c/EPA
United States Industrial Environmental Research EPA-600/8-83-006 <~i~
Environmental Protection Laboratory April 1983
Agency Research Triangle Park NC 27711
Research and Development
Pollution Control
Technical Manual for
Lurgi-Based
Indirect Coal
Liquefaction and SNG
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EPA-600/8-83-006
April 1983
POLLUTION CONTROL TECHNICAL MANUAL
FOR
Lurgi-Based Indirect Coal Liquefaction and SNG
Program Manager: Gregory G. Ondich
Office of Environmental Engineering and Technology (RD-681)
U. S. Environmental Protection Agency
401 M Street, SW
Washington. DC 20460
Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory-RTF
Research Triangle Park, NC 27711
U.S. Environmental Protection Agency
Region 5, Library (5PL-16)
230 S. Dearborn Street, Room 1670
Chicago, IL 60604
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DISCLAIMER
This Pollution Control Technical Manual was based on data obtained in
EPA's source characterization study at the Kosovo Gasification Plant of the
Elektroprivreda Kosovo, Yugoslavia. Data was also provided by the Lurgi Plant
at Westfield, Scotland and the SASOL Plant in South Africa. Additional data
sources used in this manual included other EPA synfuels characterization
studies, environmental impact statements, published literature, and EPA sup-
ported engineering calculations. No proprietary or confidential data appear
or have been used in the preparation of this manual. Although this manual
addresses the Lurgi gasifier based technology, the process developer, Lurgi
Kohle and Mineraloltechnik, GmbH, FRG, was not involved in the development of
the manual. Thus, the manual does not necessarily represent Lurgi's engineer-
ing design data, material balances, or operational information.
This document has been reviewed in accordance with U.S. Environmental
Protection Agency policy and approved for publication. Mention of trade names
or commercial products does not constitute endorsement or recommendation for
use.
ii
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FOREWORD
The purpose of the Pollution Control Technical Manuals (PCTMs) is to
provide process, discharge, and pollution control data in summarized form for
the use of permit writers, developers, and other interested parties. The PCTM
series covers a range of alternate fuel sources, including coal gasification
and coal liquefaction by direct and indirect processing, and the eztraction of
oil from shale.
The series consists of a set of technical volumes directed at production
facilities based upon specific conversion processes. The entire series is
supplemented by a pollution control technology appendix volume which describes
the operation and application of approximately 50 control processes.
All PCTMs are prepared on a base plant concept (coal gasification and
liquefaction) or developer proposed designs (oil shale) which may not fully
reflect plants to be built in the future. The PCTMs present examples of con-
trol applications, both as individual process units and as integrated control
trains. These examples are taken in part from applicable permit applications
and, therefore, are reflective of specific plants. None of the examples are
intended to convey an Agency endorsement or recommendation but rather are pre-
sented for illustrative purposes. The selection of control technologies for
application to specific plants is the exclusive function of the designers and
permitters who have the flexibility to utilize the lowest cost and/or most
effective approaches. It is hoped that readers will be able to relate their
waste streams and controls to those presented in these manuals to enable them
to better understand the extent to which various technologies may control spe-
cific waste streams and utilize the information in making control technology
selections for their specific needs.
The reader should be aware that the PCTMs contain no legally binding re-
quirements or guidance, and that nothing contained in the PCTMs relieves a
facility from compliance with existing or future environmental regulations or
permit requirements.
Herbert L. Wiser
Acting Deputy Assistant Administrator
Office of Research and Development
U.S. Environmental Protection Agency
iii
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ABSTRACT
The Environmental Protection Agency (EPA), Office of Research and Devel-
opment has undertaken an extensive study to determine synthetic fuel plant
waste stream characteristics and to evaluate potentially applicable pollution
control systems. The purpose of this and all other PCTMs is to convey this
information in a manner that is readily useful to designers, permit writers,
and the public.
This specific PCTM addresses coal-based synthetic fuels facilities using
dry ash Lurgi gasifiers to generate a synthesis process feed gas. Product
synthesis technologies examined in this PCTM include: methanation to produce
substitute natural gas (SNG), methanol synthesis, Mobil M-gasoline synthesis
from methanol, and Fischer-Tropsch synthesis.
The manual proceeds through a description of the hypothetical base plant,
characterizes the waste streams produced in each medium, and discusses the
array of commercially available controls which can be applied to the base
plant waste streams. From these generally characterized controls, several ex-
amples are constructed for each medium in order to illustrate typical control
technology applications. Then, example control trains are constructed for
each medium, illustrating the function of integrated control systems. Control
and control system cost and performance estimates are presented, together with
descriptions of the discharge streams, secondary waste streams, and energy
requirements. A summary of the gaps and limitations in the data base used to
develop this manual is presented along with a listing of additional data
needs.
IV
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CONTENTS
FOREWORD
ABSTRACT
FIGURES
TABLES
ACRONYMS AND ABBREVIATIONS
CONVERSION FACTORS
ACKNOWLEDGEMENT
Page
«v
1.0 INTRODUCTION .......................... 1
1.1 TECHNOLOGY OVERVIEW ....................... 3
1.2 APPROACH TO MANUAL DEVELOPMENT ................. 4
1.2.1 Base Plant Definition ................. 4
1.2.2 Control Technology Evaluation ............. 6
1.3 DATA BASE ............................ 7
1.4 MANUAL ORGANIZATION AND UTILIZATION ............... 10
1.4.1 Manual Organization .................. 10
1.4.2 Manual Utilization .................. 11
2.0 PROCESS OVERVIEW ........................ 14
2.1 COAL FEED CHARACTERISTICS AND PRODUCT SLATES .......... 18
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CONTENTS (Continued)
Page
2.2 BASE PLANT DESCRIPTION 23
2.2.1 Coal Preparation 23
2.2.2 Lurgi Coal Gasification 24
2.2.3 Gas Purification and Upgrading 26
2.2.4 Product Synthesis 30
2.2.5 Auxiliaries 33
2.2.6 Fugitive Emissions 34
2.3 BASE PLANT CAPITAL INVESTMENT AND ANNUALIZED OPERATING COSTS . . 35
3.0 PROCESS DESCRIPTION AND WASTE STREAM CHARACTERIZATION 37
3.1 COAL PREPARATION 46
3.2 LDRGI GASIFICATION 54
3.2.1 Coal Feeding 58
3.2.2 Lurgi Gasification 59
3.2.3 Ash Removal 61
3.2.4 Waste Stream Characteristics 64
3.3 GAS PURIFICATION AND UPGRADING 73
3.3.1 Gas Quenching and Cooling 73
3.3.2 Shift Conversion 77
3.3.3 Rectisol Acid Gas Removal 80
3.3.4 Trace Sulfur Removal 86
3.3.5 Waste Streams From Gas Purification and Upgrading. . . 87
vi
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CONTENTS (Continued)
Pane
3.4 PRODUCT SYNTHESIS 100
3.4.1 Synthesis of Substitute Natural Gas 100
3.4.2 Synthesis of Synthetic Liquid Fuels 102
3.4.3 Waste Streams Generated by Synthesis Operations. . . . 117
3.5 PRODUCTS AND BYPRODUCTS 124
3.5.1 Methanol Synthesis Product 124
3.5.2 Fischer-Tropsch Liquid Products 127
3.5.3 Mobil M-Gasoline 130
3.5.4 Substitute Natural Gas (SNG) 131
3.5.5 LPG 132
3.5.6 Lnrgi Gasification Byproducts 132
3.5.7 Ammonia and Sulfur 136
3.5.8 Excess Coal Fines 140
3.6 AUXILIARIES 141
3.6.1 Raw Water Treatment 141
3.6.2 Steam and Power Generation and Process Heating .... 145
3.6.3 Cooling Operations 148
3.6.4 Oxygen Production 150
3.6.5 Product and Byproduct Storage 151
3.7 FUGITIVE AND MISCELLANEOUS WASTES 157
3.7.1 Fugitive Organic Emissions 157
3.7.2 Non-Process/Intermittent Wastewater Streams 158
3.7.3 Equipment Cleaning Wastes 162
3.8 WASTE STREAM/CONTROL TECHNOLOGY INDEX 164
vii
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CONTENTS (Continued)
Pane
4.0 EVALUATION OF POLLUTION CONTROL TECHNOLOGY 173
4.1 GASEOUS MEDIUM 181
4.1.1 Rectisol Acid Gases 186
4.1.1.1 HjS-Rich Acid Gases 212
4.1.1.2 HjS-Lean Acid Gases 214
4.1.1.3 C0,-Rich Acid Gases 220
4.1.2 Small Volume and Intermittent/Transient Waste Gases
Containing VOC and Reduced Sulfur Compounds 221
4.1.2.1 Coal Lockhopper Gases 222
4.1.2.2 Transient (Startup, Shutdown, and Upsets)
Waste Gases 227
4.1.2.3 Depressurization and Stripping Gases. . . . 230
4.1.2.4 C02-Rich Gases from SNG Production 231
4.1.3 Transient Process Gases Containing S04, CO, and/or
Particulates 232
4.1.3.1 Shift Catalyst Regeneration Offgases. . . . 233
4.1.3.2 Mobil M Catalyst Regeneration Offgases. . . 237
4.1.3.3 Carbon Regeneration Flue Gases 238
4.1.4 Combustion Gases 239
4.1.4.1 Boiler Flue Gases 253
4.1.4.2 Process Heater Flue Gases 259
4.1.4.3 Wastewater Incineration Flue Gases 260
4.1.5 Fugitive Dust from Material Storage 263
4.1.6 Particulates from Material Conveying and Processing. . 268
4.1.7 Fugitive VOC Emissions 270
4.1.7.1 Product/Byproduct Storage Emissions .... 278
4.1.7.2 Fugitive Organic Emissions from Process
Equipment 282
viii
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CONTENTS (Continued)
Page
4.1.8 Air Pollution Control in Integrated Facilities .... 286
4.1.8.1 Example 1 - High Sulfur Coal/Selective
Rectisol 286
4.1.8.2 Example 2 - Low Sulfur Coal/Nonselective
Rectisol 296
4.1.8.3 Example 3 - Incineration of Waste Gases in
Utility Boilers 302
4.2 AQUEOUS MEDIUM 308
4.2.1 Aqueous Medium Generic Controls 314
4.2.1.1 Processes for Removal of Suspended
Solids, Tars, and Oils 315
4.2.1.2 Processes for Removal of Bulk Organj.cs. . . 323
4.2.1.3 Processes for Removal of Dissolved Gases. . 330
4.2.1.4 Processes for Removal of Dissolved
Organics 339
4.2.1.5 Processes for Removal of Residual
Organics 353
4.2.1.6 Processes for Removal of Dissolved
Inorganics 364
4.2.1.7 Processes for Volume Reduction 371
4.2.1.8 Processes for Residual Disposal 379
4.2.2 Control Applications for Specific Streams Containing
Primarily Organic Compounds 384
4.2.2.1 Gas Liquor 385
4.2.2.2 Rectisol Still Bottoms 405
4.2.2.3 Synthesis Wastewaters 406
4.2.2.4 Secondary Wastewater Streams 409
4.2.2.5 Integrated Control Examples for Streams
Containing Primarily Organic Compounds. . . 411
4.2.3 Control Applications for Specific Streams
Containing Primarily Inorganic Compounds 440
ix
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CONTENTS (Continued)
Page
4.3 SOLID WASTE MANAGEMENT 449
4.3.1 Solid Waste Control 455
4.3.1.1 Treatment 458
4.3.1.2 Reuse/Resource Recovery 460
4.3.1.3 Disposal 461
4.3.2 Inorganic Ashes and Sludges 469
4.3.2.1 Gasifier Ash 469
4.3.2.2 Boiler Bottom Ash 472
4.3.2.3 Boiler Fly Ash 473
4.3.2.4 Boiler FGD Sludge 474
4.3.2.5 Dewatered Chemical Precipitation and Raw
Water Treatment Sludges 475
4.3.3 Recovered Byproducts 476
4.3.3.1 Recovered Elemental Sulfur 476
4.3.3.2 Excess Coal Fines 476
4.3.3.3 Collected Dust from Particulate Control . . 477
4.3.4 Organic Sludges 478
4.3.4.1 Treatment 478
4.3.4.2 Disposal 480
4.3.5 Spent Catalysts and Sulfur Guard 481
4.3.5.1 Treatment 482
4.3.5.2 Resource Recovery and Reuse 482
4.3.5.3 Disposal 483
5.0 DATA GAPS AND LIMITATIONS 484
6.0 REFERENCES 506
x
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CONTENTS (Continued)
Page
APPENDIX A - LURGI DRY ASH COAL GASIFICATION A-l
APPENDIX B - RECTISOL ACID GAS REMOVAL PROCESS B-l
APPENDIX C - COSTING METHODOLOGY AND BASE PLANT COSTS C-l
APPENDIX D - THE FATE OF TRACE ELEMENTS IN LURGI GASIFICATION
SYSTEMS D-l
APPENDIX E - MATERIAL BALANCES E-l
xi
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FIGURES
Page
2-1 Simplified block flow diagram of a Lurgi-based synthesis
gas production facility 16
2-2 Simplified block flow diagram for conversion of synthesis
gas to SNG or liquid fuels . • • 17
3-1 Process operations and discharge streams associated with
Lurgi-based synfuels facilities-main gasification train. . 38
3-2 Fischer-Tropsch synthesis and product upgrading 39
3-3 Methanol and Mobil M-gasoline synthesis and upgrading. . . 40
3-4 Substitute natural gas production 41
3-5 Auxiliary processes associated with Lurgi-based synfuels
facilities 42
3-6 Simplified block flow diagram of coal preparation 47
3-7 Lurgi gasifier 55
3-8 Schematic of ash quench system for Lurgi gasification. . . 63
3-9 Raw gas quenching and cooling system 75
3-10 High temperature shift conversion 79
3-11 Nonselective Rectisol acid gas removal process 83
3-12 Selective Rectisol acid gas removal process 85
3-13 Methanation and dehydration for SNG synthesis 101
3-14 ICI methanol synthesis process 106
3-15 Mobil M-Gasoline synthesis and product recovery 109
3-16 Fischer-Tropsch (Synthol) synthesis and product recovery . 113
3-17 Methanation, C04 removal, and drying for co-production
of SNG with synthetic liquid fuels 118
3-18 Typical raw water treatment system 142
4-1 Three stage Glaus plant with split flow option 196
4-2 Simplified flow diagram of the Stretford process 199
4-3 Schematic flow diagram for example 1-integrated control. . 288
4-4 Schematic flow diagram for example 2 297
4-5 Example 3 - integrated control 303
xii
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FIGURES (Continued)
Figure
4-6 Phenosolvan solvent extraction process .......... 326
4-7 The PHOSAM-W process ................... 334
4-g Wastewater incinerator with quench ............ 359
4-9 Process flow diagram for lime/soda softening system. . . . 367
4-10 Vapor compression evaporation system ........... 376
4-11 Block flow diagram for integrated control example No. 1. . 413
4-12 Block flow diagram for integrated control example No. 2. . 418
4-13 Block flow diagram for integrated control example No. 3. . 422
4-14 Block flow diagram for integrated control example No. 4. . 425
4-15 Block flow diagram for integrated control example No. 5. . 429
4-16 Block flow diagram for integrated control example No. 6. . 432
4-17 Block flow diagram for integrated control example No. 7. . 436
4-18 Landfill designs ..................... 463
4-19 Capital investment and annual ized unit cost for
landfills ......................... 465
xiii
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TABLES
Table page
1-1 Completed and Ongoing Data Acquisition Programs at Coal
Gasification Facilities Sponsored or Co-Sponsored by
the EPA 8
2-1 Proximate and Ultimate Analyses of Base Plant Coals ... 19
2-2 Typical Upgraded Product Slates for Lurgi-Based Synthetic
Fuels Facilities 21
2-3 Estimated Base Plant Costs 36
3-1 Typical Upgraded Product Slates for Lurgi-Based
Synthetic Fuels Facilities 44
3-2 Estimated Overall Material Flows for Coal Preparation
Operation 48
3-3 Estimated ROM Coal Storage Pile Capacities 49
3-4 Estimated Fugitive Particulates from Coal Storage Piles . 51
3-5 Fugitive Particulate Emission Factors for Coal
Preparation Operations 53
3-6 Estimated Material Flows for Lurgi Gasification
Operation - Rosebud Coal 56
3-7 Estimated Major and Minor Components of Raw Lurgi
Gas 62
3-8 Estimated Composition of Air-Blown Lurgi Gases 68
3-9 Polycyclic Organic Matter Identified in Kosovo Byproduct
Tars and Oils 68
3-10 Estimated Mass Flows for Gasifier Ash Quenching System. . 71
3-11 Composition and Leaching Characteristics of Unquenched
Lurgi Gasifier Ashes 72
3-12 Estimated Material Flows for Gas Purification and
Upgrading - Rosebud Coal 74
3-13 Available Data for Gas Liquor Depressurization Gases. . . 88
3-14 Estimated Characteristics of Lurgi Gas Liquors 89
3-15 Concentrations of Organic Compounds Found In Lurgi Gas
Liquor (North Dakota Lignite) 91
3-16 Concentration of Polynuclear Aromatic Compounds in Raw
and Dephenol ized Kosovo Gas Liquors 92
3-17 Estimated Composition of Spent Shift Catalyst 94
xiv
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TABLES (Continued)
Table Page
3-18 Estimated Compositions of H2S-Containing Acid Gases
from Rectisol (Liquids Synthesis Gases) 95
3-19 Estimated Compositions of C0,-Rich Offgas from
Selective Rectisol 98
3-20 Estimated Composition of Methanol/Water Still Bottoms. . 99
3-21 Estimated Material Flows for SNG Synthesis -
Rosebud Coal 103
3-22 Estimated Material Flows for Methanol Synthesis -
Rosebud Coal 108
3-23 Estimated Material Flows for Mobil M-Gasoline
Synthesis - Rosebud Coal Ill
3-24 Estimated Material Flows for Fischer-Tropsch Synthesis -
Rosebud Coal 115
3-25 Components Reported in Commercial Methanol 125
3-26 Estimated Composition of Crude Methanol from Coal. . . . 126
3-27 Estimated Composition of Finished Indirect Coal
Liquefaction Unleaded Gasolines and Typical Petroleum
Gasolines 128
3-28 Distribution of Oxygenated Byproducts from Fluid-Bed
Fischer-Tropsch Synthesis 129
3-29 Estimated Blending Components for Mobil M-Gasoline . . . 130
3-30 Available Data on the Characteristics of Byproduct Tars. 133
3-31 Polynuclear Aromatic Compounds Found in Byproducts
from a Lurgi-Type Gasifier in Kosovo, Yugoslavia .... 134
3-32 Composition of Benzene Soluble Tars Produced in the
Synthane Gasification Process 135
3-33 Available Data on the Characteristics of Byproduct Oils. 137
3-34 Available Data on Composition of Crude Lurgi Phenols. . . 138
3-35 Composition of Naphtha Oil Produced at the Westfield
Lurgi Facility 138
3-36 Available Characterization Data for Byproduct Naphtha. . 139
3-37 Estimated Primary Demineralizer Regeneration Wastewater . 144
3-38 Estimated Uncontrolled Auxiliary Boiler Flue Gas
Compositions 147
xv
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TABLES (Continued)
Table Page
3-39 Maximum Measured Concentrations of Selected Components
in Bottom Ash and Ash Slurry 148
3-40 Water Losses from the Base Plant Cooling Towers 149
3-41 Estimated Characteristics of Cooling Tower Slowdown
and Drift 150
3-42 Estimated Product and Byproduct Properties 153
3-43 Estimated Storage Tank Evaporative Emissions 154
3-44 Composition of Evaporative Emissions from Gasoline
Storage 155
3-45 Storage Tank Vent Data from Kosovo Plant 156
3-46 Fugitive Emission Factors 159
3-47 Estimated Fugitive Hydrocarbon Emissions 160
3-48 Estimated Average Storm Runoff for Assumed Base Plant
Locations 161
3-49 Stream Index 165
3—50 Cross—Reference Index for Primary Waste Streams 169
3-51 Cross-Reference Index for Secondary Waste Streams .... 171
4-1 Summary of Estimated Gaseous Stream Characteristics in
Lurgi-Based Facilities 182
4-2 Categorization of Gaseous Waste Stream in Lurgi
Gasification Facilities According to Source Type 184
4-3 Key Features of Hydrocarbon Removal/HaS Enrichment
Processes 189
4-4 Key Features of Bulk Sulfur Removal Processes 194
4-5 Key Features of Residual Sulfur Removal Processes .... 205
4—6 Key Features of Incineration Processes 210
4-7 Costs for Control of Stretford Oxidizer Vent Gases. . . . 219
4-8 Costs Associated with Control of Lockhopper Vent Gases. . 225
4-9 Costs Associated with Incineration of Transient Waste
Gases 229
4-10 Costs for Control of S02 in Shift Catalyst Regeneration
Offgases 236
xv i
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TABLES (Continued)
Table Page
4-11 Cost Estimates for Control of Mobil Catalyst
Decommissioning Offgas 237
4-12 Cost Summary: Carbon Absorption Regeneration Offgas. . . 238
4-13 Combustion Modification Techniques for NO Control. . . . 241
4-14 NO Flue Gas Treatment Control Alternatives for Boilers . 244
x
4-15 Key Features of S02 Removal Processes 246
4-16 Key Features of Particulate Collection Equipment 250
4-17 Example Boiler Feed and Potential Emissions
Contributions 254
4-18 Control of Particulates in Boiler Flue Gas by ESP
(Rosebud Methanol Synthesis Case) 256
4-19 Costs for Wellman-Lord Control of S02 in Boiler Flue
Gases - Rosebud Coal to Methanol 258
4-20 Cost Summary of Wastewater Incinerator Flue Gas Controls. 262
4-21 Key Features of Storage Pile Dust Control Technologies. . 264
4-22 Repair Methods for Fugitive Emissions Reduction 275
4-23 Equipment Design/Modifications for Fugitive Hydrocarbon
Emissions Control 276
4-24 Storage Tank Emission Estimates . . , 279
4-25 Estimated Incremental Costs for Storage of Synthetic
Liquids 281
4—26 Fugitive Organic Emissions from Process Equipment .... 283
4-27 Capital and Annualized Costs for Fugitive Volatile Organic
Compound Emission Controls 285
4-28 Material Flow for Example 1 Integrated Control - Amine
Enrichment of Rectisol and Stripper Overhead Gases. . . . 290
4-29 Material Flow for Example 1 Integrated Control - SCOT
Tail Gas Treatment 291
4-30 Material Flow for Example 1 Integrated Control - BEAVON
Tail Gas Treatment 292
4-31 Material Flow for Example 1 Integrated Control -
Wellman-Lord Tail Gas Treatment 293
4-32 Costs Associated with Example 1 Integrated Control. . . . 294
xvii
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TABLES (Continued)
Table Page
4-33 Material Flow for Example 2 Integrated Control -
Stretf ord/Incineration 299
4-34 Costs Associated with Example 2 Control 300
4-35 Costs Associated with Example 3 Integrated Control. . . . 306
4-36 Summary of Uncontrolled Aqueous Waste Streams Generated
in Lurgi-Based Synfuels Facilities 310
4-37 Technologies Potentially Applicable to the Removal of
Suspended Solids, Tars, and Oils from Lurgi-Based Synfuels
Plant Wastewaters 316
4-38 Technologies Potentially Applicable to the Removal of
Bulk Organics from Lurgi-Based Synfuels Plant
Wastewaters 324
4-39 Technologies Potentially Applicable to the Removal of
Dissolved Gases from Lurgi-Based Synfuels Plant
Wastewaters 331
4-40 Technologies Potentially Applicable to the Removal of
Dissolved Organics from Lurgi-Based Synfuels Plant
Wastewaters 340
4-41 Comparative Performance Data for Activated Sludge Systems
Treating Wastewaters from Byproduct Coking and Various
Synfuels Processes 343
4-42 Technologies Potentially Applicable to the Removal of
Residual Organics from Lurgi-Based Synfuels Plant
Wastewaters 354
4-43 Activated Carbon Adsorption Efficiencies for Wastewater
Similar to those Expected from Synfuels Facilities. . . . 355
4-44 Technologies Potentially Applicable to the Removal of
Dissolved Inorganics from Lurgi-Based Synfuels Plant
Wastewaters 365
4-45 Technologies Potentially Applicable to Wastewater Volume
Reduction of Lurgi-Based Synfuels Plant Wastewaters . . . 372
4-46 Technologies Potentially Applicable to the Disposal of
Residuals from the Treatment of Lurgi-Based Synfuels
Plant Wastewaters 380
xviii
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TABLES (Continued)
Table Pane
4-47 Estimated Removal of Bulk Organics from Gas Liquor by
Solvent Extraction 388
4-48 Estimated Removal of Dissolved Gases from Gas Liquor
by PHOSAM-W 391
4-49 Estimated Removal of Dissolved Organics from Gas Liquor
by Activated Sludge 393
4-50 Estimated Removal of Residual Organics from Gas Liquor by
Activated Carbon Adsorption ... 395
4-51 Estimated Removal of Residual Organics from Gas Liquor
by Thermal Oxidation 397
4-52 Estimated Compositions for use of Treated Gas Liquor as
Cooling Tower Makeup 399
4-53 Estimated Reduction of Gas Liquor Volume by Forced
Evaporation 402
4-54 Estimated Composition of Pretreated Gas Liquor for
Disposal by Deepwell Injection 404
4-55 Estimated Composition of Pretreated Gas Liquor for
Disposal by Surface Impoundment 404
4-56 Estimated Removal of Dissolved Organics from F-T
Synthesis Wastewater by Activated Sludge 408
4-57 Estimated Removal of Residual Organics from F-T Synthesis
Wastewater by Activated Carbon Adsorption 408
4-58 Estimated Material Flows and Compositions - Integrated
Control Example No. 1 415
4-59 Estimated Costs - Control Example No. 1 416
4-60 Estimated Material Flows and Compositions - Integrated
Control Example No. 2 419
4-61 Estimated Costs - Control Example No. 2 420
4-62 Estimated Material Flows and Compositions - Integrated
Control Example No. 3 423
4-63 Estimated Costs - Control Example No. 3 424
4-64 Estimated Material Flows and Compositions - Integrated
Control Example No. 4 426
4-65 Estimated Costs - Control Example No. 4 427
xix
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TABLES (Continued)
Table
4-66 Estimated Material Flows and Compositions - Integrated
Control Example No. 5 430
4-67 Estimated Costs - Control Example No. 5 431
4-68 Estimated Material Flows and Compositions - Integrated
Control Example No. 6 434
4-69 Estimated Costs - Control Example No. 6 435
4-70 Estimated Material Flows and Compositions - Integrated
Control Example No. 7 438
4-71 Estimated Costs - Control Example No. 7 439
4-72 Summary of Solid Waste Streams From Lurgi-Based Indirect
Liquefaction Facilities 450
4-73 Summary of Solid Waste Management Techniques 456
4-74 Site-Specific Factors to be Considered for Terrestrial
Disposal Options 457
4-75 Estimated Treatment/Disposal Cost for Biosludge 479
4-76 Summary of Flow Rates for Spent Catalysts and Sulfur
Guard 481
5-1 Completed and Ongoing Data Acquisition Programs at Coal
Gasification Facilities Sponsored or Co-Sponsored by
the EPA 485
5-2 Data Gaps and Research Needs - Gaseous Medium 490
5-3 Data Gaps and Research Needs - Aqueous Medium 495
5-4 Data Gaps and Research Needs - Solid Wastes 502
5-5 Data Gaps and Research Needs - Products and Byproducts. . 504
xx
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ACRONYMS AND ABBREVIATIONS
ACP Ammonia from Coal Project
ADA Anthraquinone disulfonic acid
ADIP Shell patented diisopropyl amine-based acid gas removal process
AGR Acid gas removal
BOD Biochemical oxygen demand
BFW Boiler feed water
COD Chemical oxygen demand
CW Cooling water
DOE Department of Energy
DOI Department of Interior
EGD Effluent Guidelines Division
EP Extraction Procedure
EPA Environmental Protection Agency
EPRI Electric Power Research Institute
ERDA Energy Research and Development Administration
ESP Electrostatic precipitator
FGD Flue gas desulfurization
F-T Fischer-Tropsch
HF Hydrogen fluoride
HHV Higher Heating Value
kmol kg-mole
KO Knockout
LHV Lower Heating Value
LPG Liquified petroleum gas
MAP Moisture and ash free
NO Nitrogen oxides
NMHC Non-methane hydrocarbons
NPDES National Pollutant Discharge Elimination System
NSPS New Source Performance Standards
OPTS Office of Pesticides and Toxic Substances
OSW Office of Solid Wastes
xxi
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ACRONYMS AND ABBREVIATIONS (Continued)
PCTM Pollution Control Technical Manual
PNA Polynuclear Aromatics
POM Polycyclic organic matter
PSD Prevention of Significant Deterioration
SASOL South African Coal. Oil and Gas Corporation, Ltd.
SCOT Shell Claus Off-Gas Treatment
SNG Substitute Natural Gas
SO Sulfur oxides
x
TGT Tail gas treatment
TOC Total organic carbon
TSP Total suspended particulates
TSS Total suspended solids
TVA Tennessee Valley Authority
VOC Volatile Organic Compounds
W-L Wellman-Lord
xxii
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CONVERSION FACTORS
1.0 kg [kilogram]
1.0 Mg [megagram (metric ton)]
1.0 kg/min [kilogram per minute]
1.0 m3 [cubic meter]
1.0 Nm3/hr [normal cubic meter
(at 273 K) per hour!
1.0 GJ [gigajoule]
1.0 MW [megawatt]
1.0 MT/s [megajoule per second]
1.0 kWh [kilowatt hour!
1.0 MJ/Nm3 [megajoule per
normal cubic meter
(at 273 K)]
1.0 g/Nm3 [gram per normal
cubic meter (at 273 K)l
1.0 kPa [kilopascal]
1.0 kg mole
2.205 Ib [pound (mass)]
1.102 ton [short ton (2000 Ib)]
132.3 Ib/hr [pound per hour]
264.2 gal [gallon]
37.32 scfh [standard cubic feet
(at 60°F) per hour]
0.9479 i 10* Btu [British thermal
unit]
3.413 i 10* Btu/hr [British thermal
unit per hour]
3.413 x 10* Btu/hr [British thermal
unit per hour]
3413 Btu [British thermal unit]
25.40 Btu/scf [Btu per standard cubic
foot (at 60»F)]
0.413 gr/scf [grains per standard
cubic foot (at 60°C)]
0.00987 atmosphere
22.4 Nm3 (32°F)
Prefixes
T = tera = 10a
giga
10'
H
mega = 10*
k = kilo = 10J
Xxiii
-------
ACKNOWLEDGEMENT
Technical and background information for this Pollution Control Technical
Manual was prepared for the Environmental Protection Agency by Radian Corpora-
tion, Austin, Texas, and the Environmental Division, TRW, Inc., Redondo Beach,
California, under contract numbers 68-02-3137 and 68-02-3647, respectively.
The project managers for Radian and TRW were William C. Thomas and Kimm W.
Crawford, respectively.
xxiv
-------
SECTION 1
INTRODUCTION
Future U.S. energy production envisions the development of an environ-
mentally acceptable synthetic fuels industry. As part of this overall effort,
the Environmental Protection Agency (EPA), Office of Research and Development,
has for the past several years undertaken extensive studies to determine syn-
thetic fuel plant waste stream characteristics and potentially applicable pol-
lution control systems.
The purpose of the Pollution Control Technical Manuals (PCTMs) is to con-
vey, in a summarized and readily useful manner, information on synfuel waste
stream characteristics and pollution control technology as obtained from stud-
ies by EPA and others. The documents provide waste stream characterization
data and describe a wide variety of pollution controls in terms of estimated
performance, cost, and reliability. The PCTMs contain no legally binding
requirements, no regulatory guidance, and include no preference for process
technologies or controls. Nothing within these documents binds a facility to
accepting the example emission control process(es) in the service(s) indicated
nor relieves a facility from compliance with existing or future environmental
regulations or permits.
The Pollution Control Technical Manuals consist of several discrete docu-
ments. There are six process-specific PCTMs and a more general appendix
volume which describes over fifty pollution control technologies. Application
of pollution controls to a particular synfuel process is described in each
process specific manual. These volumes are:
Pollution Control Technical Manual for Lurgi-Based Indirect
Coal Liquefaction and SNG
Pollution Control Technical Manual for Koppers-Totzek-Based Indirect
Coal Liquefaction
-------
Section 1
Introduction
Pollution Control Technical Manual for Exxon Donor-Solvent Direct
Coal Liquefaction
Pollution Control Technical Manual for Lurgi Oil Shale Retorting
with Open Pit Mining
Pollution Control Technical Manual for Modified In Situ Oil Shale
Retorting Combined with Lurgi Surface Retorting
Pollution Control Technical Manual for TOSCO II Oil Shale Retorting
with Underground Mining
Control Technology Appendices For Pollution Control Technical
Manuals
By focusing on specific process technologies, the PCTMs attempt to be as
definitive as possible on waste stream characteristics and control technology
applications. This focus does not imply any EPA recommendations for particu-
lar process or control designs. Those described in the manuals are intended
as representative examples of processes and control technologies that might be
used. The organization of the PCTMs from process description through waste
stream characterization and control technology evaluation provides the user
with a number of alternative approaches to understanding the environmental
consequences in operating synthetic fuel plants.
Control technology configurations presented in the PCTMs reflect pollu-
tant removal levels which are believed to be achievable with currently avail-
able control technologies based upon existing data. Since there are no domes-
tic commercial scale synfuels facilities, the data base supporting this docu-
ment is from bench- and pilot-scale synfuel facilities, developer's estimates,
engineering analyses, analogue domestic industries, and non-U.S. commercial
synfuel plants. As commercial synthetic fuel plants are built, the EPA will
continue conducting research in order to develop a more comprehensive data
base. In the interim, the Agency encourages facility planners, permit offi-
cials, and other interested parties to take advantage of, and interact with
EPA to improve, the information contained in these documents.
-------
Section 1
Introduction
1.1 TECHNOLOGY OVERVIEW
This specific PCTM addresses coal-based synthetic fuels facilities using
dry ash Lnrgi gasifiers to generate a raw synthesis process feed gas. The
basic sequence of process steps necessary to produce synthetic gaseous and/or
liquid fuels from coal using dry ash Lurgi gasifiers is as follows.
Coal is prepared to gasifier feed specifications and gasified. The raw
synthesis gas from the gasifier is quenched and upgraded for synthesis by dust
removal, shift conversion, and acid gas removal. The purified synthesis gas
is then converted into crude gaseous/liquid products which can either be used
directly as fuels or further refined. Product synthesis technologies examined
in this document include: methanation to produce substitute natural gas (SNG),
methanol synthesis, Mobil M-gasoline synthesis from methanol, and Fischer-
Tropsch (F-T) synthesis. Significant auxiliary processes required to support
a facility of this type are those required for steam and power generation,
oxygen production, raw water treatment, and process cooling.
The dry ash Lurgi process is a commercially viable process which has been
widely used outside the U.S. to produce industrial fuel gas and synthesis gas
from coal. However, of those foreign facilities, only those operated by the
South African Coal, Oil, and Gas Corp., Ltd. (SASOL) are representative of the
completely integrated facilities (i.e., coal gasification and product
synthesis) addressed in this document. The SASOL facilities produce a wide
range of crude and refined liquid products utilizing Fischer-Tropsch technol-
ogy as the primary product synthesis step.
To date, the Lurgi gasifier has been used primarily to gasify low rank
coals. The technology has demonstrated the capability to handle highly caking
coals such as those used during the trials of American coals at Westfield,
-------
Section 1
Introduction
Scotland (1) and at SASOL, where a Kentucky No. 9 coal was gasified (2).
Companion technologies have also been developed for gas cooling/heat recovery,
gas liquor treatment, acid gas removal, and byproduct (tar, oil, naphtha,
phenol, and ammonia) recovery. The methanol and F-T synthesis processes have
been commercially applied for the production of liquids from coal-derived
synthesis gases. The methanation and Mobil processes, although yet to be
commercially demonstrated on coal-derived synthesis gases, have been operated
on a pilot scale and are considered ready for commercial application.
1.2 APPROACH TO MANUAL DEVELOPMENT
1.2.1 Base Plant Definition
In order to define the process operations and waste streams associated
with representative Lnrgi-based synthetic fuels facilities, a series of uncon-
trolled base plants were defined. These base plants incorporate many of the
features seen in the Lnrgi-based plants which are either proposed, under
construction, or in operation. In this context, an uncontrolled base plant is
one which has full production capability (all of the equipment required to
produce saleable products) but no equipment to control pollutant discharges.
Auxiliary processes included in the base plant were those that could render a
facility essentially self-sufficient in energy; i.e., one requiring only run-
of-mine coal, raw water, and various chemicals and catalysts as inputs. Three
different coals (Montana Rosebud subbituminous, Illinois No. 6 bituminous, and
Dunn County, North Dakota lignite) were examined as feeds to these facilities.
These feeds represent different ranks of coals with various heating values and
moisture, sulfur, and ash contents. Using these coals, the expected range of
uncontrolled (i.e., base plant) waste streams for which treatment and/or
disposal could be considered, were estimated.
-------
Section 1
Introduction
A base plant size corresponding to the production of approximately 120
XT/day of clean synthesis gas was selected as representative of the sizes of
the modules of the first plants that may be built. The energy output rate
(after synthesis) of a plant of this size is approximately equivalent to the
energy content of 20,000 bbls/day of gasoline. Using various data sources
(discussed below), material flows and energy usages were estimated for all
base plant feedstock/synthesis process combinations.
Uncontrolled waste stream characteristics were estimated using overall
material balance calculations and available compositional data from bench-,
pilot-, and commercial-scale facilities based on similar technologies. The
reader should recognize that Lurgi-based facilities built in the U.S. may
contain design features that will result in different uncontrolled waste
stream characteristics. Therefore, users of this manual should carefully
consider the design features of a particular facility before making judgements
concerning uncontrolled waste stream composition and the applicability and
performance of candidate control technologies for these streams.
The use of the base plant concept in this manual is not intended to imply
that facilities would be designed for U.S. sites without controls. In fact,
proposed designs have generally addressed these uncontrolled waste streams
(which are pollution control inlet streams) with control techniques. In
addition, control equipment is not generally designed as an "end of pipe"
technique. Process and control equipment would usually be designed in an
integrated fashion for a specific site in order to obtain cost-effective,
environmentally-responsive facilities. The non-site-specific base plant
concept is used in this manual to facilitate the presentation of data for
waste stream characteristics and candidate control techniques, and to make the
information more generally applicable.
-------
Section 1
Introduction
1.2.2 Control Technology Evaluation
Pollution control technology information is presented in three ways in
each process-specific PCTM. First, available pollution controls are identi-
fied and information on their operating principles, performance capabilities,
reliability, and costs are presented. The information presented is intended
to provide insight concerning factors that impact the application of each
control technique to the types of waste streams generated by the subject
synfuel technology. The second presentation of pollution control information
focuses on the application of example controls to specific waste streams.
This information is intended to provide insight concerning factors associated
with a specific waste stream that impact the application of each control
technique to that waste stream. The third type of pollution control informa-
tion is a presentation of integrated control systems for individual streams',
or combinations of streams. The integrated control systems are intended to be
illustrative examples of the overall performance and costs of pollution con-
trols for selected waste streams.
Since very limited data on the performance of pollution controls are
available from actual operating synthetic fuels plants, many assumptions were
made to extrapolate the experience gained with controls in related industries.
These assumptions have been carefully documented in the appropriate sections
of this manual. Waste streams resulting from pollution control processes
(secondary waste streams) and controls for those streams were also identified.
Cost estimates for all controls were developed based upon published data and
vendor-supplied estimates. These data were extrapolated to the first quarter
of 1980 to provide a consistent basis for comparing the relative costs of
alternate controls. Base (uncontrolled) plant costs were extrapolated in a
similar manner. This allowed the impacts of pollution control costs upon
total facility costs to be estimated.
-------
Section 1
Introduction
Users of this PCTM should recognize that there are two very significant
limitations associated with the use of the data presented.
• First, no fully integrated, well controlled commercial
plants of the type discussed in this manual have been
constructed to date. Thus, in using the data base pre-
sented here, users are cautioned to take careful note of
the documented limitations in the data and assumptions
made to resolve apparent differences in data obtained from
test facilities having widely differing feedstocks,
designs, operating characteristics, and site specific con-
straints .
• Second, this manual does not attempt to address all of the
issues that will arise in the selection and design of
environmental control systems for new synthetic fuels
facilities. Streams that are covered by existing source-
based regulations or that are similar to waste streams
routinely encountered in other industries for which regu-
latory precedents already exist, are recognized but not
treated in depth.
It should be noted that this PCTM focuses primarily on controls for point
and fugitive sources of pollution and not on the ambient impacts of those
waste streams. In addition, this manual does not address issues related to
coal mining and transportation, worker health and safety, noise, socioeco-
nomic, or ecological impacts.
1.3 DATA BASE
Since the early 1970s, the EPA has sponsored a significant environmental
assessment program addressing technologies for producing synthetic fuels from
coal. This work has involved a combination of theoretical studies and plant
data acquisition programs. These efforts have contributed to both the data
and background knowledge used in the development of this manual. Table 1-1
-------
TABLE 1-1 . COMPLETED AND ONGOING DATA ACQUISITION PROGRAMS AT COAL
GASIFICATION FACILITIES SPONSORED OR CO-SPONSORED BY THE EPA
00
Facility
Information Classlfication
Coil Used
Medium/Huh Btu Gulf icitlon acd Indirect
Liquefaction Facilities (Foreian)
• Lurgi or Lnr jt-Type Gulf lotion
- Koaovo, Yugoslavia
- SASOL, S.A.
- leltfllld, Scotlind
• Copper s-Totxek Gasification
- Nodderfonteln, S.A.
- Ptolemaia, Greece
- Cutehya, Turkey
• tinkler Gaalfication
- Kntahya, Turkey
• Texaco Gaeificetion
- Federal Republic of Geraany
Oailf tcition Facilities (U.S.)
• Wellman Galueha
- Site No. 1
- Site No. 2
• Chepman/filputte
• Rlley
• Stoic (Potter fheeler)
Control Research Facilitiea
• RaWAcld Gaa Cleanup
(Floldlied Bed Gi.ifier)
• laatewater Treatability Studlei
• Pollutant Identification
(Bench Scale Gaaifier)
• Aah Leaching ETalnationa
Other Domestic Facilitiea
Data acquisition Li|nite
Plant rlslt and discussions Low rank bituminous
Plant viait and diacnaaions Various
Data acquisition Bi|h TO! . *B* bituailnons
Data acquisition (TVA S EPA) Bituminous
Plant visit and discnssions Lifnite
Plant Tlalt and diacnaalona Lignite
Data acquisition (EPRI, TVA, * EPA) 111. No. 6 bitulnons
Data acqniaitlon Anthracite
Data acquisition Liinlte
Data acqnlaition Lo» sulfur bitmainona
Data acqnialtion Lignite
Data acqnlaition (DOE A EPA) leatern bituminous
North Carolina State University Various
University of North Carolina Various
Research Triangle Institute Various
University of Illinois Various
Products
Medina Btu fas
Variona via indirect
liquefaction
Teat center
Aauionia
Anon is
Aumonia
Aaunonia
Test center
Fuel fas
Teat center
Fuel |as
Test center
Fnel fas
Teat center
Teat center
Teat center
Teat center
e Teiaco Gaaifieation
- Aaunonia from coal plant. TVA
• Rectiaol Acid Gaa Cleannp
Data acqniaition
Texaco, Wilmington, California
Bituminous
Oil partial oxidation
Ammonia
Proceaa hydrogen
-------
Section 1
Introduction
lists the major contributing data acquisition programs sponsored or cospon-
sored by the EPA. As indicated, the data encompass specific research pro-
jects, pilot-level sampling and analysis projects, and source sampling of
foreign and domestic commercial production facilities.
Data sources employed for the development of base plant/process configu-
rations were primarily engineering studies sponsored by DOE and EPA. The
major sources of data used to define the types and characteristics of uncon-
trolled synthetic fuels facility waste streams were 1) an EPA-sponsored test
program of a Lurgi-type gasification facility in the Kosovo region of
Yugoslavia (3), 2) an Energy Research and Development Administration (now the
Department of Energy [DOE])-sponsored program involving the gasification of
American coals in a Lurgi gasifier at Westfield, Scotland (1), 3) SASOL plant
test data provided to EPA by SASOL (4), 4) a DOE-sponsored gasoline-from-coal
research study conducted by the Mobil Research and Development Corporation
(5), and 5) various permit filings and environmental impact statements for
proposed U.S. Lurgi-based SNG facilities (6,7,8).
Data sources that served as the basis for the analysis of pollution
control applicability and costs include the above engineering studies, studies
conducted by the Tennessee Valley Authority (TVA), various permit filings, and
technical information obtained from pollution control equipment vendors,
process developers, and published literature sources. In addition, data were
derived from applications of candidate controls in related industries such as
the petroleum refining, natural gas processing, byproduct coking, electric
utility, and coal preparation industries. Section 4 of this manual and the
PCTM-Pollution Control Technology Appendices identify the sources of data
used.
-------
Section 1
Introduction
1.4 MANUAL ORGANIZATION AND UTILIZATION
1.4.1 Manual Organization
This Pollution Control Technical Manual is presented in six sections and
five Appendices. Following this introductory section are:
Section 2 An overview of the operations and auxiliary processes
(base plants) addressed in this manual.
Section 3 A description of the sources and characteristics of the
waste streams generated by the operations and auxiliary
processes.
Section 4 An analysis of the performance capabilities and costs of
potentially applicable pollution control processes
including controls for those waste streams generated by
the control processes themselves.
Section 5 A summary of the quality of the data base used for waste
stream characterizations and control technology
analysis.
Section 6 A listing of references for Sections 1 through 5.
Details relating to the assumptions and bases used to calculate the estimated
base plant material flows and costs are presented in Appendices A through E of
this volume. Detailed discussions of pollution control processes presented in
Section 4 can be found in the Control Technology Appendices for Pollution
Control Technical Manuals, a separate volume.
Section 2 will be most useful to readers seeking general, summary-type
knowledge of the characteristics of the process technologies which this manual
addresses. Detailed information about the characteristics of the technologies
and specific uncontrolled waste streams is presented in Section 3. This sec-
tion also describes how the characteristics of those streams are likely to be
10
-------
Section 1
Introduction
impacted by differences in coal feed characteristics, process design features,
and plant operating characteristics. In light of the intended use of this
manual. Section 4 is probably the most important; it presents estimates
of the performance capabilities and costs of controls which have been or could
be proposed for use in the subject facilities. Users of information presented
in Sections 3 and 4 should take careful note of the data limitations and addi-
tional data needs summaries presented in Section 5. These summaries are
presented to give users of this manual insight concerning the quality of the
data used to estimate both uncontrolled base plant waste stream characteris-
tics and control equipment performance capabilities and costs.
1.4.2 Manual Utilization
This manual can be used to satisfy a variety of needs. Some users will
be interested in the entire contents of the manual, while others will be
interested only in obtaining information on one specific waste stream or
pollution control process. To aid those users interested in only a part of
the information contained in this PCTM or those whose most pressing needs are
for information on a specific waste stream or control technique, a brief
description of how to find certain types of information within this manual is
provided below.
Descriptions of the Lurgi-based synfuels facilities (base plants)
addressed in this PCTM are presented in Section 3, where they are subdivided
according to the various operations and auxiliary processes found in the
facilities, i.e., coal preparation, Lurgi gasification, gas purification and
upgrading, etc. The uncontrolled waste streams generated by each of these
operations are identified, quantified, and characterized along with the
11
-------
Section 1
Introduction
description of the operations. Thus, a user interested in a particular opera-
tion: Lnrgi gasification, for example, should turn to Section 3.2 - Lurgi
Gasification - to find a summary of the available information on the Lurgi
gasification process and the waste streams it produces.
Pollution control equipment performance and cost information is presented
in Section 4, organized according to the characteristics of the waste stream
being treated. For example, Section 4.1 (Gaseous Medium) presents information
on those air pollution control processes which are candidates for use in first
generation Lurgi-based synthetic fuels plants. Within Section 4.1 subsections
provide brief control technology descriptions and present general performance,
secondary waste stream, and costs for air pollution controls applicable to the
treatment of several categories of gaseous waste streams.
Following the general descriptions of control technologies for each waste
stream category in Section 4.1 are specific discussions of the performance,
secondary waste streams, and costs associated with the applications of example
candidate control techniques to specific gaseous waste streams in that cate-
gory. For example. Section 4.1.1.1 discusses the capabilities and costs of
specific control processes applied to HaS-rich Acid Gases. Following all of
the waste stream category discussions are illustrative examples of potential
integrated control schemes (i.e., multiple control techniques used in series)
for those streams or combinations of streams which would normally use more
than a single control (due to multiple pollutant loadings or other reasons).
Similar types of information are presented for water pollution controls and
solid waste management techniques in Sections 4.2 and 4.3, respectively.
Additional "how to use" information is presented at the beginning of Section 4
as well as at the beginning of Subsections 4.1, 4.2, and 4.3.
12
-------
Section 1
Introduction
To aid users in finding information on both the characteristics of an un-
controlled waste stream and the available pollution controls for that stream,
a cross reference index is provided at the end of Section 3 (Table 3-50).
This table lists 1) all of the uncontrolled base plant waste streams and
indicates the subsection in Section 3 that contains detailed characterization
data for each stream and 2) the subsections in Section 4 that contain informa-
tion on potentially applicable pollution controls for each stream. Thus, a
user interested in a particular waste stream could refer to Table 3-50 and
find out which parts of Sections 3 and 4 address that waste stream. Table 3-
51, also at the end of Section 3, provides similar information on the pollu-
tion controls discussed in Section 4, the secondary waste stream(s) generated
by those controls, and available controls for the secondary waste stream(s).
Section 5 provides a discussion of the data gaps and limitations asso-
ciated with the data base used in the preparation of this manual. These gaps
include both waste stream characterization and pollution control performance
and cost data. Users of the manual are encouraged to refer to this section
for insight into the quality of the information evaluated in Sections 3 and 4.
13
-------
SECTION 2
PROCESS OVERVIEW
This section presents a brief description of the operations and non-
pollution control auxiliary processes expected to be included in Lnrgi-based
indirect liquefaction and substitute natural gas (SNG) facilities. It also
identifies the major waste streams associated with those operations and pro-
cesses. In this context, waste stream refers to the uncontrolled wastes
generated, i.e., before the application of any pollution control device. It
should be noted that many of these waste streams are routinely routed to pol-
lution control systems in Lurgi-based plants. As such, the waste streams
identified should not necessarily be construed as discharge streams.
The operations and processes described in this section comprise what is
called an "uncontrolled base plant" or "base plant" in that they are all
required to produce marketable products and byproducts. According to this
definition, the "base plant" excludes those processes whose primary function
is to treat waste streams to render them suitable for discharge or reuse with-
in the plant. The use of the base plant concept in this manual is not
intended to imply that facilities would be designed for U.S. sites without
controls. In fact, proposed designs have generally addressed the uncontrolled
waste streams (which are pollution control inlet streams) with control tech-
niques. In addition, control equipment is not generally designed as an "end
of pipe" technique. Process and control equipment would usually be designed
in an integrated fashion for a specific site in order to obtain cost-
effective, environmentally-responsive facilities. The non-site-specific base
plant concept is used in this manual to facilitate the presentation of data
for waste stream characteristics and candidate control techniques, and to make
the information more generally applicable.
14
-------
Section 2
Process Overview
Base plant operations discussed here include coal preparation, coal gasi-
fication, gas purification and upgrading, crude product synthesis and separa-
tion, and product upgrading. Auxiliary processes discussed include steam and
power generation, process cooling, product storage, raw water treatment, and
oxygen production. Base plant capital investment and operating costs are also
summarized.
Figure 2-1 presents a simplified block diagram of a synthesis gas produc-
tion facility utilizing oxygen-blown dry ash Lurgi gasifiers. The processes
associated with the synthesis and purification of SN6, Fischer-Tropsch liq-
uids, methanol, and gasoline-range hydrocarbons via the Mobil M process are
shown in Figure 2-2. These base plant flow schemes are based upon published
conceptual designs (5,6,8) and are believed to be representative of the first
generation of Lurgi-based indirect liquefaction and SNG facilities that will
be built in the U.S.
15
-------
Run-of-Mine
Coal
Coal
Preparation
Sized
Coal
Acid Gases
Lurgi
Gasification
Raw
Lurgi
Ris
Quenching,
Shift Conversion)
Quenched
Lurgi
Gas
Acid Gas
Remov a 1
Sulfur
Guard
.Sulfur-Free
Synthesis Gas
Gasifier
Ash
Process
Condensates
(Gas Liquor)
Figure 2-1. Simplified block flow diagram of a Lurgi-based
synthesis gas production facility
-------
Sulfur-free J
Synthesis \
Gas ]
'
—^
-O
\
Metbanation
Fischer-Tropsch
Synthesis
Methanol
Synthesis
Methanol
Synthesis
Compression
and
Dehydration
Product
Separation
and
Upgrading
Product
Separation
and
Upgrading
Mobil
M-Gasoline
Synthesis
SNG
j_ F-T Synthesis
Products*
^ Methanol
Synthesis
Products*
Product
_ Separation
and
Upgrading
Mobil
M-Gasoline
*~ Synthesis
Products*
•includes SNG coproduct
Figure 2-2. Simplified block flow diagram for conversion
of synthesis gas to SNG or liquid fuels
-------
Section 2
Feed/Prod. Character.
2.1 COAL FEED CHARACTERISTICS AND PRODUCT SLATES
A wide variety of domestic coals are potential feedstocks for Lorgi-based
synthetic fuels facilities. Each coal will have associated with its use a
specific set of process and waste stream characteristics. Three types of
coals were chosen for examination in this PCTM to illustrate the effects that
different coal types will have on waste stream generation rates, compositions,
and ultimately waste stream treatment options and costs. These coals include
a western subbituminous coal (Montana Rosebud), a Midwestern bituminous coal
(Illinois No. 6), and a lignite (Dunn County, North Dakota). These coals were
chosen to allow calculations of base plant material flows and uncontrolled
waste stream flow rates. The coals chosen represent the major classes of
coals in the U.S. They also reflect a range of coal rank and moisture, ash,
and sulfur contents, which are the major coal characteristics influencing
waste stream characteristics. Further, all three coals have been gasified in
Lurgi gasifiers. Hence, some data are available which can be used in cal-
culating base plant material flows and identifying waste stream characteris-
tics. All base plants were assumed to be mine-mouth, i.e., they are located
near the coal sources in Montana, Illinois, and North Dakota. Table 2-1 pre-
sents data on the characteristics of these coals.
In developing the base plant material balances, a nominal plant capacity
of 120 TJ (the energy equivalent of about 20,000 barrels of gasoline) per day
of synthesis gas was used. Due to differences in the feed coal characteris-
tics, varying amounts of coal (in terms of both mass and energy content) are
required as feed to the Lurgi gasifiers to produce this quantity of synthesis
gas. The estimated base plant gasifier coal requirements are summarized
as follows:
Estimated Coal Subbituminous Bituminous Lignite
Requirements (Montana Rosebud) (Illinois No. 6) (Dunn County. ND)
Mg per day
TJ per day
18
7110
142
5800
155
9,590
143
-------
TABLE 2-1. PROXIHATE AND ULTIMATE ANALYSES OF BASE PLANT COALS
Composition
Subbituminous
(Montana Rosebud)
Bituminous
(Illinois No.6)J
Lignite
(Dunn County, ND)
Proximate Analysis, vt %
Moisture
Volatile Matter
Fixed Carbon
Ash
Higher Heating Value, MJ/kg
Ultimate Analysis, wt % (dry
Carbon
Hydrogen
Nitrogen
Sulfur
Chloride
Ash
Oxygen (by difference)
24.7
29.2
36.4
9.7
20.0
basis)
67.2
4.2
1.2
1.5
<0.1
12.9
13.0
10.2
34.7
46.0
9.1
26.6
71.5
4.8
1.4
3.1
0.1
10.1
9.0
38.6
27.0
27.6
6.8
15.0
63.6
4.4
0.6
1.3
0.1
11.1
18.9
From data contained in Reference 1.
From data contained in Reference 9.
-------
Section 2
Feed/Prod. Character.
In addition to the gasifier coal requirements, most Lurgi-based synfuels
facilities are expected to include onsite coal-fired auxiliary boilers. The
size, and hence fuel requirements, of these boilers will depend on a variety
of factors, including:
• whether the facility's power requirements are satisfied by
purchasing power or by onsite generation,
• the design of the facility's waste energy recovery system,
• the characteristics of the coal being gasified, i.e., the
gasifier steam and oxygen requirements,
• whether Lurgi liquid byproducts and high energy content waste
gases are used as boiler fuel, and
• the planned disposition of excess coal fines.
Due to the large number of variables that can affect the auxiliary boiler coal
requirements, it is difficult to estimate the quantity of boiler coal required
for each type of synfuels plant examined in this PCTH. In general, auxiliary
boiler energy requirements are expected to range from about 15 to 30 percent
of the coal energy input to the gasifier (5,8,10).
Table 2-2 lists typical upgraded product slates for the Lurgi-based syn-
fuels plants examined in this PCTM. It should be noted that large quantities
of methane are present in Lurgi synthesis gas. For reasons which are dis-
cussed in Section 2.2.4, it is assumed that this methane would be recovered as
a coproduct SNG in those facilities producing synthetic liquid fuels rather
than reformed to produce additional synthesis gas.
As indicated in Table 2-2, the total energy content of the products from
each type of plant varies, even though the same quantity of synthesis gas
(nominally 120 TT per day) is assumed in all cases. This is a reflection of
the different energy conversion efficiencies and product slates associated
with the four different synthesis operations examined.
20
-------
TABLE 2-2. TYPICAL UPGRADED PRODUCT SLATES FOR LURGI-BASED SYNTHETIC FUELS FACILITIES
Methanol Mobil
Product SNG Synthesis Synthesis M-Gasoline Fischer-Tropsch
SNG 100 54 55 65
C, LPG - 2 2
C4 LPG - - 3 <1
Methanol - 49 -
Gasoline - - 37
Diesel Oil - - -
Heavy Fuel Oil - -
Mixed Alcohols - - -
TOTAL PRODUCTS 100 103 97
—
22
4
1
_3
97
Note: All units are TJ/day. Product slates shown are based on gasifying 142 TJ/day of
Rosebud subbiluminous coal to produce a synthesis gas feed of approximately 120
TJ/day. In addition to the indicated products, the following quantities of
byproducts are produced regardless of synthesis process: Naphtha - 2.0 TJ/day;
Tars - 5.5 TJ/day; Oils - 5.9 TJ/day; and Phenols - 1.1 TJ/day. Similar quanti-
ties of products and byproducts result from use of the other coals examined in
this PCTM (See Appendix E).
-------
Section 2
Feed/Prod. Character.
It should be noted that the information presented in Table 2-2 is not
necessarily reflective of the relative overall energy conversion efficiencies
for the four types of plants. The information shown is for gasification of a
given quantity of coal (142 TJ/day for the Rosebud subbituminons coal cases
shown) and hence indicates the coal-gasified-to-products efficiency. Overall
energy conversion efficiencies include the coal energy required to fuel the
auxiliary boiler. Since these quantities will vary among synthesis plants
(even for a given coal feed), the relative overall plant efficiencies may be
different from the relative coal-gasified-to-products efficiencies.
22
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Section 2
Base Plant
2.2 BASE PLANT DESCRIPTION
2.2.1 Coal Preparation
The coal preparation operation in a Lurgi-based synfnels facility will be
similar to those found in other coal-based plants such as coal-fired power
plants. Equipment is provided to receive, transport, and store coal and to
prepare a sized coal feed for the Lurgi gasifiers and a pulverized coal feed
for onsite coal-fired steam boilers.
Run-of-mine (RON) coal received by conveyor, unit train, barge, or truck
is diverted to either an active or inactive (emergency) storage pile as neces-
sary. Coal from storage is transported by a belt conveyor to the preparation
plant where it is screened and crushed to a 3.8 cm top size. A 3.8 cm x 0.64
cm coal fraction is separated and conveyed to the gasifier feed storage silos.
(Depending on the properties of the coal, a sized coal within the range of 0.3
cm to 7.5 cm can be gasified; the 3.8 cm x 0.64 cm range shown is merely a
representative example.) The undersize coal is stored in separate fine coal
storage silos. As required to meet the auxiliary steam boiler fuel require-
ments, coal is removed from the fine coal storage silos and pulverized to
nominally 70 percent through 200 mesh. Excess undersized coal may or may not
be produced depending on the feed coal characteristics. If excess undersized
coal is produced, it could be used to generate export power, gasified in a
reactor capable of handling coal fines to produce additional synthesis gas,
sold as a byproduct, or disposed of as a solid waste. A potential, but
currently undemonstrated, alternative is to pelletize the undersized coal to a
nominal 3.8 cm size for use as Lurgi gasifier feed.
The major waste streams associated with the coal preparation operation
are ROM storage pile runoff, fugitive dust emissions from prepared coal stor-
age and conveying, and dust from coal crushing and screening. Runoff from ROM
23
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Section 2
Base Plant
coal storage tends to contain high levels of suspended and dissolved solids
and can be quite acidic in the case of Midwestern or Eastern coals. Dust from
coal preparation consists of natural soil and overburden material as well as
coal.
2.2.2 Lurgi Coal Gasification
The dry ash Lurgi gasifier is a medium pressure (2.1 to 3.2 MPa), moving
bed gasifier operating below the coal ash fusion temperature. Essentially all
types of coals with moisture contents below about 40 percent can be gasified,
although strongly caking coals require the use of a coal distributor equipped
with a stirrer. In recent tests, gasifying a medium caking coal (free swel-
ling index of 4.5) in a modified (coal distributor with stirrer) Mark IV Lurgi
gasifier resulted in 10 to 25 percent reduction in throughput rates (2). The
gasifier unit consists of a coal lockhopper, a water-jacketed pressurized
gasifier vessel, an ash lockhopper, and an ash quench system.
Sized coal is stored in a coal hopper directly above the gasifier and is
fed to the gasifier via a coal lockhopper. Cooled or raw Lurgi gas or an
inert gas such as C02 or Na can be used as the lockhopper pressurant gas.
As the coal descends through the gasifier countercurrent to gas flow, it
passes through "zones" of progressively higher temperatures which provide for
drying, devolatilization, gasification, and combustion. A revolving grate at
the bottom of the gasifier supports the ash/coal bed, provides for a uniform
flow of ash to the ash lockhopper, and distributes steam and high purity oxy-
gen uniformly across the bottom of the downward moving coal bed. The ash
lockhopper allows for discharge of the ash into the ash quench system.
Quenched ash is transported as a wet solid or water slurry to a clarification
and solids handling system.
The hot crude gas leaving the gasifier is composed primarily of hydrogen,
carbon monoxide, carbon dioxide, methane, and unreacted steam. Also present
24
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Section 2
Base Plant
are high molecular weight organics (e.g., tars, oils, phenols), reduced sulfur
and nitrogen compounds (e.g., HaS, COS, mercaptans, NH,, HCN), low molecular
weight hydrocarbons (e.g., Cas-C5s, benzene, toluene), and entrained coal
dust. Waste streams generated by the gasification operation include coal
lockhopper vent gases, ash lockhopper vent gases, gasifier ash, ash quench
blowdown, and transient waste gases (e.g., startup gases).
The composition of the coal lockhopper vent gases reflects the character-
istics of both the raw Lurgi gas and the lock pressurant gas. When Lurgi
gases are used for lock pressurization, the lock vent gases are similar in
composition to the Lurgi gases and contain organics and volatile sulfur- and
nitrogen-containing compounds. Coal lockhopper vent gases may also contain
entrained particulates consisting of coal particles and tarry hydrocarbon
materials. When C02 or Na is used for lock pressnrization, a flow of pres-
surizing gas into and through the lockhopper is maintained in order to mini-
mize, or possibly eliminate, the backflow of raw gas. As a result, the lock-
hopper gases will consist almost entirely of the pressurization gas, e.g.,
Nj or C02. Transient gases generated during gasifier startup, shutdown, and
upset conditions contain the same types of substances as coal lockhopper gases
do when Lurgi gases are used as the lockhopper pressurant.
Ash from the Lurgi gasifier is similar to ash from coal combustion in
that it consists almost entirely of mineral matter originally present in the
coal. However, gasifier ash will have somewhat higher levels of residual
carbon. Ash lockhopper vent gases consist primarily of steam with some
entrained particulate matter (ash fines). Ash quench blowdown is similar to
bottom ash quench blowdown from coal combustion in that it contains high
levels of suspended solids (mainly ash particles) and dissolved solids. The
pH of the blowdown depends mainly on the chemical (i.e., leaching) charac-
teristics of the gasifier ash.
25
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Section 2
Base Plant
2.2.3 Gas Purification and Upgrading
The gas purification and upgrading operation consists of 1) gas cooling
and quenching to reduce the gas temperature for subsequent processing and to
remove condensible organics, moisture, entrained particulates, and water-
soluble inorganics; 2) shift conversion, if necessary, to obtain the required
ratio of H2 to CO for product synthesis; 3) acid gas treatment for removal of
C02 and reduced sulfur compounds; and 4) removal of trace sulfur compounds
using "sulfur guards".
During purification and upgrading of raw Lurgi gases, most of the impuri-
ties removed from the gas become components of waste streams. Thus, the gas
purification and upgrading operation generates some of the most important
waste streams in an integrated Lurgi-based synfuels facility from the stand-
point of volume and pollutant concentrations.
Gas Cooling and Dust/Heavy Organics Removal
Raw Lurgi gas is cooled in stages with some heat recovery via steam gen-
eration. Initial cooling is carried out in a "wash cooler". Gas from the
wash cooler is further cooled in a waste heat boiler which produces medium
pressure steam. Moisture and heavy organics such as tars, oils, and phenols
are condensed as the raw gas is cooled, producing a gas liquor stream which is
routed to the gas liquor separation unit. The gas liquor also contains solu-
ble gaseous species such as ammonia, sulfides, cyanides, and carbon dioxide.
In the gas liquor separation unit, dissolved gases, tars, and oils are
separated from the water in a depressurization vessel followed by phase separa-
tors. The gas washing process also removes essentially all of the dust
entrained in the raw gas, which subsequently becomes admixed with the tar.
The separated oils and tars are recovered as byproducts which can be used as
onsite fuels, sold as byproducts, gasified in an auxiliary partial oxidation
gasifier to produce additional synthesis gas, or upgraded into materials
26
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Section 2
Base Plant
suitable for blending with other facility products. Dusty tar from the tar
separator can be recycled (to extinction) to the top of the gasifier (2) or
gasified in an auxiliary partial oxidation gasifier to produce additional
synthesis gas. Gas liquor and depressurization gases are the major waste
streams leaving the gas liquor separation unit.
Lurgi gas liquor contains appreciable quantities of dissolved/suspended
organic compounds. Inorganics present are mainly ammonia and bicarbonate,
with smaller amounts of sulfide, sulfite, sulfate, thiocyanate, and cyanide.
This liquor also contains trace elements which were scrubbed from the raw gas
or leached from the entrained coal particles that were scrubbed from the gas.
In general though, Lurgi gas liquor contains low levels of inorganic suspended
and dissolved solids. The quantity of gas liquor generated is determined by
the moisture content of the raw gas, which in turn is a function of the coal
moisture content and the gasifier feed steam-to-coal ratio. In general, as
the quantity of gas liquor generated (per unit of coal gasified) increases,
the pollutant concentrations in the gas liquor decrease.
Shift Conversion
Gases suitable for feed to methanol or hydrocarbon (i.e.. Fisher-Tropsch
or Mobil M-gasoline) synthesis processes should have slightly greater than a
2:1 ratio of hydrogen-to-carbon monoxide and no more than a few percent carbon
dioxide. Depending on the specific coal gasified and/or the degree of C0a
removal obtained in the downstream acid gas removal step, "shifting" of a
portion of the Lurgi gas may be required to obtain the necessary ratio. On
the other hand, methanation to produce SNG requires an Ha-to-COz ratio of at
least 3:1 (3:1 for CO and 4:1 for CO*). Since this ratio is not normally
present in Lnrgi gas, a shift conversion step is necessary.
27
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Section 2
Base Plant
The water-gas shift reaction of carbon monoxide and water vapor to form
hydrogen and carbon dioxide is an exothermic reaction which can be promoted by
a variety of catalysts. For application to Lurgi-based synfuels facilities,
it is desirable to conduct the shift reaction at moderate to high temperatures
(greater than 500 K) for reasons of thermal efficiency. "Sulfided" cobalt
molydate-based catalysts, which are active at temperatures above 500 K, are
not affected by the presence of gaseous sulfur compounds. Cobalt molydate-
based catalysts are also active for the hydrolysis of carbonyl sulfide. HCN
may also be partially hydrogenated to NH3 over the catalyst.
Shift catalysts must be periodically regenerated to remove accumulated
carbon deposits. This is accomplished by controlled oxidation with air to
burn off carbon and reduced sulfur. An offgas is produced containing large
amounts of oxidized sulfur. After a few regeneration cycles, shift catalysts
lose activity due to physical degradation or accumulation of chemical poisons
and must be replaced. Thus, spent shift catalyst and catalyst regeneration/-
decommissioning offgases are the major waste streams from shift conversion.
Acid Gas Removal
The removal of H2S and other sulfur compounds from quenched Lurgi gas is
necessary to prevent catalyst poisoning in subsequent SNG, methanol, Mobil
M-gasoline, and Fischer-Tropsch synthesis operations. The removal of most of
the COX is necessary to obtain a gas composition meeting the stoichiometric
requirements for synthesis feed gas.
All existing Lurgi systems use the Rectisol process for acid gas removal
(A6R). This process is based upon the physical absorption of C02, HaS, COS,
and high molecular weight organic compounds in cold methanol. A Rectisol unit
can be operated in either a nonselective or a selective mode. With non-
selective operation, C0» and sulfur species are removed together and a
single acid gas stream is produced when the methanol is regenerated. With
28
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Section 2
Base Plant
selective operation, both an H,S-rich and a C0a-rich acid gas stream are
produced. Both modes of operation remove high molecular weight hydrocarbons
from the gas stream. The resulting naphtha stream can be used as an onsite
fuel, sold as a byproduct, or upgraded for blending with other facility
products.
Waste streams generated by the Rectisol process include acid gases and
methanol/water still bottoms. In the case of nonselective Rectisol, the acid
gas stream is expected to contain up to 4 percent HaS and 500 to 1500 ppmv
COS plus mercaptans (for the coals considered). In the case of selective
Rectisol, the H2S-rich stream is expected to contain 10 percent or more HaS
and most of the COS plus mercaptans removed from the quenched Lurgi gas, while
the COj-rich acid gas stream should contain less than 100 ppmv total sulfur
compounds (mostly COS). Recent designs of selective Rectisol units in non-
Lurgi applications have indicated levels of 10 ppmv or less of total sulfur
compounds in the COj-rich stream.
Water condensed from the quenched Lurgi gases entering the Rectisol unit
and water added to enhance recovery of the byproduct naphtha leave the
Rectisol unit as methanol/water still bottoms. This stream will contain small
amounts of cyanides, sulfides, ammonia, chlorides, methanol, and other
organics.
Trace Sulfur Removal
To protect synthesis catalysts from sulfur poisoning, zinc oxide guard
beds may be used following the Rectisol process to remove residual traces of
sulfur compounds. Ordinarily, the Rectisol process can attain levels down to
0.1 ppmv total sulfur species in the synthesis feed gas, but ZnO beds would
provide insurance against sulfur species being present in the synthesis feed
29
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Section 2
Base Plant
gas during periods of Rectisol process upsets. Periodically, sulfur guard
material must be decommissioned and replaced. Thus, if sulfur guards are
used, a solid waste consisting of spent ZnO/ZnS is generated.
2.2.4 Product Synthesis
Synthesis of SNG
Methanation of synthesis gases involves the catalytic reaction of the
hydrogen and carbon oxides in the gases to produce methane.
3H2 + CO -> CH4 + HjO + heat
4H, + COz-> CE4 + 2HaO + heat
The resulting product gases have, after dehydration, a composition and higher
heating value comparable to that of natural gas.
The methanation reactions, which are carried out over nickel-based cata-
lysts, are highly exothermic. Reaction temperatures are controlled by recycle
of product gas. Normally a methanation unit consists of two reactors in
series with the bulk of the reaction taking place in the first reactor. Addi-
tional equipment includes heat exchangers, a knockout drum to condense and
remove moisture, and a product recycle gas system. If the SNG is to be trans-
ported via pipelines over long distances, a compression and dehydration unit
(such as a triethylene glycol system) would also be required.
Waste streams from a methanation unit include condensate from the metha-
nation unit, offgases from the dehydration unit, spent catalysts, and cata-
lyst decommissioning offgases. Condensate recovered from the production of
SNG should be sufficiently pure to be reused within the facility, e.g., as
boiler feedwater. However, some dissolved gases will be present and may need
30
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Section 2
Base Plant
to be removed. Spent catalysts will likely be returnable to a vendor for
reclamation of their metal content. Catalyst decommissioning offgases may
contain 00, particulate matter, and possibly Ni(CO>4.
Synthesis of Liquid Fuels
Hethanol synthesis and hydrocarbon production via Fischer- Tropsch (F-T)
synthesis can be represented by the following reactions:
CO + 2H2 -^CHjOH + heat (Methanol Synthesis)
nCO + (2n + 0.5x) H, -> C fl- _,_ + nH.O + heat (F-T Synthesis)
* n zn+x •*
where n ranges from 1 to about 20 and is determined by process operating con-
ditions, x = 2 for paraffins and x = 0 for olefins. Synthesis gas usually
contains some COJ and inerts (e.g., N2, CH4) in addition to CO and Ha.
Because synthesis catalysts are also active for the hydrogenation of C02, the
presence of C0a does not create problems (although it does require larger
quantities of Ha) as long as the synthesis gas contains the proper ratio of
H2/(CO + C0a). Methanol synthesis employs Cu/Zn-based catalysts at 470 K and
3.5 to 7.0 MPa while F-T synthesis proceeds at pressures up to 2.5 MPa over
iron-based catalysts at 590 to 600 K (fluidized bed reactors) or 490 to 530 K
(fixed bed reactors) (5).
Mobil M-gasoline synthesis from methanol can be represented as follows:
nCH.OH -> C H,, + (2n - 0.5x) ELO (Mobil M-Gasoline Synthesis)
* n Zn+x a
This process employs zeolite-based catalysts and operates at about 570 to
680 K and 2.1 MPa (5).
31
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Section 2
Base Plant
The crude liquid fuel products of methanol, F-T, and Mobil M-Gasoline
synthesis processes will require upgrading (probably on site) to yield final
products which are marketable as substitutes for petroleum-derived products.
This is particularly true for motor gasolines, where crude Fischer-Tropsch
gasoline fractions would not meet octane requirements for the retail market in
the U.S. F-T and Mobil M-Gasoline products could be upgraded by HF alkylation
of the Cj-C4 fraction to yield gasoline-blend hydrocarbons and commerical
grade LPG, by hydrotreating (in the F-T case) for destruction of olefins and
oxygenated organics, by catalytic reforming to produce more cyclic and branch-
ed chain hydrocarbons, by C5/C4 isomerization to increase the anti-knock
quality of pentanes and hexanes, and by catalytic polymerization to convert
propene/butene fractions into higher molecular weight gasoline blending com-
pounds. All of these upgrading processes are expected to use currently avail-
able petroleum refinery technology. Waste streams generated during these
upgrading operations are not expected to present any unique treatment prob-
lems. For these reasons and due to the multiplicity of possible options for
product upgrading, waste stream characteristics and pollution control alter-
natives for product upgrading processes are not specifically discussed in this
PCTM.
All of the synthetic liquid fuels synthesis processes generate a purge
gas containing large amounts of methane and unreacted CO and Ha. Several
options are available to handle the purge gas including use as an onsite
fuel, reforming to generate additional synthesis gas, or conversion of the
residual hydrogen and carbon oxides into additional methane to produce SNG.
Because Lurgi-derived synthesis gases initially contain large amounts of
methane and because SNG has considerable market value, the methanation option
was selected for analysis purposes in this PCTM. In actual practice, the
decision regarding the disposition of synthesis purge gases involves site- and
design-specific considerations which are outside the scope of this document.
32
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Section 2
Base Plant
The methanation reactions are the same as those discussed earlier in this sec-
tion on Synthesis of SNG. Following methanation, residual CO, and moisture
are removed, and the byproduct SNG is compressed to pipeline pressure for
distribution.
2.2.5 Auxiliaries
The major auxiliaries required to support Lurgi-based synfuels facilities
are: 1) steam/power boilers, 2) makeup water treatment, 3) process cooling
water, 4) liquid product/byproduct storage, and 5) oxygen production.
The most significant source of waste streams from the auxiliary processes
is the steam/power boiler. The boiler flue gases are particularly important
because the boilers will generally be coal-fired and because of the potential
for using the boilers to combust a wide range of gaseous, liquid, and solid
wastes. Energy-rich streams which are candidates for use as boiler fuels
include coal fines; byproduct tars, oils, phenols, and naphtha; and hydrocarbon-
rich acid gases. In addition to flue gases, waste streams resulting from
boiler operations include boiler blowdown condensates, bottom ashes, and spent
equipment cleaning wastes.
The major waste streams from makeup water treatment are sedimentation
pond sludges, lime/soda softener sludges, and demineralizer regeneration
wastewaters from the boiler feedwater treatment unit. Evaporation, drift, and
cooling tower blowdown are the major waste streams from the cooling water
system.
Storage of synthesis products and Lurgi byproducts is accompanied by
evaporative emissions. These vapors consist primarily of low molecular weight
organic compounds and, in the case of gasolines and Lurgi byproducts, aroma-
tic compounds such as benzene and toluene.
33
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Section 2
Base Plant
Hie oxygen plant itself is not a major source of waste streams. However,
as a major consumer of energy, it impacts the magnitude of the waste streams
produced in other units, particularly in the steam/power generation unit and
the cooling water system.
2.2.6 Fugitive Emissions
There are many potential sources of fugitive emissions in a Lurgi-based
synfuels facility. Examples of these sources are pump and compressor seals,
inline process valves, pressure relief devices, open-ended valves, sampling
connections, flanges, and cooling towers. The characteristics of these poten-
tial emissions are highly dependent on the composition of the fluid being
handled. In general though, volatile organics, reduced sulfur species, and
carbon monoxide are the pollutants expected to be most commonly present. The
quantity of fugitive emissions arising from any source is a function of
several factors. Three of the more important factors are 1) the type of
device (e.g. fugitive emission rates from flanges are different than those
from sampling connections), 2) the composition of the fluid being handled
(e.g. an inline process valve on a pure hydrocarbon stream would have a
higher potential leak rate for volatile organics than a valve on a stream
containing only minor quantities of hydrocarbons), and 3) applied maintenance.
34
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Section 2
Costs
2.3 BASE PLANT CAPITAL INVESTMENT AND ANNUALIZED OPERATING COSTS
In order to provide a basis for evaluating the economic impacts that pol-
lution controls could have on synfuels plant costs, estimates of base plant
capital costs and total annualized operating costs were developed. These
estimates were developed from published economic and engineering studies of
the subject technologies (5,11). Capital costs for pollution controls were
subtracted, to the extent that they could be quantified, from the published
estimates. The resulting uncontrolled capital cost estimates were then
adjusted to a base plant capacity of approximately 120 TT per day of synthesis
gas. Finally, the adjusted base plant costs were escalated to first quarter
1980 dollars using the CE plant cost index.
Capital costs presented in this manual are total depreciable investment
costs. Included in the total depreciable investment costs are 1) installed
equipment costs (including the costs of purchasing and delivering equipment
and the directly related costs of installation such as wiring, piping, labor,
etc.), 2) indirect installation charges (including construction and engineer-
ing costs, contractor fees, and contingency), and 3) interest during con-
struction. Startup costs are not included in the capital costs presented, but
could be a significant additional cost for new technologies such as those
examined in this PCTM. Total annualized costs presented include 1) labor and
maintenance, 2) raw materials, utilities, chemicals, and catalysts, 3) over-
head charges, and 4) capital-related charges (including interest on working
capital, taxes, insurance, and capital recovery). Capital recovery was cal-
culated as 13.7 percent of the total depreciable base plant investment cost.
Details of the methodology, assumptions, and bases used to develop the
base plant capital investment and total annualized operating cost estimates
are presented in Appendix C. A summary of the estimates is presented in Table
2-3.
35
-------
TABLE 2-3. ESTIMATED BASE PLANT COSTSa
Type of Total Depreciable
Synfuel Investment
Facility JlO«
SNG
Methanol
Mobil M
Fischer-Tropsch
810
820
910
980
Total Annual
Subb it ominous coal
(Montana Rosebud)
200
200
220
235
ized Operating Cost
Bituminous coal
(Illinois No. 6)
235
240
255
270
. ilO«/vr
Lignite
(Dunn County, ND)
215
215
235
250
A base plant is one which has all of the equipment necessary to produce saleable
products, but no pollution control equipment. Each base plant produces approximately
120 TJ/day of synthesis gas; this is equivalent to approximately 20,000 barrels/day of
gasoline. All costs are in first quarter 1980 dollars. Details on how these estimates
were developed are presented in Appendix C.
-------
SECTION 3
PROCESS DESCRIPTION AND WASTE STREAM CHARACTERIZATION
This section presents detailed descriptions of the operations and auxil-
iary processes expected to be found in Lurgi-based synthetic fuels facilities.
Along with the process description information is a presentation of character-
ization data (both test and calculated data) for the major process and waste
streams associated with those operations and auxiliaries. Figure 3-1 is a
block flow diagram showing the coal preparation, Lurgi gasification, and gas
purification and upgrading operations. Figures 3-2 through 3-4 are block flow
diagrams for the crude product synthesis and product upgrading operations.
Auxiliary processes are shown in Figure 3-5, and include raw water treatment,
steam and power generation, oxygen production, process cooling water, and
product/byproduct storage.
The process sequences indicated in Figures 3-1 through 3-5 were developed
from information presented in conceptual and proposed designs of Lurgi-based
synfuels facilities (5,6,8). They are believed to be reasonably representa-
tive of the configurations or configuration options which are likely to be in-
corporated into the first Lurgi-based synfuels facilities built in the U.S.
The remainder of this section presents information on the above opera-
tions and auxiliaries and on the characteristics of the waste streams they
generate. In this context, waste stream refers to the uncontrolled wastes
generated, i.e., before the application of any pollution control device. It
should be noted that many of these waste streams are routinely routed to pol-
lution control systems in Lnrgi-based plants. As such, the waste streams
identified should not necessarily be construed as discharge streams.
In addition, some streams identified as waste streams in this manual are
expected to be recycled, reused, and/or further processed for recovery of
valuable constituents. An example of this type of stream is the high pressure
37
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PARTICULATES
00
EXCESS
COAL FINES
PULVERIZED COAL
TO AUXILIARY BOILER
HIGH PRESSURE j CO»L LOCKHOPPEH
) GASES
LOW PRESSURE J
ASH LOCKHOPPER
r ^ GASES
MAKEUP
QUENCH
WATER
CATALYST
REGENERATION/
DECOMMISSIONING
OFF GASES
SULFUR FREE
SYNTHESIS
GAS
LEGEND
NOTES
1) CO2 RICH AND H2S RICH ACID GASEs
GENERATED BY SELECTIVE AGR ONLY
2) TRACE SULFUR REMOVAL GENERALLY
IS NOT REQUIRED BEHIND RECTISOL
ACID GAS REMOVAL
INDICATES
INTERMITTENT FLOW
Figure 3-1. Process operations and discharge streams associated with
Lurgi-based synfuels facilities—main gasification train
-------
SULFUR-FREE
SYNTHESIS
GAS
SPENT
CATALYST
• GASOLINE
• DIESEL OIL
•HEAVY FUEL OIL
•LPG
DEHYDRATION
OFF-GASES
PRODUCT
FRACTIONATION
AND UPGRADING
CATALYST
DECOMMISSIONING
OFF-GASES
INDICATES
INTERMITTENT
FLOW
F-T
WASTEWATER
Figure 3-2. Fischer-Tropsch synthesis and product upgrading
-------
SULFUR-FREE
SYNTHESIS
GAS
CATALYST
DECOMMISSIONING
OFF-GASES
CO2
OFF-GASES
DEHYDRATION
OFF-GASES
CO-PRODUCT
SNG
CATALYST
REGENERATION
OFF-GASES
GASOLINE
PRODUCT
FRACTIONATION
AND UPGRADING
LPG
SPENT CATALYST
METHANOL
PURIFICATION
MOBIL
WASTEWATER
.FUEL GRADE
METHANOL
METHANOL
WASTEWATER
LEGEND:
INDICATES
— INTERMITTENT
FLOW
INDICATES FLOW
CAN GO EITHER
DIRECTION
Figure 3-3. Methanol and Mobil M-gasoline synthesis and upgrading
-------
CATALYST
DECOMMISSIONING
OFF-GASES
DEHYDRATION
OFF-GASES
SULFUR-FREE
SYNTHESIS
GAS
METHANATION
DRYING AND
COMPRESSION
MOISTURE -FREE
SNG
SPENT CONDENSATE
CATALYST
INDICATES
INTERMITTENT
FLOW
Figure 3-4. Substitute natural gas production
-------
N5
STEAM/POWER TO
tN PLANT USERS
PRODUCTS I—»
EVAPORATIVE EMISSIONS
FROM PRODUCT STORAGE
SLOWDOWN
BYPRODUCTS
LEGEND
INDICATES
INTERMITTENT FLOW
EVAPORATIVE EMISSIONS
FROM BYPRODUCT STORAGE
I (am—»•!
Figure 3-5. Auxiliary processes associated with Lurgi-based synfuels facilities
-------
Section 3
Detailed Charac.
coal lockhopper gases. Reuse of this stream within the plant is not required
to produce the plant's main product(s). Thus, this stream fits the definition
of waste stream used in this manual. However, if Lurgi gas is used to pres-
surize the coal lockhopper, the resulting high pressure coal lockhopper gases
should have a composition similar to raw Lurgi gas. As such, these gases
would normally be recycled or reused and would not represent a waste stream
that would be directed to a pollution control system.
The waste streams identified in this manual can be classified as those
that are unique to Lurgi-based facilities and those that are not unique, i.e.,
waste streams that are commonly generated by other industrial plants in the
U.S. In general, the unique streams are produced from the main gasification
train, while the nonunique streams are produced predominantly by the auxiliary
processes, coal preparation, and refinery type product upgrading. Emphasis in
this manual is on the identification/characterization of the unique waste
streams and on the presentation of pollution control information for those
unique streams. As a result of this emphasis, the depth of treatment and pre-
sentation of information for unique waste streams is greater than that for
nonunique streams.
In order to provide consistency in the presentation of process and waste
stream information, calculated material flows were developed for the base
plants, i.e., process configuration and coal feed combinations, examined in
this manual. These material balances are for facilities capable of producing
approximately 120 TT/day of synthesis feed gas for the SN6, methanol, Fischer-
Tropsch, and Mobil M-gasoline synthesis operations. These size facilities
will gasify, depending on the coal feed, from 5800 to 9600 Mg/day of coal and
produce, depending on the coal feed and synthesis process used, the energy
equivalent of 2900 to 3100 m*/day of gasoline. Table 3-1 presents a summary
of typical upgraded product slates for the synfuels facilities examined. A
complete summary of the base plant material balances developed is contained
43
-------
TABLE 3-1. TYPICAL UPGRADED PRODUCT SLATES FOR LURGI-BASED
SYNTHETIC FUELS FACILITIES
Product
SNG
Synthesis
Methanol
Synthesis
Mobil
M-Gasoline
Fischer-
Tropsch
SNG
C, LPG
C4 LPG
100
54
55
2
3
65
2
Methanol - 49 -
Gasoline - - 37
Diesel Oil - - -
Heavy Fuel Oil - - -
Mixed Alcohols - - -
TOTAL PRODUCTS 100 103 97
—
22
4
1
_3
97
Note: All units are TJ/day. Product slates shown are based on gasifying 142 TJ/day of
Rosebud subbiluminous coal to produce a synthesis gas feed of approximately 120
TJ/day. In addition to the indicated products, the following quantities of
byproducts are produced regardless of synthesis process: Naphtha - 2.0 TJ/day;
Tars - 5.5 TJ/day; Oils - 5.9 TJ/day; and Phenols - 1.1 TJ/day. Similar quan-
tities of products and byproducts result from use of the other coals examined
in this PCTM (See Appendix E).
-------
Section 3
Detailed Charac.
in Appendix E. For illustrative purposes, the material flow calculations
based on gasifying a subbiluminous coal (Montana Rosebud) are presented in
this section. Stream numbers used in the material balances in Appendix E and
throughout the rest of this manual refer to the numbers indicated in the vari-
ous flow diagrams presented in this section and summarized in Table 3-49.
The operations which comprise a Lurgi-based synfuels facility are dis-
cussed in Sections 3.1 through 3.4. At the end of each of these sections is a
discussion of the waste streams generated by the operation. Section 3.5 pre-
sents information on the characteristics of the products and byproducts ex-
pected to be produced by the subject facilities. Sections 3.6 and 3.7 con-
tain, respectively, information on auxiliaries and fugitive type wastes.
The last part of this section (Section 3.8) contains a stream index and
summarizes the waste streams identified previously and indicates, for each
waste stream, the part of Section 3 where characterization data can be found
and the part of Section 4 where pollution control information is presented.
Similar type information is also provided for secondary waste streams, i.e.,
those which originate from a pollution control process which could be utilized
in a Lurgi-based synfuel facility.
Numerous references are included in this section to indicate the source
of data presented. Additional data (with references) is presented in Appen-
dices A and B for the Lurgi gasification process and Rectisol acid gas removal
process, respectively.
45
-------
Section 3
Coal Preparation
3.1 COAL PREPARATION
The coal preparation operation in a Lurgi-based synfuels facility will be
similar to the coal preparation operation found in other coal-based plants
such as coal-fired power plants. In addition, the waste streams generated by
this operation and the processes available to control them will also be simi-
lar. Because of the nonuniqueness of coal preparation, limited characteriza-
tion data are provided. The major focus of this manual is on those waste
streams unique to Lurgi-based synfuels facilities.
Feed coal preparation for Lurgi gasification consists mainly of crushing
and screening of run-of-mine (ROM) coal to obtain the proper size range. A
coal dryer would be included if the feed coal moisture content is greater than
about 40 percent, the practical limit for efficient operation of a Lurgi gasi-
fier. Since all three of the coals examined in this manual (see Table 2-1)
contain less than 40 percent moisture, a coal dryer is not required.
Depending on the properties of the coal, a Lurgi gasifier can accept a
sized coal within the range of 0.3 cm to 7.5 cm. A size range of 0.64 cm to
3.8 cm is used in this manual as a generalized example. A typical arrangement
of the coal preparation operation, depicted in Figure 3-6, includes inactive
and active coal storage; crushing, screening, and storage of sized coal for
gasification; and storage of fine coal with subsequent pulverization for
boiler firing. Table 3-2 summarizes the estimated quantities of sized coal
required by the Lurgi gasifiers to produce approximately 120 TJ/day of synthe-
sis gas. Also shown in the table are 1) the quantities of ROM coal which must
be processed and 2) the quantities of coal fines expected to be generated
(before boiler fuel demands are satisfied) to produce the indicated quantities
of sized gasifier feed coal. If the boiler fuel demands exceed the available
quantity of coal fines, then either additional ROM coal would need to be pro-
cessed or other sources of boiler fuel (such as Lurgi byproduct hydrocarbons)
46
-------
FUGITIVE
PARTICIPATES
WASTE STREAMS NOT INDICATED INCLUDE.
FUGITIVE PARTICULATES FROM CRUSHING,
SIZING, AND CONVEYING AND FROM
PREPARED COAL STORAGE (STREAM 202).
RUN-OF-MINE
(ROM) COAL
LEGEND:
.-INDICATES INTERMITTENT FLOW
SIZED COAL
TO COAL
LOCKHOPPERS
EXCESS
COAL FINES
FINE COAL
SILO
PULVERIZER
PULVERIZED COAL
TO AUXILIARY
BOILERS
Figure 3-6. Simplified block flow diagram of coal preparation
-------
TABLE 3-2. ESTIMATED OVERALL MATERIAL FLOWS FOR COAL PREPARATION OPERATION*
00
Stream No.
Stream Name
Subbituminoas Coal
(Montana Rosebud)
Bituminous Coal
(Illinois No. 6)
Lignite
(Dunn Co. , ND)
1 2 21
Run-of-Mine Sized Gasifier
Coal Feed Coal Coal Fines0
456 296 160
350 242 108
571 400 171
?See Figure 3-6. Units are Mg/hr.
Based on coal needed to satisfy gasifier feed requirements. If quantity of coal fines
generated is insufficient to meet boiler demand, additional ROM coal could be
processed.
Before auxiliary boiler fuel demands are met.
-------
Section 3
Coal Preparation
would need to be used. The following discussions assume that the coal fines
generated as a result of preparing the required gasifier feed are sufficient
to meet the auxiliary boiler fuel demands.
ROM coal (Stream 1) is received from the mine via trucks, unit trains,
barges, or conveyors. It is initially stored in an active storage pile (nomi-
nally containing a five-day supply of coal) which provides the feed to the
preparation unit. Raw coal is also kept in an emergency storage pile (con-
taining a 30 to 60 day supply). The emergency pile is utilized when the coal
supply from the mine is interrupted for an extended period. The storage pile
capacity estimates for the base plants presented in this manual are shown in
Table 3-3.
TABLE 3-3. ESTIMATED ROM COAL STORAGE PILE CAPACITIES
5-Day 30-Day
Active Storage Emergency Storage
Pile Pile
Subbituminous Coal (Montana Rosebud)
Bituminous Coal (Illinois No. 6)
Lignite (Dunn Co., ND)
55,000
42,000
68,000
330,000
250,000
410,000
Units are Mg.
ROM coal, with a nominal top size of 10.2 cm is transported to the coal
preparation plant by belt conveyors, where it is screened to make a size
separation at about 3.8 cm. The oversize 10.2 cm x 3.8 cm coal from the
screens is conveyed to crushers where it is reduced to 3.8 cm top size. The
undersize from the screens and the crushed coal from the crushers are then
49
-------
Section 3
Coal Preparation
further sized at about 0.64 cm. The 3.8 cm z 0.64 cm coal fraction (Stream 2)
is conveyed to the sized coal storage silos, while the undersize 0.64 cm z 0
coal (Stream 21) is conveyed to fine coal storage silos.
Coal required for the steam boiler is withdrawn continuously from the
fine coal storage silos, pulverized to 70 percent minus 0.075 mm in a pulveri-
zer, and fed to the boiler. If ezcess 0.64 cm z 0 coal fines remain after the
boiler fuel requirements are met, these can be sold as a byproduct, combusted
to produce electricity or steam for ezport, gasified (in a gasifier which can
use coal fines) to produce additional synthesis gas, disposed of as a waste,
or possibly palletized to make a suitable feed for the Lurgi gasifiers.
Waste streams from the coal preparation operation include particulate
emissions from ROM coal storage (Stream 200), runoff from ROM coal storage
(Stream 201), and particulate emissions from crushing, screening, transfer,
and prepared coal storage (Stream 202). The estimated quantities of fugitive
particulates originating from the active and emergency storage piles are
listed in Table 3-4. These values were calculated using several methodologies
that have been developed for estimating such emissions (14). Data on the
composition of particulate emissions produced by coal storage piles are becom-
ing available through source test and evaluation studies sponsored by the EPA
(15,16).
Data on the characteristics of runoff streams originating from ROM coal
storage piles for the subject coals are not currently available. However,
laboratory leaching tests with raw coal refuse materials have indicated that
the types and quantities of pollutants released from coal storage piles are
similar to those produced by coal refuse piles (17). In addition, there are
some data available on actual effluents produced by high-sulfur coal storage
50
-------
TABLE 3-4. ESTIMATED FUGITIVE PARTICTJLATES FROM COAL STORAGE PILESa
Reference for
Emission
Estimate
Active Storage Pile
Wind Erosion
Loading Activities
Vehicular Activities
Total (of Above Items)
Total (From Other Reference)
Emergency Storage Pile
12
13
13
12
12/14°
Emissions for Various Coal Feeds, ke/dav
Subb i turn inous
(Montana Rosebud)
18
260
5
283
170
120/190
Bituminous Lignite
(Illinois No. 6) (Dunn Co., ND)
15
120
3
138
110
85/120
24
160
5
189
230
150/240
£
See Table 3-3 for estimated coal storage pile capacities.
cWith no controls applied.
First reference is for first value shown; second reference is for second value.
-------
Section 3
Coal Preparation
piles (17). This information, coupled with the known composition of the sub-
ject coals, allows qualitative and semi-quantitative estimates to be made of
the composition of the storage pile runoff produced by the three coals.
Runoff from storage piles of Midwestern coals (such as Illinois No. 6) is
ezpected to be highly acidic, with pH values in the range of 2 to 4. Total
suspended solids during storm runoff can be as high as 2,300 mg/L. Sulfate
concentrations may be in excess of 9,000 mg/L. Iron concentrations can range
from 23 to 1,800 mg/L, while manganese concentrations can be in the range of
1.8 to 45 mg/L. Other elements ezpected to be present in the coal pile run-
off include aluminum, mercury, arsenic, and zinc (17).
Runoff from the subbituminous coal and lignite storage piles is ezpected
to be close to neutral, with a pH slightly above 7. Sulfate concentrations
are ezpected to be less than 1,000 mg/L. Iron and manganese concentrations
are ezpected to be low, less than 0.8 mg/L for iron and below 0.4 mg/L for
manganese (18). The dominant water contaminants are ezpected to be calcium
and magnesium, with concentrations in the ranges of 200 to 400 mg/L and 50 to
250 mg/L, respectively (19). Total suspended solids levels will probably be
higher than those present in Illinois No. 6 runoff because of the tendencies
of these coals to slake.
Published data on particulate emissions from coal preparation operations
are limited. Generally, particulate emission estimates are based upon data
taken from surface coal mining and ore mining operations, stone and rock
crushing, and coke production. Furthermore, reported emission factors (13,20)
for specific operations within preparation plants are based on estimates
rather than actual data. It is commonly reported that "western coals and lig-
nites...have several times as much dust as comparable tonnages of eastern
coal" (21).
52
-------
Section 3
Coal Preparation
Table 3-5 summarizes uncontrolled fugitive particulate emission factors
for several, but not all. activities within the coal preparation operation
(13). Applying these factors to the estimated coal flow rates in the coal
preparation plant gives the following estimates of uncontrolled fugitive
particulate emissions:
subbituminous coal - 3000 kg/day
bituminous coal - 2400 kg/day
lignite - 3900 kg/day
TABLE 3-5. FUGITIVE PARTICULATE EMISSION FACTORS FOR
COAL PREPARATION OPERATIONSa
Activity
Uncontrolled Emission Factor,
kg/Mg handled
Loading From Storage
Transfer and Conveying
Secondary Crushing/Screening
0.05
0.10
0.08
"Reference 13.
53
-------
Section 3
Gasification
3.2 LDRGI GASIFICATION
The dry ash Lurgi gasifier is a water-jacketed, medium pressure (2.1 to
3.2 MPa), moving-bed gasification system which operates below coal ash fusion
temperatures. Essentially all types of coals, with moisture contents below
about 40 percent, can be gasified without drying. A single 4 meter diameter
Lurgi gasifier processes about 700 to 1000 Mg of coal per day depending on
coal quality. Caking coals require a coal distributor equipped with a stirrer
and result in reduced throughput rates. As shown in Figure 3-7, the Lurgi
gasification unit consists of the following components: coal bunker; coal
lockhopper; water-jacketed, pressure gasifier vessel; and ash lockhopper.
Although not shown in Figure 3-7, an ash quench system is also generally
considered a part of the gasification unit.
Table 3-6 presents calculated material flows for the Lurgi gasification
operation based on gasifying a Rosebud subbituminous coal to produce approxi-
mately 120 TJ/day of synthesis gas. This balance was developed from available
test data (1,3) and published design information (6) for Lurgi gasification
systems. The major source of information used to estimate the required inputs
and resulting raw gas composition and flow rate was an experimental test
program conducted at Westfield. Scotland using Montana Rosebud coal in a
commercial Lurgi gasifier (1). However, estimates of the production of C,
and C4 aliphatics were obtained from the Environmental Impact Statement for
the ANG Coal Gasification Company North Dakota Project (6). The relative
quantities of sulfur species in the raw Lurgi gas were based on the sulfur
species distribution found in test programs at the Lurgi-type gasification
facility in Kosovo, Yugoslavia (3).
The above data sources were also used to develop the gasification materi-
al balances presented in Appendix E for gasifying Illinois No. 6 bituminous
coal. These same sources were also used for the Dunn County Lignite balances
54
-------
PREPARED
COAL
COAL
BUNKER
COAL
LOCKHOPPER
VENT GAS
PRESSURIZATION
GAS
RECOVERED
STEAM
PRESSURIZATION
GAS (STEAM)
RAW LURGI
GAS
ASH LOCKHOPPER
VENT GAS
ASH TO
QUENCH
Figure 3-7. Lurgi gasifier
55
-------
TABLE 3-6. ESTIMATED MATERIAL FLOWS FOR LDBOI GASIFICATION OPERATION - ROSEBUD COAL
Stream No. 2 3
Prepared
Stream Name Coal Steam
k i— noles/hr
a.
0,
N,+Ar
CO
CO,
CH4
C,H4
C fl
C,H,
C4H10
C H.
C* aliphatica
Benzene
Toluene
Other sromatics
H,S
COS
CH,SH
C H,SH
C , mar eaptaaa
HCN
NH,
HC1
4 5
Raw Lurgi
Ozraaa Oaa
7.619
2,270 39
137 162
2 ,806
5,733
2.075
93
13
15
13
7.4
13
8.6
9.7
2.3
1.9
82
1.1
7.2
2.3
0.3
1.2
137
0.4
205* 207 206
Low Pressure Ash
Coal Lookhopper Oasifier Lookhopper
4.7
0.024 14.3
0.10 0.9
1.7
3.5
1.3
0.057
0.008
0.009
0.008
0.005
0.008
0.005
0.006
0.001
0.001
0.050
0.0007
0.004
0.001
0.0002
0.0007
0.084
0 .0002
Total Dry Oaa
kt/hr
H,0 73,210
Coal (HAFT 194.300
Ash 28,830
Partionlatea
Organic aerosols
Tara
Oil*
Phenol «
Fatty aoida
Other constituent!
2.407
370,800
Total, kg/hr
296,340
370,800 77.460
18,843
293.634
495
5.710
6.181
1.371
604
2,389
709,664
11.6
1.7
0.052
1.9
247
15.2
15SO
30,600
3.5
30,600 2043
Assumes Lorgi synthesis gaa ia used aa the lookhopper pressnrant. Coapoaitioa
shown excludes ejection air. Composition ia also dependent oa design aad operation
of coal lookhopper systev.
HAF • moisture snd ssh free.
Blsnks iadicate not applicable or no data available.
Number of significant figures shown orerstatea the socnraoy of the calculated estimates.
Sea Appendix A for dataila of assumptions aad baaaa.
Not shown ia this table are the high-pressure ooal lookhopper gases which are expected to be similar
ia composition to the low-pressure lock-hopper gases.
56-
-------
Section 3
Gasification
presented in Appendix E, but greater use was made of information from ANG (6)
and Kosovo (3) since these facilities gasify lignite. A more detailed expla-
nation of the bases for the material flow calculations is presented in
Appendix A.
The use of Kosovo data (3) to estimate the relative distribution of sul-
fur species in raw Lurgi gas and the use of ANG data (6) to estimate the pro-
duction of Cj and C4 aliphatics in raw Lurgi gas require a special note. The
Kosovo data, which are for lignite gasification, indicate that approximately
10 percent of the gaseous sulfur species appear as non-H^S compounds with a
large portion being mercaptans, especially methylmercaptan. For this test
program, special sampling and analytical procedures were used to enable mer-
captans to be detected and quantified. The Westfield data (1) for gasifying
Rosebud and Illinois No. 6 coals indicate non-H,S species as being a much
lower percentage (2 to 6 percent) of the total gaseous sulfur species. No
breakdown of the composition of the non-HaS species was given in the
Westfied data.
The exact mechanisms by which mercaptans, as well as other sulfur species
are generated and destroyed in a Lurgi gasifier are not well documented. If
gas phase equilibrium exists between the sulfur species, then the assumption
of a constant relative sulfur species distribution seems reasonable. On the
other hand, kinetic limitations may severely impede the rate of attaining
equilibrium. If so, then the mechanism by which each sulfur species is initi-
ally created when the coal is gasified becomes most important, and the rela-
tive distribution of sulfur species could be mainly a function of coal type
and gasifier operating conditions.
The importance of this issue is that non-H,S sulfur species can impact
the performance and costs of controls for acid gases generated in the Rectisol
57
-------
Section 3
Gasification
unit. Section 4.1.1 discusses the impacts that non-H,S sulfur species, and
especially mercaptans, have on the performance and costs of reduced sulfur
species control technologies.
The quantities of C3 and C4 aliphatics produced in a Lurgi gasifier can
also impact the performance and costs of controls for acid gases generated in
the Rectisol unit. These components, as well as part of the C2 aliphatics,
are expected to be removed from the Rectisol feed gas and appear for the most
part in the acid gas stream(s) produced when the Rectisol sorbent is regen-
erated. Depending on the levels of these components in the Rectisol feed gas,
extra costs could be incurred to remove/destroy the aliphatics in the acid gas
waste stream(s).
The production of C, and C4 aliphatics depends on, among other factors,
the type of coal gasified. Thus, use of a constant production rate of these
components based on ANG data for lignite gasification (6), could be an over-
estimation or underestimation for other types of coal (or even other lig-
nites) .
Sections 3.2.1 through 3.2.4 discuss the Lurgi gasification operation and
its associated process and waste streams.
3.2.1 Coal Feeding
Sized coal (Stream 2) from the coal preparation operation is stored at
atmospheric pressure in a coal bunker located directly above the Lurgi gasi-
fier. Coal is fed from the bunker to the pressurized gasifier vessel in a
cyclic manner using a coal lockhopper. At the start of each charging cycle,
the coal lockhopper is at nominally atmospheric pressure and is filled with
residual gases from the prior charging cycle. As the lockhopper is charged
with coal, a portion of these residual gases (Stream 205) are displaced and
58
-------
Section 3
Gasification
ejected with air, generating a waste stream. When the desired quantity of
coal is obtained in the lockhopper, it is isolated from the coal bunker and
pressurized to the gasifier operating pressure using either raw or cooled
Lurgi gas or an inert gas such as N2 or C0a.
Once pressurized, valves between the lockhopper and gasifier are opened,
allowing the coal to flow by gravity into the gasifier. Raw Lurgi gases from
the top of the gasifier backflow into the lockhopper in order to fill the
space originally occupied by the coal unless additional lockhopper pressurant
is added as the coal is dropped. After the complete coal charge has been
dropped, the lockhopper/gasifier valves are closed and the lockhopper is
depressurized. The resulting depressurization gases are termed high pressure
lockhopper gases. Low-pressure-residual lockhopper gases are displaced by the
next charge of coal and ejected from the feeding chute with air.
The cycle time of the coal lockhopper is a direct function of the desired
gasifier feed rate, and can range from 10 to 30 minutes (7,10). Waste streams
generated by the coal feeding process include high-pressure lockhopper gases
(Stream 204) and air ejected low-pressure vent gases (Stream 205).
3.2.2 Lurgi Gasification
Coal enters at the top of the Lurgi gasifier. falls on the coal bed, and
slowly moves downward, countercurrent to gas flow. As the coal descends, it
passes through four "zones" of progressively higher temperature before exiting
the bottom of the gasifier as ash. The zones are, from top to bottom, drying,
devolatilization, gasification, and combustion. Major chemical reactions as-
sociated with these zones are:
Coal + heat •*• CB^ + H,0 (drying and devolatilization)
59
-------
Section 3
Gasification
C + HaO + heat ->• CO + Ha
C + C0a + heat -»• 2 CO (gasification)
C + 2Ha -> CH4 + heat
C + l/20a -»• CO + heat
C + Oa -»• C0a + heat (combustion)
In the first zone, the coal is dried by contact with the hot raw gas
leaving the gasifier. As the temperature of the coal rises in the second and
third zones, devolatilization and gasification reactions occur. On an overall
basis, the reactions in the first three zones are endothermic. Heat for the
reactions in these zones is supplied by the combustion reactions which occur
in the fourth zone. A revolving grate at the bottom of the gasifier provides
for a uniform flow of ash to the ash lockhopper and continuous introduction of
steam and high purity oxygen under the downward moving coal bed.
Steam and oxygen requirements for a Lurgi gasifier range from 1.5 to 3.1
and 0.2 to 0.6 kg per kg of MAP (moisture- and ash-free) coal, respectively,
depending on the type of coal gasified. Input rates must be suitable to
maintain the gasifier combustion zone temperature below the ash fushion tem-
perature. If this temperature is exceeded, clinker or slag formation can
occur and result in plugging or destruction of the revolving ash grate located
at the bottom of the gasifier. On the other hand, the combustion zone tem-
perature must not be so low that the gasification reactions are impaired. The
combustion zone temperature is adjusted by varying the ratio of steam to
oxygen.
The hot raw Lurgi gas leaving the gasifier (Stream 5) is composed pri-
marily of unreacted steam, methane, carbon monoxide, carbon dioxide, and
hydrogen. Also present are low molecular weight hydrocarbons (CaH4, CaHc,
C,-CS), benzene, toluene and other aromatics, higher molecular weight
60
-------
Section 3
Gasification
organics (e.g., tars, oils, phenols, fatty acids), reduced sulfur and nitro-
gen compounds (e.g., H2S, COS, mercaptans, NH,, HCN), and entrained coal
particles. Table 3-7 summarizes the concentrations of major and minor com-
ponents expected in raw Lurgi gases. In addition to the components shown,
heavy hydrocarbons (i.e. tars, oils, and phenols), entrained particulate
matter, and trace elements are expected to be present in the raw gases. On a
moisture-free basis, the concentrations of major components in the raw gas are
relatively independent of the feed coal type (approximately 40% Ha, 16% CO,
30% C0a, 10% CH4, and 1% nonmethane organics). The levels of other components
(including nitrogen-containing compounds, trace elements, and organics), in
contrast, can vary significantly with the specific coal.
3.2.3 Ash Removal
Ash is removed from the Lurgi gasifier via a lockhopper which is pres-
surized with steam. The lockhopper discharges into an ash quench basin or
sluice launder. In either case, the quenched ash slurry which results is sent
to a series of vibrating screens and classifiers where large ash particles are
separated. The remaining ash quench water contains approximately one percent
(by weight) ash fines and is pumped to thickeners and dewatering ponds for
settling. Clarified overflow from the thickeners and ponds is recycled, along
with makeup quench water, to the quench basin or sluice launder. Water is
lost from the ash quenching system due to vaporization (the hot ash (Stream
207) is initially discharged at approximately 530 K) and evaporation from the
dewatering pond. Figure 3-8 depicts a generalized gasifier ash quench system.
Waste streams generated by the ash removal process include ash lockhopper
depressurization vent gases (Stream 206), evaporation from ash quenching, and
quenched gasifier ash (Stream 403).
61
-------
TABLE 3-7. ESTIMATED MAJOR AND MINOR COMPONENTS OF RAW LDRGI GASa'b
KJ
Subb i tnminous
Coal
(Montana Rosebud)
Ha, vol. %
CO, vol. %
COa, vol. %
CH4, vol. %
Na+Ar, vol. %
Oa, vol. %
Aliphatics, vol. %
Aromatics, vol. %
HaS, ppmv
Other Reduced Sulfur
Species, ppmv
HCN, ppmv
NH» , ppmv
40.4
14.9
30.4
11.0
0.86
0.21
0.87
0.074
4400
580
60
7300
Bituminous
Coal
(Illinois No. 6)
37.6
17.2
31.6
9.5
1.2
0.11
0.85
0.11
9100
1200
60
7400
Lignite
(Dunn Co., ND)
38.8
15.6
31.7
10.8
0.84
NA
1.0
0.41
4000
530
60
4100
References 1,3, and 6.
"Also present in raw Lurgi gas are high molecular weight organics (such as phenols,
tars, oils), entrained particulate matter, and trace elements.
NA = data not available.
