
operations to be studied, beginning with
condensates from the Hygas pilot plant.
Limited sampling and analysis conducted at
CCb-Acceptor pilot plant; effluents from
LERC In-situ coal gasification facility
analyzed. Data soon to be made public.
A number of engineering studies are being
conducted, including programs on manage-
ment of sulfur emissions In commercial
gasification facilities.
The 3-year program has Involved modification
of a Lurgi gasifier and Its operation under
slagging conditions. Ohio No. 9 and
Pittsburgh No. B coals have been tested.
149
-------
analysis. A number of unpublished documents have already been received from
DOE and DOE has agreed to have TRW review and comment upon its sampling and
analysis programs for Hygas and Synthane pilot plants and to provide TRW with
selected samples from these two pilot plants.
DOE synthetic fuel pilot and demonstration programs include sampling and
analysis at various facilities, bench-scale studies of process and environ-
mental data acquisition, and related environmental engineering studies.
150
-------
9.0 REFERENCES
1. Synthetic Fuels, Quarterly Report, Cameron Engineers, Inc., Volume 15,
No. 1, March 1978, 150 p.
2. Detman, R., Preliminary Economic Comparison of Six Processes for Pipeline
Gas from Coal, C. F. Braun & Co., Alhambra, Ca., presented at Eighth
Synthetic Pipeline Gas Symposium, Chicago, Illinois, October 30-November
1, 1976, 21 p.
3. Handbook of Gasifiers and Gas Treatment Systems, Dravo Corporation,
FE-1772-11, February 1972.
4. Synthetic Fuels, Quarterly Report, Cameron Engineers, Inc., Volume 14,
No. 3, September 1977, 200 p.
5. Information provided by South African Coal Oil and Gas Corp. Ltd., to
EPA's Industrial Environmental Research Laboratory, Research Triangle
Park, November 1974.
6. Savage, P. R., Slagging Gasifier Aims for SNG Market, Chemical Engineer-
ing, September 12, 1977, p. 109-109.
7. El Paso Coal Gasification Project, New Mexico, Final Environmental
Impact Statement, Vols. I and II, Bureau of Reclamation, U.S. Dept. of
Interior, Washington, D.C., DES No. 77-4, February 1977, 1200 p.
8. Dunn Center, No. Dakota Gasification Project, No. Dakota, Draft Environ-
mental Assessment Report, Bureau of Reclamation, U.S. Dept. of Interior,
Washington, D.C., 1977, 1000 p.
9. Western Gasification Company (WESCO) Coal Gasification Project, Final
Environmental Impact Statement, Bureau of Reclamation, U.S. Dept. of
Interior, January 14, 1976, 1500 p.
10. ANG Coal Gasification Company, North Dakota Project, Final Environmental
Impact Statement, Bureau of Reclamation, U.S. Dept. of Interior,
Washington, D.C., INT-DES 77-11, March 17, 1977, 1000 p.
11. Information provided to TRW by Roger Moore, El Paso Natural Gas Co.,
June 27, 1978.
12. Information provided to TRW by J. Woodin, Texas Eastern Transmission
Co., June 27, 1978.
151
-------
13. Information provided to TRW by Gary Weinrich, American Natural Resources
Co., June 30, 1978.
14. How to Finance Gas Produced from Coal, Business Week, June 19, 1978,
p. 33-36.
15. Synthetic Fuels, Quarterly Report, Cameron Engineers, Inc., Volume 14,
No. 4, December 1977, 145 p.
16. Davis, J. C., Caution Marks Progress in Coal-Conversion Plan, Chemical
Engineering, October 10, 1977, p. 77-80.
17. Information provided to TRW by Dr. Ray Zahradnik, Occidental Research
and Development Co., July 28, 1978.
18. Burchard, J. K., Annual Report, 1976 - Industrial Environmental Research
Laboratory. Office of Research and Development, U.S. EPA, Research
Triangle Park, No. Carolina, 1976, p. 134-5.
19. Shimp, N. F., Characterization of Coal and Coal Residue, University of
Illinois, Illinois State Geological Survey, Urbana, Illinois, Monthly
Progress Summaries (PR-1), September 1977-July 1978.
