oEPA
United States
Environmental Protection
Agency
Industrial Environmental Research EPA-600/7-80-093
Laboratory May 1980
Research Triangle Park NC 27711
Environmental
Assessment Report:
Wellman-Galusha Low-Btu
Gasification Systems
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into 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.
EPA 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-600/7-80-093
May 1980
Environmental Assessment
Report: Wellman-Galusha
Low-Btu Gasification Systems
by
Pat Murin, Theresa Sipes, and G.C. Page
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78766
Contract No. 68-02-2147
Exhibit A
Program Element No. INE825
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
ABSTRACT
This Environmental Assessment Report (EAR) for Wellman-
Calusha low-Etu gasification systems was prepared as part of an
overall environmental assessment program for low/medium-Btu gasi-
fication technology. The purpose of this EAR is to provide EPA
Administrators and Program Offices with a document that repre-
sents the Office of Research and Development's (ORD's) research
input to standards support for Wellman-Galusha gasification fa-
cilities. This EAR represents a detailed evaluation and presen-
tation of process, control, and waste stream data collected from
field testing programs, open literature, vendors, process licen-
sors, and computer modeling activties.
An overview of Wellman-Galusha gasification systems is
presented, including estimates of the system's energy conversion
efficiencies and capital and operating costs. Data characteriz-
ing the system's input materials, process streams, products, by-
products, and multimedia discharges are provided. Pollution con-
trol alternatives for the multimedia discharges and toxic sub-
stances in the system's products and by-products are identified
and their costs and energy impacts estimated.
Regulatory requirements for and environmental impacts of
Wellman-Galusha systems were assessed. Data needs and recommen-
dations for obtaining those data are presented, along with a dis-
cussion of the EPA Program Office's issues and areas of concern
for Wellman-Galusha low-Btu gasification technology.
ii
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TABLE OF CONTENTS
ABSTRACT ii
LIST OF FIGURES v
LIST OF TABLES vi
ACKNOWLEDGMENT xv
1.0 SUMMARY 1
1.1 Overview of Wellman-Galusha Low-Btu
Gasification Systems 1
1.2 Waste Streams and Pollutants of Major
Concern 12
1.3 Status of Environmental Protection
Alternatives 19
1.4 Data Needs and Recommendations 29
1.5 Issues and Areas of Concern by Program
Offices 31
2.0 WELLMAN-GALUSHA GASIFICATION SYSTEMS 37
2.1 Wellman-Galusha Gasification Systems:
Technology Overview 37
2.2 Description of Processes and Systems 48
2.3 Process Areas of Current Environmental
Concern 106
3.0 CHARACTERIZATION OF INPUT MATERIALS, PRODUCTS,
AND WASTE STREAMS 112
3.1 Summary of Sampling and Analytical
Activities 112
3.2 Input Materials 128
3.3 Process Streams 137
3.4 Toxic Substances in Product and By-Product . . 140
3.5 Waste Streams to Air 153
3.6 Waste Streams to Water 167
3.7 Waste Streams to Land 174
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TABLE OF CONTENTS
(Continued)
Pat
4.0 PERFORMANCE AND COST OF CONTROL
ALTERNATIVES 190
4.1 Procedures for Evaluating Control
Alternatives 190
4.2 Air Emissions Control Alternatives 190
4.3 Water Effluent Control Alternatives 198
4.4 Solid Waste Control Alternatives 209
4.5 Toxic Substances 216
4.6 Summary of Most Effective Control
Alternatives 217
4.7 Regional Considerations Affecting
Selection of Alternatives 217
4.8 Summary of Cost and Energy Considerations . ... 220
5.0 ANALYSIS OF REGULATORY REQUIREMENTS AND
ENVIRONMENTAL IMPACTS 223
5.1 Environmental Assessment Methodologies .... 223
5.2 Impacts on Air 236
5.3 Impacts on Water 248
5.4 Impacts of Land Disposal 252
5.5 Product Impacts 257
5.6 Radiation and Noise Impacts 259
5.7 Summary of Major Environmental Impacts .... 260
6.0 SUMMARY OF NEEDS FOR ADDITIONAL DATA 265
APPENDIX: NOMENCLATURE, STRETFORD DESIGN BASIS,
TRACE ELEMENT PREDICTIONS, ATMOSPHERIC DISPERSION
MODEL 270
REFERENCES 284
iv
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LIST OF FIGURES
Number
1.1-1 Wellman-Galusha System Process Modules
and Multimedia Discharges 2
2.2-1 Wellman-Galusha System Process Modules
and Multimedia Discharges 61
2.2-2 Wellman-Galusha Gasification System
Producing a Hot Removal Product Gas
from Anthracite and Low-Sulfur
Bituminous Coals 63
2.2-3 Wellman-Galusha Gasification System
Producing a Clean Product Gas from
Anthracite Coal 64
2.2-4 Wellman-Galusha Gasification System for
Producing a Clean Product Gas from Lignite
and Low- and High-sulfur Bituminous Coal .... 65
2.2-5 Wellman-Galusha Gasification System for
Producing a Clean Product Gas (with MEA
and Gas Removal) from High-Sulfur Bituminous
Coal 66
2.2-6 Diagram of a Wellman-Galusha Gasifier
Equipped with a Coal Bed Agitator 92
2.2-7 Schematic Flow Diagram for the Stretford
Sulfur Removal Process 100
2.2-8 Schematic Flow Diagram for the MEA Acid
Gas Removal Process 103
3.1-1 Flow Diagram for Glen-Gery Gasification Facility. 114
3.1-2 Bureau of Mines Wellman-Galusha Facility,
Fort Snelling, Minnesota 118
3.1-3 Simplified Process Flow Diagram for the Chapman
Facility Showing Emission Streams 123
4.2-1 Typical Flow Diagram - Glaus Sulfur Recovery
Process 195
v
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LIST OF TABLES
Number Page
1.1-1 Operations/Process Modules in Wellman-Galusha
Low-Btu Gasification Systems 3
1.1-2 Current Wellman-Galusha Coal Gasification
Facilities in the United States 6
1.1-3 Past Users of Gas Produced by Wellman-Galusha3
Gasifiers 8
1.1-4 Calculated Energy Efficiencies for Various
Uncontrolled Wellman-Galusha Gasification
Systems 11
1.1-5 Capital Investment Requirements and Annualized
Costs of Uncontrolled Wellman-Galusha Gasifica-
tion Systems Producing Nominally 17.6 MW (60 x
106 BTU/HR) of Product Low-Btu Gas (Late-1977
Dollars)3 13
1.1-6 Capital Investment Requirements and Annualized
Costs of Uncontrolled Wellman-Galusha Gasifica-
tion Systems Producing Nominally 87.9 MW (300 x
106BTU/HR) of Product Low-Btu Gas (Late-1977
Dollars)3 14
1.2-1 Gaseous Waste Streams and Pollutants of Major
Concern from Wellman-Galusha Low-Btu Gasifica-
tion Systems 15
1.2-2 Liquid Waste Streams and Pollutants of Major
Concern from Wellman-Galusha Low-Btu Gasifica-
tion Systems 16
1.2-3 Solid Waste Streams and Major Pollutants of
Concern from Wellman-Galusha Low-Btu Gasifica-
tion Systems 17
1.2-4 Potential Toxic Streams and Compounds of Major
Concern for Wellman-Galusha Low-Btu Gasifica-
tion Systems 18
1.3-1 Summary of Most Effective Emission, Effluent,
Solid Wastes, and Toxic Substances Control
Alternatives 21
1.3-2 Summary of Major Costs and Energy Consumption
of Alternative Control Methods 23
1.3-3 Comparison of Predicted Pollutant Concentrations
to the NAAQS and State of Texas H2S Ambient Air
Standard 26
vi
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LIST OF TABLES
(Continued)
Number Page
1.3-4 Liquid Effluents from Wellman-Galusha Low-Btu
Gasification Systems 28
1.3-5 Solid Wastes from Wellman-Galusha Low-Btu
Gasification Systems that will be Regulated
by the RCRA 30
1.4-1 Summary of Waste Stream Characterization and
Control Data Needs and Planned Activities to
Obtain Those Data 32
1.4-2 Process and Process Stream Data Needs and
Planned Activities to Obtain Those Data .... 33
1.5-1 EPA Program Office Data Needs 35
2.1-1 Current Wellman-Galusha Coal Gasification
Facilities in the United States 38
2.1-2 Past Users of Gas Produced by Wellman-Galusha
Gasifiers 41
2.1-3 Classification of Industrial Processes with
Respect to Ease of Retrofit for Low-Btu Gas . . 42
2.1-4 Estimated Costs for a 73.3 MW (250 Million Btu/
Hr) Coal Gasification Plant Using Fixed-Bed
Atmospheric Pressure Gasifiers 49
2.1-5 Estimated Costs for Coal Gasification Plants
Containing One, Five, or Ten Fixed-Bed
Atmospheric Pressure Gasifiers3 50
2.2-1 Coal Composition Examined3 52
2.2-2 Raw Product Gas Compositions Resulting from
the Gasification of the Four Selected Coals . . 53
2.2-3 Product Gas Specifications Selected for
Environmental Assessment 56
2.2-4 Sulfur Removal Requirements to Attain Product
Specifications for Gases Produced from Four
Selected Coals 58
2.2-5 Operations/Process Modules in Wellman-Galusha
Low-Btu Gasification Systems 62
2.2-6 Stream Compositions and Flow Rates for Wellman-
Galusha Gasification Systems (Figure 2.2-2)
Producing 17.6 MW of Hot Product Gas from Anthra-
cite Coal 67
vii
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LIST OF TABLES
(Continued)
Number
2.2-7 Stream Compositions and Flow Rates for Wellman-
Galusha Gasification Systems (Figure 2.2-2)
Producing 17.6 MW of Hot Product Gas from Low-
Sulfur Bituminous Coals 68
2.2-8 Stream Compositions and Flow Rates for Wellman-
Galusha Gasification Systems (Figure 2.2-3)
Producing 17.6 MW of Clean Product Gas from
Anthracite Coal 69
2.2-9 Stream Compositions and Flow Rates for Wellman-
Galusha Gasification Systems (Figure 2.2-4)
Producing 17.6 MW of Clean Product Gas from
Lignite Coal 72
2.2-10 Stream Compositions and Flow Rates for Wellman-
Galusha Gasification Systems (Figure 2.2-4)
Producing 17.6 MW of Clean Product Gas from Low-
Sulfur Bituminous Coal 75
2.2-11 Stream Compositions and Flow Rates for Wellman-
Galusha Gasification Systems (Figure 2.2-4)
Producing 17.6 MW of Clean Product Gas from
High-Sulfur Bituminous Coal 78
2.2-12 Stream Compositions and Flow Rates for Wellman-
Galusha Gasification Systems (Figure 2.2-5)
Producing 17.6 MW of Clean Product Gas from
High-Sulfur Bituminous Coal (MEA Process
Operating Pressure of 0.44 MPa, 50 psig) .... 81
2.2-13 Stream Compositions and Flow Rates for Wellman-
Galusha Systems (Figure 2.2-5) Producing 17.6 MW
of Clean Product Gas from High-Sulfur Bituminous
Coal (MEA Process Operating Pressure of 1.5 MPa
or 200 psig) 83
2.2-14 Calculated Energy Efficiencies for Various
Uncontrolled Wellman-Galusha Gasification
Systems ! T 87
2.2-15 Capital Investment Requirements and Annualized
Costs of Uncontrolled Wellman-Galusha Gasifica-
tion Systems Producing Nominally 87.9 MW (.300 x
106BTU/HR) of Product Low-Btu Gas (Late-1977
Dollars) a 88
2.2-16 Capital Investment Requirements and Annualized
Costs of Uncontrolled Wellman-Galusha Gasifica-
tion Systems Producing Nominally 17.6 MW (60 x 106
BTU/HR) of Product Low-Btu Gas (Late 1977
Dollars)a 89
viii
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LIST OF TABLES
(Continued)
Number Page
2.2-17 Efficiency Range of "Conventional" Cyclones . . 95
2.3-1 Gaseous Waste Streams and Pollutants of
Major Concern from Wellman-Galusha Low-Btu
Gasification Systems 107
2.3-2 Liquid Waste Streams and Pollutants of Major
Concern from Wellman-Galusha Low-Btu
Gasification Systems , . . , 108
2.3-3 Solid Waste Streams and Pollutants of Major
Concern from Wellman-Galusha Low-Btu
Gasification Systems 109
2.3-4 Potential Toxic Streams and Compounds of Major
Concern for Wellman-Galusha Low-Btu Gasifica-
tion Systems 110
3.1-1 Multimedia Waste Streams from the Glen-Gery
Wellman-Galusha Gasification Facility* .... 116
3.1-2 Waste and Process Stream Sampled at the Glen-
Gery Wellman-Galusha Gasification Facility* . . 117
3.1-3 Multimedia Waste Streams from the Bureau of
Mines Wellman-Galusha Gasification Facility* . 120
3.1-4 Waste and Process Streams Sampled at the
BOM Wellman-Galusha Gasification Facility* . . 121
3.1-5 Multimedia Waste Streams from the Chapman
Gasification Facility* 125
3.1-6 Waste and Process Streams Sampled at the
Chapman Gasification Facility* 126
3.2-1 Input Material Requirements for the Gasifica-
tion Operation in Wellman-Galusha Systems
Producing 17.6 MW of Low-Btu Gasa 129
3.2-2 Coal Composition Data 130
3.2-3 Reported Average Trace Element Compositions
of U.S. Coals* 132
3.2-4 Input Material Requirements for the Stretford
Sulfur Removal Process 134
3.2-5 Estimated Make-Up Chemical Requirements for
MEA Process3 136
ix
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LIST OF TABLES
(Continued)
Number Page
3.3-1 Compositions of Raw Low-Btu Gas Exiting
a Wellman-Galusha Gasifier 138
3.3-2 Concentrations of Trace Elements in
Jacket and Service Water at the Glen-Gery
Wellman-Galusha Gasifiera 139
3.3-3 Water Quality Parameters of Quench Liquor
at Chapman Gasifier 141
3.3-4 Organic Compounds Found in a Chapman
Gasification Facility Quench Liquor 142
3.3-5 Trace Element Concentrations Found in a
Chapman Gasification Facility Quench
Liquor 143
3.4-1 Trace Element Concentration (By SSMS) in
the Product Gas from a Wellman-Galusha
Gasifier Using Anthracite Coal 146
3.4-2 Predicted Equilibrium Trace Element
Distributions 148
3.4-3 Composition of Low-Btu Product Gases
After Stretford 150
3.4-4 Composition of Low-Btu Product Gas from
High-Sulfur Bituminous Coal After Treatment
in MEA 151
3.4-5 Ultimate Analyses of By-Product Tar 152
3.4-6 Organic Compounds Identified in the Tar
Produced from a Chapman Facility Using
Bituminous Coal 154
3.4-7 Trace Elements (3y SSMS) in the By-Product
Tar Produced from Low-Sulfur Bituminous
Coal 155
3.4-8 Bioassay Test Results for the Tar Produced
from a Chapman Facility Using Low-Sulfur
Bituminous Coal 156
3.5-1 Composition of Coal Feeder Gas from the Glen-
Gery Wellman-Galusha Gasifier* 157
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LIST OF TABLES
(Continued)
Number
3.5-2 Organic Compounds Identified in the Separator
Vent Stream from a Chapman Gasification Facility
Using Low-Sulfur Bituminous Coal 160
3.5-3 Trace Elements (By SSMS) Found in the Separator
Vent Stream from a Chapman Gasification Facility
Using Low-Sulfur Bituminous Coal 161
3.5-4 Water Quality Analyses on the Separator Vent
Condensable from a Chapman Gasification Facility
Using Low-Sulfur Bituminous Coal 162
3.5-5 Caseous Components Found in the Separator Unit
Stream from a Chapman Gasification Facility
Using Low-Sulfur Bituminous Coal 163
3.5-6 Bioassay Results of the XAD-2 Resin Extract of
the Separator Vent Gases from the Chapman
Facility Using Low-Sulfur Bituminous Coal .... 164
3.5-7 Acid Gas from MEA Unit Purifying Gas from
High-Sulfur Bituminous Coal 166
3.6-1 Trace Element Concentration (by SSMS) of Ash
Sluice Water and Ash Leachate 168
3.6-2 Water Quality Parameters for the Ash Sluice
Water and Ash Leachate from the Glen-Gery
Wellman-Galusha Gasification Facility* 169
3.6-3 Results of Bioassay Tests on the Ash Sluice
Water and Ash Leachate from the Glen-Cery
Wellman-Galusha Gasification Facility 170
3.6-4 Bioassay Test Results for the Quench Liquor
from a Chapman Gasification Facility Using
Low-Sulfur Bituminous Coal 172
3.6-5 Quantity and Composition of Stretford Slowdown. . 173
3.7-1 Analyses of Ash 175
3.7-2 Trace Elements in Gasifier Ash from Gasification
of Anthracite and Low-Sulfur Bituminous Coals . . 176
3.7-3 Radioactive Disintegration Data for Ash
Produced from the Glen-Cery Wellman-Galusha
Gasification Facility 177
3.7-4 Concentrations of Extractable Organics and
Compounds Identified in the Ash Prodsuced from
the Gasification of Anthracite and Low-Sulfur
Bituminous Coal 177
xi
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LIST OF TABLES
(Continued)
Number Page
3.7-5 Trace Element Concentrations in the Ash
Leachate from the Gasification of Anthracite
Coal 179
3.7-6 Eioassay Results of the Ash from the Gasification
of Anthracite and Low-Sulfur Bituminous Coal. . . 180
3.7-7 Ultimate Analysis of Cyclone Dust 181
3.7-8 Trace Elements in Cyclone Dust 182
3.7-9 Trace Element Concentrations of Particulates
Collected by the Cylone and Those not Collected
for the Gasification of Anthracite Coal 183
3.7-10 Radioactive Disintegration for the Cyclone
Dust from the Glen-Gery Wellman-Galusha
Gasification Facility 184
3.7-11 Extractable Organics Found in the Cyclone Dust
from the Gasification of Anthracite and Low-
Sulfur Bituminous Coals 184
3.7-12 Trace Element Concentrations in the Cyclone
Dust Leachate from the Gasification of Anthracite
Coal 185
3.7-13 Bioassay Test Results for the Cyclone Dust from
the Gasification of anthracite and Low-Sulfur
Bituminous Coals 187
3.7-14 Ey-Product Sulfur from Stretford Process3 .... 188
3.7-15 Estimated Blowdown from MEA Acid Gas Removal
Process 189
4.2-1 Costs for Stretford and Glaus Processes
Treating an Acid Gas Produced from the
Purification of a Kigh-Sulfur Coal Gas 199
4.3-1 Costs for the Containment and Treatment of
Process Condensate in a Centrally-Located
Hazardous Waste Treatment Facility3 203
4.3-2 Costs for the Evaporation of Process Condensate
in Single-Effect Vertical Tube Evaporators . . . 204
4.4-1 Costs for Land Disposal of Gasifier Ash 213
4.4-2 Estimated Costs for Land Disposal of Recovered
Sulfur 215
4.5-1 Emission Factors for S02 Produced During the
Combustion of by-Product Tars and Oils 216
xii
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LIST OF TAELFS
(Continued)
Number
4.6-1 Summary of Most Effective Emission, Effluent,
Solid Wastes and Toxic Substances Control
Alternatives3 218
4.8-1 Summary of Major Costs and Energy Consumption
of Alternative Control Methods 221
5.1-1 MEG Values Bases for Discharge and Ambient
Level Goals 226
5.1-2 MEG Chart for 2-Aminonaphthalene 227
5.1-3 Model for Translating TLV's and NIOSH
Recommendations into AMEG Values Based on
Health Effects for Exposure to a Compound in the
Ambient Air 230
5.1-4 Proposed Bioassay Test Matrix for Samples
Collected During Environmental Sampling and
Analysis Programs 234
5.2-1 Most Stringent Emission Standards 238
5.2-2 National Ambient Air Quality Standards (40 CFR
Part 50) 239
5.2-3 Performance Guidelines for Lurgi Gasification
Plants 240
5.2-4 Stack Parameters for Model Plants 244
5.2-5 Emission Parameters for Model Plants, g/s .... 245
5.2-6 Maximum Down Wind Concentrations for Model
Gasification Plants 246
5.2-7 Percentage Contributions of t^S, CO, and NHj
from the Separator Vent Stream to the Calculated
Maximum Ground-Level Concentration3 247
5.2-8 Bioassay Results for Coal Feeding and Separator
Vent Cases 249
5.3-1 Most Stringent Water Effluent Standards 251
5.3-2 Components with DS's>l and Priority Pollutants
Identified in the Quench Liquor from a Chapman
Facility Using Low-Sulfur Bituminous Coal .... 253
5.3-3 Bioassay Test Results for Ash Sluice Water and
Process Condensate 254
5.7-1 Liquid Effluents from Wellman-Galusha Low-Btu
Gasification Systems Exceeding the Most
Stringent Effluent Standards and DMEG Values . . 262
xiii
-------
LIST OF TABLES
(Continued)
Number
5.7-2 Solid Wastes from Wellman-Calusha Low-Btu
Gasification Systems that could be Regulated
by the RCRA 264
6-1 Summary of Waste Stream Characterization and
Control Data Needs and Planned Activities to
Obtain those Data 266
6-2 Process and Process Stream Data Needs and
Planned Activities to Obtain those Data 267
6-3 EPA Program Office Data Needs . 268
A.3-1 Species Considered in Free Energy Minimization
Program 280
A.3-2 Comparison of Observed and Predicted Trace
Element Volatilization in the Coed Process. . . . 282
xiv
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ACKNOWLEDGMENTS
The authors wish to express their thanks to
W.C. Thomas, J.A. Reego, and E.A. Baker for their contri-
butions to this report. Guidance and review by W.J. Rhodes
and T.K. Janes of EPA/IERL-RTP also aided significantly in
the successful completion of this report.
xv
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SECTION 1.0
SUMMARY
This Environmental Assessment Report (EAR) for Wellman-
Galusha low-Btu gasification systems was prepared as part of an
overall environmental assessment program for low/medium-Btu
gasification technology. The purpose of this EAR is to provide
EPA administrators, Program Offices, and Policy and Planning with
a document that represents the Office of Research and Develop-
ment's (ORD's) research input to standards support for Wellman-
Galusha gasification facilities. This EAR represents a detailed
evaluation and presentation of process, control, and waste stream
data collected from field testing programs, open literature,
vendors, process licensors, and computer modeling activities.
1.1 OVERVIEW OF WELLMAN-GALUSHA LQW-BTU GASIFICATION SYSTEMS
Wellman Galusha gasifiers are one of the commercially
available gasifiers used to produce low-Btu (^5.9 MJ/Nm^ or 150
Btu/scf) gas from a variety of coal feedstocks. The Wellman-
Galusha gasification systems examined in this report are de-
scribed in the following subsections along with discussions of
their status of development, industrial applicability, commercial
prospects, energy efficiency, and capital and operating costs.
1.1.1 System Description
Wellman-Galusha low-Btu gasifictaion systems have three
basic operations: coal pretreatment, coal gasification, and gas
purification. In each operation, there are processes with spe-
cific functions, inputs, and outputs. Figure 1.1-1 is a gener-
alized flow diagram showing the operations and process modules
for the Wellman-Galusha gasification systems considered in this
report. Table 1.1-1 summarizes the input and output streams and
the function associated with each process.
Four gasification systems, as shown in Figure 1.1-1,
were considered in this study. The first system is typical of
what would be required to produce a "moderately clean" industrial
fuel from a low-sulfur coal feedstock. This system has only
three process modules: coal handling and storage, gasification,
and particulate removal (hot cyclone). This system also repre-
sents currently-operating Wellman-Galusha facilities that use
anthracite and low-sulfur bituminous coals.
A variation of the first system has an additional pro-
cess module: raw gas quenching and cooling. This additional
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Figure. 1.1-1. Wellman Galusha System Process Modules and Multimedia Discharges
-------
TABLE 1.1-1. OPERATIONS/PROCESS MODULES IN WELLMAN-GALUSHA
LOW-BTU GASIFICATION SYSTEMS
Operation/Process Module
Coal Pretreatment
Coal Handling
and Storage
Input Streams
Presized coal
Output Streams
Presized coal
Coal dust
Function
Store and transport
coal feedstock
Remarks
Coal storage piles would contain a 30 day coal
supply (2-12 Gg, 2000-13,000 short tons of coal
Coal Gasification
Fixed-Bed, Atmospheric
Pressure, Dry Ash
Gaslfler - Vellman-
Galusha
Gas Purification
Partlculate Renoval -
Hot Cyclone
Gas Quenching
and Cooling
Tar/011 Removal
Electrostatic
Preclpltator
Sulfur Removal
Stretford
Presized coal
Steam
Air
Ash sluice water
Raw product gas
Product gas
Quenching liquor
Cooled product gas
Sulfur Removal -
Monoethanolamlne
Process
Detarred product gas
Stretford solution
Air
Detarred product gas
MEA solution
Coal pile runoff water
Raw product gas
Coal hopper gases
Fugitive gases
Start-up vent gases
Ash
Ash sluice water
Product gas
Removed partlculates
Quenched/cooled
product gas
Quench liquor
Tars
Oils
Partlculate matter
Cooled/detarred
product gas
Tars
Oils
Clean product gas
Oxidlzer vent gas
Sorbent blowdown
Sulfur
React coal with a
mixture of steam and
air to produce a raw
low-Btu gas
Remove large part leu-
late natter from the
hot, raw product gas
Remove tars and oils
from the product gas
and cool the product
gas to approximately
316"K (110'F)
Remove tar and oil
aerosols from the
cooled product gas
Remove H2S fron the
detarred product gas
Clean product gas
MEA blowdown
Acid gases
Sulfur from acid gas
treatment processes
Tall gases from acid
gas treatment processes
Remove sulfur species
and CO2 from the
detarred product gas
for a plant producing 18-88 MW, 60-300 million Btu/
hr of low-Btu gas).
Coals that have been used Include anthracite and
bituminous. Coal size specification'; are 7.9 to
14.3 mm for anthracite and 26-51 ram for bituminous.
Larger particle sizes can be used for more reactive
coals.
Total particulate removal efficiencies have been
determined to be between 50-80Z. Small particulate
matter will not be removed. Collected particulates
have characteristics similar to devolatllized coal
particles.
The amount of tars and oils removed is dependent
upon the coal feedstock. Anthracite coal will pro-
duce essentially no tars, however, bituminous coal
will produce a significant amount of tars.
Emissions from the tar/liquor separator may contain
potentially hazardous compounds. Spent quench
liquor will require treatment before disposal.
ESP*s have been used to remove tars and oils pro-
duced by two-stage, fixed-bed, atmospheric gaslflers
and good removal of tars and oils have been demon-
strated by ESP's used in sampling systems.
Vent gases from tar/oil storage tanks may contain
potentially harmful compounds and nay need to be
controlled.
Organic sulfur species (i.e., COS, CS2, etc) will not
be removed from the product gas. If the HCN concen-
tration is high, then a cyanide guard may he needed.
Blowdown sorbent will require treatment before dis-
posal. If the sulfur Is to be disposed of, tests
need to be performed (i.e., RCRA tests for solid
wastes) to determine treatment and/or disposal tech-
niques required.
Removal efficiency increases with increasing inlet
gas pressure. Acid gases have to be treated to
control sulfur emissions. MEA blowdown will require
treatment before disposal.
-------
nodule removes tars and oils from the raw product gas and reduces
the potential of fouling equipment used to transport the low-Btu
product gas to its end use. This system also is capable of
producing a "moderately clean" industrial fuel gas from a low-
sulfur coal feedstock. It is similar to a facility using Chapman
(Wilputte) gasifiers to produce a low-Btu combustion gas for
process heaters.
The second Wellman-Galusha gasification system is used
to produce a "clean" industrial fuel gas from anthracite coal.
This system contains the following process modules: coal hand-
ling and storage, gasification, gas quenching and cooling, and
sulfur removal. In this system, the product gas is cooled to
316 K (110°F) before entering the sulfur removal process. Two
sulfur removal processes are considered in this report:
Stretford and Monoethanolamine (MEA) processes. If a Stretford
sulfur removal process is used, only H2S will be removed,
leaving or-ganic sulfur species (e.g., COS, CS£) in the product
gas stream. H2S removal efficiencies of greater than 99% have
been achieved with residual outlet F^S concentrations less than
10 ppmv. If the MEA process is used, both H2S and organic
sulfur compounds can be removed. However, the sulfur removal
effectiveness is dependent upon the pressure of the product gas.
For example, at 0.34 MPa (50 psi) residual E^S concentrations
of 8 ppmv can routinely be achieved, while at a higher pressure
of 0.69 MPa (100 psi), residsual H2S levels can be reduced to 4
ppmv. The MEA process also produces an acid gas stream that
requires further treatment.
The third system is used to produce a "clean" industrial
fuel gas from the following coal feedstocks: bituminous (low-
and high-sulfur) coal and lignite. In this system, the quenched
and cooled product gas is sent to a tar/oil removal process fol-
lowed by a sulfur removal process. An electrostatic precipitator
(ESP) is used to remove tars and oils that would cause operating
problems with the downstream sulfur removal process. As in the
second system, the Stretford and MEA processes were chosen for
the removal of sulfur species in order to produce a "clean"
industrial fuel gas.
The fourth system is very similar to the third system.
The major difference is that only the MEA process is used for re-
moving sulfur species. By compressing the gas to approximately
1.5 MPa (200 psi), the MEA process can remove essentially all
sulfur compounds and produce a "very clean" product gas.
-------
1.1.2 Status
Uellman-Calusha gasifiers have been commercially avail-
able since 1941. Approximately 150 gasifiers have been installed
worldwide. In the U.S., eleven Wellman-Galusha gasifiers are
currently being used to produce a low-Btu gas from anthracite and
low-sulfur bituminous coals. Table 1.1-2 summarizes the loca-
tions, processes, and coal feedstocks for each plant.
1.1.3 Industrial Applicability
Wellman-Galusha gasification systems have been used to
provide a low-Btu fuel gas and a synthesis gas for ammonia pro-
duction. A summary of past applications is given in Table 1.1-3.
In the near term, Wellman-Galusha gasifiers will be used
primarily to produce a fuel gas for on-site use, including:
• fuel to provide direct heat for processes such as
brick and lime kilns, and
• fuel for industrial boilers.
Production of gas for off-site use will probably not be signifi-
cant because of the cost of transporting atmospheric pressure,
low-Btu gas.
1.1.4 Commercial Prospects
Many industries either must have or prefer a gaseous
fuel to meet their energy requirements. In the near term, low-
Btu gas from fixed-bed, atmospheric pressure gasifiers like the
Wellman-Calusha will be used primarily as a substitute fuel by
industries threatened with natural gas curtailments. The low-Btu
gas will principally be considered for use as a fuel in on-site
furnaces, heaters, kilns, and small boilers. Its substitution
for natural gas will most likely occur when: 1) the costs of
retrofitting for use of the low-Btu gas are small, and 2) the
low-Btu gas requires minimal purification.
In both new and retrofit applications where use of a
gaseous fuel is not mandatory, low-Btu coal gasification is
mainly competing with the alternative of direct coal combustion.
Factors affecting the selection of coal gasification or direct
coal combustion include: the suitability of the coal conversion
technology for satisfying the specific end use, the cost of the
technology, the cost and difficulty of retrofitting, the cost of
environmental controls, and the cost of the coal.
-------
TABLE 1.1-2. CURRENT WELLMAN-GALUSHA COAL GASIFICATION FACILITIES IN THE UNITED STATES
Gaalfler (toed
Wellman-Galueha
Hallman-Galusha
Wallman-Galuaba
Uellmao-Caluaha
Hallman-Calueha
Wellman-Galusha
Wellmaa-Caluaha
Coal Feedstock
Anthracite, low
•ulfur OX). 7)
Anthracite, low
•ulfur
Anthracite, low
•ulfur
Bltuminoua, low
•ulfur (M). 71)
Anthracite, low
•ulfur
K( Bituminous
CO Subbltuminous
NT Bituminous
•D Lignite
Bltumlaoua, low
•ulfer
Gaa Purification
Processes
• Cyclone
• Cyclone
• Cyclone
• Cyclone
• Cyclone
• Gaa Quench
• Cyclone
• Gas Quench
• Tar/Liqoor separation
• Cyclone
• Possibly gaa quench,
Company /Location
Glen-Gery Brick Co.
- York, PA
- Reading, PA
- Shoemakersvllle. PA
- Watson town, PA
- Hew Oxford, PA
Bazelton Brick Co.
- Hazel ton, PA
Blnghamton Brick Co.
- Blnghamton, HI
National Lima 6 Stone Co.
- Gary, OH
Can Do, Inc.
- Haxeltoo, PA
Bureau of Nine*
- Ft. Snelllng, Ml
Pike County
- rlkeriUe. KT
•umber of
Gasifiers Remarks
8 * Currently in commercial operation
• Product gas used to fire brick kiln
4 • One gasifler in use
• Three other gasiflera inactive
• Product gaa used to fire brick kiln
2 • Gasiflers not currently in use
1 • Currently in commercial operation
• Product gaa used to fire lime kiln
• Line will remove some of the sulfur
apecies in the flue gaa
2 • To be completed in 1980
• Product gas to be used in an
industrial park
• Possibility of adding two more
gaslfiera
• Partial funding by DOC
1 • Comercial-size demonstration unit
• Partial funding by DOE
• First series of teat runs completed
in 1978
• Additional tests conducted in 1979
• Product gaa was used to fire an
iron palletizing kiln
• Excess product gas we* combusted
2 • To be completed in 1982
• Product gaa used to fire boilers
tar/liquor aaparatlon,
waatewater treatment
and sulfur remove!
(St ret ford)
and process heater*
Partial funding by DOB
-------
TABLE 1.1-2. (CONTINUED)
Gaslfler Used
Vellasn-Galusha
Chapman (Hilputte)
Coal Feedstock
Anthracite, low
sulfur (-V.0.7Z)
Bituminous, low
sulfur (-V0.6I)
Gas Purification
Process**
• Cyclone
• Cyclone
• G&s quench
Company /Location
Hovmet AluBlmm
- Lancaster, FA
Hols ton Any Ammunition Plant
- Klngsport, HI
Huaber of
Gasifiers
1
12
Remarks
• to be completed In early 1980
• Product gas used to fire process
furnaces
• Possibility of adding up to eleven
•ore gaslfiers
• Currently In commercial operation
• Product gas used to fire process
Poster Wheeler/Stoic Bituminous, low
sulfur
Tar/liquor separation
Wastewater evaporation
Cyclone
Electrostatic
precipltator (ESP)
University of Minnesota
- Duluth, MR
Hsllaan Incandescent
tlley Korean
Poster Wheeler/Stoic
Uellmen~Galusha
Uellaan-Calusha
Vellman-Calusha
Bituminous
Bituminous
lignite
Various
Coke
Coke
Lignite
• Cyclone
. ESP
• Sulfur removal
(Stretford)
• Cyclone
• Cyclone
• quench
• Cyclone
• Cyclone
• Rot available
Caterpillar, Inc.
- York, PA
Rlley Stoker Co.
- Worchester, MA
General Motors Corp
- Siglnaw, Mich
Gulf & Western (N. J. zinc)
- Ashtabula, Ohio
Olin Chemical Corp.
- Ashtabula, Ohio
Chemical Exchange
- Houston, IX
1
1
1
1
1
1
heaters
• Only two gasifiers are operated at
one tine to meet current fuel needs
* By-product tar used with coal to
fire a ateam boiler
• Construction completed In 1978
- Partial funding by DOE
• 100 hours of start-up tests
completed
• Full time operation scheduled for
fall 1979
• Product gas to be used to fire
steam boilers
• By-product tar to be used to fire
a steam boiler
• Demonatratlon-comercial sire
• Product gas to be used to fire
process heaters
• Commercial-size demonstration unit
• Coal hopper vent control
• Commercial size demonstration unit
• Gas used in metal processing fur-
nace
• Start up in 1979
• Gas used in process furnace
• Installed 1963
• Gas used in process furnace
• Installed 1963
• Start up In 1979
• Gas end use not available
-------
TABLE 1.1-3. PAST USERS OF GAS PRODUCED BY
WELLMAN-GALUSHA* GASIFIERS
• chemical plants • aluminum and stainless steel
• glass plants manufacturers
• steel mills ' ordinance plants
• magnesium manufacturers * tin Plate mills
• silk mills ' lime plants
• bakeries * brick Plants
. wire mills ' *inc smelte«
. foundries ' iron ore Proce88O«
. potteries * fertilizer plants
aSpecific uses varied from heat treating (in glass and steel
mills) to synthesis gas (for synthetic fertilizer manufacture)
Materials gasified included charcoal, coke, anthracite, and
bituminous coa.
8
-------
Increased commercialization of low-Etu gasification sys-
tems like the Wellman-Galusha will also depend on demonstration
of the environmental acceptability of the gasification systems.
Although commercially available controls seem to be adequate,
some of the ocntrols (such as treatment of process condensate
blowdown) have not been adequately demonstrated on coal gasi-
fication systems. The costs of these controls are also
uncertain.
Gasification systems featuring Wellman-Galusha gasifiers
are most suitable for relatively small applications, with fuel
demands ranging from about 8.8 to 88 MW of thermal energy (30 to
300 million Btu/hr). This would require from 1 to 10 gasifiers.
Energy demands greater than about 88 MW (300 million Btu/hr) may
be better served by gasification systems using gasifiers with
larger capacities (for example, pressurized gasifiers).
McDowell-Wellman can deliver Wellman-Galusha gasifiers 6
to 8 months from the date of order. However, systems using 2 to
4 gasifiers and including extensive gas purification will require
18 to 24 months from initial feasibility studies to full-scale
operations. (Refs. 1, 2).
Wellman-Galusha gasification systems will be most widely
used in industrialized areas which also contain available coal
reserves. Two areas of the country which meet these conditions
are the Northeast and Midwest.
1.1.5 Energy Efficiency
The energy efficiency of Wellman-Galusha gasification
systems will be a significant factor affecting their commerciali-
zation potential. However, this factor may become less critical
if alternative fuels, e.g., natural gas or petroleum liquids, are
either unavailable or too expensive.
A large number of energy efficiencies can conceivably be
defined. In this study, three efficiencies are used:
• coal to low-Btu gas efficiency which relates the en-
ergy of the product gas (higher heating value or
HHV of combustibles plus sensible heat) to the HHV
of the feed coal,
• gas production efficiency which relates the energy
of the product gas to the total energy input to the
system (HHV of coal plus utility steam and elec-
tricity energy), and
-------
• overall thermal efficiency which relates the energy
of the product gas and by-product tars, oils, and
steam to the total energy input to the system.
Mathematically, the three energy efficiencies are defined as fol-
lows :
n« - if\ . * KM
in
^-,100
and
vtar*
ne. • eo«l to gM efficiency (X)
n.j • gu production efficiency (X)
i\<[ • overall thermal efficiency (X)
«Jg) wt • output product gM «Mrgy
• input coal
(Oj.) ollt • total output «ntrgy (product g«* -f
by-product* + it««a)
<. • total input tnorgy (coal + ataaa +
** •Uetrieity)
Calculated energy efficiencies for the Wellman-Galusha systems
considered in this report are shown in Table 1.1-4. These
calculated efficiencies show that the types of processes used,
by-products produced, and the nature of the coal feedstock affect
the coal to gas and overall thermal energy efficiency of the sys-
tem.
1.1.6 • Detailed Capital and Operating Costs
Capital and operating costs were calculated for the fol-
lowing Wellman-Galusha gasification systems producing nominally
17.6 MW (60 x 106 Btu/hr) and 87.9 MW (300 x 106 Btu/hr) of
product low-Btu gas:
10
-------
TABLE 1.1-4.
CALCULATED ENERGY EFFICIENCIES FOR VARIOUS UNCONTROLLED
WELLMAN-GALUSHA GASIFICATION SYSTEMS
Lignite
Energy Efficiencies
for Systems Producing
a Hot Product Gas
Energy Efficiencies
for Systems Producing
Cool Uesulfurized Gas
Coal Feed Type
Anthracite
Low-Sulfur,
HVA Bituminous
High-Sulfur,
HVA Bituminous
Typical Raw
Gas Temperature
700° K (800°F)
840°K (1050° F)f
640°K (700°F)
a b c a b
n n _ n n n T
87. 2d 86. 6d 86. 6d 80.5° 78. 9e
92. 8d 92. 2d 92. 2d 68.8° 67. Oe
NA NA NA o9 • o«_ oo • o,
K >>
nrC
81. 5e
83. 2e
82 -6u
420°K (300°F)
NA
NAR NAR
60.4'
62.11
77. Oe
55.9'
50.51
73.6e
71.2"
63.91
88.5e
H is the coal to low-Btu gas energy efficiency which relates the energy of the product gas
Cg (higher heating value of HHV of the combustible gases plus sensible heat) to the HHV of the
feed coal.
PgT ls the gas Production efficiency which relates the energy of the product gas to the total
energy Input to the system (HHV of coal plus utility steam and electricity energy).
!"1T is the overall thermal efficiency which relates the energy of the product gas and by-product
tars, oils, and steam to the total energy input to the system.
These systems produce a "moderately clean" industrial fuel gas. A "moderately clean" Industrial
fuel gas Is used In this report to describe a low-Btu gas whose combustion emissions would be
equal to or lower than the 1971 new source performance standards (NSPS) for direct combustion of
coal in a large stream.
These systems produce a "clean" Industrial fuel gas using the Stretford process for removing H2S.
A "clean" industrial fuel gas is used In this report to describe a low-Btu gas whose combustion
emission would be approximately equal to the 1979 NSPS for direct combustion of
coal in a large steam generator.
This temperature is much higher than that which would normally be encountered in a Wellman-Galusha
gaslfler (600-700*K is more typical). See discussion in Section 3.
8Not applicable - These coals have sulfur contents too high to produce a hot, "moderately clean"
Industrial fuel gas.
Tliese systems produce a "clean" Industrial fuel gas using the MEA process to remove sulfur species.
In these systems some of the low-Btu gas is used to meet the energy requirements of the MEA process.
These systems produce a "very clean" gas using the MEA process.
-------
• System 1 produces a hot, raw product gas.
• System 2 produces a desulfurized product gas (down
to 10 ppinv H2S) using the Stretford sulfur removal
process.
• System 3 produces a desulfurized product gas (down
to 200 ppmv H2S) using a MEA sulfur removal pro-
cess operating at 0.44 MPa (50 psi).
• System 4 produces a desulfurized product gas (less
than 10 ppmv total sulfur) using an MEA sulfur
removal process operating at 1.5 MPa (200 psi).
Tables 1.1-5 and 1.1-6 summarize the capital and operating costs
for uncontrolled Wellman-Galusha gasification systems using var-
ious coal feedstocks. Cost of removing sulfur species from the
low-Btu product gas are included in these cost estimates. How-
ever, pollution control equipment costs are not included.
As shown in Tables 1.1-5 and 1.1-6, the product gas
costs are dependent upon coal feedstock, product gas specifica-
tions (tar/sulfur content) and plant size. Product gas costs for
producing a hot, raw gas for on-site use (System 1) range from
$1.90 to $3.80 per GJ ($2.00 to $4.00 per 106 Btu) depending
upon the coal feedstock. For systems using a Stretford sulfur
removal process, product gas costs range from $3.40 to $5.80 per
GJ ($3.60 to $6.10 per 10° Btu) depending upon the product gas
sulfur content and unit size. If an MEA sulfur removal process
is used to remove gaseous sulfur species, product gas costs would
range from $3.80 to $6.10 per CJ ($4.00 to $6.40 per 106 Btu)
depending upon the product gas sulfur content and unit size.
For each of these gasification systems, the major cost
item is the coal feedstock. For systems using anthracite coal,
the coal costs represent 36 to 56 percent of the total costs of
the product gas. For systems using low-sulfur bituminous coal,
coal costs are 36 to 70 percent of the product gas costs and for
high-sulfur bituminous coals, 25 to 42 percent.
1.2 WASTE STREAMS AND POLLUTANTS OF MAJOR CONCERN
Wellman-Galusha low-Btu gasification systems are sources
of gaseous, liquid, and solid waste streams. Also associated
with these systems are process and by-product streams that may
contain toxic substances. The multimedia waste streams and pol-
lutants of major concern are summarized in Tables 1.2-1 through
1.2-3. Process and by-product streams that may contain poten-
tially toxic compounds are summarized in Table 1.2-4.
12
-------
TABLE 1.1-5. CAPITAL INVESTMENT REQUIREMENTS AND ANNUALIZED COSTS OF UNCONTROLLED
WELLMAN-GALUSHA GASIFICATION SYSTEMS PRODUCING NOMINALLY 17.6 MW
(60 x 106 BTU/HR) OF PRODUCT LOW-BTU GAS (LATE-1977 DOLLARS) a
Coal Feedstock/Type of Product Cas
Capital Investment Requirements* , $1,000
Design Plant Capacity, MW
Annual Operating Factor
Annual 1 zed Coats, $l,000/yr
Operating and Maintenance Coats
CoalS
Labor/Overhead (8 $15.00/aan-hr)
Electricity (9 $0.04/kWh)
efr h
Steam
Chemicals
Maintenance (8 61 of direct equipment
costs)
Taxes, Insurance, and GSA Costs (g 41
of depreciable investment)
Capital Related Charges1
TOTAL Annualized Costa, $10s/yr
Average Gas Costs, S/GJ
An
Hot Gasb
3,250
19.1
90Z
1,040
131
16
—
-
149
117
602
2,055
3.79
thraclte
Cold Gasc
6,110
17. h
90Z
1,040
197
48
(17)
8
276
229
1,116
2,897
5.80
Low Sulfur
Hot Gas1
1,730
24.9
90Z
919
66
18
—
-
74
58
326
1,461
2.07
Bituminous
Cold Gas1-
5,200
18.5
90Z
919
131
79
~
8
233
194
950
2,514
4.79
High Sulfur
Stretfordc MEA
5,500
18.0
90*
702
131
118
~
63
248
207
1,003
2,472
4.84
Bituminous
(200 ppmv)d
3,890
15.6
90Z
702
131
225
*~
55
175
143
715
2,146
4.85
(Cold Gas)
MEA (neg.)e
4,700
16.0
90Z
702
131
643
~
55
210
171
867
2,779
6.10
<-° "Each system has a nominal capablty of 17.6 MW (60 x 10* Btu/hr) of tar/oil-free product gas at 43.3*C (110°F). The actual total energy supplied to the
end-user though Is as indicated. Differences in the indicated useful energy supplied and the basic capacity of 17.6 MW (60 x 108 Btu/hr) are a result of
1) energy credits taken for the sensible heat and/or tar/oil content of the product gas for the hot gas systems, and 2) use of a portion of the product
gas to supply energy to the atrlpper reboiler in the systems that use the MEA process.
These systems use only a cyclone for product gas purification and deliver a hot product gas to the end user.
°These systems use the Stretford process to remove H2S from the cooled product gas. Residual H2S levels are nominal 10 ppmv. Organic sulfur compounds,
such as COS and CSz, are not removed by the Stretford process.
This system uses the MEA process operating at 0.44 MPa (50 pslg) to remove sulfur species from the cooled product gas. Residual sulfur species amount to
the equivalent of 200 ppmv H2S.
This system uses the MEA process operating at 1.5 MPa (200 palp.) to remove sulfur species from the cooled product gas. Negligible sulfur species are left
in the product gas.
In estimating capital investment requirements, a spare gaslfler/cyclone unit is included for all systems and cooling liquor pumps are spared 100Z.
'Assumed coal properties and delivered costs are: Anthracite: 29.7 Ml/kg (12,800 Btu/lb) and $50/metrlc ton ($45/short ton)
Low sulfur bituminous: 33.2 MJ/kg (14,300 Btu/lb) and $40/metrlc ton ($36/short ton)
High sulfur bituminous: 29.0 MJ/kg (12,500 Btu/lb) and $28/metrlc ton ($25/short ton)
Steam costs were assumed to be $0.Oil/kg ($5/10* Ib). Steam credits were taken as Sl/GJ ($1.05/10' Btu).
Basis for capital related charges: Utility financing method 100Z equity financing
Late-1977 dollars without inflation 15Z after tax return on equity
25-year economic project lifetime 46Z federal Income tax rate
41 per year straightllne depreciation 10Z pretax return on working capital
of depreciable investment
-------
TABLE 1.1-6.
CAPITAL INVESTMENT REQUIREMENTS AND ANNUALIZED COSTS OF UNCONTROLLED
WELLMAN-GALUSHA GASIFICATION SYSTEMS PRODUCING NOMINALLY 87.9 MW
(300 x 106 BTU/HR) OF PRODUCT LOW-BTU GAS (LATE-1977 DOLLARS)3
Coal Feedstock/Type of Product Gas
Anthracite
Capital Investment Requirements f, $1,000
Design Plant Capacity, MW
Annual Operating Factor
Annualiced Coats, $l,000/yr
Operating and Maintenance Coats
Coal*
Labor/Overhead (6 $15.00/man-hr)
Electricity (0 $0.04/kWh)
Steam"
Chemicals
Maintenance (8 6Z of direct equipment
costs)
Taxes, Insurance, and GSA Costs (6 4Z
of depreciable investment)
Capital Related Charges
TOTAL Annuallzed Costs. $10*/yr
Average Gas Coats, S/GJ
each system, except the one producing a hot
Hot Gaa"
13,300
95.6
90Z
5.198
524
81
-
-
596
468
2.476
9,343
3.44
product gas from
free product gas at 43.3*C (110'F) . The actual total energy
supplied and the basic capacity of 87.9 MU
product gas for the hot gaa systems, and 2)
(300 x 10* Btu/hr)
use of a portion
process. For the hot gas, low sulfur bituminous system, the
Low Sulfur
Cold Gas*- Hot Gas"
19,700
87.9
90Z
5,198
657
238
(86)
40
871
713
3.640
11,271
4.52
4,770
99.7
90Z
3,676
263
72
-
-
189
149
916
5,265
1.86
low sulfur bituminous coal, has
supplied to the end-user though
are a result of 1)
of the product gas
Bituminous
Cold Gas1-
13.100
92.4
90Z
4.595
394
396
-
40
563
465
2,436
8,889
3.39
a basic capacity
is as indicated.
High Sulfur Bituminous (Cold Gas)
Stretfordc MEA (200 ppnv)d
14,200
89.9
90Z
3,510
394
590
-
315
617
512
2,614
8.552
3.35
of 87.9 MU (300
Differences in
11.600
77.9
90Z
3,510
394
1,125
-
274
499
406
2,165
8,373
3.78
MEA (neg.)11
14,000
80.1
90Z
3,510
394
334
3.390
274
582
474
2,625
11,583
5.09
x 10' Btu/hr) of tar/oil-
the indicated u
acful energy
energy credits taken for the sensible heat and/or tar/oil content of the
to supply energy to the stripper reboiler in
the systems that
tar/oil-free product gas rate is 74.0 MU (253 x 10* Btu/hr). But, the sensible
tar/oil content of the hot product gaa raise the total system capacity to 99.7 H
U (340 x 10'
Btu/hr) . This capacity was used
use the MEA
heat and
in the cost analysis because
it la comparable to the capacity of the other systems examined.
These systems use only a cyclone for product gas purification and deliver a hot product gaa to the end user.
cTbese systems use the Stratford process to remove HiS from the cooled product gaa. Residual H2S levels are nominal 10 ppmv. Organic sulfur compounds,
such as COS and CSj, are not removed by the Stretford process.
This system uses the MEA process operating at 0.44 MPa (50 psig) to remove sulfur species from the cooled product gas. Residual sulfur species amount to
the equivalent of 200 ppmv HjS.
*Thls system uses the MEA process operating at 1.5 MPa (200 psig) to remove sulfur species from the cooled product gas. Negligible sulfur species are left
In the product gas.
In estimating capital Investment requirements, a spare gaslfier/cyclone unit is Included for all systems and cooling liquor pumps are spared 100Z.
'Assumed coal properties and delivered costs are: Anthracite: 29.7 HJ/kg (12,800 Btu/lb) and $50/metrlc ton ($45/short ton)
Low sulfur bituminous: 33.2 MJ/kg (14,300 Btu/lb) and $40/metric ton ($36/sbort ton)
High sulfur bituminous: 29.0 MJ/kg (12.500 Btu/lb) and $28/metrlc ton ($25/short ton)
''Steam costs were assumed to be $0.Oil/kg ($5/10* Ib). Steam credits were taken as $1/GJ ($1.05/10' Btu).
Sasls for capital related charges: Utility financing method 100Z equity financing
Late-1977 dollars without Inflation 15Z after tax return on equity
25-year economic project lifetime 46Z federal Income tax rate
4Z per year strslgfatllae depreciation 10Z pretax return on working capital
of depreciable investment
-------
TABLE 1.2-1. GASEOUS WASTE STREAMS AND POLLUTANTS OF MAJOR CONCERN FROM
WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
Operation
Process
Gaseous Waste Stream
Pollutants of Major Concern
Remarks
Coal Preparation
Coal Storage and
Handling
Coal Gasification
Coal dust
Partlculate matter similar In composition ot the
coal feedstock.
Bituminous coal gave slightly positive results for
the Ames test which indicates a potential for the
coal being carcinogenic. Anthracite coal results
were negative.
Uellman-Galusha
Gasifler
Coal feeder vent
gases
Start-up vent gases
Gas Purification
Gas Quenching and
Cooling (Tar/
Liquor Separation)
Sulfur Removal-
Stretford
Sulfur Renoval-
MEA
Fugitive emissions
(pokehole gases)
Separator vent gases
Evaporator and
oxldizer vent gases
Acid gas stream
Gaseous species in the product gas (CO. H2S, NHs,
HCN, light hydrocarbons).
Raw product gas constituents. Partlculate matter
(coal dust, tar, oil aerosols) and gaseous
species (CO, H2, H2S, COS, HH3, HCN, light hydro-
carbons, etc.). Organlca of concern Include fused
aromatic hydrocarbons, heterocycllc nitrogen,
sulfur and oxygen compounds, carboxylic acids,
amines, sulfonlc acids, aulfoxides, phenols,
thlols, benzene, and substituted benzene hydro-
carbons. Inorganics of concern Include CO,
ethylene, Cr, Hg, U, V, Al, P, As, Cu, Cd, H2S,
C02, HCN, Li, Tl, Si, Pb, Sb, SO2, CSj , Cl, Ti,
Zr, Fe, Co, Hi, Ag and Zn.
Caseous species in the product gas (CO, H?S, NHj,
HCN, light hydrocarbons).
Organlcs of concern include fused aromatic hydro-
carbons, amines, heterocycllc nitrogen and sulfur
compounds, ethylene, phenols, methane, and
carboxylic acids. Inorganics of concern include
CO, HH3, NO2, C02, Cr, Ag, V, Cu, P, Li, As, Fe,
Nl, and U.
Volatile compounds in the Stretford liquor (H;0,
C02, N2, O2, and possibly NHs).
CO2, H2S, COS, CS2, mercaptans, and light
hydrocarbons.
High levels of CO were found In the coal hopper
area.
The amount of tars and oils will depend upon the
coal feedstock. Bituminous coals will have a
significant amount of tars where anthracite will
not. Tars from the gasification of bituminous
coals gave positive results on the Ames test which
Indicates they may be carcinogenic.
Emissions of tars and oils will occur when poke-
hole valves are open; however, the majci: emissions
from the pokeholes will be from gaseous species
in the product gas leaking from the pokehole
valves.
These pollutants of concern are associated with
bituminous coals.
This strpam has not been sample because no
.Stretford processes are currently used in this
application or have been successfully demon-
strated to remove sulfur species for low-Btti gas.
This stream is sent to a sulfur recovery unit
consisting of a Claus process followed by a Claus
tail gas clean-up process to remove the sulfur
species in the acid gas stream. This stream has
not been sampled since MEA processes have not
been used to remove sulfur species from low-Btu
gas. However, Koppers has used the MEA process
to desulfurlze medium-Btu gas.
-------
TABLE 1.2-2. LIQUID WASTE STREAMS AND POLLUTANTS OF MAJOR CONCERN FROM
WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
Operation
Process
Liquid Uaate Stream
Pollutants of Major Concern
rka
Coal Preparation
Coal Handling and
Storage
Coal Gasification
Uellman-Calusha
Gaalfler
Caa Purification
Gas Quenching and
Cooling
Sulfur Removal-
Stretford
Coal pile runoff
Ash sluice water
Process condensate
Solvent blovdovn
Contain teachable organlcs and Inorganics.
Inorganics of major concern Include P, Tl, V, Cu,
Fa, la, Cd, Cr, CM', LI and Ml. Organic concen-
trations of 65 mg/t have been found; however. It
la not certain whether these were present In the
plant'* service water used to sluice the ash
from the gaalfler.
May contain organic and inorganic pollutants
found in the quench liquor (see Table 2.3-4).
Thlosulfate and thiocyanate aalts.
The composition of this stream will depend upon
the coal feedstock and site-specific conditions
(i.e. pH of leachate).
The amount of sluice water Is low and highly variable.
Negative Ames testa were obtained with low to non-
detectable results Indicated for the cytotoxlclty and
rodent acute toxlclty tests for sluice water from a
facility gaaifylng anthracite coal. This Indicates
that the ash sluice water has a low potential for
effecting health of the environment.
The amount of process condensate produced will
depend upon the system operation and type of
processes used. Typical process condenaate flow
may range between 3.79 x 10"' to 1.52 x 10"'
m'/sec (5 to 20 gpm).
The amount- of these salts produced will depend
upon the sulfur and cyanide content of the cooled
product gas entering the Stratford process.
Sulfur contents may range from 600 to 10,000 ppmv
while cyanide say range from SO to 200 ppmv.
-------
TABLE 1.2-3. SOLID WASTE STREAMS AND MAJOR POLLUTANTS OF CONCERN FROM
WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
Operation
Process
Solid Waste Streams
Pollutants of Major Concern
Remarks
Coal Gasification
Wellnan-Galusha
Gasifier
Gasifier ash
Ash leachate
(anthracite coal)
Gas Purification
Particulate Removal-
Hot Cyclone
Collected participate
natter
Sulfur Renoval-
Stretford
Sulfur Ren
HEA
jval-
Collected particulate
matter leachate
(anthracite coal)
Sulfur
MEA sludge
Inorganics of major concern include Be, P, Fe,
Ca, Al, Li, Ba, Se, Pb, Cs, Cu, Ti, Cd, Sb, V,
Co, U, Mg, Sr, Si. Hg, Zr, F, Rb, As, Mn, Cr, Ni,
Th, Bi, Ag, Y. Total extractable organics in
the ash is low ranging from 40-116 yg/g. Organics
of potential concern Include phthalate esters,
phenols, nitrophenols, and fused aromatic hydro-
carbons.
Inorganics of concern Include P, Zn, Cd and Ag.
Inorganics of major concern include Nl, Pb, P,
Mn, Fe, Cu, Ba, Sb, Ti, Cr, Ca, Al, V, Li, Hg,
Zr, Co, As, Si, Se, Be, Cd, Ag, Th, Zn, F, Ca,
Hf, Hg, Sr, TI, Y. Lou concentrations (40 to
800 Mg/g) of extractable organics have been
determined. Organics of concern Include phthalate
esters, phenols, nitrophenols, amines, cresols.
Inorganics of major concern Include Mn, Pb, Li,
Zn, Al, Cd, Co, Cu and Fe.
Contain organics and inorganics including
thlocyanate and thlosulfate salts.
Degradation products including oxazolidon-2,
l-(Z-hydroxyethyl) lmldazollndone-2, diethanol
urea, dlthlocarbamates, thiocarbamldes and other
high molecular weight nonregenerable compound*.
Results from the Ames, cytotoxlclty, and rodent
acute toxicity tests for ash produced from gasi-
fying anthracite and bituminous coals were nega-
tive, low or nondetectable. Effects on soil
microcosms were also low. This Indicates that the
ash may have a low potential for harmful health
and ecological effects.
Results from the Ames, cytntoxicjty and rodent acute
toxicity tests of leachate from ash produced from
gasifying anthracite coal were negative, low or
uondetectable. This indicates that leachate
resulting from ash may have a low potential for
harmful health and ecological effects.
Negative results from the Antes test have been
obtained with low to nondetectable results from
cytotoxlcity and rodent acute toxicity tests.
High effects on soil microcosms were found. Col-
lected participates resemble devolatllized coal
with carbon contents ranging from 70 to 80Z.
These may indicate that the cyclone dust may have
a low potential for harmful health effects but a
high potential for ecological effects.
Negative Ames test results were obtained and
cytotoxicity test results were nondetectable.
This indicates that the leachate may have a low
potential for harmful health effects.
No data is currently available on the chemical
and biological aspects of the recovered sulfur.
No data is currently available on the character-
istics (chemical or biological) of MEA sludge.
-------
TABLE 1.2-4.
POTENTIAL TOXIC STREAMS AND COMPOUNDS OF MAJOR CONCERN
FOR WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
Operation
Proem
Potential
Toxic Stream
Compounds of Major Concern
Remarks
Gas Purification
Gas Quenching and
Cooling
By-product tar
and oils
Quench liquor
Organlcs of major concern include fused
aromatic hydrocarbons, benzene, substituted
benzene hydrocarbons, heterocycllc nitrogen,
sulfur and oxygen compounds, carboxyllc acids,
aliphatic hydrocarbons, phenols and amines.
Inorganics of concern include Cu, Pb, Sb, Cr,
Cd, Ba. Rg. V, Mg. and As.
Organic* of Major concern Include phenols,
fused aromatic hydrocarbons, heterocycllc
nitrogen and sulfur compounds, carboxylic
acids, thlols, glycola, and apoxldes. Inorganics
of concern include Mb . cyanides, P, Se, As, F,
Cl, Ca, Te aid Cd.
Tar will be produced from bituminous and lignite
coals. Positive Ames test results have been
obtained. This indicates that the tar may be
carcinogenic. Safe handling and controlling tar
leaks procedures are required.
Results from aquatic bioassay tests Indicated a
high potential effect on aquatic species. Health
effects tests yere low; however, because of the
chemical characteristics of the quench liquor,
safe handling end control of leeks are required.
OO
-------
Gaseous emissions from Wellman-Galusha systems contain a
significant amount of pollutants that may have harmful health and
ecological effects. Gaseous pollutants (CO, l^S, HCN, NH3,
and light hydrocarbons) from the coal feeder and gasifier poke-
holes need to be controlled. Start-up vent gases will contain
compounds found in the raw product gas (CO, sulfur species, light
hydrocarbons, tars ands oils) which will require control before
venting to the atmosphere. Vent gases from the by-product tar
recovery process will contain significant amounts of potentially
harmful pollutants and will, therefore, need to be controlled.
Emissions from sulfur removal processes are not yet characterized
since there are currently no sulfur recovery processes being used
with fixed-bed, atmospheric pressure, low-Btu gasification sys-
tems.
The amount of liquid effluents from Wellman-Galusha sys-
tems will be limited to blowdown streams, ash sluice water, and
coal pile runoff. Of these effluents, the blowdown streams will
contain significant quantities of potentially harmful constitu-
ents. Ash sluice water and coal pile runoff will contain com-
pounds leached from the ash and coal which may affect health and
the environment.
Solid waste streams from Wellman-Galusha systems will
consist of ash, collected particulates, sulfur, and blowdown from
the MEA sulfur removal process. Ash and sulfur may contain
leachable constituents that may be potentially harmful. Collec-
ted particulates resemble devolatilized coal and therefore, may
be classified as a solid combustible material. MEA blowdown
sludge contains potentially harmful constituents and needs to be
treated before disposal.
The by-product tar and quench liquor represent process
streams that contain potentially harmful organic and inorganic
compounds. Worker exposure and accidental releases of these
streams should be carefully controlled.
It should be emphasized that the chemical characteris-
tics and potential biological effects are highly dependent upon
the coal feedstock and processes used. For example, tars will
not be produced when anthracite coal is gasified; however, pro-
cess condensate may contain light oils.