-------
MAKEUP
QUENCH WATER
DRY GASIFIER,
ASH
u>
EVAPORATION
RECYCLE TO
ASH QUENCH
FINES
THICKENER
FINE ASH POND
DREDGED
SOLIDS
QUENCHED
GASIFIER
ASH
Figure 3-8. Schematic of ash quench system for Lurgi gasification
-------
Section 3
Gasification
3.2.4 Waste Stream Characteristics
Waste streams generated by the Lnrgi gasification operation include:
1) high pressure (Stream 204) and low pressure (Stream 205) coal lockhopper
gases, 2) transient waste gases (Stream 208), 3) ash lockhopper vent gases
(Stream 206), and 4) quenched gasifier ash (Stream 403).
jer Vent Gases (Stream;
Characteristics of the coal lockhopper gases are determined largely by
the gas used to pressurize the lockhopper. Raw or cooled Lurgi gas or an
inert gas such as C02 or N2 can be used, but the most commonly proposed design
uses cooled Lurgi gas for pressurization. In this design, approximately 98%
of the gases produced when the lockhopper is depressurized (high-pressure
lockhopper gases; Stream 204) are collected, compressed, and recombined with
the raw Lurgi gases. Low-pressure residual gases which cannot be recycled
(Stream 205) are ejected with air in conventional designs. Due to the nature
of the lockhopper operation, the lockhopper vent gases are generated on an
intermittent basis.
Whether Lurgi gas or an inert gas is used to pressurize the coal lockhop-
pers, the residual lockhopper gases are expected to contain the same constitu-
ents as found in the raw Lnrgi gas (Stream 5). This is expected because raw
Lurgi gases will enter the lockhopper, after the coal is dumped, to fill the
space originally occupied by the coal. The resulting lockhopper gases will
thus be a mixture of raw Lnrgi gases and the lockhopper pressurant gas. If an
inert gas is used as the lockhopper pressurant, the amount of raw gases which
enter the lockhopper can be minimized or possibly eliminated if a positive
flow of pressurant gas is maintained as the coal charge is dumped.
-------
Section 3
Gasification
If Lurgi gas is used as the pressnrant, the coal lockhopper gases (both
low- and high-pressure) should resemble the composition shown in Table 3-6 for
raw Lurgi gas. In addition to the components shown in this table, test data
indicate that entrained coal particles and aerosol organics (basically con-
densed tars and oils) will be present (3). The concentrations of these com-
ponents are estimated at 0.2 g/Nm* and 7.3 g/Nm3, respectively. These
estimated concentrations are based on data from the Kosovo gasification plant
where raw Lurgi gases are used to pressurize the coal lockhoppers (3). At the
Kosovo plant the low-pressure lockhopper gases are those below 0.2 MPa.
Lowering this cutoff pressure between high- and low-pressure gases can not
only reduce the quantity of low-pressure gases generated, but also can help
reduce the concentrations of entrained coal particles and aerosol organics in
the residual low-pressure gases (2). The reader should remember that the
design features and operating procedures for coal lockhoppers can affect the
composition of coal lockhopper vent gases. Therefore, modern Lnrgi designs
may result in a different coal lockhopper vent gas composition than that
observed at Kosovo.
If an inert gas is used as the lockhopper pressurant the same components
shown in Table 3-6 are expected to be present. However, their concentrations
are expected to be decreased due to the dilutive effect of the inert gas.
The volume of coal lockhopper vent gases generated has been estimated
using data for the ANG Lurgi-based SNG facility (7). For that plant, low
pressure residual lockhopper gases are reported to be approximately 37 kg-
moles/hr, before dilution with ejection air. The lignite feed rate for the
ANG plant is about 1020 Hg/hr. Assuming that the lockhopper gases generated
are proportional to the coal feed rate, a factor of 0.04 kg-moles of low
pressure vent gas per Ng coal feed is calculated. Information for the ANG
plant (7) also indicates that the low-pressure residual lockhopper gases
65
-------
Section 3
Gasification
represent 2 percent of the total volume of lockhopper gases generated (exclud-
ing ejection air). Thus, the volume of high-pressure coal lockhopper gases is
approximately 49 times the volume of the low-pressure gases. The calculated
flow rates of low- and high-pressure lockhopper gases are summarized below.
Again, flow rates shown are exclusive of ejection air. Including this ejec-
tion air, as well as dilution air required to reduce explosion hazards (see
Section 4.1), could increase the flow rate of the low pressure gases by a
factor of 20 or more (7). Of course pollutant concentrations would be reduced
by a similar factor.
Low-Pressure Gases High-Pressure Gases
Subbituminons Coal 12 kg-moles/hr 570 kg-moles/hr
Bituminous Coal 9 kg-moles/hr 460 kg-moles/hr
Lignite 15 kg-moles/hr 740 kg-moles/hr
Transient Waste Gases (Stream 208)
Raw gasifier outlet gases produced during startup, shutdown, and upset
conditions are not suitable for synthesis use and constitute a gaseous waste
stream. The following is assumed to be representative of the frequency of
generation and volume of transient waste gases generated by the Lurgi-based
synfuels facilities examined in this manual. These estimates, which are based
on data submitted for the ANG facility (7) and reported to be worst case
estimates for unscheduled hot startups, are for facilities using approximately
twelve gas ifiers.
Waste lias Generation
Rate per Startup,
kg-moles/min
Type of
Maintenance
Scheduled
Overhaul
Type of
Startup
Cold
Duration of
Startup (hr)
8
Number
Per Year
13
11
Unscheduled:
Long Cold 8 26 11
Short Hot 1 104 19
66
-------
Section 3
Gasification
Additional information for the ANG facility (7) indicated transient waste
gases associated with worst case plant operating conditions are assumed to
occur when two gasifiers are in the "cold" startup mode and one gasifier is in
the "hot" startup mode. Under these conditions waste gases would be generated
at a rate of about 42 kg-moles/min. Based on the schedule given above, the
annual quantity of transient gases is estimated as approximately 330,000 kg-
moles.
The composition of transient waste gases is expected to vary considerably
over the duration of the startup. For analysis purposes, it is assumed that
the composition of the transient waste gases is approximately that of raw
Lurgi gases generated by gasification using air as the source of oxygen for
the gasifier (see Table 3-8). This should be a reasonable assumption since
gasifiers are commonly "cold started" with air rather than oxygen, and it is
this type of transient operation which is expected to account for the bulk of
the generated transient gases.
In addition to the components shown in Table 3-8, transient waste gases
will also contain entrained particulate matter and aerosol organics. The
concentrations of these components after the transient gases have been sub-
jected to a quenching step are estimated at 0.06 and 9 g/Nm3, respectively,
based on data from the Kosovo gasification plant (3). Like raw Lurgi gas and
coal lockhopper gases, the aerosol organics in transient gases contain poly-
cyclic organic material (POM) similar to that found in the byproduct tars and
oils (22). Table 3-9 summarizes the POM components identified in Kosovo
byproduct tars and oils (3).
67
-------
TABLE 3-8. ESTIMATED COMPOSITION OF AIR-BLOWN LURGI GASES* (7)
Component
Ha
CO
COa
CH4
Na
HaS
NH3
HaO
Volume %
Wet Basis
16.8
6.7
15.0
5.1
28.1
0.2
0.4
27.7
*Gasifier startup gases are assumed to be of similar composition.
TABLE 3-9. POLICYQLIC ORGANIC MATTER IDENTIFIED IN
KOSOVO BYPRODUCT TARS AND OILS (3)
Concentration (mg/kg) in
Component
Benz (a)anthracene
7 , 12-dime thy Ibenz ( a ) anthracene
Benzo(b) fluoroanthrene
Benzo(a)pyrene
Dibenzo(a,h)anthrene
3-Methylcholanthrene
Light Tar
490
1.100
310
210
23
26
Medium Oil
160
62
120
68
6.6
<1
68
-------
Section 3
Gasification
Ash Lockhopper Vent Gases (Stream 206)
Steam is utilized for pressurization of the ash lockhopper to avoid the
flow of gasifier feed (i.e. steam and Oa) from the gasifier into the ash lock-
hopper. Before ash is discharged from the lockhopper to the ash quench sys-
tem, it is depressnrized. The resulting vent gases should contain essentially
only steam, minor amounts (less than 1 percent) of 02, and entrained ash
particles (2). The only test data available on ash lockhopper vent gases is
for the Kosovo plant (3). At this plant, the ash lockhopper gases are sent to
a cyclone where they are contacted with process water (the source of the
process water was not known). The cyclone exit gas contained 85 percent
moisture and had the following composition on a dry basis (3):
Component Concentration
0* 48%
N» 35%
CO, 14%
H»S 82 ppmv
NH, 340 ppmv
HCN 54 ppmv
Particulates 10.3 g/m»
It is not known whether the C0a, HaS, NH,, and HCN originated from the ash
lockhopper gases or the process water used to scrub the gases. However,
the results obtained are unexpected and probably indicate that the contami-
nants originated with the process water. For material flow estimating
purposes, the ash lockhopper vent gases are assummed, based on Kosovo data
(3), to be produced at a rate of 0.016 kg/kg dry ash and contain 85 percent
moisture and 10.3 g particulate per Mm* of dry vent gas. The dry vent gas
was assumed to consist of Oa and Na in the same proportion as found in the
oxygen feed (Stream 4).
69
-------
Section 3
Gasification
Quenched Gasifier Ash (Stream 403)
Table 3-10 presents flow rate information for the major streams found in
the ash quenching system. The water vaporized during quenching was calculated
by assuming that 10 percent of the quench makeup water would be vaporized.
The water lost through evaporation from the fine ash pond was calculated as
0.158 kg water per kg dry ash based on data in Reference 10. The quenched ash
ready for disposal was assumed to be 20 weight percent water.
Table 3-11 presents data on the expected composition of unquenched gasi-
fier ashes and leachates from these ashes (9,23). There are currently no
data publicly available on the characteristics of leachates from quenched
Lurgi ash. Since the ash quenching operation is a net consumer of water,
constituents solubilized during quenching would ordinarily remain with the wet
ash sent to disposal. Hence, the data in Table 3-11 should present a reason-
able picture of the teachability of trace elements from quenched gasifier ash
assuming no contribution of constituents from quench makeup water. If con-
taminated process waters are used for ash quenching, it is possible that the
ash may become contaminated with water-derived substances which may be subse-
quently leachable.
70
-------
TABLE 3-10. ESTIMATED MASS FLOWS FOR GASIFIER ASH QUENCHING SYSTEM
Stream
Dry Gasifier Ash
Makeup Water
Water Vaporized
during Quench
Water Evaporated
from Dewa taring Pond
Ash for Final Disposal
Subbituminous
(Montana Rosebud)
30.600
13.600
1,100
4.800
38.300
Flow Rates (ktt/hr)
Bituminous
(Illinois No. 6)
22,300
9.900
830
3.500
27,900
Lignite
(Dunn Co. . ND)
28.600
12.700
1,000
4.500
35,800
(20% water)
-------
TABLE 3-11.
COMPOSITION AND LEACHING CHARACTERISTICS
OF UNQ0ENCHED LURCI GASIFIES ASHES
Rosebud*
RCRA
Constituent Ash Leachate
Maioi Constituents (Iffc-Drr
A^O,
CaO
Fe,0,
H(0
Na,0
SiO,
TiO,
SO,
c
Cl
Tiriflfl K
At
As
B
Ba
Be
Br
Cd
Ce
Co
Cr
Cs
Cn
F
Ga
Ge
flt
Li
Mo
MB
Ml
P
Pb
Kb
Sb
Sc
Se
Sn
Sr
Te
C
V
1
I
Zn
Zr
17.7
8.3
11.2
_
3.9
—
46.8
—
1.7
6.5
0.115
Basis)
_ w
—
—
—
—
—
—
—
—
—
—
Illinois No. 6*
RCRA
Ash Leachate
20.5
2.3
20.5
1.8
0.6
0.3
49.3
1.0
1.5
3.2
0.01
_
—
—
—
—
—
—
—
—
—
—
b
Dnas County
Ash Leachate
24
26
11
0.6
7
8
25
0.6
3.1
6.5
0.007
__
—
—
—
—
—
—
—
—
—
—
eaents (PPM-Drr Basis)
0.23
26
380
1900
2.8
—
2.4
—
4.3
440
—
130
600
—
—
0.03
85
200
790
200
—
40
—
6.2
—
2.2
3.7
—
—
13
91
—
—
32
—
0.0002
0.003
1.85
2.3
—
—
0.002
—
—
0.006
—
0.013
0.12
—
—
0.004
—
—
9.25
0.138
—
0.002
—
—
—
0.001
—
—
—
0.5
—
—
—
0.33
— •
0.4
3
355
950
12
1
1.6
140
34
212
11
57
10
26
7
0.05
42
30
1859
89
87
45
162
4.2
20
1
—
370
—
17
184
1.5
—
400
170
0.001
0.004
0.25
0.2
—
—
0.013
—
—
0.003
—
0.004
0.18
—
—
0.0005
—
—
0.71
—
—
0.002
—
—
—
0.003
—
—
—
0.5
—
—
—
4.27
— —
1
74
1680
8270
6
3
0.5
190
13
140
0.9
27
191
53
2
0.055
45
12
760
25
3500
58
35
33
4
0.5
4
12.900
0.3
7
150
2
320
10
520
__
0.03
13.36
0.37
—
—
0.001
0.009
0.01
0.31
0.02
0.09
0.43
—
—
0.0001
0.25
0.55
0.1
0.02
0.88
0.01
1.03
—
0.001
0.009
—
—
—
—
0.39
0.024
—
0.02
^*
,Fro»
23.
Calculated froB data in Raferenoa 9. la that study boiler water was naed to prepare
10% solids slurries. The slurry elemental concentrations reported were adjusted to
the Tolnaei which the SCRA Extraction Procedure would repreaent.
— indicates aot applicable or no data awailable.
72
-------
Section 3
Purification
3.3 GAS PURIFICATION AND UPGRADING
Raw Lurgi gases contain a number of impurities which must be removed
prior to product synthesis. In addition, for some raw Lurgi gases and/or
synthesis operations the composition of the gas must be adjusted to meet the
stoichiometric requirements for the synthesis process. The gas purification
and upgrading operation accomplishes these objectives by 1) quenching and
cooling the raw gases, 2) shifting a portion of the gases to adjust the H2
to CO ratio, 3) removing C0a and reduced sulfur compounds, and 4) removing
traces of sulfur compounds.
During purification and upgrading of raw Lurgi gases, the contaminants
removed from the gas become components of waste streams. As a result, the
purification and upgrading operation generates several of the most important
waste streams in Lurgi-based synfuels facilities from the standpoint of stream
composition and volume.
Table 3-12 presents calculated material flows for the gas purification
and upgrading operation of a Lurgi-based synfuel facility producing approxi-
mately 120 TT/day of synthesis gas from a subbituminous (Montana Rosebud)
coal.
3.3.1 Gas Quenching and Cooling
A typical processing sequence for raw gas quenching and cooling in a
Lurgi-based synfuels facility is shown in Figure 3-9. As indicated in this
figure, raw Lurgi gas (Stream 5) is cooled in several stages. Also indicated
in this figure is that shift conversion, if necessary, would typically occur
between primary and secondary cooling. Section 3.3.2 discusses shift conver-
sion.
73
-------
TABLE 3-12. ESTIMATED MATERIAL FLOWS FOR GAS PURIFICATION AND UPGRADING - ROSEBUD COAL
Streasi No.
5
Streasi Nsaie
ka-aiolea/hr
B,
o,
N,-fAr
CO
CO,
CB4
C,H,
C,B4
C,B,
CJB4
C4BH
C4B-
C, aliphatics
Beniene
Toluene
Other iroBitics
H,S
COS
CB.SB
C^B.SB
Cs aiercsptsBS
BCN
NB,
BC1
Me thsnol
Total Dry Gaa
B,0
Ash
Psrticulates
Tars
Oils
Phenols
Fatty Acids
Other Constituents
Total, kg/'hr
Blanks indicate not
Gas
7.619
39
162
2,806
5.733
2.075
93
13
15
13
7.4
13
S.6
9.7
2.3
1.9
82
1.1
7.2
2.3
0.3
1.2
137
0.4
18,843
293,634
495
5,710
6,181
1,371
604
2,389
709,664
applicable
D t A.. J_ ».
209
Gas Liquor
Gases
1.1
80
3.6
0.18
0.18
0.93
0.011
0.34
0.2
0.027
0.005
2.0
88.6
85
3,830
111 112 210 10
213
Byproduct Byproduct Quenched
Tara Oils Liquor Gas
7.619
39
162
2,805
93.3 5,560
2,071
93
13
15
13
7.4
13
8.6
9.7
2.3
1.9
0.50 81
1.1
6.9
2.1
0.3
0.056 1.1
135 0.2
0.2
18,526
292,960 576
426 12 57
5,665 45
6,181
1,371
604
2.389
6,091 6.193 303.850 388.868
or no dsta available. Nusiber of significant figures shonn
nwu
Offgases
23
4
56
4,954
54
53
7.5
15
13
6.6
11.5
0.9
0.53
0.032
80.9
1.1
6.6
1.5
0.54
0.15
8.1
5.298
9
228,219 9
overststes the
216
Methanol/
later
Q» 1 1 I
0 t 1 i 1
Bottosis
0.004
0.007
0.044
0.19
0.017
0.26
.965
,965
sccuracy
114 12
Byproduct Sulfur-Free
Lurgi Synthesis
Naphtha Gas
7.596
39
158
2,749
606
2,017
40
5.5
0.1
0.8
1.5
7.6
9.2
2.27
1.9
0.1
0.3
0.6
0.27
0.55
13.211
1.876 158.451
of the calculated estimates.
-------
RECYCLE
GAS LIQUOR
RAW
LURGI
GAS
ui
GAS LIQUOR
DEPRESSURIZATION
GASES
QUENCHED
LURGI
GAS
DUSTY TAR
TOGASIFIER
GAS
LIQUOR
NOTE
SHIFT CONVERSION MAY NOT
BE NECESSARY FOR ALL LURGI
SYNFUELS PLANTS.
TAR TO
STORAGE
OIL TO
STORAGE
Figure 3-9. Raw gas quenching and cooling system
-------
Section 3
Purification
Raw gas from the Lurgi gasifier is immediately quenched in a direct con-
tact "wash cooler." Quenched gas from the wash cooler undergoes primary cool-
ing in vertical tube waste heat boilers. Secondary cooling, either immedi-
ately after primary cooling or after shift conversion, is accomplished in a
series of indirect coolers. Energy recovery is normally practiced to the ex-
tent possible during the secondary cooling step, but final cooling to about
310 K is accomplished using cooling water and/or air coolers.
Moisture, tars, oils, and phenols are condensed as the raw gas passes
through the wash cooler and primary and secondary coolers. The resulting
condensate, termed gas liquor, is sent to the gas liquor separation unit.
Also present in the gas liquor stream are water soluble components present in
the Lurgi gases, including ammonia, carbon dioxide, hydrogen sulfide, and
hydrogen cyanide, and dust scrubbed from the raw gas.
The gas liquor separation unit, shown in Figure 3-9 as tar separation and
oil separation, actually consists of a series of coolers, depressurization ves-
sels, and gravity separators. These pieces of equipment permit the tars
(Stream 111) and oils (Stream 112) to be separated from the aqueous phase of
the gas liquor and recovered as byproducts. Dust present in the gas liquor
becomes admixed with a portion of the tars. This dusty tar is recycled to the
gasifier.
Waste streams produced by gas quenching and cooling come from the gas
liquor separation unit and include flashed gases from the depressurization and
gravity separation vessels (Stream 209) and gas liquor (Stream 210). The
expected characteristics of these waste streams is discussed in Section 3.3.5.
76
-------
Section 3
Purification
3.3.2 Shift Conversion
The production of synthetic liquids requires a synthesis gas containing
Ha and CO in a ratio of 2 to 1 or higher. For SNG synthesis, the required
ratio is 3:1. To obtain the desired Ha:CO ratio, a portion of the Lurgi
gases may require shifting, i.e., the reaction of carbon monoxide and water to
form carbon dioxide and hydrogen. This reaction is mildly exothermic and can
be promoted by a variety of catalysts.
CO + HaO -*• C0a + Ha + heat
In principle, shift conversion may be conducted either prior to or fol-
lowing sulfur species removal. When shift conversion precedes sulfur species
removal, moisture (steam) contained in the partially cooled gases can be uti-
lized in the shift reaction. Subsequent acid gas removal steps can deal with
COj and HaS at the same time. However, sulfur tolerant shift catalysts must
be employed. Shift conversion after sulfur species removal allows the use of
nonsulfnr-tolerant catalysts but incurs energy penalties for steam addition.
The primary advantage of nonsulfur-tolerant shift catalysts is that a greater
degree of carbon monoxide conversion is attainable, which is desirable for
pure hydrogen and ammonia production. A separate step for C0a removal fol-
lowing nonsulfur-tolerant shift conversion is needed. Shift conversion is
thus not readily separable from acid gas removal in terms of overall facility
design and operation.
Since raw Lurgi gas contains large amounts of unreacted steam, it is
thermodynamically advantageous to conduct shift prior to acid gas removal.
Also, a high degree of carbon monoxide conversion is not needed for indirect
liquefaction or SNG production. Thus, all proposed Lnrgi SNG or indirect
liquefaction facilities in the U.S. feature the use of sulfur tolerant cobalt
molybdate based catalysts, which are active above about 500 E (5,24).
77
-------
Section 3
Purification
In most designs, only a portion of the quenched Lurgi gas (Stream 6)
would undergo shift conversion. This shifted portion (Stream 8) would then be
recombined with the shift bypass stream resulting in a stream with the neces-
sary H2/CO ratio. The portion of the gas to be shifted will depend on the
performance of the gasifier and Rectisol units, the characteristics of the
coal, the activity (or age) of the shift catalyst, and the synthesis operation
requirements. Although shift conversion can follow acid gas treatment,
locating this unit upstream of the acid gas removal unit avoids an additional
acid gas treatment step for the removal of the C02 generated in the shift
reaction.
Figure 3-10 illustrates a typical fixed bed shift conversion process.
All steam required for the shift reaction is supplied by moisture contained in
the partially-cooled Lurgi gases (Stream 6). The two-reactor configuration
serves to control temperatures in the process via feed/product heat exchange.
Available data indicate that cobalt molybdate-based catalysts can also
catalyze the hydrolysis of carbonyl sulfide:
COS + H20 •+ HaS + C02
Further, mercaptans and hydrogen cyanide can be partially hydrogenated to
H2S and ammonia, respectively, over the catalyst. Olefins and aromatics can
also be hydrogenated.
For the three coals examined in this manual, raw Lurgi gases contain H2
and CO in amounts exceeding the theoretical 2:1 ratio required for methanol
(and Mobil M-gasoline) or F-T synthesis. Thus, during steady state operations
and assuming C02 removal in the Rectisol acid gas removal unit to levels of
1 to 3% in the synthesis feed, no shift conversion would be necessary prior to
methanol or F-T synthesis operations. However, to provide flexibility in
78
-------
CATALYST
REGENERATION/
DECOMMISSIONING
OFF-GAS
'
rESKsHj
1
k
r
i
ti SHIFTED GAS TO
^ /T\ ^ SFOONDARY
1
^ J
is
\ /
\ /
X
/ \
/ \
V
t"" L
SPENT
CATALYST
1
^ SH
REAC
N v_X COOLING
k |
TORS \ /
N y INDICATES
\ ' INTERMITTENT
X FLOW
/ \
/ \
M
T \^/
(REGENERATION !
AIR/STEAM |
SPENT
Figure 3-10. High temperature shift conversion
-------
Section 3
Purification
dealing with minor process upsets in either the gasifier or the Rectisol unit,
it is expected that shift capacity for about 10 to 20 percent of the raw gas
would be provided. For analysis purposes though, no shift conversion is
assumed for methanol, Mobil H-gasoline, or F-T synthesis. For SNG synthesis a
shift conversion unit will normally always be required to obtain the necessary
3:1 ratio of Ha to CO.
Shift catalysts in service with hydrocarbon containing gases must be peri-
odically regenerated to remove accumulated coke (carbon) deposits. This is
accomplished by steam injection and controlled oxidation with air to burn off
carbon (and reduced sulfur). An offgas (Stream 211) is produced containing
oxidized sulfur compounds. After a few regeneration cycles, shift catalysts
lose activity due to physical degradation or accumulation of chemical poisons
and must be replaced. Thus, regeneration/decommissioning offgas and spent
shift catalyst (Stream 212) are the wastes from the shift conversion process
(see Section 3 .3 .5) .
3.3.3 Rectisol Acid Gas Removal
The removal of HaS and other sulfur-containing compounds from quenched
and cooled (and shifted if necessary) Lurgi gas is required to prevent cata-
lyst poisoning in the synthesis operations. The removal of most of the C0a
content of the Lurgi gases is necessary to obtain the required synthesis feed
gas Ha:CO ratio. Although there are many acid gas removal processes cur-
rently available, Rectisol is the only process examined in this manual.
Rectisol refers to a generic class of refrigerated methanol-based acid gas re-
moval processes which are licensed worldwide by Lurgi Hineraloltechnik GmbH
(Frankfurt), Linde AG (Munich), and Krupp Koppers GmbH (Essen). In the U.S.,
Rectisol is licensed by subsidiaries of the above firms — Lurgi Corp. USA,
Lotepro Corp., and Gesellschaft fur Kohle Technologie mbH (GET). The Rectisol
process was originally developed primarily to treat Lurgi gases. All existing
80
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Section 3
Purification
and currently proposed Lurgi-based synfuel facilities feature Rectisol designs
by either Lurgi or Linde (Lotepro). The GET Rectisol license is limited to
applications with Koppers-Totzek gasification.
The Rectisol process functions by physically absorbing gaseous components
in refrigerated methano1. The components of quenched and cooled Lurgi gas
have widely different solubilities in cold methanol. As a result, the
Rectisol process can effectively remove gases which are usually considered im-
purities (such as HJS and C02), but only remove minor amounts of useful gases
such as CO, CH4, and Ha.
The Rectisol process basically consists of three sections. In the pre-
wash section, heavy organics (such as naphtha, high molecular weight sulfur
compounds, and gumformers) and water are removed from the inlet gas and pro-
cessed to recover a byproduct naphtha and an aqueous waste. In the absorp-
tion section, sulfur species and C0a are removed from the prewashed gas pro-
ducing an essentially sulfur-free synthesis feed gas. The third section
regenerates the acid gas-laden methanol for recycle to the absorption and pre-
wash sections. Offgases from regeneration constitute the major waste stream
from the Rectisol process.
There is a great deal of flexibility available in designing a Rectisol
unit. Important considerations include the desired composition of the treated
synthesis gas, the composition of the gas to be treated, the desired composi-
tion of the acid gas waste stream(s) generated, capital investment require-
ments, operating costs, and energy usage/recovery. In general, Rectisol units
can be designed to meet the requirements of almost any application, although
some designs may not be economically attractive. Conceptually, Rectisol de-
signs are of two basic types - nonselective Rectisol and selective Rectisol.
81
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Section 3
Purification
These two designs are described below. Important factors which can influence
the characteristics of the waste streams generated by either of the two types
of Rectisol designs are discussed in Section 3.3.5.
In the nonselective Rectisol process (see Figure 3-11), feed gas (Stream
10) is first cooled to approximately 240 to 250 K. The cooled gas then enters
the prewash tower where methanol absorbs water, naphtha, ammonia, and residual
heavy organics such as high molecular weight sulfur compounds and gumformers
from the raw gas. The solvent leaving the prewash column enters the prewash
flash vessel where a flash stream containing H,S and C0a 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 114) from
methanol/water by phase separation. Residual naphtha, HCN, and sulfur species
are stripped from the methanol/water in an azeotrope column. The methanol/
water are subsequently separated in a methanol/water still with the methanol-
containing offgases from the still unit routed to a hot regenerator and the
aqueous still bottoms (Stream 216) sent to wastewater treatment.
After prewash the gas stream enters the main absorber where the bulk of
the acid gases are absorbed. Additionally, some hydrocarbons, Ha, and CO are
absorbed, as in all physical absorption systems. The rich methanol from the
absorber is flashed in several stages. The high pressure flash gas is rich in
valuable compounds (e.g., Ha, CH4, and CO) and is normally recompressed
and added to the inlet raw gas or used as a fuel gas. Flash gases from the
other stages are predominantly C0a and HaS and are combined with the off-
gases from the prewash flash and the hot regenerator. After flash regenera-
tion, 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 regene-
rator to remove the last traces of absorbed gases. The hot regenerated
82
-------
SYNTHESIS
GAS
QUENCHED
LURGI
GAS
oo
H2S-LEAN
ACID
GASES
WATER
MAKEUP
METHANOL
STILL
BOTTOMS
Figure 3-11. Nonselective Rectisol acid gas removal process
-------
Section 3
Purification
methanol is returned via cross-exchange to the top section of the main
absorber, while the regenerator overhead gases are combined with the prewash
and flash regenerator offgases (Stream 213).
Except for the use of a two-stage absorber and two separate flash col-
umns, selective Rectisol (Figure 3-12) is similar to nonselective Rectisol.
After leaving the prewash absorber, the raw gas is contacted with a CO -
saturated methanol stream to remove H2S in the first stage absorber. In the
second stage absorber, pure methanol contacts the H4S-free raw gas from the
first stage absorber to remove C02. The resulting C02~rich methanol stream
is then split into two streams, one of which is sent to the first stage ab-
sorber, while the second stream is sent to a flash and stripping unit. Here,
the C0a is flashed to atmospheric pressure and then stripped with nitrogen
or further regenerated by vacuum flashing, creating a C02-rich stream
(Stream 214) which also contains small amounts of hydrocarbons and H . The
H2S-rich methanol stream from the first stage absorber is routed to a sepa-
rate flash unit. Flash gases from this unit are combined with other sulfur-
bearing offgases generated in the Rectisol unit. The liquid stream from the
H^S flash unit is then regenerated at elevated temperatures to remove the
last traces of absorbed gases before being returned to the absorber.
The concentration of sulfur species in the H S-rich gas and in the CO -
rich gas can be varied by modification of the Rectisol design in order to meet
the given requirements. For a given set of product and pollution control
specifications, Rectisol designs and costs will involve tradeoffs with other
units within an integrated facility. Thus, it is difficult to define a gen-
eric "Rectisol" system without consideration of upstream and downstream pro-
cesses and of constraints imposed by emission limitations and product specifi-
cations.
84
-------
SYNTHESIS
GAS
CO
H2S-RICH
GAS
CO2-RICH
GAS
STILL
BOTTOMS
NAPHTHA
Figure 3-12. Selective Rectisol acid gas removal process
-------
Section 3
Purification
For purposes of this document, the material flows for selective Rectisol
have been primarily based upon EPA test data for the Kosovo partially selec-
tive unit (3). In the Kosovo Rectisol unit, which was not designed with
environmental constraints in mind, the fate of key species may differ from
that in newer or more selective designs where environmental constraints have
been placed upon the process designers. Controls for Rectisol acid gases that
are evaluated and the associated costs in Section 4, to some extent, reflect
the limitations of the Kosovo Rectisol design. Some of the control functions
served by add-on units could be effected within Rectisol itself once the boun-
dary conditions are known. Of course, certain incremental costs of Rectisol
will be incurred with changes aimed ultimately at pollution control, but the
costs of add-on processes would be reduced or eliminated.
Waste streams generated by the non-selective Rectisol design are HsS-lean
acid gas (Stream 213) and methanol/water still bottoms (Stream 216). For the
selective Rectisol design, a C0,-rich acid gas (Stream 214) and a H,S-rich
acid gas (Stream 215) are generated instead of an H2S-lean acid gas. Section
3.3.5 discusses the expected characteristics of these waste streams.
3.3.4 Trace Sulfur Removal
The Rectisol process can routinely achieve sulfur levels down to 0.1
ppmv. However, a guard bed may be employed following the Rectisol unit as
insurance to prevent catalyst poisoning during upset or transient conditions.
Zinc oxide is the most commonly proposed guard bed material. Spent guard bed
material is the only waste produced by trace sulfur removal.
86
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Section 3
Purification
3.3.5 Waste Streams From Gas Purification and Upgrading
Gas Liquor Depressurization Gases (Stream 209)
Some of the gases dissolved in gas liquor under pressure are released
during gas liquor depressurization and tar and oil separation. The available
data on this waste stream are presented in Table 3-13 (1,3). Both of these
sources indicated that this stream was difficult to sample and quantify
accurately. Thus, the composition data presented in Table 3-13 should be
taken only as an indication of the types of constituents expected in gas
liquor depressurization gases. Also, the temperature to which the gas liquor
is cooled prior to depressurization will impact both the flow rate and composi-
tion of the waste stream. The flow rates of this waste stream are estimated
to range from 90 to 190 kg-moles/hr for the base plants examined in this
manual based on information in Reference 1.
Gas Liquor (Stream 210)
Table 3-14 presents data on the expected composition of Lurgi gas liquors
after tar and oil separation but before filtration. After filtration, which
is considered a part of bulk organics removal (see discussion in Section 4.2),
Lurgi gas liquors are expected to contain essentially no suspended tars and
reduced levels of suspended oils. The gas liquors contain large amounts of
dissolved/suspended organics as reflected by high values for BODS, TOC, tar
and oil, phenols, and organic acids. Inorganics present are mainly ammonia
and bicarbonate, with smaller amounts of sulfide, sulfate, sulfite, thio—
cyanate, and cyanide. The gas liquors also contain some trace elements which
were scrubbed from the raw Lurgi gas or leached from the dust removed from the
raw gas.
87
-------
TABLE 3-13. AVAILABLE DATA FOR GAS LIQUOR DEPRESSURIZATION GASES
Component
Westfield Data
(dry basis)
Kosovo Data.
(dry basis)
Vol %
Ha 3-10
Oa + Ar 1-5
Na 3-10
CO 3-8
COa 40-70
CH4 2-6
CaH<
CaH4
Cs's
C4's
Cs's
Of,
ppmv
Benzene
Toluene
Other Aroma tics
HaS 4-10°
COS
CHsSH
CaHsSH
NHj 10-25°
HCN
9.8-11
0.01-1.1
0.01-1.8
1.0-7.2
71-81
3.4-6.1
0.32-0.36
<0. 01-0. 01
0.21-0.45
0.09-0.72
<0. 01-0. 24
1.3-2.0
9600-10,000
1160-1250
135-200
2800-19,000
87-150
910-3400
280-2300
420-20,000
64
aFrom Reference 1; only parameters shown were provided; moisture
content not given.
^From Reference 3; moisture content given as 7.7 percent.
cVolume percent.
88
-------
TABLE 3-14. ESTIMATED CHARACTERISTICS OF LURGI GAS LIQUORS
Constituent
IDS (non-volt tile)
Snlfide (as HaS)
Total S (as S)
Thiocyanate
Cyanide (as HCN)
Carbonate (as COi)
NHi
Monohydrie Phenols
Polyhydric Phenols
Fatty Acids
Tar A Oil
TOC
BOD*
COD
a
pH
Production Rate" (m'/hr)
Rosebud
2.480
55
225
6
5
13,600
7,610
3.860d
680d
2,000
150
7,640d
10.600
22,800
25
8.2
304
Covpoiitian ( in ng/T. axoept
Illinois No. 6*
1.860
290
360
160
37
7,780
4,800
l,940d
340d
380
500
2.980d
4.570d
8.900
95
7.8
507
pB)
Dunn Co."
2,460
49
144
85
46
7,600
2,900«
2,170d
380d
230
300
4,190
5,600d
12,500
1
8.9
441
•Unless noted otherwise these are empirical data fro» Reference 1.
^Unless noted otherwise these are empirical data frost References 9 and 25.
cAdjusted based on coal nitrogen content.
^Distributed based on information in References 9 and 25 to provide
consistency between parameters indicated.
•Flow rates shown are for the liquids synthesis facilities examined. For
SNG synthesis, shift conversion will consume some raw gas moisture and thus
reduce the gas liquor flows by about 5 percent. However, most component
concentrations would then be increased by about 5 percent.
39
-------
Section 3
Purification
Not all of the species/parameters listed in Table 3-14 have been reported
for the subject coals. Unless otherwise indicated, the data represent actual
measurements from testing of the subject coal(s). Where test data are not
available, the values reported in Table 3-14 are extrapolated or adjusted from
test data for other coals (9,25).
The quantity of gas liquor generated is determined mainly by the moisture
content of the raw Lurgi gases, which in turn is a function of the coal mois-
ture content and the steam/coal ratio to the gasifier. The flow rates shown
in Table 3-14 assume no raw gas moisture is consumed by shift conversion
(i.e., the flow rates are for the synthetic liquids facilities examined in
this manual). For SNG production which requires shifting, the flow rates of
gas liquor would be decreased by about 5 percent. However, the concentrations
of most components presented in Table 3-14 would then be increased by about 5
percent.
The organics found in Lurgi gas liquors are a highly complex mixture and
only a few specific compounds have been identified. Table 3-15 presents data
on some specific organics in a gas liquor generated during gasification of a
North Dakota lignite (25). As indicated, the calculated TOC and COD contri-
buted by fatty acids, monohydric phenols, and aromatic amines together consti-
tute about half of the TOC and COD measured in the gas liquor. Based on data
from the Westfield Lurgi facility (26), polyhydric phenols may account for an
additional 20 percent of the total organics. The remaining organics are
thought (27) to be high molecular weight oxygenated compounds, many of which
are not readily biodegradable (as suggested by the high COD/BOD5 ratios in
Table 3-14).
Table 3-16 presents recent data on the levels of certain polynuclear aro-
matic compounds found in gas liquors at the Kosovo plant (3). These data in-
dicate that such compounds are present in gas liquor at levels of 1 mg/L or
90
-------
TABLE 3-15. CONCENTRATIONS OF ORGANIC COMPOUNDS FOUND
IN LURGI GAS LIQUOR (NORTH DAKOTA LIGNITE)
Concentration* Calculated
COBBPlM'd (me/L) COD (ma/L)
Fatty Acids
Acetic Acid
Propanoic Acid
Bntanoic Acid
2-Methylpropanoic Acid
Pentanoic Acid
3-Methylbutanoic Acid
Hezanoic Acid
Total Fatty Acids
Monohvdric Phenols
Phenol
2-Me thylphenol
3-Methylphenol
4-Me thylphenol
2 ,4-Dimethylphenol
3 ,5-Dime thylphenol
Total Monohydric Phenols
Nitrogen Hetarocyeles and
Affiina pi fi Amines
Pyridine
2-Methylpyridine
3-Me thy Ipyri dine
'4-Me thy Ipyri dine
2 ,4-Dime thy Ipyri dine
2 ,5-Dime thylpyridine
2 ,6-Dimethylpyridine
Aniline
Total Nitrogen Heterocycles
and Aromatic Amines
Calculated Totalb
Measured Total
% Unidentified
171
26
13
2
12
1
_J,
226
1.250
340
360
290
120
50
2,410
117
70
26
6
1
1
1
-11
234
2.870
NA
NA
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
28.9
28.9
544
6.738
12.500
46
Calculated
TOC fmg/Ll
68.4
12.7
7.8
1.1
7.1
0.6
0.6
98.3
983
265
277
226
95
J2.
1.866
88.9
53.9
20.0
4.6
0.8
0.8
9.2
9.2
179
2.143
4.190
49
aFrom Reference 25.
"Calculated total values derived from summing the given concentrations.
NA = not applicable.
91
-------
Section 3
Purification
less. These data also show that the Phenosolvan process employed at the
Kosovo plant largely removes these compounds as part of the phenol recovery
step.
TABLE 3-16. CONCENTRATION OF POLYNUCLEAR AROMATIC COMPOUNDS
IN RAW AND DEPHENOLIZED KOSOVO GAS LIQUORS (3)
Constituents
Benz ( a ) anthracene
7 ,12-dimethylbenz(a)anthrancene
Benzo(a) fluoranthrene
Benzo(a)pyrene (BAP)
3-methylchloranthrene
Dibenz( a, h) anthracene
252 Molecular Weight Group
(as BAP)
Gas
Liquor
0.92
0.23
0.68
0.19
<0.004
0.02
1.3
Concentration, mg/L
Dephenolized
Gas Liquor*
<0.008
<0.008
<0.008
<0.008
<0.008
<0.008
0.19
aPhenosolvan process was used.
Shift Catalyst Regeneration/Decommissioning Offgases (Sti
Based on information in Reference 7 for a Lurgi-based SNG facility, shift
catalyst regeneration offgas is estimated to contain 1.1 volume percent SO,
and about 92 percent water, with the remainder being Na and C0}. Using
the frequency of regeneration cited in Reference 7, maximum shift regenera-
tion emissions are estimated to occur for approximately 60 hours per year and
92
-------
Section 3
Purification
at a flow rate of 1800 kg-moles/hr. Thus, annual S0a emissions are calcula-
ted to be about 80 Mg. In addition to SO,, some particnlate matter, CO, and
hydrocarbon emissions are also expected, but no data were available to esti-
mate these.
For indirect liquefaction facilities, shift conversion may be required
only to handle minor process upsets. Thus, for these facilities, the quanti-
ties of shift catalyst regeneration gases would be significantly lower than
those estimated above for SNG synthesis facilities.
Spent Shift Catalyst (Stream 212)
The subject Lnrgi synfuel facilities are calculated to have an inventory
of about 120 Mg of shift catalyst (24). Assuming an average useful life of 3
years, about 40 Mg/year of spent catalyst would be generated. Table 3-17
presents data which indicate the range of concentrations of several elements
expected to be present in spent shift catalyst. Co and Mo are the basic
catalyst elements, and sulfur will always be present since Co-Mo-based cata-
lysts are active only in the sulfided state. Coke or carbon accumulation is a
primary cause of catalyst deactivation. Potentially volatile trace elements
originally present in the feed coal (e.g., As, Pb, Se, and Hg) may also accu-
mulate on the catalyst over time and contribute to loss of shift catalyst
activity. No data are available on the quantities of these elements which
might be found in spent shift catalyst.
93
-------
Section 3
Purification
TABLE 3-17. ESTIMATED COMPOSITION OF SPENT SHIFT CATALYST
Concentration
(wt% of catalyst
Element material) Comment
Co 5-15 Basic catalyst constituent*
Mo 15-25 Basic catalyst constituent*
S 5-20 Derived from coal. Catalyst is
active in snlfided state.
C 5-10 Coke accumulation results in
catalyst deactivation.
Representative catalyst composition would be 20-50% CoMo04 on alumina (28).
HaS-Rich Acid Gases (Stream 215)
This waste stream refers to the concentrated HaS stream generated by
the selective Rectisol design (Stream 215). Table 3-18 summarizes the ex-
pected compositions and flow rates of this stream for the cases in which the
feed gas to the Rectisol unit has not undergone shifting. Similar composi-
tions are expected for feed gas which has been shifted (SNG cases), with the
exception of slightly higher C0a concentrations. Also, the total stream
flow rate would be somewhat higher (10 to 15 percent) for shifted feed gas
cases.
HaS-rich acid gases from a Kosovo—type Rectisol unit are estimated to
contain 4 to 10 percent sulfur species. However, much higher levels of sulfur
species should be obtainable with Rectisol designs of high selectivity; H2S
levels of 25 percent or more are commonly obtained in selective Rectisol
94
-------
TABLE 3-18. ESTIMATED COJIPOSITIONS OF H,S-CONTAINING ACID GASES
FROM RECTISOL (LIQUIDS SYNTHESIS CASES)8
H.S-lean Acid Gases (Stream 213)
Component
H,
N2 + Ar
CO
CO,
CH4
Aliphatics
Aromatic*
»>s
COS
CH,SH
C,n,SH
HCN
NH,
Metbanol
Total Flow,
kg-moles/hr
Subbituminous
0.4
0.1
1.1
93.5
1.0
1.1
0.01
1.5
0.02
0.12
0.03
0.01
<0.01
0.15
5298
Bituminous
0.3
0.1
1.1
92.7
0.8
1.8
0.01
2.8
0.03
0.22
0.05
<0.01
<0.01
0.13
6317
Lignite
0.4
0.1
1.0
93.9
0.9
2.1
0.01
1.3
0.02
0.10
0.02
<0.01
<0.01
0.14
5815
HjS-rich Acid Gases (Strea
Subbituminous
0.2
0.2
3.2
86.4
1.6
3 .0
0.01
4.6
0.05
0.37
0.08
0.03
0.01
0.46
1774
Bituminous
0.2
0.3
3.4
82.1
1.3
2.7
0.01
8.7
0.09
0.70
0.16
0.01
<0.01
0.42
2017
m 215)b
Lignite
0.2
0.2
3.2
86.9
1.6
3.1
0.01
4.0
0.05
0.32
0.07
0.01
<0.01
0.44
1863
All units, except Total Flow, are in mole percent. Data shown are for Rectisol
feed gas which has not been shifted. If the feed gas has been shifted to obtain a
proper SNG synthesis feed composition, the only significant differences would be
.somewhat higher levels of CO, and 10 to IS percent increase in the stream flow rate.
Compositions shown reflect partial B S enrichment.
See Appendix B for assumptions and bases used to estimate stream flows and compositions.
-------
Section 3
Purification
designs by Linde in oil gasification applications. H2S-rich Lurgi acid
gases are also estimated to contain some methanol and about 5 percent hydro-
carbons (nonmethane hydrocarbons are around 3 percent). Data indicating the
total methanol loss for selective Rectisol systems are available (29,30)
although data relating to methanol losses in individual streams have not been
published. Therefore, for evaluation purposes, the entire methanol loss has
been assumed to be associated with the H2S-rich acid gases, resulting in an
estimated methanol concentration of about 0.45 percent.
The distribution of hydrocarbons indicated in Table 3-18 is based mainly
on test data for the Kosovo plant (3). At that plant, the initial gases from
flash regeneration of the HaS-containing methanol are not segregated for
recycle to the inlet gas stream or for use as plant fuel. And, the initial
gases from flash regeneration of the C02-containing methanol are combined
with the H2S-rich acid gases. These initial flash gases will contain appre-
ciable amounts of hydrogen, carbon monoxide, and low molecular weight hydro-
carbons. Thus, lower concentrations of these components would be expected if
the initial flash gases were segregated from the rest of the HaS-containing
regeneration offgases (Rectisol vendors report levels of 2 percent hydro-
carbons can be obtained).
HjS-Lean Acid Gases (Stream 213)
Sulfur containing waste gases from nonselective Rectisol are referred to
as HjS-lean acid gases (as compared to HaS-rich acid gases from selective
Rectisol). Table 3-18 summarizes the expected compositions of these gases.
HjS-lean acid gases contain 1 to 3 percent sulfur species and about 2 to 3
percent hydrocarbons (mostly methane and ethane). Unlike the case of selec-
tive Rectisol above where the organics can be significantly reduced in the
H4S fraction by design modifications, most of the C, to C, hydrocarbons
96
-------
Section 3
Purification
originally present in raw Lnrgi gas will report to the HaS-lean acid gas in
nonselective Rectisol designs. High-pressure flash gases containing absorbed
CO, Ha, and low molecular weight hydrocarbons (mainly methane) are recom-
pressed for recycle in nonselective designs, but this step is already
reflected in the data in Table 3-18.
CO^-Rich Acid Gases (Stream 214)
The selective Rectisol design generates a C0a-rich stream containing
greater than 95 percent CO,. Table 3-19 summarizes the estimated composi-
tions and flow rates of this waste stream. As indicated, C0a-rich acid
gases contain less than about 20 ppmv HaS and about 80 ppmv COS with essen-
tially no mercaptans. If necessary selective Rectisol units can achieve
levels of less than 10 ppmv of total sulfur species in the C0a-rich acid gas
stream. Nonmethane hydrocarbons (mostly ethane) amount to about 2 percent of
the waste stream while aromatics are present only at the low (less than 10)
ppmv level. About two-thirds or more of the C0a in the Rectisol feed gas
ultimately is present in the C0a-rich acid gas stream. Not indicated in
Table 3-19 is nitrogen, which is used for stripping in most selective Rectisol
units. This nitrogen adds about 20 percent to the volume of the CO^-rich
acid gases.
Hethanol vapor will also be present in the C0a-rich acid gases, al-
though no data are publicly available at present to indicate the exact level
of this compound. For analysis purposes all methanol losses from the selec-
tive Rectisol process are assumed to be associated with the HaS-rich acid
gases. Some portion of this methanol will in actuality be contained in the
C0a-rich acid gas and synthesis gases.
97
-------
TABLE 3-19. ESTIMATED COMPOSITIONS OF CO,-RICH OFFGAS
(Stream 214) FROM SELECTIVE RECTISOL*
co
Component
• .. *
N, + Ar, %
CO, %
CO,. %
CH,, %
Aliphatios, %
Aroma tics, ppmv
B,S, pp.v
COS , ppmv
HCN, ppmv
NH, , ppmv
Total Flow,
kg-moles/hr
Liquid*
Subbi tnninons
1.1
<0.1
0.1
96.0
0.4
2.3
4
«
36
10
5
3568
Svnthesis
Bitnaint
0.9
<0.1
0.1
96.7
0.3
2.0
3
16
69
9
5
4341
Casesb
3ns Lignite
0.9
<0.1
0.1
96.1
0.4
2.5
3
7
25
10
5
4001
Snbbltnnii
1.0
<0.1
0.1
96.6
0.4
2.0
3
7
21
10
5
4204
SNO Svnthesis
ions l^tnmii
0.9
<0.1
0.1
97.0
0.3
1.8
4
14
29
10
5
4897
Casesb
ions L*i.ini tb
0.9
<0.1
0.1
96.5
0.3
2.2
4
7
18
10
5
4571
'Composition* shown exclude stripping nitrogen. If included, the total flow would be increased
.by abont 20 percent.
The difference between liquids synthesis and SNO synthesis cases is that the feed gas to the
Rectisol unit has undergone shift conversion for the SNG cases, but not for the liquids cases.
See Appendix B for assumptions and bases used to estimate stream flows and compositions.
-------
Section 3
Purification
Methanol/Water Still Bottoms (Stream 216)
Water contained in the feed gas to the Rectisol unit and process water
added to enhance recovery of byproduct naphtha are recovered from the metha-
nol/water still as a waste stream. The amount of water added for naphtha
recovery was assumed to be five times the weight of naphtha recovered based on
design information from Reference 10. The still bottoms waste stream is
estimated to contain minor quantities (less than 100 mg/L) of dissolved
ammonia, cyanides, methanol, and other organics, plus all of the HC1 present
in the Rectisol feed gas. Table 3-20 summarizes the estimated composition and
flow rates of this stream.
TABLE 3-20. ESTIMATED COMPOSITION OF METHANOL/WATER
STILL BOTTOMS8 (Stream 216)
Component
HCN
NHj
Methanol
Other Organics
HC1
Concentration,
15-20
60-75
45-60
30-40
600-700
mg/L
Estimated compositions based on data in Reference 4.
Estimated flow rates are: Rosebud coal-9.9 m3/hr; Illinois No. 6 coal-
12 mj/hr; and Dunn County lignite-9.9 mVhr.
Spent Sulfur Guard Material (Stream 217)
Most proposed designs of Lurgi-based synthetic fuels facilities do not
indicate use of sulfur guards behind the Rectisol unit. This is a reflection
of the high degree of removal of sulfur species achievable by the Rectisol
unit. As a result of this high degree of sulfur removal, it is difficult to
estimate the generation rate of spent sulfur guard material. In many cases a
sulfur guard may not even be used.
99
-------
Section 3
Product Synthesis
3.4 PRODUCT SYNTHESIS
Four synthesis operations are examined in this manual for converting sul-
fur-free Lurgi synthesis gases into synthetic fuels. Included are production
of substitute natural gas (SNG) via methanation and three liquid fuels syn-
thesis processes: methanol, Mobil M-gasoline, and Fischer-Tropsch. Informa-
tion on SNG synthesis is presented in Section 3.4.1, while information on the
liquids synthesis processes is presented in Section 3.4.2. Section 3.4.3 pre-
sents information on the characteristics of the waste streams generated by the
synthesis operations.
3.4.1 Synthesis of Substitute Natural Gas
Methanation of Lurgi synthesis gases (Stream 12) involves the catalytic
reaction of the hydrogen and carbon oxides in the synthesis gas to produce
methane.
3H2 + CO ->• CH4 + HjO + heat
4Ha + C0a -> CH4 + 2H20 + heat
The resulting product gases have, after dehydration, a composition and higher
heating value comparable to that of natural gas.
The methanation reactions are carried out in steel pressure vessels at
temperatures between 640 K and 760 K. Reactor feed stream requirements in-
clude a maximum concentration of four percent CO (to minimize the temperature
rise across the reactor), a moisture level below saturation at 330 K, and the
essential absence of sulfur and chlorine compounds. Normally a methanation
unit consists of two reactors in series with the second stage used for final
methanation as shown in Figure 3-13. Additional equipment includes heat
exchangers, a knockout drum to condense and remove moisture, and a product
100
-------
10
O)
c
>>
CO
CO
00
i.
o
c
o
O)
I
CO
a>
3
CT>
101
-------
Section 3
Product Synthesis
recycle system. The recycle system helps to control the reactor exit tempera-
ture and permits dilution of the synthesis feed gas to obtain a reactor feed
gas containing less than four percent CO.
Dehydration and compression of SNG is required following methanation if
the SNG (Stream 110) is to be transported over long distances or introduced
into the U.S. natural gas transportation (pipeline) system. A variety of
processes can be used for dehydration. The triethylene glycol dehydration
process is shown in Figure 3-13. Table 3-21 presents calculated material
flows for the SNG synthesis operation.
Waste streams generated by the synthesis of SNG include condensates from
the methanation unit (Stream 228), spent methanation catalysts (Stream 229),
methanation catalyst decommissioning offgases (Stream 230), and dehydration
offgases (Stream 236).
3.4.2 Synthesis of Synthetic Liquid Fuels
Methanol synthesis and hydrocarbon production via Fischer-Tropsch (F-T)
synthesis can be represented by the following reactions:
CATALYST
CO + 2Ha * CHSOH + heat (Methanol Synthesis)
CATALYST
nCO + (2n + .5x)H, * CQH2n+i + nH,0 + heat (F-T Synthesis)
where n ranges from 1 to 20 and is determined by process operating conditions,
and z = 2 for parafins and i = 0 for olefins. Since Lurgi synthesis feed
gases (Stream 12) would usually contain some C0a in addition to CO and H^
and since synthesis catalysts are also active for the interconnecting water
gas shift reaction (CO + HaO ->• C02 + H4), the hydrogenation of C0a may be
represented as follows:
102
-------
TABLE 3-21. ESTIMATED MATERIAL FLOWS FOR SNG SYNTHESIS - ROSEBUD COAL
Stream No.
Stream Name
kg-moles/hr
H2
Oa
Na+Ar
CO
CO a
CH4
ct
Total Dry Gas
kg/hr
HaO
Total, kg/hr
12
Sulfur-Free
Synthesis
Gas
8255
39
158
2103
448
2017
46
13,066
135,664
228 236 110
Methanation Dehydration Product
Condensate* Offgases SNG
123.7
158
2.1
0.1 23.1
0.4 4633.6
4940.5
54,300 204 10
54,332 204 81,128
aBased on data from Reference 10.
Blanks indicate not applicable or no data available.
Number of significant figures overstates the accuracy of the calculated estimates.
-------
Section 3
Product Synthesis
CATALYST
C0a + 3Ha >• CHjOH + HaO + heat (Methanol Synthesis)
CATALYST
nCOa + (3n + .5x)H, >• CnH2n+x + 2nH>° + heat (F~T Svnthesis)
Although the theoretical stoichiometry for synthetic liquids production calls
for a ratio of 2 moles of Ha per mole of CO and 3 moles of Ha per mole of
COj, in practice the following ratio is required (5):
HJ/(2CO + 3C02) = 1.03
The major difference in methanol and F-T synthesis is in the catalysts
used and temperatures and pressures employed. Methanol synthesis is accom-
plished over Cu/Zn-based catalysts at 470 K and 3.5 to 7.0 MPa while F-T syn-
thesis proceeds at pressures up to 2.5 MPa over iron oxide-based catalysts at
590 to 600 K (fluidized bed) and 490 to 530 K (fixed bed) (31).
Mobil M-gasoline synthesis from methanol can be represented as follows:
QH CATALYST +
J a n a
The process employs a zeolite-based catalyst and operates at about 570 to 680
K and 2.1 MPa (5).
For methanol, F-T, and Mobil M-Gasoline synthesis processes, high conver-
sions of synthesis gas are achieved only when gas recycle is employed due to
performance limitations of the catalysts. Complete recycle, however, is not
possible due to the buildup of inert components in the system (e.g., Na, Ar,
CH4). Thus, all synthesis processes produce a purge gas containing inerts
as well as CO and Ha. Variations in process designs for synthesis reactors
104
-------
Section 3
Product Synthesis
reflect different approaches to heat recovery, maximum synthesis gas conver-
sion, minimum recycle, and minimum purge. The discussions below provide some
detail about the subject synthesis processes.
Methanol Synthesis
Methanol production is a fully commercialized technology with a number of
firms offering conversion processes - Lurgi, ICI, Chem Systems, Vulcan-
Cincinnati, Mitsubishi, Nissui-Topsoe, and Selas-Polimex (31). As an example,
Figure 3-14 is a simplified flow diagram of the ICI process. In the ICI pro-
cess, compressed synthesis feed (Stream 12) is mixed with recycle gas and
heated by exchange with methanol product before entering the synthesis reac-
tor. The bulk of the reactor feed enters the top of the reactor while a por-
tion of the gas, which has bypassed remaining heat exchangers, is injected at
various levels in the reactor. The cooler "quench" gases serve as the main
temperature control in the system. Crude methanol vapors which exit the bot-
tom of the reactor are cooled by feed/product heat exchange and expansion in a
turbo-expander before the crude methanol product (Stream 107) is condensed.
Condenser overhead is partially recycled, with a purge stream withdrawn from
the system through an expansion turbine. Depressurization gases from crude
methanol pressure letdown are combined with these purge gases.
In the Lurgi methanol production process, a commercial alternative to the
ICI process, the fixed bed reactor would be replaced by a boiling water
jacketed tube reactor with catalyst in the tubes (5). In the Lurgi case, iso-
thermal reactor operation is realized and no gas quench is necessary. In all
methanol synthesis processes, large amounts of heat are recovered as medium
pressure steam.
105
-------
RECYCLE GAS
SPENT
CATALYST
I
SULFUR-FREE
SYNTHESIS
GAS
COMPRESSOR
METHANOL
SYNTHESIS
REACTOR
STEAM
BFW
;\_
PROCESS f (y\
WATER ' \$S~\
HOT
WATER
(
V
1
TURBO
EXPANDER PURGE
GAS
METHANOL EXPANSION
SEPARATOR VESSEL
TURBO
EXPANDER
EXPANSION
GASES TO
METHANATION
FUEL GRADE
METHANOL TO
STORAGE
METHANOL
WASTEWATER
LEGEND:
INDICATES
INTERMITTENT
FLOW
Figure 3-14. ICI methanol synthesis process
-------
Section 3
Product Synthesis
Regardless of the specific process employed, all methanol synthesis pro-
cesses generate a continuous purge gas stream (Stream 18) and, on an intermit-
tent basis, spent catalyst (Stream 222). The purge gas (plus depressurization
gases) are useful as sulfur-free fuel gases or feed gases for production of co-
product SNG (Stream 110). If the crude methanol product is distilled to pro-
duce a fuel grade methanol product (Stream 117) an aqueous waste stream
(Stream 237) is generated.
Table 3-22 presents a calculated material balance for methanol synthesis.
As indicated in this table, a large amount of purge gas is produced due to the
high methane content of the Lurgi synthesis feed gas. These purge gases are
subsequently methanated to produce a SNG coprodnct as discussed later in this
section.
Mobil M—Gasoline Synthesis
The Mobil M-Gasoline process is depicted in Figure 3-15 (32). Crude
methanol (Stream 107) is vaporized by heat exchange with the reactor product
and fed to the dimethyl ether (DME) reactor where it is catalytically con-
verted to an equilibrium mixture of methanol, dimethyl ether, and water vapor.
DME reactor product is subsequently converted to hydrocarbons in Mobil M-
Gasoline reactors, with temperature control obtained by recycling cooled gas
from product separation. The DME reactor inlet conditions are about 570 K and
2.3 MPa while M-Gasoline reactor inlet temperature is about 600 K. Product
vapors from the M-Gasoline reactors are cooled by methanol feed heat exchange,
by generation of steam in a waste heat boiler, and by air cooling. Crude
liquid product is separated in a knockout drum. Drum overhead is split into a
recycle stream and a purge stream. The bulk of the liquid product is sent to
the product fractionation unit, with a small slipstream injected at the inlet
107
-------
TABLE 3-22. ESTIMATED MATERIAL FLOWS FOR METHANOL SYNTHESIS - ROSEBUD COAL*
Stream No. 12
Stream Name Feed Gas
kK-moles/hr
H, 7596
N,. Ar. 0, 197
CO 2749
' CO, 606
CH4 2017
Ct 46
CH.OH
ROH+HCt
Total dry gas 13.211
kK/hr
B,0
Total, kg/hr 158.451
117 237
Fuel Grade Methanol
Methanol Wastewater
0.04
0.01
0.03
5.7
1.1
0.25
2797 1.6
2.5 0.57
88 5202
90,080 5289
18 228
Purge Gas To Me tht nation,
Methanation Condensate
1608
158
190
310 0.05
2016 0.2
45
42
0.89
4370
10 20,180
61.680 20,180
231
CO, Removal
Offgas
0.1
0.1
0.001
70
2.4
72
78
3180
236 110
Dehydration Co-Product
Offgas SNO
80
158
0.95
3
2521
2763
329 4
329 46,200
bnaseo on oata iron Keterence S unless otherwise noted.
Based on data froai Reference 10.
Blanks indicate not applicable or no data available.
Number of aignificant figures shown overestimates the accuracy of the calculated estimates.
-------
M GASOLINE REACTORS
O
VO
REGENERATION HEADER
RECYCLE,* HEADER
r rf rfrrf ";
t t >•"""• t >
REGENERATION HEADER
CATALYST
REGENERATION
OFF^SAS
PROCESS
HEATER
SPENT ~-. FROM DME 1
MOBIL ^ (223V j M GASOLINE
CATALYST —' REACTORS
AIR
COOLER
RECYCLE GAS
COOL
BFW !
PURGE GAS
FOR IN PL ANT
FUEL USE
1
CRUDE
HECYC
YDROCARBONS """
LE LIQUID
PRODUCT
FRACTIONATION
~^9
TPQT®-
GASOLINE
OFF GAS
• TOCO2
REMOVAL
AQUEOUS
CONDENSATE
Figure 3-15. Mobile M-gasoline synthesis and product recovery (32)
-------
Section 3
Product Synthesis
to the boiler feed water heat exchanger to control durene crystallization.
The aqueous condensate from the knockout drum (Stream 225) constitutes the
only continuous waste stream from the process.
Both the DME catalyst and M-Gasoline catalyst require periodic regenera-
tion. The DME catalyst accumulates coke slowly and requires regeneration per-
haps once or twice per year. The M-Gasoline catalyst requires regeneration
about every two weeks to remove coke (5). Regeneration is accomplished using
Na to purge hydrocarbons from the system followed by air injection. Control
of inlet Oa level and injection of cooled recycle gas to the system maintain
combustion temperatures below 760 K. Regeneration offgas is cooled by ex-
change with fresh regeneration gas and by air cooling. Any water of combus-
tion is condensed in a knockout drum before depressurization and venting to
the atmosphere. As depicted in Figure 3-15, five M-Gasoline reactors consti-
tute a "train" with one reactor being regenerated while four are in service.
Thus, regeneration is more-or-less continuous, resulting in the routine gener-
ation of an offgas.
Table 3-23 presents calculated material flows for Mobile M-Gasoline
synthesis. A large methanol synthesis purge stream is produced which accounts
for over half of the total product heating value. This stream, along with the
fractionation offgas is subsequently converted to coproduct SNG (Stream 110).
Most of the remaining fuel value is recovered as gasoline (Stream 108), with
lesser amounts of LPG (Stream 109) also produced.
The methanol conversion condensate waste (Stream 225) contains the oxy-
genated organics (ketones, acids) which are generated in small amounts in the
Mobil M-Gasoline reactors. Other waste streams generated by Mobil M-Gasoline
synthesis include Mobil M catalyst regeneration offgases (Stream 224) and
spent catalysts (Stream 223).
110
-------
TABLE 3-23 . ESTIMATED MATERIAL FLOWS FOR MOBIL M-GASOLINE SYNTHESIS - ROSEBUD COAL
*.b
Stream No.
Stream Name
kg-aoles/hr
H,
Ni.Ar.O,
CO
COi
CH<
C»S
CHiOH
ROH+HCs
Cts
Cts
Organic acida
Ke tones
Total dry gaa
kg/hr
H,0
Total, kg/hr
12
Feed Gas
to Methanol
Synthesis
7596
197
2749
606
2017
46
13,211
158,451
18
Purge and
Ezpanaion
Gases to
Methanation
1608
158
190
310
2016
45
42
0.89
4370
10
61,680
107
Crude
Methanol
0.05
0.02
0.03
6.7
1.3
0.3
2799
3.1
5298
95,430
225
Mobil
Synthesis
fsstewater
0.02
1.2
0.6
4.8
3.6
55,450
55,990
226 228
Fractionation
Offgases to Methanation
COi Removal Condensate0
0.7
0.01
0.3
6.3 0.05
19 0.2
5.8
2.1
2.4
36
35 20,180
1022 20,180
231
CO,
Removal
Offgas
0.1
0.1
0.001
76
2.6
0.005
79
85
3460
236 110
Dehydration SNG
Offgas Co-product
81
158
1.3
3
2539
5.8
2.1
2.4
2793
332 4
332 45,820
*Main products from Mobil H-Gasoline Syntheais are: Blended Gasoline (108) - 32.510 kg/hr; C. LPG (109) - 1756 kg/hr; C, LPG (109) - 2972 kg/hr
Based on data from Reference 5 unless otherwise noted.
Based on data from Reference 10.
Blanks indicate not applicable or no data available.
Number of significant figures shown overestimates the accuracy of the calculated eatimatea.
-------
Section 3
Product Synthesis
Fischer-Tropsch (F-T) Synthesis
The F-T process can produce a wide range of products from methane to
heavy fuel oil. Generally, fluidized bed designs operating at higher tempera-
tures produce a lighter mix of products than fixed bed designs. For the
purpose of analysis, it was assumed that the fluidized bed design similar to
that used at Sasol, S.A. (called the Synthol process) would be utilized in the
U.S. since major emphasis in synfuels production would be on light motor
fuels. However, even the Synthol process produces a range of products from
middle distillates to methane. A Lurgi-based F-T synthesis facility could be
designed to produce mostly liquid products by: 1) steam reforming of methane
and other light hydrocarbons for recycle and/or 2) catalytic cracking of
heavier oils. Such an approach, however, would result in low overall thermal
efficiencies due to extensive heat losses. Thus, a mix of hydrocarbon pro-
ducts including SNG, LPG, gasoline, diesel fuel, and alcohols is viewed as a
more practical scenario for U.S. facilties and is the route used for analysis
purposes in this manual.
Figure 3-16 is a flow diagram of the Synthol process (5). Purified
synthesis gas (Stream 12) and recycle gas are compressed together and heat
exchanged against hot reactor product. Synthesis gas is mixed with circulat-
ing iron catalyst in the Synthol reactor where the synthesis reactions pro-
ceed. Reaction heat is removed by hot oil circulating in tubes internal to
the reactor. Catalyst and vapor products are separated in a cyclone system
and catalyst solids are recycled. Crude product vapors are cooled in a hot
wash tower which uses cooled F-T recycle oil as the wash medium. Heat is
recovered via feed/product exchange and by generation of steam in waste heat
boilers.
Heavy oil condensate is sent to product fractionation while hot wash
tower overhead is sent to a cold wash tower for recovery of lighter oils.
112
-------
PURGE GAS TO
MCTHANATION
OFF GASES
TOSNG
CO PRODUCTION
WASTEWATER
Figure 3-16. Fischer-Tropsch (Synthol) synthesis and product recovery (5)
-------
Section 3
Product Synthesis
In the cold wash tower, cool process water spray effects condensation of
most of the light hydrocarbons. Oxygenated organics (alcohols, ketones,
acids) become dissolved in the aqueous condensate. Liquid light oil is fur-
ther washed with process water and sent to product fractionation. The aqueous
condensate is sent to alcohol recovery where the wastewater is steam stripped
and hydrogenated to recover a mixed alcohol product (Stream 105). Stripper
bottoms (Stream 219), containing mostly organic acids, constitute the aqueous
waste from the F-T process. Overhead vapors from the cold wash tower are
split into a recycle and a purge stream, with the latter sent to light ends
recovery.
Table 3-24 presents calculated material flows for F-T synthesis. Over
half of the heating value of F-T products is accounted for by the purge gas
(Stream 14) and fractionation unit offgas (Stream 220) which are subsequently
converted to SNG (Stream 110). F-T products are about 80 percent gasoline
range hydrocarbons (Stream 100) and 20 percent diesel/fuel oil hydrocarbons
(Streams 101 and 102). Alcohols (Stream 105) represent significant chemical
byproduct(s).
Wastewater generated in the alcohol recovery unit (Stream 219) and spent
MT catalyst (Stream 218) are the major wastes from F-T synthesis.
F-
Crude Synthetic Liquid Fuels Upgrading
The crude liquid fuel products of methanol, F-T, and Mobil M-Gasoline
synthesis processes will require upgrading (probably on site) to yield final
products which are marketable as substitutes for petroleum-derived products.
This is particularly true for motor gasolines, where crude coal-derived gaso-
line fractions would not meet octane requirements for the retail market in the
U.S. F-T and Mobil M-Gasoline products could be upgraded by HF alkylation of
the C3-C4 fraction to yield gasoline-blend hydrocarbons and commercial
114
-------
TABLE 3-24. ESTIMATED MATERIAL FLOWS FOR FISCHER-TROPSCH SYNTHESIS - ROSEBUD COAL
a.b
Stream No.
Stream Name
k«-moles/hr
H,
N,,Ar,0,
CO
CO,
0*4
c,»
c,«
ct-
Organic Acids
Total dry gas
k»/hr
H,0
Total, kg/hr
12 14 219 220 228
Feed Gas Purge Gsses Wastewater Fractionation
to F-T to From Alcohol Offgases to Metbanation
Synthesis Methanation Recovery CO, Removal Condensate
7596 1363 8.2
197 155 2.6
2749 84 1.6
606 310 160 0.04
2017 2129 161 0.14
46 83 99
33
0.8 0.2
13.6
13,211 4126 466
75,900 332 18.300
158,451 59.760 76.720 14.390 18.300
238 231
Wastewater CO, Removal
From CO, Offgas
0.3
0.4
0.01
219
7.8
0.2
0.1
228
358 247
358 10.040
236 110
Dehydration Co-Product
Offgaa SNG
89
157
2
14
2766
99
33
0.2
3160
375 5
375 53.930
*Main products from Fiscber-Tropscb Synthesis are: Blended Gasoline (100) - 19,660 kg/hr
C, LPG (106) - 1284 kg/hr
C4 LPG (106) - 195 kg/hr
Diesel Oil (101) - 3986 kg/hr
Heavy Fuel Oil (102) - 1167 kg/hr
Mixed Alcohols (105) - 3380 kg/hr
Based on data from Reference 5 unless otherwise noted.
Based on data from Reference 10.
Blanks indicate not applicable or no data available.
Number of significant figures shown overstates the accuracy of the calculated estimates.
-------
Section 3
Product Synthesis
grade LPG, by naphtha hydrotreating (in the F-T case) for destruction of ole-
fins and oxygenated organics, by catalytic reforming of naphtha to produce
more cyclic and branched chain hydrocarbons, by Cf/Cf isomerization to in-
crease the anti-knock quality of pentanes and hezanes, and by catalytic poly-
merization to convert propene/butene fractions into higher molecular weight
gasoline blending compounds. All of the upgrading facilities are expected to
be able to use currently available petroleum refinery technology. Of course,
the specific characteristics of the crude synthetic liquids must be considered
in the design of the upgrading facilities.
Since the feed streams to the upgrading processes in an indirect lique-
faction plant are not expected to have any unusual characteristics relative to
current refinery experience, waste streams generated during these upgrading
operations are not expected to present any unique treatment problems. For
these reasons, and due to the multiplicity of possible options for product
upgrading, waste stream characteristics and pollution control alternatives for
product upgrading processes are not specifically discussed in this PCTM.
SNG Coproduction.
All of the synthetic liquid fuels synthesis processes generate a purge
gas containing large amounts of methane and nnreacted CO and Ha. Several
options are available to handle the purge gas including use as an onsite
fuel, reforming to generate additional synthesis gas, or conversion of the re-
sidual hydrogen and carbon oxides into methane to produce SNG. Because Lurgi-
derived synthesis gases initially contain large amounts of methane and because
SNG has considerable market value, the methanation option was selected for
analysis purposes in this PCTM. In actual practice the decision regarding the
disposition of synthesis purge gases involves site- and design-specific consi-
derations which are outside the scope of this manual. The methanation reac-
tions are the same as those discussed earlier in Section 3.4.1 on Synthesis of
116
-------
Section 3
Product Synthesis
SN6. Following methanation, residual C03 and moisture are removed and the
co-product SNG is compressed to pipeline pressure for distribution. Any of a
number of processes can be used for 00, and H20 removal. The HEA and tri-
ethylene glycol processes are shown in Figure 3-17.
Waste streams produced by the coproduction of SNG include methanation
(Stream 228) and C02 removal (Stream 238) condensates, C03 containing off-
gases (Stream 231), dehydration offgases (Stream 236), methanation catalyst
decommissioning offgases (Stream 230), and spent methanation catalyst (Stream
229).
3.4.3 Waste Streams Generated by Synthesis Operations
The product synthesis and upgrading operations do not routinely generate
any unique gaseous waste streams. Nonunique waste streams generated include
flue gas from process heaters, C03 removal offgas from the coproduction of
SNG, and SNG dehydration offgas. However, periodic regeneration or decommis-
sioning of synthesis catalysts results in the generation of offgases. In
addition, spent catalysts represent solid wastes. Aqueous wastes are rou-
tinely generated by methanol, F-T, Mobil M-Gasoline, and SNG synthesis. In
the methanol, F-T, and Mobil cases, these wastewaters contain alcohols and
oxygenated organics. In the SNG case, condensates contain only dissolved
gases and are considered clean and reusable.
Spent Methanol Synthesis Catalyst (Stream 222)
No data are currently available in the public domain relating to the
characteristics or quantity of spent methanol catalyst. For the subject faci-
lity a catalyst inventory of 150 Mg having a useful life of 3 to 5 years is
assumed. Therefore, based on these assumptions, the maximum annual spent
catalyst rate is 50 Mg.
117
-------
00
CATALYST
DECOMMISSIONING
OFF^AS
FR"
CAT*
i
1
f — ^S
L
> *
§
rSH I BFW
LYST (A
7
^ i
r
"J
I
>
^
1
f
FHACTIONATION
OFF GASES
DEHYDRATION
OFF GASES
Q
COMPRESSOR
METHANATOR
FEED
COMBINED
CONDENSATES
Figure 3-17. Methanation, C02 removal, and drying for co-production
of SNG with synthetic liquid fuels
-------
Section 3
Product Synthesis
Spent F-T Catalyst (Stream 218)
As with methanol catalyst, no data are currently available on the proper-
ties of spent F-T catalyst. In addition, the metal compositions other than
iron which are used in formulations of fresh catalysts are proprietary. For
the subject facilities, it is estimated that there will be about 3500 Mg/yr of
spent F-T catalyst (5).
Spent Mobil Catalysts (Stream 223)
Mobil catalysts are zeolite-based (synthetic clay-like) materials. No
data are publicly available at present on the characteristics of these
catalysts. Host zeolites are essentially inert in aqueous environments. How-
ever, it is possible that trace metals such as Zn, Co, Cu, and Cr may be
leached from the waste. It is estimated that the subject facilities would
generate about 40 Mg year of spent DME catalyst and about 150 Mg/year of spent
M-Gasoline catalyst (5).
Mobil Synthesis Catalyst Regeneration Offgas (Stream 224)
Based on design data contained in a Mobil report (5) concerning the
number of catalyst vessels, regeneration frequency, regeneration duration, and
offgas volume, it is anticipated that catalyst regeneration will occur over a
period of about 3800 hours per year with an average flow rate of approximately
100 kg-moles/hr. Pollutants expected in this offgas stream include CO at
approximately 1 percent by volume, organics (from purging), and perhaps parti-
culates.
119
-------
Section 3
Product Synthesis
Spent Methanation Catalyst (Stream 229)
Nickel-based methanation catalysts are eventually deactivated by physical
degradation of crystal size and by chemical accumulation of poisons such as
sulfur. The quantity of spent catalyst is estimated to average about 20
Mg/year.
Methanation Catalyst Decommissioning Offgas (Stream 230)
Methanation catalyst contains nickel in reduced form and is thus pyropho-
ric in nature. Prior to removal of spent catalyst from the bed, the material
is oxidized with air in a controlled manner to convert nickel to its oxide.
No information is available on the characteristics of the catalyst decommis-
sioning offgas. However, the possibility exists that nickel compounds, such
as Ni(CO)4, could be produced during decommissioning.
F-T. Mobil M. and Methanol Synthesis Wastewaters
Waste-waters or condensates generated by these synthesis operations will
contain varying levels of dissolved organics (mainly water soluble organics
such as acids, ketones, alcohols, etc.). However, they will contain no to
very low levels of dissolved inorganics, trace elements, or sulfur or nitrogen
species due to the absence (or near absence) of inorganics, sulfur, and nitro-
gen species in the synthesis feed gas.
Condensates generated by the alcohol recovery step in Fischer-Tropsch
synthesis (Stream 219) are estimated to have the following gross characteris-
tics (5):
Production rate 72-77 m3/hr
Organic acids 11,000-13,000 mg/L
COD 11,000-13,000 mg/L
BOD, 8,000-9,000 mg/L
TOC 4,300-4,800 mg/L
120
-------
Section 3
Product Synthesis
Condensates generated by the Mobil product separation step (Stream 225)
are estimated to have the following gross characteristics (5,24):
Production rate 56-59 m3/hr
Organic acids 3,800-4,100 mg/L
Ketones 3,800-4,100 mg/L
C6+ hydrocarbons 1,100-1,200 mg/L
COD 16,000-18,000 mg/L
BODj 11,000-12,000 mg/L
TOC 4,800-5,200 mg/L
The levels of contaminants could be lower than those shown above, depending on
the specific catalyst employed and whether or not chemicals recovery from the
condensate is practiced.
Methanol synthesis wastewaters (Stream 237) generated by distilling crude
methanol to obtain a fuel grade methanol product are estimated to have the
following gross characteristics (5):
Production rate 1.5-5.3 m3/hr
Alcohols 17,000-36,000 mg/L
COD 31,000-77,000 mg/L
BOD, 22,000-54,000 mg/L
TOC 7,800-19,000 mg/L
The production rate of this wastewater is determined largely by the C02
content of the synthesis feed gas; as the level of C02 increases, the pro-
duction rate of wastewater increases. The mass loading of propanol in this
wastewater was assumed to be proportional to the quantity of carbon oxides
converted (a relatively constant value for all coal cases). Therefore, the
concentrations of propanol (and total alcohols) in this wastewater are
inversely proportional to the wastewater production rate.
For all of the synthesis wastewaters listed above, the COD, BODJt and
TOC values are calculated estimates. All BOD, values were estimated as 70
121
-------
Section 3
Product Synthesis
percent of the calculated COD values. COD and TOC values were calculated by
assuming the organic acids were acetic acid, the ketones were acetone, and the
alcohols were a mixture of methanol and propanol.
Methanation Condensate (Stream 228)
Water contained in crude SNG is condensed under pressure and is estimated
to contain about 125 mg/L CH4 and 100 mg/L of C02 (10). The quantity of
methanation condensate generated depends on the synthesis operation and coal
gasified. For the SNG synthesis facilities methanation condensate is gener-
ated at approximately 55 ma/hr. In the indrrect liquefaction facilities, the
SNG coproduction unit is smaller and hence the quantities of condensate are
smaller. Estimated flow rates range from 8 to 20 mj/hr. Since this stream
contains essentially no dissolved solids, it could be reusable as boiler feed
water after depressurization and air or N} stripping to remove dissolved
gases. For this reason, methanation condensate is more appropriately consi-
dered an internal process stream rather than a waste stream.
Removed C0a (Stream 231)
In most cases, residual C0a in the crude SNG from SNG synthesis facili-
ties will not require removal. However, in indirect liquefaction facilities
residual C0a in the crude SNG is higher and would be removed to obtain a
pipeline quality gas. Since amine processes for CO2 removal will remove
some CO, H2, and hydrocarbons, the C0a offgas from an amine process will also
contain these constituents. The estimated composition of the C0a removal
offgases is (5):
122
-------
Section 3
Product Synthesis
C0a 91 vol %
CO 20 ppmv
Hj 200-1400 ppmv
CH4 3 vol %
Noomethane hydrocarbons 100-1100 ppmv
Ha 5.7 vol %
N2 1700-3100 ppmv
The flow rate of the removed C02 stream is estimated around 24 to 83
kg-moles/hr for methanol and Mobil M synthesis. For F-T synthesis the flow
rate is approximately 240 to 260 kg-moles/hr.
COg Removal Wastewater (Stream 238)
The fractionation offgas sent to the C0a removal unit in an F-T synthe-
sis facility is estimated to contain appreciable quantities of water. As a
result, a wastewater is generated in the C0a removal step. The flow rate of
this waste stream is estimated at approximately 0.4 m*/hr. Composition data
are not available for this waste stream, but it should contain only minor
quantities of dissolved gases such as C03. As such it could be combined
with the methanation condensate for reuse within the facility.
Dehydration Offgas (Stream 236)
The triethylone glycol regenerator offgas contains very small amounts of
methane and the glycol solvent. No data are available to quantify these con-
stituents. The offgas is estimated to have a flow rate of about 11 to 21 kg-
moles/hr and to consist mostly of water vapor.
123
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Section 3
Products/Byproducts
3.5 PRODUCTS AND BYPRODUCTS
The products/byproducts considered in this section include: 1) those
produced as substitutes for petroleum-derived fuels or chemicals, 2) Lurgi by-
products, 3) sulfur and ammonia recovered as a result of air and water pollu-
tion control and, 4) excess coal fines. The substitutes for petroleum-derived
fuels include methanol, Fischer-Tropsch liquids, Mobil M-Gasoline, LPG, and
SNG. The Lurgi byproducts include tar, oil, naphtha, and phenols. The avail-
able data on the composition of each product and byproduct are presented in
this section. These data are included to provide a general understanding of
the nature of these products and byproducts. Because speciation data on these
substances are limited, the data presented are not sufficient, nor intended,
to provide a basis for risk evaluation judgements.
3.5.1 Methanol Synthesis Product
Methanol is produced primarily from natural gas. The composition of the
crude product varies somewhat depending upon such factors as the specific
synthesis process used, the synthesis pressure and temperature, and the
H2/CO ratio in the synthesis feed (33). The primary reaction in methanol
synthesis is:
CO + 2H2 »• CH,OH + heat
However, a number of side reactions also take place which introduce impurities
into the crude methanol. A representative, but not exhaustive, list of impur-
ities which can be expected in crude methanol is presented in Table 3-25. An
additional potential impurity not shown in the table is iron carbonyl. Under
certain conditions the formation of this compound has been observed in the
compression and synthesis sections of methanol plants (34). The use of
special alloys could reduce or eliminate this occurrence.
124
-------
TABLE 3-25. COMPONENTS REPORTED IN COMMERCIAL METHANOL (33)
Dimethyl Ether
Acetaldehyde
Methyl Formate
Diethyl Ether
n-Pentane
Propionaldehyde
Methyl Acetate
Acetone
Methanol
Isopropyl Ether
n-Hexane
Methyl Propionate
Ethanol
Methyl Ethyl Ketone
t-Butyl Alcohol
n-Propanol
n-Heptane
Water
Methyl Isopropyl Ketone
Acetal
Isobutanol
n-Butyl Alcohol
Isobutyl Ether
Diisopropyl Ketone
n-Octane
Isoamyl Alcohol
4-Methyl Amyl Alcohol
n-Amyl Alcohol
n-Nonane
n-Decane
125
-------
Section 3
Products/Byproducts
Synthesis gases derived from coal gasification have many similarities to
those derived from natural gas reforming; however, they also have some impor-
tant differences. Lurgi-derived synthesis gases have high concentrations of
methane and other light hydrocarbons which may affect the activity and selec-
tivity of traditional synthesis catalysts. Of course, operating experience is
needed to assess whether these differences will have an impact upon product
purity.
Table 3-26 shows an estimated composition of a crude methanol (Stream
107) made from coal. The amounts and types of impurities present will vary
somewhat depending upon the specific synthesis process used and process con-
ditions. However, water is expected to be the largest single impurity (5
percent) with all others comprising less than one percent. Several methods
for purifying methanol are currently available (33), and the degree of
methanol purification will largely be determined by user needs. Thus, coal-
derived methanol in commerce may range in purity from about 95 percent pure in
the case of the crude product to 99.85 percent pure for Grade AA methanol.
TABLE 3-26. ESTIMATED COMPOSITION OF CRUDE METHANOL
(Stream 107) FROM COAL (24)
Compound Concentration
CH3OH 94.6 wt %
CjHsOH, C3H7OH and C4H9OH 2800 ppm
(CH3)aO 150 ppm
Nonmethane HCs 600 ppm
H20 5.0 wt %
126
-------
Section 3
Products/Byproducts
3.5.2 Fischer-Tropsch Liquid Products
The crude Fischer-Tropsch synthesis product is composed primarily of
straight-chained paraffinic and olefinic hydrocarbons (35). Minor quantities
of aromatic, naphthenic, and branched-chain hydrocarbons are also present,
along with small amounts of oxygenated compounds such as alcohols, aldehydes,
ketones, and acids, most of which have fewer than five carbon atoms (36). The
crude F-T product can be refined into several different products including
LPG, gasoline, diesel oil, heavy oil, methanol, acetone, methyl ethyl ketone
(MEK), and heavy alcohols. Much of the chemical composition data presented
here is based on analyses of products from the commercial-scale Fischer-
Tropsch synthesis plant which is currently operating in Sasolburg, South
Africa.
Limited data on the composition of gasolines (Stream 100), diesel oils
(Stream 101), and heavy oils (Stream 102) from F-T synthesis indicate that
they are essentially nitrogen-and-sulfur-free (37). Crude Fischer-Tropsch
gasoline requires upgrading prior to its use as a motor fuel. Table 3-27
shows the estimated chemical composition, by compound class, of the finished
Fischer-Tropsch gasoline. The aromatics content (17%) is lower than that of
typical petroleum gasolines (23-26%). The saturates content is similar to
that of petroleum-derived gasoline, but the olefins content is much higher.
The estimated Reid Vapor Pressure of 69 kPa for finished Fischer-Tropsch
gasoline is within the range of values (48 to 100 kPa) for typical petroleum
gasolines (41).
Table 3-28 shows the distribution of the oxygenated byproducts from fluid
bed Fischer-Tropsch synthesis before further refining. At the SASOL plant,
the aldehydes are hydrogenated and methanol is reported to be used on site as
Rectisol solvent makeup. Ethanol, propanol, bntanol, pentanol, acetone.
127
-------
TABLE 3-27. ESTIMATED COMPOSITION OF FINISHED INDIRECT COAL LIQUEFACTION
UNLEADED GASOLINES AND TYPICAL PETROLEUM GASOLINES
K>
OO
Fi sober- Tr ops ch
Unleaded Gasoline
Component (Refs. 5, 37)
Saturates, vol% 63
Olefins, vol% 20
Aromatics, vol% 17
Sulfur, wt% Nil
Nitrogen, wt% Nil
Oxygen, wtlb —
Finished Crude Petroleum-Derived
Unleaded Mobil-M Mobil M-Gasoline Gasolines
Gasoline (Ref. 5) (Ref. 5) (Refs. 38, 39, 40)
60 56 56-69
11 13 4-8
29 30 23-36
Nil -- 0.014-0.417
— 0.50-0.49
— — 0.18-0.22
— Indicates no data available.
-------
TABLE 3-28. DISTRIBUTION OF OXYGENATED BYPRODUCTS FROM
FLUID-BED FISCHER-TROPSCH SYNTHESIS (37)
Component Wt %
Acetaldehyde 3.0
Propionaldehyde 1.0
Acetone 10.6
Methanol 1.4
Buty r al dehy de 0.6
Ethanol 55.6
Methyl Ethyl Eetone 3.0
i-Propanol 3.0
n-Propanol 12.8
2-Butanol 0.8
EEK-MPK 0.8
i-Butanol 4.2
n-Butanol 4.2
n-BntyIketone 0.2
2-Pentanol 0.1
n-Pentanol 1.2
C6+ alcohols 0.6
129
-------
Section 3
Products/Byproducts
methyl ethyl ketone, and a higher alcohol fraction are distributed commerci-
ally (37). SASOL also converts propylene and butylene from the light ends
recovery to gasoline by polymerization over a solid phosphoric acid catalyst.
The propane and butane are sold as LPG (42).
3.5.3 Mobil M-Gasoline
The Mobil M-Gasoline synthesis product is fractionated into a gasoline
(Stream 108) and an LPG product (Stream 109). Table 3-27 shows the estimated
composition of the finished Mobil M-Gasoline. It can be seen from this table
that the olefins content of the Mobil M-Gasoline is higher than that of petro-
leum gasoline, while the saturates and aromatics contents are within the
ranges found in petroleum gasolines. The benzene content of the finished
Mobil M-Gasoline is also reported to be less than the one percent by volume
which is typical of petroleum gasolines (41). As was mentioned earlier, iron
carbonyl could be present in trace quantities in the methanol feed. It is,
however, expected that any carbonyls in the methanol feed would be trapped by
the gasoline synthesis unit's zeolyte catalyst and thus would not be present
in the gasoline product.
Table 3-29 shows the blending compounds of an estimated finished gasoline
product in a conceptual design of a Lurgi-based, Mobil M-Gasoline plant. It
TABLE 3-29. ESTIMATED BLENDING COMPONENTS FOR MOBIL M-GASOLINE (25)
Component Wt %
Mixed butanes 2.4
Alkylate 3.2
Stabilized Gasoline 87.8
Hydrotreated Gasifier Naphtha 6.6
100.0
130
-------
Section 3
Products/Byproducts
can be seen that the stabilized gasoline fraction constitutes almost 88 weight
percent of the finished gasoline and hydrotreated Lurgi naphtha constitutes
nearly 7 percent. The estimated Reid Vapor Pressure of the finished gasoline
is 69 kPa (5), which is within the range of values for typical petroleum
gasolines (48 to 100 kPa) (41). The finished gasoline is reported to contain
essentially no sulfur (5). The stabilized gasoline fraction from the synthe-
sis unit may also be used for blending with petroleum gasoline. Although the
chemical composition of the stabilized gasoline component of the finished
gasoline product is fairly well characterized, no actual data on the chemical
composition of the finished gasoline liquid or its vapors are yet available.
3.5.4 Substitute Natural Gas (SNG)
The primary constituent of the SNG product is methane with smaller quan-
tities of Ha, CO, CO,, Na, and Ar. Coproduct SNG from liquids synthesis also
contains minor amounts of low molecular weight hydrocarbons. Standards for
pipeline gas generally require that the CO content be less than 1000 ppmv, and
it is expected that the crude SNG product would be sufficiently upgraded, if
necessary, to meet this criterion. Trace quantities of metal carbonyls may be
produced during catalytic methanation, during gasification, or by reaction of
CO and Ni or Fe in piping. Nickel carbonyl at concentrations above 0.01 ppmv
was reported in product gas from the Lurgi gasifier at Westfield, Scotland
(34). However, operators of the Lurgi gasifier at Sasol, South Africa, report
that carbonyls are not present in measurable concentrations (less than about
1 ppbv) in the product gas from that facility (43). And, recent data from the
Kosovo, Yugoslavia, Lurgi-type facility indicate that carbonyls are not pre-
sent in gasifier gases to any appreciable extent in the desulfurized gases
leaving the Rectisol unit (3).
131
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Section 3
Products/Byproducts
3.5.5 LPG
LPG from both F-T (Stream 106) and Mobil (Stream 109) synthesis will
consist primarily of propane and butane with smaller quantities of ethane,
methane, and short-chain olefins. It is not expected that coal-derived LPG
will be significantly different in chemical composition than petroleum-derived
LPG. However, this has not been verified with product composition data from
commercial-scale production facilities.
3.5.6 Lurgi Gasification Byproducts
Lurgi gasification generates several byproducts including tar, oil,
naphtha, and crude phenol. Because Lurgi byproducts have a high energy con-
tent, they may be used as auxiliary fuel sources at the plant site or they
could be gasified (in a suitable gasifier) to produce additional synthesis
gas. However, the byproducts also may have value in the marketplace as fuel
oil substitutes, gasoline blending stocks, or as chemical feedstocks. The
available information on the composition of these substances is presented
below.
Lurgi Tars (Stream 111)
Only limited data are available on the characteristics of byproduct
tars. These data are summarized in Table 3-30. Some data are available for
selected polynuclear aromatic (PNA) compounds in Kosovo tars (3). These data
are shown in Table 3-31. Some composition data are also available for the
tars produced in the Synthane coal gasification process (44). The Synthane
data, which are presented in Table 3-32, are indicative of the type of sub-
stances which would also be expected in the Lurgi tars.
132
-------
TABLE 3-30. AVAILABLE DATA ON THE CHARACTERISTICS OF BYPRODUCT TARS
Rosebud
Specific gravity, g/c»» 1.035
Dust, wt % 22.0
Phenols, wt % 5.3
Ultimate Analysis
(dry. dust free), wt *
Carbon 83 .1
Hydrogen 7.7
Nitrogen 0.6
Sulfur 0.3
Ash 0.1
Oxygen (by diff) 8.2
Higher Heating Value, MX/kg 36.8
Viscosity, centistokes 396
Distillation Range. %
to 210«C
210»C to 230«C
230°C to 270»C
270*C to 300»C
300«C to 330»C
Residue and losses
Water
Tar Acids, wt %
Free Carbon, wt %
Ash. wt %
Sulfur, wt *
Illinois Westfield Coal Kosovo
No. 6* (low rank) Lignite0
1.145 1.124-1.126 1.06
4.5
2 3.9d
85 .5 81
6.4 8.3
1.2 1.3
1.7 0.5
<0.1 0.2
5.2 7.7
36.9 37.3
1336 120
1.1-1.2
1.2-1.6
9 .8-11 .1
6.3-7.2
27.7-28.6
49.6-50.7
1.8-2.1
7.1-10.7
2.16-1.38
0.16-0.22
0.77-0.78
'Reference 1.
^Reference 26.
cReference 3 .
dSummation of identified phenolic compounds.
133
-------
TABLE 3-31. POLYNUCLEAR AROMATIC COMPOUNDS FOUND IN BYPRODUCTS
FROM A LURGI-TYPE GASIFIER IN KOSOVO, YUGOSLAVIA5
Heavy Light Medium
Component Tar Tar Oil Naphtha
Benz(a)anthracene 500 490 160 <0.1
7,12-dimethylbenz(a)anthracene 1300 1100 62 <0.1
Benzo(b)fluoroanthrene 320 310 120 <0.1
Benzo(a)pyrene (BAP) 240 210 68 <0.1
Dibenzo(a,h)anthracene 14 23 6.6 <0.1
3 methylcholanthrene <1 26 <1 <0.1
252 Molecular Weight Group 1000 950 280 <0.1
(as BAP)
aFrom Reference 3. Units are mg/kg.
134
-------
TABLE 3-32.
COMPOSITION OF BENZENE SOLUBLE TARS PRODUCED
IN THE SBtTHANB GASIFICATION PROCESS (44)
Trne/Oricin of Coal
Bitnminons
Illinois)
Compound/Class
Mono Aromatics
Benzene
Phenols
Pi Aromatics
Naphthalenes
Indanes/Indanas
Naphthols and Indanols
Tri Aromatics
Phenylnaphthalenes
Acenaphthenas
Fluor one i
Anthrancenes/Phaaanthxenea
Acenaphthols
Phenanthrols
TetraoTolio Aromatics
2.1
2.8
11.6
10.5
0.9
9.8
13.5
9.6
13.8
—
2.7
Lignite Subbitnminous
(N. Dakota) (Montana)
4.1
13.7
19.0
5.0
11.4
3.5
12.0
7.2
10.5
2.5
—
Volnme %
3.9
5.5
15.3
7.5
11.1
6.4
11.1
9.7
9.0
4.9
0.9
Bitninons
(Pennarlvania)
1.9
3.0
16.5
8.2
2.7
7.6
15.8
10.7
14.8
2.0
—
Pericondensed 7.2
(benzanthracenaa. chryaena)
Cataeondenaed 3.0
(pyrene, benzphananthranaa)
Pentacyclic Aromatics traoa
HeterocTclics
Dibenzofvrana 6.3
Dibenzothiophenas and 6.2
Benznaphthothiophenaa
N-Heterooyolica 10.8
3.5
1.4
5.2
1.0
3.8
4.9
3.0
5.6
1.5
5.3
7.6
4.1
traoa
4.7
2.4
8.8
135
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Section 3
Products/Byproducts
Lurgi Oils (Stream 112)
The available characterization data for byproduct oils are summarized in
Table 3-31 and 3-33. With respect to the PNAs shown in Table 3-31, many of
the same constituents are present in both the tars and oils. In general
though, lower concentrations of these constituents are found in the oils.
Lurgi Crude Phenols (Stream 113)
Table 3-34 presents the estimated composition of the crude phenol by-
product. The Phenosolvan solvent is expected to extract organics other than
phenols which are present in the gas liquor; thus, byproduct crude phenol is
expected to also contain small quantities of non-phenolic organics.
Lurgi Naphtha (Stream 114)
Lurgi naphtha is similar to petroleum-derived naphtha in that the princi-
pal constituents include benzene, toluene, and olefins. Table 3-35 presents
composition data on Lurgi naphtha from the Westfield facility (26). Addi-
tional characterization data for byproduct naphtha are summarized in Tables 3-
31 and 3-36. As indicated, Lurgi naphtha contains almost 90 weight percent
aromatic compounds. Lnrgi naphtha also contains significant quantities of
dissolved gases including mercaptans, HCN, and H,S as indicated by data for
naphtha storage tank vent gases at the Kosovo plant (3).
3.5.7 Ammonia and Sulfur (Streams 115 and 116)
Ammonia is recovered as a byproduct in the treatment of condensates by
steam stripping. The ammonia recovered may contain trace quantities of other
substances (e.g., thiocyanates, phenols), although no actual data are
currently available on the impurities present in the byproduct ammonia.
136
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TABLE 3-33. AVAILABLE DATA ON THE CHARACTERISTICS OF BYPRODUCT OILS
Specific gravity, g/cm'
Dnet. wt %
Phenols, wt %
Ultimate Analysis
(dry, dust free), wt %
Carbon
Hydrogen
Nitrogen
Sulfur
Ash
Oxygen (by difference)
Higher Heating Value. MX/kg
Viscosity, centistokes
Distillation Range, *C
5 vol. %
20 vol. %
40 vol. %
60 vol. *
80 vol. %
95 vol. %
Tar Acids, wt %
Pyridine Bases, wt %
Sulfur, wt %
Naphthalene, wt %
Rosebud*
0.937
0.4
19.1
81.3
9.2
0.5
0.5
<0.1
8.5
39.4
4
140
178
207
231
270
297'
Illinois
Mo. 6*
1.015
0.8
20.1
84.8
7.8
0.7
2.4
<0.1
4.3
38.3
5
164
198
218
238
280
331*
Westfield Coal tosovo
(low rank) Lignite6
0.975-1.005 0.97
12.0*
81.1
8.9
1.0
0.8
<0.1
8.2
39.8
183-198
190-207
211-223
235-239
274-278
350-354
16.5-32.8
1.3-3.3
0.29-0.99
5.5-7.6
'Reference 1.
^Reference 26.
cReference 3.
dSuanation of identified phenolic coaponnds.
•Cracked at 88.5 percent.
fCracked at 92 percent.
137
-------
TABLE 3-34. AVAILABLE DATA ON COMPOSITION OF CRUDE LDRGI PHENOLS (26)
From Tarry Gas From Oily Gas
Phenol Class/Compound Liquor Liquor
Honohydric phenols
Phenol 35 60
Cresols 13 20
Xylenols 3 g
Catechols 39 7
Resorcinols 10 5
Units are weight percent.
TABLE 3-35. COMPOSITION OF NAPHTHA PRODUCED AT
THE WESTFIELD LURGI FACILITY (26)
Compound/Class Concentration (wt %)
Paraffins and Olefins 10.71
Aromatics
Benzene 19.56
Toluene 28.40
lylene and ethylbenzene 14.7
Ethyl toluene 2.69
Trimethyl benzenes 11.8
Styrene 1.07
Indane 1.43
1,2-benzofuran 1.09
Indene 5.37
Naphthalene 1.40
Thiophenes 1.77
TOTAL 100
138
-------
TABLE 3-36. AVAILABLE CHARACTERIZATION DATA FOR BYPRODUCT NAPHTHA
Westfield Coal Kosovo .
(Low Rank)4 Lignite
Specific Gravity, g/cm3
Distillation Range, °C
Initial Boiling Point
5 vol. %
20 vol. %
40 vol. %
60 vol. %
80 vol. %
95 vol. %
Paraffins, wt %
Olefins, wt %
Aroma tics, wt %
Sulfur, wt %
Ultimate Analysis
Carbon
Hydrogen
Nitrogen
Sulfur
Ash
Oxygen (by difference)
Higher Heating Value, MJ/kg
0.851
69.2
82.5
92.0
102.5
117.5
145.5
189.5
12.0
21.8
65.4
0.676
0.831 0.845
69.5
80.5
86.0
91.0
98.5
115.5
160.0
26.0
8.0
65.9
0.078
86
9.9
0.2
2.2
NA
2.2
41.6
^Reference 26.
^Reference 3.
139
-------
Section 3
Products/Byproducts
Elemental sulfur is recovered as a byproduct in the treatment of concen-
trated acid gases for air pollution control. The recovered sulfur may be
contaminated with a number of impurities. When the Stretford process is
employed, the byproduct sulfur contains traces of vanadium, thiosulfate, and
thiocyanate. Sulfur from the Clans process may contain carbonaceous materials
to the extent that the byproduct is at times termed "black sulfur". Depend-
ing on site-specific factors, the sulfur may be saleable, require additional
processing to produce a saleable product, or may need to be disposed as a
waste.
3.5.8 Excess Coal Fines
Because the Lurgi gasifier requires a sized coal, the coal preparation
operation will always generate some quantity of coal fines. Most proposed
Lurgi-based facilities use these coal fines as fuel for steam and power gen-
eration. Depending on the physical properties of the ROM coal and the auxili-
ary boiler fuel requirements, excess coal fines may be generated.
A variety of methods are potentially available to handle these excess
fines. They could be:
• combusted on site to produce electricity or steam for sale to
offsite users,
• gasified in a reactor capable of handling coal fines to produce
additional synthesis gas,
• sold as a byproduct,
• disposed of as a solid waste, or
• possibly palletized to make a suitable feed for the Lurgi
gasifiers.
140
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Section 3
Auxiliaries
3.6 AUXILIARIES
A number of nonpollution control auxiliary processes are associated
with Lurgi-based synthetic fuels facilities. Included are raw water treat-
ment, steam and power generation, process cooling, oxygen production, and pro-
duct/byproduct storage. Sections 3.6.1 - 3.6.5 below provide brief descrip-
tions of the most important auxiliaries and define the expected characteris-
tics of the major waste streams. Generally, waste streams from the auxiliary
processes are not unique to Lurgi-based facilities.
3.6.1 Raw Water Treatment
Raw water makeup requirements for Lurgi-based synthetic fuels facilities
are dependent on the quality of available makeup water, the characteristics of
the coal gasified, the synthesis operations employed, and the degree of water
recycle/reuse practiced as well as a variety of other factors. Detailed esti-
mates of raw makeup water requirements were not made for the base plants con-
sidered in this manual. However, based on estimates of water requirements for
the two major consumers of water in a Lurgi-based plant (steam generation and
the process cooling system), raw water makeup requirements are estimated to be
900 to 1300 m»/hr.
The approach to raw water treatment is the same for the three plant loca-
tions considered in this manual (i.e., Montana for Rosebud coal, Illinois for
Illinois No. 6 coal, and North Dakota for Dunn Co., ND lignite), with treat-
ment requirements dominated by the system requiring the highest quality makeup
water (steam/power boiler). Figure 3-18 shows a typical treatment scheme for
producing boiler feedwater. Systems with lower quality requirements may with-
draw water after any step in the treatment process that meets their require-
ments. For example, cooling tower makeup could be supplied directly from the
sedimentation/equalization ponds in cases where raw water is low in hardness.
141
-------
-p-
N>
RAW
WATER
SEDIMENTATION
AND
EQUALIZATION
RAW WATER
TREATMENT
SLUDGES
DEMORALIZATION
COOLING
TOWER
MAKE-UP
REGENERATION
CHEMICALS
REGENERATION
WASTEWATER
BOILER
FEEDWATER
MAKE-UP
BACKWASH
Figure 3-18. Typical raw water treatment system
-------
Section 3
Auxiliaries
alkalinity, and suspended solids. Where any of these constituents are present
at high concentrations, raw water may require further treatment by softening,
coagulation, clarification, or filtration prior to its use in the cooling
water system.
The sedimentation and equalization step in Figure 3-18 includes with-
drawal of water and storage in a reservoir. This storage provides a reliable
supply of water to the facility independent of river flow, reduces the impact
of daily water quality variations, and allows sedimentation of silts and other
suspended material.
The raw water leaving the reservoir is treated in a sludge contact clari-
fier followed by a filter and a demineralizer. The clarifier is fed with
lime, a coagulant, and a polymer to coagulate and/or flocculate fine suspended
solids. The treated water then passes through a sludge bed of previously
formed floe. This sludge contact enhances the agglomeration and settling
characteristics of flocculated particles. An added benefit of this unit is a
partial reduction in calcium alkalinity. A filter is also provided to protect
the demineralizers from solids carryover from the clarifier. Excess sludge
(Stream 300) consisting of calcium carbonate, magnesium hydroxide, and
coagulated particulate matter is removed from the clarifier.
Demineralization is accomplished in two steps. Strong acid and strong
base ion exchange units are used as the primary treatment step and a mixed bed
polisher is used as the secondary step. Table 3-37 summarizes the estimated
flow rates and characteristics of demineralizer regeneration wastes (Stream
301) from the strong acid and strong base exchangers. The mixed bed regenera-
tion wastes will be comparable in dissolved solids to the compositions shown,
but their flow will be intermittent and insignificant compared to those from
the primary ion exchange step.
143
-------
TABLE 3-37. ESTIMATED PRIMARY DEMINERALIZER REGENERATION WASTEWATER (Stream 301)
Flow Rate, m»/lir
Constituent*
TDSb
HCOi~
S04 =
Ca++
Mg++
Na++
Cl~
SiOa
pH
Rosebud
45
13,810
0
9,700
160
360
3,400
190
90
1.7
Coal Type
Illinois No. 6
68
7,220
0
5,000
160
90
1,800
170
70
1.7
Dunn County
50
13,760
0
9,500
160
200
3,800
100
80
1.8
aAll units are mg/L except pH.
t>Total dissolved solids calculated as a sum of the ions except SiOa.
-------
Section 3
Auxiliaries
The flow rates shown in Table 3-37 are calculated as nine percent of the
total raw water makeup flow rate to the boiler. Although a single value is
indicated for each coal feed case, these wastewater flow rates will vary with
the synthesis process. The flow rates shown for demineralizer regeneration
wastewaters are averaged flows. In an actual plant the regeneration waste-
waters will probably be produced on an intermittent, higher flow rate basis.
3.6.2 Steam and Power Generation and Process Heating
Lurgi-based synthetic fuels facilities will require boilers for steam
generation and heaters for various process units. In addition to steam boil-
ers and heaters, other auxiliaries could include dedicated gasifiers for pro-
ducing low heating value fuel gas, electrical generating units, and gas tur-
bines. The size of the steam boilers will be determined, in part, by both the
gasifier steam needs and the extent to which steam drivers are used. Where
electrical drivers are used, steam demand for electricity production may dif-
fer (qualitatively and quantitatively) from the case where steam drivers are
used. When gas turbine drivers are used, steam requirements would be greatly
reduced. A large number of possible auxiliary configurations is possible, and
it is beyond the scope of this manual to perform the detailed engineering re-
quired to assess all of these configurations.
Auxiliary steam boilers are assumed to supply the facilities with all
steam not produced in process waste heat boilers. Steam from the boilers is
used for process purposes, for direct heating, in steam turbine drivers for
motive power, and for generation of electric power. For certain purposes,
steam superheating may be necessary.
Potential fuel sources for the steam boilers include coal fines, by-
products from the Lurgi gasification process (i.e., tars, oils, phenols, and
naphtha), low-Btu fuel gas, and high energy content waste gases. As mentioned
145
-------
Section 3
Auxiliaries
above, the size of the steam boilers will depend on a great number of fac-
tors. As a result, no attempt has been made in this manual to estimate the
auxiliary boiler duties. As a rough approximation though, the energy require-
ments for the auxiliary boilers should range from 15 to 30 percent of the coal
energy input to the gasifier (5,8,10). Table 3-38 presents the expected
compositions of flue gases resulting from combustion of coal fines and Lurgi
byproducts. Boiler flue gases (Stream 302) produced by the combustion of coal
are not expected to present any new or unique pollution control problems be-
yond those encountered in the electric utility industry or other industries
where large boilers are used. In general, this is true for flue gases derived
from combustion of coal-derived fuels. However, the levels of trace heavy
organics and trace elements which could be present in synfuel-derived flue
gases are not well known.
Although complete data on the characteristics of bottom ash (Stream 406)
for the subject coals are not available, their bulk composition would reflect
the major inorganic elements found in the raw coal. Table 3-39 summarizes
available data on the maximum levels of various constituents which have been
reported in bottom ash and ash slurry waters from coal-fired boilers (46).
The quality and quantity of the boiler blowdown wastewater stream (Stream
303) will be dictated by the boiler drum operating pressure. In this analysis
a boiler drum operating pressure of 10.3 HPa is assumed for all coal and syn-
thesis process cases. For the base plants examined in this manual, boiler
blowdown, after flashing, is estimated to be approximately 4000 to 5000 kg/hr.
An integrated facility would also have a number of small gas-fired
heaters serving various process units (e.g., startup heaters). Such heaters
would probably utilize sulfur-free waste gases from synthesis/fractionation
operations as the most convenient fuel.
146
-------
TABLE 3-38. ESTIMATED UNCONTROLLED AUXILIARY BOILER FLUE GAS COMPOSITIONS
Component''
CO*. %
HiO, %
Ni. %
Oi. %
SO (as 80s), ppmv
N0x (.1 NO,). ppmv
CO, ppmv
EC (as CH4). ppnv
Particnlatet, g/Nm»
Flow rate.
kg-molet/100 kg fuel
Energy input.
NJ/100 kg fuel
Rosebud
Coal
14.2
10.0
72.4
3.2
1100
660
60
30
12
30
2000
Illinois
No. 6
Coal
14.2
7.3
75.0
3.3
2200
520
50
25
8.6
38
2660
Dnnn Co.
Lignite
13.7
14.7
68.4
3.0
790
370
75
<130
4.5
24
1500
Boiler Fuel
Lurgi
Tar."
13.5
7.5
75.6
3.4
150°
270
45
15
0.70*
48
3760
Lurgi
Oils
12.8
8.7
75.2
3.3
260°
120
45
15
0.024
53
3950
Lurgi
Phenols
14.1
7.1
74.4
3.3
d
130
50
15
0.025
45
3200
Lurgi
Naphtha
12.1
9.2
75.3
3.3
1100°
120
45
15
0.023
58
4340
•Compositions shown are for Lnrgi byproducts derived from gasifying Rosebud coal.
^Compositions shown are based on combustion with 20% excess air. Pollutant quantities
are estimated using Reference 45.
cFor byproducts from Illinois No. 6 coal, SOi is estimated as follows: Tars - 910 ppmv
Oils - 1200 ppmv
Naphtha - 2100 ppmv
^Sulfur content of phenols is unknown but expected to be low.
•Assumes actual ash content of dust associated with tar is the same as ash content of parent
coal.
-------
Section 3
Auxiliaries
TABLE 3-39. MAXIMUM MEASURED CONCENTRATIONS OF SELECTED
COMPONENTS IN BOTTOM ASH AND ASH SLURRY (46)&
As
Ba
Cd
Cr
Pb
Hg
Se
Ag
F-
Cl-
Cu
Fe
Mn
S04
Zn
Bottom Ash
ppm
40
4,000
250
270
35
4
7.7
25
100
1,800
720
203,000
720
950
Slurry
mg/L
0.12
3.0
0.052
0.17
0.2
0.026
0.05
0.02
16.2
2.415
0.45
11.0
1.1
2,300
2.7
Based on a variety of coals.
