vvEPA
United States      Industrial Environmental Research
Environmental Protection  Laboratory
Agency        Research Triangle Park NC 2771 1
                                     EPA-600/8-83-008
                                     April 1983
            Research and Development
Pollution Control
Technical Manual for
Koppers-Totzek
Based Indirect Coal
Liquefaction

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                                            EPA-600/8-83-008
                                            April 1983
               POLLUTION CONTROL TECHNICAL MANUAL

                              FOR

         KOPPERS-TOTZEK-BASED  INDllMWoAL  LIQUEFACTION
                           Contract
                          68-02-3137
             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-RTP
               Research Triangle Park, NC  27711


          INDUSTRIAL  ENVIRONMENTAL  RESEARCH LABORATORY
               OFFICE OF RESEARCH AND DEVELOPMENT
              U.S.  ENVIRONMENTAL  PROTECTION AGENCY
                 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 Koppers-Totzek based plants at Modder-
fontein, S.A. and Ptolemais, Greece.  The evaluation at Ptolemais was a joint
study supported by the  Tennessee Valley  Authority (TVA) and the Environmental
Protection Agency (EPA).   Additional data sources used in this manual in-
cluded other EPA synfuels characterization studies, environmental impact
statements, published literature, and EPA supported engineering calculations.
No proprietary or confidential data appear or have been used in the prepara-
tion of this manual.  Although this manual addresses the Koppers-Totzek
gasifier based technology, the process developer, Krupp-Koppers, GmbH, Essen
was not involved in the development of this manual.  Thus, the manual does
not necessarily represent Krupp-Koppers1 engineering design data, material
balances, or operational  information.
This document has been  reviewed in accordance with U.S. Environmental
Protection Anency policy and approved for nublication.  Mention of trade
names or commercial oroducts does not constitute endorsement or recommenda-
tion for use.

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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 extraction 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
control applications, both as individual  process  units and as integrated con-
trol trains.  These examples are taken in  part from applicable permit  appli-
cations and, therefore, are reflective of  specific plants.  None of the
examples are intended to convey an Agency  endorsement or recommendation but
rather are presented 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 tech-
nologies may control specific 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
requirements 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

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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.

     The Koppers-Totzek (K-T)-based indirect liquefaction PCTM addresses the
K-T gasification technology as licensed by Krupp-Koppers, QnhH, Essen, West
Germany (GeselIschaft fur Kohle-Technologie for licensing within the U.S.)
and all  intermediate process operations leading to each of three liquid pro-
duct configurations.  The liquid product syntheses considered include Fischer-
Tropsch liquids, methanol, and Mobil M-gasoline.  A single feed coal  (Illinois
No. 6 bituminous) is utilized throughout the manual as the basis for illus-
tration, with the impacts of alternative coal  ranks also described in the
text.

     This manual proceeds through a description of the hypothetical base
plant, character!«s 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 wast>^ 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	•	ill
ABSTRACT	iv
FIGURES	viii
TABLES 	  x
GLOSSARY OF ACRONYMS	xv
CONVERSION FACTORS 	  xviii
ACKNOWLEDGEMENT  	  xviii

SECTION 1     INTRODUCTION  	   1

        1.1  Koppers-Totzek Based Indirect Liquefaction  	   2
        1.2  Approach to Manual Development   	   4
             1.2.1  Base Plant Definition  	   4
             1.2.2  Control Technology Evaluation  	   5
        1.3  Data Base	   6
        1.4  Manual Organization and Utilization 	   9
             1.4.1  Manual Organization  	   9
             1.4.2  Manual Utilization 	  10
SECTION 2    PROCESS DESCRIPTION OVERVIEW  	  13

        2.1  Coal Feed Characteristics and Product Slate	17
        2.2  Base Plant Description	20
             2.2.1  Coal  Preparation	20
             2.2.2  K-T Coal  Gasification	21
             2.2.3  Gas Purification and Upgrading	22
             2.2.4  Product Synthesis  .	25
             2.2.5  Auxiliaries	28
             2.2.6  Fugitive and Miscellaneous Wastes  	  28
        2.3  Base Plant Capital Investment and Annualized Operating
             Costs	30
SECTION 3    PROCESS DESCRIPTION AND WASTE STREAM CHARACTERIZATION .  .  33

        3.1  Coal Preparation	42
        3.2  Coal Gasification	52
        3.3  Gas Purification and Upgrading	60
             3.3.1  Gas Cooling and Dust Removal	60
             3.3.2  NOX Reduction	69
             3.3.3  Raw Gas Compression and Cooling	70
             3.3.4  Cyanide Wash	74
             3.3.5  Shift Conversion 	  78
             3.3.6  Acid Gas Removal	83
             3.3.7  Trace Sulfur Removal  	  89

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CONTENTS (Continued)

        3.4  Product  Synthesis 	   91
             3.4.1  Methanol  Synthesis  	   92
             3.4.2   Fischer-Tropsch (F-T)  Synthesis   	   96
             3.4.3  Methane Co-production  (Fischer-Tropsch Synthesis
                   Case)	98
             3.4.4  Mobil  M-gasoline Synthesis 	   100
             3.4.5  Product Recovery and Upgrading 	   105
             3.4.6  Waste  Streams Generated by Synthesis  Operations   .   106
        3.5  Products and  By-Products	Ill
             3.5.1  Methanol  Synthesis  Product 	   Ill
             3.5.2  Fischer-Tropsch Liquid Products   	   113
             3.5.3  Mobil  M-gasoline Products  	   114
             3.5.4  Substitute Natural  Gas (SNG)  	   119
             3.5.5  LP Gas	119
             3.5.6  By-Product Sulfur (Stream 112) 	   119
        3.6  Auxiliaries	121
             3.6.1  Raw Water Treatment	121
             3.6.2  Power  Generation and Process  Heating  	   128
             3.6.3  Cooling Operations  	   134
             3.6.4  Oxygen Production  	   137
             3.6.5  Product and By-Product Storage 	   138
        3.7  Fugitive and  Miscellaneous Wastes 	   142
             3.7.1   Fugitive Organic Emissions (Stream 241)  	   142
             3.7.2  Non-Process/Intermittent Wastewater Streams  .  . .   143
             3.7.3   Equipment Cleaning  Wastes (Streams 242 and 305)   .   146
        3.8  Waste/Control Technology Index  	   147
SECTION 4    EVALUATION OF POLLUTION CONTROL TECHNOLOGY  	   163

        4.1  Gaseous  Medium	169
             4.1.1  Acid Gases Containing Reduced Sulfur/Nitrogen,
                    Organics, and/or Carbon Monoxide 	   173
             4.1.2   Combustion Gases 	   218
             4.1.3  Organic and CO Containing Waste  Gases  	   249
             4.1.4   Fugitive Dust from  Material Storage (Stream 200) .   254
             4.1.5   Fugitive VOC Emissions	259
             4.1.6   Fugitive Particulates from Material Conveying and
                    Processing	274
        4.2  Aqueous  Medium	276
             4.2.1   Water Pollution Control Processes  	   285
             4.2.2   Water Pollution Controls for Streams Containing
                    Predominantly Organic Constituents 	   309
             4.2.3   Water Pollution Controls for Streams Containing
                    Predominantly Inorganic Constituents 	   320
             4.2.4   Integrated Pollution Control  Examples  	   335

                                     vi

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CONTENTS (Continued)
        4.3  Solid Waste Management 	   370
             4.3.1  Solid Waste Control 	   375
             4.3.2  Inorganic Ashes and Sludges 	   390
             4.3.3  Recovered By-Products 	   404
             4.3.4  Organic Sludges	   405
             4.3.5  Spent Catalysts and Sulfur Guard  	   408
SECTION 5

SECTION 6

Appendix A
Appendix B
DATA GAPS AND LIMITATIONS

REFERENCES 	
411

432
Costing	   A-1
Rectisol Acid Gas Removal Process  	   B-l
                                    VII

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                                   FIGURES
Number                                                                  Page
 2-1    Simplified flow diagram for K-T based synthesis gas
        production	    14
 2-2    Simplified flow diagram for conversion of synthesis gas to
        liquids	    15
 3-1    Operations associated with synthesis gas production in K-T
        based indirect liquefaction facilities 	    34
 3-2    Synthesis operations associated with K-T based indirect
        liquefaction facilities  	    35
 3-3    Auxiliary processes associated with K-T based indirect
        liquefaction facilities  	    36
 3-4    Waste streams associated with coal preparation for a K-T based
        indirect liquefaction facility - Illinois No. 6 coal 	    44
 3-5    GKT's gasifier with waste heat boiler and slag extraction
        system	    53
 3-6    Gas cooling and dust removal	    61
 3-7    Raw gas compression and cooling	    72
 3-8    Shift conversion  	    82
 3-9    Two-stage selective Rectisol  acid gas removal system  	    85
 3-10   Flow diagram for  the ICI methanol synthesis  process   	   93
 3-11   Fischer-Tropsch (Synthol) synthesis and product recovery  ...   97
 3-12   Methanation, C02  removal, and drying  for SNG production   ...   101
 3-13   Flow diagram for  Mobil M-gasoline synthesis  and crude  product
        fractionation   	   102
 3-14   Flow diagram for  base  plant  raw water treatment system ....   124
 4-1    Three  stage Glaus plant with  split  flow option  	   176
 4-2    The Stretford  process	179
 4-3    Example  1 - Glaus bulk sulfur removal with  Beavon/Stretford
        tail gas  treatment	205
 4-4    Example  2 - Glaus bulk sulfur removal with  SCOT tail  gas
        treatment and  incineration  	   210
 4-5    Example  3 - Glaus bulk sulfur removal with  Wellman-Lord tail
        gas  treatment	   214

                                     viii

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FIGURES (Continued)
Number                                                                 Page
 4-6    Integrated control examples - Mobil  M or F-T synthesis case .   340
 4-7    Integrated control examples for base plants producing crude
        methanol  - discharge to surface waters  	   352
 4-8    Integrated control examples for base plants producing crude
        methanol  - discharge to surface impoundment or deep well
        injection	   353
 4-9    Landfill  design	   383
 4-10   Capital  investment and annual ized unit cost for landfills . .   384
 4-11   Surface  impoundment design  	   387

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                                   TABLES
Number                                                                 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 Illinois No. 6
       Coal  	    17
 2-2   Estimated Product/By-Product Slate for K-T Base Plants  ...    19
 2-3   Capital  Costs for Uncontrolled K-T Based Indirect Liquefaction
       Plants	    30
 2-4   Annualized Costs for K-T Based Indirect Liquefaction Plants  .    31
 3-1   Flows of Major Streams for K-T Based Indirect Liquefaction
       Facilities - Illinois No. 6 Coal   	    38
 3-2   Characteristics of Illinois No. 6 Coal  Selected for Use in
       Indirect Liquefaction Base Plants 	    43
 3-3   Coal Preparation Section Mass Flows - Methanol Synthesis Case    46
 3-4   Estimated Fugitive Dust Emissions from Coal Storage Piles .  .    47
 3-5   Particulate Emissions from Coal Preparation (Illinois No. 6
       Coal)	    50
 3-6   Material Flow Estimates for K-T Gasification (Illinois No. 6
       Coal)	    56
 3-7   Results  of K-T Slag Leaching Tests	    57
 3-8   Material Flow Estimates for Raw Gas Cooling and Dust Removal
       Processes (Illinois No. 6 Coal) 	    63
 3-9   Leachability of Selected Elements from K-T Dust and from
       Illinois No. 6 Feed Coal  	    66
 3-10  Characteristics of Slowdown from Cooling and Dust Removal .  .    68
 3-11  Material Flow Estimates for K-T NOX Reduction, Compression and
       Cooling, and Cyanide Wash Processes (Illinois No. 6 Coal) .  .    71
 3-12  Characteristics of Primary Compression and Cooling Condensate
       from South African Sub-bituminous Coal   	    74
 3-13  Material Flow Estimates for K-T Shift Conversion and Acid Gas
       Removal  Processes (Illinois No. 6 Coal) 	    87
 3-14  Methanol Synthesis Material Flow Estimates for K-T Gasification
       (Illinois No. 6 Coal)	    95

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TABLE (Continued)

Number                                                                  Page
  3-15  Fischer-Tropsch Synthesis Material  Flow Estimates for K-T
        Gasification (Illinois No. 6 Coal)  	   99
  3-16  Mobil M-gasoline Synthesis Material  Flow Estimates for K-T
        Gasification (Illinois No. 6 Coal)  	  104
  3-17  Components Reported in Commercial Methanol  	  112
  3-18  Estimated Composition of Crude Methanol  from Coal  	  113
  3-19  Comparison of the Estimated Composition of  Finished Indirect
        Coal  Liquefaction, Unleaded Gasolines,  and  Typical  Petroleum
        Gasolines	115
  3-20  Distribution of Oxygenated By-Products  from Fluid-Bed Fischer-
        Tropsch Synthesis	116
  3-21  Methanol  Conversion Unit Feed and Product Composition  ....  117
  3-22  Composition of Raw Makeup Water	122
  3-23  Estimated Makeup Water Quantity for  a K-T Based Indirect
        Liquefaction Plant (Illinois No.  6 Coal)  	  123
  3-24  Raw Water Treatment Sludge (Stream 300)  Production Rates and
        Characteristics  	  126
  3-25  Demineralizer Regeneration Wastewater Composition (Stream 301)  127
  3-26  Boiler Mass Flow for Illinois No. 6  Coal  -  Methanol  Synthesis
        Case	130
  3-28  Cooling System Makeup Water Requirements  for a K-T Indirect
        Liquefaction Plant 	  135
  3-29  Estimated Characteristics of Cooling Tower  Slowdown and Drift   136
  3-30  Evaporative Emission Estimates for Product  and By-Product
        Storage	139
  3-31  Composition of Evaporative Emissions from Gasoline Storage . .  141
  3-32  Estimated Total Fugitive Organic  Emissions  	  144
  3-33  Drainage  Estimate from Non-Process/Intermittent Streams  . . .  145
  3-34  Stream Index	148
  3-35  Cross-Reference Index for Primary Waste Streams  	  154
  3-36  Cross-Reference Index for Secondary  Waste Streams  	  159

                                     xi

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TABLES (Continued)
Number                                                                 Page
 4-1    Summary of Estimated Gaseous Waste Stream Characteristics in
        K-T Based Indirect Liquefaction Facilities 	   170
 4-2    Categorization of Gaseous Waste Streams According to Source
        Type in K-T Indirect Liquefaction Facilities 	   171
 4-3    Key Features of Bulk Sulfur Removal  Processes  	   175
 4-4    Key Features of Residual  Sulfur Removal Processes  	   183
 4-5    Comparison of Incineration Processes 	   188
 4-6    Example 1 - Material Flow Estimates for Integrated Control
        Employing Claus Bulk Sulfur Removal  with Beavon/Stretford
        Tail Gas Treatment	   206
 4-7    Example 1 - Costs of Integrated Claus Bulk Sulfur Removal
        with Beavon/Stretford Tail Gas Treatment (1980 Basis)  ...   208
 4-8    Example 2 - Material Flow Estimates for Integrated Control
        Employing Claus Bulk Sulfur Removal, SCOT Tail Gas Treatment,
        and Incineration	   211
 4-9    Example 2 - Costs of Integrated Claus Bulk Sulfur Removal
        with SCOT Tail Gas Treatment and Incineration (1980 Basis)  .   213
 4-10   Example 3 - Material Flow Estimates for Integrated Control
        Employing Claus Bulk Sulfur Removal  with Well man-Lord Tail
        Gas Treatment	   215
 4-11   Example 3 - Costs of Integrated Claus Bulk Sulfur Removal
        with Wellman-Lord Tail  Gas Treatment (1980 Basis)  	   217
 4-12   Combustion Modification Techniques for NOX Control 	   221
 4-13   NOX Flue Gas Treatment Control Alternatives for Boilers   .  .   228
 4-14   Key Features of Particulate Collection Equipment  	   234
 4-15   Key Features of S02 Removal Processes	   237
 4-16   Composition of Flue Gas from the Dewatered Dust-Fired
        Fluidized-Bed Boiler (Stream 413)   	   246
 4-17   Key Features of Storage Pile Dust Control Technologies .  .  .   255
 4-18   Repair Methods for Fugitive Emissions Reduction   	   264
 4-19   Equipment Design/Modifications for  Fugitive Hydrocarbon
        Emissions Control   	   265
                                     Xll

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TABLES (Continued)
Number                                                                 Page
 4-20   Storage Tank Emission Estimates 	  267
 4-21   Estimated Incremental Costs for Storage of Synthetic Liquids   269
 4-22   Fugitive Organic Emissions from Process Equipment 	  271
 4-23   Capital and Annualized Costs for Fugitive Organic Emission
        Controls	273
 4-24   Summary of K-T Base Plant Wastewater Streams and Estimated
        Characteristics 	  277
 4-25   Categorization of Aqueous Waste Streams in K-T Gasification
        Facilities	280
 4-26   Control Processes Potentially Applicable to the Treatment of
        K-T-Based Gasification Plant Wastewaters  	  286
 4-27   Material Flow for Cooling Tower Concentration - Mobil M
        Synthesis Case	314
 4-28   Material Flow for Forced Evaporation-Mobil M Synthesis Case  .  317
 4-29   Material Flow for Cooling Tower Concentration and Forced
        Evaporation - Water-Based Cyanide Wash Case 	  326
 4-30   Material Flow for Cooling Tower Concentration and Forced
        Evaporation - Methanol-Based Cyanide Wash Case  	  331
 4-31   Characterization of Major Streams Combined for Common Treat-
        ment - Mobil M Synthesis Case	338
 4-32   Example 1 - Material Flow for Mobil M Synthesis Base Plant
        Integrated Controls  	  342
 4-33   Example 2 - Material Flow for Mobil M Synthesis Base Plant
        Integrated Controls  	  345
 4-34   Example 3 - Material Flow for Mobil M Synthesis Base Plant
        Integrated Controls  	  347
 4-35   Estimated Characteristics of Wastewater Streams Discharged
        to Ultimate Disposal - Mobil M Synthesis Case 	  348
 4-36   Costs of Integrated  Control Examples - Mobil M Synthesis
        Case	349
 4-37   Characterization of Major Streams to be Combined for Treat-
        ment - Crude Methanol Production Case  	  355
 4-38   Example 4 - Material Flow for  Crude Methanol Production Base
        Plant  Integrated Controls 	  357

                                    xi ii

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TABLES (Continued)
Number                                                                 Page
 4-39   Example 5 - Material Flow for Crude Methanol Production Base
        Plant Integrated Controls 	  358
 4-40   Example 6 - Material Flow for Crude Methanol Production Base
        Plant Integrated Controls 	  363
 4-41   Example 7 - Material Flow for Crude Methanol Production Base
        Plant Integrated Controls 	  364
'4-42   Example 8 - Material Flow for Crude Methanol Production Base
        Plant Integrated Controls 	  365
 4-43   Estimated Characteristics of Wastewater Streams Discharged
        to Ultimate Disposal - Crude Methanol Production Case ....  366
 4-44   Costs of Integrated Control  Examples - Crude Methanol
        Production Case	367
 4-45   Summary of Solid Waste Streams from K-T-Based Indirect
        Liquefaction Facilities 	  371
 4-46   Summary of Solid Waste Management Technologies  	  376
 4-47   Site-Specific Factors to be Considered for  Land-Based
        Disposal Options  	  377
 4-48   Estimated Flow Rates for the Inorganic Ash  and Sludge
        Streams	390
 4-49   Characteristics of  Flue Gas and Spent Bed Media from FBC
        Boiler	396
 4-50   Estimated Capital Investment and Total Annualized Cost for
        Burning Dewatered Gasifier Dust in FBC Boiler 	  397
 4-51   Summary of Capital  Investment and Total Annualized Cost for
        Disposinq of Gasifier Dust  in Surface Impoundment	399
 4-52   Estimated Treatment/Disposal Cost for Biosludge 	  406
 4-53   Estimated Flow Rates for Spent Catalysts and Sulfur Guard  .  .  408
 5-1    Completed and Ongoing Data Acquisition Programs at Coal Gasi-
        fication  Facilities Sponsored or Co-Sponsored by the EPA   .  .  415
 5-2    Data Gaps and Research Needs - Gaseous Medium	416
 5-3    Data Gaps and Research Needs - Aqueous Medium	422
 5-4    Data Gaps and Research Needs - Solid Medium	438
 5-5    Data Gaps and Research Needs - Products/By-Products  	  431

                                     xiv

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                           GLOSSARY OF ACRONYMS
ACP     Ammonia from Coal Project
ADA     Anthraquinone disulfonic acid
ADIP    Shell-patented diisopropyl amine-based acid gas removal process
AGR     Acid gas removal
BM      Bureau of Mines
BOD     Biochemical oxygen demand
COD     Chemical oxygen demand
CRA     Compression-refrigeration-absorption
CRF     Capital Recovery Factor
DEA     Diethanolamine
DIPA    Diisopropanolamine
DOE     Department of Energy
DOI     Department of Interior
EGD     Effluent Guidelines Division, Office of Water Regulations and
        Standards, EPA
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
FGR     Flue gas recirculation
FGT     Flue gas treatment
F-T     Fischer-Tropsch
GKT     Gesellschaft fur Kohle-Technologie
HHV     Higher Heating Value
IERL    Industrial Environmental Research Laboratory
K-T     Koppers-Totzek
LEA     Low excess air
LHV     Lower Heating Value

                                    xv

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GLOSSARY OF ACRONYMS (Continued)
LNB     Low NO  burners
              s\
LPG     Liquified petroleum gas
MAP     Moisture and ash free
MEA     Monoethanolamine
MDEA    Methyldiethanolamine
NFI     Nitrogenous Fertilizer Industry (S.A.)
NOV     Nitrogen oxides
  A
NMHC    Non-methane hydrocarbons
NPDES   National Pollutant Discharge Elimination System
NSPS    New Source Performance Standards
OAQPS   Office of Air QUality Planning and Standards, EPA
OFA     Overfire Air
OPTS    Office of Pesticides and Toxic Substances, EPA
OSW     Office of Solid Wastes, EPA
PCB     Polychlorinated Biphenyls
PCTM    Pollution Control Technical Manual
PNA     Polynuclear Aromatics
POM     Polycyclic organic matter
PSD     Prevention of Significant Deterioration
RCRA    Resource Conservation and Recovery Act
RL      Reduced Load
ROM     Run of Mine
SASOL   South African Coal, Oil and Gas Corporation, Ltd.
SCOT    Shell Claus Off-Gas Treatment
SCR     Selective Catalytic Reduction
SNG     Substitute Natural Gas
SNPA    Societe Nationale des Petroles d'Aquitaine
SO      Sulfur oxides
  /\
TDS     Total dissolved solids
                                    xvi

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GLOSSARY OF ACRONYMS  (Continued)

TEA     Triethanolamine
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
                                    xvn

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                              CONVERSION  FACTORS
 1.0  kg  [kilogram]
 1.0  Mg  [megagram  (metric  ton)]
 1.0  kg/min  [kilogram  per  minute]
 1.0m3  [cubic  meter]
 1.0  Nm3/hr  [normal  cubic  meter
   (at 0°C)  per hour]
 1.0  GJ  [gigajoule]

 1.0  MW  [megawatt]

 1.0  MJ/s  [megajoule per second]

 1.0  kWh [kilowatt hour]
 1.0  MJ/Nm3  [megajoule per
   normal cubic meter  (at  0°C)]
         o
 1.0  g/Nm   [gram per normal
   cubic meter  (at 0°C)]
 1.0  kPa [kilopascal]
 1.0  kmole
 Prefixes
                    2.205  Ib  [pound  (mass)]
                    1.102  ton  [short ton  (2000  lb)l
                    132.3  Ib/hr  [pound  per  hour]
                    264.2  gal  [gallon]
                    37.32  scfh  [standard  cubic  feet
                    (at  6QOF)  per  hour]
                    0.9479 x  106 Btu [British thermal
                    unit]
                    3.413  x 106  Btu/hr  [British thermal
                    unit per  hour]
                    3.413  x 106  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°F)]
                    0.00987 atmosphere
                    22.4 Nm3  (at 0°C and  1  atmosphere)
 T - tera - 10
              12
G - giga = 10'
M = mega = 10
k = kilo =
                               ACKNOWLEDGEMENT
     Technical and background information for this Pollution Control Technical
Manual was prepared for the EPA by the Environmental  Division, TRW, Inc.,
Redondo Beach, California, under Contract 68-02-3647.  The TRW Project
Manager for this effort was Mr. R. Orsini.
                                    xvi

-------
                                                                  Section  1
                                                                  Introduction
                                  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 determines  syn-
thetic fuel plant waste stream characteristics and potentially applicable
pollution  control systems.
      The purpose of the Pollution Control Technical Manuals (PCTMs)  is to
convey in  a summarized and  readily useful manner, information on synfuel
waste stream  characteristics and pollution control technology as obtained
from  studies  by EPA and others.  The documents provide waste stream  character-
ization 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 suggested emission control  process(es)  in the ser-
 vice^)  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.   The volumes currently contemplated are:
     Pollution Control Technical  Manual  for Lurgi-Based Indirect
     Coal  Liquefaction and SNG
     Pollution Control Technical  Manual  for Koppers-Totzek-Based Indirect
     Coal  Liquefaction
     Pbllution Control Technical  Manual  for Exxon Donor-Solvent
     Direct Coal  Liquefaction
                                      1

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Section  1
Introduction
     Pollution Control  Technical  Manual  for Lurgi Oil  Shale Retorting
     vn'th 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 the 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 tech-
nology applications.  This focus  does not imply any EPA recommendations for
particular 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 pro-
vides the user with a number of alternative approaches.  Permit writers must
be cautioned that these control technology configurations are not the only
ones suitable for a specific plant.
     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
domestic commercial scale synfuels facilities, the data base supporting this
document is from bench and pilot synfuel facilities, developers' estimates,
engineering analyses, analogue domestic industries, and non-U.S. commercial
synfuel plants.
1.1  Koppers-Totzek Based Indirect Liqufaction
     Indirect coal liquefaction links of two types of  processes.   One
produces the H2- and CO-rich synthesis gas from coal by gasification, while
the second produces a range of synthetic liquid products  by reacting the H?
and CO components of a synthesis  gas.  A number of specific processes are

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                                                                  Section  1
                                                                  Introduction
available for the performance of both the gasification and synthesis steps.
The combination of gasification and synthesis steps is in constrast with
direct liquefaction, wherein any of several technologies can be used to
directly produce liquid products from coal.
     This PCTM addresses indirect liquefaction facilities for the production
of synthetic fuels by means of Koppers-Totzek (K-T) coal gasification followed
by any of three alternative fuel product synthesis routes, including methanol,
Fischer-Tropsch, and Mobil  M-gasoline.  Facilities of this type utilize all
of the process operations normally associated with indirect liquefaction,
namely coal preparation; coal gasification and raw gas cleaning; shift con-
version and acid gas removal; and synthesis of the desired fuel product.
Auxiliary processes required to support these production operations are those
required for oxygen production, raw water treatment, process cooling, and
waste stream treatment.  Depending upon the local availability and cost of
electric power, on-site auxiliary power generation facilities may also be
required.
     The K-T process, as developed and licensed by Krupp-Koppers, GmbH,
Essen, West Germany (Gesellschaft fur Kohle-Technologie (GKT) in the U.S.),
is a commercially viable process which has been widely used outside the U.S.
to produce industrial fuel  gas and synthesis gas from coal.  To date, the
GKT K-T process has been used with a variety of coal feeds, ranging from
brown coals through lignite and bituminous ranks and encompassing the full
breadth of coking tendencies.
     As a consequence of the recent formal separation of Koppers, Pittsburgh
from Krupp-Koppers, a new gasifier has been designed and is being marketed
by Koppers-Pittsburgh and Babcock and Wilcox as the KBW unit.  While the KBW
gasifier does incorporate different approaches (relative to K-T) to both heat
recovery and dust separation, it does not appear to incorporate any features
which would alter the actual  gasification conditions, reactions or the extent

-------
Section 1
Introduction
of those reactions.  Therefore, while the KBW gasifier has riot been operated
commercially and no specific process, operational  or environmental  data on
the design were available for use in this manual,  the Agency believes that the
statements and examples presented herein regarding the K-T gasifier are also
valid to a first approximation for the KBW gasifier.
     All of the process operations discussions in  this PCTM are largely based
upon foreign experience, with the exception of the U.S.-developed Mobil M-
gasoline process which is not yet in commercial operation.  The methanol and
Fischer-Tropsch synthesis processes have been commercially applied to the pro-
duction of liquids from coal-derived synthesis gases.  For purposes of this
document, all of these technologies are considered ready for commercial appli-
cation.
1.2  Approach to Manual Development
1.2.1   Base Plant  Definition
     In order to define the production operations and waste streams that would
be associated with representative integrated  process  facilities, an uncon-
trolled base plant was defined which incorporates the features seen in  the  K-T-
based  plants which are either  proposed, under  construction, or currently  in
operation.  In  this context, an  uncontrolled  base plant is one which has  full
production capability  (all of  the equipment required  to produce  saleable  pro-
duts)  but no equipment to control pollutant discharges.  Auxiliary processes
included  in the base plant are those that  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.  Illinois No. 6 bituminous coal
was  examined as the primary feed to  these  facilities, with the impacts  of
using  different ranks  of  coals with  various heating  values, moisture,  sulfur,
and  ash contents being examined  as  variations  to the primary coal.  This
approach  permitted estimation  of total  stream and consistent flow  rates in
a  process facility utilizing  different  feedstocks and served to  define the

-------
                                                                 Section 1
                                                                 Introduction
range of uncontrolled (i.e., base plant) waste streams for which treatment
and/or disposal could be considered.
     A base plant size corresponding  to approximately 120 TJ/day of clean
synthesis gas produced was selected to be representative of the sizes of the
modules of the first plants that may  be built in the U.S.  The energy output
rate (after synthesis) of a plant of  this size is equivalent to the energy
content of about 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.
1.2.2  Control Technology Evaluation
     The PCTMs examine control alternatives from three viewpoints:  first,
identifying several control technologies with their operating principles
and applicability to particular types of waste streams and defining the in-
herent performance limitations of these control technologies; second, by
using waste streams of given compositions as feeds to several of these con-
trol technologies, estimates of achievable control unit performance levels
and costs are illustrated; and third, alternative integrated control trains
are employed to treat base plant waste streams, thereby illustrating the
range of overall control and control  economics for individual streams.  Each
control technology utilized in the illustrative examples is further described
in the control appendix volume.
     Since very limited data on the performance of controls are available
from operating synthetic fuels plants, many assumptions had to be made to
extrapolate the experience gained with the same control technologies in
related industries.  These assumptions have been carefully documented in  the
appropriate sections of this manual.   Waste streams resulting from pollution
control process operations (secondary waste streams) were also identified
and controls for those streams described and illustrated.  Cost estimates
for all controls were developed based upon published data and vendor-supplied

-------
Section 1
Introduction
estimates.  These data were extrapolated to a 1980 cost basis to provide a

consistent basis for comparing the relative costs of alternate controls.

Base (uncontrolled) plant costs were extrapolated in a similar manner.

     Users of this PCTM should recognize that there are two yery significant

limitations associated with the use of the data presented.


     t  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 presented 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
        constraints.

     t  Second, it should be noted that this manual does not attempt to
        address all of the issues that will be important in the selection
        and design of environmental control systems for new synthetic fuels
        facilities.  Since this manual focuses on streams that tend to be
        unique to synfuels facilities, streams that are covered by exist-
        ing source-based regulations or that are similar to waste streams
        routinely encountered in other industries for which regulatory
        precedents already exist are recognized but not treated in depth.
        Also, this PCTM focuses primarily on controls for point and
        fugitive sources of pollution, and not on the environmental impacts
        of those emissions.

        Fugitive dust from coal storage and handling facilities may have
        to be controlled to satisfy Prevention of Significant Deteriora-
        tion (PSD) limitations associated with ambient particulate matter
        concentrations.  Selecting appropriate controls for this type of
        emission requires more details on the use of technologies and site-
        specific analyses than are included in this manual.

        It should also be noted that this manual does not address issues
        related to worker health and safety, noise, socioeconomic, or
        ecological impacts.

1.3  Data Base

     Since the early 1970's the EPA has sponsored a significant environmental

assessment program addressing technologies for producing synthetic fuels  from

-------
                                                                 Section 1
                                                                 Introduction
coal.  This work has involved a combination of theoretical  studies and plant
data acquisition programs and has contributed to both the data and background
knowledge used in the development of this document.  Table 1-1 lists the major
contributing data acquisition programs sponsored or co-sponsored by the EPA.
As indicated, the data encompass specific research projects, pilot-level
sampling and analysis projects, and source sampling of foreign and domestic
commercial production facilities.
     The  major  sources of data  used to define the  types  and characteristics  of
 uncontrolled  synthetic fuels  facility waste  streams  and  to  develop  base  plant/
 process configurations were:  (1) an EPA-sponsored  test program  of a  K-T  gasi-
 fication  facility  at  Modderfontein, S.A.;  (2) an  EPA- and TVA-sponsored  test
 program at  the  K-T facility  at  Ptolemais,  Greece;  (3) Linde/LOTEPRO  research
 and  EPA  (IERL and  OAQPS) sponsored tests  at  Rectisol  installations;  (4)  DDE-
 sponsored gasoline-from-coal  research studies conducted  by  Mobil  Research
 and  Development Corporation;  and (5)  permit  filings,  environmental  impact
 statements,  and design studies  for various proposed  K-T-based domestic syn-
 thetic fuel  facilities.   In  addition, data derived from  applications of con-
 trols  in  related industries  such as the  petroleum refining,  natural  gas
 processing,  by-product coking,  electric  utility,  and coal  preparation indus-
 tries  were relied  upon heavily in  determining  control applicability and costs.
     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 K-T-based facilities built  in  the  U.S.  may con-
 tain 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  judgments concern-
 ing  uncontrolled waste stream composition and  the applicability and perfor-
 mance  of  candidate control  technologies  for these streams.

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      TABLE  1-1.   COMPLETED AND  ONGOING  DATA ACQUISITION  PROGRAMS  AT  COAL GASIFICATION  FACILITIES  SPONSORED
                     OR CO-SPONSORED BY  THE EPA
oo
Facility
Medium/High Btu Gasification
and Indirect Liquefaction
Facilities (Foreign)
t Lurgi Gasification
- Kosovo, Yugoslavia
- SASOL, S.A.

- Westfield, Scotland
« Koppers-Totzek Gasification
- Modderfontein, S.A.

- Ptolemais, Greece
- Kutahya, Turkey
• Winkler Gasification
- Kutakya, Turkey
• Texaco Gasification
- Federal Republic of Germany

Low-Btu Gasification Facilities
(U.S.)
* Wellman Galusha
- Site No. 1
- Site No. 2
• Chapman/Wilputte
• Riley
• Stoic (Foster Wheeler)
Control Research Facilities
• Raw/Acid Gas Cleanup (Fluidized
Bed Gasifier)
• Wastewater Treatability Studies
t Pollutant Identification (Bench
Information Classification




Data acquisition
Plant visit and discussions

Plant visit and discussions

Data acquisition

Data acquisition (TVA & EPA)
Plant visit and discussions

Plant visit and discussions

Data acquisition (EPRI, TVA
& EPA)



Data acquisition
Data acquisition
Data acquisition
Data acquisition
Data acquisition (DOE & EPA)

North Carolina State Univ.

Univ. of North Carolina
Research Triangle Institute
Coal Used




Lignite
Low rank bituminous

Various

High volatile "B"
bituminous
111 . No. 6 bituminous
Lignite

Lignite

111 . No. 6 bituminous




Anthracite
Lignite
Low sulfur bituminous
Lignite
Western bituminous

Various

Various
Various
Products




Medium Btu gas
Various via indirect
1 iquefaction
Test center

Ammonia, methanol

Ammonia
Ammonia

Ammonia

Test center




Fuel gas
Test center
Fuel gas
Test
Fuel gas

Test center

Test center
Test center
                                Scale Gasifier)
                             • Ash Leaching Evaluations

                             Other Domestic Facilities

                             • Texaco Gasification
                               - Ammonia from coal plant, TVA

                             • Rectisol Acid Gas Cleanup
University of Illinois




Data acquisition (TVA & FPA)

Texaco, Wilmington, CA
                          Va-ious
111. No. 6 bituminous
  (in shakedown)
Oil fired partial
  oxidation
Test center




Ammonia

Process hydrogen

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                                                                  Section 1
                                                                  Introduction
 1.4  Manual  Organization and Utilization
 1.4.1   Manual  Organization
      This Pollution Control  Technology Manual  is  presented in two volumes.
 The main text  volume describes the processes,  their associated waste streams,
 and the pollutants potentially requiring control.   It also provides descrip-
 tions  and illustrative examples of pollution control  technologies.   Detailed
 information  supporting the cost  estimates  cited  in the main text can be
 found  in the appendix of the main text volume.   In  addition, detailed
 discussions  of control  processes  can  be  found  in a  separate  appendix volume
 that is common to  all  PCTMs.
     The subsequent sections of this  volume  provide:
          Section 2  An overview of the process operations discussed
                     in this manual.
          Section 3  A description of the sources  and characteristics
                     of the waste streams generated  by those process
                     operations.
          Section 4  An analysis of the performance  capabilities and
                     costs of candidate control  processes for waste
                     streams, including those generated by the control
                     processes themselves.
          Section 5  A summary of the quality of the data base used for
                     the base plant development and  control technology
                     analysis.
     Section  2  will be most useful to readers seeking a general knowledge of
the characteristics of the gasification technology which this document addres-
ses.  Detailed  information about the  characteristics of specific uncontrolled
waste streams is presented in Section 3.   This section also describes how the
characteristics of those streams are  likely to be  impacted by differences in
feedstock (coal) characteristics, process design features, and plant operating
characteristics.  The rationale for the selection  of specific control processes
to serve as illustrative examples as  well as an analysis of the expected

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Section 1
Introduction
performance of those controls is presented in Section 4.   In light of the in-
tended use of this document, this Section is most critical because it presents
current estimates of the performance capabilities and costs of controls which
have been or could be proposed for use in the subject facilities.  Potential
users of information presented in Section 4 should carefully note the data
limitations summaries presented in Section 5 and should utilize the control
appendices to establish the bases for adapting the PCTM base plant information
to the specific case at hand.  These summaries are intended to give potential
users of this document a general feel for the quality of the data used to
estimate both uncontrolled  base plant waste  stream characteristics and con-
trol equipment  performance  and  cost  data.
1.4.2  Manual Utilization
     PCTM  use has  been targeted for  those individuals concerned with the  pre-
paration of  permits  and the applications  for them.   As such, the  interests of
these  plant  designers and permit writers  will focus  both  on grouped waste
streams, with the  common characteristics  being  the medium  (i.e.,  air, water,
or solid waste  streams)  and/or major pollutant  species  involved,  as  well  as
on individual streams which,  because of  their flow volume  or constituents,
could  significantly impact  environmental  design  criteria.
     The PCTM accommodates  these  interests  in several ways.  First,  the  entire
study  is centered  around a  generalized uncontrolled  "base"  plant, which  con-
tains  all  of the  production operations to be found in the  coal conversion
sections of  K-T-based indirect  liquefaction  facilities;  second,  all  waste
streams  (including control  residuals or  secondary wastes)  are  categorized  by
medium;  and  third, within each  medium, the  streams are  grouped by major  pol-
lutant constituents.
     To  illustrate the  utilization  of the PCTM  by someone with a designer's  or
permit writer's interest  in a particular waste  stream  in  a planned  site-specific
 facility,  the initial step  will,  of course,  be  to locate  the counterpart waste

                                      10

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                                                                Section  1
                                                                Introduction
stream in the base plant.  This can be done through the use of the Section 2
and 3 flow diagrams and the stream and cross reference indicies in Section 3.8.
Section 3 will provide both a full characterization of the counterpart base
plant stream,  plus a description of (as applicable) other base plant streams
which may have to be analytically combined in order to better match the design
stream in question.
      Section  3.8  contains  a  process/waste  stream  index  and  cross  reference
 indicies  for  waste  streams.   The  process/waste  stream index,  Table  3-34,
 provides  stream  numbers  for  many  process  streams  and  all  waste  streams, and
 facilitates  identification of streams  discussed in  the  text.   The cross refer-
 ence  index  for primary waste streams,  Table  3-35,  lists:   (1)  all  of  the  un-
 controlled  base  plant waste  streams  and  indicates  the Section  3 subsection
 that  contains detailed characterization  data  for  each stream,  and (2)  the
 Section  4 subsection  that  contains  information  on  potentially applicable  pol-
 lution  controls  for each stream.   The  cross  reference index for secondary
 waste streams, Table  3-36, provides  similar  information on  the  pollution  con-
 trols discussed  in  Section 4, the secondary  waste  stream(s) generated  by
 those controls,  available  controls  for the secondary  waste  stream(s),  and
 references  to the appropriate Control  Technology  Appendices.
      Should the  user's interests  lie only with  waste  stream controls,  Table
 3-35  will direct him  to  the  appropriate  level of  discussion in  Section 4.  J
 General  control  technology descriptions  are  followed  by specific  discussions
 of the performance, secondary waste streams,  and  costs  associated with the
 application of  example control  techniques to specific waste streams.   For
 example,  Section 4.1.1.1 discusses the capabilities and costs of  specific
 control  processes applied  to the  offgases from  the acid gas removal  unit.
 Following the stream-by-stream discussions and  examples of individual  control
 applications are illustrative examples of potential integrated control schemes
 (i.e.,  multiple  control  techniques used in series)  for those streams  or com-
 binations of streams  which would  normally be expected to use more than a
                                   .   11

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Section 1
Introduction
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 Sections 4.1, 4.2,
and 4.3
     If the user's interests involve a potential control residual or secondary
waste stream, these and the location of applicable PCTM discussions of control
alternatives can also be directly determined through the Table 3-36 cross
reference index for secondary waste streams.  The user will find that cross-
media secondary wastes are generally discussed  under the medium to which they
contribute; exceptions are those peculiar cases in which the character of the
secondary stream implies a potential for treatment in excess of that which
would be provided  if it were combined with other streams.   In these cases,
the control alternatives are discussed under the medium of origin.
     Additional detail on the controls utilized in the Section 4 illustrative
examples can be found in the Control Technology Appendices volume.  Discus-
sions of current commercial applications, performance, and the basis for both
the performance and cost estimates are described there.
     Limitations in the available data base are discussed  in Section 5.  The
section is organized such that the data bases on both synfuel-unique primary
streams and on the applicable control  unit  alternatives  are covered.   The user
will find the counterpart base plant waste  streams arranged by medium.   This
section covers the main base plant waste streams and associated  secondary
streams from  potential control applications.
                                      12

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                                                             Section 2
                                                             Process Overview
                                 SECTION 2
                       PROCESS DESCRIPTION OVERVIEW

     This section presents a brief description of the process operations and
non-pollution control auxiliary processes expected to be included in Koppers-
Totzek (K-T) based indirect liquefaction facilities.  It also identifies the
major uncontrolled waste streams associated with those operations and pro-
cesses.  The operations and processes described in this section comprise
what is called an "uncontrolled base plant" or "base plant" since they are
all required to produce marketable products and by-products.  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 within the plant.  Base plant process operations discussed here in-
clude coal  preparation, coal gasification, gas purification and upgrading,
crude product synthesis and separation, and product upgrading.  Auxiliary
operations discussed include process cooling, product storage, raw water
treatment,  and oxygen production.  Integrated K-T facilities are ordinarily
more than self-sufficient with respect to process steam requirements.
Further, on-site generation of electric power is not expected to be econom-
ical in the U.S. as compared with the purchase of power.  However, on-site
auxiliary power generation using coal  as boiler fuel  is  examined in this
document in an attempt to cover a broad range of possible plant configura-
tions.   Capital  investment and operating costs for the base plant are also
summarized.
     Figure 2-1  presents a simplified block diagram of a K-T based synthesis
gas production facility.  The process operations associated with the synthe-
sis of Fischer-Tropsch liquids, 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 designs for existing facilities, and con-
ceptual  and proposed designs.   They are believed to reasonably represent the
                                     13

-------
              COAL PREPARATION OPERATION
                 COAL GASIFICATION OPERATION
RUN OF
MINE COAL
-

RAW COAL
STORAGE

^

i
COAL
CRUSHING,
DRYING
AND
PULVERIZING
1 / STEAM — >
j \ PREPARED COAL — *•
• | OXYGEN — *•
1 ' QUENCH WATER — *
COAL
GASIFICATION
1
1
1.
1
1
                       GAS PURIFICATION AND UPGRADING OPERATION
             GAS COOLING
             AND DUST
             REMOVAL
 NOX
 REDUCTION
RAW GAS
COMPRESSION
AND COOLING
CYANIDE
WASH
                                         BYPASS GAS
               H2S
               REMOVAL
SHIFT
CONVERSION
  CO2
  REMOVAL
TRACE
SULFUR
REMOVAL
SULFUR-FREE
SYNTHESIS
GAS
          Figure 2-1.  Simplified flow diagram for K-T based synthesis gas  production

-------
SULFUR-FREE
SYNTHESIS
GAS
                     FISCHER-
                     TROPSCH
                     SYNTHESIS
METHANOL
SYNTHESIS
                     METHANOL
                     SYNTHESIS
                      MOBIL
                      M-GASOLINE
                      SYNTHESIS
                                          PRODUCT
                                          SEPARATION AND
                                          UPGRADING
PRODUCT
SEPARATION AND
UPGRADING
PRODUCT
SEPARATION AND
UPGRADING
                      F-T SYNTHESIS
                      PRODUCTS
METHANOL
SYNTHESIS
PRODUCTS
MOBIL M-GASOLINE
SYNTHESIS
PRODUCTS
     Figure  2-2.   Simplified flow diagram for conversion of synthesis  gas  to  liquids

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Section 2
Process Overview
configuration options that are likely to be incorporated into the first

generation facilities built in the U.S.
                                     16

-------
                                           Section 2
                                           Feed Characteristics/Product Slate
2.1  COAL FEED CHARACTERISTICS AND PRODUCT SLATE
     A wide variety of domestic coals are potential  feedstocks  for K-T based
synthetic fuels facilities.  In general,  specific characteristics of the coal
feedstocks will determine the characteristics of process and waste streams.
To date, the North Alabama Coal Gasification Consortium has performed large
scale K-T gasification tests only with an Illinois No.  6 coal.  Thus, an
Illinois No. 6 coal was chosen for examination in this  PCTM to provide a basis
for sizing and characterizing base plant process and waste streams and eval-
uating waste stream control options and costs.  Characteristics of the base
plant Illinois No. 6 coal are summarized in Table 2-1.   The effects of differ-
ing feed coal characteristics, particularly with respect to waste stream
generation rates and characteristics, are discussed qualitatively and, to an
extent consistent with available data, quantitatively in Section 3.
TABLE 2-1.  PROXIMATE AND ULTIMATE ANALYSES OF BASE PLANT ILLINOIS NO. 6 COAL

	Analyses	Composition	
         Proximate Analysis, wt %
             Moisture                                     10.2
             Volatile matter                              34.7
             Fixed carbon                                 46.0
             Ash                                           9.1
         Higher Heating Value, MJ/kg  (as  received)        26.5
         Ultimate Analysis, wt % (dry basis)
             Carbon                                       71.5
             Hydrogen                                      4.8
             Nitrogen                                      1.4
             Sulfur                                        3.1
             Chloride                                      0.28
             Ash                                          10.1
             Oxygen (by difference)                        9.0
                                      17

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Section 2
Feed Characteristics/Product Slate
     In developing the base plant material  flow estimates, a fixed coal  feed
rate of 6682 Mg per day (dry basis) to gasification corresponding to 120 TJ/
day synthesis gas was used.  In addition to the gasifier coal  requirements,
some K-T based synfuels facilities may include on-site coal-fired auxiliary
boilers for power generation.  Coal requirements for any such  boilers will
depend upon the amount of purchased electricity from off-site  sources.
Boiler fuel requirements could also be offset by using high energy process
waste gases as fuel.  Due to the large number of variables that affect the
auxiliary boiler coal requirements, it is difficult to estimate the quantity
of or need for boiler feed coal for each type of synfuels plant examined in
this manual.  For facilities which are self-sufficient in energy, auxiliary
boiler energy requirements for electric power are expected to  range from
about 4 to 26% of the coal energy  input to the gasifier.  It should be noted
that most plants are potentially self-sufficient with respect to steam and,
depending upon the cost of electric power, an on-site power boiler may not
be needed at all.
     Typical upgraded product slates for the K-T based synfuels plants ex-
amined in this PCTM  are summarized in Table 2-2.  As  indicated in this table,
the quantity and energy content of the products from  each type plant  varies
even tnough  tne  same quantity of synthesis gas  is assumed in all cases
(i.e., the same  coal feed  rate to  gasification  for all cases).  This  is a
reflection of the different  energy conversion efficiencies associated with
the three different  synthesis operations examined.  The only K-T based in-
direct liquefaction  facility proposed in the U.S.  (The North Alabama  Coal
Gasification Consortium Project) is currently designed for methanol  produc-
tion.
                                     18

-------
TABLE 2-2.   ESTIMATED PRODUCT/BY-PRODUCT SLATE FOR K-T  BASED  PLANTS*

Product/ Methanol Synthesis
By-Products Mg/day TJ/day
Gasoline
Diesel Oil
Fuel Oil
LPG
SNG
Alcohols 4710 113
Sulfur 202
Total 4910 113
Mobil M-Gasoline
Synthesis
Mg/day TJ/day
1750 81.0


236 11.7


202
2190 92.7
Fischer-Tropsch
Synthesis
Mg/day
992
201
58.9
74.6
798
171
202
2497
TJ/day
46.9
9.45
2.71
3.72
34.8
5.38

103.0

 Coal  feed  rate  to gasification  is  G682 Mg per day (dry basis) which
 corresponds to 120  TJ/day of synthesis gas.
                                   19

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Section 2
Base Plant
2.2  BASE PLANT DESCRIPTION
     Base plant process operations consist of coal  preparation, coal  gasifi-
cation, gas purification and upgrading, crude product synthesis and separa-
tion, and product upgrading.  In addition, the auxiliary processes required
to support a fully integrated, self-sufficient, liquid fuels production
facility would include raw water treatment, power generation, and oxygen
production.  These processes and their associated waste streams are described
briefly in this section.  Detailed descriptions are presented in Section 3.
2.2.1  Coal Preparation
     The coal preparation operation in a K-T based synfuels facility will be
similar to those found in other coal-based plants such as pulverized coal-
fired power plants.  Equipment is provided to receive, transport, and store
coal, and to prepare pulverized coal for gasification and consumption in on-
site power boilers.  Coal is received by conveyor, train, barge, or truck and
is stored in either an active or inactive  (emergency) storage pile, as neces-
sary.  Coal from storage is prepared for gasification/combustion by screen-
ing, crushing, drying, and  pulverizing to  a size predominantly less than
0.1 mm.  Prepared coal moisture contents of 1 to 2% are required for gasifi-
cation of bituminous coals  and 8 to 10% are required  for gasification of
lignites.  Dried and sized  coal is stored  in silos and transported to gasi-
fiers  and boilers as required.
     Major waste streams associated with  the coal preparation  operation  are
storage  pile runoff; fugitive dust emissions from coal storage and transport;
and  dust from  coal screening, crushing, and pulverizing.  Storage  runoff
tends  to contain high  levels  of suspended  and  dissolved solids and can  be
quite  acidic in  the case of Midwestern and Eastern coals.   Dust  from coal
preparation  consists of  natural soil and  overburden material as  well as  coal.
                                     20

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                                                                  Section 2
                                                                  Base Plant
2.2.2  K-T Coal Gasification
     The K-T process involves low pressure (slightly above atmospheric), en-
trained-flow slagging coal gasification in the presence of steam and oxygen.
Flame temperatures may range from 2000-2300K during gasification with re-
actor temperatures of 1510-1860K.  The gasifier is a water-cooled steel
vessel with a refractory lining, which, in the most common two-headed config-
uration, resembles an ellipsoid with horizontally opposing burners at the
apices.  The newest installations (three gasifiers each at Ramagundam and
Talcher, India) employ four-headed gasifiers which resemble two intersecting
ellipsoids with burners located 90 degrees apart at each of the four apices.
Coal is introduced continuously into the gasifier through screw feeders at
the burner heads and then entrained in a stream of low pressure steam and
high purity oxygen.  Partial oxidation reactions occur rapidly within the
central portion of the gasifier; coal residence time is less than a second.
Raw product gas and entrained dust exit the gasifier vertically upward
through a waste heat boiler system producing high pressure saturated steam.
Molten slag exits the bottom of the gasifier and falls into a quench tank
where circulating cooling water causes it to shatter into granular form.
Slag is removed from the quench tank by a drag chain conveyor on which de-
watering occurs prior to subsequent slag disposal.
     Waste streams associated with the gasification operation are quenched
slag and transient waste gases.  K-T slag is a coarse, pebble sized material
which is physically stable and essentially inert.  Quenched slag has about
the same composition as the parent coal ash and retains about 10% moisture.
Depending upon the quench water quality, and whether the slag is rinsed,
contaminants such as NhL and SCN~ may be present in the slag moisture.
Transient gases unsuitable for processing into synthetic liquids may be
generated for short periods of time (less than 1/2 hour) during startup,
shutdown, and unscheduled transient operations.  These waste gases will vary
in composition but are similar to either gases from heavy oil  combustion or
                                     21

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Section 2
Base Plant
raw K-T product gas depending upon the gasifier conditions during the parti-
cular transient period.
2.2.3  Gas Purification and Upgrading
     The gas purification and upgrading operation consists of (1) gas cool-
ing and dust removal; (2) NO  reduction; (3) raw gas compression and cooling;
                            X
(4) cyanide washing; (5) shift conversion; (6) acid gas removal; and (7)
trace sulfur removal.
Gas Cooling and Dust Removal
     Hot raw gas from the waste heat boiler is cooled and scrubbed of en-
trained dust in two stages by means of direct water contacting.  Final de-
dusting is provided by a wet electrostatic precipitator.  The collected dust
slurry is pumped to settling basins for thickening.  Most of the clear water
overflowing the settlers is indirectly cooled and recycled.  The settler
underflow is filtered to produce dewatered dust  (up to 50% moisture) and
filtrate which is  combined with a portion of the clarifier overflow as blow-
down for controlling the buildup of dissolved components within the washer
system.
     Waste streams  associated with the gas cooling and dust removal process
are dewatered  dust and blowdown.  Gasification dust consists primarily of
coal ash and unreacted carbon.  The dust  is combustible and has leachable
components.  In addition, moisture associated with the dust will be similar
in  composition to  the washer blowdown, containing contaminants  such as NH^,
CN~, SCN", S^, SOjj,  Cl",  and other  species.
NOX Reduction
     The NO  reduction  unit catalytically hydrogenates nitrogen oxides  and
           X
oxygen present in  the  raw synthesis gas to  eliminate  associated  fouling  on
compressor blades  and  in the acid gas  removal  system.  Although  such  a  unit
is  currently in use at  an operating K-T based  facility, details  regarding

                                     22

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                                                                  Section 2
                                                                  Base Plant
unit performance and reaction chemistry are not available.  The only waste
stream expected from this unit is spent cobalt molybdate catalyst which will
periodically require disposal.
Raw Gas Compression and Cooling
     Koppers-Totzek technology involves coal gasification at essentially
atmospheric pressure.  However, downstream operations such as cyanide wash,
shift conversion, acid gas removal, and liquid product synthesis are more
efficient and economical at elevated pressures.  Therefore, raw gas from
cooling and dust removal is compressed to about 3 MPa prior to subsequent
treatment.  The temperature rise of the gas during compression is controlled
by intercoolers and an aftercooler, consistent with materials limitations
and temperature requirements of downstream processes.
     The principal waste stream from raw gas compression and cooling is com-
pression condensate.  Contaminants expected to be present in the condensate
include NH^, Cl", S=, SCN", and CN".
Cyanide Wash
     Hydrogen cyanide and any residual ammonia present in the raw synthesis
gas are removed by absorption in either water or cold methanol.  In the case
of a water-based cyanide wash, rich wash water from the absorber is flashed
to atmospheric pressure yielding depressurized wash water and a sour flash
gas.   In the case of a methanol-based cyanide wash, rich methanol from the
absorber is regenerated by depressurization and indirect heating to also
yield a sour flash gas.  Water vapor coabsorbed with the cyanide is re-
covered from the process methanol by distillation.
     Major waste streams associated with a water-based cyanide wash process
are depressurized wash water and sour flash gas.  Depressurized wash water
is expected to contain CN", S~, and traces of NH».  Sour flash gas from a
water-based cyanide wash is expected to consist primarily of CCu and H2S

                                    23

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Section 2
Base Plant
with lower levels of HCN.  The major waste stream associated with a methanol-
based cyanide wash process is sour flash gas.  Sour flash gas from a methanol-
based cyanide wash is expected to consist primarily of H2S, CO, HCN, C02,
COS, H2, and methanol vapor.
Shift Conversion
     Gases suitable for feed to methanol synthesis or hydrocarbon production
via Fischer-Tropsch synthesis should have somewhat greater  than a 2:1  ratio
of \\2 to CO and no more than a few percent C02-  The H2  to  CO ratio  in raw
K-T gas typically ranges from 1:2 to 1:2.5, well below the  ratio required  for
liquids synthesis.  Thus, a shift conversion  step is a necessary part  of the
gas upgrading.  All  commercial  scale  K-T  based coal gasification facilities
employ a shift conversion unit  which  follows  raw gas sulfur removal  and
precedes C02 removal, and this  approach has been incorporated into the
base plant design.  This approach enables the  use of conventional iron-
chromium or copper-zinc shift catalysts.  Also, due to the favorable
HpS to C02 ratio before shift conversion, it  facilitates  production of
an FLS-rich offgas for economic sulfur  recovery.

     Waste streams  produced  by  shift conversion are  spent shift catalyst
which periodically  requires  replacement  and  shift condensate  blowdown  which
is expected  to  be reused as  makeup water to  the gasification  quench  circuit.
Acid Gas Removal
      Removal  of hUS and other sulfur compounds present in the raw K-T gas
 is  necessary  to prevent catalyst poisoning in subsequent shift conversion,
 and methanol  and Fischer-Tropsch synthesis operations.  Bulk removal of C02
 is  necessary  to obtain a composition meeting the stoichiometric requirements
 for synthesis feed gas.  There are several acid gas removal processes which
 have been demonstrated in coal gasification or similar applications.  However,
                                       24

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                                                                  Section 2
                                                                  Base Plant
only the two-stage selective Rectisol process has been included in the base
plant design, since all commercial scale K-T based coal gasification facili-
tates utilize two-stage selective Rectisol units and the only K-T based in-
direct liquefaction facility proposed in the U.S. (The North Alabama Coal
Gasification Consortium Project) is also expected to use this process.
     Rectisol is a physical absorption process using low temperature methanol
as a solvent.  In two-stage selective Rectisol systems, sulfur compounds are
removed from the raw gas prior to shift conversion and subsequent C02 removal.
This facilitates high process selectivity due to the favorable HUS to CCU
ratio before shift conversion.  Sulfur laden methanol from sulfide absorption
is enriched by flashing and stripping a portion of the absorbed C02 and then
regenerated in a hot stripper to produce a sulfur-rich offgas typically con-
taining 25 to 35% H2S.  Carbon dioxide laden methanol from the C02 absorber
is regenerated by flashing and stripping with N2 to produce a C02-rich off-
gas.  An additional  waste stream from the Rectisol system is still bottoms
from a methanol/water distillation unit which controls moisture buildup in
the methanol solvent.
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 of less
than 0.1 ppmv total sulfur species in the synthesis feed gas, but ZnO provides
for temporary removal  during periods of Rectisol process upsets.  Periodi-
cally, sulfur guard material must be decommissioned and replaced.  This gen-
erates a solid waste consisting of spent ZnO/ZnS.
2.2.4  Product Synthesis
     Methanol synthesis and hydrocarbon production via Fischer-Tropsch (F-T)
synthesis can be represented by the following reaction:
                                     25

-------
Section 2
Base Plant
             CO + 2H2  -*•  CH3OH + heat (Methanol  Synthesis)

     nCO + (2n + 0.5x) \\2  +  CnH2n+x + nH20 + heat (F-T Synthesis)

where n ranges from 1 to about 20, x = 2 for paraffins and x = 0 for olefins.
The mix of F-T products obtained (i.e., the range of n and x values) is
dependent upon several factors including the reactor design, temperature,
pressure, and type of catalyst used.  Synthesis gas usually contains some
C02 in addition to CO and Hp.  Because synthesis catalysts are also active
for the hydrogenation of COo, the presence of C02 does not create  problems
as long as the synthesis gas contains the proper ratio of H2/(CO + C02).
Methanol synthesis employs Cu/Zn-based catalysts at 470K and 3.5 to 7.0  MPa
while F-T synthesis  proceeds over iron-based catalysts at 600K and 2.3 MPa
(fluidized bed reactors) or 500K and  2.7 MPa  (fixed bed reactors).

     Mobil M-gasoline synthesis from methanol can be represented as follows:
          nCH3OH  ->   (CH2)n + nH20  (Mobil M-gasoline Synthesis)

This process employs  zeolite-based catalysts and operates at about 570K  and
2.2 MPa.
     The crude liquid fuel products  of methanol, F-T, and Mobil M-gasoline
synthesis processes  will require upgrading  (probably onsite) to yield  final
products which are marketable as substitutes for petroleum-derived fuels.
This is particularly  true for motor  gasolines, where crude coal-derived
gasoline fractions would not meet octane  requirements  for  the  retain market
in the U.S.   F-T and Mobil M-gasoline  products could be upgraded by catalytic
alkylation of  the C3~C4 fraction  to  yield gasoline-blend hydrocarbons  and
commercial grade LPG by hydrotreating  (in the  F-T  case) for  destruction  of
olefins and  oxygenated organics,  by  catalytic  reforming to  produce more
cyclic and branched  chain hydrocarbons,  by  C5/Cg isomerization  to  increase

                                      26

-------
                                                                   Section 2
                                                                   Base Plant
 the  anti-knock  quality  of  pentanes  and  hexanes,  and by catalytic polymeriza-
 tion to convert propene/butene  fractions  into  higher molecular weight gaso-
 line blending compounds.   All of  these  upgrading processes  will  utilize con-
 ventional  petroleum  refinery  technology.   Since  the feed streams to these
 upgrading  processes  in  an  indirect  liquefaction  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 charac-
 teristics  and pollution control alternatives for product upgrading processes
 are  not specifically discussed  in this  PCTM.
      All of the synthetic  liquid  fuels  synthesis processes  generate a purge
 gas  containing  compounds such as  unreacted carbon oxides, hydrogen, methane,
 and  methanol.   Several  options  are  available to  handle the  purge gas in-
 cluding use as  an on-site  fuel, reforming to generate additional synthesis
 gas, or conversion of the  residual  hydrogen and  carbon oxides into methane
 to produce SNG.  Because supplemental fuel may be required for power genera-
 tion in  all synthesis  cases,  use  of these purge  gases as an on-site fuel was
 selected  for analysis  purposes  in this  PCTM.   In actual practice, the deci-
 sion regarding  the disposition  of synthesis purge gases involves site- and
 design-specific considerations  which  are outside the scope of this manual.
      A variety of waste streams are associated with  liquid product  synthesis
 processes,  exclusive of upgrading processes.  Major waste streams  from  F-T
synthesis  include spent F-T and methanation catalysts, methanation  catalyst
decommissioning  offgases, SNG  dehydration offgases, carbon dioxide offgases,
condensates, and wastewaters.  Major waste streams from methanol  synthesis
include spent catalyst and  synthesis condensate.  Major waste streams
from Mobil  M-gasoline synthesis  include spent methanol and Mobil  catalysts,
Mobil catalyst regeneration offgases, and wastewater.
                                      27

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Section 2
Base Plant
2.2.5  Auxiliaries
     The major additional  auxiliary processing units  required for self-suffi-
cient K-T based synfuels facilities are:   (1)  on-site boiler for power gen-
eration; (2) makeup water treatment facilities; (3)  process  cooling water
system; (4) liquid product/by-product storage  facilities;  and (5) oxygen
production unit.
     The most significant potential source of  waste  streams  from the auxiliary
processes is  the boiler.  The boiler flue gases are particularly important be-
cause the boilers will generally be coal-fired and are therefore potentially
major sources of SO , NO , and particulate emissions.  In  addition to flue
                   X    X
gases, waste streams resulting from the boilers include blowdown condensates
and bottom ashes.  It should be again noted that most plants are potentially
self-sufficient with respect to steam and, depending upon  the local avail-
ability and cost of electric power, an on-site power boiler may not be needed.
     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.  Evaporated volatiles,
drift, and cooling tower blowdown are the major waste streams from the cool-
ing water system.  Evaporative emissions are the major waste streams from
product/by-product storage facilities.
2.2.6   Fugitive  and Miscellaneous Wastes
      In  addition to  the waste  streams associated  with  specific  processes,
 there  are  three general categories  of wastes  which are of non-specific
 origin.   These  categories  are  fugitive organic emissions, non-process/
 intermittent wastewater streams, and equipment cleaning wastes.   There  are
 many  potential- sources  of  fugitive  organic  emissions in an  indirect  coal
 liquefaction plant.   These include  pumps, compressors,  valves,  flanges,  and
 pressure relief devices.   Non-process waste streams  include fluid leaks  from
 sources  such as pump  seals,  valves,  and  flanges.  In addition,  drainage

                                     28

-------
                                                                   Section 2
                                                                   Base Plant
resulting from emergency process fluid discharges or process area washdown/

cleanup activities will  contribute additional  intermittent aqueous wastes.

The two primary sources  of equipment cleaning wastes in an indirect lique-

faction facility are process equipment and boiler cleaning wastes.
                                     29

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Section 2
Costs
2.3  BASE PLANT CAPITAL INVESTMENT AND ANNUALIZED OPERATING COSTS
     In order to assess the relative impact of the costs of pollution con-
trols on the total plant cost, approximate costs for uncontrolled base
plants were developed.  Both capital and operating costs for K-T plants were
estimated and are presented in Tables 2-3 and 2-4, respectively.  Details
of the costing methodology are presented in Appendix A.   These base plant
cost estimates are used subsequently in Section 4 to evaluate the relative
magnitude of costs for individual pollution control technologies; however,
since control systems for an integrated facility are not evaluated in this
manual, the total relative cost impact of pollution control has not been
evaluated.
  TABLE 2-3.  CAPITAL COSTS FOR UNCONTROLLED K-T BASED INDIRECT LIQUEFACTION
              PLANTS*

Item
Installed cost
Contractors Overhead and Fee
Engineering and Construction
Contingency
Subtotal, Facility Cost
Interest during Construction
Working Capital
Total Capital Investment
Capital Costs
Methanol
603
18
151
121
893
201
17
1111
, 106 Dollars
Fischer-
Tropsch
714
21
178
143
1056
238
20
1314
(1980 Basis)
Mobi 1
M-Gasoline
657
20
164
131
972
220
_17
1209

  Capital cost estimates are based upon estimates published in references
  1, 2, 3, 4, 5, and 6.  Published estimates were scaled to a plant capacity
  of 6682 Mg dry coal per day to gasification.  To the extent that they could
  be identified, capital costs associated with pollution controls were deleted
  from published cost estimates.  Details of the costing methodology are pre-
  sented in Appendix A.
                                     30

-------
                                                                  Section 2
                                                                  Costs
   TABLE 2-4.   ANNUALIZED COSTS FOR K-T BASED INDIRECT LIQUEFACTION PLANTS*


Coal
Water
Other
Total


, Catalyst, and Chemicals*
Operating Costs*
Operating Cost
Capital Charges
Total Annual i zed Cost
Annual
Methanol
98
4
53
155
191
346
ized Cost,
Fischer-
Tropsch
114
4
63
181
226
407
106 Dollars
Mobi 1
M-Gasoline
95
4
51
150
208
358

  *
   Annual operating costs relating to "water, catalyst, and chemicals"
   and "other operating costs" are based upon published cost estimates for
   a  K-T  based methanol production facility (3).   Published estimates were
   scaled directly to a plant capacity of 6682 Mg dry coal per day to gasi-
   fication.  Insufficient details were available to enable adjustment, if
   any is required, for F-T and Mobil  M-gasoline synthesis cases or to deduct
   the annual operating costs for pollution controls.  Details of the costing
   methodology are presented in Appendix A.
     Installed costs are based upon published cost estimates for K-T based
methanol  and hydrogen production facilities (3,4).  Published cost data were
adjusted to reflect differences in costs for methanol, F-T, and Mobil M-
gasoline synthesis processes (1,2,3,5,6).  To the extent that pollution con-
trol  costs could be quantified, they were deleted from published installed
costs.  The resulting installed cost estimates were then scaled to the base
plant capacity using a scaling exponent of 0.8.   For analysis purposes, the
adjusted base plant installed costs were escalated to 1980 dollars using the
Chemical  Engineering (CE) plant cost index.   Total uncontrolled base plant
capital  investments were estimated to be $1.1, $1.3, and $1.2 billion  (1980
basis) for the methanol, F-T, and Mobil  M-gasoline synthesis cases, respec-
tively.   Differences among the estimated capital investment costs derive

                                     31

-------
Section 2
Costs
primarily from differences in costs of the synthesis operation and, to a
lesser extent, differences in on-site boiler costs.
     The total operating costs are based upon the annual coal cost and pub-
lished cost estimates for "water, catalyst, and chemicals" and "other opera-
ting costs" in a K-T based methanol production facility  (3).   Published
operating cost estimates were scaled directly on the basis of plant capacity
and escalated to 1980 dollars.  Published cost estimates for "water, catalyst,
and chemicals" and "other operating costs" relate specifically to a methanol
production facility; however, no adjustment has been made for F-T and Mobil
M-gasoline synthesis cases, if any is required, since insufficient details
of these estimates are available to do so.  Similarly, the annual operating
costs of pollution control equipment have not been deducted from cost esti-
mates for "water, catalyst, and chemicals" and "other operating costs" since
insufficient  details of these estimates are available to do so.
      It should be noted that annual coal costs and annualized capital charges
comprise about 84% of the total annualized cost.  Therefore, uncertainties
associated with estimated costs for "water, catalyst, and chemicals" and
"other operating costs" are not expected to have a major impact on  the esti-
mated total annualized cost.   Total annualized costs were estimated to be
$346, $407, and $358 million for  the methanol, F-T, and Mobil M-gasoline
synthesis cases, respectively.
                                      32

-------
                                                            Section 3
                                                            Detailed Charac.
                                 SECTION 3
            PROCESS DESCRIPTION AND WASTE STREAM CHARACTERIZATION

     This section defines the basic operations and auxiliary processes assoc-
iated with Koppers-Totzek (K-T) based indirect liquefaction facilities, and
the characteristics of major associated process and waste streams.  Material
flow estimates are also presented to provide pertinent information relating
to the magnitudes of the various waste streams and their environmental con-
trol needs.  Operations covered by this manual are shown schematically in
Figures 3-1 and 3-2.  These operations include coal preparation, coal gasi-
fication, gas purification and upgrading, crude product synthesis and sep-
aration, and product upgrading.  Auxiliary processes are shown in Figure 3-3
and include all of the operations which may be required to support a fully
integrated, self-sufficient, liquid fuels production facility.  These pro-
cesses include raw water treatment, oxygen production, and product storage.
Integrated K-T facilities are ordinarily more than self-sufficient with
respect to steam requirements.  Also, on-site power generation is not expected
to be economical in the U.S. as compared with the purchase of power.  However,
on-site power generation using coal as boiler fuel is examined in this docu-
ment in an attempt to cover a broad range of possible plant configurations.
Stream numbers have been provided in the figures for major process streams
and all waste streams to clarify stream identification in subsequent sec-
tions.  A stream identification listing and cross referencing indicies are
provided in Section 3.8.  Figures 3-1 through 3-3 are based primarily upon
published designs for existing facilities (e.g., the AECI Limited facility
at Modderfontein, Republic of South Africa) and conceptual and proposed de-
signs (e.g., the North Alabama Coal Gasification Consortium Project).  They
are believed to reasonably represent the configuration options that are  likely
                                     33

-------
FUGITIVE      FUGITIVE
DUST        DUST
                                                            DRVER
                                                            OFF GAS
FUGITIVE
DUST
FUGITIVE
DUST
CJ
         PREPARED
         COAL







/~\
RUN OF /T\ fe RAW COAL ^ COAL CRUSHING k -
MINE COAL V^/ STORAGE AND TRANSFER *"
„,„ ,. ~|
1 | 	


^
WASTE GAS
t
,208,
1
HAI DRviittr » COAL . . PULVERIZED
OAL DRYING » PULVERIZING * COAL STORAGE
	 	 ., . * 1

V'
PREPARED COAL
TO BOILER



                                                                                                      L H2S RICH
                                                                                                      I OFF GAS
LEGEND
•_ ^ mm Indicates nte-rt
NU I C Trace iui'ui .Cp
aad'^MfeTO?!
itrent flow
t'eamo* RECTlSOL
                                                                    "SPENT SULFUR
                                                                    GUARD
       Figure  3-1.  Operations associated with  synthesis gas  production in  K-T based indirect liquefaction
                     facilities

-------
oo
en
                                                                                                      DEHYDRATION
                                                                                                      OFF-GAS
                                            FUEL GAS  CATALYST REGENERATION/
                                            TO BOILER  DECOMMISSIONING OFF-GAS

                                                     t
                                                                       WASTEWATER
                                                               CRUDE PRODUCTS
GASOLINE

MIXED BUTANES

PROPANE
                                      CATALYST * -(232)    (3)—». CONDENSATE
        Figure 3-2.    Synthesis  operations associated  with  K-T based  indirect  liquefaction  facilities

-------
                                                                                                                               EVAPORATIVE EMISSIONS PROM
                                                                                                                               PRODUCT STORAGE
CO
CTi
            RAW
            WATER '
                                                METHANATION
                                                CONOENSATE







HOLDING PONDS

(
RAW WATER
TREATMENT
i) d
+
SLUDGES


1
D
BOILER
FEEDWATER
MAKEUP
TREATMENT
/~\ ^
(301J 	 >-R
\^ w
MAKEUP
WATER


(X6) 	 ^E
l'^ D
COOLING
TOWER
                                                                            BOILER
                                                                            FEED WATER
                                                                    DEMINERALIZER
                                                                    REGENERATION
                                                                    WATESWATER


                                                                     PREPARED COAL-
                                                                    EVAPORATION/
                                                                    DRIFT
POWER
GENERATION
(SEE NOTEI
                                                                                                             BOILER F"LUEGAS
BOILER SLOWDOWN
                                                                                                             BOILER BOTTOM ASH
                   BOILER CLEANING WASTES
                                                       OXYGEN TO
                                                       GASIFIER
                                                                                                                              NOTE ON-SITE POWER GENERATION MAY
                                                                                                                                  NOT BE REQUIRED, DEPENDING ON
                                                                                                                                  THE AVAILABILITY AND COST OF
                                                                                                                                  LOCAL ELECTRICITY
                   Figure 3-3.    Auxiliary  processes  associated  with  K-T based  indirect liquefaction  facilities

-------
                                                            Section 3
                                                            Detailed Charac.
to be incorporated into the first generation K-T facilities built in the
U.S.
     Flow estimates for major process and waste streams are presented in
Table 3-1 for facilities based on an Illinois No.  6 coal.  The base plant is
sized for a fixed coal input to gasification.  Therefore, the material  flows
presented for gasification and gas purification and upgrading are identical
for all  three synthesis alternatives considered.  Since the overall thermal
efficiency of indirect liquefaction differs among synthesis routes, energy
to on-site auxiliary boilers for self-sufficient facilities will be strongly
dependent on the specific synthesis process.  To a lesser extent, this is
also true with respect to material flows through coal preparation and raw
water treatment.  Hence, process and waste streams associated with the power
boiler and most other auxiliary processes will  be synthesis specific.
    Numerical values presented in Section 3 are based upon both published
data and engineering estimates derived from published data and material
balance considerations.  Material flow estimate tables in this section gen-
erally contain both published data and engineering estimates.  Detailed
references are provided for published data in both the text and below each
table; values which are not referenced represent either summaries of published
data which cannot be referenced in summary format or engineering estimates.
                                     37

-------
    TABLE  3-1.   FLOWS OF MAJOR STREAMS FOR K-T BASED  INDIRECT LIQUEFACTION FACILITIES -  ILLINOIS NO. 6 COAL'
CO
00
Component Flows, kmol/hr
»2
CO
co2
N2 + Ar
CH4
S
Total Dry Gas
Moisture in Gas
Total gas, kmol/hr
Total Aqueous, m /hr
Total Dry Solids, Mg/hr
Quench Quenched Dewatered Raw Gas From
Prepared Coal Steam Oxygen Water Slag Dust Washer Cooler
Stream 2 Stream 3 Stream 4 Stream 5 Stream 207 Stream 209 Stream 7
5829
13699
1907
300
22
259
8430 22019
2082 964
2082 8430 22982
2.8 93 1.0 30
278 9.3 30
Washer Cooler
Slowdown
Stream 210









322

                                                                                                     (Continued)

-------
         TABLE 3-1.   (Continued)
        Component Flows, kmol/hr
Synthesis
  Feed
Stream 14
Fuel  Grade
 Methanol
Stream 108
  Methanol
Disti llation
 Wastewater
 Stream 229
    F-T SNG
Liquids and  LPG
Streams 100-107
   F-T
Wastewater
Stream 223
    Mobil-M
 Liquids  + LPG
Streams 109-111
 Mobil-M
Wastewater
Stream 233
         "2


         CO
                                     13664
   5719
         CO,
    610
CO
10
         CH,
              Ar
    307
     21
         Total Dry Gas

         Moisture in Gas
  20320
         Total Gas, kmol/hr


         Total Aqueous, m /hr


         Total Organic Liquids,
            Mg/hr
  20320
              0.2


              196
                 9.7


                 0.17
                     96
                     159


                     1.5
                                                    83
                                  110


                                  0.92
                                                                                                                    (Continued)

-------
TABLE 3-1.    (Continued)
Component Flows, kmol/hr
H2
CO
co2
N2 + Ar
CH4
S
Total Dry Gas
Moisture in Gas
Compression HCN HCN Flash Gas HCN Flash Gas
Condensate Wash Water (Water Wash) (Methanol Wash)
Stream 211 Stream 215 Stream 21 4a Stream 21 4b
0.5
4.4
20 1.2


2.3 7.9
22 16

HgS-Ricn
Offgas
Stream 216


269
6

255
535

Shift C02-Rich
Slowdown Offgas
Stream 218 Stream 219
46
101
8875
1041
1.2
0.1
10064

Rectisol
Still Bottoms
Stream 220








Total  gas, kmol/hr




Total  Aqueous, in /hr




Total  Dry Solids,  Mg/hr
                                                    22
                            16
535
                            17
238
                                                                                                           10064
                                                                                                                    (Continued)

-------
TABLE 3-1.   (Continued)

Coal to
Boiler-t
Component Flows, kmol/hr Stream 30
N2 + Ar
co2
°2
NOX
so2
Total Dry Gas
Moisture in Gas
Total Gas, kmol/hr
o
Total Aqueous, rr /hr 3.2
Total Dry Solids, Mg/hr 78.7
Boiler Boiler Boiler ,
Air to Flue Gas1" Bottom Ashf Fly Ash1"
Boiler"1" Stream 302 Stream 304 Stream 423
24356 24388
10 4597
6455 1065
12
69
30821 30133
651 2581
31472 32713

1.8 7.6

   For overview  purposes, only major streams and their principal components have been
   included.   Detailed stream characterization data are presented subsequently  in this
   section.
   These  streams are representative of the estimated maximum boiler size for a  K-T based
   indirect  liquefaction plant with a coal feed of 278 Mg/hr (dry basis) to the gasifier.

-------
 Section 3
 Coal  Preparation
3.1  COAL PREPARATION
     Run-of-mine (ROM) coal  is received from the mine via conveyor and stored
in an active storage pile which holds a five-day supply.   The five-day active
storage pile (40,000 Mg for methanol  synthesis case) normally provides the
gasifier feed.   Raw coal is also kept in an emergency storage pile contain-
ing a 30-day supply.  The 30-day emergency pile (241,000 Mg for methanol
synthesis case) is built up over a period of time, when coal  is not required
at the active storage pile, and is used if the coal supply from the mine is
interrupted for an extended period of time.  Coal storage piles for the
Fischer-Tropsch synthesis case are approximately 16% larger than the coal
piles for the methanol synthesis case.  However, coal piles for the Mobil
M synthesis case are approximately 4% smaller in size.  These changes in size
are due to the different coal feeds to the boiler in each of the three syn-
thesis cases.

     Because the K-T gasification process requires free flowing pulverized
coal, some level of drying during coal preparation is necessary for all  coals.
The extent of drying which is required is coal specific,  with residual mois-
ture levels of approximately 1 to 2%  required for bituminous  coals and 8 to
10% required for lignites.  Recent tests in Greece  (7) indicated that drying
of Illinois coal to a 1% moisture level might be  required.  The particle  size
of the feed coals to the K-T gasifier is predominantly less than O.lmm.   The
allowable portion of oversize coal is about 10%  in  the case of bituminous
coal, and 15 to 20% in  the case of lignites  (8)  .   The particle size  of
boiler feed coal is typically 70% less  than 0.075mm.  Table 3-2 presents  the
characteristics of  the  Illinois No.  6 coal under  consideration.

     A schematic diagram of the coal  preparation plant is presented in Figure
3-4.  Run-of-mine coal with a top size of 10.2 cm is transported to the pre-
paration plant by a belt conveyor.  It is then transferred through the feed
                                     42

-------
TABLE 3-2.  CHARACTERISTICS OF ILLINOIS NO. 6 COAL SELECTED FOR USE IN INDIRECT
            LIQUEFACTION BASE PLANT  (9,10)


Moisture
Volatile Matter
Fixed Carbon
Ash
C
H
0
S
N
Heating Value
MJ/kg
Major and Minor Elements in
(%, on moisture-free whole
Al
Ca
Cl
Fe
K
Trace Elements
(ppm, on moisture-free whol
As
B
Be
Br
Cd
Co
Ce
Cu
F
Ga
Ge
As Revised Basis (wt %)
10.23
34.70
46.0
9.15
64.16
4.34
8.1
2.81
1.21

26.63
Coal
coal basis)
1 . 20 Mg
0.92 Ma
0.28 Si
1 . 50 Ti
0.16
e coal basis)
1.0 Hg
132 Mo
1.6 Mn
17 Ni
<0.4 P
4 Pb
20 Sb
12 Se
79 V
4.5 Zn
6.0
Dry Basis (wt %)



10.19
71.47
4.83
9.02
3.13
1.35

29.67


0.04
0.060
2.45
0.06


1.1
7
20
14
29
10
0.1
1.3
20
43

                                     43

-------
   LEGEND:
   	INDICATES THE
       MAIN PROCESS
       FLOW
        INDICATES
        EMISSIONS
        FLOW
                                                         PARTICULATES
PARTICULATES
                                ROM COAL
                              STORAGE PILE
                                       TO MAIN BAGHOUSE
                                        RUNOFF
                         PARTICULATES (TO
                         MAIN BAGHOUSE)
                                                     SCREEN
                                                CRUSHER
                                   STORAGE
                                   SILO
PARTICULATES

    [205
                 PRODUCT
                 SILO
r
PULVERIZER
i
r
4-
i
r
THERMAL
DRYER

i
±
' i
-
PULVERIZER
' 1
r
1
                                                                   PRODUCT
                                                                   SILO
                    I
    TOGASIFIER 4~	'
                                     [204]

                                       PARTICULATES
I
1	^ TO BOILER
 Figure 3-4,   Waste streams  associated  with coal  preparation for  a K-T  based indirect  liquefaction
               facility -  Illinois No. 6 coal

-------
                                                            Section 3
                                                            Coal  Preparation
hopper to the raw coal  screens that make a size separation at 1.9 cm.  The
oversize coal (10.2 cm x 1.9 cm) is conveyed to double roll crushers where it
is reduced to a top size of 1.9 cm.  The undersize coal from the sizing
screens and the crusher product are transferred to storage silos by a belt
conveyor.  Coal from the storage silo is transported to the pulverizer after
it is ground to 70% minus 20 mesh.  The moisture content of the coal is re-
duced in the thermal dryer and the pulverizer from 10% to 1-2% for the K-T
gasifier.  Coal to the boiler does not require thermal drying since the
pulverizers reduce the moisture content from 10% to a desirable 4%.  The dry
ground coal from the pulverizers is transferred to the product silos by gravity
and then continuously fed to the boiler and K-T gasifier.  Coal preparation
mass flow estimates for the methanol synthesis case are presented  in Table
3-3.
     Major waste streams associated with the ROM coal storage and handling
operations are particulate emissions from storage (Stream 200), storage pile
runoff (Stream 201), particulate emissions from crushing/screening/transfer/
pulverizing (Streams 202, 203, 204), and particulate emissions from prepared
coal storage and feed (Stream 205).  Sources of these wastes streams are
shown in Figure 3-4.
     The quantities of fugitive particulates generated by the five-day active
and 30-day emergency storage piles are shown in Table 3-4.  Emissions from
coal storage piles have been investigated and results presented in several EPA
reports  (11,12,13).   Estimates for uncontrolled emissions from various acti-
vities were compiled from information given in the references indicated in
Table 3-4.   Environmental assessment studies data showed relative high total
suspended particulate values within 200 meters of the coal and refuse piles
when compared to 24-hour primary and secondary ambient air quality standards
(14,15).  Ambient concentrations decrease sharply at 500 to 600 meters downwind.
Particulate morphology tests showed that downwind particles were primarily a
quartz material rather than coal particles indicating that the source of
                                     45

-------
 Section 3
 Coal Preparation
participates is activity around the piles, not the coal itself.  The prepara-

tion plants were found to contribute no gaseous organic matter to the environ-

ment, other than trace amounts attributable to diesel truck activity around

the coal pile.

     TABLE 3-3.  COAL PREPARATION SECTION MASS FLOWS - METHANOL SYNTHESIS CASE

Stream
ROM Coal to
Screen*
Coal to Crusher*
Coal from Screen*
Coal from Crusher*
Coal to Storage
Silo*
Coal from Storage
Silo*
Coal to Product
Silos*
Coal to Gasifier*
Coal to Boiler1"
Hours per Day
of Operation
13
13
13
13
13
24
24
24
24

Dry
Mg/day
7225
4624
2601
4621
7225
7225
7225
6682
544
Illinois No..
Basis
Mg/hr
556
356
200
356
556
301
301
278
23
6 Coal
Moist Basis
Mg/hr
619
396
223
396
619
335
305
281
24

  These streams increase by approximately 16% for the Fischer-Tropsch (F-T)
  synthesis case and decrease by 3-6% for the Mobil  M synthesis case.

  Coal  to boiler increases by 215% for the F-T synthesis case and decreases
  by 48% for the Mobil  M synthesis case.
                                      46

-------
                                                          Section 3
                                                          Coal Preparation
   TABLE 3-4.  ESTIMATED FUGITIVE DUST EMISSIONS FROM COAL STORAGE PILES

Activity
Wind erosion*
Loading on+
Loading off*
Vehicular
activity5
TOTAL
Reference
12
13
13
13

Emission
Active Storage Piles
(5-day storage)
10
28
36
1

75
Estimates* (Mg/yr)
Emergency Storage Piles
(30-day storage)
57
28
36
6

128

 Based on a respirable emission factor of 6.4 mg of dust per kg/yr of coal
 stored
"^Assumed activity factor of 0.75, silt content of 0.5% and Thornthwaite's
 precipitation index (PE) of 93 for S.W. Illinois
^Assumed activity factor of 0.77, silt content of 0.5% and PE of 93
§Assumed activity factor of 0.5, silt content of 0.5% and PE of 93
^Emissions will increase by 16% for the Fischer-Tropsch synthesis case and
 decrease by 3.4% for the Mobil M synthesis case
     Runoff streams originating from coal storage piles have been character-
ized in detail during environmental assessment testing programs at two coal
preparation plants (14,15).  The assessment results indicated that runoff
water quality parameters complied with the most stringent state effluent
regulations for eastern and midwestern states.

