POLLUTION CONTROL
GUIDANCE DOCUMENT FOR
SRC-II DIRECT LIQUEFACTION PLANTS
VOLUME I. GUIDANCE
FIRST DRAFT
22 May 1981
NOT TO BE RELEASED, QUOTED OR CITED OUTSIDE OF THE
AGENCY AND ITS REVIEWING ORGANIZATIONS.

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POLLUTION CONTROL
GUIDANCE DOCUMENT FOR
SRC-II DIRECT LIQUEFACTION PLANTS
VOLUME I. GUIDANCE
FIRST DRAFT
22 May 1981
NOT TO BE RELEASED, QUOTED OR CITED OUTSIDE OF THE
AGENCY AND ITS REVIEWING ORGANIZATIONS.

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DISCLAIMER
This report has been reviewed by the Alternate Fuels Group, U. S.
Environmental Protection Agency, and approved for publication. Mention of
trade names or commercial products does not constitute endorsement nor
recommendation for use.
11

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FOREWORD
The purpose of the Pollution Control Guidance Documents (PCGD's) is to
provide environmental control guidance to permitters and developers until the
EPA promulgates applicable regulations. The PCGD's are structured into multi-
ple volumes: Volume I provides control guidance, while Volumes II and III
present engineering evaluations, assumptions, supporting data and calculations.
This draft of Volume I for SRC-11 direct liquefaction plants has been prepared
for key non-EPA reviewers prior to release for public review.
The reader must be aware that the PCGD has no legal effect and imposes
no new regulations. Further, the guidance in the document identifies target
values which are believed to be achievable at reasonable costs with available
control techniques. Thus, the guidance is not given in the form of specific
control technologies. The selection of control technologies is left to the
developers, designers and permitters with complete flexibility to utilize the
lowest cost, most effective systems. Control technologies supporting the
discharge target values are presented to demonstrate controllability,
alternate control techniques and cost impacts.
The presentation of existing regulations is not intended to be definitive
and may not represent current Agency guidelines of recent modifications or
changes. New and updated Federal regulations and legal notices are published
by the Office of the Federal Register.
This document is based on an integrated baseline comnercial plant concept
which may not accurately reflect any specific current plant designs. However,
the report does describe the important multimedia waste streams and control
levels that could be achieved with current state-of-the-art techologies and
techniques. The baseline plant approach will allow designers and reviewers
to relate their specific waste streams to those presented in this document
and to make the appropriate selections and tradeoffs.
David W. Tunderman	Frank T. Princiotta
Co-Chairman, Alternate	Co-Chairman, Alternate
Fuels Group	Fuels Group
111

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ABSTRACT
The Environmental Protection Agency (EPA) believes it is desirable to
provide environmental guidance for the first generation synthetic fuel plants.
The EPA has not completed the research it will use to support the promulga-
tion of new regulations applicable to this industry under the air, water,
solid waste, and toxic substances programs of the Agency. To avoid costly
delays in the commercialization of synfuels processes due to uncertainties
concerning environmental control requirements, the EPA is developing a series
of Pollution Control Guidance Documents (PCGD's). This document provides
environmental guidance for SRC-II direct liquefaction facilities.
The SRC-II Direct Liquefaction PCGD is based on a fixed product slate
with two types of coal inputs. The PCGD identifies and evaluates two control
options for each potential waste or discharge stream.
In the context of this document, both options incorporate guidance
consistent with existing regulations for those waste streams having similari-
ties to wastes produced by other industries. For those waste streams which
are unique to coal liquefaction operations, Option I guidance is generally
the more effective option, and Option II guidance is generally consistent with
present regulatory approaches for other industries.
iv

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TABLE OF CONTENTS - VOLUME I
Disclaimer		ii
Foreword	iii
Abstract		iv
Table of Contents - Volume I		v
Table of Contents - Volume II		v1
Table of Contents - Volume III		xiv
Conversion Factors		xv
1.	Introduction 		1
1.1	Direct Liquefaction - Technology Overview of the SRC-II
Process 		3
1.2	Approach to PCGD Development		4
1.3	Document Organization 		9
2.	Environmental Control Guidance for Key Discharges from a
SRC-II Plant 		11
2.1	Summary of Guidance 		14
2.2	Cost Impacts		17
3.	Regulations Applicable to Direct Liquefaction Plants 		21
3.1	Air Pollution Regulations		22
3.2	Water Pollution Regulations 		22
3.3	Regulations Affecting the Disposal of Solid Wastes,
Sludges, and Brines		25
3.4	Requirements for Toxic Substances Control 		31
4.	Process Description and Pollutant Sources		34
4.1	Coal Preparation		34
4.2	Coal Liquefaction		36
4.3	Product Separation and Purification 		37
4.4	Hydrogen Production Plant 		39
4.5	Waste Streams from Auxiliary Processes		42
4.6	SRC-II Products and By-products 		43
5. Evaluation of Pollution Control Technologies
5.1	Approach	
5.2	Air Pollution Control 	
5.3	Water Pollution Control 	
5.4	Solid Waste Management	
5.5	Toxic Substances Control	
v
47
47
51
110
145
160

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TABLE OF CONTENTS - VOLUME II
Page
1.1	General Description of Liquefaction Processes 		1-1
1.1.1	Coal Preparation and Handling	1-1
1.1.2	Coal Liquefaction	1-1
1.1.3	Product Separation, Purification, Upgrading	1-2
1.1.4	Processing of Liquefaction Residue 		1-3
1.1.5	Auxiliary Operations 		1-3
1.2	Analysis Approach and Basis for Material Balances 		1-4
1.2.1	Direct Liquefaction Process Designs	1-4
1.2.2	Approach to Process Characterization 		1-5
1.2.3	Control Technology Evaluation Methodology	1-8
1.3	Organization and Purpose of the Direct Liquefaction PCGD		1-9
1.3.1	Purpose of the Document	1-9
1.3.2	Organization of the PCGD	1-10
1.4	Use of the PCGD for Permit Review	1-11
1.4.1	Support to Permit Reviews	1-11
1.4.2	Examination of Uncontrolled Gaseous Streams Requiring
Control	1-12
1.4.3	Examination of Uncontrolled Wastewater Streams Requiring
Control	1-14
1.4.4	Examination of Solid Waste Discharges	1-15
1.4.5	Examination of Proposed Air Pollution Control Equipment
and Procedures	1-16
1.4.6	Examination of Proposed Wastewater Treatment Equipment
and Procedures	1-17
1.4.7	Examination of Proposed Solid Waste Management Practice. .	1-18
2. Sources of Waste Streams and Pollutants of Concern	2-1
2.1 SRC-II Process	2-1
2.1.1	Overall Description of the SRC-II Process	2-1
2.1.2	Coal Preparation	2-10
2.1.2.1	Coal Preparation for the SRC-II Plant 		2-10
2.1.2.2	Waste Stream Characterization 		2-10
2.1.2.2.1	Storage Pile Runoff	2-12
2.1.2.2.2	Fugitive Dust Emissions from Storage
Piles	2-12
2.1.2.2.3	Crushing/Screening Dust	2-14
2.1.3	Coal Liquefaction	2-17
2.1.3.1	Dissolver Plant 		2-17
2.1.3.2	Raw Product Phase Separation	2-19
2.1.3.3	Waste Stream Characterization 		2-20
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VOLUME II CONTENTS (Cont.)
Pa^e
2.1.4	Product Separation and Purification	2-27
2.1.4.1	Recycle Gas Treating and Hydrogen Recovery Plan .	2-27
2.1.4.2	Low Pressure Gas Compression and Treating Plant .	2-29
2.1.4.3	Product Gas Plant 		2-30
2.1.4.4	Refining Plant	2-31
2.1.4.5	Waste Stream Characterization 		2-32
2.1.5	Hydrogen Production Plant	2-38
2.1.5.1	Syngas Production 		2-38
2.1.5.2	Syngas Shift Conversion 		2-40
2.1.5.3	Hydrogen Purification and Compression 		2-41
2.1.5.4	Syngas Purification 		2-42
2.1.5.5	Methanation and Dehydration 		2-42
2.1.5.6	Waste Stream Characterization 		2-43
2.1.5 Auxiliary Operations 		2-56
2.1.6.1	Raw Water Treatment 		2-56
2.1.6.2	Steam and Power Generation	2-58
2.1.6.3	Cooling Operation 		2-61
2.1.6.4	Oxygen Production 		2-64
2.1.6.5	Product and By-Product Storage	2-66
2.1.7	Fugitive and Transient Emissions from Plant Operations . .	2-69
2.1.7.1	Fugitive Hydrocarbon Emissions	2-69
2.1.7.2	Transient Emissions 		2-70
2.1.8	Summary of Gaseous, Liquid, and Solid Waste Streams. . . .	2-74
References	2-92
2.2 EDS Process	2-92
2.2.1	Overall Description of the EDS Process	2-92
2.2.2	Coal Preparation	2-103
2.2.2.1	Coal Preparation Operations 		2-103
2.2.2.2	Waste Stream Characterization 		2-104
2.2.2.2.1	Storage Pile Runoff	2-104
2.2.2.2.2	Fugitive Dust Emissions from
Storage Piles	2-105
2.2.2.2.3	Crushing/Screening Dust	2-108
2.2.3	Coal Liquefaction	2-111
2.2.3.1	Slurry Drying and Liquefaction	2-111
2.2.3.2	Raw Product Separation	2-113
2.2.3.3	Waste Stream Characterization 		2-114
v11

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VOLUME II CONTENTS (Cont.)
Page
2.2.4	Product Separation and Purification	2-119
2.2.4.1	Liquefaction Product Fractionation	2-119
2.2.4.2	Solvent Hydrogenation 		2-121
2.2.4.3	Gas Treating	2-122
2.2.4.4	Product Recovery	2-122
2.2.4.5	Waste Stream Characterization 		2-123
2.2.5	Processing Liquefaction Residue/Hydrogen Production. . . .	2-130
2.2.5.1	Flexicoking 		2-130
2.2.5.2	Hydrogen Production 		2-133
2.2.5.3	Waste Stream Characterization 		2-136
2.2.6	Auxiliary Operations 		2-152
2.2.6.1	Raw Water Treatment 		2-152
2.2.6.2	Steam and Power Generation	2-155
2.2.6.3	Cooling Operation 		2-157
2.2.6.4	Oxygen Production 		2-159
2.2.6.5	Product and By-Product Storage	2-160
2.2.7	Fugitive and Transient Emissions from Plant Operations . .	2-163
2.2.7.1	Fugitive Hydrocarbon Emissions	2-163
2.2.7.2	Transient Emissions	"	2-163
2.2.8	Summary of Gaseous, Liquid, and Solid Waste Streams. . . .	2-166
References to EDS Process	2-184
2.3 SRC-I Process	2-187
2.3.1	Overall Description of the SRC-I Process 		2-187
2.3.2	Coal Preparation	2-197
2.3.2.1	Coal Handling and Storage 		2-197
2.3.2.2	Waste Stream Characterization 		2-197
2.3.2.2.1	Storage Pile Runoff	2-198
2.3.2.2.2	Fugitive Dust Emissions from
Storage Piles	2-198
2.3.2.2.3	Crushing/Screening Dust	2-200
2.3.3	Coal Liquefaction and Deashing	2-204
2.3.3.1	Dissolver Plant 		2-204
2.3.3.2	Raw Product Separation	2-206
2.3.3.3	Deashing and Solidification 		2-207
2.3.3.4	Waste Stream Characterization 		2-207
v111

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VOLUME II CONTENTS (Cont.)
Page
2.3.4	Product Purification and Upgrading 		2-211
2.3.4.1	DEA Treating	2-211
2.3.4.2	Expanded-bed Hydrocracker 		2-213
2.3.4.3	Coker-Calciner	2-214
2.3.4.4	Waste Stream Characterization 		2-216
2.3.5	Hydrogen Production Plant	2-222
2.3.5.1	Syngas Generation 		2-222
2.3.5.2	Compression and Shift Conversion	2-224
2.3.5.3	Hydrogen Purification and Compression 		2-225
2.3.5.4	Waste Stream Characterization 		2-226
2.3.6	Auxiliary Operations 		2-237
2.3.6.1	Raw Water Treatment 		2-237
2.3.6.2	Steam and Power Generation	2-240
2.3.6.3	Cooling Operation 		2-241
2.3.6.4	Oxygen Production 		2-244
2.3.6.5	Product and By-Product Storage	2-245
2.3.7	Fugitive and Transient Emissions from Plant Operations . .	2-248
2.3.7.1	Fugitive Hydrocarbon Emissions	2-248
2.3.7.2	Transient Emissions 		2-249
2.3.8	Summary of Gaseous, Liquid, and Solid Waste Streams. . . .	2-253
SRC-I References	2-267
ix

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VOLUME II CONTENTS (Cont.)
Page
3.1	Introduction 	 ..........	3-1
3.2	Pollutants of Concern from the SRC-II Process. ...	3-1
3.2.1	Aqueous Emissions 		3-1
3.2.2	Atmospheric Emissions 		3-4
3.2.3	Solid Wastes	3-4
3.2.4	SRC-II Products - Hazardous Properties. . . .	3-8
3.3	Pollutants of Concern from the SRC-I Process ....	3-13
3.3.1	Aqueous Emissions 		3-13
3.3.2	Atmospheric Emissions 		3-13
3.3.3	Solid Wastes	3-16
3.3.4	SRC-I Products - Hazardous Properties ....	3-20
3.4	Pollutants of Concern from the EDS Process 		3-23
3.4.1	Aqueous Emissions 		3-23
3.4.2	Atmospheric Emissions 		3-23
3.4.3	Solid Wastes. .......... 		3-23
3.4.4	EDS Products - Hazardous Properties 		3-28
3.5	Existing Regulations Applicable to Direct Liquefaction
Facilities	3-36
3.5.1	Water Pollution Regulations 		3-36
3.5.2	Air Pollution Regulations	3-37
3.5.3	Regulatory Authority for Solid Waste	3-43
3.5.4	Requirements for Toxic Substances Control . .	3-50
3.6	Sources of Noise and Radiation in Direct Coal
Liquefaction 		3-52
x

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VOLUME II CONTENTS (Cont.)
Page
4.0 Evaluation of Pollution Control Options	4-1
4.1	Procedures for Evaluating Control Alternatives	4-1
4.1.1 Base Plant Costs	4-6
4.2	Air Pollution Control Alternatives	4-14
4.2.1	Summary of Uncontrolled Gaseous Streams	4-14
from Process
4.2.2	Review of Capabilities, Costs and Energy	4-14
Requirements for Air Pollution Control Options
4.2.2.1	Sulfur Removal	4-16
4.2.2.2	Particulates	4-52
4.2.2.3	Waste Gas and Liquid Combustion	4-61
4.2.2.4	Evaporative Emission Control	4-65
4.2.2.5	Fugitive Emission Control Costs	4-67
4.2.2.6	NOx Contorl for Turbines, Process	4-69
Boilers, and Heaters
4.2.2.7	S02 Control for Coal Fuels	4-70
4.3	Water Pollution Control	4-73
4.3.1	Summary of Uncontrolled Wastewater Streams	4-73
4.3.2	Review of Capabilities, Costs and Energy	4-75
Requirements for Wastewater Treatment Options
4.3.2.1	Suspended Solids Removal	4-75
4.3.2.2	Volatile Inorganics Removal	4-90
4.3.2.3	Bulk Organics Removal	4-97
4.3.2.4	Residual Organics Removal	4-119
4.3.2.5	Dissolved Solids Removal	4-130
4.4.1	Summary of Uncontrolled Streams from	4-147
Processes
4.4.2	Summary of Solid Waste Streams Generated	4-152
by Water and Air Pollution Control
4.4.3	Review of Management/Disposal Technologies	4-154
in Light of RCRA Requirements for Each Waste
Type
4.4.3.1	Fixation	4-156
4.4.3.2	Encapsulation	4-164
4.4.3.3	Incineration	4-1G6
4.4.3.4	Deep Well Injection	4-168
x1

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VOLUME II CONTENTS (Cont.)
Page
4.4.3.5	Land Treatment	4-170
4.4.3.6	Surface Impoundments	4-172
4.4.3.7	Landfill	4-173
4.4.3.8	Resource Recovery	4-178
4.5 Pollution Control Options in Integrated SRC-II
Faci1ities
4.5.1 Air Pollution Control in Integrated	4-181
Facilities (SRC-II)
4.5.1.1	Performance and Costs for Sulfur	4-181
Removal in Integrated SRC-II Facilities
4.5.1.2	VOC and Hydrocarbon Control in	4-184
Integrated SRC-II Facilities
4.5.1.3	Carbon Monoxide Control in Integrated 4-187
SRC II-Facilities
4.5.1.4	SO2, N0X and Particulate Control in 4-187
Integrated SRC-II Facilities
4.5.1.5	Control of Non-Criteria and Hazardous 4-188
Gaseous Pollutants in Integrated SRC-II
Faci1ities
4.5.2 Wastewater Treatment in Integrated Facilities	4-189
(SRC-II)
4.5.2.1	Treatment of Process Waste Streams	4-194
4.5.2.2	Treatment of Non-process Waste Streams	4-196
4.5.2.3	Treatment of Combined Process and Non-	4-196
process Waste Streams
4.5.2.4	Wastewater Treatment Cost	4-197
4.5.3 Solid Waste Management Options in an Integrated 4-202
SRC-II Facility
4.6 Pollution Control Options in Integrated EDS Facilities
4.6.1 Air Pollution Control in Integrated Facilities 4-209
(EDS)
4.6.1.1	Performance and Costs for Sulfur	4-209
Removal in Integrated EDS Facilities
4.6.1.2	VOC and Hydrocarbon Control in Inte- 4-213
grated EDS Facilities
4.6.1.3	Carbon Monoxide Control in Inte-	4-216
grated EDS Facilities
xi1

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VOLUME II CONTENTS (Cont.)
Page
4.6.1.4	SO?, N0X and Particulate Control in 4-216
Integrated EDS Facilities
4.6.1.5	Control of Non-Criteria and Hazardous 4-217
Gaseous Pollutants in Integrated EDS
Facilities
4.6.2	Wastewater Treatment in Integrated Facilities- 4-217
EDS
4.6.2.1	Treatment of Process Waste Streams	4-218
4.6.2.2	Treatment of Non-process Waste Streams 4-228
4.6.2.3	Treatment of Combined Process and Non- 4-228
process Waste Streams
4.6.2.4	Wastewater Treatment Cost	4-229
4.6.3	Solid Waste Management Options in Integrated 4-233
EDS Facilities
4.7 Pollution Control Options in Integrated SRC-11
Facilities
4.7.1	Air Pollution Control in Integrated Facilities 4-243
(SRC-I)
4.7.1.1	Performance and Costs for Sulfur Removal 4-243
in Integrated SRC-I Facilities
4.7.1.2	VOC and Hydrocarbon Control in	4-246
Integrated SRC-I Facilities
4.7.1.3	Carbon Monoxide Control in Integrated 4-251
Facilities
4.7.1.4	SO2, N0X and Particulate Control in 4-251
Integrated SRC-I Facilities
4.7.1.5	Control of Non-Criteria and Hazardous 4-252
Gaseous Pollutants in Integrated SRC-I
Facilities
4.7.2	Wastewater Treatment in Integrated Facilities 4-252
SRC-I
4.7.2.1	Treatment of Process Waste Streams	4-253
4.7.2.2	Treatment of Non-Process Waste Streams 4-261
4.7.2.3	Treatment of Combined Process and Non- 4-261
process Waste Streams
4.7.2.4	Wastewater Treatment Cost	4-263
4.7.3	Solid Waste Management Options in Integrated 4-266
SRC-I Facilities
X111

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TABLE OF CONTENTS - VOLUME III
A.	SLAG DATA FOR EACH PROCESS CASE
B.	UTILITY DETAILS
C.	FUGITIVE AND EVAPORATIVE HYDROCARBON EMISSIONS
D.	TOXIC AND HEALTH EFFECTS DATA BASE
E.	HISTORICAL PERSPECTIVE AND BASES FOR DEVELOPMENT OF AIR
POLLUTION CONTROL MATERIAL BALANCES AND CAPITAL AND
OPERATIONAL COSTS,
F.	CONSIDERATIONS IN THE DESIGN OF COAL DUST EMISSION
SYSTEMS
G.	WASTEWATER TREATMENT SYSTEMS - DESIGN BASIS
H.	SOLID WASTE MANAGEMENT DATA BASE
xlv

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CONVERSION FACTORS
1.0 kg [kilogram]
1.0 tonne [metric ton, (10 kg)]
1.0 kg/min [kilogram per minute]
3.785 L [liter]
2
1.0 Nm/hr [normal cubic meters]
(@ 0°C) per hour]
1.055 GJ [gigajoule]
1.0 MW [megawatt]
1.0 MJ/s [megajoule per second)
1.0 kwh [kilowatt hour]
1.0 $/GJ [dollars per gigajoule]
478.5 ng/J [nanogram per joule]
3
1.0 MJ/Nm [megajoules per
normal cubic meters @ 0°C)]
239 ng/J [nanogram per joule]
1.0 mg/L [milligram per liter]
101.3 kPa [kilopascals]
1.0 atmospheres
= 2.205 lb [pound (mass)]
= 1.102 ton [short ton (2000 lb)]
= 132.3 Ib/hr [pound per hour]
= 1.0 gal [galIon]
= 37.32 SCFH [standard cubic feet
(@ 60°F) per hour]
= 10® 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]
= 1.055 $/106 Btu [dollars per million
Btu]
= 1.0 lb/106 Btu [pounds per million Btu]
= 25.40 Btu/SCF [Btu per standard cubic
foot (@ 60°F)]
= 1.0 kg/106 kcal [kilogram per million
kilocalories]
= 8.33 x 10~6 lb/gal [pound per gallon]
=1.0 atmospheres
= 14.70 psia [pounds per square inch
absolute]
Prefixes
T = tera	=	lOp
M = mega	=	10.,
k = kilo	=	10_g
n = nano	=	10
xv

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SECTION 1
INTRODUCTION
The Environmental Protection Agency (EPA) is responsible for ensuring
that the designs of first generation synthetic fuel plants provide for ade-
quate protection of the environment. However, at present, the EPA has not
completed the research necessary to support the promulgation of new toxic
substances programs of the Agency. To serve the need for protection of
the environment during the period preceding regulations promulgation and to
avoid costly delays in the commercialization of synfuels processes due to
uncertainties concerning environmental control requirements, the EPA is
developing a series of Pollution Control Guidance Documents (PCGDs).
The primary purpose of each PCGD is to provide guidance to both
system developers and permitting authorities on control approaches which
are available at a reasonable cost for the technologies under consideration.
The PCGDs are also intended to provide the public with the EPA's best
current assessment of the environmental problems posed by the different
synfuel technologies and the effectiveness and costs of available controls.
This information should a) assist system developers in their efforts to
design facilities incorporating best available control technologies at the
outset1, b) aid permit reviewers in their decision-making by delineating
both likely pollutants and their concentrations as well as available control
options.
The agency intends this PCGD to provide guidance only. The document
has no legal effect, contains no new regulations of any kind, and includes
nothing that is mandatory in nature. In publishing this document, the
Agency is in no way establishing a binding norm for a permit official to
follow, and does not intend that it be used in lieu of site-specific
analyses. This PCGD leaves permitting authorities free to exercise their
informed discretion, within the confines of applicable law, in choosing
control strategies to be implemented at each SRC-II direct lique-
faction facility. Permitting officials should use this document as an
aid in identifying the environmental problems associated with each
particular facility and evaluating the adequacy of proposed environmental
control system designs. The EPA does not intend the recommendations
1

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contained in the PCGD to be applied in a mechanical, automatic manner,
nor does the Agency intend the the conclusions reached herein to be viewed
as finally determinative of the issues to which this document is addressed.
Rather, it is the intent of this guidance document to promote good faith
efforts by facility planners in the design, operation, and maintenance of
appropriate environmental controls. If, for specific streams or consti-
tuents, a developer feels that the targets specified herein cannot or
should not be met, that developer should provide data supporting this case.
Since all possible options for achieving the specified targets have not
been examined in this PCGD, and since innovation in pollution control is to
be encouraged, permit reviewers should be aware that control schemes other
than those covered are available. Where an applicant proposes to use
alternate controls, the applicant should provide evidence to show that the
proposed controls offer equivalent, if not superior, performance.
EPA's authority to issue PCGD's is based on the Agency's broad charter
to publish information and recommendations regarding pollution control.
For example, Section 103 of the Clean Air Act, 42 U.S.C. §7403 (Supp.1977),
directs the Agency to "establish a national research and development program
for the prevention of air pollution" and authorizes the Administrator of the
EPA to:
collect and make available, through publications and other means,
the results of and other information, including appropriate recom-
mendations by him in connection therewith, pertaining to such
research and other activities ....
Section 104 of the Act, 42 U.S.C. §7404, directs the Agency to: "give
special emphasis to research and development into new and improved methods
. . . for the prevention and control of air pollution resulting from the
combustion of fuels."
Other statutory provisions granting similar research and publication
authority to the EPA include: Section 104 of the Federal Water Pollution
Control Act, 33 U.S.C. §1254 (directing the Administrator to "collect and
make available, through publication and other appropriate means, the
results of (its research) and other information (relating to the prevention,
reduction, and elimination of pollution), including appropriate recommen-
dations . . ."); Sections 8001(a) and 8003 of the Resource Conservation and
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Recovery Act (RCRA), 42 U.S.C. § § 6981(a) and 6983 (directing the Adminis-
trator to conduct research and coordinate and disseminate information on
solid and hazardous waste management); Section 1442, of Title XIV of the
Public Health Service Act (the Safe Drinking Water Act), 42 U.S.C §300j-1
(b)(1) (authorizing the Administrator to "collect and make available
information pertaining to research . . . with respect to providing a depen
dably safe supply of drinking water together with appropriate recommen-
dations . . ."); and Section 10 of the Toxic Substances Control Act,
15 U.S.C. §2609 (directing the Administrator to conduct research necessary
to carry out the Act's purposes). More specifically related to the environ-
mental problems of fuel production, Section 111 of the Non-nuclear Energy
Research and Development Act, 42 U.S.C. §5910, in combination with
Executive Order No. 12040, directs EPA to evaluate the "adequacy of
attention to environmental protection and the environmental consequences
of the application of energy technologies."
Guidance in this document is based upon the projected discharge
limits which are believed to be achievable with available control tech-
nologies. As the first few facilities are built and operated, the EPA will
continue to conduct research to develop a more comprehensive data base. On
a continuing basis, the Agency will review and update the underlying
assumptions and recommendations contained in this PC6D and eventually
promulgate regulations applicable to various synthetic fuels processes.
1.1 DIRECT LIQUEFACTION - TECHNOLOGY OVERVIEW OF THE SRC-II PROCESS
The SRC-II process has been in development for over 15 years by
subsidiary companies of Gulf Oil. Current process development work is
being carried out at a 50 ton/day pilot plant at Fort Lewis, WA. The
development program includes variation of liquefaction reactor conditions
for the optimization of distillate yields, and performance evaluation of
other critical equipment (slurry preheater, vacuum separator, pumps and
valves for severe service). A variety of coals have been tested at Fort
Lewis, including Powhatan (No. 1, 3,5,6), Pittsburgh Seam, Blacksville,
and Kentucky (no. 9,14).
A demonstration plant is currently under design, to process 6000 tons
of coal per day and produce the equivalent of 20,000 barrels of oil per
3

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day. The product slate will include fuel oil, pipeline gas, naphtha,
light hydrocarbons and butanes, sulfur, ammonia, and tar acids. While
limited facilities for pollution control exist at the Fort Lewis plant,
the planned configuration for the acid gas sulfur removal and wastewater
treatment operations will be considerably more sophisticated for the
demonstration plant. The closest examples of commercial-scale pollution
control facilities of a similar type are found in modern refineries and
coke oven plants. Pilot scale or commercial scale solid waste management
operations do not exist for the SRC-11 process. The Fort Lewis plant does
not use gasification of vacuum bottoms to make hydrogen, so that gasifier
ash (the predominant solid waste in a commercial facility) is not produced.
1.2 APPROACH TO PCGD DEVELOPMENT
As discussed previously, the primary purpose of the PCGD is to provide
a data base for pennitters to use in evaluating the adequacy of proposed
controls for specific facilities. Although the exact volume and charac-
teristics of various waste streams will differ among plants and tire
relative importance of individual wastes will vary from site to site, the
major streams of concern are covered by this PCGD and the conclusions
regarding controls may generally be extrapolated to facilities with
configurations which differ from those examined.
In developing this PCGD, an inventory of waste streams and pollutants
generated in baseline integrated facilities was prepared and an assessment
of the performance and costs of various control alternatives for those
streams and pollutants was made. The approaches used to develop the pollu-
tant inventory and to select and evaluate applicable controls are briefly
described below.
The cost estimates developed in this PCGD are generally believed to
be accurate to within about - 50%. More accurate estimates were possible
in cases where the characteristics of the uncontrolled waste streams could
be accurately predicted, and performance data for the subject controls in
related applications were available. However, because of the inherent
limitations in the data base, the cost estimates developed in this
document are useful primarily as indicators of when candidate control
approaches are unreasonably expensive. These estimates are generally not
4

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accurate enough to distinguish between alternate processes having roughly
the same performance characteristics and costs.
1.2.1	Pollutants Covered by the PCGD
A listing of all the pollutants expected in the gaseous and aqueous
discharges from SRC-II direct liquefaction processes that are covered by
existing regulations is provided in Table 1-1. The major pollutants not
listed in this table which are expected to be present in the gaseous wastes
generated by the subject technology are polycyclic organic matter (POM),
and ammonia. In selected process wastewaters, a variety of organic con-
taminants are expected to be present which are represented only by gross
parameters such as COD in current regulations.
1.2.2	Process Characterization, Data Sources and Control Levels Definition
The PCGD methodology uses a baseline design for the SRC-II process,
sized at 100,000 bbls/day net equivalent of product liquids and fuel gases.
The design and pilot plant experience of this liquefaction process has been
limited to certain types of feed coals; consequently, the guidance docu-
ment recognizes that expected variations in proposed liquefaction plant
feed coals will be limited to an experience range. This is particularly
critical for non-catalytic processes like SRC-II, which depend on the
catalytic properties of constituents found in bituminous coals for adequate
yields. Two feed coals, Powhatan No. 5 and Blacksville, are used in the
PCGD analysis for the SRC-II process. Powhatan No. 5 has been used
extensively in the pilot plant development program. Initial baseline
design concepts were prepared and submitted for comment to the developer
of the SRC-II process. In most cases, commercial design concepts of the
process are somewhat of a moving target, and it should not be assumed that
the baseline design cases will necessarily represent a particular final
design configuration. The process developer for SRC-II has confirmed that
the proposed baseline design represents a feasible plant configuration. The
goal of this methodology is to provide a process description that EPA permit
reviewers can reasonably compare with submitted applications.
The intial baseline design, including material balances and flow-
charts which identify the major and minor stream constituents at key points,
was prepared by incorporating pilot plant test results and engineering
5

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TABLE 1-1. CONSTITUENTS EXPECTED IN SRC-II DIRECT LIQUEFACTION FACILITY WASTE
STREAMS COVERED BY EXISTING AIR AND WATER STANDARDS
Standard
Pollutants Expected in Discharge Streams from SRC-II
Direct Liquefaction Facilities
National Ambient Air Quality Standards
New Source Performance Standards
National Emission Standards for
Hazardous Air Pollutants
Prevention of Significant Deterioration
Standards
Increments
De Minimis Levels
Effluent Limitation Guidelines
Conventional and nonconventional
pollutants
Consent decree pollutants
(toxic pollutants)
CO, NO, S02, Pb, TSP, NMHC
CO, NO, SO2J TSP, Total Reduced Sulfur, NMHC
Hg, Be, Inorganic As*, Benzene*, Radionuclides*
S02> TSP
CO, NO, TSP, S0?, Pb, Hg, Be, H?S, Fluorides, Sulfuric Acid
Mist, Total Redoced Sulfur (includes H2S, COS, CS2» Mercaptans
A1, Anmtonia, Fluoride, Fe, Nitrate, Organic Carbon, P, Sulfate,
Sulfide, U, BOD,-, COD, pH, Total Nitrogen, Total Suspended
Solids, Color, Oil and Grease, Settleable Solids
Sb, As, Be, Cd, Cr, Cu, Cyanides, Pb, Hg, Ni, Phenol and
phenolic compounds, Polynuclear aromatic hydrocarbons, Se,
Ag, Zn
* Listed as hazardous air pollutants but no regulations promulgated.

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estimates with commercial-plant design cases that have been released
by the process developer. A critical feature of these analyses was the
validation and interpretation of pilot-plant test data obtained by EPA
and DOE contractors. Determinations were made as to whether these data
were obtained under steady-state conditions, using standardized sampling
and analysis techniques. The uncontrolled constituents in each waste
stream (gaseous, liquid, or solid) were estimated in the baseline design
case in order to realistically evaluate control requirements.
The major gaseous emission streams requiring control include the
following:
•	Fugitive dust emissions from coal storage
•	Fugitive dust emissions from coal and slag handling
•	Fugitive hydrocarbon emissions from valves, flanges, and seals
•	Fugitive hydrocarbon emissions from product and byproduct storage
•	Acid gases from sour water stripping units
•	Acid gases from acid gas removal units
•	Flue gas from process heaters
•	Flue gas from steam plant
a Evaporation and drifts from cooling towers.
The major wastewater streams requiring control include the following:
•	Sour and phenolic process wastewater from vapor washes, con-
densers, fractionator overhead drums, sulfur recovery plant,
and coal slurry mixing operation
•	Cooling tower blowdown
•	Boiler blowdown
•	Coal pile runoff
•	Oily water runoff from processing areas.
Untreated wastewater characterizations were derived from measurements
conducted by process developers, EPA, and DOE sampling and analysis efforts.
Some judgments were made concerning the effects of coal feed characteris-
tics and process operating configurations on these measurement values.
7

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Most of these measurements have focused on process wastewater (or "sour
water", following refinery terminology). Other anticipated sources of
wastewater include coal pile and area runoff, cooling tower blowdown, and
discharge from dust collection and conveying use. These other categories
are analagous to related discharges from coal handling and other industrial
operations.
Solid waste discharges will include gasifier slag (from hydrogen
synthesis), spent catalysts, wastewater and raw water treatment sludges,
and possibly non-salable byproduct residues. Some limited amount of
leaching tests have been done to characterize gasifier slags and some
residue material, but more work will have to be done before a determina-
tion can be made as to the probable characterization of these wastes as
non-hazardous or hazardous.
1.2.3 Control Technology Evaluation Methodology
EPA permit reviewers will be faced with a range of possible control
technologies connected with direct liquefaction process designs. To
assist permit reviewers in their examination of submitted plans, a number
of control-technology options are evaluated in the PCGD for each potential
waste stream for the SRC-II process. The evaluation of each control tech-
nology includes the efficiency of pollutant removal from a stream,
multipollutant removal capability, installed and operating cost, relia-
bility, turndown ratio, sensitivity to process stream conditions, energy
consumption, and any other operating history information such as mainten-
ance requirements. The PCGD evaluates combinations of integrated control
technology to establish performance and cost ranges.
At least two "levels" of control were identifed for most streams/
stream types. These control levels were defined in terms of either control
capability (e.g., % removal of a given pollutant) or residual pollutant
discharge rates (concentration or mass emission limits). The bases for
the levels selected are discussed in detail in Section 5 of this document.
The guidance options and control approaches which are described in
Sections 2 and 5 of this document are organized according to the charac-
teristics of the uncontrolled discharge streams being treated. For
example, all aqueous waste streams treatment options and ultimate disposal
8

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alternatives are discussed in the context of wastewater management strate-
gies for fully integrated facilities. This approach was taken to facilitate
the discussion of treatment options for all waste streams of a given type,
even though it is recognized that different ultimate disposal alternatives
might be handled differently from a regulatory point of view. For
example, wastewater disposal in a surface impoundment will be regulated
by RCRA whereas wastewater discharge to a receiving water body will require
an NPDES permit. Data sources which served as the basis for the analysis
of pollution control applicability and costs include engineering studies,
various permit filings, and technical information obtained from pollution
control equipment vendors, process developers, and published literature.
Because there are no well controlled direct liquefaction facilities to
provide control equipment operating and performance data, considerable
engineering judgment was used in defining the applicability, effective-
ness, and costs of available controls. In addition, data derived from
applications in related industries such as the petroleum refining, natural
gas processing, by-product coking, electric utility, and coal preparation
industries was relied upon heavily.
The manner in which the available data were used to define base
plant waste stream characteristics and control equipment performance
capabilities versus costs is discussed in detail in Volume II. This
discussion includes detailed presentations of base plant material balances
and control equipment performance and costing calculations.
1.3 DOCUMENT ORGANIZATION
This Pollution Control Guidance Document consists of three volumes.
The first volume presents the applicable guidance, describes the
process(es), pollutants and sources under consideration and provides a
summary evaluation of candidate pollution control technologies. Volume II
describes the bases for the guidance, including the development of the
baseline plants; application of the data base; and economic analyses of
the various control options. Volume III is a data compilation which con-
tains background information, technical assumptions, and calculations which
support the technology assessments in Volume II and, hence, the guidance in
Volume I.
9

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The subsequent sections of this volume provide a summary of the
guidance for key waste streams (Section 2), a tabulation of existing
regulations applicable to direct liquefaction facilities (Section 3), a
description of the basic process technology and the variations in that
technology which are included in the guidance development (Section 4) and
the costs and capabilities of candidate controls (Section 5). Section 5
also presents details of the guidance options for all identified waste
streams generated in a fully integrated facility. This includes waste
streams generated in the main process train, the auxiliaries and pollution
control processes.
10

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SECTION 2
ENVIRONMENTAL CONTROL GUIDANCE FOR KEY
DISCHARGES FROM A SRC-II PLANT
This section of Volume 1 summarizes the guidance for controlling key
atmospheric emissions, wastewater effluents and solid wastes, and aslo
indicates the major factors involved in minimizing SRC-II product and byproduct
handling and storage hazards. As indicated in the introduction, this summary
section is supported by the detailed discussion of all discharge streams and
porduct/byproduct considerations in Section 4. The key waste streams are
segregated and highlighted because they could, with inadequate controls,
constitute the greatest potential for adverse encironmental and/or health impacts.
As a corollary, the implementation of controls for these particular streams
has the greatest potential for impacting the design features, pollutant
discharges, and costs associated with individual facilities.
Nine waste streams have been classified as key, as follows:
Air: Combined acid gases
Gas turbine exhaust
Process heater emissions
Transient waste gases
Water: Combined sour water streams
NH^ scrubber discharge and Texaco gasifier purge
Solid Wastes: Gasifier slag
Spent catalysts
Wastewater treatment sludge
It is because of the indicated volume, potential severity, or cost of
control of these streams that the Agency has classified them as key waste
streams and has judged their control to be of major importance. Figure 2-1
indicates the uncontrolled contributions of these streams to each medium and
the total discharge to each medium by all waste streams generated by an un-
controlled SRC-II baseline plant (100,000 bbl/day). The relatively small
discharge rate of the transient waste gases is more than compensated for by
the health hazard of its pollutant constituents (e.g., POMs).
* "Uncontrolled" denotes the absence of all discharge controls.
11