3.6.3 Cooling Operations
A portion of the input energy to a synfuels plant will be rejected as
waste heat. The exact amount of heat lost will be a function of both process
design and operating practices and will be highly plant-specific. Further,
the cooling water evaporation rate will be a function of the amount of wet
versus dry cooling used at a given site. This, in turn, will be affected by
design decisions based upon climatic factors and raw water costs. Since de-
tailed designs and heat balances were not developed for this manual, some sim-
plifying assumptions were made to develop representative cooling system loads.
The energy rejection rate from the cooling system was obtained by assum-
ing that 40 percent of the thermal energy in the feed coal that is not
148
-------
Section 3
Auxiliaries
recovered in the plant's products is rejected through evaporative cooling in
a cooling tower (47). For purposes of estimating the heat rejection in the
cooling tower, overall plant efficiencies of 54 to 64 percent were used (5,8).
Under these assumptions, the variation in the energy rejection rates is di-
rectly reflected in the calculated cooling water evaporation rates for each
base plant. Table 3-40 summarizes the waste stream rates expected to arise
from cooling tower operations based on these assumptions. No basis was avail-
able to vary the cooling tower heat duty as a function of coal type. Thus,
the data in Table 3-40 are assumed to apply to all three coals examined.
TABLE 3-40. WATER LOSSES FROM THE BASE PLANT COOLING TOWERS
Synthesis Process
Hethanol or SNG Fischer-Tropsch Mobil-M
Cooling water evaporation 270 375 325
rate, Mg/hr
Cooling water blowdown
flow rate, m*/hr
Drift loss, Mg/hr)b
66
1.9
92
1.9
79
1.9
.At an assumed five cycles of concentration operation.
Calculated as 0.01 percent of recirculation rate (48).
Discharges from the plant cooling systems consist of: blowdown water
(Stream 307); evaporative losses (Stream 306), which include evaporated water
and stripped gases; and entrained water (drift) (Stream 306). Table 3-41 sum-
marizes the estimated cooling tower blowdown and drift characteristics
(assumed to be the same composition) for a cooling system operating at 5
cycles of concentration. The blowdown/drift characteristics are intended to
149
-------
Section 3
Auxiliaries
be typical of the concentrations expected for the plant locations when raw
water is used as makeup. These characteristics do not necessarily represent
optimum conditions for any given site (e.g., process waters after treatment
could be used as cooling towers makeup). In addition to the concentrations of
inorganic dissolved solids shown, scale and corrosion control additives would
also be present in the blowdown/drift.
TABLE 3-41. ESTIMATED CHARACTERISTICS OF MAJOR COMPONENTS
OF COOLING TOWER SLOWDOWN AND DRIFT*
Blowdown/Drif t Constituents
Total Dissolved Solids
HC07
so;
Ca++
Mg++
Na+
ci-
SiOa
pH
Rosebud
2350
110
1500
260
180
180
85
40
7.5
Coal TVDO
Dunn County
2280
110
1450
250
100
300
45
35
7.5
Illinois No. 6
1320
100
740
180
45
150
75
30
7.5
Concentrations are presented for operation at 5 cycles of concentration
using raw water as makeup. All units are mg/L except pH.
^Total dissolved solids is the sum of the constituents shown.
3.6.4 Oxygen Production
Oxygen required by the Lurgi gasification process (Stream 4) is assumed
to be produced by standard cryogenic air separation units. Oxygen purities
150
-------
Section 3
Auxiliaries
used in the mass flow calculations are based on published data for oxygen
purities used in gasification tests of the subject coals. It should be noted
that the purity of oxygen utilized affects the quantity of the purge stream
from the downstream synthesis process and thereby affects synthesis effi-
ciency. Therefore, a trade-off exists between the energy required to produce
high purity oxygen and the efficiency of the synthesis process. An analysis
of optimum oxygen purities is beyond the scope of this manual. Oxygen re-
quirements for the Lurgi-based synthetic fuels plants examined in this manual
are estimated at 72,600, 110,000, and 83,600 kg/hr for Rosebud, Illinois No.
6, and Dunn County coals, respectively.
Production of oxygen does not directly generate waste streams requiring
treatment, since chemical reactions do not take place in the air separation
process nor are any chemicals added to the process streams. A gaseous waste
stream containing mostly nitrogen and a liquid condensate are produced, but
these streams are essentially pollutant free.
3.6.5 Product and Byproduct Storage
Onsite storage facilities will be provided for liquid products and Lurgi
byproducts. For those liquids with very high vapor pressures (e.g., LPGs),
pressurized storage vessels are assumed and hence no routine evaporative emis-
sions are expected. For those liquids with relatively low vapor pressures
(diesel oil and heavy fuel oil from F-T synthesis and Lurgi byproduct oil,
tar, and phenol) fixed-roof storage tanks are assumed. All other liquids
(methanol, gasoline, and Lurgi byproduct naphtha) are assumed to be stored in
floating roof tanks with mechanical shoe seals.
For purposes of estimating potential emissions (Streams 308 through 311
and 313 through 317) from these storage vessels, a storage capacity equal to
15 days of production was assumed. Evaporative emissions were estimated.
151
-------
Section 3
Auxiliaries
using correlations presented in References 45 and 49, for three locations in
the U.S. - Southern Illinois; Dunn County, North Dakota; and Rosebud, Montana.
Meteorological data for these locations were obtained from the National
Climatic Atlas (50). Product and byproduct properties used in the emission
correlations are summarized in Table 3-42. The resulting calculated emissions
are summarized in Table 3-43 for both average annual conditions and worst case
conditions (midsummer).
Data on the components of evaporative emissions associated with the stor-
age of coal-derived liquid fuels are generally not available. However, lim-
ited data are available on evaporative emissions associated with petroleum
gasoline storage as indicated in Table 3-44. In addition to the paraffins and
olefins listed in this table, aromatics are expected to be present in evapora-
tive emissions in the 1 to 1000 ppm range. Since the compositions of F-T and
Mobil M-Gasolines are not dramatically different from those of petroleum
gasolines, the gross characteristics of evaporative emissions are expected to
be similar. Table 3-45 presents recent data on the evaporative emissions
associated with the storage of byproducts at the Lurgi-type gasification plant
in Kosovo, Yugoslavia (3). As indicated in the table, the vapors from the
naphtha storage tank consist mostly of hydrocarbons heavier than Cf. Since
Lurgi naphtha also contains high levels of mercaptans, HCN, and ammonia, these
substances are found in the storage tank vapors. It should be noted that
Lurgi crude tars, oils, and naphtha have somewhat higher vapor pressures than
their petroleum-derived counterparts. This is due to the fact that Lurgi
liquids are obtained by physical phase separation processes and still contain
high levels of volatile components while petroleum liquids are usually "stabi-
lized" to decrease volatility by fractionation and blending.
152
-------
TABLE 3-42. ESTIMATED PRODUCT AND BYPRODUCT PROPERTIES
Ul
u>
Vavor Pressures, kPa
Product
Methanol*
Gasoline
Diesel Oil
Fuel Oil
Naphtha
Lurgi Oil
Lurgi Tar
Phenols
Molecular
Weight
32
66
130
190
65
190
190b
190b
Density
kg/m»
790
670
840
950
770
950
950b
950b
South 111.
July Ann.
17
50
0.08
0.0006
35
0.9
0.7
0.8
9
34
0.05
0.0003
23
0.5
0.3
0.4
No. Dakota
July Ann.
14
43
0.06
0.0004
30
0.7
0.5
0.6
5
24
0.02
0.0001
16
0.2
0.1
0.1
Montana
July Ann.
15
46
0.07
0.0005
32
0.8
0.6
0.7
6
27
0.03
0.0002
18
0.3
0.2
0.2
Ann = Annual average.
Properties of mixed alcohols are assumed to be equal to those of methanol.
Assumed equal to that of Lurgi oil for mass emission estimate purposes.
Molecular weight, density, and vapor pressure properties were taken as those of
similar petroleum products.
-------
TABLE 3-43. ESTIMATED STORAGE TANK EVAPORATIVE EMISSIONS*
Product/
By- Product
Mixed Alcohols
Methanol
Gtsoline
Gasoline
Diesel Oil
Heavy Fuel Oil
Lnrgi Naphtha
Oi
*- Lnrgi Oil
Lor|i Tars
Lur|i Phenols
Type
of
Tanka ge
Floating Roof
Floating Roof
Floating Roof
Floating Roof
Fixed Roof
Fixed Roof
Floating Roof
Fixed Roof
Fixed Roof
Fixed Roof
Synthesis
Process
F-T
Methanol or
Mobil N
F-T
Mobil M
F-T
F-T
All6
All
All
All
Sooth
July
14
72
31
34
0.8
0.01
7
10
29
7
111.
Ann.
Avg.
9
43
28
32
0.5
0.005
7
6
14
3
North Dakota
July
15
75
47
51
0.4
0.009 ,
12
8
22
5
Ann.
Avg.
6
28
26
29
0.3
0.004
6
3
5
1
Montana
July
17
84
49
54
0.7
0.01
12
9
26
6
Ann.
Avg.
7
33
29
32
0.3
0.004
7
4
8
2
•All data are in kg/day.
bFloating roof tanks are equipped with mechanical shoe seals.
CA11 Means SNG, Bethanol, Mobil M-Gasoline and Fischer-Tropsch synthesis.
-------
TABLE 3-44. COMPOSITION OF EVAPORATIVE EMISSIONS
FROM GASOLINE STORAGEa
Compound Vol. %b
Methane 1.13
Ethylene 0.001
Ethane 0.15
Propylene 0.03
Propane 0.82
Isobutane 3.03
Isobutylene 1.12
n-butane 3.53
cis-2-butane 0.84
Isopentane 6.18
n-pentane 2.89
Hezanes 0.44
Heptanes 0.16
Octanes 0.17
aFrom Reference 51.
^Balance is air.
155
-------
TABLE 3-45. STORAGE TANK VENT DATA FROM KOSOVO PLANT
Ln
Component
Light Tar
Storage Tank
Medium Oil
Storage Tank
Naphtha
Storage Tank
Crude Phenol
Storage Tank
Vol. %
Na 81
Oa 19
CO,
c*,l
C4s
C.s
Cts
Acid Gases NF-0.4
Saturated HCs NF
Unsaturated HCs 0.2-1.4
ppmv
HaS 230-890
COS
CHjSH
CaH,SH
Benzene
Toluene
Other Aroma tics Tr
NH, 100
HCN
88 84-95
6.2 2.5-9.0
NF-0 . 85
Tr-0.009
0.004-0.10
0.03-0.10
0.07-0.39
5.1-5.4
06. -5,0
0.4
NF-1.2
1500-1600 NF-1600
NF
2400-4100
6700-12000
37000-38000
1600-2100
Tr 57-63
75 NF-23
1100
84
16
NF
0.4
NF
NF
NF-Tr
3.7
From Reference 3.
Tr means ~ 1 ppmv.
NF = less than 0.01 vol.% or less than 1 ppmv. as appropriate.
Single value data generally indicate only one data point available.
Blanks indicate no data available.
-------
Section 3
Fugitive Wastes
3.7 FUGITIVE AND MISCELLANEOUS WASTES
3.7.1 Fugitive Organic Emissions (Stream 233?
There are many potential sources of fugitive emissions in a Lurgi-based
synthetic fuels facility. These sources include: pumps, compressors, inline
process valves, pressure relief devices, open-ended valves, sampling connec-
tions, flanges, agitators, and cooling towers. Constituents of fugitive emis-
sions include any of the volatile components present in the stream from which
the emissions arise, including organics, H3S, CO, NH3, etc. No data are
available on nonorganic fugitive emissions. However, extensive tests and mea-
surements for fugitive organic emissions have been performed at petroleum
refineries (52). As a result of this testing, average emission factors have
been developed for fugitive emission sources such as pump seals, compressor
seals, valves, etc. (53). These factors were applied to the product synthe-
sis and upgrading operations of methanol, Mobil M, and F-T synthesis and to
Lurgi byproduct handling in order to estimate fugitive organic emissions
because these operations are quite similar to those in petroleum refining.
Fugitive emissions estimates were made by estimating the number of each
type of emission source and applying the appropriate emission factor, with no
adjustment for size, pressure, or flow rate. The number of pumps, compres-
sors, and process units for each synfuel plant was estimated by correlating
equipment lists to the proper size synfuel plant or adjusting the equipment
counts reported in conceptual designs (5,18,54). Equipment spares were
counted in determining the number of pumps and compressors, because it was
assumed that spares usually contain fluid under pressure. In addition, it was
assumed that eight pumps are used to handle the Lurgi byproduct tars, oils,
phenols, and naphtha.
157
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Section 3
Fugitive Wastes
The process streams associated with each piece of equipment were classi-
fied with respect to percentage of hydrocarbon content and hydrocarbon type.
Different factors were used for liquid streams containing light and heavy
hydrocarbons. Liquid streams containing C, through C9 hydrocarbons,
naphtha, and other aromatic hydrocarbons were classified as light. Kerosene,
diesel oil, and other heavy hydrocarbons were classified as heavy. All emis-
sion factors shown assume 100 percent hydrocarbon content, so all emission
factors except those for compressors were multiplied by the actual hydrocarbon
content for each process stream. Streams containing less than 10 percent
hydrocarbons were neglected and those containing greater than 80 percent were
considered to contain 100 percent. Gaseous streams were classified as either
hydrocarbon or hydrogen depending on which was present in a greater percent-
age. The compressor seal emission factors for these two classifications were
used as reported and not adjusted for percent hydrocarbon content. Table 3-46
summarizes the fugitive emission factors used.
Results of these fugitive emission calculations for Lurgi-based synthetic
fuels facilities are given in Table 3-47. It should be noted that for the SNG
production case, the only fugitive emissions estimated are those that arise
from byproduct handling. Any fugitive emissions from the SNG synthesis opera-
tion would consist primarily of methane. It should also be noted that some
fugitive emissions from the Lurgi gasification and gas purification operations
are expected. However, there is not a good basis for estimating these addi-
tional emissions and hence they have not been estimated in this manual.
3.7.2 Non-Process/Intermittent Wastewater Streams
Fugitive process fluid leaks from sources such as pump seals, valves, and
flanges will generate a composite waste stream with a highly variable flow and
composition. In addition, drainage resulting from emergency process fluid
158
-------
TABLE 3-46. FUGITIVE EMISSION FACTORS
Equipment Tvoe
Pumps
Compressor*
Process Units
Valves
Flanges & Fittings
Drains
Classification
Light Liquid
Heavy Liquid
Hydrocarbon
Hydrogen
All
Gas Service
Light Liquid
Heavy Liquid
All
All
Source
Emission Equipment
Factor Emission Factor
Emission Source (ks/hr) Quantity (ks/hr)
Pump Seals .11 1.4 z No. of Pumps
.021
Compressor Seals .64 2 x No. of Compressors
.05
Relief Valves .086 6 z No. of Process Units
.027
Valves .011 41 z No. of Pumps
.00023
Flanges & Fittings .00025 164 z No. of Pumps
Drains .032 2.6 z No. of Pumps
-Oi!
.029
1.28
.10
.516
Equipment Emission Factor equals Source Factors times Quantity.
-------
TABLE 3-47. ESTIMATED FUGITIVE HYDROCARBON EMISSIONS
Uncontrolled Emission Rates
(ke/hr)
Pump Seals
Light Liquid Service
Heavy Liquid Service
Inline Valves
Gas Service
Light Liquid Service
Heavy Liquid Service
Safety Relief Valves
Vapor Service
Compressor Seals
Hydrocarbon
Hydrogen
Flanges
Drains
Totals
Fischer- Tr ops ch
18
0.5
37
40
0.1
25
13
1.8
1.4
_12_
149
Hethanol Mobil
4.4 8.3
0.2 0.4
9.9 18
9.8 18
0.1 0.1
5.2 11
2.9 1.5
1.5 2.8
3.1 5.6
37 66
SNGa
1.2
2.2
2.7
-
-
0.3
SL1
7.1
Estimates are only for byproduct handling and storage.
The uncontrolled emission factors for pumps and compressors represent emissions
from each pump and compressor and not from each pump seal and compressor seal.
-------
Section 3
Fugitive Wastes
discharges or process area washdown/cleanup activities will contribute addi-
tional intermittent aqueous wastes. All of these wastes would normally be
collected in a process sewer or oily waste sewer. The estimated flow rates of
the combined wastewaters from these types of sources is 20 to 25 m*/hr. These
process drainage (Stream 318) flow rate estimates are based upon refinery
experience and are estimated as 2 percent of the total raw water makeup to the
plant (55).
Both the flow rate and composition of these wastewaters will vary widely
among the different plant sites. Of course, good housekeeping and maintenance
practice will minimize these flows. These wastewaters will contain oil and
grease, dissolved organics, dissolved inorganics, and particulate matter in
widely varying concentrations. Because the characteristics of these waste-
waters will be site-specific and highly variable with time, no composition es-
timates were developed for these streams.
Storm runoff water (Stream 319) flow rates will be a function of the sur-
face drainage of the plant site and the annual rainfall. For calculation pur-
poses, a plant site drainage area of 400,000 square meters was used. The
annual rainfall rates for the assumed plant locations (50) and the resulting
average storm runoff flow rate estimates are listed in Table 3-48.
TABLE 3-48. ESTIMATED AVERAGE STORM RUNOFF FOR
ASSUMED BASE PLANT LOCATIONS
Annual Annual Average
Coal Type Rainfall. cma Storm Runoff, m»/hr
Rosebud
Illinois No. 6
Dunn County
30
100
40
14
47
18
Reference 50.
161
-------
Section 3
Fugitive Wastes
The composition of storm runoff will vary with the frequency of rainfall
occurrences and with time during a rainfall occurrence. The major contami-
nants are total suspended solids, oil, and grease. Because of the variable,
site-specific nature of the composition of this stream, no attempt has been
made to develop a detailed composition.
3.7.3 Equipment Cleaning Wastes
The two primary sources of equipment cleaning wastes at Lurgi-based
facilities are process equipment (Stream 234) and boiler cleaning wastes
(Stream 305). Process equipment cleaning wastes will result from periodic
cleanup or maintenance of equipment such as heat exchangers, pumps, and pres-
sure vessels. The volume of cleaning waste generated will be determined by
the vessel volumes, frequency of cleanup, cleaning agent used, and rinsing
requirements. Cleaning waste discharges are intermittent, short duration,
high flow rate occurrences.
Boiler cleaning wastes will be generated on a one to four year cycle
depending on plant maintenance practices. The large volume of the boiler can
result in cleaning waste produced in excess of 3800 Mg over short periods of
time. Boiler cleaning wastes will probably be the largest single source of
cleaning wastes at a Lnrgi-based facility.
The composition of equipment cleaning wastes will vary with the cleaning
agents used and the materials being removed. Cleaning of process equipment
generally includes the removal of oils, sludges, and waxy materials using
alkaline solvents. Boiler cleaning is undertaken to remove inorganic
(scaling) materials and metal corrosion products with acidic and alkaline
cleaning agents. Rinse volumes from both process and boiler cleaning wastes
contain lower contaminant concentrations but can amount to 2 to 5 times the
volume of the cleaning waste. Treatment of these wastes is difficult because
162
-------
Section 3
Fugitive Wastes
of their complex composition. Despite the intermittent and large volumes of
waste generated, when considered on an annual average basis, cleaning wastes
are produced at relatively low flow rates compared with other wastewaters
generated in a Lurgi-based facility.
163
-------
Section 3
Stream Index
3.8 WASTE STREAM/CONTROL TECHNOLOGY INDEX
The proceeding parts of this section have presented a compilation of data
(both calculated and test data) on the uncontrolled or primary waste streams
expected to be produced by Lurgi-based synfuels facilities. Section 4 of this
manual presents information on the available control techniques for these pri-
mary waste streams.
To aid users in finding characterization data and control technology
information for any waste stream addressed in this manual, a stream number
index and a cross reference index were developed. The stream number index is
presented in Table 3-49. The waste stream cross reference index is presented
in Table 3-50; for each primary waste stream, it indicates where in Section 3
characterization data can be found and where in Section 4 control technology
information can be found. The waste streams in Table 3-50 are grouped by the
operation or auxiliary process from which they originate and then further
grouped within each operation by media, i.e., gaseous, aqueous, or solid.
Table 3-51 presents information similar to that in Table 3-50, but for
residuals or secondary wastes streams, identified in Section 4, i.e., those
resulting from use of pollution control techniques. The entries in Table 3-51
are not meant to imply that those streams will be necessarily found in Lurgi-
based facilities, but only that if the control techniques listed are used,
then those streams will be produced.
164
-------
TABLE 3-49. STREAM INDEX
Process Streams
Products/Byproducts
Stream
Number
Stream Name
Stream
Number
Stream Name
1
2
3
4
5
6
7
8
9
10
11
12
14
15
16
18
19
21
22
23
24
Run of mine (ROM) coal
Prepared coal to gasifier
Steam to gasifier
Oxygen to gasifier
Raw Lnrgi gas
Shift feed gas
Shift bypass gas
Shifted gas
Combined gas after shift
Quenched Lurgi gas to acid
gas removal
Acid gas removal product
gas
Sulfur—free synthesis gas
F-T purge gas
Methanator product
C0,-free SNG
Hethanol purge gas
Crude Mobil M-gasoline
synthesis product
Coal fines
Raw water
Boiler feedwater
Cooling tower makeup
100 Gasoline
101 Diesel oil
102 Heavy fuel oil
105 Mixed alcohols
106 F-T LPG
107 Crude methanol
108 Mobil gasoline
109 Mobil LPG
110 Moisture free SNG
111 Tar
112 Oil
113 Phenol
114 Naphtha
115 Ammonia
116 Sulfur
117 Fuel grade methanol
Primary ffagf? ?tr?{IB?
200 Dust from ROM coal
storage
201 Coal pile runoff
202 Dust from coal
preparation
204 High—pressure coal
lockhopper gases
(Continued)
165
-------
TABLE 3-49. (Continued)
Primary Waste Streams
Stream
Number
205
206
207
208
209
210
211
212
213
214
215
216
217
218
219
220
222
223
224
225
Stream Name
Low-pressure ooal
lockhopper gases
Ash lockhopper gases
Hot ash
Transient waste gases
Gas liquor depressurization
gases
Gas liquor
Shift catalyst regeneration/
decommissioning off-gases
Spent shift catalyst
HjS-lean acid gases
(nonselective Rectisol)
C0,-rich acid gases
(selective Rectisol)
HjS-rich acid gases
(selective Rectisol)
Hethanol/water still bottoms
Spent sul fur guard
Spent F-T catalyst
F-T synthesis wastewater
Offgases from F-T product
fractionation
Spent methanol catalyst
Spent Mobil catalyst
Mobil catalyst regeneration
off-gases
Mobil synthesis wastewater
Prig»rv Waste Streams
Stream
Number
226
228
229
230
231
233
234
236
237
238
300
301
302
303
304
305
306
307
308
Stream Name
Mobil fractions tor
offgasess
Methanation condensate
Spent methanation
catalyst
Methanation catalyst
COj removal offgases
Fugitive organic
emissions
Process equipment
cleaning wastes
SNG dehydration
offgases
Methanol synthesis
wastewater
COj removal condensate
Raw water treatment
sludge
Demineralizer regener-
ation wastewaters
Boiler flue gas
Boiler blowdown
Boiler bottom ash
Boiler cleaning wastes
Cooling tower
evaporation/ drift
Cooling tower blowdown
Evaporative emissions
from methanol storage
(Continued)
166
-------
TABLE 3-49. (Continued)
Primary Waste Streams
Stream
Number
Stream Name
Secondary Waste
Stream
Number
Stream Name
309 Evaporative omissions
from gasoline storage
310 Evaporative emissions
from diesel oil storage
311 Evaporative emissions
from heavy fuel oil
storage
313 Evaporative emissions
from mixed alcohols
storage
314 Evaporative emissions
from Lorgi tar storage
315 Evaporative emissions
from Lorgi oil storage
316 Evaporative emissions
from Lurgi naphtha storage
317 Evaporative emissions
from Lurgi phenols
storage
318 Plant process drain
wastes
319 Storm drain wastewater
Secondary Waste Streams
400 Collected dust from
pollution control
401 Coal lock vent gas
scrubber blowdown
402 Ash look vent gas
scrubber blowdown
403 Quenched gasifier ash
404 Gasifier ash quench
blowdown
406 Quenched boiler bottom
ash
407 Boiler bottom ash
quench blowdown
409 ADIP HjS-rich offgases
410 ADIP hydrocarbon-rich
offgases
411 Claus tail gas
412 Claus catalyst
regeneration offgases
413 Spent Claus catalyst
414 Stretford tail gas
415 Stretford ozidizer
vent
416 Stretford solution
blowdown
417 Beavon tail gas
418 Spent Beavon or SCOT
catalyst
419 Beavon catalyst
decommissioning
offgases
420 SCOT tail gas
421 SCOT recycle gas
423 Incinerated tail gases
428 Ammonia stripper
overhead gases
(Continued)
167
-------
TABLE 3-49. (Continued)
Secpndarv Vaste Strains
Stream
Number
431
Stream Name
Biological oxidation
slndge
Secondary Waste Strcnn?
Stream
Number
441
442
Stream Name
Boiler fly ash
Part icul ate— free
433 Chemical precipitation
sludge
435 Spent carbon
436 Activated carbon
regeneration offgases
437 Brine concentration
offgases
440 Flue gases from
wastewater incinerator
boiler fine gas
443 Particnlate and S0}-
free boiler fine gas
444 FGD sludges/dry solids
445 W-L purge and bleed
446 Regeneration offgas
scrubber blowdown
447 Collected particnlates
168
-------
TABLE 3-50. CROSS-REFERENCE INDEX FOR PRIMARY WASTE STREAMS
PCTM Section Reference For
Waste Strata (Stream No.) Waste Characterization Control Techniques
Coal Preparation
• Gaseous Wastes
- Dust From ROM Coal Storage (200) 3.1.4 4.1.5
- Dust From Coal Preparation (202) 3.1.4 4.1.6
• Aqueous Wastes
- Coal Pile Runoff (201) 3.1.4 4.2.3
Lorgi Gasification
• Gaseous Wastes
- High Pressure Coal Lockhoppez Gases (204) 3.2.4 4.1.2.1
- Low Pressure Coal Lookhopper Gases (205) 3.2.4 4.1.2.1
- Ash Lockhopper Gases (206) 3.2.4 NE
- Transient Waste Gases (208) 3.2.4 4.1.2.2
• Solid Wastes
- Quenched Gasifiez Ash (403) 3.2.4 4.3.2.1
Gas Purification and Upgrading
• Gaseous Wastes
- Gas Liquor Depzessnrization Gases (209) 3.3.5 4.1.2.3; 4.1.8
- Shift Catalyst Regeneration/Decommissioning
Offgases (211) 3.3.5 4.1.3.1
- HjS-lean Acid Gases (nonseleotive Reetisol) (213) 3.3.5 4.1.1.2; 4.1.8.2
- COj-rich Acid Gases (selective Reetisol) (214) 3.3.5 4.1.1.3
- HjS-rich Acid Gases (selective Reotisol) (215) 3.3.5 4.1.1.1; 4.1.8.1
• Aqueous Wastes
- Gas Liquor (210) 3.3.5 4.2.2.1; 4.2.2.5
- Methanol/Water Still Bottoms (216) 3.3.5 4.2.2.2; 4.2.2.5
• Solid Wastes
- Spent Shift Catalyst (212) 3.3.5 4.3.5
- Spent Sulfur Guard (217) 3.3.5 4.3.5
Product Synthesis
• Gaseous Wastes
- Mobil Catalyst Regeneration Offgases (224) 3.4.3 4.1.3.2
Methanation Catalyst Decommissioning
Offgases (230)
- CO, Removal Offgases (231)
- SNG Dehydration Offgases (236)
• Aqueous Wastes
- F-T Synthesis Wastewater (219)
- Methanol Synthesis Wastewatar (237)
- Mobil Synthesis Wastewater (225)
- Methanation Condensata (228)
- CO, Removal Condensate (238)
• Solid Wastes
- Spent F-T Catalyst (218)
- Spent Methanol Catalyat (222)
- Spent Mobil Catalyst (223)
- Spent Methanation Catalyst (229)
3.4.3
3.4.3
3.4.3
3.4.3
3.4.3
3.4.3
3.4.3
3.4.3
3.4.3
3.4.3
3.4.3
3.4.3
KB
4.1.2.4
NE
4.2.2.3
4.2.2.3
4.2.3.3
4.2.3
4.2.3
4.3.5
4.3.5
4.3.5
4.3.5
(Continued)
169
-------
TABLE 3-50. (Continued)
PCTM Section Reference For
Waste Stream (Stream No.)
Watt* Characterization
Control Teohniq.net
Auxiliary Procesaes
• Gaieous Waatea
- Boiler Fine Gaaea (302)
- Proceaa Heater Fine Gaaea
- Cooling Tower Evaporation/Drift (306)
- Evaporative Eaisaiona fron Methanol Storage (308)
- Evaporative Emissions from Gasoline Storage (309)
- Evaporative Emissions from Diesel Oil Storage (310)
- Evaporative Emissions from Heavy Fuel Oil
Storage (311)
- Evaporative Emissions from Mixed Alcohols
Storage (313)
- Evaporative Emissions from Lnrgi Tar Storage (314)
- Evaporative Emissions from Lnrgi Oil Storage (313)
- Evaporative Emissions from Lnrgi Naphtha
Storage (316)
- Evaporative Emissions from Lnrgi Phenols
Storage (317)
• Aqueous Wastes
- Demineralizer Regeneration Waatewaters (301)
- Boiler Slowdown (303)
- Boiler Ash Quench Slowdown (407)
- Cooling Tower Slowdown (307)
• Solid Wastes
- Raw Water Treatment Slndge (300)
- Quenched Boiler Bottom Ash (406)
Fugitive and Miscellaneous Wastes
• Gaseous Wastes
- Fugitive Organic Emissions (233)
• Aqueous Wastes
- Process Equipment Cleaning Waatea (234)
- Boiler Cleaning Wastes (305)
- Plant Process Drain Wastes (318)
- Storm Drain Wastewater (319)
3.6.2
3.6.2
3.6.3
3.6.5
3.6.5
3.6.5
3.6.5
3.6.5
3.6.5
3.6.5
3.6.5
3.6.5
3.6.1
3.6.2
3.6.3
3.6.1
3.6.2
3.7.1
3.7.3
3.7.3
3.7.2
3.7.2
4.1.4.1
4.1.4.2
ME
4.1.7.1
4.1.7.1
4.1.7.1
4.1.7.1
4.1.7.1
4.1.7.1
4.1.7.1
4.1.7.1
4.1.7.1
4.2.3
4.2.3
4.2.3
4.2.2.5; 4.2.3
4.3.2.5
4.3.2.2
4.1.7.2
4.2.3
4.2.3
4.2.3
4.2.3
NE » Not evaluated.
170
-------
TABLE 3-51. CROSS-REFERENCE INDEX FOR SECONDARY WASTE STREAMS
PCTM Section Reference For PCTM-PolIntIon Control
Pllfrl r t l/Q A W
Air Pollution Control Techniques
Amine Enrichment
Hydrocarbon offgas (410)
Clint
Citilyst regeneration offgas (412)
Snlfur (116)
Spent catalyst (413)
Stretford
Purge liquids (416)
Snlfur (116)
Beavon
(See Stretford)
Sour water (240)
Spent catalyst (418)
SCOT
Spent catalyst (418)
Wellaan-Lord
Purge liqnids (242)
Sulfur (116)
Dry solids (441)
Dry Particulate Collectors
Dry solids (400)
Water Pollution Control Techniques
Phenosolvan
Spent filter media
PBOSAM-W
Acid gases (428)
4.1.1 A-l
4.1.1.2 4.1.8.1
4.1.1 A-6
NE
4.3.3.1
4.1.1 4.3.J
4.1.1 A-7
4112 4182
4.1.1.2 4.2.3
4.3.3.1
4.1.1 A-9
(See Stretford) (See Stretford)
4.1.1.2 4.2.2.4
4.1.1.2 4.3.5
4.1.1 A-10
4.1.1.2 4.3.5
4.1.1 A-10
4.1.1 .2; 4 1 .4.1 4.2 .3
4.1.4.1 4.3.3.1
4.1.4; 4.1.6 A-13
4.3.2.3
4.1.4; 4.1.6 A-14
4.2 2.4; 4.2.3
4.1.4; 4.1 .6 A-ll; A-12
4.3.3.3
4.2.1.2; 4.2.2.1 B-5
NE
4.2.1.3; 4.2.2.1 B-8
4.2.2.1 4.1.2.3
(Continued)
-------
TABLE 3-51. (Continued)
PCTM Section Reference For
Pollution Control/Secondary fattei
tute Characterliatlon
Control Technique!
PCTM-Pollotion Control
Technology Ancendlcei
Water Pollution Control Technique!
Activated Sludge
Of f |aaes
Biolo|lcil aludfe (431)
Activated Carfaon Adsorption •
Beaeneration off|ii (436)
Spent carbon (435)
Thermal Oxlditlon
Incinerator fine
(440)
Cooling Tower Oiidation/Concentration
Evaporation/Drift (306)
Chemical Precipitation
Sludie (433)
Forced Evaporation
Noncondenaible/Vent taiea (437)
Deep fell Injection
Surface Impoundment
Evaporation
Leachate
Solid Waate Manaiement Techntauet
Incineration
Flue |a»ee
A eh
Landfill
Leachate
Land Treatment
Volatile (a»ei
Leachate
4.2.2.1
4.2.2.1
4.2.2.1
4.2.2.1
4.2.2.1
4.2.1.4: 4.2.2.1; 4.2.2.3 B-10
NE
4.3.4
4.2.1.5: 4.2.2.1; 4.2.2.3
4.1.3.3
NE
4.2.1.5; 4.2.2.1
4.1.4.3
4.2.1.5; 4.2.1.7; 4.2.2.1
NE
4.2.1.6; 4.2.2.1
4.3.2.5
4.2.1.7; 4.2.2.1
NE
4.2.1.8; 4.2.2.1
4.2.1.S; 4.2.2.1
NB
NE
4.3.1.1; 4.3.4.1
4.3.4.1
4.3.4.1
4.3.1.3
4.3.1.3
4.3.1.3; 4.3.4.2
4.3.4.2
4.3.4.2
B-15
B-17
B-1S
B-19
B-26
B-27
B-28
NE - Not evaluated.
-------
SECTION 4.0
EVALUATION OF POLLUTION CONTROL TECHNOLOGY
At the present time, there are no Lurgi-based SNG or indirect coal lique-
faction plants in commercial operation in the United States. In addition,
very limited information is available which relates to pollution control pro-
cesses used by the only significant Lnrgi-based indirect liquefaction plant in
commercial operation outside of the U.S. (i.e., the SASOL facilities). The
emphasis on pollution control which has been incorporated into designs for
most Lurgi-based facilities abroad is generally less than that which is anti-
cipated for U.S. plants. Therefore, directly applicable performance data for
most pollution control technologies are quite limited. The potential applica-
tion of most pollution control technologies to waste streams identified in
Section 3 has, therefore been extrapolated from their use in similar applica-
tions in industries such as petroleum refining, coke production, natural gas
processing, coal cleaning, and electrical utilities. This section provides an
evaluation of the control methods which may be adapted from other industries
and from general pollution control practice, and a discussion of the principal
limitations of these control methods in Lurgi-based synfuels plants. Control
alternatives evaluated include process modifications (relative to existing
designs) in addition to add-on control.
Approach
In this section a wide variety of potentially applicable pollution
control technologies are discussed. In addition, illustrative examples of the
application of individual control technologies to specific waste streams as
well as the application of integrated systems of control technologies to
specific waste streams are presented for each waste medium (i.e., gaseous,
aqueous, and solid media).
173
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Section 4
Pollution Control
Descriptions of the pollution control technologies presented in this sec-
tion are based upon more detailed descriptions provided in the Control
Technology Appendices for Pollution Control Technical Manuals. Performance
data for control technologies have been obtained primarily from the open
literature and supplemented by vendor-supplied data in some cases. The capa-
bilities of various controls have not usually been assessed on a design-
specific basis, but rather upon a generalized basis derived from available
test results and/or engineering studies of the subject technologies. Example
performance levels used for evaluation purposes encompass most of the pub-
lished data. Therefore, only limited data referencing is provided in Section
4; detailed references are available in the Control Technology Appendices.
In many cases, performance has been, and can only be, estimated in terms
of control of major constituents (e.g., volatile organic carbon) or gross
parameters (e.g., COD) since often no information is available for removal
efficiencies of specific substances. Further, even in those cases where sub-
stance-specific performance information exists for a control technology, accu-
rate or complete characterization of the waste stream being treated may be
lacking. In the final analysis, the capabilities of controls can be
accurately evaluated only by testing at operating facilities or at smaller
units from which data can be confidently extrapolated to commerical size. The
performance estimates in this manual are believed to reflect the best informa-
tion publicly available which is based on actual experience and on engineering
analysis.
In providing example applications of pollution control technologies,
waste streams unique to Lurgi-based synthetic fuels facilities and large
volume/high loading waste streams have been emphasized. The source and char-
acteristics of these waste streams have been detailed in Section 3, and those
characteristics of principal significance with regard to the application of
pollution control technologies are reiterated in this section. It should be
174
-------
Section 4
Pollution Control
noted, however, that Section 3 does not reflect the design of a specific
facility, but incorporates key features of a number of existing and proposed
facilities. Some of the waste streams identified in Section 3 may not be
found in all facilities. Further in a specific facility, some streams
encountered may differ significantly in size and characteristics from
analogous streams discussed in this section, and controls other than those
cited in the examples may be more appropriate. For these reasons, the reader
is encouraged to consider design-specific waste stream characterization data
whenever they are available, and to use the detailed Control Technology
Appendices for estimating the applicability and performance of specific con-
trols to waste streams. The control examples in this section emphasize the
Rosebud subbituminous coal cases. Effects of coal characteristics and design
modifications are discussed in cases where either may significantly influence
control performance or cost.
Quantitative reliability data on pollution control processes in most
industrial facilities, and in coal conversion facilities in particular, are
generally not publicly available. Many of the operators who keep records on
reliability feel that that information is proprietary to their business and
hence do not make it publicly available. As a result, much of the publicly
available information on process reliability consists only of relative judg-
ments, such as "the process is highly reliable" or "no significant reliability
problems have been encountered."
Because most of the pollution control technologies potentially applicable
to synthetic fuels facilities have not been employed in these facilities, few
directly related reliability data are available. Further, the overall charac-
teristics and variability of waste streams in synthetic fuels facilities are
often significantly different from those encountered in other industries. As
a result, reliability data accumulated in other industries may not be applic-
able to coal conversion processes.
175
-------
Section 4
Pollution Control
A large number of factors can affect the reliability of a process in a
specific application, including:
1) The design of the equipment;
2) The presence of spares or redundant equipment pieces for
critical parts of the process;
3) The variability of feed characteristics and operating
conditions;
4) The skill of operators and their dedication to making the
process work; and
5) The emphasis placed on corrective and preventive maintenance
and the skill and dedication of the maintenance personnel
From an examination of just the above factors, it is obvious that even identi-
cally designed processes in identical applications can have different reli-
ability records. It should also be noted that in essentially any industry,
the introduction of a new process or the modification of an older process for
application to a new stream can meet with unexpected problems relating to both
design features and operating practices. Thus, some shakedown period must be
expected during which process performance, efficiency, and onstream time will
improve. Once a process is properly characterized for a specified applica-
tion, reported reliability in terms of onstream time and performance levels
may still vary among facilities. However, it can be anticipated that relia-
bility will improve as experience is gained with individual systems and their
applications, i.e., reliability will increase with time.
176
-------
Section 4
Pollution Control
The reliability information presented in the rest of this section is in
the form of general comments on the reliability of pollution control pro-
cesses. The types of factors considered in developing these comments include
1) the complexity of the process (more complexity tends to indicate lower
reliability), 2) the age of the process (the continued use of a process over a
long period of time tends to indicate it can be designed and operated relia-
bly), 3) the sensitivity of the process to changes in the characteristics of
the feed stream (e.g. composition, flow rate, temperatures, pressure), etc.
More detailed discussions of reliability and available reliability data are
presented in the Control Technology Appendices for Pollution Control Technical
Manuals.
Organization
The pollution control technology evaluations are presented according to
the medium to which the technologies apply. Technologies applying to gaseous,
aqueous, and solid waste media are discussed in Sections 4.1, 4.2, and 4.3,
respectively. Included in each of these sections are 1) a summary of waste
stream characteristics which are significant with respect to the application
of pollution controls (detailed characterization estimates are presented in
Section 3), 2) a brief description of the performance and costs of potentially
applicable pollution control technologies, 3) examples of the performance ad
cost of individual pollution control technologies applied to specific waste
streams, and 4) examples of the performance and cost of integrated pollution
control systems.
Gaseous waste streams may be categorized according to the principal
pollutants which are present and, in general, different controls or groups of
controls are applicable to each category. Therefore, the technology
description and control examples are presented in Section 4.1 (Gaseous Medium)
by the waste stream categories or source types to which they apply.
177
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Section 4
Pollution Control
Source type categorizations may also be made for aqueous and solid
wastes. Waste streams in these media, however, often lend themselves to
treatment by control technologies which may be applicable to several indivi-
dual source types or to combinations of source types. Therefore, in Section
4.2 and 4.3 (Aqueous Medium and Solid Waste Management, respectively) poten-
tially applicable pollution control technologies are discussed at the begin-
ning of the sections prior to the presentation of control examples.
Costing Methodology
Capital and operating cost estimates have been developed for the control
processes discussed in this section. These cost estimates are based primarily
on estimates contained in non-proprietary published literature. The estimates
are provided to give the reader an indication of the costs of controls that
are applicable to Lurgi-based synthetic fuels plants. It was beyond the scope
of this document to develop detailed engineering designs necessary for highly
accurate cost estimation.
There are three general factors that lead to uncertainties in the cost
estimates provided. These are related to the assumptions used to develop
material and energy balances, the level of accuracy of the published cost data
used, and the general methodology used to apply the acquired cost data to the
control processes addressed in this document.
Material and energy balances were derived mainly from 1) commercial
synfuels tests and synfuels pilot plant studies, 2) data from analog
industries, and 3) engineering calculations, as described in Section 3 and
Appendices A and B in this volume. The level of accuracy in specifying the
flow rates and quality of input streams to controls will affect the accuracy
of the resulting cost estimates.
178
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Section 4
Pollution Control
Sources of cost data used in this document are published costs for pro-
cesses applied to similar streams in related industries, costs from published
design studies for coal gasification plants, and vendor quotes. The accuracy
of cost data taken from published sources is influenced by the details of the
design upon which the cost was based, the cost methodology used, and the
degree of similarity of the streams. In addition, the accuracy of the
published estimates and definition of the components included in these esti-
mates (e.g., contingency reserves, working capital, land) are not always
specified in the reference. Thus, extrapolation of published costs to the
stream being treated in this document will introduce uncertainties in the
resulting estimates.
The general costing methodology used in this manual (see Appendix C for
details) also introduces some uncertainties. Other estimators may choose to
use different factors for components such as direct and indirect installation
costs and interest during construction. In addition, available cost estimates
were adjusted to a first quarter 1980 basis using chemical process construc-
tion escalation indices. It is therefore possible that recent advances in the
state-of-the-art are not reflected in some of the resulting cost estimates.
As a result of the above influences, the accuracy of the cost information
presented will vary from control to control. However, the cost information
presented is believed to be adequate for the use intended.
The capital costs presented are total depreciable investments. Included
in the total depreciable investment is 1) installed equipment costs (including
the cost of delivered equipment and direct installation charges such as those
for wiring, piping, labor, etc.), 2) indirect installation charges (including
construction and engineering costs, contractor fees, and contingency), and
3) interest during construction. Startup costs are not included in the
179
-------
Section 4
Pollution Control
capital cost estimates presented, but could be a significant additional cost
for new technologies such as as those examined in this PCTM. Total annualized
costs presented include 1) labor and maintenance, 2) raw materials, utilities,
chemicals, and catalysts, 3) overhead charges, and 4) capital-related charges
(including interest on working capital, taxes, insurance, and capital
recovery). The same methodology was used to calculate capital and annualized
costs for both the base plant and pollution controls. Details of that method-
ology and other pertinent assumptions and bases which were used to develop the
cost estimates are presented in Appendix C.
180
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Section 4
Gaseous Medium
4.1 GASEOUS MEDIUM
Gaseous waste streams (or uncontrolled gaseous emissions) generated in
Lurgi gasification facilities and originating from the main process train and
from nonpollution control auxiliary processes were identified in Section 3.
Table 4-1 summarizes the characteristics of these streams along with
additional streams generated by pollution control processes in other media
(primarily water pollution control). In terms of volume and pollutant load-
ing, the most important streams in the subject facilities are Rectisol acid
gases and combustion flue gases. Pollutants of primary concern are reduced
sulfur species (H2S, COS. and RSH), SO,, and non-methane organics (or VOC -
volatile organic compounds). Smaller volume waste gases include coal lock-
hopper and transient waste gases, catalyst regeneration offgases, and depres-
surization/stripping gases. These streams contain the above pollutants and
one or more of the following: HCN, NHS, CO, and organic aerosols (possibly
containing polycyclic organic matter). Additional sources of VOC are fugitive
emissions from pumps, valves, and product/byproduct storage. Particnlate mat-
ter (other than organic aerosols) originates from coal preparation operations
and combustion units firing coal or high ash tars or oils.
The waste streams in Table 4-1 may be regrouped into two broad catego-
ries - those which are unique to gasification or synthesis operations and
those which are not unique, being associated with auxiliary processes within
an integrated facility. In Section 3, gaseous wastes were identified and
characterized from the standpoint of their origin in an integrated plant.
Table 4-2 is a regrouping of these waste streams according to the major types
of potential pollutants which they contain. Streams unique to the subject
facilities are primarily those containing reduced sulfur, non-methane organ-
ics, and smaller amounts of HCN and NHS. These are 1) Rectisol acid gases,
2) depressurization and stripping gases, 3) gasifier transient waste gases,
181
-------
TABLE 4-1. SUMMARY OF ESTIMATED GASEOUS STREAM CHARACTERISTICS IN LURGI-BASED FACILITIES
M
00
NJ
Stream Nut H,S COS
Streams frosj HI in
procen triin
Du«t ft OB coal — —
preparation
Bigh-pressure coal 0.4-1 0.01
lockhopper latea
Lo«-pretiure coal 0.4-1 0.01
lockhopper |»
Waste ft* tiom 0.2-0.5 0.01
atartupa, ahnt-
Constituent Concentration (Volume Percent Drv Basis)
Participate
RSH SO, VOC CO NH, BCN Hatter
— — — — — — Present
0.1 — 2 20 0.4-0.8 0.01 Present
0.1 — 2 20 0.4-0.8 0.01 Present
O.OJ — 1 10 0.2-0.5 0.01 Present
Flow Rate
(kmolt/hc dry
NO basis)
— Intermittent
and highly
variable
— 76"0 (average)
— 12 (average
undiluted
baais)
— 2000 (•aziBia);
30 (average)
dovns, and upsets
B,S Lean acid gases/
nonselective
Rectisol
CO,-rich acid gases/
selective Rectisol
BjS-rich acid gases/
selective
Shift catalyst decosr-
•issionlng offgas
Streams from synthesis
orocessina
1-3 0.01-0.03 0.01-0.5 —
<0.01 <0.01
5-25 0.05-0.25 0.1-0.5 —
1-4
10-20 —
(0.001 <0.01
0.1 <0.001 <0.01
<0.1 <0.001 <0.1
Present
— 6000 - 7000
— 4000 - 6500
— 300 - 2000
Present 150 (»»iiBU»);
10 (average)
Methanation catalyst
regeneration/decom-
missioning offgas
Mobil M-Oasoline
catalyst regenera-
tion offgas
— Present
Present — Dnknovn; very
infrequent
Present Present 100 (•axiuuB)
48 (average)
(Continued)
-------
TABLE 4-1. (Continued)
Constituent Concentration (Volume Percent Pry Basis)
Stream Nine
H,S
COS
ESU
SO.
voc
CO
NH,
HCN
Particulate
Matter NO
Flo* Rate
(kaols/hr dry
Str
nthesis
processlnt (continued)
Hethanation conden»tte —
depressnrization gases
COj-tich gases from
SNG production
Fugitive or|inlci from —
process sources
1-3
Present
0.1
— Unknown
— SO - 100
Intermittent
•nd highly
variable
OO
U)
StlttBt ftO»
suiiliarv processes
Floe fas from power —
generation
Product and byproduct Present
storage epillions
— 0.05-0.3 0.01
0.03
— Present —
Present
4-8 g/fe' Present 7000 - 20,000
— Intermittent
and highly
variable
Streams from water
pollution control
processes
Depressurizatlon and 0.4-1.0
stripping gases
Activated carbon
regeneration offgas
Wastewater incinerator
flue gas
Present
0.01-0.7 0.3-0.6 0.1-0.2 0.01-0.2
Present 1-5
— 0.02-0.1 Present Present
— 200 - 600
Present — 2000-2500
(maximum);
160-200
(average)
4-5g/N«« Present 3400 - 7300
Double dashes (—) indicate that the constituent is not present in any significant quantity in the subject ttreu.
-------
TABLE 4-2. CATEGORIZATION OF GASEOUS WASTE STREAM IN LURGI GASIFICATION FACILITIES ACCORDING TO SOURCE TTPE
Source Type
Stream Hue and Origin
Factors Affecting Flow Rite and Pollutant Loading
Reduced sulfur and
VOC-contlining gaaea
Rectitol acid gaaea Rectiaol acid gaaes
00
-P-
Small volume and
intermittent/
tranaient watte
gaae a
Transient proceaa
gases containing SO,,
CO, and/or particu-
latea
Combustion gaaea con-
taining SO,, particn-
late, and NO
Fugitive VOC
Nonfugitiva particolate
Fugitive partlculate
Depreaanriiation and atripplng gaaea
(tar/oil aeparation and water
pollution control)
Gaaifier tranaienta (startup, shut-
down, and off apecification gaaea)
Selective vs. nonaelective H,S and CO, removal; coal aulfnr; and coal rank
Preaaure of operation; may be coal apecific but data are not available to
determine relationships
Not readily related to coal variables, would be highly deaign- and operation-
specific
Coal lockhopper gaaea (Lurgi gaaifier) Coal rank; lock preaaurant; and proceaa deaign
Shift catalyst legenerstion/dscom-
•iaaioning offgaaea
Mobile M-gaaoline catalyst regenera-
tion offgasea
Miscellaneous catalyat decommissioning
offgaaes
Boiler flue gaaea
Procesa heater flue gaaea
faatewater incinerator fine gaaea
Product/byproduct atorage evaporative
emissions
Process equipment fugitivea
Cotl handling and preparation
Aah lookhopper vent gaaea
Coal atorage
Degree of shift (SNO va. liquids); regeneration frequency, bat not especially
related to coal variablea
Not related to coal variablea; primarily a function of throughput
Not related to coal; deaign and plant apecific
Not unique to gaaification plants; overall plant thermal efficiency; fuel
mix, coal rank, aah, and aulfnr content
Tend to be design/synthesis-specific; not related to coal parameters
Fuel used, extent of waatewater concentration prior to incinerator
Syntheaea and final product alate; Lnrgi byproducta somewhat coal-apecific
Entirely plant apecific; highly dependent upon synthesis and upgrading atepa
Coil physical propertiea and rank, but not related to gasification or syntheses
Coal aah content
Coal physical properties, but not related to gaaification or synthesis
-------
Section 4
Gaseous Medium
and 4) coal lockhopper gases. Unique streams containing S0a, VOC, CO, and/or
particnlates include shift and Mobil M-catalyst regeneration offgases, and
emissions from storage and combustion of Lurgi byproducts. Nonunique streams
found in all of the subject facilities would include coal combustion flue
gases, coal preparation dust, product storage emissions, and process VOC emis-
sions.
In the subsections which follow, controls which may be applicable to the
above gaseous wastes are identified. For those technologies for which data
are available, the expected performance and unit costs are provided. In many
cases, control of gaseous pollutants involves both inherent process design fea-
tures and tradeoffs among processes. Further, some waste gases would gener-
ally be combined for treatment rather than handled separately. Accordingly,
example approaches to control of pollutants in integrated facilities are pro-
vided. Sufficient detail is included in these examples such that overall
emissions reductions and costs can be seen. In the discussions below, empha-
sis is on the unique streams rather than on those streams for which informa-
tion about control may be found in other documents.
185
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
4.1.1 Rectisol Acid Gases
As discussed in Section 3, Lurgi gasification plants would employ the
Rectisol process(es) for removal of CO,, sulfur compounds, and HCN from
Lurgi gases. The regeneration of the methanol solvent produces waste gases
enriched in these acid gases. Since low molecular weight organics and, to a
lesser extent, carbon monoxide and hydrogen are also soluble in cold methanol,
Rectisol acid gases will also contain these constituents. In terms of waste
gas volume and loading, Rectisol acid gases are by far the largest source of
uncontrolled sulfur (sulfur in this context refers to all sulfur species:
HXS, COS, CS2, RSH, and S02) and VOC emissions in a Lurgi facility.
Approaches to treatment of Rectisol acid gases are aimed primarily at
removal of H2S and can be divided into three categories for discussion pur-
poses: 1) pretreatment, 2) bulk sulfur removal, and 3) tail gas treatment.
Partial or essentially complete control of non-H,S sulfur, HCN, CO, and VOC
can be realized either as an integral part of the sulfur control approach or
as separate intermediate or add-on steps. Pretreatment of the acid gases
serves two main functions: 1) to enrich acid gases for economical and effi-
cient sulfur removal by Claus type sulfur recovery (streams which contain less
than approximately 10% HaS require enrichment for efficient and economical
sulfur recovery in a Claus process); and/or 2) to remove impurities which can
either detrimentally affect downstream pollution control processes or present
nonsulfur emissions problems. Bulk sulfur removal is aimed at recovery of the
majority of the sulfur contained in the gases. Tail gas treatment is aimed at
control of smaller amounts of HaS and other sulfur compounds (e.g., mercaptans
and COS).
Since reduced sulfur compounds are the primary pollutant of concern in
acid gases, sulfur control is the main focus of control approaches for this
stream. However, other potential pollutants (HCN, CO, and VOC) are also
186
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
present in acid gases and their control will be necessary to either reduce
atmospheric emissions or to improve the performance of sulfur control
processes. Control of nonsulfur species can involve the design of
Rectisol, the design/operation of sulfur control processes, and/or the
addition of other processing steps.
187
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Pretreatment
Pretreatment
Table 4-3 summarizes the key features of selective Rectisol and amine
systems for enrichment of H2S in acid gases. As discussed in Section 3,
Rectisol systems can be designed to be either nonselective (no separation of
C02 and HaS during removal from Lurgi gas) or selective (removal such that an
HaS-rich gas and a C0a-rich gas are generated). Thus, selective Rectisol
itself may be considered as a pretreatment step for enrichment of the HaS
content of a portion of acid gases removed from Lurgi gas. Various levels of
selectivity can be obtained in Rectisol designs depending on the relative
economics of the Rectisol unit compared to the downstream Glaus plant or other
H2S enrichment alternatives (e.g., amine systems).
The Rectisol selectivity assumed for analysis purposes in this document
is based primarily upon data from an early, partially selective Rectisol unit
at Kosovo, Yugoslavia. Licensers of Rectisol technology (Lurgi and Linde,
West Germany) indicate that greater selectivity than assumed in this document
can be obtained with Lurgi type feed gases, and that the issue is primarily
one of economics, with hydrocarbon content of HaS gases as an additional con-
sideration for reliable Claus plant operation. Even with low sulfur feed
gases, selective Rectisol units have been designed and built to obtain H2S
fractions suitable for Claus processing without further enrichment (15% or
more H2S).
Selectivity in Rectisol systems is obtained by sequentially absorbing
H2S and C02 present in the feed gas and separately regenerating the resulting
HjS-rich and C02-rich methanol streams. First, HaS is removed from the feed
gas by absorption in C0a saturated methanol. Carbon dioxide is subsequently
removed by absorption in regenerated, HaS-free methanol. Rich methanol from
'H2S absorption is enriched in a fractional distillation column by removing a
188
-------
TABLE 4-3 . KEY FEATURES OF HYDROCAKBON REMOVAL/H,S ENRICHMENT PROCESSES
Process
Principle of Operation
Efficiency
Reliability/Limitations
Effects of High CO,
in Feed Gas
General Comments
Selective
Rectisol
oo
DIPA
(Di-isopropanol
slice)
MDEA
(Methyl
Di-ethanol
amine)
Physical absorption
with methanol at ele-
vated pressure. Selec-
tivity for BaS obtsined
both during absorption
and by concentrating
BtS in an enrichment
column during solvent
regeneration.
Chemical absorption at
atmospheric pressure.
Selectively absorbs
B,S over CO,. Gener-
ates an HjS-rich acid
gas and a COa-rich acid
gas. Also absorbs BCN
and a small fraction of
the COS.
Chemical absorption at
atmospheric pressure.
Higher selectivity for
B,S over CO, than DIPA.
Generates an B,S-rich
acid gas and a CO,-rich
acid gas.
B,S-rich acid gases
are concentrated enough
for Clans processing
and contain moat of the
orgsnics in the feed
gas. Total sulfur
levels in the C0,-rich
offgas can be as low
as 10 ppmv.
H,S-rich acid gaa pro-
duced is concentrated
enongh for Clans pro-
cessing. CO,-rich acid
gas contains the major-
ity of BCa. COS. and
mercaptans.
BtS-rich acid gases
produced are concen-
trated enough for Cltus
processing. C0t-rich
acid gaa containa the
majority of HCs, COS,
and mercaptans.
Bigh onstream factors
are realized with
existing Rectisol
units. Energy require-
ments and coata can be
high when both highly-
enriched Clana feeds
and nearly sulfur-free
CO, fractions are
desired. It is diffi-
cult to obtain Clans
feeds without organica
when anch compounds are
present in feeds.
CO,-rich acid gal
stream contains sulfur
compounds and organica
which may require re-
moval prior to dis-
charge.
CO,-rich acid gas
stream contains sulfur
compounds and organics.
Residual sulfur levels
not aa low as with
DIPA.
High CO, make a both
selective absorption
and regeneration more
capital coat and
energy intensive. Bigh
CO, makes separation of
COS more difficult, so
that larger towers are
needed to obtain a
sulfur-free CO, frac-
tion.
Reduces selectivity of
CO, over B,S and CO,
over COS.
Bas limited effect.
CO, does not react
directly with ter-
tiary amines.
Selective Rectisol has
seen wide commercial
application in both oil
gaaification and en-
trained coal gasifica-
tion. Suitable Claus
feeds and sulfur—free
CO, offgases are ob-
tained even with low
sulfur fuela. Existing
selective applieations
have not involved feed
gases with nonmethane
organios.
Applicable primarily for
hydrocarbon gaaea. Some
enrichment of B,S also
results. Capital costs
for DIPA range from i50
i 10' to 1330 x 10* per
Hg sulfur removed per
day, depending on the
total flow, B,S content,
and degree of enrichment
desired.
Limited commercial appli-
cation to date. Selec-
tivity for B,S over CO,
and the H,S level in the
treated gaa are very
senaitive to abaorber
temperature. Capital
ooata are similar to DIPA
where high selectivity is
not necessary. Tertiary
amines are leaa capital
intensive for selective
applieationa.
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Pretreatment
portion of the absorbed C02. This enriched methanol is regenerated to yield
an HaS-rich acid gas. Rich methanol from CO, absorption is regenerated to
yield a nearly sulfur-free, C02-rich acid gas which may be combined with C0a~
rich offgases from the enrichment column for discharge to the atmosphere. It
is the enrichment step within the Rectisol process which may be viewed as pre-
treatment.
Enrichment of H,S in Rectisol acid gases can also be accomplished using
amine-type processes (DIPA. MDEA, or TEA). Amine processes operate by chemi-
cal absorption of acid gases. Under the proper operating conditions MDEA and
TEA, and to a lesser extent DIPA, are partially selective for HaS over COj,
and the solutions do not appreciably absorb hydrocarbons. Thus, the major
advantage of such processes in Lurgi applications is that organics which are
not desirable in Glaus plant feed gas are largely separated from the H^S-rich
gas. Two gaseous streams are generated: 1) an enriched H2S stream which is
sent to a Claus unit and 2) a stream containing the majority of hydrocarbons
and C02. The COj-rich stream from the amine process contains residual sulfur
and VOC. Decisions regarding the extent of Rectisol enrichment and necessity
or desirability of amine enrichment involve both economic and technical trade-
offs in an integrated facility. From an environmental standpoint the specific
enrichment process employed is not of great importance as long as the offgases
are subsequently treated for sulfur control.
In addition to the flexibility for HaS/COa selectivity, the Rectisol pro-
cess also provides for varying degrees of control/removal of HCN, NH,, CO, and
hydrocarbons from bulk acid gases. In Rectisol designs for Lurgi gases, the
naphtha removal step also results in the removal of HCN and NHa since the spe-
cies are very soluble in the methanol prewash solvent. About half of the
removed HCN will remain as a component of the crude naphtha, the other half
and essentially all of the ammonia joins the methanol/water phase. During
190
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Pretreatment
methanol/water separation by distillation, HCN can either be stripped for
routing to a Clans unit for destruction or fixed via caustic addition for sub-
sequent treatment in the aqueous phase.
Control of carbon monoxide in acid gases can be provided by Rectisol sys-
tems. Carbon monoxide is sparingly soluble in methanol, and that which is ab-
sorbed at process pressure from Lurgi gas can be largely recovered as a sepa-
rate CO-rich C02 stream by flashing of laden methanol to an intermediate pres-
sure before H2S/COa removal. The CO-rich offgas can be subsequently inciner-
ated, perhaps with heat recovery. The CO-rich offgas may also be recompressed
for addition to Rectisol product gas if the resulting C02 load is compatible
with synthesis requirements. Either approach is usually preferred to "add on"
control of CO in C0a-rich acid gases (selective mode) or H^S lean acid gases
(nonselective mode) due to the energy penalty associated with incineration of
high volume, low heating value gases.
Control of potential VOC emissions can also be achieved to some extent
via Rectisol design. Hydrocarbons vary in their solubility in methanol ac-
cording to their molecular weight. Ethane exhibits limited solubility while
propane is intermediate in solubility between H^S and C02. Hydrocarbons with
more than three carbon atoms (C4+) are more soluble than H S in cold methanol
and are largely removed in the naphtha prewash step of either selective or
nonselective Rectisol. The ethane/ethylene component of Lurgi gas presents
the greatest difficulty for control since C^s constitute the largest non-
methane hydrocarbon component of Lurgi gas and most C^s will be removed from
Lurgi gas by cold methanol. Only part of the absorbed C2s can be recovered by
flash regeneration; hence the remainder will be present in either the CO -
rich offgases of selective Rectisol or H2S-lean offgases of nonselective
191
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Pretreatment
Rectisol. The C,/C4 component can be largely recovered in the HaS-rich offgas
of selective Retisol with little remaining in the C0a~rich fraction. Essen-
tially all C3/C4s would be potential emissions in H^S-lean offgas from non-
selective Rectisol.
As mentioned previously, amine processes have the advantage of separating
organics from HaS during enrichment. Thus, amine enrichment simplifies Glaus
plant design compared to enrichment with selective Rectisol. However, the
amine offgas containing the separated organics would also contain some sulfur
compounds. In contrast, enrichment within selective Rectisol can result in a
nearly sulfur-free offgas.
Amine processes using DIPA or MDEA are not expected to generate secondary
wastes other than sour condensates when excess moisture must be handled in
feed gases. Some solvent losses are reported due to leaks, but no routine
blowdown of solvents is reported in existing applications.
192
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Bulk Sulfur Removal
Bulk Sulfur Removal
To date, only three processes have had any significant commercial appli-
cation for the removal of H^S from acid or fuel gases: the Glaus, Stretford,
and Giamarco-Vetrocoke (G-V) processes. These are the only processes examined
in the present study because of their commercial status, reliable operation,
applicability to the wide range of sulfur contents in the acid gases, and, in
the cases of Claus and Stretford processes, availability of operating require-
ments and capital cost data. It is recognized that other processes are avail-
able or have been proposed; however, it is unlikely that processes other than
Claus, Stretford, or Giamarco-Vetrocoke will be utilized in first generation
coal gasification facilities in the U.S. In existing applications, Stretford
units are favored economically over Claus units for feeds containing only a
few percent sulfur, although Claus plants have operated successfully on feeds
containing as low as 8% HaS. The Giamarco-Vetrocoke process is generally
applicable to streams with HaS concentrations of up to 1.5%. Table 4-4 sum-
marizes the key features of bulk sulfur removal processes.
The Claus process is a dry, high temperature process in which H^S is
catalytically reacted with S02 to form elemental sulfur. Two basic versions
of the process: "straight through," and "split flow," are described. In the
"straight through" mode sufficient air is added to oxidize one-third of the
HjS to S0a. The "split flow" mode, shown in Figure 4-1, is often used when
H2S-levels in the feed gas are below 25% by volume or where high CO, levels
are encountered. The acid gas is split into two streams and one-third of the
input acid gas is combusted in a reaction furnace to form SO,. Heat is
recovered from the gas before it is recombined with the other two-thirds of
the feed. The combined stream then enters a series of converter stages where
elemental sulfur is produced. Regardless of the Claus mode, the number of
stages determines sulfur removal efficiency; Claus units of three-stage design
193
-------
TABLE 4-4. KEY FEATURES OF BULK SULFUR REMOVAL PROCESSES
Cl.ui
Stratford
Giamarco-Vetrocoke (G~V)
Inoineration/SO, Reaioval
Principle of
Operation
Components
Removed
Efficiency
Feed Stream
Requirements/
Restrictions
Byproduct!
Secondary
Waste Streams
Reliability/
Limitations
Effects of Bigh
CO. in Feed
Catalytic oxidation of
BaS and SO, to ele-
mental sal for*
B,S, COS. RSH, VOC,
NH., and BCN.
Liquid phase oxidation of B,S
to elemental sulfur in an
alkaline solution of metavan-
adate and anthraquinone
ditnlfonic acid.
H,S, BCN, and CH.SB.
Over 95% total S, other As low aa 1 ppmv H1S but no
combuatibles partially removal of non-B,S sulfur.
destroyed.
Streams containing B,S
level* much below 10*
require enrichment prior
to processing. Organ-
ic* cause combustion
control problems and
"grey" sulfur.
Elemental sulfur.
Spent catalyst and
catalyst regeneration
decommissioning offgas.
NB, and BCs may cause
catalyst plugging and
variable sulfur
recovery.
Can adversely affect
sulfur removal ability
of the process.
High BCN loading should be
reduced prior to processing
to prevent excessive solution
purge.
Elemental sulfur.
Oxidixer vent ga* and purge
solution.
Process does not remove COS,
RSB. or organics. BCN form*
nonregenerable salts in scrub-
bing solution.
Bigh CO, concentrations will
decrease absorption efficiency
by lowering solution alkalin-
ity. Increased absorber tower
height and addition of caustic
are required.
Liquid phase oxidation of B,S
to elemental sulfur in sodium
carbonate and arsenate/
arsenite solution.
B,S. COS. and CSa.
99.99% B,S removal.
maximum 1.5% B,S in feed.
Elemental sulfur which may
require arsenic removal.
Oxidation of reduced sulfur and
organica, followed by SO, re-
moval using either regenerative
or throwsway POD technologies.
B,S, COS, RSB. VOC. and CO.
A* low aa 100 ppmv VOC is in-
cinerated ga* and up to 99%
total sulfur removal.
In principle, gaae* with any
level of B,S and other reduced
sulfur compounds could be in-
cinerated and subsequently
treated via FGD. Other com-
ponents cause no problem*.
Either C*S04, concentrated SO,,
or throwaway lime (lodge* arc
generated by FGD unit*.
Oxidixer vent gas and arsenate/ Some oondenaate and scrubber
arsenite wash water. sludge.
Haxardons nature of arsenic
solution may caoae handling
and safety problems.
Little or no effect.
FODs have varying degrees of
reliability and generally have
lower onatream factors than
process units.
No effect except to increase
energy requirement for inciner-
ation if insufficient combust-
ibles are present in feed gas.
(Continued)
-------
TABLE 4-4. (Continued)
Cl«u»
Stretford
Giaaarco-Vetrocoke (G-V)
Incinerttion/SO, Renovtl
Capital Cost*
General Comment!
i2S to ilBO x 10' pex
H| eulfnr/day capacity
dependlni on both total
flow and sulfnr content.
Applicable only to acid
ia*e* froai selsetive
AGR. Bydtocarbon re-
•oval fro* feeds Bay be
necettary.
IllO to 1270 x 10" per Kg
ml fur/day capacity, depending
primarily upon total flow.
1 ppanr BtS in tail faa ia
poaaible, however bi|her limits
are proposed when nigh levels
of other reduced sulfur species
are preaent in tail gas.
No cost data available.
Limited data available. Hai-
ardoos nature of araenic solu-
tion cukes application nnlikely
in large D.S. facilitiea.
»700 to 11700 x 10' per Mg
snlfnr/day capacity depending
npon total flow and degree of
snlfnr removal.
FGD process has osnally been
applied to coabustion fine
gsaes containing less than 5000
ppmv SO, and achieving abont
90% control. Performance and
cost dsta for higher SO, feeds
achieving 99% control are
limited.
'Costs are first quarter 19SO dollars.
-------
VD
HP
STEAM
CLAUS _
FEED
t
D REACTS
FURNACE
,,i,J
t
BFW
^
1
n
/
HP
STEAM
\
LP
STEAM
• t
CONDENSER
NO,
t
BFW
L| *44 &>B —
*
(CONVERTER \
NO, )
J
r\REHEATER
/NO,
1
Q
s
HP
STEAM
LP
STEAM
• t
1 CONDENSER
NO. 2
t
BFW
r 1
*
(CONVERTER \
NO. 2 1
^
^\ REHEATER
^/NO. 2
^
H
f
HP
STEAM
LP
STEAM
t
CONDENSER
NO. 3
t
BFW
' )
t
(CONVERTER |
M0.3 )
Jt
>\REHEATER
^NO. 3
^
TAIL
i
LP
STEAM
• t
CONDENSER
NO. 4
t
BFW
r i
GAS
t
LIQUID
SUl FUR
SULFUR PIT 1
BLOWER
Figure 4-1. Three stage Claus plant with split flow option
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Bulk Sulfur Removal
can achieve overall removal efficiencies of over 95%. Gaseous sulfur species
distribution in Clans tail gas in high C0a applications is approximately 60%
H,S, 30% S0a, 9% COS, and 1% CS2. Elemental sulfur as both vapor and en-
trained mist can contribute 20 to 50% to the total sulfur in Claus tail gases,
depending primarily on the level of H2S in the Claus feed and the effective-
ness of mist eliminators. The relative contribution of elemental sulfur to
total sulfur in Claus tail gas generally increases as H»S content of Claus
feed gas decreases.
In the "straight through" mode of Claus operation, organics, HCN, and NH,
in the feed are largely converted to carbon dioxide, water vapor, and elemen-
tal nitrogen. Such components are not ordinarily of concern unless levels ex-
ceed perhaps 1% each. Organics make control of combustion stoichicane try and
temperature more difficult and can lead to sulfur-containing elemental carbon
(grey sulfur), particularly when olefins and aromatics are present in the
Claus feed. HCN at high levels causes corrosion throughout the process while
NH3 can form deposits which plug/deactivate Claus catalysts. The problem with
organics is usually solved by limiting their content in the Claus feed. HCN
at high levels can be destroyed (converted to NH3) prior to entering the Claus
furnace using Claus or shift type catalysts under reducing conditions. Ammo-
nia at high levels requires either bulk removal prior to Claus or special
design to control temperatures and minimize deposition of ammonia salts.
Use of the "split flow" mode allows for control of the sulfur combustion
process in the Claus plants with feeds containing less than about 25% H^S or
more than about 30% C0a. Only about one-third of the organics, HCN, and
NHj in Claus feed gases would be destroyed in the split flow mode unless
streams containing high levels of these constituents are specifically routed
to the combustion furnace of the Claus plant. Generally, organics present the
most difficult problem for split flow Claus plants, leading to carbon
197
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Bulk Sulfur Removal
contaminated sulfur. Two thirds or more of the input organics, HCN, and NH3
to split flow Claus plants may be present in Claus tail gases prior to
incineration.
Due to the problem of carbon contaminated sulfur with split flow
operation, other approaches to combustion control with dilute Claus feeds
have been utilized. First, combustible gases such as CO, H2, or CH4 are added
to the feed in the straight through mode. Liquid sulfur has also been used.
Second, and of particular attractiveness in coal gasification facilities, is
the use of oxygen or enriched air. Use of 02 not only improves flame stabi-
lity but also decreases the inert volume throughout the Claus and any subse-
quent tail gas treatment units. Since unit sizes and associated costs are
flow-dependent, savings can be realized. Of course, orygen is expensive to
generate, but much of the capital cost is already absorbed in a gasification
facility which would necessarily have a large oxygen plant onsite. Thus, the
incremental 02 costs for Clans use would be relatively low. Finally, the
acid gas and/or air can be preheated before being fed to the Claus burner,
using steam or flue gas from fuel combustion as the heating media.
The Claus process produces spent catalyst and catalyst regeneration off-
gases where catalyst regeneration has been used. The Claus catalyst has an
estimated life of two to three years. Regeneration of catalyst is performed
intermittently at a few facilities when the efficiency of the process drops
below accepted levels.
The original Stretford process (as developed by the British Gas
Corporation) is a liquid-phase oxidation process using an aqueous solution of
sodium vanadate and anthraquinone disulfonic acid (ADA) in which HaS is both
absorbed and converted to sulfur. Figure 4-2 is a simplified flow diagram of
the Stretford process. The HaS is absorbed in either a packed tower (or
198
-------
ACID
GAS '
r
TAIL GAS
C. W.
ABSORBER
VENT
PRIMARY
OXIDIZER
AIR
i
H2S RICH GAS
WATER CHEMICALS
SOLVENT
MAKE-UP
LA
SECONDARY
OXIDIZER
RECOVERED CHEMICALS
WATER
CENTRIFUGE
STEAM
SULFUR
MELTER
SEPARATOR
REDUCTIVE
INCINERATION
PURGE SOLUTION
SULFUR
Figure 4-2. Simplified flow diagram of the Stretford process
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Bulk Sulfur Removal
contacted in a venturi scrubber) and then oxidized to sulfur by the sodium
vanadate. Reduced vanadium is then oxidized by the ADA solution. ADA is
regenerated by air in the oxidizer tanks where elemental sulfur is removed as
a froth. A continuous solution purge is required to remove the buildup of
sodium thiosulfate and sodium thiocyanate. Until recently, disposal or treat-
ment of the purge solution containing thiosulfate, thiocyanates, and small
amounts of vanadium salts was required. In 1973, a reductive incineration pro-
cess was developed which converts the purge solution into a gas stream con-
taining HjS, water vapor, and a solid residue containing soda ash and reduced
vanadium salts. The salts are returned to the Stretford process as makeup
chemicals and the HJS-rich gas and water vapor are recycled to the absorber as
shown in the figure. Thus, the reductive incineration process recovers expen-
sive chemicals while effectively attaining a zero discharge of purge solution.
To date, no commercial Stretford unit has employed the reductive incineration
process.
Recently, modifications of the original Stretford process have been
developed. One version of the Stretford process has been used at the SASOL
Lurgi coal gasification complex in South Africa. At SASOL, severe plugging
problems have occurred in the Stretford towers which apprently relate to the
high C04 levels in the Stretford feed compared to feeds in other applications.
Preliminary information indicates that sulfur deposition is primarily respon-
sible. SASOL has modified the original Stretford unit, presumably substitu-
ting a different absorbent but saving the bulk of the existing equipment.
The process modifications mentioned previously owe a major portion of
their design/development impetus to this SASOL experience. In one, under
development by Union Oil, a different (proprietary) solution is employed,
while in the other (Peabody-Holmes) a venturi absorber replaces the packed
tower. The latter Peabody design, which features reductive incineration of
Stretford blowdown, is used as the basis for evaluation in this document.
200
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Bulk Sulfur Removal
The Stretford process generates two waste streams: the ozidizer vent
gas and the purge solution. The purge solution is treated via the
reductive incineration process where sulfur is recovered as H^S for recycle
to the absorber and sodium and vanadium salts are recovered for reuse. The
oxidizer vent gas is expected to consist mostly of air, C0a, and water vapor;
however, some mercaptans and ammonia may also be present.
Except for the Stretford unit at SASOL, applications of the Stretford
technology to date have been in natural gas, coke, petroleum, and related
industries with feed gases containing only a few percent C0a and little, if
any, non-H S sulfur compounds. With feed gases such as those at SASOL which
contain over 90% C0a. C0a absorption by the Stretford solution lowers the pH
and alkalinity which in turn lowers the rate of HaS absorption. Larger
Stretford towers can be employed to address the H2S absorption kinetics pro-
blem. Caustic addition is necessary for pH control which leads to larger
solution blowdown rates. The secondary problem of sulfur formation and depo-
sition in the absorption towers occurs when alkalinity is not maintained, and
is thought to result from decomposition of thiosulfate.
A separate limitation from the operating problems which the Stretford
process has experienced in the high C0a application at SASOL, is that the pro-
cess is not capable of removing carbonyl sulfide. Whether any removal of mer-
captans from feeds containing such species occurs is also unclear at this
time. Very low levels of H,S can, however, be obtained in Stretford offgases,
with many units in low C0a applications reporting less than 10 ppmv H»S. Unit
costs, however, increase with decreased HaS in the offgas. Designs proposed
for application in several U.S. coal gasification facilities call for 100 ppmv
(or less) HjS. Since as much as 1300 ppmv of non-H,S sulfur compounds are
present in Stretford tailgases, designers apparently felt that levels of HaS
lower than 100 ppmv were not justified.
201
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Balk Sulfur Removal
Noncondensible organic components of Stretford feed gases pass through
the process essentially unchanged (unabsorbed). In contrast, HCN and NH, in
feed gases are largely absorbed in the Stretford solution. HCN is converted
to SCN which would eventually exit the system with the purge solution.
Generally, levels of a few ppmv HCN present no problems, but higher levels
translate into larger solution blowdowns. Ammonia absorbed from Stretford
feed gas is partly expelled during the sulfur oxidation step by air stripping.
An "inventory" of NH3 would be established by the circulating solution so that
some NHj would also exit the system with the blowdown. In Lurgi applications,
NH3 and HCN originate from the gas liquor stripper overhead rather than from
Rectisol acid gases. Levels of these species in the overhead gases are not
large enough to present problems of excessive purge solution or oxidizer emis-
sions.
The Giamarco-Vetrocoke H,S removal process is a liquid phase oxidation
process using an absorbent solution of alkali arsenates/arsenites in which
H2S is both absorbed and converted to elemental sulfur. Sodium carbonate is
the alkali usually applied for removal of large quantities of sulfur because
of its relatively low cost. The Giamarco-Vetrocoke process is applicable to
gas streams containing up to 1.5% HaS and can reduce H2S levels to 0.5 ppmv
or less. The HaS is absorbed at pressures from 0.1 to 7.5 MPa by counter-
current absorption. Rich solution from the absorber is subsequently oxidized
in an atmospheric pressure, air-blown column to produce regenerated solution
and elemental sulfur. Product sulfur is recovered by froth flotation, fil-
tered, and washed. Based upon limited available data, the only waste streams
generated by this process are wash water from the sulfur washing operation and
oxidizer vent gas. Characterization data are not available for these streams,
although the wash water will contain arsenate/arsenite absorber solution.
One other approach to bulk sulfur control should be mentioned. In
principle, acid gases can be directly incinerated to convert organics, CO,
202
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Bulk Sulfur Removal
and reduced sulfur and nitrogen species to C02, HJ0, N2, and SO . SO
removal from the incinerated gas could then be accomplished using any one
of a number of available FGD processes (see Section 4.1.2). Generally, such
an approach is unattractive for several reasons. First, throwaway FGD systems
create large solid waste disposal problems. Secondly, recovery type FGD sys-
tems often feature Claus or Claus type processes for elemental sulfur recov-
ery; thus, there is little to be gained over direct use of Claus or Stretford.
For example, the Allied process (licensed by Allied Chemical Corp.) is essen-
tially a Claus unit preceded by a reduction step where part of the S02 is
reduced to H2S with gas containing C0/Ha. H2S and S02 are then converted to
elemental sulfur over a catalyst. Thirdly, in high S02 applications, FGD sys-
tems are expected to be several times more costly than Claus or Stretford
plants applied directly to crude acid gases.
However, for facilities using very low sulfur coals, the direct incinera-
tion/FGD approach might be employed. For coals with, for example, less than
0.2% sulfur, nonselective Rectisol acid gases would contain less than 0.3%
HaS. Enrichment of such low sulfur gases to levels suitable for Claus proces-
sing or direct application of Stretford may not be as economically attractive
as the incineration/FGD alternative, particularly if the FGD system could be
integrated with the onsite boiler.
203
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Tail Gas Treatment-Sulfur
Tail Gas Treatment - Residual Sulfur
A number of processes are commercially available for treatment of
sulfur plant tail gases or other waste gases containing low levels of
reduced sulfur species. Table 4-5 summarizes the key features of the most
prominent of these processes. The processes can be broken down into three
generic types:
1) Extensions of the Claus process - such as IFP-Clauspol 1500,
Sulfreen, and BSR/Selectoz.
2) Conversion of sulfur species to sulfur dioxide (S0a) by
incineration, followed by S0a removal - such as Wellman-Lord or
Chiyoda Thoroughbred 102.
3) Conversion of sulfur species to H2S followed by its removal using
such processes as Beavon/Stretford and SCOT.
Processes in the first category are used exclusively for Claus plant
tail gases and are capable of approximately 80% recovery of the sulfur in
the tail gas. These extensions of the Claus process require a 2:1 HaS to S0a
ratio for proper operation. These processes have limited removal capabilities
(not less than 1000 ppmv total sulfur) and have not been proposed for applica-
tion in Lnrgi gasification facilities in the U.S.
The second category of processes involves incineration of the waste
gas followed by SO removal. Such processes are capable of achieving levels
as low as 150 ppmv of S02 in tail gas. One of the more prominent processes,
the Wellman-Lord, was examined for costing purposes. The Wellman-Lord process
removes SO, with an alkaline sodium sulfite solution. Subsequent regeneration
of the absorbent generates a concentrated S0a stream which would be recycled
to the parent Claus plant. Two approaches to incineration can be employed.
204
-------
TABLE 4-5. KEY FEATURES OF RESIDUAL SOLFDR REMOVAL PROCESSES
Beavon
SCOT
Incineration
Incineration Plna SO,
Removal (FGD)
Principle of
' Operation
Component•
Removed
Efficiency
Feed Stream
Requirement a/
Reatrictlona
Catalytic reduction of
ml far coBponnde to B,S,
followed by integrated
Stretford proceaa.
B,S, COS. C,, and SO,.
Dp to 99.8* total ml for
removal in combination
•1th the Clana plant or
can attain equivalent
of 50 ppn total anlfnr
in tail faa (not inclnd-
Ing reducing gaeea).
Snlfnr apeclea are oetalyt-
ically reduced to HtS; B,S
la acrobbed in a regenerable
aaiiae ayatem.
H,S, SO,. COS. and CS,.
Dp to 99.5* total anlfnr
removal in combination with
the Clana plant or can attain
equivalent of 250 ppei total
anlfnr in tail ge< (will vary
dependinf on CO, and 8,8
concentration in specific
applioatlona).
Thermal incineration in
incinerator or onaite ateam
and power boiler or catalytic
incineration.
Convert* reduced aulfnr apeciea
to SO,, alao removea BCa.
CB.SH, NB,, and BCN.
Eaaentlally 100% converaion
of reduced anlfnr to SO,.
No removal achieved.
Incineration (on onaite boiler
or aeparate incinerator) fol-
lowed by SO, removal (e.g.,
lellman-Lord).
SO,
NB,
alao removea HCi, CH,SB.
nd BCN.
Dp to 99% total aolfnr re-
moval from Clana tail ga> or
50 ppm SO, in tail gaa and
complete removal of other
conponnda.
O
Ln
Byproduct a
Secondary
taate Streama
Reliability/
Llmltationa
Effecta of Bigh
CO, in Feed
Capital Coata*
General Commenta
Elemental anlfnr.
Sour condenaate, oxl-
diier veat gai, aoln-
tion purge and apent
catalyat.
Baa only been applied
to Clam prooeaa tail
faaea.
Reduce* converaion
efficiency of catalyat
and decreaaea fl,S
abaorption in Stretford
aolntlon.
i20 to iSO i 10' per
Hf/day of S at Clam
plant.
Exact ppm limit achiev-
able in coal gaaiflca-
tlon application la not
known. 100 ppm ia
believed by vendor to be
attainable.
Concentrated B,S.
Sonr condeneate and apent
catalyat.
Requlree further treatment
and/or recycle to Clana.
Redncea converaion efficiency
of catalyat and efficiency of
alkanolamine ay*tem.
{20 to (60 x 10' per Mg/day
of S at Clana plant.
Offgai from amino acrnbber
i> not aa low in total sulfur
aa Beavon proceaa.
None.
Spent catalyat from cata-
lytio incineration.
Doee not remove eulfari only
converta to another form
(SO,). Catalytic incinera-
tion may not be able to handle
hlgh-BC and anlfnr content
gai atreama.
None.
Refer to Table 4-3 for coata.
Hay be a low coat control for
atreama with amall amount! of
anlfnr compounds. Onaite
boiler incineration can almnl-
taneonaly remove SO, in FOD.
Snlfnr or anlforic acid from
lellman-Lord prooea*.
Sonr condenaate and aolntion
parge.
Solid waetea may be generated
by throwaway FGD proeeaaea.
None.
t40 to IllO x 10* per Kg/day
of S at Clana plant.
Onaite boiler/FDD ayatem la
the moat likely candidate.
Installing a aeparate inciner-
ator and FGD would not be aa
economically feasible.
-------
TABLE 4-5. (Continued)
Sulfreen
Cleanair
IFF Cliui 1,500
IFP-2
BSP/Sel«ctox
Principle of
Operation
Componentt
Removed
Efficiency
Feed Siren
Requirements/
Restrictions
Byproducts
Secondary
Waste Sreams
Bel lability/
Limitations
Effects on High
CO, in Feed
Solid phase continuation
of Clint reaction at a
low temperature.
B,S, SO,. COS. and CSa.
Dp to 30 to 35% removal
of sulfur in the till
Optimnai performance
requires 8,8:50, ratio
of 2:1.
Elemental liquid aulfur.
Spent catalyst.
Baa only been applied to
Clans process tail gases.
No effect.
Catalytic reduction of Liquid phase continuation
sulfur compounds to of Clans reaction at a
H,S followed by a con- low temperature.
tinuation of the Claus
reaction and Streford
process.
BaS, COS, CS,, and SO,. H,S and SO,.
Reduces sulfnr to less Reduces sulfur species in
than 250 to 300 ppm Clans tall gas to 1500
SO, equivalent in ppm as SO,.
effluent.
B,S:SO, ratio can vary B,S:SO, ratio muat be
General Comments Much higher residuals in
tail gas than Beavoo
process.
up to 8:1 without
affecting efficiency;
designed specifically
for Claua tail |as.
Elemental aulfur.
Spent catalyst.
Bas only been applied
to Clans process tail
gases.
Bednces conversion
efficiency of cata-
lyst; decreases B,S
absorption in Stretford
solution.
Cannot attain as low a
residual snlfnr level
in tail |aa as Beavon
process.
maintained in the range
of 2:0 to 2:4.
Elemental sulfur.
Spent catalyst.
Baa only been applied to
Clans procesa ttil
gases.
No effect.
Cannot attain as low a
residual sulfur level in
tail gas as Beavon
process.
Incineration of tail
gas followed by ammo-
nia scrubbing. Solu-
tion is evaporated to
produce a concentra-
ted SO, stream which
is returned to the
Clans plant.
COS. CS,, and B,S.
Catalytic reduction
of sulfur com—
ponnds to B,S, fol-
lowed by oxidation
of H,S to sulfur
over Selextox
oatalyat.
B,S. SO,. COS. and
CS,.
Reduces aulfur species Dp to 99.5% total
in Clans tail gas to
leaa than 500 ppai.
B,S:SO, ratio must be
•aintained in the
range of 2:0 to 2:4.
pent catalyst.
Bas only been applied
to Claus procesa tail
gaaea.
No effect.
Cannot attain as low
a residual snlfnr
level in tail gaa as
Beavon process.
sulfnr removal
equivalent to 750
ppmv SO, in the
Incinerated offgaa.
B,S:SO, ratio must
be maintained in
rang* of 2:0 to
2:4. BC and NH,
should be In the
feed.
Elemental liquid
aulfur.
Spent Beavon and
Selectox catalyst,
and sour conden-
aate.
Bas only been
applied to Clans
plant tail gas.
Reduces conversion
efficiency of BSR
oatalyat.
Bigher sulfur emis-
sions than Beavon
process.
*Costs are first quarter 1980 dollars.
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Tail Gas Treatment-Sulfur
either separate incineration (with added fuel where needed) or incineration in
an onsite boiler. Either option would produce similar net results from the
standpoint of sulfur oxidation.
The third category of processes involves catalytic reduction of
oxidized sulfur species to HaS followed by HaS removal from the gas stream by
solvent absorption. In general, the designs of these processes are influenced
by high levels of C0a in the feed gas. The C0a reduces the efficiency of
catalytic reduction of COS and CSa to HaS and impairs the effectiveness of the
HaS removal/recovery systems.
Both the Beavon/Stretford and SCOT processes are commercially available
catalytic processes which are potentially applicable to coal-derived sulfur
plant tail gases. These processes feature two sections: a hydrogenation sec-
tion to convert sulfur species in the gas to HaS and an HaS absorption sec-
tion. In the hydrogenation reactor a reducing gas is added to the feed gas
and the combined gas stream is passed over a cobalt molybdate catalyst. The
hydrogenation/hydrolysis reactions occur in the catalyst bed reducing the sul-
fur species to HaS. From the standpoint of non-HaS conversion, the Beavon
and SCOT catalytic steps may be considered as nearly equivalent.
The Beavon process includes a Stretford unit for HaS absorption. The
SCOT process includes absorption of the HaS in an alkanolamine scrubbing sys-
tem. The absorbing solution is then regenerated, resulting in a HaS-rich acid
gas which is ordinarily returned to the parent Claus plant for treatment. The
alkanolamine scrubbing system ultimately limits the SCOT'S capabilitities
because the solvent is only partially selective for C0a over HaS. Thus, where
feeds contain large amounts of C0a, it is more difficult to generate an H^S
stream suitable for Claus processing while simultaneously obtaining a tail gas
stream with a low level of total sulfur. In high C0a applications, vendors of
207
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Tail Gas Treatment-Sulfur
the Beavon process report that levels of less than 100 ppmv total sulfur
can be achieved, while vendors of the SCOT process guarantee less than 350
ppmv total sulfur (Claus plant tail gas bases).
Inherent limitations of selectivity in the amine absorption step of
the SCOT process places a lower limit of about 200 ppmv of H,S which will be
present in SCOT tail gases. In comparison, the Stretford unit following
the Beavon reactor can remove H2S to as low as 10 ppmv HaS. Both systems
would result in 20 to 100 ppmv tail gas COS in high C02 applications. It
might be noted that the higher levels of H2S in SCOT tail gases in existing
applications have necessitated that the gases be incinerated to minimize odor
problems while Beavon tail gases have generally not required incineration.
However, the previous discussion relating to the operating problems with
Stretford in high C02 service is equally applicable to Beavon/Stretford.
Also, no Beavon/Stretford units currently exist in high C02 service, while
several SCOT units have successfully operated on feeds with C02 levels
above 40%. These SCOT units are designed to meet a 500 ppmv total sulfur
limit.
208
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Tail Gas Treatment-VOC
Tail Gas Treatment - VOC, CO, HCN, and NH»
As discussed previously, partial or total control of the subject species
can be achieved during bulk sulfur removal or sulfur tail gas treatment. The
combustion furnace of a Clans unit destroys these constituents but only in
that portion of the gas passing through the furnace. HCN can also be destroy-
ed over Glaus type catalysts used ahead of the Claus plant itself. HCN is
removed from feed gases in the Stretford process, forming SCN which leaves
the systems with the aqueous blowdown. NH, is also partially removed by
Stretford solvent, while organics and CO are not removed by Stretford.
Catalytic sulfur tail gas treatement systems achieve control of any
HCN contained in sulfur plant tail gases. Both Beavon and SCOT catalytic
sections will result in essentially complete conversion of HCN to NH3 and
CO. Hydrocarbons, CO, and NH} contained in the feed to Beavon or SCOT
units or added/generated within such units will be present in tail gases.
Incineration of these tail gases would destroy these constituents. As
mentioned above, SCOT tail gases are ordinarily incinerated to minimize
odor problems arising from residual H>S. Beavon tail gases (with lower H^S
levels) are not ordinarily incinerated, but an incineration step can be
added for control of organics, CO, and/or NH3. SO, tail gas treatment pro-
cesses, such as the Wellman-Lord, inherently achieve control of VOC, CO, and
NH3 as part of the incineration step.
Table 4-6 summarizes the advantages and disadvantages of the various
incineration technologies aimed primarily at control of volatile organic com-
pounds. Generally, a greater degree of control is obtained with high tempera-
ture incineration in either a fuel-fired boiler or a separate incinerator
(either thermal or catalytic) than can be achieved through the use of flares.
The main combustion zone of a gas incinerator is engineered such that the
209
-------
TABLE 4-6. KEY FEATURES OF INCINERATION PROCESSES
Type of Incineration
Advantage
Disadvantage
Coata (Total Depreciable Capital)*
Themal Incineration
via Separate Incinerator
Thermal Incineration
in Fuel-Fired Boiler
NJ
H
O
Catalytic Incineration
Flaring
Can handle all types of waate gaaea.
Reliable and aimple operation ia
common. VOC/CO control and oxida-
tion of sulfur compounds simulta-
neously.
Snlfnr and particulatea can be
removed in the aaaociated eleotro-
atatic preoipitator and fine gaa
deanlfnriiation (FGD) nnita when
theae are integral with the boiler.
The fuel required for ateaai boiler
incineration ia leaa than that of
a aeparata incinerator for waatea
with low heating valnea.
Reqnirea leaa fuel than thermal
incineritioa, although heat re-
covery may not be aa high, faate
gaaea with very little conbnatible
material can often be incinerated
catalytically without aupplemental
fuel.
High aupplemental fuel coata for
atreama with low heating value.
Control ia a problem with streams
of varying flow and compoaition.
On baaia of kmole/hr of flow: flow
range of 0.3 to 3 .0 x 10* kmol/hr
a. no heat recovery: I 140 to 1870
b. primary heat recovery: $190 to $1000
o. primary and aeoondary heat recovery:
$225 to 11200.
In moat caaea, this option ia more
capital intensive than a aeparate
incinerator; however, extent of
heat recovery ia generally greater
with boilera than with inciner-
atora. Subject to control problema mole incremental flue gaa
with varying waate gaa flow ratea
and compoaitiona.
Incremental boiler capital coata are
$2000-$3000/kg mole of incremental flue
gaa compared to coal combnation on a heat-
ing value baaia. Incremental ESP and FGD
coata are an additional $2000-$2500/kg
Cannot handle large quantitiea of
particulatoa; they will gradually
coat the catalyat and reduce ita
efficiency. Some catalyat can be
eaaily poiaoned by sulfur compounds
and elementa auch aa araenic and
lead. High levels of hydrocarbona
can raiae eatalyat to exceaaive
temperatures and ahorten the uaefnl
life of the catalyat. Temperature
control ia alao a problem with
atreama of varying flow and compo-
aition.
$400 to 12200 per kmol/hr of flow for
a flow rate range of 40 to 7100 kmol/hr.
Simple to operate. Least expenaive Destruction efficienciea believed
alternative, especially for tranaient lower than for thermal or cata-
and small volume waate gaaea. lytic incineration. Performance
data are generally lacking.
40 to 100 ft elevated flarea for flow
rate range of 800 to 6500 kmol/hr -
$25 to $125 per kmol/hr
Ground flarea for flow rate of 100 to
1000 kmola/hr - $800 to $2700 per
kmol/hr.
"Costs are firat quartet 1980 dollars.
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
Tail Gas Treatment-VOC
gases are maintained at a designed minimum temperature and residence time.
Typical design values are 1090 E and 0.5 seconds. This results in nearly
complete destruction of volatile organic compounds, organic aerosols, and
particulate matter which contains combustible material.
Thermal incineration may also be affected in a boiler where a minimum
combustion temperature of 1500 K and a minimum resident time of 0.5 second
are typical design parameters. This approach results in a similar degree
of pollutant destruction as in a specially-engineered incinerator. The
boiler as an incinerator of waste gases necessitates a corresponding
increase in the capital and annualized operating costs of captive ESP and
FGD units, since the costs of the pollution control units are flow rate
dependent (even if the increased gas flow to the ESP/FGD unit contains no
dust or sulfur dioxide).
Catalytic incineration is not likely to be an attractive alternative for
VOC and CO control of tail gases from sulfur recovery units due to the pre-
sence of sufficient reduced sulfur compounds to interfere with or degrade
catalysts. However, catalytic incineration of CO-rich flash gases from
Rectisol has considerable promise and is featured in the recent design of at
least one U.S. coal gasification facility under construction (based on Texaco
gasification).
211
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Section 4
Gaseous Medium
Rectisol Acid Gas
HjS-Rich Acid Gases
4.1.1.1 HaS-Rich Acid Gases
HjS-rich acid gases are sulfur-containing Rectisol gases which have pur-
posely been enriched either as part of acid gas removal or by use of addi-
tional processing so that Claus sulfur recovery may be used. It was
assumed that a minimum of 10% HaS is necessary for proper operation of the
Claus process. Rectisol units in the subject facilities remove from 5500 to
6600 kmols/hour of acid gases from quenched Lurgi gas. Generally, higher
rank coals produce slightly more acid gases (C02 plus H2S) in Lurgi gasifica-
tion than lower rank coals. HaS, COS, and mercaptans in these acid gases
amount to 80 to 200 kmols/hour (60 to 140 Hg/day) depending on the feed and
sulfur content. H^S-rich acid gases containing 10 to 30% H^S would represent
5 to 30% of the total acid gas volume, or 300 to 2000 kmols total per hour.
The exact H,S levels in the design values for Claus feeds would be
determined by engineering/economic tradeoff studies of enrichment costs vs.
Claus and tail gas treatment costs and would vary for coals with different
sulfur contents. Similarly, use of split flow vs. straight through mode and
use of pure oxygen vs. air would also involve tradeoff studies. From an
environmental performance standpoint, these design variations are essentially
equivalent. Capital costs for the Claus plant range from $4 to $12 million
depending primarily upon the volumetric flow and, to a lesser extent, the sul-
fur loading. This large range largely reflects costs either incurred or
avoided upstream in enrichment. For an example, a Claus plant processing 180
kmols/hr of 40% H^S feed gas has an estimated capital cost of $7 million.
Depending upon the Claus feed HaS level, overall sulfur recovery may vary
from as low as 90% to over 95%. Less concentrated feeds result in lower
212
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
HaS-Rich Acid Gases
percentage recoveries. Organics, CO, and reduced nitrogen species will be al-
most completely destroyed in straight through Claus units and partially
destroyed in split flow units.
The only secondary waste stream generated by all Clans units is spent
catalyst. The subject Clans plants would have bauxite or alumina catalyst
inventories ranging up to approximately 100 Mg which would require disposal
every few years. Claus catalyst regeneration occurs infrequently at a few
facilities, and thus was not evaluated in this document.
213
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
H2S-Lean Acid Gases
4.1.1.2 HjS-Lean Acid Gas
These gases refer to acid gases containing more than 500 ppmv but less
than 10% total sulfur and include 1) Clans tail gases, 2) amine enrichment
offgases, and 3) nonselective Rectisol acid gases. Also included in this
category is the ozidizer vent gas (a secondary waste stream) from the
Stretford process.
Glaus Tail Gases
In the subject facilities these tail gases contain 0.3 to over 1 percent
total sulfur and amount to 300 to 3000 kmols total per hour. SCOT, Beavon/
Stretford, and Wellman-Lord technologies are all applicable to these gases and
achieve residual sulfur levels of less than 350 ppmv total sulfur (on a Claus
tail gas basis). Capital costs for these processes range from $6 to $20 mil-
lion, depending primarily on the flow and, to a much lesser extent, the sulfur
load. Since the relative importance of sulfur mass load vs. volumetric flow
rate is somewhat different for Claus plants and tail gas treatment units, the
relative costs of the Claus plant and its tail gas treatment unit will vary
with coal sulfur and overall plant design. SCOT, Beavon/Stretford, and
Wellman-Lord units handling the tail gas from a 140 Mg/day (40% H2S feed)
Claus plant are estimated to have capital costs of i5, $6, and ilO million,
respectively. Incinerators for SCOT or Beavon tail gases have capital costs
of about il million, or about 10% of the capital cost of the SCOT or Beavon
units. In Lurgi facilities the tail gases have sufficient VOC, CO, and H,
levels such that no supplemental fuel is needed and hence, operating costs are
very low for incineration.
Secondary waste streams from the Beavon/Stretford process are 1) sour
reactor effluent condensate; 2) Stretford solution purge; 3) Stretford oiidi-
zer vent gas; and 4) spent catalyst from the Beavon reactor. Sour condensate
214
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
HaS-Lean Acid Gases
is expected to contain dissolved sulfide and traces of NH , and would be gen-
erated at a rate of up to 3 m»/hr. Stretford solution purge for control of
thiosulfate and thiocyanate buildup may be present as a waste stream contain-
ing vanadium and sodium salts as thiosulfate, sulfate, carbonate, and thiocya-
nate. The solution purge rate is approximately 0.1 Mg/hr and purge solution
may either be regenerated or discarded (refer to Section 4.1.1). Oxidizer
vent gas would consist primarily of air, water vapor, and CO but may con-
tain traces of NH,. Insufficient data are available for estimating the flow
rate of oxidizer vent gas. The cobalt molybdate hydrogenation catalyst inven-
tory is approximately 11 Mg and would require replacement about every five
years.
Secondary waste streams from the SCOT process are sour water and spent
catalyst. The sour water is expected to contain dissolved sulfide and NH},
and would be generated at a rate of 4 mj/hr. The cobalt molybdate hydrogen-
ation catalyst inventory is approximately 11 Mg, and would require replacement
about every five years.
Secondary waste streams from the Wellman-Lord process are acidic waste-
water from combustion gas quenching and thiosulfate/sulfate byproduct purge.
The acidic wastewater typically has a pH value between 1 and 2 and would be
generated at a rate of 3 m»/hr. Byproduct purge consists primarily of sod-
ium salts as snlfite, pyrosulfite, sulfate, and thiosulfate with approximately
29 percent water. Byproduct purge is generated at a rate of 80 kg/hr.
Amine Enrichment Offgases
When amine processes are used to both remove organics from, and increase
the HaS content of, Claus feed, a hydrocarbon-rich offgas at least as large in
volume as the Claus feed is also generated. For example, an amine unit
215
-------
Section 4
Aqueous Medium
Rectisol Acid Gas
HjS-Lean Acid Gases
processing 2300 kg-moles/hr of 8.7% HaS feed gas produces 1900 kg-moles/hr of
offgas containing about 2.9% nonmethane hydrocarbons, and 0.15 to 1.3% sulfur
compounds. Since only about half or less of the sulfur is HaS, catalytic or
oxidative tail gas treatment processes would be most applicable. SCOT,
Beavon/Stretford, and Wellman-Lord units treating the example amine offgas
alone would incur estimated capital costs of i9, $10, and $17 million,
respectively. However, separate tail gas treatment units would, in most
cases, not be used for the subject gases since treatment of Claus tail gases
would also be necessary and combined treatment would result in cost savings.
Due to the organics in amine offgases, catalytic sulfur tail gas treatment
offgases would probably be incinerated. Incremental incinerator capital costs
for Beavon/Stretford and SCOT are estimated to be no more than 10%. Amine
offgases contain sufficient VOC so that no supplemental fuel is needed for
incineration.
With regard to secondary waste streams from tail gas treatment processes
such as Beavon/Stretford, SCOT, and Wellman-Lord, combining the amine enrich-
ment offgas with Claus tail gas results in increased waste generation rates.
Combining the example amine enrichment offgas with the example Claus tail gas
given above would result in a slight increase in sour condensate production,
and a factor of two to three increase in all other secondary wastes associ-
ated with tail gas treatment.
Nonselective Rectisol Acid Gases
These gases amount to 5300 to 7200 kmols/hr in the subject facilities and
contain from 1.2 to 3% sulfur compounds and about 1% nonmethane hydrocarbons.
Stretford technology has been most widely proposed for treating such gases.
Like the Claus tail gas treatment process, Stretford plant costs are primarily
determined by volumetric flow and, to a lesser extent, sulfur mass loading.
216
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
H2S-Lean Acid Gases
Capital costs for a 6600 kmols/hr plant are estimated at $15 million.
Stretford tail gas contains less than 1 kmol/hr of HaS bnt may contain over
8 kmol/hr of COS and mercaptans and 50 kmols/hr of VOC.
Stretford tail gases have an energy value (LHV) of about 10 kcal/knol.
The adiabatic flame temperature of such a gas burned with 20% excess air is
only about 900 K. Since at least 1100 K is usually required for complete
destruction of organics with thermal incineration, supplemental fuel will be
needed. The costs of incineration for this low heating value stream are pri-
marily capital in nature, since heat recovery can more than offset supple-
mental fuel requirements (the primary operating cost item). The capital
investment for an incinerator handling 6600 kmols/hr Stretford gas is $2.3
million. About 80 x 85 GJ/hr of supplemental fuel is needed, but about the
same amount of medium pressure steam is generated in a typical incinerator
with 35% heat recovery.
Secondary waste streams from the Stretford process are solution purge and
ozidizer vent gas. Stretford solution purge may be present as a waste stream
or may be regenerated for reuse (refer to Section 4.1.1). The solution purge
would be generated at a rate of approximately 1 Mg/hr and contains vanadates
and sodium salts of thiosulfate, sulfate, carbonate, and thiocyanate. Oxidi-
zer vent gas consisting primarily of air, carbon dioxide, and water vapor with
traces of mercaptans would be generated at a rate of approximately 1000 to
2000 kmols/hr.
Since the Stretford process does not remove non-H,S sulfur, it might
appear that using those processes designed primarily for Claus plant tail
gases could be applied directly to nonselective Rectisol acid gases. In the
case of the catalytic processes (SCOT and Beavon/Stretford), few, if any,
advantages are seen with this approach. The high HjS loading relative to COS
217
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
H S-Lean Acid Gases
would work directly against COS destruction over the catalyst in both pro-
cesses (indeed COS may be actually generated in such applications). In the
SCOT case the high C0a loading of the feed and lack of a Claus plant to which
the H S fraction can be recycled are fundamental limitations.
WeiIman-Lord could in principle be applied directly to the subject acid
gases after incineration. As discussed in Section 4.1.1.1. however, direct
use of FGD type processes is generally not cost effective relative to
Stretford except where very low sulfur gases (e.g., very low sulfur coals) are
encountered.
Stretford Oxidizer Vent Gases
During regeneration of Stretford solution, air is used as an ozidant to
promote flotation of elemental sulfur. About 1000 kmols/hr of air depleted in
oxygen is emitted from the Stretford oxidizer. There is some concern that
mercaptans and ammonia removed from the feed gas in the Stretford absorber may
be emitted in the oxidizer. Even small amounts could present an odor problem.
Controls for oxidizer vent gas are limited to direct incineration and
carbon adsorption with incineration of regenerant gases. Since the vent gas
contains oxygen, it can be used in place of air in an incinerator or boiler
(displacing ordinary air). Due to the lower level of oxygen in the vent gas
relative to air, more inerts are carried through combustion and heat recovery.
Thus, an energy penalty is incurred which corresponds to heating of the extra
inerts (compared to air) from the oxidizer temperature to the final combustion
flue gas temperature after heat recovery. About 66% additional inerts are
present in the vent gas in comparison to air.
218
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
HaS-Lean Acid Gases
Activated carbon adsorption for control of HaS and mercaptans usually
includes metal impregnation of carbon to enhance sulfur removal. Ozidizer
gases would be discharged through a carbon bed at 280 to 310 K. After satura-
tion, the bed is regenerated with steam, and the regeneration gases inciner-
ated with supplemental fuel. Beds would operate in parallel so that regenera-
tion and adsorption would occur concurrently. Since gas must be relatively
dry for proper carbon performance (to prevent moisture condensation in the
bed), the dew point of the gas must be lowered to about 280 K. Several
approaches could be taken to remove moisture, but direct refrigeration is most
likely, generating a condensate. Dewatered gas would be heat exchanged with
feed gas to warm it well above the 280 K dew point.
Table 4-7 presents estimated costs for the above controls. The calcula-
tions suggest that incineration may be more costly than carbon adsorption.
However, ammonia may not be controlled by the carbon approach.
TABLE 4-7. COSTS FOR CONTROL OF STRETFORD OXIDIZER VENT GASES*
Incineration Carbon Adsorption
Total Capital
Total Annual Operating
Total Annual ized
Percent of Base Plant Costs
Capital
Total Annual ized
2.21
0.10
0.48
0.27
0.24
0.64
0.15
0.26
0.08
0.13
a
Costs are million of first quarter 1980 dollars.
Vent gas would substitute in part for combustion air in a boiler or
gas incinerator.
219
-------
Section 4
Gaseous Medium
Rectisol Acid Gas
C02-Rich Acid Gases
4.1.1.3 C02-Rich Acid Gases
These gases refer to the offgases from selective Rectisol containing the
bulk of the C02 removed from Lurgi gas. The selective Rectisol at Kosovo,
Yugoslavia which serves as the basis for analysis in this manual is not
designed nor operated to minimize sulfur species in the C02 fraction. As
discussed previously, however, levels of total sulfur can be as low as 10
ppmv in the Rectisol C02 fraction. Since most available "add on" control
cannot generally achieve levels below 10 ppmv, no further sulfur control is
considered for this stream type.
The C02 fraction may also contain about 1.5% nonmethane hydrocarbons
(mostly ethane and methanol) and 0.1% CO. If VOC and/or CO control is
desired, some flexibility exists in Rectisol designs for reducing the levels
in the bulk C02 offgas. Incineration is a technically feasible "add-on"
control, but the large fuel penalty associated with this approach makes its
use very unlikely for such a large volume waste gas. However, incineration is
feasible for a smaller volume stream(s) enriched in CO and/or VOC generated
within the Rectisol process to minimize levels in the bulk C02 offgas. Costs
associated with such "in process" control cannot readily be estimated. Also,
costs for incineration of a smaller volume VOC/CO enriched gas are difficult
to define since the volume of such a gas is not known.
220
-------
Section 4
Gaseous Medium
Small Volume Gases
4.1.2 Small Volume and Intermittent/Transient Waste Gases Containing
VOC and Reduced Sulfur Compounds
In addition to Rectisol acid gases, several other waste streams in the
subject facilities contain reduced sulfur and nitrogen compounds, organics,
and CO. In principle, the same techniques discussed previously for acid gases
can be applied to these streams. Indeed, combined treatment of small volume
waste gases with Rectisol acid gases can offer certain technical and economic
advantages. However, unlike the case with acid gases, sulfur removal is not
necessarily the only or primary concern. Further, small volume and intermit-
tent streams do not necessarily lend themselves well to control approaches
designed for large volume, continuous streams.
Controls for these small volume and intermittent waste gases fall into
three broad categories: 1) recovery of energy value of contained organics,
CO, and Ha via recycle to the main process train or via use as fuel;
2) incineration with or without subsequent removal of S0a; and 3) removal
of sulfur, nitrogen, or organic species, perhaps in conjunction with acid
gases. Sulfur removal and incineration (including use as fuel) have been dis-
cussed previously in Section 4.1.1. Since it is probably not economically
attractive to provide captive S0a control for the subject types of waste
gases, any S0a control would employ larger S02 removal systems associated with
onsite boilers/heaters. Boiler FGD systems are discussed in Section 4.1.4.
221
-------
Section 4
Gaseous Medium
Small Volume Gases
Coal Lock Gases
4.1.2.1 Coal Lockhopper Gases
Depressurization of the coal lockhopper, which is carried out in tiro
stages, is a source of potential pollutants. When using Lurgi gas as the
pressurant for the coal lockhopper, the internal pressure of the lockhopper
during the first-stage depressurization is reduced from approximately 3.1 MPa
to about 0.11 MPa, based on current operating practices at the SASOL facility
in South Africa as well as the design criteria for a Lurgi plant proposed for
the United States. The pressure is then further reduced to atmospheric during
the second-stage depressurization using an air ejector system. Therefore, for
the purposes of this document, high-pressure lockhopper gases are defined as
those gases discharged from the coal lockhopper with a pressure of over 0.11
MPa when using product gas as the pressurant. Below 0.11 MPa these discharges
are defined as low-pressure lockhopper gases. In some instances, inert gas
rather than Lurgi gas has been proposed as the pressurant because of envi-
ronmental emissions limitations imposed by regulatory agencies (e.g.. New
Mexico State Health Department).