1.3 STATUS OF ENVIRONMENTAL PROTECTION ALTERNATIVES
The assessment of the status of environmental protection
alternatives involves identifying and evaluating control alterna-
tives to determine the:
19
-------
• most effective control alternatives, and
• costs and energy impacts of those control
alternatives.
The secondary waste streams from the most effective control
alternatives are compared to existing and proposed regulations
and to the Multimedia Environmental Coals (MFC's) (Ref. 3).
1.3.1 Host Effective Control Alternatives
The criteria used to identify the most effective control
alternatives are:
• applicability to treating waste streams from low-
Btu gasification systems,
• control effectiveness,
• development status, and
• secondary waste streams.
Costs and energy considerations are not considered in the selec-
tion of the most effective controls. Table 1.3-1 shows the most
effective control alternatives to treat the multimedia waste
streams and potential toxic substances associated with Wellman-
Calusha gasification systems.
1.3.2 Cost and Energy Considerations
Costs of the "best available" candidate control methods
(identified in Table 1.3-1) are summarized in Table 1.3-2. Most
of the control alternatives have negligible costs when compared
to the costs of the low-Btu gas. The most costly control alter-
natives are those for treatment of the MEA acid gas vent stream
and process condensate. The most costly control methods also
have the largest energy consumption. Tars and oils represent a
large energy credit (up to 0.25 J per J of product gas produced
depending upon the coal feedstock).
One method to reduce the costs and energy consumption of
process condensate treatment is to reduce the size of the conden-
sate stream. This may be accomplished by drying the coal prior
to gasification (the dryer off-gas could contain large amounts of
coal volatiles). The size of the stream could also be reduced by
minimizing the amount of steam fed to the gasifier.
20
-------
TABLE 1.3-1.
SUMMARY OF MOST EFFECTIVE EMISSION, EFFLUENT,
SOLID WASTES, AND TOXIC SUBSTANCES CONTROL
ALTERNATIVES
Waste Stream
Most Effective Control Technology
Air Emissions
• Fugitive dust from coal storage
• Fugitive dust from coal handling
• Coal feeding system vent gas
• Ash removal system vent gas
• Start-up emissions
• Fugitive emissions and pokehole
gases from gasifier
• Fugitive emissions from hot cyclone
• Separator gas
• MEA acid gas
• Stretford oxidizer vent gas
• Stretford evaporator vent gas
Liquid Effluents
• Water runoff
• Ash sluice water
• Process condensate
Covered bins
Asphalt and polymer coatings
Enclosed equipment, collect gas
and recycle to gasifier inlet
air or treat with baghouse
Collect gas and recycle to
gasifier inlet air or combine
with product gas
No control necessary in a
properly designed system
Incinerator
Adherence to good operating
and good maintenance procedures
Same as for gasifier
Combine with product gas
Recycle to gasifier
Stretford
Claus with tail gas cleanup
None required with existing
applications. However, via-
bility of this approach needs
to be confirmed in a gasifica-
tion process application.
Same as for oxidizer vent gas
Use covered bins for coal
storage
Contain, collect and reuse for
process needs
Collect and recycle to ash
sluice system
Containment and treatment at
hazardous waste facility
21
-------
TABLE 1.3-1. (Continued)
Waste Stream
Most Effective Control Technology
• Stretford blowdown
Solid Wastes
• Ash
• Cyclone dust
• Recovered sulfur
• MEA blowdown
Toxic Substances
• Tars and oils
* Containment and treatment at
hazardous waste facility
• Reductive incineration at
high temperature
• Secured landfill
• Combustion in incinerator
or coal-fired boiler
• Purify for sale or disposal
• Containment and treatment at
hazardous waste facility
• Combustion in boiler or
furnace
only on effectiveness in eliminating or reducing emissions.
22
-------
TABLE 1.3-2.
SUMMARY OF MAJOR COSTS AND ENERGY CONSUMPTION
OF ALTERNATIVE CONTROL METHODS
Operation Waste Stream Media Control Costs
Process Waste Stream Control Method ($/GJ)a
Coal Preparation
Coal Handling and Gaseous Emissions
Storsge • Fugitive dust • Covered bins
• Asphalt and polymer coatings
• Enclosed equipment, collection
systems
Liquid Effluents
• Coal pile runoff * Covered bins
• Collection and reuse
<0.01
<0.01
<0.01
<0.01
<0.01
Energy Consumption
(J/J)b
• Negligible
• Negligible
• Negligible
• Negligible
• Negligible
Coal Gasification
Vellman-Galusha
Gasifier
Gas Purification
Particulate Removal-
Hot Cyclone
Gas Quenching
and Cooling
Gaseous Emissions
• Coal feeding vent gases
• Ash removal vent gases
• Start-up vent gases
• Fugitive emissions
(pokehole gases)
Liquid Effluents
• Ash sluice water
Solid Wastes
• Ash (low-S Bituminous)
• Ash (high-S Bituminous)
- Stratford
- MEAe
- MEA (Stringent)*
• Ash (Anthracite)
• Ash (Lignite)
Solid Waates
• Collected participates
Gaseous Emissions
• Quench llquor/ter
separator vent
Liquid Effluents
* Process Condensate
- High-S Bituminous
• Stretford
• MEA8
• MEA (Stringent)5
- Lignite
• Process Condensate
- High-S Bituminous
• Stretford
• MEA'
• KEA (Stringent)f
- Lignite
Collection and recycle to gasi- <0.01
fier inlet air or product gas
None required —-
Flare or incinerator <0.1
Good maintenance and operating
Collection and reuse <0.01
Secured landfill
0.01-0.02(0.01-0.03)
0.02-0.06(0.04-0.08)..
0.03-0.07(0.05-0.10).
0.03-0.06(0.04-0. ior
0.04-0.10(0.07-0.IS)1
0.04-0.10(0.07-0.15)1
Combustion
Combine with the product gas
Containment and treatment
off-site in a hazardous
waste treatment facility
Forced evaporation on-site
<0.01
<0.01
0.40-0.59
0.88-1.32
1.16-1.69
1.43-2.01
0.06-0.07
0.12-0.14
0.16-0.18
0.18-0.20
Negligible
NAC
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
NA
NAh
NA
0.019
0.042
0.055
0.065
23
-------
TABLE 1.3-2. (CONTINUED)
Operation
Process
lulfur Raaoval-
S tret ford
Weata Stream Media
Waste Stream Control Method
Caseous Emissions
• Oxldlier vent us • Nona raoulred
Control Coats Energy Conaumptlom
Sulfur Removal-
MEA
• Evaporator vent gas
Liquid Effluents
• Slowdown aolvent
Solid Waetea
• Sulfur
- Low-S Bituminous
- Hlgh-S Bituminous
- Anthracite
- Lignite
Caeeous Emissions
• Acid gaa
- 15 MW product gaa
- 74 MW product gaa
• Acid gaa
- 15 MW product gaa
- 74 MW product gaa
Solid Wastes
• MEA Slowdown
• Sulfur
Bone required
• Reductive Incineration
Secured landfill
• Stretford acid gae removal
Claua without tall gaa
cleanup
0.002-0.009
0.02-0.07
0.002-0.009
0.005-0.020
1.2-1.6
0.6-0.8
0.5-0.6
0.2
<0.01
Containment and treatment
at a hazardous vasts facility
•* Same as tha Stretford sulfur removal case.
Negligible
negligible
Negligible
Negligible
0.007
0.007
0.008
0.008
«Ah
MA - Data not available for calculation of energy conaumptlona.
*Coet* are annuallied coata per CJ of cooled, deterred product gae.
Energy conaumptlons are J of energy required by the control method per J of cooled, deterred product gaa.
cEnergy consumption will depend upon tha materials (coke, coal, wood, oil, etc.) uaed to start up tha gaaifler and tha compoai-
tlon of the gas during the atert up time period.
Good maintenance and operating prccedurea should already be defined and Included in tha units operating costs.
*HEA produces a product gaa to meet combustion Units of 86 ng SOj/J (0.2) lb/10 Itu.
'KEA (stringent) produces a "very clean" product gae containing 6 ng/Nm (10 ppmv) of sulfur species.'
•Combustion characteristics of tha collected partlculatee have not bean determined.
Sate ara not available on tha energy consumption of treating procaae condeaaate at an off-alte haaardoua waata treatment
facility.
^Control coatst Without fixation (with fixation)
24
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1.3.3 Impacts on Air Quality
The potential air quality impacts of gaseous waste
streams from Wellman-Calusha low-Btu gasification facilities were
estimated and compared to the following air standards and guide-
lines :
• New Source Performance Standards (NSPS) for
stationary sources,
• National Emissions Standards for Hazardous Air
Pollutants (NESHAP) ,
• National Ambient Air Quality Standards (NAAQS) ,
• State and Federal Emission Standards, and
• Performance Guidelines for Lurgi Gasification Plants
The air quality impacts of specified pollutants (CO,
H2S, COS, NHj, HCN, NOX , SOX , and non-CH4 hydrocarbons)
in uncontrolled gaseous waste streams from Wellman-Calusha sys-
tems using a low- and high-sulfur bituminous coal were estimated
using atmospheric dispersion models (See Appendix) . The waste
streams considered were:
• coal feeder gases,
• tar/ quench liquor separator vent gases, and
• incinerated Glaus tail gases (high-sulfur case only)
Table 1.3-3 shows a comparison between predicted maximum
ground-level concentrations of CO, nonmethane hydrocarbons,
NOX, and S02 to the NAAQS and F^S concentrations to the
Texas ambient air standards. With the exception of nonmethane
hydrocarbons, the predicted pollutant concentrations for both the
low- and high-sulfur coals are below the NAAQS; however, they are
relatively high. As indicated in Table 1.3-3, H^S concentra-
tions for the high-sulfur coal case exceed the Texas standard.
The major source of CO, I^S NH3 , HCN, and COS emis-
sions is the separator vent. Recycling the separator vent gas to
the product gas would given an 85 to 98 percent reduction in the
ground-level concentrations of those pollutants. Those gases
could also be flared or incinerated. The resulting combustion
gases would contain SOX and NOX with smaller amounts of CO,
H2S, NH3 , HCN and COS. There are no data on using combustion
to control this emission.
25
-------
TABLE 1.3-3. COMPARISON OF PREDICTED POLLUTANT CONCENTRATIONS TO THE
NAAQS AND STATE OF TEXAS H2S AMBIENT AIR STANDARDS
Low-Sulfur Coal*
Predicted Concentrations (ug/m1)
Pollutant 24-h 3-h 1-h
CO 2.3OO
Non-CH. Hydrocarbons 650
HOX 20
SOX NA
H2S 10
9,800 13,700
2,800 3,900
70 90
NA NA
50 70
High-Sulfur Coalb
Predicted Concentrations (pg/m!)
24-h 3-h 1-h
2.300
650
20
110
90
9,800
2,800
70
380
390
13,700
3,900
90
560
540
HAAQS (Ug/m5)
Primary Secondary
Standards Standards
10,000 (8-h)c
160 <3-h)c
100 (aam)
365 (24-h)
State of
10,000 (8-h)c
•d 160 (3-h)c'd
100 (aam)
c 1,300 (3-h)c
Texas Regulations
122 pg/m'
NA - Not applicable, SOX emissions are from the high-sulfur case using an incinerator to combust the Glaus unit's tall gases.
aam - Annual arithmetic mean.
*For the low-sulfur coal case, a Stretford sulfur removal process is used.
For the high-sulfur coal, an NEA sulfur removal process is used followed by a Glaus process and a Claus tail gas incinerator.
Concentration not to be exceeded more than once • year.
d6:00 a.m. to 9:00 a.m.
-------
The Glaus tail gas incinerator is the major source of S02 emis-
sions. These emissions can be reduced approximately 90 percent
by incorporating a Glaus tail gas clean up process.
In summary, the gaseous emissions from a well-controlled
Wellman-Calusha gasification facility should not significantly
impact air quality. This implies that the separator vent gases
are recycled to the product gas and for the high-sulfur case
(using KEA and Glaus processes), a Glaus tail gas clean-up
process is used before incineration.
1.3.4 Impacts on Water
The quantity of liquid wastes from a Wellman-Calusha
gasification facility will be small; however, the concentrations
of various constituents in those waste streams may exceed ef-
fluent standards. The liquid effluents associated with a
Wellman-Calusha system are as follows:
• water runoff from coal storage,
• ash sluice water,
• process condensate, and
• blowdown from the Stretford process.
Water runoff may contain constituents exceeding effluent
standards. The concentration of those constituents will be vari-
able and highly site- and coal-specific.
Table 1.3-4 shows the constituents in the ash sluice
water, process condensate, and Stretford blowdown that have
either been found or estimated to exceed the most stringent ef-
fluent standards and Discharge Multimedia Environmental Goal
values given in the MEC's. The amounts and types of organic com-
pounds found in the process condensate will vary depending upon
the coal feedstock. High levels of organics will be present when
bituminous and lignite coals are used. Low levels of organics
will be present when anthracite coals are gasified.
1.3.5 Impacts on Land
Under the Resource Conservation and Recovery Act (RCRA),
EPA has issued guidelines for the land disposal of solid wastes.
These standards set minimum levels of performance for any solid
waste land disposal site. The guidelines apply to the land dis-
posal of all solid material. Additional standards have been pro-
posed for hazardous solid wastes (Ref. 4).
27
-------
TABLE 1.3-4. LIQUID EFFLUENTS FROM WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
EXCEEDING THE MOST STRINGENT EFFLUENT STANDARDS AND DMEG VALUES
Liquid Effluent
Constituents Exceeding
Most Stringent
Effluent Standards
Constituents Exceeding Health and/or
Ecological DMEG Values in the
Multimedia Environmental Goals3
Ni
oo
Ash Sluice Water
Process Condensate
(Bituminous Coal)
Stretford Slowdown
Fe, Cr, CN~ and suspended
solids
NH3, As, Cl~, CN~, B, F~,
Fe, Phenols, P, Se, SO IT,
BOD, COD, and suspended
solids
Fe
P, Fe, Ti, Ba, La, Li, Cd, Cu, CN~, Ni and V
Phenols, Fused Aromatic Hydrocarbons,
Heterocyclic Nitrogen and Sulfur Compounds,
Carboxylic Acids, Thiols, Glycols, Epoxides,
NHi,, CN~, P, Se, As, F~, Cl~, Ca, Fe and Cd
Vanadate, Fe, EDTA and possibly Thiocyanates
and Thiosulfates
case DMEG values were used when specific compounds were not identified.
Process condensate produced from gasifying anthracite coal should not contain the high amounts of
organic constituents found in process condensate from gasifying bituminous or lignite coals.
DMEG: Discharge Multimedia Environmental Goal
-------
The following solid waste streams from a Wellman-
Galusha gasification facility will be regulated under the RCRA:
• gasifier ash,
• cyclone dust,
• sulfur cake, and
• MEA blowdown.
Table 1.3-5 shows the characteristics of those solid waste
streams and how the proposed RCRA regulations may apply. All of
the solid waste streams may be classified as hazardous wastes
under the proposed RCRA regulations.
1.3.6 Product/By-Product Impacts
The product gas and by-product tar produced by Wellman-
Calusha facilities may be regulated by the Toxic Substances Con-
trol Act (TSCA) of 1976. However, polychlorinated biphenols
(PCB's) and chlorofluorocarbons are currently the only specific
substances for which regulations have been issued.
The product low-Btu gas may contain toxic substances
even after extensive purification. The by-product tar does con-
tain toxic substances. Positive Ames test results for mutageni-
city have been obtained as well as toxic responses for the Rodent
Acute Toxicity test and the soil microcosm test.
1.3.7 Radiation and Noise Impacts
Wellman-Galusha low-Btu gasification facilities may have
radiation and noise impacts. Some radioactive species in the
coal may be concentrated in the entrained particulate matter in
the raw, low-Btu gas and in the ash. Sources of potential noise
impacts in Wellman-Galusha facilities are process blowers and
turboblowers, coal conveyors, coal bucket elevators, and pumps.
1.4 DATA NEEDS AND RECOMMENDATIONS
Data needs and recommendations for obtaining those data
are divided into the following categories:
• gaseous, liquid, and solid waste stream
characterizations and control,
• process and process streams, and
• health and environmental impact assessments.
29
-------
TABLE 1.3-5. SOLID WASTES FROM WELLMAN-GALISHA LOW-BTU GASIFICATION
SYSTEMS THAT WILL BE REGULATED BY THE RCRA
Characteristics of the Waste Stream
Solid Waste Stream that may be Classified as Hazardous
Gasifier Ash High levels of trace elements are present and may be leached
from the ash.
Cyclone Dust High levels of trace elements are present. The dust contains
high levels of carbon (70-90%) and may be classified as
ignitable.
Sulfur Cake The sulfur will contain various components such as vanadium
salts, thiocyanatea, and thiosulfates.
MEA Slowdown This stream will contain oxazolidin-2, l-(2-hydroxyethyl)
imidazolindone-2; diethyl urea; dithioc
and other high molecular weight compoui
formation of nonregenerable complexes.
imidazolindone-2; diethyl urea; dithiocarbamates; thiocarbamides;
o and other high molecular weight compounds resulting from the
-------
The data needs for the multimedia waste streams and the process
and process streams associated with Wellman-Galusha gasification
systems are summarized in Tables 1.4-1 and 1.4-2, respectively.
In general, data associated with the gasification of high-sulfur
bituminous coal are currently not available. Since existing and
planned commercial Wellman-Galusha gasification plants use low-
sulfur bituminous and anthracite coals, data on high-sulfur coals
may have to be obtained from bench-scale units. Data on the per-
formance of and waste streams from sulfur recovery processes are
not available.
Data requirements for assessing the health and environ-
mental impacts of nonregulated pollutants and streams will in-
volve pollutant-specific determinations, long term monitoring and
biological testing (including both acute and chronic tests for
health and ecological effects). The specific methodologies to be
used in performing these impact assessments are still under de-
velopment. Therefore, the specific data needs are not totally
defined.
1.5 ISSUES AND AREAS OF CONCERN BY PROGRAM OFFICES
The EPA Program Offices' issues and areas of concern for
Wellman-Calusha low-Btu gasification technology are briefly dis-
cussed here. The basic issues and areas of concern include:
• Wellman-Galusha gasification technology:
- At what stage should existing standards apply
to a developing technology?
- When and to what extent will the technology be
commercialized?
• Waste Streams from Wellman-Galusha facilities:
- What are the potentially harmful pollutants in
gaseous, liquid and solid waste streams including
potential fugitive emissions?
- What are the emission rates of regulated and un-
regulated pollutants?
- What potentially harmful pollutants in those
streams are not currently regulated?
- What are the health and ecological effects of
those pollutants and streams?
• Pollution control technology
- What technologies have been demonstrated in con-
trolling gaseous, liquid and solid waste streams
from Wellman-Galusha facilities?
31
-------
TABLE 1.4-1. SUMMARY OF WASTE STREAM CHARACTERIZATION
AND CONTROL DATA NEEDS AND PLANNED
ACTIVITIES TO OBTAIN THOSE DATA
Watte Stream Media
Waste Stream
Additional Characterization
Needed
Control Technology
Performance Needed
Planned Activities to
Obtain Data Need*
G&ievvs Emissions
Coal feeder vent gas
Start-up vent gas
Pokehole gases
Tar/quench liquor
aeparator vent gasea
Stretford oxidizer
vent gase*
Compounds present for gaai-
ficatlon of hlgh-auLfur coal
Chemical characteristics
during the start-up period
for various start-up
materials (I.e. coke, wood,
oil, etc.)
Compounds present for gasi-
fying bituminous (high- aad
low-sulfur) coals
Chemical and biological
characteristics for gasifying
high-sulfur bituminous,
anthracite and lignite coals
Chemical characterisation
Effectiveness and actual
cost of recycling this
stream to the gaalfier inlet
air
Effectiveness and energy
requirements using a flare
to control these gaaes. Cur-
rently there are no good tech-
niques for evaluating the
control effectiveness of
flares
Effectiveness of Injecting an
Inert gas (I.e. steam) Into
the pokehole during the poking
operation
Effectiveness of using
automatic pokers
Effectiveness of recycling
to the product gas
None should be required,
however, this vill depend
on the results of charac-
terisation studies.
This control will be evaluated
by Radian and ORNL at the
University of Mlnncaota (Duluth)
(UMD) Foster Wheeler/Stoic
gasification facility
The'Wellman-Galuaha test facility
at the U.S. Bureau of Mines at
Ft. Snelling Minn, has a start-
up vent flare that may be
available for teecing
None
The UMD facility will uae thla
for their tar storage tank.
Vent gaaes will be characterised
by Radian and ORNL
Potential test sites are
currently being pursued by
Radian.
KEA acid gas stream
Liquid Effluents*
Ash sluice water
Process condensate
Stretford blovdovn
Solid Wastes
Gaslfier ash
Cyclone dust
HEA blovdovn
Chemical characterization
Chemical and biological char-
acterizations for affluent
guideline standarda and com-
parison to the MEG's for high-
sulfur bituminous aad lignite
coals
Chemical and biological char-
acterizations for effluent
guidelines and comparison to
the HEG's for high-sulfur
bituminous, anthracite and
lignite coals
Chemical and biological char-
acterizations for effluent
guidelines and comparison to
the HEG's for high- and low-
sulfur bituminous, anthracite
and lignite coals
Chemical and biological char-
acterizations for high-
sulfur bituminous and lignite
coals. Leaching atudies are
needed to determine if the aah
is classified as hazardous by
the RCRA and determine any
potential problems.
Chemical aad biological char-
acterizations of dust collected
from gasifying high- and low*
sulfur bituminous and lignite
coals sre needed for the RCRA
and for determining potential
probloma.
Chemical and biological char-
acterizations of sulfur are
needed for the RCRA and for
determining potential problems.
Chemical and biological char-
acterizations are needed for
the RCRA and for determining
potential problaaa.
Effectiveness of using a Clau
and tall gas cleanup process
for sulfur removal
Effectiveness of collection
and reuse of the aah sluice
water
Effectiveness of concentrating
process condenaate by forced
evaporation
Effectiveness of reductive
incineration
Control and disposal require-
ments will be defined by the
RCRA based on chemical and
biological characteristic*.
Permitting agencies will also
define these requirements.
Control requirements will be
defined by the RCRA based on
chemical and biological
characteristics
Effectiveness of combusting
the dust nay be required
Control requirements will be
defined by the RCRA based on
chenlcal and biological
characteristics
Ash sluice water for the gasi-
fication of lignite at the Ft.
Snelllnft facility may be char-
acterized by Radian.
Laboratory teats may be performed
to evaluate the gaseoua emissions
generated by forced evaporation
No reductive incineration
process** are planned.
Leaching tests for lignite ash
are planned. Other leaching
tests for low-sulfur bituminous
aah may alao be performed
Control requirements will be
defined by the RCRA based on
chemical and biological
characteristics
Leaching tests for lignite are
planned. Other leaching tests
for low-sulfur bituminous coal
may be performed
Laboratory tests may be performed
to evaluate duat combustion
characteristics
Sulfur produced by the Stretford
process will be characterized if
a Stretford proctas Is used at
Pike County or if another teat
site can be obtained.
None
*Liquld effluents may fall under RCRA guidelines if they are disposed of on land.
32
-------
TABLE 1.4-2. PROCESS AND PROCESS STREAM DATA NEEDS AND PLANNED
ACTIVITIES TO OBTAIN THOSE DATA
Process
Data Needs
Planned Activities
Wellman-Galusha Gasifier
LO
CO
Particulate Removal -
Hot Cyclone
Gas Quenching/Cooling
Tar Removal -
Electrostatic Precipitation
Sulfur Removal - Stretford
End Use - Combustion
Fate of pollutants (sulfur species, nitrogen species, tars and oils)
for various gasifier operating conditions and coal feedstocks.
Operating conditions that need to be evaluated include steam/air
ratio, coal throughput, and bed depth. High-sulfur bituminous coal
has not been tested since all commercial facilities use low-sulfur
bituminous and anthracite coals.
Collection efficiencies of hot cyclones are needed since the
participates not removed will affect downstream gas purification
processes and the raw gas combustion process characteristics and
flue gases.
Fate and distribution of sulfur species, nitrogen species, tars,
oils and particulate matter are needed. The quenched and cooled
gas characteristics will affect the performance and design of
downstream purification processes.
Tar removal effectiveness needs to be determined since residual
tar/oil aerosols will affect the performance and design of
downstream sulfur removal processes.
Sulfur removal effectiveness needs to be determined. There are
currently no data on the performance of the Stretford process
used to remove HjS from low-Btu gas.
Combustion gases from burning hot raw gas, quenched gas and
desulfurized gas are needed along with tar combustion gases.
Research Triangle Institute and North
Carolina State University will be performing
parametric studies on bench-scale gasifiers
using various coal feedstocks.
Particulate removal efficiency studies for
the hot cyclone at the UMD facility are
planned.
The Can Do Wellman-Galusha facility
will have a gas quenching/cooling process.
The Chapman facility may also be used to
evaluate this process.
The tar/oil removal effectiveness vill be
determined at the UMD gasification facility.
Stretford process performance will be
evaluated by EPA and DOE if a Stretford unit
is used at Pike County. Other test sites
are currently being Identified.
Combustion gases will be characterized at
the UMD facility.
-------
- VJhat are the economics and energy usage associated
with controlling those streams?
Each Program Office needs representative, quantitative and long-
term monitoring data concerning:
• Chemical, physical, and biological characteristics
of the waste streams to air, water and/or land,
• Technology required to control those waste streams,
and
• Chemical, physical, and biological characteristics
of fugitive emissions resulting from the processing,
storage, and transport of waste streams, products,
and by-products.
The waste stream and fugitive emission data must be able to stand
up to a traditional peer review and court review before the data
are used for recommending standards. Control technology data
should be obtained on demonstration-scale control equipment. A
summary of the EPA Program Office data needs is given in Table
1.5-1.
34
-------
TABLE 1.5-1. EPA PROGRAM OFFICE DATA NEEDS
EPA Program
Office
OAQPS
OWP/Effluent
Guidelines Div.
osw
Chemical Analyses
• Air Emissions
- Long tern monitoring
and quantitative
analyses for:
• CO
' N0x
• Nonmethane
hydrocarbons
• Photochemical
oxidants
' S0x
• Pb
- Identification and
quantification of
other potentially
harmful pollutants:
Sulfur species
• Organlcs
• Trace elements
• Pollutant Monitoring
- Development of
cont Inuous /semi-
continuous
monitoring devices
• Liquid Effluents
- Long-term monitoring
and quantitative
analyses for:
• 129 priority
pollutants
• n/in
• ouu
• pH
• Grease/oils
• P
• COD
- Identification and
quantification of
other potentially
harmful pollutants
• Pollutant Monitoring
- Development of
continuous/semi-
continuous
monitoring devices
• Solid Wastes or Haste
Streams Sent to Land
Disposal Sites
- pH
- Reactivity (explo-
sion potential)
- Hadium-226
- Leachate
As
Cd
Pb
Se
Endrin
Methoxychlor
2,4-D
Ba
Cr
Hg
Ag
Lindane
Toxaphane
2,4,5-TP
• Recommendations for
New/Modified Methods
Biological Analyses Physical Analyses
Done • Air Emissions
- Participate
loading and
size
distribution
None • Liquid Effluents
- Long-term
monitoring and
quantitative
analysis for:
. TSS
• TtlC
1113
• Solid Wastes or • Solid Wastes or
Waste Streams Sent Waste Streams Sent
to Land Disposal to Land Disposal
Sites Sites
- Leachate - Flash point
• Mutagenicity - Corrosion tests
• Bloaccunu-
lativity
• Toxic organic
(LD-50)
Control Technology
Control Effectiveness
for Normal, Start-up,
Upset and Shut-down
Operation and for
Operational Responses
• Identification and
Quantification of
Liquid and/or Solid
Waste Streams from
Air Pollution Control
Technology
• Recommendations for
Control Technology
R&D Needs
• Control Effectiveness
for Hornal, start-up,
Upset and Shut-down
Operation and for
Operational Responses
• Identification and
Quantification of
Gaseous and/or Solid
Waste Streams from
Water Pollution
Control Technology
• Recommendations for
Control Technology
R&D Needs
• Identification and
Quantification of
Leachable matter from
•olid wastes
• Control Effectiveness
of leechate contain-
ment/control alternatives
35
-------
TABLE 1.5-1. (Continued)
EPA Program
Office
OTS
Chemical Analyses
Products/By-Products
and Streams not Regu-
lated by other
Program Offices
- Identification and
quantification of
potentially harmful
organic and
inorganic species
Biological Analyses Physical Analyses
• Products/By-
Products and
Streams not Regu-
lated by other
Program Offices
- Health effect*
' Ecological effect*
Control Technology
• Recommendations for
Controlling Exposure to
Potentially Harmful
Streams
ORP
Gaseous, Liquid and
Solid Waste Streams
- a, 3 and Y-ray
measurements
- Quantitative
analyses for U-235
and Th-232
None
Gaseous Emissions
- Participate
loading and
size
distribution
OE
Office of
Criteria and
Standards
Data needs are similar to those needed by other Program Offices. Data should be sufficient to
evaluate permits and to issue permits for gasification plants.
Gaseous, Liquid and
Solid Waste Streams
- Identification and
quantification of
potentially harmful
organic and
inorganic species
Gaseous, Liquid and
Solid Waste Streams
- Health effects
- Ecological
effects
Office of
Noise
Abatement
and Control
Control Effectlveneas
for Moroml, Start-up,
Upset and Shut-dovn
Operation and for
Operational Responses
Identification and
Quantification of
Pollutants in Gaseous,
Liquid and/or Solid
Waate Streams from
Each Control Tech-
nology
Currently no data are needed for coal gasification technology. Noise sources should be identified.
Gaseous Emissions
- Particulate
loading and
size
distribution
Liquid Effluents
- TSS
- TDS
OAQPS: Office of Air Quality Planning and Standard*
OWF: Office of Water Planning
OSW: Office of Solid Wastee
OTS: Office of Toxic Substance*
OIF: Office of Radiation Planning
OE: Office of Enforcement
36
-------
S1CTION 2.0
UELLMAN-CALUSHA GASIFICATION SYSTEMS
Wellman-Galusha gasifiers are one of the commercially
available gasifiers used to produce low-Btu (^5.9 MJ/Nm^ or
150 Btu/scf) gas from a variety of coal feedstocks. In this sec-
tion an overview of Wellman-Calusha gasification systems is
presented followed by detailed descriptions of the systems ex-
amined in this report.
2.1 WELLMAN-GALUSHA GASIFICATION SYSTEMS: TECHNOLOGY
OVERVIEW
The overview of Wellman-Galusha gasification systems
contains discussions concerning development status, industrial
applicability, commercial prospects, energy efficiency, and
costs. Detailed energy efficiencies and costs for the systems
examined in this report are given in Section 2.2.
2.1.1 Development Status
About 150 Wellman-Galusha gasifiers have been installed
worldwide since 1941. While the operating status, locations, and
uses of these gasifiers are mostly unknown, the current status of
Wellman-Galusha gasifiers in the U.S. is summarized in Table
2.1-1. Eleven gasifiers are currently being used to produce low-
Btu gas from anthracite or low-sulfur bituminous coals. In all
of these applications, the hot, raw product gas is used directly
to fire lime or brick kilns. The only gas cleanup process used
in these facilities is a cyclone for partial particulate removal.
Glen-Gery Brick and Hazelton Brick Companies gasify an-
thracite coal in nine gasifiers which are located in eastern
Pennsylvania. The product gas contains essentially no tars and
oils and is used on-site to fire brick kilns. A hot cyclone is
used to remove about 60 to 70 percent of the particulates en-
trained in the product gas.
In Ohio, National Lime and Stone Company intermittently
operates two Wellman-Galusha gasifiers with low-sulfur bituminous
coal. The product gas contains tars and particulates and, after
particulate removal in a cyclone, is used on-site to fire lime
kilns.
Five gasifiers are scheduled to become operational in
1980-1982. The Can Do. Inc. gasification facility will operate
two gasifiers with product gas quenching/cooling processes. The
Pike County facility will have two gasifiers and may have gas
37
-------
TABLE 2.1-1. CURRENT WELLMAN-GALUSHA COAL GASIFICATION FACILITIES IN THE UNITED STATES
CO
Caalfler Deed
wellmao-Galusha
Uallmao-Caluaba
Wellmen-Galueha
•ellnen-Caluaha
Vellnao-Galuaha
Hellnaa-Gelueha
Coal Feedstock
Anthracite, low
aulfur (-V0.7)
Anthracite, low
aulfur
Anthracite, low
aulfur
Bituminous, low
aulfur (•NO. 71)
Anthracite, low
sulfur
tT Bltomlaoua
CO Subbltumlaona
MT Bltuminoua
«D Lignite
Bltuminoua, low
aulfur
Gaa Purification
Processes
• Cyclone
• Cyclone
• Cyclone
• Cyclone
• Cyclone
• Gaa Quench
• Cyclone
• Gaa Quench
• Tar/Liquor separation
• Cyclone
• Poaslbly gaa quench.
Company/Location
Glen-Gery Brick Co.
- York, PA
- Beading, PA
- Shoemakeraville, FA
- Wat son town, PA
- Hew Oxford, PA
Hazel ton Brick Co.
- Hacelton, PA
Blnghamton Brick Co.
- Blnghamton, MT
Rational Lime 4 Stone Co.
- Cary, OH
Can Do, Inc.
- Haselton. PA
Bureau of Mlnea
- Ft. Snelllng. Ml
Pike County
- Plkevllle, KT
Huaber of
Gaaiflera Remarks
8 * Currently la commercial operation
• Product gas used to fire brick kiln
4 • One gaalfler In use
• Three other gaaiflera inactive
• Product gaa used to fire brick kiln
2 • Gaaiflers not currently in use
1 • Currently in commercial operation
• Product gas used to fire line kiln
• Line will remove some of the aulfur
apeclea In the flue gaa
2 • To be completed in 1980
• Product gas to be used in en
industrial park
• Possibility of adding two more
gaslfiers
• Partial funding by DOC
1 • Commercial-size demonstration unit
• Partial funding by DOE
•• First series of test runs completed
In 1978
• Additional tests conducted In 1979
• Product gas was used to fire an
iron pelletlrlng kiln
• Excess product gaa waa combueted
2 • To be completed In 1982
• Product gaa used to fire pollen
tar/liquor aeparation,
waatewatar treatment
and aulfur removal
(Stratford)
and proceaa heater*
Partial funding by DOB
-------
TABLE 2.1-1. (CONTINUED)
Caslfler Used
Wellman-Galusha
Chapman (Wtlputte)
Coal Feedstock
Anthracite, low
•ulfur (M).7X)
Bituminous, low
•ulfur (-V0.6X)
Gas Purification
Processes
• Cyclone
• Cyclone
• Gaa quench
Company /Location
Howmet Aluminum
- Lancaster, PA
Holaton Army Ammunition Plant
- Kingsport, IM
Number of
Gaaifiara
1
12
Remarks
• To be completed in early 1980
• Product gas used to fire process
furnaces
• Possibility of adding up to eleven
•ore gasifiers
• Currently in comae rcial operation
• Product gas used to 'fire process
Foster Wheeler/Stoic Bituminous, low
sulfur
UJ
vo
We 11 man Ineaade
Bituminous
Kiley Morgan Bituminous
lignite
Foster Wheeler/Stoic Various
Vellman-Calusha
Hellman-Galusha
Wellmaa-Caluaha
Coke
Coke
Lignite
Tar/liquor separation
Hastewater evaporation
Cyclone
Electrostatic
preclpltator (ESP)
Cyclone
ESP
Sulfur removal
(Stretford)
Cyclone
Cyclone
quench
Cyclone
Cyclone
Rot available
University of Minnesota
- Duluth, MN
Caterpillar, Inc.
- York, PA
Eiley Stoker Co.
- Worchester, MA
General Motors Corp
- Siglnav, Mich
Gulf t Western (N. J. zinc)
- Auhtabula, Ohio
Olln Chemical Corp.
- Ashtabula, Ohio
Chemical Exchange
- Houston, TX
heaters
• Only two gasifiers are operated at
one time to meet current fuel needs
• !iy-product tar used with coal to
fire a steam boiler
• Construction completed In 1978
• Partial funding by DOE
• 100 hours of start-up tests
completed
• Full time operation scheduled for
fall 1979
• Product gas to be used to fire
steam boilers
• By-product tar to be used to fire
a steam boiler
• Demonstration-commercial size
• Product gas to be used to fire
process heaters
• Commercial-size demonstration unit
• Coal hopper vent control
• Commercial size demonstration -unit'
• Gas used in metal processing fur-
nace
• Start up in 1979
• Gas used in process furnace
• Installed 1963
• Gas used in process furnace
• Installed 1963
• Start up in 1979
• Gas end use not available
-------
quenching/cooling and sulfur removal. The Howmet Aluminum Com-
pany's facility will be similar to those used by the Glen-Cery
Brick Company.
Cabot Titanium and Olin Chemicals have each operated
Wellman-Calusha gasifiers in Ashtabula, Ohio. These gasifiers
used a petroleum coke feed and pure oxygen to generate high-
purity (greater than 99%) carbon monoxide reducing gas. Wellman-
Calusha gasifiers in Taiwan, Spain and Cuba have been similarly
operated. These and other past applications of the gas produced
from Wellman-Galusha gasifiers are summarized in Table 2.1-2.
2.1.2 Industrial Applicability
In the near term, Wellman-Calusha gasifiers will be used
primarily to produce a fuel gas for on-site uses, including:
• fuel to provide direct heat for processes such as
brick and lime kilns, and
• fuel for industrial boilers.
Production of gas for off-site use will probably not be signifi-
cant because of the cost of transporting atmospheric pressure,
low-Btu gas.
While low-Btu gas certainly is an applicable fuel for
most new industrial uses, industrial boilers currently fueled by
natural gas and oils can also be retrofitted to burn low-Btu gas.
However, since natural gas and low-Btu gas have different combus-
tion characteristics, process burners must be modified or re-
placed and fuel supply lines and manifolds must be enlarged to
handle the increased fuel gas flows. Depending on the composi-
tion of the low-Btu gas, changes may also be required to accomo-
date an increased flow of combustion products. If changes in the
process cannot compensate for these increased flows and pres-
sure drops, process derating may be unavoidable. The inability
to handle increased flue gas flows could cause a derating of up
to about 20 percent. Some processes also need recuperation for
fuel air preheat to maintain equivalent furnace temperatures when
operating wit;h low-Btu gas. Because of these considerations, in
many instance^, retrofitting existing natural gas-fired equipment
to allow the use of low-Btu gas may be impractical. Existing
natural gas consuming industrial processes were classified accor-
ding to their suitability for operation with low-Btu gas (Ref.
6). This classification is reported in Table 2.1-3. Processes
in the first category, which in general are large energy con-
sumers, are well suited to the use of a low-Btu fuel gas. Gener-
ally, retrofit problems in these applications will tend to be
less severe than those encountered in other applications.
40
-------
TABLE 2.1-2. PAST USERS OF GAS PRODUCED BY
WELLMAN-GALUSHA GASIFIERSa
• chemical plants
• glass plants
• steel mills
• magnesium manufacturers
• silk mills
• bakeries
• wire mills
• foundries
• potteries
• aluminum and stainless steel
manufacturers
• ordinance plants
• tin plate mills
• lime plants
• brick plants
• zinc smelters
• iron ore processors
• fertilizer plants
aSpecific uses varied from heat treating (in glass and steel
mills) to synthesis gas (for synthetic fertilizer manufacture)
Materials gasified included charcoal, coke, anthracite and
bituminous coals.
Source: Ref. 5
41
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TABLE 2.1-3.
CLASSIFICATION OF INDUSTRIAL PROCESSES WITH RESPECT TO EASE
OF RETROFIT FOR LOW-BTU GAS
Attractive for Retrofit
Potentially Attractive for
Retrofit
Unattractive for Retrofit
to
Sintering (primary metals industry)
Palletizing (primary metals indus-
try)
Incinerators (all industries)
Afterburners (all industries)
Various kilns (ceramics industry,
lumber industry)
Reheat furnaces (primary metals
industry
Soaking pits (iron and steel
industry
Air preheating (iron and steel
industry
Open hearth furnaces (iron and
steel industry)
Direct reduction of iron ore (iron
and steel industry)
Calcining (cement, lime, aluminum
industries)
Heat treating where finish is not
important (primary metals,
ceramics industries)
Forging furnaces (iron and steel
industries)
Direct-fired atmosphere generators
(primary metals, ceramic
industry)
Smelting operations (nonferrous
metals industry)
Industrial boilers
Direct firing on finished products
(ceramics, primary metals
industries)
Indirect fired furnaces with pull
through radiant burners
Glass tanks (glass industry)
Finish annealing operations
(primary metals industry)
Processes using flat flame burners
(ceramics, primary metals
industry)
Processes using partial premix
burners
Blast furnace injection (iron and
steel industry)
Paper and print drying (pulp and
paper industry)
Processes using flow
through radiant burners
(ceramic or metallic
grid)
Automated flame heating
systems such as
soldering, brazing, and
lamp sealing (glass,
pottery, special metals)
Glass and ceramic fiber
production (glass
industry)
Glass cutting, scraping,
annealing (glass
industry
Direct-fired or indirect-
fired space heaters
Source: Ref. 6
-------
The second category includes processes that may be at-
tractive for operation with low-Btu gas. For these processes,
suitable burners may need to be developed, or substantially more
process modification or derating may be necessary in a retrofit
application.
The third category includes those processes that are un-
attractive for retrofitting with low-Btu gas.
2.1.3 Commercial Prospects
Many industries either must have or prefer a gaseous
fuel to meet their energy requirements. In the near term, low-
Btu gas from fixed-bed, atmospheric-pressure gasifiers like the
Wellman-Galusha will be used primarily as a substitute fuel by
industries threatened with natural gas curtailments. The low-Btu
gas will principally be considered for use as a fuel in on-site
furnaces, heaters, kilns, and small boilers. Its substitution
for natural gas will most likely occur when: 1) the costs of
retrofitting for use of the low-Btu gas are small, and 2) the
low-Btu gas requires minimal purification.
In both new and retrofit applications where use of a
gaseous fuel is not mandatory, low-Btu coal gasification is main-
ly competing with the alternative of direct coal combustion.
Factors affecting the selection of coal gasification or direct
coal combustion include: the suitability of the coal conversion
technology for satisfying the specific end use, the cost of the
technology, the cost and difficulty of retrofitting, the cost of
environmental controls, and the cost of the coal.
Increased commercialization of low-Btu gasification sys-
tems like the Wellman-Galusha will also depend on demonstration
of the environmental acceptability of the gasification systems.
Although commercially available controls seem to be adequate,
some of the controls (such as treatment of process condensate
blowdown) have not been adequately demonstrated on coal gasifica-
tion systems. The costs of these controls are also uncertain.
Gasification systems featuring Wellman-Galusha gasifiers
are most suitable for relatively small applications, with fuel
demands ranging from about 8.8 to 88 HW of thermal energy (30-300
million Btu/hr). This would require use of from 1 to 10 gasi-
fiers. Energy demands greater than about 88 MVJ (300 million
Btu/hr) may be better served by gasification systems using gasi-
fiers with larger capacities (for example, pressurized
gasifiers).
McDowell-Wellman can deliver Wellman-Galusha gasifiers 6
to 8 months from the date of order (Ref. 2). However, systems
43
-------
using 2 to 4 gasifiers and including extensive gas purification
will require 18 to 24 months from initial feasibility studies to
full-scale operation (Ref. 1).
Uellman-Galusha gasification systems will be most widely
used in industrialized areas which also contain available coal
reserves. Two areas of the country which meet these conditions
are the Northeast and Midwest.
2.1.4 Input Materials, Products, and By-Products
Input materials required for Wellman-Galusha gasifica-
tion systems include coal, air, and water. If a sulfur removal
process is used, sulfur removal sorbents or reactants will be ad-
ditional input materials. Low-Btu gas is the only product from
these systems with tar/oils and sulfur being potential by-
products.
Input Materials -
Wellman-Galusha gasifiers require a sized coal feed-
stock. For less reactive coal feedstocks, e.g., anthracite, a
size range between 7.9 to 14.3 tnm (0.31 to 0.56 in.) is pre-
ferred. A size range of 4.8 to 7.9 mm (0.19 to 0.31 in.) may be
used, although at a lower coal feedrate. For reactive coals,
e.g., bituminous coals, larger particle sizes can be used, with
the preferred range being 26 to 51 mm (1 to 2 in.) (Refs. 5, 7).
In all cases, excessive fines tend to decrease the gasifier ca-
pacity by causing operating problems such as channeling and/or
increased pressure drops. Oversized particles, because of their
lower surface area per unit weight, also decrease the gasifier
capacity.
Gasification of high-moisture coals (such as lignite)
yields product gases with high-moisture contents and reduced tem-
peratures. Significant condensation of the tars in the product
gas could, therefore, occur as the gas leaves the gasifier.
Coals with high moisture contents also cause lower gasification
efficiencies because of the energy that must be supplied to
evaporate the moisture in the coal. Coals with excessively high
moisture contents could be dried before being fed to the gasi-
fier. The decision to dry a high moisture coal versus purchase
lower moisture (and probably more costly) coal must be determined
on an individual case basis considering site-specific economic
factors.
In general, coal ash softening temperatures are prefer-
red to be higher than 1480 K (2200°F). Coals with softening
-------
points lower than about 1260 K (1800°F) can be gasified by in-
creasing the amount of steam introduced with the reaction air
(Ref. 7).
Air and water are also required for producing the pro-
duct low-Btu gas. Vaporization of water in the gasifier water
jacket provides the steam used for gasification. Makeup water is
required for these gasifier jackets and possibly for ash quench-
ing.
Products -
The main product of a Wellman-Galusha gasification sys-
tem is low-Btu gas. The composition of the low-Btu product gas
is dependent upon the requirements of the end use. In some in-
stances, a "very clean" gas (e.g., contain essentially no par-
ticulates, sulfur compounds, or tars and oils) may be required,
such as that used for certain direct heating/drying applica-
tions. Conversely, a low-Btu fuel gas which has only undergone
partial particulate removal and still contains particulate,
sulfur compounds, etc., may be acceptable.
In this report, three product gas specifications were
examined. These correspond to industrial fuels considered to be:
• "moderately clean",
• "clean", and
• "very clean".
The level of contaminants allowable in each fuel type
were selected to provide a reasonable range of performance con-
straints for analyzing gas purification processes used in a gas-
ification facility producing an industrial fuel gas. Details of
the product gas specifications selected are presented in Section
2.2.
By-Products -
Gasification of coals containing significant amounts of
volatile matter produces tars and oils in the raw product gas.
These tars and oils can be recovered as by-products if the raw
low-Btu gas is cooled. The amount recovered depends on the coal
feedstock properties and the desired product gas specifications.
Sulfur may also be recovered as a by-product if a desulfurized
product gas is desired. A third by-product, steam, is produced
by systems gasifying anthracite and using a waste heat boiler to
cool the low-Btu gas.
-------
The energy efficiency of Wellman-Galusha gasification
systems will be a significant factor affecting their commercial-
ization potential. However, this factor may become less critical
if alternative fuels, e.g., natural gas or petroleum liquids, are
either unavailable or too expensive.
A large number of energy efficiencies can conceivably be
defined. In this study, three efficiencies are used:
• coal to low-Btu gas efficiency which relates the en-
ergy of the product gas (higher heating value or HHV
of combustibles plus sensible heat) to the HHV of the
feed coal,
• gas production efficiency which relates the energy of
the product gas to the total energy input to the sys-
tem (HHV of coal plus utility steam and electricity
energy), and
• overall thermal efficiency which relates the energy
of the product gas and by-product tars, oils, and
steam to the total energy input to the system.
Mathematically, the three energy efficiencies are defined as fol-
lows :
n.T - out x 100
81 (QT> in
and
^xlOO
in
46
-------
where
ncg - Coal to gas efficiency (%)
ng T - gas production efficiency (7.)
rim • overall thermal efficiency (%)
(Q») out " output product gas energy
(Qc) ^n - input coal energy
(Q™) t - total output energy (product gas +
by-products H- steam)
" total input energy (coal + steam +
electricity)
Values for these energy efficiencies are dependent upon the coal
feedstock and the gas purification processes used. Coal to gas
efficiencies (riCg) for the systems examined in this study range
from about 60 to 93 percent. Product gas production efficiencies
(DPT) range from about 50 to 92 percent while overall thermal
efficiencies Cn-p) range from 64 to 92 percent. Section 2.2
gives further details on the calculated energy efficiencies for
the Wellman-Galusha gasification systems examined.
2.1.6 Product Gas Costs
Product gas costs are dependent upon coal feedstock,
product gas specification (e.g., tar/sulfur content), and plant
size. Product gas costs for systems producing a hot, raw low-Btu
gas range from approximately $1.90 to $3.80 per GJ ($2.00 to
$4.00 per 10" Btu). For systems producing a desulfurized pro-
duct gas using a Stretford sulfur removal process, product gas
costs range from $3.40 to $5.80 per GJ ($3.60 to $6.10 per 106
Btu). If an MEA sulfur removal process is used to remove gaseous
sulfur species, desulfurized product gas costs range from $3.80
to $6.10 per GJ ($4.00 to $6.40 per 106 Btu).
For almost all of these gasification systems, the major
cost item is the coal feedstock. For systems using anthracite
coal, the coal costs represent 36 to 56 percent of the total
costs of the product gas. For systems using low-sulfur bitumi-
nous coal, coal costs are between 36 and 70 percent of the
product gas costs and for high-sulfur bituminous coal, 25 to 42
47
-------
percent. Details of the capital and operating costs for the sys-
tems considered in this report are presented in Section 2.2.
Gilbert Associates, Inc. (Ref. 1) and Dravo Corporation
(Ref. 8) have also developed costs for fixed-bed, atmospheric-
pressure gasifiers which are essentially similar to Wellman-
Galusha gasifiers. These cost estimates are summarized in Tables
2.1-4 and 2.1-5, respectively. In general, the gas costs shown
in these tables are lower than those estimated in this study for
similar systems. However, insufficient details were provided
with the literature estimates to ascertain the basis for the dif-
ferences. Like the cost estimates for the systems examined here
though, the literature estimates indicate that coal costs are a
major portion of the gas costs.
2.2 DESCRIPTION OF PROCESSES AND SYSTEMS
Descriptions of the Wellman-Galusha gasification systems
examined in this report are presented in this section. Section
2.2.1 is a discussion of factors which affect the selection of
processes for use in low-Btu systems. Detailed flow diagrams and
material balances for the systems examined are contained in Sec-
tion 2.2.2. Also presented in Section 2.2.2 are estimates of the
energy conversion efficiencies and capital and annualized oper-
ating costs for those systems. A more detailed description of
the operations and processes found in the Wellman-Galusha sys-
tems examined is presented in Section 2.2.3.
2.2.1 Factors Affecting Process Selection
The primary factors affecting selection of the processes
used in Wellman-Calusha gasification systems are:
• coal feedstock properties and gasifier operating
parameters
• product gas specifications,
• capacity, and
• location of the facility.
Coal Feedstock Properties and Gasifier Operating
Parameters -
The properties of the coal and gasifier operating para-
meters determine the kinds and quantities of contaminants found
in the raw product gas. Contaminants of principal concern are
tars and oils, particulates, and compounds of sulfur and nitro-
gen. Moisture in the raw product gas is determined by the mois-
ture content of the feed coal and the amount of steam introduced
with the reactant air.
48
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TABLE 2.1-4.
ESTIMATED COSTS FOR A 73.3 MW (250
MILLION BTU/HR)a COAL GASIFICATION
PLANT USING FIXED-BED ATMOSPHERIC
PRESSURE GASIFIERS
Capital Costb, Million $
Coal Cost, $/ton
$/day
$/106 Btu
Other Operating Costs, $/day
$/106 Btu
By-Product Credit, $/106 Btu
Net Gas Cost, $/106 Btu
Anthracite
(Hot Gas)
4.0-6.7
50
13,900-15,700
2.31-2.61
3,900-5,500
0.65-0.93
2.97-3.35
Low Sulfur
Bituminous
(Hot Gas)
1.7-4.5
40
10,200-10,300
1.70-1.71
2,300-3,900
0.38-0.65
2.08-2.36
High Sulfur
Bituminous
(Cold Gas)
5.7-8.5
30
8,600-9,200
1.43-1.53
4,850-6,540
0.81-1.09
0.08-0.14
2.18-2.45
a
is limited to particulate removal in a cyclone. Gas purification for systems
using high sulfur bituminous coals includes cooling and the removal of
hydrogen sulfide. The costs are assumed to be mid-1977 dollars; the
accounting method used to develop the operating cost is unknown. By-product
credits for the high-sulfur system are lOc/gal for tar and $25/ton for
sulfur.
^Retrofitting costs are omitted.
Source: Ref. 1
49
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TABLE 2.1-5. ESTIMATED COSTS FOR COAL GASIFICATION PLANTS
CONTAINING ONE, FIVE OR TEN FIXED-BED
ATMOSPHERIC PRESSURE GASIFIERSa
Number of Gaaifiers (10' Diameter)
10
Co«l Feed (2" to IV). kg/s (TPD)b
Sulfur Content, I
Ga* Production, MW (10* Btu/day)
Capital Colt, $10*
Adjusted Capital Co«tc, $10*
Coal Coat $/ton
$/day
S/10'. Btu
Estimated Gas Costs, $/108 Btud
Capital Cost, Utility Financing
Adj. Capital Cost, Utility Financing
Capital Cost, Equity Financing
Adj. Capital Cost, Equity Financing
0.9 (78)
3.0
20 (1.64)
4.46
3.80
25
1950
1.19
3.75
3.59
3.06
2.99
0.9 (78)
0.7
20 (1.64)
2.90
2.24
35
2730
1.66
3.44
2.96
4.7 (390)
3.0
100 (8.2)
11.09
9.18
25
9750
1.19
2.48
2.36
2.12
2.05
4.7 (390)
0.7
100 (8.2)
8.09
6.18
35
13.650
1.66
2.62
2.33
9.4 (780)
3.0
200 (H.4)
17.3
14.2
25
19,500
1.19
2.24
2.24
1.95
1.90
9.4 (780)
0.7
200 (16.4)
13.3
10.2
35
27,300
1.66
2.46
2.21
The coals are bituminous coals with equal heating values.
°Adjustsd capital cost* omit costs for administration buildings and wastewater treatment.
The Utility Financing Method as outlined in DOE's Ga* Cost Guideline* was used. The cost* are average cost* and assume-
20-year project life
Straight-line depreciation on plant investment, allowance for fund* used during construction, and capitalised
portion of start-up co*t*
Debt-equity ratio of 75/2S
Percent interest on debt of 9 percent
Percent return on equity of 15 percent
Federal income tax rate of 48 percent.
Maintenance cost* are proportional to the capital costs:
6 percent for coal feed preparation, coal gasification, gas quench and solid* removal
3 percent for sulfur recovery, product gas compression and drying, oxygen plant, liquid and aolid effluent
treating and water treating
1 percent for all other offsites.
Included in the total capital requirement* arc:
Estimated installed cost of both onsite and offsite facilities
Project contingency at 15 percent of the estimated cost of the facilities
Initial charge of catalyst and chemicals
Paid-up royalties
Allowance for fund* u«ed during construction
Start-up costs
Working capital.
Operating costs are based on a 90 percent plant service factor. Included in operating costs are:
Purchased utilities
Raw materials
Catalysts and qhemicals
Purchased water
Labor
Administration
Supplies
Local taxes and, Insurance
Ash disposal.
No credit is taken for byproducts such as sulfur, tars, oils, etc. As stated above, it is aisumed that power, (team and
watar will be purchased. , The co*t of power 1* 2« per kw hour. Steam cost 1* a**umed to be $2 per 1000 pound*. Coolino.
water is 3C par 1000 gallon* and m*k*-up water 40c per 1000 gallon*.
Source: Ref. 8 ';
50
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Coal feed properties also determine the compositions and
quantities of the multimedia emissions from the gasifier (for ex-
ample, the quantity and characteristics of gasifier ash). To a
small extent, properties of the coal feed also define applicable
coal preparation processes.
The properties of coal feeds examined in this report are
summarized in Table 2.2-1. The four coal feeds selected a) pro-
vide a reasonable range of properties affecting environmental
discharges, and b) represent feedstocks for which actual gasifi-
cation test data are available. The compositions of the anthra-
cite and low-sulfur bituminous coals are typical of Pennsylvania
anthracite and eastern Kentucky bituminous coals. The composi-
tion of the high-sulfur bituminous coal is representative of sev-
eral eastern bituminous coals (including bituminous coals from
Illinois and Ohio). The lignite coal shown is a North Dakota
lignite.
The compositions of the raw product gases produced from
the gasification of the four selected coals are shown in Table
2.2-2. These compositions are largely based on the results of
gasifier testing, as discussed in Section 3. The effects of coal
feed properties on contaminants in the raw product gas and on the
quantities and characteristics of the multimedia waste streams
are discussed below.
Tars and Oils - The quantities and characteristics of
the tars and oils found in the raw low-Btu product gas depend
upon the properties of the coal feedstock and on the time-
temperature profile of the coal as it passes through the gasi-
fier. Coals containing little volatile matter (like anthracite)
form virtually no tars while coals with larger amounts of vol-
atiles will produce significant amounts of tars.
Tars ands oils in the product gas can interfere with the
operation of downstream processes. Most sulfur removal pro-
cesses, for example, operate best when inlet tar and oil concen-
trations are small. This is because tars and oils may be ab-
sorbed into the sorbent, causing foaming problems and possibly
fouling of the absorber packing. Nearly complete removal of tars
and oils is required to maintain efficient operation. Also, if
the sulfur compounds are recovered as elemental sulfur, absorbed
tars and oils could contaminate the sulfur by-product. The
removal of tars and oils may also be necessary to protect other
downstream equipment such as blowers.
Particulates - The quantity and characteristics of the
particulates found in the product gas also depend on the proper-
ties of the coal feedstock. Gasification of hard coals such as
anthracite, produces substantially less entrained particulates
51
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TABLE 2.2-1. COAL COMPOSITIONS EXAMINED3
Low-Sulfur High-Sulfur
Anthracite Bituminous Bituminous Lignite
Proximate Analysis (wt %)
Moisture 0.94 2.5 6.1 35.0
Volatile Matter 5.15 36.7 34.5 27.8
Fixed Carbon 82.24 57.9 51.0 28.9
Ash 11.67 2.9 8.4 8.3
Ultimate Analysis (wt %)
Carbon 81.2 79.1 67.9 41.5
Hydrogen 2.1 5.6 4.8 2.9
Nitrogen 0.8 1.6 2.1 1.0
Oxygen 2.6 7.6 6.8 10.5
Sulfur 0.6 0.7 3.9 0.9
Ash 11.7 2.9 8.4 8.3
Moisture 0.9 2.5 6.1 35.0
High Heating Value
(as received, MJ/kg 29.9 33.2 29.2 16.0
Btu/lb) 12,900 14,300 12,600 6,900
a
Coal compositions selected a) provide a reasonable range of properties
affecting environmental discharges and b) represent feedstocks for
which environmental test data are available.
Source: Refs. 9, 10, 11
52
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TABLE 2.2-2.
RAW PRODUCT GAS COMPOSITIONS RESULTING FROM THE
GASIFICATION OF THE FOUR SELECTED COALS3
Low- Sulfur
Anthracite Bituminous
Component
CO
H2
CO 2
N2
CHf
CaHi,
C2H6
C3H6
CsHs
HaS
COS
CS2
S02
NHs
HCN
Ar
02
Dry
25.45
16.31
5.51
51.48
0.23
JO. 0001
JO. 0004
0.081
0.009
0.0001
0.002
0.02
0.004
ND
0.9
Water
0.06
Dust
0.15 (0.06) 0.73
Tar/Oil
High-Sulfur
Bituminous
Lignite
Gas Composition, % vol
25.9
12.5
4.9
53.4
2.1
0.27
0.10
ND
ND
0.10
0.01
ND
0.002
0.03
0.01
0.6
ND
Content ,
0.06
Loading,
(0.30)
Loading,
ND 39 (16)
28.83
14.81
3.42
48.90
2.72
0.27
0.10
ND
ND
0.84 - 0.86
0.01 - 0.03
ND
0.002
0.03
0.01
ND
ND
mole/mole dry gas
0.14
g/Nm3 (gr/scf)
0.87 (0.36) 0.
g/Nm3 (gr/scf)
39 (16)
30.6
16.85
3.89
46.55
1.30
0.039
0.089
0.025
0.024
0.25
0.011
ND
0.002
0.03
0.01
0.6
ND
0.30
78 (0.32)
36 (15)
aThese gas compositions are mostly based on experimental data as discussed in
Section 3.
ND: Not determined
Source: Refs. 9, 10, 11
53
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than gasification of the softer and more reactive coals such as
bituminous, subbituminous, and lignite coals. Particulate re-
moval is almost always required to meet product gas specifica-
tions and protect downstream equipment.
Sulfur Compounds - The raw product gas contains various
compounds of sulfur including H£S and COS with small amounts of
carbon disulfide, mercaptans, S02, and possibly free sulfur.
The quantities and distribution of these compounds in the raw
product gas are dependent on the properties of the coal feedstock
and the operating conditions of the gasifier. The most important
coal properties are the coal volatile matter, the coal ash and
its composition, and the sulfur content and distribution in the
coal. Among the important operating parameters are the time-
temperature profile of the coal as it passes through the gasi-
fier, the size of coal particles, the superficial velocity of the
product gas, and the amount of steam fed to the gasifier (Ref.
12).
As discussed in Section 3, few data are available de-
scribing the distribution of sulfur in gases produced from
Wellman-Calusha gasifiers. Although hydrogen sulfide and car-
bonyl sulfide are the principal sulfur species in the product
gas, the quantitative distribution of H2S and COS is largely
unknown. The distribution of sulfur between gaseous and solid
(ash) phases is also largely unknown and variable. Alkaline
ashes, typical of those obtained from lignite and certain bitu-
minous coals, may retain significant amounts of sulfur.
The sulfur distributions shown in Table 2.2-2 are mainly
based on the results of tests conducted in fixed-bed atmospheric-
pressure gasifiers. Environmental testing at a Wellman-Calusha
gasifier gasifying anthracite provided the basis for the sulfur
distribution in gas produced from the gasification of anthracite
(Ref. 10). Testing at Wellman-Galusha and Chapman-Wilputte
gasifiers supplied the basis for the sulfur distribution in gas
produced from low-sulfur bituminous coal (Ref. 13). The sulfur
distribution in lignite-produced gas is supported by test data
from a thin-bed Riley Morgan gasifier (Ref. 9), but may not be
exactly representative of results obtained during the gasifica-
tion of lignite in a thick-bed Wellman-Galusha gasifier.
Nitrqgen Compounds - During gasification, a portion of
the coal-bound; nitrogen reacts to form volatile species such as
ammonia and hydrogen cyanide. Smaller amounts of coal nitrogen
also may react to form thiocyanates as well as other organic com-
pounds. These compounds could form NOX when the low-Etu gas is
burned. Very small amounts of NOX may also be present in the
product low-Btu gas.
54
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The distribution of nitrogen compounds in the product
gas depends on the coal nitrogen content, the steam feed rate to
the gasifier, the surface mositure content of the coal, and the
time-temperature history of the coal in the gasifier (Ref. 14).
The ammonia and hydrogen cyanide contents of the raw gases ex-
amined in this study are based on experimental data obtained from
these in Wellman-Galusha, Chapman-Wilputte, and Riley-Morgan
fixed-bed atmospheric-pressure gasifiers (Refs. 10, 13, 15).
Moisture - Moisture in the raw low-Btu product gas is
determined by the moisture content of the feed coal and the
amount of steam fed to the gasifier. Essentially all moisture in
the feed coal is evaporated. The evaporation of moisture and de-
volatilization of volatile matter from the coal cool the raw
product gas. The gasification of coals with high moisture con-
tents, such as lignite, may reduce the raw gas temperature
causing condensation of tars and oils at or downstream of the
point of gas exit from the gasifier. As a result, gasification
of coals with excessively high moisture contents is not desir-
able. These coals could be dried prior to gasification. How-
ever, the decision to dry a high moisture coal versus use of a
lower moisture (and probably more costly) coal must be determined
on an individual case basis considering site-specific economic
factors.