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5000
TOTAL = 4554
TOTAL = 3556 x 10J
GAS TURBINE
EXHAUST
= 1767 x 103
PROCESS
HEATER
EMISSIONS
= 793 x 103
ACID GAS
TREATING
EMISSIONS
= 555x 103
TRANSIENT
WASTE	,
GASES = 8 x103
>-
<
o
co
c
UJ
2
3
O
S
o
cc
UJ
h-
<
5
UJ
H
i/i
<
3
30
20
10 -
TOTAL = 29 x 103
COMBINED
SOUR WATER
= 8.4* 103
NH3SCRUBBER
DISCHARGE &
GASIFIER PURGE
= 18 x 103
>
<
O
Z
o
I-
<
cc
(3
UJ
fc
<
s
Q
O
(/>
4000 -
3000 -
2000 - S
1000 -
GASIFIER
SLAG = 4238
WASTEWATER
TREATMENT
SLUDGE = 171
SPENT
CATALYSTS
Figure 2-1. Distribution of Uncontrolled Air, Water and Solid Waste Discharges (Baseline SRC-II Plant, 100,000 Bbl/Day)

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Of the many guidance alternatives which were analyzed by the Agency, two
options were selected for presentation in the PCGD. In the context of this
document, both options incorporate guidance consistent with existing regulations
for those waste streams having similarities to wastes produced by other
industries. For those waste streams which are unique to coal liquefaction
operations, Option I guidance is generally technology-forcing, and Option II
guidance is generally consistent with present regulatory approaches for other
industries.
In addition to these wastes, the major product and byproduct streams
are treated in terms of the intent of TSCA, the possible need for Pre-manufac-
turing Notice (PMN) submittal and the importance of the TSCA Chemical Sub-
stance Inventory.
With regard to all key waste streams, it should be recognized that the
control levels actually achievable under any given set of conditions may vary
from the guidance presented here due to feed coal or plant configuration
differences, operational/reliability problems or control technology limitations.
Regardless of the controls or control systems selected and the above constraints,
it is the intent of the Agency that such controls be designed, operated and
maintained in a good faith effort to achieve the guidance levels. It should
also be emphasized that the Agency considers the stated discharge levels to
be the guidance, rather than the technologies listed as means for achieving
these levels. The users of this document should not feel constrained to
use the listed technologies, but may utilize other individual or sequential
controls as may be supported by direct or allied applications data to meet
the intent of the guidance. It is also recognized that there are many
process and site-specific factors which have an influence on the technical
feasibility and costs of controls used as the basis for guidance. Where
possible these are accounted for in the guidance by considering two feed
coals with a range of heating values, sulfur contents, and ash percentage;
and several wastewater disposal options which are site dependent.
As indicated earlier, the waste streams in any direct liquefaction facility
can be divided into two broad categories, namely 1) those which are very
similar to streams encountered in other industries, and 2) those which are
unique to coal liquefaction operations. The basic objective of the guidance
13

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is to provide for total plant control, considering both categories of streams
and all affected media. To this end, the guidance is structured such that
tradeoffs between streams containing the same pollutant species may be
considered, within basic governing constraints on the pollutant concentration
in any given waste stream and observance of a total plant mass discharge of
the pollutant. This "bubble" approach is expected to provide additional
design flexibility in dealing with site- and process-specific effects.
2.1 Summary of Guidance
The preferred selection of control options that will generally be employed
for control of the key waste streams can be summarized as follows:
Atmospheric Discharges
Gas Turbine exhaust
Adherence to the NSPS for steam generating utility gas turbines, and
sulfur removal from sour fuel gases to meet 160 ppmv total reduced
sulfur, as achievable by DEA scrubbing.
Process Heater Emissions
Sulfur removal from sour fuel gases to meet 160 ppmv total reduced
sulfur, and for process boilers, adherence to the electric utility
NSPS for gas-fired boilers.
Offgases From Acid Gas Removal Systems
100 ppmv total reduced sulfur and 2.5 ng total sulfur/joule of feed
coal as achieveable by the use of bulk sulfur recovery technology plus
tail gas treatment of the residual sulfur.
Transient Waste Gases
For liquefaction and gasifier waste gases, guidance is incineration
in a controlled combustor with SOg removal (and particulate removal
for gasifier waste gases).
For catalyst regeneration/decommissiong vent gases, guidance is
incineration (followed by SO2 and particulate removal for shift
and hydrolysis catalysts).
14

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Aqueous Discharges
Main process wastewaters (Sour water, NH^ stripper discharge, Texaco
gasifier purge)
Removal of tars/oils and bulk dissolved orgamcs and dissolved gases
by solvent extraction and steam stripping.
Disposal of effluent from above treatment by one of the four following
options. The choice of the most appropriate option is a site-specific
permitting decision.
For discharge to surface waters, effluent levels should
not exceed those achieveable by treatment equivalent to
biological oxidation followed by chemical precipitation
and carbon adsorption. An NPDES permit will be necessary
for such discharges.
For discharge to subsurface formations (deep well injec-
tion), the well should comply with state/federal provisions
for a Class I well. If a cooling tower is used to concentrate
the wastewaters before injection, they should first be
treated by the equivalent of biological oxidation and carbon
adsorption to remove most of the organics. A subsequent
incineration step is assumed for avoidance of well fouling.
Subsurface discharges are subject to RCRA and SDWA regulations.
If a surface impoundment is used for ultimate disposal of
the residues, the waste should be considered hazardous until
data to the contrary are presented and the impoundment
should be designed and operated in compliance with 40 CFR 261-
265. Concentration of the wastewater in the cooling tower
is not used under the preferred option. Surface
impoundments are subject to RCRA requirements.
If co-disposal with gasifier slag is used for ultimate disposal
of wastewater residues, the combined waste can be treated as
non-hazardous (pending RCRA-EP test results) provided the
wastewater organic constituents are incinerated first.
15

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Solid Waste
Gasification Slag
Resource recovery is the preferred option.
The slag is believed to be non-hazardous, but the permit applicant
must justify its classification as non-hazardous with data for its
case in order to landfill as non-hazardous (Subtitle D) in accordance
with 40 CFR 241.
If process wastewaters are used to moisturize the slag, landfill the
mixture as a hazardous waste (Subtitle C) (pending RCRA-EP test
results) in accordance with 40 CFR 261-265 unless the organics have
been removed from the process waters by incineration.
Sludges from Biological Oxidation Treatment Systems
These sludges are presumed to be hazardous, in the absence of data
to the contrary, due to their organic and heavy metal constituents.
Landfarming is the preferred option where site-specific factors allow.
Landfill as hazardous waste in accordance with 40 CFR 261-265 is
also acceptable.
Spent Catalysts
The spent catalysts are presumed to be hazardous because of their
heavy metal content.
Resource recovery is the preferred option.
Products
The thrust of the guidance for complying with the provisions of TSCA
for the products is that a premanufacturing notice (PMN) is required for all
products that are neither burned on-site nor are characterized by a single
molecular structure. Thus fuel oil would require a PMN, but methane would not.
The requirement to submit a PMN does not necessarily imply a presumption
that the coal-derived fuel poses a greater risk than its petroleum-derived
counterpart.
TSCA places the primary burden of minimizing hazards and exposure to
products in commerce on the manufacturer. In their PMN's, through toxicity
16

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and exposure assessment data, manufacturers must demonstrate that their prod-
ucts will not pose unreasonable risks. To serve this purpose, the Office
of Toxic Substances has formed the Synfuel Toxics Work Group, a committee
composed of technical experts on synthetic fuel processes. This committee
will provide a forum for the exchange and review of information during the
PMN development process, and serve as a source of guidance for the synfuel
developer. The intent of the committee is to minimize the potential for
unnecessary regulating constraints and delays. Therfore, developers are
encouraged to contact OTS, EPA for guidance on the inventory status of their
PMN well before the mandatory 90-day period.
2.2 Cost Impacts
The guidance presented in Section 5 for air pollution control and water
and waste management discusses two levels of control. One option provides
greater environmental protection than the other, but also costs more (generally).
The guidance in Section 5 follows the same approach for all key and non-key
streams. It is possible to show the probable range of costs for protecting
the environment by presenting total costs for two control strategies --
across-the-board implementation of 1) the most protective controls and
2) the less protective controls on all streams. These costs are tabulated
in Table 2-1 by medium, as a percentage of the plant's overall capital and
annualized costs. As indicated in the introductory part of this section,
these cost ranges reflect the impacts of different coal feed stocks and alternate
approaches to achieving the same control levels for a SRC-II production facility.
The Agency preference entries indicate the summed capital and annualized
cost estimates for the preferred control options for each of the key streams.
These figures reflect a mixture of Option I and Option II controls. Agency
preference entries for the non-key streams in Table 2-1 were developed by
taking a numerical average of the Option I and Option-II control costs.
Three streams, including the gas turbine and heater flue gases, acid
gas treating offgases and the combined process wastewater stream, account for
most of the ultimate discharges from the plant and over 70 percent of the
annual control costs. The relative cost contribution of key streams to the
total pollution control cost estimate is shown in Figure 2-2. The total costs
for the control of waste streams and for the containment of solid wastes are
17

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TABLE 2-1. ENVIRONMENTAL CONTROL COST SUMMARY AS PERCENT OF BASE SRC-II PLANT COSTS
Medium
Capital
Option I
Annualized
Capital
Option II
Annualized
Agency Preference
Capital
For Key Streams
Annualized
Key Air Streams
Key Water Streams
Key Solid Wastes
5 5- 7.4
1.3- 1.8
0 - 0.3
4.6- 7.2
3.1- 5.3
1 2
4.2- 6.8
1.1- 1.5
0.2- 1.2
6 0- 6.9
1.1- 5 0
12-24
5 6-72
1.3- 1.8
0 - 0.3
4 4-70
3 1-53
1.2
Key Streams
Subtotals
6.8- 9 5
8.9-13.7
5.5- 9 5
8.3-14.3
6 9- 9.3
8 7-13 5
Non-Key Streams
All Media
PLANT TOTALS
0.7
7.5-10.2
1.5
10 4-15 2
0.5
6.0-10 0
1.2
9.5-15.5
0 6
7 5-99
1.4
10 1-14 9

-------
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o
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cr (/>
<	8
Ui _l
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DC I-
UJ Z
> o
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•A
TOTAL
CAPITAL = 6 0%
ANNUAL = 6 5%
ACID GASES
CAPITAL = 2 8%
ANNUAL = 3 6%
3 ~\
TRANSIENT
CAPITAL = 1 9%
ANNUAL = 1.1%
COMBUSTION
CAPITAL = 1 2%
ANNUAL=17%
TOTAL
CAPITAL = 2 1%
ANNUAL=5 0%
SOUR WATER
CAPITAL = 1 6%
ANNUAL= 3 8%
to
o
o
<
Ui
O
o z
=i<
8-
U.S
(J <
2"
>°
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1 -
TOTAL
CAPITAL = 0 8%
ANNUAL = 2 7%
SLAG
CAPITAL = 0 6%
ANNUAL=15%
TREATMENT SLUDGE
CAPITAL = 0 1%
ANNUAL = 0 5%
CATALYSTS
CAPITAL,
ANNUAL <0 01%
Figure 2-2. Average Costs of Treatment and Disposal of Air, Water and Solid Wastes (Baseline SRC-II Plant, 100,000 Bbl/Day)

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similar to those for new petroleum refinery or integrated iron and steel
complexes but less than those for new electric utility stations. The
similarity between the projected control costs for the baseline SRC-II plant
and the other, related sources is due, in large part, to the fact that recently
constructed facilities in these other industries are generally providing
environmental protection equivalent to Option II. in a sense Option II
represents current practice, and Option I represents a blend of more recent
requirements (as with the air NSPS for utility boilers), to insure that the
best controls are used in the absence of sufficient data for a firm deicsion
on such issues as waste clarification and controls to minimize emissions of
potentially harmful organics.
If one assumes that the uncontrolled base plant's annualized cost plus
the annualized control costs (developed for this document) would represent
the total cost of plant operations for producing an equivalent of 100,000
bbl per day of products, then the values of the product would be in $31/bbl
to $32/bbl range for all cases. It must also be recognized that this $/bbl
cost range does not take into account the different types of products and other
cost factors that would normally be included in a product cost analysis, such
as, distribution costs, corporate overheads, etc. The control costs for
the key streams discussed in this section would be in the range of $2 to $4
per bbl. If the non-key stream control costs (taken as an average of Option
I and Option II costs) are added to the key stream costs, the resulting
total costs would be in the same range.
20

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SECTION 3
REGULATIONS APPLICABLE TO DIRECT LIQUEFACTION PLANTS
The following subsections summarize the plant- and process-oriented
federal environmental regulations applicable to direct liquefaction plants-
These cover: (1) sources within the plant that are already subject to regu-
lation; (2) the generation, transportation, treatment, storage and disposal
of solid, liquid or contained gaseous wastes which are neither vented to the
air nor discharged to surface water; and (3) ambient-based limitations, such
as National Ambient Air Quality Standards (NAAQS), Prevention of Significant
Deterioration (PSD) requirements, Water Quality Criteria, and Drinking Water
Standards which may indirectly limit the quantities or concentrations of spe-
cific source emissions. In addition, most unrefined direct liquefaction pro-
ducts will be subject to control under the Toxic Substances Control Act since
these materials represent new products in commerce which may contain a varie-
ty of toxic substances.
New facilities will also be required to comply with existing state and
local environmental regulations. In addition, a number of existing regula-
tions, such as the OSHA Health and Safety Standards; the pipeline safety pro-
grams; and the Surface Mine Reclamation Control Act may affect environmental
operations both within and outside of the plant boundaries. While the guid-
ance provided in this document is in no way intended to supersede the require-
ments of these existing or other proposed regulations, this section empha-
sizes the federal environmental regulations because it is this body of
legislation which is being directly utilized in the guidance statements.
The Agency is presently developing formal regulations which will cover
direct liquefaction. When these are promulgated, they will, as noted in
Section 1 supersede this guidance document. The pertinent federal regula-
tions which apply to direct liquefaction plant discharges and/or products are
summarized below according to the media to which the wastes are discharged
(air, water, solid or toxic substances in products/by-products) and the char-
acteristics of the stream.
21

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3.1	Air Pollution Regulations
Currently, the only air emission sources within an integrated direct
liquefaction facility which would be specifically regulated are the boilers,
coal preparation/storage facilities and product storage vessels. Table 3-1
presents the applicable federal air emissions standards for these sources,
as well as those for several analagous sources in related industries. The
1971 new source performance standard (NSPS) for fossil fired steam gener-
ating units, as amended in 1974, applies to all boilers with heat inputs
greater than 73 MW (63 x 10^ kcal/hr). In 1980, the EPA promulgated a more
stringent NSPS for fossil fuel fired electric utility steam generating units
which is also shown on Table 3-1. The Agency is currently developing a
standard for industrial boilers which is expected to supersede the 1971 NSPS
for non-utility boilers with heat inputs greater than 73 MW.
Current PSD regulations set forth increments and ceilings for SOg and
total suspended particulate (TSP) by area classification. Since a commercial -
scale direct liquefaction plant will emit these critical pollutants at a suf-
ficient rate to be classified as a major emitting source, the owners of a pro-
posed facility will have to apply for a construction permit and demonstrate
that they do not exceed the allowable increments. In addition, they will
have to demonstrate that best available control technology (BACT) is to be
employed for all "de minimis" pollutants exceeding the emissions levels listed
in Table 3-2.
3.2	Water Pollution Regulations
With the exception of the coal handling and storage operations, there
are no operations producing aqueous waste streams for which regulations speci-
fically apply. However, the regulatory framework does exist for controlling
the discharge of aqueous wastes to both above-ground and underground sources.
Surface discharges are controlled under the National Pollutant Discharge
Elimination System (NPDES), a permit process whereby any source discharging
wastes to surface water bodies can be regulated. Where promulgated effluent
guideline limitations exist for an industrial source, the NPDES permit would
specify those limits as a maximum allowable discharge.
22

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TABLE 3-1. SUMMARY OF FEDERAL AIR EMISSION STANDARDS APPLICABLE TO GASEOUS
EMISSIONS SIMILAR TO THOSE ENCOUNTERED IN INTEGRATED DIRECT
LIQUEFACTION FACILITIES.
Air Standard or Guideline
Applicable Source
I Electric Utility
Stean Generating
Units (NSPS)
• Coal and coal
denvea fuels
• Subbitummous Coal
- Bituminaus Coal
- Lignite
- Gaseous and Iiqu^d
fuels not derived
from coa)
- Gaseous Fuels
• Liquid Fuels
Fossil-Fuel Fired
Steam Generators
(NSPS)
- Coal and
solid fuels.
Liquid Fuels
• Gaseous Fuels
3 Coal Preparation
Plant (NSPS)
a Petroleum
Hydrocarbon
Storage Vessel
(NSPS)
5 Incinerators
(NSPS)
40 CFR 60
Part Dd
Steam-Electric power
plants
Steam-Electric Power
plants
40 CFR 60 Industrial boilers
Part 0	>73 KW
heat input
40 CFR 60 Coal preparation
Part y	operations for
gasifier and
power plant
43 CFR 60
Part Ka
Product and
By-product storage
210 ng/J
(0 50 Ib/HBtu)
260 ng/J
(0 50 lb/MBtu)
260 ng/J
(0 60 Ib/KBtu)
86 ng/J
(0 20 lb/MBtu)
130 ng/J
(0 30 lb/MBtu)
300 ng/J
(0 70 lb/MBtu)
130 ng/J
{0 30 lb/MBtu)
86 ng/J
(0 20 lb/MBtu)
520 ng/J
(J 2 Jb/MBtu)
and
901 control unless
emissions <260 ng/J
(0 60 lb/MBtu), m which
case 701 control is
required
340 ng/J
(0 BO lb/MBtu)
tnC.
901 control unless
emissions <86 ng/J
(0 20 lb/MBtu). in which
case percent reduction
requirement does not
apply
520 ng/J
(1 2 Ib/HStu)
340 ng/J
(0 80 lb/KBtu)
None
None
Particulates
None
Equipment specifications
based on the vapor
pressure of the stored
liquid
40 CFR 60 Sludge Incinerators
Part t	>45 Mg/day
None
None Kone
13 ng/J
(0 03 lb/MBtu)
13 ng/J
(0 03 lb/MBtu)
43 ng/J
(0 10 lb/MBtu)
13 ng/J
(0 03 lb/MBtu)
i Pneumatic
cleaning
equipment
0 40 g/dscf
(0 018 gr/dscrn)
and
101 opacity
ii Processing and
conveying
equipment
20% opacity
in Thermal Dryers
Q 07 g/dscm
{0 031 gr/dscf)
None
0 2 g/m corrected
to 12* CO,
Between 10 7 and
107 2 9iga-
joules/hr
(all uses)
»iQ7 2 glgajotles/hr
1 Gas and oil transpor-
tation on oroduction
not located in an
MSA
2 Gas And oil transpor-
tation an production
located in an KSA
ISO ppmv
150 ppmv
75 Dpmv
ISO PPfTV,
Or
i fuel
with 1 ess
than 0 S*
sulfur
ISO ppmv.
or fire
a fuel
with 1««
than 0 81
sulfur
150 ppmv,
or nre
a fuel
with less
tha* o Bi
su flur
•NMHC - Honmetnane Hvdrocarbons
23

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TABLE 3-2. DE MINIMIS LEVELS TRIGGERING PSD REVIEW
De Minimis Level*
Pollutants	tonnes/yr	
Carbon monoxide	91
Nitrogen oxides	36
Sulfur dioxide	36
Particulate matter	23
Ozone	36 (as volatile
organic compounds)
Lead	0.54
Asbestos	0.006
Beryllium	0.0004
Mercury	0.04
Vinyl chloride	0.9
Fluorides	2.7
Sulfuric acid mist	6
Hydrogen sulfide (h^S)	9
Total reduced sulfur (including H2S)	9
*40 CFR 51-52. In addition, any major stationary source constructed
within 10 km of a Class I area would require a PSD permit and appli-
cation of BACT for any pollutant that would otherwise increase the
24-hour average ambient concentration of that pollutant in the
Class I area by at least 1 yg/m3.
24

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Effluent guideline limitations which have been developed for waste
streams similar to tnose encountered in direct liquefaction plants are sum-
marized in Table 3-3. While there is no requirement to this effect, permit
reviewers often rely upon existing guidelines for similar industrial sources
in reviewing NPDES permit applications.
A secondary regulatory mechanism which controls surface discharge is
the Dredge and Fill Permit program which is administered by the U.S. Army
Corps of Engineers (or by any authorized state). This program regulates any
hydro!ogic modifications that can result in surface water quality impacts
due to facility construction in floodplains or wetlands. The potential
physical, chemical and biological effects of proposed discharges are all
evaluated for this permit.
Liquid wastes that are disposed of by underground injection are regu-
lated by the Underground Injection Control (UIC) program recently proposed
by EPA under the authority of the Safe Drinking Water Act. A primary goal
of this program is the protection of all existing and potential underground
sources of drinking water. Recently promulgated UIC regulations (40 CFR
122/146) classify injection wells by type and specify minimum technical
and procedural requirements for the operation and abandonment of such
wells.
3.3 Regulations Affecting the Disposal of Solid Wastes, Sludges, and Brines
All solid and liquid wastes not discharged into the air or surface
water are subject to regulation under the Resource Conservation and Recovery
Act. RCRA regulations for the control of both hazardous and non-hazardous
wastes are listed in Table 3-4.
Criteria for land disposal of non-hazardous wastes were promulgated in
September 1979. These regulations are being adopted by the states and imple-
mented through state permitting authority.
The Federal hazardous waste regulations presently in place define the
testing procedures and thresholds which cause a waste to be defined as hazard-
ous. Certain wastes are listed as hazardous and for these wastes no testing
is necessary. While no coal liquefaction wastes are listed hazardous wastes
25

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TABLE 3-3. SUMMARY OF FEDERAL REGULATIONS FOR AQUEOUS EFFLUENTS SIMILAR TO
THOSE PRODUCED IN INTEGRATED DIRECT COAL LIQUEFACTION FACILITIES
Category of
Effluent Standard
or Guidelme
CFR
Reference Basis*
Pollutant
or Effluent
Maximum for
Any One Day
Average of
Daily Values
for 30 Con-
secutive Days
(Shall not
exceed)
Coal Mining
- Coal Preparation
Plants and Mine
Drainage
Iron and Steel
Manufacturing
- By-Product
Coking
40 CFR 434 BPT
Parts B-D
BAT
40 CFR 420 BPT
Part A
BAT
NSPS
Petroleum Refining
- For typical
topping refinery
40 CFR 419
Part A
BAT
Organic Chemical
Manufacturing
Steam Electric
Power Generation
40 CFR 414
Part B
40 CFR 423
Parts A-D
BAT
NSPS
BPT
Total Fe^.
Total Mn
TSS
pH
As in BPT
except for Fe
Ammonla
Cyanide
Oil/Grease
Phenol
TSS
pH
Cyanide amenable
to chlorination
Oil/Grease
Phenol
Aimionia
Sulfide
TSS
PH
BOD 5
TSS
COD
Oil/Grease
Phenolic Compounds
Ammonia (as N)
Sulfide
Total chromium
COD
B0D5
TSS
PH
pH
Polychlorinated
Biphenyl
Compounds
TSS
Oil/Grease
mg/1
7.0,.
4.0
70.0
6 0-9.0
6.0
q/kq product
0.2736
0.0657
0.9327
0.0045
0.0195
6.0-9.0
0.0003
0.0126
0.0006
0.0126
0.0003
0.0312
6.0-9.0
mg/1 feed
2.5
2 4
10 0
0.5
0.012
0 68
0.055
0.124
mg/1 feed
7.8
0 57
0.94
6.0-9.0
6.0-9.0
No discharge
100.0
20.0
3.0
q/kq product
0.0912
0 0219
0.0109
0 0015
0 0365
0.0001
0.0042
0.0002
0.0042
0.0001
0.0104
mq/1 feed
2.0
2.0
8.0
0 4
0.009
0 51
0.035
0.105
mg/l feed
4.2
0.27
0.50
No discharge
mg/1
30.0
15.0
(continued)
26

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TABLE 3-3. (Continued)
Category of
Effluent Standard
or Guideline
CFR
Reference
Basis*
Pollutant
or Effluent
Maximum for
Any One Day
Average of
Daily Values
for 30 Con-
secutive Days
(Shall not
exceed)
Steam Electric
Power Generation
(continued)
40 CFR 423
Parts A-D
BPT
BAT
Total CopDer from
Metal Cleaning or
Boiler Blowdown
Total Iron from
Metal Cleaning or
Boiler Blowdown
Free Available
Chlorine in
Cooling Tower
Blowdown
Cooling Tower
Blowdown
Zinc
Chromium
Phosphorus
Free Available
Chlorine
Materials added
for Corrosion
Inhibition
Heat from Main
Condensers
1 0
1 0
0 5
Same as BPT
except as below
1 0
0.2
5 0
Zero except for
2 hour period
each day
Limits to be
established on a
case-by-case basis
None except under
special
circumstances
1.0
1 0
0 2
Same as BPT
except as below
1.0
0.2
5.0
*BPT - Effluent limitations based upon best practicable control technology currently available (appli-
cable to existing sources), BAT - Effluent limitations based upon best available technology economi-
cally achievable, NSPS - New Source Performance Standards
+Acidic streams only.
27

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TABLE 3-4. SUMMARY OF RCRA REGULATIONS PERTINENT TO THE DISPOSAL OF SOLID
WASTES, SLUDGES AND BRINES FROM DIRECT LIQUEFACTION FACILITIES
CFR
Reference	Description
40 CFR 241	Proposed guidelines recommending management practices
which meet the criteria for non-hazardous waste disposal
facilities. The Guidelines provided specific recommenda-
tions on landfill design for leachate control, surface
runoff diversion dikes, liners and grading specifications.
40 CFR 257	Contains minimum criteria for determining what non-hazard-
ous solid waste land disposal facilities and practices
pose a reasonable probability of adverse effects on health
or the environment.
40 CFR Part 260 Hazardous Waste Management System: General
-	Defines terms common to all hazardous waste regulations,
establishes procedures for handling confidential infor-
mation and for the submission and processing of rule
making petitions, including petitions to exclude a parti-
cular waste from a particular facility from regulation.
40 CFR Part 261 Identification and Listing of Hazardous Waste
-	Defines solid and hazardous wastes, establishes tempor-
ary exclusions based on statutory exemptions including
those for fly ash, bottom ash, slag, and flue gas emis-
sion control wastes generated primarily from the com-
bustion of coal or other fossil fuels, and mining wastes.
The mining exemption has been interpreted by EPA to
cover the processing of coal for the purpose of synthe-
tic fuel production (see 45 Federal Register 76618,
November 19, 1980). EPA is in the process of evaluat-
ing the legislative history and comments received on the
interpretation of the November 19, 1980 Federal Register
(45 CFR 255) to establish the proper sense of congres-
sional intent.
- Requires generators, treaters, storers, and disposers
to notify EPA on a one-time basis of the kinds and
amounts of hazardous waste they handle.
40 CFR Part 262 Standards for Generators of Hazardous Waste
- Requires generators of hazardous waste to initiate mani-
fests designating the waste for a permitted facility;
properly package, label, and mark waste for shipment;
keep records; and make reports.
28

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TABLE 3-4. (Continued)
CFR
Reference	Description	
40 CFR Part 263 Standards for Transporters of Hazardous Waste
- Requires transporters to participate in the manifest
system, keep records, and deliver waste to permitted
facility.
40 CFR Part 264 Standards for Owners and Operators of Hazardous Waste
Treatment, Storage, and Disposal Facilities*
- Sets standards for permitted facilities, including
participation in manifest system, security, inspection,
personnel training, preparedness and prevention, con-
tingency plans and emergency procedures, financial
responsibilities, closure and post-closure cost, and
specific design, operating and performance standards
for various types of facilities.
40 CFR Part 265 Interim Status Standards for Owners and Operators of
Hazardous Waste Treatment, Storage, and Disposal Facilities*
-	Sets financial responsibilities and standards for faci-
lities to be applied while in interim status (before
permitting), including standards similar to Part 264.
Requires groundwater monitoring at some facilities, also
preparation of closure plans, and sets specific facility
standards. This part only applies to facilities in
existence as of November 19, 1980.
40 CFR Part 266 Standards for the Management of Specific Hazardous Wastes
and Specific Types of Hazardous Waste Management Facilities
-	Sets minimum national standards which defines the accept-
able management of specific wastes and the acceptable
practices for specific kinds of v/aste management faci-
lities. At the time of this writing, no specific regu-
lation has been promulgated but some are in the planning.
40 CFR Part 267 Permitting Standards for New Land Disposal Facility
-	Sets minimum requirements and procedures for permitting
new landfills, surface impoundment, land treatment faci-
lities and injection wells. This regulation is temporary
and will cease to exist upon promulgation of general
	standards under Part 264 for this kind of facilities.
*These standards do not apply to owners and operators of wastewater treatment
(including neutralization) tanks which are currently exempted according to
the promulgation on November 17, 1980.
29

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at the present time, some may fail the toxicity or corrosivity test and thus
be hazardous. Listed wastes such as certain solvents which are found on
many industrial sites and are not unique to coal liquefaction are in the
control system now. In addition, EPA may determine that some of the streams
generated by direct liquefaction systems are hazardous and may list these
wastes at a future time.
Once a waste is determined to be hazardous, it enters a "cradle-to-
grave" system of pollution control. Hazardous waste regulations which were
promulgated in February and May 1980 mandate permitting procedures and mani-
fest systems as well as prescribed actions at the point of generation, during
transportation and on through treatment, storage, and disposal. The regula-
tions for treatment, storage, and disposal facilities are largely adminis-
trative in nature, covering such items as personnel training, security,
inspections, waste analysis, etc.; however, some technical requirements such
as ground water monitoring, closure care, and post-closure care are included.
The regulations promulgated in January and February 1981 contain the major
portion of technical requirements for hazardous waste incinerators, tanks,
piles, storage surface impoundments, and containers; and temporary permitting
standards for new surface impoundments, new landfills, new land treatment
facilities, and new underground injection wells. More permanent permitting
standards for new and existing land disposal facilities were proposed at the
same time. Waste-specific regulations will be promulgated for specific
streams which require either more/less stringent or different control in
order to protect public health and the environment over the next few years.
An area of uncertain regulatory authority is the use of surface mines
as sites for the disposal of both hazardous and non-hazardous wastes generated
by synfuels facilities. The Surface Mine Reclamation Control Act provides
for disposal of mine-related wastes but does not specifically address the
disposal of non-mining wastes in surface mines. The Office of Solid Waste
(EPA) and Office of Surface Mining (DOI) are currently addressing the juris-
dictional aspects of this issue. When this issue is settled, it is likely
that the regulations will be equivalent to RCRA land disposal regulations for
hazardous and non-hazardous wastes.
30

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Pursuant to 1980 congressional amendments to RCRA, EPA recently amended
the hazardous waste regulations in interim final fashion to exclude from re-
gulation under Subtitle C of the Act solid waste from the extraction, bene-
fication, and processing of ores and minerals. The congressional amendments
included special provisions designed to coordinate regulation of coal mining
waste with the requirements of the Surface Mining Control and Reclamation Act.
Until the Agency has resolved questions of legal interpretation presented by
these provisions, it is interpreting the RCRA exclusion broadly to include
coal exploration, mining, cleaning and other processing activities, on the
basis that coal is an "ore or mineral". EPA will examine public comments and
the legislative history to determine more fully the scope of the exclusion
and in particular, the impact on wastes from direct coal liquefaction.
3.4 Requirements for Toxic Substances Control
Virtually all the authorities of the Toxic Substances Control Act (TSCA)
can impact manufacturers of synthetic fuels. Central to the Act is the
responsibility placed on developers to develop adequate data with respect to
the effects of their products on health or the environment. Where industry
has not developed sufficient data on synfuel products, and where the Agency
finds that unreasonable risks may occur, TSCA grants the authority to require
that testing be performed.
Under Section 5 of TSCA, the manufacturer of a new synthetic fuel or
by-product, including process by-products which are sold commercially, must
submit a pre-manufacturing notice (PMN) to the agency at least 90 days prior
to the commencement of manufacture for commercial purposes. This 90-day
requirement is the latest point at which a notice is required under the sta-
tute. Due to the long lead time associated with planning and commercial
development of a synfuel facility, the developer should consider submitting
well before the mandatory 90 day period.
The requirement to submit a PMN may also be applied to substances which
are on the Inventory (see below), but which are intended to be manufactured
or processed in a manner which presents markedly different exposure patterns
(under a Significant New Use Rule - SNUR). EPA will review the data pre-
sented in the PMN and may take no action, in which case the product may be
manufactured for commercial purposes at the end of the 90 day period. If
31

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however, the agency determines that sufficient data have not been submitted
to make a reasonable assessment of the risks posed by the chemical substance,
and believes that the product may present an unreasonable risk to man or the
environment, it could restrict the manufacture or use of the product until
appropriate data are developed. While the general data requirements for a
PMN are defined in Section 5 of TSCA, submitters are encouraged to contact
EPA at the earliest possible time for guidance concerning the specific nature
of data which should be submitted, thereby avoiding potential delays.
The requirement to submit a PMN depends on whether the substance is
already included on the Chemical Substance Inventory. A determination of
whether a substance is on the inventory depends in part on the type of sub-
stance. Class I chemical substances, i.e., those which can be characterized
by a single molecular structure, e.g., methane, benzene and ethane are con-
sidered to be on the inventory, irrespective of their source. Thus, methane
produced by a synfuel plant is considered to be equivalent to methane on the
Inventory and thus does not require the submission of a PMN.
Class II chemical substances, i.e., those of undefined or variable com-
position (e.g., naphtha, fuel oil) or those derived from biological sources
are distinguished by:
1)	composition,
2)	the raw material source,
3)	process by which it was extracted.
Therefore, products with an undefined or variable composition, such as
fuel oils or naphthas, will require a PMN. While they may not pose a greater
risk than their associated natural gas or petroleum-derived counterparts, the
manufacturer should provide enough data in the PMN so that EPA can assess the
risks associated with the product.
TSCA places the primary burden of minimizing hazards and exposure to
products in commerce on the manufacturer. In their PMN's, through toxicity
and exposure assessment data, manufacturers must demonstrate that their pro-
ducts will not pose unreasonable risks. To serve this purpose, the Office
of Pesticides and Toxic Substances has formed the Synfuel Toxics Work Group,
a committee composed of technical experts on synthetic fuel processes. This
32

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committee will provide a forum for the exchange and review of information
during the PMN development process, and serve as a source of guidance for
the synfuel developer. The intent of the committee is to minimize the poten-
tial for unnecessary regulating constraints and delays.
The authority of TSCA also extends to any synfuels or associated pro-
ducts and by-products which are on the inventory or which have already passed
through the PMN process. EPA may use the authorities of TSCA to require the
reporting of available data relative to potential risks to man and the envir-
onment. If EPA determines that these substances pose unreasonable risk
(e.g., after reviewing new data on effects or control system performance),
it can stipulate data reporting or testing requirements, and subsequently,
regulation.
33

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SECTION 4
PROCESS DESCRIPTION AND POLLUTANT SOURCES
This chapter provides a brief description of the operations and non-
pollution control auxiliary processes involved in SRC-11 direct liquefaction
facilities and identifies the major process and waste streams associated with
those operations and processes. The operations and processes described in
this section comprise the "uncontrolled base plant" in that they are all re-
quired to produce marketable products and by-products. Operations covered
include coal preparation, coal liquefaction, product separation/upgrading,
and hydrogen production plant. Auxiliary operations covered are divided into:
raw water treatment, steam and power generation, cooling system, oxygen pro-
duct, and product/byproduct storage.
A simplified flow diagram of the SRC-II process is presented in Figure
4-1. Pollution control operations such as sulfur recovery, ammonia recovery,
tar acid recovery, and plant wastewater treatment/reclamation are also in-
cluded in this block flow diagram to indicate the flows of waste streams into
various treatment areas.
4.1 Coal Preparation
Coal is received as 20 x 0 cm (8" x 0) run-of-mine (ROM) coal by 100-car
unit trains. The coal is crushed and screened to a minus 20 cm (8") size
and conveyed to one of six long piles in the coal storage area. Coal is re-
claimed from these storage piles and transferred to the secondary crushing
plant. The secondary crushing plant reduces the 5 x 0 cm (2" x 0) coal to
minus 0.32 cm (1/8") size before providing feed for the pug mills.
The major waste streams associated with the coal preparation operation
are storage pile runoff, fugitive dust emisions from coal storage and trans-
portation and dust from coal crushing and screening. Storage runoff tends
to be high in iron, manganese, and dissolved solids (particularly sulfate)
and can be quite acidic in the case of Powhatan and Blacksville type coals.
34

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-&
¦o-

-a>
Figure 4-1. Block Flow Diagram for SRC-II Commercial Plant

-------
Dust from coal preparation consists of natural soil and overburden material
as well as coal.
4.2 Coal Liquefaction
In the coal liquefaction area, coal feed from the coal crushing system is
first sent to pug mills and extruders for blending and pressuring, then con-
tacted with hot recycle solvent slurry. The coal slurry mixture then flows
into the slurry charge tank, where moisture and light hydrocarbons are flashed
out. The flash gas is passed through a vapor recovery system for phase sep-
aration. Hydrocarbon gas from the vapor recovery system is sent to the DEA
unit for treating after compression, whereas the hydrocarbon liquid conden-
sate is sent to the atmospheric fractionator. The coal slurry is pumped from
the charge tank to feed the fired dissolver charge heater at high pressure.
Heated makeup hydrogen is also introduced into the dissolver charge heater.
The effluent from the heater is sent to the dissolver, where hydrocracking
reactions take place at about 730°K (860°F) and 13.9 MPa (2000 psig). Ad-
ditional cold feed hydrogen is introduced into the dissolver to control the
temperature of the exothermic reactions. The effluent from the dissolver is
quenched with cold recycle liquid hydrocarbons to stop further reactions be-
fore it enters the high pressure effluent separator.
The quenched dissolver effluent is sent to a vapor-liquid separator.
The vapor product and unreacted hydrogen from this high pressure separator
is cooled. The gas then goes to the recycle gas treating area for cleanup
and recovery of hydrogen, which is recycled to the dissolver. Liquid con-
densate from the flash drums in this high pressure cooling area is partly
used as quench oil for the dissolver, with the remainder sent to the low
pressure cooling area for additional processing.
The separated liquid from the dissolver effluent separator, together
with remaining solids (mineral residue and some unreacted coal), is de-
pressured in three letdown stages. The letdown vapor and slurry are flashed
in a sequence of steps. The major portion of the slurry is recycled to the
coal feed slurry mixing system, with the remainder sent to the product re-
fining area for vacuum flash treatment. About half of the liquid hydrocar-
bon condensate is sent to the atmospheric fractionator for product refining,
36

