EPA-600/8-83-007
April 1983
POLLUTION CONTROL TECHNICAL MANUAL
FOR
EXXON DONOR SOLVENT DIRECT COAL LIQUEFACTION
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
(202) 382-2627
Project Officer: D. Bruce Henschel
Industrial Environmental Research Laboratory-RTP
Research Triangle Park, NC 27711
(919) 541-4112
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 report has been reviewed and approved for publication by the U.S.
Environmental Protection Agency. Approval does not signify that the con-
tents necessarily reflect the views and policy of the U.S. Environmental
Protection Agency nor does mention of trade names or commercial products
constitute endorsement or recommendation for use. No proprietary or confi-
dential data appear in or have been used in the preparation of this manual.
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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
iii
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ABSTRACT
The Environmental Protection Agency (EPA), Office of Research and
Development, has undertaken an extensive study to determine synthetic fuel
plant waste stream characteristics and pollution control systems. The purpose
of this and all other Pollution Control Technical Manuals (PCTMs) is to convey
this information in a manner that is readily useful to designers, permit writ-
ers, and the public.
The Exxon Donor Solvent (EDS) direct coal liquefaction PCTM addresses the
coal liquefaction technology being developed by Exxon Research and Engineering
Company. Two configurations of the EDS process are considered in detail in
this manual. These are the base case configuration and the Market Flexibility
Sensitivity (MFS) configuration. The PCTM also considers a single feed coal
(Illinois No. 6 bituminous), although the effects of other coal types on emis-
sions and controls are described. Throughout the PCTM, the flow rates of waste
streams and process streams presented correspond to an EDS commercial plant
processing 1,134 Mg/hr (30,000 tons per stream day) of "as received" Illinois
No. 6 coal in the liquefaction area. This EDS plant would produce about 9,580
o
m (60,240 barrels) fuel oil equivalent per stream day of liquid products for
the base case design, or 11,300 m (71,080 barrels) fuel oil equivalent per
stream day of liquid and gas products for the MFS case design.
This manual describes the two configurations of the EDS process, charac-
terizes 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, example control trains
are constructed for each medium, illustrating the function of some typical
integrated control systems. Control and control system cost and performance
estimates are presented, together with descriptions of the discharge streams
and secondary waste streams.
A summary of environmental and control technology considerations is pre-
sented. This summary includes a listing of data limitations and needs.
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TABLE OF CONTENTS
FOREWORD
ABSTRACT
FIGURES
TABLES
GLOSSARY OF ACRONYMS
CONVERSION FACTORS
ACKNOWLEDGMENT
SECTION 1 INTRODUCTION
1.1 Purpose and Use of PCTM's
1 .2 Content of This PCTM
1.2.1 Synfuels Process Addressed
1.2.2 Information Presented in PCTM
1.3 Approach for Developing PCTM
1.3.1 Plant Design and Uncontrolled Discharge Estimates
1.3.2 Control Technology Evaluation
1.4 Data Base for PCTM
1.4.1 Data Base for Uncontrolled Discharge Estimates
1.4.2 Data Base for Control Performance/Costs
1.5 How to Use the PCTM
SECTION 2 PROCESS DESCRIPTION OVERVIEW
2.1 Overall Process Description
. 2.1.1 Base Case
2.1.2 Market Flexibility Sensitivity (MFS) Case
2.1.3 Bottoms Recycle Case
2.2 Effects of Major Variables on Discharges/Controls
2.2.1 Effect of Coal Type
2.2.2 Effects of EDS Plant Design
2.2.3 Effects of Product Slate
2.3 Capital and Operating Costs for Uncontrolled EDS Plants
2.3.1 Base Case
2.3.2 MFS Case
SECTION 3 DETAILED PROCESS DESCRIPTION AND WASTE STREAM
CHARACTERIZATION
3.1 Detailed Description of Overall EDS Process
3.1.1 Base Case
3.1.2 Market Flexibility Sensitivity Case
3.1.3 Bottoms Recycle Case
3.2 List of Uncontrolled and Secondary Discharge Streams
3.2.1 Base Case
3.2.2 MFS Case
3.3 Detailed Description of Discharge Sources by Process
Area
Coal Preparation Area (Area 1)
Coal Liquefaction Area (Area 2)
Product Separation and Purification Area
(Area 3)
v
1
2
3.3.3
3.3
3.3
1
1
2
2
4
5
5
8
10
10
12
13
16
16
17
19
21
22
22
26
28
28
30
36
37
38
39
42
44
45
45
51
56
57
68
83
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CONTENTS (Continued)
SECTION
3.3.4 Liquefaction Residue Processing/Hydrogen
Production Area (Area 4)
3.3.5 Auxiliary Operations (Area 5)
3.3.6 Products
3.3.7 Fugitive Organic Emissions
3.3.8 Other Areas
3.4 Summary of Uncontrolled Discharges by Medium
3.4.1 Gaseous Waste Streams
3.4.2 Liquid Waste Streams
3.4.3 Solid Waste Streams
3.4.4 Product Streams
3.5 Waste/Control Technology Index
4 EVALUATION OF POLLUTION CONTROL TECHNOLOGIES
4.1 Introduction
4.1.1 Organization of Section
4.1.2 Approach
4.1.3 Costing Methodology
4.2 Air Pollution Control Technologies
4.2.1 Source Tvoe 1 - Acid Gases ;
4.3
Source Type 1 - Acid Gases and Other Reduced
Sulfur/Nitrogen, Organic-Laden Gases
Combustion Gases
Organic and CO Containing Waste
4.2.1
4.2.2 Source Type 2
4.2.3 Source Type 3
Gases
4.2.4 Source Type 4 - Fugitive Dust from Material
Storage
4.2.5 Source Type 5 - Fugitive Organic Emissions
4.2.6 Source Type 6 - Fugitive Particulates from
Material Conveying and Processing
Water Pollution Control Technologies
4.3.1 Source Type 1: Organic- and Dissolved
Gas-Containing Wastewaters
4.3.2 Source Type 2 - Inorganic Containing Wastewaters
4.4 Solid Waste Management
.1
.2
.3
4.4.
4.4,
4.4.
4.4.4
4.4.5
4.4.6
Solid Waste Control Functions
Source Type 1 - Inorganic Ashes and Sludges
Source Type 2 - Recovered By-Products
Source Type 3 - Organic Sludges
Source Type 4 - Spent Catalysts
Integrated Control Examples
SECTION 5 DATA LIMITATIONS, GAPS AND RESEARCH NEEDS
SECTION 6 REFERENCES
117
177
195
204
208
209
209
213
218
221
227
235
235
235
237
238
246
250
320
356
366
372
389
391
392
472
481
484
497
517
518
523
527
533
555
vi
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FIGURES
Number Title Page
2-1 Simplified Block Flow Diagram for Exxon Donor Solvent
Process - Base Case 18
2-2 Simplified Block Flow Diagram for Exxon Donor Solvent
Process - MFS Case 20
3-1 Block Flow Diagram for EDS Commercial Plant - Base Case 40
3-2 Block Flow Diagram for EDS Commercial Plant - MFS Case 43
3-3 Block Flow Diagram for EDS Commercial Plant Coal Preparation
Area (Area 1) 58
3-4 Block Flow Diagram for EDS Commercial Plant Coal Liquefaction fiq
Area (Area 2)
3-5 Block Flow Diagram for EDS Commercial Plant Product Separa- g.
tion and Purification Area (Area 3)
3-6 Block Flow Diagram for EDS Liquefaction Residue Processing ,,R
and Hydrogen Production (Area 4) - Base Case
3-7 Block Flow Diagram for EDS Liquefaction Residue Processing liq
and Hydrogen Production (Area 4) - MFS Case ' '
3-8 Raw Water Treatment Block Flow Diagram 178
4-1 Example 1 - Claus Bulk Sulfur Removal with Tail Gas Treatment
by Beavon Sulfur Removal Process 303
4-2 Example 2 - Claus Bulk Sulfur Removal with SCOT Tail Gas
Treatment and Incineration 308
4-3 Example 3 - Claus Bulk Sulfur Removal with Wellman-Lord Tail
Gas Treatment 314
4-4 Block Flow Diagrams for Integrated Control Examples 1 and 2
for Treating Type 1 Wastewater 451
4-5 Block Flow Diagram for Integrated Control Example 2 for
Treating Type 1 Wastewater 459
4-6 Block Flow Diagram for Integrated Control Examples 3 and 4 for
Treating Type 1 Wastewater 464
4-7 Landfill design 491
4-8 Estimated Landfill Costs as a Function of Landfill Capacity 492
4-9 Solid Waste Control Example 2: FBC Boiler and Landfill for
Flexicoking Wastes 531
vii
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TABLES
Number Title Page
2-1 Characteristics of EDS Coal Feedstock: Representative
Illinois No. 6 Coal Considered in PCTM 23
2-2 Trace Element Concentrations of Representative Illinois No. 6
Coal Considered in PCTM 24
2-3 Net Product Slates for EDS Commercial Plant (Stream Day Basis) 29
2-4 Capital Costs for Uncontrolled EDS Base Case Design Commercial
Plant 32
2-5 Annualized Costs for Uncontrolled EDS Base Case Design Com-
mercial Plant 33
2-6 Capital Costs for Uncontrolled EDS MFS Case Design Commercial
Plant 34
2-7 Annualized Costs for Uncontrolled EDS Commercial Plant 35
3-1 Listing of Waste Streams and Selected Process Streams for the
EDS Illinois Coal Base Case Design 45
3-2 Listing of Waste Streams and Selected Process Streams for the
EDS Illinois Coal MFS Case Design 52
3-3 Coal Feed Requirements - EDS Plant 57
3-4 Uncontrolled Fugitive Dust Generation 5-Day Coal Storage
Piles (Stream 011-1) 60
3-5 Uncontrolled Fugitive Dust Generation 30-Day Coal Storage
Piles (Stream 011-2) 61
3-6 Average and 10-Year, 24-Hour Storm Runoff From 5-Day Wet
Storage Piles at the EDS Plant (Stream 012-1) 64
3-7 Fugitive Particulate Emissions from Coal Handling and
Crushing (Stream 013) 66
3-8 Estimated Uncontrolled Emissions for Flue Gas from Slurry
Preheat Furnace (Stream 107) 71
3-9 Estimated Characteristics of Transient Waste Gas from
Liquefaction Reactors (Stream 803) 73
3-10 Estimated Quality of Slurry Drier Cold Separator Wastewater
(Stream 103) 74
3-11 Characteristics of Liquefaction Cold Separator Wastewater
(Stream 106) - Three Data Sources 77
3-12 Characteristics of Liquefaction Cold Separator Wastewater
Used for PCTM in Wastewater Treatment Technology Evaluation
(Stream 106) 79
viii
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TABLES (Continued)
Number Title
3-13 Concentrations of Trace Metals in Liquefaction Cold
Separator Wastewater (Stream 106) 80
3-14 Concentrations of Organic Compounds in Liquefaction Cold
Separator Wastewater (Stream 106) 82
3-15 Estimated Uncontrolled Emissions for Flue Gas from Partial
Oxidation Feed Vacuum Fractionator Preheat Furnace (Stream
161) 87
3-16 Characteristics of Atmospheric Fractionator Overhead Drum
Wastewater (Stream 152) - Three Data Sources 89
3-17 Characteristics of Atmospheric Fractionator Overhead Drum
Wastewater Used for PCTM Wastewater Treatment Technology
Evaluation (Stream 152) 90
3-18 Concentrations of Trace Metals in Atmospheric Fractionator
Overhead Drum Wastewater (Stream 152) 92
3-19 Concentrations of Organic Compounds in Atmospheric Frac-
tionator Overhead Drum Wastewater (Stream 152) 93
3-20 Characteristics of Vacuum Fractionator Wastewater (Streams
155/157) - Three Data Sources 94
3-21 Characteristics of Vacuum Fractionator Wastewater Used for
PCTM Wastewater Treatment Technology Evaluation (Streams
155/157) 96
3-22 Concentrations of Trace Metals in Vacuum Fractionator
Wastewater (Streams 155/157) 97
3-23 Concentrations of Organic Compounds in Vacuum Fractionator
Wastewater (Streams 155/157) 98
3-24 Estimated Uncontrolled Emissions for Flue Gas from Solvent
Hydrogenation Feed Preheat Furnace (Stream 203) 101
3-25 Estimated Quality of Solvent Hydrogenation Cold Separator
Wastewater (Stream 202) 103
3-26 Concentrations of Trace Metals in Solvent Hydrogenation
Cold Separator Wastewater (Stream 202) 104
3-27 Characteristics of Solvent Hydrogenation Fractionator
Overhead Drum Wastewater (Stream 252) - Three Data Sources 105
3-28 Characteristics of Solvent Hydrogenation Fractionator
Overhead Drum Wastewater Used for PCTM Wastewater Treatment
Technology Evaluation (Stream 252) 107
3-29 Concentrations of Trace Metals in Solvent Hydrogenation
Fractionator Overhead Drum Wastewater (Stream 252) 108
1x
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TABLES (Continued)
Number Title Page
3-30 Concentrations of Organic Compounds in Solvent Hydrogenation
Fractionator Overhead Drum Wastewater (Stream 252) 109
3-31 Composition and Flow Rates of Acid Gas Stream from EDS
Commercial Plant Product Separation and Purification Opera- -,-,?
tions (Stream 508) "
3-32 Composition and Flow Rates of Sour Gas Streams Treated in
EDS Commercial Plant DEA Unit (Illinois Coal Base Case) 113
3-33 Composition and Flow Rates of Sour Gas Streams Treated in
EDS Commercial Plant DEA Unit (Illinois Coal MFS Case) 114
3-34 Estimated Composition and Flow Rates of Sour Fuel Gas from
the Flexicoker Heater/Gasifier Unit (Stream 304) 122
3-35 Estimated Characteristics of Transient Waste Gas from
Flexicoking Units (Stream 801) 123
3-36 Estimated Quality of Flexicoking Recontacting Drum Waste-
water (Stream 307) 125
3-37 Estimated Quality of Flexicoking Fractionator Overhead Drum
Wastewater (Stream 308) 127
3-38 Estimated Quality of Flexicoking Heater Overhead Drum
Wastewater (Stream 312) T28
3-39 Elemental Analyses of Leachates Derived from EPA Draft
Extraction Procedure Applied to EDS Flexicoking Gasifier/
Heater Dry Fines (Stream 302) 130
3-40 Elemental Analyses of Leachates Derived from EPA Draft
Extraction Procedure Applied to EDS Flexicoking Gasifier/
Heater Bed Coke (Stream 306) 133
3-41 Elemental Analyses of Leachates Derived from EPA Draft
Extraction Procedure Applied to EDS Flexicoking Heater/
Reactor Chunks/Agglomerates (Stream 313) 134
3-42 Estimated Composition and Flow Rates of Vent Gas from C0?
Removal (Stream 426) 143
3-43 Estimated Uncontrolled Emissions for Flue Gas from Reformer
Furnaces (Stream 434) 145
3-44 Estimated Composition and Flow Rates of Shift Gas to the
Acid Gas Removal Unit in MFS Case Design 147
3-45 Estimated Composition and Flow Rates of Acid Gas from Acid
Gas Removal Unit (Stream 428) 149
3-46 Estimated Composition and Flow Rates of Flash Gas from
Partial Oxidation Unit (Stream 440) 150
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TABLES (Continued)
Number Title Page
3-47 Estimated Composition and Flow Rates of Regeneration/
Decommissioning Off-Gas from Shift Catalyst (Streams 449/450) 152
3-48 Estimated Characteristics of Transient Waste Gas from Partial
Oxidation Units (Stream 802) 153
3-49 Estimated Quality of Knockout Drum Wastewater from Cryogenic
Hydrogen Recovery (Stream 403) 156
3-50 Estimated Quality of Slowdown and Knockout Drum Wastewater
from Hydrogen Generation (Stream 430) 157
3-51 Estimated Quality of Catacarb Overhead Receiver Wastewater
(Stream 431) 158
3-52 Estimated Quality of Aqueous Ammonia from Ammonia Synthesis
(Stream 451) 160
3-53 Estimated Quality of Knockout Drum Wastewater in Ammonia
Synthesis (Stream 452) 162
3-54 Estimated Quality of Sour Water from the Partial Oxidation
Unit (Stream 441) 163
3-55 Concentrations of Trace Elements in Sour Water from the
Partial Oxidation Unit (Stream 441) 164
3-56 Estimated Quality of Slag Filtrate from the Partial
Oxidation Unit (Stream 443) 166
3-57 Concentrations of Trace Elements in Slag Filtrate from the
Partial Oxidation Unit (Stream 443) 167
3-58 Elemental Analysis of Leachates Derived from Various Batch
Leaching Protocols Applied to Texaco Slag from Gasification
of SRC-II Residue (Ky 9/14 Coal) 173
3-59 Elemental Analysis of Slag Leachates Derived from Laboratory
Columns 174
3-60 Concentrations of Benzene Solubles and Selected Polynuclear
Aromatics in Texaco Slag from Gasification of SRC-II Residue 175
3-61 Assumed Characteristics of Raw Water for EDS 179
3-62 Estimated Characteristics of Regeneration Waste from Water
Demineralization (Stream 723) 181
3-63 Estimated Characteristics of Raw Water Treatment Sludge
(Stream 722) 183
3-64 Uncontrolled Flue Gas Emissions from Steam Generation System
(Stream 701 a) 185
3-65 Uncontrolled Flue Gas Emissions from Power Generation System
(Stream 707a) 186
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TABLES (Continued)
Number Title Page
3-66 Characteristics of Cooling Tower Drift and Blowdown
(Streams 731/732) 190
3-67 Uncontrolled Evaporative Emissions from Storage Tanks
(Stream 751) 194
3-68 Concentrations of Trace Metals in Naphtha from EDS Pilot
Plant Solvent Fractionation Tower 198
3-69 Concentrations of Organic Compounds in Naphtha from EDS
Pilot Plant Solvent Fractionator Tower 199
3-70 Comparison of Composition of Fuel Oil Products from the EDS
Base Case and MFS Case Designs 200
3-71 Concentrations of Trace Metals in Light Solvent Fuel Oil
from EDS Pilot Plant Solvent Fractionation Tower 202
3-72 Concentrations of Organic Compounds in Light Solvent Fuel
Oil from EDS Pilot Plant Solvent Fractionation Tower 203
3-73 Uncontrolled Fugitive Hydrocarbon Emissions from EDS
Commercial Plant 206
3-74 Summary of Uncontrolled Gaseous Waste Streams from EDS
Commercial Plant (Illinois Coal Base Case) 210
3-75 Summary of Uncontrolled Gaseous Waste Streams from EDS
Commercial Plant (Illinois Coal MFS Case) 214
3-76 Summary of Uncontrolled Liquid Waste Streams from EDS
Commercial Plant (Illinois Coal Base Case) 216
3-77 Summary of Uncontrolled Liquid Waste Streams from EDS Commercial
Plant (Illinois Coal MFS Case) 219
3-78 Summary of Uncontrolled Solid Wastes from EDS
Commercial Plant (Illinois Coal Base Case) 222
3-79 Summary of Uncontrolled Solid Wastes from EDS Commercial
Plant (Illinois Coal MFS Case) 223
3-80 Summary of Products from EDS Commercial Plant (Illinois
Coal Base Case) 225
3-81 Summary of Products from EDS Commercial Plant (Illinois
Coal MFS Case) 226
3-82 Cross-Reference Index for Primary Waste Streams 22f
3-83 Cross-Reference Index for Secondary Waste Streams from
Pollution Control Operations 233
4-1 Capital Cost Estimating Method 242
4-2 Unit Costs and Factors for Annualized Cost Estimates 244
4-3 Assumptions Used to Calculate Capital Recovery Factor 245
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TABLES (Continued)
Number Title Page
4-4 Estimated Characteristics of Gaseous Waste Streams According
to Source Type for EDS Commercial Plant (Illinois Coal Base
Case) 247
4-5 Estimated Characteristics of Gaseous Waste Streams According
to Source Type for EDS Commercial Plant (Illinois Coal MFS
Case) 248
4-6 Key Features of Bulk Sulfur Removal Processes 253
4-7 Key Features of Residual Sulfur Removal Processes 259
4-8 Comparison of Incineration Processes 264
4-9 Estimated Characteristics of Combined Acid Gases for EDS
Commercial Plant (Illinois Coal Base Case) 267
4-10 Estimated Characteristics of Combined And Acid Gases for EDS
Commercial Plant (Illinois Coal MFS Case) 268
4-11 Costs of Bulk Sulfur Removal With Stretford Process for Acid
Gas from AGR Unit in Hydrogen Purification (Stream 428) 283
4-12 Costs of Bulk Sulfur Removal With Stretford Process for
Flexicoking Heater/Gasifier Sour Fuel Gas (Stream 304) 287
4-13 Costs of Bulk Sulfur Removal With Stretford Process for
Slurry Drier Vent Gas and Vacuum Fractionator Off-Gas (Streams
102 and 153/156) 291
4-14 Costs of Flaring for Transient Waste Gases (Streams 801, 802,
803) 296
4-15 Costs of Thermal Incineration for Transient Waste Gases
(Streams 801, 802, 803) 297
4-16 Costs of Thermal Incineration with Waste Heat Recovery for
Transient Waste Gases (Streams 801, 802, 803) 298
4-17 Costs of Sulfur Dioxide Control by Sodium Throwaway Processes
for Transient Waste Gases (Streams 801, 802, 803) 300
4-18 Material Flow Estimates and Performance of Integrated Control
for Combined Acid Gas Stream Employing Claus Bulk Sulfur
Removal and Beavon Tail Gas Treatment (Illinois Coal Base
Case) 304
4-19 Material Flow Estimates and Performance of Integrated Control
for Combined Acid Gas Stream Employing Claus Bulk Sulfur
Removal and Beavon Tail Gas Treatment (Illinois Coal MFS Case) 305
4-20 Costs of Integrated Control For Combined Acid Gas Stream
Employing Claus Bulk Sulfur Removal and Beavon Tail Gas
Treatment 307
xiii
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TABLES (Continued)
Number Title Page
4-21 Material Flow Estimates and Performance of Integrated Control
for Combined Acid Gas Stream Employing Claus Bulk Sulfur
Removal with SCOT Tail Gas Treatment and Incineration
(Illinois Coal Base Case) 310
4-22 Material Flow Estimates and Performance of Integrated Control
for Combined Acid Gas Stream Employing Claus Bulk Sulfur
Removal with SCOT Tail Gas Treatment and Incineration
(Illinois Coal MFS Case) 311
4-23 Costs of Integrated Control for Combined Acid Gas Stream
Employing Claus Bulk Sulfur Removal with SCOT Tail Gas
Treatment and Incineration 313
4-24 Material Flow Estimates and Performance of Integrated Control
for Combined Acid Gas Stream Employing Claus Bulk Sulfur
Removal with Wellman-Lord Tail Gas Treatment (Illinois Coal
Base Case) 315
4-25 Material Flow Estimates and Performance of Integrated Control
for Combined Acid Gas Stream Employing Claus Bulk Sulfur
Removal with Wellman-Lord Tail Gas Treatment (Illinois Coal
MFS Case) 316
4-26 Costs of Integrated Control for Combined Acid Gas Stream
Employing Claus Bulk Sulfur Removal with Wellman-Lord Tail
Gas Treatment 318
4-27 Combustion Modification Techniques for NO Control 322
/\
4-28 NOV Flue Gas Treatment Control Alternatives for Boilers 330
A
4-29 Key Features of Particulate Collection Equipment 334
4-30 Key Features of SO- Removal Processes 337
4-31 Costs of Particulate Control with Electrostatic Precipitators
for Flue Gases from Steam and Power Generation Systems
(Streams 701a and 707a) 345
4-32 Costs of S02 Removal with Limestone Scrubbing for Flue Gases
from Steam and Power Generation Systems (Streams 701 a and
707a) 347
4-33 Costs of S02 Removal with the Wellman-Lord FGD Process for
Flue Gases from Steam and Power Generation Systems (Streams
701 a and 707a) 349
4-34 Costs of S02 Removal with Sodium Throwaway Process for Sour
Shift Catalyst Regeneration/Decommissioning Offgas(Streams 355
449/450)
4-35 Costs of Organics and CO Control by Thermal Incineration 358
with Waste Heat Recovery for C02 Vent Gas (Stream 426)
x1v
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TABLES (Continued)
Number Title Page
4-36 Costs of Organics and CO Control by Catalytic Incineration
for C02 Vent Gas (Stream 426) 360
4-37 Costs of Organics and CO Control by Flaring for Catalyst
Regeneration/Decommissioning Off-Gases 364
4-38 Costs of Organics and CO Control by Thermal Incineration for
Catalyst Regeneration/Decommissioning Off-Gases 365
4-39 Key Features of Storage Pile Dust Control Technologies 368
4-40 Repair Methods for Fugitive Emissions Reduction 379
4-41 Equipment Design/Modifications for Fugitive Hydrocarbon
Emissions Control 380
4-42 Storage Tank Emission Estimates 383
4-43 Costs of Control of Evaporative Emissions from Product and
By-Product Storage (Stream 751) 385
4-44 Fugitive Organic Emissions from Process Equipment for EDS
Commercial Plant (With Leak Detection/Repair and Equipment
Specification) 387
4-45 Summary of Control Techniques Potentially Applicable to the
Treatment of EDS Wastewater Containing Primary Dissolved
Organics and Dissolved Gases 395
4-46 Estimated Characteristics of Stream A - Combined Sour Water
Stream (1,134 Mg/hr Coal Feed EDS Plant) 404
4-47 Estimated Composition of Feed and Treated Effluent from
Phenosolvan Process (Stream A) 409
4-48 Summary of Cost Estimates for Phenosolvan Process (Stream A)
(1J34 Mg/hr Coal Feed EDS Plant) 409
4-49 Estimated Composition of Feed and Treated Effluent for
Chem-Pro Process (Stream A) (1,134 Mg/hr Coal Feed EDS Plant) 413
4-50 Summary of Cost Estimates for the Chem-Pro Process (Stream A) 413
4-51 Summary of Cost Estimates for the Resin Adsorption Process -
Stream A (1,134 Mg/hr Coal Feed EDS Plant) 415
4-52 Estimated Composition of Feed and Treated Effluent from the
Wet Air Oxidation Process - Stream A (1,134 Mg/hr Coal Feed
EDS Plant) 417
4-53 Estimated Composition of Feed and Treated Effluent Streams
for the Phosam-W Process (1,134 Mg/hr Coal Feed EDS Plant) 419
4-54 Summary of Cost Estimates for the Phosam-W 419
4-55 Estimated Composition of Feed and Treated Effluent Streams
for the Chrvron-WWT Process (1,134 Mg/hr Coal Feed EDS Plant) 422
xv
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TABLES (Continued)
Number Title Page
4-56 Summary of Cost Estimates for the Chevron-WWT Process 422
4-57 Estimated Characteristics of Combined Stream A As Feed to
Control Function 4 (1,134 Mg/hr Coal Feed EDS Plant) 424
4-58 Estimated Composition of Feed and Treated Effluent for the
Activated Sludge Process - Stream A (1,134 Mg/hr Coal Feed
EDS Plant) 426
4-59 Summary of Cost Estimates for the Activated Sludge Process 426
4-60 Estimated Composition of Feed and Treated Effluent for the
Activated Carbon Adsorption Process - Stream A (1,134 Mg/hr
Coal Feed EDS Plant) 430
4-61 Summary of Cost Estimates for the Activated Carbon Adsorption
Process 430
4-62 Estimated Composition of Feed and Treated Effluent for the
Incinerator - Stream A (1,134 Mg/hr Coal Feed EDS Plant) 433
4-63 Summary of Cost Estimates for the Incinerator 433
4-64 Estimated Characteristics of Feed and Effluents for the
Cooling Tower Operation (1,134 Mg/hr Coal Feed EDS Plant) 437
4-65 Estimated Composition of Feed and Concentrate for the Vapor
Compression Evaporation - Stream A (1,134 Mg/hr Coal Feed EDS
Plant) 439
4-66 Summary of Cost Estimates for the Vapor Compression Evaporator 439
4-67 Estimated Composition of Uncontrolled Waste Streams, Treated
Effluents and Secondary Waste Streams for Integrated Control
Example 1 Base Case (1,134 Mg/hr Coal Feed EDS Plant) 454
4-68 Estimated Composition of Uncontrolled Waste Streams, Treated
Effluents and Secondary Waste Streams for Integrated Control
Example 1 MFS Case (1,134 Mg/hr Coal Feed EDS Plant) 455
4-69 Summary of Estimated Costs for Integrated Control Example
One - Base Case (1,134 Mg/hr Coal Feed EDS Plant) 457
4-70 Summary of Estimated Costs for Integrated Control Example
One - MFS Case (1,134 Mg/hr Coal Feed EDS Plant) 458
4-71 Composition of Treated Effluent for Integrated Control
Example 2 Base Case and MFS Case (1,134 Mg/hr Coal Feed EDS
Plant) 461
4-72 Summary of Costs for Integrated Control Example 2 (1,134
Mg/hr Coal Feed EDS Plant) 462
4-73 Estimated Composition of Treated Effluents for Integrated
Control Example 4 Base Case and MFS Case (1,134 Mg/hr Coal
Feed EDS Plant) 466
xvi
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TABLES (Continued)
Number Title Page
4-74 Summary of Estimated Costs for Integrated Control Example 3
Base Case and MFS Case (1,134 Mg/hr Coal Feed EDS Plant) 467
4-75 Estimated Composition of Treated Effluents for Integrated
Control Example 4 Base Case and MFS Case (1,134 Mg/hr Coal
Feed EDS Plant) 469
4-76 Summary of Estimated Costs for Integrated Control Example 4
Base Case and MFS Case (1,134 Mg/hr Coal Feed EDS Plant) 471
4-77 Summary of Control Techniques Potentially Applicable to EDS
Wastewater Containing Primarily Dissolved Inorganics 473
4-78 Summary of Solid Waste Management Technologies 485
4-79 Site-Specific Factors to be Considered for Terrestrial
Disposal Options 486
4-80 Summary of Solid Waste Quantities for Source Type 1 Streams 495
4-81 Summary of Estimated Costs for FBC Boilers Applied to Combined
Flexicoking Solids (1,134 Mg/hr Coal Feed EDS Plant) 501
4-82 Summary of Estimated Costs for Treatment/Disposal of Biosludge 521
4-83 List of Spent Catalysts Waste Streams 524
4-84 Summary of Cost Estimates for Solid Waste Integrated Control
Examples 1 and 2 528
5-1 Data Gaps, Limitations, and Research Needs for Gaseous Waste
Streams and Air Pollution Control Technologies 536
5-2 Data Gaps, Limitations, and Research Needs for Wastewater
Streams and Water Pollution Control Technologies 545
5-3 Data Gaps, Limitations, and Research Needs for Waste Streams
and Solid Waste Management Technologies 551
xv ii
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GLOSSARY OF ACRONYMS
•ADA Anthraquinone disulfonic acid
ADIP Shell-patented acid gas removal process based on DIPA or MDEA
AGR Acid gas removal
BFOE Barrels fuel oil equivalent, 1 BFOE = 6,050,000 Btu (LHV)
BOD Biochemical oxygen demand
BSRP Beavon Sulfur Removal Process
COD Chemical oxygen demand
CRA Compression-refrigeration-absorption
CRF Capital Recovery Factor
DEA Diethanolamine
DIPA Diisopropanolamine
DOE Department of Energy
ECLP Exxon Coal Liquefaction Pilot Plant
EDS Exxon Donor Solvent
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
ER&E Exxon Research and Engineering Company
ESP Electrostatic precipitator
FBC Fluidized bed combustion
FGD Flue gas desulfurization
FGR Flue gas recirculation
FGT Flue gas treatment
HHV High Heating Value
IERL Industrial Environmental Research Laboratory
LEA Low excess air
LHV Lower Heating Value
LNB Low NO burners
A
LPG Liquified petroleum gas
xviii
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GLOSSARY OF ACRONYMS (Continued)
MAP Moisture and ash free
MEA Monoethanolamine
MDEA Methyldiethanolamine
MFS Market Flexibility Sensitivity
NO Nitrogen oxides
J\
NMHC Non-methane hydrocarbons
NPDES National Pollution Discharge Elimination System
NSPS New Source Performance Standards
OAQPS Office of Air Quality Planning and Standards, EPA
OFA Overfire Air Injection
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
RCRA Resource Conservation and Recovery Act
RL Reduced Load
ROM Run of Mine
SCOT Shell Claus Off-Gas Treatment
SCR Selective Catalytic Reduction System
SNG Substitute Natural Gas
SNPA Societe Nationale des Petroles d"Aquitaine
SO Sulfur oxides
X
SRC Solvent Refined Coal
TDS Total dissolved solids
TEA Triethanolamine
TGT Tail gas treatment
TOC Total organic carbon
TSP Total suspended particulates
TSS Total suspended solids
xix-
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GLOSSARY OF ACRONYMS (Continued)
TVA Tennessee Valley Authority
VGO Vacuum gas oil
VOC Volatile Organic Compounds
W-L Wellman-Lord
xx
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CONVERSION FACTORS
1.0 kg [kilogram]
1.0 Mg [megagram (metric ton)]
o
1.0 m [cubic meter]
1.0 £ [litre]
o
1.0 Nm /hr [normal cubic meter
(at 0°C) per hour ]
1.0 GO [gigajoule]
1.0 MW [megawatt]
1.0 MJ/s [megajoule per second]
1.0 kWh [kilowatt hour]
o
1.0 MJ/Nm [megajoule per
normal cubic meter at 0°C)]
1.0 g/Nm [gram per normal
cubic meter (at 0°C)]
1.0 MPa [megapascal]
1.0 kmol
Prefixes
T = tera = 10
k = kilo = KT
= 2.205 Ib [pound (mass)]
= 1.102 ton [short ton (2000 Ib)]
= 264.2 gal [gallon]
= 0.2642 gal [gallon]
= 37.32 scfh [standard cubic feet =
(at 60°F) 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 6°C)]
= 9.87 atmosphere
= 22.4 Nm3 (at 0°C and 1 atmosphere)
12
G = giga
m = milli
= 10-
= 10
-3
M = mega = 10
y = micro = 10
-6
XXI
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ACKNOWLEDGEMENT
Technical and background information for this Pollution Control Technical
Manual was prepared for the EPA by the Energy and Environmental Division, TRW
Incorporated, Redondo Beach, California, under Contract 68-02-3174, Work
Assignments 90 and 108. The TRW Project Manager for this effort was Dr. Kar
Y. (Timothy) Yu.
xxn
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1 . INTRODUCTION
1.1 PURPOSE AND USE OF PCTM'S
It is envisioned that an environmentally acceptable synthetic fuels in-
dustry will be developed for future U.S. energy production. As part of this
overall effort, the Environmental Protection Agency (EPA), Office of Research
and Development, has for the past several years undertaken an extensive study
to determine synthetic fuel plant waste stream characteristics and potentially
applicable pollution control systems.
The purpose of the Pollution Control Technical Manuals (PCTM's) is to
convey in a summarized and readily useful manner information on synfuel waste
stream characteristics and pollution control technology as obtained from stu-
dies by EPA and others. The documents provide waste stream characterization
data and describe a wide variety of pollution controls in terms of estimated
performance, cost, and reliability. The PCTM's 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 utilize a specific emission control process 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 process-specific PCTM's and a more general appendix volume
which describes over fifty pollution control technologies. Application of pol-
lution 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
Pollution Control Technical Manual for Exxon Donor Solvent
Direct Coal Liquefaction
1
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Pollution Control Technical Manual for Lurgi Oil Shale
Retorting with Open Pit Mining
Pollution Control Technical Manual for Modified In-Situ
Oil Shale Retorting Combined with Lurgi Surface Retorting
Pollution Control Technical Manual for TOSCO II Oil Shale
Retorting with Underground Mining
Control Technology Appendices for the Pollution Control
Technical Manuals
By focusing on specific process technologies, the PCTM's attempt to be as
definitive as possible on waste stream characteristics and control technology
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 PCTM's from process description through waste
stream characterization and control technology evaluation provides the user
with a number of alternative approaches to understanding the environmental
consequences in operating synthetic fuel plants.
Control technology configurations presented in the PCTM's reflect pollu-
tant removal levels which are believed to be achievable with currently avail-
able control technologies based upon existing data. Since there are no domes-
tic commercial scale synfuels facilities, the data base supporting this docu-
ment is from bench and pilot synfuel facilities, developers' estimates, engi-
neering analyses, analogue domestic industries, and non-U.S. commercial synfuel
plants. As commercial synthetic fuel plants are built, the EPA will continue
conducting research in order to develop a more comprehensive data base. In
the interim, the Agency encourages facility planners, permit officials, and
other interested parties to take advantage of the information contained in
these documents.
1.2 CONTENT OF THIS PCTM
1.2.1 Synfuels Process Addressed
This PCTM addresses the Exxon Donor Solvent (EDS) process for direct coal
liquefaction. In direct liquefaction technologies such as EDS, coal is con-
verted directly into liquids, as distinguished from indirect liquefaction pro-
cesses where the coal is first gasified and the product gas then synthesized
-------
into liquid products. The direct liquefaction approach receiving the most
attention involves hydrogenation of the coal at intermediate temperature (650-
900°F, or 340-480°C) and elevated pressure (100-200 atm, or 10-20 MPa), using
a heavy coal-derived organic solvent as a medium to aid in adding the hydrogen
to the depolymerized coal molecules. This hydrogenation approach is employed
by EDS and by other direct liquefaction processes in advanced stages of develop-
ment, including Solvent Refined Coal (SRC) and H-Coal. These processes produce
a range of products -- including naphtha (which can be refined into gasoline
and other fuels), a range of fuel oils (for domestic heating, industrial/
utility boilers and stationary turbines), light hydrocarbon gases and other
by-products such as sulfur, ammonia and phenols.
Research and engineering on the EDS process began at Exxon in 1966. A
two-year test program has recently been completed on a 250 ton coal/day pilot
plant in Baytown, Texas. No demonstration-scale or commercial-scale EDS faci-
lities are contemplated at the present time, although Exxon considers the tech-
nology technically ready for commercial application, and although plans are
underway for large-scale plants employing some of the other direct liquefaction
processes.
The EDS process is fundamentally similar to the SRC and H-Coal processes
in many respects: all of the processes involve the addition of hydrogen to
finely-crushed coal at elevated temperature and pressure in a medium of hydro-
gen-donating solvent, followed by separation of the product liquids and recycle
of the recovered solvent back to coal hydrogenation reactors. There are some
significant differences between the processes, also; one unique feature of the
EDS process is the use of a separate catalytic reactor to add hydrogen back
into the recovered solvent prior to the return of the solvent to the coal
hydrogenation reactors.
The similarities among the direct liquefaction processes will naturally
lead to similarities in the types of environmental discharges from commercial
plants employing these different processes. There will be differences in exact
discharge stream identities, in exact discharge flow rates and in exact dis-
charge compositions, depending upon which direct liquefaction process is em-
ployed, and depending upon how the process is designed; but the types of
-------
commercial discharges will be similar for all processes and designs. For
example, all direct liquefaction processes will have an acid gas stream re-
quiring control; all will have a high-organics wastewater stream; all will have
a solid waste stream consisting largely of coal ash. The control technologies
applicable to these types of streams will generally be the same, irrespective
of the direct liquefaction processes- although performance and costs of the
controls will necessarily vary as discharge stream flow and composition varies
from process to process.
This PCTM addresses the EDS process specifically, due to the availability
of pilot plant environmental data and good commercial-scale conceptual plant
designs for the EDS process. Detailed stream identifications, discharge rates,
and stream compositions presented in this manual -- and the related estimated
performance and costs of alternative control techniques -- are based upon
specific conceptual commercial EDS plant designs. However, the information
presented in this manual concerning the types of streams requiring control --
and concerning the types of control techniques applicable to these stream
types -- should be of general use in considering SRC and H-Coal facilities as
well as EDS, and in considering EDS plant designs in addition to the specific
designs utilized in this manual.
This PCTM addresses the discharges and controls associated with a commer-
cial-scale EDS direct liquefaction plant, beginning with the receipt of the
feed coal and other raw materials, and proceeding through the separation and
storage of the direct liquid products which would normally then be transferred
to a conventional refinery for further refining/upgrading. All ancillary
operations associated with the direct liquefaction plant (e.g., steam and power
generation, feedwater treatment) are addressed. The manual does not address
discharges/controls associated with: the ultimate refining/upgrading of the
direct liquids into marketable products, the distribution of these products
to ultimate users, or the ultimate use of the products.
1.2.2 Information Presented in PCTM
Section 1 of the manual presents an introduction to the overall approach
and content of the manual. Section 2 is an overview of the EDS process. Section
3 presents the flow and composition for each discharge stream within a conceptual
-------
commercial EDS plant design, broken down by process area within the plant.
For each discharge stream thus identified, the manual summarizes (in Section
4) a wide range of alternative individual control techniques that might be
considered for the control of that stream, providing such information as:
control process principle; development status; pollutant removal performance;
reliability; factors influencing performance; secondary discharge streams
resulting from the control process; and advantages/disadvantages. For many
of these alternative control techniques, further details concerning the tech-
nique are presented in the separate volume entitled "Control Technology Appen-
dices for PCTMs", and design considerations and costs for applying the tech-
nique to the EDS commercial design are discussed in Section 4. Where a stream
would require several individual control techniques in series (for example, a
wastewater control system with three or four or more techniques combined),
Section 4 also presents some examples of possible integrated control systems,
to illustrate possible ways in which individual controls might be combined.
Finally, in Section 5, the manual summarizes data gaps and limitations (con-
cerning e.g., stream composition or control technique performance), in order
to illustrate the limitations of the data base.
The PCTM addresses both uncontrolled, or primary, discharge streams (i.e.,
those that would result from an uncontrolled EDS facility), and secondary dis-
charge streams (those which result from the application of a control technique
to the EDS plant). The term "uncontrolled discharge stream" refers to a stream
prior to the application of any controls; as such, an "uncontrolled discharge
stream" is generally not a true discharge stream at all, since, in a commercial
EDS facility, control techniques would normally be applied.
1.3 APPROACH FOR DEVELOPING PCTM
1.3.1 Plant Design and Uncontrolled Discharge Estimates
The discharge stream identifications, flow rates and compositions pre-
sented in this manual are based upon two conceptual commercial-scale EDS plant
designs prepared by Exxon, using Illinois coal (5,6,7,8). One of the two con-
ceptual plant designs, identified as the "base case", is fed with 30,000 tons
of coal per stream day, and has a product output (in the form of naphtha, fuel
oil, and liquified petroleum gas) of 60,240 barrels per stream day (fuel oil
-------
equivalent). In the "base case" design, hydrogen for the coal liquefaction
reaction is generated through steam reforming of the plant's by-product syn-
thetic natural gas. The second related conceptual plant design, identified as
the "market flexibility sensitivity" (or MFS) case, utilizes 30,000 tons of
coal per stream day and generates 71,080 barrels per stream day (fuel oil
equivalent) of liquid and gaseous products. The MFS design differs from the
base case primarily in that the MFS case generates the hydrogen for liquefac-
tion by gasifying about half of the heavy residual organics remaining after
the liquefaction/separation steps, rather than by steam reforming the synthe-
tic natural gas; this approach leaves the MFS case with the synthetic natural
gas as a plant product, and results in an increased plant efficiency relative
to the base case. Both the base and the MFS cases are addressed throughout
the PCTM, in order to illustrate the effect that plant design can have on dis-
charges and controls. In fact, Exxon has recently introduced a third design
(the "bottoms recycle" case), designed to increase the yield of lighter liquid
products; the bottoms recycle design was not completed in time for inclusion
in the PCTM.
In utilizing the Exxon commercial plant designs, the PCTM has relied upon
heat and material balances prepared by Exxon. In order to confirm the flow
rate of uncontrolled discharges within the designs, EPA has, where warranted,
conducted independent engineering evaluation of the Exxon mass balances. Like-
wise, in estimating the composition of the discharges, the Exxon design esti-
mates have been bolstered using: environmental data which have become avail-
able since the Exxon designs were completed; thermodynamic calculations; and
engineering evaluation.
The PCTM focuses in Section 3 on an "uncontrolled" EDS plant -- i.e., a
plant with no environmental controls at all. The philosophy is that, once the
uncontrolled plant is defined, then the array of possible alternative control
techniques can be presented (in Section 4) for each uncontrolled discharge
stream. Since the Exxon designs for the base and MFS plants incorporated en-
vironmental controls, these controls have been "subtracted out" for the pur-
poses of the uncontrolled plant description in Section 3, and for the purposes
of estimating uncontrolled plant capital and operating costs in Section 2. In
cases where there might be some question concerning whether some technique is
-------
primarily intended as an environmental control measure -- or whether it is
instead a part of the EDS process which would be utilized even in the absence
of environmental requirements — this question is addressed in the appropriate
part of Section 3. For example, acid gas removal processes -- intended to
remove reduced sulfur and other contaminants from EDS process gases -- are
considered part of the EDS process; the sulfur recovery and other steps which
are then used to treat the removed acid gases, however, are considered to be
environmental control measures.
Discharges from future commercial EDS plants (or discharges presented in
environmental permit applications associated with such plants) could differ
from those presented in the PCTM. One reason for such differences would be
the uncertainty involved in estimating emission/effluent compositions at this
time; as discussed elsewhere, the environmental data are limited, the available
experimental facilities are not always representative of commercial plants in
terms of environmental discharges, and there is always necessarily some un-
certainty in making engineering estimates of trace components in discharges
from complex systems. Beyond this uncertainty, however, there are other rea-
sons why there will be differences between the PCTM and subsequent EDS facili-
ties. Discharges will vary depending upon a number of factors:
• Feedstock properties. For example, the PCTM (and the Exxon base and
MFS designs) are based upon an Illinois bituminous coal. The EDS
process has also been piloted on sub-bituminous coal and lignite;
discharges from a commercial plant processing these coals will be
somewhat different from a plant processing Illinois coal.
• EDS plant design. The detailed design of the plant can affect the
identity of the discharge streams as well as their flows and composi-
tions. The PCTM is based upon the base and MFS cases. But a third
case exists now (bottoms recycle), and variations on these cases are
possible in the future.
• EDS plant operating conditions. Along with plant design, plant
operating conditions can be varied in order to adjust product slate
and production rates. Changes in operating conditions can influence
discharges.
The approach that has been employed in the PCTM has been to use the best esti-
mates/data currently available, and the feedstock, design details and operating
conditions employed in the Exxon base and MFS conceptual designs.
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1.3.2 Control Technology Evaluation
For each "uncontrolled" EDS plant stream identified in Section 3, the
manual presents in Section 4 a range of possible individual alternative con-
trol techniques that might be considered for that stream. Key information
concerning each control technique (as generally applied to synfuels processes)
is summarized in a tabular format (e.g., process principle, development status,
general performance, reliability, secondary streams, and advantages/disadvan-
tages). For many of the individual control techniques, further discussion
is provided in Section 4 of the specific performance and costs associated with
the application of the technique to each pertinent stream in the EDS plant
designs, stream by stream. Also for many of the techniques, further details
supporting the Section 4 presentation are provided in the separate appendix
volume. Where a stream would require several individual control techniques
combined in some manner, Section 4 also presents some examples of how the
individual techniques might be combined into integrated control systems,
including assessment of the performance and costs of these integrated control
examples applied to the EDS designs.
The evaluation of individual control techniques in the manual is based
upon literature information, contacts with control equipment vendors, informa-
tion on experience with the control technique in related conventional indus-
tries, any experimental data regarding the performance of the technique on EDS
or other synfuels streams, and engineering evaluation. In some cases, simple
models have been developed providing technique cost as a function of major
variables, such as capacity. Since essentially none of the control techniques
have been operated routinely on a large EDS (or other synfuels) facility, some
extrapolation has generally been required in projecting control performance on
an EDS plant. Of particular difficulty has been the estimation of process
reliability, capital and operating costs.
In the Section 4 summary of individual control techniques for each stream,
an effort has been made to address essentially all of the possible alternative
techniques that might be considered by a developer planning an EDS plant. How-
ever, the techniques discussed in detail in the Appendix -- and the techniques
which are further discussed in Section 4, in terms of their application to the
-------
EDS plant designs -- do not include the full list of techniques. Rather,
these latter discussions address only those techniques which have received
serious consideration to date from synfuels plant designers, or which offer
potential for improved performance relative to commonly considered techniques.
Capital and operating costs for control techniques are presented on three
bases, wherever possible: 1) cost per unit throughput; 2) absolute cost of the
technique, as applied to the EDS plant designs; and 3) control technique cost
as a percentage of the total cost of the uncontrolled EDS plant. In some cases,
only the cost per unit throughput is shown for a technique; these cases result
when the potential variability in the cost of the technique (e.g., due to pos-
sible variations in system design) is so great that the cost range would be too
broad to be meaningful if expressed as absolute cost or as percentage cost.
The cost estimates are considered accurate to an extent no greater than j^ 50%.
As with the estimates of plant discharge flows/compositions, there might
be differences between the performance and cost estimates presented in the
PCTM for the control techniques, and the performances/costs that will be ex-
perienced in practice in future synfuels plants. One reason is the uncertainty
in the estimates of flow rates and compositions of the streams being fed to the
controls, as discussed in Section 1.3.1. In addition, there is uncertainty
associated with estimating the performance and costs of a control, even if the
feed stream to the control were defined exactly; design information to enable
rigorous detailed design of many controls is not generally available; detailed
designs are beyond the scope of this manual; and even detailed designs reflect
some uncertainty. The possible effect on the control technique of some perhaps
unanticipated, interfering trace contaminant in the EDS stream might not be
predictable. Beyond the uncertainty in estimating control performance/costs
for the EDS base and MFS designs, there is variability that can result from
variations in these EDS design conditions in future, actual plants: variations
in coal feedstock, plant design and plant operating conditions could signifi-
cantly influence uncontrolled discharges, as discussed in Section 1.3.1, and
thus influence control performance/costs.
Most significant of all, the performance and costs of a control technique
can be affected tremendously by variations in the design of the control system
-------
in which the technique appears. For example, the performance and cost of one
individual wastewater control technique, such as biological oxidation -- which
is only one of several individual technques that might appear in a multi-
component wastewater control system -- will depend upon: how the various indi-
vidual wastewater streams are combined and fed into the various individual sys-
tem components; which specific techniques precede the biox unit in series; and
what organisms and operating procedures are selected for the biox unit. As
another example, the performance/cost of flaring could vary significantly depend-
ing upon whether one central flarestack is used for the entire plant, or whether
two separate smaller flares are employed. One purpose of the integrated con-
trol examples in Section 4 is to illustrate performance/costs for a few repre-
sentative systems for which these fundamental control system design decisions
have been made. A third example is that there is an "equipment quality - ser-
vice factor" tradeoff which affects capital investment costs and operating costs.
Some companies prefer to modify equipment or add additional equipment to a basic
design to insure smoother, less troublesome operation. This results in a high-
er service factor and lower operating costs, but also increases capital invest-
ment cost. Other companies prefer to take the basic design, or minimize capi-
tal investment, with resulting lower service factor and higher operating costs.
The tradeoff between maximizing service factor or minimizing capital investment
is usually based on design philosophy and/or economics. The capital investment
and operating costs presented in Section 4 will be subject to variation due to
the "equipment quality - service factor" tradeoff.
Despite the unavoidable uncertainty/variability in any performance/cost
estimates which are made at the present time, the performance and cost figures
presented in this manual are felt to be effective relative indicators of con-
trol performance and costs. Throughout the PCTM, efforts have been made to
quantify the uncertainty/variability where this is possible.
1.4 DATA BASE FOR PCTM
1.4.1 Data Base for Uncontrolled Discharge Estimates
The experimental data upon which the uncontrolled discharge estimates are
based, result from two major sources:
10
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1) The small pilot-scale data which were reflected in the Exxon con-
ceptual commercial plant designs. Exxon's designs for the base case
and MFS case EDS facilities reflect process and environmental data
obtained by Exxon using a 1 ton coal/day small pilot-scale unit, and
various smaller bench-scale experimental facilities. These designs
were completed prior to the availability of significant data from the
large, 250 ton coal/day Exxon Coal Liquefaction Pilot Plant (ECLP).
Therefore, to the extent that the PCTM utilizes the discharge flow
rates and compositions generated in the Exxon designs, the manual
reflects Exxon's data from the 1 ton/day small pilot unit.
2) Source testing data from the 250 ton/day ECLP facility. EPA has
completed a three-day environmental source sampling effort on the
ECLP plant, and the data from this campaign have been utilized in
updating and supplementing the discharge composition estimates from
the earlier EDS designs. The EPA campaign included a broad screen-
ing effort addressing conventional pollutants, trace metals, and a
wide range of organic compounds. In addition, Exxon has completed
some environmental testing on the ECLP unit, and some of the Exxon
data have been made available to EPA and have been utilized in the
PCTM. Where appropriate, the ECLP data have been used in place of
any corresponding design estimates (based on the 1 ton/day unit),
or in place of calculated values.
In addition to the above major sources, data are available from three EPA
source testing campaigns on a 30 ton coal/day Solvent Refined Coal pilot plant.
These data, while not presented extensively in this manual, were helpful in
confirming the data from comparable streams in the EDS plant.
There are some apparent limitations in this discharge stream data base.
First, the substantive ECLP source testing was conducted at essentially one
(representative) set of EDS conditions; thus, the data base does not cover
a range of plant feedstock, operating or design conditions. Second, the plant
is lacking certain discharge streams that would exist in a commercial facility;
other streams that are present in ECLP might not be representative of the com-
parable commercial-scale stream. For example, ECLP does not include a bottoms
processing operation (e.g., Flexicoking or gasification), so that the waste-
water and waste ash streams associated with that operation are missing. ECLP
does not include its own wastewater treatment plant, so that representative
samples of wastewater treatment sludges cannot be obtained. Because the ECLP
facility does not include the full array of valves, pumps, flanges, etc., at
representative scale, EPA did not obtain data on fugitive organics emissions;
nor was a representative flarestack available.
11
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Additional environmental data from the ECLP facility are expected to be-
come available in the future.
1.4.2 Data Base for Control Performance/Costs
There are essentially no data on the performance of control equipment
operating continuously on an experimental EDS facility. The reason is that
the experimental units do not include dedicated, representative control tech-
niques; the units are built primarily to explore EDS process-related questions,
not to demonstrate environmental control technology. In the ECLP facility,
for example, recovered acid gases are directed to the sulfur recovery system
in the refinery which adjoins the pilot plant, where the ECLP acid gases are
mixed with gases from the refinery prior to treatment; thus, no data can be
obtained on the performance of the sulfur recovery system on the ECLP acid
gases alone. Likewise, ECLP wastewaters are directed to the neighboring re-
finery's wastewater treatment system. Solid wastes typical of a commercial
EDS facility -- e.g., Flexicoker and gasifier ash, wastewater treatment slud-
ges -- are not generated at ECLP, and hence are not treated/disposed. Some
pilot plants for direct liquefaction processes other than EDS, do include dedi-
cated wastewater treatment systems, but these systems are not considered to be
representative, so the data can be used only with caution in this PCTM. A
small wastewater treatment train has been installed on a slipstream of the
wastewaters from the H-Coal pilot plant in Catlettsburg, Kentucky, but no
results were available in time to be included in the PCTM.
As a result, the only real control performance data obtainable from EDS
would be that developed by taking samples of streams in the EDS facilities,
and treating them separately in remote experimental control facilities. In
fact, Exxon had reportedly planned to treat ECLP wastewater samples in bench-
scale wastewater treatment equipment, but the results from this effort were
not available for inclusion in the PCTM. Similar types of testing are being
conducted by others on samples of wastewaters from other direct liquefaction
experimental facilities, for SRC and H-Coal; the available data are limited,
but have been utilized where felt to be applicable to the EDS case.
12
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1.5 HOW TO USE THE PCTM
There are two major components of the PCTM: 1) identification and charac-
terization of uncontrolled discharge streams, in Section 3; and 2) assessment
of a range of alternative control options for each uncontrolled stream thus
identified, in Section 4.
Section 3 begins (Section 3.2) with a listing of all of the discharge
streams (both uncontrolled and secondary) in the EDS base and MFS commercial
plant designs. This list is broken down by process area within the plant and,
within each process area, is further broken down by medium (gaseous, liquid,
solid). The bulk of Section 3 which then follows (Section 3.3) provides a
detailed description of each process area and of each discharge stream, giving
flow and composition information for each stream. This detailed description
follows the same order as the listing in Section 3.2, and is broken down by
process area and, within process area, by medium, in the same manner. Further-
more, Section 3.3 includes index terms in the upper outside corner of each
page, indicating the process area and the stream(s) covered on that page.
Therefore, a user of the manual who is interested in only one medium or in
only a few specific streams, can readily locate the streams of interest in
the listing in Section 3.2; and, using the process area and stream number in-
formation obtained from the listing, the user can then quickly flip through
Section 3.3, using the index terms, to find the detailed discussion of the
particular streams of interest.
In Section 3.4, summary tables are presented which list uncontrolled
emissions fro the total EDS base and MFS plants, broken down according to
each of the uncontrolled streams discussed in Section 3.3.
At the end of Section 3 (Section 3.5), there are two cross-reference
tables, linking Section 3 with Section 4 (and with the Appendix). In the
first of these cross-reference tables, for each uncontrolled discharge stream
identified in Section 3, the table indicates the precise subsection in Sections
3 and 4 where the user will find detailed stream characterization and discus-
sion of the control techniques applicable to that stream. For completeness,
the table includes not only the uncontrolled discharge streams discussed in
Section 3, but also secondary discharge streams which are introduced in Section
-------
4. The second cross-reference table is broken down by pollutant, rather than
by stream, indicating where in Section 4 and the Appendix the user will find
the control techniques applicable to each individual pollutant. The user in-
terested in a few specific streams, or a few specific pollutants, can then
readily locate the detailed discussions of the pertinent control techniques
for those streams or those pollutants.
The control technique discussion in Section 4 is broken down by medium
(Sections 4.2, 4.3, 4.4). Within each medium, the discussion is broken down
by "source type"; a source type includes individual discharge streams which
have similar control requirements. At the beginning of each source type sub-
section, a summary table is presented summarizing key information for each
alternative control technique that might be considered for use on that source
type. Then, for each source type, each specific stream within that source
type is discussed, stream by stream. Both uncontrolled and secondary streams
are addressed. In these stream-by-stream discussions, further details are
provided for many of the individual control techniques, concerning the per-
formance and costs associated with the application of each technique to each
stream.
Where a stream would require several individual control techniques in
some combination, the controls for that stream are divided into functional
areas. For example, if a wastewater stream might utilize bulk organics re-
moval and dissolved gas removal and further dissolved organics removal, then
these steps would be defined as "functions", and the individual control tech-
niques that fit into each of these functional areas would be identified. In
general, functional areas would normally fit together in some fairly consis-
tent sequence, and are usually defined such that either only one individual
control technique, or no technique, would be selected from each function in
assembling the total, combined system. With this functional method of pre-
sentation, the user then has the flexibility of considering the individual
techniques in any desired combination that he chooses, knowing the sequence
in which the functions normally fit together. For streams that do require
multiple control techniques in combination, Section 4 also includes some re-
presentative examples of how the variety of individual techniques from dif-
ferent functions might be combined into specific integrated control systems.
14
-------
Throughout Section 4, index terms appear in the upper outside corner of
each page, indicating the medium, source type, stream number, and (where
appropriate) functional area covered on that page. Referring to these index
terms -- especially with the aid of the cross-reference tables in Section 3.5
-- the user should be able to readily locate the page on which the controls
are discussed for any stream of interest.
The Appendix provides substantial additional details for many of the in-
dividual control techniques, beyond the level of detail in Section 4. The
Appendix presents information general to the control technique, and does not
address the application of the technique to the EDS plant designs specifically.
For example, the Appendix might present curves showing the cost of a technique
as a function of key variables. This information supports the presentation
in Section 4, where, for example, the cost numbers emphasized would be the
costs (taken from the Appendix curves) for applying the technique to the spe-
cific EDS plant designs, considering the values for the major variables asso-
ciated with these designs.
In Section 5, a table is presented summarizing data gaps and limitations
concerning the characterization of major discharge streams, and concerning the
performance/cost of major control techniques. This table is broken down by
stream, with the control techniques applicable to a given stream included
under that stream.
15
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2. PROCESS DESCRIPTION OVERVIEW
The EDS process is one of the more developed direct coal liquefaction
processes. Direct coal liquefaction processes convert coal directly into
liquid hydrocarbons whereas indirect coal liquefaction processes first convert
coal into gaseous products (gasification step) and then catalytically react
the gaseous products to form liquid hydrocarbons (liquefaction step) (1,2).
The EDS process is fundamentally similar to other leading direct liquefaction
processes in many aspects: all of the processes involve the addition of hydro-
gen to finely-crushed coal at elevated temperature and pressure in a medium
of hydrogen-donating solvent, followed by separation of the product liquids
and recycle of the recovered solvent back to the coal liquefaction reactors.
There are also, of course, significant differences between the EDS and other
direct liquefaction processes. One unique feature of the EDS process is the
use of a separate catalytic reactor to add hydrogen back into the recovered
solvent prior to recycling the solvent to the coal liquefaction reactors.
This section presents a brief discussion of the overall EDS process and
identifies the major waste streams generated in the facility. The major vari-
ables that affect the emissions and the cost for an EDS plant without environ-
mental controls will also be discussed.
2.1 OVERALL PROCESS DESCRIPTION
Two configurations for the EDS process are in advanced stages of develop-
ment. These are the base case configuration and the Market Flexibility Sensi-
tivity (MFS) case configuration. A third configuration (the bottoms recycle
configuration) has been proposed by Exxon, but is covered only briefly in the
PCTM because design details were not available in time for inclusion.
These alternative configurations, examined in this PCTM, are embodied in
specific commercial plant conceptual designs prepared by Exxon. Where specific
16
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flows, conditions and compositions are referenced to the base, MFS, and bottom
recycle cases in this manual, these are referring to the specific Exxon designs
2.1.1 Base Case
Figure 2-1 presents a simplified flow diagram for the EDS plant based on
the base case design. This design maximizes the production of C.+ liquids;
light hydrocarbons (C3~) produced in the liquefaction reactor are steam re-
formed to generate hydrogen for in-plant use.
Raw coal is crushed to minus 8 mesh in the coal preparation area (at a
rate of 27.2 Gg, or 30,000 tons/stream day in the Exxon commercial design).
Crushed coal is then fed to the slurry drier, where it is mixed with recycled
donor solvent to form a slurry; the slurry is dried to less than 4.0 wt %
moisture based on dry coal feed. After drying, the coal slurry is pumped to
reaction pressure, mixed with preheated hydrogen and heated in the slurry pre-
heat furnace before entering the liquefaction reactor which operates at 700-
750°K (800-890°F) and 13.9 MPa (2000 psig) (3). In the reactor, coal is lique-
fied in the presence of molecular hydrogen and hydrogenated donor solvent. The
donor solvent facilitates the dissolution of coal, and donates hydrogen to the
dissociated coal radicals. In the process, the donor solvent decomposes and
becomes "spent".
The products from the liquefaction reactor are separated in a vapor-liquid
separator and several distillation steps into a light hydrocarbon gas stream,
spent donor solvent, a C3 liquefied petroleum gas (LPG), a C, LPG, a naphtha
(pentanes to 350°F normal boiling range), fuel oil, and a heavy vacuum bottom
stream. The light hydrocarbon gas stream, scrubbed with diethanolamine (DEA)
to remove NH^, H^S and C02> is then passed through a steam reforming unit where
hydrogen for the liquefaction step is generated. The spent donor solvent is
hydrogenated in a fixed bed catalytic reactor and is recycled back to the
liquefaction reactor. The C3 LPG, C^ LPG, naphtha and fuel oil are stored as
products (60,240 barrels fuel oil equivalent per stream day for the Exxon com-
mercial design). The heavy vacuum bottoms are fed to a Flexicoking* unit where
*"Flexicoking" is the service mark for a proprietary process developed by Exxon.
17
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SOLVENT
COAL
PREPARATION
COAL
H2
1
SOLVENT
HYDRO-
GENATION
SLURRY
DRIER
SLURRY
PREHEAT
FURNACE
00
SLURRY
LIQUEFACTION
SPENT
DONOR
SOLVENT
DEA
SCRUBBER
STEAM
REFORMING
H2TO
LIQUEFACTION
AND SOLVENT
HYDROGENATION
C1/C2GAS
DISTILLATION
VACUUM
BOTTOM
SLURRY
STEAM
AIR
FLEXiCOKING
LIQUID
'PRODUCTS
DEA
SCRUBBER
• LOW BTU GAS
Figure 2-1. Simplified Block Flow Diagram for Exxon Donor Solvent Process - Base Case
-------
steam and air are added to produce additional distillate liquid products and
a low Btu fuel gas for process furnaces. The vacuum bottoms are the organic-
and ash-containing heavy residues remaining after rigorous vacuum distillation
has removed essentially all of the desired liquid products. In the Flexicok-
ing unit, essentially all organic material in the vacuum bottoms is recovered
as liquid products or fuel gas. A small amount of residual carbon is rejected
with the ash.
There are several major types of emissions from an uncontrolled EDS plant.
These include acid gases, fugitive emissions, inorganic- and organic-laden
wastewaters, and inorganic- and organic-based solid wastes. The acid gases
are generated by acid gas removal systems (DEA) in the liquid distillation
area and the Flexicoking and hydrogen generation area, and by steam stripping
of sour water. These streams contain high concentrations of reduced sulfur
and nitrogen species such as H^S and NH3. Fugitive emissions include parti-
culate emissions resulting from coal storage and handling, and organics from
leaks, product storage and material handling. Inorganic- and organic-laden
wastewaters include process wastewaters and plant area runoff; process waste-
waters result from unreacted steam used in liquefaction, from oxygen or mois-
ture in the coal, and from water added to dissolved output slurry in order to
prevent salt deposition. Many of these wastewater streams contain high concen-
trations of phenols and ammonia. Inorganic-based solid wastes include ash
generated in the Flexicoking area and spent catalysts generated in various
operations such as hydrotreating and sulfur recovery. Organic-based solid
waste consists primarily of sludges from treatment of wastewater. In general,
the characteristics of waste streams generated from the EDS process are simi-
lar to those generated from other direct liquefaction processes, in that the
same major components are typically found in corresponding waste streams. The
differences between EDS waste streams and other waste streams are primarily
in waste generation rates, in concentration levels of major components, and
in types and concentration levels of minor and trace components.
2.1.2 Market Flexibility Sensitivity (MFS) Case
Figure 2-2 is a simplified block flow diagram for the EDS plant based on
the MFS case design. The major difference between the base case and the MFS
case design is the approach used for the production of hydrogen. In the MFS
plant, hydrogen is produced by partial oxidation of about 50% of the vacuum
19
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SOLVENT
COAL
PREPARATION
COAL
H2
1
SOLVENT
HYDRO-
GENATION
SLURRY
DRIER
SLURRY
PREHEAT
FURNACE
SLURRY
LIQUEFACTION
SPENT
DONOR
SOLVENT
GAS
DISTILLATION
VACUUM
BOTTOM
SLURRY
•50%
FLEXICOKING
LIQUID
' PRODUCTS
DEA
SCRUBBER
LOW BTU GAS
•50%
PARTIAL
OXIDATION
ACID GAS
REMOVAL
H2TO
LIQUEFACTION
' AND SOLVENT
HYDROGENATION
Figure 2-2. Simplified Bfock Flow Diagram for Exxon Donor Solvent Process MFS Case
-------
bottoms instead of by steam reforming of light hydrocarbon gases as in the
base case. The remaining 50% of the vacuum bottoms are fed to a Flexicoking
unit to produce low Btu gas for plant fuel and additional liquid products.
The light hydrocarbon gases recovered by eliminating the steam reforming step
are sold as pipeline gas after undergoing further treatment. Total gaseous
and liquid products from the Exxon commercial MFS design amount to 71,080
barrels fuel oil equivalent per stream day, for the same coal feed rate to
the liquefaction section as in the base case design. Thus, the differences
in the methods for processing vacuum bottoms between the base case and MFS
case designs result in significant differences in the quantity of net products
generated, and hence the overall thermal efficiency of an EDS plant.
There are some differences between the waste streams generated from the
EDS base case and MFS case designs, but primarily only in the section that
processes the vacuum bottoms. For example, waste streams from the Flexicoking
operation in the MFS case are generated at approximately half the rate as
corresponding waste streams in the base case design, because only 50% of the
vacuum bottoms are fed to Flexicoking in the MFS case. Also, there are waste
streams generated from partial oxidation of vacuum bottoms in the MFS case but
not in the base case, and waste streams generated from steam reforming of light
hydrocarbon gases in the base case but not in the MFS case.
2.1.3 Bottoms Recycle Case
Exxon's bottoms recycle design incorporates reycle of some vacuum bottoms
and all vacuum gas oil, as well as hydrogenated donor solvent to the liquefac-
tion reactor. The vacuum gas oil and vacuum bottoms recycle is intended to
give these heavy materials longer residence time in the liquefaction reactor
in order to convert them to lighter liquids, and reduce the production of heavy
materials. The vacuum gas oil is a sidestream recovered from the vacuum dis-
tillation column, and the vacuum bottoms are the heavy residues obtained from
the same column. This column is designed to recover liquid products from the
higher boiling fractions of the coal liquefaction product. Distillation is
carried out at low pressures because the boiling temperature decreases with a
lowering of pressure. As discussed previously, the bottoms recycle case is
covered only briefly in the PCTM.
21
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2.2 EFFECTS OF MAJOR VARIABLES ON DISCHARGES/CONTROLS
An EDS plant is a very complex, integrated facility. There are many
variables that affect the emissions from the plant and the approach in con-
trolling emissions. The changes in emissions, of course, could also impact
the cost and performance of applicable control technologies. The following
provides some brief discussion on some of the major variables.
2.2.1 Effect of Coal Type
A wide range of coals, including bituminous, subbituminous, and lignite,
have been liquified using the EDS process. In general, higher rank coal pro-
duces more liquid and provides a better service factor (operability) than lower
rank coal. Without recycle of bottom products, bituminous coals studied were
found to produce 39-46% liquid products, subbituminous coals about 38% liquid
products, and the lignite about 36% liquid products (4). These liquid yields
are given as weight percent of coal feed on a dry, ash-free basis.
The coal feedstock selected for examination in both the base case and the
MFS case designs is an Illinois No. 6 coal, which is a high sulfur bituminous
coal. This coal was selected because it is the design coal for the 1975/1976
EDS commercial plant study design (3), and subsequent updates of the EDS com-
mercial plant study design (5-8). Illinois No. 6 coal has also been extensive-
ly tested by Exxon Research and Engineering Company (ER&E) in the laboratory,
and a considerable amount of process and waste stream characterization data
are available. Data on the composition of the Illinois No. 6 coal considered
in the PCTM are presented in Table 2-1. This representative composition of
an Illinois coal is that which was used by Exxon in their conceptual design,
and is that on which the flows/material balances in this PCTM are based. In
Table 2-2, data on the trace element contents of the Illinois No. 6 coal are
presented.
Using a different type of coal will affect emissions in all three media
(air, water and solid). The major factors which can influence the flow rates
and characteristics of waste streams, and therefore the selection, costs and
performance of control techniques, are discussed as follows.
22
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TABLE 2-1. CHARACTERISTICS OF EDS COAL FEEDSTOCK: REPRESENTATIVE
ILLINOIS NO. 6 COAL CONSIDERED IN PCTM
Coal Composition
C
H
0 (By difference)
N
Pyritic
S Sulfate
Organic
Cl
Ash
Water
TOTAL
Ash Composition
P2°5
Si°2
Fe2°3
A12°3
CaO
MgO
so3
Na20
TOTAL
Dry
Wt %
69.9
5.2
10.1
1.2
1.2
0.1
3.1
0.1
9.1
-
100.0
Dry
1.08
51.64
19.37
18.17
.87
3.15
1.23
1.57
2.19
1.07
100.34
"As Received"
Wt %
58.2
4.3
8.4
1.0
1.0
0.1
2.6
0.1
7.6
16.7
100.0
Wt %
S03 Free
1.10
52.29
19.61
18.40
.89
3.19
1.24
2.22
1.08
100.02
Data source: Reference (7).
23
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TABLE 2-2. TRACE ELEMENT CONCENTRATIONS OF REPRESENTATIVE
ILLINOIS NO. 6 COAL CONSIDERED IN PCTM
Trace
Element
Al
As
B
Ba
Be
Br
Ca
Cd
Ce
Cl
Co
Cr
Cs
Cu
Eu
F
Fe
Ga
Ge
Hf
Hg
K
La
Wt %
of Ash
9.74
0.0050
0.114
0.0936
0.0013
0.0126
2.28
0.0034
0.0110
1.35
0.0056
0.0169
0.0010
0.0110
0.0002
0.0531
13.7
0.0026
0.0047
0.0004
0.0002
1.84
0.0059
Trace
Element
Mg
Mn
Mo
Na
Ni
P
Pb
Rb
Sb
Sc
Se
Si
Sm
Sn
Sr
Ta
Th
Ti
Tl
U
V
Zn
Zr
Wt %
of Ash
0.748
0.0447
0.0078
0.801
0.0185
0.480
0.0228
0.0135
0.0008
0.0022
0.0019
24.4
0.0010
0.0040
0.0304
0.0001
0.0019
0.534
0.0006
0.0013
0.0278
0.354
0.0438
Data source: Values for Al, Ca, Fe, K, Mg, Na, P, Si, and Ti are based on
ER&E EDS commercial plant design data (7). Values for other trace
elements were from Illinois No. 6 coal analysis determined by Gluskoter, et
al. ( 9.).
24
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Coal Sulfur. The sulfur in the coal feedstock will eventually end up in
acid gas streams, ash or products. The relative distribution of the sulfur in
these streams is affected by the reactivity of the coal, product slate, opera-
ting conditions of the various units (such as the liquefaction reactor and
distillation column) and other design features of the plant (such as process
selection for handling vacuum bottoms). There are insufficient data to predict
the exact distribution of sulfur in these streams. However, it is reasonable
to assume the bulk of the sulfur will appear in the acid gases, i.e., higher
sulfur coal will have higher levels of h^S and other sulfur species in the
acid gas streams.
Coal Moisture. As discussed earlier, the coal-solvent slurry feed to the
liquefaction reactor is pre-dried to 4% moisture on dried coal basis. Thus,
coals with higher moisture content (lower rank coals) will generate larger
quantities of wastewater from the slurry drier area.
Coal Ash. Coal ash will eventually end up as ash from Flexicoking opera-
tion or bottom partial oxidation (gasification) operation, which is the major
solid waste stream from an EDS facility. Thus, higher ash coal will require
larger solid waste disposal/management capacity. However, Teachabilities of
various pollutants (especially trace metals) from Flexicoking or gasifier ash
may be highly coal specific and not be easily predictable.
Coal Reactivity. It is known that coal reactivity depends on the solvent,
the operating conditions of the liquefaction reactor, and the composition and
rank of the coal. Coal reactivity will affect the distribution and composition
of liquid and gaseous products, as well as the generation rate and composition
of various waste streams. For example, lower reactivity results in the genera-
tion of larger quantities of vacuum bottoms (containing higher proportions of
unreacted coal), and therefore higher generation rates for waste streams from
processing of vacuum bottoms (e.g., by Flexicoking). Also, the differences in
coal reactivity could result in the presence of different high molecular weight
organics in gaseous waste streams, wastewater streams, solid waste streams
such as sludges, and fugitive organic emissions. These high molecular weight
organics could be refractory in nature, difficult to destroy in flares and
incinerators, and resistant to wastewater treatment. There are, however, no
25
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publicly available data to indicate the effects of coal reactivity on waste
streams.
2.2.2 Effects of EDS Plant Design
EDS is still an evolving process. Several designs have been considered
and some have been tested in the EDS pilot scale unit. The two configurations
considered in this manual, the base case and the MFS case are the most advanced
in development. The major difference between these two designs is the method
of hydrogen production. The effect of this on the waste streams is briefly
discussed below. A more detailed discussion, which includes tables summarizing
the stream characteristics of the two designs, will be presented in Section 3.
In addition to the base and MFS case, Exxon Research and Engineering has re-
cently completed a study on recycling some vacuum bottoms and vacuum gas oil
to generate more light liquid products (11). The potential impact of this is
also briefly discussed below.
Hydrogen Production
Both the base and MFS cases obtain a portion of the make-up hydrogen
requirement by cryogenic separation of gas streams from liquefaction, donor
solvent hydrogenation, product distillation, donor solvent fractional on, and
Flexicoking areas. However, the balance of the hydrogen requirement is gen-
erated by steam reforming for the base case, while the MFS case employs partial
oxidation of half of the vacuum-bottoms slurry.
Base case hydrogen generation involves steam reforming of light hydro-
carbon gases, shift conversion of carbon monoxide and steam to carbon dioxide
and hydrogen, carbon dioxide removal and removal of residual carbon oxides
and nitrogen. Feed streams to the reformer are the CZ hydrocarbons from cryo-
genic hydrogen recovery, and the C-j and C2 hydrocarbons from light ends reco-
very. Hydrogen production for the MFS case involves syngas generation in the
partial oxidation step, shift conversion of the syngas, acid gas removal and
compression. Approximately half of the vacuum-bottoms slurry produced in the
liquefaction/distillation units will be processed via partial oxidation into
hydrogen while the balance will be processed through Flexicoking to produce
additional liquid and gas products.
26
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There are several differences between the waste streams generated from
hydrogen production in the base case and MFS cases. First, since only approxi-
mately half of the vacuum-bottoms slurry will be processed by Flexicoking in
the MFS case, waste streams from Flexicoking in this case will only be gener-
ated at approximately half the rate as in the base case. Second, there are
three major waste streams in the MFS case that are not present in the base
case, due to the addition of the partial oxidation unit. These are ash from
partial oxidation process, acid gas from AGR system in the partial oxidation
area, and gasifier process condensate from the partial oxidation area. The
acid gas stream from partial oxidation is different from acid gas streams
generated from other process areas, in that the H2S/C02 ratio of this stream
is relatively low and might necessitate the application of different control
techniques. This is because in partial oxidation, the C02 resulting from the
shift conversion is removed simultaneously with the H^S from partial oxidation.
Also, the partial oxidation (gasification) process included in the design
operates at a high temperature M670°K) (12). Thus, the process condensate
is low in organics compared to most other EDS wastewater streams. The gasi-
fier ash is essentially composed of uncombustible, inert material from coal (12),
The combined gasifier ash and Flexicoking ash from the MFS case design is,
therefore, similar in properties and generation rate to the Flexicoking ash
from the base case design.
Recycle of Vacuum Gas Oil
The EDS Bottom Recycle Study Design (11) recently completed by the Exxon
Research and Engineering Company involves recycle of the vacuum gas oil from
the vacuum distillation column back to the liquefaction reactor. This mode of
operation increases the production of light end products (12), and will likely
affect the process wastewaters and gaseous waste streams generated.
Compared to the MFS and base case designs, the Bottom Recycle design
requires more severe operating conditions in various units. For example,
slurry drier temperature and residence time is increased from 408°K (275°F)
and 40 minutes to 422°K (300°F) and 55 minutes, respectively; the hydrogen
partial pressure at the reactor inlet is increased from 8.4 MPa (1200 psig) to
27
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11.4 MPa (1640 psig); and the liquefaction pressure is increased from 13.9 MPa
(2000 psig) to 17.3 MPa (2500 psig). These changes in operating conditions
will likely affect the amount of reaction water generated, the quantity and
nature of organics and NH3 in the wastewater stream, and the H?S distribution
in the various gaseous streams. Flexicoking is eliminated as a means for pro-
cessing vacuum bottoms, thereby altering the identity and composition of streams
from bottom processing. There are no data publicly available on the character-
istics of any of the waste streams generated in the Bottoms Recycle design.
2.2.3 Effects of Product Slate
The exact product slate from an EDS plant is dependent upon the process
design configuration, the reactivity of coal, and the process operation condi-
tions. Table 2-3 presents the net product slate for the base and MFS cases,
assuming 27.2 Gg (30,000 tons) per stream day of coal feed on an "as received"
basis, and excluding coal being used in steam and power boilers. As discussed
before, the base case is designed to produce a maximum amount of C, liquids;
the C~~ hydrocarbon gas is steam reformed to generate plant hydrogen. In the
MFS case, hydrogen is produced via gasification of a portion of the vacuum
bottoms; this allows the C.," hydrocarbon gas produced within the plant to be
sold as an additional product.
As will be apparent from the comparison of the base and MFS streams/com-
positions in Section 3, the changes in design and operating conditions that
effect a change in product slate can cause some variations in the compositions
of some streams, and can sometimes result in the appearance of different streams
in different designs. However, these differences are generally relatively
minor; similar types of streams with similar general compositions will normally
be present.
2.3 CAPITAL AND OPERATING COSTS FOR UNCONTROLLED EDS PLANTS
In order to assess the relative impact of the costs of pollution control
on overall plant cost, baseline costs for "uncontrolled" plants were developed.
Both capital and operating costs for uncontrolled EDS plants were estimated.
The total facility cost (total process cost) is the sum of: installed equip-
ment cost (IEC), contractor's overhead and fee (3% of IEC),, engineering and
construction (25% of IEC), and contingency (20% of IEC). The total depreciable
28
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TABLE 2-3. NET PRODUCT SLATES FOR EDS COMMERCIAL PLANT (STREAM DAY BASIS)
Net Product Base Case MFS Case
Pipeline Gas -- 1.731 Gg (11,900 BFOE)
C3 LPG 0.236 Gg (1,780 BFOE)* 0.334 Gg (2,570 BFOE)
C4 LPG 0.227 Gg (1,680 BFOE) 0.235 Gg (1,740 BFOE)
Naphtha 2.880 Gg (20,100 BFOE) 2.824 Gg (19,710 BFOE)
Fuel Oil 6.033 Gg (36,680 BFOE) 5.788 Gg (35,160 BFOE)
Total 9.376 Gg (60,240 BFOE) 10.912 Gg (71,080 BFOE)
By-products
Sulfur 0.885 Gg 0.907 Gg
Ammonia 0.159 Gg 0.089 Gg
Crude Phenols 0.059 Gg (55 m3) 0.059 Gg (55 m3)
*1 barrel fuel oil equivalent (BFOE) = 6,050,000 Btu (LHV).
Data source: Reference 13.
Basis: 27.2 Gg (30,000 tons) coal per stream day conceptual commercial
design prepared by Exxon.
Product Property Basis
Pipeline Gas 63.0 vol % methane, 22.3 vol % C2, 2.7 vol % C3+ hydro-
carbons, 5.4 vol % N2, 3.4 vol % H2, and 3.2 vol % CO.
Lower heating value of 40.3 MJ/Nm3 (1,024 Btu/SCF).
Cs LPG 95.8 wt % C3, 0.9 wt % C2~, 3.3 wt % C4+.
C4 LPG 95.1 wt % C4, 3.2 wt % C3-, 1.7 wt % C5+.
Naphtha Petanes to 350°F normal boiling range; contains 0.43 wt %
sulfur and 0.06 wt % nitrogen.
Uses: Downstream processing (hydrotreating) required prior
to use as gasoline feedstock or in aromatics production.
Fuel Oil 19.0 wt % C5/400°F, 34.0 wt % 400/700°F, 29.1 wt % 700/1000°F,
(Base Case) and 17.9 wt % 1000°F+; contains 0.54 wt % sulfur and 0.77
wt % nitrogen.
Uses: Low sulfur fuel oil, refine into stationary turbine
fuel, others.
Fuel Oil 19.2 wt % C5/400°F, 35.2 wt % 400/700°F, 31.6 wt % 700/1000°F,
(MFS Case) and 14.0 wt % 1000°F+; contains 0.51 wt % sulfur and 0.75
wt % nitrogen.
Uses: As base case fuel oil above.
29
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investment (TDI) is the sum of total facility cost and interest during con-
struction (22.56% of total facility cost). The total capital investment is
the sum of total depreciable investment and working capital. Startup costs
and land costs are not included. Working capital is assumed to be equivalent
to 60 days of inventory of coal and catalysts and chemicals; there is no
separate allowance for product inventory and accounts receivable. The operat-
cost is the sum of: coal cost, cost of catalysts and chemicals, operating labor
cost ($11.00 per hour), operating supervision cost (15% of total operating labor),
maintenance cost (2% of capital investment), maintenance supervision cost (5%
of maintenance cost), laboratory charges (5% of operating labor), plant general
overhead (50% of operating labor), plant G&A overhead (15% of total labor plus
maintenance), and contingency (20% of total direct and indirect costs, exclud-
ing the cost of coal). The annualized cost is the sum of annual operating cost
and capital charges (17.2% of total depreciable investment). The cost methodo-
logy used is discussed in greater detail in Section 4.1.3.
2.3.1 Base Case
The installed cost of the uncontrolled plant was estimated by cost data
supplied by Exxon. In Table 1-IV-ll of Reference 13, Exxon estimated an in-
stalled cost of $1538 million for a plant corresponding to the Illinois coal
base case design, with 27.2 Gg (30,000 tons) of "as received" coal feed per
stream day and using 4th quarter of 1978 as the cost basis. Included in the
plant cost (installed equipment cost) were: $15.9 million for sulfur plant and
sulfur plant tail gas cleanup unit, $7.9 million for sour water treating and
ammonia recovery, $10.2 million for phenol extraction, $40.1 million for waste-
water treatment, $17.0 million for handling of waste solids from the steam
boiler (ash and FGD sludge), and $5.2 million for waste solids disposal land-
fill. The sum of the pollution control cost of $96.3 million was subtracted
from the plant cost to obtain an estimated uncontrolled plant cost of $1441.7
million. Acid gas removal and cooling water facilities were considered to be
process related functions and included in the uncontrolled plant cost. The
plant cost also included all off-site facilities except the coal-fired power
plant, as Exxon assumed power for plant use will be purchased. After adjust-
ment for inflation, the uncontrolled plant installed cost was estimated to be
$1640 million on 1980 basis.
30
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As shown in Table 2-4, the total capital investment for the uncontrolled
EDS base case plant - starting with the $1640 million installed cost, and
adding other factors listed above - is $3190 million. Also added to the capi-
tal investment cost is the cost of a 268 MW coal-fired power plant, costed at
$500/kW. This is in contrast to the original Exxon commercial design, in that
the design/costs in the PCTM assume that plant power is generated on site
rather than being purchased. The size of the power plant is based on the
operating power requirement of 223 MW plus 20% for contingency. Working capi-
tal is based on the dollar equivalent of 60 days of coal (1,846 Gg*), and cata-
lysts and chemicals at the plant.
Annualized operating costs for the uncontrolled EDS base case plant, as
presented in Table 2-5, were based on a 0.9 plant stream factor. The amount
of coal consumed is the sum of coal feed to the liquefaction section (1134
Mg/hr), the power plant (112 Mg/hr), and the steam boiler (35.3 Mg/hr). An-
nualized cost for coal was computed on the basis of $1.14/GJ ($1,20/MM Btu).
Cost for catalysts and chemicals was estimated to be $12 million/year (3rd
quarter 1978, 0.85 plant steam factor) by Exxon (13). This cost was adjusted
to $13 million by correction for inflation, a higher plant stream factor of
0.9, and allowance for catalysts and chemicals used for pollution control
(assumed to be 6%, the same factor used in deriving the uncontrolled plant
cost). The operating labor requirement of 580 personnel was estimated using
figures provided in the same 1981 Exxon report. Operating labor cost was cal-
culated at $11.00/manhour. The remaining annualized operating costs presented
in Table 2-5 were estimated by using factored methods. For example, mainte-
nance cost was assumed to be 2% of capital investment, laboratory charges were
assumed to be 5% of operating labor, etc. The factors used are described ear-
lier in this section. The total annualized cost of $960 million is equivalent
to $305/m3 ($48.5/bbl), based on a production rate of 9,580 m3 (60,240 bbl)
fuel oil equivalent of C3 hydrocarbon liquids per stream day.
* All coal feed rates are given on "as received" basis, unless otherwise
stated.
31
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TABLE 2-4. CAPITAL COSTS FOR UNCONTROLLED EDS
BASE CASE DESIGN COMMERCIAL PLANT
Item Cost (Dollars)
Installed Equipment Cost 1,640.0 x 10^
Contractors Overhead and Fee 49.2
Engineering and Construction 410.0
Contingency 328.0
2,427.2 x 106
Coal-Fired Power Plant 134.0 ,
Subtotal, Facility Cost 2,561.2 x 106
Interest During Construction 577.8
Total Depreciable Investment (TDI) 3,139.0 x 106
Working Capital 52.8
Total Capital Investment 3,190 x 106~
Cost basis: 1980 dollars.
32
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TABLE 2-5. ANNUALIZED COSTS FOR UNCONTROLLED EDS
BASE CASE DESIGN COMMERCIAL PLANT
Item Annualized Cost, ($10 )
Coal 276.29
Raw water 0.01
Catalysts and Chemicals 13.00
Operating Labor 13.27
Supervision 1 .99
Maintenance Labor and Material 63.79
Maintenance Supervision 3.19
Plant Overhead 6.64
Plant G&A 12.34
Laboratory Charges 0.66
Contingency 22.98
Total, Operating Cost 414.16
Capital Charges
(0.172 of TDI) 539.91
Total Annual 1 zed Cost 960
33
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2.3.2 MFS Case
The total erected cost of the MFS plant was estimated by Exxon to be
91.84% of the total erected cost of the base case plant (13). Using 4th quar-
ter of 1978 as the cost basis, an installed cost of $1412.5 million was esti-
mated for an MFS plant processing 27.2 Gg (30,000 tons) of "as received"
Illinois coal per stream day. In Table 2-1-1 of Reference 13, Exxon estimated
the same pollution control cost for the base case and MFS case designs, within
1 to 2 percent. Therefore, the sum of the pollution control cost of $96.3
million was subtracted from the plant cost to obtain an estimated uncontrolled
plant cost of $1316.2 million. As in the base case, this plant cost included
all off-site facilities except the coal-fired power plant, as Exxon assumed
power for plant use will be purchased. After adjustment for inflation, the
uncontrolled plant cost was estimated to be $1497.4 million on 1980 basis.
As shown in Table 2-6, the capital investment for the uncontrolled EDS MFS
plant is $2890 million. The lower capital investment cost for the MFS design
is the result of the lower physical plant cost and the smaller power plant
(192 MW) requirement. The size of the power plant is based on the operating
power requirement of 160 MW plus 20% for contingency.
Annualized operating costs for the uncontrolled EDS MFS plant are pre-
sented in Table 2-7. In the MFS design, the amount of coal consumed is 1134
Mg/hr for the liquefaction section, 68.7 Mg/hr for the power plant, and 92.8
Mg/hr for the steam boiler. Cost for catalysts and chemicals was estimated to
be $10.8 million/year by Exxon (13). This cost was adjusted accordingly as in
the base case. Operating labor requirement for the MFS case design was assumed
to be the same as for the base case design (13). The remaining annualized costs
presented in Table 2-7 were estimated by using factored methods described
earlier. The total annualized cost for the MFS plant is $910 million. This
o
is equivalent to a unit cost of $242/m ($38.5 bbl), based on a production
rate of 11,300 m3 (71,080 bbl) fuel oil equivalent per stream day of C3+ hydro-
carbon liquids and C-/C pipeline gas.
34
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TABLE 2-6. CAPITAL COSTS FOR UNCONTROLLED EDS
MFS CASE DESIGN COMMERCIAL PLANT
Item Cost (Dollars)
Installed Equipment Cost 1,497.4 x 106
Contractors Overhead and Fee 44.9
Engineering and Construction 374.4
Contingency 299.5
35
2,216.2 x 106
Coal-Fired Power Plant 96.0
Subtotal, Facility Cost 2,312.2 x 106
Interest During Construction 521.6
Total Depreciable Investment (TDI) 2,833.8 x 106
Working Capital 53.8
Total Capital Investment 2,890 x 10
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TABLE 2-7. ANNUALIZED COSTS FOR UNCONTROLLED EDS
COMMERCIAL PLANT
Item Annualized Cost ($106)
Coal 282.89
Raw Water 0.01
Catalysts and Chemicals 11.63
Operating Labor 13.27
Supervision 1.99
Maintenance Labor and Material 57.71
Maintenance Supervision 2.89
Plant Overhead 6.64
Plant G&A 11.38
Laboratory Charges 0.66
Contingency 21.23
Total, Operating Cost 410.30
Capital Charges
(0.172 of TDI) 487.41
Total Annualized Cost 900
36
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3. DETAILED PROCESS DESCRIPTION AND
WASTE STREAM CHARACTERIZATION
In this section, the process and auxiliary operations associated with the
Exxon Donor Solvent (EDS) process and the characteristics of uncontrolled waste
streams resulting from these operations are described. The material presented
in Section 3 is used in evaluating pollution control options in Section 4.
Throughout Section 3, the flow rates of waste streams and process streams
presented correspond to an EDS commercial plant processing 1,134 Mg/hr (30,000
tons per stream day) of "as received" Illinois No. 6 coal in the liquefaction
•3
area. This EDS plant produces about 9,580 m (60,240 barrels) fuel oil equiva-
o
lent* per stream day of liquid products for the base case design, or 11,300 m
(71,080 barrels) fuel oil equivalent per stream day of liquid and gas products
for the Market Flexibility Sensitivity (MFS) design. The stream compositions
presented throughout Section 3 represent the specific design/operating condi-
tions reflected in the base and MFS designs. These compositions could vary in
practice due to uncertainty in the estimates, and due to the variations in coal
type and plant design/operating conditions. The commercial plant configura-
tions, and the stream flows and compositions are based largely upon conceptual
designs prepared by Exxon.
To facilitate the discussion, a detailed description of the overall EDS
process is first presented in Section 3.1. This is followed in Section 3.2
by listings of waste streams and selected process streams for the base case
and Market Flexibility Sensitivity (MFS) case designs, the two designs con-
sidered in detail in this document. In Section 3.3, detailed descriptions of
discharge sources and uncontrolled discharge streams are provided by process
area. For discussion purposes, the process operations covered are divided into:
1 barrel fuel oil equivalent (BFOE) = 6,050,000 Btu (LHV)
37
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coal preparation, coal liquefaction, product separation and purification, and
processing of liquefaction residue/hydrogen production plant. Auxiliary opera-
tions covered are divided into: raw water treatment, steam and power generation,
cooling system, oxygen production, and product/by-product storage. Product
streams and fugitive emissions are covered in individual subsections. In
Section 3.4, characteristics of uncontrolled discharges and product streams are
summarized in tabular form by medium and by process area. Finally, cross-
references are provided in Section 3.5 for ready reference of applicable con-
trol technologies described in Section 4 and the Appendix to waste streams
described in Section 3.
As discussed in Section 1, the "uncontrolled discharge streams" discussed
in the manual are waste streams prior to the application of any controls. As
such, these streams are generally not true discharge streams, since, in a com-
mercial EDS facility, control techniques would normally be applied.
3.1 DETAILED DESCRIPTION OF OVERALL EDS PROCESS
The Exxon Donor Solvent (EDS) is a noncatalytic process that liquefies
coal by reacting the coal with hydrogen in a medium of a hydrogen donor solvent
obtained from coal-derived distillates. The donor solvent assists in the trans-
fer of hydrogen to the coal, maximizes the yield of desired liquid products and
prevents the conversion of the reaction coal into char and asphalt-like mater-
ials. Two process configurations, based on Exxon's Study Design Update com-
pleted in 1981, are described in this manual. These two process configurations
are referred to as the base case design and the Market Flexibility Sensitivity
(MFS) design (5,7,13). The method for hydrogen production is the major differ-
ence between these two designs. In the base case, hydrogen for the liquefaction
reaction is produced by steam reforming of light hydrocarbon gases generated in
the plant. In the MFS design, the hydrogen is produced by partial oxidation
of about 50 percent of the vacuum bottoms, the heavy residual material remain-
ing after vacuum distillation of liquefaction products has removed all of the
desired liquids. Hence, the light hydrocarbon gases made available by elimi-
nation of steam reforming can be sold as pipeline gas.
38
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Because of the differences in design, the overall average energy efficiency*
is 56% for the base case compared with 63% for the MFS case, when Illinois No,
6 is used as the feed coal (13).
More recently, Exxon has completed the preliminary conceptual design of
an EDS plant feeding Wyoming subbituminous coal with recycle of all vacuum
gas oil (VGO) and of some vacuum bottoms (11). In this design, the VGO - the
heaviest liquid produced from the plant, above vacuum bottoms - is recycled
to the liquefaction reactor in order to convert it to lighter products. This
Bottoms Recycle Study design is not addressed in detail in the PCTM because:
1) the level of design detail for this design is less than that of the base
case and MFS case designs; and 2) waste stream characterization and pollution
control evaluation studies for the EDS process were completed before informa-
tion on this particular design became available. However, the primary dif-
ferences between this design and the base case and MFS case designs are ad-
dressed briefly in Section 3.1.3.
3.1.1 Base Case
The base case configuration for the EDS process, designed to maximize
the production of C. liquids, is shown schematically in Figure 3-1. The
major process areas include: coal preparation, coal liquefaction, product
separation and purification, and liquefaction residue processing/hydrogen pro-
duction. Auxiliary operations shown include raw water treatment, steam gener-
ation, power generation, cooling system, and product/by-product storage. Pol-
lution control operations such as sulfur recovery, ammonia recovery, phenol
extraction, and wastewater treatment are also included in the block flow dia-
gram to indicate the flows of waste streams into various treatment areas.
* Energy efficiency = „ + c
where A = heating value of net products + by-products
B = heating value of process coal + off-site coal
C = heating value of fossil fuel to generate required electric
power
39
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PRODUCT SEPARATION AND PURIFICATION PROCESS AREA
RECYCLE OONOH SOLVENT
* POLLUTION CONTROI OPERATIONS PROCESS AREA
11111 ill ^T
© © © © © © © © .Li
T T J T © J ] J i
«NT SKNT ] »€NT SMWT |
HYOBOTBEATTR [ HEKtmCR » MFmAHATIOIt I AMMONIA i
CATALYST | CATALYST | WASTEWATEfl CATALYST | SYNTHESIS1
Figure 3-1. Block flow diagram for EDS commercial plant - base case
-------
In the coal preparation area, cleaned coal from the mines is transferred
for storage in stockpiles. The cleaned coal is then reduced from 90% minus
25 mm (1 inch) to minus 8 mesh (2.4 mm) in impact-mill crushers, and fed via
enclosed belt conveyors to the slurry drier.
The coal liquefaction area consists of the slurry drier, the liquefaction
reactor, and raw product separation operations. In the slurry drier, the
crushed coal is mixed with recycle donor solvent. The slurry is then heated
by a preheat furnace, and preheated hydrogen is added. The slurry and the
hydrogen are then fed to a liquefaction reactor operated at 700-750°K (800-
900°F) and 13.9 MPa (2000 psia). In the liquefaction reactor, the polymeric
coal molecules are broken down into smaller, lighter molecules through the
solvent-aided addition of hydrogen. Most of the organically-bound sulfur is
converted to H?S, which then appears in various process streams. Products
from the liquefaction reactor are separated in raw product separation into a
gas stream and a liquid/solids stream. The gas stream is further cooled to
condense vaporized hydrocarbon liquids, and scrubbed with diethanolamine (DEA)
for hydrogen sulfide and carbon dioxide removal. This treated hydrogen-rich
gas stream is then compressed for recycle to the liquefaction reactor with
make-up hydrogen.
In the product separation and purification area, the liquid/solids stream
and the hydrocarbon condensate recovered from the gas stream in raw product
separation are fed first to atmospheric and then vacuum fractionators to separ-
ate the liquefaction products. Recovered naphtha is sent to light ends pro-
cessing (product recovery) for stabilization. Vacuum gas oil product is re-
moved as the bottom sidestream of the vacuum fractionator and sent to product
storage. The distillates heavier than naphtha but lighter than VGO - consist-
ing of atmospheric and vacuum fractionator sidestreams - are sent to solvent
hydrogenation in order to recover the spent solvent and to recover additional
liquid products. Hydrogen is catalytically added to the spent solvent before
it is recycled to the slurry drier in the liquefaction area, in order to re-
store its hydrogen - donating ability; this solvent hydrogenation step is a dis-
tinguishing feature of the EDS technology. In solvent hydrogenation, the spent
solvent distillate is hydrotreated in a fixed-bed catalytic reactor operating
at about 12.3 MPa (1785 psia). Effluent from the solvent hydrogenation reactor
41
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is cooled and separated into a hydrogen-rich gas and a hydrotreated liquid
stream. The gas is scrubbed with DEA, and along with make-up hydrogen, is
recycled to the solvent hydrogenation unit. The hydrotreated liquid is fed
to the solvent fractionator to recover the hydrogen donor solvent, a hydro-
treated low-sulfur fuel oil (LSFO) product, and a naphtha stream.
In the liquefaction residue processing/hydrogen plant area, the heavy
bottoms from the vacuum distillation are fed to a Flexicoking* unit with air
and steam to produce additional distillate liquid products, a low-Btu fuel gas
for process furnaces, and light gases for hydrogen production. Inorganically-
bound sulfur largely remains in the vacuum bottoms throughout the liquefaction
and product separation steps, and is released as HLS when the vacuum bottoms
are processed in the Flexicoker. The light gases from the Flexicoking unit,
in combination with the atmospheric and solvent fractionator off-gases, are
scrubbed with DEA and sent to cryogenic hydrogen recovery. The cryogenic
hydrogen recovery section separates the high pressure hydrogen purge gases
from liquefaction and solvent hydrogenation and the low pressure sweet gas
from the DEA absorber for recovery of hydrogen, C-|/C2, and C3 . The C,/C2
hydrocarbon gases from cryogenic hydrogen recovery, along with Ci/C2 hydro-
carbon gases from the product recovery section, are then fed to a steam re-
former. This is followed by shift conversion and carbon dioxide removal to
produce process hydrogen. The hydrogen product is blended with the hydrogen
from the cryogenic recovery section, treated for removal of trace carbon oxides
and nitrogen, and compressed for use as make-up hydrogen.
3.1.2 Market Flexibility Sensitivity Case
The NFS design for the EDS process is shown schematically in Figure 3-2.
As in the base case design, the MFS case also encompasses four major process
areas: coal preparation, coal liquefaction, product separation and purifica-
tion, and liquefaction residue processing/hydrogen production.
* "Flexicoking" is the service mark for a proprietary process developed by
Exxon.
42
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PRODUCT SEPARATION ANO PURIFICATION M*OCC» ARtA
AUXILIARY OPERATIONS PROCESS AREA
Figure 3-2. Block flow diagram for EDS commercial plant - MFS case
-------
There is no difference between the base case and MFS case designs in the
coal preparation and coal liquefaction areas. In product separation and pur-
ification, the atmospheric fractionator is followed by two parallel vacuum
fractionators of different designs in the MFS case. One vacuum fractionator
is designed with a bottoms cut point* of 768°K (920°F) for feed to the Flexi-
coking unit as in the base case. However, the second vacuum fractionator is
designed with a deeper bottoms cut point of 798°K (975°F) for feed to the
partial oxidation unit for hydrogen production.
The principal difference between the base case and MFS case designs is
the method for hydrogen production. In the MFS design, approximately 50 per-
cent of the vacuum bottoms (i.e., the bottoms product in the second vacuum
fractionator described above) are fed to the partial oxidation unit with steam
and oxygen. The raw synthesis gas produced is converted to hydrogen through
shift conversion and acid gas removal. The remaining 50 percent of the vacuum
bottoms (from the first vacuum fractionator) are fed to a Flexicoking unit to
produce distillate liquids, a low-Btu fuel gas, and light hydrocarbon gases.
Because steam reforming for hydrogen production is no longer required, the
light hydrocarbon gases from the Flexicoking unit and from the product separa-
tion area are recovered in the cryogenic hydrogen recovery section as a C-|/C2
high-Btu gas product. Hydrogen from the cryogenic hydrogen recovery section
is blended with the treated hydrogen from the partial oxidation section, com-
pressed, and used as make-up hydrogen for the liquefaction reaction.
3.1.3 Bottoms Recycle Case
The Bottoms Recycle case design (with Wyoming subbituminous coal) differs
from the base case and MFS case designs primarily in the following features:
• Recycle of some vacuum bottoms and all vacuum gas oil (VGO) as well
as donor solvent to the liquefaction reactor. The VGO and vacuum
bottoms recycle is intended to give these heavy materials longer
* Bottoms cut point - a temperature limit for the bottoms product; products
with boiling points above this temperature limit are obtained in the dis-
tillate bottoms.
44
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residence time in the liquefaction reactor, in order to convert
them to lighter liquids, and reduce production of heavy materials.
Only the donor solvent is recycled to the liquefaction reactor in
the Illinois coal base case and MFS case designs.
• Gasification of most of the remaining vacuum bottoms to produce plant
hydrogen.
• Firing of the last of the remaining solid vacuum bottoms in conjunc-
tion with additional coal, in a hybrid boiler to provide the necessary
process heat and plant steam. C2~ high-Btu gas is used to meet the
balance of fuel needs in the plant. Flexicoking units are eliminated.
• More severe operating requirements including: finer coal feed (-20
mesh); higher temperature (422°K) and longer residence time (55 min)
in the slurry drier; and higher pressure (17.3 MPa or 2500 psig)
longer residence time (60 min), and higher hydrogen partial pressure
(11.4 MPa or 1640 psig) in the liquefaction reactor.
As a result of thes design changes, the Bottoms Recycle Study design produces
no 850°F+ product, reduces the amount of C2~ for sale, and delivers a thermal
efficiency (with Wyoming coal) of 59%.
3.2 LIST OF UNCONTROLLED AND SECONDARY DISCHARGE STREAMS
A listing of the uncontrolled waste streams by process area and by medium
is provided in this section. Secondary discharge streams from pollution con-
trol operations are listed as a distinct subset. In addition, to facilitate
the tracking of material flows between processing operations, selected process
streams are also listed. Uncontrolled waste streams, as the name implies, are
waste streams generated by process operations with no pollution controls in
place. Secondary discharge streams, on the other hand, are waste streams gen-
erated as a result of pollution control. For example, the acid gas generated
from sour water stripping/ammonia recovery is a secondary discharge stream.
3.2.1 Base Case
A listing of the waste streams and selected process streams for the
Illinois coal base case design is presented in Table 3-1. Uncontrolled dis-
charge streams are listed by process area, and also by medium within each
process area. Selected process streams are listed by process area but not
by medium. Secondary discharge streams are listed under pollution control
operations area because uncontrolled discharge streams are often combined for
treatment in a separate plant area.
45
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TABLE 3-1 . LISTING OF WASTE STREAMS AND SELECTED
PROCESS STREAMS FOR THE EDS* ILLINOIS COAL
BASE CASE DESIGN
Coal Preparation Process Area
Uncontrolled Discharge Streams
Gaseous
Oil Fugitive dust from coal pile
013 Fugitive particulate from coal handling and crushing
Liquid
012 Coal pile runoff
Process Stream
010 Run-of-mine coal
Coal Liquefaction Process Area
Uncontrolled Discharge Streams
Gaseous
102 Slurry drier vent gas
107 Flue gas from liquefaction slurry preheat furnace
803 Transient gas from liquefaction reactor
Liquid
103 Slurry drier cold separator wastewater
106 Liquefaction cold separator wastewater
Solid
108 Solids accumulated in the slurry drier
Process Streams
101 Coal feed to slurry dryer
104 Liquefaction cold separator sour gas
Product Separation and Purification Process Area
Uncontrolled Discharge Streams
(Continued)
46
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TABLE 3-1. (Continued)
Gaseous
153 Vacuum fractionator off-gas*
203 Flue gas from solvent hydrogenation fuel preheat
furnaces
508 Acid gas from DEA regenerator
Li quid
152 Atmospheric fractionator overhead drum wastewater
155 Vacuum fractionator wastewater
202 Solvent hydrogenation cold separator wastewater
252 Solvent hydrogenation fractionator overhead drum
wastewater
Solid
204 Spent solvent hydrogenation catalyst
Process Streams
151 Atmospheric fractionator off-gas
159 Vacuum bottoms slurry to Flexicoking
200 Solvent hydrogenation cold separator vapor
251 Solvent hydrogenation fractionator sour gas
Liquefaction Residue Processing/Hydrogen Production Process Area
Uncontrolled Discharge Streams
Gaseous
304 Flexicoking gasifier/heater sour gas*
426 Vent gas from C02 removal
434 Flue gas from hydrogen plant reformer furnaces
438 Hydrogen Plant deaerator vent
446 Regeneration/decommissioning off-gas from reformer
catalyst
448 Decommissioning off-gas from methanation
catalyst
801 Transient gas from Flexicoking
(Continued)
* Will normally be desulfurized and burned within the plant as fuel gas.
