&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-78-091
June 1978
Standards
of Practice Manual
for the Solvent
Refined Coat
Liquefaction
Process
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Off ice of Research and Development, U.S. Environmental Protec-
tion Agency, have been grouped into nine series. These nine broad categories were
established to facilitate further development and application of environmental tech-
nology. Elimination of traditional grouping was consciously planned to foster technology
transfer and a maximum interface in related fields. The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the ENVIRONMENTAL PROTECTION TECHNOLOGY
series. This series describes research performed to develop and demonstrate instrumen-
tation, equipment, and methodology to repair or prevent environmental degradation from
point and non-point sources of pollution. This work provides the new or improved tech-
nology required for the control and treatment of pollution sources to meet environmental
quality standards.
REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is available to the public through the National Technical Informa
tion Service, Springfield, Virginia 22161. <=unmuai imorma-
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EPA-600/7-78-091
June 1978
Standards of Practice Manual
for the Solvent Refined Coal
Liquefaction Process
by
P.J. Rogoshewski, P.A. Koester, C.S. Koralek,
R.S. Wetzel, and K.J. Shields
Hittman Associates, Inc.
9190 Red Branch Road
Columbia, Maryland 21045
Contract No. 68-02-2162
Program Element No. EHE623A
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
This Standards of Practice Manual provides an integrated
multimedia assessment of control/disposal options emissions
and environmental requirements associated with a hypothetical.
50,000 barrel/day (7,950 cubic meters per day) Solvent
Refined Coal (SRC) facility producing gaseous and liquid
fuels (SRC-II mode).
An overall outline of the basic system is provided in-
cluding module descriptions, and summaries on pollution con-
trol practices and costs. The manual also provides a survey
of currently available and developing control/disposal prac-
tices that may be applicable to waste streams from coal
liquefaction technologies. In the detailed definition of
the basic system, modules are described in detail, and input
and output streams are quantified. Applicable control/dis-
posal practices are specified in accordance to waste stream
characteristics and pertinent environmental requirements.
For each treatment option, capital and operating costs are
given along with estimated emissions after treatment.
Subsequently, levels of specific pollutants in quantified
waste streams are compared to Multimedia Environmental Goals
(MEG's) as developed by EPA's IERL-RTP. Finally, emission
variations in solid and liquid SRC production are discussed.
•t-l
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TABLE OF CONTENTS
ABSTRACT ii
TABLE OF CONTENTS Hi
LIST OF FIGURES iv
LIST OF TABLES vii
LIST OF ABBREVIATIONS xv
1. 0 SUMMARY 1
2 . 0 INTRODUCTION 2
3 . 0 OUTLINE OF BASIC SYSTEM 4
4.0 EXISTING ENVIRONMENTAL REQUIREMENTS 17
5.0 SURVEY OF CONTROL/DISPOSAL PRACTICES 20
6. 0 DETAILED DEFINITION OF BASIC SYSTEM 134
7.0 ENVIRONMENTAL EMISSIONS AND FACTORS ACHIEVED 250
8.0 EMISSION VARIATIONS FROM THE SRC I SYSTEM 266
9. 0 ACKNOWLEDGEMENTS 269
10. 0 REFERENCES 270
11.0 BIBLIOGRAPHY 276
12.0 GLOSSARY. . 280
APPENDICES 285
A. METRIC CONVERSION FACTORS 286
B. FEDERAL AND STATE REGULATIONS 289
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LIST OF FIGURES
No. Title
1 SRC-II System Overall Flow Diagram 6
2 Overall Material Balance for a 50,000 bbl/day
(7 , 950 M^/day) SRC-II System '
3 TYCO's Modified Sulfuric Acid Scrubbing
Process For NO Removal :}y
A.
4 Lime Scrubbing For N0x Removal 41
5 Magnesium Hydroxide Scrubbing of N0x 42
6 Urea Scrubbing Process For N0x Removal 43
7 Recommended Values of F for Various Values of
55
8 Three Flow Schemes Employed in the Dissolved
Air Flotation Process ........................... 58
9 Moving Belt Concentrator Yield vs . Cake Solids . . 82
10 Steam-to-Air Ratio at Saturation in the Reactor
Vapor Space for Various Operation Temperatures
and Pressures .............. . .................... 85
11 Reduction in COD Resulting from Sludge Being
Exposed to Excess Air for One Hour at Various
Temperatures .................................... 86
12 High Operation Temperatures Result in High COD
Reduction and Low Reaction Time ................. 86
13 Tank Bottom Drainage Systems .................... 109
14 Tank Bottom Replacement ......................... 112
15 Internal Heating Coal Monitoring System ......... 112
16 Tank Filling Control System ..................... 113
17 "Navy" Boom (Curtain Type) ...................... 121
18 Kain Boom (Fence Type) ......................... 121
19 Boom/ Skimmer Configuration for Oil Spill Clean-
UP .............................................. 122
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LIST OF FIGURES (CONTINUED)
No. Title Page
20 Circulation Patterns Upstream of an Air
Barrier in a Current 122
21 Classes of Skimmers 125
22 Process Schematic - Coal Preparation Module 136
23 Coal Preparation Module Process and Waste
Streams 138
24 Hydrogenation Module Flow Diagram 156
25 Hydrogenation Module Process and Waste Streams... 158
26 Phase (Gas) Separation Module 161
27 Phase (Gas) Separation Module Process and Waste
Streams 163
28 Process Flow Schematic Solids Separation Module.. 167
29 Solids Separation Module Process and Waste
Streams 168
30 Process Flow Schematic Fractionation Module 171
31 Fractionation Module Process and Waste Streams... 172
32 Process Flow Schematic Hydrotreating Module 175
33 Hydrotreating Module Process and Waste Streams... 177
34 Solidification Units 180
35 Process and Waste Streams in the Solidification
Module 131
36 Gas Purification Module (One Process Train) 134
37 Process and Waste Streams in the Gas Purification
Module 186
38 Cryogenic Separation Module Process Flow
Schematic 19Q
v
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No,
LIST OF FIGURES (CONTINUED)
Title
39 Cryogenic Separation Module Process and Waste
Streams ......................................... iy
40 Hydrogen Generation
41 Hydrogen Production Module ...................... 197
42 Ammonia Recovery ................................ 203
43 Ammonia Recovery Process and Waste Streams ...... 204
44 Phenol Recovery ................................. 207
45 Phenol Recovery Process and Waste Streams ....... 208
46 Stretford Sulfur Recovery with High Temperature
Hydrolysis ...................................... 211
47 Process and Waste Streams in the Sulfur
Recovery System. . ............................... 214
48 Oxygen Generation ............................... 220
49 Oxygen Plant .................................... 221
50 Raw Water Treatment ............................. 224
51 Raw Water Treatment Process and Waste Streams ... 226
52 Plant Cooling Tower System ...................... 230
53 Cooling Tower Process and Waste Streams ......... 233
54 Steam Generation Facilities ..................... 234
55 Steam and Power Generation Process and Waste
Streams ....................... ....... 235
56 Crude Run vs . Flare Loading ................. 249
57 A Typical MEG Chart ...................... 252
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LIST OF TABLES
No. Title Page
1 Suggested Control/Disposal Practices For
The SRC-II System 12
2 Control/Disposal Costs For A 50,000 bbl/day
(7,950 m3/day) SRC-II System 15
3 Efficiency of Cyclones 24
4 Characteristics of Filter Fabrics 28
5 Air-To-Cloth Ratios For Coal Dust 29
6 Efficiency of Scrubbers At Various Particle
Sizes . 30
7 Applicability of Various Wet Scrubbers To
Coal Dusts and Fly Ash 31
8 Combustion Temperatures In Direct-Fired And
Catalytic Afterburners 31
9 SO Removal Systems 37
X
10 Gaseous Waste Streams In The SRC Process -
Major Contaminants and Stream Characteristics. 44
11 Treatment Processes 47
12 Neutralization Reagents 52
13 Gravity Oil-Water Separator Design Equations. .
. . , 54
14 Air Flotation Unit Operating Conditions 57
15 Dissolved Air Flotation 59
16 Biological Treatment Systems 60
17 Filtration Processes 62
18 Ion Exchange Process 69
19 Solids Treatment 74
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LIST OF TABLES (CONTINUED)
No. Title Page
20 Thickeners 76
21 Centrifuges 78
22 Wet Air Oxidation Process Operating Condition. 84
23 Wet Oxidation Process 84
24 Incineration 88
25 SRC Sludges 89
26 Composting 95
27 Irrigation Systems 96
28 Effect of Two-Stage Combustion on Emission Of
Nitrogen Oxides From A Large Steam Generator
At Full Load 99
29 Estimated Percent Reduction In NOx Emissions
By Combustion Modification of Coal-Fired
Boilers 100
30 Sulfur Content in Illinois No. 6 Seam Coal
By County 105
31 Sorbents ' Relative Effectiveness And Cost 124
32 Process And Waste Stream Constituents In
Coal Preparation Module 139
33 Run Of Mine (ROM) Illinois No. 6 Coal
Analysis
34 Average Ash Analysis of Illinois No. 6 Coal... 142
35 Trace Element Composition of Illinois No. 6
Coal Samples
36 Characteristics Of Coal Pile Drainage
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LIST OF TABLES (CONTINUED)
No. Title Page
37 Waste Streams From Coal Preparation Module... 147
38 Treatment Alternatives For Dust Stream From
Coal Receiving 149
39 Costs Of Control Alternatives For Fugitive
Dust 151
40 Treatment Alternatives For Dust Streams From
Coal Reclaiming And Crushing 152
41 Control Alternatives For Stack Gas From
Coal Drying 153
42 Tailings Pond 154
43 Hydrogenation Reactor Effluent 157
44 Hydrogenation Module Stream Compositions 159
45 Phase (Gas) Separation Module Stream
Compositions 164
46 Process And Waste Stream Constituents In The
Solids Separation Module 169
47 Fuel Gas and Flue Gas Constituents 173
48 Process And Waste Stream Constituents In The
Hydrotreating Module 178
49 Process And Waste Stream Constituents In The
Gas Purification Module 187
50 Process And Waste Stream Constituents In The
Cryogenic Separation Module 193
51 Hydrogen Production Module Stream Composi-
tion 198
52 Hydrogen Production Waste Streams 200
53 Sludge Landfilling 201
54 Ammonia Stripping Stream Compositions 205
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LIST OF TABLES (CONTINUED)
N^ Title EMC
909
55 Phenol Recovery Stream Compositions
56 Sulfur Recovery Stream Compositions 215
57 Components In Stretford Tail Gas 217
58 Hydrocarbon Treatment Alternatives For
Stretford Tail Gas Zlb
59 Oxygen Plant Process And Waste Streams 222
60 Typical Constituents In White County, Illinois
Raw Water Supply 225
61 Raw Water Treatment Stream Compositions 227
62 Lime Sludge Disposal 229
63 Steam And Power Generation Stream Compositions. 236
64 Constituents In Flue Gas From Steam And Power
Generation 238
65 Required Removal Efficiencies To Meet Illinois
Emission Standards For Coal-Fired Boilers 239
66 Costs, Efficiencies, And Final Emission For
Commercially Available S02 Wet Scrubbing
Processes 240
67 Product/By-Product Storage 243
68 Common Treatment Processes To All Alternative
Treatment Disposal Methods 244
69 Costs Of Treatment Processes 246
70 Fort Lewis Pilot Plant Effluent Limit 247
71 Estimated Costs For Flare System Of A 50,000
BBL/DAY SRC Plant | 248
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LIST OF TABLES (CONTINUED)
No. Title Page
72 A Comparison Of Estimated Air Emissions From
Coal Receiving And MEG's - Trace Metals 256
73 A Comparison Of Estimated Air Emissions From
Coal Reclaiming And Crushing With MEG's -
Trace Metals 257
74 A Comparison Of Estimated Air Emissions From
The Flow Dryer And MEG's - Trace Metals 258
75 A Comparison Of Estimated Stretford Tail Gas
Emissions And MEG' s 259
76 A Comparison Of Estimated Air Emissions From
Steam Generation And MEG's 260
77 A Comparison Of Slag From The Gasifier And
MEG's - Trace Metals 261
78 A Comparison Of Estimated Effluents From The
Wastewater Treatment Plant And MEG's -
Organic Compounds 263
79 A Comparison Of Estimated Effluent Constituents
From The Wastewater Treatment Plant And MEG's -
Trace Metals 264
80 A Comparison Of Other Estimated Emissions From
The Wastewater Treatment Plant And MEG's 265
81 National Primary And Secondary Ambient Air
Quality Standards 292
82 Federal New Source Performance Standards Of
Related Technologies 293
83 Federal Effluent Guidelines And Standards For
New Sources 294
84 Some EPA Requirements And Recommendations For
Solid Wastes 295
85 Ambient Air Quality Standards In Alaska 298
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LIST OF TABLES (CONTINUED)
No. Title Page
86 Emissions Standards For Industrial Processes
And Fuel Burning Equipment In Alaska ............ 299
87 Water Quality Criteria Of Alaska ................ 300
88 Ambient Air Quality Standards Of Arizona ........ 301
89 Industrial Emissions Standards In Arizona ....... 302
90 Arizona Water Quality Criteria .................. 303
91 Standards Of Performance For Petroleum Re-
Fineries In Colorado ............................ 305
92 Colorado Water Quality Standards ................ 306
93 Colorado Effluent Discharge Criteria ............ 3Q7
94 Indiana Ambient Air Quality Standards ........... 3Q9
95 Water Quality Criteria Of Indiana ............... 310
96 Applicable Illinois Emissions Regulations ....... 3H
97 Illinois Air Quality Standards For Particulate
Matter ................................ . ......... 3^2
98 Illinois Water Quality Standards
99 Illinois Effluent Standards
100 Ambient Air Quality Standards In Kentucky
104
101 Standards Of Performance For Petroleum
Refineries In Kentucky .......................... 0-17
102 Kentucky Water Quality Standards.. 010
.......... Jio
103 Ambient Air Quality Standards In Montana ........ 32n
Selected Water Quality Criteria of Montana ...... 32l
105 New Mexico Emissions Standards For Commercial
Gasif iers .................................... _
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LIST OF TABLES (CONTINUED)
No. Title Page
106 Ambient Air Quality Standards In New Mexico 325
107 New Mexico Water Quality Criteria 326
108 Ambient Air Quality Standards Of North Dakota... 327
109 Class I Water Quality Standards In North Dakota. 328
110 Ohio Ambient Air Quality Standards 330
111 Ohio Stream Quality Criteria For Public Water
Supply Use 331
112 General Water Standards Applicable Within 500
Yards Of Any Public Water Supply Intake In Ohio. 332
113 Ambient Air Quality Standards of Pennsylvania... 333
114 Water Quality Standards For The Monongahela
River In Pennsylvania 335
115 Ambient Air Quality Standards Of South Dakota... 335
116 Selected South Dakota Industrial Emissions
Standards 337
117 Applicable Water Quality Standards of South
Dakota 333
118 Texas Air Regulations 340
119 Water Uses And Quality Criteria For The San
Antonio River Basin 342
120 Water Criteria For Class "A" Utah Waters (From
Public Health Service Drinking Water Standards,
1962) 345
121 Applicable Air Pollution Regulations In West
Virginia 345
122 West Virginia Air Quality Standards 347
123 Water Quality Criteria For The Gauley River And
Tributaries In West Virginia 34g
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LIST OF TABLES (CONTINUED)
No. Title Page
124 Wyoming Ambient Air Standards 350
125 Applicable Wyoming Emissions Regulations 351
126 Wyoming Water Quality Standards 352
127 EPA National Interim Primary Drinking Water
Standards 353
x^v
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LIST OF ABBREVIATIONS
ADA
API
BBL/D
BOD
BOD5
COD
DEA
EOD
EPC
GPD
LD50
LPG
MATE
MEA
MEG
MGD
NO
NOX
PAH
PNA
ROM
SNG
SOX
SRC
TLV
TPD
VSS
anthraquinone disulfonic acid; or salt of
American Petroleum Institute
barrels per day
biochemical oxygen demand
five day biochemical oxygen demand
chemical oxygen demand
diethanol amine
elimination of discharge
estimated permissible concentration
gallons per day
lethal dose, 50 percent kill
liquified petroleum gas
minimum acute toxicity effluent
monoethanol amine
multimedia environmental goal
million gallons per day
nitric oxide
oxides of nitrogen
polyaromatic hydrocarbons
polynuclear aromatics
run of mine
synthetic natural gas
oxides of sulfur
solvent refined coal
threshold limit value
tons per day
volatile suspended solids
xv
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1.0 SUMMARY
This Standards of Practice Manual provides a multimedia
summary of environmental requirements guidelines and control/
disposal options applicable to commercial Solvent Refined
Coal (SRC) plants.
For the purposes of this manual a conceptual 50,000
bbl/day (7,950 m3) equivalent SRC facility producing liquid
fuel (SRC-II mode) was located on the Wabash River in White
County, Illinois. This site was selected because of its
accessibility to large reserves of a compatible raw coal
feed (Illinois #6), sufficient quantities of water, and an
expressed interest by the state of Illinois in coal conver-
sion processes.
Costs associated with the controls are delineated and
best practices identified. Based on a preliminary assess-
ment of quantities and constituents in SRC waste streams, it
appears promising that conventional control equipment can be
utilized to achieve compliance with emission standards.
Costs for control equipment are significant, but do not
appear to be prohibitive.
Environmental standards are determined (utilizing
existing local, state and federal regulations) for such
industries as petroleum refineries and coal-fired steam
electric power plants, and the basic SRC process matched
with appropriate control units. Emissions after controls
are compared with Multimedia Environmental Goals (MEG's),
and a number of areas are found to exist in SRC processing
in which specific constituents discharged exceed the MEG's.
In coal preparation - specifically in coal receiving
and crushing - chromium, aluminum and, in some cases, arsenic
are found to be emitted in concentrations significantly
higher than the MEG's. Chromium and vanadium exceed MEG
values by factors of less than 10 in air emissions from
steam generation. Gasifier slag contains metals that are
excessive, including chromium, cobalt, nickel, barium,
arsenic, tin, zinc and selenium. Metals in wastewater
effluent are also higher, including magnesium, nickel, scan-
dium and barium.
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2.0 Introduction
This manual provides a multimedia summary of environ-
mental requirements, guidelines and control disposal options
applicable to Solvent Refined Coal (SRC) plants The SRC
process is summarized and control/disposal modules are
identified. The cost of controls are included and best
practices are noted. Existing applicable environmental
standards are identified. Finally, the basic process for
SRC is matched with appropriate control technologies.
The basis for this study is a hypothetical commercial
SRC facility producing a liquid fuel (SRC- II mode) at a rate
equivalent to 50,000 bbl/day (7,950 mj/day) of crude oil.
The plant is located on the Wabash River in White County,
Illinois. This site was selected because of its proximity
to large reserves of a process compatible raw coal feed,
Illinois #6; the availability of an adequate water supply,
and an expressed interest by the State of Illinois in coal
conversion.
The initial portion of the report provides a descrip-
tion of the overall process. A basic flow sheet showing all
processing steps was developed from existing design and
economic studies and pilot plant data. This flow sheet
identifies the processes and groups them into operations or
system modules. The flow sheet identifies all relevant
process waste streams. Streams entering and leaving each
system module are identified in terms of quantity and
composition. Any waste streams that have to be treated by
control/disposal measures are characterized in detail. For
these streams, the characterization includes quantity,
conditions, composition, and identification of the components
that must be treated to comply with environmental regula-
tions. The quantities, concentrations and forms of the
components are estimated to the fullest extent possible.
A completed version of existing environmental regul-
ations, standards and guidelines is also included in this
manual. Regulations imposed by Federal, Local, and State of
Illinois authorities are discussed. Regulations from other
LTfls eefaCtl°n facilities rai^ ^ constructed
petrochemical processing
as oil refinr
-------
Control/disposal practices are identified as potential
treatments for waste streams to meet these environmental
requirements. However, they do not constitute matching a
control to a stream, but rather serve as guide for more de-
tailed specification of control equipment. Estimates of the
necessary quantities of treatment chemicals, steam, strip-
ping gases, and fuel are also included.
An economic evaluation of each control disposal option
is also included. Capital costs for the controls are based
upon the type and size of the equipment required. Operating
expenses are based on the cost of materials, energy, and
manpower. Those control/disposal practices identified as
being potentially applicable are studied in greater detail.
After determining ranges of operating parameters and per-
formance characteristics, options found to be unsuitable for
controlling the waste streams under study are eliminated
from further considerations. These characteristics are
determined from available sources such as vendors, developers,
technical literature, handbooks and licenses. When infor-
mation is not available, engineering calculations and
estimates of performance are used. Commercial developmental
control systems proven to be both technically and economi-
cally practical are identified. Control/disposal costs for
these various options are tabulated.
Component emissions levels after controls are compared
with Multi-media Environmental Goals (MEG's). Emissions
exceeding the MEG's are noted.
Differences between the SRC-I (solid product) and SRC-
II (liquid product) processes are identified with regard to
process design and potential emissions; however, additional
information is required to quantitatively assess the dif-
ferences in emissions.
Finally, a glossary is provided for the definition of
terms that are not defined in the text.
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3.0 Outline of Basic System
3.1 Introduction
The Solvent Refined Coal (SRC) system utilizes a non-
catalytic direct-hydrogenation coal liquefaction process.
It coverts high sulfur and ash coal into clean-burning _
gaseous, liquid, and/or solid fuels There are two basic
fystem variations: (1) SRC-I, which produces a solid coal-
like product of less than 1 percent sulfur and 0.2 percent
ash- and (2) SRC-II, which produces low sulfur fuel oil
(0.2-0.5 percent sulfur) and naphtha product. Both system
variations produce significant quantities of gaseous hydro-
carbons, which are further processed in the SRC system to
synthetic natural gas and liquified petroleum gas products.
Some constituents that are formed during the hydrogenation
reaction are recovered as by-products. These include sulfur,
ammonia, and phenol.
This Standards of Practice Manual has been aimed pri-
marily at the SRC-II system, which at this point in time
seems to be the most promising alternative. For the purposes
of research, a theoretical 50,000 bbl/day (7,950 cubic
meters per day) SRC-II commercial facility has been designed.
The design is limited to showing basic process and waste
flows, and major pieces of equipment.
To facilitate an understanding of the basic components
of the SRC system, a modular approach is taken. In the
modular approach, the SRC-II system is subdivided into
operations. Each operation is accomplished by carrying out
a group of processes, a process being the smallest unit of
the overall system. Auxiliary processes perform functions
incidental to the functions of system operations. All pro-
cesses may be represented visually by process modules, which
display process input and output stream characteristics.
Sets of process modules may be used to describe SRC system
operations. The overall SRC system or the entire coal
liquefaction energy technology.
Pollution control/disposal processes are not entirely
amenable to the modular approach. For example, a dust
collection system for a dust stream from coal preparation
would fit into the modular approach while techniques foT
solid waste disposal encompass the SRC system as a whole
Those control/disposal practices that fit the modular
approach will be discussed as such, while the more general
areas will be discussed under separate titles in thf ?ext
-------
The basic SRC system is described using the modular
approach in the following section. A brief summary of the
most applicable pollution control options on a modular basis
is given in the section on control/disposal practices. The
more general control/disposal techniques are also summarized
in this section. Cost data for these recommended control/
disposal practices is summarized in the section on control/
disposal costs.
3.2 System Modules
The SRC-II system is divided into eleven system modules.
These include coal preparation, hydrogenation, phase (gas)
separation, solids separation, fractionation, hydrotreating,
solidification, hydrogen generation, gas purification,
cryogenic separation, and auxiliary facilities. The first
six modules are considered basic system modules, while the
remaining four are considered supporting operations.
Figure 1 depicts the overall flow pattern for the SRC-II
process including both process and waste flow streams.
Figure 2 presents major inputs and outputs of the SRC-II
system.
3.2.1 Coal Preparation Module
Coal preparation includes coal receiving, storage,
reclaiming and crushing, cleaning, drying, and pulverizing,
and slurry mixing. These processes, excluding slurry mixing,
are designed to clean and size-reduce the coal to levels
acceptable for use in the SRC liquefaction process. The
slurry mixing process mixes the processed coal with recycled
process solvent prior to entering the hydrogenation reactor.
Dryer stack gases, refuse, and wastewaters heavily laden
with suspended solids constitute major wastes, in this
module.
3.2.2 Hydrogenation Module
Hydrogenation consists of a slurry preheater and a
hydrogenation reactor. This module constitutes the key
operation within the SRC system where coal is transformed
into liquid products. All other subsequent operations focus
on refining the products generated in this module. Flue gas
represents the only significant waste discharged from the
module.
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• CO?
. t VAPOR LEAKAGE
• SPILLS
RW, COAL
• COAL OUST
• REFUSE
• VAPOR LEAKAGE
• WASTEHATER TO
TAILINGS POND
• SPILLS
I VAPUR LEAKAGE
• SPILLS
• VAPOR LEAKAGE
• SPILLS
• VAPOR LEAKAGE
• SPILLS
• RESIDUE
• VAPOR LEAKAGE
I SPILLS
• VAPOR LEAKAGE
• SPILLS
• TREATED
WASTEWATER
• SLUDGE
• TAIL GAS-1
(CO?)
• HYDROCARBON
VAPOR
Figure 1. SRC-11 System Overall Flow Diagram
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WASTE GAS 53,737 TPD (48,852 Mg/day)
PRIMARY
INPUTS
COAL 31,552 TPD
(28,684 Mg/day)
WATER 35,263TPD
(32,057 Mg/day)
OXYGEN 2,745TPD
(2,495 Mg/day)
SRC -II
SYSTEM
PRIMARY
PRODUCTS
LPG
903 TPD(821 Mg/day)
SNG
^1,434 TPD(1,304 Mg/day)
SRC r s,nRn TPD(5,527 Mg/day)
FUEL OIL
TPD(2,591 (Mg/day)
NAPHTHA t 570 TPD (518 Mg/day)
SULFUR „ 487 TPD (443 Mg/day)
AMMONIA > 70 TPD (64 Mg/day)
PHENOL
37 TPD (34 Mg/day)
SLAG 3,392 TPD(3,084 Mg/day)
Figure 2. Overall Material Balance for a
50,000 bbl/day (7,950 m3/day) SRC-II System
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3.2.3 Phase (Gas) Separation Module
There are a number of processes within the phase (gas)
separation module including: high pressure separation,
condensate separation, intermediate flashing, intermediate
pressure condensate separation, and low pressure condensate
separation. These processes separate hydrocarbon vapors and
other gaseous products from the hydrogenation reactor
effluent slurry and direct the solids/liquid portion of the
coal slurry to other processing areas. Process streams from
the module are directed to gas purification, solids separa-
tion, and fractionation. Waste emissions include accidental
and fugitive vapor discharges and material spills.
3.2.4 Solids Separation Module
The processes within the solids separation module
include feed flashing and solids separation. These processes
separate the residue (solids) stream from the liquid portion
of the feed stream. The residue is routed to the solidifi-
cation module to be prepared for gasification or disposal.
No wastewater streams are discharged from this module under
normal operations. Intermittent discharges include fugitive
vapors and accidental material spills.
3.2.5 Fractionation Module
The fractionation module consists of a vacuum flash and
an atmospheric distillation functioning to (1) separate the
high boiling liquid SRC product from lower boiling fractions;
(2) combine light streams for fractionation into light
products; and p) separate wash solvent for recycling to the
solids separation module. Evacuation of the flash vessel
may be accomplished by steam ejector which produces a continuous
wastewater stream or vacuum pump which produces a gaseous
waste stream. Preheater flue gas constitutes the only other
continuous waste stream. Intermittent discharges include
fugitive vapors and accidental material spills.
3.2.6 Solvent Hydrotreating Module
The solvent hydrotreating module consists of hydrogen
addition, catalytic reaction, flashing, oil-water separation
and stripping. Solvent hydrotreating involves the reaction '
of raw hydrocarbon streams with hydrogen to remove con-
-------
taminants such as organic sulfur and nitrogen compounds, and
to improve combustion characteristics. Flue gas from the
solvent preheater and wastewater from an oil-water separator
are the only continuous waste streams.
3.2.7 Solidification Module
The function of the solidification module in the SRC-II
system is to cool the residue into a solid suitable as a
feed to the gasifier. This function is accomplished by
feeding the liquid residue onto a Sandvik belt cooler. The
cooled solid residue is scraped off the belt with a knife
and routed to gasification. Emissions from the solidifica-
tion module include vapors and particulates from the belt
cooling process. Also, a solid waste stream results from
the disposal of residue in excess of gasifier requirements.