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and the other half returned as recycle solvent to the coal slurry mixing sys-
tem. Overhead gas is sent to the DEA unit for treating after compression.
Three sour water streams are generated from the coal liquefaction area.
These are the sour water from the coal slurry nix tank, and the sour water
streams from the high pressure cooling and low pressure cooling of the dis-
solver effluent. The coal slurry mix tank sour water contains only traces
of hydrogen sulfide and ammonia, but the other two sour water streams contain
hydrogen sulfide in the 1,000 - 10,000 ppmw range and ammonia in the 1,000 -
42,000 ppmw range. In addition, the sour water streams from cooling of the
dissolver effluent also contain C5 -350°F organics in the 5,500 - 43,000 ppmw
range. The Cg -350°F organic fraction consists primarily of phenolic, cresy-
lic, and higher boiling range polar aromatics.
4.3 Product Separation and Purification
The produce separation and purification operations for the SRC-II com-
mercial plant consist of four major process areas: recycle gas treating
and hydrogen recovery plant, low pressure gas compression and treating plant,
product gas plant, and refining plant.
4.3.1 Recycle Gas Treating and Hydrogen Recovery Plant
In recycle gas treating, raw recycle gas from the high pressure cooling
of dissolver effluent is first washed in an absorption column with lean oil
from the refining plant. This results in the extraction of substantially
all of the C5 and heavier components, which are returned to the refining
plant with the rich oil. The scrubbed gas is then sent to the diethanolamine
(DEA) absorption unit to remove COj and ^S. The acid gas from the regenera-
tion of the DEA solution contains 64 - 72% and requires treatment.
The sweet recycle gas from the DEA unit is compressed before recovery
of the hydrogen by cryogenic separation. In the cryogenic separation reaction,
hydrocarbon contaminants and inert components (nitrogen and argon) are removed
to produce upgraded hydrogen for recycle to the dissolver plant. In addition,
four separate hydrocarbon fractions are obtained: a methane-rich gas, an
ethane-rich stream, a propane-rich gas, and a butane-rich liquid.
Two small sour water streams are generated from recycle gas treating and
37

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hydrogen recovery. Both streams contain trace quantities of hydrogen sul-
fide and carbon dioxide.
4.3.2	Low Pressure Gas Compression and Treating Plant
Sour hydrocarbon gas streams produced from the dissolver plant and the
refining plant are compressed and cooled in several stages. Liquid hydro-
carbons, separated from the sour water, are sent to the debutanizer of the
refining plant for processing. The sour gas is treated in a low pressure DEA
unit, then sent to the product gas plant. As in recycle gas treating, the
acid gas stream from the DEA regenerator contains high concentrations of f^S
in the 67 - 762S range.
4.3.3	Product Gas Plant
The sweet gas from the low pressure DEA unit is passed through a fixed
bed absorber containing molecular sieves to remove the last traces of carbon
dioxide, hydrogen sulfide, and water, and then enters the cryogenic unit.
The products from cryogenic separation include a hydrogen-rich gas for use as
plant fuel, an ethane-propane product which can be pipelined for use as ethy-
lene plant feedstock, and liquid hydrocarbons (butane and heavier) which are
sent to the depropanizer.
The liquid hydrocarbons from the cryogenic unit, in combination with the
propane-rich gas and butane-rich liquid from the recycle gas hydrogen re-
covery plant, are fractionated in the depropanizer. The non-condensed de-
propanizer overhead ethane-propane gas stream is combined with ethane-propane
products from other areas to yield the Cg-C^ pipeline product. The depropani-
zer bottoms are fed to the debutanizer to yield butane and naphtha products.
4.3.3 Refining Plant
The refining plant includes an atmospheric fractionator, a naphtha stabi-
lizer (debutanizer), and a vacuum flash tower. Liquid hydrocarbons from the
low pressure cooling of the dissolver effluent, the rich absorption oil from
the recycle gas oil wash absorber, and the heavy oil obtained as the overhead
product from the vacuum flash tower are fed to the atmospheric fractionator.
These liquid hydrocarbons are separated into a vapor sent to the low pressure
gas compression and treating plant, a sour water stream, a light liquid
38

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hydrocarbon product sent to the naphtha stabilizer (debutanizer), a light
fuel oil product and a heavy fuel oil product.
In addition to the liquid hydrocarbons from the atmospheric fractionator,
a liquid hydrocarbon condensate stream from the low pressure gas compression
and treating plant is also fed to the naphtha stabilizer (debutanizer). Vapors
from the debutanizer overhead are sent to the low pressure gas compression and
treating plant. The sour water separated from the liquid hydrocarbons in the
overhead accumulator, as other sour water streams from the refining plant, con-
tain trace quantities of hydrogen sulfide and carbon dioxide. Stabilized
naphtha is obtained as the bottoms product from the debutanizer.
The slurry stream from the dissolver effluent separators is fed directly
to the vacuum flash unit. This vacuum is produced by a four-stage condensing
ejector system. Overhead vapors are condensed, cooled, and pumped to the
atmospheric fractionator. The hot slurry oil bottoms are pumped directly to
the Texaco gasifier for hydrogen production. Oil water mixtures collected
at the hotwell for the vacuum ejector system are separated. The recovered oil
is sent to the atmospheric fractionator. The sour water has similar charac-
teristics as the sour water from the debutanizer and the atmospheric fraction-
ator.
4.4 Hydrogen Production Plant
The hydrogen production plant produces purified high pressure hydrogen
for makeup to the dissolver plant, and essentially sulfur-free fuel gas for
process use. Principal operations within this plant include syngas produc-
tion, syngas shift conversion, hydrogen purification and syngas purification.
Also included in this plant are methanation and dehydration operations which
convert excess methane rich gas to pipeline sales gas. The hydrogen produc-
tion plant and associated process/waste streams are described in the ensuing
sections.
4.4.1 Syngas Production
Production of raw synthesis gas will be based upon Texaco coal gasifi-
cation technology. The Texaco gasification process involves a pressurized,
downflow, slagging gasifier which gasifies the vacuum-bottoms slurry with
39

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oxygen and steam. Available test data and design information indicate that
pressures of 2.1 to 8.2 MPa (300 to 1200 psi) would be appropriate for gasi-
fying SRC-II vacuum bottoms slurries. Gasification temperatures are general-
ly above the ash fusion temperature (1,500°K 2,300°F) to obtain high gasifi-
cation rates and minimize the quantities of undesirable byproducts such as
tars, oils, and phenols.
Gasification feed is partially reacted with oxygen, in the presence of
steam, to produce a raw gas consisting primarily of CO, H^, and steam.
Raw gas is partially cooled and the slagged ash is solidified through contact
with water in a quench bath. Quenched gas is scrubbed with water to remove
impurities such as ammonia, formate and char. Buildup of soluble ash con-
stituents as well as organic and inorganic reaction products is controlled
by blowdown of quench and scrubber water. Flash gas derived from blowdown
streams contains 3-5% reduced sulfur (primarily ^S) and is, therefore, sent
to the sulfur recovery area for processing.
Solids generated during gasification are slag and char. Quenched coarse
slag is readily dewatered, while slag fines require thickening and filtration
dewatering. Slag fines are combined with the coarse slag and trucked to dis-
posal. Filtrate from slag dewatering is pumped to wastewater treatment for
suspended solids removal. A small quantity of char, containing approximately
6-12% unreacted carbon, is recovered from scrubber and recycle water by set-
tling. Depending upon the carbon content of the char, this material may be
recycled to the gasifier or added to the coal feed in the front end of the
liquefaction plant.
4.4.2 Syngas Shift Conversion
A major portion of the Texaco syngas (approximately 82%) is processed
through two stage shift conversion to produce the hydrogen required for
makeup to the dissolvers and to supply reducing hydrogen for the sulfur plant,
if required. Two stage shift conversion with interstage gas cooling is em-
ployed to reduce the CO concentration of the produce gas to about one percent
(dry basis) without excessive heating of the catalyst bed and subsequent
suppression of the CO conversion reaction. The remainder of the syngas is
processed through a single stage hydrolysis reactor where COS is hydro!ized
40

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to which is subsequently removed to yield a low sulfur fuel gas.
Shift arid COS hydrolysis catalysts may periodically require regeneration
to remove accumulated carbon deposits. Regeneration involves controlled oxi-
dation of the catalyst with air utilizing steam for temperature control. Off-
gas produced by regeneration will contain both carbon and sulfur oxides. After
a few regeneration cycles, these catalysts lose activity due to physical de-
gradation or accumulation of chemical poisons (e.g., arsenic) and must be
replaced.
Condensate produced during shift gas cooling is consumed by the Texaco
gasifier as makeup water. Hence, no shift condensate treatment is required.
4.4.3 Hydrogen Purification and Compression
The hydrogen purification plant employs Allied Chemical's selective Sele-
xol process to remove acid gases from the hydrogen rich shift gas. Crude
shift gas is cooled and contacted countercurrently with Selexol solution in
two absorbers in series to sequentially remove H2S and CO2. In the first ab-
sorber, high-pressure, CO2 rich solution contacts the shift gas and selectively
absorbs H2S down to a concentration of about 2 ppm in the gas leaving the ab-
sorber. H2S is removed from the rich solvent by the combined action of pres-
sure release and thermal regneration to produce an 18-22$ H2S, 200-300 ppmv
COS feed stream to the sulfur plant. Condensate from shift gas cooling is con-
sumed in the Texaco gasifier as makeup water.
Sweet shift gas is then contacted in the second absorber for bulk CO2 re-
moval yielding a product hydrogen stream containing about 1 ppm H2S and 2500
ppm CO2. Rich solution from the CO2 absorber is flashed in two stages prior
to regeneration stripping with nitrogen. The first-stage flash vapors are com-
pressed and recycled to the C02 absorber inlet. Second-stage flash gas, which
contains very small amounts of H2S and less than 0.5 percent combustable gases,
is combined with the COj stripper off-gas for disposal.
Purified hydrogen from the CO2 absorber is compressed to 16.9 MPa (2450
psia) and delivered to the dissolver plant as makeup. A slipstream of puri-
fied hydrogen may be provided to the sulfur plant if reduction gas is required.
41

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4.4.4	Syngas Purification
Excess syngas is processed through a nonselective Selexol unit to reduce
t^S and CO2 concentrations in a single physical absorption step. Cooled syn-
gas is contacted countercurrently with refrigerated lean Selexol solution, re-
ducing the syngas t^S concentration to 1 ppm and removing a portion of the CO2
Rich Selexol solution is regenerated by pressure release and thermal regenera-
tion to yield lean solution and a 20-30% fr^S feed gas to the sulfur plant.
Condensate from syngas cooling is consumed in the Texaco gasifier as makeup
water.
4.4.5	Methanation and Dehydration
Methane-rich gas from the cryogenic hydrogen recovery unit (Area 12) is
catalytically converted to pipeline quality gas in the methanation and de-
hydration plant. The hydrogen content of the gas exceeds the stoichiometric
requirement for the methanation reaction and no hydrogen addition is required.
Feed gas is preheated and passed through sulfur guard beds to reduce trace
sulfur concentrations to below 1 ppm prior to methanation. Ethane, heavier
hydrocarbons, and CO in the desulfurized feed gas are converted to methane
in a two stage methanation system.
Product gas from methanation is cooled and routed to a glycol dehydra-
tion unit. Condensate from gas cooling is consumed in the Texaco gasifier
as makeup water. Dried product gas containing less than 70 ppm water is
sent through a metering station to a natural gas pipeline. The wet glycol
is regenerated in a reboiler which reproduces a wastewater feed to treatment
and a small quantity of reflux accumulator vent gas for disposal.
Periodically, sulfur guard must be replaced due to loss or reactivity.
Similarly, methanation catalyst eventually require replacement due to de-
activation by physical degradation and chemical poisoning. Decommissioning
of spent methanation catalyst involves controlled oxidation with air and,
therefore, results in the periodic production of an offgas requiring disposal.
4.5 Waste Streams from Auxiliary Processes
The major auxiliary processing units generating waste streams are: 1)
makeup water treatment, 2) process cooling, 3) liquid product/by-product
42

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storage, and 4) oxygen production. A major waste stream not present in a
SRC-II commercial plant is the coal-fired steam/power boiler flue gas,
since the plant power requirements are met by low pressure steam turbine
and syngas expander gas turbine generators. Steam is generated in gas-fired
process heaters and waste heat boilers. The contribution of these units to
overall combustion flue gas volume and pollution is small since treated fuel
gases contain only small amounts of sulfur and nitrogen containing compounds,
heavy organics and particulates.
The major waste streams from the makeup water treatment operation are
sedimentation pond and lime/soda softener sludges and demineralizer regenera-
tion wastewaters from the boiler feedwater treatment unit. Coal pile runoff
and storm water runoff are assumed to be contained and used to satisfy in-
plant process makeup water needs.
The use of treated process wastewater as cooling tower makeup may be
justified either to minimize plant makeup water requirements or to concentrate
process wastewaters prior to further treatment. However, in either case, the
use of treated process wastewater as cooling tower makeup may result in: 1)
residual organics and inorganics in the cooling tower blowdown stream, and 2)
emissions due to the stripping or entrainment of makeup cooling water contami-
nants .
Storage of liquid products and by-products is accompanied by evaporative
emissions. These vapors consist primarily of low molecular weight hydrocar-
bons, and contain aromatic compounds such as benzene and toluene. Similar
emissions are generated from fugitive sources in an integrated facility such
as valves, flanges, pump and compressor seals, leaks, and spills.
The oxygen plant will not itself be a source of waste streams requiring
control. However, as a major consumer of energy, it will impact the magni-
tude of the waste streams produced in other units, particularly in the steam/
power generation and cooling sections.
4.6 SRC-II Products and Byproducts
For purposes of analysis, a plant size corresponding to 633 TJ per stream
day (equivalent to 100,000 barrels per stream day, assuming 6 million Btu per
barrel) of net products has been selected. For commercial plants of this size,
43

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the SRC-II product slate is given in Table 4-1.
A brief assessment of the toxic potential of SRC-II products and byproducts
is presented below. However, the samples which have been chemically analyzed
or tested for biological activity are from a pilot facility, and thus, are not
necessarily representative of products from a commercial facility.
The available information on the biological activity and chemical com-
position of direct coal liquefaction products and byproducts indicates that,
in general, the toxic effects of the fuel products are not attributable to
low level contamination by a single and easily removed constituent. Similarly,
some of the byproducts are relatively toxic chemicals even in pure form,
although contamination may substantially alter the level of hazard they pose.
Other byproducts, however, are relatively non-toxic or could be by the
elimination of some low concentration constituents. The SRC-II products and
byproducts are reviewed below in light of these three categories.
4.6.1	SRC-II Fuel Oil
The fuel oil product corresponds to a blend of approximately three parts
middle distillate with one part heavy distillate and has a nominal boiling
range of 177°C to 482°C (350°F to 900°F). Although some testing for bio-
logical activity has been performed on the fuel oil blend, most of the
available test results are for the unblended middle distillate and heavy
distillate fractions. These tests indicate that the fuel oil would pose a
significant hazard to human health and ecological systems. Comparable test
results from corresponding petroleum products are limited and, thus, make
an assessment of relative toxicity very difficult. The directly comparable
results which are available suggest that the SRC-II fuel oil would be at
least somewhat more toxic to humans and substantially more toxic to aquatic
ecosystems than its petroleum analog. Studies also indicate that mild
hydrotreatment resulted in a substantial reduction in the mutagenicity, as
measured by the Ames/Salmonella test, of the SRC-II fuel oil blend.
4.6.2	Naphtha
There are also very few directly comparable health effects test results
available for SRC-II and petorleum naphthas. Ames/Salmonella and skin
44

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TABLE 4-1. NET PRODUCT SLATE FOR SRC-II COMMERCIAL PLANT (STREAM DAY BASIS)
Net Product*
Powhatan
No. 5
B1acksville
Fuel Oil
Pipeline Gas
Naphtha
Light Hydrocarbons
Butanes
Sulfur
Ammonia
Tar Acids
8,742 m
1,410,200 snf
2,658 m3
2.556 Gg
0.268 Gg
1.046 Gg
0.163 Gg
37.2 m3
8,472 mJ
6,125,000 snf
1,947 m3
0.862 Gg
0.706 Gg
0.71-2 Gg
0.140 Gg
35.5 m3
* Product Property Basis
Fuel Oil
Pi peline Gas
Naphtha
Light Hydrocarbons
Butanes
350-900 F normal boiling range.
940 Btu/cu ft higher heating value.
Petanes to 350°F normal boiling range.
93% of 50-50 wt % ethane and propane, 7 wt S
miscellaneous gases for Powhatan No. 5 case;
liquid propane product for the Blacksville
coal case.
96 wt % of C. hydrocarbons, 4 wt % and C,.
hydrocarbons for Powhatan No. 5 case; 73.5
wt % C« hydrocarbons, 1.3 wt % C3 hydrocarbons,
and 25.2 wt % Ce+ hydrocarbons for the
Blacksville coat case.
45

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painting studies suggest that the two naphthas are not significantly different
in their mutagenic or tumorigenic activity. The SRC-II naphtha, however,
appears to be more acutely toxic via skin sbsorption.
4.6.3	Pipeline Gas, Light Hydrocarbons, Butanes and Sulfur
These byproducts are expected to be very similar in composition and,
hence, toxicity to products currently in conmerce. It must be recognized, how
ever, that contamination by toxic impurities could significantly alter the
hazards posed by the byproducts. At this time there is no information avail-
able on contaminants in the byproduct gases, but the sulfur may contain trace
levels of thiosulfate, thiocyanate, and vanadium.
4.6.4	Ammonia and Tar Acids
Ammonia and phenols are sufficiently toxic in pure form to warrant
special precautions. However, contaminants may require extra precautions to
be taken. For example, the ammonia may contain trace quantities of thio-
cyanates or phenols and the tar acids may contain trace quantities of organic
solvent from the phenol recovery process.
46

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SECTION 5
EVALUATION OF POLLUTION CONTROL TECHNOLOGIES
At the present time no direct coal liquefaction plants exist in the
United States, and very limited data are available relating to pollution
control from the operation of the SRC-I, SRC-11, EDS, and H-coal pilot plants.
Thus, control technologies applicable to the waste streams identified in
Chapter 4.0 and to wastes generated by pollution control systems are gener-
ally those which are currently used or are under development for use in
such related industries as petroleum refining, coal cleaning, by-product
coking, and electric utilities. The following comprises an evaluation of
the control methods which may be adapted from other industries and from
general pollution control practices and provides supporting information for
the primary waste stream guidance in Section 2 and the secondary waste stream
guidance presented by discharge medium in this section.
5.1 Approach
Evaluations of control technologies for application to individual waste
streams were based on considerations of control efficiency, energy and re-
source consumption, safety and reliability, simplicity, multi-pollutant abate-
ment capability, residue generation and disposal requirements, potential for
recovery of by-products, capital and operating costs and stage of technology
or process development. The above criteria were used as a basis for 1) com-
parison of candidate control technologies, used alone or in combination with
in-plant control methods or other add-on controls, and 2) identification of
trade-offs among controls for minimizing total plant emissions and energy
requirements.
Performance data for applicable control technologies have been obtained
primarily from the open literature and supplemented by vendor-supplied data.
The capabilities of various control technologies have not usually been assess-
ed on a design-specific basis, but rather upon a generalized basis derived
from test results and/or engineering studies of the subject technologies. In
many cases, performance can only be estimated in terms of control of major
constituents (e.g., total sulfur) or gross parameters (e.g., BOD) since often
47

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no data are available on removal efficiencies for specific substances.
Further, even in those cases where substance-specific performance information
exists for a control technology, accurate or complete characterization of the
waste streams requiring control may be lacking. In the final analysis, the
capabilities of controls can only be accurately evaluated by testing operating
facilities or smaller units from which data can be confidently extrapolated to
commercial size. The performance estimates in this document, which are based
upon actual experience or engineering analysis, are believed to reflect the
best information currently available in the public domain.
In order to compare controls for cost effectiveness and to estimate the
impact of pollution control costs on overall plant costs, approximate capital
and operating costs for individual control processes have been developed.
These costs are based on factored estimates of costs contained in non-pro-
prietary published literature (normalized to a first quarter 1980 basis), as
well as actual vendor quotes. However, it was generally beyond the scope and
purpose of the PCGD to develop the detailed engineering designs necessary for
cost estimation at the "firm" (+ 5 to 10%) level. Although the accuracy of
the cost estimates vary, most are believed to be within +50%. Under usual
circumstances, a conservative approach was taken. It is also recognized that
total costs are strongly influenced by oversizing and/or redundancy designed
into system in order to compensate for the uncertainties in reliability or
performance levels. No attempt has been made in the PCGD to account for these
factors in the costing, although uncertainties in control costs arising from
these factors have been considered in the recommendations of control levels.
For purposes of presentation in this volume, costs for various pollution
controls are expressed as a percentage of the base plant capital and total
annualized costs. This approach was selected since the percentage values
are relatively insensitive to economic assumptions (e.g., interest rate), are
relatively independent of inflation and plant size (in the size range examined),
and more clearly indicate the magnitude of pollution control costs relative to
overall plant costs than would actual dollar estimates. The base plant costs
used for these calculations are summarized in Table 5-1. These costs were
developed from published economic/engineering studies of the subject technolo-
gies using procedures described in Volume 2.
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TABLE 5-1 BASE PLANT* CAPITAL AND TOTAL ANNUALIZED COSTS
FOR SRC-II COMMERCIAL PLANT (MILLIONS OF DOLLARS,
1st QUARTER 1980)
Capital Cost	Total Annualized Cost+
2878	914
*Base plant is one which includes all process operations necessary for
self-sufficiency but no pollution controls.
+Total annualized costs include capital charges.
49

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Total annualized costs were calculated as the sum of annual operating
costs and annualized capital costs. The following assumptions were made for
purposes of annualizing the base plant capital investment:
100 percent equity financing
interest charges during construc-
tion added to total capital invest-
ment
discount rate = 12%
life of system = 20 years
depreciation method = sum-of-
year's-digit
depreciable life = 16 years
o income tax rate = 48%
® real property tax rate = 1.5%
•	capital property tax rate =1.5%
o investment tax credit = 20%
•	insurance rate = 0.5%
t working capital = value of 60
day inventory of coal
fuel escalation rate = 0%
• stream factor = 90%
• 0 & M escalation rate = 0%
Based upon these assumptions, a fixed rate charge factor of 0.172 is
calculated, which represents the fraction of the total base plant capital
investment which must be assessed as annualized capital charge. This same
factor was used for purposes of annualizing capital costs of pollution controls.
The energy impacts of pollution control are also presented in this volume
as a percentage of the total plant input energy (HHV). Model plants producing
633 TJ per stream day (equivalent to 100,000 barrels per stream day, assuming
6 million Btu per barrel) of saleable products would consume the coal equiva-
lent of 890 to 1150 TJ/stream day, depending on the specific coal and process-
ing route.
The control technology evaluations which are presented in this section
are organized according to the characteristics of the waste stream in question.
Thus, the treatment and disposal of all aqueous wastes are dealt with in the
water pollution control section, even though some ultimate disposal options
for treated wastewaters (e.g., surface impoundment) would fall under the
purview of RCRA. This approach is taken because it facilitates the presen-
tation and discussion of integrated plant control strategies for key waste
streams.
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At the conclusion of this section, a summary of the two control technology
guidance options selected for each waste stream is presented. In establish-
ing this two-option approach, the Agency defined an Option II control level
which corresponds roughly to current required levels of environmental pro-
tection in other industries as well as a more stringent Option I approach.
Option I is generally more protective of the environment in that it is tech-
nology-forcing and covers both currently regulated pollutants as well as some
which are not presently regulated. Reference to these options, in the context
of the preceding definitions, is made throughout the balance of this section.
5.2 Air Pollution Control
Table 5-2 lists the gaseous waste streams generated in SRC-II based direct
liquefaction facilities, the pollutants of concern for each of these streams,
and the relative stream flow rates. The largest volume streams requiring
control are acid gases, sour fuel gases, and combustion flue gases. Control
options for reduced sulfur compounds, sulfur oxides, reactive hydrocarbons (RHC),
carbon monoxide, particulates, oxides of nitrogen, ammonia, hydrogen cyanide,
polycyclic organic matter (POM), and trace elements are summarized in the
remainder of this section on both a stream-by-stream basis and in the context
of integrated facility control approaches.
For evaluation of control alternatives for reduced sulfur compounds,
reactive hydrocarbons (RHC), and CO, both the Powhatan No. 5 coal and the
B1acksvilie coal cases are examined. The Blacksville coal differs from the
Powhatan No. 5 coal in having a lower sulfur content, and is analyzed mainly
for the impact of coal sulfur on the cost and performance of various options.
Reactive hydrocarbon (RHC) and CO control performance and costs are not
generally coal specific.
5.2.1 Sulfur Emission Control in an Integrated Facility
Gaseous waste streams in a direct liquefaction facility which require con-
trol of reduced sulfur compounds ^S, COS, CS2, mercaptans) are, in order of
importance, (1) acid gases, (2) sour fuel gases, and (3) transient waste gases.
The major stream requiring SOg control in a direct liquefaction facility is
normally the boiler flue gas stream. Intermittent streams from regeneration/
decommissioning of shift or Beavon catalyst also contain SO2• Key features of
technologies applicable to the control of reduced sulfur comDounds and SO2 are
51

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TABLE 5-2. SUMMARY OF UNCONTROLLED GASEOUS WASTE
STREAMS GENERATED IN SRC-II COMMERCIAL PLANT
Stream
and
(Stream Number)
Pollutants of Concern
Factors Affecting Stream
Flow and Characteristics
Uncontrolled Waste
Stream Flow Rate
Waste Stream/Main Process Train
Coal storage/preparation
• Coal storage (6103)
Particulates
Size and configuration of coal storage pile,
meteorological conditions
240 Hg/yr
• Coal loading, unloading,
transfer, and crushing
(6104)
Particulates
Transport system design, size requirements for
liquefaction reactor
19,600 Hg/yr
Sour fuel gas used as plant fuel



• Itethane rich gas (1218
after treatment, part of
1201 prior to treatment)
Reduced sulfur compounds,
RHC, CO
Design of hydrogen recovery and treating system,
coal type and sulfur content
3,100 kmol/hr
• Excess syngas used as
plant fuel (2202)
Reduced sulfur compounds,
CO, HCN, MHj
Type of gaslfler used, coal type and
sulfur content
20,400 kmol/hr
• Hydrogen rich gas from
low pressure gas treating
(3201 after treatment,
part of 3101 prior to
treatment)
Reduced sulfur compounds,
RHC, CO
Design of product separation and low pressure
gas preparation systems, coal type and sulfur
content
2,500 kmol/hr
• Butane (5401 after
treatment, part of 3101
prior to treatment)
Reduced sulfur compounds.
RHC, CO
Design of product separation and low pressure
gas preparation systems, coal type and sulfur
content
200 kmol/hr
Acid gas from AGR unit in
recycle gas treating (1207)
Reduced sulfur compounds
Type AGR process used, coal type and
sulfur content
870 kmol/hr
Flash gas from gasification
unit (2104)
Reduced sulfur compounds,
CO. NHj
Type of gasifier used, coal type and
sulfur content
700 kmol/hr
-continued-

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TABLE 5-2.
(Continued)


Stream
and
(Stream Number)
Pollutants of Concern
Factors Affecting Stream
Flow and Characteristics
Uncontrolled Uaste
Stream Flow Rate
H^S-rich acid gas from AGR
unit in hydrogen purification
(2202)
Reduced sulfur compounds
Type of gaslfler and AGR process used, coal
type and sulfur content
1,600 kmol/hr
CO^-Hch acid gas from AGR
unit in hydrogen purification
(2303)
Reduced sulfur compounds
Type of AGR process (selective or non-selective)
used
21,800 kmol/hr
Acid gas from AGR unit In
syngas purification (2402)
Reduced sulfur compounds,
CO
Type of gaslfler and AGR process used, coal
type and sulfur content
260 kmol/hr
Acid gas from AGR unit In
low pressure gas treating
(3105)
Reduced sulfur compounds,
RHC
Type of AGR process used, coal type
and sulfur content
280 kmol/hr
Transient waste gases



• Liquefaction reactor
(8103)
Reduced sulfur compounds,
RHC, CO, NHj, POM
Liquefaction unit startup/shutdown
procedures and operational difficulties,
coal type and sulfur content
12,000 kmol/hr
» Gaslfler (8104)
Reduced sulfur compounds
RHC, CO, NH3, POM
Type of gaslfler used, gaslfler startup/
shutdown procedures and operational
difficulties, coal type and sulfur content
29,000 kmol/hr
Catalyst decoirmlssionlng/
regeneration offgases



• Shift/hydrolysis
catalyst reneneratlon
(2204, 2205)
Particulates, SO., trace
elements
Regeneration frequency and procedures,
catalyst characteristics
39,000 kmol/hr
• Methanation catalyst
decommlssloning (2510)
Particulates, CO,
Ni(C0)4
Decomnisslonlng frequency and procedures,
catalyst characteristics
28 kmol/hr
Uaste stream flow rate during generation period
-continued-

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TABLE 5-2. (Continued)
Stream
and
(Stream Number)
Pollutants of Concern
Factors Affecting Stream
Flow and Characteristics
Uncontrolled Uaste
Stream Flow Rate
Fugitive organic emissions
VOC. other gases.
POM
Vapor pressure of liquids, temperatures and
pressures of process lines, types of seals
and gaskets used, maintenance practices
N/A
Combustion flue gas from
fired process heaters
(1121, 2509. 3418)
Particulates, SOj. N0X
Type of sour fuel gas treatment system
used, combustion temperature and excess air
36,700 kmol/hr
Auxiliary Operations



Steam boiler combustion
flue gas (5101)
Particulates, S02> N0X
Type of sour fuel gas treatment system
used, combustion temperature and excess air
'5,700 kmol/hr
Air compressor gas turbine
combustion flue gas (4414)
Particulates, S02> N0X
Type of sour fuel gas treatment system
used, combustion temperature and excess air
81*800 kmol/hr
Evaporative emissions from
product storage (5424)
VOC. POM
Type of tanks used, vapor pressure of
liquid stored, storage temperature
56,800 kg/hr
Drift and evaporation from
cooling tower (5301)
NHj. H2S, VOC
Characteristics of makeup water, design
of cooling tower
N/A
Combustion flue gas from
syngas heater (54?5)
Pollution Control Operations
Particulates, SO^, N0X
Type of sour fuel gas treatment system
used, combustion temperature and excess air
2,100 kmol/hr
Acid gas from sour water
stripping/ammonia recovery (4103)
Reduced sulfur compounds,
NHj. VOC
Type of sour water stripping/ammonia
recovery process used
190 kmol/hr
Flue gas from waste water
sludge incineration (4305)
Particulates, SO^. N0x
Type of upstream wastewater treatment,
coal type and sulfur content
-

-------
presented in Tables 5-3 and 5-4, respectively. The most appropriate controls
for each of the gaseous waste streams identified above are discussed in the
following text.
Acid Gases
Figure 5-1 depicts the control alternatives for acid gases. For purposes
of analysis, AGR is considered as a process function (sulfur and C02 removal)
to obtain a suitable recycle gas or hydrogen feed. As indicated in Figure 5-1,
bulk sulfur recovery is accomplished using Claus technology. The process is com-
mercially demonstrated in the natural gas, petroleum refining, and by-product
coking industries. The Stretford process is not considered because of the
high concentration in the acid gas. The Giamarco-Vetrocoke process (Table
5-3), although technically promising, is not considered viable due to the
hazardous nature of the solvent employed. In the case of the Claus process,
additional sulfur removal would be necessary for all applications, since Claus
tail gas treatment is commonly practiced/required in other industries. It
should be commented that control alternatives represented by Claus without
tail gas treatment or by incineration/FGD without prior sulfur recovery result
in significantly greater sulfur emissions than the alternatives shown in Figure
5-1 and, hence, these controls are not considered adequate (greater levels of
control are currently practiced in related industries).
The Beavon technology is the most applicable for residual sulfur control
of Claus tail gases. Other tail gas treatment processes listed in Table 5-3
(e.g., SCOT) cannot generally achieve the same degree of sulfur control.
None of the residual sulfur removal processes have actually been demonstrated
in direct liquefaction applications but the Beavon, WeiIman-Lord, and SCOT
processes have been successfully demonstrated in the petroleum refining and
electric utility industries.
55

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TABLE 5-3. KEY FEATURES OF REDUCED 3ULFUR REIIOVAL TECHNOLOGIES
Process
Process Principle
Components
Removed
Efficiency
Feed Stream
Requirements/
Restrictions
Sour Fuel Gas 1
DEA
'reatment
Simultaneously absorbs
H^S and CC>2
H S, CO , COS,
CS , RSH, NH ,
HC
Normally reduces H2S
level to 100 ppm.
Can be designed to
reduce I^S level to
10 ppmv

Selective
Selexol
Selectively absorbs H^S
over CO^ thus producing
an H^S rich acid gas for
sulfur recovery and a CO^
rich acid gas suitable
for direct discharge to
atmosphere
H S, COS, CS2,
RSH, NH3, HC
Can reduce H S, COS
and RSH levels in
fuel gas to less than
1 ppmv each

Non-selective
Selexol
Simultaneously absorbs
H2S and C02
H S, C02. COS,
RSH, NH3, HC
Can reduce H S , COS,
and RSH levels in
fuel gas to less than
1 ppmv each

Catalytic Re-
duction prior
to AGR
Catalytically reduces
sulfur species to h2s
Conversion of
COS + cs2 to
»2S
Levels of non-H2S sul-
fur as low as 10 ppmv
are possible. Exact
levels depend on tem-
perature, total sulfur
£ CO2 content and
catalvst activity.

Bulk Sulfur Rem
Claus
oval
Catalytic oxidation of
H2S and S02 to elemental
sulfur
Sulfur Compoun
HC' 3
NH3
HCH
CO
Is 95%
33%
33%
33%
33%
12S levels much
selow 10% req's
enrichment prior
to processing.
Stxetford
Liquid phase oxidation
of H2S to elemental
sulfur in an alkaline
solution of metavanadate
and anthraqumone
disulfonic acid
h2s
HCN
CH3SH
nh3
As low as 1 ppmv
100%
90%
0%
High HCN loading
should be reduced
prior to proces-
sing to prevent
excessive solu-
tion purge.
-Giamarco -
VetrocoJce
(G-V)
Liquid phase oxidation
of HjS to elemental sul-
fur in potassium carbon-
ate and arsenate/arsenite
solution.
h2s
COS
cs2
1
|99.99%
Maximum 1.5%
H2S in feed
56

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TABLE 5-3. CONTINUED
By-Products
Reliability/
Limitations
Effects of High
CO2 in Feed
General Comments
Offgas with
hydrocarbons
which can be used
as auxiliary fuel
Very reliable, exten-
sive operating
experience
Increases cost of
AGR system
Applicable to sour fuel
gas streams with high
sulfur content. Also,
contaminants such as COS,
CSj, and HCN will not form
degradation products with
dea.

Over 15 years of com-
mercial experience,
reported to be depend-
able, flexible, and
relatively maintenance
free
Reduces selectivity
for H^S vs CO- and
C02 vs COS
Applicable to sour fuel
gas streams at high acid
gas partial pressures and
relatively low H2S/C02
concentrations ratios. COS
will proportion between
the H^S rich gas and the
C0? rich gas.