47
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TABLE 3-1. (Continued)
Liquid
307 Flexicoking recontacting drum wastewater
308 Flexicoking fractionator overhead drum wastewater
312 Flexicoking heater overhead drum wastewater
403 Knockout drum wastewater in H£ cryo recovery
430 Slowdown and K.O. drum wastewater from hydrogen
generation
431 Catacarb overhead receiver wastewater in hydrogen
generation
451 Aqueous ammonia from ammonia synthesis
452 Knockout drum wastewater in ammonia synthesis
Solid
302 Flexicoking gasifier/heater dry fines
303 Flexicoking gasifier/heater wet fines
306 Flexicoking gasifier/heater bed coke
313 Flexicoking heater/reactor chunks/agglomerates
404 Spent hydrotreater catalyst in H2 cryo recovery
405 Spent drying agents in H? cryo recovery
433 Spent sulfur guard in hydrogen generation
435 Spent reformer catalyst in hydrogen generation
436 .Spent shift catalyst in hydrogen generation
439 Spent methanation catalyst in hydrogen generation
453 Spent drying agents in ammonia synthesis
454 Spent ammonia synthesis catalyst
Process Streams
310 Flexicoking fractionator off-gas
406 Sweet gas from DEA scrubbing
Auxiliary Operations Process Area
Uncontrolled Discharge Streams
Gaseous
701 a Flue gas from steam generation system
707a Flue gas from power generation system
731 Drift and evaporation from cooling tower
751 Evapbrative emissions from product and by-
product storage (Continued)
48
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TABLE 3-1. (Continued)
Liquid
702 Slowdown from steam generation system
708 Slowdown from power generation system
723 Regeneration wastes from water demoralization
732 Cooling tower blowdown
901 Low quality rain runoff
Solid
704 Bottom ash from steam generation system
710 Bottom ash from power generation system
722 Raw water treatment sludge
Pollution Control Operations Area
Secondary Discharge Streams
Gaseous
501 Acid gas from sour water stripping/ammonia recovery
510 Tail gas from sulfur plant
512 Off-gas from sulfur plant tail gas treatment unit
(prior to incineration)
514 Incinerator stack gas from sulfur plant tail gas
treatment unit
525 Flue gas from wastewater sludge incineration
527 Brine concentration off-gas
529 Activated carbon regeneration off-gases
540 Oxidizer vent gas from Stretford process
541 Oxidizer vent gas from Stretford unit in Beavon
Sulfur Removal Process (BSRP)
542 Incinerated vent gas from COp removal by Catacarb
process
543 Incinerated hydrogen plant deaerator vent
544 Incinerated regeneration/decommissioning off-gas
from reformer catalyst
545 Incinerated decommissioning off-gas from methanation
catalyst
701 Flue gas from steam generation system (discharge to
the atmosphere following controls)
707 Flue gas from power generation system (discharge to
the atmosphere following controls)
741 Flue gas from combustion of slurry drier vent gas
and vacuum flash off-gas
(Continued)
49
-------
TABLE 3-1. (Continued)
811 Controlled transient waste gas from Flexicoking
813 Controlled transient waste gas from liquefaction reactor
j
Liquid
502 Wastewater from ammonia recovery
504 Mastewater from phenolic extraction
515 Sour water from sulfur recovery plant
516 Sour water from sulfur plant tail gas treatment unit
519 Solution blowdown from sulfur plant tail gas treat-
ment unit
521 Effluent from wastewater treatment
522 Reclaimed water from reuse
706 Ash pond overflow from steam and power generation
systems
Solid
014 Collected coal fines from particulate control in
coal preparation
517 Spent sulfur plant catalyst
518 Spent catalyst from sulfur plant tail gas treatment
unit
523 Biological sludge from wastewater treatment
524 Sludge from chemical treatment of wastewater
526 Residue from wastewater incineration
528 Residue from brine concentration
530 Recovered sulfur from sulfur plant and tail gas
treatment unit
703 Fly ash from steam generation system
705 FGD sludge from steam generation system
709 Fly ash from power generation system
711 FGD sludge from power generation system
50
-------
3.2.2 MFS Case
A listing of the waste streams and selected process streams for the
Illinois coal MFS case design is presented in Table 3-2. There is no dif-
ference in the listing of waste streams between the MFS case and base case
designs in the coal preparation, coal liquefaction and auxiliary operations
process areas. Listing of waste streams from these three process areas is
therefore not repeated. In the product separation and purification process
area, the MFS case design generates three additional waste streams because
a separate vacuum fractionator is provided for the partial oxidation feed.
In the liquefaction residue processing/hydrogen plant process area, the waste
streams from the MFS case and base case designs are significantly different
because of the method of hydrogen production. In the pollution control opera-
tions area, the MFS case design generates two additional waste streams because
a separate HLS removal/sulfur recovery unit was assumed for the treatment of
acid gas streams containing less concentrated levels of f-LS from the partial
oxidation unit.
51
-------
TABLE 3-2. LISTING OF WASTE STREAMS AND SELECTED
PROCESS STREAMS FOR THE EDS ILLINOIS
COAL MFS CASE DESIGN*
Product Separation and Purification Process Area
Uncontrolled Discharge Streams
Gaseous
153
156
161
203
508
Liquid
152
155
157
202
252
Solid
204
Vacuum fractlonator off-gas
Partial oxidation feed vacuum fractionator off-gas
Flue gas from partial oxidation feed vacuum fractlonator
preheat furnaces
Flue gas from solvent hydrogenation fuel preheat
furnaces
Acid gas from DEA regenerator
Atmospheric fractionator overhead drum wastewater
Vacuum fractlonator wastewater
Partial oxidation feed vacuum fractionator wastewater
Solvent hydrogenation cold separator wastewater
Solvent hydrogenation fractionator overhead drum
wastewater
Spent solvent hydrogenation catalyst
Process Streams
151
159
200
251
Atmospheric fractionator off-gas
Vacuum bottoms slurry to Flexicoking
Solvent hydrogenation cold separator vapor
Solvent hydrogenation sour gas
Liquefaction Residue Processing/Hydrogen Production Process Area
(Continued)
* Listing of waste streams in the coal preparation, coal liquefaction and
auxiliary operations is the same as for the base case design and not
repeated! here.
52
-------
TABLE 3-2. (Continued)
Uncontrolled Discharge Streams
Gaseous
304 Flexicoking gasifier/heater sour gas
428 Acid gas from acid gas removal unit in hydrogen
purification
438 Hydrogen plant deaerator vent
440 Flash gas from partial oxidation unit
449 Regeneration/decommissioning off-gas from high
temperature shift conversion catalyst
Regeneration/decommTssioning off-gas from low
temperature shift conversion catalyst
Transient waste gas from Flexicoking
Transient waste gas from partial oxidation unit
Liquid
ony
^n Flexicoking recontacting drum wastewater
Flexicoking fractionator overhead drum wastewater
Flexicoking gasifier/heater overhead drum wastewater
Knockout drum wastewater in H£ cryo recovery
Blowdown and K.O. drum wastewater from hydrogen
generation
^ Sour water from partial oxidation unit
Slag filtrate from partial oxidation unit
Solid
onp
^^ Flexicoking gasifier/heater dry fines
Flexicoking gasifier/heater wet fines
Flexicoking gasifier/heater bed coke
Flexicoking heater/reactor chunks/agglomerates
Spent hydrotreater catalyst in \\2 cryo recovery
Spent drying agents in H2 cryo recovery
Slag from partial oxidation unit
Spent high temperature shift catalyst in hydrogen
generation
Spent low temperature shift catalyst in hydrogen
generation
"" (Continued)
53
-------
TABLE 3-2. (Continued)
Process Streams
310 Flexicoking fractionator off-gas
406 Sweet gas from DEA scrubbing
Pollution Control Operations Area
Secondary Discharge Streams
Gaseous
429 CO^ rich vent gas from h^S removal/sulfur recovery
unit in hydrogenation
501 Acid gas from sour water stripping/ammonia recovery
510 Tail gas from sulfur plant
512 Off-gas from sulfur plant tail gas treatment unit
(prior to incineration)
514 Incinerator stack gas from sulfur plant tail gas
treatment unit
525 Flue gas from wastewater sludge incineration
527 Brine concentration off-gas
529 Activated carbon regeneration off-gases
540 Oxidizer vent gas from Stretford process
541 Oxidizer vent gas from Stretford unit in Beavon
Sulfur Removal Process (BSRP)
543 Incinerated hydrogen plant deaerator vent
546 Controlled regeneration/decommissioning off-gas from
high and low temperature shift catalysts
701 Flue gas from steam generation system (discharge to
the atmosphere following controls)
707 Flue gas from power generation system (discharge to
the atmosphere following controls)
741 Flue gas from combustion of slurry drier vent gas
and vacuum flash off-gas
811 Controlled transient waste gas from Flexicoking
812 Controlled transient waste gas from partial oxidation
unit
813 Controlled transient waste gas from liquefaction
reactor
(Continued)
54
-------
TABLE 3-2. (Continued)
Liquid
432 Solution blowdown from H?S removal/sulfur recovery
unit
502 Wastewater from ammonia recovery
504 Wastewater from phenolic extraction
515 Sour water from sulfur recovery plant
516 Sour water from sulfur plant tail gas treatment unit
519 Solution blowdown from sulfur plant tail gas treatment
unit
521 Effluent from wastewater treatment
522 Reclaimed water from reuse
706 Ash pond overflow from steam and power generation
systems
Solid
014 Collected coal fines from particulate control
517 Spent sulfur plant catalyst
518 Spent catalyst from sulfur plant tail gas treatment
unit
523 Biological sludge from wastewater treatment
524 Sludge from chemical treatment of wastewater
526 Residue from wastewater incineration
528 Residue from brine concentration
530 Recovered sulfur from sulfur plant and tail gas
treatment unit
703 ply ash from steam generation system
705 FGD sludge from steam generation system
709 Fly ash from power generation "system
711 FGD sludge from power generation system
55
-------
3.3 DETAILED DESCRIPTION OF DISCHARGE SOURCES BY PROCESS AREA
In this subsection, the sources and characteristics of discharge streams
from the EDS process are described in detail. The descriptions are provided
according to process area. Fugitive emissions are covered as a separate
section because in most cases they are not generated from any one process
area alone. Products from the EDS process are also covered in a separate
section.
56
-------
Coal Preparation - Area 1
3.3.1 Coal Preparation Area (Area 1)
The amount of coal handled by the coal preparation plant was determined
by assessing the coal requirements for the liquefaction reactor, the power
boiler, and the steam boiler. These coal requirements are listed in Table 3-3
on an "as received" basis. Part of the plant fuel requirements to produce
process steam will be met by plant products and by-products.
The coal preparation area includes coal storage and coal handling opera-
tions. A simplified flow diagram indicating all the major process operations
and the emission sources is presented in Figure 3-3. As shown in this figure,
the only difference between the base case and MFS case designs is the amount
of coal handled for steam and power boiler requirements.
TABLE 3-3. COAL FEED REQUIREMENTS - EDS PLANT
Unit
Liquefaction Reactor
Power Boiler
Steam Boiler
Base Case,
Mg/hr
1,134
95.8
35.3
Market Flexibility
Sensitivity (MFS)
Mg/hr
1,134
68.7
92.8
Data Source: Reference 13
3.3.1.1 Coal Storage (Coal Preparation - Area 1)
*
In the Exxon designs, cleaned and washed Illinois No. 6 coal is received
five days per week 24 hours per day from three adjacent mines by three belt
conveyors. The incoming coal is stored in two parallel live storage piles.
The two piles together have a combined capacity of 5 days throughput of coal.
A 30-day dead storage is built up and maintained. Two 100% capacity boom type
stackers mounted on rails are provided to pile the coal being received.
57
-------
FUGITIVE DUST
FROM COAL PILE
COAL
PILE
012 I RUNOFF
1134 Mg/hr
i
/013)
SLURRY DRIER
DISTRIBUTION
BIN
1
1
/013)
161 .5 Mg/hr (MFSCASE)
131.1 Mg/hr (BASE CASE)
BOILER
DISTRIBUTION
BIN
vvvv
1134 Mg/hr
(5)
SLURRY DRIER
COAL CRUSHER
TO
SLURRY
DRIERS
VIBRATING
FEEDERS
(2)
ROLL
CRUSHERS
PULVERIZER
BIN
PULVERIZER
Figure 3-3. , Block flow diagram for EDS commercial plant coal
preparation area (Area 1) P '
58
-------
Coal Preparation - Area 1
Streams Oil. 012
Two 100% capacity reclaimers are used to reclaim coal from the live stor-
age piles (24 hrs/day, 7 days/week). Each is a bucketwheel on boom type re-
claimer mounted on rails.
3.3.1.1.1 Gaseous Waste Stream
There is only one air emission stream from coal storage:
• Stream Oil - fugitive dust from coal pile
Fugitive dust emissions from coal pile (Stream Oil) (Coal Storage - Area 1)
The quantities of fugitive particulates generated by the 5-day and 30-
day storage piles were estimated using methodology described by Jutze et al (15),
The four major sources of fugitive particulate emissions are: loading onto
piles; equipment and vehicle movement in storage area; wind erosion; and load-
out from piles. Emission rates from these sources are dependent on the turnover
rate for the pile, methods for adding and removing material, and the pile con-
figuration.
Fugitive emission estimates were calculated using several different for-
mulas (15). These formulas include correction factors which account for such
parameters as activity on and around storage piles, silt content of material
stockpiled, duration of storage and average surface moisture in different geo-
graphic areas. The formula factors used in developing fugitive emission esti-
mates assumed that no control techniques are applied (e.g., application of wet-
ting or crusting agents). Estimated uncontrolled fugitive dust emissions from
the 5-day live coal storage piles (Stream 011-1) and the 30-day dead coal stor-
age pile (Stream 011-2) are presented in Tables 3-4 and 3-5, respectively.
Total uncontrolled fugitive dust emissions from coal storage would be obtained
by summing the values in these two tables.
3.3.1.1.2 Liquid Waste Stream
There is only one liquid waste stream from coal storage:
t Stream 012 - coal pile runoff.
59
-------
TABLE 3-4. UNCONTROLLED FUGITIVE DUST GENERATION
5-DAY COAL STORAGE PILES (STREAM 011-1)
Activity
Wind Erosion*
Loading On
Loading Offf
Vehicular Activity**
TOTAL
Illinois No.
Base Case,
kg/hr
2.22
7.31
9.39
0.25
19.20
6 Coal
MFS Case
kg/hr
2.27
7.59
9.61
0.25
19.72
* Based on a respirable emission factor of 6.4 mg of dust per kg/yr of coal
stored (Ref. 16). Since respirable emissions represent only 5 percent of
total particulate emissions, a correction of 20 has been applied.
F . . f t f , H • - - kg/Mg of material
t Emission factor formula used is - ~ - 3/ J
transferred (15). (PE/100r
where ^ (Activity Factor) = 0.75
S1 (Silt Content) = 0.5, and
PE (Thornthwaite's precipitation-evaporation index) is 93 for
Southwestern Illinois.
(0.025)(K1) (5,71.5)
I Emission factor formula used is - ~ - kg/Mg of material
transferred (15). (PE/100r
where ^ = 0.77
S, = 0.5, and
PE = 93 for Southwestern Illinois
(0.065)(K,) (S,/1.5)
**Emission factor formula used is - ^ - kg/Mg-yr of material
stored (15). (PE/lOOr
where K, = 0.5
S1 = 0.5
PE = 93 for Southwestern Illinois
60
-------
TABLE 3-5. UNCONTROLLED FUGITIVE DUST GENERATION
30-DAY COAL STORAGE PILES (STREAM 011-2)
Activity
Wind Erosion*
Loading On*
Loading Off f
Vehicular Activity**
Illinois No.
Base Case,
kg/hr
13.31
7.31
9.39
1.44
6 Coal
MFS Case,
kg/hr
13.62
7.59
9.61
1.49
Total 31.45 32.31
* Based on a respirable emission factor of 6.4 mg of dust per kg/yr of coal
stored (Ref. 16). Since respirable emissions represent only 5 percent of
total particulate emissions, a correction of 20 has been applied.
(0.02)(K1) (5,71.5)
t Emission factor formula used is kg/Mg of material
transferred (15) (PE/100)2
where K-, (Activity Factor) = 0.75
S, (Silt Content) = 0.5, and
PE (Thornthwaite's precipitation-evaporation index) is 93 for
Southwestern Illinois
(0.025)(K,) (S,/1.5)
•f Emission factor formula used is kg/Mg of material
transferred (15) (PE/100)2
where ^ = 0.77
S1 = 0.5, and
PE = 93 for Southwestern Illinois
(0.065MK,) (5,71.5)
** Emission factor formula used is * kg/Mg-yr of material
stored (15) (PE/100)
where K, = 0.5
S] = 0.5
PE = 93 for Southwestern Illinois
61
-------
Coal Preparation - Area 1
Stream 012
Coal pile runoff (Stream 012) (Coal Storage - Area 1)
Only a limited amount of data are available in the published literature
on the chemical characteristics of coal pile runoff. However, effluents from
some coal storage piles comprised of high sulfur coal have been analyzed. In
addition, laboratory leaching tests done at Los Alamos Scientific Laboratories
have shown that types and quantities of pollutants released from coal storage
piles are similar to those from coal refuse (17).
In general, coal from eastern sources has been found to produce a highly
acidic runoff stream with pH's ranging from 2.2 to 3.1. Total suspended solids
concentrations are generally low during base flow periods but increase drama-
tically during storm runoff to levels as high as 2300 mg/1. Sulfate concen-
trations are also quite high with ranges from 1800 to 9600 mg/1. Concentra-
tion of iron and mannanese are both very high, ranging from 23 to 1800 mg/1
and from 1.8 to 46 mg/1, respectively. Other elements of potential concern
include aluminum, mercury, arsenic, and zinc.
Estimates of the amount of runoff produced at the coal storage sites as
a result of a 10-year, 24-hour storm were determined as follows. The surface
area covered by the 5-day and 30-day storage piles were calculated based on a
pile height of 18.3 m (60 ft) and a bulk density of 1.153 Mg/m3 (72 Ib/cu ft.).
The storage pile was assumed to be a truncated cone with an angle of repose
of 40°. Annual and 10-year, 24-hour storm rainfall values for Southwestern
Illinois were obtained from the Rainfall Frequency Atlas of the U.S.
According to Cox et al. (17), 70 percent of the rainfall incident upon a
coal pile ultimately appears as runoff. This factor was therefore used to
calculate the total runoff from the coal pile itself. In addition, to allow
for the fact that the drainage ditch would not be contiguous to the storage
pile, an arbitrary 20 percent of the above areas was used to take this into
account. The "rational method" presented in Clark, et al (18), was used to
calculate peak runoff flow rates. The runoff coefficient used in the rational
62
-------
Coal Preparation - Area 1
Stream 012
method was the ratio of peak runoff rate to average rainfall rate, but is also,
by virtue of the units used in the equation, the ratio of runoff quantity to
rainfall quantity. While this was a peak rather than average value, it was
used in the absence of a better method to calculate the maximum runoff that
would be expected from a particular site. A value of 0.17, corresponding to
flat lawns with heavy soil, was chosen for all site. The rational formula
relates runoff to rainfall in the following manner:
Q = cia
where Q = Peak runoff rate, cfs
c = runoff coefficient
i = average rainfall intensity, in/hr
a = drainage area, acres.
Estimated average and 10-year, 24-hour storm runoffs from the 5-day live
storage piles (Stream 012-1) and 30-day dead storage pile (Stream 012-2) are
presented in Table 3-6. Total runoff would be the sum of the runoff values for
the 5-day and 30-day piles.
3.3.1.1.3 Solid Waste Stream
There is no solid waste stream from coal storage.
3.3.1.2 Coal Handling (Coal Preparation - Area 1)
A spared system of belt conveyors is used to transport reclaimed coal to
the distribution bins (13). The slurry drier distribution bin is provided to
distribute coal to five crushers through five gravimetric weight belt feeders.
Impact cage mill crushers are used to reduce the reclaimed coal to minus 8 mesh
size. A single conveyor conveys the coal from each crusher to the top of one
of the five slurry driers.
63
-------
TABLE 3-6. AVERAGE AND 10-YEAR, 24-HOUR STORM RUNOFF FROM
5-DAY WET STORAGE PILES AT THE EDS PLANT
(STREAM 012-1)
Coal Type
Quantity of coal in*
5 day storage (Mg)
Storage pile volume (m )
Ground area coveredto
by storage pile (m )
10-year, 24-hour storm**
runoff (m3)
Average daily runoff (m )
FROM 30-DAY DEAD STORAGE
Coal Type
Quantity of coal in*
30 day storage (Mg)
Storage pile volume (m )
Ground area coveredt
by storage pile (m^)
10-year, 24-hour**
storm runoff (m3)
Average daily runoff (m )
Base Case
151,800
131,700
10,630
990
70
PILE AT THE EDS
Base Case
910,700
789,900
52,000
4,860
346
MFS Case
155,460
144,600
11,610
1,080
78
PLANT (STREAM 012-2)
MFS Case
932,800
809,000
52,400
4,880
347
* Based on 24 hours per day
t Based on 1.153 Mg/m3 bulk density
T Based on a covered radius of 76 m.
** 10-year, 24-hour rainfall in Southwestern Illinois was assumed to be
5 inches
tt Annual rainfall in Southwestern Illinois was assumed to be 40 inches.
64
-------
Coal Preparation - Area 1
Stream 013
A second distribution bin for the steam and power boilers is provided
to distribute coal to the pulverizer coal crushers through vibrating feeders.
Two roll crushers are used to reduce the coal to minus 2 inch size, which are
then conveyed to bins for feed to the pulverizers.
3.3.1.2.1 Gaseous Waste Streams
Fugitive particulates are generated from a variety of sub-sources during
the conveying/transfer, screening, and crushing of coal as shown in Figure 3-3.
Fugutive particulate emissions from coal pulverizers have been reported to be
negligible and not considered here (41). The combined emissions from these
sub-sources are denoted as:
• Stream 013 - fugitive particulates from coal handling and crushing
Fugitive particulates from coal handling and crushing (Stream 013) (Coal
Handling - Area 1]~
Coal crushing/screening data are available from surface coal mining and
ore mining operations, the crushed stone, and the manufacturing of coke indus-
tries. Published data on particulate emission factors for coal operations are
limited. The uncontrolled emission factors that are available vary over a
broad range, reflecting the uncertainties in the determination of these factors.
One study lists an average uncontrolled emission factor of 0.2 kg/Mg of coal
processed for loading and unloading activities in all modes of transport (15)
while another study (19) lists emission factors of 0.05 kg/Mg and 0.01 kg/Mg
of coal mined for coal loading and unloading operations, respectively (19).
The emission factors used in deriving uncontrolled particulate emission rates
presented in Table 3-7 are intended to provide approximate emissions generated
during the specific operations. The streams associated with the estimated
emission values are shown in Figure 3-3. Because of the uncertainties in emis-
sion factors, estimated uncontrolled emission rates are given in Table 3-7 as
ranges, with the range encompassing the-low end to the high end of emission
factor estimates (0.02 kg/Mg to o.48 kg/Mg in most cases). For the base case
65
-------
TABLE 3-7. FUGITIVE PARTICULATE EMISSIONS FROM COAL HANDLING AND CRUSHING (STREAM 013)
Stream No.
013-1
013-2, 3, 4
013-5
013-6
013-7
013-8
013-9
013-10
013-11
013-12
013
Illinois No.
Participate
Emission
Source
Conveying/Transfer
Conveying/Transfer
Conveying/Transfer
Screening
Conveying/Transfer
Crushing
Conveying/Transfer
Conveying/Transfer
Crushing
Conveying/Transfer
Total
6
Estimated Average
Emission Factors
Uncontrolled
kg/Mg
0.02-0.48*
0.02-0.48*
0.02-0.48*
0.041"
0.02-0.48*
0.04f
0.02-0.48*
0.02-0.48*
0.04f
0.02-0.48*
Base
Feed Rate
(as received
basis)
Mg/hr
1265.1
1265.1
131.1
131.1
131.1
131.1
131.1
1134
1134
1134
Case
Uncontrolled
Emission
Rates
kg/hr
25.3-607.2
25.3-607.2
3.0-62.9
5.2
3.0-62.9
5.2
3.0-62.9
22.7-544.3
45.4
22.7-544.3
161-2548
MFS
Feed Rate
(as received
basis)
Mg/hr
1295.5
1295.5
161.5
161.5
161.5
161.5
161.5
1134
1134
1134
Case
Uncontrolled
Emission
Rates
kg/hr
25.9-621.8
25.9-621.8
3.2-77.5
6.5
3.2-77.5
6.5
3.2-77.5
22.7-544.3
45.4
22.7-544.3
165-2623
Both.the low end and the high end of the emission factor range are obtained from Reference 19. This range covers
results from a variety of conveying and transferring applications; some of these applications might have included
some degree of fugitive particulate control, creating the low end of the presented range. Because of the uncertainty
over the degree of control reflected in the lower end of the range, the full range is presented here, although the
intent o* the table is to present uncontrolled emissions.
Emission factor as reported for combined "secondary crushing/screening operations" are 0.08 kg/Mg of coal processed,
Arbitrarily assumed contribution from crushing = that from screening = 0,04 kg/Mg of coal processed (19). Preliminary
data from Exxon pilot plant on emissions from the impact mill crushing operation indicate a lower emission factor of
0.01 kg/Mg (22).
Emissions from coal pulverizer a,re negligible (41).
-------
Coal Preparation - Area 1
Stream ITH
and MFS case designs, uncontrolled fugitive particulate emissions from coal
handling and crushing were estimated to be 161-2548 kg/hr and 165-2623 kg/hr,
respectively.
In the absence of more specific data several simplifying assumptions
were made. No modification to the emission factor was made to correct for
the moisture content of the coals. Nonparticulate emissions in the pulverizer/
dryer off-gases were assumed to be negligible.
3.3.1.2.2 Liquid Haste Stream
There is no liquid waste stream from coal handling.
3.3.1.2.3 Solid Haste Stream
There is no solid waste stream from coal handling.
67
-------
Coal Liquefaction - Area 2
3.3.2 Coal Liquefaction Area (Area 2)
In the coal liquefaction area for the EDS commercial plant, crushed coal
from coal preparation facilities is fed to the slurry drier, where it is mixed
with recycle donor solvent from solvent hydrogenation (13). The dry slurry
is pumped to reaction pressure, preheated, mixed with preheated hydrogen, and
heated in the slurry preheat furnace to the reaction temperature. The pre-
heated dry slurry is then sent to the liquefaction reactor. The reactor efflu-
ent is separated into a recycle gas and a slurry stream. The recycle gas is
treated, combined with makeup hydrogen, compressed, preheated, and sent to the
slurry preheat furnace. The slurry is let down to nearly atmospheric pressure
and sent to the product fractionation facilities. A block flow diagram indi-
cating all the major process and waste streams for the coal liquefaction area
is presented in Figure 3-4.
3.3.2.1 Slurry Drying and Liquefaction (Coal Liquefaction - Area 2)
In the slurry dreiers, crushed coal feed (minus 8 mesh) is mixed with
recycle solvent to form a coal slurry (13). The slurry driers are pressure
vessels where the heat for drying is provided by the hot recycle solvent intro-
duced at 558°K (545°F). The operating temperature of the slurry driers is 408°K
(275°F). Concurrently with the mixing process, the slurry is dried to less
than 4 wt % moisture on dry coal feed basis. The dry product slurry is then
pumped to reaction pressure, further heated by heat exchange with liquefaction
reactor effluents, and fed to the liquefaction slurry preheat furnace. The
overhead from the slurry drier consisting of water vapor (dirven from the coal),
stripped recycle donor solvent and some coal volatiles is condensed, cooled and
separated into phenolic water, distillate liquid, and offgas. The phenolic
wastewater (Stream 103) is withdrawn from the drum and sent to the phenol ex-
traction unit while the distillate is returned to the slurry drier. The slurry
drier vent gas (Stream 102) is burned as fuel.
The coal slurry from the slurry drier is mixed with preheated hydrogen
68
-------
SLURRY DRYING AND LIQUEFACTION I RAW PRODUCT SEPARATION
U3
OAL FEED — 0°y*
DONOR
SOLVENT
VENT
GAS
nm\
y
COAL
SLURRY
DRIER
A ^
•x
H2
RICH
H2MA
i
TREAT
GAS
FLUE
C.L
iS
(l07)
1_^
"1
S
LIQUEFACTION
SLURRY
PREHEAT
FURNACE
t
(108) (103)
T 1
T
SLURRY
DRIER
SOLID
COLD
FU
i
EL
TRANSIENT
GAS
(S03J
7
LIQUEFACTION
REACTOR
GAS
1
KEUP
r
H2 PURGE TO
CRYOGENIC
HYDROGEN
RECOVERY
i ,
VAPOR
HOT
SEPARATOR
WASH
OIL
i
,
*
R
E
S
4
F
VAPOR
EACTOR
FFLUENT
EPARATOR
SLURRY TO
ATMOSPHERIC
SEPARATOR
WASTEWATER
FRACTIONATOR
i
'
i
LEAN DEA FROM DEA
"* REGENERATION
DEA
ABSORBER _^~\_^ RICH DEA TO
(^y~* REGENERATION
(§»
|
HYDROCARBON
' fc COLD to LIQUID TO
SEPARATOR " ATMOSPHERIC
FRACTIONATOR
WASTEWATER
A
noe)
Y
COLD
SEPARATOR
WASTEWATER
HYDROCARBON
LIQUID TO
ATMOSPHERIC
FRACTIONATOR
Figure 3-4. Block flow diagram for EDS commercial plant coal liquefaction area (Area 2)
-------
Coal Liquefaction - Area 2
Streams 102, 107
treat gas and fed to the slurry preheat furnace fired with fuel gas. The
slurry-hydrogen mixture is heated to liquefaction reactor conditions of
700-750°K (800-900°F) and 13.9 MPa (2000 psig). This mixture is then sent
to the liquefaction reactor, where the coal is liquefied in the presence of
molecular hydrogen and the hydrogen donor solvent.
3.3.2.1.1 Gaseous Waste Streams
There are three gaseous waste streams from slurry drying and liquefaction:
• Stream 102 - slurry drier vent gas
0 Stream 107 - flue gas from slurry preheat furnace
• Stream 803 - transient waste gas from liquefaction.
Slurry drier vent gas (Stream 102) (Slurry drying and liquefaction - Area 2)
The slurry drier vent gas is the offgas from the condensation of the
slurry drier overhead vapor. This stream was estimated to be generated at
the rate of 532.1 kmol/hr (20). The composition of the slurry drier vent gas
is given as follows (6): 86.0% N2, 9.9% H20, 4.1% hydrocarbons (average mole-
cular weight of 97.6, mostly in the Cg - 400°F normal boiling range), and 30
ppmv H-S.
Flue gas from slurry preheat furnace (Stream 107) (Slurry drying and
liquefaction - Area 2)
This flue gas stream is generated from the preheating of the coal feed
slurry by the combustion of the low-Btu fuel gas obtained from the Flexicoking
operation. Total heat provided by the fuel gas is 1.885 TJ/hr (1785.6 MM Btu/
hr). The low-Btu fuel gas contains 80 ppmv H,,S and 3 ppmv COS (13). Assuming
combustion with 20% excess air, the flow rate of the flue gas generated was
calculated to be 34,535 kmol/hr (480,920 SCFM). In Table 3-8, the emission
factors used and the estimated emission rates of pollutants for this flue gas
stream are presented.
70
-------
TABLE 3-8. ESTIMATED UNCONTROLLED EMISSIONS FOR
FLUE GAS FROM SLURRY PREHEAT FURNACE
(STREAM 107)
Pollutant
Emission
Factor*
ng/J (Ib/MM Btu)
Emission
Rate
kg/hr
Participate Matter
N0x (as N02)
CO
Hydrocarbons
SOo
2.1 - 6.4 (0.005-0.015)
52 - 99 (0.12-0.23)
7.3 -10.7 (0.017-0.025)
1.3 (0.003)
48 (0.11)
4.1 - 12.1
97 - 186
14 - 20
2.4
91
* Emission factors for participate matter, NOX, and hydrocarbons are
obtained from AP-42 for natural gas combustion in industrial process
heaters (21). By comparison, Exxon estimated emission factors of 3.1
ng/J for particulate matter, and 60 ng/J for NOX (20). The emission
factor for CO is based on 7.3 ng/J from AP-42 and 10.7 ng/J from Exxon.
The emission factor for S0£ is based on 83 ppmv total reduced sulfur in
the low-Btu fuel gas (13).
71
-------
Coal Liquefaction - Area 2
Streams 803, 103, 108
Transient waste gas from liquefaction (Stream 803) (Slurry drying and
liquefaction - Area 2)
Gas flows in the liquefaction reactors during startup, shutdown, or upset
conditions are considered to be transient waste gases because they may not
be suitable for use within the liquefaction facility. For the four liquefac-
tion reactors, it is assumed that transient conditions would be expected twice
per year per reactor, and up to 3 hours in duration each time. Also, outage
for the reactors will not occur simultaneously. The transient waste gas from
the liquefactor reactor is anticipated to be similar in composition to the
liquefaction separator sour gas (Stream 104), assuming that the vapor-liquid
separation stages are operational under transient conditions. Characterization
data for this transient waste gas stream are presented in Table 3-9. The esti-
mated flow rate of this stream is 3,280 kmol/hr (20).
3.3.2.1.2 Liquid Waste Stream
There is only one liquid waste stream from slurry drying and liquefaction:
• Stream 103 - slurry drier cold separator wastewater
Slurry drier cold separator wastewater (Stream 103) (Slurry drying and
liquefaction - Area 2)
The estimated characteristics of this wastewater stream are presented in
Table 3-10. These characteristics were estimated by Exxon based on analyses
of wastewater samples obtained from several small operating units together
with computer process synthesis (13,20). Stream 103 is a non-sour phenolic
wastewater stream that can be sent directly to the phenol extraction unit with-
out sour water stripping.
3.3.2.1.3 Solid Waste Stream
There is only one solid waste stream from slurry drying and liquefaction:
• Stream 108 - solids accumulated in the slurry drier.
72
-------
TABLE 3-9. ESTIMATED CHARACTERISTICS OF TRANSIENT
WASTE GAS FROM LIQUEFACTION REACTORS
(STREAM 803)
Component
H2
Cl
C2
C3
C4
C5
C, - 400°F
b
400/700°F
CO
co2
H?S
NH3
H20
Total flow rate
Temperature, °K
Pressure, MPa
Volume Percent
in Waste Gas
50.5
34.9
6.6
2.5
0.7
0.2
0.2
20 ppmv
0.5
1.2
2.5
49 ppmv
0.07
Flow Rate,
kmol/hr
1657.4
1144.0
217.8
81.2
22.5
5.7
6.6
0.07
15.2
38.4
83.6
0.16
2.3
3275
316
12.7
Data source: Characteristics of Stream 104 in Attachment 3 of Reference 20.
Average frequency of discharge: Two occasions per year for each of 4 reactors,
up to 3 hours in duration per occasion.
Note: The single numbers presented in this table represent a specific set of
design/operating conditions for the EDS plant. This composition could
vary in practice due to uncertainty in the emission estimates, and due
to variations in coal type, plant design conditions and plant operating
conditions. This note is equally applicable to other composition tables
throughout Section 3.
73
-------
TABLE 3-10. ESTIMATED QUALITY OF SLURRY DRIER COLD
SEPARATOR WASTEWATER (STREAM 103)
Contaminant
H2S
NH3
HC1
co2
Phenols*
Total flow rate, kg/hr
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration
ppmw
4
76
13
290
970
Flow Rate
kg/hr
0.6
12
2
46
150
155,640
157.1
317
0.09
Data source: Table 1-X-l of Reference 13.
* Organics other than phenols may also be present. However, no data on the
Identity or concentration levels of other organlcs are publicly available.
74
-------
Coal Liquefaction - Area 2
Stream 108
Solids accumulated in the slurry drier (Stream 108) (Slurry drying and
liquefaction - Area 2)
Coal feed to the EDS process has a nominal top-size of 8 mesh (2.38 mm).
Oversize feed is intermittently removed from the slurry drier for disposal
(Stream 108). A removal frequency of one eight-hour shift every three months
has been estimated. Approximately 204 Mg are recovered from the slurry drier
during each removal operation (6). The corresponding annual generation rate
for this waste is 820 Mg/yr. The slurry drier solids are similar in composi-
tion to the feed coal.
3.3.2.2 Raw Product Separation (Coal Liquefaction - Area 2)
In the raw product separation section, the liquefaction reactor effluent
is being separated into liquids for further fractionation, and light gases
(after acid gas removal) for plant use as recycle hydrogen-rich gas to the
liquefaction reactor.
As shown in Figure 3-4, the reactor effluent is separated into a vapor
stream and a slurry stream in a vapor-liquid separator. Wash oil from the
hot separator drum is used to minimize solids entrainment in the overhead
vapor. The vapor from the vapor-liquid separator is cooled by heat exchange
and enters the hot separator drum. The hot separator vapor flows to a venturi
mixer, where cold separator water is added to prevent ammonia chloride deposi-
tion. This mixture is then cooled by additional heat exchange and fed to the
cold separator drum. The water added to the hot separator vapor in the mixer
is condensed and removed in the cold separator drum, removing, along with it,
the ammonia formed in the process.
The vapor from the cold separator, now consisting largely of hydrogen,
light hydrocarbons and acid gases, is scrubbed with DEA for acid gas removal.
A portion of the resulting hydrogen-rich gas is directed to the cryogenic
hydrogen concentration section. The remaining hydrogen-rich gas is mixed with
makeup hydrogen and hydrogen purge from the solvent hydrogenation section to
75
-------
Coal Liquefaction - Area 2
Stream 106
form recycle treat gas. The treat gas is compressed, preheated by heat ex-
change with effluent separator vapor, and recycled back to the slurry furnace.
The slurry stream from the reactor effluent separator is let down to nearly
atmospheric pressure and sent directly to the atmospheric fractionator. A
portion of the liquid stream from the hot separator is recycled to the reactor
effluent separator as wash oil. The remainder of the hot separator liquid is
let down in pressure and fed to the atmospheric fractionator. The cold separa-
tor hydrocarbon liquid is let down in pressure, preheated by heat exchange
with hot separator vapor, and fed to the atmospheric fractionator. A portion
of the cold separator sour water is recycled and mixed with hot separator vapor
to prevent ammonium chloride plugging. The remainder of the liquefaction cold
separator sour water (Stream 106) is sent to the sour water stripper/ammonia
recovery system for treatment.
3.3.2.2.1 Gaseous Waste Stream
There is no gaseous waste stream from raw product separation.
3.3.2.2.2 Liquid Haste Stream
There is only one liquid waste stream from raw product separation:
• Stream 106 - Liquefaction cold separator wastewater.
Liquefaction cold separator wastewater (Stream 106) (Raw product separation -
Area 2)
The liquefaction cold separator wastewater is generated from the condensa-
tion of the water vapor present in the liquefaction reactor effluent. The
estimated characteristics of this wastewater stream are presented in Table
3-11. Three sets of values are presented. The first set of values are design
estimates developed by Exxon using analyses of wastewater samples from small
operating units together with computer process synthesis (13,20), prior to the
availability of the data from the large pilot plant. The second and third sets
of values are respectively results from EPA (37) and Exxon (23) test campaigns
on the 250 ton coal/day EDS pilot plant at Baytown, Texas. As noted in Table
76
-------
TABLE 3-11. CHARACTERISTICS OF LIQUEFACTION COLD SEPARATOR
WASTEWATER (STREAM 106) - THREE DATA SOURCES
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Sulfate
Cl"
F"
N03~
N02"
SCN"
COD
TDS
TSS
TOC
Alkal inity
(mg/1 as CaC03)
Oil and Grease
Total N
Total S
Flow rate, kg/hr
3
Flow rate, m /hr
Temperature °K
Pressure, MPa
Exxon
Design Estimate
32,330 ppmw
22,840 ppmw
2,470 ppmw
19,450 ppmw
13,720 ppmw
7,410 ppmw
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
100,583
102.6
317
0.09
EPA Testing of
EDS Pilot Plant
5,793 mg/1
6,910 mg/1
47 mg/1
No data
16,024 mg/1
No data
36 mg/1
46 mg/1
30 mg/1
2.25 mg/1
0.02 mg/1
1 ,800 mg/1
49,175 mg/1
11,514 mg/1
25 mg/1
23,512 mg/1
24,618 mg/1
<20 mg/1
7,294 mg/1
1,942 mg/1
No data
No data
No data
No data
Exxon Testing of
EDS Pilot Plant
5,527 mg/1
8,400 mg/1
No data
No data
3,650 mg/1*
No data
No data
No data
3 mg/1
No data
No data
3 mg/1
66,450 mg/1
8,245 mg/1
4 mg/1
14,500 mg/1
30,500 mg/1
No data
8,500 mg/1
5,200 mg/1
No data
No data
No data
No data
Data source: Table 1-X-l of Reference 13 for Exxon design estimate, Table 6-8
of Reference 37 for EPA testing results and Reference 23 for Exxon
testing results.
*GC/MS results by Exxon indicate that this number is too low.
77
-------
Coal Liquefaction - Area 2
Stream 106
3-11, there are significant differences between the three sets of values pre-
sented. Concentration values for the Exxon design estimate are generally
greater than those reported by EPA and Exxon test results. A partial explana-
tion may be that less water is condensed in the cold separator for the Exxon
commercial plant design compared to the pilot plant operation. According to
Exxon, three times more water (per unit coal input basis) may be condensed
in the EDS pilot plant as in the Exxon design estimate (22). Also, the ele-
vated level of thiocyanates and the lower level of total sulfur in EPA test
results indicate that some of the sulfide present could have participated in
the formation of thiocyanates in the sample collected. For purposes of evalu-
ating wastewater treatment technology, the Exxon design estimate values will
be used wherever available, even though the design estimates are based upon
data from experimental equipment that is much smaller in scale than the
Baytown pilot plant. This decision to use the design values is made because
the two sets of pilot plant data have not yet been correlated to process con-
ditions, or incorporated into the material balance for the overall plant by
Exxon. These pilot plant data, if used independently without proper integra-
tion, may result in erroneous wastewater balances for the EDS commercial plant
based on the base case and MFS case designs. The Exxon design estimate values
will be supplemented by values from the Exxon and EPA test results where
necessary. In providing these supplemental values, Exxon test results are
preferred over EPA test results because unlike the EPA samples which necessarily
had to be shipped for analysis to a laboratory outside the Baytown site, Exxon
samples could be analyzed on site minimizing sample degradation. Accordingly,
the characteristics of Stream 106 selected for use in the PCTM wastewater treat-
ment technology evaluation are summarized in Table 3-12. For each species,
the table indicates whether design estimates, pilot data, or some combination
of design estimates and pilot data were used to arrive at the concentration
for that particular species.
In Table 3-13, the concentrations of trace metals in Stream 106, as deter-
mined by EPA and Exxon from pilot plant wastewater samples, are presented. As
78
-------
TABLE 3-12. CHARACTERISTICS OF LIQUEFACTION COLD SEPARATOR
WASTEWATER USED FOR PCTM IN WASTEWATER TREATMENT
TECHNOLOGY EVALUATION (STREAM 106)
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Sulfate
F"
N03~
N02"
SCN"
COD
TDS
TSS
TOC
Alkal inity
(ppmw as CaC03)
Total flow rate, kg/hr
3
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration
ppmw*
32,330'
22,840
2,470
19,450
13,720
7,410
37
3
2
0.02
3
58,970
8,410
4
19,390
31,100
Flow Rate,
kg/hr
3,251
2,297
249
1,956
1,380
745
3.7
0.3
0.2
0.002
0.3
5,933
810
0.4
1,950
3,130
100,583
102.6
317
0.09
Source for
Selection of
Cone. Value
Design
Design
Design
Design
Design
Design
EPA Data
Exxon Data
EPA Data
EPA Data
Exxon Data
Avg. Exxon/EPA Data
Exxon Data
Exxon Data
Avg. Exxon/EPA Data
Exxon Data
* Note that mg/1 values in Table 3-11 have been converted to ppmw values by
using the density of the wastewater.
79
-------
TABLE 3-13. CONCENTRATIONS OF TRACE METALS IN LIQUEFACTION
COLD SEPARATOR WASTEWATER (STREAM 106)
Element
Al umi num A1
Antimony Sb
Arsenic As
Barium Ba
Beryl 1 1 urn Be
Bismuth B1
Boron B
Cadml urn Cd
Calcium Ca
Chromium Cr
Cobalt Co
Copper Cu
Iron Fe
Lead Pb
Magnesium Mg
Manganese Mn
Mercury Hg
Molybdenum Mo
Nickel N1
Phosphorus P
Potassium K
Selenium Se
Silicon Si
Silver Ag
Sodium Na
Strontium Sr
Tin Sn
Titanium Ti
Tungsten W
Uranium U
Vanadium V
Zinc Zn
EPA Testing
of EDS
Pilot Plant*
0.031
<0.01
0.004
0.084
<0.003
<0.50
383
<0.025
1.79
<0.03
<0.02
<0.015
1.64
<0.08
0.18
0.043
Not detected
<0.04
0.035
<0.40
0.60
<0.001
9.91
<0.03
3.92
<0.001
<0.03
<0.006
~
—
<0.01
0.086
Exxon Testing
of EDS
Pilot Plant1"
3.18
(0.0636)
(0.09)
0.264
<0.002
__
163?
<0.016
4.09
0.0629
0.0451
0.324
1.16
0.0999
0.52
0.0293
—
(0.0182)
0.405
(0.142)
0.972
<0.0353
56.4
<0.0086
7.69
0.0146
0.0954
0.041
<0.101
<0.0487
0.541
0.893
Data source: Reference 24 for EPA testing
25 for Exxon testing results
— Not analyzed
* All EPA values are
1n units of mg/1
results, Reference
t All Exxon values are 1n units of ppmw
t Value out of range,
needs further dilution
( ) Value may not be significant.
80
-------
Coal Liquefaction - Area 2
Stream 106
can be seen from this table, the EPA and Exxon test results differ signifi-
cantly, possibly because the samples were taken two weeks apart. Both sets
of values, however, indicate low levels of trace metals for this wastewater
stream.
In Table 3-14, preliminary results of organic analysis obtained by EPA
from the EDS pilot plant wastewater sample are presented. These results pro-
vide some insight on the types of organic compounds present, and indicate that
the major organic components are aliphatic hydrocarbons and phenols.
The liquefaction cold separator wastewater stream will likely be combined
with other process wastewater streams from the product separation and purifi-
cation and liquefaction residue processing/hydrogen plant process areas, prior
to treatment in the sour water stripper/ammonia recovery system.
3.3.2.2.3 Solid Waste Stream
There is no solid waste stream from raw product separation.
81
-------
TABLE 3-14. CONCENTRATIONS OF ORGANIC COMPOUNDS IN LIQUEFACTION
COLD SEPARATOR WASTEWATER (STREAM 106)
Organic Compound Concentration
Class mg/1
Aliphatic Hydrocarbons 2,170
Ethers 260
Aldehydes and Ketones 51
Nitrites 310
Amines 7.4
Thiols, Sulfides and Disulfides 31
Benzene and Substituted Benzene Hydrocarbons 140
Phenols* 2,150
Fused Polycyclic Hydrocarbons 18
Fused Non-Alternant Polycyclic
Hydrocarbons t 17
Heterocyclic Nitrogen Compounds 120
Heterocyclic Oxygen Compounds 320
Heterocyclic Sulfur Compounds 18
(Thiophenes)
Total 5,610
Data source: Table 6-6 of Reference 37. These results are preliminary.
* Breakdown for the phenols: 1,200 mg/1 phenol, 150 mg/1 o-cresol , 410
mg/1 m-cresol, 150 mg/1 p-cresol, 190 mg/1 C~ phenol, 19 mg/1 C~ phenol,
2.3 mg/1 C, phenol, 14 mg/1 methyl naphthol, 15 mg/1 C? naphthof.
+
The only fused polycyclic hydrocarbons identified were naphthalene and
methyl naphthalene.
T The only fused non-alternant polycyclic hydrocarbons identified were
fluorene and methyl fluorene.
82
-------
Product Separation and
Purification - Area 3
3.3.3 Product Separation and Purification Area (Area 3)
The product separation and purification operations for the EDS commercial
plant consist of four major process areas: liquefaction product fractionation,
solvent hydrogenation, gas treating, and product recovery (13). A block flow
diagram indicating all the major process and waste streams from these opera-
tions is presented in Figure 3-5.
3.3.3.1 Liquefaction Product Fractionation (Product Separation/Purification -
ATea 3j
The slurry streams from the liquefaction hot and cold separators (Area 2)
are fed to the atmospheric fractionator (or tower) at different points (13).
In the atmospheric tower, the reactor effluent is separated into offgas, naph-
tha, a 400/650°F low sulfur fuel oil (LSFO)/spent solvent sidestream, and a
slurry bottoms stream. The 400/650°F LSFO/spent solvent cut is steam stripped
in a sidestream stripper tower in order to meet flash point requirements for
the LSFO product and for the solvent, and sent to solvent hydrogenation area.
The atmospheric tower offgas (Stream 151), a sour gas consisting primarily of
hydrogen, light hydrocarbons, and hydrogen sulfide, is sent to the DEA scrubber
for acid gas removal. The overhead drum wastewater (Stream 152), resulting
from additional condensation of water vapor present in the liquefaction reac-
tor effluent, is sent to wastewater treatment. Naphtha separated from the
overhead drum wastewater is sent to the product recovery area for additional
processing.
The atmospheric tower bottoms are let down in pressure and fed directly
to the vacuum fractionator. Products from the vacuum fractionator include
offgas, vacuum distillate, vacuum gas oil (VGO), 650/900°F LSFO/spent solvent
sidestreams, and the vacuum bottoms which are fed to the Flexicoker. The
vacuum fractionator offgas (Stream 153) is burned as fuel. The sour water
separated from the vacuum distillate is combined with the condensate from the
83
-------
LIQUEFACTION PRODUCT FRACT1ONATION
SWEET GAS
TO CRYOGENIC
HYDROGEN
RECOVERY
GAS TREATING
00
LIQUID AND
SLURRY STREAMS
FROM LIQUEFACTION
REACTOR EFFLUENT
SEPARATORS
LEAN OEA
TO COAL
LIQUEFACTION
IAREA2)
RICH DEA —(105
IAREA2I
PARTIAL
OXIDATION
FEED VACUUM
FLASH TOWER
IMFS CASE ONLY!
PRODUCT RECOVERY
Figure 3-5. Block flow diagram for EDS commercial plant product separation and purification area (Area 3)
-------
Product Separation and
Purification - Area 3
Streams 153, 156
vacuum jet ejector (Stream 155), and sent to wastewater treatment. The VGO
obtained is sent to liquid storage. The vacuum distillate and 650/900°F
LSFO/ spent solvent are sent to the solvent hydrogenation area.
For the MFS case, a vacuum fractionator for the partial oxidation feed is
added to process part of the atmospheric tower bottoms. The major difference
between this fractionator and the Flexicoker feed vacuum fractionator is pre-
heating of the atmospheric tower bottoms in furnaces before feeding to the
partial oxidation feed vacuum fractionator. As a result, the partial oxida-
tion feed vacuum fractionator bottoms have a cut point of 975°F vs. the Flexi-
coker feed vacuum fractionator bottoms cut point of 920°F. The deeper cut
point allows the recovery of additional heavy liquids which would be destroyed
if left in the bottoms feed to partial oxidation. Similar process and waste
streams are generated from the partial oxidation feed vacuum fractionator,
including a vacuum fractionator offgas (Stream 156) burned as fuel, a sour
water (Stream 157) sent to wastewater treatment, a VGO to liquid storage, a
vacuum distillate and a 650/900°F LSFO/spent solvent sent to the solvent hydro-
genation area.
3.3.3.1.1 Gaseous Haste Streams
There are three gaseous waste streams from liquefaction product fractiona-
tion:
• Stream 153 - offgas from vacuum fractionator feeding Flexicoker
• Stream 156 - offgas from vacuum fractionator feeding partial oxida-
tion unit (MFS case only)
• Stream 161 - flue gas from preheat furnace for vacuum fractionator
feeding partial oxidation unit (MFS case only).
Vacuum fractionator offgases (Streams 153 and 156) (Liquefaction product
fractionation - Area 3)
The vacuum fractionator offgases result from the letdown in pressure of
the atmospheric fractionator bottoms slurry feed to the vacuum fractionator.
85
-------
Product Separation and
Purification - Area 3
Streams 153, 156, 161
For the base case design, the vacuum fractionator offgas (Stream 153) genera-
tion rate was estimated to be 68.9 kmol/hr (20). For the MFS case, the com-
bined vacuum fractionator offgas (Stream 153) and partial oxidation feed
vacuum fractionator offgas (Stream 156) generation rate was estimated to be
68.9 kmol/hr (20). For both the base case and the MFS case, the offgas is
estimated to contain 7.5% 02, 28.7% N2> 11.3% H20, 47.5% hydrocarbons (with
average molecular weight of 46.2), and 5.0% FLS (8).
Flue gas from preheat furnace for vacuum fractionator feeding partial
oxidation unit (Stream 161) (Liquefaction product fractionation - Area 3)
This flue gas stream is generated only in the MFS case design and results
from the combustion of the low-Btu fuel gas in the preheater for the atmospher-
ic tower bottoms. The heated atmospheric tower bottoms are sent to the vacuum
fractionator designed to produce vacuum bottoms feed for the partial oxidation
unit. Total heat provided by the combustion of the low-Btu fuel gas from the
Flexicoking unit is 0.023 TJ/hr (22.0 MM Btu/hr). The low-Btu fuel gas con-
tains 80 ppmv H2S and 3 ppmv COS (13). With 20% excess air, the flow rate of
this flue gas stream was calculated to be 425 kmol/hr (5925 SCFM). In Table
3-15, the emission factors used and the estimated emission rates of pollutants
for this flue gas are presented.
3.3.3.1.2 Liquid Waste Stream
There are three aqueous waste streams from liquefaction product fractiona-
tion:
• Stream 152 - atmospheric fractionator overhead drum wastewater
• Stream 155 - vacuum fractionator wastewater
• Stream 157 - partial oxidation feed vacuum fractionator wastewater
(MFS case only).
86
-------
TABLE 3-15. ESTIMATED UNCONTROLLED EMISSIONS FOR
FLUE GAS FROM PARTIAL OXIDATION FEED
VACUUM FRACTIONATOR PREHEAT FURNACE
(STREAM 161)
Pollutant
Particulate Matter
N0x (as N02)
CO
Hydrocarbons
S00
Emission
Factor*
ng/J (Ib/MM Btu)
2.1 - 6.4 (0.005-0.015)
52 - 99 (0.12-0.23)
7.3-10.7(0.017-0.025)
1.3 (0.003)
48 (0.11)
Emission
Rate
kg/hr
0.05-0.15
1.2 -2.3
0.17-0.25
0.03
1.1
* Emission factors for participate matter, NO , and hydrocarbons are obtained
from AP-42 for natural gas combustion in industrial process heaters (21).
By comparison, Exxon estimated emission factors of 3.1 ng/J for participate
matter, and 60 ng/J for NOX (20). The emission factor for CO is based on
7.3 ng/J from AP-42 and 10.7 ng/J from Exxon. The emission factor for SOp
is based on 83 ppmv total reduced sulfur in the low-Btu fuel gas (13).
87
-------
Product Separation and
Purification - Area 3
Stream 152
Atmospheric fractionator overhead drum wastewater__(Stream 152) (Liquefaction
product fractionator - Area 3)
The atmospheric fractionator overhead drum wastewater is generated as a
result of the additional condensation of water vapor present in the liquefac-
tion reactor effluent, and condensation of steam fed to the atmospheric frac-
tionator sidestream stripper. The estimated characteristics of this waste-
water stream are presented in Table 3-16. Three sets of values are presented.
The first set of values represents design estimates by Exxon based on analyses
of wastewater samples from small operating units together with computer proces
synthesis (13,20), prior to the availability of data from the large pilot plant.
The second and third sets of values represent EPA and Exxon test results from
the 250 ton coal/day EDS pilot plant, respectively. Comparison of these three
sets of values shows that hLS and NH- concentrations are considerably higher
and the phenolic concentration is considerably lower in the Exxon design esti-
mate. Direct comparisons are difficult because of possible differences in pro-
cess operating conditions. According to Exxon (22), there may be more than
three times the amount of water condensed (per unit coal input basis) in the
pilot plant as in the Exxon design estimate. The Exxon design estimates are
used for purposes of evaluating wastewater treatment technology wherever pos-
sible. This is because the two sets of pilot plant data have not yet been
correlated to process conditions, or incorporated into the material balance
for the overall plant. These pilot plant data, if used independently without
proper integration, may result in erroneous wastewater balances for the EDS
commercial plant based on the base case and MFS case designs. The Exxon de-
sign estimate values will be supplemented by values from the Exxon and EPA
test results as necessary. As discussed for Stream 106 previously, Exxon test
results are preferred over EPA test results because Exxon samples were analyzed
on site minimizing sample degradation. Accordingly, the characteristics of
Stream 152 selected for use in the PCTM wastewater treatment technology evalu-
ation are summarized in Table 3-17. For each species, the table indicates
88
-------
TABLE 3-16. CHARACTERISTICS OF ATMOSPHERIC FRACTIONATOR
OVERHEAD DRUM WASTEWATER (STREAM 152) - THREE
DATA SOURCES
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Sulfate
cr
F"
N03"
N02"
SCN"
COD
TDS
TSS
TOC
Al kalinity
(mg/1 as CaC03)
Oil and Grease
Total N
Total S
Flow rate, kg/hr
3
Flow rate, m /hr
Temperature °K
Pressure, MPa
Exxon
Design
Estimate
4,200 ppmw
5,400 ppmw
1 ,270 ppmw
330 ppmw
18,400 ppmw
3,130 ppmw
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
29,105
30.8
392°K
0.52
EPA Testing
of EDS Pilot
Plant
200 mg/1
1 ,730 mg/1
125 mg/1
No data
27,861 mg/1
No data
63 mg/1
122 mg/1
8 mg/1
0.15 mg/1
Not detected
240 mg/1
93,700 mg/1
678 mg/1
31 mg/1
26,504 mg/1
5,022 mg/1
<20 mg/1
1 ,985 mg/1
1 ,639 mg/1
No data
No data
No data
No data
Exxon Testing
of EDS Pilot
Plant
372 mg/1
1 ,800 mg/1
No data
No data
39,500 mg/1
No data
No data
No data
1 mg/1
No data
No data
2 mg/1
119,500 mg/1
175 mg/1
4 mg/1
40,000 mg/1
5,200 mg/1
No data
1 ,850 mg/1
350 mg/1
No data
No data
No data
No data
Data source: Table 1-^-1 of Reference 13 for Exxon design estimate, Table 6-20-of
Reference 37 for EPA testing results and Reference 23 for
Exxon testing results.
89
-------
TABLE 3-17. CHARACTERISTICS OF ATMOSPHERIC FRACTIONATOR
OVERHEAD DRUM WASTEWATER USED FOR PCTM
WASTEWATER TREATMENT TECHNOLOGY EVALUATION
(STREAM 152)
Contaminant
H£S
NH3
HC1
co2
Phenols
Organic Acids
Sulfate
F"
N03~
N02-
SCN"
COD
TDS
TSS
TOC
Alkal inity
(ppmw as CaCO~)
Total flow rate, kg/hr
3
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration,
ppmw*
4,200
5,400
1,270
330
18,400
3,130
67
1
0.15
Not Detected
2
112.700
185
4
35,150
5,500
Flow Rate
kg/hr
122
157
36.9
9.5
536
91.0
2
0.03
0.004
0
0.06
3,280
5.4
0.1
1,024
160
29,105
30.8
392
0.52
Source for
Selection of
Cone. Value
Design
Design
Design
Design
Design
Design
EPA Data
Exxon Data
EPA Data
EPA Data
Exxon Data
Avg. Exxon/EPA Data
Exxon Data
Exxon Data
Avg. Exxon/EPA Data
Exxon Data
* Note that mg/1 values in Table 3-16 have been converted to ppmw values by
using the density of the wastewater.
90
-------
Product Separation and
Purification - Area 3
Streams 152, 155, 157
whether design estimates, pilot plant data, or some combination were used to
arrive at the concentration for the species.
Table 3-18 presents the concentrations of trace metals in this stream as
determined by EPA and Exxon from pilot plant wastewater samples. The EPA and
Exxon samples were taken two weeks apart. The test results indicate that con-
centration values determined by EPA are higher than those by Exxon for certain
trace metals, and lower for other trace metals. Both sets of data, however,
indicate very low levels of trace metals for this wastewater stream.
In Table 3-19, preliminary results of organic analysis obtained by EPA
from the EDS pilot plant wastewater samples are presented (37). These results
indicate that most organics are present as phenols.
The atmospheric fractionator overhead drum wastewater will likely be com-
bined with other sour wastewater streams from process areas prior to treatment
in the sour water stripper/ammonia recovery system.
Vacuum fractionator wastewater (Streams 155 and 157) (Liquefaction product
separation - Area~3T ——
The vacuum fractionator wastewater is the combined wastewater from two
sources: 1) wastewater from the vacuum fractionator distillate drum, and 2)
steam ejector condensate from the vacuum fractionator. For the base case,
this wastewater stream is identified as Stream 155. For the MFS case, there
is an additional wastewater stream from the partial oxidation feed vacuum
fractionator. This additional wastewater stream is identified as Stream 157.
For the MFS case, the combined Stream 155/157 has the same flow rate and char-
acteristics as the single Stream 155 in the base case design.
The estimated characteristics of the vacuum fractionator wastewater are
presented in Table 3-20. The three sets of values presented represent Exxon
design estimates, and EPA and Exxon pilot plant test results, respectively.
In contrast to the atmospheric fractionator overhead drum wastewater, the
Exxon pilot test results show a higher H2S level and a lower phenol level when
91
-------
TABLE 3-18. CONCENTRATIONS OF TRACE METALS IN ATMOSPHERIC
FRACTIONATOR OVERHEAD DRUM WASTEWATER
(STREAM 152)
El ement
Aluminum
Antimony
Arsenic
Barium
Beryllium
Bismuth
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Selenium
Sil icon
Silver
Sodium
Strontium
Tin
Titanium
Tungsten
Uranium
Vanadium
Zinc
Al
Sb
As
Ba
Be
Bi
B
Cd
Ca
Cr
Co
Cu
Fe
Pb
Mg
Mn
Hg
Mo
Ni
P
K
Se
Si
Ag
Na
Sr
Sn
Ti
W
U
V
In
EPA Testing
of EDS
Pilot Plant*
0.024
<0.010
0.006
0.021
<0.003
<0.50
0.054
<0.025
2.61
<0.03
<0.02
<0.015
1.90
-------
TABLE 3-19. CONCENTRATIONS OF ORGANIC COMPOUNDS IN ATMOSPHERIC
FRACTIONATOR OVERHEAD DRUM WASTEWATER (STREAM 152)
Organic Compound Concentration
Class mg/1
Aliphatic Hydrocarbons 3,750
Ethers 560
Aldehydes and Ketones 210
Carboxylic Acids and Derivatives 120
Nitrites 700
Amines 53
Benzene and Substituted Benzene
Hydrocarbons 270
Phenols* 15,800
Heterocyclic Nitrogen Compounds 160
Heterocyclic Oxygen Compounds 22
Heterocyclic Sulfur Compounds 56
(Thiophenes)
Total 21 ,700
Data source: Table 6-18 of Reference 37. These results are preliminary.
* Breakdown for the phenols: 13,000 mg/1 phenol, 1,100 mg/1 o-cresol, 470
mg/1 m-cresol, 1,200 mg/1 p-cresol, and 27 mg/1 C? phenol.
93
-------
TABLE 3-20. CHARACTERISTICS OF VACUUM FRACTIONATOR
WASTEWATER (STREAMS 155/157) - THREE
DATA SOURCES
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Sulfate
Cl"
F"
N03~
N02"
SCN"
COD
TDS
TSS
TOC
Al kalinity
(mg/1 as CaC03)
Oil and Grease
Total N
Total S
Flow rate, kg/hr
3
Flow rate, m /hr
Temperature °K
Pressure, MPa
Exxon
Design
Estimate
8,550 ppmw
37.5 ppmw
18.7 ppmw
730 ppmw
4,910 ppmw
340 ppmw
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
4,839
4.9
317
0.74
EPA Testing
of EDS Pilot
Plant
15 mg/1
171 mg/1
<1 mg/1
No data
813 mg/1
No data
47 mg/1
<1 mg/1
<1 mg/1
0.18 mg/1
Not detected
Not detected
3,701 mg/1
402 mg/1
28 mg/1
1 ,329 mg/1
728 mg/1
1 ,154 mg/1
540 mg/1
473 mg/1
No data
No data
No data
No data
Exxon Testing
of EDS Pilot
Plant
29,229 mg/1
145 mg/1
No data
No data
455 mg/1
No data
No data
No data
<1 mg/1
No data
No data
3 mg/1
4,835 mg/1
135 mg/1
15 mg/1
1 ,250 mg/1
517 mg/1
No data
155 mg/1
27,500 mg/1
No data
No data
No data
No data
Data source: Table 1-X-l of Reference 13 for Exxon design estimate, Table 6-32
of Reference 37 for EPA testing results and Reference 23 for Exxon
testing results.
94
-------
Product Separation and
Purification - Area 3
Streams 155, 157
compared with the corresponding Exxon design estimates. The H2S level from
the EPA test results was 15 mg/1 and appears to be unreasonably low. A par-
tial explanation for the differences in concentration values is the possible
differences in process operating conditions and wastewater flow rates (per
unit coal input basis) between the Exxon design and the pilot plant. For
purposes of wastewater treatment technology evaluation, the Exxon design esti-
mates will be used wherever available. As discussed for Stream 152 previously,
this is primarily because the two sets of pilot plant data have not yet been
integrated into the EDS commercial plant design by Exxon. In Table 3-21, the
characteristics of Streams 155/157 selected for use in PCTM wastewater treat-
ment technology evaluation are presented. The values presented in this table
are primarily Exxon design estimate values, supplemented by values from the
Exxon and EPA test results only where necessary. In the latter case, Exxon
test results are preferred over EPA test results because Exxon samples could
be analyzed on site and hence were less subject to sample degradation problems.
In Table 3-22, the concentrations of trace metals in this stream deter-
mined by EPA and Exxon using pilot plant wastewater samples are presented. As
with other wastewater streams sampled, the EPA and Exxon samples were taken
two weeks apart. For most trace metals, the EPA test results indicate higher
concentration levels than the Exxon test results. Both sets of data, however,
indicate very low levels of trace metals for this wastewater stream.
In Table 3-23, preliminary results of organic analysis obtained by EPA
from the EDS pilot plant wastewater samples are presented. These results pro-
vide information on the types of organic compounds present in this wastewater
stream.
The vacuum fractionator wastewater will also likely be combined with other
sour wastewater streams from process areas prior to treatment. By comparison,
this wastewater stream is relatively small and contributes less than 2% of the
combined sour wastewater stream.
95
-------
TABLE 3-21. CHARACTERISTICS OF VACUUM FRACTIONATOR
WASTEWATER USED FOR PCTM WASTEWATER
TREATMENT TECHNOLOGY EVALUATION
(STREAMS 155/157)
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Sulfate
F~
N03"
N02~
SCN"
COD
TDS
TSS
TOC
Alkalinity
(ppmw as CaCO,,)
Total flow rate, kg/hr
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration,
ppmw*
8,550
37.5
18.7
730
4,910
340
48
<1
0.18
Not Detected
3
4,330
137
15
1,310
524
Flow Rate
kg/hr
41.4
0.2
0.1
3.5
23.8
1.6
0.2
0.005
0.0009
0
0.01
20.9
0.7
0.07
6.3
2.5
4,839
4.9
317
0.74
Source for
Selection of
Cone. Value
Design
Design
Design
Design
Design
Design
EPA Data
Exxon Data
EPA Data
EPA Data
Exxon Data
Avg. Exxon/EPA Data
Exxon Data
Exxon Data
Avg. Exxon/EPA Data
Exxon Data
* Note that mg/1 values in Table 3-20 have been converted to ppmv values by
using the density of the wastewater.
96
-------
TABLE 3-22. CONCENTRATIONS OF TRACE METALS IN VACUUM
FRACTIONATOR WASTEWATER (STREAMS 155/157)
Element
Aluminum
Antimony
Arsenic
Barium
Beryl! ium
Bismuth
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Selenium
Silicon
Silver
Sodium
Strontium
Tin
Titanium
Tungsten
Uranium
Vanadium
Zinc
Al
Sb
As
Ba
Be
Bi
B
Cd
Ca
Cr
Co
Cu
Fe
Pb
Mg
Mn
Hg
Mo
Ni
P
K
Se
Si
Ag
Na
Sr
Sn
Ti
W
U
V
Zn
EPA Testing
of EDS
Pilot Plant*
0.18
<0.010
0.008
0.0305
< 0.003
<0.50
0.265
<0.025
0.89
<0.03
<0.02
0.0435
0.47
<0.08
0.13
0.135
Not detected
<0.04
0.042
<0.040
0.285
0.004
6.02
<0.03
2.57
0.002
<0.03
0.0135
--
—
<0.01
0.0205
Exxon Testing
of EDS .
Pilot Plantt
0.082
< 0.035
(0.0328)
0.0153
< 0.0014
--
0.387
<0.0107
0.281
0.0164
(0.0099)
0.108
0.203
< 0.0181
0.124
0.0071
--
(0.0127)
0.107
<0.052
<0.0226
<0.0237
3.14
< 0.0058
1.09
0.0009
(0.0248)
<0.0012
<0.0678
<0.0328
(0.0112)
0.255
Data source:
Reference 24
Exxon testing
for EPA testing results,
results.
Reference 25 for
Not analyzed
* All EPA
' HIT C.. «,
values are in
units of mg/1
( ) Value may not be significant
97
-------
TABLE 3-23. CONCENTRATIONS OF ORGANIC COMPOUNDS IN VACUUM
FRACTIONATOR WASTEWATER (STREAMS 155/157)
Organic Compound Concentration,
Class mg/1
Aliphatic Hydrocarbons 290
Ethers 10
Aldehydes and Ketones 25
Nitrites 7.1
Amines 1.6
Thiols, Sulfides, and Disulfides 1.8
Benzene and Substituted Benzene
Hydrocarbons 110
Phenols* 280
Fused Polycyclic Hydrocarbons 64
Fused Non-Alternant Polycyclic
Hydrocarbons I 38
Heterocyclic Nitrogen Compounds 13
Heterocyclic Oxygen Compounds 180
Heterocyclic Sulfur Compounds (Thiophenes) 11
Total 1,040
Data source: Table 6-30 of Reference 37. These results are preliminary.
* Breakdown for the phenols: 12 mg/1 phenol, 13 mg/1 o-cresol, 54 mg/1
m-cresol, 26 mg/1 p-cresol, 75 mg/1 C~ phenol, 24 mg/1 C~ phenol, 15
mg/1 methyl naphthol, 19 mg/1 C~ naphthol, 40 mg/1 C3 naphthol, 2 mg/1
C. naphthol.
The only fused polycyclic hydrocarbons identified were: naphthalene,
methyl naphthalene, phenanthrene, methyl anthracene, methyl phenanthrene,
C? phenanthrene, and pyrene.
t The only fused non-alternant polycyclic hydrocarbons identified were:
fluorene, methyl fluorene, C,, fluorene, C. fluorene, and fluoranthene.
98
-------
Product Separation and
Purification - Area 3
3.3.3.1.3 Solid Waste Stream
There is no solid waste stream from liquefaction product fractionation.
3.3.3.2 Solvent Hydrogenation (Product Separation/Purification - Area 3)
In the solvent hydrogenation area, the spent solvent is hydrogenated for
reuse; also, liquid products are upgraded through further hydrogenation (see
Figure 3-5). The sidestreams from the atmospheric and vacuum fractionators
and the liquid distillate from the vacuum fractionator are blended. The
blended stream is pumped to process pressure, mixed with hydrogen makeup gas,
and fed to the gas-fired solvent hydrogenation feed preheat furnace. The mix-
ture is then passed through a catalytic bed of nickel-molybdenum in the sol-
vent hydrogenation reactor, which operates at an outlet pressure of 11.2 MPa
(1605 psig). Recycle quench gas is fed to the reactor in order to absorb the
exothermic heat of reaction and control the reactor temperature. The reactor
effluent is cooled and sent to the hot separator drum, which separates a vapor
and liquid phase at 622°K (660°F) and 11 MPa (1580 psig). The hot separator
vapor is cooled, and washed intermittently with water for corrosion control.
This mixture is then fed to the cold separator drum, where the hydrogenated
solvent, product liquids and water vaporized from the hot separator are con-
densed and collected, and the unreacted hydrogen and light hydrocarbons formed
in the reactor are removed as gases at 316°K (110°F) and 11 MPa (1540 psig).
The vapor from the cold separator drum (Stream 200) is scrubbed with DEA
for acid gas removal. A portion of the scrubbed gas is purged to cryogenic
hydrogen recovery. The remainder of the scrubbed gas is compressed. Most of
the compressed gas is recycled back to the process as quench gas, which is
added to the solvent hydrogenation reactor between reactor beds for tempera-
ture control. The rest of the compressed gas is heated and recycled as treat
gas to the solvent hydrogenation reactors. Ammonia formed in the process is
removed with the sour water from the solvent hydrogenation cold separator
(Stream 202). Water is formed in the hydrogenation of the spent solvent and
99
-------
Product Separation and
Purification - Area 3
Stream 203
liquid products due to the reaction between hydrogen and organically bound
oxygen; Stream 202 results from the condensation of this water and water pre-
sent in the feed to the solvent hydrogenation reactors. The solvent
hydrogenation cold separator sour water is sent to wastewater treatment.
The liquid streams from the hot and cold separator drums are sent to a
conventional steam stripped solvent fractionator. The products from this
solvent stripper include: a sour offgas stream (Stream 251) which consists
primarily of hydrogen and methane that will be combined with the atmospheric
and Flexicoker fractionator offgas (Streams 151 and 310) and fed to the DEA
scrubber for acid gas removal, a naphtha product sent to product recovery, a
recycle donor solvent product, and a LSFO product sent to liquid storage.
The overhead drum sour water (Stream 252) is sent to wastewater treatment.
This sour water results from the condensation of the stripping steam, and is
drawn off from the solvent fractionator overhead drum after separation from
the overhead gas and the naphtha product. As such, the sour water will con-
tain dissolved gases (H~S and NH~) extracted from the overhead gas as well as
organics extracted from the overhead gas and the naphtha product.
3.3.3.2.1 Gaseous Waste Stream
There is only one gaseous waste stream from solvent hydrogenation:
• Stream 203 - flue gas from solvent hydrogenation feed preheat
furnace.
Flue gas from solvent hydrogenation feed preheat furnace (Stream 203)
(Solvent hydrogenation - Area 3)
This flue gas stream is generated from the preheating of the feed to the
solvent hydrogenation reactor by the combustion of the low-Btu fuel gas from
the Flexicoking unit. Total heat provided by the fuel gas is 0.21 TJ/hr (199.8
MM Btu/hr)(13). The flow rate of the flue gas was calculated to be 3,864 kmol/
hr (53,810 SCFM). In Table 3-24, the emission factors used and the estimated
emission rates of pollutants for this flue gas stream are presented.
100
-------
TABLE 3-24. ESTIMATED UNCONTROLLED EMISSIONS FOR FLUE
GAS FROM SOLVENT HYDROGENATION FEED
PREHEAT FURNACE (STREAM 203)
POLLUTANT
Participate matter
N0x (as N02)
CO
Hydrocarbons
so2
EMISSION EMISSION
FACTOR* RATE
ng/J (Ib/MM Btu) kg/hr
2.1 - 6.4 (0.
52 - 99 (0.
7.3 -10.7 (0.
1.3 (0.
005-0.015) 0.45 - 1.4
12-0.23) 11 - 21
017-0.025) 1.5 - 2.3
003) 0.27
48 (0.11) 10
Emission factors for participate matter, NOX, and hydrocarbons are obtained
from AP-42 for natural gas combustion in industrial process heaters (21).
By comparison, Exxon estimated emission factors of 3.1 ng/J for particulate
matter, and 60 ng/J for NOX (20). The emission factor for CO is based on
7.3 ng/J from AP-42 and 10.7 ng/J from Exxon. The emission factor for SOp
is based on 83 ppmv total reduced sulfur in the low-Btu fuel gas (13).
101
-------
Product Separation and
Purification - Area 3
Streams 202, 252
3.3.3.2.2 Liquid Waste Streams
There are two aqueous waste streams from solvent hydrogenation:
• Stream 202 - solvent hydrogenation cold separator wastewater
• Stream 252 - solvent hydrogenation fractionator overhead drum
wastewater.
Solvent hydrogenation cold separator wastewater (Stream 202) (Solvent
hydrogenation - Area 3)
This wastewater stream is generated from separation of the hydrocarbon
liquid, sour water, and vapor in the cold separator drum. The estimated
characteristics of the cold separator wastewater are presented in Table 3-25.
These estimates were prepared during the Exxon commercial plant design, based
on analyses of wastewater samples obtained from several small pilot operating
units and computer process synthesis (no data on the species shown in Table
3-25 are available from the EDS pilot plant). In Table 3-26, the concentra-
tions of trace metals in this stream, as determined by Exxon tests of waste-
water samples from the 250 ton coal/day pilot plant, are presented. The
solvent hydrogenation cold separator wastewater will be combined with other
sour water streams before being sent to the sour water stripper/ammonia
recovery system for treatment.
Solvent hydrogenation fractionator overhead drum wastewater (Stream 252)
(Solvent hydrogenation - Area 3T
The estimated characteristics of this wastewater stream are presented in
Table 3-27. Because EPA and Exxon pilot plant test results are available for
this stream, these data are presented along with the Exxon design estimates
(which were prepared prior to the availability of pilot plant data). Again,
there are significant differences between the Exxon design estimates and the
pilot plant test results. These differences may be partially explained by
the possible differences in process operating conditions and wastewater
flow rates. According to Exxon (22), there may be four times more water
102
-------
TABLE 3-25. ESTIMATED QUALITY OF SOLVENT HYDROGENATION
COLD SEPARATOR WASTEWATER (STREAM 202)
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Total flow rate, kg/hr
3
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Exxon Design
Concentration,
ppmw
58,140
54,460
0
0
1,030
0
Estimate
Flow Rate,
kg/hr
730.2
684.0
0
0
12.9
0
12,561
13.4
317
10.7
Data source: Table 1-X-l of Reference 13 and Attachment 3 of Reference 20.
103
-------
TABLE 3-26. CONCENTRATIONS OF'TRACE METALS IN SOLVENT HYDROGENATION
COLD SEPARATOR WA3TEWATER (STREAM 202)
Element
Al uminum
Antimony
Arsenic
Barium
Beryl! ium
Bismuth
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Sel enium
Sil icon
Silver
Sodium
Strontium
Tin
Titanium
Tungsten
Uranium
Vanadium
Zinc
Al
Sb
As
Ba
Be
Bi
B
Cd
Ca
Cr
Co
Cu
Fe
Pb
Mg
Mn
Hg
Mo
Ni
P
K
Se
Si
Ag
Na
Sr
Sn
Ti
W
U
V
Zn
Exxon Testing
of EDS Pilot Plant,
ppmw
0.143
<0.0313
(0.0388)
0.0412
(0.0017)
--
31.6*
<0.0096
2.4
0.147
0.0204
0.182
1 .57
(0.0248)
0.132
0.0644
--
<0.0084
0.162
<0.0465
0.566
<0.0212
5.84
0.0155
1.24
0.0041
(0.0329)
<0.0011
<0.0606
<0.0293
(0.0113)
0.526
Data source: Reference 25.
Not analyzed
* Value out of range, needs further dilution
( ) Value may not be significant
104
-------
TABLE 3-27. CHARACTERISTICS OF SOLVENT HYDROGENATION FRACTIONATOR
OVERHEAD DRUM WASTEWATER (STREAM 252) - THREE DATA SOURCES
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Sul fate
Cl"
F"
N03~
N02"
SCN"
COD
TDS
TSS
TOC
Alkalinity
(mg/1 as CaC03)
Oil and Grease
Total N
Total S
Flow rate, kg/hr
3
Flow rate, m /hr
Temperature, °K
Pressure, MPa
Exxon
Design
Estimate
26,720 ppmw
18,640 ppmw
0
0
5,160 ppmw
0
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
No data
12,461
12.7
317
0.48
EPA Testing
of EDS Pilot
Plant
3,905 mg/1
Not detected
<1 mg/1
No data
6,852 mg/1
No data
51 mg/1
<1 mg/1
<1 mg/1
2.71 mg/1
Not detected
210 mg/1
33,709 mg/1
166 mg/1
7 mg/1
4,618 mg/1
15,681 mg/1
3,732 mg/1
4,040 mg/1
3,158 mg/1
No data
No data
No data
No data
Exxon Testing
of EDS Pilot
Plant
11,692 mg/1
7,500 mg/1
No data
No data
13,000 mg/1
No data
No data
No data
3 mg/1
No data
No data
2 mg/1
73,000 mg/1
30 mg/1
10 mg/1
16,000 mg/1
30,500 mg/1
No data
9,100 mg/1
11,000 mg/1
No data
No data
No data
No data
Data source: Table 1-X-l of Reference 13 and Attachment 3 of Reference 20 for
Exxon design estimate, Table 6-45 of Reference 37 for EPA testing
results and Reference 23 for Exxon testing results.
105
-------
Product Separation and
Purification - Area 3
Streams 252, 204
condensed (per unit coal input basis) in the pilot plant as in the Exxon
design estimate. The Exxon design estimate values will be used in the evalua-
tion of wastewater treatment technology wherever available. As discussed for
Stream 152 previously, this is primarily because the two sets of pilot plant
data have not yet been integrated into the EDS commercial plant design by
Exxon. Exxon and EPA pilot plant test results will only be used to supple-
ment Exxon design estimate values as necessary. In Table 3-28, the character-
istics of Stream 252 selected for use in the PCTM water treatment technology
evaluation are presented.
The concentrations of trace metals in Stream 252 are presented in Table
3-29. Exxon reported analysis results of individual samples collected from
two drums, whereas the EPA analysis results relate to the composite sample
from these two drums. Also, the Exxon and EPA samples were taken two weeks
apart. Both sets of pilot plant data indicate low levels of trace elements
in the wastewater.
In Table 3-30, preliminary results of organic analysis obtained by EPA
from the EDS pilot plant wastewater samples are presented. These results in-
dicate that most of the organics present are either phenols or aliphatic hydro-
carbons.
The solvent hydrogenation fractionator overhead wastewater will be com-
bined with other sour water streams prior to treatment in the sour water
stripper/ammonia recovery system.
3.3.3.2.3 Solid Waste Stream
There is only one solid waste stream from solvent hydrogenation:
• Stream 204 - spent solvent hydrogenation catalyst
Spent solvent hydrogenation catalyst (Stream 204) (Solvent hydrogenation -
Area 3)
The discharge rate of spent solvent hydrogenation catalyst is considered
proprietary by Exxon. However, in order to obtain an order-of-magnitude
106
-------
TABLE 3-28.
CHARACTERISTICS OF SOLVENT HYDROGENATION
FRACTIONATOR OVERHEAD DRUM WASTEWATER USED
FOR PCTM WASTEWATER TREATMENT TECHNOLOGY
EVALUATION (STREAM 252)
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Sulfate
F"
N03"
N02"
SCN"
COD
TDS
TSS
TOC
Alkalinity
(ppmw as CaC03)
Total flow rate, kg/hr
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration,
ppmw*
26,720
18,640
0
0
5,160
0
52
3
2.8
Not Detected
2
54,370
31
10
10,510
31 ,080
Flow Rate
kg/hr
332.9
232.2
0
0
64.3
0
0.6
0.04
0.03
0
0.02
677.5
0.4
0.1
130.9
387.3
12,461
12.7
317
0.48
Source for
Selection of
Cone. Value
Design
Design
Design
Design
Design
Design
EPA Data
Exxon Data
EPA Data
EPA Data
Exxon Data
Avg. Exxon/EPA Data
Exxon Data
Exxon Data
Avg. Exxon/EPA Data
Exxon Data
* Note that mg/1 values in Table 3-27 have been converted to ppmw values by
using the density of the wastewater.
107
-------
TABLE 3-29. CONCENTRATIONS OF TRACE METALS IN SOLVENT HYDROGENATION
FRACTIONATOR OVERHEAD DRUM WASTEWATER (STREAM 252)
El ement
Al umi num Al
Antimony Sb
Arsenic As
Barium Ba
Beryllium Be
Bismuth Bi
Boron B
Cadmium Cd
Calcium Ca
Chromium Cr
Cobalt Co
Copper Cu
Iron Fe
Lead Pb
Magnesium Kg
Manganese Mn
Mercury Hg
Molybdenum Mo
Nickel N1
Phosphorus P
Potassium K
Selenium Se
Silicon SI
Silver Ag
Sod 1 urn Na
Strontium Sr
Tin Sn
Titanium T1
Tungsten W
Uranium U
Vanadium V
Z1nc Zn
Data source: Reference
results.
Not analyzed
EPA Testing
of EDS Pilot
Plant*
0.425
<0.010
0.013
0.0615
<0.003
<0.50
1.899
0.025
2.10
<0.03
0.0545
<0.015
25.05
<0.08
0.205
0.225
Not detected
<0.04
0.057
<0.40
0.345
<0.001
12.8**
<0.03
3.40
0.004
<0.03
0.0165
--
—
<0.01
0.0605
24 for EPA testing results,
* All EPA values are 1n units of mg/1. EM data
f All Exxon values
are 1n units of ppmw
Exxon Testing of
EDS Pilot Plant +
Drum No. 1
0.316
<0.0322
<0.0218
0.0385
<0.0012
—
0.909
<0.0099
1.19
0.0237
(0.0046)
0.0985
0.948
<0.0166
0.222
0.0183
--
<0.0086
0.102
<0.0478
0.457
<0.0218
7.44
<0.0053
1.32
0.0037
<0.0166
<0.0011
<0.0624
<0.0302
(0.0195)
0.264
Reference 25 for
arc for Druns 1
Drum No. 2
0.0784
(0.0366)
(0.0426)
0.106
<0.0012
—
0.275
<0.0099
?.21
0.0207
0.0143
0.0935
1 .39
<0.0166
0.293
0.0121
--
<0.0086
0.10
<0.0478
0.675
<0.0218
2.59
<0.0053
1.98
0.0049
•eO.0166
-------
TABLE 3-30. CONCENTRATIONS OF ORGANIC COMPOUNDS IN SOLVENT
HYDROGENATION FRACTIONATOR OVERHEAD DRUM
WASTEWATER (STREAM 252)
Organic Compound Concentration,
Class mg/1
Aliphatic Hydrocarbons 1,880
Ethers 200
Aldehydes and Ketones 160
Nitrites 250
Thiols, Sulfides, and Disulfides 6.7
Benzene and Substituted Benzene
Hydrocarbons 200
Phenols* 6,910
Heterocyclic Nitrogen Compounds 220
Heterocyclic Oxygen Compounds 35
Heterocyclic Sulfur Compounds (Thiophenes) 280
Total 10,140
Data source: Table 6-42 of Reference 37. These results are preliminary.
* Breakdown for the phenols: 4,600 mg/1 phenol, 880 mg/1 o-cresol, 1,300
mg/1 p-cresol, and 130 mg/1 C« phenol.
109
-------
Product Separation and
Purification - Area 3
Stream 204
estimate of what quantity of spent catalyst might have to be dealt with, it
was assumed that Exxon's estimated storage requirement (6) corresponds to one
year of consumption. Based on this assumption, the consumption rate for the
solvent hydrogenation catalyst will be 739 Mg/yr for the nickel-molybdenum
catalyst and 82 Mg/yr for the inert balls. Thus, approximately 821 Mg of
spent solvent hydrogenation catalyst are generated each year. The composi-
tion for the spent catalyst is not well defined, but it is expected to con-
tain nickel, molybdenum, carbonaceous material, and sulfides.
3.3.3.3 Gas Treating (Product Separation/Purification - Area 3)
As shown in Figure 3-5, the gas treating area includes a low pressure
(L.P.) DEA absorber, a high pressure (H.P.) DEA absorber, and a regenerator
for H?S-rich DEA solution. In the Exxon design, the atmospheric fractionator
offgas (Stream 151), solvent stripper offgas (Stream 251), and Flexicoker
fractionator offgas (Stream 310) are combined as a low pressure gas stream
and treated for H^S removal in the same L.P. DEA absorber. The treated gas
is sent to the cryogenic hydrogen recovery section (Area 4) for recovery of
hydrogen, C,/C? light hydrocarbons, and C~ hydrocarbon liquids. The solvent
hydrogenation cold separator vapor (Stream 200), a high pressure gas stream,
is treated for H?S removal separately in a H.P. DEA absorber. As described
previously in Section 3.3.3.2, a portion of the treated gas is sent to the
cryogenic hydrogen recovery section (Area 4), a portion is recycled back to
the solvent hydrogenation reactor as quench gas for temperature control, and
the remainder is heated and recycled as hydrogen reactant for the solvent
hydrogenation reactions.
The hLS-rich DEA streams from the bottom of the L.P. and H.P. DEA absorb-
ers in Area 3 are combined with the H2S-rich stream from the bottom of the DEA
absorber for the liquefaction cold separator sour gas (Stream 104) in Area 2,
110
-------
Product Separation and
Purification - Area 3
Stream 508
and are fed to a common DEA regeneration unit in Area 3. The concentrated H2S-
rich acid gas (Stream 508) from the common DEA regenerator is sent to the sulfur
plant. The regenerated H^S-lean DEA solution is returned to the various indivi-
dual DEA scrubbers as absorbent.
3.3.3.3.1 Gaseous Waste Stream
There is only one gaseous waste stream from gas treating:
t Stream 508 - acid gas from DEA regenerator.
Acid gas from DEA regenerator (Stream 508) [Gas treating - Area 3)
The composition, flow rates, temperature, and pressure of the acid gas
from the common DEA regenerator (Stream 508) for both the base case and the
MFS case are presented in Table 3-31. With the exception of the COS composi-
tion, all values are based on design estimates provided by Exxon (20). Exxon
assumed that all of the COS present in the sour gas streams entering the DEA
scrubbers would be hydrolyzed by the DEA, and would thus appear in the DEA
regenerator offgas as H,,S. More typically, the less reactive secondary amines
such as DEA exhibit COS hydrolysis efficiencies on the order of 70 to 80%,
primarily through hydrolysis. Thus, approximately 25% of the COS fed to the
DEA scrubbers would be found in the acid gas from the DEA regenerator. The
COS concentration in the Stream 508 was estimated by assuming that it is ap-
proximately equal to the COS concentration in the acid gas from the DEA unit
in the SRC-II commercial plant design (26)f or about 510 ppmv. For both the base
case and the MFS case, the acid gas from tne DEA regenerator was estimated to
contain 64% H2S.
The characteristics of the sour gas streams entering the DEA scrubbers
are presented in Tables 3-32 and 3-33 for the base case and the MFS case,
respectively. These values were also based on design estimates provided by
Exxon (20). With the exception of Stream 310, the composition and flow rates
of the sour gas streams are identical for the base case and MFS case designs.
Ill
-------
TABLE 3-31. COMPOSITION AND FLOW RATES OF ACID GAS
STREAM FROM EDS COMMERCIAL PLANT PRODUCT
SEPARATION AND PURIFICATION OPERATIONS
(STREAM 508)
Component
COp, kmol/hr
hLS, kmol/hr
NH3, kmol/hr
COS, kmol/hr
HpO, kmol/hr
Total , kmol/hr
Temperature, °K
Pressure, MPa
Stream 508 - Acid Gas
Base Case
312.1
779.4
47.7
0.5
74.2
1,213.9
322
0.19
from DEA Unit
MFS Case
296.8
772.5
62.2
0.5
73.7
1,205.7
322
0.19
Data source: Attachment 3 of Reference 20 for all components except COS.
COS concentration was estimated using SRC-II commercial plant
design data (26).
112
-------
TABLE 3-32. COMPOSITION AND FLOW RATES OF SOUR GAS STREAMS TREATED
IN EDS COMMERCIAL PLANT DEA UNIT (ILLINOIS COAL BASE
CASE)
Component
H2, kmol/hr
C, , kmol/hr
C2, kmol/hr
C^, kmol/hr
C^, kmol/hr
Cc, kmol/hr
Cg , kmol/hr
N2, kmol/hr
CO, kmol/hr
C02, kmol/hr
H2S, kmol/hr
NH3, kmol/hr
COS, kmol/hr
H20, kmol/hr
Total , kmol/hr
Temperature, °K
Pressure, MPa
Stream 104
Liquefaction
Cold Separator
Sour Gas
6,629.6
4,576.0
871.2
324.9
90.1
23.0
26.9
0
60.8
177.8
334.2
0.6
1.6
9.2
13,125.9
317
12.7
Stream 151
Atmospheric
Fractionator
Offgas
690.3
788.5
339.1
208.1
100.5
40.4
93.2
0
24.2
92.1
370.6
8.0
0.2
50.0
2,805.2
317
0.48
Stream 200
Solvent
Hydrogenation
Cold Separator
Vapor
17,259.9
5,702.5
56.7
8.0
0.5
0.3
23.1
0
0
0
44.0
34.1
0
19.1
23,148.2
317
10.6
Stream 251
Solvent
Hydrogenation
Fractionator
Sour Gas
670.1
347.8
8.1
2.0
0.2
0.4
63.6
0
0
0
10.6
5.4
0
21.6
1,129.8
317
0.48
Stream 310
Flexicoking
Fractionator
Offgas
921.4
644.2
114.5
34.7
10.0
0
20.3
87.7
80.2
42.2
21 .0
0
0
37.2
2,013.4
317
0.48
Data source: Attachment 3 of Reference 20.
-------
TABLE 3-33. COMPOSITION AND FLOW RATES OF SOUR GAS STREAMS TREATED IN
EDS COMMERCIAL PLANT DEA UNIT (ILLINOIS COAL MFS CASE)
Component
HL, kmol/hr
C, , kmol/hr
C2, kmol/hr
Cg, kmol/hr
C., kmol/hr
C5, kmol/hr
Cc+, kmol/hr
b
N2, kmol/hr
CO, kmol/hr
C02, kmol/hr
HpS, kmol/hr
NH,, kmol/hr
0
COS, kmol/hr
HpO, kmol/hr
Total , kmol/hr
Temperature, °K
Pressure, MPa
Stream 104
Liquefaction
Cold Separator
Sour Gas
6,629.6
4,576.0
871 .2
324.9
90.1
23.0
26.9
0
60.8
177.8
334.2
0.6
1.6
9.2
13,125.9
317
12.7
Stream 1 51
Atmospheric
Fractionator
Offgas
690.3
788.5
339.1
208.1
100.5
40.4
93.2
0
24.2
92.1
370.6
8.0
0.2
50.0
2,805.2
317
0.48
Stream 200
Solvent
Hydrogenation
Cold Separator
Vapor
17,259.9
5,702.5
56.7
8.0
0.5
0.3
23.1
0
0
0
44.0
34.1
0
19.1
23,148.2
317
10.6
Stream 251
Solvent
Hydrogenation
Fractionator
Sour Gas
670.1
347.8
8.1
2.0
0.2
0.4
63.6
0
0
0
10.6
5.4
0
21 .6
1,129.8
317
0.48
Stream 310
Flexicoking
Fractionator
Offgas
454.1
317.0
56.5
17.1
5.2
0
9.4
45.5
40.4
26.9
15.4
14.7
0
18.7
1 ,020.9
317
0.48
Data source: Attachment 3 of Reference 20.
-------
Product Separation and
Purification - Area 3
Stream 508
As shown in Tables 3-32 and 3-33, StreamJ04 has a H2S/C02 ratio of 1.9:1
whereas the combined L.P. sour gas has a H^S/CCL ratio of 3.0:1. Carbon
dioxide is not present in Stream 200. Enrichment of the H^S present in these
sour gas streams by selective acid gas removal (AGR) processes prior to bulk
sulfur recovery, in order to increase the I^S/COg ratio is therefore not neces-
sary. The data presented in Tables 3-32 and 3-33 can be used to assess the
environmental and economic impacts of other acid gas removal systems.
3.3.3.3.2 Liquid Waste Stream
There is no liquid waste stream from gas treating,
3.3.3.3.3 Solid Waste Stream
There is no solid waste stream from gas treating.
3.3.3.4 Product Recovery (Product Separation/Purification - Area 3)
The product recovery operations shown in Figure 3-5 consist of a deethani-
zer, a debutanizer, and a C3/C4 splitter. The compressed gas from cryogenic
hydrogen recovery, the cryogenic liquid condensates (C- ), and the naphtha
distillate from the atmospheric fractionator, the solvent stripper, and the
Flexicoker fractionator are fed to the deethanizer. The offgas (C2~) from
the deethanizer is used as feed to steam reforming for hydrogen generation in
the base case, and sent to the cryogenic hydrogen recovery area for C,/C? gas
+
product in the MFS case. The deethanizer bottoms (Cg ) are fed to the debu-
tanizer where they are fractionated to yield a C3/C. overhead product and a
stabilized naphtha (Cr/400°F) bottoms. The naphtha product is cooled and sent
to storage. The C3/C. overhead product is treated for removal of trace quanti-
ties of hydrogen sulfide and mercaptans, if necessary, by conventional tech-
niques such as caustic scrubbing and water washing. In the current Exxon de-
sign, mercaptans present in the spent caustic are oxidized to disulfides, which
can then be separated as an oil phase and sent to the Flexicoking unit. The
regenerated caustic is reused for C3/C^ treating. The treated C3/C4 product
115
-------
Product Separation and
Purification - Area 3
is fed to the C3/C. splitter. In the C3/C. splitter, the C3/C. stream is
fractionated to yield a C., LPG overhead and a C. LPG bottoms product. The C.
LP6 is cooled and sent to storage. The C- LPG is dried and sent to storage.
3.3.3.4.1 Gaseous Haste Stream
There is no gaseous waste stream from product recovery.
3.3.3.4.2 Liquid Waste Stream
There is no liquid waste stream from product recovery.
3.3.3.4.3 Solid Waste Stream
There is no solid waste stream from product recovery.
116
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
3.3.4 Liquefaction Residue Processing/Hydrogen Production Area (Area 4)
Vacuum-bottoms slurry from the product separation and purification area
(Area 3) is utilized to generate additional liquid products (e.g., naphtha
and low sulfur fuel oil), fuel gas and either light gases or syngas (by partial
oxidation) for hydrogen production. In the MFS case, high Btu gas is also
produced for sale. The principal operations involved in processing vacuum-
bottoms are Flexicoking* and hydrogen generation. These operations are pre-
sented schematically in Figures 3-6 and 3-7 for the base and MFS cases,
respectively, and are described in the ensuing sections.
3.3.4.1 Flexicoking (Liquefaction Residue Processing/Hydrogen Production -
Area 4)
The Flexicoking unit converts vacuum-bottoms slurry through reactions with
steam and air into additional liquid and gas products, and generates low Btu
fuel gas for process consumption. Flexicoking is a low pressure process (<0.45
MPa; <65 psia) consisting of a fluid-bed reactor (coker), a heater, and a gasi-
fier. Vacuum-bottoms slurry is coked in the fluid-bed reactor section in the
presence of steam at temperatures of 755-920°K (900-1200°F) to yield liquid
and gas products and coke. Reaction heat is supplied by a circulating stream
of coke which transports heat from the heater to the reactor vessel. Tempera-
tures in the heater are maintained by circulating gas and solids from the gasi-
fier. Coke produced in the Flexicoking reactor circulates to the heater where
it is devolatilized to yield a light hydrocarbon gas and residual coke. The
residual coke is then fed to the gasifier, where it is reacted with air and
steam at 1100-1250°K (1500-1800°F) to form low Btu fuel gas.
Flexicoking is the service mark for a proprietary process developed by Exxon.
117
-------
FLEXI COKING
APS OFF-GAS
VACUUM
BOTTOMS
SLURRY
(AREA 31-
STEAM
HYDROGEN PRODUCTION
SOLVENT
FRACTIONATOR
OFF-GAS
RICH DEATO
REGENERATION
C3+TO
LIGHT ENDS
RECOVERY
SPENT ' ' SPENT
REGENERATION/
DECOMMISSIONING
OFF-GAS
HYDROGEN
PURGE FROM
LIQ AND S/H
HYDROTREATER
CATALYST
CO
AIR
STEAM
— e*
FLEXICOKER
REACTOR
SOUR
WATER
COKE
i
k
HEATER/
GASIFIER
1
0
G)
1
L
10-
=F.
\s
*— *
DEA
ABSORBER
(PART OF
AREA 3)
SHIFT
CONVER-
SION
<
SPENT
»
r
r
LYST-
b
BY
H>
-&
SWEE
GAS
PASS
DROG
C02 VENT
a>2
REMOVAL
L
T
EN
i
©)
WASTEWATER
DRY FINES
RECOVERY
— ft
CRYOGENIC
HYDROGEN
WASTEWATER
DECOMMISSIONING
OFF-GAS
M ETHAN-
ATION
SPENT
WET FINES
RECOVERY
STEAM
SPENT WASTEWATER
CATALYST
COMPRES-
SION
>• PROCESS HYDROGEN
AQUEOUS AMMONIA
SPENT CATALYST
WASTEWATER SPENT
DRYING AGENTS--
WATER
AGGLOMERATES
FUEL GAS
* H2S REMOVAL REPRESENTS A SULFUR EMISSION CONTROL OPTION
Figure 3-6. Block flow diagram for EDS liquefaction residue processing and
hydrogen production CArea 4) * base case
-------
FLEXICOKING
HYDROGEN PRODUCTION
C3+ TO LIGHT
ENDS RECOVERY
> HIGH BTU GAS
SPENT
DRYING AGENTS
SPENT
HYDROTREATER
CATALYST
^ FUEL GAS
I I
AGGLOMERATES
BED
COKE
TRANSIENT
DEAERATOR WASTE
VENT GAS FLASH GAS GAS
REGENERATION/
DECOMMISSIONING
OFF-GAS
ACID GAS
PARTIAL
OXIDATION
ACID GAS
REMOVAL
HYDROGEN ^
WASTEWATER
" H2S REMOVAL REPRESENTS A SULFUR EMISSION CONTROL OPTION
SOUR COM- SLAG
WATER BINED FILTRATE
SLAG
SPENT
CATALYST
Figure 3-7. Block flow diagram for EDS liquefaction residue processing and
hydrogen production (Area 4) * MF5 case
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Stream 304
Vapor products from the Flexicoking reactor are cooled and separated, and
heavy organics and solids are recycled to the reactor. The lighter organics
are fractionated to separate naphtha from low sulfur fuel oil and wash oil.
Olefinic coker gas from fractionation is cooled, compressed, and sent to hydro-
gen recovery. Coker gas (Stream 310) consists primarily of light hydrocarbons,
hydrogen and carbon oxides with lesser amounts of nitrogen, hydrogen sulfide
and ammonia. The composition of the coker gas has been presented in Tables
3-32 and 3-33.
Raw fuel gas from the heater/gasifier system is treated for particulate
removal. In the Exxon design, entrained particulate consisting of ash and
approximately 20% residual coke is removed by sequential dry and wet (venturi
scrubber) removal systems. Wet fines (Stream 303) are recovered as a 6% solids
slurry and dewatered to 40% solids prior to disposal. The sour fuel gas stream
(Stream 304) may be further treated for sulfur removal prior to use as plant
fuel.
Ash and residual coke (Stream 306) are removed on a continuous basis from
the heater/gasifier system at an ash-to-coke weight ratio of approximately two.
Chunk coke or agglomerates (Stream 313) are removed from the system for dis-
posal on a daily basis. There might also be air emissions associated with the
recovery of coke and coke fines from the Flexicoking operations, but the rates
of these emissions cannot be readily determined.
3.3.4.1.1 Gaseous Waste Streams
There are two gaseous waste streams from Flexicoking:
t Stream 304 - Flexicoking gasifier/heater sour fuel gas
• Stream 801 - transient waste gas from Flexicoking.
Flexicoking gasifier/heater sour fuel gas (Stream 304) (Flexicoking - Area 4)
This gaseous stream is generated in the gasifier vessel where coke formed
in the Flexicoking reactor is gasified with steam and air. The product sour
fuel gas, after passing through the heater and waste heat boilers, contains
120
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Stream 304, 801
0.4-0.5% sulfur as h^S and COS, as a result of the residual sulfur that was
present in the coke. With a heating value of 4.7 MJ/Nm3 (125 Btu/SCF, dry
basis), combustion of this sour fuel gas would result in S02 emissions of
approximately 2550 ng/J (5.9 Ib/MM Btu). Hence, removal of reduced sulfur
compounds from the sour fuel gas prior to combustion in process heaters and
boilers is a pollution control option that may be considered. Characteriza-
tion data for the sour fuel gas stream under the base case and MFS case de-
signs are presented in Table 3-34. These characteristics are based on EDS
design information provided by Exxon (20). The sour fuel gas is a large
stream with a low H2S/C02 ratio (<0.04) and cannot be conveniently treated
in DEA adsorbers because the resultant acid gas would not be sufficiently
concentrated as feed to Claus sulfur recovery plants.
Transient waste gas from Flexicoking (Stream 801) (Flexicoking - Area 4)
Transient waste gas is generated from Flexicoking operations during start-
up, shutdown, and upset conditions. For the three parallel Flexicoking units
in the base case design, it is assumed that transient conditions generating
waste gases would occur 30 times per year per unit due to unscheduled out-
ages (13), and up to 3 hours in duration each time. Also, outage for the
Flexicoking units will not occur simultaneously. Similar assumptions are made
for the two Flexicoking units in the MFS case design. The transient waste gas
from the Flexicoking unit is anticipated to be similar in composition and flow
rate to the Flexicoker fractionator off-gas (Stream 310). Characterization
data for this transient waste gas stream are presented in Table 3-35. The
estimated flow rate of this stream during periods of release is 671 kmol/hr
for the base case design and 511 kmol/hr for the MFS case design.
3,3.4.1.2 Liquid Waste Streams
There are three aqueous waste streams from Flexicoking:
t Stream 307 - Flexicoking recontacting drum wastewater
121
-------
TABLE 3-34. ESTIMATED COMPOSITION AND FLOW RATES
OF SOUR FUEL GAS FROM THE FLEXICOKER
HEATER/GASIFIER UNIT (STREAM 304)
Component
H?, kmol/hr
C, , kmol/hr
N?, kmol/hr
CO, kmol/hr
C0?, kmol/hr
H?S, kmol/hr
COS, kmol/hr
FLO, kmol/hr
Total, kmol/hr
Temperature, °K
Pressure, MPa
Stream 304 -
Base Case
9,821.7
831.3
25,757.1
9,834.9
6,343.0
229.2
5.9
1,958.2
54,781.3
316
0.2
Sour Fuel Gas
MFS Case
5,364.3
416.2
12,471.0
4,735.5
3,141.0
121.0
2.5
973.3
27,224.8
316
0.2
Data source: Characterization data are based upon EDS design information
from Attachments 3 and 4 of Reference 20.
122
-------
TABLE 3-35. ESTIMATED CHARACTERISTICS OF TRANSIENT
WASTE GAS FROM FLEXICOKING UNITS
(STREAM 801)
Component
H,
Cl
C2
C3
C4
C5
c6+
N
CO
co2
H2S
NH
H20
Total flow rate
Temperature, °K
Pressure, MPa
Base
Volume
Percent
45.8
32.0
5.7
1.7
0.5
0
1.0
4.4
4.0
2.1
1.0
0
1 .8
Case
Flow
Rate,
kmol /hr
307.1
214.7
38.2
11.6
3.3
0
6.8
29.2
26.7
14.1
7.0
0
12.4
671.1
317
0.48
MFS
Volume
Percent
44.5
31 .1
5.5
1.7
0.5
0
0.9
4.5
4.0
2.6
1.5
1 .4
1.8
Case
Flow
Rate,
kmol/hr
227.1
158.5
28.3
8.6
2.6
0
4.7
22.8
20.2
13.5
7.7
7.4
9.4
510.8
317
0.48
Data source: Characteristics of StreamSlO in Attachments 3 and 4 in Reference
20.