Control alternatives for the high-pressure lockhopper gas stream include
recompression and recycle of the gas stream to the quenched gas stream or use
as fuel in the boiler or incinerator, with or without particulate matter and
SOj control. Recompression and recycle would result in no emissions to the
atmosphere, while incineration of the lockhopper gas stream would result in a
net increase in emissions of particulate matter, S02, and NO . Costs and
energy requirements for the control alternatives for the high-pressure coal
lockhopper gas stream are anticipated to be offset by the savings resulting
from the recovered heat or synthesis components.
222
-------
Section 4
Gaseous Medium
Small Volume Gases
Coal Lock Gases
Of major concern with the low-pressure coal lockhopper gas is polycyclic
organic matter (POM), and hence the control alternatives are aimed primarily
at particulate matter/organic aerosol control. Accordingly, control alterna-
tives for the low-pressure coal lockhooper vent gas stream consist of
1) boiler, 2) thermal incinerator, 3) flare, 4) venturi scrubber, and 5) vent
gas dispersion. The first three alternatives involve incineration in some
manner. When the boiler is used as an incinerator for such waste gases, the
gas would be substituted for secondary air. In this case, no oversizing of
the boiler or its captive ESP or FGD systems is necessary. However, provi-
sions for collecting and holding of the gas and delivery to the boiler are
required. No energy penalty need be incurred in the boiler case since the
heating value of the waste gas is largely recovered in modern boiler systems.
The boiler alternative also results in the control of reduced sulfur compounds
present in the lockhopper gas. When a captive incinerator is used, provisions
would again be required for delivery and storage, although piping distances
and holding volumes would be lower than in the boiler case. An energy penalty
would probably be incurred with an incinerator, since the extent of heat recov-
ery practical with small incinerators is not as high as with large boilers.
Flare systems would be even simpler than incinerators or boiler use, requiring
no gas holding. With flares, complete combustion cannot be assured at all
times and of course there is no energy recovery.
Incineration of lockhopper gases may involve safety risks. The SASOL
Lurgi facility coal lock design featured a common header for 10 gasifiers and
a blower exhaust to collect the low pressure lockhopper gases. This system
was abandoned because of explosion hazards which were encountered. Several
modifications to the SASOL design have been examined, including dilution of
the gas using the air ejector system to maintain the gas mixture well below
the lower explosive limit and use of flashback controls in the ducting system.
Even with such measures, there is always some risk in piping gases containing
air, combustible gases, and coal dust.
223
-------
Section 4
Gaseous Medium
Small Volume Gases
Coal Lock Gases
The alternative to air ejection of residual lockhopper gases is the use
of inert gas. Either Na from the air separation plant or C02 from Rectisol
or methanation units could be used for this purpose. Any diluent gas (other
than air) would incur energy penalties in subsequent incineration/heat
recovery units as well as increased capital costs for gas collection and
transport. Inert gas ejection could be coupled with venturi scrubbing as a
control alternative since particulate matter is the primary concern with this
stream. Only a small collection system and fan would be needed along with the
scrubbers.
A final approach, aimed only at dispersing the low-pressure lockhopper
gas, involves ejection with air and subsequent dilution with additional heated
air to aid in thermal buoyancy. The diluted gases are emitted through a stack
to minimize ground levels of pollutants.
Table 4-8 summarizes the costs of controls for lockhopper gases. Costs
for compression and recycle are not estimated due to the design specific
nature of such costs. The high-pressure lockhopper gas is a valuable fuel,
but it produces a greater volume of flue gas than does coal on a heating value
basis. Thus, all boiler heat exchange components would need to be oversized
accordingly. In Table 4-8 both boiler and ESP/FGD costs have been derived by
oversizing base plant units by 12% to account for this increased flue gas
volume. Since increased flue gas volume at constant heat input also trans-
lates into lower efficiency in heat recovery, a small downrating (about 1%) of
the boiler is also necessary with high-pressure lockhopper gas.
High-pressure lockhopper gas has sufficient heating value that incinera-
tion costs at the boiler are more than offset by recovered energy, even when
the boiler has a captive ESP/FGD system. Such is not the case with low pres-
sure lockhopper gas diluted with air where collection and transport costs
dominate. The increased flue gas volume and boiler downrating discussed above
224
-------
TABLE 4-8. COSTS ASSOCIATED WITH CONTROL OF LOCKHOPPER VENT GASES
Ln
Estimated Control
Control Technique
Incineration in Boiler
HP Gas
LP Gas°
Boiler Plus ESP/FGD
HP Gas
LP Gas°
Inert Gas Ejection Plus
Incineration Without
Heat Recovery
LP Gas
Inert Gas Ejection Plus Flare
LP Gas
Inert Gas Ejection Plus
Venturi Scrubber
LP Gas
Hot Air Dispersion
LP Gas
Total
Capital
2.01
0.29
3.14
0.31
0.28
0.09
0.09
0.20
Total Annual
Operating
(3.35)
(0.05)
(3.18)
(0.04)
0.02
0.01
0.01
0.05
Total
Annual ized
(3.0)
0.02
(0.02)
0.01
0.07
0.02
0.03
0.09
Costs
Percent
Capital
0.25
0.04
0.38
0.04
0.03
0.01
0.01
0.02
of Base Plant Costs
Total Annual ized
Negative
0.01
Negative
<0.01
0.04
0.01
0.01
0.04
.Costs are millions of first quarter 1980 dollars.
Air ejection.
Values in parenthesis indicate negative costs due to energy credits.
-------
Section 4
Gaseous Medium
Small Volume Gases
Coal Lock Gases
with high-pressure lockhopper gas would also apply to the low-pressure lock-
hopper gas. However, the residual lockhopper gas is diluted with air for
safety purposes, and it is this air which is substituting for air needed at
the boiler for fuel combustion. Hence, only a very small change in boiler
size is required to accommodate the lockhopper gas, and this is ignored in the
Table 4-8 calculations. In different words, the boiler air feed system con-
tinually draws air from the lockhopper vent header system, and the contained
residual gasifier components are swept along in the process.
Low-pressure lockhopper gas diluted with inert gas and handled by thermal
incineration, venturi scrubbing, and flaring incurs progressively lower costs
with each option. Hot air dispersion is the least costly alternative, but
achieves no removal or destruction of pollutants.
The degrees of emission control associated with the control alternatives
in Table 4-8 are difficult to estimate. A high-temperature combustion process
can reduce VOC and CO levels to below 100 and 300 ppmv, respectively. Venturi
scrubbers can achieve over 99% particulate control. Flare performance has
never been adequately measured so that the level of control of various species
is purely speculative. Since levels of VOC, CO, organic aerosols, and coal
dust are not well known, the cost effectiveness of any of the controls for low-
pressure lockhopper gas cannot be determined. Control of high-pressure lock-
hopper gas is cost effective under any assumed level of pollutant reduction
since recovered energy offsets control costs.
226
-------
Section 4
Gaseous Medium
Small Volume Gases
Startup Gases
4.1.2.2 Transient (Startup, Shutdown, and Upsets) Waste Gases
Control options for waste gases which occur during startups, shutdowns,
and upset conditions differ from those for continuous sources. Because of the
intermittent nature (estimated to occur over approximately 400 hours through-
out the typical operating year) and variable composition of the waste gases,
proper operation and performance of many types of controls may be hampered.
Additionally, waste gases emitted during startups, shutdowns, and upset condi-
tions may sometimes be explosive (generally defined for combustible gases when
the 0, content exceeds 2%), thus requiring special design in ductwork and fans
for flashback control.
Since Lurgi gasifiers are often started with air rather than oxygen for
gasification, the composition of transient gases is expected to be similar to
that for air blown Lurgi gasifiers. From a pollution control standpoint, the
waste gas is similar to raw Lurgi gas or lockhopper gas except that it
is diluted with nitrogen. The diluent nitrogen also lowers the heating value
of the gas so that an energy penalty, or downrating of heat recovery equip-
ment, would be necessary when the gases are incinerated with heat recovery.
Compared to coal, about 6% less of the enthalpy of combustion (LHV) can be
recovered using the same heat exchange units. The inerts in the transient gas
also result in a flue gas which is more than twice the volume of that from an
equivalent amount of coal (LHV basis). Thus, all heat exchange equipment
would have to be correspondingly larger and would be more costly.
Incineration of transient gases can be accomplished in boilers, super-
heaters, dedicated incinerators, or flares. Since the degree of heat recovery
in large boilers/superheaters is generally higher than with gas incinerators
227
-------
Section 4
Gaseous Medium
Small Volume Gases
Startup Gases
and since maximum steam load in a Lurgi facility occurs at the same time in
which startup transients occur, there is considerable incentive to burn these
gases as fuel in plant boilers.
Table 4-9 presents the estimated costs for incineration of transient
gases. For incineration in the boiler, incremental capital costs have been
assumed to be proportional to flue gas volume (relative to coal). Unlike the
case of high pressure lockhopper gases, recovered energy does not offset the
fixed capital cost. This is because so little energy is recovered from trans-
ients on an annual basis. The situation becomes more costly when sulfur
removal from the flue gas is included, since FGD units would have to be
designed for larger flue gas volumes. It should be noted that calculating
incremental costs in direct proportion to increased flue gas flow probably
results in overestimates. However, even when the engineering "six-tenths
power" rule of thumb for cost as a fraction of size is applied, the overall
results are not changed dramatically. Thermal incineration of the transient
gases also incurs high costs relative to the annual volume of gases handled.
Flaring is the least expensive option, particularly when the flare cost is
shared among several waste gases in an integrated facility.
228
-------
TABLE 4-9. COSTS ASSOCIATED WITH INCINERATION OF TRANSIENT WASTE GASES
Estimated Control Costs*
Control Technique
Boiler or Superheater
Boiler Plus ESP/FGD
Thermal Incinerator
Thermal Incinerator
Plus ESP/FGD
Flare
Total
Capital
10.3
17.3
3.6
4.1
0.44
Total Annual
Operating
0
1.3
0.06
0.07
0.01
Total
Annual ized
1.8
4.3
0.68
0.78
0.09
Percent
Capital
1.26
2.11
0.44
0.50
0.05
of Base Plant Costs
Total Annual ized
0.9
2.15
0.34
0.39
0.04
Costs are millions of first quarter 1980 dollars.
-------
Section 4
Gaseous Medium
Small Volume Gases
Depress, and Strip Gases
4.1.2.3 Depressurization and Stripping Gases
When Lurgi gas liquor is steam stripped for ammonia removal/recovery, a
stripping gas is generated which contains HaS, HCN, NH3, and organics derived
from the aqueous phase. After ammonia removal, the waste gas may either be
incinerated or combined with Rectisol acid gases for sulfur removal. It is
expected that direct routing of such gases to sulfur recovery will be prac-
ticed at gasification facilities, as this is common practice in both petroleum
refineries and coke plants.
Offgases from gas liquor separation also contain both combustibles and
reduced nitrogen and sulfur compounds. Such gases may be directly inciner-
ated, combined with Rectisol acid gases for sulfur control, or routed to the
ammonia recovery section of water pollution control facilities. The latter
alternative is most attractive since these offgases would not add appreciably
to the cost of the stripping/ammonia recovery unit. The combined ammonia
recovery overhead would be either incinerated, sent to bulk sulfur recovery,
or sent to sulfur recovery tail gas treatment.
Costs for control of the subject gases are not readily calculated since
their combination with larger volume Rectisol acid gases or gasifier waste
gases makes cost breakdown difficult. Their volumetric flow would add only a
few percent to the load of a typical sulfur recovery unit so that incremental
costs might be assigned in the same proportion. A similar problem arises with
costs for flaring or incineration, since these small volume streams would be
combined with other gases for control rather than separately handled.
230
-------
Section 4
Gaseous Medium
Small Volume Gases
CO, Gases from SNG
4.1.2.4 C0a-Rich Gases from SNG Production
When byproduct gases from synthesis operations are methanated, C0a
removal may be necessary to obtain pipeline quality gas. From 22 to 76
kmols/hr of C0a gas are generated in the methanol and Mobil M-gasoline
gases, and about 260 kmols/hr in the Fischer-Tropsch case. These gases con-
tain about 1000 ppmv VOC and 3% methane. Either thermal or catalytic inciner-
ation would achieve about the same degree of VOC control. A capital invest-
ment of $270,000 and an annual operating cost (primarily fuel) of $39,000 are
estimated. Catalytic incineration incurs larger capital costs, but these are
largely offset by fuel savings, so that total annualized costs for both incin-
eration approaches are similar.
231
-------
Section 4
Gaseous Medium
Intermittent Gases
4.1.3 Transient Process Gas Containing SO.,. CO and/or Particulates
Lurgi synthetic fuels facilities have several intermittent sources of
S0a, CO, and/or particulates which result from regeneration or decommission-
ing of catalysts or related materials. Cobalt molybdate based shift catalysts
are active in the sulfided state, and the sulfur is released as SOJ when such
catalysts are regenerated with air and steam to burn off coke. Mobil M cata-
lysts are also regenerated with air and steam to remove coke, but no sulfur is
present in this case. Some CO and, during purging of either the shift or
Mobil M units, some VOC may be contained in the offgases. Methanation cata-
lyst is not normally regenerated, but it is oxidized in a controlled manner
when its useful life has ended. The reduced form of the catalyst is pyro-
phoric which would create handling/disposal problems unless the material is
stabilized prior to removal from the catalytic unit. In a few existing faci-
lities, Claus catalysts have been regenerated, resulting in a sulfur-contain-
ing offgas. When activated carbon is employed for wastewater treatment, an
offgas is generated when the carbon is regenerated with air and steam.
Controls for these intermittent waste gases are difficult to evaluate due
to their uncertain character and frequency of generation, and because such
waste gases are not usually treated in refineries, coke plants, or in other
industries where similar units are found. Thus, little direct experience
exists upon which to base an assessment of control possibilities, performance,
or costs. In the case of S02, controls which would be possible include FGD
processes such as those used for boilers or Claus plant tail gases and the use
of the Claus process itself. These processes are described in Sections 4.1.1
and 4.1.4. Incineration for CO and VOC control is also described in Section
4.1.1. Controls for particulates are discussed in Section 4.1.4. The follow-
ing is an evaluation of such controls as applied to the major intermittent
waste streams (shift and Mobil M catalyst and carbon regeneration offgases).
232
-------
Section 4
Gaseous Medium
Intermittent Gases
Shift Cat. Regen.
4.1.3.1 Shift Catalyst Regeneration Offgases
Shift catalysts are periodically regenerated with air and steam to burn
off accumulated coke and sulfur and to allow safe access of maintenance per-
sonnel to the shift reactors. The offgas is over 90% steam but contains about
13% SOj on a dry basis. Regeneration offgas would be produced over several
hours and occurs an average of 7% of the plant operating time. About 150
kmols/hr of dry gas containing 1700 kmols of steam is an estimated flow rate
for purposes of sizing controls.
Since the shift unit(s) contain interstage quenching for temperature con-
trol, it is entirely reasonable to envision operation of the quench system
during regeneration to condense moisture from the offgas. Removal of most of
the moisture would be desirable for purposes of volume reduction, prevention
of condensation in piping to controls, and to avoid problems in controls them-
selves with high moisture levels.
Control of the offgas after bulk moisture removal can be accomplished
using onsite Clans units. The S0a in shift regeneration gases could dis-
place S02 produced by air oxidation of H2S in the Claus units. Since the
maximum S0a load from regeneration gases is about 20 kmols/hr, while sulfur
in Rectisol acid gases is 100 to 180 kmols/hr, there is sufficient Claus
capacity to allow substitution of regeneration gases for S0a produced by air
oxidation. The following represents the Claus oxidation step with air.
HaS + 1.5 0, + 5.64 Na —> SO, + H.,0 + 5.64 Na
233
-------
Section 4
Gaseous Medium
Intermittent Gases
Shift Cat. Regen.
Notice that oxidation of one bnol of H,S produces 6.64 kmols of inert
gases which ordinarily would be carried through the Claus unit. Since one
kmol of SO, in shift regeneration gas (dry basis) at 13% SO, carries 7.7 kmols
of inert gas into the Claus unit, the addition of the waste gas to Claus feed
increases the inert volume in the Claus plant only by about 1 bnol per kmol
SO, added. Claus tail gases in the subject facilities are 500 to 1000
kmols/hr so that essentially no increase in Claus plant size is necessary to
accommodate the shift offgas. Of course, the increased sulfur load at con-
stant volume will increase Claus plant capital and operation costs slightly,
but no large cost impact is expected at the Claus plant for handling the waste
gas. Claus tail gas treatment units would also experience a higher sulfur
load but essentially no increase in volumetric throughput. It should be
remembered that water vapor in Clans feeds not only acts as an inert but also
reduces the thermodynamic efficiency of the Clans reaction. By not removing
the bulk of the moisture from the shift offgas, the Claus plant would have to
be larger and would operate at a lower efficiency.
Shift offgases may be treated by S0a removal processes (e.g., Wellman-
Lord) used on site for boiler SO, control or for Claus plant tail gas sulfur
control. In the case of a boiler FGD, the volumetric flow rate increases by
only 1 to 2%, but the sulfur loading would almost double. In the case of a
Claus tail gas treatment unit, flow would increase by about 3 to 5% and sulfur
load would increase by about 60%. Costs for SO, removal processes are in-
fluenced by both volumetric flow rate and sulfur load so that a detailed eval-
uation would be required to determine the relative costs of boiler vs. Claus
tail gas FGD as controls for sulfur offgases.
Since the subject waste gas is small in volume and intermittent, a dedi-
cated caustic scrubber is also feasible for SO, control. Moisture removal
234
-------
Section 4
Gaseous Medium
Intermittent Gases
Shift Cat. Regen.
would not be as critical with a dedicated unit as with the use of Claus or FGD
units elsewhere in the facility. Although caustic is expensive, the amount
needed on an annual basis is not large, so that a "throwaway" approach has
merit.
Table 4-10 summarizes the costs for both dedicated and integrated control
of shift offgases. The estimates indicate that Claus sulfur control is more
expensive than FGD and that dedicated FGD units are more cost effective than
existing units in an integrated facility. The low cost of a throwaway
caustic scrubber largely reflects the small volume of the stream on an annual
basis. It should be noted that S0a control via a dedicated Clans plant re-
quires reducing gas and a catalytic conversion unit to convert S02 to HaS.
A commercial version of this approach is licensed by Allied Chemical
Corporation. Indeed, Wellman-Lord FGD units feature this technology for ulti-
mate recovery of elemental sulfur in boiler applications where a Claus plant
is not available.
There are currently a number of installations using sour shift catalysts
in petroleum and related applications. As far as is known, control of regene-
ration offgases is not practiced at any of the facilities. Catalyst users in-
dicate that, due to the short duration and high variability of S0a-containing
offgases, control would be difficult. Regeneration often occurs when
facilities are shut down for general maintenance, so that use of FGD or Clans
units on site at such time presents difficulties. Even if regeneration of
catalyst units were to be scheduled during times in which FGD or Claus units
were online, integration of the highly variable regeneration gases into such
units would make overall system control difficult and performance less than
usual. For these reasons, in the first Lurgi gasification facility for the
U.S. (Great Plains Project), there are no plans to control regeneration off-
gases.
235
-------
TABLE 4-10. COSTS FOR CONTROL OF S0a IN SHIFT CATALYST REGENERATION OFFGASES
NJ
U)
Control Technique
Dedicated Claus
A
Combined Claus
Dedicated FGD (Wellman-Lord)
Dedicated Caustic Scrubber
Total
Capital
5.7
1.43
1.25
0.15
Estima
Total Annual
Operating
0.03
0.03
0.02
0.14
ted Control Costs*
Total
Annual ized
1.01
0.28
0.23
0.15
Percent
Capital
0.7
0.18
0.14
0.02
of Base Plant Costs
Total Annual ized
0.5
0.14
0.11
0.08
"Costs are millions of first quarter 1980 dollars.
Includes reducing gas and catalytic unit for converting 2/3 of the S0a to H4S.
CSCOT basis.
-------
Section 4
Gaseous Medium
Intermittent Gases
Mobil M Cat. Re gen.
4.1.3.2 Mobil M Catalyst Regeneration Offgases
Limited information is available on the frequency of catalyst regenera-
tion and offgas volume and CO content expected in a Lurgi-based Mobil M gaso-
line facility. Residual organics and particnlates may also be present in the
gas during purging of the unit or initial phases of regeneration. For VOC or
CO control, either thermal or catalytic incineration are prime candidates.
Table 4-11 summarizes the costs estimated for control of Mobil M-offgas. If
the particulate loading of the gas is low, catalytic incineration offers cost
savings compared to thermal incineration.
TABLE 4-11. COST ESTIMATES FOR CONTROL OF MOBIL CATALYST DECOMMISSIONING OFFGAS
Estimated Control Costsa
Control Technique
Thermal Incineration
Without ESP
With ESP
Catalytic Incineration
Flare
Total
Capital
0.26
0.7
0.18
0.1
Total
Annual
Operating
0.03
0.05
0.03
0.03
Total
Annual ized
0.08
0.17
0.06
0.05
Percent
Plant
Capital
0.03
0.08
0.02
0.01
of Base
costs
Total
Annual ized
0.04
0.08
0.03
0.02
Costs are millions of first quarter 1980 dollars.
No heat recovery.
237
-------
Section 4
Gaseous Median
Intermittent Gases
Act. Carbon Regen.
4.1.3.3 Carbon Regeneration Flue Gases
When granular activated carbon is used for water pollution control,
regeneration of the carbon with steam and air is required on a periodic basis.
The exact schedule for regeneration will depend on the wastewater flow and
loading. An annual average of about 200 kmols/hr is expected for the subject
facilities with regeneration occurring about 10% of the operating time. The
regeneration offgases contain unbnrned organics, CO, and carbon dusts which
are controlled in existing applications by incineration and particulate scrub-
bers.
Table 4-12 presents cost estimates for control of the offgases. Thermal
incineration is seen to be less costly than catalytic incineration for streams
of the size encountered. Particulate control via ESP either before or after
incineration can significantly increase the costs.
TABLE 4-12. COST SUMMARY: CARBON ABSORPTION REGENERATION OFFGAS
Estimated Control
Control Technique
ESP/Thermal Incineration
ESP/Catalytic Incineration
Venturi/Catalytic
Incineration
Flare
Total
Capital
1.38
2.69
2.13
0.43
Total
Annual
Operating
o.iob
0.14
0.14
0.13
Total
Annual ized
0.34b
0.60
0.50
0.20
Costs*
Percent
Plant
Capital
0.17
0.33
0.26
0.05
of Base
Costs
Total
Annualized
0.17
0.30
0.25
0.10
Costs are millions of first quarter 1980 dollars.
Includes energy recovery credit.
238
-------
Section 4
Gaseous Medium
Combustion Gases
4.1.4 Combustion Gases
The major pollutant species associated with the combustion of fossil
fuels are S02> NO , and particulates. Sulfur dioxide is formed rapidly in
the combustion process when sulfur contained in the fuel reacts with oxygen in
the air. Variations in the combustion process are not effective in reducing
S02 emissions. Rather, sulfur must be removed from the fuel, or, once formed,
S0a must be removed from the exhaust gas.
The generation of NO from air-fed fuel combustion processes occurs by
two separate mechanisms, identified as thermal NO and fuel NO . Thermal
NO results from the thermal fixation of molecular nitrogen and oxygen in the
combustion air and is sensitive to flame temperatures and to local concentra-
tions of oxygen. Fuel NO is created from the oxidation of chemically bound
nitrogen in the fuel being combusted. Fuel NO formation is strongly
affected by the rate of mixing of the fuel and air and by the local oxygen
concentration. Approximately 95% of oxides of nitrogen from combustion are
emitted as NO (56,57).
Particulates generated during combustion result mainly from the ash con-
tent of the fuel. The magnitude of these emissions in the flue gas is a func-
tion of fuel ash content and combustion unit design. Particulate emissions
are negligible when gaseous or oil—based fuels are used.
The major sources of flue gases from a coal gasification facility are the
plant power boiler, process heaters, and secondary combustion gas streams from
other media. It should be emphasized that combustion of fuels is not unique
to coal gasification facilities and, generally, presents no new problems for
emission control over those encountered in any other industrial application.
239
-------
Section 4
Gaseous Medium
Combustion Gases
NO Control
z
NO Control
JL
NO pollution control techniques are of two types: 1) combustion modifi-
cations to limit nitrogen conversion to NO and 2) flue gas treatment. Com-
bustion modification techniques are the most widely used. They can achieve
from 25 to 60% reduction in NO emissions. Some of the most common of these
z
techniques are 1) low ezcess air, 2) staged combustion, 3) flue gas recircula-
tion, 4) reduced load, 5) low NO burners, and 6) ammonia injection. The key
features and unit costs of these techniques as applied to coal- and oil-fired
combustors are discussed in Table 4-13.
The cost of combustion modification techniques for controlling NO emis-
sions depends upon the additional hardware required and any changes in opera-
tional procedures that may increase the cost of steam production. Cost esti-
mates for combustion modification techniques are included in Table 4-13. For
more detailed information, other EPA studies should be consulted.
Flue gas treatment techniques have been proposed for control of NO emis-
sions to levels significantly below those achievable by combustion modifica-
tion techniques. Although large scale flue gas treatment schemes have not
been proved commercially in the U.S., these techniques are being applied in
Japan. The key features of some of these processes are provided in Table
4-14. Additional flue gas treatment techniques are discussed in the Control
Technology Appendices for Pollution Control Technical Manuals.
240
-------
TABLE 4-13. COiBUSTION MODIFICATION TECHNIQUES FOR NO CONTROL
Control
Technique
Description
of Technique
% NO Reduction
(Type of Fuel Fired)*
R>n|e of
Applicetion
Stage of
Development
Capitel Colt
(pei KV of
hot input)
Limitations
and Comments
Low Excess Air
(LEA)
Combustion sir is re-
duced to the minimum
amount required for
complete combustion
while maintaining
proper stream tem-
perstnre.
0-15 (PC)
0-28 (BO)
0-24 (DO)
Excess Oa lowered to
5.2% on the average.
Excess Oa can be
reduced to 2.5%.
Available but imple-
mented on a limited
basis only.
Available.
t440 to iSSO
1460 to 12400
Limited by increase in CO,
HC. and particulate emis-
sions. Increase in boiler
efficiency may be achieved
aa a benefit.
Added benefits include it
cresse in boiler effi-
ciency. Limited by
increase in CO. HC, and
TSP emissions.
Stsied Combustion
Over fire Air
Injection (OFA)
Staged Combus-
tion Air
(LEA + OFA)
Air snd Fuel-
Rich Firing
the top burner level
through OFA ports
together with s reduc-
tion in air flow to
combustion) .
tion air ports.
One or more burners 27 - 39 (PC)
fired on sir only.
Remainder of burners
firing fuel rich.
Burner stoichiometry
as low as 100%.
with proper burner
installation.
minimum of 4 burners
or be designed with
Available but not $800 to 4940
field-erected unit*.
However, not c owner-
c i a 1 ly avail lib le for
•11 design types.
neerina, refinement it
•entatlon.
Limited by possible in-
crease in >l*f|in| and
corrosion. Excess air »«y
b« required to ensure COB-
plete combustion thereby
decreasing efficiency.
unita. Retrofit is prob-
ably not feasible for aiost
units especially packaged
one a.
Load reduction required in
•ost caaes. Possible in-
creased slagging and cor-
rosion. Nev boiler design
will incorporate the re-
quired nna.be r of burners.
(Continued)
-------
TABLE 4-13. (Continued)
N>
-P-
NJ
Control Description * NO Reduction Range of
Technique of Technique (Type of Fuel Fired) Application
Recirculation flue gas to the burner the flue gas can be
15 - 30 (RO) Up to 25-30% of flue
design types.
(RL) air flow to the burner. to 25% of capacity.
25% increase boiler types and
(RO) sizes. Load can be
31% decrease to reduced to 25% of
17% increase maximum.
(DO)
Capital Cost
Stage of (per IH of
Development heat input)
Not offered because Not available
the method is com-
paratively ineffec-
tive.
Available. Requires tl070 to 15150
Hon. to the burner
and windbox.
implemented because
of negative operational
impacts.
retrofit application.
Better implementation
with improved firebox
design.
Limitations
and Comments
Flue gas recirculation
lovers the bulk furnace
gas temperatures and re-
the combustion zone. Re-
quires installation of
flu* gaa recirculation
instability.
Best suited for new units.
Costly to retrofit. Pos-
sible flam* instability at
high FGD rates.
Best used with increase in
Load reduction may not be
effective becauae of in-
crease in excess 0,.
Technique not effective
when it necessitates an
levels. RL is possible to
implement in new designs
intensity (enlarged fur-
nace plan area) .
Low NO Burners New burner designed
(LNB) * to utiliie controlled
air-fuel mixture.
45 - 60 (PC)
Prototypes are
limited to size
ranges >30 HW.
Development stage
prototypes are avail-
able from major boiler
manufacturers.
4800 to 4940 Low NO burners could
maintain the furnace in an
oxidizing environment to
minimize slagging and re-
ducing the potential for
furnace corrosion. Uore
complete carbon utiliza-
tion results because of
better coal/air mixing in
the furnace. Lower 0, re-
quirementa may be obtained
with all the combustion
air admitted through the
burners.
(Continued)
-------
TABLE 4-13. (Continued)
Control
Technique
Lo» NO Burner i
(US) {Continued)
NH, Injection
Description
of Technique
Injection of MB, into
* NO
(Type o
20
20
40
Reduction
f Fuel Fired)*
- 50 (BO)
- SO (DO)
- 60 (PC)
Range of
Application
New burners described
generally applicable
to all boilers.
NH, injection rate
Halted to NB,/NO -
COB
bat
Co.
State of
Development
aercitliy offered
not demonstrated.
iKercially offered
Capital Coat
(per MW of
beat input)
i860 to 15150
14800
Limitation.
and Comment a
Specific ••iaaiona data
from oil-fired induatrial
boilara equipped with LNB
are lacking. ped with LNB
Limited by furnace geom-
etry. Performance ia
the boiler.
40 - 70 (RO)
40 - 70 (DO)
1.5
Applicable for large
package and field-
erected watertube
boilera.
Commercially offered
but not demonatrated.
J4940 to 19770
UJ
•ensit.ve to fine (•• tea-
peratare and residence
time at optimum tempera-
tures.
Some increased Maintenance
of air keater/econoaizer
parts Bight be necessary
when bnrnini hi|h sulfur
oil. Teohniqne is very
costly. Byproduct emIt-
si ons snob as aamonina
bisnlfate could cause
operational probleas.
PC - pulverized coal. RO - residual oil, DO - distillate oil.
Costi are first quarter 1980 dollara.
-------
TABLE 4-14. NO FLUE GAS TREATMENT CONTROL ALTERNATIVES FOR BOILERS
Control
Technique
Selective
Catalytic
Seduction (SCR)
- Fixed Packed
- Parallel Flow
Reactor
- Simultaneous
Reaioval of
NO /SO
X X
Electron Beam
Radiation NO /SO
Description
of Technique * NO Reduction
Utilizes NH, to Op to 904
NO to N,. Reactoi
coitalns ring shaped
packed in fixed bed.
Utilizes NH, to Dp to 90*
NO to Na. Beactor
contains a special
catalyst arrangement
( honeycomb , pa ral lei
plate, or tube s) .
Utilise* NH, to cata- 80% NO ;
lytically redace NO 90% SO*
after SO is absorbed (theoretical)
and reacted with cata-
lyst. Uniquely
designed parallel
avoid particnlate
pr obi ens.
A dry process that Bemoval effi-
flue gas, thereby NO^ and SO,
readying NO and S0t. increase.
Applicability
Appl i cable only to
emissions of less
than 20 mg/Nm» .
Testing currently
onder way for high
particnlate (>1 g/Mm')
flue gas.
Should be applicable
flue gas.
Byproduct {asusoniuai
nitrate and ammonium
snlfate powder)
treatment technology
needa to be atore
folly developed
before commercial iza-
tion.
Stage of Capital Coats
Development (for 20 MW)
Comnercielly available JlSS/LW (coal)
fired boilers at this
time.
Has b en applied in Japan iS3/kW (coal)
to ae eral oil-fired »45/k» (oil)
boile s. Applicability
to co 1-fired boilers
cnrre tly being tested
by EPA.
No continuous coal-fired J567/1* (coal
available.*
No coal-fired tests have 4241/kf (coal)
been performed at this
time.
Limitations
and Comments
to coal-fired boilers.
Greatly reduces particnlate
isipaction ae gas flow it
parallel to catalyst surface.
Onreacted NH. downstream can
react with SO, or SO, to for»
awaoBinai bisulfate or the NH,
could eater FGD and ESP
equipment.
Systev ia not affected by
concentrations. Changes in
h y
with the NH. injection equip-
ment.
NO^/SO, removal will drop off
drastically at low radiation
other ionic apecies formed
aa byproducts.
'Costs are first quarter 1980 dollars.
Spent catalyst is secoudsry waste.
Ammonium nitratea and aulfates are secondary wastes.
-------
Section 4
Gaseous Medium
Combustion Gases
SO, Removal
S0a Removal
Several flue gas desulfurization (FGD) processes are commercially avail-
able. They are basically of two types: 1) throwaway systems which produce a
waste sludge byproduct, and 2) regenerable systems which produce a usable
sulfur byproduct and regenerate the sorbent. Examples of throwaway systems
are the lime/limestone, double alkali, fly ash alkalinity, and Chiyoda
Thoroughbred 121. Regenerable systems include the Wellman-Lord and magnesium
oxide processes. Key features of some of these scrubbing systems are pre-
sented in Table 4-15.
The lime/limestone scrubbers are the most commonly employed throwaway
systems for electric utility applications. In the lime/limestone process,
solid lime or limestone is pulverized and mixed with water to form a scrubber
liquor, which contacts the flue gas in an absorption tower where calcium sul-
fate and calcium sulfite are formed. The resulting slurry is removed from the
system and treated, and the sludge is disposed of. Scrubbing solution is
recovered and recycled to the absorption tower. Lime/limestone removal effi-
ciencies can approach 90% by carefully balancing the many chemical-reaction
parameters involved. Of the throwaway FGD systems available, lime/limestone
offers the least complex system and equipment, the easiest pH control, and the
cheapest raw materials. Operating experience has indicated that careful
attention to system control is important for successful operation of lime/
limestone FGD systems.
Of the commercially available regenerable FGD systems, Wellman-Lord is
the most extensively used. A venturi prescrubber often proceeds the Wellman-
Lord absorber to remove residual particulates from the flue gas. and avoid ash
accumulation in the absorber. Sulfur dioxide is absorbed by an alkaline
245
-------
TABLE 4-15. KEY FEATURES OF SO. REMOVAL PBOCESSES
Proce ss
Feature
Principle
Lime/Linestone
Scrubbing Double Alkali Scrubbing
Liquid phase absorb- Liquid phase absorption
tlon of SO, in 1 l»o of SO, in a sodiuai
or limestone slurry. hydroxide, sodium sill-
fit*, sodium bisulfite,
sodium aulfate, and
eodlusi carbonate solu-
tion. Regeneration of
the sodium sulfite/
bisulfite with lime in
a reactor. A dilute
•ode can be used for
concentrations of 200-
1500 ppei SO, and where
leaa than 25% oiidation
of sulfite to aulfate
•ode ean be uaad for
concentrations of 1000-
(000 ppm SO,.
Chiyoda
Thoroughbred 121
Liquid absorption of
SO, in a single
vessel, where llme-
dissolution, air
oxidation, and gypsum
precipitation occur.
Vel Iman-Lord
Liquid phase absorption
snlfite. todiurn sulfite.
solution. A rich SO,
is produced by evapora-
tion, which is then pro-
to produce elcBontil
acid plant.
Dry Scrubbing
Process involves the
which contacts the
flue gaa with an
aqueout alkaline
•aterial and produces
a dry product. Syt-
atages: 1st sttge-
stage-dry paniculate
collector which re—
•oves flue ash and
fro* flue gee.
Fly Ash
Alkalinity Scrubbing
Process involves e two
ing the fly ash alka-
linity for SO,
removal. Hydrated
doloaitlc lime.
(Kg (OB), and Ca(OB),)
it alto uted to
achieve an outlet SO,
of 43 ng/J.
ON
Feed Strcm
Requirementt
Absorbent
Product/
faate
Particnlate can be
removed in an EPS or
fabric filter to
achieve 99+* at
loweat energy con-
tumption. Fly ath
•ay be removed in n
venturi where the
fly ash contains
ligniflctnt alka-
linity. A acrubber
can be used for
both high particu-
late and SO, re-
moval.
Slaked lime or 200-
300 mesh limestone
6-12% slurry circu-
lated.
Gypsum can be pro-
duced with forced
oxidation. Cilclum
tulftte/aulfite cen
be produced with
50-70% tolidt.
Excessive ptrticnlates
should be reaoved In an
ESP, fabric filter or
venturi. 0, thould be
lest than 1% for con-
centrated Bode.
Particulatet and
chloride a should be
removed from inlet
floe gee if byproduct
gypsum it to be told.
Sodium hydroxide, tedium Limestone slurry.
tulfite/bitulfite. and
a tmall amount of aodium
tulftte.
Filter ceke with 60-70*
tolidt, primarily eal-
cium tulfite and calcium
inlftte.
Gypsum (CaS04-2H,0)
with lets than 20*
moisture content.
Particulates and chlo-
rides must be removed
from flue gat.
Concentrated todium
tnlfite/bitulflte.
Concentrated SO purge
ttream (90* SO,).
Inlet SO, concentre- Venturi it uted to re-
tion thould not move particulatet and
exceed 1000 ppmv. a portion of SO,
Lime tlurry or todlu
carbonate solution.
Sodium sulfite-todinm
sulfttci calcium sul-
fite/enlfete.
Fly teh alkalinity and
hydrated lime (calcium
and magneaium hydrox-
ide).
Sludge consists of fly
ath, gyptnm
(CaSOt-2BaO), (Hg(OB),,
small amount of cal-
cium anlfite.
(Continued)
-------
TABLE 4-15. (Continued)
Process
Feature
Efficiency
Lime/Limestone
Scrubbing
90% removal can be
obtained generally
for low and high
snlfnr coals. Higher
removals ean be ob-
tained with higher
drop, and to some
extent scrubber type.
be obtained for low
sulfur coals. 91%
removal (or high
sulfur coals when
Commercially demon-
strated in over 30
FGD unita.
Double Alkali Scrubbing
90-99% removal can be
high aulfur coala. Con-
centrated mode has been
demoaatrated at
Louisville Oat «
Electric'* 200 W coal-
fired boiler. Smaller
industrial unita (General
Motora) have been oper-
ated in the dilute mode.
Chiyoda
Thoroughbred 121 Wellman-Lord
300 ppmv. Proceas 115UI coal-fired boiler.
has been demonatrated Can remove up to 95%
in Gulf Power' a Scholi SO,
atation - 20MV proto-
type.
Fly Ash
Dry Scrubbing Alkalinity Scrubbing
70% SO, removal using SJ-90% removal of SO,
80% SO, removal using atrated in Montana
sodium absorbent. Power's Colatrip 1 *
2. 95+% expected in
Colstrip units 3*4.
N3
Cost* Capital - |90/k! to
ll»5/kW.
Advantagea Lower capital cost
and OtM costs. SO,
and partlculatea can
be removed simul-
taneously. Rela-
tively simple
process.
Disadvantagea Process produces
approximately 2
times (by wt) sludge
aa ash collected.
Sludge can be
thixotroplo.
Sludge quantities
can be reduced by
forced oxidation.
Capital - flOl/kf to
e!63/kl.
Lower capital and OtM
costs. SO, can be
removed to vary high
efficiencies (99%).
Conventional process
equipment.
Proceaa produces 1.5
timea (by wt) filter
cake as collected aah.
316SS material of con-
atructlon may be re-
quired to prevent
corrosion and pitting.
Capital - »160/kW.
Capital and OtH costs
appear to be competi-
tive but data limited
to prototype experi-
ence. Potential
saleable gypsum by-
product .
Process haa not been
demonstrated commer-
cially in a 100HW or
larger unit.
Capital - (138/kW to
i265/kl.
Commercially demon-
atrated. Process pro-
duces saleable product
aulfur with a Claus unit
or eulfnrio acid. Lower
potential for scaling
than calcium system.
High utility costs
(steam) compared to
other systems. Special
metallurgy may be re-
quired. System required
to proceaa SO, to sulfur
or aulfnrio acid.
Capital - *2J/k¥ to
147/kW.
Lower projected
operating and capital
coats. Dry product.
Process will not be
commercially demon-
strated until late
1982. Product dis-
posal could be a
problem when sodium
salta are used aa
absorbents.
Not available.
Commercially demon-
atrated in 300MV
units. Sludge eon-
tsins little calcium
sulfite which im-
proves dewatering and
therefore reduces
settled water content.
Leas potential for
scaling.
Process is generally
applied to coal-fired
boilers which burn
high alkalinity coala.
Costs are first quarter 1980 dollars.
-------
Section 4
Gaseous Medium
Combustion Gases
S02 Removal
sodium sulfite solution to produce primarily sodium bisulfite. This bisulfite-
rich solution is then pumped to a forced-circulation vacuum evaporator where
it is indirectly heated by steam to convert the bisulfite to sulfite and gase-
ous S0a. A portion of the sodium sulfite is also converted irreversibly to
sodium sulfate and thiosulfate which must be purged from the system, requiring
a makeup of NaOH or NaCO,. The Wellman-Lord process can achieve over 90% S0a
removal.
Dry scrubbing experience to date has been limited, although systems that
have been operated show much promise, especially for low- and medium-sulfur
coals (58). The spray drying process is the only dry scrubbing process cur-
rently being offered commercially. In this process the absorbent solution,
usually either lime or soda ash, is atomized and sprayed into the incoming
flue-gas stream to increase the liquid/gas interface and promote mass transfer
between the S02 and the slurry droplets. Simultaneously, the thermal energy
of the gas stream evaporates the water in the atomized droplets to produce a
dry, powdered mixture of sulfite/sulfate and unreacted reagent. When used in
combination with fabric filters these systems have performed extremely well.
The fabric filter collects the particulates and also recovers some of the
expensive reagent which is reused. In addition, unused reagent that cakes on
the fabric is available to react with more SO, as flue gas passes through it.
FGD costs for boilers in synfuel plants will depend upon the amount of
sulfur emissions control required. This may vary depending upon the amount of
sulfur in the fuel. FGD cost data have been developed by the EPA for electric
utility steam generating units ranging in size from 25 MW to 1000 MW . The
c 0
cost variations are principally governed by 1) size of the boiler, 2) coal
used, 3) averaging time over which the plant must meet S0a limitations, and
4) the level of control maintained. Capital investment and annual operating
costs for lime/limestone and Wellman-Lord FGD systems are listed in Table
4-15.
248
-------
Section 4
Gaseous Medium
Combustion Gases
Particulate Removal
Particulate Removal
The choice of the particulate collection equipment depends upon a number
of factors: the properties of the materials such as particle size and physi-
cal and chemical properties; the concentration and volume of the particulate
to be handled; the temperature and humidity of the gaseous medium; and most
importantly, the collection efficiency desired.
There are four basic types of particulate collection equipment:
1) cyclones, 2) fabric filters/baghouses, 3) venturi scrubbers, and 4) elec-
trostatic precipitators. The key features and unit costs of these collection
devices are presented in Table 4-16.
Cyclones are generally employed for the removal of bulk particulates
(usually greater than 4 microns in size) and, in many cases, precede other
control devices. The unit installed costs of cyclones are relatively low,
approximately $212/m*/min.
Baghouses have very high particulate removal efficiencies and lend them-
selves to applications involving small or intermittent gas flows. Baghouses,
however, have high pressure drops (in comparison with electrostatic precipita-
tors) and cannot ordinarily handle wet gases, gases containing oily materials,
or gases having temperatures in excess of 573 K. Installed cost for a typical
baghouse unit is about J300/m3/min.
Venturi scrubbers can generally handle gases having temperatures higher
than those which can be handled by fabric filters, can operate at high pres-
sure, can tolerate wet and dry gases, and can be very efficient for the
removal of submicron particles. In contrast to devices in which the particles
249
-------
TABLE 4-16. KEY FEATURES Of PARTICIPATE COLLECTION EQUIPMENT
High Efficiency Cyclone
Fabric Filter (Baghouse)
Venturi Scrubber
Electrostatic Precipitatox
Operating Principle
Particulates removed from
gat stream by imparting a
centrifugal force. The
inertia of the particulatea
carriea thorn to the walla
where they fall to the
bottom of the cyclone for
removal.
Fabric filter material ia
arranged in a tabular shape
with the particulate-laden
gas stream paasing through
the filter. Particulate
removal primarily reaulta
from the buildup of col-
lected material on the
dirty-air aide of the fil-
ter. The filter it per-
iodically cleaned by mech-
anical ahaking ox a pres-
surized reverse air flow.
Removal of particulates
from a gas stream by
intimate contact with
multiple jet atreams of
scrubbing water and drop-
lets. Agglomerated pax-
ticulates are subtequently
removed in a centrifugal
and/or mitt eliminator.
A negative electrical charge
it imparted to the particu-
latea and they are collected
on positively charged platea.
Collected material ia removed
by periodically rapping or
vibrating the collection
platea.
Ln
O
Removal Efficiency
Range (weight %)
Inlet Loading
Limitations (g/Ha«)
Normal Pretaure
Drop Range (cm H,0)
Reliability or
Other Limitationa
SO to 80t for >5 |im.
80 to 95% for 5 to 20 urn.
>2.4
7 to 20
Cannot effectively remove
particulatea smaller than
S urn.
Secondary Waste
Collected particnlates.
98.5 to 99.5% for 0.2S
to O.S urn.
99 to 99.5% for 0.75
to 1 urn.
99.5 to 99.9% for 3 urn.
99.95% for >3 urn.
>0.24
5 to 25
Plugging problema will
result If condensation
occnra on filter media
or if hygroscopic-material
is collected. Temperature
limit varies with type of
filter media used, maximum
is 560 E.
Collected particulates.
50 to 92.5% for 0.25 urn.
60 to 98% for 0.5 urn.
70 to 99% for 0.75 urn.
90 to 99.6% for 3 urn.
>0.5
13 to 250
Reliability may be limited
by scaling, fouling, or
corrosion. Scrubbing liquor
blowdown may require treat-
ment or contain potentially
valuable material not
directly recoverable.
Scrubbing liquor blowdown
and wet slurry.
95 to 99% for 0.1 u
90 to 96% for 0.5 u
95 to 99% for 1 urn.
99 to 99.9% for 5 it
>0.24
0.5 to 2.5
Not applicable to combnatible
or potentially exploaive mix-
tnrea. Particulatea to be col-
lected muat have suitable
electrical resistivity to
facilitate efficient removal.
Used in low pressure applica-
tions. Limited to gaa streams
with temperatnrea below 700 E.
Collected particnlates.
(Continued)
-------
TABLE 4-16. (Continued)
High Efficiency Cyclone
Fabric Filter (Baghonae)
Venturi Scrubber
Electrostatic Precipitator
Inatalled Costs*
General Commenta
About i212/m'/min for total
installed ayatem.
High reliability due to
operating principle with
no moving parti. Low
energy requirements.
About i282/m>/min for total About t250/m'/min (increaa-
ayatem. ing cost with removal
efficiency).
High particulate reaioval
efficiency. High inatalla-
tion coat. Large acale
required.
High particulate removal
efficiency. Capable of
treating atreams with wide
rangea in temperature (no
limitation for high tem-
peratures), preaaure, and
gaa compoaition. High
effioienciea require high
energy consumption.
About 1250 to I530/m»/min
(increaaing coat with increas-
ing removal efficiency).
High particulate removal
efficiency, especially the sub-
micron rang*. High capital and
installation coata. Very low
pressure drop. Suitable for
high temperature or large
volume applicationa. High
electrical consumption. Sensi-
tive to particulate resistiv-
ity.
Coata are firat quarter 1980 dollara.
N)
Ul
-------
Section 4
Gaseous Medium
Combustion Gases
Particulate Removal
are collected in dry fora, venturi scrubbers generate a wet slurry which is
more voluminous and generally more difficult to dispose of. Unit installed
costs for venturi scrubbers are approximately i250/mj/min.
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 precipita-
tors, 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 sys-
tems). Unit installed costs range from $250 to $530/m3/min.
252
-------
Section 4
Gaseous Medium
Combustion Gases
Boiler Flue Gases
4.1.4.1 Boiler Flue Gases
Steam requirements for gasification, process heating, and power genera-
tion depend on the feed coal type, synthesis route and final products, types
of mechanical drivers employed, the extent of energy self sufficiency, and
several other site- and design-specific factors. Self sufficient facilities
are reported to have boiler heat input requirements amounting to 15 to 30 per-
cent of energy input to the gasifier. Host Lurgi facilities are expected to
burn coal along with some or all of the gasification byproducts to meet boiler
needs.
For purposes of developing example cost estimates for boiler flue gas
controls, a specific case of methanol synthesis with Rosebud coal is examined.
Total boiler input is estimated at 1490 GJ/hr (HHV), and about 40% of this can
be met by firing Lurgi tars, oils, phenols, and naphtha. Table 4-17 sum-
marizes the amounts of coal and byproducts used as boiler feed in this example
along with the percent of heat input and fuel sulfur, nitrogen, and ash con-
tributed by each material. About 22,000 kmols/hr of flue gas are generated
from this fuel mix containing 760 ppmv S0a, 280 ppmv NO , 8 grams/m3 of par-
ticulate, and less than 100 ppmv each of CO and VOC.
The quantity of flue gas from combustion on site varies directly with the
boiler duty and, to a much lesser extent, the fuel mix. The quantities of
S0a, NO , and particulate will vary both with type of coal and fuel mix. The
types of controls applicable to boilers in the subject facilities are not
influenced by the exact boiler size or by fuel mix. Of course, where fuel mix
is such that the desired level of control for SO , NO , or particulate can be
met without add-on processes, such processes might be considered as "not
applicable." For analysis purposes it is assumed that some portion of the
boiler duty will be met by firing coal; therefore, it may be desirable to con-
trol SO,, NO^, and particulates at the subject facilities.
253
-------
TABLE 4-17. EXAMPLE BOILER FEED AND POTENTIAL EMISSIONS CONTRIBUTIONS8
N>
Ul
.p-
Feed to Boiler
Coal
Lurgi Tar
Lurgi Oil
Lurgi Naphtha
Lurgi Phenol
Total Inputs
Feed Rate Input Heat
(Mg/hr) (%)
44.3 59.6
6.1 15.4
6.2 16.5
2.15 2.3
1.05 6.3
1487 GJ/hr
Input S
(%)
84.0
2.8
5.4
7.9
<0.01
0.58 Mg/hr
Input Ash
(%)
90.8
9.0
0.3
<0.01
<0.01
4.7 Mg/hr
Input N
(%)
84.1
7.8
6.5
1.6
<0.01
0.47 Mg/hr
Rosebud coal.
-------
Section 4
Gaseous Medium
Combustion Gases
Boiler Flue Gases
NO Control
As discussed previously, NO control in boilers is achieved through both
the design and operation of the combustion units to minimize its formation.
For new pulverized coal-fired boilers this is achieved primarily by the use of
low NO burners. Boiler manufacturers have used low NO burners as standard
z z
equipment on new boilers since the early 1970s. Therefore, there are no
incremental costs for NO control equipment since no new boilers can be pur-
chased from U.S. manufacturers with alternative burners, regardless of whether
the boiler is being built in the U.S. or abroad. However, retrofitting NO
control equipment on older boilers does have cost implications. Their cost
should be site specific and will also depend upon the type of NO control tech-
nique utilized. Since new facilities will employ new boiler units, retrofit
costs for NO controls are not discussed in this document. However, these
costs can be attained from several EPA documents (56,57).
Particulate Control
Particulate loading in boiler flue gases is a function of the type of
fuel being fired, the amount of ash in the fuel, and, to a lesser extent, sul-
fur content of the fuel. For the Rosebud coal case under consideration, the
uncontrolled particulate emission rate for the methanol synthesis case is
estimated to be 4200 kg/hr.
Usually electrostaic precipitators or baghouses are used for particulate
emission control from coal-fired boilers. The use of these technolgoies has
served dust control purposes as well as operational requirements for S0a con-
trol equipment employed downstream of these units. Although in utility appli-
cations at present electrostatic precipitators are more widely used than bag-
houses, the trend in new installations is towards use of baghouses.
255
-------
Section 4
Gaseous Medium
Combustion Gases
Boiler Flue Gases
Costs for ESPs are based upon the ESP effluent particulate loading
desired and the flue gas flow rate. To bracket emission levels commonly
achieved, emissions corresponding to fossil-fuel-fired steam generator stan-
dards and electric utility steam generator standards were used as a basis for
costing. Table 4-18 summarizes the controlled particulate emissions and esti-
mated costs for particulate control. With a control efficiency of 99.6%, the
estimated capital investment of $8 million and annualized cost of $12 million
are 1.0 and 0.85% of the respective total base plant costs.
It should be noted that this 99% reduction of particulates emissions in
the flue gas results in the collection of some 4200 kg/hr of dry solids.
Handling this dry solid can result in fugitive particulate emissions. Control
of such emissions are discussed in Section 4.1.6 under fugitive particulate
emissions from materials handling.
TABLE 4-18. CONTROL OF PARTICULATES IN BOILER FLUE GAS BY ESP
(ROSEBDD-METHANOL SYNTHESIS CASE)
99.6% Control 98.6% Control
Controlled Particulate Emissions (kg/hr) 19 60
Costsa
Total Capital
Total Annual Operating
Total Annual ized
Percent of Base Plant
Capital
Annual ized
8.2
0.2
1.7
1.0
0.85
6.8
0.2
1.3
0.83
0.63
o
Cost are millions of first quarter 1980 dollars.
256
-------
Section 4
Gaseous Medium
Combustion Gases
Boiler Flue Gases
SOa Removal
As discussed previously, a number of competitive FGD processes are capa-
ble of achieving similar S0a reductions from flue gases. However, Wellman-
Lord and limestone FGD processes are the most widely used in industry today.
The Wellman-Lord has been chosen to represent costs typical of non-throwaway
FGD processes. These FGD costs have significant dependence on boiler size,
fuel sulfur, and the degree of S0a removal desired. When sludge disposal
costs are included, throwaway S0a removal processes incur costs similar to
Wellman-Lord in similar service.
The boiler associated with a Lurgi methanol plant using Rosebud coal has
approximately 16.5 kmol/hr (760 ppmv) of S0a in the flue gas. For cost analy-
sis purposes, S0a reductions corresponding to 90 percent removal, the
standards of performance for fossil-fuel-fired boilers (520 ng/J or 28 percent
removal in this example), and the standards of performance for large electric
utility steam generators (70 percent removal in this example) have been used.
Table 4-19 presents the cost estimates for these levels of S0a control.
Secondary wastes from FGD systems include sludges, brines, and elemental
sulfur. For the Wellman-Lord case about 130 kg/hr of brine is generated.
Byproduct sulfur production of up to 330 kg/hr is also generated in the
Wellman-Lord case.
257
-------
TABLE 4-19. COSTS FOR WELLMAN-LORD CONTROL OF S0a IN BOILER FLUE GASES
ROSEBUD COAL TO METHANOL
SO. Removal (percent)
90 70 28
Costs a
Capital 38.7 34.3 23.7
Operating 7.3 5.8 2.9
Total Annualized 13.9 11.7 7.0
Percent of Base Plant
Capital 2.9 4.2 2.9
Annualized 3.5 5.9 3.5
S0a Emissions After Control 1.7 5.0 12.0
(fanols/hr)
aCosts are millions of first quarter 1980 dollars.
258
-------
Section 4
Gaseous Medium
Combustion Gases
Process Heaters
4.1.4.2 Process Heater Flue Gases
Process heaters in a coal gasification facility are expected to utilize
either waste gases or liquid products from synthesis/fractionation operations.
These waste gases and liquid fuels are essentially sulfur and nitrogen free.
Therefore, the contribution of process heaters to sulfur and particulate emis-
sions is minimal. Any NO^ emissions generated are a function of combustion
design, and combustion modification techniques discussed previously are appli-
cable.
Coal lockhopper gases may also be used as fuels in Lurgi-based plants and
controls for these gases have been discussed in Section 4.1.2.1. If controls
for S0a or particulates were desired, lockhopper gases would be used only in
large boilers where controls should already exist rather than in small process
heaters which would require add-on devices.
Control of NO^ emissions from process heaters has been investigated in
recent years. Initial data indicate that low excess air, staged combustion,
and low NO burners can be used to reduce NO emissions. Costs and effec-
x x
tiveness of these techniques are very site-, size-, and fuel-specific. The
number and size of process heaters for a coal gasification facility depend
upon the auxiliary configuration chosen. Since it is beyond the scope of this
document to perform the detailed engineering required to assess all the possi-
ble configurations, no detailed cost estimates for the control of NO emis-
x
sions from specific process heaters was performed. However, cost information
from vendors indicates that low NO^ burners may cost approximately J0.95/MJ
when applied to process heaters (59).
259
-------
Section 4
Gaseous Medium
Combustion Gases
Wastewater Incin.
4.1.4.3 Wastewater Incineration Flue Gases
One approach to wastewater treatment in Lurgi facilities is incineration
of preconcentrated wastes to destroy organics. Lurgi byproduct tars, oils,
phenols, or naphtha could serve as convenient fuels. Flue gases from waste-
water incineration will contain the inorganic salts present in the wastewater
and SO, derived from sulfur in the fuel. NO is not expected to present pro-
blems since combustion temperatures are low. Some fixed nitrogen will be pre-
sent in both the waste to be incinerated and the fuel and could contribute to
fuel NO . Flue gas flow rates are estimated at 3400-7300 kmols/hr containing
0.02-0.1% SOj and 4-5 grams/Mm* particulate.
Venturi scrubbing is the most applicable control for particulate removal
from high moisture flue gases. Scrubbing liquor will solubilize salts origi-
nally contained in the wastewater, and a blowdown for these salts from the
system is required. Any particulate matter generated by fuel combustion
(i.e., ash and carbon) will also be largely removed by venturi scrubbing so
that suspended solids removal from scrubbing liquor blowdown should also be
necessary. Venturi scrubbers can remove over 99% of particulate in flue
gases, but in the subject application, 90-99% removal is probably more realis-
tic.
If SO, removal is required, a captive FGD unit could be added to the
venturi scrubber. Alternatively, caustic soda could be added to the venturi
scrubbing liquor to effect SO, removal. Sodium sulfate/snlfite would be
removed as blowdown from the system along with wastewater-derived salts.
260
-------
Section 4
Gaseous Medium
Combustion Gases
Wastewater Incinerator
Table 4-20 summarizes the estimated costs for the above controls. The
calculations indicate that either Wellman-Lord or caustic addition for S0a
control greatly add to the annualized cost of ventnri scrubbing alone for par-
ti cul ate control. Control costs are also compared to base plant costs in
Table 4-20. The capital and annualized costs range from 0.04 to 0.07% and
0.07 to 1.5%, respectively, of base plant costs based on control alternatives
selected. In all cases, an aqueous brine is generated which would require
disposal or further treatment.
261
-------
TABLE 4-20. COST SUMMARY OF WASTEWATER INCINERATOR FLUE GAS CONTROLS
Control Technique
Estimated Control Costs
Total
Capital
Total Annual
Operating
Total
Annualized
Percent
Capital
of
Base Plant Costs
Total Annualized
Low Pressure Venturi
Venturi Only
With Wellman-Lord
Alkaline Scrubber
0.33-0.56 0.07-0.13
4.01-6.24 0.62-0.87
0.35-0.60 1.33-2.49
0.13-0.23 0.04-0.07 0.07-0.12
1.31-1.94 0.49-0.76 0.66-0.97
1.39-2.95 0.04-0.07 0.70-1.48
High Pressure Venturi
Venturi Only
With Wellman-Lord
Alkaline Scrubber
0.34-0.66
4.38-6.34
0.36-0.71
0.12-0.22
0.67-0.96
1.38-2.94
0.18-0.33
1.42-2.06
1.44-3.05
0.04-0.08
0.53-0.77
0.04-0.09
0.09-0.17
0.71-1.03
0.73-1.53
&Costs are millions of first quarter 1980 dollars.
-------
Section 4
Gaseous Medium
Dust From Storage
4.1.5 Fugitive Dust from Material Storage
Open or partially enclosed storage piles are often used for bulk
materials not affected by precipitation or slight contamination such as coal,
sand, gravel, clay, and gypsum. The material may be stored for a short time
with a high turnover rate to accommodate surges in daily or weekly rates of
sequential processes or may provide a long-term reserve for emergency supply
or to meet cyclical seasonal demands.
Most dust arises from stockpile areas as the material is dumped from the
conveyor or chute onto the pile and as material is removed from the pile.
During periods of high wind speeds or low moisture, wind erosion of the sur-
face may also cause emissions.
In coal gasification/liquefaction plants, fugitive dust emissions are
emitted from coal and solid waste storage piles. The techniques used to con-
trol these emissions are not unique to coal gasification plants and are widely
used in industries that require large scale materials storage. The most com-
monly used techniques are vegetative stabilization, chemical stabilization,
capping, stacked segregation, water spraying, and confinement. Surface pro-
tection methods such as vegetative stabilization, chemical stabilizaton, cap-
ping, and stacked segregation are primarily used on reserve (inactive) storage
piles since these piles are subject to minimal disturbances. Active storage
piles generally require either water spraying or confinement to control dust
emissions. The key features and unit costs for these techniques are listed in
Table 4-21.
Vegetative stabilization involves planting an appropriate ground cover or
shrub over the pile to be stabilized. A soil cap may be required to support
vegetation. The efficiency of vegetative cover in reducing wind erosion is
dependent on the density and type of vegetation that can be grown. For
263
-------
TABLE 4-21. KEY FEATURES OP STORAGE PILE DUST CONTROL TECHNOLOGIES
Method
Control Principle
Control
Effectiveness
Reliability/
Special Problems
Unit Costs
Other Pollutants
Generated
Vegetative
Stabilization
Chemical
Capping
Covering pile vith sod.
Wetting Agents
Modify surface tension
properties to improve
effectiveness of water
sprays.
Crusting Agents
Organic binders combine
with particles to form
tough crust on surface.
Paving with earth or
asphalt or cover with
polyethylene.
Approximately 65%
reduction over un-
stabilized pile; and
90% if chemical
stabilizer is alao
used.
Up to 90% reduction
in dutt losses.
Up to 90% reduction
in dost losses.
Up to 100%.
Requires frequent
watering.
Handling of sod during
reclamation operations
is cumbersome and
expensive.
Upper layer of stored
material is contami-
nated with soil.
Piping may require heat
tracing when freezing
is a concern.
Can cause corrosion
problems in equipment
exposed to sprays.
May increase material
degradation.
May increase chances
of spontaneous combus-
tion, especially in
piles subject to stock-
pile and reclaim opera-
tions.
Crust tends to break up
during heavy rains.
Both coverings may
increase chances of
spontaneous combustion.
Polyethylene presents
severe handling prob-
lems and is also not
practical in high wind
climates.
*2.70/m>
Soil dust from
earth covering.
i.33-.77/Mg
Volatile! which
depend on wetting
agent utilized.
i.55-.22/m»
Volatiles which
depend on crust-
ing agent uti-
lized.
4.49/m* for
asphalt.
tl.967m> for
polyethylene.
Soil dust from
earth covering.
(Continued)
-------
TABLE 4-21. (Continued)
Method
Stacked
Segregation
Control
Control Priogiple Effectiveness
Coating surface or con- No data available.
pacted storage pile with
layer of select, median
sized materials.
Reliability/ Other Pollutants
Special Problems Dnit Costs* Generated
Either deliveries of dif- Not available
ferent sized material must
be coordinated or both sizes
•ust be readily available
from storage.
None
Water Spray
NJ
C^
Oi
Spray application of
210-150 L/Hg to reduce
dusting.
Approximately 50%
reduction in losses.
Piping may require heat Not available
tracing when freezing is
a concern.
None
2. Hay increase degradation.
3. Frequent re-treatment
Confinement Enclosure of active Dp to 99% reduction
storage pile in a in losses.
totally enclosed barn
or silo with point
source dust control
equipment on building
vents.
necessary.
Requires extreme care when
storing potentially ex-
plosive materials.
IllO/Mg of
stored material
4l million to
|3 million per
silo depending
on size.
None
Costs are first quarter 1980 dollsrs.
-------
Section 4
Gaseous Medium
Dust From Storage
applications such as stabilizing tailing piles, the use of vegetative stabili-
zation results in a decrease in emissions of approximately 65%. When vegeta-
tive stabilization is used in conjunction with a chemical stabilizer, this
efficiency increases to approximately 90%.
Chemical stabilization to decrease fugitive dust emissions involves the
application of wetting or crusting agents. Wetting agents are used to provide
better wetting of fines and longer retention of moisture. They also reduce
the water's surface tension allowing the fines to be wetted with a minimum
amount of water. This treatment protects stockpiled material until the added
moisture is removed by heat and wind. Some of these agents remain effective
for weeks or months without additional rewatering, depending on local condi-
tions. Crusting procedures involve the use of bunker C crude oil, water solu-
ble acrylic polymers, or organic binders. These materials are sprayed on the
surface of the storage pile, coating the top layer of particles with a thin
film. This film causes the particles to adhere to one another to form a tough
durable crust which is resistant to wind and rain. As long as the crust
retains intact, the storage pile is protected from wind losses.
Capping involves the paving of the surface area of the storage pile with
asphaltic compounds or earth or covering the pile with polyethylene tarpau-
lins. Usually a slurry of wood pulp and asphalt or road tar is sprayed over
the surface of the pile. The covering is usually about 3 mm thick. Polyethy-
lene tarpaulins are also used; however, they are cumbersome to handle when
there are high wind speeds or when a large size storage pile is to be capped.
Another effective means of controlling dust emissions from coal storage
piles is the stacking of coarse material on the surface- of a properly com-
pacted pile. For instance, a 0.152 m layer of fine coal (6.4 mm x 0 mm) on
the top and sides of the coal storage pile can be anchored in place by a
266
-------
Section 4
Gaseous Medium
Dust Prom Storage
0.102 m layer of larger size coal (24 mm x 0 mm) placed on top of the fine
coal. The larger size coal has better weathering characteristics compared to
the smaller sized coal.
Water spraying is another commom method of dust suppression. Dust con-
trol by water spraying is usually obtained by placing spray nozzles at strate-
gic locations over the stockpile area. The spraying operation is simple in
that it only involves the operation of a pump. Water requirements for large
volume operations vary from 0.21 to 0.25 m»/Mg of material. Such systems
are, however, prone to freezeups during winter months. Also, the added mois-
ture can create handling problems during reclamation and subsequent pro-
cessing.
Enclosure of the coal storage pile is generally the most effective means
of reducing fugitive dust emissions, because it allows the emissions to be
captured. However, enclosures can be very expensive, since they have to be
designed to withstand wind and snow loads and meet requirements for interior
working conditions. An alternative to enclosure of all material is screening
the material prior to storage, and sending the oversize material to open
storage and the fines to enclosures.
267
-------
Section 4
Gaseous Medium
Part. From Conveying
4.1.6 Particulates from Material Conveying and Processing
Material transfer and conveying operations are common to nearly all pro-
cessing industries. Equipment includes belt conveyers, screw conveyers, bas-
ket elevators, vibrating conveyors, and pneumatic conveyors. The type of con-
veying equipment varies with the application and is determined primarily by
the quantity and characteristics (size, specific gravity, moisture content,
etc.) of the material being handled, the transfer distance and elevation, and
conditions of the working environment. Loss of material from conveyors is
primarily at the feeding, transfer, and discharge points and occurs due to
spillage or windage. The majority of particulate emissions are generally from
spillage and mechanical agitation of the material at transfer points.
Material from storage piles is generally crushed, screened, and pulver-
ized prior to transfer to the boiler or gasification plants. Fugitive dust
generated during this process is typically controlled by either wet suppres-
sion techniques or dry particulate collection systems.
Fugitive particulate control systems utilizing a wetting agent consist of
pre-engineered modules which incorporate both water handling components and
automatic spray controls. A typical spray solution contains 1,000 to 4,000
parts of water to one part of a wetting agent. The rate of spray application
is about 4 to 8 liters/Mg of material. This rate of application results in an
increase of total surface moisture by about 0.5 to 1.0%.
In wet dust suppression, the fugitive particulate is first confined by a
curtain of moisture droplets. Then the wetting of dust takes place by contact
and penetration with moisture droplets. Finally, agglomerates are formed by
contact with other droplets and settling takes place because of the additional
weight of the other droplets. Wet suppression techniques can cost from $0.33
to $0.77/Mg of material processed, depending on the wetting agent utilized.
268
-------
Section 4
Gaseous Medium
Part. From Conveying
Dry particulate collection systems consist of enclosures to contain the
particulates, ductwork and exhaust systems to convey the particulate laden
air, and particulate collectors to separate the particulate from the discharge
air. Typically, hoods are used to capture particulate emissions at transfer
points. Conveyors generally have a half cover which provides dust containment
and also shields the conveyor from wind, rain, and snow. Enclosure sizing is
a function of the source under consideration. The type of enclosure used
depends upon the particulate source. Typical ductwork velocities for particu-
late capture for different source types are readily available (60). Dust
collectors that are applicble to the collection of the captured particulates
are: 1) venturi scrubbers, 2) electrostatic precipitators, 3) fabric fil-
ters, and 4) dry centrifugal collectors. These have been discussed previously
in Section 4.1.4.
269
-------
Section 4
Gaseous Medium
Fugitive VOC
4.1.7 Fugitive VOC Emi
There are many sources of fugitive VOC emissions in a synthetic fuel
plant. These emissions can be categorized as 1) evaporative emissions that
result from the storage of liquid products and byproducts and 2) VOC emis-
sions that result from fluid leaks from plant equipment.
Evaporative emissions from storage tanks storing volatile liquids occur
because of temperature change which causes the vapor pressure of the stored
liquids to vary, resulting in vapor emissions. The minimal accepted standard
for storage of VOC is the fixed roof tank. It is designed to operate at only
slight internal pressure or vacuum and is susceptible to emissions from ther-
mal expansion and other mechanisms by which vapors are produced.
Emissions from fixed roof tanks can be reduced by minimizing diurnal tem-
perature variations (e.g., placing tanks underground), proper setting and
maintenance of pressure/vacuum vents, and leak prevention efforts. Signifi-
cant controls can be effected by either floating a cover on the surface of the
stored liquid or by replacing the fixed roof storage tank by a floating roof
storage tank.
Floating roof tanks successfully limit hydrocarbon losses by eliminating
the ullage into which stored material vaporizes. This is accomplished by
floating a rigid deck or roof on the surface of the stored liquid, thus elimi-
nating air space and preventing the formation of organic vapor above the
liquid surface. To effectively control emissions, the floating roof employs
primary and secondary seals to shelter the liquid surface from the atmosphere.
Control efficiencies of greater than 90% are achievable by floating roof
tanks.
270
-------
Section 4
Gaseous Medium
Fugitive VOC
Vapor processing units can also be used to control VOC emissions from
fized roof storage tanks. Some of the vapor processing techniques available
and primarily demonstrated for gasoline usage are carbon adsorption, thermal
oxidation, refrigeration, compression-refrigeration-absorption, and compres-
sion-refrigeration-condensation.
The carbon adsorption vapor recovery unit uses beds of activated carbon
to remove VOCs from the air-vapor mixture. These units generally consist of
two vertically positioned carbon beds and a carbon regeneration system. Air-
vapor mixture enters the base of one of the adsorption columns and the VOC
components are adsorbed onto the activated carbon as the gases ascend.
Adsorption in one carbon bed occurs for a specific timed cycle before switch-
over to desorption. The nearly saturated carbon bed is then subjected to
vacuum, steam, or thermal regeneration or a combination of these methods, and
the VOCs are stripped from the bed. Vacuum regenerated units recover VOCs by
absorption in a cooled liquid stream which circulates between the control unit
and product storage. The air and any remaining VOCs exiting from the absorber
are passed again through the absorbing bed and exhausted to the atmosphere.
Steam regenerated units condense the VOC-water mixture and return the sepa-
rated product to storage. Some vacuum regenerated systems remain in operation
for up to two hours after loading activity ceases, in order to collect any
residual vapors in the system and to assure complete regeneration of the car-
bon beds.
Thermal oxidation units rely upon burning VOC vapors to produce nonpol—
luting combustion products. Vapors are piped either to a vapor holder or
directly to the oxidizer unit. When a vapor holder is used, operation of the
oxidizer begins or ends when the holder reaches the respective preset levels.
With no vapor holder in the system, the oxidizer is energized by means of
271
-------
Section 4
Gaseous Medium
Fugitive VOC
pressure in the vapor line or by an electrical signal produced by manual acti-
vation. In some cases, propane is injected into the vapor stream to keep the
VOC level above the explosive range.
Refrigeration type recovery units remove VOCs from an air-vapor mixture
by straight refrigeration at atmospheric pressure. Vapors displaced from
storage tanks enter a condenser section where the temperature ranges from
190 K to 210 K. Some units contain a precooler section at 274 K to remove
most of the water from the gases prior to the main condenser. There are no
compression stages in this type of unit. The condensed product is collected
and piped to one of the product storage tanks. The cold collection surfaces
are periodically defrosted by pumping warm (305 K) liquid through the conden-
ser. This defrost fluid is kept warm by heat salvaged from the refrigeration
equipment. Recovered water can pass to a waste storage tank or an oil-water
separator if the combination is not miscible. The defrost cycle takes from IS
to 60 minutes, depending on the amount of ice accumulated on the finned-tubes.
In a compression-refrigeration-absorption (CRA) vapor recovery system,
the vapors from the storage tanks are first passed through a saturator which
sprays liquid product into the air-vapor gas stream. This ensures that the
VOC concentration is above the explosive range. The saturated gas mixture is
stored in a vapor holder until, at a preset level, it is released to the con-
trol unit. The vapor holder is usually a special tank containing a bladder
with variable volume and constant pressure. A product storage tank with a
lifter roof can also function in this capacity.
The first stage of CRA processing is a compression-refrigeration cycle in
which water and heavy VOCs are compressed, cooled, and condensed. The uncon-
densed vapors move into a packed absorber column where they are contacted by
chilled liquid product drawn from product storage and absorbed. The fresh
product stream is used first in the saturator, then it passes through an
272
-------
Section 4
Gaseous Medium
Fugitive VOC
economizing heat exchanger as it enters the absorber. The rich absorbent also
passes through the heat exchanger before being pumped back to storage. The
operation of the control system is intermittent, starting when the vapor
holder is filled and stopping at its lower preset level. Cleaned gases are
vented from the absorber column to the atmosphere.
A vapor recovery system employing a compression-refrigeration-condensa-
tion unit makes use of a vapor holder to store accumulated air-vapor mixture
and a saturator for ensuring that the VOC concentration is above the explosive
range. The unit is activated and begins processing vapors when the vapor
holder has filled to a preset level. Incoming saturated air-vapor mixture is
first compressed in a two-stage compressor with an intercooler. Condensate is
withdrawn from the intercooler prior to compression in the second stage. The
compressed vapors then pass through a refrigeration-condenser section where
they are returned along with the intercooler condensate to the product storage
tank. Cleaned gases are exhausted from the top of the condenser.
Costs for vapor processing units vary with the type of product and the
product throughput. In the case of gasoline, capital investment costs for
these units range from $152,000 to $270,000 for a gasoline throughput of 380
m*/day. These costs increase by 15% when the gasoline throughput increases
by 150%.
Costs for aluminum internal floaters range from approximately $4300 to
$42,200 for storage tanks with diameters of 5 to 30 meters, respectively.
Secondary seals are estimated to cost $75 per linear meter for internal float-
ers and $130 per linear meter for external floating roofs (61).
273
-------
Section 4
Gaseous Medium
Fugitive VOC
Fugitive Emissions
Fugitive Organic
There are many potential sources of fugitive organic emissions that
result when process fluids leak from plant equipment in a typical gasifica-
tion/liquefaction synthetic fuel plant. Some of these are: pumps, compres-
sors, in-line process valves, pressure relief devices, open-ended valves,
sampling connections, flanges, agitators, and cooling towers.
There are two basic methods which have been used to control fugitive
organic emissions: 1) leak detection and repair methods, and 2) equipment
specification. Leak detection methods include individual component surveys,
area (walkthrough) surveys, and fixed point monitors. In an individual com-
ponent survey each fugitive emission source (pump, valve, compressor, etc.) is
checked for VOC leakage. The source may be checked for leakage by visual,
audible, olfactory, soap bubble, or instrument techniques. Visual methods are
particularly effective in locating liquid leaks. Escaping vapors from high-
pressure leaks can be audibly detected, and leaks of odorous materials may be
detected by smelling the odor. Perhaps the best method of identifying leaks
of VOC from equipment components is by using portable detection instruments.
By sampling and analyzing the air in close proximity to the leak the hydro-
carbon concentration of the sampled air can be determined. The leak rate from
the source can be estimated, since relationships exist between monitoring con-
centrations and mass emission rates.
An area survey requires the use of a portable hydrocarbon detector and a
strip chart recorder. The procedure involves carrying the instrument within
one meter of the upwind and downwind sides of process equipment and associated
fugitive emission sources. An increase in observed concentration indicates
leaking fugitive emission sources. The instrument is then used for an indivi-
dual component survey in the suspected leak area.
274
-------
Section 4
Gaseous Medium
Fugitive VOC
Fugitive Emissions
Fixed point monitors are automatic hydrocarbon sampling and analysis
instruments positioned at various locations in the process unit. The instru-
ments may sample the ambient air intermittently or continuously. Elevated
hydrocarbon concentrations indicate a leaking component. As in the walk-
through method, an individual component survey is required, to identify the
specific leaking component in the area. For this method, the portable hydro-
carbon detector is also required.
Reduction of fugitive emissions from the identified leaking components is
effected by repair methods. In many cases, perfect repair will not be
achieved; however, effective repair can substantially reduce emissions from
the leaking component. Typical repair methods employed on the various compon-
ents are listed in Table 4-22.
TABLE 4-22. REPAIR METHODS FOR FUGITIVE EMISSIONS REDUCTION
Component Repair Method
Pumps and compressors Tighten packing gland
Relief valves Manual release of the valve may
improve the set seal
In-line valves Tighten packing gland; lubricate
plug type valves; inject sealing
fluid into process valves
requiring repair
Flanges Replace flange gaskets
The second method used to control fugitive emissions is by equipment
specification. Typical equipment specifications are listed in Table 4-23.
275
-------
TABLE 4-23 . EQUIPMENT DESIGN/MODIFICATIONS FOR FUGITIVE HYDROCARBON EMISSIONS CONTROL
Pumps - improve seal at the junction of moving shaft and stationary casing
- use sealess pumps
- use double mechanical seals
- use closed vent systems around seal areas
Compressors - improve seal at the junction of moving shaft and stationary casing
- use double mechanical seals
- use closed vent systems around seal areas
Pressure Relief - use rupture disks upstream from the safety/relief valve
•jj Devices - use resilient seal or "o-ring" relief valves
- use closed vent systems to transport valve discharge to control
devices
Open-Ended Valves - install a cap, plug, flange, or a second valve to the open end of
the valve
In-Line Valves - use diaphgragm and bellows seal type valves
-------
Section 4
Gaseous Medium
Fugitive VOC
Fugitive Emissions
Costs for repair methods will depend upon the complexity of the component
undergoing repair. The major costs of maintenance and repair methods are
labor related. In the case of equipment specifications, costs will depend
upon the component being replaced. Typically, double mechanical seals cost
i815/pump. Flush oil systems for double mechanical seals cost $1500/pump.
277
-------
Section 4
Gaseous Medium
Fugitive VOC
Storage Emissions
4.1.7.1 Product/Byproduct Storage Emissions
Various types of storage vessels are employed to store petrochemical pro-
ducts. The suitability of a specific tank design depends on the vapor pres-
sure that the stored product exerts at ambient conditions and the storage
desired. The floating roof tank is widely used for control of volatile organ-
ic compounds such as gasoline, when the true vapor pressure is in the range of
10 to 80 kPa at storage conditions. Low vapor pressure VOCs «10 kPa) are
stored in fixed roof tanks. Therefore, methanol and gasoline products would
be stored in floating roof tanks, and diesel fuel and fuel oil in fixed roof
tanks. Uncontrolled emissions estimates from these tanks have previously been
discussed in Section 3.6.5.
Emissions from floating roof tanks consist primarily of standing storage
losses and wetting losses. These losses are greatly reduced by the addition
of secondary seals. The most widely used approach for VOC control is addition
of secondary seals to existing floating roof tanks. The secondary seal is
generally of a resilient fabric (e.g., loop seals) or a pliable material such
as treated rubber. Its flexibility allows it to maintain contact in places
where the shell might be out of round as well as in areas where rivet heads
project from the shell wall. Upon descent of the roof, these seals wipe down
the film left behind by the primary seal. These seals also reduce standing
storage evaporative losses since they form a second seal above the vaporized
product which has diffused past (or permeated through) the primary seal. Not
only do they form a second barrier for the vapor, they also seal this vapor
off from the effects of mixing air. As a result, secondary seals are effec-
tive control devices which, when used on floating roof tanks, can reduce over-
all emissions by as much as 98% (refer to Table 4-24).
278
-------
TABLE 4-24. STORAGE TANK EMISSION ESTIMATES
Tank Information
Product
Mixed A}cohol •
Methanol
Gasoline
Gasoline
Diesel
Fuel Oil
Lnrgi Naphtha
NJ
vo Lurgi Oil
Lurgi Tar
Lurgi Phenol
Roof Type
Float
Float
Float
Float
Fixed
Fixed
Float
Fixed
Fixed
Fixed
Capacity
1.415
42,930
9,540
14,310
1.590
493
1.113
1.590
6,360
1,113
Diameter
12.2
61.0
32.0
35.1
13.1
10.4
12.5
13.1
23.4
12.5
Process
Types
F-T
M.G
F-T
G
F-T
F-T
All
All
All
All
Vapor
Pressure
(kPa)
15.4
5.1
15.4
5.1
46.1
5.1
46.1
24.1
0.08
0.023
5.5 x 10~*4
1.48 x 10~
32.1
16.4
0.90
0.10
0.66
0.24
0.79
0.124
Mass Emission
Uncontrolled
6.092
2.075
30.500
10.400
17,940
9.650
19.660
10.580
386
98
4.2
1.5
4,370
2.190
3.730
1,160
10,640
1,990
2,430
480
Rate (k«/vr)b
Controlled
2,350
760
11,760
3.810
992
527
1.100
591
25.8
25.3
0.53
0.14
246
136
40.7
32.4
79.6
66.3
31.2
22.8
Control
Efficiency
61
63
61
63
94
95
94
94
93
74
87
91
94
94
99
97
99
97
99
95
V-T = Fischer-Tropscb; M = Methanol; G - Mobil; M = Gasoline
The higher values represent the month with maximum emissions from one of the study sites. The lower numbers represent the
minimum average annual values from one of the study sites.
-------
Section 4
Gaseous Medium
Fugitive VOC
Storage Emissions
Fixed roof tanks consist of a steel cylindrical shell with a permanently-
affixed roof. The roof design may vary from cone-shaped to flat. Of present-
ly employed tank designs, the fixed roof tank is the least expensive to con-
struct and is generally considered as the minimal accepted standard for stor-
age of petroleum liquids. Fixed roof tank emissions are most readily con-
trolled by the installation of internal floating roofs. An internal floating
roof tank is essentially a fixed roof tank with a cover floating on the liquid
surface inside the tank, rising and falling with the liquid level. Generally,
emission reductions of more than 90% are achieved by retrofitting fixed roof
tanks with internal floating roofs. Other control technologies such as vapor
processing systems can also be used to effect 90% control. However, internal
floating roof covers are widely used because of their simplicity and low
annual operating and capital costs. Controlled emissions from fixed roof
tanks are listed in Table 4-24.
Cost increments for the application of secondary seals or internal float-
ers to storage tanks at the subject facilities are listed in Table 4-25. The
capital investment and net annualized costs per product produced in the sub-
ject facilities are estimated to range from $4,900 to $30,800 and from zero to
$7,000, respectively. These costs are less than 0.004% of the respective base
plant costs.
280
-------
TABLE 4-25. ESTIMATED INCREMENTAL COSTS FOR STORAGE OF SYNTHETIC LIQUIDS*
Type of
Liquid
(tank size)
Methanol
(1.415 m»)
Metahnol
(42.930 •')
Gasoline
(9. 540 B»)
Gasoline
(14.310 •*)
Diesel
(1.590 «')
NJ
M Fuel Oil
(493 •>)
Lnrgi Naphtha
(1.113 •')
Lnrgi Oil
(1.590 ••)
Lnrgi Tar
(6.360 m>)
Lnrgi Phenol
(1.113 ••)
Type ofb
Control
SS
SS
SS
SS
IF
IF
SS
IF
IF
IF
Capital
Investment
(10«i)
4.98
24.91
13.07
14.34
14.74
10.99
5.10
14.74
30.78
13.88
Percent
of Base
Plant Costa
0.001
0.003
0.002
0.002
0.002
0.001
0.001
0.002
0.004
0.002
Annual ized
Control
System Costs
(Dollars)
1,340
5,770
3.140
3,420
3,400
2,550
1.370
3,400
7,150
3,250
Annual
Product
Savings
(Dollars)
590
2.960
4.610
5.050
41
0.41
90
120
160
31
Net
Annual
Cost
(Dollars)
750
2.810
(1.470)°
(1.630)°
3,350
2.550
1,280
3.180
6,990
3,220
Controlled
Emissions
Cost per kg
(i/kg)
0.30
0.22
0
0
20.2
981
0.41
0.03
1.12.
2.25
'Costs are first quarter 1980 dollars.
SS - secondary seal, IF - internal floater.
°Credits.
-------
Section 4
Gaseous Medium
Fugitive VOC
Process Sources
4.1.7.2 Fugitive Organic Emissions from Process Equipment
As discussed earlier, process equipment such as pumps, compressors, in-
line valves, pressure relief devices, open-ended valves, etc., are prone to
leakage and thus are sources of fugitive organic emissions. Two methods can
be employed to control these emissions. A labor intensive method involving
leak detection and constant repair and maintenance can be used and/or replace-
ment of leaking equipment by leak-free equipment can be applied. Obviously,
if equipment specification, in addition to extensive leak detection and
repair, is performed greater reduction in fugitive organic emissions is
achieved.
Two approaches to reduce fugitive organic emissions are generally used.
In the first approach, leak detection and repair methods presented in the
VOC leak control techniques guideline document for the petroleum industry
(62) can be applied. Here leak detection is accomplished by checking equip-
ment components for emissions of VOC at specified intervals using a portable
VOC detection instrument to sample and analyze the air in close proximity to
the potential leak area. A measured VOC concentration greater than some
predetermined level would then be a leak that would require equipment repair.
A measured VOC concentration less than the detection level is assumed not to
require any equipment repair. Inspection of all equipment has to be performed
on a regular basis.
Using the aforementioned approach, controlled emissions were estimated
for the subject facilities. Emission reductions of approximately 70% (see
Control Technology Appendices for Pollution Control Technical Manuals for
details of emission reduction calculations) were estimated for the three
indirect liquefaction cases as shown in Table 4-26. For SNG production, no
liquid products are synthesized and the uncontrolled fugitive VOC emissions
from byproduct handling are less than those estimated for best control of
282
-------
TABLE 4-26. FUGITIVE ORGANIC EMISSIONS FROM PROCESS EQUIPMENT
NJ
00
Pump Seals
Light Liquid Service
Heavy Liquid Service
In-Line Valves
Gas Service
Light Liquid Service
Heavy Liquid Service
Safety Relief Valves
Vapor Service
Compressor Seals
Hydrocarbon
Hydrogen
Flanges
Drains
TOTALS
Uncontrolled
Emission
Factor
(kg/hr)
0.113
0.021
0.027
0.011
0.00023
0.086
0.64
0.05
0.00025
0.032
Uncontrolled Emission Rates
(kK/hr)
Fischer-
Tropsch
18.0
0.5
37.0
40.0
0.1
25.0
13.0
1.8
1.4
12.0
149
Methanol
4.4
0.2
9.9
9.8
0.1
5.2
2.9
—
1.5
_JLI
37.0
Mobil-M
8.3
0.4
18.0
18.0
0.1
11.0
1.5
—
2.8
5.6
66.0
Controlled Emission
(kc/hr)
Fischer-
Tropsch
0 - 4.5
0 - 0.4
3.7
10.3
0.1
9.4
0-3.8
0.9
1.4
6.7
22 - 41
Methanol
0-1.1
0-0.2
1.0
2.6
0.06
0 - 2.0
0 - 0.8
—
1.5
1.8
7.0 - 11
Rates
Mobil-M
0 - 2.1
0 - 0.3
1.8
4.8
0.1
0 - 4.3
0 - 0.5
—
2.8
3.2
13 - 20
Uncontrolled emission factors for each pump seal and compressor seal.
-------
Section 4
Gaseous Medium
Fugitive VOC
Process Sources
indirect liquefaction plants (compare Table 3-47). These estimates were based
on a detection level of 10,000 ppm, weekly inspections of light liquid pump
seals, monthly inspections of all other equipment, and sealing of open-ended
values with a caplug or another valve.
Both capital investment and annualized costs are approximately $41,0000
for methanol synthesis which correspond to less than 0.01% and 0.02% of the
respective base plant costs. Additional cost data are presented in Table
4-27.
The second approach goes a step beyond the first in that it relies on
equipment specification in addition to leak detection, repair, and mainte-
nance. Monitoring requirements are similar to those for the first approach,
except in cases where equipment specification eliminates the need for monitor-
ing. Typical equipment specifications can consist of caps for open-ended
valves, rupture disks on gas service relief valves, and double mechanical
seals with a seal oil flushing system on pumps. In addition, compressor seal
areas and degassing vents from seal oil reservoirs, or both, can be connected
to a control device with a closed vent system. As a result of these equipment
specifications, fugitive emissions from pumps, safety/relief valves, compres-
sors, and sampling connections can be completely controlled.
Application of these equipment specifications can reduce emissions by
approximately 80% (See Control Technology Appendices for details) as shown in
Table 4-26. As can be seen from Table 4-27, equipment specification costs are
higher than that for inspection and repair. Capital investment costs are
about 13 times greater and net annualized costs between 5 and 6 times greater
with an additional 35 to 40% reduction in emissions.
284
-------
TABLE 4-27. CAPITAL AND ANNUALIZED COSTS FOR FUGITIVE VOLATILE ORGANIC COMPOUND EMISSION CONTROLS
00
Estimated Control
Control Technique
Fischer-Tropsch Cases
Inspection/Repair
Equipment Specifications
Methanol Cases
Inspection/Repair
Equipment Specifications
Mobile M Cases
Inspection/Repair
Equipment Specifications
Total
Capital
145
2140
41
526
70
916
Total Annual
Operating
106
197
34
52
21
(92)C
Total
Annual ized
132
851
42
205
34
197
Costs
Percent
Capital
0.02
0.26
<0.01
0.06
<0.01
0.11
of Base Plant Costs
Total Annual ized
0.07
0.43
0.02
0.10
0.02
0.10
Costs are thousands of first quarter 1980 dollars.
Includes credit for recovered products.
'Net credit.
-------
Section 4
Gaseous Medium
Integrated Examples
4.1.8 Air Pollution Control in Integrated Facilities
Processes for the control of specific air pollutants and specific streams
have been examined in Sections 4.1.1 through 4.1.7. However, the overall
effectiveness and costs of control cannot be assessed without an examination
of integrated systems for management of gaseous waste streams. In this sec-
tion, examples of sequential and combined control of waste streams are evalua-
ted from the standpoint of the overall emissions reductions achieved and costs
incurred. The selection of specific control examples for evaluation in this
section is not intended to imply that other technologies could not provide
equivalent or better performance with similar or even lower costs. Specific
technologies are selected to cover the types of alternatives which have actu-
ally been proposed for facilities in the U.S. (63). Selection of integrated
controls will be based upon specific design requirements and local conditions
and can only be made by designers and permitting authorities involved in a
specific project.
For evaluation of control alternatives of reduced sulfur compounds, vola-
tile organic compounds (VOC), and CO, only the methanol synthesis cases with
low sulfur (Dunn lignite) and high sulfur (Illinois No. 6) coals were exam-
ined. The F-T, Mobil M-gasoline, and SNG cases generally do not present new
control options, but rather only small changes in the absolute volumes of
gaseous waste streams (and hence absolute control costs). The two selected
coal cases are sufficient to provide some insight into the impact of coal on
control choices and on the cost and performance of integrated controls.
4.1.8.1 Example 1 - High Sulfur Coal/Selective Rectisol
Fundamental to the design of a Lurgi gasification plant is the mode of
Rectisol operation. Although Rectisol units can be designed for selective
operation with feed gases from coals having any level of sulfur, the economics
286
-------
Section 4
Gaseous Medium
Integrated Examples
are dramatically affected by coal sulfur level. Generally, selective Rectisol
would become more economical in an integrated facility as the coal sulfur
level increases, since it is the ratio of H^S to CO, which determines cost
in selective acid gas removal. C0a loading is only modestly dependent upon
coal type, while HaS loading is almost directly proportional to coal sulfur
content.
Implicit in the choice of selective Rectisol is the use of Claus technol-
ogy for bulk sulfur removal. Depending on the coal sulfur level and mode
chosen for Claus operation (split flow vs. straight through; oxygen vs. air),
hydrocarbon removal and/or HaS enrichment using ami lie processes may be fea-
tured. As coal sulfur content increases, the sulfur level in the H^S-rich
fraction also increases while hydrocarbon levels remain essentially constant.
With high sulfur coals and/or the use of oxygen in the Claus process, no H,S
enrichment or hydrocarbon removal may be necessary in order to process the
waste gas in a "straight through" Claus unit.
Claus tail gases and amine offgases are treated using either
incineration/SOa removal processes (Wellman-Lord) or catalytic processes
(Beavon or SCOT). From the standpoint of overall sulfur emissions reduction,
these processes are nearly equivalent. SCOT and Beavon tail gases may be
incinerated for VOC and CO control. The smaller volume, sulfur containing
waste gases from gas liquor separation and ammonia stripping/recovery are com-
bined with HaS-rich Rectisol (or amine) acid gases for amine processing.
The small volume waste gases could alternatively be handled directly in Claus
tail gas units, depending on the sulfur loading of the gases.
Figure 4-3 depicts the Example 1 flow scheme. Amine enrichment/
hydrocarbon removal is included in this integrated example since the H^S con-
tent of selective Rectisol acid gases is only 8% (this value is based upon
data from a specific selective Rectisol plant at Kosovo). This value of 8% is
287
-------
so,
WELLMAN-LORD
t
KJ
00
OO
SYNTHESIS
GAS
A CO2 RICH
OFFGAS
H2SRICH
QUENCHED SELECTIVE uAi>
LURGI GAS * RECTISOL 1 1
OVEI
DECOMPRESSION * NH3 RECOVEf
GASFS
1 1
STR
WASTEWATER » NH3 STRIPPE
(
„ s
AMINc ^
*HEAD /
He '
,Y RICH
GAS
IPPING GASES
SI
R ^WAE
HC RICH
-------
Section 4
Gaseous Medium
Integrated Examples
believed to be very low relative to what can actually be obtained with modern
selective Rectisol designs. Tables 4-28 through 4-31 present calculated mass
flow data for Example 1. Over 99.5% control of potential sulfur emissions is
achieved, which corresponds to emissions of 15 to 30 kg/hr sulfur in the form
of SO,. Over 99% control of both VOC and CO are also achieved corresponding
to 20 kg/hr VOC and 60 kg/hr CO emissions to the atmosphere.
Estimated costs for the Example 1 controls are summarized in Table 4-32.
These estimates indicate that amine enrichment can be an imporatnt cost factor
in integrated control. Also, the relatively large contribution of tail gas
treatment costs compared to Claus cost reflects the fact that amine offgases
as well as Claus tail gases are handled by the tail gas treatment units. Only
small differences in costs are seen in the estimates for SCOT and Beavon pro-
cesses as might be expected for competing processes achieving similar control
levels. Wellman-Lord is calculated to be more expensive than the catalytic
processes. The three tail gas treatment processes have different impacts on
the size and cost of the parent Claus plant. In the Beavon case, no recycle
occurs so that the Claus unit is unaffected. In the SCOT case, H2S is recy-
cled so that the Claus plant has a 20% increase in sulfur load and a 50% in-
crease in input flow. In the Wellman-Lord (W-L) case, S0a amounting to
about 20% of the Claus feed is recycled, but unlike the SCOT case the feed gas
flow is not greatly increased since no CO, recycles with the sulfur. Also
compared to the SCOT case, Claus tail gas volume in the W-L case is not
greatly increased since recycle of sulfur as SO, rather than H,S reduces
air requirements for the Clans plant. The Claus costs in Table 4-32 partially
reflect the impact of these flow differences. A more detailed cost evalua-
tion, would probably show total annualized costs of integrated Claus/W-L to be
even closer to those of Claus/SCOT/incineration. In Example 1, 3.7 to 4.9% of
the base plant capital cost and 2.7 to 3.4% of the base plant annualized costs
are represented for the integrated control of Rectisol acid gases and smaller
volume gases.
289
-------
TABLE 4-28. MATERIAL FLOW FOR EXAMPLE 1 INTEGRATED CONTROL -
AMINE ENRICHMENT OF RECTISOL AND STRIPPER OVERHEAD GASES
a,b
Selective
COa-Rich
Rectisol Gases
Ha
Na+Ar
CO
CO a
CH4
Aliphatics
Aromatics
HaS
VD
<=> COS
Mercaptans
HCN
Nil,
CHjOH
Total Dry Gas
HaO
37
0.8
5
4196
14
88
0.014
0.07
0.3
0.04
0.02
4.3
4345
0
HaS-Rich
Rectisol Gases
4
6
68
1655
26
55
0.21
174.7
1.9
17.5
0.19
8.5
2017
0
NHa Stripper
Overhead
2.2
253
7.3
0.7
6.5
0.023
1.24
0.35
0.7
272
114
Combined
Acid Gas
4
6
70.2
1908
33.3
56
0.21
181.2
1.92
18.7
0.54
0.7
8.5
2289
114
Amine
HC-Rich
4
6
70.2
1703
30.1
55.3
0.21
1.05
1.69
18.7
0.003
0.7
8.5
1899
91
Gases
HaS-Rich
Claus Feed
205
3.17
0.65
180.14
0.23
0.54
390
23
Methanol synthesis from Illinois #6 coal, selective Rectisol.
Units are kmol/hr.
-------
TABLE 4-29. MATERIAL FLOW FOB EXAMPLE 1 INTEGRATED CONTROL - SCOT TAIL GAS TREATMENT
,a.b
vO
Clana Feed Gaa
(Includes
Recycle)
H,
Os
Ni+Ar
CO
CO. 410
CH4 6.3
Aliphatica 1.5
Aronttics
HiS 215
COS 0.23
CS.
SO,
Mercaptana
BCN 0.54
NBt
CHiOB
Total Dry Gat 633
BiO 36
Elenental Sol far
Clans Clana
Air Tail Gaa
113
423 423
412
4.2
0.98
6.5
0.97
0.05
3.2
0.36
536 851
250
4e
Clana Tail +
Aaine flC-Rich SCOT Gatet SCOT Incinerated SCOT Snlfnr
Gatea Recycle Gaa Tail Gatc Condentate Tail Gaa Recovered
4 284
56
429 784 2050
70.2 277 1.3
2115 205 1910 2186
34.3 3.1
56.3 0.8 0.4
0.21
7.4 3J 0.65 <0.1
2.8 0.16
0.05
3.2 0.64
18.7
0.36
0.7 0.1 1.0
8.5 8.5
2750 244 3264 4295
341 13 140 218 424
4* 200
.Methanol synthesis fro> Illinois #6 caae, selective Reatiaol, aaine enriched.
Unit* are kaol/hr.
^Excludes air (449 kjool/hr) added to partially oxidized hydrocarbons.
20% exceaa air, no additional fuel for incineration as sued.
Entrained anlfnr in Clana tail |as.
-------
TABLE 4-30. MATERIAL FLOW FOR EXAMPLE 1 INTEGRATED CONTROL - BEAVON TAIL GAS TREATMENT
a.b
Glaus
Feed
Hi
Oi
N.+Ar
CO
COi 205
CH4 3.17
Aliphatict 0.65
Aroaatica
HiS 180.14
COS 0 .23
CSi
SOi
NJ
v£> Mexcaptana
NJ
HCN 0.54
NH,
CHiOB
Total Dry Gat 390
HiO 23
Sal far
Claui Claus
Air Tail Gai
93
348 348
206
2.11
0.42
5.41
0.81
0.05
2.71
0.36
441 566
200
4*
Claus Tail Gas
+ Anine
HC-Bich Gaa
4
354
70.2
1909
32.24
55.7
0.21
6.46
2.50
0.05
2.71
18.7
0.36
0.7
8.5
2465
291
4°
Beavon Sulfur Incinerated
Tail Gasc Recovered Tail Gas Beavon Condensate
329
63
763 2192
304 1 .4
1909 2213
0.5
0.03 <0.1
0.23
0
0 0.25
0
0.1 1.06
3306 4469
114 443 177
201f
Methanol synthesis from Illinois §6 coal, selective Rectisol, aaiine enriched.
Units are baol/hr.
^Excludes air (518 kaol/hr) added to partially oxidized hydrocarbons.
20% excess air.
"Sulfur entrained in Claus tail (as as S.
as S.
-------
TABLE 4-31. MATERIAL FLOW FOR EXAMPLE 1 INTEGRATED CONTROL - WELLMAN-LORD TAIL GAS TREATMENT*>b
Clans Feed (with
Recycle SO,)
H,
0,
Ni+Ar
CO
CO. 205
CH4 3.17
Aliphatics 0.65
Aromatics
H,S 180.14
COS 0.23
CSi
SO, 32
N5
vo Mercaptans
HCN 0.54
NH,
CH,OH
Total Dry Gas 422
HsO 25
Sulfur
Clans
Claus Air Tail Gas
60
225 225
205
2.49
0.5
6.37
0.95
0.05
3.18
0.42
284 444
201
2d
Clans Tail Gas Auxiliary f el loan-Lord Sulfur
+ Aaine HC-Rich Gas Air° Recycle SO, Tail Gas Recovered
4
555 111
231 2090 2321
70.2 1.3
1908 2211
32.6
55.8 0.46
0.21
7.42
2.64
0.05
3.18 32 0.69
18.7
0.42
0.7
8.5
2343 2645 32 4645
292 413
2d 200e
bMethanol synthetic fro* Illinois 96 coal, (elective Rectisol-uine enriched.
Unit* are bnol/hr.
.20% excess air.
Entrained and vaporous sulfur as S.
as S.
-------
TABLE 4-32. COSTS ASSOCIATED WITH EXAMPLE 1 INTEGRATED CONTROL
M
Case la
Beavon/Stratford
Capital Operating
Hydrocarbon 10.5 1.17
Removal /Sulfur
Enrichment
(Amine)
Bulk Sulfur 7.10 (0.72)
Removal (Claus)
Tail Gas Treatment 11.9 1.92
(Residual Sulfur)
Tail Gas Treatment 1.00 (1.18)
(VOC, CO, and
Reduced Sulfur)
TOTAL 30.5 1.19
Total Annual ized Costs 6.44
Percent of Base Plant Costs
Capital 3.71
Annual ized 2.68
Case Ib Case Ic
SCOT Wellman-Lord (W-L)
Capital Operating Capital Operating
10.5 1.17 10.5 1.17
>
8.6b (0.87) 7.8b (0.79)
11.8 1.63 21.7 0.21
1.00 (0.82) 0C 0C
31.9 1.11 40.0 0.59
6.60 7.47
3.89 4.88
2.75 4.95
Costs are millions of first quarter 1980 dollars.
Claus cost differences result from sulfur load and quantity of SCOT and W-L recycles to the
parent Claus plant.
No incremental costs for control of reduced species occur in W-L since incineration is implicit
in W-L.
-------
Section 4
Gaseous Medium
Integrated Examples
It should be noted that some portion of Rectisol costs in the selec-
tive mode might be assigned to pollution control. Data are not available
relating to such costs, so it is not possible to estimate the specific incre-
mental Rectisol contribution. The inclusion of costs for amine enrichment/
hydrocarbon removal in Example 1 serves to indicate the magnitude of costs
likely to be associated with generating high H,S, low VOC Glaus feed gases.
In an integrated design there will always be a tradeoff between costs of en-
richment within Rectisol, costs of enrichment with an amine system following
Rectisol, and costs of larger or smaller Glaus and tail gas treatment units.
In Example 1, HaS-rich Rectisol acid gases are enriched to about 40%
H2S, and organics have been largely removed from Glaus feed. With lower
sulfur coals it would be more difficult to achieve such a high H2S level.
For straight through Glaus mode, 35 to 40% H2S is probably the lowest H^S
level consistent with stable combustion; below this level split flow mode or
oxygen (or enriched air) firing would be necessary for flame stability. With
the split flow mode, where only one-third of the Clans feed is burned, any
hydrocarbon and mercaptans in the feed would lead to coke deposits on the
Glaus catalyst and to "grey" sulfur. Thus either the organics must be removed
from the Glaus feed or oxygen used instead of air allowing straight through
operation with lower HaS levels. There is an economic tradeoff between
Glaus plant capital costs vs. oxygen use costs which tends to become more
important as HaS levels in Glaus feed decrease. Further, since oxygen use
also reduces tail gas treatment capital costs, and since organics limit the
use of split-flow Glaus below about 35% H^S, oxygen or enriched air offers
several potential advantages. Rough calculations based on oxygen at $50/Mg
and the Clans and TGT costs in Table 4-32 suggest that for H2S-rich Rectisol
acid gases having 20% or less HaS, oxygen-fired Glaus would be cost competi-
tive with amine enrichment/organics removal plus air-fired Glaus when incre-
mental TGT costs are included. Although Clans units are not ordinarily fired
295
-------
Section 4
Gaseous Medium
Integrated Examples
with oxygen in existing applications, such Claus designs are considered com-
mercially available and present no new developmental problems. The lack of
existing oxygen fired units merely reflects the relative economics, especially
when a dedicated oxygen plant would be required. In coal gasification facili-
ties a large oxygen plant would already exist, and the incremental costs for
producing additional oxygen or enriched air are small (about 2 to 7% addi-
tional oxygen production capacity would be needed, depending primarily on the
coal sulfur content).
4.1.8.2 Example 2 - Low Sulfur Coal/Nonselective Rectisol
Most existing Lurgi gasification plants overseas as well as proposed
Lurgi plants for the U.S. feature nonselective Rectisol acid gas removal.
Example 2 is based upon this mode of Rectisol operation and includes H^S
removal by the Stretford process. Depressurization and stripping gases are
combined with Rectisol gases for treatment in the Stretford unit. Stretford
tail gases are incinerated with heat recovery for conversion of reduced sulfur
species to SOZ and oxidation of VOC and CO. Figure 4-4 depicts the flow
scheme for Example 2.
The nonselective Rectisol/Stretford approach is generally most attractive
for lower sulfur coals since the generation of acid gases with H^S contents
sufficient for economical Claus processing becomes more expensive as coal sul-
fur level decreases. The Stretford process removes only H2S sulfur and
hence COS and mercaptans contained in the Rectisol acid gases will be present
in the Stretford tail and/or oxidizer vent gases. Since non-HjS sulfur in
Rectisol acid gases increases as coal sulfur increases, total sulfur in
Stretford tail gases will increase with feed coal sulfur content.
296
-------
QUENCHED T
LURGI GAS V
DECOMPRESSION,
GASES * ^
WASTEWATER ^ »
GAS
NONSELECTIVE
RECTISOL
NH3 RECOVERY
I3TRIPPE
GASES
NH3 STRIPPER
INCINERATED
GAS ' I "
AP.in nYini7PH
GAS » STRETFORD VENT»
i i
SULFUR AIR
SOLVENT
PURGE
D
^ STRIPPED
^ WASTEWATER
Figure 4-4. Schematic flow diagram for example 2
297
-------
Section 4
Gaseous Medium
Integrated Examples
Table 4-33 presents calculated mass flows for Example 2. Stretford ab-
sorber vent gases contain about 1400 ppmv total sulfur and 2% VOC. Incinera-
tion of Stretford tail gases converts the COS and mercaptans to S0a and
destroys most organics and CO. Since the tail gases represent a significant
amount of energy, heat recovery is an attractive alternative. If a captive
incinerator is used, heat exchange/steam generation could be an integral part
of the design. Stretford gases can also be incinerated in boilers or steam
superheaters, so that the energy value is recovered within those units. From
the standpoint of control of reduced sulfur species, CO, and VOC, any of the
incineration options are expected to achieve similar results.
Some of the mercaptans and ammonia contained in the Stretford feed gas
may be found in the oxidizer vent gas. For control of these species, the vent
gas can be used as supplemental combustion air for incineration of the ab-
sorber vent gases or for the boiler. Sufficient data are not currently avail-
able to indicate whether appreciable amounts of these species will be emitted
in the Stretford oxidizer.
Table 4-34 summarizes the costs associated with Example 2 for a low sul-
fur coal. Specific costs attributable to incineration of Stretford tail gas
can vary somewhat, depending on the extent of heat recovery and the dollar
value of steam or direct heat assumed. In the table, the incremental costs of
downrating a boiler which fires relatively low heating value Stretford tail
gases are assigned to pollution control. A somewhat larger boiler incurs a
slightly higher capital cost, while the recovered energy reduces operating
costs by displacing overall fuel to the plant. A captive incinerator with 35%
heat recovery appears to be about as cost effective for pollution control as a
slightly larger boiler with 80% heat recovery.
298
-------
TABLE 4-33. MATERIAL FLOW FOR EXAMPLE 2 INTEGRATED CONTROL - STRETFORD/ INCINERATION
a,b
Acid Gas from
Nonseleotive NBi Stripper Combined
Rectisol Overhead Gas Acid Gas
Ha
0,
Na+Ar
CO
COi
CH4
Aliphatic*
Aromatic*
HaS
COS
SO,
Hercaptans
HCN
NH.
CB.OB
Total Dry
H,0
Sulfur
25
4
43
6274
54
123
0.7
74.3
0.64
7.2
0.10
0.18
8.6
Gas 6615
40
1.6
210
5.3
2.4
l.T
2.1
0.017
0.84
0.39
0.39
225
191
*SNG from Dunn lignite nonseleotiv* Reotisol.
Units are kmol/hr.
20% ezcess oxygen, including ozidizer vent.
25
4
44.6
6484
59.3
125
2.4
76.4
0.66
8.0
0.49
O.S7
8.6
6839
231
No supplemental
Stretford Stretford
Absorber Vent Ozidizer Vent
25
138
4 78.2
44.6
6397 87
59.3
125
2.4
0.67
0.66
8.0 trace
trace
0.57
8.6
6676 1008
332 SO
fuel assumed.
Air Total Ozidized
Sulfur Required Off gases
749 148
2818 3604
3.2
6934
1.1
9.37
<0.01
3567 10700
75.7d 71 97«
-------
TABLE 4-34. COSTS ASSOCIATED WITH EXAMPLE 2 CONTROL*
o
o
Gat Transport
Capital
Annual Operating
Stretford
Capital
Annual Operating
Incineration
Capital
Annual Operating
FCP
Capital
Annual Operating
Energy Penalty
Total Capital
Total Annual Operating
Total Annual ized
Percent of Base Plant Costa
Capital
Total Annual ized
Absorber Vent
HaS Control Only
—
—
14.9
2.6
—
—
—
—
14.9
2.6
5.16
1.82
2.40
Absorber Vent
Absorber Vent VOC and CO Control VOC. CO, and SO. Control
Captive Incinerator
—
—
14.9
2.6
2.3
0.39
—
—
(0.54)b
17.2
2.45
5.41
2.10
2.52
Use in Boiler
0.80
0.10
14.9
2.6
2.6
0.01
—
—
(4.4)
41.7
(1.7)
5.47
5.09
2.54
Boiler + FGD
0.80
0.10
14.9
2.6
2.5
0.01
19
4.5
(4,4.)
60.7
2.7
13.1
7.40
6.09
Ozidizer Vent
Incineration
in Boiler
0.22
0.01
—
~~
1.97
0.02
—
—
0.06
2.19
0.08
0.46
0.27
0.21
'Costs are Billions of first quarter 1980 dollars.