Over 15 years of com-
mercial experience,
reported to be depend-
able, flexible and
relatively maintenance
free
Increases cost of
AGR system
Economically attractive
for treatment of sour
fuel gas streams at high
acid gas partial pressures.
"lone
Effect of HC's on
catalytic activity
unknown
Reduces conversion
efficiency
Conversion of COS and CS2
to HjS reduces total sul-
fur discharge from Stret-
ford tail gas and CO2 rich
acid gas streams from
selective AGR processes.
Elemental sulfur
NH3 and HC's may cause
catalyst plugging and
variable 9ulfur
recovery
Can adversely affect
sulfur removal ability
of the process
Dire-c application to H2S
rich acid gases may only
be possible in high sulfur
coal cases, low sulfur
coal cases require enrich-
ment (e.g., ADIP)
Elemental sulfur
Process does not
remove COS + CSj. HCN
and SO2 degrade
solution
High CO2 concentrations
will decrease absorp-
tion efficiency by low-
ering solution alkali-
nity. Increasing absor-
ber tower height S base
addition are required
1 ppmv H2S in tail gas is
possible however higher
limits would probably be
employed when 200-500 ppm
of other reduced sulfur spe-
cies are present in "-.oil gas
Elemental sulfur
which may require
arsenic removal
Hazardous nature of
arsenic solution may
cause handling and
safety problems
Little or no effect
Limited data, hazardous
nature of arsenic solu-
tion and feed stream
requirements make this
process an unlikely
candidate.
57

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TABLE 5-3. CONTINUED
Process Principle
Components
Removed
Efficiency
Feed Stream
Requirements/
Restrictions
Residual Sulfur Removal
Beavon
Catalytic reduction of
sulfur compounds to H2S,
followed by Stretford
process
H2S, COS, CS2,
SO2
99.8% removal for
Claus tail gas con-
taining 4% equiva-
lent H2S or can
attain equivalent of
50 ppm total sulfur
in tail gas (not in-
cluding reducing gases)
Cxean-Air
Catalytic reduction of
sulfur compounds to H2S
followed by a continua-
tion of the Claus reac-
tion and Stretford
process
H2S, COS, CS2,
S02
Plant effluent nor-
mally guaranteed to
contain less than 250
to 300 ppm S02 equiv.
H2S,S02, ratio c=i
vary up to 8.1
without affectini
efficiency; desi-
gned spec.for
Claus tail gas
IFP Clauspol
1,500
Liquid phase continua-
tion of Claus reaction
at a low temperature
H2S, S02
Capable of reducing
sulfur species in
Claus tail gas to
1,500 ppm as SO2
H2S-S02 ratio
maintained in tht
range of 2.0 tn
2.4
IFP-2
Incineration of tail gas
followed by ammonia
scrubbing. Solution
is evaporated to pro-
duce a concentrated
S02 stream which is
returned to the Claus plai,
COS,CS2,H2S
Capable of reducing
sulfur species in
Claus tail gas to
less than 500 ppm
H2S•S02 ratio
maintained in th
range of 2.0 tc
2.4
Sulfreen
Solid phase continua-
tion of Claus reaction
at a low temperature
h2s, so2,
cs2
COS
Capable of removing
30 to 35% of sulfur
in the tail gas
Optimum perfor-
mance requires
H2S-S02 ratio
?<; 3.A	
SCOT
Sulfur species are cata-
lytically reduced to
H2S; H2S is scrubbed in
a regenerable amine
system
h2s, S02, cos
cs2
Can remove up to 97%
of sulfur species (will
vary depending on C02
S H2S concentration in
specific applications).
Incineration
Thermal incineration in
incinerator or on-site
steam and power boiler
or catalytic incinera-
tion
Converts redu-
ced sulfur
species to S02
also removes HC's,
CH3SH, NH3, and
HCN
Essentially 100%
conversion
Incineration
plus S02
Removal (FGD)
Incineration (in on-
site boiler or separate
incinerator) followed
by S02 removal (e.g.,
wellman-Lord)
S02 also re-
moves HC' s,
ch3sh, NH
fi HCN
As low as 50ppm S02
in tail gas and com-
plete removal of
other compounds
58

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TABLE 5-3. CONTINUED
By-Products
Reliability/
Limitations
Effects of High
CO? in Feed
General Comments
Elemental sulfur
Has only been applied
to Claus process tail
gases
Reduces conversion
efficiency of cata-
lyst; decreases H2S
absorption in Stret-
ford solution
Exact ppm limit
achievable in coal
gasification appli-
cation not well known
100 ppntv is believed
by vendor to be
attainable
Elemental sulfur
Has only been applied
to Claus process tail
gases
Reduces conversion
efficiency of cata-
lyst; decreases H2S
adsorption by Stret-
ford solution
Cannot attain as low
of residual sulfur
in tail gas as Beavon
process
:lemental sulfur
Has only been applied
to Claus process tail
gases
No effect
Cannot attain as low
of residual sulfur in
tail gas as Beavon
process
Uemental sulfur
Has only been applied
to Claus process tail
gases
No effect
Cannot attain as low
of residual sulfur in
tail gas as Beavon
process
Elemental liquid
sulfur

No effect
Much higher residuals
in tail gas than Beavon
process
Concentrated H2S
Requires further
treatment/or recycle
to Claus. Acceptable
level of sulfur in
tail gas may be
unobtainable
Reduces conversion ef-
ficiency by catalyst;
high CO2 levels reduce
efficiency of alkano-
mine system
Offgas from amine scrub-
ber is not as low in
total sulfur as Beavon
process offgas
None
Does not remove sul-
fur; only converts to
another form (SO2).
Catalytic incinera-
tion may not be able
to handle HC & sulfur
content gas streams
None
May be used as less
stringent control for
streams with small
amounts of sulfur com-
pounds. On-site boiler
incineration can simul-
taneously remove SO2 in
FGD
Sulfur or sul-
furic acid from
Wellman-Lord
process
Solid wastes may be
generated by other
FGD processes which
require disposal
None
On-site boiler/FGD sys-
tem is the most likely
candidate. Installing
a separate incinerator
& FGD would not be as
economically feasible.
59

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TABLE 5-4. KEY FEATURES OF S02 REMOVAL PROCESSES
Um/UmiUm
ll«ry tcrabblag
OmI Alboll tcr*bla«
Chljodo Tfcora^ttrod 121
Uollma-tor*
Dry 8en*kli| (liny Orylai)
UviM pk*H idnift!
of SO] Is • ItM or
Ilaoatoaa flurj-
Uqold pbiM «kMi>llea of
10] It «b iIUIIn nltr>
ilti «(	bydroiido,
•¦lilts, awlfoio, oad eir
boo«t«> A 4tUli »4i
piectii lo proforrod for
SO] cMcwiritUM of ISO
(• IJ00 fpm oad «
CBMMtntW ooda la ooad
for SO} COKIfllNlItU of
IMO to 1000 fpm o*4 *ara
Uii ]i
llaaotoao oddltlea/
4U«UtloB aod
r>«lrlU(lp« ia I
•laglo «mn1.
la «• albaLUa
aalatlao of ioIIm
NlUu fallowi by
tboraol rqtauiliM
af tho Awrttai
•Ilk IlktfillM af
caacaattatod (Oj.
Cootoctiaf af llao olwrry wltb
floa pi la a roaetor,
fallaaad by collactloa of
fUllcilitM oa fabric flltor
or la ur
ftW !((««
b^ilrMUi
fWtlC«l»l«l BHl I
r«***4 ta a K«"
Bala Of 80)/0] Ml b«
rilitinlf bl|h for
cMcMtratW eftitilta «
rarticolatao id
cblotldoo Ml b«
r«v«W froa ItUt ll«
(•a If b?f rodact in«a
!• U bo aold.
Partlcalotaa awl ba
(w
Nt 10] ar laao tbaa
li acbiavabb
frodueoa potoatlally
oalooblo gyya*
by-product.
Caa raaaoa ia aicaoa
of 90S af SO],
loaoaotratod la
•IP9C0 tooto.
Cosarclally
loHaiKiial, leaor
pttailol for
faallat/ocollat (boa
calelwbaaad
flMOIM.
baaoval of ay to 901 SO] for
lav aolfar coala.
Raiatlaa to xt acrobklcat,
loaar capital lovoataoat)
alaflor procaoa (tterafora
bl$bor i;otn rollablltyi dry
¦alii low aaargy
raqairaaoatai lowor imm!
coata for lov aolfar coala.
Oloadvaatogoo
Oa-Uaa rallablllty aay
ba laa  to •»)
prodaraa ifftoilaoiolf 2
tlaoo (by Ml|kt) «o
¦Kb «Ua Ualni aa
collactad ask. far tow
•olfoa coala, 10]
(oviii affUlaacy «aai4
ba laoar.
hoteoo ayproilaataly I.)
tlaaa (by wl(bt) aa audi
calclaa oolflto/aolfoto
MOII lldl* oo colloctol
oab.
fiocoaa Imalraial
ooly aa a protatyya
ocolo*
USb otlllty
rafiliiaimi
•facial aatallariyi
ra^alraa oayorota
ayatoa to yracooo
eaaeoatratoi SO]
to aalfor ar aal-
laric acid. Il|b
cayltal lad
ipiratl^ coata*
bltlln ta «( MNbklti,
blgbor odoerWat coot: oat
caaaorclally daaoaatratad (ar
otlllty-typo bailor
ayyllcitUao
60

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OPTION I FOR CONTROL OF ACID GASES
CO} RICH •
ACID GAS
HYDROGEN
PURIFICATION
SYNGAS
PURIFICATION
LOW PRESSURE
AND
RECYCLE GAS
TREATING
SELECTIVE
SELEXOL
NON SELECTIVE
SELEXOL
SOUR
WATER
SOUR WATER
STRIPPING/
AMMONIA
RECOVERY
~(D—•
-
-------
The estimated residual emissions and costs for various alternatives for
reduced sulfur control of acid gases are shown in Table 5-5. The Option I
control using Beavon technology can achieve levels of less than 100 ppmv total
reduced sulfur and 2.5 ng sulfur per J coal (HHV) to the liquefaction unit.
Total annualized costs for Option I control range from 1.5 to 4.4% of total
uncontrolled plant costs, depending on whether the Beavon tail gas is incin-
erated and credit is taken for waste heat recovery. Tail gas from the Beavon
unit normally does not require incineration and can be vented directly to the
atmosphere. However, if the presence of toxic organics in the acid gases
(only one-third of which is combusted in the Claus unit) becomes a primary
concern, incineration of the Beavon tail gas will have to be considered.
Option II control alternatives are represented by Claus sulfur recovery
plus SCOT or Wellman-Lord tail gas treatment. Mass sulfur emissions are
23 to 51% higher in the Option II cases than in the Option I case, depending
on the coal feedstock and the specific controls employed. Total annualized
costs range from 3.1 to 4.5% of uncontrolled plant costs.
Table 5-6 summarizes the energy impacts of different control options for
acid gases. The data indicate that for the very worst case, approximately
1.6% of the plant input energy could be required for control of acid gases,
although more reasonable alternatives have energy penalties of 0.5% (with
credit for waste heat recovered after incineration). The Claus/Beavon option
shows an energy credit of 0.2-0.3% when the Beavon offgas is vented directly
to the atmosphere. Based on the energy requirements estimated, the energy
costs for Option I control are approximately the same as the energy costs for
Option II.
NUMERICAL GUIDANCE FOR ACID GASES - OPTION I CONTROL
Since the philosophy of the guidance is to provide targets for emission
control levels rather than to specify the technologies to be used, numerical
forms of guidance options were developed based upon the capabilities of the
control alternatives in Table 5-5. The following concentration levels have
been assumed for the subject controls (based upon both vendor quotes and test
data):
62

-------
TABLE 5-5. COSTS AND RESIDUAL SULFUR EMISSIONS ASSOCIATED WITH ALTERNATIVE
SYSTEMS FOR CONTROL OF ACID GASES IN SRC-II COMMERCIAL PLANT
Powhatan No 5 Coal Case
Blacksville Coal Case
Control
Options
Horst Case*
Best Case*
Capital Annualized Capital Annualized Total
Cost* Cdst+	Cost+ Cost+ Sulf'ir
Cone
Sulfur Emissions
Worst Case*
Best Case*
Sulfur Emissions
tt
Total
Sulfur
Total
Sulfur
Capital Annualized Capital Annualized Total Total
Cost1"
CostT
Cost+
CostT
,, Emissions Emissions
ppmv* kg/hr** ng/J**
Tota 1
Sulfur Sulfur Sulfur
Cone, ["missions Emissions
ppmv* kg/hr** ng/J**
Option I Alternatives
Claus/Beavon	2 5 2 0
Clai.s/Beavon/
Incineration	2 6 4 4
2 5
2 7
2 0
3 7
100 91 8
ioo 9i a
2 44
2 44
1 9
2 0
1 5
3 7
1 9
2 1
1 5
3 1
100
100 88 5
2 38
2 38
o»
CJ
Option 11 A1ternatives
Claus/SCOT	2 7 4 5	2 8 3 8	250 121 0 3 22 2 1 3 7	2 2 3 1 250 HO 3 2 97
Claus/Wel 1man-Lord	4 a	4 5	4 4	4 5	150 139 1	3 70	3 4	3 8	3 4	3 8	150 133 5	3 5C
* Worst case represents no credit received during the incineration of Claus/Beavon or Claus/SCOT offgascs Best case includes credit b?sed on waste heal
recovery
As % of base plant cost
^ Sulfur concentration is for treated stream Sulfur concentration in C0? rich acid gas from Selective Selexol AGR unit is 100 ppmv
**
Mass emissions include those associated with the CO^ rich acid gas that is vented to the atmosphere
i~t Sulfur emissions from ClausyBeavon are in the form of 90 ppmv COS and CS? and 10 ppmv H-S Sulfur emissions from other control options are in the form
of SO^

-------
TABLE 5-6 ENERGY REQUIREMENTS FOR CONTROL OF
ACID GASES IN SRC-11 COMMERCIAL PLANT
Powhatan No. 5 Coal
Energy Requirements
% of Total Plant Input
Worst Case* Best Case*
Blacksville Coal
Energy Requirements
% of Total Plant Input
Worst Case* Best Case*
Option I Alternatives
Claus/Beavon	(0.25)1" (0.25)1
Claus/Beavon/
Incineration	1.40	0.51
(0.15)1" (0.15)+
1.33
0.54
Option II Alternatives
Claus/SCOT	1.61
Claus/Wellman-Lord	0.84
0.72
0.84
1.47
0.86
0.67
0.86
*	Worst case assumes no energy recovery during incineration of Claus/Beavon
or Claus/SCOT offgases. Best case includes credit based on waste heat
recovery.
*	Parenthesis indicate energy credit
64

-------
•	Stretford <10 ppmv H2S	*
•	Beavon <100 ppmv total reduced sulfur in Beavon offgas
•	SCOT <250 ppmv total sulfur in SCOT off gas prior to incineration*
•	Weilman-Lord <150 ppmv SO2 in Wellman-Lord offgas
•	Selective Selexol <100 ppmv total reduced sulfur in ^-rich
vent gas
Based upon the data presented in Table 5-5, the Claus/Beavon option
can achieve emission levels of less than 2.5 ng of total sulfur per J of coal
input to the liquefaction unit. The exact emission levels are sensitive to
the ^S and COS concentrations in the ^-rich selective Selexol vent gas. The
100 ppmv total reduced sulfur in the C02~rich vent gas is a conservative estimate
based on information currently available on the t^S and COS content of the shift
gas treated in the selective Selexol unit, and data on the distribution of the
h^S and COS components in the F^S-rich acid gas, ^-rich acid gas, and product
gas from the selective Selexol process. Also, mass emissions of sulfur would
be relatively independent of coal sulfur content and depend more on the
reactivity of the coal processed. A highly reactive coal would result in
greater distillate yield and lower organic vacuum bottom yields. Thus, the
coal reactivity would affect the volume of acid gas requiring control, and
the amount of inerts (e.g., carbon dioxide) as well as combustibles (e.g.,
carbon monoxide and hydrocarbons) present in the acid gas. These in turn would
have an impact on the volume of ^-rich vent gas, the amount of combustion air
fed to the Claus furnace and hence the volume of Claus tail gas generated. The
final mass emissions of sulfur from the selective Selexol process and the Beavon
process are proportional to the volume of the COg-rich vent gas and the volume
of the Claus tail gas treated, respectively. The Powhatan No. 5 coal considered
is high in sulfur content, but also highly reactive (greater distillate yield
and lower organic vacuum bottom yields). Conceivably, a less reactive coal
with the same sulfur content would result in slightly higher sulfur emissions.
However, the SRC-II process is designed to produce liquid fuels and less re-
active coals would not normally be considered as suitable feedstocks. There-
fore, two targets for numerical guidance are given. The mass emisision target
is 2.5 ng of total sulfur per J of coal feed to the liquefaction unit. This
target is the numerical guidance for total sulfur compounds (as S) contained
in all treated acid gas streams and the direct venting of C02-rich acid gas
*The Beavon and SCOT offgases are approximately equal in magnitude to the
undiluted Claus offgases.	„

-------
from the selective AGR process. Also, since the Beavon technology can achieve
emission levels of less than 100 ppmv of total reduced sulfur (undiluted Claus
tail gas basis), this concentration target is also part of the Option I guidance.
NUMERICAL GUIDANCE FOR ACID GASES-OPTION II CONTROLS
For Option II control of acid gases, the Claus/Wellman-Lord combination
was selected as the basis for the development of numerical guidance. Effluent
levels less than 150 ppmv SO2 in the stack gas have been consistently achieved
in commercial Wellman-Lord installations. In terms of mass emissions, the
Claus/Wellman-Lord option can achieve emission levels of less than 3.7 ng of
total sulfur per J of coal input to the liquefaction unit. As shown in Table
5-5, the Claus/SCOT option can achieve slightly lower emission levels of total
sulfur. Again, the exact emission levels are sensitive to the f^S and COS
concentrations in the COg-rich selective Selexol vent gas.
As in the case of Option I control, two targets for numerical guidance
are given for Option II control. The mass emission target is 3.7 ng of total
sulfur per J of coal feed to the liquefaction unit. This target is the numer-
ical guidance for total sulfur compounds (as S) contained in all treated acid
gas streams and the direct venting of the COg-rich acid gas from the selective
AGR process. The concentration target is 150 ppmv of SO2 at zero percent oxygen
if emissions are controlled by an oxidation control system (e.g., Wellman-Lord),
or a reduction control system followed by incineration (e.g., SCOT).
The preferred option to control acid gases is Option I control. This
preference is based upon the recognition that: 1) the individual control
components have been demonstrated in other applications and are expected to
perform with reasonable reliability in direct liquefaction plants; 2) signifi-
cantly greater emission control is achieved compared to Option II control; 3)
incremental control costs and energy requirements for Option I control, even
when incineration of the offgas is included, do not appear to be unreasonable.
66

-------
Sour Fuel Gases
Treatment of sour fuel gases that are subsequently used as plant fuel
is considered pollution control, whereas treatment of sour fuel gases for sale
is considered a process function. In Figure 5-2, the alternatives for treat-
ment of SRC-II sour fuel gases are depicted. For low pressure sour fuel gases,
Option I control involves removal of sulfur compounds by DEA scrubbing with
high circulation rates (0.45 gal. DEA solution per SCF of acid gas removed)
and high steam rates for regeneration (1.5 lb steam per gal. of DEA solution).
Beacuse of the low residual levels of sulfur compounds in the lean DEA solution,
sulfur levels of less than 10 ppmv are obtained in the treated fuel gas. This
same level of total sulfur in the treated fuel gas can also be attained by
employing the Stretford process, followed by the Beavon process for removal of
residual sulfur after catalytic conversion of any COS, CS2, or mercaptans
present. For the excess syngas which is available at high pressure, Option I
control with the non-selective Selexol process can result in a treated fuel
gas containing less than 1 ppmv total reduced sulfur compounds. The Selexol
process, utilizing the dimethyl ether of polyethylene glycol for physical
adsorption, is more economical than amine or hot carbonate processes for the
treatment of sour fuel gases at high pressure, while at the same time achieving
a higher degree of sulfur removal.
The estimated sulfur emissions from the combustion of treated fuel gases
and the cost and energy requirements associated with the various alternatives
for treatment of sour fuel gases are presented in Table 5-7. Total sulfur
emissions with Option I control amount to less than 0.1 ng sulfur per J coal
(HHV) to the liquefaction unit. This is only 4% of the total sulfur emissions
from Option I control for acid gases. Annualized cost for sour fuel gas treat-
ment with Option I control is 1.9X of total uncontrolled plant cost.
For treatment of low pressure sour fuel gases, Option II control also
involves removal of sulfur compounds by DEA scrubbing, but with lower and
more typical DEA circulation rates and steam rates for regeneration. Sulfur
levels of approximately 100 ppmv are obtained in the treated fuel gas. This
sulfur limit in the treated fuel gas can also be attained by using the Stret-
ford process, as long as the total concentration of COS, CS2> and mercaptans
in the sour fuel gas is less than 90 ppmv. For the excess syngas available
57

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OPTION I FOR TREATMENT OF SOUR FUEL GASES
RECYCLE GAS
LOW PRESSURE
FLASH GASES,
FRACTIONATOR
OFF GASES, AND
SLURRY MIX
TANK VAPOR
EXCESS
SYNGAS
AT HIGH
PRESSURE
NON-SELECTIVE
ACID GAS TO SULFUR
RECOVERY PLANT
TREATED
FUEL GAS
ACID GAS TO SULFUR
RECOVERY PLANT
TREATED
+¦ SYNGAS FOR
PLANT FUEL
OPTION II FOR TREATMENT OF SOUR FUEL GASES
ACID GAS TO SULFUR
RECOVERY PLANT
RECYCLE GAS
TREATED
FUEL GAS
LOW PRESSURE
FLASH GASES,
FRACTIONATOR
OFFGASES, AND
SLURRY MIX
TANK VAPOR
ACID GAS TO SULFUR
RECOVERY PLANT
EXCESS
SYNGAS
AT HIGH
PRESSURE
TREATED
SYNGAS FOR
PLANT FUEL
DEA
NON-SELECTIVE
SELEXOL
* DEA PROCESS WITH HIGH DEA CIRCULATION RATES AND HIGH STEAM RATES FOR
REGENERATION, DESIGNED TO YIELD A TREATED FUEL GAS WITH LESS THAN
10PPM H2S
Figure 5-2. Options for Treatment of SRC-II Sour Fuel Gases
68

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TABLE 5-7 COSTS, ENERGY REQUIREMENTS, AND RESIDUAL SULFUR
EMISSIONS ASSOCIATED WITH ALTERNATIVE SYSTEMS FOR
TREATMENT OF SOUR FUEL GAS IN SRC-II COMMERCIAL PLANT
Sulfur Emissions
Control
Options
Capital
Cost*
Annualized Energy Total Sulfur Total Sulfur Total Sulfur
Cost* Requirements* Concentration Emissions, Emissions,
ppmv'
kg/hr t
ng/jf
Option I
DEA for Low Pressure
Sour Fuel Gases	0.75
Non-Selective Selexol
for High Pressure Syngas 0.53
Total for Option I	1.28
1.34
0.51
1.85
0.90
0.11
1.01
10
10
10
1.13
2.38
3.51
0.030
0.063
0.093
Option II
DEA for Low Pressure
Sour Fuel Gases	0.54
Non-Selective Selexol
for High Pressure Syngas 0.53
Total for Option II	1.07
0.94
0.51
1.45
0.57
0.11
0.68
100
10
<100
11.30
2.38
13.7
0.30
0.06
0.36
*As % of base plant cost or energy input
+Sulfur concentration in the treated fuel gas stream
^Sulfur emissions from the combustion of treated fuel gas
**DEA process with high DEA circulation rates (0.45 gal DEA solution/SCF acid gas removed) and high
steam rates (1.5 lb/gal. DEA solution) for regeneration.

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at high pressure, the most appropriate Option II control will be the same as
Option I control using the non-selective Selexol process. This is because
for treatment of sour fuel gases at high pressure, the Selexol process is
more economical than any other available treatment processes designed for 100
ppmv fuel gas residual sulfur levels. As shown in Table 5-7, total sulfur
emissions with Option II control amount to 0.36 ng sulfur/J coal (HHV) to the
liquefaction unit. Although this is 3.6 times higher than sulfur emissions
from Option I control, the total sulfur emissions with Option II control are
still only a small fraction (14%) of the total sulfur emissions from Option
I control for acid gases. Annualized cost for sour fuel gas treatment with
Option II control is 1.5% of total uncontrolled plant cost.
Numerical Guidance for Sour Fuel Gas Treatment - Option I Control
Based on the data presented in Table 5-7, Option I controls can result
in a treated fuel gas containing less than 10 ppmv total reduced sulfur. The
t
estimated 10 ppmv sulfur for the combined fuel gas is conservative because
the sulfur level in the treated fuel gas from the Selexol process is expected
to be significantly lower at 1 ppmv. Since the Selexol process is employed
to treat the excess syngas, which constitutes approximately 78% by volume of
the total fuel gas, the sulfur level in the remainder 22% of the fuel gas
treated by the DEA process can be as high as 40 ppmv for the combined fuel
gas to have a sulfur level less than 10 ppmv. The 10 ppmv of total reduced
sulfur in the treated combined fuel gas is the numerical guidance for Option
I control. A lower sulfur limit in the treated fuel gas, although technically
feasible, does not lead to significantly lower sulfur emissions. As discussed
previously, total sulfur emissions from the combustion of fuel gases based on
Option I control is less than 0.1 ng sulfur per J of coal feed to the lique-
faction unit.
Numerical Guidance for Sour Fuel Gas Treatment - Option II Control
Option II control to treat low pressure sour fuel gases is represented
by the DEA process with normal ciruclation rates and steam requirements for
regeneration. DEA scrubbing are typically designed to yield a treated fuel
gas containing 100 ppmv of total reduced sulfur. DEA scrubbing can also be
used to treat the high pressure syngas, but the Selexol process is more
70

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economically attractive for this application while at the same time yields a
treated fuel gas with lower sulfur content. For the combined fuel gas, total
reduced sulfur level of less than 100 ppmv can be readily obtained by using
Option II controls.
The concentration target of 160 ppmv of total reduced sulfur in the
treated combined fuel gas is the numerical guidance for Option II control.
This concentration target is based on the NSPS for petroleum refinery Claus
sulfur recovery plants, which state that no owner or operator shall burn in
any fuel gas combustion device any fuel gas which contains hydrogen sulfide
in excess of 160 ppmv (230 mg/dscm) without further treatment to control
sulfur dioxide emissions. This NSPS is considered applicable and used to
provide numerical guidance for direct liquefaction plants because: 1) a
portion of the treated fuel gas in the direct liquefaction plant is used to
control sulfur emissions from the Claus sulfur recovery plant; 2) the limit
of 160 ppmv of total reduced sulfur can be attained by using Option II controls
and 3) the suggested limit is consistent with the NSPS for electric utility
steam generating units, which state that no SO2 reductions are required if
SO2 emissions into the atmosphere from the combustion of gaseous and liquid
fuels not derived from solid fuels are less than 86 ng/J heat input. This
standard is equivalent to allowing a ppmv sulfur level in the fuel gas of 1.18
times the HHV (Btu/SCF) of the fuel gas. For a fuel gas with a HHV of 125
Btu/SCF, therefore, the electric utility NSPS stipulate a fuel sulfur limit
of 148 ppmv if no subsequent S0£ cleanup is intended. For fuel gases with
HHV in excess of 136 Btu/SCF, however, the 160 ppmv sulfur limit is more
stringent than the electric utility NSPS requirement.
Total sulfur emissions from the combustion of fuel gas containing 160
ppmv sulfur in a SRC-II commercail plant would amount to 1.5 ng sulfur per
J of coal feed to the liquefaction unit. This level of sulfur emissions is
60% of the sulfur emissions from Option I control for acid gases.
The perferred option to treat sour fuel gases is Option II control. This
preference is based on the consideration that: 1) the technologies for Option
II control are well established and have been demonstrated in similar applica-
tions; 2) Option II control will yield a treated fuel gas that can be used in
petroleum refinery Claus sulfur recovery plants or electric utility steam

-------
generating plants without additional S0£ central; and 3) the numerical guid-
ance for Option II control to treat sour fuel gases (160 ppmv total sulfur)
is more consistent with the numerical guidance for Option I control of acid
gases (100 ppmv total sulfur).
Boiler Flue Gases
The Option I control for boiler flue gases corresponds to the "sliding"
scale represented by the electric utility NSPS, while Option II control corre-
sponds to the fossil fuel fired steam generator limit fixed at 520 ng SOg per
J heat input.
The Agency's preferred option to control boiler flue gases is that the
electric utility NSPS for SOp apply to boilers used in a direct liquefaction
facility. A limit of 86 ng SOg/J heat input to the boiler (the liquid and
gaseous fuels cutoff point in the electric utilfty NSPS) 1s suggested below
which no additional control is required.
For the proposed SRC-II commercial plant design, steam generation and
in-plant power generation are all provided by the combustion of treated fuel
gas. The SRC-II fuel gas has a heating value of 21 MJ/scm (566 Btu/SCF) and
the Option II control for sour fuel gas treatment will yield a treated fuel
gas containing less than 160 ppmv sulfur. This will result in SO2 emissions
of less than 21 ng/J heat input from the combustion of fuel gas, a level
which is only 24% of that stipulated by the electric utility NSPS. Thus,
the Option II control for sour fuel gas treatment will assure meeting the
requirements of Option I control for boiler flue gases.
Tradeoff Between Control of Acid Gases, Sour Fuel Gases, and Boiler Flue Gases
From the standpoint of total emissions from an integrated facility, a
tradeoff in the degree of control between acid gases and sour fuel gases can
be made. No tradeoff between these gases and boiler flue gases, however,
is considered in the SRC-II commercial plant because sulfur emissions from
boiler flue gases are controlled by sour fuel gas treatment.
Sulfur emissions from the preferred options for acid gas control and sour
fuel gas treatment * amount to 2.5 ng/J and 1.5 ng/J, respectively. Tighter
* More correctly, from combustion of the treated fuel gas.
72

-------
control to treat sour fuel gas can reduce sulfur emissions from the combustion
of fuel gas down to the 0.1 ng/J level. Thus, it is possible to employ Option
II control for acid gases, with estimated sulfur emissions between 3.0 to 3.7
ng/J, while not exceeding the combined mass sulfur emission limit of 4.0 ng/J
if more stringent controls are used for fuel gas treatment.
It is recommended that emissions from acid gas treatment (including
venting of the (^-rich acid gas from the selective AGR unit) and combustion
of the treated fuel gas be calculated as a sum total. The separate emission
limits for these two streams need not be met as long as the combined total
mass emission limit of 4.0 nq S per J of coal feed to the liquefaction unit
is met, and provided that no stream discharged to the atmosphere contains
more than 100 ppmv total reduced sulfur. The latter limit is intended to
ensure that the emissions tradeoff is primarily between sulfur emissions in
the form of SO2• Since Option II control of acid gases involves incineration
and fuel gases are always combusted before discharge to the atmosphere, no
problem is envisioned in achieving the 100 ppmv value.
Transient Waste Gases
Liquefaction waste gas and Texaco waste gas comprise the transient
waste gases from an SRC-II coal liquefaction plant. Although in principle
these streams could be controlled by most of the processes in Table 5-3, the
intermittent nature, and variable flowrates and compositions of these streams
hinder the operability and proper performance of sulfur recovery and associated
tailgas treatment systems. Therefore, controlled incineration with SO2 removal
has been identified for Option I control.
The alternative selected for Option II control involves incineration
without S02 recovery and, in terms of sulfur emissions, provides only for
control of reduced sulfur species. Because liquefaction waste gases may
contain high molecular weight aromatic hydrocarbons, nitrogen containing com-
pounds and polycyclic compounds in addition to reduced sulfur species, the
Option II control alternative for this waste is controlled incineration as
opposed to flaring. However, flaring appears to be an appropriate alternative
for Option II control of Texaco waste gas which is essentially free of high
molecular weight organics.
73

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Uncontrolled SOg emission rates due to incineration of either liquefaction
waste gas or Texaco waste gas have potential to substantially exceed the total
controlled SC^ emission rate for other streams from the plant during transient
periods. Annual uncontrolled SC^ emissions due to incineration of transient
waste gases would have potential for comprising a significant portion of total
annual sulfur emissions from the plant. Therefore, Option I controls, controlled
incineration with SOo removal, is preferred for transient waste gases.
Costs of Option I and Option II sulfur emission control alternatives for
transient waste gases are presented in Table 5-8 as percentages of uncontrolled
liquefaction plant costs. Capital cost and annualized cost due to capital
charges for Option I control of Texaco waste gas are included in the Option I
control costs for liquefaction waste gas since an incineration/FGD system
sized to control liquefaction waste gas is also sufficiently large to control
Texaco waste gas, provided that these streams need not be controlled simulta-
neously. With proper scheduling of operations comprising plant startup and
shutdown, control of these streams need not be concurrent since the transient
period associated with each stream is anticipated to be short in duration (e.g.
less than about 10 hours).
Catalyst Regeneration/Decommissioning Off-Gases
Sulfur present in catalyst regeneration/decommissioning off-gases is
anticipated to be primarily in the form of SO2 with small quantities of
reduced sulfur species (e.g, H^S, metallic sulfides or elemental sulfur); data
regarding the compositions of these streams are not available. Controlled
incineration with SO2 removal has been identified for Option I control. With
regard to total sulfur emissions, no Option II control level would provide
a significant cost savings short of uncontrolled venting. However, since
reduced sulfur species may be present, Option II control involves incineration
to provide control of reduced sulfur species.
These waste gases each have potentially high SO2 concentration. Uncon-
trolled SOj emission rates due to shift and hydrolysis catalyst regeneration/
decommissioning off-gases have potential to substantially exceed the total
controlled SO2 emission rate from other streams in the plant dueing regenera-
tion/decommissioning periods. Without SO2 emission control, these two
74

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TABLE 5-8. COSTS FOR CONTROL OF SULFUR EMISSIONS DUE TO TRANSIENT AND CATALYST
REGENERATION/DECOMMISSIONING WASTE GASES FROM SRC-II COMMERCIAL PLANT
Stream
Alternatives Consistent With Option 1 Sulfur Emissions Control	Alternatives Consistent With Option II Sulfur Emissions Control
Controlled Incineration with FGD	Controlled Incineration 	Flare	
Capital Total	Capital
Annua)lzed
Total
Annualized
Capital
Total
Annual 1 zed
Liquefaction Waste Gas
Texaco Waste Gas
Shift Catalyst
Regenera 11on/Decomm1ssioning
Off-Gases
Hydrolysis Catalyst
Regenera t lon/Oecoraii ss 10m ng
Off-Gases
Claus Catalyst
Regeneration/Deconniss 10m ng
Off-Gases
2 1-3 2
+
t
12-16
0 0087-0 0091
0 021-0 022
(0 0026-0 0027)**
0 0025-0 0028
(0 00029-0 00030)**
0 00083-0 0012
(0 00010-0 00015)**
0 91-1 2 0 55-0 74
0 12	0 071
t	0 017-0 018
t	0 OC10-0 0020
+	o aoo6o-o oooqi
(0 003-0 012)	(o 0057-0 0083)t
All cost data are expressed as percentages of the uncontrolled plant capital or annualized cost
Capital cost and annualized cost due to capital charges are included in the Option 1 control costs for liquefaction uaste gas since an incineration/
FGD system capable of controlling 1lquefaction v*aste gases is sufficiently large to control this stream, provided these two mtermtccent streams need
not be controlled simultaneously The tabulated annualized cost for this stream is the operating cost associated with control of this stream
Capital cost and annualized cost due to capital charges are included in the Option II control costs for Texaco waste gas since a flare Ccoable of
incinerating Texaco waste gas is sufficiently large to control this stream, provided these two intermittent streams need not be controlled
smuttaneoulsy The tabulated annual>zed cost for this stream is the operating cost associated with control of this stream
"** These cost data are for control with FGO without waste gas incineration
-I
These cost data are ror a dedicated flare system designed for control of Claus catalyst regeneration/decommissioning off-gas

-------
streams have potential to comprise a major portion of total annual SO2 emission
from the plant. For these reasons, Option I control, controlled incineration
with SOq removal, may be preferred for shift and hydrolysis catalyst regenera-
tion/decommissioning off-gases. Although SO2 concentrations in Claus regen-
eration/decommissioning off-gas are potentially high, annual SC^ emissions due
to this stream are expected to be low relative to the total annual controlled
SO2 emissions from the plant. Furthermore, existing Claus plants do not
generally employ SO2 emission controls. Therefore, Option II controls,
incineration to provide control of reduced sulfur species, is considered
adequate for control of Claus catalyst regeneration/decommissioning off-gas.
Costs of Option I and Option II sulfur emission control alternatives for
catalyst regeneration/decommissioning off-gases are presented in Table 5-8.
Capital costs and annualized costs due to capital charges for Option I control
of shift and hydrolysis catalyst regeneration/decommissioning off-gases are
included in the Option I control cost for liquefaction waste gas. This is
because an incineration/FGD system sized to control liquefaction waste gas
is also sufficiently large to control these waste gases, provided that these
intermittent streams need not be controlled simultaneously. This incineration/
FGD system would also be sufficiently large to provide Option I control of
Claus catalyst regeneration/decommissioning off-gas. Therefore, Option I
control of waste gas from the Claus catalyst may be more cost effective than
Option II control if the latter requires acquisition of a dedicated flare
system.
Wastewater Incinerator Flue Gas and Activated Carbon Regeneration Off-Gas
Emissions of SO2 due to wastewater incineration and activated carbon
regeneration are anticipated to result primarily from fuel sulfur since most
sulfur in the wastewater is effectively removed by stripping and biological
oxidation. These emissions may be controlled by FGD systems, but this
approach is not economically attractive for such small streams. A requirement
for FGD controls may discourage use of these otherwise desirable wastewater
treatment options. To avoid this problem, the use of low sulfur fuels
consistent with liquid fuel limits for fossil fuel fired stream generators
or the use of treated sour fuel gas is preferred.
76

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5.2.2 Reactive Hydrocarbons* and CO Emission Controls in an Integrated Facility
Gaseous waste streams, which require control for reactive hydrocarbons
are: 1) treated acid gases, 2) transient waste gases, 3) activated carbon and
catalyst regeneration offgases, and 4) evaporative emissions from product/
byproduct storage and fugitive sources. Catalyst regeneration/decommissioning
offgases will not generally require RHC control while evaporative emissions
will not require CO control. Figure 5-3 depicts the control options for streams
which require hydrocarbon/CO control in addition to reduced sulfur control.
Figure 5-4 depicts options for streams requiring control primarily of reactive
hydrocarbons or other organics. Figure 5-5 indicates alternatives for streams
requiring primarily carbon monoxide control. Guidance options for these streams/
pollutants are discussed below.
Process Hydrocarbon and CO Sources
Advantages and disadvantages of various incineration technologies
for controlling reactive hydrocarbons, and carbon monoxide are summarized in
Table 5-9. Generally, more stringent control is achieved with high tempera-
ture thermal incineration either in an incinerator or a fuel fired boiler.
Such systems are reported to be capable of achieving less than 100 ppmv of
hydrocarbons and less than 300 ppmv of CO. These alternatives are particularly
appropriate when subsequent controls are required for sulfur or particulate
removal. Catalytic incineration is applicable to waste streams with low
particulate loadings and low concentrations of catalyst poisons such as sulfur
and heavy metals. However, while the low reaction temperatures associated with
long catalyst life are suitable for conversion of common pollutants including
CO, parafinic organics and high molecular weight organics may require reaction
temperatures which are inconsistent with acceptable catalyst lifetimes. Flares
provide a lesser degree of control than thermal or catalytic incineration
although performance data are generally 1acl^ng.
The need for RHC and CO control in Beavon and SCOT tail gas streams
is not well defined at present. Beavon tailgas is generally expected to contain
only low concentrations of reactive hydrocarbons and CO. Under these conditions,
Beavon tailgas may be vented directly to the atmosphere. However, if
the presence of toxic organics in the acid gases becomes a major concern,
*Reactive hydrocarbons exclude methane, ethane, and propane for purposes of
this PCGD.
77

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BEAVON TAILGAS
OPTION I
CONTROL
—~DILUTE WASTE GAS
OPTION II
CONTROL
THERMAL
INCINERATION
DISCHARGE
WITH DISPENSION
OPTION I
CONTROL
SCOT TAILGAS

OPTION II
CONTROL
THERMAL
INCINERATION
•FLUE GAS
FLARE
•FLARED GAS
GASIFIER TRANSIENT
WASTE GASES
OPTION I
CONTROL
-~ FLUE GAS
SHIFT/HYDROLYSIS	
CATALYST REGENERATION
WASTE GASES
04
FLARED GAS
OPTION II
CONTROL
CLAUS CATALYST
REGENERATION
FLARE
THERMAL INCINERA-
TION WITH FGD
WASTE GAS
OPTION I
CONTROL
—~ FLUE GAS
LIQUEFACTION
WASTE GAS
OPTION II
CONTROL
THERMAL INCINERA-
TION WITH FGD
THERMAL
INCINERATION
Figure 5-3. Alternatives for streams from a SRC-11 Commercial Plant which require
Hydrocarbon and/or Carbon Monoxide Control in addition to reduced Sulfur
control.
78

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OPTION I
CONTROL
C02-RICH ACID GAS
FROM SELECTIVE
SELEXOL

THERMAL
INCINERATION
•FLUE GAS



DISCHARGE
WITH
DISPERSION
OPTION II
mMToni
~ DILUTE WASTE GAS
OPTION I
CONTROL
THERMAL OR CATALYTIC
INCINERATION
•FLUE GAS
ACTIVATED CARBON
X>
REGENERATION OFF-GAS




FLARE
OPTION II
•FLARED GAS
OPTION I
CONTROL
—~VAPORS
PRODUCT AND
BY PRODUCT
STORAGE
VAPORS
OPTION II
CONTROL
FLOATING ROOF TANKS
WITH DOUBLE SEALS OR
FIXED ROOF TANKS WITH
INTERNAL FLOATERS
FLOATING ROOF TANKS
FOR HIGH VAPOR
PRESSURE LIQUIDS
FUGITIVE
ORGANIC
EMISSIONS
OPTION I
CONTROL
—~ VAPORS
*o
—~VAPORS
OPTION II
CONTROL
EQUIPMENT DESIGN,
LEAK DETECTION,
MAINTENANCE AND
REPAIR PRACTICES
LEAK DETECTION,
MAINTENANCE AND
REPAIR PRACTICES
Figure 5-4. Alternatives for streams from a SRC-11 Commercial Plant which require control
primarily of Reactive Hydrocarbons/Organic Compounds.
79

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SRC-II
OPTION I
CONTROL
FLUE GAS
METHANATION CATALYST
REGENERATION/	-
DECOMMISSIONING
OFF GAS
FLARED GAS
OPTION II
CONTROL
THERMAL
INCINERATION
FLARE
Figure 5-5. Alternatives for streams from a SRC-II Commercial Plant which require primarily
Carbon Monoxide control.