Estimated period of release: 30 occurrences per year for each Flexicoking
unit; up to 3 hours duration per occurrence.
123
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 307, 308
• Stream 308 - Flexicoking fractionator overhead drum wastewater
• Stream 312 - Flexicoking heater overhead drum wastewater.
Flexicoking recontacting drum wastewater (Stream 307) (Flexicoking - Area 4)
This wastewater stream is generated from compression of the Flexicoking
fractionator off-gas leaving the overhead drum to 0.48 MPa (55 psig), followed
by cooling to 317°K (110°F), partial condensation, and liquid phase separation
in the recontacting drum. Thus, Stream 307 is the additional water vapor con-
densed from the Flexicoking fractionator off-gas (at a higher pressure), after
an initial amount of water vapor is condensed and removed as Stream 308 (at a
lower pressure). Streams 307 and 308 both result from unreacted steam added
to the Flexicoking reactor. Streams 307 and 308 will contain dissolved acid
gases, ammonia, and organics due to intimate contact with the Flexicoking
fractionator off-gas. The hydrogen sulfide and ammonia result from inorgani-
cally bound sulfur and nitrogen in coal, which remained in vacuum bottoms and
were released during Flexicoking. Compared with Stream 308, Stream 307 is re-
latively low in organics because most soluble organics have been removed with
Stream 308. The estimated characteristics of this wastewater stream are pre-
sented in Table 3-36. These estimated characteristics are based on Exxon's
design information (13,20). The composition of this wastewater stream is the
same for the base case and MFS case designs. However, only half of the vacuum
bottoms slurry is sent to the Flexicoking unit in the MFS case design. There-
fore, the flow rate in the MFS case design is only half that of the base case
design. Stream 307 will likely be combined with other sour water streams
before being sent to wastewater treatment.
Flexicoking fractionator overhead drum wastewater (Stream 308) (Flexicoking -
Area.4)
This wastewater stream is generated from initial condensation of water
vapor and heavy organics present in the Flexicoking fractionator off-gas at
0.18 MPa (11 psig) and 317°K (110°F), followed by phase separation in the over-
head drum. As discussed for Stream 307 previously, Stream 308 results from
124
-------
TABLE 3-36. ESTIMATED QUALITY OF FLEXICOKING
RECONTACTING DRUM WASTEWATER
(STREAM 307)
Base Case
Contaminant
H2S
NH3
HC1
C09
c.
Phenols
Organic Acids
Flow rate, kg/hr
3
Flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration
ppmw
17,640
23,860
0
25,930
16
0
Flow
Rate,
kg/hr
23.1
31.3
0
34.0
9.5
0
1,312
1.4
316
0.5
MFS Case
Concentration Flow
ppmw Rate,
kg/hr
17,640 11.6
23,860 15.6
0 0
25,930 17,0
16 4,8
0 0
656
0,67
316
0,5
Data source: Table 1-X-l of Reference 13, Attachments 3 and 4 of Reference 20.
125
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 308, 312
condensation of unreacted steam that was added to the Flexicoking reactor.
The hydrogen sulfide and ammonia present in Stream 308 result from inorgani-
cally bound sulfur and nitrogen (which had remained in the vacuum bottoms)
released in the Flexicoking reactor. Stream 308 is higher in organics than
Stream 307 because most of the heavier organics in the Flexicoker fractiona-
tor overhead are condensed at the lower pressure and removed with Stream 308
as water-soluble phenols. The estimated characteristics of this wastewater
stream, based on Exxon design information, are presented in Table 3-37. Again,
the flow rate of this wastewater stream for the MFS design is half that for
the base case design, although the stream compositions are identical for the
two designs. Stream 308 will likely be combined with other sour water
streams before being 'sent to wastewater treatment.
n_exj_coking gasifier/heater overhead wastewater (Stream 312) (Flexicoking -
Area 4"j~
This wastewater stream results from condensation of the water vapor (un-
reacted steam fed to the gasifier) present in the sour fuel gas stream from
the Flexicoking gasifier/heater. As expected, the wastewater stream is fairly
well saturated with f-LS, NH3 and C02 as shown in the estimated characteristics
presented in Table 3-38, due to the presence of these species in the sour fuel
gas. Organic levels in this waste stream are low because the sour fuel gas
contains mostly lighter hydrocarbon gases. Similar to other wastewater streams
from Flexicoking, the flow rate of Stream 312 for the MFS design is half that
for the base case design. Stream compositions for the two designs are again
identical. Stream 312 will also be combined with other sour water streams
prior to wastewater treatment.
3.3.4.1.3 Solid Waste Streams
There are four solid waste streams from Flexicoking:
• Stream 302 - Flexicoking gasifier/heater dry fines
• Stream 303 - Flexicoking gasifier/heater wet fines
126
-------
TABLE 3-37. ESTIMATED QUALITY OF FLEXICOKING
FRACTIONATOR OVERHEAD DRUM WASTEWATER
(STREAM 308)
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Flow rate, kg/hr
Flow rate, m /hr
Temperature, °K
Pressure, MPa
Base Case
Concentration,
ppmw
1,770
2,140
145
2,620
3,890
0
99
Flow
Rate,
kg/hr
176.9
213.6
14.5
261.3
388.7
0
,910
100.9
316
0.9
MFS
Concentration
ppmw
1 ,770
2,140
145
2,620
3,890
0
Case
Flow
Rate,
kg/hr
88.5
106.8
7.3
130.6
194.4
0
49,955
50.4
316
0.9
Data source: Table 1-X-l of Reference 13, Attachments 3 and 4 of Reference 20.
127
-------
TABLE 3-38. ESTIMATED QUALITY OF FLEXICOKING HEATER
OVERHEAD DRUM WASTEWATER (STREAM 312)
Contaminant
H2S
NH3
HC1
CO,
Phenols
Organic Acids
Flow rate, kg/hr
3
Flow rate, m /hr
Temperature, °K
Pressure, MPa
Base Case
Concentration
ppmw
6,020
13,930
0
21,680
16
0
28
Flow
Rate,
kg/hr
171.0
395,5
0
615.5
0.5
0
,400
28.7
316
0.7
MFS Case
Concentration Flow
ppmw Rate,
kg/hr
6,020 85.5
13,930 197.8
0 0
21,680 307.8
16 0.2
0 0
14,200
14.3
316
0.7
Data source: Table 1-X-l of Reference 13, Attachments 3 and 4 of Reference 20.
128
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Stream 302
• Stream 306 - Flexicoking gasifier/heater bed coke
• Stream 313 - Flexicoking heater/reactor chunks/agglomerates.
Essentially all of the ash in the coal fed to the EDS commercial plant
will appear in these four streams for the base case design. In the MFS case,
about half of the ash will appear in these Flexicoking solid waste streams,
and the other half will appear as slag from the partial oxidation unit in the
hydrogen production area.
Flexicoking gasifier/heater dry fines (Stream 302) (Flexicoking - Area 4)
This solid waste stream results from the collection of particulate matter
from the Flexicoking heater overhead in tertiary cyclones,* The heater over-
head consists of a light hydrocarbon gas from the devolatilization of coke in
the heater, as well as low-Btu gas generated in the gasifier and passed upward
through the heater. Based on Exxon's estimate, the tertiary cyclones dry fines
are generated continuously at the rate of 137,950 Mg/yr for the base case design
and 65,670 Mg/yr for the MFS case design (13). These dry fines have a bulk
density of 0.61 Mg/m3 (38.0 lb/ft3), a particle density of 1.94 Mg/m3 (121.0
o
Ib/ft ), and contain approximately 80 wt % coal ash and 20 wt % carbonaceous
material (6,13). In Table 3-39, the results of leaching tests on Flexicoking
dry fines using the 12/18/1978 EPA Extraction Procedure (EP) are presented (20).
The analysis results show that concentrations of all elements in the leachate
are below limits set by RCRA criteria. RCRA testing will need to be conducted
on dry fines produced in commercial EDS facilities to confirm these results.
* These particulate controls are considered an integral part of the EDS process,
primarily because particulates need to be removed from the sour fuel gas
before it can be used as fuel in process heaters.
129
-------
TABLE 3-39. ELEMENTAL ANALYSES OF LEACHATES DERIVED FROM EPA DRAFT
EXTRACTION PROCEDURE APPLIED TO EDS FLEXICOKING
GASIFIER/HEATER DRY FINES* (STREAM 302)
Element
F"
N03"
Ag
Al
As
B
Ba
Be
Ca
Cd
Co
Cr
Cu
Fe
Hg
K
Mg
Mn
Mo
Na
Nb
Ni
p
Pb
Pt
Sb
Se
Si
Sn ft
Ti
Tl
U
V
Zn
Concentration in RCRA
Leachate, Criteria'1'
ppmw ppmw
0
<3
N
17
N
12
1
0
2
0
0
.3 140-240
4430
.D. (<0. 002)1 5.0
.5
.0. (<0.055) 5.0
.1
.76 100
.003
.060
.0425 1.0
.155
0.0042 5.0
0
3
0
3
328
2
N
22
N
1
0
[0
[0
No
.44
.54
.0004 0.2
.89
.3
.0. (<0.009)
.D. (<0.016)
.19
.3
.0462]** 5.0
.0364]
test
N.D. (<0.036) 1.0
25.5
0.889
0.0252
N.D. (<0.012)
N.D. U0.051)
N.D. (<0.0098)
1.68
Data source: Attachment 10 of Reference 20.
* Extraction procedure based upon draft EPA procedures proposed
September 12, 1978 and December 18, 1978. Results based upon solid wastes
obtained from runs *n Ill1n*1s coal EDS vacuum bottoms 1n small F1ex1cok1ng
units.
f RCRA criteria are 100 times the national Interim Primary Drinking
Water Standards.
t N.D. Indicates that the element was not detected. Detection
limits are provided 1n parentheses.
** Bracketed concentrations may not be analytically significant.
tt Values for tin may be too high due to the method of sample storage.
130
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 303, 306
Flexicoking gasifier/heater wet fines (Stream 303) (Flexicoking - Area 4)
This solid waste stream results in the Exxon design from the collection
of additional particulate matter from the Flexicoking heater overhead down-
stream of the tertiary cyclones. The particulate matter is collected in a
water slurry using a venturi scrubber,* and the slurry is subsequently de-
watered to generate a waste containing 40 wt % solids. Based on Exxon's esti-
mate, these wet fines are generated continuously at the rate of 344,870 Mg/yr
(40 wt % solids basis) for the base case design, and 164,160 Mq/yr (40 wt %
solids basis) for the MFS case design (13). The wet fines have the same par-
3
tide density as the dry fines (1.94 Mg/m ), and also contain approximately
80 wt % coal ash and 20 wt % carbonaceous material (6,13). The leaching char-
acteristics of the wet fines are expected to be similar to the leaching char-
acteristics of the dry fines. However, RCRA testing will need to be conducted
on wet fines produced in commercial EDS facilities to confirm this.
Flexicoking gasifier/heater bed coke (Stream 306) (Flexicoking - Area 4)
This is a waste stream that results from continuous purge of the recircu-
lating solids which circulate between the reactor and the heater and between
the gasifier and the heater. The purge is necessary to avoid buildup of metals
and ash in the system. The generation rate of the bed coke purge is estimated
to be 707,100 Mg/yr for the base case design and 363,030 Mg/yr for the MFS case
design (13). The bed coke purge contains approximately 61 wt % coal ash and
39 wt % carbonaceous material (13). The results of leaching tests on this waste
stream using the 12/18/1978 EPA Extraction Procedure (EP) are presented in Table
* These particulate controls are considered an integral part of the EDS process,
primarily because particulates need to be removed from the sour fuel gas
before it can be used as fuel in process heaters.
131
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 306, 313
3-40. These results show that the concentration levels of all elements in the
leachate from the bed coke purge are very low and well below RCRA criteria!
limits.
Flexicoking heater/reactor chunks/agglomerates (Stream 313) (Flexicoking -
Area "47
This is an intermittent waste stream generated daily from purge of coke
chunks/agglomerates from the Flexicoking heater and reactor to avoid buildup
of oversize coke. On annual basis, the generation rate of this solid waste
is estimated to be 19,860 Mg for the base case design and 9,660 Mg for the MFS
case design (13). The chunks/agglomerates have a bulk density of 1 Mg/m3
o
(65.0 Ib/ft ), and should have composition similar to the bed coke purge
(Stream 306). Particle size distribution for the chunks/agglomerates was esti-
mated by Exxon to be as follows: 50 wt % between 28 mesh and 1/4 in.; 40 wt %
between 1/4 in. and 1 in.; and 10 wt % greater than 1 in. (6). Leaching char-
acteristics of the chunks/agglomerates using the EPA Extraction Procedure (EP)
are presented in Table 3-41. As with other Flexicokinq solid wastes, the con-
centration levels of the pertinent trace elements, measured on chunks/agglo-
merates from experimental Flexicoking runs, are extremely low and well below
RCRA EP criteria. RCRA testing will need to be conducted on chunks/agglomerates
produced in commercial EDS facilities in order to confirm these results.
3.3.4.2 Hydrogen Production (Liquefaction Residue Processing/Hydrogen
Production - Area 4)
A major difference between the base and MFS cases is the method of hydro-
gen production. Both cases obtain a portion of the make-up hydrogen require-
ment by cryogenic separation of hydrogen from hydrogen-rich gas streams leaving
the liquefaction, solvent hydrogenation, product distillation, solvent frac-
tionation and Flexicoking areas. However, the balance of the hydrogen require-
ment is generated by steam reforming of light hydrocarbon gases in the base
case and partial oxidation of vacuum-bottoms slurry in the MFS case.
132
-------
TABLE 3-40. ELEMENTAL ANALYSES OF LEACHATES DERIVED FROM EPA DRAFT
EXTRACTION PROCEDURE APPLIED TO EDS FLEXICOKING
GASIFIER/HEATER BED COKE* (STREAM 306)
Element
F"
N03
Ag
Al
As
8
Ba
Be
Ca
Cd
Co
Cr
Cu
Fe
Hg
K
Mg
Mn
Mo
Na
Nb
Ni
P
Pb
Pt
Sb
Se
51
Snft
Ti
Tl
U
V
Zn
Concentration RCRA
in Leachate, Criteria
ppmw ppmw
0.94 140-240
<3 4430
N.D. (<0.0026)t 5.0
0.112
N.D. (<0.036) 5.0
3.89
0.032 100
N.D. (0.0009)
38.9
N.O. (<0.0066) 1.0
N.D. (<0.0061)
N.D. (<0.003) 5.0
0.47
0.0215
0.0009 0.2
5.41
1 .04
0.0587
N.D. (<0.019)
3.7
N.D. (<0.012)
N.D. (<0.01)
N.D. (<0.051)
N.D. (<0.019) 5.0
N.D. (<0.027)
0.0443
N.D. (<0.055) 1.0
2.89
N.D. (<0.024)
0.0095
N.D. (<0.027)
N.D. (<0.063)
0.0181
N.D. (<0.0035)
Data source: Attachment 10 of Reference 20.
* Extraction procedure based upon draft EPA procedures proposed
September 12, 1978 and December 18, 1978. Results based upon solid
wastes obtained from runs on Illinois coal EDS vacuum bottoms In
small Flex1cok1ng units.
RCRA criteria are 100 times the National Interim Primary
Drinking Water Standards.
I N.D. indicates that the element was not detected. Detection
limits are provided in parentheses.
tt
Values for tin may be too high due to the method of sample storage.
133
-------
TABLE 3-41. ELEMENTAL ANALYSES OF LEACHATES DERIVED FROM EPA DRAFT
EXTRACTION PROCEDURE APPLIED TO EDS FLEXICCKING
HEATER/REACTOR CHUNKS/AGGLOMERATES* (STREAM 313)
Element
F"
N03
Ag
Al
As
8
Ba
Be
Ca
Cd
Co
Cr
Cu
Fe
Hg
K
Mg
Mn
Mo
Na
Nb
Ni
P
Pb
Pt
Sb
Se
Si
Sn
Ti
Tl
U
V
In
Concentration RCRA
in Leachate, Criteria,
ppmw ppmw
0.17 140-240
<3 4430
N.D. (<0.002) 1 5.0
0.485
N.D. (<0.055) 5.0
0.765
0.0407 100
N.D. (<0.0004)
25.4
N.D. (<0.0048) 1.0
0.658
0.0019 5.0
N.O. (<0.0006)
2.19
N.D. (<0.0002) 0.2
1 .55
0.403
0.0496
N.D. (<0.009)
44
N.D. (<0.016)
0.236
[0.0941]**
N.D. (<0.023) 5.0
N.D. (<0.021)
N.D. (<0.076)
N.D. (<0.036) 1.0
0.979
N.D. (<0.013)
N.D. (<0.001)
N.D. (<0.012)
N.D. (<0.051)
N.D. (<0.0098)
N.D. (<0.0301)
Data source: Attachment 10 of Reference 20.
* Extraction procedure based upon draft EPA procedures proposed
September 12, 1978 and December 18, 1978. Results based upon solid
wastes obtained from runs on Illinois coil EOS vacuum bottoms 1n
small Flexlcoking units.
f RCRA criteria are 100 times the National Interim Primary
Drinking Water Standards.
£ N.D. indicates that the element was not detected. Detection
limits are provided in parentheses.
** Bracketed concentrations may not be analytically significant.
ft Values for tin may be too high due to the method of sample storage.
134
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
In the Exxon design for the EDS base case, shown in Figure 3-6, hydrogen
production consists of: a hydrogen recovery section, a hydrogen generation
section, and an ammonia synthesis section. The hydrogen recovery section cryo-
genically separates hydrogen, C,-C3 steam reformer feed, and C, product from
the high-pressure purge gases and low-pressure off-gases leaving the liquefac-
tion, solvent hydrogenation, production distillation, and Flexicoking areas.
The low-pressure off-gases, which contain significant quantities of H2S and COo,
are treated by low pressure DEA scrubbing in Area 3 prior to cryogenic separa-
tion. After DEA scrubbing, the low-pressure gases are compressed from 0.45 MPa
(50 psig) to 5.2 MPa (740 psig), and hydrotreated over nickel-molybdenum cata-
lyst to remove olefins present in the coker off-gas. Spent hydrotreater cata-
lyst (Stream 404) is removed periodically as a result of deactivation by foul-
ing (e.g., carbon deposition) or poisoning (e.g., chemisorption of residual
hydrogen sulfide present). The off-gases are then cooled to 297°K (75°F) which
results in the condensation of most of the water vapor present in knockout
drums (Stream 403). The high-pressure purge gases which come from the high-
pressure DEA scrubber in Area 3 are depressurized and cooled to 297°K (75°F),
and then combined with the cleaned, low-pressure off-gases. The combined gas
stream is dried with zeolites to remove the remaining water, hLS and C02 prior
to being sent to the cold box, where the cryogenic separation takes place.
Spent zeolites (Stream 405) are removed periodically as they become saturated
with water, H2S and CO,,.
Hydrogen generation in the EDS base case design involves steam reforming,
shift conversion, carbon dioxide removal and removal of residual carbon oxides.
Feed streams to the reformer are the C3~ hydrocarbons after hydrogen removal in
cryogenic hydrogen recovery, and the C-, and C2 hydrocarbons from light ends
recovery. These streams are passed through a ZnO sulfur guard for trace sulfur
removal prior to steam reforming. Reforming of the hydrocarbon feed is per-
formed over a nickel-urania catalyst at approximately 2 MPa (300 psia) and
135
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
1090°K (1500°F), reacting the steam and the light hydrocarbons to yield hydro-
gen and carbon oxides (CO and C02). Reaction heat is provided by burning low
sulfur fuel gas; waste heat is recovered in steam production for the reformer
feed and for other process uses. Additional hydrogen is produced by high tem-
perature (>622°K; >660°F) shift conversion (of CO + H20 to H? and C02) over an
iron oxide catalyst.
The gas following the reforming and shift reactions consists of hydrogen
with high levels of C02 and lower levels of CO, water vapor, and light hydro-
carbons. Bulk removal of carbon dioxide from the shift gas can be accomplished
by an acid gas removal (AGR) process; the Catacarb process is employed in the
current Exxon design. This process is a hot potassium carbonate process utiliz-
ing amine borates to increase the carbonate solution activity. A Catacarb or
alternative AGR unit will remove most of the carbon dioxide and water vapor
along with a small amount of hydrogen, carbon monoxide and methane. Any ammon-
ia which may be generated by reaction of hydrogen and nitrogen during hydrogen
generation will also be removed. Hence, regeneration of rich Catacarb (or alter-
native AGR) solution will produce a carbon dioxide rich off-gas containing water
vapor and small quantities of hydrogen, carbon monoxide, methane and possibly
ammonia.
Hydrogen rich gas from the base case carbon dioxide removal unit is com-
bined with the hydrogen from cryogenic separation prior to removal of trace
carbon oxides. Methanation of the combined hydrogen stream is employed to
remove trace carbon oxides by converting them to methane, through reaction
with H2 and typically over a nickel oxide catalyst at 588 to 638°K (599 to
689°F) and 3 MPa (420 psig) (33). In the methanation step, carbon oxide levels
are reduced to 10 ppmv or less to prevent catalyst poisoning in the subsequent
nitrogen removal/ammonia synthesis step. Methanation is followed by cooling
and compression, steps in which most of the water vapor is condensed and re-
moved in knockout drums (part of Stream 430).
136
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
In the EDS base design, a proprietary ammonia synthesis step is employed
to remove nitrogen present in the hydrogen-rich gas from methanation. This
nitrogen is introduced into the Flexicoking gasifier with the air feed, remains
with the C-,-Co fraction after the cryogenic separation step, and subsequently
enters the steam reformer and the methanator. In the ammonia synthesis section,
the compressed hydrogen-rich gas from methanation is further cooled, and addi-
tional compression condensate is removed by physical separation employing a
knockout drum (condensate removed as Stream 452) and with alumina drying agents.
Ammonia synthesis typically proceeds at about 620°K (550°F) and 13 MPa (1900
psia) over an iron oxide catalyst (33). Ammonia is removed from the product
gas stream by water scrubbing and sent to ammonia recovery for dehydration.
The purified, high pressure hydrogen following nitrogen removal is sent to the
liquefaction and solvent hydrogenation units as required.
In the Exxon design for the EDS MFS case, hydrogen production consists of
a hydrogen recovery section and a hydrogen generation section. The cryogenic
hydrogen recovery section for the MFS case is similar to that for the base case,
except that less off-gas from the Flexicoking reactor is processed (since only
half of the vacuum-bottoms slurry is being sent to Flexicoking) and the Cn/Cp
is recovered as high-Btu gas for sale and not as feed to the steam reformer.
Hydrogen generation for the MFS case involves syngas generation, shift
conversion, acid gas removal and compression. Approximately half of the vacuum-
bottoms slurry produced in the liquefaction/distillation units will be processed
into hydrogen for the process while the balance will be processed through Flexi-
coking to produce additional liquid and gas products.
Production of raw synthesis gas for MFS hydrogen generation will be based
upon coal gasification technology such as the Texaco partial oxidation process.
The Texaco gasification process involves a pressurized, downflow, slagging
gasifier which gasifies the vacuum-bottoms slurry with oxygen and steam. Pilot
units gasifying coal operate at pressures of 2.1 to 8.2 MPa (300 to 1200 psia);
137
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
available test data and design information indicate that pressures in this
range are appropriate for gasifying liquefaction residues similar to those
generated by the EDS process (12,27). Gasification temperatures are generally
above the ash fusion temperature (1500°K; 2300°F) to obtain high gasification
rates and minimize the quantities of undesirable by-products such as tars, oils
and phenols in the raw gas.
The gasifier is a refractory-lined carbon steel vessel which can roughly
be divided into two zones, a gasification zone and a quenching zone. During
gasification, the feed is partially reacted with oxygen, in the presence of
steam, to produce a raw gas consisting primarily of CO, FL, C02, and steam
contaminated by H2S and other reduced sulfur species (resulting from the large-
ly inorganic sulfur in the vacuum bottoms), ammonia and other trace species.
Quenching takes place in the lower portion of the reactor where the raw gas is
partially cooled and the slagged ash is solidified through contact with water
in a quench bath. The quenched gas is scrubbed with water to remove additional
char and impurities such as ammonia and formate prior to subsequent processing
(e.g., shift conversion). The quench water, after removal of the coarse slag
and part of the slag fines by clarification, is combined with the used scrubber
water. Most of this sour water is recycled as quench or scrubber water; how-
ever, a portion of the sour water is bled off, depressurized (Stream 441), and
sent to wastewater treatment, in order to control the buildup of soluble ash
constituents as well as organic and inorganic reaction products in the recir-
culating quench and scrubber water. When the blowdown stream is depressurized,
a flash gas is derived (Stream 440) which is sent to the sulfur recovery area
for processing.
Solids generated during gasification are slag and char. Quenched slag is
removed from the gasifier through an ash lock system, and sized into coarse
and fine fractions using a moving screen. Coarse slag is readily dewatered,
while slag fines contained in a slurry (after separation from the quench water
138
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
by clarification) require additional processing by thickening and filtration.
Slag fines are filtered in the slag handling area, combined with the coarse
slag and trucked to disposal. Filtrate from dewatering of the fine slag slurry
(Stream 443) is pumped to wastewater treatment for suspended solids removal.
Although not considered in the current EDS conceptual design, the small quanti-
ty of char containing approximately 6-12% unreacted carbon, may be recovered
from the recirculating quench and scrubber water by settling. Depending upon
the carbon content of the char, this material may be recycled to the gasifier,
added to the coal feed in the front end of the liquefaction plant, or fed to
the coal-fired boiler.
Carbon monoxide in the synthesis gas leaving the gasifier reacts with
steam to produce hydrogen and carbon dioxide by combined high and low tempera-
ture shift conversion. High temperature shift (in range of 590-750°K; 600-
890°F) proceeds in two stages over a cobalt-molybdenum catalyst. Gas leaving
the high temperature shift reactor is cooled in a waste heat boiler and fur-
ther shifted at low temperature (530-560°K; 490-550°F) over a cobalt-molybdenum
catalyst. Both the high and low temperature shift reactions are conducted in
the presence of hydrogen sulfide (hence, the term "sour shift") and sulfur-
tolerant catalysts are used. The gases leaving the shift reactors will con-
sist largely of H2, C02, steam, CO and contaminants such as H2S and ammonia.
In the Exxon design, removal of acid gases from the shift gas employs the
Catacarb process, as in the base case, although an alternative AGR process
could be considered. A Catacarb or alternative AGR unit will remove most of
the carbon dioxide, hydrogen sulfide, ammonia and carbonyl sulfide along with
a small amount of hydrogen, carbon monoxide and methane. Acid gas from regen-
eration of the Catacarb (or alternative AGR) solution is sent to sulfur recovery.
Purified hydrogen leaving the Catacarb absorber is cooled for condensation of
water vapor (part of Stream 430), combined with the hydrogen from cryogenic
recovery, compressed and sent to the liquefaction and solvent hydrogenation
units as required.
139
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
Methanation, which is included in the EDS base case design to remove resi-
dual carbon oxides and prevent poisoning of the ammonia synthesis catalyst,
has been deleted along with the ammonia synthesis section in the EDS MFS case
design. In the base case design, ammonia synthesis is utilized to purge nitro-
gen from the hydrogen recovery/generation system. In the MFS case design,
most of the nitrogen and carbon monoxide present in the feed stream to the
hydrogen recovery section are removed along with the C,/C~ product gas stream
in the cryogenic hydrogen separation step. Since most of the hydrogen for MFS
process use is generated by partial oxidation of the vacuums-bottom slurry with
steam and oxygen (no nitrogen introduced), the overall purity of the combined
hydrogen from hydrogen recovery and partial oxidation is sufficiently high to
be accepted for recycle to the liquefaction section. Thus, additional steps
to remove any residual nitrogen in the MFS case are not necessary.
3.3.4.2.1 Gaseous Waste Streams
There are five gaseous waste streams from the hydrogen plant for the base
case design, and six gaseous waste streams from the hydrogen plant for the MFS
case design. Only one of these gaseous waste streams is common to both designs.
These waste streams are:
• Stream 438 - deaerator vent gas from hydrogen generation
• Stream 426 - vent gas from COp removal (base case only)
• Stream 434 - flue gas from reformer furnaces (base case only)
• Stream 446 - regeneration/decommissioning off-gas from the reformer
catalyst (base case only)
• Stream 448 - decommissioning off-gas from the methanation catalyst
(base case only)
• Stream 428 - acid gas from acid gas removal by Catacarb
(MFS case only)
• Stream 440 - flash gas from the partial oxidation unit (MFS
case only)
t Stream 449 - regeneration/decommissioning off-gas from the high
temperature shift catalyst (MFS case only)
140
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
Stream 438
t Stream 450 - regeneration/decommissioning off-gas from the low
temperature shift catalyst (MFS case only)
• Stream 802 - transient waste gas from partial oxidation unit
(MFS case only).
Different gaseous waste streams are generated from the two EDS designs because
of the major differences in the design of the hydrogen production plant. A
less obvious case, however, is the absence of the regeneration/decommissioning
off-gas from shift catalyst for the EDS base case design. This is because two
different types of shift catalysts are used for the two EDS designs.
The high temperature and low temperature shift catalysts in the EDS MFS
case design are sulfided cobalt-molybdenum catalysts because the shift reactions
are carried out in the presence of hydrogen sulfide. These catalysts need to
be regenerated for removal of sulfides, so that plant personnel can have safe
access to shift converters for repairs and maintenance. Shift catalysts in
the base case design (iron oxide catalyst) is not sulfided and generally not
regenerated for process or safety reasons. Thus, there is no regeneration/
decommissioning off-gas from shift catalyst for the base case design.
Deaerator vent gas from hydrogen generation (Stream 438) (Hydrogen production -
Area 4)
Steam is needed for the steam reformer in the base case design and for
the partial oxidation unit in the MFS case design. The feedwater to the boilers
generating this steam includes in both cases condensed water from elsewhere in
the plant, and therefore needs to be deaerated. The deaerator in the hydrogen
production section serves two purposes: to increase boiler feedwater temperature
by direct contact with low pressure exhaust steam, and to remove most unde-
sirable dissolved gases from boiler feedwater due to its prior use. Stream
438 is the small amount of steam (about 1% of the boiler feedwater supplied)
and non-condensible gases that escape through the deaerator vent. For the
base case design, the boiler feedwater to the deaerator (to generate steam
141
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
Stream 438, 426
for the steam reformer) includes approximately 39% condensate from the high
temperature shift gas and 61% demineralized water. For the MFS case design,
the boiler feedwater to the deaerator (to generate steam for the partial oxi-
dation unit) includes approximately equal portions of condensate from the low
temperature shift gas and demineralized make-up water. Thus, the deaerator
vent gas is expected to contain traces of shift gas components that are dis-
solved in the condensates. The deaerator vent gas should consist primarily
of water vapor with a small quantity of carbon dioxide and traces of light
hydrocarbons in the base case, and additional H2S and NH. in the MFS case,
although detailed characterization data are not available. For both the base
case and MFS case designs, the deaerator vent gas is also estimated to contain
0.6 ppmv CO, with total CO emissions of less than 0.5 kg/hr (20). Assuming
that the flow rate of this vent gas is approximately equal to 1% of the boiler
feedwater supplied to the deaerator, the deaerator vent gas is generated at the
rate of 6.5 kmol/hr for the base case design and 6.2 kmol/hr for the MFS case
design.
Vent gas from CO,, removal (Stream 426) (Hydrogej^jpj^oducjHor^j^j^re a_ _4_)
The Catacarb process is used for the bulk removal of carbon dioxide from
the gas leaving the shift reactor in the base case design, although alternative
AGR systems could be considered. In the Catacarb absorber, most of the carbon
dioxide and water vapor in the shift gas is removed along with a small amount
of hydrogen, carbon monoxide, and methane. Vent gas (Stream 426) is generated
from the regeneration of the Catacarb solution (found only in the base
case design). Stream 426 will consist primarily of carbon dioxide and water
vapor, along with 1.9% hydrogen, 370 ppmv methane and 160 ppmv carbon monoxide.
Any ammonia which may be generated by reaction of hydrogen and nitrogen
during hydrogen generation would also be present in the vent gas. Charac-
terization data for this waste stream are presented in Table 3-42.
142
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TABLE 3-42. ESTIMATED COMPOSITION AND FLOW RATES
OF VENT GAS FROM C0? REMOVAL
(STREAM 426)*
Component Base Case
H2, kmol/hr 118.1
Cv kmol/hr 2.2
N2, kmol/hr 0
CO, kmol/hr 0.96
C02, kmol/hr 4,782.7
H2S, kmol/hr 0
COS, kmol/hr 0
H20, kmol/hr 1 ,196.0
Total, kmol/hr 6,100.0
Temperature, °K 339
Pressure, MPa 0.1
Data source: Data for C02 and H2 are obtained from Attachment 3 of
Reference 20, composition of other components is estimated
based upon available data for hot carbonate process in
Reference 28.
* Stream 426 is generated only from the base case design.
143
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 434, 446
Flue gas from reformer furnaces (Stream 434) (Hydrogen production - Area 4)
This flue gas stream is generated from supplying heat to the steam re-
formers by the combustion of the low-Btu fuel gas provided from the Flexicok-
ing gas, and applies only to the base case design. Total heat provided by
the fuel gas is 3.165 TJ/hr (3000 MM Btu/hr). The low-Btu fuel gas contains
80 ppmv HpS and 3 ppmv COS (13). Assuming combustion with 20% excess air,
the flow rate of the flue gas generated was calculated to be 58,023 kmol/hr
(808,000 SCFM). In Table 3-43, the emission factors used and the estimated
emission rates of pollutants for this flue gas stream are presented.
Regeneration/decommissioning off-gas from the reformer catalyst (Stream 446)
'(Hydrogen production - Area 4)
In steam reforming, carbonaceous deposits are gradually formed on the
surface of the nickel-urania catalyst. The continuing accumulation of the
carbonaceous deposits reduces the activity of the catalyst to the point that
it must be regenerated. It is assumed that once a year on the average, the
reformer catalyst will be regenerated by a mixture of steam and air. Thus,
the regeneration/decommissioning off-gas from the nickel-urania reformer
catalyst will be intermittent in nature, and applies only to the base case
design. No data are available regarding the composition of this off-gas;
however, it is anticipated to consist primarily of steam and nitrogen with
small amounts of CO and particulate matter because of the steam-carbon reac-
tion and catalyst carryover. Small quantities of Ni (CO), may also be present
in the off-gas. Estimated generation rate of this off-gas, based on typical
catalyst regeneration off-gas values (29), is 6,800 kmol/hr. The average
emission frequency for this waste stream is once a year, with an average emis-
sion duration of 24 hours.
144
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TABLE 3-43. ESTIMATED UNCONTROLLED EMISSIONS FOR
FLUE GAS FROM REFORMER FURNACES
(STREAM 434)*
Pollutant
Particulate Matter
N0x (as N02)
CO
Hydrocarbons
so2
Emission
Factor t
ng/J (Ib/MM Btu)
2.1 - 6.4 (0.005-0.015)
52 - 99 (0.12-0.23)
7.3 - 10.7 (0.017-0.025)
1.3 (0.003)
48 (0.11)
Emission
Rate
kg/hr
6.8 - 20.4
163 - 313
23 - 34
4.1
150
* Stream 434 is only
generated from the base case design.
L. 111 I O O I VS I I IU\*wL/l O I V I L/UI l>lx*>UIUl*L HIUI^W^.1 ^ 11 VJ y 9 LA I I VJ I I y v.j | u W IA I LJU I I O U I *— WUirfUIII^-*-*
from AP-42 for natural gas combustion in industrial process heaters (21).
By comparison, Exxon estimated emission factors of 3.1 ng/J for particulate
matter, and 60 ng/J for NOX (20). The emission factor for CO is based on
7.3 ng/J from AP-42 and 10.7 ng/J from Exxon. The emission factor for S02
is based on 83 ppmv total reduced sulfur in the low-Btu fuel gas (13).
145
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 448, 428
Decommissioning off-gas from the methanation catalyst (Stream 448) (Hydrogen
production - Area 4)
The nickel catalyst used in methanation is pyrophoric and may lead to
spontaneous ignition in the reduced state. Prior to disposal, the nickel
catalyst would be oxidized by air, with steam added for temperature control.
It is assumed that methanation catalysts will be decommissioned once every
four years. Thus, the decommissioning off-gas from the methanation catalyst
will be intermittent in nature. This stream is found only in the base case
design. Based upon composition of the feed gas to the methanation unit and
typical catalyst decommissioning procedures, this off-gas is expected to con-
sist primarily of steam and nitrogen with small amounts of particulate matter,
and free of sulfur and carbon oxides. This is because sulfur species have
been removed prior to methanation and carbon deposition on catalysts is not
known to be a problem in methanation. Although there are no supporting data,
small quantities of Ni (C0)4 may also be present in the off-gas. Using typi-
cal catalyst regeneration off-gas flow rate values (29), Stream 448 was esti-
mated to be generated at the rate of approximately 5,000 kmol/hr. The average
emission frequency of this waste stream is once every four years, with an aver-
age emission duration of 24 hours.
Acid gas from acid gas removal (Stream 428) (Hydrogen production - Area 4)
The Catacarb process is used for the removal of acid gases from the shift
gas in the MFS design, although alternative acid gas removal techniques might
also be considered for this application. Because the H2~rich syngas produced
by partial oxidation of the sulfur- and nitrogen-containing vacuum bottoms
slurry is sent to the shift reactors without extensive gas cleaning, the shift
gas will contain H2S and NH3 as well as C^. This gaseous waste stream results
from regeneration of the Catacarb solution, and applies only to the MFS case
design. The estimated composition of the shift gas that is fed to the Catacarb
unit is presented in Table 3-44. These data may be used to evaluate alternative
146
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TABLE 3-44. ESTIMATED COMPOSITION AND FLOW RATES
OF SHIFT GAS TO THE ACID GAS REMOVAL
UNIT IN MFS CASE DESIGN
Shift Gas to
Component Acid Gas Removal*
Hp, kmol/hr
C, , kmol/hr
Np, kmol/hr
CO, kmol/hr
C02, kmol/hr
HpS, kmol/hr
NH3, kmol/hr
COS, kmol/hr
H20, kmol/hr
HCN, kmol/hr
Total , kmol/hr
Temperature, °K
Pressure, MPa
18,506.7
90.0
122.3
263.2
12,392.9
137.4
8.9
0.6
1,060.6
0.02
3,258.6
394
6.2
Data source: Estimated by using test and design data from References
12, 20, 26 and 27.
* Composition of the shift gas after cooling to 394 °K and condensation
of water vapor present in the hot shift gas.
147
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 428, 440, 449
acid gas removal (AGR) systems. Assuming the Catacarb process is the AGR tech-
nique employed, the composition of the acid gas stream from regeneration of
the Catacarb solution has been estimated based upon Exxon design estimates and
test data from tests by others on the Catacarb system (20,26,27,28). The
estimated characteristics of this acid gas stream are presented in Table 3-45.
These estimated characteristics show that Stream 428 is expected to contain
1% H2S, 670 ppmv NHg, 60 ppmv CO, and 40 ppmv COS.
Flash gas from the partial oxidation unit (Stream 440) (Hydrogen production -
Area 4j
Flash gas from the partial oxidation unit is generated on a continuous
basis from the depressurization of the bleed stream in the recirculating quench
and scrubber water loop. The dissolved gases (H2S, NH3, H2, CO, CO,,, COS and
CH^) build up at the elevated gasifier pressure in the recirculating water loop,
and are partially released when the bleed stream is depressurized. Assuming that
the Texaco gasifier is employed for the partial oxidation of the vacuum-bottoms
slurry, the flash gas will consist primarily of H2, CO, C02 with 4.4% H2S, 0.12%
COS, and 150 ppmv NH~ (27). Composition estimates for this flash gas stream,
as presented in Table 3-46, are based upon Texaco pilot plant, tests gasifying
SRC-II vacuum bottoms from Kentucky 9/14 coal. No characterization data for
this stream using EDS vacuum-bottoms slurry and Illinois No. 6 coal are publicly
available as of this writing.
Regeneration/decommissioning off-gas from the high temperature shift catalyst
(Stream 449) (Hydrogen production - Area 4)'
As discussed previously in the introduction to this section, shift cata-
lysts in the MFS case design are of the sulfided form. These catalysts require
periodic regeneration for removal of deposited carbon and dusts. Sulfide re-
moval is also necessary to provide safe access to the shift converters for re-
pairs and maintenance. The shift units in an EDS plant would be modular with
several parallel trains. During regeneration, one or more trains would be
148
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TABLE 3-45. ESTIMATED COMPOSITION AND FLOW RATES
OF ACID GAS FROM ACID GAS REMOVAL UNIT
(STREAM 428)*
Component
HL, kmol/hr
C, , kmol/hr
CO, kmol/hr
C02, kmol/hr
H2S, kmol/hr
NH3, kmol/hr
COS, kmol/hr
H20, kmol/hr
Total , kmol/hr
Temperature, °K
Pressure, MPa
Stream 428
MFS Case
112.9
0.3
0.8
12,130.1
137.1
8.9
0.5
913.0
13,303.6
316
0.1
Data source: C02, H2S and 1^0 composition from Attachment 4 of
Reference 20, composition of other components estimated
using shift gas composition (Table 3-44) and Catacarb
process model (28).
* Stream 428 is only generated from the MFS case design.
149
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TABLE 3-46. ESTIMATED COMPOSITION AND FLOW RATES
OF FLASH GAS FROM PARTIAL OXIDATION
UNIT (STREAM 440)*
Component
\\2* kmol/hr
C, , kmol/hr
N?, kmol/hr
CO, kmol/hr
C0?, kmol/hr
I-LS, kmol/hr
NH3, kmol/hr
COS, kmol/hr
H20, kmol/hr
Total , kmol/hr
Temperature, °K
Pressure, MPa
Stream 440
MFS Case
61 .3
0.08
1.4
77.7
82.7
11.2
0.04
0.3
19.0
253.7
322
0.2
Data source: Pilot plant tests performed with SRC-II residue using
Kentucky 9/14 coal (27).
* Stream 440 is only generated from the MFS case design.
150
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Liquefaction Residue Processing/
Hvdrogen Production - Area 4
Streams 449, 450,802
taken off line for regeneration while others remain in service. It is assumed
that regeneration of each train of high temperature and low temperature shift
catalysts will be conducted once a year. Regeneration is by reaction with
steam and air, driving off SOg. Thus, emissions from regeneration would be
intermittent in nature, depending on the number of trains and the exact regen-
eration schedule. The duration of regeneration may range from 12 hours to 72
hours, depending on which shift stage is being regenerated. Off-gas from re-
generation/decommissioning of high and low temperature shift catalyst (Streams
449 and 450) would consist primarily of steam with 6% N2, 1% S02 and 0.5% C02 (29)
Characterization data for Stream 449 and the regeneration/decommissioning off-
gas from low temperature shift catalyst (Stream 450) are presented in Table 3-47.
Data on the characteristics of the individual waste streams are not available.
The average emission frequency for Streams 449 and 450 is once a year, with an
average emission duration of 24 hours.
Regeneration/decommissioning off-gas from the low temperature shift catalyst
(Stream 450) (Hydrogen production - Area 4)'
The characteristics of this waste stream have been discussed in conjunc-
tion with Stream 449.
Transient waste gas from partial oxidation units (Stream 802) (Hydrogen
production - Area 4)
Transient waste gas is generated from the partial oxidation units in the
MFS case design. It is assumed that transient conditions generating waste gases
would be expected only once a year, and only to one of the units and up to a
day in duration (13). The transient waste gas from the partial oxidation unit
is anticipated to be similar in composition to the quenched syngas from the
unit. Estimated characteristics for this waste stream, based upon EDS design
data and data for the Texaco gasifier when processing SRC-II vacuum flash drum
bottoms from Kentucky No. 9/14 coal (20,27), are presented in Table 3-48. The
estimated flow rate for this waste stream is 12,120 kmol/hr.
151
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TABLE 3-47. ESTIMATED COMPOSITION AND FLOW RATES
OF REGENERATION/DECOMMISSIONING OFF-GAS
FROM SHIFT CATALYST (STREAMS 449 AND 450)*
Streams 449/450
Component MFS Case
N2, kmol/hr 1,357.6
C02, kmol/hr 111.3
S02, kmol/hr 244.8
H20, kmol/hr 20,540.9
Total, kmol/hr 22,254.6
Particulate matter, kg/hr 608
Temperature, °K No data
Pressure, MPa 0.1
Data source: Off-gas composition is based upon estimates provided in permit
applications for the ANR Synthetic Natural Gas Plant (29)
* Streams 449/450 are generated only from the MFS case design.
Intermittent stream: average occurrence of once a year, 24 hours per
occurrence.
152
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TABLE 3-48. ESTIMATED CHARACTERISTICS OF TRANSIENT
WASTE GAS FROM PARTIAL OXIDATION UNITS
(STREAM 802)*
Component
H2
Cl
CO
co2
NH3
COS
H20
HCN
HC02H
Total flow rate
Temperature, °K
Pressure, MPa
Volume Percent
in Waste Gas
20.2
0.2
17.7
7.9
0.3
170 ppmv
250 ppmv
53.4
8 ppmv
70 ppmv
Flow Rate,
kmol/hr
2,454.5
24.3
2,150.7
959.9
36.5
2.1
3.1
6,488.6
0.1
0.9
12,120.7
No data
No data
Data source: Estimated from EDS design data (20) and data for the Texaco
gasifier when processing SRC-II vacuum flash drum bottoms
from Kentucky No. 9/14 coal (27).
* Stream 802 is generated only from the MFS case design.
Intermittent stream: average occurrence of once a year, and up to 24 hours
per occurrence.
153
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
Stream 403
3.3.4.2.2 Liquid Waste Streams
There are five aqueous waste streams from the hydrogen plant for the base
case design, and four aqueous waste streams from the hydrogen plant for the
MFS case design. Only two of the aqueous waste streams are common to both
designs. These waste streams are:
• Stream 403 - knockout drum wastewater from cryogenic hydrogen
recovery
• Stream 430 - blowdown and knockout drum wastewater from hydrogen
generation
• Stream 431 - Catacarb overhead receiver wastewater (base case only)
• Stream 451 - aqueous ammonia from ammonia synthesis (base case only)
0 Stream 452 - knockout drum wastewater from ammonia synthesis (base
case only)
0 Stream 441 - sour water from the partial oxidation unit (MFS case
only)
• Stream 443 - slag filtrate from the partial oxidation unit (MFS
case only).
Knockout drum wastewater from cryogenic hydrogen recovery (Stream 403)
T~Hydrogen production - Area 4)
For both the base case and the MFS case designs, the cryogenic hydrogen
recovery feed is comprised of hydrogen-rich purge gases from the high-pressure
liquefaction (Area 2) and solvent hydrogenation (Area 3) separators, and off-
gases from the low-pressure atmospheric fractionator distillate drum (Stream
151, Area 3), solvent stripper (Stream 251, Area 3), and Flexicoking unit
reactor system (Stream 310, Area 4). The off-gases are treated by DEA scrub-
bing, compressed to 5.2 MPa (740 psig) , and cooled to 297°K (75°F).
These off-gases will contain moisture because of moisture and oxygen present in
coal feed, excess steam added to the Flexicoking reactor, and possibly water
evaporated from wash water and scrubbing solutions in the processing sequence.
154
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Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 403, 430
The cooling sequence condenses out most of the moisture in knockout drums as
Stream 403. Detailed characterization data for this wastewater stream are not
available, although traces of hydrogen sulfide, ammonia, carbon dioxide, phenols,
and organic acids may be present, as shown in Table 3-49. The estimated genera-
tion of Stream 403 is 1,334 kg/hr (1.3 m3/hr) for both the base case and the
MFS case design.
Slowdown and knockout drum wastewater from hydrogen generation (Stream 430)
(Hydrogen production - Area 4)
Steam is used as feed to the steam reformer in the base case design and
to the partial oxidation unit in the MFS case design. The blowdown from the
steam drum of the boilers providing this steam constitutes approximately 20%
of Stream 430 in the base case and 35% of Stream 430 in the MFS case. In the
base case, hydrogen-rich gas leaving the methanator is compressed and cooled
to condense out most of the water vapor. The water vapor results from steam
fed to the steam reformer that remains unreacted after the shift conversion.
The condensate from the methanator effluent constitutes the remaining 80% of
Stream 430 in the base case. In the MFS case, hydrogen-rich gas leaving the
Catacarb absorber is further cooled to 317°K (110°F) to condense out water
vapor, and this condensate constitutes the remaining 65% of MFS Stream 430.
The water vapor in this case results from steam fed to the partial oxidation
unit that remains unreacted after the shift conversion. For both designs,
Stream 430 should be relatively free of contaminants because boiler feedwater
consists of deaerated demineralized water and shift condensates but detailed
characterization data are not available. Estimated characteristics of Stream
430 are presented in Table 3-50. Although not shown in the table, the stream
should also contain total dissolved solids (TDS) and boiler feedwater additives
for scale and corrosion control such as hydrazine and phosphates. The gener-
3
ation rate of this wastewater stream is 55,430 kg/hr (57.7 m /hr) for the base
q
case design and 3,110 kg/hr (3.2 m /hr) for the MFS case design. The differ-
ences in the generation rates are due to the differences in the steam
155
-------
TABLE 3-49. ESTIMATED QUALITY OF KNOCKOUT DRUM
WASTEWATER FROM CRYOGENIC HYDROGEN
RECOVERY (STREAM 403)
Contaminant
H2S
NH3
HC1
co2
Phenol s
Organic Acids
Total flow rate, kg/hr
3
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration
ppmw
Trace
Trace
Trace
Trace
Trace
Trace
Flow Rate,
kg/hr
0
0
0
0
0
0
1,334
1.3
316
10.3
Data source: Table 1-X-l of Reference 13.
156
-------
TABLE 3-50. ESTIMATED QUALITY OF SLOWDOWN AND KNOCKOUT
DRUM WASTEWATER FROM HYDROGEN GENERATION
(STREAM 430)
Base Case
MFS Case
Contaminant* Concentration, Flow Rate
ppmw kg/hr
H2S
NH3
HC1
co2
Phenols
Organic Acids
Total flow rate, kg/hr
3
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
0
0
0
Trace
0
0
0
0
0
0
0
0
55,430
57.7
366
1.7
Concentration Flow Rate
ppmw kg/hr
Trace 0
Trace 0
0 0
Trace 0
0 0
0 0
3,110
3
366
1
.2
.7
Data source: Composition and flow rate data for the base case design were
obtained from Table 1-X-l of Reference 13. Composition data
for the MFS case design are slightly different from base case
design because sour shift is employed in the MFS case. Flow
rate for the MFS case was calculated using data presented in
Tables 3-44, 3-45 of this section and Figure 2-VII-2 of
Reference 13.
*0ther contaminants present should include total dissolved solids (TDS) and
boiler feedwater additives for scale and corrosion control.
157
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 430, 431, 451, 452
requirements and the amount of water vapor present in the effluent from the
shift conversion units.
Catacarb overhead receiver wastewater (Stream 431) (Hydrogen production -
Area 4) —
This wastewater stream is generated from condensation of water vapor pre-
sent in the overhead gas grom the Catacarb regenerator, and applies only to
the base case design. For the MFS case design, this wastewater stream is not
generated because there is less water vapor present in the feed gas to the MFS
Catacarb absorber, and any water subsequently condensed in the regenerator
overhead is combined with the regenerated Catacarb solution and returned to
the absorber. Estimated characteristics of this stream are presented in Table
3-51. Stream 431 should be free of hydrogen sulfide, phenols and organic acids,
since the base case Catacarb is simply sorbing CO- from a clean hydrogen stream.
However, Stream 431 will contain 600 ppmw C09 and may contain traces of ammonia.
o
The generation rate of this waste stream is 22,690 kg/hr (23.2 m /hr).
Aqueous ammonia from ammonia synthesis (Stream 451) (Hydrogen production -
Area 4)
The ammonia synthesis section removes nitrogen from the hydrogen by cata-
lytic conversion over iron oxide to ammonia. The ammonia synthesis reactor
effluent is cooled and sent to a water scrubber where aqueous ammonia is re-
covered as Stream 451 in the base case design. Estimated characteristics of
this stream are presented in Table 3-52. The aqueous ammonia contains 11.5%
NH- and possibly traces of H9S and organics. The generation rate of this
3
stream is 22,560 kg/hr (24.1 m /hr). The ammonia present in this stream is a
potentially salable by-product.
Knockout drum wastewater from ammonia synthesis (Stream 452) (Hydrogen
production - AreaTJ"
This wastewater stream is generated from the cooling and condensation of
residual water vapor present in the hydrogen-rich gas which is fed to the am-
monia synthesis reactor for nitrogen removal, and applies only to the base
158
-------
TABLE 3-51. ESTIMATED QUALITY OF CATACARB OVERHEAD
RECEIVER WASTEWATER (STREAM 431)*
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Total flow rate, kg/hr
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration,
ppmw
0
Trace
0
600
0
0
Flow Rate,
kg/hr
0
0
0
13.6
0
0
22,690
23.2
339
1.4
Data source: Table 1-X-l of Reference 13.
* Stream 431 is generated only from the base case design.
159
-------
TABLE 3-52. ESTIMATED QUALITY OF AQUEOUS AMMONIA
FROM AMMONIA SYNTHESIS (STREAM 451)*
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Total flow rate, kg/hr
3
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration
ppmw
Trace
115,260
0
Trace
0
0
Flow Rate,
kg/hr
0
2,600
0
0
0
0
22,560
24.1
322
12.9
Data source: Table 1-X-l of Reference 13.
* Stream 451 is generated only from the base case design.
160
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 452, 441
case design. Any pollutants present in Stream 452 are expected to be at trace
levels since the hydrogen-rich gas from which the water condenses will be fair-
ly clean before it reaches the ammonia synthesis step. Estimated characteris-
tics of this stream are presented in Table 3-53. The generation rate of this
o
wastewater stream is 450 kg/hr (0.45 m /hr).
Sour water from the partial oxidation unit (Stream 441) (Hydrogen production -
Area 4)
The gas stream leaving the gasification zone of the Texaco gasifier is
quenched with water to remove most of the slagged ash, and the quenched gas
is scrubbed with water to remove additional char and impurities such as ammon-
ia and formate. The quench water, after removal of the coarse slag and part of
the slag fines by clarification, is combined with the used scrubber water.
Most of this sour water is recycled as quench or scrubber water; however, a
portion of the sour water is bled off in order to control the buildup of solu-
ble ash consitutents as well as organic and inorganic reaction products in the
recirculating quench and scrubber water. This bleed stream, after depressuri-
zation, is Stream 441. Thus, Stream 441 originates from the condensation of
the water vapor present in the effluent from the partial oxidation unit as a
result of steam injected into this gasifier. Estimated characteristics of
Stream 441, based upon test data and design data for gasification of various
coals in a Texaco gasifier (12,30,31,32), are presented in Table 3-54. The
stream is expected to contain 65-336 ppmw H2S, 1220-2700 ppmw NH3, 492-1200
ppmw formate, and very low levels of phenols. Also, based upon very limited
test data on coal gasification in a Texaco coal gasifier, polycyclic hydro-
carbons (e.g., anthracene, pyrene) are present at parts per billion levels (12).
In Table 3-55, the concentrations of trace elements in Stream 441 are presented,
also based on coal gasification tests. It is emphasized that the numbers in
Tables 3-54 and 3-55 are based upon tests gasifying various coals and could be
different from compositions when gasifying EDS vacuum bottoms resulting from
Illinois No. 6 coal. When ranges of concentration values are presented, the
161
-------
TABLE 3-53. ESTIMATED QUALITY OF KNOCKOUT DRUM
WASTEWATER IN AMMONIA SYNTHESIS
(STREAM 452)*
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Total flow rate, kg/hr
3
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration,
ppmw
Trace
Trace
0
Trace
0
0
Flow Rate,
kg/hr
0
0
0
0
0
0
454
0.45
311
12.4
Data source: Table 1-X-l of Reference 13.
* Stream 452 is generated only from the base case design.
162
-------
TABLE 3-54. ESTIMATED QUALITY OF SOUR WATER FROM THE
PARTIAL OXIDATION UNIT (STREAM 441)*
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Formate
Sulfate
Sulfite
S2°3=
cr
CN"
SCN"
COD
TDS
TSS
TOC
PH
Total flow rate, kg/hr
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration,
ppmw
65-336
1220-2700
No data
No data
0.023
No data
492-1200
21-166
180
69
7.5-1320
8-45
8-70
405-760
420-2000
330
215-760
7.7-8.8
Flow Rate,
kg/hr
3-15
56-123
No data
No data
0.001
No data
22-55
1.0-7.6
8.2
3.1
0.3-60
0.4-2.0
0.4-3.2
18-35
19-91
15
9.8-35
Not applicable
45,550
45.5
355
0.14
Data source: H^S, CN", Cl", TDS, and TOC data were obtained from References
12, 30 and 31; NH- and formate data were obtained from Refer-
ences 12, 30, 31 and 32; phenol and sulfite data were obtained
Reference 31; sulfate and SCN- data were obtained from Refer-
ences 12, 31, and 32; S?0^= data were obtained from Reference
32; COD and pH data were Obtained from References 12 and 31;
TSS data were obtained from Reference 31. Flow rate was extra-
polated from the SRC-II design for the Texaco gasifier (26).
Temperature and pressure were obtained from Table 2-VII-2 of
Reference 13. Data from References 12, 30, 31 and 32
were acquired in the gasification of both eastern and western
coals in pilot Texaco units.
* Stream 441 is generated only from the MFS case design.
163
-------
TABLE 3-55. CONCENTRATIONS OF TRACE ELEMENTS IN SOUR WATER FROM
THE PARTIAL OXIDATION UNIT (STREAM 441)*
Element
Aluminum
Antimony
Arsenic
Barium
Beryllium
Bromine
Cadmium
Calcium
Chromium
Cobalt
Copper
Fluorine
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Sil icon
Silver
Sodium
Tha 11 i urn
Vanadium
Zinc
Al
Sb
As
Ba
Be
Br
Cd
Ca
Cr
Co
Cu
F
Fe
Pb
Mg
Mn
Hg
Mo
Ni
Se
Si
Ag
Na
Tl
V
Zn
Concentration,
ppmw
20
<0.001
0.022
0.54
0.018
<1
0.003
140
<0.003
0.021
0.01
39-500
3.7
0.054
100
0.10
<0.0001
<0.02
0.03
0.010
5.0
0.002
80
0.01
<0.04
0.03
Data source: Data for Al, Ca, Fe, Mg, Na and Si were obtained from Reference
32; data for Br were obtained from References 12 and 31; data
for F were obtained from References 12, 31 and 32; all other data
were obtained from Reference 12. Data from these references were
acquired in th« gasification of both eastern and western coals in
pilot Texaco units.
* Stream 441 is generated only from the MFS case design.
164
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 441, 443
higher value will be used in the PCTM evaluation of wastewater treatment tech-
nology. The generation rate of Stream 441, estimated by extrapolating the
SRC-II commercial plant design data for processing SRC-II vacuum bottoms in
the Texaco gasifier (26), is 45,550 kg/hr (45.5 m3/hr). The composition/flow
estimates from Stream 441 were prepared using coal gasification data and SRC-
II design estimates, because no data/estimates are publicly available address-
ing gasification of vacuum bottoms from the EDS design facility.
Slag filtrate from the partial oxidation unit (Stream 443) (Hydrogen
production - Area 4)
Most of the slag fines in the quench water from the Texaco gasifier are
removed by clarification and a slag fines slurry is obtained. Stream 443 is
the wastewater stream that results from filtration of the slag fines slurry.
Estimated characteristics are based upon test data for the Texaco coal gasi-
fier (12,31) and presented in Table 3-56. The data show that the concentra-
tion levels of contaminants in the slag filtrate are generally an order of
magnitude lower than the concentration levels of the same contaminants in the
sour water from the partial oxidation unit. The concentrations of trace ele-
ments in Stream 443 are presented in Table 3-57. As with the sour water from
the partial oxidation unit, the numbers in Tables 3-56 and 3-57 are based
upon results from gasifying a variety of coals, not EDS vacuum bottoms; the
results from gasification of vacuum bottoms could be different. In Tables
3-56 and 3-57, the higher value will be used in the evaluation of wastewater
treatment technology when ranges of concentration values are presented. The
generation rate of Stream 443 was estimated by extrapolating SRC-II design
estimates to be 9,320 kg/hr (9.3 m /hr). No data are available from Exxon
concerning the characteristics of this wastewater stream.
165
-------
TABLE 3-56. ESTIMATED QUALITY OF SLAG FILTRATE FROM THE
PARTIAL OXIDATION UNIT (STREAM 443)*
Contaminant
H2S
NH3
HC1
co2
Phenols
Organic Acids
Formate
Sulfate
Sulfite
s2o3=
Cl"
CN~
SCN"
COD
TDS
TS5
TOC
pH
Total flow rate, kg/hr
Total flow rate, m /hr
Temperature, °K
Pressure, MPa
Concentration,
ppmw
<0.5-6
130-380
No data
No data
<0.01
No data
56-94
5-38
4.7
5
42-146
0.4-1
2-4
48-221
28-355
No data
28-38
8-8.9
Flow Rate,
kg/hr
<0. 005-0. 06
1.2 - 3.5
No data
No data
<0.0001
No data
0.52-0.88
0.05-0.35
0.044
0.05
0.39-1.4
0.004-0.01
0.019-0.037
0.45-2.1
0.26-3.3
No data
0.26-0.35
9,320
9.3
303
0.10
Data source: Data for sulfite were obtained from Reference 31; data for
were obtained from Reference 12; all other concentration data
were obtained from References 12 and 31. Flow rate was extra-
polated from the SRC-II design for the Texaco gasifier (26).
Temperature and pressure were obtained from Table 2-VII-2 of
Reference 13. Data from References 12 and 31 were acquired in the
gasification of both eastern and western coals in pilot Texaco
units.
* Stream 443 is generated only from the MFS case design.
166
-------
Element
TABLE 3-57. CONCENTRATIONS OF TRACE ELEMENTS IN SLAG
FILTRATE FROM THE PARTIAL OXIDATION UNIT
(STREAM 443)*
Concentration,
ppmw
Aluminum
Antimony
Arsenic
Barium
Beryllium
Bromine
Cadmium
Calcium
Chromium
Cobalt
Copper
Fluorine
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silicon
Silver
Sodium
Thallium
Vanadium
Zinc
Al
Sb
As
Ba
Be
Br
Cd
Ca
Cr
Co
Cu
F
Fe
Pb
Mg
Mn
Hg
Mo
Ni
Se
Si
Ag
Na
Tl
V
Zn
No data
<0. 005-0. 016
0.07-0.08
0.10-0.27
<0.005
<1
<0.005
No data
<0.003
<0. 005-0. 10
0.017-0.043
<0.1-31
No data
0.045-0.059
No data
0.016-0.08
<0. 0001-0. 11
0.016-0.03
<0. 05-0. 07
0.033-0.14
No data
0.002-0.01
No data
<0.01
<0.05
<0.05
Data source: References 12 and 31 for all elements. Data from References 12
and 31 were acquired in the gasification of eastern and western
coals in pilot Texaco units.
* Stream 443 is generated only from the MFS case design.
167
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Stream 404
3.3.4.2.3 Solid Waste Streams
There are eight solid waste streams from hydrogen production for the base
case design, and five solid waste streams from hydrogen production for the MFS
case design. Only two of the solid waste streams are common to both designs.
These solid waste streams are:
t Stream 404 - spent hydrotreater catalyst from cryogenic hydrogen
recovery
• Stream 405 - spent drying agents from cryogenic hydrogen recovery
• Stream 433 - spent sulfur guard from hydrogen generation (base
case only)
• Stream 435 - spent reformer catalyst from hydrogen generation
(base case only)
• Stream 436 - spent shift catalyst from hydrogen generation (base
case only)
• Stream 439 - spent methanation catalyst from hydrogen generation
(base case only)
• Stream 453 - spent drying agents from ammonia synthesis (base case
only)
• Stream 454 - spent ammonia synthesis catalyst (base case only)
• Stream 442 - slag from the partial oxidation unit (MFS case only)
• Stream 444 - spent high temperature shift catalyst from hydrogen
generation (MFS case only)
• Stream 445 - spent low temperature shift catalyst from hydrogen
generation (MFS case only).
Spent hydrotreater catalyst from cryogenic hydrogen recovery (Stream 404)
(Hydrogen production - Area 4)
Hydrotreating over nickel-molybdenum catalyst is employed to remove ole-
fins present in the off-gas from the Flexicoking reactor, prior to sending this
gas stream to cryogenic separation for hydrogen recovery. The hydrotreater
catalyst will require periodic replacement as a portion of it becomes deacti-
vated as a result of buildup of carbonaceous deposits on the catalyst surface.
168
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 404, 405, 433
Based on Exxon's estimates (13), the consumption rate for the nickel-molybdenum
catalyst is 65.8 Mg/yr for the base case design, and 31.8 Mg/yr for the MFS
case design. Consumption rate for the inert balls is 2.7 Mg/yr and 5.4 Mg/yr
for the base case and MFS case designs, respectively. Thus, approximately
68.5 Mg/yr of spent hydrotreater catalyst are generated for the base case de-
sign, and 37.2 Mg/yr for the MFS case design. The composition for the spent
catalyst is similar to the fresh catalyst, and is expected to contain nickel,
molybdenum, carbonaceous material, and sulfides. Leaching characteristics for
this spent catalyst are not known.
Spent drying agents from cryogenic hydrogen recovery (Stream 405) (Hydrogen
production - Area 4)
The gas stream entering the cold box in cryogenic hydrogen recovery is
dried with zeolites to remove the remaining water, H^S, and CO^. The estimated
generation rate for the spent zeolites used in cryogenic hydrogen recovery is
263 Mg/yr and 177 Mg/yr for the base case (6) and MFS case (8) designs,
respectively. These spent molecular sieves are saturated with water, H?S and
COp, but detailed characterization data are not available.
Spent sulfur guard from hydrogen generation (Stream 433) (Hydrogen
production - Area 4)
Zinc oxide sulfur guards are used to remove residual amounts of sulfur
species present in the feed gas to the steam reformer, in order to protect
reformer catalysts from sulfur poisoning. These sulfur guards must be replaced
periodically as most of the zinc oxide has been reacted to form zinc sulfide.
Stream 433 results from the generation of the spent sulfur guards, and applies
only to the base case design. The estimated generation rate for the spent zinc
oxide is 271 Mg/yr, including 38 Mg/yr of inert balls (13). The spent sulfur
guard is expected to contain mostly zinc oxide, zinc sulfide, and carbonaceous
material. Leaching characteristics for this solid waste are not known.
169
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 435, 436, 439
Spent reformer catalyst from hydrogen generation (Stream 435) (Hydrogen
production - Area 4)
Steam reforming of light hydrocarbons over nickel-urania catalyst is
employed for hydrogen production in the base case design. The reformer cata-
lyst will require periodic replacement as some of it becomes deactivated as a
result of fouling by carbon deposition or poisoning by sulfur compounds or
other trace species. Based on Exxon's estimate of the catalyst consumption
rate, the spent reformer catalyst is generated at the rate of 181 Mg/yr (13).
Detailed characterization data for the spent reformer catalyst are not avail-
able. A representative composition for the fresh nickel-urania catalyst is
13.0 wt % Ni, 12.1 wt % I), 0.3 wt % K, and the balance supporting alumina (33).
The composition for the spent catalyst is similar, but with the addition of
carbonaceous material and traces of sulfides.
Spent shift catalyst from hydrogen generation (Stream 436) (Hydrogen
production - Area 4)
For the base case design, the shift reaction (sweet shift) takes place
after the removal of all sulfur species in the DEA acid gas removal unit and
the zinc oxide sulfur guards located upstream of the steam reformer. Thus,
the spent iron oxide catalyst is expected to contain only iron oxide, carbona-
ceous material, and catalyst supporting material. The estimated generation
rate for this spent catalyst, based upon Exxon's estimate of the consumption
rate (13), is 321 Mg/yr including 35 Mg/yr of inert balls.
Spent methanation catalyst from hydrogen generation (Stream 439) (Hydrogen
production - Area 4)
The reaction of low concentrations of CO in a mixture with H,, to form CH
is incorporated into the EDS base case design as a gas purification step for
CO removal. The spent nickel oxide catalyst is expected to contain little or
no contaminants because the gas is fairly clean by the time it enters the
170
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 439, 453, 454, 442
methanator. Also, carbon deposition is not known to be a problem in methana-
tion. The estimated generation rate of this spent catalyst is 115 Mg/yr, in-
cluding 18 Mg/yr inert balls (13).
Spent drying agents from ammonia synthesis (Stream 453) (Hydrogen production -
Area 4)
The spent alumina used as drying agents for the feed gas to the ammonia
synthesis reactor is generated only from the base case design. Although char-
acterization data for this waste are not available, the spent alumina is not
expected to contain any contaminants other than water and traces of ammonia.
The estimated generation rate of the spent drying agents is 172 Mg/yr, includ-
ing 27 Mg/yr of inert balls (13).
Spent ammonia synthesis catalyst (Stream 454) (Hydrogen production - Area 4)
Ammonia synthesis is used in the base case design to remove traces of
nitrogen from the hydrogen produced. Typical catalysts used today for ammonia
synthesis contain A1203, K20, CaO and MgO (total of 5-8%) as promoters in addi-
tion to iron and iron oxides (33). The spent catalyst generated is similar
in composition to the fresh iron oxide catalyst, but is also expected to con-
tain traces of NH3 and ammonium compounds. Leaching characteristics for this
spent catalyst are not known. The estimated generation rate of the spent am-
monia synthesis catalyst is 166 Mg/yr, including 17 Mg/yr of inert balls.
Slag from the partial oxidation unit (Stream 442) (Hydrogen production -
Area IT
In the MFS case, about half of the ash in the coal fed to the EDS lique-
faction section will appear as slag from the partial oxidation unit. The
other half of the ash will be discharged in the various solid streams from
the Flexicoking operations. Slag from the partial oxidation unit is provided
to the slag handling system in two streams, a 90% solids coarse slag stream
and a 20% solids fine slag slurry. After dewatering, coarse and fine slag
fractions are combined to yield a 79% solids waste gasifier slag (Stream 442)
171
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 442, 444
to disposal. Characterization data are not available for slags from gasifica-
tion of EDS vacuum-bottoms residues. The slag is anticipated to be similar in
composition to the feed coal ash with up to 2% carbonaceous material. The
estimated generation of the combined slag is 447,300 Mg/yr on 79% solids bas-
is (13).
Leaching data have been published for slag produced in the Texaco pilot
plant at Montebello, California. This slag resulted from gasification of SRC-
II flash drum bottoms obtained with Kentucky No. 9/14 coal (27,34). Detailed
leaching results are presented in Tables 3-58 and 3-59. Table 3-60 presents
the content of selected polynuclear aromatic (PNA) hydrocarbons in the slag
itself. Bulk and true specific gravities of the composite dry slag were found
to be 1.64 and 2.62, respectively. Approximately 50% of the dry composite slag
is smaller than 0.4 mm. Batch leaching tests were performed using slag/extrac-
tant weight ratios, time intervals, and equipment suggested in the proposed
standard leaching tests (34). Although the two leaching tests with HN03 and
NH.OH are not standard, the same techniques and sol id-to-liquid ratios were
used. Column leaching tests were performed in 95 mm (3.75 inch) diameter col-
umns using a slag depth of 305 mm (12 inches) and approximately one liter of
demineralized water extractant. Results of these tests appear to indicate that
the concentration levels of the pertinent trace elements in the leachate from
the slag are well below RCRA EP criteria. Low levels of polynuclear aromatics
were detected in the slag by benzene extraction, although details of the ex-
traction procedure are not available.
Spent high temperature shift catalyst from hydrogen generation (Stream 444)
(Hydrogen production - Area 4)
For the MFS case design, the synthesis gas fed to the shift converters
enters the converters without acid gas removal, and thus still contains sour
hydrogen sulfide (sour shift). The high temperature catalyst used for this
application is a cobalt-molybdenum catalyst. The spent catalyst is similar
172
-------
TABLE 3-58. ELEMENTAL ANALYSIS OF LEACHATES DERIVED FROM VARIOUS
BATCH LEACHING PROTOCOLS APPLIED TO TEXACO SLAG FROM
GASIFICATION OF SRC-II RESIDUE (Ky 9/14 Coal)
Element EPA
Extraction
Procedure
Arsenic, ppb
Barium, ppm
Cadmium, ppb
Chromium, ppb
Lead, ppb
Mercury, ppb
Nitrate (as N),
ppm
Selenium, ppb
Silver, ppb
Sulfate, ppm
Iron, ppm
Copper, ppb
Beryllium, ppb
Antimony, ppb
Nickel , ppb
0.53
0.5
3.4
0.13
1.6
0.191
-j-
1
0.07
4.89
20.5
0.94
0.09
2
758
ASTM
H20
5
0.5
4.0
3.7
5.2
0.025
0.05*
0.04
0.09
23.63
147
—
—
—
...
ASTM
pH 5
5
0.5
4.9
3.9
2.1
0.010
0.05*
0.04
0.23
22.90
720
—
—
—
...
0.1 N
HN03
6.1
0.5
25
42
8.3
0.04
—
1
3.2
26.79
2482
—
—
—
...
0.1 N
NH4OH
2.4
0.5
1.3
1.9
4.4
0.33
—
7
0.20
36.57
0.06
—
—
—
...
RCRA*
Criteria
5000
100
1000
5000
5000
200
None
1000
5000
None
None
None
None
None
None
Data source: Table K.2 of Reference 34. ASTM H?0 uses distilled water, whereas
ASTM pH 5 uses a sodium acetate -acetic acid buffer solution. The
HN03 and NH.OH tests are not standard tests.
* RCRA regulations (May 19, 1980).
t — means not determined
* Samples not acidified before analysis.
**Extraction procedure published in Federal Register (December 18, 1978).
173
-------
TABLE 3-59. ELEMENTAL ANALYSIS OF SLAG LEACHATES DERIVED FROM LABORATORY
COLUMNS
Column
Number
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
Element
Arsenic, ppb
Barium, ppb
Cadmium, ppb
Chromium, ppb
Lead, ppb
Mercury, ppb
Selenium, ppb
Silver, ppb
1
1.16
1.36
<0.5
<0.5
11
16
7.0
6.2
1.4
0.93
0.007
0.011
120
195
0.34
0.36
Leach
2
0.79
1.33
<0.5
<0.5
0.13
0.11
3.5
3.2
<0.3
<0.3
0.024
0.012
44
34
0.17
0.17
Number
10
2.0
1.53
<0.5
<0.5
0.014
0.020
0.25
0.24
<0.3
<0.3
0.013
0.003
16
<5
0.13
0.12
20
3.1
3.4
<0.5
<0.5
0.10
0.091
0.49
0.41
<0.43
<0.3
0.019
0.001
<5
<5
0.10
0.10
Data source: Table K.3 of Reference 34. Data are from tests performed at
the Texaco pilot plant at Montebello, California. The ash/slag
was from gasification of a Kentucky No. 9/14 SRC^II flash drum
residue. The laboratory columns used (3.75 in. diameter) have a
12 in. depth of slag and are dosed daily with 1 liter of de-
mineralized water (about 1 column volume). Results for leaches
1, 2, 10 and 20 are given in this table.
174
-------
TABLE 3-60. CONCENTRATIONS OF BENZENE SOLUBLES AND SELECTED
POLYNUCLEAR AROMATICS IN TEXACO SLAG FROM
GASIFICATION OF SRC-II RESIDUE
Contaminant Coarse Slag
Total benzene solubles, wt % 0.0315
Benz-a-anthracene, ppb 12
Benz-a-pyrene, ppb 17
Benzo-e-pyrene, ppb 4
Benzo(g,h,i) perylene, ppb 8
Fine Slag
0.0165
10
13
17
5
Data source: Reference 34. Vacuum bottoms from the Fort Lewis SRC-II
pilot plant were gasified in a Texaco gasifier. The gasifier
slag was then subjected to a benzene extraction, and the
benzene extract was analyzed for the presence of benzene
solubles and polynuclear aromatic (PNA) compounds.
175
-------
Liquefaction Residue Processing/
Hydrogen Production - Area 4
Streams 444, 445
in composition to the fresh catalyst, except for the presence of contaminants
such as carbonaceous material, sulfides, sulfur, and volatile trace metals.
Leaching characteristics for this spent catalyst are not available. The esti-
mated generation rate of the spent cobalt-molybdenum catalyst is 451 Mg/yr,
including 35 Mg/yr of inert balls (13).
Spent low temperature shift catalyst from hydrogen generation (Stream 445)
(Hydrogen production - Area 4j
The low temperature shift converter is employed in the MFS case design
because considerable amount of carbon monoxide remains in equilibrium at the
exit temperature of the preceding 2-stage high temperature shift converter.
The low temperature shift catalyst used is also a cobalt-molybdenum catalysts.
The spent catalyst is expected to contain cobalt, molybdenum, sulfides, car-
bonaceous material, and possibly volatile trace metals. Leaching characteris-
tics for this spent catalyst are not known. The estimated generation rate of
the spent Co/Mo catalyst is 254 Mg/yr, including 22 Mg/yr of inert balls (13).
176
-------
Auxiliary Operations - Area 5
3.3.5 Auxiliary Operations (Area 5)
The auxiliary operations in an EDS commercial plant are: 1) raw water
treatment, 2) steam and power generation, 3) cooling operations, 4) oxygen
production, and 5) product and by-product storage. These auxiliary operations
and the associated waste streams are described in the ensuing subsections.
3.3.5.1 Raw Water Treatment (Auxiliary Operations - Area 5)
Various treatments are required to render raw waters to be suitable for
use as boiler feed water, cooling tower makeup water and potable water in
direct liquefaction facilities. The degree of treatment required depends up-
on the characteristics of the raw water and the end-use water quality require-
ments. Figure 3-8 presents a block flow diagram of the raw water treatment
systems. Boiler feed water has highest quality requirements and thus requires
more sophisticated treatment. In Table 3-61, the source and characteristic
of raw waters assumed for the EDS direct liquefaction facility are presented.
Raw water is generally pumped from rivers and stored in a reservoir.
This storage: 1) provides a reliable supply of water to the facility indepen-
dent of river flow, 2) reduces the impact of raw water quality variation, and
3) allows sedimentation of silts and other large suspended materials.
The raw water is chlorinated to prevent biogrowthjto destroy organics,
and to oxidize reduced species (mainly iron and manganese) to their more in-
soluble oxidized form for removal in the subsequent coagulation/sedimentation
step. Alum and polymers are generally added in the coagulation step to improve
suspended solids removal. After the coagulation/settling step, the water is
generally suitable for use as cooling tower makeup. If high recirculation is
required, acidification to reduce bicarbonates and/or addition of lime and
magnesium hydroxide to remove hardness may be required.
177
-------
RAW
WATER'
STORAGE
RESERVOIR
CHLORINATION
00
COOLING
WATER
BACKWASH
COAGULATION/
CLARIFICATION
THICKENING
VACUUM
FILTRATION
FILTRATION
REGENERATION
CHEMICALS
DEMINERAL-
IZATION
BOILER
FEED WATER
REGENERATION
WASTE
SLUDGE
Figure 3-8. Raw water treatment block flow diagram.
-------
TABLE 3-61. ASSUMED CHARACTERISTICS OF RAW WATER FOR EDS
DIRECT LIQUEFACTION FACILITY
Parameter*
Total Hardness, as ppmw CaC03
M-Alkalinity
so4
Ca
Mg
Na
Cl
Si02
pH
Mississippi River
130
105
46
37
9
9
10
6
7.7
* All concentrations except pH expressed in mg/1.
179
-------
Auxiliary Operations - Area 5
Streams 723, 722
A filtration step is usually required to protect the demineralization
units, and to render the water suitable for use as potable water. The filter
effluent is sent to the demineralization unit. The demineralization ef-
fluent is essentially pure water and is used as boiler feed water.
3.3.5.1.1 Gaseous Waste Stream
There is no gaseous waste stream from raw water treatment.
3.3.5.1.2 Liquid Uaste Stream
There is only one aqueous waste stream from raw water treatment:
• Stream 723 - regeneration waste from water demineralization.
Regeneration waste from water demineralization (Stream 723) (Raw water
treatment - Area 5)
Mixed bed anion-cation exchangers are used for water demineralization
in the EDS plant. In ion exchangers, dilute chemicals are introduced down-
ward through the resin bed periodically to remove exchanged ions and to re-
store exchange capacity. The regeneration step results in the generation of
a waste brine which must subsequently be handled as Stream 723. Based on the
demineralization feedwater requirements (13), the estimated generation rate
for the regeneration waste is 30,000 kg/hr (3.0m /hr) for the base case de-
sign and 34,000 kg/hr (3.4 m3/hr) for the MFS case design. The estimated
characteristics of the regeneration waste are presented in Table 3-62. This
waste stream contains high levels of dissolved solids.
3.3.5.1.3 Solid Waste Stream
There is only one solid waste stream from raw water treatment:
t Stream 722 - raw water treatment sludge.
Raw water treatment sludge (Stream 722) (Raw water treatment - Area 5)
The sludge from the filter press is a cake-like material with about 60%
moisture content, and consists mainly of calcium carbonates and magnesium
180
-------
TABLE 3-62. ESTIMATED CHARACTERISTICS OF REGENERATION
WASTE FROM WATER DEMINERALIZATION
(STREAM 723)
Contaminant Concentration,
ppmw
Calcium 1,030
Magnesium 760
Sodium 2,280
Sulfate 11,690
Chloride 530
Nitrate TOO
Silica 70
Data source: Estimated using characteristics of raw water (Table 3-61)
181
-------
Auxiliary Operations - Area 5
Stream 722
hydroxide. The estimated characteristics of this stream for the EOS lique-
faction facilities are presented in Table 3-63. Based on the raw water feed
requirement (13), the estimated generation rate of the raw water treatment
sludge is 46 Mg/day and 41 Mg/day for the base case and MFS case design,
respectively.
3.3.5.2 Steam and Power Generation (Auxiliary Operations - Area 5)
The steam generation system provides net plant requirements and utilizes
all the low Btu fuel gas available, which amounts to 1,46 TJ (1385 MM Btu) per
hour for the base case design and 1.69 TJ (1599 MM Btu) per hour for the MFS
case design. Additional coal feed, at the rate of 35.3 Mg/hr for the base
case design and 92.8 Mg/hr for the MFS case design, are provided to the steam
generation system as supplemental fuel. Steam is required in the EDS plant
as feed to Flexicoking reactor and gasifier, as feed to the steam reformer
(base case only) or partial oxidation unit (MFS case only), and for other pro-
cess uses such as stripping steam for the atmospheric fractionator.
Although the EDS commercial design stipulated the purchase of power from
a local utility, some coal liquefaction plants may prefer ori-site power gener-
ation. For this reason, this PCTM assumes that power is generated through on-
site coal-fired boilers. For the base case design, the power requirement of
223 MW can be met by the use of coal at a rate of 95.8 Mg/hr., For the MFS case
design, the power requirement of 160 MW can be met by the use of coal at 68.7
Mg/hr. This power is required in the EDS plant to run electrically-driven
equipment such as pumps and compressors.
If power were purchased from a local utility, instead of being generated
on-site, the discharge streams discussed below -- associated with the coal-
fired power boilers -- would be eliminated from the EDS power plant,
3.3.5.2.1 Gaseous Waste Streams
There are two gaseous waste streams from steam and power generation:
182
-------
TABLE 3-63. ESTIMATED CHARACTERISTICS OF RAW
WATER TREATMENT SLUDGE (STREAM 722)
Component Wt % in Sludge
CaC03 36.4
Mg (OH)2 3.6
H0 60
Data source: Estimated using characteristics of raw water (Table 3-61)
183
-------
Auxiliary Operations - Area 5
Streams 701 a, 707a
t Stream 701 a - flue gas from steam generation system
• Stream 707a - flue gas from power generation system.
Flue gas from steam generation system (Stream 701a) (Steam and power
generation - Area 5)
The burning of low-Btu fuel gas provides approximately 63% and 43% of the
energy input for steam generation in the base case and MFS case designs,
respectively. The remaining energy requirements for steam generation are pro-
vided by burning coal. Estimated emission rates of pollutants in the flue gas
from the steam generation system are presented in Table 3-64. It is re-em-
phasized that these are emissions assuming no particulate or SO^ controls.
Emissions of particulate matter and SO,, are mainly contributed by the coal
feed. Assuming combustion with 30% excess air, the flow rate of the flue gas
stream was calculated to be 42,560 kmol/hr (592,700 SCFM) for the base case
design and 69,150 kmol/hr (962,930 SCFM) for the MFS case design. In these
estimates, no assumptions were made concerning whether the plant steam needs
will be generated by one large steam boiler, or two or more smaller ones.
Flue gas from power generation system (Stream 707a) (Steam and power
generation - Area 5) ———
Estimated emission rates of pollutants in the flue gas from the power
generation system are presented in Table 3-65, assuming no particulate or S02
controls. Emission rates of pollutants from the power generation system are
higher than those from the steam generation system in the base case design,
but lower in the MFS case design. Assuming combustion with 30% excess air,
the flow rate of the flue gas stream was calculated to be 36,450 kmol/hr
(507,600 SCFM) for the base case design, and 26,110 kmol/hr (363,600 SCFM) for
the MFS case design.
3.3.5.2.2 Liquid Waste Streams
There are two aqueous waste streams from steam and boiler generation:
184
-------
TABLE 3-64. UNCONTROLLED FLUE GAS EMISSIONS FROM
STEAM GENERATION SYSTEM (STREAM 701 a)
Pollutant Emissions Rate, kg/hr
Base Case MFS Case
Participate Matter
N0x (as N02)
CO
Hydrocarbons
so2
2,190
297-366
28-34
7.2
2,520
5,740
670-750
59-65
16-1
6,530
Data source: Emission rates for particulate matter were computed based on
the ash content of coal and assuming that 81.3% of the coal
ash results in fly ash; emission rates for S02 were computed
based on the sulfur content of coal and assuming that 94% of
the fuel sulfur becomes S02; emission rates for hydrocarbons,
and CO were computed using AP-42 emission factors for pulver-
ized coal-fired boilers and natural gas-fired boilers larger
than 100 MM Btu/hr in capacity (21). Emission rates for NO
from low-Btu gas combustion were computed by using AP-42 NOX
emission factor for natural gas-fired boilers larger than ifio
MM Btu/hr in capacity (21). The NO emission factor used is
52-99 ng/J (0.12 - 0.23 Ib/MM Btu), which is approximately
the same as the 86 ng/J (0.20 Ib/MM Btu) NSPS NO standard
for utility boilers burning gaseous fuel. Emission rates for
NO from coal combustion were computed using the NSPS NO
standard of 260 ng/J (0.60 Ib/MM Btu) for utility boilers'
burning bituminous coal.
Other assumptions: For the base case design, approximately 63% of the
energy input to the steam boiler is provided by burning low-
Btu fuel gas (125 Btu/SCF, 83 ppmvS)and 37.0% provided by
burning coal (3.7% S, 7.6% ash). For the MFS case design,
approximately 42.8% of the enrgy input to the steam boiler
is provided by burning low-Btu fuel gas, and 57.2% provided
by burning coal.
185
-------
TABLE 3-65. UNCONTROLLED FLUE GAS EMISSIONS FROM
POWER GENERATION SYSTEM (STREAM 707a)
Pollutant Emission Rate, kg/hr
Pollutant Base Case MFS Case
Participate Matter
NOV (as N09)
X c~
CO
Hydrocarbons
S09
5,930
601
47.9
14.3
6,660
4,250
431
34.4
10.3
4,780
Data source: Emission rates for participate matter were computed based on
the ash content of coal and assuming that 81.3% of the coal
ash results in fly ash; emission rates for S02 were computed
based on the sulfur content of coal and assuming that 94% of
the fuel sulfur becomes S02; emission rates for hydrocarbons,
and CO were computed using AP-42 emission factors for pulver-
ized coal-fired boilers larger than 100 MM Btu/hr in capacity (21)
Emission rates for NOX were computed using the NSPS NO standard
of 260 ng/J (0.60 Ib/MM Btu) for utility boilers burning bitu-
minous coal. All power is assumed to be generated by burning
coal containing 3.7% sulfur and 7.6% ash.
186
-------
Auxiliary Operations - Area 5
Streams 702, 708, 704
t Stream 702 - blowdown from steam generation system
• Stream 708 - blowdown from power generation system.
Blowdown from steam generation system (Stream 702) (Steam and power
generation - Area 5j_ ~~~~
Based on Exxon's design estimate (13), blowdown from the steam generation
system is generated at the rate of 67 m /hr for the base case design and 55
3
m /hr for the MFS case design. This is a stream containing typically up to
4,000 mg/1 total dissolved solids (35), and additives for scale and corrosion
control such as hydrazine and phosphates.
Blowdown from power generation system (Stream 708) (Steam and power
generation - Area 5)
Based on a typical boiler blowdown rate of 12.6 1/MW-hr (36), Stream 708
was estimated to be generated at the rate of 2.8 m /hr for the base case de-
sign and 2.0 m /hr for the MFS case design. Because higher pressure steam is
generated in the power boilers, the blowdown contains lower levels of total
dissolved solids in the 200-500 mg/1 range (35). Additives for scale and cor-
rosion control such as hydrazine and phosphates are also present.
3.3.5.2.3 Solid Waste Streams
There are two solid waste streams from steam and power generation:
• Stream 704 - bottom ash from steam generation system
• Stream 710 - bottom ash from power generation system.
Bottom ash from steam generation system (Stream 704) (Steam and power
generation - Area 5)
Assuming that 18.7% of the ash content of the coal fed to the steam
generation system results in bottom ash (36), the generation rate of this solid
waste was calculated to be 3,960 Mg/yr for the base case design and 10,400 Mg/yr
for the MFS case design. Concentrations of trace elements present in the bottom
ash are similar to those found in the coal feed (Table 2-2), although the levels
187
-------
Auxiliary Operations - Area 5
Streams 704, 710
of some of the more volatile elements (or elements associated with volatile
compounds) will be depleted (36).
Bottom ash from power generation system (Stream 710) (Steam and power
generation - Area 5T~~
Using the same assumptions as for the steam generation system, the gen-
eration rate of bottom ash from the power generation system was calculated to
be 10,740 Mg/yr for the base case design and 7,700 Mg/yr for the MFS case de-
sign.
3.3.5.3 Cooling Operation (Auxiliary Operations - Area 5)
All direct liquefaction plants generate non-recoverable heat, most of
which is dissipated through cooling towers. The selection/design of optimum
cooling systems would require detailed heat balances for the whole plant, and
is beyond the scope of this study. The use of wet cooling towers is proposed
in the Exxon design; this is the only type of cooling operation analyzed in
the PCTM. The total plant wet cooling loads for the EDS commercial plant
3
amount to a cooling water circulation rate of 55,190 m /hr for the base case
3
design and 44,740 m /hr for the MFS case design.
A wet cooling tower removes heat by evaporating part of the circulating
water. To prevent excessive buildup of impurities in the circulating circuit,
some of the circulating water must be removed from the system. Makeup water
is required to compensate for losses through evaporation, blowdown, and to a
lesser extent, drift. The makeup water can either be from treated raw water
or from treated process wastewater. Thus, cooling operation not only affects
the overall plant water balance, but can also be a critical factor in the dis-
posal and reuse of process wastewater.
3.3.5.3.1 Gaseous Waste Stream
There is only one gaseous waste stream from cooling operation:
0 Stream 731 - drift and evaporation from cooling tower.
188
-------
Auxiliary Operations - Area 5
Streams 731, 732
Drift and evaporation from cooling tower (Stream 731) (Cooling operation -
Area 5)
Assuming that approximately 1.25 percent of the circulating cooling water
is lost due to drift and evaporation, the total amount of water loss through
3
this waste stream was calculated to be 690 m /hr for the base case design and
560 m /hr for the MFS case design. Only a small fraction of the cooling tower
loss is due to drift alone. In modern cooling towers, drift losses are typi-
cally only 0.005 percent of the circulating water (35). Thus, drift losses
o o
only amount to 2.8 m /hr and 2.2 m /hr of water for the base case and MFS case
designs, respectively; the remainder of the total loss is due to evaporation.
Estimated characteristics for the drift droplets are presented in Table 3-66.
There is also some potential for VOC emissions from cooling towers, because
organics could be present in the cooling loop via heat exchanger leaks, etc.
3.3.5.3.2 Liquid Haste Stream
There is only one aqueous waste stream from cooling operation:
• Stream 732 - cooling tower blowdown.
Cooling tower blowdown (Stream 732) (Cooling operation - Area 5)
Blowdown from the cooling tower is necessary to maintain the total dis-
solved solids (TDS) in the circulating water at a reasonable level to prevent
solids deposition. For estimation purposes, the TDS level in the circulating
cooling water is assumed to be maintained at 500 mg/1, which corresponds to
two cycles of concentration. The calculated cooling tower blowdown rate is
o 3
630 m /hr for the base case design, and 510 m /hr for the MFS case design.
Estimated characteristics of the cooling tower blowdown are presented in Table
3-66.
3.3.5.3.3 Solid Waste Stream
There is no solid waste stream from cooling operation.
189
-------
TABLE 3-66. CHARACTERISTICS OF COOLING TOWER DRIFT
AND SLOWDOWN (STREAMS 731/732)*
Parameter Concentration, mg/1
Hardness, as CaCO., 260
TDS 500
Alkalinity, as CaC03 205
Cr 0.8
Cu 0.25
Fe 0.8
Mg 18
Na 18
Ni 0.03
Si 9
Zn 1
Sulfate 300
Chloride 20
Nitrate 8
Phosphate-P 4
Data source: Estimated from raw water characteristics by assuming two cycles
of concentration, except that data for Cr, Cu, Fe, Ni, Zn,
nitrate and phosphate were obtained from Reference 36.
* Concentration values only apply to the drift portion of Stream 731. The
evaporation portion of Stream 731 is essentially free of contaminants,
unless process wastewaters are used as makeup or organics have worked
their way into the cooling loop via heat exchanger leaks, etc.in which
case some volatilized organics might appear.
190
-------
Auxiliary Operations - Area 5
3.3.5.4 Oxygen Production (Auxiliary Operations - Area 5)
Oxygen production only applies to the MFS case design. Oxygen required
for partial oxidation is assumed to be produced by standard cryogenic air
separation units. Air is compressed to 0.58 to 0.61 MPa (85-90 psia) and
cryogenically cooled to facilitate distillation of oxygen, nitrogen and noble
gases. The oxygen stream, containing small quantities of nitrogen and argon,
is compressed and sent to the gasifiers. Air and oxygen compressors can either
be steam, gas, electric driven or a combination thereof. The separated nitro-
gen containing small quantities of oxygen, water and carbon dioxide is primar-
ily vented to the atmosphere. However, a portion of the nitrogen stream may
be utilized as an inerting agent for coal storage and transfer, and/or as
stripping gas for solvent regeneration in acid gas treatment and phenol recov-
ery units. The quantity of condensate resulting from air compression depends
upon atmospheric humidity and therefore, is highly variable. Condensate con-
tains only dissolved gases and can be utilized as a supplement to the plant
high quality water supply. The estimated EDS MFS case oxygen requirement is
4,190 Mg/day (13).
3.3.5.4.1 Gaseous Waste Stream
A gaseous stream containing mostly nitrogen is generated. As discussed
previously, this stream may be used as an inerting agent in other plant areas
or may be vented to the atmosphere and is not considered a waste stream. There
is no gaseous waste stream from oxygen production.
3.3.5.4.2 Liquid Waste Stream
The only liquid stream generated is a condensate which may be used as
makeup water in other plant areas. There is no liquid waste stream from oxy-
gen production.
3.3.5.4.3 Solid Haste Stream
Dessicants are used in oxygen production to remove VOCs from incoming air.
191
-------
Auxiliary Operations - Area 5
Stream 751
Also, participate filters are used. Thus, small amounts of solid wastes will
be generated from discarded dessicants and particulate filter material on an
intermittent basis.
3.3.5.5 Product and By-Product Storage (Auxiliary Operations - Area 5)
Storage capacities for product and by-products were estimated based upon
the expected production rates of upgraded liquid and gaseous fuels for the EDS
direct liquefaction plant. Storage for the EDS process plant consists of a
variety of storage tanks for liquid products, by-products, and makeup chemi-
cals. Depending on the vapor pressure of the liquid stored, the design incor-
porates floating roof, fixed (cone) roof, pressurized or dome type tanks. The
more volatile products (e.g., LPG, ammonia) are stored in pressure vessels and
are expected to have no routine evaporative emissions. Products such as naph-
tha are stored in floating roof tanks and products such as phenol and blended
fuel oil are stored in fixed roof tanks. Some streams such as sour water/
phenolic water require intermediate storage and are stored in dome tanks. Var-
ious products such as vacuum bottoms, liquefaction hydrogenated recycle solvents,
blended fuel oil, etc., require storage at temperatures ranging from 343 to 533°K
(160°F to 500°F). Consequently, these tanks are provided with a heating mecha-
nism and are insulated in designs proposed by Exxon.
3.3.5.5.1 Gaseous Waste Stream
There is only one type of gaseous waste stream from product and by-product
storage:
• Stream 751 - evaporative emissions from product and by-product storage.
Evaporative emissions from product and by-product storage (Stream 751)
(Product and by-product storage - Area 5)
For both the base case and MFS case designs, storage tanks containing
fuel oil, naphtha, and phenol were identified as the main sources of evapora-
tive emissions. Based on Exxon's proposed design, naphtha will be stored in
external floating roof tanks, and blended fuel oil and phenol will be stored
in fixed roof tanks.
192
-------
Auxiliary Operations - Area 5
Stream 751
Evaporative emissions from external floating roof tanks consist primarily
of standing storage losses and withdrawal losses. Standing storage losses
result from wind induced mechanisms as air flow across the top of an external
floating roof tank. Withdrawal losses are caused by the vaporization of liquid
that clings to the tank wall and is exposed to the atmosphere when a floating
roof is lowered by withdrawal of liquid. Evaporative emissions from fixed
roof tanks consist primarily of breathing losses and working losses. Breathing
losses are caused by the expulsion of vapor from a tank due to vapor expansion
and contraction from changes in temperature and barometric pressure. Working
losses are the combined losses from tank filling and emptying.
Estimated uncontrolled evaporative emissions from product and by-product
storage are presented in Table 3-67. In estimating these uncontrolled emis-
sions, the external floating roof tanks were assumed to be equipped with pri-
mary seals only, and the fixed roof tanks were assumed to be neither
equipped with internal floating roofs nor with vapor recovery systems.
Data on the components of evaporative emissions associated with storage
of coal derived liquid fuels are generally lacking. However, limited data
are available regarding the chemical composition of some of the direct lique-
faction products. For example, the major constituents of naphtha are paraf-
fins, naphthenes and aromatics, and these are also expected to be present in
evaporative emissions. Compositions of these products are presented in Section
3.3.6.
3.3.5.5.2 Liquid Waste Stream
There is no liquid waste stream from product and by-product storage.
3.3.5.5.3 Solid Waste Stream
Tanks will require cleaning at one time or another to remove sludges
from storage of hydrocarbon products. Thus, small amounts of waste sludges
will be generated on an intermittent basis.
193
-------
TABLE 3-67. UNCONTROLLED EVAPORATIVE EMISSIONS
FROM STORAGE TANKS (STREAM 751)
Product
Base Case
Naphtha
Blended
Fuel Oil
Phenol
MFS Case
Naphtha
Blended
Fuel Oil
Phenol
Total
Capacity, No. of Type of Uncontrolled
m3/tank Tanks Tanks Emissions*
kg/hr
41,200 2 Floating roof 2.14
36,800 2 Fixed roof 0.018
730 2 Fixed roof 0.022
40,000 2 Floating roof 2.14
34,000 2 Fixed roof 0.016
730 2 Fixed roof 0.022
* Uncontrolled emissions from fixed roof and floating roof storage tanks were
calculated based on emission equations listed in AP-42 (21).
194
-------
Products
3.3.6 Products
Liquid products from the EDS plant include C3 LPG, C. LPG, naphtha, and
blended fuel oil. The C3 LPG, C^ LPG, and blended fuel oil are produced as
finished products at the coal liquefaction plant according to either the base
case or the MFS case design. The naphtha product, however, requires further
processing prior to use as gasoline blendstock or in aromatics production. In
addition, a pipeline gas product is generated from the MFS case design.
The product yields, origins, and composition information are presented in this
section. By-products from pollution control operations include sulfur, ammonia
and crude phenol. These by-products are not covered here, but are briefly
addressed in Section 4 where the responsible control operations are discussed.
3.3.6.1 Pipeline Gas
Pipeline gas is obtained from the hydrogen recovery section (Hydrogen
plant - Area 4) of the MFS case design. The hydrogen recovery section cryo-
genically separates hydrogen, C^/C2 pipeline gas product, and C3 product gas
from the high pressure purge gases and low-pressure off-gases from liquefaction,
solvent hydrogenation, and Flexicoking. The pipeline gas becomes a net product
in the MFS case design because the C^/C,. gas is not needed for hydrogen produc-
tion by steam reforming, as in the base case design.
Total pipeline gas product from the MFS case design amounts to 1,991,000
o
Mm /stream day (70.3 MM SCFD, or 11,900 BFOE*). The pipeline gas contains 63.0
vol. % methane, 22.3 vol. % C2, 2.7 vol % C3+ hydrocarbons, 5.4 vol. % N2, 3.4
vol. % H2, and 3.2 vol. % CO, and has a lower heating value (LHV) of 40.3 MJ/Nm3
(1024 Btu/SCF) (13). Thus, this pipeline gas is similar to natural gas in that
methane is the primary constituent. The EDS pipeline gas, however, contains
* 1 barrel fuel oil equivalent (BFOE) = 6,050,000 Btu (LHV)
195
-------
Products
more C2 and C3 hydrocarbons and CO than natural gas.
3.3.6.2 LPG
Two LPG products, C3 LPG and C^ LPG, are produced from the product re-
covery section (Product separation and purification - Area 3) of the EDS
commercial plant. The C3 LPG contains 95.8 wt % C~, 0.9 wt % C?~, and 3.3 wt
% C4+ (13). The C4 LPG contains 95.1 wt % C4, 3.2 wt % C3~, and 1.7 wt % C5+(13),
For the base case design, the production rates of C., LPG and C» LPG are 0.236
Gg (463 m3; 2,915 bbl or 1,780 BFOE) per stream day and 0.227 Gg (393 m3; 2,465
bbl or 1,680 BFOE) per stream day, respectively (13). For the MFS case design,
the production rates of C3 LPG and C4 LPG are 0.334 Gg (667 m3; 4,198 bbl or
2,570 BFOE) per stream day and 0.235 Gg (405 m3; 2,548 bbl or 1,740 BFOE) per
stream day, respectively (13).
3.3.6.3 Naphtha
Naphtha is obtained from the product recovery section (Product separation
and purification - Area 3) of the EDS commercial plant. In product recovery,
the total distillate products from the atmospheric fractionator, the solvent
stripper, and the Flexicoker fractionator are fed to the deethanizer. The
bottoms product from the deethanizer is then fed to the debutanizer to yield
a stabilized naphtha product.
The naphtha product is estimated by Exxon to contain mainly the pentanes
to 350°F fraction. Elemental composition of this product is as follows: 85.20
wt % C, 13.16 wt % H, 0.43 wt I S, 0.06 wt % N, and 1.15 wt * 0 (13). Naphtha
was one of the two product streams sampled and analyzed by EPA at the EDS pilot
plant (37). However, the naphtha sampled was a distillate cut from the solvent
fractionation tower and does not necessarily represent the naphtha produced
from other process operations. In particular, the aromatic content of this
naphtha sample might be higher than in naphtha from commercial EDS facilities.
196
-------
Products
In Table 3-68, concentrations of trace metals present in this naphtha sample
are presented. In Table 3-69, results of organic analysis for the naphtha
sample are presented. These results indicated that approximately 80 percent
of the total organic concentration of the naphtha was aliphatic hydrocarbons.
The most prevalent aromatic compounds were benzenes and substituted benzenes.
Additional analyses for volatile organics also showed that about 80 percent of
the total organic concentration of the naphtha was volatile organics, as would
be expected for this light oil (37).
Based on Exxon's estimate (13), naphtha is produced at the rate of 2,880
o
Gg (3,770 m ; 23,710 bbl) per stream day for the base case design, and 2,824
Gg (3,695 m3; 23,243 bbl) per stream day for the MFS case design.
3.3.6.4 Blended Fuel Oil
The low sulfur fuel oil (LSFO) from the EDS commercial plant is obtained
by blending: 1) vacuum gas oil from the vacuum fractionation tower (Product
separation and purification - Area 2); 2) LSFO from the solvent fractionation
tower (Product separation and purification - Area 2); and 3) LSFO from Flexi-
coking (Liquefaction residue processing/hydrogen production - Area 4). Vacuum
gas oil may also be further processed by hydrocracking or catalytic cracking
to produce lighter products, but additional processing is not considered in
the current designs.
The fuel oil products from the base case and MFS case designs are slightly
different. In Table 3-70, the compositions of fuel oil products from the two
designs are compared. The fuel oil from the base case design contains a higher
percentage of the 1000°F+ fraction, and also slightly higher levels of sulfur
and nitrogen.
The LSFO from the solvent fractionation tower was the other product stream
sampled and analyzed by EPA at the EDS pilot plant (37). As in the case of
naphtha, the light solvent fuel oil sampled only represents part of the blended
197
-------
TABLE 3-68. CONCENTRATIONS OF TRACE METALS IN NAPHTHA
FROM EDS PILOT PLANT SOLVENT FRACTIONATION
TOWER
Element Concentration,
mg/1
Barium 0.013
Calcium 0.67
Iron 4.0
Magnesium 0.16
Manganese 0.029
Nickel 0.049
Potassium 0.32
Sodium 0.72
Data source: Reference 37.
198
-------
TABLE 3-69. CONCENTRATIONS OF ORGANIC COMPOUNDS IN
NAPHTHA FROM EDS PILOT PLANT SOLVENT
FRACTIONATOR TOWER
Organic Compound Concentration,
Class g/1
Aliphatic hydrocarbons 907.96
Ethers 9.55
Aldehydes and Ketones 2.88
Benzenes and Substituted Benzene Hydrocarbons 127.4
Phenols* 8.1
Heterocyclic Oxygen Compounds 47.8
Heterocyclic Sulfur Compounds 18.05
(Thiophenes)
Total 1,121.74
Data source: Reference 37.
* Breakdown for the phenols: 1.3 g/1 o-cresol, 5.9 g/1 C2 phenol, and 0.9
g/1 C~ phenol.
Note: Aromatic content of this naphtha sample might be
higher than in naphtha from commercial EDS facilities.
199
-------
TABLE 3-70. COMPARISON OF COMPOSITION OF FUEL OIL
PRODUCTS FROM THE EDS BASE CASE AND MFS
CASE DESIGNS
Component
Composition
C5/400°F, wt %
400/700° F, wt %
700/1000°F, wt %
1000°F, wt %
Elemental Composition
C, wt %
H, wt %
S, wt %
N, wt %
0, wt %
Base Case
19.0
34.0
29.1
17.9
87.56
8.83
0.54
0.77
2.30
MFS Case
19.2
35.2
31 .6
14.0
87.72
8.89
0.51
0.75
2.13
Data source: Tables l-S-2 and 2-S-2 of Reference 13,
200
-------
Products
fuel oil mix. In Table 3-71, concentrations of trace metals present in this
light solvent fuel oil sample are presented. In Table 3-72, preliminary
results of organic analysis for the light solvent fuel oil sample are present-
ed. Although complete analysis results are not yet available, the results to-
date indicated that the major organic components are: aliphatic hydrocarbons,
benzene and substituted benzene hydrocarbons consisting mostly of tetralin
and methyl tetralin, phenols, and heterocyclic oxygen compounds such as furans
and especially C^-Cg benzofurans (13). Comparable data for the vacuum gas oil
(VGO) and LSFO from Flexicoking are not publicly available. However, it is
anticipated that the blended fuel oil will contain more of the heavier hydro-
carbon fractions because both the VGO and the LSFO from Flexicoking are heavi-
er (13).
Based on Exxon's estimate (13), blended fuel oil is produced at the rate
of 6.033 Gg (5,868 m3; 36,910 bbl or 36,680 BFOE) per stream day for the base
case design, and 5.788 Gg (5,625 m ; 35,378 bbl or 35,160 BFOE)per stream day
for the MFS case design.