Product Gas Specifications -
While coal feedstock properties determine to a large ex-
tent the quantities of contaminants found in the raw low-Btu pro-
duct gas, product gas specifications define the degree to which
those contaminants must be removed. The product gas specifica-
tions are in turn defined by the intended use of the product gas.
In this report, three product gas specifications were examined.
These correspond to industrial fuels considered to be:
• "moderately clean",
• "clean", and
• "very clean".
The three setp of specifications corresponding to these indus-
trial fuels are summarized in Table 2.2-3.
Combustion of low-Btu industrial fuel gas must comply
with all applicable emission regulations. These include both
Federal, State, and local regulations. Under Prevention of
Significant Deterioration permits, State Implementation Plans,
and other provisions of the Clean Air Act, low-Btu gas combustion
sources may be regulated on a case-by-case basis.
55
-------
TABLE 2.2-3. PRODUCT GAS SPECIFICATIONS SELECTED
FOR ENVIRONMENTAL ASSESSMENT3
Particulates SOz
6 6
ng/J (lb/106 Btu) ng/J (lb/106 Btu) mg/Nm3 (gr/100 scf)
"Moderately Clean"
Industrial Fuel Gas
(1971 NSPSb)
"Clean" Industrial
Fuel Gas
(1979 NSPSb)
"Very Clean" Gas°
43 (0.10) 520 (1.2)
13 (0.03)
86 (0.2)
(0.25)'
For this report, the gasification facility is constrained only by limitations
on particulates and sulfur compounds in the low-Btu gas or in the gas result-
ing from combustion of the low-Btu gas.
The product gas specifications refer to the allowable emissions of combustion
products per unit energy of low-Btu gas. These low-Btu product gas specifi-
cations are similar to the 1971 and 1979 NSPS for direct combustion of coal in
a steam generator. That these regulations should be applied to combustion
of low-Btu gas is not implied or intended.
The "very clean" gas is essentially free of contaminants; the sulfur speci-
fication is adapted from natural gas pipeline specification (<11 ng/Nm ,
<5 ppmv) .
Refers only to
(10 ppmv) .
total sulfur specification arbitrarily set at 22 mg/Nm3
56
-------
In light of the lack of general guidelines for the al-
lowable emissions from combustion of low-Btu gas, a range of gas
specifications were selected. The intent of the selections was
to provide a reasonable range of performance constraints for an-
alyzing gas purification processes used in gasification facili-
ties. The "moderately clean" gas specifications were selected
such that resulting emissions would be basically the same as
permitted by 1971 new source performance standards (NSPS) for
direct combustion of coal in a steam generator. The "clean" gas
specifications were selected to limit emissions to levels that
are similar to those allowable under the revised (1979) NSPS for
direct coal combustion.
Use of low-Btu product gas specifications tied to NSPS
for direct coal combustion does not imply that these should be
applied as a formal regulation to the combustion of coal-derived
fuels. As stated previously, the gas specifications were only
selected to provide a reasonable range of performance constraints
for analyzing gas purification processes.
The most stringent specification considered in this re-
port provides for production of a "very clean" gas essentially
free of sulfur compounds and particulates. End uses requiring
such intensive clean-up of the low-Btu gas are few but possibly
include certain metals treatment and food preparation processes.
The principal constraint with respect to the target gas
specifications shown in Table 2.2-3 is the quantity of sulfur
compounds in the product low-Btu gas. Depending on the sulfur
content of the feed coal and the distribution of sulfur in the
low-Btu gas, the target specifications may be attained:
• without cleanup
• by removal of some or all of the hydrogen sulfide
• by removal of some or all of the hydrogen sulfide and
carbonyl sulfide
Table 2.2-4 summarizes the gas cleanup requirements associated
with gasification of the four selected coals to attain the three
product specifications shown in Table 2.2-3.
The selection of processes for removing sulfur compounds
from the low-Btu gas depends on the distribution of sulfur in the
gas and the removal required to meet product gas specifications.
As shown in Table 2.2-4, certain gas specifications could require
the removal of both hydrogen sulfide and carbonyl sulfide.
57
-------
TABLE 2.2-4. SULFUR REMOVAL REQUIREMENTS TO ATTAIN PRODUCT
SPECIFICATIONS FOR GASES PRODUCED
FROM FOUR SELECTED COALS
Product Gas Specifications
"Mdderately Clean"
Industrial Fuel Gas
"Clean"
Industrial Fuel Gas
"Very Clean"
Gas
Coal Feeds
Anthracite
• no cleanup
Low-Sulfur • no cleanup
HVA Bituminous
High-Sulfur • partial removal
HVB Bituminous of H2S
Lignite
• partial removal
of H2S
• removal of H2S
• removal of H2S
• removal of H2S
• removal of COS
• removal of H2S
• removal of COS
removal of H2S • removal of H2S
possible partial • removal of COS
removal of COSa
• removal of H2S
• removal of H2S
• removal of COS
Depends on the distribution of sulfur species in raw gas.
58
-------
Hydrogen sulfide is relatively easy to remove from the gas stream
and can be directly converted to elemental sulfur in processes
like the Stretford process. Carbonyl sulfide is not removed in
the direct conversion processes. Requirements to remove carbonyl
sulfide would mandate use of processes featuring the absorption
of acid gases into a sorbent like monoethanolamine followed by
regeneration of the sorbent with desorption of the acid gases.
While sulfur species would be removed from the low-Btu gas, the
desorbed acid gas stream would require further treatment.
Capacity -
This report examines gasification facilities producing
low-Btu product gas at the following rates:
• 17.6 MW (60 x 106 Btu/hr)
• 87.9 MW (300 x 106 Btu/hr)
The smaller size is the nominal capacity of one 3.0 m (10.0 ft)
diameter Wellman-Calusha gasifier producing low-Btu gas from
bituminous coal. The larger size was selected to give a range
for demonstrating the economies of scale associated with gas
purification processes and possibly alternative pollution control
options.
For the gasification facilities examined in this report,
the coal preparation operation will be limited to coal storage
and handling, since it is more economical to purchase pre-sized
coal than to install crushing, sizing, and briquetting equipment
at the gasification plant (Ref. 1).
Location -
Three locational factors affect the selection of coal
preparation and gas purification processes: (1) the availability
and cost of the coal feed and other raw materials; (2) the avail-
able space for the plant; and (3) the local and state regulations
affecting the design of the plant. The facility location may
also affect the selection of disposal practices for wastes pro-
duced at the gasification plant.
Of the four feed coals examined in this report, anthra-
cite, low-sulfur bituminous, and high-sulfur bituminous coals are
most likely to be used in Wellman-Galusha gasifiers constructed
in the near term. For purposes of this report, gasifiers using
these three coals have been assumed to be located within 150
miles of the coal supply. Facilities located greater distances
from the coal supply will suffer increased coal transportation
costs.
59
-------
In some instances, limited space may be available for
the installation of a complete gasification facility. This
constraint could limit coal storage and possibly affect the
selection of gas purification processes. Certain processes for
the removal of hydrogen sulfide (e.g., the iron oxide process)
require large areas for equipment installation and maintenance.
If little free space is available, such processes would be
impractical.
Design of gasification facilities with acceptable con-
trols for multimedia emissions depends on the requirements of ap-
plicable Federal, State, and local regulations. These require-
ments are described in Section 5.
2.2.2 System Flow Diagrams and Energy and Cost Analyses
Wellman-Galusha low-Btu gasification systems have three
basic operations: coal pretreatment, coal gasification and gas
purification. In each operation, there are processes with spe-
cific functions, inputs and outputs. Figure 2.2-1 is a general-
ized flow diagram showing the operations and process modules for
the Wellman-Calusha gasification systems considered in this re-
port. Table 2.2-5 summarizes the input and output streams and
the function associated with each process.
Detailed process flow diagrams for each of the four un-
controlled Wellman-Galusha gasification systems considered in
this report are shown in Figures 2.2-2 through 2.2-5. Following
each flow diagram is a table showing the composition of process
and waste streams as well as their flow rates, temperatures, and
pressures (see Tables 2.2-6 through 2.2-13). The flow rates
given in each table are for systems producing nominally 17.6 MW
(60 x 106 Btu/hr) of low-Btu gas.
The first system considered in this study (see Figure
2.2-2) is typical of what would be required to produce a
"moderately clean" industrial fuel from a low-sulfur coal feed-
stock. This system has only three process modules: coal hand-
ling and storage, gasification, and particulate removal (hot
cyclone). This system also represents currently-operating
Wellman-Calusha facilities that use anthracite and low-sulfur
bituminous coals (Refs. 10, 11).
A variation of the first system has an additional pro-
cess module: raw gas quenching and cooling. This additional
module removes tars and oils from the raw product gas and reduces
the potential of fouling equipment used to transport the low-Btu
product gas to its end use. This system also is capable of pro-
ducing a "moderately clean" industrial fuel gas from a low-sulfur
60
-------
CON. PKMMTIW
G»S PURIFICATION
TARS. OILS. OUST
K£T TO SrSTD6
Q GASIFICATION OF LOM-SULFUt COALS (LESS THAN 0.71 SULFUR FOR COALS UIIH HEATING VALUES OF 30 MJ/KG OR 13,000 6TU/LB) TO PRODUCE « "MODERATELY CLEAN' INDUSTRIAL FUEL US.
Q SASIFICATIO» OF AKTHRACITE COALS TO PRODUCE * "CLEAT WDUSTRIAL FUEL GAS.
Q GASIFICATIOK OF HIW OR LOW-SULFUR BITUMHOUS. SUB-BITUMIHOUS. AMD LIGNITE COALS TO PRODUCE A "CLEAN" INDUSTRIAL FUEL GAS.
(T) GASIFICATION OF HIGH-SULFUR BITUMINOUS COALS TO PRODUCE A "VERY CLEAN" GAS.
DETAILED PtOCESS FLOWSHEETS ARE FOUND IN FIGURES 2.2-2 TO 2.2-5
Figure 2.2-1. Wellman-Galusha System Process Modules and Multimedia Discharges
-------
TABLE 2.2-5.
OPERATIONS/PROCESS MODULES IN WELLMAN-GALUSHA
LOW-BTU GASIFICATION SYSTEMS
Operation/Process Module
Input Str
Output Streama
Function
Re-arks
Coal Pretreatment
Coal Handling
and Storage
Presized coal Preslzed coal
Coal duat
Coal pile runoff water
Store and transport
coal feedstock
Coal storage piles would contain a 30 day coal
supply (2-12 Gg, 2000-13,000 short tons of coal
for a plant producing 18-88 MU, 60-300 million Btu/
hr of low-Btu gas) .
Coal Gasification
Fixed-Bed, Atmospheric
Pressure, Dry Ash
Gaslfler - Vellman-
Calusha
Preslzed coal
Stem
Air
Ash sluice water
Raw product gas
Coal hopper gases
Fugitive gases
Start-up vent gases
Ash
Ash sluice water
React coal with a
mixture of steam and
air to produce a raw
low-Btu gas
Coals that have been used Include anthracite and
bituminous. Coal size specifications are 7.9 to
14.3 mm for anthracite and 26-51 nan for bituminous.
Larger particle sizes can be used for more reactive
coals.
N>
Gas Purification
Particulate Removal -
Hot Cyclone
Gas quenching
and Cooling
Tar/011 Removal
Electrostatic
Precipltator
Sulfur Removal
Stretford
Raw product gas
Product gas
Quenching liquor
Cooled product gas
Sulfur Removal -
Honoethanolamlne
Process
Detarred product gas
Stretford solution
Air
Detarred product gas
MEA solution
Product gas
Removed particulates
Quenched/cooled
product gas
Quench liquor
Tars
Oils
Particulate matter
Cooled/detarred
product gas
Tars
Oils
Clean product gas
Oxldizer vent gas
Sorbent blowdown
Sulfur
Remove large particu-
late matter from the
hot, raw product gas
Remove tars and oils
from the product gas
and cool the product
gas to approximately
316*K (110'F)
Remove tar and oil
aerosols from the
cooled product gas
Remove H;S from the
detarred product gas
Clean product gas
MEA blowdown
Acid gases
Sulfur from acid gas
treatment processes
Tall gases from acid
gas treatment processes
Remove sulfur species
and COz from the
detarred product gas
Total partlculate removal efficiencies have been
determined to be between SO-80Z. Small partlculate
matter will not be removed. Collected particulates
have characteristics similar to devolatillzed coal
particles.
The amount of tars and oils removed Is dependent
upon the coal feedstock. Anthracite coal will pro-
duce essentially no tars, however, bituminous coal
will produce a significant amount of tars.
Emissions from the tar/liquor separator may contain
potentially hazardous compounds. Spent quench
liquor will require treatment before disposal.
ESP's have been used to remove tars and oils pro-
duced by two-stage, fixed-bed, atmospheric gaslfiers
and good removal of tars and oils have been demon-
strated by ESP's used In sampling systems.
Vent gases from tar/oil storage tanks may contain
potentially harmful compounds and nay need to be
controlled.
Organic sulfur species (I.e., COS, CS2, etc) wilt not
be removed from the product f>as. If the HCN concen-
tration is high, then a cyanide guard may he needed.
Blowdown sorbent will require treatment before dis-
posal. If the sulfur Is to be disposed of, tests
need to be performed (i.e., RCRA tests for solid
wastes) to determine treatment and/or disposal tech-
niques required.
Removal efficiency Increases with increasing Inlet
gas pressure. Acid gases have to be treated to
control sulfur emissions. MEA blowdown will require
treatment before disposal.
-------
COAL
HOPPER
GASES
COAL A
COAL DUST
COAL RUNOFF
POKEHOLE
GASES
CLEANED GASES
t
STARTUP
VENT
A
i
i
I
COAL
HOPPER
'"1
A/
AIR
I I
i i
CYCLONE
GASIFIER
—*- —
\y
WATER VAPOR FRCM
GASIFIER JACKET
DUST
ASH SLUICC
WATER
ASH
Figure 2,2-2.
Wellman-Galusha Gasification System
Producing a Hot Removal Product Gas
from Anthracite and Low-Sulfur
Bituminous Coals
63
-------
ON
Figure 2.2-3. Wellman Galusha Gasification System Producing
A Clean Product Gas from Anthracite Coal
-------
Oi
Figure 2.2-4. Wellman Galusha Gasification System for Producing a Clean
Product Gas from Lignite and Low- and High-Sulfur Bituminous
Coals
-------
o\
Uif.
Figure 2.2-5. Wellman Galusha Gasification System for Producing a Clean
Product Gas Cwith MEA Acid Gas Removal) from High-Sulfur
Bituminous Coal
-------
TABLE 2.2-6. STREAM COMPOSITIONS AND FLOW RATES FOR WELLMAN-GALUSHA GASIFICATION
SYSTEMS (FIGURE 2.2-2) PRODUCING 17.6 MW OF HOT PRODUCT GAS FROM
ANTHRACITE COAL
STREAM NUMBER AND DESCRIPTION
S3
E
U)
3
g
.L
«)
§ 9
H
8 "
|
CoBponcnt (Vol I)
S U,0
3 CO
0 It,
o1 CO,
a "*
* 0,
CM,
Component (ppaw)
» C2IUl
U Cjllci
S*
II 2 S
A cos
7; cs,
o «.*»
5 SOz
S Nlli
IICN
Partlculates (g/tte1)
Tars (g/N»J)
Water (wtl)
Auli (wtl)
Carbon (wtl)
Hydrogen (wtZ)
Nitrogen (wtZ)
Oxygen (wtl)
Sulfur (wtX)
Total Flow ((/sec)
Temperature, *K
Pressure. fcPa
IUIV solids (MJ/kf )
UHV gaaes (HJ/IV* )
u £
0.9
11.7
81.2
2.1
0.8
2.6
0.6
731
294
29.9
•
79
21
2740
333
|
100
430
333
il
100-
1 &&
L64
14
1 Castfl*
1 Ash
0.29
65.8
33.0
0.29
0.19
0.29
0.19
130
7.4
Pokehol
Gases
6.0
23.9
15.3
5.18
48.4
0.86
0.22
0.9
38
761
87
0.9
20
183
40
0.37
3.5
420
101
25.3
i!
6.0
23.9
15.3
5.18
48.4
0.86
0.22
0.9
38
761
87
0.9
20
183
40
0.37
8.4
300
101
S.3
7
Raw
Produce
1 Caa
6.0
23.9
15.3
5.1
48.4
0.8
0.2
0.9
38
761
87
0.9
20
183
40
0.37
3770
700
103
25. 3
8
J.
o •
25.1
70.4
1.3
0.7
1.0
1.5
0.75
25.3
9
Hot
Produce
6.0
23.9
15.3
5.18
48.4
0.86
0.22
0.9
38
761
87
0.9
20
183
40
0.15
770
620
101
5.3
S*
• Z
-------
TABLE 2.2-7. STREAM COMPOSITIONS AND FLOW RATES FOR WELLMAN-GALUSHA GASIFICATION
SYSTEMS (FIGURE 2.2-2) PRODUCING 17.6 MW OF HOT PRODUCT GAS FROM
LOW-SULFUR BITUMINOUS COALS
STREAM NUMBER AMD DESCRIPTION
00
y
d
"
B
2
2
**
a
si
in g
@ M
H
gC
|
Component (Vol X)
8 u,o
3 CO
0 II,
8 co,
5 H,
o,
Cll«
Component (ppov)
. C,IU
S c,m
3 CilU
• Cjll.
S ii, s
A cos
"2 CS,
| so,
S Hill
ItCN
l-.rtlc.il.te* («/»•')
Tar. (g/Nn'l
Water (utl)
A»l> (wtZ)
Carbon (utZ)
Hydrogen (wtZ)
Nitrogen (utZ)
Oxyftuii (ulZ)
Sulfur (utZ)
Total Flaw (g/uec)
Tenperaturc, *K
fccnvurc, kP.
UHV .olid. (HJ/k*)
IUIV |aae. (HJ/lt" )
1
II
2.5
2.9
79.1
5.6
1.6
7.6
0.7
810
294
13.2
2
w
79
21
2610
323
3
!
100
220
323
-
• •-IB
•3 tn 9
20-33
4
u
01
•H
*M
1*
86.3
11.5
0.1
0.1
0.1
1.9
26
3.8
5
•
t-i
Pokeho
Case.
5.5
24.5
11.8
4.6
50.5
1.98
2550
945
945
95
19
284
95
1.8
39
1.8
420
101
29.7
6
14
-SL
So-!
U CB C
5.5
24.5
11.8
4.6
50.5
1.98
2550
945
945
95
19
284
95
1.8
39
8.8
300
101
29.7
7
u
|2S
at PUO
5.5
24.5
11.8
4.6
50.5
1.98
2550
945
945
95
19
284
95
1.8
39
3610
839
103
29.7
8
£
•H U
S!
6.2
87.3
3.3
1.5
1.5
0.4
3.5
29.7
9
y
u
5.5
24.5
11.8
4.6
50.5
l.ojj
2550
945
945
95
19
284
95
0.72
39
3607
756
101
29.7
71
• 3
.
-------
TABLE 2.2-8. STREAM COMPOSITIONS AND FLOW RATES FOR WELLMAN-GALUSHA GASIFICATION
SYSTEMS (FIGURE 2.2-3) PRODUCING 17.6 MW OF CLEAN PRODUCT GAS FROM
ANTHRACITE COAL
ON
STREAM NUMBER ADD DESCRIPTION
5 6 7 8 9 10
11
12
13
14
j3
1
CA
3
*
8
Component (Vol Z)
3 H,0
3 CO
0 Hi
o CO,
3 Ml
* 0,
CH.,
Component (ppanr)
S C'H
o CilUl
• CilUl
o «
« lisa
H COS
"N CS«
i SOl
fl Hill
IKM
Partlculatea (g/Ma1)
Tars (g/H-')
Water (wtX)
5 Auli (wtZ)
"xj Carbon (wtZ)
@ 3 Hydrogen (wtZ)
^R Nitrogen (wtZ)
3 *" Oxygen (wtZ)
0 Sulfur (wtZ)
Total Flow (g/sec)
Temperature. *K
Pressure, kt»
IttV solids (HJ/kc)
WIV gases (KJ/M-')
ii
0.9
11.7
81.2
2.1
0.8
2.6
0.6
731
294
29.9
5*
79
21
2740
333
|
100
430
333
1
Us
100-
164
u
S
-------
TABLE 2.2-8. (Continued)
15
16
17 18
19
STREAM NUMBER AMD DESCRIPTION
2O 21 22 23* 24*
25
26*
27
26
29*
13
i
Ul
M
O
i
3
Component (Vol X)
S u,o
S CO
U H,
8 CO,
3 MI
* 0,
CII,
Component (ppsnr)
• C,IIO
S" C,ll»f
CiHtl
S H'"'
£ cos
"M CSi
3 so.
JJ Hill
1ICH
Partlculatea (g/tta5)
Tata (g/Mai )
8 Uatcr (wtl)
0 Aali (wtl)
2 Carbon (wtl)
§ |3 Hydrogen (utX)
"* P Hltrogcn (wtl)
0™ Oxygon (wtX)
g. Sulfur (wtX)
-i
Total Flow (g/sec)
Temperature, *K
Pressure . kPa
IIHV solids (MJ/k|)
IWV gaaes (KJ/H-1)
[Separator
went Gas
105
158
t-t
»f»
82
303
Hold Tank
Blowdown
>erlr:
Ddic
[Compressed
Product
8.0
23.4
15.0
5.1
47.4
0.84
0.22
0.9
35
750
35
1
20
180
40
-
-
3600
317
110
4.7
4J
U
•3-3
• o «
££3
8.1
23.4
15.0
5.1
47.3
0.84
0.21
0.9
35
10
85
1
20
180
40
-
-
3550
317
109
4.7
Stretford
Liquor to
nr1A1r.fr
6371
,i*4.iwvt|Vj
o) aonbfl
paojwjs]
6367
Make-up
Chemical
0.115
Make-up
Water
0.542-
None
Stretford
Liquor to
Surze Ink
26.2-
27.6
Oxidizer
Vent gas
unk.
41.7
Stretford
Liquor
Blowdown
1.73-
2.60
Air to
Oxidizer
42.1
Stretford
Liquor
from Oxid.
90
10
29.1
jt
u
M
3 X
ill
•
2.91-
8.73
-------
TABLE 2.2-8 (Continued)
STUMf MJMUk AM) DUOtlPTIOM
30 31* 32* 33
8
1
in
M
i
3
Component (Vol Z)
J
8 HtO
J CO
0 Hi
8 CO,
a Nl
* 0,
CIK
Cooponent (ppov)
. C,1U
3Czll«
CiH«
• Cillt
£ cos
7; csi
SO 2
mil
IKM
Psrtlculates (g/Msi')
Tara (g/N.1)
8 Water (wtZ)
o Anil (wtl)
•"S Carbon (wtl)
6 jj Hydrogen (wtZ)
** P Nitrogen (wtl)
3 M Oxygen (wtl)
3 Sulfur (utZ)
H*
Total Flow (g/aec)
Temperature, *K
rreaaure. kPa
UUV aoltda (HJ/kc)
HUV ga»ea OU/NB1)
b
3
"* "?
•» U
SO
SO
5.82
•Sfi
o
IH M
S** §
0*-^
26.2-
32.0
•ss
o
u o*
U >H
w J A
one-
4.40
s:
il
• »•
S c
aok.
. •
;
•Flow rates will depend upon the nuaber of 'sulfur cake washes' low r tes are for'l wash, high' ratea 'are for 3 wasn
•
-------
TABLE 2.2-9. STREAM COMPOSITIONS AND FLOW RATES FOR WELLMAN-GALUSHA GASIFICATION
SYSTEMS (FIGURE 2.2-4) PRODUCING 17.6 MW OF CLEAN PRODUCT GAS FROM
IGNITE COAL
S3
53
i
M
IA
a
^j
**
8
Component (Vol X)
S H,0
J CO
0 Mj
g CO,
V H,
* 0,
CH»
Component (ppaw)
• CiHi,
S" CzU*
Cilli
v C )!!•
3 lias
A cos
"M CS>
JSOj
Mill
IICN
Paniculate, (g/lta1)
Tars (g/N-1)
Wutcr (wtl)
S Aah (utZ)
"S3 Carbon (utZ)
8 u Hydrogen (wtZ)
*R Mltrogon (wtZ)
& m . Oxygen (wtZ)
B Sulfur (wtZ)
»*4
Total Flow (g/aec) .
Teapitraturc. *K
Premuire, kPa
UUV •olidi OU/ka)
IUIV gavea (MJ/N-1)
II
35
8.3
41.5
2.9
1.0
10.5
0.9
1460
294
16
u
1985
330
s
CO
240
330
3s
n p *J
100-
160
IcaalfleT
Aah
88.8
9.8
1.4
134
3.3
ii
23.1
23.5
13.0
2.99
35.8
l.Q
2980
660
1950
183
1920
85
_
_
231
77
1.9
36
1.8
400
101
24.8
6.1
M
*3 O. 0
23.1
23.5
13.0
2.99
35.8
1.3
2980
660
1950
183
1920
85
_
_
231
77
1.9
36
17.5
300
101
24.8
6.0
ill
23.1
23.5
13.0
2.99
35.8
1.0
2980
660
1950
183
1920
85
_
_
231
77
1.9
36
3470
422
103
24.8
6.1
Cyclone
Duat
22.4
68.2
1.6
,5.8
1
1.9
3.91
24.8
u
u
a
•o
41 O 0
SM ,1
04 C
23.1
23.5
13.0
2.99
35.8
1.0
2980
660
1950
183
1920
85
_
_
231
77
0.76
36
3465
394
101
24.8
6.1
Quenched
Product
Gas
25.9
22.6
12.5
2.ae
34.5
0-9^
2870
636
1880
176
1850
82
_
_
222
74
0.59
28
3520
339
101
24.8
5.8
1 Scrubbed
Product
iGaa
15.6
25.7
14.2
3.3
39.3
1.1
3270
724
2141
200
2110
94
_
_
253
84
0.54
26
3200
328
100
24.8
6.2
Cool
Quenched
Prod/gaa
9.2
27.6
15.3
3.6
42.2
1.2
3520
780
2300
215
2270
101
_
_
272
90
0.46
22
2990
317
98.8
24.8
6.4
1
H •-• .C
35 S
Sol
J u O-
1660
328
790
o
- s
§>>!
18400
319
790
-------
TABLE 2.2-9. (Continued)
u>
15 16 17 18 19 20 21 22 23 24 25 26 27 28** 29
j3
I
K
i
!2
a
Component (Vol X)
5 «jO
j CO
0 Hj
o CO*
a Ml
* 0,
Clls
Conponent (ppaw)
. C,IU
5* CilU
CiH«
• Cjll.
• II jS
& COS
"i cst
Jso>
Nlli
IKH
Partlculatea (c/Nai')
Tara (g/lta1)
Water (wtZ)
o Auli (wtt)
** zj Carbon (wtt).
Q j5 Hydrogen (wtl)
p Nitrogen (wtl)
8 OT Oxygen (wtl)
B- Sulfur (wtZ)
Total Flow (g/aec)
Teaperature. *K
Preauure, kPa
IHIV aollda (Ml/kg)
HUV ga«ea (MJ/H-1)
2
S *'
10000
308
790
£
1580
339
M
h:
18700
331
IM
102W
31!
ill
47
30.0
L.
1 h r-
3
1.3
76.6
7.1
1.0
9.8
1.3
120
30.0
liar/uii
Separator
Blovdown
428
M.
II j
•ooe
8
hs
v» C
185
358
21
o "v
u •
8.0
28.0
15.5
3.7
42.8
1.2
3570
790
2380
218
2300
102
^
275
91
_ .
0.14
900
317
110
5.9
Desulfur
Product
Gas
8.1
28.3
15.6
3.7
43.2
1.2
3600
798
2400
220
10
103
_
278
92
—
0.14
890
317
109
5.8
Stretford
Liquor Co
Oxldlzer
0125
Stretford
Liquor to
Absorber
0115
Stretford
Liquor
Blowdown
2.56
5.32
Ozldizer
Vent
Caa
unit*
32
-------
TABLE 2.2-9. (Continued)
30 31
32** 33
STREAM NUMBER AND DESCRIPTION
34** 35** 36** 37** 38
5J
1
K
M
S
2
**
Caevoncnt (Vol Z)
8 H20
3 CO
U,
'o CO,
*i y
* o!
CIU
Covfionent (ppew)
• CjlU
S* Cilli
CilU
• CilU
S MiS
a cos
"M CS,
3 soi
3 Nil)
IICN
Partlculatee (g/lta1)
Tara (g/N»*>
8 Water (wtl)
g Auh (wtZ)
** £ Carbon (wtl)
§ 3 Hydrogen (wtZ)
P Nitrogen (wtZ)
9"' Onygun (wtl)
& Sulfur (wtl)
Total Flow (g/uec)
Tu»|».-rat.ire. *K
Pressure, kl'a
UUV aollda (MJ/ka)
UMV gaaeit (MJ/*.1)
•go
Stretfo
90
10
92.0
M
08
u rl
79
21
133
S J
Wi
9.2-
27.6
ii
50*
50
18.4
"Sfi
Stretfo
Liquor
Filter
82.8-
101
h
•O o o
u u u
Stretfo
Liquor
Evapora
None-
16.1
•23-S
Stretfo
Liquor
1 Surge T
82.8
85.1
o.
« •
31
0.479-
Hone
Make-up
Cham.
0.239
Flow rates depend upon the noaber of aulfur cake waahea, low rate* are for 1 vaah, high ratea are for 3 vaabea
-------
TABLE 2.2-10.
STREAM COMPOSITIONS AND FLOW RATES FOR WELLMAN-GALUSHA GASIFICATION
SYSTEMS (FIGURE 2.2-4) PRODUCING 17.6 MW OF CLEAN PRODUCT GAS FROM
LOW-SULFUR BITUMINOUS COAL
Ul
3
|
in
(A
3
«3
o
8
g
IA UJ
6 3
H
Q
&
M
.J
Coavonent (Vol X)
• H,0
j CO
3 Hi
S CO,
¥ "'
* 0,
cu.
Component (ppaw)
• CjIK
• CjlU
0 C»H»
SCilli
H,S
£ cos
"u CSz
8 so.
2 Hill
IKH
Fartlculates (g/Na*)
Tars (g/N-1)
Water (utl)
Avh (wtZ)
Carbon (utl)
Hydrogen (wtZ)
Nitrogen (wtZ)
Oxygen (wtZ)
Sulfur (utZ)
Total Flow (g/aec)
Tenperature, *K
Prvanure. kPa
UUV solids (NJ/k|)
IUIW fanes (HI /MB )
11
2.5
2.9
79.1
5.6
1.6
7.6
0.7
810
294
33.2
44
•3»
S3
79
21
2610
323
S
m
100
220
323
ii
20-3:
3
«H
-ri
0=1
86.3
11.5
0.1
0.1
0.1
1.9
26
3.8
Pokehol*
leasts
5.5
24.5
11.8
4.6
50.5
-
1.9
2550
945
-
_
945
95
—
19
284
95
1.8
39
1.8
420
101
29.7
S
II
5.5
24.5
11.8
4.6
50.5
-
1.9
2550
945
-
_
945
95
—
19
284
95
1.8
39
8.8
300
101
29.7
*»
iL
5.5
24.5
11.8
4.6
50.5
-
1.98
2550
945
-
_
945
95
—
19
284
95
1.8
39
3610
839
103
29.7
1-1 **
£s
6.2
87.3
3.3
1.5
1.5
0.4
3.5
29.7
Hot
Product
r.««
5.5
24.5
11.8
4.6
50.5
-
1.98
2550
945
_
_
945
95
-
19
284
95
0.72
39
3600
756
101
29.7
7 4
i .^
Quenched
Product
Gas
27.6
18.8
9.0
3.5
38.7
-
1.5
1950
720
-
_
720
73
»•
15
218
73
0.44
24
4340
341
101
29.7
5.0
Scrubbed
Product
Gas
16.0
21.8
10.4
4.1
44.9
-
1.76
2260
835
-
^
835
85
-
17
253
85
0.41
22
3810
329
100
29,7
5.6
Quenched
Cooled
Prod/gas
9.2
23.6
11.2
4.4
48.5
-
1.9
2440
903
-
_
903
92
—
18
273
92
0.36
19
3400
317
98.8
29.7
5.8
S
ss-s
11!
100
2520
328
790
o
*t
M .
!*'
Z3A.
100
9400
319
790
-------
TABLE 2.2-10 (Continued)
STREAM NUMBER AMD DESCRIPTION
15 16 17 18 19 20 21 22 23 24 25 26 27 28* 29
h u
2
1
vt
O
8
2
**
Component (Vol Z)
3 H,0
3 CO
0 U,
b' CO,
a »»
2 o,
CIU
Component (ppav)
2 C2IU
• CilU
0 CiH(
• C illt
2 H,S
ft COS
1 so!
2 Hill
IICN
Particulatea (g/N»*)
Tara (g/H.1)
9 Water (wtZ)
3 A»li (wtZ)
Mjjj Carbon (wtZ)
QS Hydrogen (wtZ)
^P Nitrogen (wtZ)
§ Oxygen (wtZ)
Sulfur (wtZ)
3
Total Flow (g/acc)
Temperature, *K
Preaaure, kPa
HOT aollds (HJ/ka)
IMV gaaea (HJ/N-1)
S
M M
•J W «J
L2900
308
790
Liquor fr
Gaa/Liquo
Separator
1750
341
Liquor fr
Tray
Scrubber
19900
333
M
H4
14 kl
O >l 4
13100
319
3885
48
317
37
By-Produc
Tara/Olla
2.9
0.1
82.6
7.7
1.3
4.9
0.52
121
328
37
Tar/011
Separator
UlrKjHfWn
perl-
die
1 U 14
|8S
88
303
Separator
Product
Gaa
190
358
Conprea
Product
Caa
8.0
23.9
11.3
4.5
49.1
1.93
2470
915
»
_
915
93
18
277
93
.
0.15
3310
317
110
5.3
§«
«M U
i-* 3
3 -O
no*
v n a
Q p. U
8,1
23,9
11.3
4.5
49.0
1.93
2470
915
—
_
10
93
18
277
93
_
0.15
3300
317
109
5.2
Stretford
Liquor to
Oxidizer
9450
Stretford
Liquor to
Absorber
9445
Stretford
Liquor
Slowdown
3.97-
5.27
Oxidizer
Vent
Gaa
unk.
61.9
-------
TABLE 2.2-10 (Continued)
STREAM NUMBER AND DBSCRIPTIC4I
30 31 32* 33 34* 35* 36* 37* 38
s
1
g
§
3
Component (Vol X)
5 H,0
3 »
^ CO,
3 o'
CH«
CoBpooeot (ppew)
• C2H<
O ClHi
• HjS
A COS
t CSj
| so,
3 NIli
HCN
Partlculatea (g/""'>
Tar. (g/H.*)
9 Water (utZ)
g Anil (wtt)
M3 Carbon (utZ)
83 Hydrogen (wtZ)
""R Nitrogen (wtZ)
0"1 Oxygen (wtZ)
8 Sulfur (wtZ)
M
•J
Total Flow (g/iiec)
Temperature, *K
Preavure, kPa
UUV aoltda (Ml/kg)
UUV «aaea (HJ/*V)
S2
O
•H M u
4J 0 |
He
90
10
43.]
M
Si
35
62.2
g
ii.
4.32-
3.0
y
"3 ^
to c
SO
SO
8.64
•gh
o
•M 14
*l O
«s
«0 J fr
8.9-
7.6
•a o !
M O W
O 1
sli
Z3&
Mnn
5.47
•00^
u o'
IS,
8.9-
2.1
? M
Js
s
,
.88-
Mone
J
II
0.231
*riov ratea depend upon the nuaber of aulfur' cake wachM. law rate* are, for. 1 •eeh. high retes ara
for 3 wachea
-------
TABLE 2.2-11. STREAM COMPOSITIONS AND FLOW RATES FOR WELLMAN-GALUSHA GASIFICATION
SYSTEMS (FIGURE 2.2.-A) PRODUCING 17.6 MW OF CLEAN PRODUCT GAS FROM
HIGH-SULFUR BITUMINOUS COAL
STUAM man Aim DESCRIPTION
-J
00
2
i
in
3
H
3
Component (Vol X)
8 n*o
3 cu
" III
8 CO,
5 "»
2 o,
cu,
Component (ppen>)
m ClIU
3* CilU
Cillt
i Mrs*
& COS
"u CSi
a soi
a mil
IICH
Participate* ((/Ma1)
Tars (g/NB )
8 Voter (wtl)
£ Auk (wtl)
MiJ Carbon (vtX)
§ 9 Hydrogen (wtl)
"*G Nitrogen (wtZ)
3 Oxygen (wtl)
& Sulfur (wtl)
3
Total Flow (g/eec)
Temperature, *K
Pressure, kPa
raw «olld« (Hl/k|)
UIIV gasea (HJ/M*1)
11
6.1
8.4
67.9
4.8
2.1
6.8
3.9
883
294
29.2
I;
2040
336
CO
390
336
O 1
55-91
Caalfler
Aah
92.8
5.6
0.3
1.2
73.7
2.0
Pokehole
Gaaei
12.3
25.3
13.0
3.0
42.9
2.4
2370
877
-
-
88-263
_
18
263
88
2.2
40
1.8
420
101
7.5
M
H Q.
gg-:
oat
12.3
25.3
13.0
3.0
42.9
2.4
2370
877
-
. -
18-263
_
18
263
88
2.2
40
7.81
300
101
28.2
7.4
Raw
Product
GM
12.3
25.3
13.0
3.0
42.9
2.4
2370
877
_
-
18-263
_
IB
263
88
2.2
40
3200
644
28.2
7.6
1-
12
6.6
89.1
0.3
1.3
1.7
0.7
3.78
28.2
Hot
Product
12.3
25.3
13.0
3.0
42.9
2.4
2370
877
_
-
38-263
^
18
263
88
0.88
40
3202
617
101
28.2
7.6
P
1 83
23.5
22.1
11.3
2.6
37.4
2.1
2070
765
-
77-230
_
16
229
77
0.61
28
3640
338
101
28.2
6.1
o o
Scrubbed
Product
Gas
15.7
24.4
12.5
2.9
41.2
2.3
2280
843
_
-
85-250
IB
252
85
0.54
25
3220
328
100
28.2
6.5
Quenched
Cooled
Prod/gai
9.2
26.3
13.5
3.1
44.4
2.5
2460
908
_
-
92-270
19
271
92
0.47
22
3100
317
98.8
28.2
6.8
Liquor t
Inline
Oueneh
2260
328
790
Liquor t
Tray
Scrubber
!0500
319
790
-------
TABLE 2.2-11. (Continued)
15 16
17
18
19
20
21
22 23
24
25 26
27
V0
28* 29
s
R
M
M
§
3
O
*
Component (Vol Z)
8 HiO
3 CO
" Hi
£ COj
3^2
0,
C1I,
Coaponent (ppaw)
• CjHs
: ciiu
" cllli
• HlS
K cos
"M CS,
JSO,
HU)
IKN
1
rarclculatea (g/Mai1)
Tara (g/lta')
8 Uutcr (wtZ)
5 Anil (wtl)
" S Carbon (wtZ)
§ d Hydrogen (wtZ)
*p Nitrogen (wtl)
§M Oxygen (wtl)
Sulfur (wtl)
3
Total Flow (g/aec)
Te-iKsrature. 'K
Prenaure, kPa
UIIV aollda
-------
TABLE 2.2-11. (Continued)
CO
o
S
1
"
M
B
5
**
a
n
18
§1
B
1"
Component (Vol S)
5 H,0
S CO
3 Bi
8 CO,
J «i
* 0,
CIU
Coopooatt (ppaw)
« CiH«
3* CiM.
CiH*
. C>U.
§ n>s
ti cos
"t cs>
2J ||||
IKN
fartlculataa (c/lto )
Tara ((/Ha')
Mater (utX)
Aul. (wtl)
Carbon (wtl)
Hydrogen (wtl)
Nitrogen (wtZ)
Oxygen (wtl)
Sulfur (utZ)
Total Plow (•/««<:)
TeniMtrature. *K
Prevuure, kFa
HUV solid* (HJ/ki)
WN «MCS (Hi/Mai1)
•Flow rataa dapand upon tl
for 3 waabaa
30
S8
u " !
329
• OUBl
31
i
•
^
90
10
*75
wr of
32*
h
1
' I
32.9-
98.7
sulfu
33
I,
50
50
70.8
• eako.
34*
*O h
Stratft
Liquor
Flltar
291-
357
VMlMI
35*
u
88
If
8.32-
i. low
36*
! 8-3
|||
283-
290
rata*
37
&M
HOM
ara fa
38*
li
.529
-.378
• 1 vw
™f O*J
I rataj
" ara
-------
TABLE 2.2-12.
STREAM COMPOSITIONS AND FLOW RATES FOR WELLMAN-GALUSHA GASIFICATION
SYSTEMS (FIGURE 2.2-5) PRODUCING 17.6 MW OF CLEAN PRODUCT GAS FROM
HIGH SULFUR BITUMINOUS COAL (MEA PROCESS OPERATING PRESSURE OF 0.44
MPa, 50 psig)
STREAM NUMBER
AMD DESCRIPTION
123-4567
'8 9 10 11 12 13 14
O 0
OO
M
i
•>
M
8
53
3
Component (Vol Z)
S H,O
9 co
0 n,
g CO,
a "•
* 0,
CIK
Component (ppaw)
• CjlU
m CjlU
o Cillt
• C.H.
3 H,S
A cos
7: csi
| so,
3 HHi
IICM
Partlculatea (g/Na*)
Tare (if/Me*)
ft Water (wtZ)
g Auh (wtZ)
1/1 2 Carbon (wtZ)
§ to) Hydrogen (wtZ)
*C Nitrogen (wtZ)
3 Oxygen (wtZ)
B Sulfur (wtZ)
Total Flow (g/aec)
Temperature , *K
Pressure, kPa
I1UV nollds (HJ/kg)
UIIV gasee (MJ /(*•*)
I!
6.1
8.4
67.9
4.8
2.1
6.8
3.9
883
294
Z9.2
3;
2040
336
S
n
390
336
Air
Sluice
5-91
Icaalfler
lAah
92.8
5.6
0.3
1.2
3.7
2.0
IPokahold
Caaaa
12.3
25.3
13.0
3.0
42.9
2.4
2370
877
_
^
88-263
„
18
263
88
2.2
40
1.8
420
101
8.2
H
12.3
25.3
13.0
3.0
42.9
2.4
2370
877
_
_
18-263
«.
18
263
88
2.2
40
7.8
300
101
28.2
3 PL, <
12.3
25.3
13.0
3.0
42.9
2.4
2370
877
..
^
88-263
„
18
263
88
2.2
40
3200
644
28.2
li
6.6
89.1
0.3
1.3
1.7
0.7
3.8
8.2
Hot
Product
Ifiaa
12.3
25.3
13.0
3.0
42.9
2.4
2370
877
_
18*263
^
18
263
88
0.88
40
3202
617
101
28.2
6.9
Quenched
Product
Cai
23.5
22.1
11.3
2.6
37.4
2.1
2070
765
_
77-23C
_
16
229
77
0.61
2.8
3640
338
101
28.2
5.4
Scrubbed
Product
Gaa
15.7
24.4
12.5
2.9
41.2
2.3
2280
843
85-250
w
18
252
85
0.54
25
3220
328
100
28.2
5.8
Ji
a«-
§3]
9.2
26.3
13.5
3.1
44.4
2.5
2460
908
92-270
„
19
221
92
0.47
22
3100
317
98.8
28.2
6.0
o
II]
2260
328
790
S
It!
0500
319
790
-------
TABLE 2.2-12. (Continued)
oo
15
16 17 18
STUAM
19
AMD DESOtlPTIOH
20
21 22
23
24 25
26
27
28
2
M
9
**
Coaponeot (Vol S)
8 HtO
3 CO
Hz
£ CO,
3 l\
cm
• C|Hij
• C>Ut
a C.H.
3 c>u*
i HsS
A cos
"H csi
K
Q SO]
3 •".
ICN
rartieulatea (•/*•')
Tara (g/lta*)
9 Mater (vtX)
5 A»h (wtl)
8 Carbon (wtl)
§3 Hydrogen (wtl)
•*K Nitrogen (wtl)
§ Oxygen (wtl)
Sulfur (wtZ)
Total Flow (t/aac)
T«^,r.tur.. «K
Preaaura, kPa
IWV aolida (HJ/k|)
WV gaaaa OU/H-1)
S
i&;
9900
308
790
ill
1800
33»
i«
-------
TABLE 2.2-13.
STREAM COMPOSITIONS AND FLOW RATES FOR WELLMAN-GALUSHA SYSTEMS
(FIGURE 2.2-5) PRODUCING 17.6 MW OF CLEAN PRODUCT GAS FROM HIGH-
SULFUR BITUMINOUS COAL (MEA PROCESS OPERATING PRESSURE OF 1.5 MPa
OR 200 psig)
CO
u>
1 2
STUAH HDMBER AMD DESCRIPTION
8
10
11
12
13
U
2
|
**
i
3
a
jii
"* 3
g 3
R
81"
jj
3
Component (Vol S)
8 HiO
3 °°
0 H,
o °°t
3 **
* 0,
CM,
Coaponent (ppew)
• CjlU
2 C»U«
5 CilU
• Cill.
3 H,S
£ cos
"N CSi
1 SOi
» "111
HCH
Fartlculatea (*/»•')
Tat. (g/MM1)
Hater (wtZ)
Auh (wtZ)
Carbon (utZ)
Hydrogen (vtZ)
Hltrogen (utZ)
Oxygen (wtZ)
Sulfur (wtZ)
Total Flow (g/aee)
Teaperature, *K
Precuure. kPa
IUIV aollda (MJ/kc)
«UV gaaea (HJ/H-')
II
6.1
8.4
67.9
4.8
2.1
6.8
3.9
883
294
292
*»
2040
336
I
90
36
u
ll.
5-91
II
92.8
5.6
0.3
1.2
73.7
2.0
.
Pokehola
Gasea
12.3
25.3
13.0
3.0
42.9
_
2.4
2370
877
-
18-263
*.
18
263
88
2.2
40
1.8
420
101
6.8
X
II.
12.3
25.3
13.0
3.0
42.9
_
2.4
2370
877
• -
88-26:
«
18
263
88
2.2
40
7.8
300
101
8.2
6.7
Raw
Product
Gaa
12.3
25.3
13.0
3.0
42.9
2.4
2370
877
-
88-263
^
18
263
88
2.2
40
3200
644
28.2
6.9
•H *-
Si
6.6
89.1
0.3
1.3
1.7
0.7
3.8
28.2
41
st,
12.3
25.3
13.0
3.0
42.9
2370
877
-
88-26:
„
18
263
88
0.88
40
202
617
101
8.2
6.9
Quenched
Product
Gaa
23.5
22.1
11.3
2.6
37.4
2070
765
-
77-230
—
16
229
77
0.61
28
3640
338
101
28.2
5.4
Scrubbed
Product
Gaa
15.7
24.4
12.5
2.9
41.2
2380
843
-
85-250
18
252
85
0.54
25
220
328
100
8.2
5.8
Quenched
Cooled
Prod/eaa
9.2
26.3
13.5
3.1
44.4
2460
908
-
12-270
19
271
92
0.47
22
3100
317
93.8
28.2
6.0
o
K • f
3 31
2260
328
790
0
u M
l A
0500
319
790
-------
TABLE 2.2-13. (Continued)
00
fi
a
•»
s
Q
3
**
Co«yoi»g«t (Vol X)
S H.O
3 CO
0 "i
8 co,
S »«
a o,
01*
Component (pp>w)
. C,H»
• C>H«
3 CiHt
• C.IU
3 H,S
A COS
"N CS>
1 SQl
3 Hill
IKM
Partlculcte* (I/MM')
1*r« (•/«•')
3 Voter (wtX)
3 A»l> (wtX)
Mg Carbon (wtX)
33 Hydrogen (wtl)
"*p Nitrogen (wtl)
§" Omygcn (wtX)
Sulfur (wtX)
5
Total Plow (C/MC)
Tmpnntnrit. *K
Preswr*. kP«
UUV colld* (HJ/k|)
HHV «•»•• (Hf/W**)
15
S
« t*
9900
308
790
ILlquor fr
IcaVLiqur g
|8«p«r«tor
1800
339
17
u
!0900
331
18
M
44
is-^
3*|
LOOOO
319
19
1
*"J fij
*
45.3
37.2
20
w
!!
3.0
0.1
86.1
7.6
0.8
1.4
1.2
114
37.2
21
Sfi
315
319
22
!$J
MOM
23
S
tin
180
f
• 4*
S3
0.6
28.7
14.7
3.4
48.6
2.7
2620
950
_
^
ttM»
•M
90-28C
_
20
284
96
-
0.17
2810
322
567
6.7
25
3 u
0.6
29.9
15.5
0.002
50.8
2.8
2780
1010
_
4
_
_
_
-
-
-
0.17
2570
322
1565
6.8
26
S|
5000
317
27
m
t-l
S
28
I
2
Stripped
Acid N
CM
2.6
6.3
1.0
62.2
10.1
0.9
420
220
163000
_
_
5200
.
-
241
317
103
5.3
-------
coal feedstock. It is similar to a facility usin^ Chapman
(Wilputte) gasifiers to produce a low-Etu combustion p,as for
process heaters (Ref. 13).
The second Wellman-Galusha gasification system (see
Figure 2.2-3) is used to produce a "clean" industrial fuel gas
from anthracite coal. This system contains the following process
modules: coal handling and storage, gasification, gas quenching
and cooling, and sulfur removal. In this system, the product gas
is cooled to 316 K (110°F) before entering the sulfur removal
process. Two sulfur removal processes are considered in this re-
port: Stretford and Monoethanolamine (MEA) processes (only the
Stretford process is shown in Figure 2.2-3). If a Stretford sul-
fur removal process is used, only I^S will be removed, leaving
organic sulfur species (i.e., COS, CS2, etc.) in the product
gas stream. H2S removal efficiencies of greater than 99% have
been achieved with residual outlet H£S concentrations less than
10 ppmv (Ref. 16). If the MEA process is used, both t^S and
organic sulfur compounds can be removed. However, the sulfur re-
moval effectiveness is dependent upon the pressure of the product
gas. For example, at 0.34 MPa (50 psi) residual H2S concentra-
tions of 8 ppmv can routinely be achieved, while at a higher
pressure of 0.69 MPa (100 psi), residual H2S levels can be
reduced to 4 ppmv. The MEA process also produces an acid gas
stream that requires further treatment (Refs. 17, 18).
The third system (see Figure 2.2-4) is used to produce a
"clean" industrial fuel gas from the following coal feedstocks:
bituminous (low- and high-sulfur) coal and lignite. In this sys-
tem, the quenched and cooled product gas is sent to a tar/oil re-
moval process followed by a sulfur removal process. An electro-
static precipitator (ESP) is used to remove tars and oils that
would cause operating problems with the downstream sulfur removal
process. As in the second system, the Stretford and MEA pro-
cesses (only the Stretford is shown in Figure 2.2-4) were chosen
for the removal of sulfur species in order to produce a "clean"
industrial fuel gas.
The fourth system (see Figure 2.2-5) is very similar to
the third system. The major difference is that only the MEA pro-
cess is used for removing sulfur species. By compressing the gas
to approximately 1.5 MPa (200 psi), the MEA process can remove
essentially all sulfur compounds and produce a "very clean" pro-
duct gas.
Energy Efficiencies -
Three energy efficiencies are used to describe the
Wellman-Galusha gasification systems examined:
85
-------
• coal to low-Etu gas efficiency which relates the
energy of the product gas (higher heating value or
HHV of combustibles plus sensible heat) to the HHV of
the feed coal,
• gas production efficiency which relates the energy of
the product gas to the total energy input to the
systems (HHV of coal plus utility steam and
electricity energy), and
• overall thermal efficiency which relates the energy
of the product gas and by-product tars, oils, and
steam to the total energy input to the system.
The energy efficiencies for each uncontrolled Welltnan-
Galusha gasification system examined in this report are summar-
ized in Table 2.2-14. Energy efficiencies for systems producing
a hot "moderately clean" industrial fuel gas are approximately 90
percent. Systems producing a desulfurized gas have overall ener-
gy efficiencies ranging from 64 to 88 percent depending upon the
coal feedstock, product gas sulfur content, and type of sulfur
removal process used. For the same coal feed, the system using
the Stretford sulfur removal process had a higher energy effi-
ciency than systems using the MEA process.
Detailed Capital and Operating Costs -
Capital and operating costs were calculated for the fol-
lowing Wellman-Galusha gasification systems producing nominally
17.6 MW (60 x 106 Btu/hr) and 87.9 MW (300 x 106 Btu/hr) of
product low-Btu gas:
• System 1 produces a hot raw product gas.
• System 2 produces a desulfurized product gas (down to
10 ppmv H2S) using a Stretford sulfur removal
process.
• System 3 produces a desulfurized product gas (down to
200 ppmv ^28) using a MEA sulfur removal process
operating at 0.44 MPa (50 psi).
• System 4 produces a desulfurized product gas (less
than 5 ppmv) using an MEA sulfur removal process
operating at 1.5 MPa (200 psi).
Tables 2.2-15 and 2.2-16 summarize the capital and operating
costs for uncontrolled Wellman-Galusha gasification systems using
86
-------
oo
TABLE 2.2-14. CALCULATED ENERGY EFFICIENCIES FOR VARIOUS
UNCONTROLLED WELLMAN-GALUSHA GASIFICATION
SYSTEMS
Energy Efficiencies Energy Efficiencies
for Systems Producing for Systems Producing
a Hot Product Gas Cool Desulfurized Gas
Coal Feed Type
Anthracite
Low-Sulfur,
HVA Bituminous
High-Sulfur.
HVA Bituminous
Lignite
Typical Raw
Gas Temperature
700°K (800°F)
840°K U050°F)f
640°K (700eF)
420°K (300°F)
a b r a
eg gT T eg
87. 2d 86. 6d 86. 6d 80. 5e
92. 8d 92. 2d 92. 2d 68. 8e
NAg NAe NA* 69.6!"
60.4,
62. 11
NAg HA* NAg 77. 0C
vb
78. 9e
67. Oe
66.8*
55.9?
50. 51
73. 6e
<
81. 5C
83. 2e
82 '6h
71. 2?
63. 91
88. 5e
H is the coal to low-Btu gas energy efficiency which relates the energy of the product gas
°8 (higher heating value or HHV of the combustible gases plus sensible heat) to the HHV of the
feed coal .
T
8
Is the gas production efficiency which relates the energy of
product gas to the total
energy input to the system (HHV of coal plus utility steam and electricity energy).
H_ is the overall thermal efficiency which relates the energy of the product gas and by-product
tars, oils, and steam to the total energy Input to the system.
These systems produce a "moderately clean" industrial fuel gas. A "moderately clean" industrial
fuel gas is used in this report to describe a low-Btu gas whose combustion emissions would be
equal to or lower than the 1471 new source performance standards (NSPS) for direct combustion of
coal in a large steam generator.
eThese systems produce a "clean" industrial fuel gas using the Stretford process for removing H2S.
A "clean" industrial fuel gas is used in this report to describe a low-Btu gas whose combustion
emission would be approximately equal to the 1979 NSPS for direct combustion of coal in large
utility steam generators.
fThis temperature is much higher than that which would normally be encountered in a Wellman-Galusha
gaslfler (600-700°K is more typical). See discussion in Section 3.
BNot applicable - These coals have sulfur contents too high to produce a hot, "moderately clean"
Industrial fuel gas.
These systems produce a "clean" Industrial fuel gas using the MEA process to remove sulfur species.
In these systems some of the low-Btu gas is used to meet the energy requirements of the MEA process.
These systems produce a "very clean" gas using the MEA process.
-------
TABLE 2.2-15.
00
00
CAPITAL INVESTMENT REQUIREMENTS AND ANNUALIZED COSTS OF
UNCONTROLLED WELLMAN-GALUSHA GASIFICATION SYSTEMS PRODUCING
NOMINALLY 87.9 MW (300 x 10« BTU/HR) OF PRODUCT LOW-BTU GAS
(LATE-1977 DOLLARS)3
Coal Feedstock/Type of Product Gaa
Capital Investment Requirements*. $1,000
Design Plant Capacity. MU
Annual Operating Factor
Annualized Coats. $l,000/yr
Operating and Maintenance Costs
Coal8
Labor/Overhead (« $15.00/man-hr)
Electricity (« $0.04/kUh)
Steam"
Chemicals
Maintenance (0 61 of direct equipment
costs)
Taxes, Insurance, and CSA Coata (£ 4Z
of depreciable investment)
Capital Related Chargea1
TOTAL Annuallced Costs. $10* /yr
Average Gaa Coata. $/GJ
An
Hot Gas"
13.300
95.6
901
5.198
524
81
_ .
596
468
2.476
9.343
3.44
thraclte
Cold Gaau
19.700
87.9
90Z
5.198
657
238
(86)
40
871
713
3.640
11.271
4.52
Low Sulfur
Hot Gasb
4,770
99.7
90Z
3,676
263
72
-
189
149
916
5,265
1.86
Bituminous
Cold Cas1-
13,100
92.4
901
4,595
394
396
40
563
465
2.436
8.889
3.39
High Sulfur
Stretfordc MEA
14.200
89.9
901
3.510
394
590
315
617
512
2.614
8.552
3.35
Bituminous
(200 ppmv)d
11.600
77.9
901
3.510
394
1.125
274
499
406
2.165
8,373
3.78
(Cold Gas)
MEA (neg.)e
14,000
80.1
901
3.510
394
334
3.390
274
582
474
2.625
11,583
5.09
*Iach system, except the one producing a hot product gaa from low sulfur bituminous coal, has a basic capacity of 87.9 MW (300 x 10* Btu/hr) of tar/oil-
free product gaa at 43.3*C (110'F). The actual total energy supplied to the end-user though Is as Indicated. Differences In the Indicated useful energy
supplied and the basic capacity of 87.9 Ml (300 x 10* Btu/hr) are a result of 1) energy credits taken for the sensible beat and/or tar/oil content of the
product gas for the hot gas system, and 2) use of a portion of the product gas to supply energy to the stripper reboller in the systems that use the MEA
process. For the hot gaa, low aulfur bituminous system, the tar/oil-free product gas rate 18*74.0 MW (253 x 10 Btu/hr). But. the sensible heat and
tar/oil content of the hot product gaa ralaa the total system capacity to 99.7 HW (340 x 10* Btu/hr). This capacity waa used in the cost analysis because
It la comparable to the capacity of the other systems examined.
Theee system* use only a cyclone for product gaa purification and deliver a hot product gaa to the end user.
cTbese systems use the Stretford process to remove HjS from the cooled product gas. Residual H2S levels are nominal 10 ppnv. Organic sulfur compounds,
such aa COS and CSj, are not removed by the Stretford process.
This system uses the MEA process operating at 0.44 MPa (50 pslg) to remove sulfur species from the cooled product gas. Residual sulfur species amount to
the equivalent of 200 ppmv H2S.
This system uses the MEA process operating at 1.5 MPa (200 paIK) to remove sulfur species from the cooled product gas. Negligible sulfur species are left
In the product gee.
In estimating capital Investment requirements, a spare gaslfler/cyclone unit is Included for all systems and cooling liquor pumps are spared 100Z.
'Assumed coal properties and delivered costs are: Anthracite: 29.7 MJ/kg (12,800 Btu/lb) and $50/metrlc ton ($45/short ton)
Low aulfur bituminous: 33.2 Hi/kg (14,300 Btu/lb) and S40/metrlc ton ($36/abort ton)
High sulfur bituminous: 29.0 MJ/kg (12.500 Btu/lb) and $28/metrlc ton ($25/short ton)
"Steam costs were assumed to be $0.Oil/kg ($5/10* Ib). Steam credits were taken aa $1/GJ ($1.05/10* Btu).
Bast* for capital related charges: Utility financing method 1001 equity financing
Late-1977 dollars without inflation 15Z after tax return on equity
25-year economic project lifetime 46Z federal income tax rate
41 per year atraightllme depreciation 10Z pretax return om working capital
of depreciable investment
-------
TABLE 2.2-16.
CAPITAL INVESTMENT REQUIREMENTS AND ANNUALIZED COSTS OF
UNCONTROLLED TOLLMAN -GALUSHA GASIFICATION SYSTEMS PRODUCING
NOMINALLY 17.6 MW (60 x 10 6 BTU/HR) OF PRODUCT LOW-BTU GAS
(LATE-1977 DOLLARS)
Coal Feedstock/Type of Product Gas
Capital Investment Requirements1, $1,000
Design Plant Capacity, MW
Annual Operating Factor
Annualized Costs, $l,000/yr
Operating and Maintenance Costs
CoalS
Labor/Overhead (6 $15.00/man-hr)
Electricity (g $0.04/kWh)
Steam6
Chemicals
Maintenance (S 6Z of direct equipment
costs)
Taxes, Insurance, and GSA Costs (g 4Z
of depreciable Investment)
Capital Related Charges1
TOTAL Annualized Costs. $109/yr
Average Gas Costs, $/GJ
Hot Gas
3,250
19.1
90Z
1,040
131
16
-
149
117
602
2,055
3.79
Anthracite
b Cold Gasc
6,110
17.6
90Z
1,040
197
48
(17)
8
276
229
1,116
2,897
5.80
Lou Sulfur
Hot Gasb
1.73O
24.9
90Z
919
66
18
-
74
58
326
1,461
2.07
Bituminous
Cold Gasc
5,200
18.5
90Z
919
131
79
8
233
194
950
2,514
4.79
High Sulfur
Stretfordc MEA
5,500
18.0
90Z
702
131
118
63
248
207
1,003
2,472
4.84
Bituminous
(200 pP«v)d
3,890
15.6
90Z
702
131
225
55
175
143
715
2,146
4.85
(Cold Gas)
MEA (neg.)e
4,700
16.0
90Z
702
131
643
55
210
171
867
2,779
6.10
"Each system has a nominal capabity of 17.6 MW (60 x 10* Btu/hr) of t«r/oll-free product gas at 43.3*C (110'F). The actual total energy supplied to the
end-user though Is as Indicated. Differences In the Indicated useful energy supplied and the basic capacity of 17.6 MW (60 x 10s Btu/hr) are a result of
1) energy credits taken for the sensible heat and/or tar/oil content of the product gas for the not gas systems, and 2) use of a portion of the product
gas to supply energy to the stripper reboller In the systems that use the MEA process.
These systems use only a cyclone for product gas purification and deliver a hot product gas to the end user.
These systems use the Stretford process to remove HjS from the cooled product gas. Residual H2S levels are nominal 10 ppmv. Organic sulfur compounds,
such as COS and CS2, are not removed by the Stretford process.
This system uses the MEA process operating at 0.44 MPa (50 pslg) to remove sulfur species from the cooled product gas. Residual sulfur species amount to
the equivalent of 200 ppmv H2S.
This system uses the MEA process operating at 1.5 MPa (2OO pslg) to remove sulfur species from the cooled product gas. Negligible sulfur species are left
in the product gas.
In estimating capital Investment requirements, a spare gasifier/cyclone unit Is Included for all systems and cooling liquor pumps are spared 100Z.
^Assumed coal properties and delivered costs are: Anthracite: 29.7 Hi/kg (12,800 Btu/lb) and $50/metrlc ton ($45/short ton)
Low sulfur bituminous: 33.2 HI/kg (14,300 Btu/lb) and $40/metrlc ton ($36/short ton)
High sulfur bituminous: 29.0 MJ/kg (12,500 Btu/lb) and $28/metric ton ($25/short ton)
hSteam costs were assumed to be $0.Oil/kg ($5/10* Ib). Steam credits were taken as $1/GJ ($1.05/10* Btu).
Basis for capital related charges: Utility financing method 100Z equity financing
Late-1977 dollars without Inflation 15Z after tax return on equity
25-year economic project lifetime 46Z federal Income tax rate
4Z per year stralghtllne depreciation 10Z pretax return on working capital
of depreciable Investment
-------
various coal feedstocks. Costs of removing sulfur species from
the low-Btu product gas are included in these cost estimates.