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TABLE 5-9. COMPARISON OF HYDROCARBON CONTROL PROCESSES
Process
Advantage
Di sadvantage
Thermal Incineration
via Separate Incinerator
Thermal Incineration
in On-Site Steam and/or
Power Boiler
Catalytic Incineration
Flaring
Can handle all gas streams.
Relaible and simple operation.
Can be used for hydrocarbon and CO
control, and oxidation of sulfur
compounds simultaneously.
Sulfur and particulates are removed
in the associated electrostatic pre-
cipitator and Flue Gas Desulfurization
(FGD) units. The fuel required for
stream incineration is less than that
of a separate incinerator.
Requires 40-50% less fuel than
thermal incineration, although
heat recovery may not be as
high.
Simple to operate, least expensive
alternative, especially for tran-
sient and small volume waste gases.
High auxiliary fuel costs for streams
with low heating value.
High volume intermittent waste
streams may result in operational
problems.
Cannot handle large quantities of
particulates; they will gradually coat
the catalyst and reduce its efficiency.
The catalyst can be easily poisoned by
sulfur compounds. High levels of
hydrocarbons which raise catalyst to
excessive temperatures tend to shorten
the useful life of the catalyst.
Destruction efficiencies much lower
than for thermal or catalytic
incineration. Performance data are
generally lacking.

-------
incineration should be considered. Guidance would be the same for SCOT tail-
gas with respect to RHC and CO control, although high concentrations of reduced
sulfur preclude direct venting to the atmosphere. Therefore, a minimum of
flaring is required for SCOT tailgas. Residual sulfur controls for these
streams, discussed previously, will provide concurrent RHC and CO control.
Costs associated with RHC and CO control for these streams are included in
residual sulfur control costs for these streams.
Transient waste gases and regeneration/decommissioning offgases from
shift, hydrolysis, methanation and Claus catalysts are not well characterized
in terms of RHC and CO concentrations. Gasification waste gas and regeneration/
decommissioning offgases from shift, hydrolysis and Claus catalysts may contain
light hydrocarbons and/or CO, in addition to reduced sulfur compounds and
particulates. As discussed previously, these streams require control for
total and reduced sulfur, and these controls will provide concurrent control
of RHC and CO emissions. Therefore, RHC and CO control costs for these
streams are included in the cost of sulfur controls. The principal pollutants
expected in methanation catalyst decommissioning offgas are CO and particulate
with potential for small quantities of Ni(C0)4; control of CO will also provide
control of Ni(CO)^. Option II control, flaring, is considered adequate for
control of CO emissions from methanation catalyst decommissioning offgases
since emissions from this stream under Option II control would be small
relative to other CO emission sources in the plant. Costs associated with
CO control for methanation decommissioning offgas are presented in Table 5-10.
Liquefaction waste gas may contain high molecular weight aromatic hydro-
carbons and polycyclic compounds in addition to light hydrocarbons and CO.
Because of the toxic or carcinogenic characteristics of high molecular weight
organich which may be associated with this stream, conventional flares are
not considered to provide adequate RHC control for this application. There-
fore controlled incineration is the preferred alternative for destroying RHC
and CO in liquefaction waste gas. Control of RHC and CO in this waste is
provided concurrently with reduced sulfur controls. RHC and CO control costs
for liquefaction waste gas are included in the cost of sulfur control.
COg-rich acid gas from selective Selexol will have very low concentrations
of RHC and CO. RHC concentrations will be very low because Texaco gasification

-------
does not produce significant quantities of RHC. Concentrations, of CO will be
low because the partial pressure of CO is low in the hydrogen production shift
gas and because of the low solubility of CO in Selexol solution. Therefore,
C02~rich acid gas may be vented directly to the atmosphere. However, if the
presence of toxic orqanics in the shift gas becomes a major concern, inciner-
ation should be considered. Costs for control of ^-rich acid gas are
presented in Table 5-10.
Activated carbon employed in wastewater treatment yields an off-gas as
a result of periodic regeneration. This regeneration off-gas may contain
volatile and/or particulate organics which can be destroyed by thermal or
catalytic incineration or in a flare. Due to the potentially refractory
nature of organics adsorbed on activated carbon, thermal or catalytic inciner-
ation of activated carbon regeneration off-gas, Option I control, may be the
preferred option for control of RHC and CO. Control costs are included in
the cost of wastewater treatment.
Fugitive and Evaporative Hydrocarbon Emissions
The current regulatory approach for volatile organic compounds (VOC)
control requires that liquid storage tanks with capacities greater than
150,000 liters and storing volatile liquids with true vapor pressure greater
than 10.5 kPa be controlled by a floating roof (external or internal) or
equivalent. Fixed roof tanks are normally used for liquid storage if the
product is a low vapor pressure liquid or if the required tank capacity is
nominally less than 150,000 liters.
Option I requires secondary seals on floating roof tanks and internal
floaters or vapor recovery systems on fixed roof tanks. Since it is established
practice to sotre the more volatile products in floating roof tanks no Option
II was considered. Option I control is desirable for all direct liquefaction
products and by-products due to the presence of dissolved toxic gases (HCN,
CHgSH, H£S) and aromatic compounds in the vapors from these products.
Control of fugitive hydrocarbon emissions from pump compressors, valves,
pipe flanges, and pressure relief devices is accomplished by a combination of
equipment design practices and inspection/monitoring/maintenance procedures.
The more stringent Option I level of control relies on equipment specifications
83

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TABLE 5-10 COSTS FOR CONTROL OF REACTIVE HYCROCARBON AND CARBON MONOXIDE EMISSIONS
DUE TO METHANATION CATALYST DECOMMISSIONING OFF-GAS AND COo-RICH
SELECTIVE SELEXOL OFF-GAS FROM AN SRC-II COMMERCIAL PLANT*

Stream
Alternatives
Option I RHC
Consistent With
and CO Control
Alternatives Consistent With
Option II RHC and CO Control
Controlled
Incineration
Flaring
Direct

Capital
Total
Annualized
Capital Total
Annualized
Venting Into
Atmosphere
Methanation Catalyst
Decommissioning Off-gas
+
0.00010
{ 0.00008

COg-Rich Acid Gas
From Selective Selexol
~
All cost data are expressed as precentages of the uncontrolled plant capital or annual cost.
+ Capital cost and annualized cost due to capital charges are included in the Option I control
cost for liquefaction waste gas since an incineration system capable of controlling liquefaction
waste gas is sufficiently large to control this stream, provided these intermittent streams need
not be controlled simultaneously. The tabulated annualized cost for this stream is the operating
cost associated with control of this stream.
* Capital cost and annualized cost due to capital charges are included in the Option II control costs
for Claus catalyst regeneration/decommissioning off-gas since a flare capable of incinerating
gasification waste gas is sufficiently large to control this stream, provided that these streams
need not be controlled simultaneously. The tabulated annualized cost for this stream is the
operating cost associated with control of this stream.

-------
instead of more frequent equipment inspections. Table 5-11 presents some of
these equipment pracitces. Option II essentially consists of leak detection
and repair methods. Under this level of control leak detection is accomplished
by checking equipment components for emissions of VOC. A measured VOC concen-
tration less than the detection level does not require any equipment repair.
The major expense for Option I in a new plant can be offset by installing
desired requipment. Consequently, Option I may be preferred over Option II
in new plants.
5.2.3 Particulate Emissions Control
Emissions streams which contain particulates in sufficient quantities to
require control prior to atmospheric discharge are:
1)	dust from coal storage, coal handling, coal crushing/sizing, and
coal drying.
2)	steam/power generation flue gas
3)	gasifier transient waste gases
4)	catalyst regeneration/decommissioning offgases and
5)	wastewater incinerator flue gases
Table 5-12 summarizes the operational characteristics of particulate
control technologies which are potentially applicable to these sources.
Dust from Coal Storage, Handling and Preparation
Two control techniques are generally used to control particulate emissions
from active storage piles. Enclosure of active storage pile in a totally
enclosed barn or silo with point source dust control equipment on building
vents can produce up to 99 percent reduction in particulate emissions. The
other alternative of wet or chemical suppression can produce up to 50 percent
reduction in emissions, however,frequent addition to and withdrawal from the
storage pile renders this method ineffective. Alternatively, wet and chemical
suppression techniques are quite effective in controlling emissions from
reserve storage piles. Other techniques that are employed to control emissions
from reserve storage piles are stabilization with vegative cover, capping,
and coating surfaces of compacted storage piles with layers of select, medium-
sized higher grade coal.
85

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TABLE 5-11 EQUIPMENT DESIGN/MODIFICATIONS FOR FUGITIVE HYDROCARBON EMISSIONS CONTROL
Pumps
Compressors
Pressure Relief
Devices
Open-Ended Valves
In-Line Valves
improve seal at the junction of moving shaft and stationary casing
use seal ess 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 disk upstream from the safety/relief valve
use resilient seal or "0-ring" relief valves
use closed vent systems to transport valve discharge to control devices
install a cap, plug, flange, or a second valve to open end of the valve
use diaphram and bellows seal type valves

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TABLE 5-12. KEY FEATURES OF PARTICULATE CONTROL TECHNOLOGIES
Control Device
Operating Principle
Removal
Efficiency Range
(weight %)
Inlet Loading
Limitation
(g/Nm3)
Normal
Pressure
Drop Range
(cm H^)
Rel labi 1 i ty
or Other Limitations
General Comments
High Efficiency
Cyclone
Particulates removed from gas
stream by imparting a centrifu-
gal force The inertia of the
particulates carries them to
the walls where they fall to
the bottom of the cyclone for
50 to 80% for --5 urn,
80 to 95% for 5 to
20 pm.
>2 4
7 to 20
Cannot effectively remove
particulates smaller than
5 iim
High reliability due to
simple opeiotinq pi in-
ciple with no moving
parts Low energy
requirements
removal
co
fabric Filter	Fabric f 11 te- material is
(Baghouse)	arranged in a tubular shape
with the particulate laden gas
stream passing through the
filter Particulate removal
primarily results from the
buildup of collected material
on the dirty-air side of the
filter. The filter is periodi-
cally cleaned by mechanical
shaking or a pressurized
reverse air flow.
98	5 to 99 5X for
0 25 to 0 5 ill,
99	to 99 5% for
0 75 to 1 nil,
99 5 to 99 9% for
3 um.
99 95i for ^3 ui>.
>0 24	5 to 25	Plugging problems will
result if condensation
occurs on filter media or
if hygroscopic material is
collected Temperature
limit varies with type of
filter media used, maximum
is 290°C
High paiticulaie
removal efficiency
High installation cost
Large space requited
Venturi Scrubber
Removal of particulates from
a gas stream by intimate con-
tact with multiple jet streams
of scrubbing water and droplets
Agglomerated particulates are
subsequently removed in a cen-
trifugal and/or mist eliminator
50 to 92 51 for
0 25 pm,
50 to 98% for
0 5 ym,
70 to 99% for
0 75 ym,
90 to 99 6% for
> 3 um
>0 5	13 to 250 Reliability may be limited
by scaling, fouling or
corrosion Scrubbing
liquor blowdown may require
treatment or contain poten-
tially valuable material
not directly recoverable
High particulate removal
efficiency Capable of
treating streams with
wide ranges in tempera-
ture (no limitation for
high temperatures),
pressure and gas com-
position High effici-
encies require high
energy consumption

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TABLE 5-12. (continued)
Hormal
Removal	Inlet Loading Pressure	Reliability
Control Device	Operating Principle	Efficiency Range Limitation Drop Range or Other Limitations	General Comments
(weight %)	(g/Nm'')	(cm H.,0)
Electrostatic A negative electrical charge is
Precipitator	imparted to the particulates
and they are collected on posi-
tively charged plates. Col-
lected material is removed by
periodically rapping or vibra-
ting the collection plates
95 to 99* for
0 1 iiin,
90 to 96% for
0	5 um,
95 to 99* for
1	um,
99 to 99 9% for
5 um
0 24	0 5 to 2 5 Not applicable to combus-
tible or potentially
explosive mixtures Par-
ticulates to be collected
must have suitable elec-
trical resistivity to fac-
ilitate efficient removal
Used in low pressure appli-
cations Limited to gas
streams with temperatures
below 430°C
High particulate removal
efficiency, especially
the sub-micron range
High capital and in-
stallation cost Very
low pressure drop
Suitable for high tem-
perature or large vol-
ume applications High
electrical consumption
Sensitive to particu-
late resistivity
Dust Suppression
System
CO
00
Fugitive dust generated by
material transfer and hand-
ling or coal storage is con-
trolled by spraying water
containing a wetting agent
High pressure nozzles are
used for material handling
applications.
Hater only 80% for
5 um,
431 for 3 urn,
25% for 1 um,
Water & Steam 43%
for 3 um,
40% for 1 um,
Mater with wetting
agent 95% of overal1
mass .
NSL
NA
Nozzle may become clogged
if flow rate is excessive
Heat tracing may be re-
quired to prevent freeze
up Low efficiency for
small particles
System is simple and
generally requires min-
imal maintenance A
waste stream is not
generated Low cost
system
Thermal t	Gases are introduced into a
Incineration	refractory lined combustion
chamber employing direct-fired
burners to convert contaminants
into less noxious compounds,
primarily CO^ and ^0
Unknown
NSL
5 without
heat
exchange,
20 with
heat
exchange
Applicable to polycyclic
organic matter (POM) and
tarry substances Will
not control noncombustible
particulate emissions
Longer combustion cham-
ber residence time will
increase destruction
efficiency Heat ex-
changers can be used
downstream of the
incinerator to recover
heat from exhaust gases
thereby reducing fuel
requirements

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5-12. Continued
Control Device	Operating Principle
Normal
Removal	Inlet Loading Pressure
Efficiency Range Limitation Drop Range
(weight*)	(g/Nm3)	(cm H^O)
Rellabi11ty
or Other Limitations	General Conments
Elevated Flare Open combustion of waste gases
at the top of a stack equipped
with a burner Contaminants
are converted into less noxious
compounds, primarily C09 and
Ho0
00
v©
Unknown
Normally used to con-
trol intermittent or
emergency emission of
NSL	Less than Less efficient destruction
150	efficiency than thermal
incineration Applicable
to polycyclic organic matter waste gas streams
(POM) and tarry substances Capable of turndown
Will not control noncom-
bustible particulate
emissions
ratios up to 1000 1
NSL - No Specific Limitations
NA - Not Applicable
*
Catalytic incineration is not applicable for particulate control because catalyst bed plugging and/or fouling will result

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In the preparation operation, particulate control equipment can serve a
dual purpose: 1) increase the efficiency of the process by minimizing coal
losses and 2) control the escape of particulates to the environment. Covers
on conveyors, primary cyclone collectors, and various types of hoods are
appropriate for these applications. Fabric filters are the most suitable
secondary control equipment for particulates from transfer, crushing, and
screening and for vent gas streams from storage silos. Fabric filters can
normally achieve 99.9 percent or greater removal efficiency, are effective
for fine particles, and have low maintenance requirements. Table 5-13
summarizes the estimated particulate control costs for the SRC-II preparation
operation. These costs reflect the NSPS for coal preparation plants. No
Option II is considered for the preparation operation.
Combustion Flue Gases
Particulate control for combustion flue gases is not needed because these
flue gases are generated from the combustion of fuel gases in the current design.
However, if combustion flue gases are generated from the burning of coal, partic-
ulates can be controlled by fabric filters, electrostatic precipitators (ESP),
venturi scrubbers or combinations of these processes. These technologies serve
as the basis for NSPS for electric utilities and large industrial boilers.
Transient Waste Gases
As discussed previously, incineration of transient waste gases is considered
minimum control for reduced sulfur, hydrocarbons and CO. Incineration will also
provide at least limited control of particulates since some fraction of the
particulate in transient waste gases is expected to be combustible. Therefore,
incineration represents an Option II control alternative for particulate
emissions. Higher removal efficiencies consistent with Option I control would
be achieved with an incinerator followed by an ESP, venturi scrubber or fabric
filter.
Particulates associated with transient waste gas from liquefaction would
consist primarily of high molecular weight organic aerosols as opposed to
unidssolved coal and ash. Such aerosols would be efficiently destroyed in a
properly designed incinerator. Therefore, Option II control, incineration,
is considered to be appropriate for control of particulate in liquefaction
90

-------
TABLE 5-13 ESTIMATED COSTS ASSOCIATED WITH PARTICULATE CONTROL
ALTERNATIVES FOR COAL STORAGE, HANDLING AND
PREPARATION IN A SRC-11 COMMERCIAL PLANT

Stream
Control
Equi pment
Efficiency
Percentage of Base Plant Cost
Capital Annualize?
• Coal Storage Area
Enclosure/Fabric Filter
Up to 99%
50 to 90%
0.015 0.01
Active Storage
Reserve Storage
Chemical and Wet
Suppression

• Coal Preparation



Transfer, crushing
and screening
Enclosures, Fabric
Filter
98 to 99.9%
0.08 0.07
TOTAL	0.10	0.08

-------
waste gases. Particulate control will be provided concurrently with control
of reduced sulfur, hydrocarbons and CO.
Transient waste gas from gasification is subject to high particulate
loadings due to entrained coal ash and uncombusted carbon. Uncontrolled
particulate emission rates from gasification waste gas have potential to
substantially exceed the total controlled particulate emission rate for other
streams in the plant during transient periods. Annual uncontrolled particulate
emissions due to this stream would comprise a significant fractionof antici-
pated total annual particulate emissions from the plant. Therefore, Option I
control, incineration followed by an ESP, venturi scrubber or fabric filter,
is preferred for control of particulate emissions from gasification waste gas.
Costs associated with particulate control for gasification waste gas are
presented in Table 5-14. The cost of incineration is included in control costs
for reduced sulfur and CO emissions from this stream.
Catalyst Regeneration/Decommissioning Off-Gas
The need for particulate control for these gases is not well defined. In
the case of shift and hydrolysis catalysts, uncontrolled particulate emissions
have potential to be significant relative to the total controlled particulate
emissions due to other streams from the plant. Therefore, an incinerator,
followed by an ESP, venturi scrubber or fabric filter, Option I control, may
be preferred for control of particulate emissions from shift and hydrolysis
catalyst regeneration/decommissioning off-gases. The cost of particulate
control for these streams is included in the particulate control costs for
gasification waste gases, since these streams are of comparable magnitudes and
proper scheduling of regeneration/decommissioning operations would ensure the
applicability of a system sized for gasification waste gas treatment.
For methanation and Claus catalyst regeneration/decommissioning off-gases,
Option I control does not appear to be warranted. Particulate emissions
associated with the methanation catalyst are small compared to overall plant
emissions. Although, the Claus catalyst may represent a major source of
particulate emissions during regeneration operations, current practice does
not support particulate controls for this stream. Therefore, particulate
control attained in conjunction with reduced sulfur, hydrocarbon and CO
control by incineration is considered adequate.
92

-------
TABLE 5-14 COSTS FOR CONTROL OF PARTICULATE EMISSIONS DUE TO TRANSIENT
WASTE GASES AND CATALYST REGENERATION/DECOMMISSIONING OFF-
GASES FROM AN SRC-11 COMMERCIAL PLANT*
Alternative Consistent With Alternative Consistent With
Option I Particulate Control Option II Particulate Control
Incineration with ESP	Incineration
Capital Total Annualized Capital Total Annualized
Transient Waste
Gas from	0.30	0.19	t	t
Gasification
Shift, hydrolysis
regeneration/	f	f	t	t
decommissioning
off-gas
~
Costs are presented as a percentage of uncontrolled plant capital or
annualized costs.
incineration costs are included in the cost of reduced sulfur, hydrocarbon
and CO controls
^Particulate control costs for shift and hydrolysis catalysts are included
in the cost of particulate control for gasification waste gases.
Wastewater Incinerator Flue Gas
Flue gases from incineration of wastewaters/brines will contain particulate
salts requiring control. Either venturi scrubbers or electrostatis precipitator
would be potentially applicable, although operating experience with existing
incinerators indicates that venturi scrubbers are more reliable. A perform-
ance minimum of 90% removal can be guaranteed with the scrubbers and actual
performance will likely be better than this (perhaps as high as 99%). Costs
for the scrubbers are included in wastewater treatment costs.
5.2.4 NO^ Control
N0X is generated during the combustion of synthetic fuel gases and the
incineration of waste gases. For boilers N0X controls are essentially linited
93

-------
to combustion design and operating practices, and these have served as the
basis for current NSPS for electric utility and large fossil fuel fired steam
generators. Option I and Option II requirements for boilers adhere to electric
utility and fossil fuel fired steam generators NSPS respectively for gaseous
fuel combustion. The electric utility NSPS may be considered to be the pre-
ferred option, since combustion of fuel gas presents no unique problems in
meeting the more stringent requirements of the electric utility NSPS.
In the case of gas turbines used for power generation in the current
SRC-II design, only one Option is considered. This requires N0X emissions to
meet the gas turbines NSPS (Table 3-1).
5.2.5	Ammonia and Hydrogen Cyanide Control
NHg and HCN are present in untreated acid gases, and fugitive emissions
from naptha storage/handling, process cooling, wastewater treatment, and ash
quenching. In the case of concentrated acid gases, HCN and NH^ control is
achieved by proper design and operation of AGR units, by destruction preceding
or in Claus sulfur recovery systems or by incineration for tail gas treat-
ment/hydrocarbon control. Incineration of sulfur recovery tail gases, and
transient gases is expected to reduce HCN and NHg levels to less than 1 ppmv
each based on data from waste gas incinerators and boilers.
Fugitive NHg and HCN control from naphtha storage/handling is accomplished
by RHC controls identified in Section 5.2.2. Evaporative emissions from waste-
water treatment (biological oxidation and cooling tower) and ash quenching are
minimized by steam stripping of gas liquors prior to treatment or use in the
cooling tower or as ash quench makeup. Ammonia recovery from stripped gases
is required. Option I control would be to prohibituse of wastewaters as
cooling tower or ash quench makeup. This prohibition is not an Agency pre-
ference since large economic penalties may be incurred in wastewater treat-
ment and greatly increased plant water could result.
5.2.6	Pol.yc.yc1ic Organic Matter (POM)
The major streams which are expected to contain POM in amounts warranting
concern are transient waste gases. Generally, Option I controls for RHC and
particulates discussed previously (particularly controlled incineration)will
achieve a high degree of POM control for these streams. For less significant
94

-------
sources of POM (fugitive emissions), the hydrocarbon and particulate controls
indicated previously should be sufficient to provide control without specific
PON requirements.
5.2.7	Trace Elements/Other Hazardous Substances
Nickel Carbonyl
Since it is possible that small amounts of Ni(CO)^ will be present in
methanation catalyst decommissioning offgases, incineration is the preferred
approach for destruction of this compound unless the operation can be conducted
in such a way to insure that Ni(CO)^ is not formed.
Trace Elements
With the possible exception of volatile elements such as As, Se, Sb,
and Hg, trace elements are not expected to be present in any of the controlled
gaseous waste streams in amounts warranting concern. The stringent controls
for sulfur, hydrocarbon and particulates are expected to minimize potential
trace element emeissions. For these reasons no specific control preferences,
other than those discussed previously for particulates, RHC and sulfur com-
pounds, are noted until sufficient data are available to determine if a
specific element problem exists. Both Tables 5-17 and 5-18 present guidance
for these sources.
5.2.8	Summary of Controlled Emissions
Tables 5-15 and 5-16 summarize the uncontrolled and controlled emissions
of sulfur compounds, RHC, CO and particulates on a stream by stream basis.
For purposes of presentation all emission rates have been normalized to the
heating value of coal input to the liquefaction unit (ng/J on a HHV basis).
The data in Table 5-15 indicate that 99.6 and 99.8 percent control of potential
emissions of reduced sulfur compounds are realized under Option II and Option
I, respectively. Also, 99.1 and 99.9 percent of the potential S0£ emissions
are controlled under Option II and Option I, respectively. Using the pre-
ferred control options, 99.7 percent control of potential emissions of total
sulfur can be achieved.
95

-------
TABLE 5-15. SULFUR EMISSION SUMMARY FOR SRC-II COMMERCIAL PLANT (ALL UNITS IN ng/J
OF COAL INPUT TO LIQUEFACTION UNIT)*
Haste Stream

h2s


COS


so2

Total
Sulfu» 1
(as S)
Uncon-
trolled
Option
11
Option
I
Uncon-
trol1ed
Option
II
Option
I
Uncon-
trolled
Option
II
Option
I
Uncon-
trol1ed
Option
II
Option
I
Flue Gas from Fuel Gas Combustion
0
0
0
0
0
0
560
3 0
0 19
280
1 5
0 093
Acid Gas
1230
0 08
0 14
3 0
2 8
3 6
0
4 1
0
1160
3 9
2 5
Transient Waste Gas from
Liquefaction1,
210
(0 16)
0 73
(0 0006)
0 73
(015006)
0
0
0
0
390
(0 30)
39
(0-30)
200
(0 15)
200
(0 15)
20
(0 15)
Transient Waste Gas from
93
2 5
0 25
8 7
0 24
0 024
0
179
18
92
92
9 2
Gasi ficationf
(0 57)
(0 015)
(0 0015)
(0 053)
(0 0015)
(0 0002)

(1 1)
(Oil)
(0 56)
(0 56)
(0 56)
Shift Catalyst Regeneration/
Decommissioning Off-Gac+
0
0
0
0
0
0
o o
<~D
CM
660
(2 0)
66
(0~?0)
330
(1 0)
330
(1 0)
33
(0 10)
Hydrolysis Catalyst Regeneration/
Decommissioning Off-Gas1,
0
0
0
0
0
0
70
(0 21)
70
(0 21)
7 0
(0 021)
35
(0 11)
35
(0 11)
3 b
(0 Oil)
Methanation catalyst
Decommissioning Off-Gas
0
0
0
0
0
0
0
0
0
0
0
0
Claus Catalyst Regeneration/
Deconmissioning Off-Gas
0
0
0
0
0
0
18
(0 041)
18
(0 041)
1 8
(0 0041)
9 0
(0 021)
9 0
(0 021
0 90
(0 0020
TOTAL	1230- 0 08-	0 14 2 0-11 7 2 8-3 0	3 6	560-	7 1-	0 19 1440- 4 4- ? 6-
1530	3 3	1 12	1290	1320	132	2106 671 69
(1230) (0 095)	(0 14) (3 0) (2 8)	(3 6) (1562) (10 8)	(0 56) (1442) (7 2) (2 8)
TOTAL FOR PREFERRED	0 14-1 1	3 6	3 0-151	4 0-79
CONTROL	(0 14)	(3 6)	(3 4)	(4 2)
Underlining indicates emissions corresponding to preferred control options
Tabulated rates for intermittent streams represent the emission rates during transient periods Parenthetis values indicate average
annual emission rates (total annual emission rates divided by 7889 operating hours per year)

-------
TABLE 5-16. HYDROCARBONS, CARBON MONOXIDE, AND PARTICULATE EMISSIONS SUMMARY
FOR SRC-II COMMERICAL PLANT (ALL UNITS IN ng/J OF COAL INPUT TO LIQUEFACTION UNIT)*

Reactive
Hydrocarbons


Carbon
Monoxide

Particula tes
Waste Stream
Uncon-
trolled
Option^
II
Option*
I
Uncon-
trolled
Option
11
Option
1
Uncon-
trol1ed
Option
11
Option
1
Flue Gas from Fuel Gas Combustion
0 87
0 87
0 87
3 1
3 1
3 1
1 46
1 46
1 46
Acid Gas
2 8
2 8
12
186
12
3 6
-
-
-
Fugitive Hydrocarbon Emissions
3 31
0 91
0 52
-
-
-
-
-
-
Product and By Product Evaporative Emissions
0 18
0 18
11 007
-
-
-
-
-
-
Fugitive Dust from Coal Storage Piles
-
-
-
-
-
-
0 73
0 73ft
0_05
Coal Preparation and Transfer Emissions
-
-
-
-
-
-
65 9
65 9 1 +
3 2
*~
Transient Waste Gas from Coal Liquefaction
700
(0 53)
6 0
(0 0046)
6 0
TO-0046)
550
(0 42)
18
(0 014)
18
To 014)
-
-
-
~ *
Transient Waste Gas from Gasification
-
6 4
(0 039)
2 1
To-013)
4200
(26)
21
(0 13)
6 4
TO"039)
49
(0 30)
39
(0 24)
3 6
TCPQ22)
Shift Catalyst Regeneration/Decommissioning
Off-Gas**
-
-
-
-
13
(0 040)
3 9
To"012)
26
(0 079)
26
(0 079)
2 0
(0 0061)
Hydrolysis Catalyst Regeneration/Decommissioning
Off-Gas**
-
-
-
-
1 4
(0 0043)
0 42
T0~0013)
2 8
(0 0085)
2 8 0 21
(0 0085)(0 0006)
**
Methanation Catalyst Decomnissioning Off-Gas
-
-
-
2 4
(0 0018)
0 22
TiTff002)
0 065
( 000005)
0 050 0 050 0 036
(0 0004) (OTTO )(0 00003)
Claus Catalyst Regeneration/Decommissioning
Off-Gas**
-
-
-
-
2 2
T(F00050)
0 67
(0 0015)
21
(0 048)
21
(IT048)
0 34
(0 0008)
To tal
7 2-707
(7 7)
4 8-17 2
(4 8)
2 6-10 7
( 26)
189-4940
(216)
15-71
(15 3)
6 7-36
(6 8)
78-167
(79)
68-157
(68)
4 7-11
(4 7)
Total for Preferred Control	2 6-10 7	6 7-38	4 7-32
(2 6)	(6 8)	(4 8)
*
Underlining indicates emissions corresponding to preferred control options
+ Reactive hydrocarbons are defined as all hydrocarbons except CH^, C^H^, CjHg and CH^OH (consistent with definition in 42FR131)
* Controlled emissions of RHC are reported as ethylene
**
Tabulated rates for intermittent streams represent the emission rate during transient periods Parenthetic values indicate
annual average emission rates (total annual emission rates divided by 7889 operating hours per year)
No Option II guidance is given for particulate control of these streams

-------
For reactive hydrocarbon and carbon monoxide emissions (Table 5-16) approxi-
mately 38 and 93 percent control, respectively, are achieved under Option II.
Approximately 66 and 92 percent control, respectively, for hydrocarbons and CO
are realized under Option I. For particulate emissions (Jable 5-16) only 14
percent control is associated with Option II and over 94 percent control with
Option I. Using the preferred control options, controls of potential emissions
of reactive hydrocarbons, CO, and particulates are 66 percent, 97 percent, and
94 percent, respectively.
5.2.9	Guidance Summary
Tables 5-17 and 5-18 summarize the Agency guidance for the control of air
emissions. Table 5-17 addresses guidance for sources unique to SRC-II direct
liquefaction facilities. This guidance indicates the Agency preference for
control of the two largest volume streams in an integrated facility (AGR/vent
gases and flue gas from fuel gas combustion) and provides that individual
limits for these two streams need not necessarily be met separately as long
as the combined sulfur mass limits are atained. The Option I guidance for
reduced sulfur compounds also achieves a high degree of hydrocarbon and CO
control. Option II control is suggested for sour fuel gas treatment and cer-
tain smaller volume streams where stricter control would not be cost-effective
or would present safety problems. Table 5-18, which addresses guidance for
direct liquefaction plant sources similar to existing sources, generally
indicates an Agency preference for Option I controls.
5.2.10	Air Pollution Control Costs and Energy Impacts
Capital and total annualized cost for air pollution control for Option I
and Option II controls are summarized in Table 5-19. As shown in the table,
most of the costs are associated with control of the acid gas streams. Option
I control results in costs of 5.7 to 7.4 percent of capital costs for an un-
controlled plant and 4.8 to 7.4 percent of the annualized cost. Option II
control results in costs of 4.2 to 6.8 percent of capital and 6.0 to 6.9
percent of annualized costs. Annualized costs for the preferred controls are
4.4 to 7.0 percent depending on whether the offgas from sulfur plant tail gas
treatment is incinerated and on the coal sulfur content.
Gross energy requirements (Table 5-20) associated with air pollution
98

-------
TABLE 5-17. SUMMARY OF CONTROL GUIDANCE FOR GASEOUS WASTE
STREAMS UNIQUE TO SRE-II DIRECT LIQUEFACTION FACILITIES
Stream
(Stream No )


Control Guidance

Pollutants
Option I
Option 11
Discuss ion
VO
Acid Gases
f ran AGR
(1207, 2302,
2402, 3105),
Sour Water
Stripping/
Amnion la
Recovery
(4103), and
Gasifler
(2104)
Reduced
sulfur
compounds,
NH-,, HCN
Guidance
Emissions to the atmosphere
should not exceed
-100 ppmv+ total reduced
sulfur and 2 5 ng total
sulfur/J coal input to
1lquefaction unit **
-The total sulfur mass
emission limits for acid
gases and combustion of
fuel gases need not be met
individually if the com-
bined total for the two
streams is met
Technology Basis
Claus sulfur recovery plus
catalytic tail gas treat-
ment by Beavon
Cost *
Capital
Annualized
1 9-2 6%
1 5-4 4%
Guidance
Emissions to the atmosphere
should not exceed
-150 ppmvl of S0j at zero
percent oxygen if emissions
are controlled by an oxida-
tion control system (e g ,
WeiIman-Lord), or a reduc-
tion control system follow-
ed by incineration (e g ,
SCOT), and 3 7 ng total
sulfur/J coal input to
1lquefaction unit **
-Total sulfur mass emission
limits for acid gases and
combustion of fuel gases
need not be met individual-
ly if the combined total
for the two streams is met
Technology Basis
Claus sulfur recovery plus
incineration and FGD
(Weilffian-Lord) or catalytic
tail gas treatment (SCOT)
Cost *
Capital	2 1-4 42
Annualized 3 1-4 5%
The tradeoff with fuel gas combustion sulfur emissions allows flexi-
bility in meeting overall plant mass emission targets
Tail gas HCN and NH^control is achieved prior to, during, or following sul-
fur recovery (incineration) and hence no problems wim i cuullu m <.¦
gen species emissions are envisioned whenever control of ieduced
sulfur compounds is practiced
The Agency prefers the use of Option 1 controls Factors supporting
the use of Option I controls
-These control levels have been demonstrated in petroleum
refineries
-66 to 80% of the total sulfur emissions from Option li
-Insignificant incremental control costs and energy require-
ments, even when incineration of the offgas is included
Factois suppoiting the use of Option II controls
-Control levels have been demonstrated in petroleum rcfineiies,
power plants, and sulfuric acid plants
-A high degree of control for toxic organics, since gas stream is
incinerated either prior to or following tail gas treatment
-Proven operational reliability
Reactive	Guidance
hydro-	Emissions to the atmosphere
carbons!	should not exceed
(RHC), CO	-100 ppmv RHC
Technology Basis
Controlled incineration
Cost
Included in reduced sulfur
control cost
Guidance
Technology is the guidance
Technology Basis
Incineration in flare
Cost
Higher cost than Option I
because of no provisions
for waste heat recovery
A high degree of CO control is achieved with eithei of these
options The Agency prefers the use of Option 1 Controls
Factors supporting the use of Option I controls
-Compared to flaring (Option II), greater control of emissions of
hydrocarbons and toxic organics is achieved by controlled
incinera tion
-Waste heat recovery m a boiler following incineration can help Lo
offset the costs of control
Factors supporting the use of Option II controls
-Ease of operation
-Greater flexibility in handling upset conditions
* As percent of uncontrolled base plant cost Ranges reflect the impacts of different coal types and/or control approaches
! Reactive hydrocarbons are defined as all hydrocarbons except CH4, C2Hg, C3H8 and CH^OH (consistent with definition in 42FR131)
' All concentration limits in the guidance assume that no dilution with air or waste gases (e g , CO2 or N^) will occur Concentrated limits for acid
gases are based on zero percent oxygen
** The mass emission limits include sulfur emissions from the direct venting of the C^-rich acid gas from the selective AGR unit
Continued