     Laboratory leaching tests with raw coal  and 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 (16).
Assuming that this similarity carries over to the pollutant loadings gene-
rated by actual refuse and coal piles, the information available from refuse

pile pollutant analysis provides a source of data.  In addition, there are

                                     47

-------
Section 3
Coal Preparation
some data available on actual  effluents produced by high-sulfur coal storage
piles (17).  Information for these two sources, coupled with what is known
about the composition of the subject coal, allows at least a range estimation
of the composition of the storage pile runoff produced.
     Runoff from storage piles of Midwestern coals (such as the Illinois No.
6) and Eastern coals can be highly acidic, with pH values in the range of
2 to 4, if the runoff is allowed to remain in contact with the coal for long
periods of time.  Total suspended solids during storm runoff can be as high
as 2300 mg/L.  Sulfate concentrations may be in excess of 9000 mg/L.  Iron
concentrations can range from 23 to 1800 mg/L, while manganese concentrations
can range from 1.8 to 45 mg/L.  Other elements that are at concentrations of
potential concern include aluminum, mercury, arsenic, and zinc (17).
     At facilities utilizing either sub-butiminous coal or lignite, runoff
from the coal storage piles would be expected to be close to neutral, with
a pH slightly above 7.  Sulfate concentraions would probably be less than
1000 mg/L.   Iron and manganese concentrations would be expected 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 expected to be calcium and magnesium, with
concentrations in the ranges of 200 to 400 mg/L for calcium and 50 to 250
mg/L for magnesium (19).  Total suspended solids levels would probably be
higher than  those present in Illinois No. 6 runoff because of the tendency
of these coals to slake.
     Published data on particulate emissions for coal operations are limited
and were taken from surface coal mining and ore mining operations, the crushed
stone industry, and the manufacturing of coke.  Reported emission factors
(13,20) for specific operations within preparation plants are based on esti-
mates rather than actual data.  There is no consensus on the best available
values for use with specific coal preparation operations.  In one surface
mine study,  an average uncontrolled particulate emission factor of 0.2 kg/Mg

                                     48

-------
                                                         Section 3
                                                         Coal Preparation
of coal processed was used for loading and unloading activities in all modes
of transport  (21).  In another surface mine investigation, a factor of 0.05
kg/Mg  of  coal mined  was used for coal loading and unloading operations,
respectively  (20).  The moisture contents and coal types used in these
studies were  not specified, and thus no distinction can be made between
bituminous, sub-bituminous, and lignite coals.  However, it is commonly
reported  that western coals and lignites generate several times as much dust
as comparable amounts of eastern coal (22).
     Table 3-5 provides estimates of emissions generated during the specific
operations, such as unloading, crushing, and  screening.  The streams  assoc-
iated  with the estimated emission values are  shown in  Figure 3-4.
     In the absence of more specific data, simplifying assumptions were
necessary in preparing these estimates.   First, the same average factors
were used for similar operations, such as screening,  disregarding the effect
of particle sizes (i.e., the same factor is used for secondary and for terti-
ary screening).  Since the reported emission factor was based upon combined
crushing/screening operations, only 50% of the published factor was used for
emissions from screening alone or crushing alone.  In addition, the moisture
content of the coals from which the emission factors  were generated was un-
known; therefore, corrections for moisture content were not applied.
     The quantities  of particulate emissions  generated by the various  opera-
tions associated  with  the storage and subsequent handling of  the screened,
crushed coal  are  included in  Table 3-5.   As with crushing/screening emission
factors, no distinctions have been made  for differences in  particulate emis-
sions associated  with  lignite,  sub-bituminous, and bituminous coals.
     The emission factors used to calculate emissions  at transfer points  to
the gasifier  and  boiler feed  equipment are  the same as those  used for  trans-
fer points inside the  preparation plant.
                                     49

-------
                    TABLE 3-5.   PARTICULATE  EMISSIONS  FROM  COAL PREPARATION  (ILLINOIS  NO.  6 COAL)
en
o
Discharge
Stream
Number
202
202
202
202
202
203
203

203
203
204

204

204
205

205
205
205

206
Hours per
Day of
Emissions Source Operation
Loading
Transfer to screening
Screening
Transfer to crushing
Crushing
Transfer to silo
Transfer to silo
from screening
Transfer to storage
Inert gas purge
Transfer to pulverizer
and thermal dryer
Transfer to Pulverizer
from thermal dryer
Pulverizer
Transfer to product
silo
Transfer to boiler
Transfer to gasifier
Inert gas product silo
purge
Thermal dryer
13
13
13
13
13
13
13

13
13
24

24

24
24

24
24
24

24
Estimated Average
Emission Factors
Uncontrolled
kg/Mg
Negl igible
0.02 - 0.48
0.04*
0.02 - 0.48
0.04*
0.02 - 0.48
0.02 - 0.48

0.02 - 0.48
0.02 - 0.48-1-
0.02 - 0.48

0.02 - 0.48

Negligible
0.02 - 0.48

0.02 - 0.48
Negligible
0.02 - 0.48f

10
Reference
20
13
13
13
13
13
13

13
13
13

13

13
13

13
13
13

13
Feed Rate
As Received
Basis
Mg/hr
619
619
619
396
396
396
223

619
619
335

290

-
314

24
290
314

290
Uncontrol led
Emission
Rates
kg/hr

12.4

7.9

7.9
4.5

12.4
12.4
6.7

5.8


6.3

0.5

6.3


_
- 297*
25*
- 190*
16*
- 190*
- 107*

- 297*
- 297*
- 161*

- 139*

-
- 151*

- 11. 5§
-
- 151*

435
                       Emission factor as  reported for combined "secondary crushing/screening operations"   is 0.08 kg/Mg of coal
                       processed.  Assumed contribution from crushing is equal  to  that from screening  and  is  thus equal to 0.04
                       kg/Mg  of coal processed.
                      fAssume same emission factor as that  of transfer.
                      ^Emissions from these streams increase by approximately 16?:'-  for the Fischer-Tropsch  synthesis and decreases
                       by  3-4% for the Mobil^M  synthesis case.
                      Emissions from this stream increase  by 215% for the Fischer-Tropsch synthesis case  and decrease by 48%
                       for the Mobil-M synthesis case

-------
                                                             Section 3
                                                             Coal Preparation
Emissions from Thermal Dryers (Stream 206)
     In a thermal dryer, hot gas from a furnace is forced past wet coal in
the drying chamber to volatilize coal moisture.  Drying gas is generated by
combustion of coal or fuel gas.  In the case of coal combustion, dryer off-
gases would be similar in composition to flue gases from the boiler system
with respect to gaseous pollutants such as SO , NOV, and CO.  Particulate
                                             X    A
loadings would be higher due to entrainment of dried coal.  Low Btu fuel
gases available for coal drying purposes at this type of facility are expected
to be essentially free of sulfur and nitrogen compounds.  The gaseous pollu-
tants associated with use of these gases from thermal drying are NO  and CO.
                                                                   /\
The exact quantity of dryer offgases generated is dependent upon the quality
of dryer fuel used, ROM coal moisture, and residual coal moisture require-
ments.  The composition of dryer offgases with respect to SO. NOV, and CO
                                                            X    X
is dependent upon the quality of dryer fuel used, and is not unique to the
coal preparation operation; offgas compositions will be discussed in conjunc-
tion with auxiliary combustion processes (Section 3.6.2).   It should be noted
that offgases from coal drying may contain low levels of volatile organic
compounds (VOC), although essentially no data are available regarding such
emissions.
     The amount of coal particles entrained in the drying chamber exit gas
stream is significant.  One study estimated an uncontrolled particulate emis-
sion factor from thermal dryers to be 10 kg/Mg of coal  dried (23).   In order
to recover these substantial quantities of dry airborne product coal, mechan-
ical collectors are generally included as process equipment for thermal dryers.
Uncontrolled fugitive emissions from the dryer were calculated and are
assumed to be those from the mechanical collector outlet.  For a gasifier feed
rate of 290 Mg/hr uncontrolled emissions from the thermal dryer are estimated
to be 435 kg/hr.
                                     51

-------
Section 3
Gasification
3.2  COAL GASIFICATION
     Gasification consists of the partial oxidation of pulverized coal  to
produce raw synthesis gas.  The Koppers-Totzek (K-T) process is characterized
by low pressure (slightly above atmospheric), entrained-flow slagging coal
gasification, featuring rapid partial  oxidation of pulverized coal  in a
stream of oxygen and steam.  Flame temperatures may range from 2000-2300K
during gasification, with reactor temperatures of 1500-1900K (7,24,25,26).
The gasifier is a double-walled, water-cooled steel vessel with a refractory
lining.  Low pressure steam is generated in the water cooling system for
process use.  While older commercial installations utilize a two-headed
gasifier configuration resembling an ellipsoid with horizontally opposing
burners at the apices, the newest installations (three gasifiers each at
Ramagundam and Talcher, India) employ four-headed gasifiers.  The four-headed
configuration resembles two intersecting ellipsoids with burners located 90
degrees apart at each of the four apices.  Essentially all ranks of dried
coal (1 to 8% moisture) with ash contents of up to 40% can be gasified.
Four-headed K-T gasifiers are capable of processing up to 800 Mg of coal per
day.
     The K-T gasification process is depicted in Figure 3-5.  A mixture of
dried, pulverized coal, low pressure steam, and high purity oxygen are con-
tinuously injected  into the gasifier with injection speeds exceeding flame
propagation speeds  to prevent flash back.  Coal is  introduced into the gasi-
fier through screw  feeders at the burner heads.  This system provides for
(1) a  high degree of turbulence and mixing;  (2) continuous ignition should
one burner become temporarily blocked;  (3) flue gases being directed into
the center of the gasifier, thus minimizing  hot spots in  the refractory
lining; and  (4) unreacted coal  particles from one  flame region being gasified
in  the opposing region.   Reaction between the coal  and oxygen upstream of the
gasification zone is inhibited  by maintaining moderate temperatures in the
mixing nozzles through circulation  of cooling water.  The gasification

                                     52

-------
        RAW QUENCHED
        GAS TO DUST
        REMOVAL
                          SATURATED
                          STEAM (10 MPa)
   SATURATED STEAM (0.1 MPa)
  QUENCH WATER
        OXYGEN

  PREPARED COAL

         STEAM


 QUENCHED
 SLAG TO DISPOSAL
                                                              FEEDWATER
                                                              PREHEATER
                                                                  FEED
                                                                  WATER
                                                              VAPORIZER
                                                              WASTE
                                                              HEAT BOILER
   CLINKER
   OUTLET
QUENCH
WATER RETURN

SLAG QUENCH
WATER
                                       SLAG QUENCH TANK
Figure 3-5.  GKT's  gasifier with waste heat boiler  and  slag extraction  system
             (26,27)
                                       53

-------
Section 3
Gasification
reactions occur in a cocurrent stream of suspended coal  particles, with raw
product gas and entrained particles exiting the gasifier vertically.  Coal
residence time in the gasifier is less than one second.
     Coals vary widely in terms of their reactivity or degree of carbon con-
version to useful gas (CO plus hL) as a function of temperature in a K-T
gasifier.  Coals also differ greatly in their ash fusion temperatures and
molten ash viscosities.  The temperature of gasification for a particular •
coal in a  K-T gasifier is largely dictated by the coal ash properties since
a layer of slowly flowing molten slag must be maintained on the sides of  the
gasifier to protect the refractory lining.  Temperature control in the gasi-
fier is achieved by addition of moderating steam along with oxygen.  Lignitic
coals commonly show higher reactivities (low gasification temperatures for
high carbon conversion) at the temperatures needed for proper slag flow.
Bituminous coals require higher gasification temperatures than lignites to
obtain a high degree of carbon conversion, and thus the ash (slag) behavior
in  such coals is more critical.  Generally, lower rank coals will show
higher carbon conversions in a K-T gasifier than higher rank coals.  Unreacted
carbon along with a fraction of the original coal ash exits the gasifier  as
dust entrained in the hot raw product gas  (Stream 7).
     That  portion of the coal ash which impinges as molten slag on  the gasi-
fier walls eventually exits the bottom of  the gasifier into a quench tank.
Circulating cold water causes the slag to  shatter into a granular form, and
a continuous conveyor system removes  the granulated slag (Stream  207) from
the tank.  The relative amounts of coal ash exiting the K-T gasifier as
slag or  dust varies among coals.  The dust-to-slag ratio (carbon  free basis)
can be as  low as  1:10 for some lignites, and as  high  as 2:1 for some bitu-
minous coals.
     The composition of  K-T gas  has  been measured at  commercial facilities
gasifying  Indian  bituminous coal  (28), South African  sub-bituminous coal
                                      54

-------
                                                                Section 3
                                                                Gasification
(o,24,29), and Turkish lignite (8,30).  Gas characterization data are
also available from commercial-scale gasification tests performed with an
Illinois No. 6 coal (7) and with Char-Oil-Energy Development (COED) process
chars derived from Western Kentucky and Pittsburgh seam coals (25).  These
data indicate that the bulk composition of K-T gas is determined by the
water-gas equilibrium and the relative amounts of coal, steam,  and oxygen.
Raw gas consists of 55-65% CO, 25-30% H2> and 6-12% C02 on a dry basis.
Small amounts of CH. are present in K-T gas (ppmv levels) but no tars, oils,
phenols, or high molecular weight organics have been found.  Coal sulfur is
largely gasified forming H2S and COS at a ratio of about 9:1.  Traces of CS^
and S02 are also found.  A fraction of the original coal sulfur will also be
contained in the slag and dust in the raw gas.  Nitrogen in the coal is mostly
converted to elemental nitrogen (over 90%), although side reactions also lead
to the formation of NH^, HCN, and NO in the ppmv range.  Limited data indi-
cate that ammonia levels are higher with low rank coals than with high rank
coals, but the data do not show a convincing similar trend in the case of HCN.
     Water sprays are utilized at the gasifier outlet to reduce the gas tem-
perature to below the ash fusion temperature, approximately 1360-1500K.
This solidifies molten entrained dust to prevent its adherence  to waste heat
boiler tubes.  Raw product gas exiting the gasifier flows vertically through
a waste heat boiler system producing high pressure steam, thereby recovering
heat rejected by the gasifier, and cooling raw gas to approximately 570K.
Material flow estimates for the coal gasification operation are presented
in Table 3-6.
Quenched Slag (Stream 207) and Slag Quench Water
     K-T slag is a coarse, pebble sized material which is physically stable
and essentially chemically inert.   Due to the irregular surfaces/shapes
which form during slag solidification in the quench tank, the material can
be crushed and broken somewhat by handling and compacting.   Quenched slag
retains about 10% moisture.
                                     55

-------
                  TABLE  3-6.    MATERIAL FLOW ESTIMATES  FOR  K-T GASIFICATION  (ILLINOIS  NO.  6  COAL)1
01
01
Prepared Coal Steam Oxygen
Stream 2 Stream 3 Stream 4
kmol/hr kg/hr kmol/hr kg/hr kmol/hr kg/hr
H,
CO
co2
CH4
H2S
COS
cs2
so2
so=/s,o;
so3
02 8261 264342
HCN
HSCN
NO
NH3
N2 65 1817
Ar 104 4145
Cl 22 780
F 1.3 22
Total Dry Gas
H20 156.1 2810 2082 37500
Ash 28400
Coal (MAP) 250000
C 16565 198970
H 13343 13450
S 272 8710
0 1519 24308
N 268 3760
Total- kmol/hr 2082 8430
kg/hr 281210 37500 270303
Temperature(K)
Pressure(MPa)
Quench Water Quenched Slag
Stream 5 Stream 207
kmol/hr kg/hr kg/hr


0.4

0.001



0.4
0.03

0.01
0.004

0.16


2.2
0.07

5134 92496 1037
9245

48

38


5134
92496 10371
300
0.1
Raw Quenched Gas
Stream 6
kmol/hr Vol "•
5829 26.4
13699 62.1
1910 8.7
22 998 ppmv
229 1.0
26 1166 ppmv
2 89 ppmv
0.5 21 ppmv



2.6 118 ppmv

0.07 3 ppmv
4.0 180 ppmv
196 0.9
1 04 0.5
22 998 ppmv
1.3 58 ppmv
22047
7919
18351 kg/hr

10805 kg/hr Dust
30 kg/hr
419 kg/hr


29966
672242
450
0.1
                         The number of significant  figures shown in some cases do not  represent the degree of accuracy and are retained for material  balance
                         purposes only   Nevertheless, slight imbalances do appear as  a result of numerical  rounding.  Material flow estimates and stream composi-
                         tions are based upon published data and engineering estimates.  Tabulated data are  based upon references /, 8, 24, 2b, and M.

-------
                                                                Section 3
                                                                Gasification
     Slag from the gasification of Illinois No.  6 coal  has essentially the
same overall composition as that of the parent coal  ash.   The quenched slag
contains about 0.5% carbon by weight  (7).  Quenching of the slag is integral
with gasification and involves intimate contact with circulating water (e.g.,
from gas cooling and dust removal); hence slag from  the quench  tank is leached
of any readily soluble material.  Table 3-7 summarizes  the results  of leach-
ing tests on quenched slag from K-T gasification of an  Illinois coal at the
Nitrogenous Fertilizer Industry (NFI), Ptolemais, Greece (31).   The NhU,  SCN ,
and COD values shown in Table 3-7 reflect residuals  derived from washer cooler
water used for slag quenching.  Such species are not believed to be present
in measurable amounts when non-process water is used for quenching  or for
rinsing the quenched slag.

             TABLE 3-7.   RESULTS OF K-T SLAG LEACHING TESTS  (31)

Element
Ag
As
Ba
Cd
Cr
Hg
Pb
Se
NH3
SCN-
COD
Concentration
KCKA Lxtract AS
pH 5
<0.2
<8
<0.2
<0.1
<0.8
<0.004
<1
<8


in rng/kg SI
ag
TM Neutral Extract
pH 7
<0.2
<8
<0.2
<0.1
<0.8
<0.004
<1
<8
14
<2
100










                                     57

-------
Section 3
Gasification
     The slag generation rate in the example case is  about 9300 kg/hr.   About
30 kg of cooling (or quench)  water are needed for each kg of slag.   Since the
slag is essentially non-leachable, the quality of water leaving the quench
tank is determined primarily  by the quality of input  water.   In existing K-T
plants the input water is the same as input to gas cooling (see Section 3.3.1)
since slag and wash waters are treated together in common solids settlers
and direct contact cooling towers.  The slag quench flow in such systems
amounts to only a few percent of the total  water flow.  As mentioned pre-
viously, "clean" water may be used for slag quenching and/or slag may be
rinsed to minimize the slag loading of undesired species (e.g., CN  or NhL).
Thus, the slag quench water is not viewed as a separate waste stream but
rather as an integral part of the overall wash circuit.  In fact, the slag
quench tank may be a point of makeup to the water circuit.  The very small
amounts of pollutant species  actually contributed to  the water during slag
quenching exit the system with cooling and dust removal blowdown.
Transient Waste Gases (Stream 208)
     For short periods of time during startup, shutdown, and transient opera-
tion, gases are generated which are not of use in downstream processing.
Startup of a K-T gasifier generally features use of fuel oil and oxygen under
essentially stoichiometric conditions to accomplish gasifier heatup.  The
combustion gases are vented to the atmosphere through startup stacks.  Gen-
erally, less than one-half hour is needed to start a gasifier from a cold
state, and emissions during most of this period are representative of com-
bustion rather than gasification conditions.  Startup of a gasifier which is
still warm from earlier operation can be accomplished in as little as five
minutes.  During upsets or shutdowns, the gasifier system is flooded with
inert nitrogen to purge combustibles.  Thus, the entire gas volume of  the
gasifier/waste heat boiler system is  vented  to the atmosphere  in just a few
seconds.  These gases will contain all of the components of raw  K-T gas
(Table  3-6) along with  the purge  nitrogen.

                                      58

-------
                                                                Section 3
                                                                Gasification
     At present, no data are publicly available relating to characteristics
of transient gases or to the quantities which might be encountered in K-T
facilities.  All existing facilities are provided with vent stacks for such
gases, although no further control (e.g., flaring) is effected other than
discharge away from the immediate areas where personnel may be exposed.  The
transient waste gases are generally viewed as more of an occupational safety
problem than as a pollution problem since the actual mass emissions repre-
sented are very small on an average basis.  Since a relatively large volume
of such gases can be released in a very short period in a small area, K-T
plant designs reflect concern for safety of operating personnel.
                                      59

-------
Section 3
Purification
3.3  GAS PURIFICATION AND UPGRADING
     The gas purification and upgrading operation consists of:  (1) gas cool-
ing and dust removal  to remove some of the volatile contaminants (e.g.,
ammonia, chloride, fluoride, and some fraction of the cyanide) and all dust
from the raw K-T gas; (2) NO  reduction for control of traces of NOV present
                            A                                      X
in the raw gas; (3) raw gas compression and cooling to compress the raw K-T
gas to a pressure suitable for downstream operations; (4) shift conversion
to obtain the hydrogen to carbon oxides ratio required for liquid product
synthesis; (5) acid gas removal  for removal of sulfur compounds and carbon
dioxide; and (6) removal  of trace sulfur compounds which may be present in
the synthesis gas.
     Contaminants removed from the raw K-T gas during purification and up-
grading operations become components of various waste streams.  Thus, purifi-
cation and upgrading operations  generate several of the most important waste
streams in an integrated facility from the standpoint of waste characteristics
and volumes.  The ensuing sections provide details on the nature of specific
processes and their associated waste streams.
3.3.1  Gas Cooling and Dust Removal
     Raw K-T gas from the waste  heat boiler contains entrained dust which
must be removed prior to compression and downstream processing.  Because
primary dust removal  is effected by water washing, gas cooling is an integral
part of the dust removal  operation.  The gas cooling and dust removal opera-
tions are presented schematically in Figure 3-6.  Hot raw gas from the waste
heat boiler is cooled and scrubbed of entrained dust in two stages.  The
first stage consists of a washer cooler which reduces the gas temperature
and provides bulk dust removal by means of direct water scrubbing.  Addi-
tional cooling and dust removal  are subsequently achieved in Thiesen disinte-
grators and droplet separators.   The gas temperature is reduced from about
570K to 300K during these washing operations.  Blowers downstream of the

                                     60

-------
                                                                             RAW GAS TO
                                                                             PURIFICATION
                                               SLOWDOWN TO
                                               WASTEWATER
                                               TREATMENT
Figure  3-6.   Gas cooling  and dust removal

-------
Section 3
Purification
droplet separator compress the gas  for transport to the raw gas  holders.
The gas holders provide for a continuous,  uniform gas  feed rate  to  the down-
stream operations (e.g., compression).  Final  dedusting is provided by a  wet
electrostatic precipitator (ESP) which can reduce the  raw gas  dust  content
                     o
to less than 0.2 mg/m  of raw gas (7).
     Dust collected in the washer cooler,  droplet separator, and wet ESP  is
pumped to settling basins for thickening.   Most of the clear water  overflow-
ing the settlers is indirectly cooled and  recycled (although all existing K-T
gasification facilities utilize cooling towers for wash water cooling, com-
mercial designs for U.S. facilities feature indirect cooling to  eliminate the
potential for volatilization of pollutants such as NHL and HCN).  The settler
underflow is filtered to produce dewatered dust (Stream 209) and filtrate
which is combined with a portion of the clarifier overflow as blowdown
(Stream 210) for controlling of dissolved component buildup.  Makeup water
required to maintain the system water balance is added to the recycle wash
water stream to minimize corrosion in the washer cooler, disintegrator, drop-
let separator, and wet ESP.  Material flow estimates for key streams in the
gas cooling and dust removal process are presented in Table 3-8.   It should
be noted that dewatering of carbonaceous dusts using fuel oil to displace
dust moisture has been demonstrated in conjunction with coal gasification
and petroleum refining industries.  This approach is not considered in this
manual because developers indicate that it is economically unattractive in
these applications due to the associated fuel oil consumption.
     Waste streams from gas cooling and dust  removal are the dewatered dust
(Stream 209), and cooling and dust removal  blowdown  (Stream 210).  The dust
from gasification is typically  disposed of in settling ponds.   However, large
land requirements can be associated with such ponding.  Further, in the case
of higher rank coals, gasification dust may contain 6% or more  of  the feed
coal carbon.  Therefore, a  filtration step has been included in the design
gas cooling and  dust removal process  to reduce both area  requirements and/
                                     62

-------
      TABLE  3-8.   MATERIAL  FLOW  ESTIMATES  FOR  RAW  GAS  COOLING AND DUST  REMOVAL  PROCESSES  (ILLINOIS NO.  6 COAL)'
oo
Raw Quenched Gas
Stream 6
kmol/hr Vol %
H2
CO
co2
CH4
H2S
COS
cs2
so2
S20|
so3
504
HCN
HSCN
NO
NH3
N2
Ar
cr
F-
Total Dry Gas
H20
Dust
Total: kmol/hr
kg/hr
Temperature (K)
Pressure (MPa)
5829
13699
1910
22
229
26
2
0.5

2.6

0.07
4.0
196
104
22
1.3
22047
7919
29605
29966
672242
450
0.1
26.4
62.1
8.7
998 ppmv
1
1166 ppmv
89 ppmv
21 ppmv

118 ppmv

3 ppmv
180 ppmv
0.9
0.5
998 ppmv
58 ppmv


kg/hr



Raw Gas From
Washer Cooler
Stream 7
kmol/hr
5829
13699
1907
22
229
26
2
0.1

2.5

0.07
0.75
196
104
1
0.06
22019
964

22982
516351
300
0.1
Vol %
26.5
62.2
8.7
999 ppmv
1.0
1168 ppmv
89 ppmv
6 ppmv

113 ppmv

3 ppmv
34 ppmv
0.9
0.5
50 ppmv
3 ppmv






Dewatered Dust
Stream 209
kmol/hr


0.3
0.001

0.03
0.009
0.08
0.008
0.002

0.27

1.8
0.1

1639

1641
310
0.1
kg/hr


12
0.03

3.0
0.74
7.5
0.2
0.1

4.6

62.3
2.0

29520
29605
59217


Slowdown to
Wastewater Treatment
Stream 210
kmol/hr


2.9
0.009

0.3
0.1
0.85
0.08
0.02

2.9

19
1

17843

17870
322448
310
0.1
mg/L


403
1

103
25
254
7
4

156

2111
66






                        The number of significant figures  shown in some  cases do not  represent the degree of accuracy and are
                        retained for material  balance purposes only.   Nevertheless, slight imbalances do appear as a result
                        of numerical rounding.   Material flow estimates  and stream compositions are  based upon published data
                        and engineering estimates.  Tabulated data are based upon Reference 7.

-------
Section 3
Purification
or improve the feasibility of dust combustion prior to disposal.   For flow
estimating purposes, gasification dust from Illinois No.  6 coal  has  been
assumed to settle to about a 20% solids slurry and be further concentrated
to 50% solids by filtration, although a higher degree of dewatering  (65%
solids) has been indicated in a similar design for K-T gasification  of a sub-
bituminous coal  (4).
     Slowdown from the gas cooling and dust removal operation may be required
to maintain a system water balance and/or to prevent excessive buildup of
soluble components in the wash water.  Thus, as a minimum, the blowdown
stream would remove that portion of the unreacted gasification steam and
quench water condensed during gas cooling which is not removed with  the gasi-
fication dust.  The blowdown of any additional water must be accompanied by
the addition of a corresponding amount of makeup water and serves to lower
the level of dissolved solids in the washer circuit.  Because the quantities
of gasification steam, quench water, and water soluble ash/dust components
are coal specific and because the quantity of water removed from the washer
system with the  dust is both coal and  process specific, the quantity of blow-
down required  is therefore both coal specific and  process specific.   The
blowdown quality is determined by the  coal characteristics and to a lesser
extent, the makeup water characteristics.
     Slag quench water may be incorporated into the gas cooling and dust  re-
moval water circuit through the settling basin used for fine slag settling and
cooling purposes.   Alternatively, the  slag quench  system  could utilize a
separate settling/cooling circuit which would tend to minimize the level  of
contaminants  (particularly NH3, HCN, Cl~, and F~)  present in the slag mois-
ture.   In this  case, slag quench water may be suitable for use as makeup
water  to the  gas cooling and dust removal circuit.   In either case, specifics
of  the  slag quench/gas cooling and  dust removal interconnection have little
effect  on either the flow or quality of the  dewatered dust (Stream 209) and
                                      64

-------
                                                                Section 3
                                                                Purification
blowdown (Stream 210) streams since slag quench consumes a negligible amount
of process water and is not likely to contribute significantly to levels of
dissolved ammonia, cyanide, chloride, and fluoride.
Dewatered Dust (Stream 209)
     Dust entrained  in raw K-T gas consists of very small particles (mean
diameter about 0.03 mm) containing ash and ungasified carbon from the feed
coal.  When the dust is removed by water washing, a water slurry is generated
which is normally sent to clarification.  Clarifier underflow contains around
20% solids and can be dewatered further by simple gravity thickening in hold-
ing ponds or by mechanical means.  The final moisture content of dewatered
dust depends largely upon the dust characteristics (particularly its carbon
content) and the method of dewatering employed.  Regardless of the exact
moisture content, the dewatered material has a relatively low density when
compared to slag or combustion ash.  It also has poor mechanical stability,
and upon rewetting, exhibits tendencies toward plastic flow and/or gravity
settling.
     Elemental analyses of the dry dust from Illinois No. 6 coal gasification
indicate that the dry dust contains approximately 36% carbon, 0.1% hydrogen,
and 1.4% sulfur (7).  Ash present in the dust has essentially the same com-
position as that of the coal  ash, although it is substantially depleted of
volatile elements such as chlorine and fluorine.  Ash in the dust corresponds
to approximately 67% of the total coal  ash to gasification.
     Since the dust particles are very small and experience thorough contact
with wash water for at least a few minutes, it is expected that most of the
readily soluble material  in the dust will be leached.   Further, the remain-
ing interstitial  water in dewatered dust will  contain constituents derived
from wash water used in the quench circuit.  Table 3-9 presents the avail-
able data on the Teachability of selected elements in dry K-T dust, wet
(dewatered)  K-T dust, and,  for  comparison  purposes, the  parent  coal.
                                     65

-------
Section 3
Purification
The dry dust was collected using a cyclone for test purposes only.   The data
show that for Ag, Cr, Hg, Pb, and Se, readily soluble levels are near or be-
low analytical detection limits in all of these solid materials.  Detectable
amounts of Cd, As, and Ba are Teachable from the dry dust.   Based upon ele-
mental balance considerations, mass loadings of trace elements per unit weight
of dry material in extracts of dry dust would be expected to be greater than
or equal to those in extracts of wet dust.  Boron is highly Teachable from
both the dry dust and the parent coal.  Chromatographable organics, including
priority organic pollutants have not been detected in wet K-T dust (32,34).
TABLE 3-9.  LEACHABILITY OF SELECTED  ELEMENTS FROM K-T DUST AND FROM  ILLINOIS
            NO. 6 FEED COAL*
———————



Dry K-T Dust (31)* Wet K-T Dust (32)T
Element
Ag
As
B
Ba
Cd
Cr
Hg
Pb
Se
RCRA
(pH 5)
<0.2
<7
44
0.4
<0.14
<0.4
<0.004
<3
<16
ASTM
(PH 7)
<0.2
5.6
340
2.4
11
<0.4
<0.004
<3
<13
RCRA
(pH 5)
<0.2
0.04
—
<2
0.6
0.02
<0.004
0.26
<0.02

Illinois No.
RCRA
(PH 5)
<0.2
<8
58
1.0
2
<0.4
<0.004
<3
<8

6 Coal (33)
ASTM
(PH 7)
<0.2
<8
114
16
--
--
<0.004
--
--

  Collected-by  a  cyclone  for  test  purposes  only;  dry  dust  collection  is  not
  employed  in conventional  plants
 f34%  solids basis
 *Units are mg/kg solid
      Not indicated  in  Table  3-9 are  components which are  associated  with  the
 wash  water as  a  result of  scrubbing  gaseous  constituents  from  the  raw  gas
 stream; these  include  Cl", F", CN"  (and,  indirectly, SCN"),  NhJ, and S=.

                                      66

-------
                                                                 Section 3
                                                                 Purification
The exact levels of these species are dependent upon the coal  type and the
water management plan for the washer cooler.   Wash water associated with the
dewatered dust is expected to have the same composition as cooling and dust
removal blowdown (Stream 210), discussed below.
Cooling and Dust Removal Slowdown (Stream 210)
     If water quality were not a concern in the wash water circuit, it could,
in principle, be possible to eliminate an aqueous blowdown by internal re-
cycle.  In such a case, water would only leave the  system with dewatered
slag and dust.  However, constituents derived  from  coal, particularly chlo-
rine,  will concentrate  in the wash water and  limit  the ability to  internally
recycle all of  the wash water due to  corrosion and  scaling considerations.
Further, in the case of high chlorine, low alkalinity ash coals,  such as  the
example coal  in this document, pH control with caustic or lime would  be
necessary in  the wash circuit.  The sodium or  calcium added for pH control
will contribute to the  dissolved solids load of the wash water, affecting
the quantity  of blowdown needed.  Thus, blowdown quantity is dependent upon
the coal characteristics and water quality requirements for the washer cooler
system.
     For purposes of analysis, it has been assumed  that levels of  Cl  exceed-
ing around 2000 mg/L would be unacceptable from a corrosion standpoint.
Given  the Cl  level in the subject coal (2800  ppm),  a blowdown of  322 m /hr
was estimated.  For  coals with different Cl levels, the corresponding blow-
down would differ proportionally.  The estimated characteristics  of the blow-
down in the case of  the subject  coal  are presented  in Table 3-10.  Principle
potential pollutants are NH^, CN", and reduced sulfur species.  The net pro-
duction of these species is  not  thought to be  greatly different among coals,
so  that their concentrations will be  similar  for most coals when  blowdown
rates  are similar.   Also, heavy  elements such  as  As and Se will  be present,
but levels are  highly  coal  specific.

                                     67

-------
                      TABLE 3-10.   CHARACTERISTICS OF  SLOWDOWN  FROM  COOLING  AND DUST  REMOVAL  (7,34)
cr>
03
Major Constituents/Gross Parameters mg/L
NH* (as NH3) 156
CN" 7
SCN" 4
S202 103
S03 25
SO; 254
S= 1
C1" 2111*
Na+ 1000*
Ca++ plus Mg++ --f
TDS 4200**
pH 7§
,





Organic Constituents/Parameters
Total Chromatographable Organics
Oil & Grease
Phenols
Formate
COD
TOC

Trace Elements
F
B
As
Se
Ag
Ba
Cd
Cr
Hg
Pb
mg/L
1.3
<0.001
<0.1
100**
<10**

66#
100'
<1
<1
<0.02
0.04
<0.01
<0.01
<0.001
<0.03
                        Added in the  form of NaOH  to water system for pH control, also influenced by makeup water quality
                       fHighly influenced by makeup water quality as well as  ash characteristics
                        Dependent upon clarifier design
                       ^Without pH control the wash water would be acidic for high chlorine,  low alkalinity ash coals
                       ^Estimated from raw coal analysis and  assuming that all of the amount  in the raw coal  will report to the
                        wash water
                       **
                        Calculated from contributing constituents

-------
                                                                Section 3
                                                                Purification
     Since essentially no non-methane organics are produced in K-T gasifica-
tion, no measurable levels of chromatographable organics have been found in
K-T wastewaters.  All COD and TOC in these wastes can be attributed to re-
duced sulfur and nitrogen species.  Some suspended carbonaceous dust will
remain in the blowdown; the exact amount depends heavily upon the clarifier
and filter designs.
3.3.2  NOX Reduction
     Operating data from Modderfontein (29) have indicated fouling of compressor
components and the acid gas removal  unit which is attributed to the presence
of nitrogen oxides and 02 in the raw synthesis gas.   Fouling in the compressor
resulted in reduced heat transfer in intercoolers, and,  occasionally, vibra-
tion due to rotor imbalance.  Fouling in the acid gas removal  columns resulted
in reduced solvent circulation rates, and fouling of the heat exchangers
resulted in insufficient cooling capability to achieve the required degree
of gas purification.  Generation of fouling deposits was attributed to the
following reactions:
                       Fe + H2S  -*  FeS + H2

                       4FeS + 7NO  -v  Fe^NO)^ + S       (Roussin's salt)

                       2NO + 02  ->  2N02

                       2N02 + 2H2S  -»•  2H20 + 2NO + 2S

     Although several operating modifications had been employed to permit
stable process operation, final resolution was achieved by catalytic reduc-
tion of nitrogen oxides in the process gas.  Reduction of nitrogen oxides is
achieved by passing compressed gas through a reactor containing a cobalt
molybdate catalyst.  Therefore, a nitrogen oxide reduction reactor has been
included in the base plant design.  For balance purposes it has been  assumed
that NO in the raw gas is catalytically hydroyenated to produce N2 and H20;

                                     69

-------
Section 3
Purification
data regarding this unit's performance and reaction chemistry are not publicly
available.  Some degree of gas compression preceding the NO  catalytic re-
                                                           A
actor would be required to reduce unit size and promote the desired  reaction.
For simplicity, raw gas compression is shown to follow NO  reduction in  Figure
                                                         A
3-1 since  this is where most of the compression would occur.
     Material  flow estimates  for NOY reduction, raw gas  compression,  and  HCN
                                   A
wash steps are presented in Table 3-11.   In addition to  essentially complete
NOY destruction,  some conversion of HCN to NH-, and CO is also known to occur
  A                                          0
over the catalyst.   For analysis purposes, and due to lack of publicly avail-
able data relating to such HCN conversion , the material  flow in Table 3-11
indicates no HCN destruction in the subject unit.
Spent NOX Reduction Catalyst (Stream 212)
     The only waste stream expected from this reactor is spent catalyst.
Since no experience has been documented for this reaction system, the quantity
of spent catalyst requiring disposal and its physical/chemical  characteristics
are currently unknown.  However, based upon experience with shift conversion
catalysts, approximately 80 Mg of spent catalyst would be generated every 3
to 5 years.
3.3.3  Raw Gas Compression and Cooling
     Koppers-Totzek technology involves coal gasification at essentially
atmospheric pressure.  However, the NO  reduction, cyanide wash, shift con-
                                      A
version, and acid gas removal  (particularly in the case of physical  absorp-
tion processes) processes are more efficient and economical at elevated  pres-
sures.  Therefore, raw gas is compressed  to about 3 MPa prior to subsequent
treatment.  The temperature rise of the gas during compression is controlled
by intercoolers and an aftercooler, consistent with compressor materials
limitations and temperature requirements  of downstream processes.  Raw gas
compression and cooling are depicted schematically in Figure 3-7.  Waste
streams from raw gas compression and cooling are condensate  (Stream  211)  and

                                      70

-------
TABLE 3-11.   MATERIAL FLOW ESTIMATES FOR K-T NO   REDUCTION, COMPRESSION  AND  COOLING,  AND  CYANIDE WASH
                PROCESSES  (ILLINOIS  NO. 6  COAL)*  x





H2
CO
co2
CH4
V
COS
cs2
so2
S2°3
S03
HCN
HSCN
NO
NH,
N2
Ar
Cl"
F"
Methanol

Total Dry Gas
H20
Total, kmol/hr
kg/hr
Temperature (K)
Pressure (MPa)

Raw Gas From
Washer Cooler
Stream 7
kmol/hr Vol I
5829 26.5
13699 62 2
1907 8.7
22 999 ppmv
299 1.0

Kaw Gas After
NOX Reduction
Stream S
kmol/hr Vol I
5829 26.5
13699 62 2
1907 8.7
22 999 ppmv
229 1.0

Compression
Condensate
Stream 211
kmol/hr mg/L


0.7 1900

0.03 48 7
26 1168 ppmv 26 1168 ppmv
2 89 ppmv
0.1 6 ppmv


2.5 113 ppmv

0.07 3 ppmv
0.75 34 ppmv
196 0.9
104 05
1 50 ppmv
0.06 3 ppmv


22019
964
22982
516351
300
0.1
The number of significant figures
numerical roundina. Material flow
2 89 ppmv
0.1 5 ppmv


2.5 113 ppmv


0.75 34 ppmv
196 0.9
104 0.5
1 50 ppmv
0 U6 3 ppmv


22019
964
22982
516349


shown in soire cases do


0.001 6.3
:0.0002 <1
0.006 8 9
0.004 14

0.75 735


1 2200
0.06 66



964
967
17454
300
0.1
not represent the
mnnsitinn*; nrf ha'

Ra»
Compressed Gas
Stream 9
kmol/hr Vol 1
5829 26.5
13699 62.2
1907 8.7
22 999 ppmv
229 1.0
26 1168 ppmv
2 89 ppmv
0. 1 5 ppmv


25 113 ppmv

0.07 3.2 ppmv

196 0.9
104 0.5




22018

22016
498898
420
3
degree of accuracy and

Compressed Gas HCN Wash Water
After HCN Wash Water Wash Case
Stream 10 Stream 25 5+
kmol/hr Vol % kmol/hr mg/L
5829 36.5
13699 62.3
1873 8 5 11.4 2111
22 1001 ppmv
225 1.0 1.2 176
26 1170 ppmv
2 89 ppmv
0.1 5 ppmv


0.34 16 ppmv 2.1 241



196 0.9
104 0.5




21979
9 13227
21988 13242
497444 238884
280 280
3 0 1
are retained for material balance

Cyanide Wash Flash Gas
Water Wash Case
Stream 214af
kmol/hr Vol %


19 7 89 3

2.3 10 7





0.011 499 ppmv









22
0.3
22
951
280
0.1
purposes only Nevertheless,

Cyanide Wash Flash
Methanol Wash Ca
Stream 21 4b*
kmol/hr Vol
0.49 3.0
4.4 26.
1 2 7.3

7.3 44
0.56 3.4




2.1 12.








0.3 1.8
16

16
524
310
0.2
slight Imbalances
Aqueous Cyanide
Gas Wash Still Bottoms
se Methanol Wash Case
Stream 213*
J kmol/hr mo/L

4


7





9 <0. 00001 10








0.00004 1000

0.07
0.07
1.3
310
0.1
do appear as a result of
   Streams 215 and 214a exist only

  ^Streams 213 and 214b exist only
the water-based cyanide wash case.

the methanol-based cyanide wash case.

-------
RAW GAS
FROM
NOX
REDUCTION
  RAW GAS
COMPRESSION
COOLING
                  DEPRESSURIZATION
                  OFF-GASES
RAW
COMPRESSED
GAS
                                         CONDENSATE
                                       DEPRESSURIZATION
                                          CONDENSATE
                        Figure 3-7.   Raw gas compression and cooling

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                                                               Section 3
                                                               Purification
condensate depressurization offgases.   Characterization data are not avail-
able for condensate depressurization offgases; however, these offgases are
recycled back to the primary compression feed gas and are not a discharge
stream.
Raw Gas Compression and Cooling Condensate (Stream 211)
     Characterization data for raw gas compression and cooling condensate
available from the K-T coal gasification facility operated by AECI Limited
at Modderfontein, Republic of South Africa, are summarized in Table 3-12.
These data relate to gasification of South African sub-bituminous coal and
are likely to be somewhat coal specific.  Material balances of the Modder-
fontein data indicate that virtually all of the compression feed gas ammonia
was recovered in the compression condensate, while only 1 to 2% of the cyanide
was recovered as either cyanide or thiocyanate.  Because raw gas ammonia and
cyanide levels are anticipated to be similar for bituminous and sub-bituminous
coals, the quality of condensate with respect to these species is also
expected to be similar.

      The  higher  raw  gas  sulfide  levels  presented  in  the  base  case design  as
 compared  with  the  Modderfontein  data may  result  in higher  sulfide levels  in
 the pressurized  condensate, although depressurized condensate  sulfide  levels
 are expected to  be similar.   It  should  be  noted  that higher sulfide levels
 in  the  pressurized condensate could influence  the levels of nonvolatile sulfur
species in the condensate (e.g., SCN", S^, SO^, and 50=), provided that
formation reactions for the nonvolatile sulfur species are rapid,  if these re-
actions occur slowly, that is, occur after condensate decompression, the tab-
ulated levels of nonvolatile sulfur species would be appropriate for the
Illinois coal case.  In any event, the condensate characterization data from
Modderfontein provide a good qualitative basis for estimating condensate
characteristics  for systems utilizing other coals.
                                     73

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Section 3
Purification
 TABLE 3-12.   CHARACTERISTICS  OF PRIMARY  COMPRESSION  AND COOLING  CONDENSATE
              FROM SOUTH  AFRICAN SUB-BITUMINOUS  COAL  (24)
       PH                                          8.0 - 8.2
       Total suspended solids, mg/L                  0-12
       Total dissolved solids, mg/L                170 - 260
       Hardness, mg/L                               46 - 60
       Alkalinity, p-value (as CaC03 mg/L)             o
                   m-value (as CaC03 mg/L)        2690 - 2990
       COD, mg/L                                   559 _ 644

       NH3> m9/L                                   900 - 973
       CN-, mg/L                                   7.2 - 10.5
       SCN", mg/L                                 10.g _ 17j
       H2S, mg/L                                  43i9 _ 53-5

       S2°3' m9/L                                  4.8 - 7.8
       S03, mg/L                                      <1
       S0~, mg/L                                    49 _ 56
       PO'3, mg/L                                    2 _ 3
 3.3.4   Cyanide Wash
     Because the base plant design  includes the Rectisol process for acid
 gas  removal, minor gas constituents such as ammonia and hydrogen cyanide can
 complicate operation of the acid gas removal unit.  Ammonia and hydrogen
 cyanide, which are very soluble in  methanol, make methanol regeneration more
 complex and result in additional steam requirements  (,35).  These contaminants
 may  be  removed from the raw compressed gas  by employing a prewash of either

                                     74

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                                                               Section 3
                                                               Purification
water or cold methanol.   A water wash unit is employed at the Modderfontein
facility (24), and wash  water to gas ratios from this unit provided the
basis for the water wash system presented herein.   Methanol-based cyanide
wash units have been employed in several applications (partial oxidation of
oil) and may be attractive for coal conversion applications where water con-
sumption is a major concern or to minimize cyanic wastewater generation.

     In the case of a water-based cyanide wash, cyanide is absorbed at 280K
and 3 MPa.  The rich wash water is subsequently flashed to atmospheric pres-
sure yielding depressurized wash water (Stream 215) and sour flash gas
(Stream 214a) waste streams.  The depressurized cyanide wash water can be
partially recycled as gasifier quench water, combined with wastewaters from
the gas cooling and dust removal and raw gas compression and cooling pro-
cesses and sent to wastewater treatment, or treated separately.  The sour
flash gas is processed through the sulfur removal/recovery system since its
sulfide content corresponds to approximately 1% of the total sulfur in the
gasified coal.
     In the case of a methanol-based cyanide wash, cyanide absorption was
assumed to proceed at 270K and 3 MPa.  The rich methanol is regenerated by
depressurization and indirect heating to yield a sour flash gas (Stream 214b).
The sour flash gas is processed through the sulfur removal/recovery system
since its sulfide content corresponds to approximately 3% of the total sulfur
in the gasified coal.  Because of the rigorous hot regeneration required to
liberate the highly soluble cyanide from wash methanol, solvent losses with
the flash gas are anticipated to  be relatively high, although no operating
data are available.
     An additional waste stream associated with the methanol-based cyanide
wash is an aqueous cyanide wash still bottoms (Stream 213).  Feed gas to the
cyanide wash unit contains moisture which would accumulate in the wash meth-
anol.  This moisture is  recovered by distillation of the regenerated methanol.
                                      75

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Section 3
Purification
     The composition of the compressed gas after cyanide wash (Stream 10) is
essentially independent of the cyanide wash absorbent used since, in either
case, only a small quantity of gas is absorbed in the cyanide washer.  There-
fore, material flows in operations downstream of the cyanide washer (i.e.,
shift conversion, acid gas removal, and liquid product synthesis) are essen-
tially independent of the cyanide wash absorbent used.  For these reasons,
material flow estimates for downstream operations will be provided only  for
the water-based cyanide wash case.
     Estimated characteristics and material flows of waste streams from  the
cyanide wash process have been presented  in Table 3-11.
Cyanide Hash Water  (Stream 215)
     The cyanide  wash water stream exists only in the case of a water-based
cyanide wash system.  No characterization data are available for this waste
stream.  Therefore, the wash water quality has been estimated using  gas  solu-
bility data  (25,3fc>).   Publicly available data indicate that low pressure
aqueous wash systems approach Henry's Law equilibria  for HCN and NH-, when
the  influence of  pH is considered  (7,25).   Therefore, theoretical HCN and
NH^  solubility data were utilized  in conjunction with absorption/desorption
estimates.  However, H-S absorption  does  not  appear to be equilibrium con-
trolled and, therefore, empirical  absorption  data were utilized  (7,25).
Some C02 is also  absorbed  in aqueous wash systems and theoretical  solubility
data were  used for  purposes of analysis  (this approach may overestimate  the
quantity of C02  in  the flash gas).   These estimates indicate a depressurized
cyanide wash water  containing 2111 mg/L  C02,  241 mg/L HCN, and 176 mg/L  H2$.
The  flow rate of  depressurized  cyanide  wash  water  has been  factored from
                                                                     2
nominal Modderfontein operating data  (24) and is approximately 238 m /hr.
Sour Gas from Cyanide Uash Flash - Water  Uash Case  (Stream 214a)
     No flow rate or characterization data are available for sour  flash  gas
from cyanide wash water depressurization.  The sour gas flow rate  and

                                      76

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                                                                 Section 3
                                                                 Purification
composition have been estimated using gas solubility data.  Sour flash gas
will be generated at a rate of approximately 22 kmol/hr and is composed of
89% C02, 11% H2S, and 499 ppmv HCN.  The sulfur content of this sour gas, 2.35
kmol/hr, corresponds to nearly 1% of the total  sulfur in the gasified coal.
Sour Gas from Cyanide Wash Flash - Methanol Wash Case  (Stream  214b)
     No flow rate or characterization data are available  for sour flash  gas
from cyanide wash methanol regeneration.  The sour gas  flow rate and composi-
tion have  been estimated using gas solubility data  (37).  The methanol con-
tent of the sour gas has been  derived  from Rectisol operating data on the
basis of inorganic gases stripped during hot regeneration (38).  Sour flash
gas will be generated at a rate of approximately 16 kmol/hr and is composed
of 45% H2S, 27% CO, 13% HCN, 7% C02, 3% COS, 3% H2> and 2% methanol.  The
sulfur content of this sour gas, 7.3 kmol/hr, corresponds to nearly 3% of
the total  sulfur in the gasified coal.
     Losses of \\2 and CO in this stream are expected to be small owing to
their low  solubility in methanol and the low methanol circulation rate re-
quired for cyanide removal.  Carbon dioxide losses in this stream are small
due to the low C02 partial pressure prior to shift conversion.  Thus, the
losses of H2, CO, and C02 in the sour gas correspond to only 0.008%, 0.03%
and 0.06% of their respective feed rates into the cyanide wash unit.

Cyanide Wash Still  Bottoms - Methanol Wash Case (Stream 213)
     Raw compressed gas contains a small amount of moisture which will be
removed during cyanide washing by absorption in methanol.   This moisture is
recovered by distillation of regenerated methanol  and will have a flow rate
                        3
of approximately 0.001  m /hr.   No characterization data are available for
the aqueous cyanide wash still  bottoms.   However,  HCN and methanol levels of
10 mg/L and 1000 mg/L,  respectively, have been estimated as upper limit
concentrations based upon data for Rectisol  still  bottoms at Sasol (39).
                                     77

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Section 3
Purification
3.3.5  Shift Conversion
     Methanol synthesis and hydrocarbon production via Fischer-Tropsch (F-T)
synthesis can be represented by the following reactions:

     CO + 2H2 CATALYST> CH3OH + heat (Methanol Synthesis)

     nCO +  (2n + ,5x)H2 CATALYST )  CnH2n+x + nH20 + heat (F-T Synthesis)

where n ranges from 1 to 20 and x = 2 for parafins and x = 0 for olefins.
Since feed  gas to synthesis would usually contain small amounts of C02 in
addition to  CO and H?, and synthesis catalysts are also active for the inter-
connecting  water gas shift reaction (CO + HLO -> C0? + H?), the hydrogenation
of C0? may  be represented as follows:

     C02 +  3H2 CATALYST^ CH3OH + H20 + heat (Methanol Synthesis)

     nC02 + (3n + .5x)H2 CATALYST) = CnH2n+x + 2nH20  (F-T Synthesis)
Although the theoretical stoichiometry for synthetic liquids production calls
for a  ratio of 2 moles of H2 per mole of CO and 3 moles of H2 per mole of C02,
in practice a stoichiometric excess of about 3% is required (1).  That is:

                         H2/(2CO  + 3C02)  =  1.03

      Assuming  a  residual C02  concentration  of  about  3%  in  the  synthesis  gas,
 an Hp to CO mole ratio of  about  2.4:1  is  required  in the synthesis  gas.  The
 H2 to CO ratio  in  compressed,  raw K-T  gas typically  ranges  from 1:2 to  1:2.5
 (7,8,24,29), well  below the ratio required  for liquids  synthesis.   Thus,  a
 shift conversion step  is a necessary part of the gas  upgrading operations
 for K-T based  indirect liquefaction plants.
                                      78

-------
                                                                 Section 3
                                                                 Purification
     The shift conversion reaction, reaction of CO and water vapor to form
\\2 and CC^, is a mildly exothermic reaction which can be promoted by a variety
of catalysts:
                     CO + H20 = C02 + H2 + 41.2 kJ/mol

Shift conversion catalysts currently in use include iron-chromium, copper-
zinc, and cobalt-molybdenum catalysts.  Iron-chromium catalysts are active
at 600K to 823K, and retain their activity and physical strength with sulfur
species concentrations of up to about 200 ppmv in the shift gas (40,41,42).
Copper-zinc catalysts  are active at low temperatures (475K to 520K) and are
typically used for final CO conversion following high temperature shift con-
version.  Copper-zinc shift catalysts lose activity due to poisoning by sul-
fur and chlorine compounds in the process gas at concentrations in the range
of 1 ppmv (40,41).  The newest types of shift catalysts (cobalt-molybdenum
catalysts) maintain high activity over a wide range of temperatures (473K
to 810K) and are not affected by the presence of gaseous sulfur compounds.
Indeed, since cobalt-molybdenum catalysts are active in the sulfided form,
some hydrogen sulfide is required in the process gas to maintain catalyst
activity (43,44).   Thus, iron-chromium or copper-zinc catalysts are appli-
cable if shift conversion is preceded by a sulfur removal  process, while a
cobalt-molybdenum catalyst would be required if shift conversion precedes
acid gas removal.
     The sequence in which shift conversion and acid gas removal are per-
formed  is dependent upon a variety of design considerations including raw
gas temperatures, acid gas removal selectivity requirements, and catalyst
costs.  K-T based coal conversion facilities have, in the past, employed a
shift conversion  process which  follows  raw  gas sulfur  removal  and  precedes
carbon  dioxide removal  (e.g., the  AECI Modderfontein facility).  Such a con-
figuration facilitates achievement of highly selective sulfur  recovery due
to the  favorable H2S to C02 ratio prior to shift conversion.   In addition,
conventional iron-chromium or copper-zinc shift conversion catalysts can be
                                     79

-------
Section 3
Purification
 utilized.   All  commercial  K-T coal  gasification  facilities  utilize  this  con-
 figuration and  the only K-T-based  indirect liquefaction  facility  proposed  in
 the U.S.  (The North Alabama Coal Gasification Consortium Project) is  expected
 to utilize this configuration also.   This  is, therefore, the approach which
 has been incorporated into the base plant  design.   Because  shift  conversion
 feed gas is the outlet gas from HpS removal  and  the shift conversion  outlet
 gas is the inlet to C02 removal, material  flow estimates for shift  conversion
 are presented in the acid gas removal section (Section 3.3.6).
      It should be noted that an additional gas compression  step will  likely
 precede shift conversion (24).  In contrast with raw gas compression, the
 desulfurized gas is dry and hence  no compression condensate results.   Since
 there would be no waste streams associated with this additional compression,
 this process is not further considered in this manual.
      To achieve the required H~ to CO ratio of about 2:1 using catalytic
 shifting, two approaches are possible:  (1) processing the entire raw gas
 stream through a relatively low conversion efficiency reactor, and (2) pro-
 cessing a portion of the raw gas stream through a higher conversion effici-
 ency reactor and combining the shifted and unshifted  (bypass) gases after-
 ward.  Based on actual operating experience, a residual CO concentration of
 less than 3% can be obtained at 500K to 700K.  Taking advantage of the high
 conversion efficiency  achievable, the split  flow approach  is preferred since
 it  provides  costs  savings  associated with a  smaller conversion reactor size
 and a  smaller  C02  absorber.  A tradeoff exists between  bypass  fraction and
 degree of shift conversion.  The exact bypass for a given  facility is an
 important consideration from a cost  and process efficiency  standpoint.  For
 analysis  purposes,  a bypass  fraction of 20%  has been  assumed,  a  value which
 is  consistent  with a single  stage of shift conversion.   In  the extreme, two
 stage  shift  conversion providing a  3%  (or less) CO  residual  in the shifted
 gas would enable  a bypass  fraction  of  about  one-third.   The  magnitude of  the
 bypass  fraction  has essentially no  impact upon waste  stream generation  in

                                      80

-------
                                                                Section 3
                                                                Purification
the shift section.  The  shift conversion operation is presented  schematically
in Figure 3-8.
     Two waste streams associated with the shift conversion unit are spent
shift catalyst (Stream 217) and shift condensate blowdown (Stream 218).
Spent catalyst, in this case iron-chromium and/or copper-zinc, can either
be disposed of or reclaimed, depending upon the current metal cost and re-
clamation trends.  Shift condensate blowdown is suitable for reuse within
the plant since it is low in dissolved solids although it may contain traces
of ammonia and methanol from acid gas removal.
Spent Shift Conversion Catalyst (Stream 217)
     Typically, iron-chromium shift catalyst contains about 44% iron and 6%
chromium, and copper-zinc catalysts contain about 24% copper and 36% zinc
(40,41,42,45).  There is very little interest in the steel industry and
specialized metals industry for recovery of iron or chromium from spent high-
temperature shift catalysts, and this material  will probably be disposed of
directly.  Spent chromium promoted copper-zinc catalysts are usually re-
claimed  for their copper content, although reclaimers have difficulty separat-
ing out  the zinc and the chromium (46,47).  Spent alumina promoted copper-zinc
catalysts are usually reclaimed for both their  copper and zinc contents (48).
There are essentially no publicly available leachate data for these materials.
However, few coal specific contaminants are expected to be present in spent
shift catalysts since shift conversion follows  sulfur removal from the raw
gas.  Spent shift catalyst generation rates are estimated to be approximately
70 Mg every 3 to 5 years.
Shift Condensate Blowdown (Stream 218)
     Because shift conversion is preceded by cyanide wash and sulfur removal
operations, shift condensate is expected to be  free of contaminants associated
with coal gasification.  However, traces of methanol volatilized from the
sulfur removal operation and ammonia used  for pH control may be present  in

                                     81

-------
co
RAW GAS
FROM
HCN WASH
                                                           SHIFT/C02 REMOVAL BYPASS GAS
i
, H2S REMOVAL 1
4 (REFER TO '_
[SECTION 3.3.6) '
I 1
k -\ii-i —
-6j) — *
STEAM 	 »
1
SHIFT
COMVERTER(S)
j C02 RE
vjv 1 (REfER
1 SECTIOf
L.
r
MOVAL '
TO |.
< 3.3.6) |
                                                                                                                  SYNTHESIS
                                                                                                                  GAS
                                                      SPENT      SHIFT
                                                      SHIFT      CONDENSATE
                                                      CATALYST
                                               Figure  3-8.   Shift  conversion

-------
                                                                Section  3
                                                                Purification
 the  condensate.   A  shift  condensate  blowdown  is  generated  to  control  buildup
 on dissolved  solids in  the  condensate  recycle system.   Shift  condensate
                                                         3
 blowdown will be  generated  at a rate of approximately 3 m /hr.  Ordinarily
 this very  small volume  waste stream would be  used as makeup to  the  raw  gas
 wash circuit.  Hence, this  stream  is not considered further as  a  separate
 waste.
 3.3.6  Acid Gas Removal
      Removal of  hydrogen  sulfide and other sulfur compounds present  in the
 raw  K-T gas  is  necessary  to  prevent catalyst poisoning in subsequent shift
 conversion  (if sulfur sensitive catalysts are to be used) and methanol or
 Fischer-Tropsch  synthesis  operations.  Bulk removal of carbon dioxide is
 necessary to obtain a composition meeting the stoichiometric requirements
 for  synthesis feed gas  (see Section 3.4).  There are several acid gas removal
 processes which  have been  demonstrated in coal gasification applications or
 similar applications.   However, only the two-stage selective Rectisol process
 has  been included in the base plant design since most of the recently com-
 missioned K-T coal gasification facilities utilize two-stage selective
 Rectisol units and the  only K-T based indirect liquefaction facility proposed
 in the U.S. is also expected  to use this process.  A detailed description of
 the  Rectisol process and a summary of published performance data are pre-
 sented in Appendix B and Control Technology Appendices.
      Rectisol is an acid gas  removal process which removes CCL, H?S, COS,
 HCN,  NH3, organic sulfur compounds, benzene, and gum-forming hydrocarbons
 from  synthesis gases by means of physical absorption in cold methanol.  The
 principle of operation  is based upon the fact that these compounds, parti-
 cularly the reduced sulfur species and C02, are very soluble at high pres-
 sure  in cold methanol  and are readily recoverable by flash desorption.
 Solubility coefficients (the ratios of solubility to partial  pressure) of
 H2S and C02 are higher than those of major product gases such as H2 and CO
and increase substantially with decreasing temperature while those of major
                                     83

-------
Section 3
Purification
product gases are relatively temperature independent.   For this reason,
Rectisol  absorption columns operate at low temperatures,  typically in the
range of 210 to 250K (37,49,50).   Low temperature operation also reduces
solvent losses by reducing the partial pressure of methanol in the outlet
streams.
     Because the solubilities of reduced sulfur species (e.g., H?S and COS)
in methanol are substantially greater than that of C02 at the same partial
pressure, the Rectisol  process is capable of selective recovery of reduced
sulfur species versus C02; to some degree, this holds  for all physical absorp-
tion solvents capable of absorbing reduced sulfur species and C02 almost
independently.
     The two-stage  selective  Rectisol process  is presented schematically  in
Figure 3-9.   In  general, a small quantity of methanol   is added to the  raw  gas
exiting  the  HCN  washing step  prior to cooling  and H2S  absorption, to  prevent
icing.   This  step would not be required when a methanol-based cyanide  wash
process  is employed.  Moisture in the feed gas is removed  from the H2S
absorber in  solution with methanol which  is recovered  by distillation.
Hydrogen sulfide and COS are  absorbed from the feed gas using lean methanol
from the C0?  regeneration column.  Rich methanol from  the  1-LS absorber is
flashed  to liberate absorbed  CO  and  H2 which is  returned to  the  raw  gas.
Additional flashing and stripping  in the  concentration column, with  reabsorp-
tion of  reduced  sulfur species in  lean methanol, produces  an  H^S-rich
methanol stream  for hot regeneration and  a  CO^ offgas.  Hydrogen sulfide is
recovered  by stripping with methanol  vapor  in  the hot  regeneration column.
     Carbon  dioxide is removed from  shifted process gas  by absorption in
regenerated  methanol.  A  small quantity of methanol is added to  the  shift
gas prior  to cooling and  COo  absorption to  prevent  icing,  and moisture in
the shift  gas is removed  from the  C02 absorber in  solution with  methanol.
Shift  conversion bypass gas  may  be  injected into the  upper portion of the C02
absorber.   This  serves as  a  convenient  mixing  point for  shifted  and  bypass

                                      84

-------
oo
en
                                                                                                                                          FLASH GAS MAY ALSO 8E ROOTED TO THE
                                                                                                                                          GAS HOLDERS OR RAW GAS COMPRESSION
                                                                                                                                          SYSTEM RATHER THAN BEING COMPRESSED
                                                                                                                                          IN A DEDICATED COMPRESSOR FOR RECYCLE
                                                                                                                                          FLASH GAS FROM THE C02 tOAOED METH ANOL
                                                                                                                                          FLASH MAY ALSO BE USED W
-------
Section 3
Purification
gas streams, and provides for trace sulfur removal  from the bypass gas.
Rich methanol from the C02 absorber is flashed to recover absorbed HL.
Carbon dioxide is recovered by flashing and stripping with No in the C02
regeneration column.  Material flow estimates for the shift conversion and
acid gas removal operations are presented in Table 3-13.
     It should be noted that desulfurization prior to shift conversion en-
ables the use of conventional shift catalysts (e.g., iron-chromium and copper-
zinc).  Also, due to the favorable H2S to C02 ratio before shift conversion,
it facilitates production of an hLS-rich offgas for economic sulfur recovery.
Shift conversion prior to acid gas removal would result  in an increased con-
centration  of COo in the H2S absorber feed gas; the associated  decrease in
the H2S to  C02 ratio is much less  favorable for highly  selective operation.
     There  are two  gaseous waste streams and one liquid  waste stream  produced
by the selective Rectisol unit.  The  gaseous waste streams are  the H2S-rich
offgas  (Stream  216) which contains most of the sulfur present in  the  feed
coal to gasification and the  C02-rich offgas  (Stream  219).  The H2S-rich  off-
gas is  combined with flash gas from the HCN wash and  sent to sulfur  removal/
recovery  because of its  high  sulfur content, while the  C02-rich offgas  is
typically vented directly  to  the atmosphere.  The  liquid waste  stream is  the
Rectisol  condensate/still  bottoms  (Stream  220) from  the methanol/water  dis-
tillation column.
H2S-Rich  Offgas  (Stream  216)
      Approximately  94% of  the total  sulfur present in the feed  coal  to  gasi-
fication  is present in  the H2S-rich  offgas.   The offgas is estimated to con-
tain  about  50%  C02, 42%  H2S,  5%  COS,  0.4% CS2,  340 ppmv HCN,  and  200 ppmv
S02.   The only  organic  compound  present in significant quantities is ex-
pected  to be process methanol.  Data indicating the total  methanol loss for
selective Rectisol  systems are available (35,38),  although data  relating to
methanol  losses  in  individual streams have not  been published.   Therefore,

                                      86

-------
                    TABLE  3-13.   MATERIAL  FLOW  ESTIMATES  FOR  K-T SHIFT  CONVERSION  AND ACID  GAS  REMOVAL PROCESSES  (ILLINOIS
                                       NO.  6  COAL)*"1"
00
Compressed Gas
from HCN Hash
Stream 10

H2
CO
co2
CH4
H2S
COS
cs2
Sf2
HCN
N2
»r
Methanol
Total Dry Gas
H20
Total . kmol/hr
kg/hr
Temperature (K)
Pressure (MPa)
kmol/hr
5829
13699
1873
22
225
26
2
0 1
0.34
196
104

21979
9
21988
497444
280
3
Vol %
26.5
62.3
8.5
0.1
1.0
1170 ppmv
89 ppmv
5 ppmv
16 ppmv
0.9
0 5







HjS Rich Offgas
Stream 216
kmol/hr Vo! %


269 50.2

225 42.1
26 48
2 0.37
01 216 ppmv
0.34 636 ppmv
6 1.2

7 1 3
535

535
21671
310
0.3
Shift Conversion Shift Conversion Shift Gas to Shift
Bypass Gas Feed Gas C02 Absorber Condensate
Stream 12 Stream 11 Stream 13 Stream 218
kmol/hr Vol % kmol/hr
1039
2443
321
3 9
0.004




35
18
Trace
3860

3860
86421
305
3
26 9 4790
63 3
8.3 1480
0 1 18
1 ppmv 0 02




0.9 161
0.5 85
Trace
17791

17791
398279
305
3
Vol I kmol/hr Vol % kmol/hr
26.9 12670 49.4
63.3 3377 13.2
8 3 9359 36.5
01 18 700 ppmv
1 ppmv 0 02 0.8 ppmv




09 161 06 Trace
0.5 85 0 3
Trace Trace
25671
55 167
25726 167
541238 3000
310 370
3 0.1
Nitrogen C02-Rich Rectisol tondensate/
Strip Gas Vent Gas Still Bottoms
Stream 15 Stream 215 Stream 220
kmol/hr kmol/hr Vol % kmol/hr mg/L
45 05
101 1.0
8875 tl 2
12 122 ppmv
0 05 5 ppmv
0 0^ 8 ppmv


0 0004 10*
1054 1041 10 3

0.04 1000
1054 10064
64
1054 10064 64
29534 422684 1160
310 305 340
0 4 0.1 0.1
Combined
Synthesis Gas
Stream 14
kmol/hr Vol I
13664 67.2
5719 28.1
610 3.0
21 0.1
0 02 1 ppmv




203 1 0
104 0.5

20320

20320
224718
305
3
                 The number of significant figures  shown in some cases do not represent the degree of accuracy and are retained for material balance purposes only.  Nevertheless, slight imbalances
                 do appear as a result of numerical rounding  Material flow estimates are based upon published data and engineering estimates.  Tabulated data are based upon References 1,  24, 35, 37, 38 and 39.
                 A two-stage Rectisol acid gas removal system is used with shift conversion following sulfur removal and preceding carbon dioxide removal

                *This value represents the total cyanide plus thiocyanate.

-------
Section 3
Purification
for evaluation purposes, the entire methanol  loss has been assumed to be
associated with hot regeneration, resulting in an estimated methanol  concen-
of about 1% in the H2S-rich offgas.  The H2S-rich offgas will  be generated
at a rate of about 535 kmol/hr.
     A somewhat higher level of selectivity has been incorporated into the
Rectisol material flow estimates than is typically reported for existing
units processing low-sulfur feed gases.  Hydrogen sulfide concentrations
in the H?S-rich offgas from selective Rectisol units are generally in the 25
to 35% range for these applciations (35,37,38,51).  However, these data are
from facilities with Rectisol  feed gas H2$ to C02 mole ratios ranging from
about 1:18 to 1:66.  Because of the relatively high sulfur content of the
design Illinois No. 6 coal  (3.13%  sulfur, dry basis), the design feed gas
H2S to C02 ratio is about  1:8.  Thus, other variables being equal, a higher
selectivity would be expected.   In any case, the available data indicate that
H?S concentrations of at least 25  to 35% can be obtained for a wide  range of
feed coal sulfur contents.
 CQ2-Rich Offgas  (Stream 219)
      C02-rich  offgas  is  generated  in the subject  facility at about 10,000
 kmol/hr  and  consists  of 88% C02  with the remainder  being  largely  N2.   Small
 amounts  of  H2,  CO, methanol  vapor, and  sulfur  compounds will also be present
 in the  offgas.   The  CO  level  in  the  C02-rich  offgas  is  related  to the CO
 level  in the shifted  gas.   The design  in this  manual  is consistent with
 single  stage shift conversion.  This results  in  a higher  level  of CO in the
 shifted  gas  to  the C02  absorber  as compared  to multi-stage  shift  conversion.
 Thus,  the estimated  concentration  of CO in  the C02~rich offgas  (i.e.,  1%  CO)
 is higher than  published concentrations for  multi-stage shift  conversion
 systems.  Published  data relating  to multi-stage  shift  conversion systems
 indicate CO  concentrations of 0.1% to  0.4%  in  the C02-rich  offgas (35,37,38).
 It should be recognized that CO  (and H2) could be largely recovered  by

                                      88

-------
                                                                Section 3
                                                                Purification
flashing of the CCL-loaded methanol  from the C02 absorber.   This flash gas
could be recycled to the raw gas or used as fuel or reducing gas elsewhere
in the plant.   Hence, the CO content of Stream 219 as shown in Table 3-13
probably represents an extreme case.
     Methanol  vapor will also be present in the COp-rich offgases, although
no data are publicly available at present to indicate the exact level of this
compound.  For analysis purposes all methanol losses from the Rectisol pro-
cess are assumed to be associated with the H^S-rich fraction.  Some portion
of this methanol will in actuality be contained in the CO^-rich offgas and
synthesis feed gas.
     A few ppm each of H~S and COS will be present in the COo offgases.
Data from existing facilities indicate about 5 ppmv HoS and 8 ppmv COS.
Designs for several recent selective Rectisol plants specify less than 10
ppmv total sulfur in the CO^-rich offgas (52).

Rectisol Condensate/Still Bottoms (Stream 220)
     Little characterization data are available for Rectisol condensate/
still bottoms  from the methanol/water distillation.  Based upon data from
SASOL (39), concentrations of methanol and total cyanide (cyanide and thio-
cyanate) in this stream are estimated to be less than 1000 mg/L and  about
10 mg/L, respectively.  The generation rate for this stream is estimated to
be 1 m3/hr.
3.3.7  Trace Sulfur Removal
     Although the Rectisol process can routinely achieve sulfur levels well
below the  ppmv  required  to protect  synthesis  catalysts, a guard bed  material,
employed as insurance to prevent catalyst poisoning during  upset or  trans-
ient conditions.  Zinc oxide, the most commonly proposed guard bed material,
can reduce hUS  levels to below 0.01  ppmv.  However, COS levels cannot  be  re-
duced below the 0.01 ppmv level.  Zinc oxide  beds  are closed systems during

                                     89

-------
Section 3
Purification
routine operation,  and spent material  is  infrequently  generated.   Assuming
a sulfur absorption capacity of 66 g/kg ZnO,  an average of about  80  Mg/yr
of spent guard material  (Stream 218)  would require  disposal  (53).   If the
sulfur guard bed is sized for a 3-year operating life,  about 230  Mg  of spent
guard material would require disposal  every 3 years.
                                    90

-------
                                                            Section 3
                                                            Product Synthesis
3.4  PRODUCT SYNTHESIS
     Methanol synthesis and hydrocarbon production via Fischer-Tropsch
(F-T) synthesis can be represented by the following reactions:

     CO + 2H9 CATALYST > CH.OH + heat (Methanol Synthesis)
            C.              O

     nCO + (2n + .5x)H2 CATALYST > CnH2n+x +nH20 + heat (F-T Synthesis)
where n ranges from 1 to 20 and x = 2 for parafins and x = 0 for olefins.
The mix of F-T products obtained (i.e., the range of n and x values) is
dependent upon several factors including the reactor design, temperature,
pressure, and type of catalyst used.  Since feed gas to synthesis would
usually contain some C02 in addition to CO and H2 and synthesis catalysts
are also active for the interconnecting water gas shift reaction (CO + H20 ->
C02 + Hp), the hydrogenation of C02 may be represented as follows:

               TATAI YST
     C02 + 3H2          >  CH3OH + H20 + heat  (Methanol Synthesis)

     nC02 +  (3n +  .5x)H2 CATALYST > = CnH2p+x  +  2nH20  (F-T  Synthesis)

Although the  theoretical stoichiometry for  synthetic liquids  production
calls for a  ratio  of  2 moles of H   per mole of CO  and  3 moles  of H   per
mole of C02,  in practice the following ratio  is  required:

          H2/(2CO  +3C02)   =  1.03  (1)

     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 473K  and 3.5 to 7.0 MPa  while F-T
                                      91

-------
Section 3
Product Synthesis
synthesis proceeds over iron oxide-based catalysts  at 603K (fluidized bed)
and 438K (fixed bed)  (3).
     The Mobil M-gasoline  synthesis from methanol  can be represented as
follows:
                          CATALYST
                  nCH3OH  - >

The process employs a zeolite-based catalyst and operates at about 573K and
2.2 MPa (1).
     For methanol, F-T, and Mobil M-gasoline synthesis processes, high con-
versions 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 nonreactive components in the system (e.g.,
N2, Ar, CH4).  Thus, all synthesis processes produce a purge gas containing
inerts and lost CO and H2.  Variations in process designs for synthesis
reactors reflect  different approaches to heat recovery, maximum syngas con-
version, minimum recycle, and minimum purge.  The discussions below provide
some detail about the subject synthesis processes.
3.4.1  Methanol Synthesis
     Methanol  production  is a fully commercialized  technology with a  number
of firms offering conversion processes including  Lurgi ,  ICI, Chem Systems,
Vulcan-Cincinnati, Mitsubishi, Nissui-Topsoe, and Selas-Pol imex  (3).   Figure
3-10 is a  simplified flow diagram of  the  ICI process,  one of the leading
commercial  processes.   In the ICI process,  compressed  synthesis  feed  is
mixed  with  recycle gas  and heated by  exchange with  methanol product before
entering the synthesis  reactor.  The  bulk of the  reactor feed enters  the top
of the reactor while a  portion of the gas,  which  has bypassed the 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

                                      92

-------
                                  RECYCLE GAS
     SPENT
  CATALYST
COMPRESSOR
                              -METHANOL'
                               SYNTHESIS
                              -REACTOR ^
                               PROCESS
                                WATER'
 HOT
'WATER
                                                                                                             DISTILLATION
                                                                                                               OFFGAS
                                                                                    WASTEWATER
         Figure  3-10.   Flow diagram for  the  ICI  methanol  synthesis process

-------
Section 3
Product Synthesis
methanol vapors which exit the bottom of the reactor are cooled by feed/pro-
duct heat exchange and expansion in a turbo-expander before the methanol pro-
duct is condensed.  Condenser overhead is partially recycled, with a purge
stream withdrawn from the system through an expansion turbine.   Depressuriza-
tion gases from crude methanol pressure letdown are combined with these purge
gases for use as plant fuel.
     In the Lurgi process, a leading commercial alternative to the ICI pro-
cess, the fixed bed reactor would be replaced by a boiling water jacketed
tube reactor with catalyst in the tubes  (1).   In the Lurgi case, isothermal
reactor operation is realized, and no gas quench is necessary.   In all metha-
nol synthesis processes, large amounts of heat are recovered as medium pres-
sure steam.
     Regardless of the specific process employed, all methanol  synthesis
processes generate a continuous purge gas and an intermittent spent catalyst.
The purge gas (plus expansion and distillation gases) are useful as sulfur-
free fuel gases.  When crude methanol is purified by distillation, a waste-
water stream is generated.  The quantity of vastewater generated is alnoct
directly proportional to the quantity of CCu present in the synthesis gas,
and its quality  (i.e., its content of methanol and higher alcohols) is depen-
dent upon the specific process employed.
     Table 3-14  presents example material flow estimates for methanol syn-
thesis.  Because a commercial facility may produce either crude methanol or
fuel grade methanol, or both, estimated  compositions of both crude and fuel
grade methanol have been presented.  As  indicated by the data, a small amount
of purge gas is  produced due to the  inerts in  the synthesis feed gas.  Con-
version of carbon oxides to fuel methanol is about 97%.  Crude methanol con-
tains a few percent water and small  quantities of higher alcohols, dimethyl
ether,  and low molecular weight hydrocarbons and is purified by distillation.
                                      94

-------
         TABLE  3-14.  METHANOL  SYNTHESIS  MATERIAL FLOW ESTIMATES FOR K-T  GASIFICATION   (ILLINOIS NO.  6 COAL)11
on
Feed Gas
Stream 14'
Constituent kmol/hr Vol %
CO 5719 28.1
H2 13664 67.2
C02 610 3.0
CH4 21 0.1
N2 + Ar 307 1.5
CH3OH
(CH3)20
C2H5OH
C3H7OH
H20
Total 20320 100
Crude Kethanol
Stream 20
kmol/hr Wt %
0.02
0.02
1.5
0.01
0.02
6123
5.1
1.9
1.2
549
6682
<0.01
<0.01
0.03
<0.01
<0.01
95.1
0.12
0.04
0.03
4.8
100
Purge Gas
Stream 226
kmol/hr Vol %
106
818
58
20
304
4.0
0.08


0.05
1309
8.1
62.5
4.4
1.5
23.2
0.3
0.01


0.04
100
Expansion Gas
Stream 225
kmol/hr
2.5
7.5
11
0.8
3.3
4.6
0.1


0.06
30
Vol %
8.3
25.0
36.7
2.7
11.0
15.3
0.3


0.2
100
Fuel Grade
Hethanol
Stream 108
kmol/hr Wt %
0.01
0.02
1.3
0.01
0.02
6120
5.1
1.9
0.02
11
6139
<0.01
<0.01
0.03
<0.01
<0.01
99.7
0.12
0.04
<0.01
0.1
100
Distillation
Wastewater Off gas
Stream 229 Stream 228
kmol/hr Wt % kmol/hr
0.
0.
0.
0.
0.
3.0 1.0 0.
0.
0.001 <0.01
1.2 0.74
538 98.25
542 100 0.
003
003
2
002
003
1
002



35
Vol %
1.0
1.0
62
1.0
1.0
33
1.0



100
          Material flow estimates are based upon published engineering studies (1,2).

-------
Section 3
Product Synthesis
3.4.2  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 tem-
peratures produce a lighter mix of products than fixed bed designs.  For pur-
poses of analysis, it is 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.  An indirect liquefaction plant using F-T
synthesis could be designed to produce mostly liquid products by:  (1) steam
reforming of methane and other light hydrocarbons for recycle and  (2) cata-
lytic 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 products including SNG, LPG, gasoline, diesel fuel, alcohols,
and ketones may be a more practical scenario for U.S. facilities.
     Figure 3-11 is a flow diagram of the Synthol process  (1).   Purified
synthesis gas and recycle gas are compressed together and heat exchanged
against hot reactor product.  Synthesis gas is mixed with circulating iron
catalyst in the Synthol reactor where the synthesis  reactions proceed.  Re-
action 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  re-
covered 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.
In the  cold wash  tower, cool process water  spray effects condensation of
                                     96

-------
1JO
                                             RECYCLE GAS
                                                                                                 PURGE GAS TO
                                                                                                 METHANATION
      SULFUR FREE
      SYNTHESIS GAS
                                                                                                                   OFF GASES TO SNG
                                                                                                                   CO PRODUCTION
                                                                                                           WASTEWATER
                        Figure 3-11.   Fischer-Tropsch  (Synthol)  synthesis and  product recovery

-------
Section 3
Product Synthesis
most of the  light hydrocarbons; oxygenated organics (alcohols, ketones,
acids) become dissolved in the aqueous condensate.  Liquid light oil is
further washed with process water and sent to product fractionation.  The
aqueous condensate is neutralized with lime and stripped to recover alcohols
and ketones.  Stripper bottoms, 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
catalytic methanation.
      Not shown in Figure 3-11 is the catalyst preparation process.  At
Sasol, S.A., catalyst is prepared on-site from iron ore via reduction with
fuel gas  (39).  Other transition metals are added as promoters during the
preparation  step.  It is not known whether F-T catalyst would be prepared
on-site (at  least the ore reduction step) for U.S. facilities; or purchased
from a vendor.  For simplicity, it is assumed that no preparation other than
mixing/packaging would be conducted on-site and thus no wastes are generated
by the preparation step.
      Table  3-15 presents example material flow estimates for F-T synthesis.
About 15% of the heating value of F-T products is accounted for by purge gas
which is  subsequently converted to SNG.  Light hydrocarbons in the fractiona-
tion light gas would be recovered as LPG and a fuel gas (or as methanation
feed).  F-T  middle oil is about 80% gasoline range hydrocarbons and 20% diesel/
fuel oil  hydrocarbons.  Alcohols  (and ketones) represent significant chemical
by-product(s).  A relatively  large amount of wastewater is generated in the
F-T process, since approximately  one mole of water is produced for each mole
of carbon oxides reacted during hydrocarbon synthesis.
3.4.3  Methane  Co-production  (Fischer-Tropsch  Synthesis Case)
      Purge  gas  from  light ends  recovery  in  the  F-T synthesis  case  contains
 large amounts of methane along  with  CO and  H2.   An efficient  way  to  recover
 the  fuel  value  of these  purge gases  is to convert residual  hydrogen  and

                                     98

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       TABLE  3-15.   FISCHER-TROPSCH  SYNTHESIS-MATERIAL  FLOW ESTIMATES  FOR  K-T GASIFICATION  (ILLINOIS  NO.  6  COAL)*
IO
Purge Gases to
Feed Gas Methanation
Stream 14 Stream 25

H2
N2 + Ar
CO
co2
CH4
H20
C2H4
C2H6
C3H6
C3H8
C4H8
C4H10
VC7
C? + oils
Organic Acids
Total kmol/hr
Total kg/hr
kmol/nr vol % kmol/hr
13664 67.2 973
307 1.51 307
5719 28.1 61.4
610 3.00 396
20.8 0.102 612
12.4
118
177
240
40.0
122
15.7
108.88
21.7

20320 3204
78340
Vol %
30.4
9.57
1.92
12.3
19.1
0.386
3.67
5.52
7.49
1.25
3.82
0.491
3.402
0.678



Fractionation
Wastewater from Offgases to
Alcohol Recovery C02 Removal
Stream 223 Stream 224
kmol/hr Wt % kmol/hr
5.42
5.17
1.18
139
44.8
8820 98.9 12.3
61.2
103
65.4
6.31
0.08
0.01
0.03
0.22
29 1.1
8849 443
160600 15100
Vol %
1.22
1.17
0.267
31.4
10.1
2.78
13.8
23.2
14.8
1.42
0.002
0.003
0.006
0.05



Methanation Wastewater CO? Removal Dehydration
Condensate from C02 Offgas Offgas
Stream 236 Stream 235 Stream 239 Stream 240
kmol/hr Wt % kmol/hr Wt % kmol/hr Wt % kmol/hr Vol %
0.0287 0.01
0.794 0.291
0.0042 0.001
253 . 92.7
15.5 5.67
703 98.1 22.9 100 3.01 1.11 10.6 100
0.252 0.06
0.150 0.09
0.016 0.006
0.159 0.06




4.2 1.9
707.2 22.9 100 273 10.6 100
12910 413 11490 191
CO-Product SNG
Stream 107
kmol/hr Vol %
2.77 0.188
302 20.5
0.301 0.02
131 8.94
1028 69.9
6.35 0.432









1470
33240
           Material flow estimates are based upon published engineering studies (1).  Main products from Fischer-Tropsch
synthesis are:  Blended gasoline (Stream 100) - 41320 kg/hr
             C3 LPG (Stream 106) - 2699 kg/hr
             C4 LPG (Stream 106) - 410 kg/hr
             Diesel oil (Stream 101) - 8380 kg/hr
             Heavy fuel oil (Stream 102) - 2454 kg/hr
             Mixed alcohols (Streams 103,104,105) - 6995 kg/hr

-------
Section 3
Product Synthesis
carbon oxides in the gases to additional  methane,  producing high heating
value gas equivalent to pipeline gas (substitute natural  gas or SNG).   Metha-
nation involves the catalytic reaction of carbon oxides in the gases to
methane as indicated by the following reactions:

                         3H2 + CO = CH4 + H20 + heat

                         4H2 + C02 = CH4 + 2H20 + heat

Figure 3-12 is a simplified flow diagram for SNG production showing catalytic
methanation, C02 removal, and drying.
     The methanation reactions which are carried out over nickel-based  cata-
lyst at 573 and 753K and  7 MPa  (54) are highly  exothermic.  In  the  fixed
bed design shown in Figure 3-12 temperature is controlled by recycle of
cooled product gas.  Also, a large amount of steam is recovered in this pro-
cess.  Water vapor formed during methanation is condensed in knockout drums
and the condensate is subsequently depressurized for reuse as a boiler feed
water.  Methanator product gas is most commonly treated for CCL removal
using an amine-based acid gas removal system (e.g., monoethanolamine).  Final
moisture removal is usually accomplished in a triethylene glycol (TEG)
absorber.
     The material flow estimates for SNG co-production have been included
in Table  3-15.
     Waste streams generated continuously during SNG co-production  are metha-
nation and C02  removal,  C02 containing offgases, dehydration offgas, metha-
nation catalyst, decommissioning offgases and spent methanation catalyst.
3.4.4  Mobil M-Gasoline  Synthesis
     The Mobil  M-gasoline process  is depicted in Figure 3-13  (1).   Crude
methanol  is  vaporized  by heat exchange with  reactor product and fed to  the
dimethyl ether  (DME)reactor where  it is catalytically  converted to  an

                                     100

-------
CATALYST
DECOMMISSIONING
OFF-GAS
                                                                FRACTIONATION
                                                                OFF-GASES
                                                                                             DEHYDRATION
                                                                                             OFF-GASES
COMPRESSOR
                                                                                         COMBINED
                                                                                         CONDENSATES
                     Figure 3-12.  Methanation,  C02  removal,  and  drying for  SNG  production

-------
 -5
 O>
 CO
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 CO
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 Q.
to
 -5
 Ol
 o
 -s
 o
 cr
 OJ
 CO
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 Z5
 05
 t-h
 3"
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 O
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-------
                                                           Section 3
                                                           Product Synthesis
equilibrium mixture of methanol, DME, and water vapor.  DME reactor product
is subsequently converted to hydrocarbons in M-gasoline reactors, with
temperature control obtained by recycling cooled purge gas from product
separation.  The DME reactor inlet conditions are about 573K and 2.3 MPa
while  M-gasoline inlet conditions are 603K.  Product  vapors from the M-gaso-
line 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 used as plant fuel.  The bulk of liquid product is sent
to the product fractionation unit for light ends recovery, with a small slip-
stream injected at the inlet to the boiler feed water heat exchanger to con-
trol Durene* crystallization.   The aqueous condensate from the knockout drum
(Stream 233) constitutes  the only continuous wastewater 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
perhaps once or twice per year.  The M-gasoline catalyst requires regenera-
tion about every two weeks to  remove coke.  Regeneration is accomplished
using  No  to purge  hydrocarbons from the system followed by air injection.
Control of inlet CL level and  injection of cooled recycle gas to the system
maintain  combustion temperatures below 753K.  Regeneration offgas is cooled
by exchange with fresh regeneration gas and by air cooling.  Any water of
combustion is  condensed in a knockout drum before depressurization and vent-
ing to the atmosphere.  As depicted in Figure  3-13,  five M-gasoline reactors
constitute a "train" with one  reactor being regenerated while four are in
service.  Thus, regeneration is a regular but intermittent process resulting
in the routine generation of an offgas.
     Table 3-16 presents  example mass flow calculations for Mobil M-gasoline
synthesis.  As indicated  in the table, a small methanol synthesis purge stream
*1,2,4,5-tetramethylbenzene  (Durene)  has a  very  high octane  rating and  is
 desirable in  product  gasoline  for  that  reason but  it  freezes at  353K.

                                     103

-------
TABLE  3-16.  MOBIL M-GASOLINE SYNTHESIS MATERIAL FLOW ESTIMATES  FOR K-T GASIFICATION  (ILLINOIS  NO.  6 COAL)'
Crude Methanol Purge Gas Expansion Gas
Stream 20 Stream 226 Stream 225
Constituent kmol/hr Wt - fcmol/hr Vol i kmol/hr Vol
CO 0.02 <0.01 106 8.1 2.5 8.3
H2 0.02 <0.01 818 62.5 7.5 25.0
N£ + Ar 0.02 <0.01 304 23.2 3.3 11.0
C02 1.5 0.03 58 4.4 11 36.7
CH4 0.01 <0.01 20 1.5 0.8 2.7
' C2H4
C2H6
H20 549 4.8 0.05 0.004 0.06 0.2
CH3OH 6123 95.1 4.0 0.3 4.6 15.3
(CH3)20 5.1 0.12 0.08 0.01 0.1 0.33
C2HgOH 1.9 0.04
C3H?OH 1.2 0.03
C3H6
C3H8
1 C4H10
C4H8
n C4H10
i C5H12
C5H10
n C5H12
C6
C,HfiO
CH202
Coke
Total moles 6682 100 1309 100 30 100
Crude Product
Stream 21
kmol/hr
0.7
1.6
0.01
3.5
39.0
1.0
12.6
4.2




3.9
89.0
131.2
16.4
40.6
144.0
26.6
16.4
531



1061
Vol ':>
0.07
0.15
0.001
0.33
3.7
0.10
1.2
0.4




0.36
8.4
12.4
1.6
3.8
13.6
2.5
1.5
50.0



100
Fuel Gas
Stream 230
kmol/hr
0.3
0.9
0.006
0.3
6.8
0.06
0.6
0.2




0.08
1.6
1.2
0.1
0.3
0.5
0.09
0.05
0.3



13.4
Vol '
2.3
6.8
0.04
2.6
50.8
0.5
4.3
1.6




0.6
11.6
8.7
1.0
2.1
3.7
0.7
0.4
2.5



100
Condensate
Stream 233
kmol/hr Wt "
0.04


0.68 0.03



6099 99.0












1.35 0.10
7.92 0.42
10.0 0.42

6119 100
   Material flow estimates are based upon published engineering studies  (1).