However, pollution control equipment costs are not included.
As shown in Tables 2.2-15 and 2.2-16, the product gas
costs are dependent upon coal feedstock, product gas specifica-
tion (tar/sulfur content) and plant size. Product gas costs for
producing a hot raw gas for on-site use (System 1) range from
$1.90 to $3.80 per GJ ($2.00 to $4.00 per 106 Btu) depending
upon the coal feedstock. For systens using a Stretford sulfur
removal process, product gas costs range from $3.40 to $5.80 per
GJ ($3.60 to $6.10 per 10° Btu) depending upon the coal and
unit size. If an MEA sulfur removal process is used to remove
gaseous sulfur species, product gas costs would range from $3.80
to $6.10 per GJ ($4.00 to $6.40 per 10° Btu) depending upon the
product gas sulfur content and unit size.
For each of these gasification systems, the major cost
item is the coal feedstock. For systems using anthracite coal,
the coal costs represent 36 to 56 percent of the total costs of
the product gas. For systems using low-sulfur bituminous coal,
coal costs are between 36 to 70 percent of the product gas costs
and for high-sulfur bituminous coals, 25 to 42 percent.
2.2.3 Detailed Description of Processes and Systems
As mentioned previously, Wellman-Galusha gasification
systems have three basic operations: coal pretreatment, coal
gasification, and gas purification. Details of these operations
and the processes which comprise them are presented below:
Coal Preparation -
The coal preparation operation at Wellman-Calusha gasi-
fication facilities consists solely of coal storage, handling,
and conveying. Because Wellman-Galusha gasification facilities
may be limited in size, coal grinding and sizing will probably
not be performed on-site. Instead, coal will be purchased
presized from the coal mine or coal preparation plant.
Coal is transported by rail or truck to the gasification
plant. At the gasification plant, it is stored in uncovered
piles on the ground or possibly in covered or uncovered bins.
Coal stockpiling could include coal supplies equal to 30 or more
days of production. For facilities producing 17.6 to 87.9 MW (60
to 300 x 10^ Btu/hr) of low-Btu gas from bituminous coal, a 30
day supply of coal is about 2 to 12 Gg (2000 to 13,000 short
tons) .
90
-------
Front-end loaders or belt conveyors transport coal from
storage to an underground bunker which empties into a bucket ele-
vator. The bucket elevator then transports the coal to a main
storage bin located above the coal hoppers that feed the gasi-
f iers.
Emissions from coal preparation consist of rainwater
runoff/ leachate from uncovered storage piles or bins, and coal
dust from coal handling and conveying.
Coal Gasification -
Figure 2.2-6 is a diagram of a Wellman-Galusha gasifier
equipped with a coal bed agitator. In the Wellman-Galusha gas-
ifier, low-Btu gas is produced from the countercurrent gasifica-
tion of coal with a mixture of air and steam. Use of the agita-
tor increases the gasifier capacity and permits the gasification
of caking bituminous coals.
Coal Feeding - Coal is continuously fed by gravity from
the coal hoppers to the gasifier via a set of coal pipes. Slide
valves are located at both the top and bottom of the coal hop-
pers. Under regular operating conditions, the upper valves are
closed and the lower ones are open. At periodic intervals, the
bottom slide valves are closed and the top ones opened. This al-
lows coal to gravity feed from the coal bin to the coal hoppers.
After being replenished with coal, the coal hopper slide valves
are returned to their regular operating positions.
Gasification - As coal flows downward through the gasi-
fier, it passes countercurrently to the flow of gas. In the
upper portion of the gasifier, the coal is preheated by the hot
gas. As the coal flows downward, moisture in the coal evaporates
and the coal undergoes a range of devolatilization reactions
producing tars and oils.
In the gasification zone of the gasifier, various
endothermic reactions occur between the coal and the hot gases
passing upward from the combustion zone. The principal reactions
are shown in Equations 2.2-1 to 2.2-3.
C 4- COa •* 2CO (2.2-1)
C + HiO •*• CO + Hz (2.2-2)
C + 2Ht + CH,, (2.2-3)
Heat for the various endothermic reactions is provided by the
sensible heat of the gases leaving the combustion zone. A fourth
reaction, the water-gas shift reaction, occurs in the gas phase:
91
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VENT
ELEVATOR
AGITATOR
COUNTERWEIGHT
COAL BIN
COAL HOPPERS
PRODUCT GAS
SATURATION PIPE
DEVOLATILIZATION ZONE
GASIFICATION ZONE
COMBUSTION ZONE
REVOLVING GRATE
CYCLONE AND
WATER SEAL
SHUT-OFF
VALVE
••AIR
ASH BIN
Figure 2.2-6.
Diagram of a Wellman-Galusha Gasifier
Equipped with a Coal Bed Agitator
92
70-1428*1
-------
CO + H20 + C02 + H2 (2.2-4)
Equilibrium established by this reaction largely determines the
composition of the raw product gas. Various reactions involving
sulfur and nitrogen species also occur in the gasification zone.
Exothermic reactions occurring in the combustion zone
produce the heat needed for the endothermic reactions in the gas-
ification zone. The principal reactions occurring in the combus-
tion zone are the complete and incomplete combustion of carbon:
C + %02 •* CO, and (2.2-5)
C + 02 - C02. (2.2-6)
Steam fed to the gasifier with the inlet air absorbs some of the
heat released during combustion, and helps to maintain the com-
bustion temperature below the coal ash softening temperature.
Some cooling is also provided by water circulating in a jacket
that completely surrounds the gasifier.
The inner wall of the gasifier is steel plate, although the lower
portion of the gasifier may be refractory-lined. The coal bed
agitator has a revolving horizontal arm which also spirals verti-
cally below the surface of the coal bed. The agitator prevents
channeling in the coal bed by breaking up agglomerates and helps
to maintain a uniform bed. The agitator arm and its shaft are
made of water cooled heavy steel tubing. The arm can be revolved
at varying speeds. Pokeholes are 'located on the top of the gasi-
fier. Periodically, rods are inserted through the pokeholes to
measure the depth and location of the "fire" and ash in the com-
bustion zone. These rods can also be used to break up any ag-
glomerates formed in the bed.
A fan supplies the air required for gasification. The
air is passed over water in the water jacket and is nearly sat-
urated with water vapor. The amount of water vapor added to the
air is controlled by the temperature of the jacket water. The
air/steam blast is then introduced into the ash bin beneath the
ash grate. The grate distributes the blast to the coal bed
above. The blast is preheated by contact with hot coal ash be-
fore entering the combustion zone.
Ash Removal - A revolving step-type grate at the bottom
of the gasifier moves ash from the gasifier into the ash bin.
The grates supports the ash and coal beds and distributes the
air/steam mixture fed to the gasifier. The ash hopper is sealed
with the atmosphere by a slide valve. Before ash is removed from
the ash hopper, water is added to slurry the ash to aid in its
removal and to help seal the ash hopper from the atmosphere.
93
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Air emissions from the gasification operation include
raw product gas which passes through the coal feeding mechanism
and which leaks past the pokeholes, startup vent gases and fugi-
tive emission from the ash bin during ash removal. Ash sluice
water is a liquid effluent, while ash is the only solid waste.
Gas Purification -
The purpose of the gas purification operation is to re-
move undesirable constituents such as particulates, tars, oils,
and sulfur compounds from the raw low-Etu gas. The performance
specifications for the prcesses in this operation are defined by
the intended use of the product gas. The product gas specifica-
tions examined in this environmental assessment are reported in
Table 2.2-3. The processes needed to satisfy these product gas
requirements include:
• particulate removal,
• gas quenching and cooling,
• tar and oil removal, and/or
• sulfur compound removal.
These processes are discussed below:
Particulate Removal - All proposed or operating Vlellman-
Galusha gasification systems feature cyclones as the initial
cleanup step. Cyclones are preferred for the bulk removal of
particulates because they are relatively inexpensive, low-energy
consuming devices. Although cyclones are efficient in the re-
moval of large particulates, other techniques are required to ob-
tain efficient removal of small particulates. The efficiency
range of conventional cyclones typically supplied with Wellman-
Calusha gasifiers is summarized in Table 2.2-17.
Data from testing at low-Btu gasification facilities
show overall removal efficiencies of 60 to 80% (Ref. 13). Re-
moval of only 60% of the particulates from the raw low-Btu gas is
sufficient for all but the most stringent product gas specifica-
tions examined. This is because most of the particulate matter
is carbon, which should be burned with the product gas. Particu-
lates not removed by the cyclone may be removed in downstream
scrubbers and electrostatic precipitators. Potential waste
streams from the cyclone include collected particulate matter and
fugitive emissions.
94
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TABLE 2.2-17. EFFICIENCY RANGE OF "CONVENTIONAL" CYCLONES
Particle size, \im Efficiency range, wt 70 collected
5 50
5-20 50-80
15-40 80-95
40 95-99
Source: Ref. 19
95
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Gas Quenching and Cooling - In the gas quenching and
cooling module , tars and oils are condensed, and particulates and
other impurities such as ammonia are scrubbed from the raw
product gas. For systems described in this report, the principal
purposes of the quenching/cooling process are:
• the removal of most of the tars and heavy oils from
the product gas, and
• the cooling of the product gas to approximately 316 K
These conditions are required by the downstream sulfur removal
processes .
The gasification of anthracite coal produces a gas con-
taining essentially no tars and oils. The absence of tars and
oils simplifies the design of the quenching/cooling module and
permits the use of waste heat boilers to recover a portion of the
sensible heat of the product gas. In a system producing 17.6 MW
(60 x 106 Btu/hr) of low-Btu gas, 0.32 kg/s (2500 lb/hr) of
steam are recovered, with an energy content of 0.615 MW (2.1 x
106 Btu/hr).
Downstream of the waste heat boiler, the gas is quenched
and cooled in a simple spray tower. Cooling liquor leaves the
tower at 325 K (125°F) and is cooled to 308 K (95°F) for recycle
to the spray tower. Sediment is periodically removed from the
cooling loop.
Although waste heat recovery is always desirable, foul-
ing problems from tar and oil condensation in the waste heat
boiler may preclude the use of waste heat boilers in gasification
systems gasifying tar-producing coals. Quenching of the gas oc-
curs in an in-line quench. Further cooling and scrubbing of the
gas occurs in vertical tray and spray towers. The quenching and
cooling scheme chosen for nonanthracite gasification systems is
similar to that of an existing Chapman facility (Ref. 13).
The quenching and cooling system is designed to remove
about 60-70% of the tars and oils from the gas (Refs. 13, 15,
20). Although the system can be designed for more stringent re-
covery of tars and oils, it appears to be desirable to leave
cleanup of residual tars and oils to an electrostatic precipi-
tator. High energy scrubbers (like Venturis) could conceivably
replace part of the cooling system to provide greater collection
efficiency of small tar particles and aerosols.
96
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The tar-laden quench/cooling liquor is sent to a tar
liquor separator. Tars and heavy oils collect in the bottom of
the separator and are periodically removed and stored. Process
condensate is removed from the system as a blowdown. Lighter
oils can be skimmed from the tank.
Various organic and inorganic compounds are scrubbed
from the raw product gas by the quenching and cooling processes.
In the tar/liquor separator, some of the absorbed gases and
vapors desorb from the quench liquor and fill the vapor space
above the liquor. A vent stream from the separator would then
contain constituents of the product gas, including I^S, COS,
CS2i S02> H2» C02» co> NK3» HCN, and organic vapors.
The quenching and cooling systems used with the Stretford sulfur
removal process feature a centrifugal blower to yield a product
gas at 110 kPa (30 in W.G.). Systems used with the MEA sulfur
removal process include turboblowers or compressors to attain the
higher pressures needed for satisfactory operation.
Waste streams from the quenching and cooling processes
include:
• vent gases from tar/liquor separator,
• process condensate, and
• fugitive gases and liquids.
Tar and Oil Removal - As previously described, the bulk
removal of tars and oils from raw product gas occurs in the
quenching and cooling process. However, both sulfur removal
processes examined in this study have strict limits on the inlet
gas tar and oil loadings. Electrostatic precipitators are used
to achieve the final removal of tar and oil aerosols.
In similar processing of coke oven and carburetted water
gases, ESP's have demonstrated removal efficiencies in excess of
99 percent, achieving outlet particulate/tar loadings as low as
0.003 g/m^ (0.0131 gr/ft3). In cleaning suspended matter
from producer gas from lignite, loadings as low as 0.1 g/m3
(0.0437 gr/ft3) have been achieved (Refs. 21, 22). Recently, a
vertical-flow dry ESP demonstrated removal efficiencies in excess
of 99 percent in cleaning gas from a pilot-scale Riley Morgan
gasifier (Ref. 15)..
About 99 percent of the residual tar and oil aerosols
and most of the remaining particulates in the gas are assumed to
be removed in the ESP.
97
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Sulfur Compounds Removal - A wide variety of processes
is available for the removal of sulfur species from gas (Ref.
23). However, not all of these processes can effectively remove
sulfur compounds from a low-pressure gas, nor can they remove
both H2S and COS.
Certain product gas specifications assessed in this re-
port require the removal only of H2S from the low-Btu gas.
This is probably most easily accomplished in a sulfur removal
process that directly converts the H2S to sulfur, such as the
Stretford or Thylox processes.
Product gas specifications requiring both COS and H2S
removal can use either amine and alkaline salt chemical solvent
processes. These processes--represented by the monoethanolamine
(MEA), diethanolamine (DEA), and diglycolamine (DCA) processes,
and the Benfield process, respectively—form chemical complexes
with the acid gas component. Subsequent thermal regeneration of
the chemical complexes produces an acid gas stream that requires
further treatment before release.
The Stretford process was selected as the sulfur removal
process for those systems requiring the removal of H2S only.
The Stretford process which has been commercially applied to the
treatment of a variety of gases (including coke oven and low-
Btu) , now appears to be among the most popular processes for re-
moving H2S from gas streams containing small concentrations of
H2S. Alternate processes (e.g., the iron oxide process) appear
to be more costly and to have greater environmental impacts and
land requirements.
The MEA process was selected as the sulfur removal pro-
cess for those systems requiring the removal of both H2S and
COS. Although the MEA process has disadvantages such as solvent
degradation caused by COS and its high steam regeneration re-
quirements, it has been shown to be the most reactive of the
chemical sorbents and much data are readily available. While the
MEA process is examined here, other amine systems should have
similar general characteristics.
Stretford Process - The Stretford process uses direct,
liquid-phase oxidation to recover elemental sulfur from gas
streams containing I^S. Numerous commercial applications have
successfully treated a variety of gas streams, including coke
oven gas, refinery gas, synthesis gas, natural gas, Claus plant
tail gas, and acid gas from physical absorption or amine absorp-
tion processes (Refs. 16, 24, 25, 26). t^S removal efficien-
cies greater than 99 percent have been achieved, with residual
98
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outlet H2S loadings less than 10 ppmv (less than 1 ppinv in some
cases) (Refs. 16, 27).
The overall reaction to produce sulfur is as follows:
2H2S + Oz
2S
2HzO
(2.2-7)
This reaction takes place in several steps. First, H2S is ab-
sorbed in a sodium salt solution of CO;**8, HC03~, roetavan-
adate and anthraquinone disulfonic acid (ADA). The absorbed
HoS then reacts with the carbonate to form hydrosulfide
(HS-).
H,S
co;
- + HC01
(2.2-8)
Next, the HS~ is oxidized to elemental sulfur by the vanadium,
which is reduced from the pentavalent to the quadrivalent form:
4VOj + 2HS- + H20 £ V^O; + 2S + 40H~ (2.2-9)
The vanadate is reoxidized to the pentavalent form by the ADA:
V^Of + 20H- + H20 + 2ADA * 4VOI + 2ADA (reduced)
(2.2-10)
The reduced ADA is then oxidized by air back to its original
form:
2ADA (reduced) + 02 + 2ADA + 2HaO
(2.2-11)
A simplified flow diagram for the process is shown in
Figure 2.2-7. Solution leaving the absorber is held in a delay
tank to allow sufficient time for the HS~ to be oxidized to S.
The solution is then sent to an oxidizer for the oxidation of
ADA. Air bubbled through the solution also causes the sulfur
particles to float to the top of the oxidizer. Regenerated solu-
tion is returned to the absorber, while the sulfur froth is sent
to a surge tank for feed to a vacuum filter. The sulfur is de-
watered to about 50 percent solids and then washed to recover the
Stretford solution (Ref. 16). The sulfur may be further purified
by autoclaving to produce a salable by-product. However, the
quantities of sulfur produced in the systems described in this
report are probably too small to justify recovery.
Alternatively, the sulfur cake can be disposed of as a
solid waste. Depending on the amount of water used to wash the
sulfur cake, some of the water may have to be evaporated before
it is returned to the absorber (Ref. 16).
99
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STRETFORD PROCESS
TREATED GAS
INLET GAS
EVAPORATOR
OFF-GAS
t
SORBENT
SLOWDOWN
HASH HATER SULFUR
CAKE
70-1423-4
Figure 2.2-7. Schematic Flow Diagram for
the Stretford Sulfur Removal
Process
100
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KCN in the feed gas is also absorbed by the Stretford
solution, producing nonregenerable thiocyanate. In addition,
about 1 to 2 percent of the H2S absorbed is oxidized to nonre-
generable thiosulfate (Ref. 16). These salts must be removed
from the system. A small quantity will be removed with the sul-
fur cake; the remainder must be removed as a blowdown stream.
Batch blowdowns are generally carried out when the total salts
concentration reaches about 40 percent. Alternatively a contin-
uous blowdown can be used to maintain the salts concentration at
20 to 25 percent (Ref. 28). Quantities and compositions of this
blowdown are discussed in Section 3. Methods for treating this
blowdown stream are discussed in Section 4.
More than 99 percent of the inlet ^S can be removed
by the Stretford process. Outlet H^S concentrations of 10 ppmv
are common with concentrations less the 1 ppmv achievable (Ref.
16). The H2S removal reaction is very fast, and approaches
equilibrium. Thus, for gases with low C(>2 concentrations it
may not be practical to design a Stretford unit to leave more
than about 100 ppmv of H2S in the exit gas (Ref. 29). Depen-
ding on the concentration of C02 in the gas stream, some is
absorbed along with the H2S. The absorbed CC>2 lowers the
solution pH and decreases the I^S absorption rate. As a re-
sult, very tall absorbers are required to treat gas streams with
high C02 partial pressures (Refs. 16, 30). The Stretford pro-
cess does not remove significant amounts of organic sulfur com-
pounds such as COS and CS2 (Ref. 16).
One problem that may affect the use of the Stretford
process for treating the low-Btu gas from the Wellman-Galusha
gasifier results from the high level of tars produced by the gas-
ifier. Tar in the gas fed to the Stretford can lead to foaming
in the absorber, difficulty in sulfur flotation, and production
of a contaminated sulfur product ("Black Sulfur") (Refs. 30, 31).
An acceptable upper limit for tar loading to prevent these pro-
blems is unknown (Ref. 31). Tar removal in a quench system and
electrostatic precipitator have been sufficient for applications
involving coke oven gas. However, gas from Wellman-Galusha gas-
ifiers contain more tar than coke oven gas. The Stretford pro-
cess has yet to be successfully demonstrated on gas from such a
system (Ref. 32).
Potential waste streams from the Stretford process in-
clude evaporator and oxidizer vent gases, process blowdown, and
recovered sulfur.
Monoethanolamine (MEA) Process - Aqueous mono ethano la-
mine solutions were once among the most widely used solutions for
the removal of acid gases. Today, MEA systems are rapidly being
replaced by more efficient systems, particularly for the treat-
ment of high-pressure natural gases. However, MEA is still the
101
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preferred solvent for treating sour gas streams containing
relatively small amounts of H2S and C02« MEA is especially
preferred when low-pressure gas is treated and maximum removal of
H2S and C02 is required (Refs. 16, 33). Although MEA has not
been used to remove acid gases from coal gases, a similar amine
(diglycolamine) has been used for acid gas removal at the IGT
pilot gasification plant (Ref. 34).
The removal effectiveness of MEA absorption processes
depends mainly on operating pressure and the residual l^S and
C02 contents of the lean MEA solution fed to the absorber. The
residual H2S and C02 contents of the lean MEA solution de-
termine the minimum H2S and CC>2 loadings in the treated gas,
as defined by gas-liquid equilibria. The operating pressure of
the contactor determines the partial pressure of acid gases over
the MEA solution. For given residual H2S and CC>2 con-
tents in lean MEA solution, the operating pressure determines the
minimum levels of H2S and C02 practically achieved in the
treated gas.
The residual H2S and COo contents in lean MEA
solutions are mainly determined by the amount of steam used to
strip the acid gases from solution and by the height of the
stripping column. The removal of CC>2 from rich solutions is
the more difficult stripping operation because of the relative
stability of the monoethanolamine-C02 complex. The lean
solution recirculated to the absorber usually is stripped to a
level of about 0.15 moles of C02 per mole of MEA. Although the
H2S content of the lean solution is low, the high C02
loadings increase the equilibrium partial pressure of H2S over
the solution, which reduces the effectiveness of H2S removal
(Ref. 16). Increased steam rates lower the residual contents of
HoS and C02 in the lean solution and thus increase the
effectiveness of H2S removal. The rate of desorption of C02
from MEA solutions is relatively slow, and is "not materially
affected by the flow rate of stripping steam (Ref. 16).
H2S concentrations of 6 mg/Nm^ (0.25 gr/100 scf) or
less in the treated gas can be practically obtained at operating
pressures above 1.4 MPa (200 psi) (Ref. 16).
If the operating pressure is less than 0.7 MPa (100
psi), it is difficult to attain hydrogen sulfide loadings in the
outlet gas of less than 24 mg/Nm^ (1 gr/100 scf). Below 0.4
MPa (50 psi), it is difficult to attain I^S loadings in the
outlet gas of less than 50 mg/Nm3 (2 gr/100 scf) (Ref. 17).
A flow scheme of the basic MEA process is shown in
Figure 2.2-8. In operation, gas is contacted in the absorber by
102
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ME/1. PROCESS
INLET GAS
MAKE-UP
CHEMICALS
29>— — »-ACID GAS
REBOILER r>J
J
— e STEAM /^
STEAM"* \
SLOWDOWN
70-1425-4
Figure 2.2-8. Schematic Flow Diagram for the
MEA Acid Gas Removal Process
103
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a 10 to 2C vt °L MEA-water solution. Many units are designed to
operate with 20 percent MEA solution, but a more conservative
figure is 15 percent MEA in water. At the lower concentration,
reduced corrosion and fouling are encountered (Ref. 17). The
princiapl reactions occurring in the absorber are (Ref. 16):
2HOCtH,NHi + HtS * (HOCtH»JM,)tS (2.2-12)
(HOCiH»NHi)iS + HiS * 2HOCjH,NH,HS (2.2-13)
2HOCiH,NHi * COt + HiO * (HOC.H.NHi)jCO> (2.2-14)
(HOCiH»NHt)tCOi + COi + HtO - 2HOC
-------
reactions between C02 and MEA also occur. All ethanolamines,
including MEA, are subject to oxidative degradation with the
formation of dithiocarbamates, thioureas, thiosulfuric acid,
formic acid, and other degradation products. Carboxylic acids,
hydrochloric acid, and hydrogen cyanide also react irreversibly
with MEA (Ref. 16).
Carbonyl sulfide reacts irreversibly with MEA to form
oxazolidon-2, l-(2-hydroxyethyl) imidazolidone-2, and diethanol
urea. In commercial facilities, most of the COS present in the
gas undergoes hydrolysis to form H2S and C02, with 15 to 20
percent of the COS reacting irreversibly with the MEA (Ref. 16).
At low pressures, residual COS in the clean gas may amount to
about 30 ppmv (Ref. 18).
Carbon disulfide, present in the low-Btu gas in small
amounts, reacts irreversibly to form substituted dithiocarbamates
and thiocarbamides (Ref. 16).
Precipitates, sludge, and high-molecular weight degrada-
tion products are commonly removed from MEA solutions by filtra-
tion through activated carbon or by reclaiming. Reclaiming
involves the distillation of a small side stream, usually 1.5 to
2 percent of the main flow of MEA. Sodium carbonate or hydroxide
is added, if necessary, to free the amine from the acid salts and
minimize corrosion. Reclaiming is a batch operation; at the com-
pletion of each reclaiming cycle, accumulated solids and high-
boiling constituents are removed from the reclaimer and disposed
(Refs. 16, 17, 33).
Advantages and disadvantages of MEA absorption have been
summarized by Goar and Arrington (Ref. 35). Advantages of MEA
absorption include:
• high reactivity,
• low solvent cost
• good chemical stability, and
• ease of reclamation.
Disadvantages include:
• irreversible degradation due to reaction with various
contaminants,
• high solvent vaporization losses,
• low removal of mercaptans, and
• nonselectivity for H2S absorption.
In this report, MEA absorption was selected as the sulfur-removal
process when removal of both H2S and COS is required.
105
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Potential waste streams from the MEA process include an
acid gas stream and solvent blowdown.
2.3 PROCESS AREAS OF CURRENT ENVIRONMENTAL CONCERN
Wellman-Calusha low-Btu gasification systems are sources
of gaseous, liquid, and solid waste streams. Also associated
with these systems are process and by-product streams that may
contain toxic substances. The multimedia waste streams and pol-
lutants of major concern are summarized in Tables 2.3-1 through
2.2-3. Potentially toxic compounds that may be present in
product and by-product streams are summarized in Table 2.3-4.
Caseous emissions from Wellman-Galusha systems contain a
significant amount of pollutants that may have harmful health and
ecological effects. Gaseous pollutants (CO, I^S, HCN, NHo,
and light hydrocarbons) from the coal feeder and gasifier poke-
holes need to be controlled. Start-up vent gases will contain
compounds found in the raw product gas (CO, sulfur species, light
hydrocarbons, tars and oils) which will require control before
venting to the atmosphere. Vent gases from the by-product tar
recovery process will contain significant amounts of potentially
harmful pollutants and will, therefore, need to be controlled.
Emissions from sulfur removal processes are not yet characterized
since there are currently no sulfur recovery processes being used
with fixed-bed, atmospheric pressure, low-Btu gasification sys-
tems.
The amount of liquid effluents from Wellman-Galusha sys-
tems will be limited to blowdown streams, ash sluice water, and
coal pile runoff. Of these effluents, the blowdown streams will
contain significant quantities of potentially harmful constitu-
ents. Ash sluice water and coal pile runoff will contain com-
pounds leached from the ash and coal which may affect health and
the environment.
Solid waste streams from Wellman-Galusha systems will
consist of ash, collected particulates, sulfur, and blowdown from
the MEA sulfur removal process. Ash and sulfur may contain
leachable constituents that may be potentially harmful. Collect-
ed particulates resemble devolatilized coal and therefore, may be
classified as a solid combustible material. MEA blowdown sludge
contains potentially harmful constituents and needs to be treated
before disposal.
The by-product tar and quench liquor represent process
streams that contain potentially harmful organic and inorganic
compounds. Worker exposure and accidental releases of these
streams should be carefully controlled.
106
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TABLE 2.3-1.
GASEOUS WASTE STREAMS AND POLLUTANTS OF MAJOR CONCERN
FROM WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
Operation
Process
Caseous Haste Stream
Pollutants of Major Concern
Remarks
Coal Preparation
Coal Storage and
Handling
Coal Gasification
Uellman-Galusha
Gaslfler
Coal dust
Coal feeder vent
gases
Start-up vent gases
Gas Purification
Gas Quenching and
Cooling (Tar/
Liquor Separation)
Sulfur Removal-
Stratford
Sulfur Removal*
HEA
Fugitive emissions
(pokehole gases)
Separator vent gases
Evaporator and
oxidlzer vent gases
Acid gas stream
Particulate matter similar in composition ot the
coal feedstock.
Gaseous species in the product gas (CO. HzS. HHS,
HCH, light hydrocarbons).
Raw product gas constituents. Particulate matter
(coal dust, tar, oil aerosols) and gaseous
species (CO. H2. H2S, COS, MB,, HCH, light hydro-
carbons, etc.). Organic* of concern include fused
aromatic hydrocarbons, heterocyclic nitrogen,
sulfur and oxygen compounds, carboxylic acids,
amines, sulfonic acids, sulfoxides, phenols,
thiols, benzene, and substituted benzene hydro-
carbons. Inorganics of concern include CO,
ethylene, Cr, Hg, U, V, Al, P, As, Cu, Cd, U2S,
C02. HCN. Li. Tl, Si, Pb. Sb, SO2. CS2, Cl. Ti.
Zr, Fe. Co, Hi, Ag and Zn.
Gaseous species in the product gas (CO, H2S, HH»,
HCN. light hydrocarbons).
Organlcs of concern Include fused aromatic hydro-
carbons, amines, heterocyclic nitrogen and sulfur
compounds, ethylene, phenols, methane, and
carboxylic acids. Inorganics' of concern Include
CO. NHj. NOi, C02, Cr. Ag. V. Cu. P. LI. As. Fe.
Hi, and U.
Volatile compounds in the Stratford liquor OfcO.
C02, N2, 02, and possibly NHj).
C02, H2S, COS, CS2,
hydrocarbons.
ercaptans, and light
Bituminous coal gave slightly positive results for
the Ames test which indicates a potential for the
coal being carcinogenic. Anthracite coal results
were negative.
High levels of CO were found in the coal hopper
area.
The amount of tars and oils will depend upon the
coal feedstock. Bituminous coals will have a
significant amount of tars where anthracite will
not. .Tars from the gasification of bituminous
coals gave positive results on the Ames test which
Indicates they may be carcinogenic.
Emissions of tars and oils will occur when poke-
hole valves are open; however, the major emissions
from the pokeholes will be from gaseous species
In the product gas leaking from the pokehole
valves.
These pollutants of concern are associated with
bituminous coals.
This stream has not been sampled because no
Stretford processes are currently used or have
been successfully demonstrated to remove sulfur
species from low-Btu gas.
This stream is sent to a sulfur recovery unit
consisting of a Glaus process followed by a Claus
tall gas clean-up process to remove the sulfur
species in the acid gas stream. This stream has
not been sampled since HEA processes have not
been used to remove sulfur species from low-Btu
gas. However, Koppers has used the HEA process
to desulfurlze medlum-Btu gas.
-------
TABLE 2.3-2. LIQUID WASTE STREAMS AND POLLUTANTS OF MAJOR CONCERN FROM
WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
Haate Stream
Pollutant* of Major Concern
kmarks
O
oo
Coal Preparation
Coal Handling and
Storage
Coal Gasification
Hellmsn-Calueha
Caalflar
Ca« Purification '
Ca* Quenching and
Cooling
Sulfur temoval-
S tret ford
Coal pile runoff
Aah alulca water
Proceia condenaate
Solvent blowdown
Contain teachable organic* and inorganic*.
Inorganic* of major concern Include P. Tl, V, Cu,
Fe, Ba, Cd, Cr, CM', LI and HI. Organic concen-
tration* of 65 ng/t have been found; however. It
la not certain whether theee were present In the
plant'* service water used to alulce the aah
fro* the gaalfler.
May contain organic and Inorganic pollutant*
found In the quench liquor (*ae Table 2.3-4).
Thloeulfate and thlocyanat* salts.
The composition of thla atreaa will depend upon
the coal feedatoek and alte-apeclflc condition*
(i.e. pH of leachate).
The Mount of sluice water la low and highly variable.
Negative tact tests were obtained with low to non-
detectable results indicated for the eytotoxlcitjr and
rodent acute toxlclty teat* for sluice water fro* a
facility gasifying anthracite coal. This indicates
that the a*h sluice water has a low potential for
effecting health of the environment.
The amount of process condensate produced will
depend upon the system operation and type of
processes used. Typical process condensata flow
nay range between 3.79 x 10"* to 1.52 x 10~'
•'/sec (5 to 20 gpm).
The amount of these salts produced will depend
upon the sulfur and cyanide content of the cooled
product gaa entering the Stretford process.
Sulfur contents nay range from 600 to 10.000 pomv
while cyanide nay rang* from 50 to 200 ppsjv.
-------
TABLE 2.3-3.
SOLID WASTE STREAMS AND POLLUTANTS OF MAJOR CONCERN
FROM WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
Operation
Process
Solid Waste Strea
Pollutants of Major Concern
Remarks
Coal Gasification
Well-Ban-Galusha
Gaslfier
Gaslfler ash
Ash leachate
(anthracite coal)
Gas Purification
Participate Removal- Collected particulate
Hot Cyclone Batter
Sulfur Removal-
Stretford
Sulfur Removal-
MEA
Collected particulate
natter leachate
(anthracite coal)
Sulfur
MEA sludge
Inorganics of major concern include Be, P, Fe,
Ca, Al, Li, Ba, Se, Pb, Cs, Cu, Tl, Cd, Sb, V,
Co, U, Mg, Sr, SI, Ug, Zr, F, Rb, As, Mn, Cr, Nl,
Tli, Bl, Ag, T. Total extractable organics in
the ash is low ranging from 40-116 |ig/g. Organlcs
of potential concern include phthalate esters,
phenols, nitrophenols, and fused aromatic hydro-
carbons.
Inorganics of concern include P, Zn, Cd and Ag.
Inorganics of major concern include Ml, Pb, P,
Hn, Fe. Cu, Ba, Sb, Tl. Cr, Ca, Al, V, Li, Mg,
Zr, Co, As, SI, Se, Be, Cd, Ag, Th, Zo, F, Ga,
Hf, Hg, Sr. Tl, ¥. Low concentrations (40 to
800 Mg/g) of extractable organics have been
determined. Organlcs of concern Include phthalate
esters, phenols, nitrophenols, amines, cresols.
Inorganics of major concern Include Ha, Pb, LI,
Zn, Al, Cd, Co, Cu and Fe.
Contain organics and Inorganics including
thlocyanate and thlosulfate salts.
Degradation products including oxazolldon-2,
l-(2-hydroxyethyl) imldazollndone-2, dletbanol
urea, dithiocarbamates, thiocarbamides and other
high molecular weight nonregenerable compounds.
Results from the Ames, cytotoxlcity, and rodent
acute toxicity tests for ash produced from gasi-
fying anthracite and bituminous coals were nega-
tive, low or nondetectable. Effects on soil
microcosms were also low. This indicates that the
ash may have a low potential for harmful health
and ecological effects.
Results from the Ames, cytiitoxicity and rodent acute
toxicity tests of leachate from ash produced fron
gasifying anthracite coal were negative, low or
nondetectable. This indicates that leachate
resulting from ash may have a low potential for
harmful health and ecological effects.
Negative results tram the Ames test have been
obtained with low to noadetectable results from
cytotoxicity and rodent acute toxicity tests.
High effects on soil microcosms were found. Col-
lected particulates resemble devolatillzed coal
with carbon contents ranging from 70 to 801.
These may indicate that the cyclone dust may have
a low potential for harmful health effects but a
high potential for ecological effects.
Negative Ames test results were obtained and
cytotoxicity test results were nondetectable.
This Indicates that the leachate may have a low
potential for harmful health effects.
No data Is currently available on the chemical
and biological aspects of the recovered sulfur.
No data Is currently available on the character-
istics (chemical or biological) of MEA sludge.
-------
TABLE 2.3-4. POTENTIAL TOXIC STREAMS AND COMPOUNDS OF MAJOR CONCERN FOR
WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
Op«r»tlo«
Process
Potential
Toxic Stream
Compound* of Major Concern
Remarks
Gas Purification
Gas Quenching and
, Cooling
By-product tar
and oils
Quench liquor
Organlcs of major concern Include fused
aromatic hydrocarbons, benzene, substituted
benzene hydrocarbons, heterocycllc nitrogen,
aulfur and oxygen compounds, carboxylic acids,
aliphatic hydrocarbons, phenols and amines.
Inorganics of concern Include Cu, Pb, Sb, Cr,
Cd. Ba, Hg, V, Hg, and As.
Organlcs of major concern Include phenols,
fused aromatic hydrocarbons, heterocycllc
nitrogen and sulfur compounds, carboxylic
acids, thiols, glycols, and epoxldes. Inorganics
of concern Include NHj, cyanides, P, Se, As, F,
Cl, Ca, Fe and Cd.
Tar will be produced from bituminous and lignite
coals. Positive Ames test results have been
obtained. This Indicates that the tar may be
carcinogenic. Safe handling and controlling tar
leaks procedures are required.
Results from aquatic bioassay tests Indicated a
high potential effect on aquatic species. Health
effects tests were low; however, because of the
chemical characteristics of the quench liquor,
safe handling and control of leaks are required.
-------
It should be emphasized that the chemical characteris-
tics and potential biological effects of the multimedia waste
streams are highly dependent upon the coal feedstock and pro-
cesses used. For example, tars and oils will be produced when
bituminous or lignite coal is gasified. However, if anthracite
is the coal feedstock, tar and oils are not produced although
some light oils may be present.
Ill
-------
SECTION 3.0
CHARACTERIZATION OF INPUT MATERIALS, PRODUCTS,
AND WASTE STREAMS
This section summarizes the best available information
on the physical, chemical, and biological characteristics of in-
put materials, products, by-products, and waste streams associ-
ated with Wellman-Galusha gasification systems. These data are
results from test programs performed in the U.S. at various
commercial-size low-Btu gasification facilities.
3.1 SUMMARY OF SAMPLING AND ANALYTICAL ACTIVITIES
The EPA's Industrial Environmental Research Laboratory
at Research Triangle Park, NC (IERL/RTP) is conducting an envi-
ronmental assessment of low- and medium-Btu gasification tech-
nology. As part of that assessment study, source test and evalu-
ation programs have been conducted at the following low-Btu
gasification facilities:
• The Wellman-Galusha facility (gasifying
anthracite coal) at the York, PA plant
of the Glen-Gery Brick, Co.,
• a Chapman facility which gasifies low-
sulfur bituminous coal, and
• the Wellman-Galusha facility (gasifying
lignite coal) at the U. S. Burea of Mines
(BOM) facility in Ft. Snelling, MN.
Results of the first two test programs listed above were used ex-
tensively in this report. Results from the test program at
the BOM facility were not available for inclusion in this report.
Non-IERL/TRP sponsored test programs have been conducted at two
other low-Btu gasification facilities.
• The Wellman-Galusha facility (gasifying low-
sulfur bituminous coal) at the National Lime
and Stone Plant near Carey, OH and
• the Riley-Morgan test facility (gasifying
bituminous and lignite coals) in Worcester,
MA.
112
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3.1.1 IERL/RTP Environmental Assessment Activities
Wellman-Galusha Facility Using Anthracite Coal -
Radian Corporation, under contract to IERL/RTP has con-
ducted environmental sampling acitivities at the Glen-Gery Brick,
Go's gasification facility located in York, PA (Ref. 10). This
facility gasifies anthracite coal to produce a low-Btu gas for
combustion in a brick kiln. The gasification system includes
three process operations:
• coal handling/conveying,
• coal gasification, and
• gas purification.
A simplified flow diagram of the system is given in Figure 3.1.1.
A brief description of the system and its 'discharge streams is
presented below.
Coal Handling/Conveying - Presized anthracite coal is
received by truck and stored outside the brick warehouse in an
uncovered coal receiving area. Coal is periodically moved from
this area to an "active" storage pile inside the warehouse near
the gasifier. At approximately 4-hour intervals, a small
front-end loader is used to feed a bucket elevator which trans-
ports the coal to a hopper atop the gasifier. A weigh belt
located at the bucket elevator discharge measures the amount of
coal delivered to the hopper.
Gasification - The gas producer tested at the Glen-Gery
facility is a single-stage, fixed-bed, atmospheric pressure
Wellman-Galusha gasifier. It is normally kept full of coal at
all times, with four coal pipes and the lower portion of the dual
compartment coal hopper providing surge capacity. About once ev-
ery four hours, slide valves at the top of the coal pipes are
closed, isolating the gasifier from the coal hopper. A slide
valve located in the partition in the coal hopper is then opened
and the lower portion of the hopper is replenished with coal.
The gasifier is both water jacketed and lined with re-
fractory brick (bottom portion). Air, saturated with water vapor
by its passage over the top of the water jacket, is introduced at
the bottom of the gasifier through a grate which also supports
the ash and coal beds. Ash is removed through this grate and ac-
cumulates in a hopper at the bottom of the gasifier. Ash is nor-
mally dumped from this hopper twice a day. During ash removal,
water is added to the ash hopper to help seal the gasifier from
the atmosphere and to slurry the ash to aid in its removal.
113
-------
BUCKET
ELEVATOR
JACKET HATER
TO CODLING TOMER
JACKET HATER
FRO* COOLING TONER
POKEHOLE
CAS
SATURATED
AIR
COM. PIPES
PRODUCT LOM-BTU GAS
RAH PRODUCT GAS
GASIFIER
HATER
COOLED
JACKET
1
CTCLONE
GASIFIER
INLET AIR
CYCLONE
OUST
SERVICE
HATER
ASH
SLURRY
NATURAL
CMS
COMBUSTION
GAS
i i
fl
TEST BURNER
KILN
FLUE
GAS
i
BRICK KILN
70-1482-2
Figure .3.1-1. Flow diagram for Glen-Gery gasification facility.
-------
Raw low-Btu gas exits the top of the gasifier at
approximately 400°C (750°F). Pokeholes located on the top of the
gasifier permit the insertion of rods used to monitor the
position and depth of the "fire" and ash zones.
Gas Purification - The gas purification operation con-
sists solely of a refractory brick-lined cyclone used to remove
particulates from the hot, raw low-Etu gas. The removed parti-
culates (cyclone dust) are disposed of with the gasifier ash.
The multimedia waste streams associated with this facil-
ity are listed in Table 3.1-1. The process and waste streams
sampled during the test program are given in Table 3.1-2 (Ref.
10).
Wellman-Galusha Gasifier Using Lignite Coal -
Radian Corporation, under their environmental assessment
program with IERL/RTP, recently sampled a Wellman-Galusha gasi-
fication test facility at the U.S. Bureau of Mines (BOM), Ft.
Snelling, Minnesota. This facility was constructed to demon-
strate the use of low-Btu gas as an acceptable fuel for an iron
palletizing kiln. The BOM plant had coal handling/conveying,
gasification, and gas purification operations along with a
start-up flare. The product gas was combusted in a pelletizing
kiln and a test burner. Figure 3.1-2 shows a flow diagram of
this gasification test facility.
Gasification - Coal is fed into the coal storage bin on
top of the Wellman-Calush gasifier where it falls through two
parallel valves at the bottom of the storage bin into the coal
feeder. Coal flows through two parallel valves at the bottom of
the coal feeder into two feed legs which drop the coal into the
top of the gasifier. The valves in the bottom of the coal stor-
age bin and coal feeder are not opened at the same time to minim-
ize loss of product gas from the gasifier through the coal feed
system.
In the 1.98 m (6.5 ft) diameter gasifier, a water cooled
agitator distributes the coal evenly as it falls from the feed
bin. Hot product gas from the bottom of the gasifier dries and
devolatilizes the coal as it moves down the gasifier to the com-
bustion zone. At the bottom of the gasifier, the coal is par-
tially combusted by moist air to "form a low-Btu product gas and
ash. The ash falls through a rotating grate, is dumped through a
valve at the bottom of the gasifier and is sent to disposal.
Steam to the gasifier is provided by passing air over hot water
in the gasifier cooling jacket before entering the bottom of the
gasifier. |
115
-------
TABLE 3.1-1. MULTIMEDIA WASTE STREAMS FROM THE
GLEN-GERY WELLMAN-GALUSHA GASIFI-
CATION FACILITY*
Operation Stream Description
Coal Handling/Conveying Gaseous Emissions
• Coal Dust
Gasification Gaseous Emissions
• Coal hopper gases
• Pokehole gases
Liquid Effluents
• Ash sluice water
Solid Wastes
• Gasifier ash
Gas Purification Solid Wastes
• Cyclone dust
Product Gas Utilization Gaseous Emissions
• Brick kiln flue gas
*Anthracite is the coal feedstock for this facility
Source: Reference 10
116
-------
TABLE 3.1-2. WASTE AND PROCESS STREAM SAMPLED AT THE
GLEN-GERY WELLMAN-GALUSHA GASIFICATION
FACILITY*
Operation Stream Description
Gasification Gaseous Emissions
• Coal hopper gases
• Pokehole gases
Liquid Effluents
• Ash sluice water
Solid Wastes
• Ash (dry)
• Ash (wet)
Process Streams
• Coal feedstock
• Gasifier jacket makeup water
• Inlet air
• Gasifier jacket cooling water
• Raw product gas
Gas Purification Solid Wastes
• Cyclone dust
Process Streams
• Product low-Btu gas
Gas Utilization Gaseous Emissions
• Test kiln flue gas
*Anthracite is the coal feedstock for this facility
Source: Reference 10
117
-------
oo
Coal
Jacket
Water
Jacket
Water
Ash Sluice
Water
-------
The hot low-Btu product gas is cooled as it passes up
through the coal in the gasifier. During start-up or banking of
the gasifier, produced gas is diverted to the start-up inciner-
ator.
Gas Purification - A cyclone is the only gas purifica-
tion process used at the BOM plant. The particulates in the
product gas fall to the bottom of the cyclone, down the cyclone
leg and into a water quench. The quenched particulates are
scrapped out of the quench trough, passed over a dewatering
screen and disposed of. Water from the quench trough flows to
the process sewer.
Test Burner - Most of the low-Btu gas produced in the
BOM Wellman-Calusha gasifier is burned in a test burner. The
test burner is a combustion chamber designed to study the burning
characteristics of low-Btu gas. The combustion gases from the
test burner are contacted with a caustic water solution for S02
removal before being discharged to the atmosphere through an ex-
haust fan. Spent caustic water solution from the combustion gas
scrubber is discharged to the process sewer from the scrubber re-
cycle tank.
Pelletizer - Low-Btu gas from the BOM Wellman-Calusha
gasifier also is combusted in a pelletizer rotary kiln. The
low-Btu gas is combusted with air heated by direct contact with
hot iron ore pellets leaving the kiln. The hot combustion gases
flow countercurrent to the iron ore pellets in the rotary kiln.
A portion of the kiln exhaust gases flow to the pelletizer grate
with the remainder going directly to the kiln exhaust system.
The kiln exhaust gas that goes to the pelletizer grate
combines with hot combustion gases from three natural gas burners
to harden the iron ore pellets before they pass to the kiln. The
hot gases from the pelletizer grate combine with the rotary kiln
exhaust gases, and are contacted with a caustic water solution
for S02 removal before being discharged through a fan to the
atmosphere. Spent caustic water solution from the scrubber is
discharged to the process sewer from the scrubbing settling tank.
Table 3.1-3 shows the multimedia waste streams associ-
ated with the BOM Wellman-Galusha gasification facility. The
streams that were sampled during the test program are given in
Table 3.1-4.
Chapman Casifier Using Low-Sulfur Bitminous Coal -
The Chapman facility produces low-Btu gas which is used
as a combustion fuel for process heaters. The facility is equip-
ped with twelve operational Chapman gasifiers. However, current
119
-------
TABLE 3.1-3. MULTIMEDIA WASTE STREAMS FROM THE BUREAU OF
MINES WELLMAN-GALUSHA GASIFICATION
FACILITY*
Operation Stream Description
Gasification Gaseous Emissions
• Coal hopper gases
• Pokehole gases
• Start-up flare gases
Liquid Effluents
• Gasifier jacket water
• Ash sluice water
Solid Wastes
• Ash
Gas Purification Liquid Effluents
• Cyclone dust quench water
Solid Wastes
• Cyclone dust
Gas Utilization Gaseous Emissions
• Test kiln scrubber exhaust gas
• Test burner scrubber exhaust gas
Liquid Effluents
• Test kiln scrubber blowdown
• Test burner scrubber blowdown
*Lignite was the coal feedstock used during the test period
120
-------
TABLE 3.1-4. WASTE AND PROCESS STREAMS SAMPLED AT
THE BOM WELLMAN-GALUSHA GASIFICA-
TION FACILITY*
Operation Stream Description
Gasification Gaseous Emissions
• Coal hopper gases
Liquid Effluents
• Ash sluice water
Solid Wastes
• Ash
Process Streams
• Lignite coal feedstock
• Service water
Gas Purification Liquid Effluents
• Cyclone dust quench water
Solid Wastes
• Cyclone dust
Process Streams
• Product low-Btu gas
Gas Utilization Gaseous Emissions
• Test burner combustion gases
*Lignite was the coal feedstock used during the test period
121
-------
fuel demands are low and can be met by operating only two gasi-
fiers at any specific time (Ref. 13).
Three basic operations are used in the gasification
plant: a) coal handling, b) gasification, and c) gas purifica-
tion. Water (process condensate) treatment is also practiced. A
block diagram of the operations used at this plant is presented
in Figure 3.1-3. This diagram also shows the major air, water,
and solid waste streams associated with each operation. In the
following text, each of these operations and their respective
waste streams are discsussed in more detail.
Coal Handling/Conveying - The coal handling operation at
the facility consists of:a) delivery and storage of presized
Virginia bituminous coal in hopper cars, b) conveying, and c)
storing this coal in the gasifier feed hoppers. No coal grind-
ing, crushing, or sizing operations are performed at the plant
site.
Gasification - The gas producers are single-stage, at-
mospheric pressure,Fixed-bed, air-blown Chapman gasifiers. The
coal feedstock enters the top of each gasifier through a rotating
feeder. Steam and air are introduced into the bottom of the gas-
ifier and pass through a grate which distributes these gases
evenly and also supports the coal bed. Ash from the gasifier is
collected in a water-sealed ash pan and removed from the unit us-
ing an ash plow. The hot raw gas exits the top of the gasifier
at 840-950 K (1050-1250°F) and enters a cyclone. Pokeholes lo-
cated on top of the gasifier are opened periodically to permit
the insertion of rods to break up any coal agglomerates which
form in the gasifier. The rods are also used to check the depth
of the bed in the gasifier.
Gas Purification - Particulate matter is removed from
the hot, raw, low-Btu gas in refractory-lined cyclones. Each
gasifier at the Chapman facility is equipped with a cyclone. The
particulates removed by the cyclones consist of devolatilized
coal dust, ash and tar entrained in the raw gas. The particu-
lates collect at the bottom of the cyclones. Pokeholes are lo-
cated on the top of each cyclone and in the inlet and outlet hot
gas ducts to permit insertion of steam lances which are used to
break up agglomerated particulates.
Hot, low-Btu gas leaving the cyclones is quenched by
spraying water into the exit lines from each cylone. Excess
quench water is collected in a liquor trap (one trap for each
gasifier/cyclone), while the cooled gas from all operating gasi-
fiers enters a collecting main. Water sprayed inside this main
122
-------
to
Coal Dust
Coal Feeder
Vent CMC*
Pokehole Liquor Trap
Vapor*
Fugitive
Separator
Vapors
Lov-Btu Cas to
"" Process Furnaces
Gaslflcr Cyclone Duct
Ash
By-Product Tars
and Oils to
Utility Boilers
02-3059-2
Figure 3.1-3. Simplified process flow diagram for the Chapman
facility showing emission streams.
Source: Ref. 13
-------
cools the gas to approximately 340 K (150°F). Tar and quench
liquor from the liquor traps and the collecting main are sent to
the liquor separator. Pitch (a lighter-than-water, tarry mater-
ial) and agglomerated particulates which accumulate in the liquor
traps are collected for periodic off-site disposal.
After the initial quenching step, the gas is cooled
further by water in two tray scrubbers which are operated in
parallel. Here, most of the tars, oils, and particulates are
scrubbed from the gas as it is cooled to approximately 330 K
(135°F).
The gases exiting the tray scrubbers are recombined and
compressed before entering a spray scrubber. In the spray
scrubber, some residual tars, oils, and particulates are removed
as the gas is further cooled to about 320 K (120°F). The efflu-
ent scrubbing liquor from both the spray and tray scrubbers is
sent to the liquor separator.
The liquor separator at the Chapman facility is a large
concrete tank (5 x 12 x 2 meters or 16 x 40 x 6 feet). Process
condensate and condensed tars and oils from the quenching/scrub-
bing steps enter at one end of the tank. A series of baffles
minimizes the turbulence caused by the incoming liquor. The tars
and oils settle to the bottom of the separator and are removed
periodically for use as an auxiliary fuel in a coal-fired boiler.
A portion of the water from the liquor separator is cooled in a
set of cooling towers before being reused in the spray scrubber.
The remainder of the water is recirculated to the other quenching
and scrubbing steps.
Water Treatment - Water treatment problems are minimized
at the Chapman gasification facility by operating the process
such that there is no net accumulation of water. This is accom-
plished by regulating the temperature and hence the water con-
tent, of the product gas. If excess water (quench liquor) ac-
cumulates, it is directed to a set of evaporators. Emissions
from this evaporation process should contain volatile materials
found in the quench liquor.
The multimedia waste streams from the Chapman facility
are listed in Table 3.1-5. The streams sampled and analyzed dur-
ing the test program are indicated in Table 3.1-6 (Ref. 13).
Criteria for selection of streams for sampling included accessi-
bility, plant operation, and potential for pollution. For ex-
ample, process neater flue gas was not sampled because the heater
was located in a restricted area. Evaporator vapors were not
sampled because no spent quench liquor was sent to the evaporator
during the test period.
124
-------
TABLE 3.1-5.
MULTIMEDIA WASTE STREAMS FROM
THE CHAPMAN GASIFICATION
FACILITY*
Operation
Stream Description
Coal Handling/Conveying
Gasification
Gas Purification
Gas Utilization
Tar By-Product Utilization
Liquid Effluent Control
Gaseous Emissions
• Coal dust
Gaseous Emissions
• Coal feeder vent gases
• Pokehole gases
Solid Wastes
• Ash
Gaseous Emissions
• Separator vent gases
• Liquor trap vapors
Liquid Effluents
• Spent quench liquor
Solid Wastes
• Cyclone dust
• Pitch from liquor traps
• Separator sludge
Process Heater Flue Gases
Tar/Coal Flue Gases
Evaporator Vapors
*Low-sulfur bituminous coal is the coal feedstock for this
facility
Source; Reference 13
125
-------
TABLE 3.1-6. WASTE AND PROCESS STREAMS SAMPLED AT THE
CHAPMAN GASIFICATION FACILITY*
Operation Stream Description
Gasification Gaseous Emissions
• Coal feeder vent gases
Solid Wastes
• Ash
Process Streams
• Raw product gas
Gas Purification Gaseous Emissions
• Separator vent gases
Solid Wastes
• Cyclone dust
Process Streams
• Product gas
• Quench liquor
• By-product tar
*Low-sulfur bituminous coal is the coal feedstock for this facility
Source: Reference 13
126
-------
Analysis of Crab Samples -
Grab samples of selected effluents from five coal gasi-
fication plants were analyzed by Radian Corporation under con-
tract to IERL/RTP (Ref. 36). All of the gasifiers were single-
stage, atmospheric pressure, fixed-bed units fired with bitumi-
nous or anthracite coals. The purpose of the study was to gain
insight into the nature of the samples that would be encountered
in an ongoing test program and also to gain experience with the
analytical methods proposed for use in the program. In general,
EPA Level 1 methodology was used in the analyses of the samples,
but some additional characterizations were also performed (Ref.
36).
3.1.2 Non-IERL/RTP Site Evaluations
Wellman-Galusha Gasifier Using Low-Sulfur Bituminous
Coal -
The Institute for Mining and Minerals Research of the
University of Kentucky has conducted tests at a Wellman-Galusha
gasifier in Carey, Ohio (Ref. 11). The gasifier was fired with
low-sulfur bituminous coal. A cyclone was used to remove parti-
culates from the product gas, but not quench system was used.
The purpose of the tests was to collect process data and to quan-
tify the product gas compositon to aid in the design of gasifier
and gas cleanup systems.
The coal feed, gasifier ash, cyclone dust, and product
gas streams were measured and analyzed. Tars were not measured
or analyzed. Some trace components in the gas phase (l^S,
NH3, HCN) were measured, but COS was not (Ref. 11).
Riley Morgan Gasifier Using Various Coals -
The Riley Morgan gasifier, like the Wellman-Galusha, is
a single-stage, atmospheric-pressure, fixed-bed gasifier. Riley
Stoker has conducted various test in a pilot-scale Riley Morgan
gasifier (Refs. 9, 15, 37, 38). Coals tested include"anthracite;
low-sulfur, high volatile A bituminous; medium volatile bitumi-
nous; and North Dakota lignite. Trace components in the product
low-Btu gas stream (H2S, COS, NH3, HCN) were measured in some
of the tests conducted. One set of tests investigated the forma-
tion of NH3 in the product gas and the NOX emissions obtained
from the combustion of low-Btu gas. Other tests have considered
control methods for removing tar aerosols from the product gas
and the feasibility of using lignite as a coal feedstock.
127
-------
3.2 INPUT MATERIALS
Raw materials required for the production and purifica-
tion of 17.6 MW (60 x 106 Btu/hr) of lov-Btu gas from the four
coal feedstocks were estimated from the test data discussed in
Section 3.1 and other data on H2S removal processes. Extensive
use was made of the test results obtained from the Glen-Gery
Wellman-Galsuha facility (using anthracite) and the Chapman
facility (using low-sulfur bituminous coal). The quantities and
characteristics of the raw materials for coal preparation and
handling, coal gasification, and gas purification are discussed
in this section.
3.2.1 Coal Preparation and Handling
Presized coal is the only raw material required for coal
preparation.
3.2.2 Coal Gasification
The major raw material for coal gasification is the coal
feed. Steam, air, and possibly ash removal sluice water are also
required. The quantities of raw materials required for produc-
tion of 17.6 MW (60 x 10° Btu/hr) of raw product gas are pre-
sented in Table 3.2-1.
Coal -
* '
Gasification of four differesnt types of coal with dif-
ferent compositions was consisdered in order to study the effects
of various coal properties on multimedia emissions and their con-
trol. The four coal types consisdered were anthracite, low-
sulfur bituminous, high-sulfur bituminous, and lignite. Anthra-
cite and low-sulfur bituminous coals have been used in Wellman-
Calusha gasifiers (Refs. 10, 11). High-sulfur bituminous coal
should have gasification characteristics similar to those of
low-sulfur bituminous, but will produce more sulfur compounds in
the product gas and the gasification by-products. Lignite has
been gasified in a thin-bed Riley Morgan gasifier (Ref. 9) and
has undergone limited testing in a Wellman-Galusha gasifier.
Proximate and ultimate analyses of the four coals con-
sidered in this study are given in Table 3.2-2. The composition
for high-sulfur bituminous coal is a "representative" composition
128
-------
TABLE 3.2-1. INPUT MATERIAL REQUIREMENTS FOR THE GASIFICATION
OPERATION IN WELLMAN-GALUSHA SYSTEMS
PRODUCING 17.6 MW OF LOW-BTU GASa
Coal Feedstock Characteristics
Input Material
Coal kg/s (Ib/hr)
Steamb kg/s (Ib/hr)
Air kg/s (Ib/hr)
Temperature of Air/
Steam to the
Gasifier °K (°F)
Low-Sulfur
Bituminous
0.81 (6,410)
0.22 (1,750)
2.61 (20,710)
323 (122)
High-Sulfur
Bituminous
0.88 (7,000)
0.39 (3,090)
2.05 (16,200)
336 (147)
Anthracite
0.73 (5,800)
0.43 (3,400)
2.74 (21,700)
333 (140)
Lignite
1.46 (11,570)
0.24 (1,920)
1.99 (15,740)
330 (134)
Input material requirements were estimated using material balances obtained from environmental test
data. For a low-Btu gas production rate of 87.9 MW (300 x 106 Btu/hr), all quantities would be
multiplied by a factor of 5.
Obtained by passing the inlet air stream over the gasifier cooling jacket water.
-------
TABLE 3.2-2. COAL COMPOSITION DATA
Low-Sulfura
Bituminous
High Sulfurc
Bituminous
Anthracite0 Lignited
Proximate Analysis
(weight %)
Moisture 2.5
Volatile Matter 36.7
Fixed Carbon 57.9
Ash 2.9
Ultimate Analysis
(weight %)
Carbon 79.1
Hydrogen 5.6
Nitrogen 1.6
Oxygen 7.6
Sulfur 0.7
Ash 2.9
Moisture 2.5
Heating Value
(as received, 33.2
MJ/kg)
(as received, 14,300
Btu/lb)
6.1
34.5
51.0
8.4
67.9
4.8
2.1
6.8
3.9
8.4
6.1
29.2
12,600
0.94
5.15
82.24
11.67
81.2
2.1
0.8
2.6
0.6
11.7
0.9
29.9
12,900
35.0
27.8
28.9
8.3
41.5
2.9
1.0
10.5
0.9
8.3
35.0
16.0
6,900
Coal used at a Wellman-Galusha gasifier (Ref. 11)
"Representative" composition (Ref. 39)
CGoal used at a Wellman-Galusha gasifier (Ref. 10)
The lignite composition chosen for this study is that of a lignite tested
in a Riley Morgan gasifier (Ref. 9) and may not be representative of lignites
that may be used in such gasifiers in the future. An analysis of 23 samples
of North Dakota lignite has indicated an "average" sulfur composition of 0.6%
and ash composition of 6.2% (Ref. 40). Ranges of these values were 0.2-1.4%
for sulfur, and 4.4-8.0% for ash. The selected values of 0.9% for sulfur
and 8.3% for ash may indicate more severe environmental impacts from gasifica-
tion of lignite than may actually be encountered.
130
-------
of this type of coal. The compositions for the low-sulfur
bituminous, anthracite, and lignite coals are compositions of
coals used in the gasification tests discussed in Section 3.1
(Refs. 9, 10, 11, 39).
In addition to the major elements reported in the ul-
timate compositions, coals contain various elements in trace
amounts. These "trace elements" in the coal feedstock will ul-
timately be contained in the products, by-products, or waste
products of the gasification or purification operations. Trace
element concentrations in coals from different areas and from
different locations in the same coal seam can be quite variable.
In general, the elemental concentrations have been reported to be
highest in coals from the Appalachian Basin (eastern coals), low-
est in western coals and intermediate in coals from the Illinois
Basin (Ref. 41). Thus, it is difficult to predict a trace ele-
ment concentration for a certain coal. Trace element con-
centrations reported in a study by the Illinois State Geological
Survey (Ref. 41) are given in Table 3.2-3, along with data from
the U.S. Geological Survey (Ref. 42).
Steam -
Steam requirements (obtained from the gasifier cooling
jacket water) for production of 17.6 MW (60 x 106 Btu/hr) of
product gas from each coal feedstock are given in Table 3.2-1.
These amounts are variable depending largely on the temperature
control required to prevent ash slagging. Higher steam rates are
required for coals with low ash deformation temperatures.
Air -
Air requirements for production of 17.6 MW (60 x 106
Btu/hr) of product gas from each coal feedstock are given in
Table 3.2-1. The amount of air required depends on the carbon
content of the coal.
Ash Removal Sluice Water -
Small amounts of water will be required to remove ash
from the gasifier. The amount of water used is quite variable.
At the Glen-Gery Wellman-Galusha gasifier, the amount of water
used was roughly 4500 to 6800 I/day (1200 to 1800 gallons per
day) (Ref. 10).
131
-------
TABLE 3.2-3.
REPORTED AVERAGE TRACE ELEMENT
COMPOSITIONS OF U.S. COALS*
Element
Be
Se
Cd
Hg
As
Pb
B
Co
Cr
Cu
Ge
Mn
Mo
Ni
P
Sb
Sn
U
V
Zn
Ba
Source:
Illinois
Coal
1.6
2.0
0.59
0.16
7.4
15.0
98.0
6.0
16.0
13.0
4.8
40.0
6.2
19.0
45.0
0.81
0.94
1.3
29.0
87.0
75.0
Ref. 41
Eastern
U.S.
Coal
1.1
3.4
0.19
0.17
15.0
4.7
28.0
7.6
18.0
16.0
0.87
12.0
1.8
14.0
81.0
1.1
0.97
1.3
35.0
19.0
170.0
Ref. 41
Western
U.S.