( ) indicates a credit.
-------
Section 4
Gaseous Medium
Integrated Examples
In principle, Stretford tail gases could be treated for removal of addi-
tional sulfur, using the Beavon or FGD technologies. Technologies such as
SCOT and Wellman-Lord are not applicable since they require Claus (or Clans
type) plants to handle the produced HaS (or S0a). Since the economic and
technical attractiveness of nonselective Rectisol/Stretford increases as coal
sulfur contents decrease, Stretford tail gas would probably not exceed 1400
ppmv total S (the non-HaS sulfur emissions in Example 2 have been taken as a
worst case). While Beavon and FGD processes can handle such relatively dilute
sulfur gases, their costs become very high, relative to the degree of further
control achieved.
When Stretford tail gases are incinerated in boiler systems, the possi-
bility does exist for combined S0a removal from boiler flue gases and incin-
erated Stretford tail gases. However, high incremental costs for FGD, com-
pared to incineration only, are indicated by the calculations in Table 4-34.
Further, captive boiler units in facilities gasifying the low sulfur coals
most suited to Stretford acid gas treatment may not have FGD units, and hence
the combined treatment option may not exist. Finally, the choice of nonselec-
tive Rectisol/Stretford/incineration versus selective Rectisol/Claus/tail gas
treatment is primarily based on economics and an assessment of the overall
reliability of the integrated system. If Stretford incineration alone cannot
achieve sulfur levels consistent with source or ambient pollution control
needs, it is likely that designers would opt for the selective Rectisol/
Clans/TGT approach rather than add technologies such as Beavon or captive FGD
to a basic Stretford unit.
The Beavon catalytic reactor was examined to assess whether it could pre-
cede the basic Stretford unit in an integrated facility, converting non-HaS
sulfur to HaS and allowing very high levels of total sulfur removal. Such
an arrangement is not feasible, however, since the catalyst performance is
determined by the thermodynamics of the process which limits the degree of COS
conversion at fixed C0a and HaS levels. Without prior HaS removal, a
301
-------
Section 4
Gaseous Medium
Integrated Examples
catalytic reactor might actually produce COS when C0a levels are in the 90%
range. It is possible that most mercaptans would be hydrogenated over the
catalyst, but total non-HaS sulfur may not be greatly affected. Hence,
catalytic conversion preceding Stretford is not likely to be a viable approach
to reducing non-H2S emissions in the subject facilities.
In Example 2, Stretford oxidizer vent gas is used as combustion air to an
onsite boiler. The calculations in Table 4-34 indicate that costs for such
an approach are in the same range as costs for incineration of absorber vent
gases. Since the amounts of sulfur compounds and ammonia present in the
oxidizer vent gases are not known, the cost effectiveness of control is impos-
sible to evaluate.
4.1.8.3 Example 3 - Incineration of Waste Gases in Utility Boilers
Several gaseous streams in an integrated Lurgi-based facility contain
organics and/or reduced sulfur and nitrogen species controllable by incinera-
tion. The energy value of many of these gases has drawn attention to heat
recovery as part of the combustion step. Heat recovery is a common practice
with gas incinerators; however, only minimal efficiency is attained when waste
gases are burned in large boilers fired by coal, coal liquids, or fuel gases
(over 85% recovery of LHV enthalpy of combustion is common in industrial
boilers). Recovered heat partly offsets conventional fuel requirements to the
plant, but increased capital cost are usually incurred. If a waste gas must
be incinerated, there is always an economic tradeoff between capital cost of
heat recovery equipment and the value of the energy recovered.
Figure 4-5 depicts integrated use of plant boiler/superheater system(s)
to incinerate waste gases. High-pressure lock gases and startup transient
gases have sufficient heating value to be considered fuels in their own right.
For the intermittent waste gases, some storage would be necessary to lessen
302
-------
HIGH PRESSURE
LOCK GAS
FLUE GAS TO
ATMOSPHERE
TRANSIENT
WASTE GASES
AIR
LURGIGASIFIER
LOCK HEADER
SYSTEM
GAS
HOLDER
DILUTED LOW
PRESSURE
LOCK VENT GAS
OJ
o
CO
RECTISOL
ACID
GASES
STRETFORD
SULFER
RECOVERY
AIR
ABSORBER
TAIL GAS
OXIDIZER
VENT
GAS
(a)1
ESP
FGD
FLUE GAS TO
ATMOSPHERE
COMBUS-
TION
AIR
A
BOILER
AND
STEAM
SUPER-
HEATER
SYSTEMS
MOBIL M
CATALYST
REGENERATION
OFF GAS
SYNTHESIS
OFF GASES
COAL
AIR
ALTERNATIVE ROUTES FOR
BOILER FLUE GAS
Figure 4-5. Example 3. - integrated control
-------
Section 4
Gaseous Medium
Integrated Examples
surges and match production rates with boiler needs. Continuous, low heating
value gases such as Stretford absorber vent gases may be difficult to incine-
rate alone due to flame stability problems, but they contain enough combusti-
ble components to justify their incineration in larger steam generation units.
Low-pressure (residual) coal lockhopper gases also have energy value but
may contain ejection air. Such waste gases can supplement combustion air to
large fuel using systems. Since dilution of lockhopper gases with at least
30/1 air would constitute prudent practice from an explosion hazard stand-
point, combustion systems could draw a continuous air flow from the gasifier
lock header system, thus diluting the gas to below explosive limits and
achieving control when the diluted components pass through the combustion pro-
cess. Since very little heating value is represented by the low pressure
lockhopper gases, heat recovery is not a significant factor relative to the
capital and operating costs of the collection and transport system.
Stretford oxidizer vent gases may contain low levels of odorous species
and thus incineration is a likely alternative for odor control. The vent gas
contains oxygen and could displace combustion air to the boiler. However,
the lower Ot content relative to air translates into an energy penalty in
the boiler system. As with lock vent gas, collection/transport system costs
will also be incurred.
The intermittent Mobil M-catalyst regeneration offgas may contain hydro-
carbons and CO which could be controlled by incineration. Such gases could be
incinerated in boiler systems rather than in a captive incinerator which would
only operate intermittently.
The use of the boiler as an incinerator also offers the additional possi-
bility of particulate and S02 control. When units such as ESPs and FGDs are
304
-------
Section 4
Gaseous Medium
Integrated Examples
captive to coal fired boilers, any waste gases incinerated in the boilers will
pass through these units. Whether significant levels of dust and S0a removal
are realized depends on the amounts of these constituents in the waste gas.
Since ESPs and FGDs incur costs roughly proportional to flow rates, any waste
gas producing more flue gas during combustion than an equivalent amount of
coal (or other high grade fuel) on a heating value basis will necessitate
larger pollution control units and capital costs.
The extent of overall control achieved with Example 3 is difficult to
estimate. Generally, hydrocarbon and carbon monoxide levels in boiler flue
gases are below 100 ppmv and 300 ppmv, respectively, but exact levels can vary
widely. Such levels would correspond to over 90% control for all streams in
Example 3, and over 99% control for high-pressure lockhopper gases and transi-
ent waste gases. If ESP/FGD systems are captive to the boiler, up to 90% con-
trol of potential S0a emissions could also be realized with boiler incinera-
tion. Since inorganic particulate is not a concern with the subject waste
gases, the ESP does not serve a special purpose in Example 3, but rather is
merely integral to coal fired boilers.
The estimated costs associated with Example 3 controls are summarized in
Table 4-35. Since all of the subject gases except the intermittent Mobil M-
catalyst regeneration offgases and the Stretford oxidizer vent gases contain
combustibles (organics, CO, and Ha) of over 2% by volume, energy credits via
heat recovery in the boiler are realized. Larger boiler and ESP/FGD systems
are required, however, relative to coal-fired units having the same duty.
Thus, an incremental capital cost is associated with use of the boiler as an
incinerator. Additional capital and operating costs results from piping,
fans, gas holding, and other handling/transport equipment.
305
-------
TABLE 4-35. COSTS ASSOCIATED WITH EXAMPLE 3 INTEGRATED CONTROL
Estimated Control Costs
Control Technique
H.P. Lock Gas
VOC + CO Control
S04 Control
L.P. Lock Gas
VOC + CO Control
S0a Control
Stretford Absorber Vent
VOC + CO Control
SO, Control
Stretford Ozidizer Vent
VOC + CO Control
S0a Control
Mobil M-Catalyst Regeneration
VOC + CO Control
Transient Waste Gas
VOC + CO Control
S0a Control
Total
Capital
2.01
3.14
0.29
0.31
26.8
45.8
1.97
3.42
0.4
10.2
17.3
Total Annual
Operating
(3.35)b
(3.28)
(0.024)
(0.024)
(4.3)
0.2
0.08
0.42
0.02
0.002
1.3
Total
Annual ized
(3.0)
(2.7)
0.026
0.029
0.3
8.1
0.42
1.01
0.09
1.76
4.27
Percent
Capital
0.25
0.38
0.03
0.03
3.3
5.6
0.24
0.41
0.04
1.2
2.1
of Base Plant Costs
Total Annual ized
Neg.
Neg.
0.01
0.01
0.14
3.8
0.19
0.47
0.04
0.88
2.1
*Costs are millions of first quarter 1980 dollars.
( ) indicates a net credit.
Neg. = Negative value.
-------
Section 4
Gaseous Medium
Integrated Examples
The calculations in Table 4-35 indicate that the dollar value of the
energy recovered from high-pressure lock gases can more than offset the
capital costs incurred with use of such gases as supplemental boiler fuel,
even when S0a removal costs are included. For low-pressure lock gas there is
a small energy penalty, and incremental capital costs are large relative to
the pollutant loading. For transient gases, a relatively large annualized
cost occurs with boiler incineration, since only a small annual energy
recovery is realized for this intermittent stream and since oversizing of
transport and boiler systems must be based on maximum flow rates.
The Stretford absorber vent gases contain sufficient energy value that
capital costs associated with boiler incineration are nearly offset by re-
covered energy. When S0a removal is added, a relatively large capital
increment is incurred, so that overall costs for incineration plus S02 removal
are high relative to the amount of sulfur removal. When the Stretford oxi-
dizer vent gas is substituted for air in the boiler system, both a capital
cost and an energy penalty result since the inert portion of the vent gas
(which is larger than that of air) must be carried through the boiler system.
307
-------
Section 4
Aqueous Medium
4.2 AQUEOUS MEDIUM
This section discusses the control of wastewaters produced by Lurgi-based
synfnels plants. Information presented includes:
• a summary of the waste stream characteristics and flow rates
(from Section 3),
• a general discussion of the wastewater treatment processes
which are potentially applicable,
• illustrative examples of the application of individual control
processes to specific streams, and
• examples of the sequential application of several control
processes for the treatment and ultimate disposal of specific
streams or combinations of streams.
The main emphasis in Section 4.2 is on control measures for wastewater streams
which are unique to Lnrgi-based synfuels plants. Since the treatment and
reuse/disposal of gas liquor is the primary wastewater treatment challenge for
Lurgi-based synfuels plants, this section concentrates on that stream. Treat-
ment techniques for wastewater streams which are not unique to Lurgi-based
synfuels plants (such as coal pile runoff) are not discussed in depth in this
manual. Standard treatment methods for these non-unique streams have been de-
veloped in existing U.S. industries, and these methods should generally be
applicable to the non-unique streams generated in Lurgi-based synfuels plants.
A key concept in this discussion of the control of wastewaters from Lurgi-
based synfuels plants is the classification of these wastewaters into two
source types:
• streams containing primarily organic compounds and
• streams containing primarily inorganic compounds.
308
-------
Section 4
Aqueous Medium
The use of these source types and the organization of the individual stream
control technology presentations by source types allow the grouping of streams
with similar characteristics and potentially applicable controls. Secondary
wastewater streams produced by pollution controls for gaseous or solid waste
streams are also discussed in this section within their applicable source
types. Controls for aqueous waste streams produced by water pollution con-
trols are discussed along with the discussions of the control processes that
generate them. Controls for secondary gaseous and solid wastes are discussed
in their media sections (Sections 4.1 and 4.3), respectively.
Much of the characterization data for wastewaters which are unique to
Lurgi-based synfuels plants is based on data from full-scale synfuels plants.
Some of the potential Lurgi wastewater streams, however, have not been tested,
and therefore, the characterizations given here and in Section 3 for those
streams are estimates based on the available information. In contrast, most
of the wastewater treatment processes discussed in this section have not been
used to treat Lnrgi wastewaters. Therefore, many of the performance and cost
estimates given in this manual are based on extrapolations of existing data
from related industries. Section 5 summarizes the gaps and limitations of the
data base used to develop this manual.
Table 4-36 gives a summary of the wastewater streams which could be gen-
erated by Lurgi-based synfuels plants. This table also gives estimated flow
rates for the plant configurations and sizes discussed in Section 3. Pollu-
tants of potential concern and factors affecting stream characteristics are
also given.
The rest of this section presents general information on the water pollu-
tion control processes which could potentially be applied to the two waste-
water source types described above (Section 4.2.1), and examples of
309
-------
TABLE 4-36. SUMMARY OF UNCONTROLLED AQUEOUS HASTE STREAMS GENERATED IN LURGI-BASED SYNFUELS FACILITIES
Stream
(Stream No.)
Pollutants
of Potential Concern
Factors
Affecting Effluent Synthesis
Stream Characteristics Process
Wastewater Stream Flows (m'/hr)
Coal Feedstock
Rosebud
Illinois
No. 6
Dunn
Lignite
Waste Streams From Main Process Train
Gas Liquor
(210)
Rectisol
condensate/still
bottoms from
acid gas removal
(AGR) system
(216)
Suspended solids (coal dust),
dissolved inorganics, (NH,, acid
gases, trace metals), suspended
tars/oils, and dissolved organics
(phenols, organic acids, other
water-soluble organics)
Dissolved organics and inorganics
including acid gases, blowdown
solvent and solvent degradation
products
Feed coal properties,
gasifier and gas cool-
ing section operating
conditions
The AGR process used
and its operating
characteristics, pro-
perties of the inlet
raw gas (e.g., flow,
temperature, moisture
content)
Indirect
Liquefaction
SNG
All
293
281
10
495
476
12
433
418
10
Methanation (228)
and COj removal
condensates (238)
Synthesis process
wastewaters:
Methanol (237);
Fischer-Tropsch
(219); Mobil (225)
Gasifier ash
quench blowdown
(404)
Raw coal storage
runoff (201)
Negligible quantities of
dissolved gases (e.g., CO,)
Dissolved organics (alcohols,
organics acids, other hydro-
carbons)
Suspended solids, pH, inorganics
leached from the ash and inlet
ash quench water components
Suspended solids (coal fines)
and inorganics leached from the
coal
Synthesis process purge
gas characteristics
Synthesis section
operating conditions
and feed gas properties
Source of quench water
and ash characteristics
SNG
Methanol
F-T
Mobil
Methanol
F-T
Mobil M
All
Coal type and conditions All
of wastewater contact with
coal (e.g., residence time
and temperature). Rainfall
rates, coal storage, and
washing practices.
54
21
19
21
5
76
55
56
8
20
8
1
72
58
54
15
19
15
4
72
56
No net discharge - this
stream is assumed to be
contained and recycled.
Blowdown is in the form of
water associated with the
wet ash.
0.7
1.8
1.1
(Continued)
-------
TABLE 4-36. (Continued)
Stream
(Stream No.)
Pollutants
of Potential Concern
Factors
Affecting Effluent
Stream Characteristics
Wastewater Stream Flows (m'/hr)
Coal Feedstock
Synthesis
Process
Illinois
Rosebud No. 6
Dunn
LiKnite
Waste Streams from Auiiliarv Processes
U>
Demineralizer
regeneration
wastewaters
(301)
Boiler blowdown
(303)
Cooling tower
blowdown (307)
Dissolved inorganics (e.g.,
Na , S0~), and raw water
contaminants
Dissolved inorganics (silica,
metals)
Dissolved inorganics and possibly
organics, including makeup water
components and treatment chemical
residuals
Boiler (305) and Organics, inorganics, cleaning
process equip- chemicals, and metals removed
ment (320) from equipment surfaces
cleaning wastes
Boiler bottom ash Suspended solids, pH, inorganics
quench/sluice leached from the ash and inlet
system blowdown ash quench water components
(407)
Makeup water flow and All
composition
Makeup water quality and All
boiler operating pressure
Makeup water quality and Methanol
cooling tower operating F-T
characteristics Mobil M
SNG
Waste stream source; All
plant operating, main-
tenance, and equipment
cleaning practices
Source of quench water All
and ash characteristics
45
66
92
79
66
68
66
92
79
66
50
66
92
79
66
Flow rates expected to be
highly variable, but small
compared to the above.
No net discharge - this
stream is assumed to be con-
tained and recycled. Blow-
down is the water associated
with the wet ash.
Waste Streams from Pollution Control Processes
Stretford solu- Vanadium salts, thiocyanates,
tion blowdown and thiosulfates
(416)
Beavon (240) and HaS, and NH,
SCOT (241)
condensates
Wellman-Lord
sulfate purge
(242)
Sulfites, sulfates. and
polysulfites
Coal sulfur content. All
gasifier operating condi-
tions, and Stretford unit
design and operation
Unit design and opera- All
ting conditions.
Coal sulfur content and All
Wellman-Lord unit
design
2.2
4.3
2.2
(Continued)
-------
TABLE 4-36. (Continued)
Wastewater Stream Flows (m'/hr)
Stream
(Stream No.)
Pollutants
of Potential Concern
Factors
Affecting Effluent
Stream Characteristics
Synthesis
Process
Coal Feedstock
Illinois
Rosebud No. 6
Dunn
Lignite
u>
Slowdown streams Depends on source; coal fines,
from vent gas tars, oils, dissolved organics,
scrubbers. and inorganics including acid
gases
Waste Streams from Auxiliary Processes
Plant process
drain (318)
effluent
Storm drain
(319) effluent
Any of the above
Any of the above
Vent gas and scrubber All
makeup water quality
Plant operating and All
maintenance practices
Rainfall rates. All
collection system de-
sign, and plant house-
keeping practices
Flowrates are unknown, but
expected to be small
20 to 25
14
47
18
-------
Section 4
Aqueous Medium
applications of control processes to specific streams (Sections 4.2.2 and
4.2.3). General information about the potential vastewater controls is given
in a single section (4.2.1), rather than in separate sections for each source
type. This approach has been taken to avoid repetition since many water
treatment processes are applicable to streams of both source types.
313
-------
Section 4
Aqueous Medium
Generic Control
4.2.1 Aqueous Medium Generic Controls
The water pollution control processes discussed in this manual include
techniques for:
• removal of suspended solids, tars, and oils (Section 4.2.1.1);
• removal of bulk organics (4.2.1.2);
• removal of dissolved gases (4.2.1.3);
• removal of dissolved organics (4.2.1.4);
• removal of residual organics (4.2.1.5);
• removal of dissolved inorganics (4.2.1.6);
• volume reduction (4.2.1.7); and
• residual disposal (4.2.1.8).
The information given here is derived from data on industrial applica-
tions and laboratory tests with various wastewaters. Available information is
given describing each process, its performance and factors affecting
performance, secondary wastes produced, reliability, and estimated costs on a
unit throughput basis. The water pollution control technologies discussed
here represent a wide, but not all-inclusive, range of the processes which
could be used in the treatment of wastewaters from Lurgi-based synfuels
plants. The information given in this section is specific to wastewater
streams from Lurgi-based synfuels plants. Sections 4.2.2 and 4.2.3 discuss
examples of the application of specific wastewater treatment processes to
specific wastewater streams from Lurgi-based synfuels plants.
A more detailed discussion of each control process may be found in the
PCTM Pollution Control Technology Appendices.
314
-------
Section 4
Aqueous Medium
Generic Control
Suspended Solids
4.2.1.1 Processes for Removal of Suspended Solids, Tars, and Oils
The removal of settleable solids and floating material from wastewaters
is desirable for a number of reasons. First, if downstream treatment equip-
ment is present, the removal of these contaminants helps avoid problems due to
plugging or fouling of that equipment. Second, the tars and oils may be re-
covered for their fuel or byproduct value. Third, it reduces the load on
downstream processing units and thus lowers their capital and total annu-
alized costs.
Suspended solids and free oils and tars may be removed from wastewater by
a number of different processes. The selection of a given process or series
of processes depends on a number of factors such as particle size, particle
density relative to the wastewater, settleability of the particles, miscibi-
lity of the contaminants with the wastewater, and tendency of the particles to
form colloidal suspensions.
Processes potentially applicable for the removal of suspended solids,
tars, and oils from Lurgi gasification wastewaters include screening, gravity
separation, coagulation/flocculation, air flotation, and filtration. Table
4-37 gives some summary information about these processes. Screening is gen-
erally used for removing relatively large particles. The amount of solids re-
moved depends on screen size and wastewater characteristics such as the size
distribution of suspended solids in the wastewater. Screening is often in-
cluded as a pretreatment step before other suspended solids, tars, and oil re-
moval procedures. The rest of this section (Section 4.2.1.1) summarizes
available information for the remaining processes listed above.
315
-------
TABLE 4-37.
TECHNOLOGIES POTENTIALLY APPLICABLE TO THE REMOVAL OF SUSPENDED
SOLIDS. TARS, AND OILS FROM LURGI-BASED SYNFDELS PLANT WASTEWATERS
U)
Technology
Gravity
Separation
Coagulation/
Flocculation
Al r
Technology Principle
ProviaioB of adequate reaidence
time in a atagnait veaael to
allow impended aolida or
immiaclble (luidi to aeparate
into lighter- and heavier-than-
water phaaea.
Dae of agent a to promote co-
alescence of fine suspended
aolida and adaorption of tara
and oila; generally need in
conjunction with other pro-
ceaaea (e.g. gravity aepara-
tion. filtration).
n«« nf «4r hnlitilaB to nrcmotm
Coaponente Removed
Nonemnl sif icd free
oila, tara, and
aettleable parti-
culatea.
Fine auapended
tolida, colloids.
and some heavy
•etala.
Fine snaoanded
Removal Efficiency
Dependa on design;
10-50% removal of
TSS typical. 60-99%
for free oila.
Outlet auapended
aolida concentration
to 10 mg/L poaaible.
oila removal 60-95%.
Denenda on charac-
Feed
Requirement a/
Reatrictiona
atream turbu-
lence.
A wide range
of commercial
flocculanta
are available
for treating
range of waate-
watera.
Byproduct a
and Waate
oila (e.g. <1>.
heavy tara, and
aolid aedlmenta
(a.g. >1>.
Same aa gravity
aeparation.
Recovered oila.
Comment a
Incorporated into the
tar/oil aeparation
ayatem of all eziating
Lnrgi gaaification
pi ant a.
Widely need in water
treatment ayatema to
remove fine aolida and
oolloida. Often need
in conjunction with
other proceaaea (e.g.
chemical precipita-
tion, filtration, air
flotation).
Subiect to variation!
Flotation the diaengagement of lighter
thau-water particlei.
Filtration Paaaing waatewater through
auitable filter Bediua;
filter material cleaned by
backwaahing or diacarded.
Screening Paaaing waatewater through a
wire meah, parallel bare, or
aimilar device.
aolida, oila. and
grease. Useful for
removing auapeaded
materials with den-
sities cloae to
that of water.
Suspended aolida,
oil; alxe of par-
ticles removed de-
pends oa coarseness
of media, pretreat-
ment, etc.
Suspended partiolea;
aiie removal dependa
on acreen mesh size;
often removea only
larger particnlatea.
teriatica of aource
and treatment pro-
cess; TSS removal of
2-75%, oil removala
of 75-85% typical.
Higher when combined
with flocculatioa.
TSS removal 30-70%;
with flocculation/
coagulation between
10-98%; oil removala
66-90% fox refinery
API aeparator ef-
fluent.
Dependa on aize dis-
tribution of parti-
culatea in waate
and acreen site uaed.
mente depend entrained aolida.
upon waate and aludge,
characteriatica.
Generally ap- Filter backwash,
plioable for and apent filter
waatewatera media.
with 5-250 mg/L
of TSS, up to
200 mg/L oil.
Tara and
can foul
acreen.
till
Recovered
ticlea.
in influent waatewater
flow and loading if
not combined with
chemical pretreatment.
Dtiliied to treat
waatewater in commer-
cial Lurgi gaaifica-
tioa planta. 'Sticky*
tara/oil may cause
filter plugging and
regeneration problems.
Often uaed aa a pre-
treatment atep for the
removal of large
debria.
-------
Section 4
Aqueous Medium
Generic Control
Suspended Solids
Gravity Separation
The removal of suspended tars and oils by gravity separation is currently
utilized in all operating Lurgi gasification facilities. This process is of-
ten considered an integral part of the byproduct recovery operation.
Gravity separation relies upon the differences in density between immis-
cible oil, water, and suspended solids for successful operation. Byproduct
oils in Lurgi wastewater, which are lighter than water, can be removed from
the top of the aqueous phase, while heavy tars and solid particles sink to the
bottom of the separator vessel.
The design of oil-water separators used in refinery wastewater applica-
tions has been well-defined in studies by the American Petroleum Institute
(API). In API separators, the influent wastewater passes through trash bars
and a skimmer to remove floating oil before entering the quiescent zone of the
separator. In this quiescent zone, the wastewater velocity is kept very low
to avoid turbulent mixing. An adjustable weir at the end of the separator
divides the waste into aqueous and organic phases. A rotating skimmer is used
to remove the organic phase from the surface. The bottom of the separator
contains slowly moving panels which convey the settled solids to a pump.
Typical removal efficiencies for oil/water separators range from 60 to 99
percent for free oils and 10 to 50 percent for suspended solids. Removal
efficiencies depend on a number of factors including relative densities of
oil, water, and solids; particle size; separator configurations; and retention
time.
317
-------
Section 4
Aqueous Medium
Generic Control
Suspended Solids
Secondary waste streams produced by the gravity separation of Lurgi
wastewaters are the light oil skimmed from the surface of the wastewater and
heavy tars, oils, and solid sediments removed from the bottom of the separa-
tor. In addition, if the wastewater being treated contains significant quan-
tities of dissolved gases, it may be desirable to collect these gases and com-
bine them with other gas streams for treatment.
Gravity separation has been widely used in many different industries for
many years. The process is a highly reliable method of separating non-emulsi-
fied oil from wastewater providing the equipment is properly controlled and
regularly maintained and wastewater flow rates and compositions do not vary
widely.
For API separator applications in Lurgi-based synfuels plants, capital
investment requirements for treating 100 m*/hr of wastewater are estimated
to be J800 per m3/hr.
Coanulation/Flocculation
Coagulation and flocculation are techniques for enhancing the gravity
separation of suspended tars, oils, and solids from a wastewater through the
addition of chemicals. Coagulation is the process of destabilizing colloidal
particles by neutralizing surface charges built up on the particle surfaces.
Common chemicals used for coagulation include alum, lime, and ferric sulfate.
Flocculation is the formation of settleable particles from destabilized col-
loidal-sized particles by coalescence and physical enmeshment. Common floccu-
lation aids are polymers, activated silica, and polyelectrolytes.
318
-------
Section 4
Aqueous Medium
Generic Control
Suspended Solids
The equipment generally required for coagulation/flocculation consists of
a mixing tank (where the appropriate coagulants, polymers, and pH adjustment
chemicals are added to the wastewater) and a sedimentation basin or clarifier
(which provides retention time for the settling of the coagulated solids).
Facilities must also be provided for storing, diluting (or dissolving), and
metering the chemicals.
Reported removal efficiencies for oils range from 61 to 95 percent, while
suspended solids concentrations as low as 10 mg/L can be achieved in a pro-
perly designed system. Performance depends strongly on the composition and
concentration of impurities in the wastewater being treated. The use and
dosages of specific coagulants/flocculants are generally determined by the use
of jar tests and field trials.
The major waste stream produced by coagulation/ flocculation is the
sludge stream. It typically contains 1 to 2 percent solids, is quite gelati-
nous, and may be difficult to dewater. The sludge will contain insoluble
metal hydroxides and entrapped solids. Adjustment of the sludge pH may be
required prior to subsequent treatment or disposal.
Coagulation and flocculation have shown good reliability both from a per-
formance and mechanical standpoint. They have been proven over a number of
years of successful operation. The key to reliable performance lies in keep-
ing the influent wastewater composition and flow rate as constant as possible.
Mechanical reliability depends on the use of proper materials of construction
since some coagulation/flocculation chemicals are extremely corrosive.
A coagulation/flocculation system consisting of alum and polymer storage,
feed, and mixing equipment is estimated to require a capital investment (for
319
-------
Section 4
Aqueous Medium
Generic Control
Suspended Solids
treating 100 mj/hr of wastewater in Lurgi-based synfuels plants) of approxi-
mately tlOOO per mj/hr of wastewater flow.
Air Flotation
Air flotation removes small particles, oil, and grease from aqueous
streams by passing small gas bubbles through the wastewater. The bubbles ad-
here to the small particles, reducing their apparent density. The resulting
froth rises to the surface where it is skimmed off. The process is often used
in conjunction with coagulation/flocculation to improve removal efficiencies
for colloidal suspensions or emulsified oils. Air flotation is especially at-
tractive for the removal of particles with densities close to that of water.
Two types of flotation units are currently used: dissolved air flotation
(DAF) and induced air flotation (IAF). DAF involves saturating water with air
under pressure (typically between 0.27 to 0.58 HPa). The gas-saturated water
is then depressurized in a flotation vessel, causing the formation of small
bubbles. Retention times of 20 to 60 minutes are typical for DAF units.
IAF units operate by mechanically dispersing the gas into the wastewater
by the use of a rotor-disperser. A typical IAF unit consists of four flota-
tion cells each of which has a retention time of about one minute.
Air flotation is capable of removing a wide range of suspended solids,
oils, and greases from wastewater streams. Total oil removals of 75 to 85
percent are typically achieved while solids removals of 20 to 75 percent are
expected. When combined with flocculation, free oil removals of 97 percent or
more and suspended solids removals of 80 to '93 percent can be achieved.
320
-------
Section 4
Aqueous Medium
Generic Control
Suspended Solids
Air flotation produces two major secondary waste streams. The first is
the froth skimmed from the surface of the wastewaters which contains oils and
entrapped solid particles. The second is the sludge consisting of solids
having densities greater than that of water.
Air flotation has been demonstrated over many years to be a reliable pro-
cess. The mechanical reliability is high since the equipment required is sim-
ple. Performance reliability depends on minimizing variations in the influent
wastewater flow rate, suspended solids, oil, and grease loadings, temperature,
and pH. Chemical pro treatment helps reduce the adverse effects of such
changes on reliability.
For dissolved air flotation applications in Lurgi-based synfuels plants,
capital investment requirements for treating 100 m3/hr of wastewater are
estimated to be $4700 per m3 of wastewater flow.
Filtration
Granular-media filtration is one of the oldest and most widely used me-
thods for the removal of suspended solids, oils, and tars from wastewater
streams. Although other types of filtration processes are available, this ma-
nual discusses only granular-media filtration for Lurgi wastewaters applica-
tions. Granular-media filtration is currently used to treat wastewaters in a
number of Lurgi-based coal gasification facilities. The wastewater flows
either by gravity or under pressure through a bed of inert material which phy-
sically retains the solids. Materials used as filter media include sand, an-
thracite, resins, and garnet; combinations of these materials are used in mul-
timedia filters. The filter bed is contained in a basin or tank and is sup-
ported by an underdrain system that retains the filter medium while the
321
-------
Section 4
Aqueous Medium
Generic Control
Suspended Solids
filtered liquid is drawn off. Other equipment used in typical filtration sys-
tems includes facilities for backwash storage and pumping (for cleaning the
filter bed after it becomes loaded with retained solids), plus piping and
valving to permit backwashing of some units while others are on line.
Suspended solids removals for granular media filtration range from 30 to
70 percent without pretreatment and between 80 to 98 percent when preceded
with flocculation and/or coagulation. Performance data have not been reported
for filters in Lurgi gasification plants.
Granular-media filtration produces one secondary waste stream intermit-
tently (backwash effluent) and, periodically, spent filter media. The volume
of the backwash stream is generally between 2 to 10 percent of the filtered
wastewater volume, and hence contains 10 to 50 percent higher concentrations
of suspended solids and oil than the original wastewater.
Granular-media filtration is very reliable both from a performance and
mechanical standpoint. Pilot tests generally performed prior to designing
full-scale treatment processes serve to increase performance reliability.
Mechanical reliability is primarily dependent on adequate cleaning of the fil-
ter bed, air and/or water scouring, surface washing, and special media clean-
ing solvents are commonly used to enhance cleaning of the filter bed and thus
reduce operating problems.
For granular-media filtration applications in Lurgi-based synfuels
plants, capital investment requirements are estimated to range from $1800 to
$2500 per ms/hr of wastewater treated, for wastewater flows of 300 and 100
m3/hr, respectively.
322
-------
Section 4
Aqueous Medium
Generic Control
Bulk Organics
4.2.1.2 Processes for Removal of Bulk Organics
For wastewaters with high organic contents, it is often desirable to per-
form an initial bulk organics removal step prior to treatment in processes
which are designed to produce effluents with relatively low concentrations of
organic compounds. Bulk organics removal may be desirable for several rea-
sons. First, it may be economically attractive to recover the organics for
fuel or byproducts. Second, bulk organics removal may be a necessary pre-
treatment step before the application of processes which will produce a de-
sired effluent or recycle water quality. And, third, the lower capital and
total annualized costs for downstream processing units (attainable if a bulk
organics removal step is employed) may more than offset the cost of the bulk
organics removal process.
Table 4-38 presents a brief summary of information on two bulk organics
removal processes: solvent extraction and wet air oxidation. The rest of
this section (4.2.1.2) summarizes available information for these two pro-
cesses. These are not the only processes which could be used for bulk .orga-
nics removal. They were selected as examples of processes which could be used
to remove bulk organics from Lurgi-based synfuels plant wastewaters. It
should be noted that these two processes could also be used in some applica-
tions for residual organics removal.
Solvent Extraction
Solvent extraction processes are often used to remove dissolved organics
such as phenols from process wastewaters. These processes consist primarily
of two steps. First, an extraction step in which the solvent extracts the
dissolved organics from the wastewater, and second, a regeneration step in
323
-------
TABLE 4-38.
TECHNOLOGIES POTENTIALLY APPLICABLE TO TOE REMOVAL OF BULK
OBGANICS FBOU LURGI-BASED SYNFUELS PLANT WASTEWATEKS
Technology
Solvent
Wet Air
Technology Principle
Extraction of organic* fro«
an immiscible solvent. By-
product organic liquids re-
covered frost the solvent IB
Direct reaction of 0, with
Components Removed
Phenols, TOC, BOD,
COD, snd other
orisnics.
TOC, BOD. COD, and
SOBS inorganic pollu-
tants. Destruction
of difficult to
be achieved.
Removal Efficiency
For the Phenosolvan
process, 99.5% re-
moval of monohydric
phenols, 60% for
dihydric phenols,
and 15% for other
organics typical.
SO-90% removal of COD
is possible in a sys-
tem with a residence
tiae of one hour or
greater; 99+% phe-
nol ics destruction.
Feed
Requircaents/
Restrictions
Sensitive to
suspended
Better in
makeup
solvent is
the only
ma j or raw
Baterial.
Air or oxygen;
heet if auto-
thermic reac-
are not pre-
sent.
Byproducts
and Waste
Crude phenols,
filter backwash,
and spent filter
media.
Vent gases con-
taining CO. CO,,
light hydro-
sulfur species.
Comments
This is the basis for
the Phenosolvan pro-
cess used in ell major
Lurgi facilities.
Promising but not pro-
ven in this applica-
tion; fairly rigorous
tion requirements.
-------
Section 4
Aqueous Medium
Generic Control
Bulk Organics
which the removed organics are separated from the solvent. Conntercnrrent ex-
traction columns and distillation columns are used in these processes. Use of
solvent extraction is generally applicable to wastewaters containing at least
2000 mg/1 of extractable organics and having a flow rate of at least 11
mj/hr.
A wide variety of solvents can be used in extraction processes including
benzene, tricresyl phosphate, isopropyl ether, aliphatic esters (such as
n-butyl acetate), light oils, light aromatics, sodium hydroxide solutions, and
various proprietary solvents. The most commonly used process for removing
bulk dissolved organics from Lurgi gas liquors is the Phenosolvan process.
This process is also included in virtually all proposed Lurgi plant designs
and is part of Lurgi's proprietary design package. Although this process is
discussed as one of the water pollution control processes in this manual, in
most Lurgi-based synfuels projects the Phenosolvan process is, for all prac-
tical purposes, part of the Lnrgi base plant. The Phenosolvan process is a
proprietary solvent extraction process developed by Lurgi to extract phenols
and other water soluble organic compounds from process wastewaters. A simpli-
fied flow diagram for this process is shown in Figure 4-6. In this process,
the gas liquor is filtered and fed to a series of mixer-settlers where it
contacts a lean organic solvent (such as butyl acetate or diisopropyl ether)
in countercnrrent flow contactors. After solvent-water phase separation (not
shown in the diagram), the rich solvent is sent to a distillation column for
solvent recovery. The lean solvent from the column returns to the mixer-
settlers while crude phenol is stripped for residual solvent recovery.
The extracted wastewater from the mixer-settlers is stripped with nitro-
gen to recover residual solvent. The solvent-rich nitrogen gas is then con-
tacted with a crude phenol slipstream from the crude phenol stripper to
325
-------
GAS
LIQUOR
FILTER
BACKWASH
SPENT
FILTER
MEDIA
CO
to
MAKEUP
SOLVENT
iLEAN
SOLVENT
RICH
SOLVENT
PHENOL
RECOVERY
SCRUBBER
RA
CTOR
T
-^
ENT
VERY
3BER
_ 4
SOLVENT
DISTIL-
LATION
COLUMN
k^^^
1
.^
1
1
(
1
1
1
1
j
X
STEAM
$
f
N2~"
1
1
I „
1
1
1
MAKEUP)
N2 '
^
— ^
S
SOLVENT
RECOVERY
SCRUBBER
v^ ^X
, ^
CRUDE STEAM
PHENOL Y
STRIPPER ^ 1
f CRUDE
^ PHENOLS
^ EXTRACTED
"^ GAS LIQUOR
te
Figure 4-6. Phenosolvan solvent extraction process
-------
Section 4
Aqueous Medium
Generic Control
Bulk Organics
recover most of the solvent. Phenolic vapors remaining in the nitrogen gas
are then removed via contact with a portion of the feed wastewater. The clean
gas returns to the solvent recovery scrubber and the feed wastewater proceeds
to the mixer-settlers.
Extraction efficiencies for the Phenosolvan process are estimated at:
• 99.5% for monohydric phenols,
• 60% for polyhydric phenols, and
• 15% for organic acids.
Low volume air emissions from various unit operations (e.g., solvent
storage tank vents), spent filter media, and filter backwash are secondary
waste streams from the Phenosolvan process. The crude phenol stream recovered
by the Phenosolvan process is more appropriately considered a by-product than
a waste stream.
The Phenosolvan process has been commercially available for over 40
years. Although there are no publicly available data on the operating his-
tories of the over 30 commercial installations, the continued use of this
process tends to indicate it has adequate reliability.
For Phenosolvan applications in Lurgi-based synfuels plants, a represen-
tative capital investment requirement is $35,000 per m3/hr for a wastewater
flow of 300 mj/hr.
Wet Air Oxidation
Although the wet air oxidation process could be used to remove bulk or-
ganics from Lurgi wastewaters, it has not been proven in that application.
327
-------
Section 4
Aqueous Medium
Generic Control
Bulk Organics
The good commercial record of the Phenosolvan process in this application and
the fact that the Phenosolvan process is part of Lurgi's proprietary gasifica-
tion package have tended to discourage development of alternate approaches for
application to Lurgi-based systems. The primary advantage of the wet air oxi-
dation process in this service is that the process might not require any auxi-
liary fuel and might even be adapted to recover byproduct energy in the form
of steam. Economics tend to limit wet air oxidation to small volume streams
having relatively high organics concentrations. (Another potential applica-
tion of wet air oxidation to a Lnrgi-based synfuels plant is in the regenera-
tion of spent activated carbon in systems which use activated carbon enhance-
ment of activated sludge.)
In the wet air oxidation process, dissolved or suspended organics are ox-
idized by direct contact with compressed air or oxygen at elevated tempera-
tures and pressures. Temperatures of about 590 K, pressures up to 21 MPa, and
residence times of one hour or more are often used to destroy certain toxic
compounds, but less severe conditions can achieve significant reductions in
organic loadings.
Wet air oxidation is capable of reducing the concentration of both organ-
ic and inorganic COD in wastewater streams. The reduction achieved for a
given waste depends on the operating temperature and pressure, presence of
catalyst, and the nature of the waste itself. COD removals of greater than 80
to 90 percent have been reported while greater than 99 percent destruction of
phenolic compounds has been achieved. Whether these levels of destruction can
be achieved with Lurgi wastewaters is not known. Bench- or pilot-scale
studies would need to be performed on actual wastewaters.
328
-------
Section 4
Aqueous Medium
Generic Control
Bulk Organics
The secondary waste stream produced by wet air oxidation consists of the
offgas produced as a result of waste oxidation. Depending on the nature of
the influent, the offgas may contain ammonia, volatile organics, carbon
monoxide, and carbon dioxide. The flow rate of this stream depends on the
flow rate of air (or oxygen) required to oxidize the waste.
Information on the reliability of the wet air oxidation process is
limited, but careful operator attention is reportedly required.
For wet air oxidation of high strength wastewaters like those found in
Lurgi-based synfuels plants, a representative capital investment requirement
is $490,000 per mj/hr of wastewater flow for treating 300 m3/hr of waste-
water.
329
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Gases
4.2.1.3 Processes for Removal of Dissolved Gases
A number of aqueous wastes produced in a Lurgi-based synfuels facility
may contain dissolved gases such as ammonia, carbon dioxide, hydrogen sulfide,
hydrogen cyanide, and/or volatile organics. Removal of dissolved gases may be
desirable to reduce gaseous emissions from downstream water treatment units,
to reduce dissolved gas loadings in downstream treatment units, and to recover
potentially saleable byproducts.
Removal of these gases is normally accomplished by stripping. Five tech-
nologies which appear to be applicable to Lurgi-based synfuels plants are dis-
cussed:
• Steam Stripping,
• PHOSAM-W,
• Chevron WWT,
• Inert Gas Stripping, and
• Vacuum distillation.
Table 4-39 gives a brief summary of information presented in the text.
Steam Stripping
Steam stripping is used to remove ammonia, hydrogen sulfide, carbon
dioxide, phenols, cyanides, organics, and other volatile compounds from waste-
water. The stripped gases and vapors can be further processed, recovered, or
destroyed. The stripped wastewater passes to further treatment or re-use. If
large amounts of ammonia are in the wastewater, the basic steam stripping pro-
cess may be expanded to include the recovery of ammonia. (See the description
of PHOSAM-W and Chevron WWT which follows this steam stripping discussion.)
330
-------
TABLE 4-39
TECHNOLOGIES POTENTIALLY APPLICABLE TO THE REMOVAL OF
DISSOLVED GASES FROM LURGI-BASEO SYNFUELS PLANT WASTEWATERS
Technology
Steam Stripping
PHOSAM-V
Chevron WT
Inert Gat
Stripping
Vacuua
Distillation
Technology
Principle
Increasing teaperature and
providing a poaitive flow
of an inert tutorial
(tteaa) through the waate-
with overhead atreaa.
atripping, but aaaonia is
acrubbed froa the stripper
tion in a phoaphorio acid
solution. Aaaonia ia then
teparated froa phoaphorio
acid and water which are
both renaed in the proceaa.
Si.il sr to tteaa ttrlpping
except that aaaonia !• not
reaoved in the initial
atripper. A aecond •trip-
per reaovet aaaonia, which
ia aubaequently purified to
produce anhydrous aBBonia
byproduct .
Air (or other inert gat)
water proaoting the
deaorption of diaaolved
gatet.
lowered. Vapor pressure
of the dissolved gaaea
then drive* portions of
thea into the vapor
phaae.
Coaponenta Reaoval
Reaoved Efficiency
MB,, acid gaaea 95-99* removal of
and light - and acid gaaet
(phenola). carbon reaoval
variea with
volatility of
atripped
coaponenta.
Saae aa ateaa Saae aa ateaa
•tripping. ttrlpping.
Saae aa ateaa Saae aa tteaa
ttripping. atripping.
Saae aa ateaa Dependa on tpeci-
atrlpplng. fie design fac-
tors (such as
flow rate of the
inert gaa) and on
characteriatioa.
Reaovala aiailar
to ateaa atripping
are achievable.
•tripping. to ataaa (trip-
ping are
achievable, but
for thia perfor-
aanoe ia high.
Feed
Requireaent •/
Reatrictiona
Feed preheat can be
ateaa requireaenta;
acid/cauatic for pH
tdjuataent optional.
Saae as tteaa
atripping.
Saae at tteaa
•tripping.
Be»t applied on
on low flow rate
wattewater ttreaas
aaaonia and CO,.
the inlet waste-
water aay be
required to pre-
vaporization of
water.
Byproduct a
and Wastes
Stripped acid
gaaea and
volatile com-
pounds are in
gaaeoua secon-
dary waste-
atreaa.
Anhydrous
aaaonia by-
product.
Stripped acid
gases and vola-
tile coapounda
are in gaseous
secondary waste
•treaa.
Saae aa
PBOSAM-W.
Stripped acid
gaaea and
volatile coa-
pounda which
are diluted
by the inert
gaa atreaa.
•tripping ex-
cept acid gaa
waate atreaa
ia at lower
and therefore
haa lower
content.
Coaaent a
Acid/canatic addition
the efficiency and
selectivity of the
stripping proceaa.
Proceaa ia a derivative
of the PBOSAM proceaa
which reaovea aaaonia
froa coke oven gaaea.
Proceaa waa deaigned
for refinery aour
watera, but ia aaid
ing synfuels plant
waatewater.
Dilution of the offgai
difficult. Therefore,
thla proceaa ia proba-
bly Halted to waste-
waters whose diaaolved
gaaea can be vented.
the desired reaoval s
in aynfuela plant
applicationa Bake thit
prooeta leaa likely to
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Gases
Steam stripping is usually conducted as a continuous operation in a
packed tower or conventional fractionating column (bubble cap or sieve tray)
with more than one stage of vapor/liquid contact. The wastewater feed is
first preheated by heat exchange with stripped wastewater. The preheated
water enters near the top of the stripping column and then flows by gravity
countercurrent to steam and vapor rising from the bottom of the stripper. As
the wastewater flows downward, it is heated and volatile compounds and gases
are stripped by the steam and vapors rising from the bottom of the stripper.
The performance of steam stripping depends on the characteristics of the
wastewater feed and the stripper design. The most efficient strippers are
generally able to remove ammonia down to 50 to 100 mg/L, but some can achieve
levels of 15 mg/L or less. The degree of ammonia removal obtainable will be
influenced by the ratio of free-to-fixed ammonia present in the wastewater.
Strippers achieving ammonia levels of less than 100 mg/L remove hydrogen
sulfide to 0 to 30 mg/L depending on the initial ammonia, hydrogen sulfide,
and carbon dioxide concentrations. Carbon dioxide is totally stripped. For
several types of wastewaters from synfuels facilities, typically 17 to 22
percent of the residual phenols are stripped. For refinery type wastewaters,
unrefluxed strippers on the average remove 55 percent of the phenols, and
refluxed strippers on the average remove 39 percent of the phenols. Cyanide
removal efficiencies are reported to vary widely but average 37 percent for
stripping refinery-type wastewaters.
The only secondary waste stream from steam stripping is the stripped gas
or vapor which exits the stripper. This stream is saturated with water and
contains all of the stripped gases and vapors. It may be processed to recover
specific components or treated to destroy (or otherwise control) specific
pollutants.
332
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Gases
In refinery applications steam stripping has proven to be highly depend-
able.
For steam stripping applications in Lurgi-based synfuels plants, a repre-
sentative capital investment requirement is $4,000 per m'/hr of wastewater
flow for treating 300 m'/hr of wastewater. This cost estimate does not
include the costs associated with treating the stripped gas stream.
PHOSAM-W
PHOSAM-W (Figure 4-7) is a proprietary process for removing and recover-
ing dissolved gases from wastewaters. It was originally developed by USS
Engineers and Consultants Incorporated. This process is a revision of the
original PHOSAM process to recover ammonia from coke oven gases.
In the PHOSAM-W process, the wastewater stream is first steam stripped to
vaporize and remove ammonia and other dissolved gases and volatile compounds.
The stripped vapors are then scrubbed with a phosphoric acid solution to
recover ammonia. The remaining acid gases and volatile compounds exit as the
absorber overhead gases, which are a secondary waste stream. The absorbed
ammonia is first removed from the phosphoric acid solution in a stripper and
then distilled to remove water, producing a liquid byproduct ammonia stream.
Most strippers are designed to remove free ammonia down to 50 to 100
mg/L, but some can achieve levels of 15 mg/L or less depending on the levels
of fixed ammonia in the wastewater. Strippers achieving ammonia levels of
less than 100 mg/L will generally remove hydrogen sulfide to 0 to 30 mg/L
depending on the initial ammonia, hydrogen snlfide, and carbon dioxide concen-
trations. Carbon dioxide is totally stripped. For several types of waste-
waters from synfuels facilities, typically 17 to 22 percent of the residual
333
-------
Acid
Gases
Wastewater
Feed
Aqua
Ammonia
^
^
— >•
F
R
A
C
T
I
0
N
A
T
0
R
^
^
^^
(^
Product
Ammonia
Steam
Condensate
Stripped
Wastewater
Figure 4-7. The PHOSAM-W process
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Section 4
Aqueous Medium
Generic Control
Dissolved Gases
phenols are stripped. For refinery-type wastewaters, unrefluzed strippers on
the average remove 55 percent of the phenols and refluzed strippers on the
average remove 39 percent of the phenols. Cyanide removal efficiencies are
reported to vary widely but average 37 percent for stripping refinery-type
wastewaters.
For this manual, the PHOSAM-W process is estimated to achieve the follow-
ing residual wastewater concentrations:
Component mg/L
Ammonia 150
HaS 1
CO, 1
In addition, a 50% removal of HCN has been assumed.
The only secondary waste stream from a PHOSAM-W plant is the acid gas or
vapor which exits the ammonia absorber. This stream is saturated with water
and contains acid gases such as carbon dioxide and hydrogen sulfide and other
volatile compounds. This stream also contains a small amount of ammonia,
typically comprising 0.1 to 0.5 percent of the total gas volume.
The original PHOSAM process has been operated reliably in several plants
for up to 10 years, with a service factor of about 95 percent. No data are
available on commercial application of the PHOSAM-W process, but this process
has been proposed for use in several new U.S. synfuels plants.
For PHOSAM-W applications in Lurgi-based synfuels plants, a representa-
tive capital investment requirement is $35,000 per m*/hr of wastewater flow
for treating 300 m3/hr of wastewater. This cost estimate includes equipment
for recovering ammonia as a byproduct, but does not include the costs asso-
ciated with treating the stripped acid gases.
335
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Section 4
Aqueous Medium
Generic Control
Dissolved Gases
Chevron WWT
The Chevron Wastewater Treatment (WWT) process is a proprietary process
developed by Chevron Research Company. Although the process was originally
developed to treat sour refinery wastewaters, its developers claim it to be
capable of treating sour wastewaters from coal processing and synthetic fuel
plants.
The process basically consists of sequentially stripping first acid gases
such as hydrogen sulfide and carbon dioxide and next ammonia from a foul
water. The stripped ammonia is recovered, concentrated, and washed to yield a
high-purity anhydrous ammonia byproduct. In refinery wastewater applica-
tions, a high—purity hydrogen sulfide stream is produced and may be fed to a
sulfur recovery plant. In other applications, the hydrogen sulfide stream may
be diluted by other acid gases such as carbon dioxide, but sulfur recovery may
still be feasible.
In the acid gas stripper, hydrogen sulfide and other acid gases are strip-
ped upwards while ammonia and water flow downward, countercurrently to the
stripped vapors. A stripped water reflux stream is used to hold ammonia in
the wastewater. In the next stripper, ammonia is stripped from the waste-
water. The ammonia vapors are subsequently compressed to yield a liquid
ammonia byproduct. Depending on the characteristics of the wastewater, pH
adjustment may be necessary preceding the ammonia stripper in order to strip
fixed ammonia.
The stripped bottoms from the ammonia stripper typically contain less
than 5 ppmw hydrogen sulfide and less than SO ppmw ammonia. The purity of
this stream and the acid gas and ammonia streams can be adjusted by changing
336
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Section 4
Aqueous Medium
Generic Control
Dissolved Gases
the operations of the scrubbing and distillation towers. Any carbon dioxide
in the wastewater is totally stripped in the acid gas stripper. Removals for
other compounds have not been reported.
The acid gas taken from the stripper typically contains less than 50 ppmw
ammonia and less than 5000 ppmw water. The purity of this acid gas may be
affected by other contaminants in the wastewater feed, but these effects are
not discussed in the open literature. Secondary wastes from the Chevron WWT
process include the acid gas which exits the first fractionating column, a
light flash gas from the degasser, and unspecified waste products from the
ammonia scrubber.
As of 1978, the Chevron WWT process had been employed in ten commercial
facilities, mainly at refineries. No information is available which indicates
its reliability in Lurgi-based synfuels plants.
For Chevron WWT applications in Lurgi-based synfuels plants, a represen-
tative capital investment requirement is $35,000 per m»/hr for treating 300
n»3/hr of wastewater. This cost estimate includes the costs associated with
recovering ammonia as a byproduct, but does not include the costs associated
with treating the stripped acid gases.
Inert Gas Stripping
Inert gas stripping involves passing a gas (e.g., air, nitrogen, CO )
through a separation tower countercurrent to the wastewater flow. The contact
between the gas and liquid phases promotes desorption of the dissolved gases.
The vapor phase, containing the stripping gas and NH3, HaS, HCN, and C02 is
then further processed. If air is used as the inert gas, oxidation of
organics can occur, as well as oxidation of H2S to form colloidal sulfur.
337
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Aqueous Medium
Generic Control
Dissolved Gases
Because the carrier gas is generally noncondensible at standard operating
conditions, it is frequently difficult to treat the various acid gases in the
stripper overhead stream. While this stream has generally been incinerated in
the past, the practice is now being phased out because of NO and S02 emis-
sions limitations.
Although inert gas stripping can be performed at lower temperatures than
steam stripping, the added cost of flue gas control and the increased diffi-
culty of byproduct recovery could significantly raise the capital and opera-
ting costs. Inert gas stripping is best applied on low flow rate wastewater
streams with low NH} and C0a levels which can be vented. Inert gas stripping
removal efficiencies equivalent to those obtained with steam stripping can be
obtained when the inlet feed water or stripper feed gas is preheated.
Vacuum Distillation
Vacuum distillation removes dissolved gases from wastewater by lowering
the total system pressure. Dissolved gases whose vapor pressures are rela-
tively high tend to leave the liquid phase when their partial pressure in the
vapor phase is decreased due to a lowering of the system pressure. In order
to prevent excessive amounts of water from vaporizing, the liquid temperature
must be fairly low. Some cooling of the sour water stream may be required.
Removal efficiencies equivalent to those achieved with steam stripping
are possible with this approach, but generally lower removals are experienced.
The high energy costs associated with this technology make this approach
noncompetitive in installations where stripping steam is available.
338
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Section 4
Aqueous Medium
Generic Control
Dissolved Organics
4.2.1.4 Processes for Removal of Dissolved Organics
The most widely used processes for the reduction of dissolved organics,
both in industrial and municipal wastewaters, are biological processes. In
biological processes, concentrated masses of microorganisms break down organic
matter, resulting in the stabilization of the wastewater. The microorganisms
can be classified as follows:
Aerobic organisms - require molecular oxygen for metabolism.
Anaerobic organisms - derive energy from organic compounds and
function in the absence of oxygen.
Facultative organisms - may function in either an aerobic or anaero-
bic environment.
Several different processes are available which utilize one or more of
the different types of organisms. These processes are potentially applicable
to the treatment of a number of Lurgi gasification wastewater streams as long
as concentrations of inhibitory compounds are kept low enough not to adversely
affect the organisms. The remainder of this section (4.2.1.4) summarizes
available information on dissolved organics removal by the following pro-
cesses :
Activated Sludge,
Trickling Filters,
Rotating Biological Contactors,
Lagoons, and
Anaerobic Digestion
Table 4-40 is given as a brief summary of some of the information discussed
in the text.
339
-------
TABLE 4-40.
TECHNOLOGIES POTENTIALLY APPLICABLE TO THE REMOVAL OF DISSOLVED
OEOANICS FROM LDBGI-BASED SYNFUELS PLANT WASTEWATERS
Technology
Act ivated
Sludge
Technology Principle
Biological conversion ox the
carbonaceous organic Hatter in
various gaseous end products.
•TOC BOD COD d D
so>e inorganic stream character-
tiate; 60-90* re-
moval of BOD and
SOt reaioval of COD
•nd TOC possible
with realdence time
>12 houra.
Feed
Requirements/
Re strictions
supplemental
(nitrogen.
phosphorus)
stay be re-
required; feed
rate and load-
ing should be
relatively con—
Byproducts
and Waate
excess biological
sludge and
gases.
Comment s
a variety of indus-
ing coke oven and
refinery waatewaters.
•tint; inhibitory
Trickling
Filter!
Rotating
Biologi cal
Contactors
Lagoons
Anaerobic
Digeation
Saaie as activated sludge.
Bacteria fora film on per-
•eable media bed, ait blown
flow.
Saaie as activated aludge.
Bacteria form film on
rotating plastic disks.
Disk rotstion also provides
oxygen.
the action of aerobic.
anaerobic, or facultative
bacteria in ponda; aettling
of snapended aolids.
Degradation of organic! by
the action of anaerobic
bacteria to fora (ultimately)
CH4 and CO,.
Saaie as activated 60-85* of BOD in
aludge. refinery waate-
watersi 40-90*
BOD rcBOYaV 1 » QC~~
pending oa lotdinf.
•ludf s • cosaaOvcl 68~92%
•Phenolic waste"
(100 Bg/L phenol)
99% reduction of
phenol .
Same as'sctivated BOD removala £0~90%
sludge plua sus- (influent 200-100
pended solids. mg/L); 10-90* re-
duction of COD and
TSS.
Sane as activated Liaiited data avail-
sludge, plus aolids. able; for treatment
of biological aludge
total solids reduc-
tions of 33-58%
reported.
oompounda may
need to be
diluted
Dilution Bay be
required to
control load-
ing. More re —
sistant to shock
loading than
activated
•lodge.
to changea in
loading than
activated
sludge.
upsets due to
changes in
waatewa ter
flow, tempera-
ture, and
composition.
Required good
control over
pH, alkalinity.
temperature
and inhibitory
compound con-
centratlona.
Excess biological
sludge and
•tripped volatile
gases.
sludge and
atripped volatile
gaaea.
potential for
leaching; volatile
gases may be
stripped from
aerated lagoons.
Methane, CO,, and
aoae HaS, possi-
ble; excess
sludge.
Dae of trickling fil-
ters to treat synfuels
plant waatewater has
Often used aa a rough-
ing unit before an
activated slndge
system.
Not demonstrated for
plant wastewatera;
have been installed in
refineries.
tively large land
areas and long resi-
dence times. Odors
may be a problem with
facultative and
anaerobic lagoona.
Currently used pri-
marily to reduce
volume of aludge from
aerobic treatment
proceaaea.
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Section 4
Aqueous Medium
Generic Control
Dissolved Organics
Biological systems for dissolved organics removal can be either single-
or multi-stage systems. In multi-stage systems, two or more biological reac-
tors are used in series. The type(s) of biological processes used in multi-
stage systems do not necessarily have to be the same in each stage. The main
purpose for using multi-stage systems is to treat high strength wastewaters
and/or to achieve better performance than is technically feasible in single-
stage systems.
Activated Sludge
An activated sludge system consists of two key components: a reactor and
a clarifier. Organic-laden wastewater is introduced into the reactor where an
aerobic bacterial culture is maintained in a suspension called the mixed
liquor. The bacterial culture or sludge converts the organic materials to
carbon dioxide, water, metabolic intermediates, and ammonia. The sludge
concentration maintained in the reactor is dependent on the desired treatment
efficiency and other application-specific factors. Oxygen is supplied to the
reactor by aeration with air or an oxygen-enriched stream. A portion of. the
mixed liquor is continuously passed into a settling tank or clarifier where
the sludge is separated from the treated wastewater. A portion of the sludge
is recycled to the reactor while the remainder is removed from the .system.
Powdered activated carbon can be added to the system to achieve simultan-
eous biological and physical-chemical treatment of wastewaters in a modified
process known as the activated carbon enhanced activated sludge (ACEAS)
process. The organisms grow on the carbon, which helps retain organic mole-
cules near the organisms for faster metabolism. Physical adsorption of organ-
ics on the activated carbon also helps reduce the impact of shock loadings of
inhibitory compounds on the bacteria.
341
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Dissolved Organics
Knowledge about the performance of a commercial-scale activated sludge
process in treating wastewaters from Lurgi gasification is currently limited
to foreign experience. Data are available from the treatment of wastewaters
having similar compositions, such as weak ammonia liquor from byproduct coking
operations, and from bench-scale treatability data for wastewaters from other
gasification processes. Table 4-41 summarizes these performance data. These
data show that activated sludge is effective in reducing phenolic compounds.
COD, BOD, and TOC removals vary greatly with the wastewater being treated.
The data in Table 4-41 and other test data on various wastewaters are
providing a growing data base for predicting the performance of activated
sludge systems with and without oxygen or activated carbon enhancement.
Interactions occnring in the activated sludge process are very complex and are
not completely understood. Appendix B-10 in the Control Technology Appendices
for PCTMs discusses the development of detailed performance models for acti-
vated sludge systems. While these models may be useful in understanding
proposed systems, they were not used to predict activated sludge effluent
compositions and characteristics in this manual. The amount of uncertainty in
estimating the flow rates, compositions, and characteristics of wastewaters
produced by synfuels plants does not justify using the complex approach of the
detailed models in this manual.
In this manual the compositions and characteristics of treated waste-
waters from activated sludge systems are estimated based on the information in
Table 4-41. Although a range of removal efficiencies are indicated by the
data in this table, the single point values listed below were used in this
manual.
342
-------
TABLE 4-41.
COUPABATIVE PERFORllANCE DATA FOR ACTIVATED SLUDGE SYSTEMS TREATING
WASTEWATEES FROU BYPRODUCT COKING AND VARIOUS SYNFUELS PROCESSES
LO
^
U>
Characterization,
Process
Coke Plant*
GFETCb
Hyga."
Synthane
*
METCe
B-Coalf
Synthetic1
Coal Conversion
Wastewater
SRC-Ih
Waatewater
Waatewater Source
Ammonia Still Effluent
Bioz Effluent
Raw Proceta Effluent
Pretreated Bioz Influent
Bioz Effluent
Raw Proceaa Effluent
Pretreated Bioz Influent
Bioz Effluent
Raw Proceaa Effluent
Pretreated Biox Influent
Bioz Effluent
Raw Proceaa Effluent
Pretreated Bioz Influent
Bioz Effluent
Raw Process Effluent
Pretreated Bioz Influent
Bioz Effluent
Raw Waste
Pretreated Influent
Bioz Effluent
Raw Recycle Proceaa
Pretreated Influent
Bioz Effluent
COD
3900-4600
300-410
21,000-30,000
5380-7130
1110-1340
3400-5300
3540-4190
660-890
22,000
1250-5690
390-2030
4800
820-1600
88,600
3070-4180
310-380
5710
60,000
2,000
250
BOD
1700-2800
5-15
3000-6700
75-230
2980
2570-3090
270-450
2290
52,700
1890-2600
24-36
3500
5-1000
16,900
1200
5
Phenol ica
750-1000
0.25-1.4
3500-6500
1090-1730
01! 1 f
600-900
620-940
3000
175-1205
<1.0-2.5
920
£800
4650
1900
280
1
. m«/L
SCN- NH,-N
280-510 35-92
80-200 4000-7500
2-4 87-122
31 9500
Org-N
21-27
70-140
10
1-8
51
10-24
5-13
NO,-N TOC
<1
11 1000
bEffluent BOD data are for a reactor ahowing a well nitrified effluent (64).
cRaw gaaifier effluent from Indian Head lignite. Pretreated for ammonia removal; dilated to 33% strength (65).
^Cyclone and quench effluenta from Illinois subbiluminous. Pretreated for aamonia removal; no dilution (66).
^Byproduct water from Montana Roaebud anbbituminona. Pretreated for ammonia removal and diluted to ~5 to 6% and ~2S% (67).
^Pretreated for ammonia removal and diluted to 36-40% strength. These data are from teat aeriea c with producer Run 90 waatewater (68).
Foul water from coal liquefaction. Pretreated for aulfide and ammonia removal and diluted to 22% strength (69).
•Pretreated by dilution to 25% strength (70).
Pretreated for ammonia and tar acid removal before being diluted to 20% (71).
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Organics
Percent Removal Percent Removal
COD 80 Organic acids 95
BOD, 90 Cyanide 70
TOC 80 Thiocyanate 70
Total Phenol 95 Tar and Oil 70
Ammonia removals are estimated as 13.5 percent (by weight) of the dry
biological sludge produced.
The principal waste stream generated by the activated sludge process is
the excess sludge produced as a result of the microorganism growth process.
The quantity of sludge generated corresponds to the net growth rate of sludge
in the reactor. It is concentrated to between 0.5 to 1.2 weight percent
solids in the clarifier.
Another potential waste stream is the emission of volatile species from
the surface of the reactor. Pretreatment of the wastewater (e.g., by strip-
ping) might be considered to reduce the concentration of volatiles. However,
additional volatile organics will be formed during the biodegradation pro-
cesses.
No data are available for the reliability of the activated sludge process
operating on Lurgi wastewaters. Experience from other applications shows that
good reliability depends heavily on avoiding sudden variations in the waste
strength or flow; maintaining adequate concentrations of nutrients, such as
phosphorus and nitrogen; and on providing equipment spares. Monitoring of the
process by well trained operators is also required.
For activated sludge applications in Lurgi-based synfuels plants, a
representative capital investment is $40,000 per m3/hr of wastewater flow.
This estimate is for treating approximately 300 m3/hr of wastewater
containing 2000 mg/L BOD5.
344
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Dissolved Organics
Trickling Filters
Trickling filters are fixed-film biological treatment units in which the
wastewater is percolated or trickled over a bed of highly permeable media to
which a biological slime is attached. Oxygen and organic matter are adsorbed
at the surface of the slime layer, where aerobic microorganisms degrade the
organics. Excess microorganisms are washed off and a new layer begins to grow
in its place. A portion of the treated wastewater is recirculated to the
trickling filter to provide control over the hydraulic and organic loadings
which determine the sloughing characteristics of the slime layer. The re-
circulated effluent also ensures continuous wetting of the media and serves to
dilute high strength wastewaters. If desired, sloughed-off slime can be
separated from the effluent in a downstream clarifier.
The medium used for trickling filters is generally a plastic material
which can be designed to provide better oxygen transfer and a much greater
specific surface area than naturally occurring materials which can also be
used. The light—weight plastic medium can also be contained in less—expensive
structures.
Typically, trickling filters will remove from 60 to 85 percent of the
influent BOD from refinery wastewaters. With extensive treatment, above 90
percent BOD removal has been obtained for phenolic wastewaters. However, with
high organic loadings, BOD removal can be as low as 40 percent. No data are
available on the use of trickling filters to treat wastewaters from Lurgi
gasification facilities or other high strength wastewaters from synfuels
facilities.
There are two secondary waste streams associated with the operation of a
trickling filter. The first is the air stream which continually flows across
345
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Section 4
Aqueous Medium
Generic Control
Dissolved Organics
the beds. This stream will contain volatile gases stripped from the waste-
water and volatile products of the biological degradation process. The second
waste stream is the excess slime which must be continuously removed from the
reactor. The slime can be separated from the effluent in a conventional
clarifier. However, if the trickling filter is used as the first stage of a
multi-stage biological treatment system, it may not be necessary to provide
for sludge separation between stages.
Biological filters are highly reliable due to their mechanical simplicity
and high concentrations of microorganisms that provide resistance to shock
loadings. Decreased performance reliability can be experienced in cold
weather due to decreased biological activity.
For use of trickling filters to treat low strength wastewaters (influ-
ent BODj of about 150 mg/L), the capital investment requirements are essen-
tially constant at $4000 per m»/hr of wastewater treated. For treating high
strength wastewaters, such as those from Lnrgi-based synfuel facilities, the
unit costs for trickling filters would be expected to be significantly
higher. For example, treating a wastewater containing 2000 mg/L BOD{ could
require a ten-fold increase in the wastewater recirculation rate to the trick-
ling filter. For this example then, the capital investment requirement is
estimated at over $50,000 per m3/hr of influent wastewater. In addition, a
trickling filter in a high strength application may not be able to achieve the
60 to 85 percent reduction of influent BOD typical of low strength applica-
tion.
Rotating Biological Contactors
A rotating biological contactor (RBC) is a form of fixed film biological
treatment unit similar to a trickling filter. In an RBC the slime layer of
346
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Section 4
Aqueous Medium
Generic Control
Dissolved Organics
microorganisms grows on the surface of disks, 1.8 to 3.7 m in diameter, which
are usually constructed of polystyrene or polyvinyl chloride. BBC's may be
operated either as aerobic or anaerobic treatment units depending on the
fraction of the rotating disk which is submerged in the wastewater. Excess
slime is sloughed off by shearing forces created by rotation of the disks.
Data from RBC treatment of Lurgi gasification wastewaters are not avail-
able. Results from the treatment of wastes from other industries showed the
following results:
• For an oily waste, reductions of BOD from 47 and 375 mg/L in
the influent to 15 and 31 mg/L in the effluent were obtained.
This corresponds to 68 to 92 percent removal.
• For a phenolic waste containing 100 mg/L of phenol, 99 per-
cent removal of the phenol was achieved.
Results from treatment of refinery wastes show an increase in removal
efficiency with increasing influent concentration.
The only secondary wastes from an RBC are the volatile gases released
from the surface of the wastewater and the underflow solids (excess slime)
from the downstream clarifier. As with trickling filters, if the RBC is used
as the initial stage of a multi-stage system, biological sludge may not be
generated as a waste stream from the RBC unit.
RBC units are considered to be moderately reliable in the absence of high
organic loadings and extreme cold temperatures. They are subject to limita-
tions involving mechanical considerations, shock loadings, inhibitory sub-
stances, and oil. Mechanical problems can arise from weight shifts during
sloughing or if the water level in the treatment tank drops too low.
347
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Generic Control
Dissolved Organics
BBCs used to treat low strength wastewaters (influent BOD$ of about 150
mg/L) are estimated to have capital investment requirements of ill,000 per
mVhr of wastewater treated (over a wide range of flow rates). However, for
treating high strength wastewaters, the capital costs would be significantly
higher. For treating a wastewater containing 2000 mg/L, capital investment
requirements could increase by a factor of 10 or more. Thus, capital costs
could be over $100,000 per m3/hr. The BOD5 reduction obtainable in high
strength applications is unknown. On a percentage basis, however, removal
efficiencies are expected to be lower for high strength applications than for
low strength applications.
Lagoons
Lagoons, or ponds, are general terms used to describe bodies of water,
generally contained in earthen dikes, which are designed for wastewater treat-
ment. Lagoons contribute to wastewater treatment in several ways, including
settling of suspended solids (in undisturbed lagoons) and reduction of dis-
solved organics by biological activity. Lagoons may be classified as aerobic,
anaerobic, or facultative depending on the type or types of biological acti-
vity occurring in them.
Aerobic lagoons may be further classified as aerobic algal lagoons or
aerated lagoons. Aerobic algal lagoons depend on diffusion from the air and
the action of algae to provide the oxygen needed by aerobic organisms. They
are typically very shallow (up to 0.5 m). They require large land areas and
are used most successfully in warm climates. Aerated lagoons receive their
oxygen requirement through mechanical aeration. Depths of 1.8 to 6.1 m are
commonly used. The contents of aerated lagoons are also kept well mixed by
the mechanical agitation. One potential problem with aerated lagoons is the
formation foams.
348
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Section 4
Aqueous Medium
Generic Control
Dissolved Organics
Anaerobic lagoons are generally 2.4 to 6.1 m deep and are characterized
by heavy organic loadings. In these lagoons, wastewater degradation occurs by
the action of anaerobic bacteria.
•
Facultative lagoons are the most common type of wastewater treatment
lagoon. They range in depth from 0.9 to 2.4 m. The wastewater is acted on by
anaerobic organisms at the bottom of the pond, facultative organisms in the
middle, and aerobic bacteria near the surface. Oxygen is maintained in the
upper level either by algae or by aerators which do not completely mix the
contents of the pond.
Contaminant removals by lagoons depend on a number of design and opera-
tional variables including pond depth; retention time; wastewater organic
loading, temperature, wastewater pH, flow, and composition; and nutrient
levels. Treatment times are longer than for other biological processes.
Aerated lagoons are reported to remove from 60 to 90 percent of BOD5
from wastewaters having influent BOD5 concentrations of 200 to 500 mg/L; COD
removals are reported to be 70 to 90 percent. Total suspended solids (TSS)
removals also range from 70 to 90 percent.
Anaerobic lagoons typically remove from 50 to 70 percent of influent
BOD4 depending on loading and retention time. TSS levels may show an increase
due to entrained excess sludge. Facultative lagoons are capable of BOD}
reductions of 75 to 95 percent.
All types of lagoons produce a sludge residue. This sludge accumulates
in the bottom of aerated and facultative lagoons and is removed infrequently
(typically every 10 to 20 years). Anaerobic lagoons produce less sludge than
349
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Section 4
Aqueous Medium
Generic Control
Dissolve Organics
the other types. Sludge may be continuously removed from aerated and anaero-
bic lagoons. All lagoons may produce seepage which may ultimately impact
ground water. The amount depends on the type (natural or man-made) and condi-
tion of the pond liner.
Aerated lagoons may impact the air due to the stripping of volatiles by
the air injected into the lagoon. Anaerobic and aerated facultative lagoons
may produce odors due to the release of degradation products such as hydrogen
sulfide.
Aerated lagoons are typically very reliable. They require little opera-
tor expertise. However, they are susceptible to upsets caused by changes in
influent temperature, flow, or composition if the influent is not properly
dispersed and/or diluted. Anaerobic lagoons are highly reliable when operated
in their narrow optimum pH range of 6.8 to 7.2. They are fairly resistant to
upsets due to their high loading of microorganisms. Facultative lagoons are
also highly reliable.
Estimated capital investment requirements for the various lagoon types
treating relatively low strength wastewaters (200 to 600 mg/L BODf) are given
below. The values shown are for wastewater flows in the range of 100 to 1000
m3/hr. For treating high strength wastewaters (~2000 mg/L BOD,), the cost
of lagoons would be significantly increased, as indicated below. The perfor-
mance of lagoons for treating high strength wastewaters is unknown.
Capital Investment Requirements, J/(m3/hr)
Low Strength High Strength
Lagoon Type Wastewaters Wastewaters
Aerated 900 - 2700 9000 - 27,000
Anaerobic 3800 - 7000 13,000 - 23,000
Facultative
Warm Climate 11,000 - 19,000 110,000 - 190,000
Cool Climate 5000 - 9000 50,000 - 90,000
350
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Organics
Anaerobic Digestion
Anaerobic digestion is a biological treatment process in which organic
molecules are converted to methane and carbon dioxide in the absence of oxy-
gen. The process is carried out in special reactors called digesters, of
which there are two basic types. In the standard rate digestor the contents
are generally unmixed and unheated. This leads to separation of the reactor
contents into several layers. From bottom to top these are: digested sludge,
an active digestion zone, relatively clear supernatant, undigested scum, and
bacteriologically-produced gas. Residence times are typically 30 to 60 days.
High-rate digesters are usually completely mixed and heated. The effluent is
separated after leaving the reactor into sludge and supernatant phases.
Residence times of 15 days or less are typical. Two stage digestion combines
a high-rate digestor with a standard rate unit which serves to separate the
digested solids from the treated wastewater.
Two commonly used temperature ranges for anaerobic digestion are 303 to
311 K (mesophilic) and 322 to 330 K (thermophilic). The pH range for anaero-
bic digestion is from 6.6 to 7.6.
Anaerobic digestion is currently used primarily to reduce the volume of
sludge from aerobic treatment processes. Total solids reductions of 33 to 58
percent are reported. No data are available for the treatment of Lurgi waste-
waters by this process.
Anaerobic digestion produces two secondary waste streams, waste gas and
treated sludge. The gas stream, which consists primarily of carbon dioxide
and methane, can be combusted to provide process heat. Care must be taken to
avoid explosive mixtures with air. The nature of the treated sludge will
351
-------
Section 4
Aqueous Medium
Generic Control
Dissolve Organics
depend on the characteristics of the waste being treated. The sludge produced
in current applications of the technology has been landfilled after dewater-
ing.
Anaerobic digestion is susceptible to upsets caused by changes in waste-
water pH, alkalinity, temperature, and toxics concentrations. It can be
operated successfully if these variables are well-controlled. It has not been
demonstrated for the treatment of Lurgi wastewaters.
352
-------
Section 4
Aqueous Medium
Generic Control
Residual Organics
4.2.1.5 Processes for Removal of Residual Organics
Previous sections have discussed processes which are applicable to the
removal of organics from aqueous streams containing bulk organics (4.2.1.2) as
well as somewhat lower concentrations of dissolved organics (4.2.1.4). The
present section (4.2.1.5) summarizes available information on processes which
generally will be used in a polishing mode for residual organics removal. It
should be emphasized that these categories are somewhat arbitrary and that
some of the processes discussed previously might be used for the removal of
residual organics. An example of this is wet air oxidation.
The remainder of this section summarizes available information on acti-
vated carbon adsorption, chemical oxidation, thermal oxidation, and cooling
tower oxidation. Table 4-42 provides a brief summary of the information pre-
sented in the text.
Activated Carbon Adsorption
Activated carbon adsorption is one of the most widely used methods for
removing residual organics from industrial wastewaters. Adsorption operates
on the principle that certain species have a higher affinity than others for
the sorbent (in this case activated carbon). Wastewater passing through a
packed bed of activated carbon is depleted of those species which have an af-
finity for the carbon, including a number of organics. As the surfaces on and
within the pores of the activated carbon become saturated with adsorbed orga-
nics, it is necessary to remove this spent carbon and either dispose of it or
regenerate it for reuse. For applications in a Lurgi-based synfuel plant,
this regeneration will normally be done by thermal processes, the most common
of which is thermal oxidation (in a furnace).
353
-------
TABLE 4-42.
TECHNOLOGIES POTENTIALLY APPLICABLE TO THE REMOVAL OF KESIDUAL
ORGANICS FROM LURGI-BASED SYNFUELS PLANT WASTEWATERS
U)
Ln
Technology
Activated
Carbon
Chemical
Oxidation
Thermal
Oxidation
Cool ing
Tower
Oxidation
Technology Principle
by activated carbon; powdered
in conjunction with biological
processes.
water with ozone* peroxides.
or chlorine-baaed oxidanta.
Combnation of organics.
Air and aerobic oxidation
and atripping of organica
omponen a en v
with phenols; tone
tivity of given
apeciet and compe-
titions in waste-
water.
TOC, BOD. COD, and
oxidiiable inor-
ganici .
All oxidizable
organica.
TOC, COD. BOD,
phenols, other
organics, and
NH,.
99% removal for
phenols and other
remov a 1 for COD .
High removal s
achievable depend-
ing upon conditions
of operation.
Essential ly complete
designed system.
For refinery appl i-
cation. 99+% phenol
obtained with BOD
reduction of 80%.
Feed
Requirements/
Restrict ions
Adsorbent
Oxidant
Supplemental
improve perfor-
mance and lower
snppl emental
fuel require-
ments.
Sensitive to
suspended
and high TDS.
Byproducts
and Waste
Spent adsorbent.
of f gases, and
backwash.
Most cheaical
produce second-
dation products
depend on dosages.
Blowdown/drift.
Comments
Probably more effec-
tive as a polishing
rather than a bulk
process.
Chlorine-based oxi-
blems with treated
for removing organics
but the supplemental
fuel requirements may
be substantial .
Treated wastewater use
in small refinery
cooling towers has
been practiced.
-------
Section 4
Aqueous Medium
Generic Control
Residual Organics
The performance of activated carbon adsorption in treating specific
wastewater streams depends on the nature of the compounds present. Tests are
generally conducted to determine the applicability and economics of the pro-
cess. Tests conducted on streams similar to those expected in Lurgi gasifica-
tion have shown the results summarized in Table 4-43. The removals given in
this table were used as the basis for performance of carbon adsorption systems
in this manual. In addition cyanide and thiocyanide removals of 50 percent
were used, although some data indicate higher removals may be possible (76).
TABLE 4-43. ACTIVATED CARBON ADSORPTION EFFICIENCIES FOR WASTEWATER
SIMILAR TO THOSE EXPECTED FROM SYNFDELS FACILITIES
Component Removal Reference
Tars 99% 72
Oils 99% 72
Organic Acids 70% 73
COD 80% 72
BOD 60% 74
TOC 70% a
Phenols 99.9% 75
aBased on adsorption isotherms generated in the laboratory using pretreated
gas liquor from Lurgi-type plant in Kosovo, Yugoslavia.
The most important secondary waste streams generated by carbon adsorption
are related to the bacfcwashing and regeneration steps. Backwashing of down-
flow fixed bed adsorbers produces a stream containing high levels of suspended
solids since the bed acts like a granular media filter. (A separate filter
ahead of the carbon adsorption unit may be required if high levels of sus-
pended solids are present.) Thermal regeneration produces an offgas stream
which may contain some unoxidized organics, carbon monoxide, and other pollu-
tants derived from the furnace fuel and the waste material being combusted.
The furnace fuel is first burned stoichiometrically to produce C02 and H20.
355
-------
Section 4
Aqueous Medium
Generic Control
Residual Organics
These species then react with the organic material which has deposited on (and
within) the carbon particles. Oxygen, which would react directly with the
carbon, is not desired in these gases.
Solid wastes from this process include ash and carbon fines. If the car-
bon is not regenerated, the spent carbon would constitute a solid waste.
Granular activated carbon processes are reported to be moderately relia-
ble both mechanically and operationally. Regeneration furnaces are more sub-
ject to mechanical failures than many wastewater treatment processes. How-
ever, the wide use of activated carbon adsorption is indirect evidence that
the process has acceptable reliability. Data are not available for the appli-
cation of the process to Lurgi aqueous waste streams.
For activated carbon adsorption applications in Lurgi-based synfuels
plants, a representative capital investment requirement is $25,000 per m3/hr
of wastewater flow. This estimate is for treating approximately 300 m3/hi
of wastewater and includes the cost of onsite regeneration but does not
include the cost of the initial charge of activated carbon.
Chemical Oxidation
Chemical oxidation is the oxidation of wastewater contaminants to produce
more environmentally acceptable degradation products such as water and carbon-
ates by reaction with chemical oxidants such as chlorine, chlorine dioxide,
ozone, hydrogen peroxide, and potassium permanganate. The choice of oxidant
depends on the nature and concentration of the wastewater organics, the poten-
tial oxidation products (some of which may potentially be more toxic than the
original compounds), and the wastewater flow rate. For example, oxidation of
phenolic compounds using chlorine-based oxidants could result in the formation
of highly toxic chlorinated phenols.
356
-------
Section 4
Aqueous Medium
Generic Control
Residual Organics
Simple equipment is required for chemical oxidation, including storage
vessels for the chemicals, metering equipment, contacting vessels, and instru-
mentation for monitoring pH and the degree of completion of oxidation.
Data are not available for the performance of chemical oxidation in the
treatment of Lurgi gasification aqueous wastes. Preliminary results of ozona-
tion of aqueous waste from another coal conversion process bench scale faci-
lity showed reductions in phenols and polynuclear aromatic hydrocarbons of 95
to 98% with contacting times of 15 minutes or less. Other laboratory tests
showed the following removals for an ozone dosage of 325 mg/L and 90 minutes
contact time:
Influent Removal. %
COD 318 50
BOD, 142 58
TOC 93 46
Application of chemical oxidation to wastewaters from synthetic fuels
facilities have thus far been confined to bench- or pilot-scale studies, so
reliability data are lacking for full-scale treatment plants. Mechanical
reliability should be quite high, considering the simplicity of the equip-
ment.
The estimated capital investment required for wastewater ozonation at a
dosage of 300 mg/L and 60 minutes contact time is approximately $15,000 per
m3/hr of wastewater flow. This cost estimate is for treating approximately
300 m3/hr of wastewater at the indicated dosage. The costs for ozonation
will obviously depend on the COD content of the wastewater treated. For Lurgi
applications, significantly higher dosages of ozone could be required unless
the wastewater has undergone fairly extensive pretreatment.
357
-------
Section 4
Aqueous Medium
Generic Control
Residual Organics
Thermal Oxidation
Thermal oxidation or incineration is a high temperature process for the
destruction of a variety of organic wastewater contaminants. Some wastewater
incinerators only heat water (with no major amount of the water vaporized) and
have low energy requirements and low destruction capabilities. The wastewater
incinerators which have the greatest destruction capabilities, and the great-
est energy requirement, are those which introduce the wastewater directly into
the combustion zone (77). For this manual, it is assumed that incinerators
treating wastewaters from Lurgi-based synfuels plants would be of the type
which introduces the wastewater directly into the combustion zone (Figure
4-8). Also, for this application it is assumed that the combustion flue
gases and the vaporized wastewater stream would be exhausted directly into a
quench bath. This approach is similar to that proposed for use at the ANG
Coal Gasification Company North Dakota Project (now called the Great Plains
Gasification Associates project) which will produce SNG using Lurgi technology
(78). For applications in this manual, the incinerator quench system is
operated such that the offgas temperature is approximately 350 K. The quench
system blowdown (which removes wastewater TDS which is not destroyed or does
not exit with the offgas) is the treated wastewater stream and has a flow rate
essentially equal to the inlet wastewater flow rate. This approach reduces
the amount of water vapor which is lost in the quench offgas stream.
Thermal oxidation is capable of achieving essentially complete destruc-
tion of a wide range of otherwise difficult-to-treat organics. Test data for
pesticide and PCS destruction show over 99.9% destruction. Data are not
available for the incineration of Lurgi aqueous wastes. For this manual ther-
mal oxidation is assumed to achieve 99.9% destruction of COD, BOD, TOC, phe-
nol, organic acids, tars, oils, CN , SCN , NH,, and H2S.
358
-------
WASTEWATER^
STREAM
COMBUSTION
AIR
U>
Oi
THERMAL
OXIDATION
INCINERATOR
QUENCH OFF-GAS
QUENCH
MAKE-UP WATER
INCINERATED
WASTEWATER
(QUENCH SYSTEM
SLOWDOWN)
Figure 4-8. Wastewater incinerator with quench
-------
Section 4
Aqueous Medium
Generic Control
Residual Organics
The incinerator quench offgas stream is estimated to have a flow rate of
170 kg mole for each m3 of wastewater treated. This flow rate estimate
assumes combustion of oil (such as Lurgi byproduct oil) with 15% excess air
and that the quench offgas is saturated with moisture at 75°C. The estimated
composition of the quench offgas stream under these conditions is as follows:
N 51 Vol. %
C02 9 Vol. %
02 1.8 Vol. %
H20 39 Vol. %
NO 90 ppmv
CO 35 ppmv
Hydrocarbons 10 ppmv
Particulate matter 4 g/Nm3
S02 Depends on the fuel sulfur content
The sulfur dioxide content of the offgas will typically be in the range of
150 to 1000 ppmv for liquid fuels with sulfur contents in the range of 0.4 to
2.4 wt. %. Nitrogen oxides in the offgas will depend on the nitrogen content
of both the fuel and wastewater, but are expected to be relatively low.
The particulate matter value is the least certain of the values given.
The portion of this value which is due to fuel combustion products is estima-
ted to be small (0.15 g/Nm3 or less). The major source of particulate mat-
ter is the inorganic portion of the inlet wastewater TDS. The particulate
matter content shown (4 g/Nm3) is based on an assumed inlet wastewater TDS
of 35,000 mg/L. If all of that TDS entered the offgas stream, the particu-
late matter content would be around 10 g/Nm3. Part of that inlet TDS is or-
ganic and is destroyed by thermal oxidation and part of it is removed by the
quench system. It is assumed that 60 percent of the inlet TDS would be re-
moved by these two mechanisms.
360
-------
Section 4
Aqueous Medium
Generic Control
Residual Organics
Thermal oxidation is widely used to dispose of a variety of industrial
organic wastes. Incinerators have been operated for periods exceeding a year
without a forced shutdown. Important factors affecting performance reliabi-
lity are atomization of the waste, location of atomizers with respect to pri-
mary combustor, mixing of the waste with combustion air, combustion tempera-
tures, residence time, and excess air flow. In one synfuels application heat
recovery was not used because of incinerator/quench system reliability consi-
derations (78) .
For thermal oxidation applications in Lurgi-based synfuels plants, a
representative capital investment requirement is $180,000 per m3/hr of
wastewater flow. This cost estimate is for treating approximately 30 m3/hr
of wastewater.
Cooling Tower Oxidation
Cooling tower oxidation describes a natural process which occurs when
wastewaters with appreciable organics loadings are used as cooling tower make-
up. Reactions with oxygen diffusing from the air and the action of bacteria
will reduce the concentration of biodegradable organics in the water. The use
of cooling tower oxidation has thus far been limited to the concentration of
wastewaters containing low levels of easily oxidizable, nonvolatile organics.
Very limited performance data are available for cooling tower oxidation.
In one refinery which used biological treatment effluent as cooling tower
makeup, reductions in phenolics from 12 mg/L in the influent (makeup water) to
0.09 mg/L in the cooling tower blowdown were reported. BOD5 reductions of
about 80% were also reported.
361
-------
Section 4
Aqueous Medium
Generic Control
Residual Organics
Data are not available at present for the performance of cooling tower
oxidation on Lurgi wastewaters. In wastewater treatment examples presented in
Section 4.2.2, wastewaters introduced into the cooling tower are assumed to be
concentrated, but no removal of organic constituents is assumed to occur
(other than those which leave with the cooling tower drift). This assumption
is based on the reasoning that the water has been subjected to strong
oxidizing and stripping treatment prior to entering the cooling tower. Thus,
the organics present should have a relatively low volatility. The degree of
oxidation that will occur with the residual organics in a synfuels wastewater
has not been determined.
Ammonia is expected to be stripped in the cooling tower if it is
present in the wastewaters used as makeup water. The quantity of ammonia
removed is estimated to be ten percent (by mass) of the ammonia in the makeup
for each cycle of concentration, i.e., 10 percent for one cycle, 19 percent
for two cycles, 27 percent for three cycles, etc. The cycles of concentration
predicted for each coal case will vary, depending on the quality and volume of
wastewater produced.
While the use of a cooling tower to oxidize organics and reduce waste-
water volume in a synfuels plant has some potentially significant advan-
tages, it also presents some potential problems. First, contaminant
concentrations different than those encountered in refinery wastewaters can be
expected; phenol concentrations, for example, will probably be higher. Asso-
ciated with this process will be an increased potential for fouling of process
heat exchangers by wastewater contaminants such as particulates, inorganics,
or biologically-generated solids. The potential for biological fouling of
heat transfer surfaces has not been well defined (in data available in the
public domain), but may be high due to the presence of organic/inorganic com-
pounds in the cooling water that will support biological growth. Chlorination
362
-------
Section 4
Aqueous Medium
Generic Control
Residual Organics
of cooling water for biological growth control may not be applicable because
of the potential to form toxic chlorinated organics; other biocides may need
to be used in place of chlorine. Conventional cooling water treatment
chemicals for controlling corrosion and scaling may also not be applicable to
cooling towers using process wastewaters as makeup due to interferences caused
by dissolved organic and inorganic compounds.
Discharge streams from cooling towers include evaporation/drift and blow-
down. When treated process wastewaters are used as cooling tower makeup,
evaporation and drift will include stripped volatile gases such as ammonia as
well as dissolved species present in the water. Cooling tower blowdown will
contain the non-volatile, non-degradable makeup water constituents plus water
treatment chemicals that are added to the system.
Costs associated with using wastewaters as cooling tower makeup are not
available. The economics will depend on savings realized due to reduced plant
demands for raw makeup water and on the overall plant wastewater treatment
scheme and water balance.
363
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Inorganics
4.2.1.6 Processes for Removal of Dissolved Inorganics
Inorganic compounds may need to be removed from Lnrgi gasification plant
aqueous wastes in order to meet discharge considerations or to prevent opera-
tional problems due to scaling and plugging where these streams are to be
recycled/reused in the plant. The degree of inorganics removal that is
desired will depend on the water quality requirements of the various end use
processes or discharge options.
In general, most inorganic treatment processes are designed to lower the
calcium, magnesium, silica, carbonate, and/or sulfate levels in the waste-
water. These species form the majority of the compounds which cause plugging,
scaling, and fouling when their solubility products are exceeded. Usually
dissolved inorganic treatment processes also lower the concentrations of other
inorganic compounds such as heavy metals and trace elements. Reductions
achieved depend on pH, temperature, reagents used, etc.
Processes discussed in this section include chemical precipitation and
ion exchange. Table 4-44 gives a brief overview of the information presented
in the text.
Chemical Precipitation
Chemical precipitation is a process which can significantly reduce the
concentrations of selected dissolved solids in a wastewater stream. The key
to the process is the addition of chemicals which will promote the precipita-
tion of salts containing the components desired to be removed. The precipi-
tated solids can be removed from the treated wastewater by settling and/or
flotation.
364
-------
TABLE 4-44.
TECHNOLOGIES POTENTIALLY APPLICABLE TO TBE REMOVAL OF DISSOLVED
INORGANICS FROM LURGI-BASED SYNFUELS PLANT WASTEWATERS
U)
Technology
Chemical
Precipitation
Ion
Exchange
Use of chemical agents to pro- Ca, Kg, heavy metals,
•ote the precipitation of and alkalinity.
waters.
Substitution of H , Na , OH . or Heavy nctals, F ,
Cl ions for other ionic ape- CN , and scaling
cies; exchange resins regener- species.
ated with acid, base, or salt
solutions.
Variable depending
on constituents.
Typical values are
40% removal for Cr,
50% for Ni, and 20%
for Cu and Hg.
Essential ly coup! etc
removal for most
Ions.
Feed
Requi rement s / Byproduct s
Restrictions and Waste
Line, polymer. Sludge coat ami-
and soda ash nated with heavy
may be re— metals.
quired. Spe-
and dosages
based on tests.
Begenerants, Spent regener ants
sins are needed.
found by high
organic loadings
in inlet water.
Comments
Generally followed by
filtration and/or
activated carbon ad-
sorption.
Host effective as a
polishing process.
Clearly applicable to
boiler feedwater
treatment needs. Of
limited use in treat-
containing high con-
centrations of orga-
nic S or dissolved
solids.
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Inorganics
The most common use of chemical precipitation is in lime-soda softening.
This process lowers hardness (dissolved calcium and magnesium) and adjusts
alkalinity by the addition of lime and soda ash in the correct proportions.
It is widely used in industry for the treatment of both raw water and waste-
water. Figure 4-9 shows a typical industrial lime-soda softening system.
Influent wastewater is thoroughly mixed with lime slurry and soda ash which
causes the pH to rise (typically to a range of 9.8 to 10.5). Under these con-
ditions, a variety of compounds can exceed their solubility products although
the process is most often applied to reduce hardness and alkalinity by preci-
pitating calcium and magnesium hydroxide. The solids that precipitate are
frequently finely divided and difficult to dewater. A clarifier is normally
used for solids removal, followed by a gravity-flow granular bed filter. The
gravity filter effluent will normally need pH adjustment before release to
downstream processes. Recycle of the clarifier underflow is used to provide
the seed crystals necessary to sustain reasonable precipitation rates. Clari-
fier underflow blowdown may be further dewatered, if desired, with a device
such as a rotary vacuum filter.
Lime-softener performance depends strongly on influent composition, rea-
gent dosages, and equipment configuration. For cold lime-soda softening,
effluent calcium hardness is typically 50 mg/L (expressed as CaCOj), and non-
sodium alkalinity is typically 35 mg/L (as CaC03). For cold lime-soda soft-
ening, two sets of trace element removal data are:
Element % Removal
Cadmium 0 Not reported
Chromium 88 35
Copper 40 50
Mercury 25 Not reported
Nickel 45 40
Lead 2 27
Selenium 33 Not reported
Zinc 71 36
366
-------
INITIAL pH
ADJUSTMENT
SODA ASH
FEEDER
WASTEWATER
FEED
LIME
FEEDER
D
MIX TANK
CLARIFICATION
0
POLYMER
FEEDER
CLARIFIER
SLUDGE
TO
DISPOSAL
FILTRATION
DEEP
BED
FILTER
FINAL pH
ADJUSTMENT
ACID
FEEDER
0
D
MIX TANK
1
TREATED
WATER
Figure 4-9. Process flow diagram for lime/soda softening system
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Inorganics
Trace element concentrations in coal gasification wastewaters are highly
dependent on the concentrations of those elements in the coal. Prediction of
trace element removals and concentrations within a specific wastewater treat-
ment system requires detailed coal feedstock and treatment system design
information. Trace element balances must be determined which account for
removals, recycle effects, reactions, and precipitation/scaling tendencies.
Since this level of detail is beyond the scope of this manual, the levels of
trace elements in treated wastewaters has not been estimated.
This manual does, however, give estimated capital and operating costs for
some potential chemical precipitation applications within the Lurgi-based syn-
fuels plants examined. For these example applications, costs are based on the
wastewater stream flow rates involved and assumed typical chemical addition
requirements.
The major waste produced by chemical precipitation is the precipitated
solids stream. For lime/soda softening, the precipitated solids consist pri-
marily of insoluble hydroxide salts. Dewatered sludge from a vacuum filter is
estimated to contain 20 weight percent solids.
Lime-soda softening is widely used in industry and is generally very
reliable. The equipment used shows a high degree of reliability and is also
easily spared. Fluctuations in temperature, flow rate, and reagent dosage can
lead to process upsets.
For chemical precipitation applications in Lurgi-based synfuels plants, a
representative capital investment requirement is $6000 per m3/hr of waste-
water flow. This estimate is for treating 300 m3/hr of wastewater.
368
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Inorganics
Ion Exchange
The ion exchange process involves a reversible interchange of ions in so-
lution with other ionic species bound to a solid ion-exchange medium. Natural
and synthetic media are available for the removal of both positive and nega-
tive ions. Ion exchange equipment and the operation of the process are simi-
lar to activated carbon adsorption in that the wastewater to be treated flows
through packed beds of ion exchange media until regeneration is required. In
ion exchange, the regenerant is usually a concentrated solution containing the
ionic species to be replaced in the resin matrix. The removed species are
displaced and may be treated further as desired. Solution pH and the presence
of species whose affinity for the given media is greater than that of the spe-
cies to be removed have an impact on the operation of the process.
A properly designed and operated ion exchange system is capable of pro-
ducing a very high quality effluent suitable for boiler feedwater makeup (if
organics are not present) or for other systems requiring high purity water.
The process is reported to be less successful in treating industrial waste-
waters than raw water. Irreversible fouling and reduced removal efficiencies
have been reported.
Regeneration of the ion exchange media produces the only secondary waste
stream from the process. The spent regenerant will contain all the species
reversibly adsorbed from the original wastewater, but in higher concentra-
tions. The volume of the stream will depend upon the frequency of regenera-
tion.
369
-------
Section 4
Aqueous Medium
Generic Control
Dissolved Inorganics
Ion exchange has been successfully utilized in water softening, boiler
water deionization, and chromate recovery from cooling tower blowdown. Quan-
titative onstream availability data are not available.
For ion exchange applications in Lurgi-based synfuels plants, a represen-
tative capital investment requirement is $36,000 per mj/hr of wastewater
flow. This cost estimate is for treating approximately 300 m3/hr of waste-
water containing 3000 mg/L of total dissolved solids.
370
-------
Section 4
Aqueous Medium
Generic Control
Volume Reduction
4.2.1.7 Processes for Volume Reduction
In order to make the disposal of residual treated aqueous wastes more
economical, it may be desirable to reduce their volumetric flow rate. The
three processes discussed in this section are designed to provide that reduc-
tion. They are:
I,
• Membrane separation,
• Forced evaporation, and
• Cooling tower concentration.
Table 4-45 is a brief summary of the information discussed in the text.
In each of these technologies, a portion of the water is removed from the
waste stream, which results in a smaller volume residual stream for disposal.
In the process of doing so, however, the concentrations of contaminants re-
maining in the residual stream are increased. The solubility of the waste
components may limit the ultimate volume reduction of the residual stream.
Another factor which may potentially limit the use of some of these processes
in Lurgi-based synfuels plants is the potential need to extensively pretreat
the wastewaters for the removal of contaminants which may cause operating
problems.
Membrane Separation
Three membrane processes having potential applicability for aqueous waste
treatment are ultrafiltration, reverse osmosis, and electrodialysis. Ultra-
filtration and reverse osmosis are very similar processes in that they both
achieve separations by applying a pressure gradient across a semipermeable
371
-------
TABLE 4-45.
TECHNOLOGIES POTENTIALLY APPLICABLE TO WASTEWATER VOLUME
REDUCTION OF LURGI-BASED SYNFUELS PLANT WASTEWATERS
Technology Technology Principle
filtration, fro» its dissolved consti-
reverse tuent* .
osnosi s. and
electro-
dialysis).
sa te recovery opti onal .
Evaporation by evaporation.
Feed
Requirements/ Byproducts
variou soluble brine .
specie will be de-
tern in d by neatbrane
conditions of process
operat ion.
All nonvolatile ape- None Noncondenaible
brine. brine.
All nonvolatile 73-80% volume Extensive Blowdown
in blowdown. in conventional nay be
cool ing towers. required.
Comments
May be useful as pre-
prior to further
disposal of waste-
ing and fouling with
applicability of this
technology to the
Very stringent
•eats. Process re-
quires significant
•jaounts of energy
(either stea» or
electricity).
treatment .
-------
Section 4
Aqueous Medium
Generic Control
Volume Reduction
membrane. The primary differences between the processes are related mainly to
the properties of the membranes. Due to use of larger pore size membranes,
ultrafiltration is generally not impeded by osmotic pressure and can therefore
be effective at lower operating pressures. In ultrafiltration, which typical-
ly operates from 0.17 to 0.79 MPa, solvent molecules (e.g., water) are allowed
to pass through the membrane while higher molecular weight impurities are
retained. In reverse osmosis, higher pressures, typically up to 7 MPa are
used. Water, light aliphatics capable of hydrogen bonding (e.g., alcohols,
phenol, amines, etc.), and other nonelectrolytes having molecular weights less
than about 200 pass through the membrane while ionic species and heavier
organics are rejected.
Electrodialysis removes ionic species from the original stream by the use
of alternating cation- and anion-ezchange membranes arranged to form a number
of solution compartments. Under an electric potential driving force the
anions in solution tend to migrate toward the anode while cations tend to move
toward the cathode. The alternating ion-exchange membranes result in the de-
pletion of ionic species in half the solution compartments and their concen-
tration in the other half.
Each of these processes is capable of high removal efficiencies of the
species which they are designed to remove. All membrane processes are subject
to fouling and plugging and thus are applicable only to streams having very
low concentrations of suspended solids.
Reverse osmosis is capable of concentrating up to 95 percent of the TDS
present in waste streams. Rejection rates for chlorinated hydrocarbons of
nearly 100 percent have been reported. Electrodialysis is capable of water
recoveries of 80 to 90 percent from wastewaters containing up to 100 mg/L of
373
-------
Section 4
Aqueous Medium
Generic Control
Volume Reduction
dissolved organics; the recovered water can contain as little as 3 to 5 mg/L
of dissolved solids. Removals of from 50 to greater than 90 percent of
ionic compounds from aqueous streams containing from 5,000 to 10,000 mg/L of
such compounds are reported.
Membrane processes produce a stream in which the removed species are
concentrated and another in which they are depleted. Either stream may be
considered a waste depending on the application. In the context of wastewater
concentration, the concentrated stream would be considered the waste stream.
It may be concentrated further by other processes or disposed of.
The reliability of membrane processes is primarily a function of membrane
life, which, in turn, is a function of the nature and extent of fouling and
plugging. For most wastes, membrane life must be determined experimentally.
No data are available for the reliability of membrane technologies applied to
Lurgi wastewaters. However, for the more highly contaminated waste streams
which can be produced by a Lurgi-based facility, pretreatment of the waste-
water will undoubtedly be required to maintain reliable operation of membrane
separation processes.
For reverse osmosis and electrodialysis applications in Lurgi-based
synfuels plants, representative capital investment requirements are $8,000 and
$11,000 per m3/hr of wastewater flow, respectively. These costs estimates
are for treating approximately 300 m*/hr of wastewater containing 3000 mg/L
of total dissolved solids. Brine disposal costs are not included in the
estimates.
Forced Evaporation
Forced evaporation processes are used to reduce the volume of wastewater,
and in most cases, to recover the evaporated water. If few organics are
374
-------
Section 4
Aqueous Medium
Generic Control
Volume Reduction
present in the inlet wastewater, the recovered water is usually high quality
and can be reused after little or no additional treatment. Nonvolatile com-
ponents in the wastewater are concentrated into a small waste brine.
Many types and arrangements of evaporators are possible for reducing the
volume of wastewater and concentrating nonvolatile components. The two prin-
cipal classes are multi-effect evaporators and vapor compression evaporators.
Vapor compression evaporators have lower energy consumption and operating
costs than comparable multi-effect evaporators, while multi-effect evaporators
typically have lower capital costs. This manual addresses only vapor compres-
sion evaporators, mainly because of their lower operating costs and because
some designs have special non—scaling features. However, the choice between
multi-effect evaporators and vapor compression evaporators can be strongly
influenced by the availability of excess low grade steam. In other words, if
excess steam is available, multi-effect evaporators will not have an energy
disadvantage to vapor compression evaporators. Figure 4-10 is a simplified
flow diagram of a vapor compression evaporator.
Scale formation on the evaporation side of the heat transfer surfaces is
avoided by preferential precipitation of solids on seed crystals in the slur-
ry. Also, the small temperature difference across the heat transfer surfaces
ensures that vaporization will occur at the brine—vapor interface rather than
at the brine film-wall interface.
The total solids concentration in the residual brine is maintained at or
below a maximum of about 200,000 to 400,000 mg/L by removing a waste brine
stream. Wastewater streams containing up to 50,000 mg/L of IDS can be treated
by vapor compression evaporation to yield a high purity water product contain-
ing TDS levels less than 10 mg/L. Higher IDS levels in the inlet wastewater
tend to limit the amount of concentration which can be achieved. Vapor com-
pression evaporation systems are generally designed to recover over 90 percent
375
-------
VENT
Evaporator
U)
—i
FEED
Steam
Compressor
CONCENTRATED
WASTE TO
DISPOSAL
PRODUCT
Product
Pump
Recirculation
Pump
Figure 4-10. Vapor compression evaporation system (79)
-------
Section 4
Aqueous Medium
Generic Control
Volume Reduction
of the feed wastewater as product, and recoveries of over 99 percent are
possible. For this manual, a maximum concentration of 92 percent has been
assumed.
The only significant secondary waste stream produced by forced evapora-
tion is the concentrated brine. This stream will contain all of the nonvola-
tile components in the inlet wastewater. If the inlet wastewater has been
pretreated to remove dissolved gases and volatile species, then the recovered
water will be a high quality byproduct stream which can be reused. If dis-
solved gases and volatile species are in the inlet wastewater, a gaseous
secondary waste stream could be produced and/or the recovered water could be
contaminated. The composition of the gaseous waste stream obviously depends
on the inlet wastewater components. For some applications, the concentrated
brine could be further treated via crystallization techniques to produce a
solid waste and additional recovered water.
Small compression evaporators were developed about 100 years ago and
thousands have been used for desalting seawater (typically shipboard) and
brackish water. Hundreds more have been applied in the chemical industries.
No specific reliability measures are reported in the open literature. The pro-
cess uses standard equipment and operations, which tends to indicate adequate
reliability.
For vapor compression evaporation applications in Lurgi-based synfuels
plants, a representative capital investment requirement is $50,000 per m3/hr
of wastewater flow. This estimate is for treating approximately 300 m3/hr
of wastewater at an overall volume reduction of 92 percent.
377
-------
Section 4
Aqueous Medium
Generic Control
Volume Reduction
Cooling Tower Concentration
When wastewaters are used for cooling tower makeup, two beneficial proces-
ses can occur. The first, oxidation of residual organics in the makeup water,
was discussed in Section 4.2.1.5. The second is the reduction in waste volume
which occurs as a result of the evaporative cooling process. The major incen-
tive for using process wastewaters in cooling towers is the volume reduction
which occurs. Concentration increases of 4 to 5 times compared to the inlet
water are common for the blowdown from conventional recirculating cooling
towers, represening a 75-80 percent volume reduction. This concentrating
capability can be effectively used to balance wastewater flows and reduce
downstream wastewater treatment costs in a Lurgi gasification facility.
The desire to use treated wastewater as cooling tower makeup may result
in the use of more extensive upstream treatment to produce an acceptable
quality water for makeup to the cooling system. Also, more expensive cooling
water treatment approaches may be necessary to avoid the formation of toxic
byproducts (e.g., the formation of chlorinated phenols) or scale, or excessive
corrosion in the circulating cooling water. These added costs must be weighed
against the cost savings accrued due to decreased demand for cooling tower
makeup water or raw water supplies, as well as possible cost savings in down-
stream treatment processes due to the smaller volume of wastewater to be
treated.
378
-------
Section 4
Aqueous Medium
Generic Control
Disposal Processes
4.2.1.8 Disposal Processes
Four processes for the disposal of aqueous wastes are discussed in this
section. They are typical of alternatives that may be available at locations
across the United States based on current and proposed practices in other in-
dustries. They include:
• Surface discharge,
• Deepwell injection,
• Surface impoundment, and
• Codisposal with ash.
Table 4-46 briefly summarizes the information about these processes presen-
ted in the following tezt.
The viability and costs of any of these alternatives depends on a number
of site-specific factors, as well as the required level of pretreatment to
render the wastewater suitable for disposal.
Surface Discharge
The technical aspects of discharging treated wastewater streams from
Lurgi gasification facilities are fairly simple. In particular, the ability
of the surface water body to assimilate the pollutants remaining in the treat-
ed wastes must be considered carefully before this option can be implemented.
It is likely that extended treatment will be desired in order to reduce
levels of pollutants such as residual organics and trace metals remaining in
many Lurgi wastewater streams prior to surface discharge.
379
-------
TABLE 4-46. TECHNOLOGIES POTENTIALLY APPLICABLE TO THE DISPOSAL OF RESIDUALS
FROM THE TREATMENT OF LURGI-BASED SYNFUELS PLANT WASTEWATEHS
CO
00
O
Technology
Surface
Oi scharge
Deep Veil
Injection
Surface
Removal
a receiving body of surface
water.
Wastes are pumped into sub- Entire stream. 100%
and from potentially useful
aquifers.
Wastes are placed in a con- All nonvolatile 100%
evaporated. Beat .
•ized with gasifier
and/or boiler ash for
disposal .
Feed
Requi rements/
Restrictions
Effluent discharge
limitations.
•ove particnlates
(>5 ji») and organ-
ics to avoid plug-
ging of receiving
formation. Volume
reduction stay be
economical .
tile organic
compound concen-
trations should
be low to avoid
pheric emissions.
Volume reduction
prior to impound-
ment may be eco-
nomical .
e azar ons
be desired.
Byproducts
and Waste
None
None
Offgases from
evaporation of
volatile spe-
cies* residue,
and leachate
(potentially) .
(potentially);
diipottl dis-
Coaments
•ent il I ifcely to be
required. Disposal
technique itself is
extremely sl>ple.
Deaonstrated in nuaer-
ons applications and
Lurgi-based synfnels
plant*.
Dte of technique
lialted to locations
with available land
and net evaporation
B/year.
Dae of this technique
depends on the effects
of residual wastewater
contaainants concen-
trations and their
environmental avail-
ability.
-------
Section 4
Aqueous Medium
Generic Control
Disposal Processes
Deepwell Injection
Deepwell injection is an aqueous waste disposal technique in which the
waste is pumped into a suitable subsurface formation via a well. A deepwell
disposal system consists of a surface facility for handling and pumping the
waste liquid, a specially constructed well or wells, and a subsurface disposal
zone.
Some wastes may require pretreatment prior to disposal by deepwell injec-
tion in order to remove specific substances from the waste which could plug
the disposal zone formation and/or damage equipment. Processes which may
potentially be required include oil separation, suspended solids removal,
neutralization, heavy metals removal, and/or organics removal.