201
-------
TABLE 3-71. CONCENTRATIONS OF TRACE METALS IN LIGHT
SOLVENT FUEL OIL FROM EDS PILOT PLANT
SOLVENT FRACTIONATION TOWER
Element Concentration,
mg/1
Aluminum 0.41
Barium 0.018
Boron 0.18
Calcium 1.2
Chromium 0.12
Copper 0.032
Iron 1.0
Magnesium 0.16
Manganese 0.028
Nickel 0.092
Potassium 0.36
Sodium 1.0
Strontium 0.006
Titanium 0.016
Data source: Reference 37.
202
-------
TABLE 3-72. CONCENTRATIONS OF ORGANIC COMPOUNDS IN
LIGHT SOLVENT FUEL OIL FROM EDS PILOT
PLANT SOLVENT FRACTIONATION TOWER
Organic Compound Concentration,
Class g/1
Aliphatic Hydrocarbons 54.64
Ethers 0.051
Aldehydes and Ketones 0.026
Thiols, Sulfides and Disulfides 0.002
Benzene and Substituted Benzene 58.74
Hydrocarbons
Phenols* 19.06
Fused Polycyclic Hydrocarbons 11
Fused Non-Alternant Polycyclic 1.4
Hydrocarbons t
Heterocyclic Nitrogen Compounds 0.0091
Heterocyclic Oxygen Compounds 140.21
Heterocyclic Sulfur Compounds 0.023
(Thiophenes)
Total 285.16
Data source: Reference 37. These results are preliminary.
* Breakdown for the phenols: 0.059 g/1 phenol, 7.7 g/1 methyl naphthol,5.5
g/1 C~ naphthol, 5.4 g/1 C., naphthol, and 0.4 g/1 C. naphthol.
The only fused polycyclic hydrocarbon identified was methyl naphthalene.
T The only fused non-alternant polycyclic hydrocarbon identified was fluorene.
203
-------
Fugitive Organic
Emissions
3.3.7 Fugitive Organic Emissions
Fugitive organic emissions from the EDS commercial plant are not derived
from any one process area alone. For this reason, these emissions are dis-
cussed in this separate section.
3.3.7.1 Air Fugitives
There are many potential sources of fugitive organic air emissions in a
typical EDS direct coal liquefaction plant. Some of these are: pumps, com-
pressors, in-line process valves, pressure relief devices, open-ended valves,
sampling connections, and flanges. Extensive tests and measurements for fugi-
tives have been performed at petroleum refineries (38). As a result of this
testing, average emission factors were developed for fugitive emission sources
such as pump seals, compressor seals, valves, etc. (39). These factors were
applied to synfuel plants because it was assumed that synfuel plant operations
are similar to petroleum refining operations. However, it should be recognized
that emissions of fugitive organics from EDS plants and petroleum refineries
could differ in two aspects: 1) emission factors could differ since coal lique-
faction slurries are abrasive and could cause more leaks in some parts of the
plant than conventional refinery experience would suggest; and 2) compositions
of fugitive organic emissions could differ significantly, depending on the
compositions of process streams. Limited data are available on the concentra-
tions of organic compounds in some of the wastewater streams (e.g., Table 3-14
for liquefaction cold separator wastewater) and product streams (e.g., Table
3-69 for naphtha) from the 250 ton coal/'day EDS pilot plant. Fugitive organic
emissions from the EDS commercial plant are expected to contain some of the
same constituents as found in the wastewater streams and product streams, such
as aliphatic hydrocarbons, benzene and substituted benzene hydrocarbons, and
phenols.
204
-------
Fugitive Organics Emissions
Fugitive emissions estimates were made by estimating the number of each
type of emission source and applying an emission factor with no adjustment
for size, pressure or flow rate. Estimates of the number of valves, flanges,
pump seals, compressor seals, drains, relief valves and sampling connections
in the EDS commercial plant were provided by Exxon (40).
The process streams associated with each piece of equipment were classi-
fied with respect to percent hydrocarbon content and hydrocarbon type. Dif-
ferent factors were used for liquid streams containing light and heavy hydro-
carbons. Liquid streams containing C2 through Cg hydrocarbons, naphtha and
other light aromatic hydrocarbons were classified as light. Coal liquids,
low sulfur fuel oil, and other heavy hydrocarbons were classified as heavy.
All emissions 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% hydrocarbons were con-
sidered to contain 100% hydrocarbons. 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 given and not altered by percent hydrocarbon content.
Results of these fugitive emission calculations for eht EDS process are
given in Table 3-73. Since separate component counts distinguishing the two
EDS designs are not available, it is assumed that the total fugitive hydro-
carbon emissions of 153 kg/hr apply equally to the base case design or the
MFS case design. Also, only a small portion of the total uncontrolled hydro-
carbon emissions in Table 3-73 are likely to be low-volatile heavy organics,
which would be expected to contain most of the compounds of health concern.
3.3.7.2 Liquid Fugitives
Liquid fugitives from the EDS commercial plant include spills, leaks,
and area runoffs. At the present time, it is not possible to estimate the
205
-------
TABLE 3-73.
UNCONTROLLED FUGITIVE HYDROCARBON
EMISSIONS FROM EDS COMMERCIAL PLANT
Components/
Service
Pump Seals
Light Liquid
Heavy Liquid
Compressor Seals
Hydrocarbon
Hydrogen
Drains
Light Liquid
Heavy Liquid
Relief Valves
Flanges
Valves
Gas/Vapor
Light Liquid
Heavy Liquid
Hydrogen
Sampling Connections
Total
Total No. of
Components
78
164
57
18
150
300
252
25,535
1,211
1,787
3,575
519
141
Emission
Factor, *
kg/hr/unit
0.113
0.0209
0.635
0.0499
0.0318
0.0454
0.0862
0.000254
0.0268
0.0109
0.000227
0.00816
0.00227
Uncontrolled
Hydrocarbon
Emissions
kg/hr
8.85
3.40
36.2
0.90
4.76
13.61
21.73
6.49
32.39
19.46
0.82
4.22
0.32
153.15
Data source: Component counts of emission sources are provided by Exxon (40);
emission factors are obtained from Reference 39.
* These emission factors were determined using test data from a statistically
valid sample of petroleum refineries, and reflect the average of a range of
equipment types and maintenance practice.
206
-------
Fugitive Organic Emissions
nature of liquid fugitives caused by leaks or spills. Based on the maximum
25 year, 24 hour rainfall of 5.1 inches and 100% runoff, Exxon estimated a
maximum dirty rain runoff (low quality rain runoff - Stream 901) of 318 m /hr
during the period of the rainfall. This low quality rain runoff is expected
to contain components present in the process and product/by-product streams,
oil and grease, and moderately high levels of total dissolved solids.
207
-------
Other Areas
3.3.8 Other Areas
There are a number of other operations in the EDS commercial plant that
generate waste streams, especially in the pollution control operations pro-
cess area. Waste streams from these operations are considered secondary dis-
charge streams and are not covered here because Section 3 only addresses un-
controlled waste streams.
Some of the major pollution control operations that generate waste
streams are:
0 Sulfur recovery plant and associated tail gas treatment plant
• Sour water stripping/ammonia recovery system
0 Phenolic extraction unit
• Wastewater treatment operations
• Particulate control and flue gas desulfurization systems for steam
and power generation
• Incinerators/flaring for organic and CO containing gases
• Incinerators for solid residue/sludge disposal
• Solid waste disposal area.
Waste streams from these operations are discussed in Section 4 of this docu-
ment.
208
-------
3.4 SUMMARY OF UNCONTROLLED DISCHARGES BY MEDIUM
The uncontrolled discharges from the EDS commercial plant are summarized
in tabular form in this section. The summary provided is broken down by
medium and by process area. All uncontrolled waste streams, including inter-
mittent discharges, are listed. In the summary tables, estimated uncontrolled
mass emission rates of selected pollutants are presented. These pollutants
were selected for presentation on the basis that they are generally of inter-
est in the selection and evaluation of pollution control technologies. Detail-
ed characterization of the uncontrolled waste streams which includes additional
information on individual compounds has been presented in Section 3.3. Secon-
dary waste streams from control technologies are discussed in Section 4 and
not addressed here. The emission rates presented correspond to an EDS commer-
cial plant processing 1,134 Mg/hr (30,000 tons per stream day) of "as received"
Illinois No. 6 coal in the liquefaction area. Discharges shown are uncontrol-
led in order to facilitate consideration of control alternatives in Section 4.
Of course, in a commercial EDS plant, suitable controls will be placed on these
streams.
3.4.1 Gaseous Haste Streams
The total molar flow rate and mass emission rates for gaseous waste streams
are summarized in this subsection according to process area. Mass emission
rates for nine pollutants are presented: total hydrocarbons, CO, H2S, NFL, COS,
S02, HCN, NOX (as N02), and particulate matter.
3.4.1.1 Base Case
The characteristics of uncontrolled gaseous waste streams for the EDS base
case design are summarized in Table 3-74. To avoid duplicate accounting, the
Flexicoking gasifier/heater sour fuel gas (Stream 304) is assumed to be untreat-
ed and contains all the sulfur present as H^S and COS, whereas flue gas streams
resulting from the combustion of this low-Btu fuel gas are assumed to contain
levels of S02 corresponding to the treated fuel gas (80 ppmv COS and 3 ppmv H?S).
Also, two totals are shown in Table 3-74, one for normal operation (no intermit-
tent streams), another for the hypothetical worst case if all intermittent
streams are discharging at the same time.
209
-------
TABLE 3-74. SUMMARY OF UNCONTROLLED GASEOUS WASTE STREAMS FROM EDS COMMERCIAL PLANT
(ILLINOIS COAL BASE CASE)
Total
Flow,
Uncontrolled Waste Stream kmol/hr
Coal Preparation Process Area (Area 1)
Stream Oil - fugitive dust from coal pile N/A*
Stream 013 - fugitive participates from coal N/A
handling and crushing
Coal Liquefaction Process Area (Area 2)
Stream 102 - slurry drier vent gas 532
Stream 107 - flue gas from liquefaction slurry 34,535
preheat furnace
Stream 803 - transient waste gas from liquefaction 3,280
reactor (intermittent)**
Product Separation and Purification Process Area
(Area 3)
Stream 153 - vacuum fractionator off-gas1"1"1' 69
Stream 203 - flue gas from solvent hydrogenerator 3,864
fuel preheat furnaces
Streaa 508 - icld gti from DEA regenerator 1,214
Liquefaction Residue Processing/Hydrogen Production
Process Area (Area 4)
Stream 304 - Flexicoking gasifier/heater sour fuel 54,781
gasttt
Stream 426 - vent gas from C02 removal by Catacarb 6,100
process
Stream 434 - flue gas from hydrogen plant 58,022
reformer furnaces
Stream 438 - hydrogen plant deaerator vent 6.5
Stream 446 - regeneration/decommissioning off -gas 6,800
from reformer catalyst (intermittent)
Stream 448 - decommissioning off-gas from ++ 5,000
methanation catalyst (intermittent)''''
Stream 801 - transient waste gas from Flexicoking 671
(intermittent)***
Emission Rate, kg/hr
Total
Hydrocarbon CO HgS NH3 COS
0 0000
0 0000
2,129 0 0.54 0 0
2.4 14-20 000
30,836 426 2,849 2.7 0
1,512 0 117 0 0
0.27 1.5-2.3 000
0 0 26,562 812 27
13,336 275,509 7,811 0 354
35 27 000
4.1 23-34 000
0 <0.5 000
No datat No data 000
No data No data 000
5.387 748 239 0 0
S02 HCN
0 0
0 0
0 0
91 0
0 0
0 0
10 0
0 0
0 0
0 0
150 0
0 0
0 0
0 0
0 0
Paniculate
N0x Matter
0
0
0
97-
186
0
0
11-
21
0
0
0
163-
313
0
No
data
No
data
0
(Continued)
51
161-2,548
0
4-12
0
0
0.45-1.4
0
0
0
7-21
0
No data
No data
0
-------
TABLE 3-74. (Continued)
ro
Uncontrolled Waste Stream
Auxiliary Operations Process Area (Area 5)
Stream 701a - flue gas from steam generation
system
Stream 707a - flue gas from power generation
system
Stream 731 - drift and evaporation from cooling
tower
Stream 751 - evaporative emissions from product/
byproduct storage
Fugitive organic emissions from pump and compressor
seals, valves, pipe flanges, pressure relief valves,
and drains
Total uncontrolled emissions excluding intermittent
emissions
Total uncontrolled emissions Including intermittent
emissions
Total
Flow, Total
kmol/hr Hydrocarbon
42,560 7.2
36,450 14.3
N/A No data
0.02f 2.2
1.5f 153
238,135 17,196
253.886 53,418
Emission Rate,
CO H2S
28 -
34 0
48 0
0 0
0 0
0 0
277,800 34,491
278,974 37,579
NH3
0
0
0
0
0
812
815
kg/hr
COS
0
0
0
0
0
381
381
S02 HCII
2.522 0
6.659 0
0 0
0 0
0 0
9.432 0
9.432 0
N0x
297 -
366
601
0
0
0
1.169-
1.487
1.169-
1.487
Participate
Matter
2,187
5.927
No data
0
0
8.337-
10.747
8,337-
10.747
N/A - not applicable
fEstimated assuming sn average Molecular weight of 100.
Streams with no data on the pollutant are not expected to contribute significantly to the total emission of the pollutant.
**
Transient conditions would be expected twice per year for each of the four reactors, and up to 3 hours 1n duration each time.
t+Estimated emission frequency 1s once a year, with an average emission duration of 24 hours.
Estimated emission frequency 1s once every four years, with an average emission duration of 24 hours.
***
Transient conditions would be expected 30 times per year for each of the three units, and up to 3 hours 1n duration each time.
tttThese gas streams will normally be desulfurized and burned within the plant as fuel gas.
-------
As shown in Table 3-74, the Flexicoking gasifier/heater sour fuel gas
(Stream 304) is the major contributor to hydrocarbon and CO emissions. This,
of course, is an unlikely situation because Stream 304 will be used as fuel
gas within the EDS plant. Other than the sour fuel gas, the two major contri-
butors to hydrocarbon emissions are the slurry drier vent gas and the vacuum
fractionator off-gas, both also contain sufficient heating value to be used
as in-plant fuel gas. With these exceptions, hydrocarbon emissions are mostly
contributed by fugitive emissions from pump and compressor seals, valves, pipe
flanges, pressure relief valves and drains. Total uncontrolled hydrocarbon
emissions were estimated to be 17,200 kg/hr if intermittent streams are ex-
cluded, and 53,400 kg/hr if all intermittent streams are included. If one ex-
cludes the gas streams which would likely be burned within the plant as fuel
gas -- sour fuel gas (Stream 304), slurry drier vent gas (Stream 102), and
vacuum fractionator off-gas (Stream 153) — and if one excludes the intermit-
tent streams, then uncontrolled hydrocarbon emissions would be only 218 kg/hr.
The acid gas from the DEA regenerator (Stream 508) is the largest source
of sulfur emissions (in the form of H2$) within the plant. Of course, in
practice, this acid gas will be treated in a sulfur recovery system. If un-
treated, SOp emissions from the combustion of the sour fuel gas (Stream 304)
would also be significant and greater than the uncontrolled S02 emissions from
coal combustion in the steam and power plants. Total sulfur emissions, ex-
pressed as S02 equivalent,* were estimated to be 74,680 kg/hr if intermittent
streams are excluded, and 80,500 kg/hr if intermittent streams are included.
Of the 74,680 kg/hr of emissions of S02 equivalent, approximately 67% are con-
tributed by the acid gas from the DEA regenerator.
Emissions of particulate matter were estimated to range from 8,340 to
10,750 kg/hr if intermittent streams are excluded. However, intermittent
streams are not expected to contribute significantly to emissions of particu-
late matter. Particulate emissions are derived mainly from three sources:
uncontrolled emissions from coal combustion in the steam plant (Stream 701a),
* 1 kg of H9S is equivalent to 1.8798 kg of S0?; 1 ka of COS is equivalent
to 1.0664% of S02. c
212
-------
uncontrolled emissions from coal combustion in the power plant (Stream 707a),
and fugitive particulates from coal handling and crushing (Stream 013).
3.4.1.2 NFS Case
The characteristics of uncontrolled gaseous waste streams for the EDS MFS
case design are summarized in Table 3-75. The contributions of various streams
to the total emission burden for the MFS case are similar to the contributions
for the base case, excpet in cases where the waste streams are unique to the
MFS case design. Contributions to the total emission burden from waste streams
unique to the MFS design, however, are relatively insignificant except for the
acid gas from the AGR unit in hydrogen purification (Stream 428).
For most pollutants listed in Table 3-75, emissions for the MFS case de-
sign are comparable to emissions for the base case design. The only exceptions
are the considerably lower uncontrolled hydrocarbon and CO emissions for the
MFS case design. This is because the sour fuel gas (Stream 304) for the MFS
case design is only half the size of the sour fuel gas for the base case design.
3.4.2 Liquid Waste Streams
Mass discharge rates for liquid waste streams are summarized in this sub-
section according to process area. The total mass discharge rate and the mass
discharge rates for nine pollutant parameters are presented. These nine pollu-
tant parameters are: F^S, NHo, HC1, COo, phenols, organic acids, COD, TOC, and
TDS. These are the most important parameters needed to evaluate pollution
control options.
3.4.2.1 Base Case
The characteristics of uncontrolled aqueous waste streams for the EDS
base case design are summarized in Table 3-76. There are eleven sour and
phenolic wastewater streams in the base case design. The slurry drier cold
separator wastewater (Stream 103) is a non-sour phenolic wastewater stream.
The other ten sour and phenolic wastewater streams are Streams 106, 152, 155,
202, 252, 307, 308, 312, 430 and 431. Streams 430 and 431 would be expected
to contain only trace levels of contaminants; Stream 430 only contains trace
levels of C02 and Stream 431 contains 600 ppmv CO-. In addition, Streams 451
and 452 contain NH3 that require removal/recovery; although Stream 452 only
213
-------
TABLE 3-75. SUMMARY OF UNCONTROLLED GASEOUS WASTE STREAMS FROM EDS COMMERCIAL PLANT
(ILLINOIS COAL MFS CASE)
ro
Tnt T 1
1 ULd 1
Flow, Total
Uncontrolled Waste Stream kmol/hr Hydrocarbon
Coal Preparation Process Area (Area 1)
Stream Oil - fugitive dust from coal pile N/A* 0
Stream 013 - fugitive particulates from coal N/A 0
handling and crushing
Coal Liquefaction Process Area (Area 2)
Stream 102 - slurry drier vent gas 532 2,129
Stream 107 - flue gas from liquefaction slurry 34,535 2.4
preheat furnace
Stream 803 - transient waste gas from liquefaction 3,280 30,836
reactor (intermittent)**
Product Separation and Purification Process Area
(Area 3)
Streams 153/156 - vacuum fractionator off-gas1"1"* 69 1,512
Stream 161 - flue gas from partial oxidation feed 425 0.03
vacuum fractionator preheat
furnaces
Stream 203 - flue gas from solvent hydrogenation 3,864 0.27
fuel preheat furnaces
Stream 508 - add gas from DEA regenerator 1,214 0
Liquefaction Residue Processing/Hydrogen Production
Process Area (Area 4)
Stream 304 - rlexicoking gasifier/heater sour fuel 27,225 6,677
gasttt
Stream 428 - acid gas from add gas removal unit 13,304 4.8
1n hydrogen purification
Stream 438 - hydrogen plant deaerator vent 6.2 0
Stream 440 - flash gas from partial oxidation unit 254 1.3
Stream 449/450 - regeneration/decommissioning off- 22,255 0
gas from high and low temperature
shift catalysts (intermittent)
Emission Rate, kg/hr
Particulate
CO H?S NH3 COS S02 HCN NOX Hatter
0 000 000 52
0 000 000 165-2.623
0 0.54 00 000 0
14-20 000 91 0 97- 4-12
186
426 2,849 2.7 0 0000
0 117 0 0 0000
0.17-0.25 000 1.1 0 1.2- 0.05-0.15
2.3
1.5-2.3 000 10 0 11- 0.45-1.4
21
0 26,562 812 27 0000
132,643 4,124 0 150 0 0 0 0
22 4,672 152 30 0000
<0.5 000 0000
2,176 382 0.68 18 0 0 0 0
0 000 15,683 0 0 608
(Continued)
-------
TABLE 3-75. (Continued)
Total
Flow,
Uncontrolled Waste Stream kmol/hr
(Area 4) (Continued)
Stream 801 - transient waste gas from Flexicoking 511
(intermittent)tt
Stream 802 - transient waste gas from partial 12,121
oxidation units (intermittent)***
Auxiliary Operations Process Area (Area 5)
Stream 701a - flue gas from steam generation 69,150
system
Stream 707a - flue gas from power generation 26,110
system
Stream 731 - drift and evaporation from cooling N/A
tower
ro
en Stream 751 - evaporative emissions from product/ 0.02f
byproduct storage
Fugitive organic emissions from pump and compressor 1.5
seals, valves, pipe flanges, pressure relief valves,
and drains
Total uncontrolled emissions excluding intermittent 176,690
emissions
Total uncontrolled emissions Including intermittent 214,857
emissions
Emission Rate, kg/hr
Total
Hydrocarbon CO H2S NH3 COS S02 HCN NOX
4,372 566 262 126 0 000
390 60,242 1,244 36 186 0 2.6 0
16 55 " 000 6,528 0 75$ "
10 34 000 4,775 0 431
No datar 0 000 000
2.2 0 000 000
153 0 000 000
10,508 134,957 35,858 965 225 11,405 0 896-
1.076
46,106 196,190 40,213 1,129 411 27.088 2.6 1.210-
1.390
Particulate
Matter
0
0
5.741
4.245
No data
0
0
10,208-
12.«75
10,816-
13.283
N/A - not applicable.
Estimated assuming an average molecular weight of 100.
Not expected to contribute significantly to the total emissions of the pollutant.
Transient conditions would be expected twice per year for each of the four reactors, and up to 3 hours in duration each time.
Estimated emission frequency of once a year, with emission duration from 12 to 72 hours.
Transient conditions would be expected 30 times per year for each of the two units, and up to 3 hours in duration each time.
ttt
Transient conditions expected once a year, and only to one of the partial oxidation units and up to 24 hours in duration.
These gas streams will normally be desulfurlzed and burned within the plant as fuel gas.
-------
TABLE 3-76. SUMMARY OF UNCONTROLLED LIQUID WASTE STREAMS FROM EDS COMMERCIAL PLANT
(ILLINOIS COAL BASE CASE)
Uncontrolled Waste Stream
Coal Preparation Process Area (Area 1)
Stream 012 - coal pile runoff
(intermittent)
Coal Liquefaction Process Area (Area 2)
Stream 103 - slurry drier cold separator
wastewater
Stream 106 - liquefaction cold separator
wastewater
Product Separation and Purification Process
Area (Area 3)
Stream 152 - atmospheric fractionator
overhaul drum wastewater
Stream 155 - vacuum fractionator
wastewater
Stream 202 - solvent hydrogenation
cold separator wastewater
Stream 252 - solvent hydrogenation frac-
tionator overhead drum
wastewater
Liquefaction Residue Processing/Hydrogen
Production Process Area (Area 4)
Stream 307 - Flexicoking recontacting
drum wastewater
Stream 308 - Fle*icoking fractlon3tor
overhead drum wastewater
Stream 312 - Flexicoking heater overhead
drum wastewater
Stream 403 - knockout drum wastewater in
H2 cryogenic recovery
Stream 430 - blowdown and K.O. drum waste-
water from hydrogen generation
Total Discharge Rate, kg/hr
Rate, Organic
kg/hr H2S NHj HC1 C02 Phenols Acids COD TOC IDS
17,333 000 0 00 Low* Low* 139"
155,640 0.6 12 2 46 151 0 No data No data No data 1
100,583 3,251 2,297 249 1,956 1,380 745 5.933 1,950 810
29,105 122 157 37 9.5 536 91 3,280 1,024 5.4
4,839 41 0.2 0.1 3.5 24 1.6 21 6-3 0.7
12,561 730 684 0 0 13 0 No data No data No data
12,461 333 232 0 0 64 0 678 131 0.4
1,312 23 31 0 34 9.5 0 No data No data No data
99,910 177 ?14 IS ?fil 389 0 No data NO data No data
28,400 171 396 0 616 0.5 0 NO data No data No data
1,334 000 0 00 00 No data
55,430 000 0 00 0 ONo data
(Continued)
-------
TABLE 3-76. (Continued)
Uncontrolled Waste Stream
Area 4 (Continued)
Stream 431 - Catacarb overhead receiver
wastewater in hydrogen
generation
Stream 451 - aqueous ammonia from
ammonia synthesis
Stream 452 - knockout drum wastewater
in ammonia synthesis
Auxiliary Operations Process Area (Area 5)
Stream 702 - blowdown from steam
generation system
Stream 708 - blowdown from power
generation system
Stream 723 - regeneration wastes from
water demineral ization
Stream 732 - cooling tower blowdown
Low quality rain runoff (intermittent)
Total uncontrolled discharge excluding
intermittent discharges
Total uncontrolled discharge including
intermittent discharges
Total
Di scharge
Rate,
kg/hr H-S NH,
22,690 0 0
22,560 0 2,600
454 0 0
67,000 0 0
2,800 0 0
30,000 0 0
630,000 0 0
318,000 0 0
1,277,079 4,849 6,623
1,612,412 4,849 6,623
Discharge Rate, kg/hr
HC1
0
0
0
0
0
0
0
0
303
303
co2
14
0
0
0
0
0
0
0
2,940
2,940
Organic
Phenols Acids COD TOC TDS
00 0 0 No data
00 0 0 No data
00 0 0 No data
0 0 Low Low 268
0 0 Low Low 0.6 - 1.4
0 0 Low Low 494**
0 0 Low Low 315
No data No data No data No data No data
2,567 838 No data No data 1,755
2,567 838 No data No data 1,894
Typical COD and TOC values for Streams 012, 702, 708, 723, and 732 are below 100 mg/1 (36).
TDS for coal pile runoff was computed assuming a TDS value of 8,000 mg/1. TDS values for coal pile runoff can vary over a very wide range (e.g., 3,000
to 20,000 mg/1) (36).
Although no data are publicly available, TDS for Streams 103, 202, 307, 308, 312, 403, 430, 431, 452, are expected to be low.
The TDS value for this waste stream was estimated from the concentrations of sulfate, nitrate, and chloride compounds present to be 16,460 mg/1.
-------
contains trace levels of NFL. These thirteen wastewater streams from Areas
2, 3 and 4 are unique to the EDS process and contribute a major portion of
all pollutant loadings except IDS. Discharges from auxiliary operations and
intermittent runoff streams, although comparably larger in magnitude, are ex-
pected to contribute mainly to the IDS loading of wastewater streams from the
EDS process.
3.4.2.2 MFS Case
The characteristics of uncontrolled aqueous waste streams for the EDS
MFS case design are summarized in Table 3-77. There are also eleven sour
and phenolic wastewater streams in the MFS case design. As in the base case,
Stream 103 is a non-sour phenolic wastewater stream. The other ten sour and
phenolic wastewater streams are Streams 106, 152, 155/157, 202, 252, 307, 308,
312, 430 and 441. Of these streams, Stream 430 would be expected to be rela-
tively free of contaminants and contain only trace levels of H2S, NH3, and C02-
The slag filtrate from the partial oxidation unit (Stream 443) is expected to
contain low levels of H2S and phenols. Again, wastewater streams from Areas
2, 3 and 4 are unique to the EDS design and would have major impact on the
selection of wastewater treatment processes. Wastewater streams from auxil-
iary operations and intermittent runoff streams only have impact on the total
flow of wastewater and the TDS loading.
3.4.3 Solid Waste Streams
Mass discharge rates for solid wastes are summarized in this subsection
in tabular form. The presentation of the solid waste summary, however, is
different from the summary for gaseous and liquid waste streams in two aspects.
First, composition data and leaching characteristics for solid wastes are pre-
sented in a more descriptive format. This is because quantitative composition
data for most solid wastes are not available, and leaching characteristics are
only available for three solid wastes. Second, the generation rate for solid
wastes is expressed as Mg/yr; no hourly rate is given. This is because only
six solid wastes are generated on a continuous basis and an annual rate pro-
vides a better indication of the solid waste disposal/recovery requirements.
218
-------
ro
TABLE 3-77. SUMMARY OF UNCONTROLLED LIQUID WASTE STREAMS FROM EDS
COMMERCIAL PLANT (ILLINOIS COAL MFS CASE)
Uncontrolled Waste Stream
Coal Preparation Process Area (Area 1)
Stream 012 - coal pile runoff
(intermittent)
Coal Liquefaction Process Area (Area 2)
Stream 103 - slurry drier cold
separator wastewater
Stream 106 - liquefaction cold sepa-
rator wastewater
Product Separation and Purification Process
Area (Area 3)
Stream 152 - atmospheric fractionator
overhead drum wastewater
Stream 155/157 - vacuum fractionator
wastewater
Stream 202 - solvent hydrogenation cold
separator wastewater
Stream 252 - solvent hydrogenation frac-
tionator overhead drum
wastewater
Liquefaction Residue Processing/Hydrogen
Production Process Area (Area 4)
Stream 307 - Flexicoking recontacting drum
wastewater
Stream 308 - Flexicoking fractionator over-
head drum wastewater
Stream 312 - Flexicoking heater overhead
drum wastewater
Stream 403 - knockout drum wastewater in
H, cryogenic recovery
Stream 430 - blowdown and knockout drum
Total
Rate,
kg/hr H2S NH3
17,708 0 0
155,640 0.6 12
100,583 3,251 2,297
29,105 122 157
4,839 41 0.2
12,561 730 684
12,461 333 232
656 12 16
49,955 89 107
14,200 86 198
1,334 0 0
3,110 0 0
Discharge Rate, kg/hr
Organic
HC1 C02 Phenols Acids
00 00
2 46 151 0
249 1,956 1,380 745
37 9.5 536 91
0.1 3.5 24 1.6
0 0 13 0
0 0 64 0
0 17 4.8 0
7.3 131 194 0
0 308 0.2 0
0000
0000
COD TOC TDS
Low* Low* 142f
No data No data NO data!
5,933 1.950 810
3,280 1.024 5.4
21 6.3 0.7
No data No data No data
678 131 0.4
No data No data NO data
No data No data
No data No data No data
0 0 No data
0 0 No data
wastewater from hydrogen
generation
(Continued)
-------
TABLE 3-77. (Continued)
Uncontrolled Waste Stream
Area 4 (Continued)
Stream 441 - sour water from the partial
oxidation unit
Stream 443 - slag filtrate from the
partial oxidation unit
Auxiliary Operations Process Area (Area 5)
Stream 702 - blowdown from the steam
generation system
Stream 708 - blowdown from the power
generation system
j^ Stream 723 - regeneration wastes from
O water demineralization
Stream 732 - cooling tower blowdown
Low quality rain runoff (intermittent)
Total uncontrolled discharge excluding
intermittent discharges
Total uncontrolled discharge including
intermittent discharges
Total
Di echa rge
Rate,
kg/hr HjS NH3
45,550 3-15 56-123
9,320 <0.06 1.2-3.5
55,000 0 0
2,000 0 0
34,000 0 0
510,000 0 0
318,000 0 0
1,040,314 4,674 3,795
1,376,022 4,674 3,795
Discharge Rate, kg/hr
HC1 C02 Phenols
No data No data 0.001
No data No data <0.0001
000
000
000
000
0 0 No data
295 2,471 2,367
295 2,471 2,367
Organic
Acids COD TOC
No data 18-35 10-35
0.45-2.1 0.26-0.35 0.26-
0.35
0 Low Low
0 Low Low
0 Low Low
0 Low Low
No data No data No data
838 No data No data
838 No data No data
TDS
19-91
0.26-3.3
220
1
560
255
No data
1,909
2,051
Typical COD and TOC values for streams 012, 702, 708, 723 and 732 are below 100 mg/1 (36).
•4-
TDS for coal pile runoff was computed assuming a TDS value of 8,000 mg/1. TDS values for coal pile runoff can vary over a very wide range (e.g.,
3,000 - 20,000 mg/1) (36).
Although no data are publicly available, TDS for Streams 103, 202, 307. 308. 312, 403, and 430 are expected to be low.
*
The TDS value for this waste stream was estimated from the concentrations of sulfate, nitrate, and chloride compounds present to be 16,460 mg/1.
-------
3.4.3.1 Base Case
The characteristics of uncontrolled solid waste streams for the EDS base
case design are presented in Table 3-78. As shown in this table, the four
solid wastes from Flexicoking (Streams 302, 303, 306 and 313) are responsible
for 97.2 wt % of the total uncontrolled solid wastes generated for the base
case design. There are four other major solid waste streams if air pollution
controls are installed on the steam and power plants, as would be expected.
These four solid waste streams are: fly ash from steam generation system, FGD
sludge from steam generation system, fly ash from power generation system, and
FGD sludge from power generation system. Sludge generated in wastewater treat-
ment is a major solid waste stream from water pollution control.
3.4.3.2 MFS Case
The characteristics of uncontrolled solid waste streams for the EDS base
case design are presented in Table 3-79. For the MFS case, the four solid
wastes from Flexicoking (Streams 302, 303, 306 and 313) together with the
slag from the partial oxidation unit (Stream 442) are responsible for 96.9
wt % of the total uncontrolled solid wastes generated. As in the base case
design, there are four other major solid wastes if flue gas emissions from
steam and power plants are controlled, and a large sludge waste stream from
wastewater treatment.
3.4.4 Product Streams
The product rates and composition of EDS products are summarized in this
subsection. Since only limited product composition data that address indivi-
dual compounds or compound classes are available, this information is summar-
ized in a descriptive format. By-products recovered from pollution control,
such as crude phenol, sulfur, and ammonia are not covered here.
3.4.4.1 Base Case
The characteristics of product streams for the EDS base case design are
+ o
presented in Table 3-80. Total production rate of C- liquids is 10,493 m
(66,000 bbl or 60,240 BFOE*) per stream day. Product composition data on naph-
tha and blended fuel oil are based on very limited and preliminary sampling
and analysis efforts.
221
-------
TABLE 3-78. SUMMARY OF UNCONTROLLED SOLID WASTES FROM EDS COMMERCIAL PLANT
(ILLINOIS COAL BASE CASE)
Uncontrolled Waste Stream
Generation
Rate,
Mg/yr
Composition Data/Leaching Characteristics
ro
PO
ro
Coal Liquefaction Process Area (Area 2)
Stream 108 - solids accumulated in slurry drier 820
Product Separation and Purification Process Area (Area 3)
Stream 204 - spent solvent hydrogenation catalyst (Ni-Mo) 821
Liquefaction Residue Processing/Hydrogen Production Process Area
(Area 4)
Stream 302 - Flexicoking gasifier/heater dry fines 137,950
Stream 303 - Flexicoking gasifier/heater wet fines 344,870*
Stream 306 - Flexicoking gasifier/heater bed coke 707,100
Stream 313 - Flexicoking heater/reactor chunks/agglomerates 19,860
Stream 404 - spent hydrotreater catalyst from cryogenic hydro- 68.5
gen recovery (Hi-Mo)
Stream 405 - spent drying agents from cryogenic hydrogen 263
recovery (zeolite)
Stream 433 - spent sulfur guard from hydrogen generation (ZnO) 271
Stream 435 - spent reformer catalyst from hydrogen generation 181
(Ni-U)
Stream 436 - spent shift catalyst from hydrogen generation 321
(iron oxide)
Stream 439 - spent methanation catalyst from hydrogen genera- 115
tion (NiO)
Stream 453 - spent drying agents from ammonia synthesis (alumina) 172
Stream 454 - spent ammonia synthesis catalyst (iron/iron oxide) 166
Auxiliary Operations Process Area (Area 5)
Stream 704 - bottom ash from steam generation system 3,900
Stream 710 - bottom ash from power generation system 10,740
Stream 722 - raw water treatment sludge 15,120*
Total uncontrolled solid waste 1,242,799
Similar in composition to feed coal.
Contains nickel, molybdenum, carbonaceous material, and sulfides.
Contains 80 wt % coal ash and 20 wt * carbonaceous material. Con-
centrations of leachate using EPA EP in ppmw: As <0.055; Ba - 1.76;
Cd - 0.0425; Cr - 0.0042; Pb - 0.0462; Hg - 0.0004; Se <0.036;
Ag <0.002.
Also contains 80 wt % coal ash and 20 wt % carbonaceous material
for the solids portion.
Contains 61 wt % coal ash and 39 wt % carbonaceous material. Con-
centrations of leachate using EPA EP in ppmw: As <0.036; Ba - 0.032;
Cd - <0.0066; Cr - <0.003; Pb - <0.019; Hg - 0.0009; Se - <0.055;
Ag - <0.0026.
Concentrations of leachinate using EPA EP in ppmw: As <0.055;
Ba - 0.0407; Cd <0.0048; Cr <0.0006; Pb <0.023; Hg <0.0002; Se <0.036;
Ag <0.002.
Contains nickel, molybdenum, carbonaceous material, and sulfides.
Similar in composition to zeolites (hydrated aluminoslllcates)
Contains zinc oxide, zinc sulfide, and carbonaceous material.
Contains 13 wt * Ni, 12.1 wt % U, 0.3 wt % K, alumina, carbonaceous
material and trace of sulfides.
Contains iron oxide and carbonaceous material.
Contains nickel oxide and carbonaceous material.
Contains alumina and traces of ammonia.
Contains mainly iron and iron oxides, 5-8°'. total of
and MgO, traces of NH., and ammonium compounds.
j, K.,0, CaO
Similar in composition to coal ash.
Similar in composition to coal ash.
Contains 36.4 wt % CaC03> 3.6 wt S Mg(OH)2> and 60 wt r, water.
40 wt % solids basis.
-------
TABLE 3-79. SUMMARY OF UNCONTROLLED SOLID WASTES FROM EDS COMMERCIAL PLANT
(ILLINOIS COAL MFS CASE)
Uncontrolled Waste Stream
Generation
Rate,
Mg/yr
Composition Data/Leaching Characteristics
ro
CO
Coal Liquefaction Process Area (Area 2)
Stream 108 - solids accumulated in slurry drier 820
Product Separation and Purification Process Area (Area 3)
Stream 204 - spent solvent hydrogeneration catalyst 821
Liquefaction Residue Processing/Hydrogen Production Process Area
(Area 4)
Stream 302 - Flexicoking gasifier/heater dry fines 65,670
Stream 303 - Flexicoking gasifier/heater wet fines 164,160*
Stream 306 - Flexicoking gasifier/heater bed coke 363,030
Stream 313 - Flexicoking heater/reactor chunks/agglomerates 9,660
Stream 404 - spent hydrotreater catalyst from cryogenic 37.2
hydrogen recovery (Hi-Mo)
Stream 405 - spent drying agents from cryogenic hydrogen 177
recovery (zeolite)
Stream 442 - slag from partial oxidation unit 447,300"
Stream 444 - spent high temperature shift catalyst from 451
hydrogen generation (Co-Mo)
Stream 445 - spent low temperature shift catalyst from 254
hydrogen generation (Co-Mo)
Auxiliary Operations Process Area (Area 5)
Stream 704 - bottom ash from steam generation system 10,400
Stream 710 - bottom ash from power generation system 7,700
Stream 722 - raw water treatment sludge 13,a??*
Total uncontrolled solid waste 1,083,957
Similar in composition to feed coal.
Contains nickel, molybdenum, carbonaceous material, and sulfides.
Contains 80 wt ; coal ash and 20 wt " carbonaceous material. Con-
centrations of leachate using EPA EP in ppmw: As <0.055; Ba - 1.76;
Cd - 0.0425; Cr - 0.0042; Pb - 0.0462; Hg - 0.0004; Se <0.036;
Ag <0.002.
Also contains 80 wt * coal ash and 20 wt % carbonaceous materials
for the solids portion.
Contains 61 wt " coal ash and 39 wt '.i carbonaceous material. Concen-
trations of leachate using EPA EP in ppmw: As <0.036; Ba - 0.032;
Cd - <0.0066; Cr <0.003; Pb <0.019; Hg - 0.0009; Se <0.055;
Ag <0.0026.
Concentrations of leachate using EPA EP in ppmw: As <0.055;
Ba - 0.0407; Cd <0.0048; Cr <0.0006; Pb <0.023; Hg <0.0002;
Se <0.036; Ag <0.002.
Contains nickel, molybdenum, carbonaceous material, and sulfides.
Similar in composition to zeolites (hydrated aluminoslHcates).
Similar in composition to coal ash with up to 2 wt % carbonaceous
material.
Contains cobalt, molybdenum, carbonaceous material, sulfides, sulfur,
and volatile trace metals.
Contains cobalt, molybdenum, carbonaceous material, sulfides, and
possibly volatile trace metals.
Similar in composition to coal ash.
Similar in composition to coal ash.
Contains 36.4 wt v, CaCO, 3.6 wt .. Mg(OH)2> and 60 wt % water.
40 wt % solids basis.
f79 wt % solids basis.
-------
3.4.4.2 MFS Case
The characteristics of product streams for the EDS MFS case design are
presented in Table 3-81. For this design, total production of C- liquids
o
amounts to 10,392 m (65,367 bbl or 59,180 BFOE) per stream day. However,
total production of hydrocarbon products when pipeline gas is included (as
•3
barrels fuel oil equivalent) increases to 11,300 m (71,080 bbl) of fuel oil
equivalent per stream day, or 18% higher than the base case design. Composi-
tion of products for the MFS case design are either similar or identical to
the composition of the same products for the base case design, except pipeline
gas is not produced in the base case.
1 barrel fuel oil equivalent (BFOE) = 6,050,000 Btu (LHV)
224
-------
TABLE 3-80. SUMMARY OF PRODUCTS FROM EDS COMMERCIAL PLANT (ILLINOIS COAL BASE CASE)
Production Rate
Product m3/SD bbl/SD BFOE*/SD
C3 LPG 464 2,915 1 ,780
C4 LPG 392 2,465 1,680
Naphtha 3,770 23,710 20,100
Blended fuel 5,868 36,910 36,680
oil
Total 10,493 66,000 60,240
Product Composition
Contains 95.8 wt % C3> 0.9 wt % C^, and 3.3 wt % cj
Contains 95.1 wt % C4, 3.2 wt % C~, and 1 .7 wt % C*
Contains 85.20 wt % C, 13.16 wt % H, 0.43 wt % S, 0.06
wt % N, and 1.15 wt % 0. Analysis of a naphtha sample
from the solvent fractionation tower indicated: 80 wt %
of total organics are aliphatic hydrocarbons, 11 wt %
are benzenes and substituted benzenes, and 0.7 wt % are
phenols.
Contains 87.56 wt % C, 8.83 wt % H, 0.54 wt % S, 0.77
wt % N, and 2.30 wt % 0. Preliminary analysis of a
light solvent fuel oil indicated that the major organic
compounds are aliphatic hydrocarbons, benzenes and sub-
stituted benzenes, phenols, and heterocyclic oxygen
compounds such as furans and especially C-,-C,- benzo-
furans. b
1 BFOE (barrel fuel oil equivalent) = 6,050,000 Btu (LHV).
-------
TABLE 3-81. SUMMARY OF PRODUCTS FROM EDS COMMERCIAL PLANT (ILLINOIS COAL MFS CASE)
Production Rate
Product m3/SD bbl/SD
Pipeline gas 1,991,000 70.3 MMSCFD
Nm3/SD
C3 LPG 667 4,198
C. LPG 405 2,548
BFOE*/SD
11,900 Contains
2.7 vol.
and 3.2
2,570 Contains
wt % C+.
1 ,740 Contains
Product Composition
63
%
vol
95
95
c?
L3
•
.8
.1
vol .
, 5.4
% CO.
wt %
wt %
% CH., 22.
vol. % N2,
C3, 0.9 wt
C,, 3.2 wt
3 vol . % C2,
3.4 vol. % H2,
% C~, and 3.3
% CZ, and 1 .7
Naphtha
Blended fuel
oil
3,695 23,243
5,625 35,378
Total excluding gas 10,392 65,367
Total including
pipeline gas
19,710
35,160
59,180
71,080
wt
C+.
Contains 85.20 wt % C, 13.16 wt % H, 0.43
wt % S, 0.06 wt % N, and 1.15 wt % 0. Ana-
lysis of a naphtha sample from the solvent
fractionation tower indicated: 80 wt % of
total organics are aliphatic hydrocarbons,
11 wt % are benzenes and substituted benzenes,
and 0.7 wt % are phenols.
Contains 87.72 wt % C, 8.89 wt % H, 0.51 wt
% S, 0.75 wt % N, and 2.13 wt % 0. Prelimi-
nary analysis of a light solvent fuel oil
indicated that the major organic components
are aliphatic hydrocarbons, benzenes and sub-
stituted benzenes, phenols, and heterocyclic
oxygen compounds such as furans and especially
C,=C,- benzofurans.
* 1 BFOE = 6,050,000 Btu (LHV).
-------
3.5 WASTE/CONTROL TECHNOLOGY INDEX
The preceding parts of this section have provided a general description
of base case and MFS case designs of the EDS process, and test data and
engineering estimates characterizing the uncontrolled or primary waste streams
expected. Section 4 of this manual presents information on the available con-
trol techniques for these primary waste streams and illustrative examples of
both individual control technologies and integrated systems of control tech-
nologies applied to specific streams. As will be discussed in Section 4, re-
siduals or secondary waste streams are generated as a result of the applica-
tion of some control technologies; control of secondary waste streams is dis-
cussed in conjunction with the illustrative examples in Section 4.
To aid users in locating 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 3-82 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 3-82 are grouped by the process area from which
they originate and then further grouped within each operation by waste medium.
Similar types of information on secondary waste streams are presented in Table
3-83. The entries in Table 3-83 are not meant to imply that those streams
will necessarily be found in EDS commercial plants, but that if the control
techniques listed are used, then those streams will be produced.
227
-------
TABLE 3-82. CROSS-REFERENCE INDEX FOR PRIMARY WASTE STREAMS
PCTM Section Reference
Process Area/Media/Waste Stream
Waste
Characterization
for
Control
Technique
Coal Preparation Process Area
Gaseous Waste Streams
Fugitive dust from coal pile (Stream Oil)
Fugitive particulate from coal handling
and crushing (Stream 013)
Liquid Waste Stream
Coal pile runoff (Stream 012)
3
3
3
.3
.3
.3
.1
.1
.1
.1
.2
.1
.1
.1
.2
4
4
4
.2
.2
.3
.4
.6
.2
Coal Liquefaction Process Area
ro
ro
oo
Gaseous Waste Streams
Slurry drier vent gas (Stream 102)
Flue gas from liquefaction slurry preheat
furnace (Stream 107)
Transient gas from liquefaction reactor (Stream 803)
Liquid Waste Streams
Slurry drier cold separator wastewater (Stream 103)
Liquefaction cold separator wastewater (Stream 106)
Solid Waste Stream
Solids accumulated in the slurry drier (Stream 108)
3
3
3
3
3
3
.3
.3
.3
.3
.3
.3
.2
.2
.2
.2
.2
.2
.1
.1
,1
.1
.2
.1
.1
.1
.1
.2
.2
.3
4
4
4
4
4
4
.2
.2
.2
?
?
.4
.1
.2
.1
1
1
.2
.4
.2
.5
.4, 4.3.1 .6
.1 , 4.3.1 .6
.3
Product Separation and Purification Process Area
Gaseous Waste btreams
Vacuum fractionator off-gas (Stream 153)
Partial oxidation feed vacuum fractionator off-gas
(Stream 156)
Flue gas from partial oxidation feed vacuum
fractionator preheat furnaces (Stream 161)
3
3
3
.3
.3
.3
.3
.3
.3
.1
.1
.1
.1
.1
.1
4
4
4
.2
.2
.2
.1
.1
.2
.4
.4
.2
(continued)
-------
TABLE 3-82. (Continued)
Process Area/Media/Waste Stream
Gaseous Waste Streams (continued)
Flue gas from solvent hydrogenation fuel product
furnaces (Stream 203)
Acid gas from DEA unit (Stream 508)
Liquid Waste Streams
Atmospheric fractionator overhead drum
wastewater (Stream 152)
Vacuum fractionator wastewater (Stream 155)
Partial oxidation feed vacuum fractionator
wastewater (Stream 157)
Solvent hydrogenation coal separator wastewater
(Stream 202)
Solvent hydrogenation fractionator overhead
£ drum wastewater (Stream 252)
vx>
Solid Waste Stream
Spent solvent hydrogenation catalyst (Stream 204)
Liquefaction Residue Processing/Hydrogen Production Process
Gaseous Waste Streams
Flexicoking gasifier/heater sour gas (Stream 304)
Vent gas from CO- removal (Stream 426)
Acid gas from acfd gas removal unit in hydrogen
purification (Stream 428)
Flue gas from hydrogen plant reformer furnaces
(Stream 434)
Hydrogen plant deaerator vent (Stream 438)
Flash gas from partial oxidation unit (Stream 440)
Regeneration/decommissioning off-gas from reformer
catalyst (Stream 446)
Decommissioning off-gas from methanation
catalyst (Stream 448)
PCTM Section
Waste Characterization
3.3.3.2.1
3.3.3.3.1
3.3.3.1 .2
3.3.3.1.2
3.3.3.1.2
3.3.3.2.2
3.3.3.2.2
3.3.3.2.3
Area
3.3.4.1.1
3.3.4.2.1
3.3,4.2.1
3.3.4.2.1
3.3.4.2.1
3.3.4.2.1
3.3.4.2.1
3.3.4.2.1
Reference for
Control Technique
4.2.2.2
4.2.1 .1 , 4.2.1
4.3.1 .1 , 4.3.1
4.3.1 .1 , 4.3.1
4.3.1 .1 , 4.3.1
4.3.1 .1 , 4.3.1
4.3.1 .1 , 4.3.1
4.4.5.1 , 4.4.6
4.2.1.3
4.2.3.1
4.2.1.2
4.2.2.2
4.2.3.2
4.2.1 .1 , 4.2.1 .
4.2.3.3
4.2.3.3
fi
fi
fi
fi
fi
fi
1
fi
(continued)
-------
TABLE 3-82. (Continued)
Process Area/Media/Waste Stream
Waste Characterization
PCTM Section Reference for
Control Technique
3.3.4.2.1
3.3.4.2.1
3.3.4.1.1
3.3.4.2.1
1.2
2.2
,4.2.2
3.3,
3.3
2.2
2.2
.4
.4
3.3.4.2.2
3.3.4.2.2
4.2.2.3
4.2.2.3
4.2.1 .5
4.2.1 .5
Gaseous Waste Streams (continued).
Regeneration/decommissioning off-gas from high
temperature shift conversion catalyst (Stream 449)
Regeneration/decommissioning off-gas from low
temperature shift conversion catalyst (Stream 450)
Transient gas from Flexicoking (Stream 801)
Transient waste gas from partial oxidation unit
(Stream 802)
Liquid Haste Streams
Flexicoking recontacting drum wastewater (Stream 307) 3,3.4,
Flexicoking fractionator overhead drum wastewater 3.3.4,
(Stream 308)
0 Flexicoking heater overhead drum wastewater (Stream 312) 3.3.4,
^ Knockout drum wastewater in H2 cryo recovery (Stream 403) 3.3.4,
Slowdown and K.O. drum wastewater from hydrogen 3.3
generation (Stream 430)
Catacarb overhead received wastewater in hydrogen 3.3.4.2.2
generation (Stream 431)
Sour water from partial oxidation unit (Stream 441)
Slag filtrate from partial oxidation unit (Stream 443)
Aqueous ammonia from ammonia synthesis (Stream 451)
Knockout drum wastewater in ammonia synthesis (Stream 452)
Solid Haste Streams
Flexicoking gasifier/heater dry fines (Stream 302) 3.3.4.1.3
Flexicoking gasifier/heater wet fines (Stream 303) 3.3.4.1.3
Flexicoking gasifier/heater bed coke (Stream 306) 3.3.4.1.3
Flexicoking heater/reactor chunks/agglomerates 3.3.4.1.3
(Stream 313)
4
4
4
4
4
4
4
4.
4.
4
•^
^
?
•^
•^
?
?
3
3
?
1
1
1
1
1
1
1
.1
.1
1
1 .
1 .
p
? .
.5,
.3,
?,
4
4
4
4
4
4
4
4
4
4
^
•^
?
•^
•^
?
?
.3
.3
3
1
1
1
1
1
1
1
.1
.1
1
fi
6
6
fi
6
6
fi
.6
.6
6
4.4.2.1 , 4.4.6.1 ,
4.4.6.2
4.4.2.1 , 4.4.6.1 ,
4.4.6.2
4.4.2.1, 4.4.6.1 ,
4.4.6.2
4.4.2.2, 4.4.6.1
(continued)
-------
TABLE 3-82. (Continued)
Process Area/Media/Waste Stream
PCTM Section Reference for
Waste Characterization
Control Technique
N>
10
Solid Waste Streams
Spent hydrotreater catalyst in H,, cryo recovery 3.3.4.2.3
(Stream 404) '
Spent drying agents in H2 cryo recovery (Stream 405) 3.3.4.2.3
Spent sulfur guard in hyarogen generation (Stream 433) 3.3.4.2.3
Spent reformer catalyst in hydrogen generation 3.3,4.2.3
(Stream 435)
Spent shift catalyst in hydrogen generation (Stream 436) 3.3.4.2.3
Spent methanation catalyst in hydrogen generation 3.3.4.2.3
(Stream 439)
Slag from partial oxidation unit (Stream 442) 3.3.4.2.3
Spent high temperature shift catalyst in hydrogen 3.3.4.2.3
generation (Stream 444)
Spent low temperature shift catalyst in hydrogen 3.3.4.2.3
_ generation (Stream 445)
Spent drying agents in ammonia synthesis (Stream 453) 3.3.4.2.3
Spent ammonia synthesis catalyst (Stream 454) 3.3.4.2.3
Auxiliary Operations Process Area
Gaseous Waste Streams
Flue gas from steam generation system (Stream 701a) 3.3.5.2.1
Flue gas from power generation system (Stream 707a) 3.3.5.2.1
Drift and evaporation from cooling tower (Stream 731) 3.3.5.3.1
Evaporative emissions from product and byproduct 3.3.5.5.1
storage (Stream 751)
Liquid Haste Streams
Slowdown from steam generation system (Stream 702) 3.3.5.2.2
Slowdown from power generation system (Stream 708) 3.3.5.2.2
Regeneration wastes from water demoralization 3.3.5.1.2
(Stream 723)
Cooling tower blowdown (Stream 732) 3.3.5.3.2
4.4.5.1, 4.4.6.1
4.4.5.1, 4.4.6.1
4.4.5.1, 4.4.6.1
4.4.5.1 , 4.4.6.1
4.4.5.1, 4.4.6.1
4.4.5.1, 4.4.6.1
4.4.2.4, 4.4.6.1
4.4.5.1 , 4.4.6.1
4.4.5.1, 4.4.6.1
4.4.5.1, 4.4.6.1
4.4.5.1 , 4.4.6.1
4.2.2.1
4.2.2.1
not evaluated*
4.2.5.1
4.3.2
4.3.2
4.3.2
4.3.2
(continued)
-------
TABLE 3-82. (Continued)
PCTM Section Reference for
Process Area/Media/Waste Stream Waste Characterization Control Technique
Solid Waste Streams
Bottom ash from steam generation system 3.3.5.2.3 4.4.2.5, 4.4.6.1
(Stream 704)
Bottom ash from power generation system 3.3.5.2.3 4.4.2.5, 4.4.6.1
(Stream 710)
Raw water treatment sludge (Stream 722) 3.3.5.1.3 4.4.2.8, 4.4.6.1
Fugitive Emissions
£3 Gaseous Waste Stream
CO
Fugitive organic emissions from process equipment 3.3.7.1 4.2.5.2
Liquid Waste Stream
Low quality rain runoff 3.3.7.2 not evaluated
*not evaluated - drift loss is part of the cooling tower design, and evaporative loss is a
function of the cooling tower operating A T.
not evaluated - but treatment for this wastewater is similar to treatment of Source Type 2
wastewater streams.
-------
TABLE 3-83. CROSS-REFERENCE INDEX FOR SECONDARY WASTE STREAMS FROM POLLUTION CONTROL OPERATIONS
PCTM Section Reference for
Control Technique/Secondary Haste
Waste
Characterization
Control
Technique
Appendix
ro
CO
CO
Air Pollution Control
Claus Process
Spent catalyst
Stretford Process
Oxidizer vent gas
Solution purge
Beavon Sulfur Removal Process (BSRP)
Oxidizer vent gas
Sour condensate
Stretford solution purge
Spent catalyst
Shell Claus Off-Gas Treating (SCOT) Process
Sour condensate
Spent catalyst
Wellman-Lord Process
Acidic wastewater
Thiosulfate/sulfate purge
Electrostatic Precipitators
Boiler fly ash
Limestone Scrubbing
FGD sludge
Wellman-Lord FGD Process
Thiosulfate/sulfate purge
4.2.1.1.1.1
4.2.1.2.1.1
4.2.1.2.1.1
4.2.1.1.2.1
4.2.1.1.2.1
4.2.1.1 .2.1
4.2.1.1.2.1
4.2.1.1.2.2
4.2.1.1.2.2
4.2.1 .1 .2.3
4.2.1.1.2.3
4.2.2.1.2.1
4.2.2.1 .3.1
4.2.2.1 .3.2
4.4.5.1
4.2.1.2.1.1
4.2.1.2.1.1
4.2.1.2.1.1
not evaluated*
4.2.1 .2.1.1
4.4.5.1
not evaluated
4.4.5.1
not evaluated
not evaluated
4.4.2.6
4.4.2.7
not evaluated
A-6
A-7
A-7
A-9
A-9
A-9
A-9
A-8
A-8
A-10
A-10
A-13
A-20
A-10
(continued)
-------
TABLE 3-83. (Continued)
Control Technique/Secondary Waste
Coal Particulate Dry Collectors
Coal Particulate
Water Pollution Control
Phosam-W Process
Ac id gas
Chevron-WWT Process
Acid gas
Activated Sludge
o Waste sludge
o
~ Activated Cargon Adsorption
Regeneration off-gas
Incineration
Flue gas
Cool ing Tower
Evaporation and drift
Bl owdown
Vapor Compression Evaporator
Waste brine concentrate
Solid Waste Management
Incineration
Bottom ash
PCTM Section Reference for
Waste Control
Characterization Technique Appendix
4.2.6 not evaluated A-ll , A-12
4.3.1 .1 .3.1 4.2.1 .1 A-6, A-8,
A-9, A-10
4.3.1 .1 .3.2 4.2.1 .1 A-6, A-8,
A-9, A-10
4.3.1 .1 .4.1 4.4.4.1 .1 B-10, C
4 3.1 .1 .5.1 4.3.1 .1 .5.1 B-15
4.3.1.1.5.3 4.3.1.1.5.3 A-11,A-14,
A-20, A-21
4.3.1.1.6.1 not evaluated B-l, B-2,
4.3.1 .1 .6.1 4.3.2 B-4, B-l 9
4.3.1.1.6.2 not evaluated C
4.4.4.1.1 4.4.4.1.1 C
*Control techniques for these secondary waste streams are similar to those of other waste
streams discussed in Sections 4.2, 4.3 and 4.4.
-------
4. EVALUATION OF POLLUTION CONTROL TECHNOLOGIES
4.1 INTRODUCTION
At the present time, no commercial scale EDS plants are operating or are
under construction. Thus, control technologies which would be applicable to
the waste streams identified in Section 3 have not been demonstrated on EDS
facilities, or on other direct liquefaction facilities. The control technolo-
gies which will be applied to EDS installations will likely be adaptations of
those which are in use in such related industries as petroleum refining, coal
cleaning, by-product coke, and coal-fired power plants. This section provides
an evaluation of the applicability, performance and cost of control methods
which may be adapted from other industries and from general pollution control
practice. The section defines the limitations of and necessary modifications
to these control methods for use in coal liquefaction plants, and discusses
those controls which have actually been demonstrated in coal gasification/
liquefaction plants. The information presented in this section provides users
with background on a variety of alternative control options, and permits assess-
ment of techniques for his specific situation, and assessment of how individual
techniques might be combined for the case under examination.
Throughout this section, the flow rates of waste streams and effluents
from control devices and control costs (except unit cost) presented all cor-
respond to an EDS commercial plant processing 1,134 Mg/hr (30,000 tons per
stream day) of "as received" Illinois No. 6 coal in the liquefaction area.
This EDS plant produces about 9,580 m3 (60,240 barrels) fuel oil equivalent
per stream day of liquid products for the base case design, or 11,300 m
(71,080 barrels) fuel oil equivalent per stream day of liquid and gaseous
products for the MFS case design.
4.1.1 Organization of Section /
Section 4 is organized into three major subsections (2 digit heading) by
235
-------
waste media (air, liquid and solid). In each media section, the waste streams
identified in Section 3 and secondary waste streams from other pollution con-
trols are grouped into source types according to the waste characteristics.
A source type is a grouping of those streams which require the same or similar
types of controls. Evaluation of the applicable controls for each source type
will be presented in a separate subsection.
The source type subsection (3 digit heading) begins with a list of the
streams that fall into that source type., Where controls for a given source
type consist of several control techniques connected in series, each step in
the series is referred to as a control function. Applicable control techniques
are grouped into control functions according to their purposes or pollutants
removed. For example, bulk sulfur removal from acid gases is considered a
control function, and the Claus process is a control technique under this con-
trol function. The relations among the pertinent control functions and their
purposes are briefly discussed at the beginning of each source type subsection.
Individual control techniques for each control function are then summarized
in tables at the beginning of this subsection, briefly indicating the process
operating principles, performance, reliability, secondary waste streams gener-
ated, costs, and advantages/disadvantages.
Each source type subsection is broken down according to each of the streams
within that source type; each stream is discussed in a subsection with a 4-digit
heading. These streams can be individual streams, as defined in Section 3, or
can be combinations of these streams where appropriate (e.g., Section 4,2.1.1
discussions apply to a combination of the individual acid gas streams from vari-
ous sources within the EDS plant). Each stream subsection is then further sub-
divided into subsections for each applicable control function where appropriate
(5-digit heading; e.g., Section 4.2.1.1.1 covers bulk sulfur recovery for the
combined acid gases). Finally, each function subsection is subdivided into 6-
digit subsections for each applicable alternative individual control technique
(e.g., Section 4.2.1.1.1.1 discusses the Claus process for bulk sulfur removal
applied to the combined acid gas stream). It is under this 6-digit subsection
that the detailed discussion of the individual control techniques is presented
as applied to the specific stream. This discussion of individual control tech-
niques addresses only the unique design/operating/performance features associ-
ated with their application to the specific waste streams in an EDS commercial
236
-------
plant. The EDS base case and MFS case designs are considered in this manual,
because characteristics of emissions from these two specific Exxon designs can
be estimated. Other EDS designs could result in emission streams with differ-
ent characteristics and flow rates; however, the emission streams for the EDS
base case and MFS case designs are considered to be representative, and the
control techniques for these two designs are likely to be equally applicable
to other EDS designs.
Detailed discussions of each individual control technique supporting the
presentation in Section 4 are found in the separate Appendix volume.
For air and water pollution control technologies, the last subsection
under each source type presents integrated control examples, for selected
waste streams which require multiple control techniques in series. For solid
waste management, integrated control examples are presented after the discus-
sion of all the source types. The integrated control examples illustrate
some typical methods by which specific techniques might be combined in a con-
trol system. The integrated control examples are selected on the basis of
their consideration in designs by direct liquefaction process developers, and
being representative of a broad range of control possibilities. The integrated
control examples presented are by no means inclusive of all potentially appli-
cable combinations. Performance, costs, and other key features of the inte-
grated control examples are presented.
The cross-reference tables at the end of Section 3 (Tables 3-82 and 3-83)
indicate the subsections within Section 4 (and the Appendix sections) in which
the reader will find the control techniques applicable to each individual
stream identified in Section 3.
4.1.2 Approach
The various control technologies applicable to the management of each of
the waste streams identified in Section 3 are evaluated in Section 4. The
PCTM first discusses control functions that might be involved in the treatment
of waste streams under each source type, and then presents general information
concerning the key features of various processes for each control function.
These key features include: operating principles control efficiency for
237
-------
components removed, feed stream requirements/restrictions, potential for re-
covery of by-products, secondary waste streams generated, process reliability,
and unit capital cost. Information on the key features is based on the appli-
cation of control techniques in related industries. Following the presenta-
tion of general information on control techniques, the application of selected
control techniques to individual EDS waste streams (or combinations of waste
streams) is examined in detail, to illustrate how performance and cost esti-
mates can be derived. Finally, integrated control examples for selected waste
streams are presented to illustrate how specific control techniques might be
combined. The information presented will allow the user to assess which tech-
niques might be most useful for his use, and assemble his own systems from the
breakdown of control functions.
Performance data for applicable control technologies have been obtained
primarily from the open literature supplemented by vendor- and user-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 technolo-
gies. In many cases, performance can only be estimated in terms of control
of major constitutents (e.g., total sulfur) or gross parameters (e.g., BOD,
COD) since information for removal efficiencies of specific substances is
lacking. Further, even in those cases where substance-specific performance
information exists for a control technology, accurate or complete characteri-
zation of the EDS waste stream being fed to the control device may be lacking.
In the final analysis, the capabilities of controls on an EDS facility can only
be accurately evaluated by testing at operating facilities or of smaller units
from which data can be confidently extrapolated to commercial size. The per-
formance estimates in this document are believed to reflect the best informa-
tion currently available based on actual experience (on experimental facilities
and in related conventional industries), and based on engineering analysis.
Detailed information on performance of control technologies, supporting
the presentation in Section 4, is provided in the Appendix volume.
4.1.3 Costing Methodology
In order to compare controls for cost effectiveness and to estimate the
impact of pollution control costs on overall plant costs, approximate capital
238
-------
and operating costs are generally presented in three ways: 1) cost per unit
throughput; 2) absolute cost for an EDS commercial plant that processes 1,134
Mg/hr (30,000 tons per stream day) of "as received" Illinois No. 6 coal in the
liquefaction area; and 3) cost as a percentage of the uncontrolled EDS base
plant. The cost per unit throughput is often presented in both the general
discussion of the control techniques and the discussion of application of con-
trol techniques to individual waste streams. In the general discussion, unit
costs are sometimes given as a range of values, to represent the impacts of
throughput rates (e.g., lower unit cost for higher throughput rate), variations
in stream characteristics (e.g., lower unit cost for removing pollutant from a
stream of higher pollutant concentration, if the unit cost is computed on the
basis of amount of pollutant removed), variations in designs for a given tech-
nique (e.g., equipment quality-service factor tradeoff), and the design for
how the individual technique is integrated into the integrated control system
(e.g., residence time and other factors in the biox sections of an integrated
control system). In the application to individual waste streams, unit costs
are typically given as a single value, because a specific set of design and
operating conditions has been selected to control the waste stream, and the
specific throughput rate of the waste stream (or amount of pollutant removed)
is used to compute the unit cost. As with the case of absolute cost and cost
as a percentage of the uncontrolled EDS base plant, this single value for the
unit cost does not imply a firm cost estimate, but merely reflects that a
single set of numbers (versus ranges) has been used to estimate the cost.
The capital investment and annualized costs are based primarily on fac-
tored estimates of costs contained in non-proprietary published literature,
normalized to a first quarter 1980 basis using generally accepted cost indices
such as the Chemical Engineering (CE) plant cost index. Generally, a conser-
vative approach was taken so that an overestimation of actual costs is more
likely than an underestimation. For example, when cost data for a control
technique were scattered, the approach was to utilize the data points associated
with the higher costs to develop cost curves for use in this manual. This is
because there is a tradeoff between equipment quality and service factor.
Selection of the higher cost data points as the cost basis implies that higher
239
-------
quality equipment are to be used, to insure less troublesome operation and high-
er service factor. It is also recognized that total costs are strongly influ-
enced by oversizing and/or redundance designed into systems in order to compen-
sate for the uncertainties in reliability or performance levels. However, no
attempt has been made to include redundancy in the PCTM cost, although some
redundancy is built into many of the original literature or vendor capital cost
bases for the various controls. Detailed information on the costs of indivi-
dual control processes is provided in the Appendix volume.
To the extent possible, the same methodology was used to develop capital
and total annualized cost estimates for pollution controls and for the uncon-
trolled base plants (Section 2.3). Total capital investment costs (TCI) pre-
sented in the PCTM include:
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
• project and process contingency reserves;
4) interest expenses on capital spent prior to start of production
(interest during construction)
5) working capital.
The first four items add up to the total depreciable investment (TDI). Start-
up costs are not included and working capital is not depreciable. Total capi-
tal investment estimates for the uncontrolled EDS plant include working capital
but not land costs. Total capital investment estimates for pollution control
technologies, however, do not include non-depreciable items such as working
capital and land costs, because working capital for individual control tech-
niques is generally a small item and difficult to estimate. Thus, in the con-
text of the EDS PCTM, the total capital investment (TCI) and the total depre-
ciable investment (TDI) costs are the same for pollution control technologies.
A variety of methods can be used to estimate the above cost items, al-
though most methodologies utilize a factored approach. In a factored approach,
the cost of purchased and delivered equipment is obtained from vendor quotes
or estimated from previous projects using similar equipment. The remaining
240
-------
cost items are then estimated as a "factor" times the purchased and delivered
equipment costs or other subsequently derived subtotal.
For cost estimates developed for this PCTM, the major source of cost
information was the open literature, although some vendor quotes were used.
In general, literature cost information is not reported as 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), and some are TDI estimates.
It was beyond the scope of the PCTM to develop the detailed engineering designs
necessary for cost estimation at the "firm" (+ 5 to 10%) level. The accuracy
of cost data taken from published sources was influenced by the reliability of
the data source, the cost methodology, and the degree of similarity of the
streams. Also, the accuracy of the estimates and the components in the cost
estimates (e.g., contingency) are not always provided in the reference. Thus,
extrapolation of these costs to the stream being treated in the PCTM also in-
troduced uncertainties. Although the accuracy of the cost estimates vary, most
are believed to be within j^ 50% for the 1980 base year. Uncertainties in cost
estimates due to uncertainties in waste stream characteristics, however, are
not included in this + 50% figure.
In order to provide consistency in the various capital cost estimates re-
quired for the PCTM, a capital cost methodology was developed,, The methodology
(and cost factors) used are summarized in Table 4-1. Most cost data obtained
from the literature were installed equipment costs (IEC), which represent the
total direct capital costs. This cost includes principal equipment items to-
gether with installation of these equipment items, piping and instrumentation,
minor steelwork such as ladder platforms, supports (not major structures), con-
crete foundations and substructures, electrical, insulation, buildings housing
equipment and paint. For cost data available as equipment cost, a field mater-
ials and labor (M&L) factor was applied to relate the purchased equipment cost
to the installed equipment cost. The field materials and labor factor usually
ranged from 1.8 to 2.6, depending on the type of equipment to be installed.
In most cases, the installed equipment cost (IEC) or the purchased equipment
cost (C) was available for equipment at a different operating capacity. The
general approach in correlating costs for equipment at different capacities
241
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TABLE 4-1. CAPITAL COST ESTIMATING METHOD
Installed Equipment Costs (IEC)
Principal equipment items, installation of these items, piping, instrumen-
tation, foundations and substructures, electrical, insulation, buildings
housing equipment, and paint.
Indirect Installation Costs (IIC)
Engineering and Construction (25% of IEC)
Fees (3% of IEC)
Contingency (20% of IEC)
Total Plant or Process Costs (TPC = IEC + IIC)
Interest During Construction (IDC = 22.6% of TPC)
Total Depreciable Investment (TDI = TPC + IDC)
Working Capital*(WC = 60 days inventory of raw materials, catalysts and chemi-
cals)
Total Capital Investment*(TCI = TDI + WC)
"Total capital investment estimates for pollution control technologies do not
include non-depreciable items such as working capital and land costs; i.e.,
it is assumed that WC is small and TCI approximately equals TDI.
Cost basis: 1980 dollars.
242
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was to utilize the relationship:
CB = CA (QB/QA)n
where: CA, Cg = cost of equipment at capacity A or capacity B (C» is known)
QA, Qg = operating capacity of A or B (Q. and Og are known)
n = size exponent factor
The operating capacity factor (Q) in the above equation can refer to a volu-
metric flow rate, quantity of sulfur removed or quantity of coal processed,
for example. The size exponent factor (n) normally ranges from 0.4 to 0.9,
depending upon the type of equipment or process being evaluated. If specific
size exponents were not available in the literature, a value of 0.6 was used
(the "six-tenths rule" of equipment cost estimation). Alternatively, if suf-
ficient published cost data were available, cost curves were developed.
As indicated in Table 4-1, 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, based on 12% per year for an average of 1.88 years.
The TDI is the sum of the total process cost (TPC) and the interest during
construction (IDC).
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, catalysts,
utilities (steam, electricity, cooling water, etc.), and overhead. Capital-
related charges include interest on working capital, local taxes, insurance,
depreciation, income taxes, and return on investment. The unit costs or fac-
tors used to estimate total annualized costs in this PCTM are listed in Table
4-2. All of the terms listed in Table 4-2, except capital recovery, are ex-
pressed in first year costs, i.e., in constant 1980 dollars. The capital
recovery term, however, is a levelized value calculated using standard present
worth and levelized cost procedures and the economic assumptions listed in
Table 4-3. 243
-------
TABLE 4-2. UNIT COSTS AND FACTORS FOR ANNUALIZED
COST ESTIMATES
Operating Labor ($11/hr)
Supervision (15% of operating labor)
Maintenance (2% of total depreciable investment)
Maintenance Supervision (5% of maintenance)
Illinois No. 6 Coal~($1.14/GJ)
Raw Water ($0.031/irr)
Utilities
Steam ($5.73/Mg)
Electricity ($0.033/kW-hr)
Fuel Gas ($4.43/GJ) «
Cooling Water ($0.08/m )
Chemicals and Catalysts (representative early 1980 costs)
By-product Credit
Ammonia ($140/Mg)
Phenol ($6.05/1)
Sulfur (0)
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 (17.2% of total depreciable investment)
TOTAL ANNUALIZED COSTS (summation of above items)
244
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TABLE 4-3. ASSUMPTIONS USED TO CALCULATE CAPITAL
RECOVERY FACTOR
Financing basis:
Desired after tax return on investment:
Income tax rate:
Economic facility life:
Facility life for depreciation purposes:
Depreciation method:
Investment tax credit:
Interest rate
Property taxes and insurance
100% equity
12% of total depreciable
investment
48% of taxable income
20 years
16 years
sum-of-the-years-digit
20% of total depreciable
investment
12% per year
3% of total depreciable
investment
245
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Air Pollution Control
4.2 AIR POLLUTION CONTROL TECHNOLOGIES
Uncontrolled gaseous emissions from the EDS commercial plant have been
identified and described in Section 3 of this manual. Characteristics of
these streams and additional gaseous waste streams generated by pollution
control processes from other media are summarized in Tables 4-4 and 4-5 for
the base case and MFS case designs, respectively. The waste streams presented
in these tables are regrouped into six source types according to the major
types of potential pollutants which they contain:
• Source Type 1 - acid gases and other reduced sulfur/nitrogen,
organic-laden gases
« Source Type 2 - combustion gases
• Source Type 3 - organic and CO containing waste gases
• Source Type 4 - fugitive dusts from material storage
• Source Type 5 - fugitive organic emissions
• Source Type 6 - fugitive particulates from material conveying
and processing.
The grouping of waste streams into source types facilitates the discussion of
air pollution control technologies, because similar controls are generally
applicable to waste streams belonging to the same source type. The character-
istics of waste streams presented in Tables 4-4 and 4-5 are those that are
most relevant to the selection and evaluation of pollution control technologies
The flow rates and compositions are based upon an EDS commercial plant proces-
sing 1,134 Mg/hr (30,000 tons per stream day) of "as received" Illinois No. 6
coal in the liquefaction area (compositions of the design Illinois No. 6 coal
are given in Table 2-1). These flow rates and compositions might, of course,
vary in practice due to differences in plant design, coal type or plant oper-
ating conditions, and due to uncertainties in estimation.
In the ensuing subsections, air pollution control technologies which may
be applicable to the gaseous waste streams listed in these tables are identi-
fied. Some of these gaseous waste streams would be combined for treatment
246
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TABLE 4-4. ESTIMATED CHARACTERISTICS OF GASEOUS WASTE STREAMS
ACCORDING TO SOURCE TYPE FOR EDS COMMERCIAL PLANT
(ILLINOIS COAL BASE CASE)
Source Type/Stream
Stream Flow
Rate*
kmol/hr
Stream Characteristics
Source Type 1 - Acid Gases and Other Reduced
Sulfur/Nitrogen, Organic-Laden Gases
Stream 508 - acid gas from DEA regenerator 1,214
Stream 501 - acid gas from sour water stripper/ 263
ammonia recovery! t
Stream 304 - Flexicoking gasifier/heater sour 54,781
fuel gas
Stream 102 - slurry drier vent gas 532
Stream 153 - vacuum fractionator off-gas 69
Stream 803 - transient waste gas from liquefaction 3,280
reactor
Stream 801 - transient waste gas from Flexicoking 671
Source Type 2 - Combustion Gases
Stream 707a - flue gas from power generation system 36,450
Stream 701a - flue gas from steam generation system 42,560
Stream 107 - flue gas from liquefaction slurry 34,535
preheat furnace
Stream 203 -flue gas from solvent hydrogenator 3,864
fuel preheat furnaces
Stream 434 - flue gas from hydrogen plant reformer 58,022
furnaces
Contains 64.2% H^S, 371 ppmv COS, and 3.9% NH.
Contains 0.42% HjS, 108 ppmv COS, and 11.6% C0?
Contains 30 ppmv H.S and 4.1% hydrocarbons
Contains 5% hLS and 47.5% hydrocarbons
Contains 2.5% H^S and 45.1% hydrocarbons
Contains 1.0% H.S and 40.9% hydrocarbons
Contains 2850 ppmv S07. 359 ppmv NO., and 6760 mg/m particulate matter
T
Contains 925 ppmv SO^, 152-187 ppmv NOX, and 2140 mg/m partifulate matter
Contains 41 ppmv S0?, 61-117 ppmv NO , and 4.9-14.6 mg/m3 particulate
matter
Contains 41 ppmv SO., 61-117 ppmv NO , and 4.9-14.6 mg/m3 particulate
matter x
Contains 41 ppmv S0?, 61-117 ppmv NO , and 4.9-14.6 mg/m particulate
matter
Source Type 3 - Organic and CO Containing Waste Gases
Stream 426 - vent gas from CO- removal by Catacarb 6.100
process
Stream 438 - hydrogen plant deaerator vent 6.5
Stream 446 - regeneration/decommissioning off-gas 6,800
from reformer catalyst
Stream 448 - decommissioning off-gas from methanation 5,000
catalyst
Source Type 4 - Fugitive Dust from Material Storage
Stream Oil - fugitive dust from coal pile N/A*
Source Type 5 - Fugitive Organic Emissions
Stream 751 - evaporative emissions from product and 0.02
by-product storage
Fugitive organic emissions from pump and compressor 1.5
seals, valves, flanges, pressure relief valves, and
drains
Contains 361 ppmv CH4, 1.9% H^, and 157 ppmv CO
Consists primarily of steam with a small quantity of C0? and trace
of hydrocarbons
Consists primarily of steam and nitrogen with small amounts of CO
and particulate matter
Consists primarily of steam and nitrogen with small amounts of
particulate matter
Emits an average of 51 kg/hr of particulate matter
Contains mostly aliphatic hydrocarbons, benzenes and substituted
benzenes, and phenols
Emits 153 kg/hr of orgamcs
Source Type 6 - Fugitive Partlculates from Material
Conveying and Processing
Stream 013 - fugitive particulates from coal handling
and crushing
N/A
Emits 161-2,548 kg/hr of particulate matter
* N/A - not applicable
t For EDS plant producing 9,580 m3 (60,240 barrels) fuel
all equivalent products per stream day.
J Secondary discharge stream
247
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TABLE 4-5. ESTIMATED CHARACTERISTICS OF GASEOUS WASTE STREAMS
ACCORDING TO SOURCE TYPE FOR EDS COMMERCIAL PLANT
(ILLINOIS COAL MFS CASE)
Source Type/Stream
Stream Flow
Rate,*
kmol/hr
Stream Characteristics
Source Type 1 - Acid Gases and Other Reduced Sulfur/
Nitrogen, Organic-Laden Gases
Stream 508 - acid gas from DEA regenerator 1,214
Stream 501 - acid gas from sour water stripper/ 24^
ammonia recovery|
Stream 440 - flash gas from partial oxidation unit 254
Stream 428 - acid gas from acid gas removal unit 13,304
in hydrogen pun fi cat ion
Stream 304 - Flexicoking gasifier/heater sour fuel gas 27,?25
Stream 102 - slurry drier vent gas 532
Streams 153/156 - vacuum fractionator off-gas 69
Stream 803 - transient waste gas from liquefaction 3,280
reactor
Stream 801 - transient waste gas from Flexicoking 511
Stream 802 - transient waste gas from partial 12,131
oxidation units
Contains 64 U H?S, 373 ppmv COS, and 5.2% NH3
Contains 56 3* H?S and 0.71 NH3
Contains 4.4'/ H?S and 1180 ppmv COS
Contains 1.0*, H-S, 38 ppmv COS, and 669 ppmv NH.
Contains 0.44% H?S, 9? ppmv COS, and 11.531 C02
Contains 30 ppmv M^S and 4 1% hydrocarbons
Contains 5% H«S and 47.5% hydrocarbons
Contains 2.5% H^S and 45.1% hydrocarbons
Contains 1.51 H?S and 39.7% hydrocarbons
Contains 0.3% H.S, 250 ppmv COS, ,md 0.2% hydrocarbons
Source Type 2 - Combustion Gases
Stream 707a - flue gas from power generation system 26,110
Stream 701a - flue gas from steam generation system 69,150
Stream 107 - flue gas from liquefaction slurry 34,535
preheat furnace
Stream 161 - flue gas from partial oxidation feed 425
vacuum fractionator preheat furnace
Stream 203 - flue gas from solvent hydrogenation fuel 3,864
preheat furnaces
Streams 449/450 - regeneration/decommissioning off-gas 22,255
from high and low temperature shift
catalysts
Contains 2850 ppmv SO,, 359 ppmv NO , and 6760 mg/m particulate matter
3
Contains 1470 ppmv S0?, 210-236 ppmv NO , and 3450 mg/m particulate
matter x
Contains 41 ppmv S0?, 61-117 ppmv NO , and 4.9-14.6 mg/m participate
matter £ *
Contains 41 ppmv S0?, 61-117 ppmv NO , and 4.9-14.6 mg/m particulate
matter £ *
Contains 41 ppmv S0?, 61-117 ppmv NO , and 4.9-14.6 mg/m particulate
matter
Consists primarily of steam with 5% N,,, 1% SO,, and 0.5* CO^
Source Type 3 - Organic and CO Containing Waste Gases
Stream 438 - hydrogen plant deaerator vent
Consists primarily of steam with a small quantity of COj, and traces
of hydrocarbons
Source Type 4 - Fugitive Dusts from Material Storage
Stream Oil - fugitive dust from coal pile
Emits an average of 52 kg/hr of particulate matter
Source Type 5 - Fugitive Organic Emissions
Stream 751 - evaporative emissions from product and
by-product storage
Fugitive organic emissions from pump and compressor
seals, valves, flanges, pressure relief valves,
and drains
0.02
1.5
Contains mostly aliphatic hydrocarbons, benzenes and substituted
benzenes, and phenols
Fmits 153 kg/hr of orqamcs
Source Type 6 - Fugitive Particulates from Material
Conveying and Processing
Stream 01T3 - fugitive particulates from coal handling
and crushing
Fmits 165-2.623 kg/hr of particulate matter
* N/A - not appl icable
+ For EDS plant producing 11,300 m (71,080 barrels) fuel oil equivalent
products per stream day.
T Secondary discharge stream
248
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Air Pollution Control
rather than handled separately; for these streams, stream combinations are
identified, and controls are presented for the combined stream rather than
for each individual stream. Further, some of these waste streams would re-
quire treatment by a series of control technologies, rather than by just a
single technique; for these streams, the individual control techniques are
broken down according to the control function that they fulfill within the
total control system; and, in addition to discussions of individual techni-
ques, example approaches to the integrated control of selected waste streams
or stream combinations are provided. In the discussions which follow, empha-
sis is placed on streams unique to the EDS process, rather than on those
streams which are exactly identical to streams found in conventional indus-
tries (e.g., fugitive dust from coal piles, flue gas from coal-fired boilers).
In Tables 4-4 and 4-5, the acid gas from sour water stripper/ammonia re-
covery (Stream 501) is a secondary waste stream generated from water pollu-
tion control. Secondary gaseous waste streams -- generated from air pollu-
tion control (hence not cross-media) -- will be introduced as the control
technique causing their generation is discussed. Controls for secondary waste
streams will sometimes be handled as part of a combined stream (as will be the
case for Stream 501), and sometimes be handled separately but often following
the discussion of the control technique causing their generation.
249
-------
Air Source Type 1
Acid Gases
4.2.1 Source Type 1 -_ Acid Gases and Other Reduced Sulfur/Nitrogen,
Organic-Laden Gases
There are seven gaseous waste streams under Source Type 1 for the base
case design, and eleven waste streams under Source Type 1 for the MFS case
design. All seven gaseous waste streams for the base case design are also
present for the MFS case design. These waste streams are:
• Stream 508 - acid gas from DEA regenerator
• Stream 501 - acid gas from sour water stripper/ammonia recovery
• Stream 440 - flash gas from partial oxidation unit (MFS case only)
• Stream 428 - acid gas from acid gas removal unit in hydrogen
purification (MFS case only)
t Stream 304 - Flexicoking gasifier/heater sour fuel gas
• Stream 102 - slurry drier vent gas
• Stream 153 - vacuum fractionator off-gas
• Stream 156 - partial oxidation feed vacuum fractionator off-gas
(MFS case only)
• Stream 803 - transient waste gas from liquefaction reactor
• Stream 801 - transient waste gas from Flexicoking
• Stream 802 - transient waste gas from partial oxidation unit
(MFS case only).
All gaseous waste streams are generated from the uncontrolled EDS base plant,
with the exception of Stream 501, which is generated from treatment of the
sour water containing H«S and NH~.
Approaches to treatment of gaseous waste streams under Source Type 1 may
involve up to three control functions:
1) bulk sulfur removal
2) residual sulfur removal
3) incineration.
250
-------
Air Source Type 1
Acid Gases
Bulk sulfur removal, as the name implies, removes most of the sulfur compounds
(e.g., 95%) present in the waste stream. Residual sulfur removal is designed
to reduce the last remaining sulfur compounds in the off-gas from bulk sulfur
removal down to very low levels, employing processes that can operate in this
low concentration region more effectively than bulk sulfur removal processes,
based on either technical or economical considerations. Incineration oxidizes
reduced sulfur species in the gas stream prior to sulfur removal by S0? con-
trol techniques. It is also used to oxidize reduced sulfur species remaining
after bulk or residual sulfur removal, if necessary, for control of odor in
emission streams.
Depending on the characteristics of the waste stream and the specific
control technique(s) employed, it may not be necessary to utilize all three
control functions in any treatment approach. For example, there may not be a
need for incineration following residual sulfur removal. For the EDS process,
pretreatment or enrichment of acid gas streams (Streams 508 and 501) prior to
bulk sulfur removal is not necessary because of the concentration levels of
H2S in these streams. Also, there are some options in the sequential order
of applying these control functions. For example, incineration may precede
bulk sulfur removal (e.g., incineration followed by flue gas desulfurization)
or may follow residual sulfur removal (e.g., incineration of the off-gas from
sulfur plant tail gas treatment).
Partial or essentially complete control of reduced nitrogen compounds (NH3
and HCN, if present), CO, and organics can be realized either as an integral
part of the sulfur control approach or through a separate add-on step such as
incineration.
Bulk Sulfur Removal
To date only three processes have seen any significant commercial appli-
cation for the bulk removal of H2S from acid or fuel gases, namely the Glaus,
Stretford, and Giammarco-Vetrocoke processes. Although a few other bulk sulfur
251
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Air Source Type 1
Acid Gases
removal processes are available or have been proposed, these three are the only
processes examined here for a variety of reasons, including: expressed interest
to date by synfuels developers, advanced commercial status and an extended
operating history, applicability to a wide range of sulfur concentration levels
in the acid gases, and availability of performance and cost data. In addition
to these processes, alternatives involving incineration followed by SCL removal
may be applicable for treatment of sour fuel gas. In conventional applications,
Stretford units have historically been favored over Claus units due to economic
reasons for feeds containing only a few percent H^S. Claus plants are often
preferred for feeds containing over 25% H^S. The Giammarco-Vetrocoke process
is generally applicable to feed streams with H^S concentrations of up to 1.5%.
Table 4-6 summarizes the key features of these bulk sulfur removal processes.
These three bulk sulfur removal processes are described below. Further details
on the Claus and Stretford processes and supporting performance and cost data
for these processes can be found in Appendices A-6 and A-7 of the Appendix
volume.
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 the total acid gas stream (generally with all the sulfur in the
form of H~S or other reduced sulfur species) is sent to the combustion chamber,
and sufficient air is added to oxidize one-third of the H2S to SO,,, in order
for the Claus reaction to proceed. The "split flow" mode is often used when
hLS-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 combusted 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 and
recovered. There are also special considerations for acid gas feeds contain-
ing high levels of ammonia. Residual ammonia would form salts with sulfur
252
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TABLE 4-6. KEY FEATURES OF BULK SULFUR REMOVAL PROCESSES
Principle of
Operation
Components Removed
Claus
Catalytic oxidation
of H2S and SOp to
elemental sulfur.
H2S, COS, RSH, VOC,
NH3, and HCN.
Stretford
Liquid phase oxidation of H2S
to elemental sulfur in an
alkaline solution of metavana-
date and anthraquinone disul-
fonic acid.
H2S, HCN, and CH,SH.
Giamarco-Vetrocoke (G-V)
Liquid phase oxidation of H2S
to elemental sulfur in sodium
carbonate and arsenate/
arsenite solution.
H2S, COS, and CS?.
Incineration/502 Removal
Oxidation of reduced sulfur and
organics, followed by S02 removal
using either regenerative or
throwaway FGD technologies.
H2S, COS, RSH, VOC, and CO.
Efficiency
Feed Stream
Requirements/
Restrictions
Over 95% total S,
other combustibles
partially destroyed*
Streams containing
HjS levels much
below 10 - requi re
enrichment prior
to processing.
Organics cause com-
bustion control
problems and "grey"
sulfur,
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.
99.99* H2S removal.
Maximum 1.5°- H2S in feed.
As low as 100 ppmv VOC in incinerated
gas and up to 99? 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.
ro
en
oo
By-Products
Secondary
Waste Streams
Elemental sulfur.
Spent catalyst and
catalyst regenera-
tion decommissioning
offgas.
Elemental sulfur.
Oxidizer vent gas and purge
solution.
Elemental sulfur which may
require arsenic removal.
Oxidizer vent aas and
arsenate/arsenite wash
water.
Either CaSO/), 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 eTr-ct,
FGDs systems have varying degrees of
reliability and generally have lower
on stream factors than process units.
No effect except to increase energy
requirement fcr incineration if in-
sufficient combustibles are present
in feed gas.
Capital Costs
$2b to $180 x 10 per
Mg sulfur/day capacity
depending on both
total flow and sulfur
content.
SI 10 to $270 x 103 per Mg
sulfur/day capacity, depending
primarily upon total flow.
No cost data available.
$700 to $1700 x 10 per Mg sulfur/day
capacity depending upon total flow
and degree of sulfur removal.
General Comments
Applicable only to
acid gases from
selective AGR system.
Hydrocarbon removal
from feeds may be
necessary.
1 ppmv HjS in tail gas is
possible, however higher limits
are proposed when high levels
of other reduced sulfur species
are present in tail gas.
Limited data available. Haz-
ardous nature of arsenic solu-
tion makes application unlikely
in large U.S. facilities.
FGD process has usually been
applied to combustion flue gases
containing less than 5000 ppmv S02
and achieving about 90% control.
Performance and cost data for higher
SO? feeds achieving 99% control are
1imited.
-------
Air Source Type 1
Acid Gases
compounds and carbon dioxide which cause plugging and catalyst deactivation
problems downstream. Therefore, the ammonia-bearing contributor to the total
acid gas stream is often fed to a separate compartment of the combustion
chamber, so that all the ammonia can be entirely combusted to primarily nitro-
gen and water. The other acid gas streams might be fed to the second compart-
ment of the combustion chamber, along with additional air, if necessary, so
that overall one-third of the FLS in the total acid gas feed is combusted to
form SO,,.
Regardless of the Claus mode, the number of stages determines sulfur
removal efficiency; Claus units of 3-stage design can achieve overall removal
efficiencies of over 95%. To further reduce tail gas sulfur emissions, the
Claus sometimes uses four catalytic stages for up to 97% sulfur recovery, at
which point increased plant efficiency by this technique is limited by thermo-
dynamic considerations. Gaseous sulfur species distribution in Claus tail gas
in high C02 applications is approximately 60% H2$, 30% S02, 9% COS, and 1% CS2.
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 H2S in
the Claus feed and the effectiveness of mist eliminators. The relative con-
tribution of elemental sulfur to total sulfur in Claus tail gas generally in-
creases as HpS content of Claus feed gas decreases.
In the "straight through" mode of Claus operation, organics, HCN, and NH^
in the feed are largely converted to carbon dioxide, water vapor, and elemental
nitrogen. Such components are not ordinarily of concern to process operation
unless levels exceed perhaps ~\% each. Organics make control of combustion
stoichiometry and temperature more difficult and can lead to a by-product sul-
fur containing elemental carbon (black sulfur). HCN at high levels causes
corrosion throughout the process while NFL can form deposits which plug/deacti-
vate Claus catalysts. The organics problem is usually solved by limiting
their content in the Claus feed. HCN at high levels can be destroyed (con-
verted to NH-) prior to entering the Claus furnace using Claus or shift type
O
254
-------
Air Source Type 1
Acid Gases
catalysts under reducing conditions. This should not be a problem with the
EDS process. Ammonia at high levels require either bulk removal prior to Claus,
special design to control temperatures and minimize deposition of ammonia salts,
or split flow mode of operation. Because of the concentration levels of H2S in
the acid gas streams, the "straight through" mode would possibly be preferred
in Claus plants designed for the EDS process.
The Claus process produces spent bauxite or alumina catalyst and catalyst
regeneration off-gases where catalyst regeneration is used. The Claus cata-
lyst 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 process drops below acceptable levels; no data regarding regeneration
frequency, duration or off-gas characteristics are available. Further details
concerning the Claus process are given in Appendix A-6.
The Stretford process is suited for the treatment of sour fuel gas and
vent gas streams containing only a few percent H^S in the EDS commercial plant.
The original Stretford process (as developed by the British Gas Corporation)
is a liquid-phase oxidation process using an aqueous carbonate/bicarbonate
solution containing sodium vanadate and anthraquinone disulfonic acid (ADA)
in which H2S is both absorbed and converted to sulfur. The H2S is absorbed
by the carbonate/bicarbonate solution in either a packed tower (or contacted
in a venturi scrubber) and then oxidized to sulfur by the sodium vanadate.
The resulting reduced vanadium is then oxidized by the ADA Solution. ADA is
in turn regenerated by air in separate oxidizer tanks where elemental sulfur
is removed as a froth. A continuous solution purge is required to remove the
buildup of sodium thiosulfate and sodium thiocyanate. Concentrations of H?S
in the purified gas stream from the Stretford process can typically be reduced
to less than 10 ppmv, and sometimes to less than 1 ppmv. Carbonyl sulfide,
carbon disulfide and lower hydrocarbons (e.g., containing 5 carbon atoms or
less) are not removed by the Stretford solution and essentially appear in the
255
-------
Air Source Type 1
Acid Gases
purified gas stream. Mercaptans, however, are split between the purified gas
stream and the oxidizer vent gas. Higher hydrocarbons as well as ammonia are
almost completely removed and will all be present in the oxidizer vent gas.
HCN is also completely removed, converted to SCN~, and will appear in the
solution purge.
Recently, modifications of the original Stretford process have been
developed. One version of the Stretford process has been used at the SASOL
Lurgi coal gasification complex in South Africa. At SASOL, severe plugging
problems have occurred in the Stretford towers which apparently relate to the
high C0? 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 substitut-
ing a different absorbent but utilizing the bulk of the existing equipment.
The Stretford process generates two waste streams, the oxidizer vent gas
and the purge solution. The purge solution may be treated via the reductive
incineration process where the sulfur content of the purge is recovered as H?S
for recycle to the absorber and sodium and vanadium salts are recovered for re-
use. The oxidizer vent gas is expected to consist primarily of air, carbon
dioxide and water vapor. Further details concerning the Stretford process are
provided in Appendix A-7.
The Giammarco-Vetrocoke hLS removal process is a liquid phase oxidation
process using an absorbent solution of alkali arsenates/arsenites in which
hydrogen sulfide is both absorbed and converted to elemental sulfur. Sodium
carbonate is the alkali usually applied for removal of sulfur because of its
relatively low cost. The Giammarco-Vetrocoke process is applicable to gas
streams containing up to 1.5% hydrogen sulfide, and can reduce hydrogen sul-
fide levels to 0.5 ppmv or less (43). The successive reactions occurring
256
-------
Air Source Type 1
Acid Gases
are (42):
Na As 0 + 3HS = Na As$ + 3 H0 (4-1)
Na3 AsS3 + 3 Na3As04 = 3 Na3As03S + Na3 As03 (4-2)
Na3 As 03S = Na3 As03 + S (4-3)
Na3 As03 + 1/2 02 = Na3 As04 (4-4)
The hydrogen sulfide is absorbed at pressures from 0.1 to 7.5 MPa by counter-
current absorption, forming sodium thioarsenite according to reaction (4-1).
The resulting thioarsenite is converted to monothioarsenate by reaction with
arsenate (reaction (4-2) ). This reaction occurs in the absorber and in the
subsequent oxidizing column. Rich solution from the absorber is passed to an
atmospheric pressure, air-blown oxidizing column. Under the oxidizing condi-
tions, the monothioarsenate decomposes to arsenite and elemental sulfur
(reaction (4-3) ). Product sulfur is recovered by froth flotation, filtered
and washed. The oxidizing reaction (4-4) re-establishes the arsenite/arsenate
balance of the Vetrocoke solution by oxidizing some arsenite to arsenate.
Based upon limited available data, the only waste streams generated by this
process are wash water from the sulfur washing operation and oxidizer vent gas,
Characterization data are not available for these streams although the wash
water will contain arsenate/arsenite absorber solution.
One other approach to bulk sulfur control should be mentioned. In prin-
ciple acid gases can be directly incinerated to convert all organics, CO, and
reduced sulfur and nitrogen species to primarily COp, HpO, N~ and SOp. SOp
removal from the incinerated gas could then be accomplished using any one of
a number of available FGD processes (see Section 4.2.2). Generally, such an
approach is unattractive for several reasons. Throwaway FGD creates 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
257
-------
Air Source Type 1
Acid Gases
the Claus process. FGD systems are also not demonstrated for gases containing
over about 0.5% S02, and although there appear to be no inherent technical
limitations prohibiting designs for much higher SCL levels, such systems are
expected to be several times more costly than Claus or Stretford plants applied
directly to crude acid gases. However, SO,, removal by FGD processes might be
competitive for the treatment of incinerated sour fuel gas, as compared to the
alternative of removing sulfur from the fuel gas prior to combustion. Also,
incineration followed by throwaway FGD processes might be attractive for the
control of intermittent waste streams such as transient waste gases.
Residual Sulfur Removal
The Claus process is efficient in recovering up to 97% of the sulfur feed
by using four catalytic stages for conversion of hydrogen sulfide in acid gas
streams to elemental sulfur. Additional catalytic stages, however, would not
result in increased sulfur recovery by the Claus technique due to thermodyna-
mic limitations. The need for further reduction in emissions of sulfur com-
pounds, therefore, has resulted in the development of residual sulfur removal
processes capable of removing the residual traces of sulfur compounds present
in the tail gases of bulk sulfur removal processes. A number of processes are
now commercially available for treatment of sulfur plant tail gases or other
waste gases containing low levels of reduced sulfur species. Table 4-7 sum-
marizes the key features of the most prominent of these processes. The pro-
cesses can be categorized in three generic types:
1) Conversion of sulfur species to I^S followed by its removal
using absorption/reaction - these include processes such as
the Beavon Sulfur Removal Process (BSRP), the Shell Off-Gas
Treating (SCOT) process, the Cleanair process, and the BSR/
Selectox process.
2) Conversion of sulfur species to sulfur dioxide (S02) by incin-
eration, followed by SO^ removal - such as the Welfman-Lord,
IFP-2, and Chiyoda Thoroughbred 121 processes.
258
-------
TABLE 4-7. KEY FEATURES OF RESIDUAL SULFUR REMOVAL PROCESSES
Beavon
SCOT
Incineration Plus SO,
Removal (FGD) i
Sulfreen
Principle of Catalytic reduction of sulfur
Operation compounds to H^S, followed by
integrated Stretford process.
Components Removed HjS, COS, CS2>and S02.
Sulfur species are
catalytically reduced to
H2$; H2$ is scrubbed in
a regenerable amine
system.
H2S, COS, and CS2> S02.
Incineration (an on-site
boiler or separate
incinerator) followed by
SO? removal (e.g., Uellman-
Lord),
S02, also removes HCs,
CH3SH, NH3, and HCN.
Gas phase continuation of
Claus reaction at a low
temperature.
H2S, S02
COS, and CS2.
ro
en
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 C02and H2S 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 S02 in tail gas
and complete removal of
other compounds.
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.
None.
Sulfur or sulfuric acid from
the Wellman-Lord recovery
FGD process.
Sour condensate and solution Spent catalyst.
purge.
Solid wastes may be generated Has only been applied to
by throwaway FGD processes. Claus process tail gases.
Effects of High
C02 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 103 per Mg/
day of S at Claus plant.
Off-gas from amine
scrubber is not as low in
total sulfur as Beavon
process.
$40 to $110 x 10J per Mg/day
of S at Claus plant.
On-site boiler/FGD system Much higher residuals in tail
is the most likely candidate gas than Beavon process.
Installing a separate incin-
erator and FGD would not be
as economically feasible.
(Continued)
-------
TABLE 4-7. (Continued)
Cleanair
IFP Claus 1 ,500
IFP-2
BSR/Selectox
ro
CTi
o
Principle of
Operation
Components Removed
Efficiency
Feed Stream
Requirements/
Restrictions
By-Products
Secondary Waste
Streams
Reliability/
Limitations
Effects on High
C02 in Feed
General Comments
Catalytic reduction of
sulfur compounds to H2S
followed by a continua-
tion of the Claus reaction
and Stretford process.
H2S, COS, CS2, and S02.
Reduces sulfur to less than
250 to 300 ppm SOj equiva-
lent in effluent.
H2$:S02 ratio can vary up
to 8 to 1 without affect-
ing efficiency; designed
specifically for Claus
tail gas ,
Elemental sulfur.
Spent catalyst.
Has only been applied to
Claus process tail gases.
Reduces conversion effi-
ciency of catalyst;
decreases H2S 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
ppm as SO?.
H;>S:S02 ratio must be main-
tained in the range of 2.0
to 2.4.
Elemental sulfur.
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.
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.
Reduces sulfur species in
Claus tail gas to less than
500 pom.
H2S:S02 ratio must be main-
tained in the range of 2.0
to 2.4.
Concentrated
o.
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 H2$ to sulfur
over Selectox catalyst.
H2S, S02, COS, and CS2.
Up to 99.5% total sulfur re-
moval equivalent to 750 ppmv
S02 in the incinerated off-
gas.
H?S:SOp ratio must be main-
tained In the range of 2.0
to 2.4. HC and NH3 should not
be in the feed.
Elemental liquid sulfur.
Spent Beavon and Selectox
catalyst, and sour condensate.
Has only been applied to
Claus plant tail gas.
Reduces conversion efficiency
of BSR catalyst.
Higher sulfur emissions than
Beavon process .
-------
Air Source Type 1
Acid Gases
3) Extensions of the Claus process - such as the IFP-Clauspol
1500 and Sulfreen processes.
Processes in the first category involve catalytic conversion of oxidized
sulfur species to hLS followed by H^S removal from the gas stream by solvent
absorption. In general, the designs of these processes are influenced by high
levels of C02 in the feed gas. The C02 reduces the efficiency of catalytic
reduction of COS and CS2 to HpS and impairs the effectiveness of the f^S
removal/recovery systems. The SCOT, Beavon, and Wellman-Lord processes are
discussed in further detail in Appendices A-8 through A-10.
Both the Beavon and the SCOT processes are commercially available cata-
lytic processes which are potentially applicable to sulfur plant tail gases
in EDS commercial plants. These processes feature two sections: a hydrogena-
tion section to convert sulfur species in the gas to H?S, and an H?S absorp-
tion section. In the hydrogenation reactor of both processes, 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 cata-
lyst bed converting the sulfur species to FLS.
The Beavon process employs a Stretford unit for hLS absorption and ele-
mental sulfur production". In contrast, the SCOT process employs an alkanola-
mine scrubbing system for I-LS absorption. The absorbing solution in the SCOT
is then regenerated, resulting in a HpS-rich acid gas which is ordinarily
returned 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 HpS over C0~. Thus, where feeds to the SCOT contain
large amounts of C0?, it is more difficult to generate an H?S stream suitable
for Claus processing while simultaneously obtaining a SCOT off-gas stream with
a low level of total sulfur. For typical applications, vendors of the Beavon
process report that levels of less than 100 ppmv total sulfur can be achieved
(Appendix A-9), while vendors of the SCOT process report less than 250 ppmv
261
-------
Air Source Type 1
Acid Gases
total sulfur (Glaus plant tail gas basis) (Appendix A-8). H?S levels in the
Beavon off-gas are often below 10 ppmv; COS is the major contributor to the
total sulfur emissions for the Beavon process. By contrast, H^S levels in the
SCOT absorber effluent are typically 200 ppmv. The higher levels of H?S in
SCOT tail gases in existing applications often necessitate that the gases be
incinerated in order to minimize odor problems while Beavon tail gases have
generally not required incineration. The SCOT process is discussed in detail
in Appendix A-8, and the Beavon process in A-9.
The second category of processes involves incineration of the waste gas
followed by SO^ removal. Such processes are capable of achieving levels as
low as 150 ppmv of S02 in tail gas. One of the prominent SCL removal pro-
cesses, the Wellman-Lord process, removes SO,, with an alkaline sodium sulfite
solution. Subsequent regeneration of the absorbent generates a concentrated
S02 stream which would be recycled to the parent Claus plant. Eight of the
twenty-nine operating Wellman-Lord units have been specially designed to treat
Claus plant tail gas (incineration is an integral part of the Wellman-Lord
design for this application). However, other FGD processes are also appli-
cable for the removal of S02 from incinerated Claus plant tail gas. The
Wellman-Lord process for sulfur plant tail gas treatment is discussed in detail
in Appendix A-10.
Processes in the third category are used exclusively for Claus plant tail
gases, and are capable of no better than 80% recovery of tail gas sulfur. These
processes are extensions of the Claus process and therefore require a 2:1 ratio
of HpS 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 synthetic fuel plant appli-
cations in the U.S.
Incineration
As discussed above,some residual reduced sulfur species will remain in the
262
-------
Air Source Type 1
Acid Gases
off-gases leaving many of the bulk sulfur removal and residual sulfur removal
processes. Also, these processes achieve only partial control of HCN, CO, NH-,
and organic emissions. The combustion furnace of a Claus unit destroys these
constituents, but only in that portion of the gas passing through the furnace.
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. NH3 and heavy organics
are mostly removed by Stretford solvent, while light organics and CO are not
removed 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 NH3 and CO. Hydrocarbons, CO, and NH3 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 reduced sulfur compounds, hydrocarbons, CO, and NH3. In addition,
incineration is essentially the only alternative for controlling emissions of
these pollutants from transient gases such as Streams 801, 802 and 803. SCOT
tail gases are ordinarily incinerated to minimize odor problems arising from
residual H^S. Beavon tail gases (with lower H2S levels) are not ordinarily
incinerated, but an incineration step can be added for control of organics,
CO, and/or NH3 if necessary. Sulfur dioxide tail gas treatment processes such
as the Wellman-Lord inherently achieve control of organics, CO, and NH3 as part
of the preceding incineration step. Hence, no further control for these con-
stituents is ordinarily necessary with this type of process.