-------
                                                            Section 3
                                                            Product Synthesis
is produced which accounts for less than 10% of the total product heating
value.  Most of the remaining fuel value is recovered as gasoline and LPG.
Mobil M-gasoline offgas and fractionation light gas are used as plant fuels.
The aqueous condensate waste (Stream 233) contains the oxygenated organics
(ketones, acids) which are generated in small amounts in the Mobil M-gasoline
catalytic reactors.
3.4.5  Product Recovery and Upgrading
     The crude liquid fuel products of methanol, F-T, and Mobil M-gasoline
syntheses may require upgrading on-site to yield final products which are
marketable as substitutes for petroleum-derived fuels and chemicals.  This is
particularly true for motor gasolines, where crude coal-derived 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 catalytic
alkylation of the C3-C4 fraction to yield gasoline-blend hydrocarbons and
commercial grade LPG, by hydrotreating (in the F-T case for destruction of
olefins and oxygenated organics), by catalytic reforming to produce more
cyclic and branched chain  hydrocarbons, by 05/05 isomerization  to increase
the antiknock quality of pentanes and hexanes, and by catalytic polymeriza-
tion to convert propene/butene fractions into higher molecular weight gaso-
line blending compounds.   All  of these upgrading processes are standard
refinery technology.  Further, waste streams generated during upgrading (e.g.,
alkylation sludges, condensates)  are not expected to present treatment prob-
lems  other than  those encountered in existing refineries  since feed streams
to upgrading processes  have no unique characteristics differing from current
refinery experience.  In  fact, the absence of sulfur and nitrogen in the syn-
thesis products  elminates  waste streams such as sour waters  and gases often
generated in the upgrading of petroleum fractions.   Control  of refinery
waste streams has been  discussed in several  reports (55,56,57) and therefore
will  not be addressed in  this manual.  For these reasons and due to the multi-
plicity of possible options for product upgrading,  the "plant boundary" chosen

                                     105

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Section 3
Product Synthesis
for purposes of this manual includes only crude product separation/fractiona-
tion.  The one exception to this defined plant boundary is the fugitive
organic emissions inventory which includes emissions from all upgrading pro-
cesses (refer to Section 3.7).
     Tables presented previously in Section 3.4 have shown the characteristics
and flow rates of crude synthesis products consistent with the plant boundary
defined for purposes of this manual.  Table 2-2 in Section 2 presented typical
upgraded product slates for K-T based facilities.   This mix of upgraded pro-
ducts is assumed in Section 3.6 for purposes of estimating evaporative emis-
sions from product storage.
3.4.6  Haste  Streams Generated  by Synthesis Operations

     Synthesis operations  do not generate any continuous gaseous waste
streams.  All purge gases  are valuable as sulfur-free fuels or as SNG feed.
However, periodic regeneration  or decommissioning of catalysts results in
the generation of offgases.  In addition, spent catalysts requiring dis-
posal constitute an intermittent solid waste.  Aqueous wastes are routinely
generated by  methanol, F-T, Mobil M-gasoline, and SNG synthesis.  In  all but
the SNG case, these wastewaters contain oxygenated  organics  requiring treat-
ment.  SNG condensates contain  only dissolved gases and are  reusable  as
boiler feed water after degassing.  Water produced  during methanol  synthesis
is found in the crude methanol  fuel product.

Spent Methanol Synthesis Catalyst  (Stream  227)
     No data  are currently available  in the public  domain relating  to the
characteristics or  quantity of  spent  methanol catalyst.   For  the subject
facility a catalyst inventory of about  300  Mg  having  a  useful life  of 3-5
years is assumed.   Therefore, based on these assumptions, the average annual
spent catalyst rate is  60  to 100 Mg.
                                     106

-------
                                                            Section 3
                                                            Product Synthesis
 Spent  F-T  Catalyst  (Stream  222)
     As  with  methanol  catalyst,  no  data are currently available on properties
 of spent catalyst.   Further,  amounts  and  types of metals other than  iron
 which  are  used  in formulations of fresh catalysts are proprietary.   Based  on
data for the Sasol,  S.A. facility,  about 5200  Mg/year of spent F-T catalyst
would be generated (1).
Spent Mobil M Catalyst  (Stream 232)
    Mobil M catalysts are zeolite-based (synthetic clay-like) materials.  No
data are publicly available at present on the characteristics of these cata-
lysts.   It is estimated that the subject facilities would generate about 80
Mg/year of spent DME catalyst and about 300 Mg/year of spent M-gasoline
catalyst (1).
Mobil M  Synthesis Catalyst  Regeneration Offgas (Stream 231)
     Based on design data contained in a  Mobil report (1) 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 offgas flow  rate of
                     3
approximately 4600 Nm /hr.  Pollutants of concern in the offgas stream which
may require control are VOC,  carbon monoxide, and particulate matter.  No data
are  currently available on the  composition of the subject waste gases.
Spent Methanation Catalyst  (Stream 238)
     Nickel-based methanation catalysts are eventually deactivated by phy-
sical degradation of crystal size and by chemical accumulation of poisons
such as sulfur.  No data are currently available on the Teachability of
nickel from spent methanation catalyst.  The average generation rate of spent
catalyst is estimated at about 40 Mg/year.
Methanation Catalyst Decommissioning  Offgas (Stream 237)
     Methanation catalyst contains nickel  in reduced form and is thus
                                    107

-------
Section 3
Product Synthesis
pyrophoric 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 cata-
lyst decommissioning offgas.
Methanol Synthesis Condensate (Stream 229)
     Based on the calculations in Table 3-14, methanol synthesis condensate
has the following characteristics:
                                              3
                 Production rate          10 m /hr
                 Methanol                 10,000 mg/L
                 Ethanol                  5 mg/L
                 Propanol                 7,400 mg/L
                 COD                      33,000 mg/L
                 TOC                      7,400 mg/L
The condensates will contain very low inorganic TDS levels, no sulfur or
nitrogen  species, and no  significant levels of trace  elements.  The volume
of this stream  is determined by  the C02 level in the  feed gas which is,  in
turn,  determined by  Rectisol design.  The exact composition of methanol
systems condensate will  vary with the specific process employed.
F-T Wastewater  (Stream  223)
      Condensates generated by  the F-T product separation  step have the
following estimated  characteristics  (1)  (see Table 3-15):
                                                3
                  Production rate          160 m  /hr
                  Organic acids            10,800 mg/L
                  COD                      12,000 mg/L
                  TOC                      4,300  mg/L
 Although  the condensates would inherently have  low inorganic  TDS levels, dur-
 ing  product separation  the F-T condensates are  neutralized with lime or
 caustic to allow distillation of alcohols and ketones while leaving  acids

                                     108

-------
                                                            Section 3
                                                            Product Synthesis
in the aqueous phase.  Thus, the wastewaters would also have high levels of
alkalinity and Ca   or Na .   No significant levels of trace elements are
expected.
Mobil M-Gasoline Wastewater (Stream 233)
     Condensates generated by the Mobil  product separation step have the
following estimated characteristics (1,2) (see Table 3-16):
                                               o
                 Production  rate          110 m /hr
                 Formic acids             4,200 mg/L
                 Acetone                  4,200 mg/L
                 Cg + hydrocarbons        1,000 mg/L
                 COD                      14,000 mg/L
                 TOC                      4,000 mg/L
The waste will contain very low levels of inorganic TDS, no sulfur or nitro-
gen compounds, and no significant levels  of trace elements.  The estimates
for gross parameters or constituents may be lowered when chemical recovery
is practiced.  Also, the specific catalyst will affect condensate quality.
Methanol synthesis condensate is not generated separately in Mobil M-gasoline
facilities.  Water produced in methanol  synthesis is ultimately found in
Mobil M-gasoline wastewater.
Methanation  Condensate  (Stream  236)
     Water contained in crude SNG  is condensed  under pressure and contains
about 10 mg/L CH4  and 20,000 mg/L  of C02  (58).  About 12,910 kg/hr of con-
densate are  generated.  Since this stream contains essentially no dissolved
solids, it is reusable as boiler feed water after depressurization and air
or N2 stripping to remove dissolved gases.  In  an integrated facility,  metha-
nation condensate would be  considered an  internal process  stream rather than
a waste stream.
                                     109

-------
 Section 3
 Product Synthesis
C02 Offgas from SNG Purification (Stream 239)
     In most cases, residual C02 in the methanation product (crude SNG)
would be removed to obtain a pipeline quality gas.  Since amine processes
for C02 removal will also remove some CO, H2, and hydrocarbons, the offgas
will contain these constituents in the following approximate amounts (1,58):

                        C02             93 vol  %
                        CO              15 ppmv
                        H2              105 ppmv
                        CH4             1 vol %
                        C2H.            550 ppmv
                        C2H6            925 ppmv
                        C3H6            582 ppmv
                        C^Hg            58 ppmv
                        H20             5.8 vol %
The total flow rate is estimated to be approximately 273 kmol/hr.

Dehydration Offgas (Stream 240)
     The triethylene glycol regenerator offgas  contains very small  amounts of
methane and the glycol solvent.   No data are available to quantify these con-
stituents.  The offgas flow rate is around 1000-2000 kg/hr and consists
mostly of water vapor.
C02 Removal Wastewater (Stream 235)
     The fractionation offgas sent to the C02 removal  unit in an F-T synthe-
sis facility is estimated to contain appreciable quantities of water.  As a
result, wastewaters are generated in the C02 removal step.  The flow rate of
this waste stream is estimated at approximately 400 kg/hr.  Composition data
are not available for this waste stream, but it should contain only minor
quantities of dissolved gases such as C02.  As  such it could be combined
with the methanation condensate for reuse within the facility.

                                     110

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                                                        Section 3
                                                        Products/By-Products
3.5  PRODUCTS AND BY-PRODUCTS
     The products/by-products considered in this section include those pro-
duced as substitutes for petroleum-derived fuels or chemicals and sulfur re-
covered as a result of air and water pollution control.  The available data
on the composition of each product and by-product are presented, and those
substances or classes of substances which would be considered toxic are
identified.  However, it should be noted that product and by-product specia-
tion data are generally limited.  Data presented herein should not be con-
strued as an adequate basis for evaluating the potential environmental risks
associated with products and by-products.
3.5.1  Methanol Synthesis Product
     Methanol is currently produced primarily from natural  gas (59).  The
composition of the crude product varies somewhat depending  upon such factors
as the specific synthesis process used, the synthesis pressure and tempera-
ture, and the hydrogen to carbon monoxide ratio in the synthesis feed (59).
The  primary  reaction in methanol synthesis is:
                       CO + 2H2            CH3OH + heat

However, a number of side reactions also take place which introduce impuri-
ties into the crude methanol product.   A representative, but not exhaustive,
list of impurities which can be expected in crude methanol  is presented in
Table 3-17.  An additional, and highly toxic, 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 (60).
     Table 3-18 shows an estimated composition of a crude methanol  made from
coal.  As with a natural gas feed the  amounts and types of  impurities  present
will vary somewhat depending upon the  specific synthesis process used  and
                                     111

-------
Section 3
Products/By-Products
process conditions.  However, water is expected to be the largest single
impurity (5%) with all others comprising less than 1%.  It should also be
mentioned that several methods for purifying methanol are currently available
(59), 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% pure in the case of the crude product to 99.85% pure for Grade AA
methanol.
       TABLE 3-17.  COMPONENTS REPORTED IN COMMERCIAL METHANOL (59)

                                   Compounds
      1.   Dimethyl  Ether
      2.   Acetaldehyde
      3.   Methyl  Formate
      4.   Diethyl  Ether
      5.   n-Pentane
      6.   Propionaldehyde
      7.   Methyl  Acetate
      8.   Acetone
      9.   Methanol
     10.   Isopropyl Ether
     11.   n-Hexane
     12.   Methyl  Propionate
     13.   Ethanol
     14.   Methyl  Ethyl Ketone
     15.   t-Butyl  Alcohol
16.   n-Propanol
17.   n-Heptane
18.   Water
19.   Methyl Isopropyl Ketone
20.   Acetal
21.   Isobutanol
22.   n-Butyl Alcohol
23.   Isobutyl Ether
24.   Diisopropyl Ketone
25.   n-Octane
26.   Isoamyl Alcohol
27.   4-Methyl Amy! Alcohol
28.   n-Amyl Alcohol
29.   n-Nonane
30.   n-Decane
                                      112

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                                                         Section 3
                                                         Products/By-Products
   TABLE 3-18.  ESTIMATED COMPOSITIONS OF CRUDE METHANOL FROM COAL* (2)

	Compound	Concentration	
               CH3OH                              ~^%
               C2H5OH, C3H7OH and
                  C4HgOH                          2800 ppm
               (CH3)20                            150 ppm
               Nonmethane HCs                     600 ppm
               H20                                5.0%

*The composition of crude methanol is highly process specific.  These esti-
 mates are based upon the ICI synthesis process.
3.5.2  Fischer-Tropsch Liquid Products
     The crude Fischer-Tropsch synthesis product is primarily composed of
straight-chained paraffinic and olefinic hydrocarbons (61).  Minor quanti-
ties of aromatic, naphthenic, and branched-chain hydrocarbons are also pre-
sent, along with small amounts of oxygenated compounds such as alcohols,
aldehydes, ketones, and acids, most of which have fewer than five carbon
atoms (62).  The crude F-T product (Stream 22) can be refined into several
different products including LPG  (Stream 106), gasoline (Stream 100), diesel
oil (Stream 101), heavy oil (Stream 102), methanol (Stream 103), acetone and
methyl ethyl ketone (MEK) (Stream 104), and heavy alcohols (Stream 105).
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, diesel oils, and heavy
oils from F-T synthesis indicate that they are essentially nitrogen-and-
sulfur-free (63).   Crude Fischer-Tropsch gasoline requires upgrading prior
                                     113

-------
Section 3
Products/By-Products
to its use as a motor fuel, and Table 3-19 shows the estimated chemical  com-
position, by compound class, of the finished Fischer-Tropsch gasoline.   The
aromatics content (17%) is lower than that of typical petroleum gasolines
(23-36%).  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 (64).
     Table 3-20 shows the distribution of the oxygenated by-products from
fluid bed Fischer-Tropsch synthesis before further refining.  At the SASOL
plant, the aldehydes are hydrogenated, and methanol is reported to be used
onsite as Rectisol solvent makeup.  Ethanol, propanol, butanol, pentanol,
acetone, MEK, and a higher alcohol fraction are distributed commercially (63).
The SASOL operators also convert the 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  (65).
3.5.3  Mobil M-Gasoline Products
     The crude Mobil M-gasoline synthesis product  (Stream 21) is fractionated
into a gasoline (Stream 109), mixed butanes (Stream 110) and propane (Stream
111).  Table  3-21  which shows the expected composition of the synthesis pro-
duct, representing an  average yield over  14 days of  operation  before catalyst
regeneration  (1).
     Table 3-19 presented the estimated composition of the crude Mobil M-
gasoline.  It can be seen from this table that the olefins content of the
Mobil M-gasoline is higher than that of petroleum gasoline, while the satu-
rates and aromatics contents are within the ranges found in petroleum gaso-
lines.  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 gaso-
lines (64).  As was mentioned earlier, iron carbonyl could be present in
trace quantities in the methanol feed.  It is, however, expected that any

                                      114

-------
TABLE 3-19.  COMPARISON OF THE ESTIMATED  COMPOSITION  OF  FINISHED  INDIRECT  COAL  LIQUEFACTION,  UNLEADED
             GASOLINES, AND TYPICAL  PETROLEUM  GASOLINES

Fischer-Tropsch
Unleaded Gasoline
Component (Refs. 1,63)
Saturates
Olefins,
Aromatics
, vol %
vol %
, vol %
Sulfur, wt %
Nitrogen,
wt %
63
20
17
<1 ppm
<1 ppm
Finished
Unleaded Mobil M-
Gasoline (Ref. 1)
60
11
29
<1 ppm
<1 ppm
Crude
Mobil M-Gasoline
(Ref. 1)
56
13
30
<1 ppm
<1 ppm
Petrol eum- Deri ved
Gasolines
(Refs. 66,67,68)
56 -
4 -
23 -
0.014 -
0.05 -
69
8
36
0.417
0.49

-------
Section 3
Products/By-Products
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 3-20.  DISTRIBUTION OF OXYGENATED BY-PRODUCTS FROM FLUID-BED FISCHER-
             TROPSCH SYNTHESIS  (63)*

Component
Acetaldehyde
Propionaldehyde
Acetone
Methanol
Butyraldehyde
Ethanol
MEK
i-Propanol
n-Propanol
2-Butanol
Dimethyl Ketone-Methylpropyl
Ketone
i-Butanol
n-Butanol
n-Butylketone
2-Pentanol
n-Pentanol
Cg + alcohols
Wt %
3.0
1.0
10.6
1.4
0.6
55.6
3.0
3.0
12.8
0.8
0.8
4.2
4.2
0.2
0.1
1.2
0.6

  The sum of reported component weight percentages does not equal  100%.
                                      116

-------
TABLE 3-21.  METHANOL CONVERSION UNIT FEED AND PRODUCT COMPOSITION (1)
                 (Basis:  100 kmol Methanol in Feed)
Component Names
Coke (as CHQ g)
Acetone
Formic Acid
Methanol
Dimethyl ether
Water
Carbon Monoxide
Carbon Dioxide
Hydrogen
Methane
Ethane
Ethene
Propene
Propane
n-Butane
i -Butane
Butenes
n-Pentane
i-Pentanes
Pentenes
Cycl opentane
Methyl cycl opentane
n-Hexane
i-Hexanes
Hexenes
Methyl cycl ohexane
n-Heptane
i -Heptanes
Heptenes
Feed
.000
.000
.000
100.000
.000
7.529
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
Product
.128
.129
.163
.000
.000
106.951
.017
.053
.040
.746
.193
.018
1.474
.064
.665
2.155
.270
.268
2.353
.435
.047
.214
.113
1.991
.297
.062
.026
.786
.292
                             117
                                                         (Continued)

-------
TABLE 3-21.  (Continued)

Component Names
1,3-Dicyclopentane, cis
i-Octanes
Octenes
n-Propyl cycl opentane
n-Nonane
i-Nonanes
Nonenes
n-Butyl cycl opentane
i-Decanes
Decenes
Benzene
Tol uene
Ethyl benzene
m- + p-Xylenes
o-Xylene
1, 2, 4-Trimethyl benzene
1 , 3 , 5-Trimethyl benzene
p-Ethyl tol uene
i-Propyl benzene
1,2,4, 5-Tetramethyl benzene
1,2,3, 5-Tetramethyl benzene
1,2,3, 4-Tetramethyl benzene
p-Di ethyl benzene
Penta-Methyl benzene
2-Methyl naphtha! ene
Total kmol
Weight (kg)
Feed
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
.000
107.529
3,339.846
Product
.233
.228
.301
.299
.015
.084
.116
.071
.024
.045
.036
.280
.070
.876
.240
.818
.034
.292
.014
.436
.063
.023
.198
.068
.017
124.832
3,339.846
                                    118

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                                                         Section 3
                                                         Products/By-Products
3.5.4  Substitute Natural Gas (SNG)
     The primary constituent of the SNG product (Stream 107) is methane with
smaller quantities of H,,, CO, CO,,, N2, and Ar.  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 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 of about 0.01  ppmv was found
in product gas from the Lurgi gasifier at Westfield, Scotland (60).  Operators
of the Lurgi gasifier at Sasol,  South Africa, reported that carbonyls were
not present in measurable concentrations in the product gas from their faci-
lity (69).  Recent data from the Kosovo, Yugoslavia, Lurgi facility indicate
that carbonyls are not present to any appreciable extent in the desulfurized
process gases leaving the Rectisol unit (70).  Carbonyl formation trends are
expected to be similar for K-T and Lurgi gasification systems.
3.5.5  LP Gas
     The LP gas (Stream 106) from F-T synthesis will consist primarily of
propane and butane with smaller quantities of ethane, methane,  and short-
chain olefins.  As discussed in Section 3.4.5, it is not expected that coal-
derived LP gas will be significantly different in chemical composition than
petroleum-derived LP gas.  However, this has not been verified  with product
composition data from a commercial-scale production facility.
3.5.6  By-Product Sulfur (Stream 112)
     Elemental sulfur is recovered as a by-product in the treatment of con-
centrated acid gases for air pollution control.  The recovered  sulfur may be
contaminated with a number of impurities.   When the Stretford process is
employed, the by-product sulfur  contains traces of vanadium, thiosulfate,
and thiocyanate.   Claus sulfur may contain carbonaceous materials to the
                                     119

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Section 3
Products/By-Products
extent that the by-product is at times termed "black sulfur."   Depending on
site-specific factors, the sulfur may be saleable or may need  to  be disposed
as a waste.
                                      120

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                                                              Section 3
                                                              Auxiliaries
3.6  AUXILIARIES
     A number of non-pollution control auxiliary operations are associated
with a self-sufficient K-T indirect liquefaction facility.  Included in these
are raw water treatment, power generation, process cooling, oxygen production,
and product/by-product storage.  These support operations are sources of
additional waste streams which in many cases would be combined and treated
with the wastes generated in the main process train.   The sections below pro-
vide brief descriptions of the most important auxiliaries and define the
expected characreristies of the major waste streams.
3.6.1   Raw Hater Treatment
     The source and characteristics of the raw water  assumed  for the K-T
indirect liquefaction plant location are presented in Table 3-22.  The com-
ponent concentrations presented represent average  annual  conditions.   Varia-
tions  in raw water characteristics, while important in the design of a  faci-
lity,  are not addressed here because they do not greatly  affect the charac-
teristics of the plant's most environmentally significant waste streams.
     Makeup water quantity and composition that determine the raw water treat-
ment load for a K-T based indirect liquefaction facility  depend primarily
upon the plant location, feed coal composition, synthesis route, and the
extent of condensate/wastewater reuse achievable.   An accurate estimate of
the makeup water requirements would require detailed  site specific water and
energy balances around the plant which are beyond  the scope of this manual.
However,  rough approximations of the makeup water  requirements have been made
based upon the major water/steam consuming operations within  the facility.
These operations are process cooling,  coal  gasification and slag quench,
raw gas cooling and dust removal, cyanide wash (water wash case), and shift
conversion.
     Water/steam consumption for each of these operations has been incorporated
into their respective material  flow estimates presented throughout this section

                                     121'

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Section 3
Auxiliaries
and are summarized in Table 2-23.   The largest single consumer of makeup
water is the cooling water system (Section 3.6.3).  Makeup requirements to
the cooling system are based upon published overall  thermal  efficiency data
for an Illinois No. 6 coal and different synthesis routes.  Makeup water
requirements to the gas cooling and dust removal  operation (Section 3.3.1)
are primarily dependent upon the soluble components  in raw gas and dust,
particularly chlorides, and to coal moisture which is related to coal rank.
This requirement could decrease by as much as a factor of about three depend-
ing upon the feed coal composition.  The other tabulated makeup water re-
quirements are also dependent upon feed coal characteristics, but to a lesser
extent, and are expected to have relatively little effect upon the total
makeup water requirements.
                 TABLE 3-22.  COMPOSITION OF RAW MAKEUP WATER

Constituent
HC03
S04
Ca++
Mg++
Na+
cr*
TDS
Si02
PH
Assumed Source of Raw Water
Ohio River @ Grand Chain, 111.
(Ref. 71)
Concentration (mg/L)
no
60
36
9
30
15
250
6.5
8.1

 *
  Estimated from TDS minus major constituents and equivalence of cations and
  anions
                                     122

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                                                               Section  3
                                                               Auxiliaries
   TABLE 3-23.  ESTIMATED MAKEUP WATER QUANTITY FOR A K-T BASED INDIRECT
                LIQUEFACTION PLANT (ILLINOIS NO. 6 COAL)
           Process                     Makeup Water Quantity,
   Cooling Water                                820 - 1207
   Cyanide Wash                                   0 - 240
   Gas Cooling and Dust Removal                    230
   Shift Conversion                                160
   Gasification                                     40
   Boiler Bottom Ash Removal                     13-80
   Flue Gas Desulfurization                      10 - 60
   (Power Generation)                         	
         TOTAL                                 1270 - 2020
     Raw water makeup requirements can be reduced by the selective reuse of
wastewaters.  Systems with high makeup flow requirements, such as the cool-
ing water, cyanide wash, and gas cooling and dust removal systems, offer the
greatest potential for cost effective wastewater recycle/reuse.  These sys-
tems have lower makeup quality requirements and will allow recycle of some
wastewaters without extensive pretreatment.  The same is true of the ash
sluicing and flue gas desulfurization systems.  The high quality makeup
requirements to boilers make it difficult to recycle all but the highest
quality wastewaters (e.g., methanation/compression condensates, boiler
blowdown, and selected reclaimed wastewaters) to the boiler feedwater treat-
ment system.
     Figure 3-14 shows a raw water treatment scheme for producing makeup
water in the base plant.   Systems with lower quality requirements may choose
to withdraw water after any step in the treatment process that meets their
requirements.   For example, cooling tower makeup could be supplied directly
from the sedimentation/equalization ponds in cases  where raw water is low in

                                     123

-------
                       RECLAIMED
                       WASTEWATER
                     METHANATION
                     CONDENSATE
                  BOILER
                  SLOWDOWN
RAW
WATER
        SEDIMENTATION
        AND
        EQUALIZATION
                                   MAKEUP WATER TO
                                   GAS COOLING AND DUST REMOVAL,
                                   CYANIDE WASH, AND GASIFIER
                                   QUENCH
COAGULATION
AND
CLARIFICATION
                                                              r
FILTRATION
                                   RAW WATER            |
                                   TREATMENT            I
                                   SLUDGES              '

                               	I
                          COOLING
                          TOWER
                          MAKEUP
DEMORALIZATION
                                                                   BOILER
                                                                   FEEDWATER
                                                                   MAKEUP
                                                                         REGENERATION
                                                                         CHEMICALS
                                                   REGENERATION
                                                   WASTEWATER
                                                   NOTE:
                                                   DASHED LINES INDICATE
                                                   FLOW ALTERNATIVE
                                     BACKWASH
                         Figure 3-14.   Flow diagram for  base plant raw water  treatment system

-------
                                                                Section 3
                                                                Auxiliaries
hardness, 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 3-14 includes  with-
drawal of water and storage in a reservoir.   This storage provides a  reliable
supply of water to the facility that is 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
clarifier 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 the calcium alkalinity.  Boiler blowdown is
recycled to the raw water treatment loop at this point to provide  a mechanism
for the removal of residual boiler feedwater treatment chemicals prior to
demineralization.  A filter is also provided to protect the demineralizers
from solids carryover from the clarifier.
     Demineralization is accomplished in two steps.   Strong acid and  base
ion exchange units are used as the primary treatment step, and a mixed bed
polisher is used as the secondary step.  The waste  streams generated  as a
result of this treatment scheme are discussed below.
Raw Water Treatment (Clarifier) Sludges (Stream 300)
     Excess sludge consisting of calcium carbonate,  magnesium hydroxide,  and
coagulated particulate matter is removed from the clarifier.  Table 3-24
presents expected sludge production rates  for varying suspended  solids con-
centrations and estimated characteristics  of this waste.  The impact  of
                                     125

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Section 3
Auxiliaries
suspended solids on the volume of sludge produced  can  be  significant  relative
to that of the chemical precipitates.   However,  even with high  input  TSS
levels, these sludges are low volume wastes  which  can  easily  be disposed  of
independently or with gasifier or boiler ash or  with flue gas desulfurization
sludges.  This sludge could also be used as  a neutralizing/scrubbing  agent
to supply a portion of the scrubber makeup alkalinity  requirements  for a
throwaway FGD process.
TABLE 3-24.  RAW WATER TREATMENT SLUDGE (STREAM  300) PRODUCTION RATES AND
             CHARACTERISTICS

                                             Sludge Production  Rate
  Suspended Solids Concentrations (mg/L)     _ (Mg/hr)* _
        0+                                       0.135 -  0.176
       10                                        0.172 -  0.224
       50                                        0.332 -  0.432
  Sludge Constituents                        Sludge Compositions (wt
       CaC03                                     38.0
       Mg(OH)2                                    2.0
                                                 60.0
 Sludge is assumed to be 40% solids by weight
tClarifier sludge flows for the 0 mg/L suspended solids case derived from
 calculations presented in Water and Waste Treatment Data, Permutit
 Company, Inc., 1961
^Sludge composition figures are for case involving 0 mg/L of suspended
 solids
Demineralizer Regeneration Wastewaters (Stream 301)
     Table 3-25 summarizes the estimated characteristics of demineralizer
regeneration wastes from the strong acid and strong base exchangers.  The
regeneration wastes from the mixed bed polisher will be comparable  in dis-
solved solids to the compositions shown, but their flow will be intermittent
                                     126

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                                                                 Section 3
                                                                 Auxiliaries
and small compared to those from the primary ion exchange step.  Regeneration
wastewater flow rates (Stream 301) are calculated as 9% of the total water
flow rate into the demineralizer.  The boiler feedwater (Stream 33) makeup
is assumed to  be approximately 180 m /hr.  At this makeup rate, the demin-
eralizer regeneration wastewater flow rate for Illinois No. 6 coal  is approxi-
mately 18 m /hr.  Wastewater flow rates will vary by coal  type and synthesis
process in the same manner as the raw water makeup requirements for the
boiler feedwater system.  In addition, in an actual plant the regeneration
wastewaters may be produced on an intermittent basis and require flow equali-
zation prior to treatment.

TABLE  3-25.   DEMINERALIZER  REGENERATION WASTEWATER  COMPOSITION* (STREAM 301)

Constituent
HCOg
OV/ n
4
Ca++
Mg++
Na+
cr
TDSf
Si02
PH
Regenerated Wastewater for
Illinois No. 6 Coal Case
0
5,037
156
89
1,758
167
7,207
72
1.7









*
 All units are mg/L except pH.  33% regeneration efficiency and the use of
 H?SO* and NaOH as regeneration chemicals assumed.
t
 Total dissolved solids calculated as a sum of the ions except Si02.
                                     127

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Section 3
Auxiliaries
3.6.2  Power Generation and Process Heating
     Self-sufficient indirect liquefaction facilities would require boilers
for power generation and heaters for various process units including coal
drying and pulverizing.  In addition to boilers and heaters, other auxiliaries
could include dedicated gasifiers for producing low heating value fuel gas,
electrical generating units, and gas turbines.  The size of the boiler would
be determined primarily by the extent to which electric drivers are used
versus steam or gas turbine drivers.  Where electrical drivers are used,
steam demand for electricity production may differ (qualitatively and quanti-
tatively) 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 exist, and it is beyond the  scope
of this manual to perform the detailed engineering required to assess all of
these configurations.  For purposes of analysis, electric drivers were
assumed to be employed to the maximum practical extent, and the electrical
energy needed is generated on-site.
     A pulverized coal-fired boiler is assumed to supply the facility with
all  steam not produced in process waste heat  boilers  (e.g., gasifier, shift,
synthesis).  The boiler and associated systems are of conventional design
using a   regenerative  air heater which preheats the  combustion air to 533K
by exchange with flue  gas and an economizer to preheat boiler feedwater  to
588K.  Flue gas exits  the system at 450K  and  bottom  ash at 811K.  Boiler
thermal efficiency  is  approximately 90%  (LHV)  for Illinois No. 6  coal.
Steam is  used for process purposes  (gasification, shift) for direct heating,
in turbine drivers  for motive power (e.g., compressors), and for  generation
of electric power.   For certain purposes,  steam superheating may  be necessary.
     As indicated earlier,  278,400 kg/hr  of Illinois  No. 6 coal  (dry  basis)
is being  gasified to produce approximately 113 TJ/day of fuel grade methanol
 and  other products  (methanol  synthesis  case).  An overall  plant  thermal
                                      128

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                                                                 Section 3
                                                                 Auxiliaries
efficiency of 52.4% has been assumed for a K-T indirect liquefaction plant
employing methanol synthesis  (3).   The amount of boiler coal needed for
self-sufficient facility operation is then approximately 22,650 kg/hr (dry
basis) for a K-T based methanol plant.  The quantity of coal feed to the
boiler will vary depending upon the type of coal being fired and the overall
plant efficiency.  The overall plant efficiency is different for different
synthesis processes.  Both Mobil M and Fischer-Tropsch syntheses are assumed
to be less efficient than methanol synthesis, approximately 44.8 and 40.0%,
respectively.
     Coal requirements for hot gas generation associated with coal drying and
pulverizing operations are included implicitly in the overall plant thermal
efficiency.   Therefore, using the overall thermal efficiency in estimating
the coal feed to the boiler, coal which may actually be consumed in the coal
preparation unit necessarily reports as boiler feed coal.  The amount of coal
which would be combusted in-conjunction with the coal preparation operations
(assuming coal is burned rather than fuel gas) is dependent upon a variety
of factors including the ROM coal moisture and the residual coal moisture
requirements for coal gasification.  For the subject Illinois No. 6 coal,
the coal consumption in coal preparation is estimated to be about 2500 kg/hr
(as received basis) which corresponds to about 10% of the feed rate to the
boiler in a K-T based methanol plant.  Because coal combustion related to
coal preparation is not unique, no attempt has been made to differentiate
between flue gases associated with coal preparation and those associated
with steam and power generation.
     Mass flow calculations for a pulverized coal fired boiler associated
with a K-T based methanol plant utilizing Illinois No.  6 coal are presented
in Table 3-26.
                                     129

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                    TABLE  3-26.   BOILER MASS  FLOW FOR  ILLINOIS  NO.  6  COAL*  - METHANOL  SYNTHESIS CASE
co
o
Components
Gaseous
N2
HjO
co2
°2
so2
N02
CH. (and other
hydrocarbons)
CO
CHjCHO (and other
aldehydes)
Ar
Total
Solid
C
H (non water)
0 {non water)
S
N
Ash
Water
Total
Molecular
or Atomic
Weight

28.01
18.015
44.0098
31.9988
64.0588
46.0055
16.0426
28.0104
44.0530
39.948
--
12.011
1.0079
15.9994
32.06
14.0067
--
18.0152
-
Fuel Feed
Stream 30
Weight % kg/hr knol/hr












70.757 17854.1 1486.48
4.786 1207.65 1198.18
8.933 2254.1 140.89
3.099 781.97 24.39
1.334 336 61 24.032
10.091 2546.26
1.00 252.33 11.01
100 25233 2887.98
Air Feed
mole t, kg/hr knol/hr

76.47 213989.96 7639.77
2.069 3723.7 206.7
0.032 140.7 3.197
20.513 65567.5 2049.06





0.915 3651.8 91.414
100 287073.7 9990.1








Flue Gas Discharge
Stream 302
mole X kg/hr kr.iol/hr

73.67 214273.7 7649.9
7.89 14760.2 819.33
14.05 64221.7 1459.26
3.26 10821.4 338.18
0.21 1406.2 21.951
0.036 173.603 3.773
23ppmv 3.785 0.236
43ppmv 12.616 0.45
0.14ppmv 0.063 0.00143
0.88 3651.8 91.414
100 309325 10384.5
321.37 26.76


62.56 1.95

2037.01

2420.94 28.71
Bottom Ash
Stream 304
kg/hr kmol/hr












35.71 2.97


15.63 0.49

509.25

560.59 3.46
                  Boiler mass flows will increase

                  represent engineering estimates
by 215% for the Fischer-Tropsch synthesis case and decrease by 48% for the Mobil M synthesis case.  Tabulated naterial flows

-------
                                                                 Section  3
                                                                 Auxiliaries
     An integrated facility would also have a number of small gas-fired
heaters serving various process units (e.g., startup heaters).  Such heaters
would likely utilize sulfur-free waste gases from synthesis/fractionation
operations as the most convenient fuel.   Since the contribution of small
heaters to sulfur and particulate emissions is expected to be minimal, pol-
lution control alternatives (other than for NOX) for these small heaters are
not discussed in this report.
Boiler Flue Gases (Stream 302)
     Table 3-26 also contains the estimated composition of the combustion
flue gases for the Illinois No. 6 coal case.  In addition to the high load-
ings of S02 and total particulates, these flue gases contain both particulate
and volatile trace elements derived from the coal.  NO  emissions (as N09)
                                                      X                 c.
were assumed to be controlled by boiler design and were estimated to be 260
ng/J.  New pulverized coal  fired boiler designs  include some type of NOX con-
trols.  However, if boiler design does not incorporate NOX controls, uncon-
trolled NO  emissions are expected to range from 280 ng/J to 430 ng/J.  In
          A
the case of  the boiler in Table 3-26, this would result in an increase of
8 to 65% in NO  emissions.  In an integrated facility, the flue gas would
              A
represent one of the major  uncontrolled gaseous waste streams  in  terms of
pollutant loading and volume.  It should be noted, however, that  combustion
emissions are not unique to indirect  liquefaction facilities and generally
present no new problems for emissions control over those encountered in elec-
tric utility or industrial applications.
Boiler Bottom Ash (Stream 304) and Fly Ash (contained in Stream 302)
     Although data on the characteristics of bottom and fly ash for Illinois
coals are available,  no data were available for the subject Illinois No. 6
coal  but its  bulk composition is expected to reflect the major inorganic ele-
ments found in the raw coal  (see Table 3-2).   Table 3-27 summarizes  available
data  on the maximum  levels of various constituents which have been reported

                                      131

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Section 3
Auxiliaries
in ash slurry waters from coal-fired boilers.
  TABLE 3-27.  COMPARISON OF ASH AND ASH SLURRY MAXIMUM CONCENTRATIONS (72)

As
Ba
Cd
Cr
Pb
Hg
Se
Ag
F-
cr
Cu
Fe
Mn
so4
Zn
Fly
Ash
ppm
1,700
13,900
250
7,400
1,600
22
500
50
624
25,000
3,020
289,000
4,400
13,000
Bottom
Ash
ppm
40
4,000
250
270
35
4
7.7
25
100
1,800
720
204,000
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

Boiler Slowdown (Stream 303)
      The  quality  of  the  boiler blowdown wastewater stream will be dictated
 by  the  boiler  drum operating  pressure.  In  this analysis a boiler drum opera-
 ting  pressure  of  10.3 MPa  is  assumed for all  synthesis  process  cases.
 Maximum silica concentrations and specific  conductivity  concentrations
 allowed in  boilers at this  pressure are 2.0 mg/L and  150 micromhos/cm,
                                      132

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                                                                 Section 3
                                                                 Auxiliaries
respectively.  As the pressure of the blowdown stream is reduced to atmo-
spheric pressure, 62% of the blowdown will  flash to steam leaving a stream
with a specific conductivity of approximately 400 micromhos/cm.  Assuming
a one to one ratio between specific conductance and total dissolved solids,
this results in a maximum dissolved solids concentration of 400 mg/L.   The
dissolved solids will contain varying quantities of phosphates or other
treatment chemicals, trace metals, and contaminants resulting from condenser
leakage.  This water can either be reused directly (e.g., as cooling tower
makeup) or returned to the boiler feedwater pretreatment system as discussed
in Section 3.6.1.  It is assumed that 1% of the steam made is lost as  blow-
down from the steam drum.  In the case of the K-T based methanol plant this
is equivalent to 2145 kg/hr.
     An energy efficient indirect liquefaction plant will produce large quan-
tities of low pressure steam from process waste heat boilers.   The specific
conductivity of the blowdown from these low pressure boilers can range as
high as 2000-5000 micromhos/cm for boilers  in the 4.1  MPa to 6.9 MPa range.
After flashing to atmospheric pressure, the blowdown concentrations can be
two to three times higher.   The design, economic, and site-specific considera-
tions involved in determining the quantities of low pressure and high  pres-
sure steam generated in the model  plants are beyond the scope of this  study.
Supply steam pressure, low pressure boiler makeup water treatment, and
cascading reuse of high pressure boiler blowdown in the low pressure boiler
system are all  considerations that must be evaluated in terms of the overall
water management plan at a specific site.
     These blowdown flow rates can increase dramatically if severe condenser
leakage occurs.  However, since operation under severe leakage conditions
cannot be tolerated for a long period of time, the impact of these upset
conditions should be minimal.
                                    133

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Section 3
Auxiliaries
3.6.3  Cooling Operations
     In an indirect liquefaction facility, a certain portion of the input
energy to the 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 detailed designs and heat
balances were not developed for each of the indirect liquefaction facilities
addressed in this manual, some simplifying assumptions were made to develop
representative cooling system loads.
     Table 3-28 summarizes the discharge rates expected to arise from cool-
ing tower operations.  The energy rejection rate from the cooling system
was obtained  by assuming an overall  conversion efficiency of coal energy  (HHV)
to  useful  product energy of 52.4% in K-T  indirect  liquefaction  plants and
assuming  40%  of the  unrecovered thermal energy in  the feed  coal  is  rejected
through evaporative cooling in a cooling tower (63).  Under these assumptions,
the energy rejected through the cooling tower will not be significantly
affected  by the different coal types employed.  However, the energy rejec-
tion rate will be affected by the different overall efficiencies of the
Methanol,  Fischer-Tropsch, and Mobil M synthesis processes, and  the varia-
tion in the energy rejection rates  is directly reflected in the  calculated
cooling water evaporation rates for each model plant.
     Discharges from  cooling systems consist  of:   Slowdown  water (Stream
307),  evaporative  losses  (Stream  306), which  include  evaporated water,  en-
trained water (drift),  and  stripped gases.  Table  3-29  summarizes  the  cooling
tower  blowdown  and  drift  characteristics  for  a cooling  system  operating at
5 cycles  of  concentration  for a  K-T plant using  the  raw waters  described  in
Section 3.6.1  for  cooling  tower makeup.   The  blowdown/drift characteristics

                                     134

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                                                                Section 3
                                                                Auxiliaries
 are  intended to be typical of the  concentrations expected  for the Grand
 Chain,  Illinois location where  raw water  is  used as makeup.  These  charac-
 teristics  do not  necessarily represent  optimum  conditions  for any given  site,
TABLE 3-28.
COOLING SYSTEM MAKEUP WATER REQUIREMENTS FOR A K-T INDIRECT
LIQUEFACTION PLANT*
                              WaterRate (m3/hr) for Illinois No. 6 Coal Case
    Stream          Stream         Methanol      Mobil M     Fischer-Tropsch
     Name           Number    	Synthesis   Synthesis	Synthesis	
Cooling water       306
evaporation
rate (E)

Drift loss (D)      306
(0.01% of circu-
lation rate)+

Cooling water       307
blowdown  (BD)
flow rate (five
cycles of con-
centration)*
                        660
                        3.7
                        161
737
4.1
180
966
5.4
236
 Assumed cooling water inlet temperature 314K, outlet temperature 303K,
 cooling water flow rate = 36,980 m^/hr
^Calculation based on reference 74
^Cycles of concentration (CC) is calculated by the following equation:
 CC = (E + BD + D)/(BD + D)

     In addition to the concentrations of inorganic dissolved solids shown,

 scale and corrosion control additives would also be present in the blowdown/

 drift.  The control additives, especially chromate- and zinc-based inhibitors,
 will be a consideration in the treatment of cooling tower blowdown.  Treat-

 ment for removal of these inhibitors will be discussed in Section 4.
                                     135

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Section 3
Auxiliaries
TABLE 3-29.   ESTIMATED CHARACTERISTICS  OF  COOLING  TOWER  SLOWDOWN  AND  DRIFT*
     Slowdown/Drift Constituents
 Discharge  Concentration  for
 the  Illinois  No.  6  Coal  Case
	(mg/L except  pH)	
       HCOs
       S0§
       Ca++
       Na+
       CT
       Total  Dissolved Solidst
       Si02
       pH
            110
            650
            180
             45
            150
             75
           1210
             33
            8.0
  Blowdown/drift composition estimated using raw water makeup  chemistry  from
  Section 3.6.1.  Concentrations are presented for operation at 5  cycles of
  concentration.
 fTotal dissolved solids is the sum of the ions except Si02
     The number of cycles of cooling water concentration which can oe
achieved in the cooling tower is largely dependent upon the total  dissolved
solids (particularly CaCOj and CaS04) of makeup water to the system, and a
higher makeup water quality permits a larger number of cycles.  Also, in-
creasing the number of cycles of concentration has the effect of decreasing
the blowdown rate for a given system.  For calculation purposes, blowdown
flow rates are  based on cooling system operation at 5 cycles of concentration.
Operation at lower cycles of concentration to allow for discharge to a  sur-
face water or operation at higher cycles in order to minimize wastewater
volume and treatment equipment costs may be considered on a site-specific
basis.
                                     136

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                                                                  Section 3
                                                                  Auxiliaries
    The cooling operation at an indirect liquefaction facility can be a
critical factor in the disposal and reuse of process wastewaters.   The
use of treated process wastewaters as cooling tower makeup water will have
a significant effect on raw water makeup requirements and discharge stream
pollutant concentrations.  The impact of potential  emissions in both blow-
down and drift resulting from the reuse of treated  wastewaters will be
discussed in Section 4 under air and water pollution control.
3.6.4  Oxygen Production
    Oxygen required by the K-T gasification processes is assumed to be pro-
duced by standard cryogenic air separation units.   Oxygen purities assumed
in the gasification process mass flow calculations  are based on published
data for the subject coal, and no attempt has been  made to force consis-
tency.  It should be noted that the purity of oxygen utilized in the gasi-
fication process affects the quantity of the purge  stream from the down-
stream synthesis process and thereby affects synthesis efficiency.  There-
fore, a tradeoff 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.

     In an air separation plant, air is compressed  to 0.68 to 0.72 MPa and
cryogenically cooled to facilitate distillation of  oxygen, nitrogen, and
noble gases (75).  The oxygen stream, containing small quantities of nitro-
gen and argon, is compressed and sent to the gasifiers.  Air and oxygen
compressors can either be steam, gas, electric driven, or a combination
thereof.  Most of the separated nitrogen, containing small quantities of
oxygen, water,  and  carbon  dioxide, is vented to the  atmosphere.  However
a portion of the nitrogen may be utilized as an inert gas for blanketing
coal storage and transfer operations or as stripping gas for solvent regen-
eration in acid gas treatment.   The quantity of condensate resulting from
air compression depends upon atmospheric humidity and therefore is highly
                                     137

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Section 3
Auxiliaries
variable.   Condensate contains only dissolved gases  and can  be  utilized  as
a supplement to the plant's high quality water supply.
     Oxygen requirements for the design K-T gasification system are 132,200
kg/hr for Illinois No. 6 coal, and may increase by approximately 10% for
lower rank coals (23).
     Production of oxygen does not directly generate environmentally signifi-
cant waste streams,  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.  Reducing
the compressed air temperature prior to cryogenic cooling results in in-
creased drift and blowdown from the cooling towers because of increased
interstage compressor cooling required.  Emissions indirectly associated with
the compressors are dependent upon the type of power drive (either  steam,
gas, or electric).
3.6.5  Product and By-Product Storage
     The expected production  rates of upgraded liquid and gaseous fuels for
the K-T indirect liquefaction plant are presented in Section 3.5.  For pur-
poses of estimating potential emissions from the storage of liquid products,
a  15-day capacity is  assumed  in all cases.  Table 3-29 provides a summary of
the storage  capacities, vessel  types, and  estimated uncontrolled mass emis-
sion rates for  the various  liquids.  The more  volatile products (e.g., LPG)
are stored in pressure  vessels  and have no  routine evaporative  emissions.
Methanol and gasoline are  stored  in floating  roof tanks while  diesel  oil and
fuel oil are stored  in  fixed-roof tanks.
     Data  on the  components of  evaporative  emissions associated with  the
storage of coal derived liquid  fuels  are generally  lacking.  However, limited
 data are  available on evaporative emissions associated with  petroleum gasoline

                                     138

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             TABLE  3-30.  EVAPORATIVE EMISSION ESTIMATES FOR PRODUCT AND BYPRODUCT STORAGE*

Product
Methanol
Methanol
Methanol
Gasoline
Gasoline
Diesel Oil
Fuel Oil
No. of
Tanks
1
2
2
1
1
1
1
Capacity (m^)
Float Roof
(3200)
Float Roof
(45,000)
Float Roof
(46,500)
Float Roof
(22,000)
Float Roof
(39,000)
Fixed Roof
(3600)
Fixed Roof
(940)
Tank Diameter
(m)
18.2
62.5
64.0
43.6
53.3
19.5
11.6
Synthesis Case
Fischer-Tropsch
Methanol
Mobil M
Fischer-Tropsch
Mobil M
Fischer-Tropsch
Fischer-Tropsch
Vapor
Pressure
kPa
17.3
8.83
17.3
8.83
17.3
8.83
49.78
33.85
49.78
33.85
0.080
0.046
0.00059
0.00026
Uncontrolled Mass
Emission Rate*
(kg/hr)
8,740
6,630
59,790
45,360
61,250
46,470
21,790
20,430
28,950
27,140
800
500
9
5

Calculations based on information  contained in  AP-42 (76)

The higher values represent the  month  with  maximum average  emissions  (July).   The lower number
represents the average annual  values.

-------
Section 3
Auxiliaries
storage as indicated in Table 3-31.  In addition to the paraffins and olefins
listed in the table, aromatics are expected to be present in evaporative
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.
     Product sulfur storage may result in H?S emissions due to the evolution
of dissolved sulfide.  H~S may be liberated from the liquid sulfur either
inadvertantly during storage/handling operations or as a result of intentional
liquid sulfur degassing to produce a sulfide-free product.  Intentional de-
gassing may be employed to minimize the fire and toxicity hazards potentially
associated with liquid sulfur handling.  Data are not publicly available
relating to the magnitude of such potential H-S emissions or to typical con-
trol practices in the sulfur industry.  In any case, such emissions are not
unique to coal gasification and hence are not further addressed in this
manual.
                                     140

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TABLE 3-31. COMPOSITION OF EVAPORATIVE EMISSIONS

Section 3
Auxiliaries
FROM GASOLINE STORAGE (77)

Compound
Methane
Ethyl ene
Ethane
Propylene
Propane
Isobutane
Isobutylene
n-butane
cis-2-butane
Isopentane
n-pentane
Hexanes
Heptanes
Octanes
Vol %*
1
0
0
0
0
3
1
3
0
6
2
0
0
0
.13
.001
.15
.03
.82
.03
.12
.53
.84
.18
.89
.44
.16
.17

Balance is air
                                 141

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Section 3
Fugitive Wastes
3.7  FUGITIVE AND MISCELLANEOUS WASTES
     In this section gaseous and liquid emissions from process equipment,
emergency process discharges and washup/cleanup activities are discussed.
Emission estimates for these streams are based upon petroleum refining experi-
ence.
3.7.1  Fugitive Organic Emissions (Stream 241)
     There are many potential sources of gaseous fugitive emissions in an
indirect coal liquefaction plant.  These sources include:  pumps, compressors,
in-line process valves, pressure relief devices, open-ended valves, sampling
connections, flanges, agitators, and cooling towers.  Extensive tests and
measurements for fugitives have been performed at petroleum refineries (78).
As a result of this testing, average emission factors have been developed for
fugitive emission sources such as pump seals, compressor seals, valves, etc.
(79).  These factors can be applied to synfuel plants because plant opera-
tions following synthesis are quite similar to those in petroleum refining.
Although the plant boundary as stated in Section 3.4.5 excludes upgrading
processes, these processes were included in estimating fugitive organic emis-
sions since these processes are the major contributors to fugitive organic
emissions in a K-T based indirect liquefaction facility.
     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, com-
pressors, and process units for synfuel plants was estimated by correlating
equipment lists to the proper size synfuel plant or adjusting the equipment
counts reported in conceptual designs.  Equipment spares were counted in
determining the number of pumps and compressors, because it was assumed  that
spares usually contain fluid under pressure.
     The process streams associated with each piece of equipment were clas-
sified with respect to percent  hydrocarbon content  and hydrocarbon type.
                                      142

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                                                              Section  3
                                                              Fugitive Wastes
 Different  factors were used for liquid streams containing light and heavy
 hydrocarbons.   Liquid streams containing C2 through Cg hydrocarbons, naphtha,
 and other  aromatic hydrocarbons were classified as light.  Kerosene, diesel
 oil, and other  heavy hydrocarbons were classified as heavy.  All emission
 factors shown assume 100% 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% hydrocarbons were
 neglected  and those containing greater than 80% were considered to contain
 100%.  Gaseous  streams were classified as either hydrocarbon or hydrogen
 depending  on which was present in a greater percentage.  The compressor seal
 emission factors for these two classifications were used as reported and not
 adjusted for percent hydrocarbon content.
     Results of these fugitive emission calculations for K-T based indirect
 liquefaction facilities are given in Table 3-32.  The data indicate that
 methanol plants are expected to have considerably lower fugitive organic
 emissions  than  Fischer-Tropsch plants.  In-line valves are the single biggest
 contributor to  total fugitive organic emissions for all facilities.
 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 discharges or process area washdown/cleanup activities will  contribute
 additional  intermittent aqueous  wastes.   All  of these wastes would normally
 be collected in a process or oily waste sewer and routed to a common treat-
ment system.  The estimated flow rates of the combined wastewaters from these
 types of sources in the subject  plants are summarized in Table 3-33.
     These process  drainage calculations  are based upon refinery experience
and are estimated as 2% of the total  raw  water makeup to the plant (80).
Since the process drainage flow  rate  is based on the total  plant raw water

                                     143

-------
         TABLE  3-32.   ESTIMATED TOTAL  FUGITIVE ORGANIC  EMISSIONS


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)
0.154
0.029
0.027
0.011
0.00023
0.086
1.28
0.10
0.00025
0.07
Uncontrol
Fischer-
Tropsch
16.74
0.52
34.72
37.02
0.14
24.77
12.8
1.8
1.09
10.94
140.5
led Emission Rates
(kg/hr)
Methano'l
3.17
0.23
7.78
7.09
0.06
5.16
2.88
--
1.18
2.45
30.0
Mobil M
7.09
0.38
15.39
15.68
0.09
11.35
1.54
--
2.42
4.90
58.8

Uncontrolled emission factors for pumps
emissions from each pump and compressor
compressor seal.
and compressors represent
and not from each pump seal and
                                   144

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                                                             Section 3
                                                             Fugitive Wastes
makeup  rate,  it will  vary with  coal  type and synthesis  process as discussed
in  Section  3.6.1.
     TABLE  3-33.  DRAINAGE  ESTIMATE  FROM NON-PROCESS/INTERMITTENT STREAMS
                                                    Drainage  Flow  Rate
	Stream	m3/hr	
       Process drain effluent  (Stream  315)*               32 - 42

       Storm drain effluent  (Stream 314)                    47
—.-                                                   _______________________
  Flow rate based on  2% of  total raw  water makeup to the plant

     Both the flow rate and composition of these wastewaters  will vary widely
among the different  plants.   Of course, good housekeeping and mainten-
ance 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
estimates were developed for these streams.  The treatment of these streams
and their impact on facility costs and energy usage will be discussed in
Section 4.
     Storm runoff water flow rates will be a function of the surface drain-
age area of the plant site and the annual rainfall.   For calculation purposes,
a plant site drainage area of 100 surface acres was  used with an annual  rain-
fall rate of 1 m/yr (81).   The average storm runoff flow was estimated to be
47 m3/hr (refer  to Table 3-33).
     The composition of storm runoff from the area will vary with the fre-
quency of a rainfall  occurrence and with time during a rainfall occurrence.
The major contaminants potentially requiring control are total  suspended

                                     145

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Section 3
Fugitive Wastes
 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 de-
 tailed composition.
 3.7.3    Equipment Cleaning Wastes (Streams  242 and 305)
     The two  primary sources of  equipment cleaning wastes at an indirect
 liquefaction  facility are  process equipment  (Stream 242) 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 pressure  vessels.  The volume of cleaning waste generated will be deter-
 mined  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 dumps  in excess of 3800 m  over short periods
 of time.   Boiler  cleaning  wastes will probably be the  largest single  source
 of cleaning wastes  at  an indirect  liquefaction facility.
      The composition  of  equipment  cleaning  wastes will  vary with  the  clean-
 ing agent  used and  the material  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 (scal-
 ing) materials and  metal corrosion products with  acidic and  alkaline clean-
 ing agents.  Rinse  volumes from both  process and  boiler cleaning  wastes con-
 tain lower contaminant concentrations  than  the cleaning wastes  themselves
 but can amount to 2 to 5 times the volume of the  cleaning waste.   Treatment
 of these wastes is  difficult because 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 an indirect liquefaction
 facility.
                                      146

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                                                                 Section 3
                                                                 Stream Index
3.8  WASTE/CONTROL TECHNOLOGY INDEX
     The preceding parts of this section have provided a general  description
of K-T based synfuels facilities and test data and engineering estimates
characterizing the uncontrolled or primary waste streams expected.  Section 4
of this manual presents information on the available control  techniques for
these primary waste streams and illustrative examples of both individual con-
trol  technologies and integrated systems of control technologies  applied to
specific streams.  As will be discussed in Section 4, residuals or secondary
waste streams are generated as a result of the application of some control
technologies; control of secondary waste streams is discussed in  conjunction
with the illustrative examples.  A summary of the process streams and primary
and secondary waste streams discussed in this manual is presented in Table
3-34.
     To aid users in finding characterization data and control technology
information for any waste stream addressed in this manual, a cross reference
index was developed.  This index is presented in Table 3-35 and indicates
where characterization data can be found in Section 3 and where control tech-
nology information can be found in Section 4 for each primary waste stream.
The waste streams in Table 3-35 are grouped by the operation or auxiliary
process from which they originate and then further grouped within each opera-
tion by waste medium.  Similar types of information on secondary  waste
streams are presented in Table 3-36.  The entries in Table 3-36 are not meant
to imply that those streams will necessarily be found in K-T based facilities,
but that if the control techniques listed  are used, then those streams will
be produced.
                                     147

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                    TABLE  3-34.   STREAM  INDEX
                Main  Process  Streams  (Numbers  1-99)
 Coal  Preparation
 1.   Run of mine coal
 2.   Prepared coal  to gasifier
 Gasification
 3.   Gasifier steam
 4.   Oxygen
 5.   Quench ring water to gasifier
 6.   Raw quenched  gas from waste heat boiler
 Gas Purification  and Upgrading
 7.   Raw gas from  washer cooler
 8.   Raw gas after NOV reduction
                     /\
 9.   Raw compressed gas
10.   Compressed gas after cyanide wash
11.   Desulfurized  gas to shift conversion
12.   Desulfurized  shift conversion bypass gas
13.   Shift gas to  C0~ absorber
14.   Synthesis gas
15.   Nitrogen strip gas
 Product Synthesis
20.   Crude methanol
21.   Crude Mobil M-gasoline products
22.   Crude Fischer-Tropsch synthesis products
23.   Methanation product gas
24.   C02-free SNG
25.   Purge gas to methanation

                                                       (Continued)
                               148

-------
TABLE 3-34.  (Continued)
      Auxiliaries
      30.  Prepared coal  to boiler
      31.  Plant raw water
      32.  Cooling tower makeup water
      33.  Boiler feed water

              Product and By-Product Streams (Numbers 100-199)
      Fischer-Tropsch Synthesis
      100.  Gasoline
      101.  Diesel oil
      102.  Heavy oil
      103.  Methanol
      104.  Ketones
      105.  Heavy alcohols
      106.  LPG
      107.  SNG
      Methanol Synthesis
      108.  Fuel grade methanol
      Mobil M-gasoline Synthesis
      109.  Gasoline
      110.  Mixed butanes
      111.  Propane
      By-Products
      112.  Sulfur

       Discharge Streams from the Main Process Train (Numbers 200-299)
      Coal Preparation
      200.  Fugitive dust from raw coal storage
                                                           (Continued)

                                     149

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TABLE 3-34.  (Continued)
     Coal Preparation (continued)
     201.  Raw coal storage runoff
     202.  Fugitive dust from coal screening and crushing
     203.  Fugitive dust from screened/crushed coal transfer
     204.  Fugitive dust from coal pulverizing
     205.  Fugitive dust from pulverized coal storage and feeding
     206.  Emissions from thermal dryers
     Gasification
     207.  Quenched slag
     208.  Transient waste gases
     Gas Purification and Upgrading
     209.  Dewatered dust
     210.  Cooling and dust removal blowdown
     211.  Raw gas compression and cooling condensate
     212.  Spent NO  reduction catalyst
                   A
     213.  Aqueous still bottoms from methanol based cyanide wash
     214.  Sour flash gas from cyanide wash
     215.  Cyanide wash water
     216.  H2S-rich offgas
     217.  Spent shift catalyst
     218.  Shift condensate blowdown
     219.  C02-rich offgas
     220.  Rectisol condensate/still bottoms
     221.  Spent sulfur guard
     Product Synthesis
     222.  Spent F-T catalyst
     223.  F-T wastewater
     224.  Fractionator light gas
     225.  Methanol synthesis expansion gas
                                                         (Continued)
                                     150

-------
TABLE 3-34.  (Continued)
      Gas Purification and Upgrading (continued)
      226.  Methanol synthesis purge gas
      227.  Spent methanol synthesis catalyst
      228.  Methanol distillation offgas
      229.  Methanol distillation wastewater
      230.  Fuel gas from Mobil synthesis
      231.  Mobil synthesis catalyst regeneration/decommissioning offgas
      232.  Spent Mobil catalyst
      233.  Mobil synthesis condensate
      234.  Mobil fractionator offgas
      235.  C02 removal condensate
      236.  Methanation condensate
      237.  Methanation catalyst regeneration/decommissioning offgas
      238.  Spent methanation catalyst
      239.  COp offgas from SNG purification
      240.  Dehydration offgas
      Miscellaneous Waste Streams
      241.  Fugitive organic emissions
      242.  Equipment cleaning wastes

        Discharge Streams from Auxiliary Processes (Numbers 300-399)
      Raw Water Treatment
      300.  Raw water treatment sludges
      301.  Demineralizer regeneration wastewater
      Power Generation
      302.  Flue gases from power generation
      303.  Boiler blowdown
      304.  Boiler bottom ash
      305.  Boiler cleaning wastes
                                                           (Continued)

                                     151

-------
TABLE 3-34.  (Continued)
      Cooling Tower
      306.  Cooling tower evaporation/drift
      307.  Cooling tower blowdown
      Product/By-Product Storage
      308.  Evaporative emissions from methanol storage
      309.  Evaporative emissions from gasoline storage
      310.  Evaporative emissions from diesel oil storage
      311.  Evaporative emissions from heavy oil storage
      312.  Evaporative emissions from ketones storage
      313.  Evaporative emissions from heavy alcohols storage
      Miscellaneous
      314.  Storm drain effluent
      315.  Plant process drains effluent

    Discharge Streams from Pollution Control Processes (Numbers 400-499)
      Coal Preparation
      400.  Coal particulates from coal preparation
      Gasification
      No secondary waste streams are associated with this process area.
      Gas Purification and Upgrading and Product Synthesis*
      401.  Catalyst regeneration offgas from Claus process
      402.  Claus spent catalyst
      403.  Claus sulfur
      404.  Stretford oxidizer vent gas
      405.  Sour condensate from Beavon/Stretford process
                                                          (lontTnueBl
*Secondary waste stream numbers 401 to 414  result from control processes
 treating waste streams from gas purification and upgrading operations only,
 Secondary waste stream numbers 415 to 422  result from control processes
 treating combined waste streams from gas purification and upgrading, and
 product synthesis
                                      152

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TABLE  3-34.  (Continued)
     Gas Purification and Upgrading and Product Synthesis (continued)
     406.  Stretford solution purge
     407.  Beavon/Stretford spent catalyst
     408.  Beavon/Stretford sulfur
     409.  SCOT sour condensate
     410.  SCOT spent catalyst
     411.  Wellman-Lord acidic wastewater
     412.  Wellman-Lord thiosulfate/sulfate purge
     413.  Flue gas from fluidized bed boiler
     414.  Spent bed media from fluidized bed boiler
     415.  Activated sludge solid waste
     416.  Sulfide/cyanide offgas
     417.  Filtration backwash
     418.  Denitrification waste sludge
     419.  Evaporation/drift from cooling tower concentration
     420.  Regeneration offgas from granular activated carbon
     421.  Offgas from liquid waste incinerators
     422.  Offgas from solid waste incinerators
     Auxiliaries
     423.  Boiler fly ash from ESPs/fabric filters
     424.  FGD sludge from lime/limestone scrubbing
     425.  Thiosulfate/sulfate purge from Wellman-Lord FGD process
     426.  Sulfur from Wellman-Lord FGD process
                                    153

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                      TABLE 3-35.   CROSS-REFERENCE  INDEX  FOR PRIMARY WASTE STREAMS
                Stream Identification
                                                 	PCTM Section Reference	
                                                 Waste Characterization	Control Techniques
en
Coal Preparation
   Gaseous Waste Streams
   Fugitive dust emissions from raw coal
   storage piles (Stream 200)
   Crushing/screening/transfer/pulverizing
   dust (Streams 202, 203, 204)
   Particulate emissions from prepared coal
   storage and feeding (Stream 205)
   Emissions from thermal dryers (Stream 206)
   Aqueous Waste Streams
   Raw coal storage pile runoff (Stream 201)
Coal Gasification
   Gaseous waste Streams
   Transient waste gases (Stream 208)
   Solid Waste Streams
   Quenched slag (Stream 207)
Section 3.1

Section 3.1

Section 3.1

Section 3.1

Section 3.1
                                                           Section  3.2
                                                          Section  3.2
Section 4.1.4

Section 4.1.6

Section 4.1.6

Section 4.1.2.1

Section 4.2.1
                            Section 3.2
                            Section 4.3.2.1
                                                                                      (Continued)

-------
     TABLE  3-35.  (Continued)
                   Stream Identification
                                                                      PCTM Section Reference
                                                 Waste Characterization
                          Control Techniques
en
en
Gas Purification and Upgrading

   Gaseous Waste Streams

   Sour flash gas from cyanide wash - water
   wash case (Stream 214a)

   Sour flash gas from cyanide wash - methanol
   wash case (Stream 214b)

   H2S-rich offgas (Stream 216)


   C02-rich offgas (Stream 219)

   Aqueous Waste Streams

   Cooling and dust removal  blowdown
   (Stream 210)

   Raw gas compression and cooling
   condensate (Stream 211)

   Cyanide wash water (Stream 215)

   Cyanide wash still bottoms -  methanol
   wash case (Stream 213)

   Shift condensate blowdown (Stream 218)

   Rectisol  condensate/still  bottoms
   (Stream 220)
Section 3.3.4


Section 3.3.4


Section 3.3.6


Section 3.3.6



Section 3.3.1


Section 3.3.3


Section 3.3.4

Section 3.3.4


Section 3.3.5

Section 3.3.6
                                                                                       Sections 4.1.1.2
                                                                                       and 4.1.1.5

                                                                                       Sections 4.1.1.2
                                                                                       and 4.1.1.5

                                                                                       Sections 4.1.1.1
                                                                                       and 4.1.1.5

                                                                                       Section 4.1.1.3
                                                                                       Section 4.2.3.3


                                                                                       Section 4.2.3.2


                                                                                       Section 4.2.3.1

                                                                                       Section 4.2.1


                                                                                       Section 4.2.1

                                                                                       Section 4.2.1
                                                                                       (Continued)

-------
     TABLE 3-35.  (Continued)
                   Stream Identification
                                                                      PCTM  Section Reference
                                                 Waste Characterization
Control Techniques
en
01
   Solid Waste Streams

   Dewatered dust (Stream 209)

   Spent NOV reduction catalyst (Stream 212)
           /\

   Spent shift conversion catalyst
   (Stream 217)

   Spent sulfur guard (Stream 221)

Product Synthesis

   Gaseous Waste Streams

   Mobil  synthesis catalyst regeneration
   offgas (Stream 231)

   Methanation catalyst decommissioning
   offgas (Stream 237)

   C09 offgas  from SNG purification
   (Stream 239)

   Dehydration offgas  (Stream 240)

   Liquid Waste Streams

   Methanol  distillation wastewater
   (Stream 229)

   F-T wastewater (Stream 223)
                                                           Section  3.3.1

                                                           Section  3.3.2

                                                           Section  3.3.5


                                                           Section  3.3.7
                                                          Section 3.4.6


                                                          Section 3.4.6


                                                          Section 3.4.6


                                                          Section 3.4.6



                                                          Section 3.4.6


                                                          Section 3.4.6
  Section 4.3.2.2

  Section 4.3.5

  Section 4.3.5


  Section 4.3.5
  Section  4.1.3.2


  Section  4.1.3.2


  Section  4.1.3.1


  Not evaluated



  Section  4.2.2.3


  Section  4.2.2.2
                                                                                      (Continued)

-------
     TABLE 3-35.  (Continued)
                   Stream Identification
                                                 Waste Characterization
PCTM Section Reference	
               Control Technique?
en
   Mobil synthesis condensate (Stream 233)
   Methanation condensate (Stream 236)
   Solid Waste Streams
   Spent methanol synthesis catalyst
   (Stream 227)
   Spent F-T catalyst (Stream 222)
   Spent Mobil catalyst (Stream 232)
   Spent methanation catalyst (Stream 238)
Auxiliaries
   Gaseous Waste Streams
   Boiler flue gases (Stream 302)
   Cooling tower evaporative losses
   (Stream 306)
   Evaporative emissions from product and
   by-product storage (Streams 308  through  313)
   Fugitive organic emissions (Stream 241)
   Aqueous Waste Streams
   Demineralizer regeneration wastewaters
   (Stream 301)
                                                           Section  3.4.6
                                                           Section  3.4.6

                                                           Section  3.4.6

                                                           Section  3.4.6
                                                           Section  3.4.6
                                                           Section  3.4.6
                                                           Section  3.6.2
                                                           Section  3.6.3

                                                           Section  3.6.5

                                                           Section  3.7.1

                                                           Section  3.6.1
                 Section 4.2.2.1
                 Section 4.2.1

                 Section 4.3.5

                 Section 4.3.5
                 Section 4.3.5
                 Section 4.3.5
                 Section 4.1.2.1
                 Not evaluated

                 Section 4.1.5.1

                 Section 4.1.5.2

                 Section 4.2.1
                (Continued)

-------
00
TABLE 3-35.  (Continued)
                                                                 PCTM Section Reference
              Stream Identification _ Waste Characterization        Control  Techniques

    Boiler blowdown (Stream 303)                       Section 3.6.2               Section 4.2.1

    Cooling tower blowdown (Stream 307)                Section 3.6.3               Section 4.2.1

    Process drain effluent (Stream 315)                Section 3.7.2               Section 4.2.1

    Storm drain effluent (Stream  314)                  Section 3.7.2               Section 4.2.1

    Equipment cleaning wastes  (Streams  242             Section 3.7.3               Section 4.2.1
    and 305)

    Solid Waste Streams

    Raw water treatment sludges  (Stream  300)           Section 3.6.1                Section 4.3.2.8

    Boiler bottom ash (Stream  304)                     Section 3.6.2               Section 4.3.2.3

-------
                 TABLE  3-36.  CROSS-REFERENCE INDEX FOR SECONDARY WASTE STREAMS
       Control Technology/Secondary Waste
     Waste
Characterization
                                                                PCTM Section Reference	
                                                                                   Control  Technology
   Control
  Technique
Appendix^
Air Pollution Control

   Claus Process

   Catalyst regeneration offgas  (Stream 401)

   Spent catalyst (Stream 402)


   Sulfur (Stream 403)

   Beavon/Stretford Process

   Stretford oxidizer  vent gas  (Stream 404)


   Sour condensate (Stream 405)


   Stretford solution  purge  (Stream  406)


   Spent catalyst (Stream 407)


   Sulfur (Stream 408)

   Shell Claus Offgas  Treatment  (SCOT)  Process

   Sour condensate (Stream 409)
Sections 4.1.1
and 4.1.1.1
Sections 4.1.1
and 4.1.1.1

Sections 4.1.1
and 4.1.1.1

Sections 4.1.1
and 4.1.1.1

Sections 4.1.1
and 4.1.1.1
Section 4.1.1
and 4.1.1.1
Not evaluated

Section 4.3.5


Section 4.3.3.1



Not evaluated


Section 4.2.3.4


Section 4.2.3.4


Section 4.3.5


Section 4.3.3.1



Section 4.2.3.4
                                          A-6
                                          A-9
                                          A-8
                                                                               (Continued)

-------
     TABLE 3-36.  (Continued)
                                                                      PCTM Section Reference
            Control Technology/Secondary Waste
                                                  Waste             Control     Control Technology
                                             Characterization	Technique	Appendix*
CTl
o
Spent catalyst (Stream 410)

Wellman-Lord Process
Acidic wastewater (Stream 411)

Thiosulfate/sulfate purge (Stream 412)

Electrostatic Precipitators
Boiler fly ash (Stream 423)
Limestone Scrubbing
FGD sludge (Stream 424)
Wellman-Lord FGD Process
Thiosulfate/sulfate purge (Stream 425)
Sulfur (Stream 426)
Coal Particulate^ Dry Collectors^
Coal particulate (Stream 400)
                                                      Sections 4.1.1
                                                      and 4.1.1.1
                                                      Sections 4.1.1
                                                      and 4.1.1.1
                                                      Sections 4.1.1
                                                      and 4.1.1.1
Section 3.6.2
                                                      Section 4.1.2
                                                      Section  4.1.2
                    Section 4.3.5
                    Section 4.2.3.4
                    Section 4.2.3.4
                                                      Section  3.1
Section 4.3.2.4

Section 4.3.2.5

Section 4.2.3.4
Section 4.3.3.1

Section 4.3.3.2
                                                                                                A-10
                                                                                                A-13
                                                                                                A-20
                                                                                                A-10
                                                                                              A-ll.A-12
                                                                                       (Continued)

-------
      TABLE  3-36.   (Continued)
                                                                       PCTM  Section  Reference
             Control  Technology/Secondary Waste
                                                     Waste             Control      Control Technology
                                                Characterization	Technique	Appendix*
cr>
Water Pollution Control

   Activated Sludge

   Sulfide/cyanide offgas (Stream 416)

   Waste sludge (Stream  415)


   Filtration

   Backwash (Stream 417)

   Biological Denitrification

   Waste sludge (Stream  418)


   Cooling Tower Concentration

   Evaporation/drift (Stream 419)


   Granular Activated Carbon

   Regeneration offgas (Stream  420)

   Incineration^

   Flue gas (Stream 421)
                                                      Section 4.2.4

                                                      Sections 4.2.2.1,
                                                      4.2.3.1, 4.2.3.2
Section 4.1.1.4

Section 4.3.4
                                                      Section 4.2.2.1      Section  4.2.2.1
                                                      Sections 4.2.3.1    Section  4.3.4
                                                      and 4.2.3.2
                                                      Sections 4.2.2.1,
                                                      4.2.3.1, 4.2.3.2
Not evaluated
                                                      Section 4.2.2.1     Section  4.2.2.1
                                                      Section 4.2.2.1     Section  4.2.2.1
                                                                                               B-10,B-23
                                                                                                 B-4
                                                                                                 B-23
                                                                                                 B-18
                                                                                                 B-15
                                                                                                 B-17
                                                                                       (Continued)

-------
      TABLE  3-36.   (Continued)
                                                                       PCTM Section  Reference
             Control  Technology/Secondary Haste
     Waste
Characterization
   Control
  Technique
       Solid Waste Management
          Fluidized  Bed  Combustion Boiler
          Boiler  flue gas  (Stream 413)
          Spent bed  media   (Stream 414)
          Incineration
          Flue gas (Stream  422)
Section 4.3.2.2
Section 4.3.2.6

Section 4.3.4.1
Section 4.1.2.3
Section 4.3.2.6

Section 4.3.4.1
o>
ro
       The Control Technology Appendices  for  the  PCTMs  are  compiled in a separate volume.

-------
                                                            Section  4
                                                            Pollution  Control
                                 SECTION 4
                 EVALUATION OF POLLUTION CONTROL TECHNOLOGY

     At the present time, no K-T based indirect liquefaction plants are opera-
ting in the United States, although the K-T process is widely used in other
countries for the production of hydrogen (primarily for ammonia) and fuel gas.
The emphasis on pollution control which has been incorporated into designs
for facilities abroad is generally less than that which is anticipated for
U.S. facilities.  Thus, directly applicable performance data for most pollu-
tion control technologies are quite limited.  The potential applicability of
most pollution control technologies to waste streams identified in Section 3
has, therefore, been inferred from their use in similar applications in indus-
tries 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 definition of the principal limita-
tions of these controls methods in K-T based synfuels plants.  Control alter-
natives evaluated include process modifications (relative to existing designs)
in addition to add-on controls.
     Approach
     In this section a wide variety of potentially applicable pollution con-
trol 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 (e.g., gaseous,
aqueous, and solid waste).
     Descriptions of the pollution control  technologies presented in this
section are based upon more detailed descriptions provided in the Control
Technology Appendices.  Performance data for control technologies have been

                                     163

-------
Section 4
Pollution Control
obtained primarily from the open literature and have been supplemented by
vendor-supplied data in some cases.  The capabilities of various controls
have not usually been assessed on a design-specific basis, but rather upon
a generalized basis derived from test results and/or engineering studies of
the subject technologies.    Example performance levels used for evaluation
purposes encompass most of the published data.  Therefore, only limited data
referencing is provided in Section 4; detailed references are available in
the Control Technology Appendices.
     In many cases, performance can only be estimated in terms of control of
major constituents (e.g.,  hydrogen sulfide)  or  gross  parameters  (e.g.,
COD) since often no information is available for removal efficiencies of
specific substances.   Further, even in those cases where substance-specific
performance information exists for a control  technology, accurate or complete
characterization of the waste stream requiring control may be lacking.  In
the final analysis, the capabilities of controls can only be accurately eval-
uated by testing at operating facilities or at smaller units from which data
can be confidently extrapolated to commercial size.  The performance estimates
in this document are believed to reflect the best information publicly avail-
able based on actual  experience and on engineering analysis.
     In providing example applications of pollution control  technologies,
waste streams unique to K-T based synfuels facilities and large volume/high
loading waste streams have been emphasized.  The source and characteristics
of these waste streams have been detailed in Section 3, and those characteris-
tics of principal significance with regard to the application of pollution
control technologies are reiterated in this section.  It should be 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

                                     164

-------
                                                           Section 4
                                                           Pollution Control
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 con-
sider design-specific waste stream characterization data whenever they are
available and to use the detailed Control Technology Appendices for estimat-
ing the applicability and performance of specific controls to waste streams.
The control examples in this section emphasize the Illinois No. 6 coal and the
the base plant defined in Section 3.  Effects of coal characteristics and
design modifications are discussed in those cases where either may signifi-
cantly influence the control performance or cost.
     Reliability of pollution control processes in U.S.  coal  conversion
facilities will  depend largely upon the time required to determine the
optimum operating conditions and the emphasis placed upon operation and
maintenance.  In essentially any industry, the introduction of a new process
or modification of an older process for application to new streams meets with
unexpected problems relating to both design features and operating practices.
Thus, some shakedown period must be expected where process performance,
efficiency, and on-stream time will improve.  Once a process is properly char-
acterized for a specified application, reported reliability in terms of on-
stream time and performance levels may still vary among facilities.  Some-
times the specific design is a factor, but reliability also reflects the
emphasis placed upon operation and maintenance.  A properly trained operating
crew and a regular maintenance regimen can significantly improve the reli-
ability of well  designed pollution control equipment.
     Because most of the potentially applicable pollution control technologies
have not been employed  in synthetic  fuels  facilities, few  directly  related
reliability data are available.  Further, the overall characteristics and
variability of waste streams in coal conversion facilities are often signif-
icantly different from those encountered in other industries.  As a result,
reliability data accumulated in other industries may not be directly
                                     165

-------
Section 4
Pollution Control
applicable to coal conversion processes.  Published reliability data for con-
trol technologies in other industrial applications are summarized in the Con-
trol Technology Appendices.  However, in this section, reliability is dis-
cussed primarily in terms of those factors which have a major influence upon
process operation and stability.
     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 and 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
descriptions and control examples presented in Section 4.1 (Gaseous Medium)
are by waste stream categories or source types to which they apply.
     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 Sections
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 section prior to the presentation of control examples.

                                     166

-------
                                                           Section 4
                                                           Pollution Control
     Costing Methodology
     Capital and operating cost estimates have been developed for the control
processes discussed in this section.  These cost estimates are based pri-
marily on estimates contained in non-proprietary published literature.   The
estimates are provided to give the reader an indication of the costs of con-
trols that are applicable to K-T based synthetic fuels plants.  It was  beyond
the scope of this manual 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 manual.
     Material and energy balances were derived mainly from commercial synfuels
tests, from data from analog industries, and from results of engineering cal-
culations, as described in Section 3.  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.
     Sources of cost data used in this manual are published costs for pro-
cesses applied to similar streams in related industries, costs from published
detailed design studies, 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, and the degree of similarity  of
the streams.  Also, the accuracy of the estimates and the components included
in the cost estimates (e.g., contingency reserves and working capital), are
not always provided in the reference.  Thus, extrapolation of these costs to
the stream being treated in this manual will also introduce uncertainties.
                                     167

-------
Section 4
Pollution Control
     The costing methodology used in this manual  (see Appendix A for details)
also introduces some uncertainties.  Other estimators may have used differ-
ent factors or weighted them differently.  In addition, available cost esti-
mates were adjusted to a 1980 basis using the Chemical Engineering plant
cost annual index.  It is also 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 informa-
tion presented will vary from control  to control.    However, the cost infor-
mation presented is believed to be adequate for the use intended.
     Capital  costs presented are total  depreciable investment costs.   Included
in the total  depreciable investment costs are (1)  installed equipment costs,
(2) indirect installation charges (including construction and engineering
costs, contractor fees, and contingency), and (3)  interest during construc-
tion.  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 methodology and other pertinent assumptions and bases which
were used to develop the cost estimates are presented in Appendix A.
                                     168

-------
                                                                Section 4
                                                                Gaseous Medium
4.1  GASEOUS MEDIUM
     Gaseous waste streams, or uncontrolled gaseous emissions, originating
from the main process train and from non-pollution control auxiliary processes
in a K-T based gasification facility, were identified in Section 3.  Char-
acteristics of these streams and additional gaseous waste streams generated
by pollution control processes are summarized in Table 4-1.  In terms of
volume and pollutant loading, the most important streams in the subject
facilities are Rectisol acid gases, flash gases from cyanide washing, and
combustion flue gases.  Pollutants of primary concern in these streams are
reduced sulfur species, S02, HCN, CO, and particulates.  These pollutants
may also be present in intermittent transient waste gases generated during
startup, shutdown, and transient operations.  Smaller volume waste gases sucn
as regeneration/decommissioning offgases, COp-rich offgases from SNG purifica-
tion, condensate depressurization offgases, fugitive organic emissions, and
evaporative emissions may contain non-methane organics  (or VOC-volatile
organic compounds),  CO, or  particulate emissions.  An additional  source of
particulate emissions  is the coal preparation operation.
     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.  Non-unique streams  are associated with auxiliary
operations within an integrated facility.  In Section 3, gaseous wastes were
identified and characterized from the standpoint of their origin in an inte-
grated 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 K-T facilities are primarily those containing reduced sulfur, non-methane
organics, and smaller amounts of HCN and NH3>  These streams are: (1) Rectisol
acid gases, (2) flash gases from the cyanide wash, and (3) gasifier transient
waste gases.  Another unique stream which contains VOC, CO, and/or particulates
is the Mobil M-catalyst regeneration offgas.  Non-unique streams common to
                                      169

-------
TABLE  4-1.    SUMMARY  OF  ESTIMATED  GASEOUS  WASTE  STREAM  CHARACTERISTICS   IN   K-T  BASED  INDIRECT  LIQUEFACTION
                    FACILITIES
                    Stream  Name
                                                               Constituent Concentration (volume percent, dry basis)	    Flow Rate (kraol/hr dry  basis
                                                                                              NfT        HCN      fjfjParticulate    unless otherwise specified)*
                                                                          VOC
                                                                                    CO
                Streams from Main
                Process Train
                Dust from coal preparation
                (streams 200, 202 to 206)

                Transient waste gases
                (stream 208)

                Sour gas from cyanide wash
                flash - water wash case
                (stream 214a)

                Sour gas from cyanide wash
                flash - methanol wash case
                (stream 214b)

                HjS-nch Rectisol offgas
                (stream 216)

                C02-rich Rectisol offgas
                (stream 219)

                Streams from synthesis
                processes
                Mobil synthesis catalyst
                regeneration offgas
                (stream 231)

                Methanation catalyst
                decommissioning offgas
                (stream 237)

                002-nch offgas from SNG
                purification (stream 239)

                Fugitive organic emissions
                (stream 241)

                Streams from auxiliary
                processes
                Flue gases  from power


                Evaporative emissions from
                product storage (stream 308
                to 313)

                Streams from pollution
                control processes'
                Fugitive emissions from waste-
                water treatment (stream 416)

                Flue gas from K-T dust incin-
                eration (stream 413)
            3.1
0.0005     0.0008
                                                Present
                                     -62       -0.02      -0.01


                                                        0  05
            3       --       2         26



            5      0.02      1


                         Present       1
                                                         15
0.06
                         Present       '



                                   Present



                           0.2


                         Present





                  0.2      0.01       0.03


                         Present
                  Present      100-2200 kg/hr  (maximum rate)
                              70-1400 kg/hr  (average rate)

                  Present      Unknown but small on an
                              average basis

                                         22
                       16



                      535


                   10,064





Present      200 maximum,  100 average



Present      Unknown but very infrequent



                      273


            30-140 kg/hr
                                                                                                                0.04      10 g/m
                                                                                            Present   Present
                                                                   02     10 g/m
                                                                                                                                     5400-32711
                                                                                      2.5-7.5 kg/hr average
                                                                                      2.8-9.3 kg/hr max.
                                                                                                                                     Unknown
                                                                                               7419
                 For  a plant with an input to the  gasifier of 278 Mg/hr dry  Illinois No.  6 coal.

-------
     TABLE 4-2.  CATEGORIZATION OF GASEOUS WASTE STREAMS ACCORDING TO SOURCE TYPE IN K-T INDIRECT
                 LIQUEFACTION FACILITIES
     Source Type
Stream Name and Origin
        Factors Affecting Flow Rate
           and Pollutant Loading
Acid gases containing
reduced sulfur/nitrogen,
organics and CO
Combustion gases
Organic and CO
containing gases
Fugitive dust



Fugitive VOC
Fugitive particulate
Rectisol acid gases
(stream 216)

Flash gases from cyanide
wash (stream 214)

Boiler flue gases
(stream 302)

Process heater flue
gases

Flue gas from K-T dust
incineration (stream 413)

Catalyst regeneration/
decommissioning offgases
(stream 237)

C02-rich offgas from SNG
purification (stream 239)

Dust from coal  storage
(stream 200)
Product storage evapora-
tion emissions (streams
308 to 313)

Process equipment
fugitives (stream 241)

Particulate from coal
handling and preparation
(streams 202 to 206)
Coal sulfur; coal rank; acid gas removal selec-
tivity

Coal sulfur; cyanide wash solvent; process pres-
sure; coal rank may influence HCN formation

Overall plant thermal  efficiency; coal ash and
sulfur; boiler design and efficiency

Tend to be design/synthesis specific; not related
to coal parameters

Coal rank; coal ash and sulfur; combustor design
and efficiency; dust feed rate

Tends to be design specific; not related to coal
parameters


Tends to be design specific; not related to coal
parameters

Coal physical properties (particle size, moisture,
density, etc.); site-specific climatological
factors

Synthesis process; product slate
Synthesis process; upgrading steps employed;
plant design

Coal physical  properties; coal preparation opera-
tions and layout

-------
Section 4
Gaseous Medium
all K-T plants would include coal  combustion flue gases, coal  preparation

dust, product storage emissions, and process VOC emissions.

     In each of the subsections that 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 costs are provided.   Techno-
logy descriptions are provided at the beginning of each subsection as follows:

     •  Section 4.1.1 provides descriptions of bulk sulfur removal,
        tailgas treatment, and incineration technologies.

     •  Section 4.1.2 provides descriptions of N0x removal,
        particulate removal, and S02 removal technologies.

     •  Section 4.1.3 refers to the Section 4.1.1 incineration technology
        description.

     •  Section 4.1.4 provides descriptions of technologies for suppression
        of fugitive dust from coal storage piles.

     •  Section 4.1.5 provides descriptions of fugitive VOC control
        technologies.

     •  Section 4.1.6 provides descriptions of technologies for suppression,
        capture, and collection of fugitive particulates from material
        conveying and processing.

In many cases control of gaseous pollutants involves both inherent process
design features and  tradeoffs among  processes.   Further,  some waste  gases are
combined for  treatment rather than handled  separately.  Accordingly, example
approaches to the 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,
emphasis is on the  unique  streams rather than on  those  streams for which in-
formation about control may be found in other documents.