Injection wells are usually cased and cemented to prevent upward movement
of waste fluids. Maximum injection pressures are set by regulations or
engineering calculations so as to avoid fracturing of the receiving formation.
Operating pressures are set by field tests. Injection zones must be below the
deepest underground source of drinking water in the vicinity of the disposal
site. Few disposal wells deeper than 1800 meters have been constructed to
date due to high costs and because satisfactory disposal zones have usually
been found at lesser depths.
A well-designed and controlled deepwell system injecting properly pre-
treated waste into a suitable receiving formation should be capable of dispos-
ing of large volumes of aqueous wastes over a number of years. Deepwell
injection requires little surface land and permanently removes the waste from
contact with air, surface water, usable groundwater, and the surface of the
ground. It may not be a viable option for some locations due to the lack of
suitable injection zones and/or if extensive pretreatment is required.
381
-------
Section 4
Aqueous Medium
Generic Control
Disposal Processes
Secondary wastes are not generated by deepwell injection, however, pre-
treatment prior to disposal may generate secondary wastes.
Deepwell injection has been used to dispose of industrial wastes for over
25 years. Related experience has been provided over an even longer period by
the large number of wells injecting oil field brines. Process reliability
depends upon careful site selection, proper well completion and casing, and
good control over waste pretreatment and pumping pressure.
For deep well applications in Lnrgi-based synfuels plants, a representa-
tive capital investment requirement is $30,000 per m3/hr of wastewater.
This estimate is for disposing of about 65 m3/hr of concentrated wastewater
in a well 3200 m deep. Flow rates above 65 ms/hr would require additional
wells.
Surface Impoundment
Surface impoundments are widely used in industry to provide for temporary
or permanent retention of waste liquids, slurries, and sludges. They are
frequently constructed in a natural depression or an artificial excavation
with earthen dikes surrounding the impoundment area. They may be lined with a
variety of natural or man-made materials including clay, concrete, and thin
sheets of various plastics.
Wastewater routed to an impoundment may be discharged or recycled after
settling of solids or natural biological degradation, or may be allowed to
evaporate in place. Residual sludges or dry solids may be periodically re-
moved for ultimate disposal elsewhere, or the impoundment may be,closed with
the solids left in place.
382
-------
Section 4
Aqueous Medium
Generic Control
Disposal Processes
If properly designed and operated, surface impoundments should result in
minimum environmental contamination. Their use as evaporation ponds will be
limited to areas having sufficient net evaporative losses. Their major draw-
back is the need for relatively large areas of land.
Potential secondary wastes from surface impoundments include volatile
contaminants which may be present in the air around the impoundment and
leachate. Due to pretreatment, the quantities of air contaminants will pro-
bably be small. The quantity of leachate escaping is highly dependent on the
nature and integrity of the impoundment liner.
Surface impoundments have been widely used for disposing of various
industrial and municipal wastes. When properly designed and operated, poten-
tial degradation of groundwater and surface water should be minimized. The
major design concern is to minimize the probability for leachate migration
through the impoundment liner. The long term integrity of either natural or
artificial liners has not been established.
A representative capital investment requirement for disposing of 30
mj/hr of wastewater is $120,000 per m*/hr of wastewater flow.
Codisposal with Ash
A potential disposal alternative for treated wastewaters from a Lurgi
gasification facility is codisposal with gasifier and/or auxiliary boiler ash.
The use of this disposal method is dependent on the effects of the addition of
the treated wastewater on overall contaminant concentrations and their leach-
abilities. Disposal options for solid wastes are discussed in Section 4.3.
383
-------
Section 4
Aqueous Medium
Stream Control
Organic
4.2.2 Control Applications for Specific Streams Containing Primarily
Organic Compounds
Waste streams included in this source type are gas liquor, Rectisol
still bottoms, synthesis wastewaters, and secondary wastewater streams from
pollution controls. Examples of the application of specific controls to each
of these wastewater streams are given in Sections 4.2.2.1 through 4.2.2.4, re-
spectively. Each of the control examples shows the performance of a single
treatment step on a specific waste stream.
For each example, the following types of information are given (as
available):
• influent and effluent wastewater compositions and flow rates,
• byproduct and secondary wastestream compositions and flow
rates,
• capital investment requirements, and
• total annualized costs
Where appropriate, information is provided on the impacts that different coal
feed characteristics and/or process changes would have on the example given.
The Rosebud coal case is used for each of the examples and any significant
differences between that case and the Illinois No. 6 coal case are discussed.
The Dunn County lignite case generally has flow rates and compositions which
are within the range of the Rosebud/Illinois No. 6 case data.
In Section 4.2.2.5 examples are given of the treatment and ultimate dis-
posal of organic-containing wastewaters in several integrated treatment sys-
tems.
384
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
4.2.2.1 Gas Liquor (Stream 210)
Gas liquor will be the largest wastewater stream continuously generated
in a Lurgi-based synthetic fuels facility. Its flow rate is determined mainly
by the moisture content of the raw Lurgi synthesis gas. The gas moisture con-
tent in turn is a function of the moisture content of the coal gasified and
the quantity of steam (per unit of coal) fed to the gasifier. Higher flow
rates of gas liquor are expected when high moisture content coals, such as
lignites, are gasified, or when high rank coals requiring high steam rates,
such as Illinois No. 6 bituminous coal, are gasified. The flow rates esti-
mated in this manual for the non-SNG synthesis cases are summarized below.
For the SNG cases, approximately 5 percent of the raw gas moisture is lost in
shift conversion, thus reducing the gas liquor flow rate.
Subbituminous - 293 m3/hr
Bituminous - 495 ms/hr
Lignite - 433 m3/hr
Gas liquor contains a complex mixture of organic pollutants many of which
are present in high concentrations. For example, TOC loadings in gas liquor
are estimated in this manual to range from 3000 to over 7500 mg/L and BOD,
to range from 4600 to almost 11,000 mg/L. Phenolic compounds and fatty acids
are two classes of organics which have been identified and quantified in gas
liquor. Estimated concentrations range from 2300 to 4500 mg/L for phenolics
and 200 to 2000 mg/L for fatty acids. In general, the mass loadings of organ-
ics in gas liquor are expected to be similar for any coal gasified. However,
due to the varying quantities of gas liquor generated, the concentrations of
these components can vary significantly. For example, the mass flow rates of
phenolic compounds in gas liquor are estimated at 1100 to 1300 kg/hr, but
their concentrations range from 2300 to 4500 mg/L.
385
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
Gas liquor will also contain high concentrations of dissolved C02 and NH3
as well as lower levels of dissolved HaS and HCN. The concentrations of the
nitrogen- and sulfur-containing gases depend on factors such as nitrogen and
sulfur contents of the coal and the gasifier operating conditions. Compared
to the levels of organics and dissolved gases, gas liquor contains only minor
amounts of dissolved inorganics.
For the reasons discussed above (high flow rate and high pollutant load-
ings), the treatment of gas liquor will be the most important consideration in
the design of the wastewater treatment system in a Lurgi-based synfuel
facility. The design of the treatment system will be heavily influenced by
the design of the overall facility water system. This in turn will depend on
factors such as 1) the availability of plant makeup water (in water—short
areas it may be desirable to treat and reuse gas liquor within the plant in
order to reduce makeup water requirements), 2) environmental considerations,
3) technical considerations (some processes within the treatment system may
require wastewater pretreatment to remove/destroy certain constituents in
order to operate effectively and/or reliably, and 4) economic considerations
(some processes may be included in order to reduce the size and thus the costs
of downstream treatment steps).
Components of the treatment system for gas liquor will likely include
processes for removing organics, dissolved gases, and/or dissolved inorganics,
as well as wastewater concentration and ultimate disposal techniques. Because
of the expected importance of gas liquor to the overall plant treatment
system, several examples of applications of control techniques are given in
this section (4.2.2.1). Examples of integrated treatment systems for gas
liquor (and similar waste streams that likely would be combined with gas
liquor for treatment) are presented in Section 4.2.2.5.
386
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
Removal of Suspended Solids. Tars, and Oils
Suspended solids, tars, and oils may be removed from wastewater streams
by screening, gravity separation, coagulation/flocculation, air flotation, and
filtration. In Lurgi-based synfuels plant designs, suspended solids, tars,
and oils typically are removed by gravity separation in the gas liquor separa-
tion unit. Gravity separation relies upon the different densities of immisci-
ble oil, water, and solids. Although the use of gravity separation for
removal of suspended solids, tars, and oils from gas liquor involves the
application of a wastewater treatment process to a primary wastewater stream,
this example will not be discussed in depth in this section. The gas liquor
separation unit in a Lurgi-based synfuels plant is part of the base plant
since it is required to upgrade the gas liquor so that a part of it can be
recycled to quench the raw Lurgi gas. This process application is mentioned
here only to point out the use of this wastewater treatment process on gas
liquor in the base plant. In further discussions, the term "gas liquor"
refers to the gas liquor stream after it leaves the gas liquor separation unit
(this stream is also known as "phenolic water" in some Lurgi synfuels plants).
Removal of Bulk Organics
Solvent extraction and wet air oxidation are processes which may be used
to remove bulk organics from Lurgi gas liquor. Solvent extraction has been
proven in commercial applications on gas liquor and is the example given
here.
Table 4-47 gives the estimated influent and effluent wastewater compo-
sitions and flow rates for treating gas liquor by solvent extraction for
the Rosebud coal case. The solvent extraction process wastewater flow rates
387
-------
TABLE 4-47.
ESTIMATED REMOVAL OF BULK ORGANICS FROM
GAS LIQUOR BY SOLVENT EXTRACTION
Wastewater Flow Rate,a (m»/hr)
Constituent Compositions (mg/L)
COD
BOD
TOC
Phenol
Organic Acids
Tars and Oils
CN~ (as HCN)
SCN-
NHt (as NHs)
Cl~
COf (as CO*)
S= (as HaS)
Influent
293
22,800
10,600
7,640
4.540
2,000
150
5
6
7,610
25
13,600
55
Estimated
Percent
£
Removal Effluent
293
46.0 12,320
70.9 3,090
44.6 4,230
93.6 290
15.0 1,700
66.7 50
5
6
7,610
25
13,600
55
rates and compositions axe calculated values for the Rosebud coal case.
Influent stream is assumed to be gas liquor from the base plant (i.e., after
removal of suspended solids, tars, and oils).
A byproduct phenol stream (1330 kg/hr) is also produced.
388
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
for the Illinois No. 6 coal case are higher than for the Rosebud coal case
(approximately 500 m»/hr versus about 300 m3/hr), and the individual
stream component concentrations vary due to the different gas liquor
composition. For example, the Illinois coal case COD, BOC, and TOC loadings
are significantly lower; but CN , SCN , and Cl , levels are higher (see
Section 3). Tars and oils in the solvent extraction effluent are assumed to
be 50 mg/L for all cases.
The phenolic compounds in most gas liquors are estimated to be
approximately 85 percent monohydric phenols and 15 percent polyhydric
phenols. Therefore, based on the estimated solvent extraction removal
efficiencies of 99.5 percent for monohydric phenols and 60 percent for
polyhydric phenols, this example shows an estimated removal of total phenols
of 93.6 percent. These recovered phenolic compounds plus recovered oils and
organic acids (about 15 percent of the inlet organic acids) comprise the by-
product phenol stream. For this Rosebud coal case example the byproduct
phenol rate is 1330 kg/hr. No other significant byproducts or secondary
waste streams are produced from this process.
The application of solvent extraction in this example (Rosebud coal case)
is estimated to require a total capital investment of ilO.6 millon. Total
annualized costs (including capital recovery and byproduct credit) are about
$2.7 million per year.
Removal of Dissolved Gases
Processes which may be used to remove dissolved gases from Lurgi gas
liquor include steam stripping, PHOSAM-W, Chevron WWT, inert gas stripping.
389
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
and vacuum distillation. Of these the PHOSAM-W process has been included in
several proposed designs and is given here as an example. This example as-
sumes that the gas liquor stream has been pretreated to remove bulk organics.
Table 4-48 gives the influent and effluent wastewater compositions and
flow rates associated with the application of a PHOSAM-W process to remove am-
monia and other dissolved gases from pretreated Lurgi gas liquor (for the
Rosebud coal case). The wastewater compositions shown in Table 4-48 are
equivalent to 99+ percent removal of carbonate, 98 percent removal of ammonia
and hydrogen sulfide, and 50 percent removal of hydrogen cyanide.
The PHOSAM-W process recovers ammonia as a byproduct and produces an
acid gas secondary waste stream (Stream 428) which contains the other removed
dissolved gases. The flow rates of these streams are also shown in Table
4-48. For the Rosebud coal case, the acid gas waste stream is approximately
(by volume wet basis) 75% C02, 0.4% H4S, and 200 ppmv HCN. The balance is
water vapor plus a small amount of residual NH3. For the Illinois No. 6
coal case the acid gas composition is estimated to be 70% C02, 3.4% HjS, and
0.3% HCN, with the balance being water vapor and residual NH3.
The total capital investment requirement for the Phosam-W process in this
application (Rosebud coal case) is estimated to be $11.8 million while total
annualized costs (including capital recovery and by—product credit) are esti-
mated to be $1.5 million per year.
Removal of Dissolved Organics
Dissolved organics could be removed from Lurgi gas liquor by activated
sludge, trickling filters, rotating biological contactors, or lagoons.
390
-------
TABLE 4-48. ESTIMATED REMOVAL OF DISSOLVED GASES
FROM GAS LIQUOR BY PHOSAM-W
Wastewater Flow Rate,* (m»/hr)
Constituent Compositions. (mg/L)
COD
BOD
TOC
Phenol
Organic Acids
Tars and Oils
CN~ (as HCN)
SCN~
NHt (as NH3)
Cl~
COf (as COi)
S= (as H2S)
Influent
293
12,320
3,090
4,230
290
1,700
50
5
6
7,610
25
13,600
55
Estimated
Percent
Removal Effluent0
292
12,320
3,090
4,230
290
1,700
50
50 2.5
6
98 150
25
99+ 1
98 1
"Flow rates and compositions are calculated values for the Rosebud coal case.
Influent stream is assumed to have been pretreated for removal of bulk
organics.
Other discharges are byproduct ammonia (2190 kg/hr) and an acid gas secondary
waste stream (120 kg mole/hr) containing COz, H»S, HCN, water vapor, and
residual ammonia.
391
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
The most widely used process to remove dissolved organics is activated sludge
and that process is given here as an example for the treatment of gas liquor.
For this example the air activated sludge process will be used, but other
variations are available (such as oxygen activated sludge and powdered activa-
ted carbon enhancement of activated sludge). Table 4-49 shows the influent
and effluent wastewater flow rates and compositions for air activated sludge
treatment of pretreated Lurgi gas liquor (for the Rosebud coal case). With
the removals shown in Table 4-49, the effluent from the air activated sludge
process (Rosebud coal case) is estimated to have COD and BOD loadings of
approximately 2500 and 300 mg/L, respectively. For the Illinois No. 6 coal
case, these COD and BOD values are about 750 and 90 mg/L, respectively. The
Illinois No. 6 case loadings are lower because that case's gas liquor has
lower COD and BOD levels.
Biodegradable species such as residual phenols and other organics, ammo-
nia, and cyanides are removed in the activated sludge unit with the efficien-
cies shown in Table 4-49.
The activated sludge unit for this example produces a secondary waste
stream of biological oxidation sludge (Stream 431). This stream has a flow
rate of 1620 kg/hr and is approximately 20 weight percent solids (after
dewatering).
The total capital investment for activated sludge treatment of the
Rosebud case gas liquor stream is estimated to be $14 million. Total
annualized costs (including capital recovery) are estimated to be $2.9 million
per year. For the Illinois No. 6 coal case, these two costs are estimated to
be ilO.8 million and 2.2 million per year for total capital and total
392
-------
TABLE 4-49. ESTIMATED REMOVAL OF DISSOLVED ORGANICS FROM
GAS LIQUOR BY ACTIVATED SLUDGE
Wastewater Flow Rate,8 (rnVhr)
a
Constituent Compositions. (mg/L)
COD
BOD
TOC
Phenol
Organic Acids
Tars and Oils
OT (as HCN)
SCJT
NHt (as NHs)
Cl~
S= (as H»S)
Influent
292
12,320
3,090
4,230
290
1,700
50
2.5
6
150d
25
1
Estimated
Percent
Removal
80
90
80
95
95
70
70
70
d
Effluent0
291
2,460
310
850
15
85
15
0.75
1.8
5d
25
1
fplow rates and compositions are calculated values for the Rosebud coal case.
Influent stream is assumed to have been pretreated for bulk organics and
dissolved gases removal.
A secondary waste stream of biological oxidation sludge (1620 kg/hr) is also
.produced.
Supplemental ammonia is added to supply nutrient to the organisms for the
Rosebud coal case.
393
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
annnalized costs, respectively. The lower values for the Illinois coal case
result from the lower total BOD, loading associated with gas liquor from
Illinois No. 6 coal.
Removal of Residual Organics
Residual organics may be removed from Lurgi gas liquor by activated car-
bon adsorption, chemical oxidation, thermal oxidation, and cooling tower oxida-
tion. In this section examples will be given of the application of activated
carbon, thermal oxidation, and cooling tower oxidation to gas liquor from
Rosebud coal. These examples assume that the gas liquor has been pretreated
by removal of bulk organics, dissolved gases, and dissolved organics.
Removal of residual organics bv activated carbon adsorption—Activated
carbon may be used to adsorb residual organics and other species from pre-
treated gas liquor. Table 4-50 gives the estimated influent and effluent
wastewater flow rates and compositions for treating gas liquor from Rosebud
coal by activated carbon adsorption.
The adsorbed constituents accumulate in the carbon bed and must be
removed periodically either by replacement or thermal regeneration of the car-
bon; carbon replacement is normally limited to smaller installations where the
carbon is supplied in disposable or returnable containers. For this applica-
tion (Lurgi gas liquor), onsite regeneration would be more economical, and
therefore, secondary waste streams of regeneration flue gas (Stream 436) and
carbon fines or char from oxidation of the adsorbed organics would be
produced. The carbon fines and char are produced in small amounts and would
normally remain in the bed and eventually be removed along with the spent
carbon (Stream 435). The regeneration process produces an offgas stream
394
-------
TABLE 4-50. ESTIMATED REMOVAL OF RESIDUAL ORGANICS FROM
GAS LIQUOR BY ACTIVATED CARBON ADSORPTION
Wastewater Flow Rate,* (m3/hr)
Constituent Compositions. (mg/L)
COD
BOD
TOC
Phenol
Organic Acids
Tars and Oils
OT (as HCN)
SCN~
NHt (as NH3)
Cl~
S- (as H»S)
Influent
291
2,460
310
850
15
85
15
0.75
1.8
5
25
1
Estimated
Percent
Removal
80
60
70
99.9
70
99
50
50
Effluent0
291
490
120
250
0.01
26
0.15
0.38
0.9
5
25
1
fFlow rates and compositions are calculated values for the Rosebud coal case.
Influent stream is assumed to have been pretreated for bulk organics,
dissolved gases, and dissolved organics removal.
Secondary wastestreams produced are an intermittent carbon regeneration
offgas stream (about 180 kg mole/hr average) and a minimal amount of spent
carbon.
395
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
containing some carbon monoxide and any sulfur species that are in the
regenerator fuel. NO emissions from this stream are not expected to be
significant. Control measures for this stream are discussed in Section 4.1.
For this example, (Rosebud coal case) the estimated total capital cost is
$4.6 million. Total annualized costs are estimated to be $1.6 million per
year.
Removal of residual organics by thermal oxidation—One method of remov-
ing residual organics from gas liquor is thermal oxidation (incineration).
The example given here assumes that for economic reasons the wastewater has
been concentrated prior to incineration. Table 4-51 gives the estimated in-
fluent and effluent flow rates and compositions for the incineration of pre-
treated gas liquor. The effluent composition corresponds to 99.9 percent
destruction of thermally oxidizable constituents. Thermal oxidation is capa-
ble of 99.96 to 99.99 percent destruction of many organic compounds (such as
DDT, chlordane, and PCBs). Therefore the actual removals may be higher than
the 99.9 percent value shown in this example.
The only secondary waste stream produced is the wastewater incinerator
quench offgas (Stream 440). The composition of this stream was estimated
using emission factors for oil combustion (45) and an assumed combustion of
Lurgi byproduct oil (0.5 wt percent sulfur) with 15 percent excess combustion
air. Particulate emissions were estimated assuming 40 percent of the IDS in
the inlet wastewater appears as particulates in the quench offgas. For this
case a total flow rate of 4000 kg-moles/hr is estimated with the following
concentrations of pollutants: 200 ppmv S02; 90 ppmv NO ; 35 ppmv CO; 10
ppmv hydrocarbons; and 4 g/Nm3 particulate matter. For this example, 23
mj/hr of quench make-up water is required.
396
-------
TABLE 4-51.
ESTIMATED REMOVAL OF RESIDUAL ORGANICS FROM
GAS LIQUOR BY THERMAL OXIDATION
Wastewater Flow Rate,* (mj/hr)
Constituent Compositions. (mg/L)
COD
BOD
TOC
Phenol
Organic Acids
Tars and Oils
CN~ (as HCN)
SCN~
NHt (as NHs)
Cl~
S= (as H*S)
Influentb
23
30,800
3,860
10,600
180
1,060
190
9.4
23
63
310
13
Estimated
Percent
Removal
99.9
99.9
99.9
99.9
99.9
99.9
99.9
99.9
99.9
99.9
Effluent0
23
31
3.9
11
0.18
1.1
0.19
0.01
0.02
0.06
310
0.01
rates and compositions are calculated values for the Rosebud coal case.
Influent stream is assumed to have been pretreated for bulk organics,
dissolved gases, and dissolved organics removal and to have been
concentrated.
An incinerator quench offgas secondary waste stream is produced (4000 kg
mole/hr).
397
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
Thermal oxidation of this stream (Rosebud coal case) is estimated to
require a capital investment of $5.0 million, while total annualized costs
(including capital recovery) are estimated to be 5.8 million per year.
Removal of residual organics by cooling tower oxidation—Although cool-
ing towers have been successfully used in several industrial applications to
remove residual organics, ammonia is the only constituent assumed to be
removed (stripped) in the cooling tower (other than the small amount of all
constituents that are lost in the cooling tower drift). All other consti-
tuents are assumed to be retained in the recirculating cooling water and hence
appear in the cooling tower blowdown. Because of the loss of water due to
evaporation, the concentrations of dissolved constituents in cooling tower
blowdown are greater than in the inlet makeup water. Table 4-52 shows the
influent and effluent wastewater flows and compositions for using pretreated
Lurgi gas liquor from Rosebud coal as cooling tower makeup.
Stripping of ammonia in the cooling tower is estimated to be ten percent
(by mass) for each cycle of concentration. For this Rosebud coal example, the
cooling tower is assumed to be operating at approximately 10 cycles of
concentration. The ammonia concentration in the effluent (blowdown) would
have been approximately 50 mg/L if no stripping had occurred.
Secondary waste streams produced are cooling tower evaporation (270,000
kg water/hr) and drift (1900 kg/hr) (Stream 306). The evaporation stream will
contain most of the ammonia which is removed unless organics are biologically
destroyed in the cooling tower. In that instance some of the ammonia will be
consumed by the biological oxidation process.
398
-------
TABLE 4-52. ESTIMATED COMPOSITIONS FOR USE OF TREATED
GAS LIQUOR AS COOLING TOWER MAKEUP
Wastewater Flow Rate,a (m3/hr)
Constituent Compositions. (mg/L)
COD
BOD
TOC
Phenol
Organic Acids
Tars and Oils
CN~ (as HCN)
SCN~
NHt (as NHS)
Cl~
S=(as H2S)
Influent
(Makeup)
291
2,460
310
850
15
85
15
0.75
1.8
5
25
1
Effluent0
(Slowdown)
28
24,000
3,000
8,200
140
830
150
7.3
18
17
240
9.7
aFlow rates and compositions are calculated values for the Rosebud coal case
and assumed cooling tower operation at 10 cycles of concentration.
Influent stream is assumed to have been pretreated for removal of bulk
organics, dissolved gases, and dissolved organics. For this example, 8,600
kg/hr of additional makeup water is required.
Secondary waste streams produced are evaporation (270,000 kg water/hr) and
drift (1900 kg/hr).
399
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
The costs of using cooling tower oxidation/concentration have not been
estimated in this manual due to the highly site-specific factors involved.
Removal of Dissolved Inorganics
Processes which could be used to remove dissolved inorganics from Lurgi
gas liquor include chemical precipitation and ion exchange. The example given
in this section is the use of chemical precipitation. This example assumes
that the gas liquor stream has been pretreated to remove bulk organics,
dissolved gases, and dissolved organics.
Chemical precipitation is effective in reducing the concentrations of a
number of dissolved inorganics which contribute to the hardness, alkalinity,
and total dissolved solids contents of waters. This treatment process is also
capable of reducing trace element concentrations. Since inadequate data are
available on the dissolved inorganics present in Lurgi gas liquors, effluent
composition from chemical precipitation treatment cannot be estimated.
For the Rosebud coal case, the pretreated gas liquor that might be
treated by chemical precipitation would have a flow rate of about 290
m3/hr. Assuming chemical dosages as listed below, the total capital invest-
ment for chemical precipitation treatment is estimated to be $1.8 million.
Total annualized costs (including capital recovery) are estimated to be
$530,000 per year.
Reagent Dosage (g/m3)
93 % hydrated lime 127
Soda ash 65
Polymer flocculant 2
Sulfuric acid 61
400
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
The only secondary waste stream produced by chemical precipitation is the
precipitation sludge (Stream 433). This material consists mainly of car-
bonates and hydroxides and is estimated to be produced at the rate of 0.35 kg
(dry basis) per m3 of wastewater treated. For this example, the chemical
precipitation sludge flow rate is about 510 kg/hr assuming it is dewatered to
20 percent solids.
Volume Reduction
Volume reduction of Lurgi gas liquor may be achieved by membrane separa-
tion, forced evaporation, or cooling tower concentration. The use of the
cooling tower to oxidize/concentrate Lurgi gas liquor was discussed earlier in
this section. The example given here is for forced evaporation of Lurgi gas
liquor for the Rosebud coal case.
Table 4-53 gives the influent and effluent wastewater compositions and
flow rates for reducing the volume of Lnrgi gas liquor by forced evaporation.
The flow rates and concentrations shown in the table are equal to a 92 percent
recovery of influent water. This recovery results in a 12.5 times concentra-
tion increase in the brine effluent and a recovered water stream of 270
m3/hr.
The estimated total capital investment for this application of forced
evaporation is il6 million. The estimated total annualized costs (including
capital recovery) are $4.8 million per year.
Residual Disposal
Four methods of residual disposal are discussed in this manual: dis-
charge to surface waters, deepwell injection, surface impoundment, and
401
-------
TABLE 4-53. ESTIMATED REDUCTION OF GAS LIQUOR VOLUME
BY FORCED EVAPORATION
Wastewater Flow Rate,* (m3/hr)
Constituent Compositions. (mg/L)
COD
BOD
TOC
Phenol
Organic Acids
Tars and Oils
CN~ (as HCN)
SCN~
NHt (as NH3)
Cl~
S= (as HaS)
Influentb
291
2,460
310
850
15
85
15
0.75
1.8
5
25
1
Effluent0
23
31,000
3,900
11,000
180
1,100
190
9.4
23
63
310
12.5
/Flow rates and compositions are calculated values for the Rosebud coal case,
Influent stream is assumed to have been pretreated for bulk organics,
dissolved gases, and dissolved organics.
Effluent concentrations are 12.5 times influent concentration. Ninety-two
percent of the inlet water is recovered as reusable water (270 m*/hr).
402
-------
Section 4
Aqueous Medium
Stream Control
Gas Liquor
codisposal with ash. Two of these methods — discharge and codisposal —
involve no additional costs or equipment beyond pretreatment needs. This sec-
tion gives examples of residual disposal of pretreated Lurgi gas liquor (for
the Rosebud coal case) by deepwell injection and by surface impoundment.
Residual disposal by deepwell in.iection—Table 4-54 .gives the estimated
flow rate and composition of pretreated gas liquor which could be disposed by
deepwell injection. This example assumes that the gas liquor has been
pretreated for removal of bulk organics, dissolved gases, dissolved organics,
and residual organics. For economic reasons, the gas liquor stream is also
assumed to have been concentrated. This method provides for complete disposal
of the gas liquor residual with no byproducts or secondary waste streams
produced. The estimated total capital investment for deepwell disposal of gas
liquor in this example is $1.9 million. Total annualized costs (including
capital recovery) are estimated to be $430,000 per year.
Residual disposal by surface impoundment—Table 4-55 gives the esti-
mated flow rate and composition of pretreated gas liquor which could be dis-
posed of in a surface impoundment (evaporation pond). Assumed pretreatment
steps are removal of bulk organics, dissolved gases, and dissolved organics
plus wastewater concentration.
This disposal method results in two potential secondary waste streams:
evaporation losses from the surface of the pond and any leachate which may
escape through the natural or artificial liner. These streams have not been
quantified for this example, but the evaporative losses will be essentially
the water content of the wastewater stream plus any volatile components.
Total capital investment for this example is estimated to be S3.6
million. Total annualized costs (including capital recovery) are estimated to
be $770,000 per year.
403
-------
TABLE 4-54. ESTIMATED COMPOSITION OF PRETREATED GAS LIQUOR
FOR DISPOSAL BY DEEPWELL INJECTION
Deepwell Injection
Wastewater Flow Rate,a (m3/hi) 23
a
Constituent Compositions. (mg/L)
COD
BOD
TOC
Phenol
Organic Acids
Tars and Oils
CN
-------
Section 4
Aqueous Medium
Stream Control
Rectisol Still Bottoms
4.2.2.2 Rectisol Still Bottoms
Rectisol still bottoms will contain a variety of contaminants including
ammonia, cyanide, sulfide, chloride, and organics at relatively low
concentrations. Hie organics present in this stream will mainly be methanol
which is used as a solvent in the Rectisol process. The low flow rate of
Rectisol still bottoms (10 to 12 m*/hr) will make it economically unattrac-
tive to treat it in a dedicated treatment system. The contaminants present in
this stream are also present in Lurgi gas liquor. Thus, blending and treating
it with gas liquor is a logical approach, especially since its flow rate is
only about three percent of the gas liquor flow.
Rectisol still bottoms do not contain high enough concentrations of
organics or dissolved gas to warrant treatment by solvent extraction or
ammonia stripping. So, blending of Rectisol still bottoms with extracted and
stripped gas liquor is appropriate. Combination of the streams at this point
would minimize the treatment costs of the still bottoms stream and take
advantage of the economies of scale associated with a relatively small
increase in the size of gas liquor treatment facilities.
405
-------
Section 4
Aqueous Medium
Stream Control
Synthesis Wastewaters
4.2.2.3 Synthesis Wastewaters
In the Fischer-Tropsch, methanol, and Mobil M-Gasoline syntheses process-
es, water is produced as a byproduct of the liquefaction reactions and removed
from the liquefaction products during the purification and upgrading pro-
cesses. These Wastewaters contain high concentrations of organic contami-
nants. However, the low concentrations of dissolved gases, dissolved inorgan-
ics, and suspended matter would enhance the reuse potential of this wastewater
after treatment for organics removal. Where reuse of this wastewater is a
priority, treatment in separate facilities to avoid contamination from other
wastewater streams may be considered. However, in most facilities this waste-
water will probably be combined with other organic containing Wastewaters for
treatment.
The organic acids, ketones, and aliphatic and ring compounds found in
these synthesis process wastewaters are expected to be readily biodegradable.
Treatment of these wastewaters in separate facilities by biological oxidation
will require consideration of two critical factors: 1) nutrient requirements
of biological organisms and 2) influent organic concentrations. Since these
wastewater streams will contain little or no dissolved inorganic material,
supplemental phosphorus, nitrogen, and traces of other compounds will need to
be added to maintain a healthy biomass and ensure effective treatment. The
second factor to be considered in treating these wastewaters is the organic
concentration/loading on the treatment unit. Treatment of synthesis process
wastewaters directly could seriously overload the system and cause a treatment
failure. Therefore, dilution of these wastewaters into a range that would be
compatible with the biological treatment unit would be required. To maintain
an influent BOD of 2500 to 3000 mg/L, F-T synthesis wastewater (about 70 to 75
m3/hr) must be diluted, depending on coal type, by a factor of 2 to 3.
406
-------
Section 4
Aqueous Medium
Stream Control
Synthesis Wastewaters
Mobil M synthesis wastewater (about 55 to 60 m'/hr) would have to be diluted
by a factor of three to four depending on coal type. Similarly, methanol
synthesis waste water (about 1 to 5 m3/hr) would have to be diluted from six
to 20 times depending on coal type. The Illinois No. 6 case methanol synthe-
sis wastewater would require the greatest dilution (20 to 1), but it is also
the smallest flow rate (1.4 m3/hr). Dilution of these wastewaters would
require an equalization pond upstream of the biological treatment unit. Over-
sizing a system to handle the larger diluted flow will dramatically increase
the treatment costs of this stream.
Two examples have been developed to illustrate the application of spe-
cific treatment technologies to these synthesis wastewater streams. These
examples are based on treating F-T wastewater but are representative of
treating F-T, methanol, and Mobil M wastewaters.
Table 4-56 gives the estimated influent and effluent wastewater flow
rates and compositions for treating F-T synthesis wastewater (Rosebud coal
case) in an activated sludge unit. The total capital investment requirement
for this treatment step is estimated to be $12 million. Total annualized
»
costs are estimated to be $2.5 million per year. These costs are similar to
those given earlier for treating Rosebud gas liquor, a much larger volume
stream.
Table 4-57 gives the estimated influent and effluent wastewater flow
rates and compositions for removing residual organics from pretreated F—T syn-
thesis wastewater by activated carbon adsorption. The estimated total capital
investment required for this treatment is $2.2 million and the estimated total
annualized costs are $670,000 per year.
407
-------
TABLE 4-56. ESTIMATED REMOVAL OF DISSOLVED ORGANICS FROM
F-T SYNTHESIS WASTEWATER BY ACTIVATED SLUDGE
Wastewater Flow Rate,a (m3/hr)
«
Constituent Compositions. (mg/L)
COD
BOD
TOC
Organic Acids
NHt (as NHs)
Influent
76
11,000
8,000
4,300
11,000
0
Estimated
Percent
Removal
80.0
90.0
80.0
95.0
c
Effluent13
75
2,300
800
860
540
5
Flow rates and compositions are calculated values for the Rosebud coal case.
A secondary waste stream of biological oxidation sludge (1100 kg/hr) is also
produced.
"" Supplemental ammonia is added to supply nutrients to the organisms.
TABLE 4-57. ESTIMATED REMOVAL OF RESIDUAL ORGANICS FROM F-T
SYNTHESIS WASTEWATER BY ACTIVATED CARBON ADSORPTION
Wastewater Flow Rate,* (mVhr)
a
Constituent Compositions, (mg/L)
COD
BOD
TOC
Organic Acids
NHt (as NHs)
Estimated
Percent
Influent Removal
75
2,300 80
800 60
860 70
540 70
5
Effluent0
75
460
320
260
160
5
TFlow rates and compositions are calculated values for the Rosebud coal case.
Influent stream is assumed to have been pretreated by removal of dissolved
organics.
CSecondary waste streams of regeneration offgas and spent carbon are also
produced. Both have small and intermittent flow rates.
408
-------
Section 4
Aqueous Medium
Stream Control
Secondary Wastes
4.2.2.4 Secondary Wastewater Streams
There are two types of potential secondary wastewater streams which will
contain primarily organic, reduced sulfur, and/or reduced nitrogen compounds.
These streams are condensates from tail gas treatment units used to remove re-
sidual sulfur species from acid gas waste streams and scrubber blowdown
streams such as the blowdown from the coal lockhopper vent gas scrubber.
Beavon and SCOT Condensates
The Beavon and SCOT processes are examples of processes which might be
used to remove residual sulfur from acid gas streams in a Lurgi-based synfuels
plant (see Section 4.1). Both of these processes produce a small sour water
blowdown from water scrubber/cooler towers. These condensates will have a
flow rate of approximately 4 mj/hr and will contain about 100 mg/L H2S and
5000 mg/L NH3. Other pollutant species are not expected to be present in
significant amounts.
For this manual, it is expected that a stream of this type and size would
be combined with gas liquor upstream of the dissolved gas removal step. No
other treatment options have been examined for purposes of this manual.
Scrubber Blowdown Streams
The coal lockhopper vent gas scrubber blowdown stream is used as the
basis for example treatment approaches for this type of stream. The composi-
tion of this blowdown stream will vary with the lockhopper vent gas composi-
tion. The vent gas composition, in turn, will depend on the method used to
pressurize the lockhopper. If Lurgi gas is used to pressurize the lockhopper.
409
-------
Section 4
Aqueous Medium
Stream Control
Secondary Wastes
the scrubber blowdown will contain similar contaminants to those found in the
raw gas. If an inert gas is used, the scrubber blowdown will be contaminated
mainly with particulate matter, although some raw gas components may also be
present. The treatment route employed will vary with the blowdown
composition.
Because the contaminants present in this stream will be so similar to
those found in Lurgi gas liquor, it is assumed that this stream would be
routed to the gas liquor separation unit. This treatment approach will have a
negligible impact upon the costs of gas liquor treatment.
410
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
4.2.2.5 Integrated Control Examples for Streams Containing Primarily
Organic Compounds
The previous portions of Section 4.2.2 illustrated the application of in-
dividual wastewater treatment technologies to specific organic—laden streams.
In practice, determining which treatment processes should be applied to which
wastewater streams and in which sequence depends on numerous factors. Devel-
oping a wastewater management plan is a detailed process requiring many site-
specific inputs and economic and technical evaluations. It is not within the
scope of this manual to develop wastewater management plans for Lurgi-based
synfuels plants. However, it is felt that presenting some examples of the
sequential application of controls can aid users of this manual. These
examples, some of which have features similar to publicly-available proposed
treatment schemes in Lurgi-based synfuels plants, illustrate a few of the pos-
sible integrations of treatment technologies and residual disposal options.
To a large extent, a wastewater management plan is driven by the residual
disposal options available at the plant site. For this manual, four basic
methods of residual disposal are assumed to be potentially applicable to U.S.
synfuels plants:
• discharge to surface waters,
• subsurface discharge via deepwell injection,
• surface impoundment (evaporation pond), and
• codisposal with gasifier and/or boiler ash.
Deepwell injection and surface impoundment produce no significant dis-
charges to the environment other than the loss of water vapor and possibly
some volatile compounds and leachates from surface impoundments. These tech-
nologies were discussed in Sections 4.2.1.8 and 4.2.2.1.
411
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
Discharge to surface waters requires that the discharged waters be treat-
ed sufficiently to meet all local, state, and federal requirements concerning
the quantity and quality of the discharge. The integrated control example
given here for discharge to surface waters is a system which produces a final
effluent which would need to be compared to any site-specific requirements.
Ultimately this determination will have to be made for each synfuels plant and
plant site.
The integrated control examples for codisposal with ash are options
which use treated wastewaters for ash quenching. For these cases, the waste-
water residual is used to moisturize the ash and is disposed of along with the
ash. Although only one residual disposal method is shown here in each inte-
grated example, in practice two or more techniques could be used at a given
plant site. For example, a portion of the treated residual could be co-
disposed with ash while the remaining portion could be deepwell injected.
For each of the integrated control examples given in this section, the
following information will be given:
• Description and block flow diagram,
• Influent and effluent compositions and flow rates,
• Secondary waste streams and byproducts generated, and
• Total capital investment and total annualized costs.
Integrated Control Example No. 1
An example of an integrated treatment scheme for wastewaters containing
primarily organic compounds is illustrated in Figure 4-11. As shown, gas
liquor is treated by solvent extraction for bulk organics removal and by the
412
-------
GAS ,
LIQUORf
js
M
U)
RECOVERED
PHENOLS
ACID
GASES
AMMONIA
SOLVENT
EXTRACTION
PHOSAM-W
AIR
1
\
I RECTISOL 2
i
^ AOMVA1CU
SLUDGE
1
1
f
^, CHEMICAL
""" PRECIPITATION
1
STILL BOTTOMS L BIOSLUDGE
FISCHER-TROPSCH
SYNTHESIS
WASTEWATERS
• WASTEWATER STREAMS
> RECOVERED BYPRODUCTS
•SECONDARY WASTES PRODUCED
CHEMICAL
PRECIPITATION
SLUDGE
REGENERATION
OFFGASES
l
i
ACTIVATED
CARBON
ADSORPTION
|
I
SPENT
MEDIA
DISCHARGE
TO SURFACE
WATERS
Figure 4-11. Block flow diagram for integrated control example No. 1
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
Phosam-W process for dissolved gases removal. The resulting extracted and
stripped gas liquor is then combined with Rectisol still bottoms and Fischer-
Tropsch synthesis wastewater for dissolved organics removal in an air-acti-
vated sludge unit. Effluent from the activated sludge unit is then treated
for dissolved inorganics by chemical precipitation and for residual organics
by activated carbon adsorption. The treated effluent is discharged to surface
waters. At the present time, there is no publicly available information indi-
cating that a proposed Lurgi-based synfuel plant will use this approach nor
what the treatment scheme would be if this approach were selected. This exam-
ple therefore was constructed based on engineering analysis (for a generalized
situation) and should not be construed to necessarily represent an acceptable
treatment scheme for a given facility.
Illinois No. 6 coal is the basis for this surface discharge example.
This feedstock is found in regions where adequate supplies of makeup water are
generally available. Therefore, plants which are likely to use an Illinois
No. 6-type feedstock would be more likely to consider discharge of treated
wastewaters (i.e., they would not necessarily be faced with the need to reuse
wastewaters in order to minimize raw water makeup requirements) than facili-
ties located in arid regions (and assumed to use western coal feedstocks).
The estimated material flows and compositions for this example are shown
in Table 4-58. This control example provides for significant reductions in
most pollutant species. Also, the chemical precipitation process is expected
to reduce the trace metals content of the effluent, although no information on
trace elements is shown in this presentation.
This integrated control example produces the following secondary waste
streams and byproducts:
414
-------
TABLE 4-58. ESTIMATED MATERIAL FLOWS AND COMPOSITIONS - INTEGRATED CONTROL EXAMPLE NO. 1
Wattewater Flow Rate.1* (m'/hr)
Constituent Compositions. (mj/L)
COD
BOD
TOC
Phenol
Organic Acida
Tars and Oils
or Us BOO
SQT
NBt (a> NH.)
cr
CO? (at CO.)
S= (aa H,S)
TDS
'Effluent to Surface Vatert.
Flo* ratet and compositions are
Gat
Liquor
498
8,900
4.570
2,980
1,280
380
500
37
160
4,800
95
1,780
290
1,860
calculated
Extracted
Gat
Liquor
498
3,700
860
1,300
150
320
50
37
160
4,800
95
7,780
290
c
values for
Stripped Eeotlaol Fischer-
Gas Still Troptch
497 12 71
3.700 120 12.900
860 85 9.000
1,300 31 4,800
150
320 81 12,100
50
19 16
160
150 65
95 605
1
1
c
the Illinois coal/F-T synthesis case.
Combined
580
4,800
1,800
1.700
130
1,800
43
16
140
130
94
1
1
c
Activated
Chemical Carbon
Biox Precipitation Absorption
Effluent Effluent Effluent
579
960
190
340
6
88
13
5
41
40
94
0
1
c
578
190
72
100
0.006
26
0.1
2
21
40
94
e
1
0
578
190
72
100
0.006
26
0.1
2
21
40
94
c
1
c
• UV 1 • IV V*. baH.UUUsf.l'C mUU AUtX III IJ11* lUlCfKBkCU GUI
Blanks indicate not applicable or no data Available.
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
Secondary Waste Streams Byproducts
Acid gases (120 kg mole/hr) Phenols (1090 kg/hr)
Biosludge (1930 kg/hr) Ammonia (2320 kg/hr)
Regeneration
off-gases (145 kg mole/hr average)
Chemical preci-
pitation sludge (1000 kg/hr)
Spent carbon ad-
sorption media (small and intermittent flow rate)
The carbon adsorption regeneration offgases will contain a small amount of
carbon monoxide and any sulfur species that are in the regenerator fuel. NO
emissions in this stream are not expected to be significant.
Table 4-59 summarizes the estimated capital and total annualized costs
for this integrated control example. For the total system, capital require-
ments are estimated to be $51.5 million or 5.3 percent of the base plant
costs. Total annualized costs are estimated to be $13.2 million per year or
4.9 percent of base plant costs.
TABLE 4-59. ESTIMATED COSTS - CONTROL EXAMPLE NO. la
Total Annualized
Capital Requirement, Cost,
Pollution Control Process 10*$ 10* i/yr
Solvent Extraction
PHOSAM-W
Biological Oxidation
Chemical Precipitation
Activated Carbon Adsorption
TOTAL SYSTEM
14.4
14.4
14.8
2.5
5.3
51.5
4.8
2.9
3.1
0.8
1.7
13.2
Costs are first quarter 1980 dollars.
416
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
Integrated Control Example No. 2
Deepwell injection has been used to dispose of many industrial wastes in
several areas of the country. This disposal method has also been discussed
(although not proposed for disposal of waste brines) as a potential approach
for treated synfuels aqueous wastes. For these reasons, two control examples
are given in this manual to illustrate the possible integration of deepwell
injection technology with potential pretreatment steps. Example No. 2 differs
from Example No. 3 only in that Example No. 2 uses forced evaporation to
achieve volume reduction while Example No. 3 uses cooling tower concentration.
Both of these examples are based on the Rosebud coal/F-T synthesis case.
In integrated control example No. 2 (Figure 4-12) extracted and stripped
gas liquor is combined with Rectisol still bottoms and F-T synthesis waste-
water and sent to an air-activated sludge unit. The activated sludge unit ef-
fluent wastewater stream is concentrated by forced evaporation (to reduce the
overall costs of the treatment system), incinerated to remove residual organ-
ics that could cause operating problems (e.g., plugging of the formation) for
the injection well system, and then deepwell injected. The estimated mate-
rial flows and compositions for this example are shown in Table 4-60.
This control example produces the following secondary waste streams and
byproducts:
Secondary Waste Streams Byproducts
Acid gases (120 kg mole/hr) Phenols (1300 kg/hr)
Biosludge (2700 kg/hr) Ammonia (2200 kg/hr)
Incinerator quench Water (346,000 kg/hr)
offgas (5200 kg mole/hr)
417
-------
AMMONIA
-P-
M
00
RECOVERED
WATER
INCINCERATOR
QUENCH OFFGAS
A
FISCHER-TROPSCH
SYNTHESIS BIOSLUDGE
WASTEWATERS
QUENCH
MAKEUP WATER
• WASTEWATER STREAMS
• RECOVERED BYPRODUCTS
• SECONDARY WASTES PRODUCED
Figure 4-12. Block flow diagram for integrated control example No. 2
-------
TABLE 4-60. ESTIMATED MATERIAL FLOWS AND COMPOSITIONS - INTEGRATED CONTROL EXAMPLE NO. 2
Wastewater Flow Kate,* (»'/hr)
Constituent CoBPOiitioiltf (mg/l.)
COD
BOD
TOC
Phenol
Organic Acids
Tare and Oili
OT (ai BOO
SOT
NBt (a> NBi)
Cl~
COT (aa CO.)
S= (as H,S)
TDS
Gaa
Liquor
293
22,100
10,600
7,600
4,500
2,000
150
5
6
7,600
25
13 ,600
55
2.500
Extracted
Gaa
Liquor
293
12,300
3,100
4,200
290
1,700
50
5
6
7,600
25
13,600
55
b
Stripped
Oaa
Liquor
292
12,300
3,100
4,200
290
1,700
50
3
6
150
25
1
1
b
Bectiaol Fischer-
Still Tropsch
Bottoms Waatewater
10 76
140 11.500
98 8,000
36 4,300
94 10,700
19
74
700
Combined
378
11,800
4,000
4,100
230
3,500
39
2
5
120
38
1
1
b
Bio*
Effluent
377
2,400
400
830
11
170
12
0.7
1
5
38
b
1
b
Forced
Evaporator
Brine
30
29.600
5,000
10.300
140
2,200
150
9
17
62
470
b
10
b
Incinerator
Brine to
Disposal
30
30
5
10
0.1
1
0.1
0.009
0.02
0.06
470
b
0.01
b
*Flo« rates and compoaltions are calculated value* foi tfa« Illlnoi* coal/F-T ayathetit cate.
The fate of carbonate and TDS in tbii integrated control example has not been determined.
Blanks indicate not applicable or no data available.
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
The incinerator quench offgas flow is based on burning Lurgi oil (0.5 percent
sulfur) with 15% excess air. For this case, this stream will contain approxi-
mately 9% C0a, 39% HaO, 200 ppmv SO,, 90 ppmv NO , 35 ppmv CO, 10 ppmv hydro-
carbons, and 4 g/NmJ particulate matter. An incinerator quench makeup
water flow rate of 30 m3/hr is required.
Table 4-61 summarizes the estimated capital and total annualized costs
for this integrated control example. For the total system, capital require-
ments are estimated to be $65.7 million or 6.7 percent of the base plant
costs. Total annualized costs are estimated to be 21.4 million per year or
9.1 percent of base plant costs.
TABLE 4-61. ESTIMATED COSTS - CONTROL EXAMPLE NO. 2*
Pollution Control Process
TOTAL SYSTEM
Capital Requirement,
10'*
Total Annualized
Cost,
Solvent Extraction
PHOSAM-W
Biological Oxidation
Forced Evaporation
Incineration
Deepwell Injection
10.6
11.8
16.3
19.6
5.5
1.9
2.7
1.5
3.5
5.9
7.3
0.4
65.7
21.4
aCosts are first quarter 1980 dollars.
420
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
Integrated Control Example No. 3
This integrated control example (Figure 4-13) is similar to Example No.
2 except that a cooling tower is used for concentration rather than forced
evaporation. The estimated material flows and compositions for this example
are shown in Table 4-62. This control example produces the following second-
ary waste streams and byproducts:
Secondary Waste Streams Byproducts
Acid gases (120 kg mole/hr) Phenols (1300 kg/hr)
Biosludge (2700 kg/hr) Ammonia (2200 kg/hr)
Cooling tower
evaporation (375,000 kg/hr)
Cooling tower drift (1900 kg/hr)
Incinerator quench (7400 kg mole/hr)
offgas
The incinerator quench offgas flow is for burning Lurgi oil (0.5 percent
sulfur) with 15% excess air. The incinerator quench offgas composition is
the same for this example as was given in example No. 2. For this example,
additional raw water makeup to the cooling tower of 40 m3/hr is required.
Also, an incinerator quench makeup water flow rate of 40 m3/hr is required.
Table 4-63 summarizes the estimated capital and total annualized costs
for this integrated control example. For the total system, capital require-
ments are estimated to be $46.8 million or 4.8 percent of base plant costs.
Total annualized costs are estimated to be $17.6 million per year or 7.5
percent of base plant costs.
421
-------
.p-
N3
K>
PHENOLS
ACID
GASES
f
I
I
AMMONIA
EVAPORATION DRIFT
INCINERATOR
QUENCH OFFGAS
? '
1 \ '
It 1
if II
SOLVENT
EXTRACTION
PHOSAM-W
AIR COOLING TOWER
1
j
f RECTISOL ,
<
RECOVERED STILL BOTTOMS'- FISCHER^
SLUDGE CONCENTRATION
1
1
1
1
ROPSCH f
1
I
1
1
THERMAL
* OXIDATION
1
QUENCH
MAKEUP WATER
DEEP WELL
INJECTION
SYNTHESIS
WASTEWATERS
» WASTEWATER STREAMS
.RECOVERED BYPRODUCTS
• SECONDARY WASTES PRODUCED
BIOSLUDGE
Figure 4-13. Block flow diagram for integrated control example No. 3
-------
TABLE 4-62. ESTIMATED MATERIAL FLOWS AND COMPOSITIONS - INTEGRATED CONTROL EXAMPLE NO. 3
N)
UJ
lattewater Flow Rate,* (m'/hr)
Constituent Comcoii tiont. (mt/L)
COD
BOD
TOC
Phenol
Organic Acid<
Tart and Oilt
CIT (at BCN)
SCN-
NBt (at NHi)
cr
COT (at CO,)
S= (at B,S)
TDS
Gat
Liquor
293
22,800
10,600
7,600
4.500
2,000
150
5
6
7,600
25
13,600
55
2,500
Extracted
Gat
Liquor
293
12,300
3.100
4.200
290
1,700
50
5
6
7,600
25
13,600
55
b
Stripped
Gat
Liquor
292
12.300
3.100
4.200
290
1,700
50
3
6
150
25
1
1
b
Rectitol Fitcher-
Still Troptch
10 76
140 11,500
98 8.000
36 4.300
94 10,700
19
74
700
Combined
378
11,800
4,000
4,100
230
3,500
39
2
5
120
38
1
1
b
Biox
Effluent
377
2,400
400
830
11
170
12
0.7
1
5
38
b
1
b
Cool ing
Tower
Slowdown
40
21,400
3.600
7,500
100
1,600
110
7
13
16
340
b
7
b
C.T. Slowdown
to Ditpoaal
40
21
4
7
0.1
2
0.1
0.007
0.01
0.02
340
b
0.007
b
.Flow ratet and competition! are calculated valnet for the Illinoit ooal/F-T tynthetit cate.
The fate of carbonate and TDS in thit integrated control example hat not been determined.
Blankt indicate not applicable or no data available.
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
TABLE 4-63. ESTIMATED COSTS - CONTROL EXAMPLE NO. 3a
Pollution Control Process
Capital Requirement,
lO'j
Total Annualized
Cost,
lO'J/vr
Solvent Extraction
PHOSAM-W
Biological Oxidation
Cooling Tower Concentration
Incineration
Deep Well Injection
TOTAL SYSTEM
10.6
11.8
16.3
6.2
1.9
46.8
2.7
1.5
3.5
9.4
0.4
17.6
Costs are first quarter 1980 dollars.
Integrated Control Example No. 4
The configuration of this control example (No. 4) has some features which are
similar to the proposed wastewater management strategy for the Hampshire
Energy project (Mobil M—gasoline synthesis plant) and includes volume reduc-
tion (for economic and water conservation purposes) and residual disposal in a
surface impoundment. In this integrated control example (Figure 4-14)
extracted and stripped gas liquor is combined with Rectisol still bottoms and
F-T synthesis wastewater and sent to an air-activated sludge unit. The
activated sludge effluent is then concentrated in a cooling tower and the
cooling tower blowdown stream sent to a surface impoundment.
The estimated material flows and compositions for this example (based on
Rosebud coal) are shown in Table 4-64. The impounded stream is not completely
removed from the environment since evaporative losses and a potential leachate
stream will exist. This control example produces the following secondary
waste streams and byproducts:
424
-------
GASi
LIQUOR *
ACID
GASES
| AMMONIA
LL
SOLVENT
EXTRACTION
RECOVERED
Dudkini c
~& PHOSAM-W
RECTISOL -
STILL BOTTOMS
1
EVAPORATION DRIFT
* A
! i
AIR
SLUDGE
1
1
1
/ BIOSLUDGE
COOLING TOWER
— * OXIDATION/
CONCENTRATION
EVAPORATION
A
i
I
i
_^ SURFACE
IMPOUNDMENT
1
1
1
LEACHATE
FISCHER-TROPSCH
SYNTHESIS
WASTEWATERS
•WASTEWATER STREAMS
• RECOVERED BYPRODUCTS
•SECONDARY WASTES PRODUCED
Figure 4-14. Block flow diagram for integrated control example No. 4
-------
TABLE 4-64. ESTIMATED MATERIAL FLOWS AND COMPOSITIONS - INTEGRATED CONTROL EXAMPLE NO. 4
NJ
ON
Wastewater Flow Rate,* (m'/hr)
Constituent Compositions.' («g/L)
COD
BOD
TOC
Phenol
Organic Acids
Tart and Oils
or (as HCN)
SOT
NBt (as NHi)
Cl"
COT (as CO,)
S= (as B>S)
TDS
Gas
Liquor
293
22,800
10,600
7,600
4,500
2,000
150
5
6
7,600
25
13,600
55
2,500
Extracted
Gas
Liquor
293
12,300
3,100
4,200
290
1,700
50
5
6
7,600
25
13,600
55
b
Stripped
Gas
Liquor
292
12,300
3,100
4,200
290
1,700
50
3
6
150
25
1
1
b
Rectisol Fischer-
Still Tropsch
Bottoms Wastewater
10 76
140 11.500
98 8,000
36 4,300
94 10,700
19
74
700
Cofflbi ned
Wastevaters
378
11,800
4,000
4,100
230
3,500
39
2
5
120
38
1
1
b
Biox
Effluent
377
2,400
400
830
11
170
12
0.7
1
5
38
b
1
b
Cooling Tower
Slowdown
to Surface
Impoundment
40
21,400
3,600
7,500
100
1,600
110
7
13
16
340
b
7
b
bPlow rates and compositions are calculated values for the Illinois coal/F-T synthesis case.
The fate of carbonate and TDS in this integrated control example has not been determined.
Blanks indicate not applicable or no data available.
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
Secondary Waste Streams Byproducts
Acid Gases (120 kg mole/hr) Phenols (1300 kg/hr)
Biosludge (2700 kg/hr) Ammonia (2200 kg/hr)
Cooling tower
evaporation (375,000 kg/hr)
Cooling tower drift (1900 kg/hr)
Impoundment evaporation (~40,000 kg/hr)
Impoundment leachate (unknown flow rate)
For this example, additional raw water makeup to the cooling tower of 40
m /hr is required.
Table 4-65 summarizes the estimated capital and total annnalized costs
for this integrated control example. For the total system, capital require-
ments are estimated to be $43.8 million or 4.5 percent of base plant costs.
Total annualized costs are estimated to be $8.8 million per year or 3.8
percent of base plant costs.
TABLE 4-65. ESTIMATED COSTS - CONTROL EXAMPLE NO. 4a
Total Annnalized
Capital Requirement, Cost,
Pollution Control Process 10*$ 10*j/yr
Solvent Extraction 10.6 2.7
PHOSAM-W 11.8 1.5
Biological Oxidation 16.3 3.5
Cooling Tower Concentration — —
Surface Impoundment
TOTAL SYSTEM
5.1
43.8
1.1
8.8
lCosts are first quarter 1980 dollars.
427
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
Integrated Control Example No. 5
The configuration of this control example (Figure 4-15) is similar to
Example No. 4 except that volume reduction is achieved by forced evaporation
rather than cooling tower concentration. The estimated material flows and
compositions for this example are shown in Table 4-66. This control example
produces the following secondary waste streams and byproducts:
Secondary Waste Streams Byproducts
Acid gas (120 kg-mole/hr) Phenols (1300 kg/hr)
Biosludge (2700 kg/hr) Ammonia (2200 kg/hr)
Impoundment evaporation (~30,000 kg/hr) Water (348,000 kg/hr)
Impoundment leachate (unknown flow rate)
Table 4-67 summarizes the estimated capital and total annualized costs
for this integrated control example. For the total system, capital require-
ments are estimated to be $62.2 million or 6.4 percent of base plant costs.
Total annualized costs are estimated to be il4.5 million per year or 6.2
percent of base plant costs.
Integrated Control Example No. 6
The configuration of this control example (No. 6) has some features which are
similar to the proposed wastewater management system for the Nokota project
(Methanol synthesis plant) and includes codisposal of the residual wastewater
stream with ash. Both cooling tower concentration and forced evaporation are
used for volume reduction. In this integrated control example (Figure 4-16),
extracted and stripped gas liquor is combined with Rectisol still bottoms and
F-T synthesis wastewater and sent to an air-activated sludge unit. The acti-
vated sludge unit effluent is concentrated by cooling tower oxidation/
concentration and then further concentrated by forced evaporation. The
428
-------
GAS
LIQUOR
.p-
N3
PHENOLS
ACID
GASES
RECOVERED
! AMMONIA WATER EVAPORATION
SOLVENT
EXTRACTION
RECOVERED
M
^ PI in^ftM \A/
_ AIR __ FOP
1
RECTISOL ,
j
STILL BOTTOMSf A
•- MUMVMItU — EVAPO
SLUDGE
1
1
1
1
I/ BIOSLUDGE
f t
f !
CED fc SURFACE
RATION IMPOUNDMENT
1
1
*
1 FACHATE
FISCHER-TROPSCH
SYNTHESIS
WASTEWATERS
. WASTEWATER STREAMS
• RECOVERED BYPRODUCTS
•SECONDARY WASTES PRODUCED
Figure 4-15. Block flow diagram for integrated control example No. 5
-------
TABLE 4-66. ESTIMATED MATERIAL FLOWS AND COMPOSITIONS - INTEGRATED CONTROL EXAMPLE NO. 5
-p-
LO
o
Wastewater Flow Rate.* (m'/hr)
Constituent Competitions. (ug/L)
COD
BOD
TOC
Phenol
Organic Acids
Tart and Oila
CN~ (at HOO
SCN"
NHt (at NHi)
Cl~
COT (at CO,)
S= (as HiS)
•TDS
Gas
Liquor
293
22,800
10,600
7.600
4,500
2.000
ISO
5
6
7,600
25
13,600
55
2.500
Extracted
Gas
Liquor
293
12,300
3,100
4,200
290
1,700
50
5
6
7,600
25
13,600
55
b
Stripped
Gas
Liquor
292
12,300
3,100
4,200
290
1.700
50
3
6
150
25
1
1
b
Rectisol Fischer-
Still Tropsch
Bottoms Wastewater
10 76
140 11,500
98 8,000
36 4,300
94 10,700
19
74
700
Combined
Wastewaters
378
11,800
4,000
4,100
230
3,500
39
2
5
120
38
1
1
b
Biox
Effluent
377
2,400
400
830
11
170
12
0.7
1
5
38
b
1
b
Forced
Evaporator
Brine to
Surface
Impoundment
30
29,600
5,000
10,300
140
2,200
150
9
17
62
470
b
10
b
Flow rates and compositions are calculated values for the Illinois coal/F-T synthesis case.
The fate of carbonate and TDS in this integrated control example has not been determined.
Blanks indicate not applicable or no data available.
-------
TABLE 4-67. ESTIMATED COSTS - CONTROL EXAMPLE NO. 5*
Total Annualized
Capital Requirement, Cost,
Pollution Control Process 10*j 10*j/yr
Solvent Extraction
PHOSAM-W
Biological Oxidation
Forced Evaporation
Surface Impoundment
10.6
11.8
16.3
19.6
3.9
2.7
1.5
3.5
5.9
0.8
TOTAL SYSTEM 62.2 14.5
aCosts are first quarter 1980 dollars.
431
-------
NJ
ACID
RECOVERED INCINERATOR
GASES AMMONIA EVAPORATION DRIFT WATER QUENCH OFFGAS
GAS, SOLVENT
LIQUOR * "" EXTRACTION
i
RECOVERED
PHENOLS
I I
1 \
1 1
PHOSAM W
AIR
1 1
RECTISOL , |
STILL BOTTOMS'
FISCHER-THOPSCH
SLUDGE
1
1
BIOSLUDGE
t f
1 |
COOLING TOWER cr.
•• QAlDATluN/ •• EVAPC
CONCENTRATION
t T
> 1
> 1
1 I
RCED THERMAL
JRATION OXIDATION
1
QUENCH
MAKEUP WATER
EVAPORATION
t
1
1
ASH
QUENCH
CO DISPOSAL
WITH ASH
SYNTHESIS < '
WASTEWATERS
• WASTEWATER STREAMS
• RECOVERED BYPRODUCTS
• SECONDARY WASTES PRODUCED
Figure 4-16. Block flow diagram for integrated control example No. 6
-------
Section 4
Aqueous Medium
Integated Controls
Organic
resultant treated and concentrated wastewater is then incinerated and used as
gasifier/ boiler ash quench water. The residual wastewater (that which is not
evaporated in the ash quenching operation) is disposed of along with the ash.
In this example, the wastewater stream is incinerated to avoid contaminating
the ash with organics and possibly causing the ash to become a hazardous waste
requiring special disposal procedures with higher disposal costs.
The estimated material flows and compositions for this example (based on
Rosebud coal) are shown in Table 4-68. This control example produces the
following secondary waste streams and byproducts:
Secondary Waste Streams
Acid gases
Biosludge
Cooling tower
evaporation
Cooling tower drift
Incinerator quench
offgas
Ash quench evaporation (5800 kg/hr)
(120 kg mole/hr)
(2700 kg/hr)
(375,000 kg/hr)
(1900 kg/hr)
(3400 kg mole/hr)
Byproducts
Phenols
Ammonia
Water
(1300 kg/hr)
(2200 kg/hr)
(20,000 kg/hr)
The incinerator quench offgas flow is for burning Lurgi oil (0.5 percent
sulfur) with 15% excess air. The incinerator quench offgas composition for
this example is the same as was given for Example No. 2. For this example,
additional raw water makeup to the cooling tower of 40 m /hr is required.
Also, an incinerator quench makeup flow rate of 20 m /hr is required.
Table 4-69 summarizes the estimated capital and total annualized costs
for this integrated control example. For the total system, capital require-
ments are estimated to be $45.5 million or 4.6 percent of base plant costs.
Total annualized costs are estimated to be $13.4 million per year or 5.7
percent of base plant costs.
433
-------
TABLE 4-68. ESTIMATED UATEBIAL FLOWS AND COMPOSITIONS - INTEGRATED CONTROL EXAMPLE NO. 6
Co
-P-
Waste*. ter Flo* Rite,*
(m'/hr)
Constituent Cog post tioni. *
(•g/L)
COD
BOD
TOC
Phenol
Organic Acidi
Tirs and OiU
CN~ (as HCN)
SOT
NHt (at NHi)
Cl~
COT (at COi)
S= (as HaS)
TDS
Flow rates and cospofitioni
Gat
Liquor
293
22,800
10,600
7,600
4,300
2,000
150
5
6
7,600
25
13,600
55
2,500
Extracted
Gat
Liquor
293
12,300
3,100
4,200
290
1,700
50
5
6
7,600
25
13,600
55
b
Stripped
Gas
Liquor
292
12,300
3,100
4,200
290
1,700
50
3
6
150
25
1
1
b
Rectisol Fischer-
Still Tropsch
10 76
140 11,500
98 8,000
36 4,300
94 10.700
19
74
700
Illinois coal/F-T tynt
Combined
378
11,800
4,000
4.100
230
3,500
39
2
5
120
38
1
1
b
hesis case.
Bioi
Effluent
377
2,400
400
830
11
170
12
0.7
1
5
38
b
1
b
Cooling
Tower
Blovdown
40
21,400
3,600
7,500
100
1,600
110
7
13
16
340
b
7
b
Forced
Evaporator
Brine
20
43,000
7,300
15,000
210
32,000
210
13
25
32
690
b
14
b
Incinerated
Brine
to Ash
Quenching
43
7
15
0.2
3
0.2
0.01
0.03
0.03
690
b
0.01
b
Residual
Disposed
with
O^ienched
Ash
61
10
21
0.3
4
0.3
0.02
0.04
0.04
970
b
0.02
b
The fate of carbonate and TDS in this integrated control exanple hat not been determined.
Blanks indicate not applicable or no data available.
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
TABLE 4-69. ESTIMATED COSTS - CONTROL EXAMPLE NO. 6»
Total Annualized
Capital Requirement, Cost,
Pollution Control Process 10*i 10'i/yr
Solvent Extraction
PHOSAM-W
Biological Oxidation
Cooling Tower Concentration
Forced Evaporation
Incineration
Co-disposal With Ash
TOTAL SYSTEM
10.6
11.8
16.3
-
2.2
4.6
—
45.5
2.7
1.5
3.5
-
0.6
5.0
—
13.4
Costs are first quarter 1980 dollars.
Integrated Control Example No. 7
The configuration of integrated control example No. 7 has some features which
are similar to the proposed wastewater management strategy for the Great
Plains Coal Gasification Associates, Inc. SNG project. This control example
(Figure 4-17) is the same as Example No. 6 except that there is no activated
sludge unit and only gas liquor and Rectisol still bottoms are treated. These
two wastewaters would exist if the plant produced substitute natural gas.
Omitting the activated sludge unit results in greater organics concentrations
in the cooling tower makeup water. Thus, in this example it is more likely
that COD, BOD, TOC, etc. reductions will occur in the cooling tower than in
previous examples (Nos. 3, 4, and 6) where less organic material is charged to
the cooling tower. These cooling tower oxidation effects have not, however,
been demonstrated and are not shown in this example. Also, due to the higher
organics (and other species) loadings in the cooling tower, the cooling tower
evaporation and drift streams are more likely to contain significant amounts
of pollutants.
435
-------
ACID
GASES
. AMMONI
, , ! 1
SOLVENT
EXTRACTION
f
EVAPORATION DRIFT
A A A
1 1
1 1
1 1
COOLING TOWER
CONCENTRATION
RECO\
WA
I
/ERED
'ER
^ FORCED
EVAPORATION
INCINERATOR
QUENCH OFFGAS
»
1
1
^ THERMAL
OXIDATION
J.
QUENCH
MAKEUP WATER
EVAPORATION
1
1
1
I
f, ARH
QUENCH
^ CO-DISPOSAL
WITH ASH
RECOVERED
PHENOLS
RECTISOL
STILL BOTTOMS
WASTEWATER STREAMS
RECOVERED BYPRODUCTS
SECONDARY WASTES PRODUCED
Figure 4-17. Block flow diagram for integrated control example No. 7
-------
Section 4
Aqueous Medium
Integrated Controls
Organic
The estimated material flows and compositions for this example (Rosebud
coal case) are shown in Table 4-70. This control example produces the follow-
ing secondary waste streams and byproducts:
Secondary Waste Streams
Byproducts
Acid gases
Cooling tower
evaporation
Cooling tower drift
Incinerator quench
offgas
Ash quench evaporation (5800 kg/hr)
(120 kg mole/hr)
(375,000 kg/hr)
(1900 kg/hr)
(3400 kg mole/hr)
Phenols
Ammonia
Water
(1300 kg/hr)
(2200 kg/hr)
(20.000 kg/hr)
The incinerator quench offgas flow is for burning Lurgi oil (0.5 percent
sulfur) with 15% excess air. The incinerator quench offgas composition for
this example is the same as was given for Example No. 2. For this example,
additional raw water makeup to the cooling tower of 114 m3/hr is required.
Also, an incinerator quench makeup flow rate of 20 m*/hr is required.
Table 4-71 summarizes the estimated capital and total annualized costs
for this integrated control example. For the total system, capital require-
ments are estimated to be $29.2 million or 3.6 percent of base plant costs.
Total annualized costs are estimated to be $9.9 million per year or 4.9
percent of base plant costs.
437
-------
TABLE 4-70. ESTIMATED MATERIAL FLOWS AND COMPOSITIONS - INTEGRATED CONTROL EXAMPLE NO. 7
-P-
UJ
Oo
Extracted
Gas Gas
Liquor Liquor
(n'/hr)
293
293
Stripped Rectisol
Gas Still
Liquor BottOBt
292 10
Combined
Waateva terc
302
Cooling Forced
Tower Evaporator
Slowdown Brine
40
20
Incinerated
Brine
to Aah
Quenching
20
Reaidual
Diapoted
with
Quenched
Aah
14
Constituent Con pent tiona.*
(ng/L>
COD
BOD
TOC
Phono 1
Organic Acids
Tars and Oil«
Ctr (as HCN)
SOT
• NHt (as NHi)
Cl~
C07 U> COi)
S= (it BiS)
TDS
22,800
10,600
1.600
4.500
2,000
150
5
6
7,600
25
13,600
55
2,500
12,300
3,100
4.200
290
1,700
50
5
6
7,600
25
13,600
55
b
12,300 140
3,100 98
4,200 36
290
1.700 94
50
3 19
6
150 74
25 700
1
1
b
12,000
3,000
4,100
280
1,600
48
3
6
150
47
b
1
b
87,000
22,000
30.000
2,000
12,000
350
22
42
370
340
b
7
b
170,000
44,000
60,000
4,000
24,000
700
44
84
740
680
b
14
b
170
44
60
4
24
0.7
0.04
0.08
0.7
680
b
0.01
b
250
62
85
6
34
1
0
0
1
980
b
0
b
.06
.1
.02
*Flov ratei and compositions are calculated values for the Illinois coal/F-T synthesis case.
The fate of carbonate and TDS in thia integrated control example haa not been determined.
Blanks indicate not applicable or no data available.
-------
TABLE 4-71. ESTIMATED COSTS - CONTROL EXAMPLE NO. 7a
Pollution Control Process
Capital Requirement,
Total Annualized
Cost,
10«i/vr
Solvent Extraction
PHOSAM-W
Cooling Tower Concentration
Forced Evaporation
Incineration
Codisposal With Ash
TOTAL SYSTEM
10.6
11.8
2.2
4.6
29.2
2.7
1.5
0.6
5.0
9.9
Costs are first quarter 1980 dollars.
439
-------
Section 4
Aqueous Medium
Stream Control
Inorganic
4.2.3 Control Applications for Specific Streams Containing Primarily
Inorganic Compounds
The waste streams in this source type are not unique to Lurgi-based syn-
fuels plants. As was discussed earlier, controls for these non-unique streams
in a Lurgi plant would be similar to the controls which would be used for
similar streams in existing U.S. industries. For example, the blowdown stream
from a coal-fired boiler in a Lurgi-based synfuels plant would have character-
istics and treatment needs which are essentially the same as for blowdown from
a coal-fired boiler in other industries.
These streams and their controls will not be discussed in depth in this
manual since this PCTM concentrates on the control of streams which are unique
to Lurgi-based synfuels plants. Therefore, this section discusses the availa-
ble control options but does not present influent and effluent wastewater
compositions and flows or treatment costs.
Gasifier Ash and Boiler Ash Quench/Sluice Blowdown
The wastewaters resulting from gasifier and boiler ash quenching are ex-
pected to be similar in composition as long as similar quality waters are
used. These waters will primarily contain suspended solids and inorganics
leached from the ash. The pH may be high or low depending on the leachable
components in the ash. The primary objectives in treating this waste stream
are removal of suspended solids and neutralization.
One approach to the treatment/reuse of this stream involves closed loop
operation of the sluicing system. Under this mode of operation, the quench/
sluice waters are routed to a clarifier or settling pond which separates the
440
-------
Section 4
Aqueous Medium
Stream Control
Inorganic
ash while the overflow water is recircnlated. A Lurgi—based system should be
able to operate in this mode because the water associated with the quenched
gas (80 wt% solids) should remove sufficient quantities of dissolved solids to
satisfy dissolved species blowdown requirements. Another approach involves pH
adjustment and removal of suspended solids. The clarified stream could be
considered for discharge to some surface waters if the trace element concen-
trations are not significant.
Methanation and CG1 Removal Condensates
The condensates which result from methanation and C02 removal from
crude SNG will be of high quality. The primary contaminants will be small
quantities of dissolved gases (e.g., C02> CH4). The objective in treating
this stream will be to remove dissolved gases (as necessary) prior to reuse.
These condensates may be used directly as cooling tower or raw water
makeup. Alternately, they can be routed to the boiler feedwater deaerator or
demineralizer decarbonator for dissolved gas removal prior to use as boiler
feedwater. Use of these condensates as makeup to the boiler feedwater system
will reduce feedwater treatment costs because of the low concentrations of
dissolved inorganic solids in these streams. Their use will also decrease the
volume of demineralizer regeneration wastewaters. Since boiler feedwater
makeup treatment equipment is designed to satisfy total plant makeup needs
based upon raw water, the use of these condensates in this system will not
affect the capital investment but will reduce operating costs.
Raw Coal Storage Runoff
The runoff associated with raw coal storage/handling will be an inter-
mittent stream with a highly variable composition. It will contain suspended
and dissolved solids as well as inorganic compounds leached from the coal.
441
-------
Section 4
Aqueous Medium
Stream Control
Inorganic
The objectives in treating this stream include removal of suspended and
dissolved solids. An approach which might allow discharge involves routing
the wastewater to a sedimentation pond where the suspended solids are allowed
to settle out. Lime or acid can be added for pH adjustment where required.
Chemical precipitation may occur as a result of pH adjustment, thus potential-
ly removing some additional undesirable dissolved solids. The effluent may
then be discharged to surface waters, recycled, or sent to final disposal.
Reuse of the runoff as cooling tower makeup is an alternative to discharge.
The treatment utilized for this approach is expected to be similar to that
for discharge.
Demineralizer Regeneration Wastewaters
The wastewaters which result from demineralizer regeneration are gene-
rated at relatively high flow rates. These wastewaters contain high concen-
trations of dissolved inorganic salts. One approach to treatment of this
wastewater involves removal of suspended solids and chemical precipitation.
These steps may produce a water quality which could be discharged at some
plant sites. If a discharge approach is not available, then wastewater con-
centrating steps would probably be needed to reduce the cost of residual dis-
posal. A substantial portion of the volume reduction may be accomplished by
segregating high quality demineralizer regeneration wastewaters from low qual-
ity wastewaters. Portions of the initial raw water backwash and much of the
final rinse water will be of raw water quality or better and can be reused
without treatment.
If chemical precipitation is used, a sludge containing approximately 20
weight percent solids will be produced. Treatment alternatives for this
secondary waste stream are discussed in Section 4.3.
442
-------
Section 4
Aqueous Medium
Stream Control
Inorganic
Boiler Slowdown
The blowdown from the auxiliary boilers has a quality comparable in dis-
solved solids to the raw water makeup supply. It has a relatively low flow
rate when compared to the other streams presented in this section. The blow-
down will contain low to moderate amounts of inorganic dissolved solids in-
cluding treatment chemicals and traces of dissolved metals.
The objectives in treating this stream depend on the reuse/disposal route
to be taken. If the blowdown is to be reused as boiler feedwater, removal of
dissolved solids and residual treatment chemicals will be needed. In this in-
stance, it could be routed to the boiler feedwater treatment system upstream
of the sedimentation/equalization basin. If the blowdown may be discharged,
pH adjustment and sedimentation may be desirable.
Cooling Tower Blowdown
The cooling tower blowdown is a large stream which contains fairly high
concentrations of dissolved solids. The expected flows and compositions of
the various cooling tower blowdown streams for raw water makeup cases were
given in Section 3. The flow rate and composition of the blowdown will be a
function of the heat load on the tower and the cycles of concentration at
which the system is operated. For a given plant heat load, the cycles of con-
centration will be determined by the quality of the makeup water fed to the
tower. The compositions listed in Section 3 are for operation at 5 cycles of
concentration.
As discussed in previous sections, some control alternatives for treat-
ment of raw gas liquor and related wastewaters employ the cooling tower as a
443
-------
Section 4
Aqueous Medium
Stream Control
Inorganic
means of concentrating the wastewater. This discussion deals only with treat-
ment of the cooling tower blowdown when raw water is the only source of
cooling tower makeup.
The objectives in treating the blowdown depend on the disposal/reuse
options available. If operation with no discharge is desired, the objective
would be to minimize the blowdown flow. If the blowdown is to be discharged,
the objectives in treating the stream would be to remove suspended solids and
to treat by chemical precipitation.
Depending upon the corrosion and scale inhibitors chosen for use in the
cooling tower system, additional treatment of the cooling tower blowdown may
be desirable before disposal. Systems employing chromate or zinc-based corro-
sion inhibitors would normally have additional treatment for removal of these
compounds. Since the choice of corrosion inhibitors is dependent upon plant
operating practices, additional treatment for removal of these inhibitors from
cooling tower blowdown was not considered.
If chemical precipitation/coagulation is included in treatment for dis-
charge, a solid waste containing approximately 20 weight percent solids will
be produced. This waste will be composed primarily of precipitated inorganic
compounds and suspended matter. Disposal of this 'sludge is discussed in Sec-
tion 4.3.
Boiler and Process Equipment Cleaning Wastes
Wastewaters which result from the cleaning of process equipment will con-
tain suspended and dissolved solids, trace metals, and organics and could be
either acidic or basic. The waste composition will be determined primarily by
444
-------
Section 4
Aqueous Medium
Stream Control
Inorganic
the cleaning solution and the type of equipment being cleaned. If a surface
discharge approach is used, these wastes may be collected in a sedimentation
basin for suspended solids removal followed by chemical precipitation and pH
adjustment. In this case a chemical precipitation sludge similar to that
described earlier (see the cooling tower blowdown discussion) would be pro-
duced. Another approach to control of these equipment cleaning wastes is to
dispose of them via deepwell injection or surface impoundment.
Plant Process Drain and Storm Drain Effluents
Process drain wastewaters will result from plant process spills, drain-
age, and leakage that occurs during the operation and maintenance of the sys-
tem. Process drain flows should be low where good plant housekeeping and
maintenance procedures are followed. The stream is likely to contain oil,
grease, dissolved organics, suspended solids, and dissolved solids.
Storm drain wastewater is storm water which falls on the plant grounds
outside the coal storage area. It will be similar to process drain wastewater
but will typically have a much greater peak flow rate and much lower oil and
grease levels.
Both of these wastewaters will be collected (separately) and sent to im-
poundments for sedimentation to allow suspended matter to settle out and to
provide surge capacity. Process drain wastewater systems will normally be en-
closed between the drains and an initial gravity separation step (such as an
API separator) which recovers oil and grease. This practice minimizes fugi-
tive gaseous hydrocarbon emissions and recovers a byproduct oil stream. Ad-
ditional treatment for process drain wastewaters depends on the amounts and
445
-------
Section 4
Aqueous Medium
Stream Control
Inorganic
types of contaminants remaining and on the specific reuse options available.
Storm water can normally be reused (after sedimentation) directly in the cool-
ing tower or the raw water makeup system.
Secondary Wastewater Streams Containing Primarily Inorganic Compounds
Three secondary wastewater streams which contain primarily inorganic com-
pounds will potentially be present in Lurgi-based synfuels plants. If the
plant has a Stretford sulfur recovery unit, then a small Stretford solution
purge might be present. Similarly, if the Wellman-Lord sulfur recovery pro-
cess were used, then a small sulfate purge stream would exist. The third po-
tential secondary wastewater stream of this source type would be blowdown
streams from certain gas scrubbers (such as incinerator flue gas scrubbers,
catalyst regeneration offgas scrubbers, and the ash lock vent gas scrubber).
Stretford Solution Blowdown—The blowdown stream from the Stretford unit
will contain thiosulfates, thiocyanates, sulfates, vanadium compounds,
ethylene diamine tetraacetic acid (EDTA) , and anth.raqui.none disulfonic acid
(ADA). It may also include other toxic compounds which may greatly impact the
treatment methodology. This stream should have a relatively low flow rate.
The objective in treating this stream is to control the discharge of re-
duced sulfur compounds, organics, and vanadium salts. One approach to treat-
ing this stream is reductive incineration. Reductive incineration is a com-
mercially proven process whereby the blowdown stream contaminants are reduced
to gaseous H2S and a solid composed of vanadium compounds and sodium carbon-
ate. The hydrogen sulfide stream is recycled to the Stretford absorber while
the solids are recycled to the absorber solution to reduce chemical makeup re-
quirements. The use of this process should greatly reduce or eliminate the
446
-------
Section 4
Aqueous Medium
Stream Control
Inorganic
blowdown stream from the Stretford unit. An alternative approach to reductive
incineration involves acid treatment to oxidize the thiosulfates to a sulfate
form which can be concentrated prior to disposal. This process, however, is
commercially unproven while reductive incineration of Stretford blowdown has
had some commercial experience.
Wellman-Lord sulfate purge—In the Wellman-Lord process a portion of the
circulating liquor is purged to control the buildup of sodium thiosulfate, an
inert compound which is formed in the process (see Section 4.1). This purge
would have a flow rate of approximately 5 mj/hr for typical synfuels
applications and would have the following composition:
Component
Water
Sodium Sulfite
Sodium Bisulfite
Sodium Sulfate
Sodium Thiosulfate
Sodium Dithionite
Control measures for this stream include crystallization and combination
with other streams for treatment and ultimate disposal. For the cyrstalliza-
tion approach, the Wellman-Lord process is slightly redesigned so that the
water which is removed during drying is returned to the process. The salt
formed would be a byproduct or a small volume solid waste. One combination
approach involves blending the small stream with a larger stream prior to che-
mical precipitation (or other inorganic salt removal process) for plants with
surface discharge strategies. For plants with deepwell, surface impoundment,
or codisposal with ash strategies this concentrated brine stream may be com-
bined with treated and concentrated wastewater from the main treatment train.
447
-------
Section 4
Aqueous Medium
Stream Control
Inorganic
Scrubber Slowdown Streams Containing Primarily Inorganic Compounds—The
blowdown streams from the various gas scrubbers which may be present (incine-
rator flue gas, catalyst regeneration offgases, and ash lock vent gas) will
all contain primarily suspended solids and inorganic compounds. The catalyst
regeneration offgas scrubbers may contain a number of contaminants depending
on which catalysts are involved. The shift catalyst offgas will contain
large amounts of sulfur oxides along with small amounts of cobalt-molybdenum
catalyst fines and possibly other trace elements. The Mobil M catalyst con-
tains cobalt and nickel compounds which may be present in the offgas. The
scrubber blowdown will contain the contaminants removed from the offgas
including particulates, nncombusted organics, and inorganic salts.
The objectives in treating these various scrubber streams are to remove
suspended solids and to treat with chemical precipitation and/or adjust pH if
remaining inorganics concentrations are too great for the residual disposal
option available.
448
-------
Section 4
Solid Wastes
4.3 SOLID WASTE MANAGEMENT
Many solid waste streams, including ashes, sludges, and spent catalysts,
are generated in a Lurgi-based synthetic fuels facility. The available con-
trol techniques that are applicable to these streams are identified and
evaluated in this section. In comparison with air and water pollution control
operations, solid waste management techniques available for a Lurgi-based
facility are fewer and also more site specific. In addition, the quantities
and characteristics of some solid waste streams (e.g., brines and sludges) are
affected by the processes selected for air and water pollution control.
Because of this, solid waste management at a Lurgi-based facility is not an
isolated issue but rather an element in the total program for pollution con-
trol.
The sources and factors affecting the characteristics of the solid waste
streams generated in Lurgi-based facilities are summarized in Table 4-72. Of
the streams listed, gasifier ash is by far the largest volume stream. Depend-
ing on the coal type and synthesis process used, it comprises 48% to 64% of
the total solid waste generated from the plant. Flue gas desulfurization
(FGD) sludge from lime/limestone processes is the next largest volume stream,
comprising up to 21% of the total waste generated. Both of these streams are
highly influenced by the characteristics of the coal used.
The type of coal used has considerable impact on the characteristics of
the solid wastes generated, and hence the solid waste management techniques
used. Major coal properties affecting the solid waste control approaches
include: ash content, sulfur content, friability, and ash acidity/alkalinity.
Coals with higher ash or sulfur contents will result in the generation of
larger quantities of gasifier ash or FGD sludges, and thus will require larger
control facilities.
449
-------
TABLE 4-72. SUMMARY OF SOLID WASTE STREAMS FROM LURGI-BASED INDIRECT
LIQUEFACTION FACILITIES
Stream
Stream Pollutants of
No. Potential Concern
Factors Affecting Waste
Stream Characteristics
Ul
o
From Main Process Train
Quenched Gasifier Ash 403
Spent Shift Catalyst 212
Spent Sulfur Guard 217
Spent Methanation Catalyst 229
Spent Synthesis Catalysts
Tars and Oils
222
218
223
111
112
From Auxiliary Processes
Boiler Bottom Ash 406
Raw Water Treatment Sludges 300
Leachable trace
elements, organics
Leachable trace
elements
Leachable trace
elements
Leachable trace
elements
Leachable trace
elements
Higher aromatics, POM,
mercaptans, HCN
Leachable trace
elements
Leachable trace
elements
Feed coal characteristics,
gasifier operating conditions
quench water characteristics.
Catalyst life, regeneration
frequency, raw gas characteris-
tics
Sulfur guard life, regeneration
frequency, AGR effluent gas char-
acteristics.
Catalyst life, regeneration
frequency, synthesis gas charac-
teristics.
Catalyst life, regeneration
frequency, synthesis gas charac-
teristics.
Feed coal characteristics,
gasifier operating conditions,
tar/oil removal process design
and operating conditions.
Feed coal characteristics,
boiler operating conditions,
slurry water characteristics.
Raw water characteristics,
treatment system design and
operation.
(Continued)
-------
TABLE 4-72. (Continued)
Stream
Stream Pollutants of
No. Potential Concern
Factors Affecting Waste
Stream Characteristics
Ul
From Pollution Control
Boiler Fly Ash
441
FGD Sludges from Boiler* 444
Spent Claus Catalyst 413
Biological Sludge from 431
Wastewater Treatment
Dewatered Chemical 433
Precipitation Sludges
Recovered Sulfur 116
Collected Dust from 400
Particulate Control
Leachable trace
elements, potential
dust emissions
Leachable trace
elements
Leachable trace
elements
Leachable organics,
trace metals
Leachable trace
elements
Vanadates, thiocyanates
(with Stretford only)
Potential dust
emissions
Feed coal characteristics, boiler
operating conditions, slurry water
characteristics.
Coal sulfur content, FGD process
design and operation.
Catalyst life, regeneration
frequency, acid gas character-
istics.
Gas liquor characteristics, waste-
water treatment system design and
operation.
Gas liquor characteristics, waste-
water treatment system design and
operation.
Coal sulfur content, gasifier
operating conditions, sulfur
recovery unit design and opera-
tion.
Dust collection process design
and operation.
For the wet limestone process.
-------
Section 4
Solid Wastes
Friability of coal is dependent upon the clay and mineral contents of the
coal. During coal preparation operations, highly friable coals (coals with
low clay contents) will generate large quantities of coal fines which are too
small to be used as feed to the Lurgi gasifier. Ihe energy value of the coal
fines may be recovered by using them as boiler fuel or to produce additional
synthesis gas in a gasifier capable of handling fines. However, coals that
generate excess coal fines (i.e. more than can be used) may have to dispose of
them by landfilling.
The gasifier and boiler ash generated may be acidic or alkaline. Alka-
line fly ash has been used in existing power plants to mix with FGD sludges
before disposal. Mixing these two may result in a material structurally more
suitable for landfilling. The acid/alkaline nature of ashes may affect their
leaching characteristics and thus influence control practices.
The solid waste streams listed in Table 4-72 can be classified according
to four waste type categories (source types) which are based on the nature of
the waste. These waste types are: inorganic ashes, recovered unsalable by-
products, organic sludges, and spent catalysts. Several control techniques
are potentially applicable to these streams.
In general, solid waste control techniques aim at containing the entire
waste stream. Thus, the performance of these techniques, in terms of removal
or control efficiencies, is generally 100 percent. However, unless designed
and operated properly, secondary waste streams with undesirable characteris-
tics may be generated and migrate away from the site employing the technique.
For example, runoff can contaminate surface water and percolating water can
contaminate groundwater. The significance of this depends upon the nature of
the species which might be leached out of the solids by the runoff/percolation.
Thus, in selecting solid waste management techniques, the major evaluation
criteria are whether the secondary waste streams are suitably contained.
452
-------
Section 4
Solid Wastes
Based upon current techniques practiced in synfuel and other industries,
together with those being considered by proposed synfuel plants, the bulk of
the solid waste from Lurgi facilities will likely be disposed of on land.
Land-based disposal techniques are by far the most site-specific techniques.
The suitability of the site, as well as the design and operation of the
facility, would depend on the site location, transportation costs, hydro-
geologic conditions, and many other factors. In short, a detailed analysis of
the specific site is an important element of the overall control technique
evaluation process.
Land disposal (e.g., landfill, surface impoundment, land treatment) will
be subject to regulations promulgated by EPA pursuant to the Resource
Conservation and Recovery Act (RCRA), covering the generation, transport,
treatment, storage, and disposal of solid wastes. Requirements concerning a
solid waste can vary significantly, depending upon whether the waste is
determined to be "hazardous" or "non-hazardous" as defined by RCRA
regulations. In this manual, no attempt is made to judge whether the various
individual waste streams will be determined to be hazardous or not. Rather,
treatment and disposal techniques are presented which would cover the range of
possibilities, whether the waste is hazardous or non-hazardous.
Another technique potentially applicable to some solid waste streams - in
addition to land disposal — is incineration. If a waste which is determined
to be "hazardous" is proposed for incineration, the incinerator will have to
be designed and operated in accordance with RCRA requirements.
The available techniques that may apply to the Lurgi solid waste streams
are identified and evaluated in this section. Since no specific site is being
considered, a general overview of these techniques is first presented. This
is followed by an evaluation of the applicable controls to each individual
453
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Section 4
Solid Wastes
stream under each waste source type. The emphasis is on identifying the
applicability of the technique. For the reasons stated above and because the
characteristics of many of the solid waste streams are not known, it is not
possible in this manual to evaluate the optimum design and operation of these
techniques; optimum design/operation will vary with the site. It is assumed
that solid waste management facilities are captive, i.e., they only handle
wastes from the Lurgi plant.
454
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Section 4
Solid Wastes
Generic Control
4.3.1 Solid Waste Control
Several control techniques are potentially applicable for management of
solid waste streams. These techniques are summarized in Table 4-73. As
shown, they can be broadly divided into three control categories according to
their functions. The three control functions are treatment, reuse/resource
recovery, and disposal. Treatment may involve specific chemical/physical
processes for preparing the waste to meet certain reuse/resource recovery
specifications or to stabilize the waste for disposal. Reuse/recovery is one
form of ultimate or final control for the waste. This approach is usually
waste-specific, highly dependent on market availability and cost tradeoffs,
and may require specific treatment of the waste. Disposal is another form of
ultimate control for the waste. Most disposal techniques are land-based tech-
niques and thus are highly site-specific. The major site-specific factors
that affect the design, operation, and cost of land-based techniques are sum-
marized in Table 4-74. The following is a brief description of the individual
techniques.
455
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TABLE 4-73. SUMMARY OF SOLID WASTE MANAGEMENT TECHNOLOGIES
Ln
Technology
Treatment
Fixation/
Encapsulation
Incineration
Reuse /Re source
Recovery
Disposal
Landfill
Surface
Impoundment
Land
Treatment
Description
Chemical s are added to
stabilize or solidify
the wastes
Organic wastes undergo
voliute and tozicity
Waste is utilized in
application, or is
processed for reuse
in original a ppl i ca-
tion
• traded, end operated
to totally contain
natural or artificial
liners, leachate col-
groundwater aonitoring
system
Site ii excavated or
diked to form pond to
natant ii syphoned off
and treated or allowed
to evaporate
Watte i« treated by
incorporation into the
clfic procedures
Operational
Considerations
Wide variety of wastes
feasibility of solidi-
fying a particular
waste may differ with
different processes
Each type of organic
ferent operating char-
enced operators
required
located; cessation of
reuae requirea immedi-
ate alteration of Ban-
thereby, necessitating
long-term contracts
can be accepted; provi-
sions Bust be Bade for
reactive wastes
Siailar to landfill
Only United types
and aass of organic
Reliability or
Limitation*
Limited commercial
Only organic wastes
are limited and
economic viability
ia heavily influ-
enced by distance
to aarket
tained subject to
adequate site opera-
treae hydrogeolog-
ical changes or
earth aoveaents
Similar to landfill
Heavily dependent
upon weather condi-
tions
Waste
Equipment Generated
May include mixing Solidified
chamber, pumps, waste
metering devices,
storage tanks,
chemical feed
system
Waste transports- Ash; air pol-
vehicles
aent, waste and leachate
handling aachinery
Machinery to move Supernatant
waste to site, usu- and leachate
ally pipelines
Waste moving Possibly sur-
Bachinery, usually face runoff
trucks, and waste and leachate
incorporation
machinery, usually
bulldozers and discs
General
Comment*
Most processes are
applicable only to
small waate
streaas
Process is energy
ally acceptable
aanageaent tech-
nique
Site location and
design dependent
upon hydrogeolog-
ical conditions;
provisions must be
•ade for site care
after cessation of
operations
be removed when
operation ceases;
long-term site
care and mainte-
nance prograa Bust
be established
Site location
dependent on soil
conditions; provi-
sions Bust be aade
for long-term site
care
-------
TABLE 4-74. SITE-SPECIFIC FACTORS TO BE CONSIDEBED FOR TERRESTRIAL DISPOSAL OPTIONS
Climatolonical
• Wind conditions (e.g.. speed, directional flux, dilution factors, humidity, temperature, etc.)
• Precipitation (e.g., annual precipitation, storm intensity, snow contributions, etc.)
• Evapotranspiration rate (e.g., season variations)
Geologic Factors
• Physiographic features (e.g., runoff coefficient, slope, drainage patterns, erosional features, etc.)
• Surface and subsurface geology (e.g., outcrops, bedrock features, strike and dip of the bedrock, rock composition, etc.)
• Soil types (e.g., CEC capscity, texture, permeability, stratification, homogenous vs. heterogenous deposition, chemical compoaition,
percent of humic material, etc.)
• Seismic factors (e.g., ground shaking or rupture)
Hvdrogeologic Factors
• Drainage patterns
• Stream flow (e.g., velocity, perennial vs. intermittent, effluent or influent source, etc.)
• Surface waters (e.g., tidal effects, recharge vs. discharge points)
• Vadose xone (e.g., depth, moisture content, hysteresis patterns, storage capacity, etc.)
• Groundwater (e.g., depth, number of aquifers and relationships, confined or arteaian, nature of confining layer(s), capillary fringe
characteristics, etc.)
• Piezometric surface (e.g., streamline flux patterns due to seasonal or event related phenomena, influence of recharge/discharge areas,
streamline anomalies, etc.)
• Water quality (e.g., background vs. nndersite vs. downgradient, water uses - consumptive, irrigation, recreation, point source con-
tributors and their respective hydrogeologic pathways, etc.)
• Floodplain (100 year flood) (e.g., aerial flooding limits, degree of localized streamline pattern reversal, erosional consequences,
etc.)
• Wetlands (e.g., recharge vs. discharge source, wetland/groundwater continuity and pathway)
• Recharge and discharge areas (e.g., proximity to disposal area, volume of flow)
Land Use Factors
• Historic significance • Beneficial uses • Demographic setting • Ultimate land use
• Transportation corridor (access) • Cost • Geopolitical impact
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Section 4
Solid Wastes
Generic Control
Treatment
4.3.1.1 Treatment
For the purpose of this manual, only two solid waste treatment techniques
are considered. These are fixation/encapsulation and incineration. Other
techniques such as dewatering and neutralization are either considered as
part of the base plant operation, or part of the pollution control processes
in other media (air or water), depending on the origin of the waste.
Fixation/Encapsulation
Fixation and encapsulation are treatment processes which stabilize or
solidify waste constituents, or enclose the waste within other materials.
Fixation processes generally combine the concepts of solidification (the
alteration of the characteristics of a waste to attain desired structural
characteristics) and stabilization (the immobilization of waste constituents
by chemical reactions to form insoluble compounds or by entrapment within an
inert polymer or stable crystal lattice). Depending on the principal chemical
agents used, fixation processes can be categorized as cement-based, lime-
based, thermoplastic organic polymer, and glassification techniques. Encap-
sulation processes involve enclosing the waste in a coating or jacket of an
inert, relatively impermeable material so that contact between the waste and
water is prevented. Regardless of the specific chemicals used, typical fixa-
tion process operations involve mixing the chemical with the waste in a
reactor at a specific temperature and for a specific time period. The end
product is the fixed or encapsulated waste. In the case of encapsulation,
bulk wastes are enclosed in a stabilizing shell or container rather than being
intimately mixed with a stabilizing agent.
In principle, these processes are applicable to treating any waste by
applying "sufficient" chemicals. In practice, for economic reasons these
458
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Section 4
Solid Wastes
Generic Control
Treatment
techniques have only been applied to small volume waste streams or streams
which are prone to pozzolanic reactions. Chemical requirements for fixing the
latter type of streams are generally low. FGD sludge is one example of this
type of stream. Several proprietary, cement- or lime-based fixation tech-
niques have been used in fixing FGD sludges. Typical unit costs are reported
to be ill to $17 per metric ton of sludge fixed (80,81,82,83). Before using
these techniques for a specific waste, detailed treatability studies with
various chemical additives should be performed to: 1) establish that the
waste is treatable, 2) select the optimal process, and 3) minimize the cost
(80).
Incineration
Incineration is a controlled thermal decomposition process which reduces
the weight and volume of the waste by converting many component elements of
organic matter into gaseous forms. The extent of volume and weight reduction
is dependent upon the waste characteristics, the incineration process, and
equipment used. Incineration is also a viable detoxification process if the
toxicity results from the structure of the organic material as opposed to the
properties of the elements it contains (84). The end products of incineration
include carbon dioxide, water, ash, and other inorganic compounds. Incinera-
tion has been applied to various industrial wastes including refinery wastes,
sewage sludge, paper mill waste liquor, pharmaceutical wastes, and organic
chemical wastes. The common types of incinerators used for solid waste dis-
posal include rotary kilns, multiple hearths, and fluid bed reactors. The
annualized unit cost for a 1.0 x l.O7 kcal/hr capacity multihearth incinerator
is estimated to be $350/Mg.
459
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Section 4
Solid Wastes
Generic Control
Reuse/Recovery
4.3.1.2 Reuse/Resource Recovery
Reuse or resource recovery of waste streams is desirable from an envi-
ronmental standpoint because of direct waste reduction and perhaps displace-
ment of other resource requirements. Potential adverse environmental impacts
associated with disposal of the waste are eliminated although other impacts
may arise as a result of the reuse/recovery process utilized. This control
approach is highly waste—specific and is constrained by the availability of
markets or uses for the waste. Available reuse/resource recovery alternatives
will be identified as part of each specific waste stream discussion.
The economics of reuse/resource recovery are sensitive to site-specific
factors such as transportation costs and some general factors such as the
prices of the recovered/reusable materials and the cost of preparing the waste
for reuse/resource recovery. The feasibility of this control should be
thoroughly analyzed for each individual facility before implementation.
460
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Section 4
Solid Wastes
Generic Control
Disposal
4.3.1.3 Disposal
The bulk of the solid wastes from Lurgi facilities are likely to be
disposed of on land. Three potentially applicable land disposal techniques
for these streams are discussed in this section. These are landfill, surface
impoundment, and land treatment.
Landfills
Landfills have been widely used for the disposal of municipal refuse and
a range of industrial wastes. In landfilling, waste is brought to the dis-
posal site by truck or conveyor, spread in layers, and compacted with heavy
equipment. In most landfills the waste is covered with a thin layer of soil
at the end of the working day. The process is repeated until the desired
depth is reached or the available area is filled. A final cover of soil is
then added. The finished site is either revegetated or prepared for other end
uses.
Landfill can be accomplished in unexcavated depressions (the area-fill
method) or in excavated sites (the trench-fill method). These can be natural
sites or man-made sites such as coal mines. There are two major concerns in
landfill design and operation. Runoff from landfill sites may contaminate
surface water, and percolation from sites, after passing through the waste
pile, may contaminate groundwater. Runoff/surface water contamination may be
prevented by grading the site and by containment of runoff. Diversion
channels should be incorporated into the initial design of the landfill and
constructed before the site begins accepting waste (85). This prevents sur-
face runoff water from entering the site and generating leachate.
461
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Section 4
Solid Wastes
Generic Control
Disposal
Migration of leachate from the site can be controlled by lining the land-
fill with clay, concrete, asphalt, or plastic. Liners will often be required
if the solid waste is considered to be hazardous and may at times also be
desirable if the waste is nonhazardous. The choice of an appropriate liner or
liners will depend on 1) site—specific climatologic, geologic, and hydrogeo—
logic factors, 2) the compatibility of the liner and the waste to be con-
tained, and 3) the relative cost of compatible liners. A leachate collection
and treatment system may also be necessary. Such systems consist of per-
forated pipes and sumps placed in a layer of permeable sand at the bottom of
the fill. After being pumped out of the landfill, the collected leachate may
be treated in the gasification facility's wastewater treatment system or in a
separate treatment system (86).
In the absence of any judgment concerning whether or not a given waste
might ultimately be determined to be hazardous, and in order to remain inde-
pendent of site-specific factors, two landfill designs are considered in the
PCTM. These two designs cover the range from the simplest set of conditions
(nonhazardous waste and favorable site conditions that preclude the need for
liners) to the most complex (hazardous waste and unfavorable site conditions
which necessitate double liners). The two landfill designs are presented in
Figure 4-18. For the purpose of this assessment, the lined landfill design
assumes an upper liner consisting of 1 m of clay and a lower liner of 0.76 mm
synthetic material. Both landfill designs assume the completed fill will be
30 m above the original land surface with a slope of 3:1. Both landfills will
have a final cover consisting of 0.5 m sand and 0.3 m of clay. The most com-
plex, hazardous case would also include provision for closure and post-closure
care, monitoring, record keeping, and other requirements.
462
-------
a) LANDFILL—DOUBLE LINER
b) LANDFILL—NO LINER
ON
U)
CLAY LINER
DRAINAGE
LAYER
ORIGINAL
GROUND
LEVEL
ORIGINAL
GROUND
LEVEL
LEACHATE
COLLECTION
SYSTEM
LEACHATE
DETECTION
SYSTEM
Figure 4-18. Landfill designs
-------
Section 4
Solid Wastes
Generic Control
Disposal
The total capital investment and annualized unit costs as a function of
the site capacities for the two designs are presented in Figure 4-19. The
capital investment estimates include site preparation costs (e.g., cleaning
and scrubbing, groundwater monitoring and collection, liners), final cover and
revegetation costs, and landfill equipment costs. It was assumed no excava-
tion is required. The annualized costs include labor, fuel, and amortized
capital costs, but do not include hauling costs and other costs such as
administrative, closure/postclosure, and liability costs. These other costs
would depend on the classification of the disposed wastes under RCRA. EPA has
estimated that for a 50,000 Mg/yr commercial hazardous waste landfill,
administrative and other compliance costs amount to J9/Mg (87). Hauling costs
are a function of distance between the plant and the disposal site. It is
estimated that the unit costs for a roundtrip distance of 5 and 15 km are $2
and $4/Mg, respectively.
Land costs are not included in the cost data in Figure 4-19. About
1,100,000 m* of land is required per 106 Mg/yr of waste generated. Assuming
a land cost of $5,000 per 10,000 m2, the capital investments for the
lined and unlined landfills, as presented in Figure 4-19, will be increased by
more than nine percent. Additional land may be required for road construc-
tion, buffer zone, buildings, etc.
Surface Impoundments
Surface impoundments have been utilized widely by municipalities and
industries to process or dispose of waste liquids, sludges, and slurries.
Like landfill sites, the impoundments can be in natural depressions or in
excavated areas. Earthen dikes are usually constructed around the impoundment
area. Wastes are usually transported hydraulically to the impoundment. While
the wastes deposit at the bottom of the impoundment, the supernatant may be
removed and treated for discharge or recycle or allowed to evaporate.
464
-------
S
11
10
LEGEND
co
o
LU
I
K
O
UNLINED LANDFILL
DOUBLE LINED LANDFILL
A •» BOILER FLY ASH + BOTTOM ASH
B-GASIFIER ASH
C- A + B + FGD SLUDGE
+ CHEMICAL SLUDGE
+ RAW WATER TREAT-
MENT SLUDGE
+ BIOSLUDGE
11
10
7 8
o
6
Q
ai
N
5 g
z
z
o
10
20
TOTAL WASTE QUANTITY, 10* Mg/Yr
30 40 50
100
Figure 4-19. Capital investment and annualized unit cost for landfills
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Section 4
Solid Wastes
Generic Control
Disposal
Leachate migration from surface impoundments is controlled in much the
same way leachate from landfills is controlled. Diversion structures prevent
runoff from entering the site, while liners of in-place or compacted soils or
synthetic materials retard leachate migration down into the soil and ground-
water. As in the case of landfills, the PCTM considers both an unlined and a
double-lined impoundment in order to cover the range of possible experience.
The unlined impoundment represents the simplest set of conditions (non-
hazardous waste and favorable site conditions that preclude the need for
liners). The lined impoundment represents a much more complex situation
(hazardous waste and unfavorable site conditions that necessitate a double
liner system) .
When the surface immpoundment has been filled with waste, the site may be
closed in one of two ways: the waste may be left in place and covered with
clay and sand to prevent erosion and the infiltration of precipitation, or it
may be removed from the impoundment site for further treatment or final dis-
posal in a landfill (88). If wastes are left in place, the site becomes a
landfill (subject to any requirements pertaining to a landfill), and a long-
term site care and maintenance program will probably need to be established.
The cost per unit volume for surface impoundments is expected to be similar
to those of landfills with similar depths. However, since surface impound-
ments generally are used for the disposal of wet, not yet dewatered wastes, a
larger area may be required, per unit mass of dry solids, resulting in higher
disposal costs (i.e. some of the disposal area will be for disposing of
water). Disposal costs could be reduced if the wet wastes were dewatered
first, but there would be costs associated with dewatering. Similarly, dis-
posal costs may be reduced if appreciable natural dewatering occurs within the
surface impoundment due to settling and evaporation. This trade-off in cost
is highly dependent upon the waste characteristics and site-specific factors.
466
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Section 4
Solid Wastes
Generic Control
Disposal
Land Treatment
Land treatment refers to the use of land or soil as a medium to treat and
dispose of waste. Also known as landfarming, landspreading, and soil applica-
tion, land treatment has been practiced successfully for the treatment and
disposal of municipal wastewater treatment sludges and petroleum industry oily
wastes for many years. It relies on the ability of naturally occurring soil
microorganisms to decompose and utilize organic compounds under aerobic condi-
tions. The design and operation of land treatment systems would be affected
by whether or not the wastes were considered to be hazardous.
Wastes added to soil are subject to one or more of the following pro-
cesses: 1) decomposition/degradation; 2) leaching; 3) volatilization; and
4) incorporation into the soil matrix (e.g., through ion-exchange or adsorp-
tion). It is the degradation processes which treat the waste to reduce its
objectionable properties; these processes must be maximized during land treat-
ment, while the other processes must be minimized or eliminated. Applying bio-
degradable wastes, maintaining proper (aerobic) conditions for microbial
action, and avoiding or pretreating wastes which are toxic to the micro-
organisms will encourage degradation processes. Proper site selection will
minimize leaching and subsequent contamination of surface waters or ground-
waters. If volatile wastes are to be land-treated, subsurface injection of
the wastes or immediate tilling after application will minimize air pollution.
Wastes with high concentrations of toxic substances such as arsenic, cad-
mium, lead, and mercury should not be land treated in sites where food chain
crops are grown, as they may be incorporated into the soil and taken up by
plants (89). Prior to land treating wastes, long term studies should be per-
formed to confirm that the waste is degradable in the soil, that there is no
accumulation of'nondegradable toxic substances in the soil, and to establish
the area required for the particular soil-waste combination.
467
-------
Section 4
Solid Wastes
Generic Control
Disposal
Assuming biosludge is applied 10 times/yr, with an application rate of
0.015 Mg/m*/application, and a factor of 2 to account for land required for
roads, buffer zones, dikes, etc., it is estimated that 20,000 ma of land is
required to land treat 15,000 Mg/yr of biosludge. The annualized unit cost
for this is estimated to be $7.6/Mg.
468
-------
Section 4
Solid Wastes
Stream Control
Inorg. Ash/Sludge
4.3.2 Inorganic Ashes and Sludges
Inorganic ashes are the largest volume solid waste type from a Lurgi-
based plant. Waste streams in this waste type include gasifier ash, boiler
bottom ash, boiler fly ash, FGD sludges, dewatered chemical treatment sludges,
and raw water treatment sludges. The application of the available control
techniques to these streams are evaluated in this section.
4.3.2.1 Gasifier Ash
Gasifier ash consists of the inorganic, noncombustible portion of the
feed coal. This is the single largest volume solid waste stream in a Lurgi
facility; the flow rate of this stream (for the Rosebud coal case) is esti-
mated to be 38.3 Mg/hr. As discussed in Section 3, this stream is essentially
coal ash. Gasifier ash leachate may contain low levels of trace elements.
Tests of leachate for organics have not been conducted but organic levels
would be expected to be low. The following treatment, reuse, and disposal
techniques are applicable to this stream.
Treatment
The techniques applicable to treatment of gasifier ash are fixation and
encapsulation. Treatment of gasifier ash may be appropriate if future data
indicate that significant concentrations of trace metals are detected in
leachate from the gasifier ash. Currently available leachate data indicate
the trace elements in the leachate are low and should not be significantly
different from commercial coal boiler bottom ash.
The performance of treating this stream is dependent upon the specific
process (additive agent) used, and can only be established after thorough
treatability studies. The cost for treating this stream is also dependent
469
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Section 4
Solid Wastes
Stream Control
Inorg. Ash/Sludge
upon the process used. Assuming that the fixation processes which have been
applied to FGD sludge are applicable to treating this stream, the unit cost
will be about $ll-Jl7 per Mg (80,81,82,83).
Reuse/Resource Recovery
Gasifier ash may be utilized in a number of commercial applications, just
as boiler bottom and fly ash from fossil-fueled power plants have been used.