Advantages and disadvantages of the various tail gas and waste gas incin-
eration technologies are summarized in Table 4-8, Generally, a greater degree
of control is obtained with high temperature incineration in either a fuel-
fired boiler or a separate incinerator (either thermal or catalytic) than can
263
-------
TABLE 4-8. COMPARISON OF INCINERATION PROCESSES
Type of Incineration
Advantage
Disadvantage
Costs (Total Depreciable Capital)
Thermal Incineration
via Separate Incinerator
Thermal Incineration
in Fuel Fired Boiler
ro
CT)
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
desulfurization (FGD) units when
these are integral with the boiler.
The fuel required for steam boiler
incineration 1s 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. Haste
gases with very little combustible
material can often be incinerated
catalytlcally 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: $140 to $870
b. primary heat recovery: $190 to $1000
c. primary and secondary heat recovery:
$225 to $1200
Incremental boiler capital costs are
$2000-$3000/kg mole of incremental flue
gas compared to coal combustion on a heat-
Ing value basis. Incremental ESP and FGD
costs are an additional $2000-$2500/kg
mole Incremental flue gas.
$400 to $2200 per kmol/hr of flow for
a flow rate range of 40 to 7100 kmol/hr
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 of 100 to
1000 kmols/hr - $800 to $2700 per
kmol/hr
-------
Air Source Type 1
Acid Gases
be achieved through the use of flares, because temperature, residence time,
and the amount of air feed are better controlled. The main combustion zone of
a gas incinerator is typically engineered to maintain a minimum gas temperature
of 1100°K for a minimum of 0.5 seconds. These conditions should result in
nearly complete destruction of volatile organic compounds, reduced sulfur com-
pounds, organic aerosols, CO, NH3, HCN, and particulate matter consisting pri-
marily of combustible material.
Thermal incineration may also be effected using the coal-fired steam or
power boiler on site, where a minimum combustion temperature of 1500°K and a
minimum residence time of 0.5 seconds are typical design parameters. The
coal-fired boiler could be adapted so that the firebox could handle the feed
of these tail gas and waste gas streams, and the flue gas system could handle
the resulting increase in exhaust gases. This approach results in a degree
of pollutant destruction similar to that which would be achieved in a specially
engineered incinerator. In tail gas or waste gas treatment applications, using
the boiler as an incinerator results in an increase in the boiler capital and
annualized operating costs. A larger boiler firebox will be needed, and more
coal must be fed for a given steam/power output, due to the requirements for
heating the volume of waste gases and the inability to recover all the thermal
energy expended. Costs will also increase for the enlarged ESP and FGD units,
since costs of the pollution control units are flow rate dependent, and these
tail gases and waste gases will not be of sufficient heating value to displace
the primary boiler fuel,. Detailed discussion of thermal incineration is pro-
vided in Appendix A-16.
Catalytic incineration is not likely to be an attractive alternative for
control of carbon monoxide and organic emissions in tail gases from sulfur
recovery units or transient waste gases due to the presence of sufficient re-
duced sulfur compounds to interfere with or degrade catalysts. However, cata-
lytic incineration of CO-rich off-gases from acid gas removal (AGR) systems
265
-------
Air Source Type 1
Acid Gases
has considerable promise, and is featured in the recent design of at least
one U.S. coal gasification facility under construction (based on Texaco gasi-
fication). Detailed discussion of catalytic incineration is provided in Appen-
dix A-17.
In the ensuing subsections, the applicability of the control techniques
discussed above is addressed for each of the specific waste streams from the
EDS base case and MFS case designs covered under Air Source Type 1.
4.2.1.1 Combined Acid Gases (Streams 508, 501, 440)
Details of pollution control alternatives applicable to the following
three waste streams in the EDS designs are discussed in this section:
• Stream 508 - acid gas from DEA regenerator
• Stream 501 - acid gas from sour water stripper/ammonia recovery
• Stream 440 - flash gas from partial oxidation unit (MFS case only).
These individual streams are addressed together because, due to their similar
characteristics, they will normally be combined in a commercial EDS facility
and treated by a single set of controls as a combined acid gas stream. The
estimated characteristics for the combined acid gas stream are presented in
Tables 4-9 and 4-10 for the base case and MFS case designs, respectively.
The likelihood of combining Streams 508 and 501 for treatment derives
from the high H~S concentrations of both of these streams. Combination of
these two acid gas streams for treatment has also been proposed in all known
design studies for direct coal liquefaction commercial plants. For the MFS
case design, Stream 440 has been included in the combined acid gas stream due
to the relatively high COS concentration (1180 ppmv) of this stream. The high
COS concentration in Stream 440 means that it cannot be conveniently treated
in conventional Stretford units, which do not remove any of the COS present.
The control approach for the combined acid gas stream involves all three
functions described previously: bulk sulfur removal, residual sulfur removal,
and incineration.
266
-------
TABLE 4-9. ESTIMATED CHARACTERISTICS OF COMBINED
ACID GASES FOR EDS COMMERCIAL PLANT
(ILLINOIS COAL BASE CASE)*
Component
co2
H2S
NH3
COS
H20
Total
Temperature, °K
Pressure, MPa
Stream 508,
kmol/hr
312.1
779.4
47.7
0.45
74.2
1,213.9
322
0.2
Stream 501 ,
kmol/hr
65.4
142.3
1.8f
0
53.8
263.3
322
0.1
Combined
Volume %
25.56
62.40
3.35
0.03
8.66
100.00
Acid Gases
kmol/hr
377.5
921.7
49.5
0.45
128.0
1,477.2
322
0.1
3
* EDS plant producing 9,580 m (60,240 barrels) fuel oil equivalent of liquid
products per stream day.
Assumes NH^ recovery is employed in the sour water stripping operation.
Note: The single composition numbers used here (rather than ranges) reflect
a single set of design and operation conditions for the EDS plant.
In practice, compositions could vary due to uncertainty in these esti-
mates, and due to variations in coal type, design parameters, and
operating conditions. This note is equally applicable to other com-
position tables or anv single composition numbers presented in Section
4.
267
-------
TABLE 4-10. ESTIMATED CHARACTERISTICS OF COMBINED
AND ACID GASES FOR EDS COMMERCIAL PLANT
(ILLINOIS COAL MFS CASE)*
Component
co2
H2S
NH3
COS
H20
H2
Cl
N2
CO
Total
Temperature, °K
Pressure, MPa
Stream
508,
kmol/hr
296.8
772.5
62.2
0.45
73.7
0
0
0
0
1,205.7
322
0.2
Stream
501,
kmol/hr
55.1
136.8
1.6 f
0
49.7
0
0
0
0
243.2
322
0.1
Stream
440,
kmol/hr
82.7
11.2
0.04
0.3
19.0
61.3
0.08
1.4
77.7
253.7
322
0.2
Combined
Volume %
25.53
54.07
3.75
0.044
8.36
3.60
0.0047
0.082
4.56
100.00
Acid Gases
kmol/hr
434.6
920.5
63.8
0.75
142.4
61.3
0.08
1.4
77.7
1,702.6
322
0.1
* EDS plant producing 11,300 m (71,080 barrels) fuel oil equivalent of liquid
and gaseous products per stream day.
Assumes NH_ recovery is employed in the sour water stripping operation.
O
268
-------
Air Source Type 1
Combined Acid Gases
Control Function 1 -
Bulk Sulfur Removal
4.2.1.1.1 Control Function 1 - Bulk Sulfur Removal
In an EDS commercial plant, the combined acid gas streams contain 62.4%
HpS and 54.1% H,,S for the base case and MFS case design, respectively. Such
a stream is highly suitable for bulk sulfur removal by the Claus process, from
both technical and economical considerations, because it has such a relatively
high hLS concentration. Other available bulk sulfur removal processes generally
operate best on streams with lower H^S levels, and hence would be less appro-
priate for the treatment of this gas stream.
4.2.1.1.1.1 Control Technique 1 - Claus Process
Because of the high H~S concentration in the combined acid gas stream,
Claus plant designs of the "straight-through" mode are a reasonable choice
for buT1c sulfur removal. The "straight-through" mode of operation has several
distinct advantages. Most of the organics and CO present would be combusted,
because organics and CO tend to be preferentially oxidized before one-third
of the H?S is oxidized to SOp. Likewise, the majority of the ammonia present
would be preferentially burnt to nitrogen and water, and some NO . The pre-
J\
sence ofc.ammonia is of some concern because the levels of ammonia in the com-
bined acid gas stream, at 3.4% for the base case and 3.8% for the MFS case,
are considered to be marginally acceptable as Claus plant feed. If ammonia
is not properly combusted, residual ammonia would react with hydrogen sulfide,
sulfur dioxide, and carbon dioxide to form salts (e.g., ammonium hydrosulfide,
ammonium polysulfides, ammonium carbonates or carbamates and/or ammonium sul-
fate) that precipitate throughout the Claus unit, causing plugging and cata-
lyst deactivation problems which frequently result in premature plant shut-
downs (Appendix A-6). Thus, special attention in the design of burners and
combustion chambers and proper control of air feed are necessary for the suc-
cessful operation of the Claus unit in the EDS commercial plant. If ammonia
269
-------
Air Source Type 1
Combined Acid Gases
Control Function 1 -
Bulk Sulfur Removal
is not recovered after stripping of the sour water, Stream 501 will contain
high levels of NH- and a two compartment combustion chamber might be employed
for the Claus design. The NH^-bearing stream would be fed to the first compart-
ment along with a sub-stoichiometric amount of air. Operation under these
reducing conditions would lower the tendency to form S03, while hardly dimin-
ishing the destruction of NFL. The other acid gas streams would then be fed
to the second compartment of the combustion chamber, along with additional air,
and allowed to react with the S02 formed in the first compartment to produce
sulfur.
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 46.6 kmol/hr and 46.5 kmol/hr
would be expected for the base case and MFS case designs, respectively.* The
gaseous sulfur species distribution in Claus tail gas is approximately 60% H2S,
30% S02, 9% COS and 1% CS2. 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 sul-
fur species distribution (e.g., for 50% S02 equivalent sulfur as Sg, the spe-
cies distribution would become 53% H2S, 27% S02, 8% COS, 1% CS2, and,11% Sg).
The corresponding concentration of total sulfur (S02 equivalent) in the Claus
tail gas would be 13,600 ppmv and 11,900 ppmv for the base case and MFS case
designs, respectively. The corresponding total tail gas flow rate would be
3,420 kmol/hr and 3,930 kmol/hr.
Unit cost and capital investment costs for Claus plants were obtained
from the cost curve provided in Appendix A-6; total process cost (TPC,sum
of installed equipment cost and indirect installation cost) for the Claus
plant (2 parallel Claus trains; 14.8 Mg/hr or 461 kmol/hr sulfur per Claus
train for either the base case or the MFS case) was obtained by reading from
Figure A 6-5 in Appendix A-6 and multiplying by a factor of two (for 2
* Material flows are also presented in tabular form in Section 4.2.1.6
(Tables 4-18 and 4-19) under Integrated Control Examples.
270
-------
Air Source Type 1
Combined Acid Gases
Control Function 1 -
Bulk Sulfur Removal
parallel trains); this cost was converted to total capital investment (TCI)
using the procedures shown in Table 4-1. Annualized costs for the Claus pro-
cess were derived using the methodology described in Section 4.1.3 (summarized
in Table 4-2), and based on utilities and operating labor requirements provided
in Appendix A-6. For a Claus plant in the capacity range designed for an EDS
commercial plant, the capital investment cost per unit capacity of bulk sulfur
removal would be about $0.97 million per Mg/hr sulfur recovered. For the base
case design with no recycle sulfur stream from tail gas treatment, the total
capital investment cost would be $27.1 million (assuming 2 parallel trains) and
the total annualized cost would be $3.0 million.* These costs would be the
same for the MFS case design. The annualized cost is low due to credits for
steam (about $2.0 million) generated by the exothermic Claus reactions.
Secondary Haste Streams
The only secondary waste stream generated by the Claus process is spent
catalyst. The EDS Claus plant would have a bauxite or alumina catalyst inven-
tory of approximately 206 Mg and 237 Mg for the base case and MFS case designs,
respectively. Assuming a catalyst life of 5 years, the average spent catalyst
generation rate would be 41 Mg per year and 47 Mg per year for these two designs,
The spent catalyst consists of bauxite or alumina contaminated by the buildup
of carbonaceous matter, elemental sulfur, and sulfates. Controls for this
secondary waste stream are addressed in Section 4.4.5.
Depending on the tail gas treatment process employed, the amount of sulfur
recovered in the Claus plant would range from 28.1 to 29.5 Mg/hr. The higher
sulfur recovery corresponds to tail gas treatment processes (such as SCOT) with
sulfur streams recycled to the Claus plant.
* Costs are also presented in tabular form in Section 4.2.1.6 (Table 4-20)
under Integrated Control Examples.
271
-------
Air Source Type 1
Combined Acid Gases
Control Function 2 -
Residual Sulfur Removal
4.2.1.1.2 Control Function 2 - Residual Sulfur Removal
In an EDS commercial plant, tail gas from bulk sulfur removal would con-
tain 13,600 ppmv and 11,900 ppmv total sulfur for the base case and MFS case
designs, respectively. Traces of NH., may also be present as a result of in-
complete NH3 destruction. A number of processes are available for recovering
residual sulfur from the bulk sulfur removal tail gas (refer to Section 4.2.1).
For purposes of discussion, the Beavon, SCOT and Wellman-Lord processes will
be considered.
4.2.1.1.2.1 Control Technique 1 - Beavon Process
The Beavon process is reported to be capable of reducing residual sulfur
concentrations to about 100 ppmv with less than 10 ppmv t-LS (Appendix A-9).
Available data show that the Beavon off-gas often contains significantly less
than 100 ppmv of total sulfur compounds. Data from four Beavon units tested
indicate that the level of H2S in the off-gas ranged from 0.1 - 7 ppmv,
whereas the levels of COS and CS~ ranged from 5-50 ppmv and from 0.1 - 0.2
ppmv, respectively (Appendix A-9). Assuming a 100 ppmv sulfur level in the
Beavon off-gas, the total sulfur emission rate would be 0.30 kmol/hr and 0.35
kmol/hr for the base case and MFS case designs, respectively. The correspond-
ing amount of sulfur recovered in the Beavon unit would be 1,46 Mg/hr for both
EDS designs.* An external source of reducing gas may be required for the cata-
lytic hydrogenation of S02 and other sulfur species prior to Stretford absorp-
tion. Reducing gas may be added directly to tail gas treatment in the form of
H_ and CO-rich gas or may be generated by substoichiometric combustion of fuel
* Materials flows and costs are also presented in tabular form in Section
4.2.1.6 (Tables 4-18, 4-19 and 4-20) under Integrated Control Examples.
272
-------
Air Source Type 1
Combined Acid Gases
Control Function 2 -
Residual Sulfur Removal
gas derived from synthesis operations. The total process cost (TPC) for the
Beavon plant (2 parallel Beavon trains; each train removes 17.5 Mg/day sulfur
for the base case design) was obtained by reading from Figure A 9-2 in Appen-
dix A-9 and multiplying by a factor of two (for 2 parallel trains); this cost
was converted to total capital investment (TCI) using the procedures shown in
Table 4-1. Annualized costs for the Beavon process were derived using the
methodology described in Section 4.1.3, utilities and chemicals requirements
provided in Appendix A-9, and an operating labor requirement of 0.25 man/shift.
For the base case design, the total capital investment cost (assuming 2 par-
allel trains) and the total annualized cost would be $21.1 million and $8.5
million, respectively.* These costs would be approximately the same for the
MFS case design. For a Beavon plant in the capacity range designed for an EDS
commercial plant, the unit capital investment cost (TCI) would be approximately
$14 million per Mg/hr sulfur removed in tail gas treatment.
Secondary Haste Streams
Secondary waste streams from the Beavon process are: 1) sour reactor
effluent condensate; 2) Stretford solution purge; 3) Stretford oxidizer vent
gas; and 4) spent catalyst from the Beavon hydrolysis reactor. Sour conden-
sate is generated by the condensation of water vapor present in the Beavon
hydrolysis reactor effluent. This sour condensate is expected to contain
dissolved sulfide and traces of NH3, and would be generated at a rate of
17.9 m3/hr and 19.4 m3/hr for the base case and MFS case designs, respectively.
Controls for this secondary waste stream are identical to those for sour
water streams addressed in Section 4.3.1. Stretford solution purge for con-
trol of thiosulfate buildup typically contains 0.19 wt % anthraquinone disul-
fonic acid (ADA), 0.38 wt % vanadium, 1.45 wt % Na2C03, 8.95 wt % Na2S203,
* Materials flows and costs are also presented in tabular form in Section
4.2.1.6 (Tables 4-18, 4-19 and 4-20) under Integrated Control Examples.
273
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Air Source Type 1
Combined Acid Gases
Control Function 2 -
Residual Sulfur Removal
and 4.02 wt % NapS04 (Appendix A-9). The solution purge rate is approximately
441 kg/hr for both EDS designs. As will be discussed in Section 4.2.1.2, and
also in Appendix A-7, this purge stream may be regenerated by reductive incin-
eration or discarded. Oxidizer vent gas would consist primarily of air, water
vapor, and C02, but may contain traces of NH3 and probably some entrainment
of the Stretford solution. Controls for this secondary waste stream, if requir-
ed, are addressed in Section 4.2.1.2.1.1. Insufficient data are available for
estimating the flow rate of oxidizer vent gas. The cobalt molybdate hydrogen-
ation catalyst inventory is approximately 59 Mg for both EDS designs and would
require periodic replacement. Assuming a catalyst service life of three years,
the average spent catalyst generation rate would be 20 Mg/year. The spent
catalyst consists of cobalt and molybdenum contaminated with sulfur and sulfur
compounds. Controls for the spent catalyst are addressed in Section 4.4.5.
4.2.1.1.2.2 Control Technique 2 - SCOT Process
The SCOT process is reported to be capable of reducing residual sulfur
concentrations to about 250 ppmv with approximately 200 ppmv of H2$ (Appendix
A-8). This corresponds to a total sulfur emission rate of 0..79 kmol/hr and
0.93 kmol/hr for the base case and MFS case designs, respectively.* Sulfur
is not recovered in the SCOT process; a concentrated H~S stream is recycled
to the Claus plant for sulfur recovery. The total process cost (TPC) for the
SCOT plant (2 parallel SCOT trains; each train treats off-gas from a 373 Mg/
day sulfur Claus train and removes 0.77 Mg/hr sulfur for the base case design)
was obtained by reading from the upper cost curve in Figure A 8-2 of Appendix
A-8 and multiplying by a factor of two (for 2 parallel trains); this cost was
.converted to total capital investment (TCI) using the procedures shown in Table
* Material flows and costs are also presented in tabular form in Section
4.2.1.6 (Tables 4-21, 4-22 and 4-23) under Integrated Control Examples.
274
-------
Air Source Type 1
Combined Acid Gases
Control Function 2 -
Residual Sulfur Removal
4-1. Annualized costs for the SCOT process were derived using the methodology
described in Section 4.1.3, and utilities, chemicals and operating labor re-
quirements provided in Appendix A-8. For the base case design, the total capi-
tal investment cost (assuming 2 parallel trains) and the total annualized cost
would be $18.4 million and $7.9 million, respectively.* These costs would be
approximately the same for the MFS case design. For a SCOT plant in the capa-
city range designed for an EDS commercial plant, the unit capital investment
cost (TCI) would be approximately $12 million per Mg/hr of sulfur removed in
tail gas treatment.
Secondary Waste Streams
Secondary waste streams from the SCOT process are sour water and spent
catalyst. The sour water is generated from condensation of the water vapor
present in the SCOT hydrolysis reactor. This sour water is expected to contain
dissolved sulfide and traces of NH?, and would be generated at a rate of 18.8
33
m /hr and 20.3 m /hr for the base case and MFS case designs, respectively.
Controls for this sour water stream are identical to those for sour water
streams addressed in Section 4.3.1. The cobalt molybdate hydrogenation cata-
lyst inventory is approximately 59 Mg for both EDS designs. Assuming a cata-
lyst service life of 5 years, the average spent catalyst generation rate would
be 12 Mg/yr. The spent catalyst consists of cobalt and molybdenum contaminated
with sulfur and sulfur compounds. Controls for the spent catalyst are addressed
in Section 4.4.5.
Material flows and costs are also presented in tabular form in Section
4.2.1.6 (Tables 4-21, 4-22 and 4-23) under Integrated Control Examples
275
-------
Air Source Type 1
Combined Acid Gases
Control Function 2 -
Residual Sulfur Removal
4.2.1.1.2.3 Control Technique 3 - Wellman-Lord Process*
The Wellman-Lord SOp recovery process is typically designed to achieve
effluent levels of less than 150 ppmv to 250 ppmv S0?. Effluent levels of
less than 100 ppmv SO^ in the stack gas have been consistently achieved in
commercial installations (Appendix A-10). More recently, Davy McKee has de-
signed a Wellman-Lord SOp absorption system to treat the Claus tail gas in a
coal liquefaction plant, so as to reduce the S02 concentration in the treated
stack gas to a maximum of 150 ppmv (Appendix A-10). Unlike the Beavon and
SCOT process, residual sulfur compounds in the Claus tail gas are incinerated
to S0? prior to absorption in the Wellman-Lord process. Thus, the composition
and heating value of the fuel gas used for Claus tail gas incineration would
impact the total flow rate of the gas stream entering the Wellman-Lord absorp-
tion system. Use of low-Btu fuel gas would result in higher flow rate of com-
bustion product gas entering the Wellman-Lord absorber. And, at the higher
flow rates, the 150 to 250 ppmv S02 level achievable with the Well man-Lord
process translates into higher SO^ mass emissions.
For the EDS base case and MFS case designs, an effluent concentration of
150 ppmv S0? corresponds to a total sulfur emission rate of 1.40 kmol/hr and
1.63 kmol/hr, respectively.t These emission rates were estimated with the
assumption that the low-Btu fuel gas from Flexicoking would be used for incin-
eration of the Claus tail gas. Sulfur is not recovered in the Wellman-Lord pro-
cess; a concentrated S0? stream is recycled to the Claus plant for sulfur re-
covery. The capital investment cost per unit capacity of the Wellman-Lord unit
would be approximately $22 million per Mg/hr of sulfur removed in tail gas
treatment. For the base case design, the total capital investment cost (assum-
ing two parallel incinerator-absorber trains and one regenerator) and the total
t Material flows and costs are also presented in tabular form in Section
4.2.1.6 (Tables 4-24, 4-25 and 4-26) under Integrated Control Examples.
* Note that incineration of bulk sulfur removal tail gases, prior to W-L
absorption, is an integral part of the Wellman-Lord process.
276
-------
Air Source Type 1
Combined Acid Gases
Control Function 2 -
Residual Sulfur Removal
annualized cost would be $33.8 million and $11.1 million, respectively.*
Again, these costs would be approximately the same for the MFS case design.
The capital investment costs for the Well man-Lord process were derived from
the sum of the total process cost (TPC) curves for the incinerator-absorber
train (2 parallel trains) and the regenerator (1 train) provided in Appendix
A-10. Incineration is an integral part of the Wellman-Lord process and in-
cluded in the cost estimate. Annualized costs for the Wellman-Lord process
were derived using the methodology described in Section 4.1.3, and utilities,
chemicals and operating labor requirements provided in Appendix A-10.
Secondary Waste Streams
Secondary waste streams from the Wellman-Lord process are acidic waste-
water from combustion gas quenching and thiosulfate/sulfate by-product purge.
The acidic wastewater is generated from condensation of water vapor present in
the incinerator off-gas, and typically has a pH value between 1 and 2 due to
the S02 absorbed. No other composition data for the acidic wastewater are
available. This wastewater would be generated at a rate of 67.6 m /hr and
3
76.5 m /hr for the base case and MFS case designs, respectively. Controls for
this wastewater stream are identical to those for Water Source Type 1 addressed
in Section 4.3.1. The by-product purge typically contains 41.5 wt % Na2SCU,
18.1 wt % Na2S205, 10.0 wt % Na2S04, 1.1 wt % Na^Og, and 29.2 wt % H20
(Appendix A-10). By-product purge is generated at a rate of 314 kg/hr for
both EDS designs. Controls for this purge stream are identical to those for
Solid Waste Source Type 1 addressed in Section 4.4.2.
*
Material flows and costs are also presented in tabular form in Section
4.2.1.6 (Tables 4-24, 4-25 and 4-26) under Integrated Control Examples,
277
-------
Air Source Type 1
Combined Acid Gases
Control Function 3 -
Incineration
4.2.1.1.3 Control Function 3 - Incineration
Waste gases from tail gas treatment may be incinerated to control odors
due to the presence of H?S and to remove any residual organics and CO. As
discussed in Section 4.2.1, thermal incineration, catalytic incineration and
flaring are employed in various commercial applications. Thermal incineration
in a dedicated incinerator is an approach often used in conjunction with tail
gas treatment units, and will be considered in this section.
4.2.1.1.3.1 Control Technique 1 - Thermal Incineration
In an EDS commercial plant, gases from tail gas treatment processes (such
as Beavon and SCOT) not having an integral incineration step are generated at
a rate of approximately 3,150 kmol/hr and 3,710 kmol/hr for the base case and
MFS case designs, respectively. The sulfur content of these gases might range
from 100 to 250 ppmv with H^S concentrations ranging from less than 10 to 200
ppmv. The level of combustibles is expected to be inadequate to support com-
bustion, and supplemental fuel would be required for incineration. Using
treated low-Btu fuel gas from Flexicoking and assuming an incineration tempera-
ture of 978°K (1300°F) and 20% excess air for combustion, about 6,570 kmol/hr
and 7,730 kmol/hr of incinerated gas (including combustion products from low-
Btu fuel gas) would be generated for the base case and MFS case designs, re-
spectively. The concentration of SO^ in the effluent would be approximately
140 ppmv. Concentrations of CO and hydrocarbons in the incinerated gas would
typically range from 10 - 100 ppmv and 5-20 ppmv (Appendix A-16). No
secondary waste streams are generated by thermal incineration processes. The
capital investment cost per unit capacity of the thermal incinerator with waste
heat recovery would be approximately $940 - $1,010 per kmol/hr of gas from tail
gas treatment, for gas flows in the 3,150 - 3,710 kmol/hr range. For the base
case design, the total capital investment cost and the total annualized cost
for SCOT off-gas incineration with waste heat recovery would be $3.2 million
and $4.7 million, respectively. The corresponding costs for the MFS case design
278
-------
Air Source Type 1
Combined Acid Gases
Control Function 3 -
Incineration
would be $3.5 million and $5.5 million. The capital investment costs for
thermal incineration were obtained using the cost curve provided in Appendix
A-16. Annualized costs for thermal incineration were derived using the metho-
dology described in Section 4.1.3, and based on calculated fuel requirements
and steam generation rates from energy balances and an operating labor require-
ment of 0.125 man per shift.
279
-------
Air Source Type 1
Acid Gas from H2 Purification
Control Function 1 -
Bulk Sulfur Removal
4.2.1.2 Acid Gas from Acid Gas Removal Unit in Hydrogen Purification
(Stream 428)
This gaseous waste stream results from regeneration of the solution from
the Catacarb process (or other acid gas removal systems) used in removing H?S
and C02 from the shift gas following partial oxidation, and applies only to
the MFS case design. The stream is generated at a rate of 13,304 kmol/hr,
and contains 1.03% H2S, 38 ppmv COS, 669 ppmv NH3, 23 ppmv C,, 60 ppmv CO, and
91.18% C02. The low sulfur level and high flow rate imply that this stream
might not be suitably combined with the other acid gas streams (Streams 508,
501, and 440) for treatment. Further, the low levels of hydrocarbons and CO
present indicate that incineration to control these pollutants might not be so
critical. For this particular waste stream, the only control function needed
appears to be removal of the H^S present by bulk sulfur removal. Because of
the high levels of C02 present, however, treatment of this gas stream by resi-
dual sulfur removal processes such as Beavon and SCOT would not be effective.
The high C02 levels would result in high equilibrium COS levels in the Beavon
or SCOT hydrolysis reactions. The COS formed would not be removed by the
Stretford absorber in the Beavon process; thus, the addition of the hydrolysis
step would result in an effluent containing higher sulfur levels than the ef-
fluent from the Stretford process alone (without the hydrolysis step). For the
SCOT process, a portion of the C02 would be co-absorbed with the H2S and COS.
Regeneration of the amine absorption solution would result in an H2S-lean acid
gas stream consisting primarily of C02, and unsuitable for further processing
in Claus type sulfur recovery units. Incineration of Stream 428 followed by
S02 removal is an alternative that might be considered; however, this alterna-
tive is not economically attractive for application to this particular waste
stream when compared with bulk sulfur removal processes such as the Stretford,
because of the low levels of combustibles in Stream 428 and the supplemental
fuel requirement for incineration of this gas stream.
280
-------
Air Source Type 1
Acid Gas from H?
Purification i
Control Function 1 -
Bulk Sulfur Removal
4.2.1.2.1 Control Function 1 - Bulk Sulfur Removal
The low HpS level in the acid gas stream suggests that the Stretford or
the Giammarco-Vetrocoke process would be suited for controlling sulfur emis-
sions from this stream. For purposes of discussion, only the Stretford process
will be considered.
4.2.1.2.1.1 Control Technique 1 - Stretford Process
The Stretford process has generally been proposed for the treatment of
sour gas streams containing only a few percent H«S in coal liquefaction faci-
lities. Concentrations of H?S in the purified gas stream can typically be
reduced to less than 10 ppmv, and sometimes to less than 1 ppmv. Most of the
Stretford installations, however, have been designed to treat gases containing
only a few percent CO,,. With a feed gas containing over 90% CO^ as in this
case, there is some concern that C02 absorption by the Stretford solution would
lower the pH and increase the bicarbonate/carbonate ratio, which in turn would
lower the rate of H,,S absorption. At the SASOL I Stretford plant, original
design and operational problems in treating the high C02 (>90%) feed gas had
resulted in H2S levels of 0.8% in the inlet stream and 0.81% in the effluent
stream, indicating no H?S removal. According to Peabody-Holmes, one of the
licensees for the Stretford process, these problems could be solved by con-
sidering the different rates of C02 and H»S absorption in the Stretford solu-
tion. The Peabody-Holmes Stretford design subsequently installed at SASOL I
incorporated the following changes: 1) contact of gas and liquid in a venturi
scrubber to minimize contact time and hence C0? absorption; and 2) modifica-
tion of the Stretford solution. Peabody-Holmes, for example, reportedly has a
Stretford unit operating successfully in St. Elmo, Illinois since 1973 on a
stream consisting of 85% C0? and 15% H?S (Appendix A-7). Thus, treatment of
sour gas streams containing over 90% C0? might warrant special design consider-
ations but does not appear to be a formidable problem.
281
-------
Air Source Type 1
Acid Gas from H?
Purification
Control Function 1 -
Bulk Sulfur Removal
The Stretford process is not capable of removing carbonyl sulfide. Assum-
ing a 10 ppmv H2S level in the Stretford absorber effluent, the total sulfur
emitted would include 0.13 kmol/hr of H2$ and 0.50 kmol/hr of COS (representing
the 38 ppmv COS in the feed to the Stretford unit). Sulfur recovered from the
Stretford plant amounts to 4.4 Mg/hr. The total capital investment cost and
the total annualized cost for the Stretford plant are presented in Table 4-11.
Both costs represent approximately 1% of the corresponding uncontrolled base
plant costs.
Secondary Waste Streams
There are two secondary waste streams from the Stretford plant: 1) Stret-
ford solution purge stream due to thiosulfate and sulfate formation; and 2)
oxidizer vent gas. The solution purge is generated at a rate of 1,310 kg/hr,
and would typically contain 0.19 wt % anthraquinone disulfonic acid (ADA), 0.38
wt % vanadium, 1.45 wt % Na^CO-^, 8.95 wt % Na2S203, 4.02 wt % Na2S04, and 85.01
wt % H?0. In the past, disposal of this solution purge was often considered.
In 1973, a reductive-incineration process was developed which converts the solu-
tion purge into a gas stream containing FLS, 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 H?S-rich gas and water vapor are
recycled to the absorber. Thus, the reductive incineration process recovers
expensive chemicals while effectively attaining a "zero" discharge of solution
purge. The reductive-incineration process is considered to be an integral part
of the Stretford process offered by Peabody-Holmes.
The Stretford oxidizer vent gas would contain mostly nitrogen, oxygen,
essentially all the ammonia present in the feed gas, and be saturated with
water. Assuming that the efficiency for transfer of oxygen from air to the
Stretford solution for regeneration is only 1/3, the oxidizer vent gas would
be generated at a rate of approximately 1,000 kmol/hr. At this flow rate,
ammonia contained in the oxidizer vent gas would be 8,900 ppmv, if all the
282
-------
TABLE 4-11. COSTS OF BULK SULFUR REMOVAL WITH STRETFORD
PROCESS FOR ACID GAS FROM AGR UNIT IN
HYDROGEN PURIFICATION (STREAM 428)
Cost Element Total Capital Total Annualized
Investment* Costt
Total Cost $28.1 million $8.5 million
% of Base Plant! 0.97 0.94
Unit Cost $ 6.4 million per $245/Mg sulfur
Mg/hr sulfur recovered
recovered
* The total process cost (TPC) was calculated using: 1) 2 parallel Stretford
trains, each processing 52.7 Mg/day sulfur; 2) a TPC of $7.8 million for
a Stretford unit processing 27.7 Mg/day sulfur (115); 3) cost increases
that vary with the 0.6 power of the capacity ratio. The TPC was converted
to total capital investment cost (TCI) using the procedures outlined in
Table 4-1.
f The annualized cost was derived using methodology described in Table 4-2,
utilities and chemicals requirements provided in Table A 7-3 of Appendix
A-7 (assuming these requirements are linearly proportional to the amount
of sulfur processed), and an operating labor requirement of 0.5 man per
shift.
I Cost estimates for uncontrolled base plant for both the EDS base case and
MFS case designs are presented in Section 2.3.
Note: The single numbers (as versus ranges) presented in this table
represent a specific set of design and operating conditions for
the EDS plant and for the control technique. Both cost and per-
formance figures could vary due to uncertainties in cost and per-
formance estimates and variations in such parameters as coal type,
design and operating conditions. This note is equally applicable
to other stream-specific tables in Section 4.
283
-------
Air Source Type 1
Acid Gas from H2
Purification
Control Function 1 -
Bulk Sulfur Removal
ammonia in the feed to the Stretford appears in this vent gas. The ammonia
in the oxidizer vent gas can be readily removed by water scrubbing. Because
of the high solubility of ammonia in water, only a few stages in a tray tower,
a short packed-bed tower, or a small pressure drop in a venturi scrubber would
be needed for ammonia removal. The added cost for incorporating ammonia re-
moval would be a very small fraction of the cost for the Stretford plant pre-
sented in Table 4-11. For example, the capital investment cost for a packed-
bed tower to remove ammonia from the oxidizer vent gas would be approximately
$70,000. This cost was calculated assuming a packed-bed depth of 1.8 m (ade-
quate for 99 percent removal of ammonia) and using cost information provided
by Hanf and MacDonald (44). The wastewater stream from ammonia scrubbing
might be sent to the sour water stripper/ammonia recovery system for treatment.
Alternately, the oxidizer vent gas might also be used as air feed to boilers,
process heaters, incinerators, or the Glaus plant, where most, of the ammonia
would be combusted to form nitrogen and water.
284
-------
Air Source Type 1
Flexicoking Sour Fuel Gas
Control Function 1 -
Bulk Sulfur Removal
4.2.1.3 Flexicoking Gasifier/Heater Sour Fuel Gas (Stream 304)
The sour fuel gas is generated in the Flexicoking gasifier vessel where
coke formed in the Flexicoking reactor is gasified with steam and air. Total
sour fuel gas produced is 54,781 kmol/hr and 27,224 kmol/hr for the base case
and MFS case designs, respectively. The sour fuel gas from base case design
contains 0.42% H2$, 108 ppmv COS, 11.6% C02, 17.9% H2, 18.0% CO, 1.5% C-,,
47.0% N2, and 3.6% H20. The sour fuel gas from the MFS case design is slightly
different in composition in that it contains 92 ppmv COS, 19.7% H2, and 45.8%
N2. With a heating value of 4.7 MJ/Nm3 (125 Btu/SCF, dry basis), combustion
of this sour fuel gas would result in S02 emissions of approximately 2,550
ng/J (5.9 Ib/MM Btu). Hence, removal of reduced sulfur compounds from the
sour fuel gas prior to combustion in process heaters and boilers is an option
that might be considered. The other control option, removal of S02 after com-
bustion, is more conveniently discussed under control technologies for combus-
tion gases (Source Type 2).
Two general types of control strategies to remove reduced sulfur compounds
from the sour fuel gas are available. The first type involves two control func-
tions: acid gas removal (AGR), and bulk sulfur removal of the acid gas stream
from the regenerator of the AGR unit. For example, an AGR system that have a
greater affinity for H2S than for C02, such as the Selexol (Appendix A-3) or
the Rectisol (Appendix A-2) process, can be used to remove the H2S along with
some of the COS and C02 (e.g., 15% of the C02) from the sour fuel gas. The
acid gas stream from the regenerator will contain practically all of the H,,S,
and could be sufficiently concentrated in H2S — depending on the AGR process
and the design conditions -- to be fed directly to the Claus plant for bulk
sulfur recovery. In cases where lower H,,S concentrations are obtained in the
acid gas stream from the AGR regenerator, this acid gas stream might be com-
bined with acid gases from other process areas prior to bulk sulfur removal
in a Claus plant. The second type of control strategy is to remove and recover
285
-------
Air Source Type 1
Flexicoking Sour Fuel Gas
Control Function 1 -
Bulk Sulfur Removal
reduced sulfur compounds from the sour fuel gas within a single control func-
tion. This second type of control strategy is discussed in the following sec-
tion.
4.2.1.3.1 Control Function 1 - Bulk Sulfur Removal
Since the sour fuel gas only contains approximately 0.4% H2S, the Stret-
ford or Giammarco-Vetrocoke process would be the choice for reducing the sul-
fur content of this stream. For purposes of discussion, only the Stretford
process will be considered.
4.2.1.3.1.1 Control Technique 1 - Stretford Process
As discussed previously, concentrations of H2S in the treated fuel gas
stream from the Stretford process can generally be reduced to less than 10
ppmv, and sometimes to less than 1 ppmv. The Stretford process, however, is
not capable of removing carbonyl sulfide. Thus, the treated fuel gas would
be expected to contain less than 10 ppmv H^S and 108 ppmv COS for the base
case design, and less than 10 ppmv H2S and 92 ppmv COS for the MFS case design.
Because of the relatively low C02 levels in the sour fuel gas, no specific
operational problems involving C02 absorption and pH lowering are expected.
Sulfur recovered from the Stretford plant would amount to 7.3 Mg/hr and 3.9
Mg/hr for the base case and MFS case designs, respectively.
The total capital investment costs and the total annualized costs for
the Stretford plant are presented in Table 4-12. Because three Flexicoking
trains have been proposed in the EDS base case design and only two in the MFS
case design, the capital investment costs were estimated based on three parallel
Stretford units for the base case design and two parallel Stretford units for
the MFS case design (i.e., one Stretford unit for each Flexicoker). Both the
capital investment cost and the annualized cost represent approximately 1.4%
of the corresponding uncontrolled base plant costs for the base case design,
and approximately 0.9% of the corresponding uncontrolled base plant costs for
the MFS case design.
286
-------
TABLE 4-12. COSTS OF BULK SULFUR REMOVAL WITH
STRETFORD PROCESS FOR FLEXICOKING
HEATER/GASIFIER SOUR FUEL GAS
(STREAM 304)
Cost Element
Base Case
Total
Capital
Investment*
Total
Annuali zed
Cost t
MFS Case
Total Total
Capital Annual
Investment* Costt
ized
Total Cost
% of Base Plant
Unit Cost
$45.0 million $13.8 million
1.41 1.43
$ 6.1 million $237/Mg sulfur
per Mg/hr sul- recovered
fur recovered
$26.1 million $7.8 million
0.90 0.86
$ 6.7 million $254/Mg
per Mg/hr sulfur
sulfur recovered
recovered
* The total process cost (TPC) was calculated using: 1) a TPC of $7.8 million
for a Stretford unit processing 277 Mg/day sulfur (115); and 2) cost in-
crases that vary with the 0.6 power of the capacity ratio. The TPC was
converted to total capital investment cost (TCI) using the procedures
outlined in Table 4-1. For the base case, the capital investment cost
is the sum of the costs of three Stretford units, each treating 1/3 of
Stream 304 or 58.8 Mg/day sulfur. For the MFS case, the capital investment
cost is the sum of the costs of two Stretford units, each treating 1/2 of
Stream 304 or 46.6 Mg/day sulfur.
^ The annualized costs were derived using the methodology described in Table
4-2, utilities and chemicals requirements provided in Table A 7-3 of Appen-
dix A-7 (assuming these requirements are linearly proportional to the amount
of sulfur processed), and an operating labor requirement of 0.5 man per shift.
287
-------
Air Source Type 1
Flexicoking Sour Fuel Gas
Control Function 1 -
Bulk Sulfur Removal
Secondary Waste Streams
As in other Stretford designs, there are two secondary waste streams from
the process: 1) Stretford solution purge stream due to thiosulfate and sulfate
formation; and 2) oxidizer vent gas. The solution purge is generated at a rate
of 2,186 kg/hr and 1,154 kg/hr for the base case and MFS case designs, respect-
ively. The composition of this purge stream has been described in Section
4.2.1.2. The solution purge might be treated by reductive-incineration with
all the sulfur released as H^S and recycled to the Stretford absorber.
The Stretford oxidizer vent is not expected to cause any problems. This
is because of the absence of ammonia and mercaptans in the sour fuel gas. The
Stretford oxidizer vent would therefore contain only nitrogen, oxygen, and be
saturated with water.
288
-------
Air Source Type 1
Vent Gas and Off-gas
4.2.1.4 Slurry Drier Vent Gas (Stream 102) and Vacuum Fractionator
Off-Gases (Streams 153/156)*
The slurry drier vent gas is generated at a rate of 532 kmol/hr, and
contains 30 ppmv HLS and 4.1% hydrocarbons. The vacuum fractionator off-gas
is generated at a rate of 69 kmol/hr, and contains 5.0% H?S and 47.5% hydro-
carbons. The slurry drier vent gas has a heating value of approximately 7.1
3
MJ/Nm (190 Btu/SCF), and might be used as fuel gas without additional treat-
ment. The vacuum fractionator off-gas has a higher heating value but also
higher F^S level. In practice, it might be convenient to combine these two
gas streams with the Flexicoking sour fuel gas, so that removal of reduced
sulfur compounds from this combined fuel gas stream prior to combustion might
be considered. The slurry drier vent gas and vacuum fractionator off-gas to-
gether are generated at a rate of 601 kmol/hr, and contain 0.58% HpS and 9.1%
hydrocarbons. Thus, the H~S level of these two streams together is similar
to the HpS level in the Flexicoking sour fuel gas. The only control function
needed for these two streams is bulk sulfur removal. The other control option,
removal of SO^ after combustion, is more conveniently discussed under control
technologies for combustion gases (Source Type 2).
Similar to the Flexicoking sour fuel gas (Section 4.2.13), two types of
control strategies to remove reduced sulfur compounds from Streams 102 and
153/156 are available. The first type involves acid gas removal (AGR) followed
by bulk sulfur removal. AGR techniques that have a greater affinity for hUS
than C0? would be applicable if these streams were combined with the Flexicok-
ing sour fuel gas. If Streams 102 and 153/156 were not combined with the
Flexicoking sour fuel gas, (#2 is not present in these streams and non-selective
AGR systems such as the DEA process might be considered for sulfur removal.
* Streams 153/156 in the MFS case design is identical to Stream 153 in the
base case design.
289
-------
Air Source Type 1
Vent Gas and Off-gas
Control Function 1 -
Bulk Sulfur Removal
The application of AGR techniques to these streams is not discussed
here; descriptions of AGR systems can be found in Appendices A-l through A-5.
The second type of control strategy involves removing and recovering reduced
sulfur compounds within a single control function, and is discussed in the fol-
lowing section.
4.2.1.4.1 Control Function 1 - Bulk Sulfur Removal
Either the Stretford or the Giammarco-Vetrocoke process would be suited
for the treatment of the slurry drier vent gas and vacuum fractionator off-gas
combined with the Flexicoking sour fuel gas. Only the Stretford process for
treating the combination of Streams 102 and 153/156 will be discussed here.
4.2.1.4.1.1 Control Technique 1 - Stretford Process
As discussed previously, it might be convenient to combine these two
gaseous streams with the Flexicoking sour fuel gas for treatment by the Stret-
ford process. Total combined fuel gas produced would be 55,382 kmol/hr and
27,826 kmol/hr for the base case and MFS case designs, respectively. Prior to
Stretford treatment, the combined sour fuel gas from the base case design
would contain 0.42% FUS, 107 ppmv COS and 11.5% COp, a composition almost iden-
tical to the Flexicoking sour fuel gas. Similarly, the combined sour fuel gas
from the MFS case design would be almost identical in composition to the Flexi-
coking sour fuel gas, and would contain 0.45% FLS, 90 ppmv COS, and 11.3% C02-
The treated fuel gas from these combined streams would then contain less than
10 ppmv H-S and 107 ppmv COS for the base case design, and less than 10 ppmv
HpS and 90 ppmv COS for the MFS case design. Additional sulfur recovered in
the Stretford plant would amount to 0.11 Mg/hr for both EDS designs.
The capital investment costs and annualized costs for a single Stretford
system designed to handle the combined Streams 304, 102, and 153/156 are pre-
sented in Table 4-13. The table also shows the incremental portion of this
combined cost that is attributable to Streams 102 and 153/156. Finally, the
290
-------
TABLE 4-13. COSTS OF BULK SULFUR REMOVAL WITH STRETFORD
PROCESS FOR SLURRY DRIER VENT GAS AND VACUUM
FRACTIONATOR OFF-GAS (STREAMS 102 and 153/156)
Cost Element
Base Case
Total Total
Capital Annual ized
Investment* Cost*
MFS Case
Total Total
Capital Annual ized
Investment* Costt
Stretford Plant
for Treating Streams
304, 102 and 153/176"
Total Cost
% of Base Plant
Unit Cost
Incremental Portion
of Above Cost
Attributable to
Streams 102 and 153/156
Total Cost
% of Base Plant
Unit Cost
Stretford Plant
for Treating Streams
102 and 153/156
Total Cost
% of Base Plant
Unit Cost
$45.4 million
1.42
$6.1 million
per Mg/hr
sulfur
recovered
$0.41 million
0.013
$3.7 million
per Mg/hr
sulfur
recovered
$13.9 million $26.5 million $7.9 million
1.45 0.92 0.87
$237/Mg
sulfur
recovered
$6.7 million
per Mg/hr
sulfur
recovered
$252/Mg
sulfur
recovered
$0.15 million $0.44 million $0.16 million
0.016 0.015 0.018
$175/Mg $4.0 million $183/Mg
sulfur per Mg/hr sulfur
recovered sulfur recovered
recovered
$2.3 million
0.074
$21 million
per Mg/hr
sulfur
recovered
$0.56 million
0.058
$634/Mg
sulfur
recovered
$2.3 million
0.081
$21 million
per Mg/hr
sul fur
recovered
$0.56 million
0.061
$634/Mg
sulfur
recovered
* The total process cost (TPC) was calculated using: 1) a TPC of $7.8 million
for a Stretford unit processing 27.7 Mq/day sulfur (115): and 2) cost in-
creases that vary with the 0.6 power of the capacity ratio. The TPC was
converted to total capital Investment cost (TCI) using the procedures out-
lined 1n Table 4-1. Also, three parallel Stretford units were assumed for
the base ease design (each processing 59.7 Mg/day sulfur) and two parallel
units for the MFS case design (each processing 47.9 Mg/day sulfur),w,,e,i Stream
304 is combined with Streams 102 and 153/156. Only one Stretford unit is as-
sumed in treating Streams 102 and 153/156 separately (processing 2.66 Mg/day
sulfur).
f The annualized costs were derived using the methodology described in Table 4-2
and utilities and chemicals requirements provided 1n Table A 7-3 of Appendix
A-7 (assuming these requirements are linearly proportional to the amount of
sulfur processed). Operating labor requirement was assumed to be 0.5 man
per shift for combination of Streams 304, 102 and 153/156, and 0.125 man per
shift for combination of just Streams 102 and 153/156.
291
-------
Air Source Type 1
Vent Gas and Off-gas
Control Function 1 -
Bulk Sulfur Removal
table shows the costs involved in installing and operating a separate Stretford
system just for Streams 102 and 153/156. The incentive for combining Streams
102 and 153/156 with Stream 304 is clearly indicated by the much higher costs
of the separate Stretford system.
Secondary Waste Streams
Additional Stretford solution purge generated from the treatment of the
slurry drier vent gas and vacuum fractionator off-gas would be 33 kg/hr for
both EDS designs. Because of the absence of ammonia and mercaptans in the two
gas streams, additional contribution to the Stretford oxidizer vent gas would
involve only nitrogen, oxygen, and water vapor.
292
-------
Air Source Type 1
Transient Waste Gases
4.2.1.5 Transient Uaste Gases (Streams 803, 801, 802)
Transient waste gases are generated from the EDS commercial plant during
startups, shutdowns, and upset conditions. In this section, pollution control
alternatives applicable to the following three transient waste gas streams are
discussed:
• Stream 803 - transient waste gas from liquefaction reactor
• Stream 801 - transient waste gas from Flexicoking
• Stream 802 - transient waste gas from partial oxidation unit
(MFS case only).
These transient waste streams are discussed together because the control
approach for each is the same, although the streams would not necessarily be
combined for treatment. In all likelihood, these transient waste gases would
be generated at different times, and pollution control equipment sized to con-
trol the largest transient waste gas stream might also be used to handle other
transient or intermittent waste gas streams.
The transient waste gas from liquefaction reactor was estimated to be
generated at a rate of 3,275 kmol/hr. Transient conditions would be expected
twice per year for each of the four reactors, and up to 3 hours in duration
each time. This transient waste gas in the Exxon designs was estimated to
contain 45.1% hydrocarbons, 0.5% CO, and 2.5% FLS. The hydrocarbons present
include 20 ppmv organics in the 400 to 700°F boiling range. It is likely that
some refractory compounds might be present in organics of this boiling range.
The transient waste gas from Flexicoking was estimated to be generated
at a rate of 671 kmol/hr and 511 kmol/hr for the base case and MFS case designs,
respectively. Transient conditions would be expected 30 times per year for
each of the Flexicoking units (three for the base case design and two for the
MFS case design), and up to 3 hours in duration each time. For the base case
design, this transient waste gas contains 40.9% hydrocarbons, 4.0% CO, and 1.0%
293
-------
Air Source Type 1
Transient Waste Gases
Control Function 1 -
Incineration
H2$. For the MFS case design, this transient waste gas contains 39.7% hydro-
carbons, 4.0% CO, and 1.5% H2$. For both designs, the hydrocarbons present
include approximately 1% organics with boiling points equal to or higher than
that of hexane. This high boiling fraction might contain significant amounts
of refractory organic compounds.
The transient waste gas from partial oxidation unit was estimated to be
generated at a rate of 12,121 kmol/hr, and applies only to the MFS case design.
Transient conditions would be expected once a year, only to one of the partial
oxidation units and up to 24 hours in duration. This transient waste gas con-
tains 0.2% methane, 17.7% CO, 0.3% H2S, 250 ppmv COS, 8 ppmv HCN, and 170 ppmv
NH3.
The approach to control these transient waste gases may involve up to two
control functions: incineration and bulk sulfur removal (S0? removal after
incineration).
4.2.1.5.1 Control Function 1 - Incineration
Incineration of transient waste gases can be accomplished in boilers,
dedicated incinerators, or flares. For purposes of discussion, only flares
and dedicated thermal incinerators will be considered. Catalytic incineration
is not likely to be an attractive alternative, because the presence of sulfur
compounds in transient waste gases might interfere or degrade catalysts.
4.2.1.5.1.1 Control Technique 1 - Flaring
Flares are special burners designed to dispose of relatively high volume
waste streams consisting of hydrocarbons and other combustibles. Compared to
incinerators, flares provide less control of combustion temperature and amount
of air feed, but are better equipped to handle sudden surges in gas flow rates
and are less expensive. Data on the combustion efficiency of flares are limited.
Most recent studies indicate that 96 to greater than 99% of the hydrocarbons in
the waste gas are typically destroyed by flaring (Appendix A-15). Hydrocarbon
294
-------
Air Source Type 1
Transient Waste Gases
Control Function 1 -
Incineration
destruction in flares depends on the amount and distribution of oxygen in the
combustion zone, and the nature of organic compounds in the gas being burnt.
Refractory organic compounds present in the transient waste gases, for example,
might experience much lower destruction efficiency than light hydrocarbon gases
such as methane or ethane. In addition, most of the CO would be converted to
CO,; NH~ to nitrogen, NO , and water; HCN to nitrogen, N0v,water, and CO,,; and
C. O X At
sulfur compounds to S02 and S03.
Estimated capital investment costs and annualized costs for flaring of the
three transient waste gases in separate systems are presented in Table 4-14.
The unit annualized cost ($/kmol waste gas) for flaring of the transient waste
gas from Flexicoking is lower, because of the larger flows associated with the
longer duration of transient conditions.
4.2.1.5.1.2 Control Technique 2 - Thermal Incineration
Thermal incinerators provide a combustion chamber and mixing between waste
gas and air at a high temperature for the oxidation of combustible compounds
present in the transient waste gases. Concentrations of CO and hydrocarbons
in the incinerated gas would typically range from 10-100 ppmv and 5-20 ppmv,
respectively. Assuming combustion with 20% excess air, incineration of the
transient waste gas from liquefaction reactor would generate 29,350 kmol/hr
of flue gas containing 2,850 ppmv S02. For the base case design, incineration
of the transient waste gas from Flexicoking would generate 5,610 kmol/hr of
flue gas containing 1,250 ppmv SOp. For the MFS case design, incineration of
this same transient waste gas would generate 4,250 kmol/hr of flue gas con-
taining 1,810 ppmv SO,,. Flue gas from incineration of the transient waste gas
from partial oxidation unit would be generated at a rate of 23,590 kmol/hr,
and contains 1,680 ppmv SO^.
Estimated capital investment costs and annualized costs for thermal in-
cineration of transient waste gases are presented in Table 4-15. Similar costs
are presented in Table 4-16 for thermal incineration with waste heat recovery.
295
-------
TABLE 4-14. COSTS OF FLARING FOR TRANSIENT WASTE GASES (STREAMS 801, 802, 803)
ro
to
Transie5nWst8eUi3as from Transient fiatWs from Stream 802
Liquefaction Reactor Flexicoking Transient Waste
Cost Element Base Case
Capital Investment Cost*
Total Cost, $ million 0.47
% of Base Plant 0.015
Unit Cost, $ per
kmol/hr waste gas 143
Annualized Cost!
Total Cost, $ million 0.094
% of Base Plant 0.0097
Unit Cost, $7kmol
waste gas 1.2
MFS Case Base Case
0.47 0.096
0.016 0.00
143 143
0.094 0.022
0.010 0.002
1.2 0.12
Gas from
MFS Case Partial Oxidation*
0.073 1.7
0.003 0.060
143 143
0.016 0.34
0.002 0.038
0.18 1.2
Generated only from the MFS case design.
* The capital Investment costs were derived using the equipment cost curve for 200 ft high flares (Figure
A 15-3) presented in Appendix A-15 and the methodology outlined in Table 4-1. This capital
investment cost corresponds to a unit cost of $143 per kmol/hr waste gas.
•rThe annualized costs were derived using the methodology described in Section 4.1.3. and rough estimates
of manpower and steam requirements.
-------
TABLE 4-15. COSTS OF THERMAL INCINERATION FOR TRANSIENT WASTE GASES
(STREAMS 801, 802, 803)
ro
vo
—i
Stream 803 Stream 801
Transient waste Gas from Transient Waste Gas from
Liquefaction Reactor Flexicoking
Cost Element Base Case MFS Case Base Case
Capital Investment Cost*
Total Cost, $ million 3.8 3.8 0.75
% of Base Plant 0.12 0.13 0.023
Unit Cost, $ per 1,168 1,168 1,113
kmol/hr waste gas
Annual ized Cost \
Total Cost, $ million 0.75 0,75 0.14
% of Base Plant 0.078 0.083 0.015
Unit Cost, $/kmo1 9.6 9.6 0.78
waste gas
MFS Case
0.57
0.020
1,108
0.11
0.012
1.2
Stream 802
Transient Waste
Gas from
Partial Oxidation*
3.1
0.11
259
0.62
0.068
2.1
Generated only from the MFS case design.
The capital investment costs were obtained using the calculated combustion product flow rates and the
installed equipment cost curve (Curve A) presented in Figure A 16-6 of Appendix A-16. This capital
investment cost corresponds to a unit cost of $133 per kmol/hr combustion product gas.
tThe annualized costs were derived using the methodology described in Section 4.1.3. Annualized cost
for each case is approximately 20% of the corresponding capital investment cost (17.2% capital charge,
2% maintenance, the other costs are small for handling transient waste gases).
-------
TABLE 4-16. COSTS OF THERMAL INCINERATION WITH WASTE HEAT RECOVERY FOR TRANSIENT WASTE GASES
(STREAMS 801, 802, 803)
ro
vo
00
Cost Element
Capital Investment Cost"1"
Total Cost, $ milHon
% of Base Plant
Unit Cost. $ per
kmol/hr waste gas
Annual i zed Cost J
Total Cost, $ million
% of Base Plant
Unit Cost, $/kmol
waste gas
Stream 803
Transient Waste Gas from
, Liquefaction Reactor
Base Case
5.0
0.16
1,526
0.98
0.10
12.5
MFS Case
5.0
0.17
1,526
0.98
0.11
12.5
Stream 801
Transient Waste Gas
, Flexicoking
Base Case MFS
0.95
0.030
from
Case
0.72
0.025
1,423 1,416
0.19
0.020
1.0
0.14
0.016
1.5
Stream 802
Transient Waste
Gas from
Partial Oxidation*
4.0
0.14
331
0.79
0.087
2.7
Generated only from the MFS case design.
tjhe capital investment costs were obtained using the calculated combustion product flow rates and the
Installed equipment cost curve (Curve B) presented in Figure A 16-6 of Appendix A-16. This capital
.investment cost corresponds to a unit cost of $170 per kmol/hr combustion product gas.
+ The annuallzed costs were derived using the methodology described in Section 4.1.3. Annualized cost
for each case is approximately 20% of the corresponding capital investment cost (see footnote for Table
4-15). Steam credits from heat recovery are negligible because these transient waste gases are generated
only for very short periods of time.
-------
Air Source Type 1
Transient Waste Gases
Control Function 2 -
Bulk Sulfur Removal
This latter case would be equivalent to incineration in a boiler. The capital
investment costs per unit capacity in Tables 4-15 and 4-16 vary because these
unit costs are dependent on the flow rate of the combustion product gas and
not the flow rate of the transient waste gas.
4.2.1.5.2 Control Function 2 - Bulk Sulfur Removal
As will be discussed in Section 4.2.2 under Source Type 2 - Combustion
Gases, a number of flue gas desulfurization (FGD) processes are commercially
available. For control of SCL emissions from incinerated transient waste
gases, only the sodium throwaway process will be discussed here.
4.2.1.5.2.1 Control Technique 1 - Sodium Throwaway Process
Compared to other FGD systems, the sodium throwaway process is lower in
capital investment cost and higher in operating cost. The higher operating
cost is the result of the cost of sodium carbonate employed for scrubbing.
This higher chemical cost is of lesser concern in the control of intermittent
waste streams such as incinerated transient waste gases. Sodium throwaway
systems can be designed to remove 90% of the S02 present in the inlet stream.
Thus, sodium throwaway processes can reduce the S02 concentration in the incin-
erated transient waste gases to 125-285 ppmv.
Estimated capital investment costs and annualized costs for sodium throw-
away processes are presented in Table 4-17. Although these costs appear to
be relatively high, the use of a common FGD system, sized to control the in-
cinerated transient waste gas from the liquefaction reactor, could also be
used to control SOp emissions from other transient or intermittent waste gases,
There is no need for a dedicated FGD system for each of the transient or inter-
mittent waste gas streams.
299
-------
TABLE 4-17. COSTS OF SULFUR DIOXIDE CONTROL BY SODIUM THROWAWAY PROCESSES FOR TRANSIENT WASTE GASES
(STREAMS 801.802.803)
OJ
o
o
Transient Waste Gas from Transient Waste Gas from stream BUZ
Liquefaction Reactor Flexicoking Transient Waste
Cost Element Base Case MFS Case Base Case
i
Capital Investment Cost"1'
Total Cost, $ million 12.2 12.2 2.3
% of Base Plant 0.38 0.42 0.073
Unit Cost, $ per 3,722 3,722 3,471
kmol/hr waste gas
Annual i zed Cost!
Total Cost, $ million 2.5 2.5 0.51
% of Base Plant 0.25 0.27 0.053
Unit Cost, $/ktno1 31.2 31.2 2.8
waste gas
Gas from
MFS Case Partial Oxidation*
1.8 9.8
0.061 0.34
3,454 808
0.39 2.0
0.043 0.22
4.2 6.7
Generated only from the MFS case design.
1"Capital Investment costs were obtained using the calculated combustion product flow rates and cost data
provided in Reference 45, which indicate a unit capital investment cost of $415 per kmol/hr combustion
product gas.
|The Annualized costs were derived using the methodology described in Section 4.1.3. Sodium carbonate
consumption was assumed to be 1.2 mo! per mol SO, removed. Cost of sodium carbonate was assumed to be
$264/Mg. £
Note: These cost estimates assume the worst case, that a separate flue gas treatment
unit will be installed for each transient stream. Use of a single, common
scrubber would reduce these costs.
-------
Air Source Type 1
Integrated Control
Examples
4.2.1.6 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 performance with similar or even lower costs.
Specific technologies were selected to cover the types of alternatives which
have actually been proposed for facilities in the U.S. Selection of inte-
grated controls will be based upon specific design requirements and local con-
ditions, and can only be made by designers and regulatory authorities involved
in a specific project.
The integrated control examples for Source Type 1 address only the combi-
nation of three acid gas streams, because this is the one case for which several
likely alternatives for multiple controls in series are possible. As discussed
in Section 4.2.1.1, it would be logical to combine the following acid gas streams
prior to treatment in an integrated control system:
• Stream 508 - acid gas from DEA regenerator
• Stream 501 - acid gas from sour water stripper/ammonia recovery
• Stream 440 - flash gas from partial oxidation unit (MFS case only).
Three integrated control alternatives for the combined acid gas stream will
be examined in this section:
• Claus bulk sulfur removal with tail gas treatment by the Beavon
Sulfur Removal Process (BSRP).
• Claus bulk sulfur removal with SCOT tail gas treatment, followed by
incineration
• Claus bulk sulfur removal with Wellman-Lord tail gas treatment.
The first alternative was proposed for the SRC-I demonstration plant in treat-
ing similar acid gas streams, and also by Exxon (although not explicitly stated)
301
-------
Air Source Type 1
Integrated Control
Examples
in the conceptual design of the EDS commercial plant. The second alternative
was proposed for the SRC-II demonstration plant and commercial plant, and the
third alternative was proposed in the conceptual design of the H-Coal commer-
cial plant, also for treating similar acid gas streams. Thus, the three con-
trol alternatives selected as examples here cover all the cases that have been
proposed by the four leading developers of direct liquefaction processes in
the U.S.
4.2.1.6.1 Example 1 - Glaus Bulk Sulfur Removal with Tail Gas Treatment by
the Beavon Sulfur Removal Process
The integrated control system in this example for treating the combined
acid gas is illustrated in Figure 4-1. Because of the high concentration
level of H2S in the combined acid gas stream, the Claus plant is operated in
the "straight through" mode in this example, with the complete stream sent to
the combustion chamber. Ammonia present in the combined acid gas would there-
fore be mostly combusted to nitrogen and water.
Material flow estimates and performance of the Claus/Beavon integrated
control system are presented in Tables 4-18 and 4-19 for the base case and
MFS case designs, respectively. The stream names used in these tables are
those shown in Figure 4-1. Assumptions used for Claus/Beavon performance
included: 1) 95% sulfur removal in the Claus plant; and 2) less than 100 ppmv
total sulfur in Beavon off-gas. The Claus tail gas for the base case design
is generated at a rate of 3417 kmol/hr, and contains 13,625 ppmv total sulfur
(S0? equivalent). For the MFS case design, the Claus tail gas is generated
at a slightly higher rate of 3926 kmol/hr, because of the presence of CO and
hydrogen in the feed gas. The Claus tail gas in this case contains 11,850
ppmv total sulfur (SO^ equivalent). Total sulfur emissions through the Beavon
off-gas were estimated to be less than 0.30 kmol/hr (<10 ppmv HLS and <90 ppmv
COS) for the base case design, and less than 0.35 kmol/hr (<10 ppmv H?S and
<90 ppmv COS) for the MFS case design. These are equivalent to greater than
302
-------
CO
o
OO
A/*in f?AQ EROU nCA
MOIL/ VJ/VO rnVlM UCM
ftFP rwr n A TO n
ACID GAS FROM SOUR WATER
STRIPPER/AMMONIA RECOVERY
FLASH GAS FROM PARTIAI
OXIDATION (MFSCASE ONLY)
A
STRETFORD
OXIDIZER
VENT GAS
t
I
^
^
->
^
R
GLAUS BULK
SULFUR REMOVAL
! 1
CLAUSTAILGAS^
^
FUEL/REDUCING
AS p
AIR ^
BEAVON SULFUR
REMOVAL PROCESS
T~
X SULFUR SOUR
7, CONDENSATE.
i J
SULFUR 5
1
CDCU
k.
w
r
r
T
BE AVON TAIL GAS
TO ATMOSPHERE
CATALYST
FUNCTION 1
STRETFORD CATALYST
SOLUTION
PURGE
FUNCTION 2
Figure 4-1. Example 1 -
Claus bulk sulfur
removal process
removal with tail gas treatment by Beavon sulfur
-------
TABLE 4-18. MATERIAL FLOW ESTIMATES AND PERFORMANCE OF INTEGRATED CONTROL
FOR COMBINED ACID GAS STREAM EMPLOYING CLAUS BULK SULFUR
REMOVAL AND BEAVON TAIL GAS TREATMENT (ILLINOIS COAL BASE CASE)
Stream Description/
Control Option
Combined Acid Gas
Claus Tail Gas
Spent Claus Catalyst
Sulfur Recovered in Claus Plant
Beavon Off -Gas
Beavon Sour Condensate
Stretford Solution Purge
Spent Beavon Catalyst
Component
H2S
NH3
COS
Total
H2S
S02
COS
CS2
Total
Bauxite/
Alumina
Sulfur
H2S
COS
Total
Sour Water
ADA
Vanadium
Na2 COa
Na2 S203
Na? S04
H20
Total
Cobalt-
Molybdate
Flow Rate
921.7 kmol/hr
49.5 kmol/hr
0.45 kmol/hr
1477.2 kmol/hr
27.7 kmol/hr
13.8 kmol/hr
4.2 kmol/hr
0.46 kmol/hr
3417.2 kmol/hr
41 Mg/yr
28.1 Mg/hr
<0.03 kmol/hr
<0.27 kmol/hr
3033.8 kmol/hr
17.9 m3/hr
0.84 kg/hr
1.68 kg/hr
6.41 kg/hr
39.5 kg/hr
17.8 kg/hr
375.6 kg/hr
441.8 kg/hr
20 Mg/yr
Concentration
62.40 vol %
3.35 vol %
0.03 vol %
8094 ppmv
4047 ppmv
1214 ppmv
135 ppmv
<10 ppmv
<90 ppmv
0.19 wt %
0.38 wt %
1.45 wt %
8.95 wt %
4.02 wt %
85.01 wt %
Sulfur Recovered in
Beavon Process
Sulfur
1.46 Mg/hr
304
-------
TABLE 4-19. MATERIAL FLOW ESTIMATES AND PERFORMANCE OF INTEGRATED CONTROL
FOR COMBINED ACID GAS STREAM EMPLOYING CLAUS BULK SULFUR REMOVAL
AND BEAVON TAIL GAS TREATMENT (ILLINOIS COAL MFS CASE)
Stream Desciption/
Control Option
Combined Acid Gas
Claus Tail Gas
Spent Clans Catalyst
Sulfur Recovered in Claus Plant
Beavon Off-Gas
Beavon Sour Condensate
Stretford Solution Purge
Spent Beavon Catalyst
Component
H2S
NH3
COS
Total
H2S
S02
COS
CS2
Total
Bauxi te/
Alumina
Sulfur
H2S
COS
Total
Sour Water
ADA
Vanadium
Nag COs
Na2 S203
Na2 S04
H20
Total
Cobalt-
Molybdate
Flow Rate
920.5 kmol/hr
63.8 kmol/hr
0.75 kmol/hr
1702.6 kmol/hr
27.6 kmol/hr
13.8 kmol/hr
4.2 kmol/hr
0.46 kmol/hr
3926.0 kmol/hr
47 Mg/yr
28.1 Mg/hr
<0.035 kmol/hr
<0.32 kmol/hr
3538.5 kmol/hr
19.4 m3/hr
0.84 kg/hr
1.68 kg/hr
6.40 kg/hr
39.5 kg/hr
17.7 kg/hr
375.0 kg/hr
441.1 kg/hr
20 Mg/yr
Concentration
54.07 vol %
3.75 vol %
0.044 vol !
7040 ppmv
3520 ppmv
1057 ppmv
117 ppmv
<10 ppmv
<90 ppmv
0.19 wt %
0.38 wt %
1.45 wt %
8.95 wt %
4.02 wt %
85.01 wt %
Sulfur Recovered in
Beavon Process
Sulfur
1.46 Mg/hr
305
-------
Air Source Type 1
Integrated Control
Examples
99.96% total sulfur removal from the combined acid gas for the Claus/Beavon
integrated control system.
There are four secondary waste streams from the Claus/Beavon integrated
control system: 1) spent Claus catalyst, 2) Beavon sour condensate, 3) Stret-
ford solution purge, and 4) spent Beavon hydrolysis catalyst. The generation
rates of these secondary waste streams are also presented in Tables 4-18 and
4-19. Characteristics of these waste streams and applicable control techniques
are described in Sections 4.2.1.1, 4.3, 4.4, and Appendices A-6, A-7 and A-9.
Cost estimates for the Claus/Beavon integrated control system are summar-
ized in Table 4-20. The calculation bases for these cost estimates have been
described in Section 4.2.1.1. The capital investment costs for the Claus and
the Beavon system are both based on two parallel trains. The capital invest-
ment cost for the Claus plant is 28% higher than that for the Beavon plant.
However, the total annualized cost for the Claus plant is 65% lower than that
for the Beavon plant, primarily as a result of credits for steam generated by
the Claus plant. The total capital investment cost and the total annualized
cost for the integrated control system represent 1.5-1.7% and 1.2-1.3% of
the respective costs for the uncontrolled EDS base plant. On annual ized basis,
sulfur can be recovered at a cost of approximately $50/Mg.
4.2.1.6.2 Example 2 - Claus Bulk Sulfur Removal with SCOT Tail Gas Treatment
and Incineration
The Claus/SCOT/incineration integrated control system for treating the
combined acid gas is illustrated in Figure 4-2. The Claus plant for this
example is similar to the Claus plant in Example 1, except the Claus feed also
includes a recycle concentrated HLS stream from the SCOT plant. Incineration
of SCOT tail gas is a common practice to minimize odor problems arising from
the higher levels of residual HLS. In addition, incineration is also effective
in controlling any residual reduced nitrogen compounds, CO or hydrocarbon pre-
sent in the SCOT tail gas.
306
-------
TABLE 4-20. COSTS OF INTEGRATED CONTROL FOR COMBINED ACID GAS STREAM EMPLOYING CLAUS
BULK SULFUR REMOVAL AND BEAVON TAIL GAS TREATMENT
oo
o
Control
Option
Base Case
Claus
Beavon
Total
MFS Case
Claus
Beavon
Total
Capital
Total Cost,
$ Million
27.1
21.1
48.2
27.1
21.1
48.2
Investment Cost
% of
Base
Plant
0.85
0.66
1.51
0.94
0.73
1.67
Unit Cost,
$ Million per
Mg/hr Sulfur
Recovered or
Removed
0.97
14.4
1.63*
0.97
14.4
1.63*
Total Cost,
$ Million
3.0
8.5
11.5
3.0
8.6
11.6
Annual i
% of
Base
Plant
0.31
0.88
1.19
0.33
0.95
1.28
zed Cost
Unit Cost,
$/Mg
Sulfur Recovered
or Removed
13.6
735.8
49.3*
13.6
747.3
49.9*
Unit costs for the two control functions are not additive. The total unit cost per Mg/hr
sulfur was calculated by dividing the total capital investment cost by total Mg/hr
sulfur recovered. Similarly, the total unit cost per Mg sulfur was calculated by dividing
the total annualized cost by total Mg sulfur recovered in one year.
-------
SCOT RECYCLE GAS
uo
o
CD
ACID GAS FROM DEA
REGENERATOR
ACID GAS FROM SOUR WATER
STRIPPER/AMMONIA RECOVERY
FLASH GAS FROM PARTIAL
OXIDATION (MFS CASE ONLY)
^
— r
^
"
CLAUSBULK
SULFUR
REMOVAL
1
1
AIR |
t i
CLAUS
I r-vi l_ VJAAO ~
~
FUEL/
REDUCING ^
GAS
AIR ^
' 1
SCOT
SCOT TAIL
GAS
TREATMENT
^
FUEL GAS ^
AIR ^
INCINERATION
WITH WASTE
HEAT
RECOVERY
INCINERATED
GAS TO
ATMOSPHERE
1
1
1
r +
SPENT SULFUR SOUR SPENT
CATALYST
CONDENSATE CATALYST
FUNCTION 1
FUNCTION 2
FUNCTION 3
Figure 4-2. Example 2 - Glaus bulk sulfur removal with SCOT tail gas treatment and incineration
-------
Air Source Type 1
Integrated Control
Examples
Material flow estimates and performance of the Claus/SCOT/incineration
integrated control system are presented in Tables 4-21 and 4-22 for the base
case and MFS case designs, respectively. The stream names used in these tables
are those shown in Figure 4-2. Assumptions used for Claus/SCOT/incinerat^on
performance included: 1) 95% sulfur removal in the Claus plant; 2) less than
250 ppmv total sulfur in SCOT off-gas prior to incineration; 3) incineration
at 978°K (1300°F) with 20% excess air, with essentially complete conversion
of residual H^S in SCOT off-gas to SO-. Because of the presence of H^S in
the SCOT recycle gas stream, the Claus tail gases in this example are generated
at a higher rate than the Claus tail gases in Example 1. Total sulfur (S0?
equivalent) levels in the Claus tail gas are 12,920 ppmv and 11,110 ppmv for
the base case and MFS case designs, respectively. Total sulfur emissions
through the SCOT off-gas were estimated to be less than 0.89 kmol/hr and less
than 0.93 kmol/hr for the base case and MFS case designs. These are equivalent
to approximately 99.9% total sulfur removal from the Claus/SCOT system. Sulfur
emissions (in the form of $02) through the incinerated SCOT off-gas are slightly
higher because of the presence of sulfur (80 ppmv COS and 3 ppmv H?S) in the
low-Btu fuel gas. Concentration levels of S0? in the incinerated SCOT off-gas
were estimated to be less than 140 ppmv. Residual CO and organics, if present
in the SCOT off-gas, would typically be reduced to concentration levels of 10-
100 ppmv and 5-20 ppmv respectively in the incinerated gas (Appendix A-16).
There are three secondary waste streams from the Claus/SCOT/incineration
integrated control system: 1) spent Claus catalyst, 2) SCOT sour condensate,
and 3) spent SCOT hydrolysis catalyst. The generation rates of these secon-
dary waste streams are also presented in Tables 4-21 and 4-22. Characteristics
of these waste streams and applicable control techniques are described in
Sections 4.2.1.1, 4.3, 4.4 and Appendices A-6 and A-8.
309
-------
TABLE 4-21. MATERIAL FLOW ESTIMATES AND PERFORMANCE OF INTEGRATED CONTROL
FOR COMBINED ACID GAS STREAM EMPLOYING CLAUS BULK SULFUR
REMOVAL WITH SCOT TAIL GAS TREATMENT AND INCINERATION (ILLINOIS
COAL BASE CASE)
Stream Description/
Control Option
Component
Flow Rate
Concentration
Combined Acid Gas
SCOT Recycle Gas
Claus Tail Gas
Spent Claus Catalyst
Incinerated SCOT Off-Gas
SCOT Sour Condensate
Spent SCOT Catalyst
H2S
NH3
COS
Total
H2S
C02
H20
Total
S02
COS
Total
Bauxite/
Alumina
Sulfur Recovered in Claus Plant Sulfur
SCOT Off-Gas
COS
Total
Total
Sour Water
Cobalt-
Molybdate
921.7 kmol/hr
49.5 kmol/hr
0.45 kmol/hr
1477.2 kmol/hr
48.3 kmol/hr
206.6 kmol/hr
30.2 kmol/hr
285.1 kmol/hr
29.1 kmol/hr
14.6 kmol/hr
4.4 kmol/hr
0.49 kmol/hr
3795.9 kmol/hr
46 Mg/yr
29.5 Mg/hr
<0.63 kmol/hr
<0.16 kmol/hr
3151.6 kmol/hr
<0.92 kmol/hr
6574.3 kmol/hr
18.8 m3/hr
12 Mg/yr
62.40 vol %
3.35 vol %
0.03 vol %
16.94 vol %
72.46 vol %
10.60 vol %
7674 ppmv
3838 ppmv
1151 ppmv
129 ppmv
<200 ppmv
<50 ppmv
<140 ppmv
310
-------
TABLE 4-22. MATERIAL FLOW ESTIMATES AND PERFORMANCE OF INTEGRATED CONTROL FOR
COMBINED ACID GAS STREAM EMPLOYING CLAUS BULK SULFUR REMOVAL WITH
SCOT TAIL GAS TREATMENT AND INCINERATION (ILLINOIS COAL MFS CASE)
Stream Description/
Control Option
Combined Acid Gas
SCOT Recycle Gas
Claus Tail Gas
Spent Claus Catalyst
Sulfur Recovered in Claus Plant
SCOT Off-Gas
Incinerated Off-Gas
SCOT Sour Condensate
Spent SCOT Catalyst
Component
H2S
NH3
COS
Total
H2S
C02
H20
Total
H2S
C02
COS
CS2
Total
Bauxite/
Alumina
Sulfur
H2S
COS
Total
S02
Total
Sour Water
Cobalt-
Molybdate
Flow Rate
920.5 kmol/hr
63.8 kmol/hr
0.75 kmol/hr
1702.6 kmol/hr
48.1 kmol/hr
270.2 kmol/hr
37.7 kmol/hr
356.0 kmol/hr
29.1 kmol/hr
14.5 kmol/hr
4.4 kmol/hr
0.48 kmol/hr
4405.6 kmol/hr
53 Mg/yr
29.5 Mg/yr
<0.74 kmol/hr
<0.19 kmol/hr
3707.8 kmol/hr
<1.09 kmol/hr
7734.5 kmol/hr
20.3 m3/hr
12 Mg/yr
Concentration
54.07 vol %
3.75 vol %
0.044 vol %
13.51 vol %
75.91 vol %
10.58 vol %
6601 ppmv
3300 ppmv
990 ppmv
109 ppmv
<200 ppmv
<50 ppmv
<140 ppmv
311
-------
Air Source Type 1
Integrated Control
Examples
Cost estimates for the Claus/SCOT/incineration integrated control system
are summarized in Table 4-23. The calculation bases for these cost estimates
have been described in Section 4.2.1.1. However, the costs for the Claus plant
are slightly different from those presented in Section 4.2.1.1, because more
sulfur is processed in this example as a result of the recycle gas from SCOT.
The capital investment costs are based on two parallel trains. Of the total
capital investment cost for the integrated control system, approximately 56%
are incurred by the Claus plant, 37% by the SCOT plant, and 7% by incineration
with waste heat recovery. On annualized cost basis, however, the relative
contributions are approximately 18%, 50%, and 32% for Claus, SCOT, and incin-
eration with waste heat recovery. The total capital investment cost and the
total annualized cost for the integrated control system represent 1.5 - 1.8%
and 1.6 - 1.9% of the respective costs for the uncontrolled EDS base plant.
On annualized basis, sulfur can be recovered at a cost of $67-74/Mg.
4.2.1.6.3 Example 3 - Claus Bulk Sulfur Removal with Wellman-Lord Tail
Gas Treatment
The Claus/Wellman-Lord integrated control system for treating the combined
acid gas is illustrated in Figure 4-3. Unlike the Beavon or SCOT process, in-
cineration of the Claus tail gas prior to SOp removal by absorption is an inte-
gral part of the Wellman-Lord. Thus, the heating value and the sulfur content
of the fuel gas used for incineration have a direct impact on the performance
of the Wellman-Lord plant. A concentrated SO- stream from the Wellman-Lord
regenerator is recycled to the Claus plant for sulfur recovery.
Material flow estimates and performance of the Claus/Wellman-Lord inte-
grated control system are presented in Tables 4-24 and 4-25 for the base case
and MFS case designs, respectively. The stream names used in these tables are
those shown in Figure 4-3. Assumptions used for Claus/Wellman-Lord performance
included: 1) 95% sulfur removal in the Claus plant; and 2) less than 150 ppmv
SOp in Wellman-Lord off-gas. Since the Wellman-Lord recycle gas contains S0?,
312
-------
TABLE 4-23. COSTS OF INTEGRATED CONTROL FOR COMBINED ACID GAS STREAM EMPLOYING
CLAUS BULK SULFUR REMOVAL WITH SCOT TAIL GAS TREATMENT AND
INCINERATION
w
Control Option
Base Case
Claus
SCOT
Incineration with
Waste Heat Recovery
Total
MFS Case
Claus
SCOT
Incineration with
Waste Heat Recovery
Total
Capital
Total % of
Cost, Base
$ Million Plant
28.0 0.88
18.4 0.58
3.2 0.10
49.6 1.56
27.9 0.97
18.4 0.64
3.5 0.12
49.8 1.73
Investment Cost
Unit Cost, '
$ Million
0.95 per Mg/hr sulfur
recovered
11.9 per Mg/hr sulfur
removed
1.0 per Mmol/hr
SCOT tail gas
1.68 per Mg/hr
sulfur recovered*
0.94 per Mg/hr sulfur
recovered
11.9 per Mg/hr sulfur
removed
0.94 per Mmol/hr
SCOT tail gas
1.69 per Mg/hr sulfur
recovered*
Annualized Cost
Total
Cost,
$ Million
3.0
7.9
4.7
15.6
3.0
8.5
5.5
17.0
% of
Base
Plant
0.32
0.82
0.49
1.63
0.34
0.94
0.61
1.89
Unit Cost,
$
13.1/Mg sulfur recovered
648.3/Mg sulfur removed
190.0/Mmol SCOT tail gas
gas
67.3/Mg sulfur recovered*
13.1/Mg sulfur recovered
702.5/Mg sulfur removed
188.3/Wmol SCOT tall gas
73.4/Mg sulfur recovered*
Unit costs for the three control functions are not additive. See footnote for Tible 4-20.
-------
WELLMAN-LORD RECYCLE GAS
ACID GAS FROM
fe.
ACID GAS FROM SOUR WATER k
STRIPPER/AMMONIA RECOVERY W
n AIII HA*? rnnh/i . , ^
PARTIAL OXIDATION
(MFS CASE ONLY)
A
w
R
^
CLAUS BULK
SULFUR REMOVAL
CLAUS TAIL GAS
AIR ^
WELLMAN-LORD
TAIL GAS TREATMENT*
i 1 \
T T SOUR
SPENT SULFUR CONDENSATE
CATALYST V
WELLMAN-LORD
•TAIL GAS TO
ATMOSPHERE
CO
-p*
FUNCTION 1
THIOSU LF ATE/SU L F ATE
PURGE
FUNCTION 2
•INCINERATION is AN INTEGRAL PART
OF THE WELLMAN-LORD TAIL GAS
TREATMENT PROCESS
Figure 4-3. Example 3 - Glaus bulk sulfur removal with Wellman-Lord tail gas treatment
-------
TABLE 4-24. MATERIAL FLOW ESTIMATES AND PERFORMANCE OF INTEGRATED CONTROL FOR
COMBINED ACID GAS STREAM EMPLOYING CLAUS BULK SULFUR REMOVAL WITH
WELLMAN-LORD TAIL GAS TREATMENT (ILLINOIS COAL BASE CASE)
Stream Description/
Control Option
Combined Acid Gas
We 11 man-Lord Recycle Gas
Claus Tail Gas
Spent Claus Catalyst
Sulfur Recovered in Claus Plant
Wellman-Lord Off-Gas
Thiosulfate/Sulfate Purge
Wellman-Lord Acidic Wastewater
Component
H2S
NH3
COS
Total
S02
H20
Total
H2S
S02
COS
CS2
Total
Bauxite/
Alumina
Sulfur
S02
Total
Na2 SOs
Nag S205
Na2 S04'
Na2 S203
H20
Total
Acidic
Wastewater
Flow Rate
921.7 kmol/hr
49.5 kmol/hr
0.45 kmol/hr
1477.2 kmol/hr
45.4 kmol/hr
24.0 kmol/hr
69.4 kmol/hr
28.7 kmol/hr
14.4 kmol/hr
4.3 kmol/hr
0.48 kmol/hr
3267.4 kmol/hr
39 Mg/yr
29.5 Mg/hr
<1.40 kmol/hr
9322.6 kmol/hr
130.2 kg/hr
56.8 kg/hr
31.4 kg/hr
3.4 kg/hr
91.8 kg/hr
313.6 kg/hr
67. 6 m3/hr
Concentration
62.40 vol %
3.35 vol %
0.03 vol 5
65.39 vol %
34.61 vol %
8796 ppmv
4398 ppmv
1319 ppmv
147 ppmv
<150 ppmv
41.5 wt %
18.1 wt %
10.0 wt %
1.1 wt %
29.2 wt %
315
-------
TABLE 4-25. MATERIAL FLOW ESTIMATES AND PERFORMANCE OF INTEGRATED CONTROL FOR
COMBINED ACID GAS STREAM EMPLOYING CLAUS BULK SULFUR REMOVAL WITH
WELLMAN-LORD TAIL GAS TREATMENT (ILLINOIS COAL MFS CASE)
Stream Description/
Control Function
Combined Acid Gas
Wellman-Lord Recycle Gas
Claus Tail Gas
Spent Claus Catalyst
Sulfur Recovered in Claus Plant
Wellman-Lord Off-Gas
Thiosulfate/Sulfate Purge
Wellman-Lord Acidic Wastewater
Component
H2S
NH3
COS
Total
SO?
H20
Total
H2S
S02
COS
CS2
Total
Bauxi te/
Alumina
Sulfur
SOe
Total
Na2 SOs
Na2S205
Na2 S04
Na2S203
H20
Total
Acidic
Wastewater
Flow Rate
920.5 kmol/hr
63.8 kmol/hr
0.75 kmol/hr
1702.6 kmol/hr
45.2 kmol/hr
23.9 kmol/hr
69.1 kmol/hr
28.7 kmol/hr
14.4 kmol/hr
4.3 kmol/hr
0.48 kmol/hr
3777.3 kmol/hr
46 Mg/yr
29.4 Mg/hr
<1.63 kmol/hr
10,875.8 kmol/hr
130.0 kg/hr
56.7 kg/hr
31.3 kg/hr
3.4 kgh/r
91.9 kg/hr
313.3 kg/hr
76.5 m3/hr
Concentration
54.07 vol %
3.75 vol %
0.044 vol %
65.39 vol %
34.61 vol %
7598 ppmv
3799 ppmv
1141 ppmv
127 ppmv
<150 ppmv
41.5 wt %
18.1 wt %
10.0 wt %
1.1 wt %
29.2 wt %
316
-------
Air Source Type 1
Integrated Control
Examples
less than one-third of the H,,S in the combined acid gas needs to be combusted
to S0? for subsequent sulfur formation. Thus, less air is needed for combus-
tion, and the Claus tail gases in this example are generated at a lower rate
than the Claus tail gases in Examples 1 and 2. Total sulfur (S02 equivalent)
levels in the Claus tail gas are 14,810 ppmv and 12,790 ppmv for the base case
and MFS case designs, respectively. The Claus tail gas is incinerated with a
o
low-Btu fuel gas which has a heating value of 4.7 MJ/Nm (125 Btu/SCF, dry
basis) and contains 83 ppmv reduced sulfur compounds. Total sulfur emitted
through the Wellman-Lord off-gas was estimated to be less than 1.40 kmol/hr
and less than 1.63 kmol/hr for the base case and MFS case designs. These are
equivalent to greater than 99.8% total sulfur removal from the Claus/Wellman-
Lord integrated control system. Higher sulfur removal efficiencies can be
achieved if a higher heating value fuel gas is used for incineration, because
total sulfur mass emissions in the Wellman-Lord off-gas (assumed to be less
than 150 ppmv) are directly proportional to the flow rate of the off-gas.
There are three secondary waste streams from the Claus/Wellman-Lord inte-
grated control system: 1) spent Claus catalyst, 2) thiosulfate/sulfate purge,
and 3) acidic wastewater. The generation rates of these secondary waste streams
are presented in Tables 4-24 and 4-25. Characteristics of these waste streams
and applicable control techniques are described in Sections 4.2.1.1, 4.3, and
4.4, and Appendices A-6 and A-10.
Cost estimates for the Claus/Wellman-Lord integrated control system are
summarized in Table 4-26. The calculation bases for these estimates have been
described in Section 4.2.1.1. However, the costs for the Claus plant are
slightly different from those presented in Section 4.2.1.1, because more sulfur
is processed in this example as a result of the recycle gas from Wellman-Lord.
The capital investment costs are based on two parallel Claus units, two parallel
Wellman-Lord incinerator-absorber units, and one Wellman-Lord regenerator.
The total capital investment cost and the total annualized cost for the integra-
ted control system represent approximately 1.9 - 2.2% and 1.4 - 1.7% of the
317
-------
TABLE 4-26. COSTS OF INTEGRATED CONTROL FOR COMBINED ACID GAS STREAM EMPLOYING CLAUS BULK SULFUR
REMOVAL WITH WELLMAN-LORD TAIL GAS TREATMENT
CO
_j
CQ
Base Case
Claus
We11 man-Lord
Total
Capital Investment Cost
Annual ized Cost
Control
Option
Total
Cost,
$ Million
% of
Base
Plant
Unit
Cost,
$ Million per
Mg/hr
Recovered
Sulfur
or Removed
Total
Cost,
$ Million
% of
Base
Plant
Unit
$/Mg
Recovered
Cost,
Sulfur
or Removed
27.9
33.8
61.7
0.88
1.06
1.94
0.95
22.2
2.09*
3.0
11.1
14.1
0.32
1.15
1.47
13.1
926.8
60.9*
MFS Case
Claus
Wellman-Lord
Total
27.9
33.8
61.7
0.97
1.17
2.14
0.95
22.4
2.10*
3.0
11.8
14.8
0.34
1.30
1.64
13.1
990.0
63.9*
Unit costs for the two control functions are not additive. See footnote for Table 4-20.
-------
Air Source Type 1
Integrated Control
Examples
respective costs for the uncontrolled EDS base plant. On annualized basis,
sulfur can be recovered at a cost of $61-64/Mg with the Claus/Wellman-Lord
integrated control system.
319
-------
Air Source Type 2
Combustion Gases
4.2.2 Source Type 2 - Combustion Gases
There are five gaseous waste streams under Source Type 2 for the base
case design, and six gaseous waste streams under Source Type 2 for the MFS
case design. These waste streams are:
• Stream 707a - flue gas from power generation system
• Stream 701 a - flue gas from steam generation system
• Stream 107 - flue gas from liquefaction slurry preheat furnace
• Stream 161 -flue gas from partial oxidation feed vacuum fractiona-
tor preheat furnace (MFS case only)
• Stream 203 - flue gas from solvent hydrogenation fuel preheat
furnaces
• Stream 434 - flue gas from hydrogen plant reformer furnaces
(base case only)
• Streams 449/450 - regeneration/decommissioning off-gas from high
and low temperature shift catalysts (MFS case only).
With the exception of Streams 449/450, these gaseous waste streams are gener-
ated by the combustion of coal and/or fuel gas. Streams 449/450 are included
under this source type because the characteristics of the combined stream are
very similar to those of flue gases from fuel combustion.
Combustion of fossil fuels produces a flue gas stream that contains S0p>
NO , and/or particulates. Sulfur dioxide is formed rapidly in the combustion
X
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 re-
moved from the exhaust gas.
The generation of NOV from air-fed fuel combustion processes occurs by
X
two separate mechanisms, namely thermal NO formation and fuel NO formation.
X X
Thermal NO results from the thermal fixation of molecular nitrogen and oxygen
X
in the combustion air and is sensitive to flame temperatures and to local con-
centrations of oxygen. Fuel NO is created from the oxidation of organically-
X
320
-------
Air Source Type 2
Combustion Gases
bound nitrogen in the fuel being combusted. Fuel NO formation is strongly
/\
affected by the rate of mixing of the fuel and air and by the local oxygen
concentration. Approximately 95% of oxides of nitrogen from combustion are
emitted as NO, about 5% are emitted as N02, and trace quantities are emitted
as other nitrogen oxides.
The particulates generated during combustion result mainly from the ash
content of the fuel. The partition of ash emissions between fly ash in the
flue gas and bottom ash is a function of combustion unit design. Particulate
emissions from combustion of gaseous or oil-based fuels are significantly
less than for combustion of coal.
Approaches to treatment of gaseous waste streams under Source Type 2 may
involve up to three control functions:
1) NO control
A
2) Particulate removal
3) S02 removal
NO.. Control
"X
NO pollution control techniques are of two types: 1) those that limit
A
nitrogen conversion to NO by modifying combustion characteristics and 2) flue
A
gas treatment techniques.
Combustion modification techniques are the most widely used techniques.
They can achieve from 25 to 60% reduction in NO emissions. Some of the com-
A
mon combustion modification techniques are: 1) low excess air, 2) staged com-
bustion, 3) flue gas recirculation, 4) reduced load, 5) low NO burners, and
A
6) ammonia injection. The key features and unit costs of these techniques are
discussed in Table 4-27.
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
J\
reduced to the minimum amount required for complete combustion, while main-
taining acceptable furnace cleanliness, and steam temperature. With less
321
-------
TABLE 4-27. COMBUSTION MODIFICATION TECHNIQUES FOR NOX CONTROL
Control
Technique
Low Excess Air
(LEA)
Description
of
Technique
Combustion air is reduced
to the minimum amount re-
quired for complete com-
bustion while maintaining
proper stream temperature.
Efficiency
(as % NOX
Reduction)
0-25
5 - 25
Type of
Fuel Fired
Pulverized coal
Stoker coal
Range of
Application
Excess 02 lowered to
5.2% on the average.
Excess Q£ limited to
5-6°= minimum.
0-28 Residual oil
0-24 Distillate oil
5-35 Natural gas
Excess 02 can be
reduced to <3=:.
Excess 02 can be
reduced to <3%.
CO
ro
ro
Staged Combustion
Overfire Air
Injection (OFA)
Staged
Combustion Air
(LEA + OFA)
Injection of air above the 5-30
top burner level through
OFA ports together with a
reduction in air flow to
the burners (staged com-
bustion) .
Reduction of under grate 5-25
air flow and increase of
overfire air flow.
Fuel rich firing burners 20 - 50
with secondary combustion 17 - 44
air ports.
Injection of secondary 5-46
air downstream of the
burner(s) in the direction
of the flue gas path.
Pulverized coal
Stoker coal
Residual oil
Distillate oi1
Natural gas
Burner 02 can be as
low as stoichiontetric
Excess 02 limited to
5% minimuir.
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 4-27. (CONTINUED)
Control
Technique
Stage of
Development
Secondary Haste
Cost
Limitations and Comments
Low Excess Air
(LEA)
CO
ro
CO
Staged Combustion
Overfire Air
Injection (OFA)
Staged
Combustion
Air (LEA + OFA)
Available but implemented
on a limited basis only
Available now but need
R&D on lower limit of
air
Available
Available
None
None
None
None
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
Capital: * $440 to $550/MW heat input
Operating: 0 to 8 mills/103 kg steam
Capital: S600 to $1850/MU heat input
Operating: 13 to 57 mills/103 kg steam
Capital: $460 to $2400/MW of heat
input
Operating: <83 mills/103 kg steam
Capital: $580/MW of heat input
Operating:
Capital: $800 to $940/MW heat input
Operating: 80 to 85 mills/103 kg steam
Capital: $600 to $800/MW heat input
Operating: 24 to 32 mills/103 kg steam
Capital: $870 to $5150/MH of heat
input
Operating: 123 to 370 mills/103 kg
steam
Capital: $1070/HW of heat input
Operating: 117 mills/10J kg steam
Limited by increase in CO,
HC and particulate emis-
sions. Increase in boiler
efficiency may be achieved
as a benefit
Danger of overheating grate,
clinker formation, corrosion
and high CO emissions
Added benefits included in-
crease in boiler efficiency.
Limited by increase in CO,
HC and TSP emissions.
Generally practical because
of increase 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.
Capital costs presented In this table are total process costs (TPC; and do not Include interest
during construction.
(ContTnuedT
-------
TABLE 4-27. (CONTINUED)
Control
Technique
Description
of
Technique
Efficiency
(as % NOX
Reduction)
Type
of
Fuel Fired
Range of
Appl i cation
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.
CO
ro
-p.
27 - 39
0 - 20
15-30
58 - 73
- 86
Reduced Load
Reduction of fuel and
air flow to the burner.
Up to 45%
Average 15%
Pulverized coal
Pulverized coal
Residual oil
Distillate oil
Natural gas
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%.
(ContinuedT
-------
TABLE 4-27,
(CONTINUED)
Control
Technique
Staged Combustion
Air and Fuel
Rich Firing
Flue Gas
Recirculation
ro
en
Reduced Load
Stage of
Development
Secondary Waste
Costs
Limitations and Comments
Available, but engineering
refinement is needed prior
to implementation
Not offered because the
method is comparatively
ineffective
None
Not available
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 15150/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
Load reduction required in
most cases. Possible in-
creased slagging and corro-
sion. New boiler design
will incorporate the re-
quired number of burners.
Flue gas recirculation
lowers the bulk furnace gas
temperatures and reduces 02
concentration in the com-
bustion zone. Requires in-
stallation of flue gas re-
circulation ducts, fans,
etc. Many cause combustion
instability.
Best wuited for new units.
Costly to retrofit. Possible
flame instability at high
FGR rates.
Flame instability problem
1s 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 02-
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 4-27. (CONTINUED)
CO
ro
CTi
Description Efficiency
Control of (as % Type of
Technique Technique NOX 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
NHg 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
NO ~ 1>5
Applicable for large
package and field-erected
watertube boilers
Not feasible for firetube
boilers
* Increase in NO is a surprising result indicated by limited
due to higher Sir/fuel ratio under reduced load conditions.
need confirmation.
test data, possibly
These results will
(Continued)
-------
TABLE 4-27. (CONTINUED)
Control
Technique
Type of
Fuel Fired
Stage of
Development
Secondary
Waste
Costs
Limitations and Comments
Reduced Load
Low NO Burners
Residual Oil
Distillate Oil
Natural Gas
Pulverized
Coal
Available now as a retrofit
application. Better imple-
mentation with improved
firebox design.
Technique available. How-
ever, retrofit application
is not feasible due to
initial low load factor of
industrial units.
Development stage prototypes
are available from major
boiler manufacturers.
None
Not Available
None
None
Not Available
Capital: S800 to S940/MW of heat
input
Operating- 80 to 85 mills/103 kg
steam
CO
ro
Residual Oil Commercially offered but
Distillate Oil not demonstrated.
Injection
Natural Gas
Pulverized
Coal
Commercially offered but
not demonstrated.
Commercially offered but
not demonstrated.
None
None
Ammonium
Bisulfate
Capital: S860 to S5150/MW of heat
input
Operating: 123 to 375 mills/103 kg
steam
Capital- S860 to S1070/MW of heat
input ,
Operating: 106 to 117 mills/10 kg
steam
Capital. S4800/MW of heat input
Operating 247 mills/103 kg steam
Residual Oil Commercially offered but
Distillate Oil not demonstrated.
Ammonium
Bisulfate
Capital: $4940 to $9770/MW of
heat input
Operating: 266 to 433 mills/103 kg
of steam
Not available for natural gas
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).
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 03 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.
Data source: Reference 46 and 47,
-------
Air Source Type 2
Combustion Gases
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 Np. 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 per-
formance and applicability are provided in Table 4-27.
Flue gas recirculation consists of recycling a portion of the flue gas
back to the primary combustion zone. This reduces NO formation by lowering
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 NO emissions. Thermal NO forma-
x x
tion generally increases as the volumetric heat release rate or combustion in-
tensity increases. Reduced combustion intensity can be brough about by load
reduction by either derating the boiler or using an enlarge firebox.
Low NOX burners have been developed primarily for reducing NO emissions
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.
A
The process of injecting ammonia was developed by Exxon Research and
Engineering Company under the trade name of Thermal DeNO . This technique
/\
acts by reducing NO to elemental nitrogen and oxygen with NH_ at flue gas
temperatures ranging from approximately 1070 to 1290°K. However, optimal NO
reduction occurs over a very narrow temperature range, around 1240 +_ 50°K.
The cost of combustion modification techniques for controlling NOV emis-
> /\
sions depend upon: 1) the additional hardware required, and 2) any changes in
328
-------
Air Source Type 2
Combustion Gases
operational procedures that may increase the cost of steam production. Cost
estimates for combustion modification techniques are provided in Table 4-27.
Flue gas treatment techniques have been proposed for control of NOX emis-
sions to levels significantly below those achievable by combustion modifica-
tion techniques. Although large scale flue gas treatment schemes have not
been proved commercially in the U.S., these techniques are being applied in
Japan. The key features of some of these processes are provided in Table 4-28.
Of the processes listed in Table 4-28, the Selective Catalytic Reduction
(SCR) system, using ammonia to react with NO is perhaps the most promising.
/\
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 advances
have been made; however, some significant technical/economic questions must be
answered before widespread application of SCR units can occur. At this time,
flue-gas treatment techniques are not commercially utilized in the U.S. Control
techniques for nitrogen oxides are further discussed in Appendix A-21.
Particulate Removal
The choice of the particulate collection equipment depends upon a number
of factors: the properties of the particulate such as particle size distribu-
tion and resistivity; the concentration and volume of the particulate to be
handled; the temperature, humidity and chemical composition 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) electrostatic preci-
pitators. The key features and unit costs of these collection devices are pre-
sented in Table 4-29. In addition, there are other particulate control devices
which use a combination of the above approaches. However, these are not address-
ed here.
329
-------
TABLE 4-28.
NOV FLUE GAS TREATMENT CONTROL ALTERNATIVES FOR BOILERS
X
Control
Technique
Description
of
Technique
Principle
of
Operation
Efficiency
(% as NOX
Reduction)
Applicability
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.
- Moving
Reactors
Bed
OJ
U)
CD
- 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 wi11
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 4-28. (CONTINUED)
Control
Technique
SCR - Fixed
Packed Bed
Reactors
SCR - Moving
Bed Reactors
Co
CO
SCR - Parallel
Flow Reactor
Absorption-
Oxidation
SCR - NOX/SOX
Removal
Stage of
Development
Secondary Hastes
Costs
-imitations 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
N03 salts in
wastewater
No continuous coal-
fired NOX removal
test data for NOX/
SOX systems are
available.
Spent catalyst
20MW estimate:
Capital: * $155/kW (coal)
$84/kW (oil)
S32/kW (gas)
Operating: 2.5mills/kWh (coal)
2.3 mills/kWh (oil)
1.4 mills/kWh (gas)
20MW estimate:
Capital: S110/kW (coal)
S84/kW (oil)
Operating: 2.4 mills/kWh (coal)
2.5 mills/kWh (oil)
20MW estimate:
Capital: S53/kW (coal)
S46/kW (oil)
Operating: 1.8mills/kWh (coal)
20MW estimate
Capital: S597/kW (coal
Operating: 9.6mills/kUh (coal)
20MW estimates
Capital: $567/kW (coal & oil)
Operating: 6 mills/kWh (coal
& oil)
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 NH3 downstream can
react with SO^ or $03 to
form ammonium bisulfate or
the NH3 could enter FGD and
ESP equipment.
The presence of particulates
requires a prescrubber.
The presence of S02 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)
* Csp'.tal costs presented in this title are total process costs (TPC) and dc not Include Interest
during construction.
-------
TABLE 4-28. (CONTINUED)
Control
Technique
Description
of
Technique
Principle
of
Operation
Efficiency
(% as
NOX Reduction)
Applicability
Adsorption Adsorbed NOX is reduced
N0x/S0v to N? while S02 is re-
RemovaT duced and condensed to
elemental S
The adsorption process
removes NOX and S02
from flue gas by
absorbing them onto
a special activated
char
40-60% NOX
reduction, 80-
95% SOX reduc-
tion
May be applicable
to handle coal
GO
CO
ro
Electron Beam
Radiation
N0x/S0x
Removal
A dry process that
utilizes an electron
beam to bombard the
flue gas, thereby
removing NOX and SOo
Flue gas is taken from
the boiler air pre-
heater and passed
through a cold ESP tp
remove particulate.
NH3 is added and the
gas is then bombarded
with an electron beam.
Removal effici-
ency will de-
crease as NOX
and S02 increase
By-product treatment
technology needs to
be more fully devel-
oped 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, 90% S02
reduction
90% NOX reduction,
95% S02 reduction
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 4-28. (CONTINUED)
Control
Technique
Stage of
Development
Secondary Wastes
Costs
Limitations and Comments
CO
OJ
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 NH§ based com-
pounds in waste-
water
NOs 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: 7.6mills/kWh
Not available
Very complex process. Numerous
process steps involve hot
solids handling with numerous
mechanical problems possible.
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 .
Data source: Reference 48.
-------
TABLE 4-29. KEY FEATURES OF PARTICULATE COLLECTION EQUIPMENT
CO
CO
Control
Device
Cycl one
Fabric filter
(Baghouse)
Venturi
Scrubber
Electrostatic
Precipitator
Operating Principle
Participates removed from gas
stream by imparting a centri-
fugal force. The Inertia of
to the walls where they fall
to the bottom of the cyclone
for removal.
Fabric filter material is
arranged in a tubular shape
with the participate 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.
or by a pulsed jet.
Removal of participates from
a gas stream by intimate con-
contact with scrubbing water
and droplets. Agglomerated
participates are subsequently
removed 1n i centrifugal
and/or mist eliminator.
A negative electrical charge
is imparted to the particu-
lates and they are collected
on positively charged plates.
Collected material is removed
hy periodically rapping or
vibrating the collection
plates.
Inlet
Removal Loading
Efficiency Range Limitation
(weight %) (g/Nm3)
50 to 80% for >5 .m. >2.4
80 to 95% for 5 to
20 un.
98.5 to 99.51 for >0 24
0.25 to 0.5 i-m.
99 to 99.5% for
0.75 to 1 urn.
99.5 to 99.9% for
3 ^m.
99.95% for 3 urn.
50 to 92.5% for >0.5
0.25 urn.
60 to 98% for
0.5 urn,
70 to 99% for
0.75 ^m.
90 to 99.6% for
3 urn.
90 to 99% for 0.24
0.1 um.
80 to 96% for
0.5 MHI.
95 to 99% for
! ^.
99 to 99.91 for
5 ym.
Normal
Pressure
Drop Range Reliability
(cm H_0) or Other Limitations
7 to 20 Cannot effectively remove
particulates smaller than
5 um.
5 to 25 Plugging problems will
result if condensation
occurs on filter media or
if hygroscooic-matenal is
collected. Temperature
limit varies with type of
filter media used, maximum
is 560 K.
13 to 250 Reliability may be limited
by scaling, fouling, or
corros i on . Scrubbi ng
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
ticulates to be collected
must have suitable elec-
trical resistivity to
facilitate efficient re-
moval. Used in low pres-
sure applications. Limited
to gas streams with temper-
atures below 700 K.