-------
                                               Section  4
                                               Acid  Gas -  Red.  S/N,  Org.,  CO
4.1.1  Acid Gases Containing Reduced Sulfur/Nitrogen, Organics, and/or Carbon
       Monoxide
     As discussed in Section 3, K-T based coal gasification plants will
employ the Rectisol  process for removal of sulfur compounds, C02, and HCN
from the washed product gas.  Regeneration of the methanol solvent produces
waste gases enriched with these acid gases.  Since CO and hL are soluble in
cold methanol, Rectisol acid gases will also contain these constituents as
well as traces of methanol vapor.   Rectisol acid gases are by far the largest
sources of uncontrolled sulfur and CO emissions in a K-T facility.
     An additional acid gas stream is generated in conjunction with the
cyanide wash operation preceding the acid gas removal unit.  Flash gases
from the cyanide wash are enriched in FLS and HCN.  In methanol-based cyanide
wash systems, flash  gases may also contain CO, COS, and methanol.
     Approaches to treatment of the sulfur-rich acid gases are aimed pri-
marily at removal of reduced sulfur species by bulk sulfur removal followed
by tail gas treatment.  Partial or essentially complete control of HCN, CO,
NH^, and methanol can be realized either as an integral part of the sulfur
control approach or  through a separate add-on step such as incineration.
The approach for controlling CO emissions in sulfur-free acid gas streams
involves incineration.
                                     173

-------
Section 4
Acid Gas - Red. S/N, Org., CO
Bulk Removal
 Bulk  Sulfur  Removal
      To  date  only  three  processes  have  seen  any  significant  commercial  appli-
 cation  for the removal of  hLS  from acid or fuel  gases,  namely  the  Claus,  Stret-
 ford, and Giamarco-Vetrocoke  processes.   These are  the  only  processes  examined
 here due to their  commercial  status,  reliable operation,  applicability to
 the wide range of  sulfur contents  in  the acid gases,  and,  in the cases of the
 Claus and Stretford processes,  availability  of operating  information  and
 capital  cost data.  In addition to these processes,  alternatives involving
 incineration  with  S02 removal  may  be  applicable  for facilities  using  low  sul-
 fur coals.  It is  recognized  that  a few other processes are  available  or  have
 been proposed; however,  it is  unlikely  that  processes other  than Claus, Stret-
 ford or Giamarco-Vetrocoke will be utilized  in first generation coal  gasifica-
 tion 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% H2$.   The Giamarco-Vetrocoke process is generally applicable to
 feed streams with hLS concentrations  of up to  1.5%.  Table 4-3 summarizes
 the  key features of these 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.   There are two
 common versions of the process:  "straight through", and  "split flow".
 In the "straight through" mode, sufficient air is added to oxidize
 one-third  of  the  H2S to S02.   The  "split flow" mode, shown  in  Figure  4-1, is
 often used when H2S  levels in  the  feed gas are below 25% by volume.   The
 acid gas  is split  into  two streams and one-third of  the input  acid gas is
 combusted in  a  reaction furnace to form  S02.  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 3-stage  design  can  achieve  overall

                                      174

-------
                                                  TABLE   4-3.    KEY  FEATURES  OF   BULK  SULFUR  REMOVAL  PROCESSES
                          Principle  of
                          Operation
                                              Claus
Catalytic  oxidation
of H2S and SO? to
elemental  sulfur.
                          Components  Removed   H2S, COS,  RSH, VQC,
                                                                     Stretford
Liquid phase oxidation of  HoS
to elemental  sulfur  in an
alkaline solution  of metavana-
date and anthraquinone disul-
fonic acid.
                                                                     H
                                                                      ?S, HCN, and CH..SH.
                                                                                    ^
Giamarco-Vetrocoke  (G-V)	

Liquid phase oxidation of H^S
to elemental sulfur in sodium
carbonate and arsenate/
arsenite solution.
                                                        H2S, COS, and
                                                                                                                                        lncineration/S02 Removal
Oxidation of reduced sulfur and
organics, followed by S02 removal
using either regenerative or
throwaway FGD technologies.
                                                                   H2S, COS, RSH, VOC, and CO.
CJ1
                          Efficiency
                          Feed Stream
                          Requirements/
                          Restrictions
                          By-Products
                          Secondary
                          Waste Streams
Over 95X total  S,
other combustibles
partially destroyed*

Streams  containing
H2S levels much
below 10-  require
enrichment prior
to processing.
Organics cause com-
bustion  control
problems and  "grey"
sulfur.

Elemental  sulfur,
Spent catalyst  and
catalyst regenera-
tion decommissioning
offgas^
                                                                     As low as  1  ppmv  H.S but no
                                                                     removal of non H-S^sulfur.
High HCN loading  should be
reduced prior to  processing  to
prevent excessive solution
purge.
                                                                     Elemental  sulfur.
Oxidizer vent gas and purge
solution.
Maximum 1.5"  H2S  in  feed.
                                                                                                      Elemental sulfur which may
                                                                                                      require arsenic removal.
Oxidizer vent gas  and
arsenate/arsenite wash
water.
As low as TOO ppmv VOC in incinerated
gas and up to 992 total  sulfur
removal.

In principle, gases with any level
of H2S or sulfur compounds could
be incinerated and subsequently
treated via FGD.  Other components
cause no problem.
Either CaS04, concentrated S02,  or
throwaway lime sludges are gen-
erated by FGD units.

Some condensate and scrubber
sludge.
                          Reliability/
                          Limitations
                          Effects of High
                          C02  in Feed
NH3 and  HCs may
cause catalyst plug-
ging and variable
sulfur recovery.

Can adversely affect
sulfur removal
ability  of the
process.
Process  does  not  remove COS,
RSH, or  organics, HCN forms
nonregenerable  salts  in scrub-
bing solution.

High C02 concentrations will
decrease absorption efficiency
by lowering  solution  alka-
linity.   Increased absorber
tower height  and  addition of
caustic  are  required.
Hazardous nature  of  arsenic
solution may cause handling and
safety problems.
Little or no effect ,
FGDs systems have varying degrees  of
reliability and generally have lower
on stream factors than process units.
                         Capital Costs        $?b  to  $180 x 10  per   $110 to  $270 x  103 per Mg
                                              Mg sulfur/day capacity   sulfur/day capacity, depending
                                              depending on both       primarily upon total flow.
                                              total flow and sulfur
                                              content.
                                                        No cost data  available.
                                                                   $700 to $1700 x 10J per Mg sulfur/day
                                                                   capacity depending upon total flow
                                                                   and degree of sulfur removal.
                         General Comments
                                             Applicable only to
                                             acid gases from
                                             selective AGR system.
                                             Hydrocarbon removal
                                             from feeds may be
                                             necessary.
                       1 ppmv H^S in tail gas is
                       possible, however higher limits
                       are proposed when high levels
                       of other reduced sulfur species
                       are present in tail  gas.
                                 Limited  data available.  Haz-
                                 ardous nature of arsenic solu-
                                 tion  makes application unlikely
                                 in  large U.S. facilities.
                                  FGD process  has  usually been
                                  applied  to combustion  flue gases
                                  containing less  than 5000 ppmv S02
                                  and achieving  about 90^ control.
                                  Performance and  cost data for higher
                                  SO? feeds achieving 99°= control are
                                  limited.

-------
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                          Figure 4-1.  Three stage Claus plant with split flow option

-------
                                               Section 4
                                               Acid Gas - Red. S/N, Org., CO
                                               Bulk Removal
 removal  efficiencies of over 95%.   Gaseous sulfur species distribution in
 Claus tail  gas in high CCL applications is approximately 60% FLS,  30% S02,
 9% COS,  and 1% CSp, although exact levels can vary depending upon  the feed
 gas composition and Claus plant operation.  Elemental  sulfur as both vapor
 and entrained mist can contribute  20-50% to the total  sulfur in Claus tail
 gases, depending primarily on the  level of h^S in the  Claus feed and the
 effectiveness of mist eliminators.  The relative contribution of elemental
 sulfur to total  sulfur  in  Claus  tail gas  generally  increases  as  HLS  content
 of Claus feed  gas  decreases.
      In  the "straight through"  mode  of  Claus  operation,  organics,  HCN,  and
 NhU in the  feed are largely  converted to  carbon dioxide,  water vapor,  and
 elemental nitrogen.  Such  components are  not  ordinarily  of  concern unless
 levels exceed perhaps 1% vol.  each.  Organics make control  of combustion stoi-
 chiometry  and temperature more difficult  and  can lead  to an off-color by-
product sulfur containing elemental carbon.  HCN at high  levels causes  corro-
 sion throughout the process  while  NH3 can form deposits  which plug/deactivate
 Claus catalysts.  The organics  problem  is usually solved by limiting their
 content  in  the Claus feed.  HCN at high levels can be  removed (converted
 to NH3)  prior to entering  the Claus  furnace using Claus  or  shift type  cata-
 lysts under reducing conditions.  Ammonia at  high levels  requires  either bulk
 removal  prior to entering the Claus  unit  or special design  to minimize
 deposition  of ammonia salts.
      With  feed gases dilute in H^S or  other combustibles, flame stability
 can be a problem in "straight through"  operation.  One method for control
 of the sulfur combustion process in Claus plants with  feeds containing less
 than 25% H2S or more than 30% C02  has  been the use of  the "split flow" mode.
 In this  process, any organics, HCN,  and NH^ in Claus feed gases would be
 only about one-third destroyed in  the  split flow mode  unless streams contain-
 ing high levels of these constituents  are specifically routed to the combus-
 tion furnace of the Claus plant.  Generally,  organics  present the most

                                      177

-------
Section 4
Acid Gas - Red. S/N, Org.,  CO
Bulk Removal  .
difficult problem for split flow Claus plants, leading to carbon contaminated
sulfur.  A portion of the input organics, HCN, and NHg to split flow Claus
plants may be present in Claus tail gases prior to incineration.
     One problem potentially associated with "split flow" operation is the
decomposition of olefins and aromatics to elemental carbon which contaminates
the product sulfur.  In such cases, other approaches to combustion control
have been utilized.  First, combustible gases such as CO, H£, or CH^ are
added to the feed or are combusted separately to provide sufficient heat to
enable operation in the straight through mode.  Liquid sulfur has also been
used.  Second, and of particular attractiveness in coal gasification facil-
ilities, is the use of oxygen  (Og)  or  enriched air.  Use of 02 not  only  im-
proves flame stability, but also decreases the inert volume  through the Claus
and any subsequent tail gas treatment units.  Since unit sizes  and associated
costs are flow dependent, savings  can be realized.  Oxygen is expensive to
generate, but much of the capital  cost is already  absorbed in a gasification
facility which would  necessarily have a  large on-site oxygen plant.  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 is used.  The Claus catalyst has an
estimated  life of  at  least  two  to  three  years.  Regeneration of catalyst  is
performed  intermittently at a  few  facilities  when  the  efficiency  of  the  proc-
ess  drops  below  acceptable "levels. However,  no data  regarding  regeneration
frequency,  duration,  or offgas  characteristics are available.
      The original  Stretford process  (as  developed  by  the British  Gas  Corpora-
tion)  is a  liquid-phase  oxidation  process  using an aqueous  solution  of sodium
vanadate and anthraquinone  disulfonic acid  (ADA)  in which  H2$  is  both  absorbed
and  converted  to sulfur.   Figure 4-2  is  a  simplified  flow diagram of the Stret-
ford process.   The H^S  is  absorbed in either a  packed tower (or contacted in

                                      178

-------
ACID
GAS '
                AIR
                          TAIL GAS
                                 C. W.
ABSORBER
                         VENT
                           PRIMARY
                           OXIDIZER
                             i
                                                               H2S RICH GAS
                                                WATER CHEMICALS
                                                   SOLVENT
                                                   MAKE-UP
                        SECONDARY
                        OXIDIZER
                                                                    RECOVERED CHEMICALS
                                                                    WATER
                                                CENTRIFUGE
                                                                           STEAM
                                                         SULFUR
                                                         MELTER
SEPARATOR
                                                                      REDUCTIVE
                                                                     INCINERATION
                                                                                   PURGE SOLUTION
                                                                          SULFUR
                                   Figure  4-2.   The Stretford process

-------
Section 4
Acid Gas - Red.  S/N, Org.,  CO
Bulk Removal
a venturi scrubber) and then oxidized to sulfur by the sodium vanadate.  Re-
duced vanadium is then oxidized by the ADA Solution.  ADA is regenerated with
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 thio-
sulfate  and  sodium thiocyanate.  Until recently, disposal or treatment of the
solution purge containing thiosulfate, thiocyanates, and small  amounts of
vanadium salts was required.   In 1973, a reductive  incineration process  was
developed which  converts  the  purge solution into a  gas  stream containing H^S,
water  vapor  and  a  solid  residue containing  soda ash and  reduced vanadium
salts   The  salts are  returned  to the  Stretford process  as make-up chemicals
 and the F^S-rich gas  and water vapor  are recycled  to  the absorber as
 shown in Figure  4-2.   Thus, the reductive  incineration  process  recovers
expensive chemicals while effectively attaining a  "zero" discharge of solu-
tion  purge.
    Recently, modifications of the original  Stretford process have been
developed.   One  modified version of the  Stretford  process has been used  at  the
 SASOL  Lurgi  coal gasification  complex in South Africa.   At  SASOL, severe plug-
 ging  problems  have occurred in the Stretford towers which apparently  relate  to
 the high CO^ levels  in the  Stretford  feed  compared  to feeds in  other  services.
 Preliminary information  indicates  that  sulfur deposition is primarily respon-
 sible.   SASOL  has  modified  the original  Stretford  unit,  presumably substituting
 a different absorbent while saving the  bulk of the  existing equipment.
      The Stretford process  generates  two waste streams, the oxidizer vent
 gas and the purge solution.  The purge  solution  is treated  via  the  reductive
 incineration process where  sulfur is  recovered as  HLS for recycle to the
 absorber and sodium and vanadium salts  are recovered for reuse.  The oxidizer
 vent gas is expected to consist primarily  of air,  carbon dioxide,  and water
 vapor.
      The Giamarco-Vetrocoke H2S removal  process  is a liquid phase oxidation
 process using an absorbent  solution  of  alkali arsenates/arsenites in which
                                     180

-------
                                              Section 4
                                              Acid Gas - Red.  S/N, Org., CO
                                              Bulk Removal
hydrogen sulfide 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% hydrogen sulfide and can
reduce hydrogen sulfide levels to 0.5 ppmv or less.  The hydrogen sulfide is
absorbed at pressures from 0.1 to 7.5 MPa by countercurrent absorption. Rich
solution from the absorber is subsequently oxidized in an atmospheric pres-
sure, air-blown column to produce regenerated solution and elemental sulfur.
Product sulfur is recovered by froth flotation, filtered, 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.
     In principle acid gases can be directly incinerated to convert all
organics, CO, and reduced sulfur and nitrogen species to C02, H20, N2 and SOp.
S02 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.   Throwaway FGD systems create
large solid  waste disposal  problems and recovery type FGD systems often feature
Claus or Claus type (e.g.,  the Allied process)  processes for elemental sulfur
recovery.  There is little  to be gained in these approaches over direct use
of the Claus process.   FGD  systems  are also not demonstrated for gases con-
taining over about 0.5% S02, and although there appear to be no inherent tech-
nical  limitations prohibiting designs for much  higher S02 levels, such systems
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 incineration approach  might be viable  due to high
costs associated with  enrichment to obtain an  H2S-rich acid gas suitable for
Claus processing.
                                     181

-------
Section 4
Acid Gas - Red. S/N, Org.,  CO
Tail Gas Treatment
Tail Gas Treatment
     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 4-4 summarizes the key features of the most prominent of these
processes.  The processes can be categorized in three generic types:
     1)  Conversion of sulfur species to H2S followed by its removal - this
         includes processes such as the Beavon/Stretford and SCOT processes.
     2)  Conversion of sulfur species to sulfur dioxide (S02) by incineration,
         followed by S02 removal - this includes processes such as the Well-
         man-Lord or Chiyoda Thoroughbred 102.
     3)  Extensions of the Claus process - this includes processes such as the
         IFP-Clauspol 1500, Sulfreen or BSR/Selectox processes.
     Processes in the first category involve catalytic reduction of oxidized
sulfur species to hUS followed by HLS removal from the gas stream by solvent
absorption.  In general, the designs of these processes are influenced by the
high levels of C02 in the feed gas.  High C02 levels reduce the efficiency of
catalytic reduction of COS and CSp to H^S and impair the effectiveness of the
h^S removal/recovery systems.
     Both the Beavon/Stretford and  the SCOT processes are commercially avail-
able catalytic processes which are potentially applicable to sulfur plant tail
gases in indirect coal liquefaction facilities.  These processes feature two
sections:  a hydrogenation section to convert sulfur species in the gas to
HpS and an H^S absorption section.  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 sulfur species to  HLS.
     The Beavon process employs a Stretford  unit for hLS absorption and
elemental sulfur production.   In contrast, the SCOT process employs an
alkanolamine scrubbing system  for hLS absorption.  The absorbing solution  is
then regenerated resulting in  a HpS-rich acid gas which is ordinarily returned

                                      182

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                                       TABLE  4-4.    KEY  FEATURES  OF  RESIDUAL SULFUR  REMOVAL  PROCESSES
                                               Beavon
                                                                              SCOT
                                                                                     Incineration Plus SO,
                                                                                        Removal (FGD)   i
                                                                                                                                         Sulfreen
Principle of
Operation
Components Removed
                                     Catalytic  reduction of sulfur
                                     compounds  to  H2S, followed by
                                     integrated Stretford process.
                                     H2S, COS,  CS2> and
                                Sulfur species are
                                catalytically reduced to
                                H2$; HjjS is scrubbed in
                                a regenerable amine
                                system.
                             Incineration (an on-site
                             boiler or separate
                             incinerator) followed by
                             SO? removal (e.g., Uellman-
                             Lord).
                                H2S, COS, and CS.,, S02.      503, also removes HCs,
                                                                                                  CH3SK,  NH3,  and HCN.
                              Gas phase continuation of
                              Claus reaction at a low
                              temperature.
                                                           H-S, S02> COS, and CS2-
00
co
                 Efficiency
Feed Stream
Requirements/
Restrictions

By-Products
                Secondary Waste
                Streams
                Reliability/
                Limitations
                    Over 99.9% total  sulfur  re-
                    moval in combination with the
                    Claus plant or can attain
                    equivalent of 50  ppm total
                    sulfur in tail gas  (not
                    including reducing gases).
None.

Elemental  sulfur.


Sour condensate, oxidizer
vent gas,  solution purge,
and spent  catalyst.

Has only been  applied to
Claus  process  tail gases.
Over 99.9;» total  sulfur
removal in combination with
the Claus plant or can
attain equivalent of 250
 ppm total  sulfur in tail
 gas (will vary depending
 on C02 and H?_S concentra-
 tion in specific  applica-
 tions) .

 None.
                                                                     Concentrated H2S.
                                                    Sour condensate and
                                                    spent catalyst.
                                                     Requires further treat-
                                                    ment and/or recycle to
                                                    Claus.
                                                                                                  Up to 99'  total  sulfur re-
                                                                                                  moval from Claus tail  gas
                                                                                                  or 50 ppm SOj in tail  gas
                                                                                                  and complete removal  of
                                                                                                  other compounds.
None.

 Sulfur or sulfuric acid from
 the  Wellman-Lord recovery
 FGD  process.

 Sour condensate and solution
 purge.
                                                                                            Up  to  99°  sulfur  removal
                                                                                            in  combination with Claus
                                                                                            plant.   Can exoect a
                                                                                            typical  total sulfur level
                                                                                            of  2500  ppm in tail gas.
Optimum performance requires
H2S:S02 ration of 2:1.

Elemental liquid sulfur.
                                                           Spent catalyst.
                             Solid wastes may be generated  Has only been applied  to
                             by throwaway FGD processes.    Claus process tail  gases.
                Effects of High
                CO- in Feed
                    Reduces conversion  efficiency
                    of catalyst and  decreases H?S
                    absorption in Stretford
                    solution.
                                Reduces conversion
                                efficiency of catalyst
                                and efficiency of
                                alkanolamine system.
                             None.
                                                           No effect.
                Capital Costs


                General Comments
                    $20 to $60 x 103 per Mg/day
                    of S at Claus  plant.

                    Exact ppm limit  achievable in
                    coal  gasification application
                    is not known.  Vendor believes
                    100 ppm is  attainable.
                                $20 to $60 x 10J per Mg/
                                day of S at Claus plant.

                                Off-gas from amine
                                scrubber is not as low in
                                total  sulfur as ReSvon
                                process.
                             $40 to $110 x 10  per Mg/day
                             of S at Claus plant.

                             On-site boiler/FGD system    Much higher residuals  in tail
                             is the most likely candidate  gas than Beavon process.
                             Installing a separate incin-
                             erator and FGD would  not  be
                             as economically feasible.
                                                                                                                                           (Continued)

-------
        TABLE  4-4.   (CONTINUED)
                                       Cleanair
                                                                  IFP Claus 1,500
                                                                      IFP-2
                                                                                                   BSR/Selectox
00
           Principle  of
           Operation
           Components Removed

           Efficiency
          Feed Stream
          Requirements/
          Restrictions
          By-Products

          Secondary Waste
          Streams

          Reliability/
          Limitations

          Effects  on High
          C02  in Feed
          General Comments
Catalytic reduction of
sulfur compounds  to t^S
followed by a continua-
tion of the Claus reaction
and Stretford process.
H2S, COS, CS2, and S02>

Reduces sulfur  to less  than
250 to 300 ppm  S02 equiva-
lent in effluent.
H2$:S02 ratio can  vary  up
to 8 to 1  without  affect-
ing efficiency;  designed
specifically for Claus
tail gas e

Elemental  sulfur.

Spent catalyst„
Has only been  applied to
Claus process  tail  gases.

Reduces conversion  effi-
ciency of catalyst;
decreases HoS  absorption
in Stretford solution.

Cannot attain  as  low a
residual sulfur  level in
tail gas as  Beavon  process.
Liquid phase continuation
of Claus reaction at a low
temperature.
H2S, and  S02.

Reduces sulfur species in
Claus tail gas to 1500
ppa as S02-
H2S:S02 ratio must be main-
tained in the range of 2.0
to 2.4.
Elemental  sulfur.

Spent catalyst o


Has only been applied to
Claus process tail  gases.

No effect.
Cannot attain as  low a
residual  sulfur level  in
tail  gas  as  Beavon process.
                               Incineration of tail  gas
                               followed by ammonia scrub-
                               bing.  Solution is evapor-
                               ated to produce a concen-
                               tration S02 stream which
                               is returned to the Claus
                               plant.

                               COS, CS2,  and  H2S.

                               Reduce^ suhur species  in
                               Claus tail  gas to less  than
                               500 ppn.
                               H2S:S02 ratio must be main-
                               tained in the range of 2.0
                               to 2.4.
                               Concentrated S02.

                               Spent catalyst •
                               Has  only been applied  to
                               Claus  process tail  gases.

                               No effect.
                                                                                           Cannot  attain as  low a
                                                                                           residual  sulfur level in
                                                                                           tail gas  as Beavon process.
Catalytic reduction of sulfur
compounds to H2S, followed
by oxidation of H2S to sulfur
over Selextox catalyst.
H2S, S02, COS, and CS2.

Up tu 99.5*.  total sulfur  re-
moval equivalent  to  750 ppmv
S02  i"  the incinerated off-
gas.
                                                                                                 o
        ratio must be main-
tained in  the range of 2.0
to 2.4. HC and NH, should not
be in the  feed.
Elemental liquid sulfur,

Spent Beavon and Selectox
catalyst, and sourcondensate.

Has only been applied to
Claus plant  tail gas.

Reduces conversion efficiency
of BSR catalyst.
                                                              Higher sulfur emissions than
                                                              Beavon process ,

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                                               Section 4
                                               Acid Gas - Red.  S/N, Org.,  CO
                                               Tail Gas Treatment
to the parent Claus plant for treatment.   The alkanolamine  scrubbing  system
ultimately limits the SCOT'S capabilities  because the solvent is  only
partially selective for H^S over CO,,.   Thus,  where feeds  contain  large  amounts
of C0?, it is more difficult to generate  an FUS stream suitable for Claus
processing while simultaneously obtaining  a tail  gas  stream with  a low  level
of total sulfur.  In high C02 applications, vendors of the  Beavon process
report that levels of less than 100 ppmv  total  sulfur can be achieved,  while
vendors of the SCOT process report less than 350 ppmv total sulfur (Claus
plant tail gas bases).
     Inherent limitations of selectivity  in the amine absorption  step of the
SCOT process place a lower limit of about 200 ppmv of H2S which will  be present
in SCOT tail gases.  In comparison, the Stretford unit following  the Beavon
reactor can remove H2S to below 10 ppmv H2S.  Both systems would result
in 50-100 ppmv tail gas COS in high C02 applications.  The higher levels of
HLS in SCOT tail gases in existing applications have necessitated that the
gases be incinerated to minimize odor problems while Beavon tail  gases  do not
generally require incineration.  However,  no Beavon/Stretford units are
currently used in high C02 service, while at least four SCOT units have
sucessfully operated on feeds with C02 levels above 40%.
     The secondary category of processes  involves incineration of the waste
gas followed by SOo 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 process, removes S02 with a sodium sulfite solution.  Sub-
sequent regeneration of the absorbent generates a concentrated SOo stream
which would be recycled to the parent Claus plant.  Two approaches to
incineration can be employed, either separate incineration (with  added fuel
where needed) or incineration in an onsite boiler.  Either option would
net similar results from a sulfur oxidation standpoint.
     Processes in the third category are used exclusively for Claus plant
tail gases and are capable of approximately 80% recovery of tail  gas sulfur.
                                      185

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Section 4
Acid Gas - Red. 5/N, Org., CO
Tail Gas Treatment
These processes are extension of the Claus process and therefore require a
2:1 ratio of HUS to S02 for proper operation.   The limited sulfur removal
capabilities of these processes result in sulfur concentrations of not less
than 1000 ppmv.  To date, these processes have not been proposed for coal
gasification applications in the U.S.
                                      186

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                                              Section 4
                                              Acid Gas - Red.  S/N,  Org.,  CO
                                              Incineration
Incineration
     As discussed above, partial  or total  control  of HCN,  CO,  NHU,  and VOC
can be achieved during bulk sulfur removal  or sulfur tail  gas  treatment.
The combustion section of a Claus unit largely destroys these  constituents,
but only in that portion of the gas passing through the burner.   Cyanide  can
also be destroyed over Claus 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.  NhU  is also par-
tially removed by Stretford solvent while organics, CO, and COS are not re-
moved by Stretford.   Catalytic sulfur tail  gas treatment systems achieve  at
least partial  control of any residual HCN contained in sulfur  plant tail
gases.  Both Beavon  and SCOT catalytic sections are expected to achieve a
high degree of conversion of HCN to NHo 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 their tail gases.
     Incineration of these tail gases is an effective approach to controlling
residual hydrocarbons, CO, NH^, and reduced sulfur species.  In addition,
incineration is essentially the only alternative for controlling CO emissions
associated with COo-rich acid gases.  SCOT tail gases are ordinarily incin-
erated to minimize odor problems arising from residual H2S.  Beavon tail
gases (with lower H^S levels) are not ordinarily incinerated,  but an incin-
eration step can be  added for control of organics, CO, and/or  NHo if neces-
sary.  Sulfur dioxide tail gas treatment processes such as the Wellman-Lord
inherently achieve control of VOC, CO, and NI-L as  part of the  incineration
step.  Hence,  no further control  for these constituents is ordinarily neces-
sary with SOo removal processes.
     Advantages and  disadvantages of the various incineration  technologies
aimed primarily at control of volatile organic compounds are summarized in
Table 4-5.  Generally, a greater degree of control is obtained with high
                                    187

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                                                 TABLE 4-5.    COMPARISON  OF  INCINERATION  PROCESSES
           Type of Incineration

         Thermal  Incineration
         via Separate  Incinerator
         Thermal  Incineration
         in Fuel  Fired  Boiler
             Advantage
          Disadvantage
  Costs (Total  Depreciable Capital)
CO
oo
         Catalytic  Incineration
        Flaring
Can handle all types  of  waste gases.
Reliable and simple operation is
common.  VOC/CO control  and oxida-
tion of sulfur compounds  simulta-
neously.
Sulfur and particulates  can be
removed in the associated electro-
static precipitator  and  flue gas
desulfunzation (FGD)  units when
these are integral with  the boiler.
The fuel required for  steam boiler
incineration is less than that of
a separate incinerator for wastes
with low heating values.

Requires less fuel than  thermal
incineration, although heat re-
covery may not be as high.  Waste
gases with very little combustible
material can often be  incinerated
catalytically without  supplemental
fuel.
Simple to operate,  least expensive
alternative,  especially for trans-
ient and small  volume waste gases.
High supplemental fuel costs for
streams with low heating value,
control is a problem with streams
of varying flow and composition.
In most cases, this option is more
capital intensive than a separate
incinerator; however, extent of
heat recovery is generally greater
with boilers than with incinerators.
Subject to control  problems with
varying waste gas flow rates and
compositions.
Cannot handle large quantities  of
particulates; they will  gradually
coat the catalyst and reduce its
efficiency.  Some catalyst can  be
easily poisoned by sulfur compounds
and elements such as arsenic and
lead.  High levels of hydrocarbons
can raise catalyst to excessive
temperatures and shorten the useful
life of the catalyst.  Temperature
control is also a problem with
streams of varying flow  and com-
position.

Destruction efficiencies much  lower
than for thermal or catalytic  incin-
eration.  Performance data are
generally lacking.
On basis of kmols/hr of flow:   flow
range of 0.3 to 3.0 x 103 kmol/hr

  a. no heat recovery:   S140 to S870
  b. primary heat recovery:  $190 to S1000
  c. primary and secondary heat recovery:
     $225 to S1200

Incremental  boiler capital costs are
$2000-S3000/kg mole of  incremental  flue
gas compared to coal combustion on  a  heat-
ing value basis.  Incremental  ESP and FGD
costs are an additional S2000-S2500/kg
mole incremental flue gas.
S400 to S2200 per kmol/hr of flow for
a flow rate range of 40 to 7100 kmol/nr
   40 to 100 ft elevated flares  for flow
   rate range of 800 to 6500 kmol/hr -
   $25 to $125 per kmol/hr
   Ground flares for flow rate o^ 100 to
   1000 kmols/hr - $800 to $2700 per
   kmol/hr

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                                               Section 4
                                               Acid Gas - Red. S/N, Org., CO
                                               Incineration
temperature incineration in either a fuel-fired boiler or a  separate  incin-
erator (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 gases are maintained at a minimum temperature of HOOK for a mini-
mum of 0.5 seconds.  This results in nearly complete destruction of volatile
organic compounds, reduced sulfur compounds, organic aerosols,  CO,  Nf-U,  HCN,
and particulate matter consisting primarily of combustible material.
     Thermal incineration may also be effected in a boiler where a  minimum
combustion temperature of  1500K and a minimum residence time of 0.5  seconds
are typical design parameters.   This approach results in a degree  of  pollu-
tant destruction similar to that which would be achieved in  a specially
engineered incinerator.  In tail gas or C02-rich offgas  treatment applica-
tions, using the boiler as an incinerator results in an increase in the
capital and annualized operating costs of captive ESP and FGD units,  since
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),
and these waste gases will not be of sufficient heating value to displace
the primary boiler fuel.
     Catalytic incineration is not likely to be an attractive alternative
for control of carbon monoxide and VOC in tail gases from sulfur recovery
units due to the presence of sufficient reduced sulfur compounds to inter-
fere 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 construc-
tion (based on Texaco gasification).
                                    189

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Section 4
H2S-Rich Rectisol Gases
4.1.1.1  H2S-Rich Rectisol Offgas (Stream 216) - Individual  Stream Contro"!
     Details of pollution control alternatives applicable to the H-S-rich
Rectisol offgas (Stream 216)  are discussed in this  section.   Although
this discussion focuses primarily upon individual  stream controls, the cost
estimates provided reflect the fact that, in a K-T  based gasification faci-
lity, h^S-rich Rectisol offgas would most probably  be combined  with the
relatively small volume cyanide wash flash gases (Stream 214) prior to treat-
ment.  The likelihood of such stream combination derives from the high sulfur
concentrations of both of these streams, and the high percentage of the gasi-
fied coal total sulfur present in the cyanide wash  flash gases  (about 1 to
3%).  This approach is necessary in order to provide realistic  cost esti-
mates for the bulk sulfur removal, tail  gas treatment, and incineration con-
trols discussed in this section.
     For evaluation purposes, the H2S-rich Rectisol offgas have been
assumed to contain 50% carbon dioxide, 42% hydrogen sulfide, 5% carbonyl  sul-
fide, 0.4% carbon disulfide,  636 ppmv cyanide, and  200 ppmv sulfur dioxide.
The main organic compound present in significant quantities is  expected to be
methanol at about a 1% level  (see Section 3.3.6).   The corresponding flow
rate for this stream is about 535 kmol/hr.  It should be noted  that the exact
hydrogen sulfide level in the H2S-rich Rectisol  offgas would be determined
based upon engineering/economic tradeoff studies of Rectisol enrichment costs
versus bulk sulfur removal and tail gas  treatment costs.  The most economic
sulfide level is likely to be coal-specific and, in particular, vary with
coal sulfur content and sulfur recovery/pollution control alternatives.
                                     190

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                                                     Section 4
                                                     H2S-Rich Rectisol Gases
                                                     Bulk Sulfur  Removal
Bulk Sulfur Removal_
     In the base plant, the H^S-rich Rectisol offgas contains approximately
255 kmol/hr total sulfur, and is the primary feed gas to the bulk sulfur re-
moval unit.  An additional 2 to 8 kmol/hr of total sulfur is likely to be
present in the feed gas to bulk sulfur removal, depending upon whether a
water-based or methanol-based cyanide wash system is employed (refer to Sec-
tions 3.3.4 or 4.1.1.2 for cyanide wash flash gas compositions).   Thus, a
total feed rate to the bulk sulfur removal unit of about 549 kmol/hr, includ-
ing 257 to 263 kmol/hr total sulfur (approximately 47% total sulfur), is
expected from the uncontrolled base plant.  Such a stream is suitable for
bulk sulfur removal by the Claus process since it has a relatively high sul-
fur concentration and does not contain appreciable levels of contaminants
such as organics, HCN, or NH^.
     As discussed previously, Claus units of 3-stage design can achieve over-
all sulfur removal efficiencies of over 95%.  Assuming a 95% sulfur removal
efficiency, a Claus tail gas sulfur loading of 13 kmol/hr would be expected.
The gaseous sulfur species distribution in Claus tail gas in high C0? appli-
cations is approximately 60% H2S, 30% S02, 9% COS, and 1% CS2-  It should be
noted that up to 50% of the Claus tail gas total sulfur (S02 equivalent basis)
may actually be present as either sulfur vapor or entrained elemental sulfur.
However, this would not appreciably alter the tail gas sulfur species distri-
bution (e.g., for 50% S02 equivalent sulfur as Sg, the species distribution
would become 53% H2S, 27% S02, 8% COS, 1% CS2, and 11% Sg).   The  correspond-
ing concentration of total sulfur (S02 equivalent) in the Claus tail  gas
would be 1.5 to 1.6% (dry basis).  Some degree of removal of minor constitu-
ents present in the Claus feed gas such as methanol, CO, and HCN would be
achieved in addition to sulfur removal.  It is expected that about one-third
or more of the methanol and CO present in the feed gas would be combusted
resulting in tail gas concentrations of less than 0.6% and 0.4%,  respectively.
However, CO is apparently generated within the Claus reactor, and concentrations

                                     191

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Section 4
H2S-Rich Rectisol Gases
Bulk Sulfur Removal
of CO in the 1 to 2% range are typically reported.   Feed gas cyanide, present
at concentrations of up to about 0.4%, is expected  to be almost totally des-
troyed during Claus processing but may contribute to low levels of NhU in
the tail gas.  For the subject Claus plant, a dry tail  gas flow rate of about
800 to 900 kmol/hr would be expected with 200 to 250 kmol/hr of reaction
moisture.
     For a Claus plant of the capacity specified above, total  capital invest-
ment and annualized costs would be about $8.7 million and $0.4 million,
respectively.  However, the cost of the Claus unit  is dependent upon both the
feed gas flow rate and sulfur content.  For example, if the selectivity
achieved by the Rectisol unit was reduced to produce a Claus feed gas with
15% sulfur for the same coal sulfur content, the Claus feed gas rate would
increase by a factor of about three and the total capital investment for the
Claus plant would increase by about 40%.  Alternatively, with the same
Rectisol selectivity (i.e., 47% sulfur in the Claus feed) for a feed coal
having one-half the total sulfur content initially  considered, the Claus feed
rate would decrease by about one-half and the total capital investment for
the Claus plant would decrease by about 40%.
     The principal secondary waste stream generated by the Claus process is
spent catalyst (Stream 402).  The subject Claus plant would have a bauxite
or alumina catalyst inventory of approximately 50 Mg which would periodically
require disposal.  Assuming a catalyst life of 5 years, the average spent
catalyst generation rate would be 10 Mg per year.  Claus sulfur is produced
at a rate of approximately 7.9 to 8.3 Mg/hr and may also require disposal
depending upon its quality and market considerations.
                                      192

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                                                     Section 4
                                                     ^S-Rich Rectisol  Gases
                                                     Tail  Gas Treatment
Tail Gas Treatment
     In the base plant, tail gas from bulk sulfur removal  would contain
approximately 1.5% total sulfur and less than 0.6% methane and 1 to 2% CO,
on a dry gas basis.  Traces of NFU may also be present as a result of HCN
destruction during bulk sulfur removal.  A tail gas flow rate of about 840
kmol/hr dry gas and 300 kmol/hr water vapor is expected.  A number of pro-
cesses are available for recovering residual sulfur from  tail gases from bulk
sulfur removal  processes (refer to Section 4.1.1).  For purposes of discus-
sion, the Beavon/Stretford, SCOT,  and Wellman-Lord processes will be considered.
     The Beavon/Stretford process  is reported to be capable of reducing
residual sulfur concentrations to  about 100 ppmv (dry tail gas basis) with
a 9:1 ratio of COS to H^S.  This corresponds to a total sulfur emission rate
of less than 0.1 kmol/hr from tail gas treatment.  Minor constituents such
as methanol and NHg present in the tail gas from bulk sulfur removal are not
expected to be affected by the Beavon/Stretford process.  An external source
of reducing gas may be required for the catalytic hydrogenation of S0? and
elemental sulfur.  Reducing gas may be added directly to tail gas treatment
in the form of H2 and CO-rich gas  (e.g.,  flash gases from Rectisol) or
may be generated by substoichiometric combustion of organic-rich fuel gas
derived from synthesis operations.  The extent to which this reducing gas
dilutes the residual sulfur concentration from tail gas treatment depends
upon the reducing gas quality and  the amount of air required for stable com-
bustion.  For this reason, performance of Beavon/Stretford units is typically
reported on a dry tail gas basis.   Residual reducing gas will contribute to
CO concentrations in the effluent  from the Beavon/Stretford process although
quantitative data are not available.  The total capital investment and annual-
ized costs of the subject Beavon/Stretford unit would be approximately $7.4
million and $1.4 million, respectively.
     Secondary waste streams from  the Beavon/Stretford process are:  (1) sour
reactor effluent condensate (Stream 405), (2) Stretford solution purge (Stream
                                     193

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Section 4
H2S-Rich Rectisol  Gases
Tail  Gas Treatment
406), (3) Stretford oxidizer vent gas  (Stream 404),  and (4)  spent  catalyst
from the Beavon reactor (Stream 407).   Sour condensate  is  expected to  contain
dissolved sulfide and traces of NH^,  and would be generated  at  a rate  of up
      3
to 4 m /hr.   Stretford solution purge  for control  of thiosulfate and thiocyanate
buildup may be present as a waste stream containing  vanadium and sodium salts
as thiosulfate, sulfate, carbonate,  and thiocyanate.  The  solution purge rate
is approximately 0.1 to 0.2 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 (^ but may  contain traces  of  NhU.   Insufficient data
are available for estimating the flow  rate of oxidizer  vent  gas.   The  cobalt
molybdate hydrogenation catalyst inventory is approximately  15  Mg  and  would
require periodic replacement.  Assuming a catalyst service life of three years,
the average spent catalyst generation  rate would be  5 Mg/year.  Beavon/
Stretford sulfur is generated at a rate of approximately 0.4 Mg/hr and may
require disposal, depending upon its  quality and market considerations.
     The SCOT process is reported to  be capable of reducing  residual sulfur
concentrations to about 250 ppmv (dry  tail gas basis).   This corresponds to
a total sulfur emission rate of 0.2  kmol/hr from tail gas  treatment.   Minor
constituents such as methanol and NH3  present in the tail  gas from bulk sul-
fur removal  are not expected to be affected by the SCOT process.   As dis-
cussed in conjunction with the Beavon/Stretford process, supplemental  reduc-
ing gas would be required, and the reducing gas quality/generation mode
would influence the concentration of sulfur species  in  the tail gas treatment
effluent but not the sulfur effluent rate.  Residual  reducing gas  will con-
tribute to CO concentrations in the  treated gas from the SCOT process  although
quantitative data are not available.   The total capital investment and
annualized costs of the subject SCOT unit would be approximately  $6.3  million
and $1.9 million, respectively.
     Secondary waste streams from the  SCOT process are  sour water  (Stream 409)
and spent catalyst (Stream 410).  The sour water is  expected to contain dissolved
                                     194

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                                                       Section 4
                                                       I^S-Rich Rectisol Gases
                                                       Tail Gas Treatment
                                                                  3
sulfide and traces of NH^, and would be generated at a rate of 5 m /hr.   The
cobalt molybdate hydrogenation catalyst inventory is approximately 15 Mg, and
would require periodic replacement.  Assuming a catalyst service life of 5
years, the average spent catalyst generation rate would be 3 Mg/year.
     The Wellman-Lord process is reported to be capable of reducing residual
sulfur concentrations to about 250 ppmv SOo (dry tail gas basis).  This
corresponds to a total sulfur emission rate of 0.2 kmol/hr from tail gas
treatment.  Minor constituents such as methanol, CO, and NHo present in  the
tail gas from bulk suflur removal are expected to be destroyed during tail gas
incineration.  Combustion of the tail gas requires supplemental fuel and air,
and results in an increase in the molar flow rate through the tail gas treat-
ment unit.  The magnitude of this increase and its related SOn dilution  depend
upon the quality of the supplemental fuel and the stoichiometric excess  of
air.  Assuming methane as the incineration fuel with 20% excess air, effluent
from the subject Wellman-Lord unit would contain about 150 ppmv S02.  The total
capital investment and annualized costs for this Wellman-Lord unit would be
approximately $11 million and $3.7 million, respectively.
     Secondary waste streams from the Wellman-Lord process are acidic waste-
water from combustion gas quenching (Stream 411) and thiosulfate/sulfate by-
product purge (Stream 412).   The acidic wastewater typically has a pH value
                                                        3
between 1 and 2, and would be generated at a rate of 3 m /hr.  By-product
purge consists primarily of sodium salts such as sulfite, pryosulfite, sul-
fate, and thiosulfate with approximately 29% water.  By-product purge is
generated at a rate of 90 kg/hr.
                                     195

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Section 4
H2S-Rich Rectisol  Gases
Incineration
Incineration
     Waste gases from tail  gas treatment may be incinerated to control  odors
due to the presence of H2$  and to destroy CO.  As discussed in Section  4.1.1,
thermal incineration, catalytic incineration, and flaring are employed  in
various commercial  applications.   Thermal incineration in a dedicated incin-
erator is an approach often used  in conjunction with tail gas treatment units
and will  be considered in this section.
     In the base plant, gases from tail  gas treatment processes not having
an integral incineration step are generated at a rate of approximately  880
kmol/hr.   The sulfur content of these gases ranges from 100 to 250 ppmv with
H2S concentrations  ranging  from 10 to 200 ppmv.  The level  of combustibles
is expected to be inadequate to support  combustion,  and supplemental  fuel
would be required for incineration.  Using desulfurized, unshifted synthesis
gas as a typical fuel and an incineration temperature of HOOK, about 1230
to 1300 kmol/hr of incineration gas would be generated.  The concentration
of S02 in the effluent would be 70 to 180 ppmv, depending upon the input
sulfur concentration and the amount of excess combustion air provided for
incineration.  Concentrations of CO in the combustion gas are likely to be
below 100 ppmv although quantitative data are limited.  No secondary waste
streams are generated by thermal  incineration processes.  The total capital
investment and annualized costs for the  subject thermal incinerator would
be approximately $0.42 million and $0.63 million, respectively.
                                    196

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                                                       Section 4
                                                       Cyanide Wash Flash Gas
4.1.1.2  Cyanide Wash Flash Gases (Stream 214) - Individual Stream Control
     Generation rates and compositions of flash gases from cyanide wash
operations are dependent upon whether a water-based or methanol-based cyanide
wash is employed (see Section 3.3.4).  In the case of a water-based cyanide
wash, the estimated flash gas generation rate is 22 kmol/hr, consisting of
89% C02, 11% H2$,  and 449  ppmv HCN (Stream 214a).  In the case  of  a methanol-
based cyanide wash, the estimated flash gas generation rate is 16 kmol/hr,
consisting of 45% H2S, 27% CO, 13% HCN, 7% C02, 3% COS, and 2% methanol
(Stream 214b).  Due to the relatively high sulfur concentrations of these
streams and since they may contain 1 to 3% of the gasified coal's total sul-
fur, these gases would probably be treated in bulk sulfur  removal with the
larger volume H2S-rich Rectisol offgas (Stream 216).  Control of cyanide
wash flash gases would be achieved as previously discussed in conjunction
with controls applicable to the H2S-rich Rectisol offgas (Section 4.1.1.1).
                                     197

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Section 4
C02-Rich Rectisol  Gases
4.1.1.3  C02-Rich Rectisol  Offgas (Stream 219)  - Individual  Stream Control
     For purposes of analyses,  the combined C02-rich Rectisol  offgas (Stream
219) has been estimated to  consist primarily of C0? with 13  ppmv total  sulfur
and 1% CO (see Section 3.3.6).   The indicated sulfur level  in  this stream is
below the levels attainable with existing sulfur removal processes, and no
further treatment for sulfur removal  is warranted.   In the  event that CO
control would be required for this stream, the  Rectisol  unit could be de-
signed to further reduce the CO concentration.   Carbon monoxide is sparingly
soluble in methanol, and CO absorbed from K-T product gas at high pressures
can be largely recovered as a separate CO-rich  C02  stream by flashing laden
methanol from C02 absorption to an intermediate pressure before regeneration
for bulk CO- removal.  The  CO-rich offgas can be subsequently  incinerated
for control of CO emissions; this approach has  been proposed in the U.S. for
one Texaco-based coal gasification facility employing the selective Rectisol
process.  Alternatively, the CO-rich offgas may be  recompressed for addition
to the Rectisol product gas if the resulting C02 load is compatible with
synthesis requirements.  This latter alternative may involve design modifica-
tions for both the shift conversion and C02-removal operations to ensure an
appropriate synthesis gas composition.  Finally, the CO-rich offgas may be
utilized within the facility as either fuel or reducing gas.  Any of these
alternatives would offer advantages over "add on" control of CO in the com-
bined C02-rich offgas stream due to the energy penalty associated with incin-
eration of high volume, low heating value gases.
     With regard to controlling potential CO emissions associated with the
C02-rich Rectisol acid gas, catalytic incineration of a CO-rich offgas will
be examined in this section.  It should be noted that constraints  associated
with the control of CO emissions would influence the design of the Rectisol
acid gas removal unit and,  possibly, the shift conversion unit.  This influ-
ence may result in an increased cost for these units which should  be attri-
buted to pollution control.  However, due to the absence of specific design

                                     198

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                                                      Section 4
                                                      C0?-Rich Rectisol  Gases
and cost information for the Rectisol  and shift conversion units,  these
costs will  not be addressed in this section.   Therefore,  control  costs pre-
sented in this section may be lower than the  actual  cost  incurred in an inte-
grated facility.
                                    199

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Section 4
C02-Rich Rectisol  Gases
Incineration
Incineration
     To evaluate catalytic incineration as a CO control  alternative, a CO-
rich COo stream containing 20% CO and 80% COo has been assumed to be obtain-
able from the Rectisol  unit.   The flow rate of this stream would be approxi-
mately 500 kmol/hr.  No supplemental  fuel is required for incineration of
this waste gas in a catalytic incinerator.  With a 99% combustion efficiency,
CO emissions from the incinerator would be 1 kmol/hr at an effluent concen-
tration of about 1000 ppmv.  The total capital investment for this catalytic
incinerator would be approximately $574,000 which corresponds to 0.05% of
the base plant capital  investment.  The associated annualized capital charge
is offset by steam credits from heat recovery and a net annualized credit of
$54,000 results.
                                     200

-------
                                                 Section 4
                                                 Acid Gas -  Red.  S/N, Org.,  CO
                                                 Sec. Strms.  - Other Media
4.1.1.4  Secondary Streams from Other Media
      As will be discussed in Section 4.2.4,  certain volatile species  may  degas
or be stripped from wastewaters during treatment.   This  problem is  most likely
to occur with the polysulfide addition and activated sludge processes.  The
mass flow of volatile species in the offgas is uncertain,  but is expected  to
be quite low, and volatiles would primarily consist of hydrogen sulfide with
lesser amounts of hydrogen cyanide and ammonia.   Such fugitive emissions would
primarily represent a potential odor problem.
      If control of volatile emissions (sulfide/cyanide  offgas - Stream 416)
from water pollution control operations is warranted, incineration  may be  a
viable destruction alternative.  One approach to control would involve pro-
viding air-blanketed enclosures for water pollution control units which may
emit odorous volatiles.  The enclosure vent gas could then be used  as  combustion
air in on-site incinerators or boilers.  Such an approach would obviate the
need for a dedicated incineration unit, but would require the purchase and
maintenance of  enclosures, fans,  and ducting.   Control  costs would primarily
depend upon factors such as the specific water pollution control units
requiring control, the location of the incineration unit(s) best suited for
such an application, and the purge rate of blanketing air required  to  maintain
slightly subatmospheric pressures within the water pollution control enclosures.
      Enclosure of activated sludge units with induced draft collection of over-
head gases for incineration is practiced at a number of domestic/industrial
sewage treatment plants in the U:S.  These treatment plants are generally
much larger than those which would be found in K-T based facilities; therefore,
induced draft collection appears feasible from both an economic and technical
standpoint.  Large ponds which might be utilized in K-T facilities  as  "polishing1
steps would be difficult to enclose.  However, most volatiles would evolve from
upstream treatment units which could be more economically enclosed.  Costs
associated with control of volatile species from wastewater treatment operations
                                      201

-------
 Section 4
 Acid Gas -  Red. S/N, Orq., CO
 Sec. Strms.  - Other Media
will not be addressed in this manual  due to large uncertain!ties in emissions,

their sources, and the site/design-specific nature of costing factors.
                                     202

-------
                                                Section 4
                                                Acid Gas - Red. S/N, Org., CO
                                                Integrated Control
4.1.1.5  Integrated Control Examples
     In this section, examples of combined and sequential control of waste
streams are evaluated 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 are under consideration for facilities in the U.S.  Selection of
integrated controls will be based upon specific design requirements and local
conditions  and  can only be made by designers and regulatory authorities in-
volved in a specific project.
     Acid gas streams containing reduced sulfur/nitrogen compounds, organics,
and CO  and  which would logically be combined prior to sequential control
treatment are the H2S-rich Rectisol  offgas (Stream 216) and the cyanide
wash flash gases (Stream 214).  Three sequential control alternatives  for  the
combined waste gas stream will be examined in this section.
     •  Claus bulk sulfur removal  with Beavon/Stretford tail gas treatment
     0  Claus bulk sulfur removal  with SCOT tail gas treatment, and
        incineration
     t  Claus bulk sulfur removal  with Wellman-Lord tail gas treatment
These alternatives have been demonstrated in refinery applications and are
currently under consideration for application to the North Alabama Coal
Gasification Consortium Project (82).   Detailed descriptions of the controls
included in these alternatives are presented in the PCTM Pollution Control
Technology Appendices.
Example 1 - Claus Bulk  Sulfur Removal  with Beavon/Stretford  Tail Gas Treatment
     This example illustrates treatment of the combined hLS-rich Rectisol  off-
gas (Stream 216) and the flash gas from a methanol-based cyanide wash  unit
(Stream 214b) in a Claus bulk sulfur removal  unit with Beavon/Stretford tail

                                      203

-------
Section 4
Acid Gas - Red. S/N, Org., CO
Integrated Control
gas treatment.  The control  system is presented schematically in Figure 4-3,
and material flow estimates  are presented in Table 4-6.   The Claus process
could operate in either a "split flow" mode, with the cyanide-rich flash gas
passing entirely through the burner for HCN destruction, or in a "straight
through" mode.  The sulfur concentration of the combined feed gas (47% total
sulfur) is sufficiently high to enable "straight through" processing.  Also,
the HCN level of 0.4% in the combined feed gas is not expected to require
special approaches for HCN destruction.
     The Claus unit is reported to achieve 95% sulfur removal and have
a residual sulfur distribution of 60% H2S, 30% S02, 9% COS, and 1% CS2.  It
should be noted that up to 50% of the residual sulfur (S0? equivalent basis)
may actually be present as either sulfur vapor or entrained elemental sulfur,
which would slightly reduce the tail  gas volume.  One-third of the feed gas
CO and methanol have been assumed to be destroyed during Claus processing,
although higher methanol destruction efficiencies may result depending upon
the specifics of the combustion process.   Carbon monoxide may actually be
generated in the Claus process since some facilities report tail gas concen-
trations of 1 to 2% CO with essentially CO-free Claus feed gases.  Complete
HCN destruction has been assumed; some low level NH-, emission may result from
HCN destruction  although  quantitative data are not available.
     The Beavon/Stretford unit is reported to be capable of reducing tail
gas residual sulfur concentrations to about 100 ppmv (dry Claus tail gas
basis) with a 9:1 ratio of COS to H2S.  A CO-rich fuel gas has been used in
the example for reheat of the Claus tail  gas and catalytic reduction of S0?.
The resulting sulfur emission rate is 0.08 kmol/hr from tail gas treatment.
Methanol present in the Claus tail gas is not expected to be affected by the
Beavon/Stretford process.   While no residual reducing gas in the Beavon
effluent has been indicated in Table 4-6, concentrations of CO ranging from
250 to 670 ppmv in the effluent have been reported.
                                     204

-------
no
o
on
H2S-RICH
OFFGAS

FLASH GAS
FROM      —
METHANOL-
BASED
CYANIDE WASH
                                                                         STRETFORD
                                                                         OXIDIZER
                                                                         VENT  GAS
                                CLAUS BULK

                              SULFUR REMOVAL.
                                 i
                                _L
                                402'
                               -	'
                                t

                           SPENT CATALYST
                                                 CLAUS TAIL GAS
FUEL/REDUCING
GAS
 BEAVON/STRETFORD

TAIL GAS TREATMENT
                                      SULFUR
                                                                 SOUR
                                                              CONDENSATE
                                                                               SPENT
                                                                              CATALYST
                                                                      STRETFORD
                                                                       SOLUTION
                                                                        PURGE
BEAVON/STRETFORD TAIL
GAS TO ATMOSPHERE
          Figure 4-3.  Example  1  -  Claus bulk sulfur  removal  with Beavon/Stretford tail gas treatment

-------
                        TABLE  4-6.   EXAMPLE  1   - MATERIAL  FLOW  ESTIMATES  FOR  INTEGRATED CONTROL  EMPLOYING
                                         CLAUS  BULK SULFUR  REMOVAL  WITH  BEAVON/STRETFORD  TAIL GAS  TREATMENT*
ro
o
01
Rectisol Cyanide Wash Flash Gas
H2S-Rich Offgas Methanol Wash Case
Stream 216 Stream 214b
kmol/hr Vol kmol/hr Vol
H
CO
co2
COS
cs2
so2
HCN
'2
Methanol
Sulfur
Total Dry Gas
H20
Total
kmol/hr
kg/hr


271 50.8
222 41.6
25 4.7
2 0.4
0.1 218ppmv
0.3 636ppmv
6 1.2
7 1.3

533

533
21544
0.49 3.0
4.4 26.4
1.2 7.3
7.3 44.7
0.56 3.4


2.1 12.9

0.3 1.8

16

16
524
Combi ned
Feed
kmol /hr
0.49
4.4
272
229
26
2
0.1
2.4
6
7

549

549
22068
Claus
Gas
Voi -
892ppmv
0.8
49.5
41.7
4.7
0.3
211 ppmv
0.44
1.2
1.3




Stretford Sour
Claus Sulfur Beavon/Stretford Sulfur Condensate
Claus Tail Gas Stream 403 Fuel Gas Tail Gas Stream 408 Stream 405
kmol/hr Vol kg/hr kmol/hr Vol kmol/hr Vol kq/hr kq/hr
0.33 0.04 33 26.9
2.9 0.3 78 63.3
310 36.8 12 9.8 402 35.6
7.8 0.9 0.008+ 7ppmv
1.2 01 0.075f 74ppmv
0.07 78ppmv
3 9 0.5

512 60.7 721 63 9
4.7 0.6 4.7 0.4
7857 411
843 123 1128
227 47 4027
1070 123 n75
32926 7857 2784 38893 411 4027
             The number of significant figures shown in some cases do  not represent the degree of accuracy and are retained for material balance purposes only
             Nevertheless, slight imbalances  do appear as a result of  numerical  rounding   Material flow estimates are based upon published data and engineering
             estimates.   Performance data and references are detailed  in the  Control Technology Appendices.
             Residual sulfur levels are based upon  100 ppmv total sulfur (Claus tail gas basis).

             ^Some level of residual reducing  gas would be present in the Beavon/Stretford effluent.  Concentrations of CO in the effluent ranging from 250 to
             670 ppmv have been reported.

-------
                                                 Section 4
                                                 Acid Gas - Red.  S/N,  Org.,  CO
                                                 Integrated Control
     Secondary waste streams from the control system are:  (1) spent Claus
 catalyst  (Stream 402),  (2) sour condensate  (Stream 405),  (3) Stretford solu-
 tion purge  (Stream 406),  (4) Stretford oxidizer vent gas  (Stream 404), and
 (5) spent Beavon catalyst  (Stream 407).  The Claus unit would have a bauxite
 or alumina  catalyst inventory of approximately 50 Mg.  Assuming a catalyst
 life of 5 years, the average spent Claus catalyst generation rate would be 10
 Mg/year.  Sour condensate  is expected to contain dissolved sulfide and traces
                                                    o
 of NH3 and  would be generated at a rate of about 4 m /hr.  Stretford solution
 purge (Stream 406) for  control of thiosulfate and thiocyanate buildup may be
 present as  a waste stream  containing vanadium and sodium  salts as thiosulfate,
 sulfate, carbonate, and thiocyanate.  The solution purge  rate is approximately
 0.1 to 0.2  Mg/hr.   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 C02 but may contain traces of NH3.  Insufficient data are
 available for estimating the flow rate of oxidizer vent gas.   The cobalt
 molybdate Beavon hydrogenation catalyst inventory is approximately 15 Mg.
 Assuming a  catalyst service life of three years,  the average spent catalyst
 generation  rate would be 5 Mg/year.  In addition, sulfur  from the Claus and
 Beavon/Stretford processes (Streams 403 and 408)  is generated at a combined
 rate of 8.3 Mg/hr and may  require disposal, depending upon sulfur quality and
 market considerations.
     Cost estimates for the Claus and Beavon/Stretford units  are summarized
 in Table 4-7.  Estimates are presented on two bases:   (1) total  capital in-
 vestment and annualized costs and (2) total capital investment and annualized
 costs as percentages of the uncontrolled base plant costs for the methanol
 synthesis case.   All  costs are presented on a 1980 basis.   The total
 capital  investment was  found to be  similar for the Claus and  Beavon/Stretford
 units.   However,  annualized Claus costs were estimated to be  about 70% lower
 than those for the Beavon/Stretford, primarily as a result of large credits
associated with  steam generated during  Claus processing, and  fuel  gas require-

                                     207

-------
Section 4
Acid Gas - Red. S/N, Org., CO
Integrated Control
    TABLE 4-7.   EXAMPLE 1  - COSTS OF INTEGRATED CLAUS  BULK SULFUR  REMOVAL
                WITH BEAVON/STRETFORD TAIL  GAS  TREATMENT  (1980  BASIS)
Total Capital Investment
106 Dollars

% of
Base Plant*

Annual i zed Cost
106 Dollars
0.41
% of
Base Plant*

 Beavon/
 Stretford Unit
 7.4
                 1.4
 Total
16.1
1.45
1.8
0.52
 Expressed as a percentage of the cost for an uncontrolled methanol  synthesis
 facility.

ments for the Beavon/Stretford process.  Capital  and annualized costs for the
integrated control system represent approximately 1.4% and 0.5% of the respec-
tive costs for the uncontrolled methanol synthesis base plant.
     Performance and cost of the Claus/Beavon/Stretford control system are
dependent upon both the feed gas flow rate and sulfur content.   For example,
if the selectivity of the Rectisol unit were reduced to produce a Claus feed
gas of 15% total sulfur for the same coal sulfur content, the Claus feed gas
flow rate would increase by a factor of about three and the Beavon/Stretford
tail gas flow rate would increase by a factor of about two.  Therefore, emis-
sions from the Beavon/Stretford would also increase by a factor of about two.
The resulting increases in capital costs for Claus and Beavon/Stretford units
are estimated to be about 40% and 60%, respectively.  Alternatively, with the
same Rectisol selectivity (i.e., 47% sulfur in the Claus feed)  for a coal
having one-half the total sulfur content initially considered,  the Claus feed
                                      208

-------
                                                Section 4
                                                Acid Gas - Red.  S/N,  Org.,  CO
                                                Integrated Control
gas rate and the Beavon/Stretford tail  gas flow rate would decrease by about
one-half.  Therefore, emissions from the Beavon/Stretford would also decrease
by about one-half.  The resulting decreases in capital costs for Claus and
Beavon/Stretford units are estimated to be about 40% and 35%, respectively.

Example 2 - Claus Bulk Sulfur  Removal with SCOT Tail Gas Treatment and
Incineration
     This example illustrates treatment of the combined FUS-rich Rectisol
acid gas (Stream  216) and the flash gas from a methanol-based cyanide wash
unit (Stream 214b) in a Claus bulk sulfur removal unit with SCOT tail gas
treatment and thermal incineration.  The  control system is presented schemat-
ically  in Figure  4-4, and material flow estimates are presented in Table 4-8.
Assumptions relating to Claus unit performance are idential to those pre-
sented for Example 1  although in this example the SCOT recycle gas repre-
sents an additional Claus feed gas stream.
     The SCOT unit is reported to be capable of reducing Claus tail gas resi-
dual sulfur concentrations to about 250 ppmv (dry Claus tail gas basis).  A
CO-rich fuel gas  has been used in this example to reheat the Claus tail
gas, catalytic reduction of SO-, and subsequent incineration.  The resulting
sulfur emission rate is about 0.2 kmol/hr S02 from tail gas treatment and
incineration.  While methanol present in  the Claus tail gas is not expected to
be affected by SCOT tail gas treatment, essentially complete destruction would
be achieved during incineration.
     Secondary waste streams from the control system are:  (1) spent Claus
catalyst (Stream  402), (2) sour condensate (Stream 409), and (3) spent SCOT
catalyst (Stream  410).  As in Example 1,  spent Claus catalyst would be gen-
erated at an average rate of approximately 10 Mg/yr assuming a 5 year catalyst
life.  The sour condensate is expected to contain dissolved sulfide and traces
                                              3
of NhL and would  be generated at a rate of 4 m /hr.  The cobalt molybdate SCOT
hydrogenation catalyst inventory is approximately 15 Mg.  Assuming a catalyst
                                      209

-------
HgS-RICH
ACID GAS
FLASH  GAS
FROM
METHANOL-
BASED
CYANIDE WASH
                                  SCOT RECYCLE GAS
  CLAUS BULK
SULFUR REMOVAL
   I
(To?)
   t
 SPENT
CATALYST
                                   403
                 CLAUS TAILGAS
                 FUEL/REDUCING
                 GAS
                                 SULFUR
                                     SCOT  TAIL GAS
                                       TREATMENT
                                                          SOUR
                                                       CONDENSATE
                                                      SCOT TAIL GASJ
                                             SPENT
                                            CATALYST
                                                         FUEL GAS
                                                                                                 THERMAL
                                                                                               INCINERATION
INCINERATED
GAS TO
ATMOSPHERE
     Figure  4-4.   Example 2  -   Claus  bulk  sulfur removal-with  SCOT  tail  gas  treatment and  incineration

-------
       TABLE 4-8.   EXAMPLE  2 - MATERIAL FLOW ESTIMATES FOR  INTEGRATED CONTROL EMPLOYING
                    CLAUS  BULK SULFUR REMOVAL, SCOT  TAIL GAS TREATMENT, AND  INCINERATION*

H2
CO
co2
H2S
COS
cs2
so2
HCN
N2
Methanol
Sulfur
Total Dry Gas
H20
Total
kmol/hr
kg/hr


Offgas
Stream 216
krol/hr


271
222
25
2
0 1
0 3
6
7

533

533
21544
Vol ,


50 8
41.6
4.7
0.4
218ppmv
636ppmv
1 2
1.3




The number o! significant figures
slight imbalances do appear as a
data and references are detailed
Cyanide ^ash
Flash Gas
Methanol hash Case Combined Claus
Stream 214b SCOT Recycle Gas Feed Gas (
kmol/l
0.49
4.4
1 2
7.3
0 56


2 1

0.3

16

16
524
shown in
result of
in the Coi
ir Vol '. kmol/hr Vol = kmol/hr Vol * k
3.0 0 28 0.6 0.8 0 1
26 4 2.4 50 6.8 1 1
7.J 32 66 8 304 50.9
44 7 13 27 6 242 40 5
34 26 4.4
2 03
0 1 168ppmv
12 9 2.4 0.4
6 1.0
18 7 1.2

48 597
2 2
50 599
1984 24052
some cases do not represent the degree of accuracy and
numer'cal rounding. Material flow estimates are based
Claus Sour
:laus Tail Gas Stream 403 SCOT Fuel Gas SCOT Tail Gas Stream 409 Fuel Gas Tail Gas
mol/hr Vol kg/hr kmol/hr Vol . kmol/hr Vol t kq/hr kmol/hr Vol ". kmol/hr Vol
0 46 SOOppnw 38 26.9 40 26 9
4.1 05 89 63 3 94 63.3
340 37 7 14 9 8 411 34 5 15 9.8 520 33 6
8.1 0 9 0 2f 168ppm»
12 01 0.04* 34ppfflv
0 07 78ppmv
4105 0.2 129ppmv

538 59 7 776 65 1 1029 66 4
4 7 0.5 4.7 0 4
8260
90! 141 1192 149 1549
242 50 3978 90
1220 8260 141 1244 149 1639
35295 2569 40889 3978 2715 5335
are retained for material balance purposes only Nonetheless
upon published data and engineering estimates. Performance
fResidual sulfur levels are based upon 250 ppmv total sulfur (Claus plant tail gas basis).

-------
Section 4
Acid Gas - Red. S/N, Org., CO
Integrated Control
life of 5 years, the average spent catalyst generation rate would be 3 Mg/yr.
In addition, Claus sulfur is produced at a rate of about 8.3 Mg/hr and may
require disposal, depending upon sulfur quality and market considerations.
     Cost estimates for the Claus, SCOT, and incineration units are summarized
in Table 4-9.  Estimates are presented on two bases:  (1) total capital in-
vestment and annualized cost, and (2) total capital investment and annualized
cost percentages of the uncontrolled base plant cost for the rnethanol synthe-
sis case.  All costs are presented on a 1980 basis.  The total capital invest-
ment for the combined SCOT/incineration system was estimated to be nearly 30%
lower than the capital investment for the Claus unit.  However, annualized
Claus costs are estimated to be about 80% lower than those for the combined
SCOT/incineration system.  This is primarily due to large credits associated
with steam generated during Claus processing, and fuel gas requirements for
tail gas treatment and incineration.  Capital and annualized costs for the
integrated control system represent approximately 1.4% and 0.7% of the res-
pective costs for the uncontrolled methanol synthesis base plant.
     The effects of feed gas flow rate and sulfur content upon the control
system's performance and cost have been discussed in Example 1.  Similar  con-
clusions can  be drawn with  respect to the effects of these parameters  upon
the Claus/SCOT/incineration control system.
Example  3  -  Claus  Bulk  Sulfur Removal with Wellman-Lord  Tail  Gas  Treatment
     This  example  illustrates treatment  of  the  combined  H2S-rich  Rectisol
acid gas  (Stream 216)  and  the flash  gas  from  a  methanol-based  cyanide wash
unit  (Stream 214b)  in  a  Claus bulk  sulfur removal  unit with  Wellman-Lord
tail gas  treatment.   The control  system is  presented schematically in Figure
4-5, and  material  flow estimates  are  presented  in Table 4-10,. Assumptions
relating  to Claus  unit performance  are  identical  to those presented in
Example  1, although  in this example  the Wellman-Lord recycle gas represents
an additional Claus  feed stream.
                                      212

-------
                                               Section  4
                                               Acid Gas -  Red.  S/N,  Org.,  CO
                                               Integrated  Control
    TABLE 4-9.   EXAMPLE 2 - COSTS OF INTEGRATED CLAUS  BULK SULFUR REMOVAL
                WITH SCOT TAIL GAS TREATMENT AND INCINERATION  (1980 BASIS)
                     Total  Capital  Investment
                                      2T6T
                     106  Dollars    Base Plant*
                                 Annualized  Cost
                           106  Dollars
                               % of
                            Base Plant*
 Claus Unit
 9.2
                 0.44
 SCOT Unit
 6.3
                 1.9
 Incineration
 Unit
Total
 0.42
15.9
1.44
                 0.63
3.0
0.86
 Expressed as a percentage of the cost for an uncontrolled methanol  synthesis
 facility.

     The Wellman-Lord unit is reported to be capable of reducing Claus
tail gas residual sulfur concentrations to about 250 ppmv (dry Claus tail
gas basis).  In this example, the corresponding Wellman-Lord tail gas sulfur
concentration is about 150 ppmv.  A methane-rich fuel gas has been used for
Claus tail gas incineration in this example  consistent with the design upon
which the Wellman-Lord flow estimates are based.  In an integrated facility
other fuels may be preferable.  The resulting sulfur emission rate is about
0.2 kmol/hr S02 in the Wellman-Lord tail  gas.  Minor constituents such as
methanol, CO and NH3 which may be present in the Claus tail gas are expected
to be effectively destroyed during the incineration step of tail gas treatment,
     Secondary waste streams from the control system are:  (1) spent Claus
catalyst (Stream 402), (2) sour condensate (Stream 411), and (3) thiosulfate/
                                     213

-------
                                       WELLMAN-LORD RECYCLE GAS
ro
     H2S-RICH
     ACID  GAS
     FLASH GAS
     FROM
     METHANOL-
     BASED
     CYANIDE WASH
  GLAUS BULK

SULFUR REMOVAL
 T
                   CLAUS  TAIL GAS
                      FUEL GAS
                              SPENT
                             CATALYST    SULFUR
   WELLMAN-LORD

TAIL GAS TREATMENT
                                        (4U)

                                           t
                                          SOUR
                                       CONDENSATE
 WELLMAN-LORD
-TAIL  GAS  TO
 ATMOSPHERE
                                                                            THIOSULFATE/SULFATE
                                                                                  PURGE
          Figure  4-5.   Example 3  -  Claus  bulk sulfur  removal with  Wellman-Lord  tail  gas  treatment

-------
         TABLE 4-10.    EXAMPLE  3  -  MATERIAL  FLOW  ESTIMATES  FOR  INTEGRATED  CONTROL  EMPLOYING
                             CLAUS BULK SULFUR  REMOVAL  WITH  WELLMAN-LORD  TAIL  GAS  TREATMENT*
Cyanide Wash
H2$-Rich Flash Gas
Offgas Methanol Hash Case Wellman-Lord Combined Claus
Stream 216 Stream 214b Recycle Gas Feed Gas
kmol/hr Vol I kmol/hr Vol * kmol/hr Vol % kmol/hr Vol %






f\>
. — i
cn











H2
CO
co2
H,S
COS
cs2
so2
HCN
N2
°2
CH4
C2H6
Methanol
Sulfur
Total Dry Gas
H20
Total
kmol/hr
kg/hr


271
222
25
2
0.1
0 3
6



7

533


533
21544
0.49 3 0
4.4 26.4
50.8 1.2 7.3
41.6 2.3 44.7
4.7 0 56 3.4
0.4
218ppmv 13
636ppmv 2.1 12.9
1.2



1.3 0.3 1.8

16 13
7

16 19
524 938
0.49 0 09
4.4 0.8
272 48.4
229 40.7
26 4.6
2 0.4
100 13 2.3
2.4 0.4
6 1.1



7 1.2

562
7

569
23006
Claus .
Sulfur
Claus Tail Gas Stream 403 Fuel
kmol/hr Vol '. kg/hr kmol/hr
0.34 0.04
3.1 0.4
302 38.5
8.1 1.0
1.2 0.2
0.07 87ppmv
4.1 0.5

461 58.7

35
2.2
5 2 0.7

785 8260 37
232

1017 37
31270 8260 623
Sour
+ Wellman-Lord Condensate
Gas Feed Gas Stream 411
Vol % kmol/hr Vol 'i kg/hr


352 27.0



14 1.0

920 70.4
20 1.5
94
6


1306,
327 3297

1682
48651 3297
Hellman-Lord
Tail Gas
kmol/hr Vol "


352



0.2*

920
20




1292
143

1435
44484


27.2



147ppnw

71 2
1.5









 The number of significant figures shown in some cases do not represent the degree of accuracy and are retained for material  balance purposes only.  Nonetheless,
 slight imbalances do appear as result of numerical  rounding  Material flow estimates are based upon published data and engineering estimates.  Performance data
 and references are detailed in the Control Technology Appendices.

fA methane-rich fuel gas has been used in this example consistent with the design upon which the Wellman-Lord flow estimates  are based.   In an integrated
 facility other fuel gases may be preferable.
*The S0? emission rate is based upon 250 ppmv total  sulfur (Claus plant tail gas basis).

-------
Section 4
Acid Gas - Red. S/N, Org., CO
Integrated Control
sulfate by-product purge (Stream 412).   As in Example 1, spent Claus catalyst
would be generated at an average rate of approximately 10 Mg/yr, assuming a
5-year catalyst life.  The sour condensate typically has a pH value between
                                               3
1 and 2 and would be generated at a rate of 3 m /hr.  By-product purge con-
sists primarily of sodium salts such as sulfite, pyrosulfite, sulfate, and
thiosulfate with approximately 29% water.  By-product purge is generated at a
rate of 90 kg/hr.  In addition, Claus sulfur is produced at a rate of about
8.3 Mg/hr and may require disposal, depending upon sulfur quality and market
considerations.
     Cost estimates for the Claus and Wellman-Lord units are summarized in
Table 4-11.  Estimates are presented on two bases:  (1) total capital invest-
ment and annualized costs, and (2) total capital investment and annualized
cost as percentages of the uncontrolled base plant cost for the methanol
synthesis case.  All costs are presented on a 1980 basis.  The total capital
investment was found to be similar for the Claus and Wellman-Lord units.
However, annualized Claus costs are estimated to be about 90% lower than
those for the Wellman-Lord unit.  This is primarily due to large credits
associated with steam generated during Claus processing, and fuel gas require-
ments for tail gas incineration.  Capital and annualized costs for the inte-
grated control system represent approximately 1.8% and 1.2% of the respective
costs for the uncontrolled methanol synthesis base plant.
     The effects of feed gas flow rate and sulfur content upon the control
system's performance and cost have been discussed in Example "I.  Similar con-
clusions can be drawn with respect to the effects of these parameters upon
the Claus/Wellman-Lord control system.
                                      216

-------
    TABLE 4-11.   EXAMPLE 3 - COSTS OF INTEGRATED CLAUS BULK SULFUR REMOVAL
                 WITH WELLMAN-LORD TAIL GAS TREATMENT (1980 BASIS)

Total Capital Investment
, % of
10° Dollars Base Plant*
Annuali zed Cost
, % of
10° Dollars Base Plant*
Claus Unit               9.2                            0.44
Wellman-Lord            11                               3.7
Unit
Total                   20             1.8              4.1            1.2
*
 Expressed as a percentage of the cost for an uncontrolled methanol  synthesis
 facility.
                                      217

-------
Section 4
Combustion Gases
4.1.2  Combustion Gases
     Combustion of many types of fossil fuels produces a gas stream that
contains undesirable amounts of S09, NO, and/or particulates.   Sulfur dioxide
                                  c.    X
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, S02 must be removed from the exhaust  gas.
     The generation of NO  from air-fed fuel combustion processes occurs by
                         /\
two separate mechanisms, namely thermal NO  formation and fuel  NOV formation.
                                          X                      X
Thermal NOV results from the thermal fixation of molecular nitrogen and
          A
oxygen in the combustion air and is sensitive to flame temperatures and to
local concentrations of oxygen.  Fuel NOV is created from the oxidation of
                                        X
chemically-bound nitrogen in the fuel being combusted.  Fuel NO  formation
                                                               X
is strongly affected by the rate of mixing of the fuel and air  and by the
local oxygen concentration.  Approximately 95% of nitrogen oxides from com-
bustion are emitted as NO (83,84).
     The particulates generated during combustion result mainly from the ash
content of the fuel.  The magnitude of these emissions in the flue gas is a
function of combustion unit design and ash content of the fuel.  Particulate
emissions are very low when oil-based fuels are used and are negligible with
gaseous fuels.
     Combustion gases will also contain CO and very small amounts of unburned
organics (including polycyclic compounds).  Concentrations  of these compon-
ents are a function of both the fuel burned and the design  and operation of
the  combustion unit.  Trace elements present in the fuel may also be present
in flue gases.  Ordinarily, however, no controls are applied to combustion
gases  specifically for control of CO, organics, or trace elements.  Some
degree of trace elements control  is achieved as part of particulate removal.
                                     218

-------
                                                             Section 4
                                                             Combustion Gases
     The major sources of flue gases from a K-T based indirect liquefaction
facility are the power boiler, process heaters, gas turbines,  and secondary
combustion gas streams from other media.   In this section control technologies
applicable to the removal of nitrogen oxides, particulates, and sulfur oxides
from such stationary sources are discussed.
                                     219

-------
Section 4
Combustion Gases
NOV Control
  X
NOX Control
     NOX pollution control  techniques are of two types:   (1) those that
limit nitrogen conversion to NOY by modifying combustion characteristics and
                               /\
(2) flue gas treatment techniques (i.e., removal of NO  after it is formed).
                                                      X
     Combustion modification techniques are the most widely used techniques.
They can achieve from 25 to 60% reduction in NOV emissions.  Some of the
                                               X
common combustion modification techniques are (1) low excess air, (2) staged
combustion, (3) flue gas recirculation, (4) reduced load, (5) low NO  burners,
                                                                    X
and (6) ammonia injection.   The key features and unit costs of these techni-
ques are discussed in Table 4-12.
     Low excess air level in the furnace has generally been found to be an
effective method for NO  control.  In this technique, the combustion air is
                       /\
reduced to the minimum amount required for  complete combustion while main-
taining acceptable furnace cleanliness  and steam temperature.  With less
oxygen available in the flame zone, both thermal and fuel NO  formation are
                                                            X
reduced. In addition, the reduced air flow lowers the quantity of flue gas
released resulting in an improvement in boiler efficiency.
     Staged combustion produces overall fuel-rich conditions during the first
couple of seconds and promotes the reduction of NO to N~.  Various methods
to achieve this are available.  Overfire Air and Burners Out of Service are
two techniques  generally used on coal  fired  boilers.  Details  regarding  their
performance and applicability are provided  in Table  4-12.
     Flue gas recirculation  (FGR) consists of recycling a portion of the flue
gas back to the primary combustion zone.  This reduces NO formation by lower-
ing the bulk gas temperature and oxygen concentration.  This technique,
however, is effective only on oil and gas fired boilers.
     Load reduction can be used to decrease NOV emissions.  Thermal NOV for-
                                              X                       X
nation generally increases as the volumetric heat release rate or combustion

                                     220

-------
                            TABLE 4-12.   COMBUSTION MODIFICATION  TECHNIQUES FOR  NOX CONTROL
              Control
             Technique
                            Description
                               of
                             Technique
                               Efficiency
                                (as % NOX
                               Reduction)
    Type of
   Fuel  Fired
     Range of
    Application
          Low Excess Air
          (LEA)
ro
Staged Combustion
  Overfire Air
  Injection (OFA)
            Staged
            Combustion Air
            (LEA  +  OFA)
                      Combustion air is reduced
                      to  the minimum amount re-
                      quired for complete com-
                      bustion while maintaining
                      proper stream temperature.
Injection of air above the
top burner level  through
OFA ports together with a
reduction in air flow to
the burners (staged com-
bustion).

Reduction of under grate
air flow and increase of
overfire air flow.

Fuel rich firing  burners
with secondary  combustion
air ports.
                               Injection of secondary
                               air downstream of the
                               burner(s) in the direction
                               of the flue gas path.
                                 0 - 25


                                 5 - 25
                                                                0 - 28
                                                                0-24

                                                                5 - 35
                                                                5 - 30
                                                      5 - 25
                                                               20 - 50
                                                               17 - 44
                                                      5 - 46
Pulverized coal
                                                                              Stoker coal
                                                                    Residual oil
                                                                    Distillate oil

                                                                    Natural gas
Pulverized coal
Stoker coal
                                                                    Residual  oil
                                                                    Distillate oil
                                               Natural  gas
Excess Q£ lowered to
5.2% on the average.

Excess 02 limited to
5-6% minimum.
                   -\
Excess 02 can be
reduced to <3%.

Excess 02 can be
reduced to <3%.
Burner 02 can be as
low as stoichiometric
Excess 02 limited to
5% minimum.
                   70-90% burner stoichio-
                   metry can be used with
                   proper burner installa-
                   tion.

                   70-90% burner stoichio-
                   metries can be main-
                   tained.  Applicable to
                   all  units, however,
                   requires extensive equip-
                   ment modification.
                                                                                                       (Continued)

-------
          TABLE 4-12.    (CONTINUED)
Control
Technique
Low Excess Air
(LEA)
Type of
Fuel Fired
Pulverized
Coal
Stage of
Development
Available but implemented
on a limited basis only.
Secondary
Waste
None

Capital :
Operating:
Cost
$440 to $550/MW heat input
0 to 8 mills/103 kg steam
Limitations and Comments
Limited by increase in CO,
HC, and particulate emis-
sions. Increase in boiler
efficiency may be achieved
as a benefit.
                                Stoker coal
                                Residual  Oil
                                Distillate  Oil
                                Natural  Gas
IV.
no
         Staged  Combustion

           Overfire  Air
           Injection (OFA)
           Staged
           Combustion
           Air  (LEA  + OFA)
Pulverized
Coal
                                Stoker Coal
                                Residual  Oil
                                Distillate Oil
                                Natural  Gas
                   Available now but need
                   R&D on lower limit of
                   air.

                   Available.
                                                   Available.
Available but  not
demonstrated.
                   Most stokers  have OFA
                   ports as  smoke  control
                   but may need  better air
                   flow control  devices.
                   Technique is  applicable
                   on packaged and  field-
                   erected units.   However,
                   not commercially avail-
                   able for all  design types.

                   Technique is  still
                   experimental  especially
                   for small  firetube and
                   watertube units.
                                                                                 None
                                                 None
                                                                                 None
None
                                                 None
                             None
                                                                                 None
                                                                                           Capital:
                                                                                           Operating:
                                        Capital:

                                        Operating:
                                                                                           Capital:
                                                                                           Operating:
Capital:
Operating:
                                        Capital:
                                        Operating:
          Capital:

          Operating:
                                                                                           Capital:
                                                                                           Operating:
                                                    $600 to $1850/MW heat input
                                                    13 to 57 mills/103 kg steam
                       $460 to $2400/MW of heat
                          input
                       <83 mills/103 kg steam
                                                                       $580/MW of heat input
$800 to $940/MW heat input
80 to 85 mills/103 kg steam
                      $600 to $800/MW heat input
                      24 to 32 mills/103 kg steam
            $870 to  $5150/MW of heat
                input
            123 to  370  mills/103 kg
                steam
                                                    $1070/MW  of  heat  input
                                                    117 mills/ICr  kg  steam
                                          Danger of overheating  grate,
                                          clinker formation,  corrosion,
                                          and high CO emissions.

                                          Added benefits  include in-
                                          crease in boiler efficiency.
                                          Limited by increase in CO,
                                          HC, and TSP emissions.

                                          Generally practical  because
                                          of increase in  boiler  effici-
                                          ency.   Best NOX reductions
                                          reported for large  multi-
                                          burner units.
Limited by possible increase
in slagging and corrosion.
Excess air may be required
to ensure complete combus-
tion thereby decreasing
efficiency.

Overheating grate, corrosion,
and high CO emissions can
occur if under grate air
flow is reduced below accept-
able level as in LEA.

Best implemented on new units.
Retrofit is probably not fea-
sible for most units espe-
cially packaged ones.
                                                    Found to be less effective
                                                    on firetube boilers than
                                                    watertube boilers.   Generally
                                                    less effective for gas-fired
                                                    units.
                                                              (Continued)~

-------
        TABLE 4-12.   (CONTINUED)
Control
Technioup
Description
of
Technique
Efficiency
(as % NOX
Reduction)
Type of
Fuel Fired
Range of
Application
       Staged Combustion
         Air and Fuel
         Rich Firing
       Flue Gas
       Recirculation
       (FGR)
One or more burners
fired on air only.
Remainder of burners
firing fuel rich.

Recirculation of the
flue gas to the burner
windbox.
rv>
ro
CO
27 - 39
 0 - 20
                              15-30
                              58 -  73
                                                           48  -  86
Pulverized coal
Pulverized coal
                Residual oil
                Distillate oil
                                              Natural  gas
       Reduced Load
Reduction of fuel  and
air flow to the burner.
                                                            Up  to  45%


                                                          Average  15%
                Pulverized coal


                Stoker coal
Boilers must have a
minimum of 4 burners,
or designed with excess
burners.

A maximum of 25% of the
flue gas can be recir-
culated.

Up to 25-30% of flue gas
recycled.  Can be imple-
mented on all design
types.

Flue gas recirculation
rates possible up to 45%.
Technique is applicable
to all boiler types except
ones equipped with ring
burners.
                    Load may be reduced to
                    25% of capacity.

                    Load may be reduced to
                    25%.
                                                                                                       (Continued)

-------
           TABLE  4-12.
  (CONTINUED)
Control
Technique
Staged Combustion
Air and Fuel
Rich Firing
Type of
Fuel Fired
Pulverized
Coal
Stage of
Development
Available, but engineering
refinement is needed prior
to implementation.
Secondary
Waste Costs
None Not available
Limitations and Comments
Load reduction required in
most cases. Possible in-
creased slagging and corro-
         Flue Gas
         Recirculation
Pulverized
Coal
ro
ro
         Reduced Load
Residual  Oil
Distillate Oil
                              Natural Gas
                              Pulverized
                              Coal
                              Stoker Coal
Not offered because  the
method is comparatively
ineffective.
                                   None
               Not available
Available.   Requires
extensive modifications
to the burner  and wind-
box .

Available now.  Best suited
for new boilers.  Retrofit
application  would result
in extensive burner modi-
fications.
                   Available but  not  imple-
                   mented because of  negative
                   operational  impacts.
                                                 Available.
None
                                                                                    None
                                                      None
                                                                                    None
               Capital:     $1070  to  S5150/MW of
                              heat input
               Operating:   196 to 438 mills/103 kg
                              of  steam
                                                                                                   Capital:
                                                                                 $870  to  $1070/MW  of
                                                                                    heat  input
                                                                     Not available
                                                                                                   Not available
 sion.  New boiler design
 will incorporate the re-
 quired number of burners.

 Flue gas recirculation
 lowers the bulk furnace gas
 temperatures and reduces C>2
 concentration in the com-
 bustion zone.  Requires in-
 stallation of flue gas re-
 circulation ducts, fans,
 insulation, etc.  flay cause
 combustion instability.

 Best suited for new units.
 Costly to retrofit.   Possible
 flame instability at high
 FGR rates.

 Flame instability problem
 is not severe except for
 ring burners.  Minor burner
modifications can guarantee
 stable flames.   Most effec-
 tive on watertube units.

Best used with  increase in
firebox size for new boilers.
Load reduction  may not be
effective because of increase
in excess 0£.

Only for stokers  that can
reduce load without  in-
creasing excess  air.   Not
a desirable technique be-
cause of loss in  boiler
efficiency.
           (Continued)

-------
       TABLE 4-12.   (CONTINUED)
ro
rv>
en
Description Efficiency
Control of (as % NOx Type of
Technique Technique Reduction) Fuel Fired
Reduced Load 33% decrease to Residual oil
25% increase*
31% decrease to Distillate oil
17% increase*
32% decrease to Natural gas
82% increase*
Low NOX Burners New burner designed 45 - 60 Pulverized coal
to utilize controlled
air-fuel mixture.
20 - 50 Residual oil
20 - 50 Distillate oil
all boilers.
20 - 50 Natural gas
NHj Injection Injection of NH3 into 40 - 60 Pulverized coal
convective section of
the boiler.
40 - 70 Residual oil
40 - 70 Distillate oil
40 - 70 Natural gas
Range of
Application
Applicable to all boiler
types and sizes. Load
can be reduced to 25% of
maximum.
Tests to 20% of rated
capacity. Applicable to
all units.
Prototypes are limited
to size ranges >30 MW.
New burners described
generally applicable to
all boilers.
More specific information
needed.
NH3 injection rate limited
to NH3
NO = ]'5
Applicable for large
package and field-erected
watertube boilers.
Not feasible for firetube
boilers.
         Apparent increases in NOX are  indicated by  limited test data and need confirmation.
         Such increases could be due to higher oxygen  levels at reduced loads relative to oxygen

         levels at design load.
                                                                                                   (Continued)

-------
            FABLE  4-12.     (CONTINUED)
Control
Technique
Reduced Load






Type of
Fuel Fired
Residual Oil
Distillate Oil





Stage of
Development
Available now as a retrofit
application. Better imple-
mentation with improved
firebox design.