Coal
0.35
1.3
0.15
0.07
1.5
2.6
48.0
1.5
8.1
8.5
0.5
28.0
0.59
4.4
82.0
0.45
0.43
0.99
12.0
5.0
430.0
Ref. 41
Pennsylvania
Anthracite
1.0
2.7
0.19
0.11
4.0
7.5
10.0
5.0
20.0
21.5
NR
4.2
1.5t
15.0
NR
0.6
NR
1.2
20. Ot
10.0
70.0
Ref. 42
Lignite &
Subbituminous
Coal from
Northern
Great Plains
0.3
0.5
0.2
0.06
2.0
4.3
70.0
1.5
3.0
7.4
NR
34.0
1.5t
2.0
NR
0.4
NR
0.7
7.0t
12.8
300.0
Ref. 42
Bituminous
Coal from
Appalachian
Region
2.0
3.5
0.3
0.14
11.0
10.9
20.0
5.0
15.0
16.0
NR
200.0
2. CM-
IS. 0
NR
0.8
NR
1.0
20. Ot
12.8
70.0
Ref. 42
All concentrations are in ppm by weight, and are geometric means of a number
of samples.
Mo and V values for these coals may be low due to volatilization in ashing.
NR - Not reported in summary tables.
132
-------
3.2.3 Gas Purification
Required input materials to the gas purification oper-
ation are make-up quench/cooling water and make-up sorbents or
reactants for sulfur removal processes (Stretford or Monoethanol-
amine).
Make-Up Quench/Cooling Water -
Quenching and cooling water is used to scrub tars and
oils from the raw gas and to cool the gas. In general, make-up
water will be necessary only if the amount of water vapor in the
raw product gas is less than the water vapor contained in the
cooled gas. Other factors that will affect the make-up water re-
quirements include blowdown frequency, water leaving with the by-
product tar, evaporated water from separators, evaporators and
oxidizers. For the Wellman-Galusha systems examined in this
report, only gasification of anthracite and low-sulfur bituminous
coals require make-up water. For producing 17.6 MW of low-Btu
gas, these requirements are:
• Anthracite coal - 0.09 kg/sec (700 Ib/hr), and
• Low-sulfur bituminous coal - 0.08 kg/sec (650 Ib/hr).
Stretford Sulfur Removal Process -
Make-up chemical requirements for the Stretford process
were estimated using the assumptions described in the Appendix.
These requirements are summarized in Table 3.2-4.
Since the Stretford process uses a regenerable scrub-
bing solution, the make-up chemicals are only required to replace
those lost in the sulfur cake and solution blowdown. Loss in the
sulfur cake is generally small, since the cake is washed to re-
cover most of the Stretford solution.
The blowdown is necessary to remove nonregenerable com-
pounds formed by absorption of HCN from the feed gas (forming
thiocyanates) and by oxidation of HS~ to thiosulfates. These
compounds must be removed, either in the sulfur cake or in a con-
tinuous or batch blowdown stream. Batch blowdowns may be carried
out when the solution reaches a salts concentration of 40%. Con-
tinuous blowdown typically maintains the salts concentration at
20 to 25%. The major factors affecting the size of the blowdown
(and hence the chemical loss) are the HCN content of the feed gas
and the rate of thiosulfate formation. An increase in either
quantity necessitates an increased purge.
Several factors affect the rate of thiosulfate forma-
tion. The rate increases with increasing pH, increasing temper-
ature, and increasing oxygen content in the feed gas.
133
-------
TABLE 3.2-4. INPUT MATERIAL REQUIREMENTS FOR THE STRETFORD
SULFUR REMOVAL PROCESS
Gh&vLc&l Mafce-Qf Low-Sulfur
g/sec (lb/hr)* Bituminous
Anthraqulone 0.034 (0.27)
Disulfonic Acid
Sodim Metavanadate 0.023 (0.18)
Sodium Carbonate 0.028 (0.22)
Sodlun Bicarbonate 0.126 (1.00)
Bthylenediaalne 0.014 (0.11)
Tetraacetlc Acid (EDTA)
Iron 0.0003 (0.002)
High-Sulfur
Bituminous
0.076 (0.60)
0.050 (0.40)
0.040 (0.32)
0.189 (1.50)
0.020 (0.16)
0.0004 (0.003)
Anthracite Lignite
0.018 (0.14) 0.037 (0.29)
0.012 (0.094) 0.024 (0.19)
0.014 (0.11) 0.029 (0.23)
0.068 (0.54) 0.139 (1.10)
0.007 (0.057) 0.015 (0.12)
0.0001 (0.001) 0.0003 (0.002)
Basis: (See Appendix for discussion and references) .
treatment of 17.6 J» (60 x 106 Btu/hr) of
Chemical concentrations
NaHC03: 6.3N
Na2OC3: 0.1N
ADA: 1.2 times stoichiometric
NaV03: 1.2 times stoichiometric
Iron: 50 ppm
EDTA 2700 ppm
gas
HS~ loading: 750 ppm for high sulfur bituminous
500 ppm for others
Total salts concentration in recirculatlng Stretford Solution: 25%
Sulfur cake washing efficiency: 66% of original chemicals recovered with one displacement
wash; 96% with three washes
-------
Insufficient hold time in the delay tank allows HS~ to be car-
ried over into the oxidizer, which also results in increased
thiosulfate formation. By proper operation, the thiosulfate
formation can be limited to less than one percent of the sulfur
in the feed gas (Ref. 16).
Other factors affecting the size of the blowdown and
chemical requirements are the total salts concentration of the
purge and the concentration of the Stretford chemicals in the
purge. A decrease in the allowable total salts concentration re-
sults in an increase in the purge. For a given total salts con-
centration, an increase in the concentration of the Stretford
chemicals would also result in increased chemical losses. The
type of effluent treatment for the blowdown also affects the
chemical make-up rate. Certain treatment processes recover the
chemicals for recycle to the system, thus reducing make-up rates.
Monoethanolamine (MEA) Acid Gas Removal Process -
Raw materials for the absorption of acid gases by MEA
(or other ethanolamines) mainly include water and sorbent (MEA).
Depending on the operating circumstances, small quantities of
chemicals may be added to inhibit foaming and reduce the accumu-
lation of degradation products. Make-up chemicals for MEA solu-
tions used to purify product gases from high-sulfur coals are
summarized in Table 3.2-5.
The quantities of make-up chemicals for MEA absorption
are dependent on losses due to entrainment, vaporization, and
solution degradation. Entrainment losses can be minimized by use
of efficient mist eliminators and application of foam inhibitors.
Vapor losses are normally minor compared to losses due to the
formation of degradation products.
The most serious solution loss is caused by chemical de-
gradation of the amine sorbent. All ethanolamines are subject to
oxidative degradation with the formation of dithiocarbamates,
thioureas, thiosulfuric acid, formic acid, and other decompo-
sition products. Oxidation inhibitors may be beneficial in a-
voiding these degradation products. Certain gas impurities react
irreversibly with the amines. These compounds include carboxylic
acids, sulfur compounds such as COS and CS2, hydrochloric acid,
and hydrogen cyanide. Some irreversible reactions between C02
and MEA also occur (Ref. 16).
Quantitative data on the degradation of MEA solutions
are mostly unavailable. The reported chemical make-up may under-'
estimate the actual requirement. Water make-up is assumed to be
135
-------
MAKE-]
TABLE 3.2-5. ESTIMATED MAKE-UP CHEMICAL REQUIREMENTS
FOR MEA PROCESS3
Desired Low-Btu Gas
"Clean" Industrial Fuel GasC
Chemical
Water
MEA
Quantity
g/s (Ib/hr)
3.1 (25)
1.5 (12)
"Very Clean" Gasd Water 3.8 (30)
MEA 1.4 (11)
Gas is produced from gasification of 3.9% sulfur coal; 17.6 MW of gas is
produced.
Chemicals will be added periodically, depending on the schedule for batch
reclaiming. The estimated requirements include only the requirements due
to losses from vaporization, and degradation by COS and HCN. The require-
ments have been estimated by assuming that nearly all of the HCN is the
raw gas and 20% of the COS form nonregenerable compounds. The reported
values are average requirements.
°Gas is cleaned to limit SO2 in the combustion products to 86 ng per Joule of
low-Btu gas (0.2 Ib per 10 Btu).
Gas is cleaned to 4 ppmv H2S.
136
-------
dependent only on vaporization losses, although some water is
needed for the reclaiming of degraded solutions. Degradation
losses are discussed further in Section 3.7.
3.3 PROCESS STREAMS
Process streams from the coal gasification and gas puri-
fication operations are discussed in this section. These streams
are not emission streams, but may have potential to result in em-
issions from leaks in the system or occasional blowdowns.
3.3.1. Coal Preparation and Handling
Because presized coal is purchased for use in the gasi-
fier, the only process stream from coal handling is the coal
feedstock.
3.3.2 Coal Gasification
Process streams from the coal gasification operation in-
clude the raw product gas and the water circulated through the
gasifier cooling jacket.
Raw Product Gas -
Compositions, flow rates and temperatures of the raw low-
Btu gas produced from each of the four coal feedstocks are given
in Table 3.3-1. The hot, raw gases from bituminous and lignite
coals have high dust and tar loadings, and the gases from high-
sulfur bituminous and lignite coals have high sulfur contents.
The gases also contain trace elements volatilized from the coal.
These will be discussed in Section 3.4. The sulfur and nitrogen
compounds in the gas will also be discussed in Section 3.4.
Jacket Water -
Concentrations of trace elements measured in the service
water and the recirculating gasifier jacket water at the Glen-Gery
Wellman-Galusha facility are given in Table 3.3-2 (Ref. 10). The
concentrations of most of the elements are very similar for the
two streams, but those in the jacket water are generally slightly
higher. This is expected, since some of the water circulated
through the jacket is evaporated and the dissolved species are
thus somewhat concentrated.
3.3.3 Gas Purification
Process streams in the gas purification section include
the quenched/cooled product gas and the recirculated quench water.
137
-------
TABLE 3.3-1.
COMPOSITIONS OF RAW LOW-BTU GAS EXITING
A WELLMAN-GALUSHA GASIFIER
Component (vol %, dry)
CO
H2
CO 2
N2
CM*
02
Component (ppmv, dry)
C2Hi»
C2H6
C3H6
C3H8
H2S
COS
CS2
SO 2
NH3
HCN
Ar
HHV, MJ/Nm3
(Btu/scf), dry
Water Content;
mol/mole dry gas
Dust Loading, g/Nm3
(gr/scf)
Tar Loading, g/Nm3
(gr/scf)
Temperature, °K
(°F)
Flow Rate, Nm3/sec
(scfm)
Low-Sulfur
Bituminous
25.9
12.5
4.9
53.4
2.1
ND
2700
1000
ND
ND
1000
100
ND
20
300
100
6000
5.09
(144.5)
0.058
1.8
(0.75)
39
(16.0)
840
(1050)
3.1
(7000)
High-Sulfur
Bituminous"
28.83
14.81
3.42
48.90
2.72
ND
2700
1000
ND
ND
8400-8600
100-300
ND
20
300
100
ND
5.90
(167.6)
0.140
2.2
(0.91)
40
(16.5)
640
(700)
2.9
(6420)
Anthracite0 Lignited
25.45
16.31
5.51
51.48
0.23
0.91
\ !
f X
J40
810
93
1
21
195
43
ND
4.81
(136.5)
0.064
0.37
(0.15)
-
— •
700
(800)
3.4
(7670)
30.60
16.85
3.89
46.55
1.30
ND
3880
858
2530
238
2490
110
ND
ND
300
100
6000
5.81
(165.0)
0.300
1.9
(0.80)
36
(15)
420
(300)
3.4
(7630)
ND - not detected
aBased on data in Ref. 11
Based on data in Ref. 39
CBased on data in Ref. 10
iased on data in Ref. 9
138
-------
TABLE 3.3-2. CONCENTRATIONS OF TRACE ELEMENTS IN JACKET AND
SERVICE WATER AT THE GLEN-GERY WELLMAN-GALUSHA
GASIFIERa
Element
Uranium
Thorium
Bismuth
Lead
Thallium
Mercury
Gold
Platinum
Iridium
Osmium
Rhenium
Tungsten
Tantalum
Hafnium
Lutetium
Ytterbium
Thulium
Erbium
Holmium
Dysprosium
Terbium
Gadolinium
Europium
Samarium
Neodymium
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Tellurium
Antimony
Tin
Indium
Cadmium
Silver
Palladium
Rhodium
Jacket
Cone. Service
(yg/mJO (yg/mi,)
0.02 0.008
0.2 0.07
NR NR
£0.003
0.003
0.007 0.001
0.01 0.002
0.5 0.2
<0.001
0.06 0.001
0.07
0.005
STD STD
0.004 0.001
0.004 0.004
Element
Ruthenium
Molybdenum
Niobium
Zirconium
Yttrium
Strontium
Tunifium
Bromine
Selenium
Arsenic
Germanium
Gallium
Zinc
Copper
Nickel
Cobalt
Iron
Manganese
Chromium
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Oxygen
Nitrogen
Carbon
Boron
Beryllium
Lithium
Hydrogen
Jacket
Cone.
(yg/mfc)
0.01
0.02
0.008
0.004
0.5
0.02
0.3
0.02
0.04
0.007
0.004
3
0.07
0.01
0.004
9 "
0.3
0.04
0.01
<0.03
<0.001
MC
MC
3
>8
0.9
MC
>1
MC
3
&3
NR
NR
NR
0.005
0.001
NR
Service
(yg/mJO
0.004
0.001
0.001
0.1
0.003
0.03
gO. 003
0.006
<0.081
0.8
0.05
0.02
<0.001
*0.2
0.02
£0.02
0.002
SO. 02
go. ooi
MC
MC
0.5
1
0.2
0.6
0.01
MC
>2
M).3
NR
NR
NR
0.002
0.001
NR
element concentrations will vary significantly from site to site.
Source: Reference 10
139
-------
These gaseous and liquid streams will be discussed in the follow-
ing text.
Gas Streams -
The quenched/cooled low-Btu gas streams are essentially
unchanged in composition from the raw low-Btu gas with the excep-
tion of dust and tar loadings and water content. About 60-80 per-
cent of the dust is removed in the hot cyclone. In the systems
requiring quenching/cooling and electrostatic precipitation, es-
sentially all of the residual dust is removed. For the bitumi-
nous and lignite coals about 60 to 70 percent of the tars and oils
are removed in the quenching/cooling system, with about 99 percent
of the residual tars and oils removed in an ESP. Some of the
NH3 and HCN in the gas is removed in the quenching steps, as
indicated by the high levels of ammonia (or ammonium ion) and
cyanide in the quench liquor at the Chapman gasifier (Ref. 13).
However, data quantifying removal of these compounds were not
available. Removal of these compounds in the quench system should
be measured in future tests. These intermediate product gas
streams may also contain various trace elements. These will be
discussed in Section 3.4.
Liquid Stream -
Large quantities of water must be circulated to cool the
hot gas down from the gasifier exit temperature to a temperature
low enough for tar removal and for treatment in the sulfur removal
process. This recirculating quench liquor will absorb various
compounds from the gas as well as particulates and tars in the
gas. No data were available on quench liquor from a Welltnan-
Galusha gasification system. However, quench liquor was sampled
at a Chapman gasification facility (Ref. 13). Water quality para-
meters determined for the quench liquor are given in Table 3.3-3
(Ref. 13). Concentrations of various organic compounds and trace
elements in the liquor are given in Tables 3.3-4 and 3.3-5, re-
spectively (Ref. 43).
3.4 TOXIC SUBSTANCES IN PRODUCT AND BY-PRODUCT
The product gas and by-product tar and oil will contain
various compounds that are potential pollutants or toxic sub-
stances. These will be discussed in this section.
3.4.1 Coal Gasification
Unquenched product gas from the cyclone will be the final
product for two of the cases considered in this study - the use of
low-sulfur bituminous and anthracite coals to produce a gas whose
140
-------
TABLE 3.3-3. WATER QUALITY PARAMETERS
OF QUENCH LIQUOR AT CHAPMAN GASIFIER
Parameter Value
Color (Pt-Co units) 5,000
Odor (Threshold No.) 4,000
pH 7.66
IDS (ppm) 6,300
TSS (ppm) 144
COD (ppm) 22,200
BOD (ppm) 6,530
DO (ppm) ND
Conductivity ( mhos) 32,000
Hardness ND
Alkalinity (as CaC03) 2,140
ND: Not determined due to interference in the analysis
Source: Ref. 13
141
-------
TABLE 3.3-4.
ORGANIC COMPOUNDS FOUND IN A CHAPMAN
GASIFICATION FACILITY QUENCH LIQUOR
ro
MEG
Category Compound Category
Ho. Organic Compound
1 Alaphatlc Hydrocarbons
>C* Alkanea (Honane, Heptane)
tfethyleyclohexane
5 Alcohols
>Ct Alkylalcohols
>ds Alkylalcohols
8 Carboxylic Acids and Their
Derivitlves
Phthallc acid
Phthalates
Adlpates
10 Amines
Aniline
Amino toluenes
C2 -Alkylaniline
Hethylpyrrollne
15 Benzene, Substituted Benzene
Hydrocarbons
Indene
Methylindene
18 Phenols
Phenol
Anisoles
C2 -Alkylphenols
Cj -Alkylphenols
Estimated
Stream
Concentration
(VK/l)
1 x 10s
400
1.2 x 10*
5.4 x 10*
4 x 10'
2.2 x 10"
1.9 x 10"
3 x 10'
3.8 x 10'
1.0 x 10*
1.3 x 10s
8.2 x 10*
3.4 x 10'
7.2 x 10s
1.3 x 10*
3.7 x 10s
5.0 x 10"
MEG
Category Compound Category
No. Organic Compound
21 Fused Aromatic Hydrocarbons and
Their Derivitlves
Naphthalene
Hethylnaphthalene
Acenaphthylene
Benzoperylene
23 Heterocyclic Nitrogen Compounds
Nethylpyrldine
Cj -Alkylpyridlne
Cj -Alkylpyridlne
Indole
Methyllndole
Quinoline
Methylquinollne
Cj -Alkylqulnoline
24 Heterocyclic Oxygen Compounds
Methylidioxolone
Estimated
Stream
Concentration
(pg/*.)
1.7 x 10*
5.1 x 10'
4.1 x 101
3.0 x 10"
3.0 x 10'
3.8 x 10'
1.0 x 101
5.3 x 10*
8.9 x 10'
3.1 x 10'
1.8 x 10s
2.4 x 10s
5.0 x 10'
Source: Ref. 43
MEG: Multimedia Environmental Goals
-------
TABLE 3.3-5.
TRACE ELEMENT CONCENTRATIONS FOUND IN A CHAPMAN
GASIFICATION FACILITY QUENCH LIQUOR
MEG
Category
No.
(27)
(29)
(30)
(31)
(33)
(34)
(35)
(36)
(37)
(43)
(45)
(48)
(40)
(50)
(53)
(54)
(56)
(57)
(58)
(59)
(60)
Element
Lithium
Potassium
Rubidium
Cesium
Magnesium
Calcium
Strontium
Barium
Boron
Silicon
Tin
Phosphorous
Arsenic
Antimony
Sulfur
Selenium
Fluorine
Chlorine
Bromine
Iodine
Scandium
Concentration
(pg/Jl)
3
2 x 10"
10
1
2 x 103
2 x 10"
80
300
9 x 103
2 x 103
30
2 x 10"
800
70
8 x 103
2 x 103
2 x 103
200
300
300
2
MEG
Category
No.
(61)
(62)
(63)
(66)
(70)
(72)
(78)
(79)
(82)
(83)
(84)
(85)
Element
Yttrium
Titanium
Zirconium
Niobium
Tungsten
Iron
Copper
Silver
Cadmium
Mercury*
Lanthanum
Cerium
Concentration
5
100
10
8
10
1 x 103
10
2
5
< 0.3
7
3
Source: Ref. 43
* Mercury was analyzed by flameless atomic absorption spectrometry
MEG: Multimedia Environmental Goals
NOTE: Elements analyzed by SSMS that are not listed, had a concentration
-------
combustion product have less than 520 ng S02/J (1.2 Ib
802/10^ Etu) of low-Btu gas. As discussed in Section 3.3.3,
this gas will have essentially the same composition and flow rate
as the raw gas from the gasifier, given in Table 3.3-1, but will
have only about 20 to 40 percent of the original dust loading.
This gas stream will contain several potential pollutants
including sulfur compounds, nitrogen compounds, metal carbonyls
various trace elements, and possibly hazardous organic compounds.
The predominant sulfur species is H2S, but organic sul-
fur (such as COS and CS2> is also present along with small
amounts of S02 and free sulfur. Data on COS formation from
gasification of anthracite, low-sulfur bituminous, and lignite
coals are available from the test programs described previously
(Refs. 9, 10, 13, 15). No data were available on COS formation
from gasification of high-sulfur coals in at atmospheric pressure,
fixed-bed gasifier. Research Triangle Institute (RTI) (Ref. 44)
has reported very low (less than 100 ppmv) COS concentrations from
the gasification of high-sulfur coal (Illinois No. 6) and char in
a pressurized (1.52 MPa) gasifier. However, very high steam rates
were used in the RTI tests. According to the hydrolysis reaction
of H2S and COS (Equation 3-1),
H2S + C02 t COS + H20 (3-1)
it appears that high steam rates would suppress formation of COS.
A value of 315 ppmv for COS was reported for the Morgan-
town Energy Research Center pilot gasifier (Ref. 44). From
consideration of the equilibrium of Equation 3-1 and from the
H2S/COS ratios reported in Riley Stoker's tests on low-sulfur
bituminous and lignite coals (Refs. 9, 15), an t^S/COS ratio of
about 25 (COS concentration of about 300 ppmv) was estimated for
the high-sulfur bituminous coal. The actual COS concentration,
however, could be much higher than this. Actual data on COS
production from high-sulfur coal under the proper operating condi-
tions are needed.
During gasification, a portion of the coal-bound nitrogen
forms ammonia and hydrogen cyanide. Smaller amounts of coal ni-
trogen are found as thiocyanates and certain organic compounds.
These compounds could form NOX when the low-Btu gas is burned.
Experimental data on the formation of NH3 and HCN are
available from tests in Wellman-Galusha, Chapman, and Riley-Morgan
gasifiers. These data are for coals with nitrogen contents of
about 1 to 2 percent. Steam rates of 0.5 to 0.9 kg steam/kg coal
were used. Higher steam rates favor the formation of NH^ by
144
-------
increasing the hydrogen partial pressure in the gasifier. The
time-temperature history of the coal in the gasifier' also has an
impact on NHq formation because it affects the amount and
characteristics of nitrogen intermediates formed in the gasifier.
Data from the Glen-Cery Wellman-Calusha gasifier (anthra-
cite coal feedstock) show IIK^ an^ ^CN concentrations of about
200 ppmv and 40 ppmv, respectively. The coal was gasified with a
steam input of about 0.9 kg steam/kg coal. The coal nitrogen con-
tent was about 0.8 percent (Ref. 10).
Data from a Chapman gasifier using bituminous coal shows
NH3 and HCN concentrations of about 400 ppmv and 80 ppmv respec-
tively. The coal was gasified with a steam input of about 0.5 kg
steam/kg coal. The coal nitrogen content was 1,9 percent (Ref.
13).
Data for a Riley-Morgan gasifier are available for both
high and medium volatile bituminous coals. Ammonia concentrations
for the high and medium volatile coals were 190 and 113 ppmv, re-
spectively. Hydrogen cyanide concentrations were 113 and 129
ppmv, respectively. The steam rate for the high volatile coal was
0.6 kg steam/kg coal (Ref. 15).
The NH3 and HCN contents in the raw gases from coal ex-
amined in this study are estimated based on the above data. The
contents are shown in Table 3.3-1.
From the dust loadings shown in Table 3.3-1 it appears
that particulate emissions from combustion of the raw product gas
from low sulfur bituminous coal would be high. However, most of
the dust is carbon, which will be burned along with the gas so
that the actual particulate emissions fromm combustion of the gas
should be well below 43 ng/J (0.1 lb/106 Btu). The dust loading
in the gas from anthracite coal is lower than that from bitumi-
nous. Since it is also mostly carbon, particulate emissions from
combustion of the gas should be less than 13 ng/J (0.03 lb/ 106
Btu).
Raw, low-Etu gas will also contain trace elements
volatilized from the coal. Few data are available on these trace
element levels. Trace element concentrations measured (by spark
source mass spectroscopy or SSMS) in the product gas from the
Clen-Cery Wellman-Galusha gasifier using anthracite are given in
Table 3.4-1 (Ref. 10). These data indicate that trace element
levels in the actual vapor phase are very low. Most of the trace
elements in the product gas are contained in the particulates re-
maining in the gas after the cyclone. This is supported by
measurements of the concentration of selected trace elements by
145
-------
TABLE 3.4-1. TRACE ELEMENT CONCENTRATION (BY SSMS) IN THE
PRODUCT GAS FROM A WELLMAN-GALUSHA GASIFIER
USING ANTHRACITE COAL
Partlculatea (UK/t)
>3y <3y
Al
Sb
Al
Ba
Be
Bi
B
Br
Cd
Ca
• Ce
CB
Cl
Cr
Co
Cu
Dy
Er
Eu
r
Gd
Ga
Ce
Au
Hf
Ho
In
I
Ir
Fe
La
Pb
Li
Lu
Mg
Mb
Hg
>30
200
>900
600
0.4
40
0.6
J
20
>900
40
It
>900
90
30
200
2
<0.9
1.9
•200
2
>900
0.9
<0.2
0.9
0.9
Std
0.9
-
>900
30
>900
70
0.3
>900
300
HR
>4000
2000
2000
>9000
2
700
300
90
300
>9000
300
9
>9000
600
60
500
-
6.0
"900
9
4000
20
Std
4
-
19000
200
19000
50
-
>9000
400
NX
Gaaes
(Ug/Bs @ 25 °C)
Mo
2 Nd
<50 Ni
Nb
Os
Pd
P
Ft
10 K
* Pr
Re
Rh
* Kb
6 Ru
SB
10 Sc
Se
Si
Ag
Na
Sr
10 S
Ta
Te
Tb
Tl
Th
TB
Sn
Ti
V
0
50 V
Yb
Y
3 Zn
Zr
Particulates (pg/g) Gaaea
>3y
90
30
Int
30
>800
>300
6
<0.1
30
9
4
80
20
40
>90
200
>200
<0.9
20
0.7
90
9
<0.1
200
>900
9
6
30
0.9
20
>900
40
<3ti (ug/n 9 25 *C)
600 i
40
200 20
50
3000 10
>9000 *
40
70 7
30
40
500 20
2000
300
>9000
600
>9000 *
<30
3
<20
<80
3000
3000 800
90
<90
300 0.8
90
>9000 40
600
HE - not reported
lot - int«rf«r«nee
Std - itandard
El«s«it« not raport«d
P«rticul«t«i >3w, <0.093 u«/g
<3u, 9000 ug/»!) in the *a*ple and the blank.
Source: Reference 10
furnace la a quarts
•ajor component
146
-------
atomic absorption. For antimony (Sb), these measurements
indicated that essentially no Sb remained in the vapor phase,
while over 80 percent of the Sb in the coal was contained in the
particulates remaining in the gas after the cyclone and about 10
to 11 percent was contained in the dust collected in the cyclone.
For arsenic, less than 5 percent was found in the vapor phase,
with more than 45 percent in the particulates in the product gas
and 2 to 6 percent in the cyclone dust.
Because of the scarcity of measured data on trace ele-
ments in low-Btu gases, a computer equilibrium model was used to
predict trace element volatilization. This model (discussed in
more detail in the Appendix) predicts the equilibrium distribution
of trace elements into various species at a given temperature and
pressure. The results from using this model to predict gasifier
exit compositions are presented in Table 3.4-2. This table gives
the predicted trace species and the predicted degree of
volatilization of the elements. As shown, the following elements
were predicted to be completely volatilized for all four coals:
Se, Hg, As, B, P, and Sb. The elements Be, Co, Cr, Cu, Mn, Ni, U,
V, Zn, and Ba were not predicted to volatilize for any of the
coals. Five other elements (Cd, Ge, Mo, Sn and Pb) were predicted
to volatilize completely for the low sulfur bituminous coal (which
had the highest gas temperature) but varied for the other coals
depending on the gas temperature.
It is difficult to accurately compare these predictions
to the SSMS measurements in Table 3.4-1. The SSMS measurements
indicate a rough distribution of the trace elements among the gas
phase, particulates in the gas phase, cyclone dust, and gasifier
ash. According to these rough distributions, Cd, As, Sb, Sn, and
Se were found mostly in the particulates in the product gas
stream. It appears that these elements volatilize in the gasifier
and then recondense on the particulates. The elements Pb, P, Zn,
and Ba had uncertain distributions, with concentrations of two or
more streams given as "major components," (greater than 1000 ppm
in sample tested). One element (boron) was predicted to be com-
pletely volatilized, but apparently is not. The elements Be, Co,
Cr, Cu, Ge, Mn, Mo, Ni, U, and V were found primarily in the ash
phase, as expected from the model. Thus, although the computer
model is incorrect in predicting complete or zero volatilization,
the elements it predicts to be volatilized (with the exception of
boron) do appear to be found primarily in the particulates in the
gas stream (or the vapor phase itself) rather than in the gasifier
ash. Most of the other trace elements that had concentrations in
the coal of greater than 1 ppm appear to be primarily retained in
the ash.
147
-------
TABLE 3.4-2. PREDICTED EQUILIBRIUM TRACE ELEMENT DISTRIBUTIONS
lie
IM falfw
Itajvc
*• Specie*
M
"•J" X .f
Specie* Blmeat
• .t «4*1
t «f IUJ.r I •!
BlcMut Specici Elnmt
totbrxlte «t 7M«R
BicMtit
lUJ.t
Specie*
•t «XX*K
1.1
Clrarat
tlaetf
•e
C4
IS
17
*••<«)
oo
Cc
Oi
•I
r
it
xi.s
•.a
if
tx
1.1
i.a
CrOU)
SkCI(t)
IM
77
XI
tx
IM
M
•I
•.54
*.S7
71
*.f
4.S
IM
IM
IM
IM
I*
IM
IM
IM
IM
M
I*
ts
*.»
IM
IM
IM
IM
IM
»»•»<•> IM
IM
II
If
13
SeCg(|) «.•
IM
••(I)
IM
rbci«u>
M,0a(|) IM
CrfU) IM
Cr,0,(.) IM
€•,!(•) IM
6eSs(«) IM
6ef(») *.X
IM,(.) IM
ltoSt(*) IM
•!•(•) IM
r«o«) IM
Cr,0,(.) IM
€«,»(.) IM
CcS(|) 7«
0«0(|) !•
IM
IM
IM
•»**0,U) IM
77
If
IM
IM
10
IM
IM
XX.«
•
100
SfM,(,) 100
too
100
»,*.o4(t) too
10
IM
IM
IM
PbS(.)
100
0.4f
100
100
CrtOa(>) 100
C«
-------
Metal carbonyls (Fe and Ni) in the product gas were
measured at the Glen-Gery Wellman-Galusha gasifier. These measure
ments indicated average concentrations of approximately 104
3 of Fe(CO)5 and 25 yg/NnP of Ni(CO>4 (Ref. 10).
3.4.2 Gas Purification
Product Gas -
Compositions of the final product gas are reported in
Tables 3.4-3 and 3.4-4. As indicated, many of the potential pol-
lutants present in the raw product gas (as discussed in Section
3.4.1) have been removed. The Stretford unit will remove most of
the H2S (down to 10 ppmv or less) and essentially all of the
HCN, but will not remove the organic sulfur. MEA systems will
remove organic sulfur as well as
Most of the tars and particulates will probably be
removed in the quench system and ESP, but the precise degree of
removal is uncertain since few data are available on tar and
particulate removal in an application such as this. Tar removals
in the tray and spray scrubbers were calculated based on a tar
aerosol size distribution from Riley Stoker tests. Indirect
cooling rather than direct water quenching was reportedly used in
these tests, however, so the size distribution may not accurately
represent the system studied in this report. The electrostatic
precipitator was designed to remove 99 percent of the remaining
tar aerosols. Removals greater than 99 percent were reportedly
achieved in the ESP in Riley Stoker's pilot system (Ref. 38).
More data are needed on the tar removal efficiencies of the quench
scrubber and the ESP in atmospheric pressure fixed-bed gasifier
applications .
Data on removal of trace elements in the quench system
and sulfur removal processes are not available. Since most of the
trace elements in the gas are apparently in the small particu-
lates, however, it appears that the final gas product, from which
essentially all of the particulates are removed, may have few re-
maining trace elements.
Tars and Oils -
Tars and oils produced from gasification of bituminous
and lignite coals will be predominantly organic material, but will
also contain ash and various trace elements. Estimated ultimate
compositions for the tars from the bituminous and lignite coals
are given in Table 3.4-5. A more detailed analysis of the organ-
ics in the tar produced at the Chapman facility is given in Table
149
-------
TABLE 3.4-3. COMPOSITION OF LOW-BTU PRODUCT GASES AFTER STRETFORD
in
O
Low Sulfur High Sulfur
Bituminous Bituminous Anthracite Lignite
Component (vol %, dry)
CO
H2
C02
N2
CH4
C2H4
C2H6
C3H6
C3H8
H2S
COS
CS2
S02
NH3
HCN
Ar
02
Water content,
mole/mole dry gas
Tar loading, g/Nm3 (gr/scf )
Flow rate*, Nm3/s (scfm)
25.9
12.5
4.9
53.4
2.1
0.27
0.10
^
o.ooi
0.01
-
0.002
0.03
0.01
0.6
-
0.095
0.15 (.064)
3.2 (7240)
28.83
14.81
3.42
48.90
2.72
0.27
0.10
_
0.001
0.03
-
0.002
0.03
0.01
ND
—
0.095
0.16 (.066)
2.8 (6285)
25.45
16.31
5.51
51.48
0.23
f 0.0001
/ 0.004
0.001
0.0093
0.0001
0.0021
0.0195
0.0043
ND
0.91
0.095
~
3.5 (7830)
30.6
16.85
3.89
46.55
1.30
0.388
0.0858
0.253
0.0238
0.001
0.011
-
-
0.03
0.01
0.6
—
0.095
0.14 (.058)
2.9 (6440)
*For 17.6 MW (60 x 106 Btu/hr) gas production
ND: Not Detected
-------
TABLE 3.4-4.
COMPOSITION OF LOW-BTU PRODUCT GAS FROM HIGH-
SULFUR BITUMINOUS COAL AFTER TREATMENT IN MEA
Component (Vol. %)
Concentration, Vol. %
Case A
Case B
CO
H2
C02
N2
CH4
C2H4
CoHg
H2S
COS
MEA
H20
Flow rate, Nm3/s (scfm)
28.6
14.1
0.5
48.6
2.7
0.26
0.1
0.016
0.006
0.003
4.5
2.5 (5630)
29.8
15.5
0.3
50.7
2.8
0.28
0.10
0.0004
neg.
0.003
0.56
2.4 (5460)
a~200 ppmv sulfur species in product gas
k~10 ppmv sulfur species in product gas
cFor production of 17.6 MW (60 x 106 Btu/hr) of low-Btu
151
-------
TABLE 3.A-5. ULTIMATE ANALYSES OF BY-PRODUCT TAR
Ultimate Comp. ,
Wt. % (dry basis?
a
b
C
H
0
N
S
Ash
Moisture contents
Low-Sulfur
Bituminous
85.2
7.9
5.1
1.2
0.5
0.1
are about 0.10 kg/kg tar.
High-Sulfur c
Bituminous
88.8
7.8
1.4
0.8
1.2
0.1
Lignited
78.1
7.2
10.0
1.3
1.3
Source: Ref. 45
Source: Ref. 9
152
-------
3.4-6 (Ref. 43). The major organic categories identified were
polycyclic aromatic hydrocarbons and heterocyclic organics. A
wide distribution of trace elements was found, with sulfur and
potassium the predominant ones. Trace elements identified in the
tar are given in Table 3.4-7 (Refs. 13, 36).
Bioassay tests have been performed on the by-product tar
produced at the Chapman facility. Table 3.4-8 gives the results
of these tests. The Ames test was positive which indicates that
the tar is possibly carcinogenic. Toxic effects were also noted
in the Rodent Acute Toxicity Test; however, an LD-50 was not ob-
tained. The tar was the second most toxic sample in the soil
microcosm test.
3.5 WASTE STREAMS TO AIR
Various waste streams will be emitted to the air from a
Wellman-Galusha gasification facility. These include fugitive
dust from coal handling; vent gases from coal feeding, ash re-
moval, and gasifier start-up; fugitive emissions and pokehole
gases from the gasifier; vent gases from the tar/water separator
and Stretford oxidizer; acid gases from the MEA process; and com-
bustion gases from burning the product gas. These streams are
discussed in this section.
3.5.1 Coal Preparation and Handling
Since presized coal is received at the gasification fa-
cility, fugitive coal dust from coal receiving, storage, and con-
veying are the only air emissions. The quantities of these emis-
sions will be variable, depending on factors such as wind
velocities and coal size distribution.
3.5.2 Coal Gasification
Coal Feeding Gases -
Coal feeding gases are released when the slide valves at
the bottom of the coal feed hopper open to allow the coal feed to
enter the gasifier. As the coal is discharged, a small amount of
raw product gas from the gasifier fills the space in the hopper.
This gas escapes to the atmosphere when the slide valves at the
top of the coal feed hopper open to admit another charge of coal.
The composition of the major gaseous components in this stream
should be similar to that of the raw product gas. However, minor
gaseous species and tars may condense on the coal and not be emit-
ted from the coal feeder. The composition of the coal feeder
eases from the Glen-Gery Wellman-Galusha gasification facility is
|iven in Table 3.5-1 (Ref. 10).
153
-------
TABLE 3.4-6.
ORGANIC COMPOUNDS IDENTIFIED IN THE TAR
PRODUCED FROM A CHAPMAN FACILITY USING
BITUMINOUS COAL
Category
Mo.
1
5
8
10
13
18
21
utiaece*
Sereaje
Organic Category Coaceatraet
Organic Compound (u«/g)
Aliphatic Hydrocarbon*
>C, Alkaaaa 4.0 x 10
^C, •, Alkaaes 9.0 x 10
Alcohol*
>C, Alkylalcohol* 3.4 x 10
Cerboxylie Acid* and Their
Derlvlclva*
Fhthallc acid 1.0 x 10
Phthalaca aatar* 3.0 x U
Adlpat* aatara 2.2 x 10
>d Aliphatic eecara 4.* x 10
Amlae*
AxUotacratlo 9.0 x 10
OAlkylaailloe 1.0 x 10
C|-Alkyl«nilia* 2.0 x 10
Baaxofluoreaeamiae (.0 a 10
Mathylbeaxotluoreneamin* 2.0 x 10
Aminonaphchalene 1.0 x 10
Mathyl-aaiaoaceaephthyleM 2.0 x 10
Beueae, Subaeitutad Beaxaaa
Hydrocarbon*
Indaa* 3.0 x 10
C,-Alkylindaae 3.0 x 10
Phenol*
Phenol 1.8 x 10
Aolaola* 8.4 x 10
C,-Alkylphenol 9.8 x 10
C ,-Alkylpbeaol 1.0 x 10
Indaaol 3.0 x 10
Maphchol 1.8 x 10
Mathylaaphehol 2.0 x 10
C ,-Alkylnaphehol 3.0 x 10
Acaaephthol 3.0 x 10
Hachylacenaphthol 9.0 x 10
C ,-Alkylacenaphthol 1.4 x 10
C ,-Alfcylaceaaphchol 7.0 x 10
Hydroxyenthraceaa l.J « 10
C ,-Alkylhydroryanthraceaa 2.0 x 10
C j-Alkylhydroxypyraaa 2.1 x 10
Hydro xybeniofluorene 3.J x 10
Fuaed Aromatic Hydrocarbon* aad
Their Oerivltive*
Saphthalena 2.1 x 10
Methylnephchalaae 4.2 x 10
C j-Alkylnaphthalene 4.4 s 10
Acanaphthene 1.4 x 10
Mathylaeeaapatheae 4.0 x 10
C i-Alky lacenaphtheue 1.2 x 10
C i-Alkylacanaphcheae J.O x 10
Acanaphthylana 4.3 x 10
Mathylaeeaephthylaae 2.8 x 10
C j-Alkylacan*phthyla«a 1.4 x 10
Anthracene (.3 ( 10
MethylaacHracene 2.1 x 10
C »Alkylanchr*c*na 8.0 x 10
HethylpheaaaehrMaae 2.1 x 10
Chry»*na 2.9 x 10
Mechylchryaaae 1,2 x 10
Paryleaa §.Q x 10
Pyrene 2.4 x 10
Beaxoparylaae 5.0 x 10
lenzopyrene J.O x 10
Trlpheaylaae 2.9 x 10
Mathyltrophenylene 1.2 x 10
J€C
on Cattgory Organic Category
So. Orswie Compouad
22 Fuaed Noa-Altanaat Polycyclic
Hydrocarbon*
1 Fluoreae
Hathylfluorene
Fluoraachaae
leasofluoreae
23 leterecyclic Nitrogen C^MOouada
Cavbetele
' Xethylcarboiole
* C»-Alkylpyrldin«
• C»-AOkylpyrldlae
* Acridlae
Me thy leer id laa
Ct-Alkylacrldlae
. Ci-Alkylacridine
' Quinoliaa
| Hathylqulaellae
' Ci-Alkylouiaollne
* C i-Alkylqulnoliae
* lenxoqulnollna
MethylbensoquinoUae
C t-Alkylbanioquiaoliae
C i-Alkylbeaxoquiaolina
:
i
i
i
i
)
'
i
i
*
j
i
i
i
i
i
Uciaated
Stream
Coaceatratioa
24 in 1
* • * AU
21 in 1
* • iU
IL 4 A 1
.*> 10 *
3.a 10 »
4 .0 10 •
2.0 10 »
1.0 10 «
2.0 10 >
9.0 10 *
40 in I
^.w ^y -
4.0 10 *
*.0 10 *
i.9 10 »
«.0 10 *
2.3 10 »
1.1 10*
7.0 10 »
11 in I
*•* AU
3.0 10 »
«.0 10 «
XZC: MultiMdla CnvlrooHatal Goal*
Sourea: *af. i3
154
-------
TABLE 3.4-7. TRACE ELEMENTS (BY SSMS) IN THE BY-PRODUCT TAR PRODUCED
FROM LOW-SULFUR BITUMINOUS COAL
Ui
me
Category
Number
27
28
29
30
31
32
33
34
35
36
37
38
39
A3
44
45
46
48
49
50
51
53
54
56
Element
Lithium
Sodium
Potassium
Rubidium
Cesium
Beryllium
Magnesium
Calcium
Strontium
Barium
Boron
Aluminum
Galblum
Silicon
Germanium
Tin
Lead
Phosphorus
Arsenic
Antimony
Bismuth
Sulfur
Selenium
Fluorine
Concentration
Sample 1
ND
ND
3000
0.5
ND
ND
200
ND
20
50
1
ND
<9
ND
ND
ND
50
ND
<0.2
80
5
2000
0.003*
20
(jJg/8)
Sample 2
4
71
100
0.2
0.1
0.1
23
630
10
27
19
25
8
170
1
0.9
10
17
4
0.8
ND
520
3
22
MEG
Category
Number
57
58
59
60
61
62
63
65
66
68
69
71
72
74
76
78
81
82
83
84
84
84
84
Element
Chlorine
Bromine
Iodine
Scandium
Yttrium
Titanium
Zirconium
Vanadium
Niobium
Chromium
Molybdenum
Manganese
Iron
Cobalt
Nickel
Copper
Zinc
Cadmium
Mercury
Lanthanum
Cerium
Praseodymium
Neodymiun
Concentration
Sample 1
ND
ND
5
<1
1
ND
ND
1
<5
To
ND
ND
ND
ND
ND
300
ND
<6
0.06*
5
5
ND
ND
CJg/g)
Sample 2
6
2
1
0.7
0.2
29
0.7
0.8
ND
3
1
0.9
120
5
5
3
7
ND
0.12
0.6
0.5
0.3
0.6
Sample 1: Ref. 13
Sample 2: Ref. 36
*Deterrained by Atomic Adsorption Spectrometry
-------
TABLE 3.4-8. BIOASSAY TEST RESULTS FOR THE TAR PRODUCED
FROM A CHAPMAN FACILITY USING LOW-SULFUR
BITUMINOUS COAL
Health Tests
• Ames Positive
• RAM, EC-50 ( g/ml >1000
of cell culture)
• RAT . High Toxicity
- LD-50 (g tar/kg rat)D >10
Ecological Test
• Soil Microcosm • Second
Sources Ref. 13
fEC-50: Concentration at which growth was 50 percent of control
LD-50: Dose per kg of test animal at which 50 percent died
cSoil Microcosm Test Ranking for Samples tested were:
1 - Most Toxic Cyclone Dust
2 - Tar
3 - Coal
4 - Ash
5 - Least Toxic Quench Liquor
156
-------
TABLE 3.5-1. COMPOSITION OF COAL FEEDER GAS FROM THE
GLEN-GERY WELLMAN-GALUSHA GASIFIER*
Component
CO 2
H2
02
N2
CH.+
CO
H2S
COS
SO 2
CS2
FeCCOU
NH3
HCN
SCN
Concentration
(Ug/m3 @ 25°l>)
8.5 x 107
1.2 x 107
4.8 x 107
6.5 x 108
1.4 x 106
2.7 x 108
4.1 x 10s
1.5 x 105
1.3 x 10"
1.6 x 103
1.3 x 105
ND
ND
ND
'^Anthracite coal feedstock
ND: Not Detected
Source; Reference 10
157
-------
Ash Removal Vent Gas -
This gas stream is discharged when the ash hopper is
opened in order to dump accumulated ash. Under normal operating
conditions, this stream would consist mainly of steam and air,
with traces of particulate matter. If the ash is quenched prior
to being dumped from the hopper, this gas stream could also con-
tain any volatile compounds in the quench water. No measured data
on the flow rate or composition of this stream are available.
Start-Up Emissions -
About four hours are needed to bring the Wellman-Galusha
gasifier from a "cold start" to normal operations (Ref. 7). Dur-
ing the start-up period, the gas initially contains mainly pro-
ducts of combustion such as C02 and S02. As the temperature
of the gasifier increases, the gas begins to resemble the low-Btu
gas.
Fugitive Emissions and Pokehole Gases -
Sources of product gas leakage from Wellman-Calusha
gasifiers are pokeholes. Pokeholes are used as access ports for
probing the coal bed with metal rods. These rods are used to mon-
itor the position of the combustion zone in the coal bed and to
breakup clinkers in the bed. Emissions from pokeholes consist of
all components of the raw product gas.
3.5.3 Gas Purification
Several potential sources of gaseous emissions exist in
the gas purification operation. These include fugitive emissions
from the cyclone, vent gases from the tar/oil/water separator,
vent gases from the oxidizer and evaporator in the Stretford pro-
cess, and tail gases from the MEA acid gas removal process.
Fugitive Emissions from Cyclones -
Emissions from cyclones used for bulk particulate removal
consist of leaks from the cyclone. These emissions have not been
measured but may contain components found in the low-Btu gas. Ad-
ditional emissions may arise if the cyclones are equipped with
pokeholes. The cyclones at the Chapman gasification facility were
outfitted with pokeholes (Ref. 13). However, the cyclones at the
Wellman-Galusha gasification facility discussed in Section 3.1 did
not have pokeholes. Emissions from cyclone pokeholes would be
similar to the raw low-Btu gas.
158
-------
Gaseous Emissions from Quench Liquor Separator -
Gaseous emissions from the quench liquor separator con-
sist of volatile organic and inorganic compounds that have been
scrubbed from the raw product gas in the quenching and cooling
processes. In the separator, some of the absorbed gases and
vapors desorb from the quench liquor. The vent stream from the
separator would then contain constituents of the product gas
including H2S, COS, CS2, S02, H2, C02, CO, NH3, HCN,
and organic vapors.
At the Chapman gasification facility (using low-sulfur
bituminous coal), a steam ejector is used to vent the vapor space
above the tar/quench liquor separator. The organic vapors identi-
fied in the separator vent stream are given in Table 3.5-2 (Ref.
43). Trace elements found in the separator vent stream are shown
in Table 3.5-3 while the results from water quality analyses of
the condensables in this stream are given in Table 3.5-4 (Ref.
13).
Table 3.5-5 shows the gaseous components identified in
the vent gases. Data obtained from the Chapman facility indicated
that about 70 percent of the NH3 and about 20 percent of the HCN
in the raw product gas were in the separator vent gases. About 7
percent of the H2S in the raw product gas was in this vent
stream (Ref. 13).
Bioassay tests were performed on the XAD-2 extract of the
separator vent gases from the Chapman facility. The results of
these tests are given in Table 3.5-6. A slightly positive Ames
test was obtained along with a moderately toxic response from the
WI-38 test (Ref. 13).
If the separator were fitted with a steam ejector (as at
the Chapman facility), the separator vent gas would have charac-
teristics similar to those reported in Tables 3.5-2 through 3.5-5.
A vent gas from a facility gasifying anthracite coal would contain
fewer organics. Vent gas from a facility gasifying high-sulfur
coal would contain more sulfur species.
Stretford Oxidizer Vent -
An air-blown oxidizer is used in the Stretford process to
convert the reduced ADA back to its oxidized form. A large excess
of air is used in the oxidizer, and subsequently vented to the
atmosphere. The vent stream will contain primarily oxygen and
nitrogen, along with water picked up from the solution. It can
potentially contain small amounts of ammonia and possibly COS or
HCN, if these components are presented in the inlet gas stream to
the absorber. Hydrocarbons may be released when gases with high
concentrations of tars are treated (Ref. 25). No test data are
available on the composition of this gaseous emission (Ref. 25).
159
-------
TABLE 3.5-2
ORGANIC COMPOUNDS IDENTIFIED IN THE
SEPARATOR VENT STREAM FROM A CHAPMAN
GASIFICATION FACILITY USING LOW-
SULFUR BITUMINOUS COAL
MEG
Catagory
Organic Category
btiavtad
Straa*
CaMaatratioa Catagory Organic Catagory
Eatlaatad
Straam
Concentration
Aliphatic Hydrocarbons
>Ci Alkaoaa
rhaaylacatylaaa
Bthart
Nathylaalaola
>C« Aliphatic alcohola
AUahydaa, Katoaaa
icatophaaoaa
Carkogr/lic Acida and Their
DertvitiTaa
Phthalic acid
Adipata aatara
rhthalata aatara
•itrilaa
BMSMltrila
CyaaotoloaM
10
IS
tolu
, Subatitticad
5.2 x 10"
1.4 x 10*
2.0 x 10*
8.2 x 10*
1.8 x 10'
1.6 x 10*
4.9 x 10*
3.1 x 10*
1.1 x 10*
9.2 x 10*
9.2 x 10*
2.7 x 10*
3.7 x 10'
21
Fitted Aroaetic Bydroearboas
Their Darivitivaa
Nethylaephthali
Natbylacaaaphthaaa
Ct-Alkylacaaaphthaoa
M»l li| 1 an flu l
8.
1.
1.
4.
1.
2.
3.
1.
3.
2.
4.2
1.0
10'
10»
10»
10*
10*
10*
10*
10*
10*
22
23
aVdroearbaa*
Fluoraoa
HatirlfluaraM
••tamayUlc Mtrataai
Pyridiaa
M»tlqrlpyrtdta»
Polycycllo
Ct-AlkjrlpyrtaiM
2.3 x 10*
9.2 x 10*
4.0 x 10*
1.6 x 10*
1.0 x 10*
9.2 x 10*
3.5 x 10*
1.3 x 10*
4.6 x 10*
Ci-Alkylbatuaata
ICyraaa
Ci-AlkylbaiMM
T^J^..^
MMflHV
nadiylln^jma
C * •aVlkvlladdiM
w J ^Jfcfclfcy ***•»••»»••»
Ci-Alkrliadaoa
Wf "••J**"^^^p^
Inaaaa
Matbyliadaoa
C. Uijl !•••••
C,-Alkylindaaa
8 Fhaaala
fhaaal
Craael
Ct-Alkylphaael
Ci-AUylphaool
C.-alkylphaaol
7.0
.2
.3
.0
.8
.1
.2
.2
.4
.8
.0
.0
.7
.3
1.8
2.1
10'
10'
10'
10'
10'
10*
10*
10*
10»
10*
10'
10*
10'
10*
10
10*
Sourea
NU:
. *3
160
-------
TABLE 3.5-3. TRACE ELEMENTS (BY SSMS) FOUND IN THE SEPARATOR VENT STREAM
FROM A CHAPMAN GASIFICATION FACILITY USING LOW-SULFUR
BITUMINOUS COAL
ICC
Category
(lumber
27
28
29
30
33
34
35
36
37
38
39
43
45
46
48
54
56
57
58
59
Trace
Element
Lithium
Sodium
Potassium
Rubidium
Magnesium
Calcium
Strontium
Barlua
Boron
Aluminum
Gallium
Silicon
Tin
Lead
Phosphorus
Selenium
Fluorine (as F )
Chlorine
Bromine
Iodine
Concentration
(UR/Nm3)
40
4000
2000
0.5
200
2000
20
40
3
40
3
300
8
30
3000
10
<50
200
9
1
tec
Cagetory
No.
60
.62
63
65
68
69
70
71
72
74
76
78
79
81
82
83
84
84
85
Trace
Element
Scandium
Titanium
Zirconium
Vanadium
Chromium
Molybdenum
Tungsten
Manganese
Iron
Cobalt
Nickel
Copper
, Silver
Zinc
Cadmium
Mercury
Lanthanum
Cerium
Uranium
Concentration
(UB/Nm3)
<2
40
500
100
300
400
<8
50
2000
2
70
2000
1000
100
0.9
<0.3
3
4
40
NEC: Multimedia Environmental Goals
Source:
-------
TABLE 3.5-4. WATER QUALITY ANALYSES ON THE SEPARATOR VENT
CONDENSABLE FROM A CHAPMAN GASIFICATION
FACILITY USING LOW-SULFUR BITUMINOUS COAL
Water Quality
Parameter Value
pH 9.56
IDS (pg/ml) 218
TSS (Ug/ml) 14.5
COD (Hg/ml) 8200
BOD (Pg/ml) 3900
Alkalinity (as CaCOa) (Mg/ml) 2880
Fluoride (yg/Nm3 gas) 200
Source: Ref. 13
162
-------
TABLE 3.5-5. GASEOUS COMPONENTS FOUND IN THE SEPARATOR UNIT
STREAM FROM A CHAPMAN GASIFICATION FACILITY
USING LOW-SULFUR BITUMINOUS COAL
Concentration
Component pJig/Nm3)
Methane
C2 Hydrocarbons
Ca Hydrocarbons
Ct» Hydrocarbons
C5 Hydrocarbons
Ce Hydrocarbons
CO 2
CO
NO
NO 2
NH3
CN~
SO 2
COS
H2S
CS2
2 x 106
1 x 106
4 x 105
3 x 105
1 x 10s
4 x 105
3 x 107
4 x 107
4 x 10"
3 x 105
7 x 105
3 x 103
9 x 103
4 x 10"
2 x 10s
2 x 10"
Source: Ref. 13
163
-------
TABLE 3.5-6. BIOASSAY RESULTS OF THE XAD-2 RESIN
EXTRACT OF THE SEPARATOR VENT GASES
FROM THE CHAPMAN FACILITY USING LOW-
SULFUR BITUMINOUS COAL
Results
Health Tests
• Ames Slightly Positive
• WI-38, EC-50 (Nm3/ml culture) 7 x 106
. RAM, EC-50 (NmVml culture) > 1 x 10s
Source: Ref. 13
Concent!
EC-So's were calculated by:
aEC-50: Concentration at which growth was 50 percent of control.
|EC5t reported J jmg of organic* j |BJ of organ
, • Jin yl of extract! x extracted per mil f j per Nm* of
Iper ol culture I lof extract j I vent «»«
|EC5t reported J jmg of organic* j fag of organlci)
EC,, -in yl of extract x extracted per «t « per Nm' of - «•' vent M./rf eultut.
leer nt culture I lof extract I I >i»nr ... I •••/•«• cut cur*
164
-------
Stretford Evaporator -
In order to maintain a water balance in the Stretford
unit, evaporation of excess water may be required (Ref. 16). Ex-
cess water may result from washing the sulfur cake or from conden-
sation of water in the inlet gas stream. Since the quantities of
water to be evaporated are not large, evaporator vent streams will
be small. Along with water vapor, it may contain a small con-
centration of salts in the Stretford solution. In addition, it
could contain low concentrations of other volatile components
evolved from the liquor, but these should be small since most of
these should be released in the oxidizer.
MEA Acid Gas -
The largest potential emission from the MEA acid gas re-
moval process is the acid gas stream. The quantities and com-
positions of this stream are shown in Table 3.5-7 for purifica-
tion of low-Btu gas produced from high-sulfur bituminous coal.
Acid gases corresponding to two levels of purification have been
examined: (1) removal of sulfur species to a residual of about
200 ppmv and (2) removal of sulfur species to a residual of 10
ppmv. The acid gas stream is mostly composed of the CO? and
HoS. Minor constituents may include other species found in the
low-Btu gas.
In the removal of sulfur species to 10 ppmv, the basic
MEA purification scheme can be modified to reduce the amount of
non-acid gases released in the acid gas stream. This modification
includes an intermediate-pressure flash of the rich H2S-MEA
solution. The desorbed components include both non-acid and acid
gases. The stream would require further treatment before release.
3.5.4 Combustion Gas
Another significant air emission from the Wellman-Galusha
gasification facilities results from combustion of the product
gas. This combustion gas consists mainly of N?, 02, C02,
and HoO. It will also contain small amounts of other compounds,
depending on their concentrations in the product gas. Sulfur spe-
cies in the gas will be converted to S02 (and smaller amounts of
503). Part of the nitrogen compounds (NH3, HCN) will be con-
verted to NOX. Few data are available on the actual composi-
tion of the combustion gas. The concentration of NOX in the
combustion gas depends on several factors, including the NH3 and
HCN content of the low-Btu gas, the amount of excess air used in
the burner, and the combustion temperature. The dust in the raw
product gas is primarily carbon. Since this will be burned along
with the gas, particulate emissions from combustion of the low-Btu
product gas should be low.
165
-------
TABLE 3.5-7. ACID GAS FROM MEA UNIT PURIFYING
GAS FROM HIGH-SULFUR BITUMINOUS COAL
Composition, Vol. %
C02
H2S
CO
N2
CH4
C2H6
C2H4
NH3
HCN
COS
H20
MEA
H20
Flow rate, Nm3/s (scfm)
a
Case A
70.0
18.6
1.85
3.11
0.30
0.004
0.02
0.60
-
-
0.33
0.005
5.12
0.12 (270)
Case Bb
60.5
15.9
6.12
9.84
0.92
0.02
0.04
0.51
-
-
1.05
.005
5.12
0.14 (324)
"MEA removes sulfur species to level of 200 ppmv in product gas
MEA removes sulfur species to level of 'VilO ppmv in product gas
°Based on production of 17.6 MW (60 x 10s Btu/hr) of raw low-Btu gas
166
-------
3.6 WASTE STREAMS TO WATER
Liquid effluents from the gasification and gas purifica-
tion operations include quench liquor blowdown and blowdown of
sorbents from the acid gas removal processes. Ash sluice water
and leachate or runoff from the coal piles are the other possible
wastewater streams.
3.6.1 Coal Preparation and Handling
There are no liquid effluents from coal handling and con-
veying. Runoff/leachate from rainfall and/or water sprays on coal
storage piles are potential liquid effluents from coal storage.
3.6.2 Coal Gasification
Ash sluice water may be used to remove ash from the gasi-
fier. The flow rate of this water is quite variable. At the
Glen-Gery Wellman-Galusha facility using anthracite, the amount of
sluice water used was approximately 4500 to 6800 I/day (1200 to
1800 gallons per day). This water will contain suspended solids
as well as various dissolved inorganics. Leachate from the ash
will also contain suspended solids and dissolved inorganics.
Trace elements found in the ash sluice water and ash leachate (us-
ing leaching tests defined in Ref. 4) are shown in Table 3.6-1.
Water quality parameters for the ash sluice water and ash leachate
are given in Table 3.6-2 (Ref. 10).
The results of bioassay tests performed on the ash sluice
water and ash leachate are given in Table 3.6-3. These results
indicate a low potential for harmful health effects.
3.6.3 Gas Purification
Process Condensate -
A blowdown of quench liquor will be required if water is
condensed from the product gas as it is cooled. In certain cases,
a blowdown may also be required to remove particulates or other
impurities from the quench system. The major factors affecting
the size of the blowdown stream are the water content of the raw
gas from the gasifier and the temperature to which the gas is
cooled. These two factors set the minimum size of the blowdown
stream.
For gasification of the high-sulfur bituminous and lig-
nite coals considered in this study, blowdown rates of 0.13 kg/s
(1000 Ib/hr) and 0.43 kg/s (3400 Ib/hr), respectively, were calcu-
lated due to water condensation. When an MEA acid gas removal
167
-------
TABLE 3.6-1. TRACE ELEMENT CONCENTRATION (BY SSMS) OF ASH SLUICE WATER AND ASH LEACHATE
oo
ELEMENT
Uranium
Thorium
Bismuth
Lead
Thallium
Gold
Rhenium
Tungsten
Tantalum
Hafnium
Lutetium
Ytterbium
Thulium
Erbium
Holmium
Dysprosium
Terbium
Gadolinium
Europium
Samarium
Neodymlum
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Tellurium
Antimony
Tin
Indium
Cadmium
Silver
MD: Not Detected
*Ash leachlnc proc
ASH SLUICE
WATER dig/*.)
2
40
10
1
2
1
1
2
3
1
2
1
10
10
10
100
0.4
*
4
STD
2
LEACHATE ELEMENT
7 Molybdenum
Niobium
Zirconium
8 Yttrium
Strontium
Rubidium
Bromine
*1 Selenium
Arsenic
Germanium
Gallium
Zinc
Copper
Nickel
Cobalt
Iron
Manganese
Chromium
Vanadium
Titanium
Scandium
<1 Calcium
Potassium
Chlorine
Sulfur
Phosphorus
1 Silicon
Aluminum
Magnesium
1 Sodium
ST° Fluorine
* Boron
5 Beryllium
Lithium
ASH SLUICE
WATER (yg/tX
400
30
200
40
3000
200
20
30
1
40
50
10
40
5000
500
550
MC
' 7
MC
500
2000
200
MC
>500
<1
40
MC: Major component concentration >1 x
edures used ai
re those defined in K*f« 4. STD:
Standard
LEACHATE
20
1
30
1
60
2
2
1
4
1
1
4000
8
INT
1
10
2
3
<10
<1
3000
>6000
5000
300
100
200
6
300
>1000
60
20
<1
30
10' Vg/l
-------
TABLE 3.6-2
WATER QUALITY PARAMETERS FOR THE
ASH SLUICE WATER AND ASH LEACHATE
FROM THE GLEN-GERY WELLMAN-GALUSHA
GASIFICATION FACILITY*
Parameter
CN~
SON"
Cjf
F~
S03~ + SOit" as SOi,
Sulfide
N03~
NOa"
PO-§
4
NH4+
Cat2
Mg+2
BOD
TOC
COD
IDS
TSS
Concentration
Ash Sluice Water
60
<2,000
17,000
0.0600
95,000
<3,000
17,000
ND
1,700
3,000
ND
ND
42.5 (ppm)
140,000
20,000
400,000
550,000
(yg/W
Ash Leachate
ND
ND
5700
ND
2200
ND
50
30
500
ND
4000
890
ND
ND
ND
ND
ND
*Anthracite coal feedstock
Source: Reference 10
ND - Not determined
169
-------
TABLE 3.6-3. RESULTS OF BIOASSAY TESTS ON THE
ASH SLUICE WATER AND ASH LEACHATE
FROM THE GLEN-GERY WELLMAN-GALUSHA
GASIFICATION FACILITY
Bioassay Test Ash Sluice Water Ash Leachate
Ames Negative Negative
WI-38, EC-50 (vSL/mi culture) >600 >600
RAT
Toxic response Low Low
LD-50 (g sample/kg rat)' >10 >10
Source: Reference 10
EC-50: Concentration at which growth was 50 percent of control
LD-50: Dose per kg of test animal at which 50 percent died
170
-------
process is used, gas compression yields additional process conden-
sate. The total process condensate for a system using low pres-
sure MEA absorption amounts to 0.23 kg/s (1800 Ib/hr); for high-
pressure MEA absorption, the condensate amounts to 0.32 kg/s (2500
Ib/hr). For low-sulfur and anthracite coals, no water is con-
densed from the gas. Particulates will be periodically removed
from the liquor separator, but there will be no continuous liquor
blowdown.
