&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research EPA-600/7-79-120
Laboratory May 1979
Research Triangle Park NC 27711
Environmental
Assessment Report:
Lurgi Coal Gasification
Systems for SNG
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-600/7-79-120
May 1979
Environmental Assessment Report;
Lurgi Coal Gasification
Systems for SNG
by
M. Ghassemi, K. Crawford, and S. Quinlivan
TRW Environmental Engineering Division
One Space Park
Redondo Beach, California 90278
Contract No. 68-02-2635
Program Element No. EHE623A
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
This Environmental Assessment Report (EAR) for the Lurgi SNG systems con-
sists of compilation and analysis of available data on the equipment and proc-
esses which constitute the Lurgi SNG systems, the control/disposal alternatives
for a media, the performance and cost of control alternatives, and the present
and proposed environmental requirements. The report presents, for the use by
EPA Program Offices, the best technical basis currently available for the estab-
lishment of standards for Lurgi SNG plants.
The Lurgi SNG systems were subdivided into four operations '(coal prepara-
tion, coal gasification, gas purification and gas upgrading) and a number of
auxiliary processes (air pollution control, raw water treatment, oxygen produc-
tion, etc.), with each operation comprised of a number of processes. The data
on the characteristics of input materials, products and waste streams associated
with each process were presented. The pollution control alternatives for air
emissions, water effluents, solid wastes, and toxic substances in an integrated
facility were examined for performance, costs, energy requirements and ability
to comply with current and anticipated environmental standards. The adequacy
of the data was evaluated and the additional data needed to support standards
development and enforcement and health and ecological effects and control tech-
nology R&D were identified.
The Lurgi gasification and a number of other processes which would be used
in an SNG plant have been used commercially in other applications. Some of the
data for these applications would be relevant to Lurgi SNG plants. No data are
available on characteristics and treatment of certain waste streams which would
be unique to Lurgi SNG plants. Programs which are recommended for filling many
of the data gaps include (a) comprehensive sampling and analysis of effluents
at existing Lurgi gasification plants and other industrial sites using compon-
ents of the Lurgi SNG systems and (b) engineering and pilot plant studies to
assess the performance of controls in Lurgi SNG service. The on-going and
planned programs which may supply some of the needed data are reviewed.
ii
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CONTENTS
Abstract ii
Figures viii
Tables x
Nomenclature xiv
Acknowledgement xv
1. SUMMARY 1
1.1 Overview of Lurgi SNG Systems 2
1.1.1 Status of Development 2
1.1.2 Description of Lurgi SNG Systems 3
1.1.3 Process Energy and Cost Considerations 10
1.1.4 Commercial Prospects for a Lurgi SNG Industry 11
1.2 Waste Streams and Pollutants of Major Concern 13
1.3 Status of Environmental Protection Alternatives 16
1.4 Data Needs and Recommendations 17
1.5 Issues and Areas of Concern for Program Offices 21
2. PROCESS DESCRIPTION OF LURGI GASIFICATION SYSTEMS 23
2.1 Technical Overview of Lurgi Systems 23
2.1.1 Status of Development 23
2.1.2 Industrial Applicability of Lurgi Systems 28
2.1.3 Input Materials, Products and Byproducts 29
2.1.4 Energy Efficiencies 33
2.1.5 Capital and Operating Costs 35
2.1.6 Commercial Prospects 38
2.2 Description of Processes 39
2.2.1 Generalized Process Flow Diagrams 40
2.2.2 Coal Pretreatment 40
2.2.3 Coal Gasification 48
2.2.4 Gas Purification 51
2.2.5 Gas Upgrading 60
2.2.6 Auxiliary Processes 60
*
iii
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CONTENTS (Continued)
2.3 Process Areas of Current Environmental Concern
71
.... 72
2.3.1 Coal Pretreatment and Handling 71
2.3.2 Coal Gasification
79
2.3.3 Gas Purification
2.3.4 Gas Upgrading 73
2.3.5 Auxiliary Processes 74
3. CHARACTERIZATION OF INPUT MATERIALS, PRODUCTS AND WASTE STREAMS . . 77
3.1 Summary of Sampling and Analytical Activities 77
3.1.1 IERL/RTP Environmental Assessment Activities 77
3.1.2 Non-IERL/RTP Site Evaluations 80
3.2 Input Materials 81
3.2.1 Coal Pretreatment and Handling 81
3.2.2 Coal Gasification 81
3.2.3 Gas Purification 85
3.2.4 Gas Upgrading 85
3.2.5 Auxiliary Processes 86
3.3 Process Streams 86
3.3.1 Coal Pretreatment and Handling 88
3.3.2 Coal Gasification 88
3.3.3 Gas Purification 89
3.3.4 Gas Upgrading 91
3.4 Toxic Substances in Products and By-Products 97
3.4.1 Coal Pretreatment and Handling 97
3.4.2 Coal Gasification 97
3.4.3 Gas Purification 97
3.4.4 Gas Upgrading 99
3.4.5 Auxiliary Processes 99
3.5 Waste Streams to Air 104
3.5.1 Coal Pretreatment and Handling 104
3.5.2 Coal Gasification 104
3.5.3 Gas Purification 107
3.5.4 Gas Upgrading 109
3.5.5 Auxiliary Processes 109
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CONTENTS (Continued)
3.6 Waste Streams to Water 114
3.6.1 Coal Pretreatment and Handling 114
3.6.2 Coal Gasification 116
3.6.3 Gas Purification 119
3.6.4 Gas Upgrading 124
3.6.5 Auxiliary Processes 124
3.7 Solid Wastes 127
3.7.1 Pretreatment and Handling 129
3.7.2 Coal Gasification 129
3.7.3 Gas Purification 129
3.7.4 Gas Upgrading 129
3.7.5 Auxiliary Processes ..... . 131
PERFORMANCE AND COST OF CONTROL ALTERNATIVES 133
4.1 Procedures for Evaluating Control Alternatives 133
4.2 Air Emissions Control Alternatives 134
4.2.1 Coal Pretreatment and Handling 134
4.2.2 Coal Gasification ........ 131
4.2.3 Gas Purification 140
4.2.4 Gas Upgrading 159
4.2.5 Auxiliary Processes 159
4.3 Water Effluent Control Alternatives 172
4.3.1 Coal Pretreatment and Handling 174
4.3.2 Coal Gasification 174
4.3.3 Gas Purification 175
4.3.4 Gas Upgrading 173
4.3.5 Auxiliary Processes ^g
4.4 Solid Waste Management Alternatives 201
4.4.1 Coal Pretreatment and Handling 204
4.4.2 Coal Gasification 204
4.4.3 Gas Purification 206
4.4.4 Gas Upgrading . 206
4.4.5 Auxiliary Processes 207
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CONTENTS (Continued)
211
4.5.1 Coal Pretreatment and Handling
4.5 Toxic Substances Control Alternatives
211
711
4.5.2 Coal Gasification
01 9
4.5.3 Gas Purification Ll
4.5.4 Gas Upgrading 213
4.5.5 Auxiliary Processes 213
4.6 Summary of Most Effective Control Alternatives 214
4.6.1 Emissions Control 214
4.6.2 Effluents Control 214
4.6.3 Solid Wastes Control 214
4.6.4 Toxic Substances Control 214
4.7 Multimedia Control Systems 218
4.8 Regional Considerations Affecting Selection of Alternatives . . 218
4.9 Summary of Cost and Energy Considerations 222
5. ANALYSIS OF REGULATORY REQUIREMENTS AND ENVIRONMENTAL IMPACTS ... 223
5.1 Environmental Assessment Methodologies 223
5.1.1 Multimedia Environmental Goals ..... 224
5.1.2 Source Analysis Models 227
5.1.3 Bioassay Interpretations 229
5.2 Impacts on Air 233
5.2.1 Summary of Air Standards and Guidelines 233
5.2.2 Comparisons of Wastes Streams with Emissions Standards . 248
5.2.3 Impacts on Ambient Air Quality 251
5.2.4 Evaluation of Unregulated Pollutants and Bioassay Results 256
5.3 Impacts on Water 257
5.3.1 Summary of Water Standards 257
5.3.2 Comparisons of Waste Streams with Effluent Standards . . 261
5.3.3 Impacts on Ambient Water Quality 261
5.3.4 Evaluation of Unregulated Pollutants and Bioassay Results 262
5.4 Impacts of Land Disposal 262
5.4.1 Summary of Land Disposal Standards 262
5.4.2 Comparisons of Waste Streams with Disposal Standards . . 266
5.4.3 Evaluation of Unregulated Pollutants and Bioassay Results 266
vi
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CONTENTS (Continued)
5.5 Product Impacts 266
5.5.1 Summary of Toxic Substances Standards . . 266
5.5.2 Comparisons of Product Characterization Data with Toxic
Substances Standards 269
5.5.3 Evaluation of Unregulated Toxic Substances and Bioassay
Results 270
5.6 Radiation and Noise Impacts 271
5.6.1 Radiation Impacts 271
5.6.2 Noise Impacts . 273
5.7 Summary of Major Environmental Impacts . 274
5.7.1 Air Impacts 274
5.7.2 Water Impacts 274
5.7.3 Impacts of Solid Wastes 275
5.7.4 Impacts of Toxic Substances 275
5.7.5 Other Impacts 276
5.8 Siting Considerations for Gasification Plants 276
6.0 SUMMARY OF NEEDS FOR ADDITIONAL DATA ..... 279
6.1 Data Needs 279
6.1.1 Data Needed to Support Standards Development and
Enforcement 279
6.1.2 Data Needed to Support Effects and Control Technology
R&D 286
6.2 Data Acquisition by On-going Environmental Assessment
Activities 288
REFERENCES 291
APPENDICES
Appendix A Glossary of Environmental Assessment Terms 301
Appendix B Support Data for Estimation of Emissions, Costs and
Energy Requirements for Air Pollution Control Options
for Integrated Lurgi SNG Plants 305
Appendix C Material Related to EPA Methodology for Environmental
Assessment 319
VII
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FIGURES
Number
1-1 Operations Comprising the Lurgi SNG Systems .......... 4
1-2 Auxiliary Processes Associated with Lurgi SNG Systems ..... 5
1-3 The Lurgi Gasifier ......... ............. 7
1-4 Breakdown of Capital Investment Cost for a Commercial Lurgi SNG
Plant ............................. 12
2-1 Generalized Process Flow Diagram for Lurgi Systems Producing
SNG .............................. 4^
2-2 Flow Diagram for Operations in Lurgi Systems for Producing SNG 43
2-3 Flow Diagram for Pollution Control Auxiliary Processes Associated
with Lurgi Systems ...................... 44
2-4 Flow Diagram for Non-Poll uti on Control Auxiliary Processes
Associated with Lurgi Systems for SNG Production ....... 45
2-5 Flow Diagram for a Typical Lurgi SNG Coal Preparation Operation 47
2-6 Lurgi Gasifier ........................ 49
2-7 Primary Cooling, Shift Conversion and Secondary Cooling in Lurgi
Systems ............................ 52
2-8 Solubility of Gases in Methanol .. ............... 54
2-9 Rectisol Type A, Combined Removal of CO^ and hLS ....... 56
2-10 Rectisol Type B, Separate Removal of C02 and H2$ ....... 58
2-11 Flow Diagram for Fixed Bed Methanation Process ........ 62
2-12 Flow Diagram for a Typical Lurgi Gas Liquor Separation System . 66
2-13 Flow Diagram for Phenosolvan Process ............. 67
3-1 Process Modules Generating Gaseous Wastes in Lurgi SNG Systems 105
3-2 Process Modules Generating Aqueous Wastes in an Integrated Lurgi
SNG Facility ......................... 115
3-3 Process Modules Generating Solid Wastes in Lurgi SNG Systems . 128
4-1 Process Modules for Air Pollution Control in a Commercial Lurgi
SNG Facility ........................ . 135
4-2 Process Modules for Water Pollution Control in Lurgi SNG
Facilities -
4-3 Treatment of Stretford Process Purge Solution by the NICE Process 186
vm
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FIGURES (Continued)
Number
4-4 Woodall-Duckham High Temperature Hydrolysis Process for
Stretford Effluent Treatment . 188
4-5 Proposed El Paso Burnham Lurgi SNG Plant Water Management
System 193
4-6 Wastewater Treatment Alternatives for Lurgi SNG Systems .... 200
4-7 Process Module for Solid Waste Management in a Commercial Lurgi
SNG Facility 203
B-l Air Pollution Control Option 1 314
B-2 Air Pollution Control Option 2 315
B-3 Air Pollution Control Option 3 315
B-4 Air Pollution Control Option 4 317
B-5 Air Pollution Control Option 5 . 318
C-l Environmental Assessment/Control Technology Development
Diagram ...... 321
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TABLES
Number
1-1 Major Pollutants/Parameters of Concern in Key Process and
Waste Streams and Applicable Control Technologies 14
1-2 Status of EPA Regulations Under Existing Laws Which Would Affect
Lurgi SNG Plants • • 18
2-1 Dry Ash Lurgi Commercial Installations 24
2-2 Status of Commercial Lurgi SNG Projects (as of September, 1978). 27
2-3 Input Materials Associated with Commercial Lurgi SNG Facilities 30
2-4 Product and Byproducts Associated with Lurgi Gasification ... 34
2-5 Selected Estimates of Capital Cost and Gas Selling Price for
Lurgi-Based SNG Facilities 36
2-6 Breakdown of Capital Investment Cost for Lurgi SNG Facilities . 37
2-7 Index to Stream Numbering System Used in Various Flow Diagrams . 41
2-8 Features of Methanation Guards 59
3-1 Characteristics of Coals Which Have Been or are Proposed to be
Gasified in Lurgi Gasifiers 82
3-2 Oxygen and Steam Input Rates for Gasification of Various Coals
in Lurgi Gasifiers 84
3-3 Lurgi Product Gas Characteristics and Production Rates ..... 87
3-4 Rectisol Feed and Product (Output) Gas Stream Composition ... 90
3-5 Typical Performance Data for the Zinc Oxide Sulfur Guard System
at the Hygas Pilot Plant 92
3-6 Shift Conversion Feed and Product Gas Characteristics 93
3-7 Performance Data for Fixed Bed Methanation Reactors 95
3-8 Estimated Product Gas Compositions for Proposed Lurgi SNG
Facilities 95
3-9 Lurgi By-Product Production Quantities (kg/kg MAF Coal) .... 93
3-10 Composition of Benzene Soluble Tars Products in Synthane
Gasification Process 100
3-11 Composition of Tars and Oils Produced by Gasification of Various
Coals in Lurgi Gasifiers 101
3-12 Organic Composition of Lurgi Oil Produced at the Westfield Lurgi
Facility 102
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TABLES (Continued)
Number
3-13 Phenol Composition Breakdown for Raw Lurgi Gas Liquor ...... 103
3-14 Estimated Composition of Lurgi Feed Lockhopper Vent Gas 106
3-15 Characteristics of Acid Gases Produced by the Rectisol Process. . 108
3-16 Composition of Lurgi Tar/Oil Separator Depressurization Gas ... Ill
3-17 Estimated By-Product Storage Emission Rates for the Proposed
El Paso Lurgi SNG Plant 112
3-18 Chemical Composition of Lurgi Ash Slurry Supernatant 117
3-19 Estimated Solubility of Elements in Lurgi Ash from Gasification
of Dunn County, North Dakota Lignite 118
3-20 Major Constituents and Gross Parameters for Separated Lurgi Gas
Liquors 120
3-21 Minor and Trace Element Composition of Separated Lurgi Gas Liquors 122
3-22 Concentration of Organic Compounds and Their Equivalent COD and
TOC Values for the Separated and Clean Lurgi Gas Liquor at SASOL,
South Africa 123
3-23 Characteristics of Rectisol Methanol/Water Still Bottoms for
Lurgi Facility at SASOL, South Africa 124
3-24 Properties of Separated and Clean Gas Liquor at the SASOL
Phenosolvan Plant 125
3-25 Elemental Composition of Ash Produced by Gasification of Various
Coals in Lurgi Gasifiers 130
3-26 Analysis of Spent Methanation Catalyst for the Pilot Plant ... 131
4-1 Air Pollution Control Processes Reviewed for Application to Lurgi
Systems for SNG Production 136
4-2 Key Features of Particulate Control Devices/Technology 137
4-3 General Characteristics of Sulfur Recovery Processes 141
4-4 Operating and Cost Data for Claus and Stretford Processes .... 144
4-5 Operating Parameters and Costs for the ADIP Process . . 146
4-6 Key Features of Sulfur Recovery Tail Gas Treatment Processes . . 147
4-7 Operating Parameters and Costs for Beavon and SCOT Tail Gas
Treatment Processes 150
4-8 Operating Parameters and Costs for the Wellman-Lord and Chiyoda
Thoroughbred 101 Processes 151
4-9 Key Features of Four S02 Removal Processes 152
4-10 Estimated Costs for Lime/Limestone, Dual Alkali and Wellman-Lord
FGD Processes 155
XI
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TABLES (Continued)
Number
4-11 Capital and Operating Costs for Selected HC and CO Removal
Processes Applied to a 7 x 106 Nm3/d Lurgi SNG Plant 156
4-12 Control Options for the Concentrated Acid Gas Stream from the
Gas Purification Operation lb°
4-13 Summary of Estimated Controlled Emissions for Proposed Commercial
Lurgi SNG Facilities (in kg/hr) '63
4-14 Features of Options Considered for Air Pollution Control in
Integrated Lurgi SNG Facilities 165
4-15 Summary of Estimated Emissions for Air Pollution Control Options 167
4-16 Estimated Costs for Air Pollution Control Options 168
4-17 Estimated Energy Requirements for Air Pollution Control Options. 170
4-18 Wastewater Treatment Processes Potentially Applicable to
Commercial Lurgi SNG Systems 172
4-19 Efficiency of Biological Treatment for Petroleum Refinery
Effluents 180
4-20 Estimated Costs Associated with Biological Treatment of Wastewaters
from Coal Gasification Plants 183
4-21 Wastewater Treatment Processes Used at the SASOL Lurgi Plant and
Those Proposed for Use at Commercial Lurgi Facilities in the U.S., 194
4-22 Features of Dissolved Solids Removal Processes 198
4-23 Estimated Capital and Operating Costs for Wastewater Treatment
at Integrated Lurgi SNG Facilities 202
4-24 Solids Concentration Obtained by Various Sludge Concentrating
Processes 209
4-25 Most Effective Emissions Controls 215
4-26 Most Effective Effluents Controls 216
4-27 Most Effective Solid Wastes Control 217
4-28 In-Plant Multimedia Control Possibilities for a Lurgi SNG
Facility 219
4-29 Candidate Regions for Location of Lurgi SNG Facilities 221
5-1 Current Version of the MEG's Chart 226
5-2 Bioassay Test Matrix 231
5-3 Emissions from a 63-Trillion kcal (250 Billion Btu) Per Day Lurgi
SNG Coal Gasification Plant with Alternative Emission Controls . 235
5-4 National Ambient Air Quality Standards for Criteria Pollutants . 240
5-5 Summary of State Ambient Air Quality Regulations 241
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TABLES (Continued)
Number
5-6 Maximum Permissible Increments for Sulfur Dioxide and Particulate
Matter Concentrations in Ambient Air for Each PSD Class Compared
to NAAQS Values .... .......... 245
5-7 Summary of Federal Emission Standards Applicable to Integrated
Lurgi SNG Facilities ............ 247
5-8 New Mexico Emission Regulations Applicable to Lurgi SNG Plants . 249
5-9 Comparison of Estimated Sulfur Emissions from Lurgi Gasification
Plants with Appropriate Emission Guidelines/Standards ...... 250
5-10 Comparison of S02 Emissions from Onsite Steam and Power Generation
with Appropriate Federal Standards ....... 252
5-11 Comparison of Estimated Particulate Emissions from Onsite Steam
and Power Generation with Federal Emission Standards 253
5-12 Comparison of Estimated NOX Emissions from Onsite Steam and Power
Generation with Federal Standards ................ 254
5-13 Maximum Predicted Ground-Level Concentrations Associated with
Lurgi SNG Facilities .............. 255
5-14 OSHA Standards for Materials Known or Suspected to be Present in
Lurgi SNG Plants ................... 268
5-15 Uranium and Thorium Contents of Coal Samples Taken from Various
Regions of the United States ......... 272
6-1 Data Needs Relating to Gaseous Waste Stream Characteristics and
Control Technology Capabilities ............ 281
6-2 Data Needs Relating to Aqueous Waste Stream Characteristics and
Control Technology Capabilities ................. 282
6-3 Data Needs Relating to Solid Waste Stream Characteristics and
Control Technology Capabilities ................. 284
6-4 Summary of the most pertinent EPA-Sponsored On-going Environmental
Assessment Programs ....................... 289
6-5 Summary of the Most Pertinent DDE-Sponsored On-going Environmental
Assessment Programs ....................... 290
B-l Summary of Energy Requirements for Air Pollution Control
Processes .............. 308
B-2 Estimated Energy Penalty Associated with Incineration in Air
Pollution Control Options ............... 309
C-l Summary of Environmental Assessment Methodologies Under
Development by EPA ....................... 3]9
C-2 MEG Chart for Naphthalene .................... 322
C_3 MEG Background Information Summary for Naphthalene 323
C-4 SAM/IA Summary Sheet ............. . . 324
xi i i
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NOMENCLATURE*
Commercial-scale SNG Facility. A facility having a capacity to
produce 7 x 106 Nm3/d (250 x 106 scf/d) of substitute natural gas.
Environmental Assessment. A continuing iterative study aimed at:
(a) determining comprehensive multimedia environmental loadings and
environmental control costs, from the application of existing and best future
definable sets of control/disposal options, to a particular set of sources,
processes, or industries; and (b) comparing the nature of these loadings with
existing standards, estimated multimedia environmental goals, and bioassay
specifications as a basis for prioritization of problems/control needs and for
judgment of environmental effectiveness.
Environmental Assessment Report. A report prepared for a specific
technology, covering in depth all environmental assessment information rele-
vant to existing or needed standards development plus a description of systems
which can make up the technology, the present and proposed environmental
requirements, and the best control disposal alternatives for all media.
Lurgi SNG Systems. Systems which incorporate specific Lurgi-1icensed
processes and various other processes which would be used in an integrated
SNG facility.
Process Stream. An output stream from a process that is an input
stream to another process in the technology. For example, the crude
medium-Btu gas from the Lurgi gasification process is the feed (input) stream
to the tar and particulate removal quench process.
Substitute Natural Gas (SNG). A manufactured gas containing about 97%
methane, with a higher heating value of over 8000 Kcal/Nm3 (900 Btu/scf),
and meeting the same end-use specifications as pipeline natural gas.
Waste Stream. Confined gaseous, liquid, and solid process outputs that
are sent to auxiliary processes for recovering by-products, pollution control
equipment or final disposal processes; also, unconfined "fugitive" discharges
of gaseous or aqueous waste and accidental discharges.
*See Appendix A, Glossary of Environmental Assessment Terms, for additional
and expanded definitions.
xi v
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ACKNOWLEDGEMENT
The authors wish to express their gratitude to the EPA Project Officer, Mr.
William J. Rhodes, for his continuing advice and guidance during the course of
the effort.
Special thanks are due to Mrs. Maxine Engen of TRW Environmental Engineer-
ing Division for editorial review of the report and for her secretarial services
xv
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1.0 SUMMARY
The recognition of the limited availability of the domestic supplies of
natural gas and crude oil and the desire to reduce the country's dependence on
foreign sources of energy have promoted considerable interest in this country
in developing alternative domestic sources of fuel. Because of the abundance
of mineable coal reserves in the U.S., the greater use of coal, directly or
after conversion to substitute natural gas (SNG) or oil products, is receiving
increasing emphasis. Although coal can be substituted for natural gas and
petroleum for industrial and utility steam and power generation, for technical
and economic reasons coal cannot replace oil and gas in applications such as
residential heating and transportation. Even if coal could be substituted for
oil and gas, in certain applications such substitution can present enormous
pollution control problems. For example, it would be very difficult and costly
to install, operate and maintain pollution control systems on large numbers of
existing small and scattered residential and commercial furnaces. Coal can be
converted to clean liquid and gaseous fuel which can then be conveniently sub-
stituted for natural gas and petroleum products without requiring end use equip-
ment modification or pollution control. From the standpoint of storage and trans-
portation, the use of SNG and coal-derived liquid fuels also offers advantages
over direct coal utilization since the existing gas and oil pipeline and truck
and rail distribution systems can be utilized without major modifications.
Although coal conversion processes can produce clean-burning fuels, unless
properly designed and oeprated, large scale facilities for the conversion of
coal to gaseous or liquid fuels can by themselves constitute major sources of
environmental pollution. In response to the increasing activities related to
synthetic fuels, the Environmental Protection Agency has initiated a compre-
hensive assessment program to evaluate the environmental impacts of synthetic
fuels from coal processes having a high potential for eventual commercial appli-
cation. This overall assessment program is being directed by the Fuel Process
Branch of EPA's Industrial Environmental Research Laboratory, Research Triangle
1
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Park (IERL-RTP). The primary objectives of the EPA synthetic fuels from coal
program are to define the environmental effects of synthetic fuel technologies
with respect to their multimedia discharge streams and their health and environ-
mental impacts and to define control technology needs for an environmentally
sound synthetic fuel industry. The effort will provide the EPA's Program Offices
with the necessary technical basis for establishing standards for the industry.
The synthetic fuel technologies being addressed in the EPA program include
high Btu gasification, low/medium Btu gasification and coal liquefaction. The
Lurgi "dry ash" high Btu gasification system (hereafter referred to as "Lurgi"
system), which is considered to have attained commercial status and has been pro-
posed for use in the first generation commercial SNG plants in the U.S., is one
of the systems being addressed in the EPA's high Btu gasification environmental
assessment program. This Environmental Assessment Report (EAR) for the Lurgi
SNG systems consists of compilation and analysis of all available environmental
assessment information, a description of the equipment and processes which con-
stitute the technology, a description of the control/disposal alternatives for
a media, assessment of the performance and cost of control alternatives, and a
description of the present and proposed environmental requirements. The report
presents, for the use of all EPA Program Offices, the best technical basis
available for the establishment of technology-specific standards. Since addi-
tional data on the Lurgi technology and its environmental aspects are expected
to become available as a result of related on-going and planned programs, this
EAR will be periodically expanded, refined and updated as needed for EPA's
purposes.
1.1 OVERVIEW OF LURGI SNG SYSTEMS
1.1.1 Status of Development
The Lurgi process for coal gasification was developed during the 1930's.
At present, there are eighteen operating Lurgi plants in the world producing
town gas, synthesis gas (for the production of ammonia, methanol and hydro-
carbons) or low Btu fuel gas. In the production of SNG using Lurgi systems,
the raw Lurgi gas must be "purified" and "upgraded" to the "pipeline" quality
using a number of additional processing steps. Although the required process-
ing steps have been used commercially in other applications or have been tested
on coal gases, to date no integrated commercial plant exists which incorporates
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all the unit processes which would be used in conjunction with the Lurgi gasi-
fier to produce SNG. Even though there are a number of other commercially
available coal gasification processes which can be used for SNG production, the
Lurgi process is especially suited for SNG production as it produces a gas high
in methane and hydrogen contents and requires less upgrading. Several commer-
cial SNG plants which have been proposed for construction in the U.S. (see
Section 1.1.4) all feature the Lurgi process for coal gasification.
•1.1.2 Description of Lurgi SNG Systems
The conversion of coal to SNG involves the reaction of coal with steam and
oxygen in a gasifier with subsequent gas processing to (a) adjust the H^/CO
ratio of the gas by the water-gas shift reaction, (b) remove acidic components
and (c) catalytically convert hydrogen and carbon monoxide to methane. The
chemical reactions may be approximated by the following equations:
6 (C+H) + | 09 + 3 H90 = 4 H0 + 2 CO + 3C09 + CH. Lurgi gasification
coal ^ L L <• t *
CO + H20 = C02 + H2 water-gas shift
3 H2 + CO = CH4 + H20 methanation
Based on the above reactions, the production of one mole of methane as a final
product requires 1 mole of oxygen and 1.4 moles of steam (water) and generates
1.4 moles of CCL as a waste gas.
For discussion purposes, Lurgi SNG systems may be considered to be com-
prised of four "operations" and a number of auxiliary processes. As shown in
Figure 1-1, the four operations are coal preparation, coal gasification, gas
purification and gas upgrading. Each operation consists of one or more proc-
esses and produces specific outputs from certain input materials. The auxiliary
processes, shown in Figure 1-2, are incidental to the main function of producing
SNG and are used in connection with steam and oxygen production for gasification,
recovery of products from waste streams, and pollution control.
Coal Preparation Operation. Coal pretreatment in the Lurgi systems gen-
erally consists of only crushing and screening to produce a suitably-sized coal
(3 to 35 mm particles) for feeding to the gasifier. Compared to the finer coal
sizes required for certain other gasification and for some combustion processes,
-------
COAL PREPARATION
OPERATION
COAL GASIFICATION
OPERATION
GAS PURIFICATION
OPERATION
GAS UPGRADING
OPERATION
COAL
CRUSHING
AND
SCREENING
1
•COAL FINES
(TO BOILER)
— »- GASIFICATION
I
ASH
(TO DISPOSAL)
RAW GAS
LIQUOR
(TO
TAR/OIL
SEPARATI
CONCENTR
AgID GAS
wr
i\TED
ES
UD SULFUR
RECOVERY)
PR I WRY
COOLING
t
SECONDARY
COOLING
I
RECTISOL
ACID
GAS
REMOVAL
SHIFT
*" CONVERSION
1
TRACE
SULFUR
AND
ORGAN I CS
REMOVAL
METHANATION,
DRYING AND
COMPRESSION
CONDENSATE
(TO BOILER)
-------
NITROGEN
(TO ATMOSPHERE)
AIR
A. UTILITY
OXYGEN (TO GASIFIER)
ASH (TO DISPOSAL)
FLUE GAS (TO AIR POLLUTION CONTROL)
TREATED WATER (TO PROCESS)
SLUDGES/BRINES (TO DISPOSAL)
B, AIR POLLirnON CONTROL
CONCENTRATED
AUU bflbtb
STRIPPING GASES
fc
SULFUR
RECOVERY
TAIL GAS
TREATMENT
(SULFUR AND
HYDROCARBON
CONTROL)
TO ATMOSPHERE
'BY-PRODUCT
SULFUR (TO SALE)
| SULFUR, H2S, OR SLUDGES
(TO SALE, RECYCLE OR DISPOSAL)
COMBUSTION^
FLUE GASES
PARTI CULATE
REMOVAL
S02
REMOVAL
TO ATMOSPHERE
COLLECTED DUST
(10 DISPOSAL)
SLUDGES/BRINES (TO DISPOSAL)
C. WATER POLLUTION CONTROL
RAW WATER fc
LIQUOR
TAR/OIL
SEPARATION
PHENOSOLVAN
PHENOL
RECOVERY
AMMONIA
RECOVERY
CLEAN GAS LIQUOR
(TO BIOLOGICAL TREATMENT,
COOLING TOWER OR ASH QUENCH)
TAR OIL PHENOL
(TO SALE OR FUEL USE) (TO SALE OR FUEL USE)
AMMONIA (TO SALE)
GASIFIER ASH^
BOILER ASH
SLUDGES AND
BRINES
ASH
HANDLING
SYSTEM
D. SOLID WASTE MANAGEMENT
*— CLARIFIED WASTEWATER (TO ULTIMATE DISPOSAL)
WET ASH/SOLIDS (TO ULTIMATE DISPOSAL)
Figure 1-2. Auxiliary Processes Associated with Lurgi SfIG Systems
5
-------
the*larger coal size for the Lurgi process presents less handling problems from
the standpoint of fugitive emissions control. Because of the special coal dis-
tribution system in the gasifier, which counteracts the caking tendency of coals,
the Lurgi gasifier can handle caking coals without oxidative pretreatment to
destroy caking tendencies. Coals having moisture contents up to 40 percent
do not require drying before being fed to the gasifier.
Coal Gasification Operation. Figure 1-3 presents a schematic diagram of
the Lurgi gasifier. The gasifier, which is operated at a pressure of about 2.5
to 3.5 MPa (25 to 35 atm), receives coal through a feed lockhopper located at
the top of the gasifier and discharges ash (containing less than 5% carbon)
through the ash lockhopper at the bottom of the gasifier. The hot ash is
quenched with water and transported hydraulically to settling ponds for dis-
posal. The charging of the coal to the feed lockhopper and the discharge of
ash from the ash lockhopper are intermittent operations requiring pressuriza-
tion/depressurization of the lockhopper chambers. The feed lockhopper is commonly
pressurized with the product gas or an inert gas (e.g., COp). The ash lock-
hopper is commonly pressurized with steam. The depressurization of both lock-
hoppers results in the generation of a vent gas containing components of the
gasifier gas.
As shown in Figure 1-3, oxygen and steam enter near the bottom and the raw
product gas exits near the top of the gasifier. The countercurrent flow of
solids and gases in the gasifier allows for maximum methane production and effi-
cient heat transfer. The heat needed for gasification reactions is provided
by combustion of residual carbon which takes place near the bottom of the gasi-
fier. On a dry basis, this raw product gas typically contains about 40% FL,
30% C02, 18% CO and 10% CH.. The raw gas also contains a significant amount
of unreacted steam and smaller quantities of higher molecular weight organics
(e.g., tars, oils, phenols, fatty acids), reduced sulfur and nitrogen compounds
(e.g., H2S, COS, mercaptans, NH-, HCN) and entrained dust.
Gas Purification Operation. The gas purification operation consists of gas
cooling to reduce gas temperature for subsequent processing and to effect re-
moval of condensable organics, moisture and water soluble inorganics; acid gas
treatment for the removal of bulk C02 and reduced sulfur compounds; and removal
-------
COAL
HYDRAULIC
OPERATED
VALVES
EXHAUST FAN
HYDRAULIC
MOTOR
CRUDE GAS
OUTLET
COAL
DISTRIBUTOR
V
COAL LOCK
CHAMBER
A
COAL
PREHEAT AND
DRYING ZONE
PYROLLYSISAND
GASSIFICATION ZONE
COMBUSTION ZONE '
ASH ZONE
WATER JACKETED GAS
"PRODUCER CHAMBER
ASH LOCK
CHAMBER
A
ASH QUENCH
CHAMBER
A
CO
-------
of trace sulfur and organics using "methanation guards." Depending on the mois-
ture and heat contents of the coal, the raw product gas exits, the gasifier at
a temperature of 640°K to 920°K (700°F to 1200°F). This gas must be cooled to
a temperature of about 272°K (30°F) prior to treatment for acid gas removal.
The gas cooling, which consists of quenching with water (recycled gas liquor)
and heat recovery in waste heat boilers, is carried out in two stages. Medium
pressure steam is produced in the primary coolers whereas low pressure steam is
produced in secondary coolers. After primary cooling, a portion of the gas
passes through the shift conversion unit (see below) before secondary cooling.
The condensates produced during gas cooling (referred to as "raw gas liquor")
are collected and sent to tar/oil separation units for by-product recovery.
The removal of sulfur compounds and C02 from the gas is necessary to pre-
vent catalyst poisoning in the subsequent methanation step and to obtain a high
heating value gas, respectively. The Lurgi-licensed Rectisol process is used
in Lurgi systems for the removal of the bulk of the sulfur compounds and C(L.
The process uses cold methanol to absorb acid gases under pressure. The solvent
is regenerated by step-wise depressurization and heating. Concentrated acid
gases from solvent regeneration are sent to the sulfur recovery plant. Total
sulfur levels of less than 0.1 ppmv can be obtained in the treated Rectisol gas.
The Rectisol process also enables the recovery of naphtha and affects removal of
moisture and trace constituents such as HCN.
The product gas from the Rectisol process contains traces of sulfur which
must be removed in order to avoid catalyst poisoning in the methanation step.
This is accomplished by use of "methanation guards" ahead of the methanator.
Methanation guards are beds of solid absorbent (e.g., ZnO) which removes sulfur
compounds by chemical reactions. The exhausted bed is usually discarded rather
than regenerated.
Gas Upgrading Operation. Gas upgrading consists of shift, methanation and
drying. An H2:CO ratio of 3:1 is required for methanation. To obtain this
ratio, a portion of the gas exiting the primary cooler is catalytically shifted
and then recombined, after secondary cooling, with the "unshifted" gas. Meth-
anation involves the catalytic reaction of H~ and CO to form methane and water.
The large amount of heat released in the methanation step is recovered via steam
-------
production. The gas is dehydrated by cooling to condense moisture and by use
of a dehydrating solvent (usually glycol) or molecular sieves. Cobalt molybdate
and nickel-based materials are used as shift and methanation catalysts, respec-
tively. The shift catalyst is regenerated by air oxidation which destroys the
carbon deposits formed on the catalyst. The methanation catalyst is "decommis-
sioned" (by controlled air oxidation)prior to removal from the system. Catalyst
regeneration and decommissioning produce off-gases requiring control. Both the
spent shift and methanation catalysts are solid wastes requiring treatment for
resource recovery and/or disposal.
Auxiliary Processes. Auxiliary processes at an integrated commercial
Lurgi SNG plant fall into two categories: pollution control and utilities.
Except for a number of Lurgi-licensed pollution control processes and sulfur
recovery/tail gas treatment processes, most processes are not unique to Lurgi
plants or present any special problems which would be unique to such plants.
The Lurgi-licensed pollution control processes for use in Lurgi SNG plants are
gas liquor treatment for tar and oil separation, Phenosolvan process for phenol
recovery and Linz-Lurgi process for dissolved gases removal. A brief description
of these processes and of sulfur recovery/tail gas treatment and onsite steam
and power generation (which can potentially present the largest emission source
at a Lurgi SNG plant) follows.
The Lurgi gas liquor treatment process operates on a gas flotation principle
whereby the reduction in the pressure on the gas liquor causes the release of
gas bubbles, thereby enhancing the gravity separation of tars and oils which
are recovered as by-products. The "clean" gas liquor from the tar/oil recovery
process is treated by the Phenosolvan process for phenol removal. In this proc-
ess, the phenols are removed from the wastewater by extraction with an organic
solvent; the solvent is regenerated by distillation which also results in the
recovery of crude phenols as a by-product. Although several stripping processes
are available for the recovery of ammonia and I^S from dephenolized gas liquor,
some Lurgi plants feature the Linz-Lurgi process which provides for steam strip-
ping of C(L and HLS at a controlled gas liquor pH of about 5.0 followed by
ammonia stripping in an ammonia stripper. Ammonia is recovered as a 25% gaseous
solution.
-------
Concentrated acid gases from the Rectisol acid gas treatment process and
the flue gases from onsite steam and power generation are the two most volumin-
ous and significant gaseous waste streams in a Lurgi SNG plant. Depending on
the sulfur content of the concentrated acid gases, treatment may consist of sul-
fur recovery in a Claus unit followed by tail gas sulfur removal or in a Stret-
ford unit followed by incineration. The Claus process is a dry high temperature
process in which H?S is catalytically reacted with S(L (produced by air oxida-
tion of a portion of the H2S) to form elemental sulfur. Although the Claus pro-
cess is most applicable to very concentrated acid gas streams, it has been used
on gases containing as little as 5% H^S. To maintain a high efficiency, more
dilute HpS feed gases must be concentrated using commercially available pro-
cesses such as ADIP prior to Claus treatment. Since the Claus process operates
at a high temperature, it also achieves partial destruction of hydrocarbons, COS
and CSp. Claus tail gases typically contain about 10,000 ppm total sulfur,
thus requiring tail gas treatment for pollution control using processes such as
Well man-Lord and Beavon. In contrast to Claus, the Stretford process, which
employs liquid phase oxidation of H^S to elemental sulfur, can handle dilute
HpS feed gases and can achieve very low levels of FLS (less than 10 ppm) in the
product gas. The process, however, does not remove hydrocarbons, COS or CS?
which require incineration or tail gas treatment.
When coal or gasification by-products (tars, oils, phenols or naphtha) are
used as fuel for onsite steam and power generation, the combustion flue gases
can be potentially the largest source of SO . particulates and NO emissions at
X X
a Lurgi SNG plant. For this reason, control of combustion flue gases is a very
important part of any overall air pollution control plan at a Lurgi SNG plant.
As with flue gases from coal-fired utility and industrial boilers, these emis-
sions can be controlled using electrostatic precipitators and fabric filters to
remove particulates, flue gas desulfurization systems (e.g., lime/limestone
scrubbing or Wellman-Lord process) for SO removal and combustion modification
/\
for NO control.
}\
1.1.3 Process Energy and Cost Considerations
Although through gasification an environmentally desirable fuel can be pro-
duced from our abundant supply of coal which would be substituable for natural
10
-------
gas in most applications, it must be recognized that a significant energy penalty
and a high cost are associated with the conversion of coal to SNG. Based on
the proposed designs for commercial Lurgi SNG plants, only about 60% of the
energy in the total coal input to the plant is recovered as SNG. Of the other
40%, about 5% is in the form of by-products (assuming that the by-products are
not used as part of the fuel for onsite power/steam generation), about 10% is
consumed in connection with gas purification, gas upgrading and pollution con-
trol, and the other 25% is a thermal loss incurred in the gasifier and gas
coolers. Although this energy recovery efficiency appears to be low, when end
use efficiencies are taken into account the overall energy recovery from coal
via SNG production is comparable to or higher than those associated with other
means of coal utilization. The energy recovery efficiency is about 35% for coal-
fired utility boilers producing electricity. However, when used in space heat-
ing applications, the overall energy recovery efficiencies for coal-to-SNG-to-
heat and coal-to-electricity-to-heat routes are about 36% and 32%, respectively.
Recent cost estimates for commercial Lurgi SNG plants indicate that a 7 x
10 Nm /d (250 x 10 scf/d) facility will require a capital investment of as
much as $2 billion (1978 dollars) and an annual operating cost of about $300
million. These costs would translate into a gas selling price of $20/10 kcal
($5/10 Btu) at the plant, a price well above the current price of even the most
expensive intrastate natural gas at the wellhead (about $10/10 kcal or $2.50/
10 Btu). An approximate breakdown of the capital cost for a commercial Lurgi
SNG plant is shown in Figure 1-4. As shown in the figure, coal preparation,
gasification, quench and shift collectively account for about 30% of the total
plant investment. Utilities and general facilities account for about an addi-
tional 30%. Capital investment for pollution control is estimated at about 5%
of the total. Operating costs associated with pollution control can account
for approximately 10% of the total operating costs.
1.1.4 Commercial Prospects for a Lurgi SNG Industry
Although the Lurgi technology for the production of SNG from coal is con-
sidered technically viable, and several commercial Lurgi SNG plants have been
proposed for construction in the U.S., the actual construction of such plants
has been stalled primarily by regulatory and economic uncertainties. Although
the Federal Energy Regulatory Commission (FERC) has the authority to regulate
11
-------
30 --
Q-
<
P 20'
o
ct
10 --
COAL PREPARATION,
GAS IF!CATION,COOLING
AND SHIFT CONVERSION
UTILITIES
AND
GENERAL
FACILITIES
ACID GAS
REMOVAL
METHANATION.
DRYING AND
COMPRESSION
AIR AND
WATER
POLLUTION
CONTROL
INTEREST,
DEPRECIATION
AND WORKING
CAPITAL
Figure 1-4. Breakdown of Capital Investment Cost for a Commercial Lurgi SNG Plant
-------
the price of SNG in interstate commerce, no such action has been taken to date
and it is currently unclear what the selling price and mechanism for cost re-
covery will be approved by FERC. Because of the high capital and operating
costs and the anticipated risks associated with the construction of the first
Lurgi SNG plants, developers have been unable to secure the necessary financial
commitment from private or government sources for the construction of such
plants. The development of a viable commercial SNG industry (using Lurgi or
any other gasification technology) would require a substantial commitment of
raw material (water, coal, land), manufacturing capacity (e.g., for steel fab-
rication) and labor resources. Such a large commitment of resources would im-
pact other industrial developments, create a number of socioeconomic problems
and may arouse significant opposition from environmental groups and special
interest groups.
1.2 WASTE STREAMS AND POLLUTANTS OF MAJOR CONCERN
Table 1-1 lists the key process and waste streams and pollutants/parameters
of major concern in these streams. (The applicable control technologies listed
in the table are discussed in Section 1.3.) A number of streams shown in the
table (e.g., tars and oils, clean gas liquor) are confined within the plant or
transported or used in other locations in closed systems. The hazards associ-
ated with these streams are generally related to occupational exposure or stem
from accidents and spills during handling and transportation. Some of the
streams are relatively small in volume (e.g., lockhopper vent gases) or occur
infrequently (e.g., transient gases). Waste streams such as combustion flue
gases from on-site steam and power generation are not unique to Lurgi SNG plants
and do not present new environmental problems. Because many of the streams
listed in Table 1-1 have not been well characterized (in most cases due to the
current non-existence of SNG plants),especially from the standpoint of toxicity
and trace constituents (see Section 1.4), the nature and extent of the potential
hazards associated with these streams are not known.
With respect to volume and concentration of potential air pollutants, two
gaseous waste streams of major environmental concern in a Lurgi SNG plant are
concentrated acid gases from the Rectisol process and flue gases from onsite com-
bustion of coal or by-products for steam and power generation. The volumes of
13
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TABLE 1-1. MAJOR POLLUTANTS/PARAMETERS OF CONCERN IN KEY PROCESS AMD HASTE STREAKS AND APPLICABLE
CONTROL TECHNOLOGIES
Product, By-Product
or Waste Stream
Source
Constituents/Parameters of Major Concern
Applicable Control Technology
Product/By-Product
SNG
Tars, oils and phenols
Naphtha
Armenia
Gaseous Waste Streams
Lockhopper and
transient waste gases
Concentrated acid gases
Sulfur recovery tail gas
Catalyst decommissioning/
regeneration off-gases
Combustion flue gases
Aqueous Waste Streams
Ash quench siurry
Clean gas liquor
Waste sorbents and
reagents
Combined plant effluent
Solid Waste Streams
Gasifier and boiler ash
Spent catalysts
Tarry/oily and bio-
sludges
Inorganic solids and
siudges
Final product
Raw gas liquor treatment
Rectisol process
Gas liquor treatment
Gasifier
Rectisol process
Sulfur recovery plant
Decommissioning/
regeneration of shift
and methanation catalysts
Onsite steam and power
generation
Quenching of gasifier
ash
Ammonia recovery
Pollution control units
Ash quench, FGD, and
raw water treatment
Ash quench systems
Shift and nethanation
By-product storage and
wastewater treatment
FGD systems, miscella-
neous sources
CO. Ni(CO)4
Aromatic hydrocarbons, polycyclic organics,
phenols, trace elements, toxic properties
Aromatic hydrocarbons and polycyclic organics,
toxic properties
Ammonia, trace contaminants
Sulfur and nitrogen compounds, CO, organics,
particulates, trace elements, toxic properties
H2S, COS, CS2, HCN, CO, hydrocarbons,
mercaptans
Same as for concentrated acid gases
Metal carbonyls, CO, sulfur compounds,
organics, toxic properties
S02, N0x, particulates, trace elements
Dissolved and suspended solids, alkalinity,
trace elements, components of the clean gas
liquor used for quenching (see below)
Sulfide, thiocyanate, ammonia, dissolved
organics, BOD, COD, pH, biotreatability
Sulfur compounds, trace elements, dissolved
and suspended solids and other constituents
(depending on specific source)
Dissolved and suspended solids, COD, BOD,
alkalinity, trace constituents, toxic properties
Leachability, comparability, leachate charac-
teristics {including trace elements and organic
contents and toxic properties)
Metallic compounds, accumulated trace elements/
organics, Teachability and leachate
characteristics
Aronatic and polycyclic hydrocarbons, trace
elements, toxic properties
Same as for gasifier and boiler ash
n-plant process control
'revention of leaks/spills, use of worker pro-
tection measures, combustion for steam/power
generation, injection into gasifier
revention of leaks/spills, use of worker pro-
tection measures, combustion for steam/power
generation
Prevention of leaks/spills, use of worker pro-
tection measures
Incineration and particulate control, proper
operating procedures
Sulfur recovery, incineration/FGD
Catalytic reduction and H?S recycle, incinera-
tion, incineration/FGD
Incineration and particulate control
Electrostatic precipitators, fabric filters,
FGD systems and combustion modification
Gravity separation, dissolved solids removal,
disposal of solids in containment ponds/
landfills
Biooxidation, use as cooling tower or quench
water makeup
Resource recovery, oxidation, dissolved solids
removal, use as ash quench
Forced or solar evaporation
Disposal in lined landfills and ponds, return
to mines
Resource recovery, encapsulation, disposal
in lined landfills, return to mines
Energy recovery, disposal in lined landfills,
return to mines
Same as for gasifier ash
-------
these streams are about 1.4 and 3 times the volume of the product SNG, respec-
tively. Pollutants of major concern in the concentrated acid gases are reduced
sulfur compounds, hydrogen cyanide and hydrocarbons. Essentially all the sulfur
originally present in the coal fed to the gasifier appears in the concentrated
acid gases. (Coal pretreatment, when employed, may also release some of the sul-
fur contained in the coal, thus requiring controls for the pretreatment wastes.)
Except for a very lean H,,S acid gas stream from the Rectisol process, which
would require only incineration before atmospheric discharge, the acid gases
are treated for sulfur recovery/removal (and hydrocarbon removal) prior to final
/- o
emission. The flue gases from onsite coal combustion at a 7 x 10 Nm /d (250 x
10 scf/d) plant are equivalent in volume to that produced by a 250-MW coal-
burning power plant.
As currently envisioned, commercial Lurgi SNG plants constructed in the
U.S. will have zero discharge to receiving waters. The wastewaters from these
plants will be contained in ponds and disposed of by solar evaporation or re-
claimed for process use. Accordingly, aqueous waste streams in these plants
would be considered internal process streams and not effluents. Providing for
suitable methods for wastewater containment/treatment and for disposal of resi-
dues resulting from such treatment is the major problem of environmental concern.
The characteristics of the residues resulting from the treatment of combined
plant effluents are determined by the constituents in the three major internal
aqueous waste streams, namely ash quench slurry, clean gas liquor and waste
solvents and reagents. The organic compounds in the residue originate in the
clean gas liquor while the major inorganic constituents and trace elements
originate in the ash quench slurry.
Wet ash from the gasifier and boiler ash quench systems is the largest
volume solid waste stream in an SNG plant. A 7 x 106 Nm3/d (250 x 106 scf/d)
Lurgi SNG plant using a coal containing 15% ash and employing onsite coal com-
bustion for steam and power generation would be expected to generate an esti-
mated 4900 tonne/d (5400 ton/d) of wet ash (about 20% moisture content). As
with the utility industry, the disposal of such a voluminous quantity of waste
can create a major solid waste management problem. These wastes, which are
usually disposed of in ponds and landfills, contain constituents which may be
mobilized via leaching in the disposal site. Such constituents may be the sol-
uble inorganic components of the ash or organic or inorganic materials which
become associated with the ash when process waters (e.g., clean gas liquor)
15
-------
are used for ash quenching. Although of relatively very small quantity, the
spent catalysts are of special concern due to their content of potentially
toxic metals (Ni, Mo, Co) and coal-derived organic compounds and trace elements.
Except for sludge from FGD systems, the inorganic solids and sludges and the
tarry/oily and biosludges are generated in relatively small quantities.
1.3 STATUS OF ENVIRONMENTAL PROTECTION ALTERNATIVES
The control technologies for the management of waste streams of major
environmental concern in a Lurgi SNG plant are listed in Table 1-1. These
technologies fall into two categories: (1) those which have been used on waste
streams from Lurgi and other gasification plants in other countries and (2) those
which have been used on similar waste streams in other industries. Most of the
technologies in both categories are considered to be commercial, although large
uncertainties exist relating to their performance and cost in application to
waste streams in a commercial Lurgi SNG plant. These uncertainties are due to
(a) the lack of data on applications on waste streams at foreign facilities
and (b) the differences in waste stream characteristics. Examples of the
technologies in the first category are injection of organic by-products into
the gasifier; recovery of sulfur from concentrated acid gases using the Claus
process; gravity separation of ash quench slurry and disposal of gasifier and
boiler ash in ponds. Examples of the technologies in the second category are
combustion of tars for steam/power production in the coke industry, recovery
of sulfur from coke oven gases using the Stretford process, treatment of sulfur
recovery tail gases in refineries using the Beavon and Wellman-Lord processes,
biological oxidation of petroleum refinery and coke plant wastewaters, and dis-
posal of utility ash and FGD sludges in ponds. Some of the technologies in the
second category (e.g., FGD and particulate control systems for flue gases) have
been widely used in almost identical applications in other industries and their
performance and costs are reasonably well defined. For other technologies, the
available cost and performance data are for other applications (e.g., use Beavon
sulfur recovery tail gas treatment in refineries) and must be verified on actual
or simulated SNG wastes.
As indicated in Table 1-1, there is generally more than one control tech-
nology for application to a specific waste stream. In most cases, the defini-
tion of the best or the most cost-effective control technology requires more
16
-------
detailed data on characteristics and on the capabilities of control technology
than currently are available. Furthermore, the selection of specific controls
for most individual streams in an integrated SNG plant cannot be made indepen-
dent of the selection of other controls and overall environmental management
plan for the facility. The selection of these controls and the management plan
are influenced by (and in turn influence) the design of the facility. Because
of the lack of detailed information on waste characteristics and control tech-
nology capabilities, it is not possible at this time to identify and compare
all the possible options for the control of air, water and solid waste manage-
ment in a commercial Lurgi SNG plant. Preliminary examinations have been made
of selected sulfur controls for concentrated acid gases and flue gases, the
two most important gaseous waste streams in an integrated plant. These examina-
tions indicate that: (a) the lowest overall sulfur emissions (but not the low-
est cost) can be obtained through the use of the Stretford process for the treat-
ment of concentrated acid gases and the use of desulfurized fuel gas for steam
and power generation; (b) the lowest overall cost (but not the lowest emissions)
can be achieved via use of the Claus process with tail gas treatment for sulfur
recovery from hLS-rich acid gases, the Stretford process for sulfur recovery
from H2S-lean acid gases and FGD systems on flue gases from coal-fired boilers;
and (c) incineration of concentrated acid gases in the utility boilers and use
of FGD systems on the combined flue gases does not appear to be competitive
with other options both in terms of costs and sulfur emissions levels.
1.4 DATA NEEDS AND RECOMMENDATIONS
The U.S. EPA has the responsibility for developing guidelines and standards
and promulgating and enforcing regulations to achieve national environmental
goals. The development of sound and enforceable standards for an industrial
source category requires an adequate technical data base which would include
reasonably detailed information on the characteristics of products and wastes,
capabilities and costs of control technologies, and the effects of pollutants
on human health and the environment.
At the present time there are no specific EPA standards for Lurgi SNG
plants. Under the mandate of several existing laws (see Table 1-2), however,
such standards may have to be developed in the near future. As a result of EPA
data gathering and assessment programs and activities by process developers and
17
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TABLE 1-2. STATUS OF EPA REGULATIONS UNDER EXISTING LAWS WHICH WOULD AFFECT LURGI SNG PLANTS
Law
Key Pertinent Regulatory Features
Status of Regulations
CO
The Clean Air Act
Amendments (PL 91-604)
Federal Water Pollution
Control Act Amendments
(PL 92-500); Clean
Water Act Amendments
(PL 95-217)
Resource Conservation
and Recovery Act (RCRA)
(PL 94-580)
Toxic Substances Control
Act (PL 94-469)
Development of New Source Performance
Standards (NSPS) for industrial source
categories
Preconstruction review of major emis-
sion sources to prevent significant
deterioration of ambient air quality
("PSD" regulations)
Establishment of emission standards for
hazardous air pollutants from stationary
sources
Establish effluent limitations and
guidelines covering conventional,
toxic and nonconventional pollutants
for new industrial sources discharging
into navigable waters
Develop criteria for identification of
hazardous wastes
Develop regulations for handling, trans-
portation, storage, treatment and dis-
posal of hazardous wastes
Promulgate regulations for the manu-
facture, processing and distribution in
commerce, use or disposal of substances
or mixture of substances presenting
unreasonable risk to health and environ-
ment
Issue regulations on testing, premarket
notification and reporting/retention
of information
« No NSPS have been developed for Lurgi
plants
» Emissions guidelines have been developed for
Lurgi SfIG to assist states and EPA Regional
Offices in setting plant-specific standards
« "PSD" requirements for S02 and particulates
and regional air quality classification have
been completed
« Hazardous emissions standards have been set
for asbestos, mercury, beryllium and vinyl
chloride
« No effluent guidelines have been developed
for Lurgi plants
» A list of 129 toxic substances/classes of
toxic substances have been developed for
regulation
a A list of industries categories for which
standards will have to be developed has
been developed. The list does not currently
include Lurgi SNG plants
« Identification criteria and hazardous waste
handling, storage, treatment and disposal
regulations have been proposed
9 Proposal has been made to classify coal ash
and FGD sludges as "special wastes" and not
as "hazardous wastes"
« A priority listing of chemicals for toxicity
testing has been developed
• No substance-specific regulations have yet
been developed
-------
other government agencies, a considerable volume of data currently exists on
the environmental aspects of the Lurgi SNG technology. A large number of gaps,
however, exist in these data which would have to be filled in order to establish
the data base needed for the development of standards and for defining health
effects and control technology R&D needs. These data gaps fall into two categories:
(1) the total non-existence or unavailability of data, and (2) the data which are
available lack comprehensiveness or have been obtained under conditions signi-
ficantly different than those anticipated in an integrated commercial Lurgi SNG
plant in the U.S.
The major waste streams in a Lurgi SNG plant and the applicable control
technologies were presented in Table 1-1. Although considerable characterization
data are available for some of these streams (e.g., concentrated acid gases and
clean gas liquor), such data generally cover only the major constituents and
gross parameters (e.g., hLS content for the acid gases or COD concentration for
the gas liquor) and have been obtained in foreign Lurgi facilities using coals
and process designs which would not necessarily represent those in a U.S. plant.
Almost totally lacking for all streams are data on the type and concentration
of organic substances, trace elements, and hazardous and ecological properties.
Such data would be requiredto identify those streams/constituents which have to
be regulated under the provisions of the laws listed in Table 1-2. For some
streams no data are available on quantities and characteristics primarily due to
the nonexistence of such streams (e.g., combined plant effluent) in existing
gasification plants or the proprietary nature of the data (if any such data
indeed exists).
Of the control technologies listed in Table 1-1, only a few (e.g., the Pheno-
solvan process for phenol recovery and flaring of transient gases) have actually
been used on Lurgi gasification wastes. Very little performance and cost data,
however, are available for these applications. Some control technologies have
been used in similar applications in other industries and some data are avail-
able on cost and performance of such applications. The data from these other
applications cannot be generally extrapolated to Lurgi SNG service due to dif-
ferences in process design and waste stream characteristics. The Stretford
process, for example, has been used for the treatment of coke oven acid gases
which have significantly lower levels of CO^ than Lurgi acid gases. Biological
treatment has been successfully used in the treatment of refinery wastes and
19
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considerable cost and performance data are available for such applications.
Since gasification waste streams are expected to differ from refinery waste-
waters in terms of the nature of organic constituents and presence and concen-
tration of toxic components, the applicability and cost of biological treatment
of gasification wastewaters are not known.
Some of the data needed to support standards development and enforcement
activities would have to be generated through multimedia sampling and analysis
and through R&D programs in the areas of health and ecological effects and con-
trol technology development. Through such programs, reliable and comprehensive
data must be generated on products and waste characteristics, performance and
cost of control technologies and health and ecological effects of wastes and
products/by-products. Implementation of programs in the following areas is
expected to generate some of the data needed to support the development and
enforcement of standards for Lurgi SNG plants:
• Incorporation of additional data in this "Environmental Assessment
Report" as they become available as a result of on-going and future
sampling and analysis programs and engineering studies.
• "Phased-Level" comprehensive chemical/biological testing of process
effluents at existing Lurgi coal gasification plants and at other
industrial sites using components of Lurgi SNG systems.
• Support studies to assess the health and ecological effects of Lurgi SNG
products and waste streams. Such studies should address the presence of
toxic substances and synergistic effects, bioaccumulability, mechanism
and rate of transport, and fate of pollutants in the environment.
• Engineering and pilot and bench-scale studies to determine the effec-
tiveness and cost of various control technologies as applied to Lurgi
waste streams.
• Miscellaneous support activities including development of sampling
and analysis protocols and standardized environmental assessment
methodologies.
A number of programs are currently on-going or are planned which contain
certain elements of the above recommended program areas. The most important
of these programs, the result of which will be incorporated in any revision
to this document, is the EPA-sponsored multimedia environmental sampling and
analysis effort currently under way at the Kosovo Lurgi plant in Yugoslavia.
This program is the first multimedia environmental sampling and analysis effort
undertaken at a commercial synthetic fuels plant.
20
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1.5 ISSUES AND AREAS OF CONCERN FOR PROGRAM OFFICES
The gaps in the available data which must be filled in order to provide the
necessary basis for establishing technically sound and enforceable regulations
for Lurgi SNG plants were identified in the previous section. The identified
data gaps reflect the needs and the requirements for various EPA Program Offices
for establishing such standards. Some specific needs and requirements for cer-
tain of the EPA Program Offices are listed below.
Office of Air Quality Planning and Standards
Emission Standards and Engineering Division
In the absence of actual plant operating data, the following information
would be desired:
• Comparative data on hydrocarbon control methods (e.g., use of ADIP pro-
cess vs. incineration of offgases) and fate of hydrocarbons in various
offgases
• Fate of and control methods for organic sulfur
« Operating data for the Stretford process (e.g., the unit at SASOL) hand-
ling gases containing high C02 concentrations
Office of Water Planning and Standards
Effluent Guidelines Division
« Characterization of Lurgi SNG plant wastewaters, i.e., flows, quantities
and composition (especially, the presence and concentrations of priority
pollutants)
• Assessment of wastewater pollution control technologies, specifically:
- applicability of control technologies used in other industries
- composition of residual dissolved constituents
- in-plant methods for wastewater volume and concentration
reduction
t Development of suitable analytical methods for characterization of SNG
plant wastewaters and for assessment of data and statistical soundness
of proposed sampling and analysis (e.g., for evaluating proposed DOE
programs)
Office of Solid Waste
Hazardous Waste Management Division
e Characterization of the solid wastes generated at Lurgi SNG plants to
determine whether such wastes should be classified as hazardous and
hence whether or not subject to regulations pursuant to RCRA
21
-------
• Waste characterization data, using the "Toxic Extraction Procedure
and/or long term leaching tests (e.g., using lysimeters), are needed to
assess potential for the contamination of surface and groundwaters via
leachate from landfills and runoff from waste storage/disposal sites
Office of Toxic Substances
Testing and Evaluation Division
• Identification of all toxic substances (in particular trace metals and
organics) in Lurgi SNG products/byproducts which may come in contact
with the general public
• Better definition of specific hazards associated with various substances
of concern
t Detailed characterization data on products, byproducts and wastes to
enable material balance calculations for various toxic substances
Office of Radiation Programs
Environmental Analysis Division
t Determination of radioactive waste emissions., as air pollutants (in
waste gases and fugitive emissions) and as solid waste
• Sampling and analysis of waste gases, solid wastes and feed (coal/
supplementary fuel) for radioactivity (including radon emission) to
enable material balance calculations
22
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2.0 PROCESS DESCRIPTION OF LURGI GASIFICATION SYSTEMS
For the purpose of this report, Lurgi systems for the production of SNG
are defined as systems which incorporate specific Lurgi-licensed processes and
various other processes which would be used in an integrated commercial SNG
facility. (See Section 2.2 for a discussion of processes which comprise the
Lurgi systems.) This chapter presents a technical overview of Lurgi systems
and includes information relating to the status of commercial Lurgi SNG pro-
jects, input materials, products and byproducts, energy efficiencies, costs,
and factors affecting the siting of plants and the development of an SNG indus-
try. A description of processes which constitute coal preparation, gasifica-
tion, gas purification and gas upgrading operations and of pollution control
and other auxiliary processes is provided. This description emphasizes waste
generation and waste stream characteristics, known environmental problems and
process areas of current environmental concern.
2.1 TECHNICAL OVERVIEW OF LURGI SYSTEMS
2.1.1 Status of Development
The dry ash Lurgi gasification process has been commercially available
since 1940. The original version of the technology was demonstrated by A. G.
Saechsische Werke in 1930 in a pilot plant at Hirschfelds, Germany'1'. The
pilot scale work provided the basis for subsequent development of the "Lurgi
Pressure Gasification Process" by Lurgi Mineralb'ltechnik GnibH of IJest Germany.*
To date, 18 plants located throughout the world have used the West German proc-
ess for the nroduction of town gas, synthesis gas or low-Btu fuel. The newest
and largest of these facilities is the SASOL plant in Sasolburg, South Africa,
*A parallel development of the Lurgi process has been carried out by the German
Democratic Republic (East Germany) since World War II and several commercial
plants using the East German Technology currently exist in East European coun-
tries. Examples of these commercial plants are the Gaskombinant Schwarze pumpe
in East Germany and the Kosovo Kombinant plant in Pristina, Yugoslavia.
23
-------
TABLE 2-1. DRY ASH LURGI COMMERCIAL INSTALLATIONS USING THE WEST GERMAN
LURGI TECHNOLOGY(I)
Plant
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
.
Location
Bohlen,
Central Germany
Bohlen,
Central Germany
Most, CSSR
Zaluzi-Most, CSSR
Sasolburg,
South Africa
Dors ten,
West Germany
Morwell , Australia
Daud Khel , Pakistan
Sasolburg,
South Africa
Westfield,
Great Britain
Jealgora, India
Westfield,
Great Britain
Coleshill ,
Great Britain
Naju, Korea
Sasolburg,
South Africa
Luenen, GFR
Sasolburg,
South Africa
Sasolburg,
South Africa
-
Year,
1940
1943
1944
1949
1954
1955
1955
1957
1958
1960
1961
1962
1963
1963
1966
1970
1973
1978
— • =s
Type of Coal
Lignite
Lignite
Lignite
Lignite
Subbituminous with
30% ash and more
Caking subbitum. with
high chlorine content
Lignite
High volatile coal with
high sulfur content
Subbituminous with 30%
ash and more
Weakly caking sub-
bituminous
Different grades
Weakly caking sub-
bituminous
Caking Subbituminous with
high chlorine content
Graphitic anthracite
Subbituminous with 30%
ash and more
Subbituminous
Subbituminous with 30%
ash and more
Subbituminous with 30%
ash and more
Gasifier
I.D.
8'6"
8'6"
8'6"
8'6"
1 2 ' 1 "
8'9"
8'9"
8'9"
12'1"
8'9"
N/A
8'9"
8'9"
10'5"
1 2 ' 1 "
1T4"
12'4"
13'1"
Capacity
(MMSCFD)
9.0
10.0
7.5
9.0
150.0
55.0
22.0
5.0
19.0
28.0
0.9
9.0
46.0
75.0
75.0
1400 MM
Btu/hr
190.0
1500
No. of
Gasifiers
5
5
3
3
9
6
G
2
1
3
1
1
5
3
3
5
3
36
24
-------
which currently produces 5.4 x 106 Nm3/d (200 x 106 scf/d) of synthesis gas in
13 Lurgi gasifiers and is being expanded to produce 40.2 x 106 Nm3/d (1500 x 106
scf/d) in 36 gasifiers. A complete listing of Lurgi commercial installations
using the West Germany technology, their locations, start-up dates and pertinent
features are presented in Table 2-1.
In addition to the Lurgi process, Lurgi Mineraloltechnik GmbH has devel-
oped and/or has license on several processes for use in conjunction with the
Lurgi gasification process in a commercial SNG facility. These include the
gas cooling and tar/oil/gas liquor separation processes, the Rectisol acid gas
treatment process and the Phenosolvan phenol recovery process. Lurgi has also
developed a catalytic shift conversion process which has been extensively used
in commercial operations. In addition, Lurgi has successfully pilot tested
a hot gas recycle methanation system at Westfield, Scotland; Schwechat,
Austria; and Sasolburg, South Africa. Finally, the Lurgi Corporation in
cooperation with Chemie Linz AG of Linz, Austria has developed a process to
produce anhydrous ammonia from dephenolized gas liquor. All of the above
developed technologies are considered commercial by Lurgi and most are fea-
tured in the designs for proposed commercial Lurgi SNG facilities in the U.S.
Although there are currently no integrated commercial-scale facilities pro-
ducing SNG in the U.S. (as well as abroad), there are several proposals for the
construction of such facilities in the U.S., based on the dry ash Lurgi pro-
f? 1}
cess ' . The gasification of the American coals by the Lurgi process has been
evaluated in Lurgi gasifiers at the Westfield, Scotland,facility and at the
SASOL plant in South Africa^ . Brief descriptions of the proposed domestic
commercial SNG facilities and the results of testing of U.S. coals abroad follow.
Proposed Commercial Lurgi SNG Facilities for the U.S. The proposed com-
mercial Lurgi SNG facilities for the U.S. which are furthest along in planning
are: (a) the Mercer County, North Dakota Project sponsored by the American
Natural Resources Co., the Peoples Gas Company, and the Natural Gas Pipeline
Company of America; (b) the WESCO Project sponsored by Texas Eastern Trans-
mission and Pacific Lighting Corporation to be located in northern New Mexico;
(c) the Burnham, New Mexico Project, sponsored by the El Paso Natural Gas Co.;
(d) Eastern Wyoming Project sponsored by Panhandle Eastern Pipeline Company;
and (e) the Dunn Center Project for Dunn County, North Dakota, sponsored by the
25
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Natural Gas Pipeline Co. of America. The status of these projects are listed
in Table 2-2.
Although environmental impact statements or assessments have been com-
pleted for each of the proposed projects, legal, regulatory and funding matters
are stalling initiation of construction. The Mercer County Project is the
furthest, along and is currently scheduled for initial construction in 1980;
all required permits have been obtained, and a program for plant financing is
being developed. The Federal Energy Regulatory Commission (FERC) is currently
withholding approval of the Burnham facility pending resolution of matters per-
taining to the acquisition of satisfactory commitments for coal and water. The
WESCO project is also pending FERC certification and plant site leasing; WESCO
is currently evaluating the desirability of continuing the project. A water
permit application was denied in June 1976 for the Dunn Center facility, and a
new water permit application is currently being developed.
In addition to the above projects, there are a number of other proposed
Lurgi commercial -scale gasification projects which are in very early planning
stages. These proposed projects include the Watkins, Colorado Project, spon-
sored by Cameron Engineers, Inc.; the Douglas, Wyoming facility, sponsored by
the Panhandle Eastern Pipeline Co. and the Peabody Coal Co*; and the Cities
Service Gas and Northern Natural Gas Companies' facility planned for northern
Testing of American Coals in Lurgi Gasifiers Abroad. Testing has been
conducted at the Lurgi facilities at Westfield, Scotland, and at Sasolburg,
South Africa to assess the suitability of the Lurgi process for gasification
of American coals. From 1972 to 1974, the American Gas Association and the
Office of Coal Research sponsored a program to test American coals in the Lurgi
facility at Westfield, Scotland. The coals tested were: Rosebud (coarse and
fine grades); Illinois #5 (coarse graded and simulated run-of-mine) ; Illinois
#6 (coarse graded and simulated run-of-mine); and Pittsburgh #8 (coarse graded
and simulated run-of-mine r '. The test results indicated that all four
coals could be successfully gasified on a commercial scale in a Lurgi gasifier.
Sampling and analytical activities on the feed coals, tars, oils, gas liquor,
*This project has reached the stage of draft EIS publication, but has now been
postponed indefinitely.
26
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TABLE 2-2. STATUS OF COMMERCIAL LURGI SNG PROJECTS (AS OF SEPTEMBER,
Sponsor
American Natural
Resources Co. , Ten-
neco, Peoples Natural
Gas Co. , Columbia
Transmission Corp. and
Transcontinental Gas
Pipel ine Corp.
Texas Eastern Trans-
mission Corp. and
Pacific Lighting Corp.
El Paso Natural Gas Co.
Panhandle Eastern
Pipe Line Co. (mining
partner: Peabody Coal
Co.)
Natural Gas Pipeline
Co. of America
Project
Acronynm
ANG
WESCO
El Paso
Wyoming
Dunn Co.
Site
Beulah-Hazen Area,
Mercer County, N.D.
Four Corners Area,
N.M.
Four Corners Area,
N.M.
Eastern Wyoming
Dunn County, N.D.
Coal Feed,
tonne/d
(ton/d)
11,207
(12,328)
22,564
(24,820)
12,886
(14,175)
25, 182
(27,700)
27,273
(30,000)
Peak Output,
10° Nm3/d
(106 scf/d)
3.69
(137)
7.38
(275)
3.87
(155)
7.38
(275)
7.25
(270)
Status/Miscellaneous Data
The plant will be built in two phases. The first
phase is scheduled to be operational by the end of
1982 and will be half the size of a full commercial
plant. Plant costs are estimated at $890 million
(1978 dollars) with another $88 million for trans-
mission facilities. Output from the plant is pro-
jected to cost $5.60 per Mcf not including trans-
mission and distribution costs.
The pi an calls for construction of four plants on
the Navajo Indian Reservation near Farmington, N.M.
by the year 2005. Negotiations for site lease have
not yet been completed. Utah International Corp.
will supply the coal and water for the plant(s).
Estimated project cost for the first plant is $1.4
billion (1978 dollars).
Plans are to construct and operate a half or quarter
size plant on the Navajo Indian Reservation. A
joint partnership with Rhurgas A.G. of West Germany
is under consideration. A new application is
expected to be filed in early 1979.
Plans remain in a holding stage. Investment costs
are estimated at $1.3 billion (early 1976 dollars).
No filing has yet been made to the FERC.
Phase I engineering design has been completed. No
filing has been made with the FERC. Further action
on the project is currently under review.
ro
-------
flash gas, flare gas and product gas were also performed as part of the program.
At the Westfield facility the American coals have also been successfully
treated using the slagging Lurgi gasification process. (The slagging Lurgi
process is not addressed in this document:)
At the SASOL plant in South Africa, Texas lignite has been gasified in a
program sponsored by the Exxon Corporation^8'. Technical evaluations of the
test runs are to be completed in early 1979. If favorable, Exxon may construct
a 38,000-tonne/d (41,900-ton/d) plant at Troup, Texas in the early 1980's. In
1974, 10,900 tonne (12,000 ton) of North Dakota lignite were gasified in a
Lurgi gasifier at the Sasolburg facility under the sponsorship of the Michigan-
Wisconsin Gas Pipeline Company. The results of the tests indicated that the
lignite could be satisfactorily processed in the Lurgi gasifier. A secondary
objective of the program was the determination of trace element distributions
in gasifier ash, tars, oils, and gas liquors. Using spark source mass spec-
trometry as the analytical method, trace element compositions were determined
(Q\
on all effluents sampledv;.