Secondary
Waste
Collected
Collected
Scrubbing
liquor blow-
down and
wet slurry
Collected
particulates
Capital
Costs*
loading and size distribution, and
About $282/m /rain for total system.
and size distribution, gas stream
temperature, fabric material^nobe
of cleaning, and collection
efficiency specified.
About $250/m3/min Costs vary with
but ion, and collection efficiency
specified
About $250 to $530/m3/min. Costs
vary with particle loading and size
distribution, particle resistivity,
and collection efficiency specified.
General Consents
High reliability due to
simple operating prin-
ciple with no moving
parts. Low energy
requirements.
High participate removal
lation cost. Large scale
required.
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. SuitabTe
for high temperature or
large volume applications.
High electrical consump-
tion. Sensitive to parti -
*Cap1tal costs presented In this table are total process costs (TPC) and do not Include Interest during construction.
Data source: Reference 49
-------
Air Source Type 2
Combustion Gases
Cyclones are generally employed for the removal of bulk particulates
(usually greater than 5 microns in size) and, in many cases, precede other
control devices. The unit total process costs (TPC) of cyclones are relative-
o
ly low - approximately $212 per m /min. Cyclones for paniculate control are
further discussed in Appendix A-ll.
Baghouses have very high particulate removal efficiencies and can lend
themselves to applications involving small or intermittent gas flows (although
continuous operation is preferred). Baghouses, 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 573°K. The unit total process cost (TPC) for a typical baghouse
3
is about $300 per m /min. Fabric filters for particulate control are further
discussed in Appendix A-12.
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 (at high pressure drops and hence high operating costs).
In contrast to devices in which the particles are collected in dry form, ven-
turi scrubbers generate a wet slurry which is more voluminous and generally
more difficult to dispose of. The unit total process costs (TPC) for venturi
o
scrubbers are approximately $250 per m /min. Venturi scrubbers for particu-
late control are further discussed in Appendix A-14.
Electrostatic precipitators are high efficiency particulate removal de-
vices, have low pressure drops, are capable of handling large volumes of gases,
and can tolerate high feed gas temperatures (typically up to 700°K). Electro-
static precipitators, however, are not generally suitable for applications to
gases above atmospheric pressure and are not economical for treating small or
intermittent gas flows (such as those resulting from material handling dust
collection systems). The unit total process costs (TPC) range from $250 to
335
-------
Air Source Type 2
Combustion Gases
o
$530 per m/min. Electrostatic precipitators for particulate control are
further discussed in Appendix A-13.
SOg Removal
Several flue gas desulfurization (FGD) processes are commercially avail-
able. They are basically of three types: 1) throwaway systems which produce
a waste sludge by-product, 2) regenerable systems which produce a usable sulfur
by-product and regenerate the sorbent, and 3) dry scrubbing systems. Common
examples of throwaway systems are the lime/limestone system, double alkali
scrubbing, soda ash 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 4-30.
The lime/limestone scrubbers are the most commonly employed throwaway
systems for electric utility applications. In the lime/limestone process,
solid lime or limestone is pulverized and mixed with water to form a scrubber
liquor, which contacts the flue gas in an absorption tower where calcium sul-
fate and calcium sulfite are formed. The resulting slurry is removed from the
system and treated, and the sludge is disposed of. Scrubbing solution is re-
covered and recycled to the absorption tower. Lime/limestone removal effici-
encies can approach 90% by carefully balancing the many chemical-reaction
parameters involved. Out of the throwaway FGD systems available, lime/
limestone offers the least complex system and equipment, the easier pH control,
and the cheapest raw materials. Operating experience has indicated that care-
ful attention to system control is important for successful operation of lime/
limestone 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 evaporator where it is
336
-------
TABLE 4-30.
KEY FEATURES OF S02 REMOVAL PROCESSES
CO
CO
Process
Feature
Principle
Feed Stream
Requirements
Absorbent
Product/
Waste
Lime/Limestone
Scrubbing
Liquid phase absorption
of S0;> in lime or lime-
stone slurry.
t
Particulates can be re-
moved 1n 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 SOj
removal .
Slaked lime or 200-300
mesh limestone 6-12%
slurry circulated.
Gypsum can be produced
with forced oxidation.
Calcium sulfate/sul-
fite can be produced
with 50-70% solids
Double Alkali Scrubbing
Liquid phase absorption
of S0;> in a sodium
hydroxide, sodium sulfite.
sodium bisulfite, sodium
sulfate.and sodium carbon-
ate solution. Regenera-
tion of the sodium sul-
in a reactor. A dilute
centrations of 200-1500
ppm SO? and where less
than 25% oxidation of sul-
fite to sulfate occurs.
Concentrated mode can be
used for concentrations
of 1000-8000 ppB S02-
Excessive particulates
should be removed in an
ESP, fabric filter or
venturi. 02 should be
less than 7% for con-
centrated mode.
Sodium hydroxide, sodium
sulfite/bisulfite, and
a small amount of sodium
sulfate.
Filter cake with 60-70%
solids, primarily calcium
sulfite and calcium sul-
fate.
Chiyoda
Thoroughbred 121
Liquid absorption of SO^
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.
Limestone slurry.
Gypsum {CaSO^ZHoO) with
less than 20% moisture
content.
Uellman-Lord
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 )s then pro-
to produce elemental
acid plant
Particulates and chlo-
rides must be removed
from flue gas.
Concentrated sodium
sulfite/bisulfite.
Concentrated SO? purge
stream (90% $02*.
Dry Scrubbing
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-dry particulate
flue ash and reaction
product fron flue gas.
Inlet $0? concentration
should not exceed 1000
ppmv.
,
*
Lime slurry or sodium
carbonate solution.
Sodium sulflte-sodium
sulfate, calcium sulfite/
sulfate.
Fly Ash
Alkal inity Scrubbing
Process invol ves a two
stage venturi -spray tower
absorber utilizing the
fly ash alkal inity for
S02 removal. Hydrated
dolomitic lime, (Mg(OH)2
and Ca(OH)2) is also used
to achieve an outlet S02
of 43 ng/J.
Venturi 1s used to remove
particulates and a portion
of S02.
Fly ash alkalinity and
hydrated lime (calcium and
•agneslum hydroxide).
Sludge consists of fly ash,
gypsum (CaSOa-ZHjO) ,
Ng(OH)2, small amount of
calcium sulfite.
Efficiency
90? removal can be
obtained generally for
low and high sulfur
coals. Higher removals
can be obtained with
higher L/G and pressure
drop, and to some extent
scrubber type. 90% 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.
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
1n the dilute mode.
90% SOg removal or outlet
S02 equal to 300 ppmv
Process has been demon-
strated at Gulf Power's
Scholz station - 20MW
prototype.
Process has been demon-
strated in a NIPSCO 115MW
coal fired boiler. Can
remove up to 95% S02.
70% S02 removal using
lime as absorbent. 80%
S02 removal using sodium
absorbent.
85-90% removal of S02
commercially demonstrated
1n Montana Power's Colstrlp
142, 96+l expected in
Colstrlp units 3 & 4.
^Continued]
-------
TABLE 4-30. (CONTINUED)
CO
CO
oo
Process
Feature
Cost*
Advantages
Disadvantages
Mine/Limestone
Scrubbing
Capital - $90/kW to
J185/kH.
Loner capital cost and
OW costs S02 and
participates can be
removed sltnul taneously.
Relatively simple proc-
ess. Reliability 1s
90-95*.
Process produces approxi-
mately 3 times (by wt)
sludge as ash collected.
Sludge can be thixo-
troplc. Sludge quanti-
ties can be reduced by
forced oxidation.
Double Alkali Scrubbing
Capital - SlOl/kW to
t!63/kU.
Loner capital and OS*
costs. SOj can be
removed to very high
efficiencies (99?) .
Reliability Is 90-951.
Conventional process
equipment.
Process produces 1 5
times (by wt} filter
cake as collected ash.
316SS material of con-
struction may be re-
quired to prevent
corrosion and pitting
Chiyoda
Thoroughbred 121
Capital - $160/kW.
Capital and OW costs
appear to be competitive
but data limited to pro-
totype experience. Poten-
tial saleable gypsum by-
product
demonstrated conwercially
in a 100HW or larger unit.
Mellman-Lord
Capital - $138/kW to
$265/kW.
Comnercially demonstrated.
Process produces saleable
product sulfur with a
Claus unit or sulfuric
acid lower potential for
scaling than calcium
system.
compared to other systems.
Special metallurgy may be
required. System required
to process SO? to sulfur
or sulfuric acid.
Dry Scrubbing
C«o1tal - $23/kW to
$47/kW.
Lower projected
operating and capital
costs. Dry product.
commercially demon-
strated until late
1982. Product disposal
could be a problem
when sodium salts are
used as absorbent.
Fly Ash
Alkalinity Scrubbing
Not available.
Comnercially 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.
Data source: Reference <5.
* Capital costs included in this Uble ire total process costs (TPC) and do not
Include interest during construction.
-------
Air Source Type 2
Combustion Gases
indirectly heated by steam to convert the bisulfite to sulfite and gaseous S0?.
A portion of the sodium sulfite is also converted irreversibly to sodium sul-
fate and thiosulfate which must be purged from the system, requiring makeup
of NaOH or NaCO^. The Wellman-Lord process can achieve over 90% S00 removal.
3 c,
Dry scrubbing experience to date has been limited, although systems that
have been operated show much promise, especially for low- and medium-sulfur
coals. The spray drying process is the only dry scrubbing process 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 S02 and the slurry droplets. Simultaneously, the thermal energy of the gas
stream evaporates the water in the atomized droplets, to produce a dry, powder-
ed 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 re-
agent which is reused. In addition, unused reagent that cakes on the fabric
is available to react with more SCL as flue gas passes through it.
One type of FGD process not included in Table 4-30 is the sodium scrubbing
process. The sodium scrubbing process is capable of achieving high S0~ removal
efficiencies over a wide range of inlet S02 concentrations. The process con-
sumes a premium chemical such as Na^COo and produces a soluble waste salt con-
taining Na-SO^ and NaHSOo, which is normally discharged to a lined evaporation
pond for drying. Compared with other FGD processes, the sodium scrubbing pro-
cess is lower in capital investment cost and higher in operating cost because
of the simplicity in scrubber design and the expense of sodium chemicals. Based
on these considerations, the sodium scrubbing process might be suited for con-
trolling SOp emissions from intermittent gaseous waste streams. The capital
investment cost (TCI) for sodium scrubbing on a unit capacity basis is approx-
imately $415 per kmol/hr feed gas, based on a system that removes 90% of the SCL
contained in the flue gas from a 211 GJ (200 MM Btu) per hr industrial boiler
339
-------
Air Source Type 2
Combustion Gases
burning 3.5% sulfur coal (45).
FGD costs for boilers in synfuel plants will depend upon the amount of
sulfur emissions control required. This may vary depending upon the amount
of sulfur in the fuel. FGD cost data has been developed by the EPA for elec-
tric utility steam generating units ranging in size from 25 MWe 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 S0? limitations,
and 4) the level of control maintained. Capital investment and annual operat-
ing costs for lime/limestone and Wellman-Lord FGD systems are listed in Table
4-30. These costs are for a 500 MWe unit boiler burning 3.5% sulfur bitumi-
nous coal capable of achieving 90% removal.
FGD systems are further discussed in Appendix A-20.
340
-------
Air Source Type 2
Flue Gases from Steam
and Power Generation
System
4.2.2.1 Flue Gases from Steam and Power Generation Systems
(Streams 701 a and 70717
Fuel requirements for the steam generation systems are met by a combina-
tion of treated low-Btu fuel gas and coal in current Exxon designs. The op-
tion of burning untreated high-sulfur fuel gas in the steam boilers -- and
using an FGD system to remove the resulting SCL in the flue gas -- is not con-
sidered in the current Exxon design, and is not addressed in this manual. For
the base case design, total energy input to the steam boiler is 2.32 TJ
(2,199 MM Btu) per hour, 63.0% of which is provided by burning low-Btu fuel
gas (125 Btu/SCF, 83 ppmv sulfur) and 37.0% provided by burning coal (3.7%
sulfur, 7.6% ash) at 35.3 Mg/hr. For the MFS case design, total energy input
to the steam boiler is 3,95 TJ (3,740 MM Btu) per hour, 42.8% of which is pro-
vided by burning low-Btu fuel gas and 57.2% provided by burning coal at 92.8
Mg/hr. Flue gases from the steam boiler were estimated to be generated at a
rate of 42,560 kmol/hr and 69,150 kmol/hr for the base case and MFS case de-
signs, respectively.
Energy for the power generation system, on the other hand, is derived
from the combustion of coal alone. For the base case design, the power require-
ment of 223 MW is met by burning coal at a rate of 95.8 Mg/hr (2.33 TJ/hr).
For the MFS case design, the power requirement of 160 MW is met by burning
coal at 68.7 Mg/hr (1.67 TJ/hr). Compared with the steam boiler, flue gases
from the power boiler are generated at lower rates of 36,450 kmol/hr and 26,110
kmol/hr for the two EDS designs. However, emission concentrations of NOX,
particulate matter, and S02 are all significantly higher in the power boiler
flue gas because of the exclusive use of coal as combustion fuel.
In this section, pollution control alternatives applicable to the flue
gases from the steam and power boilers are examined. The control approach
involves all three functions described previously; NOX control, particulate
control, and SO- removal. The control of these pollutants from the steam and
341
-------
Air Source Type 2
Flue Gases from Steam
and Power Generation System
Control Function 1 -
NOX Control
power boilers in an EDS commercial plant is expected to present no unique pro-
blems over those encountered in the electric utility and other industries which
use boilers fired by coal and fuel gas.
4.2.2.1.1 Control Function 1 - NOW Control
- ' ' • "-— • '•""• ~""~A
As discussed earlier, NO 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 and gas—fired boilers this is achieved through
the application of a variety of combustion modification techniques (see Table
4-27) including low NO burners. Boiler manufacturers have regularly incorpor-
A
ated combustion modifications as standard equipment on new boilers since the
early 1970's. Accordingly, it is considered in this manual that the cost of
any new coal-fired or gas-fired boiler installed in an EDS plant will inher-
ently incorporate the cost of any NO combustion modifications that have been
A
incorporated into the boiler. No attempt is made here to separate out the
portion of the total cost which is attributable to NO control. For the pur-
X
poses of this manual, it is assumed that a well-designed coal-fired boiler with
suitable combustion modifications would be able to meet the current New Source
Performance Standard (NSPS) that applies to electric utility coal-fired boilers,
260 ng/J. The NO emission factor for low-Btu gas combustion is 52-99 ng/J
A
(Table 3-64), approximately the same as the 86 ng/J NSPS standard for utility
boilers burning gaseous fuel. It is assumed that a well-designed gas-fired
boiler would be able to operate in the 52-99 ng/J range. For the steam boiler,
these emission factors translate into total NO emissions of 297-366 kg/hr in
A
the base case, and 670-750 kg/hr in the MFS case. For the coal-fired power
boiler, NO emi
X
respectively.*
boiler, NO emissions for these two EDS designs would be 601 kg/hr and 431 kg/hr,
X
No~te: the use of the electricity utility NSPS in estimating NO emissions from
the EDS boilers is done here for illustrative purposes only, and is not
intended to suggest that EDS boilers would necessarily be required to
meet that standard.
342
-------
Air Source Type 2
Flue Gases from Steam and
Power Generation System
Control Function 2 -
Particulate Control
4.2.2.1.2 Control Function 2 - Particulate Control
Particulate loading in boiler flue gases is a function of many variables
such as the type(s) of fuel being fired, the ash content of the fuel and boiler
design. In pulverized coal-fired boilers, typically 60 to 90% of the ash in
the feed coal is emitted as fly ash, the remainder appearing as bottom ash.
For the steam boiler, uncontrolled emissions of particulate matter were esti-
mated to be 2,190 kg/hr and 5,740 kg/hr for the base case and MFS case designs,
respectively. Uncontrolled emissions of particulate matter from the power
boiler for these two EDS designs would be 5,930 kg/hr and 4,250 kg/hr.
Electrostatic precipitators (ESPs) or baghouses are commonly used for con-
trol of particulate emissions from coal-fired boilers. The use of these tech-
nologies has served to meet most state, local or federal performance standards
as well as any operational requirements for pollution control equipment em-
ployed downstream of these units. In utility applications ESPs are more widely
used than baghouses. Only the application of ESPs will be discussed here.
4.2.2.1.2.1 Control Technique 1 - Electrostatic Precipitators
Costs for ESPs are based upon the ESP effluent particulate loading desired
and the flue gas flow rate. Typically, to achieve an ESP outlet loading of 13
ng/J, ESP capital investment costs (TCI) are approximately $88.8/kw ($545 per
kmol/hr) for Illinois No. 6 coal. For an outlet loading of 43 ng/J, capital
investment costs (TCI) decrease to $70.0/kw ($428 per kmol/hr). These costs
were derived from the installed equipment costs (IEC) presented in Figure A
13-5 of Appendix A-13 for eastern high sulfur coal, by applying the methodology
outlined in Table 4-1 and adjusting to 1980. In achieving either one of these
emission levels, over 99% of the particulate matter will be collected by the
ESP for the power boiler. Collection efficiencies of the ESP for the steam
boiler at these two emission levels would be slightly lower because particulates
are generated at a lower rate from the combustion of a combination of coal and
fuel gas. Controlled emissions of particulate matter from the low-Btu gas- and
343
-------
Air Source Type 2
Flue Gases from Steam and
Power Generation System
Control Function 3 -
S02 Removal
and coal-fired steam boiler (2.32 TJ/hr for the base case, 3.95 TJ/hr for the
MFS case) at these two emission levels (13 ng/J and 43 ng/J) were estimated to
be 30-100 kg/hr and 51-170 kg/hr for the base case and MFS case designs,
respectively. Similarly, controlled emissions of particulate matter from the
coal-fired power boiler (2.33 TJ/hr for the base case, 1.67 TJ/hr for the MFS
case) at the same two emission levels would be 30-101 kg/hr and 22-72 kg/hr
for the two EDS designs.
Estimated capital investment costs and annualized costs for control of
particulate matter from steam and power boilers are presented in Table 4-31.
On annualized basis, the cost for particulate control with ESP would be $11 -
$14 per Mmol of flue gas.
Secondary Waste Stream
The fly ash collected is a secondary waste stream generated by the ESP.
For the steam boiler, the fly ash collected would amount to 16,740 Mg/yr and
44,420 Mg/yr for the base case and MFS case designs, respectively. For the
power boiler, the fly ash collected would amount to 46,240 Mg/yr and 33,120
Mg/yr for these two EDS designs. Concentrations of trace elements present in
the fly ash are similar to those found in the coal feed (Table 2-2), although
the levels of some of the more volatile elements (or elements associated with
volatile compounds) will be enriched (36). Disposal of this secondary waste
stream is addressed in Section 4.4.2.6.
4.2.2.1.3 Control Function 3 - S02 Removal
As discussed previously, a number of competitive FGD processes are capable
of achieving similar reductions. The limestone and Wellman-Lord FGD processes
are two of 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, and the degree of SO- removal desired. The limestone and the Wellman-
Lord FGD processes are discussed here.
344
-------
TABLE 4-31 . COSTS OF PARTICULATE CONTROL WITH
ELECTROSTATIC PRECIPITATORS FOR FLUE
GASES FROM STEAM AND POWER GENERATION
SYSTEMS (STREAMS 701 a and 707a)
Base Case
Cost Element
Total
Capital
Investment*
Total
Annualized
Costt
Total
Capital
Investment*
MFS Case
Total
Annualized
Costt
Steam Boiler (701a)
Total Cost,
$ million
% of Base Plant
Unit Cost
Power Boiler (707a)
Total Cost,
$ million
% Base Plant
18.2-23.2
0.57-0.73
$428-545 per
kmol/hr flue
gas
15.6-19.8
0.49-0.62
3.6-4.6
0.38-0.48
29.6-37
.7* 5.9-7.5*
1.02-1.31
0.65-0.83
$11-14 per
Mmol /flue
gas
$428-545
per kmol/hr
flue gas
$11-14 per
Mmol flue
gas
3.1-4.0
0.32-0.41
11.2-14.2
0.39-0.49
2.2-2.8
0.25-0.31
Unit Cost
$428-545
per kmol/hr
flue gas
$11-14
per Mmol
flue gas
$428-545
per kmol/hr
flue gas
$11-14
per Mmol
flue gas
* The capital investment costs were obtained using the calculated flue gas flow
rates and the unit cost of $70.0-$88.8/kw ($428-545 per kmol/hr flue gas)
derived from Figure A 13-5 in Appendix A-13 and using the methodology out-
lined in Table 4-1.
f The annualized costs were derived using the methodology described in Section
4.1.3 and assumptions indicated in Appendix A-13 (Section 6).
I The lower cost corresponds to an emission level of 43 ng/J, and the higher
cost corresponds to an emission level of 13 ng/J.
345
-------
Air Source Type 2
Flue Gases from Steam and
Power Generation System
Control Function 3 -
SC>2 Removal
For the steam boiler, uncontrolled S02 emissions were estimated to be
2,520 kg/hr (1095 ng/J) and 6,530 kg jnr (1668 ng/J) for the base case and MFS
case designs, respectively. Uncontrolled S02 emissions from the power boiler
for these two EDS designs would be 6,660 kg/hr (2878 ng/J) and 4,780 kg/hr
(2878 ng/J).
4.2.2.1.3.1 Control Technique 1 - Limestone F6D Process
Two different S02 emission levels are considered with limestone scrubbing.
For the steam boiler, the S02 emission level is assumed to be 260 ng/J for the
combined gas and coal feed. The 260 ng/J emission level is the NSPS for coal-
fired electric utility steam generating units, when uncontrolled SCL emissions
are in the 867-2,600 ng/J range. This emission level would result in S02 emis-
sions of 599 kg/hr and 1,018 kg/hr for the base case and MFS case designs,
respectively. For the power boiler, it is assumed that 90% S02 removal would
be needed. The 90% S02 removal requirement is the NSPS for coal-fired electric
utility steam generating units, when uncontrolled S02 emissions are in the
2,600-5,200 ng/J range,, This would result in S02 emissions of 666 kq/hr and
478 kg/hr for the two EDS designs. [Note: These emission levels are used here
for illustrative purposes only; its use should not be construed to suggest
that EDS boilers would necessarily have to meet NSPS].
Estimated capital investment costs and annualized costs for S0? removal
from steam and power boilers with limestone scrubbing are presented in Table
4-32. On annualized basis, the cost for S0? removal with limestone scrubbing
would be $52-83 per Mmol of flue gas.
Secondary Waste Stream
The FGD sludge generated from limestone scrubbing typically contains 18.4
wt % CaS04 . 2H20, 45.5 wt % CaSOg . 1/2 H20, 0.3 wt % fly ash, and 35.8 wt %
limestone on dry basis. For the steam boiler, FGD sludge (dry basis) generated
would amount to 50,720 Mg/yr and 147,590 Mg/yr for the base case and MFS case
346
-------
TABLE 4-32. COSTS OF S02 REMOVAL WITH LIMESTONE
SCRUBBING FOR FLUE GASES FROM STEAM
AND POWER GENERATION SYSTEMS
(STREAMS 701a and 707a)
Cost Element
Base Case
Total Total
Capital Annual ized
Investment* Cost t
MFS Case
Total
Capital
Investment*
Total
Annual ized
Cost t
Steam Boiler (701a)
Total Cost,
$ million
% of Base Plant
Unit Cost
Power Boiler(707a)
Total Cost,
$ million
% of Base Plant
Unit Cost
50.2
1.57
$1,179 per
kmol/hr
flue gas
52.0
1.63
$1,427 per
kmol/hr
flue gas
20.1
2.09
$60 per
Mmol flue
gas
20.8
2.16
$72 per
Mmol flue
gas
70.7
2.45
$1,023 per
kmol/hr
flue gas
42.6
1.48
$1,632 per
kmol/hr
flue gas
28.3
3.13
$52 per
Mmol flue
gas
17.1
1.88
$83 per
Mmol flue
gas
* The capital investment costs were obtained using the calculated flue gas
flow rates and the unit costs provided in Appendix A-20 (Table A 20-2) for
90% S0? removal,and by adjustments to scale down from 500 MW unit in Table
A 20-2 based upon the six-tenths rule. For convenience, costs for FGD
systems providing less than 90% SO,, removal (i.e., flue gas from the steam
boiler) were estimated by assuming bypassing part of the flue gas and
treating the remainder for 90% S02 removal so as to achieve the required
S02 removal.
f The annualized costs were derived from the methodology described in Sec-
tion 4.1.3, and by using annual operating costs provided in Appendix A-20.
Note: Cost estimates assume one limestone scrubber for steam boiler, and
second, separate scrubber for power boiler.
347
-------
Air Source Type 2
Flue Gases from Steam and
Power Generation System
Control Function 3 -
S00 Removal
c.
designs, respectively. For the power boiler, FGD sludge (dry basis) generated
would amount to 162,450 Mg/yr and 116,500 Mg/yr for these two EDS designs.
Disposal of this secondary waste stream is addressed in Section 4.4.2.7.
4.2.2.1.3.2 Control Technique 2 - Wellman-Lord FGD Process
The same S02 emission levels are considered here as in the limestone scrub-
bing case. Estimated capital investment costs and annualized costs for S02
removal from steam and power generation with the Wellman-Lord FGD process are
presented in Table 4-33. On annualized basis, the cost for S02 removal with
Wellman-Lord would be $56 - $78 per Mmol of flue gas.
Secondary Waste Stream
Sulfur is recovered in the form of elemental sulfur. However, there is
a secondary waste stream from the Wellman-Lord process as the thiosulfate/
sulfate by-product purge. This by-product purge typically contains 41.5 wt %
Na2S03, 18.1 wt % Na2S205, 10.0 wt % Na2S04, 1.1 wt % Na^Og, and 29.2 wt %
H20. For the steam boiler, sulfur would be recovered at a rate of 921 kg/hr
and 2,638 kg/hr for the base case and MFS case designs, whereas the by-product
purge would be generated at a rate of 209 kg/hr and 598 kg/hr for these two
EDS designs. For the power boiler, sulfur would be recovered at a rate of
2,869 kg/hr and 2,057 kg/hr for the base case and MFS case designs, and the
by-product purge would be generated at a rate of 650 kg/hr and 466 kg/hr for
the two EDS designs. Disposal of this secondary waste stream is addressed in
Section 4.4.2.7.
348
-------
TABLE 4-33. COSTS OF SOo REMOVAL WITH THE WELLMAN-LORD
FGD PROCESS FOR FLUE GASES FROM STEAM AND
POWER GENERATION SYSTEMS
(STREAMS 701a and 7Q7a)
Base Case
MFS Case
Cost Element
Total Total
Capital Annualized
Investment* Costt
Total
Capital
Investment*
Total
Annualized
Costt
Steam Boiler (70la)
Total Cost,
$ million
% of Base Plant
Unit Cost
48.6
1.52
18.9
1.96
68.4
2.37
31.8
3.51
$1,141 per
kmol/hr
flue gas
$56 per
Mmol flue
gas
$990 per
kmol/hr
flue gas
$58 per
Mmol flue
gas
Power Boiler (707a)
Total Cost, 50.3
$ million
% of Base Plant
Unit Cost
1.58
$1,380 per
kmol/hr
flue gas
19.6
2.03
$68 per
Mmol flue
gas
41.2
1.43
$1,579 per
kmol/hr
flue gas
16.1
1.77
$78 per
Mmol flue
gas
* See footnotes for Table 4-32.
349
-------
Air Source Type 2
Flue Gas from Process Heaters
4.2.2.2 Flue Gases from Process Heaters (Streams 107, 161, 203, 434)
There are three major flue gas streams from process heaters for both the
base case and the MFS case designs:
t Stream 107 - flue gas from liquefaction slurry preheate furnace
• Stream 161 - flue gas from partial oxidation feed vacuum
fractionator preheat furnace (MFS case only)
• Stream 203 - flue gas from solvent hydrogenation fuel preheat
furnaces
• Stream 434 - flue gas from hydrogen plant reformer furnaces
(base case only).
These flue gas streams would be expected to be generated by the combustion of
the low Btu fuel gas from Flexicoking. Uncontrolled emissions of particulate
matter were estimated to be 2J - 6.4 ng/J, compared to an NSPS of 13 ng/J for
electric utility steam generating units; the low emission results because the
fuel gas is expected to have a low particulate loading. Emissions of NOX from
the process heaters were estimated to be 52-99 ng/J,compared to an NSPS of 86
ng/J for electric utility steam generating units. Thus, there does not appear
to be further need for control of particulate matter and NO ..
Sulfur emissions from these furnaces could be controlled by one of two
alternative approaches: removal of reduced sulfur from the Flexicoking sour
fuel gas prior to combustion, or removal of SO- from the furnace flue gas after
combustion. Treatment of the Flexicoking sour fuel gas for removal of reduced
sulfur compounds by the Stretford process is discussed in Section 4.2.1.3. The
alternative of installing flue gas desulfurization systems on the furnace flue
gas appears to be less attractive from both technical and economical considera-
tions. The capital investment cost and the annualized cost of 90% S02 removal
with limestone scrubbing would be approximately 3.5 and 4.6 times the correspond-
ing costs for sulfur removal with the Stretford process. Further, over 97% of
350
-------
Air Source Type 2
Flue Gas from Process
Heaters
the reduced sulfur compounds in the Flexicoking sour fuel gas would be removed
by the Stretford process. If treated by Stretford, the fuel gas would contain
83 ppmv sulfur, which corresponds to S02 emissions of 48 ng/J. By comparison,
SOp emissions after 90% removal with FGD systems would be approximately 250
ng/J.
351
-------
Air Source Type 2
Regeneration/Decommissioning Off-Gas
from High and Low Temperature Shift
Catalysts
Control Function 1 -
S02 Removal
4.2.2.3 Regeneration/Decommissioning Off-Gas from High and Low Temperature
Shift Catalysts (Streams 449/450)
Off-gas from regeneration/decommissioning of high and low temperature
sour shift catalysts with air and steam is generated only from the MFS case
design. This is an intermittent waste stream estimated to be generated at a
rate of 22,255 kmol/hr. Regeneration would be expected once a year, and up to
72 hours in duration each time. The waste stream would consist primarily of
steam with 6% N2, 1% S02 and 0.5% C02.
Since the shift gases are provided with interstage and effluent cooling
and condensation, it is entirely reasonable to expect operation of the cooling
and quench systems during catalyst regeneration to condense moisture from the
off-gas. Removal of most of the moisture would be desirable for purposes of
volume reduction, prevention of condensation in piping to control devices, and
to avoid the other problems which arise in controlling gas streams with high
moisture levels. At 316°K (110°F), the off-gas would be reduced to a flow
rate of 1877 kmol/hr. This gas stream would contain 8.7% HgO, 13.0% S02, 72.4%
N2, and 5.9% C02-
For this off-gas stream, the only control function needed would be S0?
removal.
4.2.2.3.1 Control Function 1 - SO., Removal
Sulfur dioxide removal in the off-gas after bulk moisture removal can be
accomplished by a number of FGD processes that are commercially available.
Alternatively, this off-gas could also be sent to the Claus plant, so that the
S02 in the shift catalyst regeneration off-gas would displace S02 produced by
air oxidation of H2S in the combined acid gas. Since S02 from the shift cata-
lyst regeneration off-gas is about 245 kmol/hr, while H,,S in the combined acid
gas feed to the Claus plant is 921 kmol/hr, there is sufficient capacity in
the Claus to allow substitution of the S02 in the off-gas for S02 produced by
air oxidation. For the MFS case design, the introduction of the shift catalyst
352
-------
Air Source Type 2
Regeneration/Decommissioning Off-Gas
from High and Low Temperature Shift
Catalysts
Control Function 1 -
S(X, Removal
regeneration off-gas into the Claus plant would only increase the flow rate of
the Claus tail gas by approximately 2%. Thus, control of the shift catalyst
regeneration off-gas by the Claus process is a potential option if fluctua-
tions in sulfur loading caused by Streams 449/450 and if control of proper air
feed to the Claus hLS oxidation step can be accommodated in the Claus design
and operation.
It should be commented that there are currently a number of installations
using sour shift catalysts in petroleum and related applications. As far as
is known, control of catalyst regeneration off-gases is not practiced at any
of the facilities. Catalyst users indicate that, due to the short duration
and high variability of S0? containing off-gases, control would be difficult.
Regeneration often occurs when facilities are shut down for general maintenance,
so that use of FGD or Claus units onsite at such time presents difficulties.
Even if regeneration of catalyst units were to be scheduled during times in
which FGD or Claus units were online, integration of the highly variable re-
generation gases into the FGD or Claus units could cause difficulties in over-
all system control. For these reasons, only the sodium throwaway FGD process
dedicated to S0? control for intermittent waste gas streams is discussed here.
4.2.2.3.1.1 Control Technique 1 - Sodium Throwaway Process
As discussed previously, the sodium throwaway process is lower in capital
investment cost and higher in operating cost compared to other FGD systems.
For the control of intermittent waste gas streams, however, the high cost of
sodium carbonate employed for scrubbing is a lesser concern. Sodium throwaway
processes can be designed to remove 90% of the SO^ present in the inlet stream.
Thus, sodium throwaway processes can reduce the SOp concentrations in the shift
catalyst regeneration off-gas to 1.3% after moisture removal. This is equiva-
lent to an S0~ concentration of 0.1% in the off-gas prior to moisture removal.
Higher SOp removal by sodium throwaway processes can be readily achieved
353
-------
Air Source Type 2
Regeneration/Decommissioning Off-Gas
from High and Low Temperature Shift
Catalysts
Control Function 1 -
SO. Removal
because of the high reactivity of sodium chemicals with S0?.
Estimated capital investment cost and annualized cost for the sodium
throwaway process are presented in Table 4-34. As noted in Section 4.2.1.5,
any sodium throwaway FGD system sized for the control of S0? emissions from
the transient waste gases would have much greater capacity and could also be
used to control S02 emissions from the sour shift catalyst regeneration off-gas.
Treatment of Streams 449/450 in any scrubber installed for the transient waste
gases would eliminate the costs shown in Table 4-34, except for a small frac-
tion attributable to cost of sodium carbonate. Almost all the costs for treat-
ment of Streams 449/450 would then be included in the costs shown in Table
4-17.
354
-------
TABLE 4-34. COSTS OF S0? REMOVAL WITH SODIUM THROWAWAY
PROCESS FOR SOUR SHIFT CATALYST REGENERATION/
DECOMMISSIONING OFFGAS (STREAMS 449/450)
Cost Element
MFS Case
Total
Capital
Investment*
Total
Annualized
Costt
Total Cost, $ million
% of Base Plant
Unit Cost
0.99
0.038
$45 per kmol/hr
waste gas
0.86
0.095
$0.54 per kmol
waste gas
* The capital investment costs were obtained using the calculated combustion
product flow rate and cost data provided in Reference 45, which indicate
a unit capital investment cost (TCI) of $530 per kmol/hr combustion product
gas for units that handle approximately 2000 kmol/hr gas flow.
^ The annualized costs were derived using the methodology described in
Section 4.1.3. Sodium carbonate consumption was assumed to be 1.2 mol
per mol S09 removed. Cost of sodium carbonate was assumed to be $264/Mg.
355
-------
Air Source Type 3
Organic and CO Containing
Waste Gases
4.2.3 Source Type 3 - Organic and CO Containing Waste Gases
There are four waste streams for the base case design and one waste stream
for the MFS case design under Source Type 3. These waste streams are:
t Stream 426 - vent gas from COo removal by Catacarb process
(base case only)
• Stream 438 - hydrogen plant deaerator vent
0 Stream 446 - regeneration/decommissioning off-gas from reformer
catalyst (base case only)
• Stream 448 - decommissioning off-gas from methanation catalyst
(base case only).
The vent gas from COp removal are expected to contain organics and CO at the
hundreds of ppmv level. The other three waste streams are expected to contain
only traces of hydrocarbons and/or CO, but the exact concentration levels are
not known.
Because waste streams under Source Type 3 are free of sulfur compounds,
the only control function needed would be incineration for removal of organics
and CO. Incineration processes applicable to the control of these waste streams
include thermal incineration, catalytic incineration, and flaring. Key fea-
tures of these incineration processes are discussed in Section 4.2.1. Details
regarding these processes are included in Appendices A-15 through A-17.
In an EDS commercial plant, 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
generally available for these 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 the waste gases. Costs ex-
perienced in practice could be lower than these costs if a single, common in-
cinerator were employed which would be designed to handle any one of the streams
individually, or any combination of the streams which might reasonably be ex-
pected to be generated concurrently.
356
-------
Air Source Type 3
C02 Vent Gas
Control Function 1 -
Incineration
4.2.3.1 Vent Gas from COp Removal (Stream 426)
The vent gas from C02 removal (by Catacarb or alternative AGR system) is
generated at a rate of 6100 kmol/hr, and applies only to the base case design.
This vent gas will consist primarily of carbon dioxide (78.4%) and steam (19.6%),
along with 1.9% hydrogen, 370 ppmv methane and 160 ppmv carbon monoxide. Direct
discharge of this vent gas to the atmosphere has been considered to be one of
the options. In the event that further reduction of hydrocarbon and CO emis-
sions would be needed, incineration is a control function that may be considered.
4.2.3.1.1 Control Function 1 - Incineration
Thermal and catalytic incineration are applicable techniques to control
organic and CO emissions from the COp vent gas. These control techniques are
discussed in this section.
4.2.3.1.1.1 Control Technique 1 - Thermal Incineration
The C0? vent gas was estimated to contain 2.2 kmol/hr of methane and 0.96
kmol/hr of CO. Thermal incineration of organic-containing waste gases and
liquids can typically result in flue gas concentrations ranging from 5 to 20
ppmv total hydrocarbons (expressed as CH4) and 10 to 100 ppmv CO. Assuming
incineration of the C02 vent gas at 1100°K (1520°F) with 5,330 kmol/hr (0.59
TJ/hr) of a low-Btu fuel gas and 50% excess air, the generation rate of the
flue gas stream would be 18,510 kmol/hr. At concentration levels of 20 ppmv
total hydrocarbons and 50 ppmv CO, this flue gas would result in emissions of
0.37 kmol/hr of total hydrocarbons (expressed as CH4) and 0.93 kmol/hr of CO.
Thus, thermal incineration would reduce emissions of total hydrocarbons by 83%.
There would be no net reduction in CO emissions because of the additional CO
contributions from combustion of the low-Btu fuel gas.
Estimated capital investment and annualized costs for thermal incinera-
tion (with waste heat recovery) of the C02 vent gas are presented in Table
4-35. Because this stream is generated on a continuous basis, and utilizes a
357
-------
TABLE 4-35. COSTS OF ORGANICS AND CO CONTROL BY THERMAL
INCINERATION WITH WASTE HEAT RECOVERY FOR
C02 VENT GAS (STREAM 426)
Cost Element
Base Case
Total
Capital
Investment*
Total
Annualized
Costt
Total Cost, $ million
% of Base Plant
Unit Cost
3.2
0.10
$516 per
kmol/hr
waste gas
17.1
1.78
$356 per
Mmol waste
gas
* The total capital investment cost (TCI) was obtained using the calculated
combustion product flow rate and the installed equipment cost curve (Curve
B) presented in Figure A 16-6 of Appendix A-16. This capital investment,
cost corresponds to a unit cost of $170 per kmol/hr combustion product gas.
^ The annualized cost was derived using the methodology described in Section
4.1.3. The annual cost for fuel gas is $20.5 million, and the annual
steam credit received is $4.0 million.
358
-------
Air Source Type 3
C02 Vent Gas
Control Function 1 -
Incineration
substantial quantity of low-Btu gas, the annualized cost for thermal incinera-
tion is relatively high and represents 1.8% of the total annualized cost for
the uncontrolled EDS base plant.
4.2.3.1.1.2 Control Technique 2 - Catalytic Incineration
The efficiency of catalytic incinerators in destroying organics and CO is
strongly dependent on the type of catalyst used and the temperature of the
catalyst bed. At a temperature of 700°K (800°F), the destruction efficiencies
for most organics and for CO are over 97% and approximately 99%, respectively
(Appendix A-17). Effluent concentrations for total hydrocarbons are typically
1 to 20 ppmv. Catalytic incineration of the C02 vent gas at 700°K (800°F),
with 1,230 kmol/hr (0.28 TO/hr) of a low-Btu fuel gas and 50% excess air, would
generate a flue gas stream at a rate of 11,990 kmol/hr (170,000 SCFM). At con-
centration levels of 20 ppmv total hydrocarbons and 50 ppmv CO, this flue gas
would result in emissions of 0.24 kmol/hr of total hydrocarbons (expressed as
CHL) and 0.60 kmol/hr of CO. This is equivalent to approximately 89% net re-
duction in the emission of hydrocarbons. Net reduction in CO emissions is not
anticipated because of additional CO contributions from combustion of the low-
Btu fuel gas, and because actual CO emissions from any incineration device
could fluctuate over a wide range (e.g., 10-100 ppmv) during even a short time
period.
Estimated capital investment and annualized costs for catalytic incinera-
tion of the C02 vent gas are presented in Table 4-36. The capital investment
cost for catalytic incineration would be slightly higher than that for thermal
incineration. The total annualized cost for catalytic incineration, however,
would be 39% lower than that for thermal incineration.
359
-------
TABLE 4-36. COSTS OF ORGANICS AND CO CONTROL BY
CATALYTIC INCINERATION FOR C0? VENT GAS
(STREAM 426)
Cost Element
Base Case
Total
Capital
Investment*
Total
Annualized
Cost t
Total Cost, $ million
% of Base Plant
Unit Cost
3.6
0.11
$595 per
kmol/hr
waste gas
10.4
1.09
$217 per
Mmol waste
gas
* The capital investment cost was obtained using the calculated combustion
product flow rate, the equipment cost curve for fixed-bed catalytic
incineration presented in Appendix A-17 (Figure A 17-3), and the methodology
outlined in Table 4-1.
The annualized cost was derived using the methodology described in Section
4.1.3. The annual cost for fuel gas amounts to $9.7 million.
360
-------
Air Source Type 3
Deaerator Vent
Control Function 1 -
Incineration
4.2.3.2 Hydrogen Plant Deaerator Vent (Stream 438)
The deaerator vent gas from the hydrogen plant is generated at a rate
of 6.5 kmol/hr for the base case design and 6.2 kmol/hr for the MFS case design,
This vent gas would consist primarily of steam with a small quantity of carbon
dioxide and traces of light hydrocarbons. Direct discharge of this vent gas
to the atmosphere is one of the options. However, this waste stream and other
vent gases are usually not well characterized, and incineration is a control
function that might be considered if organic and CO emissions are of concern.
4.2.3.2.1 Control Function 1 - Incineration
Thermal incineration, catalytic incineration, and flaring are applicable
techniques to control organic and CO emissions from vent gases. Only thermal
incineration is discussed in this section, because this is a small volume waste
gas stream.
4.2.3.2.1.1 Control Technique 1 - Thermal Incineration
As discussed previously, thermal incineration of waste gases would typi-
cally result in flue gas concentrations of 5-20 ppmv total hydrocarbons (as
CH.) and 10-100 ppmv CO. Based on energy balances, thermal incineration of
the hydrogen plant deaerator vent would require approximately 0.72 mol of low-
Btu fuel gas (125 Btu/SCF) per mol of waste gas, assuming incineration at
1100°K (1520°F) with 50% excess air. The estimated unit capital investment
(TCI) cost, derived using the calculated combustion product flow rate and the
installed equipment cost (IEC) curve for thermal incineration presented in
Appendix A-16, (Curve A, Figure A 16-6), would be about $2600 per kmol/hr of
waste gas. The estimated unit annualized cost, derived using the cost metho-
dology described in Section 4.1.3 and the fuel gas requirement, would be $490
per Mmol waste gas. Thus, the capital investment and annualized costs for
thermal incineration of the hydrogen plant deaerator vent would be approxi-
mately $16,900 and $25,000, respectively. These unit costs can also be used
to estimate the capital investment and annualized costs for thermal incinera-
ation of other small volume vent gases in dedicated units.
361
-------
Air Source Type 3
Catalyst Regeneration/
Decommissioning Off-Gases
Control Function 1 -
Incineration
4.2.3.3 Catalyst Regeneration/Decommissioning Off-Gases (Streams 446/448)
There are two off-gas streams from the regeneration and/or decommission-
ing of catalysts for the base case design. For the reformer catalyst, it has
been estimated that regeneration will occur over a period of 24 hours per year,
and the off-gas will be generated at an average rate of 6,800 kmol/hr. The
off-gas is anticipated to consist primarily of steam and nitrogen with small
amounts of CO and particulate matter. Methanation catalysts are not typically
regenerated; however, these catalysts are oxidized during decommissioning
because they tend to be pyrophoric in the active state. The decommissioning
off-gas has been estimated to be generated at an average rate of approximately
5,000 kmol/hr. The average emission frequency of this off-gas is once every
four years, with an average emission duration of 24 hours. The characteris-
tics of the decommissioning off-gas are not well known, except that it is ex-
pected to consist primarily of steam and nitrogen with small amounts of parti-
culate matter. For either off-gas stream, no data are available on CO or
particulate levels. Residual organics may also be present during purging of
the unit or initial phases of regeneration/decommissioning.
Control of the catalyst regeneration/decommissioning off-gases by incin-
eration is discussed in this section.
4.2.3.3.1 Control Function 1 - Incineration
Flaring and thermal incineration are applicable techniques to control
organic and CO emissions from catalyst regeneration/decommissioning off-gas.
These control techniques are discussed in this section. Catalytic incinera-
tion is not applicable because the presence of particulate matter in these
off-gases may result in catalyst deactivation.
4.2.3.3.1.1 Control Technique 1 - Flaring
Data from recent studies indicate that 96 to >99% of the hydrocarbons
in waste gases are typically destroyed by flaring (Appendix A-15). Data
on the effectiveness of CO control by flaring are limited; CO levels of
362
-------
Air Source Type 3
Catalyst Regeneration/
Decommissioning Off-Gases
Control Function 1 -
Incineration
hundreds of ppmv have been reported.
Estimated capital investment and annualized costs for flaring of catalyst
regeneration/decommissioning off-gases are presented in Table 4-37. These
estimates are based on the assumptions that the off-gases would not have signi-
ficant heating value, and that a low-Btu fuel gas would be employed as supple-
mental fuel.
4.2.3.3.1.2 Control Technique 2 - Thermal Incineration
Concentrations of CO and hydrocarbons in the incinerated gas would typi-
cally range from 10-100 ppmv and 5-20 ppmv, respectively. Although character-
ization data for the catalyst regeneration/decommissioning off-gases are not
available, emissions of CO and hydrocarbons from the incineration of these
gases may be estimated by assuming typical flue gas concentrations of 50 ppmv
CO and 20 ppmv total hydrocarbons. Incineration of the reformer catalyst
regeneration/decommissioning off-gas with a low-Btu fuel gas at 1100°K (1520°F)
and 50% excess air would generate 14,850 kmol/hr of flue gas, 0.30 kmol/hr of
total hydrocarbons and 0.74 kmol/hr of CO. Similarly, incineration of the
methanation catalyst decommissioning off-gas would generate 10,920 kmol/hr of
flue gas, 0.22 kmol/hr of total hydrocarbons and 0.55 kmol/hr of CO.
Estimated capital investment and annualized costs for thermal incineration
of catalyst regeneration/decommissioning off-gases are presented in Table 4-38.
These estimates are also based on the assumption that these off-gases would
not have significant heating value.
363
-------
TABLE 4-37. COSTS OF ORGANICS AND CO CONTROL BY FLARING
FOR CATALYST REGENERATION/DECOMMISSIONING
OFF-GASES
Reformer Catalyst Regeneration/ Methanation Catalyst
Decommissioning Off-Gas Decommissioning Off-Gas
Cost Element
Total Cost,
$ million
% of Base Plant
Unit Cost
Total
Capital
Investment*
1.5
0.046
$216 per
kmol/hr
waste gas
Total
Annual ized
Costt
0.29
0.030
$1 .8 per
kmol waste
gas
Total
Capital
Investment*
1.1
0.038
$216 per
kmol/hr
waste gas
Total
Annual ized
Costt
0.21
0.023
$7.1 per
kmol waste
gas
* The capital investment costs were derived using the combined waste gas
and low-Btu fuel gas flow rates and the equipment cost curve for 200 ft
high flares presented in Appendix A-15 (Figure A 15-3).
"t" The annual ized costs were derived using the methodology described in Section
4.1.3 and the calculated fuel gas requirements.
364
-------
TABLE 4-38. COSTS OF ORGANICS AND CO CONTROL BY THERMAL
INCINERATION FOR CATALYST REGENERATION/
DECOMMISSIONING OFF-GASES
Reformer Catalyst Regeneration/
Decommissioning Off-Gas
Methanation Catalyst
Decommissioning Off-Gas
Total
Capital
Investment *
Total Cost, 2.0
$ million
% of Base Plant 0.062
Unit Cost $291 per
kmol/hr
waste gas
Total
Annuali zed
Costt
0.38
0.040
$2.3 per
kmol waste
gas
Total
Capital
Investment *
1.5
0.046
$291 per
kmol/hr
waste gas
Total
Annual i zed
Costt
0.29
0.030
$9.5 per
kmol
waste gas
-
* The capital investment costs were obtained using the calculated combustion
product flow rates and the installed equipment cost curve presented in
Appendix A-16 (Curve A, Figure A 16-6). This capital investment cost corre-
sponds to a unit cost of $133 per kmol/hr combustion product gas.
t The annualized cost was derived using the methodology described in Section
4.1.3 and the calculated fuel gas requirements.
365
-------
Air Source Type 4
Fugitive Dust from
Material Storage
4.2.4 Source Type 4 - Fugitive Dust from Material Storage
There is one uncontrolled waste stream identified under Source Type 4:
Stream Oil - fugitive dust from coal pile
Another waste stream in this category is a secondary waste stream: fugitive
dust emissions from solid waste storage piles. Since these waste streams
are identical to similar waste streams from conventional sources such as coal-
fired power plants and because the control techniques are not stream-specific,
a general discussion of applicable control techniques is given rather than a
stream-by-stream presentation.
Open or partially enclosed storage piles are often used for bulk materials
not affected by precipitation or slight contamination such as coal, sand,
gravel, clay, and gypsum. The material may be stored for a short time with
a high turnover rate to accommodate surges in daily or weekly rates of sequen-
tial 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 EDS based commercial plants fugitive dusts are emitted from coal and
solid waste storage piles. The techniques used to control these emissions
are not unique to liquefaction plants and are widely used in industries that
require large scale material storage. During loading operations, fugitive
dust emissions could be reduced by minimizing the distance from free drop to
the stockpile, or by incorporating devices such as a telescoping chute to
essentially enclose the coal stream (or solid waste stream) during the drop.
Water sprays could also be directed into the unloading coal or waste and the
storage pile. During reclamation, water spraying could again be used for
366
-------
Air Source Type 4
Fugitive Dust from
Material Storage
control of fugitive dusts. The most commonly used techniques to control dust
emissions from storage piles are water spraying, chemical stabilization, stack-
ed segregation, confinement, capping, and vegetative stabilization. Surface
protection methods such as vegetative stabilization, chemical stabilization,
capping and stacked segregation are primarily used on reserve storage piles
since these piles are subject to minimal disturbances. Active storage piles
generally require either water spraying or confinement to control dust emis-
sions. The key features and unit costs for these techniques are listed in
Table 4-39. These techniques apply equally to coal storage piles and solid
waste storage piles, including methods such as vegetative stabilization, which
have been used by the Tennessee Valley Authority on coal piles.
Water spraying is common method of dust suppression. Dust control by
water spraying is usually obtained by placing spray nozzles at strategic loca-
tions 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 moisture
can create handling problems during reclamation and subsequent processing.
Water spraying is also commonly employed during loading and reclamation opera-
tions.
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
367
-------
TABLE 4-39. KEY FEATURES OF STORAGE PILE DUST CONTROL TECHNOLOGIES
Method
Water
Spray
Control Principle
Spray application of
210-250 1/Mg to reduce
dusting
Control
Effectiveness*
Approximately 50%
reduction in losses
Reliability/
Special Problems Unit Costs*
1. Piping may require heat
tracing when freezing
is a concern
Other
Pollutants
Generated
none
Chemical
CO
en
CO
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
2. May increase degradation
3. Frequent re-treatment
necessary
1. Piping may require heat
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
of spontaneous com-
bustion, especially
in piles, subject to
stockpile and reclaim
operations
2. Crust tends to break
up during heavy rains
$.33-.77/Mgt
$.55-.22/m2
Volatiles which
depend on wetting
agent utilized
Volatiles which
depend on crust-
ing agent
utilized
(Continued)
-------
TABLE 4-39, (Continued)
Method
Control Principle
Control
Effectiveness*
Reliability/
Special Problems
Unit Costs*
Other
Pollutants
Generated
Stacked Coating surface of corn-
Segregation pacted storage pile with
layer of select, medium
sized material
No data available
Either deliveries of differ-
ent sized material must be
coordinated or both sizes
must be readily available
from storage
none
Confinement
CO
CTl
Capping
Vegetative
Stabilization
Enclosure of active
storage pile in a totally
enclosed barn or silo
with point source dust
control equipment on
building vents
Paving with earth or
asphalt or cover with
polyethylene
Up to 99% reduction
in losses
Up to 100%
Covering pile with sod
Approximately 65%
reduction over un-
stabilized pile; 90%
if chemical stabilizer
is also used
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
1. Requires frequent
watering
2. Handling of sod during
reclamation operations
is cumbersome and
expens i ve
3. Upper layer of stored
material is contami-
nated with soil
a) $110/Mg of
stored material
b) $1 million to $3
million per silo
depending on
size
for
none
asphalt
$1.96/m2 for
polyethylene
$2.70/m2
Soil dust from
earth covering
Soil dust from
earth covering
* Cost and control efficiency data obtained from Reference 50.
t Data obtained from Reference 51.
| Data obtained from Reference 15.
-------
Air Source Type 4
Fugitive Dust from
Material Storage
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.
Another effective means of controlling dust emissions from material stor-
age piles is the stacking of coarse material on the surface of a properly
compacted pile. For instance, a 0.152 m layer of fine coal (6.4 mm x 0 mm)
on the top and sides of the coal storage pile can be anchored in place by a
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.
Enclosure of the material 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.
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.
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
370
-------
Air Source Type 4
Fugitive Dust from
Material Storage
applications such as stabilizing tailing piles, the use of vegetative stabi-
lization results in a decrease in emissions of approximately 65%. When
vegetative stabilization is used in conjunction with a chemical stabilizer,
this efficiency increases to approximately 90%.
There are, of course, other fugitive dust emission control techniques
that have not been addressed here. One possibility, for example, is to use
windscreens (porous windbreaks) to reduce the velocity of the air in the
vicinity of the storage pile. Another technique is the optimal profiling and
orientation of the storage piles.
371
-------
Air Source Type 5
Fugitive Organic Emissions
4.2.5 Source Type 5 - Fugitive Organic Emissions
There are two types of fugitive organic emissions in an EDS commercial
plant:
• Stream 751 - evaporative emissions from product and by-product
storage
• Fugitive organic emissions from process equipment such as pump
and compressor seals, valves, pipe flanges, pressure relief valves,
and drains.
Because of the differences in the nature of these emissions, control techni-
ques for each type are discussed in individual subsections.
Evaporative Emissions from Product and By-Product Storage
Evaporative emissions from storage tanks storing volatile liquids occur
because of temperature change, pressure change, or wind induced mechanisms
which cause vapor pressure of the stored liquid to vary, resulting in vapor
emissions. The minimum accepted standard for storage of volatile liquids is
the fixed roof tank. Fixed roof tanks are commonly equipped with a pressure
relief valve that allows them to operate at a slight internal pressure or
vacuum. The pressure/vacuum valves prevent the escape of vapors only when
the changes in temperature, pressure or liquid levels are relatively small.
With greater changes in these variables, vapors would be emitted through the
pressure/vacuum valves. These vapor emissions are contributed primarily by
breathing losses and working losses (21). Breathing loss is the expulsion
of vapor from a tank due to vapor expansion and contraction from changes in
temperature and barometric pressure. It occurs in the absence of any liquid
level change in the tank. Working loss is the combined loss from filling
and emptying. In filling, the vapors are expelled from the tank when the
pressure inside the tank exceeds the relief pressure, as a result of increase
of the liquid level in the tank. In emptying, air is drawn into the tank and
becomes saturated with organic and expands, thus exceeding the capacity of
the vapor space.
372
-------
Air Source Type 5
Fugitive Organic
Emissions
Emissions from fixed roof tanks can be reduced by minimizing diurnal
temperature variations (e.g., placing tanks underground), proper setting and
maintenance of pressure/vacuum vents, and leak prevention efforts. Signifi-
cant controls can be effected by: 1) floating a cover on the surface of the
stored liquid, 2) using vapor processing units, or 3) by replacing the fixed
roof storage tank with a floating roof storage tank.
Floating roof tanks (external and covered) 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. Evaporative losses from floating roof tanks
are mainly due to standing storage losses and withdrawal losses (21). Stand-
ing storage loss results from wind induced mechanisms as air flows across the
top of an external floating roof tank. Withdrawal loss is the vaporization
of liquid that clings to the tank wall, and is then exposed to the atmosphere
when a floating roof is lowered by withdrawal of liquid. To effectively con-
trol emissions, the floating roof employs a seal system to cover the small
annular space between the roof and the tank wall. Floating roof tanks are
commonly equipped with primary seals. However, evaporative losses from float-
ing roof tanks can be greatly reduced by the installation of secondary seals.
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 main-
tain contact in places where the tank shell (walls) 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 per-
meated through) the primary seal. Not only do they form a second barrier for
the vapor, they also seal this vapor off from the effects of moving air. As
a result, secondary seals are effective control devices which, when used on
373
-------
Air Source Type 5
Fugitive Organic
Emissions
floating roof tanks, can reduce overall emissions by as much as 95% when
compared to the use of only primary seals.
Vapor processing units can also be used to control VOC emissions from
the pressure/vacuum vents in fixed roof storage tanks. Some of the vapor
processing techniques available are carbon absorption, thermal oxidation,
refrigeration, compression-refrigeration-absorption, and compression-refriger-
ation-condensation.
The carbon adsorption vapor recovery unit uses beds of activated carbon
to remove VOCs from the air-vapor mixture, that is vented from the overhead
space in the tank. These units generally consist of two vertically positioned
carbon beds and a carbon regeneration system. Air-vapor mixture enters the
base of one of the adsorption columns and the VOC components are adsorbed onto
the activated carbon as the gases ascend. Adsorption in one carbon bed occurs
for a specific timed cycle before switchover to desorption occurs. The nearly
saturated carbon bed is then subjected to vacuum, steam, or thermal regenera-
tion, or a combination of these methods, and the VOCs are stripped from the
bed. Vacuum regenerated units recover VOCs by absorption in a gasoline stream
which circulates between the control unit and gasoline 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. The air and any remaining
VOCs exiting from the absorber are passed again through the absorbing bed,
and exhausted to the atmosphere. Steam regenerated units condense the VOC-
water mixture of steam and stripped VOCs and return the separated organic
product to storage.
Thermal oxidation units rely upon burning VOC vapors to produce non-
polluting combustion products. Vapors driven from the absorbent by increased
temperature are piped either to a vapor holder or directly to the oxidizer
unit. Uhen a vapor holder is used, operation of the oxidizer begins when the
374
-------
Air Source Type 5
Fugitive Organic
Emissions
holder reaches a preset level, and ends when the holder is empty. 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 range.
Refrigeration type recovery units remove VOCs from the air-vapor mixture
by straight refrigeration at atmospheric pressure. Vapors displaced from
storage tanks enter a condenser section where methylene chloride "brine" is
pumped through the finned tube sections of the heat exchanger. Brine tempera-
ture in this section ranges from 190°K to 210°K. Some units contain a pre-
cooler section (glycol and water solution circulating at 274°K) to remove
most of the water from the vapors prior to the main condenser. There are no
compression 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 (305°K) trichlorethylene through
the condenser. This defrost fluid is kept warm by heat salvaged from the re-
frigeration 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 storage tanks are first passed through a saturator which
sprays liquid gasoline 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 the vapors are compressed and cooled, and water and heavy VOCs are
375
-------
Air Source Type 5
Fugitive Organic
Emissions
condensed. The uncondensed vapors move into a packed absorber column where
they are contacted by chilled gasoline (277°K) 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, start-
ing when the vapor holder is filled and stopping when it has emptied. Cleaned
gases are vented from the absorber column to atmosphere.
A vapor recovery system employing a compression-refrigeration-condensa-
tion unit makes use of a vapor holder to store accumulated air-vapor mixture,
and a gasoline 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 mix-
ture is first compressed in a two-stage compressor with an intercooler. Con-
densate is withdrawn from the intercooler prior to compression in the second
stage. The compressed vapors then pass through the refrigeration-condensor
section where they are returned along with the intercooler condensate to a
gasoline storage tank. Cleaned gases are exhausted from the top of the con-
densor.
Costs for vapor processing units on fixed roof tanks vary with the type
of product and the product throughput. In the case of gasoline, capital in-
vestment costs for these units range from $152,000 to $270,000 for a gasoline
3
throughput of 380 m /day. These costs increase by 15% when the gasoline
throughput increases by 150%. Costs for internal floaters in fixed roof tanks
range from approximately $4,000 to $40,000 for storage tanks with diameters
of 5 and 30 meters, respectively. For floating roof tanks, controls of eva-
porative emissions by the addition of secondary seals are estimated to cost
$75 per linear meter.
376
-------
Air Source Type 5
Fugitive Organic
Emissions
Fugitive Organic Emissions from Process Equipment
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 sources are: pumps, compressors, in-line process valves, pressure re-
lief devices, open-ended valves, sampling connections, flanges, and drains.
There are two basic methods which have been used to control fugitive
organic emissions from process equipment:
1) leak detection and repair methods, and
2) equipment specification.
Leak detection methods include individual component surveys, area (walk-
through) surveys, and fixed point monitoring at specified intervals. Guide-
lines for the frequency of leak detection surveys in petroleum refineries have
been suggested by EPA (52). However, different guidelines might have to be
developed for direct liquefaction plants, due to differences in equipment and
composition of leaks between these plants and refineries.
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, olfactory, soap bubble, or instrument techni-
ques. 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 de-
tection instruments. By sampling and analyzing the air in close proximity to
the leak the hydrocarbon concentration of the sampled air can be determined.
The leak rate from the source can be estimated since relationships exist be-
tween monitoring concentrations and mass emission rates.
377
-------
Air Source Type 5
Fugitive Organic
Emissions
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 instru-
ments may sample the ambient air intermittently or continuously. Elevated
hydrocarbon concentrations indicate a leaking component. As in the walk-
through method, an individual component survey is required to identify the
specific leaking component in the area. For this method, the portable hydro-
carbon detector is also required.
Reduction of fugitive emissions from the identified leaking components
is effected by repair methods. In many cases, perfect repair will not be
achieved; however, effective repair can substantially reduce emissions from
the leaking component. Some repairs might not be performed while the plant
is on-stream. Also, both the speed with which repairs are made and the size
of leak requiring repair are issues addressed in EPA's refinery VOC leak con-
trol techniques guidelines document (52). Typical repair methods employed
on the various components are listed in Table 4-40.
The second method used to control fugitive emissions is by equipment
specification. Typical equipment specifications used are listed in Table
4-41.
Costs for leak detection and repair methods will depend upon the fre-
quency of leak detection surveys, the number of type of fixed point monitors
used, and the complexity of the component undergoing repair. The major costs
of leak detection, maintenance and repair methods are labor related. In the
378
-------
TABLE 4-40. REPAIR METHODS FOR FUGITIVE EMISSIONS REDUCTION
Component
Repair Method
Pumps and compressors
Relief valves
In-line valves
Flanges
Tighten packing gland
Replace pump and compressor
seals
Manual release of the valve
may improve the seat seal
Replace relief valve seats
Tighten packing gland
Lubricate plug type valves
Inject sealing fluid into process
valves requiring repair
Replace valve packing
Replace flange gaskets
379
-------
TABLE 4-41. EQUIPMENT DESIGN/MODIFICATIONS FOR FUGITIVE HYDROCARBON EMISSIONS CONTROL
Component
Specification
Pumps
co
00
o
Compressors
Pressure Relief Devices
Open-Ended Valves
In-Line Valves
Drains
- improve seal at the junction of moving shaft and stationary
casing
- use sealess pumps
- use double mechanical seals
- use closed vent systems around seal areas
- 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 diaphragm and bellows seal type valves
- covers
- drain traps.
-------
Air Source Type 5
Fugitive Organic Emissions
case of equipment specifications, costs will depend upon the component being
specified. Typically, double mechanical seals in conventional refinery appli-
cations cost $815/pump (installed). Flush oil systems for double mechanical
seals cost $1500/pump, These costs could be higher in direct liquefaction
applications, due to the potential abrasiveness of some materials that will
be pumped in direct liquefaction plants. Leak detection/repair and equipment
specification techniques are discussed in further detail in Appendix A-18.
381
-------
Air Source Type 5
Evaporative Emissions
4.2.5.1 Evaporative Emissions from Product/B.y-Product Storage Emissions
(Stream 751T
Various types of storage vessels are employed to store petrochemical pro-
ducts. The suitability of a specific tank design depends on the vapor pres-
sure that the stored product exerts at ambient conditions and the storage
desired.
According to Exxon's designs, naphtha from the EDS process will be stored
in floating roof tanks, whereas fuel oil and phenol will be stored in fixed
roof tanks. For naphtha, uncontrolled emissions were estimated by assuming
that the external floating roof tanks are equipped with only primary seals.
For fuel oil and phenol, uncontrolled emissions were estimated by assuming
that there are no vapor recovery systems and no internal floating roofs in-
stalled on the fixed roof tanks. Uncontrolled emission estimates from these
tanks have previously been discussed in Section 3.3.5.5.1.
Emissions from floating roof tanks consist primarily of standing storage
losses and withdrawal losses, as discussed previously. These losses are great-
ly reduced by the addition of secondary seals, which is the most widely used
approach for VOC control in existing floating roof tanks. The addition of
secondary seals can reduce overall emissions from naphtha storage tanks by
95%, and is the control option discussed here. Estimated controlled organic
emissions from naphtha storage are presented in Table 4-42.
Emissions from fixed roof tanks consist primarily of breathing losses and
working losses, as discussed earlier in this section. These losses can be
reduced by the installation of vapor recovery systems, thermal oxidation for
emission control, or internal floating roofs. For purposes of this discussion,
emissions from fixed roof tanks for fuel oil and phenol storage are controlled
by installation of internal floating roofs with secondary seals. The overall
control efficiencies of vapor recovery systems and thermal oxidation could
be potentially higher than the installation of internal floating roofs, but
insufficient information concerning the properties of blended fuel oil and
382
-------
TABLE 4-42. STORAGE TANK EMISSION ESTIMATES
to
co
co
No. of
Product Tanks
Base Case
Naphtha
Blended Fuel Oil
Phenol
MFS Case
Naphtha
Blended fuel Oil
Phenol
2
2
2
2
2
2
Roof Type
Floating
Fixed
Fixed
Floating
Fixed
Fixed
Capacity
per Tank
(m3)
41 ,200
36,800
730
40,000
34,000
730
Mass Emission Rate*
Diameter
(m)
62.5
59.4
12.2
62.5
56.4
12.2
Vapor Pressure
kPa
10
0.00028
0.14
10
0.00028
0.14
Uncontrolled t
kg/yr
18,750
153
196
18,730
140
196
Control led •)•
kg/yr
905
31
78
880
28
78
Avg. Control
Efficiency
95
80
60
95
80
60
Calculations based on information contained in AP-42 (21).
^Uncontrolled floating roof tanks were assumed to have only primary seals.
Uncontrolled fixed roof tanks have no vapor recovery system and no internal
floating roof.
^Controlled floating roof tanks were assumed to have both primary and secondary seals.
Controlled fixed roof tanks were assumed to have internal floating roof covers with
secondary seals.
-------
Air Source Type 5
Evaporative Emissions
phenol and site-specific factors was available to allow the design, evalua-
tion and costing of these alternative control systems. As shown in Table 4-42,
only approximately 15% of the estimated controlled evaporative organic emissions
would be from fuel oil and phenol storage, after the installation of internal
floating roofs with secondary seals.
In Table 4-43, the capital investment and annualized costs for control of
evaporative emissions from storage of naphtha, fuel oil, and phenol are pre-
sented. For either the base case or the MFS case design, the total capital
investment cost for these controls corresponds to only 0.008% of the uncon-
trolled base plant cost. The annualized control cost for either EDS design
corresponds to less than 0.006% of the uncontrolled base plant cost.
384
-------
TABLE 4-43. COSTS OF CONTROL OF EVAPORATIVE EMISSIONS FROM PRODUCT AND BY-PRODUCT
STORAGE (STREAM 751)
OJ
00
en
Product
Base Case
Naphtha
Blended Fuel
Oil
Phenol
MFS Case
Naphtha
Blended Fuel
Oil
Phenol
Capital Investment Cost*
Total
Cost,
$ million
0.051
0.155
0.030
0.051
0.147
0.030
% of
Base
Plant
0.002
0.005
0.001
0.002
0.005
0.001
Unit Cost,
$ per kg/yr
product
recovered
2.9
1,270
387
2.9
1 ,310
389
Annual i zed Cost +
Total
Cost,
$ million
0.012
0.036
0.007
0.012
0.034
0.007
% of
Base
Plant
0.001
0.004
0.0007
0.001
0.004
0.0007
Unit Cost,
$ per kg
product
recovered
0.67
295
90
0.67
304
295
* The capital investment costs for control of evaporative emissions correspond to: 1) installation
of secondary seals for naphtha storage, 2) installation of internal floating roofs with secondary
seals for fuel oil and phenol storage. Costs were obtained from data presented in Reference 53.
The annualized costs were derived using methodology described in Section 4.1.3. The annualized
cost for control of evaporative emissions from naphtha storage is reduced by $4,600 for products
recovered. Credits for products recovered from control of evaporation emissions in fuel oil
and phenol storage are negligible.
-------
Air Source Type 5
Fugitive Organic Emissions
from Process Equipment
4.2.5.2 Fugitive Organic Emissions from Process Equipment
As discussed earlier, process equipment such as pumps, compressors, in
line valves, pressure relief devices, open-ended valves, etc., are prone to
leakage and thus are sources of fugitive organic emissions. Two methods can
be employed to control these emissions. A labor intensive method involving
leak detection and constant repair and maintenance can be used and/or equip-
ment can be employed which is designed to reduce the risk of leaks. Obvious-
ly, if equipment specification in addition to extensive leak detection and re-
pair 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 (52). Using this approach, controlled emission estimates for the
EDS based direct liquefaction facility under consideration were made. An
overall emission reduction of approximately 66% was estimated for leak detec-
tion/repair only, as shown in Table 4-44. These estimates were based on a
detection level of 10,000 ppmv, 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 (TCI) and
annualized costs for leak detection/repair only were estimated to be $39,000
and $65,000, respectively, using the labor requirements (Table A 18-7) and
equipment cost information provided in Appendix A-18. These costs correspond
to 0.001% of the base plant capital investment and 0.007% of the base plant
annualized costs.
The second approach is a step beyond the first in that it relies on equip-
ment specification in addition to leak detection, and repair and maintenance.
Monitoring requirements are similar to those for the first approach, except in
cases where equipment spcification eliminates the need for monitoring. On
applying equipment spcifications in addition to leak detection/repairs to an
386
-------
TABLE 4-44. FUGITIVE ORGANIC EMISSIONS FROM PROCESS EQUIPMENT
FOR EDS COMMERCIAL PLANT (WITH LEAK DETECTION/REPAIR
AND EQUIPMENT SPECIFICATION)
oo
00
—1
Uncontrolled
Components/ Emission
Service Factor Uncontrolled Emission Rates,
kg/hr/unit kg/hr
Pump Seal
Light Liquid Service
Heavy Liquid Service
In-Line Valves
Gas Service
Light Liquid Service
Heavy Liquid Service
Hydrogen
Safety Relief Valves
Vapor Service
Compressor Seal
Hydrocarbon
Hydrogen
Flanges
Drai ns
Light Liquid
Heavy Liquid
Totals
0.113
0.021
0.027
0.011
0.00023
0.0082
0.086
0.64
0.05
0.00025
0.032
0.045
8.8
3.4
32.4
19.5
0.8
4.2
21.7
36.2
0.9
6.5
4.8
13.6
153
Controlled Emission Rates,*
kg/hr
0-2.2
0-2.9
3.2
5.1
0.8
0.4
0-8.3
0-10.9
0-0.4
6.5
2.8
7.8
26.6-51.3
* The higher numbers in emission rates correspond to control by leak detection/repair methods only and the
lower numbers correspond to control by both leak detection/repair and equipment specification. Where a
single value is given, information on controlled emissions from equipment specification is not available.
-------
Air Source Type 5
Fugitive Organic Emissions
from Process Equipment
EDS commercial plant, an overall emission reduction of approximately 83% can
be achieved, with the combination of these two approaches, as shown in Table
4-44. The emission reduction was estimated on the basis of the following
equipment specifications: 1) installation of caps for all open-ended valves,
2) use of double mechanical seals on pumps and compressors, 3) use of flush
oil system for double mechanical seals, 4) installation of vents for compres-
sor and pump degassing reservoirs, 5) installation of rupture disks for re-
lief valves, and 6) use of closed loop sampling connectors. The capital in-
vestment costs for equipment specifications were calculated by multiplying
the number of these components required and the cost per component provided
in Appendix A-18 (2) (e.g., the capital investment cost for double mechanical
seals on pumps was derived by multiplying the number of pump seals given in
Table 3-73 by the installed cost (IEC) for each double mechanical seal), and
added to the capital investment cost for leak detection/repair. The annualiz-
ed cost for both leak detection/repair and equipment specification was calcu-
lated based on the labor requirements given in Appendix A-18 and the methodo-
logy described in Section 4.1»3. The capital investment (TCI) and annualized
costs for these combined controls were estimated to be $1.6 million and $0.66
million, respectively. These costs correspond to 0.05% of the base plant capi-
tal investment and 0.07% of the annualized base plant cost.
Detailed bases for the emission reductions and costs are provided in
Appendices A-18 (1) and A-18 (2).
388
-------
Air Source Type 6
Fugitive Particulates from
Material Conveying and
Processing
4.2.6 Source Type 6 - Fugitive Particulates from Material Conveying
and Processing
There is only one waste stream identified under Source Type 6:
• Stream 013 - fugitive particulates from coal handling and
crushing.
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 primar-
ily by the quantity and characteristics (size, specific gravity, moisture
content, etc.) of the material being handled, the transfer distance and ele-
vation, and conditions of the working environment. Loss of material from
conveyors is primarily at the feeding, transfer, and discharge points and
occurs due to spillage or windage. The majority of particulate emissions
are generally from spillage and mechanical agitation of the material at trans-
fer points.
Coal from storage piles is generally crushed, screened, and pulverized
prior to transfer to the boiler or EDS liquefaction area. Fugitive dust gen-
erated during this crushing and handling process is typically controlled by
either wet suppression techniques or dry particulate collection systems.
Wet suppression systems utilizing a wetting agent consist of pre-engineered
modules which incorporate both water handling components and automatic spray
controls. A typical spray solution contains 1,000 to 4,000 parts of water to
one part of a wetting agent. The rate of spray application is about 4 to 8
liters/Mg of material. This rate of application results in an increase of
total surface moisture by about 0.5 to 1.0%.
In wet dust suppression the fugitive particulate is first confined by a
curtain of moisture droplets. Then the wetting of dust takes place by contact
and penetration with moisture droplets. Finally, agglomerates are formed by
389
-------
Air Source Type 6
Fugitive Particulates from
Material Conveying and
Processing
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, depending upon the wetting agent utilized.
Dry particulate collection systems consist of enclosures to contain
the particulates, ductwork and exhaust systems to convey the contained parti-
culate laden air, and particulate collectors to separate the particulate from
the air. Typically, exhaust hoods can be used to capture particulate emissions
at transfer points. Conveyors generally have a half cover which provides dust
containment and also shields the conveyor from wind, rain and snow. Enclosure
sizing is a function of the source under consideration. The type of enclosure
used depends upon the particulate source. Typical ductwork velocities in ex-
haust hoods for particulate capture for different source types are readily
available. Dust collectors that are applicable to the collection of the cap-
tures particulate are: 1) venturi scrubbers, 2) electrostatic precipitators,
3) fabric filters, and 4) dry centrifugal collectors. These have been discussed
previously in Section 4.2.2.
390
-------
Water Pollution Control
4.3 WATER POLLUTION CONTROL TECHNOLOGIES
The EDS process generates many wastewater streams which may need various
forms and degrees of control prior to discharge or reuse. The commercially
available techniques that are potentially applicable to the EDS wastewater
streams are identified and evaluated in this section. The primary focus of
the material presented is on applying the control techniques to streams speci-
fic to the EDS process.
A conclusive and concise selection of one control technique over another
would require more data than is currently available as well as an in-depth
analysis of many site- and design-specific tradeoffs. Performing such an ana-
lysis is outside of the scope of this manual. In reviewing applications for
specific proposed new facilities, permit reviewers are encouraged to look care-
fully for evidence that proposed controls are supported by adequate treatability
and design data.
The applicability, performance, cost, reliability and other process re-
lated data reported here are based on engineering judgement, available litera-
ture data, and specifications and costs supplied by process vendors or licensors.
Areas of particular concern with respect to many of the control techniques like-
ly to be used in an EDS facility are identified throughout this section.
The presentation in this section is organized as follows. The waste streams
characterized in Section 3 are divided into two source types, based on their
characteristics and treatment requirements. The two source types are:
• Source Type 1 - Organic and Dissolved Gas-Containing Wastewaters
• Source Type 2 - Inorganic Containing Wastewaters
Under each source type, the generic approach in treating the streams is present-
ed, followed by an evaluation of the applicable control techniques -tfhen applied
to'each individual stream. Some integrated control examples are then discussed to
i^Tlustrate possible ways of combining the individual control techniques.
391
-------
Water Source Type 1
4.3.1 Source Type 1: Organic- and Dissolved Gas-Containing Wastewaters
Streams that fall into this source type include: a) streams that are
common to both the Base and MFS Cases.
Stream No. Stream Description
103 Slurry dryer cold separator wastewater
106 Liquefaction cold separator wastewater
152 Atmospheric fractionator overhead drum
wastewater
155 Vacuum fractionator overhead drum
wastewater
202 Solvent hydrogenation cold separator
wastewater
252 Solvent hydrogenation fractionator
overhead drum wastewater
308 Flexicoking fractionator overhead drum
wastewater
307 Flexicoking recontacting drum waste-
water
312 Flexicoking heater overhead drum
wastewater
403 Knockout drum wastewater in H? cryo
recovery
b) streams that are unique to the Base Case:
Stream No. Stream Description
430 Slowdown and K.O. drum wastewater from
Hp generation
431 Overhead receiver wastewater for AGR
in H- generation
452 Knockout drum wastewater in ammonia
synthesis
451 Aqueous ammonia from ammonia synthesis
392
-------
Water Source Type 1
c) streams that are unique to the MFS case:
Stream No. Stream Description
441 Sour water from partial oxidation unit
443 Slag filtrate from partial oxidation unit
In addition to these streams, certain secondary waste streams which also
belong to this source type will exist in a controlled EDS plant. Examples
of these include Beavon Sour Condensate and SCOT Sour Condensate. These
secondary streams are identified where the appropriate control techniques are
discussed (e.g., Section 4.2.1.1.2.1 for Beavon Sour Condensate) and they
could be treated along with the streams listed here.
As discussed in Section 3, these streams contain, among other pollutants,
high levels of phenols and/or dissolved gases such as ammonia and hydrogen
sulfide. Controlling these streams typically involves more than one techno-
logy arranged in series. Table 4-45 presents some summary information about
the commercially available treatment techniques that are potentially applicable
to these waste streams. While this list of control techniques is believed to
be fairly complete, it is by no means inclusive; other techniques may be avail-
able or may be developed which could also be applicable. The techniques pre-
sented in Table 4-45 are broadly divided into seven categories according to
their functions within the overall control sequence. The seven control areas
are:
1) suspended solids, tars and oils removal
2) bulk organics removal
3) dissolved gases removal
4) dissolved organics removal
5) residual organics removal
6) volume reduction, and
7) final disposal .
393
-------
able 4-45. SUMMARY OF CONTROL TECHNIQUES POTENTIALLY APPLICABLE TO THE TREATMENT OF EOS WASTEHATER CONTAINING PRIMARY DISSOLVED ORGANICS AND DISSOLVED GASES
CO
Techno1 ogy
Removal of Suspended
Gravi ty separation
- Parallel plate
Coagulation'
f 1 occulation
Air flotation
- Dissolved aT
- Induced air
"'"echno I ogy Pr i nci pie
Sol ids, Tars and Cnl s
Provision of adequate res-
vesse1 to allow suspended
sol •'ds or imp-isc ible
fluids to separate into
lighter and heavier tha^
water phases.
_se of agents to p"oT*ote
the coalescence of fine
suspended sol ids and
adsorption of tars and
01 1 s , general ly used in
iJse of air bubbles to pro-
mote the disengagement of
lighter- than-water mate-
Components Removed Removal Efficiency
Suspended solids, tars Depends upon design,
and oils. 10-50 removal of TSS
typical , 60-99 for oils.
:''3votes removal of finely Outlet suspended solids
dispersed particles, concentration to 10 mg/i
possible, oils removal of
60-95 .
Suspended oils and solids. Depends on characteristics
of source and treatment
process, TSS removal of
Feed Requirements/
Restrictions
Mininijm feed stream
turbulence.
A wide range of connercial
Air requirements depend
upon waste characteristics.
By-Products and
Secondary Waste Streams Comments
Recovered oils (Sp gr < 1), Incorporated into the tar/oil
sludges/solids (Sp. gr. >1) separation system design and tne
biological treatment syster
Sane as gravity separation. Widely used in water treat~ert
system to remove fine soilds
Recovered oils entrained, Widely used in various industries,
sol ids.
Passing waste^ater through Depends on filter mediur,
suitable filter med^r, both coarse and fine
fiMer Catena"1 discarded structure materials
or cleaned by backflushing, are used industrially,
20-75 , oil removals of
75-85..
TSS removals of 30-90+
011 removals of 65-90
Filter media (sand, clay,
fabric or polymeric
menbrane \
Filter backwash, soent
filter media.
Per-cval of Bui k Qrgamcs
Sol vent extraction
Extract" on of orga^ics
frorr wastewater via cor.
tact with an ir-iscib'e
solvent By-rroauct
organic liquids recovered
from the solvent in a
separate regeneration step.
-henols, TOC. BOD, COD
Ser,sit:.e to suspended
makeup sol vent.
Crude phenols, fiHer
backwash, spent fi1ter
redia.
Resin Adsorption
Selective removal of
nhpnril c uig COnt3Ct W
a solid medium (the
resins).
Phenols TOC, BOD, COD
Phenosolvan
- monohydnc phenol 99 5
- polyhydric phenol 60
- organic acids 15
Chem-Pro.
- monohydric phenol 99 8
- dihydric phenol 95'
- trihydric phenol 90-95
- other orgamcs 50-'
90+ removal of phenols, Acetone for regenerating Crude phenols.
Proposed for use as polish-i: ste:
for phenolic water downstrea- o*
tar/oi1 separation, "Sticky ta* s
oils may cause problems wtr ^^'re-'
plugging and regeneration
Cornercially proved in coke-^.e
industry and Lurgi gasificaf cr
plants First plant insta1 ec
Several commercial appl icafcrs
phenol formaldehyde resin "ar^f
turing plants First applicaf
in 1961 to recover phenol fro-
oven waste 1 iquor,
Commercially proven in organ-c
Lfiem tLd" industry.
{Continued}
-------
TABLE 4-45. (CONTINUED)
00
VO
en
Technology
Removal of Dissolved
Biological
oxidation
- act. sludge
- trickl ing f i 1 ter
- rotating
biol ogi cal
contacto-"
- lagoons
- high purity
oxygen (HPSAS)
Wet ai r oxidation
Ul traf 1 1 tration
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 0^
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 CH4 and other
hydrocarbons, digestion
process rel les upon
metabolic processes of
anaerobic organisms
Components
Removed
TOC, BOD, COD,
some i norgdni c
pol 1 utants
Same as biologi-
cal oxidation
except better-
destruction of
cyanides and
other difficult
to treat organics
can be achieved
Most effective
wi th high molec-
ul ar weight
o-'gani cs
TOC, BOD, COD
Removal
Ef f i ciency
Varies with waste
stream character-
i sti cs Typical
removal s .
BOD 60-90
COD, TOC 80
total phenol 95
org acids 95
oil & grease 70
CN- 70
Over 90- removal
of COD is possible
in a system with a
residence time of
1 hour or greater.
Actual eff i ciency
heavily dependent
upon waste char-
acteristics .
Up to 95
removal for total
organi cs
Unknown - thi s
process has not
been applied to
these types of
waste streams
Feed
Requirements/
Restrictions
Ai r or oxygen ,
suppl emental
nutrients may be
requi red , rela-
tively constant
feed temperature
and pollutant
loadings required
to minimize
"shocks" to
system
Ai r 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.
5700 per kg BOD
per day
Vent gases con-
taining CO, C02»
1 ight hydrocar-
bons , NhU , sul fur
species
Spent filter
media , concen-
trated
wastewater
Waste gases
(combustibl e,1
Comments
This is the basis for the
treatment of coke oven
wastewaters
Promising but not proven
this application, fairly
i n
rigorous materials of con-
struction requirements.
May be attractive as a or
concentration step prior
wastewater i nci ne ration
Kinetic limitations and
process control problems
could be substantial
e-
to
(Continued)
-------
TABLE 4-45, (CONTINUED)
OJ
10
echnol ogy
Renuval of Dissolve
Steam stripping
- chosa^-n
- Cnevror *'«'
Inert gas
Selective
absorpfon
Activated carbon
adsorption
Chemical oxidation
Technology Principle Components Removed
providing a positive flow HCN,, light hydrocarbons
of inert material (steam) (phenols,1,
through the wastewater,
and inorganics with ove1"-
head steam.
stnppea and NHo absorbed
by phosphate salts, NH3
recovered, scrubbed sour
;Unt
stripped in two stages with
the H2S and CO? reroved in
the f-rst stage, NH3
removed and subsequently
recovered in tne second
stage.
Sa-he as with stea^ except Sane as for steam
N2, 3i r or C02 is used as
the stripping medur".
ature stf-ppT.g process. stripping.
jsed in conjunction with N^3 with acid^ solu-
one of the above processes tions , ac^d gases (with
stripped gases,
Drgarrcs
Adsorption of orgamcs in Most effective with corn-
water by activated carbon plex orgamcs and phenols,
or polymeric resin, some heavy metal removal
powdered activated carbon expected.
has been used in conjunc-
tion with biological pro-
cesses (above with some
success in the organic
chemical industry.
Reaction of orgamcs in TOC, BOD, COO, oxidizable
peroxides or chlorine-
based oxidants.
Feed Requirements/
Removal Efficiency Restrictions
95-99 removal of "free" Feed preheat can be used
ammonia and acid gases to reduce steam require
typical , hydrocarbon ments, acid/caustic for
removal varies with vola- pH adjustment optional.
tility of stripped
components*
Removal to 150 mo/£ NH3
1 ntg/e. H2S, CO?, 95% HCN.
Removal to. 50 mg/jl NH^ ,
5 mg/4 H2S.
Same as for stear Generally operates at
stripping. stripping.
90 * removal of acid gases Makeup acid caustic.
or NH3 is typical.
Varies with wastestream Ad-orbent.
character] sties
Typical removal s
80D 60
COD 80
TOC 70
Phenols 99.9
org acids 70
CN 50
SCN" 50
Tars 99
oils 99
High removals achievable Oxidant,
depending upon conditions
of operation.
By-Products and
Secondary Waste Streams Comments
Stripped gases, uncondensed Acid/caustic addition can be
steam. used to improve the efficiency
of the stripping process.
Stripped gases, stripping The presence of an inert stripping
gas. gas as a diluent may nake it rore
difficult to handle or further
treat the gases stripped f--or the
wastewater.
Stripped gases. High energy requirements, not cost
ping steai- 1S readily available
Recovered NH3 or acid gases, ~his ~s the basis for several co"-
rich sorbent. mercially proven processes for
recovering high quality amron-a
Spent adsorbent regeneration Probably more effective as a no'^sn-
off-gases. ing rather than a bulk organ-cs
removal process
Vent gases, wastewater and Chlorine-based oxidants may cause
reaction products* problems with treated wastewater
(Continued)
-------
*S.E 4-45 (CONTINUED)
Techno!ogy
"echnology Principle
Components Removed
Removal Efficiency
Feed Requirements/
Restrict!ons
By-Products and
Secondary Haste Streams
Comments
Cooling tower
oxidation
Co^busfon of organics.
»'r oxidation 'and
stn pping , or orgamcs
ard dissolved gases.
All oxidizable organics Essentially complete
including conplex organics destruction of organics
such as ^AH's. in properly designed
system.
"CC, COD, BOD. phenols
and orgamcs, NH^-
Unknown - this process
has been tested using
SASOL wastewaters on a
pilot scale but results
are not available.
Supplemental fuel, precon-
centration will improve
performance and lower
supplemental fuel
reqin rements-
Sensitive to suspended
matter, oils, high TDSt
Flue gases.
Blowdown/drift.
This will be the most effective
process for removing organics but
the supplemental fuel requirements
may be substantial.
Treated wastewater use in small
refinery cooling towers has been
practiced - 75-80 reduction in
wastewater volume is common
Co
10
Meirb'-ane separation _se of sen pen^eable -elatwe rejection effi- 90-95 rejection of
- Reverse us-osis re-brane and pressure to ciencies Df the various dissolved salts
seoarate water frof its soluble spec'es will be Reductions in dissolved
d-'ssoJved constituents. dete1"- -~ed by ^e-^brane organics and BOD of up
character-sties and to 99 .
or cation-permeable operat 01.
"•e^b^anes with electric
*ield to separate -meral
ions fror water.
Forced evaporation Thermally induced e^a^or- i" 1 r.crvolat" 1 e ssecnes
ation of excess waste- ni?l '"e^a"1" in Drine.
water, condensate
recovery optional.
Cooling tower ^astev-ater used as All rcn.olati le species
concentration partial rrakeup to the concentrated ~nto the
cooling tower and there- blowdo^r.
by concentrated into the
blowdown
Surface discharge Wastes are conveyed to txtire strea-. 100
and r.ixed with a natural
water body.
Spent membrane material,
recovered water, brine-
Feed characteristics
limited by corrosion,
scaling, and biological
foul ing.
Restrictions are site-
specific depending on
local stream background
levels and applicable
water quality requirements.
Recovered condensate, non-
condensible gases, waste
brine.
vaDoration/drifU
May be useful as preconcentration
step prior to further treatment or
ultimate disposal of wastewater
Membrane scaling and fouling with
organics may limit the applicability
of this technology to the treatment
of process condensates
Very stringent materials
requirements, significant
energy requirements.
(Continued)
-------
TABLE 4-45. (CONTINUED)
CO
10
00
Technology
Surface "^Doundnient
Co-disDCsal
Technology Principle Components Reroved Removal Efficiency
isolated frcr1 a1! sj'-'ace
and groundwater supo^'es.
Wastes are held T, a cor- All nonvolatile species 100
tainrent basin, regain as residual in
Ash is quenched *-f> inf"~e stream. iOO
Feed Requirements/ By-Products and
Restrictions Secondary Waste Streams
filtered to 5 ir'icro-ete'-s
and have a low orgamc
content to prevent olug-
ging Wastes must not
precipitate in the well
or when mixed with sub-
surface fluids Volume
reduction prio1" to injec-
tion is often econorical
Concentrations of volatile Loss of volatile species.
species may need to be low
to prevent loss to the
atmosphere.
species -"ay need to be low
Comments
depends on the availability of
suitable subsurface formation.
Thi s technique is 1 ir.i ted to loca-
tions having available land and net
evaporation rates exceeding 0 5 "\yr
'20 in/yr)
by a solid waste d'srosa''
technique.
to prevent loss to the
atmosphere.
-------
Water Source Type 1
Although an integrated system for controlling some streams may often require
one technique from each of the functional areas arranged in the same sequence
as listed, this is not always the case. Depending on the characteristics of
the stream and the control requirements, an integrated control scheme may in-
clude individual techniques from only a few of the areas and/or may suggest
more than one individual technique from the same functional area. Coagulation/
flocculation + Gravity Separation and Chemical Oxidation (ozonation) + Carbon
Adsorption are good examples where more than one technique from the same area
might be combined in a treatment scheme.
The removal efficiency data presented in Table 4-45 are "typical optimum"
performances reported for industrial/municipal applications and are believed
to be reasonable estimates for the EDS wastewaters. In principle, any control
technique can be designed to remove the pollutants it is capable of removing
to any degree of efficiency. Likewise, a treatment scheme can be selected to
control a stream to any degree. However, primarily due to economic constraints,
a typical, or optimum removal efficiency is often used by process developers/
designers, and this may vary depending on the waste stream characteristics and
site-specific factors. For the same reasons techniques in different functional
areas are usually combined in typical arrangement; all techniques in one func-
tional area are not necessarily candidates for integration with each technique
in another area.
Control Function 1 includes those techniques that are capable of removing
tars and oils, and suspended solids. These materials may plug up other control
equipment or interfere with the control mechanisms. Thus, to protect the down-
stream control techniques or improve their efficiencies, Function 1 is generally
placed ahead of other processes. For costing purposes, this function is con-
sidered as part of the EDS process. The oils and tars removed are recycled
back to the process.
399
-------
Water Source Type 1
Control Function 2 includes those techniques that are applicable to treat-
ing wastewater with high phenol levels. This function may be placed ahead or
after Function 3 - Dissolved Gases Removal. Reversing the sequencing of these
two functions may generate different secondary waste streams. If Function 2
technique is placed ahead of Function 3, some of the dissolved gases will be
stripped during the residual solvent recovery step of the Function 2 extrac-
tion processes. If the sequence is reversed, some phenols and other volatile
organics will be stripped by the stripping step in Function 3. In either
approach, these components are recovered by minor adjustment of the auxiliary
equipment. The stripped dissolved gases may be routed to the ammonia recovery
unit to recover the ammonia; the stripped phenol may be recovered in a conden-
ser.
Due to the high levels of phenolics and dissolved gases in some EDS waste-
waters, they are good candidates for removal before other conventional treat-
ment techniques are applied. Phenol removal techniques include solvent extrac-
tion, resin adsorption and oxidation techniques. Both solvent extraction and
resin adsorption generally recover the phenolics in the waste stream while oxi-
dation destroys the phenolics. The solvent extraction and adsorption techni-
ques are expected to recover more than 95% of the phenolics in the EDS waste-
waters, and oxidation can destroy more than 90% of the organics. Dissolved
gases removal techniques generally employ a steam stripping step to remove
dissolved gases such as C0?, H?S and NH.,, and an absorption step to recover
ammonia from the stripped gases as by-product. These techniques are expected
to remove more than 99% of the CCL and H^S, recover the bulk of the ammonia,
and generate a stripper bottom stream with about 50 to 200 ppm NH,.
After the phenolics and dissolved gases are removed, other dissolved
organics can be destroyed by one of the dissolved organics removal techniques
(control function 4). These techniques include biological oxidation (biox)
which involves the use of microorganisms to breakdown the organic molecules;
other dissolved organics removal techniques include wet air oxidation.
400
-------
Water Source Type 1
Typically, biox techniques remove about 80% COD and TOC.
Biological processes are very sensitive to fluctuation in the incoming
wastewater characteristics such as pH, temperature, toxic chemicals, nutrients,
etc. Significant changes in any of these parameters could reduce the overall
treatment efficiency or even result in a complete shutdown of the system due
to destruction of microorganisms. Provision of adequate holding capacity
ahead of the bio-treatment system would reduce the effect of fluctuation in
waste characteristics and is a must in integrated treatment facilities. The
toxic and the synergistic effects of various pollutants on the biogrowth are
not completely known. However, raw EDS waste streams contain such high con-
centrations of phenol, ammonia, and hydrogen sulfide that they are likely to
be toxic. Thus, pretreatments to remove these constituents are required to
ensure proper operation of the bio system. In other words, Functions 2 and
3 would generally be placed ahead of Function 4 for those EDS streams high in
phenols and dissolved gases.
The residual organics removal techniques (Control Function 5) are either
physical sorption or chemical oxidation processes. These are considered
polishing steps and can remove 90% or more of the residual organics, depending
on the organic characteristics and process designs.
Volume reduction (Control Function 6) involves reducing the volume of
wastewaters that require further treatment or disposal. This is usually
achieved by either evaporating the water or concentrating the pollutants into
a much smaller volume by physicochemical means. A greater than 90% reduction
in waste volume can be achieved, depending on process selection and design.
This function is generally considered only for integrated wastewater systems
involving zero discharge or recovery and reuse of the wastewater.
Final disposal (Control Function 7) includes fundamentally different dis-
posal approaches which may be feasible for use at a given site, depending on
site-specific factors such as the availability of land, net evaporation rates,
401
-------
Water Source Type 1
groundwater reservoir characteristics, and surface discharge limitations. The
choice of disposal techniques will have profound impacts on the treatment tech-
niques selected for treating the waste streams since each disposal alternative
requires different levels of treatment to render the wastewater amenable to
disposal, reuse or discharge. For example, surface discharge of treated ef-
fluent may involve a combination of techniques from Function 1 through Function
5. If zero discharge is employed, the volume of the treated effluent from
Function 5 technique may be reduced using Function 6 technique. The brine
thus generated may be disposed in deepwells, surface impoundments (solar eva-
poration pond) or co-disposed with solid wastes.
The application of specific control techniques to the individual EDS
waste streams under Source Type 1 is discussed in the next section, followed
by some integrated control examples.
402
-------
Water Source Type 1
Combined Sour Water
Control Function 1 -
Suspended Solids, Tars
and Oil Removal
4.3.1.1 Combined Stream A - Combined Sour Water Stream
Combined Stream A consists of seven sour water streams which are present
both in the base case and the MFS case. These streams are:
« Stream 106 - Liquid Cold Separator Wastewater
• Stream 152 - Atmospheric Fractionator Overhead Drum Wastewater
• Stream 155 - Vacuum Fractionator Overhead Drum Wastewater
• Stream 202 - Solvent Hydrogenation Cold Separator Wastewater
• Stream 252 - Solvent Hydrogenation Fractionator Overhead Drum
Wastewater
0 Stream 307 - Flexicoking Recontacting Drum Wastewater
o Stream 308 - Flexicoking Fractionator Overhead Drum Wastewater.
These streams are generally combined for treatment because they all contain
high concentrations of H?S, NHL, CQy and phenols.
Table 4-46 presents the estimated characteristics of the combined stream;
the characteristics of the individual streams have been discussed in Section
3. Major species for which data/estimates are available for the seven indi-
vidual streams listed above are included in the Table. As presented in Section
3, more than 10 classes of organic compounds have been quantified in four of
the streams from pilot plant sampling (37). However, there are insufficient
data to allow a reliable estimation regarding the levels of these trace species
that would consistently be observed in commercial EDS streams.
With the exception of COD, TOC, TDS, and Oil and Grease, all data present-
ed in Table 4-46 are based upon Exxon design estimates (13). No COD, TOC, TDS
or Oil and Grease data are estimated in the Exxon design, but they were deter-
mined for Streams 106, 152, 155 and 252 in pilot plant sampling by EPA (37)
and Exxon (23). TOC and COD values in Combined Stream A are estimated by using
the data on the 4 of the 7 component streams for which pilot data are available
and assuming TOC and COD in the other 3 missing streams (202, 307 and 308) are
present in the same ratio to phenol in these 3 streams as in the other 4 streams
403
-------
TABLE 4-46. ESTIMATED CHARACTERISTICS OF STREAM A
COMBINED SOUR WATER STREAM
(1.134 Mg/hr Coal Feed EDS PI a nt]_
Components
H2S
NH3
co2
Phenols
Organic Acid
COD
TOC
Oil and Grease
TDS
Flow Rate, m3/hr
Concentration"*
Base Case
18,000
14,000
8,700
9,300
3,200
45,000
14,000
200
4,000
260
, mg/1
MFS Case
22,000
17,000
10,000
11 ,000
4,000
51 ,000
16,000
250
4,900
210
* All values except those for TDS, COD, TOC and Oil and Grease are based on
Exxon Design Estimates (13). TDS, COD, TOC and Oil and Grease values are
prorated from EPA and Exxon test results (23,37), and Exxon Design estimates,
404
-------
Water Source Type 1
Combined Sour Water
Control Function 1 -
Suspended Solids, Tars
and Oil Removal
sampled at the pilot plant. The TDS and Oil and Grease values in Combined
Stream A are estimated assuming their values in the 3 missing streams are
negligible.
4.3.1.1.1 Control Function 1 - Suspended Solids, Tars and Oil Removal
The combined waste stream will have about 200 ppm to 250 ppm of tars and
oils which may need to be removed prior to other treatment to ensure efficient
operation. Several techniques discussed below can be applied to achieve this.
4.3.1.1.1.1 Control Technique 1 - Gravity Separation
This technique operates under the principle that by providing enough
residence time in a quiescent reactor, the tars and oils will be separated
from the wastewater due to their difference in density. For rectangular or
circular type of separators wastewater is introduced into one end or the
center of the separator, flowed through a diffusion baffle and the length of
the separator. Oils and tars, which float to the surface, are pushed into
slotted pipes by flight scrapers. At the same time the flight scrapers push
any sludge deposits on the bottom of the reactor to sludge hoppers. For tilted
parallel plate type separators, the oil floats to the top of the plates (or
tubes) while the treated wastewater exits through the bottom of the plates.
See Appendix B-l for more detailed discussion of gravity separation. Based
upon related experience in refinery operations (54,55), this technique is
expected to remove 40 to 80% of the oils and tars in the Combined Stream A.
3
For treating a 260 m'/hr combined stream, the total annualized cost is esti-
mated to be 1.3<£/m3 (5<£/1000 gal.) (56).
Secondary Streams
In refinery and other industrial operations, gravity separation will
generate two secondary waste streams, namely, an oils and tars stream and a
settled sludge stream. However for Combined Stream A treatment, it is likely
405
-------
Water Source Type 1
Combined Sour Water
Control Function 1 -
Suspended Solids, Tars
and Oil Removal
that minimal or no settled sludge will be formed because the stream contains
only small amounts of suspended solids (less than 20 ppm). Thus only one
secondary waste stream is expected from this operation. However, the tars
present may have a density greater than water. Thus these systems should be
designed to handle settled tars. Assuming a 75% removal efficiency, and that
the oil skim pipes removes four times as much water as oil, the secondary
tars and oils stream generated will amount to 330 1/min (88 gal/min). This
stream can be incinerated or disposed with other wastewater treatment sludges.
See Appendix B-l for a more detailed discussion of gravity separation.
4.3.1.1.1.2 Control Technique 2 - Air Flotation
In air flotation, the removal of oil is achieved by dissolving air in the
wastewater under pressure and then releasing the air at atmospheric pressure
in a flotation tank. The released air forms tiny bubbles which adhere to the
oil globules surface, causing the oil to float to the surface where it is re-
moved by skimming. Flocculant aides such as polyelectrolytes, alum, ferrous
sulfate and lime are commonly added to improve the flotation process. Oil
removal efficiency of greater than 80% can be achieved with this technique (57)
For treating Combined Stream A, the total annualized cost is estimated to be
o
0.3
-------
Water Source Type 1
Combined Sour Water
Control Function 2 -
Bulk Organics Removal
through the filter media to the underdrain. Oil and other suspended matters
are trapped in the filter media and are later flushed out of the filter during
the backwash cycle.
In refinery operations, where the wastewater contains high levels of free
oils, filtration is generally applied as a secondary treatment, after gravity-
settling. However this may be used as primary treatment for the subject stream
since the stream contains relatively low suspended solids and oils. Based on
experiences from refinery operations, about 66 to 90% of the oil is expected
to be removed by filtration (56,57). The capital investment for treating
a 260 m3/hr Combined Stream A is estimated to be $470,000,or less than 0.01%
of the uncontrolled base plant cost (see Figure B-4-1 in Appendix B~4 for in-
stalled equipment cost and Table 4-1 for bases for converting installed equip-
ment cost to capital investment). The total annualized cost is estimated to
be $130,000/yr, or about 1% of the uncontrolled base plant cost.
Secondary Stream
Filtration generates one secondary waste stream, namely, the filter back-
wash. There are no data to estimate the characteristics of this stream. This
stream is generally recycled to sedimentation unit for treatment.
4.3.1.1.2 Control Function 2 - Bulk Organics Removal
The Combined Sour Water Stream contains high levels of soluble organics,
the bulk of which are phenolics (around 8,000 ppm to 10,000 ppm). The effect
of the Control Function 1 (Suspended Solids, Tars and Oil Removal) techniques
on these soluble organics is assumed to be minimal. The control techniques
most appropriate for treating this stream are solvent extraction and resin
adsorption processes which recover the phenolics, and oxidation processes
which destroy the phenolics and other COD exerting materials. It has been
reported that it is cost effective to recover phenol from wastewaters contain-
ing more than 2,000 ppm phenol (58). A study comparing applying solvent
407
-------
Water Source Type 1
Combined Sour Water
Control Function 2 -
Bulk Organics Removal
extraction, adsorption and biological oxidation to phenolic waste similar to
the Combined Sour Waste Stream indicated that solvent extraction is the most
economical of all three techniques (59). The following sub-sections evaluate
the applicabilities of two extraction processes (Phenosolvan and Chem-Pro),
one resin adsorption process (Rohm and Haas), and one oxidation process (Wet
Air Oxidation). As discussed before, these techniques can be placed ahead
of or after the Control Function 3 techniques.
4.3.1.1.2.1 Control Technique 1 - Phenosolvan Process
The Phenosolvan Process is a proprietary solvent extraction process
developed by the Lurgi Company. In this process the waste stream is filtered
with a sand filter and is then fed to a series of mixer-settlers where it con-
tacts a lean organic solvent (such as butyl acetate, isopropyl ether, and
Phenisol, a Lurgi proprietary solvent) (60) in countercurrent flow. The
solvent extracts the phenols from the wastewater, and after solvent-water phase
separation, the rich solvent is sent to a distillation column for solvent and
phenol separation. The extracted wastewater is stripped with nitrogen in a
packed tower to recover residual solvent and is then sent to subsequent treat-
ment.
The performance of the Phenosolvan process is dependent upon a number of
factors such as the characteristics of the wastewater, the number of extraction
stages and the solvent-to-wastewater ratio used. It has been estimated that
the process can remove 99.5% monohydric phenol, 60% polyhydric phenols and
15% of other organics (61). The breakdown of the phenolics in an EDS Combined
waste stream sample is about 90% monohydric and 10% dihydric (62). Thus, it is
expected that about 95% of the total phenols in EDS can be removed (see Table
4-47). This is consistent with performance of a Phenosolvan process operating
on Lurgi gasification wastewater (63). A more recent Phenosolvan design re-
covers the monohydric and polyhydric phenols in separate stages (64). This
design, when applied to the EDS wastewater, is expected to improve the overall
408
-------
TABLE 4-47. ESTIMATED COMPOSITION OF FEED AND TREATED EFFLUENT
FROM PHENOSOLVAN PROCESS (STREAM A)
Component
Phenols, mg/1
TOC, mg/1
COD, mg/1
Organic Acids, mg/1
3
Flow, m /hr
Base
Combined
Stream Feed
9,300
14,000
45,000
3,200
260
Case
Phenosolvan
Effluent
460
4,200
18,000
2,700
260
MFS
Combined
Stream Feed
11,000
16,000
51 ,000
4,000
210
Case
Phenosolvan
Effluent
550
4,800
20,000
3,400
210
Note: The single numbers (versus ranges) presented in this table represent a
specific set of design and operating conditions for the EDS plant and
for the control technique. Both cost and performance figures could
vary due to uncertainties in cost and performance estimates and due to
variations in design/operation of the EDS plant and of the control
technique. This note is equally applicable to other stream-specific
performance and cost tables in this section.