The quench liquor blowdown would have essentially the
same composition as the circulating quench liquor, which was dis-
cussed in Section 3.3.3.
Bioassay test results for the quench liquor from the
Chapman facility using low-sulfur bituminous coal are given in
Table 3.6-4. These results indicate a low potential for harmful
health effects. However, the liquor was highly toxic to aquatic
species.
Spent Sorbents -
As discussed in Section 3.2.3, a blowdown of solution
from the Stretford process is necessary to remove non-regenerable
compounds formed by absorption of HCN (forming thiocyanates) and
by oxidation of HS~ to thiosulfate. The major factors affecting
the size of the blowdown stream are the HCN concentration of the
feed gas and the thiosulfate formation rate. Other important
factors (which were also discussed in Section 3.2.3) are the de-
gree of washing of the sulfur cake and the total salts con-
centration of the solution.
Increases in HCN sorption and in thiosulfate formation
increase the quantity of salts that must be purged. The salts
concentration affects the size of the blowdown required to remove
a given quantity of salts. The lower the allowable salts concen-
tration, the larger the blowdown will have to be. The sulfur cake
produced as a by-product will contain about 50 percent water. It
would normally be washed to recover most of the Stretford chemi-
cals, but some will remain in the cake. Some of the thiocyanate
and thiosulfate salts will also remain in the cake, thus reducing
the quantities of these materials that must be removed in the
blowdown. The less the cake is washed, the more salts (along with
desirable Stretford chemicals) are lost with the sulfur cake, and
the smaller the blowdown required; Estimated quantities and com-
positions of the blowdown streams from the four coal feedstocks
for two different levels of cake washing are given in Table 3.6-5.
These numbers were calculated based on the design assumptions dis-
cussed in the Appendix.
171
-------
TABLE 3.6-4. BIOASSAY TEST RESULTS FOR THE QUENCH
LIQUOR FROM A CHAPMAN GASIFICATION
FACILITY USING LOW-SULFUR BITUMINOUS COAL
Test Value
Ames Negative
RAM, EC-50 (yg liquor/m£ culture) >600
RAT
• Toxicity response Low
• LD-50 (g liquor/kg rat) > 10
Fresh Water Tests
• Algal, EC-50 (15 days) (wt%) 1.0 to 0.1%
• Daphnia, LC-50 (96h) (wt%) 0.11%
• Fathead Minnow, LC-50 (96h) (wt%) 0.02%
Salt Water Tests
• Algal, EC-50 (12 days) (wt%) 0.53 / 0.4l%a
• Shrimp, LC-50 (96h) (wt%) 0.25
• Sheepshead Minnow, LC-50 C96h) (wt%) 0.16
Soil Microcosm (Toxicity ranking) Fifth
Source: Ref. 13
EC-50: Concentration at which growth was 50 percent of a control
LC-50: Concentration at which 50 percent of the experimental animals died
LD-50: Dose per kg of test animal at which 50 percent died
T?iltered/Unfiltered Sample
Soil microcosm toxicity rankings were:
High 1 - Cyclone dust
2 - Tar
4- 3 - Coal
4 - Ash
Low 5 - Quench Liquor
172
-------
TABLE 3.6-5. QUANTITY AND COMPOSITION OF STRETFORD SLOWDOWN.
Estimated Concentrations (|Jg/£)
Component
Na2S203
Na CNS
Na V03
ADA
NaHC03
Na2C03
Iron
EDTA
Flow Rate,* kg/ sec
(Ib/hr)
Low- Sulfur
Bituminous
2.1
1.97
4.42
6.67
2.52
5.3
5.0
2.7
0.00397
C31.5
x
X
X
X
X
X
X
X
-
107
108
106
106
107
10 6
10"
106
0.000527
41.8)
High- Sulfur
Bituminous
1.03
1.10
6.63
1.0
2.52
5.2
5.0
2.7
None
(None
x
X
X
X
X
X
X
X
—
108
108
106
107
107
106
10"
10 6
0.00673
53.4)
Anthracite
3.49
1.83
4.42
6.67
2.52
5.3
5.0
2.7
0.00154
(12.2
x 107
xlO8
x 106
x 106
xlO7
x 106
x 10"
x 106
- 0,00266
- 21.1)
4
1
4
6
2
5
5
2
Lignite
.24
.76
.42
.67
.52
.3
.0
.7
0.00256
(20.3
x 107
x 108
x 106
x 106
x 107
x 106
x 10"
x 106
- 0,00532
- 42.2)
*Low value refers to recovery of 66 percent of the salts from the sulfur cake by washing, while
the higher value refers to recovery of 96 percent of the salts from the sulfur cake by washing.
Basis: See Appendix
-------
Actual blowdown rates may exceed these estimated values. For
example, upsets in process chemistry can result in increased
thiosulfate formation, and, thus, increased blowdown requirements.
Typical blowdown rates of 6 to 60 1 (1.5 to 15 gallons) per 100
moles feed gas have been reported (Ref. 46). These figures are
greater than the estimates given in this report.
3.7 WASTE STREAMS TO LAND
Waste streams sent to final disposal from the gasifica-
tion and gas purification operations are gasifier ash, particulate
matter collected from the product gas, sulfur produced by the
sulfur recovery processes, and sludge from the MEA unit.
3.7.1 Coal Gasification
Gasifier ash is the only solid waste stream from the coal
gasification operation. It consists primarily of the ash that was
in the coal, but it also contains unreacted carbon, small amounts
of sulfur, hydrogen, nitrogen, and oxygen, and various trace ele-
ments. Ash composition can be quite variable, depending on the
coal feedstock and operating characteristics of the gasifier. Es-
timated quantities and compositions of the ash remaining after
gasification of the four coal feedstocks are given in Table 3.7-1.
The quantities of ash resulting from gasification of the four can-
didate feedstocks are also summarized in this table.
Trace element levels in the ash (measured by spark source
mass spectroscopy) at the Glen-Gery Wellman-Galusha facility (an-
thracite coal) and a Chapman facility (low-sulfur bituminous coal)
are given in Table 3.7-2. The concentrations for most of the ele-
ments are similar (within about an order of magnitude or less).
However, a few elements (Sn, Sb, Rb, and Mn) show a much larger
variation. The major trace elements in the ash were Na, K, Ba,
Ca, Sn, Fe, Ti, P, Si, Al, Mg, and S. As discussed in Section
3.4.1, several elements (including Be, B, Co, Cr, Cu, Ge, Mn, Mo,
Ni, U, and V) appear to be concentrated in the ash from the
Wellman-Galusha gasifier.
Radioactive disintegration data have been obtained for
ash produced from gasification of anthracite coal. These data are
presented in Table 3.7-3.
The ash will also contain a certain amount of organics.
Extractable organics found in ashes produced from the gasification
of anthracite and low-sulfur bituminous coals are given in Table
3.7-4. The organic compounds identified in the extractable organ-
ics are also included in this table.
174
-------
TABLE 3.7-1 ANALYSES OF ASH
Low Sulfur3 High Sulfur5
Bituminous Bituminous Anthracite Lignite
Ultimate Analysis,
wt. % (dry basis)
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen
Moisture, wt. %
MJ/kg (Btu/lb)
Quantity, kg/s (lb/hr)e
11.3
0.1
0.1
-
0.1
86.4
2.0
NG
3.8 (1650)
0.026 (210)
5.7 33.06 9.8
0.3 0.07
0.18
0.01
1.2 0.02 1.4
92.8 65.97 89.1
0.1 0.31
NG 0 . 25
2.0 (870) 7.4 (3193)
0.074 (585) 0.13 (1030) 0.134 (1060)
aFrom Wellman-Galusha gasifier (Reference 11)
bFrom Riley-Morgan gasifier (Reference 15)
cFrom Wellman-Galusha gasifier (Reference 10)
^Rough composition, estimated from material balance.
eFor production of 17.6 MW (60 x 106 Btu/hr) of low-Btu gas.
NG • value not given
175
-------
TABLE 3.7-2. TRACE ELEMENTS IN GASIF1ER ASH FROM GASIFICATION
OF ANTHRACITE AND LOW-SULFUR BITUMINOUS COALS
ESTIMATED
ELEMENT
ANTHRACITE*
Uranium
Thorium
Bismuth
Lead
Thallium
Gold
Rhenium
Tungsten
Tantalum
Hafnium
Lutetium
Ytterbium
Thulium
Erbium
Holmlum
Dysprosium
Terbium
Gadolinium
Europium
Samarium
Neodymium
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Tellurium
Antimony
Tin
Indium
Cadmium
Silver
32
29
18
12
0.3
0.1
2
-
2.
0.3
2
0.2
1
2
3
0.6
2
1
11
34
16
180
160
MC
10
0.3
0.2
0.5
2.0
STD
0.4
1.0
CONCENTRATION (Ug/g) ESTIMATED CONCENTRATION (ug/g)
LOW-SULFUR, LOW-SULFUR. ELEMENT LOW-SULFUR. LOW-SULFUR
BITUMINOUS BITUMINOUS ANTHRACITE* BITUMINOUS BITUMINOUS0
400
_
_
20
_
_
—
—
_
_
_
-
-
-
-
-
-
-
-
-
-
90
100
2000
-
-
-
200
300
-
<9
-
56
86
0.4
7
0.5
0.3
10
2.
10
2.
12
1.
8.
11
17
4.
10
5
28
56
42
260
280
MC
10
0.3
-
1
4
STD
3
20.3
Molybdenum
Niobium
Zirconium
Yttrium
Strontium
Rubidium
Bromine
Selenium
Arsenic
Germanium
Gallium
Zinc
Copper
Nickel
Cobalt
Iron
Manganese
Chromium
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Boron
Beryllium
Lithium
15
35
350
56
490
150
6
2
3
1
22
18
200
62
23
MC
69
190
200
MC
9
MC
MC
8
MC
MC
MC
MC
MC
MC
59
13
1
240
—
20
90
<20
2000
20000
-
30
<0.4
-
50
-
1000
—
50
10000
—
30
30
3000
50
50000
10000
-
1000
800
7000
3000
6000
MC
<200
20
10
70
22
82
430
260
MC
120
12
20
4
4
66
26
540
120
61
MC
680
510
MC
MC
29
MC
MC
230
250
MC
MC
MC
MC
MC
56
130
22
190
MC - Major components concentration > 1000 yg/g
STD • Standard
*Source: Ref. 10
Source: Ref. 13
CSource: Ref. 36
-------
TABLE 3.7-3. RADIOACTIVE DISINTEGRATION DATA FOR ASH
PRODUCED FROM THE GLEN-GERY WELLMAN-
GALUSHA GASIFICATION FACILITY*
Parameter Value (pCi/g)
Gross a emissions
Gross 3 emissions
4.3 + 1.0
0.0 + 3.4
*Anthracite coal feedstock
Source: Ref. 10
TABLE 3.7-4. CONCENTRATIONS OF EXTRACTABLE ORGANICS
AND COMPOUNDS IDENTIFIED IN THE ASH PRODUCED
FROM THE GASIFICATION OF ANTHRACITE AND LOW-
SULFUR BITUMINOUS COALS
Anthracite3 Low-Sulfur Bituminous
Total Concentration
of Extractable Organics , yg/g 39 60
Compounds Identified, yg/g
- Bis-(2-Ethylhexyl) Phthalate 0.58
Di-N-Butyl Phthalate 0.08
Diethyl Phthalate 0.05
> Ce Alkanes - 2.0
> Cis Alkanes - 2.0
phthalabs Esters - 2.3
Ca-Alkylbenzene - 1.0
Naphthalene - 3.0
Methylnaphthalene - 2.0
_ : Not detected
aSource: Ref. 10
bSource: Ref. 43
177
-------
Leaching tests have been conducted on gasifier ash
obtained from gasification of anthracite. Trace elements found in
the leachate are given in Table 3.7-5.
Bioassay test results for ash from the gasification of
anthracite and low-sulfur bituminous coals are shown in Table
3.7-6. These results indicate that the ash has a low potential
for harmful health effects. The soil microcosm tests were not
comparable between the two coals. The ash derived from anthracite
was more toxic than the cyclone dust while the dust was more toxic
than the ash for the low-sulfur bituminous coal feedstock.
3.7.2 Gas Purification
Collected Particulate Matter -
About 60 to 80 percent of the dust that is entrained with
the raw product gas from the gasifier is removed in a cyclone.
This cyclone dust contains mostly carbon (about 70 to 90 percent)
along with up to about 25 percent ash and small amounts of H, M
0, S, and various trace elements. Ultimate analyses of cyclone'
dust from low-sulfur bituminous, anthracite, and lignite coals are
given in Table 3.7-7. Most of the particulates not removed in the
cyclone will be removed in the quench system and ESP. These
particulates will either be discharged with a blowdown stream, or
removed periodically from the separator.
Trace element concentrations (measured by spark source
mass spectroscopy) in the cyclone dust from the gasification of
anthracite and low-sulfur bituminous coals are given in Table
3.7-8. Trace element concentrations of the cyclone dust and the
particulates not removed by the cyclone (anthracite coal case) are
given in Table 3.7-9. These data indicate that many of the ele-
ments appear to be concentrated in the small (<3 ym) particu-
lates. A few are more concentrated in the larger cyclone dust.
Radioactive disintegration measurements have been obtained on col-
lected particulates at the Clen-Gery Wellman-Galusha facility (us-
ing anthracite coal). These data are shown in Table 3.7-10.
Data on the extractable organics in particulates col-
lected by hot cyclones from the gasification of anthracite and
low-sulfur bituminous coals are summarized in Table 3.7-11.
Leaching tests have been performed on the cyclone dust
from gasification of anthracite coal. The trace elements found in
the leachate are given in Table 3.7-12.
178
-------
TABLE 3.7-5. TRACE ELEMENT CONCENTRATIONS IN THE ASH
LEACHATE FROM THE GASIFICATION OF
ANTHRACITE COAL
Trace
Element
Al
As
Ba
Be
B
Br
Cd
Ca
Ce
Cl
Cr
Co
Cu
F
Ga
Ge
Au
Zn
Concentration
(yg/ml)
0.006
0.004
0.1
<0.001
0.02
0.002
0.001
0.099
<0.001
0.16
0.002
0.001
0.008
-9.06
0.001
<0.001
<0.001
4
Trace
Element
Sc
I
Si
Fe
Pb
Li
Na
Mg
Mn'
Mo
Sr
Ni
Nb
S
Sn *
V
Y
Zr
Concentration
(yg/ml)
<0.001
<0.001
0.2
0.01
0.008
0.03
>1
0.036
0.004
0.02
0.06
Int
0.001
0.3
0.001
0.003
<0.001
0.03
Int - interference
All elements not reported: <0.001 yg/ml
Leaching procedures as defined in Ref. 4
Source: Ref. 10
179
-------
TABLE 3.7-6. BIOASSAY RESULTS OF THE ASH FROM THE GASIFICATION
OF ANTHRACITE AND LOW-SULFUR BITUMINOUS COAL
Test
Anthracite
Low-Sulfur Bituminous
Ames
RAM, EC-50
RAT
Negative
ash/mil culture) > 1000
• Toxic response
• LD-50 (g ash/kg rat)
Soil Microcosm (Toxicity
Ranking
Low
> 10
First
Negative
> 300
Low
> 10
Fourth
Source: Ref. 10
Source: Ref. 13
EC-50: Concentration of which growth was 50 percent of a control
Soil microcosm test rankings were:
Toxicity
Anthracite
Low-Sulfur
Bituminous
High
Low
1-Ash
2-Cyclone Dust
1-Cyclone Dust
2-Tar
3-Coal
4-Ash
5-Quench Liquor
180
-------
TABLE 3.7-7. ULTIMATE ANALYSIS OF CYCLONE DUST
Ultimate Analysis
Weight % (Dry Basis)
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Oxygen
Ash
Low- Sulfur
Bituminous
89
1.3
1.4
0.5
1.6
6.2
Low-Sulfur
Bituminous
82.1
0.83
1.5
0.62
3.8
11.1
Anthracite
70.64
1.37
0.62
0.01
1.53
0.95
24.88
Lignite
67.4
1.7
5.8e
2.0
22.3
aFrom Wellman-Galusha gasifier (Ref. 11)
bFrom Chapman gasifier (Ref. 13)
cFrom Wellman-Galusha gasifier (Ref. 10)
dFrom Riley-Morgan gasifier (Ref. 9)
eNitrogen and oxygen
181
-------
TABLE 3.7-8. TRACE ELEMENTS IN CYCLONE DUST
CO
CONCENTRATIONS (yg/g)
ELEMENT
Uranium
Thorium
Bismuth
Lead
Thallium
Gold
Rhenium
Tungsten
Tantalum
Hafnium
Lutetlum
Ytterbium
Thulium
Erbium
Holmium
Dysprosium
Terbium
Gadolinium
Europium
Samarium
Neodymlum
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Tellurium
Antimony
Tin
Indium
Cadmium
Silver
MC - Major
ANTHRACITE*
45
97
3
230
22
0.1
5
3
0.3
2
0.2
0.9
1.
2.
0.6
1.
1.
11.
110
35
99
130
MC
15
24
0.9
53
89
STD
2
5
LOW-SULFUIL
BITUMINOUS6
—
-
-
60
-
-
-
_
_
-
—
—
—
-
-
-
-
-
-
-
20
80
500
-
-
-
100
—
-
-•
—
component; concentration
LOW-SULFUR
BITUMINOUS0
_
-
2
60
-
-
-
_
_
-
-
_
-
-
9
2
1
9
21
5
45
45
460
1
4
-
8
2
STD
2
3
>1000 ug/g
STD • Standard
ELEMENT
Molybdenum
Niobium
Zirconium
Yttrium
Strontium
Rubidium
B romlne
Selenium
Arsenic
Germanium
Gallium
Zinc
Copper
Nickel
Cobalt
Iron
Manganese
Chromium
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Boron
Beryllium
Lithium
*Ref. 10
t>D_r 1 1
Ref. 13
Ttof. 36
ANTHRACITE3
57
52
110
42
270
15
11
16
85
11
220
MC
68
47
10
MC
570
58
150
MC
7
MC
MC
71
MC
MC
MC
MC
MC
MC
•V240
5
0.8
160
CONCENTRATIONS (vg/g)
LOW-SULFUR
BITUMINOUS
_
-
30
10
80
3
-
-
0.4
-
10
-
900
100
3
1000
200
30
20
200
2
2000
1000
-
300
8000
2000
100
500
-
100
7
7
2
LOW-SULFUR
BITUMINOUS0
14
12
80
70
340
33
20
24
27
5
130
85
130
30
16
MC
120
90
100
MC
12
MC
MC
720
MC
MC
MC
MC
MC
MC
1-720
720
6
27
-------
TABLE 3.7-9. TRACE ELEMENT CONCENTRATIONS 0? PARTICULATES COLLECTED BY THE CYCLONE AND THOSE
NOT COLLECTED FOR THE GASIFICATION OF ANTHRACITE COAL
CO
CO
ELEMENT
Uranium
Thorium
Bismuth
Lead
Thallium
Gold
Rhenium
Tungsten
Tantalum
Hafnium
Lutetium
Ytterbium
Thulium
Erbium
Holmium
Dysprosium
Terbium
Gadolinium
Europium
Samarium
Neodymlum
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Tellurium
Antimony
Tin
Indium
Cadmium
Silver
CYCLONE DUST
(yg/g)
45
97
3
230
22
<0.1
842
18.7
>28.1
MC
>93.5
-V187
0.56
0.37
65.5
600
51
600
86
600
69
86
514
1715
17
4286
MC
514
171
60
MC
429
600
257
3429
43
MC
MC
MC
MC
3429
1715
>4286
MC
MC
^857
257
1.7
51
Trace Elements by SSMS
MC " Major Component Concentration >1000 yg/g for cyclone dust (Ref. 10)
MC - >9,350 yg/g for particulate* >3 ym (Ref. 47)
INT • Interference
STD - Standard
MC - >85,700 yg/g for
particulates <3 ym
(Ref. 47)
-------
TABLE 3.7-10.
RADIOACTIVE DISINTEGRATION FOR THE
CYCLONE DUST FROM THE GLEN-GERY
WELLMAN-GALUSHA GASIFICATION
FACILITY*
Parameter
Value
CpCi/g)
Gross ex emissions
Gross 3 emissions
280 ± 20
1120 ± 40
*Anthracite Coal Feedstock
Source: Ref. 10
TABLE 3.7-11.
EXTRACTABLE ORGANICS FOUND IN THE
CYCLONE DUST FROM THE GASIFICATION
OF ANTHRACITE AND LOW-SULFUR
BITUMINOUS COALS
Anthracite
Low-Sulfur
Bituminous
Total Concentration of
Extractable Organics, yg/g
Compounds Identified, yg/g
Anthracene/Phenanthrene
Fluorene
Naphthalene
Bis - (2-Ethylhexyl) Phthalate
Di-N-Butyl Phthalate
Diethyl Phthalate
Adipate Esters
Phthalate Esters
625
.1
.1
0.
0.
0.4
2.0
0.2
0.2
40
3.0
3.0
9.0
-: Not Detected
Source: Ref. 10
Source: Ref. 13
184
-------
TABLE 3.7-12. TRACE ELEMENT CONCENTRATIONS IN THE CYCLONE
DUST LEACHATE FROM THE GASIFICATION OF
ANTHRACITE COAL
Trace
Element
Al
Sb
Ba
Be
B
Cd
Ca
Ce
Cs
Cl
Cr
Co
Cu
F
Zn
Concentration
Cpg/ml)
2
0.03
0.7
0.003
0.7
0.005
> 10
0.01
0.002
> 10
O.OOA
0.3
0.09
>10
>10
Trace
Element
I
Si
Fe
La
Pb
Li
Na
Mg
Mn
Hg
Mo
Nd
Ni
Nb
P
S
K
Pr
V
Sc
Y
Ag
Zr
Tl
Ti
U
Concentration
(pg/ml)
0.1
2
1*
0.008
0.7
0.5
>4
7
>10*
<0.0005
0.07*
0.005
Int
0.002
0.3
>10
>10
0.002
0.002*
<0.002
0.004
0.002
0.004
<0.001
0.2
<0.01
-------
Eioassay test results for the cyclone dust from gasifica-
tion of anthracite and low-sulfur bituminous coals are given in
Table 3.7-13. These results indicate that the dust from an-
thracite coal gasification has a low potential for health effects
while the dust from low-sulfur bituminous coal gasification may
have moderate effects. The results of the soil microcosm tests
were not comparable. The dust for the anthracite case had lower
toxic effects than the ash while the dust had higher effects than
the ash for the bituminous case.
Recovered Sulfur -
The H2S removed from the low-Btu product gas and con-
verted into elemental sulfur in the Stretford unit is treated as a
waste stream. This is because the facility sizes examined in this
study do not produce enough sulfur to warrant purification to make
a salable by-product. The sulfur is disposed of as a wet cake
containing about 50 percent water. It also contains some of the
chemicals from the Stretford solution. The cake is washed (with
one or more displacement washes) to recover most of these chemi-
cals, but some are still retained with the cake. Few data are
available on the degree of cake washing efficiency, but according
to one reference (Ref. 48) 96 to 97 percent of the chemicals are
recovered with three displacement washes. More salts would
probably be left in the sulfur cake if less wash water were used.
For the cases considered in this report, the liquor remaining with
the cake will have about 1.0 to 8.5 percent total dissolved solids
(TDS) consisting mainly of sodium thiocyanate and sodium thiosul-
fate along with smaller amounts of NaHCC^, Na2CC>3, ADA,
iron, and EDTA. If the sulfur cake is not washed, it will contain
as much as 25 percent TDS. The sulfur cake may also contain small
amounts of tar picked up from the gas in the absorber. The sulfur
cake will probably have less than 2 percent tar. The amounts of
sulfur cake produced from cleaning gas from the four coal feed-
stocks are given in Table 3.7-14.
MEA Acid Gas Removal Blowdown -
In acid gas removal plants using the MEA process, degra-
dation products and sludge are commonly removed by the semi-
continuous steam distillation of a small side stream of stripped
MEA solution. The high-boiling degradation products and sludge
are then drained from the reclaiming kettle and disposed of.
Table 3.7-15 presents estimates of the blowdown from MEA systems
treating low-Btu gas from the gasification of 3.9 percent sulfur
coal. The stream has not been characterized, but it includes de-
composition products such as dithiocarbamates, thioureas, salts of
thiosulfuric acid and formic acid, oxazolidone-2, l-(2-hydrox-
eyth!) i™idazolid°ne-2, and N-(2-hydroxyethel)-ethylenediamine
(Ref. 16).
186
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TABLE 3.7-13. BIOASSAY TEST RESULTS FOR THE
CYCLONE DUST FROM THE GASIFI-
CATION OF ANTHRACITE AND LOW-
SULFUR BITUMINOUS COALS
Test
Ames
RAM, EC-50 (ug dust/ml culture)
RAT
• Toxlcity response
. LD-50
Soil Microcosm (Toxicity ranking)
Anthracite3
Negative
>1000
Low
> 10
Second
Low-Sulfurb
Bituminous
Negative
>1000
Moderate
> 10
First
EC-50: Concentration at which growth was 50 percent of control
LP-50: Dose per kg test animal at which 50 percent died.
Moderate toxic response: rates showed hair loss, eye discoloration, etc.
Soil microcosm toxicity rankings were:
Response
High
4-
Low
Anthracite
1 - ash
2 - cyclone
dust
Low- Sulfur
Bituminous
1
2
3
4
5
- cyclone dust
- tar
- coal
- ash
- Quench
Liquor
aSource: Ref. 10
bSource: Ref. 13
187
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TABLE 3.7-14. BY-PRODUCT SULFUR FROM STRETFORD PROCESS3
Sulfur Cake Production
Coal Feedstock kg/s (Ib/hr)(50% Sulfur)
Low Sulfur 0.009 (70)
Bituminous
High Sulfur 0.06 (500)
Bituminous
Anthracite 0.008 (60)
Lignite 0.02 (150)
*For a gas production of 17.6 MW (60 x 106 Btu/hr)
188
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TABLE 3.7-15. ESTIMATED SLOWDOWN FROM MEA
ACID GAS REMOVAL PROCESS3
Specification Quantity
Combustion Gas° 0.002 Kg/s (13 Ibs/h)
Clean Gasd 0.002 Kg/s (13 Ibs/h)
aMEA process treats gas from gasification of 3.9% sulfur coal to
produce 17.6 MW (60 x 106 Btu/hr) of low-Btu gas.
These quantities are gross estimates of the blowdown from MEA.
systems. The blowdown includes degradation products, particulates,
and sludge. This stream would be smaller for other ethanolamine
systems, since those systems are not degraded by organic sulfur
species such as COS. The other systems are also not as easily
degraded by oxygen and carbon dioxide. About half of the blowdown
is due to degradation products of COS. Water added to the
purification kettles for cleaning is not included in the estimate.
The estimates assume that 20% of the organic sulfur species and
nearly all of the HCN react with MEA to form non-regenerable
compounds.
cGas is cleaned to meet combustion emission limit of 86 ng SOz/J
(0.2 Ib S02/106 Btu).
Gas is cleaned to 4 ppmv HaS, 10 ppmv total sulfur.
Source: Refs. 16, 49
189
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SECTION 4.0
PERFORMANCE AND COST OF CONTROL ALTERNATIVES
This section addresses the control alternatives for the
multimedia waste streams and toxic substances associated with
Wellman-Calusha low-Btu gasification facilities. Regional con-
siderations affecting the selection of control alternatives and
cost/energy usage tradeoffs for various controls are also
presented.
4.1 PROCEDURES FOR EVALUATING CONTROL ALTERNATIVES
Control alternatives for Wellman-Calusha gasification
plant waste streams were selected using the following procedures.
First, target levels of desired control for each waste stream
were obtained. Next, candidate control alternatives were identi-
fied. Finally, the proposed alternatives were evaluated.
Potential control levels were determined by assessing
the potential environmental impacts of each waste stream. These
impacts were assessed by comparing waste stream pollutant concen-
trations to appropriate target values (limits imposed by current
regulations in related applications). These assessments are dis-
cussed in Section 5.0.
For the most part, control alternatives for gasification
plant waste streams were identified from the literature or
through expert contacts, although engineering judgement was used
to suggest several additional alternatives. All proposed control
alternatives were then compared with respect to the following
criteria:
applicability,
control effectiveness,
stage of development,
secondary emissions,
energy and material requirements,
capital and operating costs, and
operating reliability.
4.2 AIR EMISSIONS CONTROL ALTERNATIVES
This section discusses alternatives for the control of
air emissions from Wellman-Galusha low-Btu coal gasification
facilities. Alternatives for the control of the following emis-
sions are considered:
190
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fugitive dust emissions from coal handling and
storage,
coal feeding system vent gases,
ash removal system vent gases,
start-up emissions,
fugitive emissions and pokehole gases,
fugitive emissions from particulate removal
equipment,
gas from tar/quench liquor separation,
MEA unit acid gas stream,
Stretford oxidizer vent gas, and
Stretford evaporator vent gas.
A.2.1 Coal Preparation and Handling
Coal dust emissions from storage and handling will vary
from site to site, depending primarily on wind velocities and
coal properties. These emissions are not quantified in this
report since available suppression and collection techniques, if
used, appear to be adequate in controlling these emissions.
Asphalt and various polymer coatings have been used to
control dust emissions from coal storage piles, with typical con-
trol efficiencies of about 80 percent. By using covered bins,
coal dust emissions can be suppressed almost totally. Water
sprays and enclosed equipment are commonly used to control coal
handling emissions, with typical efficiencies of 50 percent and
80 percent, respectively. Dust-laden air from coal conveyors can
be routed to the gasifier inlet air line, or transported to
cyclones, baghouses, scrubbers, or electrostatic precipitators
for dust removal. The costs of these controls are quite small
compared to the cost of producing the low-Btu gas. Chemical
fixation of storage piles with asphalt or polymers, for example,
cost $20 to 55 per Gg (1000 metric tons) processed (Refs. 23,
50), or less than $0.01/GJ of low-Btu gas.
4.2.2 Gasification
Coal Feeder Vent Gas -
The composition of the coal feeding system vent gas will
be very similar to that of the major gaseous species in the raw
product gas. Minor species in the raw product gas (NH3, HCN,
HoSj anc* organics) may condense on the coal before exiting the
coal feed hopper. Because this stream will contain high concen-
trations of a number of toxic materials, it can be hazardous to
plant workers. The stream can be collected in a hood and subse-
quently routed to the gasifier inlet air line, or incinerated.
191
-------
A potential problem associated with either of these approaches is
caused by the potential presence of tar aerosols in the raw gas
which can condense and coat the collecting hood and other down-
stream equipment.
Because of its relatively small flow rate, the coal
feeder vent gas stream can be collected and transported to the
gasifier inlet air with negligible impact on the cost of the
low-Btu gas (estimated at less than $0.01/GJ of product gas).
Generally coal feeding vent gases will be too small to
justify a dedicated combustion device (incinerator or flare). If
such devices are provided for other streams, the coal feeder vent
gas could be disposed there. Currently, coal feeding gases are
emitted without controls.
Ash Removal Gas -
No measured data are available on the flow rate or com-
position of this stream. However, emission controls may not be
required due to its suspected low volume and anticipated nontoxic
nature.
Start-Up Emissions -
Because of the magnitude of this stream, it must be con-
sidered a major emission despite the fact that it is produced
intermittently. The stream can be controlled by using a flare to
burn the combustible constituents. Heavy tars and coal particu-
lates in this stream can affect the performance of the flare.
Problems with tars and coal particles can be minimized by using
oil, charcoal, or coke as the gasifier start-up fuel. Use of any
of these as the start-up fuel will also reduce the emission of
sulfur compounds. Costs of a start-up gas incineration system
have not been estimated but are expected to be small.
Fugitive Emissions and Pokehole Gases -
Pokehole gases and other fugitive emissions can be re-
duced by establishing proper inspection and maintenance schedules
for valves and flanges.
4.2.3 Gas Purification
Fugitive Emissions from Particulate Removal Equipment
Emissions from cyclones used for bulk particulate re
moval mainly consist of leaks from the cyclone's water seal o
pokeholes. Characterization data on these emissions are very
192
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scarce. Again, sound maintenance programs can be used to minim-
ize these emissions.
Gas from Tar/Quench Liquor Separator -
Gaseous emissions from the tar/quench liquor separator
will consist of volatile organic and inorganic compunds that have
been scrubbed from the raw product gas in the quenching and cool-
ing processes. In the separator some of the absorbed and en-
trained gases and vapors will desorb from the quench liquor and
fill the vapor space above the liquor. In removing these gases
from the separator, additional vapors may be stripped from the
quench liquor. These vapors can be released directly to the
atmosphere, recycled to the gasifier inlet air line, combined
with the cooled product gas, or combusted. If vapors are re-
leased directly to the atmosphere, they must be dispersed to re-
duce concentrations of potentially harmful components at ground
level. However, this may not be an acceptable approach.
Recycling the separator gases to the gasifier inlet air
should be an effective control approach although some of these
oases could escape to the atmosphere along with the gasifier ash.
While specific effects of recycling the separator gas to the
gasifier inlet air have not been determined, slight adjustments
in the amounts of steam and air fed to the gasifier may be re-
quired. And since the recycled gas contains nitrogen compounds,
a portion will be combusted to form NOX in the combustion zone
of the gasifier. Therefore the concentration of NOX, as well
as NH3 and HCN, in the product gas could be increased.
Because of the separator gas stream's relatively small
size, it can be recycled with negligible impact on the cost of
the low-Btu gas. Recycling also avoids the cost of a system
/e.g., a tall stack) for dispersing the gas. However, specific
effects and operating characteristics of recycling have not been
determined.
Combining the separator gases with the product gas also
increases the concentrations of nitrogen compounds in the product
gas. Certain of these compounds (HCN for example) can affect the
design and operation of a sulfur removal process. (Costs estima-
ted in this report for sulfur removal systems are based on sys-
tems containing these nitrogen compounds.) Again, the costs of
this control alternative are insignificant when compared with the
cost of the low-Btu gas. In comparison to the alternative of re-
cycling the gas to the inlet air, the alternative of combining
separator and product gases involves smaller expenses for duct-
work but possibly higher compression requirements. This latter
193
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control alternative will also not affect the operation of the
gasifier. This method is feasible however, only if the separator
gases are not diluted by in-leakage air.
The separator gases could also be combusted in an on-
site boiler or incinerator. The flow rate is probably too small
to justify a separate combustion device dedicated solely to this
stream. And, if incineration is chosen, the energy value of the
separator gas is lost. This control alternative has no advantage
over combining the separator gases with the product gas unless
the separator gases are diluted by in-leakage air.
MEA Acid Gas -
The Glaus and the Stretford processes appear to be the
processes best suited for treating the acid gas stream from the
MEA absorption unit. These processes are compared in the
following text.
Glaus - In the Glaus process, H£S in the gas stream is
catalytically reacted with S02 to recover elemental sulfur.
The required SC>2 is produced by first combusting a portion of
the H2S in a reaction furnace. A simplified flow diagram of
the process is shown in Figure 4.2-1. For gas streams with low
H2S concentrations, like the MEA acid gas stream, the split
stream configuration is used. In this configuration, one-third
of the gas stream is fed to the furnace and its sulfur content
completely combusted to S02» For higher H2S concentrations,
the entire gas stream is fed to the furnace along with just
enough air to combust one-third of the H?S to S02« This is
the partial combustion configuration. After combustion, the
remaining t^S is reacted with the SC>2 over a bauxite catalyst
at 530 to 590 K (500 to 600°F) to produce elemental sulfur,
according to the following reaction:
2H2S + S02 2H20 + 3S + heat
Because this is a reversible reaction, equilibrium constraints
limit the conversion. Lower temperatures favor elemental sulfur
formation. However, at too low a temperature, the catalyst will
become fouled by condensed sulfur. Because the above reaction is
exothermic, the fractional conversion achievable in one stage is
limited to about 80 percent in most systems. Therefore, two or
more reactors are used in series in most applications with inter-
stage cooling to remove the heat of reaction and condense the
sulfur. Condensing the sulfur improves conversion by decreasing
the sulfur back pressure (Refs. 23, 24).
194
-------
SULFUR
CONDENSER
vO
Ul
CATALYTIC
CONVERTER
CATALYTIC
CONVERTER
f. TAIL GAS
NOTES: SOLID LINES INDICATE FLOW PATHS
FOR PARTIAL COMBUSTION PROCESS
CONFIGURATION
DASHED LINE INDICATES ADDITIONAL
STREAM PRESENT IN THE SPLIT
STHEAM PROCESS CONFIGURATION
* ADDITIONAL CONVERTERS/CONDENSERS
TO ACHIEVE ADDITIONAL RECOVERY OF
ELEMENTAL SULFUR ARE OPTIONAL AT
THIS POINT
SPENT CATALYST
SULFUR
Source: Ref. 23
Figure 4.2-1. Typical Flow Diagram - Glaus Sulfur Recovery Process
-------
The sulfur recovery efficiency of a Glaus plant depend
on several factors. These include the following:
• number of catalytic stages,
• inlet gas composition,
• operating temperatures and catalyst maintenance,
• maintenance of proper H2S/S02 ratio, and
• operating capacity factor.
The sulfur recovery efficiency decreases with decreasing
concentration in the feed gas. For example, the recovery effi-
ciency for a Glaus plant with 2 or 3 catalytic stages may be
about 95 percent for a gas stream containing 90 percent H£S, 93
percent for a 50 percent H2S stream and only about 90 percent
for a 15 percent H2S stream (Ref. 46). Contaminants such as
hydrocarbons, carbon dioxide, and ammonia in the feed gas also
reduce the Glaus efficiency (Ref. 51). The efficiency of a two-
stage Glaus plant treating an acid gas stream from an MEA absorp-
tion unit applied to the treatment of a gas stream generated by
gasifying high-sulfur coal (this acid gas stream might contain 16
to 19 percent H2S) may be only 75 to 80 percent (Ref. 52).
Because of the low recovery efficiency of a Glaus plant,
the tail gas contains high concentrations of sulfur compounds.
For 80 percent sulfur recovery, the tail gas from a 16 to 19
percent H2S feed stream may contain roughly 20,000 ppmv of
sulfur compounds, mostly 112$ anc* S02 (in roughly a 2:1
ratio), along with smaller concentrations of organic sulfur. In
the past, Glaus plant tail gases were incinerated and vented to
the atmosphere. Tail gas treatment is now generally required.
For example, new federal standards for Glaus plants, effective
March 1978, limit the concentration of SC-2 in tail gases from
petroleum refinery Glaus plants to 250 ppmv. Glaus plants
producing less than 20.3 Mg (20 long tons) per day of sulfur and
located in small refineries are exempt from the regulation.
Tail gas treatment processes fall into three categories:
1) extension of the Glaus reaction,
2) conversion of sulfur compounds to SC>2 , followed by
S02 removal, and
3) conversion of sulfur compounds to H2S, followed by
H2S removal.
Processes in the first category include the IFP-1, Sulfreen, and
Amoco CBA processes (Refs. 35, 46). Removal with these processes
are limited, however, so that about 1500 to 2500 ppmv of sulfur
compounds remain in the tail gas (Refs. 35, 53, 54).
196
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Processes in the other two categories of tail gas
treatment are more effective. With these processes, sulfur
concentrations in the tail gas of less than 250 ppmv can be
achieved (Ref. 35). Processes in the second category involve
incineration of the tail gas to convert all sulfur compounds to
S02 followed by removal of SC>2 from the incinerated tail gas.
Various S02 removal processes, such as the Wellman-Lord are
suitable for treating incinerated tail gas (Ref. 46).
In processes in the third category, the tail gas is
mixed with a reducing gas and passed over a reducing catalyst
(such as cobalt/molybdenum) to convert the sulfur compounds to
HoS. The H2S is then removed. This H2S removal is accom-
plished by a Stretford unit in the Beavon process, or by an amine
scrubber in the SCOT process. The Stretford converts the H2S
directly to sulfur, while the amine produces a rich t^S stream
which is recycled to the Glaus plant (Ref. 46).
The Glaus process has been used extensively for recover-
ing sulfur from H2S rich streams in refineries and natural gas
plants (Ref. 24). The Glaus process is best suited for treating
gas streams with H2S concentrations greater than about 10 to 20
percent, but with certain modifications, it can also be used on
lower H2S streams. At low H2S levels, however, other pro-
cesses (such as the Stretford) are generally more economical than
the Glaus (Refs. 23, 24, 55, 56).
Stretford - The Stretford process, as discussed earlier
in this report, directly oxidizes H2S in the acid gas stream to
sulfur. A system designed to treat the acid gas stream will be
somewhat different than those discussed previously for treating
the low-Btu gas directly. Because of the higher H2S content of
the inlet gas, a spray tower or venturi may be required before
the packed tower to remove the bulk of the H2$ and prevent
plugging of the packing with elemental sulfur (Ref. 16). In
addition, the high C02 content of the gas lowers the pH of the
scrubber liquor and, consequently, reduces mass transfer rates.
Because of this reduced mass transfer, the F^S absorbers in
gasification plants will be much taller than those required to
treat gases with low concentrations of C02 (Ref. 16).
Assessment - The Stretford process should probably be
used for treatment of the acid gases from the anthracite, low-
sulfur bituminous, and lignite coals because the F^S content of
these streams is too low to make treatment by the Glaus process
197
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economical. However, a selective ethanolamine process, such as
MDEA, could produce an acid gas suitable for treatment with the
Glaus process. Either the Stretford or the Glaus process could
be used to treat the acid gas from high-sulfur bituminous coal.
With tail gas treatment, the Glaus tail gas sulfur concentration
can be reduced to 250 ppmv or less. The Stretford process can
reduce the H2S in the tail gas to 10 ppmv or less (Ref. 57).
The cost of the Stretford process may be somewhat less than the
cost of the Glaus process with tail gas treatment (Refs. 56, 58),
Costs for the Stretford and Glaus processes are summarized in
Table 4.2-1. These costs describe the treatment of an acid gas
from an MEA process resulting from the purification of a high-
sulfur coal gas. The Glaus plant cited is a two-stage unit
without tail gas treatment. Some vendors recommend the Glaus/
tail gas system over the Stretford for H£S levels of 20 percent
or greater (Refs. 55, 58). If the 75 to 90 percent removal
efficiency of the Glaus plant alone would be acceptable, with the
tail gas incinerated, the Glaus plant would be much cheaper than
the Stretford (Ref. 55). However, this alternative will probably
not be environmentally acceptable. Thus, the ultimate choice
between the Stretford and the Glaus/tail gas processes will have
to be made on an application-specific basis.
Stretford Oxidizer Vent Gas -
As discussed in Section 3.5.3, the Stretford oxidizer
vent gas consists mostly of air and water vapor. Because the
concentrations of pollutants in this stream are expected to be
low, no controls should be required for the oxidizer vent.
Stretford Evaporator Vent Gas -
As discussed in Section 3.5.3, the Stretford evaporator
vent gas is a small stream which consists mostly of water vapor.
No control should be required for this stream.
4.3 WATER EFFLUENT CONTROL ALTERNATIVES
This section discusses the control of water effluents
from Wellmna-Galusha gasification facilities. Alternatives for
the control of the following effluents are discussed.
• water runoff from coal storage,
• ash sluicing water,
• process condensate, and
• blowdown from the Stretford process.
198
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TABLE 4.2-1. COSTS FOR STRETFOKD AND GLAUS PROCESSES
TREATING AN ACID GAS PRODUCED FROM THE
PURIFICATION OF A HIGH-SULFUR COAL GAS
Treatment Process r> • *. -i n *. A i • j o *. a
- Low-Btu Gas Production Rate Capital Costs Annualrzed Costs
Stratford
• 15 MW (50 x 106 Btu/h) $1.9-2.9 millionb $1.2-$1.6/GJ
• 74 MW (250 x 10s Btu/h) $3.3-5.1 million0 $0.60-$0.8/GJ
Glaus w/o Tail Gas Cleanup
• 15 MW (50 x 106 Btu/h) $1.2-1.3 millionb $0.5-$0.6/GJ
• 74 MW (250 x 10s Btu/h) $1.9-2.1 million0 $0.2/GJ
aAnnualized costs include operating costs, capital charges ? 14% of capital costs
and maintenance @ 5% of capital costs; annualized costs are expressed as increased
gas costs.
^Range of estimates from vendors.
GExtrapolated from vendor costs.
Source: References 55, 59, 60
-------
4.3.1 Coal Preparation and Handling
Runoff from coal storage piles or uncovered bins may
contain a variety of leached organic and inorganic constituents.
The composition and flow rate of this stream is very site-
specific and therefore is not characterized in detail in this
report.
Leaching from rainfall and/or water sprays can be
suppressed with polymer spray coatings. Alternately, runoff
water can be collected in ditches and then reused as spray water
or ash sluice water. Costs for these controls are quite small
compared to the costs of the low-Btu product gas.
4.3.2 Gasification
Selection of a treatment method for the ash sluice water
depends on the quantity and quality of this stream, both of which
are highly variable. The amount of sluice water used is gener-
ally not well controlled. The composition of the sluice water
depends on the characteristics of the gasifier ash, and on the
quality of the inlet sluice water. If plant service water is
used for ash sluicing, the sluice water may be of a quality
suitable1 for discharge into the plant sewer system. However,
concentrations of suspended solids, various trace elements and
other components (such as SCN~ and CN~) in the sluice water
may be too high to allow discharge into a sewer. As discussed in
Section 5.3, effluent limitations and Discharge Severity (DS)
values were exceeded in the ash sluice water stream sampled at a
Wellman-Galusha gasifier using anthracite coal (Ref. 10).
If the sluice water cannot be discharged, it can be col-
lected and recycled to the ash removal step. Suspended solids
could be allowed to settle by gravity from the sluice water be-
fore it is recycled. The amount of sluice water that remains
with the disposed ash may provide a sufficient blowdown to pre-
vent excessive buildup of suspended or dissolved solids.
If the ash were ponded, the sluice water could be dis-
charged to the pond along with the ash. However, the ash will
probably be landfilled rather than ponded (see Section 4.4.2).
4.3.3 Gas Purification
Process Condensate -
Principally four options exist for the treatment and
disposal of process condensate from Wellman-Galusha gasification
facilities. These are:
200
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• treatment in wastewater facilities located on-site,
• containment on-site with transport to facilities
located off-site,
• evaporation on-site, and
• evaporation and combustion on-site.
Each of these options are discussed here; costs are provided for
the second and third control options.
The principal contaminants in the process condensate are
organic compounds (such as glycols, carboxylic acids, thiols,
phenols, and fused aromatic hydrocarbons), nitrogen compounds
(such as heterocyclic nitrogen compounds, ammonia, and hydrogen
cyanide), and compounds containing phosphorous, arsenic, and
selenium. These compounds are found in concentrations which are
significantly larger than water quality standards and DS values
(see Section 5.1.2 for explanation of DS values).
On-Site Treatment Facilities - If complete wastewater
treatment facilities with excess capacity are already available
on-site, the effluent stream might be treated at low cost. How-
ever, users of small gasification facilities are not likely to
have extensive wastewater treatment facilities.
Off-Site Treatment Facilities - Because the condensate
stream flow rate is relatively small, it could be contained on-
site and subsequently shipped to off-site hazardous wastes treat-
ment facilities. This control alternative avoids the need for
expensive treatment facilities on-site, and takes advantage of
the economics of scales provided by large treatment facilities.
A typical hazardous wastes facility has a broad treat-
ment capability for both hazardous and non-hazardous wastes.
Typical process operations inlcude:
neutralization of acids and bases,
oxidation of cyanides and other reductants,
reduction of chromium VI and other oxidants,
precipitation of heavy metals,
separation of solids from liquids,
removal of organics,
incineration of combustible wastes,
removal of ammonia, and
disposal of waste brines.
201
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Wastes processed at the facility can be segregated and processed
accordingly. Sludge from the facility is secured in sanitary
landfills (Ref. 61).
Costs for the containment and treatment of process con-
densate are based on escalated average treatment costs reported
by Battelle (Ref. 61). These costs are shown in Table 4.3-1.
While very expensive, these costs are less than those for simi-
larly constructed small facilities located on-site. If a large
waste treatment facility were located on-site, the costs (shown
in Table 4.3-1) would be lowered by 10 to 20 percent due to the
elimination of transportation costs.
Evaporation - An alternative to costly treatment
processes is evaporation. This option features the elimination
of the condensate effluent by reducing it to a concentrated brine
or sludge. The process is not as effective in limiting secondary
multimedia emissions as the first two options, since volatile
organic and inorganic compounds can be released to the atmosphere
from the evaporator. This type of secondary emission stream has
not been characterized in detail, but it will contain ammonia,
hydrogen sulfide, and other volatile compounds found in the
quench liquor.
Costs for the evaporation of the process condensate are
shown in Table 4.3-2. These costs are significantly lower than
those for hazardous wastes treatment (off-site). However, secon-
dary emissions from evaporation can be a problem. Sludge from
the evaporator will mainly consist of the heavier organic com-
pounds and metals, and can possibly be disposed of with the tars
from the separator.
Evaporation/Incineration - A final control option is
evaporation and incineration of the condensate. Combustion may
occur in modified boilers or submerged combustion evaporators.
In this control option, high-boiling organics are incineratesd
and water is evaporated in a flame. Energy to ignite the
combustibles and evaporate water is supplied by combustion of a
gaseous fuel (for instance, low-Btu gas). In submerged
combustion, the combustion produces heat and evaporates some of
the water. High-boiling organics are thus concentrated in the
unevaporated water, which are then injected into a flame.
In both submerged combustion evaporators and boilers,
the mixture of air, water, and fuel needs to be within flam-
ability zones. In practice, air and fuel are first ignited
alone. After ignition, the concentrated wastes are atomized into
the flame. Injection of the wastes directly into the flame is
202
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TABLE 4.3-1
COSTS FOR THE CONTAINMENT AND TREATMENT OF
PROCESS CONDENSATE IN A CENTRALLY-LOCATED
HAZARDOUS WASTE TREATMENT FACILITY3
Coal Type/Sulfur Removal Process0
Costs, $/GJ ($/106 Btu)b
Medium-Size Treatment Facility0
Large-Size Treatment Facility
High sulfur
• Stretford
• MEA
• MEA (stringent sulfur removal)
0.59 (0.62)
1.32 (1.39)
1.69 (1.78)
0.40 (0.42)
0.88 (0.93)
1.16 (1.22)
N>
o
Lignite
• Stretford
2.01 (2.12)
1.43 (1.36)
facilities treat both hazardous and non-hazardous wastes.
Costs in 4th quarter 1977 dollars.
°0perating parameters are defined in Sections 2 and 3.
dMedium-size facility processes a total of 0.0053 m3/s (122,000 gpd); large size facility processes
0.044 m3/s (1,000,000 gpd). Wastes are transported 800 km (500 miles) to medium-size facility;
1600 km (1000 miles) to large-size facility.
Source: Reference 61.
-------
TABLE 4.3-2.
COSTS FOR THE EVAPORATION OF PROCESS CONDENSATE
IN SINGLE-EFFECT VERTICAL TUBE EVAPORATORS
to
o
Capital Operating
Coal Type/ Gasification Facility Costs, Capital and Maintenance Costs,
Sulfur Removal Process Size, MW (106 Btu/h) $b Charges, $/GJb'c $/GJb»c
High-Sulfur Bituminous
• Stretford
• Stretford
• MEA
• MEA
• MEA (stringent sulfur
removal)
• MEA (stringent sulfur •
removal)
Lignite
• Stretford
• Stretford
17.6 (60)
87.9 (300)
14.2 (48.3)
70.9 (242)
15.1 (51.6)
75.6 (258)
17.6 (60)
87.9 (300)
43,000
102,000
58,000
139,000
70,000
165,000
83,000
194,000
0.02
0.01
0.03
0.01
0.03
0.01
0.03
0.01
0.05
0.05
0.11
0.11
0.15
0.15
0.17
0.17
Total
Annualized
Costs, $/GJb
0.07
0.06
0.14
0.12
0.18
0.16
0.20
0.18
Facility size based on heating value of cooled and scrubbed gas.
'Costs in 12/77 dollars. Costs of exchangers estimated from steam usage, overall heat transfer
coefficient, and mean temperature difference.
"Capital charges (depreciation and taxes) computed at 16% of the capital costs per year; maintenance
costs calculated at 3% of capital costs per year. Gasification facility operates 7884 hours per year.
Steam costs assumed to be $2.35/GJ ($2.30/1000 Ibs.).
Sources: References 62, 63, 64
-------
usually required since hot combustion products alone may not
completely pyrolyze the heavy organics, especially in submerged
combustion evaporators (Ref. 65).
Although combustion/incineration converts organics to
CO? an<3 H2°> anc^ disposes of the condensate (especially in
submerged combustion evaporators), some volatile compounds may
simply be volatilized. Boilers used for this function may be
derated and require some modification. Submerged combustion
evaporators are likely to have capital costs similar to those for
vertical-tube evaporators. However, energy requirements are much
higher for submerged combustion since some of the water must be
heated to the combustion temperature of the organic compounds.
Stretford Slowdown -
In the past, the liquid blowdown from the Stretford pro-
cess was considered innocuous, and the effluent was generally
discharged to municipal sewers. In the future, however, it is
doubtful that this stream could be discharged without treatment.
Various processes have been proposed to treat this stream. These
fall into three general categories:
• treatment and discharge of blowdown,
• regeneration of blowdown, and
• pretreatment to reduce size of blowdown.
These and other treatment alternatives for the Stretford blowdown
are discussed below.
Treatment and Discharge - Processes involving treatment
and discharge of blowdown include biodegradation, evaporation,
and oxidative combustion. In biodegradation, bacteria are used
to convert thiocyanate and thiosulfate ions in the effluent to
biologically nontoxic forms. Tests of Stretford effluents have
indicated that complete detoxification can be achieved if 1) the
concentrations of the thiocyanate and thiosulfate ions are less
than 1000 ppm and 500 ppm, respectively, 2) the pH is maintained
betwewen 6.0 and 7.5, and 3) the temperature is kept between 20
and 25°C.
Evaporation of the blowdown by spray drying yields cry-
stals and solids that reportedly can be disposed of by landfill
if the thiocyanate concentration of the blowdown is low. If so-
dium thiocyanate is present, as it would be for the systems con-
sidered in this assessment, further treatment of the solids would
be required before disposal (Ref. 30).
205
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Oxiclative combustion of Stretford blowdown with an
excess of air yields a solid residue of sodium sulfate with
traces of vanadium. Spray of an alkaline solution into the flame
may be necessary to neutralize the sulfur dioxide formed and can
represent a substantial operating cost. Capital costs for
combustion are reportedly higher than those for biodegradation or
evaporation; operating costs may also be higher because of the
alkali required (Refs. 30, 66).
Sodium thiosulfate in the blowdown can be converted to
sodium sulfate by the addition of sulfuric acid. The sodium sul-
fate can then be recovered by crystallization. However, this
treatment method may not be feasible for blowdown streams con-
taining thiocyanate (Ref. 25).
These treatment processes have two major disadvantages.
They all require ultimate disposal of a waste stream, and they
also decompose the sorbent solution.
Regeneration - In a regenerative process, blowdown is
treated and returned to the system. The requirement for ultimate
disposal of a waste stream is thus eliminated, and chemical make-
up requirements are decreased.
The most promising regeneration method involves reacting
the blowdown liquor at a high temperature under reducing condi-
tions. A reducing atmosphere is obtained by the substoichiomet-
ric combustion of gas (low-Btu product gas could be used) or fuel
oil. Under these conditions, the blowdown is cracked into a li-
quid stream containing reduced vanadium salts and a gas stream
containing H2S and CC>2. The gas is recycled to the Stretford
absorber. Thiocyanate and thiosulfate salts are converted large-
ly to H2S and Na2C03. The vanadium can be recovered in
solid form, along with sodium carbonate, sodium sulfide, and some
sodium sulfate. These solids can be redissolved and recycled to
the absorber. Thus no make-up of sodium or vanadium salts is
reportedly required. For the systems assessed in this report,
however, a small amount of make-up would be required to replace
salts lost in the filter cake (Refs. 25, 26, 27, 66, 67).
Regeneration processes based on this concept have been
developed by Peabody Holmes (reductive incineration), Woodall
Duckham (high temperature hydrolysis), and NCE Corporation.
Capital costs for the Woodall-Duckham high temperature hydrolysis
206
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process treating effluent from a 20 m3/s (60 x 106 scfd)
Stretford unit have been estimated at about $650,000 (1974 dol-
lars) or about 20 percent of the capital cost of the Stretford
without such treatment (Ref. 66). Capital costs for treating
blowdown from a 55 m3/s (168 x 106 scfd) plant by the NCE
process have been reported at $1.2 million (1973 dollars,
Japanese location) (Ref. 67). Operating cost data are unavail-
able. Fuel gas requirements for the Peabody reductive inciner-
ation process have been reported to be 100 kW (0.34 x 10^
Btu/hr) per ton per day of sulfur recovered. The fuel gas re-
quirement would be dependent on the amounts of thiocyanate and
thiosulfate in the blowdown treated.
Regeneration of the Stretford blowdown by selective re-
moval of thiocyanate has been investigated by Ontario Liquid
Waste Disposal Limited and DOFASCO (Dominion Foundry and Steel
Ltd.) (Ref. 66). The use of carbon adsorption and ion exchange
processes to recover ADA and vanadium salt from Stretford waste
liquor have also been investigated (Ref. 68).
Pretreatment - When gases containing HCN are treated by
the Stretford process, the size of the blowdown stream can be
substantially reduced by removing HCN from the gas before the
Stretford absorber. This can be done by a polysulfide wash, in
which HCN removals of greater than 95 percent have been achieved
(Ref. 66). Aqueous wastes from the process contain high concen-
trations of thiocyanate, polysulfide, ammonia, hydrogen sulfide,
and elemental sulfur, and should be treated prior to disposal
(Ref. 66). The effluent can be treated by combustion (as discus-
sed earlier). Conversion of the thiocyanate to carbonate or to a
mixture of ammonium sulfate and carbon dioxide with sulfuric acid
may be feasible. The applicability of this treatment depends on
solving problems such as treatment of offgases containing COS and
design of vessels to resist acid and salt attack. Catalytic hy-
drogenation of the wastes to form HN3, H2S and CO which would
be recycled to the Stretford absorber has been proposed, but
apparently has not been developed. Addition of the polysulfide
wash alone could add about 25 percent to the capital cost of the
Stretford system. Addition of the thiocyanate waste treatment
along with the polysulfide process could increase capital costs
by about 40 to 50 percent (Ref. 66).
Other Methods - Other methods of treatment may also be
feasible.For example, the blowdown could be treated in exist-
ing wastewater treatment facilities, if they are available. It
could also be concentrated (if necessary) and shipped away for
treatment at a central waste treatment facility located off-site.
207
-------
Another alternative may be to limit or eliminate washing
of the sulfur cake so that the solution discharged with the cake
would provide adequate blowdown. The increased potential for
water pollution from disposal of sulfur cake containing the
resulting high concentrations of dissolved solids may, however,
make this technique environmentally unacceptable. Moreover, this
would be feasible only in small systems (such as the ones
considered in this assessment) where the sulfur is disposed of as
a wet cake. A somewhat similar alternative, which has been
previously proposed for application in coal gas plants, is to mix
and dispose of the blowdown with the ash (Ref. 68). This would
also increase the potential for water pollution from ash disposal
and may be environmentally unacceptable. Moreover, it might be
possible only if the ash is disposed of by ponding, since the
excess water probably could not be handled in a landfill. As
discussed in Section 4.4.2, the ash will probably be landfilled.
One method of treatment that may be feasible and should
be investigated further is to use the gasifier as a reductive
incinerator. The use of coke ovens in this manner has been pro-
posed for small Stretford plants used for coke-oven gas treatment
(Ref. 25). In the high temperature reducing atmosphere of the
gasifier, the thiocyanates and thiosulfates would be broken down,
as discussed earlier. The H2S and C02 gases evolved would go
out with the product gas. The solid salts would probably be re-
moved with the gasifier ash, although some may be carried over
into the product gas and be removed in the cyclone. This method
of treatment has the advantage that existing equipment is used.
In addition, although the sodium and vanadium salts are disposed
of with the ash, the thiocyanates and thiosulfates originally
contained in the blowdown are destroyed. Thus, the ash plus
salts, should create less of a disposal problem than the ash plus
the original blowdown.
Injecting the blowdown into the gasifier, however, would
create several possible problems. First, a method for feeding
the blowdown into the gasifier must be developed. Mixing the
blowdown with the coal in the coal hopper is one option, but care
must be taken to avoid creating "cold spots" in the gasifier.
Carry-over of the reduced salts into the gas stream is another
potential problem. If this occurs, the salts would be removed in
the quench system. The salts would then dissolve, and could lead
to a build-up of dissolved solids in the quench liquor.
Assessment of Alternatives - For small Stretford units
considered in this assessment,the quantity of blowdown produced
is very small. For these small quantities, installation of
208
-------
equipment designed solely for treating the blowdown would be ex-
pensive. The most desirable disposal option appears to be treat-
ment in existing wastewater treatment facilities, if they are
available at the gasification site. If existing facilities are
not available, concentrating the blowdown and shipping it to cen-
tral treatment facilities off -site may be the best alternative.
Another alternative that should be investigated further is reduc-
tive options, if it can be done without interfering with the
performance of the gasifier. Disposal of the blowdown with the
gasifier ash or sulfur cake would be economically attractive, but
be environmentally unacceptable.
For large Stretford installations, especially where HCN
is present in the feed gas , regeneration of the blowdown at high
temperature under reducing conditions may be the most desirable
treatment method. With this option, there is no aqueous dis-
charge and chemical make-up requirements are greatly reduced.
Commercial application of this method has been reported (Refs.
27, 69). However, few details are available on their operation.
4.4 SOLID WASTE CONTROL ALTERNATIVES
Solid wastes produced from the gasification and gas
purification operations include:
• gasifier ash,
• cyclone dust,
• sulfur cake , and
• blowdown from the MEA unit.
Alternatives for disposal of these solid wastes are discussed in
this section. One of the most important factors influencing dis-
posal alternatives is the classification of the wastes according
to the Resource Conservation and Recovery Act (RCRA) . This act
is discussed in section 5.4. If the waste is classified as
hazardous, restrictions will be placed on handling and disposal.
More data on the specific waste streams which might be obtained
are needed to determine whether the wastes will be classified as
"hazardous".
4.4.1 Coal Preparation and Handling
Coal preparation and handling operations for Wellman-
Galusha gasification systems considered in this report pro-
duce no solid waste streams requiring disposal.
209
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4.4.2 Gasification
Casifier ash is the only solid waste stream from gasi-
fication that will require disposal. The gasifier ash appears to
be similar to ash resulting from coal combustion. Thus, disposal
methods used for power plant ash should be applicable to disposal
of the gasifier ash. However, the gasifier ash may have a higher
organic content than ash from direct coal combustion, and may
have a different particle size. The effect of these variables on
disposal of the gasifier ash should be determined. Additional
data are also needed on the structural characteristics, compac-
tion properties, leaching characteristics, and chemical composi-
tions of the gasifier ash.
Electric utilities have widely used ponding and landfill
for disposal of fly ash and bottom ash from coal combustion (Ref.
70). Ponding is a land disposal technique in which the waste
material is placed wet. Impoundments or other restraints are
necessary for temporary and/or long-term stability. Both the
gasifier ash and the ash sluice water could be placed directly in
the pond. Basic design criteria for ponds are pond area and
depth, ash volume and concentration, and pond life.