2.1.2 Industrial Applicability of Lurgi Systems
As discussed in Section 2.3, the Lurgi gasification process can be used
for production of low or medium Btu gas which can be used as an industrial fuel,
as chemical feedstocks and/or for SNG production. This document focuses solely
on Lurgi systems for SNG production. In principle, SNG should be substitutable
for natural gas in essentially all applications. Depending on whether the high
costs of SNG are allowed by the FERC* to be recovered by "incremental" pricing
or "rolled in" pricing and on curtailment procedures based on end use criteria,
SNG may not be economical or allowed for certain applications. At the present
time the issue of pricing and curtailment is being handled by the FERC on a
case-by-case basis and no definite precedent has been established. It appears
likely, however, that some restrictions, either directly or indirectly via
pricing mechanisms, will be placed on end uses deemed undesirable, inefficient,
^Although the production of SNG is not subject to regulation by the FERC, the
transportation and/or sale of such gas in interstate commerce is under the
jurisdiction of this agency(lO). All proposed Lurgi gasification facilities
in the U.S. would be subject to regulation since the product SNG would be
sold interstate. By virtue of its rate structure setting power over the gas
pipeline transmission industry, the FERC in effect has control over the eco-
nomics of manufacturing gas for interstate commerce.
28
-------
or unnecessary. An example of such a use of SNG would be ammonia production,
where gasifying coal at the ammonia plant site for hydrogen production would
represent a more efficient resource use than reforming coal-derived SNG to
produce the same amount of hydrogen.
2.1.3 Input Materials. Products and Byproducts
Input materials used in various processes in Lurgi systems for SNG produc-
tion include: coal, oxygen, methanol, propylene, isopropyl ether, sulfuric
acid, caustic soda, lime, limestone, calcium sulfate, magnesium sulfate, cata-
lysts (cobalt molybdate and nickel-based catalysts, and sulfur plant catalysts),
methanation guard material (e.g., zinc oxide, iron oxide), sodium sulfite, phos-
phates, alum, polyelectrolytes, chlorine, corrosion inhibitors and phosphoric
acid. Table 2-3 summarizes the uses of these chemicals in Lurgi systems, the
approximate quantity used, and their commercial availability and hazard rating.
As indicated in the table, all of the input materials are readily available.
The inorganic input materials, which include oxygen, sulfuric acid, caustic
soda, etc., are widely used in a number of industrial applications, and supplies
of these materials are well established.
Supplies of organic chemicals are also generally well established. U.S.
Tarrif Commission product data indicate the following production quantities for
1973 for the subject organics^ ^; methanol, 3,203,692 tonne (3,532,185 ton);
propylene, 4,482,427 tonne (4,942,036 ton); and isopropyl ether (quantity sold),
4,439 tonne (4,895 ton). Based on these data and those in Table 2-3, a 7 x 10
Nm3/d (250 x 106 scf/d) Lurgi SNG facility would consume less than 0.14% of the U.S
production of methanol and less than 0.01% of the U.S. production of propylene.
The quantity of isopropyl ether required in a commercial facility would amount
to 23.7% of the reported quantity sold in the U.S. in 1973. Since the actual
U.S. production capacity of isopropyl ether is not known, it is difficult to
predict the impact of usage of the chemical for SNG production on the U.S.
market and it is possible that certain increases in the U.S. production capacity
would be required to accommodate the increased demand.
It is not known exactly how much nickel, cobalt and molybdenum are in use
in catalysts in the U.S. A recent estimate of catalyst metals content has been
made, which indicates 1,360 tonne (1,500 ton) of molybdenum and 453 tonne (500
29
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TABLE 2-3. INPUT MATERIALS ASSOCIATED WITH COMMERCIAL LURGI SNG FACILITIES
Input Material
Coal
Oxygen
Methanol
Propylene
Isopropyl
ether
Sulfuric acid
(93%)
Caustic
soda (50%)
Lime
Limestone
Dessicants
(e.g. CaS04)
Use in Lurgi System
Raw fuel feed
Input raw material
to gasifier
Rectisol solvent
Rectisol solvent
Phenosolvan solvent
Water treating and
cooling tower
Water treating and
Rectisol unit
Water treating and
Phenosolvan
Stack and tail gas
treating
Oxygen plant
Approximate Quantity*
22,240 - 29,450 tonne/d
(24,521 - 32,470 ton/d)
2,500 - 5,442 tonne/d
(2,700 - 6,000 ton/d)
5,680,150 1/yr
(1,500,700 gal/yr)
138,153 1/yr
(36,500 gal/yr)
1 ,052 tonne/yr
(1,160 ton/yr)
6,440 tonne/yr
(7,100 ton/yr)
12,970 tonne/yr
(14,300 ton/yr)
10,884 tonne/yr
(12,000 ton/yr)
40,996 tonne/yr
(45,200 ton/yr)
1 .36 tonne/yr
(1.5 ton/yr)
Comment
Commercially available, usually
in close proximity to gasifica-
tion facility; non-hazardous
Commercially available; non-toxic,
non-hazardous under conditions of
proper use
Commercially available; MEG rating-
non-hazardous
Commercially available- MEG rating-
non-hazardous
Commercially available; hazardous
properties - toxic by ingestion
and inhalation, flammable
Commercially plentiful; hazardous
properties - highly toxic, a strong
irritant, corrosive
Commercially plentiful; hazardous
properties - highly toxic; a
strong irritant
Commercially available; hazardous
properties - a strong irritant,
reactive with organic materials
Commercially available; considered
non-hazardous
Commercially available; considered
non-hazardous
Reference
13,14,15,
2,3
14,15,3
3
3
3
0
3
3
3
3
CO
o
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TABLE 2-3. CONTINUED
Input Material
Catalyst (e.g. ,
alumina or
bauxite)
Catalyst
(e.g. , cobalt
molybdate)
Catalyst
(e.g., nickel-
based)
Sulfur guards
(e.g., zinc
oxide, iron
oxide)
Other water and
wastewater
treatment chem-
icals
(e.g. , sodium
sulfite, phos-
phate, alum,
polyelectro-
lytes, chlo-
rine, corrosion
inhibitors and
phosphoric
acid)
Use in Lurgi System
Sulfur plant
Shift conversion
unit
Methanation unit
Methanation unit
Water treating
and cool ing tower
Approximate Quantity*
60.5 tonne/yr
(66.5 ton/yr)
485,630 1/yr
(17,160 cu ft/yr)
Not available
Not available
Not available
Comment
Commercially available
Commercially available; MEG rating-
very hazardous
Commercially available; MEG rating-
most hazardous
Commercially available; HEG rating-
non-hazardous
Commercially available; non-
hazardous
Reference
3
o
O
3
3
3
*Quantity associated with 7 x 106 Nm3/d (250 x 10^ scfd) commercial-scale facility.
fEPA MEG hazard ratings (see Section 5.1.1) are used as the basis of the hazard classification assigned, where
applicable. Where unavailable, hazardous properties are described, based on Reference 16.
-------
ton) of nickel and cobalt were in catalysts in commercial use (mainly in re-
finery applications) in 1975^12^. A 1977 estimate indicates a 60 percent in-
C\?\
crease in Mo, Ni, and Co-containing catalyst usage by 198(r . The increased
demand for specialty catalysts may result in increased production and/or recy-
cyling of catalyst metals for domestic use. The U.S. currently has abundant
supplies of molybdenum. Although U.S. nickel and cobalt supplies are less
abundant, domestic and foreign supplies are currently available, and it is
anticipated that domestic production and/or imports will continue to provide
U.S. requirements through the year 200Cr '.
U.S. production of molybdenum and nickel in 1974 was 34,600 tonne (38,200
ton) and 13,600 tonne (15,000 ton), respectively. Although the U.S. has not
actively produced cobalt since 1971, the quantity of cobalt used in 1974 (which
came mainly from imports and from U.S. reserves) was approximately 15,600 tonne
(17,200 ton)(17). Based on the data in Table 2-3, a 7 x 106 Nm3/d (250 x 106
scf/d) Lurgi SNG facility would consume only about 0.12% of the cobalt used
annually, which does not represent a significant fraction of annual imports/
reserves.
The U.S. currently has abundant supplies of bauxite. Known reserves of
commercial bauxite in the U.S. are estimated to be approximately 40.8 million
tonne (45 million ton). About 6.25 million tonne (6.9 million ton) of aluminum
(25 million tonne or 29.6 million ton of bauxite) were produced in the U.S. in
1968; this production rate has increased several percent annually for the past
10 years, and is expected to continue to increase at about the same rate in the
future. Based on the data in Table 2-3, a 7 x 106 Nm3/d (250 x 106 scf/d) Lurgi
SNG facility would consume less than 0.01% of the annual U.S. production of
aluminum (and bauxite) which represents an insignificant fraction of the annual
production . .
As indicated in Table 2-3, only the cobalt molybdate and nickel-based
catalysts are rated "very hazardous" materials. The hazard ratings in the
table are based on EPA's Multimedia Environmental Goals (MEG) classification
system (see Section 5.1.1); where no MEG rating was available for a specific
chemical, general toxicological and other hazardous properties are presented.
Because of their toxic properties, flammability, reactivity and/or corrosivity,
isopropyl ether, sulfuric acid, caustic soda and lime are considered hazardous.
32
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Coal, oxygen, methanol, propylene, limestone, dessicants, the sulfur guards
and other water and wastewater treatment chemicals are considered non-hazardous
under conditions of proper handling and use.
Product and byproducts associated with Lurgi SNG plants include product
SNG, crude phenols, naphtha, tars, oils, sulfur and ammonia (see Table 2-4
for approximate quantities). Although markets exist for all of these materials,
the largest markets are associated with product SNG, ammonia (for use in ferti-
lizers, refrigerants, and dye synthesis), sulfur (for use in sulfuric acid
manufacture, pulp and paper manufacture, etc.) and crude phenols (for organic
synthesis, pharmaceutical manufacture, nylon, etc.). A limited market exists
for naphtha, tars, oils and phenols which can be sold as fuel or for chemical
feedstocks.
As indicated in Table 2-4, the product and many of the by-products asso-
ciated with Lurgi SNG systems are toxic to some degree, are irritants to the
skin or eyes, are carcinogenic, and/or present fire or explosion hazards. The
hazardous properties of sulfur, naphtha, tars, oils, crude phenols, ammonia and
SNG are further discussed in Section 3.4 and 4.5. Some of these materials (i.e.,
ammonia, SNG, phenols) have strict transportation standards, as regulated by
the Interstate Commerce Commission, Coast Guard, and/or the International Air
Transport Association^ ' .
2.1.4 Energy Efficiencies
The thermal efficiency of Lurgi SNG facilities will depend upon the pro-
perties of the feed coal, the overall plant design including utility and pollu-
tion control processes used, and the extent to which efficient steam/power gen-
eration are integrated in the plant. For the proposed commercial Lurgi SNG
facilities in the U.S. about 70 to 80% of the input coal energy is found in pro-
f-\Q\
duct SNG, tars, oils, naphthas and phenols, based upon higher heating valuesv ' .
If these plants were entirely self-supporting in terms of energy, the overall
thermal efficiency would be about 65% for lignites^ ' and 67% for bituminous
(20 21}
and subbituminous coalsv ' '. Actual operating data from the SASOL Lurgi
facility in South Africa indicate an overall thermal efficiency of about 76%
for the combined gasification, gas cooling and tar/oil/gas liquor separation^ '.
Thus, about 9 to 11% thermal efficiency loss may be expected for gas purifica-
tion and upgrading and pollution control. Recent estimates of energy requirement
33
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TABLE 2-4 PRODUCT AND BYPRODUCTS ASSOCIATED WITH LURGI
GASIFICATION^,3,13,14,15)
Product and
Byproduct
Approximate Quantity*
Comments^
SNG
Crude phenols
Tars
Oils
Sulfur
Ammonia
Naphtha
7 x 106 Nm3/d
(250 x 106 scf/d)
30,720-49,360 tonne/yr
(33,870-54,431 ton/yr)
223,738-305,875 tonne/yr
(246,680-337,239 ton/yr)
54,743-175,689 tonne/yr
(60,347-193,074 ton/yr)
52,968-60,977 tonne/yr
(58,400-67,230 ton/yr)
33,941-71,177 tonne/yr
(37,422-78,475 ton/yr)
25,027-68,966 ton/yr
(27,594-76,037 tonne/yr)
Principal product; flammable, a
fire and explosion risk if im-
properly handled.
Marketed liquid byproduct; MEG
rating-hazardous.+
Marketed semi-liquid byproduct;
hazardous properties - highly
toxic, carcinogenic.
Marketed liquid byproduct;
hazardous properties - moderately
toxici skin and eye irritant.
Marketed solid or liquid (phase
determined by customer demand);
non-hazardous.
Marketed, usually as anhydrous
ammonia; MEG rating - non-hazardous.
Marketed liquid; hazardous pro-
perties - flammable; toxic by
ingestion, inhalation and skin
absorption.
*Quantity associated with 7 x 106 Mm3/d (250 x 106 scf/d) commercial-scale
f a c i 1 i ty.
EPA MEG hazard ratings are used as the basis of the hazard classification
assigned, where applicable. Where unavailable, hazardous properties are
described, based on Reference 16.
MEG rating based on purified phenol; crude phenols are expected to be hazardous
34
-------
for pollution control in Lurgi SNG facilities indicate that from 3.6 to 5.6%
of the plant input is needed for air pollution contror . Although some uncer-
tainties are involved in the above calculations of thermal efficiencies, the
data indicate the approximate energy balance which may be expected for inte-
grated commercial Lurgi SNG plants.
2.1.5 Capital and Operating Costs
Individual Lurgi SNG facilities which have been proposed have a capacity
/TO C
of about 7 x 10 Nm /d or 250 x 10 scf/d of product gas, although during
initial operation output may be considerably smaller than this amount. Numer-
ous estimates have been made of the economics of SNG production, and a few
selected estimates are summarized in Table 2-5 for a facility of the above size.
As shown by the data, estimated investment costs for SNG facilities have in-
creased dramatically in the last few years, reflecting in part the impact of
inflation on the economics of large scale capital-intensive projects. Differ-
ences between the estimates in the table can also be partially attributed to
different assumptions about the financing method and discount rate and the in-
clusion or non-inclusion of mine investment costs. Despite the differences in
the estimates, it appears that a 7 x 106 Nm3/d (250 x 106 scf/d) facility will
require a capital investment of as much as $2 billion (1970 dollars) if electric
power generation and mine investment are included. Annual operating costs of
around $300 million may be anticipated for such a facility. These costs trans-
late into a required gas selling price of around $20/106 kcal ($5/10 Btu) at
the plant, a price well above the current price of even the most expensive
natural gas at the wellhead.
Table 2-6 presents a breakdown of Lurgi SNG investment costs by category
of processes or operations. Coal preparation, gasification, quench and shift
collectively account for about one-fourth to one-third of the total plant in-
vestment. Utilities and general facilities account for about an additional
one-third. Capital investment for pollution control is estimated at 2 to 7%
of the total.
Operating costs associated with pollution control are not an insignificant
fraction of total operating costs. One estimate for air pollution control
operating costs at a 7 x 106 Nm3/d (250 x 106 scf/d) Lurgi SNG facility is $20
million per year or around 7% of the $300 million annual operation costs' '.
35
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TABLE 2-5. SELECTED ESTIMATES OF CAPITAL COST AND GAS SELLING PRICE FOR LURGI-BASED SNG FACILITIES
(62 x 1(T kcal/d or 250 x 1Q9 Btu/d basis)
Year of
Estimate
1972
1973
1974
1975
1976
1977
1977
1978
1978
1978
Reference
19
23
24
25
26
27
28
5
29
6
Capital Investment
$106
330
605
450f
738t
1060
814*
970*
1400
1910
1624*
Gas Selling Price
$/106 kcal ($/106 Btu)
__*
4.92 (1.23)
7.28 (1.84)
16.80 (4.20)§
12.88 (3.22)#
10.68 (2.67)
14.92 (3.73)
--
20.60 (5.15)
22.64 (5.66)**
Annual Operating Costs
$106
—
--
--
140 - 172
--
133
--
__
287
--
CO
01
*Not available
t
Exclusive of mine investment
^Assumes no on-site power generation
§
#,
15% DCF assumed
Utility financing basis
**Cost for 1983 in 1978 dollars; cost will decrease to $16.50/106 kcal or $4.13/106 Btu over the
25 year plant life
-------
TABLE 2-6. BREAKDOWN OF CAPITAL INVESTMENT COST FOR LURGI SNG FACILITIES
(IN PERCENT OF TOTAL CAPITAL COST)
Operations/Processes
Coal preparation, gasification,
heat recovery, quench, tar oil
separation, and shift
Acid gas removal
Methanation, compression and
drying
Air pollution control and
wastewater treatment
Steam, water, utilities and
general plant facilities
Interest, depreciation and
working capital
Total
Reference 25
36
7.4
8.1
3.3
26
20
100
Reference 26
22
11
5.5
7.2
29
22
100
37
-------
2.1.6 Commercial Prospects
Factors Affecting the Development of an SNG Industry. As discussed in
Section 2.1.19 none of the proposed Lurgi-based SNG projects has reached the
"start of construction" stage. Sponsors of these projects had hoped for federal
loan guarantees to allow the projects to proceed but in the fall of 1977 the
Federal Loan Guarantee Program bill was vetoed by the President. Since that
time at least two of the projects have been restructured to obtain additional
sponsors. The size of the first facilities to be constructed have also been
reduced to minimize the initial capital investment^ ' '. Major uncertainties
for the developers are the FERC's position on allowing for the recovery of
costs associated with the first plants and the DOE role in directly or indirectly
assisting the financing of SNG plants.
In addition to the economic uncertainties which cloud the development
schedule for SNG facilities, a number of other factors may affect the rate at
which the SNG industry develops. Some of these factors are institutional, such
as the ability to obtain water permits (e.g., in the case of the Dunn County
Project) and disputes over lease arrangements (e.g., in the case of the WESCO
Project which involves Navajo lands). Other factors involve the technical logis-
tics of SNG facilities such as the availability of skilled construction labor
and steel fabricating shop capacity. For example, about 60,000 tonne (66,150
ton) of fabricated steel are estimated to be required for just one 7 x 10 Mm /d
(250 x 10 scf/d) SNG facility, a quantity which represents a sizeable fraction
of existing annual U.S. shop capacity^ '. Finally, there is the problem of local
and national opposition to large scale industrial or energy projects which has
in recent years led to many delays and/or project cancellations. Even when
such opposition has been overcome by legal actions or appeasement measures,
ultimate project costs are generally increased by significant amounts. Although
the above factors are difficult to quantify in terms of their impact on the
development schedule and cost of projects, recent history suggests that signi-
ficant time delays and greatly increased costs are likely to be associated with
the development of a viable SNG industry.
The Siting of Lurgi SNG Facilities. Although a variety of factors influence
the choice of a site for a commercial gasification plant, perhaps the most
important from an economic standpoint is the availability of a large reliable
38
-------
and inexpensive source of coal. This is the major reason why all proposed
commercial SNG facilities to date are to be located in the west. Strip-mined
coal in the west is commonly less expensive than strip or deep-mined coal in
the midwest or east and the large quantities needed daily and over the life of
the plants are more readily obtainable from western strip mines. SNG plants
located in the midwest and east may have certain advantages over western plants
such as lower gas transmission costs to market. It is expected that most plants
east of the Mississippi River will likely be of smaller size than those in the
west since the quantities of coal needed for a large gasification plant (20,000-
25,000 tonne/d or 22,000-27,000 ton/d) are difficult to obtain from underground
mines and most eastern strip mines.
Two major site-related factors have been identified which appear to be most
important in determining plant design from an environmental standpoint. These
are (1) coal type to be used at the facility and (2) regional water availability
and climate. Coal type influences the design of sulfur recovery and air pollu-
tion control units and wastewater treatment units since the amounts of sulfur
and moisture in coal (largely a function of coal type) determine the quantity of
H2S in raw product gas and the quantity of gas liquor generated, respectively.
Generally, western subbituminous and lignitic coals have low sulfur and moderate
to high moisture contents, while midwestern and eastern coals have high sulfur
and low moisture contents.
Regional climate is of major importance since it largely determines the
availability and cost of raw water and the options for ultimate disposal of
plant wastewater. In the western U.S., water is generally less available and
more expensive than in the east. Consequently, wastewater treatment for reuse
and recycle will be more economical for western plants while discharge of treated
wastewater (if allowed) would probably be more economic in the east. In addi-
tion, western facilities will have the option of ultimate disposal of all or
part of their wastewater by solar evaporation. Use of evaporation ponds is
not generally feasible east of the Mississippi River.
2.2 DESCRIPTION OF PROCESSES
This section presents a discussion of processes and unit operations which
are associated with Lurgi systems for SNG production. The information contained
in this section has been derived from the designs for proposed commercial Lurgi
39
-------
facilities'2'3'13'14'15'20'21^, the designs and operating features of existing
Lurqi gasification facilities abroad'4'7'34'44^ and from published literature
(22 23 24 30 41)
relating to engineering and environmental aspects of Lurgi systems ' ' ' ',
The discussion covers alternate processes/unit operations which may be employed
in Lurgi systems in addition to standard Lurgi-licensed technologies. The engi-
neering descriptions of production and auxiliary processes are in sufficient
detail to enable comparison of waste stream control alternatives. The auxiliary
processes used for wastewater control and solids disposal are reviewed very
briefly.
2.2.1 Generalized Process Flow Diagrams
Figure 2-1 is a simplified flow diagram of operations and processes which
constitute Lurgi systems for SNG production. SNG production includes the follow-
ing four operations: (1) coal preparation, (2) coal gasification, (3) gas puri-
fication, and (4) gas upgrading. Major auxiliary processes associated with a
commercial Lurgi SNG facility include processes for air pollution control, water
pollution control, solid waste management, steam and power generation, oxygen
production, and raw water treatment. Figure 2-2 is a more detailed block flow
diagram of operations involved in gas production and shows the major process and
waste streams associated with these operations. This flow diagram with numbered
streams will serve as one of three master flow diagrams which will be referred
to throughout the report. Two other flow diagrams (Figures 2-3 and 2-4) show
pollution control and non-pollution control auxiliary processes, respectively.
Table 2-7 provides an identification index to the stream numbering system used
on various flow diagrams. Sections 2.2.2, 2.2.3 and 2.2.4 which follow provide
brief engineering descriptions of the operations in Figure 2-2 with emphasis on
the origin and nature of waste streams. Section 2.2.5 discusses auxiliary
processes.
2.2.2 Coal Pretreatment
The Lurgi gasifier can handle, without coal pretreatment, many types of
coals having varied heat valves, ash and moisture contents, and swelling and
caking tendencies. The rotating distributor in the gasifier counteracts the
caking tendency of caking coals. The distributor has proven successful in pre-
venting caking and plugging problems during gasification tests with Illinois
and Pennsylvania coals with high swelling and caking indices ''' . High ash and
moisture contents in coals can decrease gasifier temperatures and thermal
40
-------
TABLE 2-7. INDEX TO STREAM NUMBERING SYSTEM USED IN VARIOUS
FLOW DIAGRAMS
Stream
No.
Stream Name
Stream
No.
Stream Name
1 Raw coal
2 Fugitive coal dust
3 Coal fines
4 Coal refuse
5 Sized coal
6 Coal lockhopper vent gas
7 Coal lockhopper supply gas
8 Ash lockhopper vent gas
9 Steam
10 Oxygen
11 Raw product gas
12 Ash
13 Raw gas 1iquor
14 By-pass gas (cooled raw gas)
15 Cooled raw gas
16 Shifted gas
17 Combined shifted and cooled raw
gas
18 Still bottoms
19 Make-up methanol
20 Naphtha
21 Expansion gas
22 Lean H2$ gas
23 Rich H?S gas
24 C02/H2S free product gas
25 Spent shift catalyst
26 Methanator feed cias
27 Catalyst regeneration/off-gas
28 Methanated product gas
29 Methanation condensate
30 Spent methanation catalyst
31 Drying and compression condensate
32 Dry SNG
33 Boiler feed water
34 Raw water
35 Coagulant (aluminum and ferric
salts)
36 Polymers
37 Chlorine compounds
38 Alkali (lime, caustic soda, etc.)
39 Coagulation/settling sludges
40 Clarified water
41 Backwash water
42 Filtered water
43 Acid regenerant
44 Base regenerant
45 Salt
46 Softened water (boiler feedwater)
47 Demineralized water (boiler
feedwater)
48 Spent methanation guard
49 Regeneration blowdown/sludges
50 Atmospheric discharge
_
51 Hydrocarbon rich offgas
52 Recycle I^S
53 Spent sorbents/reagents
54 Sulfate/sulfite sludge
55 Spent filter media
56 Enriched H^S Claus feed
57 Sulfur recovery
58 Methanation guard
59 Sulfur
60 Dehydrating agent
61 Atmospheric discharge
62 Particulate free boiler flue gas
63 Boiler ash
64 Utility boiler flue gas
65 Air
66 Nitrogen
67 Shift catalyst
68 Desulfurized fuel gas
69 Depressurization gas
70 Tar
71 Oil
72 Oil and tar free gas liquor
73 Methanation catlyst
74 Solvent makeup
75 Dephenolized gas liquor
76 Filter backwash
77 Phenol
78 Ash quench offgas
79 Ash quench water
80 Ash slurry
81 Stripper offgas
82 Clean gas 1iquor
83 Ammonia
84 Clarified effluent
85 Dewatered ash solids
86 Boiler blowdown
87 Evaporation/drift
88 Sulfuric acid
89 Antifoam agent
90 Biocide
91 Corrosion inhibitors
92 Biological clarified effluent
93 Biological sludge
94 Oil free water
95 Cooling tower blowdown
96 Tarry/oily sludges
97 Low oil content water
98 Sanitary wastewater
99 Clean water
100 Plant run-off water
101 Byproduct storage vent gases
102 Transient waste gases
-------
ro
COAL PREPARATION
OPERATIOr
COAL »-
g
COAL
SIZING
COAL GASIFICATION
1
GAS GAS
PURIFICATION UPGRADING
OPERATION **
COAL
FEEDING
LURGI
COAL
GASIFICATION
OPERATIO"Rr ^B OPERATION
AUXILIARY PROCESSES
WASTE
GASES
COAL OR
OTHER
FUEL
RAW
WATER
AIR
POLLUTION
CONTROL
STEAM
AND
POWER
GENERATION
RAW WATER
TREATMENT
/GASEOUS
\ AQUEOUS
*" (EMISSION^ WASTES""
f AND A SOLID .
•*-1bLbUHI-l WASTES*^'
\CITY /
/TREATED A1R __
•*n WATER
V__^
)
WATER
POLLUTION
CONTROL
SOLID
MAN/
MEI
OXV
PROC
ION
WASTE
M3E —
vJT
'GEN
UCT —
-*H
H
/AQUEOUS\
EFFLUENTS
[ULTIMATE!
IDISPOSALJ
OXYGEN
O1
PRIMARY
COOLING
i
1
SECONDARY
COOLING
l
t
BULK ACID
GAS
REMOVAL
TRACE
SULFUR
AND
ORGANICS
REMOVAL
^_ SHIFT
CONVERSION
1
1
VIETHANATION
DRYING. AND
1 COMPRESSION
1
1
1
SNG
Figure 2-1. Generalized Process Flow Diagram for Lurgi Systems Producing SNG
-------
102
-pi
CO
2
t
COAL
PREPARATION
H
5
1
i
IN II
^/ I
6 17
COAL
FEEDING
STEAM/
"^^ OXYGEN
GASIFICATION
M t
33 9 , ,10
12
1
8
11
P
C(
19 20 58
t * t
^
BUL
GAS F
(RE
K ACID
REMOVAL
CTISOL)
TRACE
SULFUR
24 AND
ORGANICS
REMOVAL
26 _
MM i
18 21 22 23 °
=(IMARY
DOLING
t13
j
15
6
i
7 27
SHIFT 16 J7 SECONDARY
CONVERSION COOLING
fl3
I
73 27
t *
VIETHANATION
t T
29 30
28 »
60
t
DRYING AND , 32_ ^~^\
COMPRESSION »H SNG )
T
31
Figure 2-2.
Flow Diagram for Processes in Lurgi Systems for Producing SNG (see Table 2-7 for
Index to Streams; Stream Numbering System is Consistent with Those Shown in
Figures 2-3 and 2-4)
-------
WASTEWATER TREATMENT
I I
J >SULFUR RECOVERY/AIR POLLUTION CONTROL *•-{
" 22 23 I
SOLID WASTE MANAGEMENT •
1 — "-
\2. 3.4
\
F 93
85
J
) '
A 85
-a9-
-
INCINERATION
OR
FUEL USE
SOIL
APPLICATION
1
/
1 35. 53. 54
/
\ 25, 30, 48
LAND
BURIAL7
LAND —
FILLING
|
^_^
EVAPORATION
POND
RESOURCE
RECOVERY
Figure 2-3.
Flow Diagram for Pollution Control Auxiliary Processes Associated with Lurgi Systems
(see Table 2-7 for index to streams; stream numbering system is consistent with those
shown in Figure 2-2 and 2-3)
-------
STEAM AND POWER GENERATION
5
63 86
43
44
RAW WATER TREATMENT
34
29/31
— ».
COAGULATION
SETTLING
40
FILTRATION
42
DEMINER-
ALIZATION
[ION EXCHANGE]
— •— 39
-•— 41
47 46_
DEPRESSURI
ZATION
33
SOFTENING
28
49
49
45
<•—
38
BYPRODUCT
" STORAGE
101
20|
70
83.
STORAGE
96
OXYGEN I
"PRODUCTION
Figure 2-4.
Flow Diagram for Non-Pollution Control Auxiliary Processes Associated with Lurgi
Systems for SNG Production (see Table 2-7 for Index to Streams; Stream Numbering
System is Consistent with Those Shown in Figures 2-2 and 2-3)
-------
efficiencies but generally do not prohibit the use of such coals. Certain coals
(e.g., lignites) with moisture contents above 35 to 40% may require drying be-
fore gasification in order to prevent condensation of moisture in the gasifier
(tests at SASOL, South Africa, with a North Dakota lignite containing 36% mois-
ture resulted in a raw product gas with a gasifier exit temperature only 30°K
or 50°F above the moisture dew point, indicating that 36% is approaching the
upper limit of coal moisture content for Lurgi gasifier feedr •
Lurgi gasifier feed (Stream 5) is limited to a size which is small enough
to allow for efficient heat transfer and complete gasification but large enough
to minimize channeling and plugging of gas flow through the coal bed. Based on
operating experience, a size range of 0.32 to 3.5 cm (0.125 to 1.3C in.) is
usually required^. To obtain coal in this size range, proper crushing and
screening of "run of mine" coal is required.
A generalized flow diagram for coal preparation proposed for commercial
facilities is shown in Figure 2-5. As shown in the figure, raw coal is trans-
ported from the mine to the dump hoppers at the coal preparation area adjacent
to the gasification plant. From the coal hoppers the coal enters the primary
crushers where the coal is reduced to a nominal size of approximately 15 to 20 cm
(6 to 8 in.). From primary crushers the coal is transported to the secondary
crushers and primary screens where the crushed coal is reduced to a size suit-
able for feeding to the gasifiers. In some cases (e.g., in the El Paso Burnham
design) two coal sizes are to be produced - 44 mm to 8 mm (1.76 to 0.32 in.) and
8 mm to 2 mm (0.32 to 0.08 in.)^31'. The larger size is for SNG production and
the smaller size is for power and steam generation. Primary screens separate
the oversize coal (>44mm or 1.75 in.) for return to the secondary crushers.
The primary sized coal is transferred to a storage area. Coal from storage is
fine screened before conveying to the gasifiers. The fines are usually cleaned
(e.g., as in the El Paso Burnham design) and either sold or used for on-site
power or steam generation.
At all transfer points, crushers and screens fugitive emissions containing
coal dust are generated (Stream 2). Two methods are proposed for the control
of the fugitive dust: (1) collecting the dusty gases via a pneumatic system
and routing to a baghouse or venturi scrubber for particulate removal, and (2)
use of water sprays at all transfer points and at crushers and screens. The major
wastewater generated by the coal preparation operation is the runoff from the
46
-------
EXHAUST
TO ATMOSPHERE
.1
-I
i
PARTICULATE
COLLECTION | ^- COAL REFUSE
i 4
-P"
—I
DUSTSUPRESSION ,^
WATER
RAW COAL kjHOPPE
REFUSE
TO MINE
BURIAL
SIZED COAL
TOGASIFIER
PRIMARY AND SECONDARY
CRUSHERS
SURFACE
RUN-OFF
TO WATER
TREATMENT
FINES TO
SALES OR
POWER AND
STEAM
GENERATION
Figure 2-5. Flow Diagram for a Typical Lurgi SNG Coal Preparation Operation (stream numbering system is
consistent with those shown in Figures 2-2, 2-3 and 2-4)
-------
coal storage pile. Water used for dust suppression is usually small in quantity
and becomes part of the coal moisture content without producing a net runoff.
Solid wastes from coal preparation include fines from screening (Stream 3), dust
from particulate collection and coal cleaning refuse (Stream 4).
2.2.3 Coal Gasification (Figures 2-2 and 2-6)
Figure 2-6 is a schematic diagram of the Lurgi gasifier. The gasifier
consists of the following components: coal lockhopper, water jacketed pressure
gasifier, ash lockhopper and ash quench system. Sized coal from coal prepara-
tion is stored in a coal hopper directly above the gasifier. Coal is trans-
ferred intermittently to the gasifier via a coal lockhopper pressurized with
either an inert gas (e.g., CO,,) or cooled raw product gas (Stream 15). When the
pressure of the lockhopper reaches a pressure slightly above that in the gasifier,
the coal is discharged into the gasifier.
The Lurgi gasifier is a water jacketed vessel and features rotating blades
near the top to stir the coal and counteract caking tendencies. A revolving
grate at the bottom of the gasifier provides for uniform flow of ash to the ash
lockhopper and introduces steam and oxygen uniformly under the downward moving
coal bed.
As the coal descends through the gasifier counter-current to gas flow, it
passes through four "zones" of progressively higher temperatures before exiting
the gasifier at the bottom as ash. The zones are, from top to bottom, drying,
devolatilization, gasification and combustion. Major chemical reactions asso-
ciated with these zones are:
Coal + heat = GX H + H20 (drying and devolatilization)
C + H20 + heat = CO + H?
CO + H20 = C02 + H2 + heat
C + C02 + heat = 2CO
C + 2H2= CH4 + heat
(Gasification)
C + 1/202 = CO + heat
I (Combustion)
C + 02 - C02 + heat )
-------
SIZED
COAL
STEAM
OXYGEN
COAL
HOPPER
FEED LOCK GAS
BOILER FEED WATER
LOCK VENT GAS
10
LURGI
GASIFIER
CRUDE GAS TO
GAS PURIFICATION
^ WATER JACKET
ROTATING ASH GRATE
STEAM-
ASH
LOCK-
HOPPER
VENT
f\ /\ r\ m r\ ,
84 ^ RECYCLED ASH niJFMPH WATER
ASH
QUENCH
T
78
VENT
TO ASH DEWATERING
VIA SLUICEWAY
Figure 2-6. Lurgi Gastfier
49
-------
In the first zone the coal is dried by contact with the hot crude gas
leaving the gasifier. As the temperature of the coal rises in the second and
third zones, devolatilization and gasification occur endothermically. Combus-
tion occurs in the fourth zone which supplies the heat for the endothermic
reactions in the second and third zones. High pressure and temperature steam
(Stream 9) and high purity oxygen (Stream 10) are supplied to the combustion
zone of the gasifier. Steam for gasification is supplied from three sources:
(1) utility boilers fired with either coal fines, low Btu gas or tar/oil, (2)
water jacket surrounding the gasifier, and (3) superheating of the steam pro-
duced in the raw product gas cooling system.
The ash (Stream 12) produced in the gasifier is discharged to the ash lock-
hopper through a revolving grate at the bottom of the gasifier. The ash lock-
hopper is pressurized with steam to gasifier pressure and ash is discharged
intermittently to the hopper. The ash lockhopper has a vent for pressure adjust-
ment thus enabling free discharge of the ash into the ash quench system. Ash
quenching is accomplished by spraying water (recycled quench water) on the hot
ash. The ash is then transported in a water slurry (Stream 80) to a clarifica-
tion and solids handling system.
The hot crude gas leaving the gasifier (Stream 11) is composed primarily
of unreacted steam, methane, carbon monoxide, carbon dioxide, and hydrogen.
Also present are higher molecular weight organics (e.g., tars, oils, phenols,
fatty acids), reduced sulfur and nitrogen compounds (e.g., H2S, COS, mercaptans,
NH3, HCN), and entrained dust.
Emissions from the gasification operation originate from the coal lock-
hopper, the ash lockhopper and the ash quench system. There are. no gaseous emis-
sions from the gasifier itself. Depending on the type of gas used to pressurize
the coal lockhopper, the pressurized lockhopper gas can be handled in a number
of ways. If cooled product gas is used for pressurization, the lockhopper gas
can be collected, compressed and added to the raw product gas. This recycling
scheme is featured in the proposed design for the El Paso plant^. If an iner!
gas is used for pressurization, the lockhopper gas can be treated for particu-
late control and subsequently discharged to the atmosphere. This method of gas
handling is featured in the proposed design for the WESCO plant whereby C02 frfl
gas purification operation is used as the inert gas for lockhopper pressuriza-
tion. In some foreign facilities (e.g., at the SASOL, South Africa plant)
50
-------
where raw product gas is used for lockhopper pressurization, the gas is not re-
covered and is discharged in the plant stack^ .
The vent gas resulting from the depressurization of the ash lockhopper
(Stream 8) contains primarily steam with small amounts of dust and other com-
ponents of the gasifier gas. The quenching of ash also produces an off-gas
(Stream 78) which contains primarily steam,* and some entrained dust, and per-
haps certain volatile substances resulting from the reaction of ash with water
or dissolved components of the quench water.
2.2.4 Gas Purification (Figures 2-1, 2-2 and 2-7)
As indicated in Figure 2-1, gas purification operation for Lurgi systems
producing SNG consists of primary and secondary gas cooling, bulk acid gas re-
moval and trace sulfur and organics removal. A discussion of these gas purifi-
cation processes follows.
Primary and Secondary Gas Cooling. The objectives of gas cooling are to
remove the condensible components of the raw gas and to reduce the gas tempera-
ture for subsequent shift conversion and acid gas treatment. Figure 2-7 shows
primary and secondary gas cooling for Lurgi systems.
Primary cooling is carried out in a "washer cooler" supplied by cooled
recycle gas liquor (Stream 72). The treated gas from the spray chamber passes
through a vertical tube waste heat boiler producing medium pressure steam. As
the raw crude gas passes through the washer cooler and waste heat boiler, mois-
ture, tars, oils and phenols are condensed, producing a gas liquor stream
(Stream 13) which is conveyed to a "gas liquor separation" unit for the separa-
tion of tar and oil from water. The gas cooling process also results in the
removal of most of the dust entrained in the raw gas. The dust becomes admixed
with tar in the gas liquor separation units.
To attain the desired Hp-to-CO ratio in the gas for methanation, only a
portion of the gas emerging from primary cooling requires shifting. Accordingly,
the gas leaving the waste heat boiler is split with one portion (Stream 15)
passing through shift conversion and secondary cooling and the other (Stream 14)
proceeding directly to secondary cooling. As shown in Figure 2-7, secondary
*About one-third of the water applied to the hot ash is evaporated during ash
quenching(31); the remaining water proceeds with the ash to the ash dewatering
and sol'ids handling system.
51
-------
PRIMARY COOLING
SHIFT CONVERSION
SECONDARY COOLING
cn
ro
RECYCLE
GAS LIQUOR
TO GAS LIQUOR
SEPARATION
LEGEND:
11. RAW PRODUCT GAS
13. RAW GAS LIQUOR
14. BY-PASS GAS (COOLED RAW GAS)
15. COOLED RAW GAS
16. SHIFTED GAS
17. COMBINED SHIFTED AND COOLED
RAW GAS
25. SPENT SHI FT CATALYST
27. CATALYST DECOMMISSIONING OFFGAS
STEAM STEAM
WHBi WHB | AIR COOL
TO ACID GAS
REMOVAL
CONVERTED GAS
COMPRESSOR
Figure 2-7. Primary Cooling, Shift Conversion and Secondary Cooling in Lurgi Systems(31) (stream
numbers refer to master index in Table 2-7 and Figures 2-2, 2-3 and 2-4)
-------
cooling consists of two parallel trains of waste heat boilers (which generate
relatively low pressure steam), air coolers, and "trim coolers" which separate
condensates from the gas. One train is for cooling of shift bypass gas, the
other for shifted gas (Stream 16). After compression, the two gas streams are
combined and sent to acid gas removal. Condensates produced during secondary
cooling are combined with the gas liquor from primary cooling and treated for
tar and oil separation.
Bulk Acid Gas Removal. The removal of HLS and other trace sulfur compounds
from combined shifted and cooled bypass gas (Stream 17) is necessary to prevent
methanation catalyst poisoning. The removal of C(L is almost always necessary
to obtain a product gas with a heating value equivalent to natural gas. The
Lurgi proprietary Rectisol process for C(L and sulfur compounds removal, which
is an integral part of the Lurgi SNG systems and is incorporated in the designs
of all proposed commercial Lurgi SNG facilities, is the only acid gas removal
process discussed in this document. The Rectisol acid gas removal process is
based on the physical absorption of C0?, H?S and other compounds in cold
methanol.
The solubility coefficients of various gases in methanol as a function of
temperature are presented in Figure 2-8. These coefficients are the ratios of
the amount of a gas found in the liquid phase to the amount of gas found in
the vapor phase at equilibrium and at a gas partial pressure of 0.1 MPa (1 atm).
As shown in the figure, the solubilities of the gases which are usually consid-
ered to be impurities (FLS, COS, and CO,,) increase with decreasing temperatures
while the solubilities of the desired product gases (CO, CH^, and H2) are not
significantly affected by temperature. This indicates that the Rectisol process
is more efficiently operated at low temperatures, a condition which also mini-
mizes the solvent losses. It is for this reason that the gas feed for the
Rectisol unit is precooled and refrigerated methanol is used in the process.
The following are important features of the Rectisol process in SNG pro-
duction application.
t Total sulfur levels of less than 0.1 ppmv can be obtained in the
treated gas
• Organic sulfur compounds such as mercaptans and thiophene and COS and
CS2 can be completely removed.
53
-------
SOLUBILITY COEFFICIENT (X)
(1b MOLES OF DISSOLVED GAS)/(SHORT TON OF SOLVENTKATM PARTIAL PRESSURE OF GAS)
Figure 2-8. Solubility of Gases in Methanol
(32)
-------
t Process removes higher molecular weight organics which tend to form coke
on the methanation catalyst and methanation guard. Sorbed organics
do not degrade the solvent and are largely recovered as a naphtha by-
product.
• Traces of solvent in the treated gas do not adversely affect the
downstream methanation catalyst.
• Process removes HCN.
t Process dehydrates gas, a feature which protects methanation guards
and allows for somewhat smaller sized downstream gas processing units.
Depending on the feed stream characteristics and the desired concentration
of H^S in the off-gases, several design alternatives are possible for the Recti-
sol process. Two such designs designated as Types A and B are presented in
Figures 2-9 and 2-10, respectively. In the Rectisol Type A flow scheme, feed
gas enters the prewash tower where methanol rich in CCL and H?S absorbs water,
naphtha, ammonia and residual heavy hydrocarbons from the raw gas. The solvent
exiting from the prewash column enters the prewash flash vessel where a flash
stream lean in HpS and CCL is produced. The liquid bottoms from the prewash
flash vessel are routed to a naphtha separator where water is added to separate
the naphtha fraction (Stream 20) from methanol/water by phase separation. The
methanol and water are then separated in an azeotrope column and a methanol/
water still with the off-gases from the latter unit routed to the hot regenera-
tor. The regenerated methanol from the hot regenerator is cooled and recycled
to the absorber where it contacts the prewashed raw gas. A slip stream of the
resulting H?S and C0? rich methanol is sent to the prewash column.
The bulk of the rich methanol from the absorber is flashed in several
stages. The high pressure flash gas (Stream 21) is rich in higher heating
value compounds and is either used as fuel or recompressed and added to the
inlet raw gas. Flash gases from the other stages (Stream 22) are predominantly
C02 and FLS and are combined with the off-gases from the prewash flash and
routed to sulfur recovery. After flash regeneration, the bulk of the methanol
is returned to the middle section of the main absorber. The balance of the
methanol is regenerated further in a hot regenerator to remove the last traces
of absorbed gases. The hot regenerated methanol is returned via cross-exchange
to the top section of the main absorber and the liberated sour gas (Stream 23)
from the hot regenerator sent to sulfur recovery.
55
-------
21
en
CT>
22
24
23
Figure 2-9.
AZEOTROPE COLUMN
I
STEA
M
-»-
ABSORBER
!_
-
r-
FLASH REGENERATOR
I
•*
ST
i
EAM
MeOH/H20 STILL
\
*
HOT REGENERATOR
| —
1
18
20
LEGEND:
17.
18,
19.
20.
21.
22.
23.
24.
COMBINED SHIFTED AND COOLED RAW GAS
STILL BOTTOMS
MAKE-UP METHANOL
NAPHTHA
EXPANSION GAS
Rectisol Type A, Combined Removal of C02 and H2S(29) (stream numbers refer to master index
in Table 2-7 and Figures 2-2, 2-3 and 2-4) "'asLer uiuex
-------
Except for the use of a two-stage absorber and two separate flash columns,
Type B Rectisol (Figure 2-10) is similar to Type A. The raw gas (after leaving
the prewash absorber) is first contacted with a CCL-saturated methanol stream.
This first stage absorber removes H?S. In the second stage a pure methanol
stream removes C02- The methanol for the first stage comes from the second stage
absorber. The two methanol streams are flashed separately to create a stream
rich in H,,S (Stream 23) and a nearly pure C02 stream (Stream 22). Regeneration
is the same as in the Type A.
Waste streams generated by the Rectisol process(es) are the concentrated
acid gases and the methanol/water still bottoms. Depending on the design,
three or more concentrated acid gas streams are present. These are Stream 21,
which contains the bulk of the volatile organics originally in the feed gas;
Stream 22, consisting of one or more individual lean I-LS streams; and Stream 23,
a relatively concentrated H?S stream.
Trace Sulfur and Organics Removal. Although most processes for acid gas
treatment remove sulfur compounds to ppm levels or lower, additional measures
to protect the methanation catalyst against sulfur poisoning and carbon forma-
tion are required. Trace sulfur and organics removal systems used as methana-
tion guards are fixed beds of adsorbents which protect methanation catalysts by
(1) removing traces of sulfur compounds under normal operating conditions, (2)
providing for "stand-by" bulk sulfur removal capacity in case of the malfunction
of the acid gas removal systems, and (3) removing olefins and aromatic hydro-
carbons which can lead to carbon formation on the methanation catalyst.*
Methanation guards are of four general types: metal oxide beds (zinc,
iron or nickel), metal oxide impregnated activated carbon, activated carbon,
and molecular sieves. Table 2-8 summarizes the key features of various meth-
anation guards. As indicated in the table, a ZnO bed can achieve the lowest
HpS (and COS) levels. The zinc oxide bed, however, is not regenerable and is
deactivated by the presence of the moisture in the feed gas. Spent methanation
catalyst (NiO), although deactivated as far as catalytic activity for methana-
tion is concerned, has a considerable capacity for adsorption of sulfur com-
pounds and can potentially be used as guard bed material.
*Trace organics removal has not been featured in the designs for proposed commer-
cial Lurgi plants, as it is assumed that the Rectisol process will provide ade-
quate organics removal for catalyst protection.
57
-------
21
22
21
23
X
17
o
o
X
CO
5
LU
CC
a.
en
CO
X
CO
X
CO
CC
0.
STEAM
X
CO
CM
O
O
STEAM
WATER
CO
<
CO
STEAM
GC
O
z
LU
LU
CC
O
x
CO
O
CM
X
19
18
—*•
20
LEGEND:
COMBINED SHIFTED AND COOLED RAW GAS
STILL BOTTOMS
MAKE-UP METHANOL
NAPHTHA
EXPANSION GAS
17.
18.
19.
20.
21.
22.
23. RICH H2SGAS
Figure 2-10. Rectisol Type B, Separate Removal of CC>2 and ^(29) (stream numbers refer to master index
in Table 2-7 and Figures 2-2, 2-3 and 2-4)
-------
TABLE 2-8. FEATURES OF METHANATION GUARDS
t
Methanation Guard
Metal Oxides
ZnO
Fe203/Fe304
NiO*
Metal Oxide
Impregnated Carbon
Activated Carbon
Molecular Sieves
Efficiency
H2S
Removal
Very high
High
High
High
Low
Moderate
COS
Removal
High
?
High
High
Low
Incomplete
Organics
Removal
Low
Low
Low
High
High
Moderate
Moisture
Removal
Low
Low
Low
Low
Low
High
Applicable
at High
Temperature
Yes
Yes
Yes
Vest
Yesf
No*
Is Bed
Regenerate
No
Yes
No
Yes
Yes
Yes
_.(
Relative
Cost
Low
Moderate
Low
High
High
High
en
*Assumes the use of spent methanation catalyst as rnethanation guard.
^Organics may not be completely removed at high"temperatures.
*HS not completely removed at high temperature; moisture only partially removed at high temperature.
-------
Metal oxide impregnated carbon offers capability for both organics and
H2S removal and can also be regenerated. The cost of• the system, however,
would be higher than the cost of the throw-away zinc oxide system. Activated
carbon is ineffective for the removal of low molecular weight sulfur compounds
(H?S and COS) but is very effective in removing aroma tics and olefins. Mole-
cular sieves are ineffective for H2S removal at high temperatures, but are
effective for removing moisture.
In summary, ZnO appears to be the most likely candidate for trace sulfur
removal applications, whereas the activated carbon and the molecular sieves are
suitable for the removal of organics and moisture, respectively.
Methanation guards are essentially closed systems during routine operation,
having only a feed stream (Stream 24, Figure 2-2) and a product stream (Stream
26). Periodically the guard material must be replaced and the spent sorbent
(Stream 49) disposed of.
2.2.5 Gas Upgrading (Figures 2-1 and 2-2)
Although a considerable amount of methane is formed directly in the Lurgi
gasifier,* hydrogen and carbon monoxide still represent the bulk of the combus-
tible components of the raw product gas. To upgrade the gas to pipeline quality
requires conversion of hydrogen and carbon monoxide to methane and this requires
an H2/CO ratio of three or greater in the gas prior to methanation. The required
H2/CO ratio is achieved by catalytic shifting. This section discusses catalytic
shifting and methanation processes proposed for use with Lurgi SNG systems.
Shift Conversion. Shift conversion involves reacting CO and water vapor
in the gas to produce hydrogen and carbon dioxide (CO + FLO = C02 + H2 + heat).
To achieve the required 3:1 H2/CO ratio, catalytic shifting may be accomplished
using one of the following two approaches: (1) sending the entire gas flow
through the catalytic reactor and (2) sending a portion of the flow through the
catalyst bed and combining the shifted and unshifted gases afterward to obtain
the proper H2/CO ratio. Based on equilibrium calculations (and actual operat-
ing experience) a H2/CO ratio of up to 10:1 can be obtained at about 550°K (530°F
As a consequence, it appears desirable to use the second approach for more reli-
able final composition control and for cost savings associated with smaller
reactor size. In Lurgi SNG designs only about 50% of the raw gas is shifted.
*Most Lurgi systems are designed to produce about 40% of the final methane con-
tent of the gas in the gasifier.
-------
Although the shift conversion reaction can be promoted by a variety of
catalysts, for the following three reasons the cobalt molybdate-based catalysts
are the preferred catalysts:
(1) The catalyst is active at a high temperature (550°K or 530°F),
thus eliminating excessive gas cooling prior to shifting.
(2) The catalyst can tolerate sour gas components such as H2S and COS.
This tolerance eliminates the need for H2S removal prior to shift-
ing. Acid gas treatment can follow shifting thus avoiding an
additional acid gas removal step for the removal of CC^ produced
in the shift reaction.
(3) The catalyst also promotes the reduction of the organic sulfur in
the gas naphtha to H2S and the hydrolysis of HCN to NH3-
The basic shift conversion equipment usually consists of two fixed bed re-
actors (used in series) and feed stream heat exchangers, as shown in Figure 2-7.
The second reactor serves as a polishing unit and a reserve for the first reactor
when the catalyst in the first reactor becomes deactivated.
The only waste streams generated in shift conversion are the spent catalyst
(Stream 25, Figure 2-2) and the catalyst regeneration off-gas (Stream 27). Re-
generation consists of controlled air oxidation of deposited carbon. Under
ordinary service and when the catalyst is regenerated once every few months, a
catalyst life of 2 to 5 years would be expected.
Methanation and Drying. The final steps in the production of pipeline
quality gas are methanation and drying. Methanation involves the catalytic
reaction of carbon oxides and hydrogen to form methane (and water):
3 H2 + CO = CH4 + H20 + heat
4 H2 + C02 = CH4 + 2H20 + heat
Methanation reactions are carried out at temperatures of 590°K to 760°K (600°F
to 900°F) and at a high pressure (about 7 MPa or 1,000 psia). Figure 2-11
shows a flow diagram for the methanation process featured in the proposed de-
signs for the U.S. commercial Lurgi SNG facilities. The process operates by
passing the feed gas (Stream 26) over a fixed bed of pelleted nickel catalyst.
Depending on the feed gas composition and the specific design of the methanator
for temperature control/heat recovery, the feed gas to the methanator may be
diluted with steam or recycled gas. A second stage methanator is employed to
61
-------
26
WASTE
HEAT
BOILER
RECYCLE
METHANATOR
27
30
CONDENSATE
SEPARATOR
1
POLISHING
METHANATOR
27
30
1
LEGEND:
26. METHANATOR FEED GAS
27. CATALYST DECOMMISSIONING OFFGAS
28. METHANATED PRODUCT GAS
29 METHANATION CONDENSATE
30. COOL SPENT METHANATION CATALYST
Figure 2-11 .
Flow Diagram for Fixed Bed Methanation Process (stream numbers refer to master index in
Table 2-7 and Figures 2-2, 2-3 and 2-4)
-------
remove any unreacted CO, C02 and H2. The methanated gas (Stream 28) is then
cooled in a waste heat boiler to produce steam.
Drying of the methanated gas is usually accomplished in two stages: con-
densation for bulk moisture removal and sorption for the removal of residual
moisture. The bulk moisture removal is achieved by cooling and heat recovery.
Molecular sieves or solvents (e.g., ethylene glycol) are used for the removal
of trace moisture which remains after cooling; the molecular sieves and the
solvents are regenerated and reused. The gas drying operations (condensation
and trace moisture removal) are not unique to SNG production and are widely used
in a number of other industries (e.g., natural gas purification).
In the methanation and drying processes, three types of waste streams are en-
countered: (1) condensed moisture (Streams 29 and 31), (2) emissions from catalyst
decommissioning (Stream 27; see below); and (3) spent catalyst (Stream 30).
Condensates formed by cooling of methanator product gas are generally free of
dissolved and suspended solids and gases such as H2S and NH~, and are therefore
suitable for boiler feed water or other uses where high quality water is
required.
From an environmental standpoint, the major hazards associated with cata-
lytic methanation arise during transient operations. At temperatures less than
480°K (400°F), carbon monoxide can react with reduced nickel catalyst to form
nickel carbonyl. Methanation is ordinarily conducted at temperatures above
590°K (600°F); however, temperatures of less than 480°K (400°F) are encountered
during start-up and shut-down. Inert gas (e.g., Np, 002) must be used during
heating and cooling to exclude carbon monoxide from the bed. Since reduced
nickel catalyst is pyrophoric, a spent bed is commonly decommissioned by slowly
adding air or oxygen to the cooled catalyst to initiate oxidation. The con-
trolled oxidation of spent catalyst may result in an off-gas containing parti-
culate matter, sulfur compounds, organometallic compounds and carbon monoxide.
"Burned" catalyst, although chemically more stable, still presents a hazard
due to the potential toxicity of nickel. As noted previously, one likely use
of oxidized spent catalyst is as methanation guard for sulfur removal.
2.2.6 Auxiliary Processes (Figures 2-3 and 2-4)
Auxiliary processes associated with the production of SNG at an integrated
commercial Lurgi facility fall into two categories: pollution control processes
-------
used for the management of gaseous, liquid and solid wastes and non-pollution
control support processes such as steam and power generation, oxygen production
and raw water treatment. A brief description of these auxiliary processes
follows.
Air Pollution Control. The two major types of gaseous waste streams asso-
ciated with Lurgi SNG facilities are the concentrated acid gases (Streams 22,
23, 69, and 81, Figure 2-3) and flue gases from on-site steam and power genera-
tion (Stream 64, Figure 2-4). Depending on the sulfur content of the acid gases,
treatment would consist of sulfur recovery in a Claus unit followed by tail gas
sulfur removal or in a Stretford unit followed by incineration. As will be dis-
cussed in Section 4.2, hydrocarbon removal/\\£ enrichment may be necessary for
acid gases treated in a Claus plant. Flue gases from combustion of coal or
gasification by-products (tars, oils, phenols) would be treated for particulate
removal using electrostatic precipitators or fabric filters and for S02 removal
by one of several commercial flue gas desulfurization processes (e.g., Chiyoda
Thoroughbred 101, Well man Lord, limestone).
Gaseous waste streams of less volume and significance than concentrated
acid gases and flue gases include lockhopper vent gases (Streams 6 and 8),
transient waste gases (Stream 102), catalyst decommissioning off-gases (Stream
27), coal crushing and screening off-gases (Stream 2), and by-product storage
vent gases (Stream 101). In the case of lockhopper vent gases, a combination
of recompression/recycle and particulate control (scrubbing or use of fabric
filters) prior to atmospheric discharge would be employed. Transient waste
gases would be incinerated in a flare prior to discharge. Catalyst decommis-
sioning/regeneration off-gases may require incineration and/or particulate
removal before discharge. Dust from coal preparation operations would be con-
trolled by water sprays and fabric filters. Evaporative emissions from by-
product storage are controlled by use of floating roofs on storage vessels,
vapor recovery systems, or incineration.
Water Pollution Control. Figure 2-3 identifies the major wastewater streams
and wastewater treatment processes/modules in Lurgi SNG facilities. The con-
densed liquors generated during the primary and secondary gas cooling are gen-
erally combined (Stream 13) and sent to a Lurgi proprietary gas liquor separa-
tion system (see Figure 2-12) where tars and oil are separated from the aqueous
-------
phase by gravity separation. As the gas liquor passes through expansion vessels,
dissolved gases are flashed off by pressure reduction and the resulting gas
bubbles enhance tar/oil separation by the flotation principle. The gas liquor
then flows through primary and secondary separators where quiescent settling
occurs and the bulk of the tar and oil are recovered. The expansion gas (Stream
69) from the pressure reduction step contains ammonia, H^S, and low molecular
weight organics and would ordinarily be combined with other sour gases in an
integrated facility for by-product recovery/pollution control. The bulk of the
clarified gas liquor is recycled to the primary cooling circuit, with the excess
(Stream 72) proceeding to the Phenosolvan unit for phenol recovery.
The Phenosolvan process, shown in Figure 2-13,,is a proprietary Lurgi pro-
cess. The gas liquor is first filtered and fed to a mixer-settler where it con-
tacts a lean organic solvent (commonly butyl acetate or isoproyl ether). After
solvent-water phase separation, the solvent is sent to a distillation column
for solvent recovery. The lean solvent from the column returns to the mixer-
settler while crude phenol is fractionated for purification and additional sol-
vent recovery.
The raffinate from the mixer-settler is stripped of solvent with nitrogen
gas in a packed tower and is sent to ammonia recovery. Solvent rich nitrogen
gas is then contacted with scrubbing phenol from the crude phenol stripper to
recover most of the solvent. Phenolic vapors remaining in the N? gas are then
largely removed via contact with a portion of the feed wastewater. The clean
gas returns to solvent recovery scrubber and the feed wastewater proceeds to
the mixer settler. The Phenosolvan process generates a crude phenol product
(Stream 77), a filter backwash liquor (Stream 76), a dephenolized gas liquor
(Stream 75) containing traces of the extraction solvent, and a spent filter
media (Stream 55).
Dephenolized gas liquor (Stream 75) contains dissolved gases such as hLS,
C09 and ammonia. Removal of the dissolved gases can be effected by steam strip-
ping or by contact with an absorbing medium. The most common dissolved gas re-
moval process is steam stripping. If necessary, the pH of the raw water is
adjusted using an acid or an alkali to improve stripping efficiency. Some Lurgi
plants feature the use of the proprietary Linz-Lurgi process for ammonia recov-
ery^ . The licensed Linz-Lurgi process steam strips the gas liquor at a
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CTi
cr>
13
(OILY GAS LIQUOR)
COOLER
13 (TARRY GAS LIQUOR)
COOLER'
LEGEND:
RECYCLE
GAS LIQUOR
13. RAW GAS LIQUOR
69. DEPRESSURIZATION GAS
70. TAR
71. OIL
72. OIL AND TAR FREE GAS LIQUOR
Figure 2-12.
Flow Diagram for a Typical Lurgi Gas Liquor Separation System
master index in Table 2-7 and Figures 2-2, 2-3 and 2-4)
(31)
(stream numbers refer to
-------
SPENT FILTER MEDIA
GAS LIQUID FEED
SOLVENT MAKEUP
DEPHENOL12ED GAS LIQUOR
FILTER BACKWASH
PHENOL
Figure 2-13. Flow Diagram for Phenosolvan Process (33)
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controlled pH of about 5.0 thus tying up the ammonia as a salt in solution.
The acid gases (C02 and H2$) are stripped off in a stripping tower and the
stripped liquor is sent to an ammonia stripper where ammonia is stripped off
and condensed, producing a 25% ammonia solution as a saleable by-product. Two
other patented processes potentially applicable for recovery of the ammonia in
Lurgi SNG facilities are the USS Phosam W and the Chevron WWT processes. These
processes will be discussed in detail in Chapter 5. The major waste stream
generated by steam stripping/ammonia recovery operations is the stripper over-
heat (Stream 81) containing H2S, C02, and other steam volatile substances (e.g.,
phenols, HCN).
Two approaches which are commonly proposed for handling the clean gas liquor
from ammonia removal/recovery units are: (1) biological treatment and the use of
the treated effluent for cooling tower makeup or ash quenching and (2) direct
use as cooling tower makeup without pretreatment. Cooling tower blowdown is
used for quenching/transportation of gasifier and boiler ash to clarifier units,
where the ash is separated as a sludge. Clarifier effluent proceeds to settling/
evaporation ponds where all or part of the wastewater evaporates. The designs
for commercial SNG facilities for New Mexico incorporate solar evaporation for
(2 3}
the disposal of all the plant wastewaterv ' ' . For facilities in Wyoming and
North Dakota, the wastewater which cannot be disposed of via solar evaporation
will be treated by flash evaporation with fresh water recovery^ ' ' .
Plant site and coal pile runoff would generally be collected by a sewer
system and the water treated by gravity separation for use within the plant as
cooling tower and/or ash quench water makeup.
Relatively saline waters will be generated as a result of raw water treat-
ment (softening and demineralization) and the use of flash and brine evaporators
for wastewater disposal/fresh water recovery. Such brines would generally be
disposed of with ash sludges, by deep well injection, or by discharge into lined
evaporation ponds.
Solid Haste Management. The general types of solid wastes associated with
Lurgi SNG facilities are gasifier and boiler ash (Streams 85 and 63), sludges
from air and water pollution control and raw water treatment (Streams 53, 54, 55,
96, 93, and 39) and spent catalysts and sorbents (Streams 25, 30, and 48). The
most commonly proposed appoach for handling and disposal of the ash and sludge
is to bury these materials with re-deposited overburden in conjunction with
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strip mine reclamation. For some sludges, lined settling/evaporation ponds are
proposed whereby the ponds eventually fill with semi-solid waste and are later
covered with soil or abandoned. The more hazardous catalyst wastes may in some
cases be sent to the manufacturer or to a reclaimer where the metal values are
recovered. Alternatively, these materials would be disposed of in the mine or
in landfills, perhaps in sealed drums and/or in isolated sections of a disposal
site. Certain solid wastes, e.g., biosludges, can also be disposed of by land
spreading or used as soil conditioners in strip mine revegetation. Sludges and
solids with high organic contents may be incinerated with or without heat
recovery.
Steam and Power Generation. The steam and power requirements for a Lurgi
coal gasification facility will be dependent upon the selection of auxiliary and
pollution control units and the choice of driving equipment for compressors,
pumps, etc. Steam needs will be satisfied on site while power may be either
purchased or generated onsite. Steam and power may be generated by burning any,
some or all of the following fuels: coal, coal fines, tars, oils, and low-
Btu gas from coal gasification. The fuel choice will be dependent upon fuel
availability and economic considerations.
The proposed designs for U.S. commercial Lurgi SNG facilities feature
different approaches to steam/power generation. The El Paso project proposes
to use gas turbine generators fueled by low-Btu gas from a series of air blown
(2\
Lurgi gasifiers for power generation^ ;. The gas turbine will drive electric
generators directly, with steam generation provided by recovery of the gas tur-
bine waste heat. The air-blown Lurgi gasifiers will have waste streams similar
to those from the oxygen-blown gasifier. Low-Btu gas will be treated for HLS
removal prior to combustion. The primary waste stream from the gas turbines
will be the combustion flue gases. Because of the clean nature of the fuel,
the gas turbines operate relatively cleanly and the major pollutant is expected
to be NOX. No liquid or solid discharges are associated with the use of gas
turbine-generator units. Comparison of emissions from this source with other
alternatives for steam and power generation (e.g., direct combustion of coal)
must include emissions from the low-Btu gasification step.
The ANG Coal Gasification Project calls for onsite steam generation but pur-
chase of electricity from a utility company^ '. The steam generation will be
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through the use of waste heat boilers and the combustion of tars, oils, phenols
and naphtha from the gasification process. Waste streams will be those commonly
associated with liquid fuel-fired steam boilers.
(3)
The WESCO gasification project also calls for the purchase of electricity^ ',
Coal fines, however, will be used to fire boilers for steam generation. Waste
streams from these boilers will include: flue gas (containing particulates,
SCL, HC, CO), ash and sludges from pollution control devices employed (e.g.,
electrostatic precipitators or flue gas desulfurization units).
The sponsors of the Dunn County, North Dakota, project and the Wyoming Coal
Gasification Project envision onsite steam and power generation using conven-
tional coal-fired boilers(13>14).
Oxygen Production. Oxygen required by the Lurgi gasification system will
be produced using standard air separation units. Several trains producing oxygen
in the 98-99.5% purity range will be required for a commercial size gasification
facility. The trains consist of air compressors, air separation units (cold
box) and oxygen compressors.
The air compressors and oxygen compressors will be either steam- or elec-
tric-driven or a combination thereof. The air separation unit cryogenically
separates the oxygen and nitrogen. The sole discharge streams will be the waste
nitrogen and cooling tower blowdown. The proposed design for the El Paso plant
features the use of a small portion of the nitrogen for pressurization of the
feed lockhoppers of gasifiers used for fuel gas production .
Raw Water Treatment. Raw water for use in the gasification facility would
be processed through various units to render the raw water suitable for use as
boiler feed water (BFW), cooling tower makeup water and as potable water. The
degree of treatment depends upon the characteristics of the raw water at each
gasification facility. A general flow diagram for water treatment is presented
in Figure 2-4.
Raw water (Stream 34) is generally treated first by coagulation and settling.
The clarified water (Stream 40) is then filtered and the product water (Stream
42) is used as potable water (after chlorination) or further treated by ion
exchange or chemical softening for use as boiler feedwater. Water condensed
from product SNG in the methanation and drying section (Streams 29 and 31) which
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is relatively free of dissolved solids, is also used as a supplementary source
of boiler feed water after the removal of dissolved gases by depressurization.
(The depressurization off-gas is commonly added to product SNG.) In the designs
for the El Paso Burnham and ANG coal gasification facilities, boiler feed water
is supplied from two different sources: (1) zeolite softened water for low
pressure boilers and (2) demineralized water for low pressure boilers' ''.
Waste streams from raw water treatment are filter backwash (Stream 41),
coagulation/settling sludges (Stream 39) and demineralizer brines/chemical
softening sludges (Stream 49).
2.3 PROCESS AREAS OF CURRENT ENVIRONMENTAL CONCERN
Currently a major fraction of the natural gas in the U.S. is used in heating
applications. If electricity produced via coal combustion or SNG were to replace
natural gas in these applications, essentially the same amount of coal would
have to be mined to produce an equivalent amount of end use energy. The envi-
ronmental problems associated with coal mining and ash disposal would be com-
parable for the two methods of coal utilization. Since one of the major moti-
vations for producing SNG from coal is to avoid the air pollution problems
associated with direct coal combustion, it is essential that SNG plants them-
selves are not major sources of pollution and that the pollution problems are
not merely being displaced from one location or media to another. For this
reason it is necessary that the commercial SNG facilities be designed and oper-
ated in a manner that pollution displacement is avoided. This section summarizes
the environmental areas of concern associated with the process/operations dis-
cussed above.
2.3.1 Coal Pretreatment and Handling
As noted in Section 2.2.2, the major waste streams associated with the coal
preparation operation are fugitive dusts, coal refuse and runoff from coal piles.
These wastes, however, are not unique to Lurgi SNG systems and methods for their
control (e.g., use of sprays for dust supression or collection and use of the
coal pile runoff as process water) have been well established and are used wher-
ever coal is mined/processed. In a Lurgi SNG facility, these wastes are not
especially large in quantity or very hazardous in nature. Compared to a coal
preparation operation for a utility boiler, considerably smaller quantities of
dusts requiring controls are generated in a Lurgi SNG facility, since larger
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size coals are fed to the Lurgi gasifier and hence a smaller degree of crushing
is required. New Source Performance Standards and Effluent Guidelines are already
in existence for coal preparation facilities. Coal preparation in Lurgi SNG
facilities is not expected to be a process area of major environmental concern.
2.3.2 Coal Gasification
As discussed in Section 2.2.3, only two types of wastes are generated in
the gasification operation. These are lockhopper (feed and ash) vent gases and
gasifier ash. Although compared to other gaseous emissions in a Lurgi SNG faci-
lity, the total volume of the lockhopper vent gases is small, these streams will
require control before discharge. The lockhopper gases are expected to contain
particulates, hydrocarbons, carbon monoxide and reduced sulfur and nitrogen com-
pounds. Essentially no data have been published on the characteristics of these
gases from an operating gasifier (including their hazardous properties) or on
the effectiveness and costs of the various controls proposed for use in gasifi-
cation facilities. The small amount of data which is available on gross charac-
teristics and Teachability of Lurgi ash is limited in that (a) the data have
been obtained on coals other than those proposed for use in commercial SNG faci-
lities in the U.S., and (b) the data are for laboratory conditions and not nec-
essarily reflective of conditions which would be expected in commercial plants
(e.g., use of plant wastewaters for ash slurrying). Based upon the available
data, except for its larger particle size, for a given coal the Lurgi ash would
be very similar to coal combustion boiler and fly ash in terms of gross physical
and chemical properties.
2.3.3 Gas Purification
Quenching and cooling of the Lurgi raw product gas produce a gas liquor
which is the major aqueous waste in the gas purification operation. Although
this waste stream is well characterized in terms of gross properties and content
of major constituents, relatively little data are available on specific organic
substances and trace inorganics in this waste stream and on the fates of these
substances in the proposed downstream treatment systems (e.g., Phenosolvan,
ammonia recovery, biological treatment and ash quenching).
The concentrated acid gases which result from gas purification in the
Rectisol process is one of the two major potential sources of atmospheric emis-
sions in a commercial Lurgi SNG facility. (The second major source is flue
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gases from onsite power and steam generation - see Section 2.3.5.) Concentrated
acid gases from the Rectisol process contain primarily CO,, and the bulk of the
original coal sulfur in the form of H2$ and to lesser extent COS, CS2 and mer-
captans. These acid gases also contain some low molecular weight organic com-
pounds, CO and HCN. Without pollution control, sulfur compounds in acid gases
could represent up to 90% of total sulfur emissions from a Lurgi facility and
nearly 100% of the CO and HC emissions. However, with pollution control systems
proposed for commercial SNG projects, acid gases represent only a small fraction
of total plant sulfur emissions. The CO and HC contribution to the plant total
from treated acid gases is much larger than in the case of sulfur emissions.
Acid gases are not significant sources of NOX or particulate emissions.
The available data for the Rectisol acid gas treatment process are not very
comprehensive in that all streams and constituents of environmental interest are
not addressed. The data are also for foreign installations which differ in
design and operating characteristics from those proposed for U.S. SNG facilities;
such differences in designs are likely to impact stream flow and composition.
In particular, the Lurgi product gas feed to the Rectisol unit needs to be char-
acterized in terms of trace constituents, and the fate of such constituents in
the particular Rectisol designs proposed for U.S. facilities needs to be defined.
Three environmentally important constituents in the feed and off-gases are COS,
HCN and HC. The levels of these constituents in the off-gases determine the type
and extent of downstream pollution control systems which would be required.
2.3.4 Gas Upgrading
The only continuous waste stream produced in the gas upgrading operation
is the methanation condensate. As noted previously, this condensate is expected
to be very clean and would be used in the plant as boiler feed water. The cata-
lysts used for shift and methanation (as well as the methanation guards), how-
ever, require periodic replacement. Very little information has been published
on the service life of these catalysts or on the characteristics of the spent
materials. Because of their expected hazardous characteristics, proper handling,
disposal, or reuse of spent catalyst is a major area of environmental concern.
Gaseous waste streams are generated as a result of decommissioning/regen-
eration of spent catalysts. Although of intermittent nature and of relatively
small volume, these gases are of environmental concern due to the potential
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presence of substances containing elements such as Ni, Co, Mo and In, in addi-
tion to CO, reduced sulfur compounds and polycyclic organic material (POM).
2.3.5 Auxiliary Processes
Although many of the pollution control processes which are proposed for
use in commercial Lurgi SNG facilities have been tested or used commercially in
other industries, their performance in SNG service has generally not been eval-
uated. For example, the Stretford process, which has been used comercially for
the treatment of natural gases and coke oven gases, has not been evaluated for
the treatment of high C02 content Rectisol off-gases. (It is only recently that
a commercial Stretford unit has been placed in such service at the SASOL Lurgi
plant in South Africa)^34^. Similarly, the performance of commercial sulfur
recovery tail gas treatment processes such as the Beavon process for handling
high C02 gases from the Stretford or Claus plant has not been evaluated. Incin-
eration is proposed for the control of hydrocarbon emissions in the Rectisol
off-gases. Since this method of control requires supplemental fuel, the trade-
offs between the degree of emission control, energy penalty and the impact on
the economics of SNG production have not been established.
With respect to water pollution control, the areas of major environmental
concern relate to the lack of adequate data on the characteristics of waste-
waters produced in an integrated Lurgi SNG plant and on the effectiveness of
various proposed treatment processes for the removal of specific pollutants
from these wastewaters. In general, much of the available wastewater charac-
terization data which have been reported are for gross properties (TOC, COD,
etc.) and major constituents (e.g., phenols, ammonia, sulfide, etc.); less data
are available on trace elements, organics and environmental and health effects.