3.2.8 Gas Purification Module
Contaminated gases from phase (gas) separation and
solvent hydrotreating modules are purified by acid gas
removal. Contaminants removed include hydrogen sulfide,
carbon disulfide, carbon dioxide, and carbonyl sulfide. The
only continuous waste stream is the wastewater from the
amine regenerator section of acid gas removal unit.
Intermittent wastewater streams are accidental spills and
backwash of the amine filter. Atmospheric emissions include
gas leakage from sumps and storage vents and fugitive emissions
during maintenance operations.
Cryogenic Separation Module
Gas from the purification module flows to a series of
cryogenic units within this module, where the heavier hydro-
carbon gases are cooled and condensed to form a liquid. The
resulting liquid stream is charged to a fractionation tower
where various hydrocarbon products are removed. The remain-
ing gases are flashed and flow to another series of cryogenic
units and a de-ethanizer column, where the liquid product is
removed and overhead gases flow to another series of cryogenic
units.
Purified gas is separated into hydrogen, synthetic
natural gas, liquified petroleum gas, and light oils in this
module. Wastewater from light oil distillation is the only
waste stream from this module.
-------
3.2.9 Auxiliary Processes Module
Auxiliary processes include ammonia recovery, phenol
recovery, sulfur recovery, oxygen generation, raw water
treatment, cooling towers, steam and power generation,
product and by-product storage, wastewater treatment, and
hydrogen production. These processes recover by-products
from waste streams, furnish utilities (steam, water, power;,
and furnish feed materials (oxygen, hydrogen)^ Major waste
streams include wastewater from ammonia stripping towers;
wastewater from the phenol extraction towers; off-gas from
the sulfur recovery absorber; gaseous waste nitrogen from
oxygen generation; sludges from raw water treatment; waste-
water resulting from blowdown of cooling towers; flue gases
and ash from steam and power generation; spills, fugitive
vapors and dust from product and by-product storage; treated
wastewater and sludges from wastewater treatment; and slag,
spent catalyst, spent scrubbing solutions and flue gases from
hydrogen production.
3.3 Control/Disposal Summary
Table 1 presents a complete list of suggested control/
disposal practices for a 50,000 bbl/day (7,950 cubic meters
per day) theoretical SRC-II system. Waste streams and
suggested control measures are presented on a modular basis.
The wastewater treatment and flare systems do not easily fit
into the modular approach, since they apply to combined
waste streams from several modules. Therefore, they are
listed separately in Table 1. Suggested control/disposal
practices were based on the information developed in Section 5
entitled "Detailed Definition of Basic System." Selection
of the suggested process from the alternatives presented in
Section 5 was based on removal efficiencies, operation and
maintenance characteristics, and capital and operating
costs.
3.4 Control/Disposal Costs
A summary of capital and operating costs of control/
disposal practices for a theoretical 50,000 bbl/day (7 950
cubic meters per day) SRC-II facility is presented in Table 2.
10
-------
Cost data was based on literature and vendor informa-
tion. Equipment sizing was based on calculated flow rates
and concentrations of waste streams. In cases where waste
flows could not be calculated, such as with flare systems,
equipment sizing and cost estimation was developed by com-
parison with pollution control systems in oil refineries
having a similar throughput. Cost adjustments were made
using the six-tenths factors (see Glossary).
From Table 2, it has been calculated that about 32.2
million dollars of fixed capital investment would be spent
on pollution control, (as of July 1977). Using Ralph M.
Parsons Company's 1973 estimate of capital equipment cost
for a 10,000 TPD (9,091 Mg per day) SRC-II plant, it has
been estimated that roughly 179.6 million dollars would be
spent on major equipment for a 50,000 bbl/day (7,950 m^/day)
SRC-II plant (as of July 1977).
Using these estimates it has been calculated that about
18 percent of the total equipment cost for a commercial size
SRC-II facility would be dedicated to pollution control/
equipment.
3.5 Variations Resulting From Regional Siting Factors
The location of an SRC facility in other regions of the
United States can affect the process design, water consump-
tion, volume and composition of wastes discharges, and
pollution controls. Those factors which may be responsible
for regional variations are raw coal composition, water
availability, climate, and federal, state, and local regu-
lations regarding waste emissions to land, air, and water.
A detailed discussion of these factors is given in Chapter
5.0.
11
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TABLE 1. SUGGESTED CONTROL/DISPOSAL PRACTICES
FOR THE SRC-II SYSTEM*
Module/ Stream
Coal Preparation
Coal receiving
Storage
Storage
Reclaiming and
crushing
Dryer stack gas
Water recycle
system
Major Waste
Constituents
Coal dust
Coal dust
Runoff
Coal dust
Particulates
Coal/water
slurry
Quantity
(TPD)
8
8
74
8
32,842
3,432
Suggested
Control
Measures
Cyclone and
baghouse
Polymer
coating
Tailings
pond
Cyclone and
baghouse
Baghouse
Tailings
pond
Crushing and
cleaning
Dryer flue gas
Hydrogenation
Flue gas
Hydrocarbon
vapors
Wastewater
Treatment
Tramp iron
& refuse
8,484
Carbon dioxide, 3,961
nitrogen
Carbon dioxide, 14,758
nitrogen
Mine burial
Vented to
atmosphere
Vented to
atmosphere
Hydrocarbons not quantified Flare system
Ammonia, hydro- 4 201
gen sulfide,
hydrocarbons
Flare System Hydrocarbons not quantified
Phase Gas Separation
Hydrocarbon Hydrocarbons not quantify
vapors 4uantiried
Extended
aeration
with recycle
Vented to
atmosphere
Flare
system
12
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TABLE 1. SUGGESTED CONTROL/DISPOSAL PRACTICES
FOR THE SRC-IT SYSTEM* (Continued)
Solids Separation
Flue gas Carbon dioxide, 10,777 Vented to
nitrogen atmosphere
Hydrocarbon Hydrocarbons not quantified Flare system
vapors
Fractionation
Flue gas Carbon dioxide, 2,291 Vented to
nitrogen atmosphere
Hydrocarbon Hydrocarbons not quantified Flare system
vapors
Solvent Hydrotreating
Flue gas Carbon dioxide, 1,697 , Vented to
nitrogen atmosphere
Hydrocarbon Hydrocarbons not quantified Flare system
vapors
Solidification
Residue Mineral matter 2,377 Landfill
from coal
Hydrocarbon vapors Mineral matter not quantified Landfill
and particulates and hydro-
carbons
Gas Purification
Hydrocarbon Hydrocarbons not quantified Flare system
vapors
Cryogenic Separation
Hydrocarbon Hydrocarbons not quantified Flare system
vapors
Hydrogen Production
Scrubber gas Carbon dioxide 752 Vent to
atmosphere
13
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TABLE 1 SUGGESTED CONTROL/DISPOSAL PRACTICES
FOR THE SRC-II SYSTEM* (Continued)
Flue gas from
gasifier
Carbon dioxide,
nitrogen
Spent MEA solution MEA
Slag from gasifier Mineral matter
Hydrocarbon vapors Hydrocarbons
Auxiliary Facilities
Ammonia recovery None
1,128
4
1,692
not quantified
Vent to
atmosphere
Landfill
Landfill
Flare system
Phenol recovery
Sulfur recovery
Raw water
treatment
Cooling towers
Steam and power
generation
Product Storage
None
Light hydro- 12,077
carbons, hydro-
gen sulfide,
nitrogen oxides
Oxygen generation Nitrogen
9,997
Calcium car- 407
bonate
Treated blowdown 762
(metals and dis-
solved solids)
Flue gas (S02, 13,145
NOx, CO, parti-
culates)
Direct flame
incineration
Vented to
atmosphere
Landfill
Discharge to
river
MgO scrubbing
Hydrocarbon
vapors
not quantified Flare system
*0nly English units are presented due to space limitations.
14
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TABLE 2. CONTROL/DISPOSAL COSTS FOR A
50,000 bbl/day (7,950 m3/day)
SRC-II SYSTEM
Module/Stream
Capital Control
Costs C$1000)
Coal Preparation
Coal receiving
Storage (coal dust)
Storage (runoff)
Reclaiming & crushing
Dryer stack gas
Water recycle system
Crushing and cleaning
Flue gas
Annual Operating
Costs ($1000)
15.0
18.0
30.0
60.0
1000.0
Same as Storage Runoff
N.A.
None
N.A.
432.6 - 561.0
N.A.
N.A.
N.A.
2500.0 - 15,300.0
None
Hydrogenation
Flue gas
Hydrocarbon vapors
Phase Gas Separation
Hydrocarbon vapors
Solids Separation
Flue gas & hydrocarbon
vapors
Fractionation
Flue gas & hydrocarbon
vapors
Solvent Hydrotreating
Flue gas & hydrocarbon
vapors
Solidification
Residue
Hydrocarbon vapors and
particulates
None
None
None
None
None
None
N.A.
None
None
None
None
None
None
None
870.0 - 6900.0
None
15
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TABLE 2. CONTROL/DISPOSAL COSTS FOR A
50,000 bbl/day C7,950 m3/day)
SRC-II SYSTEM (CONTINUED)
Module/Stream
Capital Control
Costs C$1000)
Annual
Costs
erating
1000)
Gas Purification
Hydrocarbon vapors
Hydrogen Production
Scrubber gas & flue gas
Slag & MEA solution
Hydrocarbon vapors
Auxiliary Facilities
Ammonia recovery
Phenol recovery
Sulfur recovery
Oxygen generation
Raw water treatment
Cooling towers
Steam & power generation*
Product storage
Wastewater Treatment
Flare System
TOTAL
None
None
N.A.
None
None
None
572.0
None
180.9
None
29040.0
None
1136.5
208.2
32,260.6
None
None
189.0
None
None
None
4083.0
None
285.8
None
13140.0
None
121.0
4.5
21,504.9-40,463.3
MgO scrubbing used for the purposes of cost estimating;
16
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4.0 Existing Environmental Requirements
4.1 Introduction
No legislation currently exists directly pertinent to
the SRC or other liquefaction systems. Prior to commer-
cialization such legislation may be necessary at the
federal, state and local levels. A review of existing
standards and guidelines provides an idea of long range
goals in the area of environmental policy. Additionally,
existing standards governing related fossil fuel technolo-
gies could serve as the foundation on which standards for
liquefaction facilities will be based. However, at this
time it is impossible to project how stringent and how
comprehensive environmental regulations will be specific to
commercialized SRC or other liquefaction systems.
4.1.1 Federal Policy
National primary and secondary ambient air quality
standards have been established for several types of emis-
sions including particulates, hydrocarbons and sulfur oxides.
These standards are summarized in Table 81 found in the
appendices.
Additionally, standards for new sources have been esta-
blished. Specifically the standards for coal preparation
plants, petroleum liquid storage vessels, and fossil fuel
fired steam generators may be similar to the standards which
will be established for corresponding areas of SRC produc-
tion facilities. The steam generator data may be more
applicable to SRC utilization than it is to production. New
source standards possibly applicable are presented in Table
82 of the appendices.
National emission standards for air pollutants deemed
hazardous are established in conjunction with EPA. Standards
currently exist for mercury, beryllium and asbestos. Al-
though none of these is likely to affect SRC production,
future standards for hazardous air pollutants may be appli-
cable.
The Federal Water Pollution Control Act has established
long range national goals to limit point source effluent
concentrations. The act requires "application of the best
practicable control technology currently available" not
later than July 1, 1977. Six years later "application of
the best available technology economically achievable" will
be required to meet the national goal of "eliminating the
discharge of all pollutants."
17
-------
Effluent guidelines and standards exist for several
industries which have operations similar to SRC liquefaction.
Sble 83 of tne appendices includes standards and guidelines
for coal preparation and storage facilities and coking
operations, although coking operations are more directly
applicable to liquefaction processes based on pyrolysis. In
addition, a comprehensive system of standards has been
established for petroleum refinery operations. Ettluent
limitations for refineries are functions of overall refinery
size and the capacities and pollution potentials of the
refinery operations. A similar system may be developed for
liquefaction plants, the factors of plant size and process
type making the effluent limitations as equitable as possible,
The characterization of solid waste materials leaving
SRC conversion plants is incomplete. It is possible that
hazardous wastes are present. For this reason, subsequent
discussions of solid waste disposal shall include hazardous
waste disposal although the necessity of such measures is
not certain.
Guidelines for land use and ultimate disposal of solid
wastes are not as advanced as the legislation governing
emissions to air and water. The EPA requirements and re-
commendations most applicable to SRC generated solid wastes
are described in Table 84 of the appendices.
Not all constitutents of the products, by-products and
wastes generated by the SRC system are known. The Toxic
Substances Control Act was established to provide regulation
and testing of new and existing materials which could cause
unreasonable health and environmental consequences. Testing
may be prescribed for cumulative or synergistic effects,
carcinogenicity, mutagenicity, birth defects and behavioral
disorders. Should any SRC system components be characterized
as toxic, the development of technology capable of isolating
and disposing of those components will be necessary Since
continuing coal liquefaction research has not yielded a com-
plete characterization of the SRC system components and
complete determination of substances and concentrations of
those substances which should be considered toxic the
potential impact of SRC system components has been difficult
to assess.
18
-------
4.1.2 Environmental Policy of the State of Illinois
The site for the hypothetical SRC plant considered in
this study is located on the Wabash River in White County,
Illinois. Environmental legislation in Illinois is among
the most comprehensive of all states having the large coal
reserves needed to site commercial SRC facilities. Both air
quality standards and stationary source standards have been
promulgated. Water quality standards are dependent upon
water use classification.
Promulgated emission standards most likely to be ap-
plicable to SRC plants in the future include particulates,
carbon monoxide, nitrogen oxides, sulfur dioxide, and
fugitive particulate matter. Effluent limitations of interest
include heavy metals, phenols, BOD5, and suspended solids.
Pertinent sections of the Illinois Pollution Control
Board Rules and Regulations may be found in the appendices.
4.1.3 Environmental Policies of Other States
Appendix B includes the environmental policies of 16
states other than Illinois which, due to their abundant coal
reserves, are potential sites of commercial SRC facilities.
Emphasis is placed on standards and guidelines more stringent
than their federal counterparts or dealing with areas for
which no federal legislation currently exists. For example
the New Mexico legislation for coal gasification plants
limits hydrogen sulfide emissions to less than 10 ppm.
Since this is the only known regulation pertaining to hydro-
gen sulfide emissions from an industrial complex, it has
been used as a guide to assess emissions from the hypo-
thetical SRC facility. Some local requirements different
from those of the states are also discussed.
19
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5.0 Survey of Control/Disposal Practices
5.1 Introduction
This section presents a survey of currently available
and developing control/disposal practices that may be ap-
plicable to a commercial SRC facility. In the gas, liquid,
and solids treatment sections, stream characteristics are
first discussed with respect to their effect on control/
disposal options. Next, pollution control equipment appli-
cable to gas, liquid, and solid waste streams is discussed.
Finally, the most feasible alternatives for the treatment of
waste streams specific to SRC production are developed.
More practice-oriented pollution control/disposal options are
included in sections on final disposal, fugitive emissions
control, and accidental release technology. Process-oriented
pollution control measures are discussed in fuel cleaning
and combustion modification, as well as in accidental release
technology and fugitive emissions control. The last section
deals with regional variations, such as climate and regula-
tions, and how they may affect control/disposal specification.
The following text should provide the coal liquefaction
engineer with a working knowledge of the available and de-
veloping control/disposal practices, limitations and trade-
offs, and control/disposal options selected to apply to the
treatment of wastes generated by a commercial SRC facility.
5.2 Gas Treatment
5.2.1 Gas Stream Characteristics
The proper selection of control/disposal modules is
dependent on a number of gas stream characteristics.
Stream temperature, pressure, combustibility, reactivity
flow rate, flow rate variability, grain loading, and parti
cle size are the main factors influencing equipment selec-
tion.
Stream temperature will influence the volume of the
carrier gas and the materials of construction. The volume
20
-------
and are therefore impractical at higher temperatures. Dust
resistance and dielectric strength of gas both are tempera-
ture dependent and become factors in electrostatic precipi-
tators. Wet processes cannot be used with high temperatures
because of losses from boiling and evaporation. Filter
media can be Used only in the temperature range at which
they are stable.
Gas pressure much higher or lower than atmospheric
pressure requires designing control equipment .as a pressure
vessel. High pressure is especially compatible with high
efficiency scrubbers, since the available pressure can be
used to overcome the high pressure drop across the scrubber.
In absorption, high pressure facilitates removal and is re-
quired in some situations.
Combustible carrier gases must be above or below the
explosive limits with respect to an admixture of the gas
with air. The use of water scrubbing or absorption may
minimize explosion hazards. Electrostatic precipitators are
deemed unacceptable for treatment of combustible gases,
since they tend to spark and may ignite the gas.
Reactivity of a gas may require special construction
materials. Relatively compact control modules, such as
scrubbers, may be advantageous because corrosion-resistant
components costing relatively less, may be used.
The flow rate of the carrier gas will directly in-
fluence the size of the equipment and the velocity of the
gas through the equipment. The size of the equipment should
be minimized for economic reasons. The relationship between
equipment size and gas velocity should be optimized when
selecting equipment. Two considerations are apparent:
(1) reduction of equipment size increases pressure drop and
thereby increases power requirements for a given amount of
gas; and (2) the effect of gas velocity on removal efficien-
cies must be considered. In inertial separators, higher
velocities result in greater removal efficiencies up to the
point of turbulence. For gravity settlers, flow velocity
determines the minimum particle size that can be removed.
In venturi scrubbers, removal efficiency is directly pro-
portional to gas velocity.
Variations in flow rate also may influence equipment
selection. Filters adapt well to extreme flow variations,
although they also are subject to pressure drop_variations.
In other control systems, a variation in flow will change
the removal efficiency unless the equipment has been de-
signed for varying flow conditions. Two control units in
series having efficiency versus flow rate curves which
are complementary provide a feasible solution.
21
-------
The influence of grain loading may vary with control
units For example, cyclones are quite efficient at high
dust loadings, but the efficiency of electrostatic pre-
cipitators, another type of control unit, is reduced.
Particle size distribution is one of the most important
factors when considering particulate control equipment selec-
tion and performance. Inertial separators usually have low
removal efficiencies (50-90%) for particles under 20 microns,
while impingment separators (baghouses) and precipitators
may exhibit almost 100 percent removal of particles in the
0-1 micron size range. Thus, particle size distribution of
the pollutant stream should be known before selecting control
equipment.
5.2.2 Particulate Controls
5.2.2.1 Dry Collectors
Dry collectors separate particulates from the gas
stream either by gravity settling, impingement, and/or
inertial action. The major classes of dry collectors in-
clude gravity settling chambers, cyclones and multicyclones,
and dynamic precipitators.
Gravity settling chambers are large, rectangular cham-
bers with a gas inlet at one end and an outlet at the oppo-
site end. Settling occurs due to a reduction in gas vel-
ocity. Industrial applications of settling chambers are
limited to the removal of particulates over 40 microns in
diameter. Their use is limited to pretreatment to remove
coarse and abrasive particles for the protection of more
efficient collection equipment that may follow. Performance
is described by the following equation (1):
P = 100 UtL
HV
where* P = efficiency of unit (% wt particles settling
at Ut) 5
Ufc = settling velocity of dust (ft/sec)
L = length of chamber (ft)
H = height of chamber (ft)
V = velocity of gas (ft/sec)
22
-------
The settling velocity is calculated by assuming Stoke' s law,
as follows:
Ut *
18(7
where* D = particle diameter (ft)
^- = gas viscosity [Ib m/(ft) (sec)]
gc = 32.2 (ft/sec2)
p = particle density (Ib/ft )
o
P = gas density (Ib/ft3)
Minimum particle size collected at 100 percent efficiency is
determined as follows (1):
n = / 18 [i HV
P Vgc£ (V
where* D = minimum particle diameter collected at 10070
p efficiency (ft)
*Metric conversion factors are given in Appendix A.
Cyclones and multicyclones separate particles by cen-
trifugal force. In the cyclone, the particulate gas stream
enters the cone-shaped collector tangentially and at low
velocities. The particulate-laden gas mixture flows down-
ward in a spiral of increasing velocity. The inertial
force separates the dense particles from the gas. As the
gas travels down the narrowing core, the creation of a
vortex causes the gas to reverse its downward path. This
creates a vacuum which carries the clean gas out of the top
of the collector. Particles down to 10 microns can be
effectively removed. The multicyclone consists of parallel
rows of small diameter cyclones, provided with a common
inlet tube. The particulate-laden gas is caused to swirl
by revolving vanes located at the tube entrance. A vortex
is formed and the clean gas leaves the collector through
the inner tube; the particulates collect in a dust collector
beneath the multicyclone.
23
-------
The separation efficiency of cyclones increases with _
an increase in grain loading, particle size, and gas velocity,
Design characteristics, such as cyclone body length and
inner wall smoothness, will affect particulate removal
efficiency. Cyclones up to 9 inches (23 cm) in body diameter
are considered high efficiency cyclones. Cyclones in general
provide low efficiencies for pollution control and are_least
expensive. Multicyclones are small diameter cyclones in
series designed to handle large gas flow rates. Efficiencies
of particulate removal with respect to particle size are
given in Table 3.
TABLE 3. EFFICIENCY OF CYCLONES (1)
Efficiency Range (% Collected)
Particle Size
Less than 5
5-20
15-40
Greater than 40
Conventional
Less than 50
50-80
80-95
95-99
High Efficiency
50-80
80-95
95-99
95-99
Where possible, specific calibration curves should be
used when evaluating the performance of a cyclone or multi-
cyclone. Some approximate relationships are available where
calibrated data are not available.
The cut size (Dcp) in a cyclone is the particle size
that can be collected at 50 percent efficiency It can be
calculated by the following equation (1)•
•1£
. - , , 9 W,
cp
(P -pj
where* D = cut size (ft)
V = gas viscosity (Ib/ft sec)
VL = inlet width (ft)
Ne = number of effective turns in a cyclone
(5 to 10 in most cases)
V± = inlet velocity (ft/sec)
24
-------
Pp = particle density, (lb/ft3)
P = gas density (lb/ft3)
Removal efficiency is highly dependent on gas flow rate
in cyclones. Changes in efficiency with respect to flow
rate variability can be estimated by the following equa-
tion (1) :
where* N]_ = weight percent collection efficiency at
flow rate q-, .
®2 = weight percent collection efficiency at
flow rate q^.
^Metric conversion factors are given in Appendix A.
Dynamic precipitators use centrifugal force generated
by rotating impellers to separate particulate matter. They
are generally considered more efficient than cyclones; how-
ever, specific information on the performance of these units
is not available.
5.2.2.2 Electrostatic Precipitators
Electrostatic precipitators operate by using a direct
current voltage to create an electric field between a nega-
tively charged discharge electrode and a positively charged
collection electrode. As the suspended particles (or
aerosols) pass between the electrodes the particles are
charged and collected on the oppositely charged electrode.
The deposited matter is removed by rapping or washing the
electrode. The precipitated material is then collected in
hoppers for final disposal.
Electrostatic precipitators exhibit removal effici-
encies of 90 to 99.9 percent within a particle range of less
than 0.1 microns to 200 microns (1,2). Precipitators have
the ability to handle very large flow rates at high effici-
encies. They can operate in a wide range of temperatures
and pressures, up to 800°C and 50 atmospheres, respectively
(1). Their major disadvantages include high initial cost
and little adaptability to changing process conditions.
25
-------
Removal efficiency is directly related to the volu-
metric gas flow rate, as described by the following equation
(1):
F . x_e i_l|Ll
where*
F = efficiency, decimal evaluation
2
A = collecting area (ft )
3
Q = volumetric flow rate (ft /sec)
W = drift velocity (ft/sec)
The drift velocity, W, can be calculated by the following
equation (1):
W = (1 + 1.72 L ) D EQE
D -i—~—-—*-—
where* W = drift velocity (feet/sec)
D = particle diameter (feet)
L = mean free path of gas (feet)
E = precipitation field density (KV/in)
EQ = corona field strength (KV/in)
H = absolute viscosity of the gas (Ib/sec-ft)
^Metric conversion factors are given in Appendix A.
Removal efficiencies are dependent on the temperature
and humidity of the gas stream. An increase in humidity
and/or a decrease in temperature will cause a decrease in
sparkover voltage, i.e., the voltage at which the gas be-
comes locally conductive. At sparkover voltage there is a
dramatic decrease in the electric field strength and hence a
large power loss. Such gas streams as dryer off-gases may
be too humid to separate particulates by electrostatic
cipitation.
26
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5.2.2.3 Bag and Fabric Filters
Baghouses and fabric filters are used for high effi-
ciency removal (up to 99.9%) of particulates from gases.
Baghouses and fabric filters, along with inertial dry col-
lectors, share the following characteristics.
(1) Particulates are collected dry and in usable
condition.
(2) Gases are not cooled or saturated with moisture.
(3) Solids handling accessories must be properly
designed to avoid secondary dust generation.
(4) Unlike scrubbers, filters do not add moisture to
the cleaned exhaust and do not create a plume.
(5) There is an explosion hazard risk; proper fire
protection equipment must be on-site.
There are two major types of bag filters. Envelope-
type bags prove maximum surface area per unit volume, but
suffer from dust bridging problems and are difficult to
change. Tubular bags are open at one end and closed at the
other, with the direction of filtering being either inside-
out or outside-in. An outside-in design requires a frame to
prevent bag collapse and has a shorter bag life. Tubular
filter bags are often sewn together to form multibag sys-
tems; the major disadvantage is costly bag replacement.
Different gas characteristics require different filter
media for proper operation. There are three main filter
types: paper filters, woven fabric filters, and felted
fabric filters. Paper filters are used for sampling and
analysis and clean room use rather than in large industrial
units. Woven fabric filters are employed with low air/cloth
ratios, generally from 1.5 to 6 cfm/ft* (7.6 x 10-3 to 3.0 x
102 m3/S/m2) (1). Fabric life is a function of operation
temperature, frequency and method of cleaning, and proper-
ties of particulates and carrier gas. Average life of woven
fabric filters ranges from 6 to 18 months. Performance of
some filter fabrics are summarized in Table 4 (1). The more
efficient felted fabrics are more expensive, but can be
utilized with high air/cloth ratios typically 12.1 cfm/ftz
(6.1 x 10-2 m3/S/m2) (1). Felted fabrics require thorough
cleaning for proper operation.
27
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TABLE 4. CHARACTERISTICS OF FILTER FABRICS (1)
ho
do
Midi*1
Cotton
Dacron
Orion
Nvlon
Dynel
Polypropylene
Creslan
Vycron
Nomex
Teflon
Wool
Glass
•/•
180
275
250
250
180
225
275
300
450
500
200
550
Cimi/ij
1.6
1.4
1.2
1.1
1.3
0.9
1.2
1.4
1.4
2.3
1.3
2.5
a, in
G
G
G
G
F
G
G
G
E
E.
F
E
«'t'
G
F
G
G
F
F
G
F
E
E
F
E
I'lii/wul H.IH
Ahrmian
F
G
G
E
F
E
G
G
E
P-F
G
P
,„,,,
Sliakinf.
G
E
G
E
P-F
E
G
E
E
G
F
P
„,„.,«
G
E
E
E
G
G
E
E
E
G
G
F
\liiu-tul
. Vri.lv
P
G
G
P
G
E
G
G
P-F
E
F
E
a
Or«m,u-
G
G
G
¥
G
E
G
G
E
E
F
E
'u-minil K,-it-.li
Aft-rife
F
F
F
G
G
E
F
G
G
E
P
G
iitir
Afjn.lf
F
G
G
F
G
G
G
G
G
E
P
E
E
E
E
E
G
G
E
E
E
E
F
E
c.w
Low
Moderate
Moderate
Moderate
Moderate
Low
Moderate
Moderate
High
High
Moderate
High
E-Excellent C-Good F-Fair
Metric conversion factors are given in Appendix A.
-------
Cleaning methods affect air/cloth ratios significantly,
Cleaning by shaking can be accomplished manually or mech-
anically, intermittently or continuously. Reverse jet
cleaning uses compressed air to remove filter cake from the
fabric. Reverse air flexing is accomplished by reversing
gas flow to cause a filter backwash effect.
Air-to-cloth ratios for coal dust are shown for dif-
ferent types of cleaning mechanisms in Table 5.