Prevention of surface and ground water contamination
through measures such as liners and underdrainage systems is also
an important design consideration. Because unlined disposal
ponds may cause ground water contamination, a liner would prob-
ably be required for a gasifier ash disposal pond. Possible
liners include natural materials such as compacted soils, clays,
and asphaltic compounds and various synthetic materials (Ref.
70). A major disadvantage of ponded waste material is its lack of
structural stability. Because of this, the pond likely can never
be fully reclaimed and construction over the pond site would not
be possible.
Landfill is a waste disposal operation in which the dis-
posed material has sufficient structural integrity so that im-
poundments or other structural supports are not necessary (Ref.
70). Ultimate reclamation of the landfill site may be possible.
Thus, landfill, where applicable, is a more desirable disposal
option than ponding. Important design criteria for landfills are
to prevent the accumulation of gas that may catch fire or explode
and to prevent contamination of surface and ground water (Ref.
24). Proposed regulations of the Resource Conservation and Re-
covery Act specify restrictions on the location of landfills
(Ref. 4). These regulations also require measures for preventing
surface and ground water contamination, preventing impairment of
air quality, and controlling disease vectors. These regulations
are discussed in Section 5.4.
210
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Use of landfill sealants is one possibility for prevent-
ing ground water contamination. Possible sealant materials are
combinations of bentonite, red mud slurry (bauxite residue), la-
tex, or asphalt with soil or sand. When such liners are used,
leachate is trapped at the bottom of the landfill and can be col-
lected and treated (if necessary) before being released (Ref.
70). Another method for controlling water contamination from
landfills is the interception of subsurface flow by placement of
orouted slurry-trench cutoffs and/or drains upstream of the en-
tire area of the landfill (Ref. 70). Leachate collection systems
can also be used. One type of leachate collection system con-
sists of a network of gravel-packed drainage canals or perforated
drainage pipes. Another type of leachate collection system con-
sists of a system of perimeter wells around the disposal site.
These wells form a geohydrologic core of depression. Leachate
and uncontaminated ground water collected in the wells can be
monitored and appropriately treated or released (Ref. 70).
Structural stability of the ash is an important criteria
to be considered in evaluating disposal techniques. Some ashes
self-stabilize into a structurally sound, low permeability mater-
ial suitable for landfill. Other ashes must be treated in order
to achieve the desired stability. In some cases, the permeabil-
ity of the stabilized material may be low enough to serve as a
liner. Self-stabilization of the ash is a function of the cal-
cium and alkalinity present in the ash. Ashes from most bitumi-
nous and anthracite coals are low in calcium and alkalinity and
will not self-stabilize without the addition of lime. Sub-
bituminous coal ash generally achieves marginal self-
stabilization. Lignite ash generally self-stabilizes, but high
concentrations of sodium and magnesium in the ash may have an
adverse effect on the stabilization. Ashes that do not
self-stabilize can be made more structurally stable by fixation
with lime.
Moisture content is critical to the stability of the
ash. The ash appears to follow Abram's law; the strength in-
creases exponentially with linear decreases in the water/fly ash
ratio (Ref. 70). Thus, ash removed from the gasifier by sluicing
will probably not be structurally stable. However, dewatered ash
or ash removed dry with small amounts of water added to reach the
optimum moisture content may be stable. Another consideration is
the organic content of gasifier ash, which may result in unsound-
ness of the material in the short or long term. This effect
should be investigated.
211
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Costs for landfill disposal of the gasifier ash are af-
fected by several site-specific factors. These include size of
the landfill and distance to the disposal site. For small land-
fill facilities (less than about 3.15 kg/sec, or 300 tons per
day), disposal costs per ton of solid waste increase diametri-
cally with decreasing size (Ref. 71). The trend of increasing
disposal costs with descreasing size has also been noted for
landfill disposal of flue gas desulfurization (FGD) sludge (Ref.
72). Disposal costs increase with increasing distance to the
disposal site because of increased transportation costs. Trans-
portation costs per ton of solid waste per mile transported de-
crease somewhat with increasing distance (Ref. 72). Based on
cost estimates for landfill disposal of FGD sludge, disposal
costs for the ash may be in the range of $0.0055 to $O.Ol32/Gg
($5 to $12/ton) if no fixation is necessary, or $0.0088 to
$0.0198/Gg ($8 to $18/ton) with fixation. The lower costs are
based on a large disposal facility one mile from the gasification
plant, and the higher costs are for a smaller facility 10 miles
from the gasification plant (Ref. 72). Costs for disposal of ash
from the gasification systems described in this report are shown
in Table 4.4-1. If the ash is classified as toxic, additional
costs would be incurred for monitoring, liners, leachate collec-
tion, etc.
4.4.3 Gas Purification
Potential solid waste streams from gas purification
include cyclone dust, sulfur cake (recovered in the Stretford
unit), and blowdown from the MEA unit.
Collected Particulates -
Possible alternatives for disposing of the cyclone dust
include incineration and landfill. In the Glen-Gery Wellman-
Galusha gasification facility and the Chapman gasification faci-
lity, cyclone dust is disposed of with the gasifier ash. How-
ever, the dust has a very high carbon content, and might be
classified as a hazardous "ignitable" waste according to the
Resource Conservation and Recovery Act (see Section 5.4). If it
is "ignitable", it probably could not be landfilled, unless
perhaps it could be mixed with the ash to form a mixture that is
nonignitable. There is also a possibility that the dust could be
classified as a hazardous "toxic" waste. If the dust is class-
ified toxic and the gasifier ash is not, the dust should be dis-
posed of separately from the ash. If the dust is not ignitable
212
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TABLE 4.4-1. COSTS FOR LAND DISPOSAL OF GASIFIER ASH
Coal Type
Disposal Costs,
Without Fixation
With Fixation
Low Sulfur Bituminous
0.01-0.02
0.01-0.03
to
M
U>
High Sulfur Bituminous
• Stretford
• MEA
• MEA (stringent removal)
Anthracite
Lignite
0.02-0.06
0.03-0.07
0.03-0.06
0.04-0.10
0.04-0.10
0.04-0.08
0.05-0.10
0.04-0.10
0.07-0.15
0.07-0.15
1Based on facility producing a cooled low Btu product gas
Source: Reference 72
-------
and is either classified as not toxic or the ash is also class-
ified as not toxic by RCRA guidelines (Ref. 4), the dust may be
disposed of in a landfill along with the gasifier ash. The dust
would add approximately 1 to 20 percent to the weight of the ash.
Landfill of the dust/ash mixture would involve similar con-
siderations as discussed in Section 4.4.2.
Because of the high carbon content of the dust, utili-
zation of its heat content by combusting it would be preferable
to landfilling it. If there is a coal-fired boiler near the
gasifi-cation site, the dust could be burned along with the coal.
It could also be incinerated in an existing or new incinerator.
Because of the small quantities of dust produced (0.8 to 4 g/s
for small facilities; 4 to 20 g/s for large facilities),
installation of incineration equipment for the dust alone would
be expensive. However, this may be necessary if the dust is
"ignitable" and no suitable facilities for combusting it exist.
For these small quantities of dust, a vortex (cyclone) or rotary
kiln incinerator could be used. The vortex incinerator is
designed for small capacities (63 g/s or less). The rotary kiln
incinerator is built in a wide range of sizes (5 to 300 g/s) and
has a low investment cost ($5,000 to $12,000, July 1977 dollars)
(Ref. 24). Possible environmental problems from incineration
include potential air emissions.
Recovered Sulfur -
Options for disposal of the sulfur removed from the low-
Btu product gas include landfill and purification for possible
sale. The wet sulfur cake produced in the Stretford process can
be melted in an autoclave, separated from the scrubbing liquor,
and recovered as pure liquid or solid sulfur, typically 99.5 per-
cent sulfur and up to 99.9 percent with some feed gases (Refs.
16, 26, 68). Purifying the sulfur would be capital intensive,
and marketing the small quantities of sulfur would be difficult.
Typically, the sulfur from Stretford plants producing only small
quantities is disposed of as a wet cake. Thus, the sulfur re-
covered from the facilities considered in this study would prob-
ably not be purified. The large facility producing 87.6 MW (300
x 10^ Btu/hr) of low-Btu gas from high-sulfur coal generates
310 g/s (29 tons/day) of sulfur and may be an exception. How-
ever, tars present in the gas could make even the purified sulfur
appear black in color, and thus make marketing the sulfur more
difficult. Disposal costs for this material are estimated in
Table 4.4-2.
214
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TABLE 4.4-2. ESTIMATED COSTS FOR LAND DISPOSAL OF RECOVERED SULFUR
Coal Type
Disposal Cost, $/Gj'
Without Fixation
With Fixation
10
»-•
Ul
Low Sulfur Bituminous
High Sulfur Bituminous
Anthracite
Lignite
0.002-0.006
0.02- 0.05
0.002-0.006
0.005-.01
0.004-0.009
0.03-0.07
0.004-0.009
0.008-.02
on facility producing a cooled, detarred low Btu product gas.
Source: Reference 72
-------
Landfill disposal of the sulfur would involve consid-
eration similar to those discussed in Section 4.4.2 for landfill
of the gasifier ash. Because residual Stretford chemicals will
be present in the sulfur cake to some degree even after it is
washed, the sulfur cake may be classified as a hazardous "toxic"
waste according to the RCRA (Ref. 4). This classification would
impose severe restrictions on the handling and disposal of the
waste, as discussed in Section 5.4.
ME A Slowdown -
Blowdown from an MEA process will contain potentially
harmful compounds (as discussed in Section 3.7.2) and will pro-
bably be classified as a hazardous "toxic" waste according to the
RCRA (Ref. 4). If the gasifier ash is also found to be a hazar-
dous "toxic" waste, MEA blowdown could possibly be disposed of by
landfill with the ash. If the gasifier ash is not hazardous,
however, the MEA blowdown should be disposed of separately.
Landfill of the blowdown would have to conform to regulations
discussed in Section 5.4 for the disposal of hazardous wastes.
4.5 TOXIC SUBSTANCES
Tars and oils collected downstream of the cooling step
are the principal by-products of low-Btu coal gasification. For
the smallest facilities examined in this study, the heating value
of the tars and oils amounts to about 4.5 MW (15 x 10& Btu/h),
or roughly one-quarter of the energy content of the cooled, de-
tarred low-Btu gas. Operators of gasifiers using bituminous,
subbituminous, and lignite coals will recover the energy value of
the tars and oils, probably by using them as a supplemental fuel
in a coal-fired boiler or furnace.
Of principal concern during the combustion of the tars
and oils are the emission of SO? and NOX. Emission factors
for the production of S02 are snown in Table 4.5-1. Factors
for NOX emissions are unavailable. Other emissions from the
combustion of by-product tars and oils include particulates and
trace elements.
TABLE 4.5-1. EMISSION FACTORS FOR S02 PRODUCED DURING
THE COMBUSTION OF BY-PRODUCT TARS AND OILS
Emission Factor
Coal Type ng/J (lb/106 Btu)
Low-Sulfur Bituminous 260 (0.6)
High-Sulfur Bituminous 600 (1.4)
Lignite 690 (1.6)
216
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Tars and oils are also potentially emitted as fugitive
effluents (from spills and leaks). These effluents can be mini-
mized with leak checks, pump sumps, safe handling procedures, and
good maintenance programs.
4.6 SUMMARY OF MOST EFFECTIVE CONTROL ALTERNATIVES
The most effective control alternatives for the low-Btu
gasification facilities examined in this study are summarized in
Table 4.6-1. These are simply the most effective controls in
eliminating or reducing multimedia emissions. Costs and energy
considerations are not involved in selecting the most effective
controls.
4.7 REGIONAL CONSIDERATIONS AFFECTING SELECTION OF
ALTERNATIVES
Selection of the best control alternatives for each of
the waste streams is affected by a variety of site and regional
considerations. These include the types of waste streams gener-
ated by and treatment facilities provided for other operations in
the area, the stringency of emission and effluent regulations in
the area, and the existing air and water qualities.
Because the quantities of liquid and solid waste streams
produced by low-Btu gasification facilities are small, installa-
tion of special equipment to treat them would be expensive. How-
ever, if acceptable treatment facilities designed for treating
other, larger waste streams are available on-site, the small
waste streams from the gasification facility could be treated in
the existing facilities at a low cost. Similarly, if treatment
facilities are not available on-site but a waste treatment com-
plex capable of treating the waste is available near the site,
the wastes can be shipped to the off-site complex for treatment.
If such a complex does not exist but several plants in the area
produce waste streams requiring similar treatment, construction
of a central facility may be more economical than construction of
separate treatment facilities at each site.
The degree of treatment required for the waste streams
is affected by the existing air and water qualities and by the
applicable environmental regulations in the area. For example,
if the gasification plant is to be located in a non-attainment
area for a pollutant (hydrocarbons, for example), very strict
217
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TABLE 4.6-1.
SUMMARY OF MOST EFFECTIVE EMISSION
EFFLUENT, SOLID WASTES AND TOXIC
SUBSTANCES CONTROL ALTERNATIVESa
Waste Stream
Most Effective Control Technology
Air Emissions
• Fugitive dust from coal storage
• Fugitive dust from coal handling
• Coal feeding system vent gas
• Ash removal system vent gas
• Start-up emissions
• Fugitive emissions and pokehole
gases from gasifier
• Fugitive emissions from hot cyclone
• Separator gas
• MEA acid gas
• Stretford oxidizer vent gas
• Stretford evaporator vent gas
Liquid Effluents
• Water runoff
• Ash sluice water
• Process condensate
• Covered bins
• Asphalt and polymer coatings
• Enclosed equipment, collect gas
and recycle to gasifier inlet
air or treat with baghouse
• Collect gas and recycle to
gasifier inlet air or combine
with product gas
• No control necessary in a
properly designed system
• Incinerator
• Adherence to good operating
and good maintenance procedures
• Same as for gasifier
• Combine with product gas
• Recycle to gasifier
• Stretford
• Claus with tail gas cleanup
• None required with existing
applications. However, via-
bility of this approach needs
to be confirmed in a gasifica-
tion process application.
• Same as for oxidizer vent gas
• Use covered bins for coal
storage
• Contain, collect and reuse for
process needs
• Collect and recycle to ash
sluice system
• Containment and treatment at
hazardous waste facility
(Continued)
218
-------
4.6-1. (Continued)
Waste Stream
Most Effective Control Technology
Stretford blowdown
* Containment and treatment at
hazardous waste facility
• Reductive incineration at
high temperature
• Recovered sulfur
• MEA blowdown
T>vg-Lc Substances
• Tars and oils
• Secured landfill
• Combustion in incinerator
or coal-fired boiler
• Purify for sale or disposal
• Containment and treatment at
hazardous waste facility
Combustion in boiler or furnace
(Flue gas treatment may be re-
quired .
aBased only on effectiveness in eliminating or reducing emissions.
219
-------
control of the gaseous emissions from the gasification plant
would be required. Control of other sources in the area may also
be required to offset emissions from the gasification plant. On
the other hand, if the plant is located in an area where a large
portion of the PSD increment remains, control targets could be
somewhat less stringent. Similarly, discharge of the ash sluice
water and possibly the Stretford blowdown to sewers for treatment
in municipal wastewater treatment facilities may be allowed in
certain areas resulting in significant cost savings.
4.8 SUMMARY OF COST AND ENERGY CONSIDERATIONS
Costs of the "best available" candidate methods which
were just identified are summarized in Table 4.8-1. Most of the
control alternatives have negligible costs when compared to the
costs of the low-Btu product gas. The most costly control alter-
natives are those for treatment of the MEA acid gas vent stream
and process condensate. The most costly control methods also
have the largest energy consumption. Tars and oils represent a
large energy credit.
One method to reduce the costs and energy consumption of
process condensate treatment is to reduce the size of the conden-
sate stream. This may be accomplished by drying the coal prior
to gasification (the dryer off-gas could contain large amounts of
coal volatiles). Alternately, the size of the stream could be
reduced by minimizing the amount of steam fed to the gasifier.
220
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TABLE 4.8-1.
SUMMARY OF MAJOR COSTS AND ENERGY CONSUMPTION
OF ALTERNATIVE CONTROL METHODS
aureUon "•"• *<*•«• H»JU
fto«*** "•"• *««•••
Goal Pr«|>aratlon
Caal Iiadllo* and Ca»«o«a tniaaloa*
Storage . rwgUlv* duat
Liquid tffluaatt
• Coal pile runoff
Control Coot*
Control Method ($/CJ)»
• Covered bin*
• Xaphalt and polvoor coating*
• Enclo**d equipment, collection
*7*te**)
• Covnrod bin*
• Collection and reuM
<0.01
<0.01
<0.01
<0.01
<0.01
""(JAn*"* *
• N*gllglbl*
• Negligible
• Negligible
• Negligible
UellBU-CaluOia
Caalflar
Cataoua Ealaaioaa
• A*h renaval vent gaaaa
• Start-up vent ga*«*
• fugitive eniaaion*
(pokehole ga***)
Liquid Effluent*
Collection and recycle to gaal-
fler lalet air or product ga*
Hone required
Flare or Incinerator
Good naintaoanc* and operating
practical
<0.01
••tlltlbl*
• Ann (lulc* voter
Solid Vaate*
• A*h (lov-S sltunlaou*)
• A*h (high-S Bltuninoua)
- Stratford
- MEA*
- KEA (Stringent)1
• Alb (Anthracite)
• Aab (Ugnlte)
Partlculat* Ronoval- Solid Waataa
Caa Ouanchln* Gaaeou* Eadaalona
and Cooling . Quench liquor/tar
liquid Effluent*
• Proc*** Condenaata
- Hlgh-S Bitunlnoua
• Stratford
• MEA*
• HEA (Stringent)1
- lignite
• Froceif Condenaate
- Hlgh-S lltunloou*
• Stratford
• HEA (Stringent)'
- Ugnlta
• Collection and rev** <0.01
• Secured landfill 0.01-0.02(0.01-0.03)*
i
0.02-0.06(0.04-0.08)-
0.03-0.07(0.05-0.10))
0.03-0.06(0.04-0.10)'
0.04-0.10(0.07-0.15)*
0.04-0.10(0.07-0.15)*
• ConbuatioB <0.01
* Conbln* vith the product ga* <0.01
• Contalnnent and traatnont
off-alt* in • haxardoua
vaata treatnent facility 0.40-0.59
o!88-1.32
1.16-1.69
1.43-2.01
• Forced evaporation on-«lte
0.06-0.07
0.12-0.14
0.16-0.18
0.18-0.20
• Negligible
• Negligible
• Negligible
• Negligible
• Negligible
• Negligible
• Negligible
• NA>
• Negligible
•«*n
• HA"
• NAh
0.019
0.042
0.055
0.0(5
Continued
221
-------
TABLE 4.8-1. (.CONTINUED)
Operation
Proceaa
Ve«te Strean Media
Vut« Strcaa
Control Method
Control Coat*
(I/GJ)*
Sulfur RanBval-
Stretford
Sulfur tenoval-
MEA
Caaeoua Eaii»ton«
• Oxidlxer vent ga*
• Evaporator vent gaa
Liquid effluent*
• Slowdown aolvent
Solid Wa«tea
• Sulfur
- Low-S Bltualnou*
- High-S Bltunlnou*
- Anthracite
- Lignite
Ca**ou* E»l««ion*
• Acid ga*
- 15 HU product ga*
- 74 HU product gaa
• Acid ga*
- 15 HU product ga*
- 74 HU product gaa
Solid wa«te*
• HEA Slowdown
• Sulfur
Hone required
•one required
Xeductlve Incineration
Secured landfill
Stretford acid gee renoval
Claua without tall gea
cleanup
• Containment and treatment
at a haaardoua we4te facility
0.002-0.009
0.02-0.07
0.002-0.009
0.005-0.020
1.2-1.6
0.6-0.8
O.S-0.6
0.2
<0.01
HA
Hegllglble
Htgllglble
HegUglble
Hagllglbl*
0.007
0.007
0.008
O.OM
•Sane aa the Stretford eulfur reeoval caae-
HA - Data not available for calculation of energy eonauaBtlona.
*C«iti art annuallted coati ptr GJ of cooled, detarred product gaa.
Inerty conaunBtlona ire J of energy required by the control Method per J of cooled, detarred product gaa.
'Energy eonainptioa will depend upon the naterlala (coke, coal, wood, oil. etc.) need to atart up the gaalfler and
tlon of the gaa during th< atart up tin* period.
dCood •alntenance and operating prccedurea ahould already be defined and Included In the unlta operating coata.
the coevoel-
*HEA produce* a product ga* to Met confcustlon llalte of S6 ng SOj/J (0.2) lb/10" Btu.
HEA ((trlngent) produce* a "very clean" product gaa containing 6 ng/Hn (10 ppav) of aulfur (peelea.
*Coafcuetlon characterlatlci of the collected partlculate* have not been deterained.
wta are not available on the energy comunvtlon of treating procee* eendaniata et an off-aite haaardoua weate ti
facility.
Control co*tn Without fixation (with fixation)
222
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SECTION 5.0
ANALYSIS OF REGULATORY REQUIREMENTS AND
ENVIRONMENTAL IMPACTS
This section describes the range of regulations possibly
affecting the design and operation of Wellman-Galusha coal gasi-
fication plants. To assess the environmental impacts of these
plants, levels of contaminants in the plant's multimedia dis-
charges are compared to regulations and Multimedia Environmental
Goals (Ref. 3) which might possibly apply to these facilities.
Bioassay test results are also discussed here as indicators of
potential health and ecological effects associated with the plant
waste streams.
5.1 ENVIRONMENTAL ASSESSMENT METHODOLOGIES
EPA's Industrial Environmental Research Laboratory in
Research Triangle Park, NC (IERL/RTP) is developing a standard
set of methodologies for environmental assessment of fossil en-
ergy processes. These methodologies will be used to:
• determine multimedia (air, water, and land) en-
vironmental loadings and environmental control costs
from the application of existing and future sets of
control/disposal options. These are directed toward
specific sources, processes, and industries.
• compare the characteristics (chemical, physical, and
biological) of these loadings with Multimedia En-
vironmental Goals (MEG's) (Ref. 3) and bioassay
tests in order to prioritize potential environmental
problems and control needs.
By implementing a standard methodology, inefficiencies and proli-
feration of techniques for assessing and comparing environmental
aspects and control needs for competing technologies can be
minimized.
EPA's environmental assessment methodology consists of
the following elements:
• current process technology background,
• environmental data acquisition,
• current environmental background,
223
-------
• environmental objectives development
(Multimedia Environmental Goals)
• control technology assessment,
• environmental alternatives analysis,
(Source Analysis Models, SAM's), and
• bioassay interpretations.
The following text briefly summarizes these elements.
Work in the Current Process Technology Background area
involves two major activities:conducting an information survey
of literature and industry sources; and performing an engineering
analysis of the available data. This analysis seeks to identify
which aspects of the technology are most important and need
further study and what information is missing or incomplete.
The purpose of Environmental Data Acquisition is to
fill the data gaps identified by the engineering analysis effort.
This information may be obtained from testing at commercial or
pilot plant facilities or by conducting laboratory experiments.
These data acquisition activities may also be used to verify data
reported by industry or in the literature.
After a technology's discharge sources (i.e., its poten-
tial problem areas) have been identified, the next step in the
EPA's environmental assessment program is determining which sour-
ces need to be controlled and to what levels. To answer these
questions, environmental goals must be developed. These goals
comprise the results of Environmental Objectives Development and
may be based on:
• best available control technology (BACT)
• natural background pollutant levels,
• prevention of significant deterioration, and
• Multimedia Environmental Goals (MEG's).
Background data required in the development of environmental
goals include existing standards and ambient pollutant levels.
Obtaining this information is the purpose of the Current En-
vironmental Background area.
The first four areas should define a technology's pol-
lutant discharge sources which may require control and the
control goals for those sources. Control Technology Assessment
involves identifying applicable control techniques and assessing
such factors as their effectiveness, costs, and energy require-
ments. If control techniques are not available, control tech-
nology development will precede the assessment activities.
224
-------
Determining the best control option(s) for discharge
sources and the best set(s) of control options for a given plant
is the aim of the Environmental Alternatives Analysis area. This
is accomplished by use of Source Analysis Models,which compare
the discharges from a plant employing a set of control options to
the environmental goals. Consideration must be given to the
relative potential harmful health and/or ecological effects of
the various pollutants and to cost vs. benefit of controlling the
pollutants.
Bioassay Interpretations involve determining the poten-
tial health and ecological effects of waste streams sampled in
the Environmental Data Acquisition area. The bioassay data are
compared to the chemical data and to the models used in the MEG's
to develop environmental goals for specific components.
A more detailed discussion of the Multimedia Environ-
mental Goals (MEG's), Source Analysis Models (SAM's), and Bio-
assay Interpretations is given below.
5.1.1 Multimedia Environmental Goals
Multimedia Environmental Goals (MEG's) are levels of
contaminants or degradents (in ambient air, water, or land or in
discharges conveyed to ambient media) that are judged to be (1)
appropriate for preventing certain negative effects in the sur-
rounding populations or ecosystems, or (2) representative of the
control limits achievable through technology.
To date a total of 650 chemical substances and physical
agents (e.g., noise, heat), nearly all of which are expected to
be associated with fossil fuel processes, have been selected as
part of a "Master List" for which MEG's are to be established.
The MEG's have already been established for 216 substances on the
Master List. The MEG value(s) for a given substance may be based
on several or all of the 12 criteria shown in Table 5.1-1. These
criteria cover discharge level and ambient level goals. Depend-
ing on the data available, up to 12 MEG values may be generated
for a given substance for each medium (air, water and land). One
of the MEG criterion which is most currently used in environmen-
tal assessment work is the discharge MEG (DMEG). DMEG is the ap-
proximate concentration for contaminants in source discharges
which may not evoke significant harmful or irreversible responses
in exposed humans or ecology, when those exposures are limited to
short durations (less than 8 hours per day). An example of a MEG
chart for 2-Aminonapthalene is given in Table 5.1-2.
225
-------
TABLE 5.1-1. MEG VALUE BASES FOR DISCHARGE AND AMBIENT LEVEL GOALS
Goal
Category
MEG Value Basis
Discharge Level Goals
(Air, Water, Land)
Ambient Level Goals
(Air, Water, Land)
Existing Standards
Developing Technology
Discharge Severity (DS)
Ambient Level Goal
Elimination of Discharge
Current or Proposed
Ambient Standards
on Criteria
Toxicity Based Ambient
Severity
Zero Threshold
Pollutants
NSPS, BAT, BPT
Engineering Estimates
Health Effects
Ecological Effects
Health Effects
Ecological Effects
Natural Background Level
Health Effects
Ecological Effects
Health Effects
Ecological Effects
Health Effects
NSPS: New Source Performance Standard
BAT: Best Available Technology
BPT: Best Practicable Technology
-------
TABLE 5.1-2, MEG CHART FOR 2-AMINONAPHTHALENE
CATEGORY: IOC
2-AMISONAPHIHALENE:
(2-naphthylamiae,
ULS: L66J CZ
STRUCTURE:
&-naphtbylamine).
White crystal* that darken on exposure to light and air; volatile with steam.
,98
PROPERTIES;
Molecular wt: 143.19; op: 113; bp: 306; d: 1.0614*°
* i vap. press.: 1 am
at 108'C; volatile In stean; (lightly soluble In cold water.
HATURAL OCCURRENCE. CHARACTERISTICS. ASSOCIATED COMPOUNDS:
2-Naphthylsaine does not occur a* such in nature, but la formed by the pyrollal* of nitrogen containing
organic aatter. It baa been isolated from coal-tar (ref.44). It ha*, in general, the characteristics of
priaary aroaatic amines. It is a weak base.
TOXIC PROPERTIES. HEALTH EFFECTS;
Epideniological studies have shown that occupational exposure to 2-aainonaphthalane is strongly associated
with the occurance of bladder cancer. There is no doubt that the compound is a hunan bladder carcinogen
(ref .44) 2-Aninonaphthalene is also reported to cause cancer in several animal species.
The EPA/HIOSR ordering lumber is 7628. The lowest does to induce a carcinogenic response is reported
as 19 Bg/kg. The adjusted ordering nua&er is 423.8.
LD5Q (oral, rat): 727 mg/kg.
Aquatic toxiclty: TLm 96: 10-1 ppa (ref. 2.)
REGULATORY ACTIONS. STANDARDS. CRITERIA. RECOGNITION. CAHDIDATE STATUS FOR SPECIFIC REGULATION:
2-Aainooaphthalene is recognized by ACCIH as a carcinogenic agent in humans. No TLV has been assigned.
B-Naphthylamlne was the subject of a NIOSH Basard Review Document (ref. 43)
OSHA standards dealing with exposure of eaployees to 2-naphthylamine has been established taking into
consideration substantial evidence that 2-naphthylanine i» known to cause cancer (ref. 17).
MIHIMUM ACUTE TOXICITY CONCEHTRATIONS;
Air. Health; 7 x 10*/423.8 - 165 yg/m3
Water, Health; 15 x 165 - 2.5 x 103 yg/8.
Land, Health: 0.002 x 2.5 x 103 - 5 yg/g
Alz, Ecology:
Hater, Ecology: 100 x 1 » 100 yg/g
Land, Ecology: 0.002 x 100 - 0.2 yg/g
ESTIMATED PERMISSIBLE CONCENTRATIONS;
EPCAH2 • 0.107 x 727 • 78 ug/a3
EPCAH3 " 0>081 X 72? " 59 U8/*3
- 15 x 59 - 3,500 U'jM
- 0.4 x 727 - 291 yg/4
- 0.002 x 291 - 0.6 yg/g
EPCAC2 - 103/(6 x 423.8) - 0.4 yg/m3
- 15 X 0.4 - 6 ug/l
EPC^, " 0.002 x 6 • 0.012 u»/g
tfcva. " 50 * !
" 0.002 x 50 - 0.1 ug/g
227
-------
TABLE 5.1-2. (Continued)
MULTIMEDIA
ENVIRONMENTAL
GOALS
10C220
2-AMINONAPTHALENE
f MttMN LtVIL OOALS
Wmv.ll
•Sit
LM. ..»!
1. iartont^Tmiiiilipi
.,__
•MITT. Mr
..*— ,r— .
, -—^ f^ ^j,
IMOOlOl
II.
%j!±rsicr
taMBi
MMltltaB
1.65E2
2.5E3
5.0E2
••MM
'tMnT
1.0E2
2.0E1
ttmt on «m»iim ftaan
..^-
r Jr
IWMlUMl
0.4
6.0
1.20
u-*..
taMv
"iS2£"
50
10
Clirr-
i
•To t» HOIIHM* *y
-------
Most of the MEG's are derived from models which trans-
late toxicological data, recommended concentration levels, and
federal standards or criteria into discharge or ambient level
goals. For most of the categories listed in Table 5.1-1, more
than one model is available for obtaining the ambient MEG values
(AMEG). Where different AMEC values can be obtained by using
different models, the one with the lowest value is chosen as the
AMEC value. An example of a model which translates Threshold
Limit Values (TLV's) and NIOSH recommendations into AMEC's is
shown in Table 5.1-3. Other models used to calculate MEG values
can be found in the Multimedia Environmental Goals (Ref. 3).
As part of the methodology for evaluating the toxicity
of the substances on the "MEG Master List," EPA has developed a
"hazard indicator" system which assigns indicators (x = hazar-
dous, xx = very hazardous, xxx = most hazardous, N. H. = non-
hazardous) to the substances. The system provides one simple
means of identifying, through cursory inspection, those pollu-
tants most likely to pose a human health hazard. Numerical
values which provide the basis for assigning hazard indicators
are obtained by using an equation which considers toxic and
genotoxic potentials as well as cumulative or chronic effect
characteristics.
As discussed previously, MEG charts have been developed
for 216 of the 650 substances in the "MEG Master List." Work is
in progress to complete MEG charts for the remainder of these
substances and to refine the models used to estimate discharge
and ambient level goals.
The MEG methodology can also be used in evaluating data
obtained from sampling and analysis programs. For example, DMEG
values can be used to prioritize streams and stream components
requiring more detailed characterization. This is further ex-
plained in the next section, Source Analysis Models.
5.1.2 Source Analysis Models
The Source Analysis Models (SAM's) are being developed
by IERL/RTP to provide systematic methods of comparing the effec-
tiveness of pollution control options. The SAM's are a set of
various models which provide techniques for rapid screening of
environmental data as well as intermediate or detailed approaches
to relate waste stream physical, chemical, and biological charac-
teristics to MEG values.
The simplest number of the SAM's is SAM/1A (Ref. 74).
This model provides a rapid screening technique for identifying
229
-------
TABLE 5.1-3.
MODEL FOR TRANSLATING TLV'S AND NIOSH
RECOMMENDATIONS INTO AMEG VALUES BASED ON
HEALTH EFFECTS FOR EXPOSURE TO A COMPOUND
IN THE AMBIENT AIR
Basic data
- TLV® or NIOSH recommendation:
40 hr. week occupational exposure (mg/m3)
Assumptions
Exposure adjustment factor « 40 hours work per week/
168 total hours per week
- Safety factor - 0.01
Derivation
Exposure
Adjustment
Lr] ^
4U hr
health
or
NIOSH
x 168 hr
|af?ty
Factor
-
0.01
40 x 0.01 = 0.00238
1
4~ZO~
Model
TLV
health - „«,
Source: Ref. 73
230
-------
and prioritizing potentially harmful waste streams. Major
simplifying assumptions implicit in the use of the SAM/1A
methodolgy are:
• The substances currently in the MEG's are the only
ones that must be addressed at this time (The MEG's
are currently being updated to include new data,
account for new or revised standards, and add new
compounds).
• Transport of the components in the waste streams to
the external environment occurs without chemical or
physical transformation of those components.
• Actual dispersion of a pollutant from a source to a
receptor will be equal to, or greater than, the
safety factors normally applied to acute toxicity
data to convert these data to estimated safe chronic
exposure levels.
• Discharge Multimedia Environmental Goal (DMEG)
values developed for each substance are adequate for
estimating acute toxicity. A DMEG is a concentra-
tion of a substance estimatesd to cause minimal
adverse effect in a healthy receptor exposed once or
intermitttently for short periods. It relates
either to human health or ecological effects.
• The waste stream components cause no synergistic
effects.
These assumptions, along with the accuracy of the test
data and assumptions used in developing DMEG values, must be
considered when interpreting test results using a SAM/1A analysis
scheme.
The following procedure is used in performing a SAM/1A
analysis of the screening data (Level 1) obtained from an envi-
ronmental sampling and analysis program to prioritize the waste
streams and stream components for detailed analysis (Level 2).
1) Determine the concentration of compounds or compound
classes in the MEG categories for each stream.
2) Determine the health and ecological DMEG value of
each component identified. In the case of a class
of compounds, select the component with the lowest
DMEG value. In selecting this component, determine
if it can actually be present in the waste stream.
231
-------
3) Calculate health and ecological Discharge Severity
(DS) values for the components or compound classes
in the waste stream. The following defines DS for
component "i":
(DS)i = (DC)i/(EMEC)i
where DC^ = stream concentration of
component "i"
- DMEG value of component "i"
obtained from the MEC's
(Ref. 3). Both health and
ecological DMEG values are
listed.
The DS values are used to prioritize stream
components for detailed analysis.
4) Calculate the Total Stream Discharge Severity (TDS)
by summing the DS values for all the individual com-
ponents (elements, compounds, or compound classes)
in the stream.
5) Calculate the Weighted Discharge Severity (WDS) for
the total stream by multiplying the TDS by the
stream mass flow rate.
The WDS for each stream is used subjectively in conjunction with
the total stream bioassay test results to prioritize the streams
for detailed analysis.
Other SAM's are currently being developed by EPA. These
include:
• SAM/IB will incorporate the results of bioassay
tests.
• SAM/1 will take into consideration pollutant trans-
port and transformation. The resulting ambient con-
centrations will be compared to AMEG values. An ex-
tended SAM/1 will consider urban and rural popula-
tion densities and include background pollutant
concentrations.
• SAM/II is the most detailed analysis method and is
still in the planning stage. Ambient concentrations
rather than source concentrations will be used.
Transport and transformation models will be more
rigorous than those used in SAM/1.
232
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5.1.3 Bioassay Interpretations
Development of a methodology for reducing and format-
ting bioassay data is being carried out under EPA contracts to
Research Triangle Institute, Research Triangle Park, NC., and
Litton Bionetics, Kensington, MD. EPA has established the Bioas-
say Subcommittee of the Environmental Assessment Steering Com-
mittee to monitor and coordinate the methodology development ef-
fort.
The objectives of the EPA bioassay interpretations
methodology development are as follows:
• Reduction and formatting of bioassay data into
simple form.
• Presentation of the results of bioassays in a form
useful to chemists and engineers involved with the
technologies.
• Reduction of the data to a matrix which will
"weight" the observed effects in terms of signifi-
cant differences between exposed experimental
organisms and their controls.
• Publication of the methodology in a manual which
will enable uniformity of assessment of the pollu-
tion potential of the source.
Development of a methodology for handling bioassay data
is necessary because of the complex and specialized information
resulting from bioassay sampling and analysis. Reducing and
formatting the data are particularly important because the infor-
mation must be used by chemists and engineers who may not be
familiar with bioassay techniques. However, the bioassay test
results may be used as the basis for design and operation of
plants to conform with applicable environmental regulations.
The test matrix in Table 5.1-4 is an example of the
minimal bioassay protocol which will be followed in order to as-
sess waste streams which may have harmful health and/or eco-
logical effects. The large amount of information which must be
gathered in order to produce credible bioassay results requires
careful planning and sample treatment.
In general, dose/response models are used for defining
numerical or "weighted" relationships between toxic substances
and their effect on test organisms. These ratings, which are
233
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TABLE 5.1-4.
N>
PROPOSED BIOASSAY TEST MATRIX FOR SAMPLES COLLECTED
DURING ENVIRONMENTAL SAMPLING AND ANALSIS PROGRAMS
Sample Type
Liquids (aqueous)
Solids
Solid leachates
(aqueous extract)
SASS Train
participates
SASS Train organic;
Gases
Mandatory Test
Ames mutagenlcity
CHO cytotoxiclty
Whole animal (rodent acute)
toxiclty
Freshwater or marine aquatic*
Ames mutagenlcity
BAM cytotortcity
Whole animal freshwater or
marine aquatic
Aquatic vertebrate
Aquatic algal
Aquatic Invertebrate
Ames mutagenlcity
CHO cytotoxiclty
Whole animal (rodent acute)
toxiclty
Freshwater or marine aquatic
Ames mutagenlcity
CHO cytotoxiclty
Ames mutagenlcity
CHO cytotoxiclty
Recommended Test
—t
Soil test
Plants stress
ethylene test
Optional Test
Additional cytotoxiclty
Alternate freshwater
or marine aquatic
Additional cytotoxiclty
Alternate freshwater or
marine aquatic
HI 38 cytotoxiclty
Alternate freshwater or
marine aquatic
CHO cytotoxiclty
WI 38 cytotoxiclty
fOash indicates no test recommended at this time.
^Includes aquatic vertebrate, algal and Invertebrate tests
Score*: 75
-------
designed to give an indication of the relative toxicities of
waste streams, are subject to some of the intrinsic difficulties
associated with dose/response models. A brief description of
dose/response models follows.
The basis of most dose/response models is derived from
biological effects data obtained in the laboratory. In order for
these models to be useful in estimating health/ecological ef-
fects, it is necessary to extrapolate effects observed in the
laboratory into an unknown area. This extension of knowledge as-
sume-s a continuity, similarity, or other parallelism between the
two situations. Often biological effects need to be extrapolated
from (1) laboratory to field - many differences make this diffi-
cult: (2) one species to another - no two species are alike: (3)
one medium to another - ingestion is not the same as inhalation:
and (4) one life state to another - ranges of sensitivity may
differ by orders of magnitude. In the present state of the art,
biological effects data are collected from a few life states of a
few species for a few routes of entry in a few controlled condi-
tions. On the other hand, the real world situation contains
thousands of species in many stages of growth all of which may be
continuously exposed to various types of doses.
Despite the technical difficulties involved in estimat-
ing permissible concentrations of pollutants in waste streams,
various approaches are available for dealing with the problem.
There are many potentially applicable models, some of them devel-
oped by or for the EPA and other governmental agencies. The mod-
els have two basic parts: a dose/response part and an adjust-
ment part. The dose/response generally consists of one of the
typical laboratory effects measurements:
• LD-50: Dose of sample per kg of test animal at
which 50 percent died.
• EC-50: Concentration at which growth was 50 percent
of a control.
• LC-50: Concentrations at which 50 percent of the
experimental species died.
Lowest dose of a substance introduced in
one or more portions by a route other than
inhalation over any period of time and
reported to have caused death in a
particular animal species.
235
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Currently the interpretation of bioassay data is subjec-
tive. However, as more data are obtained, the basis for inter-
pretation of these results will be more defined.
5.2 IMPACTS ON AIR
This section describes the air impacts of Wellman-
Galusha gasification plants. In estimating those impacts, the
emissions are compared to various emissions standards while re-
sults of dispersion modeling are compared to ambient air quality
standards. Bioassay results are also discussed in this section.
5.2.1 Summary of Air Standards and Guidelines
Regulations possibly applying to air emissions from coal
gasification facilities include:
standards of performance for new stationary sources,
national emission standards for hazardous air
pollutants,
state and federal emission standards,
national ambient air quality standards, and
guidelines for controlling air emissions from Lurgi
high-Btu plants.
New Source Performance Standards -
Currently, no federal new source performance standards
directly apply to emissions from coal gasification plants. New
Mexico is the only state to have promulgated performance stan-
dards for gasification plants, but these standards are pertinent
mainly to large gasification facilities. Also the New Mexico
standards principally apply to firing of fuels within the gasifi-
cation complex.
Other states have promulgated performance standards for
sulfur recovery plants. However, these standards are generally
not as stringent as regulations defining the maximum permissable
concentrations in the effluent gas. Oklahoma and Ohio, for ex-
ample, have established a performance standard for sulfur plants
at 0.01 Ib S/lb S feed. New Mexico has specified a limit of sul-
fur emissions from gasification plants as 3.4 ng/J (0.008
lb/106 Btu) of energy in the feed to the plant.
National ^Emission Standards for Hazardous Air
Pollutants -
Hazardous air pollutants are those pollutants for which
no ambient air quality standards have been specified but which
236
-------
have been determined to cause or contribute to increased morta-
lity or serious irreversible or incapacitating reversible ill-
nesses. Hazardous air pollutant standards have been established
for four pollutants: beryllium, asbestos, mercury, and vinyl
chloride. However, these hazardous air pollutant standards apply
only to a few source categories and are not directly pertinent to
coal gasification. Although some beryllium and mercury are emit-
ted from gasification plants, the quantities are very small.
State and Federal Emission Standards -
Emission standards establish a maximum permissable emis-
sion rate or concentration of a specific pollutant in an emission
stream. The most stringent of the various federal and state
standards are summarized in Table 5.2-1.
National Ambient Air Quality Standards -
National Ambient Air Quality Standards have been estab-
lished for six criteria pollutants; these standards are summar-
ized in Table 5.2-2. Primary standards are designed to protect
public health; secondary standards are aimed at protecting public
welfare.
State Implementation Plans are required to outline stra-
tegies for attaining and maintaining the National Ambient Air
Quality Standards. Major new sources which could contribute to a
violation of a national air quality standard are allowed to con-
struct only if the new source's emissions are controlled to the
greatest extent possible, if offsetting emissions reductions are
obtained from existing sources, and if significant progress is
made in achieving the NAAQS. Areas with air quality better than
that defined by the NAAQS must prevent significant deterioration
caused by new emission sources or modifications of old sources.
Texas has established an air quality regulation for the maximum
ground level concentration of H£S of 0.08 ppm (30 min. average)
(122 yg/m3).
Performance Guidelines for Lurgi Gasification Plants -
EPA issued a guidelines document in March, 1978 to aid
the EPA Regional Offices in reviewing applications for permits
for Lurgi gasification plants. The guidelines were based on
proposed high-Btu Lurgi plants using the Rectisol acid gas and
Stretford/Claus sulfur removal processes. These guidelines are
presented in Table 5.2-3.
237
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TABLE 5.2-1.
Pollutant
Particulates
Particulates
HCN
NH3
HC1
H2S
H2S, CS2, COS
S02
MOST STRINGENT EMISSION STANDARDS3
Standard
43 mg/Nm3 (0.018 gr/ dry scfb
72 mg/Nm3 (0.03 gr/ dry scfc
10 ppmc
25 ppmc
5 ppm
10 ppm°
10 ppm
250 ppm
emission standards define ma^mum concentrations
permitted In discharge.
Federal standard for discharge gas from penumatic coal
cleaning equipment.
New Mexico standard for coal gasification plants.
Federal standard for emission from large sulfur recovery
plants located at petroleum refineries.
rtOTE: Data valid as of October, 1977.
Source: Ref. 76
238
-------
TABLE 5.2-2. NATIONAL AMBIENT AIR QUALITY STANDARDS
(40 CFR Part 50)
Pollutant
Primary Standards
Secondary Standards
Sulfur Oxides
(measured as
sulfur dioxide)
Partlculate
Carbon Monoxide
Photochemical
Oxidants
Nonmethane
Hydrocarbons (as
guide for oxidant stds)
Nitrogen Oxide
(measured as
nitrogen dioxide)
80 ygm/m3 (aam)*
0.03 ppm
365 ygm/m3
0.14 ppm (24 hr)a
75 ygm/m3 (agm)*
260 ygm/m3 (24 hr)a
10 mgm/m3 (8 hr)a
9 ppm
40 mgm/m3 (1 hr)a
35 ppm
160 Ugm/m3 (1 hr)a
0.08 ppm
160
0.24 ppm
100 pgm/m3
0.05 ppm
1300 ygm/m3
0.50 ppm (3 hr)J
60 ygm/m3 (agm)*
(guide for 24 hr. std)
150 ygm/m3 (24 hr)a
10 mgm/m3 (8 hr)a
9 ppm
40 mgm/m3 (1 hr)a
35 ppm
160 ygm/m3 (1 hr)a
0.08 ppm
160 ygm/m3 (3 hr)
0.24 ppm
100 jigm/m3 (aam)*
0.05 ppm
a,b
Concentration not to be exceeded more than once a year.
b6:00 a.m. to 9:00 a.m.
aam m annual arithmetic mean; agm - annual geometric mean
40 C.F.R. Part 50, July 1976.
239
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TABLE 5.2-3. PERFORMANCE GUIDELINES FOR
LURGI GASIFICATION PLANTS
Emission
Standard
Sulfur Dioxide
ES - 0.07 (S )°-85(HHV J.°-15For System Ia
C Cr
ES = 0.032(Sj°'75(HHVj°-25For System IIb
Where:
ES ™ total sulfur emissions
S = coal sulfur input
HHV = coal heat input
Non-Methane
Hydrocarbons
EHC =0.07 HHVc
Where:
EHC - emissions of non-methane hydrocarbons
HHVC - coal heat input
System I is an emission control system consisting of a Stretford
sulfur recovery plant and a Claus sulfur recovery plant.
System II is an emission control system consisting of a Stretford
sulfur recovery plant.
Source: Ref. 77
240
-------
5.2.2 Comparisons of Waste Streams with Emission Standards
Potential emissions from Wellman-Galusha gasification
facilities include:
• fugitive dust emissions from coal handling and
storage,
coal reeding system vent gases,
ash removal system vent gases,
start-up emissions,
fugitive emissions (e.g., pokehole gases) from
the gasifier and hot cyclone,
vent gas from tar/quench liquor separation,
acid gas from MEA absorption process,
Stretford oxidizer vent gas, and
Stretford evaporator vent gas.
In a well designed plant that considered environmental hazards
most of these emission streams should not cause significant en-
vironmental problems. Detailed characterizations are avail-
able for coal feeding system vent gas and gas from the tar/
liquor separator and techniques for controlling these emissions
are available. Emissions from coal handling and storage, ash re-
moval, fugitives from particulate removal, and Stretford oxidizer
and evaporator vent gases are among those which have not been
characterized in as great a detail. For this reason, there is
some uncertainty in specifying realistic control alternatives for
these streams. Gasifier start-up emissions are variable and of
short duration. Combustion products resulting from flaring this
stream will contain S02 and NOX but these emissions will be
small if oil or coke is used as the start-up fuel. Fugitive em-
issions from the gasifier will be similar to coal feeding system
vent gases. Recovered MEA process acid gases have been charac-
terized but not for a gasification plant application. Also, data
on emissions from secondary emission control processes are lack-
ing. The coal feeding system vent gas, gas from the tar/liquor
separator, and MEA acid gas are discussed in the following para-
graphs .
Coal Feeding Gas -
The coal feeding gas contains several constituents in
concentrations exceeding the DMEG values for health effects by
one or more orders of magnitude. These include: CC>2, CO,
H2S, HCN, NH3, and particulates. If a hooding system is used
with recycle of the collected gases to the gasifier inlet air
line, emissions are reduced to those from leaks. In this case,
the coal feeder is no longer an emission source.
241
-------
Gas from Tar/Quench Liquor Separation -
If it is not controlled, the separator gas may be dis-
persed by a steam ejector. This emission contains C02, CO,
H2S, HCN, NH3, amines, phenols, fused aromatic hydrocarbons,
heterocyclic nitrogen compounds, heterocyclic sulfur compounds,
and trace elements (compounds of P, Cr, Cu, and Ag) in concen-
trations exceeding their DMEG values (worse case DMEG values used
when specific compounds were not identified) for health effects
by one or more orders of magnitude. For systems gasifying high-
sulfur coals, the level of H2S will exceed the most stringent
emission standard. If controlled by recycle to the gasifier in-
let air line or product gas, the separator gas is eliminated as
an emission source.
MEA Acid Gas -
The MEA acid gas contains most of the sulfur originally
contained in the raw, low-Btu gas. This stream should not be re-
leased directly to the atmosphere. When the Stretford process is
used to remove the sulfur compounds from this gas, the exhaust
gas is cleaned to a very low level of H2S. When the Glaus pro-
cess is used for sulfur recovery, a tail gas is produced that
contains as much as 20,000 ppmv of t^S and SC>2. As described
in Section 4, various control options can reduce the amount of
sulfur released, and reduce the level of SC>2 emission to less
than 250 ppmv. This level is less than that of the most
stringent emission standard.
5.2.3 Impacts on Ambient Air Quality
The impacts of Wellman-Galusha gasification facilities
on ambient air quality are discussed in this section. Disper-
sion models used to predict the ambient air quality impacts as-
sume worst-case meteorological conditions and are summarized in
the Appendix. Because controlled Wellman-Galusha facilities have
few emissions, relatively uncontrolled facilities have been mod-
eled.
Model Gasification Plants -
To examine the impacts of Wellman-Galusha facilities on
ambient air quality, dispersion modeling was performed for two of
the smaller-sized (18 MW or 60 x 106 Btu/hr) plants. Impacts
of larger facilities can be roughly estimated by scaling the
calculated impacts of the smaller sized plants. The two plants
modeled feature the gasification of low- and high-sulfur bitumin-
ous coals. The facility gasifying low-sulfur coal uses a Stret-
ford sulfur process. The plant using high-sulfur coal has an MEA
242
-------
acid gas removal process, with sulfur recovery by a Glaus pro-
cess. The tail gas from the Glaus plant is incinerated before
discharge to the atmosphere.
Significant emission sources for the plant using low-
sulfur coal include:
• coal feeding gases,
• pokehole gases, and
• separator vent gases.
The plant using high-sulfur coal also includes the combustion
gases from a Glaus tail gas incinerator. Stack parameters for
the four emission sources are summarized in Table 5.2-4. The
stacks are located in a straight line, with the separataor vent
15 meters downwind of the gasifier, and the incinerator stack 15
meters downwind of the separator. Emission parameters are sum-
marized in Table 5.2-5.
Incremental Ambient Loadings -
The maximum downwind concentrations projected for the
small gasification facilities are summarized in Table 5.2-6.
These concentrations describe the incremental impact on ambient
air quality of relatively uncontrolled sources.
The National Ambient Air Quality Standards can be used
to gauge the impact of the projected ambient loadings. With the
exception of nonmethane hydrocarbons, the predicted pollutant
concentrations for both the low- and high-sulfur coals are below
the NAAQS . Carbon monoxide and S02 concentrations do not ex-
ceed the NAAQS; however, they are relatively high. H2S concen-
trations were also modeled and compared to the Texas ambient air
standards. For the high-sulfur coal case, H2S concentrations
exceed the Texas standard.
The separator vent gas and incinerator gas account for
most of the potentially hazardous concentrations of air pollu-
tants at ground level. Emissions from the separator vent con-
tribute the most to the ground level concentrations of H2S, CO,
and NH3« Table 5.2-7 shows percentage contributions of these
components to the calculated maximum concentrations. The Glaus
tail-gas incinerator accounts for all of the
Controlled facilities should have few of the emissions
of the uncontrolled plants. The separator and coal feeder can be
eliminated as emission sources. If the Stretford process is used
243
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TABLE 5.2-4. STACK PARAMETERS FOR MODEL PLANTS
Parameter coal Feeder
Height, m (ft)
Tempera ture , °C
Flow rate, ACFM
Velocity, m/s
19.8 (65)
41
18
3.05 (10)
Pokeholes
7.6 (25)
80
5.2
0.31 (1)
Separator Vent
18.3 (60)
85
430
15.24 (50)
Incinerator
18.3 (60)
538
2500
12.2 (40)
(ft/a)
244
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TABLE 5.2-5 . EMISSION PARAMETERS FOR MODEL PLANTS, g/s
N>
Pollutant
C0b
H2SC
NH3b
HCNb
cosc
N0xb
non-CHi»
hydrocarbons'*
S02a
Coal Feeding Gas
2.3
0.011d
0.083a
0.0017
0.00087
0.0019d
0.0063a
-
-
-
Pokehole Gases
0.47
0.0024d
0.019a
0.00035
0.00019
0.00041d
0.0012a
-
-
-
a
Separator Gas Incinerator Gas
48.0 0.5
0.24d
1.9a
0.72
0.06
0.02d
0.06a
0.36
15.0
13.2
Only applicable to high-sulfur case.
Sane emissions exist for both high- and low-sulfur cases.
Differing emissions exist for high- and low-sulfur cases.
Only applicable to low-sulfur case.
-------
TABLE 5.2-6. MAXIMUM DOWN WIND CONCENTRATIONS FOR MODEL GASIFICATION PLANTS
10
24-Hour
Pollutant
CO
HiS
NHl
HCN
COS
MOx
non-ClU
hydrocarbons
SOi
Low
C MX.
2271
11.3
31.4
2.7
1.0
15.6
652
-
Sulfur
R MX, Bb .
350
350
350
350
. 350
350
350
-
High
C MX.
M8/"'4
2274
89.5
31.4
2.7
3.1
15.6
652
105.3
Sulfur
R MX. »b
350
350
350
350
350
350
350
950
Low
C MX.
9776
48.8
134.6
11.5
4.5
67.0
2792
-
3-Hour
Sulfur
R MX, -b
200
200
250
250
200
250
250
-
High
C MX.
W8/-'4
9789
385.6
134.6
11.5
13.5
67.0
2792
382.8
Sulfur
R MX, «b
200.
200
250
250
200
250
250
550
Low
C MX.
M8/«'4
13670
68.2
189.7
16.2
6.2
94.6
3940
-
1-Hour
Sulfur
R MX, «b
202
202
205
204
199
220
220
—
High
C MX,
13679
539.1
189.7
16.2
18.6
94.3
3936
562.0
Sulfur
R MX, »b
202
202
205
204
199
220
220
571
downwind concentrations.
Distance downwind of the gasifler at which MxlMoi concentrations occur.
-------
TABLE 5.2-7. PERCENTAGE CONTRIBUTIONS OF H2S, CO, AND NH3
FROM THE SEPARATOR VENT STREAM TO THE
CALCULATED MAXIMUM GROUND-LEVEL CONCENTRATION3
Component ?„ Contribution
H2S 92%
CO 92%
NH3 99.6%
HCN 97.4%
COS 85%
See Appendix for Ground-Level Calculation Methods
247
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in place of the Glaus process for sulfur recovery, the incin-
erator is eliminated. Also, if tail gas treatment units were
used instead of an incinerator, the S02 emissions would also be
greatly reduced.
5.2.4 Bioassay Results
Bioassay tests have been conducted on coal feeder and
separator vent gases at a Chapman-Wilputte gasification facility
(Ref. 13). Results of these tests are shown in Table 5.2-8.
Bioassay test results show that these streams have potentially
hazardous health and ecological effects. Pokehole gases and
fugitive emissions are similar to the coal feeder gas and will
have similar effects.
5.3 IMPACTS ON WATER
This section describes the water impacts of Wellman-
Galusha gasification plants. The most stringent effluent regu-
lations and environmental goals that might be used to assess the
hazard of effluents are discussed. Potential effluents from
Wellman-Galusha plants are compared to these standards and goals.
Bioassay test results are also presented for the quench liquor at
the Chapman facility using low-sulfur bituminous coal.
5.3.1 Summary of Water Standards
Standards applicable to the discharge of aqueous wastes
include water quality and effluent standards. Water quality
standards define the minimum safe quality of receiving waters.
Water effluent standards define the maximum permissible concen-
trations of contaminants in water effluents. Since the impacts
of effluent discharging facilities on ambient water quality are
very site-specific, further discussion is limited to water ef-
fluent (rather than quality) standards.
Various water effluent standards have been established
or proposed. The EPA has developed water effluent limitation
guidelines for 40 specific source categories (none for gasifica-
tion) . The only pertinent guidelines are the proposed rules for
coal preparation plants and associated areas, including coal
storage (40 CFR 434.2 Subpart B, 42 FR 21380, April 25, 1977 and
40 CFR 434.25 Subpart B, 42 FR 46932, September 1977). The pro-
posed rules exempt rainfall or snowfall overflow from facilities
designed to contain rainfall resulting from a 10-year, 24-hour
precipitation event.
The EPA has proposed toxic effluent standards (40 CFR,
Part 129) for aldrin/dieldrin, DDT (ODD, DDE), endrin, toxa-
phene, and benzidine. Many other substances are being examined
for possible addition to the toxic pollutants list.
248
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TABLE 5.2-8. BIOASSAY RESULTS FOR COAL FEEDING
AND SEPARATOR VENT GASES
Bioassay Tests
Waste Stream Health3 Ecological13
Coal Feeding Gas High High
Separator Vent Gas High NC
aHealth tests include: Ames and Cytotoxicity (WI-38, RAM)
Ecological tests include: Plant Stress Ethylene
NC - Test not conducted
Sourqe: Ref. 13
249
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The most stringent existing effluent standards (as of
October, 1977) are summarized in Table 5.3-1. These standards
prohibit the discharge of water contaminants in concentrations
exceeding those in Table 5.3-1.
In practice, the discharge of effluents is controlled by
the use of National Pollutant Discharge Elimination System
(NPDES) permits. Those discharging into "navigable waters" must
apply for and receive a NPDES permit establishing the allowable
conditions for discharge. These permits are issued by the EPA
except vAiere a state has received authority from the EPA to ad-
minister its own NPDES. Before a NPDES permit is issued, the
state must certify to the EPA that all discharges comply with the
applicable effluent limitations.
5.3.2 Comparisons of Waste Streams with Effluent Standards
Potential aqueous effluents from Wellman-Calusha gasi-
fication facilities include:
• water runoff from coal storage,
• ash sluicing water,
• process condensate, and
• blowdown from the Stretford process.
Water runoff is not discussed in detail here because of its high-
ly variable, site-specific nature. Provisions for handling this
problem must be made in the design of a facility. The other
three potential effluents are discussed below.
Ash Sluicing Water -
The ash sluicing water contains compounds of iron, cal-
cium, and phosphorus in concentrations exceeding by one or more
orders of magnitude their DMEG values based on health effects
(worst case DMEG values were used when specific compounds were
not identified). This stream also contains iron, chromium,
cyanide, and suspended solids in concentrations exceeding the
most stringent effluent standards. This water should be col-
lected and reused.
Process Condensate -
The process condensate contains thiols, phenols, fused
aromatic hydrocarbons, heterocyclic nitrogen compounds, ammonia,
hydrogen cyanide, and selenium in concentrations exceeding by one
or more orders of magnitude the DMEC values based on health ef-
fects. Carboxylic acids, phosphorus glycols and epoxides, and
arsenic are found in concentrations exceeding by one or more
250
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TABLE 5.3-1. MOST STRINGENT WATER EFFLUENT STANDARDS
Constituent or Parameter
NH3
As
Ba
Cd
Cr4*
Cu
ci-
CN~
B
F"
Fe
Pb
Mn
Hg
Ni
Phenols
P
Se
Ag
SO*"
Zn
N
BODs
COD
Suspended Solids
PH
Concentration, mg/i
2.5
0.05
1.0
0.01
0.05
0.10
250
0.02
1.0
1.0
0.3
0.05
0.1
0.002
1.0
0.005
1.0
0.01
0.05
600
0.1
2.5a or 4.0b
30C
125
15 or 37C
5-10
aApril to October.
November to March.
°Deoxygenating wastes.
Note: Data valid as of October, 1977
Source: Ref. 76
251
-------
orders of magnitude the DMEG values based on ecological effects.
For both health and ecological effects, worst case DMEC values
were used when specific compounds were not identified. The pro-
cess condensate also contains ammonia, arsenic, chlorides, cya-
nides, boron, fluorides, iron, phenols, phosphorous, selenium,
sulfates, BOD, COD, and suspended solids in excess of the most
stringent effluent standards. Table 5.3-2 shows the Priority
Pollutants along with other components with Discharge Severity
(DS) values greater than one that were identified in the quench
liquor (Ref. 13). Fifteen Priority Pollutants were identified
along with five additional compounds with DS values greater than
one.
Slowdown from the Stretford Process -
Blowdown from the Stretford process contains compounds
of vanadium and iron, and EDTA in potentailly hazardous concen-
trations based on DMEG values for health effects (worst case DMEG
values used for vanadium and iron). Iron is also found to be
present in concentrations exceeding the most stringent effluent
standards. Thiocyanate and thiosulfate are not regulated but may
be potentially harmful.
5.3.3 Bioassay Results
Bioassay tests have been conducted on the process con-
densate at a Chapman gasification facility (Ref. 13) and the ash
sluice water from a Wellman-Calusha facility using anthracite
(Ref. 1C). These results are summarized in Table 5.3-3.
5.4 IMPACTS OF LAND DISPOSAL
Although solid waste disposal has not received much at-
tention until very recently, it will be a major focus of EPA and
the states in coming years. The Resource Conservation and Re-
covery Act of 1976 (RCRA) provides a hazardous waste regula-
tory program in addition to the following:
• A system to eliminate open dumping,
• Technical and financial assistance for planning
improved solid waste management programs,
• Grants to rural communities for improving solid
waste management systems, and
• Authority for research, demonstration, and studies
in solid waste management.
The regulations implementing RCRA are just now being developed
and proposed. Thus, the draft regulations are preliminary in na-
ture and subject to change. EPA has been working with the states
252
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TABLE 5.3-2.
to
COMPONENTS WITH DS's>l AND PRIORITY POLLUTANTS
IDENTIFIED IN THE QUENCH LIQUOR FROM A CHAPMAN FACILITY
USING LOW-SULFUR BITUMINOUS COAL.