The specific areas of ecological concern which need to be addressed relate to
the biodegradability, bioaccumulability and the environmental persistence of
the constituents in various aqueous waste streams in a Lurgi SNG plant.
Although phenol and ammonia recovery and biological treatment (e.g., using the
activated sludge or cooling tower oxidation processes) are expected to result
in some removal of many of the troublesome substances (e.g., CN~, SCN~, POM,
Hg, As, Cd), actual operating data are not available to indicate the expected
residual levels in treated wastewaters.
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All proposed commercial Lurgi SNG plant designs feature "zero discharge"
of plant wastewaters to surface waters. This is to be achieved by a combination
of solar evaporation in ponds and forced evaporation using fuel. Two questions
arise from an examination of the "zero discharge" concept as applied to Lurgi
plants. First, solar and forced evaporation may solve the problem of bulk
wastewater disposal but leave a residue (sludge or brine) disposal problem.
Unless properly designed and operated, ponds may also constitute an indirect
discharge source to surface or groundwaters via leakage or infiltration.
Secondly, the practicality of "zero discharge" for SNG plants in the eastern
U.S. is not well established. With relatively inexpensive raw water readily
available, there would be less incentive for minimum water use and hence waste-
water generation. Furthermore, solar evaporation is not practical east of the
Mississippi River and hence, expensive forced evaporation (or other salt re-
moval processes) would be required to meet the zero discharge goal.
Solid wastes generated by Lurgi systems include gasification and combustion
ash, raw water treating and pollution control solids/sludges, and spent cata-
lysts and related materials. Generally, the ash generated by gasification is
not expected to be greatly different from ash generated by coal-fired boilers
and techniques for transport and disposal of this material in SNG plants would
be similar to those practiced in large coal-fired power plants. When treated
gas liquor or other SNG plant wastewaters are used as ash slurry make-up water,
however, ash slurries in SNG facilities may have somewhat different composition/
properties than slurries encountered in coal-fired power plants. Water treating
and pollution control brines and sludges from SNG plants would not be expected
to be greatly different from those in other industries. When combined with
gasifier ash slurries, however, the waste may have certain unique characteris-
tics requiring evaluation before selection of an optimum treatment/disposal
method. Sludge properties which would require evaluation include dewaterability,
Teachability and chemical reactivity. A solid waste disposal area of particular
environmental concern is the disposal of spent catalysts and related materials.
Such materials contain potentially toxic catalyst metals and accumulated coal-
derived substances from coal (e.g., As, high molecular weight organics, and
sulfur- and nitrogen-containing substances). Although the types of catalysts
which are proposed for use in SNG plants have been used in other industrial
applications, little is known about the properties of the spent materials and
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the prevailing spent catalyst handling methods, primarily due to the proprie-
tary nature of many catalyst formulations.
The non-pollution control auxiliary processes such as raw water treatment
and steam and power generation which would be utilized in commercial Lurgi SNG
plants are widely used in industry, and environmental problems associated with
their use in SNG plants are not considered to be unique or unmanageable.
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3.0 CHARACTERIZATION OF INPUT MATERIALS, PRODUCTS AND WASTE STREAMS
This chapter is a summary of the available data relating to the physical,
chemical and biological properties of input materials, products and process/
waste streams associated with Lurgi systems for the production of SNG. Since
no integrated commercial Lurgi SNG plant currently exists, all of the available
operating/testing data are for some of the individual units/processes comprising
Lurgi SNG system. These data have generally geen obtained in different locations,
under different operating conditions and in connection with programs having dif-
ferent objectives. Since in many cases these data are fragmented and not directly
comparable, these limitations should be recognized when such data are used to
estimate the characteristics of streams in an integrated commercial facility.
The data presented in this chapter fall into four categories: (1) opera-
ting or testing data for the individual components of the Lurgi systems, (2)
design bases for proposed commercial facilities, (3) laboratory testing data
for various Lurgi products or wastes, and (4) pertinent data for similar streams
from other gasification processes where Lurgi data are unavailable. Section 3.1
describes sites and equipment sampled or planned to be sampled by IERL/RTP and
other organizations and the operating conditions under which samples have been
or will be acquired. Sections 3.2 through 3.7 present the physical, chemical
and biological effects data on a stream-by-stream basis. All materials, pro-
ducts and process/waste streams are referred to master flow diagrams (Figures
2-2, 2-3 and 2-4) in Section 2.2.1.
3.1 SUMMARY OF SAMPLING AND ANALYTICAL ACTIVITIES
3.1.1 IERL/RTP Environmental Assessment Activities
The Fuel Process Branch of EPA's Industrial Environmental Research Labora-
tory, Research Triangle Park (IERL/RTP) is currently carrying out a comprehen-
sive assessment program to evaluate the environmental impacts of synthetic fuels
from coal processes having a high potential for commercial application. The
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EPA effort consists of (a) evaluation of existing process and environmental
data and the data which are being generated by process developers, (b) defini-
tion of additional data needed for comprehensive environmental assessment, (c)
acquisition of supplementary data through sampling and analysis of process/waste
streams at selected coal conversion facilities, and (d) necessary process engi-
neering support studies and completion of the comprehensive environmental assess-
ment. Many of the elements of IERL/RTP programs are carried out through contract
and grant services. The following is a brief description of the major IERL/RTP
activities involving data collection through sampling and analysis of Lurgi or
Lurgi-related process/waste streams.
/ o r \
Sampling and Analysis at the Kosovo Plant1^. The Kosovo Kombinant plant
in Pristina, Yugoslavia is a Lurgi gasification facility which converts lignite
to fuel gas and fertilizer plant feedstocks. Under a cooperative research pro-
gram EPA and the Rudarski Institute (Belgrade, Yugoslavia) are involved in an
environmental test program at the Kosovo plant. The EPA effort is being carried
out through a contract to the Radian Corporation (Austin, Texas). A test plan
which had been developed for the facility is currently being implemented. The
test plan calls for sampling a total of 42 process/waste streams associated with
coal transport, gasification, ash disposal, tar separation, Rectisol, Phenosolvan,
by-product storage and cooling towers. The data collected in the test program
are expected to become available in early 1979.
Study of Lurgi Ash' '. Illinois State Geological Survey (ISGS) has con-
ducted studies on ash from Illinois No. 6 coal which was gasified in the Lurgi
facility at Westfield, Scotland. These studies included trace element and
mineralogical analyses of the unquenched ash; solubility of elements in the ash
leachate at four pH values over the range 2 to 11; and aquatic toxicity studies,
in which fathead minnows, Pimephales promelas, were exposed to ash leachates.
The gasification of the Illinois coal at the Westfield facility was part of a
program sponsored by the Office of Coal Research (OCR) and the American Gas
Association (AGA) to test American coals at the Westfield plant, as described
in Section 3.1 .2.
Laboratory-scale Gasifier Tests^8'37'3u^. Research Triangle Institute (RTI)
has initiated a parametric evaluation of pollutants from a laboratory gasifier.
The program consists of three phases: screening studies, parametric control
evaluations, and reaction kinetics research. The screening studies consider
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qualitatively and, for selected compounds, quantitatively the variety of chemi-
cal compounds produced during gasification reactions. RTI has screened a large
number of different compounds as part of Phase 1. The second phase which is
currently under way, examines the effect of reactor operating conditions on the
pollutant production. Parameters evaluated include coal type, grind size, pre-
treatment methods, bed depth, temperature, pressure, steam flow rate, residence
time, catalysts, and additives. Other parameters such as bed type (fixed, en-
trained, fluidized) and reactor type (batch, semi-batch, plug flow, mixed flow)
are considered. The screening studies are now under way. Most recently, gasi-
fication tests using Illinois No. 6 coal have been conducted '39)_
Large Bench-scale Gasification/Gas Cleaning Unit'' ' . North Carolina
State University (NCSU) is operating a bench-scale gasification/gas cleaning
unit consisting of a continuous fluidized bed gasifier; a cyclone and scrubbers
for removing particulates, condensables, and soluble matter from raw synthesis
gas; and an acid gas removal system. The gasifier operates at pressures up to
0.8 MPa (100 psig) with a capacity of 23 kg (50 Ib) coal/h. The gasifier uses
O
either steam-Op or steam-air feeds to produce 0.67 Nm (25 scf/min) of product
gas. The acid gas removal system is testing four solvents for the removal of
acid gases: refrigerated methanol, hot potassium carbonate, monoethanolamine,
and dimethylether of polyethylene glycol.
The overall objectives of the project are to characterize completely the
product, waste gases and condensates from coal gasification and gas cleaning
processes, and to determine how emissions depend upon various process parameters.
The initial operation of the gasifier has been with a chemical grade coke. The
first tests of the acid gas removal unit have been with a synthetic feed gas
mixture. Future tests using subbituminous coal or lignite as gasifier feed are
scheduled for May 1979.
Bench-scale Treatment of Gasification Wastewaters(8'37'38). The University of
North Carolina is currently conducting a bench-scale study to evaluate the effec-
tiveness of biological and chemical processes for the treatment of gasification
and liquefaction wastewaters and to determine the environmental impacts and
health effects of treated effluents. The majority of tests have been and are
currently being carried out with synthetic wastewaters, although several tests
have used actual wastewater from a coal gasification facility. Processes eval-
uated include activated sludge, coagulation and carbon adsorption. Bioassay
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testing (i.e., Ames cell tests and cytotoxicity tests) of the synthetic waste-
waters is currently under way.
3.1.2 Non-IERL/RTP Site Evaluation
Non-IERL/RTP environmental programs relating to Lurgi SN6 systems are
limited to those carried out by DOE and by commercial SNG project sponsors to
generate data needed for full scale designs. The most relevant of these pro-
grams are briefly summarized below.
Dunn County, North Dakota Project^13^ A 7 x 106 Nm3/d (250 x 1<)6 scf/d) Lurgi
SNG facility has been proposed by the Natural Gas Pipeline Company of America
(ANG). The coal is to be mined from Dunn County lignite beds. ANG sponsored a
gasification test program at the SASOL plant in South Africa and an analytical
support program at the University of North Dakota to obtain engineering and
environmental data for the Dunn County project. Since only a very small amount
of Dunn County coal was available, coal (lignite) from a mine in nearby Mercer
County, North Dakota was gasified at the commercial Lurgi plant at Sasolburg,
South Africa^ '. Samples of the coal, gasifier ash, oil, tar, and gas liquor
were analyzed at the University of North Dakota for trace and major inorganic
elements. Samples of Dunn County coal and laboratory gasification ash were sub-
jected to proximate, ultimate, and trace and major inorganic elemental analysis.
Analytical values from the SASOL tests were then extrapolated to the gasifica-
tion of Dunn County coal to project the distribution of elements among the gasi-
fication product and waste streams. Leachability tests were also performed on
ashes from both Dunn and Mercer County lignites. In a related program samples
of gas liquors from the gasification of the South African coals were also ana-
lyzed for a wide range of constituents and tested for biotreatability.
Testing of American Coal at the Westfield, Scotland Facility^ . The
American Gas Association (AGA) and the Office of Coal Research (OCR) sponsored
a program to test American caking coals in the Lurgi facility at Westfield,
Scotland during 1972-1974. The coals tested were: Rosebud (coarse and fine
graded), Illinois No. 5 (coarse graded and simulated run-of-mine), Illinois No. 6
(coarse graded and simulated run-of-mine), and Pittsburgh No. 8 (coarse graded
and simulated run-of-mine). Chemical analyses were performed on the feed coal,
tars, oils, liquors, product gas, flash gas and flare gas.
Analyses of Lurgi Ash^ 1-l42'. Peabody Coal Company carried out trace ele-
ment analyses on coal and ash samples from gasification tests of Illinois Nos. 5
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and 6 coals at the Westfield Lurgi facility. For the purpose of comparison,
split samples were also tested by the Argonne National Laboratory. The results
have been used by Argonne to estimate potential trace element emissions associ-
ated with Lurgi gasification.
In a separate effort, the Oak Ridge National Laboratory (ORNL) is currently
completing studies on ash from the gasification of Montana Rosebud and Illinois
Nos. 5 and 6 coals at the Uestfield facility. A complete physical and chemical
characterization of the unquenched bottom ash is being performed, as well as
throughput leaching studies which include both aquatic and terrestrial bioassays.
3.2 INPUT MATERIALS
The input materials to a commercial Lurgi SNG system were identified in
Section 2,1.3 in connection with the overview of the Lurgi systems. This section
presents the available data on the properties of these input materials used in
various gas production operations and auxiliary processes.
3.2.1 Coal Pretreatment and Handling
A variety of coals have been tested and/or are proposed for use in Lurgi
gasifiers. Table 3-1 presents the proximate and ultimate analyses of these coals
where data are available. Included are trace element data as reported for
specific coals tested or for coal samples from the same seam/deposit. The data
in Table 3-1 indicate a wide range of moisture content, caking properties and
ash and trace element contents for the coals tested. When properly designed and
operated, Lurgi gasifiers can handle essentially any type of coal; the commercial
projects which have been proposed to date are to use subbituminous coals or
lignites as feeds. Product and waste stream composition data presented in sub-
sequent sections will be for coals listed in Table 3-1.
3.2.2 Coal Gasification
The only inputs to the gasification operation other than sized coal are
steam and oxygen. Table 3-2 presents steam and oxygen consumption rates (mea-
sured or estimated for design purposes) for the various input coals listed in
Table 3-1. These consumption rates are generally specific for each coal type
and gasifier design and are for conditions which maximize gasification efficiency.
Oxygen used in Lurgi gasifiers is generally separated from air and contains
around 1-2% N2-
81
-------
TABLE 3-1. CHARACTERISTICS OF COALS WHICH HAVE BEEN OR ARE PROPOSED TO BE GASIFIED IN LURGI GASIFIERS
Coal No.
Source of Data
Type/ Origin
Gasification Site/
Project Acronynn
Size mm (in)
Composition, %
Mo i s tu re
Volatile Matter
Ash (dry basis)
C
H
0
S
N
HHV (as gasified)
OD kcal/kg (Btu/lb)
ro
Swelling No.
Caking Index
Major and Minor
Elements in Coal
(% moisture free
whole coal basis)
Al
Ca
Cl
Fe
K
Mg
Na
Si
Ti
1
(7,14,43)
Subbi tumi nous/
Rosebud Montana
Westfield
Scotland
6.4 - 31.8
1/4 - 1-1/4
24.70
29.20
12.9
67.15
4.22
13.02
1.45
1.20
4,781
(0,610)
0
0
1.71
1.65
0.02
0.60
0.11
0.23
0.02
3.09
0.06
2
(7,41)
High Volatile/
Illinois #6
Westfield
Scotland
6.4 - 31.8
1/4 - 1-1/4
10.23
34.70
10.1
71.47
4.83
9.02
3.13
1.35
6,370
(11,470)
3
15
1.20
0.93
0.28
1.50
0.16
0.04
0.060
2.45
0.06
3
(7,41)
Bituminous/
Illinois #5
Westfield
Scotland
6.4 - 31.8
1/4 - 1-1/4
11.94
35.21
9.2
7.280
4.95
7.99
3.56
1.39
6,364
(11,460)
2.5
22
0.73
0.89
0.13
2.63
0.10
0.04
0.89
2.24
0.04
4
(7,43)
Bituminous/
Pittsburgh #8
Westfield
Scotland
6.1 - 31 .&
1/4 - 1-1/4
4.58
37.37
8.1
77.71
5.28
4.24
2.64
1.42
7,468
(13,442)
7.5
30
1.14
2.57
0.13
0.93
0.13
0.04
0.022
2.01
0.07
5
(7,44)
Bituminous/
So. African
Sasolburg
So. Africa
__
8.0
--
31.6
52.4
2.6
11.7
0.43
1.2
5,000
(8,980)
—
-
4.7
1.6
7.0
1.1
0.1
0.3
0.2
7.9
--
6
(15,43)
Lignite/
No. Dakota
ANG
..
35.98
27.21
7.42
71 .45
4.81
21.01
1.26
1.44
4,020
(7,230)
--
--
0.65
2.00
0.02
0.60
0.01
0.26
0.42
1.0
.044
7
(2)
Subbituminous/
New Mexico
El Paso
__
16.96
28.88
20.77
59.2
4.3
12.2
.83
1.02
4,670
(8,400)
--
--
—
—
70 (pom)
--
--
—
--
--
--
8
(3)
Subbituminous/
New Mexico
WESCO
_-
12.4
--
30.3
37.2
3.7
11.1
1.09
1.01
4,720
(8,500)
--
--
3.2
0.6
--
0.9
.2
.14
0.3
7.1
0.4
9
(13,43)
Lignite/
No. Dakota
Dunn
County
--
38.56
27.03
6.84
63.56
4.38
18.92
1.30
0.65
3,586
(6,456)
—
--
.67
1.6
.005
.72
.005
.50
.24
2.2
.03
10
(14,43)
Subbituminous/
Wyoming
Wyoming
--
28.0
32.71
5.58
68.63
4.70
17.74
0.45
0.69
4,920
(8,848)
"
-
0.52
1.50
0.02
0.40
0.03
0.10
0.169
0.69
0.06
-------
TABLE 3-1. CONTINUED
co
CO
Coal No.
Type/Origin
Source of Data
Trace Elements (ppm)
Ag
As
8
Ba
Be
Br
Cd
Ce
Co
Cr
Cs
Cu
F
Ga
Ge
Hg
I
In
La
Li
Mo
Mn
Ni
f
Pb
Rb
Ru
Sb
Sc
Se
Sn
Sr
Ta
Te
U
V
U
Y
Zn
Ir
1
17,14,43)
Subbituminous/
Rosebud Montana
.06
.08 - 1.2
32
87
.7 & .8
20
.31 - .8
—
.6 - 4
4 - 16
--
9 - 10
66
-
11 - .1 7
__
--
--
—
2.2
2.8 - 3.4
2 - 14
--
.sr- 12
-
-
--
.33
0.14
--
--
--
.88
10 - 14
--
—
•5 - 8
170
2
(7,41*)
High Volatile/
Illinois »6
--
1.0
132
--
1.6
17(7)
<.4<7)
4
20
-
12
79
4.5<7>
6.0(7)
1.1
„
__
-.
—
7
20
14
29<7)
10
--
--
0.1
—
1.3(7)
—
--
--
-
--
20
—
--
43
.-
3
(7,41*)
Bi tuminous/
Illinois »5
--
2.0
307
-
2.0
12<7)
--
--
4
15
--
10
57
1.9(7)
9.0(7)
0.2
__
__
--
--
7
22
32
—
28
-
—
0.2
--
1.3<7'
9
--
-
--
-
21
--
—
200
--
4 5
(7,43*) (7,44*)
Bituminous/ Bituminous/
Pittsburgh #8 So. African
._
6.7 2-5
5.0 100
..
1.3 2-3
23
<0.20 <.l
150 - 200
12
1.8
..
11
52 100
4.2
2.0
0.14 <.l
__
..
..
„
1.0
12 500
20 30 - 50
100
7.0 10 - 20
—
..
0.90 <,5
._
1.3 0.3
..
5.0
--
0.23
„
46 300-500
--
..
21
..
6 7
(15.43f) (2)
Lignite/ Subbituminous/
No. Dakota New Mexico
< 0.1
19.7 - 30 0.1 - 3.0
12 - 300 60-150
60 - 2500
0.12 - 2.0 2-3
1.5 100
0.63 0.2 - 0.4
150 - 200
0.84 - 6.0
1.4 - 6.0
..
1.2 - 6.4
24 - 83 100
0.46 - 1.2 0.5 - 8.0
0.3 - 1.2 0.1 - 0.5
0.05 - 0.09 0.2 - 0.3
_.
—
1.1
—
1.2 - 1.5
12.0 - 50.0 500
1.2 - 5.9 3.0 - 30.0
200<7)
0.67 -20.0 1.4 - 4.0
0.4 - 12.0
0.4
0.1 - 0.12 0.3 - 1.2
<0.1 - 6.0
1.0 - 1.3 0.1 - 0.2
0.25 - 4.0
570 - 600
..
—
0.27 - 1.0
2.7 - 12 300 - 500
--
4.0 -- 6.0
0.6 - 12.0 1.1 - 27.0
60-68
8 9
(3) (13,«3t)
Subbituminous Lignite/
New Mexico No. Dakota
0.030
1.2 10
63
230
3.4 0.31
1.7
0.66 0.21
14
5
65
0.26
23
210 21
0.60
0.01 0.20
<0.30<7)
<0.0l(7)
1.2
..
22
250
12
131
5.5 54
41
..
0.42 0.31
1.5(7)
0.74 0.85
<0.30
1030
0.05(7)
0.20
3
—
0.58
--
11
L ,
10
(14,43f)
Subbituminous/
Wyomi ng
.06 - 0.43
0.57 - 1.2
32
87
0.71 - 0.8
--
0.31 - 0.8
—
0.55
4.2 - 16.0
—
8.9 - 10
65 - 67
„
-
0.11 - 0.17
—
--
-
3.6 - 15.0
2.2
2.8 - 3.4
1.7 - 14
--
0.51 - 12
—
-
0.08 - 1.5
__
0.33
0.14
._
--
0.88
10 - 14
—
--
0.23 - 8.0
—
-------
TABLE 3-2. OXYGEN AND STEAM INPUT RATES FOR GASIFICATION OF VARIOUS COALS IN LURGI GASIFIERS
co
Coal No.
1
2
3
4
5
6
7
8
9
10
Type/Origin
Subbi tuminous/
Rosebud Montana
Bituminous/
Illinois No. 6
Bituminous/
Illinois No. 5
Bituminous
Pittsburgh No. 8
Subbi tuminous/
So. African
Lignite/
No. Dakota
Subbi tuminous/
New Mexico
Subbi tuminous/
New Mexico
Lignite/
No. Dakota
Subbi tuminous/
Wyoming
Source of Data
7
7
7
7
44
15
2
3
13
14
Oxygen - kg/kg coal
as charged
0.23
0.48
0.46
0.59
—
0.20
0.22
0.23
0.20
0.21
Steam - kg/kg coal
as charged
1.25
2.26
2.53
3.27
1.74
1.06
--
__
—
—
-------
3.2.3 Gas Purification
Rectisol solvent, methanation guard material and dehydration solvent are
the input materials for the gas purification processes. Methanol is the solvent
commonly used in the Rectisol process.* The purity (grade) of methanol which
would be required for use in a commercial facility is not known, although it is
likely that technical grade methanol would be used. Technical grade methanol
has a purity of approximately 99.85% MeOH with impurities consisting primarily
of water with smaller amounts of higher molecular weight alcohols, formaldehyde,
acetone and/or hydrocarbons^' '.
Quantities of make-up methanol (Stream 19) required would depend largely upon
the specific Rectisol design. At the SASOL, South Africa Lurgi facility about
0.7 liter of make-up methanol is consumed for every 1000 Nm (37,300 scf) of gas
(44)
processed^ '. The El Paso Burnham and HESCO designs assume 2.7 and 0.6 liters
(0.6 and 0.13 gal), respectively, of make-up methanol for each 1000 Nm3 (37,300
(2 31
scf) of gas processedv ' '. In general, higher temperature regeneration will
result in a greater methanol loss to the regenerator off-gas and hence a higher
make-up requirement.
Zinc oxide is proposed for use as methanation guard at all commercial faci-
lities in the U.S. No data are currently available on the quantities or com-
position of commercial materials which may be used in this application. Ethylene
or propylene glycol are proposed for use in dehydration of methanator product.
No data are available on make-up requirements for commercial facilities.
3.2.4 Gas Upgrading
Commercial cobalt molybdate-based catalysts used for shift conversion typi-
cally contain around 3% cobalt oxide and 10% molybdenum trioxide supported on
alumina. The catalyst is active in the "sulfide" form and is activated during
startup by exposure to raw gasifier gas containing H,>S. Make-up quantities are
not known at this time. Based on experience in the petrochemical industry,
shift catalyst may be regenerated by burning off the "coke" which accumulates over
time. The make-up quantity depends upon the deactivation rate which is in turn
a function of feed gas composition, operating conditions and the catalyst formu-
lation.
*Propylene in quantities of about 0.02 £/1000 Nm° (0.0053 gal/37,300 scf) of gas
processed is also proposed for use in at least one commercial design(3).
85
-------
Commercial methanation catalysts are usually reduced nickel-based supported
on materials such as alumina and Kieselguhr (diatomaceous earth). The proper- ;
ties and replacement requirements for such catalysts are generally considered
proprietary and hence detailed information is not publicly available.
3.2.5 Auxiliary Processes
In a commercial Lurgi SNG facility, the Lurgi-licensed processes for pollu-
tion control/by-product recovery which require input chemicals are the Phenosol-
van and the Chemie Linz AG/Lurgi processes. The Phenosolvan process can use
one of several solvents depending on the specific design. In foreign gasifica-
tion facilities butyl acetate and light aromatic oil have been used. Proposed
commercial facilities in the U.S. are designed to use diisopropyl ether as the
solvent. Make-up requirements for butyl acetate (used at the SASOL, South Africa
plant) are reported at about 15 liters per million liters of gas liquor pro-
cessed^ . Diisopropyl ether make-up rate for the proposed WESCO Lurgi faci-
6 f 3 )
lity is estimated at about 80 liters/10 liters of gas liquor^ ;.
No operating data are available on input chemicals to the Chemie Linz AG/
Lurgi ammonia recovery process. Proposed commercial facilities in the U.S. do
not feature the use of this Lurgi-licensed process for ammonia recovery. Com-
monly ammonia recovery requires addition of lime or caustic to enhance strip-
ping efficiency; alkali requirements vary with feed buffer capacity and the
desired ammonia removal efficiency.
Depending on the specific processes used for raw water treatment and pol-
lution control, a spectrum of input materials would be associated with the
auxiliary processes (see Section 2.2.5), Many of these materials (e.g., lime
and alum are widely used in the treatment of municipal and industrial waters
and wastewaters. Input material requirements for pollution control processes
which may be employed in Lurgi SNG facilities are briefly discussed in Chapter
4.
3.3 PROCESS STREAMS
Process streams in Lurgi SNG systems are defined as inputs to or outputs
from gas production processes. As shown in Figure 2-2, major process streams
are raw product gas (Stream 11), shifted gas (Stream 16), Rectisol product gas
(Stream 24), methanator feed (Stream 26) and product SNG (Stream 32). The
86
-------
TABLE 3-3. LURGI PRODUCT GAS CHARACTERISTICS AND PRODUCTION RATES
CO
Coal No. 1 23
4 567
T /n . . Montana Rosebud Illinois #6 Illinois #5 Pittsburgh #8 So. African No. Dakota New Mexico.
lype/urig n Subbituminous High Volatile Bituminous Bituminous Subbituminous Lignite Subbituminous
Reference 7 77
7 44 15 2,23
Gas Production 2.0 2.3 2.3 2.4 2.3 2.1 1.95
Rate - Nm3/kg (34) (39) (39) (41) (39) (36) (33)
(scf/lb) MAP*
Gas Composition
(mole %) dry
H2 41.1 39.1 38.8
39.4 40.05 38.77 38.95
8
New Mexico
Subbituminous
3
1.95
(33)
38.7
02 1.2 0.6 0.8 0.8
N2 + Ar -- 0.6 0.7
0.8 -- 0.12 0.31
C02 30.4 31.2 31.0 31.5 28.78 32.52 28.03
CO 15.1 17.3 17.5 16.9 20.20 15.63 20.20
CH. 11.2 9.4 9.2 9.0 8.84 10.81 11.13
C2H.
0.07 0.61
C0H, 0.50 0.70 0.50 0.70 0.54 0.05 0.40
i 6
H,S 0.50 1.1 1.1
L. 1
COS / I
I 1 \
cs " '
2 (315 ppmv' 180 ppmv <232 p
Mercaptans ) I /
Thiophenes i 1
0.8 -- 0.35 0.37
0.01
0.0012
pmv 122 ppmv
0.01
0.0012
0.3
28.4
19.9
10.3
0.1
0.60
0.50
__
__
--
—
HCN 0.0002 0.0023 0.0078 0.00066 -- -- 0.0002
NH3f 0.00012 0.0002
0.0002 -- 0.96
--
*Hoisture and ash free basis.
tQata for coals 1, 2, and 4 represent gas after cooling and moisture condensation; the data for coal 6 are calculated from mass balance
considerations and would represent raw gas.
-------
available data on the flow rates and characteristics of these streams and the
origin and fates of environmentally important species in these streams are pre-
sented below.
3.3.1 Coal Pretreatment and Handling
Data on the characteristics of the feed coals for Lurgi SNG systems were
presented in Section 3.2.1. In the Lurgi systems coal pretreatment consists
of crushing and screening which would have essentially no effect on the chemi-
cal composition of the coal. Accordingly, the composition of the sized coal
which is fed to the gasifier would be approximately the same as those presented
in Table 3-1 for the uncrushed coal.
3.3.2 Coal Gasification
Table 3-3 presents data on Lurgi product gas compositions and production
rates for four American coals tested at Westfield, Scotland (coals no. 1 through
4), three American coals which are proposed for use in commercial Lurgi SNG
facilities (coals no. 6, 7 and 8), and one South African coal used at the SASOL
facility (coal no. 5). Generally, Lurgi gas contains about 40% H?s 15 to 20%
C09 28 to 32% C02, 9 to 11% CH4, and around 1% C2-Cg hydrocarbons. For most
coals the original sulfur and nitrogen in the coal are converted during gasi-
fication mainly to f-LS and NFL, respectively, with small amounts of other reduced
substances (e.g., COS, CS2, mercaptans, thiophenes, and HCN) also produced. It
should be noted that the data in Table 3-3 are for product gas after cooling;
cooling of the raw gas results in bulk removal of tarry and oily substances,
ammonia, and dust consisting of ash and partially gasified coal. No data are
available on the composition of the gas prior to cooling.
The major variables which affect the composition at Lurgi gas are coal type,
steam and oxygen feed rates, and pressure. Generally, lower rank coals yield
lower quantities of gas but more total methane per unit weight of MAP (moisture
and ash free basis) coal. For a given coal, methane content increases with
increasing gasifier pressure up to about 2.8 MPa (450 psia). The amount of
(CO + H2) is dependent primarily upon coal grade but the H2/CO ratio is influ-
enced primarily by the steam/oxygen ratio.
Of major concern from both a product gas purification standpoint and from
a pollution control standpoint are the type and amount of reduced sulfur and
nitrogen species in the Lurgi product gas. Essentially no actual operating
88
-------
data are available for the sulfur species distribution in the product gas from
the gasification of the coals to be used in the proposed commercial SNG facili-
ties in the U.S. The proposed designs for gas purification and pollution con-
trol processes for such facilities are generally based on estimates of equili-
brium sulfur species concentrations derived from thermodynamic considerations.
For a number of other coals for which actual operating data are available on
non-H?S sulfur concentrations in the product gas, the actual concentrations,
however, are somewhat lower than would be predicted from equilibrium considera-
*
tions.
Organic nitrogen in coal is gasified primarily to ammonia and to a lesser
extent to elemental nitrogen and HCN. The data in Table 3-3 indicate that up
to 80 ppmv of HCN may be present in Lurgi gas after cooling and moisture conden-
sation. Ammonia is largely condensed with moisture and is present in cooled
gas at levels of less than 10 ppmv (around 6-9 kg NH,/tonne or 12-17 Ibs NH~/
ton MAP coal are found in Lurgi gas liquor).
3.3.3 Gas Purification
As discussed previously, after primary cooling the raw product gas from the
Lurgi gasifier is split, with half sent to shift conversion and half to secondary
cooling. After secondary cooling and shift conversion, the two streams are com-
bined and sent to Rectisol treatment.
Table 3-4 presents the available data on the performance of the Rectisol
process. As indicated by the data, h^S levels of 1.0 ppmv or less in the pro-
duct gas are achievable. Depending on the design, Rectisol units can remove (XL
to a level of 10 ppm (the fourth case in the table), although for SNG production
3% C02 in the product gas is acceptable. Although not indicated by the data in
the table, the Rectisol also removes ammonia, HCN, non-H^S sulfur compounds and
hydrocarbons heavier than ethane. Traces of methanol are to be expected in
Rectisol product gas.
*The analytical results of Westfield tests with American coals indicate non-H2S
sulfur in Lurgi product gas to range from about 120 to 300 ppmv, or about 1.5
to over 6% of the total gaseous sulfur. Based upon thermodynamic considerations
the following distribution of sulfur species would be expected in Lurgi gas:
H2S, 94 to 96%; COS, 2 to 3%; C$2, -0.3%', mercaptans, -2%; and thiophenes,
~0.3%(20,46). These equilibrium values indicate a non-H2S percentage of about
4 to 6%.
89
-------
TABLE 3-4. RECTISOL FEED AND PRODUCT (OUTPUT) GAS STREAM COMPOSITION*
Rectisol Type/
Source of Data
Constituents/
Parameters
H2*
CO
CH,
co2
N2 + Ar
H2S
COS
cs2
RSH
Thiophene
C2+
MeOH
Temp: °K (°F)
Pressure:
MPa (psia)
Rate: Nm3/hr
(scfn)
Type At (32>
Input
58.4
0.3
0.2
21.9
19.2
--
--
--
--
--
--
--
--
.4(356)
153,100
(94,300)
Output
74.8
0.38
0.25
60 ppm
24.57
--
--
--
--
--
--
—
--
2.2(327)
118,500
(73,500)
Type A* (41)
Input
40.05
20.20
8.84
28.78
1.59
2480 ppmv
10 ppm
--
20 ppm
--
0.54
--
303 (86)
2.5(380)
381 ,000
(236,000)
Output
57.30
28.40
11.38
0.93
1.77
0.035 ppm
288 (59)
2.3(345)
263,000
(163,000)
TypeA5'31'
Input
43.8
12.7
10.7
32.2
0.29
0.34
--
--
--
--
0.98
—
450 (351)
3,032,000
(1,879,000)
Output
63.6
16.8
14.9
3.1
0.43
--
--
--
--
--
1.15
—
220 (-50)
2,060,000
(1,274,000)
Type Bt <32'
Input
62.31
3.25
0.17
33.25
0.53
0.49
10 ppm
—
-
—
-
-
3.2(480)
142,340
(88,250)
Output
94.08
4.86
0.24
10 ppm
0.82
-
--
--
--
--
--
--
--
3.0(450)
94,040
(34,300)
TyPeB(32)
Input
61.59
2.60
0.33
34.55
0.41
0.52
--
--
--
--
--
--
—
7.1(1066)
137,000
(84,940)
Output
94.92
3.94
0.47
50 ppm
0.67
1 ppm
--
-
—
--
-
--
--
6.9(1037
88,530
(54,890)
TypeB*(22>
Input
63.74
4.13
0.13
31.62
0.12
0.26
63 ppm
--
—
—
-
--
303 (86)
0.3(45)
80,000
(49,600)
Output
93.58
6.06
0.19
--
0.17
—
--
--
--
--
--
--
295 (72)
2.9(44)
54,500
(33,800)
*A11 values, unless otherwise noted, are in vol. %.
+Type A - Simultaneous removal of C02 and H2S and simultaneous recovery of CO? and
Type B - Simultaneous removal of C02 and h^S and separate recovery of C02 ana H2S
*Data are for SASOL, S.A. Lurgi facility
^Concentrations/parameters assumed in the design of the El Paso Lurgi SNG facility
#Data are for an oil gasification plant using the Texaco gasification process.
-------
Designs for commercial SNG facilities incorporate zinc oxide beds which
would be placed between the Rectisol and methanation units to remove residual
sulfur and to safeguard the catalyst should the Rectisol unit malfunction. No
operating data are available on the performance of the methanation guards in
Lurgi gasification service. Methanation guards, however, have been tested in
connection with the Hygas coal gasification process pilot plant program. The
data obtained in connection with the Hygas program are presented in Table 3-5.
As noted in the table, a residual total sulfur level of about 0.05 ppmv is
achieved with the use of the methanation guard. Methanation guards are expected
to remove only the trace sulfur compounds and not alter the major constituent
composition of the product gas stream.
3.3.4 Gas Upgrading
Gas upgrading consists of shift, methanation and drying. Although these
processes have been used in many industrial applications and operating data are
available for such applications, no operating data are available on performance
in commercial SNG service. Table 3-6 presents data for shift conversion from
bench scale tests using a simulated coal gas and the data used as the design
basis for the proposed El Paso Lurgi plant.* The commercial design assumes that
an H2/CO ratio of over 9:1 is attainable at a catalyst temperature of 560°K
(550°F). As indicated by the bench-scale data, the shift catalyst is active at
the higher temperature of 627°K (670°F) but not at the lower temperature of
438°K (330°F). (At the higher temperature the H2/CO ratio in the product gas
approaches that which would be expected under equilibirum conditions.) Also at
the higher temperature there is a reduction in the concentration of the lower
molecular weight (and probably also the higher molecular weight) unsaturated
organics; these organics are probably hydrogenated to saturated forms. Based
on equilibrium considerations, at a temperature of about 560°K or 550°F (tempera-
ture proposed for commercial designs) about 65% of the COS and essentially all
of the CS0 would be hydrolyzed to H0S and mercaptans, thiophenes and HCN would
(23)
be almost completely hydrogenated to form H?S and NH~V . Although destruction
of COS, CSp, mercaptans, thiophenes, and HCN is desirable, the downstream
Rectisol unit must still be designed to handle these components, since the shift
*The commercial designs are probably based upon test or operating data which may
have been available to the process developers or designers. Such data are not
published and were not available for use in this document.
91
-------
TABLE 3-5. TYPICAL PERFORMANCE DATA FOR THE ZINC OXIDE SULFUR GUARD SYSTEM
AT THE HYGAS PILOT PLANT(47)
Parameter/Consti tuent
Temperature (°K)
Pressure (MPa)
Major Components (v%)
Hydrogen
Carbon Monoxide
Sulfur Compounds, ppmv
H2S
COS
CH3SH
CH3SCH and CH3CH?SCH
(Total Sulfur)
Feed Gas
617
7.64
50.2
31.11
0.53
0.02
0.04
0.03
(0.62)
Product Gas
617
7.56
50
31
0.003
0.045
0.002
0.000
(0.050)
92
-------
TABLE 3-6. SHIFT CONVERSION FEED AND PRODUCT GAS CHARACTERISTICS
Parameter/ Consti tuent
Reactor Temperature, °K (°F)
Reactor Pressure, MPa (psia)
Composition
CO
co2
H2
CH4
C2H6 , C3H8
C2H4' C3H6
COS
H2S
S02
N2
H20
Tar
Oil
NH3
H2/CO ratio
H2/CO ratio calculated
at equilibrium
Commercial
Feed
560 (550)
2.8 (400)
13.5
18.6
26.1
7.5
0.4
0.16
—
0.24
__
0.2
32.2
.03
0.13
0.06
1.9
Design^31)
Product
--
--
3.84
28.2
35.85
7.44
0.4
0.16
--
0.24
--
0.2
22.5
0.03
0.13
0.06
9.33
40
Bench Scale Tests ^48^
Feed
627 (670)
7 (1025)
5.2
4.1
18.6
29.3
0.80
0.12
0.09
0.60
0.06
0.78
40.28
--
--
--
1.7
Product
—
--
0.41
8.3
21.9
25.5
0.78
0.02
0
0.6
0.02
1.05
41.4
--
—
--
53
90
Feed
438 (330)
1.4 (200)
12.6
10.5
21.7
12.0
0.22
0.14
0.12
1.18
--
--
32.2
--
--
--
1.9
Product
--
--
11.0
9.5
21.1
10.7
0.19
0.14
0.11
1.32
--
0
45.2
--
—
--
1.0
140
CO
-------
bypass gas will still contain them in the approximate levels listed in Table 3-3
for the cooled raw product gas.
Designs for proposed Lurgi SNG facilities incorporate the Lurgi fixed bed
methanation process with cooling by hot gas recycle. At present, no actual
operating data are available for the use of methanation on the Lurgi gas. Table
3-7 presents pilot plant data for fixed bed methanation of Hygas coal gasifica-
tion process product gas and the design data for one proposed commercial faci-
lity. As confirmed by the pilot plant data, essentially all of the CO can be
converted to methane when the ratio of H2/CO is greater than three (standards
for pipeline gas would generally require less than 1000 ppmv CO). Any sulfur
compounds in the feed gas are also removed; these compounds are trapped by and
accumulated on the catalyst. Hydrocarbons other than methane are largely reformed.
Although not indicated by data in Table 3-7, methanator product gas can
contain traces of nickel carbonyl formed by the reaction of catalyst nickel with
carbon monoxide. Equilibrium considerations indicate that at the temperatures
which prevail near the inlet in the methanator, a Ni(CO)., concentration of
,(49)
4
several hundred ppmv can be expectedv '. Although at the higher temperatures
near the methanator outlet equilibrium concentration for Ni(CO). should be less
than 1 ppb, the bench scale data indicate significantly higher levels^ '. The
high levels of Ni(CO)4 in the methanator outlet have been attributed to the very
slow rate of decomposition of Ni(CO). formed near the inlet' .
Not all of the Ni(CO)4 found in the methanator product gas can be attri-
buted to the side reactions which may occur in the methanator. Ni(CO)4 has been
found in the product gas from the Lurgi gasifier at the Westfield, Scotland
facility^ '. This has been attributed to the reaction in the gasifier between
the carbon monoxide and nickel in the coal. The cooling and dust removal and
the acid gas removal apparently do not result in complete removal of any Ni(CO)4
formed in the gasifier.
Dehydration of methanator product is accomplished by cooling (heat recov-
ery) for bulk moisture condensation followed by treatment with solvents such as
glycol or by molecular sieves for trace moisture removal. The estimated pro-
duct gas compositions for proposed Lurgi SNG facilities are listed in Table 3-8.
94
-------
TABLE 3-7. PERFORMANCE DATA FOR FIXED BED METHANATION REACTORS'
Constituent/
Parameter
CH4
H2
co2
CO
N2 + Ar
C2H6' C2H4
H2S
COS
RSH
Catalyst
Hygas Pilot Plant^51^
Feed Product
23.6 67.4
51.6 15.5
0 0
12.7 0
10.4 17.1
1.4 0
.003 (
.045 '<.00l
.002
Harshaw
Pelleted
Nickel
( 3U
El Paso Burnham DesignV '
Feed Product
14.9 92.7
63.5 41
3.1 1.8
16.9 .01
0.4 1.1
0.45
__
__
__
Pelleted
Nickel
*Moisture free basis
95
-------
TABLE 3-8. ESTIMATED PRODUCT GAS COMPOSITIONS FOR PROPOSED LURGI SNG FACILITIES
Constituent/
5arameter
CH4
H2
CO
co2
N2 + Ar
Heating value,
kcal/Nm3
(Btu/scf)
ANG(15)
95.95
3.00
0.05
0.40
0.60
8630
(970)
El Paso^2^
92.92
4.15
0.01
1.81
1.08
8720
(980)
WESCO^3^
96.84
1.45
0.06
0.50
1.15
8720
(980)
Dunn County^13'
97.57
0.97
0.04
0.40
1.02
8790
(988)
96
-------
3.4 TOXIC SUBSTANCES IN PRODUCTS AND BY-PRODUCTS
SNG is the only product from the Lurgi SNG systems. The by-products of
Lurgi SNG systems include tar, oil, naphtha, phenol, ammonia and sulfur. The
by-products are produced by auxiliary processes in Lurgi systems, and the approx-
imate quantities generated by gasification of various coals are presented in
Table 3-9.
Product and by-products from Lurgi SNG facilities may contain substances
which could be toxic or otherwise present hazards for occupational or general
public exposure. This section reviews the composition data which have been
reported for the product and various by-products of Lurgi SNG systems and iden-
tifies those substances or classes of substances which would be considered toxic.
There is currently no universally accepted toxicity rating system; the EPA-
developed Multimedia Environmental Goals (MEG's) hazard rating system (see
Section 5.1.1) has been used in this report for the identification of potentially
hazardous substances. The system,which provides one simple means of identifying
through cursory inspection those pollutants most likely to pose a human health
hazard, takes into account toxic and genotoxic potentials as well as cummulative
or chronic effect characteristics. The MEG hazard rating system has been devel-
oped for cursory screening of potentially hazardous pollutants when detailed
stream composition data are not available and mode of exposure and synergistics
and antagonistic effects exerted by other substances are not defined. When cer-
tain of these additional data are available, a number of other more complex
methods (e.g., comparison of composition data with MEG values - see Section 5.1.1)
may be used for hazard assessment.
3.4.1 Coal Pretreatment and Handling
No by-products are generated in this operation.
3.4.2 Coal Gasification
Although tars, oils, phenols, etc. are produced as by-products in the Lurgi
gasifier, such by-products are recovered in subsequent processes for gas purifi-
cation and pollution control (see Sections 3.4.3 and 3.4.5).
3.4.3 Gas Purification
A naphtha by-product is generated during acid gas removal from cooled pro-
duct gas. The principal constituents of the naphtha are butenes (C. olefins),
benzene, toluene, xylene and smaller quantities of higher molecular weight
97
-------
TABLE 3-9. LURGI BY-PRODUCT PRODUCTION QUANTITIES (KG/KG MAP* COAL)
Coal No.f
Data Source
Tar
Oil
Naphtha
Phenol
Ammonia
Sulfur
1
7
30
30
--
7
6
—
2
7
30
5
--
6
8
—
3
7
39
7
--
6
8
—
4
7
41
9
--
4
8
__
5
44
15
7
4
4
8
--
6
15
56
9
11
7
14
--
7
2
74
41
17
9
89
13
8
3
49
50
21
7
13
8
9
13
75
13
10
11
8
14
10
14
53
8
7
4
UD
CO
*MAF = moisture and ash free basis
Coal numbers refer to coal listed in Table 3-1
-------
aromatics. Under the MEG "cursory" hazard rating system, benzene is rated "haz-
hardous" whereas both xylene and toluene are rated as "nonhazardous;" no MEG
rating has yet been established for butenes.
3.4.4 Gas Upgrading
Table 3-8 presents the estimated composition for the product gas from
Lurgi SNG systems. As indicated by the data in the table, the primary consti-
tuent of SNG is methane with smaller quantities of H,,, CO, C02, N,, and Ar also
present. The MEG "cursory" hazard rating system rates CM., CO,, and CO as "non-
hazardous." It should, however, be noted that CO is classified as a "criteria"
air pollutant and is considered an occupational hazard. Although no MEG ratings
are yet available for N2, H2 and Ar, these gases are not considered toxic (N2
and Ar are components of the atmosphere). As noted in Section 3.3.4, trace
quantities of Ni(CO)4 may also be present in the Lurgi SNG. The MEG system
rates Ni(CO). as "very hazardous." This substance is a well known carcinogen.
3.4.5 Auxiliary Processes
Tars, oils, phenol, ammonia and sulfur are the by-products recovered in
water or air pollution control processes. No actual composition data are avail-
able for the organics in the Lurgi tars. However, some composition data are
available for the tars produced in the Synthane coal gasification process.
These data which are presented in Table 3-10 are indicative of the type of sub-
stances which would be expected in the Lurgi tars. Under the MEG hazard rating
system, some of the substances/class of substances in the Synthane tar (e.g.,
pentacyclic aromatics and N-heterocyclics) would be rated as "hazardous," "very
hazardous" or "most hazardous."
Table 3-11 presents data on minor and trace elements in the Lurgi tar and
oil. As noted in the table, some of the elements which are present in relatively
higher concentrations (e.g., arsenic, mercury and nickel) would be rated as
"most hazardous." A number of trace elements which are found in smaller amounts
(e.g., vanadium, barium, cobalt, boron and copper) would be rated as "very hazard-
ous," "hazardous" or "nonhazardous."
Very limited data are available on the organic substances in the Lurgi
oil. Some of the substances which have been identified in the oil from the West-
field Lurgi plant are shown in Table 3-12. As indicated by the data, crude Lurgi
oil contains about 90% aromatic compounds and about 1.8% thiophenes. With the
99
-------
TABLE 3-10.
COMPOSITION OF BENZENE SOLUBLE TARS PRODUCED IN SYNTHANE
GASIFICATION PROCESS (52,53)
Compound/Class
Mono Aromatics
Benzene
Phenols
Di Aromatics
Naphthalenes
Indans/Indenes
Naphthols and
Indanol s
Tri Aromatics
Phenyl naphthal enes
Acenaphthenes
Fluorenes
Anthracenes/
Phenanthrenes
Acenaphthols
Phenanthrols
Tetracyclic Aromatics
Pericondensed
(benzanthracenes,
chrysene)
Catacondensed
(pyrene, benz-
phenanthrenes)
Pentacyclic Aromatics
Heterocycl ics
Dibenzofurans
Dibenzothiophenes and
Benznaphthothi ophenes
N-Heterocycl ics
Type/Origin of Coal
Bituminous
(Illinois)
Lignite
(N. Dakota)
Subbituminous
(Montana)
Volume %
2.1
2.8
11.6
10.5
0.9
9.8
13.5
9.6
13.8
2.7
7.2
3.0
trace
6.3
6.2
10.8
4.1
13.7
19.0
5.0
11.4
3.5
12.0
7.2
10.5
2.5
3.5
1.4
5.2
1.0
3.8
3.9
5.5
15.3
7.5
11.1
6.4
11.1
9./
9.0
4.9
0.9
4.9
3.0
5.6
1.5
5.3
Bituminous
(Pennsylvania)
1.9
3.0
16.5
8.2
2.7
7.6
15.8
10.7
14.8
2.0
7.6
4.1
trace
4.7
2.4
8.8
flEG
Hazard
Rating*
X
NH
NH
NH
NH
NH
NH
NH to XX
NH to XX
NH to XXX
NH to XX
*MEG hazard rating: X hazardous, XX very hazardous, XXX most hazardous,
NH nonhazardous and -- not rated.
100
-------
TABLE 3-11.
COMPOSITION OF TARS AND OILS PRODUCED BY GASIFICATION OF
VARIOUS COALS IN LURGI GASIFIERS
Coal Number
Coal Type/Origin
(Reference)
Production Rate, kg/tonne
coal (dry basis}
Elemental Composition (wt %)
5
Ash
Minor and Trace Elements (ppn
Jj
1
Subbi tuminous
Montana Rosebud
(7)
Tar Oil
26 26
0.28 0.5
0.05 0.03
2
Bituminous
Illinois 16
(7)
Tar Oil
27 5
1.7 2.4
0.03 0.01
3
81 tuminous
Illinois #5
(7)
Tar Oil
35 6
2.4 2.3
0.01 0.01
Bi tuminous
Pittsburgh 08
(7)
Tar Oil
38 8
1.5 1.5
0.01 0.01
5
Bi tuminous
S. African
(44)
Tar Oil
15 8
0.3 0.25
-
6
Lignite
N. Dakota
(15)
Tar Oil
15 8
0.65 0.52
0.45
09
92 5
9
Ligni te
N. Dakota
(13)
Tar Oil
15 &
..
--
U.I
MEG
Hazard
Rating"
(53)
XXX
x
XXX
XXX
XX
NH
*MEG hazard rating: X = hazardous, XX = very hazardous, XXX = most hazardous, NH • nonhazardous, -- = not rated.
101
-------
TABLE 3-12. ORGANIC COMPOSITION OF LURGI OIL PRODUCED AT THE WESTFIELD LURGI
FACILITY(54)
Compound/Class
Paraffins
Olefins
Aromatics
Sulfur (total)
Benzene
Toluene
Xylene and
ethyl benzene
Ethyl toluene
Trimethyl benzenes
Styrene
Indane
1,2»benzofuran
Indene
Naphthalene
Thiophenes
Concentration (wt %)
10.71
89.3
19.56
28.40
14.7
2.69
11.8
1.07
1.43
1.09
5.37
1.40
1.77
100
102
-------
exception of benzene which is rated as "hazardous" and styrene which is not yet
rated, all substances or classes of substances listed in Table 3-12 are rated as
"nonhazardous" under the MEG system.
No data are published on the composition of the crude phenols recovered
by the Phenosolvan process for the treatment of the Lurgi gas liquor. However,
some data are available on the types of phenolic compounds present in the gas
liquor (see Table 3-13). These data indicate that monohydric phenols account
for 50% to 80% of the total phenolic materials in the gas liquor. As noted in
Table 3-13, other classes of phenols found in the gas liquor are catechols and
resorcinols. Although a MEG rating has not yet been developed for all individual
members of these classes of phenols, those which have been rated are rated as
"nonhazardous." Since the Phenosolvan solvent would be expected to extract
organics other than phenols which are present in the gas liquor, the by-product
crude phenol is expected to contain some of such organics. One such organic com-
pound which would most likely be present in the crude phenol is benzene which
is rated as "hazardous."
TABLE 3-13. PHENOL COMPOSITION BREAKDOWN FOR RAW LURGI GAS
(VALUES IN MG/1)
Phenol Class/Compound
Total phenols
Monohydric phenols
Phenol
Cresols
Xylenols
Catechols
Resorcinols
Tar Separator
3570
1843
1260
483
100
1379
348
Oil Separator
5100
4560
3100
1027
393
380
240
Ammonia is recovered as by-product in the treatment of gas liquor by steam
stripping. The ammonia recovered as the by-product in the Lurqi system may be
contaminated with other hazardous substances. No actual data are available on
the impurities present in the by-product ammonia.
103
-------
Elemental sulfur would be a by-product recovered in the treatment of con-
centrated acid gases for air pollution control. Although sulfur itself is rated
as nonhazardous, it may be contaminated with hazardous impurities. When the
Stretford process is employed, the by-product sulfur has been determined to
contain traces of vanadium and other solvent-derived salts. Vanadium is rated
as "hazardous" under the MEG rating system.
3.5 WASTE STREAMS TO AIR
Figure 3-1 shows the process modules in Lurgi systems for SNG production
which generates gaseous wastes. The 12 major types of gaseous wastes identified
are (1), crushing/screening off-gas (Stream 2), (2) lockhopper vent gas (Streams
6and8), (3) ash quench off-gas (Stream 78), (4) concentrated acid gases (Streams
21, 22 and 23), (6) catalyst decommissioning/regeneration off-gases (Stream 27),
(6) depressurization and stripping gases (Streams 81 and 69), (7) by-product
sotrage vent gases (Stream 101), (8) oxygen plant vent gas (Stream 66), (10)
transient waste gases (Stream 102), (11) flue gases from steam and power genera-
tion (Stream 64) and (12) fugitive emissions (not indicated in Figure 3-1).
Available data for these waste streams are presented and discussed in this sec-
tion. The pollution control processes for the management of the waste streams
are discussed in Chapter 4.
3.5.1 Coal Pretreatment and Handling
As discussed in Section 2.2, Lurgi gasifiers require only crushing and
screening to obtain a suitably sized coal feed. Uncontrolled fugitive dust
emissions associated with crushing, screening, conveying and storage/reclamation
are estimated at 0.038 to 0.045 kg/1000 kg coal processed^ '. Emissions data
from actual operations are not available at present. It might be noted that
potential emissions from coal preparation for Lurgi gasification are likely to
be lower than those from coal preparation for gasification processes which re-
quire pulverized coal.
3.5.2 Coal Gasification
Emission streams directly associated with the gasifier are the lockhopper
vent gases and gases generated during transient operation (startup and upset
conditions).
Feed Lockhopper Vent Gas. As discussed in Section 2.2.3, most of the pro-
posed designs for commercial Lurgi SNG facilities in the U.S. feature the use of
104
-------
/CRUSHING/'
[SCREENING|
OFFGAS
LOCK-
HOPPER
VENT
GASES
TRANSIENT
WASTE
GASES
'CATALYS
'REGENER-
(ATION/DECOH
Y-MISSIONING/
)FF-GASES/
VTALYS1
'REGENER-
\TION/DECOM|
-MISSIONING
VOFF-GASES
COAL
O
cn
J
,
2
COAL
PREPARATION
AMMONIA
RECOVERY
i
\
_- 8
6
COAL
FEEDING
PHENOL
RECOVERY
(PHENO-
SOLVAN)
1
r;ACi ci
r-^
102
CATION
— »»
GAS LIQUOR
SEPARATION
1 /B
COOLING
( SNG
^^
*27
SHIFT
CONVERSION
K
DRYING AND
COMPRESSION
i
ACID
'21,22,23
GAS
REMOVAL
-^ —
METHANATION
I27
TRACE SULFUR
ANDORGANICS
REMOVAL
••
69
EPRESSURI
ATION
FF-GASE
'27
EVAPORA-
TIVE
EMISSIONS
TALYS
REGENER-
ATION/
DECOMMISS-
ONING OFF
-CASE
LEGEND:
21,22,23 Combined Gases from Rectisol Unit 81
2 Fugitive Coal Dust 69
6 Coal Lockhopper Vent Gas 66
8 Ash Lockhopper Vent Gas 64
102 Transient Waste Gases 101
78 Ash Quench Off-gas 27
27 Catalyst Decommissioning Off-gas
Stripper off-gas
Depressurization Gas
Nitrogen
Utility Boiler Flue Gas
By-product Storage Vent Gases
Catalyst Decommissioning Off-gas
Figure 3-1. Process Modules Generating Gaseous Wastes in Lurgi SNG Systems
-------
product gas for feed lockhopper pressurization. About 3% to 4% of the product
gas is used for this purpose. Most of the gas used for pressurization is return-
ed to the product gas stream; only about 3% of the pressurization gas (about 0.1J
of the total product gas flow) is lost as the off-gas from the lockhopper. No
operating data are available on the composition of the lockhopper vent gas.
This gas, however, is expected to have a composition very similar to that of
the product gas used for pressurization. Table 3-14 presents one estimate for
the composition of the lockhopper vent gas.
TABLE 3-14. ESTIMATED COMPOSITION OF LURGI FEED LOCKHOPPER VENT GAS*(31)
Component
co2
Total sulfur
C2H4
CO
H2
CH4
C2H6
N2 + Ar
Naphtha
H20
Vol %
28
0.3
0.4
20
39
11
0.6
0.4
0.1
1.0
*Based on the following assumptions: New Mexico subbituminous coal with
0.7% sulfur; coal bulk density 1016 kg/Nm3 (60 Ib/scf); lockhopper filled
to 90% capacity; coal void volume 30%; and pressurization gas compressed
to 3.1 MPa (445 psia).
One commercial design (the WESCO design) features the use of C0? (from
the Rectisol process) for feed lockhopper pressurization. In this case the lock-
hopper vent gas would be significantly larger in volume (about 3% to 4% of the
product gas flow rate) and would consist of primarily CO,, with smaller amounts
of the constituents in the raw product gas.
Ash Lockhopper Vent Gas and Ash Quench Off-gas. Steam is utilized for
pressurization of ash lockhoppers to prevent air from entering the gasifier or
product gas from flowing out of the gasifier. As ash is transferred from the
lockhopper to the ash quench chamber, vent gases are emitted from the lockhopper
containing ash particles and components of the gasifier gas. The ash discharged
106
-------
from the lockhopper is quenched with water. The quenching of the ash results
in the emission of an off-gas which contains mostly steam and particulate matter.
If process water is used to quench the ash, the resulting off-gas would be ex-
pected to contain trace amounts of volatile substances originally present in the
wastewater. No data are available on the composition or the volumes of the ash
lockhopper vent gas and the ash quench off-gas. The domestic coals likely to
be used in Lurgi SNG plants have ash contents ranging from 5.6 to 25.6% (see
Table 3-1). Hence, the mass (and consequently the volumetric) flow rate through
the ash lockhopper would be much smaller than that through the feed lockhopper.
Accordingly, the size of the ash lockhopper and hence the volume of the ash
lockhopper vent gas would be significantly smaller than the size of the feed
lockhopper and the volume of the feed lockhopper vent gas, respectively.
Transient Waste Gases. Raw gas produced during startup and upset condi-
tions is not generally of a quality suitable for SNG production. These gases
are produced only intermittently and would generally be discharged to the atmo-
sphere through a flare. Data concerning the composition of the transient gases
are not currently available. The lower temperature conditions during startup
may result in an increased production of volatile organic compounds in the gasi-
fier. Some of these compounds may be condensed in the gas cooling step; those
not condensed will probably be destroyed in the flare. Actual destruction effi-
ciency of these compounds in a flare is not known.
3.5.3 Gas Purification
Concentrated acid gases produced in the Rectisol process are the only waste
gases associated with the gas purification operation. Table 3-15 presents re-
ported composition data for concentrated acid gases from several Rectisol systems
operated in selective (separate HLS and CCL removal) and non-selective (com-
bined H2S and C02 removal) modes, and one set of data used is the design for the
proposed El Paso Burnham coal gasification facility (third set of data in Table
3-15). The second set of data in Table 3-15 is for the non-selective Rectisol
process at the SASOL, South Africa coal gasification plant and represents acid
compositions expected from facilities handling low to medium sulfur coals. The
last set of data, which is for a selective Rectisol process handling a product
gas from an oil gasification facility, provides an indication of the degree of
selectivity which can be achieved by the application of the selective Rectisol
process.
107
-------
TABLE 3-15. CHARACTERISTICS OF ACID GASES PRODUCED BY THE RECTISOL PROCESS
Consti tuents/
Parameters
H2
CO
CH4
CO,
N, + Ar
L.
H2S
COS
V
MeOH
cs2
RSH
Thiophene
Temp: °K(°F)
Pressure:
MPa (psia)
Rate: ftn3/hr
(scf/min)
1
TypeA*<3::>
22
0.4
0.014
0.017
73.95
25.62*
--
--
--
--
--
--
--
--
0.1(15)
45,090
(27,956)
2
T «i(44)
Type A +
21 22 23
21.4 2.6 0.14
18.2 4.8 0.0
11.4 7.2 0.9
46.7 83.4 97.2
1.5 0.8 0.03
3176 ppm 4941 ppm 8824 ppm
0.003
0.7 1.1 0.7
--
0.0002
0.028
0.0002
273(32) 273(32) 268(23)
1.3(195) 0.46(70) 0.1(15)
4,50? 15,000 98,000
(2,852) (9,300) (60,760)
3
Type,;'31'
21 22 23
29.6 0.4
11.9 0.2
31.0 0.6
28.5 97.5 78.8
0.2
0.8 12.6
-
2.2 0.5
8.6
--
--
-
220(-50) 220(-50) 300(80)
0.7(103) .2(25) 0.1(15)
14,100 355,000 9,720
(8,780) (220,850) (6,050)
4
Type B*(32)
21 22 23
0.15 0.79
0.05 0.22
0.05
76.81 98.91 64.6
23. Of 0.05 0.1
2 ppm 2 ppm 35.2
0.1
.-
-
-
--
--
--
0.1(15) 0.24(36 0.24(36)
41,480 14,130 1,980
(25,845) (8,760) (1,230)
5
Type B<32>
21 22 23
0.76
0.11
0.06
09.85 -- 68.31
8.22* -- 1.92
5 ppm - 29.77
--
--
-
--
-
--
-
0.1(16) -- 0.2(28)
50,280 -- 2,390
(21,170) (1,480
6
Type B*<22>
21 22 23
0.33
0.14
0.00
80.19 -- 68.46
19.34*
<5 ppm -- 30.78
8 ppm -- 0.76
--
--
--
-
--
295(72) — 322(121)
0.1(15) - 0.5(73)
30.800 -- 673
(19,100) (417)
*Type A - simultaneous removal of C02 and MjS with simultaneous recovery of C02 and H2S
Type B - simultaneous removal of C02 and H2S with separate recovery of C02 and H2S
+ Includes \\2 stripper at 353,000 Nm3/hr (223,000 scf/min)
tData are for SASOL, So. Africa Lurgi plant
^Concentrations/parameters assumed in the design of the El Paso Lurgi SNG facility
*t)ata are for an oil gasification plant using the Texaco gasification process
-------
Very little data are available on trace constituents which may be present
in Rectisol acid gases. Based on the data in Table 3-15, COS tends to concen-
trate in the hLS-rich acid gas stream (Stream 23). Some trace constituents such
as HCN, naphtha hydrocarbons and mercaptans are originally present in the feed
gas to the Rectisol process^ °'. Methanol from the prewash column is regen-
erated in the azeotrope column where the hydrocarbons and HCN are separated.
The HCN is reabsorbed in water and recycled to the shift conversion process
where it reacts to form ammonia and CO. The bulk of the mercaptans remain with
the hydrocarbons (naphtha) which are subsequently recovered as a by-product.
3.5.4 Gas Upgrading
The only waste gas streams associated with the gas upgrading operation are
the off-gas from the regeneration/decommissioning of catalyst. Both shift and
methanation catalysts require periodic regeneration or replacement due to deacti-
vation by sulfur compounds and carbon deposition. In the case of shift catalyst,
the carbon residue would be burned off resulting in an off-gas containing sulfur
compounds, catalyst-derived particulate matter, COp and CO. The spent methana-
tion catalyst which contains reduced nickel is pyrophoric, thus requiring con-
trolled oxidation of the nickel before the spent material is removed from the
bed. Oxidation results in a sulfur rich off-gas containing catalyst particu-
lates, Ni(CO)4, and oxidation products such as CO, COp, etc. Because of the pro-
prietary nature of catalysts and their handling procedures, no data have been
published on the characteristics of such regeneration/decommissioning off-gases
and on regeneration procedures. The emissions associated with catalyst decom-
missioning and regeneration (or reclamation) are expected to be small in volume
and of infrequent nature.
3.5.5 Auxiliary Processes
Few gaseous waste streams from auxiliary processes can be considered uni-
que to Lurgi SNG systems (e.g., the off-gas from the depressurization of the
Lurgi gas liquor). Most of the other waste streams, however, are of the type
which are encountered in other industries. This section presents the available
data on waste gases from the auxiliary processes; where sufficient data are
unavailable, a qualitative discussion of some of the expected characteristics
of the waste streams is presented.
109
-------
Depressurizing and Stripping Off-Gases. Raw product gas from the gasifier
is quenched and cooled to remove condensible hydrocarbons and unreacted steam
prior to gas purification. Quenching produces a pressurized aqueous and organic
condensate stream. When this stream (Lurgi gas liquor) is subsequently depres-
surized for the separation and recovery of tars and oils for wastewater treat-
ment, an off-gas is generated which contains some of the volatile components and
gases originally contained in the liquid phase(s). The major components of such
off-gases are carbon dioxide, carbon monoxide, hydrogen sulfide, ammonia, hydro-
gen and low molecular weight organics (e.g., methane). Table 3-16 contains
data on the composition of depressurization gases associated with tar and oil
separation from Lurgi quench condensates. The data indicate that these off-
gases contain significant quantities of H2$ and NHg. No information is avail-
able on the minor constituents (e.g., COS and HCN) which may be present in these
off-gases.
In the treatment of Lurgi gas liquor for the recovery of hydrogen sulfide
and ammonia by distillation or gas stripping, an off-gas is generated which con-
tains these and other volatile and gaseous compounds (e.g., HCN, CO, C0?, CH»,
and COS). Depending upon the feed composition and the stripper design, rela-
tively concentrated H^S and NH3 streams can be obtained. Steam stripping can
generally result in the removal of greater than 99% of the HLS and 95% of the
ammonia in the sour water feed. No operating data are available on the actual
composition of the stripper off-gas in applications to gas liquor from the Lurgi
process. Designs for sour water stripping/ammonia recovery and the expected
stripper overhead compositions are discussed in Section 4.3.
By-product Storage Vent Gases. The Lurgi process generates naphtha and
tars and/or oils during gasification; these are recovered as by-products for
sale or used as fuel within the facility. Evaporative emissions may be asso-
ciated with storage of these by-products. These emissions are usually in the
form of vent gases from storage facilities and generally contain the same con-
stituents as are present in the stored material. The concentrations of these
constituents in the gas phase are a function of the concentrations in the liquid
phase, the volatility of substances and the temperature. Estimates of evapora-
tive emissions for the proposed El Paso Lurgi SNG facility are shown in Table
3-17. For comparison purposes, material production/use rates for these sub-
stances are also presented.
110
-------
TABLE 3-16. COMPOSITION OF LURGI TAR/OIL SEPARATOR DEPRESSURIZATION GAS
Coal Used
Reference
Constituent*
H S
NH3
coz
CO
H2
0? + Argon
CH4
Montana Rosebud
(7)
Tar Oil
Sep. Sep.
3.8 8.6
6.3 12.0
64.7 59.3
5.9 4.7
2.9 2.3
3.1 2.5
8.0 6.4
5.3 4.2
Illinois #6
(7)
Tar Oil
Sep. Sep.
5.7 5.5
1.0 1.8
84.9 85.5
1.5 0.8
3.5 3.6
0.4 0.6
1.2 1.0
1.8 1.2
Illinois #5
(7)
Tar Oi 1
Sep. Sep.
6.2 6.8
4.6 2.7
62.9 67.0
4.5 4.2
11.7 13.3
1.3 1.4
5.9 2.3
2.9 2.3
Pittsburgh #3
(7)
Tar 01 1
Sep. Sep.
4.4 5.5
2.9 3.5
71.3 73.9
4.7 3.8
12.0 0.6
0.3 0.2
1.0 0.8
3.4 2.7
New Mexico
Su bb i turn i nous
(31)
Combined
Flash Gases
0.3
--
32.1
11.6
43.7
I-!
10.7
*A11 data are vol
-------
TABLE 3-17. ESTIMATED BY-PRODUCT STORAGE EMISSION RATES FOR THE PROPOSED EL PASO
LURGI SNG PLANTul)
Product/
By-Product
Crude phenol
Tar oil
Naphtha
Ammon i a
Product gases
Methanol
Tar
Total
Production/Use
Rate
kg/hr (Ib/hr)
5,118 (11,260)
22,090 (48,600)
9,090 (20,000)
9,727 (21,400)
233,600 (514,000)
1,218 (2,680)
40,360 (88,800)
Emission Rates
kg/hr (Ib/hr)
01.68 (1.5)
1.18 (2.6)
0.95 (2.1)
0.68 (1.5)
1.45 (3.2)
0.73 (1.6)
--
Oxygen Plant Vent Gases. An on-site oxygen plant is needed to satisfy the
oxygen requirement. No chemical reactions are involved in the cryogenic air
separation process. The emissions stream from the oxygen plant is the separated
nitrogen (containing trace atmospheric gases) which is the main component of the
air feed to the plant. Approximately 0.2 kg of oxygen is required per kilogram
of coal used in the gasifiers. For a commercial sized plant (around 7 x 106
Nm3/d or 250 x 106 scf/d of SNG), this results in a nitrogen vent stream of
approximately 7 x 105 kg/hr (1.6 x 106 Ib/hr).
Steam and Power Production Flue Gases. A major gaseous waste stream in an
integrated Lurgi SNG facility is the flue gas resulting from combustion of fuels
to generate power and/or steam onsite. The composition and quantity of such
flue gases depend upon the fuel used, whether electricity is generated onsite and
on the manner in which the fuel is combusted (e.g., gas turbine vs. boiler).
Generally, three types of fuel may be used for onsite steam and power generation:
(1) coal, particularly fines generated by crushing/screening; (2) by-products
(tar, oil, phenols, naphtha); and (3) fuel gas produced by onsite low Btu gasifi-
cation. Product SNG would not ordinarily be an economical fuel alternative.
The use of all of the above three fuels has been proposed for one or more of
the proposed commercial Lurgi SNG facilities.
The proposed design for the El Paso coal gasification facility in New Mexico
incorporates the use of low Btu Lurgi gasifiers for fuel gas production. The raw
112
-------
product gas is cooled and des.ulfuri.zed in a high pressure Stretford unit prior
(2\
to utilization as fuelv '. The low Btu gas will be used in boilers for steam
production and in gas turbines to drive generators and oxygen plant compressors.
The gas turbines would exhaust to waste heat boilers which would produce steam
for motive power, process uses and process heating.
The proposed Wyoming Coal Gasification Project includes onsite steam and
(14)
power production facilitesv '. A combination of process waste heat boilers and
boilers fired with coal fines will be used for steam production. Electrical
power will be generated utilizing a series of steam-driven turbine generators.
The coal-fired boilers will operate on low sulfur medium ash coal and will be
equipped with hot side high efficiency electrostatic precipitators.
Electrical power for the WESCO Project will be supplied by a local electric
( " }
utility ° . High pressure steam will be generated onsite in boilers fired
with coal fines. Particulates will be removed with hot side electrostatic pre-
ci pi tators. An FGD system will be used to remove 90% of the SO^. Boilers are
designed to minimize NO emissions.
X
The proposed ANG Coal Gasification Project will purchase electrical power
from an off-site utility^ '. Plant steam requirements will be supplied from
two sources: boilers fired by liquid by-products and waste heat boilers.
When coal or gasification by-products are utilized, the uncontrolled emis-
sions will contain the bulk of the original fuel sulfur, NOX (derived from the
nitrogen in the fuel and in the combustion air), and, in the case of coal, a
high concentration of particulates. When fuel gas is produced onsite, sulfur
and nitrogen compounds and particulates are generally removed from combustion.
The flue gases from use of fuel gas, therefore, will generally be lower in total
sulfur, particulates, and NOX than flue gases from direct combustion of coal,
tars and oils. It should be noted that onsite fuel combustion is not a source
of emissions unique to Lurgi SNG production, but is common to many types of
industries. The use of fuels such as low Btu gas and coal-dervied tars and/
oils, however, would be unique to Lurgi facilities. At present no operating
data are available on the composition of controlled or uncontrolled flue gases
from the combustion of these "unconventional" fuels.
fugitive Emissions. A variety of sources may generate fugitive emissions
in an integrated SNG facility. These include compressors, pumps, valves,
113
-------
flanges, pressure relief valves, wastewater treatment plants and loading and
transportation equipment and vessels. The actual compositions of the fugitive
emissions vary widely, primarily depending on the specific emission source and
the nature of the product handled. The major components of concern in many of
these fugitive emissions are hydrocarbons and particulates. At present there
are no data available relating to the magnitude or characteristics of fugitive
emissions associated with Lurgi systems.
3.6 WASTE STREAMS TO WATER
Figure 3-2 shows the process modules in a Lurgi SNG system generating
aqueous wastes. The gasification waste streams identified are: (1) coal pile
runoff (Stream 100), (2) ash quench slurry (Stream 79), (3) raw gas liquor
(Stream 13), (4) Rectisol methanol/water still bottoms (Stream 18), and (5) ,me,th-
anation/dehydration condensate (Streams 29 and 31). Phenosolvan filter backwash
(Stream 76) and clean gas liquor (Stream 82) are aqueous wastes associated with
Lurgi processes for phenol/ammonia recovery (and wastewater treatment). Aqueous
wastes associated with non-pollution control auxiliary processes include: boiler
blowdown (Stream 86), cooling tower blowdown (Stream 95) and raw water treat-
ment brines and filter backwash wastes (Streams 41 and 49). The available data
on aqueous wastes from gasification, ammonia/phenol recovery and non-pollution
control processes are presented below. Aqueous wastes from pollution control
processes are discussed in Chapter 4.0.
3.6.1 Coal Pretreatment and Handling
The major aqueous waste stream associated with this operation is the rr •
off from coal piles. The volume and characteristics of the wastewater depend
on the type and size of coal stored, the design of the storage facility and
climatic conditions. In general, the coal pile runoff is expected to contain
coal fines and other suspended particulate matter, and dissolved inorganics
resulting from oxidation and solubilization of coal impurities. Although some
data are available on the characteristics of coal pile runoff from coal storage
facilities in other industries, because of the site- and coal-specific nature
of runoff, such data may not necessarily represent the characteristics of runoff
from coal piles at a Lurgi SNG plant. At present no data are available for the
anticipated coal pile runoff from proposed commercial Lurgi SNG plants.