TABLE 5. AIR-TO-CLOTH RATIOS FOR COAL DUST (1)
Type of Cleaning Air/Cloth Ratio
cfm/ft2
Shaker
Reverse Jet
Reverse Air Flexing
2.5 -
10 -
1.1 -
3.0
12
2.0
m3/S/m2xlO"2
1.
5.
0.
3 -
1 -
6 -
1.5
6.1
1.0
5.2.2.4 Wet Scrubbers
Wet scrubbers comprise a large variety of equipment,
the main types being spray chambers, impingement plate
scrubbers, venturi scrubbers, cyclone-type scrubbers,
orifice-type scrubbers, and packed bed scrubbers. Low
pressure scrubbers, such as spray towers collect coarse
dusts in the range of 2 to 5 microns. High pressure drop
venturi scrubbers are effective at removing 0.1 to 1.0
micron particles at up to 98 percent efficiency (2).
The wet scrubbers remove dust from the carrier gas
stream by contacting it with water or a specified scrubbing
liquor. The following is a list of the characteristics of
wet scrubber technologies (1).
(1) The flue gas is both cleaned and cooled.
(2) Stack effluent will contain fines, mists, and
steam plume.
(3) The temperature and moisture content of the inlet
gas is essentially unlimited.
(4) Corrosive gases can be neutralized with proper
scrubbing liquor selection.
29
-------
(5) Consideration of freezing conditions is important.
(6) Hazards of explosion are reduced.
(7) Equipment is relatively compact and capital cost
is less than dry collection equipment.
(8) The equipment is highly efficient in collecting a
wide range of particulate sizes.
(9) Removes simultaneously gaseous pollutants such as
sulfur dioxide, hydrogen sulfide, and nitrogen
oxides.
(10) Maintenance cost is lower because of simple
design.
(.11) Water utilization is high and is an important
consideration in certain areas.
Efficiencies of various scrubbers at different particle
sizes are shown in Table 6. Wet scrubbers than can be
applied to coal dusts and fly ash control are shown in
Table 7.
TABLE 6. EFFICIENCY OF SCRUBBERS AT
VARIOUS PARTICLE SIZES (1)
Percentage Efficiency at
Type of Scrubber 50/u
Jet- impingement scrubber
Irrigated cyclone
Self-induced spray scrubber
Spray tower
Fluid bed scrubber
Irrigated target scrubber
Disintegrator
Low energy venturi scrubber
Medium energy venturi
scrubber
High energy venturi scrubber
98
100
100
99
99+
100
100
100
100
100
83
87
94
94
98
97
98
99+
99+
99+
40
42
48
55
58
50
91
96
97
98
30
-------
TABLE 7. APPLICABILITY OF VARIOUS WET
SCRUBBERS TO COAL DUSTS AND FLY ASH (1)
Type of Scrubber
Elbair scrubber
Floating bed
Flooded bed
Cyclonic
Self-induced spray
scrubbers
Mechanically induced
spray
Venturi scrubbers
Coal Dust
X
X
X
X
Fly Ash
X
X
X
X
X
Collection
Efficiency (%)
99+, 99
N.A.
N.A.
96+
N.A.
N.A.
96, 99+
N.A. = Not Available
5.2.3
Hydrocarbon Emission Controls
Four types of control technologies that can be employed
to treat gas streams containing hydrocarbons are: (1)
direct-fired and catalytic afterburners, (2) flares, (3)
condensation systems, and (4) adsorption systems.
Direct-fired and catalytic afterburners employ high
temperatures to carry out oxidation of organics to carbon
dioxide and water. They are applicable to gases with hy-
drocarbon content below the limit of flammability. In gen-
eral, catalytic afterburners, with platinum or palladium
catalysts to facilitate oxidation, utilize temperatures
lower than the direct-fired afterburners. A comparison of
temperatures required to convert various combustibles to C02
and water for both direct-fired and catalytic afterburners
is given in Table 8.
TABLE 8. COMBUSTION TEMPERATURES IN DIRECT-FIRED
AND CATALYTIC AFTERBURNERS (1)
Combustible
Methane
Carbon Monoxide
Hydrogen
Propane
Benzene
Ignition Temperature (°C)
Direct-Fired Catalytic
632
665
574
480
580
500
260
121
260
302
31
-------
Direct-fired afterburners have exhibited conversion effi-
ciencies of more than 99 percent while catalytic units have
slightly lower efficiencies (85 to 92 percent) (2).
Direct-fired afterburners are designed to operate at
about 1400°F (760°C) with retention times of at least 0.8
seconds (2). Catalytic afterburners operate at about 1000 F
(538°C) with retention times of 0.05 to 0.1 seconds (2).
Operating temperatures are sustained by combustion of a fuel
gas. This fuel consumption can only be partially offset by
heat recovery systems in which heat from exhaust gases is
used to preheat incoming gases. Another general disadvantage
of afterburners is that they produce no saleable product.
Catalytic afterburners have a number of important ad-
vantages and disadvantages compared to direct-fired units.
Because they operate at lower temperatures, they have Blower
operating and maintenance costs. Initial capital equipment
cost, however, is higher. Catalysts also are easily poisoned
by heavy metals, halogens, and sulfur compounds, or fouled
by inorganic particulates. Catalytic incineration devices
have been judged by the Los Angeles County Air Pollution
Control District to be incapable of meeting efficiency
requirements of 90 percent conversion.
Flares incorporate direct combustion of the pollutant
gases with air, and can be used only if the organic con-
centration of the gas stream is in the flammable range.
Flaring is the least costly form of incineration since the
contaminants emitted are used as the fuel. An auxiliary
fuel is usually made available to maintain a flammable
mixture in the event the organic concentration drops below
the lower explosive limit.
In condensation systems, the gas stream is cooled and
compressed to facilitate condensation of vapor phase pol-
lutants. Condensation is applicable when pollutants with
dewpoints above 30°C are present in high concentrations.
Condensers are normally used in conjunction with other
control equipment, since they are a relatively inefficient
means of control at lower organic concentrations.
Carbon adsorption systems employ parallel cycling beds
of activated carbon to adsorb gaseous organic pollutants.
Removal efficiencies are claimed to be up to 95 percent (1).
Carbon bed regeneration and desorption of organics is
accomplished by a number of means, i.e., steam contacting,
hot inert gas contacting, or vacuum desorption. The con-
centrated organic vapor is either incinerated or recovered
as solvent by condensation, distillation, or adsorption
32
-------
If pollutant concentration is below 0.1 percent by
volume, carbon regeneration is not economical and a non-
regenerative system should be utilized, in which spent
carbon would be disposed of or regenerated in external
equipment. There are a number of important design criteria
that must be considered when selecting carbon adsorption
systems (1)•
The capacity of the solid adsorbent decreases with
increasing temperature; therefore operating temperatures
should be kept below 40°C for efficient operation. Because
the adsorption reaction is exothermic, there is a tempera-
ture rise of about 10°C for dilute organic solvent-air
mixtures. However, concentrated hydrocarbon streams can
cause temperatures to rise to dangerously high levels,
presenting an explosion hazard if the gas-air mixture is
within explosive limits. Excessive temperature fluctuations
must be avoided since periods of temperature rise can cause
massive desorption (1).
Operational problems are mainly related to the adsor-
bent surface. High molecular weight molecules may not be
easily desorbed under normal regeneration; high temperature
steam stripping may be required to control organic build-up.
Particulate matter may adhere to the adsorbent surface and
become almost impossible to remove. Plugging may occur from
particulate build-up. In some operations it may be neces-
sary to place a filter at the inlet to the adsorber to
protect against particulate entry. Corrosion can be a
problem if steam stripping is used for adsorbent regenera-
tion. Light hydrocarbons, such as methane and ethane, are
not effectively adsorbed and will be present in the off-gas
The major advantages of carbon adsorption systems are
that a saleable organic solvent may be recovered through
desorption, or the desorbed concentrated gaseous pollutant
can be incinerated in a much smaller unit with much less
fuel consumption than if the original gas stream were in-
cinerated. Another major advantage of carbon adsorption is
that sulfur oxides, nitrogen oxides, and carbon monoxide are
concurrently adsorbed with organic vapors; however, no
information was found on removal efficiencies.
5.2.4 Sulfur Dioxide Control Technology
There are well over thirty processes that have been
developed for the control of S02 stack emissions. They can
be divided into a number of broad categories, namely dry
additive injection (limestone), dry adsorptive processes,
wet adsorption processes, adsorption by charcoal, and
catalytic conversion processes.
33
-------
The dry additive injection process involves_the in-^
troduction of pulverized limestone or dolomite directly into
the flue gas. The additive reacts with sulfur dioxide and
oxygen in the flue gas to form calcium or magnesium sulrate.
Major characteristics of dry additive injection techniques
are listed below (1).
(1) Flyash and limestone particles are carried along
in the gas stream and must be removed by another
pollution control unit.
(2) Capital cost is low. Feed materials are rela-
tively inexpensive.
(3) S02 removal efficiencies are low.
(4) Operational difficulties included sintering and
slagging of limestone.
(5) There is little corrosion and no interference with
boiler operation.
(6) It is a throw-away process and presents solid
waste disposal problems.
Dry adsorption processes utilize a bed of metal oxide
to adsorb S02 from the gas stream. The metal oxide is
converted to the sulfated form and must be regenerated. A
list of characteristics of dry adsorption techniques is
given below:
(1) Adsorbent generation is difficult and the adsor-
bents lose their activity after a number of re-
generation cycles.
(2) The most effective adsorbents are very expensive.
(3) Fly ash and metal oxide particulates must be
removed in a second pollution control unit.
(A) Little corrosion of metal surfaces occurs, and in
most cases there is no pressure loss through the
system.
(5) A saleable by-product such as ammonium sulfate can
be produced; hydrogen sulfide, which can be
routed to the Stretford unit for recovery of sul-
fur, may be produced.
(6)
Particulate matter may plug absorbent beds.
34
-------
Wet adsorption processes employ a spray tower or other
wet scrubber to carry out S02 removal. The adsorbent liquid
is usually a water solution of lime, dolomite, metal sul-
fite, magnesium and manganese oxides, ammonia, or caustic
soda. Products from regeneration are concentrated S02,
ammonium sulfate, or a waste stream. A number of charac-
teristics in the processes are listed below (1):
(1) Wet adsorption methods are not restricted by
temperatures or residence times within the fur-
nace.
(2) They can be added to existing units without
boiler modifications.
(3) Heat loss due to scrubbing reduces plume buoyancy
and the effluent gas stream must be reheated.
(4) Adsorbents have a capacity for heavy loading but
require complex regeneration unless a throw-away
system is acceptable.
(5) Wet adsorption techniques remove particulates and
NOX as well as sulfur oxides.
C6) Mist eliminators must be included to avoid excess
plume opacity.
C7) Efficiencies in most wet absorption processes are
better than 90 percent.
Charcoal adsorption systems utilize commercial acti-
vated carbon to chemisorb S02 from the gas stream. The S02
is oxidized to sulfuric acid in the presence of water
vapor, and oxygen. The spent carbon is regenerated ther-
mally. Both dry and wet adsorption technologies are avail-
able. Advantages and disadvantages of charcoal adsorption
systems are listed below:
(1) Smaller adsorber-desorber units are required due
to the short retention periods.
(2) Problems with regeneration are inherent including
loss of carbon due to CO and C02 formation during
thermal regeneration.
(3) Wet processes require added equipment and cor-
rosion resistant construction.
(4) Due to the continuous movement of the charcoal
material in the system, carbon abrasion becomes a
problem.
35
-------
(5) Wet processes generate a wastewater stream and
reduce plume buoyancy.
In catalytic conversion processes, gaseous sulfur
dioxide is oxidized to sulfur trioxide in the presence of a
vanadium catalyst. The SCU reacts with water vapor in the
flue gas and is condensed as sulfuric acid. The charac-
teristics of catalytic conversion of S02 are discussed
below (1):
(1) It is a simple process with no catalyst recycling
required. There is no heat loss and plume buoy-
ancy is maintained.
(2) Corrosion resistant materials are required.
(3) A particulate control unit is required to remove
fly ash so that reactor plugging does not occur.
(4) The gas stream must be reheated to a high tempera-
ture for efficient conversion (371 to 472°C).
(5) A mist eliminator or electrostatic precipitator
must be added at the end of the process.
(6) A saleable by-product (H2S04 or NH^SO^) is pro-
duced.
Because of the large number of sulfur dioxide removal
processes, it is not possible to discuss each one separ-
ately. A summary of known removal processes is given in
Table 9.
5.2.5 NO Emission Control
JI X ""
There are two major techniques for nitrogen oxide
control, i.e., combustion modification and flue gas treat-
ment. Combustion modification techniques prevent the forma-
tion of nitrogen oxides; flue gas treatment techniques
provide potential alternate methods to control or reduce the
quantity of nitrogen oxides once they are formed. Combustion
modification techniques are discussed in Section 5.6. No
NO removal processes are presently available.
X
36
-------
TABLE 9. SO REMOVAL SYSTEMS (3)
_ -x- • •
PROCESS
SORPTION
SORBENt
PRODUCTS
REGENERATION
RAW MATERIAL
Low Temperature Aqueous Sorption and
Sea water
Sulfacid
Westvaco
Thiogen
Ozone
Soda
Soda - ZnO
Soda-Sulfite
Potassium sulfite-
bisulfite
Ammonia
Ammonia
(Guggenheim,
Cominco)
Ammonia-
zinc oxide
Ammonia-
hydrazine
Wet lime-limestone
Basic aluminum
sulfate
Magnesium oxide
and hydroxide
(Chemico-basic)
Manganese oxide
and magnesium
hydroxide
Formate
Citrate
Sulfidine
Organic scrubber
DMA(brimestone)
Reinluft
Boliden
Catalytic
oxidation
Alkalized
alumina
Alkali
Alkaline-earth
Lignite ash
Mn02 (DAP)
CuO
Liquid SO2
Molten
carbonate
Liquid claus
Solid claus
Transition metal
on alumina
Flyash
Low temperature
reduction
Direct reduction
H2O
H2O. charcoal
H20
H20.03.MnS04
NajCOj
NaOH,Na2SO3
Na2SO3
K2CO3.K2SO3
NH4OH
NH4OH
NH3
NH3-N2H4
CaCO3,CaO
AI(OH)SO4
MgO.Mg(OH)2
Mg(OH)2.
MnO2
KOOCH
Sodium citrate
Xylidine or
toluidine
H2SO3,sulfites
H2S03,H2S04
"
H2S03
H2S04
Na2SO3
Na,SO4
NaHSOj
"
KHSO3,K2S20S
NH4HSO,, '
(NH4)2S04
NH4HS03
NH4
(N2HS)2S03,
(N,H5)2S04
CaSO3,CaSO4
AI(OSO2H)SO4,
AI(OSO3H)SO4
Mg (HS03)2.
Mg SO3,
Mg S04
MgSO4,MnSO4,
MnS2O6
K2S203
CaO, Mn2+
-
H2S
BaS
-
ZnO
Electrolysis
—
H2S04
Steam,H2SO4,CaO,
Coke, CH4
ZnO
Steam
CaO, CaCO3
NH3
Coal
Steam, CO2, CO
HSO3 complex H2S
Low Temperature Aqueous borption and
-
-
PRODUCTS
Regeneration
CaSO4
Dilute H2SO4
S,S02
S,S042,S2043
-
ZnSO4,ZnSO3,
ZnO,Na2SO3,
S02
H2S04
S02,H2SO4
SO2, S,
(NH4)2S04
CaSO4,NH3,S
S02
SO2,N2H4,
(NH4)2S04
CaSO4,SO2
(NH4)2S04,
H2S04,
MgO.SO2
S, H2S,
SO2,Mn02
H2S. S
5
Regeneration
S02
Glycol, Amine — Steam SO2
Medium Temperature Liquid or Solid Sorption and Regeneration
Dimethy
analine
Activated
charcoal
Coke
V2OS or
NO2 catalysts
N20,AI2O3
Nahcolite
CaO, MgO
CaO
MnO2,ZnO
Cu 1- Al oxides
Liquidification
Carbonates of
Li, Na, K
-
-
-
-
—
-
S02
SO,
—
S03
Na2SO4,AI2SO4
-
MgSO4
CaS03
MnSO4,ZnSO4
CuSO4
S02
SOT2 and SOJ2
of G.Na, K
-
-
-
-
—
-
Reformed CH4
Steam
—
NH3
Reformed CH4
-
CO
-
NH4OH
CH4,H2
—
C + H2O,
CO * H2
H2S
AI2O3,H2S
Oxides, CO
Flyash, CH4
Oxides. CH4,
CO, H,
Oxides, CH4.C
S
S02,H2S04
S
SO1,HaSO4,
(NH4)2S04
S, H2S
so;2
C, CaS04.
MgS04
SO2, CaO
(NH4)2S04,
SO2, MnO2
S
—
H2S
S
S
S
S
S
S
SPONSORING
ORGANIZATIONS
Battersea, Haenisch-Schroeder,
Kanagawa
Lurgi, Hitachi
Westvaco
Balakalla smelter
TVA
UOP. Wisconsin Power,
Peabody Coal, Dow Chemical.
Nevada Power
UOP, Wisconsin Power, Aerojet,
Ohio Corp., Peabody & Wellman
Powers (Olin Corp.), Johnstone
Stone & Webster - Ionics
Tampa Electric, Wellman-Lord,
Ohio-Matheson
Simon-Carves. Olin-Matheson,
Trail, Kiyoura, Mitsubishi,
Showa-Denka, Guggenheim
ASARCO. ICI, Trail, Mitsubishi,
Showa-Denka, Wade, TVA
U.S. Bureau of Mines
(Morgantown)
Aerojet General
Bechtel-Still, HovJden-ICI,
Combustion Engr., TVA, Zurn,
Babcock & Witcox, Peabody,
A.B. Bahco (Research Cottrell),
Battersea, UOP
ICI, Outokumpu Oy, Boliden
Boston-Edison, Chemical
Const. Corp., Babcock & Wilcox,
U.S.S.R.
Zinkendustrie,
Wilhelm Grillo
TVA
Consolidation Coal
U.S. Bureau of Mines
(Salt Lake City)
Norddeutsche Affinerie
Arthur D. Little
ASARCO - Phelps Dodge
Commonwealth Assoc.,
Reinluft. Hitachi.
Bergbau, Torschung
Boliden. ICI, Trail.
Cominco, Billingham
Metropolitan Edison,
Monsanto-Penelec,
Tyco, Kiyoura,
SNPA-Topoe, III. Power
CEGB. U.S. Bureau of Mines
(Bruceton)
Precipitator Pollution Control
Battefle, Combustion Engr.,
Wikert, CRIEPI.TVA,
Steinkohlen-Elektrizilat
Carl Still
Mitsubishi, Aerojet
UOP, Exxon..Shell, U.S. Bureau
of Mines (Bruceton)
Tacoma. Canadian Ind. Ltd.,
Copper Cliff Spanish Smelter
Atomics International,
Consolidated Edison, Garrett.
North American Rockwell
Institut Francis du Petrole,
Nippon, UOP
Princeton Chemical Research
Chevron Research. U.S. Bureau
of Mines (Twin Cities)
GATX
Allied Chemical.
Texas Gulf Sulfur
Outokumpu Oy
Source: Information Circular 8608, U.S. Dept. of the Interior, Wash. DC
37
-------
Potential techniques for NO treatment are categorized
as follows: x
(1) Catalytic decomposition
(2) Catalytic reduction
(3) Adsorption by solids
(4) Absorption by liquids
Catalytic decomposition processes would convert nitro-
gen oxides to nitrogen and oxygen gas. At present no com-
mercially available catalysts have been found which would be
sufficiently active at reasonably low temperatures. Indica-
tions are that if and when the catalyst is found, it may
have to be used at temperatures above 1000°F (538°C) (1).
In catalytic reduction processes, a reducing agent
would react with nitrogen oxides to form elemental nitrogen
and an oxidized compound. Ammonia is known to be capable of
reducing NOX selectively in an oxygen-containing atmosphere.
If found effective, the technique might also simultaneously
control sulfur oxide emissions. The reduction reaction
requires temperature control and a catalyst, which presently
is not available (1).
Both activated carbon and silica gel have been found to
adsorb nitrogen oxides to a considerable degree; activated
carbon has demonstrated better performance. Other potential
solid adsorbents are metal oxides, particularly manganese
and alkalized ferric oxides. Severe attrition of the sor-
bent is a major technological problem yet to be solved (1).
Absorption of nitrogen oxides by alkaline solutions
seems to be the most promising control technique. For this
method, equimolar concentrations of NO and N02 are essential
in the flue gas. The most feasible possibility for equi-
molar control is the recycle of N0£ formed during absorbent
regeneration. A number of liquid absorbent processes are in
the pilot plant stage. None are commercially available at
present (1).
The TYCO process, as shown in Figure 3, produces both
nitric and sulfuric acids from oxides of sulfur and nitrogen
in the flue gas. The process requires the recycle of NOo to
oxidize S02 to sulfuric acid. The N02 is oxidized to form
^203. A high efficiency scrubber would be required for
2« •
38
-------
CLEANED FLUE GAS
SCRUBBER
N02
HN03
REACTOR
DECOMPOSER
HNO,
TLUE GAS
NOHS04
.OXIDIZER
S02 + N02+ H20-^
H2S04+ NO
SCRUBBER
NO 4- N02 + 2H2S04
2NOHS04+ H20
DECOMPOSER
2NOHS04+ H20 +
1/2 02-»-2N02-t-
2H2S04
HN03 REACTOR
3N02 + H20 -*•
2HN03-I-NO
Figure 3. TYCO's Modified Sulfuric Acid
Scrubbing Process For NC) Removal (1)
39
-------
The lime scrubbing process would be similar to the
process discussed under sulfur oxide controls. Oxides o
nitrogen and sulfur are simultaneously absorbed by a lime
slurry in a spray tower. The calcium nitrite formed is
decomposed and NO is oxidized to N02 which is recycled to
the flue gas to control equimolarity between NO and N02-
Nitric acid and gypsum are formed as by-products, as shown
in Figure 4 (1).
Magnesium hydroxide can also be used simultaneously to
adsorb oxides of nitrogen and sulfur. Magnesium sulfite is
removed in a settling tank while the overflow, containing
magnesium nitrite, is evaporated and decomposed. _NO is
formed in the decomposition reaction. It is oxidized to NO2
and recycled to the flue gas for equimolar control. The
magnesium sulfite is decomposed to MgO and S02- Process by-
products are sulfuric acid and ammonium nitrite. The pro-
cess is shown in Figure 5 (1).
The urea scrubbing process involves the reaction of
nitrogen oxides with an acidic urea solution to form nitrous
acid solution. The nitrous acid reacts with urea to form
nitrogen, water, and carbon dioxide. This technique has
been proven on the pilot scale. Cost of urea is the major
operating expense. No saleable products are recovered in
the process, which is shown in Figure 6 (1).
Removal efficiencies for any of the N02 control tech-
nologies were not available.
5.2.6 Control Module Selection
There are seven major gaseous waste streams which must
undergo treatment to remove one or more specific pollutants.
Table 10 lists the seven gas streams and the contaminants
that might have to be removed. Characteristics of the gas
streams which may prove important in equipment selection are
also provided. Regulations with respect to emissions of
specific pollutants have been discussed in Chapter 4.0.
Dust streams from coal storage, receiving, reclaiming,
and crushing and from sulfur and SRC storage will generally
possess highly variable flow rates and grain loadings.
Particle sizes are frequently in the 1 to 10 micron range
and highly efficient particulate removal equipment must be
employed. For relatively small storage piles, such as
sulfur storage, enclosures with particulate control appara-
tus must be compared to outside storage piles using organic
40
-------
RECYCLE
N02
,
CLEANED
LUt VjA£>
t
11(111
V
/ \
1
S-
1 1 1 1 1
SPRAY
TOWER
A
OXIDIZER HNQ
— _
,-. ( MAKEUP
;LIMEWATER
'' A,
SETTLER NITRITE
X. ^) DECOMPOSER
/•_• n
CaS04
>» FLYASH
f
FLUE GAS
Figure 4. Lime Scrubbing For NO Removal (1)
41
-------
RECYCLE
FL
CLEANED
FLUE GAS
t
MINI
X
t 1
1 1 1 1 1
SPRAY
TOWER
UE "
" I
N02
Mg{OH)2
,
SETTLER
\
H20,
1
^
, i
MgSO,
FLYASH TO
SETTLING
4.
OXIDIZER
RECYCLE HN03
•^w^~
\g_Alflj
Mg(N02)2 NH3
U-^ NITRITE *~^ NH3
DECOMPOSER REACTOR
V
Mg(OH)2
MgS03 S02 _ H2S04
— *• DECOMPOSER PLANT
NH4N03
H2S04
'GAS
Figure 5. Magnesium Hydroxide Scrubbing
Of N0v (1)
42
-------
I CLEANED
GAS
CYCLONIC
SEPARATOR
MIST
ELIMINATOR-
FLUE GAS
CONTAINING
NITROGEN OXIDES
ACIDIC UREA SOLUTION
-PACKED BED
MAKEUP
UREA
1
HEATING
COIL
j
*l 1
:---§f
i_-_-_^^:-_-_-_-^-_-_-:
f
-eJ
MAKEl
WATE
-| T
J
h
i, _j_^"—
MIXING TANK
NO AND N02 -
NITROUS ACID + UREA-
NITROUS ACID IN SOLUTION
N2 + C02 + H20
Figure 6. Urea Scrubbing Process
For NC> Removal (1)
X
43
-------
TABLE 10. GASEOUS WASTE STREAMS IN THE SRC PROCESS -
MAJOR CONTAMINANTS AND STREAM CHARACTERISTICS
Stream
Major Pollutants
Stream Characteristics and
Criteria for Control Module
Selection
Dust from coal receiving
Dust from coal storage
3. Dust from coal reclaiming
and crushing
4. Stack gas from coal drying
5. Dust from SRC product
storage
6. Effluent gas from
Stretford sulfur recovery
Flue gas from coal-fired
boilers (Steam Generation)
Particulates
Particulates
Particulates
Volatile organics
Particulates
Moisture
Particulates
Volatile organics
Light hydrocarbons
Nitrogen oxides
Ammonia
Fly-ash
Hydrogen sulfide
Sulfur dioxide
Nitrogen oxides
Particulates
Carbon dioxide
Highly variable; ambient temper-
ature and pressure; high grain
loading; abrasive; particle size
1-100 y.
Intermittent; dispersed; variable
dependant on wind conditions;
same as above.
Same as 1.
High temperature, pressure and
flow rate; low grain loading;
high moisture content.
Same as 1.
Moderate temperature and pressure;
low grain loading; high flow rate;
corrosive low pollutant concentra-
tions; relatively constant.
High temperature; near atmospheric
pressure; high flow rate; corrosive;
abrasive; moderate grain loading,
relatively constant.
-------
polymer coatings for dust control. For larger coal piles,
such as the ROM pile, enclosure is infeasible. Dusts from
receiving, reclaiming and crushing operations can be con-
trolled by a number of means.
Generally, electrostatic precipitators are only eco-
nomically feasible for the treatment of relatively large
gaseous streams at high temperatures. Efficiencies of
removal are dependent on flow rate. Since dust streams are
relatively small and possess variable flow rates, electro-
static precipitators were not chosen as a viable means of
control.
Wet scrubbing techniques for particulate removal were
also not chosen as a viable alternative because of excessive
water use and the generation of an additional wastewater
stream.
Baghouses and cyclones were chosen as the most viable
means of particulate control in dust generating operations.
Two alternate systems are available. In some operations, a
single baghouse (or fabric filter) may be adequate to con-
trol dusts. In other applications a cyclone may be needed
prior to baghouse, in order to provide adequate and econ-
omical particulate removal. In Chapter 6.0, the two systems
will be discussed with respect to their application and
costs for specific gaseous waste streams in the SRC process.
The most feasible methods for controlling hydrocarbon
emissions from sulfur recovery unit tail gas are incineration
and carbon adsorption. Incineration has the advantage of
oxidizing other pollutants (H2S, NH3, CO) as well as the
hydrocarbon component. Carbon adsorption may not be well
suited to remove the light hydrocarbon streams expected in
the tail gas.
Since sulfur dioxide emissions are expected to be signi-
ficant, wet scrubbing processes have been suggested for boiler
flue gas treatment. Their ability to simultaneously remove
particulates, sulfur dioxide, and nitrogen oxides from flue
gas gives tham a definite advantage over electrostatic pre-
cipitators, which are more cost effective only when sulfur
and nitrogen oxide levels are low.