MEG Category
(1) Aliphatics
(8) Carboxylic
Acids
(10) Amines
(18) Phenols
(21) Fused
Polycyclics
(47) Nitrogen
(49) Arsenic
(50) Antimony
(54) Selenium
(72) Iron
(78) Copper
(79) Silver
(82) Cadmium
(83) Mercury
Compound Estimated Stream
DS Value*
Identified - Concentration ((Jg/fc)" Health Ecological
>Ce Alkanes
Phthalates
Aualine
Amino toluene
Phenol
Anisoles
Alkylphenols
Naphthalene
Acenaph thalene
Benzoperylene
Ammonia
Cyanide
As
Sb
Se
Fe
Cu
Ag
Cd
Hg
1E5
2E4
3E3
4E3
7E5
1E6
4E5
2E4
4E3
3E4
5E6
1E6
8E2
7E1
2E3
IE 3
1E1
2EO
5EO
<3E4
<1 1EO
<1 1E4
<1 3EO
2EO NA
1E5 1E3
3E5 3E3
8E4 8E2
<1 2E2
NA NA
2E3 1E5
2E3 4E4
3EO 2E1
<1 <1
4E1 8E1
<1 4EO
<1 <1
<1 <1
<1 5EO
<1 <1
Priority
Pollutant
No
Yes
No
No
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Yes
Yes
Yes
Yes
I
Stream concentrations and DS values; aEb * a x 10
NA - DMKCJ value not available
Worst case DMEG values used when specific compound were not identified
Source: Ref. 13
-------
TABLE 5.3-3. BIOASSAY TEST RESULTS FOR ASH
SLUICE WATER AND PROCESS CONDENSATE
Bioassay Test Results
Waste Stream Health Ecological
a b
Ash Sluice Water Low NC
Process Condensatec Low High6
Q
From a Wellman-Galusha facility gasifying anthracite coal (Ref. 10)
Health Tests include: Ames, cytotoxicity (WI-38) and rodent acute toxicity
From a Chapman facility gasifying low-sulfur bituminous coal (Ref. 13)
Health Tests include: Ames, cytotoxicity (RAM), and rodent acute toxicity
Ecological tests include: Fresh Water (algal, daphma, fathead minnows), salt
water (algal, shrimp, sheepshead minnows) and terrestrial (soil microcosm)
NC - Tests not conducted
254
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to develop the solid waste control programs and believes that the
states are the preferred level of government for their implemen-
tation.
Under RCRA, EPA has issued guidelines for the land dis-
posal of solid wastes (Ref. 4). These standards set minimum
levels of performance for any solid waste land disposal site.
The guidelines apply to the land disposal of all solid material
excepting hazardous, agricultural, and mining wastes.
Additional standards have been proposed for hazardous
solid waste substances (Ref. 4). A waste would be considered
hazardous if it falls into either of the two following cate-
gories :
• Wastes which demonstrate ignitability, corrosivity,
reactivity, or toxicity.
• Wastes included on EPA's hazardous waste list.
These substances have shown any of the above
characteristics. Additional hazardous wastes are
known to contain infectious agents; radioactive
substances; mutagenic, carcinogenic, or teratogenic
substances; substances which bioaccumulate; and/or
toxic organic substances.
The above criteria characteristics for hazardous wastes are de-
fined in the proposed regulations, along with laboratory methods
for their identification.
In identifying wastes as hazardous, EPA chose to em-
phasize waste streams rather than specific hazardous substances
wherever possible. This is because industrial wastes are likely
to be complex mixtures containing many components, only some of
which may show hazardous characteristics.
Thus, although only 19 generalized solid waste streams
are specifically included on the proposed list, they collec-
tively represent about 400 hazardous substances. EPA also has
listed approximately 160 different industrial processes which
discharge hazardous wastes.
EPA has proposed hazardous waste standards which are de-
signed to protect human health and the environment. EPA or
authorized State agencies will be responsible for the implemen-
tation of these standards. The standards stipulate procedures
for recordkeeping, labeling of waste containers, and the use of
appropriate containers for hazardous waste. In addition, infor-
mation on the general chemical composition of solid wastes must
255
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be supplied to persons who transport, treat, store or dispose of
hazardous waste. A system is required which assures the proper
delivery, storage or disposal of solid wastes. Reports describ-
ing the quantities and disposition of hazardous waste must be
submitted to EPA or authorized State Agencies.
Performance standards have been proposed which apply to
owners and operators of hazardous waste treatment, storage, and
disposal facilities. These include requirements for site loca-
tion and design, operating methods, contingency plans, monitor-
ing, inspection, reporting, and other practices.
A Hazardous VJaste Management Facility permit will prob-
ably be mandatory for all new facilities or for modifications to
existing facilities. A supplementary environmental analysis will
be required in addition to information included in the permit ap-
plication itself.
EPA has promulgated interim guidelines to help state and
local governments identify areas with common waste management
problems. The guidelines are designed to encourage and facili-
tate eventual regional implementation of solid waste management.
No design criteria are specified in the present guidelines.
5.4.1 Comparisons of VJaste Streams with Disposal Standards
The solid waste streams generated by the gasification
facility could be regulated under the RCRA. Consideration of the
composition of these solid wastes indicate that they may be class-
ified as hazardous, as discussed below. Tests on the actual
solid wastes will be necessary to determine their classification.
Gasifier Ash -
The gasifier ash contains various trace elements, or-
ganic constituents, and other compounds for which leachate con-
centrations defining a toxic waste have been set. Thus, the
gasifier ash may be classified as toxic.
Cyclone Dust -
The cyclone dust also contains a variety of trace ele-
ments, and may be classified as toxic. In addition, the cyclone
dust is composed mainly of carbon, and may be classified as ig-
nitable.
256
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Sulfur Cake -
The sulfur cake recovered in the Stretford unit will
contain various dissolved components, including vanadium salts,
thiocyanates, and thiosulfates. This sulfur cake may be class-
ified as toxic.
MEA Slowdown -
The blowdown from the MEA unit will consist of a var-
iety of compounds, and will probably be considered as toxic.
5.4.2 Evaluation of Unregulated Pollutants and Bioassay
Results
Gasifier Ash -
The gasifier ash should not present significant health
or ecological hazards. Bioassay tests conducted on ash from a
Chapman facility gasifying low-sulfur bituminous coal showed low
toxicities in the rodent acute toxicity and soil microcosm tests,
and negative results in the Ames test (Ref. 13). The ash from a
Wellman-Galusha facility gasifying anthracite coal had negative
Ames test results and nondetectable cytotoxicity test results.
The soil microcosm test indicated that ash had a higher toxicity
than the cyclone dust (Ref. 10). For the ash from bituminous
coal gasification, the dust had more toxic effects than the ash
(Ref. 13). Leaching tests conducted on the ash from the
Wellman-Galusha gasifier showed low levels of trace elements in
the leachate, as discussed in Section 3.3 (Ref. 10). Further
leaching tests should be conducted, especailly on ashes from
bituminous and lignite coals.
Cyclone Dust -
The cylone dust may have a more significant ecological
impact than the gasifier ash. Bioassay tests conducted on cy-
clone dust from a Chapman gasifier indicate low toxicities for
health effects but high potential toxicities for ecological ef-
fects (based on soil microcosm tests). In soil microcosm tests,
the cyclone dust was more toxic than the coal feed, ash, tar, and
separator liquor (Ref. 13).
5.5 PRODUCT IMPACTS
Certain toxic substances may be present in the product
low-Btu gas even after the gas purification operations, but few
data are available on the presence of these substances. Poten-
tially toxic substances may also be contained in the by-product
257
-------
tar. At this time, there appear to be no standards regulating
toxic substances in the gasification products. However, such
standards may be issued in the future, under the Toxic Substances
Control act or other laws.
5.5.1 Summary of Toxic Substance Standards
The toxic Substances Control Act of 1976 (TSCA) was de-
signed to protect the public from chemicals posing "unreason-
able risk of injury" to health or to the environment. Under the
Act, EPA is authorized to obtain from industry data on the pro-
duction, use, health effects, and other matters concerning chemi-
cal substances and mixtures. The EPA Administrator may require
manufacturers or processors of potentially harmful chem-icals to
conduct tests on the chemicals to evaluate their characteristics
or clarify their health and environmental effects. If the manu-
facture, processing, distribution in commerce, use or disposal of
a chemical substance or mixture is found to present an unreason-
able risk of injury to health or the environment, the Administra-
tor is empowered to take regulatory action. Possible regulatory
measures include the following:
total or limited ban on production, etc.,
setting of concentration limits or limitation of
users,
labeling requirements,
record keeping and monitoring requirements,
regulation of use or disposal,
requiring producers to give notice or recall
substances, and
• revision of quality control procedures.
Polychlorinated biphenols (PCB's) and chlorofluorocarbons are
currently the only specific substances for which regulations have
been issued.
A list of 327 chemicals or chemical groups selected by
the Toxic Substances Control Act Interagency Testing Committee as
priority chemicals for further consideration was released in
July, 1977. On October 4, 1977, the Interagency Testing Commit-
tee recommended the following ten chemicals and categories for
priority testing:
alkyl epoxides,
alkyl phthalates,
chlorinated benzenes, mono- and di-,
chlorinated paraffins, 35-6470 chlorine,
chloromethane,
cresols,
258
-------
• hexachloro -1, 3-butadiene,
• nitrobenzene,
•• toluene, and
• xylenes.
5.5.2 Comparisons of Product Characterization Data with Toxic
Substances Standards
At this time, there appear to be no standards for toxic
substances in the low-Btu product gas or the by-product tar.
Moreover, there are few data available on potentially toxic sub-
stances in the product gas. However, it appears that several
potentially toxic substances and certain chemicals that are on
the TSCA list of priority chemicals for further evaluation may be
present in the product gas and tar. Regulations controlling
these substances may be issued in the future.
Toxic substances in the gasification products may be
regulated under TSCA or other laws (such as the Occupational
Safety and Health Administration regulations) administered by EPA
and other agencies. If an "unreasonable risk" posed by gasifica-
tion products may be prevented by a Federal low not administered
by EPA, the EPA administrator will request the agency administer-
ing the other lav; to determine whether the risk exists and
whether the agency's actions would sufficiently reduce the risk.
Laws other than TSCA administered by EPA should be used to pro-
tect against unreasonable risks unless the Administrator deter-
mines that it is in the public interest to protect against such
risks under TSCA.
5.5.3 Bioassay Results
Bioassay tests have not been conducted on the product
low-Btu gas. This gas may have high health and ecological toxi-
cities. Bioassay tests for the by-product tars have shown a high
potential for harmful health and ecological effects. In soil
microcosm tests conducted on samples from a Chapman facility
gasifying low-sulfur bituminous coal (Ref. 13) the by-product
tars were less toxic than the cyclone dust, but more toxic than
the coal feed, ash, and separator liquor.
5.6 RADIATION AND NOISE IMPACTS
5.6.1 Noise
The principal sources of noise at Wellman-Calusha gasi-
fication facilities are process blowers and turboblowers, coal
conveyors and bucket elevators, and pumps. Flighted conveyors
259
-------
produce sound levels (at 50 feet from the source) ranging from 90
to 105 dBA; belted conveyors produce sound levels ranging from 75
to 85 dBA (Ref. 78). The process blowers and turboblowers pro-
duce levels ranging from 95 to 110 dBA. Pumps produce levels
ranging from 85 to 95 dBA (Ref. 79). Each piece of equipment in
the gasification plant is capable of radiating sound levels ex-
ceeding the noise exposure criterion specified by OSHA: 90 dBA
for eight-hour exposures.
Noise abatement devices and practices can significantly
reduce noise from the various process equipment. The type and
design of noise abatement devices depends on the path of the
sound energy transmission from the source to the receiver and the
degree of reduction required to satisfy OSHA requirements.
Abatement techniques for blowers and compressors include air
intake silencers or acoustic plenums, and lagging. Techniques
for controlling noise from fluid cavitation in pumps are mostly
limited to enclosure.
5.6.2 Radiation
During gasification, some radioactive species may be
concentrated in dust removed from the product gas. Hazards aris-
ing from these species have not been determined.
5.7 SUMMARY OF MAJOR ENVIRONMENTAL IMPACTS
5.7.1 Impacts on Air Quality
The potential air quality impacts of gaseous waste
streams from Wellman-Galusha low-Btu gasification facilities were
estimated and compared to the following air standards and
guidelines:
• New Source Performance Standards (NSPS) for
stationary sources,
• National Emissions Standards for Hazardous Air
Pollutants (NESHAP),
• National Ambient Air Quality Standards (NAAQS), and
• State and Federal Emission Standards.
The major source of CO, H£S, NH^, HCN, and COS emis-
sions is from the separator vent. Recycling the separator vent
gas to the product gas would give an 85 to 98 percent reduction
in the ground-level concentrations of those pollutants.
The Glaus tail gas incinerator is the major source of
S02 emissions. These emissions can be reduced by incorpora-
ting a Glaus tail-gas clean up process.
260
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In summary, the gaseous emissions from a well con-
trolled Wellman-Galusha facility should not significantly impact
air quality. This implies that the separator vent gases are re-
cycled to the product gas and, for the high-sulfur case using MEA
and Glaus processes, a Glaus tail gas clean-up process is used
before incineration.
5.7.2 Impacts on Water
The quantity of liquid wastes from a Wellman-Galusha
gasification facility will be small; however, the concentration
of various constituents in those waste streams may exceed
effluent standards. The liquid effluents associated with a
Wellman-Galusha system are as follows:
• water runoff from coal storage,
• ash sluice water,
• process condensate, and
• blowdown from the Stretford process.
Water runoff may contain constituents exceeding effluent stan-
dards. The concentration of those constituents will be variable
and highly site- and coal-specific.
Table 5.7-1 shows the constituents in the ash sluice
water, process condensate, and Stretford blowdown that have
either been found or estimated to exceed the most stringent ef-
fluent standards and DMEG values (Ref. 3). The amount and types
of organic compounds found in the process condensate will vary
depending upon the coal feedstock. High levels of organics will
be present when bituminous and lignite coals are used. Low
levels of organics will be present when anthracite coals are
gasified.
5.7.3 Impacts on Land
Under the Resource Conservation and Recovery Act (RCRA),
EPA has issued guidelines for the land disposal of solid wastes.
These standards set minimum levels of performance for any solid
waste land disposal site. The guidelines apply to the land dis-
posal of all solid material.
The following solid waste streams from a Wellman-
Galusha gasification facility could be regulated under the RCRA:
• gasifier ash,
• cyclone dust,
• sulfur cake, and
• MEA blowdown.
261
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TABLE 5.7-1. LIQUID EFFLUENTS FROM WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
EXCEEDING THE MOST STRINGENT EFFLUENT STANDARDS AND DMEG VALUES
Liquid Effluent
Constituents Exceeding
Most Stringent
Efflueiit Standards
Constituents Exceeding Health
and Ecological DMEG Values in the
Multimedia Environmental Goals
Ash Sluice Water
Fe, Cr, CN and suspended
solids
P, Fe, Ti, Ba, La, Li, Cd, Cu, CN~, Ni and V
t-o
Process Condensate
(Bituminous Coal)
Stretford Blowdown
NH3, As, Cl~, CN~, B, F ,
Fe, Phenols, P, Se, SOir,
BOD, COD, and suspended
solids
Fe
Phenols, Fused Aromatic Hydrocarbons,
Heterocyclic Nitrogen and Sulfur Compounds,
Carboxylic Acids, Thiols, Glycols, Epxides,
NH , CN~, P, Se, As, F~, Cl~, Ca, Fe and Cd
Vanadate, Fe, EDTA and possibly Thiocyanates
and Thiosulfates
worst case DKEC values were used when specific compounds were not identified.
Process condensate produced from gasifying anthracite coal should not contain the high amounts of
organic constituents found in process condensate from gasifying bituminous or lignite coals.
DMEG: Discharge Multimedia Environmental Goal
-------
Table 5.7-2 shows the characteristics of these solid waste
streams and how the proposed RCRA regulations may apply. All of
the solid waste streams may be classified as hazardous wastes
under the proposed RCRA regulations.
5.7.4 Product/By-Product Impacts
The product gas and by-product tar produced by Wellman-
Galusha facilities may be regulated by the Toxic Substances Con-
trol Act (TSCA) of 1976. However, polychlorinated biphenols
(PCB's) and chlorofluorocarbons are currently the only specific
substances for which regulations have been issued.
The product low-Btu gas may contain toxic substances
even after extensive purification. The by-product tar does con-
tain toxic substances and positive Ames test results for muta-
genicity have been obtained.
5.7.5 Radiation and Noise Impacts
Wellman-Galusha low-Btu gasification facilities may have
radiation and noise impacts. Some radioactive species in the
coal may be concentrated in the entrained particulate matter in
the raw low-Btu gas and in the ash. Sources of potential noise
impacts in Wellman-Galusha facilities are process blowers and
turboblowers, coal conveyors, coal bucket elevators, and pumps.
263
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TABLE 5.7-2. SOLID WASTES FROM WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
THAT COULD BE REGULATED BY THE RCPA
Characteristics of the Waste Stream
Solid Waste Stream that may be Classified as Hazardous
Gasifier Ash High levels of trace elements are present and may be leached
from the ash.
Cyclone Dust High levels of trace elements are present. The dust contains
high levels of carbon (70-90%) and may be classified as
JLgnitable.
Sulfur Cake The sulfur will contain various components such as vanadium
salts, thiocyanates , and thiosulfates.
MEA Slowdown This stream will contain oxazolidin-2, l-(2-hydroxyethyl)
imidazolindone-2; diethyl urea; dithiocarbamates; thiocarbamides ;
and other high molecular weight compounds resulting from the
formation of nonregenerable complexes.
-------
SECTION 6
SUMMARY OF NEEDS FOR ADDITIONAL DATA
Data needs and recommendations for obtaining those data
are divided into the following categories:
• gaseous, liquid, and solid waste stream
characterizations and control,
• process and process streams, and
• health and environmental impact assessments.
The data needs for the multimedia waste streams and process
streams associated with Wellman-Galusha gasification systems are
summarized in Tables 6-1 and 6-2, respectively. In general, data
associated with the gasification of high-sulfur bituminous coal
are currently not available. Since existing and currently plan-
ned commercial Wellman-Galusha gasification plants use low-
sulfur bituminous and anthracite coals, data on high-sulfur coals
may have to be obtained from bench-scale units. Data on the
performance of and waste streams from sulfur recovery pro-
cesses are not available.
Data needs associated with performing health and envi-
ronmental assessments include:
• data required by EPA Regional and Program Offices
and,
• data required to assess health and environmental
(air, water and land) impacts of nonregulated
pollutants or streams.
Data needs of EPA Program Offices are shown in Table
6-3. In general, these needs involve detailed chemical char-
acterizations (compound specific), long-term monitoring of the
concentrations of those compounds, and detailed control tech-
nology assessment data.
Data requirements for assessing the health and environ-
mental impacts of nonregulated pollutants and streams will in-
volve pollutant-specific determinations, long-term monitoring and
biological testing (including both acute and chronic tests for
health and ecological effects). The specific methodologies to be
used in performing these impact assessments are still under
development. Therefore, the specific data needs are not totally
defined.
265
-------
TABLE 6-1.
SUMMARY OF WASTE STREAM CHARACTERIZATION
AND CONTROL DATA NEEDS AND PLANNED
ACTIVITIES TO OBTAIN THOSE DATA
Waete Stream Media
Waste Stream
Additional Characterisation
Needed
Control Technology
Performance Needed
Planned Activities to
Obtain Data Needs
Gaseous Eaissions
Coal feeder vent gas
Start-up vant gas
Pokehole gases
Tsr/quench liquor
•eparator vent gases
Str«tford oxidlzer
vant gaaca
Compound* present for gaai-
ficatlon of high-sulfur coal
Chemical characteristics
during the •tart-up period
for varioua •tare-up
mat*rial* (i.e. colca, wood,
oil, etc.)
Compound* present for gasi-
fying bitumlnou* (high- and
low-eulfur) coala
Chemical and .biological
characteristics for gasifying
high-sulfur bituminous,
anthracite and lignite coals
Chemical characterization
Effectiveness and actual
coat of recycling this
stream to the gaslfier inlet
air
Effectiveness and energy
r«9uirem*nts using a flsre
to control theee gases. Cur-
rently there are no good tech-
niques for evaluating the
control effectiveness of
flares
Effectiveness of injecting an
Inert gas (i.e. steam) into
the pokehol* during the poking
operation
Effectiveness of using
automatic pokers
Effectiveness of recycling
to the product gas
None should be required*
however, this will depend
on the results of charac-
terisation studies*
This control will be evaluated
by Radian and ORML at the
University of Minnesota (Duluth)
(UHD) Foster Wheeler/Stoic
gasification facility
The Wellnan-Galush* test facility
at tbs U.S. Bureau of Kiaes at
Ft. Snelling Minn, has a atart-
up vent flare that may be
available for testing
Done
None
The UMD facility will use thia
for their tar storage tank.
Vent gaaes will be characterized
by Radian and ORNL
Potential test site* are
currently being pursued by
RedIan.
KEA acid gas stream
Liquid Effluent*a
Aah sluice water
Process condensete
Stratford blowdovn
Solid Vastee
Casifler ash
Cyclone dust
Sulfur
NEA blowdovn
Chemical characterisation
Chemical end biological char-
acterizations for effluent
guideline stsadarda and com-
parison to the NEC's for high-
sulfur bituminous and lignite
coala
Chemical and biologies! char-
acterizations for effluent
guidelines and comparison to
the MEC's for high-sulfur
bituminous, anthracite sad
lignite coals
Chemical and biological char-
acterizations for effluent
guideline* and comparison to
the NEC's for high- and lov-
sulfur bituminous, anthrscite
and lignite coals
Chemical and biological char-
acterisations for high-
sulfur bituminous and lignite
coal*. Leeching etudles are
needed to determine if the ash
Is classified as hazardous by
the RCRA and determine any
potential problem*.
Chemical and biological char-
acterizations of dust collected
from gasifying high- end low-
sulfur bituminous and lignite
coal* are needed for the RCRA
and for determining potential
problem*.
Effectiveness of using a Claua
and tail gas cleanup process
for aulfur removal
Effectiveness of collection
and reuse of the aah sluice
water
Effectiveness of concentrating
process condensate by forced
evaporation
Effectiveness of reductive
incineration
Control and disposal require-
ments will be defined by the
RCRA based on chemical and
biological characteristics.
Permitting agencies will slso
define these requirement*.
Control requirements will be
defined by the RCRA baaed on
chemical and biological
characteristics
Effectiveness of combusting
the du*t may be required
Chemical and biological char- Control requirement! will be
scterlsation* of sulfur are defined by the RCRA based on
needed for the RCRA and for chemical and biological
determining potential problems, characteristics
Chemical and biological char-
acterizations are needed for
the RCRA *nd for determining
potential problems.
Control requirements will be
defined by the RCRA based on
chemical and biological
charac teris 11cs
Aah sluice water for the gasi-
fication of lignite at the Ft.
SnellinR facility may be char-
acterized by Radian.
Laboratory teats may be performed
to evaluate the gaseous emissions
generated by forced evaporation
No reductive incineration
processes are planned.
Leaching tests for lignite ash
are planned. Other leaching
tests for low-sulfur bituminous
ash may also be performed
Leaching tests for lignite are
planned. Other leaching testa
for low-sulfur bituminous coal
may be performed
Laboratory tests may bs performed
to evaluate dust combustion
characteristics
Sulfur produced by the Stratford
process will be charactariied if
a Stratford process is used at
Pike County or if another teat
site can be obtained.
None
uid effluent* may fall under RCRA guidelines if they are disposed of on lend.
266
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TABLE 6-2.
PROCESS AND PROCESS STREAM DATA NEEDS AND
PLANNED ACTIVITIES TO OBTAIN THOSE DATA
Process
Data Needs
Planned Activities
N>
Wellnan-Galusha Gaslfler
Partlculate Removal -
Hot Cyclone
Gas Quenching/Cooling
Tar Removal -
Electrostatic Precipitation
Sulfur Removal - Stretford
End Use - Combustion
Fate of pollutants (sulfur species, nitrogen species, tars and oils)
for various gasifler operating conditions and coal feedstocks.
Operating conditions that need to be evaluated include steam/air
ratio, coal throughput, and bed depth. High-sulfur bituminous coal
has not been tested since all commercial facilities use low-sulfur
bituminous and anthracite coals.
Collection efficiencies of hot cyclones are needed since the
partlculates not removed will affect downstream gas purification
processes and the raw gas combustion process characteristics and
flue gases.
Fate and distribution of sulfur species, nitrogen species, tars,
oils and particulate natter are needed. The quenched and cooled
gas characteristics will affect the performance and design of
downstream purification processes.
Tar removal effectiveness needs to be determined since residual
tar/oil aerosols will affect the performance and design of
downstream sulfur removal processes.
Sulfur removal effectiveness needs to be determined. There are
currently no data on the performance of the Stretford process
used to remove H2S from low-Btu gas.
Combustion gases from burning hot raw gas, quenched gas and
desulfurized gas are needed along with tar combustion gases.
Research Triangle Institute and North
Carolina State University will be performing
parametric studies on bench-scale gasifiers
using various coal feedstocks.
Particulate removal efficiency studies for
the hot cyclone at the UMD facility are
planned.
The Can Do Wellman Galusha facility will
have a gas quenching/cooling process. The
Chapman facility may also be used to evaluate
this process.
The tar/oil removal effectiveness will be
determined at the UMD gasification facility.
Stretford process performance will be
evaluated by EPA and DOE if a Stretford unit
is used at Pike County. Other test sites
are currently being identified.
Combustion gases will be characterized at
the Ft. Snelllng and UMD facility.
-------
TABLE 6-3. EPA PROGRAM OFFICE DATA NEEDS
E?A Program
Office
OAQPS
OWP/Effluent
Guidelines Dlv.
osw
Chemical Analyses
• Air Emissions
- Long term monitoring
end quantitative
analyses for:
• CO
' ""x
• tfonmethane
hydrocarbon*
• Photochealcal
oxidsnts
• Pb"
- Identification and
quantification of
other potentially
harmful pollutant*:
• Sulfur *pecle*
• Orgsnle*
• Trace elements
• Pollutant Monitoring
- Development of
continuous /semi-
continuous
monitoring devices
• Liquid Effluents
- Long-term monitoring
and quantitative
analyses for:
• 129 priority
pollutants
BOD
pB
Grease/ oils
P
COD
- Identification and
quantification of
other potentially
harmful pollutants
• Pollutant Monitoring
- Development of
continuous / »emi-
continuoua
monitoring devices
• Solid Waste* or Haste
Streams Seat to Land
Dispoeal Sltee
- PH
- Reactivity (explo-
sion potential)
- Radiuo-226
- Leachate
As
Cd
Pb
Se
Endrin
Methoxychlor
2,4-D
Ba
Cr
Hg
Llndane
Toxaphane
t L < _1*»
Biological Analyses Physical Analyses
Hone Air Emissions
- Partlculate
loading and
size
distribution
None • Liquid Effluents
- Long-term
monitoring and
quantitative
analysis for:
• TSS
• TPS
• Solid Wastes or • Solid Hastes or
Haste Screams Sent Vests Streams Seat
to Land Disposal to Land Disposal
Sites Sites
- Leachate - Flash point
• Mutageniclty - Corrosion tests
• Bloaccuou-
Lstlvity
• Toxic organic
CLD-50)
Control Technology
• Control Effectiveness
for Normal, Start-up,
Upset and Shut-down
Operation and for
Operational Rsaponse*
• Identification and
Quantification of
Liquid and/or Solid
Waste Streams from
Air Pollution Control
Technology
Recommendations for
Control Technology
RiP Meeds
• Control Effectiveness
for Normal, Start-up,
Upset and Shut-down
Operation and for
Operational Responses
• Identification and
Quantification of
Gaseous and/or Solid
Waste Streams from
Hater Pollution
Control Technology
• Recommendations for
Control Technology
R4D Needs
• Identification and
Quutifieatlon of
LMchibla matter froei
solid mattes
• Control Effectiveness
of leachate contain-
ment/control alternative
Recommendations for
New/Modified Methods
268
-------
TABLE 6-3. (Continued)
EPA Procrasi
Office
OTS
ChesUeal analyse* •
• Products/By-Product*
and Strsaaa not Regu-
lated by other
Progras) Offices
- Identification aad
quantification of
potentially harmful
organic and
inorganic specie*
Biological Analyses Payslcsl Analyses
• Products/By-
Product* and
Stzeasa not Regu-
lated by other
Progre» Offices
- Health effect a
- Ecological effecta
Control Technology
• nn inisMiiilil linn for
Controlling Expoeure to
Potentially Harmful
Streasv
OEP
Gaseous, Liquid and
Solid Weate Stress*
- o, 9 and Y-rsy
neuureaenta
- Queatitative
analyses for U-23S
and Th-232
None
Gaseous Emissions
- Particulars
loading and
else
diatribution
OC
Office of
Criteria and
Standard!
Data needa are similar to tho*e needed by other Program Officee.
evaluate ptrmit* and to iaaue permit* for gasification pleats.
Data should be sufficient to
Caseous, Liquid aad
Solid Waste Streaas
- Identification and
quantification of
potentially harmful
organic and
inorganic specie*
Saaaous, Liquid and
Solid Haste Streams
- Health effect*
' Ecological
effects
Office of
Nolle
Abacenent
and Control
Control Effectiveness
for Noroal, Start-up,
Upset and Shut-down
Operation and for
Operational Response*
Identification and
Quantification of
Pollutants In Caseous,
Liquid and/or Solid
Waste Screase froa
Esch Control Tech-
nology
Currently no data are needed for coal gasification technology. Sols* source* should be identified.
Gaseous Eaisslons
- Partieulate
loading and
size
distribution
Liquid Effluents
- TSS
- TDS
OUI:
OSW:
OTS:
OIF:
OE:
Office of
-------
APPENDIX
NOMENCLATURE, STRETFORD DESIGN BASIS, TRACE ELEMENT
PREDICTIONS, ATMOSPHERIC DISPERSION MODEL
A-l NOMENCLATURE
The following definitions apply to the terms which are
used thoughout this report to describe Wellman-Galusha gasifica-
tion systems. Also presented are EPA's terminology for Environ-
mental Impact Analyses.
Wellman-Galusha Gasification Systems Terminology -
Energy Technology - An energy technology is made up of
systems which are capable of producing a fuel, electricity, or
chemical feedstocks from fossil fuels, radioactive materials, or
natural energy sources (geothermal or solar). A technology may
be applicable to extraction of a fuel, e.g., underground gasifi-
cation; or the processing of a fuel, e.g., low-Btu gasification,
light water reactor, conventional boilers with fuel gas
desulfurization.
Operation - An operation is a specific function asso-
ciated with a technology and consists of a set of processes that
are used to produce specific products from certain raw materi-
als. For example, the operations for low/medium-Btu gasifica-
tion technology are coal pretreatment, coal gasification, and gas
purification, the processes which might be used in each of these
operations are:
*
• Coal Pretreatment - drying, partial oxidation,
crushing and sizing, briquetting, and pulverizing.
• Coal Gasification - fixed-bed/pressurized/slagging;
fixed-bed/pressurized/dry ash; entrained-bed
pressurized/slagging; fixed-bed/atmospheric/dry
ash; fluid-bed/atmospheric/dry ash; and
entrained-bed/atmospheric/slagging.
• Gas Purification - wet or dry particulate and tar
removal, gas quenching, and acid gas removal.
Process - Processes are basic units that make up a tech-
nology. A process is used to produce chemical or physical trans-
formations of input materials into specific output streams. Every
process has a definable set of waste streams which are, for prac-
tical purposes, unique. The term "process" used without modi-
fiers is used to describe generic processes. Where the term
"process" is modified (e.g., Lurgi process), reference is made to
270
-------
a specific process which falls in some generic class consisting
of a set of similar processes. For example, a generic process in
low/medium-Btu gasification technology is the fixed-bed/atmos-
pheric/dry ash gasification process. Specific processes which
are included in this generic class are Wellman-Galusha, Woodall-
Duckham/Gas Integrale, Chapman (Wilputte), Riley-Morgan, Foster
Wheeler/Stoic and Wellman-Incandescent.
Process Module - A process module is a representation of
a process which is used to display process input and output
streams. When used with other necessary process modules, they
can be used to describe a technology, a system or a plant. A
modular approach is well suited to environmental studies of com-
plex energy technologies. For example, in the case of petro-
leum refining, the basic processes which make up a petroleum
refinery are atmospheric distillation, catalytic cracking, etc.
Information on emission rates, as a function of throughput, can
be collected for each process module. Individual process mod-
ules can be used fairly interchangeably to describe plants with
process configurations which are typical of specific areas of the
country. For example, a refinery in the Southwest United States
might maximize gasoline production while one in the Northeast
might produce more fuel oil. Data on emissions, weather con-
ditions, and air quality for assumed plant sites can then be used
for diffusion modeling studies aimed at predicting air pollution
impacts which would be experienced if a refinery was in operation
at the assumed location.
Auxiliary Process - Auxiliary processes are used for
purposes that are in some way incidental to the main functions
involved in transforming raw materials into end-products. Aux-
iliary processes might be used to recovery by-products from waste
streams, to furnish necessary utilities, or to furnish feed mate-
rials such as oxygen which may or may not be required depending
on the form of the end-product which is desired. For example,
some auxiliary processes for low/medium-Btu gasification tech-
nology include a) oxygen production used to produce medium-Btu
gas, b) the Glaus process used to recover sulfur from H2S rich
gaseous waste streams, and c) the Phenosolvan process used to
recover phenols from liquid waste streams.
System - A system is a set of processes that can be used
to produce a specific end-product of the technology, e.g., low-
or medium-Btu gas. A technology is comprised of several alter-
nate systems. The simplest gasification system is one capable of
producing a hot combustion gas from coal using a small fixed-
bed, atmospheric, dry ash gasifier. A more complex system would
be required to produce a fuel clean enough to be fired in the gas
turbines of a combined-cycle unit for production of electricity.
271
-------
Plant - A plant is an existing system (or set of proces-
ses) that is used to produce a specific product of the technology
from specific raw materials. For example, the Glen-Gery Brick
Company operates several low-Btu gasification facilities that are
plants which produce combustion gas from anthracite coal.
Input Streams - Input streams are materials that must be
supplied to a process in order for it to perform its intended
function. Input streams may include primary or secondary raw
materials, streams from other processes, chemical additives, etc.
For example, at a minimum the input streams to a Lurgi gasifier
consist of sized coal, lock hopper filling gas, oxygen, steam,
and boiler feedwater. For auxiliary processes, a waste stream
from which a by-product is recovered is an input stream.
Output Streams - Output streams are confined product
streams, waste streams, streams to other processes, or by-pro-
ducts. For example, output streams from a Lurgi gasifier include
lock hopper (coal and ash) vent gases, wet ash, recovered steam,
blowdown condensate, and crude medium-Btu gas.
Raw Materials - Raw materials are feed materials for
processes. They are of two types: 1) primary raw materials that
are used in the chemical form in which they were taken from the
land, water or air, and 2) secondary raw materials that are pro-
duced by other industries or technologies. For example, primary
raw materials for low/medium-Btu gasification technology include
coal, air, and water. Secondary raw materials include fluxes,
makeup solvent, catalysts, etc.
Process Streams - Process streams are output streams
from a process that are input streams to another process in the
technology. For example, the crude medium-Btu gas from the Lurgi
gasification process is the feed (input) stream to a tar/particu-
late removal or quenching process.
Products - Products are process output streams that are
marketed for use or consumed in the form that they exit the sys-
tem. For example, the low-Btu gas exiting the final gas purifi-
cation process is the major output stream from a low-Btu gasifi-
cation facility.
By-Products - By-products are auxiliary process output
streams that are produced from process waste streams and are
marketed or consumed in the form in which they exit the process.
For example, tar is a by-product produced by certain low-Btu
gasification facilities. It may either be consumed (e.g., in a
boiler) or sold.
272
-------
Waste Streams - Waste streams are confined gaseous,
liquid, or solid process output streams that are sent to 1)
auxiliary processes for recovering by-products, 2) pollution con-
trol equipment or 3) ultimate disposal processes. Unconfined
"fugitive" discharges of gaseous or aqueous wastes and acciden-
tal process discharges are also considered waste streams. The
tail gas from an acid gas removal process is an example of a
waste stream in low/medium-Btu gasification technology.
Source - An emission source is any equipment item which
discharges either confined waste streams (solids, liquid, gaseous
or combinations) or significant quantities of unconfined, poten-
tially polluting substances in the form of leaks, spills, and the
like. Examples of sources include gasifier coal feed lock
hoppers which discharge emissions during coal feeding, and the
Glaus reactor which recovers sulfur and discharges tail gases
containing polluting sulfur compounds.
Effluent streams - Effluent streams are confined aqueous
waste streams which are potentially polluting. These will be
discharged from a source.
Emission Streams - Emission streams are confined gaseous
waste streams which are potentially polluting. These will also
be discharged from a source.
Fugitive Emissions - Fugitive emissions are unconfined
process-associated discharges, including accidential discharges,
of potential air pollutants. These may escape from pump seals,
flanges, etc., or as emissions in abnormal amounts when accidents
occur and may be associated with storage, processing, or trans-
port of materials as well as unit operations associated with a
process. They will escape from a source.
Fugitive Effluents - Fugitve effluents are unconfined
process-associated discharges, including accidental discharges,
of potential water pollutants which are released as leaks,
spills, washing waste, etc., or as effluents in abnormal amounts
when accidents occur. These may be associated with storage,
processing, or transport of materials as well as unit operations
associated with industrial processes. They may be discharged to
municipal sewers, and can lead to the generation of contamina-
ted runoff water. They will escape from a source.
Accidental Discharge - Accidental discharges are
abnormal discharges (solid, liquid, gaseous or combinations)
which occur as a result of upset process conditions.
273
-------
Unit Operation - Unit operations, like processes des-
cribed above, are employed to take input materials and perform a
specific physical or chemical transformation. The equipment mak-
ing up a unit operation may or may not have one or more waste
stream(s). A process is made up of one or more unit operations
which have at least one source of waste material(s). Examples of
unit operations are: distillation, evaporation, crushing,
screening, etc.
Final Disposal Processes - Final disposal processes are
used to ultimately dispose of liquid and solid wastes from pro-
cesses, auxiliary processes, and control equipment employed in a
technology. Examples of final disposal processes are landfills
and evaporation ponds.
Control Equipment - The primary function of control
equipment is to minimize the release of pollutants to air, water
or land, resulting from process discharges. While the collected
materials may be sold, recycled or sent to final disposal, con-
trol equipment is not essential to the economic viability of the
process. Where such equipment is designed to be an integral part
of a process, e.g., scrubbers which recycle process streams, they
are considered a part of the basic process.
Residuals -Residuals are gaseous, liquid, or solid
discharges from control equipment and final disposal processes.
Examples of residuals include emissions from control equipment
(such as scrubbers), auxiliary processes (e.g., tail gases from a
Glaus sulfur recovery unit) and evaporation ponds (which emit
vapors).
Terminology for Environmental Impact Analysis -
EPA/IERL-RTP has developed a terminology for environ-
mental impact analyses. It includes three categories of terms:
primary, secondary, and component that can be applied to judge
the environmental acceptability of waste streams or product/by-
product discharges from industrial processes or energy systems.
Primary terms, which have been used frequently in IERL-RTP en-
vironmental assessment projects are:
Discharge Severity (PS) - Discharge severity is a simple
index of the potential harmful health or ecological effects of a
single substance in a discharge. The DS does not require mod-
eling or assumptions as to how the substance might disperse in
the receiving medium.
Weighted Discharge Severity (WPS) - WPS is a simple
index that reflects both the potential harmful health or ecolog-
274
-------
ical effects of a single substance as well as the quantity of the
total discharge. The WDS is similar to the DS except that it is
intended for comparative evaluations of streams having signifi-
cantly different discharge rates.
Total Discharge Severity (TDS) - TDS is a simplified
index of the overall potential health or ecological impact of a
discharge. The TDS is the sum of the individual human health or
ecological DS values of a given stream; in terms of human ef-
fects, the TDS covers a broad range of physiological responses,
and when applied in terms of ecological effects it includes both
species and biological ramifications.
Ambient Severity (AS) - AS is an indicator of the poten-
tial harmful health or ecological effects of substances on the
basis of estimated long-term ambient concentrations resulting
from stream discharges.
Total Ambient Severity (TAS) - TAS is the ambient ana-
log of TDS"IIts uses are similar to those for TDS; in addition,
it may be applied to compare impacts of two or more waste
streams.
Component terms are used in the specific definitions of
primary terms, as shown in the equation for DS:
DS - dc/DMEG
where ci£ is the component term for the discharge concentration of
a substance, and DMEG is the component term referring to the Dis-
charge Multimedia Environmental Goal for the same substance.
Individual DMEG values for a substance are related to health or
to ecological effects and specify the substance concentration es-
timated to cause minimal adverse effects in a healthy receptor
(man, plant, or animal) exposed once or intermittently for short
time periods.
Component terms for the WDS are used in the equation:
WDS = DS° mr
where mr is the total rate of stream discharge; i.e., the quant-
ity (g, m3 or 1) of the total stream discharged per unit of
t ime.
Component terms for the TDS appear in the equation:
TDS - DS = (dc/DMEG)
275
-------
For AS the equation is:
AS = ac/AMEG
where the component term ac is the ambient concentration of a
substance attributable to the discharge of concern, and AMEG is
the component term for the Ambient Multimedia Environmental Goal
for the same substance. The ac is estimated from mathematical
models for environmental dispersion. AMEG values for specific
substances are similar to DMEG values except that they are based
on a continuous, rather than a single or intermittent, period of
exposure.
For TAS the equation reads:
TAS = AS = (ac/DMEG)
The secondary terms of the IERL-RTP terminology are
still being developed and have been used infrequently to date.
However, they may gain prominence as risk assessment becomes more
widely practiced in environmental assessment programs. Secondary
terms include:
• Impact factor: a representation of the number of
receptors (plants, animals, or humans) exposed to
ambient severities (or total ambient severities)
greater than some critical value.
• Ambient concentration profile: a tabular or
graphic display of estimated ambient concentrations
shown as a function of distance from the point of
discharge.
• Exposure concentration profile: a tabular or
graphic illustration of the number of receptors ex-
posed to estimated ambient concentrations of sub-
stances attributable to a discharge of concern.
A-2 DESIGN BASIS FOR STRETFORD
Material balance calculations were made to determine the
raw material requirements and the quality and composition of
waste streams for the Stretford process in treating the four dif-
ferent product gases. These calculations were based on design
information given in the literature and obtained from personal
communications with licencees of the Stretford process. The major
design assumptions are given and discussed in this appendix.
276
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H£^ Loading -
The concentration of hydrosulfide ion (HS~) in the
Stretford solutuion achieved is an important design criteria. It
can be controlled by controlling the ratio of the gas flow rate
to the wash liquor flow rate. For a given gas flow rate, the
HS~ loading determines the wash liquor flow rate and thus the
size of the absorber, delay tank and oxidizer. Along with the
stoichiometry of the chemicals used and the amount of impurities
present, it also determines the wash liquor composition. Moyer
and Wilkerson (Ref. 30) in 1974 reported that practical concen-
trations lie in the range of 400 to 750 ppm, although the process
is not limited to this range. Kohl and Risenfield (Ref. 16) re-
ported that loadings of 500 ppm are common, but can be as high as
1000 ppm. The standard British Gas Council design calls for
loadings of 500 ppm (Ref. 31). Various loadings are given for
different plants in the literature. For this study, a 500 ppm
loading was used for the low-sulfur bituminous, anthracite, and
lignite coals, and 750 ppm was used for high-sulfur bitumi-
nous, which had a much higher inlet H2S loading.
Chemical Concentrations -
Concentrations of 0.3 N NaHCC>3 and 0.1 N Na2CC>3
were assumed. These proportions, however, may be affected by the
partial pressure of C02 in the gas stream. Sodium metavanadate
and anthraquinone disulfonic acid concentrations were assumed to
be 1.2 times the stoichiometric requirement. Small amounts of
iron (50 ppm) and EDTA (2700 ppm) were also assumed to enhance
the oxidation of ADA (Ref. 16).
Solution Slowdown -
A blowdown of Stretford solution is necessary to remove
non-regenerable compounds such as sodium thiocyanate and sodium
thiosulfate from the system. All HCN in the feed gas was assumed
to be absorbed in the solution, forming thiocyanate. Thiosulfate
formation depends on several factors. For example, it increases
with increasing pH, increasing temperature, and increasing oxygen
content of the feed gas. In a properly operated plant, it re-
portedly can be controlled to less than 170 of the sulfur in the
feed gas (Ref. 16). For these calculations, a formation rate of
170 of the feed gas sulfur was assumed. Continuous purge is usu-
ally practiced when the solution reaches 20 to 2570 total salts
concentration. Twenty-five percent was assumed for these
calculations.
277
-------
Oxygen Utilization -
Various degrees of oxygen utilization in the oxidizer
have been reported. A utilization of 157o was assumed for those
calculation purposes (Ref. 16).
Sulfur Cake Filtration and Washing -
The sulfur cake from the vacuum filter was assumed to be
50% solids (Ref. 16). Information on the degree and effective-
ness of cake washing to recover Stretford chemicals was difficult
to find. Up to three displacement washes are generally used.
With three washes, 96 to 97% of the chemicals are recovered. By
assuming equal washing efficiencies for each wash, it was esti-
mated that 66% of the original chemicals would be recovered by
one displacement wash.
Operating Temperature -
Since the feed gas to the Stretford is saturated with
water, it was assumed that the Stretford solution enters the
absorber at the same temperature as the gas, 317 K (110°F), to
avoid condensing water from the gas. This is within the opera-
ting temperature range of 294 to 317 K (70 to 110°F) given by
Kohl and Risenfeld (Ref. 16).
A-3 PREDICTION OF TRACE ELEMENT DISTRIBUTION BY
THERMODYNAMIC EQUILIBRIUM
A theoretical distribution of trace element species in
gasification products was calculated by assuming that the trace
elements are in equilibrium at the temperature and pressure of
the gasifier outlet. The quantities for the major elements were
established from the total coal, air, and steam fed to the gasi-
fier. Concentrations of trace elements in the coals were as-
sumed to be the highest values from Table 3.2-3.
With these inputs, free energy minimization was used to
calculate the equilibrium distribution of the trace element
species. This technique makes use of the fundamental principal
of thermodynamic equilibrium--the minimization of free energy as
a function of independent variables--with emphasis placed on
species, elements, and the elemental composition of each spe-
cies. The equilibrium species are calculated as those that make
the total free energy of the system a minimum subject to the con-
straint of the conservation of all the chemical elements.
This technique is especially well-suited to calculation
of the distribution of trace species. The trace elements are
present in such small amounts that they do not contribute to the
278
-------
total free energy of the system (to the closure error of the
iterative minimization process). Thus, their distributions can
be calculated independently from each other and from the major
element distributions. A total of 21 trace elements and 334
trace species were considered in this analysis. These species
are listed in Table A.3-1.
Certain limitations to the accuracy of these predictions
should be noted. The assumption that all trace element species
are at equilibrium is probably not valid. Moreover, the gasifi-
cation process involves complex chemical reactions that cannot be
adequately modeled with a single-stage equilibrium model. This
is demonstrated by the deviation between the calculated major
element distribution and the measured gas composition in opera-
ting gasifiers. The possible significant effect of the high
temperature in the gasifier bed on the distribution of the trace
species is not taken into account in this model. Kinetic and
other limitations on the formation of certain trace species are
not taken into account directly, although they can be reflected
by omitting species that would not be expected to form at con-
ditions normally encountered in gasification operations.
In spite of these limitations, this model does give an
indication of which trace elements are potentially volatilized in
a gasification process, and provides an insight into which
species would be thermodynamically stable at the gasifier outlet
conditions and may be present in the product gas.
A comparison of the calculated trace element distribu-
tion with measured data for the COED process is given in Table
A.3-2. As shown, elements found experimentally to be vaporized
to an extent greater than 60% (Hg, Se, As, Pb, and Cd) were cal-
culated by the program to be completely vaporized. Most of those
determined to be less than 30% vaporized were calculated to be
condensed (Be is an exception). As more of this type of data be-
comes available, the utility and range of applicability of the
model should be enhanced (Ref. 80).
A-4. DESCRIPTION OF THE ATMOSPHERIC DISPERSION MODELING
TECHNIQUES USED TO CALCULATE THE AMBIENT AIR IMPACT
DATA PRESENTESD IN SECTION 4.0
The maximum 1-hour, 3-hour, and 24-hour concentrations
were computed using the Radian short-term and intermediate-term
computer models, respectively. These models apply the Gaussian
dispersion equation to compute the ground level pollutant con-
centrations and are consistent with the procedures suggested by
the Environmental Protection Agency.
279
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TABLE A.3-1. SPECIES CONSIDERED IN FREE ENERGY MINIMIZATION PROGRAM
to
oo
o
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
CO
H20
C02
N2
HC1
H2S
H2
0
OH
H
S2
Ss (g)
S7 (g)
S5 (g)
S5 (g)
S* (g)
Sa (g)
S (g)
S02
COS
S03 (g)
CS2
SH
SO
cs
NO
N20
NO*
HCN
NH3
Cl
C12
02 (g)
CHt,
Mod* (g)
MoCl (g)
37.
38.
39.
40.
41.
42.
43.
44.
45.
46.
47.
48.
49.
50.
51.
52.
53.
54.
55.
56.
57.
58.
59.
60.
61.
62.
63.
64.
65.
66.
67.
68.
69.
70.
71.
72.
Mo (s)
Mo (g)
MoO (g)
MoO2 (s)
Mo02 (g)
Mo03 (s)
Mo03 (1)
Mo03 (g)
Mo02Cl2 (g)
H2MoOM (g)
Mod,, (g)
MoS2 (a)
MoSj (s)
Mo(SOH)s
CoCl (g)
CoCl2 (s)
CoCl2 (g)
CoCl3 (g)
Co2CL, (g)
CoH (g)
Co (g)
Co (a) A
Co (a) B
Co (a) C
Co (1)
CoO (s)
CoO (g)
Co 3 On (s)
CoS (s)
CoC03 (s)
CoSOi,
As (g)
As2 (g)
As,, (g)
AsO (g)
Aa203
73.
74.
75.
76.
77.
78.
79.
80.
81.
82.
83.
84.
85.
86.
87.
88.
89.
90.
91.
92.
93.
94.
95.
96.
97.
98.
99.
100.
101.
102.
103.
104.
105.
106.
107.
108.
As203 (1)
As2S3
As2S3 (1)
H3AsO* (g)
HAs03 (g)
AsCl3 (g)
AsH3
AsN (g)
Pb (g)
Pb (a)
(Pb)2
Pb (1)
PbS (s)
PbS (1)
PbS (g)
PbO (g)
PbO Red
PbO Yel
PbO (1)
Pb02 (s)
Pb30H (s)
Pb(Cl)
Pb(Cl)2 (s)
Pb(Cl)2 (1)
Pb(Cl)2 (g)
Pb(Cl),,
PbH
Pb(CH3K
PbCOs (c)
PbSO,,
Be (g)
Be (1)
Be (s)
BeO (g)
BeO (1)
BeO (s)
109.
110.
111.
112.
113.
114.
115.
116.
117.
118.
119.
120.
121.
122.
123.
124.
125.
126.
127.
128.
129.
130.
131.
132.
133.
134.
135.
136.
137.
138.
139.
140.
141.
142.
143.
144.
Be303 (g)
Be»0* (g)
BeCl (g)
BeH2 (g)
BeCl2 (g)
BeCl2 (1)
BeCl2 (s)
BeS (s)
BeOH (g)
Be (OH) 2 (g)
BeC03 (s)
Be,N2 (s)
BeSOH
Hg (g)
Hg (1)
HgO (s)
HgO (g)
HgS Red
HgCl (g)
Hg(Cl)2 (a)
Hg(Cl)2 (1)
Hg(Cl)2 (g)
Hg2Clz (a)
HgH (g)
Se (g)
Se (a)
SeH2
Se2C
SeCO
SeO (g)
Se02 (g)
Se2 (g)
Se(CH3)2
SeCS (g)
SeC (g)
Ni (a) A
145.
146.
147.
148.
149.
150.
151.
152.
153.
154.
155.
156.
157.
158.
159.
160.
161.
162.
163.
164.
165.
166.
167.
168.
169.
170.
171.
172.
173.
174.
175.
176.
177.
178.
179.
180.
Ni (a) B
Ni (g)
NiO (g)
NiO (s) B
NiS (a)
NiC03 (a)
Ni(COK (g)
NiCl2 (a)
NiCl (g)
NiCl2 (g)
NiSOi,
Sb (a)
Sb (1)
Sb (g)
Sb2 (g)
Sb, (g)
SbO (g)
Sb203 (a)
Sb203 (1)
Sb20H (a)
Sb2S3 (a)
Sb2S3 (1)
SbH3 (g)
SbCl (g)
SbCl2 (g)
SbCl3 (g)
SbCl3 (1)
HSb03 (g)
H3SbOH (g)
Sb^SO,,):,
V03H2 (g)
V20S (a)
V205 (1)
VO (a)
VO (g)
V203 (a)
181.
182.
183.
184.
185.
186.
187.
188.
189.
190.
191.
192.
193.
194.
195.
196.
197.
198.
199.
200.
201.
202.
203.
204.
205.
206.
207.
208.
209.
210.
211.
212.
213.
214.
215.
216.
V20H (a)
V20H (1)
V (a)
V (g)
V02 (g)
VN (s)
VN (g)
V2S3 (a)
V2S3 (1)
VS (a)
VC12 (s)
VC12 (g)
VC19 (a)
VCU (g)
VOC13 (g)
VOSO,,
Cr (g)
Cr (s)
CrCl2 (g)
CrN (g)
CrO (g)
Cr02 (g)
Cr03 (g)
H2CrO,» (g)
Cr203 (a)
Cr03 (a)
CrCl2 (s)
CrCl3 (a)
Cr (SO,,) 3
CuCl2 (g)
CuH (g)
CuCl2 (a)
Cu (a)
Cu (1)
Cu (g)
CuO (a)
Continued
-------
TABLE A.3-1. (.Continued)
217.
218.
219.
220.
221.
222.
223.
224.
225.
226.
227.
228.
229.
230.
231.
to 232'
oo 233.
M 234.
235.
236.
237.
238.
239.
240.
241.
242.
243.
244.
245.
246.
CuO (g)
CU2
Cu20 (s)
Cu20 (1)
CuCl (s)
CuCl (1)
CuCl (g)
CuS (s)
Cu2S (s)
CuC03 (s)
CuSOi»
P2 (g)
PCls (g)
P (g)
PS (g)
PO (g)
PO* (g)
P*06 (g)
P-.OIO (s)
P-Oio (g)
PCI (g)
POClj (g)
PCls (g)
PSC1S (g)
PH (g)
PH2 (g)
PH9 (g)
Sn (g)
Sn (1)
SnO (s)
247.
248.
249.
250.
251.
252.
253.
254.
255.
256.
257.
258.
259.
260.
261.
262.
263.
264.
265.
266.
267.
268.
269.
270.
271.
272.
273.
274.
275.
276.
SnO (g)
SnO 2 (s)
SnS (s) A
SnS (s) B
SnS2 (s)
SnS (g)
SnCl2 (g)
SnCl,, (g)
SnH (g)
SnCl (g)
Sn(SO,,)2
Mn (g)
MnO (s)
MnO (g)
MnCl2 (g)
MnH (g)
Mn203 (s)
MnjO,, (s)
MnS (s)
MnC03 (s)
MnS 2 (s)
MnCl (g)
MnCl2 (s)
MnSO,,
Mn2(SO,,)3
Zn (g)
Zn (s)
ZnCl (g)
ZnCl2 (g)
ZnCl2 (1)
277.
278.
279.
280.
281.
282.
283.
284.
285.
286.
287.
288.
289.
290.
291.
292.
293.
294.
295.
296.
297.
298.
299.
300.
301.
302.
303.
304.
305.
306.
ZnH (g)
ZnO (g)
ZnO (s)
ZnS (s)
ZnC03 (s)
ZnCl2 (s)
ZnSOi,
Ge (g)
Ge (s)
GeH (g)
GeO (g)
Ge02 (s)
GeS (s)
GeS2 (s)
GeS (g)
Gelt, (g)
GeCl (g)
GeClH (g)
Ge(SO,,)2
Cd (g)
Cd (1)
CdO (s)
CdO (g)
CdS (s)
CdCl (g)
CdCl, (g)
CdCl2 (1)
CdCl2 (s)
Cd(OH)2 (g)
CdH (g)
307.
308.
309.
310.
311.
312.
313.
314.
315.
316.
317.
318.
319.
320.
321.
322.
323.
324.
325.
326.
327.
328.
329.
330.
331.
332.
333.
334.
335.
336.
Cd(CH3)2
CdC03
CdSOi*
B203 (g)
BH303 (g)
BH02 (g)
BO (g)
B02 (g)
B2(OH),, (g)
B202 (g)
B203 (s)
B203 (1)
BH3 (g)
BH2 (g)
B(OH)2 (g)
BC13 (g)
BOC1 (g)
BaS (g)
BaS (s)
BaCl2 (s)
BaCl2 (1)
BaCl2 (g)
BaO (s)
BaO (g)
BaH (g)
BaCOd (s) A
BaC03 (s) B
BaC03 (s) C
Ba (s) A
Ba (s) B
337.
338.
339.
340.
341.
342.
343.
344.
345.
346.
347.
348.
349.
350.
351.
352.
353.
354.
355.
356.
357.
358.
359.
360.
361.
362.
363.
364.
365.
366.
367.
368.
Ba (1)
Ba (g)
BaCl (g)
BaSO,, (s)
UC13 (s)
UC13 (1)
UC13 (g)
U (s) A
U (s) B
U (s) C
U (1)
U(C03)2 (s)
U(SOO2 (s)
UC15 (s)
UC15 (1)
UC15 (g)
UCln (s)
UCU (1)
UC1* (g)
UOC12 (s)
UOC13 (s)
UOC1 (s)
UC16 (1)
UC16 (g)
US2 (s)
US (s)
U03 (s)
U*09 (s)
U308 (s)
U02 (s)
U02C12 (s)
U02 (g)
-------
TABLE A.3-2. COMPARISON OF OBSERVED AND PREDICTED TRACE ELEMENT VOLATILIZATION
IN THE COED PROCESS
N>
OO
Percent volatilized
Element
Hg
Se
As
Pb
Cd
Sb
V
Ni
Be
Cr
B
Co
Cu
Ge
Mn
Mo
P
Sn
U
Zn
Ba
Coal
wt, ppm
0.27
1.7
9.6
5.9
0.78
0.15
33
12
0.92
15
102
9.6
15
6.9
49
7.5
71
4.8
1.3
272
130
Important species, %
Hg(g)
H2Se(97), COSe(2.9), Se(g)(0.22)
AsN(g)(30), HAs03(g)(27), H3AsO,, (g) (23) , As2(g)(15),
AsH3(g)<3.1), Ac(g)(0.44), AsO(g)(0.24)
Pb(g)(73), PbS(g)(27), PbCl(g)(0.21)
Cd(g)
SbCl(g)(51). H3SbO,,(g)(45), Sb(g)(3.2),
HSb03(g)(0.60)
V2 S3 (DUOO)
Ni(s)(100)
Be (OH) 2 (g)
Cr203(8)
HsB03(g)(62), HB02(g)(38)
Co(s)(59), CoH(g)(41)
Cu(s)(67), CuH(g)(25), Cu(g)(7), CuCl(g)(1.9)
GeO(g)(91), GeS(g)(9)
MnO(s)(100), Mn(g)(0.03)
H2MoO^(g)(73), Mo(s)(16), MoCl2(g)(ll)
P*06 (g)
SnS(g)(95), SnO(g)(3.7), SnH(g)(1.2)
U02 (s)
Zn(g)
BaC03(s)(96), BaCl2(g)(4)
Observed
96
74
63
62
33
30
24
18
0.0
Equilib-
rium
100
100
100
100
100
0.0
0.015
100
0.0
100
41.2 •
33.4
100
0.03
83.8
100
100
0.0
100
4.0
-------
Both the short- and intermediate-term models use the RAM
formulation of the Gaussian dispersion equation and the RAM
assumption for calculating plume reflections within the mixing
layer. Plume rise is calculated using Briggs 1970 "X" formula.
The Pasquill-Gifford coefficients of dispersion described in
Turner's "Workbook" are used for all atmospheric stability con-
ditions. Wind speeds were adjusted from the surface to the plume
height using a power law relationship.
The short-term dispersion model used in this study is
capable of predicting average concentrations for time period
ranging from several minutes to several hours. The intermedi-
ate model has the option of subdividing a given averaging period
into smaller time intervals with specified plant emissions and
meteorological conditions which are assumed constant within that
time interval, but which can change from interval to interval.
The model solves the Gaussian dispersion equation for each of
these intervals, and computes the final average concentration as
a weighted average of the contributions from the individual time
increments.
The model inputs consist of two classes of data. The
first describes the atmospheric conditions during which the
pollutant is being dispersed, while the second class deals with
emission rates and stack parameters.
The EPA CRSTER model was used as a screening tool to
identify worst-case meteorological conditions. CRSTER locates
all emission sources and uses actual meteorological data. These
consist of hourly surface observations with wind directions re-
ported to the nearest 10 degrees and twice daily mixing depths
determined from upper air soundings. Meteorological data in this
format were not readily available for the Northeast part of the
U.S.; hence data for Houston's Hobby Airport in 1970 were used
instead. Since the current analysis is non-site specific, this
is an acceptable procedure.
The worst-cases 1-, 3-, and 24-hour periods were identi-
fied with a CRSTER run for CO. The meteorological conditions so
determined were then used in conjunction with the Radian short-
and intermediate-term models to produce 1-, 3-, and 24-hour down-
wind concentration curves for the pollutants considered.
283
-------
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ing Method for Environmental Assessment of Fossil-Energy
Process Effluents. PE-277 088, EPA-600/7-78-015. Acurex
Corp./ Aerotherm Corp., Mountain View, CA, February 1978.
75. Ghassemi, M., K. Crawford, and S. Quinlivan. Environmental
Assessment Report: Lurgi Coal Gasification Systems for SNC.
PB-298 109, EPA-600/7-79-120. TRW Environmental Engineering
Div., Redondo Beach, CA, May 1979.
76. Whittiker, Donald E. Pullman Kellogg. Personal Communica-
tion. August 21, 1979.
77. Environmental Protection Agency, Office of Air Quality Plan-
ning and Standards. Control of Emissions from Lurgi Coal
Gasification Plants. PB-279 012, EPA-450/2-78-012.
Research Triangle Park, NC, March 1978.
78. U.S. Department of the Interior, Bureau of Mines. Noise
Control, Proceedings: Bureau of Mines Technology Transfer
Seminar, Pittsburgh, PA, January 22, 1975. U.S. Bur. Mines,
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290
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-80-093
2.
,. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Environmental Assessment Report: Wellman-Galusha
Low-Btu Gasification Systems
8. REPORT DATE
May 1980
i. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Pat Murin, Theresa Sipes, andG.C. Page
. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78766
1O. PROGRAM ELEMENT NO.
INE825
117CONTRACT/GRANT NO.
J-02-2147, Exhibit A
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND
Final; 5/78-9/79
NO PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES jERL-RTP project officer is William J. Rhodes , Mail Drop 61,
919/541-2851. EPA-600/7-78-202 and EPA-600/7-79-185 are related reports.
16. ABSTRACT.
The report, an Environmental Assessment Report (EAR) for Wellman-
Galusha low-Btu gasification systems, is part of an overall environmental assess-
ment program for low-medium-Btu gasification technology. This EAR provides EPA
administrators and program offices with a document representing the Office of
Research and Development's (ORD's) research input to standards support for
Wellman-Galusha gasification facilities. This EAR is a detailed evaluation and pre-
sentation of process, control, and waste stream data collected from field tests,
open literature, vendors, process licensors, and computer modeling. It gives an
overview of Wellman-Galusha gasification systems, including estimates of the sys-
tems' energy conversion efficiencies and capital and operating costs. It provides
data characterizing the systems' input materials, process streams, products, by-
products, and multimedia discharges. It identifies pollution control alternatives for
the multimedia discharges and toxic substances in the systems' products and by-
products, and estimates their costs and energy impacts. It assesses regulatory
requirements for the environmental impacts of the systems. It gives data needs and
recommendations for obtaining those data, and discusses the EPA program office
issues and areas of concern for the Wellman-Galusha low-Btu gasification technology
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Coal Gasification
Assessments
Energy Conversion
Techniques
Efficiency
Expenses
Pollution Control
Stationary Sources
Wellman-Galusha Pro-
cess
Environmental Assess-
ment
13B
13H
14B
10A
14B
05C,14A
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Rtport>
Unclassified
21. NO. OF PAGES
306
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2210-1 (••73)
291
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