-------
TABLE 5-17 (continued)
Stream
(Stream No )
Control Cuidancc
Pollutants
Option I
Option 11
Discussion
Flue Gases
fi om
Combustion of
Fuel Gases
(1121 , 3418,
4414, 5101,
5425)
S0o
O
o
Guidance
Sulfur level in treated
fuel gas should not exceed
-10 ppmv total reduced
sulfur
-The total sulfur mass emis-
sion limits for acid gases
and combustion of fuel
gases need not be met
individually if the com-
bined total for the two
streams is met
Technology Basis
Treatment of high pressure
sour fuel gas with physical
adsorption process (Selexol)
treatment of low pressure
sour fuel gas by OEA scrub-
bing with high circulation
rates and high stream rates
for regeneration Also,
treatment by Stretford pro-
cess followed by Beavon
process
Cost *
Capital	1 3%
Annualized 1 9%
Guidance
Sulfur level in treated fuel
gas should not exceed
-160 ppmv total reduced
sulfur
-The total sulfur mass emis-
sion limits for acid gases
and combustion of fuel
gases need not be met indi-
vidually if the combined
total for the two streams
is met
Technology Basis
Treatment of high pressure
sour fuel gas with physical
adsorption process (Selexol),
treatment of low pressure
sour fuel gas by DEA scrub-
bing with normal circulation
rates and steam rates for
regeneration Also, treat-
ment by Stretford process
The Agency prefers the use of Option II control Factors
supporting the use of Option I controls
-Control levels have been demonstrated in petroleum refineries and
gas plants
-Higher degree of sulfur removal
-Proposed by process developers
-Permits use of Option II controls for acid gases while not exceeding
the total sulfur mass emission limit, for the two streams
Factors supporting the use of Option II controls
-Control levels have been demonstrated in petroleum refineries,
petrochemical plants, and gas pljrits
-Lower capital investment and operating costs
-Consistent with fuel gas sulfur limits stipulated in NSPS for
petroleum refinery Claus sulfur recovery plants
-Controls levels are already more stringent than requirements
stipulated in NSPS for electric utility stream generating units
NO
Guidance
Boilers - NSPS for gas fired
electric uti1ity steam gen-
erating units (86 ng/J)
Gas Turbines - NSPS for
stationary gas turbines
Technology Basis
Boilers - Combustion design
Gas Turbines - Wet injection
Cost
Boilers - Costs for this
control option are largely
offset by the increased
thermal efficiency of the
boiler, and are usually in-
cluded in the cost of the
boi1er i tself
Gas Turbines -
Capital	0 009%
Annualtzed 0 14%
Guidance
Boilers - NSPS for coal-
fired electric utility steam
generating units (260 ng/J)
Gas Turbines - Not
considered
Technology Basis
-Combustion design
Cost
-Costs for this control
option are largely offset by
the increased thermal effi-
ciency of the boiler, arid
are usually included in the
cost of the boiler itself
The Agency prefers Lhe use of Option I controls Factors
supporting the use of Option I controls
-Controls have been demonstrated on electric utilities and are
presently standard industry practice No unique circumstances
are apparent that suggest diffeient practices in SRC-11 direct
liquefaction facilities
Factors supporting the use of Option Ilcontrols
-Lower capital investment and operating costs
As percent of uncontrolled plant cost
Continued

-------
TABLE 5-17 (continued)
Control Guidance
S tr earn
(Stream No ) Pollutants	Option I	Option II	Discussion
Claus Catalyst
Regeneiation/
Deconunssion-
mg Off-Gas
(3310)
Reduced
sulfur
compounds
Particulates
CO
so„
Guidance
Emissions to the atmosphere
should not exceed
10 pprnvJ
0 2 g/dson
300 ppmvt
90% removal should be
achieved
Technology Basis
Controlled incineration with
ESP and FGD
Cost *
Cost is included in Option I
control costs for liquefac-
tion and partial oxidation
waste gases Additional
annualized cost for con-
trol of this stream (pri-
marily fuel cost) is
0 00083-0 0012%
Guidance
Technology is the guidance
Technology Basis
Incineration in flare
Capital 0 008-0 012%
Annuallzed
0.0057-0 0083%
Factors supporting the use of Option I controls
-This stream has potentially high concentrations of SO2 and
particulate, and may represent a major source of these pollu-
tants during regeneration operations
Factors supporting the use ot Option II contiols
-Regeneration occurs infrequently
-Uncontrolled annual SO2 and particulate emissions due to this
stream would correspond to less than ten percent of the plant
annual controlled SO2 and particulate emissions
-No control of this stream is employed at most existing Claus
plants
Liquefaction
Waste Gas
(8103)
Reduced
sul fur
compounds
S02
RHC+
CO
Guidance
Emissions to the atmosphere
should not exceed
10 ppmv^
90% removal should
achieved
100 ppmv^
300 ppmv^
Technology Basis
Controlled incineration with
FG0
Cost *
Capital	2 4-3 2%
Annualized 1 2-1 6%
Guidance
Emissions to the atmospher
should not exceed
10 ppniv^
100 ppmvt
300 pprnvJ
Technology Basis
Control led incinera tion
Cost *
Capital
Annuallzed
0 91-1 2%
0 56-0 74%
Liquefaction waste gases represent a large uncontrolled emission
source of both conventional and hazardous pollutants (e g POM)
PON and NH^ control is achieved through incineration for reduced
sulfur species, CO and RHC control
The Agency prefers the use of Option 1 controls Factors
supporting the use of Option I controls
-Uncontrolled SO2 emission rates due to incinerated liquefaction
waste gases have potential to substantially exceed the total
controlled SO2 emission rate for other streams from the plant
during the transient period
Factors supporting the use of Option II control
-The major pollutants of concern in this stream are reduced
sulfur, RHC, CO and POM These species would be largely
destioyed in a properly designed waste gas incinerator
* As percent of uncontrolled base plant cost Ranges reflect the impact of different coal types and/or control approaches
+ Reactive hydrocarbons defined as all hydrocarbons except CH^, 02^, C3H3 and CH^OH (consistent with definition in 42FR131)
t All concentration limits in the guidance assume that no dilution with air or waste gas (e g C0? or N?) will occur
Concentrations are based on zero percent oxygen

-------
TABLE 5-17 (continued)
Stream
(Stream No ) Pollutants
Control Guidance
Option 1
Option 11
Discussion
Texaco Waste
Gas (1804)
O
ro
Reduced
sulfur
compounds
S02
RHCf
CO
Particulate
Shift,
Hydrolysis
Catalyst
Regeneration/
Deconuiission-
ing Off-Gases
(2204, 2205,
3311)
Reduced
sulfur
compounds
so2
CO
Particulate
Guidance
Emissions to the atmosphere
should not exceed
10 ppmv^
90% removal should be
achieved
100 ppmv^
300 ppmv^
0 2 g/dscm
Technology Basis
Controlled incineration with
ESP and FGD
Cost *
Cost of the incinerator,
quench and FGD are included
in cost of Option I control
of liquefaction waste gases
Additional annualized cost
for control with these units
is 0 0004%
Capital 0 30% (ESP only)
Annualized 0 20% (ESP only)
Guidance
Emissions to the atmosphere
should not exceed
10 ppmvt
90% removal should be
achieved
300 ppmvt
0 2 g/dscm
Technology Basis
Controlled incineration with
ESP and FGD
Cost *
Cost is included in Option I
control costs for liquefac-
tion and partial oxidation
waste gases Additional
annualized cost for control
of these streams (primar-
ily fuel cost) is 0 024%
Guidance
Technology is the guidance
Technology Basis
Incineration in flare.
Cost *
Capital
Annuallzed
12%
074%
Guidance
Technology is the guidance
Technology Basis
Incineration in flare.
Cost *
Cost is included in Option II
control cost for partial
oxidation waste gases
Additional annualized cost
for control of these streams
(primarily fuel cost) is
0 020%
Control of NH3 and HCN is achieved through incineration foi
reduced sulfur spectes, CO and RHC control
The Agency prefers the use of Option 1 Controls Factors
supporting the use of Option I controls
-Uncontrolled particulate and SO2 cm1ss * on rates due to incinera-
tion of partial oxidation waste ijoses have potential to sub-
stantially exceed the total controlled particulate and S0^
emission rates for other streams in the plant during the
transient period
-The controlled incineration unit recommended for control of
liquefaction waste gases (Option I or Option II) would be
appropriate to provide contiol of partial oxidation waste gases
Because the liquefaction waste gas incinerator is of sufficient
capacity to acconmodate partial oxidation waste gases, controlled
combustion of partial oxidation waste gases can be achieved
without incurring significant additional capital cost providing
that the two waste gas streams are not incinerated concurrently
Factors supporting the use of Option II control
-The major pollutants of concern in this stream arc reduced
sulfur species and CO These species would be largely destroyed
by incineration
Although these off-gases are intermittent streams, they will con-
tain high levels of SO2 and probably contain trace elements such
as Co, Mo, Se, As and Hg Monitoring of this stream for hazard-
ous trace elements is recotiimended
The Agency prefers the use of Option I controls Factors
supporting the use of Option I control
-Uncontrolled particulate and SO? emission rates associated with
these streams have potential to substantially exceed the total
controlled particulate and SO2 emission rates for other streams
in the plant during the regerieration/deconinissioning period
-The controlled incineiation/ESP/IGD units preferred for Option
I control of liquefaction waste gases and partial oxidation
waste gases would be sufficient 111 size to enable control of
regeneration/decoirmissioning off-gases, provided that proper
scheduling is employed Therefore, Option I control could be
achieved without incurring significant additional capital cost
Factors supporting the use of Option II control
-Option II offers greater operability for intermittent streams
while providing control of reduced sulfur compounds and CO
* As percent of uncontrolled base plant cost Ranges reflect the impact of different coal types and/or control approaches
t Reactive hydrocarbons are defined as all hydrocarbons except CH4, C2H6, C3H8 and CH3OH (consistent with definition in 42FR131)
!• All concentration limits in the guidance assume that no dilution with air or waste gas (e g C0? or N?) will occur
Concentrations are based on zero percent oxygen
Continued

-------
TABLE 5-17 (continued)
Stream
(S Li earn No )
Control Guidance
Pollutants
Option I
Option II
Discussion
O
CO
Methanation
Catalyst
Regeneration/
Decoinnii sslon-
1 ng Off-Gas
(2510)
Fugitive
Organic
Enn ss ions
Particulate
CO
Ni (CO)-
Volatile
organic
compounds
(VOC),
reduced
sulfur/
nitrogen
compounds
Guidance
Emissions to the atmosphere
should not exceed
0	2 g/dscm
300 ppmv^
1	ppmv^
Technology Basis
Controlled incineration with
ESP or venturi scrubber
Cost *
Cost is included in Option I
control costs for lique-
faction and partial oxi-
dation waste gases
Additlonal annualized
cost for control of this
stream (primarily fuel
cost) is 0 0001%
Guidance
Equipment design which
minimizes or eliminates
leaks
VOC leak detection (10,000
ppmv) with repair/replacement
of leaking equipment
Technology Basis
Equipment design/replacement
monthly inspection, monitor-
ing and maintenance
Cost *	Cost *
Capital	0 06%	Capital
Annualized 0 068%	Annualized
Gu idance
Technology is the guidance
Technology Basis
Incineration in flare.
Cost *
Cost is included in
Option II control cost for
Claus Catalyst regen-
eration waste gas.
Additional annual-
wed cost for control
of this stream (prinarily
fuel cost) is 0.0001X
Guidance
Sources subject to equip-
ment leak detection
(10,000 ppmv) maintenance
and repair requirements.
Technology Basis
Monthly inspection, monitor-
ing and maintenance
0 002%
0 014%
factors supporting the use of Option I controls
-Option I provides stringent control of particulate and CO
emissions.
Factors supporting the case of Option II controls
-Decarmissioning of methanation catalyst occurs very infrequently
-Incineration will oxidize any nickel carbonyl which may be
present. The potential presence of this substance is of concern
due to its extreme toxicity
-Uncontrolled annual particulate emissions due to this stream
are very small relative to annual controlled particulate
emissions due to other streams from the plant
Levels of control are somewhat arbitrary for fugitive sources,
since major emphasis is on maintenance
Factors supporting the use of Option 1 controls
-Fugitive sources can be major contributors to total plant
reactive hydrocrabon and reduced sulfur/nitrogen species
emissions
Factors supporting the use of Option 11 controls
- Fugitive emissions can be reduced by 70 percent at
80 percent less cost required for Option I
* As percent of uncontrolled base plant cost Ranges reflect the impact of different coal types and/or control approaches
+ Reactive hydrocarbons are defined as all hydrocarbons except CH4, C2H6» C3M3 and CH3OH (consistent with definition in 42FR131)
t All concentration limits in the guidance assume that no dilution with air or waste gas (e g , CO- or N?) will occur
Concentrations are based on zero percent oxygen
Continued

-------
TABLE 5-17 (continued)
Stream
(Stream No )
Control Guidance
Pollutants
Option I
Option II
Discussion
Cooling Tower
Evaporation
and Drift
(5301)
RHC, NH3,
HCN, H2S
(from
cooling
tower
makeup
water).
Guidance
Cooling tower makeup com-
position limited to
TOC	200 mg/1
NH3	100 mg/1
CN'.Steach) 5 mg/1
Technology Basis
Phenol extraction, steam
stripping, biological
oxidation, activated
siudge
Cost
Included in wastewater
treatment costs
Guidance
Cooling tower makeup
composition limited to
4000 mg/1
100 mg/1
5 mg/1
Technology Basis
Steam stripping,
phenol extraction, and
biological oxidation of
process condensates prior
to use as cooling tower
makeup
Cost
Included in wastewater
treatment costs
The rmjor concern with using SRC-11 wastewaters as cooling tower
makeup is the transfer of RHC and volatile inoiganics Lo the
atmosphere due to air stripping or drift
Monitoring for RHC, NH3, HCN, and and organics is lecommended
to determine if these species present emissions problems
Factors supporting the use of Option I controls
-Greater emissions reductions
Factors supporting the use of Option II controls
-Lower cost
O
4*
Activated
Ca rbon
Regeneration
Offgases
(4307)
Brine
Concentra-
tion Off-
gases (4308)
Particu- Guidance
lates, RHC, Emissions to the atmos-
C0	phere should not exceed
0 2 g/Nm^ Particulates
100 ppmv RHC
Technology Basis
Controlled incineration
(e g , in thermal
incinerator) with ESP
Cost
Included in wastewater
treatment costs
HpS, RHC, Guidance
HlN, NH3 Treatment equivalent to
incineration
Technology Basis
Incineration in controlled
combustor (eg, in
thermal incinerator)
Cost
Included in wastewater
treatment costs
Guidance
Treatment equivalent to
flan ng
Technology Basis
Incineration in flare
Cost
Included in wastewater
treatment costs
Guidance
Evaporator makeup water
composition limited to
100 mg/1 NH3
5 mg/1 CN" and S=
Technology Basis
Steam stripping and
biological oxidation of
process wastewaters prior
to use as evaporator
makeup
Cost
Included in wastewater
treatment costs
This offgas is expected to contain organics volatilized froin the
carbon CO control is achieved via incineration for RHC control
with etther option
Factors supporting the use of Option 1 controls
-Volatile organics and particulates may not be completely destroyed
in a flare
Factors supporting the use of Option II controls
-Lower control system costs
Monitoring for RHC, NH3, HCN, H^S and organics is recoinnended to
determine if there is an emissions problem fiom the evaporator
Factors supporting the use of Option 1 controls*
-Greater emissions reductions
Factors supporting the use of Option 11 controls
-Incineration of these gases would be very expensive and would
involve large energy penalties
-Option II insures that the more readily volatile substances are
removed from the concentrator feed stream
Continued

-------
TABLE 5-17 (continued)
Stream
(Stream No )
Pol 1utants
Control Guidance
Option I
Option 11
Discusbion
Flue Gases
from Wastewater
Incinerator
(4305)
Particulates Guidance
o
CJ1
so.,
Emissions to the atmosphere
should not exceed
0 2 g/Nn^ or 99% removal of
uncontrolled particulate
emissions
Technology Basis
High Energy Venturi Scrubber
(or ESP)
Cost
Included in wastewater
treatment cost
Guidance
Use of fuel gas containing
less than 10 ppmv sulfur
Technology Basis
Sour fuel gas treatment by
Selexol, DEA, and Stretford/
Beavon
Cost
Included in cost for
Option I sour fuel gas
treatment
Guidance
902 or greater removal of
uncontrolled particulate
emissions
Technology Basis
Venturi Scrubber
Cost
Included in wastewater
treatment cost
Guidance
Use of fuel gas containing
less than 160 ppmv sulfur
Technology Basis
Sour fuel gas treatment by
Selexol, DEA, and Stretford
Cost
Included in cost for
Option II sour fuel gas
treatment
Particulate control required to minimize emissions of inorganic
salts (wastewater TDS) to the atmosphere
Factors supporting the use of Option I controls
-Greater emissions reductions
Factors supporting the use of Option II controls
-Medium pressure drop scrubbers are expected to achieve greater
than 90% control 99% control probably could not be guaranteed
in this type of application
-Small incremental increase in emissions reduction may not
justify greatet capital and annualized operating costs
Factors supporting the use of Option I controls
-Greater emissions reductions
Factors supporting the use of Option II controls
-Lower capital investment and operating costs
-Control levels are already more stringent than requirements
stipulated in NSPS for electric utility steam generating
uni ts
Concluded

-------
TABLE 5-18 SUMMARY OF GUIDANCE OPTIONS FOR GASEOUS WASTE STREAMS FROM
SRC-II DIRECT LIQUEFACTION FACILITIES WHICH ARE SIMILAR TO
THOSE FOR WHICH REGULATIONS EXIST
Sti earn
(Str earn No )
Control Guidance
Pollutants
Option I
Option 11
Discuss ion
O
CT»
Dust from Coal
Preparation
•Dust from
coal storage
(6103)
•Crushing/
screening
dust (6104)
Product, By-
product and
Chemical
Storage
Emissions
(5424)
Particulates Guidance
NSPS for coal preparation
plants (Table 3-1)
Technology Basis
•Wet suppression techniques
•Enclosure, central dust
collection, fabric filters
and wet suppression tech-
niques
Cost *
Capital 0 1%
Annuallzed 0 08%
Volatile
organic
compounds
(VOC)
Guidance
Technology is the guidance
Technology Basis
Floating roof/double seals
or fixed roof/internal
floaters
Cost *
(all storage)
Capital 0 02%
Annual 1 zed 0 01%
Guidance
Not considered
Guidanee
NSPS for petroleum liquids
storage (Table 3-1)
Technology Basis
Floating roofs or vapor
recovery systems for
volatile liquids
Cost *
(all storage)
Costs of control are part
of storage tank costs
Option 1 controls are presently standard industry practice No
unique circumstances are apparent to suggest different practices in
direct liquefaction facilities
Factors supporting the use of Option I controls
-In the case of high vapor pressure liquids, increased costs
of Option I are largely offset by the value of the recovered
product
Factors supporting the use of Option II controls
-In the case of heavier fuel s/cheimcals, emissions reductions
are small relative to incremental costs of Option I
*As percent of uncontrolled base plant cost

-------
TABLE 5-19 SUMMARY OF COST IMPACTS OF AIR POLLUTION
CONTROL OPTIONS FOR SRC-II COMMERCIAL PLANT*
Percentage ot Uncontrolled Base Plant Cost
Option 1

Capital
Total
Annuallzed
Capital
Total
Annuallzed
Flue Gas from Fuel Gas Combustion
1 3
1 9
1 1
i__S
Acid Gas*
1 9-2 7
2 5-3 7
2 1-44
3 8-4 5
Transient Waste Gas from
Liquefaction
2 4-3 2
1 2-1 6
0 91-1 2
0 56-0 74
Transient Waste Gas from
Gasification
0 30*
0 20t
0 12
0 074
Shift Catalyst Regeneration/
Decommissioning Offgas
f
0 022
*+
0 018
Hydrolysis Catalyst Regeneration/
Oecomnissioning Offgas
i
0 0025-0 0028
**
0 0020
Methanation Catalyst
Oecomnissioning Offgas
t
0 00010
ft
0 00008
Claus Catalyst Regeneration/
t
0.00083-0 0012
0 0080-0 012
0 0057-0 0083
Decommissioning Offgas




Coal Storage, Preparation
and Transfer Emissions
0 1
0 08
...
...
Fugitive Hydrocarbon Emissions
0 06
0 068
0 002
0 014
Product and By-Product Storage
Emissions
0 02
0 01
*+*
***
Total
5 7-7 4
4 8-7 4
4 2-6 8
6-0-6 9
Total for Preferred Controls
5 6-7 2 Capital,

4 4-7
0 Annual
Underlining indicates costs associated with preferred level of control
Ranges reflect impacts of different types of coal and/or control approaches
Capital cost and annualized cost due to capital charges associated with incineration and FGD are included in
Option I control costs for liquefaction waste gas, while those associated with particulate removal are
included in Option I control costs for gasification waste gas
Capital cost and annualized cost due to capital charges are included in Option II control costs for
gasification waste gas
Capital cost and annualized cost due to capital charges are included in Option II control costs for Claus
catalyst regeneration/decommissioning off-gas
Costs of control are part of storage tank costs
107

-------
TABLE 5-20 SUMMARY OF ENERGY IMPACTS OF AIR POLLUTION CONTROL
OPTIONS FOR SRC-II COMMERCIAL PLANT*
Waste Stream
Percentage of Total
Option I
Plant Energy Input
Option II
Flue Gas from Fuel Gas Combustion
1.0
0.68
Acid Gas^
(0.25^-0.54
0.67-0.86
Transient Waste Gas from Liquefaction
0.00044
0.00044
Transient Waste Gas from Gasification
0.0024
0
Shift Catalyst Regeneration/Decommissioning Offgas
0.013
0.0121
Hydrolysis Catalyst Regeneration/Decommissioning Offgas
0.0014
0.0013
Methanation Catalyst Decommissioning Offgas
0.000061
0.000056
Claus Catalyst Regeneration/Decommissioning Offgas
0.00069
0.00062
Coal Storage, Preparation and Transfer Emissions
0.01
0
Fugitive Hydrocarbon Emissions
0
0
Product and By-Product Storage Emissions
0
0
Total
0.78-1.6
1.4-1.6
Total for Preferred Controls	0.46-1.3
*
Underlining indicates energy requirements associated with preferred level of control.
*Parenthesis indicates energy credit.
^Ranges reflect impacts of different types of coal and/or control approaches.

-------
control technologies, consistent with Option I control of an integrated facility
range from 0.8 to 1.6 percent of total plant energy input. As expected, treat-
ment of sour fuel gases and acid gases are the major energy consumers associated
with air pollution control.
109

-------
5.3 Water Pollution Control
The uncontrolled wastewater streams generated in SRC-11 facilities are
summarized in Table 5-21. The first ten streams listed in the table are from
the coal dissolution, product separation and upgrading operations, and with
the exception of flow rates, data are available only on the characteristics
on these streams combined. The combined stream is referred to as stream A
in this document. Stream A is the largest wastestream from SRC-II facilities
and because of the variety of pollutants it contains (both organics and in-
organics), it among the most difficult to treat. Other major process waste
streams include the ammonia scrubber outlet water and the condensates from
the Texaco Gasifier. These streams contain high dissolved gases and some
organics (mainly formates). Most of the other wastestreams listed in Table
5-21 are either (1) similar to streams found in other industries for which
regulations already exist, or (2) small volume streams which can be recycled/
reused in the process or treated in combination with the larger volume streams.
The flow rates and characteristics of many major wastewater streams are
expected to vary for different types of coals used, due primarily to the dif-
ferences in reactivity and moisture contents among the coals. This document
examined two coals, the Powhatan and Blacksville coals. However, due to the
developmental status of the SRC-II process, characteristic data are available
only for the Powhatan coal. Thus, the Blacksville coal streams are only used
to estimate the cost variations due to the difference in flow rates, and only
the Powhatan coal streams are used in developing guidance in this document.
The remainder of this section only discusses the Powhatan coal case.
The treatment processes considered in developing effluent control stra-
tegies for SRC-II facilities are presented in Table 5-22. Since most of these
processes have not been applied directly to the control of SRC-II liquefaction
plant wastewaters, evaluations of the applicability, performance and costs of
these controls were based upon the experience gained in the by-product coking,
petroleum refining, and electric utility industries. Also, extensive use was
made of conceptual information generated by SRC-II developers.
The ultimate disposal alternatives for treated effluents which are ad-
dressed in this PCGD include:
110

-------
TABLE 5-21. SUMMARY OF UNCONTROLLED WASTEWATER STREAMS FOR
SRC-II COMMERCIAL PLANT (POWHATAN NO. 5 CASE)
Stream No. Stream Description
Stream Pollutants
Flow Rate of Potential
(m^/hr) Concern
Concentrat tons
of Major
Pollutants
Factors Affecting
CffLuent Scream
Cha racteristics
1208 \
Sour Water form Recycle Gas
DEA Treating and Compression
0.4 \



1210
Cryo Knockout Water from
Hydrogen Recovery
0.4



3102
Sour Water from Low
Pressure Gas Preparation
1.9



3405
Sour Water from Atmospheric
Fractionation
13



3407
3415
2504
1103
> A Sour Water from Debutanizer
Sour Water from Vacuum Flash
Glycol Dehydration Water
Sour Water from Coal Slurry
Mix Tank
0.2
6.2
0.045
86
> H2S, NH3,
phenolics,
oil and
grease
H2S-0.545 wt %
NH3-I 62 wl %
CO2-I 24 wt %
Oil and grease-
2,860 mg/1
Phenols-4000 mg/1
0 Coal composition
0 Reactor operating
condit Lon
1112
Sour Water from H.P. Cooling
of Dissolver Vapor
213



1117 i
Sour Water From L.P. Cooling
of Dissolver Vapor
66 J



2105	& Ammonia Scrubber Outlet
2106	Water and Purge Water from
Texaco Casifier
177
NH3,
Cyanide,
Trace
NH3-O.75 wt %
Cyanide-530 mg/1
0 Gasifier type

-------
Stream
3303
3306
5302
5209
9101
6102
6303
5102
8101 I
8102
TABLE 5-21. (Continued)
Stream Description
Stream
Flow Rate
(mVhr)
Sour Water from Claus Unit
Sour Water from Claus Tail
Gas Treatment Unit
Cooling Tower Blowdown
0.2
26
156
Pollutants
of Potential
Concern
H,S
Suspended solids
trace metals
Concentrations
of Major
Pollutants
Varying
Varying
Regeneration Waste
AO
TDS, excess
regenerants
Varying
Surface runoff
Coal Pile Runoff
(30-day wet storage)
Filtrate for Texaco
Gasifier Slag
Disposal
73
254
144
Oil/spilled
products
Trace metals
Dissolved solids
Trace elements
Oil-trace
Varying
Low mg/I
Boiler Blowdown
16
TDS
Low mg/'
Turbine Ejector Condensate &
Miscellaneous
Process Wastewater
69
No data
No data

-------
TABLE 5-22. PROCESSES POTENTIALLY APPLICABLE TO THE TREATMENT OF DIRECT LIQUEFACTION WASTEWATER
Process
Process	Components	Removal	By-Products	Reliability/
Principle	Removed	Efficiency	and Wastes	Sensitivity Chemical Feed
Comments
Removal of Suspended Solids. Tars and Oils
Gravity
Separation
Coagulation/
Flocculation
Air Flotation
Provision of
adequate resi-
dence time in a
quiescent vessel
to allow sus-
pended solids or
immiscible
fluids to sepa-
rate into
1lghter/heavier
than water
phases.
Use of chemical
or other agents
to promote the
coalescence of
fine (collodial)
suspended solids,
tars and oils,
generally used
in conjunction
with a gravity
separation
process.
Induces release
of dissolved
gases which are
entrapped by
suspended
solids, tars
and oils and
subsequently
separated from
the waste as
1 lghter-than-
water material.
Suspended
solids, tars,
oils, grease.
Finely dis-
persed
particles.
Suspended
solids, tars
and oils.
Varies with
design and
operational
conditions,
90+ percent
removal of
TSS achievable.
90+ percent
is achievable.
Highly denend-
ent upon
suspended
material
characteris-
tics and
design, 80 to
99 percent
with chemi-
cals, 40 to
80 percent
without
chemicals.
Scum and sludge Equipment and None
material with
s.g. < or >
wastewater.
Same as gravity
separation.
Scum consisting
of oil and sus-
pended solids,
may al so gen-
erate sludge.
process very
reliable.
Sensitive to
highly variable
flow rates.
Equipment very
rellable.
Sensitive to
change in
sol ids
characteristics
and adverse
hydraulics
causing floe
shear.
Chemical addi-
tion required
for reliable
removal rates,
equipment is
reliable.
Wide range of
commercial
flocculants,
alum, metal
salts.
Same as
coagulation/
flocculation.
Incorporated into
the tar/oil sepa-
ration system design
and the biological
treatment system.
Widely used in this
country in water
treatment for removal
of fine sol ids.
Widely used in
industry and
occasionally used
for municipal
sludge thickening,
appllcable to oily
wastewater from
liquefaction plants.
-Continued-

-------
TABLE 5-22. (cont'd)

Process
Components
Removal
By-Products
Reliability/

Process
Principle
Removed
Efficiency
and Wastes
Sensitivity Chemical Feed
Comments
Removal of Suspended Solids, Tars and Oils (cont'd)
Filtration Passing waste-	Suspended	Depends on
water through	solids, tars	solids charac-
filter medium	and oils,	tenstics and
which removes	may remove	chemical pre-
suspended	certain dis-	treatment, 90
materials,	solved	to 99 percent
filter recon-	material with	achievable,
ditioned by	appropriate	may be as low
backwash	filter	as 30 to
removal of	medium.	40 percent,
accumulated
solids.
Filter back-
wash, spent
filter media.
Equipment and
process very
reliable.
Filter media Potential for use
(precoat),
alum and
iron salts
and
commercial
flocculants.
in oil removal
sequence, chemical
precipitation of
heavy metals, and
effluent polishing.
Removal of Volatile Contaminants
PHOSAM-W	Volatile con-
taminants are
stripped and
NH3 absorbed
by phosphate
salts, NH3
recovered,
scrubbed sour
gases to sul-
fur recovery
plant.
Chevron WtfT Volatile con-
taminants are
stripped in two
stages with the
H2S and CO2
removed in the
first stage,
NH3 removed
ana subsequently
recovered in the
second stage.
H?S, NH3,
HCN, C02,
benzene,
pyridine.
HgS.Nth,
HCN, C02,
benzene,
pyridine.
HpS, to 2 mg/1,
CO2 to 10 mg/1,
99 percent of
Nth and HCN,
unknown
removal of
benzene and
pyridine.
99.9 percent
H2S, C02 to
10 mg/1, 99
percent of
NH3 and HCN,
unknown re-
moval of
benzene and
pyridine.
Scrubbed sour
gas containing
H2S, CO2 and
HCN,
99.9 percent
pure NH3
recovered.
Sour gas and
liquid NH3.
95 percent
service
factor.
H3PO4, NaOH
No reliability
values avail-
able. Sensi-
tive to extreme
quantities of
phenol.
None.
Commercially proven
process on similar
wastes with 14
operating plants, some
in service up to
10 years.
Commercially proven in
petroleum refining
operations since 1966.
-Continued-

-------
TABLE 5-22. (cont'd)

Process
Components
Removal
By-Products
Rellabi11ty/


Process
Principle
Removed
Efficiency
and Uastes
Sensitivity
Chemical Feed
Comments
Removal of Bulk Orgamcs






Phenosolvan
Phenol is solvent
Phenollcs,
99.5 percent of
Recovered
No reliability
Phemsol
Commercially proven in

extracted from
other
monohydric
phenol.
data available.
(proprietary
coke-oven industry with

waste and re-
orgamcs.
phenols, 60 per-


sol vent).
first plant installed

covered from the

cent of poly-



in 1940.

solvent by

hydric phenols,





solvent

15 percent of





distillation.

other orgamcs.




Chem-Pro
Same basic
Phenol ics,
99.8 percent of
Phenol
High relia-
Proprietary
Several commercial

process princi-
other
monohydric
recovered.
bility. Can
solvent.
applications in phenol

pals as pheno-
orgamcs.
phenols, 95

treat wastes

formaldehyde resin

solvan with

percent of

containing

manufacturing plants.

equipment

dihydric

phenol from

First application in

variations.

phenols, 90-

a few mg/1

1961 to recover phenols



95 percent of

to 8 percent.

from coke-oven waste



trihydric



11quors.



phenols,







50 percent of







other orgamcs.




Rohm & Haas
Combines stripp-
h2s, nh3,
90 percent of
Sour gas,
Rellabi1lty of
Acetone
Only two commercially

ing of volatiles,
HCN, C02,
NH3, 99.9 per-
product aqua
latest design

operating plants. One

NHj recovery,
phenolics,
cent of H2S
amnion 1 a,
not yet demon-

refinement to the resin

and resin
other
and C02, all
product
strated.

absorption operation (the

absorption of
orgamcs.
orgamcs to
phenol.
Absorption

super loading step) has not

orgamcs with

<20 mg/1, C02

step sensitive

been commercially

resin regenera-

to 10 mg/1,

to NH3 con-

proven.

tion using

99 percent

centrations



acetone. Acetone

Of HCN.

>200 mg/1.


is reused after
distillation
from the
desorbed
orgamcs.
-Continued-

-------
TABLE 5-22. (cont'd)


Process
Components
Removal
By-Products
Reliability/


Process
Principle
Removed
Efficiency
and Wastes
Sensitivity
Chemical Feed
Comments
Removal of Bulk Organics (cont'd)






Wet Air
Thermal oxi-
Organics and
40 to 97 per-
Heat and gases
Equipment down-
Air injection
Developed for pulp
Oxidation
dation of
oxidizable in-
cent depending
including CO2,
time is sig-
and auxiliary
and paper mill in-

organic matter
organics
upon waste
N2 and steam.
nificant,
fuel.
dustry, used sparingly

in the presence
(i.e., H2S).
characteristics
process

for municipal sludge

of water, oxi-
and operating

efficiency

treatment and >100

dation vessel

temperature.

dependent upon

industrial waste treat-

atmosphere

pressure and

uniform flow

ment applications.

ranges from

residence time.

rate and

Potential for destruc-

350 to 610F



operating

tion or partial oxi-

and 350 to



conditions.

dation of phenols

3000 pslg.





and complex organics







to increase







biotreatabil lty.
Biological
Provide an
Organics,
BOD5 at 80 to
Biological
Equipment is
Nutrients for
Biological treatment
Oxidation
environment
nutrients
99+ percent,
solids and
very reliable,
micro-
particularly complete

conductive
such as N,
COD at 50 to
absorbed
process sensi-
organisms.
mix and high purity

to microbial
P, and
95 percent,
metals as
tive to ex-

oxygen, has been

degradation
metals
phenols at
sludge in
treme concen-

successfully applied

of organic
absorbed by
60 to 99+
gravity
trations of

to wide variety of

constituents.
the bio-
percent,
separator
phenol, HH3,

industrial wastes.


logical floe.
thiocyanate
integrated
chloride, and

The most applicable



at 0 to 99
into the
other toxics.

success relative to



percent,
system.


liquefaction wastes



trlocyanate



has been in the



at 0 to 99



coke industry.



percent,







cyanide at 0







to 99 per-







cent, oils







at approxi-







mately 65







percent.