45
-------
5.3 Liquid Treatment
5.3.1 Introduction
This section deals with the selection of wastewater
pollution control equipment which may be applicable to the
treatment of coal liquefaction wastewaters containing sus-_
pended solids, dissolved solids, extreme pH, hardness, toxic
chemical species, oil wastes, and oxygen demanding species.
The various treatment technologies discussed provide viable
alternatives that might be considered for rendering wastes
acceptable for either discharge or for recycle/reuse within
the plant. Although this discussion does not encompass
every treatment alternative that might be considered, a
representative survey of the most significant treatment pro-
cesses has been included.
5.3.2 Pollution Control Equipment
Selection and sizing of pollution control equipment for
the SRC process depends on flow rate, variability of flow,
amenability of wastewaters to chemical and/or biological
treatment, chemical composition, chemical recoverability,
intended end-use of treated wastewaters (i.e., discharge to
stream or recycle to plant), and economic considerations.
Parameters generally considered in the design of pollution
control equipment are BOD, COD, temperature, pH, suspended
solids, dissolved solids, heavy metals, toxic materials such
as cyanides and phenols, and oils and grease.
Highly variable and polluted wastewaters usually need
one or more pretreatment processes such as equalization,
neutralization, solids removal, heavy metals removal, oil
and grease removal, toxic pollutant removal (i.e., phenols
and cyanides), and chemical recovery operations. These
methods provide preliminary removal of excess quantities of
wastewater stream constituents and prevent various stream
parameters from adversely affecting the operation of the
main treatment processes. Depending on the removal effi-
ciencies of the main treatment processes, additional waste-
water _treatment may also be required to reduce the wastewater
constituents to acceptable levels.
46
-------
Pollution control processes may be divided into three
classes according to their treatment function, i.e., primary,
secondary or tertiary treatment. Table 11 lists the general
classes of treatment methods and applicable processes within
each class which may be employed in a coal liquefaction
plant.
TABLE 11. TREATMENT PROCESSES
Class of Treatment
Primary Secondary Tertiary
Equalization Biological Filtration
Sedimentation Flocculation/Flotation Carbon Adsorption
Neutralization Advanced:
Oil and Grease Electrodialysis
Separation Reverse Osmosis
Ion Exchange
Recovery Processes
Ammonia
Phenol
Sulfur
Stripping
In the selection of pollution control equipment, the
most significant pollutants to be removed from each waste-
water stream must first be determined. Then it must be
decided whether to segregate or integrate various wastewater
streams prior to treatment. Also, it must be decided if any
stream constituents may be recovered. Once the chemicals to
be recovered and main treatment systems needed to treat
various wastewater streams have been identified, then the
appropriate pretreatment (primary) and post treatment (ter-
tiary) methods may be selected.
The following sections deal with the various treatment
operations included under the three classes of treatment.
47
-------
5.3.2.1 Primary Treatment
Primary treatment units are designed to remove waste-
water stream constituents which may adversely affect the
operation of the main treatment processes and/or may be
recovered economically. Applicable primary treatment
operations are enumerated in Table 11.
5.3.2.1.1 Recovery Operations
In the SRC process, there are a number of pollutants,
namely, sulfur, ammonia, and phenols, which may be recovered
economically from the wastewater streams. Although they
have been included in the auxiliary process modules, they
are, in essence, primary (pretreatment) treatment processes.
If it had not been economically feasible to recover these
compounds, then it most likely would have been necessary to
encorporate various treatment methods into the overall
treatment process to remove them or render them harmless.
5.3.2.1.2 Primary Solids Removal
Sedimentation is a solids-liquid separation process
whereby suspended solids are separated from water and con-
centrated by gravity settling. This type of separation is
effective when the suspended solids are capable of settling
readily as is the case for domestic wastewaters. Often,
wastewaters may contain finely divided suspended matter
which does not settle easily. Chemical coagulants are
usually added in these instances to agglomerate the suspended
matter into larger particles which exhibit improved settling
characteristics. Typical coagulants are alum, ferric chloride,
and aluminate. Popular coagulant aids are bentonite, powdered
carbon, activated alumina, and polyelectrolytes.
Sedimentation removal efficiencies vary widely depending
on the nature of the influent suspended matter. A well
designed and operated tank should remove between 50-60 per-
cent of the influent solids (4).
Sedimentation tanks may be either rectangular or circu-
lar. The detention times in circular tanks is usually
between 90-150 minutes with surface loading not to exceed
600 gpd/ft2 (36.7 m3/day/m2) (4).
48
-------
The design of rectangular sedimentation tanks is usually
based on the wastewater flow, solids loading, and settling
characteristics. The horizontal velocity through the chamber
is given by the following equation (4):
V = V L
s d
where* V = maximum horizontal velocity (ft/sec)
Vg = terminal settling velocity of the particle
to be removed (ft/sec).
L = length of basin (ft)
d = depth of basin (ft)
The terminal settling velocity in ft/sec may be estimated
from the following equation (4):
v , (Ps -P*) gD2
s
18 IJL
where*
o
P = density of solid particle (Ib/ft )
S
P* = density of wastewater (Ib/ft3)
D = diameter of solid particle (ft)
H = viscosity of wastewater (lb/sec-ft)
o
g = acceleration of gravity (32.2 ft/sec )
^Metric conversion factors are given in Appendix A.
Horizontal velocities are usually less than or equal to 1.0
fps (0.3 m/s) (4). This fixes the size of the chamber for a
given flow rate.
Tube settlers may also be used to remove suspended
matter in lieu of sedimentation basins. They essentially
act as a series of rectangular basins, where water enters the
49
-------
bottom of the inclined tube settler and flows upward through
the tubes. Particles tend to move toward each tube wall
where they become entrapped in a layer of particles pre-
viously settled. The steep incline of the tubes causes the
sludge to counterflow along the side of the tubes after it
accumulates. In then falls into a sediment storage sump
below the tubes assembly. The inclined tube settler config-
uration also requires influent and effluent chambers to
distribute the flow to the tubes and to collect if after
clarification.
Inclined tube settlers are manufactured with tubes
having various geometrically-shaped cross sections. Systems
employing flocculation with inclined tube settlers are
capable of removing particles less than 10 microns in dia-
meter (fine sand) . They are usually used to clarify in-
fluent waters which have under 1000 mg/1 of suspended solids
(5). The number of tubes may be increased to provide treat-
ment for virtually any flow rate desired.
The horizontal velocity through the settler is given by
the following equation (5):
V = Vs L cos A
d
where: A = angle of inclination (0.0 < A < tan" L)
Tube settlers are generally designed,.for flows of 5-8 zpm/
)-3 to 5.4 x 10-3 m3/s/m2) (6).
-I-U-LXW k?^.(_.l__l_^..l-k?
ft2 (3.4 x 10-
In addition to sedimentation basins, screening devices
may also be used to remove suspended solids. Separator
screens normally consist of rectangular or circular struc-
tures supporting wire mesh screens. Water is introduced
directly onto the screen surface. Solids are detained on
the surface while the screened water exits downward Trap-
ped solids are vibrated to the outer periphery of the screen
element for disposal. Typical separator screens may remove
particles ranging from a few hundred microns in diameter to
as small as 45-50 microns (5). Screen designs are based on
the screen opening and solids loadings which can be accom-
modated without blinding the screen. The sedimentation
removal rate decreases with decreasing size of particles
removed.
50
-------
5.3.2.1.3 Steam Stripping
Steam stripping may be used to remove hydrogen sulfide,
ammonia, and phenol from a wastewater stream. Depending on
the operating temperature and pressure, the ammonia and
hydrogen sulfide content of the raw feed, the type of
system - refluxed or nonrefluxed and the number and efficiency
of trays or packing, approximately 98-99 percent of the
hydrogen sulfide and 95-97 percent of the ammonia present in
the raw feed stream may be removed (7). It has also been
observed that up to 40 percent of any phenols present in the
raw feed may also be removed by this process (7).
The volume of steam required in this process has been
found to vary between 0,9-1.1 (0.4-0.5 kg) pounds of steam
per gallon of tower feed (7). As high as 2.0 (0.9 kg)
pounds per gallon have been used. Typical design parameters
include 8-10 trays, a tower pressure of 5-30 psig (3.4 x 10^
to 2.1 x 105 pa), and a tower temperature of 230-270°F (110-
132°C) (7). The stripper volume will depend on the compo-
sition of the feed stream and the number of trays required
to produce the desired effluent.
This system has an advantage over air stripping systems
in that chemical addition is not required and additional
compounds can be removed.
5.3.2.1.4 Equalization
Equalization is a process whereby the composition of a
wastewater stream is made uniform and the volumetric flow
rate constant. It is normally required when a number of
streams with highly variable chemical compositions and flow
rates are combined for treatment. The addition of equal-
ization facilities to a treatment plant improves the effi-
ciency, reliability, and control of subsequent physical,
chemical and/or biological treatment processes.
Equalization basins are normally designed with a preset
detention period for chemical mixing (i.e., 15-30 minutes)
based on the average daily flow, or, in the case of highly
variable flows, to retain a sufficient portion of the
wastewater stream, while maintaining adequate freeboard, in
order that a predetermined constant flow rate is discharged
to the treatment plant (8).
51
-------
5.3.2.1.5 Neutralization
When biological treatment processes are used to treat
industrial wastes, the influent wastewater stream pH should
be between 5.0 and 10.0. Extreme pH wastewaters may be
adjusted within these units by the addition of acids or
bases. Common reagents used for neutralization are summarized
in Table 12.
TABLE 12. NEUTRALIZATION REAGENTS
Acid Wastes Alkaline Wastes
Waste alkalis Waste acids
Limestone Sulfuric acid
Lime slurry Hydrochloric acid
Soda ash Sulfur dioxide
Caustic soda
Ammonia
Selection of neutralization reagents is based primarily on
cost considerations. Reagent solubility, neutralization
reaction rate, neutralization end products, and ease of
operation also require consideration.
The process flow scheme used for neutralization depends
on the neutralization reagent(s) employed, desired degree of
neutralization and waste flow characteristics. Depending on
the rate of waste flow, either continuous or batch-wise
neutralization is employed. Generally continuous neutrali-
zation is used when the waste flow exceeds 70 gpm (4.4 x 10~2
m3/S). Detention times of 10-30 minutes are typical (6).
52
-------
5.3.2.1.6 Oil and Grease Separators
Oily wastes may be grouped in the following classifica-
tions :
1. Light Hydrocarbons - These include light fuels
such as gasoline, kerosene, and jet fuel, and
miscellaneous solvents used for industrial pro-
cessing, degreasing, or cleaning purposes. The
presence of these light hydrocarbons may encumber
the removal of other heavier oily wastes.
2. Heavy Hydrocarbons (Fuels and Tars) - These in-
clude the crude oils, diesel oils, #6 fuel oil,
residual oils, slop oils, and in some cases,
asphalt and road tar.
3. Lubricants and Cutting Fluids - These are gener-
ally in two classes, non-emulsifiable oils such as
lubricating oils and greases, and emulsifiable
oils such as water soluble oils, rolling oils,
cutting oils, and drawing compounds. Emulsifiable
oils may contain fat, soap or various other
additives.
These compounds can settle or float and may exist as
solids or liquids, depending upon such factors as method of
use, production process, and temperature of wastewater.
Primary oil-water separators are designed to remove
free oils readily separated from a wastewater stream. This
process provides a reduction in the oxygen demand of the
wastes (both BOD and COD) and reduces operational difficulties
caused by oils and grease in subsequent biological treatment
processes.
Gravity separators are most commonly used to remove
free oils from wastewaters. The difference in densities of
oil or grease and water will cause free oily wastes to rise
to the surface of the wastewater, where they are collected
and removed by skimming devices.
The parameters considered in the design of oil-water
separators are: (1) rate of rise of oil globule, (2) minimum
horizontal area, (3) minimum vertical cross-sectional area,
and (4) minimum depth to width ratio. Design equations are
given in Table 13.
The horizontal and vertical areas and the depth to
width ratio fix the size of basin to be used.
53
-------
TABLE 13. GRAVITY OIL-WATER SEPARATOR
DESIGN EQUATIONS (6)
(1) Vt = 0.0241 (Sw - SQ)
(2) Ah = F VVt
C3) Ac =
(4) d/B =0.3
where* V. = rate of rise of a 0.015 cm diameter globule,
(ft/min).
S = specific gravity of wastewater at design tempera-
w ture
S = specific gravity of oil in wastewater at design
° temperature.
y = absolute viscosity of wastewater at design tem-
perature (poises).
2
A, = minimum horizontal area (ft )
3
0 = wastewater flow (ft /min)
F = correction factor for turbulence and short cir-
culating in separator (see Figure 7).
2
A = minimum vertical cross-sectional area (ft )
V, = horizontal flow velocity (fpm), not to exceed
3 fpm
d = depth of wastewater in separation (ft)
B = width of separator channel (ft).
Metric conversion factors are given in Appendix A.
54
-------
cc
o
o:
o
I/O
GO
1.8 r-
1.7
1.6
1.5
1.4
1.3
1.2
10
14
16
20
VVt
Figure 7. Recommended Values of F for
Various Values of Vh/Vt (6)
55
-------
5.3.2.2 Secondary Treatment
Biological treatment and flocculation/flotation are the
two main treatment processes most commonly employed for
wastewaters similar to those found in coal liquefaction pro-
cesses. When flocculation/flotation is needed, it usually
precedes the biological treatment system.
5.3.2.2.1 Flocculation/Flotation
Air flotation is a process whereby suspended matter,
including both suspended solids and insoluble oily wastes,
is separated from water. This process is often used in
conjunction with gravity oil/water separators when there are
significant quantities of both free and emulsified oils
present in wastewaters.
Air flotation separates oil globules from the waste-
water by introducing tiny air bubbles into the flotation
chamber. The air bubbles attach themselves onto oil glo-
bules dispersed throughout the water. The resultant buoyancy
of the oil globule - air bubble complex causes it to rise to
the water's surface where it is removed by surface skimming
devices. Air flotation processes are classified as dispersed
air or dissolved air depending upon the method of air intro-
duced into the flotation unit. Pressure dissolved air
flotation units are most commonly employed in industrial
wastewater treatment. The basic equation governing the
separation of oil from water is given below (6):
Vt = g D2( PO-PW)
Where*
V = terminal velocity attained by suspended
solids passing through water (ft/sec)
o
g = acceleration of gravity (32.2 ft/sec )
D = diameter of suspended impurity (ft)
o
p = density of oil in waste (Ib/ft )
o
P = density of wastewater (Ib/ft )
V- = viscosity of wastewater (Ib/sec-ft)
"Metric conversion factors are given in Appendix A.
56
-------
Based on this principle, the following design criteria have
been recommended for rectangular flotation chambers (6):
• The ratio of depth to width should be between
0.3 to 0.5 (depth usually 1.0-2.7 m) .
• The maximum ratio of the horizontal water velocity
to particle rise velocity is recommended to be 15.
• The maximum horizontal water velocity is recom-
mended to be 1.5 cm/S.
• The optimum length to width ratio is set at 4 to
1.
• A maximum width of 6.7 m is recommended.
Typical operating parameters are given in Table 14.
TABLE 14. AIR FLOTATION UNIT
OPERATING CONDITIONS (6)
Parameter Value*
Residence time in flotation chamber 10-40 minutes
Residence time in pressurization tank 1-2 minutes
2
Hydraulic loading in flotation chamber 1-6 gpm/ft
2
Oily waste loading 2-4 Ib/hr - ft
Air requirement (full flow operation) 0.35 scf/100 gal.
^Metric conversion factors are given in Appendix A.
There are three basic flow schemes employed for the
pressure type dissolved air flotation process. They are
designated as full-flow operation, split-flow operation, and
recycle operation. Full-flow operation is the most general
form of the process. Split-flow operation is used primarily
to remove oily wastes from wastewaters of low suspended
solids concentration, while the recycle operation is used
when a delicate floe is present in the influent wastewater
stream. These operations are shown in Figure 8 (6).
57
-------
OILY WASTE
AIR
WASTE
FLOTATION
CHAMBER
FLOCCULATING
AGENT
(IF REQUIRED)
PRESSURE
RETENTION
TANK
AIR FLOTATION PROCESS: FULL-FLOW OPERATION
OILY WASTE
t
WASTE
FLOCCULATING
AGENT
(IF REQUIRED)
PRESSURE RETENTION
TANK
AIR FLOTATION PROCESS: SPLIT-FLOW OPERATION
CLARIFIED
EFFLUENT
CLARIFIED
EFFLUENT
WASTE
FLOCCULATING
AGENT
(IF REQUIRED)
FLOCCULATION
CHAMBER
(IF REQUIRED)
OILY WASTE
L
FLOTATION
CHAMBER
CLARIFIED
EFFLUENT
PRESSURE RECYCLE PUMP
RETENTION AIR
TANK
AIR FLOTATION PROCESS: RECYCLE OPERATION
Figure 8. Three Flow Schemes Employed in the Dissolved
Air Flotation Process
58
-------
The efficiency of the air flotation process is depen-
dent upon the influent water characteristics. Water containing
free oil is readily removed by this process, while emulsified
oil is not. Pretreatment methods, encompassing chemical
addition, usually precede the flotation chamber when the
influent wastewater contains significant concentrations of
emulsified oils. Coagulation/flocculation and acidification
are the most common pretreatment methods used. Dissolved
air flotation treatment efficiencies are given in Table 15.
TABLE 15. DISSOLVED AIR FLOTATION (6)
Oil Removal, Percent
Treatment Description Floating or Free Oil Emulsified Oil
Flotation without chemical 70-95 10-40
pretreatment
Flotation with chemical 75-95 50-90
pretreatment
5.3.2.2.2 Biological Treatment
The three basic types of biological treatment systems
applicable to coal liquefaction wastewaters are activated
sludge processes, aerated lagoons (oxidation ponds), and
trickling filters.
Important parameters to be considered in the design of
biological treatment processes are:
BOD loading
Oxygen availability
Temperature
PH
Toxicity
Dissolved salts
Design parameters for various biological treatment
systems are given in Table 16.
59
-------
TABLE 16. BIOLOGICAL TREATMENT SYSTEMS (4)
Process
ttb
Activated Sludge
Extended Aeration
High Rate Aeration
Conventional
Aerated Lagoon
Stabilization Ponds
Trickling Filters
Standard Rate
High Rate
Loading ,,
BOD/day/1000 ftj)
10-25
100-1000
20-40
N/A
20-50a
9-14
69+
Detention Time
(hours)
18-36
0.5-2
4-8
72-240
240-720
Treatment Efficiency
(percent)
75-95
75-90
85-95
80-95
80-95
85
65-75
aunits in Ib/acre-day
N/A = Not Applicable
*
Only English units are included due to space limitation. Metric conversion
factors are given in the Appendix.
-------
The treatment process required for any industrial
wastewater will mainly depend on the biodegradability of the
waste, cost considerations taking into account other unit
processes which may be required, and the degree of treatment
required. For example, wastes which degrade very slowly
will require longer detention times than wastes which degrade
rapidly. This would most likely necessitate the use of
lagoon systems in lieu of conventional systems.
In addition to the basic biological treatment unit,
secondary clarifiers are also integral components of the
biological treatment system. The clarifiers serve two
functions: to settle out suspended matter from the bio-
logical aeration basin effluent and to recycle a portion of
the solids to the aeration basin.
The secondary clarifiers are normally designed for 4-6
hours detention based on the average daily flow (4). Surface
loading rates and weir loading rates do not normally exceed
600 gpd/ft2 and 10,000 gpd/ft (36.7 m3/day/m2 and 126 m3/day/m),
respectively (4). The recycle volume from the clarifier to
the aeration basin usually ranges from 30-100 percent of the
influent flow (4). In the case of trickling filters, there
is no recirculation of solids to the filter in standard rate
filter systems. In high rate filters, however, the recycle
ranges from 100-400 percent of the influent flow (4).
5.3.2.3 Tertiary Treatment
Tertiary treatment basically consists of physical-
chemical processes which polish or refine the effluents from
secondary processes to within acceptable limits either for
discharge to surface water or for plant reuse. Some tertiary
treatment processes are filtration, carbon adsorption, ion
exchange, electrodialysis, and reverse osmosis.
5.3.2.3.1 Filtration
There are numerous filtration processes which may be
used to polish secondary effluent wastewaters. Filtration
processes applicable to coal liquefaction wastewaters are
given in Table 17 along with design parameters. Filtration
processes may be divided into two classes: deep bed filtra-
tion and polishing filtration. Microscreening and vacuum
filtration are considered polishing filtration while gravity
and pressure filters are considered deep bed filtration.
61
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TABLE 17. FILTRATION PROCESSES
to
Process
Microscreening
Gravity Filters
Downflow
Upflow
Pressure
Filters
Vacuum
Filtration
Filter
Media
Garnet
Coal
Sand
Garnet
Coal
Sand
Garnet
Coal
Sand
Diatomaceous
Earth
Loading,-,
(gpq/fO
2-10
2-6
2-6
2-6
2-10
0.5-1
Solids
Removal
Capacity
(Ib/unit area)
—
0.3-0.5
(one layer)
.5-1.0
(multi-layer)
.5-1.0
0.3-0.5
—
Efficiency
(SS removal)
45-85%
( 5mg/l)
50-90%
80-90%
50-90%
90%
98%
^Only English units are provided due to space limitations. Metric
factors are given in the Appendix.
conversion
-------
There are three types of deep bed filtration systems
which will be described: gravity downflow, gravity upflow,
and pressure filters.
Deep bed filtration utilizes a bed of granular filter
media to separate suspended matter from water. These sys-
tems are usually applicable up to 1,000 mg/1 of solids with
particle sizes ranging from 0.1 to 50/^(10). Since the
entire filter media is available to capture solids, a clear
filtrate is produced.
Downflow filtration involves the filtration of water in
a downward direction through progressively coarser filter
media. Upflow filtration involves the filtration of water
in an upward direction through progressively finer filter
media. Prevention of the movement of the filter materials
is accomplished by the use of restrictive screens and grids.
Polyelectrolytes can be added to the sediment-laden influent
for further solids removal by these filters. Pressure
filters rely on pumps to force sediment-laden wastewaters
either upward or downward through a filter media.
The loading rates are essentially the same for both
gravity downflow and upflow filters. The use of upflow
filter is generally more advantageous because the filter
runs are usually longer and consequently the number of
backwashings required are reduced. The use of downflow
filters is somewhat disadvantageous because sufficient
hydraulic head must be available for successful operation of
the filter. A disadvantage of the upflow filter is loss of
filter material during the normal operating cycle.
Pressure filters are basically more advantageous than
gravity filters for wastewater applications because they can
handle higher solids loadings and higher pressure heads and
are more compact and less costly. A major disadvantage is
the difficulty encountered in servicing the filters when they
malfunction. The filter is completely enclosed.
Those parameters which must be considered in the design
of deep bed filters are available head loss, filtration
rate, influent characteristics, media characteristics, and
filter cleaning system. Media characteristics have been
found to be the most important considerations in the design
of deep bed filters. Media particle size determines the
performance and operation of the filter. It has been observed
63
-------
to be inversely proportional to both filtrate quality and
pressure drop across the filter. A distribution of particle
sizes (multi-media beds) enables the filter to be utilized
more efficiently in that it will not clog as readily as a
filter containing only one filter medium. Multi-media
filters consequently require less frequent backwashing.
Polishing filters such as the diatomaceous earth vacuum
filter are capable of removing suspended solids in the
micron and submicron range from very dilute aqueous suspen-
sions. Although they are capable of producing a high quality
effluent, the occurrence of varying quantities of influent
suspended solids has led to erratic operation of this filter
in tertiary treatment operations. A microscreen consists of
a rotating drum with a fine screen around its periphery.
Feed water enters the drum through an open end and passes
radially outward through the screen, depositing solids on
the inner surface of the screen. At the top of the drum,
pressure jets of effluent water are directed onto the screen
to remove the deposited solids. A portion of the backwash
water penetrates the screen and dislodges solids, which are
captured in a waste hopper and removed through the hollow
axle of the unit. Particles as small as 20-40 microns may
be removed by this system. Disadvantages include incomplete
solids removal and inability to handle solids fluctuations.
5.3.2.3.2 Carbon Adsorption
Carbon adsorption is usually employed as a tertiary
treatment unit for the removal of soluble organic matter in
wastewaters. Approximately 70-90 percent of the influent
BOD and 60-75 percent of the influent COD may be removed by
this process when it is preceded by secondary biological
treatment (11).
Carbon adsorption design considerations include adsorp-
tive capacity of the carbon, wastewater flow and character-
istics and method of carbon contacting. The general range
of hydraulic flow rates are 2-10 gpm/ft2 (1.4 x 10"' to 6.8
x 10~3 m3/s/m2) (11). Bed depths are typically 10-30 feet
(3.3-10 m) (11). 0The maximum area for good flow distribution
is 1000 ft2 (93 m2) (11).
64
-------
The alternatives for carbon contacting systems include:
downflow or upflow contacting, series or parallel operation,
pressure or gravity downflow contactors, and packed or
expanded bed upflow contactors. Upflow beds have an advant-
age over downflow beds in that there is a minimum usage of
carbon. Upflow expanded beds are able to treat wastewaters
relatively high in suspended solids and can employ finer
carbon (reduces contact time) without excessive headloss. A
disadvantage of the upflow packed bed is that it requires a
high clarity influent. The principal use of the downflow
contactor is to adsorb organics and filter suspended materials
Pressure downflow contactors increase the flexibility of
operation since they allow the system to be operated at
higher pressure losses.
The carbon dosage required depends on the strength of
the wastewater feed and the desired effluent quality. Rough
estimates of the carbon dosage required for secondary bio-
logical effluents plus filtration are 400-600 Ibs/million
gallons (48-72 Mg/m3) of wastewater (11).
Bench scale tests determine more quantitatively the
carbon dosages needed to produce a desired effluent. The
carbon column contact time (empty bed basis) is generally
10-50 gpm/ft2 (.6.8 x lO'3 to 3.4 x lO'2 m3/S/m2) (11).
5.3.2.3.3 Reverse Osmosis
The reverse osmosis process is capable of removing
particles from water in the range of 0.0004-0.06 microns.
Removal efficiencies range from 90 to 99+ percent in most
cases (12).
The principal use of reverse osmosis is for purifica-
tion of brackish waters. It is also used as water pretreat-
ment for ion exchange deionization to make ultrapure water
for subsequent use as boiler feed, cooling tower makeup, and
washwater of essentially zero hardness. Organic matter is
also removed by this process which offers a significant
advantage over demineralization systems such as ion exchange
or electrodialysis.
Measures required to reduce the incidence of membrane
fouling represent a significant disadvantage of the reverse
osmosis process in terms of operation and cost. Membrane
fouling is due to biological growth, manganese and iron,
suspended solids scale, and/or organics. Pretreatment is
generally required to reduce the incidence of fouling which
65
-------
consequently increases the capital and operating costs
considerably over other processes. Pretreatment measures
commonly used are chlorination to control biological growth,
polishing filters to reduce suspended solids levels, soft-
ening to reduce scale, and precipitation of iron and man-
ganese as ferric hydroxide and manganese dioxide.
The most important parameters considered in the design
of a reverse osmosis plant include recovery, product water
quality, brine flow rates, the necessary degree of pre-
treatment, flux maintenance procedures, and post treatment.
3 2
The design flux, expressed in m /m /day, is a function
of the feed composition, temperature, and pressure. Given
the operating conditions and influent flow rate, the membrane
area required can be determined. Membrane manufacturers
should supply this data. The product water quality can be
determined by iterative techniques from the following
equations (12):
*• Cip - Cip
-------
(Ri)a = average salt rejection by membrane
C. = mean local brine concentration on upstream side
of membrane (mg/1)
C. = concentration of salt i in concentrate stream
Q = volumetric flow rate of i in concentrate stream
c (1/min)
Pretreatment and post-treatment methods are designed
based on influent water constituents and effluent limitations
5.3.2.3.4 Ion Exchange
Ion exchange is a process whereby ions that are held by
electrostatic forces to charged functional groups on the
surface of a solid are exchanged for ions of similar charge
in a solution in which the solid is immersed. This process
is used extensively in water and wastewater treatment,
primarily for the removal of hardness ions such as calcium
and magnesium. A series of cationic and anionic ion exchangers
(demineralization) are also often used to produce water of
high purity for industrial applications.