The National Ash Association reported that 24.3 percent of the coal boiler ash
produced in 1977 was reused in commercial applications (90). Ash has been
used commercially as a partial replacement for cement in concrete, as fill
material for roads and other construction projects, and as blast grit and
roofing granules. This alternative is likely to be applied only to ashes that
are collected dry. The cost of drying the quenched ash may be prohibitively
high. In addition, quenching the ash may change its properties, making it
unfit for reuse and negating this option in certain cases.
The major constraints on reuse of gasifier ash are those of the market
for the material. Market conditions will vary from site to site. Given the
fact that not all ashes from existing power plants are commercially utilized,
it may be difficult to find markets where all or significant quantities of the
ash from a Lnrgi facility can be reused. Users for the ash will likely be
limited to those who are located in the vicinity of the plant. The economic
viability of reuse decreases with increasing distance to market and hence
increasing transportation costs. If market conditions change so that commer-
cial reuse ceases, the waste management techniques for the ash will need to be
altered. Long-term contracts with users may lessen the potential for market
interruptions.
470
-------
Section 4
Solid Wastes
Stream Control
Inorg. Ash/Sludge
Disposal
Gasifier ash can be disposed of in landfills or in impoundments.
Landfill— In landfilling, gasifier ashes are usually brought to the
site by trucks, spread on the surface of land or previously placed ashes, and
compacted. As the pile height increases, a working face with safety slope
(assumed to be 3:1) is developed to ensure stability of the fill.
If the gasifier ash is determined to be nonhazardous, an unlined landfill
might be possible in the most favorable case (e.g. favorable site conditions).
On the other hand, if the wastes were considered to contain hazardous com-
ponents, a lined landfill would be necessary where hydrogeologic or other site
factors are unfavorable.
Based on current and proposed practices in synfuel and other industries,
this stream is likely to be codisposed with other solid waste streams from
the plant in one common landfill. Although more than one landfill/disposal
facility (e.g., one landfill design for hazardous waste and one landfill for
nonhazardous waste) may be operated in a Lurgi facility, for costing purposes
in the PCTM, one landfill accepting the wastes from the Lurgi plant is
assumed. By considering the alternatives of all wastes being disposed of in a
nonhazardous waste landfill with no liner and in a hazardous waste landfill
with double liners, the range of landfill cost estimates in the PCTM should
bracket the costs that might be encountered in practice for any split of the
wastes between hazardous and nonhazardous categories.
Assuming a landfill is designed to accept the gasifier ash, boiler bottom
and fly ash, FGD sludge, and raw water treatment sludges, the capacity of the
landfill would be 420,000 Mg/yr for the Rosebud coal case. As shown in Figure
471
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Section 4
Solid Wastes
Stream Control
Inorg. Ash/Sludge
4-19, the annualized unit costs for the unlined and lined landfill designs
will be $2.7/Mg and $5.3/Mg, respectively. The total annualized costs that
would be attributable to the gasifier ash stream would be $815,000/yr and
$l,600,000/yr, respectively, for the two landfill designs.
If the gasifier ash were disposed of by itself in a separate, dedicated
landfill, annualized unit costs for this smaller landfill (302,000 Mg/yr)
would be $2.8/Mg and $5.3/Mg for a nonlined and lined landfill, respectively.
The total annualized cost for this case would be i850,000/yr and
il,600,000/yr, respectively.
Surface Impoundment— One major difference between disposing of gasifer
ash in a landfill and a surface impoundment is the means of transporting the
ash to the disposal site. Surface impoundments are usually used for storage
or disposal of wet ashes which are transported hydraulically to the impound-
ment in a fluid state. For storage impoundments, the ashes are dredged
periodically and disposed of in landfills. For disposal impoundments, the
ashes are left in place and are covered to prevent erosion and infiltration of
precipitation. The unit costs for surface impoundments are similar to the
costs of landfill ing, assuming that no excavation is required. The total
disposal costs may be higher because surface impoundments generally are used
for the disposal of wet, not yet dewatered wastes. Hence, extra capacity is
needed for the water content in the waste.
4.3.2.2 Boiler Bottom Ash
The flow rate of this stream is estimated to be 1.3 Mg/hr for the Rosebud
coal case, assuming 15% of the total feed coal to the plant is used as feed to
the boiler. The treatment, reuse, and disposal techniques for this stream
472
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Section 4
Solid Wastes
Stream Control
Inorg. Ash/Sludge
would be similar to those for gasifier ash. Where landfill is the technique
selected this stream is likely combined with other solid waste streams and
disposed of in one common landfill. As discussed in Section 4.3.2.1,
annualized unit costs for landfilling the solid waste streams in a common
landfill are estimated to be $2.7/Mg and $5.3/Mg, respectively, for a non-
lined and lined landfill. Based on these unit costs, the annualized disposal
cost attributable to this stream would be $28,000/yr and $54,000/yr, respec-
tively.
4.3.2.3 Boiler Fly Ash
The flow rate of this stream is estimated to be 5.2 Mg/hr for the Rosebud
coal case, assuming 15% of the feed coal to the plant is used as feed to the
boiler. Available technology requires that gasifier ash and boiler bottom ash
be quenched before any subsequent handling or disposal. Boiler fly ash, how-
ever, may be collected and handled dry (via a dry ESP or baghouse) or wet (via
a wet ESP or scrubber). The choice of collection technology depends in part
on site-specific disposal factors and also on factors specific to coal type.
Some fly ashes tend to undergo fixation reactions when wetted, much as
Portland cement does.
Recently, more power plants began converting to dry collection systems
for boiler fly ash. When boiler fly ash is collected and handled entirely in
the dry form, it can be potentially recovered as a resource. The available
management techniques are similar to those discussed under the gasifier ash
section. Where landfill is the technique selected, this stream is likely
combined with other solid waste streams and disposed of in one common land-
fill. As discussed in Section 4.3.2.1, annualized unit costs for landfilling
the solid waste streams in a common landfill are estimated to be $2.7/Mg and
473
-------
Section 4
Solid Wastes
Stream Control
Inorg. Ash/Sludge
$5.3 Mg, respectively, for a non-lined and lined landfill. Based on these
unit costs, the annualized costs attributable to this stream would be
il!0,000/yr and J220,000/yr, respectively.
4.3.2.4 Boiler FGD Sludge
The flow rate of this stream is estimated to be 7.8 Mg/hr for the Rosebud
coal case, assuming 15% of the total coal feed to the plant is used as feed to
the boiler. Applicable techniques for controlling FGD sludge include fixa-
tion, surface impoundment, and landfills. These techniques have been widely
used in disposing of FGD sludge from existing coal-fired power plants.
Treatment - Fixation
FGD sludge typically contains 30 to 50 percent solids after thickening or
filtration. It is not a good landfill material in this form because it is
thixotropic. To rectify this problem, treatment by fixation may be prac-
ticed. Several patented processes are available commercially for fixing FGD
sludges. One mixes the sludge with boiler fly ash and lime while another adds
a proprietary chemical (basically a cementitious agent) as the hardening
material. Typically these proprietary processes involve dewatering the sludge
and combining the sludge with proprietary additives which promote pozzolanic
reactions, resulting in a material less leachable, less permeable, and struc-
turally more suitable for landfill. Proprietary methods which have been suc-
cessfully applied to fixing FGD sludges include Chemfix (addition of Portland
cement and sodium silicate), Calcilox (calcined blast furnace sludge and
lime), IUCS - Poz - 0 - Tec (fly ash and lime under controlled temperature and
moisture conditions), ICT (lime, bentonite, and cement), and Research -
Cottrell (sludge dewatering prior to fly ash admixing).
474
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Section 4
Solid Wastes
Stream Control
Inorg. Ash./Sludge
Unit costs for these treatments range from ill to ill? per Hg of dry
solids (80,82). Another treatment alternative practiced in many coal-fired
power plants is mixing the FGD sludge with boiler bottom and fly ash before
disposal. For coals that generate ashes that are alkaline, mixing the ash
with the sludge will also initiate pozzolanic reactions.
Disposal
Disposal techniques applicable to FGD sludge include landfill and surface
impoundment. Because of its low solids content and structural instability,
FGD sludge may be treated by fixation or mixing with boiler fly ash prior to
disposal. The use of surface impoundments will reduce the liquid content of
the sludge, but the dried solids are readily soluble when exposed to moisture
after disposal, so proper surface impoundment closure will be essential.
Assuming this stream is mixed with fly ash and other inorganic ashes
before disposal in a common landfill, the annualized unit costs for a nonlined
and lined landfill are estimated to be $2.7/Mg and iS.S/Jtg, respectively (see
Section 4.3.2.1). The annualized cost attributable to this stream would be
il70,000/yr and $330,000/yr.
4.3.2.5 Dewatered Chemical Precipitation and Raw Water Treatment Sludges
The applicable treatment and disposal techniques for this stream would be
similar to those for the FGD sludge, except that the optimum fixation process
and hence the treatment costs may differ. Where landfill is the technique
selected, this stream is likely codisposed with other solid waste streams in
one common landfill. Assuming unit costs of $2.7/Mg and i5.3/Mg respectively,
for a nonlined and lined landfill, disposing of dewatered chemical
precipitation sludge will cost i8,500/yr and il7,000/yr, while disposing of
dewatered raw water treatment sludge will cost $4,000/yr and iS.OOO/yr.
475
-------
Section 4
Solid Wastes
Stream Control
Byproducts
4.3.3 Recovered Byproducts
This source type includes elemental sulfur recovered from the bulk sulfur
removal processes, excess coal fines, and collected dust from particulate
control.
4.3.3.1 Recovered Elemental Sulfur
Recovered elemental sulfur can be sold as a byproduct. However, the sul-
fur may be contaminated with carbonaceous impurities (from Claus plant) or
vanadates, thiosulfates, and thiocyanate salts (from Stretford plant), making
it non-marketable without further in-plant processing. If the sulfur cannot
be sold, it can be disposed of in landfills.
There is a potential for elemental sulfur to be oxidized in a landfill
environment and such oxidation result in acid generation. Acidic leachate
could solubilize trace elments from other wastes in the landfill. Hence, it
may be desirable to dispose of waste elemental sulfur with alkaline wastes
such as FGD sludges.
4.3.3.2 Excess Coal Fines
Excess coal fines are the small particles of coal (underflow from the
secondary screening process) that are produced in excess of steam boiler feed
requirements. Applicable treatment, reuse, and disposal techniques are
described below.
Treatment
Excess coal fines may be treated so that they can be reused as gasifier
feed. This treatment consists of blending the coal fines with a binder
476
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Section 4
Solid Wastes
Stream Control
Byproducts
(e.g., bentonite) and forming this mixture into pellets by forcing it through
a die and cutting it into pieces of the desired length. The resulting pellets
are approximately 2.5 cm in diameter and 5.0 cm in length.
Reuse
Excess coal fines may be combusted onsite to generate excess steam or
power for export. Excess coal fines can also be gasified in a gasifier which
can accept fine coal particles as feed (such as the Texaco or GET gasifier) in
order to produce additional synthesis gas. A third option is to sell the
excess coal fines to offsite users (e.g., coal-fired power plants). The third
option will depend on prevailing market conditions. The potential of this
option is further constrained because the transportation of coal particles
less than 0.9 cm in diameter presents safety problems and results in high
losses unless closed containers are used. Since these containers are not
widely used for coal transportation, significant delivery costs could be
incurred.
Disposal
Excess coal fines can be disposed of in landfills. In the actual dis-
posal operation, spraying the fines with water or some other means of dust
control may be necessary.
4.3.3.3 Collected Dust from Particulate Control
This secondary waste stream consists primarily of coal dust emissions
collected throughout the gasifier installation. This dust may be treated,
reused, or disposed of with the excess coal fines.
477
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Section 4
Solid Wastes
Stream Control
Organic Sludges
4.3.4 Organic Sludges
This waste category includes one stream, namely, biosludge from the bio-
logical treatment process. The flow rate of this secondary waste stream has
been estimated to be 1.9 Hg/hr for the Rosebud coal case.
4.3.4.1 Treatment
Although no data are currently available on the composition of this
waste, it is highly probable that some of the nonbiodegradable toxic organics
that might have been present in the raw process liquor (such as polyclic
organics and aromatic amines) will end up in the sludge through sorption.
These organics can be destroyed by incineration.
Incineration
Incineration of municipal and industrial biological oxidation sludges has
been practiced for many years. The application of this treatment technique to
this organic sludge could be expected to destroy greater than 99% of most
organics and reduce the quantity of waste that requires ultimate disposal.
Assuming the biosludge is 20% solids and 70% of the solids are volatile, the
total waste quantity will be reduced by 94% through incineration.
Table 4-75 presents the estimated costs for incinerating the biosludge in
a rotary kiln incinerator (1.0 x 107 kcal/hr) with energy recovery. The
heating value of the biosludge was assumed to be 5,500 kcal/hr. As shown in
Table 4-75 the capital investment for incineration is estimated to be 10 to 12
million dollars; the total annualized cost is 5.2 million dollars per year, or
about $350/Mg.
478
-------
Section 4
Solid Wastes
Stream Control
Organic Sludges
TABLE 4-75. ESTIMATED TREATMENT/DISPOSAL COST FOR BIOSLUDGE
Item
Total Capital Investment, $10*
Total Annual ized Cost, $10*
Annual! zed Unit Cost, $/Mg
% Base Plant Capital Investment
% Base Plant Annual ized Cost
Incineration
10 to 12
5.2
350
1.3 to 1.6
2.8
Land Treatment
0.4
0.2
10.3
0.05
0.1
Two secondary waste streams are generated by this process, namely, a flue
gas stream and a residue stream. It is not possible to estimate the charac-
teristics of the flue gas, but the cost for controlling this is included in
the incinerator cost estimates presented in Table 4-75. The incinerator is
assumed to be equipped with a scrubber for particulate control.
The flow rate of the residue stream is estimated to be 0.11 Mg/hr,
assuming a 99.9% destruction of organics (see Section 4.2). The residue is
expected to contain about 0.33% organics and other inert materials. Most of
the trace metals originally present in the biosludge will be accumulated in
the residue. Applicable treatment/disposal techniques include fixation/
encapsulation and landfill.
479
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Section 4
Solid Wastes
Stream Control
Organic Sludges
4.3.4.2 Disposal
Biological treatment sludges may be disposed of in landfills, surface
impoundment, or by land treatment. Landfill and surface impoundment have been
discussed in the previous sections. The following is a brief description of
land treatment of biosludge.
In land treatment, biological treatment sludge may or may not require
dewatering prior to application to the land. Depending on the physical state,
or the degree of dewatering performed, the sludges are transported to the land
treatment site either by truck or hydraulic means. The sludges are spread
with bulldozers, loaders, graders, or box spreaders. The site is generally
subdivided into several plots which are treated in sequence. After waste
application and evaporation of any associated water, the plot is plowed
periodically until the waste has been decomposed. Chemicals such as nitrogen,
phosphorus, and potassium may be added periodically as nutrients, and neutral-
izing agents (e.g., lime) may be added to maintain the proper pH level
(7 to 9).
The estimated costs for land treating the biosludges are summarized in
Table 4-75. The capital investment presented in Table 4-75 includes land
preparation costs ($0.52/m2), waste spreading equipment costs ($160,000), and
monitoring well costs ($25,000). The annualized costs include the cost of
labor, fuel, monitoring, maintenance, and amortized capital. No land or
transportation costs are included. It is estimated that about 20,000 m2 of
land is required. Assuming a unit land cost of $5,000 per 10,000 m2,
this would increase the total capital investment by more than 25%. Depending
on the distances involved, including transportation costs may more than double
the annualized unit cost.
480
-------
Section 4
Solid Wastes
Stream Control
Spent Catalysts
4.3.5 Spent Catalysts and Sulfur Guard
Four types of catalysts may potentially be used in a Lurgi-based plant.
These materials eventually become deactivated and require decommissioning and
disposal. Spent sulfur guard, which is not a catalyst, is also included in
this discussion because 1) this is also a small volume, intermittent stream,
and 2) applicable controls are similar. Table 4-76 summarizes the estimated
average annual quantities of spent catalysts. It should be pointed out that
although the flow rates are presented in Hg/yr, these streams only occur
intermittently, about once every three to five years. Due to the proprietary
nature of most catalysts, there is little information available on the reuse
and disposal techniques applicable to specific catalysts. Because of this,
spent catalyst reuse, treatment, and disposal are discussed in general terms
in the following sections, with only brief mention of specific techniques
applicable to individual catalysts.
TABLE 4-76. SUMMARY OF FLOW RATES FOR SPENT CATALYSTS AND SULFUR GUARD
Stream Flow Rate, Mg/yr
Spent Shift Catalyst 40
Spent Sulfur Guard 250
Spent Methanation Catalyst 20
Spent Synthesis Catalyst 50-3500
Spent Claus Catalyst 7
481
-------
Section 4
Solid Wastes
Stream Control
Spent Catalysts
4.3.5.1 Treatment
Spent catalysts may be chemically fixed or encapsulated before final dis-
posal to prevent leaching of undesirable substances. When fixing these with
cement-based techniques, the weight of the fixed material may be twice its
original weight (80), i.e., a 1:1 chemical/spent catalyst ratio may be needed.
As discussed before, the performance and cost for this alternative can only be
established after thorough treatability studies.
4.3.5.2 Resource Recovery and Reuse
Spent catalysts may be reused after reactivation by a contractor or the
original vendor. Also, the metal components of the catalyst may be recovered
for other uses. The economics of the required regeneration processes and the
market value of the metals will determine whether recovery and reuse are pos-
sible. In practice, return of the spent catalyst to the vendor for processing
will likely be the approach of choice in many cases.
Because of the current tight cobalt supply and the high demand for this
metal, it appears that the cobalt-based shift catalyst could be economically
recovered. Increasing cobalt prices have fostered interest by catalyst manu-
facturers to develop improved methods to regenerate the catalyst, to recover
the metal, and to search for other catalysts (mainly nickel-based) which can
be used in place of the cobalt-based shift catalyst.
Regeneration of spent sulfur guard, Claus catalyst, Mobil H synthesis
catalyst, and Fischer-Tropsch synthesis catalyst is expected to be economi-
cally unattractive because of the low market values of the base materials of
these catalysts (zinc for sulfur guard, bauxite for Claus catalyst, zeolite
for Mobil M synthesis catalyst, and iron for Fischer-Tropsch synthesis cata-
lyst).
482
-------
Section 4
Solid Wastes
Stream Control
Spent Catalysts
4.3.5.3 Disposal
Spent catalysts and sulfur guards may be chemically fixed or encapsulated
before final disposal to minimize leaching of toxic substances or they may be
disposed of once they are decommissioned. When disposed of, these materials
are likely to be placed in landfills. The overall spent catalyst generation
rate is largely dependent upon the synthesis process used in the plant. As
discussed before, assuming these materials are disposed of in one common
landfill with the other solid wastes from the plant, the annualized unit costs
would be $2.7/Mg and $5.3/Mg, respectively, for a nonlined and lined landfill.
The annualized disposal costs for these materials would range from $1,000 to
$20,000, depending on the landfill design and the synthesis process used.
483
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SECTION 5
DATA GAPS AND LIMITATIONS
Because of the inherent gaps and limitations which exist in the data base
used to develop this manual, it is important for all users to understand the
extent to which the performance and cost estimates presented here are support-
ed by actual operating data, extrapolations from closely related applications,
and/or engineering calculations/judgments. The purpose of this section is to
convey a sense of the applicability and completeness of the data base used in
the development of this manual.
Since no commercial Lurgi-based SNG or indirect liquefaction facility
currently exists in the U.S., and since very limited data are publicly avail-
able for the only significant facility of this type outside the U.S. (SASOL,
S.A.), background data for this manual could not be drawn exclusively from
operating commercial facilities. Rather, considerable data were obtained from
other commercial applications of Lurgi gasification and/or synthesis tech-
nologies, from applications of candidate controls in related industries, and
from pilot- or bench-scale studies.
Since the early 1970s EPA has sponsored a significant environmental
assessment program addressing synthetic fuels from coal technologies. This
work has involved a combination of theoretical studies and plant data acquisi-
tion programs. These efforts have contributed both data and background know-
ledge used in the development of this manual. Table 5-1 lists the major
data acquisition programs sponsored or cosponsored by the EPA which have pro-
vided background data used in the development of this PCTM. As indicated, the
data encompass specific research projects, pilot-level sampling and analysis
projects, and source sampling of foreign and domestic commercial production
facilities.
484
-------
TABLE 5-1.
COMPLETED AND ONGOING DATA ACQUISITION PROGRAMS AT COAL
GASIFICATION FACILITIES SPONSORED OR CO-SPONSORED BY THE EPA
-F-
00
Cn
Facility
Information Classification
Coal Used
Medium/High Btu Gasification and Indirect
Liquefaction Facilities (Foreign)
• Lurgi or Lurgi-Type Gasification
- Kosovo, Yugoslavia
- SASOL, S.A.
- Westfleld, Scotland
• Koppers-Totzek Gasification
- Hodderfontein, S.A.
- Ptolemais, Greece
- Kutahya, Turkey
• Winkler Gasification
- Kutahya, Turkey
• Texaco Gasification
- Federal Republic of Germany
Low-Btu Gasification Facilities (D.S.)
e Wellman Galusha
- Site No. 1
- Site No. 2
r Chapman/If ilputte
* Riley
* Stoic (Foster Wheeler)
Control Research Facilities
• Raw/Acid Gas Cleanup
(Fluidiied Bed Gasifier)
• Wastewater Treatability Studies
• Pollutant Identification
(Bench Scale Gasifier)
• Ash Leaching Evaluations
Other Domestic Facilities
• Texaco Gasification
- Ammonia from coal plant, TVA
• Rectisol Acid Gas Cleanup
Data acquisition
Plant visit and discussions
Plant visit and discussions
Data acquisition
Data acquisition (TVA R EPA)
Plant visit and discussions
Plant visit and discussions
Lignite
Low rank bituminous
Various
High vol. "Bn bituminous
Bituminous
Lignite
Lignite
Data acquisition (EPRI, TVA, & EPA) 111. No. 6 bituminous
Data acquisition
Data acquisition
Date acquisition
Data acquisition
Data acquisition (DOE £ EPA)
North Carolina State University
University of North Carolina
Research Triangle Institute
University of Illinois
Data acquisition
Texaco, Wilmington, California
Anthraci te
Lignite
Low sulfur bituminous
Ligni te
Western bituminous
Various
Various
Various
Various
Hi turn inous
Oil partial oxidation
Products
Medium Btu gas
Various via Indirect
1iqnefact ion
Test center
Ammonia
Ammonia
Ammonia
Ammonia
Fuel gas
Test center
Fuel gas
Test center
Fuel gas
Test center
Test center
Test center
Ammonia
Process hydrogen
-------
Section 5
Data Gaps/Limitations
Generally, estimates of the characteristics of uncontrolled waste streams
were based upon available data from operating Lurgi-type facilities (SASOL,
S. A. , Kosovo, Yugoslavia, and Vestfield, Scotland). These data are believed
to reasonably represent the waste streams which will be encountered in future
U. S. Lurgi-based synthetic fuels facilities. However, the base plant waste
stream characteristics are extrapolations from the referenced data sources and
the accuracy of these extrapolations is dependent on the representativeness of
the facility from which the test data were taken. The representativeness, in
turn, is dependent on coal feedstock properties as well as the process design
features and operating conditions.
Since very limited data on the performance of pollution control technol-
ogies are available from actual operating synthetic fuels plants, many assump-
tions were made to estimate the performance and cost of controls applied to
Lurgi-based facilities. The majority of the available data have been obtained
from: 1) bench- and pilot-scale evaluations of control technologies using
waste streams from synthetic fuel processes, and 2) performance of controls on
similar waste streams from related industries. This section summarizes the
industry sources used and indicates the applicability of that information to
Lurgi-based synfuels facilities. Some extrapolations of control technology
performance and costs can be made with a relatively high degree of confidence
(e.g., boiler flue gas controls). However, other extrapolations are based on
unproven (although not necessarily incorrect) assumptions and engineering
calculations/judgements.
Readers of this manual should use the information in this section to
understand the extent and applicability of the data base supporting the waste
stream characterization data presented in Section 3 and the pollution control
performance and cost data presented in Section 4. As commercial synthetic
fuel plants are built, the EPA will continue conducting research in order to
486
-------
Section 5
Data Gaps/Limitations
develop a more comprehensive data base. In the interim, the Agency encourages
facility planners, permit officials, and other interested parties to take
advantage of, and interact with EPA to improve, the information contained in
this document.
Tables 5-2 through 5-4 summarize (for gaseous, aqueous, and solid media,
respectively) the major sources of data used to develop this manual and some
gaps and limitations associated with that data. Table 5-5 presents similar
types of information for the products and byproducts produced by the subject
technologies of this PCTM. Waste streams are addressed first in Tables 5-2
through 5-4, followed by information on pollution controls for those waste
streams. For each waste stream and pollution control the source of the data
used in the manuals is identified by a "key" and the commercial development
status of that source of information is noted. Reference is also made to
Sections of the PCTM where additional data/discussion is presented.
Not all of the waste streams and control techniques addressed by this
manual are included in Tables 5-2 through 5-4. The streams included are
believed to be the major waste streams, in terms of waste volume and/or ex-
pected pollutant loadings, which are unique to Lurgi-based synfuels facili-
ties. The controls included in the tables are examples of those that can be
used to treat the major waste streams.
Some of the waste streams and applicable controls that are not listed in
Tables 5-2 through 5-4 are those that have been well characterized or commer-
cially proven in related industries. These streams/controls are considered
nonunique to synthetic fuels facilities. For example the compositions of flue
gases from coal-fired boilers are well defined, based on numerous evaluations
of industrial and utility boilers. Similarly, the performance and cost of
487
-------
Section 5
Data Gaps/Limitations
controls (such as flue gas desulfurization systems, ESPs, and baghouses) for
boiler flue gases are also well defined. Other waste streams (and applicable
controls) not discussed in Tables 5-2 to 5-4 include those from coal storage
and handling operations and raw water treatment facilities.
A data gap or limitation which exists for essentially all pollution con-
trol technologies relates to reliability. Because most of the potentially ap-
plicable pollution control technologies have not been employed in Lurgi-based
synthetic fuels facilities, few directly related reliability data are avail-
able. Further, the overall characteristics and variability of waste streams
in coal conversion facilities are often sufficiently different from those
encountered in other industries so that it is not certain whether reliability
data accumulated in other industries will be applicable to coal conversion
processes. These are particularly significant considerations with respect to
wastewater treatment technologies and, to a lesser extent, hold for gaseous
and solid waste control technologies also. It should be noted, however, that
such data gaps cannot be addressed for specific controls prior to the applica-
tion of these controls to coal conversion waste streams.
Research needs aimed at filling the identified data gaps for specific
waste streams and pollution controls are also presented in Tables 5-2 through
5-4. These research needs include studies that can be implemented:
• At the bench- and pilot-scale,
• At currently operating gasification facilities in foreign
countries, and
• By monitoring the performance of U.S. synfuels facilities after
startup.
In general, these additional data needs fall into one of three
categories:
488
-------
Section 5
Data Gaps/Limitations
Data required by facility owners either to evaluate the poten-
tial applicability of a pollution control process or to design
the processes selected for use. This type of data is generally
obtained through bench- , pilot-, and commercial-scale testing
as part of project feasibility studies and engineering design
activities.
Data that would contribute to a better general understanding of
1) the characteristics of uncontrolled waste streams and the
dependence of those characteristics on the type of coal
gasified, the design of a facility, and its operating
characteristics, and
2) the performance, reliability, capital investment require-
ments, and operating costs of pollution controls.
Data relating to the characteristics and hence potential
control needs for secondary waste streams produced by
pollution controls.
489
-------
TABLE 5-2. DATA GAPS AND RESEARCH NEEDS - CASEOUS MEDIUM
Keys for Data Sources
Technology Status Keys
Data Sources/Location
Al
A2
A3
B
C
D
Commercial or demonstrat ion- scale application in a
Lurgi or Lurgi- type gasification facility
Commercial or demonstration-scale application on an
Cominerci al or demonstrat ion- scale application of a
similar stream in a non-Lurgi gasification facility
Bench- or pilot-scale testing
Technology transfer from another industry - similar
but not identical streams
Conceptual
1 .
2.
3.
4.
5.
5A.
SB.
5C.
5D.
5E.
6.
7.
Kosovo, Yugoslavia Lurgi- type facility
Sasol, S.A.
Trials of American coals at Westfield, Scotland
treatability test facility
Tech no 1 ogy transfer from related industries
Petroleum refining/petrochemical product ion
Coke product ion
Electric power product ion
Natural gas processing
Conceptual or proposed designs/engineering
studi es
Vendor supplied information
Stream or Control Technology
Data Gaps and Limitations
Research Needs
VD
O
Vi'aste Streams
Rectisol Acid Gases
Available data have been obtained fron
commercial scale facilities. Sulfur and
nitrogen components of acid gases are based
primarily upon data froa the Kosovo.
Yugoslavia gasification facility. Hydro-
carbon concentrations are based upon data
from ANR for test gasification of North
Dakota lignite at Sasol, S.A.
Status: Al. A3
Data Sources: 1, 2, 3, 6, 7
PCTM Reference: Sections 3.3.3, 4.1.1
Uncertainties in acid gas compos itions relate
primarily to uncertainties in the raw Lurgi
gas composition. The specific design of a
Rectisol unit will depend on the raw gas qual-
ity, the clean synthesis gas purity require-
ments, tnd atmospheric emission constraints.
In addition, Rectisol unit design can be im-
pacted if a facility requires the generation of
a COa~rich offgas for sale or reuse. Therefore,
the design of a Rectisol unit is a very complex
site-specific issue and acid gas composition
will vary from site-to-site.
In particular, the mercaptan and organic levels
in the acid gas have not been established.
Kosovo data are not consistent with data from
GPA, Sasol, or Westfield. It is not known
whether the mercaptan and organic compos it ions
are functions of coal type and/or gasification
operating conditions.
Sulfur and organic species in Lurgi product
gas need to be determined for specific coals
and gesifier designs in the U.S. Source
testing at the first U.S. Lurgi plants offers
the best opportunity for obtaining data.
(Continue d)
-------
TABLE 5-2. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Research Needs
Coal Lockhopper Gases and Transient
Waste Gases
Characterization is based on data from
Kosovo, Yugoslavia facility and from
Lurgi product gas composition data from
Sasol, \Vestfield, and the Great Plains
proj ect.
Status: Al
Data Sources: 1, 2, 3, 6
PCTM Reference: Sections 3.2.4. 4.1.2
Control Technologies
Nonselective Rectisol
Operating data fron Sasol and designs for
Great Plains serve as the main data base.
Secondary Waste Streams: naS-lean offgases,
Methanol/water still bottoms
Status: Al
Data Sources: 2, 6, 7
PCTM Reference: Sections 3.3.3. 4.1.8.2
Selective Rectisol
Operating data was derived for Lurgi gas-
ification fron a partially selective unit
at Kosovo, Yugoslavia. Additional infor-
mation was obtained from design for Wesco
Lurgi facility and highly selective units
operating in entrained gasification
applications.
Secondary Y/aste Streams: llaS-rich offgases,
COj-rich offgases, Methanol/water
still bottoms
The levels of coal dust and tar aerosols found
in the low-pressure coal lockhopper vent gas
were based on data taken at Kosovo. Design
features and operating procedures may be dif-
ferent at facilities built in the U.S. No
experience it reported in publicly available
literature on the operability and performance
of air ejected lockioppers.
Uncertainties with high-pressure lock gas and
transients relate primarily to operability of
controls. Compositions are only approximately
known; however, uncertainties do not influence
choice or design of controls.
Data gaps relate primarily to feed composi-
tion rather than performance of nonselective
Rectisol. There is some question as to the
distribution of low molecular weight mercap-
tans between the naphtha and acid gases.
As noted above, feed composition presents
some uncertainties. Data gaps also relate
to selectivity obtainable as a function of
cost and energy requirements. The extent to
which organics and CO can be excluded from
either bulk II,S rich or CO2 rich fractions
is unclear.
Data on the dust and tar levels in air
ejected lock gases may be obtained at Sasol,
S.A. and at the first U.S. facilities which
become operational. Additional data from
older Lurgi facilities or pilot gasification
facilities are not likely to provide further
insight.
No additional research needs are identified.
Uncertainties do not affect choice or design
of controls for nonselective Rectisol acid
gases. Nonselective acid gas removal is
essentially a process step and not pollution
control.
Licensors are believed to have most of the needed
data. Since selective Rectisol can serve both
process and pollution control functions, source
testing at the first U.S. facilities would verify
emissions levels reported to be achievable by
the vendors.
Status: Al
Data Sources: 1, 5A, 6, 7
PCTM Reference: Sections 3.3.3, 4.1.1,
4,1.8.1
(Cont l nue (I)
-------
TABLE 5-2. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Research Needs
r-0
Amine Systems
Operating data are from refinery, coke
plant, and natural gas applications.
Amine processes could have major appli-
cations in Lurgi facilities for removing
organics from Claus feeds. !IaS enrich-
roent is also obtained with amlne units.
Secondary Waste Streams; Amine solution
degradation products (can be either
aqueous blowdown or filtered solids)
Status: A2, C
Data Sources: 5A, 5D, 6, 1
PCTM Reference: Sections 4.1.1, 4.1.8.1
Claus
Operating data are from applications in
coke plants, oil refineries, and gas
processing plants.
Secondary Waste Streams: Knockout drum
condensate. Spent catalyst. Catalyst
regeneration offgas
Source: A2, C
Data Sources: 5A, 5B, 5D, 7
PCTM Reference: Sections 4.1.1, 4.1.8.1
known nor is the degree of HXS enrichment
attainable in high C0a applications. Accu-
rate costs related to such selectivity are
not publIcly available.
Existing facilities provide data covering
many of the constituents expected in coal
gasification. Uncertainties relate to mini-
mum levels of HXS processable by the straight
through node. With Lurgi acid gases, organ-
ics may preclude split flow node. Use of
oxygen or enriched air offers advantages, but
operating data from existing facilities are
not currently available.
There is limited data on the maximum allow-
able concentration of contaminants such as
heavier organics and IICN.
The effect of feed fluctuations on tail gas
composi tion is not well established.
No data are available on characteristics and
generation rate of spent catalyst.
Licensors are believed to have most of the data
indicated. Some of these may be obtainable from
the vendors. Amine systems can serve a pollu-
tion control function in Lurgi applications;
hence, source testing of the first U.S. facil-
ities could verify design data.
The practical limits for straight through
operation in high C0a applications need defini-
tion. Existing facilities may provide some of
these data. Operating experience for oxygen-
fired units may also be obtainable from vendors
or plant operators.
Source testing at the first U.S. facilities can
provide data base for effects of feed concentra-
tion and fluctuations on tail gas composi tion
and un i t performance.
Spent catalyst characteristics are not likely
to affect disposal options, so that additional
data may not be needed.
(Continued)
-------
TABLE 5-2. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Research Needs
U>
Stretford
Operating data are primarily from non-
gasification applications with low CO,
levels. Limited information available
for the only existing unit in Lurgi gas-
ification service.
Secondary Waste Streams: Stretford
solution purge stream, Oxidizer
vent gas
Status: Al. A3
Data Source: 2, 5A, 5B, 6, 7
PCTM Reference: Sections 4.1.1, 4.1.8.2
tfellman-Lord (W-L)
Operating data are for refinery and
power plant applications.
Secondary Waste Streams: Thiosulfate/
sulfate purge
Status: C, D
Data Sources: 5A, 5C, 6, 7
PCTM Reference: Sections 4.1.1, 4.1.8.1
Incinerat ion
Emissions data are available for commer-
cial scale incineration and/or combustion
of a number of different types of waste
gases and liquids.
Secondary Waste Streams: None
Status: C
Data Sources: 5A, SB, SC, 5D
PCTM Reference: Sections 4.1.1, 4.1.2,
4.1.3, 4.1.8
Uncertainties relate mainly to the oper-
ability of units in high CO, applications.
There is also some question as to the fate
of low molecular weight mercaptans and
ammonia in Stretford systems.
The reductive incineration system for blow-
down has not been demonstrated in commercial
applications.
Stretford costs as a function of both
volumetric flow and sulfur loading are not
accurately known.
Characterization data and treatment scheme
for solution purge stream are needed. Oxi-
dizer vent gas characterization data is
limited.
Since W-L feed is incinerated, and since the
absorbing solution is not affected by CO,,
data from existing units should be directly
applicable to Lnrgi service. Uncertainties
relate to costs as a function of sulfur load-
ing and volumetric flow.
Uncertainties relate primarily to the oper-
ability of and emissions from incinerators
with feed gases having high CO, levels and
low heating values.
Operability is also a question for inter-
mittent and transient waste gases.
Data could be obtained on the operating experi-
ence at Sasol, and on the modification to
processes recently made there using a new
(proprietary) solvent. Source testing at the
first U.S. facilities can establish a data base
for performance in high CO, applications, as well
as defining the amounts of non-H,S sulfur present
in Lurgl acid gases.
Work is currently being done to develop techniques
to handle the Stretford solution purge stream.
Purge stream characterization data from a commer-
cial synfuels Stretford unit is desired.
Data are needed on costs for W-L relative to
SCOT or BEAVON systems with similar design
performance s.
Data on the emissions of incinerators in simi-
lar applications would provide some basis for
assessing performance with Lurgi gases.
The VOC, POM, and IICN levels from combustion of
Lurgi byproducts as fuels are also of interest.
(Continued)
-------
TABLE 5-2. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Re search Needs
Deavon/Stretford (also see previous
Stretford discussion)
Available data have been obtained for Claus
plant tail gas feeds in refinery service
with low C0a.
Secondary Waste Streams: Sour water con-
densate from the Beavon reactor
effluent. Spent catalyst from the
Beavon reactor, Stretford secondary
streams listed in previous discussion
Status: C, D
Data Sources: 5A, 6, 7
PCTM References: Sections 4.1.1, 4.1.8.1
Uncertainties relate to performance of the
catalytic section in high C02 service. Also,
the effect of the catalyst on mercaptans is
unknown. Other data gaps and limitations
are discussed in connection with Stretford.
Characteristics and/or generation rates of
spent catalyst and condensate are not well
known.
No Beavon units are currently treating Lurgi
type gases and no proposed Lurgi facilities
feature Beavon to date. If Beavon units are
used in Lurgi facilities, source testing can
establish performance in high C01 applications.
Additional data on characteristics of spent
catalyst and condensate would be useful for
defining control needs.
SCOT
Available data have been obtained for both
conventional refinery (low C0}) applications
and oil gasification and natural gas ser-
vice (where high CO, levels are encountered).
Secondary Waste Streams: Sour water from
the quench tower. Spent catalyst
Status: C, D
Data Sources: 5A, 5D, 6, 7
PCTM Reference: Sections 4.1.1, 4.1.8.1
Flares
Data used in this manual are based on
experience in the petrochemical and
refining industries
Secondary Waste Streams: None
Status: C
Data Sources: 5A
PCTM Reference: Section 4.1.1
Catalytic section of SCOT is similar to that
of Beavon, and hence uncertainties in Lurgi
service are similar. Also, uncertainties in
amine section have been identified previously.
Costs related to both sulfur loading and
volumetric flow are not accurately known.
Character!sties and/or generat ion rates of
spent catalyst and condensate are not well
known.
Performance data for flares on synfuels
gaseous stream containing combust ible species
such as VOC, CO, HaS does not eiist in the
public domain.
Several existing SCOT facilities treat gases
similar to those expected in Lurgi service.
The performance of both the catalytic and
amine sections of these units could be tested.
Such facilities do not, however, handle mer-
captans in the feed gas.
Additional data on characteristics of spent
catalyst and condensates wonld be useful to
define control needs.
Adequate methods are not available for character-
izing flared gas composition. If methods are
developed, it would be beneficial to characterize
inlet and flared gases as a function of flow rate
and flare conditions. Until adequate methods are
developed, characterization of flare feed streams
is de sirable.
-------
TABLE 5-3 . DATA GAPS AND RESEARCH NEEDS - AQUEOUS MEDIUM
Keva for Data Sources
Technology Status Keys:
Al Commercial or demonstration-scale application in a
Lurgi or Lurgi-type gasification facility
A2 Commercial or demonstration-scale application on an
"identical" stream in a related industry
A3 Commercial or demonstration-scale application of a
similar stream in a non-Lurgl gasification facility
B Bench- or pilot-scale testing
C Technology transfer from another industry - similar
but not identical streams
D Conceptual
Data Sources/Location Keys:
1. Kosovo, Yugoslavia Lurgi-type facility
2. Sasol, S.A.
3. Trials of American coals at Westfield, Scotland
4. Chapel Bill, N.C. (UNO - synfuels wastewater
treatability test facility
5. Technology transfer from related industries
5A. Petroleum refining/petrochemical production
5D. Coke production
SC. Electric power production
50. Natural gas processing
5E. Municipal gas processing
6. Conceptual or proposed designs/engineering
studies
7. Vendor supplied information
Stream or Control Technology
Data Gaps and Limitations
Research Needs
Kastewater Streams
Gas Liquor (vastewater from tar/oil separation)
Gas liquor contains a variety of organic
and inorganic (mainly dissolved gases) con-
stituents, many of which are present in high
concentrations. Although the presence of
these components is not highly dependent on
the coal gasified or the gasifier operating
conditions, the concentrations of these com-
ponents are. Data on gas liquor are based
on analyses from Lurgi-type plants gasifying
North Dakota lignite, Yugoslavian lignite.
Rosebud subbiluminous coal, and Illinois
No. 6 and No. 5 and Pittsburgh No. 8 bitu-
minous coals.
Status: Al
Data Sources: 1, 2, 3
PCTM Reference: Section 3.3.5
A complete characterization of gas liquor
inclnding all water quality parameters, organic
speciation, and trace elements is not currently
publicly-available for any coal type or plant.
Where data gaps existed, engineering judgement
was used to develop correlations with data from
other coal types in this study.
Due to differences in system configurations, test
objectives, sample collection/handling techni-
ques, and waste stream blending and analytical
procedures, the analyses are not well defined in
the literature. Some of the analyses performed
were on "aged" samples rather than "fresh" samples.
It is, therefore, difficult to extrapolate these
data to other coal types or plants.
Data on the concentrations of specific
organic and inorganic species and their
dependence on coal type and gasifier oper-
ating conditions is desirable in order to
adequately evaluate treatment, reuse,
and/or disposal alternatives. This infor-
mation is especially important in the
evaluation, selection, and design of treat-
ment processes following bulk organics and
dissolved gases removal. This kind of data
is believed to exist, but to date has
largely been developed and held as part of
proprietary plant design data bases. The
first U.S. I.urgi plants offer the best
opportunities for source testing. Data may
also be obtained from SASOL.
(Continued)
-------
TABLE 5-3. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Research Needs
Rectisol Mctbanol/Water Still Bottoms
Wastewater from the Rectisol. unit contains
dissolved gases such as ammoni a and cyanides
as well as some dissolved organics and traces
of methanol. Data on the composition of this
stream were obtained from Lurgi-based plants
in South Africa.
Status: Al
Data Sources: 1, 2
PCTM Reference: Section 3.3.5
Synthesis Wastewaters
Wastewaters from the Fischer-Tropsch,
Methanol, and Mobil M-gasoline synthesis
processes contain dis solved organics, but
negl igible amounts of inorganics. Data on
the compositions and flow rates of these
wastewaters were obtained from engineering
studies of the subj ect technologies. SNG
synthesis condensate are expected to con-
tain neglible Icveli of pollutants.
Status: D
Da ta Source . 6
Only limited data are available on the composi t i on
of this stream and on the factors which influence
its composition and flow rate. However, the types
of pollutants expected to be present can be esti-
mated from the composition of the Rectisol feed
gas.
No ana lysis of actual streams have been publi shed
to date. These wastewaters are expected to be
similar to those produced by certain petroleum
and petrochemical industry processes.
Most poll
are also
stream wi
gas liquo
rate is v
liquor fl
are low,
semi- quan
are expec
its impac
ga s 1 iquo
utants contained in this stream
present in gas liquors and this
ll most likely be combined with
r for treatment. Since its flow
ery small (compared to the gas
ow) and its pollutant loadings
the available qualitative and
t itative character! zati on data
ted to be adequate to determine
t on the treatment system for raw
Data on the composi tion of these streams is
desired in order to adequately design con-
trol systems to properly allow for the com-
bination of these wastes (with the probable
exception of SNG synthesis condensate) with
gas liquor for treatment in common equip-
ment .
PCTM Reference: Section 3.4.3
Control Technologic*
Bulk Organics Removal
Phenosol van
The Phenosolvan process is currently used in
all operating Lurgi-based synfuels facilities
and is generally considered a part of the
proprietary Lurgi-design package. Perfor-
mance data were obtained from engineering
studi es.
Secondary waste streams: Filter Backwash,
Spent Filter Medium
Status: Al , D
Data Source: 6
PCTM References: Sections 4.2.1.2, 4.2.2.1
Only very limited species-specific performance
data are avail able. In addition, different sol-
vents can be used a nd per formanee is dependent
on the solvent used.
Data on residual quantities of sol vent renia i n-
ing with treated wastewater are limited.
Determine the presence and coneentration
of organic and inorganic pollutants in
treated wastewater that could adversely
impact downstream treatment units.
Investigate the use of alternative or mul-
tiple solvents to enhance performance or
effect removal of component s which cause
operating probi ems in downstream equifment.
(This is currently being investigated by
DOE) .
Quantify residual solvent levels in treated
wastewaters - determine if these levels
have adverse impacts on downstream treat-
ment proce sse s.
(Cont inued)
-------
TABLE 5-3. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Dissolved Gases Removal
Research Needs
P1IOSAM-W
The PHOSAH-W process has been commercially
proven on coke oven wastewaters which are
comparable to gas liquor. PUOSAH-W is pro-
posed for use in several Lurgi-based plants.
Secondary Vaste Streams: Stripper offgases
Status: C, D
Data Sources: 5A, 6
PCT?I References:
Sections 4.2.1.3 ,
4.2.2.1
Dissolved Organics Removal
Biological Oxidation
This technology has been commercially proven
on similar wastewaters in the byproduct
coking Industry. Feasibility of this tech-
nology has been demonstrated for coal gasi-
fication wastewaters on the bench-scale.
Biological oxidation has been proposed for
use in most Lurgl-based synfuels plants
and is currently used to treat dephenol-
ized and stripped gas liquor at SASOL, al-
though performance data are not publicly
available.
Secondary Vaste Streams: Biological solids,
offgase s
Status: B, C, D
Data Sources: 4, 5B, £
PCTM References: Sections 4.2.1.4, 4.2.2.1
The impacts of dissolved organics on system
operations are not veil-known.
Economically achievable performance on
wastewaters containing high carbon dioxide
and anmonia levels is not well documented, nor
is the impact that complexes have on performance.
No data are available on the levels of organic
contaminants which may be present in the re-
covered ammonia and stripped acid gas streams.
Pollutant removal efficiencies and effluent
qualities obtained from bench-scale studies are
reasonably representative of what is achievable
with full-scale plants but not necessarily what
is maintainable on a long-term continuous basis.
Relationships between the removal of inorganic
nitrogen species (e.g., ammonia, cyanide, and
thiocyanate) have not been defined (e.g., com-
pounds preferentially removed, toxic effects,
removal efficiencies). The current bench-scale
treatability studies designed to optimize per-
formance (e.g., BOD, TOC, COD removal) have
been conducted primarily using single stage
biological systems. Many synfuels applications
may require multistage biological treatment to
achieve an acceptable effluent for recycle or
disposal. The data on multiple stage biological
treatment is limited at this time.
The fate of trace elements in the wastewaters are
not well defined. Data identifying organics in
untreated and treated wastewaters (e.g., priority
pollutants, POMs, or other toxic materials) is
also limited at this time.
Obtain data on the impacts that high mole-
cular weight organics have on performance
and the types and levels of organics which
are (might be) present in the ammonia by-
product and stripped acid gas streams.
Determine levels of residual ammonia,
hydrogen sulfide, cyanides, and thio-
cyanates obtainable under economically
viable operating conditions. Identify pre-
treatment steps which could enhance system
performance.
Treatability studies on a pilot- and full-
scale are needed to develop functional
relationships between coal type, influent
wastewater characteristics, and effluent
quality. Opportunities may exist to obtain
data on the SASOL II and III biological
oxidation systems.
Dench- or pilot-scale studies to optimize
performance and effluent quality of single
and multi-stage treatment schemes are
needed. These studies can also address
the removal mechanisms of nitrogen species
and trace elements.
Residual organics in treated wastewaters
from bench-, pilot-, or fall-scale facil-
ities should be characterized.
Treatability studies are needed to deter-
mine enhanced performance achievable with
addition of powdered activated carbon to a
biological system.
Definition of gaseous emissions from aera-
tion processes on a bench-, pilot-, and
full-scale system is needed.
(Continued)
-------
TABLE 5-3. (Continued)
Scream or Control Technology
Data Gaps and Limitations
Research Needs
CO
Biological Oxidation (Continued)
Residual Organics Removal
Activated Carbon Adsorption
Pollutant removal efficiencies are based
primarily on data from the refining and
byproduct coking industries.
Expected reliability, capital, operating,
and maintenance costs are also bated on
data from applications in the refining
and byproduct coking industries.
Secondary Waste Streams: Regeneration
offgases, spent carbon flees
Status: C, D
Da ta Source s: 5A, 5B, 6
PCTtl References: Sections 4.2.1.5, 4.2.2.1
The effect of using powdered activated carbon
with activated sludge on Lurgi wastewaters is
not well known.
No data are available on the potential gaseous
emissions from aeration processes.
Data characterizing biological sol ids is limited.
Thus, evaluation of disposal options for these
solids is also quite limited and generic.
Actual removal efficiencies will be dependent on
pFI, mol ecular size, and structure of the organics
present in the wastewater.
Limited data are available on the specific 'spe-
cies present in Lurgi wastewaters which contri-
bute to BOD, COD, and TOC loadings. As a result,
performance of carbon adsorption on BOD, COD,
and TOC has not been determined for these waste-
waters .
The removal efficiency and fate of trace elements
are not well known.
Effects of the variation of flow and composition
on costs and reliability are not known.
The 1 caching character! sties of spent carbon
fines and ash from regeneration and quenching
operations are not well defined.
The presence and/or concentrations of organics
in regenerator offgases is not known.
Characterization of biological solids and
evaluation of disposal and recycle options
are needed.
The potential production of unsettleable,
fine, suspended solids should be investi-
gated.
Laboratory- and pilot-scale performance
tests on synfuels wastewaters are needed
to verify design data, e.g.. required
contact times to obtain desired pollutant
removals. These tests should encompass
the range of influent strengths expected.
Carbon adsorption performance evaluations
or other tests are needed to determine
pretreatment requirements and/or perform-
ance tradeoffs. Tests obj ectives shooId
Include determining the need for pH ad-
justment to enhance performance, optimizing
the wastewater treatment temperature, and
determining whether biocide addition is
required to inhibit fouling from biological
growth.
Evaluate the leaching characteristics of
spent carbon fines and ash from regenera-
tion/quenching operations in pilot facil-
ities or byproduct coking plants. Define
final disposal and recycle alternatives.
Determine the fate of removed organics and
inorganics in the regeneration proces s.
{Cont inued)
-------
TABLE 5-3. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Research Needs
Thermal Oxidation (Incineration)
Thermal oxidation is widely used to destroy
organics in a variety of industrial wastes.
The application of this technology to Lurgi
waste streams has been proposed in a number
of synfuels plant s.
Secondary Waste Streams: Incinerator offgas
Status: C, D
Da ta Source: 6
PCTM References: Sections 4.2.1.5, 4.2.2.1
Cool ing Tower Oxidation/Concentration
The use of treated vastewaters as cooling
tower makeup is commercially proven in the
petroleum refining industry as a Beans of
reducing organic contaminants.
Secondary Waste Streams: Cool ing tower
evaporation and drift, cool ing system
sludges
Status: C
Data Source: 5A
PCBI References: Sections 4.2.1.5, 4.2.2.1
The operating temperature and combust ion zone
residence time required to obtain a desired
level of organics destruction is dependent on
specific organics present.
The materials of construction required to handle
concentrated brines are not well defined.
Control needs for incinerator off-gases are not
well-defined, nor are materials of construc-
tion requirements.
Degree of organics removal is not well known nor
is the fate of removed organics.
Potential operating problems may be caused by
biological foul ing and inorganic scale on heat
exchange surfaces.
Organics in wastewater may limit effectiveness
of conventional cool ing system biocides or
scale/corrosion Inhibitors.
Gaseous emissions due to air stripping of vol a-
tile component s are not well defined. Organics
present in drift could cause increased particu-
late emissions. Trace element concentrations
in the drift have not been characterized.
Commercial scale facility monitoring should
be implemented to confirm design basis and
emission characteristics. Pi lot studies
could be implemented to provide additional
data on wastewaters with varying composi-
ti ons.
Pilot- or full-acale tests should be
conducted to determine the fate of
organics and inorganics entering with
the treated wastewater. Tests should
determine the extent of biological
oxidation, chemical oxidation, and air
stripping. The first U.S. Lurgi plants
offer the best opportunity to obtain the
needed da ta.
Tests should be conducted to determine the
impact increased biological activity has on
cool ing system equipment performance and on
treatment chemical requirements.
Tests should be conducted to determine if
corrosion probi ems will be increased and,
if so, what corrective measures can be
taken.
(Continued)
-------
TABLE 5-3. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Research Needs
Dissolved Inorganics Removal
Chemical Precipitation
Chemical precipitation is a proven process
for reducing alkalinity and hardness in raw
waters and wastewaters. Process will also
remove trace elements, depending on initial
concentrations* inlet water composition,
and system design. The technique has not
been commercially demonstrated on coal
gasification wastewaters.
Secondary Waste Streams; Precipitated
solids
Status: C, D
Data Sources: 5A, 5C. 6
The performance of chemical precipitation in
reducing alkalinity and hardness can be de ter-
mine d if the influent water chemistry is known.
The performance in reducing trace metals is not
vrel 1 known and in any case is highly wastewater
specific.
The impact of organic constituents on system
performance is not well defined.
The composition of the precipitated solids is
not well defined due to the unknown quantities
of trace elements removed and possible organic
contamina tion.
Conduct laboratory- or bench-scale tests to
determine impact of residual organics on
system performance and to determine
achievable residual levels of trace
elements.
Conduct leachability/waste management
studies to identify appropriate disposal
methods for precipitated solids.
PCTM References: Sections 4.2.1.6,
4.2.2.1
Wastewater Concentration
o
o
Cooling Tower Oxidation/Concentration
Forced Evaporation
Forced evaporation is commerci ally proven
in wastewater applications in the steam
electric utility industry and in various
chemical manufacturing operat ions. Water
recoveries of greater than 90 percent are
reported. Several proposed synfuel facil-
ities have incorporated forced evapora-
tion in their wastewater treatment system
design.
Secondary Waste Streams: Noncondensible
offgases. Recovered water
Discussed previously under Residual Organics Removal
The Impact of res idual organics and non-condensible
gases on system operability and degree of water
recovery obtainable is not well defined.
Recovered water could be contaminated with
vaporized organics and volatile gases as well as
with entrained water. Costs for treating recovered
water to make it suitable for reuse are highly
site-specific and not well defined.
I
Conduct pilot- and commercial-seale tests
on actual wastewaters to determine impact
of noncondensible gases and organics on
system operation and identify degree of
contamination of recovered water. The
first U.S. Lurgi plants offer an opportun-
i ty to obt ai n da ta.
Conduct leachability/waste management
studies to determine appropriate disposal
methods for concentrated brine.
Status: C
Data Sources: 5A, 5C, 6
PCTM References:
Sections 4.2.1 .7,
4.2.2.1
(Continued)
-------
TABLE 5-3. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Research Needs
Residual Disposal
Deep Well Injection
Deep well injection is commercially proven
on similar waste streams in oil production
and industrial chemical applications and is
proposed for use in synfuels plants.
Acceptable practices are defined by condi-
tions which are very site-specific (i.e.,
subsurface geological and hydrological
considerations).
Status: C, D
Data Sources: SA, 6
PCTM References: Sect ions 4 .2 .1 .8 ,
4.2.2.1
Surface Impoundment
Surface impoundment is commercially proven
on similar waste streams in minerals extrac-
tion, petroleum refining, and steam electric
utility operations in the western U.S. It
is proposed for use in some synfuels plants.
Use of this technique is dependent upon the
location having a high net annual evporation
rate and land availability.
Secondary Waste Streams: Offgases fron
pond surface, Vater leakage from
containment
Status: C
Data Sources: SA, SC
PCTM References: Sections 4.2.1.8, 4.2.2.1
Design of deep well injection system is very site
dependent. Major concerns are pretreatment re-
quirements for wastes being injected. Acceptable
levels of organics and inorganics are not well
documented. Inorganics scaling and biological
activity under down-hole conditions must be avoided.
Pretreatment requirement could include organics
destruction or removal, reduction in selected
inorganics to avoid scaling, and/or pQ adjustment.
No data are available on the composition or
quantity of off-gases from the impoundment.
Biological activity in the pond could generate
hydrogen sulfide, ammonia, and organics.
No data are available on the long-term
integrity of the containment pond.
Because of the site- and waste-specific
nature of deep well injection, generalized
research will be of limited value. On-site
test wells (at a commercial facility) using
actual wastewaters or wastewaters with
simulated characteristics of the actual
wastes to be disposed can provide the best
insight to reliable disposal well opera-
tion.
Economic methods to detect and control
pond leakage need to be identified.
Test programs should be conducted to
quantify air emissions from ponds in order
to determine if environmental concerns
exist. Correlations between air emissions
and influent wastewater composition would
be useful.
-------
TABLE 5-4. DATA GAPS AND RESEARCH NEEDS - SOLID WASTES
Keys for Data Sources
Technology Status Keys
Al Commerci al or demonstration-scale application in a
Lurgi or Lurgi-type gasification facility
A2 Commercial or demonstration-sctle application on an
"identical" stream in a related industry
A3 Commercial or demonstration-seale application of a
similar stream in a non-Lurgi gasification facility
B Bench- or pilot-scale testing
C Technology transfer from another industry - similar
but not identical streams
D Conceptual
Da ta Source s/Locat i on
1. Kosovo, Yugoslavia Lurgi-type facility
2. Sasol, S.A.
3. Trials of American coals at Westfield, Scotland
4. Chapel Hill, N.C. (UNC) - synfuels wastewater
treatability test facility
5. Technology transfer from related industries
5 A. Petroleum refining/petrochemical product ion
5B. Coke product ion
5C. Electric power product!on
5D. Natural gas processing
5E. Municipal gas processing
6. Conceptual or proposed designs/engineering
studies
7. Vendor supplled information
Stream or Control Technology
Data Gaps and Limitations
Research Needs
o
ho
Waste Streams
Lurgi Gasifier Ash
The ash leachability data are based
upon tests conducted on unquenched
ashes obtained from commercial scale
gasification of Illinois No. 6, Montana
Rosebud, and Dunn County, ND, coals.
Status: Al
Data Sources: 1,2,3
PCTM References: Sections 4.3.1, 4.3.2.1
Control Technologies
Resource Recovery
Potential alternatives for recycling the
gasifier ash are based upon current
practices for coal-fired power plant
boi1er ashes.
Status: A2
Data Sources: 5C
PCTM Reference: Sections 4.3.1.1, 4.3.2.1
Long term leachah illty data are not
available for quenched ashes. There
is some uncertainty regarding sulfur
oxidation and consequent acid genera-
tion in ash. Trace metals may become
1 eachable under acidic conditions.
Avail able market for recycling the ash
i s uncertain.
Long term column or landfill cell leaching
studies should be performed to determine the
long tern ash leachate characteristics.
Appropriate materials for these studies may
not be available until the first Lurgi plant
is built in the U.S.
The effect of quench water quality on quenched
ash leachate should be evaluated.
The availability of market is highly dependent
upon local conditions which can only be
assessed on a si te-by-si te basis.
(Continued)
-------
TABLE 5-4. (Continued)
Stream or Control Technology Data Gaps and Limitations Research Needs
Landfill
Disposal of the ash in landfills is The long term leachate generation rates Long term column or landfill cell studies are
based upon current practices in the and characteristics are not known; the needed to characterize the leachate, to deter-
utility and other industries. compatibility and long term performance mine the performance of the liners, and to
of landfill liners have not been assess the attenuation value of various sub-
Secondary Waste Streams: Atmospheric established. strate materials (soils) for metals in leachates.
emissions, Leachate
Status: A2
Data Sources: 5B, 5C
PCTH Reference: Sections 4.3.1.4, 4.3.2.1
Surface Impoundments
Disposal of the ash in surface impound- The long term leachate generation rates Long term column or cell studies are needed
ments are based upon current practices and characateristies are not known; to characterize the leachate, to determine
in the utility and other industries. the compatibility and long term per- the performance of the liners, and to assess
formance of liners have not been .the attenuation value of various substrate
Secondary Waste Stream: Leachate established. materials (soils) for netals in leachates.
Status: A2
Data Sources: 56, 5C
PCTM Reference: Sect ions 4.3.1.5, 4.3.2.1
t_n
O
U)
-------
TABLE 5-5. DATA GAPS AND RESEARCH NEEDS - PRODUCTS AND BYPRODUCTS
Keys for Data Sources
Technology Status Keys
Al Commercial or demonstration-scale application in a
Lurgi or Lurgi-type gasification facility
A2 Commercial or demonstrate on-scale application on an
"identical" stream in a related industry
A3 Commercial or demonstration-scale application of a
similar stream in a non-Lurgi gasification facility
D Bench- or pilot-scale testing
C Technology transfer from another industry - sinilar
but not identical streams
D Conceptual
Data Sources/Location
1, Kosovo, Yugoslav ia Lurgi-type fac ility
2. Sasol, S.A.
3. Trials of American coals at Westfield, Scotland
4. Chapel Hill. N.C. (UNC) - synfuels wastewater
treatability test facility
5. Technology transfer from related industri es
5A. Petroleum refining/petrochemical production
5B. Coke production
5C. Electric power product ion
5D. Natural gas process ing
5E, Municipal gas processing
6. Conceptual or propo sed designs/engineering
studies
7. Vendor supplied information
Stream or Control Technology
Data Gaps and Limitations
Research Needs
SNG (both product and coproduct) and
LPG (from Fischer-Tropsch and Hobil M
synthesi s)
Product ion rates and compost tion estimates
are based on conceptual/proposed design
information.
Status: D
Da ta Source s: 6
PCTM Reference: Sections 3.5.4, 3.5.5
Gasoline, heavy fuel oil, diesel oil,
mixed alcohols (F-T synthesis), and
gasoline (Mobil M synthesis)
Production rates and composition estimates
are based on conceptual design information.
Status: D
Da ta Source: 6
PCTM Reference: Sections 3.5.2, 3.5.3
Data from a commercial facility are not
available, especially concerning
possible minor and trace components.
Characterization and storage stability
data are not available to determine the
compatibility of these products with
their petrol euro-derived counterparts.
The composition of SNG should be determined after
startup of the first commercial Lurgi SNG plant.
Characterization data on LPG from Fischer-Tropsch
may be obtainable from SASOL.
Detailed characterization data are desired.
Env ironmental effects associated with
fugitive and evaporative emissions should
be determined. Potential effects need to
be compared with those for analog petroleum
products. Data on Fischer-Tropsch product s
may be obt a i nable from SASOL.
(Cont inued)
-------
TABLE 5-5. (Continued)
Stream or Control Technology
Data Gaps and Limitations
Research Needs
Ul
O
Fuel grade methanol (methanol synthesis)
Production rates and composition estimates
are based on conceptual design information.
Status: 6
Data Source: D
PCTM Reference: Section 3.5.1
Byproducts
Lurgi tars, oils, phenols, and naphtha
Production rates and composition estimates
based on test data fron commercial Lurgi
and Lurgi-type gasification facilities.
Status: Al
Data Source: 1, 2, 3
PCTM Reference: Section 3.5.6
Ammonia and elemental sulfur
Production rate estimates based on
material flow calculations, engineering
evaluations, and vendor data
Status: A2, C. D
Data Sources: 5A, 5B, 5D, 6. 7
PCIM Reference: Section 3.5.7
Characterization data for methanol from
indirect coal liquefaction facilities
are limited. The influence of synthesis
process variables on product methanol
characteristics is unknown.
Characterization data, production rates,
and storage stability data are limited.
Presence of toxic components is expected,
but detailed analyses are limited. Ability
to upgrade for blending with other facility
liquid fuel products is not well known.
Flue gas emissions resulting from combustion
of byproducts are limited (e.g., NO and
organics).
Data are lacking on the possible con-
taminants (and level of contamination)
for both of these products.
Data on the minor and trace components in coal-
derived methanol is desired. Comparisons to
non-coal-derived methanol should be made to
determine if any special precautions in handling
and use are appropriate.
Chemical and biological characterization data
are desired if these byproducts are to be intro-
duced into commercial trade. If byproducts are
to be upgraded for blending with other products,
chemical and physical property data are necesary
to adequately design upgrading facilities.
Byproducts from commercial facilities should be
evaluated as boiler fuel. Emissions should be
characterized.
Characterization data are desired in order to
modify byproduct recovery process(es) or to
design add-on purification process(es) in order
to obtain a saleable byproduct. The first U.S.
Lurgi plants constructed offer the best oppor-
tunity to acquire the data. Data nay also be
obtainable from SASOL and other foreign Lnrgi-
based facilities.
-------
SECTION 6
REFERENCES
1. Trials of American Coals in a Lurgi Gasifier at Westfield, Scotland.
Woodall-Duckham, Ltd., Sussex, England. ERDA R&D Report No. 105, 1974.
2. Information Supplied by Lurgi to EPA IERL/RTP, Research Triangle Park,
North Carolina, September 1982.
3. Lee, Kenneth, V., et al. Environmental Assessment: Source Test and
Evaluation Report — Lurgi-Type (Kosovo, Yugoslavia) Medium-Btu
Gasification. Final Report. EPA-600/7-81-142, PB82-114-075, Radian
Corporation, Austin, Texas, August 1981.
4. Information provided by SASOL to EPA IERL/RTP, Research Triangle Park,
North Carolina, November 1974.
5. Schreiner, Max. Research Guidance Studies to Assess Gasoline from Coal
by Methanol-to-Gasoline and SASOL-type Fischer-Tropsch Technologies.
FE-2447-13, Mobil Research and Development Corporation, August 1978.
6. Final Environmental Impact Statement, ANG Coal Gasification Company North
Dakota Project. U.S. Department of Interior, January 20, 1978.
7. Data provided by the American Natural Resources Corp. to the North Dakota
Department of Health as Part of Air Pollution Control Permit Applications
for the Great Plains Coal Gasification Project.
8. Final Environmental Statement, Western Gasification Company (WESCO) Coal
Gasification Project. U.S. Department of Interior, Bureau of Reclamation,
Washington, D.C., January 1976.
9. Somerville, M.H., J.L. Elder, et al. An Environmental Assessment of a
250 MM SCFD Dry Ash Lurgi Coal Gasification Facility in Dunn County,
North Dakota. University of North Dakota, Engineering Experiment
Station, Bulletin No. 76-12-EES-01 Volumes I - IV, December 1976.
10. Sinor, J.E. Evaluation of Background Data Relating to New Source
Performance Standards for Lurgi Gasification. EPA 600/7-77-057,
PB-269-557. Cameron Engineers Inc., Denver, Colorado, June 1977.
11. Detman, Roger. Factored Estimates for Western Coal Commercial Concepts.
Interim Report. C.F. Braun & Co., Alhambra, California, October 1976.
12. Blackwood, T.R., and R.A. Wachter. Source Assessment: Coal Storage
Piles. Monsanto Research Corporation, Dayton, Ohio, May, 1978.
13. Jutze, G.A., et al. Technical Guidance for Control of Industrial Process
Fugitive Emissions. PB 272-288, PEDCo Environmental, Cincinnati, Ohio,
March, 1977.
506
-------
Section 6
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14. PEDCo-Environmental, Inc. Survey of Fugitive Dust from Coal Nines.
EPA-908/1-78-003, PB-283-162, U.S. Environmental Protection Agency,
Cincinnati, Ohio, February, 1978.
IS. Buroff, J., J. Strauss, A. Jung, and L. McGilvray. Environmental
Assessment: Source Test and Evaluation Report. Coal Preparation Plant
No. 1, EPA-600/7-81-071a, PB81-239030. Versar Inc., Springfield.
Virginia, August 1981.
16. Buroff, J., J. Strauss, A. Jung, and L. McGilvray. Environmental
Assessment: Source Test and Evaluation Report, Coal Preparation Plant
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Agency, Research Triangle Park, North Carolina, March 1981.
17. Cox, Doye P., T.Y.J. Chu, and R.J. Rnane. Characterization of Coal Pile
Drainage, EPA-600/7-79-051, PB 294-271, TVA, February, 1979.
18. Ferraro, F.A. Treatment of Precipitation Runoff from Coal Storage Piles,
Presented at Third Symposium on Coal Preparation. NCA/BCR, Louisville,
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19. Wewerka, E.M., J.M. Williams, P.L. Wanek, and J.D. Olsen. Environmental
Contamination from Trace Elements in Coal Preparation Wastes. EPA-600/7-
76-007, PB-267-339, Los Alamos Scientific Laboratories, 1976.
20. PEDCo-Environmental, Inc. Assessment of Fugitive Particulate Emission
Factors for Industrial Processes. EPA-450/3-78-107, PB-288-859,
Cincinnati, Ohio, September, 1978.
21. Rittenhouse, R.C. Fuel: Handling and Storage at Power Plants. Power
Engineering, December, 1979. pp. 42-50.
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Environmentally Based Evaluation of the Multimedia Discharges from the
Lurgi Coal Gasification System at Kosovo. Presented at the Symposium on
Environmental Aspects of Fuel Conversion Technology V, St. Louis,
Missouri, September 16-19, 1980. EPA-600/9-81-006, PB 81-245-045.
23. Yu, Kar Y. and G.M. Crawford. Characterization of Coal Gasification Ash
Leachates Using the RCRA Extraction Procedure. Paper presented at the
Symposium on Environmental Aspects of Fuel Conversion Technology V, St.
Louis, Missouri, September 16-19, 1980. EPA-600/9-81-006, PB 81-245-045.
24. Conceptual Design of a Coal-to-Methanol-to-Gasoline Commercial Plant.
Volume I, FE-2416-43, Badger Plants Incorporated, Cambridge,
Massachusetts, March 1979.
507
-------
Section 6
References
25. Bromel, M.C. and J.R. Fluker. Biotreating and Chemistry of Wastewaters
from the South African Coal, Oil and Gas Corporation (SASOL) Coal
Gasification Plant. North Dakota State University, Fargo, North Dakota,
December 1976.
26. Information provided by Westfield Development Center to EPA's Industrial
Environmental Research Laboratory, Research Triangle Park, North
Carolina, November 1974.
27. Luthy, Richard G. Treatment and Reuse of Coal Conversion Wastewaters.
Paper presented at the Symposium on Environmental Aspects of Fuel
Conversion Technology V, St. Louis, Missouri, September 16-19, 1980.
EPA-600/9-81-006, PB 81-245-045.
28. Ghassemi, M., K. Crawford, and S. Quinlivan. Environmental Assessment
Data Base for High—Btu Gasification Technology: Volumes I, II, and III.
EPA 600/7-78-186a, b, and c. September, 1978.
29. Ranke, G. Acid Gas Separation by Rectisol in SNG Processes. Linde AG,
Munich, Germany, Copy of presentation obtained through Lotepro
Corporation, New York, New York.
30. Lotepro Corporation. Capabilities brochure by Lotepro Corporation.
31. R.M. Parsons Co. Screening Evaluation for Synthetic Liquid Fuels
Manufacture. EPRI AF-523, August 1977.
32. Ulrich, W.C., M.S. Edwards, and R. Salmon. Evaluation of an In Situ
Coal Gasification Facility for Producing M-Gasoline via Methanol, Oak
Ridge National Laboratory, ORNL-S439, December 1979.
33. Mehta, D.D. and W.W. Pan. Purity Methanol This Way. Hydrocarbon
Processing, February 1971. pp. 115-120.
34. C.F. Braun and Company. Carbonyl Formation in Coal Gasification Plants.
FE-2240-16, Prepared for Energy Research and Development Administration
and American Gas Association, December, 1974.
35. Storch, H.H., et al. Synthetic Liquid Fuels from Hydrogenation of Carbon
Monoxide. U.S. Bureau of Mines, 1948.
36. Hneper, W.C. Experimental Carcinogenic Studies of Hydrogenated Coal
Oils, II, Fischer-Tropsch Oils. Industrial Medicine and Surgery, October,
1956, p. 459-462.
37. Hoogendorn, J.C. Experience with Fischer-Tropsch Synthesis at SASOL, In:
Clean Fuels from Coal. Symposium Papers. Illinois Institute of
Technology, September 10-14, 1973, pp. 353-365.
508
-------
Section 6
References
38. Bowden, J.M. and D.W. Brinkman. Stability of Alternate Fuels.
Hydrocarbon Processing, July 1980, pp. 77-82.
39. Runion, H.E. Benzene in Gasoline. American Industrial Hygiene
Association Journal, Hay 1975, pp. 383-50.
40. Enviro Control Inc. Relative Health Effects of Gasoline and Heating Fuel
Derived from Petroleum or Synthetic Crudes. Prepared for U.S. Department
of Energy under Contract No. DE-AC01-79PE-70021, Washington, D.C., 1980.
41. Schreiner, E. Motor Gasolines, Summer 1979. U.S. Department of Energy,
Bartlesville Energy Technology Center, Bartlesville, Oklahoma, February,
1980.
42. Mullowney, J.F. and P.P. Mako. Coal to Transport Fuels and Chemicals:
SASOL Two/SASOL Three. Paper presented at American Chemical Society
National Meeting, Division of Petroleum Chemistry, Las Vegas, Nevada,
1980.
43. Enviro Control Inc. Trip Report, SASOL I, Sasolburg, South Africa,
December 5-7, 1977. Prepared for National Institute for Occupational
Safety and Health, Rockville, Maryland.
44. Forney, A.J., W.P. Haynes, et al. Analyses of Tars, Chars, and Water
Found in Effluents from the Synthane Process. Pittsburgh Energy Research
Center, Pittsburgh, Pennsylvania, Technical Progress Report 76, January
1974.
45. U.S. EPA. Compilation of Air Pollution Emission Factors. Office of Air
Quality Planning and Standards, Research Triangle Park, North Carolina,
AP-42.
46. Hart, F.C., et al. The Impact of RCRA (PL 94-580) on Utility Solid
Wastes. EPRI Report FP-878, TPS 78-799, August 1978.
47. Goldstein, D.J., and D. Yng. Water Conservation and Pollution Control in
Coal Conversion Processes, EPA-600/7-77-065, June, 1977.
48. Dickey, J.B. and D.W. Dwyer. Managing Waste Heat with the Water Cooling
Tower. Missouri Valley Electric Association, 1979 Engineering
Conference, 3rd Addition.
49. American Petroleum Institute, Bulletin 2517. Evaporative Loss from
Floating Roof Tanks. February 1980.
50. Climatic Atlas of the United States, DOC-NOAA, 1974.
51. Pacific Environmental Services. Study of Gasoline Vapor Emission Controls
at Santa Monica, California. PB-267096, October 1976.
509
-------
Section 6
References
52. Wetherold, R. and L. Provost. Emission Factors and Frequency of Leak
Occurrence for Fittings in Refinery Process Units. EPA-600/2-79-044.
Radian Corp., Austin, Texas, February 1979.
S3. Assessment of Atmospheric Emissions from Petroleum Refining: Volume 5,
Appendix F: Refinery Technology Characterization. EPA-600/2-80-075e,
PB 294-741, Radian Corp., Austin, Texas, July 1980.
54. Badger Plants, Inc. Conceptual Design of a Coal-to-Methanol Commercial
Plant. DOE FE 2416-24. Cambridge, Massachusetts, February 1978.
55. Water Reuse Studies. API Publication 949, August 1977.
56. Lim, E.J., H. Lips and R.J. Milligan. Technology Assessment Report for
Industrial Boiler Applications: NO Combustion Modification.
EPA-600/7-79-178f, December 1979. x
57. Acurex Corp. Control Techniques for Nitrogen Oxides Emissions from
Stationary Sources - Second Edition. EPA-450/1-78-001, January 1978.
58. Dickerman, J.C. Technology Assessment Report for Industrial Boiler
Applications: Flue Gas Desulfurization. EPA-600/7-79-178i, Radian
Corporation, Austin, Texas, November 1979.
59. TRW In-house information obtained from Mike Boughton, Redondo Beach,
California, September 1981.
60. Industrial Ventilation. A manual of recommended practice by the
Committee on Industrial Ventilation, Michigan, U.S.A. Twelfth Edition,
1972.
61. Bulk Gasoline Terminals - Background Information for Proposed Standard.
Draft Report, Emission Standards and Engineering Division, U.S. EPA, May
1980.
62. Control of Volatile Organic Compound Leaks from Petroleum Refinery
Equipment, Guideline Series. EPA-450/78-036. Emission Standards and
Engineering Division, U.S. Environmental Protection Agency, June 1978.
63. Beychok, M.R. and W.J. Rhodes. Comparison of Environmental Design
Aspects of Some Lurgi-Based Synfuels Plants. Paper presented at
Symposium on Environmental Aspects of Fuel Conversion Technology, Denver,
Colorado, October 26-30, 1981.
64. Luthy, R.G. and L.D. Jones. Biological Oxidation of Coke Plant
Effluents. J. Environmental Engineering Division, ASCE, Vol. 106, No.
EE4, August 1980.
510
-------
Section 6
References
65. Luthy, R.G., et al. Biological Treatment of a Synthetic Fuel Wastewater,
J. Environmental Engineering Division, ASCE, Vol. 106, No. EE3, June
1980.
66. Luthy, R.G. and J.T. Tallon. Biological Treatment of a Coal Gasification
Process Wastewater, Water Research, 1980.
67. Johnson, G.E., et al. Treatability Studies of Condensate Water from
Synthane Coal Gasification. Pittsburgh Energy Technology Center Report
No. PERC/RI-77/13, Pittsburgh, Pennsylvania, November 1977.
68. Sack, W.A. Biological Treatability of Gasifier Wastewater. Morgantown
Energy Technology Center Report No. METC/CR-79/24, Morgantown, West
Virginia, June 1979.
69. Reap, E.J., et al. Wastewater Characteristics and Treatment Technology
for Liquefaction of Coal Using the H-Coal Process. Proceedings of the
32nd Purdue Industrial Waste Conference, Ann Arbor Science, Ann Arbor,
Michigan, 1977.
70. Singer, P.C., et al. Assessment of Coal Conversion Wastewaters:
Characterization and Preliminary Biotreatability. EPA-600/7-78-181,
U.S. Environmental Protection Agency, Washington, D.C., 1978.
71. Drummond, C.J., et al. Treatment of Solvent Refined Coal (SRC-I)
Wastewater: A Laboratory Evaluation. Pittsburgh Energy Technology
Center, Pittsburgh, Pennsylvania, 1981.
72. Juentgen, H. and E. Juergen. Purification of Wastewater from Coking and
Coal Gasification Plants using Activated Carbon. Amer. Chem. Soc., Div.
of Fuel Chem. Prepr., 19(5): 67-84, 1974.
73. Ginsti, D.M., Conway, R.A. and Lawson, C.T. Activated Carbon Adsorption
of Petrochemicals. J. WPCF, 46(5): 947-965, 1974.
74. Hossain, S.M., et al. Applicability of Coke Plant Control Technologies
to Coal Conversion. EPA-600/7-79-184, PB80-108954, Catalytic, Inc.,
Philadelphia, Pennsylvania, August 1979.
75. Bernardin, F.E. Selecting and Specifying Activated Carbon Adsorption
Systems. Chemical Engineering, October 18, 1976, pp. 77-82.
76. Kunz, R., J. Casey, and J. Huff. A Review of Cyanide in Refinery
Wastewaters. In proceedings of Third Annual Conference on Treatment and
Disposal of Industrial Wastewaters and Residues, Houston, Texas, April
18-20, 1978, pp. 65-77.
77. Monroe, E.S., Jr. Burning Waste Waters. Chemical Engineering, September
23, 1968, pp. 215-220.
511
-------
Section 6
References
78. Personal communication, Fred Kuhn, American Natural Resources, with D.A.
Dalrymple, Radian Corporation, July 27, 1982.
79. Stickney, W.W. and T.M. Fosberg. Putting Evaporators to Work: Treating
Chemical Wastes by Evaporation. Chemical Engineering Progress, April
1976. pp. 41-46.
80. Pojasek, R.B., ed. Toxic and Hazardous Waste Disposal, Vol. I. Ann
Arbor Science Publication, Inc., Ann Arbor, Michigan, 1979.
81. Conner, J.R. Disposal of Liquid Wastes by Chemical Fixation. Waste Age,
September 1974, pp. 26-45.
82. Michael Baker Jr., Inc. State-of-the-Art of FGD Sludge Fixation.
Electric Power Research Institute Report No. EPRI FP-671, January 1978.
83. Survey of Solidification/Stabilization Technology for Hazardous
Industrial Wastes. EPA-600/2-79-056, July 1979.
84. Hitchcock, D.A. Solid Waste Disposal: Incineration. Chemical
Engineering, May 21, 1979, pp. 185-194.
85. Brminer, D.R. and D.J. Keller. Sanitary Landfill Design and Operation.
U.S. EPA, SW-65ts, 1972.
86. Moore, C.A. Landfill and Surface Impoundment Performance Evaluation
Manual. Report submitted to U.S. EPA-MERL for publication, June 1, 1980.
87. EPA Report. Preliminary Final Economic Impact Analysis for Subtitle C
Resource Conservation Recovery Act of 1976.
88. Guidance Manual for Closure of Hazardous Waste Surface Impoundments.
Report submitted by Acurex Corporation to U.S. EPA for publication, May
1980.
89. Huddleston, R.L. Solid Waste Disposal: Landfarming. Chemical
Engineering, February 26, 1979.
90. Faber, J.H. A U.S. Overview of Ash Production and Utilization. National
Ash Association, 1979.
512
-------
APPENDIX A
LD8GI DRY ASH COAL GASIFICATION
A-l
-------
APPENDIX A
LURGI DRY ASH COAL GASIFICATION
Coal has been gasified commercially using the Lurgi dry ash process since
before 1940. Continued development of the process, based on operational ex-
perience with a variety of coals, has resulted in the current system which can
successfully process most varieties of coal including caking coals, lignite,
and peat. Significant improvement has also been made in the quantity of coal
which can be processed by a single gasifier (1).
Currently there are about 20 commercial installations of the Lurgi dry
ash process, none of which are in the United States. At least a dozen pro-
jects, however, have been proposed or studied in the United States (Table A-l)
(2). Of these, only the Great Plains Gasification Project in North Dakota
appears to have potential for near term operations.
This Appendix is a supplement to the descriptive material and waste
stream characterization data presented in Section 3 of this manual. As such,
reference is frequently made to tables presented in Section 3, rather than
present duplicative tables in this appendix.
A.I PROCESS DESCRIPTION
\
A.1.1 Gasifier Equipment
The Lurgi gasifier is a veritical, cylindrical, water-jacketed, steel,
pressure vessel (Figure A-l). Typically the Lurgi gasifier can vary in dia-
meter from 2.5 to 4 m. It has an overall height of 5.8 m and a coal bed
height that varies from 2.0 to 3.0 m. Atop the gasifier is a lockhopper
through which coal is introduced into the reactor. Near the top of the
A-2
-------
TABLE A-l. MAJOR PROPOSED COAL GASIFICATION PROJECTS USING
LDRGI GASIFIERS AS OF JANUARY 1982 (2)
Sponsor Location
Hampshire Energy Company Wyoming
WyCoal Gas Inc. Wyoming
Lake Desmet Synfuels Wyoming
Great Plains Gasification Associates North Dakota
Nokota Company North Dakota
North Dakota Synfuels Group North Dakota
Tri-State Synfuels Kentucky
Tenneco Coal Gasification Montana
Crow Indians Montana
Texas Eastern Synfuels New Mezico
Exxon USA Texas
Transco Energy Company Texas
Louisiana Gasification Associates Louisiana
A-3
-------
FEED COAL
DRIVE
RECYCLE TAR
RECYCLE
GAS LIQUOR
STEAM
GRATE DRIVE
STEAM AND OXYGEN
WATER JACKET
ASH SLURRY
Figure A-l. LuYgi Dry Ash Gasifier
GAS
A-4
-------
Appendix A
Lurgi Gasification
reactor is a watercooled, rotating coal distributor which helps to provide a
uniform coal bed and to break up coal agglomerates. A recycle tar injection
nozzle may also be located near the top of the gasifier. Tar injection helps
reduce carryover of coal fines. An attachment to the Lurgi system is a gas
quench and scrubber which removes condensibles from the raw gas.
Below the coal bed is a rotating grate which assists in the removal of
ash through an ash lockhopper. Steam and oxygen are introduced into the
gasifier below the ash extraction grate.
A.1.2 Operational Parameters
Devolatilization begins as the coal moves down through the gasifier and
is combined with gasification at temperatures of 890 to 1030 K. The major
chemical reactions which occur as the coal descends through the gasifier are
as follows:
Coal + Heat -> CH + HO (drying and devolatilization)
C + HO + Heat ->• CO + H
C + CO + Heat -»• 2CO (Gasification)
C + 2H -> CH + Heat
2C + 0. -> 2CO + Heat ,_ . _ ,
2 (Combustion)
C + 0 -* CO + Heat
2 2
Completion of the gasification process requires a minimum residence time of
one hour at temperatures of 1030 to 1150 K (1). Gasifier pressure is main-
tained at 2.1 to 3.2 MPa. These operating conditions result in the high
methane content in the raw Lurgi gas as well as the production of significant
amounts of byproduct tars, oils, and phenols.
A-5
-------
Appendix A
Lurgi Gasification
A. 1.3 Feed Requirements
Many varieties of coal, lignite, and peat have been processed success-
fully in Lurgi gasifiers. Coal size can range from 3 to 60 mm with a typical
range of 6 to 40 mm. Crushing and sizing are thus required in coal handling.
Gasification of coals containing up to 40 percent moisture appears feasible.
Steam and either oxygen or air are the additional feeds to the gasifier.
Use of oxygen results in the production of medium-Btu or synthesis gas while
air gives rise to low-Btu gas. Oxygen requirements are indicated to range
from 0.2 to 0.6 kg per kg of MAP (moisture and ash free) coal. From 1.5 to
3.1 kg of steam per kg of MAP coal have been used or proposed for the Lurgi
gasifier. Data from Environmental Impact Statements for Lurgi-based facili-
ties and typical data presented by Lurgi, however, indicate that a value less
than 2 kg steam per kg MAP coal may be satisfactory. Of the steam required
for gasification some 20% can be supplied from the gasifier jacket while the
remainder must be supplied from external steam generators (1,3).
A. 1.4. Raw Lurgi Gas
On a weight percent basis, raw Lurgi gas production will range from 42 to
50% of the total gasifier input. Table A-2 presents data on the components of
interest in quenched Lurgi gas, excluding water. Four compounds: CO,, H2, CO,
and CH4, typically account for at least 97% of the dry gas. Other components
of interest for which data were available are also presented. Sulfur com-
pounds and hydrocarbons make up the bulk of the minor constituents. Host of
the sulfur is recovered in downstream sulfur recovery systems after acid gas
removal. About 15% of the non-methane organics will be recovered as naphtha
in the acid gas removal (Rectisol) system.
A-6
-------
TABLE A-2. QUENCHED LURGI GAS COMPOSITIONS
Data Source
Component
C0»
CO
CU<
Hi
CiH«
CiB4
Ci Aliphatics
C< Aliphatics
Ct + Aliphatics
Benzene
Toluene
Other Aroma tics
H>S
COS
CHtSH
CiHjSH
HCN
NH>
0>
Ar
Nj
Temperature (K)
Pressure (HPa)
ANGa
32.5
15.6
10.8
38.8
0.50
0.07
0.15
0.11
—
—
—
—
0.35
0.01
0.01
0.01
—
0.96
—
0.05
0.07
543
2.9
Kosovo
21-40
9.6-17
8.9-14.5
36-46
Tr-0.76
Tr-0.11
0.07-0.40
0.02-0.24
0.03-0.26
0.066-0.084
0.020-0.026
0.0016-0.011
0.44-0.78
0.0063-0.012
0.046-0.07
0.0098-0.027
0.0060-0.032
0-0.0003
0.09-2.6
—
0.44-1.6
293-295
2.3
SASOL0 Rosebud
28.8 28
20.2 15
8.8 11
40.1 36
0
0.54
.8-30.4
.1-20.3
.2-12.2
.5-41.1
.4-0.5
0.1
0.08
0.03-0.04
0.01-0.02
0.004-0.007
0.28
<0.001
0.002
0.002
0
0
1.6
1.6
0.5
—
—
—
.0002
.0001
0.7
0.7
0.6
299
2.4
Westfieldd
Pittsburg
30.8-31.5
16.9-17.9
8.4-9.0
38.8-39.4
0.7
0.1-0.3
0.008-0.016
0.05-0.13
0.016-0.029
0.007
0.7
—
—
—
0.0004-0.025
Illinois
31.1-32.6
16.3-17.6
8.7-9.4
38.5-39.8
0.5-0.7
0.1-0.3
0.009-0.012
0.08-0.10
0.02-0.03
0.007-0.01
1.1
0.002-0.008
0.0003 0.0001-0.0008
0.8-1.2
0.8-1.2
0.8-1.2
299
2.4
0.6-0.8
0.6-0.8
0.6-0.8
299
2.4
'Reference 4.
bReference 5.
cReference 6.
^Reference 3, range of values.
— = No data.
Units are volume percent unless otherwise noted.
-------
Appendix A
Lurgi Gasification
A.2 WASTE STREAMS
Waste streams directly from the gasifier are: low-pressure coal lock-
hopper vent gas, ash lockhopper vent gas, ash slurry, and gases released
during transients (primarily startup). Waste streams from raw gas quenching/
cooling and subsequent gas liquor separation include gas liquors and depres-
surization gases. Tars and oils represent byproducts recovered from gas
liquors.
Prior to adding a fresh charge of coal to the lockhopper, it must be
depressurized. Vent gases above 0.2 MPa are normally recovered while those
below 0.2 MPa are not. Characteristics of the coal lockhopper vent gas are
determined by the pressurant gas. If Lurgi gases were used as pressurant, the
composition of the vent can be assumed similar to raw Lurgi gas. Testing at
Kosovo (5) indicated a particulate loading of approximately 8 g/m3, most of
which were aerosol organics.
Steam is utilized for pressurization of the ash lockhopper to minimize
the flow of gasifier feed (i.e., steam and 02) from the gasifier into the
lockhopper. Before ash is discharged from the lockhopper to the ash quench
system, it is depressurized. The resulting vent gases should contain only
steam, 02, and entrained ash particles. The only test data available on ash
lockhopper vent gases is for the Kosovo plant (5). At this plant, the ash
lockhopper gases are sent to a cyclone where they are contacted with process
water (the source of the process water was not known). The cyclone exit gas
contained 85 volume percent moisture and had the composition shown in Table
A-3. For purposes of analysis in this manual though, ash lockhopper vent
gases were assumed to contain 85 percent moisture, with the balance being 02
and N2 in the same ratio as found in the oxygen fed stream to the gasifier.
Particulates were estimated at 10.3 g/m3 (dry basis).
A-8
-------
Appendix A
Lurgi Gasficiation
TABLE A-3. AVAILABLE TEST DATA FOR ASH LOCKHOPPE8 VENT GAS (5)
Component Quantity Best Value
Moisture
oa
N
CO,
H2S
NH,
HCN
Particulates
81 - 97 wt %
48 vol % dry
35 vol % dry
14 vol % dry
0- 82 ppmv dry
130 - 340 ppmv dry
5 4 ppmv dry
0.12 - 11.6 g/m3
85
48
35
14
82
340
54
10.3
Hot ash is quenched with water in the ash lockhopper and then discharged.
Quantities of ash produced are a function of the ash content of the coal.
After dewatering, the ash results in solid waste. The results of analyses of
gasifier ash from Kosovo (5), tfestfield (3,7), and SASOL (6) are presented in
Table A-4. Also included are values calculated from estimates of the distri-
bution of elements in the gasifier ash from Dunn County coal (8).
Flow rates and compositions of transient streams are highly variable and
data are scarce. Kosovo (5) and ANG (9) data characterizing transient gases
generated during startup are presented in Table A-5. Kosovo data (5) also
indicated that startup gases contained, after being subjected to quenching/
scrubbing, 0.06 and 9 g/Nm* of entrained particulate matter and aerosol
organics, respectively. Kosovo data indicate that startup of a gasifier
required approximately eight hours (5).
Prior to removal of tars and oils, the gas liquor is depressurized. Main
components of the gases released during depressurization are given in Table
3-13. In the Westfield tests (3) the temperature varied somewhat during
depressurization and the higher temperatures were stated to have led to higher
NH3 and C02 in the flash gas.
A-9
-------
TABLE A-4. CHEMICAL COMPOSITION OF LURGI ASH
I
M
O
Components
Carbon
Si04
Fe,0,
Al.O,
CaO
MgO
SO,
Cl
Na.O
K,0
Kosovo
12-26
2S-36
3.9-11
4.1-11
29-43
5.1-7.4
0.36-5.8
—
1.1-1.8
0.4-0.8
Rosebud
6.5-4.8
46.8-46.9
11.2-9.8
17.7-21.9
8.3-6.8
3.9-4.2
1.7-1.0
<0.01-<0.01
—
American Coals
111. No. 6
3.2-2.1
49.6-50.7
17.2-18.8
20.5-19.1
2.1-2.9
1.0-1.3
1.3-1.2
<0.01-<0.01
—
at Westfieldb
111. No. 5
2.0-1.0
46.1-44.6
19.7-21.2
18.1-19.3
3.9-4.0
0.7-0.2
0.6-0.04
<0.01-<0.01
—
Pitt. No. 8
7.6-4.6
43.6-44.9
15.0-16.1
20.7-26.0
3.8-3.2
0.7-0.2
0.8-<0.01
<0.01-<0.01
—
SASOL"
3
52
5
28
7
1.7
0.2
—
0.7
0.5
Westfieldd
2.8
54.6
4.7
32.7
3.6
1.3
—
—
—
Dunn County
_.
19.4
8.7
10.6
19.0
7.0
3.2
0.03
2.7
0.5
.Reference 5.
Reference 3: 2 samples per cosl based on size, one at 1/4" to 1-1/4" and second with >30% at
-------
TABLE A-5. GAS PHASE TEST DATA FOR GASIFIER STARTUP
(COMPOSITION ON DRY BASIS)
Component
H,
o,
N,
CO
CO,
CH4
Ethane
Ethylene
c,
C4
cf
ct
.Reference 5:
Reference 9,
Tr = trace.
— = No data.
Kosovo* ANGb
(Vol %) (mol %)
0.09-0.27 23.2
4.4-18
42-67 38.9
3.7-14 9.3
10-34 20.8
0.8-1.6 7.1
0.07-0.16
0.004-0.05
0.03-0.08
Tr-0.04
Tr-0.009
0.03-0.09
moisture content 70 wt %.
moisture content 27.7 mol 1
Component
H,S
COS
CH,SB
ClHjSH
Benzene
Toluene
Xylene +
ethylbenzene
Phenols
NH,
HCN
M.W. of dry gas
Kosovo
(ppmv)
6300
40-120
90-520
30-250
10-90
TR-10
TR-10
630
11000
2900
-33.1.
ANGb
(ppmv)
3000
—
—
—
—
—
—
—
6000
—
A-ll
-------
Appendix A
Lurgi Gasification
Tars and oils can be used on site as fuel, sold as byproducts, upgraded
for blending with other facility products, or gasified in a partial oxidation
type gasifier to produce additional synthesis gas. Properties of tars and
oils are presented in Tables 3-30 and 3-33, respectively.
Gas liquor is the aqueous stream which results from quenching the raw
Lurgi gases and removing tars and oils. Major components of the gas liquor
prior to removal of phenols and ammonia are given in Table A-6. A distribu-
tion of selected organic compounds in the gas liquor is given in Table 3-15.
Expected quantities of byproducts in the gas liquor per amount of coal
gasified are given below (3,4,5,11,12). Also shown is the naphtha which is
recovered from the Rectisol AGR system.
Quantity Produced
Components (percent of MAP coal gasified)
Tars 2.4 - 5.3
Oils 0.3 - 3.2
Phenols 0.3 - 1.1
Ammonia 0.6 - 1.3
Naphtha 0.9 - 2.0
A.3 ADVANTAGES AND LIMITATIONS
The dry ash Lurgi system can gasify a wide variety of coals including
caking and non-caking coals. It has been in operation for many years, is
commercially available, and is a relatively straight forward process. Its
operating conditions favor the formation of methane, reduce the cost of gas
transmission, and are advantageous for combined-cycle or synthesis gas
utilization.
Operating conditions which favor methane formation also lead to the
formation of heavy organic byproducts and materials which require additional
processing. Coal bed temperatures below ash fushion temperatures limit
A-12
-------
TABLE A-6. MAJOR COMPONENTS AND CHARACTERISTICS OF LURGI GAS LIQUOR
UJ
Westfield American Coal*b
Tars and Oils
Phenols (as C,H,OH)
Ammonia
Free
Fixed
Fatty Acids
Aromatic Amines
Organic Carbon
Sulfide (as H,S)
Tbiocyanate (SCN)
Total Sulfur
Carbonate (as CO,)
Cyanide (as CN)
Chloride
TDS
COD
BOD,
pH
Kosovo
400
2120
3510
250
—
159
4970
—
>75
—
—
<1
—
2170
17700-18900
9030
9.1-9.2
Rosebud
150-270
5000-5400
7310-8930
300-470
1995-1050
—
—
55-330
6-60
225-445
13600-19960
5-8
25-9
2480-1940
22800-18600
10600-12250
8.2-8.1
111. No. 6
500-150
2200-2930
4800-3990
150-260
370-375
—
—
290-240
160-135
360-330
7780-10620
37-17
95-80
1860-1765
8900-9650
3600-9580
7.8-7.7
111. No. 5
200-90
3550-3300
5440-4390
310-220
390-350
—
—
320-340
164-135
370-405
5810-11020
21-13
230-165
1640-2190
11000-9400
4600-5400
7.9-7.8
Pitt. No. 8
100-240
1450-1600
3220-4090
350-250
205-260
—
—
120-220
155-210
205-340
7700-10650
33-16
195-160
1310-1140
3500-5900
2700-4300
7.7-7.6
Bromel0
2480
11200
—
—
226
232
2460
<0.5
85
—
—
—
—
2460
12500
—
8.9
SASOLd
5000
3250-4000
10600
150-200
300
—
—
237
—
—
7000
6
—
—
—
—
"
Reference 5.
Reference 3 (sidestream liquor), 2 runs made for each coal; the first for coal size 1-1/4"
cto 1/4", the second contained at least 30% less than 1/4".
Reference 10.
Reference 6.
— = No data.
Units are mg/L except pH.
-------
Appendix A
Lurgi Gasification
process efficiency and increase steam requirements from outside sources. The
fixed-bed reactor design limits the maximum size of the reactor, thus
potentially making it more costly for large installations.
A.4 MASS FLOW ESTIMATES
Estimates of mass flows for three types of coal gasified by a Lnrgi sys-
tem were developed. These values were calculated from methods indicated in
this section based on gasifying sufficient coal to produce approximately
120 TJ/day of synthesis gas. These methods involved the use of available
data from which stream quantities and composition were derived or extra-
polated. Several of the streams are thus a composite of available data. The
result is that material balances are not exact but are generally within 1%.
Details of the material balance results are presented in Appendix E.
The three coals selected include a subbituminous coal (Montana Rosebud),
a bituminous coal (Illinois No. 6), and a lignite (Dunn County, ND). The
composition of these coals is presented in Table 2-1. All three coals are
plentiful in the United States and have been successfully gasified in a Lurgi
system, with sufficient data gathered go enable estimation of gasification
stream quantities and characteristics. These coals also represent different
classes of coals and cover a range of moisture, ash, and sulfur contents.
A.4.1 Major Gaseous Constituents
Production of major gasifier output gases (H,, CO, CO,, and CH4) were
estimated from data and elemental material balances contained in a Westfield
report (3) for tests on several bituminous and subbituminous coals and on data
from Kosovo studies (5) or the EIS for the ANG SNG facility for lignite cases
(4).
A-14
-------
Appendix A
Lnrgi Gasification
A. 4. 2 Sulfur Distribution
The quantity of sulfur contained in the quenched Lurgi gas stream was
determined by subtracting that contained in the ash, tar, oil, and gas liquor
(as discussed in subsequent sections) from that contained in the coal. The
remaining sulfur was distributed among the following constituents: H2S,
COS, CHjSH, C2HSSH, and C3+ mercaptans. The distribution used was based on
Kosovo data (5) and is given below:
Constituent Mole %
H2S 88.8
COS 1.2
CHjSH 7.4
C2H5SH 2.3
C3+ mercaptans 0.3
A. 4. 3 Hydrocarbon Distribution
The distribution of hydrocarbon species in the quenched Lurgi gas stream
was based, for all coals, on the following assumptions:
• C2 through C4 aliphatics were based on the ANG EIS (4) which
gives, by percent volume in raw dry Lurgi gas: 0.495 for C2H4;
0.07 for C2H4, C,H4, and C4Hg ; 0.08 for C3Hg ; and 0.04 for
Cj aliphatics, benzene, toluene, and other aromatics were based
on Westfield data for St. Clair de Ville condensibles (3).
Distribution among these constituents was determined using
Westfield' s data for the analysis of condensible aromatic com-
pounds. The production rate of these compounds was based on
the following normalized flow rates from Westfield data:
Rosebud, 0.01; and Illinois No. 6, 0.0109 kg per kg MAP coal.
Dunn County production rate and distribution were assumed
equivalent to Rosebud.
A-15
-------
Appendix A
Lurgi Gasification
A.4.4 Hydrogen Cyanide and Ammonia
Hydrogen cyanide and ammonia in quenched Lurgi gas were assumed to be 60
and less than 10 ppmv, respectively, as estimated from Kosovo data (5).
Quantities of NH3 contained in the raw gas stream were obtained by adding
that contained in the gas liquor and depressurization gas streams (given in
following discussions). Due to variability in the available data and the feed
coals, flow estimates may differ somewhat between examples.
A.4.5 Steam and Oxygen Feed
Steam and oxygen requirements for Rosebud and Illinois No. 6 coals
were estimated from Westfield data (3). Feed requirements for Dunn lignite
were estimated from data reported in the EIS for ANG's North Dakota project
(4). Values used are given below:
Steam Oxygen
Coal (kg/kg coal as received) (excludes inerts)
Rosebud 1.25 0.24
Illinois No. 6 2.5 0.45
Dunn County 1.06 0.21
A.4.6 Gas Liquor
Gas liquor flow rates were determined as follows: 1) total hydrogen and
oxygen into the gasifier was computed; 2) total hydrogen and oxygen contained
in the output constituents, other than in the gas liquor were computed; and
3) output quantities of hydrogen and oxygen were subtracted from input quanti-
ties and the difference allocated to the gas liquor stream. Gas liquor compo-
sitions are given in Table 3-14. For Rosebud and Illinois No. 6 cases, con-
centrations of major constituents were estimated from Westfield data (3).
Concentrations of major constituents in the Dunn County case gas liquor were
A-16
-------
Appendix A
Lurgi Gasification
estimated from data contained in the Bromel report (10). The concentration of
ammonia was normalized with respect to the ratio of coal nitrogen content of
Mercer County (basis in Bromel report) and Dunn County coals. COD and TOC
values were based upon data from References 8 and 10.
A.4.7 Low-Pressure Coal Lockhooner Vent Gas
Coal lockhopper vent gas flows were assumed to be proportional to the
coal feed rate. Using the lock gas flow (excluding ejection or dilution air)
of 37.2 kg-moles/hr for 1020 Mg coal per hour as estimated in the proposed ANG
facility (4,9), a factor of 0.04 kg-moles of low-pressure vent gas per Mg
coal feed was calculated. The low-pressure vent represents about 2% of the
total coal lockhopper gases (9). The dry gas composition of the low-pressure
lockhopper gases was assumed to be the same as the raw Lurgi gas with HaO at
0.8 volume percent. Particulates in the vent gas were estimated at 0.2
g/Nm3 while aerosol organics were estimated at 7.3 g/Nm3 (5).
A.4.8 Ash Lockhopper Vent Gas
The flow rate of ash lockhopper vent gas was assumed to be proportional
to the ash flow rate. Based on Kosovo data (5) a factor of 16 kg dry gas per
1000 kg dry ash was used. The composition of ash lockhopper vent gas was
assumed to be 85 volume percent moisture based on Kosovo data (5) with the
remainder being nitrogen and oxygen in the same ratio as found in the oxygen
feed. A particulate loading of 10.3 g/Nm3 dry gas was assumed based on
Kosovo data (5).
A.4.9 Gas Liquor Depressurization Gas
Gas liquor depressurization gas compositions were generally based on both
Westfield (3) and Kosovo data (5). Flow rates for Rosebud and Illinois No. 6
coals were based on normalized Westfield data (quantity of depressurization
A-17
-------
Appendix A
Lurgi Gasification
gas produced per quantity of input coal to gasifier) (3). Flow rates for the
Dunn County coal case were based on normalized Rosebud and Illinois No. 6
data. Water vapor content was based on data presented in Reference 13.
A.2.10 Chlorine
Chlorine distribution was computed in the following manner: 1) the
quantity of input chlorine was calculated based on coal analysis; 2) 10 ppm
HC1 was assumed to be present in the quenched Lurgi gas; 3) HC1 in gas liquor
was calculated based on the assumed composition; and 4) the remaining chlorine
was distributed to the gasifier ash.
A.4.11 Ash
Available data on the composition of Lurgi ash are summarized in Tables
A-4 and 3-11. Ash sulfur and carbon contents were generally based on
Westfield data (3) for Rosebud and Illinois No. 6 coals, and the ANG EIS (4)
for the Dunn County case. Values used in mass flow calculations (weight
percent basis) are given below:
Rosebud Illinois No. 6 Dunn County
S 0.68 0.56 1.24
C 6.59 3.19 6.5
A.4.12 Byproducts
Byproduct tar, oil, phenol, and fatty acid compositions for Rosebud and
Illinois No. 6 coals were based on Westfield data (3). Since these data were
not available for the Dunn County case, compositions were derived from the
Westfield data.
A-18
-------
Appendix A
Lurgi Gasification
Mass flow calculations for tar and oil are given below on an ash free
basis.
C
H
0
N
S
Tar (wt %)
Rosebud
83.1
7.7
8.24
0.65
0.28
Illinois No. 6
85.5
6.44
5.17
1.18
1.7
Dunn Co.
83.2
7.0
8.3
1.2
0.29
Oil (wt %)
Rosebud
81.4
9.18
8.46
0.46
0.50
Illinois No. 6
84.8
7.77
4.3
0.7
2.4
Dunn Co.
81.4
8.0
9.4
0.7
0.36
Tar ash. content (total inert suspended material or dust) was assumed to be 7
wt percent, based on Westfield Illinois No. 6 (3) and Kosovo (5) data (note:
Westfield Rosebud tar ash content data was inexplicably high). Oil ash con-
tent was assumed to be 0.2 wt percent based on Kosovo data (5).
Tar and oil production rates for Rosebud and Illinois No. 6 coals were
based on Westfield data on a normalized basis (weight produced per weight of
coal gasified) (3). These values (kg/103 kg coal) are given below:
Rosebud
Illinois No. 6
Tar
19
30
Oil
20.9
2.9
Tar and oil production rates for Dunn County coal were based on values given
in the ANG EIS (4) of 1.6 and 0.37 wt percent (wet basis), respectively, in
the raw gas.
Phenol and fatty acid compositional data are given below (3). Production
rates were determined by the assumed gas liquor concentrations previously
discussed.
Phenol (wt %)
Fatty Acids (wt %)
Rosebud
C 77.1
H 5.7
0 17.1
Illinois No. 6
76.7
6.7
16.7
Dunn Co.
77.3
6.2
16.9
Rosebud
38.1
9.5
52.4
Illinois No. 6
38.5
7.7
53.8
Dunn Co .
38.3
8.6
53.1
A-19
-------
Appendix A
Lurgi Gasification
Naphtha is also a byproduct of Lurgi gasification when the raw gases are
upgraded via the Rectisol process (see Appendix B). This naphtha fraction,
composed of hydrocarbons containing at least four carbon atoms, sulfur com-
pounds, and HCN is a function of hydrocarbon distribution in the raw gas and
Rectisol operations.
A.4.13 Gasifier Transient Waste Gases
Gasifier transient waste gas composition, flow rate, emissions, and fre-
quency of discharge were based on the following assumptions:
• The following gasifier startup information was derived from ANG
permit application information (9):
Type of Type of Duration of Number of Startups
Maintenance Startup Startup (hr) per Yeara
Scheduled Cold (air) 8 13
overhaul
Unscheduled
long Cold (air) 8 26
short Hot (02)
-------
Appendix A
Lurgi Gasification
A. 5 REFERENCES
1. Considine, D.M. ed., Energy Technology Handbook, pp 1-188 to 1-200,
1-285 to 1-295, McGraw-Hill Book Co., 1977.
2. Beychok, M.R., W.J. Rhodes, "Comparison of Environmental Design Aspects
of some Lurgi-Based Synfuels Plants," Sixth Symposium, Env. Aspects of
Fuel Conversion Tech., Denver, Colorado, October 1981.
3. Trials of American Coals in a Lurgi Gasifier at Westfield, Scotland,
Woodall-Duckham Ltd., Sussex, England, ERDA RfiD Report No. 105, 1974.
4. ANG Coal Gasification Company North Dakota Project. Final Environmental
Impact Statement, D.S. Department of the Interior, January 20, 1978.
(Referred to as ANG EIS).
5. Lee, K.W. , et al.. Environmental Assessment: Source Test and Evaluation
Report — Lurgi-Type (Kosovo, Yugoslavia) Medium-Btu Gasification, Final
Report, EPA-600/7-81-142, D.S. EPA, Washington, D.C., August 1981.
6. Information supplied by South African Coal, Oil, and Gas Corp. Ltd., to
EPA's Industrial Environmental Research Laboratory, Research Triangle
Park, NC, November 1974.
7. Information Supplied by Westfield Development Center to EPA's Industrial
Environmental Research Laboratory, Research Triangle Park. November 1974.
8. Sommerville, M.H., J.L. Elder, et al.. An Environmental Assessment of a
250 MM SCFD Dry Ash Lurgi Coal Gasification Facility in Dunn County,
North Dakota. University of North Dakota, Engineering Experiment
Station, Bulletin No. 76-12-EES-01 Volumes I - IV, December 1976.
9. Permit Application Information provided to the State of North Dakota by
the ANG Coal Gasification Company, 1976-1980.
10. Bromel, M.C., J.R. Fleeker, Biotreating and Chemistry of Waste Waters
from the South African Coal, Oil and Gas Corporation (SASOL) Coal
Gasification Plant, North Dakota State University, Fargo, North Dakota,
December 1976.
11. Final Environmental Statement: Western Gasification Company (WESCO) Coal
Gasification Project and Expansion of Navajo Mine by Utah International
Inc. New Mexico, U.S. Dept. of the Interior Rep. No. FES 76-2, January
1976.
A-21
-------
Appendix A
Lurgi Gasification
12. Final Environmental Statement: El Paso Coal Gasification Project, New
Mexico, U.S. Dept. of the Interior Doc. No. DES-77-4, February 1977.
13. Sinor, I.E., Evaluation of Background Data Relating to New Source
Performance Standards for Lurgi Gasification, Cameron Engineers Inc.,
Denver, Colorado, EPA 600/7-77-057, June 1977, 233 p.
A-22
-------
APPENDIX B
RECTISOL ACID GAS REMOVAL PROCESS
B-l
-------
APPENDIX B
RECTISOL ACID GAS REMOVAL PROCESS
B.I PROCESS DESCRIPTION
Rectisol is an acid gas removal process which removes carbon dioxide,
hydrogen sulfide, carbonyl sulfide, organic sulfur compounds, hydrogen cya-
nide, ammonia, benzene, and gum-forming hydrocarbons from synthesis gases by
means of physical absorption in an organic solvent (especially cold methanol)
at temperatures below 273 K. Operation is based upon the fact that these com-
pounds, particularly the reduced sulfur species and carbon dioxide, are very
soluble at high pressure in cold methanol and are readily recoverable by flash
desorption. This is demonstrated in Figure B-l, which presents carbon dioxide
solubility as a function of partial pressure (1). Consider, for example, the
absorption of carbon dioxide at a partial pressure of 1.0 MPa. From Figure
B-l it is evident that at least 90 percent of the dissolved carbon dioxide may
be desorbed by isothermal flashing at methanol temperatures of 258 K or lower.