-Continued-

-------
TABLE 5-22. (cont'd)
Process
Process
Princi pie
Components
Removed
Removal
Efficiency
By-Products
and Wastes
Reliability/
Sensitivity
Chemical Feed
Comments
Removal of Residual Orgamcs
Granular
Activated
Carbon
Adsorption
(GAC)
Contact the
wastewater with
the activated
carbon which
absorbs dis-
solved organic
and, to some
extent, in-
organic pol-
lutants.
Waste
normally passed
through a fixed
bed of acti-
vated carbon.
Dissolved
orgamcs,
dissolved
inorganics,
and sus-
pended
sol ids.
Varies between
wastes and
types of
carbon, typi-
cal values
are 80 to
95 percent
COD, 60-70
percent BOD,
90+ percent
phenols, 50
percent
cyanide and
thiocyanate.
Metals with
high sorp-
tion poten-
tial are Sb,
As, Bi, Cr,
Sn, good
potential
are Ag, Hg,
Co, Zr, fair-
to-good
potential are
Pb, Ni, Ti, V,
Fe, low or
unknown are
Cu, Cd, Zn, Be,
Ba, Se, Mo, Hn,
W. Cl2, BR2,
I2 are
strongly sorbed,
halides are
not.
Spent carbon
which may be
disposed or
regenerated.
Modertely
reliable both
mechanically
and opera-
tional ly.
Sensitive to
suspended
solids con-
tent . May
produce
sulfides and
poses cor-
ros1 on
problem.
NaNoi for
sulfide
control, dis-
infectant for
biological
growth
control.
Process has been
used in water treat-
ment for many years,
used in wastewater
treatment for 10-20
years. Potential for
waste polishing after
liquefaction wastes have
been extensively pre-
treated.
-Continued-

-------
TABLE 5-22. (cont'd)
Process
Process
Principle
Components
Removed
Removal
Efficiency
By-Products
and Wastes
Reliability/
Sensitivity
Chemical Feed
Comments
Removal of Residual Orgamcs (cont'd)
Powdered
Activated
Carbon
Adsorption
(PAC)
co
Same process
principle as
granular.
Powered carbon
can be con-
tacted with
the waste in
one of several
treatment
processes in-
cluding
clarifiers,
primary or
secondary, and
activated
sludge aeration
basins.
Dissolved Same as GAC. Spent carbon Reasonably	Polymer to Few existing mstal-
organics and	sludge which reliable and improve	1 at ions, however
inorganics.	may be dis- would likely solids	systems have effect-
posed or	improve	capture in lvely reduced priority
regenerated. activated	clarifier. pollutants. Process
sludge	will generate larger
reliability.	quantities of sludge
and should be followed
by filtration. Potent-
ial ly applicable
biological treatment
of liquefaction
wastes.
Ozonation
Dissolution of
ozone into the
wastewater con-
tained in a
contact vessel
oxidizes waste
constituents.
Organlcs and
some
inorganics
and metals.
Varies drasti-
cally with
waste strnegth
and con-
stituents,
COD removal
of 85 per-
cent, BOD 0
to 50 per-
cent, phenol
and cyanide
99+ percent
achievable.
Ozone offgas
requires an
ozone de-
struction
unit.
Mechanical and Ozone
process reli-
bility is good,
process success
dependent upon
ozone dosage and
residence time.
Process is a develop-
ing technology.
Economically limited to
relatively weak wastes
(in terms of COD).
Efficiency may be
enhanced with UV light.
May obtain little BOD
reduction but process
breaks down orgamcs to
biodegradable state.
Some potential applica-
tion to liquefaction
wastes as GAC.
-Continued-

-------
TABLE 5-22. (cont'd)
Process
Components
Removal
By-Products
Rellability/


Process Principle
Removed
Efficiency
and Wastes
Sensitivity
Chemical Feed
Comments
Removal of Trace Metals






Chemical Increase the
Various
Varies with
Metal hydro-
Equipment and
Lime, com-
Process has been used
Precipitation pH of the waste
metals and
complexity of
xide sludge
process is
mercial
for many years by in-
to form in-
some anions
metal content.
from clarifier.
reliable.
coagulants.
dustry. Disadvantages
soluble metal
if 1tme used.
final pH and

sensitive to

include large sludge
hydroxides and

influent con-

maintaining

volume for disposal.
oxides which

centrations,

appropriate

Potential applicability
are removed by

most reduced

pH and floe

as bulk organics removal
sedimentation

to <1 mg/1.

shear due to

effluent polishing and
and filtration,



hydraulics.

also prepares waste for
pH range of





residual organics
10-12 normal.





removal.
Removal of Dissolved Solids
Forced
Evaporation
Expose waste-
water to heat
and vaporize
water portion
which serves
to concentrate
contaminants
in the remain-
ing brine.
Dissolved and
suspended in-
organic
solids and
various
dissolved
organics.
90-98 percent
water recovery,
<10 mg/1 TDS
in product
water.
Brine at 2 to
10 percent of
feed volume.
Rel l able with
special ma-
terials of
construction.
Process reli-
ability
sensitive to
pH.
Acid for pH
adjustment.
Process is a proven
method of concentrating
dissolved solids.
Potentially applicable
to preparing pretreated
liquefaction wastes for
cooling tower inake-up,
for discharge, or for
desalting cooling tower
blowdown for reuse or
discharge.
-Continued-

-------
1.	Discharge to surface waters;
2.	Subsurface discharge via deep well injection;
3.	Surface impoundment in an evaporation pond (feasible in
the western U.S. only);
4.	Co-disposal with gasifier/boiler ash.
The disposal alternatives listed above are not intended to represent different
levels of control, but rather fundamentally different disposal approaches.
Any of these approaches may be feasible alternatives for use at a given site
depending on factors such as the availability of land, net evaporation rates,
groundwater reservoir characteristics, and surface discharge restrictions.
Some of the important factors which will determine the acceptability of these
various approaches are summarized in Table 5-23. For each alternative, there
will be a number of treatment approaches which can be followed, depending on
the characteristics of the specific waste streams as well as site-specific
factors. These disposal alternatives are not all inclusive. Other alterna-
tives such as agricultural land application or mine reclamation may also be
considered on a site-specific basis. However, sufficient data are not avail-
able to address these other disposal alternatives in this document. Disposal
of hazardous liquid residues in lined drums or other containers is not con-
sidered due to recent RCRA guidelines which prohibit this practice.
Figure 5-6 presents the treatment options considered for the process
wastewater streams for each of the four ultimate disposal alternatives listed
above. Figure 5-7 shows the control options for nonprocess wastewater streams
which have low flow or low concentrations of contaminants. The selection of
these options are based upon the available information on cost, commercially
demonstrated performance on other industrial wastes, level of control as com-
pared to alternative processes, and the existing conceptual designs generated
by the SRC-II developer.
5.3.1 Treatment of process wastewater and related streams
Wastewater management concerns in SRC-II facilities will be dominated
by the treatment, disposal and reuse of the wastewaters generated from coal
dissolution, product separation/upgrading, and liquefaction residue gasifi-
cation operations. The wastewater treatment strategies and the economic and
energy impacts developed in this document all assume that to take advantage
120

-------
TA3LE 5-23. JISPOSAL OPTIONS FOR TREATED WASTEWATERS DISCHARGED
FROM SRC-II DIRECT LIQUEFACTION FACILITIES
This cable addresses four fundamentally different alternatives for disposing of the aqueous
waste streams generated in SRC-II direct liquefaction facilities.
The relative merits of these alternative disposal methods will be determined by a variety of
design and site-specific factors. Therefore, from a guidance standpoint, it is not possible to
select a "preferred" disposal alternative for all cases. Rather, the alternatives listed below
should all be evaluated as candidates for use at any given site.
Alternative
Discussion
1. Discharge to Surface Waters
Note: The use of this
alternative requires
an NPDES permit
2. Deep Well Injection
Note: The use of this
alternative requires a
RCRA or SDWA permit
Factors potentially limiting the use of this alternative:
-	Receiving water body (RWB) used as drinking water source
-	RWB contacts underground source of drinking water (USDW)
-	Low RWB flow
-	RWB is "water quality limited"
-	Discharge contains known carcinogens, toxic compounds, or
priority pollutants
Factors potentially limiting the use of this alternative:
-	All accessible aquifers are potential USDWs or are in
hydraulic contact with potential USDWs
-	Stream to be injected contains high concentrations of
carcinogens, toxic compounds, or priority pollutants
-	Volume of stream to be injected is high relative to the
capacity of the receiving aquifer
3. Surface Impoundment
Note: The use of this
alternative requires a
RCRA permit
Factors potentially limiting the use of this alternative:
-	Lack of sufficient land area suitable (under RCRA
criteria) for use as disposal site
-	Negative or low net evaporation rates at the disposal site
(this alternative will be technically and economically
feasible only in certain areas of the Western U.S.)
4. Co-disposal with Ash*
Note: The use of this
alternative requires a
RCRA permit (for disposal
of the quenched ash)
Factors potentially limiting the use of this alternative:
-	Low ash production rates (not enough ash to consume all
available wastewater)
-	The presence of wastewater components (e.g., organics,
priority pollutants and trace metals) which could cause
an otherwise nonhazardous material (ash) to be rendered
has-ardous, particularly if the availability of land area
suitable for use as a hazardous waste disposal site is
limited
* In this context, ash refers to the solid residue from any combustion/gasification process.
The gasifiers and on-site coal-fired steam/power boilers will be the major sources of ash in
a SRC-II direct liquefaction facility.
121

-------
-SUftFACE DI5Q1ABCE
•SOUJtVATES FROM TAIL CAS TREATKEWT
Figure 5-6.
Control options for
direct liquefaction
process wastewater from SRC-II
facilities

-------
COAL PILE RUNOFF—fcl02
DEMINERALIZATION
REGENERATION WASTE
CHEMICAL
TREATMENT
-RESUE AS ASH QUENCH WATER
-TO SURFACE WATER
SURFACE
RUNOFF
TURBINE
REJLU'OR
CONDENSAT
MISCELLANEOUS
PROCESS
WASTE
l^-i w-
OUS
REMOVAL
COOLING TOWER
BLOWDOWN
CHEMICAL
TREATMENT
CHEMICAL
TREATMENT
CARBON
ADSORPTION
SURFAPE IMPOUNDMENT.
DEEP WELL INJECTION
TO SURFACE WATER
TO COOLING TOWER
•TO SURFACE WATER
BOILER BLOWDOWN
ADJUSTMENT
TO BOILER FEED WATER
TREATMENT SYSTEM
~SURFACE WATER
FILTRATE FROM,
GASIFIER SLAG DISPOSAL^
^REUSE AS QUENCH WATER
CHEMICAL

TREATMENT

-SURFACE WATER
Figure 5-7. Control Options for Small Volume, Nonprocess Wastestreams

-------
of the economies of scale of a large, fully integrated wastewater treatment
facility, these wastestreams will be combined at appropriate points for treat-
ment. The following sections discuss the control options considered for
each wastestream.
Stream A
As shown in Figure 5-6, in all options considered stream A would first
go through a solvent-extraction unit (Phenosolvan) for phenol recovery and
the dephenolized effluent would then be blended with the sour waters from the
gasification operation, sulfur recovery and tailgas treatment units; the com-
bined stream would then pass through a stream stripping unit (Phosam-W) for
removal of ammonia and other dissolved inorganic gases. The stripper bottoms
would then be routed to the biological treatment (high purity oxygen activated
sludge) unit.
The need for the phenol extraction and ammonia stripping units ahead of
the biological treatment unit is apparent. The phenol, ammonia and other dis-
solved gases (mainly H^S) levels in the raw stream A would be toxic to the
biota, or at least would render the bio-treatment unit extremely vulnerable
to upset. In addition, recovered ammonia is a valuable by-product and re-
covered phenol can be used as fuel if not for resale/reuse; this would reduce
the overall operating costs. The optimum sequencing for the phenol extraction
and ammonia stripping processes cannot be assessed without detailed process
information. However, it is believed that either placing the extraction unit
before the stripping unit, or vice versa can achieve comparable performances
with minor changes in equipment designs. The dephenolized and stripped waste-
water still contains significant amounts of biodegradable organics; biological
oxidation would be the most economical and efficient process to remove these.
Ammonia Scrubber Outlet Water, Purge Waste from Gasifier
These wastewaters will contain relatively high levels of dissolved gases
(ammonia, hydrogen sulfide and carbon dioxide), some formates and other in-
organics. These streams are assumed to be blended with stream A ahead of
the stripping unit for treatment/disposal.
124

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Sour Waters from Claus and Tail gas Treatment
These wastewaters contain mainly dissolved gases and some hydrocarbons.
It is believed most of these can be steam stripped from the wastewater. For
the options considered, these streams are combined with stream A ahead of the
stripping unit for treatment/disposal. Other alternatives would be to incin-
erate this stream or route these streams to a separate stripper, with the
stripper bottom combining with stream A after the biotreatment for further
treatment/disposal. Nevertheless because of the relatively small volume of
these streams and for simplicity purpose, only the first alternative (com-
bine with stream A ahead of stripping) is considered.
Disposal Alternatives/Control Options for Process Wastewaters
Figure 5-6 summarized the treatment steps associated with each of the
control option schemes for the four major disposal alternatives. The anti-
cipated concentrations of pollutants of concerns for the blended wastewater
component concentrations at various points in the proposed treatment schemes
are presented in Table 5-24. The concentrations shown present the best avail-
able information for the Powhatan coal examined in this document.
For all options considered, solvent extraction, steam stripping and bio-
logical treatment serve 'as the "core treatment" steps for the process waste-
waters. Depending on site specific conditions other treatments would be re-
quired before ultimate disposal.
Surface Waters (Disposal Alternative 1)
Under this disposal alternative, Option II would allow discharge after
biotreatment while Option I would require additional chemical treatment and
filtration for heavy metals removal and activated carbon adsorption as a
polishing step for residual organics removal. The biological oxidation pro-
cess effluent (stream E) and the activated carbon adsorption effluent (stream
G) compositions shown in Table 5-24 were used as the basis for developing
numerical guidance for these two options. The concentrations shown in Table
5-24 were based upon (1) limited data on the individual wastestreams from one
type of coal (Powhatan No. 5), (2) performance data for applying the indicated
technologies to treating wastewaters with similar characteristics, and (3)
treatability model predictions. Although this approach already incorporates
125

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TABLE 5-24. WASTEWATER TREATMENT INFLUENT AND EFFLUENT CHARACTERISTICS





Stream
Concentration (out/l)







Parameters
A
B
C
D
E
F
G
H

I
J
K
TOC
15,400
12,300
8,140
8,140
4,000

200
49
590
7,<
*00
0 7
COD
46,400
36,600
24,100
24,100
12,000
-
1,200
290
3,480
A3,:
500
4
Polynuclear Aromatic
Hydrocarbons (PAH's)
9
-
-
0 9
0 5
-
0.
.05
0
01
0
12
1
5
0 001
Total Phenols
3,980
200
130
130
1 3
-
0
01
0
002
0
03
0
4
<0 001
Chloronethane
27
-
-
0 05
0 005
-
0
005
0
001
0
012
0
15
<0 001
Benzene
24
-
-
0.05
0 02
-
0
002
0
0005
0
006
0
08
<0 001
Toluene
65
-
-
0 05
0 02
-
0
002
0
0005
0
006
0
08
<0 001
Ethylbenzene
12
-
-
0 05
0.01
-
0
001
0
0002
0
002
0
03
<0 001
Nitrobenzene
3
-
-
0 05
0 05
-
0
005
0
001
0
012
0
15
<0 001
1 - 2 - Dlchloroethylene
2
-
-
0 05
0 05
-
0
005
0
001
0
012
0
15
<0 001
CN"
-
-
2 78
0 03
0 02
0 02
0
02
0
0C1
0
01
0
1
<0 001
h2s
54,500
-
36,800
2
0
0

0

0

0

0
0
nh3
16,200
-
11,100
200
100
100
100
24
290
3,1
600
36
Cr
0 12
-
-
-
0 06
0 006
0
006

-
0
02
0
25
0 25
Se
1.31
-
-
-
0 66
0 07
0
07

-
0
2
2
5
2 5
Hg
0 16
-
-
-
0 08
0 008
0
008

-
0
02
0
25
0 25
Legends (See also Figure 5-6)
A	Raw stream A
B	Solvent extraction effluent
C	Blended wastewater
D	Steam stripping effluent
E	Biological oxidation effluent
F	Chemical precipitation effluent
G	Activated carbon effluent
H	Blended cooling tower makeup
I	Cooling tower blovdovn
J	Forced evaporator brine
K	incinerator scrubber blowdown

-------
the best available information, many of the factors (such as impact of differ-
ences in raw wastewater characteristics due to different feed coal, synergistic
effects of treating combined wastes, etc.) had not and cannot be addressed due
to the lack of data. Thus, numerical guidance limits presented should be view-
ed as target values. In a situation where these levels cannot be achieved,
there should be a good faith effort on the part of the plant owner/operator
to achieve discharge rates consistent with the intent of the guidance.
Option I is the preferred option. This recommendation is made on the basis
of the benefits (i.e., reduction in pollutants discharged) which are anticipa-
ted from the additional treatments compared to its incremental cost. Also,
although the use of holding ponds upstream of the biological oxidation unit
(to dampen influent composition and flow fluctuations) is assumed to be an in-
tegral part of the system, the inclusion of activated carbon, as specified in
Option I technologies, will provide some protection in the event of biological
process upsets.
Disposal Alternative 2 - Deep Well Injection
This is essentially a "zero discharge" alternative with the objective of
maximizing water reuse and/or disposing a difficult to treat, highly contamina-
ted stream. It is assumed that the treated process wastewaters will undergo
forced evaporation with the concentrated brine to be disposed to deep wells.
For technical (mechanical) reasons rather than environmental reasons it is as-
sumed that incineration will be required to destroy the organics to prevent
well formation pluggage.
Volume reduction prior to forced evaporation or incineration will be much
more attractive economically than the direct evaporation or incineration of
the subject wastes. One potentially attractive method of accomplishing this
volume reduction function is to use the plant's cooling water system. In this
case, the wastewater would be used as cooling tower makeup and cooling tower
blowdown would be used as feed to an additional forced evaporator upstream of
the incinerator. With this type of treatment scheme, minimizing undesirable
air emissions from the cooling tower due to the air stripping of volatiles
from the wastewater or cooling tower drift carryover is a key environmental
concern.
127

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The guidance options for this disposal alternative calls for different
wastewater treatment to minimize air emissions from the cooling tower. Under
Option II, the use of treated process wastewaters for cooling tower makeup is
allowed once volatile acid gases, ammonia, and organics have been removed by
steam stripping, solvent extraction and biological oxidation or their equiva-
lents. The cooling tower makeup water specifications under Option II are
TOC = 4000 mg/n, NH^ = 100 mg/£., PAH's = 0.5 mg/£ and total Phenols = 2 mg/Ji.
As shown in Table 5-24, these levels are consistent with the expected charac-
teristics of biological oxidation process effluent. The guidance for Option I
calls for an additional reduction of 95% TOC, consistent with the expected ef-
fluents from the activated carbon column: TOC = 200 mg/i., NH^ = 100 mg/i,,
PAH's = 0.05 mg/i,, and total phenols = 0.01 mg/&.
The guidance for both control options specifies that RCRA and SDWA cri-
teria for the operation of a waste injection well will be met. One of those
criteria is that the incinerated brines can only be injected into a Class I
well. Class I injection wells are those discharging below all potential un-
derground sources of drinking water. Option 1 is the preferred option. This
recommendation is based upon the benefits (i.e., reduction in air emission)
which are anticipated from the additional treatments compared to the incremen-
tal cost.
Disposal Alternative 3 - Surface Impoundment
This is a viable ultimate disposal alternative only for southwestern U.S.
plants where there are high net evaporation rates. The environmental issues
involved in developing guidance for this alternative are very similar to those
addressed in the deep well injection case. Vlastewater concentration in the
plant's cooling water system is favored because of the high costs of lined
evaporation ponds. The options considered and the guidance specifications
developed are the same as those for the deep well injection case. Option I
is the preferred option.
Disposal Alternative 4 - Co-Disposal with Ash/Slag
This is a "zero discharge" alternative using the concentrated brine (from
wastewater treatment/volume reduction) as gasifier ash quench makeup. Option II
128

-------
guidance is based upon the use of the core treatments, chemical treatment,
activated carbon, cooling tower and forced evaporator; Option I guidance calls
for incinerating the brine from the forced evaporator before disposal.
The central issue distinguishing the Option I and Option II guidance for
this disposal alternative is different than that addresses previously for
deep well injection and surface impoundment. With the deep well injection and
surface impoundment cases, the Option I versus Option II guidance addressed a
water treatment cost versus an air quality impact tradeoff. With ultimate
Disposal Alternative 4, the central issue distinguishing the two options re-
volves around a water treatment versus solid waste disposal tradeoff. Option
I requires incineration of the concentrated gas liquor. In this case, it is
presumed that the resulting quenched ash would be non-hazardous. Control
Option II allows the use of unincinerated gas liquor as ash quench makeup. In
this case, the resulting mixture is presumed to be hazardous due to the pre-
sence of residual organics in the wastewater. Option I will have higher waste-
water treatment costs and lower solid waste disposal costs. Option II will
have lower wastewater treatment costs but higher solid waste disposal costs.
From a guidance standpoint, the Agency prefers the Option I approach since
this will avoid problems associated with the handling/disposal of a high vol-
ume hazardous waste. The plant designer, however, should make a site-specific
assessment of the tradeoffs between extensive treatment of plant wastewaters
with subsequent handling of the quenched ash as a non-hazardous waste (Option
I) versus minimal wastewater treatment with quenched ash disposal as a hazard-
ous waste (Option II). In cases where Option I water treatment costs would
be prohibitive and a suitable hazardous waste disposal site is available, an
Option II approach may be allowed.
Costs and Energy Impacts of Controls for Major Process and Related
Wastestreams
Estimated total capital investments, annualized costs and energy impacts
for the various process and related wastewater treatment processes and dis-
posal alternatives are presented in Table 5-25. Although cooling tower use
is included as a volume reduction for all options considered under Disposal
Alternatives 2, 3 and 4, the costs and energy impacts associated with this
usage are considered as part of the base plant costs and are not included in
129

-------
TABLE 5-25. CAPITAL INVESTMENTS, ANNUALIZED COSTS ADD ENERGY IMPACTS OF
TPF»T"E!!T PROCESSES FOR MAJOR PROCESS WASTEWATERS
POWHATAN #5 COAL
Disposal
Alternative
Treatment	% of Base Plant
Process	Capital Cost
Option I Option II
51 of Base Plant
Annualized Cost
Option I Option II
% of Base Plant
Energy Input
Option I Option II
1 Surface
Discharge
2 Deep
Well
Injection
3 Surface
Impoundment
4. Co-Oisposal
With Ash
Phenol Extraction
Steam Stripping
Biological Oxidation
Chemical Precipitation
Carbon Adsorption
Phenol Extraction
Steam Stripping
Biological Oxidation
Chemical Precipitation
Carbon Adsorption
Cooling Tower
Forced Evaporation
Incineration
Deep Well Injection
Phenol Extraction
Steam Stripping
Biological Oxidation
Chemical Precipitation
Carbon Adsorption
Cooling Tower
Surface Impoundment
Phenol Extraction
Steam Stripping
Biological Oxidation
Chemical Precipitation
Carbon Adsorption
Cooling Tower
Forced Evaporation'
Incineration
Co-Disposal with Ash
0 36
0 36
0 46
0 46
0.14
0 14
0 24
0.24
0 02
0 02
0 50
0 50
0 46
0 46
0 60
0 60
0 05
0 05
0.16
.
0 18
-
<0 01
-
0 10
-
1 83
-
0 43
-
1.32
1 06
3 09
1 08
1 12
0 69
0 36
0 36
0 46
0 46
0 14
0.14
0 24
0 24
0 02
0 02
0 50
0 50
0 46
0 46
0 60
0 60
0 05
0 05
0 16
.
0 18
-
<0 01
-
0 10
-
1 83
-
0.43
¦
*
+
*
*
*
*
0.18
0 18
1 83
1 83
1 59
1 59
0.15
0 15
0 34
0 34
0 18
0 18
0.06
0.06
0 03
0 03
<0 01
<0 01
1.71
1 45
3 46
3 28
2.89
2.46
0 36
0 36
0 46
0 46
0 14
0 14
0 24
0 24
0 02
0.02
0 50
0 50
0 46
0 46
0 60
0 60
0 05
0 05
0.16
.
0 18
-
<0 01
-
0 10
_
1 83
-
0 43
-
*
*
*
*
*
*
0 44
0 44
0 27
0 27
<0 01
<0.01
1 76
1 50
3 36
1.35
1.12
0.69
0.36
0 36
0 46
0 46
0 14
0.14
0.24
0 24
0 02
0.02
0.50
0 50
0 46
0 46
0 60
0 60
0.05
0 05
0 16
0 16
0 18
0.18
<0.01
<0 01
0.10
0 10
1 .83
1 83
0 43
0 43
*
*
*
*
+
*
0.18
0.18
1 83
1 83
1 59
1 59
0.15
.
0.34
-
0.18
-
tt
tt
tt
+t
tt
tt
1.65
1 50
5.26
4 92
2.89
2.71
*Cooling tower costs and energy impacts which are assumed to be part of the base plant costs are not Included
tCredits for the recovered water are not included 1n this cost estimate.
^Cost and energy for disposal with ash which Is considered as part of the ash disposal operation is not included
130

-------
Table 5-25. Likewise, the ultimate disposal of the concentrated brine with
ash/slag, as considered in Disposal Alternative 4, is considered as part of
the ash disposal operation; the costs and energy impacts for this is also not
included in Table 5-25.
For the surface discharge case (Disposal Alternative 1) the preferred op-
tion (Option I) adds an additional 0.26 percent to the base plant capital in-
vestment, 2 percent to the base plant annualized cost and 0.43% to the base
plant energy input compared to Option II. This level of control represents an
increase of 30% in capital cost and 200% in annualized cost when compared to
the Option II costs. The significantly higher annualized cost for Option I
is due primarily to the high supplemental carbon requirements and the carbon
regeneration cost. The approximate 37% increase in energy requirement is due
to the carbon regeneration operation.
In addition to the treatment processes considered in the surface dis-
charge case, forced evaporation and incineration are included for the deep
well injection case (Disposal Alternative 2). These two processes are esti-
mated to increase the base plant capital and annualized costs by 0.33 percent
and 2.17 percent, respectively. Both processes are highly energy intensive;
an increased use of 1.77% of the base plant energy input is anticipated, which
amounts to more than the total energy required by the Disposal Alternative 1
processes.
For the surface impoundment case, a solar evaporation pond is used for
the ultimate disposal of the treated wastewater. As compared to the forced
evaporator cost, surface impoundment (solar evaporation pond) has higher capi-
tal cost (about 3 times) but much lower annualized cost (about 15%). Also,
incineration is no longer required, and this also reduces further the total
cost and energy impact for this alternative. The total energy requirements
for this Disposal Alternative is about the same as the Alternative 1 require-
ment and is about 39% of both Alternative 2 and 4 requirements.
For the co-disposal with ash/slag alternative, the use of an incinerator
prior to ash quenching increases wastewater treatment cost by 0.2% and 0.3%
of the base plant capital and annualized costs respectively. Based upon this
131

-------
low relative cost, the use of incinerated process wastewater as ash quench
water (to maintain the nonhazardous classification for quench ash) may be
economically attractive relative to the cost of disposing of the ash as a
hazardous waste (with unincinerated process wastewater as quench water).
Of the four disposal alternatives addressed, the surface discharge case
(Disposal Alternative 1) appears to have the lowest costs and energy
impact. However the feasibility and costs for each of these alternatives will
depend upon numerous site-specific factors such as the availability and cost
of raw water, local net evaporation rates, groundwater reservoir characteris-
tics, and surface/subsurface discharge restrictions. The availability, cost
and suitability of land for evaporation pond construction in particular will
have a large effect on the viability of Disposal Alternative 3. Similarly,
tight restriction on surface/subsurface discharges, either due to technical
(mechanical) or environmental considerations, would affect greatly the Disposal
Alternative 2 and 4 economic trade-offs for many sites. Considering the econo-
mic and environmental implications of these tradeoffs, no one disposal alter-
native can be recommended without a careful evaluation of site-specific condi-
ti ons.
5.3.2 Treatment of Small Volume, Nonprocess Wastewater Streams
Figure 5-7 summarized the control options evaluated for the nonprocess
wastewater streams which have low flow or low concentrations of contaminants
from SRC-II facilities. The Option I guidance for these streams calls for no
direct discharge from the plant. With the exception of cooling tower blowdown,
all these waste streams can be treated and re-used either as ash quench water,
cooling tower makeup water or be recovered as boiler feed water. The Option I
control for cooling tower blowdown calls for deep well injection or surface
impoundment as the ultimate disposal methods.
The Option II control technologies for the coal file runoff, demineraliza-
tion regeneration waste, boiler blowdown, cooling tower blowdown and filtrates
from gasifier slag disposal include chemical precipitation, sedimentation and
pH adjustments. The guidance for these streams call for meeting the BPT limits
for the electric power generation stations. The turbine ejector condensate,
surface runoff and miscellaneous process wastewaters, may be contaminated with
132

-------
spilled products or contain significantly high organics. The inclusion of acti-
vated carbon in the control option would minimize the total organics discharged
to surface waters.
5.3.3	Guidance Summary
Tables 5-26 and 5-27 summarize the guidance options, the treatment tech-
nologies which provided the basis for the analysis of these options in the
baseline plants and the estimated cost impacts of treating the aqueous waste
streams generated in a fully generated, SRC-II direct liquefaction facility.
These tables summarize, on a stream-by-stream basis, all of the control options
and ultimate disposal alternatives described previously. Guidance for waste
streams unique to SRC-II facilities (e.g., stream A) is summarized in Table
5-26. The guidance for waste streams similar to streams for which regulations
already exist is summarized in Table 5-27.
5.3.4	Treated Wastewater Characteristics
A summary of the treated flow and composition from each of the control al-
ternatives for the major process and related streams is presented in Table
5-28. The mass flow and composition numbers shown are computed as a function
of total energy input to the plant. The wastewater streams presented are those
being discharged (Disposal Alternative 1) or those requiring final disposal
(Disposal Alternatives 2 through 4) after treatment, as were shown in Figure
5-6.
With Disposal Alternative 1, discharge to surface water, there is no sig-
nificant volume reduction occurring in the treatment processes. Comparison
of the control options indicates that the addition of chemical precipitation,
filtration, and activated carbon adsorption to the biological oxidation treat-
ment effluent results in an additional 95 percent reduction in total organic
carbon and priority pollutants, and a 99 percent reduction in phenols. The
most significant effect of the Option I approach is the reduction of organic
compounds. The quantities of hazardous solid wastes generated by the two con-
trol levels are not significantly different because 95 percent of the hazard-
ous wastes are associated with the biological oxidation treatment sludge which
is common to both options. Chemical treatment sludges account for the other
hazardous waste produced under Option I.
133

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TABLE 5-26. GUIDANCE FOR WASTEWATER STREAMS UNIQUE TO SRC-II DIRECT LIQUEFACTION FACILITIES
	Control Guidance
Stream and (Stream No.)	Pollutants	Option I	Option II	Discussion
Sour Mater from Recycle
Gas DEA Treating and
Compression (1208)
Cryo Knockout water
from Hydrogen
Recovery (1210)
Sour Water from Low
Pressure Gas Preparation
(3102)
Sour Water from Atmos-
pheric Fractionation (3405)
Sour Water from
Debutanizer (3407)
Sour Water from Vacuum
Flash (3415)
Sour Water from Coal
Slurry Mix Tank (1103)
Sour Water from H P
Cooling of Dissolver
vapor (1112)
Sour Water from L P
Cooling of Dissolver
Vapor (1117)
PH
TSS
TOC
COD
PAH
Total Phenols
CN"
NH3
Cr
Se
Hg
DISPOSAL ALTERNATIVE 1
Guidance
The combined wastes dis-
charged to surface waters
should not exceed the
following pH, concentra-
tion, and mass.
6-9
rog/fc	Kg/TJ
10
200
1200
0.05
0.05
0.2
100
0.05
0 05
0 006
Technology Basis
Solvent extraction
Steam stripping
Biological oxidation
Chemical precipitation
Carbon adsorption
Cos* *
Capital* 1.32Z
Annualized 3 09Z
DISCHARGE TO SURFACE WATERS
Guidance
The combined wastes dis-
charged to surface waters
should not exceed the
following.
6-9
og/t	Kg/TJ
30
4000
12000
0.5
0.5
0.2
100
0.05
0 5
0.06
Technology Basis
Solvent extraction
Steam stripping
Biological oxidation
Cost *
Capital	1 062
Annualized 1.08Z
Ttiese waste streams are assumed to be
blended together for treatment because or
their expected similarity in characteristics
and treatment requirements. Hie blended
waste stream is designated as stream A.
Option I includes chemical precipitation
(for heavy metal removal) and carbon
adsorption (as a polishing setp for residual
organics removal) in addition to the treat-
ment processes called for in Option II
All numerical guidance is based upon the
performances of applying the indicated
technologies to treating wastewaters with
similar characteristics There is currently
no data on the actual performance of treat-
ing these wastes Due to the inherent
limitations in this approach, these target
levels may be difficult to achieve in all
cases. In a situation where this may occur,
there should be a good faith effort on the
part of the plant owner/operator to achieve
discharge rates consistent with the intent
of this guidance.
Factors supporting the use of Option I
controls•
-	Chemical precipitation will reduce priority
pollutant trace element discharges
-	The use of carbon adsorption will (1) reduce
organic levels in the effluent, >ind (2)
provide a margin of protection against high
organics discharges in the event of upsets
in the biological process
Factors supporting the use of Option II
controls
- Lower costs
•As percent of uncontrolled base plant cost Ranges reflect the impacts of different coal types.

-------
TABLE 5-26. (Continued)
Control Guidance
Stream and (Stream No )
Pollutants
Option I
Option II
Discussion
CO
en
Sour Water from Recycle
Gas DEA Treating and
Compression (1208)
Cryo Knockout Water
from Hydrogen
Recovery (1210)
Sour Water from Low
Pressure Gas Preparation
(3102)
Sour Water from Atmos-
pheric Fractionation (3405)
Sour Water from
Debutanizer (3407)
Sour Water from Vacuum
Flash (3415)
Sour Water from Coal
Slurry Mix Tank (1103)
Sour Water from H P
Cooling of Dissolver
Vapor (1112)
Sour Water from L P
Cooling of Dissolver
Vapor (1117)
Volatile organics,
acid gases, and NH3
are the main concerns
with this treatment/
disposal alternatives
T0C
NII3
CN-, S"
DISPOSAL ALTERNATIVE 2 - DEEP WELL INJECTION
Guidance	Guidance
Well operation to be
consistent with guide-
lines specified in 40
CFR 122/146/264 (see
Table 3-4)
Class T wells only
Cooling tower makeup
water composition limited
to
200 mg/t TOC
100 mgll
5 mg/t (each)
Technology Basis
Solvent extraction
Steam stripping
Biological oxidation
Forced evaporation in a
"closed" system
Incineration
Use of these wastewaters
as cooling tower makeup
not allowed
1.71Z
Annualized	3.462
Well operation to be
consistent with guide-
lines specified in 40
CFR 122/146/264 (see
Table 3-4)
Class I wells only
Cooling tower makeup
water composition limited
to:
4000 mg/t
100 mg/t
5 mg/8. (each)
Technology Basis
Solvent extraction
Steam stripping
Biological oxidation
Cooling tower concentra-
tion
Forced evaporation
Incineration
Cost •+
Capital	1.452
Annualized 3.28X
Class I wolIs arc those discharging below all
potential underground sources of iliinkiru,
water
The direct incineration ot anv ot th«_
waste streams is an acceptable iiluinotc
approach to the pretrcdtmcnt scheme called
for here, howevei, in most cases, a direct
incineration approach would be more expensive
than one involving wastewater volume* roduci i«mi
j>rior to incineration
Tactors supporting the use ol Option II
controls
I»ower cost
rdctors supporting Die use ot" option 1
controls
Lower air emissions with Option I
*As percent of uncontrolled base plant cost Ranges reflect the impacts of different coal types.
^Disposal well costs included Credits for reduced cooling tower makeup water requirements not included under Option II

-------
TABLE 5-26. (Continued)
Stream and (Stream No )
Pollutants
Control Guidance
Option I
Option II
Discussion
DISPOSAL ALTERNATIVE 3 - SURFACE IMPOUNDMENT
CO
cr»
Sour Water from Recycle
Gas DEA Treating and
Compression (1208)
Cryo Knockout Water
from Hydrogen
Recovery (1210)
Sour Water from Low
Pressure Gas Preparation
(3102)
Sour Water from Atmos-
pheric Fractionation (3405)
Sour Water from
Debutanizer (3407)
Sour Water from Vacuum
Flash (3415)
Sour Water from Coal
Slurry Mix Tank (1103)
Sour water from H P
Cooling of Dissolver
Vapor (1113)
Sour Water from L.P
Cooling of Dissolver
Vapor (1117)
Volatile organics
acid gases, and NH3
are the main concerns
with this treatment/
disposal alternative
NH3
CN-, S"
TOC
NH3
CN- S°
Guidance
Impoundments should be
designed and operated
consistent with guidelines
specified in 40 CFR 264
(see Table 3-4)
Pond influent quality
limited to
300 mg/t
5 mg/i
(each)
Guidance
Impoundments should be
designed and operated
consistent with guidelines
specified in 40 CFR 264
(see Table 3-4)
Pond influent quality
limited to
300 mg/*
5 mg/l (each)
Use of these wastewaters
as cooling tower makeup
not allowed
4000 tng/t
100 mq/i
5 mg/i (each)
Technology Basis
Solvent extraction
Steam stripping
Biological oxidation
Use of these wastewaters
as cooling tower makeup
allowed after removing
bulk organics and
volatiles
The temoval of bulk orqamcs ond vol.n il«.-
is required with both options Lo minimise
air emissions from the evaporation |>onc1s
Factors supporting the use of Option II
controls
Lower cost
{•acfors supporting the use of Option I
controls
Lower air emisions with Option I
Cooling tower makeup water Cooling tower makeup water
composition limited to	composition limited to
200 mg/fc
100 mg/fc
5 mg/l (each)
Technology Basis
Solvent extraction
Steam stripping
Annualized
1.76Z
3.36Z
Annualized
1 50*
1 35*
•As percent of uncontrolled base plant cost Ranges reflect the impacts of different coal types and synthesis processes
*Costs of disposal ponds included. Credits for reduced cooling tower makeup water requirements not included under Option II

-------
TABLE 5-26. (Continued)
Stream and (stream No.)
Pollutants
Control Guidance
Option I
Option II
Discuss ion
DISPOSAL ALTERNATIVE 4 - CO-DISPOSAL WITH ASH'
Sour Water from Recycle
Gas DEA Treating and
Compression (1208)
Cryo Knockout Water
from Kydrogen
Recovery (1210)
Sour Water from Low
Pressure Gas Preparation
(3102)
Sour Water from Atmos-
pheric Fractionation (3405)
Sour Water from
Ijsbutamzer (3407)
Sour Water from Vacuum
Flash (3415)
Sour Water from Coal
Slurry Mix Tank (1103)
Sour Water from H P
Cooling of Dissolver
Vapor (1113)
Sour Water from L.P.
Cooling of Dissolver
Vapor (1117)
Volatile and
refractory organics,
acid gases, and NH3
are the main concerns
with this treatment/
disposal alternative
TOC
CN and S"
Ash quench system makeup
water quality limited to
50 mg/e
Disposal of quenched ash
as nonhazardolis waste
If cooling tower water is
used as ash quench cooling
tower makeup water com-
position limited to
200 mg/t
100 mg/l
5 mg/2 (each)
Technology Basis
Solvent extraction
Steam stripping
Biological oxidation
Cooling tower
concen t ra tion
Forced evaporation
Incineration
Cost
**
Capital
Annuallzed
1 65*
5.26%
Ash quench system makeup
water quality limited to
Not specified
Disposal of quenched ash
as hazardous waste
Cooling tower makeup water
composition limited to
200 mg/f
100 mq/l
5 mg/2
(each)
Technology Basis
Solvent extraction
Steam stripping
Biological oxidation
Cooling Lower
concentration
Forced evaporation
Cost **
Capital	1 50%
Annualized 4 927,
The ash quench makeup water specification
under Option II requires only the removal of
volatiles (to minimize air emissions from the
disposal site) The specification under
Option I requires wastewater incineration (or
its equivalent) The cooling tower makeup
water specifications are designed to avoid
adverse air impacts when the plant's cooling
water system is used to concentrate these
wastewaters prior to their use as ash quench
makeup
If wastewaters containing high levels of
residual oryaiULb aic iib^d fur jsIi ijii i.< '
makeup it j.3 assumed that the tcsulting
quenched ash stream would have to be
handled as a RLRA	clous wabtu ibuL/^xtLo
C). If the organics in the wastewater are
destroyed by incineration, it is assumed that
the quenched ash would satisfy RCRA criteria
for a nonhazardous waste (Subtitle D)
With Option I, the direct incineration of any
of the subject waste streams in an acceptable
alternative approach to the pretrcatmenL
scheme called for here, however, an inojl
cases, a direct incineration approach «/ould
be more expensive than one involving waste-
water volume reduction prior to incineration
Factors supporting the use of Option 1
controls
-	This option should achieve essentially
complete destruction of the residuaL
organics in the wastewater
-	This option results in the generation of
an assumed nonhazardous solid waste (lower
solid waste disposal costs than Option II)
Factors supporting the use of Option II
controls
- Lower wastewater treatment costs than Option
*As percent of uncontrolled base plant cost Ranges reflect the impacts of different coal types and synthesis processes
+In this context, ash refers to gasifier and coal-fired boiler ash
^Solid waste disposal costs not included.