The design of ion exchangers is based on the ion exchange
capacity of the selected ion exchange resin. The basic
resin usually consists of a three dimensional matrix of
hydrocarbon radicals to which are attached soluble ionic
functional groups. There are two types of ion exchange
resins, namely, cationic and anionic. Cationic resins have
positively charged functional groups such as hydrogen or
sodium attached to the hydrocarbon radicals, while anionic
resins have negatively charged functional groups such as
hydroxide or chloride ions attached to the hydrocarbon
radicals. The ability of the resin to adsorb ions is the
ion exchange capacity expressed in kg/m3. Each resin has a
different capacity which must be specified by the manu-
facturer of the resin. Also, resins have observed pref-
erences for certain ions which must be considered in the
selection of a particular resin.
67
-------
Once the resin has been selected, the volume of resin
required may be determined from the following equation (12):
R-2T
where:
R = cubic ft. of resin required
Q = equivalents of ions which must be removed per day
to meet certain effluent limitations (i.e. 90-99
percent removal for two stage operations)
T = selected operating period (days) beyond which the
effluent limitations will be exceeded and the resin
requires regeneration (economic selection based on
cost of regeneration chemicals and required
removal efficiency)
C = ion exchange capacity of resin in equivalents/day
The depth of the exchanger is usually at least 50
percent greater than the depth of the resin to allow for
expansion during backwash and regeneration (12).
Other factors to be considered in the design of ion
exchangers are the flow rate and volume of chemicals needed
to regenerate the ion exchange resin. Flow rates of 6-10
gpm/ft2 (4.1 x 10~3 to 6.8 x 10~3 m3/S/m2) are typical (12).
Typical regenerant solutions are sodium chloride, sulfuric
acid, sodium hydroxide, sodium carbonate, ammonium hydro-
xide, and hydrochloric acid. Cost considerations and type
of ion exchanger dictate the chemicals to be used. Since it
is not the intention of ion exchangers to remove large
quantities of suspended solids, filtration usually precedes
the ion exchange process. If filtration was not normally
required for a particular wastewater, then it must be in-
cluded in the cost considerations for selecting the ion
exchange process.
68
-------
Typical removal efficiencies for the ion exchange
process preceded by biological treatment and filtration are
given in Table 18.
TABLE 18. ION EXCHANGE PROCESS (4)
Wastewater Constituent Percent Removal
BOD 40-60
COD 30-50
NH3 85-98
organic nitrogen 80-95
N03 80-90
P04 85-98
dissolved solids depends on resin
5.3.2.3.5 Electrodialysis
The electrodialysis process is capable of removing
particles in the range of 0.0004-0.1 microns (4). The
removal efficiency for wastewaters which have been treated
by biological processes, filtration, and carbon adsorption
is approximately 40 percent (4).
Parameters used in the design of electrodialysis systems
are dilute cell compartment velocity, cell power input, cell -
current, product concentration, current efficiency, cell
resistance. Experimental analyses are usually performed for
a significant wastewater constituent such as sodium chloride.
The first four parameters listed above are measured in a
specific volume electrodialysis cell. The current efficiency,
required membrane area, power requirements, and energy
requirements may be determined from the following equations
using the experimental results (12).
1. n = Qd (AN±) F
69
-------
2. Qd - Wtl
3. Ap = QdF ( Nd ) In Nf
<1000)n Him
4.
5.
6.
7.
8.
9.
10.
R =
P
i =
-
P =
Na =
E =
N =
o
A =
(P/I ) L
I/Ao
2 2
/-i £.-.-,*-
Ap
C
1000 (MW)
P/Qd
Q/24(Qd)
N A
o p
(Nf - Np) /(RpNd)\ In
11. P = P NQ
where:
Q, = flow rate in dilute compartment (ml/sec)
ANi = Nf - N = difference in feed and product water
P normalities
F = Faraday's constant = 96,500
I = input current (amps)
n = current efficiency
W = width of test cell (cm)
t = thickness of test cell (cm)
o
A = effective required cell area (cm )
N, = waste product concentration of wastewater
constituent (equivalents/I)
i, . = limiting current density = i (amps)
70
-------
N£ = feed wastewater constituent concentration
(equivalents/1)
N = effluent wastewater constituent concentration
p (equivalents/I)
2
R = cell area resistance (ohm-cm )
C = concentration of wastewater constituent
( gin/ equivalent s )
MW = molecular weight of wastewater constituent
(gm/equivalent s)
E = energy requirements (kWhr/1000 gal product)
N = number of cells required
o
Ao = area of test cell (cm ) = LW
Pfc = total power required (KW)
P = test power (W)
2
Ao = area of test cell (cm )
L = length of test cell (cm)
Na = definition of normality of wastewater constituent
(equivalents/I)
P = power required per cell (W)
5.3.3 Control Module Selection
There are numerous liquid wastewater streams discharged
from coal liquefaction processes which may be highly variable
in both volume and chemical composition. Wastewater streams
in the SRC process result from hydrogen production, gas
purification, cryogenic separation, auxiliary facilities
(cooling towers), hydrotreating, and phase (gas) separation.
Typical steam constituents are ammonia, hydrogen sulfide,
phenols, organic compounds, oils and grease, heavy metals,
71
-------
cyanides, suspended solids, chemical additives such as MEA,
polyrad, and oleyl alcohol, carbon dioxide, trace elements,
sulfates, phosphates, nitrates, organics, nitrogen and
sulfur, and alkalinity.
In order to select pollution control equipment which
will be application to SRC process wastewaters, an integrated
analysis of the various primary, secondary, and tertiary
treatment processes discussed in this section must be under-
taken with regard to the following considerations:
• What are the effluent limitations which will be
imposed on the SRC plant in Illinois?
• Is it more cost effective to treat the wastewaters
to a level where the effluent can be recycled to
the SRC process rather than discharged to the
river?
• What are the various combinations of treatment
units, i.e. primary, secondary, and tertiary which
will produce the required effluent quality?
• What types of similar equipment can be inter-
changed and still produce the same quality effluent?
• What types of equipment can be used to produce the
required effluent most cost effectively?
The following selection of pollution control equipment
is based on providing effective operation of the entire
treatment facilities, and producing an effluent acceptable
for discharge and/or plant reuse. Only those essential
units needed to produce an acceptable effluent are included.
Basic treatment processes which may be used to treat
wastewaters from the SRC process to acceptable limits for
discharge include hydrogen sulfide and ammonia steam stripping,
gravity oil separation, equalization, neutralization, dis-
solved air flotation and biological treatment. There are
two alternative biological treatment systems, namely extended
aeration and aerated lagoons. The efficiencies are roughly
the same for each of these systems as long as the lagoon is
followed by a settling basin. Cost considerations will
determine which of these systems may be used. The extended
aeration system may also require tertiary treatment such as
filters which must be considered in the cost and analysis of
the two processes.
72
-------
In addition to determining the treatment units necessary
to produce an effluent acceptable for discharge, one must
also consider those treatment units which would be required
to reduce wastewater parameters to levels acceptable for
plant reuse. A cost comparison of the two systems would
then determine which is feasible. Obviously, it is more
advantageous (economically) to recycle plant wastewaters
when effluent limitations are more stringent than the effluent
quality required for plant use.
In view of the stringent effluent limiations which
would be imposed on a SRC plant located on the Wabash River,
and raw water treatment costs, it appears that plant waste-
water recycle is the only viable alternative. Also, the
treatment units required would be similar to those previously
discussed; therefore, only treatment systems capable of
producing an effluent acceptable for plant reuse will be
considered further.
5.4 Solids Treatment
5.4.1 Introduction
This section deals with the selection of pollution
control equipment which is applicable to the treatment of
sludges generated within the SRC plant and from the opera-
tion of the wastewater treatment facilities. A represen-
tative survey of applicable equipment has been included.
5.4.2 Pollution Control Equipment
Solids treatment encompasses solids volume reduction
and/or treatment processes designed to render solid wastes
harmless for ultimate disposal by improving their handling
characteristics, reducing their volume, and/or reducing their
leachability. Typical control equipment available to accom-
plish these objectives is listed in Table 19. Each type
of equipment is discussed separately.
5.4.2.1 Volume Reduction Processes
Sludge volume reduction processes are, most often,
essential components of a wastewater treatment facility when
a significant quantity of sludge must be disposed of.
Economically, it is more advantageous to dispose of sludge
which has a low moisture content and is relatively compact.
The dewatering equipment listed in Table 19 is capable of
providing a significant reduction in the moisture content of
wastewater sludges.
73
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TABLE 19. SOLIDS TREATMENT
Volume Reduction Processes
Treatment Processes
thickeners
filter press
centrifuges
rotary vacuum filter
lagoons
wet oxidation
pyrolysis.
incineration
lime recovery
heat drying
other systems:
moving screen concentrators
belt pressure filters
capillary dewatering
rotating gravity concentrators
74
-------
The selection of dewatering equipment depends on the
characteristics of the sludge, the method of final disposal,
availability of land, and economics involved.
5.4.2.1.1 Thickeners
There are three basic classes of thickeners: gravity,
dissolved air flotation, and centrifugal. Design parameters
for each class of thickener are given in Table 20 (9).
Performance of these units is dependent upon the solids
loading, hydraulic loading, and removal efficiencies.
Dissolved air flotation thickeners are preferred over
gravity thickeners because of their reliability, thicker
product, higher solids loading, lower capital cost, and
better solids capture. The operating costs, however, are
higher for the flotation unit. Centrifugal and dissolved
air-flotation units are generally used for excess activated
sludge while gravity units may be used for both primary and
excess activated sludge.
5.4.2.1.2 Filter Press (Pressure Filtration)
The design of filter presses depend on the quantity of
waste sludge to be processed and the desired daily filter
press operating period. Often, chemical conditioning agents
must be added to the sludge prior to being applied to the
filter press to aid in the dewatering process. Typical aids
are ferric chloride ash, and lime. It has been observed
that the moisture content of pressed sludges ranges from 40-
70 percent (9) .
Approximately 1 to 3 hours is required to press a
sludge to the desired moisture content (4). The whole
process, including the time required to fill the press, the
time the press is under pressure, the time to open the
press, the time required to wash and discharge the cake, and
the time required to close the press varies from 3-8 hours
(4).
Advantages of this process are high cake solids con-
centration, improved filtrate quality, improved solids
capture, and reduced chemical consumption. Disadvantages
include batch operation, high labor costs, filter cloth life
limitations, operator incompatibility, and cake delumping.
75
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TABLE 20. THICKENERS
Parameters*
Hydraulic loading
(gpm/ft^)
Solids loading
(lb/hr/ft2)
Air /Solids rates
Present solids inlet
Percent solids outlet
Percent solids recovery
Recycle ratio (percent)
Pressure (psig)
Flow range (gpm)
Detention time (hrs)
Thickener depth (ft)
Gravity
.28 - .625
P. 20-39
A.S. 4-8
NA
P. 2.5-5.5
A.S. .5-1.2
P. 8-10
A.S. 2.5-3.0
NA
HA
NA
24
10
Class
Dissolved
Air Flotation
0.8
(max acceptable)
2-3
0.02-0.03
0.5-1.2
4
90
30-150
40-80
NA
0.33
NA
Centrifugal
Disc
NA
NA
NA
.7-1.0
4-7
80-97
NA
NA
50-400
NA
NA
Solid Bowl
NA
NA
NA
.5-1.5
5-13
65-95
NA
NA
10-160
NA
NA
P. = Primary sludge
A.S. = Activated sludge
N.A. = Not applicable
*Data presented are typical parameters used for domestic wastewater
solids. Consequently, thickeners do not have to be designed strictly
within these limits. Also, data on dissolved air flotation and
centrifugal units are presented for excess activated sludge. Metric
conversion factors are given in Appendix A.
76
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5.4.2.1.3 Centrifuges
The three basic types of centrifuges which may be used
to dewater sludges include solid bowl (countercurrent and
concurrent), basket and disc. Polymeric flocculants are
most often used with this type of equipment. The use of
flocculants is dependent upon the characteristics of the
sludge to be dewatered.
Hydraulic capacities and applications of the three
types of centrifuges are given in Table 21. The theoretical
maximum capacities of these centrifuges are given by the
following equations (9,13):
For basket and solid bowl centrifuges;
92
Z z
For disc centrifuges;
T = 2 nw2 (r 3 - r.3)
3gtan0
where*
T = theoretical capacity
L = effective length of settling zone (ft)
w = angular velocity in centrifugal zone (radian/sec)
r? = radius of inside wall of cylinder (ft)
r, = radius of the free surface of the liquid layer
in the cylinder (ft)
2
g = acceleration of gravity (32.2 ft/sec )
n = number of spaces between discs
d = half the included angle of the discs
r = radius of outside measure of the disc (ft)
o
r-, = radius of inside measure of the disc (ft)
^Metric conversion factors are given in Appendix A.
77
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TABLE 21. CENTRIFUGES (13)
Centrifuge
Hydraulic
Capacity*
Connents
Application
Basket up to 60 gpm
decrease to 40 gpm
solids - 1%
3-5% solids
metal hydroxide wastes,
aerobic sewage sludges,
water treatment alum sludges
Solid Bowl
to 400 gpm
as low as 75 gpm
lime sludges
sewage sludges
Disc
20-300 gpm
400 gpm
normal
maximum
raw primary or mixed pri-
mary & biological sludges
(domestic), anaerobically
digested primary or mixed
sludges, and heat-treated
or limed chemical sludges.
It may be applied at high
cost to excess activated
sludge, aerobic digested
sludges, and alum or ferric
chemical sludges. In
water treatment, it is
excellent on water softened
lime sludges.
Excess activated sludge
for feed concentrations
of 0.3 to 1.0 percent
suspended solids
•^Metric conversion units are given in Appendix A.
78
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Variables of importance which affect the performance of cen-
trifuges include bowl design, bowl speed, pool volume, con-
veyor design, relative conveyor speed, and sludge feed rate.
The hydraulic loadings which may be applied to each centri-
fuge is a function of Q/T, where, Q is the flowrate and T
(defined above) is the theoretical capacity of the centri-
fuge.
Solids concentrations of 15 to 40 percent have been
observed from various centrifuges (9). Solids capture
ranges from 80-95 percent for oxygen activated sludges (9).
For excess activated sludges, a higher degree of dewatering
may be expected from a basket centrifuge than from a discen-
trifuge. Typically, basket centrifuges have been found to
concentrate solids in the range 0.5-1.5 percent to approxi-
mately 10-12 percent (9). Given the same sludge, disc
centrifuges can concentrate the solids to only 6 percent
(9). Also, 90 percent solids capture is possible in the
basket centrifuge with no chemical addition (9).
In many cases, two or more types of centrifuges may be
operated in series to increase the solids concentration of
sludges. A typical design may include a disc centrifuge to
thicken a sludge followed by a solid bowl centrifuge.
Disc centrifuges have a high clarification capability
but possess an upper limit on the size of particle which can
be handled. Feed waters should be degritted and screened
prior to entering this equipment.
5.4.2.1.4 Rotary Vacuum Filters
Rotary vacuum filters consist of a cylindrical rotating
filter partially submerged in an open tank filled with the
slurry to be filtered. The filter elements can be coated
with a substance such as diatomaceous earth or other precoat
material so that particles much finer than the openings in
the filter element can be retained.
Vacuum filters operate at low differential pressures,
on the order of 6-10 psi (0.04-0.07 MPa) (9). When a precoat
substance is utilized on a vacuum filter, particles_down to
about one micron in diameter can be removed, resulting in
very clean effluents. Influent slurries, however, usually
must be limited to less than a one precoat solids concentra-
tion. The vacuum filter can be cleaned by hosing, internal
sluicing, or air pump backwashing.
79
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The use of vacuum filters is governed by the media s
opening and size distribution of particles in the sludge.
It has been observed that the solids captured by vacuum
filters may range from 85-99.5 percent depending on the type
of filter media, chemical conditioning, and solids concen
tration in the applied sludge (9). Cake yields usually
range from 2-15 lb/hr/ft2 (2.7 - 20 g/s/m2) for domestic
sludges (9). The surface area of vacuum filters generally
ranges from 50 to over 300 ft2 (4.6-28 m2) (9). Estimated
performance for design purposes is usually taken to be 3.5
lb/hr/ft2 (4.7 g/s/mZ) (dry weight basis) (9).
The filtrate discharge rate and cake thickness left on
the filter may be calculated by the following equations (13)
= 60n vf = |7200(AP)Bn| 1/2
A~ \ —
L =
1
c 60
7200B(AP)nW
- z w
c f
where*
2
Z = filtrate in gph/ft total area
n = cycles per minute
V^ = volume filtrate (gal)
A = filter area (ft2)
P = pressure differential maintained across the leaf
(psi)
B = fraction of total area actually being filtered
at any given time
a = specific resistance of cake (to be calculated)
|j = viscosity of filtrate (Ib/sec-ft)
W = mass of dry solids/volume of slurry (Ib/gal)
O
pc = density of cake (Ib/ft )
W.c = solids content of filtrate (Ib/gal filtrate)
L = cake thickness (ft)
*Metric conversion factors are given in Appendix A.
80
-------
The quality of the filter cake is measured by the percentage
moisture content of the cake on a weight basis. A typical
range of moisture contents which may be expected from this
equipment is 60-80 percent (9).
Typical chemical conditioning agents for the raw sludge
are lime and ferric chloride.
5.4.2.1.5 Lagoons
Drying lagoons are most ideally used where there is a
great deal of land and the climate is hot and arid. Lagoon
depths are generally not more than 24 inches (0.6 m) with
loading rates of 2.2-2.4 Ib/ft3/yr (35-38 kg/yr/m3) (9).
Sludge can usually be removed from the lagoon in 3 to 5
months (9). If it were feasible to load a lagoon for a
period of 1 year and allow a drying period of 2-3 years,
then it is conceivable that the applied sludge may be de-
watered from 5 percent to 40 to 50 percent solids (9). An
obvious disadvantage of this method is the extensive time
required to obtain the desired product.
5.4.2.1.6 Other Systems
There are four types of dewatering systems manufactured
by various companies which do not fall into any of the
previous categories. They include moving screen concen-
trators, belt pressure filters, capillary dewatering, and
rotating gravity concentrators.
Moving screen concentrators are capable of processing
400-800 Ib/hour (182-364 kg/hour) of excess activated sludge
and 800-1600 Ib/hour (364-728 kg/hour) of primary sludge
(9). These concentrations have been reported to increase
the solids content of primary sludges to 20 to 30 percent
(9). Typical yields vs. sludge cake solids are shown in
Figure 9. These units handle thickened polymer treated
sludges.
Belt pressure filters have been reported to produce
mixed sludge concentrations of 25 to 30 percent (9).
Polymer aids are generally used with these filters.
Pilot scale studies on domestic sludges using capillary
dewatering systems have indicated that loading rates of 2-
5.4 Ib/hr/ft2 (7.25 g/s/m2) will produce cake solids of 14-
19 percent with solids recoveries of 50-90 percent (9).
Polyelectrolytes and ferric chloride were used as filter
aids in these systems.
81
-------
18
_ 16
to
g
_i
O
to
UJ
U
12
UJ
O
§ 10
8
RAW
ANAEROBICALLY
DIGESTED
ACTIVATED
I
I
I
I
100 200 300 400 500
YIELD ( LBS/HOUR )
600
Figure 9. Moving Belt Concentrator Yield
vs. Cake Solids
82
-------
The rotating gravity concentrator has been mainly
employed as a concentrating device when more complete de-
watering was required. In one instance, it was reported
that a 25 percent filter cake was produced from a 6 percent
raw primary sludge (9). A disadvantage of the system is the
short life of the dewatering belt.
5.4.2.2 Treatment Processes
In addition to dewatering equipment there are numerous
processes which may be required in a wastewater treatment
plant to render solids wastes harmless prior to ultimate
disposal, to recover valuable chemicals, and/or to make sub-
sequent processes operate more efficiently. Typical pro-
cesses include heat drying, wet oxidation, pyrolysis,
incineration, and lime recovery. In many cases, one or more
of these processes may be combined with appropriate dewatering
equipment to produce sludges acceptable for ultimate disposal.
5.4.2.2.1 Heat Drying
Heat treatment may be used in lieu of chemical pre-
treatment to improve the dewatering characteristics of
sludges. In this process, sludge may be thickened to approx-
imately 7 to 11 percent by breaking down particle structures
within the sludge. Operating conditions are generally 360°F
(182°C) and 180 psig (1.2 MPa) (14). The detention time is
approximately 30 minutes (14). Up to 100 gpm (379 liters per
minute) can be processed by this method. It has been observed
that, in many instances, the moisture content of sludges may
be reduced to lower levels by using heat drying than by
chemical addition.
5.4.2.2.2 Wet Oxidation
The wet air oxidation process is based on the principle
that any substance capable of burning can be oxidized in the
presence of liquid water at temperatures of 250-700°F (121-
371°C). It is excellent for waste sludges which do^not
dewater easily. Typical operating conditions are given in
Table 22. Figures 10, 11, and 12 provide operating condi-
tions as a function of each other.
83
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TABLE 22. WET AIR OXIDATION PROCESS
OPERATING CONDITION (14)
Operating Condition
Value Qs)
Feed COD
Temperature
Pressure
COD reduction
VSS reduction
25-150 g/1
149-316°C
2.1-13.7 MPa
5-80%
30-98%
Four important parameters which control the performance
of the oxidation process are temperature, air supply, pres-
sure, and free solids concentration. The degree and rate of
sludge solids oxidation are significantly influenced by the
reactor temperature. It has been observed that higher
degrees of oxidation and shorter retention times are possible
with increased temperatures. The air requirements are based
on the heating value of the sludge and the degree of oxidation
desired. Operating pressures must be carefully controlled
to prevent excess water vaporization in the oxidation reactor.
Advantages and disadvantages of the process are listed
in Table 23.
TABLE 23. WET OXIDATION PROCESS
Advantages
Disadvantages
does not require dewatering
no air pollution
produces easily filtered and
biodegradable end products
potential to generate or recover
steam, power and chemicals
flexible in degree of oxidation
and type of sludge handled
need stainless steel con-
struction materials
need to recycle wet air
oxidation liquors, high in
organic content, phosphorus,
and nitrogen back through
the plant
possible frequent shut-down
and maintenance problems
odor problems
84
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UJ
g
co
cc
o
Q.
2.0
1.8
1.6
z S 1.4
O _l
b o: 1.2
n>* I'i
a _• 1.0
< m
>- d 0.8
a
p 0.6
<
III
0.4
0.2
£?
I
350 400 450 500 550
TEMPERATURE (°F)
600
I ._
650
Figure 10. Steam-to-Air Ratio at Saturation
in the Reactor Vapor Space for Various
Operation Temperatures and Pressures (14)
85
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COD
{GM. OF 02 REQUIRED PER LITER OF SLUDGE)
100
80
60
40
20
- 8.9% SOLIDS, PRIMARY SLUDGE
11.4% SOLIDS,
6.2% SOLIDS,
ACTIVATED SLUDGE
- 2.0 % SOLIDS,
100 200 300 400
TEMPERATURE (°F)
500
600
Figure 11. Reduction in COD Resulting from Sludge
Being Exposed to Excess Air for One Hour
At Various Temperatures (14)
PERCENT OF
MATERIAL OXIDIZED
100 -
572 °F
1.0 1.5 2.0
REACTION TIME (HOURS)
Figure 12. High Operation Temperatures Result in
High COD Reduction and Low Reaction Time (14)
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5.4.2.2.3 Pyrolysis
Pyrolysis involves the destruction of longchain organic
materials by high temperature exposure. Retorts, rotary or
shaft kilns, or fluidized beds are used to pyrolyze waste
sludges. This process has been proposed as an alternative
to incineration since it partially disposes of solid wastes.
Volume reduction also occurs in the process. It has an
advantage over incineration methods because it eliminates
air pollution problems and produces useful by-products.
Little data has been published, as yet, on the pyrolysis of
sludges.
5.4.2.2.4 Incineration
Incineration is a two stage process including drying
and combustion. It is most often used to render offensive
sludge wastes harmless so that the sludge may be safely
disposed of in landfills. The most commonly used incinera-
tion processes are the multiple hearth furnace and the
fluidized bed burnace.
Considerations important in the design of incineration
processes are the following:
• familiarity with state and local air and water
quality regulations and with occupational, health
and safety standards
• nature and amount of sludge to be incinerated
• applicability of incineration processes to sludge
treatment
• auxiliary fuel and excess air requirements
• economics
The composition of industrial sludges may vary so widely
from one plant to another that standard incineration pro-
cesses are usually not applicable. Hence, special incin-
erators must be designed to handle the complex compounds
found in these sludges. Often more than one incinerator
must be provided to combust complex organic materials
formed in the first incineration process.
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Multiple hearth furnaces have been adapted to numerous
uses including burning of raw sludge, digested sludge and
sewage greases; recalcination of lime sludges; and pyrolysis
operations. Capacities generally range from 200-8000 Ib/hr
(91-3636 kg/hr) dry solids (14). Combustion zone temperatures
range from 1400-1700°F (760-927°C) (14). Fluidized bed
incinerators are most often used for sewage sludge disposal.
Capacities range from 220-5000 Ib/hr (100-2273 kg/hr)
dry solids (14). Operating temperatures range from 1300-
1500°F (704-816°C) (14).
Although well-designed incinerators are relatively
simple to operate and maintain, a major disadvantage result-
ing from the process is the air emissions which must be
controlled. Advantages and disadvantages of incineration
are listed in Table 24.
TABLE 24. INCINERATION
Advantages
Disadvantages
Less land required for disposal
of incinerated sludges
Incinerator residue is free of
food for rodents and insects
Incinerators can burn a variety
of refuse materials
Adverse weather conditions
should have no effect on incin-
eration process
Incineration construction is
flexible
Large initital expenditures
Disposal of remaining residue
must be provided
Air pollution
Possible incomplete reduc-
tion of waste materials
High stacks needed for
natural draft chimneys
present safety problems
5.4.2.2.5
Lime Treatment
Lime treatment is a process whereby lime is recovered
from a waste sludge. Economic considerations dictate whether
or not this process should be included in industrial waste-
water treatment facilities.
The lime treatment process typically includes dewater-
ing devices such as thickeners or vacuum filters centri-
fuges, a furnace, lime cooler, classifier, and lime storage
unit. The design of thickeners, vacuum filters, and furn-
aces has been previously discussed. Contactive'(direct)
heat transfer methods may be used to cool the resultant
furnace residue prior to directing it to the classifiers
Centrifuges Calso previously discussed) may be used prior to
88
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the furnace to purge the sludge of inert solids. They also
reduce the required furnace volume. Dry classifiers are
used after the furnace to separate the calcium oxide from
the residue. This is accomplished by air separations based
on particle size. The regenerated calcium oxide is then
sent to a lime storage tank for reuse.
5.4.2.2.6
Control Module Selection
There are numerous sludges produced within an SRC plant
for which pollution control measures must be selected.
Typical sludges are listed in Table 25. Each type will be
subsequently discussed.
TABLE 25. SRC SLUDGES
Sludge
Origin
Lime sludge
Slag
Spent catalyst
Reactor sludge
Residue
Raw water treatment
(Hydrogen production, gasi-
fier, venturi scrubbers)
Hydrotreating
Bottom of vessels such as
fractionation tower.
Solids separation
Lime sludges are produced as a result of the addition
of lime to raw water. It contains large quantities of
calcium carbonate as well as magnesium hydroxide, calcium^
hydroxyapatite, suspended solids, detergents, and metals if
they are present in the raw water.
Prior to disposal, lime sludges usually require de-^
watering as the solids content is only 4-5 percent. Typical
equipment which may be used to decrease the moisture content
of these sludges are thickeners and centrifuges.
An alternative to dewatering is the recovery of lime
from the sludge. Equipment which may be used to recover the
lime are discussed in this section. An economic analysis of
dewatering vs. recovery must be undertaken to determine
which of the two methods is most economically feasible.
89
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There are no control measures (dewatering or treatment)
which must be applied to slag, spent catalyst or reactor _
sludges prior to disposal. Ultimate disposal methods appli-
cable to these sludges may, however, require special con-
tainment or disposal techniques.
A considerable amount of residue is discharged from the
solids separation area. It is apparent that the production
of fuel gas from the residue is much more feasible an alter-
native than treating this waste sludge by incineration or
pyrolysis prior to disposal. The slag which results from
the production of fuel gas probably will not require any
further control measures prior to ultimate disposal.