20. Environmental Review of Synthetic Fuels, Industrial Environmental
Research Laboratory, Research Triangle Park, No. Carolina, Vol. 1, No. 1,
January 1978, 9 p.
21. Corbett, W. E., Low-Btu Gasification - Environmental Assessment, Radian
Corporation, Austin, Texas, presented at the EPA Third Symposium on
Environmental Aspects of Fuel Conversion Technology, Hollywood, Florida,
September 13-16, 1977, 21 p.
22. Massey, M. J., R. W. Dunlap, et al, Analysis of Coal Wastewater Analyt-
ical Methods: A Case Study of the Hygas Pilot Plant, Carnegie-Mellon
University, Pittsburgh, Pa., ERDA FE-2496-3, February 1977, 63 p.
23. Anastasia, L. J., Environmental Assessment of the Hygas Process,
Quarterly Progress Reports, Institute of Gas Technology, Chicago,
Illinois, ERDA FE-2433-1 through 20, August 1976 to March 1978.
24. Massey, M. J., R. W. Dunlap, et al, Characterization of Effluents from
the Hygas and C02-Acceptor Pilot Plants - Interim Report July - September
1976, Carnegie-Mellon University, ERDA Contract E(49-18)-2496, November
1976, 109 p.
25. Massey, M. J. and D. V. Nakles, ERDA's Coal Gasification Environmental
Assessment Program: A Status Report, Carnegie-Mellon University,
Pittsburgh, Pa., presented at the Ninth Synthetic Pipeline Gas Sympos-
ium, Chicago, Illinois, October 31-November 2, 1977, 18 p.
152
-------
26. Lewis, R., J. P. Strakey, et al, Update of Synthane Pilot Plant Status,
U.W. Department of Energy, Pittsburgh, Pa., presented at the Ninth
Synthetic Pipeline Gas Symposium, Chicago, Illinois, October 31-
November 2, 1977, 9 p.
27. Ellman, R. C., B. C. Johnson, et al, Current Status of Studies in Slag-
ging Fixed-Bed Gasification at the Grand Forks Energy Research Center,
GFERC, ERDA, Grand Forks, No. Dakota, presented at 9th Biennial Lignite
Symposium, Grand Forks, No. Dakota, May 18-19, 1977, 41 p.
28. Gehrs, C. W., Coordinator, Coal Conversion: Description of Technologies
and Necessary Biomedical and Environmental Research, Oak Ridge National
Laboratory, Oak Ridge, Tenn., ORNL-5192, July 1976, 304 p.
29. Epler, J. L., Genetic Toxicity Testing of Complex Environmental Effluents,
Oak Ridge National Laboratory, Oak Ridge, Tenn., presented at Symposium on
Land Disposal of Hazardous Waste, San Antonio, Texas, March 5-8, 1978.
30. Truchter, J. S., M. R. Petersen, et al, Characterization of Substances
in Products, Effluents and Wastes from Synthetic Fuel Development Pro-
cesses, Battelle-Pacific Northwest Laboratories, Richmond, Washington,
BNWL-2224, January 1977, 13 p.
31. Information provided to TRW by Wyman Harrison, Argonne National Labora-
tories, Argonne, Illinois, June 1, 1978.
32. Information provided to TRW by Mr. Robert Verner of DOE, July 24, 1978.
33. Atkins, W. T., Problems Associated with Controlling Sulfur Emissions
from High-Btu Coal Gasification Plants, C. F. Braun & Co., Alhambra, Ca.,
FE-13, December 1976, 39 p.
34. Fleming, D. K. and H. S. Primak, Purification Processes for Coal Gasifica-
tion, Institute of Gas Technology, Chicago, Illinois, presented at 81st
National AIChE meeting, Kansas City, Mo., April 11-14, 1976, 34 p.
35. Tennyson, R. N. and R. P. Schoof, Guidelines Can Help Choose Proper
Process for Gas-Treating Plants, The Oil and Gas Journal, January 10,
1977, p. 78-85.