114
-------
COAL
COAL
PREPARATION
COAL FEEDING
GASIFICATION
COOLING
SHIFT
CONVERSION
ACID GAS
REMOVAL
TRACE SULFUR
ANDORGANICS
REMOVAL
AMMONIA
RECOVERY
PHENOL
RECOVERY
(PHENOSOLVAN)
DRYING AND
COMPRESSION
METHANATION
82
76
29
ICONDENSATE]
Figure 3-2. Process Modules Generating Aqueous Wastes in an Integrated Lurgi SNG Facility (stream
numbers refer to Figures 2-2, 2-3 and 2-4; see Table 2-1 for index to streams)
-------
3.6.2 Coal Gasification
An ash quench slurry results when process waters are used to cool and
transport gasifier ash to a settling unit or disposal site. The nature of the
ash quench slurry depends upon the characteristics of both the hot gasifier ash
and the process water used for quenching. (The composition of typical Lurgi
ashes are presented in Table 3-25, Section 3.7.) No operating data are avail-
able for ash quench slurry characteristics. Data from laboratory experiments
simulating the ash quenching operation, however, are available and are presented
in Table 3-18. The data shown are for the composition of 10% Lurgi ash slurry
supernatants resulting from contacting an Illinois No. 6 coal ash with water
at various pH levels. The supernatants contain moderate levels of total dis-
solved solids (around 1000 mg/1) with the dominant ions being Ca++, S04", K+
and Na+. As indicated by the data in Table 3-18, elements other than Ca, Mg,
Na and K tend to be relatively insoluble under the natural alkaline conditions
of the ash supernatants (i.e., without the addition of acid or base); some in-
crease in solubility is observed with decreasing pH (e.g., Fe, Mn, Cd, Al).
About 1% by weight of the ash for the Illinois No. 6 coal is apparently readily
soluble in the supernantant. As indicated by the values for oil and grease and
COD, a small amount of organic residue may be associated with the Lurgi ash.
The use of an inert atmosphere instead of air apparently does not have a pro-
nounced effect on the solubility of the substances measured.
The ash slurry supernatants for the Illinois No. 6 coal have been tested
for toxicity to fathead minnows^06'. The results of these bioassay tests
indicate that the constituents in equilibrium with the ash at near neutral pH
leveTs are not acutely toxic to young fathead minnows. Supernatants obtained
under alkaline and acidic pH's, however, show high acute toxicity; neutralized
samples of the supernatants also show.high acute toxicity. Both pH and total
salt content were determined to be important factors affecting acute toxicity.
Lurgi ash from the experimental gasification of Mercer County, North
Dakota lignite at SASOL, South Africa has also been subjected to leaching
tests^ J'. Based on these tests and tests with laboratory ash from Dunn County
lignite samples, the Teachability of the Dunn County lignite ash produced by
the proposed ANG Lurgi facility has been estimated. Table 3-19 presents the
;olubility estimates in terms of the percentage of an element which would be
116
-------
TABLE 3-18. CHEMICAL COMPOSITION OF LURGI ASH SLURRY SUPERNATANT
(36)'
Exposure atmosphere
PH
Parameter/Consti tuent
Conductivity (umhos/cm)
COD (mg/1)
Oil & grease (mg/1 )
cr
Ca++ (mg/1)
MQ++ (mg/1)
NH^ (mg/1 )
S04"
K+
Na +
B
Cu
F~
Fe (total )
Si
Li +
Kn++
Cd
Ni
Pb
Sb
Sr
Zn
Al
As
Be
Cr
Co
Mg
Mo
Al
Te
S=
Air
7.55
1170
2
28
NDf
290
10.5
17
820
42
34
4.0
0.01
0.31
0.06
5
1.8
0.45
0.02
0.03
0.1
0.2
1 .8
0.12
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
5.10
1500
2
28
ND
480
14
8
943
49
37
4
0
0
0
29
1
1
0
0
0
0
1
5
2
ND
ND
0
0
ND
ND
ND
ND
ND
3.82
1950
2
0
ND
400
15
12
808
51
38
.5 4
.02 0
.30 0
.19 0
60
.9 2
.94 2
.03 0
.13 0
.1 0
.3 0
.9 2
.5 12
14
ND
0
.02 0
.05 0
ND
ND
ND
ND
ND
2.68
5600
81
23
ND
570
22
11
38
26
40
.5 5.5
.13 0.73
.09 0.04
.24 560
130
.0 2.0
.7 3.8
.03 0.06
.23 0.50
.1 0.2
.3 0.6
.1 2.9
17
132
ND
.01 0.03
.05 0.12
.08 0.19
ND
ND
ND
ND
ND
Argon
8.2
1200
2
10
ND
440
9
10
730
39
32
4
0
0
0
4
1
0
0
ND
ND
0
1
0
ND
ND
ND
0
ND
ND
ND
ND
ND
ND
7.20
1390
2
3
ND
37C
.5 11
10
735
43
37
.5 3
.01 0
.51 0
.06 0
9
.6 1
.11 0
.01 ND
0
ND
.3 0
.5 1
.01 0
ND
ND
ND
.01 0
ND
ND
ND
ND
ND
ND
5.35
1800
16
6
ND
430
13
10
700
48
37
.0 4
.05 0
.34 0
.11 101
27
.8 1
.90 2
0
.04 0
0
.3 0
.7 1
.4 6
ND
ND
ND
.01 0
ND
ND
ND
ND
ND
ND
3.79
5200
140
4
ND
500
.5 23
17
710
61
40
.5 8.0
,01 0.05
.16 0.02
880
120
.9 2.1
.3 3.7
.02 0.05
.14 0.42
.1 0.2
.3 0.5
.9 2.6
.3 20
92
ND
0.01
.06 0.16
0.17
ND
ND
ND
ND
ND
*Slurry containing 10% ash from Illinois No. 6 coal, except for pH values of 7.55
and 8.2 which are the "natural" pH of the supernatant, the supernatant pH adjusted
to indicated levels.
ffiD not detectable
117
-------
TABLE 3-19. ESTIMATED SOLUBILITY OF ELEMENTS IN LURGI ASH FROM GASIFICATION OF
DUNN COUNTY, NORTH DAKOTA LIGNITEU3)
Element
Al
As
B
Ba
Br
Ca
Co
Cr
Cs
Cu
F
Ga
Ge
Fe
Hg
K
Li
Mn
Mo
Ni
Ma
P
Pb
Rb
S
Sc
Se
Sr
Ti
W
V
In
Percent of Element
Leachable*
0.32
0.74
15.9
<0.09
13
0.49
1.6
4.4
42
7
4.5
5.4
<1.3
<0.4
4.4
21
11
<0.25
92
1.4
37.1
<0.5
0.31
59
84
<0.66
<34
0.71
<2.3
24
5.2
37
Quantity of Element
Solubilized,*
kg/tonne (Ibs/ton) of Ash
0.15 (0.29)
0.0005 (0.001)
0.0015 (0.003)
<0.0001 (<0.003)
0.0015 (0.003)
0.53 (1.06)
0.0005 (0.001)
0.02 (0.04)
0.005 (0.001)
0.01 (0.02
0.005 (0.01)
0.0015 (0.003)
<0.0005 (<0.001)
<0.2 (<0.4)
<0.0005 (<0.001)
0.7 (1.3)
0.001 (0.002)
<0.005 (<0.01)
0.11 (0.23 )
0.001 (0.002)
5.9 (11.7)
<0.005 (<0.01)
<0.0005 (<0.001)
0.015 (0.03)
8.7 (17.3)
<0.0005 (<0.001)
<0.0005 (<0.001)
<0.05 (0.1)
<0.05 (<0.1)
<0.001 (<0.002)
<0.001 (0.002)
0.002 (0.004)
Estimated Maximum
Concentration of Elements
in Ash Slurry Supernatant"!"
(mg/D
87
0.3
41
0.8
0.9
321
0.3
11
0.4
6
2.6.
1
0.03
<100
<0.0001
395
0.6
<3
71
6
3500
<3
0.06
10
5231
<0.2
<0.17
30
<25
<0.6
4.7
1.2
*Estimated for Dunn County lignite ash based on data for Mercer County lignite gasified
in Lurgi gasifier at SASOL, South Africa.
Assuming that ash slurry contains 0.6 kg ash/kg water.
118
-------
Teachable, the quantity which would be leached out (kg/tonne of ash) and the
maximum concentration (mg/1) of the element in the ash supernatant. The major
water soluble elements are Na, K, and S (as S0.=). For these elements, the
total quantity solubilized amounts to about 1% by weight of the ash (a value
close to that obtained in leaching tests using ash from Illinois No. 6 coal).
Several other elements, although present in the ash at much lower levels than
Na, K, and S, also show considerable solubility in water. These elements in-
clude B, Br, Cs, Li, Mo, Se, Rb, W and Zn. The maximum concentration values
listed in the last column in Table 3-19 are calculated values for the proposed
AI1G gasification facility, assuming that all water Teachable components of the
ash were released to the water used for ash transport. Such a total release
of the Teachable components can result in a relatively high concentration of
total dissolved solids (about 20,000 mg/1). In addition, the concentration
of certain hazardous elements (e.g., As, Ni, Cr and Cu) would reach levels which
would warrant concern for discharge of ash slurry water to receiving waters.
Process waters used in a commercial Lurgi facility to quench ash may contain
organic substances such as phenols, fatty acids and polycyclic aromatics, and
inorganic ions such as SCN~, CN~ and S=. The alkaline ash may adsorb or effect
precipitation of some of these substances. Substances such as CN~ and phenols
in quench water may also enhance the solubility of certain metals contained in
the ash via complex formation. At present there are insufficient data to accu-
rately define the characteristics of quench waters which would be generated in
a commercial Lurgi facility.
3.6.3 Gas Purification
Lurgi Gas Liquor. Raw gas liquor collected from primary and secondary cool-
ing units is processed for tar and oil recovery. Available data for the gas
liquor stream relate to the aqueous phase after tar and oil separation. TabTes
3-20 and 3-21 present data for separated gas liquor. Data on the separated
tars and oils were presented in Tables 3-11 and 3-12. As shown in Table 3-20,
from 1 to 2.6 kg of separated gas liquor are generated per kg of coal depending
on the coal moisture and amount of steam used for gasification. The separated
gas liquors contain large amounts of dissolved and suspended organics as
reflected by the high BOD, COD and suspended tar and oil values. The inorganic
component of gas liquor consists primarily of ammonia and bicarbonate with
smaller amounts of sulfide, thiocyanate and cyanide.
119
-------
TABLE 3-20. MAJOR CONSTITUENTS AND GROSS PARAMETERS FOR SEPARATED LURGI GAS LIQUORS*
o
Coal No.'1' (Reference)
Production Rate k<;/kq
Suspended Tar & Oil
Analysis on
tar free
ba s i s
PH
T.D.S.
T.D.S. after ignition
Sulfide
Total S
Fatty acids
Amn.onia
Free: ppm
Fixed; ppm
Carbonate
Total phenols
MonohydHc phenols
Cyanide
Thiocyanate
Cl
BOD
COD
TOC
1 (7)
0.93
350 650
Inlet Inlet
tar oil
sep. sep.
9.6 8.3
4030 1765
45 35
130 115
150 265
1250 1670
3990 14015
395 525
4070 19460
4200 4406
--
2 4
6 15
45 40
9900 13400
22700 20800
2(7)
2.11
1130 2150
Inlet Inlet
tar oil
sep. se|_.
9.8 8.5
2770 1570
110 35
25 440
180 730
490 280
1700 1765C
28C 210
1280 6500
2200 1900
._
3 11
65 160
135 75
3800 4700
10100 12000
— .
3(7)
1.77
2150 2200
Inlet Inlet
tar oil
sep. sep.
9.5 8.3
3180 1120
85 25
15 490
160 930
400 260
1520 13970
410 330
680 9210
2900 375G
--
7 14
79 158
290 170
6000 6200
9300 10600
--
4(7)
2.60
300 1100
Inlet Inlet
tar tar
sep. sep.
9.3 8.2
1550 1240
105 120
65 520
155 720
275 610
1600 14000
320 250
1360 10740
1400 2150
..
1 12
70 185
240 210
4100 5400
650 7500
5 (44)
1.06
5000
--
--
--
--
3U
10,600
150-200
8500
3250-4000
--
6
--
--
--
--
--
5 (56)
8.9
2460
--
<0.5
—
--
11,200
—
—
2410
—
85
—
—
12,500
4190
*A11 units are mg/1 except pH and production rate
numbers refer to those in Table 3-1
-------
Table 3-21 summarizes available data on the trace element composition of
the separated Lurgi gas liquors. Some elements (e.g., As, B, Cd, F, Hg and V)
are found at levels which could require removal before discharge. The fractions
of various elements which exist in soluble and suspended form are not known at
present.
Limited data are available for organics contained in Lurgi gas liquors.
The data include those presented in Table 3-13 relating to the phenolics com-
position in the gas liquor. Table 3-22 presents the levels of three classes of
organics in one sample of Lurgi gas liquor from SASOL, South Africa. (The data
on the characteristics of clean gas liquor are also presented in this table;
these data will be discussed in connection with clean gas liquor.) Monohydric
phenols are seen to comprise a significant fraction of the measured organics,
with fatty acids and aromatic amines comprising about equal but much smaller
fractions. In the table, the theoretical COD and TOC values have been calculated
to estimate the percentage of total organics accounted for by monohydric phenols,
fatty acids, and aromatic amines. Based upon the measured COD and TOC values of
12,500 and 4190 mg/1, respectively, for this wastewater sample, about 50% of
the total COD and TOC are represented by the compounds listed in the table.
Of the remaining 50% of organics approximately half would likely be represented
by the polyhydric class of phenols (see Tables 3-13 and 3-20 for the relative
concentrations of the monohydric and polyhydric classes of phenols). The poly-
cyclic aromatic hydrocarbons and heterocyclics, aromatic acids and aldehydes
probably comprise the bulk of the remaining organics.
Rectisol Methanol/Hater Still Bottoms. Recovery of naphtha and methanol
from condensates in the Rectisol process is accomplished by azeotropic distilla-
tion. Tables 3-23 presents available data on the characteristics of this stream
from the Lurgi facility at SASOL, South Africa. The still bottoms contain
mostly water with small amounts of less volatile organics and methanol. Inor-
ganics such as sulfide, thiocyanate, and ammonia are also present in small con-
centrations. The specific flow rate and composition of this stream in an SNG
facility will depend largely upon the Rectisol design employed. For example, in
the design for the El Paso Burnham Lurgi facility, the flow rate for this stream
I o-i \
is about one-third that for the SASOL facilityv '. Because of its relatively
small volume in a commercial facility the still bottoms would likely be combined
with other waste streams (e.g., clean gas liquor) for treatment.
121
-------
TABLE 3-21. MINOR AND TRACE ELEMENT COMPOSITION OF SEPARATED LURGI GAS LIQUORS
Coal Number* (Reference)
Coal Type/Origin
Liquor Production Rate (kg/kg)
dry basis
Element (mg/1.)
Al
Ca
Fe
K
Na
Si
Ti
Mg
Ag
As
B
Ba
Be
Br
Cd
Ce
Co
Cr
Cu
F
Hg
Li
Mo
Mn
Ni
P
Pb
Rb
Sb
Sc
Se
Sn
Sr
U
V
Y
Zn
Zr
1 (14)
Subbituminous
Rosebud Montana
0.93
—
--
—
--
--
--
--
--
0.017
0.014
5.3
0.001
0.22
--
0.1
--
0.001
1.3
1
19
0.056
0.9
0.01
0.01
0.5
--
0.12
--
0.002
--
0.05
0.45
--
0.15
2.5
--
0.06
--
6 (13)
Lignite
N. Dakota
1.53
2.9
14.6
0.2
0.8
82.5
117
0.02
0.6
--
0.1
0.9
0.005
--
0.001
0.2
0.006
0.001
0.02
0.02
5
0.17
0.002
0.04
0.03
0;006
6
0.005
0.003
--
0.006
0.004
--
0.004
--
0.001
0.004
0.2
0.008
9 (15)
Lignite
N. Dakota
1.53
—
--
--
--
—
—
--
—
0.2
3
3
--
0.008
--
0.03
--
0.03
0.03
0.3
0.5
0.003
0.02
0.2
__
0.2
__
0.2
0.03
2
0.03
0.2
0.003
0.4
*Coal numbers refer to those in Table 3-1.
122
-------
TABLE 3-22. CONCENTRATION OF ORGANIC COMPOUNDS AND THEIR EQUIVALENT COD AND TOC VALUES FOR THE SEPARATED
AND CLEAN LURGI GAS LIQUOR AT SASOL, SOUTH AFRICANS)
ro
CO
Compound
Fatty Acids
Acetic Acid
Propanoic Acid
Butanoic Acid
2-Methylpropanoic Acid
Pentanoic Acid
3-Methylbutanoic Acid
Hexanoic Acid
Monohydric Phenols
Phenol
2-Me thy! phenol
3- Me thy! phenol
4-Methyl phone!
2, 4- Dimethyl phenol
3, 5-Dimethyl phenol
Aromatic Amines
Pyridine
2-Methylpyridine
3-Methylpyridine
4- Methyl pridine
2, 4-Di methyl pyri dine
2, 5- Dimethyl pyri dine
2, 6-Dimethylpyridine
Aniline
Total
Separated Gas
mg/1
171
26
13
2
12
1
1
226
1,250
340
360
290
120
<50
2,410
117
70
26
6
<1
<1
<1
12
231
2,867
COD
183
39.3
23.7
3.8
24.5
2.1
2.2
278.6
2,975
857
907
731
314
<131
5,915
261
169
62.7
14.5
<2.5
<2.5
<2.5
28.9
544
6,738
Liquor
TOC
68.4
12.7
7.8
1.1
7.1
0.6
0.6
98.3
963
265
277
226
95
<39.5
1866
88.9
53.9
20.0
4.6
<0.8
<0.8
<0.8
9.2
179
2,143
Cleaned Gas
mg/1
123
30
16
5
7
5
8
194
3.2
<0.2
<0.2
<0.2
NF
NF
3.2
0.45
<0.05
<0.05
<0.05
NF*
NF
NF
NF
0.45
198
COD
131.6
45.3
29.1
9.5
14.3
10.5
17.7
258
7.6
<0.5
<0.5
<0.5
--
--
9.1
1.0
<0.12
<0.12
<0.12
--
--
--
--
1.4
269
Liquor
TOC
49.2
14.7
9.6
2.7
4.1
2.9
5.0
88.2
2.5
<0.2
<0.2
<0.2
--
—
3. 1
0.34
<0.04
<0.04
<0.04
--
--
--
--
0.5
92
*NF = not found
-------
TABLE 3-23 CHARACTERISTICS OF RECTISOL METHANOL/WATER STILL BOTTOMS FOR LURGI
FACILITY AT SASOL, SOUTH AFRICA(44)
Stream Flow Rate 42 (0.31)
liters/103 Mm3 of feed gas
(gal/1000 scf)
pH 9-7
Phenol (mg/1) 18
CN- and SCN~ (mg/1) 10.4
NH3 (mg/1) 42
S= (mg/1) Trace
COD (mg/1) 1606
Conductivity (umhs/cm) 1111
3.6.4 Gas Upgrading
Condensates produced during methanation and drying are the only aqueous
wastes associated with gas upgrading. These wastes are expected to be very low
in dissolved and suspended solids. Dissolved gases such as methane, CO, and
C02 will be present but thec-e gases would ordinarily be flashed from the con-
densate and added to product SNG. Dehydration condensate may contain traces
of glycol depending on the design of the system. No data are currently avail-
able to indicate the characteristics of this stream(s) from a commercial opera-
tion.
3.6.5 Auxiliary Processes
Phenosolvan Filter Backwash. No data are currently available for this
stream. This stream, however, is expected to contain tarry/oily substances
and coal/ash fines which are removed from the separated gas liquor.
Clean Gas Liquor. In the designs for all proposed Lurgi SNG facilities
the Phenosolvan process is used for the removal/recovery of phenols from sep-
arated gas liquor. Ammonia and H^S are subsequently removed from the dephenol-
ized gas liquor by steam stripping. The ammonia in the stripper overhead is re-
covered by one of several licensed processes. One such process, the Chemie
Linz AG/Lurgi process, is licensed by Lurgi.
Table 3-24 presents typical data on the characteristics of the separated
and clean gas liquor for a system employing the Phenosolvan process (using
124
-------
TABLE 3-24. PROPERTIES OF SEPARATED AND CLEAN GAS LIQUOR AT THE SASOL
PHENOSOLVAN PLANT*
Parameter/Consti tuent
Separated Gas Liquor
Reference 43
Clean Gas Liquor^
Reference 43
Reference 55
Total Phenols
Steam Volatile Phenols
COD
Fatty Acids (as CH^OOH)
Total Suspended Solids
Total Dissolved Solids
Suspended Tar and Oil
Total Ammonia
Total Sulfide
Cyanide
Thi ocyanate
Fluori de
Chloride
Sodi urn
Calcium
Iron
Ortho Phosphate
Conductivity (ymhos/cm)
Total Organic Carbon
PH
3250 - 4000
300
5000
10800
228
6
85
53
160
1
1126
560
21
875
21
215*
12*
1
56
25
18
1
2.5
1000 - 1800
8.4
1330
596
150
<0.5
80
0.2
8.2
*Except for pH and conductivity, all units are in mg/1
Dephenolized gas liquor is steam stripped to remove H2S and ammonia. The
stripping process is not usually considered part of the basic Phenosolvan
process.
125
-------
butyl acetate as the extraction solvent) followed by steam stripping for ammonia
and H2S removal. As indicated by the data about 90% removal of COD, 96% re-
moval of total phenols, 95 to 98% removal of ammonia and 95% removal of H2$ is
achieved by the combined extraction/stripping processes. Although steam strip-
ping is expected to remove the Phenosolvan solvent from the aqueous phase, a
few ppm of solvent will be present in the clean gas liquor. Proposed commercial
facilities in the U.S. are to use isopropyl ether rather than butyl acetate as
the extraction solvent. One design expects 99.5% removal of monohydric phenols,
(31)
60% removal of polyhydric phenols, and 15% removal of other organicsv '.
Actual operating data for the Phenosolvan process using isopropyl ether and for
the Chemie Linz AG/Lurgi ammonia recovery process are currently unavailable.
Data for other stripping/ammonia recovery processes are discussed in Section 4.3.
Boiler Slowdown. Boiler feedwater is generally demineralized to minimize
scale formation in boiler tubes. Slowdown is necessary to maintain a certain
desired dissolved solids level, which is dictated by the pressure of steam gen-
erated. Boiler blowdown will contain dissolved solids and small amounts of
phosphate and amines used to inhibit deposit formation and corrosion. No actual
data are available for boiler blowdown associated with Lurgi systems, but the
quantities and composition of this stream are expected to be similar to those
encountered in other boiler applications.
Cooling Tower Blowdown. Cooling tower blowdown will contain high levels
of total dissolved solids (IDS), treating chemicals and components of treated
plant wastewaters if such waters are used as makeup. IDS levels of less than
10,000 are usually required to inhibit precipitation of salts in the tower.
Additives to cooling water will accumulate and appear in the blowdown. One
estimate of the concentration of such additives in cooling tower feedwater
associated with a Lurgi facility indicates 300 to 500 ppm chromates, 20 to 50 ppn
total phosphate and 300 to 400 ppm chlorinated phenols' '. The concentration
of these substances in the blowdown may be several times those in the feedwater.
Sulfuric acid is commonly added to cooling water to inhibit calcium scale for-
mation and will result in high sulfate levels in the blowdown.
If treated plant waters are used as .cooling tower makeup, the blowdown will
contain some of the constituents of these waters. In the El Paso Burnham de-
sign, the clean gas liquor is to be used as the cooling tower makeup; such make-
up water is expected to contain approximately 760 ppm total phenol, 2700 ppm
126
-------
fatty acids and 200 ppm ammonia. Some degradation of organics and volatiliza-
tion of ammonia and H?S are expected in the cooling tower, although little oper-
ating data are currently available to indicate the extent of degradation/
volatilization.
Raw Water Treatment Filter Backwash and Brines. Filter backwash from
rapid sand filters used in raw water treatment generally contains soil-derived
sediment. The water is clarified by settling and the solids disposed of in a
landfill. The solids and clarified water are usually considered as relatively
innocuous materials. Brines generated by water softening and demineralization
contain high concentrations of salts, primary chlorides and sulfates of sodium
and calcium and to a lesser extent, potassium and magnesium.
Although no data are available for these wastes in SNG facilities, their
characteristics are not expected to be different from those of analogous wastes
in other industries (e.g., steam-electric power production) and are not unique
to SNG production.
Misceallenous Plant Wastewater. Included in this category of wastewaters
are plant and coal pile runoff, and sanitary wastewater. Runoff from the plant
site and adjacent storage areas can contain high levels of suspended solids
and organics. The characteristics of such waters would be highly variable,
depending on stream frequency and duration, and the nature and quantities of
materials and surfaces which the water contacts. No data are currently avail-
able on this type of stream associated with a Lurgi facility.
Sanitary wastewater would be generated at any industrial facility and
would require treatment by conventional techniques.
3.7 SOLID WASTES
Process modules generating solid wastes in Lurgi systems are depicted in
Figure 3-3. Identified are eight types of wastes: (1) coal preparation wastes
(Streams 2, 3 and 4), (2) gasifier and boiler ash (Streams 12 and 63), (3)
spent catalysts (Streams 25 and 30), (4) methanation guards (Stream 48), (5)
by-product storage sludges and solids (Stream 96), (6) spent filter media from
the Phenosolvan process (Stream 55), and (7) solids and sludges from raw water
(Streams 39, 49 and 53). The available data on the characteristics of these
wastes are presented below. Streams generated by pollution control processes
are reviewed in Section 4.4.
127
-------
co
COAL
/COAL \
1 REFUSE I
2,3,4
COAL
PREPARATION
AMMONIA
RECOVERY
©
|12
COAL
FEEDING
PHENOL
RECOVERY
(PHENOSOLVAN)
GASIFICATION
GAS LIQUOR
SEPARATION
COOLING
@.
•*
/ SPENT \
(CATALYST)
'25
SHIFT
CONVERSION
DRYING AND
COMPRESSION
ACID
GAS
REMOVAL
METHANATION
f SPENT \
METHANATIOSJ
\ GUARD J
48
TRACE SULFUR
ANDORGANICS
REMOVAL
55
30
x 39, 49,
'SOLIDS\ 53
AND
SLUDGES
Figure 3-3. Process Modules Generating Solid Wastes in Lurgi SNG Systems
-------
3.7.1 Pretreatment and Handling
Coal fines,refuse and collected fugitive dusts are the solid wastes asso-
ciated with the coal preparation operation. Coal fines resulting from screen-
ing of crushed feed may either be used directly as boiler fuel or be cleaned
for sale. In the latter case, a refuse is generated which contains mostly
inerts and some coal. The use of fabric filters for dust collection in crushing/
screening operations will also generate a solid waste containing coal fines and
inerts. The average particle size of this waste will be smaller than that
generated by coal cleaning. Although no characterization data are available
for these wastes, they are expected to be similar to the gross composition of
run-of-mine coal shown in Table 3-1.
3.7.2 Coal Gasification
Characterization data available for ashes from the Lurgi gasification are
shown in Table 3-25 for several coals. These analyses represent ash before
quenching with water for cooling and transport and therefore do not reflect loss
of solubilized material to wastewater. (The solubility of the ash components
of Illinois and No. Dakota coals were discussed in Section 3.6.2). Generally,
Lurgi ash contains the bulk of the inorganic component of the feed coal and
about 2 to 8% residual carbon. Some of the original coal sulfur is also
retained with the ash. Volatile trace elements such as Hg, Se, Te and As
may be partially lost during gasification.
3.7.3 Gas Purification
Zinc oxide used as methanation guard will require periodic replacement.
Spent guard material will consist primarily of zinc sulfide and unreacted zinc
oxide. No operating data are available on the quantity and composition of the
spent methanation guard at present.
3.7.4 Gas Upgrading
Catalysts used for shift and methanation require periodic replacement;
the spent catalysts constitute a solid waste. Gross composition of spent
catalyst is not expected to be dramatically different than that of fresh cata-
lyst, although accumulation of carbon, sulfur, and metallic elements is to be
expected. No data are available on the characteristics of spent catalysts from
Lurgi SNG systems. Data on spent methanation catalyst from pilot scale SNG
129
-------
TABLE 3-25.
ELEMENTAL COMPOSITION OF ASH PRODUCED BY GASIFICATION OF VARIOUS
COALS IN LURGI GASIFIERS
Coal Number*
Coal Type/Origin
Source of Data
Production Rate, kg/kg
(dry basis)
Major Elements (%)
A12°3
CaO
Fe2°3
K20
MgO
Na20
Si02
Ti02
S03
C
N
Cl
Trace Elements (ppm)
Ag
As
B
Ba
Be
Br
Cd
Ce
Co
Cr
Cs
Cu
F
Ga
Ge
Hg
Li
Ho
Mn
Ni
P
Pb
Rb
Sb
Sc
Se
Sh
Sr
Te
U
V
W
Y
Zn
Zr
1
Subbituminous
Montana/Rosebud
(7,14)
0.12
17.7
8.3
11.2
-
3.9
—
46.8
—
1.7
6 . 5 ;?,-
—
150
-.23
26
380
1900
2.8
—
2.4
-
4.3
440
—
130
600
—
--
.03
85
200
790
200
--
40
--
6.2
—
2.2
3.7
—
13
91
--
32
"
2
Bituminous
Illinois »6
(7,42)
0.10
20.5
2.1
17.2
—
1.0
—
49.6
--
1.3-1.5
3.2-5.4
0.05
--
--
0.1
622
-
14
--
<0.3
—
0.4
750
--
239
5
—
—
.04
-
6
200
456
--
96
--
0.2
—
~~
~~
--
--
--
301
--
--
469
2
Bituminous
Illinois #6
(36)
__
20.5
2.3
20.5
1.8
0.6
0.3
49.3
1.0
1.5
—
—
0.01
<0.4
3
355
950
12
<1
<1.6
140
34
212
11
57
<10
26
7
.05
42
30
1859
89
87
45
162
4.2
29
,1
< 1
~~
370
--
17
184
1.5
""
400
170
3
Bituminous
Illinois *5
(7,14)
.092
18.1
3.9
19.7
--
0.7
--
46.1
—
0.6-1.2
2.0-3.8
0.04
-
--
0.3
673
--
20
—
0.3
--
0.4
592
--
273
5
--
--
.016
—
8
305
452
--
200
--
19
--
--
--
--
--
—
181
—
--
--
1600
4
Bituminous
Pittsburgh *8
(7)
.081
20.7
3.0
15.0
--
0.7
—
43.6
--
0.8
7.6
--
-
--
—
--
--
—
--
--
--
--
—
__
—
—
—
__
__
—
—
_-
__
__
__
--
--
__
--
__
—
--
5
Bituminous
So. African
(34)
0.31
28
7
5
--
1.7
--
52
—
0.2
--
--
.01
--
1-2
100-150
--
<.05
>.l
<0.1
200-400
—
__
__
150
__
__
__
__
__
2000
150-200
..
50
..
<0.5
..
--
--
..
__
1000
--
..
-
6
Lignite
N. Dakota
(15)
0.1
—
--
-
--
—
—
-
—
--
--
--
-
0.7
60
<1500
12000
5
<1
10
40
__
50
230
_,
„
O
60
4
..
25
..
200
„
1
1.5
12
__
6
70
__
0.5
6
Lignite
N. Dakota
(13)
0.1
24
26
11
0.6
7
8
25
0.6
3.1
--
—
.007
1
74
1680
8270
6
3
0.5
190
13
140
.9
27
191
53
2
.055
45
12
760
25
3500
5B
35
33
4
0.5
4
12,900
0.3
7
150
2
320
10
520
-~
130
-------
production at the Hygas pilot plant in Chicago are presented in Table 3-26.
TABLE 3-26.' ANALYSIS OF SPENT METHANATION CATALYST FOR THE PILOT
Parameter/Consti tuent
Sulfur, %
Carbon, %
Nickel , %
Surface Area,
m2/g
Total Pore Volume,
cc/g
Ni Crystallite
Size, A
First
Bottom
3.7
3.4
52
36
0.16
491
Stage
Top
0.95
4.7
61
69
0.27
97
Second
Bottom
0.13
5.3
60
75
0.27
89
Stage
Top
0.16
4.5
61
79
0.27
99
Typical Fresh
Catalyst
0.15
3.4
60
150
0.25
65
*Catalyst type: Harshaw Ni-0104-T-l/4
3.7.5 Auxiliary Processes
Spent Filter Media from the Phenosolvan Process. In the Phenosolvan pro-
cess, filtration is used to remove suspended materials from the process feed
(the separated gas liquor). At the SASOL, South Africa plant the filtration
is carried out through a bed of sand. Although no data are available to indi-
cate a periodic need for the replacement of the bed material, it is very likely
that such replacement would be necessary in a commercial facility due to accu-
mulation of tarry material in the feed which would irreversibly plug the filter
pores. The characteristics of the spent bed including the required replacement
frequency are not known.
Solids and Sludges from By-Product Storage. Storage of Lurgi by-product
liquids (tars, oils, phenols and naphtha) may result in the generation of
bottom sludges. The nature or quantity of each sludge would depend upon the
material stored, its purity, length of storage and storage temperature. No
actual data are available on such solids and sludges from Lurgi systems.
Solids and Sludges from Raw Hater Treatment. Sludges containing lime,
alum, and sediment would be generated as a result of raw water treatment in
most Lurgi SNG facilities. The quantities and characteristics of such sludges
would depend upon the nature of the raw water treated and would not be unique
131
-------
to coal gasification. No operating data are currently available for this
stream in a Lurgi SNG plant.
Ash from On-Site Steam and Power Generation. When coal is burned, directly
or gasified in air blown gasifiers to produce fuel gas for on-site steam and
power generation, ash will be produced as a waste product. In either case, the
ash(es) will have overall compositions similar to those shown in Table 3-25 for
the Lurgi ash. Combustion ash would be expected to have essentially no residual
carbon, to be more alkaline, and be more depleted in volatile trace elements
when compared to gasification ash.
132
-------
4.0 PERFORMANCE AND COST OF CONTROL ALTERNATIVES
Many of the pollution control technologies which would be applicable to
waste streams identified in Chapters 2 and 3 represent adaptations of the tech-
nologies which are currently used or are under development for use in such re-
lated industries as petroleum refining, coal cleaning, by-product coke, and
electrical utilities. This chapter provides (1) a review of the control methods
which may be adapted from other industries and from general pollution control
practice, (2) a definition of limitations of and necessary modifications to
these control methods for use in coal gasification plants, (3) a discussion of
those controls which have actually been demonstrated in coal gasification plants,
and (4) an identification of control technologies which are under development
for these and similar applications. Control alternatives evaluated include
material and process changes in addition to "add on" controls.
4.1 PROCEDURES FOR EVALUATING CONTROL ALTERNATIVES
The various control technologies applicable to the management of each of
the waste streams identified in Chapters 2 and 3 were evaluated. Based on these
evaluations, a limited number of pollution control options for use in integrated
plants were selected and examined from the standpoint of total plant emissions,
costs and energy requirements. The flow diagrams and engineering assumptions/
calculations which provide the basis for arriving at these estimates are pre-
sented in Appendices B and C.
The evaluation of the control technologies for application to individual
waste streams was based on considerations of control efficiency, ability to
comply with emissions regulations, energy and resource consumption, reliability,
simplicity, multi-pollutant abatement capability, residue generation and dis-
posal requirements, potential for recovery of by-products, capital and operating
costs and stage of development. The above criteria were used as a basis for
comparison of candidate control technologies, used alone or in combination with
in-plant control methods or other add-on controls, and identification of tradeoffs
133
-------
in control technologies for minimizing total plant waste emissions and energy
requirements.
4.2 AIR EMISSIONS CONTROL ALTERNATIVES
Since no commercial Lurgi SNG facilities currently exist in the United
States, no operating data are available on many of the processes which may be
employed in such facilities to control gaseous emissions. Only a few of the
control processes have been tested in coal gasification application. Many of
the control processes, however, have been used in similar applications in other
industries (primarily in the petroleum refining and natural gas industries).
In this section, the air pollution control processes which have been tested
in coal gasification applications or which may be potentially suitable for such
applications are reviewed. A summary of the most effective air emissions con-
trol alternatives is given in Section 4.6.
Figure 4-1 shows the process modules for the control of waste gases identi-
fied in Chapters 2 and 3. The process modules shown in the figure are sulfur
recovery; tail gas treatment (for additional HpS or sulfur recovery); SOp con-
trol and/or recovery; incineration; particulate control; CO, hydrocarbon and
odor control; gas compression and recycling; NO control and hydrocarbon vapor
J\
control. Each module is comprised of a number of nearly interchangeable pro-
cesses with each individual process being applicable to a specific range of
operating conditions. The control processes which are reviewed in this section
in connection with each module are listed in Table 4-1. A discussion of the
applicability of alternate processes to individual waste streams follows.
4.2.1 Coal Pretreatment and Handling
Several particulate control devices or techniques are potentially appli-
cable to dusts generated as a result of coal crushing, screening and conveying.
These include cyclones, fabric filters, venturi scrubbers, electrostatic pre-
cipitators, and dust supression systems. The key features of these controls,
including their costs (where data were available) are presented in Table 4-2.
As indicated in Table 4-2, the control devices considered vary in their
operating principle, effectiveness in removing particles in different size frac-
tions, temperature applicability, particulate loading limitation and energy
requirements. Cyclones are generally employed for the removal of bulk parti-
culates (generally greater than 5u in size) and, in many cases, upstream of
134
-------
EAM AN
POWER GE
ERATION
FLUE
GASES
SO2 CONTROL
AND/OR
RECOVERY
PARTICULATE
CONTROL
CRUSHING/
SCREENING
EMISSIONS
PARTICULATE
CONTROL
Y-
PRODUCT
STORAGE
VENT
ASES
HC VAPQS
CONTROL
PARTICULATE
CONTROL
TRANSIENT I 102
GASES
CO, HC, &ODOR
CONTROL (IN-
CINERATION OR
ADSORPTION)
ATMOS-
PHERIC
DIS-
CHARGE
CATALYST
REGENERA-
TION/DECOM-
MISSIONING
OFFGASES
0 RAW
PRODUCT
GAS, LOCK-
HOPPER, OR
FUEL
SUPPLY
LOCK-
HOPPER
VENT
GASES
EPRESS-
URIZATION
AND
STRIPPING
N CASE
GAS
COMPRESSION
& RECYCLING
CO. HG & ODOR
CONTROL (IN-
CINERATION OR
ADSORPTION)
CONCEN
TRATED
ACID
GASES
SULFUR
RECOVERY
TAIL GAS TREATMENT
FOR ADDITIONAL H2S
OR SULFUR RECOVERY
HYDROCARBON
CONCENTRATION
(RECYCLE H2 S STREAM)
* NUMBERS REFER TO STREAMS IN FIGURES 2-2, 2-3, AND 2-4.
Figure 4-1. Process Modules for Air Pollution Control in a Commercial Lurgi
SNG Facility
135
-------
TABLE 4-1. AIR POLLUTION CONTROL PROCESSES REVIEWED FOR APPLICATION TO LURGI
SYSTEMS FOR SNG PRODUCTION
Sulfur recovery
Hydrocarbon removal/H^S
concentration
Tail gas treatment for
additional hUS sulfur
recovery
S09 control and/or recovery
CO, hydrocarbon control
Particulate control
Compression and recycling
NO control
X
Claus, Stretford, Giammarco-Vetrocoke
ADIP
SCOT, Beavon, IFP-1, IFP-2, Sulfreen,
Cleanair
Well man-Lord, Chiyoda Thoroughbred 101,
Shell copper oxide, lime/limes tone slurry
scrubbing, double alkali, and magnesium
oxide scrubbing
Thermal oxidation, catalytic oxidation,
flares, activated carbon adsorption,
vapor recovery, floating roof storage
Fabric filter, electrostatic precipita-
tion, venturi scrubbing, cyclones, dust
suppression with water sprays
Compression and recycling
Combustion modification and dry and wet
processes
136
-------
TABLE 4-2. KEY FEATURES OF PARTICULATE CONTROL DEVICES/TECHNOLOGY(58)
CO
Device
Cyclone
(Baghouse)
i/en tun
Scrubber
Precipi tator
Dust
System
Operating Principle
Removal of particu-
lates from a gas by
imparting a centri-
gas stream. The
iculates carries
them to the cyl in-
drical walls where
they fall to the
bottom of the
cyclone for removal.
lates from a gas
stream by impaction
or interception on
a fabric f il ter
(general ly tubular
shape) . Particu- \
from filter media
by mechanical shak-
ing or a pressurized
reverse air flow.
Removal of particu-
lates from a gas
stream by impinge-
The agglomerated
particles are sub-
sequently removed
in a centri fugal
col lector
lates from a gas
stream by imposi ng
an electrical charge
and collecting the
col lector plates
Col lected sol ids are
normally removed by
mechanical rapping
with hammers or
vibrators
Control of fugitive
and handling by uti-
1 izmg high pressure
nozzles spraying
water containing
wetting agent.
Range, wt %
50 to 80% for
5 to to 20 ufn
for 0.25 to
0.5 urn
99.0 to 99.51
for 0.75 to
1 .0 urn
100 um
60 to 92.5°.
for 0 25 um
85 to 97. 21
92 to 99%
for 0. 75 um
95 to 99.6%
for 1 .0 um
for 0.1 _n
90 to 9S T
for 0 5 _n
98 to 99. 9r
for 5.0 um
43S for 3 um
25% for 1 um
Without addi-
tive but with
steam addi tion .
43X for 3 um
40* for 1 um
With wetting
agent: 95% of
overall mass
- •• - — '
Particle
Size
Range
-5 um
>0.5 um
>1 um
Particulate
Limitation
>2.4 g/m3
o gr/ft3)
(»6.1 gr/ft3)
>0.24 g/m3
(>0.1 gr/ft3}
(>0 1 gr/ft3)
No specific
Drop
1.3-10.2 cm
(0.5 to 0.4 in.)
W.G
(2 to 10 in.)
W.G.
25-250 cm
(10 to 100 in.}
W.G.
(0 2 to 1 in.)
W.G.
Not appl icable
Advantages
High reliabili ty due
to a simple collection
requirements.
collection efficiency.
High particulate
ollection efficiency
apable of treating
treams wi th wide
temperature, pressure
nd gas composition
anges .
perature applications
Low pressure drop, can
treat large volumes of
No waste disposal pro-
design and maintenance.
Low capital and opera-
t ng costs .
Disadvantages
Cannot efficiently
remove particulates
below 5 um.
operating costs. Plug-
ging problems will re-
sult if feed stream is
saturated or wet or con-
tains tarry/oily mater-
ials. Temperature limit
filter media uti lized.
General ly 1 imi ted to
560°K (550°F) maximum
temperature.
Liquid scrubbing wastes
are produced which may
require treatment High
energy consumption. Some
potentially valuable dry
material cannot be directly
recovered .
erally applied at pressures
near atmospheric. Collected
particulates must have a
cient collection Not
applicable to explosive
gases.
Clogging can occur if spray
Low efficiency for small
particles. Freezing can
occur if adequate heat trac-
ing is not used.
(First quarter, 1978 dollars)
Costs vary considerably depend-
ing on the cyclone size, nature
struction and cyclone designs;
cyclones are generally less
culate control methods.
S69-109/m3/min. of installed
capacity (51.95-3 10/actn)
Operating
S18-24/m3/min.(S0.50-0.67/acfm}
Capital
S99-212/m3/min. of installed
capacity ( $2. 80-6 .00/acfm)
$S03-512/m3/min ($14. 25-14. SO/
acfm)
Capital
$185-468/m3/min of installed
capacity (S5.25-1 3. 25/acfm)
Operating
acfm)
No generalized cost data available
-------
other control devices. The capital and operating costs for cyclones are rela-
tively low. Baghouses have very high particulate removal efficiency, and can
lend themselves to applications involving small or intermittent gas flows. Bag-
houses, however, have high pressure drops (e.g., in comparison with electro-
static precipitators), and cannot ordinarily handle wet gases, gases containing
oily materials or gases having temperatures in excess of 560°K (550°F).
Venturi scrubbers can generally handle gases having temperatures higher
than that which can be handled by fabric filters, can operate at high pressures,
can tolerate wet and tarry gases, and can be very efficient for the removal of
submicron particles. In contrast to other devices in which the particles are
collected in dry form, venturi scrubbers generate a wet slurry which is more
voluminous and generally more difficult to dispose of.
Electrostatic precipitators are high efficiency particulate removal devices
have low pressure drops, are capable of handling large volumes of gases and can
tolerate high feed gas temperatures. Electrostatic precipitators, however, are
not generally suitable for applications to gases above atmospheric pressure
and are not economical for treating small or intermittent gas flows (such as
those resulting from material handling dust collection systems).
A dust suppression system consists of a spray system using water containing
wetting agents. The sprays are generally applied continuously to open conveyors
storage areas and transfer points. The function of the wetting agent is to
reduce water surface tension and enhance particulate removal efficiencies.
Dust suppression systems are simple to operate, do not create a waste disposal
problem and have low capital and operating costs. An improperly designed and
operated dust suppression system may result in clogging or packing of fine
screens. Heat tracing may be required to prevent freezing of water in the pip-
ing system.
The quantity of a solid waste stream generated by dry particulate removal
devices (cyclones, baghouses and electrostatic precipitators) is dependent upon
the inlet particulate loading and the removal efficiency. Dry particulate con-
trol devices may be more desirable than wet control devices (e.g., venturi
scrubber) for application to coal crushing and screening, especially when the
collected coal dust is to be utilized for power production or sold.
138
-------
In summary, a dust suppression system is most suitable for the control of
particulates emitted from conveyors, transfer points and other material hand-
ling operations. Particulate emissions from crushing and screening would prob-
ably be best controlled by a dust collection system utilizing a baghouse.
4.2.2 Coal Gasification
Control of Lockhopper Offgases. Feed and ash lockhopper vent gases are
the only routine gaseous waste streams from the gasification operation. As dis-
cussed in Sections 2.2 and 3.5, product gas (raw, cleaned or SNG) or inert by-
product gas (e.g., CCL from Rectisol process) can be used for feed lockhopper
pressurization. When product gas is used, the lockhopper vent gas is mostly
recycled to the process with only about 3% of it discharged as an off-gas. When
CCL is used for lockhopper pressurization, the entire volume of the pressuriza-
tion gas would be discharged as the off-gas. Because of the possible presence
of contaminants, treatment of the off-gas may be necessary prior to atmospheric
discharge.
The lockhopper off-gas may require particulate removal and possibly incin-
eration to oxidize carbon monoxide, hydrocarbons, and hydrogen sulfide. Due to
the relatively small volume and intermittent nature of the off-gas, fabric
filters appear suitable for the treatment of the off-gas for particulate removal.
The effect of tarry materials and moisture in the off-gas on the performance of
the fabric filter remains to be evaluated.
The off-gas from the ash lockhopper would be composed mainly of steam with
some entrained ash particulates. The volume of this stream is relatively small
and its composition is not well defined to establish control requirements.
Control of Transient Waste Gases. Gas produced during start-up and shut-
down and during upset conditions may not be suitable for conversion to SNG and
hence would require disposal. Generally such gases would be incinerated in a
flare. Flaring of waste gases is commonly practiced in refineries as a safety
and emission control technique. The primary purpose of flaring is to convert
organics, carbon monoxide, and reduced sulfur and nitrogen compounds to less
hazardous forms (e.g., C09, SCL, NO ). Most flares in refinery service are
L*. L- A
elevated above ground level to provide for improved pollutant and heat dis-
persion. Steam (or other inert gas) is injected in the combustion zone of the
flare to enhance turbulent mixing of waste gas and air and to suppress smoke
139
-------
formation. Since the quantity and composition of refinery waste gases vary
widely over short periods of time, modern flares incorporate sensors and feed-
back controls to regulate air and steam feed rates in response to changing waste
gas combustion characteristics.
Because of the highly variable nature of waste gases commonly flared, it
is generally difficult to achieve the proper combustion conditions consistent
with minimum emissions of oxidizable substances. Thus, even with sophisticated
flare control systems, emissions of CO, unburned hydrocarbons, and odors are
generally higher from flares than from other stationary combustion sources of
a comparable heat rating. Although some noise is inherent in the release of
steam through flare orifices, the venting of combustion products to the atmo-
sphere, and the combustion process itself, such noise can be minimized by proper
flare design (e.g., reducing the size of steam injection orifices) and operating
conditions (e.g., using a minimum amount of smoke suppressant).
4.2.3 Gas Purification
In terms of total volume and content of hUS and other reduced sulfur com-
pounds, concentrated acid gas(es) from the Rectisol process is the most import-
ant gaseous waste stream in a Lurgi SNG facility. Two major approaches are
possible for removal of most of the sulfur components before atmospheric dis-
charge. These are sulfur recovery using wet or dry catalytic oxidation pro-
cesses and incineration to convert reduced sulfur species to S0? followed by
use of wet or dry S02 removal processes. Depending on the composition of the
concentrated acid gas stream and the degree of control desired, the sulfur re-
covery approach may include pretreatment of the acid gas for FUS concentration
(and HC removal) and tail gas treatment for additional HLS removal or sulfur
recovery-and/or HC/CO removal. Processes for sulfur recovery, pretreatment for
H^S concentration/HC removal, tail gas treatment, incineration followed by SCL
removal, and HC/CO control are discussed below. The discussion includes identi-
fication of several options for the treatment of concentrated acid gases in an
integrated Lurgi SNG plant.
Sulfur Recovery. Of a number of processes which are available for sulfur
recovery, three are considered to be most promising for application to coal
gasification. These three are Claus, Stretford and Giammarco-Vetrocoke (G-V),
and have been widely used in natural gas, petroleum refinery and/or by-product
coke industry. Table 4-3 summarizes the key features of these three processes.
140
-------
TABLE 4-3. GENERAL CHARACTERISTICS OF SULFUR RECOVERY PROCESSES
(53)
Process
Claus
Stretford
Gi ammarco-
Vetrocoke
(G-'.'J
Process
Principle
Catalytic oxi-
dation of H2S
end SO^ to
elemental sul-
fur. Three
operational
modes of
Claus plants
have been
commerci al ly
employed.*
Liquid phase
oxidation of
H2S to ele-
mental sul-
fur in an
alkaline
sol ution of
metavanadate
and anthra-
quinone di-
sul fonic acid
(ADA) salts.
Liquid phase
oxidation of
H2S to ele-
mental sul-
fur i n
potassium
carbonate and
arsenate/
arsenite solu-
tion. A con-
centrated CC>2
stream wi th
very low H2S
concentration
is produced.
Limits of
Applicabili ty
Straight-through
system utilized
for higher H2S
concentrations.
Spl it-stream
system util ized
for H2$ concen-
trations of
10-15%. Sulfur
burning mode
used for H2S
levels down to
5?;.
Present appl ica-
tions are gen-
erally for 1%
sul fur or less .
Maximum of 1 .5%
H2S in feed
stream.
Control Efficiencies (%)
H2S
90 - 95
99.9 or
greater
99.99
COS/CS2
90
0
R-SH
95
0
Partially
removed
Partially
removed
HCN
Partially
oxidized
NH3
Partially
oxidized
1
-100
(converted
to SCir in
Stretford
solution)
7
0
HC
90
0
0 : 0
By-Product
Elemental
1 i qui d
sulfur
Elemental
sulfur
Elemental
sul fur
which may
req u i re
arsenic
removal
Effect of C02
Can adversely
affect sulfur
remova 1 abi 1 i ty
and therefore
increase plant
size. If C02
exceeds 30% and
NH3 exceeds 500
ppmv, catalyst
plugging pro-
blems may occur.
High C02 concen-
trations will
decrease absorption
efficiency by low-
ering solution
alkalinity. In-
creasing absorber
tower height and
base addition are
requi red.
Little or no effect.
Process can be de-
signed to selective-
ly remove H2$ with
low C02 absorption.
Commercial
Appl ications
Widely employed
in petroleum
natural gas, and
by-product coke
industry. One
known application
to gasification
in South Africa.
Primarily natural
gas service, a few
applications to pet-
roleum refining
and by-product
coke industries.
A unit has been
constructed at the
Lurgi gasification
facil ity at Sasol ,
South Africa.
Primarily natural
gas service, a few
applications for
hydrogen purifi-
cation in petro-
leum refining and
ammonia production.
*The three operational modes of the Claus process are: "straight-through, "split-stream" and "sulfur-burning. In the "straight-through" mode, all of the
feed gas along with stcichiometric quantity of air to oxidize one third of the H2S is fed to the catalytic reactor. In the "split flow" mode, one third of
the gas feed is reacted with air, followed by recombination with the other two thirds of the gas feed prior to entering the reactor. In the "sulfur-burning"
node, elemental sulfur and air are iniected into the combustion chamber to provide the S02 needed for the Claus and reaction.
-------
Operating and cost data for the Stretford and Claus processes are presented in
Table 4-4.
As indicated in Table 4-3, the Claus process is generally applicable to
feed streams containing a minimum of 10-15% H2S, whereas the Stretford and G-V
processes are applicable to feeds containing around 1% H2$. (Some Claus plants
have been designed and are operating on feeds containing as low as 5% F^S.
The Stretford process has also been used with feeds containing more than 10%
H2S. At these high concentration levels, however, the Stretford process is
not economically competitive with the Claus process.) The treated gas from
the Claus process generally contains several thousand ppm of sulfur compounds
(primarily hLS), whereas the treated gas from the Stretford and G-V contains
only a few ppm of hLS. The Claus process is a dry high temperature process in
which H2S is catalytically reacted with S02 (produced by air oxidation of the
H2S) to form elemental sulfur. The Stretford and G-V processes are liquid-
phase oxidation systems using aqueous solutions of alkaline metavanadate/
anthraquinone disulfonic acid and arsenite, respectively. While other reduced
forms of sulfur (e.g., CS2 and COS) are partially removed by the Claus and G-V
processes, they are not removed by the Stretford process. Since the Claus pro-
cess operates at a relatively high temperature, it is also capable of oxidizing
some of the hydrocarbons.
Unlike natural gas and refinery acid gases which generally do not contain
high levels of C02, acid gases from coal gasification usually contain 75 to 99%
C02- In the Claus process, high C02 concentration levels in the feed gas
(greater than 30%v) would not create a major operating problem unless the gas
also contains more than 500 ppmv of ammonia (this situation can lead to ammonium
sulfide deposition in catalyst beds). High OL levels, however, increase the
total sulfur content of the Claus tail gas by the following reactions which
occur over the Claus catalyst:
C02 + H2S = COS + H20 and C02 + 2H2S = CS2 + 2H20
In the Stretford process, high levels of C02 in the feed gas decrease the alka-
linity of the sorbent and, hence, reduce the system efficiency. Thus, where
high C02 levels are encountered, larger absorption towers would be required to
obtain high H2S removal efficiency. In the G-V process, C02 is partially re-
moved by the sorbent, but the absorption of C02 does not significantly impair the
H2S removal efficiency.
142
-------
Based on the data in Table 4-4, total annualized costs for Stretford and
Claus plants designed for Lurgi acid gas service are about $233 and $107 per
tonne of sulfur, respectively. These costs, however, are not directly compar-
able since the cost for the Stretford process is based upon 2% H^S in the feed
while that for the Claus process assumes over 15% H?S in the feed. No cost
data are currently available for the G-V process.
The Stretford process produces two waste streams (excluding the tail gas):
solvent blowdown and oxidizer vent gas. Solvent blowdown is necessary to avoid
buildup of the side reaction products in the Stretford solvent. These side
('/?'}
reactions include the following^ ':
2NaHS + 202 = Na2S203 + H20
4S + 6NaOH = Na2S203 + 2Na2S + 3H20
2HCN + Na2C03 + 2S = 2NaSCN + C02 + H20
The estimated composition of the blowdown for a Stretford unit featured in the
proposed design of the El Paso Lurgi facility is as follows' ': 80% H20, 10.8%
Na2S203, 4.4% NaSCN, 0.7% NaV03, 1.1% ADA and 3% NaHC03 and Na2C03-
The oxidizer vent gas from the Stretford process is expected to consist
mostly of air and water vapor; some sulfur compounds may also be present in
this gas. No actual data are available for this stream.
The Claus process produces spent catalyst and in some cases, sour conden-
sate as waste streams. The Claus catalyst has an estimated life of more than
two to three years^ '. The Claus process may generate sour condensates,
depending on the moisture content of the feed. Any such waste would usually
be returned to the sour water stripping units.
Hydrocarbon Removal/H2S Concentration for Claus Plant Feed. The acid gases
from the Rectisol process do not contain a sufficiently high concentration of
hLS to be suitable for direct feeding to the Claus process. Furthermore, these
acid gases contain a relatively high concentration of hydrocarbons which would
make temperature control difficult in the Claus reactor and can lead to catalyst
deactivation via carbon formation on the catalyst surface. One approach to mini-
mize catalyst deactivation and to obtain a concentrated H,>S Claus feed is selec-
tive removal of F^S using an alkanolamine process such as the Shell ADIP process.
The ADIP solvent (diisopropanolamine) does not absorb hydrocarbons and under
143
-------
TABLE 4-4. OPERATING AND COST DATA FOR CLAUS AND STRETFORD PROCESSES
Parameters
Stretford(22'1)
Claus(22,60)
Absorbent reactor
temperature
Pressure
Loading
Regeneration
Temperature
Pressure
Effi ci ency
Chemical require-
ment, kg/10°Nm3
(lbs/10°scf)
Steam
requirement
Electricity
Capital costs
t
Operating costs
Ambient to 322°K (120°F)
Ambient to 7.0 MPa (1000 psia)
2% H2S
Ambient
Atmospheric
To less than 1 ppmv H9S
ADA:* 84(5)
Sodium vanadate: 1.0 (0.06)
Citric acid: 168 (10)
830 kg/tonne sulfur
1353 kwh/tonne sulfur
$65,350/tonne/day sulfur
capacity
$55.50/tonne sulfur
311°K (100°F)
Near atmospheric
15% H0S
95-97% total
sulfur removal
High pressure
steam-437 kg
consumed/tonne
sulfur.
Low pressure
steam-4910 kg
produced/tonne
sulfur,
63 kwh/tonne
sulfur
$31,920/tonne/
day sulfur
capacity
$19.30/tonne
sulfur
*Anthraquinone disulfonic acid
fAll costs are adjusted to 1st quarter 1978 dollars; costs are for plant
sizes similar to those which would be used in commercial Lurgi SNG faci-
lities (60-200 tonnes sulfur/day)
144
-------
proper operating conditions shows selectivity for H,>S over CO,,. Thus, the use
of ADIP or a similar process to treat Rectisol acid gases can result in a
hydrocarbon free, concentrated H,,S feed for Claus processing and a product gas
which contains sufficient organics to be used as a plant fuel. Table 4-5 pre-
sents operating parameters and cost data for the ADIP process.
Tail Gas Treatment for Additional H2S Removal or Sulfur Recovery. Depend-
ing on the characteristics of the concentrated acid gas and the specific sulfur
recovery process employed, the treated gas from a sulfur recovery process may
require additional treatment for sulfur (and hydrocarbons) removal before dis-
charge to the atmosphere. As with most of the sulfur recovery processes, the
tail gas removal processes have not been used in connection with coal gasifica-
tion, but many of them have been used in other industries (primarily in the pet-
roleum refining industry).
Table 4-6 summarizes the key features of the sulfur recovery tail gas treat-
ment processes. The processes listed in this table fall into three general
categories: (1) processes such as IFP-1 and Sulfreen which are essentially
extensions of the Claus process; (2) processes such as Beavon, CleanAir and
SCOT which catalytically reduce the more oxidized sulfur compounds (e.g., S0?,
CSp, and COS) to hydrogen sulfide which is recycled to the sulfur recovery
systems; and (3) processes such as Chiyoda Thoroughbred 101, Wellman-Lord, IFP-
2 and Shell CuO which involve the removal of S0? by scrubbing and require feed
incineration to convert all sulfur compounds to S0?.
The processes in the first category have been employed exclusively for
Claus plant tail gas treatment and are capable of reducing the sulfur level to
less than 500 ppmv. As with the Claus process, these processes can tolerate
high concentrations of C02 in the feed gas. In the Beavon and SCOT processes,
hydrogen or synthesis gas is used for the reduction of oxidized sulfur; the
reduction is carried out over a cobalt molybdate catalyst. In existing commer-
cial applications, the product hydrogen sulfide in the tail gas from the Beavon
and SCOT processes is treated for H?S removal/sulfur recovery by the Stretford
and alkanolamine processes, respectively. Total sulfur levels of less than 100
ppmv have been achieved by the application of Beavon-Stretford and SCOT-
alkanolamine systems. In contrast to the first category of processes (processes
which extend the Claus reaction), Beavon-Stretford and the SCOT-alkanolamine
145
-------
TABLE 4-5. OPERATING PARAMETERS AND COSTS FOR THE ADIP PROCESS^2»
Contractor
Temperature, °K (°F)
Pressure, MPa (psia)
Loading
Stripper
Temperature, °K (°F)
Pressure
Efficiency
Raw Material Requirements
ADIP solvent
Utility Requirements
Steam
Electricity
Capital Costs
Operating Costs
310 - 333 (100 - 140)
0.1 - 7.0 (15 - 1015)
0.6 mole H2S/mole amine
374 - 408 (250 - 275)
Atmospheric
To less than 100 ppmv of H,,S
2-5 x 10 kg/kg of H2S removed
4600 kg/tonne H2S removed
13.7 kwh/tonne H2$ removed
$23,600*/tonne H2S removed
$17.33*/tonne H2S removed
*These costs are in 1978 dollars and reflect units which process
10% H2S feed. ADIP removes around 99% of the ^ and UP to 90%
of the C02 so that equipment size and cost are not strictly a
function of ^S removal alone. It is assumed here that the costs
are proportional to h^S loading.
146
-------
TABLE 4-6. KEY FEATURES OF SULFUR RECOVERY TAIL GAS TREATMENT PROCESSES
Tail Gas
Removal
Process
Chiyoda
Thoroughbred
101
Beavon
CleanAir
IFP-1
IFP-2
Process Principle
Thermal oxidation
of sulfur com-
pounds to SOj,
.followed by liquid
absorption
Catalytic reduction
of sulfur compounds
to H2S, followed
by Stretford
process
Catalytic reduction
of sulfur com-
pounds to HjS,
followed by a con-
tinuation of the
Claus reaction and
Stretford process
Liquid phase con-
tinuation of Claus
reaction at a low
temperature
Incineration of
tail gas followed
by ammonia scrub-
bing. Solution is
evaporated to pro-
duce a concentra-
ted S02 stream
which is returned
to the Claus plant.
Feed Stream
Requirements/
Restrictions
Incinerated Claus tail
gas; no specific
requirement on H,S:SO,
ratio i i
Sulfur recovery pro-
cess tail gas is
heated upstream of
catalytic reactor; no
specific H2S:S02
ratio required
H2$:S02 ratio can
vary up to 8:1 with-
out affecting effi-
ciency; designed
specifically for
Claus tail gas
H2$:S02 ratio main-
tained in the range
of 2.0 to 2.4
H2S:S02 ratio main-
tained in the range
of 2.0 to 2.4
Sorbents/
Solvents
2% (by wt.)
sulfuric acid
solution
Stretford
process
solution
Unknown aque-
ous solution
and Stretford
process
solution
Polyalkaline
glycol
Aqueous
ammonia solu-
tion
Product
Gypsum
(CaS04-H20)
5 to 20%
moisture
content
Elemental
sulfur
Elemental
sulfur
Elemental
liquid
sulfur
Elemental
liquid
sulfur
Utility
Requirements
Very high
Low
Very low
Very low
High
COS and C$2
Removal
Largely oxidized
by incineration,
not absorbed by
solution
Catalytically
converted to
H2S
Catalytically
converted to
H2S
Not removed in
catalytic reactor
Oxidized by in-
cineration, not
removed i n cata-
lytic reactor
Efficiency
95% S02 or less
than 300 ppmv
99.8% removal
for Claus tail
gas containing
4% equivalent
H2S
Plant effluent
normally guar-
anteed to con-
tain less than
250 to 300 ppm
S02 equivalent
Capable of re-
ducing sulfur
species in Claus
tail gas to 2000
ppm as S02
Capable of re-
ducing sulfur
species in Claus
tail gas to less
than 500 ppm
Effect of C02
In Feed Gas
No effect
Reduces conversion
efficiency by
catalyst; decreases
H2$ absorption by
Stretford solution
Reduces conversion
efficiency of
catalyst; decreases
H2S absorption by
Stretford solution
No effect
No effect
(CONTINUED)
-------
TABLE 4-6. CONTINUED
Tail Gas
Removal
Process
Sul freen
Shell
Copper
Oxide
Wei Iman-
Lord
SCOT
Process Principle
Solid phase con-
tinuation of Claus
reaction at a low
temperature
Thermal oxidation
of sulfur com-
pounds to S02,
followed by adsorp-
tion by CuO; a con-
centrated S02
stream is produced
by desorption with
a reducing gas (H?)
Thermal oxidation
of sulfur com-
pounds to S02,
followed by liquid
absorption; concen-
trated SOo is pro-
duced and recycled
to Claus plant
Sulfur species are
catalytically re-
duced to H2S; H2$
is scrubbed in a
regenerable anine
systen
Feed Stream
Requirements/
Restrictions
Optimum performance
requires H2$:S02
ratio of 2:1
Incinerated Claus
tail gas; no specific
requirement on H2S:
SO^ ratio
Incinerated Claus
tail gas; process can
handle SO? concentra-
tions welt over
10,000 ppm
Applicable to Claus
tail gas
Sorbents/
Solvents
Hone; sulfur
vapor conden-
sation process
utilized
Copper oxide
Concentrated
sodium
sulfite, bi-
sulfite
solution
Alkanolamine
solution
Product
Elemental
liquid
sulfur
Concentrated
SO, stream
C
Concentrated
S02 stream
(up to 90%
SOo content)
Concentrated
\\2$ stream
Utility
Requirements
Very low
No data
available
High
Moderate
COS and CS2
Removal
Not appreciably
removed
Oxidized by
incineration
Oxidized by
incineration,
not removed
by process
Catalytically
reduced to
H2S
Efficiency
Capable of re-
moving 00 to
35% of sulfur
in the tail gas
90% S02 removal
Can remove in
excess of 95%
of S02
Can remove 97%
of sulfur
species
Effect of CO-
ln Feed Gas
No effect
?
No effect
Reduces conversion
efficiency by
catalyst; high C02
levels reduce
efficiency of
alkanolamine
system
co
-------
systems are adversely affected by high levels of C02 in the feed gas. The CCL
in the feed gas reduces the efficiency of the catalytic reduction of COS and CS2
to H2S* and impairs the effectiveness of the Stretford and alkanolamine absorp-
tion systems. Table 4-7 presents operational parameters and cost data for the
Beavon and SCOT processes.
The third category of processes which involve incineration followed by S02
recovery have been applied to Claus plant tail gas and to utility boiler flue
gases. These processes, which are discussed in more detail below in connection
with the incineration of acid gases, are capable of removing over 90% of the
total sulfur in the feed gas. The Chiyoda Thoroughbred 101 and the Shell-CuO
processes which employ sulfuric acid and CuO as sorbents, respectively, are not
affected by high levels of C02 in the feed gas. In the Wellman-Lord process,
the sorbent is an alkaline solution of sodium sulfite/bisulfite whose capacity
for S02 absorption may be affected by very high levels of C02 in the feed gas.
(The use of Wellman-Lord process for S02 removal has been successfully demon-
strated on Claus plant tail gases containing over 50% v CO,,.) Table 4-8 pre-
sents operating and cost data for the Chiyoda and Wellman-Lord processes.
Incineration of Acid Gases Followed by S02 Removal. The major alternative
to direct elemental sulfur recovery for treating concentrated acid gases from the
Rectisol process is incineration of the gas to convert H2S, COS, CS2, and organic
sulfur compounds to S02 followed by S0? removal. A number of processes including
Wellman-Lord, Chiyoda Thoroughbred 101, lime/limestone scrubbing and Dual Alkali
would be potentially applicable to S02 removal from incinerated acid gases.
Although a number of the processes are under development for S0? removal, the
above four processes which are considered here represent the state-of-the-art
commercial FGD systems from the standpoint of performance and cost. Key fea-
tures of these processes are presented in Table 4-9.
*A typical Claus plant tail gas in Lurgi SNG service would contain about 64% C02,
12% H20 and 1.1% total sulfun31). For this gas composition and under equili-
brium conditions (catalyst operating temperature of 670°K or 750°F and pressure
of 0.1 MPa or 1 atmosphere), the effluent gas from the Beavon process should
contain about 280 ppmv of COS. Union Oil Co., the vendor-licensor of the Beavon
process, however, intends to offer a 250 ppmv total sulfur performance guarantee
for the process in coal gasification applications(22).
149
-------
TABLE 4-7. OPERATING PARAMETERS AND COSTS FOR BEAVON AND SCOT TAIL GAS TREATMENT PROCESSES*
Ul
o
Operating Parameters
Reactor
Temperature °K (°F)
Pressure MPa (atm)
Condenser (absorber SCOT)
Temperature °K (°F)
Pressure MPa (atm)
Efficiency
Raw Material Requirements
Fuel Gas
Stretford solution
Utility Requirements
Steam
Electricity
Cooling water
Fuel gas
Capital Costs
Operating Costs
Beavon^58'63)
644 (700)
0.1 (1)
210 (100)
0.1 (1)
to less than 250 ppmv
37,000 Nm3/day (1.25 Mscf/d)
per tonne sulfur removed in Claus
0.013 to 0.06 £/sec (0.21-1.0 gpm)
per 100 tonne/day S plant
68 kwh/tonne S in tail gas
1400 £/min for 100 tonne/day Claus
see above
$28,280/tonne S removed in Claus
$57.70/tonne S in Beavon tail gas
SCOT(50,64)
400 - 430 (260 - 320)
0.13 (19)
310 - 320 (100 - 120)
0.1 (1) atm
to less than 250 ppmv
25.6 Ib/tonne S removed in Claus
1.4 kwh/tonne S removed in Claus
52 ji/min/tonne S removed in Claus
28 MMBTU/tonne S removed in Claus
$35,000/tonne S removed in Claus
$10.00/tonne S removed in Claus
*A11 costs are adjusted to 1st quarter 1978 dollars. Costs presented are for units operating on 100 tonne
sulfur/day Claus plants.
-------
TABLE 4-8. OPERATING PARAMETERS AND COSTS FOR THE WELLMAN-LORD AND CHIYODA THOROUGHBRED 101 PROCESSES
Operating Parameters
Absorption
Temperature, °K (°F)
Pressure, MPa (atm)
Loading (ppm)
Regeneration
Temperature, °K (°F)
Pressure, MPa (atm)
Efficiency, %
Raw Material Requirements
Utility Requirements
Steam
Electricity
Process Water
Cooling Water
Costs*
Capital
Operating & Maintenance
Wellman-Lord(51>58>6°)
310 - 340 (100 - 150)
0.10 (1)
to 10,000 ppm
369 (205)
0.068 (0.7)
>90%
0.25 kg NaOH/kg S, 0.33 kg Na2C03/kg S
18,700 kg/tonne sulfur
1120 kwh/tonne sulfur
0.055 £/Nm3 (0.0004 gal/scf)
1.1 £/Nm3 (0.008 gal/scf)
$800 Nm3/min.($21,400/Mscfm) capacity
0.240 mils/Mm3 (6.5 mils/Mscf)
Chiyoda Thoroughbred 101 (58,60)
322 (120)
0.1 (1)
to 11,000 ppm
>90%
1.38 kg calcium salt/kg S
593 kg/tonne sulfur
102 kwh/tonne sulfur
0.825 £/Nm3 (0.006 gal/scf)
$554/NnT/min. ($14,900/Mscfm)
capacity
0.32 mils/Mm3 (8.5 mils/Mscf)
*Costs are adjusted to 1st quarter 1978 dollars. These cost estimates are based on sulfur plant sizes
likely to be encountered in commercial SNG application (60-200 tonne sulfur/day). Although the data
are for utility FGD service, costs for sulfur plant tail gas treatment are similar when compared on
a "tonne of sulfur removed" basis(64).
-------
TABLE 4-9. KEY FEATURES OF FOUR S02 REMOVAL PROCESSES(58)
feature
Lime/Limestone Slurry Scrubbing
Dual Alkali Scrubbing
Chiyoda Thoroughbred 101
Uellman-!_ord
Principle
cn
ro
Feed Stream
Requirements
Absorbent
Product
Efficiency
Advantages
Disadvantages
Liquid phase absorption of
a lime or limestone slurry.
Particulates must be primarily
removed in a venturi scrubber
6 to 12% lime or limestone
slurry.
Calcium sulfite and calcium
sulfate.
Generally 70 to 90% for utility
firing of high sulfur coal.
95-99% can be obtained. Removal
efficiency will vary according
to scrubber type and gas pres-
sure drop. Over 99% removal
efficiency can be achieved.
Low capital and OSM costs. SO?
and particulates are removed.
Fairly simple process. Conven-
tional process equipment.
On line reliability may be low
(70 to 85%) produces ~2 times
(by wt.) as much waste sludges
as collected ash. For low sul-
fur coals, SO? removal effi-
ciency should be as low as 50%.
Liquid phase absorption of SO? in a
sodium hydroxide, sodium sulfite,
sodium sulfate and sodium carbonate
solution. A dilute mode process is
used for SO? concentrations of 250
to 1500 ppm and a concentrated mode
is used for SO? concentrations of
1800 to 8000 ppm and where less than
25% oxidation of collected SO? is
encountered.
0? must be less than 7% for concen-
trated mode. Excessive particulates
must be removed in a venturi
scrubber.
Sodium hydroxide, sodium sulfite,
sodium sulfate and small amount of
sodium carbonate.
Primarily calcium sulfite and cal-
cium sulfate.
Capable of over 99% removal for
typical coal fired utility flue
gas and a concentrated mode process.
A General Motors demonstrated (di-
lute mode) and an FMC pilot plant
(concentrated mode) operate at
approximately 90% SO? removal.
Low capital and O&M costs. SO? and
particulates are removed. Conven-
tional process equipment.
Produces -1.5 times (by wt.) as much
calcium sul fite/sulfate waste sludge
as collected ash. Corrosion and
pitting problems may require specific
materials of construction.
Thermal oxidation of sulfur com-
pounds to SO?, followed by
liquid absorption.
Particulates must be primarily
removed from feed.
2% (by wt.) sulfuric acid
solution.
Gypsum (CaS04-2H?0) 50 to 20%
moisture content.
95% SO? or less than 300 ppmv.