TABLE 4-48. SUMMARY OF COST ESTIMATES FOR PHENOSOLVAN
PROCESS* (STREAM A)
(1,134 Mg/hr Coal Feed EDS Plant)
Cost Item
Capital Investment
Total Annual ized Cost
% Uncontrolled Base Plant
Base
$8.96
$2.1
0.28
Case
x 106
x 106
MFS
$7.62
$1 .7 x
0.26
Case
x 106
106
Capital Cost|
% Uncontrolled Base Plant
Annual Cost ^
Unit Capital Investment
Unit Annualized Cost
0.22
$35,000/m /hr
$1.1 /m3
0.19
$36,000/m /hr
$1.0/m3
* See Appendix B-5 for detailed basis and assumptions
Cost estimates for uncontrolled base plant are presented in Section 2.3.
409
-------
Water Source Type 1
Combined Sour Water
Control Function 2 -
Bulk Organics Removal
phenol removal efficiency to at least 98% (64). The only available data on the
overall bulk organic removal efficiencies of the Phenosolvan process are ob-
tained from Lurgi gasification operations. It is known that the amount of or-
ganics removed is dependent upon the types of organics present. As presented
in Section 3, portions of the organics in Combined Stream A have been quanti-
fied. However, data on the Phenosolvan removal efficiencies for these specific
compounds are not available. Also, not all of the organics in the stream have
been identified. For lack of a better data base it is assumed that the organic
removal efficiencies for Combined Stream A are similar to those of the Lurgi
waste streams, i.e., 60% for COD and 70% for TOC (65).
The estimated capital and annualized costs for this process are summarized
in Table 4-48. The capital investment (TCI) shown in Table 4-48 is obtained by
multiplying the installed cost (IEC) by 1.8139. This factor includes contractor
overhead and profit, engineering and construction cost, contingency and interest
during construction (see Section 4.1 for details). The installed cost is
factored from data reported in the literature (see Figure B-5-2 of Appendix
B-5).
The capital investments for the base and MFS cases are 8.96 and 7.62
million dollars, or about 0.28% to 0.26% of the base plant costs, respectively.
The total annualized costs for the base case and MFS case are estimated to be
3 3
3.4 and 2.9 million dollars, respectively, or about $1.1 m' and $1.0/m of
Stream A flow: these figures were derived using the procedures summarized in
Table 4-2, and the utility/solvent requirements presented in Appendix B-5. In
estimating the annualized cost, recovered phenol is credited with its heating
value only (2.2
-------
Water Source Type 1
Combined Sour Water
Control Function 2 -
Bulk Organics Removal
Secondary Streams
The Phenosolvan process generates two waste streams: the treated effluent
and the recovered phenol. The estimated characteristics of the treated effluent
are presented in Table 4-47. It is not possible to estimate the characteris-
tics of the recovered phenol because of the potential presence of other organics.
Nonetheless, based on the removal efficiency, it is expected that the relative
breakdown among monohydric phenol/polyhydric phenol/organic acid in the com-
bined stream for the base case and MFS case will be 89%/6%/5% and 88%/6%/6%,
respectively.
4.3.1.1.2.2 Control Technique 2: Chem-Pro Process
The Chem-Pro dephenolization process is a proprietary process developed
by Jones and Laugh!in Corporation to recover phenols from coke-oven waste
liquors. Although the process is similar in many respects to the Phenosolvan
process, this process uses a vertical reciprocating plate extractor column
rather than a horizontal mixer-settler vessel to extract the phenols from the
wastewater.
In this process, the wastewater is pumped to the top of the extraction
column and the proprietary solvent is introduced to the bottom of the column.
As the wastewater descends the column, it mixes with the rising solvent. The
dephenolized wastewater is stripped with steam to recover residual solvents
before it is sent to subsequent treatment. The rich solvent is sent to a sol-
vent recovery column where the solvent is distilled off as overhead and the
phenols are removed as bottoms from the column.
The performance of the Chem-Pro process is dependent on a number of fac-
tors such as the characteristics of the waste stream, the solvent-to-waste
ratio and the column design. Approximate maximum removals of phenols from
feed waters are estimated by the process developer as: 99.8% removal of mono-
hydric phenol, 95% removal of dihydric phenol, 90 to 95% removal of trihydric
phenol and 50 +_ % removal of other organics, depending on the characteristics
411
-------
Water Source Type 1
Combined Sour Water
Control Function 2 -
Bulk Organics Removal
of the organics (60,66). The breakdown of the phenols in an EDS combined
wastewater is about 90% monohydric and 10% dihydric (62). Thus it is expected
that about 99% of the total phenols will be removed by this process (see Table
4-49). There is no data on the bulk organic removal efficiencies of this pro-
cess. Since the process principle is similar to the Phenosolvan process, the
TOC and COD removal efficiencies are assumed to be the same for the two process-
es.
The estimated capital and annualized costs for this process are summarized
in Table 4-50. Using the procedures summarized in Table 4-1 the capital invest-
ment is estimated based upon the installed equipment cost reported in the liter-
ature (60). The capital investment for the two cases are 12,4 and 10.8 million
dollars, or 0.39% and 0.37% of the base plant cost. Using the procedures sum-
marized in Table 4-2 and assuming the utility and other requirements are the same
as those for the Phenosolvan process, the total annualized costs for the base
and MFS case are estimated to be 2.6 and 2.2 million dollars or about $1.3/m
->
and $1.4/m , respectively. As discussed in Section 4.3.1.1.2.1, when estimat-
ing the annualized cost, recovered phenol is credited with its heating values
only (2.2<£/kg), which is much lower than its potential resale value (20<£/kg).
If the phenol were to sell for 20<£/kg, the base case and the MFS case will gen-
erate a profit of 0.75 and 0.70 million dollars per year, respectively.
Secondary Streams
The Chem-Pro process generates two waste streams: the treated effluent
and the recovered phenol. The estimated characteristics of the treated efflu-
ent are presented in Table 4-49. It is not possible to estimate the charac-
teristics of the recovered phenol because of the potential presence of other
organics. Nonetheless, based on the removal efficiency, it is expected that
the relative concentrations of monohydric phenol/polyhydric phenol/organic
acids in the combined stream for the base case and MFS case will be 77%/8%/15%
and 76%/8%/16%, respectively.
412
-------
TABLE 4-49-. ESTIMATED COMPOSITION OF FEED AND
TREATED EFFLUENT FOR CHEM-PRO
PROCESS (STREAM A)
(1,134 Mg/hr Coal Feed EDS Plant)
Component
Phenols, mg/1
TOC, mg/1
COD, mg/1
Organic Acids, mg/1
3
Flow, m /hr
Base
Combined
Stream Feed
9,300
14,000
45,000
3,200
260
Case
Treated
Effluent
93
4,200
18,000
1,600
260
NFS
Combined
Stream Feed
11 ,000
16,000
51,000
4,000
210
Case
Treated
Effluent
110
4,800
20,000
2,000
210
TABLE 4-50. SUMMARY OF COST ESTIMATES FOR THE CHEM-PRO
PROCESS (STREAM A)
Cost Item
Base Case
MFS Case
Capital Investment
Total Annual ized Cost
% Uncontrolled Base Plant
$12.4 x 106
$2.6 x 106
0.39
$10.8 x 106
$2.2 x 106
0.37
Capital Cost
% Uncontrolled Plant
Annualized Cost
Unit Capital Investment
Unit Annualized Cost
0.27
$48,000/rri /hr
$1.3/m3
0.24
$51 ,000/nT/hr
$1.4/m3
413
-------
Water Source Type 1
Combined Sour Water
Control Function 2 -
Bulk Organics Removal
4.3.1.1.2.3 Control Technique 3 - Resin Adsorption
While the solvent extraction technique removes the phenols from wastewater
with an organic solvent, resin adsorption techniques remove the phenol by a
solid medium (the resins). Resin adsorption is a cyclic process where phenol
is recovered from wastewater. The cyclic process consists of three steps:
adsorption on the resin, regeneration followed by a water rinse, and separation
of the regenerant (acetone) and the phenolic compounds by distillation. Ad-
sorption is carried out in resin beds where wastewater enters through the top
and exits through the bottom of the bed. Regeneration is achieved by rinsing
the bed with acetone (67).
The performance of the resin adsorption process is dependent on a number
of factors such as the characteristics of the waste stream, the bed loading
rate and bed height, and frequency of regeneration. It has been reported that
less than 10 ppm phenols in the treated effluent has been achieved when treat-
ing various industrial wastewaters with initial phenol concentration ranging
from a few hundred ppm to 10,000 ppm (67). There is no data on removal
efficiencies for organics other than phenolics.
The estimated capital and annualized cost for this process are summarized
in Table 4-51. The capital investment ranges from 8.7 to 9.9 million dollars
or about 0.31% of the base plant cost. The total annualized costs for the base
and MFS case are estimated to be 4.4 and 3.6 million dollars, or about $2.1/m
o
and $2.2/m , respectively. The capital cost is factored from reported litera-
ture value on a plant treating wastewater from a Bisphenol A manufacturing
plant (64). The high annualized cost for this process is due to the high
energy consumption during regeneration and distillation steps; (this is esti-
mated to be 250 Mg of steam/m of wastewater treated). As discussed in Section
4.3.1.1.2.1, when estimating the annualized cost, recovered phenol is credited
with its heating value only (2.2
-------
TABLE 4-51. SUMMARY OF COST ESTIMATES FOR THE RESIN
ADSORPTION PROCESS - STREAM A
(1,134 Mg/hr Coal Feed EDS Plant)
Cost Item Base Case MFS Case
Capital Investment
Total Annual ized Cost
% Uncontrolled Base Plant
Capital Cost
% Uncontrolled Base Plant
Annual ized Cost
Unit Capital Investment
Unit Annual ized Cost
$9.9 x 106
$4.4 x 106
0.31
0.46
$38,000/m3/hr
$2.1/m3
$8.7 x 106
$3.6 x 106
0.31
0.41
$41 ,000/m3/hr
$2.2/m3
Note: Capital investment is estimated using Table 4-1 and installed
equipment cost from Reference 67. Annualized cost is estimated
using Table 4-2 and the following utilities/chemicals requirements
derived from Reference 67: electricity - 0.87 kwh/m3, stream - 0.25
Mg/m3, acetone - 0.43/m3 and resin - $0.25/m3 of feed.
415
-------
Water Source Type 1
Combined Sour Water
Control Function 2 -
Bulk Organics Removal
Secondary Streams
The resin adsorption generates two secondary waste streams: the treated
effluent and recovered phenol. There is no data for either of these streams.
The treated effluent is expected to contain less than 10 ppm phenol.
4.3.1.1.2.4 Control Technique 4: Wet Air Oxidation
The wet air oxidation process works on the principle that under high
pressures and elevated temperatures reduced organic and inorganic substances
can be oxidized while remaining in the liquid stage. In this process waste-
water is pumped through a preheater where its temperature is raised to about
500°K (680°F) before entering the reactor. The process is carried out under
pressure (up to 208 MPa; 3000 psig) in order to prevent boiling and to increase
oxygen solubility. Compressed air or oxygen is added to the wastewater after
preheating.
The degree of oxidation achieved depends upon the retention time in the
reactor, the reactor temperature and pressure, and the material being oxidized.
When organic COD exceeds 15,000 mg/1 the process is autotherrnic and requires
no additional energy input. COD removals of greater than 90% have been report-
ed for this process (68). This process will oxidize both organics and inorgan-
ic COD, including conversion of sulfides to sulfate. Ammonia will pass through
unaffected. Table 4-52 summarizes the expected performance of this process
when applied to the EDS combined waste stream (see Appendix E5-6 for details).
One major advantage of this process is that complex organic molecules which
are not normally biodegradable will be destroyed, making the effluent more
amenable to biotreatment; this may also reduce the costs of biological treat-
ment if it is required. On the other hand, being an oxidation process, the
phenols in the EDS wastewater will also be destroyed and thus cannot be recover-
ed as salable by-product.
WAO requires high capital investment. Special materials of construction
(such as Hastelloy or titanium) are required for the reactor and high tempera-
ture exchangers because of the corrosive process environment.. Based on the
416
-------
TABLE 4-52. ESTIMATED COMPOSITION OF FEED AND TREATED
EFFLUENT FROM THE WET AIR OXIDATION PROCESS
- STREAM A (1.134 Mg/hr Coal Feed EDS Plant)
Component
Phenols, mg/1
TOC, mg/1
COD, mg/1
Organic Acid, mg/1
H?S, mg/1
0
Flow, m /hr
Base
Combined
Stream Feed
9,300
14,000
45,000
3,210
18,000
260
Case
Treated
Effluent
93
1,400
2,200
640
1 ,800
MFS
Combined
Stream Feed
11,000
16,000
51 ,000
4,000
22,000
210
Case
Treated
Effluent
110
1,600
2,500
800
2,200
Note: See Appendix B-6 for bases and assumptions.
417
-------
Water Source Type 1
Combined Sour Water
Control Function 3 -
Removal of Dissolved Gases
process vendor's estimates, the capital investments will be 72 and 63 million
dollars or $280,000/m /hr and $300,000/m /hr for the base case and MFS case,
respectively (69).
The wet air oxidation process produces no secondary waste streams other
than the treated effluent. The characteristics of this stream are presented
in Table 4-52.
4.3.1.1.3 Control Function 3 - Removal of Dissolved Gases
The Combined Sour Water Stream contains high levels of ammonia, H?S and
CCL. Removal of these gases at such high concentration ranges is normally
accomplished by steam stripping. In all existing or proposed coal conversion
facilities, stripping is aimed also at the recovery of ammonia for sale as a
by-product. This section evaluates two such processes: the Phosam-W Process
and the Chevron WWT Process. As discussed before, these techniques can be
placed ahead of or after Control Function 2 techniques.
4.3.1.1.3.1 Control Technique 1 - Phosam-W Process
In the Phosam-W Process, wastewater enters a steam stripper where free NH.,,
H?S, COp, HCN and volatile organics are stripped. The stripper overhead gases
then enter an ammonia absorber where lean ammonium phosphate solution contacts
the sour vapor, absorbing ammonia and small amounts of other gases. Stripped
wastewater leaves the bottom of the stripper. Rich ammonium phosphate solu-
tion is purged of acid gases in a contactor and sent to a stripper for ammonia
removal. The ammonia recovered is separated from water by distillation. The
other purged acid gases usually go to the sulfur recovery plant.
The process has been reported to be capable of removing NH., to below 200
ppm, and essentially all the H^S and CO^ (70,71). Table 4-53 presents the
characteristics of the influent and effluent streams, and also of the by-
product ammonia and the purged gases. The ammonia by-product stream, with a
418
-------
TABLE 4-53. ESTIMATED COMPOSITION OF FEED AND TREATED
EFFLUENT STREAMS FOR THE PHOSAM-W PROCESS
(1.134 Mg/hr Coal Feed EDS Plant)
Stream
Base Case
Combined Feed
Stripper Overhead
Recovered Ammonia
Treated Effluent
MFS Case
Combined Feed
Stripper Overhead
Recovered Ammonia
Treated Effluent
Component, kg/hr (mg/T)
H20 H2S C02 NH3 T
250,000
16,000
nil
230,000
200,000
16,000
nil
180,000
4,700
4,700
nil
nil
4,600
4,600
nil
nil
2,300
2,300
nil
nil
2,100
2,100
nil
nil
3,600
nil
3,600
50(200)
3,500
nil
3,500
40(200)
otal Flow
(m3/hr)
260
--
--
230
210
--
—
180
TABLE 4-54-
SUMMARY OF COST ESTIMATES FOR THE PHOSAM-W*
PROCESS
Cost Item
Base Case
MFS Case
Capital Investment
Total Annualized Cost (profit)
% Base Plant Capital Cost
% Base Plant Annualized Cost
Unit Capital Investment
Unit Annualized Cost (profit)
$10.8 x 10°
(1.56 x 106)
0.34
$42,000/m3/hr
($0.80/m3)
$9.52 x 10°
(1.05 x 106)
0.33
$45,000/m3/hr
($0.60/m3)
* Capital investment is estimated using the procedures summarized in Table 4-1
and the unit installed equipment cost presented in Figure B8-2 (Appendix B-8)
Annualized cost is obtained using bases presented in Table B8-2 and the unit
cost in Table 4-2.
419
-------
Water Source Type 1
Combined Sour Water
Control Function 3 -
Removal of Dissolved Gases
purity of 99.99% , can be sold as a product. The acid gas stream which con-
sists mainly of H2S and C02, is usually routed to the sulfur recovery plant
for sulfur recovery. The stripped wastewater, which contains about 200 ppm
NH3 and other contaminants, may require further treatment before disposal or
reuse.
Table 4-54 presents the capital and annualized costs for the Phosam-W
process when applied to the EDS Combined Stream. The capital investment is
factored from reported literature values (see Figure B-8-2 of Appendix B-8).
The detailed basis and assumptions for the cost estimates are presented in
Appendix B-8. As shown in Table 4-54 the capital investments are $10.8 and
$9.5 million for the base and MFS case, respectively. Because of the high
resale value of the ammonia recovered, which is assumed to be $140/Mg, this
process generates a net profit of $1.6 and $1.1 million/year for the two
cases. If there were no market for the ammonia, the annual cost would be $2.5
and $2.9 million per year, respectively, for the base case and MFS case.
Secondary Streams
The Phosam-W process generates three by-product/waste streams, namely an
ammonia by-product stream, an acid gas stream, and a stripped wastewater stream,
The characteristics of these streams have been presented in Table 4-53.
4.3.1.1.3.2 Control Technique 2 - Chevron WWT Process
In the Chevron WWT Process, hydrogen sulfide and ammonia in the sour
waters are stripped in two separate stages to produce gaseous streams suitable
for sulfur and ammonia recovery. Feed wastewater is fed to a reboiler strip-
per column (H,,S stripper) where hydrogen sulfide and carbon dioxide are strip-
ped. Stripper bottoms with the bulk of the ammonia are fed to a second re-
boiler stripper column (NH3 stripper) for ammonia stripping. The H-S strip-
per is operated at 690 KPa (100 psig) and 367°K (200°F), and the NH~ stripper
O
is operated at 345 KPa (50 psig) and 394°K (250°F) (71). Because H2S is more
420
-------
Water Source Type 1
Combined Sour water
Control Function 3 -
Removal of Dissolved Gases
insoluble in water than NH3, heating the H2S stripper to about 367°K (200°F)
causes the H?S but not the NFL to be released in that column. The overhead
from the NHo stripper is scrubbed with cold aqueous ammonia to remove traces
of HpS and is compressed and condensed to form anhydrous ammonia.
It is reported that the process is capable of producing a hydrogen sul-
fide stream with less than 50 ppm NH3, and less than 5000 ppm H^O; an ammonia
stream with less than 5 ppm H,,S; and a stripped water stream containing less
than 50 ppm ammonia and 5 ppm sulfide (72,73). Table 4-55 summarizes the
characteristics of these streams. The ammonia stream, with less than 5 ppm H^S
and 1000 ppm H?0, can be sold as by-product. The acid gas stream which con-
sists mainly of H?S and C0?, is usually routed to the sulfur recovery plant
for sulfur recovery. The stripped wastewater, which contains 50 ppm of NH~
and other contaminants, may require further treatment before disposal or reuse.
Table 4-56 summarizes the capital and annualized costs for the Chevron-
WWT process when applied to the EDS Combined Stream. The capital investment
is factored from reported literature values (see Figure B-9-2 of Appendix B-9).
The detailed bases and assumptions for the cost estimates are presented in
Appendix B-9. As shown in Table 4-56 the capital investments are $11.8 and
$10.7 million, respectively, for the base case and MFS case. The total annual-
ized costs are $2.2 and $1.4 million. This cost includes a credit of $14/Mg
for the ammonia recovered. If there were no market for the ammonia, the
annualized cost would be increased to $6.2 and $5.2 million per year.
Secondary Streams
The Chevron WWT process generates three by-product/waste streams, namely,
an ammonia by-product stream, an acid gas stream (from the H2S stripper) and a
stripped wastewater stream. The characteristics of these streams are presented
in Table 4-55.
421
-------
TABLE 4-55. ESTIMATED COMPOSITION OF FEED AND TREATED
EFFLUENT STREAMS FOR THE CHEVRON-WWT PROCESS
(1.134 Mg/hr Coal Feed EDS Plant)
Component,
Stream
Base Case
Combined Feed
Stripper Overhead
Recovered Ammonia
Treated Effluent
MFS Case
Combined Feed
Stripper Overhead
Recovered Ammonia
Treated Effluent
H20
250,000
30 (5,000)
4 (1,000)
200,000
200,000
30 (5,000)
4 (1,000)
200,000
H2S
4,700
4,
<1 (5)
1 (5)
4,600
4,600
<1 (5)
1 (5)
Kg/hr (mg/1) Tn
co2
2,300
2,
nil
nil
2,100
2,100
nil
nil
NH3
3,600
<1 (50)
3,600
10 (50)
3,500
<1 (50)
3,500
10 (50)
tal Flow
(m3/hr)
260
--
—
250
210
—
--
200
TABLE 4-56. SUMMARY OF COST ESTIMATES FOR THE CHEVRON-WWT
PROCESS*
Cost Item
Base Case
MFS Case
Capital Investment
Total Annual ized Cost
% Base Plant Capital Cost
% Base Plant Annual ized Cost
Unit Capital Investment
Unit Annual ized Cost
$11.8 x 106
$2.2 x 106
0.37
0.23
$45,000/m3/hr
$l.l/m3
$10.7 x 106
$1.4 x 106
0.37
0.15
$51,000/m3/hr
$0,84/m3
Capital investment is estimated using the procedures summarized in Table 4-1
and the unit installed equipment cost presented in Figure B9-2 (Appendix B-9)
Annualized cost is obtained using the bases presented in Table B9-3 and the
unit cost presented in Table 4-2.
422
-------
Water Source Type 1
Combined Sour Water
Control Function 4 -
Removal of Dissolved Organics
4.3.1.1.4 Control Function 4 - Removal of Dissolved Organics
Table 4-57 summarizes the estimated characteristics of the Combined Stream
A after Function 2 and 3 controls. The ranges for the various species shown
result from the ranges of performances by the different alternative Function
2 and 3 techniques. As shown, the stream still contains high levels of organ-
ics. Common practice to remove dissolved organics is by some form of biologi-
cal treatment. In simple terms, biological treatment is a process which pro-
vides an environment conducive to microorganism reduction of organic materials
in the wastewater. There are many versions of biological treatment processes
that are commercially available. These include trickling filters, rotating
biodiscs, oxidation ponds/lagoons, and various modifications of activated
sludge. Of all these processes, activated sludge is the most studied for use
in treating coal conversion wastewaters and is the most commonly used in exist-
ing industrial and municipal applications. There is generally more information
on this process than other processes. In actual application, an optimum bio-
logical system could be a combination of these processes. For example, it has
been proposed that using a trickling filter ahead of an activated sludge system
would reduce the overall control cost (74). However, design and performance
data for these processes are generally lacking. For these reasons, activated
sludge is the only process evaluated in this section as an example of biologi-
cal treatment processes.
4.3.1.1.4.1 Control Technique 1 - Activated Sludge Process
All activated sludge processes employ one or more reactors in which aero-
bic microorganisms feed on the organic matter present in the wastewater. These
microorganisms form colonies which ultimately appear as a sludge which must be
separated from the wastewater. A portion of the settled sludge is returned to
the reactor as needed to insure a sufficient population of microorganisms in
the reactor. Air or oxygen is mixed into the reactor to provide an adequate
supply of oxygen for the overall oxidation process.
423
-------
TABLE 4-57. ESTIMATED CHARACTERISTICS OF COMBINED
STREAM A AS FEED TO CONTROL FUNCTION 4
(1,134 Mg/hr Coal Feed EDS Plant)
Estimated Concentration, mg/1 *
Component
H2S
NH3
co2
Phenols
Base Case
<5
50 - 200
nil
93 - 460
MFS Case
<5
50 - 200
nil
110 - 550
Organic Acid 640 - 2,700 800 - 3,400
COD 2,200 -18,000 2,500 -20,000
TOC 1,400 - 4,200 1,600 - 4,800
Flow, m3/hr 260 210
After Functions 2 and 3 controls.
424
-------
Water Source Type 1
Combined Sour Water
Control Function 4 -
Removal of Dissolved Organics
Biological treatment of coal conversion process wastewaters has not been
demonstrated on a commercial basis. Bench scale studies by several investi-
gators have proven the feasibility of air activated sludge systems when applied
to wastewaters from several gasification and liquefaction processes (75-82).
COD levels in these studies run as high as 12,000 mg/1. COD feed to commercial
scale activated sludge plants treating domestic or industrial wastes generally
range from several hundred mg/1 to several thousand mg/1. In an actual EDS
wastewater treatment plant, dilution of the combined stream may be required.
This can be accomplished by recycling a portion of the treated effluents or
combining with other wastewaters such as cooling tower blowdowns. In addition,
the activated sludge system will likely be a multi-staged system, and high
purity oxygen or activated powdered carbon will likely be used to enhance the
stability of the system. Nutrients such as phosphorus will need to be added.
Table 4-58 summarizes the anticipated performance of this process. Since
no EDS wastewater treatability data are publicly available, 80% removal for
both the COD and TOC contents were assumed. This is consistent with several
bench scale studies treating different coal conversion process wastewaters (75-
82). See Appendix B-10 for more details.
The ammonia concentration in the treated effluent is dependent on the
ammonia level in the feed to the biox system and the degree of nitrification
(conversion of ammonia to nitrite/nitrate) in the reactor. The optimum organic
to nitrogen ratio in the feed to biox systems is about 20:1. As shown in
Table 4-58, this ratio is much higher in the EDS streams, i.e., nitrogen is
the limiting nutrient and it must be added to the feed. The level of ammonia
in the feed to the biotreatment unit may be adjusted by changing the design
of Control Function 3 technique (ammonia recovery techniques), or by adding
compounds such as ammonium nitrate and ammonium sulfate. The effluent ammonia
concentration would thus depend on how much 'excess1 ammonia is added. It is
expected that much of the 'excess1 ammonia will be nitrified since long
425
-------
TABLE 4-58. ESTIMATED COMPOSITION OF FEED AND
TREATED EFFLUENT FOR THE ACTIVATED
SLUDGE PROCESS - STREAM A
(1,134 Mg/hr Coal Feed EDS Plant)
Component
COD, mg/1
TOC, mg/1
Phenol , mg/1
Organic Acid, mg/1
NH3, mg/1
Flow, m /hr
Base
Combined
Stream Feed
2,200-18,000
1,400- 4,200
93 - 460
640-2,700
50 - 200
260
Case
Treated
Effluent
440-3,600
280 - 840
5 - 23
32-140
10
260
MFS
Combined
Stream Feed
2,500-20,000
1 ,600- 4,800
110 - 550
800- 3,400
50 - 200
210
Case
Treated
Effluent
500-4,000
320 - 960
6-28
40-170
10
210
TABLE 4-59. SUMMARY OF COST ESTIMATES FOR THE
ACTIVATED SLUDGE PROCESS*
Cost Item
Capital Investment
Total Annual ized Cost
% Uncontrolled Base Plant
Base Case
$20 x 106
$ 4.9 x 106
0.63%
MFS Case
$16 x 106
$ 4.2 x 106
0.56%
Capital Cost
% Uncontrolled Base Plant
Annualized Cost
Unit Capital Investment
Unit Annualized Cost
0.52%
$77,000/nr/hr
$ 2.4/m3
0,47%
$ 76,000/nT/hr
$ 2.5/m3
* Capital investment is estimated from top curve in Figure BlO-2
(Appendix B-10), using BOD loading values of 79,000 Kg/day and
71,000 Kg/day, respectively, for the base and MFS case (BOD was
assumed to be 0.7 x COD). Annualized cost is derived from Figure
B10-3 and assumptions presented in Table 4-2.
426
-------
Water Source Type 1
Combined Sour Water
Control Function 4 -
Removal of Dissolved Organics
residence time in the bioreactor will be required to handle the organics.
However, some residual ammonia will likely be present in the effluent. For
this study, this is assumed to be 10 mg/1.
The capital investment and total annualized costs for the two cases are
summarized in Table 4-59. The values presented are the costs required to
treat the higher concentration range of organic (i.e., the worst case) as
shown in Table 4-58. The capital investment for the two cases are 20 and 16
million dollars, or about 0.63% and 0.56% of the base plant cost. The total
annualized costs are 4.9 and 4.2 million dollars per year, or about $2.4 and
3
$2.5/m of treated water.
Secondary Streams
The activated sludge process generates a secondary waste stream, namely,
the waste sludge. This stream is generally stabilized by anaerobic digestion,
dewatered to 20 to 40% solid and then disposed. This stream may also be sta-
bilized by aerobic digestion and incineration. The amount of dewatered sludges
generated in the base case and MFS case are estimated to be, respectively, 100
and 80 metric ton per day. The sludge is assumed to contain 80% moisture and
20% solid. The bulk of the solids are bacterial cell walls. Depending on the
characteristics of the feed to the biox system, some toxic nonbiodegradable
organics such as PAH's may also be accumulated in the sludge through sorption
mechanisms.
4.3.1.1.5 Control Function 5 - Removal of Residual Organics
Available data on several coal conversion process wastewaters indicate
high ratios of COD/BOD in the raw wastewater. This is believed to be caused
by the presence of high molecular weight, complex, refractory organics. Al-
though there is no data on the full characterization of Combined Stream A, it
is likely that the stream will contain many nonbiodegradable organic molecules.
These molecules will remain in the stream unless specific treatment processes
427
-------
Water Source Type 1
Combined Sour Water
Control Function 5 -
Removal of Residual Organics
are employed for their removal. This section evaluates three techniques for
removing these organics. Feed wastewater to these techniques will generally
be treated effluent from biox system (see Table 4-58).
4.3.1.1.5.1 Control Technique 1 - Activated Carbon Adsorption
Activated carbon adsorption is one of the most efficient and commercially
proven methods of removing organics from industrial wastewaters. Primarily
for economic reasons, it is generally used as a "polishing" step after the
majority of the organics are removed by other processes. The application of
activated carbon may be carried out by two methods: (1) the use of powdered
activated carbon in conjunction with a biological treatment or other mixed
unit and (2) the direct contact of granular activated carbon (GAC) with con-
taminated wastewaters following biox. The direct contact method will be evalu-
ated in the remainder of this section because this is the most widely used
approach and because most of the available performance data on activated car-
bon systems are for this application.
Removal of organics with granular activated carbon is accomplished by
passing the wastewater through a packed bed of the adsorbent. The adsorptive
capacity of the bed is a function of the wastewater's organic loading and con-
tact time in the bed, and the affinity of the carbon for the organics. Differ-
ent types of activated carbon can generally be selected to obtain high percen-
tage removals of various organic compounds. Carbon can act as both an adsorp-
tion medium for smaller organic molecules and a filter for long chain, high
molecular weight molecules. Carbon removal efficiency is riot sensitive to
changes in organic loading. But, organic concentrations above design loadings
can significantly increase regeneration frequency and the energy requirements
for operating the system.
428
-------
Water Source Type 1
Combined Sour Water
Control Function 5 -
Removal of Residual Organics
The characteristics of the treated effluent stream is presented in Table
4-60. Also presented in the table are the characteristics of the feed to the
activated carbon system. This feed is assumed to be the Combined Sour Stream
after going through Function 4 control. Since detailed organic characteris-
tics of the feed is not known and no treatability data are available, the table
is constructed based on available literature data on other related waste
streams (83-86). It should be emphasized that the removal efficiency is very
sensitive to the characteristics of the waste stream. Actual performance on
Combined Stream A can only be established by treatability studies with the
actual stream.
The capital investment and annualized cost for this process are summar-
ized in Table 4-61. The values presented are the costs required to treat the
higher concentration range of organics as shown in Table 4-60, i.e., the worst
case. The capital cost, which includes the thermal regeneration system, are
2.7 million dollars for both cases. The total annualized costs are 1.5 and
1.4 million dollars for the base case and MFS case, respectively; or about
$0.73/m3 and $0.93/m3 of treated water.
Secondary Streams
Activated carbon adsorption system requires regeneration when the adsorp-
tive capacity of the bed is reached. Thermal regeneration is the most common
system used. Most of the organics adsorbed by the carbon are expected to be
destroyed during regeneration. During regeneration an off-gas stream is gen-
erated. This stream is expected to contain particulates, CO and other consti-
tuents, depending on the organics adsorbed. It is common practice that scrub-
bers are included as part of the regeneration system. Thus the particulate
contents in the off-gas leaving the regeneration is expected to be minimal.
The scrubber wastewater is typically settled or routed to other treatment
before disposal.
429
-------
TABLE 4-60.
ESTIMATED COMPOSITION OF FEED AND TREATED
EFFLUENT FOR THE ACTIVATED CARBON ADSORPTION
PROCESS - STREAM A
(1,134 Mg/hr Coal Feed EDS Plant)
Component
COD, mg/1
TOC, mg/1
Phenol , mg/1
Organic Acid, mg/1
Flow rate, m /hr
Base
Influent
440
280
5
32
- 3,600
- 840
- 23
- 140
260
Case
Effluent
44
28
0
10
- 360
- 84
.05-2
- 40
260
MFS Case
Influent
500
320
6
40
- 4,000
- 960
28
- 170
210
Effluent
50
32
0
12
- 400
- 96
.06-3
- 50
210
TABLE 4-61. SUMMARY OF COST ESTIMATES FOR THE
ACTIVATED CARBON ADSORPTION PROCESS*
Cost Item
Capital Investment
Total Annual ized Cost
% Base Plant Capital Cost
% Base Plant Annual ized Cost
Unit Capital Investment
Unit Annual ized Cost
Base Case
$ 2.7 x 106
$ 1.5 x 106
0.09%
0.16%
$10,000/m3/hr
$ 0.73/m3
MFS Case
$ 2.7 x 106
$ 1.4 x 106
0.09%
0.15%
$13,000/m3/hr
$ 0.86/m3
* Capital investment is obtained by using the procedure summarized in Table
4-1 and summing the installed equipment cost for absorption contactor
(Figure B15-1, Appendix B-15) and regeneration furnace (Figure B15-3),
contactor volumes of 130 m^ and 105 m^ were used for the base case and MFS
case, respectively. These volumes were derived assuming an empty bed con-
tact time of 30 minutes. Carbon regeneration rates for the two cases were
determined assuming a carbon adsorption capacity of 0.5 Kg COD/Kg carbon.
Annualized cost was determined using the utility and-other requirements
summarized in Appendix B-15 and the unit costs presented in Table 4-2.
430
-------
Water Source Type 1
Combined Sour Water
Control Function 5 -
Removal of Residual Organics
4.3.1.1.5.2 Control Technique 2 - Chemical Oxidation
Chemical oxidation, as its name implies, is simply the oxidation of waste-
water contaminants, both organic and inorganic, to more environmentally accept-
able forms. In practice, the wastewater is introduced to one or several reac-
tors where chemical oxidants are added. Common chemicals used included chlor-
ine, ozone, hydrogen peroxide, potassium dioxide and chlorine dioxide. Some
recently developed processes employ ultraviolet (UV) light with one other
strong oxidant such as ozone, hydrogen perioxide or chlorine. The UV light
would excite the organic molecules, making them more susceptible to the chemi-
cal oxidant attack. Due primarily to economic reasons, chemical oxidation
process has been limited to use as a polishing step, treating low concentra-
tion waste streams.
The performance of chemical oxidation is dependent on a number of factors
such as the waste stream characteristics, the chemical and the dosage used, and
reactor design. Greater than 90% removal in various types of industrial waste-
water have been reported (87-89). However, no treatability test data on the
EDS wastewater are publicly available. Nevertheless, in principle, any degree
of removal can be achieved if enough chemicals and detention time are provided,
and the waste is oxidizable. However, treating the subject stream to any sig-
nificant degree could incur high costs. As presented in Table 4-58, the COD
of feed to this system may be as high as 3,600 ppm and 4,000 ppm for base case
and MFS case, respectively. Theoretically, 3 kg of ozone is required to re-
move 1 kg of COD. Applying ozone as treatment to this stream would incur capi-
tal investments of 97 and 87 million dollars for the two cases, or about
$370,000/m3/hr and $410,000/m3/hr; the annualized costs would be $42 and $38
3 3
million dollars, or about $20/m and $23/m . These costs are developed using
the assumptions presented in Tables 4-1 and 4-2, and the installation costs,
electricity requirement and oxygen requirement estimates presented in refer-
ence 89. If chlorine is used, theoretically, 4.5 parts chlorine are required
431
-------
Water Source Type 1
Combined Sour Water
Control Function 5 -
Removal of Residual Organics
for each part of COD removed. Assuming a chlorine cost of $180/Mg (89), just
the annual chlorine costs alone would amount to 6 and 5 million dollars for the
two cases. Chemical oxidation is further discussed in Appendix B-16.
4.3.1.1.5.3 Control Technigue 3 - Incineration
Incineration involves oxidizing the organics at high temperature. Most
organics can be destroyed at 1000°C with two seconds residence time. In prac-
tice, wastewater is injected into the incinerator through a liquid injection
system where the organics are destroyed. The flue gas leaving the incinerator
is cooled and quenched before discharge to the atmosphere.
Incineration is generally economical only for treating low volume, high
strength wastes because of the costs of auxiliary fuel and the equipment
required in order to heat and vaporize the entire mass of wastewater (90,91).
Approximately 2500 Kcal of energy is required to incinerate one kg of waste-
water (92). Thus, when incineration is applied to removing residual organics
in the Combined Sour Water Stream, some form of volume reduction prior to
incineration may be required. Table 4-62 presents the estimated feed and
treated effluent from the incinerator. It is assumed that the feed is the
treated effluent from Function 4 controls, and have been concentrated ten
times. The concentration technique is discussed in the next section (Function
6). The effluent composition (after re-condensation) corresponds to 99.9
percent destruction of thermally oxidizable constituents. As discussed in
Appendix B-17 incineration is capable of greater than 99.96% destruction of
many organic compounds. The 99.9% destruction efficiency shown in Table 4-62
is therefore felt to be a conservative estimate.
The capital investment and the annualized cost for this process are sum-
marized in Table 4-63. The detailed basis and assumption for the cost esti-
mates are presented in Appendix B-17. The capital investment, which includes
the quench and scrubber system, are 5 and 4.6 million dollars for the base
case and MFS case or about 0.16% of the base plant cost, respectively. The
432
-------
TABLE 4-62 .
ESTIMATED COMPOSITION OF FEED AND TREATED
EFFLUENT FOR WASTEWATER INCINERATION -
STREAM A(1,134 Mg/hr Coal Feed EDS Plant)
Base Case
MFS Case
Component
Combined
Stream Feed*
Treated
Effluent
Combined
Stream Feed*
Treated
Effluent
NhL, ppm
Phenol , ppm
TOC, ppm
COD, ppm
Organic Acid, ppm
TDS
Flow Rate, M3/hr
100
230
8,400
36,000
1,400
40,000
26
0.1
0.23
8.4
36
1.4
40,000
26
100
280
9,600
40,000
1,700
49,000
21
0.1
0.28
9.6
40
1.7
49,000
21
*Assumed to be 10-fold concentration of treated effluent from function 4.
TABLE 4-63. SUMMARY OF COST ESTIMATES* FOR THE
WASTEWATER INCINERATION
Cost Item
Capital Investment
Total Annual ized Cost
% Base Plant Capital Cost
% Base Plant Annual ized Cost
Unit Capital Investment
Unit Annual ized Cost
Base Case
$5.0 x 106
$5.2 x 106
0.16%
0.55%
$190,000/m3/hr
$25/m3
MFS Case
$4.6 x 106
$4.3 x 106
0.16%
0.48%
$220,000/ta3/hr
$26/m3
* Capital investment is estimated using the procedures summarized in Table
4-1 and the installed equipment cost presented in Figure B17-2 (Appendix
B-17). Incinerator duties of 650 x 106 Kcal/hr and 530 x 106 Kcal/hr are
assumed for the base case and MFS case, respectively. Annualized cost is
estimated by using the bases presented in Table 4-2, and the following
utility and labor requirements: 2500 Kcal of fuel/Kg of water and 2 person/
shift. 433
-------
Water Source Type 1
Combined Sour Water
Control Function 6 -
Volume Reduction
3
total annualized costs are 5.2 and 4.3 million dollars, or about $25/m to
o
$26/m of treated water.
Secondary Streams
The only secondary waste stream is the incinerator flue gas. This stream
may contain SCL, NOX and particulates. The major contribution to the S02 and
NO is likely from the fuel used. The particulates may come from the fuel and
A
from dissolved solids in the wastewater. Since control for this stream is con-
sidered as part of the incinerator system*, no estimates on the characteris-
tics or cost are presented for this stream.
4.3.1.1.6 Control Function 6 - Volume Reduction
Volume reduction is one form or part of a water reuse scheme. Water re-
use is generally practiced in arid regions where water is scarce, or regions
where surface discharge requirements are very stringent (such as no discharge)
and other disposal capacities (such as underground injection) are limited.
This function involves concentrating the pollutants into smaller waste streams
for further treatment or disposal; water of different qualities may be recover-
ed for reuse in the process, depending on the techniques used and the feed
characteristics. To prevent excessive air emission of volatile contaminants
and to ensure the water recovered is of reasonable quality, this function is
likely used after or in lieu of Function 5.
4.3.1.1.6.1 Control Technique 1 - Cooling Tower
Based upon the availability of cooling water at the plant site, the use
of process wastewater as partial or total feed to the cooling tower may be
practiced. This practice results in a reduction in the waste stream volume
* Of the 83 installed incinerators designed to burn aqueous waste containing
sodium salts, 80 have a quench tank followed by a venturi scrubber, 3 have
electrostatic precipitators (91).
434
-------
Water Source Type 1
Combined Sour Water
Control Function 6 -
Volume Reduction
due to evaporative concentration in, and drift from, the cooling tower. Cool-
ing towers typically run in 4 to 5 cycles of concentration, representing a
75 to 80% volume reduction, i.e., 75 to 80% of the water is evaporated.
It is likely that the Combined Sour Water Stream would at least undergo
Functions 2, 3 and 4 controls and probably Function 5 control, before being
used as cooling tower makeup. Using the untreated stream would generate ex-
cessive air emissions from the cooling tower of volatiles such as phenol, FLS
and NH., contained in the stream. Drift could contain even the non-volatile
species. Also, although cooling tower is conducive to organics reduction due
to biological activities, passing the non-biologically treated stream through
the cooling tower would also increase potential for fouling process heat ex-
changers by wastewater contaminants such as biological solids, and by exces-
sive biogrowth. To overcome this problem, redundant heat exchangers would
possibly be required to maintain operating reliability. These redundant heat
exchangers would be designed in such a way so that individual heat exchangers
could be isolated and backflushed while the back-up system is on-line (93). The
redundant heat exchanger design and the isolation and capability which has been
used in one refinery operation (93) would greatly increase the EDS base plant
cost and likely offset any cost savings for using the untreated stream as make-
up.
The cooling operation is an integral part of the process waste heat re-
jection system and is thus part of the base plant. It was assumed that no
additional costs to the plant are incurred as a result of using the cooling
tower as a wastewater concentrator.
Secondary Stream
Cooling tower operation generates three streams: evaporation, drift and
blowdown. Assuming all the volatile components of the waste stream have been
removed by Function 2, 3, 4, and possibly 5 controls, water evaporated from
the cooling tower is expected to be relatively clean, but could contain traces
435
-------
Water Source Type 1
Combined Sour Water
Control Function 6 -
Volume Reduction
of the non-volatile species. The drift and the blowdown are expected to be
similar in composition and would depend on the make-up characteristics and
cycles of concentrations the cooling tower is operating at. To improve the
quality of these two streams, Function 5 techniques can be used ahead of the
cooling tower. Table 4-64 presents the estimated characteristics of these
streams. The feed ranges shown in Table 4-64 cover the ranges of treated
effluents from Function 4 (in the event that 5 is not employed) and from
Function 5. The cooling tower is assumed to be using exclusively the treated
wastewater as make-up, and is operated at 4 cycles of concentration. The drift
and the blowdown are assumed, respectively to be 0.03% and 3% of the circulat-
ing water. These are typical design/operating numbers for cooling towers (92).
4.3.1.1.6.2 Control Technique 2 - Vapor Compression Evaporator
Vapor compression evaporator is used as an example of reducing the volume
of wastewater by forced evaporation. Other commercially available force eva-
porators include multi-effect and multi-stage evaporators. Although costs and
performances vary among these different designs, for the purpose of this manu-
al, they would probably fall into the same ranges.
The vapor compression evaporator supplies vaporization energy by a mech-
anical compressor, rather than an external heating medium. The wastewater
feed is first treated in a feed tank to adjust the pH to carbon dioxide for
removal in a deaerator. The waste stream is then pumped through a feed-
product heat exchanger to raise its temperature to about its atmospheric boil-
ing point. The heated feed then enters a counterflow packed column deaerator
which strips carbon dioxide, nitrogen, and oxygen.
Next, the feed enters the evaporator sump and is mixed with concentrated
slurry. The brine slurry is constantly circulated from the sump to the top of
the evaporator tubes. At the top of the vertical-tube, falling film evapora-
tor, the brine slurry is distributed to the inside wall of the tubes. The
slurry flows as a film on the inside of the tubes down to the sump. As the
436
-------
TABLE 4-64. ESTIMATED CHARACTERISTICS OF FEED AND
EFFLUENTS FOR THE COOLING TOWER OPERATION
(1,134 Mg/hr Coal Feed EDS Plant)
Component
H2S
NH3, mg/i
Phenols, mg/e
TOC, mg/f>
COD, mg/£
Organic Acid, mg/£
3
Flow rate, m /hr
Base
Feed*
0,0
10
0.05-23
28-840
44-3,600
10-140
260
Case
Drift/
Slowdown**
o,0
40
0.2-92
110-3,400
170-14,000
40-560
0.65/65
MFS
Feed*
o,0
10
0.06-28
32-960
50-4,000
12-1,000
210
Case
Drift/
Slowdown**
0,0
40
0. 24-110
130-3,800
200-16,000
48-4,000
0.53/53
*Feed ranges represented treated effluents from Function 4 and Function 5.
^Characteristics of Drift and Slowdown are assumed to be identical except
the flow rates. For illustrative purposes here, the drift and blowdown
composition and flow rates have been estimated assuming that all of the
treated Stream A is fed to the cooling tower, that no cooling tower make-
up is required beyond Stream A, and that the evaporation rate (as deter-
mined by temperature, humidity, etc.) is such that a 75% volume reduction
is achieved through evaporation. In practice, a different plant water
balance might be encountered, Stream A might be too small or too large
to serve as total plant makeup, or evaporation rate might be different
Under those conditions, the drift/blowdown composition would be different
from that illustrated above.
437
-------
Water Source Type 1
Combined Sour Water
Control Function 6 -
Volume Reduction
slurry falls down through the tubes, part of the slurry water is vaporized by
the steam condensing on the outside of the tubes. The vapor evaporated from
the slurry is withdrawn through a mist eliminator to remove entrained droplets
before entering a compressor suction line. The vapor steam enters the com-
pressor where it is compressed about 14 to 56 kPa. This pressure raises the
condensation temperature of the steam to about 3 to 12 K above the boiling
temperature of the recirculating brine. The steam is then fed to the shell
side of the evaporator tube bundle. As the steam condenses, its release of
heat causes more water to evaporate on the inside of the tubes. The product
water (condensed steam) is pumped from the evaporator shell through the feed
reheater to return as much heat as possible to the process before it is re-
cycled or sent to further treatment. The brine solids concentration in the
sump is continuously monitored. To maintain a constant slurry concentration
of about 200,000 to 400,000 mg/1 total solids, a waste brine slurry is con-
tinuously removed.
Operation of this process is sensitive to dissolved gases and volatile
organics in the feed since they only leave with the product water. When
applied to Combined Steam A, Function 2 through 4 and maybe 5 controls would
be required ahead of the evaporator to ensure the water recovered is of accept-
able reusable quality. Table 4-65 presents the anticipated performance of
the process. The feed composition range represents treated effluents from
Function 4 and 5 controls. The TDS values are assumed to remain unchanged
after the Function 2 through 5 controls.
The capital investment and total annualized costs for the two cases are
summarized in Table 4-66. The detailed basis and assumptions for the esti-
mates are presented in Appendix B-26. The capital investment ranges from 14
to 16 million dollars, or about 0.5% of the base plant cost. The total annual-
ized cost ranges from 4.2 to 5 million dollars, or about $2.4 to $2.5/m of
water treated.
438
-------
TABLE 4-65. ESTIMATED COMPOSITION OF FEED AND
CONCENTRATE FOR THE VAPOR COMPRESSION
EVAPORATION - STREAM A
(1,134 Mg/hr Coal Feed EDS Plant)
Component
Base Case
MFS Case
Combined Concentrate** Combined Concentrate**
Stream Feed* Effluent Stream Feed* Effluent
H2S ppm
NH3 ppm
Phenol , ppm
TOC, ppm
COD, ppm
Organic Acid, ppm
TDS, ppm
3
Flow rate, m /hr
0,0
10
0.05-23
28-840
44-3,600
10-140
4,000
260
o,0
100
0.5-230
280-8,400
440-36,000
100-1,400
40,000
26
,0
10
0.06-28
32-960
50-4,000
12-1,000
4,900
210
o,0
100
0.6-280
320-9,600
500-40,000
120-10,000
49,000
21
*Feed ranges represent treated effluent from Function 4 and 5.
**The concentrate flow rate is assumed to be 10% of the feed flow rate.
TABLE 4-66. SUMMARY OF COST ESTIMATES*FOR THE VAPOR
COMPRESSION EVAPORATOR
Cost Item
Capital Investment
Total Annual ized Cost
% Base Plant Capital Cost
% Base Plant Annual ized Cost
Unit Capital Investment
Unit Annual ized Cost
Base Case
$16 x 106
$ 5.0 x 106
0.51%
0.53%
$62,000/m3/hr
$ 2.4/m3
MFS Case
$14 x 106
$ 4.2 x 106
0.49%
0.47%
$67,000/m3/hr
$ 2.5/m3
* Capital investment is estimated using the procedures summarized in
Table 4-1 and the installed equipment cost presented in Figure B 26-2.
Annualized cost is estimated by using the bases presented in Table
4-2, and the utility and other requirements presented in Appendix B 26,
439
-------
Water Source Type 1
Combined Sour Water
Control Function 6 -
Volume Reduction
VCE generates: 1) a water product, 2) a small purge of noncondensible
gases from the evaporator shell, and 3) a small waste brine (concentrate).
The water product quality is dependent on the feed characteristics. Assuming
the volatile components of the Combined Sour Water Stream are removed by
Function 2 through 4 controls, the product water should essentially be void
of any pollutants. Likewise, the purge from the evaporator shell should be
negligible since all gases initially in the stream are stripped. The esti-
mated characteristics of the concentrate is presented in Table 4-65.
4.3.1.1.6.3 Control Technique 3 - Reverse Osmosis (RO)
Reverse osmosis uses a semipermeable membrane and a pressure differential
to separate relatively clean water from process wastewater,, The pressure gra-
dient forces the water through the membrane, leaving a concentrated solution
of impurities.
The removal efficiency of specific ions by a reverse osmosis membrane can
range from 90 to 95 percent of dissolved minerals, up to 99 percent of most
dissolved organics greater than a molecular weight of 200, and up to 99% of
biological and colloidal matter (94). Typically, about 75% of the feed is
recovered as water. Since the detailed characteristics of Combined Stream A
are not known, the actual performance of the process may differ from these esti-
mates. Also, although the feed to the RO system is assumed to have gone through
Function 4 or 5 treatments, these may still not be enough to prevent excessive
plugging (due to complex organics and/or inorganic precipitates) of the mem-
brane, making it nonfeasible to operate the process.
2
The capital investment for the base case (260 m /hr Stream A flowrate)
2
and MFS case (210 m /hr) are estimated to be 2.3 and 1.9 million dollars,
3 3
respectively; or about $8,900/m /hr and $9,100/m of treated water (see Figure
B22-1, Appendix B-22 for installed equipment cost and Table 4-1 for conversion
to capital investment cost). The total annualized costs for the two cases are
•3 -3
$760,000/yr and $640,000/yr, or about $0.37/m and $0.39/nT of treated water
440
-------
Water Source Type 1
Combined Sour Water
Control Function 7 -
Final Disposal
(see Figure B22-2 and Table 4-2).
4.3.1.1.7 Control Function 7 - Final Disposal
Four final disposal alternatives for treated effluents are addressed in
this manual. These alternatives are not intended to represent different levels
of control, but rather fundamentally different approaches. Any of these ap-
proaches may be feasible alternatives for use at a given site depending on
factors such as the availability of land, net evaporation rate, groundwater
reservoir characteristics, and surface discharge restrictions.
4.3.1.1.7.1 Control Technique 1 - Surface Discharge
Discharge of treated effluent to surface water (stream, lake, ocean) is
practiced by most industrial and municipal wastewater treatment plants. The
Combined Sour Water Stream may require going through some or all of the func-
tional controls to satisfy all applicable discharge requirements.
4.3.1.1.7.2 Control Technique 2 - Deep Well Injection
As potentially applied to Combined Stream A, deep well injection is essen-
tially a "zero discharge" technique with the objective of maximizing water re-
use. When deep well injecting any waste, the goal is to inject the waste into
an underground formation without creating any adverse impacts on the already
existing natural conditions. Selecting a zone with naturally high salt con-
tent would satisfy this goal. Other criteria for determining the feasibility
of a disposal zone are summarized in Appendix B-27.
One major consideration in operating a deep well injection system is to
pretreat the waste sufficiently well to avoid formation pluggage. It is
assumed that Combined Stream A will undergo some form of volume reduction tech-
niques in which water is recovered. The residual concentrated brine is then
disposed to deep well. As shown in Tables 4-64 and 4-65, the organic loadings
of the concentrated brine might be relatively high. Because of these high
residual organic levels, the organics may need to be destroyed (e.g., in an
441
-------
Water Source Type 1
Combined Sour Water
Control Function 7 -
Final Disposal
incineration step following volume reduction) to prevent well formation plug-
gage.
Injection wells are generally between 300 and 1800 meters deep. Assuming
an installed equipment cost for injection wells of $328/m (see Appendix B-27
for basis and assumption), this would correspond to a capital investment of
about $180,000 to $1 million (see Table 4-1 for bases for converting installed
3 o
equipment cost to capital investment), or about $8600/m /hr to $48,000/m /hr
for the MFS case and $6,900/m3/hr to $38,000/m3/hr for the base case.
4.3.1.1.7.3 Control Technique 3 - Surface Impoundment
In practice, the surface impoundment serves as a solar evaporation pond
where all the water is evaporated. This is a viable final disposal alternative
for southwestern U.S. plants where the arid conditions result in high net
evaporation rates. To prevent excessive air emissions, the volative organics
such as dissolved gases and organics such as phenols may need to be removed
ahead of this technique. Depending on the amount of land available for use
as impoundment, Combined Stream A may or may not need to go through any volume
reduction step before being discharged to the impoundment. However, to maxi-
mize water reuse, it is assumed that Stream A will undergo some form of volume
reduction step. The residual concentrated brine is then disposed to impound-
ment.
The costs of surface impoundments are largely costs associated with the
purchase of land and the construction of the impoundment. The design and con-
struction of the impoundment would aim at minimizing migration of leachate
to groundwater and to surface waters. These would depend on site-specific
factors such as local hydrogeologic conditions and net evaporation rates.
Assuming a net evaporation rate of 0.5 m/yr (20 in/yr) and no volume reduction
technique is applied, the capital investment for the base case (with pond area
c o
of 4.1 x 10 m ) for a non-lined and a plastic-lined (30 mil Hypalon) impound-
ment with a 2.4 m dike is estimated to be $15 x 10 and $41 x 10 , respectively;
442
-------
Water Source Type 1
Combined Sour Water
Control Function 7 -
Final Disposal
fi o
for the MFS case (with pond area of 3.3 x 10 m ), the equivalent costs are
$6 x 10 and $33 x 10 . The unit installed equipment cost for these estimates
are presented in Figure B-28-5 (Appendix B-28) and the bases for converting
installed equipment cost to capital investment are summarized in Table 4-1.
The total annualized costs, which consisted of labor (assumed to be 2000 hr/yr),
maintenance and amortized cost (see Table 4-2 for bases), are estimated to be
$2.9 x 106/yr and $7.9 x 106/yr for the base case; and $1.8 x 106/yr and
$64 x 106/yr for the MFS case.
4.3.1.1.7.4 Control Technique 4 - Co-Disposal with Ash
Co-disposal is one form of final disposal whereby the wastewater is used
to moisturize the ash from the partial oxidation, the boiler or Flexicoking
units. The wetted ash is then handled by a solid waste disposal method. As
potentially applied to Stream A, co-disposal would be done only in the zero-
discharge water reuse case. The feasibility of this technique is determined
by the quantities of ash generated and its moisture holding capacity. Based
on total feed coal rates of 1265 Mg/hr and 1296 Mg/hr for the base case and
MFS case (see Table 3-3), and an ash content of 9.1%, about 120 Mg/hr of total
ash will be generated. Assuming a moisture holding capacity of 20%, this
3
would hold about 24 m /hr of water, i.e., Combined Stream A would need to be
reduced to no greater than this amount, assuming this is the only stream from
the plant to be disposed this way. As shown in Table 4-65, 90% evaporation
of Stream A (e.g., through forced evaporation) can reduce the brine discharge
rate to about this flow. However, as shown in Table 4-64, use of cooling tower
provides less concentration; blowdown (brine) is greater than this flow.
It is assumed that co-disposal would not incur any incremental costs of
solid waste disposal due to addition of brine. The solid waste disposal cost
developed in Section 4.4 assumes that the ash would contain 20% moisture; thus,
addition of brine up to this moisture level in the ash would not increase the
cost of ash disposal in terms of the mass/volume of the material being disposed.
443
-------
Water Source Type 1
Combined Sour Water
Control Function 7 -
Final Disposal
However, dry ash consists essentially of inorganic coal ash. If the brine is
added, then the potential contaminants added by the brine must be considered
in choosing and designing the solid waste disposal approach; this choice of
disposal approach may increase the disposal costs.
444
-------
Water Source Type 1
Streams Containing
Primarily Dissolved
Gases
4.3.1.2 Combined Stream B - Streams Containing Primarily Dissolved Gases
Combined Stream B consists of five streams for the base case and three
streams for the MFS case. These are:
Base case
• Stream 312 - Flexicoking Heater Overhead Drum Wastewater
0 Stream 403 - Knockout Drum Wastewater in H~ Cryo Recovery
• Stream 430 - Slowdown and K.O. Drum Wastewater from H« Generation
t Stream 431 - Overhead Receiver Wastewater from Acid Gas Removal
in H2 Generation
• Stream 452 - Knockout Drum Wastewater in Ammonia Synthesis.
MFS case
• Stream 441 - Sour Water from Partial Oxidation Unit
• Stream 312 - Flexicoking Heater Overhead Drum Wastewater
• Stream 403 - Knockout Drum Wastewater in H^ Cryo Recovery.
These streams are generally combined for treatment because they all contain
dissolved gases, but little or no organics.
As discussed in Section 3, there is generally no quantitative informa-
tion on the characteristics of the individual streams that make up Stream B.
Thus, the dissolved gases concentrations in Stream B are not known. In general,
these dissolved gases concentrations are expected to be fairly low. Neverthe-
less, it is assumed that one or more of these dissolved gases may exist in
such a level in these streams that their removal from the streams may be de-
sired. The controls applicable to Stream B are the Function 3 techniques
(dissolved gas removal), which include, e.g., steam stripping. These techni-
ques are discussed in Section 4.3.1.1.3.
In actual application, Stream B is likely to be combined with Stream A
before the Function 3 technique in an integrated wastewater treatment system,
in order to take advantage of the economy of scale. Also, combining the two
445
-------
Water Source Type 1
Streams Containing
Primarily Dissolved Gases
streams may provide part or all of the dilution requirement for activated
sludge treatments on Stream A in Function 4 (see 4.3.1.1.4.1). There are
at least two possible ways of combining the two streams. In an intergrated
control system where Function 2 (bulk organics removal e.g., solvent extrac-
tion) is placed ahead of Function 3 for Stream A, Stream B can be added to
the system after Stream A has passed through Function 2. Alternatively in a
scheme where Function 3 is ahead of 2, Stream B could undergo the stripping
part of Function 3 independent of Stream A; bypass Function 2; and combine
with Stream A ahead of Function 4 (see the integrated wastewater control
examples in Section 4.3.1.6). Although it is assumed that these streams
would be combined before the stripping unit, in reality separate strippers
may be used for the streams which contain primarily ammonia (e.g., Stream
452) and streams which contain no ammonia. The ammonia stripper overhead
would be routed for ammonia recovery while the overhead from the other strip-
per would be routed to acid gas removal system for further treatment.
Combining this stream with Stream A for treatment will incur additional
incremental costs beyond those presented in Section 4.3.1.1 for Stream A
alone. The total costs for treating these streams in integrated control sys-
tems are presented in Section 4.3.1.6.
446
-------
Water Source Type 1
Aqueous Ammonia from
Ammonia Synthesis
4.3.1.3 Stream 451 - Aqueous Ammonia from Ammonia Synthesis
As discussed in 3.3.4.2.2, this stream is the product stream from ammonia
synthesis operation in the base case design; it contains close to 12% ammonia.
The ammonia can be recovered by any of the Function 3 techniques. As discussed
in 4.3.1.1.3 and Appendix B-7, Function 3 techniques consist of a steam strip-
ping unit and a recovery unit. It is likely that in an integrated wastewater
treatment system, separate strippers will be used for Streams A, B and 451,
but a common recovery unit will be designed to handle the combined stripper
overheads. As discussed in 4.3.1.1.3, Function 3 techniques are expected to
recover most of the ammonia in this stream, leaving a stripped effluent with
about 50 to 200 mg/1 ammonia. Combining this stream with Stream A for treat-
ment will incur additional costs beyond the costs presented in Section 4.3.1.1
for Stream A alone. The total costs for treating these streams combined in
integrated control systems are presented in Section 4.3.1.6.
447
-------
Water Source Type 1
Slurry Dryer Cold
Separator Wastewater
4.3.1.4 Stream 103 - Slurry Dryer Cold Separator Wastewater
As presented in Table 3-10, this stream contains relatively low levels
of dissolved gases (80 ppm NH-,, 4 ppm HLS) and dissolved organics (1000 ppm
phenol). This stream might be combined with Stream A ahead of Function 2 or
Function 4 for treatment. Whether Function 2 (phenol recovery) is applied or
not is a judgement which must be made on a case-by-case basis. One major
factor affecting this judgement is the trade-off between the recovered phenol
value and the incremental cost for the needed additional Function 2 treatment
capacity to handle this stream. Combining this stream with Stream A for
treatment will incur additional costs beyond the costs presented in Section
4.3.1.1 for Stream A alone. The total costs for treating these streams com-
bined in integrated control systems are presented in Section 4.3.1.6.
448
-------
Water Source Type 1
Slag Filtrate from
Partial Oxidation Unit
4.3.1.5 Stream 443 - Slag Filtrate from Partial Oxidation Unit
This stream only exists in the MFS case. As presented in Table 3-52, this
stream contains relatively low dissolved gases (about 130-380 ppm NhU) and or-
ganics (about 28-355 ppm COD). This stream may be combined with Stream A
ahead of Function 4 (e.g., biological oxidation) for treatment. The ammonia
may serve as food to the microorganisms. Also, this may provide part or all
of the dilution requirements for Function 4 control on Stream A (see 4.3.1.1.4.1)
Combining this stream with Stream A for treatment will incur additional costs
beyond the costs presented in Section 4.3.1.1 for Stream A alone. The total
costs for treating these streams combined in integrated control systems are
presented in Section 4.3.1.6.
449
-------
Water Source Type 1
Integrated Control
Example 1
4.3.1.6 Integrated Control Examples for Treating Organics and Dissolved
Gases Containing Wastewaters
As discussed previously in Section 4.3.1, there are 14 waste streams in
the base case and 12 in the MFS case which contain high levels of organics or
dissolved gases. Because of their similarity in characteristics and to take
advantage of the economics of scale of a large, fully integrated treatment
facility, these streams are expected to be combined at appropriate points for
treatment.
This section presents examples of integrated controls for treating these
streams. As discussed in previous sections, several treatment techniques would
likely be combined for treating these streams, and these techniques can be com-
bined in a large number of configurations to effect efficient control. The
approaches considered in this section are by no means inclusive or indicative
of necessary or sufficient treatment; they only serve as examples of how some
available control techniques may be combined to control the subject waste
streams.
4.3.1.6.1 Integrated Control Example 1: Chevron WWT + Chem-Pro + Activated
Sludge + Activated Carbon + Discharge to Surface Water
Figure 4-4 presents a block flow diagram of an integrated control system
for treating the Source Type 1 wastewaters. A total of five control functions
are included in this example, namely, Removal of Bulk Organics (Function 2).
Removal of Dissolved Gases (Function 3), Removal of Dissolved Organics
(Function 4), Removal of Residual Organics (Function 5), and Final Disposal
(Function 7). These functions are being considered by a number of proposed
coal conversion facilities in the U.S., including EDS, SRC-II and Lurgi
plants (93-98). The control techniques used in this example are Chem-Pro
(Function 2), Chevron WWT (Function 3), Activated Sludge (Function 4), Acti-
vated Carbon (Function 5) and Surface Discharge (Function 7). The use of
trade name processes such as Chem-Pro and Chevron WWT is simply to provide an
example and is not intended as a preference or endorsement.
450
-------
ACID RECOVERED
GASES NH3
t t
o
(IIJ\
AMMONIA
RECOVERY
(CHEVRON
WWT)
^
i
FUNCTION 3
RECOVERED
PHENOL
f
PHENOL
RECOVERY
(CHEM PRO)
r
~~V-X~^
FUNCTION 2
r<5>*
BIOLOGICAL
OXIDATION
(ACTIVATED
SLUDGE)
1
BIOSLUDGE
FUNCTION 4
-wim — ~>
FILTRATION/
ACTIVATED
CARBON
FUNCTION 5
t
_yi7v__k. SURFACE
Vl2/ DISCHARGE
I
1 FUNCTION 7
•P*
tn
I - STREAM A (STREAMS 106,152,155,202.
252,307,308)
II -STREAMS (STREAMS312,403.430,431,452)
AND STREAM 451 FOR BASE CASE
* STREAM B (STREAMS 312,403,441)
AND STREAM 443 FOR MFS CASE
III-STREAM 103
Figure 4-4. Block Flow Diagrams for Integrated Control Example 1 for Treating Type 1 Wastewater
-------
Water Source Type 1
Integrated Control
Example 1
As shown in Figure 4-4, the waste streams are combined into three groups
with each group being treated by a different combination of techniques. Group
I streams, which are the same as the Combined Stream A discussed in Section
4.3.1.1, includes the seven streams that contain high levels of NH3, H,,S,
phenols and other organics. This group enters the Chevron WWT System where
H~S, C09 and NH~ are stripped. The H9S/C09 stream is routed to acid gas re-
L. C. O L, L.
covery system for sulfur recovery, and the ammonia is recovered as anhydrous
ammonia within the Chevron WWT System. The stripped wastewater passes on to
the Chem-Pro System where phenol is recovered. The dephenolized wastewater
goes through the activated sludge system where dissolved organics are removed.
The activated sludge treated effluent is then passed through the activated
carbon system for residual organic removal before discharge to surface water.
It is assumed that the relatively low concentrations of oil and grease
in the stream will not affect the overall performance of the integrated con-
trol system.
Group II includes six streams for the base case (Stream B + 451) and four
streams for the MFS case (Stream B + 443). These streams are believed to con-
tain dissolved gases but low or no phenols. This group goes through a differ-
ent stripper setup in the Chevron WWT System. The overheads are combined with
those from treating the Group I streams for sulfur and ammonia recovery. The
stripper bottom joins the dephenolized Group I streams for a biological and
activated carbon treatment.
Group III consists of one stream which contains medium level of phenols
(1000 ppm) which might not be economical to recover but is treatable by bio-
logical processes. This stream joins the other two groups ahead of the Acti-
vated sludge system.
The rationale for suggesting the ammonia stripping unit and phenol extrac-
tion for treating Group I streams, and the ammonia stripping unit for treating
Group II streams ahead of the biological treatment unit is apparent. The phenol
452
-------
Water Source Type 1
Integrated Control
Example 1
and ammonia levels in these waste streams might be toxic to the biota, or at
least would render the bio-treatment unit extremely vulnerable to upset. In
addition, recovered ammonia can be sold as a by-product, and recovered phenol
can be used as fuel, if not for resale. It is estimated that 52,100 Mg/yr and
31,800 Mg/yr of ammonia, and 18,900 Mg/yr and 17,300 Mg/yr of phenol can be
recovered from the base case and MFS case, respectively.
The optimal sequencing for the ammonia and phenol recovery processes can-
not be assessed without detailed process information. In the commercial Lurgi
gasification plant designs it has been proposed that the Lurgi raw gas liquor
be first passed through an extraction process to recover phenol and then through
a steam stripping unit to recover ammonia (95,96). The commercial SRC-II plant
design (97) and the EDS plant design (98) proposed the sequencing as shown in
Figure 4-4. It is anticipated that if phenol extraction were ahead of ammonia
recovery, some of the dissolved gases would be stripped during the residual
solvent recovery step of the extraction process (see Appendix B-5 for detailed
process description). The stripped gas stream would be routed to the ammonia
recovery unit. On the other hand, with the ammonia recovery ahead of phenol
extraction, some phenols and other volatile organics will be stripped by the
ammonia recovery strippers. These organics can be recovered by passing the
stripper overhead through a condenser. The recovered organics stream is then
fed to the solvent extraction unit. Regardless of the actual sequencing of
the two units, the treated effluents from either system are expected to be
similar. For the purpose of this document, the combined performances and the
costs are assumed to be the same for either method of sequencing.
The estimated flow rates and compositions of the uncontrolled streams,
treated effluent from each technique and the treated discharge stream for in-
tegrated example 1 are summarized in Tables 4-67 and 4-68 for the base case
and MFS case, respectively. Detailed basis and assumptions for these estimates
have been presented in the previous sections and the Appendices. The tables
453
-------
TABLE 4-67. ESTIMATED COMPOSITION OF UNCONTROLLED HASTE STREAMS, TREATED EFFLUENTS AND SECONDARY WASTE STREAMS FOR
INTEGRATED CONTROL EXAMPLE 1 BASE CASE (1,134 Mg/hr COAL FEED EDS PLANT)
en
Components, kg/hr
H2S
NH3
co2
Phenols
Organic Acids
COD
TOC
Oil and Grease
IDS
Flow Rate
Component, kg.hr
Flow Rate
NH3
H2S
H20
co2
Phenol
Organic Solids
Stream I Stream II Stream III Stream IV Stream V Stream VI
4,700 170 0.6 0 00
3,600 3,000 12 13 7 13
2,300 630 46 000
2,400 0.5 150 2,400 0.5 24
840 0 0 840 0 320
12,000 2 720 12,000 2 4,800
3,700 0.8 230 3,700 0.8 1,100
50 0 0 50 00
1,000 90 0 1,000 90 1,000
260,000 131,000 156,000 260,000 131,000 260,000
SECONDARY STREAMS
Recovered Phenol Recovered NH,
2,400 3,600
3,600
0.2
4
0
2,400
Stream VII Stream VIII Stream IX
0.6 0 0
22 5.5 5.5
000
170 9 0.9
320 16 5
5,500 1,100 110
1,300 260 26
000
1,100 1,100 1,100
547,000 547,000 547,000
Acid Gas Biosludge
7,000 4,200
0.4
4,700
35 3,400
2,300
...
onn
-------
TABLE 4-68. ESTIMATED COMPOSITION OF UNCONTROLLED WASTE STREAMS, TREATED EFFLUENTS AND SECONDARY WASTE STREAMS FOR
INTEGRATED CONTROL EXAMPLE 1 MFS CASE (1,134 Mg/hr COAL FEED EDS PLANT)
cn
tn
Component Kg/hr Stream I Stream II Stream III Stream IV Stream V Stream VI
H2S 4,600 90 0.6 0 0 0
NH3 3,500 540 12 11 4 11
C02 2.100 310 46 0 0 0
Phenols 2,200 0.2 150 2,200 0.2 22
Organic Acids 840 0 0 840 0 420
COD 11,000 50 720 11,000 50 4,400
TOC 3,400 2 230 3,400 2 1,000
Oil and Grease 50 0 0 50 0 0
IDS 1,000 90 nil 1,000 90 1,000
Flow Rate 210,000 71,000 156,000 210,000 210,000 210,000
SECONDARY STREAMS
Component, Kg/hr Recovered Phenol Recovered NH.
Flow Rate 2,200 3,500
NH3 --- 3,500
H?S --- 0.2
H20 — 4
co2 --- o
Phenol 2.200
Organic Solids
Stream VII Stream VIII
0.6 0
27 4.4
46 0
170 9
420 21
5,200 1,000
1,200 240
0 0
1,100 1,100
437,000 437,000
Acid Gas
6,700
0.3
4,600
33
2,100
...
Stream IX
0
4.4
0
0.9
6
100
24
0
1,100
437,000
Biosludge
3,300
---
---
2,600
—
—
700
-------
Water Source Type 1
Integrated Control
Examples 1 and 2
also give the estimated flow rates for the secondary waste streams produced
by this treatment scheme. Available controls for these secondary waste streams
are discussed in the appropriate medium section. Not included in the tables
is the flue gas generated during regeneration of the exhausted activated car-
bon. As discussed in 4.3.1.1.5.1 and Appendix B-15, it is not possible to
determine the characteristics of this secondary stream. It is assumed that
the organics adsorbed by the carbon will be destroyed during regeneration and
the thermal regeneration unit is equipped with a scrubber to remove any parti -
culate in the flue gas.
Tables 4-69 and 4-70 present, respectively, the estimated costs for inte-
grated control example 1 for the base case and MFS case. The total capital invest-
ments are 50 and 43 million dollars, or about $98,000/m3/hr and $92,000/m3/hr,
expressed in terms of all treated streams combined (I, II and III). The total
*3 *3
annualized costs are $10 million for both cases, or about $2.3/m and $2.9/m
for the base case and MFS case, respectively. In all cases, the capital and
annualized costs for each individual control technique in these tables are
calculated in exactly the same manner as illustrated earlier for each techni-
que as applied for Stream A alone (section 4.3.1.1). The costs in Tables 4-69
and 4-70 for each technique are sometimes higher than shown in the respective
tables in Section 4.3.1.1 due to the increased flows resulting from the com-
bination of other streams with Stream A as shown in Figure 4-4.
4.3.1.6.2 Integrated Control Example 2 - Chevron WWT + Chem-Pro + Activated
Sludge + Activated Carbon + Cooling Tower + Surface Impoundment
Control Example 2, as shown in Figure 4-5, includes six techniques, namely,
Chevron WWT, Chem-Pro, Activated Sludge, Activated Carbon, Cooling Tower and
Surface Impoundment. The use of trade name processes such as Chem-Pro and
Chevron WWT is simply to provide an example and is not intended as a preference
or endorsement. Using treated process wastewater as make-up to cooling tower
was one option considered by the ANG Lurgi gasification project at North
456
-------
TABLE 4-69. SUMMARY OF ESTIMATED COSTS
FOR INTEGRATED CONTROL
EXAMPLE ONE-BASE CASE
(1,134 Mg/hr Coal Feed EDS Plant)
Item
Capital Investment,
$106
Total Annual i zed
Cost, $106/yr
Unit Capital
Investment*
$/m3/hr
Unit Annual ized
Cost*, $/m3
% Base Plant
Investment,
% Base Plant
Annual ized Cost,
Chevron
WWT
13
0.73
24,000
0.17
0.41
0.08
Chem Pro
12.4
2.6
23,000
0.61
0.39
0.27
Activated
Sludge
20
4.9
37,000
1.1
0.63
0.52
Activated
Carbon
4.1
1.9
7,500
0.42
0.13
0.20
Total
50
10
92,000
2.3
1.6
1.1
*Expressed in terms of m of all treated waste streams combined. (I, II,
and III).
457
-------
TABLE 4-70. SUMMARY OF ESTIMATED COSTS FOR
INTEGRATED CONTROL EXAMPLE
ONE-MFS CASE
(1,134 Mg/Hr Coal Feed EDS Plant)
Item
Capital Investment,
S106
Total Annualized
Cost, $10b/yr
Unit Capital 3
Investment, $/m /hr
Unit Annualized
Cost, $/rrr
% Base Plant
Investment,
% Base Plant
Annualized Cost,
Chevron
WWT
12
1.8
27,000
0.52
0.41
0.20
Chem Pro
11
2.2
25,000
0.64
0.38
0.25
Activated
Sludge
16
4.2
37,000
1.2
0.56
0.47
Activated
Carbon
3.8
1.8
8,700
0.52
0.13
0.20
Total
43
10
98,000
2.9
1.5
1.1
3
*Expressed in terms of m of all treated waste streams combined. (I,
II and III).
458
-------
ACID RECOVERED RECOVERED
GASES NH3
O
^-^
Cv*
• in i
t t
AMMONIA
RECOVERY
(CHEVRON
WWT)
PHENOL
t
-©-*
— .
~\s
*~
PHENOL
RECOVERY
(CHEM PRO)
VY/
DRIFT
t
s
fvni-»»
FUNCTION 3
ACTIVATED
SLUDGE
FILTRATION/ coo.ING ^ SURFACE
f i ACTIVATED » \ WJULINu f ^ »wnr«^»c
\IJJJr*' CARBON vli/*1 TOWER —V^^/* IMPOUNDMENT
A
BIOSLUDGE | |
FUNCTION 2 FUNCTIONS FUNCTIONS 1 FUNCTION 7
FUNCTION 4 1 '
I1 -STREAM A (STREAMS 106,152,155,202,
252, 307,306)
II - STREAM B (STREAMS 312.403,430,431,452)
AND STREAM 452 FOR BASE CASE
= STREAM B (STREAMS 312,403,441)
AND STREAM 443 FOR MFS CASE
HI-STREAM 103
Figure 4-5. Block Flow Diagram for Integrated Control Example 2 for Treating Type T Wastewater
-------
Water Source Type 1
Integrated Control
Example 2
Dakota (91); disposing treated process wastewater in surface impoundment was
considered by El Paso Lurgi gasification project at Texas (96).
This example is likely to be feasible only for plants in the southwestern
part of the U.S. where net evaporation is high; the surface impoundment will
serve as a solar evaporation pond. Passing the treated water through cooling
tower before discharging to the pond will reduce raw cooling water requirement
which is likely an important consideration in the southwestern states. This
treatment also reduces the area required for the impoundment, since only the
concentrated blowdown from the cooling tower will go to the impoundment. The
four techniques preceding the cooling tower will minimize emission of volatile
gases and organics through the cooling tower, and minimize cooling tower fail-
ure due to pluggage and other problems.
The characteristics of the waste streams I through IX, as well as the
secondary streams Acid Gases, Recovered Phenol, Recovered NH, and Biosludge,
are identical to those presented in Tables 4-67 and 4-68. The characteristics
of stream X, the concentrated blowdown from the cooling tower is presented in
Table 4-71. It is assumed the cooling tower is operating at a concentration
cycle of four, and no other make-up water is required.
This example generates one additional secondary stream beyond the previous
example. This is the drift from the cooling tower. The characteristics
of this stream are presented in Table 4-71. The basis for this estimate have
been presented in Section 4.3.1.1.6.1.
The estimated cost for this system is summarized in Table 4-72. The first
four treatment techniques are similar to control example 1, and the costs of
these have been presented before. The cooling tower is considered as part of
the base plant operation, hence, no cost estimate is presented. The surface
impoundment capital investments are estimated to be 7.8 and 39 million dollars
for the base case; 6.2 and 31 million dollars for the MFS case, depending on
whether the impoundment is lined or not (see Appendix B-24 for basis and
460
-------
TABLE 4-71. COMPOSITION OF TREATED EFFLUENT FOR
INTEGRATED CONTROL EXAMPLE 2 BASE
CASE AND MFS CASE
(1,134 Mg/hr Coal Feed EDS Plant)
Base Case*
Component,
Kg/hr
H2S
NH3
co2
Phenols
Organic Acids
COD
TOC
Oil and Grease
TDS
Flow Rate
Stream
IX
0
5.5
0
0.9
5
no
26
0
1,100
547,000
Stream
X
0
5.5
0
0.89
4.95
109
25.7
0
1,090
137,000
Drift
0
0.01
0
0.009-
0.05
1.1
0.26
0
10
1,370
MFS Case**
Stream
IX
0
4.4
0
0.9
6
100
24
0
1,100
437,000
Stream
X
0
4.4
0
0.89
5,94
99
23.8
0
1,090
109,000
Drift
0
0.01
0
0.009
0.06
1
0.24
0
10
1,090
Characteristics of Streams I through VIII and other secondary streams
presented in Table 4-67.
^Characteristics of Streams I through VIII and other secondary streams
presented in Table 4-68.
461
-------
TABLE 4-72. SUMMARY OF COSTS FOR INTEGRATED
CONTROL EXAMPLE 2
(1,134 Mg/hr Coal Feed EDS Plant)
Item
Capital g
Investment, $10
Total Annual ized
Cost, $106/yr
Unit Capital
Investment,***
$/M3/hr
Unit Annual ized
Cost,*** $/nr
% Base Plant
Capital
Investment, %
% Base Plant
Cost. %
Other*
Processes
50
10
92,000
2.3
1.6
1.1
Base Case
Surface**
Impoundment
7.8-39
1.6-7.8
14,000-
71,000
0.37-1.8
0.24-1.2
0.17-0.32
Total
58-89
12-18
106,000-
161,000
2.7-4.1
1.8-2.8
1.3-1.9
Other*
Processes
43
10
98,000
2.9
1.5
1.1
MFS Case
Surface**
Impoundment
6.2-31
1.3-6.2
14,000-
71,000
0.38-1.8
0.22-1.1
0.15-0.70
Total
49-74
12-16
112,000-
169,000
3.3-4.7
1.7-2.6
1.3-1.8
*Costs for the individual processes preceding surface impoundment are presented in Tables 4-69 and 4-70.
**Lower range values are for no-liner impoundment and higher range values are for plastic-lined
impoundment.
o
***Expressed in terms of m of all treated waste streams combined (I, II and III),
-------
Water Source Type 1
Integrated Control
Example 2 and 3
assumptions for cost estimates). The total investments for the system are
estimated to be 58 to 89 million dollars for the base case, or about $106,000
•3
to $161,000/m /hr; and for the MFS case, these are estimated to be 49 to 74
million dollars, or about $112,000 to $169,000/m /hr. The total annualized
cost for the two cases are estimated to be 12 to 18 million dollars per year
33 3
and 12 to 16 million dollars per year, or about $2.7/m to $4.1/m and $3.3/m
to $4.7/m , respectively. The cost estimates for surface impoundment shown
in Table 4-72 were estimated in exactly the same manner as illustrated in
Section 4.3.1.1.7.3 for Stream A alone, except adjusted downward to account
for the lower flow rate of the combined stream due to the volume reduction
technique used ahead of the impoundment.
4.3.1.6.3 Integrated Control Example 3 - Chevron WWT + Chem-Pro + Activated
Sludge + Activated Carbon + Forced Evaporation + Co-Disposal with
Ash
Control Example 3, as shown in Figure 4-6, includes six control techni-
ques, namely, Chevron WWT, Chem-Pro, Activated Sludge, Carbon Adsorption,
Forced Evaporation and Co-Disposal with Ash. The use of trade name processes
such as Chevron WWT and Chem-Pro is simply to provide an example and is not
intended as a preference or endorsement. This scheme would optimize water re-
use in the plant by recovering water through the forced evaporation step. The
concentrated brine from the evaporator is used to moisturize (quench) ashes
from the Flexicoking unit, partial oxidation unit and boiler prior to ash dis-
posal . Disposal of concentrate from evaporator with ash was one scheme con-
sidered by the ANG Lurgi gasification project.
As discussed in 4.3.1.1.7.4, assuming an average moisture holding capacity
3
of 20% for the ashes, about 24 m /hr of water can be disposed of as part of
the ash solid waste stream. Forced evaporation (vapor compression evaporator)
is used in this example to concentrate the waste stream down to this level.
(A more economic alternative may be to use a combination of cooling tower,
reverse osmosis and forced evaporation). As discussed before, to ensure proper
463
-------
cr>
ACID RECOVERED RECOVERED
GASES NH3
O
X-^w
VJI/*
t t
AMMONIA
RECOVERY
(CHEVRON
WWT)
FUNCTION 3
PHENOL
t
-0*
s^>.
~{v)
h
PHENOL
RECOVERY
(CHEM PRO)
X-N
— (VIJ
X^v
(yH/~*"
^•^
ACTIVATED
SLUDGE
x~x
— wiiy-^-
^^^
1
BIOSLUDGE
FUNCTION 2
FILTRATION/
ACTIVATED
CARBON
FUNCTION 5
X""V
— MXV*
^™^
1
1
1
1
1
FORCED
EVAPORATION
FUNCTIONS
_ CO-DISPOSAL
"N
— ( *• J —
"~ WITH ASH
EXAMPLE 3
^_^^_ ^^^_ ^^^^ ^^^^_ _^_ ^^^_ ^^_^ ^^^^ ^_^_ —
EXAMPLE 4
-k INCINERATION -/^TTV-k. i»nroTi/^K,
I - STR E AM A (STR EAMS 106. 152,155, 202,
252,307,308)
11 - STR E AM B (STR EAMS 312.403,430,431,452)
AND STREAM 452 FOR BASE CASE
- STREAM B (STREAMS 312,403,441)
AND STREAM 443 FOR MFS CASE
III = STREAM 103
FUNCTION 7
FUNCTION 5
Figure ,4-6. Block Flow Diagram for Integrated Control Examples 3 and 4 for Treating Type 1 Wastewater
-------
Water Source Type 1
Integrated Control
Example 3
operation of the evaporator and that the water recovered is of reasonable qua-
lities, volatile species and other pollutants would be removed ahead of the
evaporator. This is accomplished by the four techniques shown in Figure 4-6
preceding forced evaporation. The estimated characteristics of the effluent
from the evaporator are presented in Table 4-73. As shown, the streams will
need to be concentrated about 24 and 18 times for the base case and MFS case,
respectively. Only streams IX and X, which are directly related to the evapor-
ator, are included in the table. The characteristics of other streams, in-
cluding the secondary streams, have been presented in Tables 4-67 and 4-68.
No new secondary waste stream is expected from the evaporator and the co-dis-
posal operations.
The estimated costs for the evaporator and the total system are summar-
ized in Table 4-74. The costs for the system include costs for Chevron WWT,
Chem-Pro, Activated Sludge and Activated Carbon which have been presented in
the previous examples, and forced evaporation. The co-disposal cost is as-
sumed to be part of the solid waste disposal cost, and is not included here
(see Section 4.3.1.1.7.4). Costs for forced evaporator of the combined stream
in Table 4-74 are estimated in exactly the same manner as in Section 4.3.1.1.6.2
for stream A alone, except adjusted for the larger flow rate of the combined
stream.
The concentrate from the evaporator contains fairly high concentration
of organics which may be candidate for removal before final disposal with the
ash. One applicable control technique is incineration. Incineration, if added
to the two cases, will add 4.8 million dollars to the total capital investment and
4.8 million per year to the total annualized cost (see Table 4-76 for details).
Removing the organics before disposal may reduce the solid waste disposal
facility design/operation requirements and hence the total disposal cost, i.e.,
there may be a tradeoff in costs between the water and solid waste media for
this control scheme.
465
-------
TABLE 4-73. ESTIMATED COMPOSITION OF TREATED
EFFLUENTS FOR INTEGRATED CONTROL
EXAMPLE 4 BASE CASE AND MFS CASE
(1,134 Mg/hr Coal Feed EDS Plant)
Components, Kg/hr
H2S
NH3
co2
Phenols
Organic Acids
COD
TOC
Oil and Grease
TDS
Flow Rate
Base
Stream IX
0
5.5
0
0.9
5
no
26
0
1,100
547,000
Case*
Stream X
0
5.5
0
0.9
5
no
26
0
1,100
24,000
MFS
Stream IX
0
4.4
0
0.9
6
100
24
0
1,100
437,000
Case**
Stream X
0
4.4
0
0.9
6
100
24
0
1,100
24,000
Characteristics of Streams I through VIII and secondary streams are
presented in Table 4-67.
^Characteristics of Stream I through VIII and secondary streams are
presented in Table 4-68.
466
-------
TABLE 4-74. SUMMARY OF ESTIMATED COSTS FOR
INTEGRATED CONTROL EXAMPLE 3
BASE CASE AND MFS CASE
(1,134 Mg/hr Coal Feed EDS Plant)
Base Case MFS Case
Item Other Evaporator Total Other Evaporator Total
Processes* Processes*
Capital 50 26 76 43 22 65
Investment,
$106
Total Annualized 10 8.6 19 10 7.2 17
Cost, $106/yr
Unit Capital 92,000 48,000 140,000 98,000 50,000 148,000
Investment,**
$/m3/hr
Unit Annualized 2.3 2.0 4.3 2.9 2.1 5.0
Cost,** $/m3
% Base Plant 1.6 0.82 2.4 1.5 0.76 2.3
Capital
Investment, %
% Base Plant 1.1 0.91 2.0 1.1 0.81 1.9
Annualized
Cost %
*Costs for individual processes are in Tables 4-69 and 4-70.
q
**Expressed in terms of m of all treated waste streams combined (I, II
and III).
467
-------
Water Source Type 1
Integrated Control
Example 4
4.3.1.6.4 Integrated Control Example 4 - Chevron WWT + Chem-Pro + Activated
Sludge + Activated Carbon + Forced Evaporation + Incineration +
Deep Hell Injection
Control Example 4, as shown in Figure 4-6, includes seven control tech-
niques, namely, Chevron WWT, Chem-Pro, Activated Sludge, Carbon Adsorption,
Forced Evaporation, Incineration and Deep Well Injection. The use of trade
name processes such as Chevron WWT and Chem-Pro is simply to provide an example
and is not intended as a preference or endorsement. Deep Well injecting the
concentrate from evaporation was one scheme considered by the ANG Lurgi gasi-
fication project (91). Incineration was included to reduce the threat of well
plugging by organics in the brine. This example would optimize water reuse
by recovering water through the evaporation step, and would be applicable to
sites where local hydrogeological conditions permit deep well injection of
the treated wastewaters.
The estimated characteristics of the treated streams for this system are
presented in Table 4-75. Only streams X and XI, which are directly related
to the incineration operation are included in the table. Characteristics of
streams I through VIII and the secondary waste streams have been presented in
Tables 4-67, 4-68 and 4-73. As shown, incineration is expected to remove 99.9%
of the organics.
In addition to the recovered NH-, recovered phenol, acid gases and bio-
sludge, this system generates another secondary waste stream, namely, the off-
gas from the incinerator. As discussed in 4.3.1.1.5.3 this stream may contain
S00, NO and particulates. The major contribution to the S09 and NOV is likely
L. X £ A
from the fuel used. The particulates may come from the fuel and the wastewater.
Since control for this stream is considered as part of the incinerator system*
* Of the 83 installed incinerators designed to burn aqueous waste containing
sodium salts, 80 have a quench tank followed by a venturi scrubber, 3 have
electrostatic precipitators (91).
468
-------
TABLE 4-75. ESTIMATED COMPOSITION OF TREATED
EFFLUENTS FOR INTEGRATED CONTROL
EXAMPLE 4 BASE CASE AND MFS CASE*
(1,134 Mg/hr Coal Feed EDS Plant)
Component, Kg/hr Stream X
Stream XI
Stream X
Stream XI
HS
NH3
co2
Phenols
Organic Acids
COD
TOC
Oil and Grease
TDS
Flow Rate
0
5.5
0
0.9
5
no
26
0
1,100
24,000
0
5.5
0
0.0009
0.005
0.11
0.026
0
1,100
24,000
0
4.4
0
0.9
6
100
24
0
1,100
24,000
0
4.4
0
0.0009
0.006
0.1
0.024
0
1,100
24,000
Characteristics of Streams I through IX are presented in Tables 4-67
and 4-68.
469
-------
Water Source Type 1
Integrated Control
Example 4
no separate estimates on the characteristics or cost are presented for this
stream.
The estimated costs for this control example are summarized in Table 4-76,
As shown, the total capital investments for the base case and MFS case are
estimated to be 82 and 71 million dollars, respectively; and the annualized
costs are 25 and 23 million dollars per year, respectively. These correspond
to $150,000/m3/hr and $161,000/m3/hr, and $5.7/m3 and $6.7/m3. Costs for
incineration and deep well injection of the combined stream in Table 4-76 are
estimated in exactly the same manner as in Section 4.3.1.1.5.3 and 4.3.1.1.7.2
for Stream A alone, except adjusted for the larger flow rates of the Combined
stream.
470
-------
TABLE 4-76. SUMMARY OF ESTIMATED COSTS FOR INTEGRATED CONTROL EXAMPLE 4 BASE CASE AND MFS CASE
(1,134 Mg/hr COAL FEED EDS PLANT)
Base Case
Other
Processes* Incineration Injection Total Processes
Capital ,
Investment, $10° 76 4.8 0,77 82 65
Total Annual i zed
Cost, $106/yr 19 4.8 1.1 25 17
.U. Unit Capital .
^ Investment,** $/md/hr 140,000 9,000 1,000 150,000 148,000
Unit Annual i zed
Cost,** $/m3 4.3 1.1 0.25 5.7 5.0
% Base Plant
Capital Investment, 2.4 0.15 0.2 2.6 2.3
% Base Plant
Annulaized Cost, 2.0 0.51 0.12 2.6 1.9
MFS Case
Incineration Injection Total
4.8 0.77 71
4.8 1.1 23
11,000 2,000 161,000
1.4 0.32 6.7
0.17 0.03 2.5
0.54 0.12 2.6
Cost for the individual processes preceding incineration are presented in Tables 4-69, 4-70, and 4-74.
*
Expressed in terms of all treated waste streams combined (I II and III).
-------
Water Source Type 2
Inorganic Containing Wastewaters
4.3.2 Source Type 2 - Inorganic Containing Wastewaters
Streams that fall into this source type include:
Stream No. Stream Description
012 Coal Pile Runoff
702 Slowdown from Steam Generation
System
708 Slowdown from Power Generation
System
723 Regeneration Wastes from Water
Demineralization
732 Cooling Tower Slowdown
These streams are common to both the base case and the MFS case, but are not
unique to the EDS process. They are common to other industrial facilities such
as oil- and coal-fired power generation plants and refineries. Existing and
proposed regulations on the Electric Power Industry specify discharge limits
on total suspended solids, total residual chlorine, and pH from these streams.
These regulations also specify no discharge of priority pollutants resulting
from chemical additives.
Table 4-77 summarizes the control functions and techniques that are
applicable to these streams. As shown, control functions include Removal of
Suspended Solids, Tars and Oils, Removal of Dissolved Inorganics, Volume Re-
duction and Final Disposal. Although listed as a separation function, Removal
of Dissolved Inorganics is typically used in conjunction with Removal of Sus-
pended Solids, Tars and Oils.
472
-------
TABLE 4-77
SUMMARY OF CONTROL TECHNIQUES POTENTIALLY APPLICABLE TO EDS WASTEWATER
CONTAINING PRIMARILY DISSOLVED INORGANICS
Table 4-45. SUWW3Y OF CONTROL TECHNIQUES POTENTIALLY APPLICABLE TO THE TREATMENT OF EDS UASTEKATER CONTAINING PRIMARY DISSOLVED ORGANICS AND DISSOLVED GASES
Technology
Technology Principle
Components Removed
Removal Efficiency
Feed Requirements/
Restrictions
By-Products and
Secondary Waste Streams
Comments
Removal of Suspended Sol ids, Tars and Oils
Gravity separation
- API oil separator
- Parallel plate
Coagulation/
flocculation
Air flotation
- Dissolved air
- Induced air
Fi11rat ion
Provision of adequate res- Suspended solids, tars
and oils,
idence time in a stagnant
vessel to al'ow suspended
sol ids or iimiscible
fluids to separate into
lighter and heavier than
water phases.
Use of agents to promote
the coalescence of fine
suspended solids and
adsorption of tars and
oils; generally used in
conjunction with a gravity
separation process.
Use of air bubbles to pro- Suspended oils and solids.
mote the disengagement of
lighter-than-water mate-
rials from solution.
Passing wastewater through Depends on filter mediuro,
suitable filter medium, both coarse and fine
filter material discarded structure materials
or c1e*ntd fcjf fcackflushing, are used industrially.
Depends upon design,
10- 50^ removal of TSS
typical, 60-99'* for oils.
Minimum feed stream
turbulence.
Recovered oils (Sp. gr.l)
Promotes removal of finely Outlet suspended solids
dispersed particles. concentration to 10 mg/l
possible, oils removal of
60-95i.
A wide range of coomercial Same as gravity separation.
flocculants are available.
Incorporated into the tar/oil
separation system design and the
biological treatment system
Widely used in water treatment
system to remove fine soilds.
Depends on characteristics Air requirements depend Recovered oils entrained, Widely used in various industries.
of source and treatment
process; TSS removal of
20-75*-, oil removals of
75-85i.
TSS removals of 30-90+i,
oil removals of 65-90*
upon waste characteristics, solids.
Filter media (sand, clay,
fabric or polymeric
membrane).
Filter backwash; spent
filter media.
Proposed for use as polishing step
for phenolic water downstream of
tar/oil separation, "Sticky" tars/
oils may cause problems with filter
plugging and regeneration
-------
TABLE 4-77.
(CONTINUED)
Technology
Removal of Dissolved
Ion exchange
Technology Principle
Inorganics
Substitution of H+»
Na+, OH" or Cl~ ions
for other Ionic spe-
cies, exchange resins
regenerated with acid,
base or salt solutions
Components
Removed
Heavy metal , F~,
CN", scaling
species
KH3
Removal
Efficiency
90 J removal for
most Ions, regen-
eration frequency
is a key
parameter
Feed
Requirements/
Restrictions
Regene rants.
replacement
resins
By-Products
and
Secondary
waste
Streams
Spent regener-
ants and
resins, treated
water
Garments
Most effective as a pol-
ishing process. Clearly
appl icable to boiler
feedwater treatment needs.
Of United use in treat-
Ing process wasteuaters
containing high concen-
trations of organ Ics or
dissolved solids.
Chemical Use of agents to pro- Ca, Mg, heavy
precipitation not* the precipitation netals,
of Inorganic solids alkalinity
from wastewaters
Varies with Line, polynsr
wastestreax con- and soda ash
stituents. Typl- nay be
cal
Cd 21
Cr 401
Cu 201
Hg 201
ivals:
H1 SOS
Pb SI
Se 101
Zn 2SI
required.
Sludge con- Generally followed by
Urinated with filtration and/or actl-
heavy aetals vated carbon adsorption.
-------
TABLE 4-77.
(CONTINUED)
-J
en
Technology
Volume Reduction
Membrane separation
- reverse osmosis
- electrodlalysls
Forced evaporation
Cooling tower
concentration
Residual Disposal
Surface discharge
Deep well Injection
Surface Impoundment
Co-disposal
Technology Principle
membrane and pressure
to separate water
from Its dissolved
constituents
Use of selective anlon-
or cation-permeable
membranes with electric
field to separate
mineral Ions from water
Thermally Induced
evaporation of excess
wastewater, condensate
recovery optional
Hastewater used as
partial makeup to the
cooling tower and
thereby concentrated
Into the blowdown
Hastes are conveyed to
and mixed with a
natural water source
Hastes are pumped Into
subsurface geological
formations where they
are Isolated from all
surface and ground-
water supplies
Hastes are held In
a containment basin
Ash 1s quenched with
wastewater then han-
dled by a solid waste
disposal technique
Components
Removed
tlon efficiencies
of the various
soluble species
will be determined
by membrane charac-
teristics and con-
ditions of process
operation
All nonvolatile
species will re-
main 1n brine
All nonvolatile
species concen-
trated Into the
blowdown
Entire stream
Entire stream
All nonvolatile
species remain as
residual In the
Impoundment
Entire stream
Feed
Removal Requirements/
Efficiency Restrictions
90-951 rejection Membrane
of dissolved
salts. Reduc-
tions In dis-
solved organic*
and BOD of up
to 991
None
Feed characteris-
tics limited by
corrosion, scaling.
and biological
fouling
100X Restrictions are
site-specific
loot Injected fluids
must be filtered
to 5 micrometers
and have a low
organic content to
prevent plugging.
Hastes must not
precipitate 1n the
well or when mixed
with subsurface
fluids. Volume re-
duction prior to
Injection Is often
economical
)00t Concentrations of
volatile species
may need to be
low to prevent
loss to the
atmosphere
loot Concentrations of
volatile species
may need to be
low to prevent
loss to the
atmosphere
By-Products
and
Secondary
Haste
Streams
material , recov-
ered water.
brine
Recovered con-
densate, noncon-
denslble gases.
waste brine
Evaporation/
drift
Hone
None
Loss of
volatile
species
Loss of
volatile
species
Comments
centratlon step prior to
further treatment or ulti-
mate disposal of waste-
water. Membrane scaling
end fouling with organlcs
may limit the applicabil-
ity of this technology to
the treatment of process
condensates.
Very stringent materials
requirements.
This technique Is limited
to locations having avail-
able land and net evapora-
tion rates exceeding
0.5 m/yr (20 In/yr).
-------
Water Source Type 2
Combined Inorganic Stream
Control Function 1
4.3.2.1 Combined Inorganic Stream - Streams 702, 708, 723 and 732
Combined inorganic stream consists of four streams, namely,
• Stream 702 - Slowdown from Steam Generation System
• Stream 708 - Slowdown from Power Generation System
• Stream 723 - Regeneration Wastes from Water Demineralization
• Stream 732 - Cooling Tower Slowdown.
As discussed in Section 3, these streams are not unique to the EDS plant.
They are common to all steam electric power plants. It is expected that these
streams will contain suspended solids and may be acidic. To be consistent with
the discharge standards for steam electric power plants, it is assumed that
biocides and anticorrosion agents used in cooling tower do not contain any
priority pollutants such as chromium, zinc and nickel.
4.3.2.1.1 Control Function 1 - Removal of Suspended Solids, Tars and Oils
Two techniques may be used to treat these streams. These are presented
below.
4.3.2.1.1.1 Control Technique 1 - Gravity Separation
This technique operates under the principle that by providing enough
residence time in a quiescent reactor, the suspended solids will be separated
from the wastewater due to their difference in density. The reactor may be
a pond (surface impoundment), or a rectangular or circular tank. In the exist-
ing steam electric power plants, this technique typically produces an effluent
with less than 30 ppm suspended solids.
The combined stream flow rates for the base case and MFS case were esti-
3 3
mated to be, respectively, 730 m /hr and 600 m /hr (see Tables 3-76 and 3-77
for flow rates of the individual streams). Assuming a pond depth of 10 m and
residence time of 24 hrs (to provide some capacity for holding storm runoffs),
treating this stream in a surface impoundment would require impoundment surface
2 2
area of 1750 m and 1440 m for the base case and MFS case, respectively. From
476
-------
Water Source Type 2
Combined Inorganic Stream
Control Function 1
Figure B-28-1 in Appendix B-28 (for installed equipment cost) and Table 4-1
(for converting installed equipment cost to capital investment) and assuming
the impoundment has a 2.4 m dike, the capital investments for the base case
are estimated to be $35,000 and $150,000, respectively, for an unlined and
Hypalon-lined impoundment; for the MFS case, these are, respectively, $31,000
and $130,000. The total annualized costs which are consisted mainly of labor
(assumed to be 2000 hr/yr), maintenance and amortized costs (see Table 4-2
for bases) are estimated to be $43,000 and $65,000 for the base case and
$42,000 and $61,000 for the MFS case. All these costs are less than 0.01%
of the uncontrolled base plant cost.
Secondary Stream
This technique generates a secondary waste stream, namely, the settled
sludge. There are no data to characterize this stream. In a surface impound-
ment, the settled sludge may be dredged from time to time, and disposed in a
landfill, or be left in the impoundment permanently. The costs estimated in
the previous paragraph do not include any closure cost or dredging cost.
4.3.2.1.1.2 Control Technique 2 - Filtration
In filtration, wastewater enters the filtration unit and slowly percolates
through the filter media to the underdrain. Suspended materials are trapped
in the filter media and are later flushed out of the filter during the back-
wash cycle. This technique typically reduces suspended solids to below 10 ppm.
The capital investments for this process are estimated to be $1.3 x 10
and $1.1 x 10 , respectively, for the base case and MFS case (see Figure 8-4-1
in Appendix B-4 for unit installed equipment cost and Table 4-1 for bases for
converting installed equipment cost to capital investment); or less than 0.1%
of the uncontrolled base plant cost. The total annualized costs are estimated
to be $380,000/yr and $320,000/yr for the base case and MFS case, respectively;
or less than 0.1% of the uncontrolled base plant annualized cost.
477
-------
Water Source Type 2
Combined Inorganic Stream
Control Function 1 and 2
Secondary Stream
Filtration generates one secondary waste stream, namely, the filter back-
wash. This stream is generally routed to sedimentation unit for treatment.
4.3.2.1.2 Control Function 2 - Removal of Dissolved Inorganics
Dissolved inorganics removal techniques are designed to neutralize the
waste streams, to remove toxic trace elements or to lower the calcium, magne-
sium, silica, carbonate and/or sulfate levels. The latter species form the
majority of the compounds which cause plugging, scaling and fouling problems
when their solubility products are exceeded.
4.3.2.1.2.1 Control Technique 1 - Neutralization
This technique involves addition of chemicals (acids or bases) to neutra-
lize the stream. The chemicals are typically either added prior to Function
1 technique or just before discharge. Equipment required for this technique
includes chemical storage and feed system. Unless the waste streams are ex-
tremely acidic or basic, costs for these equipments and the chemical costs
are expected to be insignificant when compared to other control technique
costs. No secondary waste stream is generated from this process.
4.3.2.1.2.2 Control Technique 2 - Chemical Precipitation
Chemical precipitation involves the addition of chemicals, usually lime
and possibly flocculant aide whereby the wastewater pH is raised and metal
oxide/hydroxide precipitates are formed. The precipitates are removed by
gravity settling. Depending upon the resultant pH, the treated waste may be
recarbonated to lower the pH and to remove excess calcium (as CaC03) in a
second stage settling tank. The process is usually followed by filtration
to remove residual solids. When applied to the Combined Inorganic Stream,
this technique is expected to be used in conjunction with one of the Function
1 techniques (see Section 4.3.2.1.1). Equipment required in addition to those
478
-------
Water Source Type 2
Combined Inorganic Stream
Control Function 2, 3 and 4
already existing in Function 1 technique include chemical feed and chemical
storage system. The costs for these equipments and the chemical costs for
treating these streams are expected to be minor when compared to the Function
1 techniques costs.
Secondary Stream
This process generates a secondary stream, namely, the settled precipi-
tates. This stream may be disposed with other inorganic solid waste streams
generated from the plant.
4.3.2.1.3 Control Function 3 - Volume Reduction
Techniques considered in this function are similar to those discussed
under Section 4.3.1.1.6 for Water Source Type 1 controls. The performances
are expected to be similar whether the techniques are applied to Water Source
Type 1 or Type 2 waste streams, although pretreatment requirements are differ-
ent (e.g., no dissolved gases or bulk organic removal techniques are required
for this stream). The costs and performances for these techniques have been
presented in Section 4.3.1.1.6 and the appendices.
4.3.2.1.4 Control Function 4 - Final Disposal
Techniques considered in this function are similar to those discussed
under Section 4.3.1.1.7 for Water Source Type 1 controls. The performances
are expected to be similar whether the techniques are applied to Water Source
Type 1 or Type 2 waste streams, although pretreatment requirements are differ-
ent. The costs and performances for these techniques have been presented in
Section 4.3.1.1.7 and the appendices.
479
-------
Water Source Type 2
Coal Pile Runoff
Control Function 1, 2 and 3
4.3.2.2 Stream 012 Coal Pile Runoff
As discussed in Section 3 this stream is not unique to the EDS plant. It
is expected that this stream would be acidic and may contain some trace metals
leached out from the coal. This is an intermittant stream; its flow rate and
characteristics would depend on precipitations (rainfall and snow) and coal
characteristics. This stream is typically collected in a sedimentation unit
(Function 1 control) where the pH is adjusted (Function 2 control) before
discharge. Where zero discharge is desired, some form of volume reduction
(Function 3) would be applied. These control techniques have been discussed
in Section 4.3.2.1. This stream may be combined with the Combined Inorganic
Stream for treatment.