5.5 Final Disposal
5.5.1 Introduction
Ultimately, all materials discharged from a coal lique-
faction plant must be returned to the environment via air,
land, and/or water. The mechanisms by which wastes are
discharged to air and water have been thoroughly discussed
under the liquid, air, and solid waste treatment sections.
A general summary, therefore, on final disposal to air and
water is presented here. Mechanisms of ultimate disposal of
wastes to land have not been previously discussed. Conse-
quently, a survey of various methods will be presented in this
section.
5.5.2 Disposal to the Air
Biological and thermal decomposition of organic and
inorganic materials are mechanisms by which numerous compounds
are ultimately disposed of to the atmosphere. As discussed
in the Gaseous, Liquid, and Solid Waste Treatment sections,
there are a significant number of sources of gaseous waste
emissions discharged from coal liquefaction processes which
must be further processed prior to discharge to the environ-
ment. As indicated in the Solid Waste Treatment section,
there are also several possible sources of emissions to the
atmosphere as a result of sludge treatment depending on the
types of sludge treatment units employed.
The volume and characteristics of wastes which may be
discharged to the atmosphere are dictated by local, state,
and federal regulations.
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The effects of discharge of gaseous wastes to the
environment may be mitigated by their dispersion into the
atmosphere. Tall stacks may discharge wastes at such an
elevation that they will be completely dispersed by natural
elements such as wind and precipitation before they reach
the ground. Also equipment may be placed in the stack to
aid in the dispersion of gaseous wastes into the atmosphere.
5.5.3 Disposal to Water
Surface water discharge to lakes, rivers, or estuaries,
deep well injection, and ocean dumping represent the most
common mechanisms by which wastes are discharged to water.
Surface water discharge is the most accepted and widely used
method since severe restrictions have been placed on the use
of ocean dumping and deep well injection. The volume and
characterisitics of wastes which may be discharged to water
courses are dictated by local, state, and federal regula-
tions.
Controlled waste discharges to water generally result
from the operation of wastewater treatment facilities.
Accidental spills also represent a possible source of wastes
discharged to water.
5.5.4 Disposal to Land
There are numerous wastes resulting from coal lique-
faction processes and from the operation of wastewater
treatment facilities which may be ultimately disposed of on
land. Wastes discharged to land may be in the liquid or
solid phase. Typical land disposal methods include spreading
on soil, lagooning, dumping, landfilling, composting, spray
irrigation, and evaporation ponds. The first five are
considered sludge disposal techniques while the latter two
are considered liquid waste disposal techniques. State,
federal, and local regulations, availabiliity of land,
applicability of ultimate disposal processes, and economics
will dictate which of the aforementioned methods^may be
employed to ultimately dispose of liquid and solid wastes.
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5.5.4.1 Sludge Disposal
Land disposal of sludges includes the application of
sludge on soils used for crops or other vegetation, and the
stockpiling of sludges on land. Stockpiling refers to the
disposal of sludges in mines, quarries, landfills, and^
permanent lagoons. An inherent disadvantage of land dis-
posal is that it is not a permanent solution because the
sites fill and new locations must be found.
5.5.4.1.1 Land Spreading
Land spreading encompasses the disposal of sludge on
soils used for crops or other vegetation and on lands oc-
cupied by abandoned strip mines. Sludge may be spread on
the land as a soil conditioner or as an organic base for
fertilizers (biological sludges). It also serves as a
source of irrigation water. Other areas where land spread-
ing may be applicable are forest regeneration, development
of new parklands and institutional lawns, and top dressing
for parklands.
There are six acceptable methods of land application
including: plow furrow cover, contour furrow, trenching,
subsod injection, spray or flood irrigation, and spreading
(solid) (15). The application method selected will depend
on physical properties of the sludge, quantity of sludge,
acceptable application rate, site characteristics, crops
grown, site management, and public acceptance. Land spread-
ing of both liquid and dewatered sludges are feasible by the
above methods. An analysis of liquid sludge transport costs
vs. dewatering equipment costs must be undertaken when there
are no regulations restricting the moisture content of the
sludge to determine the most economic means of sludge
disposal.
Spray and flood irrigation systems are applicable only
to the disposal of liquid sludges. This method may be used
year round with proper maintenance on crop covers located on
0.5-1.5 percent sloping lands (15). Power requirements may
be significant when stationary application systems are used.
Flood irrigation is less costly than spray irrigation, but
can only be used in basin shaped sites. Problems resulting
from this method include fly breeding, odors, and a tendency
of solids to settle out near the outlets.
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The plow furrow cover method may be used for both
liquid and dewatered sludge application. Sludge may be
applied in a plow furrow manner using trucks, wagons or
irrigation systems. This method eliminates odor and pest
problems but is not usable on wet or frozen soils and on
highly sloped lands.
Contour furrows are normally used for the application
of liquid sludges. This method leaves the soil in only a
partially plowed condition.
Subsurface injection is reserved for the disposal of
liquid wastes. The site must be level or slightly sloped
and must not be wet, hard, or frozen.
Trenching may be used for both liquid and dewatered
sludges. Problems encountered with this method include
possible groundwater pollution and difficulty in keeping the
sludge where placed during backfilling operations.
Spreading applies only to the disposal of dewatered
sludges. This method encompasses the spreading of sludges
on reasonably dry solid surfaces with bulldozers, loaders,
graders or manure spreaders, and plowing it under.
It has been recommended that several alternative land
spreading methods should be made available at each site to
coincide with weather conditions, presence of crops, poor
quality sludge (odors) and equipment breakdown.
5.5.4.1.2 Lagooning
Sludge lagooning is a simple and economical method of
sludge disposal especially in remote locations. Sludges can
be stored, indefinitely in this type of system or removed
periodically to other sites after draining and drying.
Lagoons are usually 4-5 feet (1.3-1.7 meters) deep. This
method is usually feasible only when there are large tracts
of land available for dedication to lagoons.
5.5.4.1.3 Dumping
Dumping is a process whereby stabilized sludge is
deposited in abandoned mines and quarries. Where available,
this provides an alternative to other disposal methods.
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5.5.4.1.4 Landfills
Sanitary landfills are the most widely used type of
landfill. In many cases, it is permissible to mix domestic
and industrial waste sludges for disposal in a sanitary
landfill.
Criteria commonly used in the selection of a suitable
landfill site include the following:
• The site should have a relatively low permeability
and low water table.
• The site should be far enough away from surface
water bodies or shallow wells.
• A liner and drain system is recommended at the
site.
• The site should be covered with an impervious
layer to maximize runoff.
• Vector control should be provided.
• A wooded barrier should be provided.
Sludges applied to a landfill site should be dewatered as
much as possible to minimize the quantity of free water
which may leach out of the sludge.
Application rates will depend on sludge composition,
soil characterisitcs, climate, vegetation, and cropping
practices. Loading rates of 0.5-100 tons/acre (0.056-11.2
kg/m2) are common (14).
Problems associated with the use of landfills include
the following:
• groundwater pollution
• surface water pollution
• land requirement
• health hazards
• landfill gases (explosive)
• aesthetic effects on neighboring communities.
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5.5.4.1.5 Composting
Composting requires larger tracts of land than other
stabilization methods and produces a solid product which
must be disposed of. Its uses are similar to those for land
spreading, namely, as a soil conditioner and organic base
for fertilizers. Considerations with regard to site selection
and maintenance are also similar to land application methods
previously discussed. Land requirements are 1.5 acres/ton
(0.17 m2/kg) of sludge using the forced air, static pile
process. Advantages and disadvantages of the process are
listed in Table 26.
TABLE 26. COMPOSTING
Advantages Disadvantages
• odor free product • cost of transport to com-
• easy to store product posting site may have high
• able to return nutrients levels of heavy metals
and organics to soil • requires large tracts of
• nitrogen levels are land
reasonably low • product requires further
disposal
5.5.4.2 Liquid Waste Disposal
As previously discussed, liquid wastes may be ultimately
disposed of by discharge to surface waters or groundwaters
(deep well injection). Liquid wastes may also be discharged
to the land by spray or overland irrigation systems and
evaporation ponds. These methods are usually considered
when there is no direct access to surface waters or when^no
discharge systems are required due to surface water quality
restrictions.
The design of irrigation systems include the selection
of a suitable site, cover crop, application rate, and buffer
zone. Also, there are usually local restrictions on the
composition of the wastes which may be discharged on the
land. Advantages and disadvatages of irrigation systems are
listed in Table 27. Typical spray irrigation rates are
1 inch/day (2.54 cm/day) with a maximum of 3 inches/week
(7.6 cm/week) with BOD loadings of 100-250 Ib. BOD/acre/day
(11.2-28 kg/m2/day) (13).
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Evaporation ponds are usually located in an area where
land is plentiful and climatic conditions are conducive to
evaporation of wastewaters. Pond sizes will depend on the
volume of waste to be disposed of, evaporation rates, rain-
fall, and percolation rates. In many cases, the wastes may
be of such a nature that pond liners may be required. This
would eliminate the effects of percolation through the
bottom of the pond.
TABLE 27. IRRIGATION SYSTEMS
Advantages
Disadvantages
Relatively low initial costs,
Low or comparable operating
costs.
Flexible in quantity and
quality of wastes applied.
Provides for total treatment
of waste effluents.
May be used in cold weather
if operated properly.
May be used in conjunction
with harvestable crops to
subsidize procedure.
Wastes which are toxic
to biological treatment
may be handled if managed '
properly.
Requires large amount of
land.
Applicable to only certain
types of soils.
Can cause odor if wastes
are allowed to settle in
a pond.
Waste cannot hamper ab-
sorption capacity of the
soil.
Groundwater contamination
can occur if system is
not operated properly.
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5.5.5 Selection of Ultimate Disposal Methods
5.5.5.1 Disposal to Air
As stated previously, gaseous wastes emitted to the
atmosphere will be controlled by stack sizing and dispersion
techniques. It is assumed that such design measures will
be incorporated into the design of the plant.
5.5.5.2 Disposal to Water
Surface water discharge, deep well injection and ocean
dumping are the only ultimate disposal alternatives available
for the discharge of wastes to water. Since severe restric-
tions have been imposed on deep well injection and ocean
dumping is totally unfeasible for liquefaction plants located
in the midwest, surface water discharge appears to be the
only alternative available for discharge of wastes to water.
Therefore, in subsequent sections of this report, only
surface water discharge will be considered.
5.5.5.3 Disposal to Land
Several ultimate land methods have been presented in
this section which must be considered for each anticipated
waste discharge to land. Since it has been decided that
surface discharge is readily available for discharge of
aqueous wastes, spray irrigation and evaporation pond need
not be considered further as alternatives for wastewater
disposal. Also, many of the solids disposal methods such^as
spreading on soil, lagooning, and composting are not parti-
cularly applicable for many of the solid wastes discharged
from the liquefaction plant. In most cases, land-spreading
and composting are used when the sludge may be ultimately
used as a soil conditioner or fertilizer. None of the slag,
lime, or residue sludges discharged from the plant would be
suited to these purposes. Waste activated sludge from the
waste treatment facilities could be used as a soil conditioner
but its volume is so much smaller than the volume of other
waste sludges that it would be impractical to consider these
alternatives for only one sludge. It would be much more
practical to combine this sludge with other sludges prior to
disposal.
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5.6 Combustion Modification
Combustion modification techniques consist of modifying
operating and/or design features of the furnace to obtain
optimum control of nitrogen oxides emission. Operating
condition modifications include low excess air combustion,
two-stage combustion, flue gas recirculation, reduced air
preheat, and steam or water injection.
Nitrogen oxides concentrations can be lowered by
reducing excess air rates. The effectiveness of low excess
air combustion is proven for gas and oil combustion where
tests show a 20-30 percent reduction in NOX when oxygen in
the flue gas drops off to 2 percent from 3 to 4 percent (1).
No test data is yet available for coal-fired equipment.
Reduction in combustion air limits the availability of
oxygen throughout the combustion equipment and increases the
burner air-fuel mixture ratio to some extent. Very low NO
emissions with fuel oil have been attained with excess air
values as low as 2 percent. Simple lowering of excess air
does not appear as effective or damage-proof as other modi-
fication techniques. In coal firing, serious imbalances in
fuel/air distribution may result from low excess air, and
problems of unburned fuel or carbon monoxide emissions may
limit the utility of this approach. A reduction in emissions
of one pollutant may result in an increase of another. Off-
stoichiometric combustion has been found to be most effective
when applied to larger generating units with larger burners.
This is true because essentially all the nitrogen oxides are
formed in the primary combustion zone, and as the burner
size increases, the primary zone tends to become less
efficient (1).
One of the most effective methods for nitrogen oxides
control is the two-stage combustion process. In this
method, 90 to 100 percent of the theoretical combustion air
is injected into the burner. The remaining air is intro-
duced a few feet downstream of the burner to complete com-
bustion over a longer zone. With this arrangement, the
total excess air is held to the same value as that'of normal
firing. By supplying substoichiometric quantities of pri-
mary air to the burners in oil and gas-fired combustion,
reductions of 40 to 50 percent in nitrogen oxides may be
achieved. Complete burnout of the fuel is accomplished by
injecting secondary air at lower temperatures, where NOX
formation is limited by kinetics. This technique is best
used with low excess air firing. Reductions as high as 90
percent have been achieved using both technologies in large
gas-fired power plants. Table 28 shows the effect of two-
98
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stage combustion when natural gas and fuel oil are fired
(1). No full scale performance data was available for coal-
fired generators.
TABLE 28. EFFECT OF TWO-STAGE COMBUSTION ON EMISSION
OF NITROGEN OXIDES FROM A LARGE STEAM
GENERATOR AT FULL LOAD (1)
Fuel
Oil and gas
combined
Nitrogen Oxides
Concentration
When All Air
Through Burners,
ppm
by Volume
525
Two-Stage Combustion
Air Through
Burners,
% Theoretical
95
Total
Air,
7<> Excess
7-10
Nitrogen
Oxides,
ppm by
Volume
385
7o Reduction
in NOx
Concentra-
tion
27
Oil only
580
90
7-10
305
47
The recirculation of cool flue gas and its injection
through the burner is found to be quite effective in reducing
nitrogen oxides formation. This technique lowers the peak
flame temperatures by diluting the primary flame zone with
the recirculated flue gases. A direct reduction of maximum
combustion chamber temperature occurs when flue gas recirculation
is incorporated with excess air reduction techniques.
Nitrogen oxides drop off by a factor of 2 to 3 when flue gas
recirculation increases to more than 20-30 percent. Emission
concentration levels below 100 ppm are possible with over 25
percent flue gas recirculation. Most existing units are
presently limited to 20 percent recirculation, due to super-
heat and reheat steam temperature elevation (1).
Reducing the air preheat is a means of lowering primary
combustion zone peak temperatures and NOX formation. Lim-
ited data for natural gas tangential firing indicates a drop
in nitrogen oxides concentration in the order of 20 percent
with 100 percent reduction in air preheat. Operational
limitations with this technique have not been established,
but a basic disadvantage inherent in the system is a reduction
in thermal efficiency. This is undesirable, not only from
an operational standpoint, but also because more fuel is
consumed to generate electrical power or steam (1).
Injection of low temperature water or steam is similar
in concept to flue gas recirculation; thermal dilution of
the flame can be achieved by this method, resulting in re-
duced NOX emissions. This technique appears to have limited
utility for furnace control because of operating debits.
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The operating condition modifications mentioned above
can be used simultaneously. Low excess air and two-stage^
combustion reduce the quantities of gases reacting at maxi-
mum temperatures. Flue gas recirculation and reduced air
preheat directly influence maximum combustion temperatures.
Limited tests combining off-stoichiometric combustion with
gas recirculation on a 320 MW corner-fired unit showed that
NOX emissions could be reduced by 83 percent. However, it
was found that the combined conditions necessary to achieve
such low levels of NOX were not compatible with operational
procedures. Table 29 summarizes estimated nitrogen^oxides
reductions that may be achieved when combustion modification
techniques are applied to coal-fired boilers (1).
TABLE 29. ESTIMATED PERCENT REDUCTION IN
NOX EMISSIONS BY COMBUSTION
MODIFICATION OF COAL-FIRED BOILERS (1)
Low Excess Low Excess
Low Air and Air and Steam or
Boiler Excess Two-Stage Two-Stage Flue Gas Flue Gas Water
Size Air Combustion Combustion Recirculation Recirculation Injection
1000 MW
750 MW
500 MW
250 MW
100 MW
25
25
25
25
25
35
35
35
30
25
60
60
55
50
40
33
33
33
30
30
55
55
55
50
40
10
10
10
10
10
Design modification features vary in effectiveness and
ease of application from boiler to boiler. Specific boiler
designs and operating characteristics do play an important
role in determining final NOX emissions.
The concentrations of nitrogen oxides have been found
to vary with different burner types, spacings, and loca-
tions. Cyclone burners are highly turbulent operations.
This characteristic results in high-level emissions of ni-
trogen oxides in coal-fired units.
100
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The amount of heat release in the burner zone, calcu-
lated by considering the total energy input into the furnace
and the amount of energy lost to the surface area of the
water walls near the burners, seem to have a direct effect
on oxides concentration, especially during normal operation.
One test showed a linear increase of nearly 3 times the NO ,
with 2.5 times the increase in heat release (1). x
The difference in burner spacing has essentially no
effect on nitrogen oxides concentrations in the boiler
emissions, when boilers are at full load operation. How-
ever, at reduced loads, a close burner spacing would result
in higher NOX release, because the close burner spacing
inhibits effective bulk gas recirculation into the primary
combustion zone.
The distribution of air flow through the primary and
secondary air ducts can also be used as an effective means
to reduce NOX emissions. Tangential firing furnaces, in
which the furnace itself is the burner, exhibit lower peak
flame temperatures and a corresponding reduction in nitrogen
oxides emissions (as much as 50 - 60 percent compared to
conventional units) (1).
The method of steam temperature control can have a
definite effect on NOX emissions. Three conventional tech-
niques are employed: product gas recirculation, burner
tilt, and the use of high excess air. Burner tilt and the
use of high excess air both can increase NOX emissions
significantly. The logical choice for steam temperature
control is flue gas recirculation, which has already been
recommended as a viable means of NOX control. Steam tem-
perature control has a 33% removal efficiency (1).
Fluidized bed combustion offers efficient heat transfer
rates and, hence, low average combustion bed temperatures.
A major potential advantage is that both nitrogen and sulfur
oxides can be controlled by the injection of limestone or
dolomite. At present, only a few fluidized bed combustion
boilers of commercial size have been built. The boilers are
smaller and exhibit reduced fouling and corrosion problems.
Efficiencies of fluidized boilers are slightly higher than
conventional units with S02 removal systems. Potential
disadvantages include gas distribution problems and loss of
fluidization due to agglomerate formation (1).
101
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5.6.1 Control Module Selection
The selection of the appropriate combustion modifica-
tion technique is dependent on two main factors: the degree
of NOX reduction needed to meet government regulations; and,
the choice of the unit that provides the most cost-effective
alternative.
Engineering calculations for steam generation flue
gases indicate that current NOX emission standards would be
exceeded by 1 percent if conventional steam generation
equipment were used. Since the material balance was used
for calculation, which is in essence an estimation, then, in
an actual situation, conventional equipment might even
satisfy existing regulations. In this case, it is not
essential that the selected combustion modification technique
possesses high NOX reduction efficiencies (1).
The combined combustion modification techniques would
be much more than adequate to achieve required emission
levels. Being overdesigned, the combined techniques would
not present a cost-effective alternative.
The use of low excess air provides adequate reduction
efficiencies (25 percent); however, use of excess air alone
would present problems with carbon monoxide and hydrocarbon
emissions. For this reason, it is not judged a viable
alternative.
Steam or water injection may reduce nitrogen oxides by
at least 10 percent. Coupled with the fact that NOX emissions
from steam generation could be higher than estimated, the
low reduction efficiency for the steam injection technique
does not provide an adequate margin of safety.
Two-stage combustion and flue-gas recirculation are the
two modification techniques that seem most promising with
respect to meeting present day NOX emission standards.
5.7 Fuel Cleaning
Sulfur dioxide and fly ash emissions can be greatly re-
duced in the steam generation if sulfur is removed from the
coal prior to combustion. Fuel can be cleaned in two ways:
by using a physical/chemical method or by routing it through
the SRC process.
102
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Physical separation processes are based on physical
property differences of coal and pyrite (a mineral form of
inorganic sulfur). Separation techniques include gravity,
flotation, and electrical methods. Gravity methods make use
of the differences in specific gravity between coal and
impurities. Flotation separation methods rely on the differ-
ence in surface characteristics between coal and its impurities
Electrical methods use electrical (magnetic) forces to
effect the separation and work because of the difference in
magnetic susceptibility of coal and mineral matter. Com-
mercial coal cleaning is currently performed using gravity
methods in conjunction with froth flotation methods.
In general, physical methods can only separate out
pyritic sulfur and hence have relatively low total sulfur
removal efficiencies. Data from the U.S. Bureau of Mines
indicates that the average sulfur content of coal (3.2
percent, based on 455 mines) could be reduced to 2.3 percent
at 90 percent yield when crushed to 1-1/2 inch (3.8 cm)
top size. Coal crushed to 3/8 inch (0.95) cm and 14 mesh
would result in sulfur levels of 2.0 and 1.8 percent, re-
spectively (16) .
Based on federal regulations for SOX emissions (1.2
pounds of S0£ per million Btu's for coal-fired steam and
power plants producing more than 250 million Btu/hour) , and
the amount and heating value of Illinois No. 6 seam coal,
15.6 tons per day (14.2 Mg/day) of S02 may be emitted to the
atmosphere. Converting this value into the sulfur content
of the coal needed for combustion yields a figure of 0.75
percent total sulfur. In other words, coal for steam gen-
eration must be cleaned to a sulfur content of 0.75 percent
in order to meet SOX emissions regulations with no additional
pollution control techniques.
The chemical cleaning of coal involves treatment with
reagents that convert impurities into a soluble form, which
can then be removed by leaching. Chemical cleaning is most
effective in dissolving discrete particles of pyritic sul-
fur, using acid, alkaline, and oxidation reduction methods.
Physically cleaned coal is preferred as a feed to reduce
costs of reagents. Generally, all processes were found to
be effective toward the removal of pyritic sulfur, with a
less pronounced effect on organo-sulfur compounds. One
process using high temperature alkaline leaching was found
to remove 99 percent pyritic sulfur and 70 percent organic
sulfur (16).
A content of 5 percent total sulfur in Illinois No. 6
seam coal will contain approximately 2.92 percent organic
sulfur, 1.81 percent pyritic sulfur, and 0.23 percent sulfate
(17). Although the 5 percent figure is higher than the
103
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average, it is within the range given for the sulfur content
of Illinois No. 6 coal (18). Using this worst case^approach
and the removal efficiencies stated above, calculations
indicate that chemical cleaning of coal would exceed the
acceptable limit by 17 percent (.87 percent total sulfur).
Using, for calculations purposes, the organic sulfur: total
sulfur ratio stated above, the total sulfur content of a
coal that could be cleaned to acceptable limits is 1.83
percent.
Table 30 presents total sulfur ranges in Illinois No. 6
seam coal by county. It can be easily seen that all of the
counties have coals with averages above the acceptable
value.
The above discussion suggests that advanced physical
and chemical cleaning techniques are not a viable means of
achieving SOX emission standards without the use of some
pollution control equipment.
Cleaned coal below the acceptable sulfur limit (0.75
percent) can be obtained by routing additional coal along
with the process coal and using some SRC product as fuel for
steam generation. Average values for solid SRC from October
through December, 1976 were found to be 0.74 percent when a
mixture of Kentucky No. 9 and 14 coals were used, having an
average sulfur content of 3.9 percent over the three months.
These figures represent an overall sulfur removal efficiency
of 81 percent (19).
A worst case analysis using this removal efficiency and
high range values for the sulfur content of No. 6 coals from
White and Saline counties (3 percent) suggests an SRC sulfur
content of 0.57 percent, well under the acceptable limit.
The major disadvantage of using SRC is that if SRC pro-
duction is to remain at the same level, feed rates would
have to be increased by roughly 6 percent in order to supply
enough SRC for steam generation. If SRC is used for steam
generation as an alternative approach to S02 control, a
significant decrease in the overall thermal efficiency of
the process can be expected.
5.8 Fugitive Emissions Control
Significant quantities of hydrocarbons and particulate
matter are released to the atmosphere from storage tanks or
piles and leaks from pipe and process vessel flanges.
104
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TABLE 30. SULFUR CONTENT IN ILLINOIS NO. 6
SEAM COAL BY COUNTY (18)
County
Sulfur Content (percent)
LaSalle
Grundy
Bureau
Stark
Henry
Knox
Peoria
Fulton
Sangamon
Macoupin
Christian
Montgomery
Bond
Madison
Vennillion
Clinton
St. Glair
Madison
Washington
Randolph
Perry
Jefferson
Franklin
Jackson
White
Saline
Williamson
Gallatin
(Eagle Valley)
3-5
3-5
2-4
3-5
3-5
1-3
1-4
1-4
1-3
1-3
3-4
105
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Emissions from storage tanks are due to several mechanisms
that occur simultaneously as the tanks becomes warmer. The
vapor within the tank expands and is released to the atmos-
phere, carrying hydrocarbons with it. The higher tempera-
ture also raises the equilibrium partial pressure of the
hydrocarbons. In an effort to maintain equilibrium, more
hydrocarbons are evaporated from the vapor phase. These
evaporated hydrocarbons displace some of the vapor phase,
causing further venting. Vent emissions from storage tanks
can be controlled by the following practices:
• Eliminating the vent and building a tank which is
strong enough to withstand the expected pressure
• Installation of a floating roof, thereby minimi-
zing the vapor phase and allowing for changes in
the volume of the stored hydrocarbons with tem-
perature.
• Passing the vented hydrocarbons through a control
unit such as an adsorber.
These control methods can not only recover valuable
hydrocarbons for use or for sale. They also decrease the
hazard associated with the handling and storage of these
materials. Moreover, in many cases, they improve the
working conditions for operating personnel.
Leaks from pipe systems and process vessel flanges will
occur and present yet another source of fugitive emissions.
A preventative maintenance and inspection program should be
set up. In many cases, simply tightening pipe fittings and
flanges will significantly reduce fugitive emissions.
Guidelines for the prevention of fugitive emissions from
piping systems and process vessels are listed below:
• Tighten all flanges
• Replace leak-prone threaded couplings with flanges
or welded joints
• Gasket materials and pump seals should be cor-
rosion resistant and compatible with the process
_£T1 • _1 *•
fluid
• Double sealed or canned pumps should be employed
• Rupture disks should be installed under relief
valves, to avoid leaks if a valve reseats im-
properly
106
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• Preventative maintenance and inspection programs
for above-ground and buried pipelines should be
set up. These procedures are similar to those
discussed under material spill control
• Double-pipeline systems for leak monitoring of
buried pipelines should be considered
* T^e.num^er °f flanges, valves, and pumps should be
minimized while provisions for prompt isolation of
leaking sections and disposition of their contents
must be planned with great care
• Prior to maintenance work or routine disassembly,
material scavenging systems should be used, such
as evacuating a process vessel using a compressor
or purging the vessel with an inert gas.
Fugitive dusts from coal, sulfur, and SRC storage will
generally be of a highly variable nature, depending on
environmental conditions. Particle sizes are generally in
the 1-100 micron range (20). For relatively small storage
piles, such as sulfur storage, enclosures with particulate
control apparatus must be weighed against outside storage
piles using organic polymer coatings for dust control. For
larger storage piles, such as the ROM coal pile, enclosure
is infeasible.
5.9 Accidental Release Technology
5.9.1 Introduction
Accidental releases of pollutant materials from a coal
conversion process are very similar to those encountered in
a conventional petroleum refinery. Generally, there are two
main categories of accidental releases: material spills,
and gaseous venting during emergency operating conditions.
Spills are the result of leaks from tanks, pipes,
valves, and fittings; ruptures in storage and process equip-
ment; overfilling of tanks; and poor operation and main-
tenance processes in general. Material spills in coal
conversion plants are mostly on land rather than on water.
However, land spilled pollutants may find their way into the
aquatic'environment via groundwater contamination, so
proper prevention, control, and cleanup procedures are
essential to maintain environmental integrity.
107
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Provisions must be made to handle huge quantities of
process gases released by pressure release valves during
emergency operating conditions. These emergency conditions
occur due to compressor failures, loss of cooling water,
vessel overpressure, power failures, fires, and other emer-
gency conditions. It is common practice to tie all emer-
gency relief valve outlets, along with any continuous waste
gas streams, into a common header system that vents to a
combustion flare.