Produces potentially saleable
gypsum byproduct; process
commercially demonstrated.
High utility requirements; sul-
furic acid absorbent requires
that special metals be used in
construction.
Thermal oxidation of sulfur com-
pounds to SO?, followed by liquid
absorption; concentrated 50^
produced may be sent to a Claus
or sulfuric acid plant.
Particulates must be primarily
removed from feed.
Concentrated sodium sulfite, bi-
sulfite solution.
Concentrated SO? stream (up to
90% SO? content).
Can remove in excess of 95% of
SO?.
Commercially demonstrated, lower
potential for fouling/scaling
than calcium-based processes.
High utility requirements;
special metallurgy, requires sep-
arate system to process concen-
trated SO? to sulfur or sulfuric
acid.
-------
The Wellman-Lord and Chiyoda processes are wet scrubbing systems which
feature by-product recovery. In the Wellman-Lord process, SCL is absorbed in
a concentrated sodium sulfite/bi sulfite solution with subsequent regeneration
by thermal processing. A concentrated SCL offgas stream is produced and the
regenerated sulfite liquor is returned to the absorber after caustic addition.
The Chiyoda process utilizes a dilute sulfuric acid solution containing iron
catalyst to absorb/oxidize S02. The S02-rich solution is treated with limestone
in a crystal!izer to form gypsum crystals which are then separated and dried.
The liquor is recycled to the absorber. Both of these processes have been
applied to fuel combustion flue gases and to Claus plant tail gases and report-
edly have achieved S02 levels of below 200 ppmv in the treated gases.
The lime/limestone slurry and Dual Alkali scrubbing processes have been
developed and utilized for the removal of SOp from utility and industrial
boiler flue gases. In the lime/limestone process the flue gas is scrubbed with
a lime or limestone slurry (6-12%) to remove the S0?. The initial scrubbing
is carried out in a venturi scrubber which also removes most of the residual
particulate matter. The bulk of the SO,, removal is accomplished downstream in
an absorption tower. The resulting spent calcium sulfite/sulfate sludge is
discharged to a thickener/settling pond with the clarified liquid returned to
the process. Being a "throw-away" process, the process generates a relatively
large volume of sludge which requires processing and disposal. On a weight
basis, the wet sludge produced would typically be twice the amount of fly ash
and bottom ash produced in a coal-burning power planv '. S02 removal effi-
ciencies of up to 99% have been obtained in applications to flue gases from the
combustion of high sulfur coals. Somewhat lower efficiencies have been reported
for applications to lower sulfur fuels.
A concentrated sodium sulfite scrubbing solution is employed in the Dual
Alkali process. The reaction of S02 with sodium sulfite produces sodium bi-
sulfite which is reacted with lime in a separate vessel to regenerate sodium
sulfite and precipitate calcium sulfite. The calcium sulfite sludge is concen-
trated by filtration prior to disposal. The dual alkali process can achieve
99% S02 removal efficiency when treating relatively concentrated S02 streams
(1800-8000 ppmv) and 90% S02 removal when treating more dilute S02 streams (250-
1500 ppmv). As with the lime/limestone slurry process, the Dual Alkali process
153
-------
generates large amounts of waste CaS03/CaS04 sludge (typically about 1.5 times
as much as the amount of ash generated in a typical coal-fired utility boiled66)
Applications of lime/limestone and Dual Alkali processes to date have been
to flue gases which contain around 1000-2000 ppmv S02 and 10% C02. Incinerated
acid gas would generally contain considerably higher levels of S02 and C02 (at
least 10,000 ppmv S02 and 50-70% C02). The expected performance of these proc-
esses with such feed is not known. The Wellman-Lord and Chiyoda processes,
however, have been used for Claus tail gas desulfurization where the feed would
be similar to those expected for incinerated acid gases in terms of S02 and COg
concentrations. When the Wellman-Lord process is employed, a system would be
required to process the concentrated S02 stream from regeneration. The S02 may
be converted to elemental sulfur in a Claus plant or pcoesessed to produce sul-
fur ic acid.
The operating and cost data for the application of the Wellman-Lord and
Chiyoda processes to Claus plant tail gas treatment were presented in Table 4-8.
Table 4-10 presents cost data for the application of lime/limestone, Dual Alkali
and Wellman-Lord processes to the desulfurization of flue gases from coal-fired
boilers. Based on the data in Table 4-8 and the results of other studies^ ',
the Dual Alkali process would be economically most favorable for FGD applica-
tions. However, the Dual Alkali process has not been applied to the treatment
of incinerated acid gases in a Lurgi facility or to other gases having similar
compositions (e.g., Claus plant tail gas).
Hydrocarbon and Carbon Monoxide Control. Concentrated acid gases for the
Rectisol process contain hydrocarbons and carbon monoxide and small amounts of
methanol. Depending upon the approach used to control sulfur emissions, addi-
tional control for hydrocarbons and CO may be required. When the Claus process
is used, with or without preconcentration of H2$ (e.g., using the ADIP process),
organic compounds and CO are largely burned in the Claus furnace (or in plant
boiler) and thus no further control would ordinarily be necessary. If Rectisol
acid gases were treated by incineration followed by S02 removal, additional
hydrocarbon and CO control would not be required. When Rectisol offgas is
directly incinerated, the incineration may be accomplished in the plant boilers
equipped with FGD systems, thereby allowing sulfur, HC and CO control from both
acid gases and combustion flue gases in a single system.
154
-------
TABLE 4-10. ESTIMATED COSTS FOR LIME/LIMESTONE, DUAL ALKALI AND WELLMAN-LORD
FGD PROCESSES*
Process
, . (69)
Lime x
Limestone '
Dual Alkali(70)
Wellman-Lord^71)
Capi
200 MW
80
88
65-75
--
tal Cost ($/kw)
500 MW 1000 MW
61 45
68 51
__
70* 60*
Operating Costs (mils/kwh)
200 MW 500 MW 1000 MW
4.51" 3.6+ 2.9+
4.2f 3.4f 2.7f
2.8-3.3
2.6* 2.1*
*Mid-1977 basis
+An additional 15-20% would be required to account for sludge fixation
*End product assumed to be sulfuric acid
When the Stretford process is employed for removal of H?S from relatively
dilute acid gases, the process tail gas will contain essentially all of the HC
and CO originally present in the feed. Tail gas treatment processes such as
Beavon and SCOT which would be used with the Stretford process will not result
in HC and CO removal. Incineration of the tail gas which is required when
Well man-Lord or Chiyoda Thoroughbred 101 processes are used for tail gas treat-
ment will, however, effect destruction of HC and CO. When either no tail gas
treatment is employed or when Beavon or SCOT processes are used for the treat-
ment of Stretford tail gas, HC and/or CO control can be accomplished prior to
or after Stretford or Stretford/tail gas treatment processes, using any of the
several processes listed in Table 4-11. Except for the incineration processes
(the first three processes), the processes listed in Table 4-11 can be used
either before or after sulfur recovery. The alkanolamine, carbonate scrubbing
and cold water scrubbing separate HC and CO from the H^S and C02 contained in
the feed gas. The separated HC/CO stream is subsequently incinerated or used
as plant fuel. The cuprous ammonium solution absorption and cryogenic separa-
tion processes remove only CO and HC, respectively. As indicated by the cost
data in Table 4-11, the incineration options are generally more cost effective
than absorption/scrubbing options. In all cases, the recovery of fuel value
will partially (or totally) offset the energy used by the process.
155
-------
TABLE 4-11. CAPITAL AND OPERATING COSTS FOR SELECTED HC AND CO REMOVAL PROCESSES APPLIED TO A 7 x 106
(250 x 1Q6-SCFD) LURGI SNG PLANT*(22,128)
Candidate
Incineration in coal-fired boiler
Incineration in coal, gas-fired
boi ler
Catalytic oxidation
Alkanolamine (ADIP)
Hot carbonate scrubbing
Cold water scrubbing
Cuprous ammonium solution absorption
Cryogenic separation
Estimated
Capital
Investment
($106)
9
6
14
50tf
38
66
20
100
Capital and Operating Costs ($106/year)f
Capital
Charges
2.2
1.5
3.5
--
9.4
16.3
4.0
24.7
Fuel*
(0.2)*
12.0
0
--
(a.o)
(8.0)
(0.2)
(8.0)
Steam5
0
(5.0)
(1.8)
...
19
8
2
13
Catalyst
0.3
Other
1.7
1.5
2.6
--
17.9
23.4
7.9
28.7
Total
3.7
10.0
4.6
--
38.3
39.7
14.6
58.4
Total Cost
i/kcal
(
-------
Options for the Control of Concentrated Acid Gases in an Integrated Lurgi
SNG Plant. Table 4-12 lists 10 options for the control of acid gases in an
integrated Lurgi SNG plant. The table includes some qualitative statements on
the advantages and disadvantages of the options based upon the capability of
the various control processes discussed above. Some options (e.g., incinera-
tion of concentrated acid gases and atmospheric discharge) would be technically
unattractive and environmentally unacceptable for use in the U.S. The appli-
cability of certain options (e.g., those using Claus or Stretford processes for
sulfur recovery) is dependent on the sulfur concentration in the gas stream,
which is in turn determined by the sulfur content of the feed coal and the
specific design of the Rectisol acid gas treatment process employed. Accord-
ingly, the selection of the best option for the management of a specific sulfur-
bearing stream must be based on a case-by-case analysis. The determination of
the best option for use in a specific facility is also complicated by a number
of factors which relate primarily to the lack of data on (1) the detailed com-
position of gas streams from commercial facilities and (2) performance costs and
environmental aspects of actual application of control processes to Lurgi gas
streams. For example, the Stretford process has been demonstrated to be highly
effective for FLS removal from refinery and coke oven gases which contain low
to moderate levels of C0?; however, insufficient data exist for commercial appli-
cations to coal gasification acid gases which in some cases may contain 90% or
more CO^. A small Stretford unit is being tested at the Fort Lewis SRC pilot
plant handling concentrated acid gas from a diethanol amine unit. Satisfactory
(72)
performance has not been reported for this umtv
Some of the options listed in Table 4-12 have not appeared in the designs
for proposed commercial SNG facilities. In some cases this may be due to the
lack of engineering data for such options. For example, all proposed designs
include Claus and/or Stretford processes for the recovery of H2S from concen-
trated acid gases. Due to some of the shortcomings associated with these pro-
cesses for handling gases containing high levels of C02, it is possible that
acid gas incineration followed by S0? recovery (in a Wellman-Lord or wet lime-
stone unit) alone or in conjunction with flue gas from utility boilers may be
technically and economically superior.
157
-------
TABLE 4-12. CONTROL OPTIONS FOR THE CONCENTRATED ACID GAS STREAM FROM THE GAS
PURIFICATION OPERATION
Control Options
Comments
1. Claus plant sulfur recovery
2.
3.
4.
6.
7.
8.
Claus plant sulfur recovery
and tail gas incineration
Claus plant sulfur recovery
and tail gas treatment
Same as Option 1 plus S02
control and/or recovery
5. Stretford sulfur recovery
Same as Option 5 plus tail
gas treatment
Same as Option 6 plus
incineration
Incineration
1. Probably unacceptable because of high
concentration of total sulfur in the
tail gas; feed gas, H£$ enrichment and
hydrocarbon removal would likely be
required.
2. Probably unacceptable because of high
levels of S02 in the tail gas; only
applicable to streams containing more
than 5-15% H2S.
3. Tail gas treatment not highly effective
when feed gases contain high levels of
C02; only applicable to streams contain-
ing more than 5-15% H2S.
4. Reasonable option when feed gases con-
tain more than 5-15% H2S; total sulfur
removal efficiency may be less than
Option 5.
5. Inapplicable to waste gases containing
high levels of H2S; may not be econom-
ical for gases containing high CO?
levels; discharge may contain high COS
and HC levels.
6. Same as for Option 5.
7.
8.
9. Same as Option 8 plus S02
control and/or recovery
10. Incineration, treatment for
control and/or recovery in
combination with flue gases
from utility boilers
Same as for Option 5 except for oxida-
tion of CO and HC compounds.
Unacceptable because of high S02
emissions.
9. Many S02 recovery processes generate
sludges requiring disposal; no by-
product sulfur is recovered; regener-
able SOp removal processes may be
operated in conjunction with sulfur
recovery units.
10. Same as for Option 9; some economy of
scale may be realized if flue gas de-
sulfurization is required on utility
boilers.
158
-------
4.2.4 Gas Upgrading
The only gaseous waste stream generated in the gas upgrading operation is
the flue gas from catalyst regeneration/decommissioning. This stream will be
of a relatively small volume compared to other gaseous waste streams in a Lurgi
plant and will only be generated intermittently (perhaps once every year or
two). Based on current technology, incineration in the plant flare or utility
boiler appears to be the most practical approach to the control of this stream;
the effectiveness of incineration for the control of this stream is not known.
If particulate control is required, a fabric filter system would likely be the
best candidate. No specific control techniques for metal carbonyls which may
be present in the gas are identified, although incineration would likely convert
such substances to their metal oxide forms.
4.2.5 Auxiliary Processes
As discussed in Section 3.5.5, major gaseous waste streams associated with
auxiliary processes in Lurgi systems are depressurization and stripping gases,
by-product storage vent gases and steam and power generation flue gases. The
following is a brief review of processes for the control of these three waste
streams. As noted previously, steam and power generation flue gas and the con-
centrated acid gas are the two most important gaseous waste streams in a Lurgi
SNG plant. Some of the most effective options for air pollution control in an
integrated SNG facility include joint treatment of these streams. A brief dis-
cussion of the control options for integrated facilities is also included in
this section.
Control of Depressurization and Stripping Gases. Depressurization gases
from Lurgi tar/oil/gas liquor separation and overhead gases from sour water
stripping contain hLS, MR.., HC and CO at concentrations which could constitute
an emissions problem if such gases were vented directly to the atmosphere. In
comparison to Rectisol acid gases, the volumes of these streams are small, how-
ever, and thus combining them with Rectisol gases which are sent to sulfur
recovery would not dramatically affect the design of the sulfur plants. Alterna-
tively, these gases could be incinerated in the plant flare or, if sulfur con-
trol is required, in the utility boiler followed by S02 removal.
159
-------
Control of By-Product Storage Vent Gases^ Some gasification by-products
such as naphtha, light oil and phenols are sufficiently volatile to require
control of evaporative emissions which occur during handling and storage. The
control of such emissions is well established and is widely practiced in other
industries, especially the petroleum industry. EPA has promulgated New Source
Pferformance Standards (NSPS) for storage of petroleum liquids-; these standards
are expected to be applicable to gasification by-product storage. Generally,
the control techniques applicable to a given liquid are determined by its vapor
pressure. The more volatile liquids require vapor recovery systems while less
volatile liquids require either floating roof storage or conservation vents.
A variety of vapor recovery systems exist and most are approximately 9Q%
efficient. These systems include: liquid absorption (which utilizes a solvent
with low vapor pressure to absorb vapors); vapor compression (which compresses
collected vapor into the liquid state); vapor condensation (which utilizes a
refrigerated brine to condense collected vapor); and adsorption (whereby the
collected vapor is adsorbed on activated charcoal or silica gel).
Control of Flue Gases from Steam and Power Generation. Depending upon the
fuel used for on-site steam and power generation at a Lurgi SNG facility, the
combustion flue gases may require control of particulate, NQV and sulfur emis-
A
sions. Indeed, fuel combustion would generally represent the largest source
of potential emissions of SO, NO and particulates in a Lurgi SNG plant. When
X X
coal and/or by-product tars/oils/phenols are utilized as fuel, particulate and
SOX control will likely be required in order to meet state and federal emission
limitations. Federal NSPS for fossil fuel-fired steam generating plants have
been promulgated and the control technology for meeting these standards is
reasonably well established. Flue gas emissions at Lurgi SNG facilities are
not expected to involve any major new problems for these established control
techniques.
The major candidate particulate control techniques applicable to combustion
flue gas from large boilers are electrostatic precipitators and fabric filters.
The key features and costs of these types of processes have been presented in
Table 4-2. Although not reflected in the cost data shown in Table 4-2, more
recent data indicate that for large scale boiler application where high removal
160
-------
efficiency is desired, fabric filters would be more economical than electro-
(73)
static precipitatorsv '. In recent years the trend in the electric utility
industry has been toward the use of fabric filters, mainly due to increasingly
strict particulate control requirements. SO control in flue gases from coal
X
and/or by-product combustion can be accomplished utilizing any of a number of
FGD systems. Four such processes which have perhaps the best commercial pros-
pects were discussed in Section 4.2.3. Of these processes, lime or limestone
scrubbing appears to be the most commercially demonstrated process(es) and most
electric utilities which are planning to install FGD systems have chosen
this option to meet near term needs.
Onsite steam and power generation requirements may also be met using as
fuel low to medium Btu gas produced ciy air blown gasifiers. In this case,
particulate control is accomplished as part of the gas quenching/tar and oil
separation and hence additional particulate control is not required for the com-
bustion flue gases. Sulfur compounds (mainly FLS) would be removed from the fuel
gas using any of a number of commercially available acid gas removal processes.
For hLS removal from low/medium Btu gas, the most economic choices are either
Selexol absorption with Claus sulfur recovery or Stretford absorption/sulfur
( 74 2'. }
recovery^ ' . One desirable feature of these processes is that they are
selective for the removal of hLS over C02. (For fuel use, removal of (XL is
unnecessary or, in the case of turbine use, undesirable.) The Selexol process
uses dimethyl ether of polyethylene glycol for physical absorption of acid gases
and can achieve a high degree of selectivity for h^S. The separated H2S is
concentrated enough for Claus processing. Tail gas treatment would ordinarily
be required for the Claus plant. Unfortunately, Selexol solvent also removes
naphtha from feed gases and hence a hydrocarbon removal step between the Selexol
and the Claus unit is necessary to recover the fuel value of the absorbed hydro-
carbons and to avoid problems in the Claus plant.
Stretford absorption/sulfur recovery was described in Section 4.2.3. For
application to fuel gas, the required degree of total sulfur removal is not
likely to be as stringent as in the case of concentrated acid gas treatment.
The Stretford process has the advantages of achieving sulfur removal and recov
ery in a single process and of not removing hydrocarbons, CO and H£ from the fuel
gas.
161
-------
The relative economics of coal/by-product use vs. fuel gas use for onsite
steam and power generation are not well known at this time. At least one
economic study has predicted that coal gasification/combined cycle systems for
electricity generation (with Selexol sulfur removal from fuel gas) are cost
competitive with conventional coal-fired boilers using state-of-the-art FGD
processes^. Generally, the fuel gas option will result in lower total emis-
sion of SO , particulates and N0x-
The combustion flue gases will contain varying amounts of NOX depending
on the fuel type used (coal, fuel gas or gasification by-products) and combustion
conditions. Control of NO emissions can be achieved through combustion modi-
)\
fication and/or use of add-on processes. Combustion modification, which may
include staged-combustion, use of low excess air, reduction of air preheating,
steam and water injection and reduced heat release rate, may result in as much
as 60% reduction in NO emissions from gas-fired boilers. Somewhat lower effi-
X
ciencies are obtained when fuels containing nitrogen are used (e.g., coal and
tar). Add-on processes generally fall into two categories: dry processes and
wet processes. Most dry processes involve catalytic reduction of NO with
A
ammonia which is added to the flue gas. Wet processes involve a combination of
absorption and oxidation or reduction for NO removal. Removal efficiencies
/\
greater than 90% can be obtained with dry or wet processes. Only a few of the
add-on NO control processes have been developed commercially. Applications
X
of the few processes which have attained commercial status have been limited
to facilities in Japan and to oil-fired utility and industrial boilers.
Control Options in Integrated Facilities and Associated Emissions, Costs
and Energy Requirements. The overall effectiveness and economics of air pollu-
tion control in Lurgi SNG facilities cannot be properly assessed without an
examination of integrated systems for management of gaseous waste streams. A
number of factors influence the total emissions and air pollution control costs
for an integrated Lurgi SNG facility. These include the coal sulfur content,
the plant size, the design of the Rectisol acid gas removal unit, the fuel used
for onsite steam and power generation, and the specific air pollution control
processes employed. Table 4-13 summarizes the estimated total emissions for
the five proposed commercial Lurgi SIIG plants. As noted in the table, the
162
-------
TABLE 4-13. SUMMARY OF ESTIMATED CONTROLLED EMISSIONS FOR PROPOSED COMMERCIAL LURGI SNG FACILITIES
(IN KG/HR)
Proposed
Project
El Paso'2'22'
so2+
N0x
NMHC
Particulates
Gasification Plant
Feed Lockhopper
Acid Gases* Vent Gas
116 6
24
2523 17
1
CO 811 295
WLSCO(3'
so2
NOX
NMHC
Particulates
CO
ANG(15)
so2
NMHC
Particulates
CO
(14)
so2
N0x
NMHC
Particulates
CO
Dunn Co.'13'
so2
N0x
NMHC
Particulates
CO
77 33
451
—
545 11
164 26
310
460 12
—
--
On site
Fuel Combustion
41
70
--
265
720
33
-_
640
500
45
77
164
1035
1210
140
--
860
1300
180
--
Facility
Total
163
94
2640
1
1106
375
720
451
33
__
1196
500
77
--
1125
1520
140
_-
1332
1300
180
__,
Factors Affecting Emissions
Low sulfur/HHV ratio coal, high
degree of H,S removal in Stretford unit,
desulfurizen fuel gas used as plant
fuel, Stretford off-gases not incinerated
Low sulfur/HHV ratio coal, combination
of Stretford and Claus sulfur recovery,
tail gas treated with coal -fired boiler
flue gases for SO,, removal
Medium sulfur/HHV ratio coal , Stretford
efficiency lower than that in the El Paso
design, coal-fired boiler used with FGD
Very low sulfur/HHV ratio coal, no FGD
employed on coal -fired boilers, Stretford
efficiency lower than that in the El Paso
design
Same as for ANG design
*Includes sour water stripper overhead
fAll sulfur emissions in this table are reported as SO. equivalent
+ *-
^Included in combustion emissions.
-------
emissions vary widely reflecting differences in plant designs (including power/
steam generation systems selected), control systems used and coal feed charac-
teristics.
For analysis purposes a limited number of options are examined in this
section based on certain assumptions as to the plant size, coal sulfur content,
etc. As noted previously, concentrated acid gases from the Rectisol unit and
flue gases from steam and power generation are the most important gaseous
streams from the standpoint of control requirements in an integrated plant. Con-
trol of dust emissions from coal preparation has been discussed earlier. Rela-
tively small volume waste streams such as transient waste gases and catalyst
deco.mmissioning offgases would be handled in plant flares. Sour water stripping
and depressurization gases would generally be combined with bulk acid gas streams
or incinerated. Lockhopper vent gases would be recovered to a major extent, with
only a small volume of such gases being discharged to the atmosphere.
Five control options have been identified for the management of Rectisol
acid gases and combustion flue gases in an integrated facility. Table 4-14
presents the key features of these options. These options cover the range of
sulfur recovery/FGD systems which have been proposed for use in commercial Lurgi
plants or which would be potentially suitable for such applications. Emissions
associated with each option have been estimated based upon the flow diagrams
and the engineering assumptions described in Appendix B. A summary of the
estimated emissions is presented in Table 4-15. For the five options reviewed,
the contribution of treated Rectisol acid gases to total plant S0? emissions
ranges from around 10 to 90%, depending on whether sulfur recovery tail gas
treatment is utilized and whether desulfurized fuel gas is used for steam and
power generation. Option 4, in which all plant flue gases are treated in an
FGD unit, has the highest total S02 emissions. Option 1, in which acid gases
are treated in a Stretford unit and the off-gases from the Stretford unit and
the combustion flue gases are handled in an FGD unit, achieves the lowest S02
emissions. Emissions of HC and CO associated with incinerated sulfur recovery
tail gases constitute from 20 to 75% of the total plant HC and CO emissions.)
As would be expected, NO and particulate emissions are not greatly influenced
A
by sulfur and HC/CO control alternatives employed.
The estimated costs for the five options are shown in Table 4-16. Hithin
the accuracy of the cost estimates, the costs associated with Options 1, 3, 4
164
-------
TABLE 4-14. FEATURES OF OPTIONS CONSIDERED FOR AIR POLLUTION CONTROL IN INTEGRATED LURGI
SNG FACILITIES*(2,3,13,14,15)
Option
No.
Key Features
Proposed Commercial
Project(s) Whose
Designs Have Similar
Features
Comments
1
C5-1
cn
• Stretford unit handles combined
acid gases from Rectisol.
• Stretford offgases incinerated
in superheater furnace followed
by S02 removal in conjunction
with coal-fired boiler flue
gases.
• On-site energy needs met by
burning coal, tar, oil, naphtha
and phenols.
• Stretford unit handles combined
acid gases from Rectisol.
t Stretford offgases incinerated
in gas turbine generators.
• On-site energy needs met by
fuel gas which has been desul-
furized in Stretford unit.
• All Rectisol acid gases are
sent to ADIP unit for concen-
trating H2$ and removing
hydrocarbons.
• Claus plant used for sulfur
recovery followed by Beavon/
Stretford tail gas treatment.
• Coal supplies all energy needs
on site and boiler flue gases
are treated for S02 removal.
ANG
Wyoming
El Paso
WESCO
Dunn Co.
ANG design does not feature coal
use for on-site energy needs. Power
is purchased from off-site source.
All gasification byproducts are
burned rather than marketed.
Wyoming design is similar to ANG
except that coal rather than gasi-
fication byproducts are burned to
supply plant energy needs.
In the El Paso design, all on-site
energy needs are met by fuel gas.
Byproducts are sold and not used for
fuel on site. Stretford offgas is
incinerated in a catalytic converter
rather than in turbines.
In WESCO and Dunn Co. designs, only the
rich HpS Rectisol stream is sent to
ADIP/CTaus/tail gas treatment. The
lean H2S stream is sent to Stretford.
Thus, WESCO and Dunn Co. are a combina-
tion of Options 1 and 3.
-------
TABLE 4-14. CONTINUED
Option
No.
Key Features
Proposed Commercial
Project(s) Whose
Designs Have Similar
Features
Comments
cr,
cr>
e All acid gases are directly
routed to utility boiler for
incineration. 502 is subse-
quently removed from flue
gases.
9 Rectisol unit is designed to
selectively recover about 30%
of feed H2$ as a concentrated
stream suitable for Claus
processing.
f Stretford handles lean H2S
stream from Rectisol.
• Claus plant tail gas treat-
ment handles rich F^S stream
from Rectisol.
• Stretford tail gas is incin-
erated with supplemental
fuel.
• Steam and power are supplied
by coal-fired boiler. Flue
gases are treated for S02
removal.
No proposed commer-
cial facility has
this feature.
WESCO
Dunn Co.
Stretford offgases are incinerated
in utility boiler in WESCO and Dunn
Co. designs rather than separately
as in Option 5.
*See Figures B-l through B-5 in Appendix B for the flow diagram for the options.
-------
TABLE 4-15. SUMMARY OF ESTIMATED EMISSIONS FOR AIR POLLUTION CONTROL OPTIONS
(KG/MR)
Option
No.
1
2
3
4
5
Pollutant
so2
HC
CO
NOX
Particulates
so2
HC
CO
NOX
Particulates
S02
HC
CO
NOX
Particulates
S02
HC
CO
NOX
Particulates
SO 2
HC
CO
NOX
Particulates
Contribution from
Rectisol Acid Gases
25
30
100
300
Negl igible
250
10
25
100
Negligible
20
20
50
Negl igible
Negl igible
1200
2*
5
100
Negligible
240
20
80
100
Negligible
Contribution from
Fuels
150
40
140
900
60
20
37
75
1400
Negl igible
280
20
50
1100
50
300
18
45
1000
50
280
20
50
1100
50
Total
170
70
240
1200
60
270
47
100
1500
Negl igible
300
40
100
1100
50
1500
20
50
1100
50
520
40
130
1200
50
*See Appendix B for flow diagrams, assumptions, and detailed calculations.
167
-------
TABLE 4-16. ESTIMATED COSTS FOR AIR POLLUTION CONTROL OPTIONS (103 DOLLARS,
1978 BASIS)
Stretford
Capital
Annual operating
Electrostatic Precipitator
Capital
Annual operating
Wellman-Lord
Capital
Annual operating
ADIP
Capital
Annual operating
Claus
Capital
Annual operating
Beavon
Capital
Annual operating
Incineration
Capital
Annual operating
Lurgi Fuel Gas Production
Annuali zed total cost
Total Capital
Annual Capital1"1
Annual Operating
TOTAL ANNUAL COST
1
9,681
2,960
3,365
65
22,684
3,473
--
--
--
--
--
--
5,300
1,700
--
42,830
7,709
8,198
15,907
2
11,745*
3,591*
--
--
--
--
--
--
--
--
--
--
5,300
1,500
ll,054t
17,045
3,068
16,145
19,213
3
--
--
15,466
301
26,343
4,033
3,988
792
4,475
974
3,964
154
4
--
--
15,966
311
27,199
4,164
--
--
--
--
--
--
1
0 5,300
0
--
53,736
9,672
6,254
15,926
1,700
--
48,465
8,723
6,175
14,898
5
6,694
2,057
10,480
208
17,848
2,732
--
--
1,288
273
1,220
35
14,000
1,100
--
51,300
9,234
6,391
15,625
*Stretford units are used for both Rectisol acid gas treatment and for fuel
in Option 2. Although the fuel gas Stretford is designed for 100 ppmv H2S
Stretford for 10 ppmv H2S, costs on a "per tonne sulfur removed" basis are
the same for both units.
The annualized cost of Lurgi fuel gas production is estimated from data in
It is assumed that the gas fired boiler in Option 2 would cost the same as
fired boilers in other options and hence, boiler cost need not be included
purposes.
Depreciation and interest 0.14 x total installed cost. Taxes, insurance and administra-
tion 0.04 x total installed cost.
gas treatment
and the Rectisol
assumed to be
Reference 74.
coal/byproduct
for comparison
168
-------
and 5 may be considered to be nearly the same.* The higher cost for Option 2
is due to the use of air-blown Lurgi gasifiers to produce fuel gas for onsite
steam and power generation. In all options most of the air pollution control
cost is attributed to the costs associated with pollution control for steam
and power generation (use of FGD systems/electrostatic precipitators or clean
fuel gas). As discussed in Section 2.1.5, the capital and annual operating
r o
costs for a 7 x 10 Nm /d (250 MMscf/d) commercial Lurgi SNG plant have been
estimated at approximately $2 billion and $300 million, respectively. Based
on these plant costs, the estimated air pollution control costs shown in Table
4-15 represent about 2% to 3% of the capital cost and 4% to 5% of the operating
cost.
Table 4-17 presents the estimated energy requirements for air pollution
control under the five options. (See Section 7.3 for assumptions and detailed
calculations.) The estimated values range from about 65 million to 180 million
kcal/hr (260 million to 720 million Btu/hr) for a 7 x 106 Nm3/d (250 x 106 scf/d)
Lurgi SNG plant, or about 1.5 to 3.1% of total plant input energy. Option 3,
which employs ADIP/Claus/Beavon/Stretford processes for treatment of Rectisol
acid gases,would have the lowest overall energy requirement while Option 2,
which features fuel gas production,is estimated to have the highest requirement.
Options 1 and 5 would have about the same energy requirements. In Options 1,
3 and 5 incineration accounts for about one third of the total estimated energy
requirement while sulfur removal/recovery from acid gases accounts for over
50% of the total. Except for Option 2, from 12 to 25% of the total energy
requirement is attributed to particulate and S02 removal from flue gases.
The estimated emissions, costs and energy requirements presented above for
Options 1 through 5 have been based on the use of western coal (0.7% sulfur,
4670 kcal/kg or 8400 Btu/lb HHV). A few generalizations can be made on the
impact of using eastern coals (higher sulfur content and HHV) on emissions,
costs and energy requirements for air pollution control. Use of coals with
higher heat content but the same sulfur percentage should produce Rectisol acid
gases containing somewhat more C00 relative to H2$ and COS. This would not
*The cost estimate for Option 5 does not include the expected higher cost asso-
ciated with a modified Rectisol process design to produce a more concentrated
acid gas for direct feeding to the Claus plant.
169 ,
-------
TABLE 4-17. ESTIMATED ENERGY REQUIREMENTS FOR AIR POLLUTION CONTROL OPTIONS* (MILLION KCAL/HR)
Process/Energy Component
Stretford
Fuel
Steam
Electricity
ADIP
Steam
Electricity
Claus
Steam
Electricity
Beavon
Fuel
Steam
Electricity
Well man- Lord
Steam
Electricity
Electrostatic Precipitator
Electricity
Incineration
Fuel Gas Production
TOTAL
Options
1
24.00
4.20
21.10
--
--
--
--
--
10.52
2.12
0.29
28.00
90.23
2
27.91
4.88
24.5
--
--
--
--
--
--
__
121
178.29
3
--
--
22.57
0.97
1.97
(21.63)t
0.49
10.05
3.10
4.25
16.39
3.39
1.21
22.37
65.55
4
--
--
--
--
--
..
--
--
94.25
19.51
1.25
25.19
140.20
5
16.67
2.92
14.66
--
0.66
(7.23)f
0.16
3.35
1.03
1.42
16.39
3.39
0.82
27.39
81.63
*See Section 7.3 for flow diagrams, assumptions and detailed calculations.
tParentheses indicate credit for by-product steam.
-------
greatly impact the cost or performance of Stretford, Claus, Beavon, or incinera-
tion processes since the major parameters affecting the cost/performance of these
processes are the total sulfur or hydrocarbon loadings rather than concentra-
tions or total gas flow rates. On the other hand, the costs of FGD units and
electrostatic precipitators increase in direct proportion to the gas flow rate
so that some savings may be realized with particulate and S(L removal in SNG
plants using higher heat content coals for steam and power generation. The
sulfur emissions from either acid gas treatment and flue gas treatment processes
are not expected to be significantly affected by the heat content of the coal
(provided that the sulfur content remains constant). The use of higher heat
content coals results in some increase in the HC and CO in the treated Rectisol
acid gases.
When higher sulfur coals are used as feed to Lurgi gasifiers, HLS and COS
levels are expected to increase in Rectisol acid gases in approximate propor-
tion to feed coal sulfur content. If such acid gases are treated in a Stret-
ford unit, the COS will not be removed and will be emitted to the atmosphere
unless the Stretford tail gas is further treated. When Rectisol acid gases are
handled by the Claus process, tail gas sulfur loading will be in approximate
proportion to feed loading. Uhen catalytic reduction processes such as Beavon
are used for tail gas treatment, an atmospheric emission of about 250 ppmv
total sulfur is expected regardless of feed gas sulfur loading and hence the
coal sulfur content.
An increase in sulfur content of coal fed to utility boilers will generally
result in an approximately proportional increase in flue gas sulfur emissions
after treatment by S02 removal systems. Similarly, Claus or Stretford tail gas
treatment by S02 removal systems will result in an approximately constant per-
cent removal, independent of the feed gas sulfur level and coal sulfur content.
Hence, the use of higher sulfur coal will increase sulfur emissions for the
S0£ removal systems.
The general effect of increasing feed coal sulfur content will be to in-
crease total plant sulfur emissions. The contribution to total emissions from
steam and power generation will usually be greater for high sulfur feeds.
When all SNG plant sulfur-bearing waste gases are combined for treatment by
SOp removal processes (e.g., Option 4), the relative contribution of flue gases
171
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and acid gases to total emissions will also be independent of feed sulfur
levels.
In general, the air pollution control energy requirements are expected
to increase with the rise in the coal sulfur content, due to the increase
loading on (and regeneration/sludge disposal requirements for) FGD and sulfur
recovery systems. A rise in the heat content of the coal increases the acid
gas volumes to be treated and hence the energy requirement for acid gas/tail
gas treatment for sulfur, CO and HC control.
4.3 WATER EFFLUENT CONTROL ALTERNATIVES
This section defines and evaluates water pollution control alternatives
and practices which may be employed in commercial Lurgi SNG facilities. Figure
4-2 presents the process modules for treatment of the aqueous waste streams
identified in Section 3.6. One additional type of aqueous waste shown in Figure
4-2 (waste sorbents/reagents), which was not discussed in Section 3.6, is also
discussed in this section. Table 4-13 presents the wastewater treatment pro-
cesses in each module which would have potential application to wastewater
streams in a commercial Lurgi SNG system. The discussion which follows is
organized according to the origin of wastewater streams in Lurgi SNG facilities.
TABLE 4-13. WASTEWATER TREATMENT PROCESSES POTENTIALLY APPLICABLE TO COMMERCIAL
LURGI SNG SYSTEMS
Oil and Suspended Solids Removal: gravity separation (API separators),
flotation, coagulation-flocculation, filtration
Dissolved Gases Removal: conventional steam stripping, Chevron WWT,
Phosam-W, Lurgi-Chemi Linz AG ammonia recovery processes
Dissolved/Particulate Orgam'cs Removal: Phenosolvan process, biological
oxidation, chemical oxidation, activated carbon adsorption,
adsorptive resins
Separated Tar/Oil and Sludge Treatment: emulsion breaking, gravity
thickening, centrifugation, vacuum filtration, drying beds
Dissolved Inorganics Removal: ion exchange, reverse osmosis, electro-
dialysis, freezing, electrochemical treatment, distillation
Ultimate Disposal: evaporation ponds, deep well injection
172
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CO
"NUMBERS REFER TO STREAMS IN
FIGURES 2-2, 2-3, AND 2-4.
H3) (H2S 1
Figure 4-2. Process Modules for Water Pollution Control in Lurgi SNG Facilities
-------
4.3.1 Coal Pretreatment and Handling
No aqueous process waste is produced in the coal preparation operation.
Coal pile runoff, however, is generally associated with coal storage and hand-
ling. The runoff is most effectively controlled through measures to minimize
runoff generation (e.g., by division of storm runoff from adjacent areas) and
collection of the pile runoff for treatment with other plant wastewaters and/or
process use.
4.3.2 Coal Gasification
The ash quench slurry is the only aqueous waste stream associated with the
gasification operation. Commonly, low quality plant waters are used to quench
ash. The resulting slurry is transported to a ash thickening unit where bulk
solids are separated for disposal and the thickener overflow is recycled or
sent to further treatment by clarification in a settling basis or lagoon.
The thickeners and clarifiers which would be used in commercial Lurgi SNG
facilities would be similar to the systems employed in the utility and other
industries for the management of high solid content ash slurries and inorganic
sludges. The specific design and costs of these systems are affected by the
characteristics of the slurries handled (i.e., solids concentration, settle-
ability, temperature, etc.) and the desired degree of thickening and clarifica-
tion. The desired degree of thickening and clarification are in turn dependent
upon the method of sludge and clarified effluent disposal (e.g., use of onsite
sludge lagoons, transportation and disposal of sludge to offsite facilities or
return to mines; ultimate disposal of effluent by solar or forced evaporation,
and discharge to receiving water or reuse in the process). In a Lurgi SNG
facility, therefore, the design and cost of ash slurry thickening/clarifica-
tion cannot be considered independent of the total plan for wastewater and
solid waste management for the facility. At present no engineering data are
available on the characteristics of Lurgi ash slurry to permit accurate estima-
tion of the performance and costs of thickener/clarifiers for handling Lurgi
ash slurry. Based on applications to municipal wastewaters and sludges, the
capital cost for a 34-m (112-ft) diameter thickener would be about $280,000;
the annual operating cost for such a unit is about $18,500(75).
174
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4.3.3 Gas Purification
Two aqueous waste streams are generated as a result of purification of the
raw product gas. These are raw gas liquor and methanol/water still bottoms.
The raw gas liquor is ordinarily treated for the recovery of tars and oils,
phenols and ammonia. The still bottoms are generally treated in the ammonia
recovery unit.
Tar and Oil Recovery. In the designs for all proposed Lurgi SNG facilities,
raw gas liquor treatment for tar/oil/water separation consists of dissolved
gas flotation/gravity settling. As discussed in Section 2.2.6, tar/oil separa-
tors employed in Lurgi systems operate on the flotation principle in that the
reduction in pressure results in the release of dissolved gases which float oil
to the surface for recovery. These separators achieve a high removal efficiency
(up to 99% suspended tar and oil removal^ ') and are very cost effective since
they take full advantage of the inherent characteristics of the raw gas liquor
(i.e., having dissolved gases under pressure). The capital cost for a Lurgi tar
/TO ,-
and oil separation unit in a 7 x 10 Nm /d (250 x 10 scf/d) SNG plant is estimated
at about $13 million (1975 dollars) or about 2% of the total plant investment^25).
Alternatives to the Lurgi tar/oil/water separation process, which include gravity
separation using API separators, gravity separation enhanced by chemical coagula-
tion and flocculation, and filtration, do not offer any cost or performance
advantage and hence have not been featured in any of the designs for proposed
commercial Lurgi SNG facilities.
Phenol Recovery. The treated gas liquor from the tar and oil recovery
system contains a high concentration of phenols (see Tables 3-20 and 3-22) which
can be recovered as a valuable by-product. The Phenosolvan process is usually em-
ployed in Lurgi systems for phenol recovery (see Section 2.2.6 for process des-
cription). Most of the available data on the performance of the Phenosolvan
process are for the unit in Sasolburg, South Africa. This unit is reported cap-
able of achieving an effluent containing 1 ppm of steam volatile phenols and
60 ppm of total phenols'4 . The detailed characteristics of the influent fed
to the Phenosolvan unit (separated gas liquor) and the effluent after phenol
and ammonia recovery (cleaned gas liquor) have been presented in Tables 3-22
and 3-24. As indicated by the data in these tables, the Phenosolvan and the
stripping processes can achieve significant removals of organics other than
175
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phenols; a total COD removal of about 90% is achieved. The high degree of
organics removal reduces the organic loading on subsequent wastewater treatment
for pollution control.
No capital and operating cost information could be obtained in this study
on the use of the Phenosolvan process for phenol recovery. However, estimates
have been made for the cost of a solvent extraction system (benzene as the sol-
vent) for application to gas liquor. For a typical unit in a commercial size
plant handling about 8000 1/min (2000 gpm) of gas liquor containing 6000 ppm
of total phenol, a capital cost of $9.2 million and a total annual cost of $3.6
million have been estimated^76^ (1977 dollars). Considering the very high con-
centration of phenols and the nature and concentration of other organic and in-
organic constituents in the Lurgi gas liquor, solvent extraction appears to be
the most cost effective method for handling this stream. This has been confirmed
in a recent engineering study^ ' where solvent extraction was compared with two
alternative treatment methods involving resin adsorption and biological oxida-
tion.
Ammonia Recovery. Lurgi gas liquor contains a high concentration of
ammonia (and a smaller concentration of hydrogen sulfide, hydrogen cyanide and
carbonyl sulfide). Ammonia is commonly recovered as a saleable by-product by
stripping. The recovery of ammonia also significantly reduces the waste loading
on downstream wastewater treatment units. Although in a Lurgi SNG facility
stripping is primarily aimed at the recovery of ammonia from the separated gas
liquor, the process also results in the generation of an overhead gas contain-
ing recoverable amounts ofH2$. As discussed in Section 4.2.3, the overhead gas
is usually treated in combination with the Rectisol acid gases in a sulfur re-
covery unit.
Stripping can be effected by contacting the wastewater with a stripping
medium such as steam, flue gas, nitrogen, air and carbon dioxide. The most
common stripping medium is steam and the stripping operation is usually con-
ducted in a tower (packed or trays). Acid (for sulfide) or alkali (for ammonia)
may be added to the raw wastewater to improve stripping efficiency. Steam strip-
ping is widely used in refineries for the treatment of sour waters containing
ammonia and/or hydrogen sulfide. In these applications the stripped gases are
either disposed of by flaring or processed for the recovery of anhydrous or
176
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aqueous ammonia or ammonium sulfate, elemental sulfur (in a Claus plant) or
sulfuri.c acid. In many cases, the flaring of stripper off-gases is being phased
out due to SO,, and N0x limitations. Conventional steam stripping of the refin-
ery sour water can achieve up to 95% removal of NH~ and greater than 99% removal
of H9S, with residual NHL and H9S concentrations typically less than 50 ppm and
(58)
10 ppm, respectivelyv '. Since low molecular weight phenols are somewhat vola-
tile, sour water stripping can also result in the partial removal of phenols
(up to 70% in refinery applications; in these applications residual phenol
levels of 30 to 110 ppm have been reported).
Two patented applications of steam stripping which generate separate con-
centrated riH_ and H2$ streams are the Chevron WWT and the USS Phosam W processes.
In the Chevron process separate towers which operate under different pressures
and temperatures are used for NH~ and H^S stripping. The residual H?S contained
in the product ammonia stream is removed by scrubbing the gas stream with liquid
ammonia. The treated gas is then processed to convert the gaseous ammonia to
anhydrous or aqueous ammonia or to ammonium sulfate. The treated wastewaters
from the Chevron process can have residual H9S and ammonia as low as 5 and 50
(jr,\ <-
mg/1, respectivelyv;. The USS Phosam W process, which has been designed for
application to coke oven gases, features the circulation of ammonium phosphate
solution in the upper portion of the stripper to absorb the ammonia from the
product stripping gases, leaving an H?S stream containing low levels of ammonia.
The ammonia-rich phosphate solution is steam stripped in a separate vessel at
elevated pressure and temperature, producing an ammonia-rich stream which is
subsequently condensed in a fractionating column to produce anhydrous ammonia.
Removal efficiencies of over 99% for both H0S and NH- are claimed for this
( 1 ) ^3
processv '.
The Chevron WWT and USS Phosam W processes have not been employed at pilot
or commercial gasification facilities to date. Conventional steam stripping
with ammonium sulfate recovery, however, has been used at the SASOL gasifica-
tion complex^44). The USS Phosam W process has been incorporated into the de-
(15)
sign of the proposed ANG (North Dakota) SNG plantv' '. A recent engineering
study by C. F. Braun and Company comparing various stripping processes for
application to coal gasification wastewaters indicates that both USS Phosam W
and the Chevron WWT processes have higher capital and operating costs than
177
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(79)
conventional sour water stripping without by-product recovery . The value
of the recovered ammonia, however, significantly offsets the added costs for
both processes.
c ,.
One cost estimate for a Phosam W plant handling 13.7 x 10 1/d (3.6 x 10
gal/d) of sour water* is that a capital investment of 8.2 million 1975 dollars
is required^76). Operating costs for such a plant are about one dollar/1000 A
($4/1000 gals) of feed. Sale of ammonia offsets about $0.14/1000 £ ($0.55/
1000 gals) of the cost.
Lurgi-Chemi Linz AG is a Lurgi-licensed stripping process for ammonia re-
covery, which is reported to be in service at certain Lurgi facilities
abroad 4'. No data, however, are available on the operating features and
economics of this process.
Treatment of Rectisol Methanol/Water Still Bottoms. This stream represents
a relatively small flow compared to raw gas liquor (about 6% of gas liquor
(°i}
volumev° ') and contains low levels of dissolved gases and organics. Ordinarily,
this stream would be combined with gas liquor after tar/oil separation or phenol
removal and treated for ammonia removal.
4.3.4 Gas Upgrading
Methanation and dehydration condensates are the only aqueous wastes gener- :
ated in the gas upgrading operation. These condensates, which contain only very
low levels of dissolved solids and no ammonia and H^S, are considered "clean"
streams. After degasification (to remove methane and carbon dioxide), the con-
densates would be suitable for use as boiler feed water. Alternatively, the
condensates can be used as cooling tower makeup or as process water.
4.3.5 Auxiliary Processes
As discussed in Section 3.6.5, major aqueous waste streams associated with
auxiliary processes are clean gas liquor, filter backwashes, waste sorbents and
reagents, cooling tower and boiler blowdowns and miscellaneous plant wastewaters.
Processes for the control of each of these classes of wastewaters are reviewed
in this section. In addition, a discussion of the water pollution control and
ultimate wastewater disposal options in an integrated facility is provided.
^Approximate sour water flow rate for the proposed El Paso-Burnham Lurgi SNG
Plant (7 x 106 Nm3/day or 250 x 106 SCF/day).
173
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Treatment of Clean Gas Liquor. As noted in Tables 3-22 and 3-24, the clean
gas liquor from the ammonia recovery unit contains considerable organic loading,
and from this standpoint is the most important waste stream in a Lurgi SNG plant.
The clean gas liquor can be treated by any of the number of conventional waste-
water treatment processes for organics removal. These processes include: bio-
logical oxidation, chemical oxidation, activated carbon adsorption and organic
resin adsorption.
In biological oxidation, the dissolved and/or collodial organics are con-
verted to inorganic end products and microbial cells by the action of micro-
organisms. The resulting biomass (sludge) is subsequently removed by gravity
separation. Although biological oxidation can be conducted under anaerobic
(absence of oxygen) conditions, for most applications aerobic (in the presence of
oxygen) treatment is preferred because of the higher efficiency and lower costs.
Biological treatment has been widely employed for the treatment of industrial
wastes and municipal sewage. Table 4-19 lists the most commonly used biological
treatment systems including reported efficiency ranges for the removal of BOD,
COD, SS, oil, phenols and sulfide in applications to refinery wastewaters. As
noted in the table, biological treatment can result in up to 90% removal of the
biologically oxidizable compounds. Although not classified strictly as waste
stabilization ponds, evaporation and retention ponds which are widely used in
industry for ultimate disposal of raw or treated wastewaters, and which serve
as tertiary treatment basins following biological treatment or as temporary
storage ponds for controlled effluent discharge, do achieve some biodegradation
of organics.
The use of pure oxygen (in place of air) in the biological treatment of
wastewaters by the activated sludge process has received considerable attention
in recent years and a number of pure oxygen activated sludge plants are currently
in operation handling municipal sewage and a variety of industrial wastewaters.
Compared to the conventional air activated sludge process, the pure oxygen process
is claimed to have several advantages, including higher efficiency and through-
put rate, less sludge production, superior characteristics of the sludge, and
lower overall costs. The use of the oxygen activated sludge process in a Lurgi SNG
plant is especially attractive since such a plant employs onsite oxygen produc-
tion and hence ,a source of oxygen would be available for wastewater treatment.
179
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TABLE 4-19. EFFICIENCY OF BIOLOGICAL TREATMENT FOR PETROLEUM REFINERY
EFFLUENTSlSl)
Biological Treatment
Method
Activated sludge
Trickling filters
Waste stabilization
pond (aerobic)
Aerated lagoons
Cooling tower
oxidation
I
Spray Irrigation
Parameter*
(55 Removal)
BOD
88-90
60-85
40-95
75-95
90+
95+
COD
60-85
30-70
30-65
60-85
90+
90+
Suspended
Solids
-
50-80
2-70
40-65
-
99+
Oil
-
50-80
50-90
70-90
-
70-90
Phenols
95-99+
-
-
SO-99
99.9
99.9
s"
97-100
-
-
95-100
-
99+
*Approximately 70 percent of thiocyanates are removed by all processes.
Cooling towers for biological treatment of selected waste streams have
been used successfully in refineries and have been demonstrated at the SASOL
(South Africa) gasification plant ^° '. Cooling towers provide ideal tempera-
tures and surfaces for biological activity. The oxygen required by micro-
organisms are provided by extensive aeration which accompanies the cooling
process. In refinery applications, phenolic wastewaters have been used as
cooling water make-up and more than 99% destruction of phenols has been
( SI)
reported^ '. In a demonstration program at the SASOL plant, the ammonia
stripper bottoms have been used as cooling tower make-up. In this program
the bioactivity, foaming, fouling and corrosion which may be expected from
the use of this wastewater for cooling water make-up have been evaluated and
the results have been used as a basis for the design of a cooling/oxidation
tower system for the proposed El Paso Burnham plant in New Mexico^ 2\ Other
proposed designs such as the American Natural Gas Company's design in North
Dakota also feature the use of towers for biological treatment^5^.
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Biological treatment may also be accomplished by the application of raw
or partially treated wastewaters to soils. Microbiological processes in the
soil can result in the degradation of most organics and the oxidation of
ammonia, sulfide, and other pollutants. In addition, physical adsorption and
filtration can result in the removal of phosphorus and some metallic elements.
Depending on the particular soil, the geographic location, and the rate of
wastewater application, net runoff or percolation may or may not be generated.
Continued application of wastewaters containing high levels of dissolved
solids to soils can result in salinity and/or alkalinity buildup to the point
of adversely affecting plant growth. The accumulation of certain trace ele-
ments and organics in soils may also present toxicity problems for plants or
herbivores.
Several factors affect the applicability and performance of biological oxi-
dation. These factors relate to wastewater constituent biodegradability, toxi-
city, pH. nutrient content and fluctuations in characteristics. As noted pre-
viously, organics in Lurgi gas liquor tend to be highly aromatic. While cer-
tain aromatic compounds such as simple phenols are readily degradable (at rela-
tively dilute levels), the more complex and substituted phenols, polycyclic
hydrocarbons, and heterocyclic organics are generally less readily degradable or
essentially non-biodegradable (e.g., pyridine). The biodegradability of the
(
organics in coal gasification wastewaters is currently under investigation
Some of the organics (e.g., phenols), trace elements (e.g., arsenic and
mercury) and inorganic anions (e.g., cyanide and thiocyanate) can be toxic to
microorganisms at high concentration levels. Biological processes are generally
most efficient when the pH of the wastewater is in the 6-8 range. The pH of the
wastewater also affects the toxicity of certain wastewater constituents. For
example, the toxicity of sulfide increases with decreasing pH. Nutrients such
as nitrogen and phosphorus compounds are necessary for microbiological growth.
A BOD:N:P ratio of approximately 100:5:1 is generally necessary for the biologi-
cal treatment of most industrial wastewaters. When a wastewater is deficient
in nutrients, such nutrients must be added to the raw wastewater prior to bio-
logical treatment. Lurgi gas liquor has a sufficient amount of nitrogen but is
deficient in phosphorus content. At the SASOL Lurgi plant where trickling
filters are used for biological wastewater treatment, phosphate is added to the
(44)
raw wastewater to allow efficient biological treatment^ '.
181
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Very little data are available on the performance of biological treatment
processes applied to either raw or clean Lurgi gas liquors. Bench-scale experi-
ments with Lurgi gas liquors, however, have indicated that up to 70% COD reduc-
tion from raw liquor can be achieved by biological oxidation, while only 20-35%
COD reduction is achieved with clean gas liquor^0 '. These results suggest that
solvent extraction for phenol recovery and stripping for ammonia recovery selec-
tively remove the biodegradable organics and that residual organics in clean gas
liquor would be less readily biodegradable.
Although actual cost data are not available for the biological treatment
of Lurgi gas liquor, the economics of four types of biological processes in coal
gasification applications have been estimated^ '. As indicated in Table 4-20,
the trickling filter-oxygen activated sludge system provides the lowest total
annual cost compared to the other listed alternatives. Also shown by the data
is the high cost of nitrification-denitrification processes.
In addition to biological treatment, three other types of organics removal
processes are potentially applicable to Lurgi gas liquors. These are chemical
oxidation, activated carbon adsorption, and resin adsorption. Chemical oxida-
tion processes using oxidants such as ozone and chlorine compounds have been
used in industry for the treatment of cyanide, sulfide and thiocyanate wastes.
Under proper conditions, ozonation may also affect destruction of biologically
refractory organics. The potential application of chemical treatment in a Lurgi
SNG facility would probably be limited to wastewater polishing after biological
treatment. Bench scale ozone treatment of raw gas quench condensate for
another gasification process (the Synthane process) has indicated that complex
organics (e.g., quinolines and indanols) and inorganics (e.g., SCN") can be
largely removed with adequate ozone dosage^ '.
Both granular and powdered activated carbon have been used for the treat-
ment of industrial and municipal wastewaters. Being a physical process, carbon
adsorption is unaffected by the presence of toxic constituents in the waste-
water and the fluctuations in wastewater characteristics.* Granular carbon is
*When granular carbon is used in beds, some biological growth becomes estab-
lished in the bed which contributes to the overall organic removal efficiency
(via biodegradation). In this case the treatment efficiency would be affected
by the presence of toxic chemicals or by wide fluctuations in wastewater
characteristics„
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TABLE 4-20. ESTIMATED COSTS ASSOCIATED WITH BIOLOGICAL TREATMENT OF WASTEWATERS FROM COAL
GASIFICATION PLANTS(76)
CO
CO
Air Activated Sludge
System
Air Activated Sludge/
Nitrification-
Denitrification System
Oxygen Activated
Sludge System
Trickling Filter-Oxygen
Activated Sludge System
Capital Costs
106$/1000 £ (106 $/1000 gals)
2.7 (10.1)
4.6 (17.6)
2.4 (9.09)
2.3 (8.68)
Total Annual Costs
Dollars/1000 £ (Dollars/1000 gals)
0.84 (3.2)
2.8 (10.61)
0.95 (3.61)
0.82 (3.10)
-------
used in fixed or moving columnar beds with either upward or downward wastewater
flow. Powdered carbon is generally mixed with the wastewater and is subsequently
removed by settling and/or filtration. Because of its relatively high cost,
the use of activated carbon adsorption for wastewater treatment would generally
be limited to:: (1) removal of residual organics from the biological treatment
effluents, when such removal is necessary; (2) treatment of wastewaters contain-
ing high levels of refractory organics or toxic chemicals; (3) use in combination
with chemical coagulation and filtration in a "physical-chemical" combination
treatment scheme in lieu of biological treatment, and (4) recovery of by-pro-
ducts (e.g., phenols) from the wastewaters. Except when used for by-product
recovery, the spent carbon is usually regenerated by thermal treatment. In
polishing of biologically-treated refinery and coke plant wastes, removal effi-
ciencies of up to 80% COD, 90% TOC, and over 99% phenols have been reported for
granular carbon adsorption^84'85'. Similar removal efficiencies would be ex-
pected for polishing applications to biologically-treated Lurgi clean gas liquor.
Capital and operating costs of granular carbon systems depend upon the specific
design and the nature and volume of the wastewater treated. One estimate of
1976 capital costs is as follows' ':
Adsorption Equipment
Flow Cost ($)
4 x 105 £/day (1 x 105 gal/day) 180,000
4 x 106 a/day (106 gal/day) 550,000
Regeneration Equipment
Carbon Usage Rate Cost ($)
910 kg/day (2000 Ibs/day) 270,000
8200 kg/day (18000 Ibs/day) 1,000,000
1976 operating costs have been estimated at about $0.68 per 1000 liters ($2.63
per 1000 gal) for every 1000 mg/1 of COD removed'76^.
Even though at the present time powdered and granular carbon are the sor-
bents of choice for removal of residual or refractory organics, other methods
are being developed as alternatives to carbon or for specialized applications.
184
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One of the more promising of these methods involves the use of macroreticular
polymeric adsorbents such as the Amberlite XAD-8 synthetic resin which have the
ability to sorb organics without any substantial inorganic exchange capacity.
The XAD-8 and similar resins have been successfully used for the decolorization
of Kraft pulp bleaching effluent. The sorptive resins are usually regenerated
by elution with aqueous solutions of proper pH or with organic solvents. Cost
data for large-scale resin application to wastewaters are generally not available.
Treatment of Filter Backwashes. Relatively small volumes of wastewaters
with high suspended solids/suspended organics would be generated by backwashing
of filters which are used ahead of the Phenosolvan unit (to remove suspended
solids from the separated gas liquor) and for raw water treatment. These waste-
waters would most likely be sent to the ash/water clarification system for
treatment.
Control of Haste Sorbents and Reagents. Sulfur recovery, air pollution
control and raw water treatment processes employed in a Lurgi SNG facility would
produce waste sorbents and reagents in the form of brines, sludges, and blow-
downs. The specific nature of such wastes will depend upon the specific pro-
cesses employed. As discussed in Section 4.2, major candidate pollution control
processes which generate waste sorbents/reagents include the Stretford process,
the Wellman-Lord process, the Chiyoda Thoroughbred 101 process, the lime/lime-
stone scrubbing process, and the Dual Alkali process.
The reagent purge in the Stretford process contains 200 to 300 g/1 of salts
(mainly thiosulfate, thiocyanate and carbonate salts of sodium with smaller
amounts of vanadate and anthraquinone disulfonate). There are two commercially
available processes for treatment of the Stretford purge which also provides
for the recovery of sodium and vanadium salts for reuse. Nittetu Chemical
Engineering (NICE) has developed the process shown in Figure 4-3 for recovering
the sodium value in the purge solution. The purge solution is first evaporated
at 333°K (140°F) and a partial vacuum of 13 Pa (2 psia) using the quenched com-
bustion gas at 363°K (194°F) for the energy source. The concentrated waste
(-50% salts by weight) is incinerated in a reducing atmosphere maintained by
limiting oxygen in the combustion process to 70 to 80% of the theoretical amount
required for combustion. The sodium salts converted to Na^CO^ and NaHC03 are
quenched with the combustion gas. The Na,,C03 solution from the quench tank is
185
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DESULFURIZATION SECTION
INCINERATION AND SODIUM RECOVERY SECTION
CO
en
Concentrated
waste liquid
Fuel gas
Exhaust go*
{for fuel)
Treated Gas
Combustion
gas (contains
v—
Inclneratorl
Gas
cooler 5QC
Quench Tank
Compressed
Condensate
Waste liquid
|to be
incinerated) Receiver
Recovered liquid (contains NoHS)
Figure 4-3. Treatment of Stretford Process Purge Solution by the NICE Process
(87)
-------
removed continuously and used as sorbent in the H2$ absorber of the Stretford
process.
Another commercially available treatment process which is licensed by
Woodall-Duckham USA Ltd. recovers both sodium salts and vanadium by a high tem-
/oo \
perature hydrolysis process^ .In this recovery-treatment process (see Figure
4-4) the liquid is first concentrated in an evaporator. The concentrated solu-
tion is fed to a high temperature hydrolyzer, where the solution is evaporated
to dryness and decomposed in a high temperature reducing environment. The reduc-
ing atmosphere is produced by stoichiometric combustion of fuel. Gases rich in
H?S leaving the process are cleaned of solids in cyclones and are fed to the
Stretford absorber. The solids, containing vanadium and sodium, are dissolved
and recycled to the Stretford plant. It is claimed that the process breaks down
all of the thiocyanate, most of the thiosulfate, and more than half of the sul-
fate in the effluent.
Stretford purge may also be treated without resource recovery. Biological
treatment is feasible if the waste is diluted with other plant wastes to reduce
(qg\
thiosulfate and thiocyanate levelsv '. Alternatively, the purge could be used
for ash quenching, thus allowing ultimate disposal to be combined with ash quench
water disposal. At present there are no data to indicate the costs associated
with either resource recovery or waste treatment processes applied to Stretford
purge.
The Wellman-Lord, Chiyoda Thoroughbred 101, and the Dual Alkali processes
generate aqueous wastes containing primarily dissolved inorganic salts. The
Wellman-Lord process produces an aqueous sodium sulfate/sulfite purge. The
Chiyoda Thoroughbred 101 process produces an acidic aqueous purge solution which
contains H2S04, MgO with traces of Fe2(S04)3. The Dual Alkali process produces an
alkaline purge containing mainly calcium hydroxide. Treatment alternatives for
these wastes include resource recovery via processes such as those employed for
Stretford purge; dissolved solids removal by evaporation, ion exchange, etc.,
and use of the wastes as ash quench makeup with subsequent treatment of the
ash quench slurry. The latter alternative has been included in the designs for
the proposed commercial Lurgi SNG plants.
Lime/limestone scrubbing generates a sludge containing mainly calcium sul-
fate/sulfite solids. The only practical treatment method for such sludge is
concentration in a thickener or quench slurry system for combined treatment.
187
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TO STRE1FORD
OD
co
FEED GAS
STRETFORD
SOLUTION
EFFLUENT PURG^
PRECONCENTRATOR
FORCED
CIRCULATION!
EVAPORATOR
STEAM
/^
COKE OVEN GAS
COMBUSTION AIR
HYDKOL1SER WATER
PRODUCT
DISSOLVING
TANK
REAGENT
RECYCLE
Figure 4.4. Woodall-Duckham High Temperature Hydrolysis Process for Stretford Effluent Treatment
-------
Brines generated by ion exchange and demineralization units used for boiler
water treatment and sludges resulting from lime softening/clarification of raw
plant water are not unique to coal gasification facilities but rather are common
to many industrial facilities. In gasification plants, however, such wastes
would commonly be disposed of with the ash quench slurry rather than by direct
discharge or separate disposal. Deep well injection for the disposal of brines
is also featured in the designs for some proposed commercial Lurgi SNG plants.
(Seethe "Ultimate Disposal of Wastewaters," Section 4.3.5, and "Summary of Water
Standards," Section 5.3.1, for discussions of limitations of and regulations
governing deep well disposal.)
Treatment of Cooling Tower and Boiler Slowdowns. As is common practice in
many industries, in a Lurgi gasification facility the boiler blowdown can be used
as cooling tower makeup since the blowdown is relatively low in dissolved solids
and contains no other constituents which would ordinarily interfere with the
operation of cooling systems. The cooling tower blowdown can be used for ash
quenching and dust suppression. Alternatively, the cooling tower blowdown may
be treated (e.g., by ion exchange or forced evaporation) to recover water for
reuse (see the section on wastewater management in integrated facilities for a
description of the dissolved solids removal process).
Control of Miscellaneous Plant Wastewaters. In addition to the wastewaters
discussed above, several miscellaneous wastewaters are generated in an integrated
Lurgi SNG facility which require control. Perhaps the most important of these
are plant runoff, sanitary wastes, and water separated from by-products during
storage. Plant runoff would generally be collected by a sewer system and stored
for treatment for the removal of separable oils and other suspended solids prior
to reuse or discharge.
Gravity separation is usually the first step in the treatment of waste-
waters for the removal of bulk separable oil and suspended solids. "API sep-
arators", which are gravity separators designed in accordance with the criteria
suggested by the American Petroleum Institute (API), are widely used in petroleum
refineries for the treatment of oily wastewaters. Gravity separation is also
used following biological or chemical treatment for the removal of biological
and chemical floes. In gravity separation the wastewater is allowed to undergo
"quiescent settling" in a basin. The oil globules, which are lighter than water,
189
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float to and are collected at the surface; the settleable solids settle to the
bottom and are removed as sludge. The settling basins are usually rectangular
or circular in shape with "accessories" for the introduction of raw wastewater
and collection of effluent, sludge and/or oil. To maximize space utilization,
the settling basin design may incorporate use of inclined parallel plates/tubes,
each representing a "mini basin" within which solid-liquid separation takes
place. The efficiency of gravity separation is dependent on the wastewater
characteristics and the hydraulic surface area loading of the basin. The follow-
ing ranges of removal efficiencies have been reported for the API separators in
refinery oil-water separation applications: 10-50% suspended solids, 50-99%
free oil, 3-35% BOD, and 5-30% COD^90\ The capital cost for API separators
varies with the desired effluent oil concentration. For example, for a 3780 1/min
(1000 gpm) unit, the capital costs (adjusted to 1978 dollars) are estimated at
$500,000 and $1,000,000 for effluent oil levels of 100 ppm and 50 ppm, respec-
tively' '. The operating cost for a 3780 1/min (1000 gpm) unit is estimated
at $118,000/year (adjusted to 1978 dollars).
Prior to entering gravity separator units, chemicals such as iron and
aluminum salts and polymeric organics are sometimes added as coagulant aids to
improve the efficiency of gravity separation and flotation operations. When
added to wastewaters in relatively small quantities, these chemicals can destab-
ilize colloidal particles and agglomerate fine particles into larger floes
which settle or rise at a faster rate. Particle growth is often facilitated
by gentle mechanical mixing (flocculation). When used in conjunction with API
separators or dissolved air (or gas) flotation units, coagulation-flocculation
can increase removal efficiencies and/or enable higher throughput rates.
Filtration may also be employed for suspended solids removal. Generally,
filtration follows conventional treatment such as gravity separation, chemical
treatment or biological oxidation. Filtration is usually accomplished using a
bed of inert solids such as sand, diatomaceous earth or anthracite. The sus-
pended solids trapped in the filter are periodically removed from the filter by
backwashing. As a polishing step for the API separator effluent, sand filtra-
tion has been reported to achieve the following removal efficiencies: 70-75%
suspended solids, 52-83% free oil, 25-44% COD and 36%
190
-------
Sanitary wastes at gasification plants would be handled in one of two ways.
Being very small in volume relative to other plant wastes (e.g., gas liquor),
it may be combined with such wastes and treated jointly by biological oxidation.
Alternatively, sanitary waste may be treated separately in "package" units as
is common practice in many industries. The joint treatment of the sanitary and
process wastes is often desirable since the sanitary waste provides some of the
nutrients (e.g., phosphorus) required for effective biological treatment.
Water which separates from tars, oils and naphtha during storage will re-
quire treatment for dissolved and suspended organics removal. Although little
information is available regarding the quantity (if any) and characteristics of
separated water, it may be expected that such water will be "bound" in sludges
or emulsions. The handling of sludges and emulsions is discussed in Section 4.4.
Wastewater Management at Integrated Facilities and Associated Costs and
Energy Requirements. The types and characteristics of the wastewaters generated
in an integrated Lurgi SNG plant and hence the available options for wastewater
management are determined by a number of factors, the most important of which
are: (a) the type of coal gasified; (b) the air pollution control and sludge/
solid waste management processes used; (c) the availability and cost of raw
water; (d) the climate, geographical location of the plant and land availability;
and (e) the discharge regulations. Wastewater management in large industrial
facilities such as integrated commercial gasification plants would provide for
wastewater segregation, by-product recovery, wastewater treatment, water reuse
and recycling, good housekeeping practices, treatment of separated tar/oil
and sludges, and ultimate disposal of treated wastewaters. A brief review of
these approaches to wastewater volume and concentration reduction follows.
(Recovery of phenols, tar and oil and ammonia as by-products were discussed in
Sections 2.2.6 and 4.3.3. Treatment of separated tar/oil and sludges will be
discussed in Section 4.4 in connection with solid waste management.) Also pre-
sented in this section is a brief review of costs and energy requirements for
wastewater treatment in integrated facilities.
• Wastewater Segregation. Separation of dilute and concentrated waste-
waters and wastewaters of significantly different composition can often provide
for more effective and economical treatment of the separated streams and in some
cases, enable cost-effective by-product recovery and water reuse/recycle. Most
191
-------
refineries use a system of segregated sewers for separate collection, trans-
portation and treatment of sour waters, oily waters, relatively "clean" process
waters and storm runoff. Similar systems of waste segregation are used in exist-
ing Lurgi coal gasification plants abroad, and are included in the designs for
the proposed Lurgi SNG facilities in the U.S. The wastewater management system
for the proposed El Paso Lurgi SNG plant is shown in Figure 4-5.
Some of the key features of wastewater segregation schemes at a Lurgi SNG
facility are as follows. Low quality wastewaters high in dissolved and sus-
pended solids may be combined and treated together. Waste streams that fall
in this category are cooling tower blowdown, ash quench slurry and brines and
sludges from raw water treatment units.
Organics-containing wastewaters such as the clean gas liquor and plant run-
off may be combined and treated jointly by biological oxidation. Wastewaters low
in total dissolved solids may be separated from wastewaters containing high dis-
solved solids levels for selective reuse. Haters in this category are nethanation
condensate, boiler blowdown and gas liquor after treatment for organics removal.
• Wastewater Treatment. Effluents from by-product recovery operations and
raw wastewaters not suitable for by-product recovery require treatment for the
reduction of organic content (BOD, COD), suspended solids, reduced inorganic
species (SCN~, S=, NH3), toxic materials (e.g., heavy metals) and dissolved
salts. The various wastewater treatment processes and their capabilities have
been reviewed previously. The processes which are in use at the SASOL plant in
South Africa and those which have been proposed for use in the commercial SNG
facilities in the United States are listed in Table 4-21. These processes are
generally those which have been widely employed in the treatment of municipal
and industrial wastewaters and have proved to be economical and reliable. All
wastewater management plans proposed for U.S. commercial gasification facilities
are aimed at achieving zero discharge to surface waters. Accordingly, these
plans do not incorporate the use of advanced wastewater treatment systems such
as activated carbon adsorption, ion exchange and membrane processes for the
removal of potentially troublesome organics and inorganic salts and for the
reduction of total dissolved solids. The use of such processes may be required
if the plant effluents are to be disposed of into natural waters, applied to
soil, or used for certain in-plant uses.
192
-------
EVfiPORfl'ION
CO
PRODUCT G*S TO
DEHYDRATION
PIPELINE
n M n
FINAL RECnSOL
OXYGEN PLANT
COOLIH6 TOWEft
FINE ASH POt*D
LINED EVArc-PiT 1 HN
Figure 4-5. Proposed El Paso Burnham Lurgi SNG Plant Hater Management System(80)
-------
TARLE 4-21 WASTEWATER TREATMENT PROCESSES USED AT THE SASOL LURGI PLANT AND
' THOSE PROPOSED FOR USE AT COMMERCIAL LURGI FACILITIES IN THE U.S.
Plant/Process
SASOL Plant
(44)
API separation
Flocculation of oil
Trickling filtration
Sand filtration
Settling ponds
Neutralization
Drying beds
( ° )
El Paso (Burnham, New Mexico)v *" '
Oxidation tower (cooling tower)
Gravity Settling
Evaporation pond
WESCO (New Mexico)^3 ^
API separation and air flotation
Biological treatment
Gravity settling
Evaporation pond
Oxidation tower (cooling tower)
ANG (North Dakota)
(15)
Oxidation tower (cooling tower)
Evaporation/settling pond
Multi-effect evaporator
(distillation)
Gravity oil separator with
flocculation
Wyoming Coal Gas Co. (Wyoming)^
Oxidation tower (cooling tower)
Gravity separation and flotation
Multistage flash evaporation
and ozonation
Brine evaporation
Gas-oil refining condensate
Petrochemical and oil refinery wastes
Combined plant and municipal wastewater
Trickling filter effluent
Ash quench water
Fischer-Tropsch acids
Digested biological sludge
Ammonia stripper bottoms
Ash quench water
Combined plant effluent
Raw gas quench water and plant runoff waters
Air flotation effluent
Ash quench water
Combined effluent
Biological treatment effluent
Stripped gas liquor
Ash quench water
Cooling tower blowdown
Runoff waters
Ammonia stripper bottoms
Sanitary and runoff waters, ash quench
wators
Portion of ammonia strippers bottoms to
be upgraded to boiler feed water
Cooling tower blowdown, raw water treatment
brines, clarified ash quench water
194
-------
• Water Reuse and Recycling and Good Housekeeping Practices. Most of the
currently proposed commercial SNG facilities would be located in the western
United States where water is relatively scarce and expensive. To avoid exten-
sive add-on wastewater treatment which may be required as a result of possibly
very stringent effluent limitation guidelines which may be established in the
future, the wastewater management plans for proposed SNG facilities incorporate
a zero discharge concept. To achieve the goal of zero effluent discharge and
to minimize raw water requirements, proposed designs for these plants provide
maximum reuse and recycling of the wastewaters. Examples of multiple water
usage in these facilities are: use of boiler blowdown, steam and knockout drum
condensates and ammonia stripper bottoms as cooling water makeup; use of meth-
anation condensates for boiler feedwater; use of cooling tower blowdown and raw
water softening brines as ash quench water makeup; recycling of the settled raw
gas quench water to the quench tower; recycling of the settled ash quench tower
blowdown to the ash transport systems; and treatment of waste brine by distilla-
tion and use of the distillate as boiler feed water. That portion of the waste-
water not reused and recycled would either be disposed of with waste solids or
lost as vapor in the cooling tower or from the evaporation pond. To minimize
water wastage and wastewater generation, it is essential that good housekeeping
and water conservation measures be incorporated in the design of integrated
facilities and be observed during the operation of such plants. Such measures
may include elimination of leaks, routine equipment maintenance and personnel
education.