36. Christensen, K. G. and W. J. Stupin, Acid Gas Removal in Coal Gasifica-
tion Plants, C. F. Braun & Co., Alhambra, Ca., presented at Ninth Syn-
thetic Pipeline Gas Symposium, Chicago, Illinois, October 31-November 2,
1977, 20 p.
37. Control of Emissions from Lurgi Coal Gasification Plants, EPA Office of
Air Quality Planning and Standards, EPA 450/2-78-012, OAQPS 1.2-093,
March 1978.
153
-------
38. Dvorak, A. J., et al, The Environmental Effects of Using Coal for
Generating Electricity, Argonne National Laboratory, NUREG-0252, June
1977.
39. Information provided to TRW by Mr. Russell Purrussel of Pittsburgh and
Midway Coal Mining Co., Ft. Lewis, Washington SRC Pilot Plant, July 17,
1978.
40. Bonhan, J. W. and W. T. Atkins, Process Comparison Effluent Treatment
Ammonia Separation, ERDA FE-2240-19, June 1975.
41. Milios, P., Water Reuse at a Coal Gasification Plant, Chemical Engin-
eering Progress, Vol. 71, No. 6, p. 99-104, June 1975.
42. Dascher, R. E. and R. Lepper, Meeting Water Recycle Requirements at a
Western Zero Discharge Plant, Power, Vol.121, No. 8, August 1977, p. 23.
43. Kremen, S., Reverse Osmosis Makes High Quality Water Now, Environmental
Science and Technology, Vol. 9, No. 4, April 1975, p. 315.
44. Current Status of Advanced Waste-Treatment Processes, July 1970, Advanced
Waste-Treatment Research Laboratory, The Federal Water Quality Adminis-
tration, Cincinnati, Ohio.
45. Rosenberg, D. G., et al, "Assessment of Hazardous Waste Practices in the
Petroleum Refining Industry, EPA Office of Solid Waste Management, SW-
129c, June 1976.
154
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TECHNICAL REPORT DATA
(Please read /aumctions on the reverse before completing)
1. REPORT NO. 2 "~ ""
EPA-600/7-78-186a
4. TITLE AND SUBTITLE Environmental Assessment Data Base
for High-Btu Gasification Technology: Volume I.
Technical Discussion
'. HUTHOHtS)
1\ .Ghassemi, K.Crawford, and S.Quinlivan
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TRW Environmental Engineering Division
One Space Park
Redondo Beach, California 90278
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION- NO.
5. REPORT DATE
September 1978
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
EHE623A
11. CONTRACT/GRANT NO.
68-02-2635
13. TYPE OF REPORT AN.D PERIOD COVERED
Final: 6/77 - 8/78
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTESJERL-RTP project officer is William J. Rhodes, Mail Drop 61,
919/541-2851.
is.
of a comprehensive EPA program for the environmental
assessment (EA) of high-Btu gasification technology. It summarizes and analyzes the
existing data base for the EA of technology and identifies limitations of available data.
Results of the data base analysis indicate that there currently are insufficient data for
comprehensive EA. The data are limited since: (1) there are no integrated plants , (2)
some of the pilot plant data are not applicable to commercial operations , (3) available
pilot plant data are generally not very comprehensive in that not all streams and
constituents /parameters of environmental interest are addressed, (4) there is a lack
of experience with control processes/equipment in high-Btu gasification service, and
(5) toxicological and ecological implications of constituents in high-Btu gasification
waste streams are not established. A number of programs are currently under way or
planned which should generate some of the needed data. The report consists of three
volumes: Volume I summarizes and analyzes the data base: Volume U contains data
sheets on gasification, gas purification, and gas upgrading; and Volume ffl contains
data sheets on air and water pollution control and on solid waste management.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Croup
Pollution
Coal
Coal Gasification
Assessments
Pollution Control
Stationary Sources
Environmental Assess-
ment
High-Btu Gasification
13B
21D
13H
14B
18. DISTRIBUTION STATEMEN1
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
169
20. SECURITY CLASS (This pagfl
Unclassified
22. PRICE
EPA Form 2220-1 (9-73J
155
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