Secondary
Waste Costs
None Not Available






Limitations and Comments
Technique not effective when
it necessitates an increase
in excess 02 levels, RL is
possible to implement in new
designs as reduced combustion
intensity (enlarged furnace
plan area).
              Low  NO   Burners
Natural Gas       Technique available.   How-
                  ever,  retrofit application
                  is  not feasible due to
                  initial low load factor  of
                  industrial units.

Pulverized        Development stage  prototypes
Coal              are available from major
                  boiler manufacturers.
                                                                                     None
                                                                                     None
                                                                                                            Not Available
                                                                                                    Capital:   S800 to S940/HW of heat
                                                                                                                   input
                                                                                                    Operating: 80 to 85 mills/103 kg
                                                                                                                   steam
ro
ro
01
                                Residual Oil      Commercially offered but
                                Distillate Oil    not demonstrated.
                                Natural Gas
                                Pulverized
                                Coal
                                                  Commercially offered but
                                                  not demonstrated.
                 Commercially offered  but
                 not demonstrated.
                                                                                    None
                                                                                    None
                                                                                  Ammom urn
                                                                                  Bisulfate
                                                                    Capital.    S860 to S5150/MW  of  heat
                                                                                   input
                                                                    Operating:  123 to 376  mills/10J kg
                                                                                   steam
                                                                    Capital-    S860 to  S1070/MW  of  heat
                                                                                   input          ,
                                                                    Operating:  106 to  117  mills/10   kg
                                                                                   steam
                                                                    Capital:    S4800/MW  of  beat  input
                                                                    Operating:  247  mills/103  kg  steam
Residual  Oil
Distillate Oil
                                                 Commercially offered  but
                                                 not demonstrated.
Ammom urn
Bisulfate
Capital:    S4940 to S9770/MW of
                heat input
Operating  266 to 433 mills/103  kg
                of steam

Not available for natural gas
                                                           Least effective on firetube
                                                           boilers because of lower
                                                           combustion intensity.  Appli-
                                                           cable for new watertube units
                                                           with increased firebox size.

                                                           Low NOX burners could maintain
                                                           the furnace in an oxidizing
                                                           environment to minimize slag-
                                                           ging and reduce the potential
                                                           for furnace corrosion.  More
                                                           complete carbon utilization
                                                           results because of better coal/
                                                           air mixing in the furnace.
                                                           Lower 02 requirements may be
                                                           obtained with all the combus-
                                                           tion air admitted through the
                                                           burners.

                                                           Specific emissions data from
                                                           oil fired industrial  boilers
                                                           equipped with LNB are lacking.
                                                          Specific emissions data from
                                                          gas fired industrial  boilers
                                                          equipped with LNB are lacking.
Limited by furnace geometry.
Performance is  sensitive  to
flue gas temperature  and
residence time  at optimum
temperatures.   By-product
emissions such  as ammonium
bisulfate could cause opera-
tional  problems.

Some increased maintenance
of air heater/economizer
parts might be necessary
when burning high sulfur oil.
Technique is very costly.
Should have fewer problems
when firing natural gas.
                                Natural Gas
                                                  Not available.

-------
                                                            Section 4
                                                            Combustion Gases
                                                            N0v Control
                                                              A

intensity increases.   Reduced combustion intensity can  be  brought  about by
load reduction by either derating the boiler or using an enlarged  firebox.
     Low NOV burners  have been developed primarily for  reducing  NO  emissions
           A                                                      A
from utility boilers.   Their principal  characteristics  are reduced flame tur-
bulance, delayed fuel  air mixing, and establishment of  fuel-rich zones  where
combustion initially  takes place.  It is now standard practice  for all  utility
boilers to come equipped with low NO  burners.
                                    X
     The process of injecting ammonia was developed by  Exxon  Research  and
Engineering Company.   This technique acts by reducing NO to elemental  nitro-
gen and oxygen with NhU at flue gas temperatures ranging from approximately
1070 to 1290K.   However, optimal NO reduction  occurs over a  very  narrow
temperature range, around 1240K +50K.
     The cost of combustion modification techniques for controlling NO   emis-
                                                                      A
sions depends upon (1) the additional hardware  required and (2)  any changes
in operational procedures that may increase the cost of steam production.
Cost estimates for combustion modification techniques are  provided in  Table
4-12.  For more detailed information other EPA  studies  should be consulted
(83,84).
     Flue gas treatment techniques have been proposed for  control  of NO
                                                                       A
emissions to levels significantly below those achievable by combustion  modi-
fication 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
4-13.
     Of the processes  listed in Table 4-13, the Selective  Catalytic Reduction
(SCR) system, using ammonia to react with NO ,  is perhaps  the most promising.
                                            X
SCR commercial units  are being applied on many  gas and  oil-fired boilers in
Japan.  Full scale tests of coal-fired boilers  are scheduled  in  mid-1982;
two units are operating and several more are due online.  Considerable

                                     227

-------
                           TABLE  4-13.
                                NOV  FLUE GAS  TREATMENT CONTROL  ALTERNATIVES FOR  BOILERS*
                                   A

Control
Technique
Description
of
Technique
Principle
of
Operation
Efficiency
(% as NOX
Reduction)
Appl
icability
         Selective
         Catalytic
         Reduction (SCR)
         - Fixed Packed
         Bed Reactors
                    Utilizes NH3 to
                    selectively reduce
                    NOX to N2.
                       Reactor  contains
                       ring  shaped  catalyst
                       pellets  packed  in
                       fixed bed.
                           Up to 90%
                   Applicable only
                   to flue gas streams
                   containing particu-
                   late emissions of
                   less than 20 mg/Nm3.
ro
ro
CO
         -  Moving  Bed
         Reactors
- Parallel  Flow
Reactor
         Absorption-
         Oxidation
         SCR -  NOX/SOX
         Removal
                    Utilizes NH3 to
                    selectively reduce
                    NOX to N2.
Utilizes NH3 to
selectively reduce
NOX to N2.
                    Removes  NOX  from
                    flue  gas by  absorb-
                    ing the  NO or NOX
                    into  a solution
                    containing an oxi-
                    dant  which converts
                    the NOX  to a
                    nitrate  salt.

                    Utilizes NH3 to
                    catalytically reduce
                    NOX after SOX is
                    absorbed and reacted
                    with  catalyst.^
Reactor contains
catalyst (rings or
pellets) gravity-fed
mechanically-screened,
and returned to reactor.

Reactor contains a
special catalyst
arrangement (honey-
comb, parallel plate,
or tubes).

Use of gas/liquid
contactors.  Perfo-
rated plate and packed
towers accomplish NOX
absorption by generat-
ing high gas/liquid
ratio.
                      Reactor and catalyst
                      removes both NOX and
                      S02» uniquely designed
                      parallel flow reactor
                      used to avoid parti-
                      culate problems.	
                                                 Up to 90%
Up to 90%
                                                 The relative
                                                 insolubility of
                                                 NO in water will
                                                 prohibit a high
                                                 efficiency.
                           80% NOX reduc-
                           tion, 90% SOX
                           reduction
                           (theoretical).
                   Applicable only to
                   flue gas streams con-
                   taining particulates
                   at less than 1 g/Nm3.
Testing currently
under way for high
particulate (>1 g/Nm3)
flue gas.
                   No published informa-
                   tion available.
                   Should be applicable
                   to high particulate
                   flue gas.
                                                                                                     (Continued)

-------
         TABLE  4-13.   (CONTINUED)
                    Control
                   Technique
                 SCR - Fixed
                 Packed Bed
                 Reactors
                 SCR - Moving
                 Bed Reactors
ro
ro
SCR - Parallel
Flow Reactor
                 Absorption-
                 Oxidation
                 SCR - NOX/SOX
                 Removal
                         Stage  of
                       Development
                          Secondary Wastes
                                                            Costs
                                                                                                          Limitations and Comments
                    Commercially avail-
                    able  only for natural
                    gas-fired boilers at
                    this  time.
                          Spent catalyst
                    Has  been applied in
                    Japan  to several oil-
                    fired  industrial and
                    utility boilers.
Had been applied  in
Japan to several  oil-
fired industrial  and
utility boilers.
Applicability to  coal-
fired boilers cur-
rently being tested
by EPA.

No coal-fired tests
have been made.
                          Spent catalyst
Spent catalyst
                                             N05 salts  in
                                             wastewater
                     20MW estimate:
                       Capital:     $155/kW  (coal)
                                   $84/kW  (oil)
                                   $32/kW  (gas)
                       Operating:   2.5  mills/kWh  (coal)
                                   2.3  mills/kWh  (oil)
                                   1.4  mills/kWh  (gas)
                     20MW estimate:
                       Capital:     $110/kW  (coal)
                                   $84/kW  (oil)
                       Operating:   2.4  mills/kWh  (coal)
                                   2.5  mills/kWh  (oil)
20MW estimate:
  Capital:     $53/kW (coal)
              $46/kW (oil)
  Operating:   1.8 mills/kWh  (coal]
                     20MW estimate
                       Capital:     $597/kW  (coal
                       Operating:   9.6 mills/kWh  (coal)
                   No continuous coal-
                   fired NOX removal
                   test data for NOX/
                   SOX systems are
                   available.
                         Spent catalyst
                     20MW estimates
                       Capital:    $567/kW  (coal  &  oil)
                       Operating:  6 mills/kWh  (coal
                                    &  oi 1)
Although it is possible
to install a hot ESP to
reduce the particulate
level to 20 mg/Nm3, this
is expensive and not always
effective. Thus, fixed bed SCR
systems are not considered
for application to coal-
fired boilers.

Although it is possible
to install a hot ESP to
reduce the particulate
level to 1 g/Nm3, this is
expensive and not always
effective. Thus, moving bed
SCR systems are not con-
sidered for application
to coal-fired boilers.

Greatly reduces particulate
impaction as gas flow is
parallel to catalyst surface.
Unreacted NH^ downstream can
react with S02 or 503 to
form ammonium bisulfate or
the NH3 could enter FGD and
ESP equipment.

The presence of particulates
requires a prescrubber.
The presence of S0£ requires
FGD pretreatment.  Increased
NOX concentration requires
a larger column height and
increased oxidant concentra-
tion.  Nitrate salts formed
as a secondary pollutant.

System is not affected by
changes in the boiler gas
flow rate or particulate
concentrations.  Changes in
NOX concentration because
of boiler load changes may
be compensated for by con-
ventional control system
used with the NH3 injection
equipment.
        (Continued)

-------
       TABLF 4-13.   (CONTINUED)
           Control
          Technique
      Description
          of
       Technique
      Principle
         of
      Operation
  Efficiency
   (%  as  NOX
   Reduction)
   Applicability
ro
CO
o
        Adsorption       Adsorbed NOX  is  reduced
        N0x/S0v          to N2 while S02  is  re-
        Removal           duced and condensed to
                         elemental  S.
        Electron  Beam
        Radiation
        N0x/S0x
        Removal
A dry process that
utilizes an electron
beam to bombard the
flue gas, thereby
removing NOX and SOo-
The adsorption process
removes NOx and S02
from flue gas by
absorbing them onto
a special activated
char.

Flue gas is taken from
the boiler air pre-
heater and passed
through a cold ESP to
remove particulate.
NH3 is added and the
gas is then bombarded
with an electron beam.
                                                     40-60% NOX
                                                     reduction and
                                                     80-95% SOX
                                                     reduction.
Removal effici-
ency will de-
crease as NOX
and S02 increase.
                       May be applicable
                       to handle coal.
By-product  (ammonium
nitrate and ammonium
sulfate powder) treat-
ment technology needs
to be more  fully de-
veloped before commer-
cialization.
        Adsorption-
        Reduction
        NOX/SOX
        Removal
        Oxidation-
        Absorption-
        Reduction
        NOX/SOX
       Oxidation-
       Absorption
Simultaneously removes
NOX and S02 from flue
gas by absorbing them
into a scrubbing
solution.

Simultaneously removes
NOX and S02 from flue
gas by oxidizing NO to
N02 and then absorbing
N02 and S02 into a
scrubbing solution.

Excess 03 is used to
selectively oxidize
NOX to N205.
Based on the use of
Chelating compounds
complexed with iron to
"catalyze" the absorp-
tion of NOX.

Based on the use of gas-
phase oxidants, either
03 or C102, to selec-
tively oxidize NO to
N02.
     formed by oxida-
tion is absorbed into
aqueous solution and
concentrated to form
a 60% HN03 by-product.
60-70% NOX reduc-
tion  and 90% S02
reduction.
90% NOX reduction
and 95% S02 reduc-
tion for oil-fired
tests.
Not available.
Applicable only to
high sulfur coals.
Not applicable to low
sulfur coals.
May be applicable to
handle high particu-
late flue gas.
                                                                                                         (Continued)

-------
         TABLE 4-13.    (CONTINUED)
            Control
           Technique
                      Stage of
                    Development
                        Secondary Wastes
                                 Costs
                                         Limitations and Comments
ro
co
         Adsorption
         NOX/SOX
         Removal
         Electron  Beam
         •Radiation
         NOx/SOx
         Removal
Adsorption-
Reduction
NOX/SOX
Removal
        Oxidation-
        Absorption-
        Reduction
        NOX/SOX
        Oxidation-
        Absorption
                 Presently in the
                 prototype unit stage
                 of development.
                 No coal-fired tests
                 have been performed
                 at this  time.
Preliminary testing
stage of development.
                 Prototype  stage  of
                 development.   No
                 coal-fired flue  gas
                 tests  have been  per-
                 formed at  this time.

                 One  coal-fired test
                 has  been performed
                 with no published
                 information.
                        Ash  for  disposal
                       Ammonium nitrates
                       and sulfates
Sulfate and
nitrate  salts
and gypsum
                       N05 or N-S salts
                       or NH3 based com-
                       pounds in waste-
                       water
                       N0§ salts in
                       wastewater gypsum
                    20MW estimates:
                      Capital:     $257/kW (coal)
                      Operating:  2.7 mills/kWh (coal)
                    20MW estimates:
                      Capital:    $241/kW (coal)
                      Operating:   N/A (coal)
20I1W estimates:
  Capital:     $493/kW (coal)
              $223/kW (oil)
  Operating:   8.8 mills/kWh  (coal
              6.4 mills/kWh  (oil)

20MW estimates:
  Capital:     $278/kW (oil)
  Operating:   7.6 mills/kWh
                    Not available
Very complex process.  Numerous
process steps involve hot
solids handling with numerous
mechanical problems possible.

N0x/S02 removal will drop off
drastically at low radiation
doses based on oil-fired pilot
tests.  Sulfate and nitrate
salts as well as other ionic
species formed as by-products.

Requires large absorbers with
high liquid rates.  Absorbing
solution is highly corrosive;
and sulfate and nitrate salts
formed as secondary pollutants.

Costly gas-phase oxidants
create secondary wastewater
pollution problems.  The use
of C102 introduces a chloride
pollutant problem.

Production of nitrate salts
poses a potential secondary
pollution problem.  Corrosion
problems.

-------
Section 4
Combustion Gases
NO  Control
  X
advances have been made; however, some significant technical and economic
questions must be answered before widespread application of SCR units can
occur.
                                     232

-------
                                                          Section 4
                                                          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 characteristics; the concentration and volume of the parti-
culate to be handled; the temperature and humidity of the gaseous medium;
and most importantly the collection efficiency required.
     There are four basic types of particulate collection equipment:  (1)
cyclones, (2) fabric filters/baghouses, (3) venturi scrubbers, and (4) electro-
static precipitators.  The key features and unit costs of these collection
devices are presented in Table 4-14.
     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 -
                    3
approximately $212/m  per minute.
     Baghouses have very high particulate removal efficiencies and lend
themselves to applications involving small or intermittent gas flows.  Bag-
houses, however, have high pressure drops (in comparison with electrostatic
precipitators) and cannot ordinarily handle wet gases, gases containing oily
materials, or gases having temperatures in excess of 573K.  The unit installed
cost for a typical  baghouse is about $300/m  per minute.

     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 parti-
cles are collected in dry form, venturi scrubbers generate a wet slurry
which is more voluminous and generally more difficult to dispose of.  Unit
                                                              •3
installed costs for venturi scrubbers are approximately $250/m  per minute.
                                     233

-------
TABLE 4-14.   KEY FEATURES OF PARTICULATE COLLECTION EQUIPMENT
Control
Device Operating Principle
High Parti culates removed from gas
Efficiency stream by imparting a centri-
Cyclone fugal force. The inertia of
to the walls where they fall
to the bottom of the cyclone
for removal .
Fabric Filter Fabric filter material is
(Baghouse) arranged in a tubular shape
with the particulate laden gas
stream passing through the
filter. Particulate removal
primarily results from the
buildup of collected material
on the dirty-air side of the
filter. The filter is per-
iodically cleaned by mech-
anical shaking or a pressur-
ized reverse air flow.
ro
^ Venturi Removal of particulates from
Scrubber a gas stream by intimate con-
tact with multiple jet streams
of scrubbing water and drop-
lets. Agglomerated particu-
lates are subsequently removed
in a centrifugal and/or mist
el imi nator


Electrostatic A negative electrical charge
Precipitator is imparted to the particu-
lates and they are collected
on positively charged plates.
Collected material is removed
by periodically rapping or
vibrating the collection
plates .


Removal Loading
Efficiency Range Limitation
(weight -) (g/Nm3)
50 to 80= for >5 _m. >2.4
80 to 95 for 5 to
20 urn.



98.5 to 99.5. for >0.24
0.25 to 0.5 ,m.
99 to 99.5: for
0.75 to 1 jn.
99.5 to 99.9' for
3 Lm.
99.95i for 3 urn.






50 to 92.5- for >0.5
0.25 .m.
60 to 98'- for
0.5 jn.
70 to 99', for
0.75 urn.
90 to 99.6?, for
3 um.


95 to 99'; for 0.24
0.1 LIU.
90 to 96'- for
0.5 jin.
95 to 99v for
1 utn.
99 to 99.9', for
5 jin.


Pressure
Drop Range Reliability
(cm FLO) or Other Limitations
7 to 20 Cannot effectively remove
parti culates smaller than



5 to 25 Plugging problems will
result if condensation
occurs on filter media or
if hygroscooic-matenal is
collected. Temperture
limit varies with type of
filter media used, maximum
is 560 K.





13 to 250 Reliability may be limited
by scaling, fouling, or
corrosion. Scrubbing
liquor blowdown may require
treatment or contain poten-
tially valuable material
not directly recoverable.



0.5 to 2 5 Not applicable to combus-
tible or potentially
explosive mixtures. Par-
ticulates to be collected
must have suitable elec-
trical resistivity to
facilitate efficient re-
moval. Used in low pres-
to gas streams with temper-
atures below 700 K.
Secondary
Waste
Collected
particulates



Collected
particulates










Scrubbing
liquor blow-
down and
wet slurry






Collected
particulates






Installed
Costs
About $212/m3/min
for total in-
stalled system.



About S282/m3/m1n
for total system.










About S250/m3/min
(increasing cost
with increasing
removal effici-
ency).





About $250 to
S530/m3/min
(increasing cost
with increasing
removal efficiency).





General Comments
High reliability due to
simple operating prin-
ciple with no moving
parts . Low energy
requi rements .


High particulate removal
efficiency. High instal-
lation cost. Large scale
requl red.









High particulate removal
efficiency. Capable of
treating streams with
wide ranges in tempera-
ture (no limitation for
high temperatures),
pressure , and gas compo-
sition. High efficiencies
require high energy con-
sumption.
High particulate removal
efficiency, especially
the sub-micron range.
High capital and instal-
lation cost. Very low
pressure drop. Suitable
for high temperature or
large volume applications
High electrical consump-
tion. Sensitive to parti-
culate resistivity.

-------
                                                         Section 4
                                                         Combustion Gases
                                                         Particulate Removal
     Electrostatic precipitators are high efficiency participate removal
devices, have low pressure drops, are capable of handling large volumes of
gases, and can tolerate high feed gas temperatures.   Electrostatic precipi-
tators, however, are not generally suitable for applications to gases above
atmospheric pressure and are not economical for treating small  or intermittent
gas flows (such as those resulting from material handling dust  collection
systems).  Unit installed costs range from $250 to $530/m  per  minute.
                                     235

-------
Section 4
Combustion Gases
S02 Removal
    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, and (2) regenerable systems which produce a usable sulfur by-
product and regenerate the sorbent.  Common examples of throwaway systems
are  the lime/limestone system, dry scrubbing, double alkali scrubbing, fly
ash  alkalinity scrubbing, and Chiyoda Thoroughbred 121.  Typical examples
of regenerable systems are the Wellman-Lord and magnesium oxide processes.
Key  features of some of these scrubbing systems are presented 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 resulting from  slurry treatment is dis-
posed of.   Scrubbing solution is recovered and recycled to the  absorption
tower.  S02 removal  efficiencies can  approach 90% by carefully  balancing the
many chemical  reaction parameters involved in the lime/limestone FGD  process.
Of the throwaway FGD systems available,  lime/limestone offers  the least com-
plex 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/ limes tone FGD systems.
     Of all the commercially available regenerable FGD systems, Wellman-Lord
is the most extensively used.  A venturi prescrubber often precedes 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 sodium sulfite solution to produce primarily  sodium bisulfite.  This
bisulfite-rich solution is then pumped to a forced-circulation  vacuum
                                     236

-------
                                                 TABLE  4-15.    KEY  FEATURES  OF  S02   REMOVAL   PROCESSES
          Feature
      Lime/Limestone
        Scrubbing
                                                    Double Alkali Scrubbing
                                     Chiyoda
                                 Thoroughbred 121
                                                                                                                 Wellman-Lord
                                                                                                                                              Dry Scrubbing
                                                                                                                                               Alkalinity Scrubbing
         Principle
         Feed Stream
         Requirements
ro
                        Liquid  phase absorption
                        of S02  in  lime or lime-
                        stone slurry.
Particulates can be re-
moved in an ESP or
fabric filter to achieve
99*% at lowest energy
consumption.  Fly ash
may be removed in a
venturi  where the fly
ash contains signifi-
cant alkalinity.  A
scrubber can be
used for both high
particulate and SO?
removal.
Liquid phase absorption
of SO? in  a  sodium
hydroxide, sodium sulfite,
sodium bisulfite, sodium
sulfate,and  sodium  carbon-
ate solution.   Regenera-
tion of the  sodium  sul-
fite/bisulfite  with  lime
in a reactor.   A dilute
mode can be  used for con-
centrations  of  200-1500
ppm SO? and  where less
than 252 oxidation of sul-
fite to sulfate occurs.
Concentrated mode can be
used for concentrations
of 1000-8000 ppm S02.

Excessive  particulates
should be  removed in an
ESP, fabric  filter  or
venturi.  02 should  be
less than  7% for con-
centrated  mode.
                                                         Liquid absorption of  SOp
                                                         in a  single  vessel,
                                                         where limestone  addition
                                                         and dissolution, air  oxi-
                                                         dation, and gypsum preci-
                                                         pitation  occur.
Particulates and chlorides
should be removed from in-
let flue gas if byproduct
gypsum is to be sold.
                             Liquid phase absorption
                             of  SO? in a sodium bi-
                             sulfite, sodium sulfite,
                             and sodium carbonate
                             solution.  A rich S02
                             is  produced by evapora-
                             tion, which is then pro-
                             cessed in a Claus unit
                             to  produce elemental
                             sulfur or in a sulfuric
                             acid plant.
Particulates and chlo-
rides must be removed
from flue gas.
                           Process involves the use
                           of a spray dryer which
                           contacts the flue gas
                           with an aqueous alkaline
                           material and produces a
                           dry product.  System
                           involves two stages:  1st
                           stage-spray dryer; 2nd
                           stage-dry particulate
                           collector which removes
                           flue ash and reaction
                           product fron flue gas.
Inlet S02 concentration
should not exceed 1000
ppmv.
                            Process involves  a  two
                            stage venturi-spray tower
                            absorber utilizing  the
                            fly ash alkalinity  for
                            502 removal.   Hydrated
                            dolomitic lime, (Hg(OH>2
                            and Ca(OH)2>  is also used
                            to achieve an outlet S02
                            of 43 ng/J.
Venturi is used to  remove
particulates  and a  portion
of S02-
         Absorbent       Slaked  lime or 200-300
                        mesh  limestone 6-12%
                        slurry  circulated.
         Product/       Gypsum can be produced
         Waste          with forced oxidation.
                       Calcium sulfate/sul-
                       fite can be produced
                       with 50-70% solids.

         Efficiency     90?; removal can be
                       obtained generally for
                       low and high sulfur
                       coals.  Higher removals
                       can be obtained with
                       higher L/6 and pressure
                       drop, and to some extent
                       scrubber type.  90Z and
                       greater can be obtained
                       for low sulfur coals.
                       95% removal for high
                       sulfur coals when adipic
                       acid is used.   Commer-
                       cially demonstrated in
                       over 30 FGD units.
                            Sodium hydroxide, sodium
                            sulfite/bisulfite,  and
                            a  small amount of sodium
                            sulfate.

                            Filter cake with 60-70i
                            solids, primarily calcium
                            sulfite and calcium sul-
                            fate.
                           90-99' removal can be
                           obtained for low and high
                           sulfur coals.  Concentrated
                           mode has been demonstrated
                           at Louisville Gas &
                           Electric's 200 MW coal
                           fired boiler.  Smaller
                           industrial units (General
                           Motors) have been operated
                           in the di1ute mode.
                             Limestone slurry.
                             Gypsum (CaSO^HjO) with
                             less than 20" moisture
                             content.
                            90/V SO^ removal or outlet
                            S02 equal  to 300 ppmv.
                            Process has been demon-
                            strated at Gulf Power's
                            Scholz station - 20MW
                            prototype.
                             Concentrated sodium
                             sulfite/bisulfi te.
                             Concentrated S02 p
                             stream  (90% S02).
                            Process has been demon-
                            strated in a NIPSCO 11 BMW
                            coal  fired boiler.  Can
                            remove up to 95% S02-
                           Lime slurry or sodium
                           carbonate solution.
                           Sodium sulfite-sodiurn
                           sulfate, calcium sulfite/
                           sulfate.
                          70,, 502 removal using
                          lime as absorbent.  80^
                          S02 removal using sodium
                          absorbent.
                            Fly ash alkalinity and
                            hydrated lime (calcium and
                            magnesium hydroxide).
                            Sludge consists of fly ash,
                            gypsum (CaSOa-2H20),
                            Mg(OH>2, small amount of
                            calcium sulfite.
                            85-90% removal of S02
                            commercially demonstrated
                            in Montana Power's Colstrip
                            1 & 2.  96+* expected in
                            Colstrip units 3 & 4.
                                                                                                                                                                             (Continued)

-------
       TABLE  4-15.    (CONTINUED)
Process
Feature
Cost*
Lime/Limestone
Scrubbi ng
Capital - S90/kW to
S185AW.
Chiyoda
Double Alkali Scrubbing Thoroughbred 121
Capital - $101/kW to Capital - 5160/kW.
S163/kW.
Wellman-Lord
Capital - $138/kW to
$265/kW.
Dry Scrubbing
Capital - $23/kW to
$47/kW.
Fly Ash
Alkalinity Scrubbinq
Not available.
PO
CO
cx>
           Advantages
           Disadvantages
Lower capital  cost and
O&M costs.   SO? and
particulates can be
removed simultaneously.
Relatively  simple proc-
ess.  Reliability is
90-95 .

Process  produces approxi-
mately 2 times (by wt)
sludge as ash  collected.
Sludge can  be  thixo-
tropic.   Sludge quanti-
ties can be reduced by
forced oxidation.
Lower capital  and OJM
costs.   S02  can  be
removed to very  high
efficiencies  (99  ).
Reliability  is 90-95 .
Conventional  process
equipment.

Process produces  1.5
times (by wt)  fi1ter
cake as collected ash.
316SS material of con-
struction may  be  re-
quired  to prevent
corrosion and  pitting.
Capital  and  OSM costs
appear to be competitive
but data limited to  pro-
totype experience.   Poten-
tial  saleable gypsum by-
product.
Process  has  not been
demonstrated commercially
in a 100MW or larger  unit.
Commercially demonstrated.
Process produces  saleable
product sulfur with  a
Claus unit or sulfuric
acid.  Lower potential  for
scaling than calcium
system.

High utility costs  (steam)
compared to other systems.
Special metallurgy  may  be
required.   System required
to process S02 to sulfur
or sulfuric acid.
Lower projected
operating and capital
costs.  Dry product.
Process will  not be
commercially  demon-
strated until  late
1982.  Product disposal
could be a problem
when sodium salts are
used as absorbent.
Commercially demonstrated
in 300MW units.   Sludge  con-
tains little calcium sulfite
which improves dewatering
and therefore reduces
settled water content.
Less potential for scaling.

Process is  generally applied
to coal fired boilers which
burn high alkalinity coal.

-------
                                                            Section 4
                                                            Combustion Gases
                                                            S02 Removal

evaporator where it is indirectly heated by steam to convert the bisulfite
to sulfite and gaseous SC^.   A portion of the sodium sulfite is also con-
verted irreversibly to sodium sulfate and thiosulfate which must be purged
from the system, requiring a makeup of NaOH or NaCOo.   The Wellman-Lord
process can achieve over 90% SC^ 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 (79).  The Spray Drying process is the only dry scrubbing pro-
cess currently 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 SCL and the slurry droplets.  Simultaneously,  the
thermal energy of the gas stream evaporates the water in the atomized drop-
lets  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 SC^
as flue gas passes through it.
     FGD costs for boilers in synfuel plants 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
MWe.  The cost variations are principally governed by (1) size of the boiler,
(2) coal used, (3) averaging time over which the plant must meet S02 limita-
tions, 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.  These costs are for a 500 MW  unit boiler burning
3.5% sulfur bituminous coal  capable of achieving 90% removal.
                                     239

-------
Section 4
Boiler Flue Gases
4.1.2.1   Boiler Flue Gases (Stream 302)  - Individual  Stream Control
     Steam requirements for process and electric power generation purposes
for the  K-T based methanol plant are assumed to be met by the boiler coal
feed rate of  25,230  kg/hr  (as received basis).  A material  balance for the
Illinois No.  6  coal  fired  boiler was previously presented in Table 3-26.  The
offgases from the boiler were estimated to have a flow rate of 10,385 kmol/hr
and contain 0.21 and 0.036% by volume of  SOp and N02, respectively.  The
uncontrolled  particulate emissions were estimated to  be 2421 kg/hr.  These
emission rates  were  estimated to increase by 215% for the Fischer-Tropsch
synthesis case  and decrease by 48% for the Mobil-M synthesis case.
     In  this  section,  details of pollution control alternatives applicable
to the 25,230 kg/hr  Illinois No. 6 coal fired boiler  are examined.  However,
it is possible  that  some of the steam requirements of the pulverized coal
fired boiler  may be  offset by the  combustion of dewatered dust from gasifica-
tion.  If dewatered  dust is burned to generate steam, coal  requirements of
the pulverized  coal  fired  boiler for the  K-T based methanol plant will de-
crease by approximately 8900 kg/hr.  Details regarding combustion of dewatered
dust are provided in Section 4.3.   For the purposes of discussion in this
section, the  offset  in steam production from dewatered dust combustion will
be ignored.
     The  control of  NO , S0?, and  particulate emissions  from  the  Illinois  No.
                       A     C-
6 coal fired  boiler  is expected to present no unique  problems  over  those
encountered  in  the electric utility  and  other industries  which use  coal  fired
units.   The  applicability, performance,  and  costs of  these  controls  for  the
pulverized coal fired  boiler are  discussed below.
                                     240

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                                                            Section 4

                                                            Boiler Flue Gases

                                                            NO  Control
                                                              X
NOY Control
  A



     As discussed earlier, NOV control in boilers is achieved through both the
                             A

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



either low NOV burners (LNB) or overfire air (OFA).  Boiler manufacturers have
             A


used LNB or OFA as standard equipment on new boilers since the early 1970's


(85).  Therefore, there are no incremental costs for NO  control  equipment
                                                       A

since no new boilers can be purchased from U.S. manufacturers without these


controls, regardless of whether the boiler is being built in the  U.S. or


abroad.  However, retrofitting NOV control equipment on older boilers does
                                 A

have cost implications.  These costs would be site specific and will also de-


pend upon the type of NOX control technique utilized.  Since new  K-T gasifica-


tion facilities will employ new boiler units, retrofit costs for  NO  controls
                                                                   X

are not discussed in this manual.  However, these costs can be obtained from


several EPA documents (83,84).
                                     241

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Section 4
Boiler Flue Gases
Particulate Removal
Particulate Removal
     Particulate loading in boiler flue gases is a function of many variables
such as the type of coal being fired, the amount of ash in the coal, and the
boiler design.  Typically, 60 to 80% of the feed coal ash is emitted as fly
ash.  For the Illinois No. 6 coal under consideration in this document, the
uncontrolled particulate emission rate for the methanol synthesis case was
estimated to  be 2421 kg/hr.
     Usually electrostatic precipitators or baghouses are used for particu-
late emission control from coal fired boilers.  In utility applications
electrostatic precipitators are more widely used than baghouses at the pre-
sent time.
     The only secondary waste streams from particulate control devices are
the collected particulate from the boiler flue gas (Stream 423).  Typically
99% of  the uncontrolled particulates in"the flue gas stream are collected.
Varying degrees of control  for  trace  elements  are also achieved with partic-
ulate control, depending primarily on the volatility of the individual
elements and on the efficiency of particulate control.  For the size  K-T
based methanol plant under consideration, this waste dust will be  generated
at  a rate of approximately 2400 kg/hr.   In the case of both the ESP  and  bag-
house the collected particulates are dry.  Therefore,  it  is possible  that
fugitive particulate emissions may be generated during transfer and  convey-
ing  from control  device to solid waste  storage.  The control  of fugitive
particulate  emissions during conveying  and transfer  is discussed  in  Section
4.1.6.
     Costs for ESPs depend primarily upon the flue gas particulate loading
and  the flue  gas  flow rate.  To achieve outlet  loadings of  less  than  45  ng/J
for  the base  plant boiler, over  99%  particulate removal  is  desired.   For a
combustion flue gas  flow  rate  of  10,385 kmol/hr,  the  capital  investment  to
achieve outlet particulate  loadings  of  14 ng/J  and 43  ng/J  are estimated to

                                     242

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                                                          Section 4
                                                          Boiler Flue Gases
                                                          Particulate Removal
be $6.1 million and 4.8 million, respectively.  The annualized costs for the
same particulate loadings are estimated to be $1.2 million and $0.9 million,
respectively.  These costs correspond to 0.55 and 0.43% of the base plant
capital investment and 0.35 and 0.27% of the base plant annualized costs.
The limited cost data on ESPs indicate that ESP capital investment costs
vary proportionally with flue gas flow rate provided all other variables
remain the same.
                                    243

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Section 4
Boiler Flue Gases
S02 Removal
S02 Removal
     As discussed previously, a number of competitive FGD processes are cap-
able of achieving similar S02 reductions.  However, lime/limestone and Wellman-
Lord FGD processes are the most widely used S02 control processes in the
industry today.  The costs for these systems vary greatly depending upon the
boiler size, coal sulfur content, and the degree of SO.? removal desired.
     The pulverized coal-fired boiler associated with a K-T based methanol
plant utilizing  Illinois No. 6 coal has approximately 21.95 kmol/hr (0.21%)
of S0? in  the flue gas.  Assuming that 83% S02 removal is desired (outlet
concentration of 370 ppmv), a lime-limestone FGD system will require a
capital investment of approximately $23.3 million with annual operating costs
of about $5.32 million.  Alternatively, it is estimated that a Wellman-Lord
system will  require a capital investment of $22.5 million with annual opera-
ting costs of $4.9 million.  These costs correspond to 2.1% of the base plant
capital investment and 2.7% of the base plant annualized cost for the lime/
limestone  FGD.   In the case of the Wellman-Lord, the costs are 2% of the base
plant  capital  investment  and  2.5%  of  the base plant annualized cost.  Capital
investment and  annual  operating  costs would  increase  by approximately 5% had
90%  SOo  removal  been  the  design  target.
      Sludges and brines are  generated by the  lime/limes tone  and  Wellman-Lord
 FGD  systems.  For the  specific  size  K-T  based methanol  plant under  considera-
 tion,  the  lime/limestone  FGD  system  is estimated  to produce  10,722  kg/hr  of
moist  waste sludge  (Stream 424).   Alternatively,  a Wellman-Lord  FGD  system is
estimated  to produce  550  kg/hr  of  sulfur product  (Stream  426)  and  a  thiosulfate/
 sulfate  by-product  purge  stream (Stream  425)  of  150 kg/hr.
                                      244

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                                                            Section 4
                                                            Heater Flue Gases
4.1.2.2  Process Heater Flue Gases - Individual Stream Control
      Process heaters in a K-T gasification facility are expected to utilize
either offgases or liquid products from synthesis/fractionation operations.
The offgases and liquid fuels are essentially free of sulfur, particulate,
and fuel bound nitrogen.  Therefore, the contribution of process heaters to
sulfur and particulate emissions is minimal.  Any NO  emissions generated
                                                    X
are a function of combustion design, and combustion modification techniques
discussed previusly are applicable.
      Control of NOX emissions from process heaters has been investigated in
recent years.  Initial data indicate that load variation, staged combustion,
and low NOV burners can be used to control  NC"  emissions.  Cost information
          A                                  X
on these techniques is very site-, size-, and fuel-specific.  The number and
size of process heaters for a K-T gasification facility depend upon the
details of process heat requirements.  Since it is beyond the scope of this
document to perform the detailed engineering required to assess these require-
ments, no detailed cost estimation for the control of NO  emissions from
                                                        X
specific process heaters was performed.  However, cost information from
vendors indicates that low NOX burners may cost approximately $0.95/MJ when
applied to process heaters (86).
                                     245

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Section 4
Combustion Gases
Sec. Strms. - Other Media
4.1.2.3  Secondary Streams from Other Media - Fluidized-Bed Boiler Flue Gases
         (Stream 413) - Individual Stream Control                        ~~~
      As discussed in Section 3.3.1, a filtration step has been included in
the  design for  the gas  cooling and dust  removal  process.   In  the  case  of bitu-
minous  coal  gasification,  this filtration step may  be desirable to  reduce
pond area and/or  improve  the  feasibility of dust combustion prior to disposal.
In this  section details of pollution control  alternatives  applicable to the
combustion flue gases  from the fluidized bed  combustion  of dewatered dust  (see
Section  4.3) are  discussed.   The  flow rate of the flue gas from the fluidized-
bed  boiler is estimated to be 7419 kmol/hr.   It  is  estimated  to contain 0.18%
S02  by  volume and 1846  kg/hr  of particulates.  NOX  emissions  are  estimated
to be about  150 ng/J.   The composition of the flue  gas is  presented in Table
4-16.
TABLE 4-16.  COMPOSITION  OF FLUE  GAS FROM THE DEWATERED  DUST-FIRED  FLUIDIZED-
             BED  BOILER (STREAM 413)*

Components
N2f
H20
co2
°2
S09
c.
Ar

Solids*

Flue Gas
mole %
59.5
23.9
12.0
3.7
0.18

0.71
100.0



Composition (Dry Basis)
kg/hr
123,664
31,916
39,278
8,746
838

2,109
206,551
1846
kmol/hr
4415
1773
892
273
13

53
7419

  *Flue gas flow  rates are based upon engineering estimates.
   NOX is approximately  150 ng/J which is equivalent to  56  kg/hr  (as
  ^Before final particulate control.
                                      246

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                                                  Section 4
                                                  Combustion Gases
                                                  Sec. Strms - Other Media
NOX Control
     Almost all the data from fluidized-bed boilers indicates NOX emission
levels of less than 301 ng/J (87).  For a fuel  containing only 36% carbon by
weight (dry), these emissions will be even lower, around 150 ng/J.  Since these
emission levels are relatively low for coal fired boilers, no NOV controls
                                                                A
for the fluidized bed boiler are likely to be used.
Particulate Control
     Particulate matter emitted from the combustion section of a fluidized-
bed boiler consists of fly ash from the coal, unburned carbon, and elutriated
bed material.  A primary cyclone is used to collect larger particles contain-
ing the most significant carbon concentration for circulation back to the
fluidized-bed combustor or to a separate carbon burnup cell.  A secondary
cyclone of higher efficiency can also be used to collect smaller particles
for disposal as ash.  Approximately 90% of the particulate matter is captured
prior to final particulate control.
     Final particulate control after primary and/or secondary cyclones is
performed by use of conventional systems previously discussed in Section
4.1.2.  The systems can consist of electrostatic precipitators, fabric
filters, scrubbers, or cyclones.  They can be operated as hot-side or cold-
side units (upstream or downstream of final heat recovery), except for fabric
filters which must be installed cold-side to prevent excessive fabric deteri-
oration.  Existing fluidized bed units typically use either fabric filters
or electrostatic precipi tenors  (87).
     Costs for particulate control were estimated assuming the particulate
control device used is an electrostatic precipitator.   For 99.7% particulate
removal, the capital investment for the ESP unit was estimated to be $4.4
million for a flow rate of 7419 kmol/hr (refer to Table 4-16).  Annualized
costs were estimated to be $0.9 million.  These costs  correspond to 0.4% of
the base plant capital investment and 0.26% of the base plant annualized cost.
                                     247

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Section 4
Combustion Gases
Sec. Strms. - Other Media
SC>2 Removal
     Sulfur dioxide emissions are a major concern in conventional coal-fired
boilers.  However, by using fluidized-bed technology, SCL emissions can be
reduced by up to 90% or more by direct addition of sorbent into the bed.  The
coal is burned in the presence of lime sorbent.  The S0£ reacts with the
calcium oxide and excess oxygen forming calcium sulfate.  The degree of S02
capture is strongly dependent on the calcium to sulfur molar feed ratio.
Other factors which affect the sulfur capture efficiency of the system are
the reactivity of the sorbent, the particle size of both sorbent and coal,
gas residence time in the bed, the feed mechanism and material distribution
in the bed, and temperature.  These parameters can be adjusted to obtain  the
maximum S02 removal for the system at a particular Ca/S molar feed  ratio.
Past data indicate that an average Ca/S molar feed ratio of between about
 2.5  and  4 will  achieve  a  reduction of  90%  in  S02 emissions, depending  upon
 the  sorbent  reactivity;  however,  higher  ratios may be  needed  if  sorbents  of
 low  reactivity  are  used (87).
      Capital  investment and  annualized costs  for controlling  SOp  emissions
 are  included in  the  costs  of the  fluidized-bed  boiler.   Capital  investment
 and  annualized  costs  for the  fluidized boilers  are  discussed  in  Section 4.3
 Past data  indicate  that the  percent  increase  in  costs  for  fluidized boilers
 capable  of achieving  85% S02  removal  over uncontrolled conventional boilers
 (49  MW.  capacity)  burning 0.9% sulfur  coal  is approximately 5 to  7% (87).
                                      248

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                                                        Section  4
                                                        Org.  and CO Waste  Gas
4.1.3  Organic and CO Containing Haste Gases
     There are two major waste streams which are free of sulfur compounds  but
contain appreciable levels of organics and/or CO:   (1) C02 offgas from SNG
purification (Stream 239) in F-T synthesis; and (2)  Mobil  M-gasoline synthesis
catalyst regeneration/decommissioning offgases (Stream 231).   In addition, an
offgas containing CO may be generated as a result of decommissioning methana-
tion catalyst (Stream 237) in facilities employing F-T synthesis.  In the
event that these waste gases warrant control of organic and/or CO emissions,
controls such as thermal or catalytic incineration may be applicable.  Flaring
is typically employed for small volume, intermittent gases or gases resulting
from upset conditions and would not be appropriate for treatment of SNG
purification offgas or the Mobil catalyst regeneration/decommissioning off-
gases.  Key features of these incineration processes are discussed in Section
4.1.1.
     In an integrated facility, waste gases discussed in this section might
be combined with other waste gases for incineration in a common  incinerator.
However, because of the limited characterization and generation  rate data
for waste gases, cost estimates in this section are presented in terms of
dedicated incineration units.  Therefore, these control costs represent upper
limit costs for control of these streams due to the economy of scale which
might result if waste gases can be combined for incineration.
                                      249

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Section 4
C02 Offgas from SNG Purif.
4.1.3.1  C02 Offgas from SNG Purification (Stream 239) - Individual Stream
         Control
      Facilities employing F-T synthesis with SNG co-production will generate
a CC^-rich offgas  (Stream 239) on a continuous basis as a result of SNG puri-
fication.  This offgas will consist primarily of CCL and would be free of
sulfur compounds   although it may contain appreciable concentrations of
organics and CO.   For purposes of evaluation, the offgas has been estimated
to contain 1% CH^, 0.2% non-methane hydrocarbons, and traces of CO (see Section
3.4.6).  The total flow rate of this stream was  estimated to be approximately
273  kmol/hr.  Control of potential C02 offgas emissions by incineration is
discussed in this  section.
                                      250

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                                                  Section 4
                                                  C02 Offgas from SNG Purif.
                                                  Incineration
Incineration
     The CCL offgas from SNG purification is estimated to contain approxi-
mately 4.3 kmol/hr total hydrocarbons (expressed as ChL).  Thermal incinera-
tion of organic-containing waste gases and liquids is reported to result in
flue gas concentrations ranging from <5 to 70 ppmv total hydrocarbons (ex-
pressed as CHj, and 7 to 89 ppmv CO.  Assuming flue gas concentrations of
30 ppmv total hydrocarbons and 50 ppmv CO, thermal incineration of the C02
offgas using a low Btu supplemental fuel gas would result in emissions of
approximately 0.01 kmol/hr total hydrocarbons (expressed as CH^) and 0.02
kmol/hr CO.  The total capital investment for this thermal incinerator would
be approximately $296,000.  Annualized costs would be $100,000.  These costs
correspond to 0.02 to 0.03% of the base plant capital investment and the
annualized base plant costs.  Similar performance and costs would be asso-
ciated with  the catalytic incineration alternative.
                                     251

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Section 4
Regen/Decom Offgases
4.1.3.2  Regeneration/Decommissioning Offgases (Streams 231  and 237)  -
         Individual Stream ControT
     There are two sources of offgases resulting from catalyst regeneration
and/or decommissioning.  Facilities employing Mobil  M-gasoline synthesis will
generate an offgas from regeneration/decommissioning of the  synthesis catalyst
(Stream 231), while facilities employing F-T synthesis with  SNG co-production
may generate an offgas when decommissioning the methanation  catalyst (Stream
237).  The Mobil M-gasoline synthesis catalyst requires periodic regeneration
for coke removal.  For the subject facility, it has  been estimated that re-
generation will occur over a period of 3800 hours per year,  and offgases will
be generated at an average rate of 200 kmol/hr.  This offgas is likely to con-
tain hydrocarbons and/or CO.  Methanation catalysts  are not typically regen-
erated but, because they tend to be pyrophoric in the active state, they are
oxidized during decommissioning.  No data which enable the estimation of
methanation catalyst decommissioning offgas flow rates or characteristics
are available.
     Control of potential Mobil M-gasoline catalyst  regeneration/decommission-
ing offgas emissions by incineration is discussed in this section.  Control of
offgases from methanation catalyst decommissioning will not be addressed due
to data limitations.  However, in principle, control of organic/CO emissions
associated with methanation catalyst decommissioning could be achieved by
thermal or catalytic incineration or by flaring.
                                      252

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                                                       Section  4
                                                       Regen/Decom Offgases
                                                       Incineration
Incineration
     Thermal incineration of organic-containing waste gases and liquids is
reported to result in flue gas concentrations ranging from <5 to 70 ppmv
total hydrocarbons (expressed as CH^)  and 7 to 89 ppmv CO.  Although char-
acterization data are not available for offgas from Mobil  M-gasoline synthe-
sis catalyst regeneration, hydrocarbons and/or CO may be present in the in-
cinerator feed gas due to the offgas composition or the fuel  gas composition.
Assuming fuel gas concentrations of 30 ppmv total hydrocarbons and 50 ppmv
CO, thermal incineration of the Mobil M-gasoline synthesis catalyst regen-
eration/decommissioning offgas would result in emissions of approximately
0.01 kmol/hr total hydrocarbons and 0.02 kmol/hr CO.  These estimates are
based upon the assumptions that the offgas would not have significant heat-
ing value and that a low Btu fuel gas would be employed as supplemental fuel.
The capital investment for this thermal incinerator would be approximately
$289,000.  The annualized costs would be $90,000.  These costs correspond to
0.02% to 0.03% of the base plant capital investment and the annualized base
plant costs, respectively.  Similar performance and costs would be associated
with the catalytic incineration alternative.
                                    253

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Section 4
Fugitive Dust Material Storage
4.1.4  Fugitive Dust from Material  Storage (Stream 200)
     Open or partially enclosed storage piles are often  used for storage of
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 reclaimed 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 is emitted by
coal and solid waste storage piles.  The techniques used to control  these
emissions are not unique to liquefaction plants  and are  widely used in in-
dustries that require large scale material storage.  The most commonly used
techniques are vegetative stabilization, chemical stabilization, capping,
stacked segregation, water spraying, and confinement. Surface protection
methods such as vegetative stabilization, chemical stabilization, capping,
and stacked segreation are primarily used on reserve storage piles since
these piles are subject to minimal disturbances.  Active storage piles gen-
erally require either water spraying or confinement to control dust emissions.
The  key features and unit costs for these techniques are listed in Table
4-17.
     Vegetative stabilization involves planting an appropriate ground cover
or shrub over the pile to be stabilized.  A soil cap may be required to sup-
port vegetation.  The efficiency of vegetative cover in reducing wind erosion
is dependent on the density and type of vegetation that  can be grown.  For
applications such as stabilizing tailing  piles, the use of vegetative stabi-
lization decreases  emissions  approximately  65%.  When vegetative stabilization

                                      254

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                          TABLE 4-17.   KEY FEATURES OF STORAGE PILE DUST CONTROL TECHNOLOGIES
           Method
   Control  Principle
       Control
    Effectiveness*
       Reliability/
    Special Problems
                                                                                                          Unit  Costs*
    Other
  Pollutants
  Generated
        Vegetative
        Stabilization
Covering pile with  sod.
Approximately 65%
reduction over un-
stabilized pile; and 90%
if chemical  stabilizer
is also used.
IV)
tn
en
        Chemical
Wetting Agents
Modify surface  tension
properties  to improve
effectiveness of water
sprays.
Up to 90% reduction
in dust losses-,*
                         Crusting Agents
                         Organic binders  combine
                         with particles to  form
                         tough crust  on surface.
                           Up to 90% reduction
                           in dust losses.
   Requires frequent         $2.70/m2
   watering.

   Handling of sod during
   reclamation operations
   is cumbersome and
   expensive.

3. Upper layer of stored
   material is contami-
   nated with soil.

1. Piping may require heat   $.33-.77/Mgf
   tracing when freezing
   is a concern.

2. Can cause corrosion
   problems in equipment
   exposed to sprays,

3. May increase material
   degradation*

4. Effects are short-term,

1. May increase chances      $.55-  . 72/m
   of spontaneous com-
   bustion, especially
   in piles  subject to
   stockpile and reclaim
   operations.

2. Crust tends to break
   up during heavy rains.
                                                                                                Soil dust from
                                                                                                earth covering,
Volatiles which
depend on wetting
agent utilized.
                                                                     Volatiles  which
                                                                     depend on  crust-
                                                                     ing agent
                                                                     utilized.
                                                                                                                       (Continued)

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          TABLE 4-17.   (Continued)
Method
Capping
Control
Control Principle Effectiveness*
Paving with earth or Up to 100%c f
asphalt or cover with
polyethylene.
Reliability/
Special Problems
1 . Both coverings may
increase chances of
spontaneous combustion.
2. Polyethylene presents
severe handling prob-
lems and is also not
practical in high wind
climates.
Unit Costs*
$.49/m2 for
asphalt.
$1.96/m2 for
polyethylene.
Other
Pollutants
Generated
Soil dust from
earth covering.
ro
en
        Stacked
        Segregation
        Water
        Spray
       Confinement
 Coating  surface of com-
 pacted storage pile with
 layer of select, medium
 sized material,,
 Spray  application of
 210-250  L/Mg  to  reduce
 dusting.
 No data available<•
 Approximately 50%
 reduction in losses.
Enclosure of active
storage pile in a totally
enclosed barn or silo
with point source dust
control equipment on
building vents.
Up to 99% reduction
in losses.
Either deliveries of differ-  Not  available
ent sized material must be
coordinated or both sizes
must be readily available
from storage.
1. Piping may require heat
   tracing when freezing
   is a concernc
2. May increase degradation*
3. Frequent re-treatment
   necessary.

Requires extreme care
when storing potentially
explosive materials.
                                                                                  Not available
                                                                                  none
                                                                                                                                   none
$110/Mg of
stored material
$1 million to $3
million per silo
depending on
size.
none
        *Cost and control  efficiency  data obtained from Reference 88

        ^Data obtained from Reference 89
        *Data obtained from Reference 90

-------
                                             Section 4
                                             Fugitive Dust Material Storage
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 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
soluble 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, form-
ing a tough durable crust which is resistant to wind and rain.  As long as
the crust remains 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 tarpaulins,
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.   Polyethylene
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 (6.4mm  x 0 mm) on
the top and sides of the coal storage pile can be anchored in  place by a
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.
                                    257

-------
Section 4
Fugitive Dust Material  Storage
     Water  spraying  is another common method of dust suppression.  Dust con-
 trol by water spraying is usually obtained by placing spray nozzles at stra-
 tegic  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 210 to 250 liters/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 proces-
 sing.
     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 to screen
 the material prior to storage, sending the oversize material to open storage
 and the fines to enclosures.
                                     258

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                                                      Section 4
                                                      Fugitive VOC Emissions
                                                      Evaporative Emissions
4.1.5  Fugitive VOC Emissions
     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 by-products and (2) VOC emis-
sions that result from fluid leaks from plant equipment.
Evaporative Emissions
     Evaporative emissions from storage tanks storing volatile liquids result
from temperature changes which cause the vapor pressure of the stored liquid
to vary, causing vapor emissions.  The minimum 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 thermal
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 main-
tenance of pressure vacuum vents, and leak prevention efforts.  Significant
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
eliminating 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.
     Vapor processing units can also be used to control VOC emissions from
fixed roof storage tanks.  Some of the vapor processing techniques available
are carbon adsorption, thermal oxidation,  refrigeration, compression-
                                     259

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Section 4
Fugitive VOC Emissions
Evaporative Emissions
refrigeration-absorption,  and compression-refrigeration-condensation.   Cataly-
tic oxidation is not typically employed in this  application.
     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.   The
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.  Ad-
sorption 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 product 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 re-
generated units condense the VOC-water mixture and return the separated 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  carbon  beds.
     Thermal oxidation units rely upon burning VOC vapors to  produce non-
polluting 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 when the holder reaches a preset level and ends  when the holder
is empty or at the lower preset level.  With no  vapor holder in  the  system,
the oxidizer is energized  by means of pressure in  the vapor line,  or by an
electrical signal produced by manual activation.  In some cases  propane is
injected into the vapor stream to keep the VOC level  above the explosive level.
     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 methylene  chloride "brine" is
                                     260

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                                                       Section 4
                                                       Fugitive VOC Emissions
                                                       Evaporative Emissions.
pumped through the finned tube sections of a heat exchanger.   Brine tempera-
ture in this section ranges from 190K to 210K.   Some units contain a pre-
cooler section (glycol  and water solution circulating at 274K) to remove most
of the water from the gases prior to the main condenser.  There are no com-
pression stages in this type of unit.  The condensed product  is collected and
pumped to one of the product storage tanks.  The cold collection surfaces are
periodically defrosted by pumping warm  (305K)  trichlorethylene through the
condenser.  This defrost fluid is kept warm by  heat salvaged  from the refri-
geration equipment.  Recovered water passes to  a waste storage tank or
gasoline-water separator.  The defrost cycle takes from 15 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 product 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
control 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 product  (277K)  drawn from product storage and absorbed.  The fresh
product stream is used first in the saturator,  then it passes through an
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 when it has emptied or at its lower preset level.
Cleaned gases are vented from the absorber column to the atmosphere.
                                     261

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Section 4
Fugitive VOC Emissions
Fugitive Organic Emissions
     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 a 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%  (91).
     Costs for internal floaters range from approximately $4,000 to $40,000
for  storage tanks with diameters of 5 and 30 m, respectively.  Secondary
seals are estimated to cost $75 per linear meter.
Fugitive Organic Emissions
      There are many potential sources of fugitive organic emissions that
result when process fluid  (either liquid or gaseous) leaks from plant equip-
ment  in a typical gasification/liquefaction synthetic fuel plant.  Some of
these are:  pumps, compressors, 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:
                                      262

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                                                   Section 4
                                                   Fugitive VOC Emissions
                                                   Fugitive Organic Emissions

      1)   leak detection and repair methods and
      2)   equipment specification.
      Leak detection methods include individual component surveys, area (walk-
 through)  surveys, and fixed point monitors.  In an individual component survey
 each  fugitive emission source (pump, valve, compressor, etc.) is checked for
 VOC leakage.  The source may be checked for leakage by visual, audible, olfac-
 tory, 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 hydrocarbon concen-
 tration of the sampled air can be determined.  The leak rate from the source
 can be roughly estimated since relationships exist between monitoring concen-
 trations and mass emission rates.
     An area survey (also known as a walk-through 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 in-
 crease in observed concentration indicates leaking fugitive emission sources.
 The instrument is then used for an individual component survey in the suspected
 leak area.
     Fixed point monitors are automatic hydrocarbon sampling and analysis in-
 struments positioned at various locations in the process unit.  The instruments
may sample the ambient air intermittently or continuously.   Elevated hydro-
carbon 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 hydrocarbon
detector is  also required.
                                     263

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Section 4
Fugitive VOC Emissions
Fugitive Organic Emissions
     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 com-
ponents are listed in Table 4-18.
       TABLE 4-18-  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 seat 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 used are listed in Table
4-19.
     Costs for repair methods will depend upon the complexity of the compon-
ent 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
$815/pump  (installed).  Flush oil systems for double mechanical seals cost
$1500/pump.
                                     264

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              TABLE 4-19.   EQUIPMENT  DESIGN/MODIFICATIONS  FOR  FUGITIVE  HYDROCARBON  EMISSIONS  CONTROL
CTl
CJ1
         Pumps
         Compressors
         Pressure Relief Devices
Open-Ended Valves


In-Line Valves
- improve seal  at the junction of moving shaft and stationary casing
- use seal less  pumps
- use double mechanical seals
- use closed vent systems around seal areas

- improve seal  at the junction of moving shaft and stationary casing
- use double mechanical seals
- use closed vent systems around seal areas

- use rupture disks upstream from the safety/relief valve
- use resilient seal or "o-ring" relief valves
- use closed vent systems to transport valve discharge to control
  devices

- install a cap, plug, flange, or a second valve to the open end of
  the valve

- use diaphram and bellows seal type valves

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Section 4
Fugitive VOC Emissions
Storage Emissions
4.1.5.1   Product/By-Product Storage Emissions
     Various types of vessels are employed to store petrochemical  products.
The suitability of a specific tank design depends on the vapor pressure that
the stored product exerts at ambient conditions and the type of storage
desired.  The floating roof tank is widely used for control  of volatile
organic 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, it was assumed that 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 the addi-
tion 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 a treated rubber.  Its flexibility allows it to maintain contact in places
where the shell might be slightly 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 pri-
mary seal.  Not only do they form a second barrier for the vapor, they also
seal this vapor off from the effects of moving air.  As a result, secondary
seals are effective control devices which, when used on floating roof tanks,
can reduce overall emissions by as much as 98%  (refer to Table 4-20).
     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 pre-
sently employed tank designs, the fixed roof tank is the least expensive to
                                     266

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                                   TABLE 4-20.   STORAGE TANK EMISSION ESTIMATES
CTl
—1
Product
Methanol
Methanol
Methanol
Gasoline
Gasol ine
Diesel
Fuel Oil
Roof Type
Floating
Floating
Floating
Floating
Floating
Fixed
Fixed
Capacity
(m3)
3,200
45,000
46,500
22,000
39,000
3,600
940
Diameter
(m)
18.2
62.5
64
43.6
53.3
19.5
11.6
Synthesis Case
Fischer-Tropsch
Methanol
Mobil M
Fischer-Tropsch
Mobil M
Fischer-Tropsch
Fischer-Tropsch
Assumed
Vapor
Pressure
(KPa)
17.3
8.83
17.3
8.83
17.3
8.83
49.78
33.85
49.78
33.85
0.08
0.046
0.00059
0.0026
Mass Emission
Uncontrolled
(kg/yr)
8,740
6,630
59,790
45,360
61,250
46,470
21,790
20,430
28,950
27,140
800
500
9
5
Rate (kg/yr)*
Control! edt
(kg/yr)
173
125
1226
896
1256
918
1471
1208
1955
1605
39.2
38.8
1.05
0.45
Avg. Control
Efficiency
98.0
98.1
97.9
98.0
97.9
98.0
93.2
94.1
93.2
94.1
95.1
92.2
90
91
      t
Calculations based on  information contained in AP-42 (Reference 76).   The
maximum emissions  (July).  The lower number represents the average  annual
Southwest Illinois.

Floating roof tanks  were assumed to have both primary and secondary seals.
internal floaters  with  closure seals.
                                                                                higher  values represent the month with
                                                                                values.   Location was assumed to be
                                                                                  Fixed  roof  tanks were assumed to have

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Section 4
Fugitive VOC Emissions
Storage Emissions
construct and is generally considered as the minimum acceptable standard for
storage of petroleum liquids.  Fixed roof tank emissions are most readily
controlled by the installation of internal floating roofs.  An internal float-
ing roof tank is essentially a fixed roof tank with a cover floating on the
liquid surface inside the tank which rises and falls with the liquid level.
Calculations indicate that 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 be also used to effect 90%
control.  However, internal  floating roof covers are widely used because of
their simplicity and their low annual operating and capital costs.  Controlled
emissions from fixed roof tanks are listed in Table 4-20.
     Annual costs of applying secondary seals and internal floaters to storage
tanks for the K-T based indirect liquefaction facility being discussed in
this report are listed in Table 4-21.  Secondary seals were assumed to cost
$130 per linear meter (92).  The cost of the aluminum internal  floating roof
cover varies expotentially with the storage tank diameter and ranges from
$5500 for a 5m diameter tank to $49,300 for a 30m diameter tank (92).
     The capital investment and annualized costs for controls on fixed and
floating roof tanks was estimated to be from $25,500 to $69,600 and $5,900
to $10,300, respectively.  However, annualized costs are decreased  consider-
ably because of savings due to product recovered by use of these controls
 (refer  to  Table 4-21).  These costs  correspond to 0.002 to 0.005% of the base
plant capital  investment.  The annualized costs are negligible when compared
to  base  plant  costs.
                                     268

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               TABLE 4-21.  ESTIMATED INCREMENTAL COSTS FOR STORAGE OF SYNTHETIC LIQUIDS*
ro
CTl
Type of
Liquid
Methanol
(3,200 m3)
Methanol
(45,000 m3)
Methanol
(46,500 m3)
Gasoline
(22,000 m3)
Gasoline
(39,000 m3)
Diesel Oil
(3,600 m3)
Fuel Oil
(940 m3)
Synthesis
Case
Fischer-Tropsch
Methanol
Mobil M
Fischer-Tropsch
Mobil M
Fischer-Tropsch
Fischer-Tropsch
Type of
Control
Secondary
seal
Secondary
seal
Secondary
seal
Secondary
seal
Secondary
seal
Internal
floater
Internal
floater
Annual i zed
Control
System Costs
1,900
5,900
6,000
4,200
5,000
5,200
3,500
Annual
Product
Savings
1,800
12,100
12,300
7,000
9,300
150
1
Net
Annual
Cost
100
(6200)f
(6300)t
(2800)t
(4300 )f
5050
3500
Controlled
Emissions
Costs $/kg/hr
0.013
0
0
0
0
8.3
560

        t
250,000 kg/hr (MAF) coal  feed to gasifier basis

Parenthetic cost data represent credits

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Section 4
Fugitive VOC Emissions
Fugitive Organic Emissions
4.1.5.2  Fugitive Organic Emissions from Process Equipment (Stream 241)
     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 replacement of leaking equipment by leak-free equipment.  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 (as suggested in the
VOC leak control techniques guideline document for the petroleum industry) can
be applied (93).  Here,  leak detection is accomplished by checking equipment
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 pre-
determined level would indicate a  leak that would require equipment repair.
Inspection of all equipment has to be performed on a regular basis.
     Controlled emission  estimates for the K-T based indirect  liquefaction
facility under  consideration were  made assuming that the aforementioned
approach was employed.   Emission reductions of approximately 70% were esti-
mated  for the three synthesis cases as shown in Table 4-22.  These estimates
were based on a detection level of 10,000 ppm, weekly inspections of light
liquid pump seals, monthly  inspection of all other equipment,  and open-ended
valves were required to  be  sealed  with a cap plug or another valve.  Capital
investment and  annualized costs were estimated to range from $41,000 to
$145,000 and $251,000 to $102,000, respectively  (refer  to  Table 4-23).   These
                                      270

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                                   TABLE 4-22.   FUGITIVE ORGANIC EMISSIONS FROM PROCESS EQUIPMENT
ro