• Ultimate Disposal of Treated Wastewaters. Although good water manage-
ment at Lurgi SNG facilities can minimize both the raw water requirement and
the amount of aqueous wastes generated, there will be some quantity of final
effluent which requires ultimate disposal. To date, all proposed Lurgi SNG
plants are to be located in relatively dry areas where raw water is expensive.
This high cost of water plus the uncertainty about future discharge restrictions
which may be imposed on SNG facilities has prompted designers to propose "zero"
discharge to surface waters. In the southwest (New Mexico), the use of evapora-
tion ponds is entirely feasible to meet this goal since climate is favorable
and land is available and relatively inexpensive.
195
-------
Ponds for temporary or permanent retention of raw or treated wastewaters
(and sludges) are widely used for disposal of industrial and municipal waste-
waters. These ponds, which are referred to as "evaporation ponds," "holding
basins," "lagoons," "oxidation ponds," "settling basins," etc. are usually
natural or man-made earthen reservoirs into which wastewaters are discharged.
These ponds may be lined with impermeable materials (plastic, clay, asphalt,
etc.) to prevent infiltration of the contents into the surroundings. Although
liners have been used for industrial waste ponds, the ability of a liner to retain
its integrity over long periods of time has not been established. The reten-
tion of the wastewater in the pond provides for natural evaporation, settling
of solids, biological decomposition of organics and loss of the more volatile
components of the waste. In geographic regions where annual evaporation exceeds
precipitation, the ponds are generally designed to have no effluent discharge.
Ponds can also be used for temporary waste storage and controlled discharge dur-
ing high flows in the receiving waters. Evaporation/retention ponds require
minimum maintenance and when large land areas are available, can be the most
economical method for wastewater disposal. The SASOL gasification complex in
South Africa uses a settling pond for polishing treatment of the total plant
effluent before discharge into a river. Ponds are also used at all U.S. coal
gasification pilot plants and have been featured in all proposed designs for
commercial SNG facilities in the U.S. Because of solids accumulation, provisions
must be made for periodic removal and disposal of solids from ponds and/or for
ultimate decommissioning of ponds. Costs of evaporation ponds vary consider-
ably depending on pond area, land costs, depth and lining requirements.
In the Northern Great Plains and the eastern U.S. where climatic conditions
do not allow for sufficient evaporation, use of ponds alone is not feasible for
ultimate wastewater disposal. The proposed designs for the Wyoming and ANG
facilities feature forced evaporation for ultimate disposal of wastewaters and
deep well injection and mine disposal for handling brines/sludges. Fored evap-
oration (multi-effector brine concentrators) is one of several processes which
are commercially available or are under development for the removal of dissolved
solids from wastewaters. Other processes include ion exchange, reverse osmosis,
electrodialysis, freezing and electrochemical treatment. These processes are
in varying stages of development and only the first four mentioned are given
serious consideration as practical processes for large scale application. Key
196
-------
features of the dissolved solids removal processes are listed in Table 4-22.
As noted in the table, the ion exchange and membrane processes (reverse osmosis
and electrodialysis) are subject to fouling by organics. Accordingly, the appli-
cability of these processes for wastewater processing would be limited to efflu-
ent polishing and to wastewaters containing very low levels of organics. For
large scale applications, these processes would tend to be energy intensive.
The quality of suspended solids in the influent of ion exchange, reverse osmosis
and electrodialysis processes significantly effects the operating efficiencies
of these processes. Plugging occurs especially in the membrane processes
(electrodialysis and reverse osmosis) which lowers the processes efficiencies.
Therefore, the influents to these processes should be filtered for optimum
performance. Carbon adsorption may also be necessary prior to use of membrane
processes for organics removal. Unlike processes which require feed pretreatment,
the influent to the forced evaporation systems does not require filtration for
the removal of organics (influent may require caustic addition to suppress the
volatility of phenols and organic acids). However, as shown in the table,
forced evaporation has the highest energy requirements of the dissolved solids
removal processes. The energy for forced evaporation may partially be supplied
by low grade heat sources within the plant, such as steam from waste heat re-
covery during primary cooling and discarded steam from the steam compressors
used in final SNG compression.
Costs associated with dissolved solids removal processes depend heavily upon
feed and effluent TDS levels, flow rate and the cost of energy. Generally,
costs for ion exchange, reverse osmosis and electrodialysis are in the range of
$0.1 to $0.25 per 1000 £ ($0.4 to $1.0 per 1000 gal) of feed in 1976 dollars,
while costs for evaporation are estimated at around $1/1000 £ ($4/1000 galsr -
(These costs do not include residue handling and disposal.)
An alternative to ponding or discharge to surface waters for ultimate waste-
water disposal is deep well injection. This method of disposal has been used
for a number of years in the geothermal and oil fields for reinjection of fluids
and by a number of industries for the disposal of a range of concentrated wastes.
The design of the proposed ANG Lurgi commercial plant features deep well injec-
tion for the disposal of raw water treatment brines. Deep well injection can only
be practiced in areas where suitable underground geological formations exist and
where there is very little potential for the contamination of usable groundwaters.
197
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TABLE 4-22. FEATURES OF DISSOLVED SOLIDS REMOVAL PROCESSES
Process
Ion Exchange
Reverse Osmosis
Electrodialysis
Evaporation
(flulti -effect
evaporators or
or brine
concentrators)
Operating Principle
Exchange of nonobjection-
able ions (e.g. , H+, OH')
with objectionable species
(e.g., Ca+2, Mg+2, F~);
resins are regenerated with
acids, bases or salt solu-
tions
Use of semi -permeable mem-
branes and application of
pressure to separate water
from dissolved constituents
Use of anion- and cation-
permeabable membranes and
an electric field to effect
separation of mineral ions
from water
Application of heRt to
evaporate water for
recovery
Major
Existing Application
Water softening,
boiler water treat-
ment, purification
of chemicals, mater-
ial recovery
Demineralization of
brackish waters;
purification of in-
dustrial chemicals
and Pharmaceuticals;
material recovery
Industrial aoplica-
tions; pilot scale
testing for waste-
water treatment
Brackish and sea
water desaliniza-
tion; industrial
wastewater treat-
ment
Advantages
Efficient and reli-
able nrocess ; can
be automated; rela-
tively low operat-
ing cost
Removal of most
wastewater compon-
ents in a sincle
operation
Efficient separ-
ation of mineral s
from water
Recovered water
low in TOS hi ah
solids content
of brine sol-
ution of salt
cake requiring
disposal
Disadvantages
Generates waste
brine; most re-
sins subiect to
fouling by
organics
Generates a con-
centrated waste;
membrane subject
to foul inn and
degradation; re-
lativelv hiah
enerav reauire-
inents
Generates a con-
centrated waste;
membranes subject
to ornanic foul -
ina; linited ex-
perience with
wastewater treat-
ment
Generates ?
waste brine;
scalino nro-
blem; high
enerav re-
aui repent;
sore volatile
substances
mav 'appear
in" the dis-
tillate
Energy Req.
Direct re-
quirements
are low
2.1-2.9 kwh/
liter (9-11
kwh /1 000 gal
of feed
.05-0.1 kwh/
1000 1 (0.2-
0." kwh/1000
aal ) for each
. 1000 ng/1 TO"
removed plus
n.fi-O.R Ui/
inno i (2-3
kwh/inoo
gal) for
pumping
18-21 kwh/
1000 1
(70-10 kvh/
1000 gals)
in the
fnrm of
heat
ins
of Effluent
0.5 to 303 of
influent
50-100 mg/1
< 1 OOOmq / 1
< 10 mg/1
"ater
Pecovprabl lity
essentially
10" ».
"bout 80 %
50 - 90 t
90-98 °:
00
-------
A suitable geological formation is one that:(l) is sufficiently large in capacity
(area, depth and porosity) to accommodate large volumes of wastes at a reason-
able injection pressure (2) does not contain brine or minerals of commercial
value, (3) is located below the lowest groundwater zone and (4) is isolated
above and below by impervious layers and contains no extensive faults or frac-
tures of formations to assure that the injected waste would remain within the
disposal strata. The liquid waste to be injected must be physically and chemi-
cally compatible with the formation. Wastes containing significant concentra-
tions of suspended solids or constituents which may result in the formation of
precipitates and plugging of the pores in the disposal stratum require pre-
treatment (e.g., sedimentation, pH adjustment, filtration, etc.) prior to injec-
tion. Well construction should provide adequate protection against groundwater
contamination and should include provisions for continuous monitoring of well
performance and movement of the waste underground, including continuous samp-
ling of subsurface water courses by monitor wells. In the event of system fail-
ure due to the failure of the well casing, the casing would have to be replaced
or the well may have to be sealed (packed and grouted) and abandoned.
Estimates of the cost for new deep well disposal systems should be made on a
case-by-case basis and require a detailed knowledge of the subsurface geology
(92)
and physical and chemical characteristics of the waste. A 1961 survey^ 'indi-
cated that the total costs of underground waste injection systems ranged from
$30,000 (for a system without surface equipment for pretreatment of the waste)
to $1,400,000 for one with elaborate equipment and a well 3660 meters (12,000
feet) deep. The average cost was $200,000. The operating cost for deep well
injection is dependent on the pretreatment requirements and the operating pres-
sure at the well head. The well pressures reported for existing facilities
range from below atmospheric to over 7 MPa (1000 psia).
a Costs and Energy Requirements for Wastewater Treatment. Figure 4-6 pre-
sents a flow diagram for wastewater treatment at a Lurgi SNG facility, based on
by-product recovery and treatment processes which have been featured in designs
for proposed commercial Lurgi SNG plants. Depending on whether the effluent
from the ammonia recovery unit is used directly as cooling tower makeup or is
treated first by biological oxidation prior to such use and on whether solar or
forced evaporation is used for ultimate disposal of the wastewater, four
199
-------
ro
O
O
LURGI GAS
— *- COOLING
OPERATION
108
TAR/OIL (28
*~ SEPARATION
PHENOL
t
63"
70) PHENOL
EXTRACTION
EVAPORATION
AND DRIFT
1 11226
f (2966)
\2t
COOLING (32
TOWER
9621
2542)
,.,n OTHER PROCESS „„ EVAPORAT10
3460 WASTEWATERS ,"<. ^
(914), AMD SLUDGES (1|1} DRIFT
15 "*i
-9) ASH TRANSPORT/'11
*^ THICKENING
1 3471 I
T(917). 1
WKEUP WE"1" ASH
WATER
UJ
°0) SETTLING
POND
I
WET ASH
OPTIONS USE PHENOSOLVAN AND AMMONIA RECOVERY; PROCESSES
.OWING AMMDNIA RECOVERY ARE AS FOLLOWS:
' JM-IU
(901)
!
J 1
1
1
I
t
FORCED
EVAPORATIO
AfMDNIA
AWDNIA
SEPARATION
9
(2
1
1
1
{' 9000
(2378)
N
EVAPORATION
POND
200
430)
'
BIO
IREATMENT
*-SLUD
LOW TDS
N »- WATER TO
REUSE
SLUDGE
SETTLING POND AND EVAPORATION POND
OPTION 2 - SAT€ AS OPTION 1 EXCEPT COOLING TOWER PRECEDED
BY BIOLOGICAL TREATMENT
OPTION 3 - SATC AS OPTION 1 EXCEPT USE OF FORCED EVAPORA-
TION IN PLACE OF EVAPORATION POND
OPTION 4 - SATC AS OPTION 2 EXCEPT USE OF FORCED EVAPORA-
TION IN PLACE OF EVAPORATION POND
fALL FLOWS ARE IN L/MIN (GAL/MIN) AND HAVE BEEN DERIVED FROM THE
DESIGN FOR THE EL PASO LURGI SNG FACILITY
I
BRINE/SALT
Figure 4-6. Wastewater Treatment Alternatives for Lurgi SNG Systems*
-------
treatments are identified. A breakdown of the estimated capital and operating
costs for the four alternative treatment systems is presented in Table 4-23.
The cost estimates indicate the following for the specific process conditions
and unit costs assumed:
(a) The largest capital and operating cost items are those for the
Phenosolvan process; the value of the recovered phenol only
partially offsets the process cost.
(b) The relatively high cost of ammonia recovery is more than offset
by the value of the recovered ammonia.
(c) Biological treatment is a high cost item. The requirement for
biological treatment is not established at this time; if the raw
wastewater can be used directly as cooling tower makeup (i.e., as
in Options 1 and 3), the use of biological treatment ahead of the
cooling tower may not be necessary. This would result in a savings
of about 40% in total annual cost.
(d) Evaporation ponds require a much larger capital investment than
forced evaporation. Due to higher operating cost, the estimated
total annual cost for forced evaporation is somewhat higher than
for an evaporation pond.
(e) For the four options considered, the total capital cost for waste-
water treatment accounts for about 1 to 1.5% of the estimated total
plant investment of about $2 billion; the total annual cost is
about 0.5 to 1% of the total plant annual cost.
4.4 SOLID WASTE MANAGEMENT ALTERNATIVES
Figure 4-7 identifies five solid process modules for treatment/ultimate
disposal of solid wastes in a Lurgi SNG facility. These are resource recovery,
incineration/fuel use, soil application, land burial/landfilling, and use of
evaporation/retention ponds. A number of other methods, such as ocean disposal
and deep well injection, have been and are being used for the disposal of muni-
cipal and certain industrial sludges. It is, however, very unlikely that these
methods would be used for the disposal of sludges from commercial Lurgi SNG
plants because of environmental regulations or geographic factors. The follow-
ing subsections present a brief discussion of these process modules as applied
to specific solid wastes and sludges generated in coal preparation, coal gasi-
fication, gas purification, gas upgrading operations and auxiliary processes.
In addition, solid waste management options at integrated facilities are
discussed.
201
-------
TABLE 4-23. ESTIMATED CAPITAL AND OPERATING COSTS FOR WASTEWATER TREATMENT AT INTEGRATED LURGI SNG
FACILITIES
Process
Phenosolvant
Aimionia recovery
Biological treatment?
Fine ash thickening^
Forced evaporation**
Evaporation pond''"1"
Totals**
Option 1
Option 2
Option 3
Option 4
Cost for Commercial Lurgi SNG Facility
Capital
Cost (105$)
"11.44
6.53
9.9
0.84
3.5
9.6
28.41
38.31
22.31
32.21
Amortized
Capital Cost*(106$/yr)
1.96
1.11
1.49
o.i:
0.59
1.4
4.06
5.43
3.19
4.60
Annual Operating
Cost (106 $/yr)
2.22
3.82
0.44
0.056
1.14
--
5.84
6.28
6.98
7.42
By-Product
Credit (106 $/yr)
[0.72]
[6.97]
--
—
--
--
[7.69]
[7.69]
[7.69]
[7.69]
Total Annual
Cost (105$/yr)
3.46
[2.05]
1.93
0.176
1.73
1.4
2.21
4.02
2.38
4.33
Annual Energy
Requirement
109 kcal (109 Btu)
346 (1382)
520 (2081)
27 (109)
0.2 (0.7)
141 (565)
--
866 (3463)
892 (3572)
1007 (4028)
1034 (4137)
*Amortization at 15%/year.
tCosts based on benzene extraction; feed containing 1800 mg/1 monohydric phenols and 1200 mg/1 polyhydric phenols; 95% recovery
monohydric phenols and 60% recovery polyhydric phenols; credit for crude phenol at 4.8
-------
93
85, 63
INCINERATION
OR FUEL USE
SOIL
APPLICATION
INORGANICX 49 53 54 55
SOLIDS »49>53'54'bb
AND
JLUDGESy
25 30.48
i
LAND
BURIAL/
LAND-
FILLING
EVAPORATION
OR RETENTION
POND
i
!
RESOURCE
RECOVERY
'NUMBERS REFER TO STREAMS IN
FIGURES 2-2, 2-3, AND 2-4.
Figure 4-7. Process Module for Solid Waste Management in a Commercial Lurqi
SNG Facility
203
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4.4.1 Coal Pretreatment and Handling
Solid wastes generated during coal preparation consist of coal refuse,
coal fines and dust. These wastes can be disposed of along with other plant
solid wastes and by burial in surface mine(s) (see Section 4.4.2). Alternatively
such wastes may be hydraulically transported to settling ponds where solids
would accumulate. (The use of ponds for the containment of wastewaters and
sludges was discussed in Section 4.3.5.) Coal fines and dust may also be used
in boilers, thus reducing the volume of the waste to a much smaller ash volume
for disposal.
4.4.2 Coal Gasification
The Lurgi gasification operation generates an ash which is quenched with
water and then hydraulically transported to ash thickeners and settling ponds.
The bulk of the ash separates and is usually recovered as a wet sludge. The
most practical disposal methods for this material would likely be burial in sur-
face mines or landfills.
In conventional landfilling (i.e., use of sanitary landfills) the waste is
deposited in layers on land, compacted and covered with a layer of dirt. Sani-
tary landfills are widely used for the disposal of municipal and industrial
refuse. Co-disposal of biological wastewater treatment sludges and municipal
refuse is also practiced at a number of landfills. Provided that adequate mea-
sures are taken to reduce potential for the contamination of ground and surface
waters and to minimize the nuisance associated with landfill operation, sanitary
landfilling can be an environmentally acceptable and cost-effective method for
solid waste disposal. To minimize the potential for the contamination of ground-
water and surface waters, landfills must be located in areas where the subsurface
formation is relatively impervious to infiltration (e.g., dense clays) and where
the distance to the groundwater table is significantly large. The landfill sur-
face area should also be properly contoured to divert surface runoff from the
site. When the subsurface formations do not provide adequate barriers against
leachate infiltration, the use of artifical barriers such as plastic, asphalt,
concrete or clay materials for lining the landfill may be necessary. The inter-
cepted leachate would be pumped to a surface facility for treatment. Observa-
tion wells should also be installed downstream of the landfill site (in the
204
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direction of groundwater flow) to detect leachate migration. When the gasifica-
tion plant is located at some distance from the coal mine and suitable land is
available, conventional landfilling would likely be employed for the disposal of
bulk or chemically fixed solid wastes and sludges.
When transportation costs are not excessive, return of the coal gasifica-
tion solid wastes and sludges to the coal mines would be an attractive means
for the disposal of such wastes, especially when area surface mining is practiced.
The designs for all proposed commercial Lurgi SNG plants call for the return to
surface mines of all plant solid wastes. Disposal in surface mines would essen-
tially be one form of landfilling where the overburden material would be used as
the cover material. The operation would be subject to the same restrictions
cited above for sanitary landfills. When coal is mined by deep mining, there
would be a greater time delay before the waste can be deposited in the mine.
In the case of deep mining, the physical operation of returning the waste to
the mine would also be more difficult, requiring certain changes in mine design
and operation to accommodate the space and equipment for returning the wastes.
The return of ash and flue gas desulfurization sludges to the mines would have
the potential benefit of reducing acid mine drainage. This would especially
be the case in eastern mines where acid mine drainage is a major pollution
problem.
The costs of ash disposal by landfilling or return to mines are very plant-
specific and are affected by the availability and cost of land; extent of land-
fill lining, leachate collection/treatment and monitoring required; transporta-
tion distance; and the extent that ash disposal is integrated with the total solid
waste disposal plan for the plant, with the mine operation and with the surface
mine reclamation program.
The total cost for landfill disposal of power plant fly ash and FGD sludges
has been estimated at about $12/tonne^95' ($ll/dry ton). The ash disposal cost
for Lurgi plants located at the mine mouth (e.g., the proposed commercial plants)
should probably be somewhat less because a portion of the cost would be incurred
in the mine reclamation cost. The primary energy requirement for ash disposal
by landfilling or return to mine is for the fuel used for waste haulage. The
typical energy requirement for waste transportation by truck is approximately
4500 kcal/tonne-km (12,000 Btu/ton-mile), assuming that the trucks would return
205
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empty. When wastes are returned to mine, some fuel savings may be realized by
utilizing coal haul trucks for hauling solid wastes to mines.
4.4.3 Gas Purification
Spent methanation guard is the only solid waste generated in the gas puri-
fication operation. Methods for the disposal of methanation guard are essen-
tially the same as those discussed below for the management of gas upgrading
wastes.
4.4.4 Gas Upgrading
Shift and methanation catalysts (and the methanation guard material) even-
tually become deactivated and require replacement or regeneration. For ZnO and
most nickel-based methanation catalysts, onsite regeneration may not be practi-
cal or possible and hence, these materials must either be sent to metals/
catalyst vendors for recovery of metal values or disposed of as solid waste.
In the case of cobalt molybdate shift catalyst, onsite regeneration by air oxi-
dation to remove carbon, organics, and sulfur may be practical and hence reduce
the spent catalyst disposal problem. Spent methanation catalysts, although de-
activated as far as catalyst activity for methanation is concerned, still has
a large capacity for adsorption of sulfur compounds and can be used as guard
bed material. Because of the proprietary nature of most catalysts, little data
are available on the economics of metal recovery from spent catalysts.
Since the guard and catalyst wastes contain high metals contents, carbon-
aceous materials (e.g., polycyclic organic material) and sulfur compounds, they
may represent a hazardous material requiring special handling and disposal.
Containerization or chemical fixation may be necessary before disposal in mines
or landfills.
Chemical fixation (also referred to as cementation, waste passification or
waste immobilization) has been used for the solidification of highly hazardous
industrial wastes prior to disposal by landfill ing or land burial. The objec-
tive of chemical fixation is to reduce solubility and chemical reactivity of
the waste and hence reduce the potential for the contamination of ground and
surface waters via leachate formation and runoff. Both organic and inorganic
materials have been used as fixing agents. The fixing agents include asphalt,
epoxies, tars, Portland and other lime-based cements, and proprietary formula-
tions (e.g., in the Chem-fix process^ '). Raw or chemically fixed sludges can
206
-------
also be encapsulated in plastic, metal or concrete containers or coated with
self-setting resins prior to disposal. Considerable effort is currently under
way to establish the amenability of various wastes to chemical fixation and on
the effectiveness of various chemical fixation processes to reduce the Teachabil-
ity of the waste. The chemical fixation processes are generally expensive and
their applications limited to small-volume, high-toxicity wastes. Chemical fixa-
tion is estimated to add $1 to $3.70 to the cost of fly ash/FGD sludge disposal
(95)
from power pi antsv '.
4.4.5 Auxiliary Processes
As discussed in Section 3.7.5, solid wastes associated with auxiliary pro-
cesses are tarry and oily sludges from by-product storage and treatment of the
runoff water; inorganic solids and sludges from raw water treatment and air and
water pollution control processes; ash from coal-fired boilers; and biosludges
from biological wastewater treatment processes. Processes for the control of
each of these classes of solid wastes are reviewed in this section. In addition,
a discussion of solid waste management at integrated facilities is presented.
Treatment and Disposal of Tarry and Oily Sludges. The tarry and oily sludges
resulting from the treatment of plant runoff waters and the storage of by-
products still contain a large amount of water (mostly in emulsified form) which
may require removal prior to incineration or processing for by-product recovery.
Emulsions can be "broken" by a number of methods including heating with or with-
out chemical addition, precoat filtration, distillation, centrifugation and
electrolytic coagulation. It is expected that some of these methods, particu-
larly heat treatment and distillation, will find application in commercial Lurgi
SNG facilities for the treatment of tarry/oily sludges. The performance and
costs of these control processes are dependent to a large extent on the char-
acteristics of the specific sludges handled. Since essentially no data are
available on the quantities and characteristics of tarry/oily sludges from
Lurgi SNG plants, the performance and costs of the control processes in Lurgi
plant application cannot be determined at this time.
Tarry/oily sludges may be disposed of by landfilling alone or in connection
with ash disposal. These types of wastes may also be incinerated or returned
to the Lurgi gasifier(s) for destruction. Experience with refinery sludges
indicates that a heating value of 4000 kcal/1 (30,000 Btu/gal) is a minimum
207
-------
which will support combustion without supplemental fuel. Compared to land dis-
posal methods, incineration requires very little space. Except for potential
air pollution problems, which can be controlled by use of good design, after-
burners, and particulate control devices, incineration is a most desirable dis-
posal option (when resource recovery is inapplicable), especially for the des-
truction of hazardous organics. Major types of incinerators which are in com-
mercial use are rotary kiln, multiple hearth furnace, fluidized bed and multiple
chamber. Depending on the quantity and the heating value of the tarry and oily
sludges, these sludges can be returned to the gasifiers. Some existing Lurgi
plants feature injection of by-product tars and.oils into the combustion zone
of the gasifiers, and similar injection systems could probably be used for
handling tarry/oily sludges.
Treatment of Inorganic Solids and Sludges. These wastes can be generated
by raw water treatment, by air pollution control processes, and by water pollu-
tion control processes. Inorganic solids such as salts from evaporators may
require fixation or container!'zation prior to disposal in mines or landfills to
prevent leaching of soluble materials to groundwater. Relatively inert solids
such as spent bauxite Claus catalyst may be combined with ash solids for dis-
posal. Similarly, sludges such as those from raw water treatment and flue gas
desulfurization units could be combined with ash quench slurry and sent to clari-
fying units for solids settling.
Inorganic solids and sludges can also be disposed of on land and incorpo-
rated into the top soil. Depending on the soil type, such materials can improve
soil structure, reduce acidity, provide plant nutrients, and decrease the avail-
ability and hence toxicity of certain cations.
Control of Ash from Fuel-Fired Boilers. Bottom and fly ash from boilers is
not greatly different in composition from gasifier ash, although particle size
would be much smaller. Such ash can be transported to mines or landfilled either
wet or dry. In the case of dry transport, care must be exercised to minimize
fugitive ash dust emissions. In the case of wet transport, the disposal opera-
tion can be combined with gasifier ash disposal to reduce overall disposal costs.
Treatment and Disposal of Biosludges. Biosludges generated by wastewater
treatment operations may be disposed of by incineration, landfill ing, or soil
application. Incineration has been successfully practiced for municipal and
208
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industrial biosludges for many years and is a reasonable alternative where land
is not available for sludge disposal. Most sludges, however, are disposed of
in conventional landfills and it is expected that Lurgi gasification biosludges
would also be handled in a similar fashion. The sludge would be combined with
ash and other solid wastes for burial in the mine or landfill (see Section 4.4.2),
Biosludges often require further treatment for concentration and volume
reduction (dewatering) prior to disposal. Sludge dewatering is necessary to
enable economic land disposal or incineration. Sludge concentration methods
include gravity thickening, centrifugation, vacuum filtration, and use of filter
presses and drying beds. These methods have been widely used in municipal and
industrial wastewater treatment practice and considerable experience is avail-
able on them in a variety of applications. Table 4-24 presents reported data
on solids concentration levels obtained by use of various sludge concentrating
processes. Chemicals such as lime, ferric salts and synthetic organic polymers
may be added to sludges to improve dewaterability. In general, biological
sludges tend to be more difficult to dewater than inorganic sludges. Biological
sludges and some concentrated organic wastes can also be further concentrated
by use of anaerobic digestion whereby a portion of the organic material is con-
verted to methane, carbon dioxide and soluble by-products. In addition to the
reduction in sludge volume, anaerobic digestion improves sludge dewaterability
and filterability.
TABLE 4-24. SOLIDS CONCENTRATION OBTAINED BY VARIOUS SLUDGE CONCENTRATING
PROCESSES*
Process
Gravity thickening
Centrifugation
Vacuum filtration
Drying beds
Type of Sludge
Processed
Activated sludge
Activated sludge
Activated sludge
Primary and activated
sludge
Solids Concentration
Obtained (%)
5 - 8
6-11
15 - 20
40
*The ranges of values reflect differences in sludge properties, system
design and operating conditions. Results are obtained after 15 days
of drying, for one specific application.
209
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When large land areas are available and the climate (rainfall, evaporation)
and hydrogeological conditions (distance to groundwater; groundwater flow, type
of soil and geological formation) are favorable, some organic sludges may be
disposed of by application to soil. The sludge is applied to the soil by
"spreading" or "flooding," is disked under and worked into the top soil. The
organic component of the sludge undergoes biodegradation in the soil and event-
ually becomes part of the soil humus. Sludge disposal by application to soils
has been used for the disposal of biosludges from municipal sewage and refinery
wastewater treatment plants. Land disposal of sludge can be used in conjunction
with crop production or as part of a program for the reclamation/revegetation of
lands disturbed by surface mining. As with the application of wastewaters to
soils, sites for land disposal of sludges can present an odor problem or result
in the contamination of surface waters and groundwaters, unless such sites are
properly located, designed and operated.
Solid Waste Management at Integrated Facilities. In comparison with air
and water pollution control, solid waste management options in an integrated
commercial gasification facility are more limited and also more plant and site
specific. The options for solid waste disposal are essentially limited to re-
source recovery, incineration and land disposal (soil application, landfilling,
return to the mine and use of evaporation/retention ponds). Only a few of the
wastes in a gasification facility (e.g., spent catalysts and methanation guards)
lend themselves to resource recovery and it is very unlikely that this option
would eliminate the bulk solid waste disposal requirement. The thermal destruc-
tion of wastes at,an integrated gasification plant should be integrated with the
design and operation of the gasifier and the utility boilers for onsite power
generation to maximize energy recovery and minimize overall costs. The land
disposal option is by far the most site-specific option and the selection of
specific processes in this option would depend upon the plant location, trans-
portation cost, hydrogeological conditions at the site and local environmental
regulations. The solid waste management at an integrated plant is not an iso-
lated problem but rather an element in the total program for pollution control.
The choice of solid waste disposal methods is affected by the specific processes
and options selected for air and water pollution control.
210
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4.5 TOXIC SUBSTANCES CONTROL ALTERNATIVES
Based on the discussion in Chapter 3, toxic substances are or may be present
in Lurgi product SNG, by-products and waste streams. The presence of toxic sub-
stances in product SNG and by-products (tars/oils, phenols and ammonia) can pre-
sent occupational hazards and/or hazards to the general public due to end use
and leaks and spills during transportation and handling. The use of proper
operating procedures and effective industrial hygiene programs can minimize
occupational hazards. The public health hazards which may stem from accidental
spills and leaks in the plant or during handling or transportation can be mini-
mized through strict adherence to safety and transportation regulations and
prompt response to accidents. Many of the pollution control processes or
practices discussed in Sections 4.2, 4.3 and 4.4 result in partial or nearly
complete control of toxic substances in the waste streams. The following is a
discussion of the controls for the toxic substances associated with Lurgi SNG
systems.
4.5.1 Coal Pretreatment and Handling
Coal preparation can result in the generation of a certain amount of very
fine coal dusts; by virtue of their fine size, such dusts can be considered toxic
when inhaled. Most of the fine dusts are generated during crushing and screen-
ing; the particulate control device most suitable for the control of fine dusts
from crushing and screening is the baghouse (see Section 4.2.1).
All coals contain trace elements which under certain conditions (e.g., for-
mation of acids due to pyrite oxidation) may become solubilized and appear in
leachate or runoff from coal piles and coal-selected solid wastes (e.g., coal
refuse). The extent of solubilization and the volume of runoff produced would
be coal- and site-specific. Generally, coal runoff control methods (e.g., con-
tainment, use as process water, etc.) would be effective in the control of toxic
substances in the runoff. The leachate from the coal and refuse pile can be con-
tained by use of liners underneath the piles and by collecting the leachate for
treatment/reuse.
4.5.2 Coal Gasification
The only waste streams associated with coal gasification which may contain
potentially toxic substances are the lockhopper vent gases, transient waste gases
211
-------
and the gasifier ash. The toxic components of the feed and ash lockhopper vent
gases and of transient gases are CO, H2S, COS, NH3, HCN, C$2, Ni(CO) fine
participate matter, trace elements and low molecular weight aromatics. Incinera-
tion with participate control, which would be used for the control of lockhopper
and transient gases, should result in partial or total removal of these sub-
stances or their conversion to less toxic forms (e.g., conversion of H?S to SO ).
No operating data are available on the degree of effectiveness of these methods
for the control of toxic substances. The gasifier ash by itself should be a
relatively non-toxic material. However, some trace elements present in the ash
may become solubilized during hydraulic transport or in the landfill environment.
Proper design and operation of lagoons and landfills can minimize potential for
contamination of surface waters and groundwaters.
4.5.3 Gas Purification
Gas purification wastes and by-products containing potentially toxic sub-
stances are Rectisol acid gases, tars/oils, phenols, ammonia, clean gas liquor
and spent methanation guard. The major toxic substances in the Rectisol acid
gases are sulfur compounds, CO, HCN and aromatic hydrocarbons. The sulfur recov-
ery and tail gas treatment processes are highly effective in removing or oxi-
dizing these substances. Some Rectisol designs (e.g., that proposed for the
El Paso plant) incorporate a special feature which significantly reduces the
HCN loading to and the chemical losses in the downstream Stretford sulfur recov-
ery unit. In these designs, HCN in the prewash flash gas is reabsorbed in
water and sent to the shift reactor where it is converted to ammonia.
As with most crude petrochemical and industrial products, tars, oils,
ammonia and phenols are or contain toxic substances which present occupational
or public health hazards. Proper plant design and operating practices, adher-
ance to safety and transportation regulations, effective industrial hygiene
programs, good housekeeping practices and prompt response to accidents, which
can be largely adapted from other industries, can reduce the hazards associated
with the Lurgi by-products.
As noted in Section 3.6, the clean gas liquor contains a range of organic
and inorganic constituents. Many of these constituents (e.g., S=, SCN~, aro-
matics, heavy metals) would ordinarily be classified as toxic substances. Cer-
tain of these toxic substances (e.g., pyridine) are not readily biodegradable
212
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and hence may not be totally removed when the clean gas liquor is treated by
biological oxidation. Designs for the proposed commercial Lurgi SNG facilities
call for the use of clean gas liquor as ash slurry makeup with subsequent con-
trol of the solid wastes which accumulate in ponds or which are disposed of in
landfills. The control of toxic substances associated with methanation guards
is discussed below in connection with control of toxic substances in gas upgrad-
ing wastes.
4.5.4 Gas Upgrading
The product SNG, spent shift and methanation catalysts (and methanation
guard) and catalyst decommissioning/regeneration offgases are the major streams
from gas upgrading operations which may contain potentially toxic substances.
As noted in Chapter 3, these toxic substances include CO and Ni(CO). in the SNG
and in the decommissioning/regeneration offgases and metals and their inorganic
and organic compounds and high molecular weight organics (possibly polycyclic
compounds) in the spent catalyst. Through proper operating procedures, the
amounts of CO and Ni(CO). in SNG and in the catalyst decommissioning/regenera-
tion off-gases can be minimized. In the case of the off-gases, further control
can be achieved through incineration. When the spent catalysts are to be pro-
cessed for resource recovery, care must be exercised in handling and transporta-
tion to reduce occupational hazards. Disposal of spent catalysts in landfills
requires waste fixation/isolation and disposal site selection to minimize metal
mobilization and hence environmental contamination.
4.5.5 Auxiliary Processes
Waste and by-product streams from auxiliary processes which contain poten-
tially toxic substances are ash from onsite steam and power generation, evapora-
tive emissions from by-product storage, tarry/oily and biosludges and inorganic
solids and brines. The general control methods such as vapor recovery, recov-
ery of sodium and vanadium salts from the Stretford purge, and landfill disposal
of sludges and ash, which were discussed previously would also provide varying
degrees of control for the toxic substances in these wastes. Because of the
presence of toxic substances in these wastes, certain control modifications or
extra precautions may be necessary in their handling and disposal. An example
of such a change is encapsulation/chemical fixation of solids and sludges prior
to land disposal. In some cases, use of a more expensive alternate disposal
213
-------
method may be necessary (e.g., incineration of organic sludges instead of land
disposal).
4.6 SUMMARY OF MOST EFFECTIVE CONTROL ALTERNATIVES
4.6.1 Emissions Control
Table 4-25 summarizes the most effective commercially available methods for
the control of various gaseous emissions in a Lurgi SNG plant, based on the
detailed discussion in Section 4.2.
4.6.2 Effluents Control
Table 4-26 summarizes the most cost-effective methods for the control of
various effluents in a Lurgi SNG plant, based on the detailed discussion in
Section 4.3.
4.6.3 Solid Wastes Control
Table 4-27 summarizes the most cost-effective methods for the control of
various effluents in a Lurgi SNG plant, based on the detailed discussion in
Section 4.4.
4.6.4 Toxic Substances Control
Some of the emissions, effluents and solid wastes control methods listed
in Tables 4-25, 4-26 and 4-27 are specifically aimed at the control of toxic sub-
stances in a waste stream. For example, the encapsulation/fixation of spent
catalysts prior to disposal in landfills/mines is aimed at containment and
immobilization of catalyst constituents. Other control methods listed in the
tables, which are not specifically aimed at the control of toxic substances in
various waste streams, do achieve varying degrees of control via containment,
destruction or conversion of such substances to less hazardous forms. For
example, incineration of sulfur recovery tail gases and catalyst regeneration/
decommissioning off-gases results in the destruction of toxic substances such
as CO, Ni(CO)4, H^S and aromatic hydrocarbons.
Since the product SNG and various by-products and waste streams in a Lurgi
SNG facility would contain toxic substances which can present occupational ex-
posure hazards to plant workers or public health hazards (e.g., resulting from
spills/leakage during material handling and transportation or for end uses),
Lurgi SNG plants must be designed and operated in a manner which would reduce
214
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TABLE 4-25. MOST EFFECTIVE COMMERCIALLY AVAILABLE EMISSIONS CONTROLS
Operation/Process
Coal pretreatment
and handling
Coal gasification
Gas purification
ro
en
Gas upgrading
Auxi 1 i ary
Processes
Gaseous Waste Stream
Crushing and screening
dusts
Fugitive dusts
Feed lockhopper vent
gas
Ash lockhopper vent gas
Transient waste gajses
Rectisol acid gases
Sulfur recovery tail
gases (for additional
sulfur recovery as HC/
CO control)
Catalysts decommission-
ing/regeneration off-gas
Depressurization and
stripping gases
By-product storage
vent gases
Steam and power genera-
tion flue gases
Controls
Dust suppression systems and baghouse
Dust suppression systems and enclosure
of conveyors and transfer stations
Compression and recycle of pressurization
gas and incineration of waste gas
Incineration
Stretford or ADIP/Claus processes
Beavon and incineration or incineration
and Wellman-Lord (or other FGD processes)
Incineration
Treatment in combination with the Rectisol
off-gases or incineration in fuel-fired
boilers followed by flue gas desulfuriza-
tion
Vapor recovery systems (for more volatile
liquids) and use of floating roof storage
tanks or conservation vents (for less
volatile liquids)
Electrostatic precipitation or fabric
filters for particulate control; FGD sys-
tems using limestone, Uellman-Lord or dual
alkali processes; use of desulfurized low
Btu gas produced onsite as fuel for steam
and power generation
Comments
Particulate control after incineration may
be necessary
Particulate control would probably be
necessary
Control of sulfur and particulate may also
be necessary; insufficient data exists to
establish control requirements
The control choice dependent on the sulfur
content of the Rectisol gases; a combination
of Stretford and ADIP/Claus may have the
lowest overall costs
Incineration may be conducted in fuel-fired
boilers to allow for heat recovery and a
lower overall cost
Waste stream characteristics not well estab-
lished to determine additional controls (if
any) needed
Insufficient data available to determine the
preferred control option
The comparative economics of the FGD systmes
have not been well established; the sulfur re-
covery tail gases may be incinerated in the
fuel-fired boilers and the combined flue gas
handled in the FGD system. Onsite production
of fuel gas is generally more costly than direct
coal/by-product combustion with pollution control,
but results in lower overall emissions
-------
TABLE 4-26. MOST EFFECTIVE EFFLUENTS CONTROLS
Operation/Process
Aqueous Waste Stream
Controls
Comments
ro
cr>
Coal pretreatment
and handling
Coal gasification
Gas purification
Gas upgrading
Auxil iary
Processes
Coal pile runoff
Ash quench slurry
Raw gas liquor
Methanol/water still
bottoms
Methanation and
dehydration condensates
Clean gas liquor
Filter backwashes
Haste sorbents and
reagents
Boiler blowdown
Cooling tower blowdown
Miscellaneous plant
wastewaters
Overall (final) plant
effluent
Diversion of runoff from adjacent areas;
collection of runoff and treatment with
other plant wastewaters
Bulk solids settling, fines thickening and
storage/settling ponds
Use of Lurgi tar/oil separator, Phenosolvan
process and Phosam \i process for tar/oil,
phenols and ammonia recovery, respectively
Addition to dephenolized gas liquor prior
to ammonia recovery
Depressuri zation for dissolved gases re-
moval and subsequent use as boiler feed
water
Use as cooling tower makeup with or without
biological treatment
Addition to ash quench slurry
Recovery of reagents from air pollution
control processes; addition to ash quench
slurry; disposal by deep well injection
Use as cooling tower makeup
Use as ash quench makeup water
API separators and use of treated water
as process water makeup (for plant runoff);
use of packaged units for the treatment of
sanitary wastewaters
Solar or forced evaporation
Other process wastes such as raw water treatment
and air pollution control sludges and brines may
be combined with the ash quench slurry for treat-
ment and solids disposal
Lurgi tar/oil separator and the Phenosolvan process
are Lurgi-1icensed and are featured in all designs
for proposed commercial facilities
The need for and effectiveness of biological treat-
ment of clean gas liquor not established
Deep well injection may not be practical at all
sites
Depending on the hydrogeological conditions, waste
ponds may require lining; use of solar evaporation
is dependent on regional/local climate
-------
TABLE 4-27. MOST EFFECTIVE SOLID WASTES CONTROL
Operation/Process
Solid Waste Stream
Controls
Comments
r-o
Coal pretreatment
and handling
Coal gasification
Gas purification
Gas upgrading
Auxi 1 iary
processes
Coal refuse, coal fines
and dust
Wet ash
Spent methanation
guard
Spent shift and
methanation catalyst
Tarry/oily sludges
Biosludges
Inorganic solids and
sludges
Fly ash from steam/
power generation
Use of coal fines as fuel; disposal in
settling ponds and landfills
Disposal in landfills or return to mines
Fixation/encapsulation and disposal in
landfills/mines; processing for metal
recovery
Processing for material recovery; use of
spent methanation catalyst as methanation
guard; fixation/encapsulation and dis-
posal in landfills/mines
Disposal in landfills/mines with or with-
out fixation/encapsulation; incineration;
return to gasifier
Disposal in landfills/mines, soil appli-
cation, incineration
Addition to ash quench slurry, direct
disposal in landfills/mines
Disposal in landfills or return to mines
These wastes are not unique to Lurgi SNG plants and
the controls are adaptable from other industries
The quantity of ash accounts for more than 90% of the
solid wastes generated at a Lurgi SNG plant. The
choice and design of disposal system are dependent on
the ash content of coal and plant/mine site character-
istics.
The technical and economic feasibility of resource
recovery have not been established
Data on the technology and economics of resource
recovery processes have not been established
Because of lack of data on waste quantities and charac-
teristics, optimum control(s) cannot be established
Because of lack of data on waste quantities and charac-
teristics, optimum control(s) cannot be established
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worker exposure and potential for system upsets and equipment failure. Effec-
tive safety and industrial hygiene programs, strict adherence to safety stan-
dards and transportation regulations, and programs for quick response to
emergencies are also necessary to reduce occupational and public health hazards.
4.7 MULTIMEDIA CONTROL SYSTEMS
There are several systems/approaches capable of achieving controls of waste
streams to more than one medium in a Lurgi SNG plant. These systems/approaches
fall into two general categories: (1) "in-plant" controls and (2) "end-of-
pipe" controls. The "in-plant" controls include resource recovery, use of
alternative processes/equipment and water reuse/recycling and good housekeeping
practices. Some specific examples of in-plant controls are listed in Table 4-28.
Some of the end-of-pipe controls discussed in Sections 4.2, 4.3 and 4.4
achieve control of waste streams to more than one medium. Perhaps the best
example of a multimedia end-of-pipe control is the use of lined settling/
evaporation ponds for the containment/ultimate disposal of plant wastewaters.
When properly designed and operated such ponds eliminate waste streams to surface
waters and groundwaters, prevent land contamination (via percolation/seepage),
and serve as a repository for particulate and dissolved solids contained in the
waste streams.
While reducing or eliminating streams to specific media, some of the in-
plant and the end-of-pipe multimedia controls generate new streams which would
be discharged to the same or to different media. In most cases, however, the
discharge problem is significantly reduced. For example, use of fuel gas instead
of direct combustion for onsite production of steam and power generates Lurgi
ash which would be easier to process and dispose of than the fly ash/FGD
sludges produced as a result of the treatment of coal combustion flue gases.
The technical and economic viability of the many multimedia control possibilities
for Lurgi SNG facilities cannot be evaluated at this time due to the lack of an
operating data base for integrated SNG plants.
4.8 REGIONAL CONSIDERATIONS AFFECTING SELECTION OF ALTERNATIVES
A number of regional (local) factors affect the selection of waste manage-
ment processes/options at an integrated Lurgi SNG plant. Most important of
218
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TABLE 4-28. IN-PLANT MULTIMEDIA CONTROL POSSIBILITIES FOR A LURGI SNG FACILITY
Category
Examples
Description
Resource recovery
Alternative process/
equipment
ro
Water reuse/recycling
Good housekeeping
practices
Tar/oil recovery, phenol recovery,
ammonia recovery, naphtha recovery,
sulfur recovery, catalyst material
recovery
Use of fuel gas vs. direct coal/
by-product combustion
Rectisol design to allow collection
of HCN and recycling to shift con-
verter for destruction
Recompression and recycling of feed
lockhopper pressurization gas
Collection and treatment of coal
and plant runoff waters for in-plant
use
Proper design, operation and main-
tenance of equipment to minimize
process upsets, equipment failure
and leaks/spills
Eliminates the recovered material
from a waste stream and hence dis-
charges to various media
Eliminates the need for FGD/particu-
late control and hence discharges to
air (S02, particulate), to land (FGD
sludges/solids), and to water (leach-
ate from solids disposed in landfills);
system also allows for direct sulfur
recovery
Eliminates emission of HCN to air (in
the Rectisol off-gas) and to water
(via Stretford blowdown or the gas
liquor)
Eliminates emission to air and to
water and land (from air pollution
control systems)
Eliminates land and water contamina-
tion and possibly emissions to air
(when wastewaters contain volatile
components)
Reduces emissions to all media
-------
these factors are the type of coal processed, climate and hydrogeological condi-
tions, and environmental regulations. Table 4-29 lists the general characteris-
tics of the coals and the climate for six major "coal provinces" in the U.S.
which, because of coal availability, are considered likely sites for the coinmer-
cial SNG facilities. As noted in the table, both the coal characteristics and
the climate vary with the province.
As discussed previously, the type of coal (specifically its sulfur moisture
and ash content) determines the loadings to various by-product recovery/pollution
control units (e.g., Rectisol and gas treatment and ash handling systems) and
the volume and quantity of by-products recovered and sludges and solid wastes
handled. These loadings, in turn, determine the size and cost of the process/
pollution control equipment required and the choice and economics of the waste
disposal options. For example, a 7 x 106 Nm /d (250 MMscf/d) Lurgi SNG plant
processing a western coal (0.7% sulfur content) would produce Rectisol acid gases
containing about 139 tonne/d (152 ton/d) of sulfur whereas a similar sized plant
in the eastern U.S. handling an eastern coal (4% sulfur content) would produce
Rectisol acid gases containing about 5.7 times as much sulfur.
In general, western coals tend to be higher in moisture content than the
eastern coals. Lignites, for example, can contain up to 40% moisture whereas
the moisture contents of the eastern coals are generally in the 5 to 10% range.
The higher the moisture content, the larger would be the volume of the Lurgi
gas liquor produced. The gasification of a subbituminous coal containing 17%
moisture in a 7 x 106 Nm3/d (250 MMscf/d) plant is estimated to generate 1.25 x
10 1/d (3.3 mgd) of gas liquor; in comparison, a similar size plant using a
lignite coal with 38% moisture content would generate 2.4 x 107 1/d (6.3 mgd)
of gas liquor. The large volume of gas liquor produced in the gasification of
western coals coupled with the high cost of water in the coal provinces in the
more arid west (EPA Regions VI and VIII), provides a strong incentive for treat-
ment and in-plant use of the gas liquor in the western plants.
Although the ash content is not necessarily a regional characteristic of
coal (coals from the same formation can vary widely in their ash content), ash
content affects the quantity of solid wastes generated in an SNG plant and the
choice and cost of solid waste disposal options.
220
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TABLE 4-29. CANDIDATE REGIONS FOR LOCATION OF LURGI SNG FACILITIES (SELECTED FOR ANALYSIS IN THIS
DOCUMENT)
ro
ro
Coal Province
Eastern interior
Eastern
Gulf coast
Northeastern
Great Plains
Northwestern
Great Plains
Rocky Mountains
States Within
Province
Illinois
Indiana
W. Kentucky
Pennsylvania
W. Virginia
Ohio
E. Kentucky
Alabama
Texas
N. Dakota
Wyomi ng
Montana
New Mexico
Colorado
EPA Region
IV, V
III, IV, V
IV, VI
VIII
VIII
VI, VIII
Coal
Characteristics
Bituminous, high sulfur,
low moisture
Bituminous, medium/high
sulfur, low moisture
Lignite, low sulfur,
high moisture
Lignite, low sulfur,
moderate to high
moisture
Subbituminous low
sulfur, moderate
moisture
Subbituminous, low
sulfur, moderate
moisture
Climate
Type
Cold, wet
Cold, wet
Warm and wet
to warm and
semi -arid
Cold, dry
Cold, dry
Warm and dry
to cool and
dry
-------
The availability and cost of raw water and the hydrogeological conditions at
the plant site have significant impacts on the choice of wastewater treatment
processes and disposal options. As noted above, in the arid west (coal provinces
in EPA Regions VI and VIII) where the water is less available and more expensive,
there would be a stronger incentive to maximize water reuse within the plant than
in the east where water is more abundant and less costly. As has been proposed
in the designs for SNG plants to be located in EPA Region VI, such plants would
use solar evaporation for ultimate disposal of the plant wastewaters; use of
evaporation ponds would not be practical in wet climates (in EPA Regions III, IV,
and V) and cold climates (EPA Region VIII) where annual evaporation may be only
slightly more or less than the annual precipitation. Facilities located in such
regions would have to use forced evaporation or processes such as reverse osmosis
and ion exchange to treat a portion or all of the plant wastewaters.
To maintain the national ambient air quality standards and/or meet the
prevention of significant deterioration criteria (PSD), air pollution control
regulations may limit the size of Lurgi SNG plants or impose severe emissions
restrictions on such plants. Compliance with more stringent regulations would
increase pollution control requirements and costs.
4.9 SUMMARY OF COST AND ENERGY CONSIDERATIONS
Based on the cost and energy data presented in Sections 4.2, 4.3 and 4.4.,
the estimated total annual cost and energy requirements associated with air
and water pollution control and solid waste m;
(250 MMscf/d) Lurgi SNG plant are as follows:
fi o
and water pollution control and solid waste management at a 7 x 10 Nm /d
Energy Requirement,
Costs. $ million 109 kcal/yr
Air pollution control 15 - 19 569 - 1560
Water pollution control 2.2 - 4.3 866 - 1034
Solid waste management 18 - 30* 2-7
Total 25.26 - 53.3 1437 - 2601
Based on the estimated total plant annual cost and energy input require-
12
ments of about $550 million and 3.6 x 10 kcal, pollution control at an inte-
grated plant would account for about 5 to 10% of the annual cost and 4 to 7% of
the total energy input.
*Based on a coal ash content range of 7 to 20%.
222
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5.0 ANALYSIS OF REGULATORY REQUIREMENTS AND ENVIRONMENTAL IMPACTS
This section (a) reviews the standards and guidelines applicable to waste
discharges to air, water and land media and to the toxic properties of marketed
products, (b) compares the waste streams and products/by-products from Lurgi
gasification systems with the applicable discharge and toxic substances control
standards, (c) presents an analysis of the impacts of waste discharges from
Lurgi gasification systems on the quality of the ambient air, water and land
resources, (d) estimates the potential hazards associated with specific sub-
stances in products/by-products and waste streams which are not covered by
existing regulations, and (e) discusses siting considerations for gasification
plants. Before presenting an analysis of the regulatory requirements and
environmental impacts associated with the Lurgi systems, a brief description
of the environmental assessment methodologies, which are being developed by EPA
for evaluating and comparing environmental impacts associated with the emerging
fossil energy technologies, will follow.
5.1 ENVIRONMENTAL ASSESSMENT METHODOLOGIES
EPA's Industrial Environmental Research Laboratory, Research Triangle Park
(IERL/RTP) has been working on the development of a standard set of methodologies
for the environmental assessment* of fossil energy processes. Such standard
methodologies are needed on a near-tern basis to eliminate large gaps, ineffic-
iencies and proliferation of techniques for evaluating and comparing environmental
*As defined for IERL/RTP studies of fossil energy processes, an environmental
assessment is a continuing iterative study aimed at: (a) determining com-
prehensive multimedia environmental loadings and environmental control costs,
from the application of existing and best future definable sets of control/
disposal options, to a particular set of sources, processes, or industries;
and (b) comparing the nature of these loadings with existing standards, esti-
mated multimedia environmental goals, and bioassay specifications as a basis
for prioritization of problems/control needs and for judgment of environmental
effectiveness.
223
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aspects of competing technologies and the effectiveness of various pollution
control alternatives. The environmental assessment methodologies which are
being developed by EPA represent prototype approaches to multimedia, multi-
pollutant problem identification and control effectiveness evaluation for com-
plex effluents. They are prototypes of potential future regulatory approaches
that can handle the whole problem and are aimed at preventing problems before
they occur. Hopefully they will allow resolution of existing problems on
other than a one-pollutant-at-a-time basis, a basis which is fraught with end-
less studies, only partially effective results, and high costs at all levels
of implementation.
The environmental assessment methodologies which are being addressed by
EPA are currently in different stages of development with most of the work being
carried out by contractors working under the direction of the EPA. These meth-
odologies pertain to "current process technology background," "environmental
data acquisition," "current environmental background," "environmental objec-
tives development" (multimedia environmental goals), "control technology assess-
ment," and "environmental alternatives analysis" (source assessment models).
A flow/decision sequence diagram indicating how these specific methodologies
and their outputs will be used by EPA in its environmental assessment/control
technology development effort and a summary of the methodologies are presented
in Figure C-l and Table C-l (Appendix C), respectively. A more detailed des-
cription of two of the methodologies (multimedia environmental goals and source
assessment models) and a brief description of another methodology ("bioassay
interpretation") which is also being developed by EPA for formatting/inter-
pretation of bioassay data in connection with "current technology background"
and "environmental data acquisition" efforts will follow.
5.1.1 Multimedia Environmental Goals
To establish a systematic means for the prioritization of the many chemi-
cal substances which are present in complex effluents for the purpose of environ-
mental assessment and definition of control technology needs, EPA has established
"Multimedia Environmental Goals" (MEG's) which are:
...Levels of significant contaminants or degradents (in ambient air,
water, or land or in emissions or effluents conveyed to the ambient
media) that are judged to be (a) appropriate for preventing certain
negative effects in the surrounding populations or ecosystems, or
(b) representative of the control limits achievable through tech-
nology^).
224
-------
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 210 sub-
stances on the Master List. The MEG value(s) for a given substance may be
based on several or all of the 12 criteria shown as headings for the MEG's
chart in Table 5-1. These criteria cover emission level and ambient level
goals. Depending 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
criteria which is most currently used in environmental assessment work is the
minimum acute toxicity effluent (MATE). MATE is the approximate concentration
for contaminants in source emissions which will 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).
Most of the MEG's are derived through models which translate toxicological
data, recommended concentration levels, and federal standards or criteria into
emission or ambient level goals. For most of the categories listed in Table
5-1, more than one model is available for obtaining the "estimated permissible
concentration" (EPC). Where different EPC values can be obtained by using
different models, the strictest is chosen as the MEG value. An example of a
model which translates LD5Q* (oral, rat) into the toxicity-based ambient level
goal for air for the health effects category is:
EPC in yg/m3 = 0.107 LD5Q (in mg/kg)
(99)
This particular model was developed by Handy and Schindlerv ' based upon
the correlation between the reported LD5Q (oral, rat) and TLV" for 241 sub-
stances, with adjustment made for continuous exposure using a factor of
40 (hrs per work week).
168 (hrs per week)
*LD5Q, Lethal dose fifty: the dose which when administered to a group of
animals is lethal to one-half of the population. The mode of administering
the dose and the test animal must be specified.
ni\l, Threshold Limit Value: levels of contaminants considered safe for work-
room atmosphere, as established by the American Conference of Governmental
Industrial Hygienists.
225
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TABLE 5-1. CURRENT VERSION OF THE MEG'S CHART
(90)
EMISSION LEVEL GOALS
Cat»gr>rv
Air. 09/m3
(ppm Vol)
Watar. tig/l
(ppm Wt)
Land, /JQ/fl
(ppm Wt)
1 Bator) on liirtt Tnchnology
A i«liHm|»l«nelaiil«
NBit, nrr. BAT
B. Oatnloplng Taehnolnirv
rnylnnaHng E«ttm«t«l
IRa,O Qoalt)
II.
A. Minimum Acut«
TO.ICIIV EHIiMnt
BHR
-------
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 = hazardous, 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 pollutants 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 noted above, to date MEG values have been established for only 210
of the 650 substances on the "MEG Master List." Work is currently in pro-
gress to establish values for other substances on the list, to refine the
models used for calculating MEG values and to update/revise the input to
the MEG models. MEG Methodology has already found considerable application
in environmental assessment work. For example, in the "phased approach" to
sampling and analysis of process/waste streams, comparison of the pollutant
levels with MATE values provide a basis for deciding whether or not to pro-
ceed to more detailed or sophisticated levels of sampling and analysis. As
will be discussed in Section 5.1.2, MEG values are used in the "Source Ana-
lysis Models" for "screening" effluent streams. Tables C-2 and C-3 (Appendix C)
present the MEG "chart" and background information summary, respectively, which
have been developed for naphthalene.
5.1.2 Source Analysis Models (SAM's)
To fulfill part of the EPA's goal to develop control technology and per-
form environmental assessments for both energy and industrial processes, the
EPA has created set of source analysis models (SAM's), which provide systematic
methods of comparing the environmental effectiveness of pollution control
options. The various members of the set of SAM's provide rapid screening,
intermediate, or detailed approaches to relate effluent stream pollutant emis-
sion levels to the MEG's.
The simplest SAM, designated SAM/IA, will ordinarily be used for rapid
screening of the difference between an uncontrolled process and the results of
the application of various control options. This model compares either the
sample fractions or specific pollutant species in the individual effluent
227
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stream, whichever data are available, to the MATE goals. The calculation of
numerical values expressing the effectiveness of control options proceeds as
follows. The ratio of the pollutant concentration to the MATE value (which may
be based on either health or ecological effects) is called the "potential degree of
hazard" (H). A quantity called the "potential toxic unit discharge rate"(PTUDR)
is arrived at by multiplying H by the stream flow rate. Then the PTUDR's are
summed over each medium (air, water and land) for each control option considered.
Comparison of the PTUDR's calculated for each option shows (1) how the distribu-
tion of overall toxicity is influenced by choice of control options, and (2)
which option allows the minimum discharge of overall toxicity to all media.
Use of the SAM/IA methodology for rapid screening requires making the
following assumptions:
(a) The approximately 650 substances currently in the MEG list
as potential components of an effluent stream are the only
ones which need to be included at this time.
(b) Dispersion of effluents will be adequate and will offset any
transformation to more toxic substances.
(c) The MATE values (or the basic data from which they were
developed) are adequate.
(d) No synergistic effects occur.
The SAM/IA methodology is detailed in Reference 100. SAM/IB, which is currently
under development, is an extension of the SAM/IA model incorporating bioassay
test protocols.
The next of the source assessment model series, SAM/I, takes into consid-
eration the factors mentioned in items (b), (c) and (d) above by applying
"effluent transport/transformation analysis"* to the effluent stream constitu-
ents. The resultant ambient concentrations are compared with the MEG of choice,
which may be based on best technology (BT), existing ambient standards (ES),
standards based on prevention of significant deterioration (SD), estimated per-
missible concentration (EPC) or natural background concentration (NC). The
remaining steps are similar to SAM/IA. The extended SAM/I considers urban and
rural population densities and includes background ambient concentrations in
the screening analysis. The SAM/I draft is now complete and is in review.
*Tne SAM/I effluent transport/transformation analvsis incorporates a simple
dispersion model utilizing the Turner handbook (101), and elementary trans-
formation considerations.
22C
-------
The most detailed source assessment model, SAM/I I, is still in the plan-
ning stages. Calculations will be based upon ambient rather than on effluent
concentrations. The transport/transformation models will be more rigorous
than that used in SAM/I.
A SAM/IA summary sheet is presented as Table C-4 in Appendix C.
5.1.3 Bioassay Interpretations^102^
EPA/IERL is currently developing a methodology for reducing and formatting
bioassay data generated as a result of extensive environmental data acquisition
efforts using the phased approach to performing environmental source assessments.
The phased approach requires three separate levels of sampling and analytical
effort (see Table C-l in Appendix C). Most of the bioassay to date has been in
connection with Level 1 sampling and analysis which is designed to (1) provide
preliminary environmental assessment data, (2) identify problem areas, and
(3) generate data needed for the prioritization of energy and industrial pro-
cesses, streams within a process, and components within a stream for further
consideration in the overall assessment. The biological effects which are
examined in Level 1 are primarily physiological, ecological, genetic or
behavioral.
Development of a methodology for reducing and formatting bioassay data is
being carried out under EPA contracts to Research Triangle Institute, Research
Triangle Park, N.C., and Litton Bionetics, Kensington, MD. EPA has established
the Bioassay Subcommittee of the Environmental Assessment Steering Committee
to monitor and coordinate the methodology development effort^ '.
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 in the technologies
• Reduction of the data to a matrix which will "weight" the
observed effects in terms of significant differences between
exposed experimental organisms and their controls
• Publication of the methodology in a manual which will enable
uniformity of assessment of the pollution potential of the
source.
229
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Development of a methodology for handling bioassay data is necessary be-
cause of the complex and specialized information resulting from bioassay samp-
ling and analysis. Reducing and formatting the data are particularly important
because the information must be used by chemists and engineers who may not be
familiar with bioassay techniques but are required to use bioassay test results
as the basis for design and operation of plants to conform with applicable
environmental regulations.
The test matrix in Table 5=2 is an example of the minimal bioassay protocol
which will be followed in order to investigate emissions which may have a high
pollution potential. The large amount of information which must be gathered in
order to produce a credible bioassay requires carefully planned collation and
treatment^102)-.
In general, dose/response models are used for defining numerical or
"weighted" relationships between toxic materials and their effect on test
organisms. These ratings, which are designed to give an indication of the
relative toxicities of effluents, are subject to some of the intrinsic diffi-
culties associated with dose/response models. However, dose/response models
can be extremely valuable tools for assessing the toxicity of effluents when
presented by the methodology being developed. 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 effects, it is necessary to extrapolate effects
observed in the laboratory into an unknown area. This extension of knowledge
assumes a continuity, similarity, or other parallelism between the two situa-
tions. Often biological effects need to be extrapolated from (1) laboratory
to field - many differences make this difficult; (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, biolog-
ical effects data are collected from a few life states of a few species for
a few routes of entry in a few controlled conditions. 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.
230
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TABLE 5-2. BIOASSAY TEST MATRIX*
Sample Type
ro
CO
Liquids (aqueous)
Solids
Solid leachates
(aqueous extract)
SASS Train
particulates
SASS Train organics
Gases
Mandatory Test
Ames mutagenici ty
CHO cytotoxicity
Whole animal (rodent acute)
toxicity
Freshwater or marine aquatic*
Ames mutagenicity
Ram cytotoxicity
Whole animal freshwater or
marine aquatic
Aquatic vertebrate
Aquatic algal
Aquatic invertebrate
Ames mutagenicity
CHO cytotoxicity
Whole, animal (rodent acute)
toxicity
Freshwater or marine aquatic
Ames mutagenicity
CHO cytotoxicity
Ames mutagenicity
CHO cytotoxicity
Recommended Test
Soil test
Plants stress
ethylene test
Optional Test
Additional cytotoxicity
Alternate freshwater
or marine aquatic
Additional cytotoxicity
Alternate freshwater or
marine aquatic
WI 38 cytotoxicity
Alternate freshwater or
marine aquatic
CHO cytotoxicity
WI 38 cytotoxicity
*Based on Reference 102 and information supplied to TRW by Dr. R. Merril, EPA, Research Trianqle Park
No. Carolina
Dash indicates no test recommended at this time.
^Includes aquatic vertebrate, algal and invertebrate tests
-------
Despite the technical difficulties involved in estimating permissible
concentrations of toxicants in emission streams, rational approaches are avail-
able for dealing with the problem. There are many potentially applicable for-
mulae, some of them developed by or for the EPA and other governmental agencies.
The formulae have two basic parts: a dose/response part and an adjustment
part. The dose/response generally consists of one of the typical laboratory
effects measurements: LD5Q, LDLQ, and TLm-96 hr.* Each effects measurement
is adjusted by several factors, the argument being that the adjusted dose/
response data better conform to the "real world" situation. Adjustments in-
clude the following: media conversion (e.g., air-borne to water-borne toxi-
cants), safety factors (e.g., 0.01), various types of exposure (e.g., work
day to full week), and elimination rate (e.g., biological half-life). In
quantifying health effects on human populations, the notion of dose/response
relationship takes on certain connotations. Dose characterization involves
such items as numbers of people exposed, duration of exposure, and concentra-
tion of chemicals in the media. The effects are in terms of a change in the
incidence or prevalence of certain diseases within the population. Thus, in
its simplest form, a dose/response relationship might be characterized as "5
years of exposure to sulfur dioxide at 0.05 ppm causes an excess of 7 respira-
tory disease deaths per 100,000 population."
In the current early stages of the methodology development, some rela-
tively broad classes of ratings are being used to indicate toxicity. These
toxicity ratings are:
« No effect - no observed difference between test organisms and
controls
• Low - a statistically significant difference can be observed
50: Lethal dose 50' i«e., the dose which when administered to a group of
animals is lethal to one-half of the population. The mode of admin-
istering the dose and the test animal must be specified.
LDLQ: Lethal dose low, i.e., the lowest dose of a substance introduced
in one or more portions by any route other than inhalation over
any period of time and reported to have caused death in a particular
animal species.
TLm: Median tolerance limit value, i.e., the concentration in water of
a pollutant required to kill 50 percent of a particular aquatic
species.
232
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• Medium - an observable effect is produced by 10 to 99% of the
maximum dose available in the system
• High - an effect is produced by only 10% or less of the maximum
dose
It is anticipated that this methodology will change as a result of devel-
opmental work which will be continuing and because of feedback from the chem-
ists and engineers who are expected to use the technique. However, it is
expected to be useful in broadening the applicability of bioassay interpre-
tation and in quantifying the effects in terms of significant difference be-
tween experimental organisms and human populations.
5.2 IMPACTS ON AIR
5.2.1 Summary of Air Standards and Guidelines
There are currently no Federal air emissions standards that apply specifi-
cally to gasification plants. EPA, however, has proposed standards and has
(22)
recently published guidelinesv ' for control of emissions from Lurgi coal gasi-
fication plants. New Mexico is presently the only state that has specific emis-
sions regulations for gasification plants. Certain processes and operations
within an integrated gasification plant (e.g., steam and power generation and
coal preparation) would be covered by existing Federal and state regulations
governing emissions from such sources.
EPA Guidelines for Control of Emissions from Lurnj Coal Gasification
Plants^ . Currently, no commercial SNG coal gasification plants are either
operating or under construction in the United States. Accordingly, much of the
emission control technology that will be employed to reduce emissions has not
been applied to coal gasification plants. A major area of uncertainty is how
well these controls will work in this application. Because of this, it has
been EPA's decision to temporarily delay the development and promulgation of
standards for gasification plants. EPA, however, has carried out extensive
background investigation and has developed a considerable data base for estab-
lishing such standards. The collected information, which has been subjected
to public review and includes inputs from developers and industry groups, was
recently published by EPA in summary form as a guideline document (EPA-450/2-78-
012) entitled "Control of Emissions from Lurgi Coal Gasification Plants'
233
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The guideline documents which is subject to revision as new data become
available, provides information on Lurgi coal gasification plants, their emis-
sions, technologies which can be used to control emissions, and the environmental
and economic impacts of applying these control technologies. Fuel conversion
plants are included in the definition of major emitting sources under Section
169 of the Clean Air Act. This means that any coal gasification plant must
obtain a permit before construction begins. The plant must apply best available
control technoloty (BACT) before a permit is granted. Since EPA currently does
not plan to develop a new source performance standard for Lurgi coal gasification
plants, it has instead published the guideline document to enable state, local,
and regional EPA enforcement personnel to determine BACT for Lurgi coal gasifi-
cation plants on a case-by-case basis. The guideline document identifies the
Rectisol process for acid gas removal as the major emission source within a
Lurgi coal gasification plant. Gasifier lockhopper, sour water stripping, by-
product recovery and catalyst regeneration and start-up gases are identified as
secondary sources of emissions. Two alternative emission control systems
(Systems I and II) are analyzed for the reduction of hydrocarbon and sulfur emis-
sions contained in the gas streams discharged from the Rectisol process. System
I consists of a Stretford sulfur recovery plant on the lean FLS stream discharged
from the Rectisol process and an ADIP FLS concentration plant followed by a
Claus sulfur recovery plant on the rich FLS gas stream. This system reflects
the minima,! level of emission control being considered and thus represents the
base case. Alternative emission control System II can consist of either (1) a
Stretford sulfur recovery plant on the combined lean and rich H^S gas streams
discharged from the Rectisol process (Option II-l) or (2) a Stretford plant on
the lean H2S gas stream and an ADIP H2S concentration plant followed by a Claus
plant and Claus plant tail gas treatment on the rich H2S gas stream (Option II-2)
to reduce emissions to a level comparable to that obtained by the application of
II-l.
Table 5-3 summarizes the emissions estimated from a 6.x x 10 kcal/day
(2.50 x 10 Btu/day) Lurgi SNG coal gasification plant under alternative emis-
sion control Systems I and II and for the uncontrolled condition. The data in
the table are for three types of coal which cover a rangeof candidate coals
considered for first generation gasification plants. The coal types are (1) a
western subbituminous coal of extremely low sulfur content, (2) a low sulfur
234
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TABLE 5-3. EMISSIONS FROM A 63 TRILLION KCAL (250 BILLION BTU) PER DAY LURGI SNG COAL GASIFICATION
PLANT WITH ALTERNATIVE EMISSION CONTROLS(22)
Pollutant
so2
H2S
HC*
Total
Sulfur,
as S
Sulfur
Recovery,
01
h
Uncontrolled
(a)f
--
2,563
(5,658)
7,954
(17,559)
2,424
(5,325)
0
(b)f
--
8,847
(19,530)
7,954
(17,559)
8,327
(18,381)
0
(Of
--
26,541
(58,589)
7,954
(17,559)
24,980
(55,143)
0
Alternative I
(a)
418
(022)
--
113
(250)
209
(461)
91.3
(b)
1,012
(2,^34)
--
113
(250)
506
(U17)
93.9
(c) 1
2,777
(6,131)
--
113
(250)
1,389
(3,066)
94.5
Alternative II (Options 1 and 2)
Ka)
209
(461)
--
113
(250)
104
(230)
95.7
Kb)
426
(941)
--
113
(250)
213
(470)
97.4
Kc)
1 ,035
(2,285)
--
113
(250)
517
(1,142)
97.9
2(a)
215
(474)
--
113
(250)
107
(237)
95.6
2(b)
441
(973)
--
113
(250)
220
(436)
97.4
2(c)
1,067
(2,355)
--
113
(250)
534
(1,178)
97.9
ro
CO
en
*A11 numbers in kg/hr (Ib/hr) except where noted
fSulfur/heating value ratios of 0.72, 2.2 and 6.5 kg/sulfur/106 kcal (0.4, 1.2 and 3.6 Ib sulfur/106 Btu), respectively
•Non-methane hydrocarbons, average molecular weight = 29
-------
western lignite, and (3) a high sulfur midwest bituminous coal. These coals
have sulfur/heating value ratios of 0.72, 2.2 and 6.5 kg sulfur/10 kcal (0.4,
1.2 and 3.6 Ib sulfur/10 Btu), respectively. As noted in the table, alternative
emission control System I achieves 91 to 95 percent control of sulfur compound
emissions while alternative emission control System II achieves 96 to 98 percent
control of sulfur compound emissions.
The two alternative control systems should achieve nearly the same level
of hydrocarbon emission control. Since sulfur emissions must be controlled,
coal gasification plants will select either the Stretford-Claus or the Stret-
ford-only emission control system. Where the Stretford-Claus approach is selec-
ted, the Glaus plant will not be an emission source of non-methane hydrocarbons,
since the hydrocarbons present in the rich waste gas stream will be removed
prior to the Glaus plant in an HLS concentration unit such as the ADIP process.
Where the Stretford-only approach is selected, incineration of the tail gas
would be required.
The EPA guidelines document reviews the advantages and disadvantages of
establishing emission standards for gasification plants based on "mass" emis-
sion limits and "concentration" emission limits. In general, mass limits are
more meaningful than concentration limits because mass limits relate directly
to the quantity of emissions discharged into the atmosphere. Enforcement of
mass limits is usually more complex and costly due to the need for a material
balance of some sort requiring process data concerning the operation of the
plant. A major disadvantage of the concentration limits is that of possible
circumvention by dilution of the pollutants being discharged to the atmosphere,
thus lowering the concentration of the pollutant but not the total mass emitted.
A review of the process flow sheets for the proposed commercial Lurgi SN6 plants
indicates that there are any number of possibilities for mixing various gas
streams, many of which would substantially alter the volume and hence the con-
centration of emissions, but not the mass of emissions released to the atmo-
sphere. Accordingly, standards predicated on mass of pollutants emitted are
considered preferable over concentration limits for the Lurgi SNG plants.