-------
TABLE 5-26. (Continued)
	Control Guidance	
Stream and (Stream No )	Pollutants	Option I	Option II	Discussion
Sour Water from Claus
(5303)
Sour Water from Claus
Tail Gas Treatment (3306)
Anmoma Scrubber Outlet
Water (2105)
Purge Water from Texaco
Gasifier (2106)
Acid gases, NH3
trace metals,
organics
Guidance
No direct discharge
Technology Basis
Route to steam stripping
section for treatment/
disposal with stream A
Cost:*
included in stream
treatment cost
Guidance
No direct discharge
Technology Basis
Route to steam stripping
section for treatment/
disposal with stream A
Cost *
included in stream A
treatment cost
These waste streams are expected to contain
dissolved gases (e g , NHj) and some hydro-
carbons, but no or low in phenolics. and
are assumed to be blended together with
stream A before the steam stripping section
for treatment
Factors supporting the use of either options
are the same as those for stream A
*As percent of uncontrolled base plant cost Ranges reflect the impacts of different- coal types.

-------

TABLE 5-27.
GUIDANCE FOR WASTEWATER
STREAMS SIMILAR TO THOSE FOR WHICH
REGULATIONS ALREADY EXIST
stream




and

Control
Guidance

(Stream No )
Pollutants
Option I
Opt ion 11
Discussion
Cooling Tower
Suspended and dissolved
Guidance
Guidance
Factors supporting the use of Option 11 controls
Blowdown (5302)
solids, trace elements




and organics derived
No discharge
a) If stream A or B (see
A "no discharge" approach (Option I) will

from makeup water or

Table 5-26 is used as
not be achievable at a reasonable cost in

leaks

cooling tower makeup -
many locations



discharge mass limits




consistent with the
The discharge stream encountered under



Option I guidance in
Option II b would be comparable to the



Table 5-26 for stream A
corresponding stream generated in a steam




electric power plant



b) If raw water or water with




equivalent quality is used




as cooling tower makeup -




steam electric power




generation effluent stan-




dards (BPT) - (Table 3-3)



Technoloqy Basis
Technology Basis



Impoundment or deep
a) See Table 5-26



well injection {with




or without forced
b) Dechlorination pH adjustment



evaporation)
sedimentation



Cost
' Cost




II.a Cost is included as



Capital 0 24\ to 0 44%
part of stream A cost in




Table 5-26



Annualized 0 27\ to
11 b Cost is assumed to be



1 66%
part of based plant cost

Boiler blowdown
Dissolved solids,
Guidance
Guidance
Factors supporting the use of Option I contiols
(5102)
trace elements





No discharge
Steam electric power
Maximum lecycle/ieuso of trejted wastewater



generation effluent standaids
(Option I) snould be encouraged This is a



(BPT) - (Table 3-3)
high quality waste stream




This stream smull and therefore, the treat-




ment cost differential between Options 1 «md




II would be negligible


Technoloqy Basis
Technoloqy Basis



Route to boiler feed
pH adjustment prior to discharge



water treatment system




Cost
Cost



Included in the cost
See discussion



of boiler feedwater




treatment for the




base plant


As rjerc@nt of uncontrolled base plant cost

-------
TABLE 5-27. (Continued)
Stream
and
(Stream No )
Pollutants
Control Guidance
Option 1
Option II
Discussion
Runoff from raw coal
storage/handling
(6102)
Suspended and
dissolved solids,
trace elements, pH
No discharge
Technology Basis
pH adjustment
Sed imert to t ion
Reuse as ash quench,
PGD or raw water
makeup
Cost
Capital
Annualized
0.06Z
0.05Z
Guidance
Coal mining effluent
standards (BPT) -
(Table 3-3)
Technology Basis.
pll adjustment
Sed mentation
Capital	0.06Z
Annualized 0.05Z
Factors supporting the use of Option I controls
The quality of the treated wastewaters from
most coal storage pilc/runoff collection
basins should be good enough to justify its
reuse
This will minimize overall plant makeup
water requirements
Desnineralizer
regeneration
wastewaters (5209)
Dissolved inorganics Guidance
(Na+, SO40),
raw water contain- No discharge
inants
O
Technology Basis
pH adjustment
Sedimentation
Reuse as ash quench or
FCD scrubber makeup
Cost +
Capital
Annualized
0 05Z
0 04Z
Guidance
Steaxa electric power
generation effluent stan-
dards (BPT) - (Table 3-3)
Technology Basis:
pH adjustment
Sedimentation
Capital	0 05Z
Annualized 0.043
Factors supporting the use of Option II controls
- A "no discharge" approach (Option I), while
preferred, will not be achievable at a
reasonable cost in many locations
These wastes will be similar to those produced
in steam-electric power generation facilities
Filtrate from Texaco
Gasifier Slag
Pewatering (6303)
Suspended and
dissolved solids,
trace elements
No discharge
Technology Basis
Closed loop operation
of quench/sluice/
dewatering with reuse
of any excess water
Included in base
plant cost
Guidance
Steam electric power generation
effluent standards (BPT) -
(Sec Table 3-3)
Technology Basis
Sed mentation
pH adjustment
Cost
Included in base plant cost
(these controls arc an
integral part of the ash
handling systems)
Similar to the bottom ashes generated in coal-fired
boilers Closed loop operation with no discharge
is being practiced at some power plants In cases
where this approach is not feasible or cost effec-
tive, guidance consistent with current regulations
for boiler bottom ash sluice systems is proposed
Factors supporting the use of Option I controls
This option minimizes makeup water requirements
Soluble species blovdown requirements can be
satisfied via the water associated with the
disposed wet ash
Factors supporting the use of Option II controls
Soluble species present in some coal ashes may
cause operating problems when closed loop
operation is attempted
'As percent of uncontrolled base plant cost
tRe-uee cost/saving not Included

-------
TABIE 5-27. (Continued)
Stream
and
(Stream No )
Pollutants
Control Guidance
Option I
Option II
Discussion
Turbine ejector con-
densate (8101)
HisceJ 1aneous process
wastewater (8102)
Suspended and
dissolved solids,
trace elements, pH,
organics
oi1 and grease
No direct discharge
Technology Basis
Oil removal
Chemical precipi-
tation
Reuse as cooling
tower, makeup or ash
quench water
Cost
See discussion
Guidance
Steam electric power
generation effluent standards
(BPT) - (Table 3-3)
Technology Basis
pH adjustment
oil iemoval
Chemical precipitation
Carbon adsorption
Cost
See discussion
Factors supporting the use of Option I controls
Treatment criteria for these wastes should
be consistent with those for other process
wastewaters contaminated with organics and
The production rates of those wastewateis
are extremely small when considered on dn
average basis Combination of these waste-
waters with other larger streams foi treuL-
ment and disposal is hicjhLy probable
Because the volumes of these waste streams
will be determined by factors which can only bo
estimated from opetating experience, and because
of Lheir small relative volumes, no delimtive
cost estimates were developed
Runoff from plant
(9101)
Oil/spilled product
suspended solids
PH
Guidance
No direct discharge
Technology Basis
Oil removal
Sedimentation
Carbon adsorption
Reuse as ash quench
water, or cooling tower
makeup if stream is
not contaminated with
spilled products
Guidance
Steam electric power
generation effluent standards
(Table 3-3)
Technology Basis
Oil removal
Sedimen ta tion
Carbon adsorption
pH adjustment
This is an intermittent stream with varying
characteristics and because of their small
relative volumes No definitive cost estimates
were developed
Treatment criteria for these wastes should
be consistent with those for stream A if
contaminated with spills
Factors supporting tlie use of Option I controls
This will minimize plant makeup water requite
merit
Combine with stream A
for treatment if
contaminated with spills
Cost
Sec discussion
See discussion
As percent of uncontrolled base plant cost

-------
TABLE 5-28. DISCHARGE SUMMARY FOR MAJOR PROCESS AND PELATEO WASTESTREAMS
Disposal Alternative Control Option Stream Description Total Stream Total Organic
Discharge Components, Kg/TJ
(No)
Flow Rate
Carbon
Priority Organic
Pollutants
Solid Waste Produced
Phenolics Ammonia Cyanide Hazardous Nonhazardous
Uncontrolled
ro
tu
Surface Discharge
(i)
Deep Mel 1
Injection (2)
Surface
Impoundment (3)
Co-Disposal
with Ash (4)
Option I
Option II
Option I
Option II
Option I
Option II
Option I
Option II
Raw combined	13,900
wastestreams (A)
Raw Ammonia Scrubber
Outlet Hater (2105)
Raw Purge Water
from Gasifier (2106)
Raw Sour Mater from
Claus (3303)
Raw Sour Mater from
Tallgas Treatment
(3306)
Carbon Adsorption
Effluent (G)
Biological Oxidation
Effluent (E)
Brine to Deep Mell (k)
Brine to Deep Mell (k)
Cooling Tower
Blowdown to Pond (i)
Cooling Tower
Blowdown to Pond (I)
144
1 3
37
155
0 04
Brine to Ash
Disposal (K)
Brine to Ash
Disposal (J)
12,200
12,200
330
330
4,200
4,200
330
330
2 4
48
2 4
48
2 4
48
0 0002
2 4
0	0005
0	01
0	0005
0.001
0	0005
0 01
<0 0001
0 0005
0	0001
0	02
0	0001
0	02
0	0001
0 02
<0 0001
0 0001
1 2
1 2
1 2
1 2
1 2
1 2
0	02
1	2
0 0002
0 0002
0 0002
0 0002
0 0002
0 0002
<0 0001
0 0002
199
188
529
518
199
4,388
199
518
0
0
0
0
4.200
0
330

-------
TAB Li. 5-28 (CONTINUED)
Stream arid
(Stream No )
Pollutants
Control Guidance
Option I
Option II
Discussion
Sour Water from
Beavon Unit (1803)
Sour water from
Claus Unit (1811)
Compression and
Shift Condensate
(1502)
Blowdown from GKT
t»at>ifier (1504)
Acid gases, NH^
trace metals
organics
Guidance
No direct discharge
Technology Basis
Route to steam stripping
section for treatment/
disposal with Stream A
Cost *
Included in Stream A
treatment cost
Guidance
No direct discharge
Technology Basis
Route to steam stripping
section for treatment/
disposal with Stream A
Cost *
Included in Stream A
treatment cost
'frcse waste streams are expected to contain
dissolved gases (e g , NHj) and some hydro-
carbons, but no or low in phcnolics, and
are assumed to be blended together with
Stream A before the s>team stripping section
for treatment.
Factors supporting the use of either options
are the same as those for Stream A
H !'	Column Wdt i r
from DBA Unit
(1607)
L P Wash Column Water
from DEA Unit
(1608)
.	Sour Water from
^	Expundcd-Red Hydro-
r\3	cracker U810)
cr
Condensed Oily Organi<
•uidance
Guidance
(¦actors supporting t h<_ uso of opt inn 1
Waste from Hydro-
Nu discharge

controls
gen Purification
No discharge
(2001)


- resource recovery is always desirable from
Technology Basis
Technology Basis
environmental standpoint
Hydrocarbon
Reuse as fuel or
Route to solvent extrac-
- potential cost saving
Saturated waste-
incineration
tion or steam stripping
water from Hydro-

unit for treatment/
These are very small streams (-2* of the
gen Purification

disposal with Stream A
(2002)

volume of other process waste streams) and
Cost
Cost
contains >20% hydrocarbons Reuse of or

blending this stream with Stream A for

See Discussion
See Discussion
treatment/disposal would have insignificant
cost impacts

-------
Disposal Alternative 2 lists wastewater parameters of the stream to be
disposed of by deep well injection. During the treatment process, a 97 per-
cent reduction in wastewater volume occurs with the use of cooling tower con-
centration and forced evaporation. The effect of using biological treatment
effluent (Option II) versus activated carbon effluent as part of the cooling
tower makeup cannot be seen in the discharges from the more and less stringent
control options because residual organics are destroyed by the incineration
step in both options. Air emissions from the cooling tower (due primarily to
drift losses) is estimated to be reduced by about 95% of TOC going from Option
II to Option I. In addition to the hazardous biological and chemical sludges,
other solid wastes generated under this option include the incinerated brine
chich will likely be classified as hazardous under RCRA.
Disposal Alternative 3, Surface Impoundment, shows the benefit of using
cooling tower to concentrate wastewater. Reduction of 70% in wastewater vol-
ume can be achieved. Cooling tower emissions are minimized by the pretreat-
ment of wastewater by biological treatment (Option II) and activated carbon
(Option I). Due to the high residual organics in the biotreated and cooling
tower concentrated waste, the cooling tower blowdown is assumed to be hazard-
ous under RCRA.
Disposal Alternative 4, Co-disposal with Ash, involves a cross media
trade-off between the disposal of treated wastewaters in the ash quench sys-
tem and its effect on the classification of the ash as either a hazardous or
non-hazardous solid waste. If residual organics are destroyed by incinera-
tion, it is presumed that the ash can be disposed of as a non-hazardous solid
waste. Without incineration it is assumed that the residual organics in the
wastewater would render the ash hazardous. Wastewater volume is significantly
reduced in this case to match the treated effluent flow with ash system make-
up requirements. This volume reduction results in a significant increase in
the concentration of inorganic constituents.
For the low volume and/or nonprocess waste streams, the composition data
of the treated streams are very limited. Under Option I, no direct discharge
of these waste streams are allowed. Under Option II, about 10,000 Kg/TJ of
treated wastewater containing some trace elements will be discharged to surface
143

-------
water. Treatment of these wastestreams under either option will not reduce
the wastewater volume to any extent and is not expected to generate any hazard-
ous wastes.
144

-------
5.4 Solid Waste Management
The solid waste streams generated in an integrated SRC-II direct lique-
faction facility are summarized in Table 5-29. The gasifier slag and recover-
ed sulfur are clearly the largest volume wastes. Brines generated by waste-
water treatment are not covered here, although it is recognized that their
legal classification under RCRA is as solid wastes. All such brines are
covered in Section 5.3 under wastewater treatment.
Hazardous and non-hazardous waste from synfuel production are subject to
regulations promulgated under the authority of the Resource Conservation and
Recovery Act of 1976 (RCRA). To the extent that waste from synfuel facilities
are "non-hazardous" and are land disposed, they are subject to the sanitary
landfill criteria which were promulgated during September 1979 (40 CFR, Part
257). These criteria can be used to classify certain disposal facilities as
"open dumps", and, following state incorporation of EPA regulations into
specific programs, will permit the initiation of enforcement action against
such disposal facilities.
As mentioned in Section 3, the mining exemption has been interpreted by
EPA to cover the processing of coal for the purpose of synthetic fuels pro-
duction. This exemption affects the RCRA classification of gasifier ash.
EPA is currently evaluating the legislative history and comments received on
this exemption and is expected to develop conclusions by mid-1981.
Other solid wastes from an SRC-II liquefaction facility (e.g., biosludge)
will be hazardous if they fail the tests defined in 40 CFR, Part 261 (ig-
nitability, corrosibity, reactivity, toxicity) or if EPA chooses to list
specific synfuel waste streams as hazardous. It is likely that some waste
streams from these facilities will be classified as hazardous.
Criteria and guidelines for various solid waste management options are
presented in detail in Appendix I. The alternative technologies applicable
to the treatment/disposal of wastes generated in SRC-II liquefaction faci-
lities are indicated in Table 5-30. These technologies can be divided into
two categories:
145

-------
TABLE 5-29. SUMMARY OF SOLID WASTE STREAMS FROM SRC-II DIRECT LIQUEFACTION FACILITIES

-------
TABLE 5-30. MANAGEMENT ALTERNATIVES POTENTIALLY APPLICABLE FOR SOLID WASTES GENERATEn
IN SRC-II DIRECT LIQUEFACTION FACILITY	btntKAitu
Solid Haste Management Alternatives
Waste Stream (Stream No.)
or
1 'r»
a>
m J
/ 'O
o
1
i~
r oj
& l
c:
o 1
'h.
CO /
o
QJ 1
c:
or /

Gasification Slag (6302)
•


•
•
•
Spent Shift Catalyst (2206)
•



•

Spent Hydrolysis Catalyst (2207, 3309)
•



•

Spent Sulfur Guard (2508)
•



•

Spent Methanation Catalyst (2507)
•



•

Spent Claus Catalyst (2206)
•



•

Biological Treatment Sludges (4310)

•
•
•
•
•
Chemical Precipitation Sludges (4311)



•
•
•
Raw Water Treatment Sludges (3101)



•
•
•
Coal Dust from Particulate Control (6110)
•
•


•

Recovered Sulfur (3310)
•



•


-------
•	Category I - Those technologies which involve reuse and/
or treatment such as direct recycling, resource recovery,
incineration, chemical, physical, and biological treatment
facilities, and
•	Category II - Those technologies which involve placement
of the waste on the land such as landfill, surface impound-
ment, and land treatment.
The decision making processes related to disposition of SRC-II wastes
should be based on a systematic evaluation of these alternatives which bal-
ances environmental and health impacts against cost. General guidelines
for these evaluations include:
•	Category I technologies are environmentally preferable to
Category II technologies;
•	Within Category I technologies, direct recycle or resource
recovery is preferred to incineration or treatment;
•	With Category II technologies, site-specific characteris-
tics usually determine preference. The major site-specific
factors to be considered for land-based disposal are listed
in Table 5-31.
Other factors to be considered in evaluating alternatives include:
•	Waste regulatory classification
•	Waste characteristics/disposal technology compatibility
•	Intermedia environmental impacts among alternatives
•	Cost effectiveness
As a consequence of the Agency's general preference for reuse and recycle
of solid wastes, the guidance format in the following subsections has been
structured to indicate Category I approaches (reuse and/or treatment) under
Option I guidance, while the Option II guidance involves Category II approach-
es (disposal). In those instances in which reuse and/or treatment (Category
I	approaches) are not feasible for a given waste material, disposal (Category
II	approach) is shown under Option I guidance.
5.4.1 Solid Waste Management Guidance
The guidance for individual waste streams is summarized in Table 5-32.
Gasifier Slag
The guidance in Table 5-32 for this waste is based upon the assumption
148

-------
TABLE 5-31. SITE-SPECIFIC FACTORS TO BE CONSIDERED
FOR LAND-BASED DISPOSAL ALTERNATIVES
Climatic Factors
» Wind conditions
9 Precipitation
•	Evapotranspiration rate
Geologic Factors
9 Topographic features
•	Surface and subsurface geology
•	Soil types
Hydroqeoloqic Factors
o	Stream patterns
o	Stream flow
e	Surface waters
e	Groundwater
•	Water table (location, seasonal fluctuations)
®	Water quality
9	Floodplain (define in terms of 100 year flood)
o	Wetlands
Land Use Factors
e Historic sites
o Transportation corridors (access)
a Residences and institutions
o Geopolitical impact
149

-------
TABLE 5-32. GUIDANCE FOR SOLID WASTES GENERATED IN SPC-II DIRECT LIQUEFACTION FACILITIES
Stream
and	Suggested Classification/ 	Control Guidance	____
(Stream No ) Basis for Classification	Option I	Option II	Discussion
Gasification Slag
(6302)
Nonhazardous - available
RCRA leaching data indi-
cate this material to be
nonhazardous
No disposal
Guidance
Disposal as nonhazardous
waste.
Re-use of this material has not been
practiced However, the characteristics
of this is similar to those of boiler
slags which has been used as fill
materials for roads, construction sites,
land reclamation, asphalt mix, etc
Technology Basis
Resource recovery
Cost
Recovery may potentially
offset processing costs
Generally, cost savings
or penalties are not
readily calculable for
resource recovery
Technology Basis
Nonhazardous waste landfill
Cost
Capital
0.08% to 1.1*
Annualized 0 6% to 2 4%
Factors supporting the use of Option I
control
Resource recovery is always preferred
from an environmental standpoint
Potential cost savings
Factors supporting the use of Option II
control
Market potential foi the slag is
limited
Spent Catalysts
Claus (3308), Sulfur
Guard (2508)
Hazardous - sufficient
data are not available
at present to indicate
the hazardous or non-
hazardous characteristics
of these materials
Although testing data
may in the future
indicate that these
materials are
nonhazardous, it is
assumed that they are
hazardous until such
data are available
Guidance
No disposal
Technology Basis
Recycle to original
vendor or metal
reclaimer
Cost
Recovery may partially
offset processing costs
Generally, cost savings
or penalties are not
readily calculable for
resource recovery
Guidance
Disposal as hazardous waste
Technology Basis
RCRA Subtitle C (hazardous
waste) landfill
Cost *
Capital	<0 Oil
Annualized <0 01%
Factors supporting the use of Option I
controls
Resource tecovery is always desitable
from an environmental stand{Oint
Factors supporting the use of Option II
controls
Potential market for recycling those
materials is weak duo to the low
values of base-metals
As percent of uncontrolled base plant cost

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TABLE 5-32. (Continued)
Stteam
and	Suggested Classification/	Control Guidance	
(Stteam No )	Basis for Classification	Option 1	Option 11	Discussion
Spent Catalysts,
Shift (2206)
Hydrolysis (2207,
3309)
Methanation (2507)
Hazardous - it is
believed that the metal
contents of these mater-
ials would render them
hazardous ALthough no
confirming data are
currently available, it
is assumed that they are
hazardous until such
data are available
Guidance
No disposal
Technology Basis
Recycle to original vendor
or metal reclaimer
Cos t
Recovery may paitially off-
set processing costs Gen-
erally, cost savings or
penalties are not readily
calculable for resource
recovery
Disposal as hazardous
was te
Technology Basis
RCRA SubtiL3e C
(hazardous waste) land-
fill
Cost *
Capital	<0 01*
Annualized <0 01%
Potential markets for reuse of those
catalyst or the recovery of metal values
(e g , Co, Mo, Ni) are available Large
quantities of similar catalyst materials
are currently being reclaimed
Factors supporting the use of Option 1
controls
Resource iccovery is always desirable
from an environmental standpoint
Potential cost savings
Factors suppoiljng the use of Option II
contro1s
Potential market for reuse of these
materials may not exist
Biological Treat-
ment Sludges
(4310)
Hazardous - it is
believed that toxic
organics in the sludge
would be a basis for
classifying this waste
hazardous although no
confirming data are
currently available
Gu tdance
Destroy hazardous
organics prior to dis-
posal
Technology Basis
Incineration followed by
RCRA Subtitle D (non-
hazardous waste) land-
fill
Cost *
Capital
Annualized
0 02*
0 1%
Guidance
Disposal as hazardous
waste
Technology Basis
Lana treatment, landfill
or surface impoundment
consistent with RCKA
Subtitle C (hazardous
waste) Lequirements
Dewaterinq would be
required for landfill incj
Cost *
Capital	0 2\
Annualized 0 9*
Incineration, Jandtreatment, landfilJ, or
surface impoundment consistent with RCKA
may all be acceptable, depending on site
specific factors
Factors supporting the use of Option I
controls
Incineration consistent with RCRA require-
ments can render the waste nonhazarclous
Factors supporting the use of Option II
controls
Landtreatment, particularly as part of
disturbed land reveqetation/rehabi11tation
(e g , surface mine »eclamation) may render
the waste nonhazardous as well as provide
nutrients and improve soil structure for
plant growth
landfill or surface impoundments may be
less expensive than incineration
As percent of uncontrolled base plant cost

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TABLE 5-32. (Continued)
cn
rsi
Stream
and
{Stream No )
Suggested Classif1cation/
Basis for Classification
Control Guidance
Option I
Option II
Dewatered Chemical
Treatment Sludges
(4311)
Raw Water Treat-
ment Sludges
(3101V
Hazardous - it is be-
lieved the leachable
metal content of the
waste will exceed the
RCRA-EP limits
Nonhazardous - available
data indicate this waste
to be nonhazardous
Guidance
Fixation and disposal as Disposal as hazardous waste
hazardous waste	No fixation required
Technology Basis
Fixation
FCRA Subtitle C
(hazardous waste)
landfill
Cost *
Capital	0 08%
Annualized 0 5%
Technology Basis
RCRA Subtitle C (hazardous
waste) landEi11
Cost *
Capital	0 08%
Annualized	0 4%
Guidance
Guidance
Disposal as nonhazardous No other disposal option
Technology Basis
RCRA Subtitle D (non-
hazardous waste) landfill
Cost *
Capital
Annualized 0.04* to 0-14%
Discussion
Sludges would need to be rendered "non-f lowimj"
either by dewatenny or by co-disposal with
other hazardous wastes (e g , gasifier ash
moisturized wLth non inc inerated process
wastewater)
Factors supporting the use of Option I
controls
- Fixation of the waste would render it
less leachable at a small incremental
co«it
Factors supporting the use of Option 11
controls
Lower cost
RCRA places no spec\f\c requirement for
fixation on a hazardous waste generator
If co-disposed with hazardous wastes,
guidance for those wastes would apply
Co-disposal with other nonhazardous wastes
(e g , gasrfier ash not moisturised wi th
process wastewater laden with orgatucs) Lo
render this waste "non-flowing"
* As percent of uncontrolled base plant cost

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TABLE. 5-32. (Continued)
Stream
and
(Stream No )
Suggested Classification/
Basis for Classification
Control Guidance
Option I
Option II
I) i scuss ion
CT1
CO
Collected coal dust Nonhazardous - these are
from Particulate	fine coal particles
Control (6-.10J
Sulfur (3310)
Thuie is no reason to
believe this material to
he hazardous
Hazardous - There is
no data to indicate
the hazarclous/non-
hazardous nature of
this material it is
assumed hazardous be-
cause of the presence
of vanadium, thiocyanate
and possibly organics
No disposal
Technology Basis
Reuse as fuel
Cost
Values of recovered product
largely offset the hand-
ling cost However, the
exact cost savings are
generally not readily cal-
cu1 able
Guidance
No disposal
Technology Basis
Resource recovery
Cost
Generally cost savings
or penalties tire not
readily calculable for
resource recovery
Cu idance
Djs|x>sal as nonhaza i rious>
waste
Technology Basis
RCRA Subtitle D (Non-
hazardous waste landfill)
Cost •
Capital
Annualized 0.01* to 0.04*
Disposal as hazardous
waste
Technology Basis
RCRA Subtitle C
{hazardous waste)
lanJf111
Cost *
Capital	not estimated
Annualized 1S% - 2 7*
Cou 1 fines may be uscci clnccLly us boi I *_ r
fuels Whether leclaimed or disjjosud, i-d
must. be. exercised to ininimizc tugitivc
cnnsr,Jons during handling
Factors supporting the use of Option I
conuol s
- Kcsoujce locovciy is alwa/s dosiiciblu
fium an environmental staiid|«oi nt
The quality of the recovei i_d sulfur
is not known and hence it is not pos-
sible Lo oss«_ss potential maikecs 1 oi
this mutei ia 1
The Agency prefers the use of Option
I	controls Factors supporting the
use of Option I controls
Resumce recovery is alwuys de-
sirable from an environmental
standpoint
Recovery may partially otfset pro-
cess nig costs
{¦actors supporting the use of Option
II	contiols
As percent of uncontrolled base plant cosl
limited or no markets fot thic
I al.	

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that water low in organics is used as quench water.
Under the mining exemption gasifier slag is temporarily exempted from
hazardous waste control. However, this may be a moot point because avail-
able RCRA leaching data indicate that these wastes will be classified as
nonhazardous waste on this basis. The preferred management option (Option
I) for this waste is resource recovery. The characteristics of this material
is similar to that of boiler bottom ash; boiler ash has been reused as re-
placement for aggregate in building blocks, as fill material in road con-
struction, etc. Option II control calls for disposing this material in non-
hazardous waste landfill.
As discussed in Section 5.3, if nonincinerated brine from process waste-
water is used as quench water, the slag is assumed to be hazardous, due to
the high organic contents in the brine. In this case, the guidance is to
dispose the waste in hazardous waste landfills.
Spent Claus Catalyst, Spent Sulfur Guard
There is insufficient information available at present to indicate the
hazardous or nonhazardous characteristics of these materials. Nevertheless,
to be conservative, these materials should be disposed of in hazardous land-
fills until such data are available. It should be pointed out that recycling
of these materials is expected to be economically unattractive because of the
low market values of the base materials for these catalysts (bauxite for
Claus, zinc oxide for sulfur guard).
Spent Shift Catalyst, Spent Hydrolysis Catalyst, Spent Methanation Catalyst
It is believed these materials are hazardous because of their high metal
contents. They may fail the RCRA-EP test or eventually be "listed" and hence
their management should be consistent with RCRA hazardous waste disposal re-
quirements. However, several vendors have indicated that these materials are
generally recyclable to the original sources or to metal reclaimers.
Biological Sludges from Wastewater Treatment
There are no data at present to indicate the hazardous or nonhazardous
characteristics of this waste. Since it is expected that sludge would contain
154

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toxic organics and soluble trace elements, this waste should be disposed of
consistent with the hazardous waste regulations (40 CFR 260-267). The
waste can be dewatered and then landfilled, landfarmed or incinerated to
destroy the organics. A desirable disposal alternative is to landfarm the
biosludge in conjunction with surface mine reclamation. It is believed
that soil microorganisms will biodegrade the biosludge sufficiently so as
to supply nutrients necessary for revegetation.
Dewatered Chemical Precipitation Sludges from Wastewater Treatment
There are no data at present to indicate the hazardous or non-hazardous
nature of this waste. However, it is believed that the leachable metal con-
tents of the sludge can exceed the RCRA-EP standards and thus will need to
be disposed of in hazardous waste landfills. Depending on the disposal site-
specific factors other chemicals (e.g., lime, cement) may be required to
"fix" these materials to reduce the leachability of the metals before dis-
posal .
Raw Water Treatment Sludges
Limited data on the characteristics of these wastes indicate that they
are nonhazardous. Raw waters normally contain very low trace element lev-
els, so these wastes will consist mainly of calcium carbonate. This waste
can be co-disposed with gasifier in nonhazardous landfills.
Fines and Dust Collected from Pollution Control
Although there are limited data on the characteristics of these wastes
it is believed they are nonhazardous and thus can be disposed of in non-
hazardous landfills or mines. Because of the fine particulate present, how-
ever, practices such as spraying with water should be used when handling
these wastes to prevent particulate emissions to the air. Due to its high
carbon content, this can be reused as fuel or as gasifier feed.
Recovered Sulfur
Sulfur recovered in the Claus unit is normally resold as a byproduct.
If there is no market for this material, it should be considered as a hazard-
ous waste until data are available to indicate otherwise.
155

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5.4.2 Disposal Cost and Energy Requirements
Disposal costs are highly dependent on site-specific factors such as the
volume of waste handled, land availability, distance to the disposal site,
modes of transporting the waste (e.g., belt conveyor vs truck), cost of land,
local groundwater and surface flow patterns, fuel costs, and availability of
local solid or other materials to be used as liners or cover materials. Tra-
ditionally, most available cost data for solid waste disposal are expressed
on a "per ton" basis and only rarely are breakdowns of capital and operating
costs provided. For this document, the annualized unit cost for hazardous
waste landfill, nonhazardous waste landfill, land treatment and incineration
are estimated to be $24 to $45/Mg, $5 to $19/Mg, $29/Mg and $330/mg, respectively.
The landfill cost data generated in this document are for a landfill with
an annual capacity of 1,200,000 Mg/yr. The major capital costs items include
land cost, site preparation and laboratory building; the annualized cost in-
clude operating labor, equipment leasing and other costs. Land cost is in-
cluded because this is a major capital cost. Landfill equipment costs are
included as part of the annualized operating cost because it is believed
that leasing the equipment is more economical than purchasing the equipment.
For nonhazardous waste landfill, the annualized unit cost is estimated to be
$5/Mg to $19/Mg. The lower number assumes a site where minimum site prepara-
tion is required, the site is not close to any drinking water aquifer (i.e.,
no liner is required) and a landfill waste depth of 33 m (100 ft). The high-
er range cost reflects the cost for a site where liner is required, and the
waste depth was assumed to be 7 m (20 ft). For hazardous waste landfill, the
unit cost is estimated to be ~$4/Mg to $45/Mg. The major difference between
these two numbers is the liner cost since 30 mil vs 80 mil thick liners were
used in developing the two costs.
No costs are shown for the Option I (recycle/reuse) waste management ap-
proaches because these costs will be highly variable. In certain locations,
specific solid residues (e.g., spent catalysts) may be sufficiently valuable
to warrant their sale as by-products and a credit would be realized. However,
it is more likely that the costs of disposing of most direct liquefaction
plant solid waste streams (particularly the high volume wastes) will be at
least equal to those indicated for land disposal.
156

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Table 5-33 summarizes the capital and annualized costs estimated for
several waste management alternatives. As indicated previously, the EPA
preference is to encourage re-use approaches under Option I and disposal
approaches under Option II. In those cases in which re-use is not feasible
for a particular material, a disposal approach is indicated under Option I.
As also discussed earlier, re-use income can partially offset processing and
handling capital and annualized cost outlays.
With maximum solid waste reuse, (Option I) total costs would be 0.1 per-
cent and the annualized costs 0.74 percent of the uncontrolled plant costs.
With the minimum reuse (Option II) the costs would be 1.3 percent and 3.8 per-
cent, respectively.
The energy requirements associated with solid waste disposal are highly
dependent on the disposal method and the distance between the disposal site
and the plant. For landfill and land treatment, it is assumed that the major
energy requirements are for the operation of landfill equipment such as bull-
dozers and for the operation of trucks transporting the wastes. The energy
requirement for both landfills and land treatment is estimated to be 26,500
kcal per Ma. For incineration of biosludge, the energy requirement is esti-
mated to be 111,200 kcal per Mg. Energy requirements associated with re-
source recovery were not estimated. Based on this assumption, the total en-
ergy required for solid waste management in each option will be below 0.01
percent of the total energy input to the plant.
Typical quantities of solid wastes potentially disposed of on land by
landfills, land treatment or surface impoundment in the subject facilities
are summarized in Table 5-34. Under Option I, only the chemical treatment
sludge is disposed of as a hazardous waste. The other potentially hazardous
wastes are being recycled (spent catalysts, collected coal dust and sulfur)
or incinerated (biosludge). More solid wastes, both hazardous and nonhazard-
ous, are disposed of on land under Option II than under Option I (1542 Kg/TJ
hazardous and 3780 Kg/TJ nonhazardous vs 11 Kg/TJ hazardous and 256 Kg/TJ
nonhazardous).
157

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TABLE 5-33. CAPITAL AND ANNUALIZED COSTS OF SOLID WASTE DISPOSAL
(AS PERCENTAGE OF UNCONTROLLED BASE PLANT COST)
Waste Stream
(Stream No.)
Resource
Recovery
Capital'
Option I
Annualized
Disposal
Nonhazardous
Disposal
Hazardous
Pi sposal
Capital
Disposal
Option II
Annualized
Nonhazardous
Pisposal
Hazardous
Pi sposal
Gasification
Slag (6302)
Claus Catalyst (3308)
Sulfur Guard (2508)
Shift Catalyst (2206)
Hydrolysis Catalyst
(2207, 3309)
Methanation (2507)
Biological Treatment
Sludges (4310)
Chemical Treatment
Sludges (4311)
Raw Water Treatment
Sludges (3101)
Collected Dust from
Particulate Control
(1600)
N/A
N/A
N/A
N/A
N/A
0.2
0.08
N/A
N/A
N/A
0.9 ,
N/A
0.14
N/A
N/A
N/A
N/A
0.5
N/A
N/A
0.08-1.1
0.01
0.02
0.08
N/A
0.6-2.4
N/A
N/A
N/A
N/A
0.04
N/A
0.01
0.1
0.5
N/A
N/A
* Included as part of the gasification slag landfill capital cost

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TABLE 5-34. QUANTITES OF SOLID HASTES POTENTIALLY DISPOSED OF ON LAND (Kg/TJ)
Option I				Option II
Waste Stream
Hazardous
Nonhazardous
Hazardous
Nonhazardous
Gasification Slag
0
0
0
3510
Shift Catalyst
0
0
1.7
0
Hydrolysis Catalyst
0
0
0.3
0
Sulfur Guard
0
0
0.05
0
Methanation Catalyst
0
0
0.008
0
Claus Catalyst
0
0
0.8
0
Biological Treatment Sludge
~
35
118
0
Chemical Treatment Sludge
11
0
11
0
Raw Water Treatment Sludge
0
210
0
210
Collected Coal Dust
0
0
0
60
Recovered Sulfur
0
0
1400
0
Total
11
245
1532
3780
* Biosludge is incinerated in Option I

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5.5 Toxic Substances Control
5.5.1	General Approach
It is difficult to generalize how the toxicity and physical hazards of
products and by-products from direct liquefaction will compare to materials
currently utilized in the petroleum and coal-based energy industries. Where
product toxicity and physical hazards are shown to be similar to those of
petroleum-derived counterparts, similar precautions for handling, storage,
and use should be applied. For products or by-products that are suspected of
presenting greater hazards than existing products, manufacturers are advised
to use controls and safeguards which minimize potential exposure or release.
We assume responsible industrial managers will incorporate good indus-
trial hygiene practices to minimize potential health and environmental haz-
ards associated with synfuel products. In this regard, they should be aware
of the guidelines presented in "NIOSH Proposed Criteria for Coal Gasification
Plants," (EPA-600/7/78-007, January 1978), and a soon-to-be released document
on coal liquefaction plants.
5.5.2	Premanufacturing Notification
Since direct coal liquefaction fuels are designed to replace petroleum
fuels, coal-derived products generally have physical properties (e.g., boil-
ing range, vapor pressure, flash point, etc.) similar to those of their
petroleum-derived analogs. Limited data suggest that the lighter fractions
and gases often have similar chemical compositions (e.g., similar content of
total aromatics, olefins, and saturates). Similarly limited data suggest
that the heavier fractions of direct liquefaction products contain higher
concentrations of biologically active compounds (e.g., aromatic amines, het-
erocyclic compounds, phenols, etc.) than their petroleum analogs. The data
for most of these products are quite limited in extent, particularly for
health and ecological effects; and because so few samples have been tested,
it is difficult to generalize the results for all coals and process configura-
tions which may be used in a commercial coal liquefaction industry.
Developers will be required to submit a PMN on all products which are
not on the TSCA Chemical Substance Inventory before they begin to manufacture
these substances for commercial purposes.
160

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Data required in the PMN include:
1)	chemical composition of the synfuel products,
2)	details on mode of use,
3)	the projected production volume,
4)	a characterization of the by-products and emissions resulting
<
from the manufacturing process and characterization of the
products of combustion of the synfuel during its intended use,
5)	characterization of human exposure during the manufacturing
process and use of the synfuel products, and
6)	method by which manufacturing and processing wastes are disposed.
The risks posed by a synfuel process strongly depend on those controls,
safeguards and restrictions the manufacturer chooses to impose. Although
not specifically required by law, the developer's rationale or assessment of
the adequacy of these procedures can play important roles in the agency's
risk assessment.
Developers are urged to consult OPTS Policy Paper on synfuels for further
explanation of their responsibility under TSCA. More importantly, developers
are strongly urged to consult with the Agency as early as possible (well in
advance of the statutory 90-day notice requirement) in order to obtain
guidance specific to their slate of products.
161

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