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"1"
(kg/hr)
0.154
0.029
0.027
0.011
0.00023
0.086
1.28
0.10
0.00025
0.07
Uncontrolled Emission Rates
(kg/hr)
Fischer-
Tropsch
16.74
0.52
34.72
37.02
0.14
24.77
12.8
1.8
1.09
10.94
140.5
Methanol
3.17
0.23
7.78
7.09
0.06
5.16
2.88
--
1.18
2.45
30.0
Mobil M
7.09
0.38
15.39
15.68
0.09
11.35
1.54
--
2.42
4.90
58.8
Controlled Emission
(kg/hr)
Fischer-
Tropsch
0 - 4.19
0 - 0.44.
3.47
9.63
0.14
9.41
0 - 3.84
0-0.86
1.09
6.35
30.1 - 39.4
Methanol
0-0.79
0 - 0.19
0.78
1.84
0.06
1.96
0 - 0.86
--
1.18
1.42
7.2 - 9.1
Rates
Mobil M
0 - 1.77
0-0.32
1.54
4.08
0.09
4.31
0 - 0.46
--
2.42
2.84
15.3 - 17.8
* ~~~ " ~~ — ~~ 	
              Uncontrolled emission factors for pumps and compressors represent emissions  from  each  pump  and compressor and
              not from each pump seal  and compressor seal.

             fThese factors are averages for all sizes of the items indicated.   Data are  not  sufficient at present to allow
              emission rates to be  related to equipment sizes.

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Section 4
Fugitive VOC Emissions
Fugitive Organic Emissions
costs correspond to 0.004 to 0.011% of the base plant capital  investment and
0.007 to 0.025% of the base plant annualized costs.
     The second approach goes a step beyond the first in that it relies on
equipment specification in addition to leak detection,  repair, and main-
tenance.  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 oil  reservoirs seals 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, com-
pressors, and sampling connections  can be completely controlled.
     On applying these specifications to the K-T based indirect liquefaction
facility, an emission reduction of  approximately 80% can be achieved.  The
capital investment and annualized costs for these controls are estimated to
be from $0.3 million to $1.9 million and $0.09 million to $0.75 million,
respectively, as listed in Table 4-23.  These costs correspond to 0.03 to
0.14% of the base plant capital investment and 0.03 to 0.19% of the annualized
base plant cost.
                                     272

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TABLE 4-23.  CAPITAL AND ANNUALIZED COSTS FOR FUGITIVE ORGANIC EMISSION  CONTROLS

Fi scher-Tropsch

Cost Item
Capital
Cost ($)
Annual ized
Cost ($)
Leak Detection,
Repair, and
Maintenance
145,000

102,200


Equipment
Specification
1,876,300

754,200

Methanol
Leak Detection,
Repair, and
Maintenance
41 ,400

24,900


Equipment
Specification
311,900

93,900

Mobi
Leak Detection,
Repair, and
Maintenance
69,700

43,600

1 M

Equipment
Specification
531,400

178,000


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Section 4
Fugitive VOC Emissions
Fugitive Organic Emissions
4.1.6  Fugitive Particulates from Material  Conveying and Processing
      Material transfer and conveying operations are common to nearly all
processing industries.  Equipment includes  belt conveyors, screw conveyors,
bucket elevators, vibrating conveyors, and  pneumatic conveyors.  The type
of conveying equipment varies with the application  and  is determined pri-
marily by the quantity and characteristics  (size, specific gravity, moisture
content, etc.) of the material being handled, the transfer distance and ele-
vation, and the working conditions.  Loss of material from conveyors occurs
primarily at the feeding, transfer, and discharge points due to spillage or
wind.  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 particulates are first confined by
a curtain of moisture droplets.  Then the wetting of dust takes place by con-
tact 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 treated  depending upon the wetting
agent  utilized.
                                     274

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                                                   Section 4
                                                   Fugitive VOC Emissions
                                                   Fugitive Organic Emissions
     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 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.  The type and size of enclosure
depends upon the particulate source.  Data on ductwork velocities needed for
particulate capture for different source types are readily available (94).
Dust collectors that are applicable to the collection of the captured parti-
culate are:  (1) venturi scrubbers, (2) electrostatic precipitators, (3)
fabric filters, and (4) dry centrifugal collectors.   These have been discussed
previously in Section 4.1.2.
                                      275

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Section 4
Aqueous Medium
4.2  AQUEOUS MEDIUM
     A variety of wastewater streams are generated  by a  K-T gasification  facil-
ity.  Individual  streams and their characteristics  are summarized  in  Table
4-24.  The shift condensate (Stream 218) and methanation condensate  (Stream
236) contain only carbon dioxide and, therefore,  probably require  little  or
no treatment prior to being recycled to the plant as  makeup water  or  otherwise
handled.  These two streams are not considered in this section.  All  other
wastewater streams are classified in Table 4-25 as  either streams  of  an  in-
organic or organic source type.  The inorganic streams are further identi-
fied according to the predominating species present:   reduced volatile,
reduced nonvolatile, and oxidized inorganics.
     This section considers the control of only those wastewater streams  that
significantly influence the wastewater treatment approach required for the
entire K-T gasification facility.  In Section 4.2.1,  a summary of  control
technologies potentially applicable to these wastewater streams  is presented.
In Section 4.2.2 and 4.2.3, performances of individual controls  applied to
specific wastewater streams of either the organic or inorganic source type
are discussed.
     The overall control of wastewater  streams generated by a K-T gasifica-
tion facility generally involves more  than one control  process applied to
either  an individual stream or  to a  composite of several streams.   Perfor-
mance and costs of  individual  controls  are most meaningfully assessed in the
context of  integrated trains,  but exact definition of these integrated trains
can be  made only when data specific  to  a  particular  facility are available.
However, certain combinations  of controls are believed  to be likely, and
integrated  control  examples are therefore presented  in  Section 4.2.4 along
with corresponding  performances and  costs.   These combinations are intended
as  examples only and are not to be construed as EPA  recommendations.
                                      276

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           TABLE 4-24.  SUMMARY OF K-T BASE PLANT WASTEWATER STREAMS  AND ESTIMATED CHARACTERISTICS
ro
Flowt
Characteristic* m3/hr CT CN" SCN- S~ S^/SOj
Wastewater Streams from
ROM Coal Storage
Pile Runoff
(Stream 201)
- Methanol Synthesis
- Mobil M Synthesis
- Fisher-Tropsch
Synthesis
Wastewater Streams from
Gas Cooling/Dust
Removal Blowdown
(Stream 210)
Raw Gas Compression
and Cooling Conden-
sate (Stream 211)
Cyanide Wash Water
(Stream 215)
Cyanide Wash
Still Bottoms
(Stream 213)
Shift Condensate
(Stream 218)
Rectisol Condensate/
Still Bottoms
(Stream 220)
Coal Preparation

151 -5
146
174 - -
Gas Purification and Upgrading
322 2111 7 4 1 128
17.4 2200 8.9 14 48.7 6.3
239 - 241 Present 176
0.001 - 10 Present
180 - -
1.2 - 10 -
„ Trace
NH, TDSff COD TOD TSS Elements

Present Present
Present Present
Present Present
156 4000 113 4 Present Present
735 - 124 7
500 111
65-
-
6 5 -
                                                                                           (Continued)

-------
TABLE 4-24.    (Continued)
Flowt Trace
Characteristic* nvVhr CT CN~ SCN" S= S2°3/S03 NH3 TDS COD TOC Tss Elements
Wastewater Streams from
Methanol Distillation
Condensate
(Stream 229)
F-T Wastewater
(Stream 223)
Mobil M Wastewater
(Stream 233)
Methanation
Condensate
(Stream 236)
PO
co Wastewater Streams from
Demineral izer
Regeneration
Wastewater
(Stream 301)
Synthesis of Liquid Fuels
10 - - - 33000 4400
160 - - - - - - Present 12000 4300 Present
110 - - - - - - - 14000 4000
12.9 ----_._.
Additional
18 167 - - - - - 7200 _ - - -
   Boiler Slowdown         2.1
   (Stream 303)
   Cooling Tower Blow-
   down (Stream 307)
   - Methanol Synthesis    161
   - Mobil M Synthesis     180
   - F-T Synthesis         236
400    Present    Present   Present   Present
                                     Present
                                     Present
                                     Present
                                                                                                        (Continued)

-------
       TABLE 4-24.    (Continued)
no
Flowt
Characteristic* m3/hr Cl" CN" SCN" S=
Miscellaneous Waste Streams
Process Equipment -
Cleaning Wastes
(Stream 242)
Boiler Cleaning -
Wastes (Stream 305)
Storm Runoff 47 _.
(Stream 314)
Plant Process Drain 32-42 - - -
(Stream 315)
Wastewater Streams from Air Pollution Control Processes
Wellman-Lord Con- 3
densate (Stream 411 )
Beavon Condensate 4 - . Present
(Stream 405)
SCOT Condensate 4 - - - Present
(Stream 409)
Stretford Solution 2-3 - - Present
Purge (Stream 405)
Flue Gas Desulfuri-
zation Purge
(Stream 425)
- Mobil M case 6.1
- F-T case 37.5 - -
S-O./SO^ NH, TDS# COD
f. J 3 J
Present Present
Present Present
- - - Present
Present
Present - Present Present
Present - Present
Present - Present
Present - Present Present

Present - Present Present
Present - Present Present
Trace
TOC TSS Elements
Present Present Present
Present Present Present
Present Present Present
Present Present Present
Present
-
.
Present

Present Present
Present Present
         *A11  concentrations are mg/L.
         '''For  a  plant with an input to  the  gasifier of 278 mg/hr of dry'Illinois  No.  6  coal.
         ^Present but not readily quantified.
         A dash indicates that this is  not an important constituent/parameter in this stream.
         *TDS  is Total Dissolved Solids; COD  is Chemical Oxygen Demand; TOC  is Total Organic Carbon;  TSS  is Total Suspended
         Solids.

-------
           TABLE 4-25.  CATEGORIZATION OF AQUEOUS WASJE STREAMS IN K-T GASIFICATION FACILITIES
          Source Type
      Stream Name
         Factors Affecting Flow Rate
         	Pollutant Loading
                                                                                                 and
    Inorganic-predominantly
    reduced nonvolatiles
ro
§
     Inorganic-predominantly
     reduced  volatiles
Gas cooling/dust removal
blowdown (Stream 210)
Wellman-Lord condensate
(Claus tail  gas treatment)
(Stream 411)

Stretford solution purge
(Stream 405)

Flue gas desulfurization
purge (Stream 425)

Cyanide wash water
(Stream 215)

Compression condensate
(Stream 211)

Beavon condensate
(Stream 405)
                                SCOT condensate
                                (Stream 409)
Species other than NH3 are believed to be gener-
ally independent of coal type.  Ammonia produc-
tion generally increases with decreasing coal
rank.  TDS and Cl" levels in the circulating
wash water determine the blowdown flow and these
constituents are related to the Cl" and ash
content of the coal.

Flow is design specific but not necessarily
related to coal rank.  Loading is related to
coal sulfur content.

Flow and loading are related to coal sulfur
content.

Flow and loading are related to coal sulfur
content and boiler size.

Flow and loading are qualitatively  similar  for
most coal  types.

Flow and loading are qualitatively  similar  for
most coal  types.

Flow is design specific but not necessarily
related to coal rank.  Loading is related to
coal sulfur content.

Flow is design specific but not necessarily
related to coal rank.  Loading is related to
coal sulfur content.
                                                                                    (Continued)

-------
      TABLE  4-25   (Continued)
            Source Type
      Stream Name
          Factors Affecting Flow Rate and
         	Pollutant Loading
      Inorganic-predominantly
      oxidized species
rv>
oo
     Organic
Cooling tower blowdown
(Stream 307)
                                Coal storage pile runoff
                                (Stream 201)
Demineralizer regenera-
tion wastewater
(Stream 301)

Boiler blowdown
(Stream 303)

Boiler cleaning wastes
(Stream 305)

F-T synthesis condensate
(Stream 223)
Mobil M synthesis conden-
sate (Stream 233)

Methanol distillation
wastewater (Stream 229)
Cooling tower blowdown is not dependent on coal
type.  Flow and loading are related to the
makeup water quality, the amount of wet versus
dry cooling in the base plant, the climatic con-
ditions at the facility, cycles of concentra-
tion, and quantity of inhibitory chemicals added.

Coal type and conditions of wastewater contact
with coal (e.g.,  residence time and temperature).
Rainfall  rates, coal  storage, and washing
practices.

Makeup water flow and characteristics.
Size of the boiler and boiler operating pressure.


Plant operating, maintenance, and boiler clean-
ing practices; boiler size.

Flow and loading are independent of coal type
fed to the gasifier.  Type of organics depend on
the operating conditions and by product recovery.
                                                             Flow and loading are independent of coal type.
                                                             Flow depends on C02 in the synthesis gas.
                                                                                   (Continued)

-------
      TABLE 4-25  (Continued)
             Source Type
      Stream Name
           Factors Affecting Flow Rate and
           	Pollutant Loading	
      Organic (continued)
Rectisol still  bottoms
(Stream 220)

Cyanide wash  still
bottoms (Stream 213)

Process equipment clean-
ing wastes (Stream 242)

Storm runoff  (Stream  314)
Flow and loading are not specific to coal type.
                                                              Flow and  loading are not specific to coal type.
                                                              Waste stream source;  plant operating,  maintenance
                                                              and  equipment cleaning practices.

                                                              Climatic conditions;  housekeeping  and maintenance
                                                              practices.
rvs
00
Plant process drain
(Stream 315)
Total plant water makeup; housekeeping and main-
tenance practices.

-------
                                                               Section 4
                                                               Aqueous Medium
     The following wastewater streams are believed to most directly influence
the overall  wastewater treatment approach taken at a K-T gasification facil-
ity:  the gas cooling/dust removal  blowdown (Stream 210) of the reduced non-
volatile inorganics source type; the cyanide wash water (Stream 215) and the
compression condensate (Stream 211) of the reduced volatile inorganics source
type; and the three synthesis condensates (F-T, Stream 223; Mobil  M, Stream
233; and methanol distillation, Stream 229) of the organic source  types.  The
waste streams containing primarily inorganic contaminants (Streams 210, 211,
and 215) are generally considered unique to K-T indirect liquefaction facil-
ities.  Streams similar to the synthesis condensates (Streams 223, 229, and
233) would be generated regardless of the type of gasifier employed.  The gas
cooling/dust removal  blowdown is a major source of wastewater flow and con-
tains  significant concentrations of ammonia, chloride, TDS, and reduced sul-
fur species other than sulfide.  For base plant designs where cyanide is re-
moved in the gas upgrading section by a water-based wash (see Section 3.3.4),
the cyanide wash water is another major source of wastewater flow.  This
stream contains most of the cyanide that was originally in the gasifier off-
gas and sulfide.  Condensate from the raw gas compression and cooling circuit
is a low flow stream but contains significant loadings of ammonia, chloride,
and cyanides.  The methanol distillation condensate and the F-T and Mobil M
synthesis condensates contain varying loads of organics, typically ketones,
organic acids, and/or methanol.
     All other wastewater streams generated by the K-T gasification facility
should not influence the overall wastewater treatment approach.  Each would
be routed to existing controls designed for other, more heavily loaded waste-
water streams.  These streams would contribute only a small fraction of the
total load and flow such that the performance and economics of individual
controls would be affected only slightly.
     The remaining wastewater streams probably do not influence the facility-
wide wastewater treatment approach, and are generally not unique to K-T
                                     283

-------
Section 4
Aqueous Medium
gasification facilities.  These streams include the Beavon (Stream 405) and
SCOT (Stream 409) condensates of the reduced volatile inorganics source
type; the Wellman-Lord condensate (Stream 411), Stretford solution purge
(Stream 405), and flue gas desulfurization purge (Stream 425) of the reduced
nonvolatile inorganics source type; the cooling tower blowdown (Stream 307),
ROM coal storage pile runoff (Stream 201), demineralizer regeneration waste-
water (Stream 301), boiler blowdown (Stream 303), and boiler cleaning wastes
(Stream 305) of the oxidized inorganics source type; and the process equip-
ment cleaning wastes (Stream 242), storm runoff (Stream 314), and plant pro-
cess drain (Stream 315) of the organic source type.  Certain of these streams
have small flows/loadings and would be routed to existing controls designed
for larger wastewater streams with no significant effect on the performance
or economics of the control.  Others, such as the ROM coal storage pile run-
off or the cooling tower blowdown, have large flows/loadings but have char-
acteristics that are not amenable to treatment by the controls for other
streams.  Streams of this type would probably be handled by separate controls.
None of these streams are unique to K-T gasification facilities, and their
control has been well developed in parallel industries, particularly petro-
leum refining and electric utilities.
                                    284

-------
                                                        Section 4
                                                        Aq.  Med.  Gen.  Control
4.2.1  Water Pollution Control Processes
     This section presents general  information for a variety of water pollu-
tion control processes which are potentially applicable to the treatment,
disposal, and/or reuse of wastewaters from K-T-based gasification plants.
The information presented in this section is derived from industrial  appli-
cations and laboratory tests with various wastewaters.   The water pollution
control technologies discussed do not represent an all-inclusive list of
processes, as others may be available or may be developed.  Rather, these
processes represent control alternatives which have been commercially
applied in analogous applications or have potential for commercial applica-
tion.  Table 4-26 lists the treatment processes which are potentially appli-
cable to wastewaters from the K-T facility and presents summary information
about each.  This section expands on the summary information for some of the
controls.
     The water pollution control processes discussed include techniques  for:
     •  removal of suspended solids, tars, and oils;
     0  removal of bulk organics;
     t  removal of dissolved gases;
     •  removal of dissolved inorganics;
     •  removal of dissolved organics;
     •  removal of residual organics;
     •  volume reduction; and
     •  residual disposal.
A more detailed discussion of each  may be found in the  Control  Technology
Appendices.
                                     285

-------
             TABLE  4-26.
CONTROL PROCESSES POTENTIALLY  APPLICABLE TO THE TREATMENT OF K-T-BASED
GASIFICATION PLANT WASTEWATERS
00
CTi
Technology
Removal of Suspended
Gravity separation
- 'API oil separator
- parallel plate



Coagulation/
flocculation






Air flotation
- dissolved air
- induced air




Fil tration





Technology Principle
Solids, Tars, and Oils
Provision of adequate
residence time in a
stagnant vessel to
allow suspended solids
or immiscible fluids
to separate into
lighter and heavier
than water phases
Use of agents to pro-
mote the coalescence
of fine suspended
solids and adsorption
of tars and oils;
generally used in con-
junction with a gravity
separation process
Use of air bubbles to
promote the disengage-
ment of 1 ighter-than-
water materials from
solution


Passing wastewater
throujii suitable
filter medium; fil-
ter material dis-
carded or cleaned
by backflushing

Components
Removed

Suspended solids,
tars, and oils



Promotes removal
of finely dis-
persed particles





Suspended oils
and solids




Depends on filter
medium; both
coarse and fine
structure mate-
rials are used
industrially

Removal
Efficiency

Depends upon
design, 10-50 i
removal of TSS
typical , 60-991
for oils



Outlet suspended
solids concen-
tration to 10
mg/L possible,
oils removal of
60-95%


Depends on char-
acteristics of
source and treat-
ment process, TSS
removal of 20-75*=,
oil removals of
75-85i
TSS removals of
30-90+',, oil
removals of
65-90:,



Feed
Requirements/
Restrictions

Minimum feed
stream
turbulence



A wide range of
commercial floc-
culants are
available




Air requirements
depend upon waste
characteristics




Filter media





By-Products
and Secondary Estimated
Waste Streams Capital Cost

Recovered oils
(Sp. gr. <1),
sludges/solids
(Sp. gr. ^1)



Same as gravity
separation






Recovered oils,
entrained solids




Filter back- $1700 per m3/hr
wash; spent
filter media




Comments

Incorporated into the
tar/oil separation sys-
tem design in all exist-
ing Lurgi gasffication
plants.



Widely used in water
treatment system to
remove fine solids.





Of limited usefulness
in treating gasifica-
tion plant wastewaters




Proposed for use as pol-
ishing step for phenolic
water downstream of tar/
o: i separation; "Sticky"
tars/oils may cause prob-
lems with filter plugging
and regeneration.
Removal of Bulk Organics
Solvent extraction
- Phenosolvan
- Chem-Pro













Extraction of organics
from wastewater via
contact with an iimis-
cible solvent. Byprod-
uct organic 1 iquids
recovered from the sol-
vent in a separate
regeneration step.








Phenols, TOC,
BOD, COD, other
'












Phenosol van .
- monohydric
ohpnol 99 ^t
- polyhydric
phenol 60'
- organic acids
155,
Chem-Pro
- monohydric
phenol 99.8°;
- dihydric
phenol 95;.
- trihydric
phenol 90-95'.
- other organics
50+
Sensitive to
suspended matter
makeup solvent












Crude phenols,
filter back-
f liter media












Phenosolvan is the process
used in all major Lurgi
•--•••- • *- -* -
Chem-Pro process is com-
mercially applied in phenol
formaldehyde resin manu-
facturing plants. First
application in 1961 to
recover phenol from coke-
oven waste 1 iquor.





                                                                                                      (Continued)

-------
    TABLE 4-26  (Continued)
ro
CO
Technology
Wet air oxidation






Removal of Dissolved
Steam stripping








- Phosam-W



- Chevron WWT


Inert gas stripping





Vacuum distil lation



Selective
absorption



Technology Principle
Direct reaction of 0,,
with wastewater in a
closed, pressurized
vessel at elevated
temperatures


Gases
Increasing temperature
and providing a posi-
tive flow of inert
material (steam)
through the waste-
water; removes vol-
atile organKS and
inorganics with
overhead steam







Same as with steam
except that an inert
gas such as N2, air or
C02 is used as the
stripping medium

Low pressure, low
temperature stripping
process

Used in conjunction
with one of the above
processes to selec-
tively absorb
stripped gases
Components
Removed
Same as biological
oxidation except
better destruction
of cyanides and
other difficult
to treat organics
can be achieved

NH-,, acid gases
(CO,, H2S, HCN),
light hydrocar-
bons (phenols)












Same as for steam
stripping




Same as for steam
stripping


NH, (with acidic
solutions), acid
gases (with basic
solutions)

Removal
Efficiency
90+T removal of
COO is possible
in a system with
a residence time
of 1 hour or
greater


95-99S removal
of "free" ammo-
nia and acid
gases typical ;
hydrocarbon
removal varies
with volati lity
of stripped
components
Removal to:
150 mg/L NH3
1 mg/L HjS , C02.
95* HCN removal
Removal to:
50 mg/L NH3
5 mg/L H?S
Same as for
steam




Same as for
steam


9Q+1 removal of
acid gases or
NH, is typical


Feed
Requirements/
Restrictions
Air or oxygen,
heat if auto-
thermic reaction
conditions are
not present



Feed preheat
can be used to
reduce steam
requirements ;
acid/caustic
for pH adjust-
ment optional









Generally oper-
ates at lower
temperature than
steam stripping
process

Same as for inert
gas stripping


Makeup acid/
caustic



By-Products
and Secondary Estimated
Waste Streams Capital Cost
Vent gases con-
taining CO, CO™
1 ight hydrocar-
bons, NH,, sulfur
species



Stripped gases,
uncondensed steam














Stripped gases,
stripping gas




Stripped gases



Recovered NHj
or acid gases,
rich sorbent


Coninents
Piomising but not proven
in this appl ication,
fairly rigorous materials
of construction
requi r ements



Acid/caus t i c addition can
be used to improve the
efficiency of the strip-
ping process












The presence of an inert
stripping gas as a diluent
may make it more difficult
to handle or further treat
the gases stripped from
the wastewater
High energy requirements;
not cost competitive in a
plant where stripping
steam is readily available.
This is the basis for sev-
eral commercially proven
processes for recovering
high purity aninonia.

                                                                                                               (Continued)

-------
        TABLE 4-26 (Continued)
ro
oo
oo
Technology
Technology Principle
Components Removal
Removed Efficiency
Feed
Requi rements/
Restrictions
By-Products
and Secondary Estimated
Waste Streams Capital Cost
Comments
Removal of Dissolved Inorganics
Ion exchange






Chemical
precipitation






Polysulfide
addition





Activated sludge








Biological
denitrification




See also: chemical
Substitution of H*
Na+, OH-, or Cl- ions
for other ionic species,
exchange resins regen-
erated with acid, base.
or salt solutions


Use of agents to pro-
mote the precipitation
of inorganic solids
from wastewaters




Cyanide converted to
thiocyanate by
polysulfide




Microorganisms mediate
oxidation of ammonia
and thiocyanate






Microorganisms reduce
nitrate to molecular
nitrogen in the pro-
cess of oxidizing
methanol or some other
organic
oxidation, membrane separation
Heavy metal, F-, 90+% removal for
CN", scaling spe- most ions, regen-
cies, NH3 eration frequency
is a key
parameter



Ca, Mg, heavy Varies with waste
metals, stream constitu-
alkalinity ents. Typical
removals:
Cd 2% Ni 50%
Cr 40* Pb 5%
Cu 20% Se 10%
Hg 20% In 25%
CN' Varies






NH3, SCN' 90+% for NH,,
SCN-







NO" 90+3.





, and forced evaporation.
Regenerants ,
replacement
resins





Lime, polymer,
and soda ash
may be required.





Possible chem-
ical require-
ments for pH
control .



Air or oxygen,
supplemental
nutrients may be
required; rela-
tively constant
feed temperature
and pollutant
loadings
required.
Nutrients; con-
stant loading
conditions




Spent regencr- . $5700 per kg
ants and resins, NH3-N per day
treated water





Sludge contam-
inated with
heavy metals





Residual poly- $530 per m3/hr
sulfide;
increased 1%
concentration
due to NH| as
counter ion to
polysulfide
Biological $4400 per
oxidation equivalent kg
sludge NHo-N per day






Biological $2300 per kgN
oxidation per day
sludge




Most effective as a pol-
ishing process. Clearly
applicable to boiler
feedwater treatment needs.
Of limited use in treating
process watewaters contain:
ing high concentrations of
organics or dissolved solids
Generally followed by fil-
tration and/or activated
carbon adsorption.





This process utilized at
petroleum refineries to
control cyanide- induced
scaling. No experience
exists at the wastewater
treatment process level.

•
Used extensively to treat
wastewaters of a wide range
of characteristics and
sources.





Experience exists in both
municipal and industrial
applications.




                                                                                                                 (Continued)

-------
      TABLE 4-26.   (Continued)
ro
oo
Technology
Removal of Dissolved
Biological
oxidation
- act. sludge
- trickling filter
- rotating
biological
contactor
- lagoons
- high purity
oxygen (HPSAS)

Wet air oxidation








Ultrafiltration



Anaerobic digestion







Technology Principle
Organics
Biological conversion of
the carbonaceous organic
matter in wastewater to
cell tissue and various
gaseous end products.






Direct reaction of On
with wastewater in a
closed, pressurized
vessel at elevated
temperatures




Forcing wastewater
through semiperme-
able membrane under
pressure
Reduction of organics
in closed vessel at
moderate temperatures
to form CH^ and other
hydrocarbons, digestion
process relies upon
metabolic processes of
anaerobic organisms
Components
Removed

TOC, BOD, COD,
some inorganic
pollutants








Same as biologi-
cal oxidation
except better
destruction of
cyanides and
other difficult
to treat organics
can be achieved

Most effective
with high molec-
ular weight
organics
TOC, BOD, COD







Removal
Efficiency

Varies with waste
stream character-
istics. Typical
removals:
BOD 60-90=-
COD, TOC 80'-
total phenol 9K
org acids 95',
oil S grease 70*
CN- 70;

Over 90% removal
of COD is possible
in a system with a
residence time of
1 hour or greater.
Actual efficiency
heavily dependent
upon waste char-
acteristics.
Up to 955,
removal for total
organics

Unknown - this
process has not
been applied to
these types of
waste streams



Feed
Requirements/
Restrictions

Air or oxygen,
supplemental
nutrients may be
required; rela-
tively constant
feed temperature
and pollutant
loadings required
to minimize
"shocks" to
system
Air or oxygen;
heat if auto-
thermic reaction
conditions are
not present




Filter media



Some supplemen-
tal nutrients
may be required





By-Products
and Secondary Estimated
Waste Streams Capital Cost

Biological oxi- Activated
dation sludge sludge-
$700 per kg BOO
per day







Vent gases con-
taining CO, CO,,
light hydrocar-
bons, NH-i , sulfur
species




Spent filter
media; concen-
trated
wastewater
Waste gases
(combustible)






Comments

This is the basis for the
treatment of coke oven
wastewaters








Promising but not proven in
this application; fairly
rigorous materials of con-
struction requirements.





May be attractive as a pre-
concentration step prior to
wastewater incineration.

Kinetic limitations and
process control problems
could be substantial .





                                                                                                                 (Continued)

-------
        TABLE 4-26  (Continued)
f\>
<£>
o
Technology
Removal of Residual
Activated carbon
adsorption











Chemical oxidation




Thermal oxidation
( Inc i neratior ^






Cooling tower
oxidation





Volume Reduction
Me- brane separation
- reverse osmosis




- elect rodi a lysis





Technology Principle
Orqanics
Adsorption of orgamcs
in water by activated
carbon or polymeric
resin, powdered acti-
vated carbon has been
used in conjunction
with biological pro-
cesses (above) with
some success in the
organic chemical
industry


Reaction of organics
in wastewater with
ozone, peroxides or
chlorine-based
ox idants
Combustion of orgamcs







ai r oxidation (and
stripping) of orgamcs
and dissolved gases





Use of seiupem.eable
membrane and pressure
to separate water from
its dissolved
constituents

Use of selective
anion- or cation-
permeable membranes
with electric field to
separate mineral ions
from water
Components
Removed

Most effective
with phenols;
some heavy metal
removal expected









TQC, BOD, COD.
oxidi zable
inorganics


All oxidizable
orgamcs






TOC, COD, BOO,
phenols and
other orgamcs,
NH3




Relative rejec-
tion efficiencies
of the various
soluble species
wi 1 1 be deter-
mined by membrane
characteristics
and conditions of
process operation



Removal
Efficiency

Varies with
waste stream
charactenst ics.
Typical removal s :
BOD 60%
COD 80
TOC 70
Phenols 99.9
org acids 70
CfT 50
SCN- 50
tars 99
oils 99
High removals
achievable depend-
ing upon condi-
tions of operation

Essentially com-
plete destruction
of organics in
properly designed
system



Unknown - this
process has been
tested using
5ASOL waste-
waters on a pi lot
scale but results
are not available

90-95 rejection
of dissolved
caits. Reduc-
tions in dis-
solved organics
and BOD of up
to 99-





Feed
Requirements/
Restrictions

Low TSS, pH 6-9;
high TOC loadings
are less amenable
to treatment.









Oxident




Supplemental
fuel , preconcen-
tration wil )
improve perfor-
mance and lower
supplemental
fuel
requi renents
Sensitive to
suspended matter,
oils, high TDS





Membrane











By-Products
and Secondary Estimated
Waste Streams Capital Cost

Spent adsorbent $260 per kg COD
regeneration per day
off -gases










Vent gases, $850 per m^/hr
wastewater, and (Cl2 and lime
reaction basis)
products

Flue gases $300,000 per
m3/hr






Bl owdown/dnft







Spent membrane
material , recov-
ered water.
brine








Comments

Probably more effective as
a polishing rather than a
bulk orgamcs removal
process.









Chlorine-based oxidants
may cause problems with
treated wastewater.


This will be the most
effective process for
removing orgamcs but
the supplemental fuel
requirements may be
substantial .


Treated wastewater use ir
small refinery cooling
towers has be practiced -
75-80 reduction in waste-
water volume is common



May be useful as precon-
centration step prior to
further treatment or ulti-
mate disposal of waste-
water. Membrane scaling
and fouling with organics
may limit the applicability
of this technology to the
treatment of process
condensates.


                                                                                                                  (Continued)

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TABLE 4-26  (Continued)
Technology
Forced evaporation



Cooling tower
concentration



Residual Disposal
Deep well Injection















Surface Impoundment





Co-disposal



Surface discharge
Technology Principle
Thermally induced evap-
oration of excess waste-
water, condensate recov-
ery optional

Wastewater used as
partial makeup to the
cooling tower and
thereby concentrated
into the blowdown.

Wastes are pumped into
subsurface geological
formations where they
are isolated from all
surface and ground-
water supplies










Wastes are held in
a containment basin




Ash is quenched with
wastewater then han-
dled by a solid
waste disposal
technique

Wastes are conveyed to
and mixed with a nat-
Components Removal
Removed Efficiency
All nonvolatile
species will
remain in brine


All nonvolatile
species concen-
trated into the
blowdown


Entire stream IOC'S















All nonvolatile 100%
species remain as
residual in the
impoundment


Entire stream lOCrt



Entire stream 100*
Feed
Requirements/
Restrictions
None



Feed character-
istics limited by
corrosion, seal-.
ing, and biologi-
cal fouling

Injected fluids
must be filtered
to 5 micrometers
and have a low
organic content
to prevent plug-
ging. Wastes
must not precip-
itate in the well
or when mixed
with subsurface
fluids. Volume
reduction prior
to injection is
often
economical .
Concentrations
of volatile
species may need
to be low to pre-
vent loss to the
atmosphere
Concentrations
of volatile
species may need
to be low to pre-
vent loss to the
atmosphere
Restrictions are
site-specific
By-Products
and Secondary Estimated
Waste Streams Capital Cost
Recovered $86,000 per
condensate, non- m^/hr feed
condensible
gases, waste
brine
Evaporation/
drift




None $160,000 per
m3/hr














Loss of $52,000 per
volatile nrVhr
species



Loss of
volatile
species


None
Comments
Very stringent materials
requirements due to
potential corrosion.
Forced evaporation 1s
energy intensive.






Applicability highly site
specific.














Possibly large land
requirements may limit
applicability.



Presence of certain chem-
ical species in the quench
water may yield an ash that
requires handling as a haz-
ardous material .


Assimilative capacity of
receiving body must be
                ural water source
                                                                                                        investigated.

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Section 4
Aq. Med. Gen. Control
Sus. Sol.,  Tars, Oils
4.2.1.1  Processes for Removal of Suspended Solids, Tars, and Oils
     A variety of control processes have been summarized in Table 4-26 that
are applicable to waste  streams having high concentrations of suspended
solids,  tars, and/or oils.  The process or combination of processes selected
for a particular waste stream would depend on the concentration of the con-
taminant species and its physical properties such as size distribution, spe-
cific gravity, and surface  properties.  This section summarizes available
information  for filtration  as an example of a control process for removal of
suspended  solids, tars,  and oils. .
      Filtration is a well-established  technology that finds nearly industry-
wide  application.  The process consists of passing a waste stream by either
gravity  or pressure  through a bed of inert material which physically retains
the  solids suspended in  the flow.   Various materials and combination of
materials  have  been  used for  filter media including sand, anthracite,  acti-
vated carbon, natural/synthetic  fibers, resins, and garnet.   Performance
varies with different  media materials,  and  the material  giving  optimal per-
formance must generally  be  determined  by  direct testing  of the  subject waste
 streams.
      During the course of filtration,  the bed becomes  increasingly loaded
 with suspended solids  resulting  in  a  corresponding increase  in  the hydraulic
 headloss.   At some point, the bed must be backwashed to  return  it to a condi-
 tion approximating its original, unused state.   About 2  to  10%  of the filter
 throughput is needed for backwash,  and this amount is stored during the filter
 run.  Thus, suspended material  contained in the waste stream is concentrated
 by a factor of 10 to 50.
      Suspended solids removal by filtration typically range  from 30 to 70
 percent.  Exact performance can be determined only by testing the waste
 stream  to be treated.
                                      292

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                                                        Section 4
                                                        Aq.  Med. Gen.  Control
                                                        Bulk Organics
4.2.1.2  Processes for Removal  of Bulk Organics
     For waste streams having high organic loadings,  it is  sometimes advan-
tageous to apply a process capable of achieving gross organic removal.
These processes can typically achieve high percentage removals,  but since
the feed stream is heavily loaded, an appreciable concentration  of the  con-
taminant species remains in the effluent.   Other processes  that  are capable
of reducing the contaminants to the low levels possibly required for ultimate
disposal can follow these, if desired.
     Processes for removal of bulk organics are presented in Table 4-26.
These processes are not expected to be generally applied to any of the waste-
water streams generated by a K-T gasification facility.
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Section 4
Aq. Med. Gen. Control
Dissolved Gases
4.2.1.3  Processes for Removal of Dissolved Gases
     Dissolved gases such as HCN, I^S, and NhU can be removed from waste-
waters by several processes.  Some of these processes are summarized in Table
4-26.  Most are designed to handle waste streams having high loadings of dis-
solved gases.  High percentage reductions are possible in such cases, but the
concentration of dissolved gas remaining typically requires additional con-
trols of the waste stream.  Residual levels achievable with techniques such
as  steam or  inert gas stripping  are similar to those already found  in  K-T
gasification wastewaters  (except cyanide wash water).
     In the case of cyanide wash water (Stream 215) which is expected to con-
tain several hundred ppm each of HCN and H^S, stripping with inert gas may
be  applicable.  Potential stripping gases which would probably be available
onsite include waste nitrogen from an air separation plant or waste CC^ from
a selective  Rectisol unit.  The HCN laden offgas could be incinerated or sent
to  a Claus plant for treatment.
                                      294

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                                                       Section 4
                                                       Aq. Med. Gen. Control
                                                       Dissolved  Inorganics
4.2.1.4  Processes for Removal of Dissolved Inorganics
     A variety of processes summarized in Table 4-26 are applicable 'to waste
streams requiring removal of dissolved inorganics.   Processes such as chemical
precipitation, membrane separation, and chemical oxidation are capable of
removing simultaneously a wide variety of inorganic species.   Others are nar-
rowly applicable to one or a few specific species.   These processes include
ion exchange using a clinoptiloli te resin for ammonia removal, polysulfide
addition for cyanide removal, activated sludge for ammonia or thiocyanate
removal, and biological denitrification for nitrate removal.   The removal
mechanisms vary widely between individual processes.  Polysulfide addition,
activated sludge, biological denitrification, and ion exchange using a clino-
ptiloli te resin are presented herein as examples of processes for removal of
dissolved inorganics.
Polysulfide Addition
     Cyanide can be removed from wastewater streams by converting it to thio-
cyanate.  The conversion is prompted by adding a sulfur source as polysulfide,
with only uncomplexed cyanide thereby removed.  The product,  thiocyanate,
would likely need to be removed, but unlike cyanide, it is easily biodegraded.
Recent bench-scale studies have demonstrated that thiocyanate removals exceed-
ing 95% can be made by a biological system where only the thiocyanate plus
ammonia are available as growth substrates.
     Petroleum refiners have for some years used polysulfide  to convert
cyanide to thiocyanate to protect process equipment from cyanide-induced cor-
rosion.  No commercial precedent exists for promoting the reaction at the
wastewater treatment process level, but EPA-sponsored preliminary lab studies
(unpublished) suggested that the cyanide to thiocyanate conversion could be
successfully made if the polysulfide is supplied in large excess of its stoi-
chiometric requirement.  The reaction rate seems to be sufficiently slow to
require large reactor volumes to supply the needed residence  time.

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Section 4
Aq. Med. Gen.  Control
Dissolved Inorganics
     The concentration of cyanide in the influent has  only limited  effect on
the process feasibility.  With increasing influent concentrations of cyanide,
the reaction kinetics become increasingly favorable.   It is the  concentration
of cyanide in the effluent that determines the residence time  and therefore
the feasibility of the reaction.   Preliminary EPA sponsored studies (unpub-
lished) suggest that the process may be impractical for cyanide  removals to
less than about 10 mg/L.
     Polysulfide addition therefore appears usable only for waste streams
where the initial cyanide concentration is greater than about  30 mg/L and some
benefit can be identified in reducing this concentration to about the 10 mg/1
level.  Since additional cyanide removal by some other process would probably
be required, the feasibility of polysulfide addition would be  determined by
the economic tradeoffs between it being used in combination with some other
process versus the other process being used alone.
Activated Sludge

     Certain dissolved inorganics, particularly ammonia and thiocyanate, can
be biologically oxidized even in systems where these species are the only
growth substrates available for microorganisms.  Most of the contaminants are
oxidized to supply energies for metabolism while the rest are assimilated as
new cell material.  Microorganisms may be viewed as catalysts that mediate
the oxidation of material that would otherwise oxidize very slowly or not at
all.
     A variety of physical  configurations can be used to provide contact be-
tween  the microorganisms and the contaminants to be removed, but suspended
growth or activated sludge  systems are  perhaps most common.  The cells are
dispersed throughout  a  reactor volume where  they contact the incoming waste
stream on a continuous  basis.  Long enough  residence time  is provided for  the
microorganisms to degrade the contaminants  to an acceptable level.    Effluent
                                     296

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                                                       Section 4
                                                       Aq. Med. Gen. Control
                                                       Dissolved Inorganics
from the reactor is routed to a clarifier where the suspended cells are
separated from the bulk fluid.  Concentrated cells are drawn from the under-
flow of the clarifier, and a fraction are wasted equal to their increase in
mass resulting from cell growth in the reactor.  The rest, constituting the
much larger fraction, are recycled to the reactor.  By this process of cell
wastage and recycle, a constant.mass of cells can be maintained in the reactor
for a controlled period longer than the hydraulic residence time.  The period
selected is one that is in phase with the optimal life cycle of the cells.
The cell residence time is therefore the key process variable as it controls
both the overall system performance and stability.
     Activated  sludge  processes designed to  oxidize ammonia to  nitrate are
well established in  both  industrial and municipal applications.  Ammonia
destruction at  the  98% level  are  reportedly  possible.  Recent bench-scale
studies  have  indicated greater than 95% oxidation of  thiocyanate and
ammonia  for biological  systems  fed a waste stream containing only  these two
species.  This  is  especially  significant since  K-T gasification wastewaters
consist  primarily  of cyanides,  thiocyanate,  ammonia,  and more readily  oxidiz-
able species  such  as S~,  SO^, and S203-
     As  is the  case  for all  processes utilizing the growth  reactions of
microorganisms, activated sludge  processes are  subject to upsets when  the
characteristics of  the feed  stream vary beyond  certain limits.   However,
activated sludge processes designed to remove  ammonia and thiocyanate  may
be  especially prone  to upset.   In general, most organics that are  biodegrad-
able can be oxidized by a wide variety of microbial species  in  an  activated
sludge  system.  Each specie has its  particular  range of conditions to which
it  is tolerant, and  the individual ranges overlap, forming  a much  wider
spectrum of tolerance than that represented by  any one specie.  However,
ammonia  and thiocyanate are  oxidized by only a  very few, specialized micro-
organisms.  A narrow range of tolerable conditions is represented  by these
few species,  and when  conditions  fall outside  this range, the system fails.
                                    297

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Section 4
Aq. Med. Gen. Control
Dissolved Inorganics
     Another problem potentially affecting reliability is associated with
operation of the clarifier.  Conditions that lead to malfunction of the
clarifier are not fully understood.   However, where there is relatively con-
stant feed and where the system is otherwise carefully operated, activated
sludge should be a reliable process.
Biological Dentrification
     In dentrification, nitrate is removed by being reduced to molecular
nitrogen which can be vented directly to the atmosphere.   Physically the
system resembles that of activated sludge, but the removal mechanism is some-
what different.  When oxygen is not available, most microorganisms can sub-
stitute nitrate as the terminal electron acceptor in their growth and energy
reactions.  Nitrate is thereby reduced to molecular nitrogen in the denitri-
fication reactor not by being acted on directly but by participating in the
oxidation of some other organic substrate.  If not otherwise available, a
substrate (or carbon source) must be supplied, and methanol is a common
choice.  Other organic-laden wastes may be used as the carbon source to
advantage in a K-T facility.
     While less experience exists for denitrification than for activated
sludge systems, the process is considered well developed.  Nitrate removals
of up to 90% are reported  in the open literature.
     Denitrification is usually a reliable process due largely to the diverse
population of microorganisms that are cultured in the reactor.  Most reli-
ability problems relate to settleability of biosolids to  shock loadings, or
to very cold weather.
Ion  Exchange
     Ion exchange  involves a reversible interchange of ions in solution with
other ionic species bound  to a solid ion exchange medium.  Clinoptilolite  is
a naturally occurring  ion  exchange  material that will selectively exchange

                                    298

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                                                        Section  4
                                                        Aq.  Med. Gen.  Control
                                                        Dissolved  Inorganics
its bound sodium or calcium ions for ammonium ions  in  the contacting  solution.
Upon initial loading of fresh clinoptilolite, nearly all  ammonia  is  removed
from the waste stream.  With time, fewer exchange sites are available and
increasingly less ammonia can be removed.   When the concentration of  ammonia
escaping the process increases to an unacceptable level,  the resin is replaced
and regenerated for reuse by contacting it with a strong  brine  solution.
Ammonia rich brine from regeneration is air stripped in a closed  loop system.
The stripper off-gas is scrubbed by an acid wash to recover the nitrogen as
ammonium sulfate before the stripping gas  is recycled.
     Several complete ammonia removal/recovery systems  are in operation for
municipal-strength wastewaters.   One is a  system that has been  operated suc-
cessfully by the Tahoe-Truckee Sanitation  Agency.   No  major problems  have
reportedly occurred with either the ion exchange units  or the regeneration/
ammonia recovery units.  No known precedent exists  for higher strength waste
streams.  Preliminary lab studies sponsored by EPA  suggest that ion exchange
would be a feasible process for treating waste streams  having ammonia concen-
trations much higher than that normally associated  with municipal  wastewaters.
It is expected that ammonia can be removed to the 1 mg/1  level  or less from
a waste stream containing ammonia at the 100 to 200 mg/1  level.
                                    299

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 Section 4
 Aq. Med. Gen. Control
 Dissolved Organics
4.2.1.5  Processes for Removal of Dissolved Organics
     A variety of control processes are applicable to wastewater streams
requiring removal of dissolved organics.   Activated sludge  is  a  commonly
used process and is presented as an example in this section.
     An activated sludge system designed to remove organics  is identical  in
principal to that discussed for removal of inorganic  species  (refer to Sec-
tion 4.2.1.4).  Most biodegradable organics can be oxidized  by a-variety  of
microbial species.  Performance varies widely depending on  the characteristics
of the wastewater stream, but BOD removals of 80 to 90% or  better are typical.
Nitrogen and phosphorous in forms usable by the microorganisms are required  as
growth nutrients, and these elements are assimilated  as new  cell  material.
     Microorganisms that utilize organic substrates can sometimes oxidize or
otherwise remove a variety of inorganic species concurrently.   Even some
species such as cyanide that are normally nondegradable can  be oxidized.
Cyanide removals exceeding 90% have been reported in  laboratory-scale tests.
     The exact performance of an activated sludge system can  be  determined
with certainty only following bench-scale or pilot testing  of the subject
wastewater stream.  Removal of most inorganic species usually cannot be
assessed accurately until after the system is in place.
                                      300

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                                                        Section 4
                                                        Aq. Med. Gen. Control
                                                        Residual Organics
4.2.1.6  Processes for Removal  of Residual  Organics
     Residual  organics occur in wastewater streams due largely to performance
limitations of upstream controls.  When a biological  system is the upstream
control, residual  organics consist of biodegradable material  and a larger
fraction of refractory organics that are resistant to biological oxidation.
Activated carbon,  chemical oxidation, and thermal  oxidation are presented
herein as examples of processes that can remove residual  organics.  Most of
these systems can  also remove residual inorganic species.
Activated Carbon Adsorption
     Activated carbon adsorption is a widely used  method  of removing residual
organics from industrial  wastewaters.  This technology may be applied by one
of two methods:  1)  the use of powdered activated carbon in conjunction with
biological  treatment or 2) the direct contact of granular activated carbon
with contaminated  wastewaters.   The direct contact method using granular
activated carbon is considered herein.
     The activated carbon is contained in a packed bed through which the waste
stream is routed under either gravity or pressure  flow conditions.  Dissolved
organics (as well  as possibly other dissolved species) are removed from the
waste stream by being attached to adsorption sites on the carbon.  The adsorp-
tive capacity of the bed is a function of the organic loading, the contact
time in the bed, and the affinity of the carbon for the organics.
     The carbon bed requires regeneration when its adsorptive capacity is
reached.  Systems  requiring more than 225 to 450 kg of carbon per day can be
economically regenerated on-site.  Regeneration is a thermal  process that re-
quires approximately 10 MJ per kilogram of carbon  regenerated.  Approximately
2 to 10 percent of the activated carbon is lost due to physical attrition and
oxidation.   Both the thermal regeneration energy and makeup carbon required
to replenish regeneration losses are predominant factors  in the overall eco-
nomics of carbon treatment processes.
                                      301

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Section 4
Aq. Med. Gen. Control
Residual Organics
     Removal  of any contaminant species  is  highly  stream-  and  carbon-specific.
A particular species may be sorbed by the carbon differently with  varying
concentrations and characteristics of other species  present in the waste
stream.  Designs for activated carbon systems  must therefore rely  heavily on
direct testing of the actual  wastewater  stream.
Chemical  Oxidation
     Many chemical species are less reactive or otherwise  less objectionable
to the environment when they are oxidized to their highest state.  The  process
of chemical oxidation consists of driving these reactions  by adding  a suitable
oxidizing agent.
     Chemical oxidation is typically carried out in  specially  designed, closed
contactors when the oxidant is a gas and in stirred  reactors when  the oxidant
is a liquid.  A variety of chemical oxidants can be  used,  but  ozone, chlorine,
chlorine dioxide, and hydrogen peroxide  have widest  application.
     Both organic and inorganic species  are oxidized during chemical oxidation.
The extent of removal is highly dependent on the oxidant used, concentration
of the contaminant, complexity of the molecule to  be oxidized, reaction time,
extent of reactor mixing, pH, and temperature.
     Chemical oxidation is most commonly used  to remove low level  concentra-
tions of chemical species.  For the stronger oxidants such as  ozone  and chlo-
rine, generally all materials in the waste  stream  are attacked, and  each  spe-
cies is removed approximately in order of its  amenability to oxidation.  Thus
if chemical oxidation is used with the intention to  remove a particular spe-
cies, say cyanide, the presence of other oxidizable  material  in the  waste
stream may greatly increase the demand for  the oxidant above that  which would
otherwise be required.
     The equipment used for chemical oxidation with C12 and lime  is typically
simple and therefore expected to  be  highly  reliable.  While no known experience
                                     302

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                                                        Section  4
                                                        Aq.  Med.  Gen.  Control
                                                        Residual  Organics
 exists  for treating wastewaters  from coal  gasification  facilities,  the process
 has  been used extensively in other applications.   Chemical  oxidation  and the
 closely related process  of disinfection  have shown reliable performance treat-
 ing  municipal  strength wastewaters over  many years of service.   Similar per-
 formance is expected in  coal  gasification  applications.
 Thermal  Oxidation
     Thermal oxidation or  incineration is a  high temperature process for the
 destruction of  a variety of wastewater contaminants.  Wastewater incineration
 can  be  considered a  combination of evaporation, pyrolysis, and oxidation
 although oxidation  is  the  primary process leading to the ultimate destruction
 of most  toxic pollutants.  Pyrolysis, or destructive distillation, is a
 process  in which heat  breaks down the waste material into simpler components
 which can  either be  recovered or oxidized more easily than the original
 material .  Oxidation, or combustion, promotes the reaction of waste components
 or pyrolysis products with oxygen to form such products  as carbon dioxide,
 water, and oxidized  inorganics such as sulfates and nitrates.
     Thermal oxidation is capable of treating a variety  of organic-laden
 wastes.  Wastes having a high energy content are self-sustaining, that is,
 their oxidation liberates sufficient energy to raise the waste temperature to
 the  temperatures required to sustain the oxidation reactions and drive them
 to completion.  Low  energy wastes require addition of auxiliary fuel.   Pre-
 concentration of a low energy aqueous waste may also be  used to reduce or
 eliminate the need for an auxiliary fuel.
     Thermal oxidation is capable of achieving essentially complete destruc-
 tion of a wide range of otherwise difficult to treat organics.  Most organics
 can be completely destroyed at 1300K with two seconds residence time.   Tests
with various pesticides such as DDT, malathion, and chlordane have shown 99.96
 to 99.99 percent destruction.  Tests at commercial  hazardous waste incinera-
tors  have shown over 99.99 percent destruction of PCBs.  Many incinerators have
 been operated reliably for years without shutdowns.

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 Section 4
 Aq. Med. Gen. Control
 Volume Reduction
4.2.1.7  Processes for Volume Reduction
     Most volume reduction processes  are capital  and energy intensive,  but
their application can sometimes be justified by the economics  of ultimate
disposal.  An exception is cooling tower concentration which has little or  no
associated capital charge since the cooling tower is an integral  part of the
base plant.  Cooling tower concentration and forced evaporation  are  presented
as examples of volume reduction processes.
Cooling Tower Concentration
     Based upon the availability of cooling water at the plant site  and the
overall wastewater treatment strategy,  process wastewater may be used as par-
tial makeup to the cooling towers.  This practice results in a reduction in
wastewater volume due to evaporative concentration.  Concentration  increases
of 4 to 5 times that of inlet water are common for the blowdown  from con-
ventional cooling towers, representing  a 75 to 80% volume reduction.  If
organics are present in the feed, some  will be oxidized in the tower by both
biological activity and direct combination with oxygen.
     In some applications, cooling tower concentration may not be feasible.
Potential problems include excessive biological growth and fouling,  corrosion,
scaling, and loss of volatile species.   Each of these can be corrected by
appropriate pretreatment, but at some point the additional cost of  pretreat-
ment steps exceed the value of benefits derived from cooling tower  concentra-
tion.
Forced Evaporation
     Forced evaporation of a wastewater stream can be accomplished  by one  of
two principal systems.  Of these, vapor compression evaporation has  lower
energy costs and will be discussed for  purposes of this manual.
     In the vapor compression evaporation process, vaporization energy is
supplied by a mechanical compressor.  The compressor raises the temperature

                                     304

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                                                         Section 4
                                                         Aq.  Med. Gen.  Control
                                                         Volume Reduction
and pressure of the vapor from a tubeside evaporator, and steam is condensed
on the shell side of the evaporator, boiling more water.   Seed crystals are
maintained in the evaporator to prevent scaling by the supersaturated liquor.
     The evaporation overhead may be of sufficient quality to recycle directly
to the plant.  The blowdown is typically 2 to 10% of the total  wastewater
flow and contains the original contaminant species concentrated into this
small  flow.
     Vapor compression evaporators are sensitive to dissolved gases and vola-
tile organic compounds in the feed.  Volatile components will appear in the
overhead and may require control.  Such components may also affect recovered
water quality and limit its direct reuse within the facility.
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Section 4
Aq. Med. Gen.  Control
Residual Disposal
4.2.1.8  Methods of Residual  Disposal
     Most commonly, treated wastewaters are discharged to a receiving body
for ultimate disposal.   Constraints of such discharges are highly site-specific
and beyond the scope of this manual.   There are several  other methods that
can be used to dispose  of a waste stream after it has  been handled by appro-
priate upstream controls.  Deep well  injection, surface impoundment,  and co-
disposal  with ash are presented as examples.
Deep Hell Injection
     Deep well injection has been used to dispose wastes that are difficult
to treat  such as those  containing high total dissolved solids or  those  con-
taining organics like tert-butyl  alcohols (nonbiodegradable)  and  ketones  (not
amenable  to activated carbon adsorption).  The disposal  system consists of a
surface facility for pretreatment, a  well,  and a  disposal  zone.   Many types of
formations can, under favorable circumstances, have sufficient porosity and
permeability to accept  large quantities of  injected liquid wastes.   In  prac-
tice, most wells have been constructed to inject  into  sand or sandstone and
limestone or dolomite.   Detailed geological and engineering studies are re-
quired to determine the suitability of a potential  site.
     The injection depth is generally selected to provide adequate separation
from potable subsurface water.   In every case, injection zones for disposing
of hazardous wastes must be below the deepest underground source  of drinking
water.  Wells are usually cased and cemented to prevent the upward migration
of fluids that are injected through tubing  in a packer set immediately above
the injection zone.  Injection  pressures are set  to ensure that neither frac-
ture nor fluid migration occur.
     The major advantages of deepwell  injection are:  1) it is an ultimate
disposal  method, 2) it requires little land, and  3) it removes the waste from
contact with air, surface water, usable ground water,  and the surface of the
ground.  Major disadvantages include:  1) long-term effects are largely

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                                                       Section 4
                                                       Aq.  Med.  Gen.  Control
                                                       Residual  Disposal
unknown and difficult to predict,  2) control  over the waste may possibly be
lost after injection, 3) favorable geologic conditions may not be available
in the vicinity of the waste source, 4) pretreatment adds to the expense of
waste disposal, and 5) wastes with high organic loading may cause plugging
of the well formation.
     Deepwell injection has seen limited use in the disposal of industrial
wastes for over 25 years.  However, a large number of wells inject oil  field
brines.  Performance data for a number of the industrial wells has shown
failures as well as successes.  Problems have included migration of waste
to usable aquifers as a consequence of fracturing, faults in confining
strata, or defects in well casings.
Surface Impoundment
     Surface impoundments are widely used to treat/dispose of industrial
wastes.  These impoundments (also known as holding basins, lagoons, oxidation
ponds, settling basins, and evaporation ponds)  can be either natural  or man-
made reservoirs to which wastewaters, slurries, or sludges are discharged.
Retention time in the impoundment provides for  natural evaporation, settling
of solids, biological decomposition of organics, and possible loss of volatile
components of the wastes.  If properly designed and operated, minimal environ-
mental contamination should occur.
     The suitability of a surface impoundment depends on site-specific  factors
For example, in order to successfully serve as  an evaporation pond, a surface
impoundment must be located at a site having a  sufficiently high net evapora-
tion rate.  A major drawback to their use is the need for relatively large
areas of land.
Co-disposal of Wastewater Streams with Ash
     Co-disposal is an ultimate disposal  method wherby the wastewater stream
is sorbed by ash, then the ash is handled by an appropriate solid waste dis-
posal method.  The feasibility is determined by the quantity of ash generated,

                                     307

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Section 4
Aq. Med. Gen. Control
Residual Disposal
its sorptive capacity, and the volume reduction needed to match the flow of
the wastewater stream to that which can be sorbed by the ash.  All constitu-
ents in the wastewater stream become entrained in the ash, except those that
might volatilize in the course of wastewater/ash mixing.
                                    308

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                                                       Section 4
                                                       Aq.  Med.  Strm.  Control
                                                       Organic
4.2.2  Water Pollution Controls for Streams Containing
       Predominantly Organic Constituents
     Wastewater streams that contain predominantly organic constituents  are
the condensates from the synthesis operation:   Mobil  M synthesis  condensate
(Stream 233), F-T synthesis condensate (Stream 223),  or methanol  distillation
condensate (Stream 229).  Control  processes applicable to these streams  are
discussed in this section.  In all likelihood, none of these streams  would  be
treated individually, but as a consequence of  economics, each would be combined
with others for common treatment.   Therefore,  the following discussion of in-
dividual stream controls is necessarily in the context of composite streams.
     None of the water pollution control  technologies discussed in this  sec-
tion would be singularly applied to a particular composite waste  stream.   Vari-
ous combinations of controls would be used, and the wastewater characteris-
tics input to an individual control would not  necessarily be those of the raw
composite flow but those modified  by other, upstream processes.  The  empha-
sis in this section, however, is on individual controls, and as such, inputs
(and therefore performances) are estimated as  those being most likely to
occur.
     Neither the flow nor the loading o* wastewater streams from the synthesis
sections are specific to the type of coal fed  to the gasifier.  However,
waste stream quality and quantity originating  from the gasification section
are specific to both coal type and process design, and these streams  contri-
bute to the composite flow of which synthesis  condensate is a part.  In  this
sense, coal type and gasification train design affect the choice and cost of
water pollution controls.  A more detailed discussion of the effect of coal
type on wastewater streams is provided in Section 4.2.3.
                                     309

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Section 4
Aq. Med. Strm. Control
Mobil M Syn. Condensate
4.2.2.1  Mobil-M Synthesis Condensate (Stream 233)
     The waste stream from the Mobil  M synthesis section (Stream 233)  would
probably be combined with the compression condensate (Stream 211) and  the
gas cooling/dust removal  blowdown (Stream 210) from the gasifier section for
common treatment.  As discussed in Section 3.3.4, base plant designs may uti-
lize either a methanol- or water-based wash to remove cyanide from the raw gas,
In cases where a water-based wash is  used, an additional wastewater stream
would be generated which could also be combined with the three waste streams.
     This section considers individual water pollution control  technologies
that are applicable to the Mobil  M synthesis condensate where it is part of
a composite flow described for base plants utilizing either a methanol- or
water-based cyanide wash.  Each technology has been discussed in Section 4,2.1,
Only details specific to the subject  composite flow are presented herein.
Activated Sludge
     Activated sludge could be used to remove dissolved organics and other
contaminant species from the composite waste stream.  For facilities utilizing
a water-based cyanide wash, organics  expressed as BOD are estimated to be
                                  3
1100 mg/L in a flow of about 688  m /hr.  Activated  sludge by one or more
stages is expected to remove BOD  to about the 35 mg/L level with all reduced
sulfur species removed to 1 mg/L.
     For facilities utilizing a methanol-based cyanide wash, the Mobil M con-
                                                              3
densate would be part of a smaller composite flow,  about 449 m /hr. Without
the dilution of the cyanide wash  water, the BOD concentration in the composite
flow would be higher at about 1700 mg/L (but same loading) and removed to
about the 40 mg/L level.   All other species would be removed to approximately
the same extent as those cited for the water-based, cyanide wash case.
     Much of the ammonia needed to supply nitrogen  as a growth nutrient would
be present in the waste stream.  However, supplemental ammonia as well as
phosphorus and possibly trace amounts of other materials would be required,
                                      310

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                                                        Section 4
                                                        Aq.  Med.  Strm.  Control
                                                        Mobil  M Syn.  Condensate
Due to the usual variability of waste stream characteristics, precise addi-
tion of ammonia would not be practical, and some overdosing would be required.
All ammonia added in excess of that required for cell growth would appear in
the activated sludge effluent.
     Cyanide is normally considered toxic to microorganisms, but when it
occurs as part of a larger matrix of biodegradable organics, the resulting
microbial population can often acclimate to the stress of cyanide and oxidize
or otherwise remove some of it.  Greater than 90% removal has been recorded
in carefully controlled, laboratory-scale studies.  The exact removal that
would be realized is highly uncertain and can be determined only once the
system is in place.
     A secondary waste stream would be generated consisting of biological
solids drawn from the underflow of the clarifier (Stream 415).  This stream
would have a solids content of about 1 to 2% with a dry solids flow of about
12,700 kg/d for base plant designs using a water-based cyanide wash.  For
the methanol-based case, the dry solids flow would be about 12,300 kg/d.  Fol-
lowing concentration to about 20 to 40% dry solids, the solid waste stream
would be handled by one of the methods discussed in Section 4.3.
     A secondary waste stream consisting of volatile species escaping the acti-
vated sludge reactor (fugitives) may also be generated (Stream 416).  This
stream is considered further in Section 4.2.4.
     Total capital investment for activated sludge is estimated to be $18.3
million  with a  total annualized cost of $3.9 million.
Filtration
     Filtration could be used to remove suspended solids from the composite
wastewater stream.  For base plant designs utilizing a water-based cyanide
wash, the flow of the composite stream is expected to be about 688 m /hr,
                           3
while a flow of about 449 m /hr is expected for the methanol-based case.  For
                                      311

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Section 4
Aq. Med. Strm. Control
Mobil M Syn. Condensate
both cases, the filter would be utilized following upstream treatment processes,
and an influent suspended solids concentration of about 30 mg/L  is  expected
with most of this material  consisting of biological  solids.  Filtration  should
remove the suspended solids to less than 10 mg/L.
     A secondary waste stream of filter backwash (Stream 417)  would be gener-
ated on an intermittent basis.  This stream would range between  2 and 10% of
the influent flow and would contain most of the material  that  was removed dur-
ing the preceding filter run.  The filter backwash is a small  volume stream,
but its high loading prevents it from being routed directly to other control
processes for treatment.  The backwash would therefore be routed to either its
own or some other flow equalization facility for gradual  release to other
water control processes.
     Total capital investment and total annualized cost for filtration are
estimated to be $1.2 and $2.5 million for the water-based cyanide wash case
and $0.78 and $1.8 million for the methanol-based cyanide wash case.
Granular Activated Carbon
     Granular activated carbon could be used to remove residual  organics fol-
lowing upstream treatment processes.  For the water-based cyanide wash case,
the flow of the composite wastewater stream would be about 688 m /hr with a
COD of about 680 mg/L.  COD removals to approximately 70 mg/L  are expected.
For base plant designs utilizing a methanol-based cyanide wash,  the flow of
                                         3
the composite stream would be about 449 m /hr, and a COD of about 1060 mg/L
would be reduced to approximately 100 mg/L.
     Regeneration of activated carbon by standard thermal methods would gen-
erate an offgas (Stream 420).  Control of this stream would probably be a
function integral with the regeneration facility design.
     Total capital investment and total annualized cost for the granular acti-
vated carbon process are estimated to be $3.1 and $1.5 million for  the water-

                                     312

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                                                       Section 4
                                                       Aq. Med. Strm. Control
                                                       Mobil M Syn. Condensate
based cyanide wash case and $3.0 and $1.6 million for the methanol-based
cyanide wash case.

Cooling Tower Concentration
     Cooling tower concentration could be utilized to reduce the volume of the
composite wastewater stream to be handled for disposal.   The feasibility  of
this control would have to be evaluated on an individual  case basis.   Certain
species in the subject waste stream including biodegradable organics,  chloride,
IDS, calcium, and sulfate may cause excessive fouling by  biological  growth,
corrosion, or scaling.
     Loss of volatile species stripped from the wastewater stream is  a sec-
ondary waste stream (Stream 419) and another factor that  may limit the feasi-
bility of cooling tower concentration.  In particular, ammonia and hydrogen
cyanide may be lost to the atmosphere, but the exact amount as well  as the
amount that would be permissible in a given location is  uncertain.
     For base plant designs using a water-based cyanide  wash, the composite
                                    3                3
wastewater stream could supply 688 m /hr of the 920 m /hr makeup flow to  the
cooling tower.  All species in the original v/astewater stream would be concen-
                                        3
trated by a factor of 3.8 into the 180 m /hr blowdown, assuming minimal losses
by volatilization or drift.  The corresponding makeup contribution and concen-
tration factor for the methanol-based case would be 449  m /hr and 2.5 respec-
tively.
     Characteristics of the composite wastewater stream  used as partial make-
up to the cooling tower are those that have been modified by upstream treat-'
ment processes.  These feed and the resulting blowdown characteristics are
summarized in Table 4-27.  Since the cooling tower is considered part of  the
base plant, no capital costs associated with environmental controls are assumed
to be required.
                                      313

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               TABLE  4-27.  MATERIAL FLOW FOR COOLING TOWER
                           CONCENTRATION - MOBIL M SYNTHESIS CASE
Base Plant
Cyanide Wash:
Characteristic*
Flow (m3/hr)
NH3
CN~
S=
S20=3
S0=3
SCN"
COD
BOD5
Cl"
TDS
TSS
Water- based
Makeup*
688
10
9-35
<1
<1
<1
<1
680
35
1040
1900
30
Slowdown"1"
180
38
34-130
<1
4
4
4
2600
130
3900
7200
110
Methanol -based
Makeup*
449
10
1
<1
<1
<1
<1
1060
42
1600
2900
30
Slowdown*
180
25
2
<1
2
2
2
2650
105
4000
7200
75
*A11 concentrations are mg/L and reflect published data and engineering
 estimates.   Detailed performance data and references  are  contained in
 the Control Technology Appendices.
+This stream combined with another source to supply the total  makeup
 requirement of 920 nr/hr.
                                    314

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                                                     Section 4
                                                     Aq. Med. Strm. Control
                                                     Mobil  M Syn. Condensate
Forced Evaporation
     Forced evaporation could be used to decrease the volume of the composite
wastewater flow by concentrating the contaminant species into a fraction of
the original volume.  Condensate from forced evaporation may contain com-
pounds volatilized during water evaporation.  Volatilized components may in-
fluence condensate reuse alternatives, depending upon which compounds are
volatilized and their concentrations in the condensate.  For material balance
purposes, volatilization was neglected since no data are available to support
assumptions relating to species losses from the feed.  The feasibility of this
control process would have to be evaluated on an individual case basis.
     Forced evaporation would be preceeded by other control processes for dis-
solved gas or volatile organics removal.  Estimated characteristics of the
composite wastewater stream input to forced evaporation and its blowdown are
presented in Table 4-28.  The estimated blowdown quality represents the  worst
case for the specified feed and volume reduction since species volatilization
has been neglected.  Total capital investment is estimated to be $13.7 million
with a total annualized cost of $3.5 million.
Incineration
     Incineration could be used to remove residual organics following various
pretreatment and concentration steps.  For the subject composite wastewater
stream, the flow to be incinerated would be first decreased by upstream con-
                    o
trols  to about 18 m /hr for both the methanol- and water-based cyanide wash
cases.  Incineration would reduce COD and BOD in the composite flow  from
approximately 26,000 and  1000 mg/L to 25 and 1 mg/L, respectively.
     Incineration would generate both a liquid and a gaseous secondary waste
stream.  The gaseous stream is flue gas (Stream 421) from combustion of
auxiliary  fuel and  waste  stream constituents.  This stream would be  controlled
by equipment that  is an integral part of the incinerator facility.   The liquid
stream is  the flue  gas quenching/scrubbing  system blowdown.  This  stream would

                                     315

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Section 4
Aq. Med. Strm. Control
Mobil M Syn. Condensate
have a low flow and contain mainly inorganic salts  with some particulate mat-
erial .  It would be routed to other processes for treatment or combined
directly with the effluent stream.
     Total capital investment for incineration is estimated to be $4.8 mil-
lion with a total annualized cost of $2.3 million.
                                     316

-------
           TABLE 4-28.  MATERIAL FLOW FOR FORCED EVAPORATION-
                        MOBIL M SYNTHESIS CASE

Base Plant
Cyanide Wash:
Characteristic*
Flow (m3/hr)
NH3
CN~
S=
S2°3
S03
SCN"
COD
BOD5
cr
TDS
TSS
Water-based
Input
180
38
34-130
<1
4
4
4
2600
130
3900
7200
110
Slowdown*
8
380
340-1300
<1
40
40
40
26000
1300
39000
72000
1100
Methanol-based
Input
180
25
2
<1
2
2
2
2650
105
4000
7200
75
Slowdown
18
250
20
<1
20
20
20
26500
1050
40000
72000
750

*A11 concentrations are mg/L and reflect published data and engineering
 estimates.  Detailed performance data and references are contained in
 the Control  Technology Appendices.
"^Slowdown quality represents the worst case for the specified feed and
 volume reduction since species volatilization has been neglected.
                                    317

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Section 4
Aq. Med. Strm. Control
F-T Syn. Condensate
4.2.2.2  F-T Synthesis Condensate (Stream 223)
     The characteristics of the F-T synthesis Condensate (Stream 223)  are
somewhat different than those of the Mobil  M condensate (refer to Section
3.4.6), but a similar treatment approach would be involved.  Applicable
control processes are discussed in Section 4.2.2.1   with costs and per-
formances varying only slightly from those presented as a primary result of
flow rate differences.  For example, an activated sludge system designed to
treat the F-T synthesis condensate is estimated to require a total capital
investment of $20.9 million, an increase of about 14% over the equivalent
Mobil M activated sludge system.
                                     318

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                                                     Section 4
                                                     Aq.  Med. Strm. Control
                                                     Methanol Syn. Condensate
4.2.2.3  Methanol Distillation Condensate (Stream 229)
     The methanol distillation condensate (Stream 229) combined with gasifi-
cation wastewaters contains sufficient loading of organics to be handled
analogously to the Mobil M or F-T synthesis cases.  However, the nitrogen
(as ammonia) in the inorganic streams would greatly exceed the amount needed
for biological oxidation of the organics.  The methanol condensate could also
be handled by slight modification to control technologies discussed in Section
4.2.3.1 for base plant cases where cyanide is removed from the raw gas by a
water wash, and in Section 4.2.3.2 for the methanol wash case.
                                     319

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 Section 4
 Aq. Med. Strm. Control
 Inorganic
4.2.3  Water Pollution Controls for Streams Containing
       Predominantly Inorganic Constituents
     Wastewater streams that contain predominantly inorganic constituents
are the cyanide wash water (Stream 215), primary compression and cooling
condensate (Stream 211), and the gas cooling and dust removal  blowdown
(Stream 210).  It is not likely that any of these streams would be treated
separately, but each would be combined with the others,  for reasons of econo-
mics, into a composite flow.  Paralleling the approach taken in Section
4.2.2, each stream is discussed in this section in the context of a composite
flow.
                                     320

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                                                         Section  4
                                                         Aq.  Med. Strm.  Control
                                                         Cyanide  Wash  Water
4.2.3.1  Cyanide Wash Water (Stream 215)
     A number of control processes are applicable to the cyanide wash water
(Stream 215).  Of these, only polysulfide addition would be applied exclusi-
vely to this stream.  All other processes would be applied to a composite
wastewater stream consistinq of the combined flows of the cyanide wash water
(Stream 215), the compression condensate (Stream 211), and the gas cooling/
dust removal blowdown (Stream 210).  Each of the control technologies con-
sidered in this section has been discussed in Section 4.2.1, and only details
specific to the subject composite flow are considered in the following sub-
sections.
Polysulfide Addition
     Polysulfide could be added to the cyanide wash water to convert cyanide
to thiocyanate.  The cyanide wash is estimated to have a flow of 239 m /hr
with a cyanide concentration of 240 mg/L.  Less than about 10 mg/L cyanide
is expected to remain following polysulfide addition to a flash mix reactor
and subsequent reaction in a plug flow reactor.  This performance is estimated
assuming that little of the cyanide is present in a complexed form, an expec-
tation based on estimated very small concentrations of potentially complex-
forming cations in the subject waste stream.
     Preliminary EPA sponsored lab studies (unpublished) indicate that the
conversion of cyanide to thiocyanate can be accomplished at the wastewater
treatment process scale.  However, excess polysulfide of approximately double
its stoichiometric requirement may be needed to achieve reasonably rapid
reaction rates.  Otherwise, residence times and therefore reactor volumes
may assume unreasonable dimensions.
     In some applications,  it may be possible to dose polysulfide directly
to the cyanide wash circuit (or alternatively to the gas cooling/dust removal
circuit).  If feasible, substantial  cost savings would be realized.  Most
capital requirements would  be eliminated as a small  modification to the cyanide

                                     321

-------
 Section  4
 Aq.  Med. Strm.  Control
 Cyanide  Wash  Water
wash system would replace the large treatment wastewater reactors.   More
importantly, it is expected that the polysulfide demand would be reduced.
Nearly complete conversions of cyanide are realized in refinery applications
where approximately stoichiometric doses of polysulfide are made at the out-
let of process equipment.  It is therefore expected that by dosing  the poly-
sulfide directly to the cyanide wash circuit or to the gas cooling/dust re-
moval circuit, nearly complete cyanide conversions could likewise be realized
with a minimum of polysulfide added.
     Another method of effecting cyanide conversion by polysu'ifide  might be
to add the polysulfide in conjunction with another wastewater treatment pro-
cess.  A likely prospect is the activated sludge process, but this configura-
tion has never been tried.
     The cyanide to thiocyanate conversion has generally been identified as
requiring alkaline reaction conditions.  Following polysulfide addition, the
subject waste stream would be combined directly with the compression conden-
sate and the gas cooling/dust removal blowdown, or if sufficent acidity is not
available in these streams, the cyanide wash would be first neutralized with
acid.  In either case, the pH of the cyanide wash will be depressed to approx-
imately neutral and unreacted polysulfide may precipitate.  In some cases,
this precipitate may be compatible with downstream controls.  If not, a filter
or clarifier would be added.
     Total capital investment for polysulfide addition is estimated to be
$130,000 with a total annualized cost of about $730,000.
     The type of coal fed to the gasifier is expected to have little effect
on the mass flow of cyanide produced in the gasifier section.  The flow and
cyanide concentration of the cyanide wash will therefore by generally inde-
pendent of coal type, and the cost of polysulfide addition will remain con-
stant as well.
                                      322

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                                                        Section 4
                                                        Aq.  Med. Strm.  Control
                                                        Cyanide Wash Water
Activated Sludge
     Activated sludge would be utilized primarily to oxidize ammonia and thio-
cyanate, although other species would be removed as well.  The subject com-
posite wastewater stream would contain about 260 mg/L of ammonia and 210 mg/L
                        3
of thiocyanate, at 578 m /hr.  Following activated sludge, about 8 mg/L am-
monia and less than 1 mg/L thiocyanate are expected to remain.
     A secondary waste stream of biological solids (Stream 415) at about 1%
concentration would be drawn from the underflow of the clarifier at the rate
of about 1300 kg/d dry solids.  Following concentration to 20 to 40% solids
by a filter press or other solids handling equipment, this waste stream would
be handled by appropriate solid waste disposal  techniques discussed in
Section 4.3.
     Total capital investment is estimated to be $12.6 million with a total
annualized cost of about $2.7 million.
Denitri'fication
     Denitrification could be utilized to remove nitrate.  The process would
be proceeded by other controls such that the composite wastewater stream
                                                                3
would contain a nitrate concentration of about  245 mg/L at 578 m /hr.  Deni-
trification is expected to remove nitrate to about the 25 mg/L level.
     A secondary waste stream of biological solids (Stream 418) at about 1%
concentration would be drawn from the underflow of the clarifier at the rate
of about 1800 kg/d dry solids.
     Total capital investment is estimated to be $6.1 million with a total
annualized cost of about $2.2 million.
Filtration
     Details of filtration are identical  to those presented in Section 4.2.2.1.
The composite wastewater stream has  a flow of about 578 m /hr.  The total
                                     323

-------
 Section  4
 Aq.  Med. Strm.  Control
 Cyanide  Wash  Water
 capital  investment  was  estimated  to  be  $1.0 million with a total annualized
 cost of  about $220,000.
Chemical  Oxidation
     Chemical oxidation  could be used to remove low level concentrations of
cyanide that remain in the composite  wastewater stream following treatment
by other  controls.  However, since cyanide is  a slowly oxidized  species, most
other reduced chemical species would  be  removed concurrently,  increasing the
oxidant demand.  The composite wastewater stream  with a  flow  rate  of 578
 3
m /hr would  probably contain less than 10 mg/L of both cyanide and ammonia.
Both would be removed to less than 1  mg/L.
     Total capital investment is estimated to  be $720,000 with a total  annu-
al ized cost of $230,000.
Ion  Exchange for Ammonia Removal

     Ion  exchange using  a clinoptilolite resin could be utilized to remove
                                   3
ammonia.   When applied to the 578 m /hr  composite wastewater  stream contain-
ing 260 mg/L ammonia, ion exchange is estimated to be capable  of reducing
the ammonia concentration to less than 10 mg/L.

     Total capital investment is estimated to  be $12.9 million with a total
annualized cost of about $3.5 million.
Cooling Tower Concentration
     Cooling tower concentration could be utilized to reduce  the volume of the
composite wastewater stream to be handled by downstream processes and disposal
methods.   Since the subject waste stream is essentially free  of organics,  foul-
ing  by biological growth is not expected to be a problem.  However, other
characteristics of the waste stream may be limiting,  and the applicability of
cooling tower concentration would therefore have to be determined on an indi-
vidual case  basis.

                                      324

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                                                       Section 4
                                                       Aq. Med. Strm. Control
                                                       Cyanide Wash Water
     The makeup required for the cooling tower (methanol  synthesis case)  is
     3                                         3
825 m /hr.  The composite waste stream at 578 m /hr could supply most of  this
with the balance supplied by other sources.   With blowdown at 161  m /hr,
chemical species in the original wastewater  stream would  be concentrated  by
a factor of 3.6, assuming minimal  loss of species by volatilization and
drift.  The characteristics of the composite waste stream when used as cool-
ing tower makeup, and therefore of the blowdown, will  vary depending on the
upstream control processes applied.  The makeup and blowdown characteristics
summarized in Table 4-29 are estimated as worst case examples.  Since the
cooling tower is part of the base plant, no  costs associated with environ-
mental controls have been estimated for it.
Forced Evaporation
     Forced evaporation could be used to decrease the volume of the composite
wastewater stream.  Forced evaporation would also permit  recovery of a high
quality  steam suitable for recycle to the base plant. The feasibility of
this control  process would have to be evaluated on an individual  case basis.
     As with cooling tower concentration, the characteristics of the input to
forced evaporation and its blowdown would vary with upstream controls. Esti-
mated worst case characteristics are presented in Table 4-29.
     Total capital investment is estimated to be $13.7 million with a total
annualized cost of about $3.5 million.
                                     325

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  TABLE 4-29.  MATERIALS FLOW FOR COOLING TOWER CONCENTRATION AND FORCED
               EVAPORATION - WATER-BASED CYANIDE WASH CASE
Cooling Tower
Concentration
Characteristic*
Flow (m3/hr)
NH3
CN"
s=
S2°3
S03
SCN"
cr
TDS
NO^-N
TSS
Make-up1"
578
260
7.5
2
58
14
210
1200
2200
245
30
Slowdown
161
933
27
<1*
205
50
740
4500
7900
880
110
Forced
Evaporation
Feed
161
933
27
<1
205
50
740
4500
7900
880
110
Bl owdown
16
9330
270
<1
2050
500
7400
45000
79000
8800
1100

*A11 concentrations are mg/L and reflect published data and engineering
 estimates.  Detailed performance data and references are contained in
 the Control Technology Appendices.
"'"This stream combined with another source to supply the total makeup
 requirement of 825 m^/hr.
 S= is lost through both oxidation and stripping.
                                     326

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                                                        Section 4
                                                        Aq. Med. Strm. Control
                                                        Compression Condensate
4.2.3.2  Raw Gas Compression and Cooling Condensate (Stream 211)
     The compression condensate (Stream 211) could be combined with the cya-
nide wash water (Stream 215) and the gas cooling/dust removal  blowdown
(Stream 210) for common treatment.  In this context, control  technologies
applicable to the compression condensate are identical  to those presented
for the cyanide wash water, Section 4.2.3.1 with exception of polysulfide
addition.  The characteristics of all  waste streams and the performances and
costs of all controls are the same.
     As discussed in Section 3.3.4, some base plant designs may use a methanol-
rather than water-based wash to remove cyanide from the raw gas.  Where this
option is exercised, the compression condensate would probably be combined
only with the gas cooling/dust removal blowdown for common treatment since no
cyanide wash water would be generated.  The control technologies discussed  in
Section 4.2.3.1 would still be applicable  to this composite flow, but with
different waste stream characteristics, certain performances and costs would
be different.  This section considers only aspects of the control technologies
applied to  the subject composite  stream (i.e., compression condensate and
gas cooling/dust removal blowdown)  that differ from those already presented
in Section  4.2.3.1.
Activated Sludge
     The composite wastewater stream  is estimated to contain about  190 and
4.5 mg/L of ammonia and thiocyanate,  respectively, and has a flow rate of
339 m /hr.  Ammonia would be removed  to about 6 mg/L and thiocyanate removed
to less than 1 mg/L.  A biological  solids  waste stream (Stream 415) would be
generated at a rate of 270 kg/d dry solids in a 1 to 2% solids slurry.  This
solid waste stream would be concentrated to 20 to 40% solids by a filter
press or some other control, then  disposed of by a method described in Sec-
tion 4.3.
                                     327

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Section 4
Aq. Med. Strm. Control
Compression Condensate
      Total capital investment is estimated to be $6.7 million with a total
annualized cost of about $1.5 million.
      The composition of the compression condensate and therefore the charac-
teristics and costs of applicable controls are affected by the type of coal
fed to the gasifier.  As discussed in Section 3.2.1, ammonia formation during
gasification tends to increase with decreasing coal rank.  Therefore the
quantity of ammonia in the compression condensate and/or the gas cooling/dust
removal blowdown, which also contributes to the composite flow, would like-
wise  increase for lower rank coals, and there would be a corresponding increase
in the total capital investment and total annualized cost of water pollution
controls.
      Coal chloride content has little effect on the characteristics of the
compression condensate since halogens are almost completely removed during
gas cooling and dust removal.  However the characteristics of the gas cooling/
dust  removal blowdown and therefore the characteristics of the subject com-
posite stream are dependent on coal type.  These aspects are considered in
Section 4.2.3.3.
Biological Denitrification
      Denitrification would be applied to the composite waste stream following
                                                   3
upstream treatment processes.  From a flow of 339 m /hr, the concentration of
nitrate could be decreased from about 140 mg/L  to 15 mg/L.  Total capital
investment is estimated to be $3.2 million with a total annualized cost of
$980,000.
      A biological  solids waste stream (Stream 418) would be generated at a
rate  of about 590  kg/d dry solids  in a 1 to 2%  solids slurry.   Following
dewatering to 20 to 40% solids, the waste stream would be disposed of by a
solid waste disposal method described in Section 4.3.
                                     328

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                                                        Section 4
                                                        Aq. Med. Strm. Control
                                                        Compression Condensate
Filtration
     Total capital  investment  for filtration of the composite stream of 339
m3/hr is estimated  to be $590,000 with a total annualized cost of  about $150,000.
All other aspects of filtration are identical to those presented in Section
4.2.2.1.
Chemical Oxidation
     When applied to the composite wastewater stream following upstream treat-
ment processes, the chemical oxidation feed would contain approximately 6 and
                                                                         o
7 mg/L of ammonia and cyanide, respectively, and has a flow rate of 339 m /hr.
Each of these species would be reduced to less than 1  mg/L.  Total capital
investment is estimated to be $160,000 with a total annualized cost of about
$350,000.
Ion Exchange
     When applied to the composite wastewater stream,  the clinoptilolite-based
ion exchange system would be loaded with about 190 mg/L of ammonia at  339
m /hr.  The effluent from this process is expected to  contain less than 10
mg/L ammonia.  Total capital investment is estimated to be $8.3 million with
a total annualized cost of about $1.8 million.
Cooling Tower Concentration
                                                       3                3
     The composite wastewater stream could supply 339  m /hr of the 825 m /hr
                                                          3
required for cooling tower makeup.  With blowdown at 161 m /hr, constituents
in the composite stream would be concentrated by a factor of 2.1.  As  described
in Section 4.2.3.1, the characteristics of the subject composite flow  used for
makeup water and therefore characteristics of the blowdown would vary  accord-
ing to upstream controls.  The makeup and blowdown characteristics summarized
in Table 4-30 are estimated worst case examples.  No capital cost associated
with environmental controls is assumed for cooling tower concentration since
the cooling tower is part of the base plant.
                                     329

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Section 4
Aq. Med. Strm. Control
Compression Condensate
Forced Evaporation
     As with cooling tower concentration, the characteristics of the input to
forced evaporation and its blowdown would depend on upstream controls.   Esti-
mated worst case characteristics are presented in Table 4-30.  Total capital
investment is estimated to be $13.7 million with a total  annualized cost of
about $3.5 million.
                                     330

-------
        TABLE 4-30.  MATERIAL  FLOW  FOR  COOLING TOWER  CONCENTRATION
                     AND  FORCED  EVAPORATION  - METHANOL-BASED
                     CYANIDE WASH CASE

Characteristic*
Flow (m3/hr)
NH3
CN"
S=
S2°3
so-
SCN
cr
TDS
NO^-N
TSS
Cooling Tower
Concentration
Make-upt
339
190
7
3.5
98
24
4.5
2100
3800
140
30
Slowdown
161
400
15
<1*
205
50
9.5
4400
8000
300
60
Forced
Evaporation
Feed
161
400
15
<1
205
50
9.5
4400
8000
300
60
Bl owdown
16
4000
150
<1
2050
500
95
44000
80000
3000
600
*A11 concentrations are mg/L and reflect published data and engineering
 estimates.  Detailed performance data and references are contained in
 the Control Technology Appendices.
''This stream combined with another source to supply the total makeup require-
 ment of 825
=I=S= is lost by both oxidation and volatilization.
                                    331

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 Section 4
 Aq.  Med.  Strm.  Control
 Gas  Cool/Dust Removal
4.2.3.3  Gas Cooling and Dust Removal  Slowdown (Stream 210)
     The gas cooling and dust removal  blowdown (Stream 210)  could be combined
with the compression condensate (Stream 211) for common treatment.   Applicable
control technologies and corresponding characteristics are discussed in
Section 4.2.3.2.  For base plant designs where cyanide is  removed from the
raw gas by a water-based wash, the cyanide wash water (Stream 215)  would also
be combined with the two streams cited.  Applicable control  technologies and
corresponding characteristics are discussed in Section 4.2.3.1.
     The characteristics of the coal  fed to the gasifier affect  the charac-
teristics of the gas cooling/dust removal  blowdown in one  of two general  ways.
First, the mass of ammonia produced in the gasifier tends  to increase with
decreasing coal rank.  Also, higher sulfur levels generally  result from coals
having higher sulfur contents, although certain secondary  effects such as ash
alkalinity may have more of an affect  on the sulfur contained in wastewater
streams.  The level  of cyanide in wastewater streams is affected only slightly
by characteristics of the coal.
     Second, coal type can affect the quantity of water blown down from the
gas cooling/dust removal circuit.  A minimum blowdown is required represent-
ing the difference between the water entering the circuit with the raw gas
and that leaving the system with the cooled gas and dust (after dewatering).
Most of the water contained in the raw gas is the result of  the gas being
quenched at the gasifier outlet to reduce its temperature to below the ash
fusion temperature so that fouling of the waste heat boiler  does not occur.
The amount of water added depends on the gasification temperature (a function
of coal rank and ash properties) and to a lesser extent on the mass of ash to
be quenched.
     Blowdown requirements are also influenced by the chloride content of the
coal.  Chloride in the coal is almost entirely gasified and  is recovered in
the gas cooling and dust removal operation.  If the concentration of chloride

                                     332

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                                                         Section 4
                                                         Aq.  Med. Strm.  Control
                                                         Gas  Cool/Dust Removal
in the gas cooling/dust removal circuit exceeds the level  considered allow-
able for operating reasons, makeup water must be added to  dilute the chloride
concentration, and an increase in blowdown results.
     The following two examples demonstrate the effect of  coal  chloride.
For the base case utilizing the Illinois No. 6 coal described in Section  3 and
for no makeup water added to the gas cooling/dust removal  circuit, the chlo-
ride would establish itself in the circuit at about 6000 mg/L.   For purposes
of this manual, it was assumed that operating requirements of the gas cooling/
dust removal circuit impose a chloride concentration limitation of about
2100 mg/L.  Makeup water was, therefore, added to dilute the chloride result-
ing in an increase in blowdown by a factor of about 2.8.  If an actual design
assumes a significantly different concentration of chloride in  the gas cooling/
dust removal circuit, the blowdown will change accordingly.  The concentration
of all species for any composite wastewater stream of which the blowdown  is
a part would be affected, but the mass loading of all species would remain
essentially unchanged.  Some modification of individual  pollution controls
might be needed, but the overall approach to wastewater control and the costs
would not be greatly affected.
     The blowdown flow rate may also be dependent upon the chloride content
of the feed coal.  For a system gasifying essentially the  same  Illinois No. 6
coal  but which has one quarter the chloride content (0.07% dry  basis) indi-
cated for the design coal, no makeup would be required to  the circuit (assum-
ing a maximum permissible chloride level of 2100 mg/L),  and the blowdown
would decrease by a factor of 2.8.
                                     333

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Section 4
Aq. Med. Strm. Control
Secondary Waste Streams
4-2.3.4  Secondary Waste Streams from Other Media
     Secondary waste streams from other media are limited to condensates and
purge streams from tail gas treatment processes and purge streams from flue
gas desulfirization processes.  Estimated flows from these controls are:
   3                                                       "?
4 m /hr from Beavon (Stream 405) and SCOT (Stream 409); 3 m /hr from Wellman-
Lord (Stream 411); and 37.5 m /hr from flue gas desulfurization tStream 425)
in the F-T synthesis case and 6.1 m /hr in the Mobil M case.  Additionally,
                                3
a waste stream of about 2 to 3 m /hr would be generated by the Beavon process
consisting of Stretford solution purge (Stream 405).  Each of these waste-
water streams would either be combined with other streams for common treatment
or be treated separately by controls that are well developed in petroleum
refining applications.
                                      334

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                                                             Section 4
                                                             Aq. Med. Int. Ex.
4.2.4  Integrated Pollution Control Examples
     Previous sections have considered individual water pollution controls
applicable to the principal wastewater streams generated by a K-T gasification
facility.  Section 4.2.2 considered streams having predominantly organic con-
stituents and Section 4.2.3 considered streams having predominantly inorganic
constituents.  Details of individual controls or combinations of controls
have not yet been proposed for K-T-based gasification facilities in the U.S.
Except where otherwise noted, individual controls have been selected on the
basis of controls commonly utilized in parallel industries.  This section
presents examples of how individual controls might be combined to treat waste-
water streams prior to their ultimate disposal.  The approaches considered in
this section are not all inclusive but only serve to indicate how available
controls may be applied to the subject wastes.
     The controls selected in each example are largely determined by the ulti-
mate disposal method being considered and the type of synthesis section uti-
lized by the base plant.  The specific waste stream quality required by each
disposal method is uncertain and would be determined on a site-specific basis,
but certain general  requirements are associated with each, and these are
incorporated in the integrated control examples.
     Three ultimate disposal  methods are considered:  discharge to surface
waters, surface impoundment,  and deep well  injection.  In some cases, co-
disposal of the wastewater with ash from the gasifier may also be a viable
method (see Section 4.2.1.8).  Potential sources of ash are incinerated dust
from the gas cooling/dust removal  blowdown, boiler bottom ash, and boiler fly
ash.  This ash is expected to sorb 20% water.  Additionally,  slag generated
by the gasification section can sorb about  10% water.  The total  estimated
capacity of wastewater that can be sorbed by ash is 6.7 m /hr.  However, this
capacity may vary greatly, depending primarily on the ash content of the feed
coal, the slag/dust and ash partitioning during gasification, and the feasi-
bility of resource recovery by incineration of gasifier dust.
                                     335

-------
Section 4
Aq. Med.  Int.  Ex.
     It is not expected that the ash and slag generated by the gasifier would
provide sufficient capacity to dispose of the entire wastewater volume.  Co-
disposal is therefore not considered further in this manual.  However, while
only single ultimate disposal  methods are considered for each integrated con-
trol example in this section,  several methods may be combined to satisfy the
needed capacity.  In this context co-disposal may be a viable option.
     The type of synthesis operation utilized in the base plant affects the
wastewater treatment approach  required for the entire K-T plant.  Both the
F-T and Mobil M synthesis sections generate a waste stream that is heavily
loaded with organics.  Fuel grade methanol synthesis  generates a much smaller
volume of organic-loaded waste to the total wastewater stream, while crude
methanol synthesis generates no waste stream from the synthesis operation.
All other significant waste streams in the K-T facility contain principally
inorganic constituents.  Therefore, K-T plants that produce crude methanol
generate, facility-wide, only waste streams having primarily inorganic con-
stituents.  Fuel grade methanol K-T plants generate only a small load of
organics compared to the inorganics load of a combined wastewater, and F-T
and Mobil M synthesis plants generate both heavily loaded organic and in-
organic waste streams when gasification and synthesis wastes are combined.
Somewhat different water pollution control approaches appear most advantageous
for each of these three cases.  Each case is considered separately in the
following section.
                                     336

-------
                                                             Section 4
                                                             Aq. Med.  Int. Ex.
4.2.4.1  Treatment of Waste Streams from Base Plants Utilizing F-T or
         Mobil M Synthesis
     Both F-T and Mobil M synthesis operations generate a condensate having
high concentrations of organics.  These organics are relatively simple species
including short chain hydrocarbons, ketones, and organic acids.  It is expected
that the F-T and Mobil M synthesis condensates will  be highly amenable to bio-
logical oxidation:  BOD was estimated to be 70% of COD.  However, there are
two problems in applying a conventional biological system to these waste
streams.  First, the concentration of organics exceeds the maximum normally
handled by a suspended growth biological system such as activated sludge.
Dilution of the waste stream by recycling the activated sludge effluent
would require excessive pumping and increased capital  costs.  Other biologi-
cal process reactors, such as fixed film reactors (trickling filters and
others), could handle the high organic concentrations, but it is expected that
following these processes, the organics concentration  would remain relatively
high so that an activated sludge process to effect more complete removal might
still  be advisable.  Additionally, this approach does  not address the second
problem which is lack of growth nutrients.   The subject waste stream does not
contain nitrogen, phosphorus, sulfur, and trace amounts of other materials
required for cell growth.
     The waste streams generated by the gasifier section (Section 4.2.4) con-
tain,  among other species, ammonia and sulfide but no  organics.  By combining
these waste streams with a synthesis condensate, the ammonia would supply
most of the nitrogen and the sulfide would  supply all  of the sulfur required
to support cell  growth.  The concentration  of organics in the combined stream
would be diluted to a level  suitable for an activated  sludge system.   Char-
acteristics of the individual waste streams from the gasifier section, the
Mobil  M condensate, and the combined streams are presented in Table 4-31.
There are two cases of combined streams representing the two base plant
designs for cyanide wash discussed in Section 3.3.4.  Where cyanide is removed

                                     337

-------
      TABLE  4-31.   CHARACTERIZATION  OF  MAJOR STREAMS  COMBINED  FOR COMMON TREATMENT - MOBIL M SYNTHESIS CASE
co
to
Characteristic*
Flow (m3/hr)
NH3
CN"
S=
S2°3
S0=
SCN-
COD
BOD5
cr
TDS
Gas Cooling/
Dust Removal
Blowdown
Stream 210
322
156
7
1
103
25
4
--
--
2111
4000
Compression
Condensate
Stream 211
17.4
735
8.9
48.7
6.3
--
14
--
--
2200
— ™*
Cyanide
Wash
Water
Stream 215
239
--
241
176
--
--
--
—
--
--
~ ™
Compos
Mobil M Base Plant
Condensate Water-
Stream 233 basedt
110 688
92
87
63
48
12
2.5
14000 2200
6860 1100
1040
1900
ite
Cyanide Wash
Methanol-
based*
449
140
5
2.6
74
18
3
3400
1700
1600
2900
       *A11  concentrations are mg/L.
       tCombined streams:  gas cooling/dust removal  blowdown, compression condensate,
                           cyanide wash water,  and Mobil  M condensate.
       ^Combined streams:  gas cooling/dust removal  blowdown, compression condensate,
                           and Mobil  M condensate.

-------
                                                           Section 4
                                                           Aq.  Med. Int.  Ex.
from the base plant by a water wash, a wastewater stream is generated con-
tributing to a combined flow of 688 m /hr.  Where cyanide is removed by a
methanol-based wash essentially no wastewater is generated by this source,
and the combined flow is 449 m /hr.
     Presented in Figure 4-6 are three examples of integrated controls appli-
cable to a composite waste stream consisting of the Mobil M condensate
(Stream 233) combined with the wastewater streams from the gasifier section.
Identical examples could be used for the F-T synthesis case with changes
required only to reflect the different flow and organic loading of the F-T
synthesis condensate.  Neither performance nor cost characteristics would
differ  greatly.
     A  feature common to all integrated pollution control examples is flow
equalization.  Design performance of pollution control processes can be real-
ized only when the waste stream characteristics vary gradually and within a
generally narrow range.  For some processes, particularly those based on the
activity of microorganisms, equalization is especially critical.  Under con-
ditions of no more than slightly varying waste stream characteristics, micro-
bial populations can usually be acclimated to both concentrations and types
of chemical species that would otherwise not be degradable.  If significant
fluctuations in the input occur, there is no chance to acclimate the micro-
bial culture, or worse, the entire system might fail requiring a complete,
new start-up.
     Certain waste streams in the K-T plant other than those from the gasi-
fier or synthesis sections may also be routed to the equalization facility.
These waste streams would contribute only minor flows and loadings to down-
stream  controls.  The exact requirements of the equalization facility are
beyond  the scope of this manual.  Its design would take  into consideration the
variability of all waste stream inputs to be handled by  the integrated controls,