Whether a mass or a concentration format is selected, the numerical emis-
sion limit must vary depending on the properties of coal processed. For Lurgi
SNG plants the sulfur emissions would most closely correlate with the coal sulfur
236
-------
content and the coal heating value* and the hydrocarbon emissions correlate
most closely with the coal heating value. Based on the data in Table 5-3, the
following general formulas have been suggested for estimating sulfur and hydro-
carbon emissions:
ES = 0.07 (S )°'85 (HHV )°'15 for Control System I
t- (^
ES = 0.032 (Sr)0'75 (HHVJ0'25 for Control System II
t* c
EHC - 0.07 HHVc for Control Systems I and II
where
ES = total sulfur emissions (kg/hr)
S = coal sulfur input (kg/hr)
\»»
HHVc = coal heat input (MW)
EHC - emissions of non-methane hydrocarbons (kg/hr)
Selection of the alternative emission control systems has focused only on
the waste gas streams discharged from the Rectisol process. As noted earlier,
other emission sources exist within coal gasification plants. The Rectisol pro-
cess, however, is by far the major and most significant emission source account-
ing for about 95 percent of the potential sulfur emissions and about 85 percent
of the potential hydrocarbon emissions. Furthermore, for a number of these other
emission sources, the obvious emission control technique is to combine the waste
gas streams discharged with those discharged from the Rectisol process and con-
trol the combined gas streams. The emissions estimates shown in Table 5-3 for
alternative emission control Systems I and II assume control of the waste gas
streams discharged from other emission sources as follows:
Coal gasifier coal lock:
(a) Pressurization of the coal lock with an inert gas such as
N2 or C02 with release of these gases, as the lock is de-
pressurized to about 1.8 MPa (250 psig), to a gas collection
and storage system for recycle to the coal lock when it is
repressurized. Residual gases released as the lock is de-
pressurized below 1.8 MPa (250 psig) are released directly
to the atmosphere.
*The waste gas streams discharged by a Lurgi SNG plant are predominantly carbon
dioxide (i.e., 50-95 percent COz)• The coal heating value, or the higher heat-
ing value (HHV), is a function of the coal carbon content, and the carbon con-
tent determines the volume of the C02 gas produced.
237
-------
(b) Or alternatively, pressurization of the coal lock with raw
coal gas with release of these gases to the Rectisol emis-
sion control system as the lock is depressurized to about
0.1 MPa (0.5 psig). Residual gases released as the lock is
depressurized completely are released directly to the atmo-
sphere.
Sour water stripping:
Control of these gases in the Rectisol emission control system.
By-product recovery, catalyst regeneration and startup:
Control of these gases by incineration or flares.
The above equations are based on a number of assumptions including some relat
ing to gas compositions and anticipated performance of the alternative emission
control systems. Some revisions to the above equations or adjustments to the
calculated emission limit may become necessary as data become available from
actual operations.
Miscellaneous Federal and State Standards Affecting Air Emissions from
Lurgi SNG Plants. Even though there are currently no federal or state (except
for New Mexico) standards that apply specifically to coal gasification plants,
a number of federal and state air emissions and ambient air quality standards
are currently in effect or are being developed which would impact the operation
of coal gasification plants or specific process/units within an integrated SNG
facility. These standards include:
National and State Ambient Air Quality Standards
Prevention of Significant Deterioration (PSD) Regulations
New Source Performance Standards for:
fossil fuel steam generation
coal preparation
incineration
hydrocarbon storage vessels
sulfur recovery plants
New Mexico Emission Standards for Coal Gasification Plants
The 1970 Federal Clean Air Act Amendments established a common framework
for federal, state and local governments to work together for the control of air
pollutants and achievement of a cleaner air. The provisions of this act were
expanded and made more specific by the recent enactment of the Clean Air Act
Amendments of 1977. Key elements of these legislations include:
238
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« Promulgation by EPA of national ambient air quality standards (NAAQS)
for major pollutants, including NOX, SOX and total suspended parti-
culates (TSP), with states having the option to establish more strin-
gent standards if they so desire.
• Development and submission for EPA approval by states of state
implementation plans (SIPs) which specify how the NAAQS (or their
own state standards, if more stringent) will be achieved (including
emission limitations, compliance schedules and enforcement provisions)
within three years of promulgation of the SIPs.
• Establishment by EPA of national emission standards for certain
source categories; Sections 111 and 112 of the Act directs EPA to
establish standards of performance for new sources and national
emission standards for hazardous air pollutants.
• Prevention of significant air quality deterioration by states in
those cases where the air quality is already better than NAAQS.
National Ambient Air Quality Standards. Under Section 109 of the Act, EPA
is required to set two basic types of ambient air quality standards: primary
standards (for the protection of human health) and secondary standards (for the
protection of public welfare). The two sets of standards, promulgated in 1971,
are presented in Table 5-4. Thirty-five states have promulgated state ambient
SCL standards more stringent than NAAQS. The ambient TSP standards for fifteen
states are more stringent than NAAQS. None of the states have more stringent
NO standards. Table 5-5 lists standards for selected states which are sites
X
for proposed commercial gasification plants or are candidates for siting such
facilities (see Sections 2.1.6 and 4.8 for siting considerations for Lurgi coal
gasification facilities).
Prevention of Significant Deterioration of Air Quality^ •'. The Clean
Air Act (Part C) authorizes a preconstruction review and permitting authority
for major facilities in areas that are cleaner than the NAAQS. Table 5-6 shows
the maximum permissible increase in concentration above baseline values under
various averageable conditions for "Class I," "Class II," and "Class III" areas
The 1977 Amendments designate the following mandatory Class I Federal areas:
international parks, wilderness areas in excess of 2080 hectares (5000 acres),
national memorial parks in excess of 2080 hectares (5000 acres), and national
parks in excess of 2500 hectares (6000 acres). Initially, all other areas are
designated as Class II, but the states may, under certain conditions, re-desig-
nate certain areas toward either the more pristine Class I or the "dirtier"
239
-------
TABLE 5-4. NATIONAL AMBIENT AIR QUALITY STANDARDS FOR CRITERIA POLLUTANTS(104)
Pollutant
Pollutant Standard
Primary*
Secondary"*"
Nitrogen dioxide
Carbon monoxide
Sulfur dioxide
Organics
Total suspended
particulate
Photochemical
oxidant
100 yg/m3 (0.05 ppm) annual
arithmetic mean
10 mg/m3 (9 ppm) maximum
8-hour average
40 mg/m3 (35 ppm) maximum
1-hour average
80 yg/m3 (0.03 ppm) annual
arithmetic mean
365 yg/m3 (0.14 ppm)
maximum 24-hr, average
160 yg/m3 (0.24 ppm)
maximum 3-hour average
6 to 9 A.M.
75 yg/m3 annual geometric
mean
260 yg/m3 maximum 24-hour
average
160 yg/m3 (0.08 ppm)
maximum 1-hour average
Same as primary
Same as primary
1300 yg/m3 (0.05 ppm)
maximum 3-hour average
Same as primary
60 yg/m3 annual geometric
mean
150 yg/m3 maximum 24-hour
average
Same as primary
*Primary, necessary to protect the public health
fSecondary, necessary to protect the public welfare
240
-------
TABLE 5-5. SUMMARY OF STATE AMBIENT AIR QUALITY REGULATIONS
(102)
region: State
HO,
Hydrocarbons
Suspended Participate
Eastern Interior:
Illinois
TOO pg/m Annual
arithmetic mean
Indiana
ro
Kentucky
Same as above
Same as above
Primary:
0
80 jjg/m3 (0.03 ppm)
Annual arithmetic
mean
(2) 365 jjg/m3 (0.14) +
Maximum 24-hr
average
Secondary:
(1) 1 ,300 >.g/m3 (0.5 ppm)
Maximum 3-hr
average
Same as above
Sane as above
Non-methane hydrocarbons
measured as methane:
160 jjg/m3 (0.24 ppm) +
Maximum 3-hr average
6-9 a.m.
Same as above
Same as above
Primary:
(1 ) 75 jjg/m3 Annual
(2)
geometric mean
260;.g/mJ+
Maximum 24-hr
average
Secondary: ,
(1 ) 60 pg/m Annual
geometric mean
(2) 150 >jg/nr+
Maximum 24-hr
average
Primary:
as above
Same
Secondary:
150 vg/"' Maximum
24-hr average
Primary: ,
(1) 75 yg/m Annual
geometric mean
(2) 260 vg/tr,3+ Maximum
24-hr average
(3) Soiling index:
6.0 COH/1000 LF
Maximum 24-hr
Secondary: ,
(1) 60 jjg/m Annual
geometric mean
(2) 150 pg/m + Maximum
24-hr average
(3) 0.4 COH/1000 LF
Annual arithmetic mean
(4) 0.5 COH/10CO LF
Maximum 3-mo average
(5) 0.3 COH/1000 LF
Maximum 24-hr average
(6) Settleable f-artlculates:
5.25g/mz/mo
Maximum 3-mo average
(continued)
-------
TABLE 5-5. CONTINUED
Region: State
NO,
SO,
Hydrocarbons
Suspended Participate
Pennsylvania
West Virginia
Same as Federal standards Same as Federal standards Seme as Fedaral standards
None
Primary: , None
(1) 80 yg/mj (0.03 ppm)
Annual arithmetic mean
(2) 365 vg/iti3 (0.14 ppm) +
Maximum 24-hr average
Secondary: ,
(1) 1,300 ug/nr (0.50 ppm)+
Maximum 3-hr average
(2) 260
Ohio
100 g/m Annual
arithmetic mean
no
->
ro
Northeastern Great Plains:
North Dakota
(1) 100 g/m3 (0.05 ppm)
Annual arithmetic mean
(2) 200 g/mj (0.10 ppm)
Maximum 1-hr average
not to be exceeded
more than IX of the
time
(1) 60 pg/m3 (0.02 ppm)
Annual arithmetic mean
(2) 260 ng/ro3 (0.10 ppm)
Maximum 24-hr average
(1) 60 pg/m3 (0.02 ppm)
Annual arithmetic mean
(2) 260 pg/mj (0.10 ppm)
Maximum 24-hr average
(3) 715 pg/,n3 CO.28 ppm}
Maximum 1-hr average
Non-methinfe hydrocarbons
measured as carbon
(1) 126 pg/mj (C.I9 ppm)
Maximum 3-hr average
between 6 and 9 a.m..
(2) 331 ug/m3 (0.50 ppm)*
Maximum 24-hr average
Non-methane as
methane:,
160 pg/mj (0.24 pi*.)
Maximum 3-lir average
between 6 and 9 a.m.
Settled Partlculate:
(1) 0.8 Mg/cm A.O
Annual average
(2) 1.5 ^g/cm /mo
30-day average
Primary:
(1) 75 11 g/m Annual
geometric mean
(Z) 260 i/g/m3f Maximum
24-hr average
Secondary:
(1) 60 pg/m-' Annual
geometric mean
(Z) 150 j
-------
TABLE 5-5. CONTINUED
ro
-n=>
oo
Region: State NO-
Northwestern Great Plains:
Montana None
Wyoming 100 pg/nr' (p. 05 ppm)
Annual artthmettc jnean
SO., Hydrocarbons
(.1) 0.02 ppra Annual None
average
(2) 0.10 ppro 24-hr
average not to
be exceeded more
than 1% of the days
in any 3-month
period
(3) 0.25 ppm not to be
exceeded for more
than 1-hr in any
4 consecutive days
(1) 60 pg/m3 (0.2 ppm) Non-methane measured
Annual arithmetic as methane:
mean 160 g/m (0.24 ppm)
(2) 260 pg/m3 (0.10 ppm) Maximum 3-hr average
Maximum 24-hr average between 6 and 9 a.m.
not to be exceeded
more than once per
year
(3) 1 ,300 pg/nr (0.50 ppm)
Maximum 3-hr average
not to be exceeded
more than once per
year
Suspended Partlculate
Coefficient of liaze:
0.4 COH/1000 LF
Annual geometric mean
Suspended; ,
0 ) 75 pg/m Annual
geometric mean
(2) 200 jjg/m3 Not to exceed
more than 1% of the days
a year
Settled:
(.1) 5.25 g/m2/mo
(15 tons/ml 2/mo)
1n residential areas
(2} 10.50 s/mz/mo
(30 tons/m12/mo)
In industrial areas
Suspended: ,
(1 ) 60 pg/m Annual
geometric n.ean
(2) 150 pg/m3 Maximum
24-hr average
j. j.
Soiling Index:
(1 ) 0.4 COH/1000 LF
Annual geometric mean
Settleable:
(1 ) 5 g/m^/mo for
any 30-day period In
Rocky Mountain:
Colorado
None
Outside of Air Quality
Control Areas:
15 pg/nr Maximum
24-hr average not
to be exceeded more
than once 1n any
12-mo ppriod
Within Air Quality
Control Areas:
(1)10 pg/m2 Annual
arithmetic moan
(2) 55 pg/m3 Maximum
24-hr Average not
to be exceeded
more than once
In any 12-montn.
period
None
residential areas
(Z) 10 g/m2/mo for any
30-day period 1n
industrial areas
^ ***
{1 ) 45 pg/mj Annual
arithmetic mean
(2) 150 pg/m3 Maximum
24-hr average not to
be exceeded more
than once In any
12-mo period
[continued)
-------
TABLE 5-5. CONTINUED
Region: State N02 SC2 Hydrocarbons Suspended Particulate
New Mexico (1) 0.05 ppm Annual (1) 0.02 ppm Annual Non-methan hydrocarbons: Suspended: ,
arithmetic average arithmetic average 0.19 ppm 3-hr average (1) 60 pg/m Annual
(2) 0.10 ppm 24-hr (2) 0.10 ppm 24-hr geometric mean
average average (2) 90 pg/ii,3 30-day
average
(3) 110 yt,/n,3 7-day
average ,
(4) 150 ^g/n. 24-hr
average
Soiling index:
0.4 CGH/1000 LF
Annual average
+
Mot to be exceeded more than once per year.
++"Soiling Index" means a measure of the soiling property or suspended particles in air determined by drawing a measured volume of air
thorough a known area of Whatman No. 4 filter for a measured period of time, expressed as COH (Coefficient of Haze)/1000 LF (Linear
feet).
Dilutions with odorless air to reduce odor to below odor threshold level.
.Note the terms suspended sulfate, sulfation and SO, are not used in a consistent manner by the states.
** J ~~
In all areas on or before 1 January 1980.
-------
Class III. However, the reclassification as Class III requires an extensive
public hearing procedure.
TABLE 5-6. MAXIMUM PERMISSIBLE INCREMENTS FOR SULFUR DIOXIDE AND PARTICULATE
MATTER CONCENTRATIONS IN AMBIENT AIR FOR EACH PSD CLASS COMPARED
TO NAAQS VALUES (QUANTITIES IN MG/M3)
Pollutant
so2
TSP
Period for
Averaging
Annual
24-hour
3-hour
Annual
24-hour
Maximum Concentration Increments
Class I Class II Class III NAAQS
2
8
25
5
10
20
91
512
19
37
40
182
700
37
75
80
365
1300*
7560*
260,150*
^Secondary standards
By August 1979 the EPA must also promulgate classification incremental
values for hydrocarbons, carbon monoxide, photochemical oxidants and nitrogen
oxides. For any other pollutant for which NAAQS are established, EPA must prom-
ulgate classification incremental values within two years of promulgation of the
standard.
In order to protect Class I areas, no major emitting facility can be con-
structed without a permit establishing emission limitations. Prior to the issu-
ance of such a permit, EPA must require an analysis of the ambient air quality
and visibility, climate and meteorology, terrain, soils, and vegetation, both
at the site of the proposed facility and in the area potentially affected by
emissions from the facility, for each pollutant regulated under the Clean Air
Act. Furthermore, EPA must determine the degree of continuous emission reduc-
tion which could be achieved by the facility.
Another regulatory approach has been made possible under Part D of the
Clean Air Act. This deals with "non-attainment areas," i.e., those which are
polluted above the levels necessary to protect health and welfare. It puts into
effect an off-set policy which, in effect, can regulate industrial growth in
such areas. In order to issue a permit to a major new source which seeks to
locate in the non-attainment area, the state must show that the total emissions
from aJJ^ sources in the area will be sufficiently less than the total emissions
allowed for existing sources prior to construction of the major new source. In
other words, the baseline for calculating offset is the total emissions allowed
245
-------
in the SIP without taking the new source into consideration. As a condition
for permitting major new stationary sources to locate in non-attainment areas,
the states are required to obtain EPA approval for revised SIPs which include
provision for attainment of the primary NAAQS values (health realted standards)
no later than December 31, 1982, except for photochemical oxidant and carbon
monoxide, for which attainment is delayed until December 31, 1987. Among other
things the new SIP must include a permit program for new stationary sources in
which they must operate at the "lowest achievable emission rate" reflecting the
most stringent emission limitation contained in any_ SIP for any such class or
category of source, or the most stringent emission limitation which has been
achieved in practice whichever is most restrictive.
New Source Performance Standards (NSPS). Section III of the Clean Air Act
requires EPA to set standards of performance for new or modified stationary
(point) sources. These are nationally applicable direct emission limitations
for specific source types (e.g., fossil fuel-fired steam generators). This
limitation reflects the pollutant reduction achievable through use of the best
technological system of continuous emission control (taking into account cost,
non-air quality health and environmental impact and energy requirements) which
the EPA determines has been adequately demonstrated. In those cases where it
is not feasible to prescribe or enforce a standard of performance, the Adminis-
trator may, instead, promulgate a design, equipment, work practice or operational
standard - or a combination of these - which has been determined to adequately
demonstrate the best technological system of continuous emission reduction (tak-
ing into account cost, non-air quality health and environmental impact and
energy requirements). These NSPS regulations must be reviewed and revised, if
appropriate, every four years.
Several emissions sources in a Lurgi SNG facility would be subject to
Federal NSPS. Table 5-7 summarizes these standards for fossil fuel- and lignite-
fired steam generators, coal preparation plants, solid waste incinerators and
hydrocarbon storage vessels.
National Emission Standards for Hazardous Air Pollutants (NESHAP). Section
112 of the Clean Air Act defines a hazardous air pollutant as one for which no
NAAQS is applicable and which, in the judgment of the EPA, causes or contributes
to air pollution in a manner that may result in an increase of mortality or
irreversible or incapacitating reversible illness. Section 112 authorizes the
246
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TABLE 5-7. SUMMARY OF FEDERAL EMISSION STANDARDS APPLICABLE TO INTEGRATED LURGI SNG FACILITIES
ro
-f^
•-j
Air Standard
or Guideline
1 Fossil Fuel Steam
Generators (except
lignite) NSPS
- Coal and coal
derived fuels
• Subbi tumi nous
coal and liquid
and gaseous fuels
deri ved from coal
• Bituminous coal
- Gaseous and liquid
fuels not derived
from coal
• Gaseous fuels
• Liquid fuels
2. Lignite Fuel Steam
Generators NSPS
3. Coal Preparation,
NSPS
Applicable Source
Power plant (steam and
electric generation)
and steam superheater
Power plant (steam and
electric generation)
and steam superheater
Coal preparation opera-
tions for gasifier and
power plant
NOX (as N02)
0.88 g/MM cal, (106)
(0.210 ng/J)
(0.50 Ib/MM Btu)
1.1 g/MM cal, ('05>
(260 ng/J)
(0.60 Ib/MM Btu)
0.36 g/MM cal ,'107'
(86 ng/J)
(0.20 Ib/MM Btu)
0.54 g/MM cal,1107'
(130 ng/J)
(0.30 Ib/MM Btu)
1.1 gm/MM cal,(103)
(260 ng/J)
(0.6 Ib/MM Btu)
None
S02 (Sulfur)
2.2 g/MM cal(106)
(520 ng/J)
(1.2 Ib/MM Btu)
AMD
85" control
unless
0.36 g/MM cal
(86 ng/J)
(0.20 Ib/MM Btu)
1.4 g/MM cal,(106)
(340 ng/J)
(0.80 g/MM Btu)
AND
85% control
unless
0.36 g/MM cal
(86 ng/J)
(0.20 g/MM Btu)
2.2 q/MMcal.(106)
(520 ng/J)
(1.2 Ib/MM Btu)
AND
85^ control
unless
0.36 g/MM cal
(86 ng/J)
(0.20 g/MM Btu)
None
Non-methane
Hydrocarbons
None
Particulates
0.054 g/MM Btu,(106)
(13 ng/J)
(0.030 Ib/MM Btu)
20%
None
AND
opacity
None i Pneumatic cleanina'130'
equipment:
0
.040 g/dscm
(0.018 g/dscf)
20
AND
"-- opacity
i i Processing and con-
veying equipment:
4. Incineration
NSPS
5. Hydrocarbon Storage
Vessels NSPS
Solid waste
i nci nerati on
By-product storage
None
None
None
None
20
opacity
-> nt?\
None 0.18 g/NmJ (0.08 grains/'""'
scf corrected to 12% Oj
Equipment specifi- None
cations based on
vapor pressure
-------
EPA to set emission standards for these hazardous substances which are applicable
to any new source or modified existing sources. To date NESHAP's have been prom-
ulgated for asbestos, beryllium, mercury, and vinyl chloride. None of these
substances is expected to be a major emission problem for Lurgi SNG facilities.
New Mexico State Emission Standards for Gasification Plants. New Mexico
is the only state at present which has developed regulations for gasification
plants. As indicated in Table 5-8, the state has chosen a combination of mass
and concentration limits for various gaseous pollutants associated with the
gasification plant. Mass limits have been established for gas-fired power
plants associated with SNG facilities.
5.2.2 Comparison of Waste Streams with Emissions Standards
In this section emissions estimates for Lurgi SNG plants are compared with
the Federal guidelines and the New Mexico state standards for such plants.
Also, the emissions from on-site steam and power generation at Lurgi plants are
compared with the corresponding Federal standards. Emission estimates considered
are: (a) those reported for five proposed commercial projects and (b) those
prepared in this study for the five control options analyzed (see Section 4.2.5).
Table 5-9 compares the estimated total sulfur emissions from gasification
with the appropriate Federal guidelines and New Mexico standards. The data in
this table indicate that the two plants to be located in New Mexico (WESCO and
El Paso) would meet both the Federal guidelines and the New Mexico state stan-
dards, whereas the two plants proposed for North Dakota (AN6 and Dunn Co.)
would exceed both the Federal guidelines and New Mexico standards. The proposed
Wyoming plant would meet the Federal guidelines only. It should be noted that
the designs for all the proposed commercial plants were prepared before the
publication of the Federal guidelines and that the New Mexico standards would
only apply to plants located in New Mexico. Except for Option 4, the control
options examined meet the Federal guidelines. Option 4 employs FGD systems for
combined treatment of the incinerated Rectisol acid gases and boiler flue gases;
FGD systems are generally not as effective as acid gas treatment via sulfur re-
covery used in other options. Only Option 3, which features sulfur recovery/
tail gas treatment, meets the more stringent New Mexico standards.
24^
-------
TABLE 5-8. NEW MEXICO EMISSION REGULATIONS APPLICABLE TO LURGI SN6
Pollutant
Emission Limits for
Gas-Fired Power Plant
Associated with
Gasification Plant
Emission Limits for
Direct Emissions from
Gasification Plant
Sulfur compounds
Particulate matter
Oxides of nitrogen
Hydrogen cyanide
(HCN)
Hydrochloric acid
(HC1)
Amnonia
(NH3)
0.28 grams/106 cal*
(0.16 Ibs S02/106 Btu)
0.053 grams/106 cal
(0.03 lbs/106 Btu)
3.5 grams/lO0 cal
(0.02 lbs/106 Btu)
(as N02)
1) 0.015 grams total sulfur
per 10° cal of coal feed*
(0.008 lbs/106 Btu)
2) 100 ppm sum of H2S, COS,
and CS2
3) 10 ppm H2S
.065 grams/Mm13
(.03 grains/scf)
10 ppm
5 ppm
25 ppm
*Based on HHV of fuel
249
-------
TABLE 5-9. COMPARISON OF ESTIMATED SULFUR EMISSIONS FROM LURGI GASIFICATION PLANTS WITH
APPROPRIATE EMISSION GUIDELINES/STANDARDS*
Pollutant
Source
Gasification
plant
Project/
Control
Options
Projects
WESCO
El Paso
ANG
Wyoming
Dunn Co.
Control
Options*
Option 1
Option 2
Option 3
Option 4
Option 5
Estimated Emissions
kg/hr (Ib/hr)
77 (170)
116 (256)
545 (1202)
164 (362)
460 (1014)
250 (551)
250 (551)
20 (44)
1200 (2650)
240 (529)
g/MM cal (Ib/HM Btu)
0.019 (0.011)
0.029 (0.016)
0.14 (0.075)
0.041 (0.023)
0.11 (0.063)
0.061 (0.034)
0.061 (0.034)
0.005 (0.003)
0.31 (0.17)
0.060 (0.033)
Appl icable
Federal Standard
kg/hr (Ib/hr)
1016 (2240)
354 (780)
444 (979)
1118 (2465)
192 (423)
354 (780)
354 (780)
354 (780)
354 (780)
354 (780)
Appl icable
New Mexico Standard
kg/HM cal (Ib/MM Btu)
0.029 (0.016)
0.029 (0.016)
0.029 (0.016)
0.029 (0.016)
0.029 (0.016)
0.029 (0.016)
0.029 (0.016)
0.029 (0.016)
0.029 (0.016)
0.029 (0.016)
Meets/Exceeds
Federal Guideline
Meets
Meets
Exceeds
Meets
Exceeds
Meets
Meets
Meets
Exceeds
Meets
Meets/Exceeds
New Mexico Standard
Meets
Meets
Exceeds
Exceeds
Exceeds
Exceeds
Exceeds
Meets
Exceeds
Exceeds
ro
en
O
*A11 values are expressed as S02
+See Section 4.2.5 for description of options which are applied to emission streams considered in this study.
-------
The Federal guidelines would allow approximately 300 kg/hr of non-methane
hydrocarbons to be emitted from a 7 x 106 Nm3/d (250 MMscf/d) plant. This is
based on the use of incineration for the control of sulfur recovery tail gases.
Accordingly, when off-gases are incinerated in a Lurgi plant (alone or in con-
junction with steam and power generation) the Federal standards should be met.
Actual operating data are not available on the efficiency of off-gas incinera-
tion systems for distribution of HC in off-gases. Since it is generally assumed
that the incineration of off-gases for the control of HC emissions also results
in the destruction of CO, no guidelines have been developed for CO emissions.
Tables 5-10, 5-11 and 5-12 compare the estimated emissions of S0?, particui-
lates and NOX from onsite power and steam generation with the Federal standards.
As with the gasification emissions, the Hew Mexico projects, which were designed
to meet the more stringent state standards (for fossil fuel-fired boilers), meet
the Federal standards for all three pollutants. The designs for the proposed
plants in North Dakota and Wyoming were prepared before the promulgation of the
Federal standards; additional pollution control would be required for these
plants in order to meet the Federal standards. All five control options examined
would meet the S09 emissions standards. The emissions factors used to estimate
particulate and NO emissions are those reported in AP-42U 'and are generally
A
for controls which are less stringent than those required to meet the new Federal
standards. Accordingly, the estimated particulate and NO emissions for the
A
five options somewhat exceed the new Federal standards.
5.2.3 Impacts on Ambient Air Quality
Ambient air quality modelling has been conducted for four of the five pro-
posed commercial Lurgi SNG plants and in conjunction with the development of
Federal guidelines for Lurgi SNG plants. The predicted maximum ground level
concentrations for various averaging times are presented in Table 5-13 for the
four plants and for the two control options considered by EPA in developing
Federal guidelines. While there are some differences between the predicted
concentrations for the cases considered, in all cases the predicted levels are
well below the Federal and state ambient standards for S02, N0x, non-methane
hydrocarbons and particulates, and carbon monoxide (see Tables 5-4 and 5-5 for
ambient air quality standards). The observed differences reflect differences
in emission levels, assumed stack heights and locations, meteorological condi-
tions and the particular diffusion model used.
251
-------
TABLE 5-10. COMPARISON OF S02 EMISSIONS FROM ONSITE STEAM AND POWER GENERATION WITH APPROPRIATE
FEDERAL STANDARDS
Project/
Control
Options
Project
WES CO
El Paso
ANG
Wyoming
Dunn Co.
Control
Options*
Option 1
Option 2
Option 3
Option 4
Option 5
Estimated E-cvissi
kg/hr (Ib/hr)
265 (584)
41 (90)
640 (1410)
1035 (2282)
860 (1900)
150 (330)
20 (44)
280 (620)
300 (660)
280 (620)
g/106 cal
0.29
0.058
1.3
1.3
0.90
0.21
0.03
0.40
0.43
0.40
ons
(lb/106 Btu)
(0.16)
(0.032)
(0.72)
(0.73)
(0.50)
(0.12)
(0.02)
(0.22)
(0.24)
(0.22)
Federal Standard
g/106 cal
0.56
0.45
0.94
0.36
0.67
0.45
0.36
0.45
0.45
0.45
(lb/106 Btu)
(0.32)
(0.25)
(0.52)
(0.2)
(0.37)
(0.25)
(0.2)
(0.25)
(0.25)
(0.25)
Meets/Exceeds
Federal Standard
Meets
Meets
Exceeds
Exceeds
Exceeds
Meets
Meets
Meets
Meets
Meets
ro
en
ro
*See Section 4.2.5 for description of options
-------
TABLE 5-11. COMPARISON OF ESTIMATED PARTICULATE EMISSIONS FROM ONSITE STEAM AND POUER GENERATION
WITH FEDERAL EMISSION STANDARDS
ro
en
CO
Project/
Control Option
Proposed Projects
El Paso
WES CO
ANG
Wyomi ng
Dunn Co.
Control Options*
Option 1
Option 2
Option 3
Option 4
Option 5
g/MM cal (Ib/MM Btu)
Estimated
Emissions
<.05 (0.03)
0.020 (0.011)
0.13 (0.072)
0.034 (0.018)
0.175 (0.097)
0.09 (0.05)
—
0.07 (0.04)
0.07 (0.04)
0.07 (0.03)
Federal
Standards
__
0.054 (0.030)
0.054 (0,030)
0.054 (0,030)
0.054 (0.030)
0.054 (0.030)
None
0.054 (0.030)
0.054 (0.030)
0.054 (0.030)
Meets/Exceeds
Federal Standards
Meets
Exceeds
Meets
Exceeds
--
Exceeds
—
Exceeds
Exceeds
Exceeds
''See Section 4.2.5 for description of options
-------
TABLE 5-12. COMPARISON OF ESTIMATED NOX EMISSIONS FROM ONSITE STEAM AND POWER GENERATION WITH FEDERAL
STANDARDS
Project/
Control Option
Proposed Projects
El Paso
WESCO
ANG
Wyoming
Dunn Co.
Control Options*
Option 1
Option 2
Option 3
Option 4
Option 5
g/MM cal (Ib/MM Btu)
Estimated
Emissions
0.36 (0.2)
0.45 (0.25)
1.0 (0.55)
1.3 (0.70)
1.3 (0.72)
1.3 (0.7)
2.0 (1.11)
1.6 (0.89)
1.4 (0.78)
1.6 (0.89)
Federal
Standards
0.88 (0.50)
0.88 (0.50)
1.1 (0.6)
0.88 (0.50)
1.1 (0.6)
0.88 (0.50)
0.88 (0.50)
0.88 (0.50)
0.88 (0.50)
0.88 (0.50)
Meets/Exceeds
Federal Standards
Meets
Meets
Meets
Exceeds
Exceeds
Exceeds
Exceeds
Exceeds
Exceeds
Exceeds
*See Section 4.2.5 for description of options
-------
TABEL 5-13. MAXIMUM PREDICTED GROUND-LEVEL CONCENTRATIONS ASSOCIATED WITH LURGI
SNG FACILITIES*
Plant/Option
WES CO
ANG§
El Paso
Wyoming
EPA Control
Option I
EPA Control
Option II
Averaging
Time
Annual
24-hour
3-hour
Annual
24-hour
3-hour
1-hour
Annual
24-hour
3-hour
Annual
24-hour
3-hour
Annual
24-hour
8-hour
3-hour
Annual
24- hour
8-hour
3-hour
yg/m3
NOX
2.3
4.6
98
0.5
—
--
32.5
3.5
23
--
17
--
--
__
--
--
--
_ _
—
—
—
S02
1.3
2.4
51
2.4
24.3
61.8
152.8
3.2
21
123
13
44
218
1-5
15-100
—
100-700
1-5
10-70
—
100-450
NMHC+
__
—
0.16 ppm*
__
--
—
—
__
--
—
—
--
—
<1
—
--
3-5
<1
--
3-5
—
Particulates
1
1
3
0.1
0.8
--
--
—
--
--
1
3
--
—
--
--
—
—
--
--
—
CO
_ _
—
--
_ _
--
--
--
—
--
--
—
—
--
—
--
1-3
—
—
—
1-3
—
*See Tables 5-4 and 5-5 for Federal and state ambient air quality standards.
"^Non-methane hydrocarbons
*ppm as CH4
Attributable to gasification facility only; a large power plant is also to
located nearby.
be
255
-------
For the two EPA control options, the PSD increment for a Class II Region
would be met by plants gasifying low to medium sulfur coals. However, when high
sulfur coals are to be handled, the PSD increment for a Class II Region may be
exceeded (at least for control Option 1). Comparison of the data in Table 5-13
for Options 1 and 2 indicate very little improvement in ambient air quality as
a result of the more stringent S02 control in Option 2. This is primarily due to
the overriding effects of the emissions from onsite power and steam generation.
Except for the S02 emissions for Option 4, the estimated emissions assoc-
iated with the control options examined in this study are lower than those used
in calculating concentration levels shown in Table 5-13. Accordingly, the
ground level concentrations resulting from the application of these control
options should be lower than those shown in Table 5-13 (assuming similar stack
heights, locations, etc.). Although a somewhat higher S02 emission is associated
with Option 4, the increase in ambient level concentration would be small and
not likely to result in the violation of the ambient S02 standard.
Although neither the predicted ambient NO nor non-methane hydrocarbon
(1101
levels shown in Table 5-13 exceed the air quality standards, a recent study^ '
has suggested that the oxidants resulting from the photochemical reactions of
these pollutants may exceed the NAAQS for oxidants. This study, however, assumes
HC and NO emissions of about 1000 kg/hr and 2100 kg/hr, respectively. These
X
emission levels are about three times as much as those which would be allowed in
order to meet the Federal standards/guidelines for Lurqi SNG plants. Ambient
oxidant levels which would be expected from lower NOX and non-methane HC emission
levels have not been estimated.
5.2.4 Evaluation of Unregulated Pollutants and Bioassay Results
Unregulated (non-criteria) pollutants present in emissions from Lurgi SNG
facilities may include reduced sulfur and nitrogen compounds (H^S, COS, CS2,
mercaptans, HCN and NH,), HC1, aromatic hydrocarbons, heterocyclic organics,
metal carbonyls,organometallic compounds,and trace elements. Although limited
data are available on the concentration of some of these substances in certain
untreated gaseous waste streams in a Lurgi plant, no data are available on the
concentration of residuals (if any) in the final emissions to allow estimation
of the ambient impact. Incineration, which is the proposed control for all gases
before atmospheric discharge, is expected to convert most of the above types
256
-------
of substances to harmless compounds (e.g., C02), or to criteria pollutants
(e.g., S09, NO and particulates).*
£ A
Incineration of waste gases would convert most trace elements to oxides
which become components of the particulate matter. Some trace elements (e.g.,
mercury, arsenic, selenium, fluorine and chlorine) would appear in the final
emissions as gaseous compounds. Based on mass balance calculations (see data
in Chapter 3), in the gasification of coals essentially 100 percent of most
trace elements can be found in the ash, tar, oil and gas liquor. Accordingly,
negligible quantities of trace elements are expected to be found in gaseous
emissions associated with the gasification, gas purification and gas upgrading
operations. Onsite steam and power generation using coal or gasification by-
products as fuels may result in emissions of the more volatile trace elements
(e.g., Hg, F, Cl) to the atmosphere. The amount of trace element emissions
from fuel combustion is determined largely by the feed coal composition and by
the pollution control equipment used.
Although no bioassay data are currently available for gaseous emissions
from Lurgi gasification plants, such data are currently being collected in
connection with the EPA (IERL/RTP) sampling and analysis program at the Kosovo
plant. Bioassay data have also been collected by EPA for other gasification
processes.
5.3 IMPACT ON WATER
5.3.1 Summary of Hater Standards
At present there are no specific Federal or state effluent regulations for
Lurgi SNG facilities. The Federal Water Pollution Control Act (FWPCA; PL 92-
500) and the Clean Hater Act Amendments of 1977 (PL 95-217), however, authorize
the U.S. EPA to establish effluent limitations and guidelines and new source
performance standards for point source discharges into natural waters. The
Effluent Guidelines Division of the U.S. EPA is currently revising the list of
industrial categories for which effluent guidelines and limitations and new
source performance standards are to be established. Pursuant to this effort,
*The Federal guidelines for Lurgi and gasification plants(22) and the designs
for the proposed commercial facilities assume that incineration results in
nearly complete oxidation of oxidizable substances.
257
-------
EPA is currently developing background information on synthetic fuel techno-
logies, and it is possible that Lurgi SNG plants will be included in the re-
vised industry category list for which new source performance standards will be
established.
Two other water laws/standards which might impact effluent discharges from
Lurgi SNG plants are: the 1974 Safe Drinking Water Act (SDWA; PL 93-523) and
state deep well injection regulations. A brief discussion of the FWPCA, the
Clean Water Act Amendments, state deep well injection laws and the SDWA follows.
FWPCA and the Clean Water Act Amendments. FWPCA, which is the most com-
prehensive water legislation ever passed by the Congress, is aimed at restoring
and maintaining the integrity of the nation's waters. The Act directs EPA to
develop and enforce standards for waste discharges into navigable waters and
publicly owned wastewater treatment plants. It sets specific timetables
for industry to achieve effluent limitations consistent with the application of
the best practicable control technology (BPT) and best available technology
economically achievable (BATEA). In addition, the Act directs the EPA to prom-
ulgate and enforce national standards of performance for all new sources and
pretreatment standards for industrial discharges into publicly owned treatment
plants and to control discharges of toxic substances. Section 402 of the FWPCA,
National Pollutant Discharge Elimination System (NPDES), authorizes an EPA- or
state-administered permit system for discharges to navigable waters. The permit
for a point sources discharge will specify the materials, quantities to be dis-
charged, discharge conditions and the monitoring and reporting systems to be
used.
The scope of the FWPCA has been expanded by the passage of the 1977 Clean
Water Act Amendments which places a greater emphasis on the control of toxic
pollutants and establishes new deadlines for promulgation of and compliance
with effluent regulations. Under the provisions of the 1977 amendments, the
pollutants in industrial water discharges are divided into three categories,
each with a specific level of control to be imposed by a specific date. First,
there are "conventional" pollutants which include suspended solids, BOD, pH and
fecal coliform.* The conventional pollutants are subject to "best conventional
*EPA is considering the inclusion of oil and grease, COD and phosphorus in the
list of "conventional" pollutants.
258
-------
pollutant control technology" (BCT) with a deadline for achievement of July 1,
1984. Second are the "toxic" pollutants which include, at a minimum, the list
of 65 substances/classes of substances* (referred to as the "priority" or the
"consent decree" pollutants). These require best available technology eco-
nomically available (BATEA) guidelines to be promulgated by EPA and applied no
later than July 1, 1984. All other pollutants not identified as conventional
or toxic are designated "non-conventional." They require BATEA with a dealline
of three years after an effluent limitation is established or by July 1, 1984,
whichever is later. The 1977 amendments also require that NPDES permits include
limitations on the discharge of the priority pollutants.
Constituents in Lurgi SNG plant wastewaters are expected to contain sub-
stances in all three pollutant categories. Most of the priority pollutants
identified by EPA are organic compounds not generally expected to be present in
effluents from Lurgi gasification plants. However, certain aromatic hydrocarbons
(e.g., benzene, naphthalene, acenaphthylene) as well as phenols and trace ele-
ments which are included among the priority pollutants, are known or are likely
to be present in aqueous wastes from Lurgi plants.
As noted above, at present no new source performance standards have been
developed by EPA for the proposed Lurgi SNG plants. Also, since none of the
proposed commercial Lurgi plants is to discharge wastewaters to publicly-owned
treatment plants or to navigable waters, no permits have been applied for under
the NPDES or the local regulations for discharges into municipal treatment
plants. (Some effluent standards have been promulgated for a number of indus-
tries whose effluents may have certain similarities to Lurgi SNG plant waste-
water. Examples of these industries are petroleum refining and by-product coke
production. If Lurgi plants were to discharge effluent into navigable waters,
effluent standards for such plants may have some similarities to the standards
for-these similar industries.)
Safe Drinking Water Act (SDHA) and State Deep Well Injection Regulations.
Under Sections 1421 through 1424 of the SDWA, EPA is authorized to regulate
underground injection to protect underground water sources. The regulation is
done through the state programs which must be approved by EPA. The approval
*The 65 substances/classes of substances are now expanded/subdivided into 129
substances/subclasses of substances.
259
-------
also qualifies the states for receiving grant funds to administer the program.
EPA is also authorized to designate those states, U.S. territories and posses-
sions which require underground injection control programs as a first step in
the development of regulations for state underground injection control
programs*^ .
Under EPA-promulgated regulations a waste can be injected underground if
it can be demonstrated that: (a) the injection will not degrade the quality
of any of the existing groundwater, or (b) the aquifer is not a potential
source of drinking water (i.e., having more than 10,000 mg/1 total dissolved
solids). Because of the stringent nature of these restrictions, the practice
of underground injection of industrial wastes has become less frequent in
recent years. Even though one proposed commercial SNG plant (the ANG project)
features underground injection for the disposal of certain small volume saline
wastes, deep well injection is not expected to be used for the disposal of
wastes from Lurgi gasification plants. If underground waste injection is to be
used by Lurgi gasification plants, the state/EPA permit for such disposal would
be issued on a case-by-case basis^ '.
Additional regulations entitled "State Underground Injection Program Con-
trol Regulations," which will control deep well injections of wastes at the
state level, are to be issued by EPA's Groundwater Protection Branch in draft
form in early 1979 ^ '. The thrust of the regulations is to insure that wastes
are injected into strata that will not contaminate drinking water, and that all
deep wells are designed, constructed and operated in an environmentally sound
manner. Not all of the states receiving grants will be required to immediately
implement the new regulations, although all must comply within 2 years from the
date of issuance. EPA has designated 22 priority states, which must immediately
comply with the new regulations, and which were selected based on the following
considerations: (a) deep well injection is performed on a relatively large
scale within the state, and (b) the potential for contamination of drinking
water supplies is higher due to existing hydrological and geological conditions
in the state.
*A number of states, including Texas and Ohio, have had specific regulations
for underground waste disposal even before the passage of the SDWA. These
regulations have placed varying degrees of restriction on the practice of deep
well injection. For example, Idaho and Arizona strictly prohibit waste dis-
posal by deep well injection. In Texas permits for deep well injection are
issued on a case-by-case basis.
260
-------
The 22 priority states include several which are candidate locations for
Lurgi's SNG facilities including Colorado, Illinois, Indiana, Kentucky, New
Mexico, Ohio, Pennsylvania, Texas and Wyoming. Alabama, Montana, North Dakota,
and West Virginia, which are also candidate locations, are not among the 22 EPA-
designated priority states^ ', and would not be required to immediately adopt
the regulations.
5.3.2 Comparisons of Waste Streams with Effluent Standards
As noted in Section 5.3.1, at the present time there are no effluent stan-
dards for discharges from Lurgi SNG facilities. The Effluent Guidelines Division
of EPA is now in the process of evaluating background data on coal gasification
and other new energy technologies to determine the necessity and schedule for
developing guidelines for these industries. If the few proposed commercial
Lurgi SNG plants are representative of the Lurgi facilities which would be
actually built and operated, such facilities would have no direct discharge to
surface waters and any effluent standards for such plants would specify no dis-
charge. At the present time there are insufficient data on both the character-
istics of the wastewaters from Lurgi SNG plants and on the capabilities of the
proposed controls to adequately evaluate the economic and environmental impacts
of regulations requiring zero discharge.
As it has been proposed for at least one of the proposed Lurgi SNG plants,
deep well injection may be used for the disposal of certain wastes. Standards
for such disposal are set on a case-by-case basis and would depend on the char-
acteristics of the receiving formation and the particular waste to be injected.
5.3.3 Impacts on Ambient Water Quality
If Lurgi SNG plants are to have no direct discharges to surface waters,
no direct impacts on the ambient water quality are anticipated. Such plants,
however, may have "indirect" impacts on the quality of the surface waters and
groundwaters due to extensive water withdrawals, possible intermedia transfer
of pollutants or accidents and system failures. The impacts of heavy water with-
drawals on the quality of surface water and groundwater supplies are discussed
in Section 5.8. The intermedia pollution transfer routes may include percola-
tion of wastewaters from impoundments and leachates from landfill/mines, un-
controlled runoff from plant sites and precipitation "washout" and "fallout"
of air pollutants from the facility. The indirect impacts on ambient water
261
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quality can be minimized through proper plant siting and proper design and
operation of landfills, impoundments, air pollution control systems, and run-
off containment measures.
5.3.4 Evaluation of Unregulated Pollutants and Bioassay Results
As noted previously, there are currently no effluent regulations covering
discharges (if any) from Lurgi SNG plants. Further, as currently envisioned,
commercial SNG plants are not expected to have any direct discharges to sur-
face waters. Hence, any hazard associated with "regulated" or "unregulated"
pollutants in Lurgi wastewaters would be in connection with indirect discharges.
Because of the lack of composition and bioassay data on potential indirect dis-
charges (e.g., landfill leachate and pond percolation) and the site-specific/
plant-specific nature of such discharges, the degree of hazard created by any
such discharges cannot be evaluated at this time.
5.4 IMPACTS OF LAND DISPOSAL
5.4.1 Summary of Land Disposal Standards
Although there are currently no specific Federal or state regulations for
the management of solid wastes from Lurgi SNG plants, a number of general Fed-
eral/state solid waste disposal, resource recovery and reclamation acts are in
effect which would impact solid waste generation treatment and disposal at
Lurgi plants. The two most important of these acts are Resource Conservation
and Recovery Act (RCRA) of 1967 (PL 94-580) and the Surface Mining Control and
Reclamation Act (SMCRA) of 1977 (PL 95-87). These acts are briefly described
below.
Resource Conservation and Recovery Act^114'(RCRA). The overall objective
of this act is to provide for "technical and financial assistance for the devel-
opment and management plans and facilities for the recovery of energy and other
resources from discarded materials and for the safe disposal of discarded
materials and to regulate the management of hazardous waste." The hazardous
waste management provisions of this act, which would have greatest bearing on
the management of the waste generated by industry, covers generation, trans-
portation, storage, treatment/disposal and reporting requirements for hazardous
wastes. Section 3001 of the Act directs EPA to identify which wastes are haz-
ardous and in what quantities, qualities, concentrations and forms of disposal
they become a threat to health or the environment. Section 3001 also requires
262
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EPA to promulgate criteria and test procedures to be used in determining
whether or not a waste is hazardous.
Wastes classified as hazardous would be subject to subsequent provisions
of RCRA. Section 3002 requires EPA to issue hazardous waste handling proce-
dures to be implemented by generators of hazardous waste, including record
keeping and labelling practices, and use of a manifest system to assure that
the waste is designated for proper treatment, storage and disposal. Section
3003 governs the establishment of standards which are applicable to hazardous
waste transporters. Section 3004 establishes standards which are applicable
to owners and operators of hazardous waste treatment, storage and disposal
facilities; and Section 3005 establishes permits for the treatment, storage and
disposal of hazardous wastes. The implementation of the regulations promulgated
under RCRA is the responsibility of the individual states. Section 3006 directs
EPA to provide guidelines to assist states in the development of state hazard-
ous waste programs.
EPA has published proposed criteria for defining hazardous wastes^ .
Under the proposed criteria waste would be considered hazardous if (a) it meets
criteria for ignitability, corrosivity, reactivity or toxicity, or (b) it is
one of the specific wastes in the EPA list of hazardous wastes and waste sources.
Procedures have been proposed for the determination of ignitability, corrosi-
vity, reactivity and toxicity of a waste. The test for toxicity consists of a
"toxic extraction procedure." A waste would be considered toxic under the EPA
proposal if an extract, as obtained through a defined extraction procedure,
contains one of 14 contaminants above a specific level. These contaminants
are arsenic, barium, cadmium, chromium, lead, mercury, selenium, silver and
specific pesticides. The specified concentration levels for this substance in
the extracts are ten times the National Interim Primary Drinking Water Stan-
dards. EPA intends to revise and expand the list and is considering use of
the water quality criteria under the Clean Water Act as the basis for setting
standards in addition to the drinking water standards.
The EPA list of specific wastes and waste sources (the second criteria for
defining whether or not a waste is hazardous) cover 18 specific types of wastes
(e.g., waste non-halogenated solvents, leachate from hazardous waste landfills,
etc.) plus wastes from 130 categories of processes (e.g., distillation residues
263
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from the fractionation of benzene or chlorobenzene, petroleum refining, API
separator and dissolved air flotation sludge, etc.).
None of the major solid wastes generated at a Lurgi SNG facility (e.g.,
gasifier and boiler ash, FGD sludges, spent catalyst) are on the EPA list of
hazardous waste and waste sources. However, based on the toxic extraction
criteria, some of these and other wastes produced at a Lurgi plant may be clas-
sified as hazardous, in which case the production, storage, transportation,
treatment and disposal of such wastes would be subject to the regulations prom-
ulgated under RCRA.* Since (a) the limited information available on coal ash and
FGD sludges indicate that these wastes present a relatively low hazard and (b)
control techniques which might be applicable to other types of hazardous wastes
might not be practical for the management of these wastes (because of the large
volume of the waste generated in the utility industry), EPA has proposed to
classify such wastes as "special wastes" subject to special regulations which will
be promulgated at a later date. The gasification and boiler ashes produced in
a Lurgi SNG plant would most likely be covered by such "special regulations."
Pursuant to the regulations proposed under Sections 3002 and 3004, a Lurgi
SNG plant would be classified as a hazardous waste generator and as an owner/
operator of a hazardous waste treatment, storage and disposal facility and must
comply with applicable regulations. The proposed regulations for the hazardous
waste generators require reporting/record keeping and compliance with DOT ship-
ping, labelling and containerization practices. Regulations proposed under
Section 3004 covers criteria for site selection, contingency/emergency proce-
dures, record keeping/reporting procedures, closure and post closure, and
groundwater and leachate monitoring. Standards are also proposed for storage and
for treatment and disposal utilizing incineration; landfills; basins and sur-
face impoundments; land forming; chemical, physical and biological treatment
facilities; and resource recovery. Under Section 3005, owner/operators of
facilities for the treatment, storage or disposal of hazardous wastes would
*DOE recently launched a major nationwide assessment of the cost impact of RCRA
regulations on conventional and advanced coal use technologies, including gasi-
fication(115). DOE and ASTM have also begun a 3-month effort to analyze the
EPA toxic extraction procedure since it is feared that test results may warrant
the classification of all coal ash and combustion residues as toxic. It is
hoped that test results will be available by March 15, 1979, in time to provide
comments on EPA's proposals under RCRAU16).
264
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require a permit (to be issued by state/EPA) which defines conditions for
acceptable operation.
Section 8002 of RCRA requires EPA to conduct a detailed study of solid
wastes from surface and underground mines and sludges/solid wastes from the
gasification of coal and prepare recommendations for Federal and non-Federal
actions regarding their environmental impacts. This study is currently under
way.
Surface Mining Control and Reclamation Act(SMCRA). As was discussed in
Section 4.4,,disposal of solid wastes from Lurgi SNG plants in surface mines is
an attractive solid waste management option and has been featured in the designs
for the proposed commercial Lurgi SNG facilities. Since such disposal will be
integrated with the mining and mine reclamation activities, it will be affected
by certain provisions of SMCRA.
The overall objective of SMCRA is to protect the environment from the ad-
verse effects of surface coal mining operations while assuring an adequate coal
supply for the nation's energy needs and protecting the landowners near the
operation. The act also provides for reclamation of the mined areas to a condi-
tion capable of supporting the uses which were capable of supporting prior to
mining or to higher or better uses. Section 508 of the act requires submission
for Federal/state approval of a reclamation plan as part of a request for the
mining permit. Section 515 of the Act requires that the reclamation effort in-
sure that all debris, acid forming materials, toxic materials or materials con-
stituting a free hazard are treated or buried and compacted or otherwise disposed
of in a manner designed to prevent contamination of ground and surface waters.
As with other Federal environmental laws, implementation of SMCRA is the
responsibility of the states, with assistance from the Federal government.
Under SMCRA authorization, an Office of Surface Mining and Enforcement (OSME)
has been created in the Department of the Interior to review and approve the
state programs and to provide guidelines to states in developing and enforcing
regulations. OSME is also currently in the process of writing final regula-
tions pertraining to strip mines and air quality. Interim regulations, which
were issued in September 1973 would require mine operators to closely monitor
their operations for both dust and coal particles^ .
265
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5.4.2 Comparisons of Haste Streams with Disposal Standards
Based on the criteria proposed under RCRA for the definition of hazardous
wastes, some of the solid waste streams generated at a Lurgi SNG plant would
be classified as hazardous wastes. These waste streams, which are primarily
the spent catalyst and oily and biological sludges, would be subject to the
storage, transportation and treatment/disposal regulations which have been pro-
posed by EPA and which are expected to be promulgated (perhaps with some changes)
in the near future. It should be noted that these hazardous wastes account for
a very small fraction of the solid wastes generated at a Lurgi SNG plant. The
bulk of the solid wastes generated in a Lurgi SNG plant are the gasifier and
boiler ash ands depending on the air pollution control processes employed,
FGD sludges. Assuming that the gasifier ash would be considered similar to the
boiler ash, these wastes would be subject to "special standards" which EPA pro-
poses to promulgate for utility and other relatively high-volume and low-hazard
industrial wastes.
5.4.3 Evaluation of Unregulated Pollutants and Bioassay Results
The solid wastes generated in a Lurgi SNG plant would be subject to the
hazardous waste "special waste" regulations to be promulgated under RCRA. Even
though the Lurgi gasifier ash may fall into the "special waste" category, there
are some chemical composition and bioassay data (see Section 3.7.2) for the ash
leachate which indicate that the Lurgi ash may be hazardous. This information
and the results of other related on-going and planned studies (see Sections 3.1
and 6.2) would impact the promulgation of standards for the disposal of this
particular waste.
5.5 PRODUCT IMPACTS
5.5.1 Summary of Toxic Substances Standards
Since the product SNG and some of the by-products produced in a commercial
Lurgi SNG plant contain potentially toxic substances, the presence of such
material in a work environment and their distribution in commerce would be sub-
ject to the provisions of the Occupational Safety and Health Act (OSHA; PL 91-
506) and the Toxic Substances Control Act (TSCA; PL 94-469). A brief descrip-
tion of the pertinent sections of these acts follows.
266
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Occupational Safety and Health Act (OSHA). This act authorizes the U.S.
Department of Labor (DOL) to set mandatory standards to safeguard the occupa-
tional safety and health of all employers and employees of businesses engaged
in interstate commerce. The act specifically authorizes the regulation of
toxic materials, and requires the DOL secretary to "set the standard which most
adequately assures ... that no employee will suffer material impairment of
health or financial capacity" due to regular exposure to toxic substances and
other occupational hazards.
Among the standards which have been promulgated to date under OSHA are
those pertaining to worker exposure to toxic and hazardous air contaminants.
These standards consist of ceiling and peak concentration, time-weighted average
limits and/or threshold limit values for over 500 toxic organic and inorganic
compounds which include many of those identified in Section 3.4 as potential .
constituents of Lurgi SN6 and by-products. Table 5-14 lists OSHA standards for
some of the materials which are known or expected to be present in a Lurgi coal
gasification plant.
Under the authority of OSHA, regulations have been promulgated relating to
exposures to some 17 occupational carcinogens. The regulated carcinogens
are^ ': asbestos, 4-nitrobiphenyl5 alpha-naphthylamine, 4,4'-methylenebis-(2-
chloroaniline), methyl chloromethyl ether, 3,3'-dichlorobenzidine (and its
salts), bis-chloromethyl ether, beta-naphthylamine,, benzidine, 4-aminodiphenyl,
ethyleneimine, beta-propiolactone, 2-acetylaminofluorene, 4-dimethylamino
azobenzene, N-nitrosodimethylamine, vinyl chloride, coke oven emissions, 1,2-
dibromo-3-chloropropane and acrylonitrile. Except for asbestos, vinyl chloride
and coke oven emissions for which the standards are based on concentrations in
3 3
ambient air (2 fibers longer than 5 y/cm , 1 ppm and 150 Ng/m , respectively),
the standards for the regulated carcinogens are for products containing 0.1% or
1% or more by weight or volume of the regulated substance. When these concen-
trations are exceeded, the OSHA regulations prohibit the use/storage of such
products in open vessels and require strict adherence to appropriate industrial
hygiene practices.
The National Institute of Occupational Safety and Health (NIOSH) has pub-
lished a list of suspected carcinogens covering some 1500 chemical substances.
267
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TABLE 5-14.
OSHA STANDARDS FOR MATERIALS KNOWN OR SUSPECTED TO BE PRESENT IN
LURGI SNG PLANTS(121)
Compound
Acetic acid
Ammonia
Aniline (skin)
Antimony
Arsenic
Benzene
Beryllium
Butyl mercaptan
Cadmium (dust)
Carbon dioxide
Carbon disulfide
Carbon monoxide
Carbon tetrachloride
Chromium, soluble salts
Chromium, insoluble salts
Coal dust (<5% Si02)
(>j% Si02)
Coal tar pitch volatiles +
Cresol (skin)
Ethyl benzene
Ethyl mercaptan
Hydrogen chloride
Hydrogen sulfide
Hydrogen cyanide
Lead and inorganic lead
compounds
Manganese
Mercury
Methanol
Methyl mercaptan
Naphtha (coal tar)
Naphthalene
Nickel carbonyl
Nickel metal and soluble
compounds (as Ni )
Nitrogen dioxide
Phenol (skin)
Propane
Pyri di ne
Selenium compounds
Silica (respirable)
(total dust)
Styrene
Sulfur dioxide
Toluene
Vanadium
Xylene
TWA,* ppm
10
50
5
--
--
10(1)
--
10
—
5000 (10,000)
20(1)
50(35)
10
--
-
--
--
--
5
100
--
--
--
10
—
--
--
200 (200)
--
100
10
0.001
--
5(1)
5
1000
5
--
--
--
100
5(2)
200 (100)
--
100 (100)
TWA* mg/m3
25
35
19
0.5
0.5
--
0.002 (0.002)
35
0.2 (.04)
9000 (18,000)
--
55
1
0.5 (0.025)
1
2.4
0.10
0.2
22
35
435
--
--
--
0.2 (0.10)
--
0.1 (0.05)
260
--
400
50
0.07
1
9
19 (20)
1800
15
0.2
0.10 (0.05)
0.30
—
13
--
(1)
435
Concentration
--
50
--
--
(.002 mg/m3)
25 ppm
005 mg/m3
—
0.6 mg/m3. (0.2 mg/m3)
(30,000 ppm)
30 ppm (10 ppm)
(200 ppm)
25 ppm
(0.05 mg/m3)
--
--
—
—
--
--
10 ppm
5 ppm
20 ppm (10 ppm)
25 ppm
—
5 mg/m3
--
--
10 ppm
—
-
--
__
--
(60 mg/m3)
—
--
--
—
--
--
--
--
(0.05 mg/m3)
--
Where Found
Gas stream, gas liquor
Gas stream, gas liquor
Trace element in coal
Trace element in coal
Gas stream, naphtha
Trace element in coal
Gas stream, naphtha
Trace element in coal
Gas stream
Gas stream
Gas stream, product SNG
Laboratory
Trace element in coal
Coal preparation areas
Gas stream, tars, oils
Gas stream, naphtha
Gas stream, naptha
Gas stream, naphtha
Stream
Gas stream
Gas stream
Trace element in coal
Trace element in coal
Trace element in coal
Rectisol solvent
Gas stream
Gas stream, tars, oils
Gas stream, tars, oils
Methanation areas, product SNG
Trace element in coal
Incinerated wastes, boiler flue gases
Gas and gas liquor
Gas stream
Gas stream, tars, oils
Trace element in coal
Incinerated wastes, boiler flue gases
Gas stream tars, oils
Trace element in coal
Gas stream, tars, oils
"Time-weighted average. Numbers in parentheses indicate NIOSH recommended standards
Coal tar pitch volatiles, as measured by the benzene-soluble fraction of particulate matter, includes such polycyclic
aromatic hydrocarbons as anthracene, benzo(a)pyrene, phenanthrene, acridine, chrysene, and pyrene.
268
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Some of the substances on the NIOSH suspected carcinogens list would be present
in Lurgi SNG product/by-products and are subject to future regulations by OSHA.
Toxic Substances Control Act (TSCA). This act authorizes EPA to promulgate
regulations for the control of substances or mixtures of substances which, in
the judgment of EPA, present an unreasonable risk to health and to the environ-
ment through their manufacture, processing, distribution in commerce, use or
disposal. Such regulations may prohibit the manufacture, processing, etc. of
certain substances and impose restrictions on manufacture, processing, etc. of
other substances. The act also directs EPA to issue regulations on testing,
premarket notification, and for reporting and retention of information. Under
Section 4 of TSCA, the EPA is empowered to conduct testing on suspected toxic
substances to develop data with respect to the health and environmental effects
for which there is an insufficiency of data and which are relevant to the
determination of whether the manufacture, distribution, processing, use and/or
disposal of the substances present a risk of injury to health or the environ-
ment.
To achieve the TSCA goals, EPA has identified and has begun actions toward
achieving the following objectives: (1) definition of methods for assigning
priorities to chemicals for investigation and regulation; (2) establishment
of procedures for testing and evaluating hazardous chemicals; (3) establish-
ment of mechanisms for premanufacture notification of new chemical substances;
and (4) development of international approaches to toxic substances control^ '.
To date, EPA has developed a "chemical use list" for the purpose of industry
reporting and EPA-decisionmaking regarding chemical manufacture, importing
and/or processing^ . On October 26, 1978, the Interagency Testing Committee
authorized under TSCA for chemical testing prepared for EPA a priority listing
of chemicals to be considered for testing; TSCA requires EPA to respond to
these recommendations within one year. The substances recommended for testing
include: alky! epoxides, alkyl phthalates, chlorinated benzenes, chlorinated
paraffins, chloromethane, cresols, nitrobenzene, toluene and xylenes.
5.5.2 Comparisons of Product Characterization Data with Toxic Substances
Standards
The implementation of TSCA is in initial stages and no substance-specific
regulations have as yet been issued by EPA. However, since the product and
269
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by-products produced in SNG plants would contain certain toxic substances, it is
very likely that Lurgi product and by-products be subject to future TSCA regula-
tions. Such product and by-products, however, may subject the Lurgi SNG plants
to USHA regulations for the workplace ambient exposure. As noted in the previous
section, OSHA regulations currently cover seventeen substances which have been
labeled as occupational carcinogens. Although some of the regulated carcinogens
(e.g., benzidine and naphthylamines) are expected to be present in Lurgi tars
and oils, it is not envisioned that their concentrations would exceed those
which would make the by-products subject to OSHA regulations.
Table 5-14 presents the OSHA ambient standards for workplace exposure to
some of the substances which are expected to be found in Lurgi SNG plants. The
presence of these substances in the ambient environment in a Lurgi plant may
result from fugitive or evaporative emissions from various production, trans-
portation and storage units and from accidental spills and equipment/system
failure. For many of the substances listed in Table 5-14, OSHA standards are
not expected to be exceeded under normal operating conditions primarily due to
the closed nature of the Lurgi SNG systems. For some highly volatile substances
such as benzene, evaporative emissions must be controlled in order to comply
with the ambient standards.
5.5.3 Evaluation of Unregulated Toxic Substances and Bioassay Results
As noted above, no regulations have yet been promulgated under TSCA which
is to control toxic substances in commercial products. In this regard, all
toxic substances in Lurgi SNG product and by-products would be considered un-
regulated. The existing OSHA ambient regulations cover the majority of sub-
stances which are known to be present in Lurgi product and by-products. Since
composition data are not available for such materials, it is possible that addi-
tional OSHA regulations may be developed in the future covering toxic substances
not yet identified in Lurgi product and by-products.
No bioassay data are yet available to indicate toxicity of Lurgi product
and by-products. Bioassay tests and epidemic!ogical studies, however, have
been conducted on coal-derived oils and tars produced by other coal conversion
processes and in the by-product coke industry. Since these coal-derived products
contain some of the substances which would be present in Lurgi tars and oils,
the results of these bioassay and epidemiological studies may give some indications
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of the toxicity expected from Lurgi tars and oils. Several fractions of coal
oils produced by the Bergius and Fischer-Tropsch processes have been tested for
carcinogenicity, and the results have indicated that hydrogenated coal oils
are carcinogenic and that carcinogenic potency resides in the heavy ends and
higher boiling fractions. Tars produced in the coking of coals are established
as chemical carcinogens; exposure to air-borne tar particulates are regulated
under OSHA standards for occupational carcinogens.
In the 1950's Union Carbide Corporation conducted bioassay and industrial
hygiene studies in connection with a coal hydrogenation plant at Institute,
(1 22)
West Virginia . The work consisted of chemical analyses of a number of pro-
ducts and intermediate streams, bioassay experiments on mice, and epidemiolo-
gical studies of plant workers and laboratory personnel exposed to coal hydro-
genation products. Over 200 chemicals were identified in the coal hydrogena-
tion process, some belonging to classes of compounds known to include carcino-
gens. Tests indicated that light oil stream (boiling below 260°C) and its deri-
vatives were without tumorigenie action. The streams boiling at higher tempera-
tures - middle oil, light oil stream residue, pasting oil, and pitch product -
were all carcinogenic. For these streams, carcinogenic potency increased, and
the length of the median latent period decreased, with the rise in boiling point.
Protective clothing and personal hygiene procedures did not totally prevent
skin cancer.
5.6 RADIATION AND NOISE IMPACTS
Radiation and noise are two additional potential categories of environ-
mental problems associated with the operation of a Lurgi SNG plant. The radia-
tion problem stems from the presence of radioactive substances in the coal; the
noise problem is primarily due to the operation of process -and mining equipment.
5.6.1 Radiation Impacts
Coals contain varying amounts of the naturally occuring radioactive iso-
topes of uranium, thorium, and their daughter products. The limited data avail-
able on the composition of the coals which are to be gasified in the proposed U.S
commercial Lurgi SNG plants were presented in Table 3-1. The data in this table
indicated a U concentration of about 1 ppm for these coals. Table 5-15 presents
data on the ranges of U and Th which may be found in other selected U.S. coals.
As indicated by the data, the mean concentrations of U and Th in these coals
271
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TABLE 5-15. URANIUM AND THORIUM CONTENTS
STATES023)
OF COAL SAMPLES TAKEN FROM VARIOUS REGIONS OF THE UNITED
Region
Pennsylvania
Appalachia
Interior
Northern Great
Plains
Gulf
Rocky Mountain
Coal Rank
Anthracite
Bituminous
Bituminous
Subbituminous ,
1 ignite
Lignite
Bituminous,
subbituminous
Number
of
Samples
33
331
143
93
34
134
Uranium Concentration (ppm)
Range
0.3-25.2
<0.2-10.5
0.2-54
<0.2-2.9
0.5-16.7
<0.2-23.8
Geometri c
mean
1.2
1.0
1.4
0.7
2.4
0.8
Thorium Concentration (ppm)
Range
2.8-14.4
2.2-47.8
<3-79
<2. 0-8.0
<3.0-28.4
<3.0-34.8
Geometric
mean
4.7
2.8
1.6
2.4
3.0
2.0
no
*-j
ro
Note: The arithmetic average concentrations of thorium and uranium in ppm for all coal samples and
various ranks of coal for the whole United States are as follows:
Coal Rank
All coal
Anthracite
Bituminous
Subbituminous
Lignite
Samples
799
53
509
183
54
Thorium
(ppm)
4.7
5.4
5.0
3.3
6.3
Uranium
(ppm)
1.8
1.5
1.9
1.3
2.5
-------
are in the 0.7 to 2.4 ppm and 1.6 to 4.7 ppm ranges, respectively. A few North-
ern Great Plains lignites have been reported to contain up to 200 ppm U, a con-
centration much higher than those reported in Table 5-15^^'. It should be noted
that the amounts of U and Th found in most coals are not greatly different than
those found in many other types of common rocks (e.g., limestone, shale,
granite)(125)
Based on the limited data available on the fate of U and Th in Lurgi gasi-
fication systems, it appears that these elements will largely be retained by the
gasification ash. Small amounts of U and Th will be emitted to the atmosphere
in particulate form from direct combustion of coal for onsite steam and power
generation. Studies of coal-fired power plants, however, suggest that such emis-
sions would not ordinarily represent a significant public health or ecological
/TOO "1 O f 1 O "7 ^
probem ' ' . U and Th contained in gasification and boiler ash from SNG
plants may be mobilized via leaching from waste deposits in landfills/reclaimed
surface mines or in settling/evaporation ponds. Studies of settling basins and
landfills handling ash from coal-fired power plants suggest that U in ash can
be mobilized at a rate larger than 10% of the natural weathering rate of rocks.
Thus, unless the landfills and ponds which handle coal ash from Lurgi SNG plants
are designed and operated to minimize leachate formation and/or contain leach-
ate, a potential exists for intrusion of this element into ground and surface
waters in amounts which may prompt concern.
5.6.2 Noise Impacts
Like most large industrial facilities, Lurgi SNG plants may be expected to
have a number of sources of noise which would require control. Major noise
sources would include crushers, screens and coal conveying systems; blowers and
compressors; and cooling towers. Depending on the plant location in relation to
the coal mine, mining operations (e.g., blasting, hauling, use of draglines) may
also be major contributors to the noise problem from the mining/gasification
complex. During the construction phase of an SNG plant noise associated with
vehicles, jack hammers, pneumatic tools, scrapers, etc. would also be expected.
Although no actual data are available on noise levels which would be encountered
in an SNG facility, mitigating measures for noise control are available and are
considered established practice in a number of other industries. Compressors
and coal handling equipment would be located inside structures designed to
273
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minimize noise. Other equipment such as fans, blowers and burners can be de-
signed to minimize noise by reducing turbulence and streamlining flow. The very
"noisy portion" of the plant can be located in isolated areas or housed in
acoustically insulated structures. Use of hearing protection devices would also
be required for employees working in such areas.
It should be noted that noise associated with an SN6 plant would not be
unique to that type of operation but may be similar to noise from -cement plants,
coal mines, petroleum refineries, etc. Further, the proposed locations of Lurgi
SNG facilities to date are in relatively unpopulated sites which would diminish
exposure of large numbers of persons to plant noise, thus largely reducing the
problem to one of industrial hygiene nature requiring in-plant control.
5.7 SUMMARY OF MAJOR ENVIRONMENTAL IMPACTS
5.7.1 Air Impacts
Lurai SNG plants would be major point sources of emissions of sulfur com-
pounds (primarily SO,,) and hydrocarbons and, to a lesser extent, of CO, NO and
L- A
particulates. Most of the impacts on ambient air quality from an integrated
Lurgi SNG facility are due to emissions associated with the use of coal for on-
site steam and power generation rather than from gasification. Lurgi SNG plants
which would utilize the control technologies consistent with those proposed by
developers for commercial SNG plants or by EPA in its guidelines for Lurgi SNG
facilities should meet the NAAQS for all criteria pollutants.* The PSD S0?
increment for Class II region, however, may be exceeded if high sulfur coals are
to be gasified. Although very limited information is available on non-criteria
pollutant emissions from gasification plants, the proposed technologies appear
adequate for the control of such pollutants. The results of one modeling effort
has indicated the hydrocarbon and NO emissions from Lurgi SNG plants may lead
/\
to oxidant levels in excess of NAAQS.
5.7.2 Water Impacts
As was discussed in Section 5.3.3, the water impacts associated with at
least the first generation Lurgi SNG plants would be primarily of an indirect
nature since such facilities would most likely be operated with zero effluent
*This does not take into account any additive particulate emissions from mining
and coal preparation operations which may be conducted in the general vicinity
of the gasification plant.
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discharge to surface waters. Any impacts on water quality would be of an in-
direct nature resulting from heavy water withdrawal (consumptive use), possible
intermedia transfer of pollutants (e.g., contamination of surface and ground-
water by leachates and seepage from landfills and evaporation ponds), or acci-
dental spills and systems failure. The impact on water quality due to water
withdrawal, which is an important consideration in the selection of plant site,
is discussed in Section 5.8. Other indirect impacts are plant-and site-specific
and can be minimized through proper design and operation of production and pollu-
tion control systems.
5.7.3 Impacts of Solid Wastes
The large volume solid wastes in a Lurgi SNG plant are the gasifier and
boiler ash and FGD sludges (if throw-away FGD systems are used). In terms of
quantity and characteristics, these wastes would be similar to those from an
electric utility plant using the same amount of feed coal. The management of
these wastes management practices would be essentially the same for Lurgi SNG
and electric utility plants. The environmental impacts associated with the dis-
posal of these high volume wastes are generally of an indirect nature and stem
from potential mobilization of soluble components via leachate formation and
seepage from containment sites. Such impact can generally be minimized by
proper selection, design and operation of the disposal sites.
Smaller volume solid wastes at Lurgi SNG plants are spent catalyst, tarry/
oily sludges and biosludges. Because of their more hazardous characteristics
these wastes can have a greater potential environmental impact, unless properly
handled and disposed of. The practice of hazardous waste management used in
similar industries (e.g., petroleum refining and petrochemical production)
would be applicable to the management of these wastes to reduce their impacts.
5.7.4 Impacts of Toxic Substances
The product SNG and by-products from Lurgi plants would contain potentially
toxic substances. These toxic materials can have adverse impacts on plant
workers and the general public. The adverse impacts are primarily due to fugi-
tive emissions (leaks, evaporative emissions, etc. at plant site, during trans-
port and at end-use facilities) and accidental spills and system/equipment
failure. These impacts can range from acute toxic effects (e.g., inhalation of
ammonia near the spill site) to chronic effects (e.g., potential for skin cancer
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due to long-range exposure of plant workers to Lurgi tars). Although some of
the substances in Lurgi produce, by-product and waste streams are known to be
toxic, detailed quantitative characterization data and bioassay results are not
available for these materials to assess the degree of toxicity and safe exposure
levels. Moreover, because of lack of plant operating experience, the extent of
exposure that Lurgi plant workers would ordinarily experience cannot be estimated
at this time. Any epidemiological data which may exist on foreign Lurgi faci-
lities are not available to assist in the definition of health hazards in a
Lurgi plant.
5.7.5 Other Impacts (Noise, Radiation, Land Use)
Even though the radioactive elements originally present in coals concen-
trate in the gasifier and boiler ash, the radioactive content of the ash from
the majority of U.S. coals is not generally much higher than that for such common
industrial materials as limestone, gravel, etc. The large-scale use of coal in
Lurgi SNG plants thus is not expected to result in any signficiant increase in
background radiation at the plant or waste disposal site or in radiation ex-
posure levels for the general public.
As with most large-scale industrial facilities, some noise is expected from
the operation of various equipment at a Lurgi SNG plant. The noise control
practices used in other industries should be adaptable to Lurgi plants. The
reduced off-site noise levels expected from the application of such controls
cannot be quantified at this time.
The impact of land use associated with Lurgi plants is an element of the
broader siting consideration which is discussed below.