480
-------
Solid Waste Management
4.4 SOLID WASTE MANAGEMENT
Many solid waste streams are generated in an EDS facility. The charac-
teristics of the streams which are generated from the base plant were presented
in Section 3; the streams which result from the pollution control measures,
i.e., secondary streams, are discussed in various sections throughout Section
4. Secondary waste streams are fairly significant streams. Depending on the
pollution control processes used in the air and water media, they may account
for more than 20% of the total solid waste streams generated.
The solid waste streams can be grouped into four waste type categories
according to their characteristics and potential control requirements. These
waste types are:
t Source Type 1 - Inorganic Ashes and Sludges
• Source Type 2 - Recovered unsalable By-Products
0 Source Type 3 - Organic Sludges
t Source Type 4 - Spent Catalysts
Several control techniques are potentially applicable to these wastes. 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 effi-
ciencies, are generally 100 percent. However, unless designed and operated pro-
perly, secondary waste streams with undesirable characteristics may be generated
and migrated away from the site employing the technique. For example, runoff
can contaminate surface water and percolating water can contaminate groundwater.
The significance of this depends upon the nature of the species which might be
leached out of the solids by the runoff/percolation. Thus, in selecting solid
waste management techniques, the major evaluation criteria are whether the tech-
nique is applicable and economically feasible, and whether the secondary waste
streams are suitably contained.
Based upon current techniques practiced in the synfuel and other indus-
tries, together with those being considered by proposed synfuel plants, the
481
-------
Solid Waste Management
bulk of the solid waste from EDS 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 the site, as well as the design and operation
of the facility would depend on the site location, transportation costs, hydro-
geologic conditions, and many other factors. In short, a detailed analysis of
the specific site is an important element of the overall control technique
evaluation process.
Land disposal (e.g., landfill, surface impoundment, land treatment) will
be subject to regulations promulgated by EPA pursuant to the Resource Conser-
vation and Recovery Act (RCRA), covering the generation, transport, treatment,
storage and disposal of solid wastes. Requirements concerning a solid waste
can vary signficantly, depending upon whether the waste is determined to be
"hazardous" or"non-hazardous" as defined by RCRA regulations. 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 EDS solid waste streams
are identified and evaluated in this section. Since no specific site is being
considered, a general overview of these techniques is first presented. This
is followed by an evaluation of the applicable controls to each individual
stream under each waste source type. The emphasis is on identifying the appli-
cability of the technique. For the reasons stated above and because the char-
acteristics of many of the solid waste streams are not known, it is not pos-
sible to evaluate the optimum design and operation of these techniques in the
482
-------
Solid Waste Management
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 EDS plant. Those situations in which solid waste streams can be com-
bined for treatment or disposal are pointed out.
The organization of this section diverges slightly from the organization
of the air and water media sections. The applicable control functions will be
presented first because these functions generally apply to all of the waste
types. This is followed by an evaluation of the applicable controls to each
waste stream under each waste source type. Some examples illustrating how
streams might be combined for disposal in an integrated plant, and some examples
of how techniques may be combined to control specific streams, are presented
in the last part of this section.
483
-------
Solid Waste
Control Function 1
Reuse/Resource Recovery
4.4.1 Solid Waste Control Functions
Several control techniques are potentially applicable for managing the
solid waste streams. These techniques are summarized in Table 4-78. As
shown, they can be broadly divided into three control categories according to
their functions. The three control functions are:
• Control Function 1 - Reuse/Resource Recovery
0 Control Function 2 - Treatment
• Control Function 3 - Disposal
Treatment may involve specific chemical/physical processes for preparing the
waste to meet certain reuse/resource recovery specifications or to stabilize
the waste for disposal. Reuse/resource recovery is one form of ultimate con-
trol 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 4-79. The following
is a brief description of the individual techniques. A more detailed discus-
sion is included in Appendix C.
4.4.1.1 Control Function 1 - Reuse/Resource Recovery
Reuse or resource recovery of waste streams is desirable from environ-
mental standpoint because less wastes require disposal (if any) and other
resource requirements are reduced. Potential adverse environmental impacts as-
sociated with disposal of the waste are eliminated although other impacts may
arise as a result of the reuse/recovery process utilized. This control ap-
proach is highly waste specific and is constrained by the availability of
markets or uses for the waste. Available reuse/resource recovery alternatives
will be identified under each specific waste stream discussion.
484
-------
TABLE 4-78. SUMMARY OF SOLID WASTE MANAGEMENT TECHNOLOGIES
00
in
Technology
Reuse/Resource
Kecovery
Reuse,
Resource
Recovery
Treatment
Fixation/
Incineration
Disposal
Landfill
Surface
Impoundment
Land
Treatment
Deep Well
Injection
Description
Haste is utilized- in a
manufacturing process,
construction application*
in original application,
or valuable components
are recovered from waste
as byproduct for marketing.
Chemicals are added to
the wastes
Organic Wastes undergo
destruction to reduce
volume and toxicity
Site is designed, con-
structed, and operated
to totally contain waste,
leachate collection and
treatment systems, and
groundwater monitoring
system
Site is excavated or
diked to form pond to
contain waste; super-
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
User for waste must be
located, cessation of
reuse requires imme-
diate alteration of
management techniques;
thereby, necessitating
Wide variety of wastes
feasibility of solidi-
fying a particular
waste may differ with
different process
Each type of organic
ferent operating char-
enced operators re-
quired
Wide variety of wastes
can be accepted, pro-
visions must be made
for incompatible wastes
Similar to 1 andfil 1
Only 1 imited types
and mass of organic
wastes can be managed
Wastes frequently
must be treated
before injection
Reliability or
Limitations
Markets for wastes are
1 imited and economic
viabil ity is heavily
influenced by distance
to market
Limited commercial
Waste will be con-
tained subject to
adequate site opera-
tion and nemtenance
Irene hydrogeologi -
cal changes or earth
movements
Similar to landfill
Heavily dependent
upon weather condi-
tions
Injection rates
frequently 1 imited
by receiving forma-
tion
Waste
Equipment Generated
Transportation
vehicles
May include mix-
ing chamber,
pumps, metering
tanks, chemical
feed systems
tation machin-
Earth moving
equipment, waste
handling machin-
ery such as fork-
1 ifts and trucks
Machinery to move
waste to site,
usually pipe-
1 ines
Waste movi ng
machinery, usual -
waste incorpor-
ation machinery,
usually bulldozers
and discs
Pumps , injection
wells
None
Solidified
waste
pollution con-
Surface runoff
and leachate
Supernatant
and leachate
Possibly sur-
face runoff
Residues from
the waste
treatment pro-
cess
General
Comments
In general , these are
the most environmentally
acceptable management
techniques.
Most processes
are appl icabl e
only to small
waste streams
Process is energy
intensive
Site location and
design dependent
upon hydrogeolo-
gical conditions ,
be mar'e 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 he esta-
bl ishrd
Site location
dependent on
soil conditions;
provisions must
be mar's for long
term ? ite care
Some ftates pro-
hibit deep well
injection
-------
TABLE 4-79. SITE-SPECIFIC FACTORS TO BE CONSIDERED
FOR LAND DISPOSAL OPTIONS
Climatological
• Wind conditions (e.g., speed, directional flux, dilution factors, humidity,
temperature, etc.)
• Precipitation (e.g., annual precipitation, storm intensity, snow contribu-
tions, etc.)
• Evapotranspiration rate (e.g., season variations, etc.)
Geologic Factors
• Physiographic features (e.g., runoff coefficient, slope, drainage patterns -
dendritic trellis, annular, etc., erosional features, etc.)
• Surface and subsurface geology (e.g., outcrops, bedrock features, strike
and dip of the bedrock, rock composition, etc.)
0 Soil types (e.g., CEC capacity, texture, permeability, stratification,
homogenous vs. heterogenous deposition, chemical composition, percent of
humic material, etc.)
• Seismic factors (e.g., ground shaking or rupture)
Hydrogeologic Factors
• Drainage patterns
• Stream flow (e.g., velocity, perennial vs. intermittent, effluent or
influent source, etc.)
• Surface waters (e.g., tidal effects, recharge vs. discharge points, etc.)
• Vadose zone (e.g., depth, moisture content, hysteresis patterns, storage
capacity, etc.)
• Groundwater (e.g., depth, number of aquifers and relationships, confined or
artesian, nature of confining layer(s), capillary fringe characteristics, etc.)
• Piezometric surface (e.g., streamline flux patterns due to seasonal or event
related phenomena, influence of recharge/discharge areas, streamline anomalies,
etc.)
• Water quality (e.g., background vs. undersite vs. downgradient, water uses -
consumptive, irrigation, recreation, point source contributors and their
respective hydrogeologic pathways, etc.)
• Floodplain (100 year flood) (e.g., aerial flooding limits, degree of localized
streamline pattern reversal, erosional consequences, etc.)
• Wetlands (e.g., recharge vs. discharge source, wetland/groundwater continuity
and pathway, etc.)
• Recharge and discharge areas (e.g., proximity of disposal area, volume of
flow, etc.)
Land Use Factors
• Historic significance • Demographic setting
0 Transportation corridor (access) 0 Geopolitical impact
0 Beneficial uses 0 Ultimate land use
0 Cost
486
-------
Solid Waste
Control Function 2
Treatment
The economics of reuse/resource recovery is 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.
4.4.1.2 Control Function 2 - 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.
4.4.1.2.1 Control Technique 1 - 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 alter-
ation of the characteristics of a waste to attain desired structural charac-
teristics) and stabilization (the immobilization of waste constituents by
chemical reactions to form insoluble compounds or by entrapment within an
inert polymer or stable crystal lattice). Depending on the principal chemical
agents used, fixation processes can be categorized as cement-based, lime-based,
thermoplastic organic polymer, and glassification techniques. 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 pro-
cess operations involve mixing the chemical with the waste in a reactor at spe-
cific temperature and for a specific time period. The end product is the fixed
waste.
487
-------
Solid Waste
Control Function 2
Treatment
In principle, these processes are applicable to treating any waste by
applying "sufficient" chemicals. 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. Typical total annualized unit fixation costs,
not including ultimate disposal costs, are reported to be $10 to $17 per
metric ton of sludge fixed (100-103). It is recommended that, before imple-
menting 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 (100).
4.4.1.2.2 Control Technique 2 - Incineration
Incineration is a controlled thermal decomposition process which reduces
the weight, volume and characteristics of the waste by oxidizing the organic
compounds present in the waste. The extent of volume and weight reduction is
dependent upon the waste characteristics, the incineration process, and the
incinerator operating condition. The major concerns in incineration are get-
ting adequate destruction of the organics and of avoiding air emission of any
unburned organics. The end products of incineration include carbon dioxide,
water, ash, and other inorganic compounds. Incineration has been applied to
various industrial wastes including refinery wastes, sewage sludge, paper mill
waste liquor, pharmaceutical wastes, and organic chemical wastes. The common
types of incinerators used for solid waste disposal include rotary kiln, multi-
ple hearth, and fluid bed reactor (104). The capital investment for a 9.2 x 10
Btu/hr rotary kiln incinerator with energy recovery is estimated to be 16 to
20 million dollars (see Figure C6-2 in Appendix C6). The total annualized
cost for this is estimated to be 9 million dollars per year (see Figure C6-4).
488
-------
Solid Waste
Control Function 3
Disposal
4.4.1.3 Control Function 3 - Disposal
As mentioned before the bulk of the solid wastes are likely disposed on
land. Three potentially applicable techniques are discussed in this section.
These are landfill, surface impoundment, and land treatment.
4.4.1.3.1 Control Technique 1 - Landfills
Landfills have been widely used for the disposal of municipal refuse and
a range of industrial wastes. In landfill ing, waste is brought to the dis-
posal site by truck or conveyor, spread in layers, and compacted with heavy
equipment. In most landfills the waste is covered with a thin layer of soil
at the end of the working day. The process is repeated until the desired depth
is reached or the available area is filled. A final cover of soil is then
added. The finished site is either revegetated or prepared for other end uses.
Landfills 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 of the site, and containment of runoff. Diversion chan-
nels should be incorporated into the initial design of the landfill and con-
structed before the site begins accepting waste (105). This prevents surface
runoff water from the surrounding terrain from entering the site and generating
leachate.
Migration of leachate into the groundwater can be controlled by lining
the landfill with clay, concrete, asphalt or plastic. Liners will often be
required if the solid waste is considered to be hazardous; liners may some-
times also be desirable if the waste is non-hazardous. The choice of an ap-
propriate liner or liners will depend on site-specific climatologic, geologic,
and hydrogeologic factors, as well as on the compatibility of the liner and
489
-------
Solid Waste
Control Function 3
Disposal
the waste to be contained and the relative cost of compatible liners. A
leachate collection 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 EDS facility's wastewater treatment system or
in a separate treatment system (106).
In the absence of any judgement concerning whether a given waste might
ultimately be determined to be hazardous or not, 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
(non-hazardous waste with favorable hydrogeologic and other site conditions
that preclude needs of liners) to the most complex (hazardous waste with un-
favorable hydrogeologic and other site conditions that a double liner system
is felt necessary). The two landfill designs are presented in Figure 4-7.
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 0.076 cm (30 mil)
synthetic material. Both the unlined and the lined landfill designs assume
the completed fill will be 30 meters above the original land surface with a
slope of 3:1. Both landfills will have a final cover consisting of 0.5 m of
sand and 0.3 m of clay. The most complex hazardous case would also include
special provisions for closure and post-closure care, monitoring, record
keeping and other requirements.
The capital investment and annualized unit costs as a function of the
site capacities for the two designs are presented in Figure 4-8. To be con-
sistent with cost estimates performed for the base plant and the air and water
490
-------
a) LANDFILL-DOUBLE LINER
b) LANDFILL-NO LINER
CLAY LINER
DRAINAGE
LAYER
ORIGINAL
GROUND
LEVEL
_ „.-J..T... ....^. —.,..,...,>...,
\\ \
ORIGINAL
GROUND
LEVEL
LEACHATE COLLECTION
SYSTEM
CLAY LINER
UNSATURATED
ZONE
LEACHATE
DETECTION
SYSTEM
GROUNDWATER
Figure 4-7. Landfill design,
-------
I - DOUBLE LINED LANDFILL
II-UNLINED LANDFILL
CAPITAL INVESTMENT
TOTAL UNIT ANNALIZED COST
ro
UJ
10
IP"
\
— II
105 106
TOTAL WASTE QUANTITIES, 1 Mg/Yr
I I 1 t
.107
fc
8
z
N
_J
<
<
O
Figure 4-8. Estimated Landfill Costs as a Function of Landfill Capacity
-------
Solid Waste
Control Function 3
Disposal
media, no land cost is included.* The capital investment developed includes
site preparation cost (clearing and scrubbing, groundwater monitoring and col-
lection systems, liners), final cover and revegetation cost, and landfill
equipment cost (see Appendix C-2, section 7 for unit installed equipment costs
for these items and Table 4-1 for bases for converting installed equipment costs
into capital investment). It was assumed that no excavation is required. The
annualized unit cost includes labor, fuel, leachate collection and analysis and
amortized capital investment; 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 classification of wastes under RCRA. EPA has esti-
mated that for a 50,000 metric ton per year commercial hazardous waste land-
fill, administrative and other compliance costs amount to $9/Mg (107). Haul-
ing 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.
4.4.1.3.2 Control Technique 2 - Surface Impoundments
Surface impoundments have been utilized widely by municipalities and
industries to process or dispose of waste liquids, sludges, and slurries.
Like landfill sites, the impoundments can be in natural depressions or in
excavated areas. Earthen dikes are usually constructed around the impoundment
area. Wastes are usually transported hydraulically to the impoundment. The
wastes deposit at the bottom of the impoundment; the supernatant may be removed
* About 1,100,000 m of land is required per 10° Mg/yr of waste generated,
or about 110 hectare/106 Mg/yr (130 acre/106 ton/yr). Assuming a land
cost of $5,000/10,000 nr the capital investments for the lined and unlined
landfills, as presented in Figure 4.4.2, will be increased by 9 and 12 per-
cent, respectively. Additional land may be required for road construction,
buffer zone, buildings, etc., which will incur additional costs.
493
-------
Solid Waste
Control Function 3
Disposal
and treated for discharge or recycle, or allowed to evaporate.
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 double-lined impoundment, in order to cover the range
of possible experience. The unlined impoundment represents the simplest set
of conditions (non-hazardous waste with favorable hydrogeologic and other site
conditions that preclude the needs for liners), and the lined impoundment re-
presents a much more complex situation (hazardous waste with unfavorable hydro-
geologic and other site conditions that a double liner system is felt necessary).
When the surface impoundment has been filled with waste, the site may be
closed in one of two ways: the residual solids may be left in place and covered
with clay and sand to prevent erosion and the infiltration of precipitation, or
the solids 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 maintenance program will need to be established. The cost
per unit volume for surface impoundments are expected to be similar to those
of landfills with similar depths. However, since surface impoundments generally
are used for the disposal of wet, not yet dewatered wastes, a larger area may
be required per mass of dry solid, resulting in higher disposal costs, i.e.,
some of the disposal cost will be for 'disposing' of water. Disposal cost
could be reduced if the wet wastes were dewatered first but there would be
costs associated with dewatering. The trade-off in disposal cost versus de-
watering cost is highly dependent upon waste characteristics and site-specific
factors.
494
-------
Solid Waste
Control Function 3
Disposal
4.4.1.3.3 Control Technique 3 - Land Treatment
Land treatment refers to the use of soil as a medium to treat and dispose
of waste. Also known as landfarming, landspreading, and soil application,
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 micro-
organisms to decompose and utilize organic compounds under aerobic conditions.
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 processes:
(1) decomposition/degradation; (2) leaching; (3) volatilization; and (4) in-
corporation into the soil matrix (e.g., through ion-exchange or adsorption).
It is the degradation processes which treat the waste to reduce its objection-
able (e.g., toxic) properties; these processes must be maximized during land
treatment, while the other processes must be minimized or eliminated. Apply-
ing biodegradable wastes, maintaining proper (aerobic) conditions for microbial
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 surface
water and groundwater. 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,
cadmium, lead, and mercury should not be land treated in sites where food
chain crops are grown, as they may be incorporated into the soil and taken
up by plants (108). Prior to land treating biological oxidation sludge, long-
term studies should be performed to confirm that the waste is degradable in
the soil and that there is no accumulation of non-degradable toxic substances
in the soil.
495
-------
Solid Waste
Control Function 3
Disposal
Assuming biosludge is applied on land 10 times/yr, with an application
rate of 60 Mg/acre/application and a factor of 2 to account for land required
2
for roads, buffer zones, dikes, etc., it is estimated that 430,000 m of land
is required to land-treat 100 Mg/day of biosludge. The capital investment
for this site would be 0.76 million dollars. This cost was calculated from
installed equipment cost using the procedures summarized in Table 4-1. The
2
installed equipment costs include land preparation cost ($0.52/m ), waste
spreading equipment costs ($160,000) and monitoring well costs ($25,000);
but not land cost. Detailed bases and assumptions for the design of and cost
estimates for land treatment are presented in Appendix C-4.
496
-------
Solid Waste Source Type 1
4.4.2 Source Type 1 - Inorganic Ashes and Sludges
Inorganic ashes and sludges are the largest volume solid waste type
from an EDS facility. This source type includes 12 streams for the base case
and 13 streams for the MFS case. The flow rates of these streams are summar-
ized in Table 4-80, and the application of the available techniques to these
streams is evaluated in this section.
497
-------
TABLE 4-80. SUMMARY OF SOLID WASTE QUANTITIES FOR SOURCE
TYPE 1 STREAMS
Stream
(302)
(303)
(306)
(313)
(108)
(704)
(710)
(703)
(709)
(705)
(711)
(722)
(442)
No. Stream Description
Flexi coking Gasifier/Heater Dry Fines
Flexicoking Gasifier/Heater Wet Fines
Flexicoking Gasifier/Heater Bed Coke
Flexicoking Heater/Reactor Chunks/Agglomerate
Solids Accumulated in Slurry Drier
Bottom Ash from Steam Generation System
Bottom Ash from Power Generation System
Fly Ash from Steam Generation System
Fly Ash from Power Generation System
FGD Sludge from Steam Generation System
FGD Sludge from Power Generation System
Raw Water Treatment Sludge
Slag from Partial Oxidation Unit
Quantity
Base Case
138,000
345,000
707,000
20,000
820
3,900
12,600
17,000
46,000
51,000
162,000
14,000
0
, Mg/yr
MFS Case
66,000
164,000
363,000
10,000
820
10,000
8,000
44,000
33,000
150,000
116,000
15,000
447,000
Total 1,520,000 1 ,430,000
498
-------
Solid Waste Source Type 1
Combined Flexicoking Waste Streams
Control Function 1 -
Resource Recovery
4.4.2.1 Combined Flexicoking Waste Stream - Streams 302, 303. 306
As presented in Section 3.3.4.1.3 these streams contain fairly high
levels of carbon (10 to 40%) with most of the remainder being coal ash.
Leachate may include low levels of trace metals (see Table 3-39 and 3-40 for
laboratory simulated leachate characteristics); tests of leachate for organics
have not been conducted, but organics levels would be expected to be low.
Although stream 303 is wet, containing about 40% water and the other two are
dry, they are likely combined for treatment and disposal. As shown in Table
fi fi
4-80, these three streams total 1.19 x 10 Mg/yr in the base case and 0.59 x 10
Mg/yr in the MFS case.
4.4.2.1.1 Control Function 1 - Resource Recovery
Due to its high carbon content this stream may be used as fuel in a boil-
er. However this material may present two major problems with respect to con-
ventional pulverized coal-fired boilers. First, this material contains little
or no volatiles which may result in flame stability problem unless a readily
combustible supplemental fuel is added or other countermeasures are taken.
Second, the high moisture content in Stream 303 may require extensive drying
and thus special handling and drying equipment. For these reasons, fluidized
bed combustion boiler (FBC) is used as an example to illustrate this resource
recovery alternative. The use of FBC boiler is being considered for at least
one proposed Koppers-Totzek gasification facility in the U.S. (K-T gasifier
generates a dust which may contain up to 50% water, 20% carbon and 30% ash,
not unlike the Flexicoking solids).
4.4.2.1.1.1 Control Technique 1 - FBC Boiler
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, may also be in-
jected into the bed to react with S02 formed during combustion. The inert
material of the fuel usually leaves the top part of the bed with the flue gas,
499
-------
Solid Waste Source Type 1
Combined Flexicoking Waste Streams
Control Function 1 -
Resource Recovery
and the spent sorbent is removed from the bottom of the bed.
Two secondary waste streams are generated from the FBC boiler, namely a
flue gas stream and a spent sorbent stream. The flue gas is expected to con-
tain some NO , S09 and particulates. NO control is inherent in FBC; any S00
X L. X L.
control is done by bed sorbent. Thus, only particulate control is of concern.
The applicable controls for the flue gas have been discussed in Section 4.2.
Because of subsequent particulate emission controls applied, essentially all
of the ash in the flue gas will be captured and will appear as a solid waste.
The quantities of the ash generated for the base case and the MFS case are
5 5
estimated to be 6.5 x 10 Mg/yr and 3.0 x 10 Mg/yr, respectively. The charac-
teristics of this stream are expected to be similar to the fly ash from the
conventional coal-fired boiler. The quantities of spent bed materials are
estimated to be 6,600 Mg/yr and 3,300 Mg/yr, respectively, for the two
cases (109). This material contains mainly CaSO,, CaO, CaCOo and some inerts.
Assuming a carbon heating value of 850 Kcal/Kg (1554 Btu/lb), heat input
to the FBC boiler from the base case and MFS case will be 38 x 10 kcal/hr
(150 x 106 Btu/hr) and 19 x 106 kcal/hr (75 x 106 Btu/hr), respectively (see
Table 3-78 and 3-79 for characteristics of the individual streams). The capital
investments for these boilers are estimated to be 11 and 6.5 million dollars
(see Table 4-81). These costs are derived at using the procedures presented in
Table 4-1 and the installed equipment costs reported in Table A-4 of reference 109,
updated to 1980 bases. The installed equipment cost reported in reference 109
are for FBC boilers burning high sulfur coals; these costs may be low for boil-
ers burning Flexicoking wastes. Assuming a labor requirement of 2 operators
per shift, no steam credits and using the bases summarized in Table 4-2, the
total annualized costs for the base case and MFS case are estimated to be 2.5
and 1.6 million dollars per year, or about 0.26% and 0.19% of the uncontrolled
base plant costs.
500
-------
TABLE 4- 81. SUMMARY OF ESTIMATED COSTS FOR FBC BOILERS APPLIED TO
COMBINED FLEXICOKING SOLIDS (1,134 Mg/hr Feed Coal EDS Plant)
Item
Capital Investment, $106
Total Annual ized Cost, $106
Unit Capital Investment, $/Mg/hr*
Unit Annual ized Cost, $/Mg*
% Base Plant Capital Investment, %
% Base Plant Annual ized Cost, %
Base Case
11
2.5
73,000
2.1
0.34
0.26
MFS Case
6.5
1.6
86 ,000
2.7
0.23
0.19
*Expressed as Mg of Flexicoking solids burned.
501
-------
Solid Waste Source Type 1
Combined Flexicoking Waste Streams
Control Function 1 -
Resource Recovery
It is estimated that 4.1 x 105 Mg/yr and 2.1 x 105 Mg/yr of steam is
generated by the two cases. A steam credit of $6.1/Mg and $7.6/Mg would be
necessary for the base case and MFS case respectively, if the FBC boiler cost
were to break even, i.e., if the steam credit were to offset the capitalized
and operating costs. This shows that the cost estimates for burning this
stream in FBC boilers is very sensitive to the steam credit.
One other factor that affects the economics of this alternative is the
total amount of waste generated that requires disposal. Burning this stream
will reduce its quantity by more than 40% (from 1.19 x 106 Mg/yr of Flexi-
5
coker wastes to 5.1 x 10 Mg/yr of dry FBC boiler ash and spent bed media for
5 5
the base case; from 5.9 x 10 Mg/yr to 3 x 10 Mg/yr for the MFS case). Re-
covering the steam for in-plant use will result in less steam being required
from the separate coal-fired steam boiler. The net result is that less ash
is being generated from the steam/power generation part of the plant. It is
estimated that for the base case and MFS case, respectively, about 6 Mg/hr
of coal feed to the coal-fired boiler would be displaced by the burning of
the Flexicoking waste. These amount to reductions of 16% and 3% of the coal
boiler size. The associated reduction in boiler ashes and sludges are esti-
mated to be 12,000 Mg/yr and 6,000 Mg/yr (see Table 4-80). Thus, in effect
the use of FBC boiler for burning the Flexicoker wastes will reduce the total
solid waste quantities that require ultimate disposal by 6.92 x 10 Mg/yr and
2.84 x 10 Mg/yr for the base case and MFS case, respectively. Assuming an-
nualized unit costs of $2.5 and $4.1/Mg for a nonlined and lined landfill,
this reduction in waste generation would amount to savings of 1.7 and 2.8
million dollars per year for the base case, and 0.76 and 1.2 million dollars
for the MFS case.
4.4.2.1.2 Control Function 2 - Treatment
4.4.2.1.2.1 Control Technique 1 - Fixation
The techniques that are potentially applicable to treating this stream
502
-------
Solid Waste Source Type 1
Combined Flexicoking Waste
Streams
Control Functions 2 and 3
are fixation processes. Fixation of this stream may be appropriate if data
indicate that significant concentration of trace metals or unexpected high
levels of organics are detected in leachates generated from this material.
The potential need for this treatment has not been established at the present
time; available data indicate trace element levels in leachates from the
Flexicoking waste are low.
The performance and cost of fixing this stream is dependent upon the
specific process (additive) used, which can only be established after thorough
treatability studies. Lime- and cement-based fixation techniques, which have
been applied to boiler fly ash, FGD sludges and coal fines are likely candi-
dates for treating this stream. From available data on the characteristics
of this stream, it is entirely possible that much more chemical will be needed
to fix this stream than to fix an equal amount of FGD sludge. Thus, the unit
cost may be much higher than the $10 - $17 per Mg reported for FGD applica-
tions (100-103).
4.2.2.1.3 Control Function 3 - Disposal
Techniques potentially applicable to disposing this stream include land-
fill and surface impoundment.
4.4.2.1.3.1 Control Technique 1 - Landfill
In landfill ing, the Flexicoking wastes are likely transported to the
disposal site by truck, spread on the surface of land or previously placed
wastes, and compacted. As the pile height increases, a working face with
safety slope is developed to ensure stability of the fill.
If the Flexicoking wastes are determined to be non-hazardous, then, in
the most favorable case (e.g., favorable site conditions), an unlined land-
fill might be possible. On the other hand, if the wastes were considered to
contain hazardous components, a lined landfill would be necessary where hydro-
geologic or other site factors are unfavorable.
503
-------
Solid Waste Source Type 3
Combined Flexicoking Waste Stream
Control Function 3 -
Disposal
Based on current and proposed practices in the synfuel and other indus-
tries, this stream is likely co-disposed with some other solid waste streams
from the plant in one common landfill. Although more than one landfill/dis-
posal facility (e.g., one landfill design for hazardous waste and one landfill
for non-hazardous waste) may be operated in an EDS plant, for costing purposes
in the PCTM one landfill accepting all the wastes from the EDS plant is assumed,
By considering the alternatives of all wastes being disposed of in a non-
hazardous waste landfill with no liners and a hazardous waste landfill with
double liners, the range of landfill costs in the PCTM should bracket the costs
that might be encountered in practice for any split of the wastes between haz-
ardous and non-hazardous categories.
As summarized in Table 4-80 the total solid waste quantities generated
from the base case and MFS case are, respectively, 1.6 and 1.5 million Mg/yr.
The capital investments for landfills accepting these quantities of wastes are
estimated to be the same - 11 million dollars for a non-lined landfill and 23
million dollars for a lined landfill (see Figure 4-7 for landfill design and
Figure 4-8 for estimated capital investments). The unit annualized costs for
the non-lined and lined landfill will be $2.3/Mg and $4.1/Mg, respectively
(see Figure 4-8). Thus, assuming the Combined Flexicoking Wastes Stream are
disposed of in one common landfill that accepts all other wastes from the EDS
facility, the total annualized cost that would be attributable to the Combined
Flexicoking Waste Stream alone would be $2.7 million/yr (for disposal in a non-
lined landfill) and $4.9 million/yr (for disposal in a lined landfill) for the
base case; and $1.4 million/yr and $2.4 million/yr for the MFS case.
If the Combined Flexicoking Waste Stream were disposed of by itself in a
separate, dedicated landfill, costs for this smaller landfill (1.2 x 10 Mg/yr
for base case, 0.59 x 10 Mg/yr for MFS case) would be almost as great as for
a total combined landfill handling all wastes. The capital investment for
unlined and lined landfill accepting Combined Flexicoking Waste Stream alone
would be $10 and $20 million for the base case, respectively; and $0.4 and $10
504
-------
Solid Waste Source Type 3
Combined Flexicoking Waste
Stream
Control Function 3 -
Disposal
million for the MFS case (see Figure 4-8).
4.4.2.1.3.2 Control Technique 2 - Surface Impoundment
In surface impoundment, the Flexicoking wastes would be transported hy-
draulically to the site. The wastes would settle to the bottom of the im-
poundment, the supernatent being recycled or discharged. The disposal cost
per unit volume for surface impoundment are expected to be similar to land-
fills with similar depths. The total disposal cost may be higher because
surface impoundments generally are used for the disposal of wet, not yet de-
watered wastes; extra capacities are needed for the water content in the waste.
This cost may be partially or totally offset by the reduction in costs asso-
ciated with dewatering the wastes.
505
-------
Solid Waste Source Type 1
Flexicoking Heater/Reactor
Chucks/Agglomerate
Control Functions 2 and 3
4.4.2.2 Stream 313 - Flexicoking Heater/Reactor Chunks/Agglomerate
This stream contains large chunks of inert material originating from
the feed coal. Its characteristics are expected to be similar to boiler
bottom ash. Applicable control techniques include fixation and landfill. As
with the Combined Flexicoking Wastes the need for fixing this stream has not
been established. Where applicable, the likely fixation process candidates
for fixing this stream are lime- and cement-based techniques. From available
data on the characteristics of this stream (mainly on the lime content) it is
entirely possible that much more chemical will be needed to fix this stream
than to fix an equal amount of FGD sludge. Thus, the unit cost may be much
higher than the $10 - $17/Mg reported for FGD application (100-103).
In landfilling, this waste is expected to be co-disposed with the Com-
bined Flexicoking Waste Stream and all other solid wastes in a common landfill,
as discussed in the previous section. The annualized unit cost of disposing
this stream in a common landfill would be $2.3 and $4.1/Mg, respectively, for
the non-lined and lined landfill. For this stream (20,000 Mg/yr for base case,
and 12,000 Mg/yr for MFS case) these unit costs translate into incremental
annual costs of $46,000 and $82,000/yr for the base case; $23,000 and $41,000/
yr for the MFS case (not including hauling and administrative costs). Again,
the consideration of both a lined and unlined landfill is intended to bracket
the range of conditions that might be encountered in any individual situation.
506
-------
Solid Waste Source Type 1
Solids Accumulated in Slurry
Drier
Control Functions 1, 2 and 3
4.4.2.3 Stream 108 - Solids Accumulated in Slurry Drier
This is a relatively small volume solid waste stream (820 Mg/yr) which
consists essentially of part feed coal and part recycled solvent. There are
no data on the characteristics of leachates generated from this waste. Poten-
tially applicable techniques are discussed below.
4.4.2.3.1 Control Function 1 - Resource Recovery
Due to its high carbon content, this material can be used as feed to
the boilers, Flexicoker, partial oxidation unit or the FBC boiler as discussed
in 4.4.2.1.1. Pre-sizing of the material may be required before it can be
used as feed. This is a small stream with flow rates of about 820 Mg/yr.
Feeding this to the above mentioned units is not expected to incur any signi-
ficant cost or savings.
4.4.2.3.2 Control Function 2 - Treatment
If this stream were not returned to the process (per section 4.4.2.3.1)
applicable treatment techniques might include fixation/encapsulation processes.
Fixing this stream will reduce its leaching potential. This may be appropri-
ate due to its high organic content.
The performance and cost of fixing this stream is dependent upon the
specific process used. The presence of solvent and the high carbon content
of this stream will likely interfere with the pozzolanic reactions in the
fixation processes. Thus, it is expected that much more chemical will be
needed to fix this material than to fix an equal amount of FGD sludge. The
unit cost may be much higher than the $10 - $17/Mg reported for fixing FGD
sludges (100-103).
4.4.2.3.3 Control Function 3 - Disposal
Applicable disposal techniques include landfill and surface impoundment.
If disposed, this stream is assumed to be co-disposed with other Source Type 1
streams in a common landfill (see 4.4.2.1.3.1). The annualized unit cost of
507
-------
Solid Waste Source Type 1
Solids Accumulated in Slurry
Drier
Control Functions 1, 2 and 3
disposing this stream in a common landfill would be $2.3 and $4.1/Mg,
respectively, for an unlined and lined landfill. For this stream, these unit
costs translate into incremental costs of $1,900 and $3,400/yr, respectively.
508
-------
Solid Waste Source Type 1
Slag from Partial Oxidation
Control Function 1 -
Resource Recovery
4.4.2.4 Stream 442 - Slag from Partial Oxidation Unit
The slag from partial oxidation unit, which exists only in the MFS case,
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 metals (see Table 3-58 and 3-59 for laboratory
simulated leachate characteristics). Tests of leachate for organics have not
been conducted, but organics levels would be expected to be low.
4.4.2.4.1 Control Function 1 - Resource Recovery
The 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 (111). 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 dried, crushed, and sized before
it can be used in such applications.
The major constraints on reuse of the slag are market limitations. Market
conditions will vary from site to site. Given the fact that not all ashes from
existing power plants are commercially utilized, it may be difficult to find
markets where all or significant quantities of the slag from the EDS facility
can be reused. Users for the slag will likely be limited to those who are
located in the vicinity of the plant. The economic viability of reuse de-
creases with increases in distance to market and hence increased transporta-
tion costs. If market conditions change so that commercial reuse ceases, the
waste management techniques for the ash will need to be altered immediately.
Long-term contracts with users may lessen the potential for market interruptions,
509
-------
Solid Waste Source Type 1
Slag from Partial Oxidation
Control Functions 2 and 3
4.4.2.4.1 Control Function 2 - Treatment
The functional techniques applicable to treatment of the slag are fixation
and encapsulation. Treatment of the slag may be appropriate if future data
indicate that significant concentrations of trace metals were present in leach-
ate from the slag ash. Currently available leach data indicate the trace
metals in the leachate are low, and should not be significantly different from
conventional coal boiler ash.
The performance of treating this stream is dependent upon the specific
process (additive agent) used. Several lime- and cement-based fixation pro-
cesses have been successfully applied to power plant ash, a material chemically
not too dissimilar to the slag. Assuming that these fixation processes are
applicable to treating this stream, the unit cost would be about $10 - $17 per
Mg (100-103).
4.4.2.4.2 Control Function 3 - Disposal
The slag may be disposed of in two ways: in landfills or in impoundments.
4.4.2.4.2.1 Control Technique 1 - Landfill
In landfill ing, gasifier slags are usually brought to the site by trucks,
spread on the surface of land or previously placed wastes, and compacted. As
discussed in Section 4.4.2.1.3.1, it is assumed that this stream will be dis-
posed of with other solid waste streams in one landfill.
As discussed in Sections 4.4.1.3 and 4.4.2.1, annualized unit costs for
landfilling the solid waste streams in a common landfill are estimated to be
$2.3 and $4.1/Mg, respectively, for a non-lined and lined site. Based on these
unit costs, the incremental annualized disposal cost for this stream would be
$1 and $1.8 million dollars per year (not including administrative and hauling
costs).
510
-------
Solid Waste Source Type 1
Slag from Partial Oxidation
Control Function 3
4.4.2.4.2.2 Control Technique 2 - Surface Impoundment
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 in land-
fills. For disposal impoundments, the ashes are left in place and are covered
to prevent erosion and infiltration of precipitations. The unit cost for sur-
face impoundment is similar to the cost of landfill, assuming no excavation is
required, although it is likely that larger volume of wastes will be handled
due to the added water content.
511
-------
Solid Waste Source Type 1
Combined Bottom Ash
Control Functions 2 and 3
4.4.2.5 Combined Boiler Bottom Ashes - Bottom Ashes from Steam and Power
Generation Systems (Streams 704 and 710)
The characteristics of Streams 704 and 710 are the same, they consist
essentially of coal ash; these two streams are thus likely combined for treat-
ment or disposal.
The applicable control techniques for boiler bottom ash are similar to
those for the Slag from Partial Oxidation Unit. Where landfill is the tech-
nique selected, the stream is assumed to be co-disposed with other solid waste
streams in one common landfill.
As discussed in Sections 4.4.1.3 and 4.4.2.1 annualized unit costs for
landfilling the solid waste streams in a common landfill are estimated to be
$2.3 and $4.1/Mg, respectively, for an unlined and lined landfill. Based on
these unit costs, the incremental annualized disposal cost attributable to
this stream would be $38,000 and $68,000/yr for the base case, and $47,000
and $74,000/yr for the MFS case (not including administrative and hauling costs)
512
-------
Solid Waste Source Type 1
Combined Fly Ash
Control Functions 2 and 3
4.4.2.6 Combined Boiler Fly Ash - Fly Ash from Steam and Power Generation
Systems (Streams 703 and 709)
The characteristics of Streams 703 and 709 are the same, they consist
essentially of coal ash. The two streams are thus likely combined for treat-
ment or disposal. The generation rate of these two streams is 63,000 Mg/yr
in the base case, 77,000 Mg/yr in the MFS case.
Applicable control techniques for this stream are similar to those dis-
cussed for the Slag from Partial Oxidation stream. Available technology re-
quires that gasifier ash and boiler bottom ash be quenched before any sub-
sequent handling or 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 fixation reactions when wetted, much as Portland cement does. When
boiler fly ash is collected and handled entirely in the dry form, it can more
readily be utilized as a resource.
Where landfill is the disposal technique selected, this stream is assumed
to be co-disposed with other solid waste streams in one common landfill. As
discussed in Sections 4.4.1.3 and 4.4,2.1 annualized unit costs for land-
filling the solid waste streams in a common landfill are estimated to be
$2.3 and $4.1/Mg, respectively, for an unlined and lined landfill. Based on
these unit costs, the incremental annualized disposal cost attributable to
this stream would be $221,000 and $394,000/yr for the base case and $177,000
and $316,000/yr for the MFS case (not including administrative and hauling
costs).
513
-------
Solid Waste Source Type 1
Combined FGD Sludges
Control Function 2
4.4.2.7 Combined FGD Sludges - FGD Sludges from Steam and Power Generation
Systems (Streams 705 and 711)
The characteristics of the two streams are the same. For lime/limestone
FGD systems, they consist mainly of calcium sulfate and calcium sulfite, with
some calcium carbonate. (If the FGD system incorporates forced oxidation,
much of the sulfite will be converted to sulfate.) The two streams are likely
combined for treatment or disposal. These streams are generated at a combined
rate of 213,000 Mg/yr (base case) and 266,000 Mg/yr (MFS case).
4.4.2.7.1 Control Function 2 - Treatment
Where forced oxidation is not incorporated in the FGD system, FGD sludge
typically contains 30 to 50 percent solids after thickening or filtration. It
is not a good landfill material in this form because it is thixotropic. To
rectify this problem, treatment by fixation may be practiced. (Where forced
oxidation is employed, the solids might be dewatered to eliminate the thixo-
tropic properties without fixation.)
4.4.2.7.1.1 Control Techniques 1 - Fixation
Several patented processes are available commercially for fixing FGD
sludges. Typically these proprietary processes involve dewatering the sludge
and combining the sludge with boiler fly ash and proprietary additives which
promote pozzolanic reactions, resulting in a material less Teachable, less
permeable and structurally 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 lirne under controlled
temperature and moisture conditions, ICT (lime, betonite and cement), Research
- Cottrell (sludge dewatering prior to fly ash admixing). Unit costs for these
treatments range from $10 to $17 per metric ton of dry solids (100-103).
Another treatment alternative practiced in many coal-fired power plants is
514
-------
Solid Waste Source Type 1
Combined FGD Sludges
Control Function 3
mixing the FGD sludge with boiler bottom and fly ash before disposal. For
coals that generate ashes that are alkaline, mixing the ash with the sludge
will also initiate pozzolanic reactions.
4.4.2.7.2 Control Function 3 - 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 prior to disposal. The use of surface
impoundments will reduce the liquid content of disposal, but the dried solids
are readily soluble when exposed to moisture after disposal, so proper surface
impoundment closure will be essential.
As presented in Table 4-80, the flow rate of the FGD sludges stream is
about 20% of the other inorganic ashes (such as power plant ash, gasifier ash
and Flexicoking fines) combined. Assuming mixing the FGD sludges with these
ashes generate a material suitable for landfill, the incremental annualized
disposal costs for disposing the FGD sludges in a common landfill with all
other solid wastes (at an annualized unit cost of $2.3/Mg for unlined landfill,
$4.1/Mg for lined landfill) would be $490,000 and $870,000/yr for the base
case, and $610,000 and $1,100,000/yr for the MFS case, depending on whether
the landfill is unlined or lined. The basis and assumptions for these cost
estimates have been presented in Sections 4.4.1.3.1, 4.4.2.1.3.1 and Appendix
C.
515
-------
Solid Waste Source Type 1
Dewatered Raw Water Treatment
Sludge
Control Functions 2 and 3
4.4.2.8 Stream 722 - Dewatered Raw Water Treatment Sludge
This stream - composed largely of calcium carbonate and water - is gener-
ated at a rate of 14,000 Mg/yr (base case) and 15,000 Mg/yr (MFS case). The
applicable treatment and disposal techniques for this stream would be similar
to those for the FGD sludge, except that the optimum fication process, the
amount of chemical addition required and hence the treatment cost may differ.
Where landfill is the technique selected, this stream is assumed to be co-
disposed with other solid waste streams in one common landfill.
As discussed in Sections 4.4.1.3 and 4.4.2.1 annualized unit costs for
landfilling the solid waste streams in a common landfill are estimated to be
$2.3 and $4.1/Mg, respectively, for an unlined and lined landfill. Based on
these unit costs, the incremental annualized disposal cost attributable to
this stream would be $32,000 and $57,000/yr for the base case and $35,000 and
$62,000/yr for the MFS case (not including administrative and hauling costs).
516
-------
Solid Waste Source Type 2
Recovered By-Products
4.4.3 Source Type 2 - Recovered By-Products
This source type includes elemental sulfur recovered from the Bulk Sulfur
Removal processes and collected dust from particulate control. The flow rate
of these two streams is estimated to be, respectively, 29.5 Mg/hr (see Tables
4-18 and 4-19) and 0.16 to 2.6 Mg/hr (see Table 3-7). Among other by-products,
recovered phenols are assumed to be burned as a plant fuel (and recovered
ammonia is assumed to be marketed); hence the phenols are not expected to
appear as solid waste.
4.4.3.1 Recovered Elemental Sulfur
Recovered elemental sulfur can be sold as by-product. However, the sulfur
may be contaminated with carbonaceous impurities (from Glaus 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 stream cannot be sold, it can be disposed of in landfills.
There is a potential for elemental sulfur to be oxidized in a landfill
environment, and such oxidation results in acid generation. Acidic leachate
could solubilize trace elements from other wastes in the landfill. Hence
it may be desirable to dispose waste elemental sulfur with alkaline wastes
such as FGD sludges.
4.4.3.2 Collected Coal Dust from Particulate Control
This secondary waste stream consists primarily of coal dust collected
throughout the coal preparation and liquefaction operations. The dust can be
reused as feed to the gasifier or boiler, or can be disposed in landfills.
When landfilled, spraying the dust with water may be required to reduce fugi-
tive dust emission.
517
-------
Solid Waste Source Type 3
Organic Sludge
4.4.4 Source Type 3 - Organic Sludges
This source type includes one stream, namely, the biosludge from the
biological treatment process. This is a secondary waste stream; the flow
rate of this stream has been estimated to be 33,000 Mg/yr and 26,000 Mg/yr
for the base and MFS case, respectively.
518
-------
Solid Waste Source Type 3
Biosludge
Control Function 1 -
Treatment
4.4.4.1 Stream 730 - Biosludge
As discussed in Section 4.3.1.1.4, the biosludge is assumed to consist
of 80% water and 20% solid. The solid is mainly bacterial cell walls with
some other organics. The potentially applicable control techniques are dis-
cussed below.
4.4.4.1.1 Control Function 1 - Treatment
Although no data are available on the composition of this waste at pre-
sent, it is possible that some of the non-biodegradable toxic organics that
might have been present in the raw process liquor (such as polycyclic organics
and aromatic amines) will end up in the sludge through sorption. Thse organ-
ics can be destroyed by incineration.
4.4.4.1.1.1 Control Technique 1 - Incineration
Incineration of municipal and industrial biological oxidation sludges
has been practiced for many years. The application of this treatment tech-
nique to this organic sludge could be expected to destroy greater than 99% of
most organics and reduce the quantity of waste that requires ultimate disposal.
Assuming the biosludge is 20% solids and 70% of the solids are combustible, the
total waste quantity will be reduced by 94% after incineration.
Assuming a heating value of 5500 Kcal/kg (10,000 Btu/hr) for the biosludge,
the heat input to the incinerator will be 2.3 x 107 kcal/hr (9.2 x 10 Btu/hr)
and 1.8 X 107 kcal/hr (7.3 x 107 Btu/hr) for the base case and MFS case,
respectively. Table 4-82 presents the estimated costs for incinerating the
biosludge in a rotary kiln incinerator with energy recovery. The capital in-
vestments for the base case and MFS case are estimated to be, respectively, 16
to 20 million dollars and 15 to 18 million dollars (see Figure C6-2 in Appendix
C6); or about 0.49% to 0.62% and 0.52% to 0.62% of the uncontrolled base plant
costs. The total annualized costs for the two cases are 9.1 and 7.5 million
dollars per year, respectively (see Figure C6-4); or about 0.95% and 0.86% of
519
-------
TABLE 4 -82. SUMMARY OF ESTIMATED COSTS FOR TREATMENT/
DISPOSAL OF BIOSLUDGE
Treatment/Disposal
Incineration Land Treatment
Item Base Case MTS Case Base Case MFS Case
Total Capital
Investment? $106 16 to 20 15 to 18 0.76 0.67
Total Annyalized
Cost**$106 9.1 7.5 0.24 0.22
Unit Capital
Investment, $106/Mg/hr 3.8 to 4.7 4.5 to 5.3 0.18 0.20
Unit Annualized
Cost, $/Mg 280 290 7.4 8.5
% Base Plant Capital
Investment, 0.49 to 0.62 0.52 to 0.62 0.02 0.02
% Base Plant
Annualized Cost, 0.95 0.86 0.03 0.03
* Capital investments for incineration obtained from Figure C 6-2
(Appendix C6) for rotary kiln incinerators with capacities of 9.2
x 107 Btu/hr and 7.3 x 107 Btu/hr.
** Total annualized costs for incineration obtained from Figure C6-4.
520
-------
Solid Waste Source Type 3
Biosludge
Control Function 2 -
Disposal
the uncontrolled plant costs. See Appendix C6 for a more detailed description
of the bases and assumptions for these cost estimates.
Two secondary waste streams are generated by this process, namely, a flue
gas stream and a solid residue stream. It is not possible to estimate the
characteristics of the flue gas, but the cost for controlling this is included
in the incinerator cost estimates presented in Table 4-82. The incinerator
is assumed to be equipped with a scrubber for particulate control. The scrub-
ber blowdown would be routed to the wastewater treatment facility for treat-
ment, if needed.
The flow rates of the residue stream are estimated to be 6 Mg/day and 4.8
Mg/day for the base case and MFS case, respectively. Assuming a 99.9% destruc-
tion of organics (see Appendix B-7 and Appendix C-6 for basis and assumptions
for this estimate) the residue would contain about 0.33% organics, the remain-
der consisting of inert materials. Most of the trace metals originally present
in the biosludge would be accumulated in the residue. Applicable additional
treatment/disposal techniques include fixation/encapsulation and landfill.
4.4.4.1.2 Control Function 2 - Disposal
Biological treatment sludges may be disposed of in landfills, surface
impoundment or by land treatment. Landfill and surface impoundment have been
discussed in the previous sections. The following is a brief description of
land treatment of biosludge.
4.4.4.1.2.1 Control Technique 1 - 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
521
-------
Solid Waste Source Type 3
Biosludge
Control Function 2 -
Disposal
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 neu-
tralizing agents (e.g., lime) may be added to maintain the proper pH level
(7 to 9) (112,113).
The estimated costs for land treating the biosludges are summarized in
Table 4-82. The capital investments are estimated to be 0.76 and 0.67 million
dollars for the base case and MFS case, respectively. These costs are calcu-
lated from installed equipment costs using the the procedures summarized in
in Table 4-1. The installed equipment costs include land preparation cost
p
($0.52/m ), waste spreading equipment costs ($160,000) and monitoring well
costs ($25,000). No land cost was included. It is estimated that about
2 2
430,000 m and 340,000 m of land are required for the base case and MFS case.
2
Assuming a unit land cost of $5,000/10,000 per m , this would increase the total
capital investment by more than 25%. The total annualized costs for the base
and MFS case are, respectively, 0.24 and 0.22 million dollars per year. These
costs are estimated using the unit costs presented in Table 4-2 and assuming
a unit fuel requirement of 36,000 Kcal per Mg of waste landtreated and a labor
requirement of 4,000 hrs/yr. No transporting nor other costs, such as admini-
strative, closure/post-closure and reliability costs are included in the an-
nual ized cost estimates. Depending on the distances, the transportation cost
may more than double the annualized unit costs presented (at $2 and $4/Mg for
a round-trip distance of 5 and 15 km, respectively).
522
-------
Solid Waste Source Type 4
Spent Catalysts
4.4.5 Source Type 4 - Spent Catalysts
This source type includes 11 streams for the base case and 7 streams for
the MFS case. Some streams such as Spent Sulfur Guard and Spent Drying Agent
are not truly spent catalysts. They are included in this source type because
(1) all of the streams in this source type are all small volume, intermittent
streams, and (2) applicable controls are similar for these streams. The flow
rates of streams that fall in this source type are summarized in Table 4-83.
Although the flow rates are presented in Mg/yr basis, most streams are expected
to be generated (removed) once every two or three years.
523
-------
TABLE 4-83. LIST OF SPENT CATALYSTS WASTE STREAMS
Flow Rate, Mg/vr
Stream No.
Stream 204 -
Stream 404 -
Stream 405 -
Stream 433 -
Stream 435 -
Stream 436 -
Stream 439 -
Stream 453 -
Stream 454 -
Stream 444 -
Stream 445 -
Stream 517 -
Stream 518 -
Stream Description
spent solvent hydrogenation catalyst
(Ni-Mo)
spent hydrotreater catalyst from cryogenic
hydrogen recovery (Ni-Mo)
spent drying agents from cryogenic
hydrogen recovery (zeolite)
spent sulfur guard from hydrogen
generation (ZnO)
spent reformer catalyst from hydrogen
generation (Ni-U)
spent shift catalyst from hydrogen
generation (iron oxide)
spent methanation catalyst from hydrogen
generation (NiO)
spent drying agents from ammonia synthesis
(alumina)
spent ammonia synthesis catalyst (iron/
iron oxide)
spent high temperature shift catalyst from
hydrogen generation (Co-Mo)
spent low temperature shift catalyst from
hydrogen generation (Co-Mo)
spent Claus catalysts (bauxite)
spent hydrolysis catalyst (Co-Mo)
Base Case
821
68.5
263
271
181
321
115
172
166
0
0
41
20
MFS Case
821
37.2
172
0
0
0
0
0
0
451
254
47
20
524
-------
Solid Waste Source Type 4
Spent Catalysts
Control Function 1 -
Reuse/Resource Recovery
4.4.5.1 Combined Spent Catalyst Streams - All Streams Listed in Table 4-83
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 treatment, reuse/resource recovery,
and disposal are discussed in general terms in the following sections, with
only brief mention of specific techniques that are applicable to individual
catalysts.
4.4.5.1.1 Control Function 1 - Reuse/Resource Recovery
Spent catalysts may be reused after reactivation by a contractor or the
original vendor; also the metals making up 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 possible.
In practice, return of the spent catalyst to the vendor for reprocessing will
likely be the approach of choice in many cases.
Because of the current tight cobalt supply and the high demand for this
metal, it appears that the cobalt-based shift catalyst could be economically
recovered. Increasing cobalt prices have fostered interest by catalyst manu-
facturers to develop improved methods to regenerate the catalyst, to recover
the metal, and to search for other catalysts (mainly nickel-based) which can
be used in place of the cobalt-based shift catalyst (114).
Regeneration of spent drying agent (Streams 433 and 453), shift cata-
lyst (436), ammonia synthesis catalyst (454) and Glaus catalyst, is expected
to be economically unattractive because of the low market value of the base
materials of these catalysts (see Table 4-82). Spent methanation catalyst
(Stream 439) and ammonia synthesis catalysts (Stream 454), although deactivated
as far as catalyst activity is concerned, may still have a large capacity for
absorption of sulfur compounds and can be used as sulfur guard bed material.
525
-------
Solid Waste Source Type 4
Spent Catalysts and Sulfur Guard
Control Functions 2 and 3
4.4.5.1.2 Control Function 2 - Treatment
Spent catalysts may be chemically fixed or encapsulated before final
disposal to prevent leaching of undesirable substances. When fixing these
with cement-based technique, the weight of the fixed material may be twice
its original weight (1), i.e., a 1:1 chemical/spent catalyst ratio may be
needed. As discussed before, the performance and cost for this alternative
can only be established after thorough treatability studies.
4.4.5.1.3 Control Function 3 - Disposal
If these streams were not reused/reclaimed (per Section 4.4.5.1.1), they
would likely be idsposed of in landfill. Assuming the unit disposal costs
presented in Section 4.4.2.1.3.1 also apply to these wastes (i.e., assuming
that these wastes are disposed of in a common landfill along with all other plant
solid wates), the total incremental annualized cost for disposing these spent
catalysts would be $5,600 and $10,000 for the base case, and $4,100 and $7,400
for the MFS case, depending on whether the landfill is non-lined or lined. Leach-
ing and other characterization data of these streams, which are not currently
available, may indicate additional disposal control requirements which would
affect the disposal costs.
526
-------
Solid Waste
Integrated Control Example 1
4.4.6 Integrated Control Examples
There are 26 solid waste streams identified in the base case, 23 in the
MFS case. As discussed in Section 4.4.1, there are three control functions
potentially applicable to controlling these streams. This section presents
examples of how streams may be combined for ultimate disposal, and how certain
control techniques may be combined to control a particular stream. The ap-
proaches considered in this section are by no means inclusive or representa-
tive of necessary or sufficient control.
4.4.6.1 Integrated^ Control Example 1 - Landfill ing of Combined Waste
Source Types 1, 3 and 4 Streams
As presented in Sections 4.4.2, 4.4.4 and 4.4.5, there are a total of
24 solid waste streams in the base case and 21 in the MFS case that belong to
the Solid Waste Source Types 1, 3 and 4. The total annual flow rates for these
f\ f\
streams amount to about 1.6 x 10 Mg/yr for the base case, 1.5 x 10 Mg/yr
for the MFS case. One potential approach in handling these streams is to dis-
pose all these wastes in one common landfill. It should be re-emphasized that
this approach is just an example. These wastes may well be disposed in more
than one landfill with different control designs or be handled with more than
one control technique. By considering the alternatives of all wastes being
disposed in an unlined landfill, and all wastes being disposed in a lined
landfill, the range of landfill costs in the PCTM should bracket the costs
that might be encountered in practice.
In this example, the wastes are assumed to be delivered to the landfill
site by truck, unloaded at the toe of the slope of the working face, and then
spread on top of the slope. To improve the structural stability of the fill,
the FGD sludge would be mixed with fly ash or gasifier ash before being spread
in layers over the old material. The biosludge, which constitutes about two
percent of the total waste, is expected to be covered by the inert inorganic
ashes all the time. Thus potential odor and site structural stability pro-
blems caused by this material would be alleviated.
527
-------
Solid Waste
Integrated Control Example 1
The estimated costs for this integrated example is summarized in Table
4-84. The capital investments, not including the land cost, for both the
base case and MFS case are the same, namely 11 and 23 million dollars, depend-
ing on whether the landfill is non-lined or lined (see Figure 4-8). These
corrspond to 0.35% to 0.87% of the uncontrolled base plant cost. The total
annualized costs for the base case (3.7 and 6.6 million dollars per year,
respectively, for the non-lined and lined landfill) are slightly higher than
the corresponding MFS values (3.5 and 6.2 million dollars per year) although
the annualized unit costs ($2.3/Mg and $4.1/Mg, respectively, for the non-
lined landfill) are the same as for both cases. The difference in total an-
nualized costs is due to the fact that there is slightly more waste generated
in the base case than the MFS case; however, this difference (1.6 million Mg/yr
vs 1.5 million Mg/yr) is not large enough to affect the annualized unit costs.
As discussed in 4.4.2.1.3, the annualized costs presented do not include admin-
istrative and hauling costs. Including such costs may increase the annualized
costs by three times or more.
528
-------
TABLE 4-84 SUMMARY OF COST ESTIMATES FOR SOLID WASTE INTEGRATED CONTROL EXAMPLES 1 AND 2
PO
Example 1
Base Case
Capital Investment, $106
Total Annual ized Cost, $106
Total Annual ized
Unit Cost, $/Mg
% Base Plant Capital
Investment, %
% Base P.ant Annual ized
Lined
Landfill
23
6.6
4.1
0.78
0.70
Nonlined
Landfill
11
3.7
2.3
0.35
0.39
MFS Case
Lined
Landfill
23
6.2
4.1
0.87
0.70
Nonlined
Landfill
11
3.5
2.3
0.38
0.39
Example 2
Base Case
FBC
Boiler
11
2.5
2.1
0.35
0.22
Nonlined
Landfill
6
1.6
2.4
0.19
0.25
Total
17
4.1
4.5
0.54
0.47
MFS Case
FBC
Boiler
65
1.6
2.7
0.23
0.18
Nonlined
Landfill
3
0.87
2.9
0.1
0.1
Total
6.8
2.5
5.6
0.33
0.28
Cost, %
-------
Solid Waste
Integrated Control Example 2
4.4.6.2 Integrated Control Example 2 - FBC Boiler + Landfill of Combined
Flexicoking Wastes
In this control example (see Figure 4-9), the Combined Flexicoking Waste
Stream (Streams 302, 303, 306) was assumed to be used as feed to a Fluidized
Bed Combustor (FBC) boiler (see Section 4.4.2.1.1). The ashes from the boiler
are disposed of in a landfill. Burning the Flexicoking wastes in the boiler
will recover the carbon heating values of the wastes. Landfilling the ashes
generated from the boiler is an established disposal technique. As presented
in Table 4-80, the feed to the FBC Boiler is 1.2 million Mg/yr of wastes for
the base case, and 0.59 million Mg/yr for the MFS case.
Table 4-84 summarizes the cost estimates for this control example. The
FBC boiler costs have been presented before (in Table 4-81). The landfill
costs presented in Table 4-83 are based on estimates (see Figure 4-8) for
landfills with 6.5 x 10 Mg/yr and 3.0 x 105 Mg/yr capacities. These are the
expected ash quantities generated from the FBC boiler for the base case and
MFS case, respectively. Non-lined landfill is used as an example since the
residuals are essentially inorganic coal ashes. Some site-specific factors
(such as high groundwater table) may impose additional disposal control require-
ments (such as lining).
Total capital investments for these examples, as presented, are estimated
to be 17 and 6.8 million dollars for the base case and MFS case, respectively.
The total annualized unit costs are $4.5 and $5.6/Mg for the two cases. As
discussed before, no steam credits, land cost, hauling cost and other admini-
strative costs were included in the cost estimates. Including these values
would change the costs for this example.
530
-------
FLUE GAS
, >
Combined FTexicoking
in
CO
Wastes (Streams 302,
303
306)
FBC BOILER
Ash
LANDFILL
Figure 4.9. Solid waste control example 2: FBC boiler and landfill
for Flexicoking wastes.
-------
Solid Waste
Integrated Control Example 3
4.4.6.3 Integrated Control Example 3 - Incineration + Landfill ing of Biosludge
Incinerating the biosludge will reduce the potential toxicity of and the
volume of the waste that requires ultimate disposal. Assuming the biosludge
is 20% solids and 70% of the solids are combustible, the total waste quantity
will be reduced brom 100 Mg/day to 6 Mg/day for the base case, from 80 Mg/day
to 4.8 Mg/day for the MFS case. Assuming annualized unit incineration costs
of $280/Mg and $290/Mg for the two cases (see Table 4-82) and unit disposal
costs of $4.1/Mg for a lined landfill (see 4.4.2.1.3.1) (i.e., assuming the
incineration ash will be co-disposed with other solid waste in one lined land-
fill), total annualized costs for this example will be 8.9 and 5.4 million
dollars per year for the two cases, respectively, or about 0.94% and 0.61% of
the uncontrolled base plant costs. Since the landfill is assumed to accept
other wastes, no incremental capital investment attributable to just the bio-
sludge is estimated for this example.
532
-------
5. DATA LIMITATIONS, GAPS AND RESEARCH NEEDS
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, there-
fore, 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 suggesting the confidence which can be
placed in the uncontrolled discharge rates and the effectiveness of specific
controls.
Waste streams which may be considered unique to EDS base case and MFS case
designs have been emphasized in this section. These "unique" streams differ
from analogous types of streams in related conventional industries (e.g., acid
gases, organics-containing wastewater streams) in terms of detailed composition;
these composition differences can result in differences in the performance and
design of control equipment utilized. Unique streams are emphasized in Section
5 because the data limitations (concerning detailed composition, control perfor-
mance/design) can be significant for these streams.
On the other hand, waste streams which are basically identical in compo-
sition to wastes generated in other industries (e.g., boiler flue gas, coal
pile runoff, raw water treatment sludges and boiler ash) will experience con-
trol performances and designs which are identical to those employed for these
streams in the related industries. These streams are not considered in this
section. In general, much more is known about the composition of these con-
ventional , "non-unique" streams compared to the streams unique to EDS; control
performance/design is better understood through past experience in conventional
industries, and data limitations are less severe.
533
-------
Key data sources and the bases for characterization and control of unique
gaseous, aqueous and solid waste streams are summarized respectively in Tables
5-1, 5-2 and 5-3 at the end of this section. Data gaps, limitations, and
additional data needs for each waste stream are also summarized in the tables.
For each waste stream, data sources and limitations are also summarized for
some of the alternative individual control techniques that would potentially
be applicable to that stream.
In general, characteristics of the uncontrolled unique waste streams were
based on conceptual commercial design estimates provided by Exxon, and on data
obtained by EPA and by Exxon on the 227 Mg/day (250 ton coal/day) EDS pilot
plant at Baytown, Texas. The Exxon conceptual design estimates were derived
using test data from small operating units, together with computer process
synthesis. Wherever necessary, additional characteristics of the uncontrolled
unique waste streams were estimated using data from other direct coal lique-
faction processes (e.g., the Solvent Refined Coal-II process) and data from
related industries such as petroleum refining and electric utilities. In all
cases, the flow rates and compositions of all waste streams were based on an
EDS commercial plant processing 1,134 Mg/hr (30,000 tons per stream day) of
"as received" Illinois No. 6 coal in the liquefaction area. This EDS plant
o
would produce about 9,580 m (60,240 barrels) per stream day of fuel oil equi-
o
valent for the base case design, or 11,300 m (71,080 barrels) per stream day
of fuel oil equivalent for the MFS case design. These flow rates and composi-
tions might, of course, vary in practice due to differences in design, coal
type or plant operating conditions, and due to uncertainties in estimation.
In a great number of cases, however, the uncertainties relating to the charac-
teristics of waste streams would probably have limited impact on the selection
of pollution control approach, and possibly limited impact on the expected
performance of specific pollution control technology.
Since there are no existing EDS commercial plants, no direct operating
experience is available to accurately indicate the detailed stream composi-
tion, or the performance or costs of applicable controls. For certain control
systems (e.g., Claus bulk sulfur recovery and Wellman-Lord tail gas treatment)
the existing data base from applications in related industries probably re-
flects gross pollutant removal efficiencies and associated costs in an EDS
534
-------
facility reasonably well. However, for control systems for which performance
and cost are highly sensitive to individual components present in the waste
stream (e.g., activated sludge and chemical oxidation), the limited data from
conventional applications might be less indicative of performance/cost in an
EDS plant. The limitations in the control performance data are twofold.
First, the performance of control techniques in related applications is often
known only in terms of major constituents, gross parameters or classes of
substances. Little may be known about control performance for specific or-
ganics, trace elements or other trace constituents. Secondly, the performance
characteristics of many controls are uncertain even for the major constituent
and gross properties.
A data gap or limitation which exists for essentially all pollution con-
trol technologies relates to control reliability. Reliability data for many
control techniques in conventional industries are limited. Differences between
characteristics of waste streams from direct liquefaction and related indus-
tries only compounds the uncertainty of available reliability data.
535
-------
TABLE 5-1. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR GASEOUS WASTE STREAMS AND AIR POLLUTION CONTROL TECHNOLOGIES
Combined Add Ga;
Data Source and Basis
Stream
Data Gaps/Limitations
Additional Data/Research Needs
cn
OJ
CD
Acid Gas-f rom-PEA Regenerator (Stream 508)
Acid gas flow rate and composition, with the exception of
COS, are based on estimates provided by EXXON. Concen-
tration of COS is estimated by assuming that it is approx-
imately equal to COS concentration in the acid gas from
the DEA unit in the SRC-II commercial design.
Reference: Section 3.3.3.3.1
Acid Gas from Sour Hater Stripper/Ammonia Recovery
(Stream 50JT
Acid gas flow rate and composition are based on esti-
mates provided by EXXON.
Reference: Section 4.2.1.1
Flash Gas from Partial Oxidation (Stream 440)
Composition and flow rate estimates for this stream
are based on Texaco gasifier pilot plant test data per-
formed with SRC-II residue from Kentucky 9/14 coal.
Reference: Section 3.3.4.2.1
Selected Control Alternatives for Combined Acid Gas Stream
Claus Process
Performance and cost estimates are based on data from
application in petroleum refineries, gas processing
plants, and coke plants. However, the composition
for major species and flow rate of the combined acid
gas stream from the EDS process are well within the
ranye covered by these other applications.
References: Section 4.2.1, Appendix A-6.
Secondary Waste Stream
Spent catalyst is the only secondary waste stream
from the Claus process.
Beavon Sulfur Removal Process (BSRP)
Performance and cost estimates are based on data for
Claus tail gas treatment in petroleum refineries.
References: Section 4.2.1, Appendix A-9
No data on: 1) minor and trace components present
in this stream or the sour gas streams entering
the DEA scrubber, such as COS, CS2, mercaptans,
HCN, and heavy organics; 2) level of NH3 present
in this stream or sour gas streams entering the
DEA scrubbers as a function of process operating
conditions and co«! type.
No data on trace components present in the
stream such as phenolics and other high molec-
ular weight organics.
No data on composition and flow rate estimates
for this stream based on EDS residue from
Illinois No. 6 and other coals for a range
of EDS design/operating conditions.
The amount of NH3 present in the combined acid
gas is marginally high; any unburned NHj may
result in the formation of solids such as ammo-
nium hydrosulfide, ammonium polysulfides,
ammonium carbonates or carbjmates and/or ammo-
nium sulfate causing solids deposition., solids
plugging, and catalyst deactivation problems
downstream.
Generation rate and characteristics of spent
Claus catalyst are not well known.
Uncertainties relating to the performance of the
catalytic hydrogenation section under moderately
high C02 concentrations (11-13%), especially the
COS levels in the BSRP off-gas.
Distribution of sulfur species has limited
impact on selection of pollution con-
trol approach or the sizing, performance,
or cost of specific pollution control
technologies employed. However, the
types and levels of other .minor and trace
components present need to be verified,
especially if changes in process design
or coal type are considered.
The levels of trace components present
need to be determined from demonstration
or first commercial plants.
Pilot plant tests in Texaco gasifier (or
other typas of gasification units) with EDS
vacuum bottoms slurry need to be performed
to determine composition ami flow rate of
this flash gas, for a variety of coals and
design/operating conditions.
Data needed to determine if the amount of
NH3 present in the combined acid gas is
acceptable for conventional Claus plants,
or whether alternate Claus designs or con-
figurations are necessary to minimize
problems. Also, data are needed to verify
performance of Claus plants in ECS demon-
stration or first commercial plants.
Determination of the leaching charac
tics of spent Claus catalyst.
Determination of the COS levels in the
effluent from the catalytic hydrogenator
under moderately high C02 concentration
levels. Verify Beavon performance in EDS
demonstration or first commercial plants.
(Continued)
-------
TABLE 5-1. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR GASEOUS WASTE STREAMS AND AIR POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
cn
CO
Secondary Waste Streams
1) Sour condensate
2) Stretford solution purge
3) Spent Beavon catalyst
4) 'Stretford oxidizer vent gas
SCOT Process
Performance and cost estimates are based on data
for Claus tail gas treatment in petroleum
refineries.
Secondary Waste Streams
1) Sour condensate
2) Spent SCOT catalyst
Uellman-Lord Process
Performance and cost estimates are based on data for
Claus tail gas treatment in petroleum refineries.
References: Section 4.2.1, Appendix A-10.
Characteristics of the condensate, particularly
with respect to H2S and NH3 levels.
Generation rate and characteristics of the
purge stream are based on limited data and not
well established. Resource recovery of this
purge stream by reductive incineration has not
been demonstrated on commercial scale.
Generation rate and characteristics of spent
Beavon catalyst are not well known.
Characterization data are not available for
oxidizer vent gas. However, in EDS applica-
tions there probably would not be any gaseous
components of environmental concern present
in this vent gas.
No publicly available data on the performance
of the catalytic hydrogenation section under
moderately high C02 concentrations (15-18.),
especially with respect to the COS levels; no
data on the removal efficiency for COS and CS2
in the absorber; limited data on performance of
DIPA versus MDEA in H2S absorption and C02
co-absorption.
Characteristics of the sour condensate, partic-
ularly with respect to HjS and NH3 levels.
Generation rate and characteristics of spent
SCOT catalyst are not well known.
Claus tail gas is incinerated prior to absorp-
tion in the Wellman-Lord process. Once incin-
erated, there is no difference between the
incinerated tall gas streams from EDS Claus
plants and ttiose from existing refinery
Claus plants.
Detemiination of the characteristics of
sour condensate is needed for the eval-
uation of control alternatives. Test
control alternatives if needed.
Acquisition of data from EDS demonstration
or first commercial plants on characteris-
tics of Stretford solution purge under
different feed conditions. Demonstration
of "reductive incineration process on
commercial scale.
Determination of the leaching character-
istics of spent Beavon catalyst.
Determination of-the composition and flow
rate of this vent gas in EDS demonstration
or first commercial plants.
Determination of performance of SCOT
catalytic hydrogenator and absorber
under moderately high C02 concentra-
tions; acquisition of data on DIPA ver-
sus MDEA performance as absorption
solution by test: in petrolaum refineries
or petrochemical plants. Verify SCOT
performance in EDS demonstration or first
commercial plants.
Determination of the characteristics of
sour condensate is needed for the eval-
uation of control alternatives.
Determination of the leaching character-
istics of spent SCOT catalyst.
Verify Wellman-Lord performance in EDS
demonstration or first commercial plants.
(Continued)
-------
TABLE 5-1. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR GASEOUS WASTE STREAMS AND AIR POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
cn
oo
00
Secondary Waste Streams
1) Acidic waste water
2) Thiosulfate/sulfate by-product purge
Thermal Incineration
Performance and cost estimates are based on data for
incineration of gaseous and liquid wastes.
References: Section 4.2.1, Appendix A-16
Acid Gas from Acid Gas Removal Unit in Hydrogen
Purification (Stream 428)
Composition and flow rates for C02, H;>S, and HjO are
based on estimates provided by EXXON. Composition of
other components are estimated using: 1) shift gas com-
position data from the Texaco gasifier in the processing
of SRC-II residue and other Texaco gasification data;
2) performance characteristics of the Catacarb process.
References: Section 3.3.4.2.1
Limited characterization data are available.
Limited generation rate and characterization
data are available.
None identified for incineration of off-gas
from Claus tail gas treatment.
Uncertainties relating to the composition of
minor constituents, especially NH3, COS, CO.
Verify characteristics of this waste
stream in EDS demonstration or first
commercial plant.
Verify characteristics of this waste
stream in EDS demonstration or first
commercial plant.
None identified for incineration of off-
gas from Claus tail gas treatment.
Determination of the levels of NH3, COS
and CO present in the shift gas from
pilot plant tests. The concentration
levels of these species may impact the
selection of the pollution control
approach and specific control technology.
Stretford Process
Performance and cost estimates are based on data for
feed gas containing a few percent C02 in gas pro-
cessing and petroleum refinery applications.
References: Section 4.2.1, Appendix A-7
Secondary Waste Streams
1) Stretford oxidizer vent gas
2) Stretford solution purge
Limited data on performance of the Stretford
process for feed gas with high C02 levels (over
90' for Stream 428). There is some concern
that C02 absorption by the Stretford solution
would lower the pH and increase the bicarbonate/
carbonate ratio, which in turn would lower the
rate of H2$ absorption.
Generation rate and characteristics of oxidizer
vent gas are-not well known.
No data on the generation rate and characteris-
tics of this purge stream for feed gas contain-
ing high C02 levels. Resource recovery of this
purge stream by reductive incineration has not
been demonstrated on commercial scale.
Acquisition of data on performance of
the Stretford process for feed gas con-
taining high levels of C02. The Stret-
ford unit located in St. Elmo, Illinois
and operating on stream consisting of
85 i C02 and 15 H2$ would be a candidate
test site.
Determination of the generation rate, NHj
level and trace contaminant levels of this
vent gas, so that control alternatives can
be evaluated.
Acquisition of data on the generation
rate and characteristics of the Stret-
ford solution purge in plants operating
with high C02 feed gas. Demonstration
of the reductive incineration process on
commercial scale.
(Continued)
-------
TABLE 5-1. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR GASEOUS WASTE STREAMS AND AIR POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
cn
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10
Flexicoking Heater/Gasifier Sour Fuel Gas (Stream 304)
Sour fuel gas flow rate and composition are based on
estimates provided by EXXON.
References: Section 3.3.4.1.1
Stretford Process
Performance and cost estimates are based on data for
feed gas containing a few percent COo in gas pro-
cessing and petroleum refinery applications.
References. Section 4.2.1, Appendix A-7
Secondary Waste Streams
1) Stretford oxidizer vent gas.
2) Stretford solution purge
Slurry Drier Vent Gas (Stream 102)
Slurry dryer vent gas flow rate and composition are based
on estimates provided by EXXON.
Reference: Section 3.3.2.1.1
Vacuum Fractionator Off-Gases (Stream 153/156)
Flow rate and composition are based on estimates provided
by EXXON.
Reference: Section 3.3.3.1.1
Stretford Process
Performance and cost estimates are based on data for
feed gas containing a few percent C02 in gas pro-
cessing and petroleum refinery applications.
Secondary Waste Streams
1) Stretford oxidizer vent gas
Uncertainties concerning the levels and dis-
tribution of sulfur species, and the flow
rate of this fuel gas.
None identified.
11.6% C02.
Feed gas contains only
Characterization data are not available. How-
ever, feed gas does not contain NH3 or mercaptans
and these pollutants would not be present in the
vent gas.
Limited data on generation rate and characteris-
tics of the purge stream. Resource recovery of
this purge stream by reductive incineration has
not yet been demonstrated on commercial scale.
No data on minor and trace constituents of this
vent gas.
Uncertainty relating to the level of H^S in the
gas stream. Also, no data on minor and trace
constituents of this gas stream.
None identified.
Characterization data are not available. How-
ever, feed gas streams are not presently known
to contain NHj or mercaptans.
Verify characteristics of this fuel gas
stream in EDS demonstration or first com-
mercial plants.
Verify Stretford performance in EDS de-
monstration or first commercial plants.
Determination of the composition and flow
rate of this vent gas in EDS demonstration
or first commercial plant.
Acquisition of data on characteristics
of Stretford solution purge under dif-
ferent feed conditions. Demonstration
of reductive incineration process on
commercial scale.
Determination of the NH3, COS, and mer-
captan level in the vent gas in EDS
demonstration or first commercial plant.
Better definition of H2S level in the
gas stream. Determination of the NH3,
COS and mercaptan levels and nature of
organics in EDS demonstration or first
commercial plant.
Verify Stretford performance in EDS de-
monstration or first commercial plant.
Determination of the composition and flow
rate of this vent gas in EDS demonstra-
tion or first commercial plant.
(Continued)
-------
TABLE 5-1. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR GASEOUS WASTE STREAMS AND AIR POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
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2) Stretford solution purge
Transient Waste Gases
Transient Waste Gas from Liquefaction Reactor
(Stream 8037
Estimated to be similar in composition and flow rate to
the liquefaction separator sour gas. Emission fre-
quency and duration are based on engineering
assumptions.
Reference: Section 3.3.2.1.1
Transient Waste Gas from Flexicoking (Stream 801)
Estimated to be similar in composition and flow rate to
the Flexicoker fractionator off-gas. Emission frequency
and duration are based on engineering assumptions.
Reference: Section 3.3.4.1.1
Transient Waste Gas from Partial Oxidation (Stream 802)
Estimated to be similar in composition and flow rate to
the quenched syngas from the Texaco gasifier. Emission
frequency and duration are based on engineering
assumptions.
Reference: Section 3.3.4.2.1
Flaring
Performance and cost estimates are based on data
for flaring of light hydrocarbons.
References: Section 4.2.1, Appendix A-15
Thermal Incineration
Performance and cost estimates are based on data for
incineration of gaseous and liquid wastes.
References: Section 4.2.1, Appendix A-16
Limited data on generation rate and characteris-
tics of the purge stream. Resource recovery of
this purge stream by reductive incineration has
not been demonstrated on commercial scale.
No data on flow rate, composition, emission fre-
quency or duration for this waste stream.
No data on flow rate, composition, emission fre-
quency or duration for this waste stream.
No data on flow rate, composition, emission fre-
quency or duration for this waste streair.
Limited data on destruction efficiency for CO
and light hydrocarbons such as natural gas,
ethylene, and propane. No data on destruction
efficiency for high molecular weight organics
expected to be present in transient waste gases.
Limited data on destruction efficiency for high
molecular weight organics.
Acquisition of additional data on char-
acteristics of Stretford solution purge.
Demonstration of reductive incineration
on commercial scale.
Data on the nature and levels of organics
are needed. However, it would be difficult
to formulate a research program to acquire
these data.
Data on the nature and levels of organics
are needed. However, it would be difficult
to formulate a research program to acquire
these data.
Data on the nature and levels of organics
are needed. However, it would be difficult
to formulate a research program to acquire
these data.
Acquisition of data on destruction
efficiency for representative organic
compounds, especially C$+ organics and
refractory compounds such as polycyclic
organic matter (POM). This is a gen-
eral data need for flares.
Acquisition of data on destruction
efficiency for high molecular weight
organics. This is a general data need
pertinent to the incineration of hazard-
ous waste streams.
(Continued)
-------
TABLE 5-1. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR GASEOUS WASTE STREAMS AND AIR POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
cn
Sodium Throwaway Process
Performance and cost estimates are based on data for
treating boiler flue gases.
References: Sections 4.2.1, 4.2.2, Appendix A-20
Regeneration/Decommissioning Off-Gas from High and Low
Temperature Shift Catalysts (Streams 449/450;
Off-gas composition and flow rate are based on estimates
provided in permit applications for the AN3 Synthetic
Natural Gas plant. Emission frequency and duration are
based on engineering estimates.
Reference: Section 3.3.4.2.1
Sodium Throwaway Process
Performance and cost estimates are based on data for
treating boiler flue gases.
References: Sections 4.2.1, 4.2.2, Appendix A-20
Vent Gas from CO? Removal by Catacarb grocess (Stream 426)
CO? and H£ composition and flow rates are based on esti-
mates provided by EXXON. Composition of other components
are based on data for the Catacarb process.
Reference: Section 3.3.4.2.1
Thermal Incineration
Performance and cost estimates are based on data for
incineration of gaseous and liquid wastes.
References: Section 4.2.1, Appendix A-16
Catalytic Incineration
Performance and cost estimates are based on data for
gas streams from coating ovens, printing plants, and
manufacture of organic chemicals.
References: Section 4.2.1, Appendix A-17
None identified.
None identified.
No data or flow rate, composition, emission fre-
quency or duration for this off-gas.
Limited or no data on performance under highly
variable flow rate and high SOj loading (13 )
conditions.
Uncertainty relating to hydrocarbon and CO con-
centrations in vent gas.
None identified for this waste strear.
Data on performance of catalytic incineration
for this waste stream or similar waste streams
are not available.
Acquisition of data on characteristics
of this off-gas during the regeneration/
decommissioning of sour shift catalysts
in petroleum refineries, petrochemical
plants, or SNG plants.
Determination of the practicality of
controlling this off-gas with the
sodium throwaway process. Acquisition
of data on the removal efficiency for
SO, at high inlet concentrations.
Verify characteristics of this waste
stream in EDS demonstration or first
commercial plants.
Verify incinerator performance in EDS
demonstration or first coitmercial
plant.
Verify catalytic incinerator performance
in EDS demonstration or first commercial
plant.
(Continued)
-------
TABLE 5-1. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR GASEOUS WASTE STREAMS AND AIR POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
Catalyst Regeneration Off-Gases
Regeneration/Decommissioning Off-Gas from the Reformer
Catalyst (Stream 446T
Off-gas generation rate and composition are based on
typical catalyst regeneration off-gas values. Emission
frequency and duration are based on engineering estimates
Reference: Section 3.3.4.2.1
Decommissioning Off-Gas from the Methanation Catalyst
No data on flow rate, composition, emission fre-
quency or duration for this off-gas.
Acquisition of data on characteristics
of this off-gas during the regeneration/
decommissioning of reformer catalyst in
petroleum refineries, petrochemical
plants, or SNG -•lants, and EDS demonstration
or first commercial plants.
Off-gas generation rate and composition are based on
typical catalyst decommissioning procedures. Emission
frequency and duration aic uasca un engineering estimates.
Reference: Section 3.3.4.2.1
Selected Control Alternatives for Catalyst Regeneration Off
No data on flow rate, composition, emission fre-
quency or duration for this off-gas.
-Gas
Acquisition of data on characteristics
of this off-gas during the decommission-
ing of methanation catalyst in petroleum
refineries, petrochemical plants, or SNG
plants, and EDS demonstration or first
commercial plants.
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Performance and cost estimates are based on data for
flaring of light hydrocarbons.
References: Sections 4.2.1, 4.2 3.3.1.1,
Appendix A-15
Thermal Incineration
Performance and cost estimates are based on data for
incineration of gaseous and liquid wastes.
References: Sections 4.2.1, 4.2.3.3.1.2,
Appendix A-16
Fugitive Organic Emissions from Process Equipment
Emission estimates for fugitive organic emissions from
leaking process equipment were based on emission factors
for these components for conventional petroleum refin-
ing process equipment. Component counts were based on
estimates provided by EXXON.
Reference: Section 3.3.7.1
Data on flare performance for these waste
waste streams ?re not available.
Data on gas incinerator performance for
these waste streams are not available.
Characterization data are not available for EDS
liquids or their vapors, or on leak frequency/
rate in commercial scale direct liquefaction
plants.
There is a general need for data on
destruction efficiency of hydrocarbons
in flaring. Also, verify flare per-
formance in EDS demonstration or first
commercial plants.
Verify incinerator performance in EDS
demonstration or first commercial plants.
Exact composition of vapors from EDS
plant process equipment may differ from
petroleum refinery process equipment;
however, the control technology that are
applicable are not likely to be affected
by these characteristics. Since these
emissions directly enter the atmosphere,
additional information on specific con-
stituents of the vapor may be desirable.
Also, leak frequency and rate might differ
(e.g., abrasive slurries) from refineries;
emission factors need to be developed
based upon data from initial direct lique-
faction plants.
(Continued)
-------
TABLE 5-1 DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR GASEOUS WASTE STREAMS AND AIR POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
in
Leak Detection and Repair Methods
Leak detection and repair methods have been success-
fully used to control fugitive organic emission from
petroleum refining equipment. This technique was
assumed to be applicable to EDS process equipment.
Emission estimates were based upon emission factors
developed from test data for petroleum refining pro-
cess equipment.
References: Section 4.2.5, Appendix A-18
Equipment Specification
Replacement of leaking equipment with leakless com-
ponents has been successfully used for the control
of fugitive organic emissions from petroleum refin-
ing equipment. This technique was assumed to be
applicable to EDS process equipment. Emission
estimates were based upon emission factors devel-
oped from test data for petroleum refining process
equipment.
References. Section 4.2.5, Appendix A-18
Evaporative Emissions from Product and By-Product
Storage (Stream 751)
Emission estimates were based upon emission factors
developed from test data for conventional petroleum
liquid storage. The amount and types of liquids
stored and types of storage vessels were based on
estimates provided by EXXON.
References: Section 3.3.5.5.1
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 stor-
age tanks containing synthetic liquids. Emission
estimates were based upon emission factors devel-
oped from test data for petroleum liquids storage.
Reference: Section 4.2.5
Emission factors for "controlled" fugitive
sources (employing leak detection/repair
methods) could differ compared to the conven-
tional refinery case.
Emission factors for "controlled" fugitive
sources (employing equipment specification)
could differ compared to the conventional
refinery case.
Characterization data are not available for EDS
liquids or their vapors.
The performance of secondary seals is not
expected to be different for EDS liquid storage
tanks.
Determination of emission factors for
fugitive organics sources employing
leak detection/repair methods in EDS
demonstration or first commercial
plants.
Determination of emission factors for
fugitive organics sources employing
equipment specification in EDS de-
monstration or first commercial plants.
Exact composition of vapors from EDS
product and by-product storage may dif-
fer from those of conventional petroleum
liquids' however, the control technol-
ogies that are applicable are not likely
to be affected by tnese characteristics.
Since these emissions directly enter
the atmosphere, additional information
on specific constitutents of the vapor
may be desirable.
Research needs relative to the charac-
terization of the emissions and not to
the controls.
(Continued)
-------
TABLE 5-1. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR GASEOUS WASTE STREAMS AND AIR POLLUTION CONTROL TECHNOLOGIES
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
cn
Internal Floaters on Fixed Roof Tanks
Since internal floaters are used to control evapora-
tive emissions from fixed roof tanks storing petro-
leum 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.
The performance of internal floaters is not
expected to be different for EDS liquid storage
tanks.
Research needs relative to the charac-
terization of the emiss-:rs and not to
the controls.
Reference: Section 4.2.5
-------
TABLE 5-2. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR WASTEWATER STREAMS AND WATER POLLUTION CONTROL TECHNOLOGIES
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
Stream A and other High Phenolic Streams
Liquefaction Cold Separator Wastewater (Stream 106),
Atmospheric Fractionator Overhead Drum Wastewater
(Stream 152), Vacuum Fractionator Overhead Drum Waste-
water (Stream 155), Solvent Hydrogenation Fractionator
Overhead Drum Wastewater (Stream 252)
The characteristics of these streams are based upon Exxon
design estimates and analytical data on the specific
streams from the EDS pilot plants. There are differences
between the pilot data sets, and between the pilot data
and earlier design estimates.
References: Section 3.3.2.2.2, 3.3.3.1.1, and 3.3.3.2.2
Solvent Hydrogenation Cold Separator Wastewater
(Stream 202), Flexicokjng Fractionator Overhead Drum
Wastewater (Stream 308), Flexicokinq Recontacting Drum
Master (Stream 307J
The phenols and dissolved gases concentrations in these
streams are based upon Exxon design estimates.
References: Sections 3.3.2.1.2, 3.3.3.2.2, and 3.3.4.1.2
Slurry Drier Cold Separator Wastewater (Stream 103)
The phenols and dissolved gases concentrations in this
stream are based on Exxon design estimates.
Selected Control Techniques for Stream A
Phenosolvan
The performance and cost estimates are based upon
published data on Lurgi gasification plants.
References: Section 4.4.1.1.2.1, Appendix B-5
Secondary Waste Streams
Recovered Phenol
Limited data on the characteristics of these waste
streams are available from EDS pilot plant.
Confirming data on a full range of organics are
needed to allow better estimate of control per-
formances. Also, data on conventional water
pollutants and dissolved gases are needed.
Same as above, except data are only available from
small operating units.
Same as above.
The performance has not been determined for EDS
wastewaters.
Data on the characteristics of this stream are
not available. The purity of this stream may
affect its resale potentials.
Collect confirming data on a full
range of organics, conventional pol-
lutants, dissolved gases in EDS
demonstratio" or first commercial
plants.
Same as above.
Same as above.
Determine performance of Phenosolvan
for wastewater streams from EDS
demonstration or first commercial
plants.
Characterization of this stream should
be performed in EDS demonstration or
first commercial plants to evaluate
applicable resource recovery alterna-
tives.
(Continued)
-------
TABLE 5-2. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR WASTEWATER STREAMS AND WATER POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
Chem Pro
The performance and cost estimates are based upon
vendor quotes, and data from the by-product coking
industry and solvent extraction process.
The performance has not been determined for EDS
wastewaters.
Collect performance data on Chem Pro in
EDS demonstration or first commercial
plants.
References: Section 4.4.1.1.2.2, Appendix B-5
Secondary Haste Stream
Recovered Phenol
Data on the characteristics of this stream are
not available. The purity of this stream may
affect its resale potentials.
Characteri zatiori of this stream should
be performed in EDS demonstration or
first commercial plants to evaluate
applicable resource recovery alter-
natives.
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Resin Adsorption
The performance and cost estimates are based upon
published data on organic chemical industries.
The performance has not been determined for EDS
wastewaters.
References: Section 4.3.1.1.2.3, Appendix B-10
Secondary Waste Stream
Recovered Phenol
Data on the characteristics of this stream are
not available. The purity of this stream may
affect its resale potentials.
The performance and cost effectiveness
of this process on high concentration
organic waste streams should be deter-
mined. Research effort should be
directed toward determining feasibility
of the process by concentrating on the
following areas of study: maximum
period of operating cycle, phenol and
organics leakage during loading as a
function of residence time, and regen-
eration requirements. Also, collect
performance data in EDS demonstration
or first commercial plants, if resin
absorption were to be applied.
Characterization of this stream should
be performed in EDS demonstration or
first commercial plants to evaluate
applicable resource recovery alter-
natives.
(Continued)
-------
TABLE 5-2 DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR WASTEWATER STREAMS AND WATER POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
Wet Air Oxidation
The performance of this process is based upon pub-
lished data on high COD containing wastewaters.
Costs are based on vendor quotes.
Performance has not been determined for EDS
wastewaters. Also, traditionally this process
has been applied to waste streams with much
smaller sizes (about one-tenth or less) than the
EDS waste streams.
In principle, most organics in the EDS
wastewaters would be oxidized under the
operating conditions of this process.
Collect performance data in EDS demon-
stration or first commercial plants, if
wet air oxidation were to be applied.
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References: Section 4.3.1.1.2.4, Appendix B-6
Phosam-W
The performance and costs are based upon published
literature values on coking industry, Lurgi gasifi-
cation plants and oil shale operations.
References: Section 4.3.1.1.3.1, Appendix B-8
Secondary Waste Streams
1) Recovered Ammonia
2) Stripper Overhead
Chevron WWT
The performance and cost estimates are based upon
published data on refinery operations.
Performance has not been determined for EDS
wastewaters.
Characteristics of impurities present
are not known.
Characteristics of major components (NH3,
H£S, water vapor) are known. Data on minor
and trace components are lacking.
Performance has not oeen determined for EDS
wastewaters.
Collect performance data in EDS
demonstration or first commercial
plants.
Further characterization of this stream
to check impurities is needed; this stream
will likely be sold as a by-product.
Further characterization of this stream
with respect to organics is needed.
Also, verify characteristics of this
stream in EDS demonstration or first
commercia1 plants, if applicable.
Collect performance data in EDS demon-
stration or first commercial plants.
References. Section 4.3.1.1.3.2, Appendix B-9
Secondary Waste Streams
1) Recovered Ammonia
2) Stripper Overhead
Characteristics of impurities present
are not known.
Characteristics of major components (NH3,
H£S, water vapor) are known. Data on
minor and trace components are lacking.
Further characterization of this stream
to check impurities is needed? this
stream will likely be sold as a by-product.
Further characterization of this stream
with respect to organics is needed. Also,
verify characteristics of this stream in
EDS demonstration or first commercial
plants, if applicable. .. ..
(Continued)
-------
TABLE 5-2. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR WASTEWATER STREAMS AND WATER POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data Research Needs
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Biological Oxidation (Activated Sludge)
Performance is based upon that typically realized in
applications in various related industries. Actual
performance will be specific to the exact character-
istics of the wastewater. Costs are based upon
values reported in the literature, appropriately
scaled on the basis of system loading.
References. Section 4.3.1.1.4.1, Appendix B-10
Secondary Waste Stream
Biosludge
Activated Carbon Absorption
Removal 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 refin-
ing and by-product coking industries, extrapolated
on the basis of COD loading.
References: Section 4.3.1.1.5.1, Appendix B-15
Performance has not been determined for the
specific constituents in EDS wastewaters.
Only by direct testing of the wastewater to
be tested can the performance of an acti-
vated sludge or any other biological
treatment system be determined with certainty.
The flow rate and characteristic of this stream
are not known. These can only be determined by
testing with the actual wastestream. Also, per-
formance of disposal alternatives (incineration,
land disposal) are not known.
Performance has not been determined for the spe-
cific constituents in the EDS wastewaters.
Bench-and pilot studies should be performed
to determine the degree of biodegradability
of the EDS wastewater. Samples for testing
may be obtained from the EDS pilot plant.
Also, test performance in EDS demonstra-
tion or first comi ercial process, including
organics speciation upstream and downstream.
Characterization of this stream should be
part of the research studies for the bio-
logical treatment system, and part of
demonstration or commercial plant perform-
ance testing. Also, must characterize
performance of disposal alternatives for
biosludge (including incineration and land
disposal), through monitoring around tech-
niques used in EDS demonstration or first
commercial plants, and perhaps through use
of sludge generated in these plants for
experimental incineration/disposal tests.
Laboratory or pilot scale tests are needed
on the EDS wastewaters. While many of the
individual chemical species determining
COD are known, the performance cannot be
synthesized from performances typical for
individual species. Performance is gener-
ally specific to the wastewater being
treated and therefore must be determined
on an individual basis. Test performance
in EDS demonstration or first commercial
plants, including organics speciation
upstream and downstream.
(Continued)
-------
TABLE 5-2. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR WASTEWATER STREAMS AND WATER POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
tn
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10
Chemical Oxidation
Removals are based on the chemical oxidation amen-
ability of individual species on the wastewater.
Costs are based on data available in the open
1iterature.
References. Section 4.3.1.1.5.2, Appendix B-16
Incineration
Destruction of orgamcs is based on that realised in
other industries. Costs are based on vendor quotes.
References: Section 4.3.1.1.5.3, Appendix B-17
Cooling Tower Concentration
All nonvolatile chemical species with no exception are
assumed to be concentrated into the blowdown stream
without losses due to volatilization or drift.
Reference: Section 4.3.1.1.6.1
Secondary Haste Stream
Cool ing Tower Drift
Vapor Compression Evaporator
AH chemical species are assumed to be concentrated
into the blowdown stream without losses due to vol-
atilization. Costs are based on vendor quotes.
References: Section 4.3.1.1.6.2, Appendix B-26
Secondary Waste Stream
Concentrated Brine
No experience exists for performance on specific
constituents in the EDS wastewater. Overall pH
dependence and general reactor requirements are
not known. For wastewaters where orgamcs 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 established for EDS
wastewaters.
Performance has not been determined for the EDS
wastewaters. Loss of volatile species and
potential for corrosion are not known.
The characteristics of this stream are not
firmly known.
Performance has not been determined for the EDS
wastewaters. The concentration of individual
chemical species that will be carried over into
the evaporator overhead is not known. Extent of
corrosion potential is not known.
The characteristics of this stream are not
known.
Testing of the EDS wastewaters on a scale
larger than laboratory scale is needed to
better assess treatability. Destruction
of chemical species by chemical oxida
tion under carefully controlled condi-
tions are not necessarily realized in a
full scale process. Test performance in
EDS demonstration or first commercial
plants.
Test performance in EDS demonstration or
first commercial plants for which this
technique is applied, including perfor-
mance on individual orgamcs.
Volatilization and composition of drift
should be measured in EDS demonstration
or first commercial plants for which
this technique is applied.
Same as above.
Test performance in EDS demonstration or
first commercial plants for which this
technique is applied", including charac-
terization of species in overhead stream
and in blowdown.
Determine characteristics of this waste
stream in EDS demonstration or first
commercial plants.
(Continued)
-------
TABLE 5-2 DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR WASTEWATER STREAMS AND WATER POLLUTION CONTROL TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/ Limitations
Additional Data/Reseach f.eeds
tn
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Deepwell Injection
All chemical species are assumed to be contained by
this disposal technique. The costs are based on
typical well construction and maintenance costs
reported in the literature.
References: Section 4.3.1.1.7.2, Appendix B-27
Surface Impoundment
All nonvolatile chemical species are assumed to be
contained by this disposal technique. The costs are
based on typical impoundment construction costs
reported in the literature.
References: 4.3.1.1.7.3, Appendix B-28
Combined Stream B and Other Low -Phenolic Streams
Flexicoking Heater Overdrum Wastewater (Stream 312),
Knockout Drum Wastewater in H,, Cryo Recovery (Stream 403),
Slowdown and K.O. Drum Wastewater From H., Generation
(Stream 430), Catacarb Overhead Receiver Wastewater In
H, Generation (Stream 431), Knockout Drum Wastewater In
Ammonia Synthesis (Stream 452J, Aqeous Ammonia From
Airtroma Synthesis (Stream 451)
Pretreatment requirements for the EDS wastewater
has not been determined.
Long term performance of liners and compati-
bility of liners with the EDS wastewater have
not been determined.
Monitor deep wells in EDS demonstration
or first commercial plants for which
this technique is applied.
Long term column or "cell" studies should
be performed to determine the compati-
bility and the performance of liners.
Monitor disposal sites in EDS demonstra-
tion or first commercial plants.
The characteristics of these streams are based on Exxon
design estimates.
References Section 3.3.4.1.1, 3.3.4.2.2
Sour Hater From Partial Oxidation Unit (Steam 441)
The characteristics of this stream are based upon gasi-
fication of a western coal.
Selected Control Techniques for Stream B
Techniques applicable to this set of streams have
already been covered above in connection with
Stream A (except Stream B will not need phenol
extraction).
Characteristics of these streams are based on
small bench scale tests and computer simulation
studies. Characteristics of these streams from
pilot or commercial size plant may differ.
Using the residues from the EDS process a feed
to the gasifier may generate a stream with dif-
ferent characteristics.
Determine characteristics of these waste
streams in EDS demonstration or first
commercial plants.
Characteristics of this stream should be
determined to evaluate control require-
ments. Characterization might be per-
formed if EDS residues are gasified in
an experimental gasifier; or in EDS
demonstration or first commercial plants.
-------
TABLE 5-3. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR SOLID WASTE STREAMS AND SOLID WASTE MANAGEMENT TECHNOLOGIES
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
cn
01
High-Carbon Solids
Flexicoking Gasifier/Heater Dry Fines (Stream 302)
Flexicoking Gasifler/Heater Wet Fines (Stream 303)
Flexicoking Heater Bed Coke (Stream 306)
The flow rates of these streams are based upon Exxon
design estimates. Leachate characteristics are based
upon data from EDS pilot studies.
Reference: Section 3.3.4.1.3.
Slurry Dryer Solids (Stream 108)
The flow rate of this stream is based upon Exxon
design estimates.
Reference: Section 3.3.2.1.3.
Selected Contro1 Techniques for High Carbon Solids
Fluidized Bed Corbustion
The burning of these materials in fluidized
bed combustion (FBC) boiler is based upon an
approach under consideration for a proposed K-T
gasification plant in Alabama, and an existing
K-T plant in Modderfontein, South Africa.
Reference. Section 4.4.2.1.1.1.
Secondary Waste Streams
FBC Boiler Fly Ash
Spent FBC Boiler Bed Sorbent
Limited characterization data are available.
Data on the characteristics of this stream are
not available.
(1) The viability of commercial scale FBC
boiler using these materials as feed has
not been proven.
(2) Although there are cost data for coal-
fired FBC units, these data may not apply
to unbustion of these materials.
No Teachability data are available.
The flow rate and the Teachability of this
material are not known.
Verify characteristics of these waste
streams in EDS demonstration or first
commercial plants.
Determine characteristics of this waste
stream in EDS demonstration or first
commercial plants.
Perform tests on waste materials acquired
from EDS demonstration or first commer-
cial plants.
The Teachability data should be deter-
mined in conjunction with FBC tests
above.
The flow rate and the Teachability of
this material should be determined
in conjunction with FBC tests above.
(Continued)
-------
TABLE 5-3. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR SOLID WASTE STREAMS AND SOLID WASTE MANAGEMENT TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
Landfill
Landfilling of the waste is based upon current
practices in the electric utility industry
and other industries.
The long term leachate generation rates and
characteristics are not known, and the compat-
ibility and long term performance of landfill
liners have not been established.
Long term column or landfill cell studies
are needed to characterize the leachate
and to determine liner performance. Mon-
itor landfill associated with EDS demon-
stration or first commercial plants.
CJl
cn
ro
Reference: Section 4.4.2.1.2.1.
Surface Impoundment
Disposal of waste in surface impoundments is
based upon current practices in the electric
utility industry and other industries.
Reference: Section 4.4.2.1.3.2.
Fixation
Fixation of these materials to improve their
structural stability and Teachability char-
acteristics is based on current practices
for FGD sludge and other industrial wastes.
Same as 1andf111 .
Performance and cost for the application are
not known.
Same as 1andfi11.
Treatability studies with various chem-
ical additives might be performed to
determine the technical and economical
feasibility of this approach, on mate-
rials generated using EDS pilot bottoms
in experimental Flexicoker, or on mate-
rials from EDS demonstration or first
commercial plants.
Reference: Section 4.4.2.1.2.1.
Spent Catalysts
Spent Hydrogenation Catalyst (Stream 204)
Spent Hydrotreater Catalyst (Stream 404)
Spent Drying Agent (Stream 405)
Spent High Temperature Shift Catalyst (Stream 444)
Snert Low Temperature Shift Catalyst (Stream 445)
Spent Claus Catalyst (Stream 517)
Spent Hydrolysis Catalyst (Stream 518)
The flow rates of these streams are based upon
Exxon design estimates.
Leachability data on these streams are not
avail able.
Leachability of these materials, if these
catalysts are to be disposed of, instead
of recycled should be determined. Appro-
priate materials for testing would be
available one or two years after the
first EDS plant is built.
References: Sections 3.3.3.2.3, 3.3.4.2.3.
(Continued)
-------
TABLE b-3. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR SOLID WASTE STREAMS AND SOLID WASTE MANAGEMENT TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
01
tn
oo
Reuse/Resource Recovery
These materials can potentially be reused by
reactivation by a contractor or the original
vendor, or reclamation of the metals making
up the catalyst.
Reference. Section 4.4.5.1.1.
Fixation
Fixation of this material to improve its
structural stability and Teachability
characteristic is based on current prac-
tices for FGD sludge aid other industrial
wastes.
Landfill
Landfilling of the waste is based upon
current practices in the electric
utility industry and other industries.
Reference: Section 4.4.2.1.2.1.
Partial Oxidation Slag (Stream 442)
The flow rate of the slag is based upon Exxon
design estimates. The leachate characteris-
tics are based upon pilot gasification of
SRC-II flash drum bottoms using Kentucky
No. 9/14 coals.
Reference: Section 3.3.4.2.3.
Flexicoking Chunks/Agglomerates (Stream 313)
The flow rate and Teachability data are based
upon Exxon pilot studies.
Reference: Section 3.3.4.1.3.
The available markets for reuse of these
materials are uncertain.
Performance and cost for the application
are not known.
The long term leachate generation rates and
characteristics are not known, and the com-
patibility and long term performance of
landfill liners have not been established.
Slag Teachability data are not available for
residuals from EDS process.
Limited characterization data are available.
The availability of market is highly
dependent upon local conditions which
can only be assessed on a site-by-site
basis.
Treatability studies with various chem-
ical additives should be performed to
determine the technical and economical
feasibility of this approach, using
spent catalysts from applications in
related industries such as petroleum
refining.
Long term column or landfill cell studies
are needed to characterize the leachate
and to determine liner performance.
These studies could be performed using
similar spent catalysts from related
applications such as petroleum refining.
Slag Teachability data should be acquired
using residues from pilot plant gasifi-
cation of EDS vacuum bottoms.
Verify characteristics of this waste
stream in EDS demonstration or first
commercial plants.
(Continued)
-------
TABLE 5-3. DATA GAPS, LIMITATIONS, AND RESEARCH NEEDS FOR SOLID WASTE STREAMS AND SOLID WASTE MANAGEMENT TECHNOLOGIES (Continued)
Data Source and Basis
Data Gaps/Limitations
Additional Data/Research Needs
Reuse as Construction Material
Potential alternatives for utilizing these
materials are based upon current practices for
ash from coal-fired power plants.
The available market for utilization of these
wastes (agglomerated coal ash) is uncertain.
The availability of market is highly
dependent upon local conditions which
can only be assessed on a site-by-site
basis.
en
Landfill
Landfill ing of the waste is based upon
current practices in the electric utility
industry and other industries.
The long term leachate generation rates and
characteristics are not known, and the com-
patibility and long term performance of land-
fill liners have not been established.
Reference: Section 4.4.2.4.2.1.
Surface Impoundment
Disposal of waste in surface impoundments is
based upon current practices in the electric
utility industry and other industries.
Same as landfi11.
Long term column or landfill cell
studies are needed to characterize the
leachate and to determine liner perfor-
mance. Monitor disposal in EDS demon-
stration or first commercial plants.
Perform column/cell studies for samples
from EDS demonstration or first com-
mercial plants, or for samples from
experimental Flexicoker.
Same as landf 111 .
™ l\ l\ 0 f\ 9 9
-------
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