                                      339

-------
     EXAMPLE 1
     SYNTHESIS CONDENSATE
STREAM 233 OR 223 *
COMPRESSION CONDENSATE
STREAM 211 *
GAS COOLING/DUST REMOVAL BLOWDOWN
STREAM 210 *
CYANIDE WASH WATER*
STREAM 215 ^

fe


FLOW
EQUALIZATION




ACTIVATED
SLUDGE

k



ML 1 HA 1 IUIM






GRANULAR
ACTIVATED
CARBON

                                                                                                              DISCHARGE TO
                                                                                                              SURFACE WATERS
oo
-e»
o
     EXAMPLE 2
     SYNTHESIS CONDENSATE
STREAM 233 OR 223 P
COMPRESSION CONDENSATE
STREAM 211 *
GAS COOLING/DUST REMOVAL BLOWDOWN
STREAM 210 *



FLOW
EQUALIZATION


ACTIVATED
SLUDGE


COOLING
TOWER
CONCENTRATION
     CYAWDE_W_ASH_WAT ER*
     STREAM 215
DISCHARGE TO
SURFACE IMPOUNDMENT
     EXAMPLE 3
     SYNTHESIS CONDENSATE
STREAM 233 OR 223 w
COMPRESSION CONDENSATE
STREAM 211 *
GAS COOLING/DUST REMOVAL BLOWDOWN
STREAM 210
k


FLOW
FDI 1 A 1 1
ZATION


5^

ACTIVATED
SLUDGE

^


COOLING
TOWER
CONCEN-
TRATION

^


FORCED
ATION




INCINER-
ATION
     CYANjp.E WASH WATER'
     STREAIVTT15
                                                                                                                 DISCHARGE TO
                                                                                                                 DEEP WELL
                                                                                                                 INJECTION
     *This stream exists only for base plants where cyanide is removed from the raw gas by a water-based wash.
                      Figure 4-6.   Integrated control examples  -  Mobil  M or  F-T synthesis  case

-------
                                                             Section 4
                                                             Aq. Med. Int. Ex.
     Example 1.   Integrated pollution controls in Example 1  of Figure 4-6
are an example of how the waste stream might be treated prior to ultimate
disposal fay direct discharge to surface waters.  The controls are activated
sludge, filtration, and granular activated carbon.  The characteristics of
the effluent from each control  process are presented in Table 4-32 and the
estimated characteristics of the wastewater stream discharged to surface
waters by this illustrative example as well as by the other  examples  are
presented subsequently in Table 4-35.
     The activated sludge process would be designed primarily to remove
organics.  Since relatively simple organic species are involved, better than
95% removal  is expected through one or more stages.  Thiocyanate, thiosulfate,
and sulfite would be concurrently oxidized.
     Ammonia would be removed in the activated sludge process by being assim-
ilated as new cell material.  Because the nitrogen available in the composite
flow is somewhat less than that required, extra nitrogen as  ammonia would  be
added.  All  ammonia in excess of that required for cell  growth would  appear
in the effluent.  Therefore the concentration of ammonia in  the effluent
would depend on  the degree of control exercised over its addition. While
addition of ammonia representing its exact requirement is ideally possible,
in practice the  continuously varying organics concentration  in the influent
would necessitate excess  ammonia addition.
     Air or oxygen to support biological  oxidation is supplied to the reactor
under highly turbulent conditions.  This  maximizes the mass  of oxygen trans-
ferred to the water, keeps the  contaminants and microbial  floes dispersed
throughout the reactor, but provides conditions that are highly favorable  to
stripping of volatile species.   At the slightly alkaline reactor conditions
needed for optimal microorganism growth,  much of the sulfide would occur in
its potentially  volatile  form,  hydrogen sulfide (H?S).   While some of the  sul-
fide would be oxidized by direct combination with oxygen and some biologically
                                      341

-------
           TABLE  4-32.   EXAMPLE  1  - MATERIAL FLOW FOR MOBIL M SYNTHESIS BASE  PLANT  INTEGRATED  CONTROLS
                        (FIGURE  4-6)
co

Base Plant
Cyanide Wash:
Characteristic
Flow (m3/hr)
NH3
CN"
S=
S2°3
S03
SCN"
COD
BOD5
ci-
TDS
TSS


Composite Activated Sludge Filtration
Water- Methanol- Water- Methanol- Water- Methanol -
based based based based based based
*
688
92
87
63
48
12
2.5
2200
1100
1040
1900
--
449 688 449 688 449
140 10 10 10 10
5 9-35 1 9-35 1
2.6 <1 <1 <1 <1
74 <1 <1 <1 <1
18 <1 <1 <1 <1
3 <1 <1 <1 <1
3400 680 1060 680 1060
1700 35 42 35 42
1600 1040 1600 1040 1600
2900 1900 2900 1900 2900
30 30 <10 <10

Granular Activated Carbon
Water- Methanol -
based based
688 449
10 10
9-35 1
<1 <1
<1 <1
<1 <1
<1 <1
70 100
21 28
1040 1600
1900 2900
<10 <10

     *A11  concentrations are mg/L and reflect published data and engineering estimates.  Detailed
      performance data and references are contained in the Control  Technology Appendices.

-------
                                                            Section 4
                                                            Aq. Med. Int. Ex.
oxidized, the greatest fraction would probably be  stripped  from  solution.
Since this hydrogen sulfide is transferred to the  atmosphere  at  near  ground
level, even low level  emissions may cause odor problems.
     Stripping may also occur with cyanide.  At the near  neutral  conditions
found in the reactor,  nearly all the cyanide would exist  as the  potentially
volatile hydrogen cyanide species (HCN).   It is not certain how  much  cyanide
would be volatilized and how much would be oxidized biologically.  For  base
plant designs utilizing a methanol-based  cyanide wash, both the  cyanide and
sulfide concentrations in the composite wastewater stream would  be much lower
than in the water-based case resulting in less potential  for  stripping.  In
either case, if stripping of volatile species (Stream 416)  is identified as
a problem, the activated sludge reactor could be covered.  Air circulated
through the overhead space could be covered.  Air  circulated  through  the over-
head space could be routed to the boiler or to an  incinerator.
     Cyanide can be oxidized or otherwise removed  by activated sludge systems
where the cyanide occurs as part of a matrix of predominatly  organic  species.
Greater than 90% cyanide removal has been recorded in the literature  for care-
fully controlled laboratory-scale reactors.  The exact cyanide removal  that
could actually be realized in an operating system  is highly uncertain.   For
purposes of this manual, 60 to  90% removal through one or more stages of
activated sludge has been assumed.   If this removal is not sufficient or is
determined to be unattainable, much of the cyanide can be converted to the
easily degradable thiocyanate species by adding polysulfide prior to  the acti-
vated sludge process.  Polysulfide addition is not expected to be required in
this application and therefore  is not included in  cost or performance esti-
mates.   Details of polysulfide  addition are presented in Section 4.2.1  and
4.2.3.
     The activated sludge process is followed by  filtration to remove sus-
pended solids, especially cells that escape the activated sludge clarifier.
                                      343

-------
Section 4
Aq. Med. Int. Ex.
Although after filtration,  the waste stream could  possibly  be  discharged to
surface waters, it is expected that  residual/refractory  organics  that could
not be oxidized by the activated sludge process  will  remain.   Where  it  is
determined that these need  to be removed,  a granular  activated carbon system
could be added.  Granular activated  carbon would also remove some trace metals
if these are present.
     Example 2.  Integrated pollution controls  in  Example 2 are illustrative
of those that might be used to treat the waste  stream prior to ultimate dis-
posal by surface impoundment.  Estimated characteristics of the wastewater
stream discharged to surface impoundment are presented in Table 4-35.   The
controls are activated sludge and cooling  tower  concentration.  Effluent char-
acteristics for each control are presented in Table 4-33.
     All aspects of the activated sludge process are  identical to those pre-
sented in Example 1.  Following treatment  by activated sludge, the waste
stream could possibly be suitable for discharge  to a  surface impoundment;
however, the capital requirements of surface impoundment can be decreased
greatly by reducing the volume of water to be held.   The cooling tower  would
be used for this purpose with the waste stream  combined  with raw water  (or
recycle water) to supply the cooling tower makeup.
     Cooling tower concentration is  expected to  be very attractive since this
system is a capital requirement of the base plant  regardless of its  source  of
makeup water.  Problems associated with using low  quality makeup water  to the
cooling tower have been discussed elsewhere (Section  4.2.1).   Fouling  by
biological solids escaping the activated sludge  process  or  growing within the
tower can be controlled by biocides.  Alternatively,  the biological  solids  as
well as any other suspended material can be removed by filtering the activated
sludge effluent.  Where scaling such as by calcium sulfate  or  corrision, par-
ticularly by chloride, are problems, various pretreatments  would be  needed.
However, at some point the cost of additional treatment to  prepare the  waste
stream suitable for cooling tower concentration  would exceed any benefit of
                                      344

-------
      TABLE  4-33.   EXAMPLE  2  - MATERIAL  FLOW  FOR  MOBIL  M  SYNTHESIS  BASE  PLANT INTEGRATED CONTROLS
                              (FIGURE 4-6)

Base Plant
Cyanide Wash:
Characteristic*
Flow (m3/hr)
NH3
CN"
S=
£ S2°3
en =
so3
SCN"
COD
BOD5
cr
TDS
TSS


Composite
Water- Methanol -
based based
688
92
87
63
48
12
2.5
2200
1100
1040
1900
--
449
140
5
2.6
74
18
3
3400
1700
1600
2900
--


Activated Sludge Cooling Tower Concentration
Water- Methanol- Water- Methanol -
based based based based
688 449 180
10 10 38f
9-35 1 34-130*
<1 <1 <1
<1 <1 4
<1 <1 4
<1 <1 4
680 1060 2600
35 42 130
1040 1600 3900
1900 2900 7200
30 30 110
180
25f
2*
<1
2
2
2
2650
105
4000
7200
75

*A11 concentrations are mg/L and reflect published data and engineering estimates.  Detailed
 performance data and references are contained in the Control Technology Appendices.
tNo ammonia volatilization  is assumed.
*Loss by volatilization/biological  oxidation uncertain - no losses assumed.

-------
Section 4
Aq. Med. Int. Ex.
reducing its volume for downstream handling.   The feasibility of this  system
will, therefore, have to be determined on an  individual  case  basis  once  the
compositions of the waste streams are known with some certainty.
     Blowdown from the cooling tower will  contain the original  constituents
in the makeup stream but concentrated by a factor that is  the ratio of makeup
flow to blowdown.  Some losses will  result from volatilization or entrainment
in the drift (Stream 419), but the exact amounts are uncertain and  must  be
evaluated on an individual case basis.  The blowdown stream would be routed
to ultimate disposal by surface impoundment.
     Example 3.  Integrated pollution controls in Example  3 of Figure  4-6 are
illustrative of those that might be utilized  prior to ultimate disposal  of
the wastewater stream by a combination of recycle and deep well  injection.
Estimated characteristics of the wastewater stream that is deep well injected
are summarized in Table 4-35.  The controls are activated  sludge, cooling
tower concentration, forced evaporation, and  incineration. Effluent charac-
teristics for each control process are presented in Table  4-34.
     Example 3 differs from Example 2 only in the handling of the cooling
tower blowdown.  The blowdown is routed to forced evaporation where the  orig-
inal  waste stream constituents are concentrated into a low flow stream.  Cer-
tain characteristics of the waste stream may  limit the usability of forced
evaporation; these considerations have been addressed in Section 4.2.1.  The
forced evaporation overhead is virtually free of contaminants and would  be
recycled for use as high quality makeup water within the facility.   The
forced evaporation concentrate would be deep  well injected (or alternatively
surface impounded) after it has been incinerated to remove high concentrations
of organics that would otherwise foul the injection formation.
     Costs for integrated pollution controls  shown in Figure  4-6 are presented
in Table 4-36.  All costs depend on the type  of cyanide wash  used in the base
plant design.  For each integrated example, costs are presented in  total

                                     346

-------
          TABLE 4-34.  EXAMPLE 3 -  MATERIAL  FLOW FOR MOBIL  M SYNTHESIS  BASE PLANT INTEGRATED CONTROLS
                       (FIGURE 4-6)

Base Plant
Cyanide Wash :
Cooling Tower
Composite Activated Sludge Concentration Forced Evaporation Incineration
Water- Methanol- Water- Methanol- Water- Methanol- Water- Methanol- Water- Methanol -
based based based based based based based based based based
Characteristic*
Flow (m3/hr)
NH3
CN"
S=
S2°3
S03
SCN"
COD
BODC
0
cr
TDS
TSS
688
92
87
63
48
12
2.5
2200
1100
1040
1900
--
449
140
5
2.6
74
18
3
3400
1700
1600
2900
--
688 449 180
10 10 38
9-35 1 34-130
<1 <1 <1
<1 <1 4
<1 <1 4
<1 <1 4
680 1060 2600
35 42 130
1040 1600 3900
1900 2900 7200
30 30 110
180
25
2
<1
2
2
2
2650
105
4000
7200
75
18
380
340-1300
<1
40
40
40
26000
1300
39000
72000
1100
18
250
20
<1
20
20
20
26500
1050
40000
72000
750
18
0.2
0.3-1
<1
40
40
0.04
26
1
39000
72000
—
18
0.1
0.02
<1
20
20
0.02
26
1
40000
72000
—

*A11  concentrations are mg/L and reflect published data and engineering estimates.  Detailed
 performance data and references are contained in the Control  Technology Appendices.

-------
                        TABLE 4-35.   ESTIMATED CHARACTERISTICS OF WASTEWATER STREAMS DISCHARGED
                                     TO  ULTIMATE DISPOSAL - MOBIL M SYNTHESIS CASE
00
Integrated Controls
Ultimate Disposal :
Base Plant Cyanide
Characteristic*
Flow (m3/hr)
NH3
CN"
S=
S2°3
S03
SCN"
COD
BOD5
cr
TDS
TSS
Example 1 Example 2
Surface Surface
Waters Impoundment
Wash: Water Methanol Water Methanol
688 449 180
10 10 38
9-35 1 34-130
<1 <1 <1
<1 <1 4
<1 <1 4
<1 <1 4
70 100 2600
21 28 130
1040 1600 3900
1900 2900 7200
<10 <10 110
180
25
2
<1
2
2
2
2650
105
4000
7200
75
Example 3
Deep Well
Injection
Water Methanol
18
0.2
0.3-1
<1
40
40
0.04
26
1
39000
72000
"
18
0.1
0.02

-------
             TABLE 4-36.  COSTS OF INTEGRATED  CONTROL EXAMPLES - MOBIL M SYNTHESIS  CASE
Total Capital Total Annual ized % of Base Plant
Investment* Cost* Capital Cost
Base Plant Cyanide Wash
Integrated Control Example
Example 1
Control s :

oo Additional
10 Control:
Example 2
Controls:

Example 3
Control s :




Activated Sludge
Filtration

Granular Activated Carbon

Activated Sludge
Surface Impoundment

Activated Sludge
Forced Evaporation
Incineration
Deep Well Injection
Ultimate Disposal Water-
Technique based
Surface waters 19.5
18.3
1.2

3.1
Surface Impoundment 26.6
18.3
8.3
Deep well injection 39.4
18.3
13.7
4.8
2.6
Methanol -
based
19.1
18.3
0.78

3.0
26.6
18.3
8.3
39.4
18.3
13.7
4.8
2.6
Water-
based
6.5
3.9
2.6

1.5
5.6
3.9
1.7
10.3
3.9
3.5
2.3
0.56
Methanol- Water-
based based
5.7 1.6
3.9
1.8

1.6
5.6 2.2
3.9
1.7
10.3 3.2
3.9
3.5
2.3
0.56
Methanol -
based
1.6




2.2


3.2




*Mil1 ion dollars

-------
Section 4
Aq. Med. Int. Ex.
capital  investment and total  annualized cost for both individual  controls  and
the entire integrated system; and percent of base plant cost for  the entire
integrated system.  Costs of additional  controls that are possibly applicable
have also been included.
                                      350

-------
                                                             Section 4
                                                             Aq.  Med.  Int.  Ex.
4.2.4.2  Treatment of Waste Streams from Base Plants Producing
         Crude Methanol
     The integrated wastewater control examples presented thus far have been
designed to treat a highly organic waste stream from a synthesis section (F-T
or Mobil M) combined with strictly inorganic waste streams from the gasifier
section.  The resulting composite flow is highly amenable to treatment by
a conventional activated sludge process;  the high organic concentrations are
diluted to an appropriate level for biological oxidation, and the inorganic
species from the gasifier wastewaters are biological oxidized, utilized as
growth nutrients and thereby assimilated as new cell material, or are other-
wise removed.
     This water management strategy is not usable for K-T facilities where
crude methanol is produced since no. high volume waste stream with orqanics
equivalent to that generated by F-T or Mobil M synthesis would exist.  The
composite waste stream would consist exclusively of inorganic species, partic-
ularly ammonia,  cyanide, thiocyante, and a variety of reduced  sulfur species.
There is no known precedent for treating a waste stream having significant
concentrations of each of the cited species.  Due to these unique character-
istics, some novel treatment approaches are worth considering.  Two examples
of integrated controls are presented  in Figure 4-7 for cases where ultimate
disposal is by discharge to surface waters, and examples for cases where
ultimate disposal is by surface impoundment or deep well injection are pre-
sented  in  Figure 4-8.  Each addresses the two base plant designs of cyanide
removal by a water or  methanol wash.
     Cyanide can be partially destroyed in  biox processes.   Microorganisms
in an activated sludge process can be acclimated  to oxidize  cyanide but only
where the  cyanide is part of a larger matrix  dominated by biodegradable
organics.  However, cyanide can be removed  from  stricly  inorganic wastewater
streams by converting  it to thiocyanate then  oxidizing the  thiocyanate.
                                      351

-------
 EXAMPLE 4
 CYANIDE
 WASH
 WATER*
 	1
 STREAM
 215
POLYSULFIDE
ADDITION
 COMPRESSION CONDENSATE
 STREAM 211

 GAS COOLING/DUST
 REMOVAL SLOWDOWN
 STREAM 210
                     FLOW
                     EQUALIZATION
             DISCHARGE
i	1 TO SURFACE

'CHEM.CAL  ! WATERS .
  OXIDATION |         r

I	I
 EXAMPLE 5
 CYANIDE
 WASH
 WATER*
 STREAM
 215
 COMPRESSION CONDENSATE
 STREAM 211

 GAS COOLING/DUST
 REMOVAL SLOWDOWN
                                                       ACTIVATED  |_J  FILTRA- |_J
                                                       SLUDGE     |~n  TION    In OXIDATION

                                                      	I  I	I  I	1
                                                                                           DISCHARGE
                                                                                           TO SURFACE
                                                                                           WATERS
 STREAM 210


"This stream exists only for base plants where cyanide is removed from the raw gas by a water-based wash.
Figure  4-7.   Integrated control  examples  for base plants  producing crude  methanol  - discharge to  surface
               waters

-------
      EXAMPLE 6
GO
cn
OJ
      STREAM 215
      COMPRESSION CONDENSATE
      STREAM 211

      GAS COOLING/DUST REMOVAL SLOWDOWN
     STREAM 210

     EXAMPLE 7

     CYANIDE
     WASH
     WATER"

     STREAM 215
      COMPRESSION CONDENSATE
STREAM 211

GAS COOLING/DUST REMOVAL SLOWDOWN
      STREAM 210
      EXAMPLE 8
      CYANIDE
      WASH
      WATER*
      STREAM 215
      COMPRESSION CONDENSATE
      STREAM 211

      GAS COOLING/DUST REMOVAL SLOWDOWN
      STREAM 210
                                                                                                                         DISCHARGE TO
                                                                                                                         SURFACE
                                                                                                                         IMPOUNDMENT
                             CLARIFIER I	>|

                            I	1
                                                                                                                             A ALTERNATE
                                                                                                                             T r
                                                                                                                               DISPOSAL
                                                                                                                                   DISCHARGE
                                                                                                                                   TO DEEP WELL
                                                                                                                                   INJECTION
      'This stream exists only for base plants where cyanide is removed from the raw gas by a water-based wash.
         Figure 4-8.   Integrated control  examples  for  base plants producing crude  methanol  -  discharge  to
                         surface impoundment  or deep  well  injection

-------
Section 4
Sq. Med.  Int.  Ex.
Laboratory scale studies have demonstrated that  thiocyanate  can  be  biologi-
cally oxidized even where it and ammonia  are  the only  usable growth substrates
for the microorganisms.   Sulfur, when  added as polysulfide,  would drive  the
conversion.
     Assuming excess polysulfide addition, the influent  and  desired effluent
concentrations of cyanide determine the reaction time  required for  the thio-
cyanate conversion.  In  general, the effluent concentration  is more critical
since large increases in reaction time are required to achieve small  decreases
in the effluent cyanide  concentration  at  effluent levels less than  about 10
mg/L cyanide.  Therefore, polysulfide  addition does not  appear to be economical
for waste streams such as the gas cooling/dust removal blowdown  (Stream  210)
and the compression condensate (Stream 211) having less  than 10  mg/L cyanide.
However, both the cyanide concentration and loading of the cyanide  wash  water
(Stream 215) are expected to be well over an  order of magnitude  greater  than
that of the other two streams.  By treating the  cyanide  wash water  with  poly-
sulfide separately, the reaction can be accomplished under kinetically more
favorable conditions than if all three streams  had first been combined.   Since
the cyanide wash water would then be combined with the gas-cooling/dust  re-
moval blowdown and compression condensate and since both of these streams con-
tain cyanide at about the 10 mg/L level, the cyanide wash water  would be
treated by polysulfide addition to a corresponding level.  If it is desired
to decrease the cyanide concentration  in the composite stream to a  lower level,
downstream controls could be applied.
     For each  integrated control example  (Figures 4-7 and 4-8)  where cyanide
is removed from the base plant  by a water wash,  polysulfide addition would
be desirable as a  pretreatment  step.   Characteristics of the cyanide wash water
(Stream 215) before and after polysulfide addition are  presented in Table 4-37.
The characteristics of  the  compression condensate  (Stream 211)  and of the gas
cooling/dust removal  blowdown  (Stream  210) are  also presented in Table 4-37
                                     354

-------
            TABLE 4-37.   CHARACTERIZATION  OF  MAJOR  STREAMS  TO BE COMBINED FOR TREATMENT - CRUDE METHANOL
                         PRODUCTION  CASE
OJ
en
on

Cyanide
Nash
Water
Characteristic* Stream 215
Flow (m3/hr) 239
NH3
CN" . 241
S= 176
S2°3
S03
SCN"
cr
TDS
Gas Cooling/
Cyanide Wash Dust Removal
Pretreated with Slowdown
Polysulfide Stream 210
239 322
360 156
8 7
<1 1
103
25
495 4
2111
4000
Compression
Condensate
Stream 211
17.4
735
8.9
48.7
6.3
--
14
2200
--
Composite
Base Plant Cyanide Wash
Water- Methane! -
Based1" Based*
578
260
7.5
2
58
14
210
1200
2200
339
190
7
3.5
98
24
4.5
2100
3800

      *A11  concentrations are mg/L.
      ^Combined streams:  cyanide wash water pretreated by polysulfide addition,
                          gas cooling/dust removal  blowdown, and compression condensate.
      ^Combined streams:  gas cooling/dust removal  blowdown and compression condensate.

-------
Section 4
Aq. Med. Int. Ex.
as are the characteristics of the composite flows  from base plants  using  a
water-based or methanol-based cyanide wash.
     As was the case for integrated pollution controls for a base plant having
a Mobil M or F-T synthesis section, each of the examples (Figures 4-7 and 4-8)
for the subject crude methanol production case would use flow equalization.
     Example 4, Figure 4-7.  Integrated pollution  controls in Example 4 of
Figure 4-7 are illustrative of those that might be utilized prior to ultimate
disposal of the composite wastewater stream by direct discharge to  surface
waters.  The controls are activated sludge, denitrification, and filtration.
Characteristics of the effluent from each control  are summarized in Table 4-38,
and the estimated characteristics of the wastewater stream discharged to  sur-
face waters by this illustrative example as well  as by the other examples
presented in Figures 4-7 and 4-8 are presented in  Table 4-43.
     In the activated sludge process, both ammonia and thiocyanate  would  be
oxidized.  An oxidation product of each of these species is nitrate; it would
be biologically reduced to molecular nitrogen in a following denitrification
reactor.
     As discussed for Example 4 of Figure 4-6, it  may be advisable  to cover
and vent to an incinerator both the polysulfide and the nitrification reactors
to prevent loss of the potentially volatile hydrogen sulfide and hydrogen
cyanide species.  Following denitrification, loss  of volatile species is  not
expected to present problems.
     Following deniitrification, the waste stream  is filtered to remove sus-
pended solids that escape the denitrification clarifier.  At this point,
the waste stream could possibly be discharged to surface waters.  If addi-
tional treatment is desirable, particularly to further reduce the cyanide con-
centration, chemical oxidation can be included.
     Example 5, Figure 4-7.  Integrated pollution  controls in Example 5 of
Figure 4-7 are also aimed toward ultimate disposal of the composite wastewater
                                     356

-------
      TABLE 4-38.   EXAMPLE 4 - MATERIAL FLOW FOR CRUDE METHANOL PRODUCTION BASE PLANT  INTEGRATED CONTROLS

                               (FIGURE 4-7)
co
en

Base Plant
Cyanide Wash:
Composite
Water- Methanol -
based based
Nitrification Denitrification Filtration
Water- Methanol- Water- Methanol- Water- Methanol -
based based based based based based
Characteristic*
Flow (m3/hr)
NH3
CN"
S=
S90^
u. O
S03
SCN"
ci-
TDS
NO~-N
TSS
578
260
7.5
2
58
14
210
1200
2200
2200 >3800 >2200 >3800 >2200 >3800
245 140 24 15 24 15
<50 <50 30 30 <10 <10

      *A11  concentrations  are  mg/L and  reflect  published  data  and  engineering estimates.   Detailed

       performance  data  and  references  are  contained  in the  Control  Technology Appendices.

-------
  TABLE  4-39.   EXAMPLE  5  -  MATERIAL  FLOW FOR CRUDE METHANOL  PRODUCTION BASE  PLANT  INTEGRATED  CONTROLS
               (FIGURE  4-7)

Base Plant
Cyanide Wash :
Characteristic*
Flow (m3/hr)
NH3
CN"
S=
s?o"
CO *- °
on =
09 S03
SCN"
ci-
TDS
NO--N
TSS


Composite
Water- Methanol -
based based
578
260
7.5
2
58
14
210
1200
2200
--
--
339
190
7
3.5
98
24
4.5
2100
3800
--
--


Ion Exchange Activated Sludge Filtration
Water- Methanol- Water- Methanol- Water- Methanol -
based based based based based based
578
12
7.5
2
58
14
210
>1200
>2200
--
--
339 578 -- 578
12 12 -- 12
7 7.5 — 7.5
3.5 <1 -- <1
98 <1 -- <1
24 <1 — <1
4.5 <1 -- <1
>2100 >1200 -- >1200
>3800 >2200 — >2200
60 — 60
30 - <10

*A11  concentrations are mg/L and reflect published data and engineering estimates.  Detailed
 performance data and references are contained in the Control  Technology Appendices.

-------
                                                            Section  4
                                                            Aq.  Med.  Int.  Ex.
stream by direct discharge to surface waters.   Estimated characteristics  of
the wastewater stream discharged to surface waters  are presented  in  Table
4-43.  For the methanol-based cyanide wash case,  ion exchange is  the primary
control.  Activated sludge, filtration,  and chemical oxidation can also be
included if additional treatment is desired.  Estimated performance  of indi-
vidual controls is presented in Table 4-39.
     As is the case for all examples in Figure 4-7  and 4-8, where the cyanide
wash water occurs, it is pretreated by polysulfide  addition.  This reaction
must be completed at alkaline conditions, but downstream pollution control  proc-
esses require near neutral or only slightly alkaline conditions.   If the
acidity of the streams with which the cyanide wash  would be combined is not
sufficient to produce a composite flow having a stable, near neutral condition,
the cyanide wash should be first neutralized by acid addition.  In any case,
under neutral conditions, residual polysulfide may precipitate.  This pre-
cipitate is not expected to cause significant problems with the nitrification
process of Example 4, but for the following ion exchange process of this
example, plugging and fouling would result.  For purposes of this manual, the
cyanide wash  is assumed to be neutralized following polysulfide addition so
that, if needed, a filter or clarifier can  be dedicated separately to this
stream.
      Ion exchange using an exchange resin of clinoptilolite would remove
ammonium ions from the waste stream and replace them with sodium  ions.  All
known experience to date with this system is associated with removing ammonia
from  low-strength municipal wastewaters.  However,  preliminary, EPA supported
studies strongly suggest that the process would be  equally feasible for a
waste stream  having the characteristics of  the K-T  composite stream.
      For base plant cases using a methanol-based cyanide wash, the composite
wastewater stream may be suitable for discharge to  surface waters following
ion  exchange.   If additional treatment is determined necessary, chemical oxi-
dation  can be included.  For the case of  the water-based cyanide  wash, a
                                     359

-------
Section 4
Sq. Med.  Int.  Ex.
biological treatment process followed by a filter would be  included  following
ion exchange to oxidize the thiocyanate that had been  converted  from cyanide
by upstream polysulfide addition.
     Example 6. Figure 4-8.  Examples of integrated controls  presented  in
Figure 4-8 are illustrative of cases  where the ultimate discharge  technique
is either surface impoundment or complete recycle with deep well  injection.
Estimated characteristics of the wastewater stream discharged to surface  im-
poundment or deep well injected are presented in Table 4-43 for  each of the
three examples.  Each example utilizes cooling tower concentration to reduce
the volume of water to be handled for disposal.  The cooling  tower blowdown
would be disposed of by surface impoundment, or if recovery of water for
reuse is desired, the blowdown would  be routed to forced evaporation.  The
forced evaporation overhead would contain only trace amounts  of  contaminants
and would be recycled for use as makeup water within the facility.  Concen-
trate from  this process would be disposed of by deep well injection or sur-
face impoundment.
     Since cooling tower concentration is common to each of the  examples  in
Figure 4-8, upstream control processes are determined  by the  requirements of
this step.  Problems with scaling,  fouling, and corrosion that may limit  the
feasibility of cooling tower concentration have been discussed in  Section
4.2.1.   It has been assumed that no extraordinary pretreatments  would be
required to correct these problems.  Control processes are  assumed only to
remove volatile species that may be lost to the atmosphere  during  the con-
centration process.
     In general, it is not certain  how much of a particular volatile species
would be lost to the atmosphere during cooling tower concentration.   Addi-
tionally, different losses may be acceptable at different locations.  It  is
assumed, however, that the concentration of cyanide in the  cooling tower
makeup would have to be at low levels since at the expected pH operating
range nearly all the cyanide would  exist as the potentially volatile hydrogen

                                     360

-------
                                                             Section  4
                                                             Aq.  Med.  Int.  Ex.
cyanide species.  Therefore, all cases where cyanide is removed from the base
plant by a water wash, polysulfide addition is included as a  pretreatment  step.
     Example 6 represents a case where no treatment of the composite waste-
water stream is included prior to its being used as cooling tower makeup.
In some facilities,  this approach might be feasible; however, this approach
is not very likely due to expected volatilization of ammonia  and sulfide in
the cooling tower.  Estimated characteristics of the composite wastewater
stream following cooling tower concentration and forced evaporation are pre-
sented in Table 4-40.
     Example 7. Figure 4-8.  It is very likely that the composite wastewater
stream would be treated for removal of volatile species prior to being routed
to cooling tower makeup.  Example 7 utilizes activated sludge.  Estimated
characteristics of the subject wastewater stream through all  control processes
are presented in Table 4-41.  All other details are identical to those pre-
sented in Example 4 of Figure 4-7.  Where ft is determined that even higher
quality makeup water is desired, filtration can be added to remove suspended
solids and chemical  oxidation added to oxidize ammonia, cyanide, and other
remaining reduced species.
     Example 8, Figure 4-8.  Like Example 7, Example 8 prepares the subject
wastewater stream for use as makeup to the cooling tower.  The control pro-
cess for this example is ion exchange.  Details are identical to those pre-
sented in Example 5 of Figure 4-7.  Where additional treatment is needed,
chemical oxidation could be added.  Characteristics of the subject wastewater
stream through all control processes are presented in Table 4-42.
     Costs for integrated pollution controls for each example presented in
Figures 4-7 and 4-8 are summarized in Table 4-44.  All costs  depend on the
type of cyandie wash used in the base plant design.  For each integrated
example, costs are presented as total capital investment and  total annualized
cost for both individual controls and the entire integrated system; and as a

                                      361

-------
Section 4
Aq. Med. Int. Ex.
percentage of base plant cost for the entire integrated system.  Costs of

additional controls that are possibly applicable are also presented.
                                     362

-------
   TABLE 4-40.  EXAMPLE 6 - MATERIAL FLOW FOR CRUDE METHANOL PRODUCTION BASE  PLANT  INTEGRATED  CONTROLS
                (FIGURE 4-8)

Base Plant
Cyanide Wash:
Characteristic*
Flow (m3/hr)
NH3
CN-
S=
GO S 0=
S 2°3
S03
SCN"
ci-
TDS
Composite
Water- Methanol-
based based
578
260
7.5
2
58
14
210
1200
2200
339
190
7
3.5
98
24
4.5
2100
3800
Cooling Tower
Concentration
Water- Methanol-
based based
161
933
27
<1
205
50
740
4500
7900
161
400
15
<1
205
50
8
4400
8000
Forced Evaporation1"
Water- Methanol-
based based
16
9330
270
<1
2050
500
7400
45000
79000
16
4000
150
<1
2050
500
80
44000
80000

*A11 concentrations are mg/L and reflect published data and engineering estimates.  Detailed
 performance data and references are contained in the Control Technology Appendices.
^'Required for recycle only.

-------
      TABLE 4-41.  EXAMPLE  7  - MATERIAL FLOW FOR CRUDE METHANOL PRODUCTION BASE PLANT  INTEGRATED  CONTROLS
                   (FIGURE  4-8)
GO
cr>

Base Plant
Cyanide Wash :
Characteristic*
Flow (m3/hr)
NH3
CN"
s=
S2°3
S03
SCN"
Cl"
TDS
NO~-N
TSS
Composite Activated Sludge
Water- Methanol- Water- Methanol -
based based based based
578
260
7.5
2
58
14
210
1200
2200
-
•"
339 578 339
190 10 7
7 7.5 7
3.5 <1 <1
98 <1 <1
24 <1 <1
4.5 <1 <1
2100 1200 2100
3800 >2200 >3800
245 140
30 30
Cooling Tower
Concentration
Water- Methanol -
based based
161
36
27
<1
4
4
4
4300
>7900
880
110
161
15
15
<1
2
2
2
4400
>8000
300
60
Forced
Water-
based
16
360
270
<1
40
40
40
43000
> 79000
8800
1100
Evaporation*
Methanol-
based
16
150
150
<1
20
20
20
44000
> 80000
3000
600

      *A11  concentrations  are  mg/L  and  reflect  published  data  and  engineering  estimates.   Detailed
       performance  data  and  references  are contained  in the  Control  Technology Appendices.
      ^Required  for recycle  only.

-------
  TABLE 4-42.   EXAMPLE  8 -  MATERIAL  FLOW  FOR  CRUDE  METHANOL PRODUCTION BASE PLANT INTEGRATED CONTROLS
               (FIGURE  4-8)
Composite
Base Plant Water- Methanol-
Cyanide Wash: based based
Characteristic*
Flow (m3/hr) 578
NH3 260
CN~ 7.5
S= 2
# S2°3 58
01 J
S03 14
SCN" 210
cr 1200
TDS 2200
339
190
7
3.5
98
24
4.5
2100
3800
Ion Exchange
Water- Methanol-
based based
578
12
7.5
2
57
14
210
>1200
>2200
339
12
7
3.5
98
24
4.5
>2100
>3800
Cooling Tower
Concentration
Water- Methanol-
based based
161
43
27
<1
205
50
740
>4300
>7900
161
25
15
<1
205
50
8
>4400
>8000
Forced Evaporation"1"
Water- Methanol-
based based
16
430
270
<1
2050
500
7400
> 43000
> 79000
16
250
150
<1
2050
500
80
>45000
>80000

*A11 concentrations are mg/L and reflect published data and engineering estimates.  Detailed
 performance data and references are contained in the Control Technology Appendices.
''"Required for recycle only.

-------
      TABLE 4-43.  ESTIMATED CHARACTERISTICS OP WASTEWATER STREAMS  DISCHARGED TO ULTIMATE
                   DISPOSAL  - CRUDE METHANOL PRODUCTION CASE








CO
en
en


Integrated Controls
Figure:
Ultimate Disposal:
Base Plant
Cyanide Wash:
'Characteristic*
Flow (m3/hr)
NH3
CN-
S=
S2°3
S0°
SCIT
ci-
TDS
N03"-N
TSS
: Example 4
4-7
Surface Waters
Water Methanol
578 339
8 6
7.5 7
-1 <1
<1 <1
•1 <1
1 2100
.2200 >3800
60
<10
Example 6
4-8
Surface
Impoundment
Water Methanol
161 161
933 400
27 15
<1 <1
205 205
50 50
740 8
4500 4400
7900 8000
-
-
Example 6
4-8
Deep Well
Injection
Water
16
9330
270
<1
2050
500
7400
45000
79000
-
-
Methanol
16
4000
150
<1
2050
500
80
44000
80000
-
-
Example 7
4-8
Surface
Impoundment
Water
161
36
27
<1
4
4
4
4300
.7900
880
110
Methanol
161
15
15
<1
2
2
2
4400
>8000
300
60
Example 7
4-8
Deep Well
Injection
Water
16
360
270
<1
40
40
40
43000
.79000
8800
1100
Methanol
16
150
150
<1
20
20
20
44000
.80000
3000
600
Example 8
4-8
Surface
Impoundment
Water
161
43
27
<1
205
50
740
.4300
.7900
-
--
Methanol
161
25
15
<1
205
50
8
.4400
.8000
—
-
Example 8
4-8
Deep Well
Injection
Water
16
' 430
270
43000
>79000
-
-
Methanol
16
250
150
<1
2050
500
80
>45000
>80000
--
-
All concentrations are mg/L.

-------
 TABLE 4-44.   COSTS OF INTEGRATED  CONTROL EXAMPLES - CRUDE  METHANOL
               PRODUCTION CASE
Integrated Control Example
Example 4, Figure 4-7
Controls: Polysulfide
Activated Sludge
Dem trif i cation
Filtration
Additional
Control: Chemical Oxidation
Example 5, Ficure 4-7
Controls: Polysulfide
Ion Exchange
Activated Sludge
Filtration
Additional
Controls: Filtration
Chemical Oxidation
Example 6, Figure 4-8

Controls: Polysulfide
Surface Impoundment
Forced Evaporation
Deep Well Injection
Example 7> Figure 4-8

Controls: Polysulfide
Activated Sludge
Surface Impoundment
Forced Evaporation
Deep Well Injection
Additional
Controls. Filtration
Chemical Oxidation
Example 8, Figure 4-8

Controls: Polysulfide
Ion Exchange
Surface Impoundment
Forced Evaporation
Deep Well Injection
Additional
Controls: Filtration
Chemical Oxidation
Total Capital
Investment*
Ultimate Disposal Water- Methanol-
Method based based
Surface Waters 19.8
0.13
12.6
6.1
1.0

0 72
Surface Waters 18.8
0.13
12.9
4 8
1 0

0.42
0.72
Surface Impoundment 8.4
Deep Well Injection 16.4
0.13
8.3
13 7
2.6
Surface Impoundment 21.0
Deep Well Injection 29 0
0.13
12.6
8.3
13 7
2.6

1.0
0 72
Surface Impoundment 21.4
Deep Well Injection 29.3
0.13
12.9
8.3
13.7
2.6

0.42
0.72
10 5
-
6.7
3,2
0.59

0.16
8.3
-
8.3
-
-

-
0.16
8.3
16.3
-
8.3
13.7
2.6
15.0
23.0
-
6.7
8.3
13.7
2.6

0.59
0.16
16.6
24.6
-
8.3
8.3
13.7
2.6

-
0.16
Total Annual i zed Percent of Base
Cost* Plant Cost
Base Plant Cyanide Wash
Water- Methanol- Water- Methanol-
based based based based
5.8
0.73
2.7
2.2
0.22

0.23
5.6
0.73
3.5
1.1
0.22

0.11
0.23
2.4
4.8
0.73
1.7
3.5
0.56
5.1
7.5
0.73
2.7
1 7
3.5
0.56

0.22
0.23
5.9
8.3
0.73
3.5
1.7
3.5
0.56

0.11
0.23
2.6 1.8
-
1.5
0.98
0.15

0.12
1.8 1.7
-
L.8
-


-
0.35
1.7 0.8
4.1 1.5
-
1.7
3.5
0.56
3.2 1.9
5.6 2.5
-
1.5
1.7
3.5
0.56

0.15
0.12
3.5 1.9
5.9 2.6
-
1.8
1.7
3.5
0.56

-
0.35
0.9






0.7







0.8
1.5




1.4
2.0








1.5
2 2








Million dollars
                                     367

-------
Section 4
Aq. Med. Int. Ex.
4.2.4.3  Treatment of Waste Streams from Base Plants Producing Fuel Grade
         Methanol	
     For base plant cases where fuel grade methanol is produced, an organic
waste stream would be generated by the methanol distillation step.  However,
when this waste stream is combined with gasification wastewaters, the total
stream would probably not contain a high enough organic loading to be handled
by integrated controls analogous to those of the F-T and Mobil M synthesis
cases.  Instead,  controls would be similar to those in the  crude methanol case
with some modifications.  Appropriate modifications of applicable  integrated
control  examples  of Figures 4-7 and 4-8 are considered in this  section.
     Example 4, Figure 4-7.  The integrated controls presented in Example 4 of
Figure 4-7 would be applicable to base plant cases where fuel  grade methanol
is produced.  For base plant designs where cyanide is removed from the raw gas
by a water-based wash, the methanol  distillation condensate (Stream 229) could
be routed to the denitrification reactor to provide the source of organics
for reduction of nitrate to molecular nitrogen.  For base plant designs where
cyanide is removed by a methanol-based wash, the organic loading of the metha-
nol distillation condensate would exceed that needed by the denitrification
reactor.  The excess could be routed upstream to the nitrification reactor.
In either case, capital costs are expected to change by little, but annualized
costs would decrease by about $814,000 and $296,000 for the two respective
cases.
     Example 5, Figure 4-7.  Example 5 of Figure 4-7 would be applicable to
plants producing fuel  grade methanol, but unlike the crude methanol case dis-
cussed earlier, the activated sludge process would be needed for both the
water- and methanol-based cyanide wash cases.  The methanol distillation
condensate (Stream 229) would be routed to the activated sludge process, and
most of the nutrient requirements of this biological system would be met by
bleeding ammonia through the upstream, clinoptilolite-based ion exchange
process.

                                     368

-------
                                                            Section 4
                                                            Aq. Med. Int. Ex.
     Example 6, Figure 4-8.   For Example 6  of Figure 4-8 to be applicable to
fuel  grade methanol  plants,  an activated sludge system would probably have to
be added.  This example would then be essentially identical  to the following,
Example 7.
     Example 7, Figure 4-8.   Example 7 of Figure 4-8 would be directly appli-
cable to base plants producing fuel  grade methanol.  The methanol  distillation
condensate (Stream 229) could be routed to the activated sludge reactor.
Capital and annualized costs would be affected only slightly.
     Example 8, Figure 4-8.   To be applicable to base plants producing fuel
grade methanol, an activated sludge reactor would be added to Example 8 of
Figure 4-8 to follow the ion exchange process.  The methanol distillation con-
densate (Stream 229) could be routed to the activated sludge reactor, and most
nutrient requirements for this system would be met by bleeding some ammonia
through the upstream ion exchange process.  Capital and annualized cost changes
would be reflected by the requirements of the added activated sludge process.
                                      369

-------
Section 4
Solid Waste Management
4.3  SOLID WASTE MANAGEMENT
     Many solid waste streams including ashes and sludges are generated in a
K-T based indirect liquefaction facility.  The available control  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 K-T indirect liquefaction
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.  Be-
cause of this, solid waste management at a K-T indirect liquefaction facility
is not an isolated issue but rather an element in the total  program for pollu-
tion control.
     The sources and factors affecting the characteristics of the solid waste
streams generated in K-T-based indirect liquefaction facilities are summarized
in Table 4-45.  Of the streams listed, dewatered dust from gasification opera-
tion is by far the largest volume stream.  Depending on the  synthesis process
used, it comprises 45% to 64% of the total solid waste generated  from the plant.
Flue gas desulfurization (FGD) sludge from a lime/limestone  process and gasifier
slag are the next largest volume streams, comprising up to 35% of the total
waste generated.
     Coal  type has considerable impact on the characteristics of  the solid
wastes generated, and thus the control required.  Major coal  properties affect-
ing the solid waste control  approaches include: ash content,  sulfur content,
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.
     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

                                      370

-------
   TABLE 4-45. SUMMARY OF SOLID WASTE STREAMS FROM K-T BASED INDIRECT
               LIQUEFACTION FACILITIES
       Stream
Pollutants of
Potential Concern
Factors Affecting Waste
Stream Characteristics
From Main Process Train

Quenched Gasifier Slag
(Stream 207)
Dewatered Gasifier Dust
(Stream 209)

Spent Shift Catalyst
(Stream 217)
Leachable trace
elements, inorganic
compounds
Leachable trace
elements
Feed coal  characteristics,
gasifier operating condi-
tions quench water
characteristics.

Catalyst composition,
life
Spent Sulfur Guard
(Stream 218)
Leachable trace
elements
Sulfur guard composition,
AGR effluent gas
characteristics.
Spent Methanation
 Catalyst (Stream 238)
Spent NOX Reduction
 Catalyst (Stream 212)

Spent F-T Catalyst
(Stream 222)
Spent Methanol Catalyst
(Stream 227)
Spent Mobil  M Catalyst
(Stream 232)

From Auxiliary Processes

Boiler Bottom Ash
(Stream 304)
Raw Water Treatment
 Sludges (Stream 300)
Leachable trace
elements
Leachable trace
elements
Leachable trace
elements
Leachable trace
metals
Catalyst life, decommission-
ing procedure, synthesis
gas characteristics.
Catalyst life, regenera-
tion frequency, synthesis
gas characteristics
Feed coal characteristics,
boiler operating condi-
tions, slurry water
characteristics.

Raw water characteristics,
treatment system design
and operation.
                                                              (continued)
                                     371

-------
TABLE 4-45.  (Continued)
       Stream
Pollutants of
Potential Concern
Factors Affecting Waste
Stream Characteristics
From Pollution Control

Boiler Fly Ash
(Stream 302)
FGD Sludges from Boiler*
(Stream 424)
Spent Claus Catalyst
(Stream 402)
Spent Beavon Catalyst
(Stream 407)
Spent SCOT  Catalyst
(Stream 410)

Fly  Ash from FBC Boiler
 (Stream 413)
 Spent  Sorbent  from  FBC
  Boiler  (Stream 414)
 Biological  Sludge  from
  Wastewater Treatment
  (Stream 415)
Leachable trace
elements potential
dust emissions
Leachable trace
elements
Leachable trace
elements
 Leachable  trace
 elements potential
 dust  emissions
 Leachable  trace
 elements
 Leachable  organics
 and trace  metals
Feed coal characteristics,
boiler operating condi-
tions, slurry water
characteristics.
Coal sulfur content,
process design and
operation.
        FGD
Catalyst life, regenera-
tion frequency, acid gas
characteristics.
 Feed  coal  characteristics,
 boiler  operating  condi-
 tions, sorbent carryover.

 Feed  coal  characteristics,
 FBC boiler operating
 conditions, sorbent
 characteristics.

 Wastewater treat-
 ment  system design
 and operation.
 Recovered Sulfur
 (Streams 403 and 408)
 Vanadium and cyanides
 (with Beavon/Stretford
 only)
 Coal  sulfur
 bulk sulfur
 efficiency.
content
removal
 Collected Dust from
  Particulate Control
  (Stream 400)
 Potential  dust
 emissions
 Dust collection process
 design and operation.
  For the wet limestone process.
                                       372

-------
                                                         Section 4
                                                         Solid Waste Control
suitable for landfill ing.  The acidity/alkalinity nature of ashes may affect
their leaching characteristics and thus influence control practices.
     The solid waste streams listed in Table 4-45 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 by-products
which prove to be unsalable, 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, are 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 ground water.  The significance of this depends upon the  nature
of the species which might be leached out of the solids by the runoff/perco-
lation.  Thus, in selecting solid waste management techniques, the major
evaluation criteria are whether the technique is applicable and economically
feasible, and whether the secondary waste streams are suitablly contained.
     Based upon current techniques practiced in the synfuel and other indus-
tries, together with those being considered by proposed synfuel plants, the
bulk of the solid waste from K-T facilities will likely be disposed of on
land.  Land-based disposal techniques are by far the most site-specific tech-
niques.  The suitability of the site, as well as the design and operation
of the facility would depend on the site location, transportation costs,
hydrogeologic 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

                                     373

-------
Section 4
Solid Waste Control
Conservation and Recovery Act (RCRA), covering the generation, transport,
treatment, storage, and disposal  of sol id 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 regula-
tions.  In this section, 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 K-T 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 individ-
ual 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 to evaluate the optimum design and operation of these techniques
in the PCTM; optimum design/operation will vary with the site.   It is assumed
that solid waste management facilities are captive, i.e., they only handle
waste from the K-T plant.
                                     374

-------
                                                          Section 4
                                                          Sol id Waste Control
4.3.1   Solid Haste Control
     Several control  techniques are potentially applicable for management of
solid waste streams.   These techniques are summarized in Table 4-46.  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 pro-
cesses for preparing  the waste to meet certain reuse/resource recovery speci-
fications 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 techniques and
thus are highly site-specific.  The major site-specific factors that affect the
design, operation and cost of land-based techniques are summarized in Table
4-47.  The following  is a brief description of the individual techniques.
                                     375

-------
                    TABLE 4-46.   SUMMARY OF SOLID WASTE MANAGEMENT TECHNOLOGIES
oo
^J
01
Technology
Treatment
Fixation/


Incineration


Reuse/Resource
Recovery
Reuse,
Resource
Recovery



Landfill





Surface
Impoundment






Land
Treatment





Deep Well
I njection




Description

Chemicals are added to
stabil ize or sol idify
the wastes

Organic Wastes undergo
destruction to reduce
volume and toxicity




Waste is utilized- in a
manufacturing process*
construction application,
or is processed for reuse
in original application,
or valuable components
are recovered from waste
as byproduct for marketing.
Site is designed, con-
to totally contain waste.
or artificial liners,
leachate collection and
treatment systems , and
groundwater monitoring
system
Site is excavated or
diked to form pond to
natant is syphoned off
and treated or allowed
to evaporate



Waste is treated by
incorporation into the
land according to speci-
fic procedures



Wastes are pumped
through wells into
appropriate formations
generally several thou-
sand feet below the
surface
Operations
Considerations

Wide variety of wastes
can be processed, the
feasibil ity of sol idi -
fying a particular
waste may differ with
different process
Each type of organic
waste may require dif-
ferent operating char-

quired


User for waste must be
located, cessation of
reuse requires imme-
diate alteration of
management techniques,
thereby, necessitati ng
long terra contracts

Wide variety of wastes
visions must be made




Similar to landfill







Only 1 imited types
and mass of organic
wastes can be managed




Wastes frequently
must be treated
before injection



Rel labil ity or
Limitations

Limited commercial
experiences

Only organic wastes
can be processed




Markets for wastes are
1 imited and economic
viabil ity is heavily
influenced by distance
to market



Waste will be con-
tained subject to
adequate site opera-
arid absence of ex-
treme hydrogeologi -
cal changes or earth
movements

Simi 1 ar to 1 andfil 1







Heavily dependent
upon weather condi-
tions




Injection rates
frequently 1 imited
by receiving forma-
tion


Equipment

May include mix-
ing chamber,
pumps, metering
devices, storage
tanks, chemical
feed systems
Waste transpor-
tation machin-
ery , incinerator




Transportation
vehicl es



Earth moving
equipment, waste
handl i ng machin-
1 ifts and trucks



Machinery to move
waste to site.
lines





Waste moving
machinery, usual -
ly trucks, and
waste incorpor-
ation machinery,
usually bul Idozers
and discs
Pumps , i njection
wells




Waste
Generated

Solidified
waste

Ash; air
pol 1 ution con-
trol residues




None



Surface runoff
and 1 eachate




Supernatant
and leachate






Possibly sur-
face runoff
and 1 eachate




Residues from
the waste
treatment pro-
cess


General
Comments

Most processes
are appl icabl e
only to small
waste streams

Process is energy
intensive




In general, these are
the most environmentally
acceptable management
techniques.



Site location and
design dependent
upon hydrogeolo-
gi cal conditions,
be marie for site
care after cessa-
tion of operations

Waste may have to
be renoved when
if waste remains.
long term site
care and mainte-
nance program
must be esta-
blished
Site location
dependent on
soil condi tions ,
provisions must
be mac*e for long
term site care

Some states pro-
hibit deep wel 1
injection




-------
TABLE 4-47.   SITE-SPECIFIC FACTORS  TO BE CONSIDERED FOR LAND-BASED DISPOSAL
                OPTIONS


    Climatological

        t  Wind conditions (e.g.,  speed,  directional  flux,  dilution factors, humidity,
           temperature)
        0  Precipitation (e.g., annual  precipitation, storm intensity, snow contribu-
           tions)
        0  Evapotranspiration rate (e.g.,  season variations)

    Geologic Factors

        •  Physiographic features  (e.g.,  runoff coefficient, slope, drainage patterns,
           erosional  features)
        •  Surface and subsurface  geology (e.g., outcrops,  bedrock features, strike
           and dip of the bedrock, rock composition)
        t  Soil types (e.g., CEC capacity, texture,  permeability,  stratification,
           homogenous vs. heterogenous deposition,  chemical  composition, percent of
           humic material)
        •  Seismic factors (e.g.,  ground shaking or rupture)

    Hydrogeologic Factors

        •  Drainage patterns
        •  Stream flow (e.g., velocity, perennial vs. intermittent, effluent or
           influent source)
        •  Surface waters (e.g., tidal effects, recharge vs. discharge points)
        •  Vadose zone (e.g., depth, moisture content, hysteresis  patterns, storage
           capacity)
        0  Groundwater (e.g., depth, number of aquifers and relationships, confined or
           artesian,  nature of confining layer(s),  capillary fringe characteristics)
        0  Piezometric surface (e.g., streamline flux patterns  due to seasonal or event
           related phenomena, influence of recharge/discharge areas, streamline anomalies)

        0  Water quality (e.g., background vs.  undersite vs. downgradient, water uses -
           consumptive, irrigation, recreation, point source contributors  and  their
           respective hydrogeologic pathways)
        0  Floodplain (100 year flood) (e.g., aerial flooding limits, degree of localized
           streamline pattern reversal, erosional consequences)
        0  Wetlands (e.g., recharge vs. discharge source, wetland/groundwater  continuity
           and  pathway)
        0  Recharge and discharge areas (e.g.,  proximity of disposal area, volume of
           flow)

    Land Use Factors

        0  Historic significance                     0  Demographic  setting
        0  Transportation corridor  (access)          0  Geopolitical  impact
        0  Beneficial uses                           0  Ultimate land  use

        0  Cost
                                            377

-------
Section 4
Solid Waste 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, neutralization, etc. 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-based, and glassification techni-
ques.  Encapsulation 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 fixation process operations involve mixing the chemical with the
waste in a reactor at specific temperature and for a specific time period.
The end product is the fixed 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.
     For economic reasons, these 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 techniques have been used in fixing FGD sludges.

                                     378

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                                                         Section 4
                                                         Solid Waste Control
                                                         Treatment
Typical  unit costs are reported to be $10 to $17 per metric ton of sludge
fixed.  It is recommended that, before implementing this technique to a
specific waste, detailed treatability studies with various chemical additives
be performed to (1) establish that the waste is treatable, (2) select the
optimal  process, and (3) minimize the cost (95).
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
the specific 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.  The end products of
incineration include carbon dioxide, water, ash, and other inorganic com-
pounds.   Incineration has been applied to various industrial wastes including
refinery wastes, sewage sludge, paper mill waste liquor, pharmeceutical
wastes, and organic chemical wastes.  The common types of incinerators used
for solid waste disposal include rotary kiln, multiple hearth, and fluid bed
reactor.  The annualized unit cost for a 61 GJ/hr capacity rotary kiln in-
cinerator is estimated to be $270/Mg,
                                    379

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 Section 4
 Solid Waste Control
 Reuse/Resource Recovery
4.3.1.2  Reuse/Resource Recovery
     Reuse or resource recovery of waste streams is desirable from environ-
mental standpoint because of direct waste reduction and perhaps displacement
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.
     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.
                                     380

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                                                          Section  4
                                                          Solid  Waste  Control
                                                          Disposal
4.3.1.3  Disposal
    The bulk of  the solid wastes from a K-T facility are likely disposed
on land.  Three potentially applicable 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 municipal 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.  This prevents surface
runoff water from entering the site and generating leachate.
     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 sometimes also be
desirable if the waste is nonhazardous.  The choice of an appropriate liner
                                     381

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Section 4
Solid Waste Control
Disposal
or liners will depend on site-specific climatologic,  geologic,  and hydrogeo-
logic factors, as well as on the compatability of the liner and the waste to
be contained and the relative cost of compatible liners.   A leachate collec-
tion and treatment system may also be necessary.  Such systems  consist of
perforated 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.
     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, favorable hydrogeologic and other site conditions that
preclude the need for liners) to the most complex (hazardous waste, unfavor-
able hydrogeologic and other site conditions which necessitate  double liners).
The two landfill designs are presented in Figure 4-9.  For the  purposes 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 land-
fill 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 consist-
ing of 0.5 m sand and 0.3 m of clay.  The most complex, hazardous case would
also include provisions for closure and post-closure  care, monitoring, record-
keeping and other requirements.
     The total capital investment and total annualized unit costs as a func-
tion of the site capacities for the two designs are presented in Figure 4-10.
To be consistent with cost estimates performed for the base plant and the
air and water media, no land cost is included.*  The  capital investment
*About 1,100,000 m2 of land is needed per 106 Mg/yr of waste generated.
 Assuming a land cost of $5,000/10,000 m2 the capital investments for the
 lined and unlined landfills, as presented in Figure  4-10, will be increased
 by more than nine percent.  Additional land may be required for road construc-
 tion, buffer zone, buildings, etc., which will incur additional costs.
                                     382

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      a) LANDFILL-DOUBLE LINER
                      b) LANDFILL-NO LINER
                                                                                                CLAY LINER
                                                                                                    DRAINAGE
                                                                                                    LAYER
CO
GO
                                                                                                        ORIGINAL
                                                                                                        GROUND
                                                                                                        LEVEL
              ORIGINAL
              GROUND
              LEVEL
                                                       NATIVE SOIL
                                                          i
SYNTHETIC
LINER
                                                       LEACHATE COLLECTION
                                                       SYSTEM
CLAY LINER
                                                                 UNSATURATED
                                                                 ZONE
              LEACHATE
              DETECTION
              SYSTEM
UNSATURATED
ZONE
                                         GROUNDWATER
                                       Figure 4-9.  Landfill  design

-------
OJ
CO
-p.
     CO
      o
      a.
      <   4
      o
                             LEGEND
                        •DOUBLE LINED LANDFILL
	UNLINED LANDFILL


 A = GASIFIERSLAG


 B = A + BOILER ASH

     + FGDSLUDGE

     + RAW WATER TREAT-

      MENT SLUDGE

     + BIOSLUDGE


 C= B +ASH FROM

      INCINERATING

      DEWATERED

      DUST
                         2       3     4    5            10             20       30    40   50


                                        TOTAL WASTE GENERATION RATE, 104 Mg/Yr


                      Figure 4-10.  Capital investment and  annualized unit cost for landfills
                                                                                                            11
                                                                                                            10
                                                                                                            7   K
                                                                                                                o
                                                                                                                0
                                                                                                                I-
                                                                                                                Q
                                                                                                                LU
                                                                                                                N
                                                                                      100
                                                                                                               O

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                                                          Section 4
                                                          Solid Waste Control
                                                          Disposal
 developed  includes site preparation cost (e.g.,  clearing and scrubbing, ground-
 water monitoring and collection, liners),  final  cover and revegetation cost,
 and landfill equipment cost.  It was assumed  no  excavation is required.  The
 annualized cost  includes  labor, fuel, and amortized capital  costs, but does not
 include  hauling  cost and  other  costs  such as administrative, closure/post-
 closure, and liability costs. These other costs would depend on the classifi-
 cation of  wastes under RCRA.  EPA  has estimated that for a 50,000 Mg/yr
 commercial  hazardous waste  landfill,  administrative and other compliance
 costs amount to  $9/Mg.  Hauling cost  is a function of distance between the
 plant and  the  disposal site.  It is estimated that the unit cost  for  a round-
 trip  distance  of 5 and 15 km are $2 and $4/Mg,  respectively.
 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 transported hydraulically to the impoundment.   The wastes
deposit at  the bottom of the impoundment, and the supernatant may be removed
and treated for discharge  or recycle or allowed to evaporate.
      When  the  surface impoundment  has been filled with waste, the  site may
 be  closed  in one of two ways:   the waste may be left in place and covered to
 prevent  erosion and the infiltration  of precipitation, or it may be removed
 from  the impoundment site for further treatment or final disposal in  a landfill.
 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 mainten-
 ance  program will need to be established.  The cost per unit volume for sur-
 face  impoundments are expected  to  be  similar to those of landfills with similar
 depths.  However, since surface impoundments generally are used for the dis-
 posal  of wet,  not yet dewatered wastes, a larger area may be required per

                                      385

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Section 4
Solid Waste Control
Disposal
unit mass of dry solids, resulting in higher disposal costs (i.e. some of the
disposal cost will be for "disposing" of water).  Disposal cost could be re-
duced if the wet wastes were dewatered first, but there would be costs assoc-
iated with dewatering.  Similarly, disposal costs may be reduced if appreci-
able natural dewatering occurs within the surface impoundment due to settling
and evaporation.  This trade-off in cost is highly dependent upon waste char-
acteristics and site-specific factors.
     Leachate migration from surface impoundments is controlled in much the
same way leachate is controlled from landfills.  Diversion structures prevent
runoff from surrounding terrain from entering the site; liners of in-place or
compacted soils or synthetic materials retard leachate migration  down  into
the soil and groundwater.   As in the  case of landfills, the PCTM  considers
both an unlined and a lined impoundment in order to cover the range of possi-
ble experience.  The unlined impoundment represents the simplest  set of  con-
ditions (nonhazardous waste with favorable site conditions).  The lined  im-
poundment represents a much more complex situation (hazardous waste with un-
favorable site conditions).   The two  surface impoundments are presented  in
Figure 4-11.  For the purpose of this  assessment, the lined impoundment  design
assumes a liner consisting  of 1.5  m of clay.  Both designs assume the completed
site will be 10 m deep.  When the  impoundment is filled, it is capped with  a
cover consisting of 0.3 m clay and 0.5 m sand to prevent infiltration of
precipitation.

     The capital investment  for a surface impoundment with an annual capacity
of 467,000 Mg/yr is estimated to  be 4.3 and 12.5 million  dollars, respective-
ly, for the unlined and lined impoundment design.  These costs  include site
preparation costs (site clearing and installation of the groundwater monitor-
ing system and liners where required), final cover, and revegetation costs.
It was assumed no excavation  is required.  If the whole impoundment  has to
be excavated, the capital investment, which includes site  preparation  cost,
will be increased by 8 and 40 times, respectively, for the lined and non-lined

                                     386

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     a) SINGLE LINER
CO
CO
—I
                       LEAK DETECTION
                       SYSTEM
b)  NO LINER
                                                                 UNSATURATEDZONE
                                                                 -GROUNDWATER:
                               Figure 4-11.   Surface impoundment design

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Section 4
Solid Waste Control
Disposal
designs.  To be consistent with cost estimates for the base plant and pollu-
tion control in other media, no land cost is included.  Assuming a land cost
          2
of $0.50/m , including this cost item will  increase the capital  investment
by 7% and 20% for the two designs.
     The total  annualized unit costs for the two impoundment designs are
estimated to be $2.1/Mg and $5.7/Mg.  This  includes labor and amortized
capital cost, but does not include  pumping  cost and other costs  such as admin-
istrative, closure/post closure, and liability costs.  The pumping (trans-
portation cost) would depend on the topography of the site and the distance
between the site and the plant.  The other  costs would depend on the classi-
fication of wastes under RCRA.  EPA has estimated that for a 50,000 Mg per
year commercial hazardous waste landfill, administrative and other compliance
costs amount to $9/Mg.
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 con-
ditions.  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 proces-
ses:   (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
biodegradable wastes, maintaining proper (aerobic) conditions for microbial

                                     388

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                                                         Section 4
                                                         Solid Waste Control
                                                         Disposal
action, and avoiding or pretreating wastes which are toxic to the microorgan-
isms will encourage degradation processes.  Proper site selection and proper
site management will minimize leaching and subsequent contamination of ground-
water.  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 .1
plants. Prior to land treating the biological oxidation sludge, long term
studies should be performed to confirm that the waste is degradable in the soil,
that there is no accumulation of non-degradable toxic substances in the soil,
and to establish the area  required for the particular soil-waste combination
at hand.
     Assuming biosludge is applied 10 times/yr, with an application rate of
          o
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 280,000 m2 of land is
required to land treat 21,000 Mg/yr of biosludge.  The annualized unit cost
for this is estimated to be $7.6/Mg.
                                     389

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Section 4
Inorganic Ash/Sludge
Gasifier Slag
4.3.2  Inorganic Ashes and Sludges
     Table 4-48 summarizes the flow rates of the waste streams that consist
primarily of inorganic ashes or sludges.  These streams are the largest vol-
ume solid waste streams from a K-T based indirect liquefaction plant.  The
application of the available control techniques to these specific waste
streams from K-T plants are evaluated in this section.
 TABLE 4-48.  ESTIMATED FLOW RATES FOR THE INORGANIC ASH AND SLUDGE STREAMS

	Stream Description	Stream Flow, Kg/hr	
   Gasifier Slag (Stream 207)                          10,371
   Dewatered Gasifier Dust (Stream 209)                59,217
   Boiler Bottom Ash (Stream 304)                         745
   Boiler Fly Ash (Stream 302)                          2,980
   FGD Sludge (Stream 424)                             10,722
   Raw Water Treatment Sludge (Stream 300)                432

4.3.2.1  Gasifier Slag (Stream 207)
     The gasifier slag is a coarse pebble-sized material which is physically
stable and essentially chemically inert.  As discussed in Section 3, this
stream is essentially coal ash with little or no carbon if the gasifier is
operated properly.  Leachate may include low levels of trace elements (see
Table 3-7 for laboratory leachate characteristics).  Tests of leachate for
organics have not been conducted, but organic levels would be expected to be
low.  Potential may exist for very low level H~S evolution from the slag,
particularly under acidic conditions, as a result of sulfide present in the
interstitial  water or due to the reaction of metallic sulfides  in the slag.
However,  due to the  low sulfur content of the slag and interstitial water,
the potential  for sulfide evolution appears to be low.  The following tech-
niques are applicable to controlling this stream.

                                 390

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                                                         Section 4
                                                         Inorganic Ash/Sludge
                                                         Gasifier Slag
Treatment
     The techniques applicable to treatment of gasifier ash are fixation and
encapsulation.  Treatment of gasifier slag may be appropriate if future data
indicate that significant concentrations of trace metals are in leachate from
the gasifier ash.  Currently available  leach data indicate the trace elements
in the leachate are low and should not  be significantly different from con-
ventional 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
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 $10 to $17 per Mg (95-98).
Resource Recovery
     Gasifier slag 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.  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.  The slag  may need to  be  crushed and sized  before it  can
be used in such applications.
     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 oe difficult to find markets where all  or significant quantities of
the slag from the K-T facility can be reused.   Users for the slag will  likely
be limited to those who are located in the vicinity of the plant.   The eco-
nomic viability of reuse decreases with increasing distance to market and

                                      391

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 Section 4
 Inorganic Ash/Sludge
 Gasifier Slag
 hence increasing transportation  costs.   If market  conditions  change  so  that
 commercial  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.
 Disposal
      Gasifier slag can  be  disposed  of  in  two ways:   in landfills  or  in  im-
 poundments.
 Landfill  --
      In landfill ing,  gasifier slags 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 slag  is determined to be  nonhazardous,  then in  the  most
favorable case (e.g.,  favorable site conditions), an  unlined landfill might
be possible.   On the other hand,  if  the wastes  were considered to  contain
hazardous components,  a  lined landfill  would be necessary where  hydrogeologic
or other site factors  are  unfavorable.
     Based on current and  proposed practices in the synfuel  and  other indus-
tries, this  stream is  likely to be co-disposed  with some  other solid  waste
streams from the plant in  one common landfill.   Although  more  than one land-
fill/disposal facility (e.g., one landfill design for hazardous  waste and
one landfill  for nonhazardous waste) may be operated  in  a K-T  facility,  for
costing purposes in the  PCTM, one landfill accepting  the  wastes  from the K-T
plant is assumed.  By considering the alternatives of all  wastes being dis-
posed 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.
                                     392

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                                                        Section  4
                                                        Inorganic  Ash/Sludge
                                                        Gasifier Slag
      Assuming a  landfill  is  designed  to  accept  the  gasifier  slag,  boiler
 bottom and fly ash,  FGD sludge,  and  raw  water treatment  sludges,  the  capacity
 of the landfill  would be  200,000 Mg/yr.   As  shown in  Figure  4-10,  the annual-
 ized unit cost for the unlined  and lined landfill design will  be  $3.2/Mg  and
 $5.9/Mg,  respectively.   The  total annualized cost that would be attributable
 to the gasifier  slag stream  alone would  be  $262,000/yr and $482,000/yr,
 respectively, for the two landfill designs.
      If the gasifier slag were  disposed  by  itself in  a separate,  dedicated
 landfill, annualized unit costs  for  this smaller landfill  ($82,000 Mg/yr)
 would be  $4.5/Mg and $8.2/Mg for a nonlined  and lined landfill, respecitvely.
 The total annualized cost for this case  would be $370,000/yr and  $670,000/yr,
 respectively.
Surface Impoundment --
     One major difference between disposing the  slag in  a landfill  and sur-
face impoundment  is the means of transporting the  slag to the disposal site.
Surface impoundment is usually used  for storage  or  disposal  of wet ashes
which are transported hydraulically  to the impoundment 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 cost
for surface impoundment would be similar to the  cost of  landfill,  assuming
no excavation is  required.  The  total  disposal  cost  may  be higher  because
surface impoundments generally are used for the  disposal  of wet, not yet de-
watered wastes; extra icapacity is needed for the water content in  the waste.
4.3.2.2  Dewatered Gasifier Dust (Stream 209)
     The gasifier dust is the largest volume solid waste  stream from a K-T
methanol plant using Illinois No. 6  coal  as feed.  As  presented in Section
3.3.1, this stream is estimated  to be generated  at a rate of  59.2  Mg/hr,
and is assumed to contain approximately 50% water, 30% ash, and 20% carbon.

                                    393

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Section 4
Inorganic Ash/Sludge
Dewatered Gasifier Dust
The dust has a high affinity for water and is likely to have poor structural
stability at moisture contents exceeding 60% (99).
Treatment

     Treatment with cement-based or other fixation techniques may be practiced
to improve the stability of the dust when deposited on land.  Several proprie-
tary fixation techniques are commercially available.  However the performance
of these processes when applied to this stream cannot be assessed without
thorough treatability studies.  One potential problem in fixing this stream is
that it may be difficult to engage the dust in pozzolanic reactions with the
chemical additives.  Although in principle the ash content of the stream is
capable of engaging in pozzolanic reactions with the chemical agents added,
the ash may not be available due to the coating effect of the carbon.  The
net effect may be that much more chemical agent is needed, and considering
the size of the waste stream, associated costs may be prohibitive.
 Resource  Recovery
     Due to its high carbon content, the dewatered gasifier dust can be used
as fuel in a boiler.  However, this material presents two major problems with
respect to conventional pulverized coal-fired boilers.  First, extensive dry-
ing, and thus special handling and drying equipment, is needed due to its high
water content.  Second, the dust contains little or no volatiles and may re-
sult in flame stability problems unless a readily combustible supplemental
fuel is added or other countermeasures are taken.  For these reasons, the use
of fluidized bed combustion (FBC) boiler is being considered for the North
Alabama Coal Gasification Consortium Project; this approach is used as an
example in this section to illustrate a resource recovery alternative.
     An FBC boiler is comprised of a granular bed material which is suspended
or "fluidized" by a stream of air.  The fuel is injected into this bed and
burned.  Alkaline sorbents, typically limestone or dolomite, are also injected
into the bed to react with S02 formed during the combustion of high sulfur

                                     394

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                                                      Section 4
                                                      Inorganic Ash/Sludge
                                                      Dewatered Gasifier Dust
fuels.  The inert material of the fuel in part exits the top part of the bed
with the flue gas, and remainder is removed from the bottom of the bed with
the spent sorbent.
     The secondary waste streams generated from the FBC boiler include a flue
gas stream and a spent sorbent stream.  The estimated characteristics of these
two streams are presented in Table 4-49.  The applicable control  techniques
for the spent sorbent stream are discussed in Section 4.3.2.6 and the flue gas
control techniques are discussed in Section 4.1.  Because of subsequent parti-
culate emission controls applied, essentially all of the ash in the flue gas
will be captured and will appear as a solid waste stream.  The control for
this fly ash stream is discussed in Section 4.3.2.7.
     The feasibility of burning the gasifier dust is highly dependent upon
the cost of displaced fuel (i.e., coal), cost and availability of land, and
other site-specific factors.  Table 4-50 presents the estimated costs for
such an application assuming zero credit for the steam generated.  The capi-
tal investment presented is factored from cost estimates developed for coal-
fired FBC boilers.  As shown, burning the gasifier dust in the FBC boiler
would cost $8.4/Mg.  However, it is estimated that about 6.3 x 10  Mg/yr
of steam will  be generated and if a steam credit of $6.2/Mg were assumed,
the FBC boiler cost would break even, i.e., the steam credit would offset
the capitalized and operating cost.  As discussed previously, a K-T facility
is expected to be self-sufficient with respect to steam and, as such, steam
from an FBC boiler would probably be used to generate electric power.  How-
ever, the appropriate credit for power generated by dust combustion in a self-
sufficient K-T facility cannot be assessed without a detailed energy balance
around the plant and more detailed cost estimates for the boilers.   Perform-
ing such analyses is outside the scope of this manual  and, hence, no credit
has been taken for generated power.
                                     395

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TABLE 4-49.  CHARACTERISTICS OF FLUE GAS AND SPENT BED MEDIA FROM FBC BOILER
                                                        Spent Bed Media
                            Flue Gas (Stream 413)*       (Stream 414)t
Component	Kmol/hr   Kg/hr	Kg/hr
co2
N2
H20
so2
°2
Ar
Fly Ash
Total
CaS04
CaO
CaC03
Inert
Total
892
4,415
1,773
13
273
53

7,419





39,278
123,664
31,916
838
8,746
2,109
1,846
208,397













1,603
1,221
177
393
3,394

7T
 NOx is approximately 150 ng/J which is equivalent to 56 kg/hr (as N02).

"''Characteristics of spent bed media are calculated based upon the model
 presented on page 366 of Reference 87.
                                     396

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                                                     Section 4
                                                     Inorganic Ash/Sludge
                                                     Dewatered Gasifier Dust
   TABLE  4-50.   ESTIMATED CAPITAL  INVESTMENT AND TOTAL ANNUALIZED COST FOR
                BURNING  DEWATERED  GASIFIER  DUST IN  FBC BOILER

         Item      ~~~~                               FBC  Boiler

   Capital  Investment,  $106                                15.6
   Total  Annualized Cost,  $106                              3.9
   Total  Annualized Unit Cost,  $/Mg                        8.4
   % Base Plant  Capital  Investment                         1.4
   % Base Plant  Total  Annualized  Cost                       1.1
     One other factor that affects the economics  of this alternative is  the
total  amount of solid waste being generated.   Burning the dust will reduce
the quantity of final waste by more than 60% (from 59.2 Mg/hr of dewatered
gasifier dust to 21.7 Mg/hr of dry FBC boiler ash and spent bed media).   In
addition, power generated by FBC for in-plant use will result in less coal
being fed to the pulverized-coal-fired boiler (in self-sufficient facilities);
thus,  less ash and FGD sludge will be generated from that part of the plant.
It is estimated that about 8.9 Mg/hr of coal would be displaced by the burning
of the gasifier dust.  This amounts to a reduction of the coal-fired boiler
size and the associated ash and FGD sludge generated by 35% (see Table 3-30).
As presented in Table 4-48, a 35% reduction in boiler ash and FGD sludges
amounts to about 5 Mg/hr.  Thus, in effect, the use of FBC boiler for burning
dewatered gasifier dust will reduce the total solid waste that is sent to
ultimate disposal by 32.5 Mg/hr.
     Assuming the ash from the  FBC boiler  is co-disposed with other  inorganic
streams  (gasifier slag, boiler  bottom and  fly ash,  FGD  sludge, and  raw water
treatment sludge), the landfill capacity would be 37,000 Mg/yr.   The unit
annual ized cost for  this size landfill would be  $2.7/Mg and $5.4/Mg,  depending
on whether the landfill  is lined  or not (see Figure 4-10).  Assuming  these
unit costs apply, a  reduction of  32.5 Mg/hr of waste  quantity would  amount to
                                      397

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Section 4
Inorganic Ash/Sludge
Dewatered Gasifier Dust
savings of 0.7 and 1.4  million  dollars per year, respectively.  The incre-
mental  total  annualized cost  for disposing of the FBC boiler ash and spent
bed media (21.7 Mg/hr)  would  be $460,000/yr and $920,000/yr, respectively.
Disposal
     The applicable disposal  technique for controlling gasification dust is
surface impoundment.  Landfill  can also be used if the structural  stability
of the dust is improved by  fixation techniques.  When disposing of the gasi-
fier dust in  a surface  impoundment, no mechanical dewatering pretreatment is
required.  Quenched gasifier dust is transported to the site  hydraulically.
The dust settles to the bottom of the site.  Excess water  is  recycled  and
reused as quench water.  When  the site is filled, it is capped with  a  cover
consisting of 0.3 m clay and 0.5 m sand to avoid infiltration.   It  is  assumed
that the water content of the  dust at the finished site is  50%.   Mechanical
dewatering of the dust prior to impoundment can reduce the  pond  area  needed
and may be employed where land is costly or of limited availability.
     As discussed in Section 4.3.1.3, two surface impoundment designs  are
considered in the PCTM to cover the range of possible experience.   Table 4-51
summarizes the estimated costs for the two surface impoundment designs as
shown in Figure 4-11.  The total capital investment for the non-lined and
lined designs are, respectively, 4.3 and 12.5 million dollars, and  the total
annualized unit costs  are $2.10 and $5.70/Mg.
                                      398

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 TABLE 4-51.  SUMMARY OF CAPITAL INVESTMENT AND TOTAL ANNUALIZED
              COST FOR DISPOSING OF  GASIFIER DUST IN SURFACE
              IMPOUNDMENT
                             Lined Surface             Non-Lined
     Item                     Impoundment         Surface Impoundment

Capital Investment, 106$         12.5                  4.3
Total Annualized Cost, 105$       2.5                  0.9
Total Annualized Unit
  Cost, $/Mg                      2.1                  5.7

% Base Plant Capital              1.1                  0.4
  Investment
% Base Plant Annualized           0.7                  0.3
  Cost
                                 399

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Section 4
Inorganic Ash/Sludge
Boiler Ash
4.3.2.3  Boiler Bottom Ash (Stream 304)
    The applicable control techniques for boiler bottom ash are similar to
those for the gasification slag.   Where landfill  is the technique selected,
the stream is likely co-disposed with other solid waste streams 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 $3.2/Mg and
$5.9/Mg, respectively, for a non-lined and lined landfill.  Based on these
unit costs, the incremental annualized disposal cost attributable to this
stream would be $18,000/yr and $34,000/yr, respectively.
4.3.2.4  Boiler Fly Ash (Stream 302)
    Applicable control techniques for this stream are similar to those dis-
cussed for the gasification slag.  Available technology requires that gasi-
fier slag and boiler bottom ash be quenched before any subsequent handling
of disposal.  Boiler fly ash, however, 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 fixa-
tion reactions when wetted, much as Portland cement does.   Recently, more
power plants are 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.
    Where landfill is the disposal technique selected, this stream is likely
co-disposed with other solid waste streams in one common landfill.   As dis-
cussed in Section 4.3.2.1, annualized unit costs for landfilling the solid
waste streams in a common landfill are estimated to be $3.2/Mr and $5.9/Mg,
respectively, for a non-lined and lined landfill.  Based on these unit costs,
the incremental disposal cost attributable to this stream would be $74,000/
yr and $136,000/yr, respectively.

                                     400

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                                                         Section  4
                                                         Inorganic  Ash/Sludge
                                                         FGD  Sludge
4.3.2.5  Boiler FGD Sludge (Stream 424)
     Applicable techniques for controlling FGD sludge include fixation, sur-
face impoundment and landfills.  These techniques have been widely used in
disposing of FGD sludges from existing coal-fired power plants.
Treatment - Fixation
     FGD sludge typically contains 30 to 50 percent solids after thickening
or filtration.  It is a poor landfill material in this form because it is
thixotropic.  To rectify this problem, treatment by fixation may be practiced.
Several patented processes are available commercially for fixing FGD sludges.
One mixes the sludge with boiler fly ash and lime while another adds a pro-
prietary chemical (basically a cementitious agent) as the hardening material.
Typically these proprietary processes involve dewatering the sludge and com-
bining the sludge with proprietary additives which promote pozzolanic reac-
tions, resulting in a material less Teachable, less permeable, and struc-
turally more suitable for landfill.  Proprietary methods which have been
successfully applied to fixing FGD sludges include Chemfix (addition of
Portland cement and sodium silicate), Calcilox (calcined blast furnace slag
and lime), IUCS - Poz - 0 - Tec (fly ash and lime under controlled tempera-
ture and moisture conditions),  ICT (lime, betonite,  and cement), and Research-
Cottrell  (sludge dewatering prior to fly ash admixing).
     Unit cost for these treatments ranges from $10 to $17 per Mg of sludge
fixed.  Another treatment alternative practiced in many coal-fired power
plants is mixing the FGD sludge with -boiler bottom and fly ash before dis-
posal .  For coals that generate ashes that are alkaline, mixing the ash with
the sludge will also initiate pozzolanic reactions.
                                    401

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Section 4
Inorganic Ash/Sludge
FGD Sludge
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 is essential.
     Assuming this stream is mixed with the gasifier slag, boiler bottom ash
and fly ash, and raw water treatment sludge before disposal in a common land-
fill, the unit disposal cost for a non-lined and a lined landfill is esti-
mated to be $3.2/Mg and $5.9/Mg, respectively  (see Section 4.3.2.1).  The
incremental annualized cost attributable to this stream would be $270,000/yr
and $500,000/yr, respectively.
                                     402

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                                                   Section 4
                                                   Inorganic Ash/Sludge
                                                   Spent Sorbent/Fly Ash,
                                                   Raw Water Treatment Sludge
4.3.2.6  Spent Sorbent from FBC Boiler (Stream 414)
     The characteristics of this material  are similar to the solids in the
FGD sludge stream.  Thus the applicable control techniques are similar to those
for the FGD sludge with the exception that since this is a  dry  material,  it
can be landfilled directly without fixation.   When landfill  is  the technique
selected this stream is likely combined with  other solid waste  streams and
disposed of in one common landfill.
4.3.2.7  Fly Ash from FBC Boiler  (Stream  413)
     The applicable control techniques for this  stream are  identical  to those
for Boiler Fly Ash.
4.3.2.8  Raw Water Treatment Sludge  (Stream 300)
     The applicable treatment and disposal techniques for this  stream would
be similar to those for the FGD sludge, except that the  optimum fixation  pro-
cess and hence the treatment cost may differ.   Where landfill  is  the  technique
selected, this stream is likely co-disposed  with other solid  waste streams  in
one common landfill.  Assuming unit costs  of $3.2/Mg and $5.9/Mg  respectively,
for a non-lined and lined landfill, disposing this stream will  cost $11,000
and $20,000/yr.
                                     403

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Section 4
Recovered By-Products
Elemental Sulfur/Coal Dust
4.3.3  Recovered By-Products
     This source type includes elemental sulfur recovered from the bulk sul-
fur removal processes and collected dust from particulate control, if either
of these materials proves to be unsalable.  The flow rate of these two
streams is estimated to be, respectively, 8.3 Mg/hr and 0.14 to 1.9 Mg/hr.
4.3.3.1  Recovered Elemental Sulfur (Streams 403 and 408)
     Recovered elemental sulfur can be sold as by-product.  However, the sul-
fur may be contaminated with carbonaceous impurities (from Claus plant) or
vanadates, thiosulfates and thiocyanate salts (from Beavon Stretford tail gas
treatment unit), making it non-marketable without further in-plant processing.
If the sulfur cannot be sold, it may be disposed of in landfills.
     There is a potential for elemental sulfur to be oxidized in a landfill
environment, and such oxidation results in acid generation,.  Acidic leachate
could solublize trace elements from other wastes in the landfill.  Hence,
it may be desirable to co-dispose waste elemental sulfur with alkaline wastes
such as FGD sludges or spent  FBC  sorbent.
4•3•3•2  Collected Coal Dust from Particulate Control  (Stream 400)
     This secondary waste stream consists primarily of coal dust collected
throughout the coal  preparation operations.   This dust can be reused as feed
to the gasifier or  boiler, or can be disposed of in landfills.  When  land-
filled, spraying the dust with wdier ;nay be required to reduce dust emission.
                                    404

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                                                               Section 4
                                                               Organic Sludges
                                                               Biosludge
4.3.4  Organic Sludges
     This waste category includes one stream, namely, the biosludge from the
biological treatment process (Stream 415).  This is a secondary waste stream;
the flow rate of this stream has been estimated to be 2.65 Mg/hr, assuming
water is used in the cyanide wash operation in the base plant.  Impact of
cyanide wash design on the wastewater characteristics, and thus the biosludge
characteristics have been presented in Sections 3.4 and 4.2.
Treatment
     Although no data are available on the composition of this waste at pre-
sent, it  is highly probable that some of  the nonbiodegradable toxic organics
that might have been present in the raw process liquor (such as polycyclic or-
ganics 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 oxi-
dation 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 re-
quires 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 4-52 presents the estimated costs for incinerating the  biosludge  in
a  rotary  kiln incinerator (63 GJ/hr energy input) with energy recovery.  The
heating value of the biosludge was assumed to  be 23 MJ/kg.  As shown in Table
4-52, the capital investment for incineration  is estimated  to be 14 to  16
million dollars; the total annualized cost is  5.8 million dollars  per year,
or about  $270/MG.
                                      405

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Section 4
Organic Sludges
Biosludge
             TABLE 4-52.  ESTIMATED TREATMENT/DISPOSAL COST FOR
                          BIOSLUDGE

Item
Total Capital Investment, $10
Total Annual i zed Cost, $106
Annual ized Unit Cost, $/Mg

% Base Plant Capital
Incineration
14 to 16
5.8
270
1 2 to 1 4

Land Treatment
0.5
0.2
7.60

0.05
 Investment
% Base Plant Annualized                 1.6                0.06
 Cost
     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 4-52.  The incinerator is
assumed to be equipped with a scrubber for particulate control.
    The flow rate of the residue stream is estimated to be 0.16 Mg/hr.
Assuming a 99.9% destruction of organics, 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 accumulate in the residue.  Appli-
cable treatment/disposal techniques include fixation/encapsulation and landfill
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.

                                     406

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                                                              Section 4
                                                              Organic Sludges
                                                              Biosludge
Land Treatment —
     In land treatment, biological treatment sludge may or may not require
dewatering prior to applying 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 on land
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 neutra-
lizing 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 4-52.  The capital investment presented in Table 4-52 includes land
preparation costs ($0.52/m2), waste  spreading equipment costs ($160,000), and
monitoring well  costs ($25,000).   The  annualized costs include labor  cost,
fuel cost, monitoring cost,  maintenance cost, and amortized capital costs.
No land nor transportation cost was included in the cost presented.   It is
                             2
estimated that about 32,000 m   of land  is  required.   Assuming  a  unit  land
               2
cost of $0.50/m , this would increase the total capital investment by more
than 25%.  Depending on the distance, including the transportation cost may
more than double the annualized unit costs presented.
                                     407

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Section 4
Spent Catalyst/Sulfur Guard
4.3.5  Spent Catalyst and Sulfur Guard
     Nine types of catalysts may potentially be used in a K-T based indirect
liquefaction 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,
intermittant stream, and (2) applicable controls are similar.  Table 4-53
summarizes the estimated spent catalyst generation  rates.  It should be
pointed out that although the flow rates are presented in Mg/yr, these streams
only occur interim'ttantly, about once every three to five years.

 TABLE 4-53.   ESTIMATED GENERATION RATES FOR SPENT  CATALYSTS AND SULFUR GUARD


        Catalyst/Guard Material                   Generation  Rate,  Mg/yr

 Spent Shift Catalyst  (Stream 217)                      14 " 24
 Spent Sulfur Guard (Stream 218)                           80
 Methanol Synthesis Catalyst  (Stream 227)              60 -100
 Spent Methanation Catalyst (Stream 238)                  40
 Spent Claus Catalyst  (Stream 402)                       10
 Spent SCOT Catalyst (Stream 410)                          3
 Spent Beavon Catalyst (Stream 407)                        5
 Spent Mobil  Synthesis Catalyst  (Stream 232)             300
 Spent F-T Synthesis Catalyst (Stream 222)              3500
 Spent NO  Reduction Catalyst (Stream 212)              16-27
         X
                                     408

-------
                                                 Section 4
                                                 Spent Catalysts/Sulfur Guard
     Due to the proprietary nature of most catalysts, there is little informa-
tion 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 and their applicability to individual catalysts.
Treatment
     Spent catalysts may be chemically fixed or encapsulated before final
disposal 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;  i.e.,  a  1:1 chemical/spent catalyst ratio may  he  needed.
As discussed before, the performance and cost for this alternative can only
be established after thorough treatability studies.
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
manufacturers  to develop improved methods  to regenerate the  catalyst, to re-
cover 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 M  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

                                     409

-------
Section 4
Spent Catalysts/Sulfur Guard
these catalysts (zinc for sulfur guard,  bauxite for Claus catalyst,  zeolite
for Mobil  M synthesis catalyst,  and iron for Fischer-Tropsch synthesis  cata-
lyst).  Spent methanation catalyst (nickel-based)  and Fischer-Tropsch synthe-
sis catalyst (iron oxide-based), although deactivated as  far as  catalyst
activity is concerned,  still  have a large capacity for adsorption  of sulfur
compounds  and can be used as  sulfur guard bed material,
DisposaJ
     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 (i.e., assuming that these  wastes  are
disposed of in a common landfill along  with other plant solid waste).  As
indicated in Table 4-53, the  overall spent catalyst generation rate  is  largely
dependent upon the synthesis  process incorporated in the  plant.   As  discussed
before, the unit costs would  be $3.2/Mg  and $5.9/Mg, respectively,  for a
non-lined and lined landfill; the incremental annual disposal cost for these
materials would range from $720 to $22,000, depending on  the landfill design
and the synthesis process used.
                                    410

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                                                       Section 5
                                                       Data Gaps/Limitations
                                  SECTION  5
                         DATA  GAPS AND  LIMITATIONS

     Because of the inherent gaps and limitations  which exist in the data base
used to support this document, it is important for readers to understand the
extent to which the performance and  cost estimates presented here are supported
by actual operating data, extrapolations from closely related applications,  or
engineering calculations and/or judgements.   The purpose of this section,
therefore, is to convey to the reader a sense of the applicability and
completeness of the data base.  This information should contribute to a
better understanding of how this document should be used by indicating the
confidence which can be placed in the uncontrolled discharge rates and the
effectiveness of specific controls.
     Since the early 1970s the 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
acquisition programs.   These efforts have contributed both data and background
knowledge used in the  development of this manual.   The major data acquisition
programs sponsored or  cosponsored by the EPA which have provided background
data used in  the development of this PCTM are listed in Table 5-1, at the
end of this section.  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.
     Waste streams which are unique  to  K-T based indirect liquefaction facili-
ties have been emphasized in this section.  These streams differ from  waste
streams generated in other industries because of their composition and/or the
approaches applicable  to their control.  Waste streams which do not differ in
composition from wastes generated in other industries and which do not require
special consideration  with respect to control approaches (e.g., boiler flue
gas, coal pile runoff, raw water treatment sludges, and boiler ash) are not
                                     411

-------
 Section  5
 Data  Gaps/Limitations
considered in this section.  These non-unique waste streams have not been
considered because any significant data limitations or gaps related to their
characterization have been a concern in other industries, and programs to fill
identified data gaps are already underway or are currently being planned.
Key data sources and the bases for characterization estimates, data gaps and
limitations, and research needs relating to unique waste streams are summar-
ized by waste medium in Tables 5-2 through 5-4 at the end of this section.
Similar information relating to applicable pollution control technologies and
associated secondary waste streams are presented in these tables following
each waste stream or group of waste streams combined for common treatment.
     In general, estimates of characteristics of the uncontrolled unique
waste streams were based upon data from commercial scale K-T gasification
facilities (e.g., AECI Limited, Modderfontein, South Africa and the Nitrogeneous
Ferterlizer  Inudstry, S.A., Ptolemais, Greece).  Although these facilities pro-
duce hydrogen for ammonia manufacture, many of the individual process oper-
ations upstream of product synthesis are similar to those proposed for in-
direct liquefaction facilities.  Data from these operations have in some in-
stances been used directly or have been extrapolated, consistent with proposed
designs.  Waste characterization data for F-T, methanol, and Mobil M-gasoline
synthesis processes have been based upon published designs for commercial scale
facilities.
     Since none of the existing K-T gasification  facilities  employ the range
of pollution  controls  which are likely to  be  utilized  in  the U.S.,  little
direct operating experience is  available  to  accurately predict the performance
or costs  of applicable controls.   For certain control  systems  (e.g.,  Glaus
bulk sulfur recovery and Wellman-Lord tail  gas  treatment)  the  existing data
base from related applications  is  sufficient  to indicate  gross pollutant re-
moval  efficiencies and associated  costs  reasonably well.   However,  for control
systems  for which performance and  cost are highly sensitive  to individual com-
ponents  present in the waste stream (e.g.,  activated  sludge  and chemical  oxi-

                                     412

-------
                                                        Section 5
                                                        Data Gaps/Limitations
dation), only limited data or data from somewhat different applications are
generally available.  The limitations in the data of this type are twofold.
First, the characteristics of the treated waste streams in related applica-
tions of the subject controls are often known only in terms of major consti-
tuents, gross parameters, or classes of substances.  Little may be known about
specific organics, trace elements, or general toxic properties.  Secondly, the
performance characteristics of many controls are uncertain for some of the
specific waste streams addressed in this PCTM even for the major constituent
and gross properties.  Key data sources and bases for performance and cost
estimates for example controls discussed in conjunction with unique waste
streams in Section 4 are summarized in Tables 5-2 through 5-4.
     A data gap or limitation which exists for essentially all pollution con-
trol technologies relates to reliability.  Because most of the potentially
applicable pollution control technologies have not been employed in coal
gasification/indirect liquefaction facilities, few directly related reliability
data are available.   Further, the overall characteristics and variability of
waste streams in coal conversion facilities are often sufficiently different
from those encountered in other industries that reliability data accumulated
in other industries  may not be applicable to coal conversion processes.  These
are particularly significant considerations with respect to wastewater treat-
ment 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 application of these
controls to coal conversion waste streams.
     With regard to  the products and by-products produced in K-T based lique-
faction facilities,  most of the physical and chemical properties reported are
estimates relating to conceptual designs of commercial scale facilities.
Despite the fact that the Fischer-Tropsch (F-T) process is applied commercially
in South Africa, detailed chemical analysis data are not publicly available
for F-T products.  Detailed chemical analyses are not available for Mobil M-

                                     413

-------
Section 5
Data Gaps/Limitations
gasoline or coal-derived methanol,  which  are  not currently  produced  on  a  commer-
cial  scale.  Also,  there are no chemical  characterization data  available  for
by-product sulfur from indirect liquefaction  facilities.  The data sources  and
bases for characterization estimates,  data gaps  and  limitations,  and research
needs relating to products and by-products produced  in  K-T  indirect  liquefaction
facilities are summarized in Table  5-5,  at the end of this  section.
                                      414

-------
TABLE  5-1.    COMPLETED  AND  ONGOING  DATA  ACQUISITION  PROGRAMS  AT COAL  GASIFICATION
                   FACILITIES SPONSORED  OR CO-SPONSORED  BY  THE  EPA
                      Facility
                                                 Information Classification
                                                                                    Coal Used
                                                                                                              Products
             Medium/High Btu  Gasification
             and  Indirect Liquefaction
             Facilities (Foreign)

             •  Lurgi Gasification

               -  Kosovo, Yugoslavia
               -  SASOL, S.A.

               -  Westfield,  Scotland

             t  Koppers-Totzek Gasification

               -  Modderfontein, S.A.

               -  Ptolemais,  Greece
               -  Kutahya,  Turkey

             •  Winkler Gasification
               -  Kutakya,  Turkey

             *  Texaco Gasification

               -  Federal  Republic of Germany

             Low-Btu Gasification Facilities
Data acquisition
Plant visit and discussions

Plant visit and discussions
Data acquisition

Data acquisition (TVA & EPA)
Plant visit and discussions
Plant visit and discussions
Data acquisition (EPRI,  TVA
  & EPA)
Lignite
Low rank bituminous

Various
High  volatile "B"
  bituminous
111.  No.  6 bituminous
Lignite
                               Lignite
111.  No. 6 bituminous
Medium Btu gas
Various via indirect
  1iquefaction
Test center
Ammonia, methanol

Ammonia
Ammonia
                                                         Ammonia
                         Test center
            * Wellman GalusHa

               - Site No.  1
               - Site No.  2

            • Chapman/Wilputte
            • Riley

            • Stoic (Foster Wheeler)

            Control Research Facilities

            • Raw/Acid Gas Cleanup (Fluidized
                Bed Gasifier)

            t Wastewater Treatatnlity  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
Data acquisition
Data acquisition
Data acquisition

Data acquisition (DOE & EPA)



North Carolina State Univ.


Univ.  of  North Carolina

Research  Triangle Institute


University of Illinois
Data acquisition (TVA &  EPA)


Texaco, Wilmington, CA
Anthracite
Lignite

Low sulfur bituminous
Ligm te

Western  bituminous
Various
Various

Various
Various
111.  No.  6 bitutrnnous
  (in shakedown)
Oil  fired partial
  oxidation
Fuel  gas  •
Test  center

Fuel  gas
Test

Fuel  gas
Test center


Test center

Test center


Test center





Ammonia


Process hydrogen

-------
                                TABLE  5-2.    DATA GAPS AND  RESEARCH  NEEDS  -  GASEOUS  MEDIUM
                                                             Key for Technology Status and Data  Sources
                    Technology Status
                                                                                        Data  Source/Location
A.  Commercial application 1n a  K-T  gasification facility

B.  Bench scale or pilot testing

C.  Technology transfer from another industry - similar
    but not identical  streams

D.  Conceptual
                                                                     1.  AECI Limited,  Modderfonteln, South Africa

                                                                     2.  Nitrogenous  Fertilizer  Industry, S.A., Ptolemais,  Greece

                                                                     3.  Technology transfer  from related industries

                                                                    3A.  Petroleum refining/petrochemical production

                                                                    3B.  Coke production

                                                                    3C.  Electric  power generation

                                                                    3D.  Natural gas  processing

                                                                    3E.  Municipal  waste  treatment

                                                                     4.  Conceptual or  proposed design/engineering studies

                                                                     5.  Vendor supplied  information
               Data  Source and  Basis
                                                                       Data Gaps/Limitations
                                                                                                                              Research Needs
en       Uncontrolled Primary Waste Streams
         H;S-Rich Offgas  (Stream 216)	

         Offgas composition  is based upon selective Rectisol
         performance data  from commercial K-T coal  gasifica-
         tion at AECI Limited, Modderfonteln, South Africa
         and from several  commercial oil partial  oxidation
         units.  H?S to COS  ratios in raw gas are also  sub-
         stantiated  by commercial scale gasification tests
         with an Illinois  No. 6 coal at the Nitrogenous
         Fertilizers Industry, S.A., Ptolemais,  Greece.
Status:
Data Sources:
PCTM References.
A, C
1, 2,  3A,  5
Sections 3.3.6,  4.1.1.1,
4.1.1.5, and Appendix D.
                                                      The selectivity of acid gas  removal  is dependent
                                                      upon several design factors;  however, available
                                                      data indicate that selective  Rectisol can eco-
                                                      nomically produce an HoS-nch offgas containing
                                                      at least 25% total  sulfur  for a wide range of
                                                      feed coal sulfur contents.  Relative quantities
                                                      of sulfur species in raw gas, and therefore in
                                                      the H2S-rich offgas, may differ somewhat for
                                                      different rank coals.
                                                                                          Verification of sulfur and minor constituent
                                                                                          characterization data in  U.S.  facilities is
                                                                                          desirable.
Sour Gas from Cyanide wash Flasn (Stream 214)

Flash gas compositions have been estimated from
gas solubility data.

Status:            D
Data Sources:      4
PCTM References:   Sections 3.3.4, 4.1.1.2,
                  and 4.1.1.5
                                     No waste gas generation or characterization data
                                     are  available.
                                                                                                                    Generation rate and characterization data are
                                                                                                                    needed to define applicable control alternatives.