Preventative and countermeasure techniques will be
discussed with respect to material spills within the plant.
A description of the types of flare systems that can be used
for emergency venting will then be discussed.
5.9.2 Material Spill Prevention
There are a number of engineering practices which can
be applied to a material spill prevention program and they
are discussed below:
Leaks from storage tanks seem to be an ever present
source of soil and groundwater contamination in oil refin-
eries. Leaks develop when the tank bottom undergoes sig-
nificant corrosion, and so many prevention practices involve
the control of tank corrosion and include:
• Insure that structural materials are compatible
with the material being stored.
• Assess structural integrity for conformance to
code construction.
• Contained water promotes corrosion. Proper
methods for draining water from tank bottoms
should be employed. Figure 13 shows several
commonly used methods for draining tank bottoms.
It is also possible to develop automatic methods
employing oil/water interface sensors such as
density sensors, conductivity sensors, and diel-
ectric constant sensors.
• Repair of leaks, corrosion, etc. must be prompt,
no matter how minor. Leaks may be repaired by
patching while the tank is in service, and numer-
ous products are commercially available for
patching.
108
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SLOPE
WATER-
WATER'
WATER
Figure 13. Tank Bottom Drainage Systems (21)
109
-------
• Buried carbon steel tanks should be coated,
wrapped, and lined. Depending on the nature^of
the soil, cathodic protection may be appropriate.
Partially buried carbon steel tanks can set up
galvanic corrosion and increase the rate of cor-
rosion at the soil/air interface.
• Tanks should be examined periodically for evidence
of external leakage (especially bottoms). ^ This
examination may consist of visual inspection,
hydrostatic testing, and/or nondestructive shell
thickness testing.
Shell thickness may be measured by ultrasonic
analysis. Inspection records should be kept on a
frequency basis that is consistent with the his-
torical failure rate of tanks in the same service.
• Corroded tanks should be lined and coated with
epoxy. This treatment fills small pits and cre-
vices and prevents inside corrosion.
Normally, tanks are sandblasted to remove rust,
dirt and scale which not only prevents product
contamination but prepares the interior surface
for epoxy coating. The coating needs to be sel-
ected for its compatibility with the material
stored. X-ray analysis will locate pits and
crevices.
• Deteriorated bottoms should be replaced with
inverted cone-type bottoms. Figure 14 illustrates
one technique for replacement of tank bottoms.
• Mobile storage tanks should be isolated from
navigable waters by positioning and containment
construction.
One of the most common sources of leaks and spills
is the mobile storage tank such as the diesel fuel
tank used for construction machinery. It is
usually a simple task to dig a small pit or con-
struct temporary dikes around the tank.
• The condition of foundation and supports of tanks
should be assessed regularly.
In order to allow for adequate inspections and
possible structural calculations, up-to-date
drawings of the tank, foundation and structure
must be maintained. Records of inspection should
be kept for future reference.
110
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• If a tank has internal heating coils, the conden-
sate from these coils must be monitored for oil
content.
Condensate oil content can be monitored visually
or automatically. Figure 15 depicts the visual
method using an inspection sump and the automatic
method using a conductivity probe.
• Condensate from heating coils should be directed
to oil/water separator or similar systems.
• Heating coils should be tested, maintained and
replaced as needed.
• External heating systems are preferable to inter-
nal heating coils.
Typical external systems use plate coils which are
placed on the outside of the tank near the bottom.
Plate coils are bolted together and equipped with
a band that can apply pressure to the contact
surface between tank and coil for improved heat
transfer.
• Internal condition of tank should be checked dur-
ing every clean out maintenance.
Overfilling of storage tanks is a frequent cause of
accidental spills. Preventative engineering techniques are
listed below:
• Tanks should be carefully gauged before filling.
• High level alarms and pump shutoff devices should
be in place.
Figure 16 shows a control system that will auto-
matically stop a tank from overfilling. The sig-
nal generated by the level alarm can be used to
close the inlet valve, stop the pump or both.
• Overflow pipes connecting to adjacent tanks should
be in place.
• Automatic gauges and fail-safe devices must be
tested periodically.
• A communication system between pump operation and
tank gauging operation should be available.
Ill
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SEAL MELD
AROUND
CIRCUMFERENCE
.NEW BOTTOM
RING
MALL
PACKED
SAND
FILL
CORRODED BOTTOM
Figure 14. Tank Bottom Replacement (21)
COIL
o
o
STM TRAP
Y
L-T-'INSPECTION SI
VISUAL
CONDENSATE
ALARM
Figure 15. Internal Heating Coal Monitoring System (21)
112
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ALARM
.LEVEL CONTROLLER
LC }- '• ,
EMERGENCY OVERFLOW
"TO ADJACENT TANKS
PUMP
Figure 16. Tank Filling Control System (21)
113
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A number of preventative techniques are available with
respect to storage tank rupture and boilover:
• Insure structural integrity by code construction.
• Relief valves for excessive pressure and vacuum
should be in place.
Many types of relief devices are possible. One of
the most common is a pressure release manhole in
the tank top which provides a large_opening that
can quickly relieve any pressure buildup.
• Safety relief provisions should be tested period-
ically.
• Adequate fire protection facilities must be avail-
able.
Even tank maintenance practices, such as tank cleaning
and water drawoff, can generate material spillage and us-
ually do. Pollution problems can be minimized by practicing
the following guidelines.
• Water drawoff from crude storage should go to
oil/water separator or oily sewer system.
• Water drawoff must be accomplished under con-
trolled conditions with fail-safe devices, direct
supervision, visual inspection, etc.
• Tank bottoms (sludge) during cleanout should be
disposed of promptly.
• Temporary containment should be provided for
bottom sludge.
Underground pipes, valves, and fittings have a high
leak potential due to their susceptibility to corrosion.
The following practices should be considered when installing
and maintaining underground piping systems:
• Corrosion resistant pipe is preferable.
• Carbon steel pipe should be coated and wrapped
(coal tar, asphalt, waxes, resins, fiberglass,
asbestos, etc.).
114
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Cathodic protection system should be in place
where surrounding soils contain organic or car-
bonaceous matter such as coke, cinders, coal, acid
wastes, or other conditions. A soil resistivity
survey may be in order.
There are companies that specialize in cathodic
systems and they provide routine inspection ser-
vices .
Corrosion inhibitors should be used in piped pro-
ducts where internal corrosion is found and the
inhibitor is compatible with the product.
Marking lines should be obvious to prevent damage
by third party excavators.
Block valves should be located at strategic loca-
tions and periodically checked for operability.
Insure that pipe meets specifications codes.
Pressure drop fail-close devices should be in
place. If the pressure in a line changes, then
alarms can be activated and shutdown procedures
initiated.
Check valves to insure one-way flow should be in
place where required.
Rate of flow indicators should be in use.
Pipe corridors should be inspected visually.
Pipe lines should be hydrostatically tested
periodically.
Accoustical or magnetic testing equipment should
be used to check for leaks.
Condition of pipe should be checked and recorded
when construction activities expose buried lines.
Inventory of emergency repair equipment and fit-
tings should be maintained.
All abandoned lines should be removed, plugged or
capped.
115
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Above-ground piping systems also exhibit potential for
leakage. Proper preventative techniques are as follows:
• Frequent inspection should be made.
• Protection from vehicle collision should be used.
• Abrasion around pipe supports should be controlled.
• Pressure drop fail-close devices should be in
place.
• Block valves should be installed at strategic
locations.
• Rate of flow indicators should be in place.
• A preventive maintenance program should be in
force.
• Inventory of emergency repair equipment and fit-
tings should be maintained.
• All abandoned lines should be removed, plugged or
capped.
If a storage area spill does occur, the spill should be
contained by a system of dikes, which should surround each
storage -tank. Dikes must be constructed to accommodate the
maximum expected spill volume. Adequate freeboard allowance
for rainfall retention is imperative. Dikes should be
stabilized with an impervious coating such as asphalt, clay,
or concrete, so that leak potential is minimized. Material
of construction should be of an erosion-resistant nature.
With respect to maintenance, the following guidelines should
be established as practice.
• A program of dike inspection and maintenance
should be in force.
• Vegetation on earth dikes should be controlled.
• Through-the-dike pipes no longer in use should be
removed or plugged.
• Breaches made in dikes for maintenance purposes
should be minimized. Build ramps for vehicle
access.
116
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Even if the diking system is adequate and well main-
tained, overspills or leaks may occur due to a problem with
the containment area drainage valve. The following general
practices should be employed:
• Positive shutoff valves should be used, instead of
the flapper type.
• Full operational range (positive open and closed)
should be assured.
• Valves should be locked in closed position.
• Visual indicator should be installed in the
drainage system
• Easy access to drainage valves should be main-
tained.
• All weather operation should be assured, and no
debris should be present in the valve area.
When draining dikes of oily water or stormwater, the fol-
lowing guidelines should be practiced:
• Retained water should be checked for oil con-
tamination before release.
• Contaminated waters should go to oily water sewer
(oil/water separator system).
• Storm waters (uncontaminated) can be routed to the
stormwater drain.
• Records of drainage operations should be kept.
Miscellaneous practices that do not fit into any one cate-
gory are listed below:
• A closed drainage system should be installed at
sample locations.
• A maintenance and housekeeping program for drain-
age ditches and sewer inlets should be followed.
• Flooding of separator facilities must be precluded
by retention, designing separator for stormwater
flow and installing connected spare pumping
capacity. Such designs may be governed by NPDES
regulations.
117
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• Procedures for minimizing concentrated oil dumps
to the separator (sample coolers, bleed valves,
etc.) must be followed.
• Absorbents are preferable to flushing to sewer
during maintenance of piping and equipment.
• Security should be observed through limited access
lighting, fencing, patrols, alarms, etc.
• Overpressure release valves should be installed on
all process vessels to prevent plant losses and
subsequent material spills,
5.9.3 Material Spill Countermeasures
A material spill contingency plan indicates procedures
to be followed in the event that a spill occurs. There are
four phases to a material spill contingency plan: detec-
tion, containment, recovery, and disposal.
5.9.3.1 Detection
Suitable detection methods must be employed, so that a
material spill, no matter how minor, can be detected quickly.
Although large spills usually receive immediate attention,
this may not be true with smaller spills, whether continuous
or intermittent. Frequently, small spills go unnoticed and
unreported unless suitable detection methods are used. Some
methods lie midway between prevention and detection.
Periodic inspections are essential. A complete survey
can identify potential problem areas for periodic or con-
tinuous surveillance. Target areas should include heavily
eroded stream banks where pipeline crossings occur, points
of pipeline exposure, and any area where construction or
excavation work is in progress. Generally, observation
methods are marginally effective, and companion methods
should be employed.
Oil sensitive probes can be located throughout a drain-
age system of a potential spill. When a spill occurs, feed-
back to a central control panel will immediately identify
the location. Two types of probes are predominant: a
conductivity type which depends on an induced change in the
dilectric constant, and an ultrasonic type which is trig-
gered by a change in viscosity. These units will signal the
presence of oil in an area but not the source location of
the spill.
118
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Tagging may be used to identify both the source of a
leak and the spread. This consists of adding coded mater-
ials to the stored or piped materials and then periodically
analyzing drainage samples for their presence. The mater-
ials used must satisfy the following criteria:
• Physically and chemically stable
• Readily identifiable
• No effect on commercial uses of material
• Soluble and dispersible in the material, yet
insoluble and nondispersible in water
• Inexpensive
Examples of tagging substances include halogenated aro-
matics, nitrous oxide, and radiochemicals. Tagging has not
been widely used because of cost and complicating factors.
5.9.3.2 Containment
In the event that storage tanks are undiked or a
material spill extends beyond the diked area, diversion
systems, such as a catchment basin containing an oil trap,
should be available. These should be designed to contain at
least the amount of stored material plus sufficient excess
capacity to insure complete interception. The primary
separation of oil from the water should be accomplished as
early in the system as possible so that the problem of
handling large volumes of oil/water mix is minimized.
Should a spill take place outside the confines of a
drainage system, a temporary dike or diversion trench must
be constructed. The location would depend on expected
direction and rate of flow. Information concerning these
two factors, and in particular their relationship to tempera-
ture, should be included in a reaction plan.
Materials and equipment necessary for the construction
of diversion or holding structures should be on hand. Bar-
riers may be manufactured or improvised from a wide variety
of materials including wood, plastics and metal. In some
cases, locally available materials such as hay bales and
sandbags will suffice. Aside from the requirement for
mechanical strength, other considerations would include
susceptibility to heat in the event of a fire and softening
or cracking in the presence of some mineral oil components.
Equipment that should be available includes standard exca-
vation machinery and tools and commercially marketed booms.
119
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If the spill should reach navigable water, there are a
number of containment techniques that can be employed. iney
include booms, air curtains, and surface active agents. rwo
basic types of mechanical booms are available - curtain
booms and fence booms. Curtain booms include a surtace
float that acts as a barrier on the surface and supports a
subsurface curtain. The curtain is flexible and provides a
barrier 1 to 2 feet (0.3-0.6 meters) below the surface.
Weights may be attached for stabilization. Figure 17 is an
example of this type. Fence booms differ only in that they
have a rigid curtain or panel both below and above the
surface. Flotation supports the "fence." These types are
normally employed in deeper and rougher waters. Figure 18
is an example of this type.
Figure 19 shows one method of using a boom in an oil
spill. Generally a boom will perform the following tasks:
• Compact widely scattered puddles of oil to faci-
litate skimming operations.
• Manipulate slicks away from sensitive areas or
towards fixed removal installations.
With proper planning, the required booms should be
readily available. In the event that such preparations have
not been made, booms can be improvised through the use of
materials such as hoses, bladders, tires, pipe and drums
with attached planks.
Air curtains are produced by an air supply to perfor-
ated hoses and pipes. They may also serve as a containment
apparatus under specific conditions. A schematic of an air
barrier is shown in Figure 20.
Surface tension modifiers inhibit the spread of oil in
water. When relatively small quantities of these chemicals
are placed on the surface next to the floating oil, the oil
is repulsed and tends to agglomerate. Application is sim-
ple; only a small amount need be used, applied as a coarse
spray on the water at the edge of the spill. The effects
last only a matter of hours, so cleanup plans should be
implemented as soon as possible. As with any chemical
approval for the use of surface tension modifier must be
obtained from appropriate governmental agencies.
120
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55 GAL. DRUMS
%" PLYWOOD
Vi" WIRE ROPE
BALLAST FILLED
PLASTIC SKIRT
Figure 17. "Navy" Boom (Curtain Type) (22)
CHAIN LINK FENCE
Figure 18. Kain Boom (Fence Type) (22)
121
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LEAD-BOAT
12 MAT
TURBULENCE
LOSS OF OIL AT
THIS SHARP BEND
BOWSTRING TENSION
LINE REDUCES SHARP
BEND IN BOOM
BRIDGE
i—SLUICEWAY
SKIMMER
Figure 19. Boom/Skimmer Configuration for Oil Spill Cleanup (22)
STAGNATION LINE
MOUK3
r c-y&f
v vk /v°;'
/°.o
'/
<°5*- BUBBLE PLUME
Figure 20. Circulation Pattern Upstream of an
Air Barrier in a Current (22)
122
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5.9.3.3 Recovery
Numerous harvesting devices and various removal tech-
niques exist for handling harbor and inland spills. Sor-
bents are oil spill scavengers, cleanup agents which adsorb
and/or absorb oil. Based on origin, sorbents may be divided
into three classes:
• Natural products include those derived from veget-
ative sources such as straw, seaweed and sawdust;
mineral sources such as clays, vermiculite and
asbestos; and animal sources such as wool wastes,
feathers and textile wastes.
• Modified natural products include expanded per-
lite, charcoal, silicone-coated sawdust and
surfactant-treated asbestos.
• Synthetic products include SL vast array of rubber,
foamed plastics, and polymers. Table 31 details
the effectiveness of various materials.
The requirements for a satisfactory sorbent include the
following:
• Aids in handling and removing oil
• Minimizes spread of oil
• Is nontoxic
• Enhances performance of booms and other skimming
devices
Removal of soil on water may require skimming. Skim-
mers may be purchased commercially or built for a particular
application. Additionally, they may be floating, fixed, or
mobile (mounted on boats, barges, trucks, etc.). The type
of skimmer depends on its probable application. Of primary
concern is its capacity in terms of total fluid handling
volume, recovered oil volume, and pumping rate. These
factors should be compatible with the expected utilization.
Of secondary importance is the size, seaworthiness, speed,
maneuverability, and other skimmer characteristics. Figure
21 shows the classes of skimmers.
Once the spill has been contained, it is usually re-
moved and disposed of with a vacuum truck. One or more of
these should be permanently assigned to the installation.
If this is not the case, outside contractors must be iden-
tified and made familiar with the site facilities.
123
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TABLE 31. SORBENTS' RELATIVE EFFECTIVENESS AND COSTS (22)
Type material
Ground pine bark, undried
Ground pine bark, dried
Ground pine bark
Sawdust, dried
Industrial sawdust . .
Reclaimed paper fibers dried surface treated
Fibrous, sawdust and other
Porous peat moss
Ground corn cobs
Straw . .
Chrome leather shavings
Asbestos, treated
Fibrous perlite and other
Perlite, treated . .
Talcs, treated
Vermiculite dried . .
Fuller's earth
Polyester plastic shavings.
Nylon-polypropylene rayon
Resin type
Polyurethane foam
Polyurethane foam
Polyurethane foam ..
Polyurethane foam . .
Pol rurethane foam
Pick-up ratio— weight
oil pick up/weight absorbent
69
1.3
3
1.2°
1.7
3
1.0
5
3-5°
10
4
5
2.5
2
2
3.5-5.5
6—15
12
70
15
70
40
80
Unit cost, absorbent
( J/T absorbent)
6
15
15
56
30
30
30
Indicated comparable
to straw in cost.
500
416
230
70—120
25
100
3 166
20,000
4,500
2,260
1,200
I cost of absorbent for
cleanup of 1,000-gal. oil spill
27
47
50
75
21
27
440
290
320
120—210
80
900
1,000
1,050
195
55
c Another reference gives a ratio of 20
D0ther reports have indicated ratios of 20 and above
-------
ROTATING BELT
COLLECTION WELL
AVERTED ENDLESS BELT
ROTATING
DISKS
FIXED WIPER
COLLECTION
TROUGH
OLEOPHILIC DISK
TO PUMP
TO PUMP
T
HYDRO-ADJUSTABLE
SAUCER WIER
SIMPLE SAUCER WIER
TO OIL PUMP
DEFLECTOR i
FLOATS MI
SQUEEZE ROLLER vCOL^£TION
ROTATING POROUS
WATER PUMP
VORTEX WIER
WATER
WATER
QLEQPHiUC BELT
TO PUMP
OVERaOWWIER |
CALM REGION TO PUMP
LEADING
ADVANCING WIER
WATER
DOUBLE ADVANCING WIER
RFCQVFRY
BROADCAST SORBENT^,;'. BELT
OIL SOAKED SORBENT
Figure 21. Classes of Skimmers (22)
125
-------
An underground water supply may be endangered by a land
spill. A considerable portion of the oil can be removed by
excavating the contaminated soil before the oil has reacnea
great depths. The extent or depth to which this would be
economically feasible is a function of the type ot oil as
well as the underlying soil structure.
Oil from a land spill may reach the water table. If
its viscosity is not too high, large amounts may be recovered
by pumping. A well is drilled, centered in the spill, and
screened at a depth no further than the oil/groundwater
interface. In the pumping process, a cone of depression of
the oil/water interface will be formed and will prevent oil
from spreading further. At first the pump should extract
oil exclusively; it should extract progressively more and
more water. The amount of pumping is a function of recovered
oil, spilled oil, and oil retained by the soil. Generally,
pumping should stop when the oil/water ratio becomes less
than 1 percent.
Spills eventually reach the plant drainage system;
therefore, the site treatment facilities play a significant
role in the oil removal process. Various types of sepa-
rators are in use. Besides the classical API type, there
are gravity plate separators and a host of multistage
separators, some equipped with coalescence filters. In
addition, there are other devices that employ proprietary
methods ranging from ultrasonic treatment to polyelectrolyte
injection.
Separation is ideally followed by physical-chemical
treatment. This will incorporate some sequence of coagula-
tion, flocculation, sedimentation and possibly air flota-
tion. The remaining petroleum fraction can be removed by
biological treatment. The activated sludge process is
commonly used, often in conjunction with an aerated lagoon
and a trickling filter. Following a dewatering step, the
sludge may either be incinerated or hauled off for land-
filling operations by a local contractor.
5.9.3.4 Disposal
Slop oil which has been recovered prior to reaching the
drainage system or which has been separated in the initial
step of the treatment system can be disposed of in several
126
-------
• Recycling recovered oil back into the plant pro-
cess is the most common and the most economical.
This is done by bleeding the slop oil into the
feedstock over a period of time. Any impurities
picked up during recovery of the spill are removed
along with the usual bulk, sediment, and water.
Any emulsions which have been formed can be broken
using chemical agents and heat. As long as exten-
sive "weathering" (evaporation of volatile com-
ponents) has not significantly affected the fuel
quality, this method can be used.
• Reclaiming recovered oil for other uses is a less
desirable alternative. It is economically feasi-
ble only when the oil is not amenable to blending
with the feedstock. This is normally done by an
outside contractor equipped with appropriate re-
refining facilities. These might include steam-
ing, filtering, and additive rebalancing. Such
contractors frequently specialize in storage tank
and sump cleanout operations as well.
• Burning is another method of final disposal of
oil, particularly nonreclaimable sludges. Large
amounts can efficiently be disposed of in this
manner with the help of combustion agents or by
blending with lighter grades of fuel such as
kerosine. The mixture is then atomized and
burned. This course of action requires careful
control to obtain complete combustion to avoid air
pollution.
• Dispersing. Dispersants are chemical agents which
emulsify or solubilize oil in water. Their use is
governed by Annex X of the National Contingency
Plan. They should not be employed except when
other methods are inadequate or infeasible.
• Sinking. As oil weathers and becomes more dense,
there is a natural tendency of the residual frac-
tion to sink. This phenomenon depends, of course,
on the type of oil involved in the spill. Oil can
be made to sink by application of a nucleus of
high density material having an affinity for the _
oil (oleopliilic property) and not having an affinity
for water (hydrophobic property). The resulting
mass of material then settles to the bottom.
127
-------
Typical oil sinking agents include sand, fly
lime, stucco, cement, volcanic ash, chalk, crushed
stone, and specially produced materials such as
carbonized-silicanized-waxed sands. These^are
effective on thick, heavy, and weathered oil
slicks.
The major problem in sinking oil is that the
bonding of the agent with the oil must be nearly
permanent. Many agents will release oil back into
the environment after a period of time or as a
result of agitation and turbulence. Microbial
action on the oil-soaked particles also produces
gaseous by-products which give the particle a
tendency to float.
5.9.4 Flare Systems
There are three basic classifications of combustion
flares, as follows:
• Elevated combustion flares
• Ground combustion flares
• Ground pits
5.9.4.1 Elevated Combustion Flares
Elevated combustion flares are the most commonly used.
The combustion tip is usually 100-300 feet (33-100 meters)
above grade, which drastically reduces the effects of heat
radiation. Consequently, the flare can be located close to
process units. In this way, the amount of vent piping and
land requirements are minimized. The extra height also
gives the added advantage of better dispersion of combustion
products than with ground flares. Minimum height is determined
with respect to radiation protection and is adjusted upward
so that ground level contaminant concentrations will meet
ambient air standards. The elevated flares, depending upon
the method of achieving smokeless combustion, utilize air
inspiration with steam or mechanical air blowing.
Steam injection into the flare tip can greatly reduce
or even eliminate smoke generation. This reduction results
from two effects. Steam has an inspirating effect and draws
large quantities of air into the combustion zone. This
supplies necessary oxygen for burning, provides intense
128
-------
mixing, and has a solvent cooling effect which reduces
cracking and polymerization. Steam also reacts with un-
reacted carbon particles to form carbon monoxide and hydro-
gen, as shown by the following equation:
C + H20 »• CO + H2
The principal methods for inj ecting steam into flares
involve the use of multiple jets, single nozzles, or a
shroud. In the multiple jet design, waste gases are ex-
hausted from the open end of the flare tip. A large header
located around the periphery of the tip distributes steam to
several jets. The jets are oriented so that their discharge
covers the tip and creates turbulence and mixing of the
waste gases with the surrounding air. Steam consumption is
relatively low, 0.2-0.5 pounds (0.1-0.2 kg) of steam per
kilogram of waste gas; however, this is balanced against the
maintenance costs which are slightly higher than the single
nozzle design. Tip construction utilizes corrosion-resistant
alloy steel (1)•
In single steam nozzle design, the steam line enters
the flare and continues upward in the center until it
terminates several inches below the top of the tip. As the
steam exits the supply line, it expands to fill the inside
of the flare tip and, in so doing, mixes with the waste gas.
The turbulence created is not as great as with multiple
jets. However, the system requires less maintenance due to
its simple design (1).
In the shroud type design, the flare tip is surrounded
by a metal skirt or shroud. This reduces some of the cross-
wind effects and forms a turbulent zone for premixing of the
air and steam. Waste gas exits radially from the center
portion of the tip and travels toward the shroud, causing
intense mixing with the vent gas. Steam utilization is com-
parable with that of the multiple steam jet type (1).
In mechanical air blowing, blowers are utilized to pro-
vide air for smokeless combustion of small gas streams. For
gas rates over 100,000 Ib-moles/hr (45.4 Mg-moles/hr),
the amount of air requires large equipment. Capital invest-
ment is not competitive with steam inspiration systems, if
steam is available.
129
-------
5.9.4.2 Ground Combustion Flares
Ground flares are built near grade level and seldom
exceed 60 feet (20 meters) in height. Consequently, heat
radiation effects require that flares be limited in size and
located away from the process areas. This raises piping_
costs and eliminates them from consideration in plants with
little available space and high-vent gas rates. Greatest
application is for locations where elevated flares would be
unsightly and complete smokeless operation is not required
(1).
Ground flares have an important advantage in that water
can be substituted for steam in many cases. Consequently,
operating costs are greatly reduced. However, as the water
requirement increases at high vent gas rates, it becomes
increasingly difficult to obtain satisfactory combustion.
Therefore, smokeless operation is limited to a maximum of
100,000 Ib-moles/hr (45.4 Mg-moles/hr) gas flowrate (1).
A typical water injected ground flare is composed of
three concentric stacks. The innermost stack contains the
burner and water atomization nozzles. The second stack is
slightly larger and serves to confine the tiny water drop-
lets for effective mixing with the incoming air and the vent
gases. The outermost stack merely directs the flame upward
and protects against crosswinds. Slots are provided near
the base of all three stacks to allow entrance of air by
natural draft (1).
Ground flares can be designed to handle higher vent gas
rates by using air inspirating venturi burners. Application
is limited due to a pressure requirement of 1 to 4 psig
(7,000-28,000 Pa) at the burner and 7 psig (48,000 Pa)
backpressure (1).
Several burners are required to handle a wide range of
vent gas rates. These auxiliary burners and their automatic
control valves become a significant cost item. A major
drawback of the system is that it cannot handle vent rates
which substantially differ from the design basis.
5.9.4.3 Ground Pits
Burning pits are generally unacceptable except as a
device to handle catastrophic emergency situations. They
are excavated units with alloy steel burners along one or
more sides. The walls are usually concrete or refractory-
lined. Dense clouds of smoke are released during operation
and the combustion products are not dispersed efficiently.
130
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5-10 Regional Variations
5.10.1 Introduction
The Wabash River in White County, Illinois was selected
as the site for the hypothetical SRC plant discussed in this
report. This location was chosen because of the proximity
of large deposits of a process compatible coal, Illinois #6,
adequate water resources, and expressed interest by the
State of Illinois in coal conversion technology. Also,
since the area is already industrially developed, adequate
auxiliary services, such as needed electricity and transporta-
tion, are available.
Location of the SRC complex in other regions of the
continental United States can affect the quantity and com-
position of effluents, water consumption, pollution controls
and process design. In the remainder of this section these
regional influences are discussed.
5.10.2 Raw Coal
It is highly probable that SRC plants will be located
near the source of the raw coal feed. The composition of
this coal will affect the size and makeup of effluent streams,
products, and by-products. Variations in these streams
loadings will dictate the types of controls needed and the
overall plant environmental impact.