Solubility data for compounds at a partial pressure of 0.1 MPa over
methanol are presented in Figure B-2 (2). It should be noted that gas
solubilities generally increase with increasing partial pressure but that
solubility coefficients (the ratio of solubility to partial pressure) do not
increase appreciably with pressure until partial pressures exceed 0.1 to 0.2
MPa. Solubility coefficients of hydrogen sulfide and carbon dioxide are seen
to increase substantially with decreasing temperature while those of major
product gases such as hydrogen, carbon monoxide, and methane are relatively
temperature independent. For this reason, Rectisol absorption columns operate
at low temperatures, typically in the range of 253 to 213 K (1,3,4). Low
temperature operation also reduces solvent losses by reducing the partial
pressure of methanol in the product streams.
B-2
-------
SO 100 150
SOLUBILITY OF COj, VOL/VOL
Figure B-l. Effect of partial pressure on solubility of carbon dioxide in
methanol (1)
B-3
-------
SOLUBILITY COEFFICIENT (X) AT ONE ATMOSPHERE PARTIAL PRESSURE
[kmol OF DISSOLVED GAS/Mg OF SOLVENT x MPa PARTIAL PRESSURE OF GAS)]
°o
O
CO
id
C
ro
co
i
r>o
oo
o
c
cr
Cd
I
(ft
ro
to
ro
CV
3
O
-------
Appendix B
Rectisol Process
Because the solubilities of reduced sulfur species (e.g., hydrogen sul-
fide and carbonyl sulfide) in methanol are substantially greater than that of
carbon dioxide at the same partial pressure, the Rectisol process is capable
of selective recovery of reduced sulfur species versus carbon dioxide; to some
degree, this holds for all physical absorption solvents capable of absorbing
reduced sulfur species and carbon dioxide.
The Rectisol process was jointly developed by Linde Aktiengesellschaft
(Munich, Germany) and Lurgi Mineraloltechnik (Frankfurt, Germany), and is
currently licensed by both companies. It is also available through their
U.S. subsidiaries, Lotepro Corp. (New York, NY) and Lurgi Corp. (River Edge,
NJ), respectively. The Gelleschaft fur Kohle Technologic (GKT, Essen,
Germany) also has a limited Rectisol license applying to Koppers-Totzek (K-T)
gasification facilities.
Selective Rectisol Process Configurations
A variety of selective Rectisol units are currently being used in
applications such as ammonia and methanol synthesis, medium-Btu gas synthesis,
natural gas purification, and refinery hydrogen production. Although selec-
tive Rectisol designs are site- and process-specific, common key features
include low temperature operation, sequential hydrogen sulfide-carbon dioxide
absorption, discrete methanol regeneration columns for hydrogen sulfide and
carbon dioxide recovery, and separation of methanol and water by distillation.
However, there are significant differences among the designs in use which
relate to both the feed gas composition and the product specifications.
Examples of selective Rectisol process configurations used in coal
gasification applications are presented in Figures B-3 and B-4. The process
presented in Figure B-3 is used by AECI Limited at Hodderfontein, Republic of
South Africa, and desulfurizes an essentially hydrocarbon-free quenched K-T
B-5
-------
HjS-fllCH GAS
REGENERATION
COLUMN
ICO,!
CO2 RICH HAS
Figure B-3. Process flow diagram of the Modderfontein selective Rectisol section (5,6)
-------
CRUDE
PRODUCT
GAS FROM
GAS
PRODUCTION
SECTION
PRODUCT GAS
PRODUCT GAS
GAS
CONDENSATE
TO MEDIUM
OIL SEPARATOR
IN TAR OIL
SEPARATION
SECTION
»o~^
}LER
1
METHANOL
LIQUOR
*~|H,O
-04-
CLEAN PRODUCT GAS
1STC02
ABSORBER
CLEAN PRODUCT
GAS TO GAS
DISTRIBUTION
PURE PRODUCT
GAS TO AMMONIA
PLANT
2NOCO2
ABSORBER
BY PRODUCT < I f
NAPTHA TO
BY PRODUCT
STORAGE
SECTION
CYANIC WATER
TO TAR OIL
SEPARATION
SECTION
HjS RICH WASTE
• GAS TO BURNER
• CO, RICH WASTE
Figure B-4. Process flow diagram of the Kosovo selective Rectisol section (7,8)
-------
Appendix B
Rectisol Process
gas prior to carbon monoxide shift conversion and subsequent carbon dioxide
removal (5,6). Hethanol is added to the feed gas prior to cooling and
hydrogen sulfide absorption to prevent icing. Moisture in the feed gas is
removed from the hydrogen sulfide absorber in solution with methanol, which is
recovered by distillation. Hydrogen sulfide and carbonyl sulfide are absorbed
from the feed gas using sulfur-free methanol from the carbon dioxide regenera-
tion column. Rich methanol from the hydrogen sulfide absorber is partially
flashed to liberate absorbed hydrogen and carbon monoxide which is compressed
and combined with the cold feed gas. Additional flashing and stripping in the
concentration column, with reabsorption of reduced sulfur species in sulfur-
free methanol, produces a sulfur-rich methanol stream for hot regeneration and
a carbon dioxide offgas. Hydrogen sulfide is recovered by stripping with
methanol vapor in the regeneration column.
Carbon dioxide is removed from shifted process gas by absorption in
regenerated methanol. Methanol is added to the shift gas prior to cooling and
carbon dioxide absorption to prevent icing, and moisture in the shift gas is
removed from the carbon dioxide absorber in solution with methanol. Rich
methanol from the carbon dioxide absorber is partially flashed to recover
absorbed hydrogen which is compressed and combined with the cold feed gas to
the hydrogen sulfide absorber. Carbon dioxide is recovered by flashing and
stripping with nitrogen in the carbon dioxide regeneration column.
It should be noted that desulfurization prior to shift conversion enables
the use of conventional shift catalysts (e.g., iron-chromium and copper-zinc)
and can enhance process selectivity by absorbing hydrogen sulfide in the
presence of a minimum of carbon dioxide (approximately 10 to 12 percent by
volume for K-T coal gasification, 18 to 20 percent for Texaco coal gasifica-
tion, and 5 to 6 percent for gas produced by partial oxidation of oil). How-
ever, in conjunction with partial oxidation of liquid hydrocarbons for hydro-
gen or ammonia production, shift conversion employing sulfur tolerant cobalt-
molybdate shift catalysts precedes acid gas removal. Selective Rectisol
-------
Appendix B
Rectisol Process
configurations for such systems are similar to that presented in Figure B-3
except that no gas processing occurs between hydrogen sulfide absorption and
carbon dioxide absorption. Shift conversion prior to acid gas removal results
in an increased concentration of carbon dioxide in the hydrogen sulfide
absorber feed gas (up to about 42 percent volume). Owing to the less favor-
able carbon dioxide to hydrogen sulfide ratio after shift conversion, a
greater degree of methanol enrichment is required to achieve the same
selectivity attainable with an unshifted feed gas.
The process presented in Figure B-4 is used at the Kosovo Gasification
Plant near Pristina, Yugoslavia for the production of medium-Btn fuel gas and
hydrogen for ammonia synthesis (7,8). Feed gas to the Rectisol unit is
generated by gasification of lignite in oxygen-blown Lurgi-type gasifiers.
Cooled crude gas from gasification is further cooled by sequential washing
with cold water and methanol in the two stage cooler. Condensed gas liquor
from the water wash section is flashed to liberate dissolved sour gases, and
the organic phase is recovered from wash water in the naphtha separator. Con-
densed gas liquor from the cold methanol wash section is flashed, and methanol
and condensed moisture are recovered from the naphtha phase by extraction with
water. Dissolved organics in the aqueous phase are recovered by distillation.
Naphtha from the naphtha separator and the naphtha/methanol/water extractor is
sent to byproduct storage via the naphtha surge tank. Cyanic water from
naphtha separation and methanol/water distillation is sent to tar/oil separa-
tion.
Gas from the two stage cooler is scrubbed with carbon dioxide-rich
methanol in the hydrogen sulfide absorber for bulk removal of reduced sulfur
species. Carbon dioxide is removed from the first absorber top gas in two
carbon dioxide absorbers. Bulk carbon dioxide removal is achieved in the
first absorber by washing with carbon dioxide-lean methanol and regenerated
methanol. Overhead gas from the first carbon dioxide absorber is fed directly
into the fuel gas distribution system. When a higher purity gas is required
B-9
-------
Appendix B
Rectisol Process
for feed to the cryogenic hydrogen separation unit, additional carbon dioxide
removal is achieved in the second carbon dioxide absorber using regenerated
methanol.
Hydrogen sulfide-rich methanol is regenerated by multistage flashing in
the hydrogen sulfide flash tower, and steam stripping in the methanol regener-
ation column. Hydrogen sulfide-rich waste gas from methanol regeneration is
combined with flash gas from the naphtha separator and the methanol prewash
flash tank prior to disposal. Carbon dioxide-rich methanol is regenerated by
multistage flashing and nitrogen stripping in the carbon dioxide flash tower.
Based upon publicly available data, it is not known how the Kosovo
Rectisol design compares with other selective Rectisol units currently
processing Lurgi crude gas. Several selective Rectisol designs have been
prepared for proposed Lurgi gasification facilities in the United States
(e.g., facilities for Wesco, El Paso Natural Gas Co., Hampshire Energy Co. and
Nakota Co) (9). However, data with respect to process configuration are
generally proprietary.
Configurations of the two units presented in Figures B—3 and B—4 differ
in several respects. Principal differences result from 1) the fact that Lurgi
crude gas contains significant levels of condensible hydrocarbons (approxi-
mately 0.01 kg C5+ aliphatics, benzene, toluene, and other aromatics per
kg MAP coal) which must be removed prior to acid gas removal (10), 2) the need
for two-stage acid gas removal if sulfur intolerant catalysts are used for
shift conversion, and 3) the fact that at Kosovo all hydrogen sulfide contain-
ing offgases are simply burned so that high hydrogen sulfide concentrations
are not necessarily, as would be the case for Claus processing. These designs
differ substantially wtih regard to selectivity. Differences in the perfor-
mance of these two units are detailed in Section B.3.
B-10
-------
Appendix B
Rectisol Process
Nonselective Rectisol Process Configurations
Nonselective Rectisol processes differ from selective processes in that
all acid gas constituents are absorbed simultaneously and no carbon dioxide
regenerator or reabsorber is used to produce a high purity carbon dioxide vent
gas. An example of a commercial nonselective Rectisol unit is presented in
Figure B-5 which is a simplified schematic of the South African Oil, Coal, and
Gas Corporation's SASOL I acid gas removal system (1). Feed gas to acid gas
removal is crude or partially shifted Lurgi gas from Fischer-Tropsch syn-
thesis. The feed gas is split into three streams which are cooled in each of
two stages by refrigeration, heat exchange with cold high pressure flash gas
(including carbon dioxide-rich flash gases above 100 kPa) and heat exchange
with cold product gas. Condensed moisture and hydrocarbons are recovered from
the combined feed gas following the first cooling stage, and methanol is added
to prevent icing in the second gas cooling stage. Following the second gas
cooling stage, the condensed gas liquor is recovered from the coal gas and
sent to the naphtha separator for byproduct and methanol recovery.
Cooled gas is washed with cold methanol in three consecutive stages. In
the first absorption or prewash stage, the cooled gas is washed with flashed
methanol from the expansion tower to remove the final traces of condensible
organics along with some hydrogen sulfide, carbon dioxide, and organic sulfur
compounds. Rich methanol from the first stage absorber is combined with gas
liquor from the gas cooling second stage and sent to the naphtha separator.
Separator feed is flashed and extracted with water to yield an aqueous
methanol phase and a byproduct naphtha phase containing organic sulfur
compounds. Methanol is recovered from the aqueous phase by distillation.
Bulk acid gas removal is achieved in the second or main wash stage or
absorber by washing with flashed methanol from the expansion tower. Rich
methanol from the second stage absorber is regenerated along with the
B-ll
-------
METHANOL
FEED GAS
HIGH PRESSURE
FLASH GAS
PRODUCT GAS
ATMOSPHERIC
FLASH GAS
HOT
REGENERATOR
CYANIC WATER
LOW PRESSURE
FLASH GAS
Figure B-5. Process flow diagram of the SASOL I non-selective Recitsol section (1)
-------
Appendix B
Rectisol Process
methanol/water still overhead in an expansion tower. Regeneration is by
pressure reduction in six stages to a final pressure of about 30 KPa. High
pressure flash gas consisting primarily of carbon dioxide, carbon monoxide,
and hydrogen is used to cool the Rectisol feed gas, and then used as onsite
fuel gas. Low pressure flash gas is compressed and flared.
The third or finewash stage absorber effects final gas purification by
washing the second-stage absorber effluent gas with completely stripped
methanol from the hot regenerator. Rich methanol from the third-stage
absorber is partly regenerated by flashing to atmospheric pressure and then
competely stripped of acid gas in a distillation column. Atmospheric flash
gas from the hot regenerator is released for incineration. Cold product gas
is used to precool the Rectisol feed gas, and then sent to liquid synthesis.
Based upon publicly available data, it is not known how the SASOL I
Rectisol design compares with other commercial nonselective Rectisol
processes, although a similar design has been used in the SASOL II facility
which was commissioned in 1980 (11). Nonselective Rectisol designs have been
prepared for several proposed Lurgi gasification facilities in the United
States including those proposed by Great Plains Gasification Associates
(currently under construction), Wycoalgas Inc., Tenneco Coal Gasification, and
El Paso Natural Gas Co. (9.12). A schematic of the Great Plains nonselective
Rectisol section is presented in Figure B-6 (13). This schematic indicates a
similar configuration to that of the SASOL I facility but includes details
such as the prewash flash vessel and the azeotrope distillation column which
are not included in Figure B-5.
B.2 PROCESS APPLICABILITY
The Rectisol process is used in three typical applications: 1) removal of
carbon dioxide, hydrogen sulfide, carbonyl sulfide, organic sulfur compounds.
B-13
-------
Figure B-6. Process flow diagram of the Great Plains non-selective Rectisol section (13)
-------
Appendix B
Rectisol Process
hydrogen cyanide, ammonia, benzene, and gum-forming hydrocarbons from crude
gas produced by coal gasification for syngas and SNG production; 2) removal of
hydrogen sulfide, carbonyl sulfide, and carbon dioxide from gas produced by
partial oxidation for syngas or hydrogen production; and 3) used in conjunc-
tion with low temperature liquefaction and fractionation plants for removal of
acidic components present at moderate levels. Process limitations in these
applications primarily relate to requirements for high pressure, low tempera-
ture operation, and methanol contamination by minor constituents present in
the feed gas.
As with any other physical absorption process, the minimum circulation
rate of solvent required for complete removal of a gaseous constituent is
inversely proportional to the partial pressure of the constituent in the feed
gas, and to the solubility coefficient for the constituent in the solvent
used. Process economics depend mainly upon the solvent circulation rate
because the circulation rate influences the size of all equipment and,
therefore, the capital costs. Solvent circulation rate also affects the
operating costs since pumping costs are proportional to circulation rate and
regeneration costs are nearly proportional to the circulation rate (14).
Therefore, the economics of physical absorption processes improves with
increasing acid gas partial pressures. Physical solvent type acid gas removal
processes are typically selected when acid gas partial pressures are greater
than about 1.0 to 1.4 MPa (1,15). Feed acid gas partial pressures at existing
Rectisol units in coal gasification and partial oxidation applications are in
the range of 0.4 to 2.6 MPa (3,5,6).
As indicated in Figure B-2, the solubilities of most gases of interest
increase with decreasing methanol temperature. Thus, for reasons mentioned
above, Rectisol economics improve with decreasing methanol temperature.
Rectisol absorption columns operate at low temperatures, typically in the
range of 253 to 213 K (1,3,4). An additional benefit of low temperature
operation is the attendant reduction of methanol losses. Vapor pressure data
B-15
-------
Appendix B
Rectisol Process
for methanol are presented in Figure B-7 (1). These data indicate that meth-
anol losses can be decreased by a factor of about three to four for each 20 K
temperature reduction down to 253 K and by about one order of magnitude for
each 20 K temperature reduction below 253 K.
Minor constituents such as ammonia, hydrogen cyanide, and nitrogen oxides
which may be present in the Rectisol feed gas can complicate operation or
result in fouling. Ammonia and hydrogen cyanide, which are very soluble in
methanol, make the regeneration process more complicated and result in
additional steam requirements (2). Further, the presence of ammonia and
hydrogen cyanide in the hydrogen sulfide fraction is not desirable due to the
potential for adverse reactions during subsequent sulfur recovery. These
contaminants may be removed from the feed gas by employing a prewash of either
cold water or methanol. This prewash also provides feed gas drying
(particularly the methanol prewash) and, in low temperature gasification
applications, removes condensible hydrocarbons.
One coal gasification facility has reported Rectisol fouling which is
attributed to the presence of oxygen and nitrogen oxides in the Rectisol feed
gas (16,21). Oxygen in the Rectisol feed gas results in oxidation of a por-
tion of the hydrogen sulfide to elemental sulfur. The presence of nitric
oxide with oxygen accelerates the rate of sulfide oxidation. Deposits of
sulfur in columns resulted in reduced solvent circulation rates, and fouling
of heat exchangers resulted in insufficient cooling capability to achieve the
required degree of gas purification.
It has been determined that this fouling can be reduced by allowing low
levels of hydrogen cyanide and ammonia to enter the Rectisol unit to solubil-
ize sulfur by formation of ammonium thiocyanate which is ultimately removed
with the methanol/water distillation bottoms. When insufficient hydrogen
B-16
-------
1000
100
o
cc
u- 10
O
E
LU
QC
00
LU
QC
O.
QC
O
>
_i
O
1.0
LU
2
0.10
0.01
193
213 233 253 273 293
TEMPERATURE(K)
Figure B-7. Vapor pressure of methanol (1)
313
333
B-17
-------
Appendix B
Rectisol Process
cyanide is present in the feed gas, sodium cyanide solution is injected into
the methanol. A more fundamental solution which has been implemented is the
hydrogenation of nitrogen oxides and oxygen over a cobalt molybdate catalyst
upstream of the Rectisol unit. Formation of elemental sulfur and the associ-
ated fouling of the Rectisol unit have not occurred since installation of the
catalytic hydrogenation unit (21).
B.3 PROCESS PERFORMANCE
Depending upon the product requirements and other site specific con-
straints, the Rectisol process can be designed to yield a product gas contain-
ing less than 0.1 ppmv total sulfur, and less than 10 ppmv carbon dioxide.
The carbon dioxide content achievable in the purified gas is independent of
the type of Rectisol process employed (i.e., selective or nonselective
Rectisol). However, in the case of a nonselective Rectisol process, the util-
ities (steam, cooling water, and refrigerant) increase to obtain a product gas
with ppmv levels of carbon dioxide. Publicly available data indicate that in
gasification applications involving an essentially hydrocarbon-free feed gas,
selective Rectisol processes can produce a sulfur-rich offgas containing 25-
75% hydrogen sulfide, and a carbon dioxide-rich offgas containing less than 10
ppmv total sulfur. The presence of moderate quantities of hydrocarbons in the
feed gas (9 to 16 percent) has no influence on the selectivity of hydrogen
sulfide recovery; hydrogen sulfide concentrations of 25 to 35 percent in the
hydrogen sulfide-rich offgas can be achieved along with a carbon dioxide-rich
offgas containing 10 ppmv total sulfur. However, C3 and C4 hydrocarbons
present in the feed gas, will tend to concentrate in the hydrogen sulfide-rich
offgas.
Performance data for selective Rectisol units treating essentially hydro-
carbon free feed gases are summarized in Table B-l. Plants 1 and 2 produce
hydrogen and ammonia synthesis gas, respectively, by partial oxidation of
B-18
-------
TABLE B-l. SELECTIVE RECTISOL PERFORMANCE DATA FOR HIGH TEUPEEATURE GASIFICATION APPLICATIONS*
I
I—'
VD
Gas
Component
B>
H.+A,
CO
CH.
CO,
H,S
COS
Flow Rate.
kaol/hr
Teaiperatnre, E
Preaaure, MPa
Plant 3 producea
Refer to
Concentrationa of
Feed Gaa, Mole *
Plant 1 Plant 2 Plant 3
62.35- 61.59 27.5-
63.74 29.3
0.12- 0.41 1.52
0.52
3.24- 2.60 56.62
4.13
0.13- 0.33 0.10
0.17
31.62- 34.55 11.8-
33.23 13.3
0.26- 0.52 0.59-
0.49 0.75
10-6 3pp. - 0.10
3562- 6112 4691-
3992 4801
303-313 - 311
3.2-3.3 7.3 3.0-3.1
•union U ayntheaia gat by coal
Figure B-3 for exaaple procea
BCM and MB. in the CO -rich
Purified Gaa
Plant 1 Plant
93.58- 94.92
94.08
0.17- 0.67
0.82
4.86 3.94
0.19 0.47
0.24
ilOppai 50pp.
ilppai 1pp.
-
2426- 3950
2639
295-309
2.9-3.1 7.1
gaaif ication;
offgea at Plant
, Mole * Stripping Gai, Mole «
2 Plant 3 Plant 1 Plant 2 Plant 3
93.0-
93.2
1.78 100 100 100
4.97-
5.15
0.10
<50pp-
<2pp.
-
4078- 268 187 334-
4096 543
304 303 - 311
4.8 0.25 0.49 0.26
0.44
ahift converaion follova hydrogen aulfide
CO.-Rich
Offgaa. Mole % .
Plant 1 Plant Z Plant 3~
0.31-
0.33
17.2-
19.3
0.08-
0.14
10.02
80.2-
82.4
2-Spp.
8pp.
1370-
1567
295-303
0.10
renoval bot
(5.6).
0.76 0.40-
0.44
8.22 12.1-
14.5
0.11 0.34-
0.43
0.06 0.01
90.85 84.7-
87.0
5 ppat <5ppai
<2pp»
2243 2731-
3690
302
0.11 0.097
precedea carbon
fl,S-Rich Offgaa, Mole %
Plant 1 Plant 2 Plant 3
-
0.08 1.92 2.5-
8.4
-
-
54.7- 68.31 10.6-
74.7
25.2- 29.77 25.5-
35.1 71.9e
0.08- - 9.54d
0.76
30- 107 48-
55 108
303-322 - 311
0.40- 0.19 0.24-
0.44 0.26
dioxide re.oval (2.6).
Higher hydrogen vulfide concentrations require More refrigeration and More stripping gas.
d
A COS level of about 3.4 nol e percent would be expected with an BaS concentration of 25.S »ole percent.
-------
Appendix B
Rectisol Process
oil. These plants utilize sulfur-tolerant shift conversion catalysts which
enable shift conversion prior to acid gas removal. Therefore, the feed gases
to Plants 1 and 2 contain 31 to 35% carbon dioxide, 62 to 64% hydrogen, and
less than about 5% carbon monoxide (2,3,6,17). Plant 3 is a coal gasification
facility producing ammonia synthesis gas. This plant employs a two-stage
Rectisol system which removes sulfur species prior to shift conversion and
removes carbon dioxide subsequent to shift conversion (refer to Figure B-3 for
example process flow diagram). Feed gas to the Plant 3 sulfur absorber there-
fore contains only 12-13% carbon dioxide, 27-29% hydrogen, and about 57%
carbon monoxide (2,6). Feed gas to the carbon dioxide absorber, which is not
included in Table B-l, contains 42-43% carbon dioxide, 53-54% hydrogen, and
about 3% carbon monoxide.
These selective Rectisol units are seen to perform similarly in most
respects over a wide range of operating pressures although there is a substan-
tial range in the concentration of hydrogen sulfide, 25-72%, in the sulfur-
rich waste gas from Plant 3. Lotepro Corporation has indicated that the
higher hydrogen sulfide concentration is attainable at the expense of higher
refrigeration and stripping gas requirements (6). The amount of stripping gas
is a function of the hydrogen sulfide concentration desired in the hydrogen
snlfide-rich offgas, the type of Rectisol process, the feed gas pressure, and
the carbon dioxide, hydrogen sulfide, and carbonyl snlfide concentrations in
the feed gas. Under given conditions, an increase in stripping gas of about
60% is necessary to increase the hydrogen sulfide concentration from 25 to
70%.
Performance data for the Kosovo selective Rectisol unit (taken at partial
load and not fully representative of normal performance), which treats crude
gas from Lurgi-type gasification, are summarized in Table B-2 (refer to Figure
B-4 for the process flow diagram). Data were obtained during three sampling
B-20
-------
TABLE B-2. PERFOBNANCE DATA FOB SELECTIVE RECTISGL UNIT AT KOSOVO KEDIUU-BTU COAL GASIFICATION PLANT (7.18)*
Gas Conponent
a,
°,
N,
CO
<»,
«,
c,».
C,"<
c,
c.
c,
c.
Benzene
Toluene
Xylene and
Ethylbenzene
Phenols
H,S
COS
CH.sa
C.B.SB
BCN
pH
Tot.l Solidi, .g/L
Total Nonvolatile
Solids. .g/L
Total Suspended
Solids. «g/L
Tottl Dissolved
Solids. .g/L
COD (>s •(0>/L)
Pemsn(«nste
(•s .gO,/L)
Total Sulfur. B|/L
Flow Rite, bol/br
Flo. Rate, »'/hr
Temperature, K
'Refer to Pi jure B-4
(Streu 7.3). Hole %
Value Range
38.1
0.36
0.64
15
32
11.3
0.47
0.04
0.19
0.074
0.044
0.064
750pp>v
230pp>v
lOOppSIT
~lpp.v
0.60
97pp«v
590ppov
3.3pp»v
320ppsjv
703
295
36-46
0.09-2.6
0.04-1.6
9.6-17
21-40
8.9-14.5
-lpp.v-0.76
-lppaiv-0.11
0.07-0.40
0.02-0.24
0.01-0.06
0.02-0.20
660-840pp*v
200-260pp»v
16-110ppeiv
—
0.44-0.78
<3-120ppsiv
460-700ppxv
-------
Appendix B
Rectisol Process
campaigns in the period of September 1977 to November 1978. Tabulated data
represent the best overall data obtained during these tests, and the ranges of
the available data. As indicated previously, the presence of moderate levels
of hydrocarbons in the feed gas has no influence on process selectivity.
Differences in process selectivities indicated in Tables B-l and B-2 primarily
reflect differences in process requirements. At the Kosovo facility, the
sulfur-containing gases are burned and, therefore, high sulfur concentrations
in these offgases are not necessary. Thus, unlike the facilities cited in
Table B-l, the Kosovo facility does not utilize an enrichment stage. Also,
Kosovo's hydrogen and methane rich flash gases from the carbon dioxide and
hydrogen sulfide loaded methanol streams are added to the hydrogen sulfide
fraction rather than being recycled to the feed gas.
Available performance data for the SASOL I nonselective Rectisol unit,
which also treats crude gas from Lurgi gasification, are presented in Table B-
3 (refer to Figure B-5 for the process flow diagram). As initially designed,
the high pressure flash gas is used as an onsite fuel gas, the low pressure
flash gas is flared, and the atmospheric flash gas is vented to the atmosphere
through the power stack (19). More recently, a Stretford unit was designed to
treat the atmospheric flash gas which contains about 90% of the sulfur species
absorbed (17,19). Proposed designs for U.S. facilities indicate that at least
a portion of the high pressure flash gas is recycled to the gasification plant
for recovery of carbon monoxide, hydrogen, and methane; some fraction of the
high pressure flash gas may be combined with the other waste gases for sulfur
recovery (12,20). Therefore, the performance indicated in Table B-3 may
require some adjustment.
B-22
-------
TABLE B-3. NON-SELECTIVE RECTISOL PERFORMANCE DATA FOR SASOL I (LURGI GASIFICATION) (17)
Offeases, Mole %
Gas Component
H.
CO
CH4
CO »
Na+Ar
H»S
COS
ca
10 CSa
U)
RSH
Thiophene
Total Sulfur
ct
Flow Rate, Nm»/hr
Temperature, E
Pressure, MPa
Rectisol Feed
Gas, Mole %
40.05
20.20
8.84
28.78
1.59
0.30
lOppmv
NA
20ppmv
NA
NA
0.54
381,000
303
2.6
Product
Gas, Mole %
57.30
28.40
11.38
0.93
1.77
ND
NA
NA
NA
NA
0.04ppmv
-
263,000
288
2.4
High- Pressure
Flash Gas
21.4
18.2
11.4
46.7
1.5
0.32
NA
NA
NA
NA
NA
0.7
4,600
273
1.3
Low— Pressure
Flash Gas
2.6
4.8
7.2
83.4
0.8
0.49
NA
NA
NA
NA
NA
1.1
15,000
273
0.48
Atmospheric
Flash Gas
0.14
0.0
0.9
97.2
0.03
0.88
3 Oppmv
2ppmv
280ppmv
2ppmv
NA
0.7
98,000
268
0.11
Refer to Figure B-5 for process flow diagram.
-------
Appendix B
Rectisol Process
B.4 SECONDARY WASTE GENERATION
Secondary waste streams produced by the Rectisol acid gas removal process
are: 1) hydrogen sulfide-rich offgases; 2) carbon dioxide-rich offgases
(selective Rectisol processes only); and 3) methanol/water distillation
bottoms. Available characterization data for the offgas streams have been
summarized in Section B.3 for each of the three basic Rectisol process config-
urations. The sulfur-rich offgas is typically sent to the sulfur recovery
unit, either Claus or Stretford, or flared. When the Rectisol process is used
in conjunction with low temperature coal gasification systems (e.g., Lurgi
gasifiers) the Rectisol feed gas contains significant concentrations of C2
hydrocarbons relative to the concentration of hydrogen sulfide. The naphtha
fraction is recovered from the feed gas by washing prior to acid gas removal.
Lighter hydrocarbons largely pass through the prewash and are, to some extent,
absorbed with the acid gases. These light hydrocarbons, particularly the
CjS and C4s, tend to concentrate in the hydrogen sulfide-rich offgas and may
also be present in the carbon dioxide-rich offgas. Therefore, unless special
precautions are taken, high levels of these C3 and C4 hydrocarbons in the
Rectisol feed gas may result in off-color sulfur if Claus sulfur recovery is
employed or excessive tail gas hydrocarbon emissions if Stretford sulfur
recovery is employed. An approach proposed in conjunction with Wesco and
Hampshire Energy Co. selective Rectisol units involves the use of an amine
unit (ADIP) to separate hydrocarbons from the Claus feed gas (9,20).
The carbon dioxide-rich offgas from selective Rectisol units is either
sold as byproduct or vented to the atmosphere at existing facilities. As
discussed above, light hydrocarbons present in the Rectisol feed gas are
coabsorbed to some extent with the acid gases and may be present in the carbon
dioxide-rich offgas. Further, steps taken within the Rectisol process to
minimize hydrocarbon levels in the hydrogen sulfide fraction will likely
result in increased hydrocarbons levels in the carbon dioxide offgases.
-B-24
-------
Appendix B
Rectisol Process
Similarly, carbon monoxide is coabsorbed and will be present in the carbon
dioxide-rich offgas due to its low solubility in methanol. Of course the
extent of carbon monoxide coabsorption, and therefore its potential concentra-
tion in the carbon dioxide-rich offgas, depends upon its partial pressure.
Thus, for similar acid gas removal systems, processes requiring only a partial
shift conversion (e.g., SNG, methanol, or acetic acid syntheses) would be
prone to higher concentrations of carbon monoxide in the carbon dioxide-rich
offgas. Therefore, proposed designs in Lurgi-based coal gasification applica-
tions indicate either incineration of the carbon dioxide-rich offgas for con-
trol of carbon monoxide and hydrocarbon emissions, or sale of the offgas as
byproduct; direct discharge to the atmosphere is not being proposed. Also, at
least one non-Lurgi coal gasification plant currently under construction, the
Tennessee Eastman Kingsport, Tennessee Texaco gasification project, proposes
catalytic incineration of the carbon monoxide enriched portion of the carbon
dioxide offgas for control of carbon monoxide emissions (21).
Publicly available characterization data for the methanol/water distilla-
tion bottoms are extremely limited. This is apparently due to the fact that
the size of the still bottoms stream is generally quite small relative to
other wastewater streams requiring similar wastewater treatment (e.g., gas
liquor and synthesis condensates). Thus, from an operational standpoint, the
still bottoms are likely to be of minor significance other than for checking
still operation and methanol losses. One set of data, provided by SASOL per-
sonnel (19), are presented in Table B-4. At the SASOL facility, this waste
stream is sent directly to biological treatment where it comprises less than
2% of the feed to this system.
B-25
-------
Appendix B
Rectisol Process
TABLE B-4. CHARACTERIZATION DATA FOR METHANOL/WATER
DISTILLATION BOTTOMS AT SASOL (19)
Parame tor/Component Value
pH 9.7
Phenol, mg/L 18
Cyanides (as CN), mg/L 10.4
(includes thiocyanate)
Ammonia (as N), mg/L 42
Sulfides (as S) Trace
COD, mg/L 1,686
B.5 PROCESS RELIABILITY
The original Lurgi nonselective Rectisol unit built at SASOL in 1955 has
operated with an on-stream factor of about 97% (17). Normal maintenance
includes partial shutdowns about once per year for cleaning of critical equip-
ment, and complete shutdown every two years during the normal plant downtime.
Major upsets in the Rectisol unit requiring process adjustments rarely occur
(19).
As discussed in Section B.2, plugging problems in a two-stage selective
Rectisol unit at a coal gasification facility have been reported (16). This
problem has been attributed to deposition of elemental sulfur resulting from
the presence of oxygen and nitrogen oxides in the Rectisol feed gas. Fouling
was at least partially controlled by allowing low levels of hydrogen cyanide
and ammonia to enter the Rectisol unit to solubilize sulfur by formation of
ammonium thiocyanate. A more fundamental solution is the hydrogenation of
nitrogen oxides and oxygen over a cobalt molybdate catelyst ahead of the
Rectisol unit. Detailed operating data from this facility are not available.
B-26
-------
Appendix B
Rectisol Process
B.6 PROCESS ECONOMICS
Available capital costs and utility requirements for the Rectisol process
are summarized in Tables B-5 and B-6, respectively. Tabulated capital costs
are primarily conceptual design cost estimates while tabulated utility
requirements are published data for existing units. It should be noted that
the cost of a Rectisol unit is influenced by a variety of considerations
including the feed gas flow rate, pressure, acid gas content, and heavy
hydrocarbon content, and the desired levels of selectivity and product
purity. Due to the number of variables and associated interdependencies of
these variables which influence cost, costs of Rectisol systems tend to be
highly case specific.
TABLE B-5. CAPITAL COSTS FOR RECTISOL ACID GAS REMOVAL UNITS
Selective
Nonselective
Dry
Feed Gas,
kmol/hr
6,100
96.384
52,786
57,574
Total
Pressure,
MPa
7.8
2.9
2.8
2.8
COz,
vol %
35
28.9
31.4
34.2
HzS,
vol %
0.25
0.25
0.135
0.13
Capital
Cost, ilO<
(adj. to
1980 basis)
13.5*
150.6
91. 8C
81. 9C
Reference
24
25
23
22
The feed gas to this unit does not contain heavy hydrocarbons. Cost includes
refrigeration unit, erection, and plant startup. This is the same unit which
is identified as Plant 5 in Table B-6.
Data are based upon a conceptual design cost estimate. Details of the cost
estimate are not available. The feed gas to this unit does not contain heavy
hydrocarbons.
Data are based upon a conceptual design cost estimate. The feed gas to this
unit contains heavy hydrocarbons. Reported cost includes naphtha and methanol
recovery and erection. It is not specified whether the costs for a
refrigeration unit and unit startup are included.
B-27
-------
TABLE B-6. UTILITY REQUIREMENTS FOR RECTISOL ACID GAS REMOVAL UNITS
Uf
I
NJ
00
Selective Rectisol8
Flow Rate, kmol/hr
Pressure, MPa
Electric Power, kWh/kmol
Low Pressure Steam, MJ/kmol
Cooling Water, MJ/bnol
Stripping Nitrogen, kmol/kmol
Makeup Methanol, kg/kmol
Refrigeration, MJ/kmol
(at 227 to 235 K)
Plant 1
3692-3992
3.2-3.3
0.14-0.15
5.14-5.54
1.20-1.42
0.067-0.072
0.0085-0.0092
2.09-2.29
Plant 2
6112
7.3
0.31
3.44
6.43
0.031
0.0057
Included
above in power
and cooling
water
Plant 3
7112
3.0
0.18
4.16
1.92
0.048
0.012
1.90
Plant 4
6350
3.3
0.57
5.09
9.52
0.067
0.0079
Included
above in power
and cooling
water
Plant 5
6100
7.8
0.168
2.77
1.91
0.043
0.007
1.24
Non-Selective
Rectisol
Plant 6
16993
2.6
No data
3.27
0.682
No data
0.013
No data
aPlant 1 is a refinery producing hydrogen by partial oxidation of oil; shift conversion occurs prior to acid gas removal (2,6).
Refer to Table B-l for performance data.
Plant 2 produces ammonia synthesis gas from crude hydrogen generated by partial oxidation; shift conversion occurs prior to
acid gas removal (3). Utility requirements reflect the use of compression refrigeration. Refer to Table B-l for performance
data.
Plant 3 produces ammonia synthesis gas by coal gasification; shift conversion follows hydrogen sulfide removal but precedes
carbon dioxide removal (2,6). After sulfur removal the gas is increased from 3 MPa to 5 MPa by compression; the additional
power required for compression is not included in the tabulated electric power requirement. Tabulated data are based on gas
flow rate after shift conversion. Refer to Figure B-3 for process flow diagram, and to Table B-l for performance data.
Plant 4 uses a Rectisol unit for purification of hydrogen from partial oxidation of heavy crnde oil; shift conversion occurs
prior to acid gas removal (3).
Plant 5 produces ammonia synthesis gas by partial oxidation of oil; shift conversion occurs prior to acid gas removal.
Approximately 62% of the incoming carbon dioxide is provided as a carbon dioxide fraction containing less than 1.5 ppmv sulfur
for urea production (24).
Plant 6 is the SASOL coal gasification facility (17). Refer to Figure B-5 for process flow diagram, and Table B-3 for
performance data.
-------
Appendix B
Rectisol Process
B.7 REFERENCES
1. Kohl, A. and F. Reisenfeld. Gas Purification. Gulf Publishing Co.,
Houston, Texas, 1974.
2. Ranke, G. Acid Gas Separation by Rectisol in SNG Processes. Linde AG,
Munich, Germany. Copy of presentation obtained through Letepro
Corporation, New York, N.Y.
3. Scholz, tf.H. Rectisol: A Low-Temperature Scrubbing Process for Gas
Purification, Advances in Cryogenic Engineering, Vol. 15, 1969.
4. Maddox, R.S. Gas and Liquid Sweetening, Campbell Petroleum Series, 1974.
5. Zee, C.A., J. Clausen, and K.W. Crawford. Environmental Assessment:
Source Test and Evaluation Report, Koppers-Totzek Process. EPA-600/7-81
009. January 1981.
6. Lotepro Corporation brochure.
7. Lee, K.W. , W.S. Seames, R.V. Collings, K.J. Bombaugh, andG.C. Page.
Environmental Assessment: Source Test and Evaluation Report - Lurgi
(Kosovo) Medium-Btu Gasification, Final Report EPA-600/7-81-142.
August 1981.
8. Salja, B. and M. Mitrovic. Environmental and Engineering Evaluation of
the Kosovo Coal Gasification Plant, Yugoslavia. Symposium Proceedings:
Environmental Aspects of Fuel Conversion Technology, III, September 1977,
Hollywood, Florida. EPA-600/7-78-063. April 1978.
9. Beychok, M.R. and W.J, Rhodes. Comparison of Environmental Design
Aspects of Some Lurgi-Based Synfuels Plants. Symposium of Environmental
Aspects of Fuel Conversion Technology, Denver, Colorado, October 26-30,
1981.
10. Trials of American Coals in a Lurgi Gasifier at Westfield, Scotland.
Woodall-Duckman, Ltd., Sussex, England. ERDA RSD Report No. 105, 1974.
11. Cameron Synthetic Fuels Report. Rocky Mountain Division, The Pace
Company Consultants fi Engineers, Inc. Volume 18-Number 4, December 1981.
12. Sinor, J.E. Evaluation of Background Data Relative to New Source
Performance Standards for Lurgi Gasification. Cameron Engineers, Inc.
EPA-600/7-77-057, June 1977.
B-29
-------
Appendix B
Rectisol Process
13. Final Environmental Impact Statement: Great Plains Gasification Project,
Mercer County, North Dakota. Vol. I U.S. Department of Energy,
Washington, D.C. August 1980.
14. Hochgesand, G. Rectisol and Purisol. Industrial and Engineering
Chemistry, Vol. 62, No. 7. July 1970.
15. Fleming, O.K. Acid Gas Removal Systems in Coal Gasification. Ammonia
from Coal Symposium. Tennessee Valley Authority. May 8-10, 1979.
16. Engelbrecht, A.D. and L.J. Partridge. 'Operating Experience on a 1000-
ton/day Ammonia Plant at Modderfontein. Ammonia from Coal Symposium.
Tennessee Valley Authority. May 8-10, 1979.
17. Control of Emissions from Lurgi Coal Gasification Plants. U.S.
Environmental Protection Agency, Emission Standards and Engineering
Division. EPA-450/2-78—12 (OAQPS No. 1.2-093). March 1978.
18. Bombaugh, K.J. and V/.E. Corbett. Kosovo Gasification Test Program
Results - Part II, Data Analysis and Interpretation. Symposium on
Environmental Aspects of Fuel Conversion Technology, IV. Hollywood,
Florida. April 17-20, 1979.
19. Data provided to EPA's Industrial Environmental Research Laboratory,
Research Triangle Park, N.C. by South African Coal, Oil and Gas Ltd.
(SASOL). November 1974.
20. Final Environmental Impact Statement. Western Gasification Company
(WESCO) Coal Gasification Project and Expansion of Navajo Mine by Utah
International Inc., New Mexico. U.S. Department of the Interior-Bureau
of Reclamation, Vol. I, II. January 14, 1976.
21. Review comments provided to TRW by Linde AG, April, 1982.
22. Wham, R.M., J.F. Fisher, R.C. Forrester III, A.R. Irvine, R. Salmon,
S.P.N. Singh and W.C. Ulrich. Liquefaction Technology Assessment - Phase
I: Indirect Liquefaction of Coal to Methanol and Gasoline Using
Available Technology. ORNL-5664. Oak Ridge National Laboratory, Oak
Ridge, Tenn. February 1981.
23. Schreiner, Max. Research Guidance Studies to Assess Gasoline from Coal
by Methanol-to-Gasoline and Sasol-Type Fischer-Tropsch Technologies.
Mobil Research and Development Corporation, FE-2447-13. August 1978.
24. Information provided to TRW by Lotepro Corporation, January 1983.
25. Conceptual Design of a Coal to Methanol Commercial Plant. Volume IVA,
Badger Plants Incorporated, Cambridge, Mass. FE-2416-35 (Vol. 4A).
B-30
-------
APPENDIX C
COSTING METHODOLOGY AND BASE PLANT COSTS
C-l
-------
APPENDIX C
COSTING METHODOLOGY AND BASE PLANT COSTS
In order to provide an indication of the economic impact of pollution
controls, capital investment and total annualized cost estimates were devel-
oped for uncontrolled Lurgi-based facilities and applicable pollution control
processes. These estimates are based primarily on factored estimates of costs
contained in nonproprietary published literature. As such, they should be
viewed only as general indicators of expected costs and should not be con-
strued as definitive cost estimates for a specific plant. All costs have been
updated to a first quarter 1980 dollar basis using generally accepted cost
indexes such as the Chemical Engineering (CE) plant index.
The same methodology was used to develop capital and total annualized
cost estimates for the base plants and pollution controls. Details of these
methodologies are presented in Sections C.I and C.2, respectively. The bases
for the base plant cost estimates are presented in Section C.3. Bases for the
pollution control cost estimates are presented in the PCTM Pollution Control
Technology Appendices for Pollution Control Technical Manuals.
There are three general factors that lead to uncertainties in the cost
estimates developed for this PCTM. These are related to the assumptions used
to develop material and energy balances, the level of accuracy of the pub-
lished cost data used, and the general methodology used to apply the acquired
cost data to the processes addressed in this document.
Material and energy balances were derived mainly from 1) commercial syn-
fuels tests and synfuels pilot plant studies, 2) data from analog industries,
C-2
-------
Appendix C
Costing Methodology
and 3) engineering calculations, as described in Section 3 and Appendices A
and B. The level of accuracy in specifying the flow rates and quality of
input streams to controls will affect the accuracy of the resulting pollution
control cost estimates.
Sources of cost data used in this document are published costs for pro-
cesses applied to similar streams in related industries, costs from published
design studies for coal gasification plants, and vendor quotes. The accuracy
of cost data taken from published sources is influenced by the details of the
design upon which the cost was based and the cost methodology used. In addi-
tion, the accuracy of the published estimates and definition of the components
included in these estimates (e.g., contingency reserves, working capital,
land) are not always specified in the reference. Thus, extrapolation of pub-
lished costs will introduce uncertainties in the resulting estimates.
The general costing methodology used in this manual (described in this
appendix) also introduces some uncertainties. Other estimators may choose to
use different factors for components such as direct and indirect installation
costs and interest during construction. In addition, available cost estimates
were adjusted to a 1st quarter 1980 basis using chemical process construction
escalation indices. It is therefore possible that recent advances in the
state-of-the-art are not reflected in some of the resulting cost estimates.
As a result of the above influences, the accuracy of the cost information
presented will vary. However, the cost information presented is believed to
be adequate for the use intended.
C.I CAPITAL COSTS ESTIMATING METHODOLOGY
Capital costs presented in the Lurgi-based PCTM are total depreciable in-
vestments (TDI). TDI includes:
C-3
-------
Appendix C
Costing Methodology
1) purchased and delivered equipment costs;
2) labor and materials costs to install the equipment;
3) indirect installation charges; such as
• engineering and construction costs,
• contractor fees, and
• project and process contingency reserves, and
4) interest expenses on capital spent prior to start of
operation (interest during construction)
It should be noted that the total depreciable investments presented do not
include startup costs. This item could be a significant additional cost for
new technologies such as those examined in this PCTM.
A variety of methods can be used to estimate the above cost items,
although many methods utilize a factored approach. In factored cost
estimates, the costs of purchased and delivered equipment is obtained from
vendor quotes or estimated from previous projects using similar equipment.
The remaining cost items are then estimated using a "factor" times the
purchased and delivered equipment costs or other subsequently derived
subtotal. These factors are generally derived based on historical trends.
For the cost estimates developed for this PCTM, the major source of cost
information was the open literature although some vendor quotes were used. In
general, literature cost information is not reported as purchased and
delivered equipment costs. Some published data are installed equipment costs
(purchased equipment plus direct installation costs), some also include one or
more of the indirect installation charges listed previously, some are TDI
estimates, and others are total capital requirements (TDI plus working capital
and land costs).
In order to provide consistency in the various capital cost estimates
developed for the PCTM, a capital cost methodology was developed. The method-
ology (and cost factors) used are summarized in Table C-l. Most cost data
obtained from the literature were installed equipment costs (IEC). As
C-4
-------
Appendix C
Costing Methodology
indicated in the table, indirect installation charges were estimated as 48% of
the IEC. Adding the indirect installation charges to the IEC yields the total
plant (or process) costs. Interest during construction was estimated as 22.6%
of the total plant costs. Summing these two terms gave the TDI.
The methodology and factors shown in Table C-l also allowed TDI estimates
to be made when costs other than IEC were reported in the literature. As an
example, assume literature data equivalent to the total plant cost item listed
in Table C-l, but not including contingency, were available. To estimate
contingency costs, the reported data would first be adjusted back to IEC by di-
viding by 1.28. Total plant costs (as used in the PCTM) would then be esti-
mated by multiplying the calculated IEC by 1.48. This value would then be
multiplied by 1.226 to get TDI.
The factors indicated in Table C-l were selected based on an evaluation
of a variety of cost factors reported in the open literature (1,2,3,4). The
factor for interest during construction is based on an assumed average spend-
ing period of 1.88 years (5) and an interest rate of 12 percent.
TABLE C-l. CAPITAL COST ESTIMATING METHOD
Installed Equipment Costs (IEC)
Indirect Installation Costs (IIC)
Engineering and Construction (25% of IEC)
Fees (3% of IEC)
Contingency (20% of IEC)
Total Plant Costs (IEC + IIC = TPC)
Interest During Construction (IDC) (22.6% of TPC)
Total Depreciable Investment (TPC + IDC = TDI)a
Working Capital (WC) (value of sixty days of coal)
Land
Total Capital Requirement (TDI + WC + Land)
value used throughout PCTM as capital cost.
C-5
-------
Appendix C
Costing Methodology
C.2 ANNUALIZED COST ESTIMATING METHODOLOGY
Annualized costs consist of annual operating expenses plus annualized
capital-related charges. Annual operating expenses include costs for labor
(operating, supervision, and maintenance labor), raw materials, chemicals,
catalysts, utilities (steam, electricity, cooling water, etc.), and overhead.
Capital-related charges include interest on working capital, local taxes,
insurance, depreciation, income taxes, and return-on-investment. The unit
costs or factors used to estimate total annualized costs in this PCTM are
listed in Table C-2.
All of terms listed in Table C-2, except capital recovery, are expressed
in first year costs, i.e., in constant first quarter 1980 dollars. The capi-
tal recovery term, however, is a levelized value calculated using present
worth and levelized cost procedures and the economic assumptions listed in
Table C-3.
C.3 BASE PLANT COSTS
Capital and total annualized cost estimates were developed for the base
plants examined. Base plant in this PCTM refers to a Lurgi-based synfuel
plant with full production capabilities but without pollution control devices.
The cost estimates were developed from information found in the open litera-
ture, adjusted to the bases used in this PCTM. Specifically, the literature
data were 1) adjusted to delete the cost of pollution controls (to the extent
those costs could be identified), 2) scaled to the plant capacities examined
in the PCTM, and 3) adjusted to reflect first quarter 1980 dollars.
C-6
-------
TABLE C-2. UNIT COSTS AND FACTORS FOR ANNUALIZED COST ESTIMATES
Operating Labor (Jll/hr)
Supervision (15% of operating labor)
Maintenance (2% of total depreciable investment)
Maintenance Supervision (5% of maintenance)
Raw Materials
Coal
Rosebud (Jl3.86/Mg)
Illinois No. 6 (i35.44/Mg)
Dunn County Lignite ($14.70/Mg)
Water (i0.036/m3)
Utilities
Steam ($3.70 to $8.20/Mg depending on quality)
Electricity ($0.033/kW-hr)
Fuel gas (*1.79/GJ)
Cooling water (i0.08/mj)
Boiler feed water ($0.264/mJ)
Chemicals and Catalysts
Overhead Charges
Plant overhead (50% of operating labor)
General and administrative overhead (15% of operating labor and
maintenance)
Laboratory Charges (5% of operating labor)
Byproduct Credits
Ammonia ($140/Mg)
Phenols ($22.20/Mg)
Capital-Related Charges
Interest on working capital (12% of working capital)
Local taxes and insurance (3.5% of total depreciable investment)
Capital recovery (including income taxes, depreciation, and
return-on-investment) (13.7% of total depreciable investment)
TOTAL ANNUALIZED COSTS (summation of above items)
All units costs are on a first quarter 1980 basis.
TABLE C-3. ASSUMPTIONS USED TO CALCULATE CAPITAL RECOVERY FACTOR
Financing basis
Desired after tax return on
investment
Income tax rate
Economic facility life
Facility life for
depreciation purposes
Depreciation method
Investment tax credit
100% equity
12% of total depreciable
investment (TDI)
48% of taxable income
20 years
16 years
sum-of-the-years-digits
20% of TDI
C-7
-------
Appendix C
Costing Methodology
C.3.1 Base Plant Capital Costs
The major source of cost data for the Lurgi-based methanol, Mobil M-
gasoline, and Fischer-Tropsch plants is an engineering study performed by the
Mobil Research and Development Corporation (6). The plant capacities examined
in this manual are approximately 35 percent of the capacities examined in this
report. After the identifiable pollution control costs were substracted from
the installed equipment costs (IEC) reported in Reference 6, the lECs were
adjusted to the PCTM capacities by multiplying by 0.432. This factor equals
0.35 raised to the 0.8 power.
The resulting adjusted installed equipment costs were then converted into
total depreciable investment (TDI) costs using the methodology outline earlier
in Section C.I of this appendix. Finally, the TDI costs were escalated to
first quarter 1980 dollars using chemical engineering plant indices.
The Mobil report did not address the production of SNG as the only plant
product. In order to estimate capital costs for SNG plants, estimates from
the Mobil report for the nonsynthesis-related parts of the plant were combined
with estimates for SNG production equipment from a separate engineering study
(7). These combined values were then subjected to the same methodology
described above for the non-SNG plants. Table C-4 summarizes the calcula-
tional steps used to estimate the base plant TDIs.
C.3.2 Base Plant Annualized Costs
Annual operating expenses and capital-related annualized charges were
calculated for the base plant using the methodology and factors presented in
Section C.2. Required inputs for that methodology are operating labor re-
quirements, coal and raw water usage, chemical and catalyst requirements, an
estimate of working capital, and total depreciable investment. Operating
-------
TABLE C-4. BASE PLANT CAPITAL COST ESTIMATES
n
Installed equipment costs (IEC)&
IEC minus Pollution control costsa
Scaled to PCTM capacity0
Total depreciable investment
(TDI) (10/77 *)
TDI (1980 J)e>f
Me thanol
990.9
847
365.9
663.7
821.6
Mobil
1083.9
940
1406.1
736.6
912.0
F-T
1186.1
1012.2
437.3
793.2
982.1
SNG
b
360.2
653.4
808.8
Reference 6.
Based on methanol synthesis plant minus methanol synthesis and SNG coproduction
cunits (from Reference 6) plus SNG production costs from Reference 7.
dScaling factor used (0.432) was ratio of plant capacities raised to the 0.8 power.
eTDI was calculated by multiplying installed equipment costs, as adjusted, by 1.81.
fFactor used to escalate 10/77 costs to first quarter 1980 dollars was 1.24.
Original cost data were for gasifying a subbituminous coal. Cost estimates developed
from these data were assumed to be approximately true for other coals also.
All costs are millions of dollars.
-------
Appendix C
Costing Methodology
labor and chemicals and catalysts costs were based on values given in the
Mobil report (6). Raw water usage was assumed to be approximately 7600
m'/day in all instances and had negligible impact on the annualized cost
estimates. Coal usage was obtained from material flows developed for the base
plants (see Appendix E). Working capital was estimated as equal to the cost
of 60 days of coal. A 90 percent annual operating factor was assumed in
developing the annualized cost estimates. Table C-5 summarizes the inputs
used to develop the base plant annualized costs, while Table C-6 summarizes
the annualized costs developed.
C-10
-------
TABLE C-5. INUPTS USED TO ESTIMATE BASE PLANT ANNUALIZED COSTS
o
Operating Labor, people
Raw Water, m3 /day
Coal, Mg/day
Rosebud
Illinois No. 6
Lignite
Chemicals and Catalysts, 10*J/yr
Working Capital, 10«$
Rosebud coal cases
Illinois No. 6 coal cases
Lignite cases
Total depreciable investment, 10'i
Me thanol
128
7,600
7,110
5,800
9,590
1.6
5.4
11.4
7.7
822
Mobil
139
7,600
7,110
5,800
9,590
1.8
5.4
11.4
7.7
912
F-T
206
7,600
7,110
5,800
9,590
1.3
5.4
11.4
7.7
982
SNG
128
7,600
7,110
5,800
9,590
1.6
5.4
11.4
7.7
809
From data in Reference 6.
Based on value of 60 days of coal.
All costs are first quarter 1980 dollars.
-------
TABLE C-6. BASE PLANT ANNUALIZED COST ESTIMATES
Type of
Synfuel
Facility
Total Annualized Costs, 10'j/yr
Subbiluminous Coal
(Montana Rosebud)
Bituminous Coal
(Illinois No. 6)
Lignite
(Dunn County, ND)
SNG
199
235
213
Methanol
201
238
215
Mobil M
220
256
234
Fischer- Tropsch
236
272
250
C-12
-------
Appendix C
Costing Methodology
C.4 REFERENCES
1. Guthrie, Kenneth M. Process Plant Estimating Evaluation and Control.
Craftsman Book Company of America, Solana Beach, California, 1974.
ISBN 0-910460-5-1.
2. PEDCo Environmental, Inc. Cost Analysis Manual for Standards Support
Document. Cincinnati, Ohio, April 1979. (Appendix G in: Contractor
Procedures Manual for Development of National Emission Standards, U.S.
Environmental Protection Agency, Office of Air Quality Planning and
Standards, Research Triangle Park, North Carolina, October 1978.
3. Peters, Max S,, and Klaus D. Timmerhaus. Plant Design and Economics for
Chemical Engineers. McGraw-Hill Book Co., New York, 1968. ISBN
07-049579-3.
4. Dhl, Vincent W. A Standard Procedure for Cost Analysis of Pollution
Control Operations. 2 vols. U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, EPA-600/8-79-018a and b, June
1979. PB80-108038; PB80-108046.
5. Federal Power Commission. Synthetic Gas - Coal Task Force, Final Report.
The Supply-Technical Advisory Task Force - Synthetic Gas-Coal.
Washington, D.C., 1973.
6. Schreiner, Max. Research Guidance Studies to Assess Gasoline from Coal
by Methanol-to-Gasoline and SASOL-type Fischer-Tropsch Technologies.
Mobil Research and Development Corporation, Princeton, New Jersey,
August 1978. NTIS No. FE-2447-13.
7. Detman, Roger. Factored Estimates for Western Coal Commerical Concepts.
Interim Report. C.F. Braun & Co., Alhambra, California, October 1976.
NTIS No. FE-2240-5.
C-13
-------
-------
APPENDIX D
THE FATE OF TRACE ELEMENTS IN LDRGI GASIFICATION SYSTEMS
D-l
-------
APPENDIX D
THE FATE OF TRACE ELEMENTS IN LURGI GASIFICATION SYSTEMS
Coals, like other sedimentary rocks, contain small amounts of a wide var-
iety of elements derived from both the parent organic material and from inor-
ganic minerals codeposited with or subsequently introduced in the original
organic matrix. When coal is gasified, volatile elements such as Se, Hg, and
the halogens are partially or totally converted to gaseous compounds. Nonvol-
atile elements (e.g., Cd, Zn) may also be present in raw gases as compounds of
entrained dust or organic aerosols. Cooling and wet scrubbing of raw gases
results in the condensation or physical removal of most of the trace element
loading. From an environmental standpoint, trace elements are of concern when
they leave the Lurgi system as potentially mobil or bioavailable constituents
of waste streams. The primary streams which are of concern are 1) cooled syn-
thesis gases and Rectisol acid gases, 2) gas liquors, 3) Lurgi ash leachates,
and 4) flue gases and/or wastes from combustion of (or alternate processing
of) byproduct tars and oils.
There is currently a modest body of data upon which material balances
around Lurgi gasification systems for specific elements can be based. This
data is based upon gasification tests for several American and foreign coals:
• Dunn/Mercer County (N.D.) lignite at Sasol (1,2),
• Rosebud (Montana) snbbituminous coal at Westfield (3),
• Illinois No. 5 and No. 6 coals at Westfield (4),
• South African coal at Sasol (5), and
• Yugoslavian lignite at Kosovo (6).
Reports from several of these tests (Dunn/Mercer County, Sasol, and Kosovo)
include trace element and flow rate data for all of the major feed and waste
streams, allowing mass balance calculations to be made. The Illinois Nos. 5
and 6 reports include data only for the feed coal and ash, while the Rosebud
D-2
-------
Appendix D
Trace Elements
report includes data for the feed coal, ash, and liquor streams. The Rosebud
report presents two sets of analyses of the coal and ash streams, which for
most elements were considerably different. Sets of values that constituted
the worst case for each element in terms of percent found in the ash were
chosen for determining the estimated distributions.
Tables D-l through D-7 summarize, for each of the seven coals tested, the
concentrations of twenty elements of environmental concern in the input coal,
the concentration and percent of the input element in the ash, oil, tar, and
liquor streams, and the total percentage recovery. Table D-8 summarizes the
minimum and maximum concentrations found in each stream, while Table D-9 lists
the minimum and maximum percent recoveries in each stream. Few trends are
evident from this data, primarily due to limitations in the sampling and
analysis of the various streams and the lack of complete sets of data for the
Illinois Nos. 5 and 6, Rosebud, and Mercer County test reports.
Table D-10 summarizes ash leaching data for various coals expressed as
microgram trace element leached per gram ash. It is important to note that
the various leaching studies used different leaching conditions. Leaching
studies are influenced by four principal variables: 1) the duration of the
leaching period, 2) the type of system used (e.g., batch or flow through
columns), 3) the liquid to solid ratio, and 4) the experimental parameters
controlled (e.g., temperature, pH, and aerobic or anaerobic conditions).
Yu subjected ashes from the gasifications of Rosebud, Illinois No. 5, and
Illinois No. 6 coals in the Westfield Lurgi gasification facility to the RCRA
Extraction Procedure (7). The RCRA Extraction Procedure is designed to rough-
ly approximate the extraction of soluble material with rainwater. The solid
is extracted with a sixteen-fold excess of leaching solution at a pH of 5.0
for a 24-hour time period at room temperature. Following the extraction pe-
riod, the sample is diluted to an aqueous volume of 20 times the sample weight
D-3
-------
Appendix D
Trace Elements
and then filtered to separate the liquid and solid phases. The extract is
then analyzed for 8 metals and other constituents which are listed in the
Extraction Procedure.
Shriner performed two different types of leaching tests on the ash res-
ulting from gasification of Rosebud, Illinois No. 5, and Illinois No. 6 coals
in the Westfield Lurgi gasifier (8). Batch leaching tests attempted to simu-
late the conditions of natural flooding and thus the maximum dissolution of
soluble constituents. Column leaching tests attempted to simulate the move-
ment of rainwater percolate through a landfill. In the batch leaching tests,
25 g of ash and 250 ml of deionized water (pH 5.55) were shaken for 24 hours,
decanted, filtered, shaken again for 24 hours, and filtered. In the column
leaching tests, approximately 40 g of air-dried, unsieved Lurgi waste were
added to glass tubes 7.5 cm in diameter and 46 cm long. Leachate quantities
of approximately 80 ml, 80 ml, and 160 ml were collected for Rosebud, Illinois
No. 5, and Illinois No. 6 gasifier ash, respectively, under falling head con-
ditions at flow rates of 0.5 to 2.0 ml of deionized water per minute.
Griffin studied the leaching characteristics of ash obtained from the
gasification of Rosebud, Illinois No. 5, and Illinois No. 6 coals in the
Westfield Lurgi gasifier (9). Leachates were generated at 4 pH levels and
under two different gas atmospheres. Large-volume, static leaching tests were
used. The ash was initially ground to 28 mesh. Slurries of 1 part ash and 10
parts distilled water were placed in 2-1/2 and 5-gallon glass carboys. Over a
period of 3 to 6 months the slurries were stirred daily and their pH moni-
tored or readjusted when necessary to a specified value.
Somerville reported leaching characteristics of ash obtained from the
gasification of Mercer County coal in the Lurgi Gasifier at SASOL (10). Tha
leaching procedure attempted to maximize the quantity of the element leached.
Ten grams of finely ground ash were added to 50 ml of deionized water (pH
5.55) and refluxed at the boiling point of deionized water for 16 to 24 hours.
D-4
-------
TABLE D-l. CONCENTRATION AND DISTRIBUTION OF TRACE ELEMENTS - DUNN COUNTY LIGNITE (1)
O
Ul
Element
As
B
Be
Cd
Co
Cr
Cn
F
Hg
Hn
Mo
Ni
Pb
Sb
Se
Th
U
V
Zn
Zr
Coal, ppm
8
56
0.27
<1
1.2
5.3
10.6
29.3
0.20
70.7
4
6.7
2.7
0.27
0.40
4
4
21.3
6.7
85.3
Ash
ppm
74
1680
6
0.50
13
140
27
191
0.055
760
12
25
58
4
0.50
45
7
ISO
10
520
%
102
330
244
>5.5
119
291
28
71.7
3
118
33
41
236
163
13.7
124
19.2
77.5
16.4
67.1
Oil
ppm
24
4
0.50
0.90
4
2
5
0.16
0.70
6
2
4
0.40
0.20
2
1
Tar
%
3.7
0.087
>0.61
0.91
0.92
0.23
0.21
0.98 ,
0.012
1.8
0.36
1.8
1.2
0.011
0.36
0.014
ppm
7
1
<0.10
<0.30
0.60
5
3
51
2.9
11
2
3
14
0.20
1
0.90
3
0.90
10
%
4.9
0.10
<2.1
<1 .7
2.8
5.3
1.6
9.8
81.6
0.88
2.8
2.5
29.2
2.8
1.4
1.3
0.79
0.76
0.66
Liauor
ppm
0.10
0.90
<0.20
0.0010
0.020
0.010
5
0.17
0.030
0.040
0.0060
0.0050
0.0040
0.0010
0.20
0.0080
*
1.9
2.4
<30.1
0.13
0.57
0.14
25.7
128
0.064
1.5
0.13
0.28
1.5
0.0071
4.5
0.014
Total. %
112
333
<247
<38
123
297
30
107
213
119
39
44
268
163
19
125
21
78
22
68
Blanks = no data available.
-------
TABLE D-2. CONCENTRATION AND DISTRIBUTION OF TRACE ELEMENTS -
MERCER COUNTY LIGNITE AT SASOL (2)
O
Element
As
B
Be
Cd
Co
Cr
Cu
F
Hg
Hn
Ho
Ni
Pb
Sb
Se
Th
U
V
Zn
Zr
Coal
ppm
30
300
2
<0.10
2
6
5
24
0.050 <
0.50
3
20
0.10
1
1
1
10
0.60
Ash
ppm
60
>1500
5
<1
10
40
50
230
0.10
4
25
200
1
1.5
6
6
70
0.50
*
13.1
>32.8
16.4
<65.7
32.8
43.8
65.7
63
<13.1
52.6
54.7
65.7
65.7
9.9
39.4
39.4
46
5.5
Oil
opm
1.7
30
0.050
<0.10
0.020
0.60
2
0.060
<0.10
0.020
1.5
0.15
<0.020
<0.010
<1
<1
0.15
0.40
%
0.030
0.053
0.013
<0.53
0.0053
0.053 '
0.21
0.0013
<1.1
0.021
0.26
0.0040
<0.11
<0.0053
<0.53
<0.53
0.0080
0.35
Tar
ppm
2
20
0.10
<0.10
0.050
1
0.10
12
<0.10
0.020
10
1.5
<0.050
0.20
2
5
0.050
6
Lianor
*
0.21
0.21
0.16
<3 .1
0.078
0.52
0.063
1.6
<6.3
0.13
10.4
0.23
<1 .6
0.63
6.3
15.6
0.016
31.3
PPD
3
3
0.0080
<0.030
(0.030
<0.030
0.30
0.50
(0.030
(0.20
(0.20
0.20
(0.030
2
(0.20
0.0030
0.40
t
9.8
0.98
0.39
(29.5
(1.5
(0.49
5.9
2
(59
(39.4
(6.6
0.98
(29.5
197
(19.7
0.030
65.6
Total
23
34
17
(99
(34
(45
72
67
(80
(92
(72
67
(97
(207
(46
(75
46
103
Blanks - no data available.
-------
TABLE D-3.
CONCENTRATION AND DISTRIBUTION OF TRACE ELEMENTS -
SOUTH AFRICAN COAL AT SASOL (5)
Element
As
B
Be
Cd
Co
Ct
Co
F
Hg
MB
Mo
Ni
Pb
Sb
Se
Th
n
V
Zn
Zr
Coal
3.3
100
2.3
<0.10
100
<0.10
500
43.3
16.7
<0.50
367
Ash
DDm
1.7
133
0.037
<0.10
150
0.10
2000
183
50
<0.50
1000
Oil
%
18.5
47.9
0.58
<36
54
>36
144
152
108
<36
98.1
Dt>m
26.3
0.53
0.053
0.27
<0.50
0.12
0.27
1.2
0.73
0.53
0.23
*
3.6
0.0024
0.010
>1.2
< 0.0022
<0.54
0.00024
0.012
0.020
>0.48
2.8E-04
Tar
com
4.1
50
0.80
<0.040
3.2
0.40
2.7
2.7
50
0.90
4.9
%
2
0.82
0.57
<0.66
0.053
>6.6
0.0089
0.10
4.9
>3
0.022
Lianor
com
1.2
3.3
0.040
<0.030
40
<0.030
1.5
0.30
0.40
0.15
0.30
%
38.3
3.5
1.8
<31.6
42.1
<31.6
0.32
0.73
2.5
>31.6
0.086
Total
62
52
3
<69
<96
<75
144
153
115
<71
98
Blanks » no data available.
-------
TABLE D-4.
O
oo
CONCENTRATION AND DISTRIBUTION OF TRACE ELEMENTS -
ROSEBUD COAL AT WESTFIELD (3)
Element
As
B
Be
Cd
Co
Cr
Cu
F
Hg
Mn
Ho
Ni
Pb
Sb
Se
Th
U
V
Zn
Zr
Coal
pom
0.57
32
0.71
0.31
0.55
4.2
8.9
65
0.17
3.4
2.2
14
12
1.5
0.33
0.88
14
8
Ash
ppm
26
380
2.8
2.4
4.3
440
130
600
0.030
790
200
216
56
4.5
2.2
13
91
48
Oil
% Dom %
388
101
33.5
65.8
66.5
890
124
78.5
1.5
1975
773
131
39.7
25.5
56.7
126
55,2
51
Tar Lianor
oom % Dom
0.030
11.6
0.48
0.22
2.8
2.2
41.4
0.12
9.1
6
0.10
0.11
0.29
5.5
4.4
*
7.1
48.9
91.3
95.8
90
33.4
86
95.3
87.7
67.5
9
45
44.5
53
74.2
Total
%
395
150
125
162
67
980
158
164
97
1975
773
219
107
35
102
170
108
125
Blanks = no data available.
-------
TABLE D-5. CONCENTRATION AND DISTRIBUTION OF TRACE ELEMENTS -
ILLINOIS NO. 5 COAL AT WESTFIELD (4)
O
I
Element
As
B
Be
Cd
Co
Cr
Cu
F
Hg
Hn
Ho
Ni
Pb
Sb
Se
Th
D
\
Zn
Zr
Coal
PPD
1.6
307
2.2
<0.30
3.8
15
10
55
o.n
21
7
32
30
0.30
21
182
Ash
oom
0.30
673
22
<0.30
38
592
273
4.6
0.016
338
8
462
219
0.30
181
1580
Oil Tar Liquor
* oom % oom % opm %
1.7
20.2
92
<9.2
92
363
251
0.77
0.87
148
10.5
133
«7.2
9.2
79,3
79.9
Total
*
2
20
92
<9
92
363
251
1
1
148
11
133
67
9
79
80
Blanks = no data available.
-------
TABLE D-6. CONCENTRATION AND DISTRIBUTION OF TRACE ELEMENTS -
ILLINOIS NO. 6 COAL AT WESTFIELD (4)
I
t—'
o
El em
As
B
Be
Cd
Co
Cr
Cu
F
Hg
Mn
Ho
Ni
Pb
Sb
Se
Th
D
V
Zn
Zr
Coal
ODm
1
132
1.5
<0.30
3.2
18.3
12
79
1
20
7
14
12
0.10
1.3
29
43
Ash
Dom
0.10
622
13.4
<0.30
34
806
239
5.2
0.040
243
6
456
96
0.20
301
469
Oil Tar Liauor
% Bom % com % DDB> *
1
47.1
89.3
<10
106
440
199
0.66
0.40
121
8.6
326
80
20
104
109
Total
%
1
47
89
<10
106
440
199
1
<1
121
9
326
80
20
104
109
Blanks - no data available.
-------
TABLE D-7.
CONCENTRATION AND DISTRIBUTION OF TRACE ELEMENTS -
YUGOSLAVIAN LIGNITE AT KOSOVO (6)
Element
As
B
Be
Cd
Co
Cr
Cu
F
Hg
Mn
Mo
Ni
Pb
Sb
Se
Th
U
V
Zn
Zr
Coal
ppm
59
1
4
3.4
87
43
0.74
6.4
150
8.2
NF
20
14
140
Ash
ppm
75
2.5
69
17
180
40
0.3
8.9
320
52
NF
24
100
2.1
%
21
43
297
85
35
16
7
24
36
108
NF
20
123
0.3
Oil
DPD
1.9
NF
0.075
0.19
3.9
1.1
0.2
0.18
NF
1.4
NF
1.8
NF
15
*
0.05
NF
0.03
0.09
0.07
0.04 •
0.4
0.05
NF
0.3
NF
0.2
NF
0.2
Tar
ppm
18
0.1
0.7
NF
3.2
17
NF
NF
9.5
7.2
NF
1.7
0.53
30
Lianor
%
0.7
0.2
0.4
NF
0.09
0.9
NF
NF
0.2
2
NF
0.2
0.09
0.5
ppm
0.1
NF
0.0014
NF
0.023
0.011
0.14
NF
0.013
0.014
NF
0.05
NF
0.28
%
0.1
NF
0.03
NF
0.02
0.02
15
NF
0.01
0.1
NF
0.2
NF
0.2
Total
22
43
297
85
17
17
22
24
36
110
NF
21
123
1
NF = Not found.
Blanks = No data available.
-------
TABLE D-8.
O
I
SUMMARY OF TRACE ELEMENT CONCENTRATIONS IN VARIOUS WASTE STREAMS
FROM LURGI GASIFIERS FOR SEVEN AMERICAN & FOREIGN COALS (1,2,3,4,5,6)
Elememt
Ac
B
Be
Cd
Co
Cr
Cu
F
Hg
tin
Ho
Ni
Pb
Sb
Se
Th
U
V
Zn
Zr
Coal
Min
0.57
32
0.27
<0.10
0.55
4.2
5
24
0.050
3.4
050
3
2.7
NF
0.33
1
0.88
10
0.60
85.3
PPM
Max
59
307
2.3
4
3.8
87
43
100
1
SOO
7
150
30
1.5
20
4
4
367
182
85.3
Ash
Mia
0.10
133
0.037
<0.10
4.3
40
27
4.6
0.016
243
4
25
50
0.20
0.50
6
6
70
0.50
520
PPM
Max
75
1680
22
69
38
806
273
600
0.3
2000
200
462
219
4.5
24
45
13
1000
1580
520
Oil
Min
1.7
0.53
NF
0.075
0.020
0.60
1.1
0.060
<0.10
0.27
0.020
NF
0.15
NF
<0.010
<1
<1
NF
0.40
1
PPM
Max
26.3
30
0.053
0.50
0.90
4
2
5
0.2
0.70
6
2
4
0.53
1.8
<1
<1
0.23
15
1
Tar
Min
2
1
<0.10
<0.04
NF
1
0.10
3.2
NF
2.7
NF
2.7
1.5
NF
0.20
1
0.90
0.050
0.90
10
PPM
Max
18
50
0.8
0^7
0.6
5
17
51
2.9
11
2
10
50
0.9
1.7
2
5
4.9
30
10
Liquor
Min
0.030
0.90
NF
0.0014
NF
0.020
0.010
0.50
<0.030
0.030
NF
0.0060
0.0050
NF
0.0040
NF
0.0010
0.20
0.0080
PPM
Max
3
11.6
0.48
0.22
<0.030
2.8
2.2
41.4
0.17
1.5
<0.20
9.1
6
0.15
2
0.29
5.5
4.4
0.008
NF = Not found.
Blanks » no data available.
-------
TABLE D-9. SUMMARY OF DISTRIBUTION OP TRACE ELEMENTS AMONG WASTE STREAMS FROM
O
I
BlfStBt
At
B
Be
Cd '
Co
Cr
Cu
F
Hi
Mn
No
Ni
Pb
Sb
Se
Th
U
V
Zn
Zr
Coil
Win
0.57
32
0.27
<0.10
0.55
4.2
5
24
0.050
3.4
0.50
3
2.7
NF
0.33
1
0.88
10
0.60
85.3
PPM
Max
59
307
2.3
4
3.8
87
43
100
1
500
7
150
30
1.5
20
4
4
367
182
85.3
AID *
MlB
1
20.2
0.58
>5.5
32.8
35
16
0.66
0.40
118
8.6
36
39.7
NF
9.9
39.4
19.2
46
0.3
67.1
N.I
388
330
244
297
119
890
251
78.5
36
1975
773
326
236
163
56.7
124
126
123
109
67.1
Oil *
Min
0.030
0.0024
NF
0.030
0.0053
0.053
0.040
0.0013 '
0.4
2.4E-04
0.021
NF
0.0040
NF
<0.0053
<0.53
<0.53
NF
0.2
0.014
Max
3.7
0.087
0.013
>1.2
0.91
0.92
0.23
0.21
1.1
0.012
1.8
0.36
1.8
0.48
1.2
0.53
0.53
0.011
0.36
0.014
Tar
Mia
0.21
0.10
0.16
<0.66
NP
0.09
0.063
0.053
NP
0.0089
NF
0.10
0.23
NP
0.2
1.4
1.3
0.016
0.5
0.66
% Liauor %
Max
4.9
0.82
2.1
<3.1
2.8
5.3
1.6
9.8
81.6
0.88
2.8
10.4
29.2
3
2.8
6.3
15.6
0.79
31.3
0.66
Kin
0.1
0.98
NF
0.03
NF
0.02
0.02
2
15
0.064
NF
0.01
0.1
NP
0.20
<19.7
NF
0.16
0.014
Max
38.3
48.9
91.3
95.8
<1.S
90
33.4
86
128
0.32
<39.4
87.7
67.5
)31.6
197
44.5
53.
74.2
0.014
Total %
Mia
1
20.2
3
<9.2
<34.2
39.9
30
0.66
0.40
119
8.6
<39.9
66.9
9.2
19.3
<46.2
20.5 .
46
15.6
67.7
Mas
395
333
<247
307
123
980
251
164
213
1975
773
326
268
163
<207
125
170
<126
125
68
NF = Not found.
Blanks « no data available.
-------
TABLE D-10. LEACHING CHARACTERISTICS OF LUROI ASH
Rosebud
Trace
Element
Ag
As
B
Ba
Be
Cd
Co
Cr
Cn
F
Bg
Mn
No
Ni
Pb
Sb
Se
D
V
Zn
A Denotes
B Denotes
C Denotes
D Denotes
E Denotes
A B
<0.004
(0.030 6.0
18.0
16.6
<0.011 0.006
<0.12
0.092 3.0
(0.008
90
1.1
(0.011 0.08
(0.020
<10
3.2 0.084
batch leaching data
batch leaching data
column leaching data
batch leaching data
column leaching data
C
0.06
0.001
0.04
0.0009
0.517
0.059
0.24
0.13
0.063
from Yn (7)
from Shriner
from Shriner
from Griffin
D
<10.0
512
<1.0
0.8
0.6
2.0
1.4
5.4
3.0
<0.002
265
<0.3
5.0
4.0
13.0
<3.0
15.0
-------
REFERENCES FOR APPENDIX D
1. Sommerville, M.H., J.L. Elder, et al.. An Environmental Assessment of a
250 MM SCFD Dry Ash Lurgi Coal Gasification Facility in Dunn County,
North Dakota. University of North Dakota, Engineering Experiment
Station, Bulletin No. 76-12-EES-01 Volumes I - IV, December 1976.
2. ANG Coal Gasification Company North Dakota Project. Final Environmental
Impact Statement, U.S. Department of the Interior, January 20, 1978.
3. Wyoming Coal Gas Co. and Rochelle Coal Co., Applicants Environmental
Assessment for 2 Proposed Coal Gasification Projects, Campbell and
Converse Counties, Wyoming, October, 1974.
4. Sather, N.F., et al. Potential Trace Element Emissions from the
Gasification of Illinois Coal, Illinois Institute of Environmental
Quality No. 75-08, February 1975.
5. Information supplied by South African Coal, Oil, and Gas Corp. Ltd., to
EPA's Industrial Environmental Research Laboratory, Research Triangle
Park, November 1974.
6. Lee, Kenneth W., et al.. Environmental Assessment: Source Test and
Evaluation Report — Lurgi-Type (Kosovo, Yugoslavia) Medium-Btu
Gasification. Final Report. Radian Corporation, Austin, Texas,
August, 1981.
7. Yu, K.Y. and G.M. Crawford. Characterization of Coal Gasification Ash
Leachate Using the RCRA Extraction Procedure. Paper presented at the
Symposium on Environmental Aspects of Fuel Conversion Technology V,
St. Louis, Missouri, September 16-19, 1980.
D-15
-------
REFERENCES FOR APPENDIX D (Continued)
8. Shriner, D.S., et al. Physical, Chemical, and Ecological
Characterization of Solid Wastes from a Lurgi Gasification Facility. Oak
Ridge National Laboratory, Oak Ridge, TN.
9. Griffin, R.A., et al., 1980. Chemical and Biological Characterization of
Leachates from Coal Solid Wastes. State Geological Survey, Urbana, 111.
98 pp.
10. Somerville, M.H., et al. A Comparison of Trace Element Analyses of North
Dakota Lignite Laboratory Ash with Lurgi Gasifier Ash and their Use in
Environmental Analyses. University of North Dakota, Grand Forks, ND.
D-16
-------
APPENDIX E
MATERIAL BALANCES
E-l
-------
TABLE E-l. CALCULATED MATERIAL PLOTS FOR LDROI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL
€
g
o
3
1
Stream No.
Streaai Hue
Hydrogen
Oxygen
Nitrogen/ Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethylene
Propane
Propylene
Butane
Butyl ene
C5+ Aliphatioa
Benxena
Toluene
'Other aroaiatica
Hydrogen Snlfida
Carbonyl Sulfide
Methyl Mercaptan
Ethyl Heroaptan
C3+ Mercaptana
Hydrogen Cyanide
Aanaonla
Hydrogen Chloride
Hethanol
Total dry gaa
later
Coal (HAF)
Aah
Partlcnlatea
Organic Aeroaola
Tar a
Olli
Phenol a
Fatty Aolda
Other Conatltnenta
Total
1
Rnn-of-NUe
Coal
112,630
298.930
44,350
455,910
21
Coal
Fine a
39,420
104,020
15.530
159,570
2
Prepared
Coal
73,210
194.300
28,830
296,340
3
Steaa
370 , 800
370.800
4
Oxygen
2,270
137
2,407
77,460
5
Raw Lnrgi
Oaa
7,619
39
162
2,806
5,733
2,075
93
13
11
13
7.4
13
*.«
9.7
2.3
1.9
82
1.1
7.2
2.3
0.3
1.2
137
0.4
18.843
293.634
495
5,710
6.181
1,371
604
2,389
709,664
205
Low Preeaure
Coal Lockhopper
Vent Gaa
4.7
0.024
0.10
1.7
3.5
1.3
0.057
0.008
0.004
0.008
0.005
0.008
6.605
0.006
0.001
0.001
6.0 SO
0.0007
0.004
0.001
6.0602
0.0007
0.084
0.0002
11.6
1.7
0.052
1.9
247
I
N5
*Aeamaea Lurfl |aa la oaed aa the lockhopper pretanrant.
Competition ahown exclndea ejection air.
-------
TABLE E-l. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL (Continued)
£
CO
0)
o
CD
.c
o>
j:
Stream No.
Stream Name
Hydrogen
Oxygen
Nitrogen/Argon
Carbon Monoxide
Carbon Dioxide
Methane
Etbane
Ethylene
Propane
Propylene
Butane
Butvlene
C5+ Aliphatic*
Benzene
Toluene
Other aromatics
Hydrogen Snlfide
Ctrbonyl Sulfide
Methyl Mercaptac
Ethyl Mercaptan
C3 + Mercaptant
Hydrogen Cyanide
Anuoonia
Ilvdroeen Chloride
Methanol
Total dry gas
Water
Coal (MAP)
Ash
Particulates
Organic Aerosols
Tars
Oils
Phenols
Fatty Acids
Other Constituents
Total
239
Ash Quench
Makeup Water
13.600
13,600
403
Quenched
Ash
7.700
30,600
38.300
206
Ash Lock
Vent Gas
14.3
0.9
15.2
1,550
3.5
2,043
209
Gas Liquor
Depressurization
Gas
1.1
80
3.6
0.18
0.18
0.93
0.011
0.34
0.2
0.027
0.005
2.0
88.6
85
3.330
111
Tar
426
5,665
6,091
112
Oil
12
6,181
6.193
w
-------
TABLE E-l. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL (Continued)
c.
~S>
0>
0
o>
*
1
Stretn No.
Stream Name
Hydrogen
Oxygen
Nitrogen/ Argon
Cirbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethylene
Propane
Propylene
Butane
Bntylene
C5+ Aliphatict
Benzene
Toluene
Other aroaatics
Hydrogen Sol fide
Cirbonyl Sulfide
Methyl Mercaptan
Ethyl Mercaptan
C3 + Mercaptana
Hydrogen Cyanide
Aanonia
Hydrogen Chloride
Methanol
Total dry gai
later
Coal (MAP)
Aah
Particnlatei
Organic Aerosols
Tara
Oili
Phenol a
Fatty Acids
Other Constituents
Total
210
Gas Liquor
Synthesis Cas<
93.3
0.5(
0.0!
135
292,960
57
45
1,371
604
2.389
303,850
210S
Gas Liquor
s SNG Case
93.3
0.50
6 0.05
135
281,039
57
45
1,371
604
2,389
291.929
10
Quenched Lurgi
Gas- Synthesis
Cases
7,619
39
162
2,805
5,560
2,071
93
13
15
13
7.4
13
8.6
9.7
2.3
1.9
81
1.1
6.9
2.1
0.3
1.1
0.2
0.2
18,526
576
388.868
10S
Quenched
Lurgi Gas-
SNG Case
8.280
39
162
2.146
6,220
2.071
93
13
15
13
7.4
13
8.6
9.7
2.3
1.9
81
0.79
6.9
2.1
0.27
0.73
0.56
0.19
19.188
612
401,597
213
AGR Offgases-
Synthesis Case
23
4
56
4,954
54
53
7.5
15
13
6.6
11.5
0.9
0.53
0.032
80.9
1.1
6.6
1.5
0.54
0.15
8.1
5.298
228,219
213S
AGR Offgases-
: SNO Case
25
4
43
5,772
54
53
7.5
15
13
6.5
11.5
0.9
0.61
0.04
80.9
0.79
6.6
1.5
0.36
0.52
8.4
6.105
263,864
pi
.p-
-------
TABLE E-l. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL (Continued)
r.
•J5
a>
o
6>
^
^>
^
Stream No.
Streaa Nane
Hydrogen
Oxygen
Nitrogen/ Argon
f. rhnn Honn.iri.
Cubon Dioxide
Methane
Ethane
Ethvlene
Propane
Propylene
Butane
Bntvlene
C5+ Aliphatic*
Benzene
Toluene
Other aroBatics
Hydrogen Sol fide
Cirboayl Sulfide
Methyl Mercaptan
Ethvl Mercaotan
C3+ Mercaptani
Hydrogen Cyanide
Aaimonia
Hydrogen Chloride
Me thanol
Total dry gas
Water
Total
216
Methanol/Wat
Still Bottom
Synthetli Cas
0.004
0.007
0.044
0.19
o.on
0.26
9,956
9,965
216S
r Methanol/Wate
Still Bottoms
a SNG Caie
0.004
0.007
0.045
0.19
0.018
0.26
9,972
9,973
114
c By-Product
Lnrgi Naphtha
Synthesis Ca>e
0.8
1.5
7.6
9.2
2.3
1.9
0.1
0.3
0.6
0.27
0.55
25.1
1,876
-
114S
By-Product
Lutgi Naphtha
s SNG Cases
0.9
1.5
7.6
9.1
2.3
1.9
0.1
0.3
0.6
0.27
0.37
24.9
1,872
==_=__=
12
Sulfnr-Free
Synthesis Gas
Synthesis Cases
7,596
39
158
2.749
606
2,017
40
5.5
6.1
13,211
158,451
======
12S
Sulfur-Free
Synthesis Gas
SNG Case
8,255
39
158
2.103
~««
2,017
40
5.5
0.09
13,066
135,516
•
w
Ul
-------
TABLE E-l. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL (Continued)
k.
o
o
o>
1
Stream No.
Stream Name
Hydrogen
Oxygen
Nitrogen/ Argon
Carbon Monoxide
Carbon Dioxide
Methane
Total dry gat
later
Total
228S
Me thana tion
Condenaa te
SNG Synthesis
0.1
0.4
0.5
54,300
54,332
236S
Dehydration
Offgases
SNG Synthesis
204
204
110S
Product SNG
SNG Synthesis
123.7
158
2.1
23.1
4,633.6
4,940.5
10
81.128
M
ON
-------
TABLE E-l. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL (Continued)
r.
o
0
6>
o>
1£
Stroim No.
Stream Nane
Hydrogen
Oxygen
Nitrogen/Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethjrlene
Hethanol
Ethanol
Propanol
Acetone
Water
Total
117 ME
Methanol
MeOH Synthesit
0.04
0.01
0.03
5.7
1.1
0.25
2.796
0.92
0.01
1.6
88
90,080
237 ME
Wastevater
MeOH Synthesii
1.6
0 .0004
0.57
5,202
5,289
18 HE
Me thana tion
MeOH Synthesii
1,608
158
190
310
2,016
39.7
5.5
41.9
0.009
0.000
0.88
10
61,680
228 ME
M th nation
Condensa te
MeOH Synthesis
0.05
0.2
20,180
20.185
231 ME
Offgas
MeOH Synthesii
0.1
0.14
0.001
69.6
2.4
78
3,180
236 ME
Of fgaset
MeOH Synthesii
329
329
110 ME
Coproduct SNG
MeOH Synthesis
80.5
158
0.95
3.2
2,521
—4
46,198
-------
TABLE E-l. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL (Continued)
.c
n
0>
0
6>
«_
1
Strom No.
Stream Name
Hydrogen
Oxygen
Nitrogen/ Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethylene
Propane
Propylene
Butane
Butylene
C5 + Aliphatica
Methanol
Ethanol
Propanol
Acetone
Organic Acids
Total dry gat
Water
Total
18 MM
Purge & Expansion
Gas to Methanatio
1,608
158
190
310
2. OK
40
5.5
41.9
0.009
0.0007
0.88
4,370
10
(1,680
107 MM
Crude
> Methinol
0.05
0.02
0.03
6.7
1.3
0.3
2,799
0.9
0.6
1.6
5.298
95.430
225 MM
Mobil M
0.02
1.2
0.6
3.6
4.8
55,450
55,990
226 MM
Fractionation
Offgas to CO,
0.7
0.01
0.3
6.3
19
5.3
0.5
2.0
0.1
1.5
0.1
0.4
36
35
1,022
228 MM
Methanation
Condensat e
0.05
0.16
20,180
20,185
231 MM
CO, Removal
Offgas
0.1
P. 15
0.001
75.8
2.6
0.005
0.0005
85
3,458
236 MM
Dehydr a tion
Of f gases
332
332
w
CO
-------
TABLE E-l. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL (Continued)
c.
0)
-------
TABLE E-l. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL (Continued)
.c
0>
0
en
k.
B>
je
Stream No.
Stream Nune
Hydrogen
Nitrogen/ Argon
Carbon Monoxide
Carbon Dioxide
Me thane
Ethane
Ethylene
Propane
Propylene
Butane
Bntylene
Pentane
Pentene
C7+ Aliphatici
Acetone
Total dry gas
later
Total
14 FT
Methanation
F-T Caae
1,363
155
84
310
2,129
53
30
0.8
4,126
59,760
219 FT
* t t F
Alcohol Recove
F-T Caae
13.6
75,900
76,720
220 FT
F
y Offgasea to
CO, Reaioval
8.2
2.6
1.6
160
161
68
31
2.9
30
0.006
0.04
0.002
0.006
0.1
466
332
14.390
228 FT
Condensa te
F-T Case
0.04
0.14
18,300
18,304
238 FT
C0a Removal
F-T Case
358
358
231 FT
Offgaa
F-T Case
0.3
0.4
0.006
219
"7:-!
0.2
0.08
0.008
0.08
•
~~m
247
10,040
236 FT
Offgas
F-T Case
375
375
I
M
O
-------
TABLE E-l. CALCULATED MATERIAL FLOWS FOR LBRGI-BASED SYNTHETIC FUELS FACILITIES - ROSEBUD COAL (Continued)
ji|/se|ouj-S>|
B>
J£
Strean No.
StreaB Nane
Hydrogen
Nitrogen/Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethylene
Propane
Propylene
Butane
Butylene
Pentane
Pentene
C7+ Aliphatica
Total dry fas
later
Total
110 FT
Co-product
SNG
F-T Caie
89
157
2
14
2,766
68
31
3
30
0.006
0.04
0.002
0.006
0.1
3,160
5
53.930
100 FT
Blended
Gasol ine
F-T Ca»e
19.660
101 FT
Diesel Oil
F-T Case
3.986
102 FT
Heavy Fuel
Oil
F-T Cafe
1,167
105 FT
Mixed Alcohols
F-T Case
3,380
106 FT
C, LPO
F-T Case
1.284
106 FT
C4 LPG
F-T Case
195
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL
kg-moles/hr
I
J£
Stream No.
Stream Name
Hydrogen
Oxygen
Nitrogen/Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethylene
Propane
Propylene
Butane
Butvlene
C5+ Aliphatics
Benzene
Toluene
Other aroma tic«
Hydrogen Sulflde
Carbonyl Sulflde
Methyl Nercaptan
Ethyl Hercaptan
C3+ Mercaptans
Hydrogen Cyanide
ADnonia
Hydronen Chloride
Methanol
Total dry gaa
Water
Coal (MAP)
Ash
Particulatea
Organic Aerosols
Tars
Oils
Phenols
Fatty Ac Ida
Other Constituents
Total
1
Run-of-Mine
Cod
35.830
282,570
31,890
350,290
21
Coal
Fines
11,110
87,600
9.880
108.590
2
Prepared
Coal
24,720
194,970
22,010
241,700
3
Steam
607,070 .
607.070
4
Oxygen
3.430
208
3,638
117,040
5
Raw Lurgi
Gas
7,455
21
238
1,al9
6,272
1.874
98.4
14.4
16
14
7.8
14
3.7
16
3.6
2
181
2.2
15.7
S.I
0.67
1.2
146.7
1.6
19,824
497,621
579
7.427
696
1.152
192
1.480
952,630
205"
Low Pressure
Coal Lockhopper
Vent Gas
3.5
0.01
0.11
1 (.
3.0
0.9
0.047
0.007
0.008
0.007
0.004
0.007
0.002
0.008
0.002
o.noi
0.086
0.001
0.007
0.002
0.0003
0.001
0.07
0.001
9.4
1.4
0.042
1.5
213
W
I
'Assumes Lurgi gas is used as the lockhopper pressuraut.
Composition shown excludes ejection air.
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL (Continued)
kg-moles/hr ••
.n
^>
^
Stream No.
Stream Naae
Hydrogen
Oxygen
Nitrogen/Argon
'arbon Monoxide
Carbon Dioxide
le thane
Uhane
ithy lene
Propane
'ropy lene
tutane
Buty lene
U5+ Aliphatic*
Benz ene
Toluene
Other aromatic!
Hydrogen Sol tide
Carbonyl Snlfide
Methyl Uercaptan
Ethyl Mercaptan
u + Hercaptans
rydrogen Cyanide
Ammoni a
Hydrogen Chloride
Kethanol
Total dry gil
Vater
Coal (MAP)
Ash
Particul a tes
Organic Aerosol >
Tars
Oils
Phenols
'a try Aeim
Jther Constituents
Total
239
Ash Quench
Makeup Water
9,900
9,900
403
Quenched
Ash
5.500
22.300
27.800
206
Ash Lock
Vent Gas
10.5
0.6
11.1
1,132
2.6
1,491
209
Gas Liquor
)epressurization
Gas
2.2
164
7.3
0.37
0.37
1.9
0.023
0.69
0.49
0.063
0.01
4.1
182
169
7,790
111
Tar
540
7,174
7,174
112
Oil
1.4
696
697
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL
kg-moles/hr
c.
3
Stream No.
Stream Nane
Hydrogen
Oxygen
Nitrogen/ Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethylene
Propane
Propylene
Butane
Butylene
C5+ Aliphatic!
Benzene
Tolnene
Other aronatlcs
Hydrogen Sulfide
Carbonyl Sal fide
Methyl Merciptin
Ethyl Merciptin
C3+ Mercaptana
Hydrogen Cyanide
Aanonia
Hydrogen Chloride
Methanol
Total dry gas
Water
Coal (MAF)
Ash
Particulatea
Organic Aerosols
Tars
Oils
Phenols
Fatty Acids
Other Constituents
Total
210
Gas
Liquor
Synthesis Cat
89
4.3
0.7(
143
494.840
38
253
1,152
192
1.480
506.610
210S
Gas
Liquor
t SNG Csse
89
4.3
0.70
143
475.636
38
253
1,152
192
1,480
485,406
10
Quenched Lurgt
Gas- Synthesis
Cases
7,455
21
238
3.417
6.019
1.867
98
14
16
14
7.8
14
3.7
16
3.6
2
175
2.2
15
4.7
0.61
0.48
0.00
0.2
19,404
612
429.930
10S
Quenched
Lnrgi Gas-
SNG Case
8.632
21
238
2.240
7.197
1.867
98
14
16
14
7.8
14
3.7
16
3.6
2
176
1.2
15
4.7
0.61
0.48
17 0.015
0.2
20,582
630
451.208
213
AGR Offgases-
Synthesis Cases
22
6
68
5,854
49
56
8
16
14
6.9
12.4
0.4
0.63
0.04
174.8
2.2
14.2
3.3
0.23
8.5
6,317
272.077
213S
AGR Off gases-
SNG Case
26
6
45
6.729
49
56
8
16
14
6.9
12.4
0.37
0.72
0.04
175.8
1.2
14.2
3.3
0.23
9.0
7,173
309,989
I
M
.p-
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL
£
i
6)
k.
1
Stream No.
Stream Name
Hydrogen
Oxygen
Nitrogen/Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethvlene
Propane
Propylene
Butane
Bntvlene
C5+ Aliphatici
Benzene
Tolnene
Other aromatlca
Hydrogen Sol fide
Carbonyl Snlfide
Methyl Mercaptan
Ethvl Mercantan
C3+ Mercaptana
Hydrogen Cyanide
Ammonia
Hydroien Chloride
Methanol
Total dry gaa
later
Total
216
Methanol/Wate
Still Bottoms
Syntheaia Caie
0.004
0.007
0.046
0.2
0.018
0.28
12,052
12.061
216S
Methanol/Wate
Still Bottoms
i SNG Case
0.004
0.008
0.048
0.2
0.019
0.28
11,720
11,721
114
By-Product
Lnrgi Naphtha
Synthesis Case
0.9
1.6
3.3
15.4
3.6
2
0.2
0.8
1.4
0.61
0.24
2.288
114S
By-Product
Lurgi Naphtha
SNG Cases
0.9
1.6
3.3
15.3
3.6
2
0.2
0.8
1.4
0.61
0.24
2,218
12
Sulfur-Free
Synthesis Gas
Synthesis Cases
7.433
21
232
3.349
165
1,818
42
6
0.04
13,066
155,355
12S
Sulfur-Free
Synthesis Gas
SNG Case
8,606
21
232
2.195
468
1.818
42
6
0.04
13.388
138.575
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LUROI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL
kg-moles/hr
.c
B>
.*
Stream No.
Strean Najnc
Bydrogen
Oxygen
Nitrogen/ Argon
Carbon Monoxide
Carbon Dioxide
Methane
Total dry gaa
later
Total
228S
Me thana tion
Condensate
SNG Synthesis
0.1
0.4
0.5
55,989
56.002
236S
Dehydration
Of fiases
SNG Synthesis
218
218
110S
Product SNG
SNG Synthesis
155
232
2.2
23.8
4.550.7
4,963.7
7
82,357
PI
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL
£
10
0)
o
o>
k_
o>
JC
Stream No.
Stream Name
Hydrogen
Oxygen
Nitrogen/Argon
Carbon Monoxide
Methane
Ethane
Ethyl one
Ethanol
Propanol
Acetone
later
Total
117 ME
Fuel Grade
Methanol
MeOB Synthesis
0.02
0.02
0.03
1.0
1.0
0.26
3,13)
1.0
0.04
2.1
1UU
101,500
237 ME
Methanol
Wastevater
MeOH Synthesis
0.44
0.0001
0.61
1 ,4UO
1,456
18 HE
Purge Gas to
Me thanation
MeOR Synthesis
961
232
231
84.3
1,817
41.7
6
30
0.006
0.002
0.63
/
50,180
228 ME
Me thanation
Condensa te
MeOH Synthesis
U.OZ
0.06
K ,181
8.183
231 ME
CO, Removal
Offgas
MeOH Synthesis
0.006
0.07
0.0004
22.1
0.77
~23
987
236 HE
Dehydration
Offgases
MeOB Synthesis
z90
290
110 ME
Coproduct SNG
MeOH Synthesis
12
232
1.2
/ .2
2.192
i
43,569
w
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LURDI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL
g-moles/hr
^>
JC
Stream No.
Stream Name
Hydrogen
Orygen
Nitrogen/Argon
Carbon Monoxide
Carbon Dioiide
Methane
Ethane
Ethylene
Propane
Propylene
Butane
Butylene
C5 + Aliphatici
Me than ol
Ethanol
Propanol
Ace tone
Organic Acids
Total drr gas
Water
Total
18 MM
Purge £ Expansion
Gas to Methanatio
Mobil M Caae
961
232
231
84.3
1,817
41.7
6
30
0.006
0.002
0.6
3,403
7
50,180
107 MM
Crude
Me th an ol
Mobil M Case
0.03
0.02
0.04
1.8
1.2
0.3
3.157
1.0
0.6
2.1
1,506
103,000
225 MM
Mobil M
Wast ewat er
0.02
0.5
0.7
4.1
5.4
58,100
58,670
226 MM
Fractiona tion Of
to CO a R em ov a
Mobil M
0.8
0.02
0.4
2.7
21
6
0.5
2.3
0.1
1.7
0.1
0.5
36
39
953
228 MM
gas Methanation
Conde nsa t e
Mobil M
0.02
0.06
8,181
8,183
231 MM
CO, Removal
Offgas
Mobil M
0.006
0.08
0 0006
24.6
0.85
0.02
n.nnoz
•M f.
28
1.127
De hydra ti on
Of fgases
Mobil M
294
I
M
00
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LOROI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL
kg-moles/hr
c.
5
Stream No.
Stream Name
Hydrogen
Oxygen
Nitrogen/ Argon
Citboa Monoxide
Carbon Dioxide
Methane
Etbane
Ethvlene
Propane
Propylene
Butane
Butvlene
C5 + Aliphatlct
Total dry gat
Water
Total
110 MM
Co-product SN
Mobil M
12.8
232
1.6
7.4
2,214
6.0
0.5
2.3
0.1
1.7
0.1
0.5
2,479
297
44,690
108 MM
Blended
! Gasoline
Mobil M
36,690
109 MM
C, LPG
Mobil M
1.981
109 MM
C4 LPG
Mobil M
1.172
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL
kg-moles/hr
1
Stream No.
Stream Name
Hydrogen
Nitrogen/Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethylene
Propane
Propylene
Butane
Butylene
Pentane
Pentene
C7+ Aliphatica
Acetone
Total dry gas
later
Total
14 FT
Purge Gas to
Methanation
F-T Case
1,367
228
51
340
1,959
56
32
0.8
4,042
59,630
219 FT
Wastewater Froi
Alcohol Recover
F-T Case
14.3
70,970
71,830
220 FT
Fract iona t ion
y Offgases to
CO, Removal
8.2
3.7
0.96
175
147
72
32
3
31
0.006
0.04
0.002
0.006
0.1
474
328
15,080
228 FT
Condensa t e
F-T Case
0.04
0.15
19,440
19,444
238 FT
CO, Removal
F-T Case
393
393
231 FT
CO, Removal
Offgas
F-T Case
0.4
0.6
0.004
241
7.3
0.2
0.09
0.008
0.08
249
270
11,010
236 FT
Dehydration
Offgas
F-T Case
364
364
ho
O
-------
TABLE E-2. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - ILLINOIS NO. 6 COAL
-C
ID
0
6>
h_
B>
je
Stream No.
StreaB Name
Hydrogen
Nitrogen/ Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethylene
Propane
Propylene
Butane
Butylene
Pentane
Pentene
C7+ Aliphatica
Total dry |aa
later
Total
110 FT
Co-prodact
SNG
F-T Case
98
231
1.2
H
2.583
71
32
3
31
0.006
0.04
0.002
0.006
0.1
3.065
4
53,250
100 FT
Blended
Gasoline
F-T Case
20,680
101 FT
Diesel Oil
F-T Case
4,195
102 FT
Heavy Fuel
Oil
F-T Case
1,228
105 FT
Mixed Alcohols
F-T Case
3,556
106 FT
C, LPO
F-T Cate
1,351
106 FT
C4 LPO
F-T Case
205
N3
-------
TABLE E-3 . CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - DUNN COUNTY LIGNITE
kg-moles/hr
t_
1
Strom No.
Strom Name
Hydrogen
Oxygen
Nitrogen/Argon
Tirhon Mnnniide
Carbon Dioxide
Methane
Ethine
Ethvlene
Propane
Propylene
Butane
Bntvlene
C5 + Aliphatic!
Benzene
Toluene
Other •roBitio
Hydrogen Sulfide
Cirbonyl Sol fide
Methyl Merctptan
Ethyl Mercaptin
C3 + Mercaptans
Hydrogen Cyanide
Ammonia
Hydrogen Chloride
Methanol
Total dry gat
Water
Coal (MAP)
Ash
Particnlatei
Organic Aerosol •
Tin
Oils
Phenol i
Fatty Acids
Other Constituent!
Total
1
Run-of-Mine
Coal
220,140
311.740
39,030
570,910
21
Coal
Fines
66,040
93,520
11,710
171.270
2
Prepared
Coal
154,100
218,220
27.320
399,640
3
Steam
423,490
423,490
4
Oxygen
2.610
159
2.769
89,260
5
Raw Lurgi
Gas
7,453
162
4 nn<
6,098
2,078
113
19.3
15.3
13.3
7.8
1J.1
9.6
11.5
2.2
2
76
1.0
6.7
1.2
0.29
1.2
78.3
n _i»
19,233
434,162
988
12,915
2,940
1 .129
103
1,887
873.400
205"
Low Pressure
Coal Lockhopper
Vent Gas
5.9
0.13
7 4
4.8
1.6
0.09
0.01S
0.012
0.011
0.006
n.ni i
0.008
0.009
0.002
n nni
0.06
0.001
0.005
o .nai
0.0002
0.001
0.062
n nnn?
15.2
2.2
0.068
2.5
337
w
K>
N>
^Assumes Lurgi gas is used as the lockhopper pressurant. Composition
shown excludes ejection air.
-------
TABLE E-3. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - DUNN COUNTY LIGNITE (Continued)
kg-moles/hr
^
B>
_*
Stream No.
Stream Name
Hydrogen
Oxygen
Ni trogen/Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethyl ene
Propane
Propylene
Butane
Butylene
CS + Aliphatlcs
Benzene
Toluene
Other aromatica
Hydrogen Snlfide
Carbonyl Snlfide
Methyl Mercaptan
Ethyl Mercaptan
C3+ Mercaptana
Hydrogen Cyanide
Ammonia
Hydrogen Chloride
Methanol
Total dry gas
Water
Coal (MAP)
Ash
Partlculatea
Organic Aeroaola
Tara
Oils
Phenols
Fatty Aclda
Other Constituents
Total
239
Ash Quench
Makeup later
12,700
12.700
403
Quenched
Ash
7,200
28,600
35,800
206
Ash Lock
Vent Gas
13.4
0.8
14.2
1,448
3.3
1.909
209
Gas Liquor
Depressurizatio
Gas
1.6
134
5.3
0.26
0.26
0.31
0.31
0.31
0.31
0.55
1.5
0.18
0.021
1.4
0.017
0.5
0.33
0.044
0.0085
1.6
149
140
6,550
111
Tar
962
12,780
13,740
112
Oil
5.9
2,940
2,946
re
-------
TABLE E-3. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - DUNN COUNT! LIGNITE (Continued)
c.
ID
0
6)
c.
I1
Stream No.
Streim Nane
Hydrogen
Oxygen
Nitrogen/Argon
Carbon Monoxide
Carbon Dioxide
Methane
Ethane
Ethylene
Propane
Propyleno
Butane
Butylene
C5 + Aliphatict
Benxene
Toluene
Other aromatici
Hydrogen Sulfide
Carbonyl Sal fide
Methyl Mercaptan
Ethyl Mercantan
C3 + Mercaptans
Hydrogen Cyanide
Auaionia
Hydrogen Chloride
Methanol
Total dry ga>
Water
Coal (HAF)
Ash
Particulates
Organic Aerosola
Tars
Oils
Phenols
Fatty Acids
Other Constituents
Total
210
Gas
Liquor
Synthesis Cas
76.5
0.6:
0.71
7S.6
433.410
26
135
1,129
103
1.887
441,440
210S
Gas
Liquor
s SNG Case
76.5
0.65
0.78
78.6
418,208
26
135
1.129
103
1.887
426,238
10
Quenched Lurgi
Gas- Synthesis
Cases
7,453
162
3.003
5,887
2,073
113
19
15
13
7.5
13
9
10
2
2
74
1.0
6.2
1.9
0.25
0.37
0.06
0.19
18.86S
612
408,170
10S
Quenched
Lnrgi Gas-
SNG Case
8,298
162
2.158
6.732
2,073
113
19
15
13
7.5
13
9
10
2
2
74.4
0.64
6.2
1.9
0.25
0.22
0.227
0.19
19,714
604
423,780
213
AGR Offgsses-
Syuthesis Cases
22
4
60
5,462
54
65
11
15
13
6.6
11.5
0.9
0.58
0.04
73.9
1.0
5.9
1.3
0.18
0.027
8.3
5.815
250,868
213S
AGR Offgases-
SNG Case
25
4
43
6,274
54
65
11
15
13
6.6
11.5
0.9
0.66
0.04
74.3
0.64
5.9
1.3
0.10
0.18
8.6
6.615
286,134
ho
-------
TABLE E-3. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - DUNN COUNTY LIGNITE (Continued)
>_
o
6>
^>
.*
Streasi No.
Strom Na»e
Hydrogen
Oxygen
Nitrogen/ Argon
Carbon Monoxide
Cirboo Dioxide
He thine
Ethane
Ethylene
Propine
Propylene
Bnttne
Bntylene
C5+ Aliph.tict
Benzene
Toluene
Other aromttlcs
Hydrogen Sulfide
Cirbonyl Sulfide
Methyl Mercaptan
Ethyl Mercaptan
C3 + Mercaptans
Hydrogen Cyanide
Amnonia
Hydrogen Chloride
Methanol
Total dry gas
later
Total
216
Methanol/Iate
Still Bottoas
Synthesis Case
0.003
0.006
0.036
0.19
0.014
0.25
10,112
10.120
216S
: Methanol/Vate
Still Bottoms
s SNG Case
0.004
0.007
0.046
0.19
0.018
0.27
10.054
10,063
114
By-Product
Lurgi Naphtha
Synthesis Case
0.9
1.5
8.0
9.4
2
2
0.1
0.3
0.6
0.25
0.19
1,900
114S
By-Product
Lurgi Naphtha
SNG Cases
0.9
1.5
8.0
9.3
2
2
0.1
0.3
0.6
0.25
0.11
1.890
12
Sulfur-Free
Synthesis Gas
Synthesis Cases
7,431
158
2.943
425
2.019
48
8
0.1
13.032
155.471
12S
Sulfur-Free
Synthesis Gas
SNG Case
8.273
158
2.115
458
2.019
48
8
0.1
13,079
135,423
NJ
Ui
-------
TABLE E-3. CALCULATED MATERIAL FLOWS FOR LURGI-BASED SYNTHETIC FUELS FACILITIES - DUNN COUNTY LIGNITE (Continued)
kg-moles/hr
.C
B>
J£
Stream No.
Stream Name
Hydrogen
Oxygen
Nitrogen/Argon
Carbon Monoxide
Carbon Dioxide
Methane
Total dry gas
Water
Total
228S
Methanation
Condense te
SNG Synthesis
0.1
0.4
0.5
53,585
53,597
236S
Dehydration
Offgases
SNG Synthesis
208
208
110S
Product SNG
SNG Synthesis
116.5
158
1.1
20.4
4,682.5
4,978.5
7
81,618
KJ
------- |