                                                                                                                                                      (Continued)

-------
  TABLE  5-2.     (Continued)
             Data Source and Basis
                                                                      Data Gaps/Limitations
                                                                                                                              Research Needs
Control Techniques
Claus Bulk Sulfur Removal

Performance and cost estimates are based upon data
from applications In coke plants,  oil  refineries,
and gats processing plants.  Although no data are
available for coal gasification applications, data
from other applications cover the  range of all
constituents encountered in K-T coal gasification.
Status:           C
Data Sources:     3A, 3B, 3D, 5
PCTM References:  Sections 4.1.1,  4.1.1.1,
                  and 4.1.1.5

  Secondary Waste Streams

  Spent catalyst is the principal  secondary waste
  stream from Claus.
Beavon/Stretford Tail  Gas Treatment

Performance and cost estimates  are based upon
data from treatment of Claus  plant tail gases
with low CO^ feed composition from petroleum
refinery applications.

Status:            C
Data Sources:      3A
PCTM References:  Sections 4.1.1, 4.1.1.1.
                  and  4.1.1.5

  Secondary Waste Streams

  t  Sour Condensate
     Stretford Solution  Purge
  •  Stretford  Oxidizer  Vent Gas
Performance, cost, and reliability data  in  coal
gasification applications are not available.
Spent catalyst generation rates and  characteristics
are not accurately known.
Uncertainties relate to performance of  the  cata-
lytic hydrogenation section and the operability
of the Stretford sulfur recovery section  in high
C02 applications.   Process costs as a function
of both volumetric flow and sulfur  loadings are
not accurately known.
                                                     Condensate characteristics,  particularly with
                                                     respect to S=,  CN",  and NHJ  are  not  available.
                                                     Limited characterization data  are  available.
                                                     Purge rates in high  CO?  applications  are  unknown.
                                                     Reductive incineration of solution purge  has not
                                                     been demonstrated at commercial  scale.
                                                     Characterization  data  are  not  available  for oxi-
                                                     dizer vent gas.   However,  in K-T  coal  gasifica-
                                                     tion applications there  are no gaseous components
                                                     of environmental  concern having potential for
                                                     being present in  the  vent  gas.
Performance, cost, and reliability data should be
obtained for K-T coal  gasification applications.
Generation rate and characterization data  are  needed
to define applicable control  alternatives.   Such  data
may be obtainable from Claus  plant operators 1n  related
industries.
The operability, performance,  and cost of Beavon/
Stretford tail  gas treatment in high C0.2 applications
should be determined.
                                                      Condensate characteristics should be determined to
                                                      define pollution control alternatives.  Appropriate
                                                      data may be obtainable from licensors or operators
                                                      of refinery units.

                                                      Purge generation rates and characteristics should be
                                                      determined in coal gasification facilities when the
                                                      technology is applied commercially.  Characterization,
                                                      performance, and cost data for reductive incineration
                                                      should be obtained when the process is applied
                                                      commercially.

                                                      Oxidizer vent gas should be characterized in K-T coal
                                                      gasification facilities when the technology is applied
                                                      commercially.
                                                                                                                                                         (Continued)

-------
        TABLE  5-2.    (Continued)
                        Data Source and Basis
                                                                                 Data Gaps/Limitations
                                                                                                                                         Research Needs
CO
             Secondary Haste Streams  (Continued)

             I  Spent Beavon Catalyst




           SCOT Tail Gas Treatment

           Performance and cost estimates are based  upon
           data from treatment of Claus plant tail gases
           with low CO^ feed compositions from petroleum
           refinery applications.

           Status:           C
           Data Sources:     3A,  5
           PCTM References:  Sections 4.1.1,  4.1.1.1,
                             and  4.1.1.5

             Secondary Haste Streams

             •  Sour Condensate
             t  Spent SCOT Catalyst
           Mellman-Lord (M-L) Tall Gas Treatment

            Performance and cost estimates are based upon
            data  fron  refinery and power plant applications.
            Status:              C, D
            Data  Sources:        3A, 3C. 4. 5
            PCTH  References:     Sections 4.1.1. 4.1.1.1,
                                and 4.1.1.5

              Secondary Haste Streams

              o  Sour  Condensate
              o   Thlosulfate/Sulfate By-Product Purge
Spent catalyst generation rates and characteristics
are not accurately known.
Uncertainties relate to performance and  cost  in
high COj applications.   SCOT units are used  in
high CO? applications in natural  gas processing
although associated performance and cost data
are not currently available.
                                                                Condensate characteristics,  particularly with
                                                                respect to S=,  CN~,  and NH^  are  not  available.
Spent catalyst generation rates  and  characteristics
are not accurately known.
Since W-L feed gas is incinerated,  and  the
absorption solution is not affected by  CO? con-
centration, data from existing units should be
directly transferable to K-T coal  gasification
applications.   Effects of volumetric flow rate
and sulfur loading on cost are uncertain.
Limited  characterization  data are available

Limited  generation  rate and characterization
data are available
Characterization data are needed to define applicable
control/resource recovery alternatives.   Appropriate
data may be obtainable through licensors or operators
of refinery units.
SCOT performance in high CO? applications should be
determined.  Units in gas plant applications are best
suited for demonstrating applicability to K-T coal
gasification facilities.
Condensate characteristics should be determined  to
define pollution control  alternatives.   Appropriate
data may be obtainable through licensors or  operators
of refinery units.

Characterization data are needed to  define applicable
control/resource recovery alternatives.   Appropriate
data may be obtainable through licensors or  operators
of refinery units.
                                                      None
Additional characterization data  are
desirable

Additional generation rate and characteriza-
tion data are desirable.
                                                                                                                                                                   (Continued)

-------
         TABLE  5-2.     (Continued)
                      Data  Source and Basis
                                                                              Data Gaps/Limitations
                                                                                                                                       Research Needs
        Thermal  Incineration
        Performance and cost estimates are based upon
        data  from waste gas and liquid waste Incin-
        eration  applications.
        Status:              C
        Data  Sources:        3A, 3B, 3C, 30
        PCTM  References:     Sections 4.1.1, 4.1.1.1,
                             and 4.1.1.5
                                     Uncertainties relate primarily  to  the  operabillty
                                     of and emissions from Incinerators with  feed  gases
                                     having high C02 levels and low  heating valves.
Applicable data on operabllity of and emissions  from
incinerators may be obtainable from operators  of
refinery units or gas plants.
i-D
       Uncontrolled  Primary Waste Stream
       C0?-Rich  Offgas  (Stream 219)

       Offgas  total  sulfur and CO concentrations are based
       upon  selective Rectisol performance data from com-
       mercial K-T coal  gasification at AEC1 Limited,
       Modderfontein, South Africa and from several  com-
       mercial oil partial oxidation units.  Design  modi-
       fications discussed in conjuntion with control of
       CO  emissions  are  based on licensor inputs.
       Status:
       Data  Resources:
       PCTM  References:
A, C
1, 3A, 5
Sections 3.3.6 and 4.1.1.2
         Control  Technology
         Catalytic  Incineration
         Performance  and cost estimates are based upon
         data  from  industrial waste gas incineration
         applications.
                                     Baseline offgas characterization data,  and spe-
                                     cifics of CO moderating Rectisol design modifi-
                                     cations and associated performance in indirect
                                     coal liquefaction facilities are not available.
                                     Available data on performance and cost are
                                     1imited.
Offgas characteristics in indirect coal  liquefaction
facilities should be determined.   It appears likely
that two streams would require characterization:
(1) a COj-rich vent gas, and (2)  a CO-rich waste  gas.
Performance and cost data for waste streams similar
to those produced in K-T coal gasification facilities
should be obtained.
         Status:
         Data  Sources:
         PCTM  References:
  C
  3A
  Sections 4.1.1 and 4.1.1.3
       Uncontrolled  Primary Waste St,ream
       Fugitive Organic  Emissions from
       Process Equipment  (Stream 241)

       Emission estimates for fugutive organic emissions
       from  leaking  process equipment were based on
       emission factors  for these components for con-
       ventional  petroleum refining process equipment.
       Component  counts  were based on plot plans for
       potential  K-T based synthetic fuel plants.
       Status:
       Data Sources:
       PCTM References.
C
3A
Sections 3.7.1 and 4.1.5
                                     Characterization data are not available for syn-
                                     thetic liquids or their vapors.
Exact composition of vapors for synthetic fuel plant
process equipment may differ from petroleum refinery
process equipment, however, the control technology
that is applicable is not likely to be affected by
these characteristics.  Since these emissions directly
enter the atmosphere, additional information on spe-
cific constituents of the vapor may be desirable.
                                                                                                                                                                 (Continued)

-------
         TABLE  5-2.    (Continued)
                        Data  Source and Basis
                                                                                Data Gaps/Limitations
                                                                                                                                         Research Needs
           Control  Technologies
           Leak  Detection  and Repair Methods

           Leak  detection  and repair methods have been
           successfully  used to control fugitive organic
           emissions  from  petroleum refining equipment.
           This  technique  was assumed  to be applicable
           to  indirect liquefaction process equipment.
           Emission estimates were based upon emission
           factors  developed from test data for
           petroleum  refining process  equipment
                                                     The performance of leak detection and repair
                                                     methods are not expected to be different for
                                                     K-T based synthetic fuel plants.
 Research needs relate to characterization of the
 emissions and not to the controls.
           Status:
           Data  Sources:
           PCTM  References:
                  C
                  3A
                  Sections 4.1.5 and  4.1.5.2
ro
O
Equipment Specification

Replacement of leaking equipment with  leakless
components has been successfully used  for  the
control  of fugitive organic emissions  from
petroleum refining equipment.   This  technique
was assumed to be applicable to indirect
liquefaction process equipment.  Emission
estimates were based upon  emission factors
developed from test data for petroleum
refining process  equipment.
                                                                The  performance of equipment specification is not
                                                                expected  to be different for K-T based synthetic
                                                                fuel plants.
Research needs relate to characterization of the
emissions and not to the controls.
           Status.
           Data Sources:
           PCTM References:
                  C
                  3A
                  Sections  4.1.5  and 4.1.5.2
        Uncontolled Primary Waste Stream
        Storage Emissions (Streams 308 to 313)

        Emission estimates were based upon emission factors
        developed from test data for conventional  petroleum
        liquid storage.  The amount and type of liquids
        stored were determined from the synthesis  process
        used   Liquids with vapor pressure greater than
        10 kPa were assumed to be stored in floating roof
        tanks.  Low vapor pressure liquids were assumed
        to be stored in fixed roof tanks.
                                                     Characterization  data  are  not  available for
                                                     synthetic  liquids or  their vapors.
Exact composition of vapors from synthetic  fuel  storage
may differ from those of conventional  petroleum  liquids;
however, the control technology  that  is  applicable  is
not likely to be affected by these  characteristics.
Since these emissions directly enter  the atmosphere,
additional information on specific  constituents  of  the
vapor insy be desirable.
        Status:
        Data Sources:
        PCTM References:
                C
                3A
                Sections 3.6.5 and 4.1.5
                                                                                                                                                                 (Continued)

-------
TABLE  5-2.    (Continued)
               Data Source and Basis
                                                                        Data  Gaps/Limitations
                                                                                                                                Research Needs
  Control Technology
  Secondary Seals on Floating Roof  Tanks
  Since secondary seals are used  to control
  evaporative emissions from- floating  roof tanks
  storing petroleum liquids, they were assumed to
  be applicable to storage tanks  containing syn-
  thetic liquids.  Emission estimates  were based
  upon emission factors developed from test data
  for petroleum liquids storage.
  Status:
  Data Resources:
  PCTM References:
C
3A
Section 4.1.5
                                 The performance  of  secondary  seals  is not expected
                                 to be different  for synthetic  liquid storage tanks.
Research needs relate to characterization of  the
emissions and not to the controls.
  Internal Floater* or fixed Roof  Tanks

  Since Internal floaters are used to control
  evaporative emissions from fixed roof tanks
  storing petroleum liquids, they  were assumed
  to be applicable to storage tanks containing
  synthetic liquids.  Emission estimates were
  based upon emission factors developed from
  test data for petroleum liquids  storage.

  Status:             C
  Data Sources:       3A
  PCTM References:     Section 4.1.5
                                 The performance  of internal  floaters  is  not
                                 expected to be different for synthetic liquid
                                 storage tanks.
Research needs relate to characterization  of  the
emissions and not to the controls.

-------
                                        TABLE  5-3.    DATA  GAPS  AND RESEARCH  NEEDS  -  AQUEOUS  MEDIUM
                         Technology  Status

         A.   Commercial  application  In a K-T gasification facility

         B.   Bench or  pilot  scale  testing

         C.   Technology  transfer from another Industry -  similar
             but not  identical  streams

         D.   Conceptual
                                                             Key For Technology  Status and Data Sources

                                                                                                         Data Source/Location

                                                                                       1.  AECI Limited, Modderfontein.  South Africa

                                                                                       2.  Nitrogenous Fertilizer  Industry, S.A., Ptolemals, Greece

                                                                                       3.  Technology transfer from  related industries

                                                                                      3A.  Petroleum refining/petrochemical production

                                                                                      3B.  Coke production

                                                                                      3C.  Electric power generation

                                                                                      3D.  Natural  gas processing

                                                                                      3E.  Municipal  waste  treatment

                                                                                       4.  Conceptual  or proposed design/engineering studies

                                                                                       5.  Vendor supplied  information
                        Data Source and Basis
                                                                          Data  Gaps/Limitations
                                                                                                                                   Research Needs
ro
ro
Uncontrolled Primary  Waste  Streams
Cooling and Dust Removal  Slowdown  (Stream 210)

Slowdown composition  is based  upon data from com-
mercial scale gasification  tests with an Illinois
No. 6 coal  at the Nitrogenous  Fertilizers Industry,
S.A. Ptolemals,  Greece.   Halide concentrations
were adjusted consistent  with  coal Cl" and F"
contents.
         Status:
         Data Sources:
         PCTM References:
                  A,  D
                  2,  4
                  Sections 3.3.1 and 4.2.3.3
Available characterization data are limited
to gasification  of one U.S. bituminous coal
and several  foreign  sub-bituminous coals and
lignites.   However,  the quantity and quality
of blowdown  are  highly dependent upon coal
characteristics  and  design specifics.  Data
from gasification of foreign coals reflects
designs  which  are not being proposed for use
in the U.S.
                                                                                                                    The  existing  data base adequately defines ranges of
                                                                                                                    the  primary parameters of concern (eg CN", SCN", NH|
                                                                                                                    and  TOS).  However, these data should be verified 1n
                                                                                                                    U.S.  facilities.
         Primary Compression and Cooling Condensate  (Stream 211)

         Condensate flow rate and NH^,  Cl",  and  F" concentra-
         tions have been estimated oased upon  wasner cooler
         performance during commercial  scale gasification
         tests with an Illinois No. 6 coal at  the Nitrogenous
         Fertilizer Industry, S.A., Ptolemais, Greece.  Other
         parameters are based upon condensate  characterization
         data from commercial K-T gasification at AECI Limited
         which gasifies South African sub-bituminous coal.
                                                      Condensate characterization data  are  avail-
                                                      able only from AECI Limited, and  reflect
                                                      one coal and one washer cooler design.
                                                     Further characterization of this stream may be  of
                                                     limited value due to its low flow rate relative to
                                                     similar process streams (e.g., cooling and dust
                                                     removal blowdown).
        Status:
        Data Sources:
        PCTM References:
                 A, D
                 1, 2, 4
                 Sections 3.3.2 and 4.2.3.2
                                                                                                                                                                (Continued)

-------
 TABLE  5-3.     (Continued)
                Data Source  and  Basis
                                                                  Data Gaps/Limitations
                                                                                                                           Research Needs
Cyanide Mash Water (Stream 215)

The flow rate of cyanide wash  water  1s based upon
nominal flow rate data from AECI  Limited at
Modderfonteln, South Africa.   Wash water composi-
tion has been estimated from gas  solubility data.
                                     No characterization data are available.
Characterization with respect to CN".  SCN" and S  1s
desirable for defining control  processes and costs.
Status:
Data Sources:
PCTM References:
A, D
1. 4
Sections 3.3.4 and 4.2.3.1
Synthesis Mastewaters - Mobil  M (Stream  233),
F-T (Stream 223), and Methanol  Synthesis  (Stream 236)
Condensate

Characterization and flow estimates are from con-
ceptual designs and from data  on  product/compound
production rates.  Fischer-Tropsch estimates
reflect commercial  scale operating data, while
Mobil  M-gasoline estimates reflect pilot scale
data.   Methanol estimates are  from engineering/
cost studies rather than direct test data.
                                     Uncertainties relate to both the extent
                                     to which by-product organics would be
                                     reclaimed within the upgrading operation
                                     and the exact species which are present
                                     in the waste.  The biodegradabilities
                                     of these wastes are also not established.
Actual characterization data may be obtained from
SASOL (F-T) and from existing methanol  plants.   Mobil  M
data will have to await the construction of the first
commercial plant.
Status:
Data Sources:
PCTM References:
B. D
4
Sections 3.4 and 4.2.2
  Control  Technologies
  Filtration	

  Removal  of suspended  solids  is based on perfor-
  mances realized in  parallel  applications, par-
  ticularly the petroleum refining  industry.
  Actual performance  will  depend on the character-
  istics of the filter  media and the characteristics
  of the suspended solids,  including particle size
  distribution and tendency to agglomerate.  Costs
  are based on vendor quotes.
                                     Performance has not been determined for the K-T
                                     wastewaters.
Existing experience from application of filtration to
parallel industries is sufficient to estimate perfor-
mance to within reasonable limits of accuracy.   More
refined'estimates would have little bearing on  the
applicability of this control  technology.
  Status:
  Data Sources:
  PCTM References:
  3A, 3E,  5
  Sections 4.2.1.1,  4.2.2.1,
  4.2.3.1, 4.2.3.2 and 4.2.4
                                                                                                                                                         (Continued)

-------
   TABLE  5-3.    (Continued)
                  Data Source and Basis
                                                                    Data Gaps/Limitations
                                                                                                            Research Needs
  Polysulfide Addition

  Conversion of cyanide to thiocyanate is based on
  the results of EPA-sponsored preliminary kinetic
  studies.  There exists no known precedent for
  effecting the conversion as the basis of a water
  pollution control process, although polysulfide
  is commonly added at key process points in petro-
  leum refineries to control cyanide-induced corro-
  sion.  Capital costs are based on those require-
  ments for chemical addition processes such as
  chemical oxidation and disinfection.  Operating
  costs are dominated by chemical requirements,
  estimated from both stoichiometric and kinetic
  characteristics of the polysulfide reaction.
  Status:
  Data Sources:
  PCTM References:
  B, C, D
  3A, 4
  Section 4.2.1.4, 4.2.3.1
  and 4.2.4
Activated Sludge - Removal  of Organics

Removal of dissolved organics are expected  to
exceed that typically realized in parallel  appli-
cations since only simple,  highly biodegradable
organics are involved.   Actual performance  will
be specific to the exact characteristics  of the
wastewater.  Costs are  based on values  reported
in the literature, appropriately scaled on  the
basis of system loading.
Status:
Date Sources:
PCTM References:
B, C, D
3A, 3B, 3E, 4
Section 4.2.1.5, 4.2.2.1,
and 4.2.4
(1)  Optimal conditions for the polysulfide            (1)
     reaction are not known,  particularly  the  pH
     dependence and the influence of chemical
     species other than cyanide and thiocyanate.

(2)  Residual polysulfide is  expected to precipitate
     at near neutral  pH, posing possible problems  for
     downstream control processes.   Characteristics
     of this precipitate including  its  settleability
     and filterability are not known.                  (2)

(3)  The feasibility  of identifiable methods of
     adding  polysulfide to  the  wastewater  is not
     known.   In particular, it  may  prove feasible
     to add  polysulfide directly  to the cyanide
     wash  on the  gas  cooling/dust removal  circuit.
                                                                                                             (3)
(1)  Performance  has not been determined for the
     K-T  wastewaters.  Only by direct testing of
     the  wastewater to be  treated can the perfor-
     mance  of  an  activated sludge system be deter-
     mined  with certainty.

(2)  The  partitioning of cyanide between that bio-
     degraded, that stripped from solution, and
     that escaping in the  effluent  is not known.
     Several studies in the open literature report
     cyanide as being biodegradable when it occurs
     as part of a large matrix of organic species,
     but  removals vary widely.  Similar unknowns
     exist  for sulfide.
     The affect of residual polysulfide on downstream
     processes and Its amenability to removal by sedi-
     mentation or filtration needs to be determined.
     In particular, since a biological treatment process
     may well follow polysulfide addition, research is
     needed  to determine the fate of residual poly-
     sulfide  in an activated sludge system and its
     affect  on the microorganisms.

     Laboratory tests are needed to more fully define
     the reaction for varying conditions of pH, temper-
     ature,  and concentrations of cyanide and other
     species.  Experience in the petroleum refining
     industry combined with the results of preliminary
     studies  Indicate that the reaction occurs at a
     greatly  increased rate when the polysulfide is
     added as ammonium polysulfide rather than sodium
     polysulfide.  New research efforts should consider
     this.

     Research is needed to determine the feasibility
     of accomplishing the cyanide conversion 1n con-
     junction with some other process, whether that
     be some other water pollution control  process or
     a part of the base plant.   Likely possibilities
     Include addition of polysulfide to the cyanide
     wash or the gas cooling/dust removal  circuit, to
     an ion exchange column, or to an activated sludge
     system.
The fate of cyanide and sulfide in the activated sludge
system needs to be determined.  The biodegradabllity of
cyanide in particular is highly dependent on the partic-
ular microorganisms that are held in the activated
sludge reactor.  Since the characteristics of these
microorganisms are specific to the characteristics of
the wastewater being treated, it is necessary to eval-
uate tne cyanide and suiflde species in a system treat-
Ing either an exact sample of the wastewater or  one
very carefully synthesized.
                                                                                                                                                         (Continued)

-------
         TABLE  5-3.    (Continued)
                        Data Source and Basis
                                                                          Data Gaps/Limitations
                                                                                                                            Research  Needs
ro
en
        Activated Sludge - Removal  of Thiocyanate and Amnonia

        Removal of thlocyanate and  ammonia from  waste-
        waters containing essentially no organics is
        based on performance recorded in the  literature
        and the results of a laboratory scale study.
        Costs are based on values reported in the
        literature, appropriately scaled on the  basis
        of system loading.
                                                       Performance has not been determined for the K-T
                                                       wastewaters.
        Status:
        Data Sources:
        PCTM References:
                  B, C,  D
                  3E, 4
                  Sections  4.2.1.4, 4.2.3.1,
                  4.2.3.2.  and  4.2.4
        Biological Denitrification

        Removals of nitrate are based on  performances
        typically realized in parallel  industries and
        municipal applications.  Costs  are  based on values
        reported in the literature,  appropriately scaled
        on the basis of system loading.
                                                       Performance has not been determined for the K-T
                                                       wastewaters.
Status:
Data Sources:
PCTM References:
B, C, D
3E, 4
Sections 4.2.1.4,  4.2.3.1,
4.2.3.2, and 4.2.4
        Clinoptilolite-based Ion Exchange

        Removal of ammonia is based  on  the  results of
        EPA-sponsored, preliminary laboratory  scale
        studies using a synthetic wastewater having an
        ammonia concentration representative of  that
        expected in the K-T wastewater.   Costs are based
        on values reported in the literature for  two
        plants treating municipal-strength  waste-
        waters:  the Upper Occoquan  plant (Virginia)
        and the South Lake Tahoe plant  (California).
        Costs are extrapolated on the basis of
        ammonia loading.
        Status:
        Data Sources:
        PCTM References:
                  B,  C,  D
                  3E,  4
                  Sections  4.2.4, 4.2.3.1,
                  4.2.3.2,  and 4.2.4
                                                       Performance has not been determined for the K-T
                                                       wastewaters.  Since all existing clinoptilollte-
                                                       based ion exchange systems are designed to treat
                                                       municipal-strength wastewaters, little is  known
                                                       about the cost characteristics of a system
                                                       designed to treat the higher ammonia loadings
                                                       associated wtih the K-T wastewaters.
                                                                                           Bench-scale studies using actual  or synthetic  waste-
                                                                                           waters could better assess the performance and require-
                                                                                           ments of this system.   Commercial  scale  performance
                                                                                           should be determined when U.S. facilities  become  fully
                                                                                           operational.
                                                                                           Bench-scale studies using actual  or synthetic  waste-
                                                                                           waters could better assess the performance and require-
                                                                                           ments of this system.   Commercial  scale  performance
                                                                                           should be determined when U.S. facilities  become  fully
                                                                                           operational.
                                                                                           Preliminary studies need to be supported by a  more  com-
                                                                                           prehensive effort.   Research should be  directed toward
                                                                                           determining feasibility of the process  by concentrating
                                                                                           on the following areas of study:   maximum period of
                                                                                           operating cycle, ammonia leakage  during loading as  a
                                                                                           function of residence time, regeneration requirements
                                                                                           of the cl1noptilol1te resin (including  attrition),
                                                                                           affects of reduced  sulfur and other reduced nitrogen
                                                                                           species on the resin, and possible changes in  species
                                                                                           other than ammonia  passing through the  bed.

                                                                                           Information accumulated by operating systems needs  to
                                                                                           be assembled and then applied to  K-T-related systems.
                                                                                           Areas of information would include more detailed cost
                                                                                           data  and operating  experience with regeneration
                                                                                           equipment.
                                                                                                                                                                 (Continued)

-------
         TABLE  5-3.  (Continued)
                         Data Source and Basis
                                                                          Data Gaps/Limitations
                                                                                                                                    Research Needs
ro
cr>
         Activated  Carbon Adsorption

         Removals of all pollutants are based on data from
         the  refining and by-product coking industries.
         Actual  removal efficiencies will depend on pH,
         molecule size, and structure of the organics
         present  in the wastewater.  Costs are based on
         data from  the refining and by-product coking
         industries, extrapolated on the basis of COD
         loading.
         Status:
         Data Sources:
         PCTM References:
 B,  C
 3A
 Sections  4.2,1.6, 4..2.2.}
 and 4.2.4
        Chemical Oxidation

        Removals are based on the chemical oxidation
        amenability of individual species in the waste-
        water.  Costs are based on data available in  the
        open literature.
Status. B, C, D
Data Sources: 3A, 3E, 4
PCTM References: Sections 4.2
4.2.3.2, and
Thermal Oxidation


.1.6, 4.2.3.1,
4.2.4

Destruction of organics is based on that realized
in other industries where organics, sometimes
much more refractory than those in the K-T
wastewaters, are removed.   Costs are based  on
vendor quotes.

Status:           C
Data Sources:      3A,  3B,  5
PCTM References:  Sections 4.2.1.6, 4.2.2.1
                  and  4.2.4
                                      Performance has not been  determined  for  the  K-T
                                      wastewaters.
                                      No  experience exists  for  testing the K-T waste-
                                      water.   Overall pH dependence and general
                                      reactor  requirements  are  not known.  For waste-
                                      waters where organics are present, removals are
                                      uncertain, and unknown chemical species not
                                      present  in the influent are likely to be found
                                      in  the effluent.
                                                               Performance has not been determined  for  the  K-T
                                                               wastewaters.
                                                                                                             Laboratory or pilot scale tests  are  needed  on  the  K-T
                                                                                                             wastewaters.   While many of the  individual  chemical
                                                                                                             species determining COD are known, the  performance can-
                                                                                                             not be synthesized from performances typical for indi-
                                                                                                             vidual species.   Performance is  generally specific to
                                                                                                             the wastewater being treated and therefore  must be deter-
                                                                                                             mined on an individual  case basis.
                                                                                                             Testing  of  the  K-T wastewaters on a scale larger than
                                                                                                             laboratory  scale  is needed  to better assess treatability.
                                                                                                             Destruction  of  chemical  species by chemical oxidation
                                                                                                             under  carefully controlled  conditions are not necessarily
                                                                                                             realized  in  a full scale process.
                                                                                           Additional  research is  not  likely  to  improve  the present
                                                                                           data  base.   Considerable  research  has been completed  in
                                                                                           recent years,  particularly  In  the  area of destroying
                                                                                           organics  regarded  as  hazardous.  The capabilities and
                                                                                           limitations  of the process  are thereby well established.
        Cooling Tower Concentration

        All  chemical  species  with  exception  of ammonia
        and  sulfide are  assumed  to be  concentrated into
        the  blowdown  stream without  losses due to
        volatilization or  drift.
        Status:
        Data  Sources:
        PCTM  References:
D
4
Sectons 4.2.1.7, 4.2.2.1,
4.2.3.1, 4.2.3.2 and 4.2.4
                                     Performance has not been determined for the K-T
                                     wastewaters.  Loss of volatile species and poten-
                                     tial for corrosion are not known.
                                                                                                            Regardless of research, the feasibility of cooling tower
                                                                                                            concentration would be determined on an individual case
                                                                                                            basis.  Commercial scale performance should be evaluated
                                                                                                            in fully operational U.S.  facilities.
                                                                                                                                                                 (Continued)

-------
 TABLE  5-3.   (Continued)
               Data Source and Basis                             Data Gaps/Limitations                                    Research Needs

Forced Evaporation

All chemical  species with the exception of ammonia      Performance has not been determined for the K-T       Unknowns  are not expected to have a significant  impact
and sulfide are assumed to be concentrated into         wastewaters.  The concentration of  individual         on the  applicability of this process.   However,  perform-
the blowdown  stream without losses  due to volatil-      chemical species that will  be carried over into       ance should be evaluated in fully operational  U.S.
Ization.   Costs are based on vendor quotes.             the evaporator overhead is  not known.  Extent of      facilities.
                                                      corrosion potential is not  known.

Status:           D
Data Sources:     4, 5
PCTM References:  Sections 4.2.1.7, 4.2.2.1,
                 4.2.3.1, 4.2.3.2  and 4.2.4

-------
                                  TABLE  5-4.   DATA  GAPS  AND  RESEARCH  NEEDS  -  SOLID MEIDUM
                                                            Key For Technology Status and Data Sources
                     Technology  Status
                                                                                                        Data Source/Location
A.  Commercial  application  1n a K-T gasification  facility

B.  Bench or pilot scale  testing

C.  Technology  transfer from another industry -  similar
    but not identical  streams

D.  Conceptual
                                                                     1.  AECI Limited, Modderfonteln,  South Africa

                                                                     2.  Nitrogenous Fertilizer Industry,  S.A., Ptolemais, Greece

                                                                     3.  Technology transfer from related  industries

                                                                    3A.  Petroleum refining/petrochemical  production

                                                                    3B.  Coke production

                                                                    3C.  Electric power generation

                                                                    3D.  Natural gas processing

                                                                    3E.  Municipal waste treatment

                                                                     4.  Conceptual or proposed design/engineering studies

                                                                     5.  Vendor supplied information
                Data  Source and Basis
                                                Data Gaps/Limitations
                                                                                                                          Research Needs
1^3      Uncontrolled Primary Waste Streams
00      Quenched  Slag  (Stream 207)	

        Slag  generation rates, Teachability  data and resi-
        dual  moisture  are based upon commercial scale gasi-
        fication  of an Illinois No.  6 coal at  the Nitro-
        genous  Fertilizers Industry, S.A.  in Ptolemais,
        Greece.   Contaminants in the residual  moisture have
        been  estimated assuming a common slag  quench/washer
        cooler  water circuit, without slag rinsing.
                                                      Slag/dust ash partitioning and slag leachability
                                                      data  are not available for other bituminous
                                                      coals or lower rank coals.
Status:
Data Sources.
PCTM References:
A, D
2, 4
Sections 3.2.1  and 4.3.2.1
                                                                                         Slag/dust partitioning and slag  Teachability data
                                                                                         for  other bituminous coals and lower rank coals should
                                                                                         be determined.  Partitioning data  for various ranks
                                                                                         of foreign coals may be obtainable through licensors/
                                                                                         operators.
                                                                                                                                                      (Continued)

-------
TABLE  5-4.    (Continued)
                Data Source and Basis
                                                                  Data Gaps/Limitations
                                                                                                                            Research Needs
Dewatered K-T Dust (Stream 209)

The composition of dry K-T dust  and  the associ-
ated liquids are based upon data from commercial
scale gasification of Illinois No. 6 coal at the
Nitrogenous Fertilizers Industry,  S.A. in Ptolemais,
Greece.  A nominal dewatered dust  moisture content
has been assumed consistent with that indicated
in a conceptual design for a sub-bituminous coal
based hydrogen production facility.
                                     Slag/dust ash partitioning data,  dust carbon  and
                                     sulfur contents, and dust Teachability data are
                                     not available for other bituminous coals or lower
                                     rank coals.  Dust dewatering data and structural
                                     stability data are not available.
Status:
Data Sources:
PCTM References:
A. D
2, 4
Sections 3.2.1  and  4.3.2.1
  Control Technologies
  Resource Recovery

    Reuse as Construction Material

    Potential alternatives for recycling the gasi-
    fier slag are based upon current  practices for
    ash from coal-fired power plants.
    Status:
    Data Sources:
    PCTM Reference:
   C
   3C
   Section 4.3.2.1
Fluidized Bed Combustion  of Dust

The burning of K-T dust in a fluidized bed
combustion (FBC) boiler is based  upon an
approach under consideration for  a proposed
K-T plant in Alabama and  an existing K-T
plant in Modderfontein, South Africa.

Status:           B, D
Data Sources:    1, 4
PCTM Reference:   Section  4.3.2.1
                                     The available market for recycling the slag is
                                     uncertain.
                                                       (1)  The viability of commercial scale FBC boiler
                                                            using dewatered K-T dust as fed has not been
                                                            proven.

                                                       (2)  Although there are cost data for coal-fired
                                                            FBC units, these data may not apply to com-
                                                            bustion of high moisture and ash K-T dust.
                                                                                                         Slag/dust ash partitioning data, dust carbon and sulfur
                                                                                                         contents, and dust Teachability data for other bitumi-
                                                                                                         nous coals and  lower rank coals should be determined.
                                                                                                         Partitioning and dust characterization data for various
                                                                                                         ranks of foreign coals may be obtainable through
                                                                                                         licensors/operators.  Dust dewatering data should be
                                                                                                         obtained for a  range of coal types.  Engineering and
                                                                                                         geotechnical data are needed to establish design data
                                                                                                         for land-based  disposal techniques.
                                                                                                         The  availability of market  is highly dependent upon
                                                                                                         local  conditions which can  only be assessed on a site-
                                                                                                         by-site  basis.
                                                                                           The viability  of  FBC  with  K-T  dust  should be determined.
                                                                                           Data  might  be  obtainable through AECI Limited which is
                                                                                           currently evaluating  this  alternative.
      Secondary Waste Streams
      o  FBC Boiler Ash


      o  Spent FBC Boiler Bed Sorbcnt
                                     No Teachability data are available.
                                     The flow rate and the Teachability of this mate-
                                     rial is not known.
                                                                                                         The Teachability  data  should  be  determined for range
                                                                                                         of coal  types.

                                                                                                         The flow rate  and the  Teachability of  this material
                                                                                                         might be obtained from AECI.
                                                                                                                                                          (Continued)

-------
TABLE  5-4.    (Continued)
              Data Source and Basis
                                                                Data Gaps/Limitations
                                                                                                                         Research Needs
 Landfill

 Landfilling of the waste is based upon current
 practices  in  the electric utility industry and
 other  industries.
 Status:
 Data  Sources:
 PCTM  Reference:
C
3C
Section 4.3.2.1
                                    The long term leachate  generation rates and char-
                                    acteristics  are  not  known, and the compatibility
                                    and long term performance of landfill liners have
                                    not been established.
 Surface  Impoundment

 Disposal  of waste  in surface impoundments is
 based  upon current practices in the electric
 utility  industry and other industries.
                                    Same as  landfill.
 Status:
 Data  Sources:
 PCTM  Reference:

   Fixation
C
3C
Section 4.3.2.1
   Fixation of the  K-T  dust  to  Improve Us struc-
   tural  stability  and  leachablllty characteristic
   1s based on current  practices for FGD sludge
   and other industrial wastes.
                                    Performance and cost for the application are not
                                    known.
   Status:
   Data Sources:
   PCTM References:
     C
     3C
     Section 4.3.2.1
Long term column or landfill  cell  studies  are  needed
to characterize the leachate  and to  determine  liner
performance.  Appropriate materials  for  these  tests
may not be available until  the  first K-T plant  is con-
structed in the U.S.  Also,  since  these  are  long term
studies the data may not be  available in time  to
influence facility designs  that are  currently  in
advanced stages.
                                                                                         Same as  landfill.
Treatability studies  with  various chemical additives
should be performed  to  determine the technical and
economic feasibility  of this approach.

-------
   TABLE   5-5.     DATA   GAPS  AND   RESEARCH   NEEDS  -  PRODUCTS/BY-PRODUCTS
                                                   Key for Technology Status  and Data Sources
                          Technology  Status
                                                                                                       Data Sources
A.  Commercial  application In a K-T gasification facility

B.  Bench scale or pilot testing

C.  Technology  transfer front another Industry - similar but  not
    identical streams

D.  Conceptual
                                                                              !.  AECI Limited, Modderfontein, South Africa

                                                                              2.  «ftrogeneous ferttlizer Industry, S.A., PtoJawls.

                                                                              3   Technology  transfer from related  Industries

                                                                             3A.  Petroleum refining/petrochemical  production

                                                                             38.  Coke production

                                                                             3C.  Electric  power generation

                                                                             3D   Natural gas processing

                                                                             3E.  Municipal waste treatement

                                                                             3F.  Methanol  production

                                                                              4   Conceptual  or proposed design/engineering studies

                                                                              5.  Vendor supplied Information
           Data  Source and Basis
                                                           Data Gaps/Limitations
                                                                                                                Research Needs
Flscher-Tropsch  Synthesis Products
baseline.  Diesel Oil. Heavy Oil. Alcohols.
LPG and SBG (Stream tOO through  1Q7)

Production rates and composition estimates are
based upon conceptual designs for coimercial
scale F-r  faculties.
Status:
Data Sources
PCTH References
                     D
                     4
                     Sections  3 4.2 and 3 5 2
Characterization, storage stabi1ity,and «*•
data for F-T  products are lirnted   The influence
of synthesis  process variables on product cfcjrac-

medlates processdbility, and consumption/utilization
characteristics are similarly largely unknown.
Detailed  characterization data  are
desirable.  Environment*! effects
associated with fugitive and evapora-
tive emissions and product utilization
should b* determined   Such effects
should be evaluated relative to environ
mental effects associated with  analog
petroleum products.
Methanol  Synthesis Product
Fue _1_G r_a de Jteth anp_j_ iS_tream__i 08J

Production  rates are based upon conceptual
designs for commercial scale methanol
facilities.  Composition estimates are
based upon  conceptual designs  and analyses
of metha.no!  produced from petroleum feedstocks
Source:
3ata  Sources:
?CTM  References.
                     C, D
                     3F, 4
                     Sections  3 4.1 and 3 S 1
lobll  M-gasoltne Synthesis  Products
gasoline. HI »fd Butanes . and  Propane
.'Streams  109.  HO. and 1HJ
^reduction  rates and composition estimates are
used  upon  conceptual designs of commercial
-,cale  Hob II H-gasollne facilities
Status.
Jata  Sources:
References:
                     D
                     4
                     Sections 3 4 4 and 3 5.3
                                                 Characterization data  for methanol from indirect
                                                 coal liquefaction are  limited   The Influence of
                                                 synthesis process variables on product  wthanol
                                                 characteristics 1s unknown
                                                Characterization data  for Mobil M-gasollne
                                                products are limited   The Influence of synthesis
                                                process variables on product characteristics
                                                is unknown.
                                                     The EPA Office  of Pesticides and Toxic
                                                     Substances has  declared that methanol,

                                                     does not require Premanufacturlng Notices
                                                     for the production of coal-based methanol.
                                                     On this basis,  no research effort )s
                                                     required.
                                                     Detailed characterization data are desirable.
                                                     Environmental effects asslciated with fugitive
                                                     and evaporative emissions and product
                                                     utilization  should be determined. Such
                                                     effects shoutd be evaluated1 relative to
                                                     environmental effects associated with analog
                                                     petroleum products.
3y-Products
Sulfur from Claus .
 Stream 403 and 41
                   I  Stretford Process
^reduction  rate estimates  are based upon pub-
Msned  control performance data and engineering
estimates of waste gas sulfur contents
.tatus
iata  Sources -
Deferences:
                     C,  D
                     3A. 3B. 3D, 4
                     Sections 4.1.1. 4 1.1  1
                     and 4.1.1 5
                                                Essentially, no  characterization data  are available
                                                for Claus and Stretford sulfur
                                                     Characterization of sulfur is desirable,
                                                     particularly with respect to contaminants

                                                     possible  downstream processing for various
                                                     purposes
                                                                    431

-------
 Section 6
 References
                                 SECTION  6

                                 REFERENCES
 1.   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.

 2.   Conceptual  Design of a Coal-to-Methanol-to-Gasoline Commercial  Plant.
     Volume I,  Badger Plants Incorporated,  Cambridge,  Mass.,  FE-2416-43.

 3.   R.M.  Parsons Co., Screening Evaluation for  Synthetic  Liquid Fuels
     Manufacture, EPRI AF-523, August 1977.

 4.   Billings,  Roger E.  Hydrogen from Coal Cost Estimation Guidebooks.
     NASA-CR-164692,  1981.

 5.   Fischer-Tropsch Design Project Capital Cost Validation,  U.S.  Army
     Engineer Division, Huntsville, Alabama,  U.S.  Department of Energy
     Report No.  FE-1759-2,  October 1977.

 6.   Preliminary Economic Analysis of Lurgi Plant Producing 250 Million SCFD
     Gas from New Mexico Coal, U.S. Department of the Interior, Bureau  of
     Mines, Morgantown, West Virginia, ERDA Document No. 76-5,  March 1976.

 7.   Gesellschaft ftir Kohle-Technologie mbH.   Large Scale  Gasification  Tests
     with  U.S.  Coal in Ptolemais, Greece,  for Tennessee Valley  Authority,  USA.
     Essen, Federal Republic of Germany.   Final  Report, Vol.  Ill,  October 1981

 8.   Firnhaber,  B. and R.  Wetzel.  Status  of Entrained Coal Gasification
     According  to Koppers-Totzek and Shell-Koppers.  The Institute of Chemical
     Engineers,  Symposium Series No. 62,  1980.

 9.   Trials of American Coals in a Lurgi  Gasifier at Westfield, Scotland.
     Woodall-Duckham, Ltd., Sussex, England.   ERDA R&D Report No.  105,  1974.

10.   Souther, N.F., et al.   Potential Trace Element Emissions from the  Gasi-
     fication of Illinois Coal, Illinois Institute of Environmental Quality
     No. 75-08,  February 1975.

11.   Axetell, K., Jr.  Survey of Fugitive  Dust from Coal Mines, (PEDCo
     Environmental, Inc.),  EPA-908/1-78-003,  February 1978.

12.   Blackwood,  T.R.  and,R.A. Wachter.  Source Assessment:  Coal Storage
     Piles, Monsanto Research Corporation,  Dayton, Ohio, May 1978.


                                     432

-------
                                                                  Section 6
                                                                  References
13.  Jutze, G.A., et al.   Technical  Guidance for Control  of Industrial  Process
     Fugitive Emissions.   PEDCo Environmental, Cincinnati, Ohio, March  1977,
     NTIS:  PB 272-288.

14.  Buroff, J., J. Strauss, A. Jung and L.  McGilvary.  Environmental  Assess-
     ment:  Source Test and Evaluation Report,  Coal Preparation Plant  No.  1
     (Versar Inc.) U.S.  Environmental  Protection Agency,  Research Triangle
     Park, North Carolina, July 1980.

15.  Buroff, J., J. Strauss, A. Jung and L.  McGilvray.  Environmental  Assess-
     ment:  Source Test and Evaluation Report, Coal  Preparation Plant No. 2.
     Draft Report (Versar Inc.) U.S. Environmental  Protection Agency,  Research
     Triangle Park, North Carolina,  March 1981.

16.  Wewerka, E.M., et al.  Trace Element Characterization of Coal Wastes:
     Second Annual Progress Report,  Los Alamos Scientific Laboratories, EPA-
     600/7-78-028, July 1978.

17.  Cox, D.P., T.Y.J. Chu and R.J.  Ruane.   Characterization of Coal  Pile
     Drainage, TVA, EPA-600/7-79-051,  February 1979.

18.  Ferraro, F.A.  Treatment of Precipitation Runoff from Coal  Storage Piles,
     Presented at Third Symposium on Coal Preparation, NCA/BCR,  Louisville,
     Kentucky, October 1977.

19.  Wewerka, E.M., J.M.  Williams, P.L. Wanek, and  J.D. Olsen.   Environmental
     Contamination from Trace Elements in Coal Preparation Wastes, Los  Alamos
     Scientific Laboratories, EPA-600/7-76-007.

20.  PEDCo-Environmental, Inc., Assessment of Fugitive Particulate Emission
     Factors for Industrial  Processes, Cincinnati,  Ohio,  EPA-450/3-78-107,
     September 1978.   NTIS:PB-288-859.

21.  PEDCo-Environmental, Inc., Environmental Assessment  of Coal Transporta-
     tion, Cincinnati, Ohio, EPA-600/7-78-08, May 1978.

22.  Rittenhouse, R.C.  Fuel:   Handling and  Storage  at Power Plants,  Power
     Engineering, December 1979.   pp.  42-50.

23.  U.S. EPA, Compilation of Air Pollution  Emission Factors, Office of Air
     Quality Planning and Standards, Research Triangle Park, N.C., AP-42.

24.  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.


                                    433

-------
Section 6
References
25.   FMC Corporation,  Gasification of COED Chars in a Koppers-Totzek Gasifier,
     EPRI AF-615, July 1978.

26.   The Dravo Corporation.   Handbook of Gasifiers and Gas Treatment Systems.
     Report prepared for the  United States Energy Research and Development
     Administration, FE-1772-11,  February 1976.

27.   GKT Gesellschaft fur Kohle-Technologie mbH.  GKT's Coal  Gasification
     Process Facts and Data.

28.   Chaurey, K.H. and K.C.  Sharma.  Coal Based  Ammonia Plants - Preliminary
     Operating Experience of  Coal  Gasification at Talcher and Ramagundam
     Fertilizer Plants of the Fertilizer Corporation of India.  Symposium
     on Ammonia from Coal, Tennessee Valley Authority, Muscle Shoals,
     Alabama, May 8-10, 1979.

29.   Engelbrecht, A.D. and L.J.  Partridge.  Operating Experience with a 1000
     ton/day Ammonia Plant at Modderfontein.  Symposium on Ammonia from Coal,
     Tennessee Valley Authority,  Muscle Shoals,  Alabama, May  8-10, 1979.

30.   Farnsworth, J.F., D.M.  Mitsak, and J.F. Kamody.  Clean Environment
     with K-T Process.  Presented at EPA Meeting:  Environmental Aspects of
     Fuel Conversion Technology,  St. Louis, Missouri.  May 13-16, 1974.

31.   Hunter, C.A. and K.Y. Yu.  Characterization of Solid Wastes from In-
     direct Liquefaction Facilities.  Environmental Aspects of Fuel  Conver-
     sion Technology - VI, A Symposium on Coal-Based Synfuels, Denver,
     Colorado, October 26-30, 1981

32.   Tennessee Valley Authority,  Office of Natural Resources.  Wastewater
     and Solid Waste Characteristics, Process and Nonprocess  Units.   Pre-
     pared for Office of Coal Gasification, October 1982.

33.   Unpublished TRW non-proprietary data obtained during testing at the
     Nitrogenous Fertilizer Industry (NFI), Ptolemais, Greece.

34.   Wetzel, R.E., K.W. Crawford, and W.C.Yee.  Environmental Aspects of the
     GKT Coal Gasification Process.  EPA Symposium on Environmental  Aspects
     of Fuel Conversion Technology-IV, Denver, Colorado, October 26-30, 1981.

35.   Ranke, G.  Acid Gas Separation by Rectisol  in SNG Processes, Linde AG,
     Munich, Germany,  copy of presentation obtained through Lotepro Corpora-
     tion, New York, N.Y.
                                    434

-------
                                                                  Section 6
                                                                  References
36.  Seidell,  A., and W.F.  Linke.   Solubilities,  Inorganic  and Metal-Organic
     Compounds.   D.  Von Nostrand Company,  Inc.,  Princeton,  New Jersey,  1958.

37.  Scholz, W.H.  Rectisol:   A Low-Temperature  Scrubbing Process  for  Gas
     Purification, Advances in Cryogenic Engineering,  Vol.  15, 1969.

38.  Lotepro Corporation.   Capabilities  brochure  by  Lotepro Corporation.

39   Information supplied  by  South African Coal,  Oil,  and Gas Corp.  Ltd.,
     to EPA's  Industrial  Environmental  Research  Laboratory, Research Triangle
     Park, November 1974.
40.  Satterfield, C.N.  Heterogeneous Catalysts  in Practice, McGraw-Hill
     Book Co., New York, N.Y., 1980.

41.  Catalyst Handbook, Imperial Chemical  Industries,  Ltd., Springer-Verlag,
     New York, N.Y., 1970.

42.  Katalco 71-7 High-Temperature Shift Catalyst Data Sheet,  Katalco  Corp.,
     Oak Brook,  Illinois,  1981.

43.  Dybkjaer, Ib.  Carbon Monoxide Shift Catalysts  and Carbonyl  Sulfide
     Hydrolysis  Catalysts.  Ammonia from Coal Symposium, Tennessee Valley
     Authority,  May 8-10,  1979.

44.  Katalco 49-2 Cobalt-Molybdenum Shift Catalyst Data Sheet,  Katalco Corp.,
     Oak Brook,  Illinois.

45.  Katalco 52-2 Low Temperature Shift Catalyst Data  Sheet, Katalco Corp.,
     Oak Brook,  Illinois,  1976.

46.  Telephone Memorandum, Blythe, B., Davy McKee, Lakeland, Florida,
     November 5,  1981.

47.  Telephone Memorandum, Sandlin, A.D., Harshaw Chemical  Co.,  Houston,
     Texas, August 14, 1981.

48.  Telephone Memorandum, Rounthwaite,  D., Katalco  Corp.,  Oak  Brook,
     Illinois, November 5, 1981.

49.  Kohl, A.  and F. Reisenfeld.  Gas Purification,  Gulf Publishing Col,
     Houston, Texas, 1974.

50.  Maddox, R.N.  Gas and liquid Sweetening, Campbell Petroleum  Series,  1974.
                                     435

-------
Section 6
References
51.  U.S. EPA, Control  of Emissions from Lurgi  Coal  Gasification Plants,
     Office of Air Quality Planning and Standards,  Research Triangle Park,
     N.C.  EPA-450/2-78-012,  OAQPS 1.2-073,  March 1978,  178 p.

52.  Information provided to  TRW by Linde AG,  November 1982.

53.  Allen, D.W.  Final  Sulfur Removal  in Ammonia from Coal Plants,  Symposium
     on Ammonia from Coal, Tennessee Valley  Authority, Muscle Shoals,
     Alabama, May 8-10,  1979.

54.  Ghassemi, M., K.W.  Crawford, and S. Quinlivan.   Environmental Assessment
     Data Base for High-Btu Gasification Technology.   Volumes I-III, TRW
     Environmental Engineering Division, Redondo Beach,  California,  EPA-600/
     7-78-186a, b, and  c, September 1978.

55.  Ghassemi, M.  et al.   Applicability of Petroleum  Refinery Control
     Technologies  to Coal  Conversion.   (TRW  Inc.),  EPA 606/7-78-190, Oct.
     1978.

56.  Manual  on Disposal  of Refinery Wastes - Volume on Liquid Wastes.
     American Petroleum  Institute,  First Edition 1969.

57.  Manual  on Disposal  of Refinery Wastes - Volume on Atmospheric Emissions,
     American Petroleum  Institute,  Publication  No.  931.

58.  Sinor, J.W.  Evaluation  of Background Data Relating to New Source Per-
     formance Standards  for Lurgi Gasification, Cameron Engineers Inc ,
     Denver, Colorado,  EPA 600/7-77-057, June  1977,  233 p.

59.  Mehta, D.D. and W.W. Pan.  Purify Methanol This  Way.   Hydrocarbon
     Processing, February 1971.  pp. 115-120.

60.  C.F. Braun and Company,  Carbonyl  Formation in  Coal  Gasification Plants,
     Prepared for Energy Research and Development Administration and American
     Gas Association, FE-2240-16, December 1974.

61.  Storch, H.H., et al., Synthetic Liquid  Fuels from Hydrogenation of Carbon
     Monoxide, U.S.  Bureau of  Mines,  1948.

62.  Hueper, W.C.   Experimental  Carcinogenic Studies  of  Hydrogenated Coal Oils,
     II,  Fischer-Tropsch  Oils, Industrial  Medicine  and Surgery,  October,  1956,
     p.  459-462.
                                    436

-------
                                                                  Section  6
                                                                  References
63.  Hoogendorn,  J.C.   Experience  with  Fischer-Tropsch  Synthesis at SASOL,
     paper presented  at Institute  for Gas  Technology, Chicago,  Illinois,
     1973, pp.  353-365.

64.  Schreiner,  E.  Motor  Gasolines, Summer  1979, U.S.  Department of Energy,
     Bartlesville Energy Technology  Center,  Bartlesville, Oklahoma, February
     1980.

65.  Mullowney,  J.F.  and P.F.  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, 20  pp.

66.  Bowden, J.M. and D.W.  Brinkman.  Stability of  Alternate Fuels.  Hydrocar-
     bon Processing,  July  1980,  pp.  77-82.

67.  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,
     79 pp.

68.  Smith, R.P.   Toxic Responses  of the Blood, Chapter 14.  In: Casarett and
     Doull's Toxicology: The Basic Science of Poisons,  Second Edition,
     J. Doull,  C.D.  Klaasen  and  M.O. Amdur,  eds., Macmillan Publishing Co.,
     Inc., New York,  New York, 1980, pp. 311-331.

69.  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.

70.  Seames, Wayne  S.   The  Kosovo  Lurgi Gasification Plant Phase I and Phase
     II Data Compilation,  Draft  Report  prepared by  Radian Corp. for EPA,
     February  18, 1980.

71.  U.S.  Geological  Survey, Quality of Surface Waters  of the U.S., Water
     Supply Paper 2143, 1969.

72.  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.

73.  Goldstein,  D.J.  and D.  Yung.  Water Conservation and Pollution Control in
     Coal  Conversion  Processes,  EPA-600/7-77-065, June  1977.
                                     437

-------
Section 6
References
74.  Dickey, J.B. and D.N.  Dwyer.   Managing Waste Heat  with  the  Water Cooling
     Tower, Missouri  Valley Electric Association, 1979  Engineering  Conference,
     3rd Edition.

75.  Scharle,  W.J.  Large  Oxygen  Plant Economics  and Reliability, TVA
     Symposium on Ammonia from Coal,  Muscle Shoals, Alabama, May 8-10,  1979.

76.  Op.  Cit., Reference  23.

77.  Pacific Environmental  Services.   Compliance  Analysis of Small  Bulk  Plants,
     Report prepared  under  EPA Contract  68-01-3156, Task No. 17, October 1976.

78.  Wetherold,  R.  and  L. Provost.   Emission  Factors  and Frequency  of Leak
     Occurrence  for Fittings  in  Refinery Process  Units.  EPA 600/2-79-044,
     February  1979.

79.  Wetherold,  R.G.,  L.P.  Provost,  and  C.D.  Smith.   Assessment of Atmos-
     pheric Emissions  from  Petroleum  Refining, Appendix F.  EPA-600/2-80-075q,
     U.S.  Environmental Protection  Agency,  April  1980.

80.  Water Reuse Studies, API Publication 549,  August 1977.

81.  Climatic Atlas of the United States, DOC-NOAA,  1974.

82.  Coal  Gasification Project,  Draft Environmental  Impact  Statement.
     Tennessee Valley Authority, 1980.

83.  Lim,  K.J.,  H.  Lips and R.J. Milligan.   Technology  Assessment Report for
     Industrial  Boiler  Applications:  NO   Combustion Modification, EPA
     600/7-79-178f, December  1979.

84.  Acurex Corp.,  Control  Techniques for Nitrogen Oxides Emissions from
     Stationary  Sources - Second Edition,  EPA-450/1-78-001, January 1978.

85.  Telephone Memorandum,  Joe  Barrows,  Babcock  and Wilcox, Ohio, June 30,
     1982.

86.  TRW In-house information obtained from Mike Boughton,  Redondo  Beach,
     California, September  1981.

87.  Young, C.W., et  al.   Technology Assessment  Report  for  Industrial Boiler
     Applications:  Fluidized  Bed-Combustion, EPA 600/7-79-178e,  November
     1979.

88.  Information provided to  TRW from Black & Veatch, April  1981.


                                     438

-------
                                                                  Section 6
                                                                  References
89.  Castelini,  J.   Fugitive Coal  Dust Control.   Power  Engineering,  July
     1979.   pp.  86-87.

90.  Op.  Cit., Reference 13.

91.  Bulk Gasoline  Terminals - Background  Information  for Proposed  Standard.
     Draft  report,  Emission Standards and  Engineering  Division,  U.S.  EPA,
     May 1980.

92.  VOC Emissions  from Volatile Organic Liquid  Storage Tanks  -  Background
     Information for Proposed Standards, Preliminary Draft,  Emission
     Standards and  Engineering Division, U.S.  EPA,  November  1980.

93.  Control of Volatile Organic Compound  Leaks  from Petroleum Refinery
     Equipment,  Guideline Series,  Emission Standards and Engineering Division,
     U.S. EPA, EPA  450/2-78-036, June 1978.

94.  Industrial  Ventilation.  A manual of recommended  practice by  the Committee
     on Industrial  Ventilation, Michigan,  U.S.A.  Twelfth Edition,  1972.

95.  Pojasek,  R.B.,  ed.   Toxic and Hazardous Waste  Disposal, Vol.  I.   Ann
     Arbor  Science  Publication, Inc., Ann  Arbor, Michigan, 1979.

96.  Conner, J.R.   Disposal  of Liquid Wastes by  Chemical  Fixation, Waste Age,
     September 1974, pp. 26-45.

97.  Michael Baker,  Jr., Inc.  Electric Power  Research  Institute Report No.
     EPRI FR-671, January 1978.

98.  Survey of Solidification/Stabilization Technology  for Hazardous  Industrial
     Wastes.  EPA Report No. EPA 600/2-79-056, July 1979.

99.  Couch, A.T. and W.L.E.  Davey.  The Use of  Fluidized Combustion to Burn
     the Fly  Ash from Koppers-Totzek  Gasifiers.   The International Coal Con-
     version  Conference, Pretoria, South Africa, August 16-20, 1982.
                                     439

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                                                                   Appendix A
                                                                   Costing
                                 APPENDIX A
                  COSTING  METHODOLOGY,  BASES, AND ASSUMPTIONS

     Capital  and total  annualized cost  estimates were developed for uncon-
trolled Koppers-Totzek  (K-T)  based  synfuels  facilities and for pollution
control processes in order to provide an indication of the economic impact
of pollution controls.   These estimates are  based  primarily on factored
estimates of costs contained  in non-proprietary published literature.   As
such, they should be viewed only as general  indicators of expected costs and
should not be construed as definitive cost estimates for a specific plant.
All costs have been adjusted  to a 1980  dollar basis using generally accepted
cost indexes such as the Chemical Engineering (CE)  plant cost annual  index.
     To the extent possible,  the same methodology  was used to develop  capital
and total annualized cost estimates for both the base plants and pollution
controls.  Details of these methodologies are presented in Sections A.I and
A.2, respectively.  The bases for the base plant cost estimates are pre-
sented in Section A.3.   Bases for the pollution control cost estimates are
presented in the Pollution Control  Appendices for  the PCTM series.

A.I  CAPITAL COST ESTIMATING METHODOLOGY
     Costs presented as capital costs or investments in the K-T PCTM are
total depreciable investments (TDI).  TDI includes:
     1)  purchased and delivered equipment costs;
     2)  labor and materials  costs to install equipment;
     3)  indirect installation charges, such as
         •  engineering and construction costs,
         •  contractor fees,  and
         t  project and process contingency reserves, and;
     4)  interest expenses on capital spent prior to start of production
         (interest during construction).
                                     A-l

-------
Appendix A
Costing
A variety of methods can be used to estimate the above cost items, although
most methodologies utilize a factored approach.   In factored cost estimates,
the cost 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 as a "factor" times the purchased and delivered
equipment costs or other subsequently derived subtotal.
     For costs 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 delivered equip-
ment costs:  some data are published as installed equipment costs (purchased
equipment plus direct installation costs), some include one or more of the
indirect installation charges (listed previously), some are TDI estimates, and
others are total capital investment requirements (TDI plus working capital and
land costs).
     In order to provide consistency in the various capital cost estimates
required for the PCTM, a capital cost methodology was developed.  The method-
ology (and cost factors) used are summarized in Table A-l.  Most cost data
obtained from the  literature were  installed equipment costs (IEC) which often
included components such as piping, instrumentation, and  substructures.  As
indicated  in the table, indirect installation charges were  estimated as 48%
of the  IEC.  Adding the indirects  to the  IEC gave  the total plant  (or process)
costs.   Interest during construction (IDC) was estimated as  22.6% of the total
plant costs.  The  total depreciable investment  (TDI) is the sum of these  two
terms.  Working capital (WC) for the base plant  cost estimates has been
assumed to be the  value of a 60 day coal  inventory.  No provision  for working
capital related to pollution control equipment  has been included.  Summing
the TDI and WC gives the total capital investment  (TCI).   It should be noted
that the PCTM does not address a specific K-T synfuels facility or facility
location,  and thus the amount and  value of associated land  is  unknown.  There-
fore, for  cost estimating purposes, the cost of  land has  not been  included in
the total  capital  investment estimates presented.
                                     A-2

-------
                                                                   Appendix  A
                                                                   Costing
                  TABLE A-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 (TPC = IEC + IIC)
Interest During Construction (IDC =  22.6% of TPC)
Total  Depreciable Investment (TDI =  TPC + IDC)
Working Capital (WC = value of 60 day coal  inventory for base plant cost
                 estimates)
*Total Capital,Investment (TCI = TDI + WC)

*The PCTM does not address a specific K-T synfuels facility or facility
 location, and thus the amount and value of associated land is not unknown.
 Therefore, for cost estimating purposes the cost of land has not been in-
 cluded in total capital investment estimates presented in this PCTM.
A.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), raw materials, chemicals, cata-
lysts, 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  A-2.  All  of  the terms listed in Table A-2, except capital
recovery, are  expressed  in  first year  costs  (i.e., in constant 1980 dollars).
The capital  recovery, however,  is a  levelized value calculated  using  standard
present  worth  and  levelized cost procedures  and the economic assumptions
listed in Table  A-3.
                                     A-3

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                    TABLE A-2.   UNIT  COSTS AND  FACTORS  FOR  ANNUALIZED  COST  ESTIMATES
Operating Labor  (Sll/hr)
Supervision  (15% of operating labor)
Maintenance  (2% of total depreciable investment)
Maintenance  Supervision  (5% of maintenance)
Raw  Illinois No. 6 Coal  ($35.44/Mg)
Raw  Water ($0.031/m3)
Utilities
     Steam ($6.30 to $9.10/Mg depending on quality)
     Electricity ($0.033/kW-hr)
     Fuel Gas ($1.79/GJ)   ?
     Cooling  Water ($0.08/nr)   ?
     Boiler feed water  ($0.264/m )
Chemicals and Catalysts  (representative early 1980 costs)
Overhead Charges
     Plant overhead (50% of operating labor)
     General   and administrative overhead (15% of operating labor and maintenance)
Laboratory Charges (5% of operating labor)
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 profit (13.7% of total  depreciable
     investment)

TOTAL ANNUALIZED COSTS (summation of above items)

-------
                                                                 Appendix A
                                                                 Costing
      TABLE A-3.  ASSUMPTIONS USED TO CALCULATE CAPITAL RECOVERY FACTOR
Financing basis:                             100% equity
Desired after tax return on investment:      12% of total depreciable invest-
                                             ment
Income tax rate:                             48% of taxable income
Economic facility life:                      20 years
Facility life for depreciation purposes:     16 years
Depreciation method:                         sum-of-the-years-digit
Investment tax credit:                       20% of total depreciable invest-
                                             ment
A.3  BASE PLANT COSTS
     Capital  and total  annualized cost estimates were developed for base
plants examined.  ("Base plant" in this PCTM refers to a K-T based synfuel
plant with fuel production capabilities but without pollution control  devices.)
The cost estimates were developed from information found in the open literature
and 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) escalated to a 1980 dollar basis.
A.3.1  Base Plant Capital Costs
     The major source of cost data for the methanol synthesis base plant is
an engineering study performed by the Ralph M. Parsons Company (6).  The
plant capacity examined in this manual is approximately 36 percent of the
capacity examined in the Parsons study.  After the identifiable pollution
control costs were subtracted from the installed equipment costs (IEC) report-
ed in Reference 6, the  IEC was adjusted to the PCTM capacity by multiplying
                                     A-5

-------
 Appendix A
 Costing
by 0.437.  This factor equals 0.36 raised to the 0.8 power, which was con-
sidered appropriate because many parts of the plant in the Parsons study
consisted of multiple (4 to 7) trains.  Thus, the majority, but not all  of
the desired capacity reduction (and hence cost reduction) could be accomplish-
ed by eliminating one or more process trains.  In the cases of the Fischer-
Tropsch (F-T) and Mobil  M-gasoline syntheses base plants, the same approach
was used although capital costs associated with methanol  synthesis in the
Parsons study were adjusted to reflect differences in costs among the three
synthesis operations based on other cost data sources (7, 8, 9, 10).
     The resulting adjusted installed equipment costs (IEC) were then escala-
ted to 1980 dollars using the Chemical Engineering (CE)  plant cost annual
index.  Finally, the escalated IEC was used to compute the other elements of
the total capital investment as outlined earlier in Section A.I.  The result-
ing base plant capital  cost estimates are summarized in  Table A-4.
            TABLE A-4.  CAPITAL COSTS FOR UNCONTROLLED K-T  BASED
                        INDIRECT LIQUEFACTION PLANTS

Capital Costs, 106 Dollars (1980 basis)
Item
Installed cost
Contractors Overhead and Fee
Engineering and Construction
Contingency
Subtotal, Facility Cost
Interest During Construction
Working Capital
Total Capital Investment
Methanol
603
18
151
121
893
201
17
1111
Fischer-
Tropsch
714
21
178
143
1056
238
20
1314
Mobi 1
M- Gasoline
657
20
164
131
972
220
17
1209
                                     A-6

-------
                                                                  Appendix A
                                                                  Costing
A.3.2  Base Plant Annualized Costs
     Total annualized costs for the base plants have been estimated as the
sum of the total operating costs and annualized capital  changes.  The total
operating costs are based upon the annual  coal  cost ($35.44/Mg) and cost
estimates for "water, catalyst, and chemicals"  and "other operating costs"
presented for the K-T based methanol production facility examined in the
Parsons study (6).  Published operating cost estimates were scaled directly
on the basis of plant capacity and escalated to 1980 dollars.   Published cost
estimates for "water, catalyst, and chemicals"  and "other operating costs"
relate specifically to a methanol production facility; however, no adjustment
has been made for F-T and Mobil M-gasoline synthesis cases.  Furthermore,
it is not known if any adjustment is required since insufficient details of
these estimates are available.  Similarly, the  annual  operating costs for
pollution control equipment have not been  deducted from cost estimates for
"water, catalyst, and chemicals" and "other operating costs" since insuffi-
cient details of these estimates are available  to do so.  Capital-related
charges have been estimated as outlined earlier in Section A.2.
     The resulting total annualized cost estimates for K-T base plants are
summarized in Table A-5.  It should be noted that annual coal  costs and
capital-related charges comprise about 84% of the total  annualized cost.
Therefore, uncertainties associated with estimated costs for "water, catalyst,
and chemicals" and "other operating costs" are  not expected to have a major
impact on the estimated total annualized cost.
                                    A-7

-------
 Appendix A
 Costing
   TABLE A-5.  ANNUALIZED COSTS FOR K-T BASED INDIRECT LIQUEFACTION PLANTS*
Item
Coal
Water, Catalyst, and Chemicals*
Other Operating Costs*
Total Operating Cost
Capital Charges
Total Annuali zed Cost
Annual
Methanol
98
4
53
155
191
346
ized Cost,
Fischer-
Tropsch
114
4
63
181
226
407
106Dollars
Mobil
M-Gasoline
95
4
51
150
208
358

*Annual operating costs relating to "water, catalyst, and chemicals" and
 "other operating costs" are based upon published cost estimates for a K-T
 based methanol production facility (6).  Insufficient details were available
 to enable adjustment, if any is required, for F-T and Mobil M-gasoline
 synthesis cases or to deduct the annual operating costs for pollution
 controls.
A.4  REFERENCES

1.   Guthrie, K.M.  Process Plant Estimating, Evaluation and Control.  Crafts-
     man Book Company of America, Solana Beach, CA.  1974.

2.   Costs and Analysis Manual  for Utility Boiler Standards Support
     Document, Pedco Environmental,  1979.

3.   Peters, M.S., and K.D. Timmerhaus.  Plant Design and Economics for
     Chemical Engineers.   2e.   McGraw-Hill Book Company, New York, NY.  1968.

4.   Uhl, V.W.  A Standard Procedure of Economic Evaluation for Pollution
     Control Operations.   EPA-600/8-79-018a, June 1979.

5.   Synthetic Gas-Coal Task Force.   The Supply-Technical Advisory Task Force
     Synthetic Coal-Gas.   April  1973.


                                     A-8

-------
                                                                  Appendix A
                                                                  Costing
6.   Ralph M.  Parsons Company.   Screening Evaluation for Synthetic Liquid
     Fuels Manufacture,  EPRI AF-523,  August 1977.

7.   Schreiner, Max.   Research  Guidance Studies to Access Gasoline from Coal
     by Methanol-to-Gasoline and Sasol-Type Fischer-Tropsch Technologies,
     Mobil Research and Development Corporation, FE-2447-13, August 1973.

8.   Badger Plants Incorporated.  Conceptual  Design of a Coal-to-Methanol-to-
     Gasoline Commercial  Plant.  Volume I, FE-2416-43, March 1979.

9.   Fischer-Tropsch  Design Project Capital Cost Validation, U.S.  Army
     Engineer Division,  Huntsville, Alabama.   FE-1759-2, October 1977.

10.   Preliminary Economic Analysis of Lurgi Plant Producing 250 Million SCFD
     Gas from New Mexico  Coal,  U.S. Department of the Interior, Bureau of
     Mines, Morgantown,  West Virginia, ERDA Dcoument No. 76-5,  March 1976.
                                     A-9

-------
                                                                Section B
                                                                Rectisol  AGR
                                 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 cyanide,
ammonia, benzene, and gum-forming hydrocarbons from synthesis gases by means
of physical absorption in an organic solvent (especially cold methanol) at
temperatures below 273K.  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 tempera-
tures of 258K 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 solu-
bilities generally increase with increasing partial pressure but that solu-
bility 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 rela-
tively temperature independent.  For  this reason, Rectisol absorption columns
operate at low temperatures, typically  in the range of 253 to 213K  (1,3,4).
Low temperature operation also reduces  solvent losses by reducing the partial
pressure of methanol in the product streams.
                                     B-l

-------
                             50           100           150
                           SOLUBILITY OF CO2, VOL/VOL
Figure B-l.   Effect of partial pressure on solubility of carbon  dioxide  in
             methanol (1)
                                     B-2

-------
                                 SOLUBILITY COEFFICIENT (X) AT ONE ATMOSPHERE PARTIAL PRESSURE
                              [kmol OF DISSOLVED GAS/(Mg OF SOLVENT x MPa PARTIAL PRESSURE OF GAS)]
      in
      c

      CD

      CD
      I
      ro
      co
      o
GO
I
CO
o
-h
      &>
      CO
      (15
      CU
      3
      O
      ro

-------
Appendix B
Rectisol AGR
     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 almost independently.
     The Rectisol  process was jointly developed by Linde Aktiengesellschaft
(Munich, Germany)  and Lurgi Mineral61technik (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 Technologie (GKT, E'.ssen, Germany)
also has a limited Rectisol license applying to Koppers-Totzek (K-T) gasifica-
tion facilities.
Selective Rectisol Process Configurations
     A variety of selective Rectisol units are currently being used in appli-
cations 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  in-
clude 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 in Modderforitein, Republic of
South Africa, and desulfurizes an  essentially  hydrocarbon-free quenched  K-T
gas prior to carbon monoxide shift conversion  and  subsequent  carbon dioxide
removal  (5,6).  Methanol  is added  to the  feed  gas  prior to cooling  and  hydrogen

                                     B-4

-------
GO
I
C.1
                                                                                                                HjS-RCCH GAS
                                                                                                                REGENERATION
                                                                                                                COLUMN
                                                                                                                (C02I
                                                                                                              CO2 RICH GAS
              Figure  B-3.   Process flow diagram  of the  Modderfontein selective  Rectisol  system  (5,6)

-------
       CRUDE
      PRODUCT
      GAS FROM
        GAS
     PRODUCTION
      SECTION
                                    PRODUCT GAS
                                                                                                                                CLEAN PRODUCT
                                                                                                                              * GAS TO GAS
                                                                                                                                DISTRIBUTION
                                                              PRODUCT GAS
       GAS
  CONDENSATE
  TO MEDIUM
OIL SEPARATOR
   IN TAR OIL
  SEPARATION
    SECTION
«Q
)LER
I

METHANOL

LIQUOR
«-|HO



                                                                                                             PURE PRODUCT
                                                                                                             GAS TO AMMONIA
                                                                                                             PLANT
WASTE '
  GAS
               HjS RICH WASTE
               GAS TO BUHNER
CO, RICH WASTE GAS
.  <       A  I  * CO2RICH WASTE
               GAS VENT
 CYANIC WATER
   TO TAR Oil
  SEPARATION
     SECTION V-5J
               Figure B-4.    Process  flow  diagram  of  the  Kosovo  selective  Rectisol  section  (7,8)

-------
                                                                 Appendix B
                                                                 Rectisol AGR
sulfide absorption to prevent icing.   Moisture in the feed gas is removed
from the hydrogen sulfide absorber in solution with methanol,  which is re-
covered 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 re-absorption  of reduced  sulfur species in
sulfur-free methanol, produces a sulfur-rich  methanol stream  for hot regen-
eration and a carbon dioxide off-gas.  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 absoprtion 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 facilitates process selectivity by absorbing hydrogen sulfide in the or?-,
ence of a minimum of carbon  dioxide (approximately 10 to  12% by volume  for
K-T coal gasification, 18 to 20% for Texaco coal gasification, and 5 to 6%
for gas produced by partial oxidation of oil).  However, in conjunction with
partial oxidation of liquid hydrocarbons for hydrogen or ammonia production,
shift conversion employing sulfur tolerant cobalt-molybdate shift catalysts
often precedes acid gas removal.  Selective Rectisol configurations for such
systems are similar to that presented in Figure B-3 except that no gas pro-
cessing occurs between hydrogen sulfide absorption and carbon  dioxide

                                     B-7

-------
Appendix B
Rectisol AGR
 absorption.   Shift  conversion  prior  to acid  gas  removal  results  in  an  in-
 creased  concentration  of  carbon  dioxide  in the hydrogen  sulfide  absorber feed
 gas  (up  to  about  42 percent  by volume).   Owing to  the  less  favorable 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 Btu 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 gasifiers.  Cooled crude
 product  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 by-product storage via  the  naphtha surge tank.
 Cyanic water from naphtha separation and methanol/water distillation  is sent
 to tar/oil  separation.
      Product 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
 for feed to the cryogenic hydrogen separation  unit,  additional  carbon dioxide
 removal  is achieved in the second carbon dioxide absorber  using  regenerated
 methanol.
                                      B-8

-------
                                                                 Appendix B
                                                                 Rectisol AGR
     Hydrogen sulfide-rich methanol is regenerated by multi-stage flashing
in the hydrogen sulfide flash tower, and steam stripping in the methanol
regeneration column.   Hydrogen sulfide-rich waste gas from methanol  regenera-
tion is combined with flash gas from the naphtha separator and the methanol
pre-wash flash tank prior to disposal.  Carbon dioxide-rich methanol is regen-
erated by multi-stage 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 pro-
cessing Lurgi crude gas.  Several  selective Rectisol  designs have been pre-
pared 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
(approximately 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
containing offgases are simply burned so that high sulfide concentrations are
not necessary as would be the case for Claus processing.  Differences in the
performance of these two units are detailed in Section  B.3.
Non-Selective Rectisol  Process Configurations
     Non-selective 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  high pruity carbon  dioxide vent
gas.  An example of a commercial non-selective Rectisol  unit  is  presented  in

                                     B-9

-------
Appendix B
Rectisol AGR
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 synthe-
sis.  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 by-product 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 com-
bined with gas liquor from the second gas cooling stage and sent to the  naphtha
separator.  Separator feed is flashed and extracted with water to yield  an
aqueous methanol phase and a by-product naphtha phase containing organic sul-
ful compounds.  Methanol is recovered from the aqueous phase by distillation.
     Bulk acid gas removal is achieved  in  the second or main  wash  stage  or
absorption by washing with flashed methanol from the expansion tower.  Rich
methanol  from the  second stage absorber is regenerated along with the 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  hydro-
gen is used to cool the  Rectisol feed gas and then used as on-site  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
                                     B-10

-------
                               METHANOL
                      NH
        FEED GAS
     HIGH PRESSURE
     FLASH GAS
       PRODUCT GAS
CD
I

ONO
GE
1ST
AGE





r^





THIRD
ABSORBER

                                                                                                    HOT
                                                                                                    REGENER-
                                                                                                    ATION
                                                                                                                      ATMOSPHERIC
                                                                                                                     ' FLASH GAS
                                                                                                            HOT
                                                                                                            REGENERATOR
                                           CYANIC WATER
                                                                                   LOW PRESSURE
                                                                                   FLASH GAS
                 Figure B-5.   Process  flow  diagram of  the  Sasol  I non-selective  Rectisol  section (1)

-------
Appendix B
Rectisol AGR
methanol from the hot regenerator.   Rich methanol  from the third stage
absorber is partly regenerated by flashing to atmospheric pressure and then
completely 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 non-selective Rectisol processes,
although a similar design has been used in the Sasol  II facility which was
commissioned in 1980 (11).  Non-selective Rectisol designs have been prepared
for several proposed Lurgi gasification facilities in the United States in-
cluding 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 non-selective Rectisol section
is presented in Figure B-6 (13).  This schematic indicates a similar config-
uration to that of the Sasol I facility but includes details such as the pre-
wash 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,
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; 3)  used  in conjunction
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.

                                    B-12

-------
DO
I
CO
            Figure B-6.  Process flow diagram of  the  Great Plains  non-selective Rectisol section (13)

-------
 Appendix B
 Rectisol AGR
     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 213K (1,3,4 ).  An additional  benefit of low temperature operation
is the attendant reduction of methanol  losses.  Vapor pressure data for
methanol are presented in Figure B-7 (1).  These data indicate that methanol
losses can be decreased by a factor of about three to four for each 20K
temperature reduction down to 253K and by about one order of magnitude for
each 20K temperature reduction below 253K.
     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

                                     B-14

-------
 1000
  100
oc

o
flc
ui
2
a.  10
O

E


LU
QC


I
LU
IT
Q.

QC
O
_1
o

<
I
   1.0
 0.10
  0.01
     193      213       233        253        273

                                 TEMPERATURE(K)
293
313
333
                Figure B-7.  Vapor pressure  of methanol  (1)
                                      B-15

-------
Appendix B
Rectisol AGR
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 (partic-
ularly the methanol  prewash)  and, in low temperature gasification applica-
tions, 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 in addition to 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 solubi-
lize sulfur by formation of ammonium thiocyanate which is ultimately removed
with the methanol/water distillation bottoms.  When insufficient hydrogen
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 oxygen and nitrogen oxides 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

                                    B-16

-------
                                                                 Appendix B
                                                                 Rectisol AGR
type of Rectisol process employed (e.g., selective or non-selective Rectisol).
However, in the case of a non-selective  Rectisol process, the utilities  (steam,
cooling water, and refrigerant) would  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 per-
cent 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 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, 62-64% 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 in Plant 3, which is
not included in Table  B-l, contains 42-43% carbon dioxide, 53-54% hydrogen,
and about 3% carbon monoxide.
                                    B-17

-------
TABLE  B-l.   SELECTIVE RECTISOL  PERFORMANCE  DATA  FOR  HIGH  TEMPERATURE  GASIFICATION  APPLICATIONS*















CD
1
00


Gas Feed
jComponent Plant 1
H? 62.35-
63.74
N,+Ar 0.12 -
0.52
CO 3.24-
4.13
CH. 0.13-
0.17
CO,, 31.62-
33.23
H?S 0.26-
0.49
COS 10-63ppm


Flow Rate, 3562-
kmol/hr 3992
Temperature, K 303-313
Pressure, HPa 3.2-3.3
Gas, Mole I
Plant 2 Plant 3
61.59 27.5-
29.3
0.41 1.52

2.60 56.62

0.33 0.10

34.55 11.8-
13.3
0.52 0.59-
0.75
0.10


6112 4691-
4801
311
7.3 3.0-3.1
Puri
Plant 1
93.58-
94.08
0.17 -
0.82
4.86

0.19
0.24
slOppm


-------
                                                               Appendix B
                                                               Rectisol AGR
      These selective Rectisol  units are seen to perform similarly in most
respects over a wide range of operating pressures although there is a sub-
stantial 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 strip-
ping gas is a function of the hydrogen sulfide concentration desired in the
hydrogen sulfide-rich offgas, the type of Rectisol process, the feed gas
pressure, and the carbon dioxide, hydrogen sulfide, and carbonyl sulfide con-
centrations in the feed gas.  Under given conditions an increase in stripping
gas of about 60% is necessary to increase the hydrogen sulfide concentration
from 25-70%.
     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 gasification, are summarized in Table B-2  (refer to  Figure B-4
for the process flow diagram).  Data were obtained during three sampling
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 non-selective Rectisol unit,
which also treats crude gas from Lurgi  gasification, are presented in Table
                                     B-19

-------
        TABLE  B-2.   SELECTIVE  RECTISOL  PERFORMANCE  DATA  FOR  LURGI  (KOSOVO)  MEDIUM-BTU GASIFICATION  (7,18)*
TO
I
ro
o
Gas Component
H2
°2
N2
CO
co2
CH4
C2H6
C2H4
C3
C4
C5
C6
Benzene
Tol uene
Xylene and
Ethylbenzene
Phenols
H2S
COS
CH3SH
C2H5SH
NH,
HCN
pH
Total Solids, mg/L
Total Nonvolatile
Solids, mg/L
Total Suspended
Solids, mg/L
Total Dissolved
Solids, mg/L
COD (as mg02/L)
Permanganate
(as mg02/L)
Total Sulfur, mg/L
Flow Rate,
kmol/hr
Flow Rate, m/hr
Temperature, K
Crude Product Gas
(Stream 73), mole
yalue+ Range
38 1
0.36
0 64
15
32
11.5
0 47
0.04
0 19
0.074
0.044
0.064
750ppmv
230ppmv
lOOppmv

-Ippmv
0.60
97ppmv
590ppmv
200ppmv
3.3ppnv
320ppmv











703


295
36-46
0.09-2.6
0.04-1.6
9 6-17
21-40
8 9-14.5
-1 ppmv-0. 76
-lppmv-0 11
0.07-0 40
0.02-0.24
0.01-0 06
0.02-0.20
660-840ppmv
200-260ppmv
16-1 TOppmv

--
0.44-0.78
63-1 20ppmv
460-700ppmv
98-270ppmv
• l-3.3ppmv
60-320ppmv














293-295
Clean Product Gas
(Stream 7 4) , mole
Value+ Ranqe
60 59-67
0.44 0 1-1.7
0.38 0.32-6 8
22 13-23
0.02 ..0.01-2 4
16 12-18
0 15 ~lppmv-0.18
—Ippmv
-Ippmv -lppmv-0. 09
—Ippmv
— Ippinv
0.03 • lppmv-0. 03
--

..

-Ippmv
•-Ippmv
0 1 7ppmv • 1 -0 2ppmv
1 1 ppmv -1- 1 . 9ppmv
l.Oppmv — l-1.7ppmv
-Ippmv < 1 - 30ppmv
--











491


._
C02-Rich Waste Gas
(Stream 7.2), mole
Value^ Ranqe
-0 01
-0 01
-0.01
-0.01
94
1.2
1 6
—1 ppmv
0 28
—1 ppmv
—1 ppmv
Ippmv
1 ppmv
-Ippmv
-Ippmv

1 ppmv
39ppmv
62ppnv
8. 5ppmv
4 4ppmv
4 6ppmv
1 3ppmv











90


292
••0 01-0.8
-0 01-1.8
-0.01-48
•0.01- 0.01
91-95
0.6-1 8
0 29-1 6
--
0 17-0 55
•lppmv-0 23
lppn,v-0 17
--
--
--
_.

--
20-90ppmv
-1 -62ppmv
8.2-9.7ppmv
3 4-6. Ippmv
1 -4.6ppmv
















H^S-Rich Waste Gas Cyanic Water
(Stream 7.1), mole (Stream 7.5)
Value+ Ranqe ValueJ Ranqe
0.11
-0 01
-0.01
1 1
88
4 3
0.82
—1 ppmv
0.63
0 32
0.04
0.21
1 lOppmv
8ppmv
< Ippmv

-1 pnmv
4.54
420ppmv
0.21
780ppmv
0.22
200ppmv











102


285
0.02-0.11
-0.01-0 51
-0.01-3.2
1 1-3 5
85-92
4.1-4.7
0 34-0.97
--
0.22-1.1
0.14-0.58
0.03-0.21
0.01-0.22
40-110ppmv
4-8ppmv
__

--
1.6-5.0
360-540ppmv
0.19-0.48
670-850ppmv
• lppmv-0 22
83-200ppmv
11.9 11 4-12 1
7.30
450

140
590

205
570

60 52-68


0.8
353
                   Refer to Figure 8-4 for process flow diagram.

                   Values are  best overall values from available data .

-------
                                                                 Appendix B
                                                                 Rectisol AGR
B-3 (refer to Figure B-5 for the process flow diagram).  As initially designed,
the high pressure flash gas is used as an on-site 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 stream 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.4  RECTISOL WASTE STREAMS
     Secondary waste streams produced by the Rectisol acid gas removal pro-
cess are:  (1) hydrogen sulfide-rich offgases, (2) carbon dioxide-rich off-
gases (selective Rectisol processes only), and (3) methanol/water distilla-
tion bottoms.  Available characterization data for the offgas streams have
been summarized in Section B.3 for each of the three basic Rectisol process
configurations.  The sulfur-rich offgas is typically sent to the sulfur re-
covery 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 C~ 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, partic-
ularly the 035 and  045, 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 C, and C, hydro-
carbons in the Rectisol feed gas may result in off-color sulfur if Claus
sulfur recovery is employed or excessive tail gas hydrocarbon emissions if

                                   B-21

-------
          TABLE B-3.   PERFORMANCE DATA FOR THE NON-SELECTIVE RECTISOL AT SASOL I  (LURGI GASIFICATION)(17)*
CO
ro
ro
Gas Rectisol Feed
Component Gas, Mole %
H
CO
CH4
co2
N2+Ar
COS
cs2
RSH
Thiophene
Total sulfur
c+
L2
Flow Rate, NM3/hr
Temperature, K
Pressure, MPa
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
~F*> 	 r> 	 : — — 	

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
Off -Gases, Mole
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
Of
h
Atmospheric
Flash Gas
0.14
0.0
0.9
97.2
0.03
0.88
30ppmv
2ppmv
280ppmv
2ppmv
NA
0.7
98,000
268
0.11

-------
                                                                 Appendix B
                                                                 Rectisol AGR
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)
     Carbon dioxide-rich offgas from selective Rectisol units is either sold
as by-product or vented to the atmosphere at existing facilities.  As dis-
cussed above, light hydrocarbons present in the Rectisol feed gas are co-
absorbed 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 hydrocarbon levels in the carbon dioxide offgases.
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 concen-
tration in the carbon dioxide-rich offgas, depends upon its partial pressure.
Thus, for similar acid gas removal systems, processes requiring only 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 appli-
cations indicate either incineration of the carbon dioxide-rich offgas for
control of hydrocarbon and carbon monoxide emissions, or sale of the offgas
as by-product; direct discharge to the atmosphere is not proposed.   Also, at
least one non-Lurgi coal gasification plant currently under construction,
the Tennessee Eastman Kingport, Tennessee Texaco gasification project, pro-
poses catalytic incineration of a 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,
                                    B-23

-------
Appendix B
Rectlsol AGR
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 personnel  (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.
TABLE B-4.  CHARACTERIZATION  DATA FOR  METHANOL/WATER DISTILLATION BOTTOMS AT
            SASOL (19)

                 Parameter/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  non-selective  Rectisol  unit built at Sasol in 1955 has
operated with an on-stream factor of about  97%  (17).  Normal maintenance in-
cludes partial  shutdown  about once per year for cleaning of critical equipment
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 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
                                     B-24

-------
                                                                 Appendix B
                                                                 Rectisol AGR
ammonium thiocyanate.  A more fundamental solution  is  the  hydrolysis  of
nitrogen oxides and oxygen over a cobalt molybdate  catalyst ahead  of  the

Rectisol unit.  Detailed operating data from this facility are  not available.

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 require-

ments 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 and 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 interdependences 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


Non-Selective


Dry
Feed Gas,
kmol/hr
6,100

96,384
52,786
57,574

Total
Pressure,
MPa
7.8

2.9
2.8
2.8

co2,
vol %
35

28.9
31.4
34.2

H2S,
vol %
0.25

0.250
0.135
0.130
Capital
Cost, $106
(adj. to
1980 basis)
13.5*

150. 6T
91.8*
81.9*


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 refrig-
 eration unit and unit startup are included.

                                    B-25

-------
                         TABLE B-6.   UTILITY REQUIREMENTS  FOR RECTISOL ACID  GAS REMOVAL UNITS
CD
I
no
CTl

Flow Rate, kmol/hr
Pressure, MPa
Electric Power, kW hr/kmol
Low Pressure Steam, MJ/kmol
Cooling Water, MJ/kmol
Stripping Nitrogen, kmol/kmol
Makeup Methanol , kg/kmol
Refrigeration, MJ/kmol
(at 227 to 235K)
	 	 • -- -
Plant 1
3692-3992
3.2-3.3
0.14-0.15
5.14-5.54
1.20-1.42
0.067-0.072
Selective Rectisol*
Plant 2
6112
7.3
0.31
3.44
6.43
0.031
0.0085-0.0092 0.0057
2.09-2.29
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 cool ing
water
Plant 5
eioo
7.8
0.168
2.77
1.91
0.043
0.007
1.24
Non-Selective
Rectisolt
Plant 6
16993
2.6
No data
3.27
0.682
No data
0.013
No data
           *Plant 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).   Operating costs  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 crude 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 con-
            taining less than 1.5 ppmv sulfur for urea production (24).
           tPlant 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 AGR
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 Lotepro Corpora-
     tion, New York, N.Y.

3.   Scholz, W.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, and G.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 on Environmental Aspects
     of Fuel Conversion Technology, Denver, Colorado, October 26-30, 1981.
     EPA 600/9-82-017, August 1982.

10.   Trials of American Coals in  a Lurgi  Gasifier at Westfield, Scotland.
     Woodall-Duckham, Ltd., Sussex, England.  ERDA R&D Report No.  105,  1974.

11.   Cameron Synthetic Fuels Report.  Rocky Mountain Division, The Pace
     Company Consultants & Engineers, Inc.  Volume 18-Number 4, December 1981.

12.   Sinor, J.E.   Evaluation of Background  Data  Relative to New Source  Per-
     formance Standards for Lurgi Gasification.   Cameron Engineers, Inc.
     EPA-600/7-77-057, June 1977.
                                     1-27

-------
Appendix B
Rectisol AGR
13.   Final  Environmental  Impact Statement:   Great Plains Gasification Project,
     Mercer County,  North Dakota.   Vol  I.   U.S.  Department of Energy, Washing-
     ton,  D.C.   August 1980.

14.   Hochgesand, G.   Rectisol  and  Purisol.   Industrial  and Engineering Chem-
     istry, 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. Environ-
     mental Protection Agency, Emission Standards and Engineering Division.
     EPA-450/2-78-012 (OAQPS No. 1.2-093).   March 1978.

18.   Bombaugh,  K.J.  and W.  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 1976.

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.
                                     B-28

-------
                                                                 Appendix B
                                                                 Rectisol AGR
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-29

-------