5.8 SITING CONSIDERATIONS FOR GASIFICATION PLANTS
Major factors which should be considered in the comparative evaluation of
alternative sites for a Lurgi SNG plant include: air quality considerations,
hydrogeological factors, land use considerations and secondary impacts associated
with population influx.
The air quality considerations primarily relate to the EPA air quality area
designations and the local meteorological conditions. A Lurgi SNG plant cannot
be located in a "nonattainment" area unless the emissions from such a plant can
be offset through reductions in the emissions from other sources in the area.
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Lurgi plants using high sulfur coals may not be located in "Class II" areas if
the allowable "PSD" increment for Class II areas are likely to be exceeded due
to the specific local meteorological conditions. Because of the very small PSD
increment allowed for "Class I" areas, Lurgi plants cannot be located in these
areas (without use of extensive additional pollution control). In addition to
influencing whether a Lurgi SNG plant can meet PSD increment requirement for
an air quality class, local meteorological conditions effect "visibility" which
is an important aesthetic consideration for plant siting in scenic areas.
Hydrogeological conditions (specifically the distance to and the fluctua-
tions in the groundwater table, the type and permeability of geological strata
and soils, surface topography and precipitation pattern) are important siting
considerations as they impact design, operation and cost of waste treatment and
disposal systems (landfills, storage/evaporation ponds). When hydrogeological
conditions are unfavorable, landfills and evaporation ponds must be lined and
provisions must be made for collection and treatment of landfill leachate and
pond leakage to reduce potential for the contamination of surface waters and
groundwaters. When the cost for the protection of groundwater or surface waters
at a site becomes economically unjustifiable, alternate plant or waste disposal
sites should be investigated.
Even with the most effective water reuse and conservation measures, SNG
facilities will be very large consumers of water. Such large volume consumption
uses of water, especially when several plants are to be constructed in a given
watershed, will reduce the availability of the groundwaters and surface waters
for other uses and adversely affect the quality of such waters. This would be
particularly true in the relatively arid west where water supplies are less
abundant and there are existing water quality/quantity commitments (e.g., in
the case of Colorado River water) to users in both the U.S. and Mexico.
Exclusive of the land which may be used at certain sites for evaporation
ponds, Lurgi SNG plants by themselves would occupy only a very small land area
(less than 40 hectares or 100 acres). Evaporation ponds can occupy several
hundred hectares of land; however, such ponds would generally be used in plants
in arid regions where large amounts of land having no competing land use values
are available. In selecting a site for Lurgi SNG plants, the major land use
issue pertains to the possible removal of land from other productive uses (e.g.,
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agricultural production) for mining of coal to supply the SNG plants and for
disposal of wastes. It should be noted that such land use impact is not unique
to SNG plants and that which would be encountered in connection with large-scale
mining of coal for other uses such as electric power generation and coke pro-
duction.
As indirect land use impact associated with a Lurgi SNG facility is due to
the influx of population created by the construction and operation of a Lurgi
plant. Such population influx can create a host of indirect environmental pro-
blems which should be addressed in plant siting. Such environmental problems
stem from increases in traffic and construction activities, and in demands for
public utilities (water, electricity and sewage treatment) and services (schools,
roads, housing, etc.).
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6.0 SUMMARY OF NEEDS FOR ADDITIONAL DATA
At the present time there are no specific Federal standards for Lurgi SNG
plants. In connection with (a) the development of EPA guidelines for the con-
trol of atmospheric emissions from Lurgi SNG plants and (b) various studies
sponsored by EPA, DOE and process developers, a considerable amount of data
have been generated pertaining to the environmental aspects of the Lurgi tech-
nology.
Despite their considerable volume, there are a large number of gaps in these
data which would have to be filled in order to establish the data base needed
for the development and enforcement of standards for Lurgi SNG plants and for
defining health effects and control technology R&D needs. Some of the more
important gaps in and the limitations of the existing data base have been
pointed out in the preceding chapters of this report. This chapter presents
a summary of the data needs and a brief review of the on-going environmental
assessment programs which may provide some of the needed data.
6.1 DATA NEEDS
6.1.1 Data Needed to Support Standards Development and Enforcement
The data needed for setting and enforcing standards for Lurgi SNG plants
relate primarily to (a) the characteristics (including health and ecological
effects properties) of individual and combined waste streams, key process
streams and product/by-products, (b) capabilities and costs of the available
control technologies for SNG service and of alternative control options for
pollution control at integrated facilities, and (c) instrumentation, sampling
and analytical protocols and record keeping and reporting procedures. The
waste/process stream and product/by-products characterization data are needed
to establish the presence and levels of criteria/priority pollutants and other
substances in the waste streams requiring regulations. The data on the capa-
bilities of control technologies are needed for setting standards consistent
with the application of the best control technologies economically achievable.
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venturi scrubbing for particulate removal, Phenosolvan for recovery of phenols
from wastewaters, sour water stripping for NH3/H2$ removal and trickling filters
for biological treatment), the various air, water and solid waste control pro-
cesses which would be potentially employed at commercial facilities have not
been used in Lurgi coal gasification applications. Even for the few processes
which have been used for coal gasification, very little data are available on
the characteristics of the treated streams and on the performance and costs of
these applications.
In addition to the data needs pertaining to waste stream/control technology
characterization (Tables 6-1 through 6-3), data are also needed on the composi-
tion of certain key process and product/by-product streams and on the fate of
certain environmentally important constituents of the process streams in vari-
ous Lurgi process/pollution control units. Key process streams which require
more detailed characterization are "cooled" and shifted product gas. Although
some data are available on the major constituents of these streams, the data on
environmentally significant constituents such as carbonyl sulfide, mercaptans,
hydrogen cyanide, volatile trace elements, and organometallics are insuffi-
cient to determine the fate of these constituents in the downstream processing
units and hence, the pollution control needs. Based on the limited tests at
the Westfield, Scotland plant, the Lurgi SNG product gas may contain Ni(CO).
(and possibly other trace toxic organometallic substances). If such substances
are found in the product gas from commercial plants in significant concentra-
tion, the production, transportation and commercial uses of Lurgi product SNG
would be subject to possible regulations under the Toxic Substances Control
Act (TSCA). Based on the data from Westfield plant and from other gasification
processes, Lurgi by-products (specifically tars, oils, naphtha and phenols) may
contain traces or significant quantities of a host of toxic substances includ-
ing benzene, aromatic amines and polynuclear aromatic hydrocarbons and hetero-
cyclics, which may make them subject to TSCA regulations. Better characteriza-
tion data including bioassay information are needed on the Lurgi product SNG
and by-products to determine the necessity and type of regulations required.
Determining compliance with any standards which would be promulgated for
Lurgi SNG plants would require the availability of suitable methods for measure-
ment of pollutants in waste streams and product/by-products and of operating
parameters. Based on the experience in standards setting for other industries,
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TABLE 6-1. DATA NEEDS RELATING TO GASEOUS WASTE STREAM CHARACTERISTICS AND
CONTROL TECHNOLOGY CAPABILITIES
Waste Stream
Waste Characteristics
Control Technology Capabilities
Coal crushing and
screening off-gas
Feed lockhopper vent gas
Ash lockhopper vent gas
and ash quench off-gas
Concentrated acid gases
Catalyst decommissioning/
regeneration off-gases
Depressurization and
stripping gases
By-product storage vent
gases
Oxygen plant vent gases
Transient waste gases
Fugitive emissions
Sulfur recovery tai 1
gas
Flue gas from onsi te
steam power generation
No data available on the quantity and
characteristics (e.g., Level 1 analytical
data) of dust from coal preparation for
use in Lurgi plants.
The quantity and characteristics (e.g.,
Level 1) are not available for these gases.
Same as for feed lockhopper vent gas.
Limited composition data available for
off-gas from certain Rectisol designs.
These data do not cover all constituents
of interest (e.g., HCN, COS, mercaptans)
and are not reflective of Rectisol designs
which will be employed in SNG service. This
stream is expected to be the major gaseous
waste stream in a Lurgi plant.
Same as for feed lockhopper vent gas.
Limited data on major constituents based
on the operation of foreign Lurgi plantsf
More detailed characterization (e.g.,
Level 1} data necessary.
Same as for feed lockhopper vent gas.
Waste streams not expected to contain
substances requiring regulations.
Same as for feed lockhopper vent gas.
Specific sources and emission characteris-
tics in an actual plant not known.
No data available on waste characteristics
from a Lurgi SNG plant application.
Combustion flue gases are generally well
characterized; EPA and other agencies have
a number of on-going flue gas characteriza-
tion programs.
The control technologies used in coal
preparation plants should be applicable
to Lurgi plants; emission standards exist
for this source category.
The need for and the effectiveness of
incineration/particulate control not
defined.
The particulate control requirement (if
any) not defined.
The cost and effectiveness of Claus and
Stretford processes for the control of
Rectisol off-gases containing high CCL
levels and minor constituents such as HCN
and COS.
Control technology requirements not
established.
The cost-effectiveness of control options
(incineration vs. combining with the Rectisol
gases for treatment) not evaluated.
Control technologies used in petroleum refin-
ery and other industries should be applicable
to Lurgi plants; standards promulgated for the
petroleum refining industry would probably be
extended to cover the synthetic fuel industry.
Mo controls likely to be necessary.
The effectiveness of incineration (alone or in
conjunction with fuel combustion) and the
possible need for sulfur and hydrocarbon re-
moval not known.
Same as for by-product storage vent gases.
The effectiveness and costs of control options
(incineration, incineration in combination with
fuel gas combustion/FGD systems, and use of
catalytic reduction processes such as Beavon)
not established.
Controls applicable to utility and industrial
boilers would generally be applicable. Estab-
lished emissions regulations would cover boilers
at Lurgi plants.
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TABLE 6-2. DATA NEEDS RELATING TO AQUEOUS WASTE STREAM
CAPABILITIES
CHARACTERISTICS AND CONTROL TECHNOLOGY
Waste Stream
Waste Characteristics
Control Technology Capabilities
Coal oile runoff
Ash quench slurry
ro
CO
ro
Raw gas liquor
Clean gas liquor
Rectisol methanol/
water still
bottoms
No data on characteristics and quantities
for a Lurgi SNG plant(this stream would
be coal- and site-specific). Limited
data available for waste stream at
electric utility plants.
Limited data available on elemental com-
position and leaching potential of un-
quenched ash from the gasification of a
few American coals. No data available
on coals proposed for actual use in U.S.
plants and for conditions when process
waters (e.g., clean gas liquor) are used
for ash quenching.
Limited data available on major consti-
tuents and gross parameters, trace ele-
ments and a few specific organic compounds
for certain feed coals. No comprehensive
characterization data (Level 1 testing) on
the organics. No data available reflec-
tive of coals proposed for actual use in
U.S. plants.
Same as for raw gas liquor; limited data
available on constituents biodegrad-
ability.
Data available on major constituents and
parameters from a foreign facility; com-
prehensive data (Level 1 results) not
available. No data available for Ameri-
can coals or for Rectisol designs envi-
sioned for use in U.S. SNG plants.
Runoff diversion and containment tech-
niques are well established from other
industries and should be applicable to
Lurgi plants.
Slurry transport, solids sett!ing/dewater-
ing technology from utility industry
should be directly applicable. Capabi-
lities of technology in terms of charac-
teristics of clarified ash slurry water
not known.
Capabilities of tar/oil separation,
Phenosolvan, and ammonia recovery well
established in terms of removal of major
constituents. Capabilities for removal
of minor constituents not established.
Limited cost data available on processes.
No data available on performance or cost
of biological treatment or on problems
associated with use as cooling tower or
ash quench water makeup.
This small-volume stream would likely be
treated in conjunction with clean gas
liquor (see above).
(continued)
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TABLE 6-2. CONTINUED
Waste Stream
Waste Characteristics
Control Technology Capabilities
rsj
CO
oo
Phenosolvan filter
backwash
Boiler blowdown
Cooling tower
blowdown
Waste sorbents
and reagents
Miscellaneous plant
wastewaters (run-
off, sanitary
wastes, etc.)
Combined
effluent
plant
No data available on quantities, char-
acteristics or generation frequency.
Characteristics well known and not unique
to Lurgi.
Effect of using various process waste
streams (e.g., clean gas liquor or
Rectisol methanol/water still bottoms)
as cooling tower makeup on the composi-
tion of the blowdown not established.
No data available for composition and
quantities from applications in a Lurgi
plant. Limited characterization data
available on major constituents of
certain wastes (e.g., Stretford and
Well man-Lord solution purges) from
applications in other industries.
Same as for Phenosolvan filter backwash,
No data available,
This small-volume stream would likely be
treated with other plant wastewaters
(e.g., plant runoff or ash quench slurry),
This relatively "clean" stream would like
likely be used as process water; no speci-
fic control technology data needs can be
identified.
A likely treatment method would involve
use as ash quench slurry water; impacts
on the quench system and subsequent treat-
ment of clarified water not established.
Applicable controls (e.g., resource recov-
ery, disposal in lined pond, dissolved
solids removal, deep well disposal, etc.)
are waste-and site-specific; cost and
performance data should be developed on
a case-by-case basis.
The option control method (e.g., treatment
and use as process water vs. treatment
and discharge) not evaluated.
The effectiveness and costs of various
applicable controls (e.g., solar or forced
evaporation, physical-chemical treatment
for water reuse, etc.) not determined.
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TABLE 6-3. DATA NEEDS RELATING TO SOLID WASTE STREAM CHARACTERISTICS AND CONTROL TECHNOLOGY CAPABILITIES
Waste Stream
Waste Characteristics
Control Technology Capabilities
Coal fines, dust
and refuse
Gasifier and boiler
ash
IX)
co
Spent catalysts and
methanation guards
Tarry/oily sludges
Biosludges
Inorganic solids and
sludges (FGD wastes)
No data available on characteristics and
quantities for a Lurgi SNG plant (these
wastes would be coal- and site-specific).
Some data available from other industries
(e.g., electrical utility and coking).
No data available on quenched gasifier ash
(including its hazardous characteristics).
Limited data available on elemental composi-
tion and leaching potential of the unquenched
gasifier ash for certain coals (not including
those proposed for use in U.S. Lurgi plants)
Boiler ash characteristics would not be
unique to Lurgi, except when Lurgi process
water is used for ash quenching.
No characterization data (including hazardous
characteristics) available on spent shift and
methanation catalysts and methanation guards
for Lurgi plants; very limited gross character-
ization available on spent methanation
catalyst from pilot scale tests in connection
with other gasification processes.
No data available on quantities and charac-
teristics (including hazardous properties).
No data available on quantities and charac-
teristics (including hazardous properties).
Data available on composition and handling/
disposal characteristics (compactability,
permeability, Teachability) for FGD sludges
from utility industry. Characteristics of
FGD wastes are coal- and process-specific.
Control technologies (e.g., disposal in ponds/
landfills) should be applicable. Effectiveness
for containment and costs not evaluated.
Control technologies requirements dependent on
forthcoming RCRA regulations; if these wastes are
classified as "hazardous," existing controls used
in utility industry may not be adequate and more
effective controls (e.g., containment in secure
landfills, lined ponds, fixation, etc.) may be
required. Design criteria would have to be devel-
oped for these more stringent controls.
Control technologies used or proposed under RCRA
for use in other industries (resource recovery,
encapsulation and/or disposal in secured landfills)
should be applicable. Although catalyst manufac-
turers/reclaimers may have costs and effectiveness
data on these controls, such data are not publicly
available.
Control technologies used or proposed under RCRA
for use in other industries (e.g., energy recovery,
disposal in secure landfills) should be applicable;
cost and effectiveness of these controls not defined.
Same as for tarry/oily sludges.
Same as for gasifier and boiler ash.
-------
As with the standards for other industrial source categories, standards for
Lurgi SNG plants should be in a format and contain numerical limits which are
consistent with the available field data monitoring/analytical capabilities
and do not place undue burdens on the industry for collection/submission of
data.
Tables 6-1 through 6-3 summarize the specific data gaps and needs per-
taining to the characterization of waste streams and definition/evaluation of
applicable control technologies in Lurgi SNG plants. In general, the identified
data gaps fall into two categories: (1) total non-existence or unavailability
of the data, and (2) data which are available lack comprehensiveness or have
been obtained under conditions significantly different than those anticipated
in an integrated commercial Lurgi SNG plant in the U.S. Examples of data gaps
in the first category are the lack of detailed characteristics data on emis-
sions associated with decommissioning of spent methanation catalyst, on com-
bined plant effluent and on sludges resulting from the treatment of such efflu-
ent or from the treatment of tarry/oily wastewaters. Since no integrated Lurgi
SNG facility currently exists, this type of data is not available from actual
operations to check the reasonableness of the estimates which are the basis for
the proposed designs for commercial Lurgi SNG plants. In the case of emissions
from catalyst decommissioning, even though some data might exist, such data
are not publicly available due to proprietary considerations.
Examples of the second category of data gaps and limitations are the lack
of trace element and organics data and toxicological and ecological character-
istics data for various waste streams in a Lurgi SNG plant and data on the
performance of various control systems in Lurgi SNG service. In general, the
limited available waste characterization data do not cover organic and trace
element constituents, bioassay information, waste treatability and charac-
teristics such as non-biodegradability, health effects and potential for bio-
accumulation and environmental persistence. For the Stretford and Beavon pro-
cesses, which have been used in refinery and/or by-product coke applications
for H?S removal from acid gases containing relatively low levels of CC^,
limited commercial experience exists with acid gases containing high levels of
C0? which would be encountered in a Lurgi SNG plant. With the exception of a
few pollution control processes (e.g., flaring for hydrocarbon and h^S control,
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some standards call for the use of specific equipment (e.g., flares and vapor
recovery systems) rather than pollutant emission limits due to unavailability
of suitable measurement methods. In recent years considerable work has been
funded by EPA and other agencies to develop sampling and analytical protocols
for the determination of criteria and priority pollutants in industrial process/
waste streams. These protocols cover many but not all of the substances which
are expected to be present in Lurgi SNG plant process/waste streams. In addi-
tion, some modifications to certain of these protocols may be required for
application to specific conditions encountered in Lurgi SNG plants (e.g., high
temperature/pressure gases, gases containing condensable organics or effluents
containing substances which may interfere with the analytical determinations).
Although efforts to define sampling and analytical support requirements for
enforcement of standards generally go hand in hand with those for standard set-
ting, the more exact definition of such support requirements should follow a
clearer definition of the waste characteristics and of substances to be
regulated.
6.1.2 Data Needed to Support Effects and Control Technology R&D
Some of the data identified above as being needed to support standards
development and enforcement activities would have to be generated through R&D
programs in the areas of health and ecological effects and evaluation and con-
trol technology development. Through such R&D programs,reliable data must be
generated on performance and cost of control technologies and on health and
ecological effects of wastes and products/by-products to uphold environmental
standards and regulations as they are critiqued through the legal system. In
addition to supporting the standards development and enforcement mandates of
EPA, R&D programs in the subject areas are needed in connection with the EPA
responsibility for assessing, developing and verifying methods for control of
pollution from energy-related (and industrial) sources. The control technology
and health and ecological R&D needs which are specifically related to or have
some bearing upon the Lurgi SNG systems are briefly reviewed below.
s Gathering and analyzing existing process and environmental data on
Lurgi SNG systems. This document represents the most updated com-
pilation and analysis of the existing information on Lurgi SNG
systems. Considerable additional data are expected to become avail-
able as a result of on-going or planned programs. This document
must be updated periodically to incorporate additional data as they
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become available and to provide a basis for reexamination of problems
and R&D needs.
t Multimedia environmental sampling and analysis. As was discussed in
Section 6.1.1, although some characterization data are available on
certain Lurgi process/waste streams, such data are not comprehensive
in that not all streams or process conditions are addressed and not
all potential pollutants and toxicological/ecological properties are
defined. Some of these data gaps can be filled through chemical/
biological testing of process effluents at existing facilities.
Although no Lurgi SNG facilities currently exist and foreign Lurgi
facilities do not incorporate all units and design features of a
commercial Lurgi SNG plant, sampling and analysis at foreign Lurgi
sites provide the best and only currently available means of acquiring
certain process and environmental data for Lurgi systems. Additional
data can be collected through sampling and analysis of Lurgi system
components used in other coal conversion and industrial applications
(e.g., the Rectisol, Stretford and methanation processes).
• Health and ecological effect support studies. The comprehensive
environmental assessment of Lurgi SNG systems require information
on health and ecological properties of product/by-products and
waste streams from such systems. Some of this information (e.g.,
presence and levels of specific toxic substances in various streams,
and bioassay data) would be generated as part of environmental samp-
ling and analysis. Other information relating to parameters such as
bioaccumulability, environmental transport and fate and synergistic
ef/ects would have to be obtained through separate studies. The
health and ecological support studies and the data from sampling and
analysis effort provide the necessary input for the definition of
multimedia environmental goals (MEG) for substances/parameters of
interest associated with Lurgi systems and for assessing health
hazard and ambient environmental impacts using source analysis models
(SAM).
• Assessment of the cost and effectiveness of various candidate control
processes, treatment schemes and waste management options for appli-
cation to Lurgi SNG systems. As discussed in Section 6.1.1, many of
the controls which would be potentially applicable to the management
of Lurgi waste streams have not been tested in Lurgi service or in
similar industrial applications. R&D programs should include the
pilot or bench-scale testing of control processes/treatment schemes
on Lurgi streams. Such studies may be conducted onsite (e.g., at
foreign Lurgi facilities and at plants in similar industries) or
offsite using samples from such plants or from pilot/bench-scale
units simulating conditions in Lurgi systems. The pilot- and bench-
scale testing should be supplemented by engineering analysis to esti-
mate the costs and evaluate applicability of controls for use in
integrated SNG plants
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• Miscellaneous support activities. These activities, which would be
primarily in support of the above areas of environmental assessment
and control technology R&D, may include development of sampling and
analytical methodology, techniques for defining when and which more
costly detailed analysis is needed, improvement to existing SAM's
and development of more comprehensive models for source assessment,
coordination of related R&D activities sponsored by various govern-
mental agencies and the private sector and dissemination and exchange
of information through the holding of symposia, conferences, etc.
6.2 DATA ACQUISITION BY ON-GOING ENVIRONMENTAL ASSESSMENT ACTIVITIES
The on-going programs, which are expected to provide some of the needed
data identified in Section 6.1, fall into three categories: EPA-sponsored
programs, DOE-sponsored programs and miscellaneous programs. The most perti-
nent of the EPA- and DOE-sponsored programs are listed in Tables 6-4 and 6-5,
respecitvely. Mostly due to proprietary considerations, very limited data
are available on the programs in the miscellaneous category which are primarily
carried out by or under funding from the Lurgi corporation, sponsors of pro-
posed commercial Lurgi SNG projects and other private firms/organizations.
The most pertinent data-acquisition program in the EPA-sponsored category
is the multimedia sampling and analysis effort currently under way at the
Kosovo Kombinant plant in Yugoslavia. This program is the most comprehensive
environmental data acquisition effort ever undertaken at a Lurgi facility.
Although not an SNG plant, the Kosovo Lurgi facility, which produces medium
Btu gas and hydrogen for ammonia production, features many of the key unit
operations in an integrated Lurgi SNG plant, including Lurgi gasification, tar
and oil separation, Rectisol acid gas treatment and Phenosolvan process for
phenol recovery. The sampling and analysis program, which addresses all major
feed to and process streams from these and other units, consists of two phases:
a "screening phase" (Phase I) and an "in-depth" effort (Phase II). Phase I,
which is now being completed, involves analysis for selected constituents/
parameters (e.g., H2S, total hydrocarbons, C-j-Cg organics, flow rates, etc.).
Phase II involves a more comprehensive analysis for a range of constituents
including identification/quantification of heavier organics using gas chroma-
tograph/mass spectrometry (GC/MS) techniques and trace element analysis using
spark source mass spectrometry (SSMS) and atmoic absorption (AA).
288
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TABLE 6-4. SUMMARY OF THE MOST PERTINENT ERA-SPONSORED ON-GOING ENVIRONMENTAL ASSESSMENT PROGRAMS
Project Ti tie
ro
CO
Environmental Assessment
of High Btu Gasification
Environmental Assessment
of Low/Medium Btu
Gasification
Pollutants Identification
from a Bench-Scale Unit
Characterization of Coal
and Coal Residues
Water Treating Bench-
Scale Unit
Gasification/Acid Gas
Cleaning Bench-Scale
Unit
Contractor
TRW, Inc.
Redondo Beach, Ca.
Radian Corporation
Austin, Texas
Research Triangle Institute
Research Triangle Park
North Carolina
Illinois State Geological
Survey
Urbana, Illinois
University of No. Carolina
Chapel Hill, No. Carolina
No. Carolina State Univ.
Raleigh, No. Carolina
Objecti ve
Environmental assessment of high Btu
gasification, including identification
of control technology needs.
Environmental assessment of low/medium
Btu gasification, its utilization and
definition of control technology needs.
Semi-quantitative determination of
chemical species in gasification efflu-
ents as a function of gasification con-
ditions and kinetic data on rates of
species formation.
Characterization of the chemical,
physical and mineral properties of coals,
coal by-products and wastes; investiga-
tion of the effects of pyrolysis on
trace element distribution and providing
data on solubilities and toxicities of
species in coal wastes.
Assessment of the effectiveness of vari-
ous biological/chemical processes for the
treatment of synthetic fuel effluents,
and determination of the environmental
impacts and health effects of treated
effluents.
Program is in initial stages. Evalua-
tion of absorption solvents used in four
acid gas removal processes (i.e.,
Rectisol, Benfield, HEA and Selexol) to
be conducted.
Data Acquisition Activities
As part of this program, it is
planned to conduct multimedia S/A
at a foreign Lurgi plant.
Multimedia S/A under way at the
Kosovo Kombiant plant in Pristina,
Yugoslavia; Phase I, "screening,"
has been completed; Phase II, in-depth
evaluation which would involve analysis
for trace elements and heavy organics,
is to be initiated in mid-1979.
Lab-scale gasification reactor designed
and operated with coke and Illinois #6
coal. It is planned to simulate condi-
tions of a number of gasification sys-
tems, including Lurgi. S/A of gasifier
feed and effluents are to be conducted.
Final report being prepared on studies
of chemical form of trace elements in
coal. Trace element studies conducted
on ash from gasification of American
coals at Uestfield Lurgi facility.
Toxicity and bioassay studies of coal
and solid wastes recently completed.
Bench-scale studies being conducted in
order to establish criteria for design
of large-scale biological/chemical
treatment units. Activated sludge, coag-
ulation, and carbon adsorption processes
have been tested on simulated gasifica-
tion wastewaters. Bioassay testing of
simulated wastewaters currently under-
way.
Gasifier operation has been initiated
with chemical grade coke. Rectisol
solvent (i.e., methanol) tested with
synthetic feed mixture and equilibrium
solubilities of acid gases in MeOH
determined. Future tests with lignite
and subbiluminous coal scheduled for
May 1979.
-------
TABLE 6-5. SUMMARY OF THE MOST PERTINENT DOE-SPONSORED ON-GOING ENVIRONMENTAL ASSESSMENT PROGRAMS
Contractor
Objective
Data Acquisition Activities
ro
kO
CD
Carnegie-Mellon University
Pittsburgh, Pa.
Oak Ridge National Laboratory
Oak Ridge, Tennessee
DOE-Environmental Division
and American Society for
Testing Materials
Philadelphia, Pa.
To provide overall coordination
and evaluation for DOE pilot
plant environmental assessment
program; to develop sampling
and analysis protocols.
To determine and assess potential
environmental/health problems
associated with coal conversion;
to evaluate existing and develop-
ing environmental control pro-
cesses applicable to coal conver-
sion.
To evaluate the validity of EPA's
acid extraction test procedure
proposed under RCRA as a method
to classify wastes as hazardous
or non-hazardous.
Ten specific program tasks,
including development/valida-
tion of sampling and analytical
procedures, and studies on treat-
ability of process effluents, are
under way.
Program to characterize ash from
gasification of Montana Rosebud
and Illinois #5 and #6 coal from
Westfield facility nearly com-
pleted. "Ecological bioassay"
tests on Lurgi ash also being
completed.
The 3-month study (January -
March 1979) was recently
initiated; up to 18 different
samples of fly ash, scrubber
sludge, gasification wastes and
other residues are to be used in
the assessment.
-------
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Choice, The Oil and Gas Journal, August 18, 1975, pp. 109-112.
130. Federal Register, Vol. 39, No. 207, Part II, October 24, 1974.
131. Federal Register, Vol. 38, No. Ill, June 11, 1973.
132. Federal Register, Vol. 39, No. 116, June 14, 1974.
300
-------
APPENDICES
APPENDIX A. GLOSSARY OF ENVIRONMENTAL ASSESSMENT TERMS
Auxiliary Process. Process, associated with a technology, used for a pur-
pose(s) that is in some way incidental to the main function involved in trans-
formation of raw materials into end products. Auxiliary processes are used for
recovery of by-products from waste streams (e.g., Phenosolvan process for phenol
recovery), to furnish necessary utilities, and to furnish feed materials such
as oxygen.
Commercial-scale SNG Facility. A facility having a capacity to produce
7 x 106 Nm3/d (250 x 106 scf/d) of substitute natural gas.
Effluent Stream. A confined aqueous process waste stream, discharged from
a source, which is potentially polluting.
Emissions Stream. A confined gaseous process waste stream, discharged
from a source, which is potentially polluting.
Energy Technology. Consists of systems which are applicable to the produc-
tion or processing of fuel (e.g., high Btu gasification), electricity, or chemi-
cal feedstocks from fossil fuels, radioactive materials, or natural energy
sources (geothermal or solar).
Environmental Assessment. As defined for IERL/RTP studies of fossil energy
processes, an environmental assessment is a continuing iterative study aimed at:
(a) determining comprehensive multimedia environmental loadings and environ-
mental control costs, from the application of existing and best future definable
sets of control/disposal options, to a particular set of sources, processes,
or industries; and (b) comparing the nature of these loadings with existing
standards, estimated multimedia environmental goals, and bioassay specifications
as a basis for prioritization of problems/control needs and for judgment of
environmental effectiveness.
301
-------
Environmental Assessment Report. A report prepared for a specific tech-
nology, covering in depth all environmental assessment information relevant to
existing or needed standards development plus a description of systems which
can make up the technology, the present and proposed environmental requirements,
and the best control disposal alternatives for all media.
Fugitive Emissions. Unconfined process-associated discharges, including
accidental discharges, of potential air pollutants, which may escape from
pump seals, vents, 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.
Hazard Indicators. An EPA-developed ranking system which assigns one
of four indicators to substances: N = non-hazardous, x = hazardous, xx =
very hazardous, xxx = most hazardous. The indicators have been derived
from numerical ratings of substances which are based on human health effects
and include weightings for substances indicated to be cumulative or to be
hazardous at low concentrations.
High Btu Gas. Gas having a higher heating value of over 8000 Kcal/Nm3
(900 Btu/scf).
LD5Q. Lethal dose fifty, i.e., the dose which when administered to a
group of animals is lethal to one-half of the population. The mode of
administering the dose and the test animal must be specified.
LD|_0. Lethal does low, i.e., the lowest dose of a substance
introduced in one or more portions by any route other than inhalation over
any period of time and reported to have caused death in a particular animal
species.
Low/Medium-Btu Gas. Gas having a higher heating value of 800-3600 Kcal/
Mm3 (90-400 Btu/scf).
Lurgi SNG Systems. Systems which incorporate specific Lurgi-licensed proc-
esses and various other processes which would be used in an integrated SNG
facility.
302
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Minimum Acute Toxicity Effluent (MATE). The approximate concentration for
contaminants in source emissions which will 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).
Multimedia. Pertaining to air, water and/or land as recipients of environ-
mental pollutants; or gaseous, liquid or solid waste pollutants when used in
relation to pollution control levels.
Multimedia Environmental Goals (MEG's). Levels of significant contami-
nants or degradents (in ambient air, water, or land or in emissions or efflu-
ents conveyed to the ambient media) that are judged to be (a) appropriate for
preventing certain negative effects in the surrounding populations or ecosystems
or (b) representative of the control limits achievable through technology.
Operation. A specific function associated with a technology consisting
of a set of processes used to produce specific products from certain raw
materials. For example, the operations for high-Btu gasification technology
are coal pretreatment, coal gasification, gas purification and gas upgrading.
Phased Approach for Sampling/Analysis. A strategy for environmental
assessment in which all streams to be sampled at a source are first surveyed
using simplified, generalized S/A methods so they can be ranked on a priority
basis (e.g., very hazardous versus less hazardous), followed by detailed
sampling/analysis in order of descending priority. Requires three levels of
S/A effort. Level 1 entails comprehensive screening for pollutants, including
criteria pollutants; Level 2, directed analysis, based on Level 1; and Level 3,
process monitoring of selected pollutants, based on Levels 1 and 2.
Process. A basic unit that comprises a technology, used to produce chemi-
cal or physical transformations of input materials into specific output streams,
and having a unique definable set of waste streams (e.g., Lurgi gasification).
Process Module. A representation of a process which is used to display
process input and output stream characteristics, and which, when used with other
necessary process modules, can be used to describe a technology, a system or a
plant. A module is comprised of a number of nearly interchangeable processes
or processes applicable to different operating conditions and input
requirements.
303
-------
Process Stream. An output stream from a process that is an input stream
to another process in the technology. For example, the raw gas liquor from
the Lurgi gasification process is the feed (input) stream to the tar and
oil separation process.
Source Assessment Models (SAM's). Models for systematic assessment of
the environmental effectiveness of pollution control options. Four models
are under development: SAM/IA for rapid screening, SAM/IB for biological
screening, SAM/1 for screening, and SAM/11 for providing the general approach
to evaluation of U.S. regional site alternatives.
Substitute Natural Gas (SNG). A manufactured gas containing about 97%
methane, with a higher heating value of over 8000 Kcal/Nm3 (900 Btu/scf),
and meeting the same end-use specifications as pipeline natural gas.
System. A specified set of processes that can be used to produce a
specific end-product of the technology, e.g., high-Btu gasification. The
technology is comprised of several systems.
TLm. Median tolerance limit value, i.e., the concentration in water of
a pollutant required to kill 50 percent of a particular aquatic species during
a specified period of exposure (usually 24, 48 or 96 hours).
TLV. Threshold limit value, i.e., levels of contaminants considered
safe for workroom atmosphere, as established by the American Conference of
Governmental Industrial Hygienists.
Potential Toxic Unit Discharge Rate (PTUDR). Number which expresses
the effectiveness of pollution control options, equal to the ratio of the
pollutant concentration to the MATE value (called the "potential degree of
hazard," H) times the stream flow rate.
Haste Stream. Confined gaseous, liquid, and solid process output streams
that are sent to auxiliary processes for recovering by-products, pollution con-
trol or final disposal; also, unconfined "fugitive" discharges of gaseous of
aqueous waste and accidental process discharges.
304
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APPENDIX B. SUPPORT DATA FOR ESTIMATION OF EMISSIONS, COSTS AND ENERGY
REQUIREMENTS FOR AIR POLLUTION CONTROL OPTIONS FOR INTEGRATED
SNG PLANTS
BASIS FOR ESTIMATING STREAM FLOWS AND EMISSIONS FOR VARIOUS OPTIONS
(See Figures B-l through B-5 for flow diagrams and stream flows)
• A 7.7 x 106 Nm3/d (288 x 106 scf/d) Lurgi SNG plant using 0.7% sulfur sub-
bituminous coal.
• All plant energy requirements are met by use of coal, fuel gas, or gasifi-
cation by-products onsite. Total plant energy requirements are the same
for all options.
« In Options 1 and 5, incineration of Stretford off-gases using supplemental
fuel will oxidize all sulfur compounds to SOp and will reduce CO and HC
levels to 200 ppmv and 100 ppmv, respectively.
• Incineration of Stretford off-gases in turbines (Option 2) or in fossil
fuel-fired boilers (all options) oxidizes all sulfur compounds to S02. The
amounts of CO, HC and NO in turbine or boiler flue gases are estimated
X
from emission factors in Reference 109, using combined heating values of
fuels and Stretford off-gases.
• Flue gas desulfurization processes are capable of 90% SOp removal with the
percent removal independent of feed S0? concentration. The Wellman-Lord
process is assumed to be used for FGD in Options 1, 3, 4 and 5.
• Electrostatic precipitators are used for particulate control and remove
99% of flue gas particulates, with an additional 80% removal occuring in
FGD units. (An overall 99.8% particulate control is realized.)
• NO emissions from boilers, turbines and superheaters are estimated using
the data in Reference 109 and are assumed to be unaffected by dilution of
fuel/flue gases with waste gases to be incinerated. (Such dilution might
be expected to reduce NO emissions somewhat.)
A
• Boilers are fired with 20% excess air. Gas turbines are generally operated
at about 400% excess air. Stretford off-gases displace about 30% of this
excess turbine air in Option 2.
• Although the Rectisol process generates at least two acid gas streams
(commonly referred to as lean H2S and rich H2S streams), acid gases are
305
-------
combined into one stream in Options 1, 2, 3 and 4. In Option 5 the Rectisol
design generates a rich HpS stream containing about a third of the total
sulfur and a lean FLS stream containing the other two thirds. The com-
position and flow rate for the Rectisol acid gases are those used in the
proposed design for the El Paso facility (as described in References 12
and 31).
COS and CS2 in raw product gas feed to Rectisol unit constitute 2% of the
total gaseous sulfur and are entirely removed by the Rectisol process. In
Option 5, COS and CSp are in the lean and rich H2$ streams in equal amounts.
Mercaptans and thiophenes which may amount to another 2% of the total gas-
eous sulfur are removed with the naphtha fraction in the Rectisol process
and thus are accounted for in the naphtha sulfur content.
The Stretford process reduces the H^S in Rectisol off-gases to less than
10 ppmv. The Stretford unit which treats the fuel gas in Option 2 achieves an
HpS level of 100 ppmv. COS and organic compounds are not removed by the
Stretford process.
The ADIP process in Option 3 is capable of producing a Claus plant feed
containing a minimum of 15% H^S and an off-gas containing 250 ppmv HLS when
handling Rectisol off-gases. Hydrocarbons and COS contained in Rectisol
acid gases will be in the dilute t-LS stream.
When operated in the split-flow mode and treating a 15% hLS feed, the Claus
process can remove 94% of the total sulfur. A tail gas containing about
12,000 ppmv total sulfur is generated with the following approximate com-
position (based on the data in Reference 129):
S02 = 3500 ppmv
H2S = 7000 ppmv
COS + CS2 = 1400 ppmv
S = 100 ppmv
/\
The Beavon/Stretford process for Claus tail gas treatment is capable of
producing a tail gas containing 250 ppmv total sulfur. The predominant
sulfur species is COS. Beavon tail gas contains about 1000 ppmv HC and
2000 ppmv CO.
306
-------
BASIS FOR ESTIMATING ENERGY REQUIREMENTS FOR VARIOUS OPTIONS
• Direct steam, electricity, and fuel requirements for air pollution control
processes are as listed in Table B-l. These utility estimates are for units
of a size similar to that which would be encountered in a Lurgi SNG faci-
lity and assume input stream compositions representative of those in Lurgi
plants.
• Electricity is generated at 34% efficiency, steam at 80% efficiency.
• Fuel for Beavon process and for reductive incineration of Stretford purge
is SNG made from coal at 65% thermal efficiency.
• The amount of energy which can be recovered in incineration of waste gases
using supplemental fuel is directly proportional to the combustion (flame)
temperature.
• No heat is recovered from waste gases having temperatures less than 420°K
(300°F).
• An incineration temperature of 1140°K (1600°F) is required for destruction
of HC and CO.* The incineration energy penalties for each option are calcu-
lated in Table B-2.
t The use of gas turbines in Option 2 for incineration does not involve a
thermal penalty since the gas to be incinerated is displacing excess air
and should not affect turbine combustion temperatures. The heating value
of Stretford off-gas is not recovered in the turbines. The overall thermal
efficiency of gas turbine/steam turbine systems is the same as for steam
turbines alone so that no energy penalty is associated with combustion of
the waste gases.
^Certain incinerator designs can achieve effective destruction of certain simple
gaseous wastes at temperatures below 1090°K (1500°F). In a pilot plant study _
of incineration of a butane-pentane mixture in air using a low-NO>< burner, resi-
dual CO, HC and NOX levels of less than 35, 45 and 10 ppm respectively, were
obtained at temperatures below 1090°K (1500°F) - see EPA 650/2-75-042. To
assure complete combustion in the incineration of complex wastes, temperatures
of 1150°K (1600°F) or more are commonly specified.
307
-------
TABLE B-l. SUMMARY OF ENERGY REQUIREMENTS FOR AIR POLLUTION CONTROL PROCESSES
Process
Reference
Steam
Electricity
Fuel
o
co
Stretford
Claus
ADIP
Beavon
Wellman-Lord
Electrostatic
Preci pita tor
1,22
22
22
129
22
59
830 kg/tonne S
@0.4 MPa (50 psig)
437 kg/tonne S
@ 4 MPa (600 psig) consumed
4910 kg/tonne S
@0.4 MPa (60 psig) produced
4600 kg/tonne S
00.4 MPa (30 psig)
705 kg/tonne S
@0.4 MPa (50 psig)
18,700 kg/tonne S
@0.1 MPa (15 psig)
1353 kwh/tonne S
36 kwh/tonne S
13 kwh/tonne S
312 kwh/tonne S
1120 kwh/tonne S
70-123 kw/actual
cubic meter per
minute
2.5 x 10 kcal /tonne* S
1.2 x 10 kcal/tonne S
*Reductive incineration of Stretford purge solution for vanadium/sodium recovery.
-------
TABLE B-2. ESTIMATED ENERGY PENALTY ASSOCIATED WITH INCINERATION IN AIR POLLUTION CONTROL OPTIONS
Option
1
2
3
4
5
Quantity of Gas to be
Incinerated
106 Nm3/hr (106 scf/hr)
0.36 (13.3)
0.36 (13.3)
0.34 (12.66)
0.34 (13.4)
0.34 (12.7)
Quantity of
Fuel Used
for Incineration
3.37 x 103 kg/hr
(74.2 x 103 Ib/hr)
0.235 x 106 Nm3/hr
(8.76 x 106 scf/hr)
1.27 x 106 kg/hr
(280 x 103 Ib/hr)
1.27 x 106 kg/hr
(280 x 103 Ib/hr)
33,000 kg/hr
(72,700 ib/hr)
Theoretical
Adiabatic
Flame Temperature*
(°K)
1600
--
2040
2022
1600
Theoretical
Efficiency
of Heat
Recovery
(X)
73.8
--
79.4
79.2
73.8
Energy Penalty"1"
109 cal/hr (% of theoretical)
28.00 (8.8)
0 (0)
22.37 (1.9)
25.19 (2.1)
27.39 (8.8)
CO
o
*See calculations which follow this table.
t
Energy penalty is the difference between theoretical efficiencies associated with combustion of fuel alone
(82.5%) and combustion of fuel diluted with Stretford or ADIP off-gases.
-------
• The basic energy efficiency for the production of the fuel gas from coal
is 80%. Since in Option 2 the fuel gas is not treated in an FGD or parti-
culate removal system, an energy credit is taken for such a system which
is not utilized. This credit is estimated from that in Option 5.
310
-------
CALCULATION OF FLAME TEMPERATURES ASSOCIATED WITH INCINERATION OF WASTE GASES
Methane or Fuel Gas as Fuel
Combustion of methane in air can be represented as follows:
CH4 + 202 + 3N2 - C02 + 2H20 + 8N2 AH = 192 kcal/gram mole (LHV) (1)
Adiabatic combustion results in the absorption of all the reaction heat by
the combustion products; the final temperature, TC, is the flame temperature:
- AH = nCp (Tc - TQ)
where n is the number of moles of combustion products, Cp is the average heat
capacity of the products, and T is the initial temperature (assumed to be
298°K). It is helpful to express Cp as a multiple of the gas constant R and AH
as a multiple of the thermal energy unit RT :
Cp = aR (2)
- AH = hRTQ (3)
The dimensionless specific heat, "a" is estimated at about 4.5, RT° = 0.592
kcal/mole. Solving for flame temperature:
Tc = TQ (1 + h/na) (4)
where h = 324, n = 11, and a = 4.5
T = 298 (7.55) = 2250°K (for pure methane)
\*
To calculate the flame temperature of fuel gas it is assumed that the com-
bustible components can be represented by methane and that heating value of the
gas is directly proportional to methane content. Thus, a fuel gas with one
half the heating value of methane would have a flame temperature calculable
from equation (4) using n = 12 rather than n = 11 (i.e., CH4 in equation (1)
would be diluted by one mole of inert gas, say N2). Thus, for a gas with one
311
-------
half the heating value of methane:
TC •298 1 + r * 2086°K
If a diluent gas (D) is added to the methane and the diluent also contains
heating value, the following is used to estimate the flame temperature:
AHD
, v
CH4 VD
_
= AH of gas (5)
A methane gas equivalent in heating value to the diluted gas having a heating
value equal to AH" would have a total number of moles of combustion products
defined by:
AHru - AH"
LHA
- ^ - + 11 = n (6)
AH
Thus, a fuel gas with one-tenth the heating value of methane would have an
n = 20, or:
+ 11 = 20
0.1
Its flame temperature would be:
T = 2981 1 + /onw? ex 1= 1371°K
(1+l2offw)=
Coal or Tars and Oils as Fuel
Combustion of coal, tars, or oils having a C/H ratio of about 1/1 can be
represented as:
CH + 1.2502 + 5N2 = C02 + 0.5H20 + 5N2
Assuming that such fuels have a net heating value approximated by benzene (Cg
on an MAP basis then AH = 123 kcal/mole CH. As in the case of methane combus
tion above, the adiabatic flame temperature can be calculated according to
equation (4) with h = 207, a = 4.5 and n = 6.5, or:
312
-------
T = 298 1 +
^ya '
,
(6.5)(4.5)
As in the case of methane, adding an inert or waste gas to combustion pro-
ducts results in an increase in the number of moles of products which must be
heated, thus lowering the flame temperature. The flame temperature of a gas
incinerated with fuels represented by CH is calculated as follows. The CH fuel
is assumed to have a molecular weight of 13 and if it were a gas would occupy
22.4 I/mole at STP. The weight of fuel used for incinerating a waste gas is
converted to its equivalent volume of CH gas and its heating value is assumed
to be 123 kcal/gram mole (or 4958 kcal/Nm3). Using the heating value and volume
of the waste gas (W) :
VCH x AHCH * VW x aHW -
and n is then calculated by:
AHri, - AH
tH_ - + 6.5 = n (9)
AH
The flame temperature is calculated according to equations (3) and (4). For
o
example, a waste gas with a heating value of 410 kcal/Nm (50 Btu/scf) is in-
3
cinerated with coal at a ratio of 1.2 kg coal/Mm (1 Ib coal/15 scf) waste gas.
1200 grams coal x 22.4 _ ? nfift N 3 fH
- 2.068 Nm CH
2.068 x 4958 + 1 x 410 = 3477 kcal 86 kcal
3.068 " " 3 or mole
From equation (9)
Then from equation (4)
495V473477 + 6.5 = n = 6.93
] + , ,
c \ ' (6.93)(0.45)
313
-------
LURGI
AC
REMOW
20.71,77
65a _
RECTISOL 21,22,23! STRETFORD 57
\L PROCESS
STEAM • .
iULI-UK jr, -]•, " iUPtHHtMltK
UNIT ' «»
1 C0lj 4sJ
bya ™^
4 64a
64b '
BOILER
1
65c
PDUFR 64c Fl FfTBOSTATIC . '' FLUE GAS 61 S
BOILER 1 PRECIPITATORj ULSLJL^AI1UN j_
\..X\ S\ ./ ' T '
63
|59b
CO
STREAM FIOUS FOR OPTION 1*
Ccnpnnent
c
H
s
0
H
Ash
V
co2
V
COSH::;,
r;Ha
CO
H2
Olj
C2HG
I'DOH
NO
KC
E02
Stream Flo«s In 10^ kg/hr
21.22,23
.CMS
719
6.2
0 22
1 .4
?.?
0.2
a. 6
2.0
1.2
57
.045
719
.01
0.22
1 .a
2.9
0.2
4.6
2.0
1 2
70,71
28
2.6
0.23
2.6
0.23
0.45
65a
154
481
7.4
20,71,77
14.4
1.4
.045
1.9
.045
65b
57
214
2.7
1
31.2
2.3
.45
6.5
i.2
0.7
7.9
65c
114
430
5.4
64i
25
581
.045
5.0
651
.21
0.6
0.06
0.72
64b
9.4
214
15
528
.01
0.27
.005
0.09
64c
19
430
9.7
34
IN
.02
0.36
.005
0.90
f3
9.7
59a
0.77
61
54
1266
0.06
363
1018
0.24
1.2
0.07
0.17
59b
5.8
LEGEND:
21,22,23 COMBINED GASES FROM RECTISOL UNIT
57 OFF-GAS FROM STRETFORD
70,71 TAR AND TAR OIL
65a COMBUSTION AIR
71,20,77 TAR OIL, NAPHTHA AND PHENOLS
65b COMBUSTION AIR
1 COAL
65c COMBUSTION AIR
64a SUPER-HEATING FLUE GAS
64b STEAM BOILER FLUE GAS
64c POWER BOILER FLUE GAS
63 BOILER & FLY ASH
59a SULFUR
61 COMBINED FLUE GAS TO STACK
59b ELEMENTAL SULFUR
*Stream numbers refer to Figures 2-2, 2-3 and 2-4. See Table 2-7 for stream index.
Figure B-l. Air Pollution Control Option 1
-------
LURGI RECTISOL
ACID GAS
REMOVAL PROCESS
MEDIUM-BTU LURGI
GASIFICATION SYSTEM
61
59b
OJ
en
STREAM FLOUS FOR OPTION 2'
Component
C
N
S
0
Ft
Ash
HjO
co2
cos*cs2
C2H4
CO
r<2
CH
C2H6
HeOH
BO
HC
SO,
Stream Flow in ky/hr
21.22,23
.045
719
6.2
0.22
1.4
2.9
0.2
4.6
2.0
1.2
11
182
0.8
110
1.3
.023
1.2
83
7.9
1.1
1.9
57
.045
719
.01
0.22
1.4
2.9
0.2
4.6
2.9
1.2
68a
159
0.7
96
.002
.020
1.0
72
7.9
14
1.9
68b
24
0.1
14
.0003
.003
0.1
10.7
1.0
1.8
0.3
65a
214
805
10.2
65b
28
104
1.3
64a
25
964
123
997
0.1
0.40
.045
0.26
64b
5.0
127
16
37
.005
1.1
.002
.007
61
30
1091
138
1034
.10
1.5
.047
.27
59a
6.0
59b
1.2
LEGEND:
21,22,23 GASES FROM RECTISOL UNIT
11 FUEL GAS FROM LOW-BTU GASIFICATION
57 OFF-GAS FROM STRETFORD
68a FUEL GAS TO GAS TURBINES
68b FUEL GAS TO BOILERS
65a COMBUSTION AIR
65b COMBUSTION AIR
64a FLUE GAS
64b FLUE GAS
61 COMBINED FLUE GAS
59a SULFUR
59b SULFUR
*Stream numbers refer to Figures 2-2, 2-3 and 2-4. See Table 2-7 for stream index.
Figure B-2. Air Pollution Control Option 2
-------
CO
cr>
RECTISOL ACID 21'22>^
GAS REMOVAL ADI
PROCESS
56 CLAUS
H SULUJR
UNIT
57 J^ TA
TR
IL GAS
IATING
50
COMBUSTION *59a REDUCTION ?59b
AIR GAS
51 i — — .
— a.
1 ^. POWER AND
.... STEAM BOILER
ob — BB«-
68
ELECTROSTATIC
PRECIPITATOR
AND FLUE GAS
L DESULFURIZATION
(
MAKE-UP
WATER
|«.
64
59c
STREAM FLOWS FOR OPTION 3*
Component
C
H
S
0
N
Ash
V
C0?
V
cos*cs2
C2H4
CO
"2
CH4
C2H6
KoOH
N0x
HC
so2
Stream Flow fn 103 kg/hr
21,22,23
.045
719
6.2
0.22
1.4
2.9
0.2
4.6
2.0
1.2
1
97
7.1
1.4
20
1.7
30
24
65
400
1500
19
56
42
6.0
51
677
0.20
0.22
1.4
2.9
0.2
4.6
2.0
1.2
57
9.3
2.6
42
0.24
0.08
0.24
5Sa
5.4
50
9.3
42
.001
.010
0.05
0.02
59b
0.4
68
65
1510
30
126
1070
.05
1.1
.02
2.8
64
65
1510
.05
417
.05
1.1
.02
0.28
63,59c! 61
1.2
29.5
LEGEND:
21,22,23 C
65 1 C
1510 65 c
•°5 56 C
417 51 h
57 C
59a 5
.018 50 -,
59b S
o.io 64 R
68 T
63,59c A
61 C
1.1
0.04
0.28
*Stream numbers refer to Figures 2-2, 2-3 and 2-4. See Table 2-7 for stream index.
GASES FROM RECTISOL UNIT
COAL
COMBUSTION AIR
CONCENTRATED H2$ STREAM
HYDROCARBON CONTAINING STREAM TO BOILER
CLAUS TAIL GAS
SULFUR
TAIL GAS TREATMENT OFF-GAS
SULFUR
RAW FLUE GAS
TREATED FLUE GAS
ASH AND SULFUR
COMBINED GASES TO STACK
Fibure B-3. Air Pollution Control Option 3
-------
RECTISOL ACID GAS
REMOVAL PROCESS
21,22,23
65 *-
STEAM
BOILER
64 -*-
ELECTROSTATIC
PRECIPITATOR
xxv/^
J63
62
l-LUt bAi>
DESULFURIZATION
SYSTEM
t |.
MAKE-UP '
WATER
61 fc STArkK
STREAM FLOWS FOR OPTION 4«
CO
—I
Component
C
H
S
0
N2
Ash
H20
co2
H2S
cos+cs2
C,H,
2 4
CO
H?
CH,,
C2H6
McOH
NO
y
HC
so2
Stream Flow in 103 kg/hr
21,22,23
.045
719
6.2
0.22
1.4
2.9
0.2
4.6
2.0
1.2
65
409
1539
20
1
97
7.1
1.4
20
1.7
30.2
24
64
61.3
1540
30.2
139
1100
.05
1.1
0.02
14.7
63
29.9
62
61.6
1540
0.30
139
1100
.05
1.1
0.02
14.7
59
69
0.27
61
61.6
1540
.05
425
1100
.05
1.1
0.02
1.5
*Stream numbers refer to Figures
See fable 2-7 for stream index.
LEGEND:
21,22
2-2, 2-3 and 2-4.
1 COAL
65 COMBUSTION AIR
,23 ACID GASES FROM RECTISOL UNIT
64 RAW FLUE GAS
63 ASH
62 ASH FREE FLUE GAS
59 SULFUR
61 TREATED FLUE GAS
Figure B-4. Air Pollution Control Option 4
-------
OG
CO
COMBUSTION
AIR
LURGI RECTISOL
ACID GAS
REMOVAL
PROCESS
21,22 ^
STRETFORD
SULFUR
UNIT
23
57a
1
1
n& T Mr r Mrnft Tnn 013
59a T
CLAUS
SULFUR
UNIT
57b
TAI1 RAS 50
TREATING
COMBUSTION] f REDUCTION] fcn
AIR 5Jb ,GAS ' '59c
1 -a-
65 ^_
STEAM AND
POWER BOILER
64
ELECTROSTATIC
PRECIPITATOR
AND FLUE GAS
DESULFURIZATION
1
51b 61 c kiAr
1
K(s]
i ]63,59d
MAKE-UP
WATER
STREAM FLOUS FOR OPTION 5*
22 23
15.3
1.9
1 0.11
7
4
0.1
1.2
1
97
7.
1 .
20
1.
30
24
i
4
7
.2
65
356
1340
17
SlreaT
57a
695
.005
0.
1.
0.
0.
1.
1.
11
1
77
14
4
5
59a
a.3
Flous in 103 Icg/d
57b
4.3
1.2
IS
3
.064
.020
S9b
1.8
50
4.3
1.2
15.3
.0003
.005
.03
.01
59c
.07
64
59
1341
30.2
105
356
.05
1 .1
6ia
0.05
.05
i. i
63,59(1
1 .2
30.1
61b
3 4
7b
9.5
709
.Of
0.1
61c
LEGEND:
21,22 LEAN H2S RECTISOL OFF-GAS
62
1421
.05
287
1080
.005
23 RICH H2S RECTISOL OFF-GAS
1 COAL
65 COMBUSTION AIR
57a STRETFORO OFF-GAS
59a SULFUR
57b CLAUS TAIL GAS
59b SULFUR
50 TAIL GAS TREATMENT OFF-GAS
.[•>
63,
i .2
59c SULFUR
64 RAW FLUE GAS
61 a TREATED FLUE GAS
59d ASH AND SULFUR
61 b INCINERATED STRETFORD
61 c COMBINED FLUE GAS
OFF-GAS
*Stream numbers refer to Figures 2-2, 2-3 and 2-4. See Table 2-7 for stream index.
Figure B-5. Air Pollution Control Option 5
-------
APPENDIX C. MATERIAL RELATED TO EPA METHODOLOGY FOR ENVIRONMENTAL ASSESSMENT
TABLE C-l. SUMMARY OF ENVIRONMENTAL ASSESSMENT
METHODOLOGIES UNDER DEVELOPMENT BY EPA
Methodology
Description
Environmental
Acquisition
(100,102)
Data
To study the pollutant sources in a plant, such sources are
identified and organized by unit operations (Example: wind-
blown dusts, water runoff and leakage/venting as pollutant
sources for material storage). A phased approach consisting
of 3 levels of progressively more directed and detailed
effort has been developed for process/waste stream sampling
and analysis. The three levels are: "Level 1", compre-
hensive screening (including for "criteria" pollutants);
"Level 2", directed detailed analysis, based on Level 1; and
"Level 3", process monitoring of selected priority pollutants,
based on Levels 1 and 2.
Current Environ-
mental background
(97,101,103)
Compilation and continuous upgrading of data on (a) physical,
chemical and toxicological properties of specific pollutants,
(b) pollutants transport/transformation models, and (c) trace
substances in the ambient environment.
Environmental
Objectives
Development
(Multimedia
Environmental
Goals, MEG's)
(98)
Control
Technology(97)
Assessment
The "MEG methodology" is a systematic means for the priori-
tization of the chemical substances in complex effluents for
the purpose of environmental assessment. MEG's are levels
of significant contaminants or degradants that are judged to
be (1) appropriate for preventing certain negative effects
in the surrounding populations or ecosystems, or (2) repre-
sent! ve of the control limits achievable through technology.
To date MEG's have been established for 210 substances. MEG's
are generally derived through models which translate toxico-
logical data, recommended concentration levels and federal
standards or criteria into emissions or ambient level goals.
A "Multimedia Environmental Control Manual" which provides a
stepwise guidance for defining specific control options for
specific situations is under development. Pollution Control
Guidance Documents which provide integrated, multimedia,indus-
try oriented, single-package review of the environmental re-
quirements, guidelines and best control/disposal options and
accounts for variations needed for different regional site
alternatives are being developed for a number of basic energy
processes at the commercial or demonstration stage (e.g., low
Btu gasification). Work on Control Assay Development (CAD)
for coal conversion processes is in progress. CAD's objec-
tive is to perform quick screening treatments on streams
suspected of containing pollutants requiring control.
319
(continued)
-------
TABLE C-l. CONTINUED
Methodology
Description
Environmental
Alternatives
Analysis(lOO)
(Source
Assessment
Models -
SAM's)
SAM's are environmental
lowing areas: (a) rank
toxicity, (b) establish
problem pollutants, (d)
technology alternatives,
assessment tools helpful in the fol-
individual effluent streams by their
sampling priorities, (c) determine
recommend best multimedia control
and (e) recommend control technol-
ogy development programs. Four models under development
are SAM/IA for rapid screening, SAM/IB for biological screen-
ing, SAM/1 for screening and SAM/11 for providing the general
approach to evaluating any U.S. regional site alternatives.
The simplest of the models, SAM/IA, which is fully developed,
is based on a comparison of effluent concentration with the
set of Minimum Acute Toxicity Effluent (MATE) criteria estab-
lished by EPA.
Environmental
Assessment
Reports (EAR)
EAR provides the EPA Administrator, Program Offices and
Policy and Planning with a recognized, authoritative docu-
ment representing OR&D's environmental assessment research
input on standards (supporting data, needs, alternatives)
for a given technology. The report provides a comprehensive,
multimedia, multipollutant data base and checklist of envi-
ronmental facts concerning the technology covered. Recog-
nizing the evolutionary state of the technologies and of
environmental assessment methodology, the report will be
expanded, refined, and updated every one or two years as
needed for Agency purposes. This report is the EAR for
Lurgi coal gasification systems for SNG production; EAR'S
for Wellman Galusha coal gasification systems for low/medium
Btu gas production and for SRC coal liquefaction technology
are also being prepared.
320
-------
fiSO IMPACT! 13 JSLL
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Figure C-l. Environmental Assessment/Control Technology Development Diagranr97^
-------
TABLE C-2. MEG CHART FOR NAPHTHALENE
NAPHTHALENE
EMISSION LEVEL GOALS
Air. jig/m
(ppmVol)
Water, M9/I
(ppm Wt)
Land. MB/9
(ppmWt)
1. Baud on B«t Technology
A. Eallbflfi Sundwdt
NSPS. 8PT. BAT
B. Developing Technology
Engineering Eitimem
(R&D Goals)
II. Bawd on Ambient Factor*
A. Minimum Acute
Toxicltv Effluent
Baud on
Hultil Effect!
5.0E4
(10)
7.5E5
1.5E3
Beudon
Ecological
Effect!
1-.OE2
2.0E-1
B Ambknt
B«Md on
Htdtft Effects
119
(0.02)
690
1.38
LmK&ul*
Bunion
Ecological
Effectl
50
0.1
C. Elimination of
Oluhvoi
Nnuril B«ckgraun4*
3.8-11.2t
"To ba multiplied by dilution factor
AMBIENT LEVEL GOALS
Air. M9/m3
(ppmVol)
Water, ufl/|
Ippm Wt)
Land, M9/Q
(ppmWt)
1. Currant or Proposed Ambient
Standard* or CrrMria
A. Bend on
Htttltl Effect!
B. Bxedon
Eeologkal Efteeo
II. Tosicity Bated Ettimatad
PefmitKlsfe Concantration
A. aMedm
HedthEffKtl
119
(0.02)
690
1.38
B. Da«ad on
Ecological Effects
50
0.1
III. Zero Thrarivold PollutsnU
Eitirnoted Permiuibto Concentration
Bwed on Heerth Effect!
142
2,130
4.26
tReported for urban atmosphere. No rural concentration 1s reported.
322
-------
TABLE C-3. MEG BACKGROUND INFORMATION SUMMARY FOR NAPHTHALENE
WIN: L66J
STRUCTURE;
CATEGORY: 21
NAPHTHALENE: C1C)H8 (moth flakes, naphthalln, naphthaline.
naphthene, tar camphor, white tar).
Colorless monocllnlc crystals, aromatic odor.
PROPERTIES:
Molecular wt: 128.18 mp: 80.55, bp: 218, 87.510; d: 1.025320. 0.9625^°°°; vap. press: 1 ran at 52.6' C;
vap.d: 4.42; very low solubility in water; solubility may be enhanced by surfacant Impurities 1n water
(ref. 58).
NATURAL OCCURRENCE. CHARACTERISTICS. ASSOCIATED COMPOUNDS:
Naphthalene is among the lower molecular weight polycyclic hydrocarbons comprising the volatile portion
of the benzene-soluble fraction of coal tar (ref. 4). Concentrations of 3.8 to 11.2 ug/m 1n urban air
are reported (ref. 1). Naphthalene 1s associated with partlculate polycycllc aromatic hydrocarbons,
PPAH (ref. 71). The following concentrations of PPAH have been estimated or reported: A1r (urban
environment in winter in seven selected U.S. cities): 21.6 ng/m3 - 146 ng/m3 (ref. 71); groundwater
and surface treated water:
1,000 ug/kg (ref. 58).
0.001 \tq/t - 0.025 yg/£ (ref. 58); upper layer of Earth's crust: 100 ug/kg -
TOXIC PROPERTIES. HEALTH EFFECTS;
LD5Q (oral, rat): 1,780 rag/kg.
Naphthalene may cause Irritation 1n concentrations of 15 pom, and serious damage to eyes nay
result from continuous exposure (ref. 4).
Naphthalene may be present In soot, coal tar, and pitch, which ere known to be carcinogenic
to man. Carcinogenic polycycllc aromatic hydrocarbons may Induce tumors at the site of application
(ref. 59). Naphthalene 1s Included 1n the NIOSH Suspected Carcinogen List. The EPA/NIOSH
ordering number is 4101. The lowest dose to induce an oncogenlc response is reported as 3.500 mg/kg.
The adjusted ordering number is 1.17. Naphthalene is considered inactive as a carcinogen (ref. 59).
Naphthalene has been rated as moderately toxic to aquatic organisms. The 96-hour TLm 1s reported
as 1-10 ppm (ref. 2). Naphthalene in concentrations of 1 mg/t may cause tainting of fish flesh (refs. 28, 69).
REGULATORY ACTIONS. STANDARDS. CRITERIA. RECOGNITION. CANDIDATE STATUS FOR SPECIFIC REGULATION:
Naphthalene appears on EPA Consent Decree List with an assigned priority of 2.
TLV: 50 mg/m3 (10 ppm)
TLV for coal-tar pitch: 0.2 mg/m [The specification includes naphthalene, anthracene, «cr1d1ne,
phenanthrene, and fluorene collectively. The purpose of the TLV is to minimize concentrations of
higher weight polycycllc hydrocarbons which are carcinogenic (ref. 4).]
MINIMUM ACUTE TOXICITY CONCENTRATIONS:
Air. Health: 5.0 x 104 ug/m3 (10 ppm)
Water. Health: 15 x 5.0 x 104 • 7.5 x 105
Land, Health: 0.002 x 7.5 x 105 • 1.5 x 103 ug/g
ESTIMATED PERMISSIBLE CONCENTRATIONS;
EPCAH1 - 103 x 50/420 • 119 ug/m3
EPC
AH la
10/420
EPCWH, • 15 x 119
0.02 ppm
• 1.785 ug/£
EPCWH2 • 13.8 x 50 - 690 ug/£
EPC. H • 0.002 x 690 • 1.38 ug/g
EPC
"LH
'AC2
10J/(6 x 1.17) • 142 wg/mj
9/1
EPCLC • 0.002 x 2.130 • 4.26 yg/g
EPCHC • 15 x 142 - 2,130 v
A1r, Ecology:
Water, Ecology: 100 x 1 • 100 ug//
Land, Ecology: 0.002 x 100 • 0.2 ug/g
EPC
EPC
EPC
'WEI
'WE?
IE'
- 50 x 1 • 50 vg/t
• 1,000 vg/t (to prevent tainting)
0.002 x 50 • 0.1 ug/g
323
-------
TABLE C-4. SAM/IA SUMMARY SHEET
1. SOURCE AND APPLICABLE CONTROL OPTIONS
2. PROCESS THROUGHPUT OR CAPACITY
3 USE THIS SPACE TO SKETCH A BLOCK DIAGRAM OF THE SOURCE AND CONTROL ITEMS SHOWING ALL EFFLUENT
STREAMS INDICATE EACH STREAM WITH A CIRCLED NUMBER USING 101-199 FOR GASEOUS STREAMS,
201-299 FOR LIQUID STREAMS, AND 301-399 FOR SOLID WASTE STREAMS.
4. LIST AND DESCRIBE GASEOUS EFFLUENT STREAMS USING RELEVANT NUMBERS FROM STEP 3.
101 , .
102
103
104
105
106 :
107
5. LIST AND DESCRIBE LIQUID EFFLUENT STREAMS USING RELEVANT NUMBERS FROM STEP 3.
201
202 , ,
203 .
204
205
206
6. LIST AND DESCRIBE SOLID WASTE EFFLUENT STREAMS USING RELEVANT NUMBERS FROM STEP 3.
301
302
303 .
304 __ .
305
306
7. IF YOU ARE PERFORMING A LEVEL 1 ASSESSMENT, COMPLETE THE IA02-LEVEL 1 FORM FOR EACH EFFLUENT
STREAM LISTED ABOVE. IF YOU ARE PERFORMING A LEVEL 2 ASSESSMENT, COMPLETE THE IA02-LEVEL 2 FORM
FOR EACH EFFLUENT STREAM LISTED ABOVE.
324 (continued)
-------
TABLE C-4. CONTINUED
8. LIST SUMS FROM LINE 7, FORMS IA02, IN TABLE BELOW
DEGREE OF HAZARD AND TOXIC UNIT DISCHARGE RATES BY EFFLUENT STREAM
GASEOUS
STREAM
CODE
A
DEGREE OF
HAZARD
HEALTH
BASED
-
B
ECOL
BASED
-
c
TOXIC UNIT
DISCHARGE RATES
HEALTH
BASED
ECOL
BASED
(rn'/sec)
D
E
LIQUID
STREAM
CODE
F
DEGREE OF
HAZARD
HEALTH
BASED
-
G
ECOL
BASED
-
H
TOXIC UNIT
DISCHARGE RATES
HEALTH
EASED
ECOL.
BASED
(I/sec)
1
J
SOLID WASTE
STREAM
CODE
K
DEGREE OF
HAZARD
HEALTH
BASED
-
L
ECOL
BASED
-
M
TOXIC UNIT
DISCHARGE RATES
HEALTH
BASED
ECOL
BASED
(p,/sec)
N
0
9. SUM SEPARATELY GASEOUS, LIQUID AND SOLID WASTE STREAM DEGREES OF HAZARD FROM TABLE AT LINE 8
(I.E., SUM COLUViNS)
GASEOUS
LIQUID
SOLID WASTE
TOTAL DEGREE OF HAZARD
HEALTH-BASED ECOLOGICAL-BASED
(I COL. B) 9A V- COL. C) 9A1
(I COL. G) 9B d COL. H) 9B'
(I COL. L) 9C (2 COL M) 9C'
10. SUM SEPARATELY GASEOUS, LIQUID AND SOLID WASTE STREAM TOXIC UNIT DISCHARGE RATES FROM TABLE AT
LINE 0 (I.E., SUM COLUMNS)
GASEOUS (m'/sec)
LIQUID (I/sec)
HEALTH-BASED
(I COL D) 10A_
(I COL. I) 10B _._
SOLID WASTE (g/sec) (I COL. N) 10C_
TOTAL TOXIC UNIT DISCHARGE RATES
ECOLOGICAL-BASED
(I COL. E) IDA'
(2 COL. J) 10B'
(2 COL. 0) IOC'
11. NUMBER OF EFFLUENT STREAMS
GASEOUS 11A
LIQUID 11B
SOLID WASTE 11C
]2. LIST POLLUTANT SPECIES KNOWN OR SUSPECTED TO BE EMITTED FOR WHICH A MATE IS NOT AVAILABLE.
325
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-120
3. RECIPIENT'S ACCESSION
4. TITLE AND SUBTITLE
ENVIRONMENTAL ASSESSMENT REPORT: Lurgi
Coal Gasification Systems for SNG
5. REPORT DATE
May 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
M. Ghassemi, K.Crawford, and S.Quinlivan
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TRW Environmental Engineering Division
One Space Park
Redondo Beach, California 90278
10. PROGRAM ELEMENT NO.
E HE 62 3 A
11. CONTRACT/GRANT NO.
68-02-2635
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 PERIOD COVERED
Final; 5/78 - 4/79
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTESIERL_RTp project officer is William 3. Rhodes, Mail Drop 61,
919/541-285L
is. ABSTRACTThe repOrt jg a compilation and analysis of data on the equipment and pro-
cesses constituting the Lurgi Substitute Natural Gas (SNG) systems, the control/dis-
posal alternatives for a media, the performance and cost of control alternatives, and
present and proposed environmental requirements. It provides the best technical ba-
sis currently available for establishing environmental standards for Lurgi SNG
plants. Lurgi SNG systems are divided into four operations (coal preparation, coal
gasification, gas purification, and gas upgrading) and a number of auxiliary pro-
cesses (air pollution control, raw water treatment, oxygen production, etc.); each
operation consists of a number of processes. Data are provided on the characteris-
tics of input materials, products, and waste streams associated with each process.
Pollution control alternatives for air emissions, water effluents, solid wastes, and
toxic substances in an integrated facility were examined for performance, costs,
energy requirements, and ability to comply with current and anticipated environ-
mental standards. The adequacy of the data was evaluated and the additional data
needed to support standards development and enforcement and health and ecological
effects and control research and development were identified. On-going and plan-
ned programs which may supply some of the needed data are reviewed.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COS AT i Field/Group
Pollution
Assessments
Coal Gasification
Manufactured Gas
Coal Preparation
Gas Purification
Water Treatment
Toxic ity
Pollution Control
Stationary Sources
Substitute Natural Gas
Lurgi
Gas Upgrading
13 B
14B
13 H
21D
081
07A
06T
13 DlSTRI BUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
341
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
326
-------
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
INDUSTRIAL ENVIRON MENTAL RESEARCH LABORATCR'
cv° RESEARCH TRIANGLE PARK
*• NORTH CAROLINA 27711
DATE: July 10, 1979
SUBJECT: Lurgi EAR
FROM: William J. Rhodes (MD-6V
Program Manager, Synthetic Fuels
TO: Distribution
The attached report is a compilation and analysis of available data on
the equipment and processes which constitute Lurgi SNG systems, the
control/disposal alternatives for media, the performance and cost of
control alternatives, and present and proposed environmental require-
ments as of early 1979.
The information represents our best judgment in each case. Although
Lurgi technology is presently commercially available and operating,
there is still a lack of adequate information to fully characterize
the process technology for environmental effects and to evaluate the
effectiveness of control technology. Some of these needs are being
addressed in our current data acquisition programs, but they are
limited by resources and available sites.
The findings are synopsized in a twenty-two page summary in the report.
When sufficient new information is available, this environmental assess-
ment report will be updated and republished.
Attachment
-------
Distribution:
Morris Altschuler
Don Goodwin
R. P. Hangebrauck
T. K. Janes
Steve Jelinek
A. Lefohn
G. D. McCutchen
Frank Princiotta
N. Dean Smith
D. A. Schaller
Robert Statnick
P. P. Turner
Ann Alford
Paul Altschuller
Walt Barber
Del Barth
T. Belk
Rudy Boksleitner
W. E. Bye
A. Corson
Stan Cuffe
Clyde Dial
Al Ellison
J. R. Farmer
K. E. Feith
J. E. Fitzgerald
Stephen Gage
F. Galpin
Tom Mauser
Stan Hegre
Ron Hill
Horning
B. M. Jarrett
J. W. Jordan
John Knelson
R. W. Kuchkuda
Kenneth Mackenthun
Mark Mercer
Don Mount
John Nader
Eric Preston
Gerry Rausa
Steve Reznek
Shabeg S. Sandhu
Robert Schaffer
David Shaver
George Stevens
Bill Telliard
W. G. Tucker
Jerry Walsh
------- |