For example, a low sulfur coal burned in the boiler
could eliminate the need for SOX stack gas scrubbers. A
dissolver coal feed that has higher levels of trace metals,
such as mercury or arsenic, could influence the methodology
and location of solid waste disposal as well as increase air
and water emissions. Consequently, more efficient control
methods may be needed. A high sulfur coal will produce more
sulfur as a by-product and require additional acid gas
removal equipment.
The type of coal also influences the makeup and volume
of emission in the coal preparation module. For example,
different coals when pulverized produce varying quantities
of coal with differing physical and chemical properties.
This could influence the selection of control technologies.
131
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5.10.3 Water
Limited supplies of water in certain regions of the
country, such as the Southwest, can drastically influence
process and control modules and even prevent locating some
facilities.
This report emphasizes water conservation and a com-^
promise between supply and need may be necessary. Recycling
streams may be necessary, especially in extremely dry
parts of the country. Reduction of cooling water require-
ments via recycling and increased usage of air-cooled heat
exchangers can significantly affect total water usage. In
water-short areas, wet air pollution control systems, such
as particulate and 862 scrubbers may be impractical. Alter-
native control technologies, such as cyclone, baghouses, or
coal desulfurization, may be necessary. The quantity of raw
water used in boilers or cooling towers will influence the
type of raw water treatment, the frequency of blowdown, and
the type of corrosion inhibitors used. These parameters
will affect the overall influent to the waste treatment.
5.10.4 Climate
Coal pile runoff flows into process drains. The amount
of precipitation at the plant site will directly affect the
volume of coal pile runoff. Acidic rainwater, such as that
found in the eastern United States, will promote leaching of
trace metals from the coal. The wastewater treatment plant
must be designed to accommodate the runoff due to regionally
typical storms.
In arid regions, such as the Southwest, the coal pile
may have to be moistened more frequently to reduce fugitive
particulate emissions. However, wetting the pile may, in
turn, increase coal pile runoff as well as use precious
water.
5.10.5 Auxiliary Systems
Expected high concentrations of trace metals, sulfates,
and organic and inorganic compounds in solid waste produced
at the plant can pose a serious pollution problem. A land-
fill capable of properly handling the waste should be
located in a reasonable proximity to the plant. Inability
to locate or develop a proper landfill site meeting local
and federal regulations could prevent siting the facility.
132
-------
Adequate transportation for receiving raw material and
shipping products must be readily accessible to the plant.
Increased traffic, air and water pollution in the area could
restrict locating the facility.
In this study, all electricity has been assumed to be
produced off-site. However, an electrical generating unit
could be integrated into the plant operations if purchasable
electricity were unavailable. Generating power in-house
would cause additional emissions. Overall increases in air
(SOx, particulates, NOX), solids (ash), and water (cooling
tower and boiler blowdown, thermal, etc.) discharges would
be included.
5.10.6 Local Regulations
If the facility is located in an area with differing
environmental regulations from those of White County, Illinois,
allowable quantities of pollutant discharges also may differ.
These regulations could be either more stringent or more
liberal, depending upon the particular location. Obviously,
different regulations would affect both process and control
technologies or possibly prevent siting altogether.
133
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6.0 Detailed Definition of Basic System
6.1 Introduction
The previous sections of this Standards of Practice_
Manual have been presented as summary information, descri-
bing the basic SRC system, pollution control options and
costs, and existing and proposed State and Federal regula-
tions. The preceding section, although seemingly an in-
depth view of pollution control, is in actuality a summary
of the available control options and their design criteria,
with respect to expected emissions from a coal liquefaction
facility. The sections mentioned above should provide the
engineer with a general knowledge about the basic process,
its emissions, available control technology, and standards
that may apply to a commercial SRC facility.
The purpose of this section is to provide the engineer
with detailed knowledge of the SRC system, its emissions,
and the most economically feasible and environmentally
acceptable control options. This is accomplished by fur-
nishing a system description and material balance for a
50,000 bbl/day (7,950 nP/day) theoretical SRC-II commercial
facility. The SRC-II system is described with respect to
modules which carry out specific functions within the over-
all system. Material balances are provided for each module
so that process and waste streams may be viewed in a concise
manner.
Based on material balance data, process data, and
engineering calculations, the waste streams will be further
characterized to include volumetric flow rates, temperature,
pressure, grain loading, BOD, suspended solids concentra-
tions , and other parameters that may not be apparent in the
material balance and general process description.
Next, applicable control options are matched to spe-
cific waste streams using design criteria presented in
Section 5.
Cost and performance data have been developed from pub-
lished literature and vendor information. The cost and per-
formance data for recommended control modules is presented
in tabular form for each waste stream, so that treatment
alternatives can be readily compared.
Alternatives for wastewater treatment, sludge disposal
and flares cannot be included in this modular approach,
since they accommodate combined waste streams from several
process modules. They are therefore discussed under separate
headings.
134
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6.2 Coal Preparation Module
6.2.1 Module Description
There are a number of different coal preparation pro-
cesses that may be suitable for use in an SRC commercial
facility. All of them produce a cleaned, dried, and ground
coal product; however, different processes may result in
different quantities of waste streams. It is expected that
the general nature of discharges from such facilities will
be similar.
Figure 22 presents a schematic flow diagram of a typical
coal preparation facility. Only the major pieces of equip-
ment are shown. The module receives run-of-mine coal and
processes it into feed sized to minus 1/8 inch (0.3 cm),
suitable for slurry preparation (23). The module can be
divided into a number of process steps, i.e., receiving,
reclaiming and crushing, storing, drying and pulverizing,
and slurry mixing.
Run-of-mine (ROM) coal may be received either by rail
or truck. It has been calculated that about 31,552 TPD
(28,681 Mg/day) of ROM coal would be needed for a 20,000 TPD
(18,182 Mg/day) SRC facility with steam generation and
gasification. If coal is received by rail, a railroad
hopper car dumps each carload into a hopper below rail
level. ROM coal also can be received from mine trucks,
where it will also be unloaded into a receiving hopper. A
vibratory feeder transfers the coal from the hopper to a
belt conveyor, which in turn transfers it to a rail-mounted
slewing stacker. The slewing stacker may move along the
length of a belt, forming a stockpile on one or both sides
of the belt. The stockpile has been designed to hold 94,560
tons (85,964 Mg) of ROM coal. The stockpiling system will
gather up to 1,300 tons (1,182 Mg) of ROM coal per hour.
This stockpile does not represent total storage capacity of
the coal preparation facility, since minus 3" (7.6 cm) coal
(after reclaiming and crushing) is also stored.
Coal is reclaimed from the ROM stockpile by a bucket-
wheel which feeds the coal going to a transverse conveyor to
one or two belt conveyors. A transverse conveyor takes the
coal from either of the belt conveyors and delivers it to a
receiving hopper. The reclaiming system will handle up to
1,300 tons (1,182 Mg) of coal per hour. Coal is discharged
to a 60-inch (1.5 m) reciprocating plate feeder onto a 48-
mch (1.2 m) belt driven conveyor, fitted with a magnet to
remove tramp iron. The coal is conveyed to a 3-inch (7.6
cm) scalping screen, which separates out oversize coal (3-
mch [7.6 cm], plus) and allows broken coal (7.6 cm, minus)
135
-------
TO REFUSE PILE
*- TO STACK
20" DIA.
CLEAN COAL
CLASSIFYING
CYCLONES
TO PREHEATER
(HYROGENATION
iWDULE)
RECYCLED
SOLVENT
Figure 22. Process Schematic - Coal Preparation Module
-------
to pass through. The oversize coal is charged to a rotary
coal breaker, where it is crushed to less than 7.6 cm.
Oversize refuse present in ROM coal is separated in the coal
breaker. The broken coal is placed on a 1.2 meter belt
conveyor, where it is combined with the undersize coal from
the scalping screens and discharged to a 10,000 ton (9,091
Mg) storage pile.
Two storage piles are incorporated into the coal pre-
paration module, the ROM stockpile and the broken coal stor-
age pile, representing a total storage capacity of approxi-
mately 104,560 tons (95,055 Mg) of coal. A polymer coating
may be applied to each storage pile to minimize oxidation.
Most rainfall coming in contact with coated storage piles
will run off while only a small percentage will infiltrate.
Assuming a storage pile is conical 25 ft. (7.6 m) tall, its
total area has been calculated to be approximately eight
acres (3.3 x 104 m2).
Coal is withdrawn from the minus 7.6 cm, ground coal
storage pile and conveyed to the washing plant for cleaning
and reduction. A series of jigs, screens, centrifuges,
cyclones, and roll crushers clean the coal and reduce it to
minus 1-1/4 inch (3.1 cm). Oversize refuse is separated
from the coal stream and returned to the mine for disposal.
Wet fine refuse is pumped to settling ponds. The clean
minus 3.1 cm coal is then dried in a flow dryer and reduced
to minus 1/8-inch (0.3 cm) in pulverizers. The pulverized
coal is suitable for slurry feed mixing.
The dried, pulverized coal is transferred by conveyor
to the coal/solvent tank, in which 20,000 tons (18,182 Mg)
of coal and 40,000 tons (36,364 Mg) of unfiltered solvent
are mixed per day. The slurry is then pumped to the pre-
heater.
6.2.2 Process and Waste Streams
Process and waste streams present within the coal
preparation module are designated with respect to the unit
operations within the module, as shown in the block flow
diagram, Figure 23. Waste streams in the block flow diagram
are described below. Components in selected waste streams
are quantified in Table 32.
137
-------
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
„
Cl) *
* CO/
PREPAF
^ MODI
®»
*
STREAM
ROM Coal (5% Moisture)
Recycled process solvent
Air for coal drying (70% R.H.)
Makeup water
Fuel gas and air
Moisture from environment
Coal dust
Tramp iron and refuse
Refuse from cleaning processes
Coal pile runoff
Thickner underflow (35% solids
* (r j
®^ — '
/^\
' x-^x ^ V~y
\L r C-D ^
NATION -^ "vlSx
ii r »- n 1 1
^ r f 1 ? )
^ (f/T)
X^N ^rP/
' QT)
QUANTITY * (TPD)
31552,
40000
32810
4837
3961
1909
24
1645
6839
74
) 3432
Dry coal to gasification (2% moisture) 1531
(Mg/DAY)
28684
36364
29827
4397
3601
1735
22
1495
6217
67
3120
1392
Dry coal to steam generation (2% moisture) 1041 940
Coal /sol vent slurry to hydrogenation 60408
Dryer stack gas
Gland water
Flue gas
32842
NOT QUANTIFIABLE
3961
54916
29856
3601
*Streams may not balance due to roundoff.
Figure 23. Coal 'Preparation Module Process and Waste Streams
138
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TABLE 32. PROCESS AND WASTE STREAM CONSTITUENTS
IN COAL PREPARATION MODULE
(TPD)
(5) Fuel gas and Air
Fuel gas
CH4 107.3
C2H6 67.4
N22 1.6
CO 27.4
C02 0.3
Air 3757.4
(15) Dryer Stack Gas
Air 32810.0
Water 3281.0
Particulates 32.0
(17) Flue Gas
N 2981.0
C02 552.6
02 178.3
H20 249.6
—
Quantity*
(Mg/day)
97.5
61.3
1.5
24.9
0.3
3415.8
29827.3
2982.7
29.1
2710.0
502.4
162.1
226.9
^Streams may not balance due to roundoff
139
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Dust from Coal Receiving, Storage, Reclaiming and
Crushing - Coal dust is generated during transter
of coal from shipping to receiving bins and during
storage (wind action), conveying, stacking, re-
claiming, and crushing operations. Dust is com-
posed of coal particles, typically from^l to 100
microns in size, with a composition similar to
that of the parent coal. Proximate and ultimate
analyses of Illinois No. 6 seam coal can be found
in Table 33, an ash analysis is presented in Table
34, and a trace element analysis is given in Table
35. Data in Table 35 suggest that coal dust will
contain significant concentrations of the trace
elements titanium, magnesium, boron, fluorine,
zinc, and barium. Dust generated from the above
operations has been estimated to amount to approxi-
mately 24 tons/day (22 Mg/day) for a 20,000 ton/day
(18,182 Mg) plant (1). This amount has been
estimated to be divided equally among the three
processes.
Coal Pile Runoff - Coal pile runoff results from
rainfall and infiltration waters that come into
contact with the stored coal. The resulting
leachate may contain oxidation products of metal-
lic sulfides; it is frequently acidic, with re-
latively high concentrations of suspended and dis-
solved solids, sulfate, iron, calcium, and other
coal constituents. The quantity and concentration
of coal pile runoff water generated is dependent
on the type of coal used; the history of the pile;
and the rate, duration, frequency, and pH of
precipation. An analysis of runoff from two coal
piles is presented in Table 36. No information
was available specific to Illinois No. 6 coal.
Assuming a stormwater runoff coefficient of 0.7,
the mass flow rate of coal pile runoff waters has
been calculated (74 TPD [67 Mg/day]), based on the
average annual rainfall for Illinois (42.5 in [108
cm]) and the area of coal storage (3.3 x 10^- m2)
(24,25).
Refuse from Reclaiming and Crushing - Refuse from
the reclaiming and crushing modules is composed
chiefly of tramp iron, slate, coal, and "bone."
These materials are naturally present in the coal
seam. Particle size is greater than 3 inches (7.6 cm)
140
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TABLE 33. RUN OF MINE (ROM) ILLINOIS
NO, 6 COAL ANALYSIS (23)
Proximate Analysis (weight percent):
Moisture 2.70
Ash 7.13
Volatile matter 38.47
Fixed carbon 51.70
Heating value 12,821 Btu/lb
(3 x 107 J/kg)
Ultimate Analysis (weight percent):
Carbon 70-75
Hydrogen 4.69
Nitrogen 1.07
Sulfur 3.38
Oxygen 10.28
141
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TABLE 34. AVERAGE ASH ANALYSIS OF ILLINOIS
NO. 6 COAL (26)
Component Percent of Ash
Si02 44.4
A1203 21.0
Fe90 22.1
Ti02 1.1
P205 0.1
CaO 5.2
MgO 1. 0
Na20 0.5
K20 2.0
SO- 1.7
142
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TABLE 35. TRACE ELEMENT COMPOSITION OF
ILLINOIS NO. 6 COAL SAMPLES (27)
Element
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Bromine
Cadmium
Calcium
Cerium
Cesium
Chlorine
Chromium
Cobalt
Copper
Dysprosium
Europium
Fluorine
Gallium
Germanium
Hafnium
Indium
Iodine
Iron
Lanthanum
Lead
Lutetium
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Rubidium
Samarium
Scandium
Selenium
Silicon
Silver
Sodium
Strontium
Tantalum
Terbium
Thallium
Thorium
ppm
13500
0.98
5.9
111
1.5
135
15
<4
7690
13
1.2
1600
20
6.6
13
1f\
.0
0.25
/" O
63
3.1
<5.6
0.52
0*1 /
. 14
1. 9
18600
7
O ~T
27
0 OR
\J . UO
C T f\
510
53
0. 18
9 2
J * £~
22
£~ £*
45
1700
16
1.2
2.6
2.2
26800
0.03
660
36
0.16
0.17
0.67
2.2
143
-------
TABLE 35. TRACE ELEMENT COMPOSITION OF
ILLINOIS NO. 6 COAL SAMPLES (27)
(Continued)
Element ppm
Tin 4.7
Titanium 700
Tungsten 0.7
Uranium 1. 6
Vanadium 33
Ytterbium 0.54
Zinc 420
Zirconium 52
144
-------
TABLE 36. CHARACTERISTICS OF COAL
PILE DRAINAGE (28)
Concentration
mg/1 (unless otherwise indicated)
Constituents
Acidity (total) , as CaCO-
Calcium
Chemical Oxygen Demand
Chloride
Conductance , umho / cm
Dissolved Solids (total)
Hardness, as CaCO-
Magne s ium
pH, unit
Potassium
Silicon (dissolved)
Sodium
Sulfate
Suspended Solids (total)
Turbidity, JTU
Aluminum
Arsenic
Barium
Beryllium
Cadmium
Chromium
Copper
Iron
Lead
Manganese
Mercury
Nickel
Selenium
Titanium
Zinc
Plant J
1,700
240
9
0
2,400
3,200
600
1.2
2.9
--
91
__
2,600
550
300
190
0.01
--
0.001
0.005
0.56
510
0.01
27
0.0002
1 -i
olos
1
J . /
Plant L
270
350
--
--
2,100
1,500
980
0.023
2.9
— —
--
4.1
—
810
--
0.009
0.1
Ort T
.01
0.006
0.005
01 o
. 18
830
0.023
110
0.027
0 32
w • ^/ *•
0.003
1.0
145
-------
o Refuse from Pulverizing and Drying - This refuse
stream is generated after screening with the_
double deck refuse screen. The stream contains
slate, "bone," coal, and water added during
screening. Both refuse streams are stockpiled
before removal to the mine for burial.
o Thickener Underflow - Wastewater generated from
a number of processes in the coal preparation
module is routed to a thickener where particulates
are removed and clarified water is recycled. The
underflow stream has a flow of 3,432 TPD (3,120
Mg/day) with a suspended solids loading of 1,201
TPD (1,092 Mg/day) which corresponds to a con-
centration of 35% suspended solids. The waste-
water is expected to contain a substantial quan-
tity of coal-derived organic constituents prior to
wastewater treatment.
o Gland Water - Gland water is generated from leaks
in the piping system; hence, it has not been
quantified. It may contain substantial concen-
trations of particulate and organic matter. Gland
water may be collected in a sump and pumped to
treatment.
o Gaseous Emission from Drying - This waste stream
has been calculated to carry 3,281 TPD (2,983
Mg/day) of moisture and 32 TPD (29 Mg/day) of
particulates for a 20,000 TPD (18,182 Mg/day)
plant. A significant concentration of coal-
derived organics are also expected to be present
in this stream. Gas from fuel combustion is
composed of carbon dioxide, water, carbon mon-
oxide, nitrogen, oxygen, and unreacted hydrocarbons,
6.2.3 Control Equipment Specification and Cost Estimation
Waste streams that emanate from processes in the coal
preparation module are summarized in Table 37, along with
applicable control technology. The following presents a
detailed characterization of the waste streams control and
options and capital and operating costs of sized units.
146
-------
TABLE 37. WASTE STREAMS FROM COAL PREPARATION MODULE
Source
Unit Operation
Coal Receiving
Storage
Storage
Reclaiming,
Crushing &
Pulverizing
Dryer
Water Recycle
System
Screening
Nature of Waste Quantity
TPD (tfe/day)
Applicable
Control Measures
Coal Dust
Coal Dust
Runoff
Coal Dust
8
8
74
8
67
7
Stack Gas 32842 29856
Thickener 3432 3120
underflow
Tramp iron 8484 7713
and refuse
Cyclone & baghouse
High eff. cyclones
Wet scrubbers
Polymer coating
Enclosed storage
Tailings pond
Cyclone & baghouse
High eff. cyclones
Wet scrubbers
Baghouse, wet-
scrubber
Tailings pond
Mine burial
Coal dust from the coal receiving area is generated
by transferring coal from the receiving hopper to the
conveyor belt and to the slewing stacker (see Figure 2.2.).
The dust-laden air is at atmospheric pressure; therefore
collection hoods and a duct system must be designed for dust
transport to a particulate removal unit. The flow rate oi
the dust-laden air will depend on the combined flow rate ot
the collection hoods. Exhaust requirements for conveyor
belts traveling greater than 200 feet per minute (61.0
m/min) suggest.,that collection hoods be designed for a flow
rate of 500 ft3/min/ft. (0.6 m3/sec/m) of belt width (29).
If 1.2 m belt conveyors are used, then the collection hood
must have a minimum flow rate of 2,000 cfm (0.9 m3/sec) for
efficient dust collection. It is recommended that collection
hoods be installed at transfer points and enclosed^as much
as possible C29). Since there are two transfer points in
the receiving area conveyor system, two collection hoods are
required, each with a flow rate of 2,000 cfm (0 9_m-Vsec) .
Based on a dust release rate of 8 TPD (7 Mg/day) in coal
receiving and a combined flow rate of 4 000 cfm (18 m-Vsec),
a grain loading of 19.5 grains/cu. ft. (35.0 mg/m3) has been
calculated.
147
-------
Here, as in the receiving area, three particulate re-
moval systems can be considered as treatment alternatives:
cyclone and baghouse, high efficiency cyclones or multi-
clones, or a wet scrubber system. Cost data can be found in
Table 38 along with efficiencies and expected emissions
based on waste stream characteristics, as calculated.
Again, the cyclones and baghouse system is suggested above
the others.
Refuse and tramp iron from crushing operations are
disposed of by burial in the mine. Hauling costs will
depend on distance from the facility to the mine. It is
assumed that this distance will be less than fifty miles.
If collection trucks are used, hauling costs will range from
$l-$6 per ton ($0.9-5.4/Mg) of waste (14). A daily refuse
and tramp iron load of 8,483.5 TPD (7,712 Mg/day) for the
20,000 TPD (18,182 Mg/day) facility generates a hauling cost
of $8,500-$50,900 per day or $2.5-15.3 million annually.
Two major waste streams emanate from the drying and
pulverizing section of the coal preparation module, i.e.,
dryer stack gas and thickener underflow. Thermal dryers are
the largest single source of air pollution in the coal
preparation module. Particulate emissions from thermal
dryers range from 15-25 Ibs/ton (8-10 g/Mg) of coal processed
(12). Flow dryers, which have a cyclone collector built
within the unit, can be expected to have considerably lower
emissions. If cyclone efficiency is assumed to be 90%,
particulate emissions from flow dryers will range from 1.5
to 2.5 Ibs/ton (0.8-1.0 g/Mg) of processed coal. Based on
a coal rate of 31,700 TPD (28,818 Mg/day), this value
represents a particulate loading of 32 TPD (29 Mg/day).
Calculations for the dryer stack gas volume and grain
loading were based on the following criteria:
Exit gas temperature = 60°C
Exit gas pressure = 1 atmosphere
Pvelative humidity at 60°C = 70%
Heat capacity of air = 0.25 cal/g°C
The dryer stack gas flow rate was calculated to be 32 810
TPD (29,827 Mg/day) with a volumetric flow rate of 0 8
MCF/minute (377 m3/sec) at 60°C. This value equals 240
m3/sec at standard conditions, based on a relative humidity
of 70%, at 60°C. Grain loading was calculated to be 0.4
grains per actual cubic foot ^0.65 mg/m3) or 0.6 grains/dscf
(1.2 mg/m3) with a particle size range of 0.1-20 microns.
148
-------
TABLE 38. TREATMENT ALTERNATIVES FOR
DUST STREAM FROM COAL RECEIVING (31.32,33)
Basis: 4,000 cfin (1.8 m /sec) with a grain loading of 19.5 grains per
ft3 (35.0 mg/m3) (34,689 ppm)
Cost
Treatment
Cyclone &
Baghouse
Total
High-Efficiency
Cyclone
Wet Scrubber
Capital1
($1,000)
4.5
10.5
T57D"
4.5
7.75
Annual ~
Operating
not
available
not
available
$1600/yr4
Efficiency
99.9%
99+%
98.5%
Emission
After
Treatment
35 ppm
347 ppm
520 ppm5
Secondary
Waste3
dust
dust
wastewater
Includes cost of equipment and installation.
23hcludes cost of fuel, utilities, and maintenance.
3Secondary wastes are wastes generated by the operating pollution control
unit.
with recirculation.
By weight
149
-------
There are three particulate removal systems that can be
considered as treatment alternatives: cyclones and bag-
house, high efficiency cyclone system, or wet scrubber sys-
tem. Electrostatic precipitation is not viable because of
the high explosion potential. Advantages and disadvantages
of each system have been previously discussed. Table 38
presents the results of calculations for the three alternate
systems. Data are given on capital and operating costs,
efficiencies, and expected emissions based on the character-
istics of the waste stream. The cylone and baghouse system,
although expensive, gives the best removal efficiencies and
is most compatible with the highly variable dust streams.
Two waste streams emanate from coal storage area, i.e.
fugitive coal dust and coal pile runoff. Methods for fugi-
tive dust control are limited. The stock pile may be
sprayed with an organic polymer coating or the coal may be
stored in an enclosed storage bunker. The ROM coal pile of
94,560 tons (85,964 Mg) is much too large for enclosure,
therefore polymer spraying is the only feasible means of ^
control. Material costs are approximately $300/acre (7j£/m )
of stockpile (30). The material is sprayed, and using a
hydromulcher, operating costs range from $600-1000/day (30).
Material costs for the ROM coal pile (3.3 x 10^ m2) would be
$2,400 per application. An application every three days
would result in a material cost of about $240,000 per year
with operating costs of $180,000-300,000/year.
The broken coal pile is considerably smaller than the
ROM stockpile, having a capacity of about 10,000 tons (9,091
Mg) and a storage area of only 2.0 x 10^ m2. A comparative
cost analysis of polymer coating versus enclosed storage is
shown in Table 39. Operating costs for the polymer coating
of the 10,000 ton (9,091 Mg) storage pile would be over-
whelmed by the operating costs for coating the ROM storage
pile. However, a rough estimate of operating costs can be
made by using the six-tenths factor on storage area ratio of
both piles. The scaled down operating cost for coating the
smaller pile would range from $126-211/day, using the six-
tenths factor. Annual operating costs would average $12,600-
$21,100, based on an application every three days (100 days
for a 300 day stream year). Enclosed storage can no longer
be considered a feasible alternative, due to the excessive
capital cost ($6-8 million) as compared to the cost of
polymer coating.
150
-------
TABLE 39. COSTS OF CONTROL ALTERNATIVES FOR FUGITIVE DUST (30.34)
Basis: 10,000 Ton (9,091 Mg) Broken Coal Storage Pile
Operating Cost (Annual) Capital Cost
Polymer Coating $12,600-21,000 $18,000
Enclosed Storage $6-8 million
Coal pile runoff calculations were based on the 67
Mg/day average annual rainfall data for Illinois. This
value^corresponds to a hydraulic flow of 17,700 gallons/day
(67 m /day) . Coal pile runoff waters will be combined with
thickener underflow and routed to the tailings pond. Data
with respect to contaminants in coal pile runoff water are
in Table 40.
Coal dust generated from reclaiming and crushing
operations has been estimated to be roughly 8 TPD (7 Mg/day) .
There is a potential dust problem during reclaiming by
bucket wheel. The problem has been controlled in other coal
preparation plants by water spray during operation. It was
therefore assumed that the bucket wheel reclaiming system
does not contribute significantly to the total dust load.
The 7 Mg/day dust load comes from four 1.2 m conveyor belts
in the reclaiming and crushing section. Coal breakers and
crushers are water sprayed and do not generate significant
quantities of dust. Just as in the receiving area, collec-
tion hoods must be installed. Their design flow depends on
the width of the conveyor belt, and they will be installed
at the two transfer points of each belt. In order to minimize
the cost of ducting, it is suggested that separate removal
units be installed for each conveyor. Each particulate
control unit will handle the combined flow rate of two
collection hoods (1.8 m3/sec) . If it is assumed that each
conveyor belt will generate 2 TPD (1.8 Mg/day) of coal dust,
the grainoloading to each unit will be 4.86 grains/cu ft
(6.5
151
-------
TABLE 40. TREATMENT ALTERNATIVES FOR DUST STREAMS
FROM COAL RECLAIMING AND CRUSHING (31.32.33)
o
Basis: Four units, each handling 4,000 cfin (1.8 m /sec) with a grain
loading of 4.86 grains/ft3 (6.5 mg/m3) (8,646 ppm)
Cost
Treatment
Cyclone &
Baghouse
Per Unit
Total
Capital1
($1000)
4,500
10,500
15,000
60,000
2
Operating
(Annual)
not
available
Emission
After
Efficiency Treatment
99.9% 8.6 ppm
3
Secondary
Waste
Dust
High-Efficiency
Cyclone
Per Unit
Total
Wet Scrubber
Per Unit
Total
4,500
18,000
6,750
27,000
not
available
$16004
$6400
99+7o 86.5 ppm Dust
98.5% 129.7 ppm Wastewater
Includes installation.
Tuel, utilities, and maintenance.
"Vastes generated by operating pollution control unit.
\Fith recirculation.
152
-------
The promulgated federal standards of performance for
new and modified coal preparation plants require that emis-
sions from-jcoal dryers may not exceed 0.031 grains/dscf
(0.05 mg/m ) and 20 percent opacity. In order to meet these
standards, particulate removal efficiencies must be above
95.2%. Cyclones have removal efficiencies of less than 9070
for particles less than 20 microns. Therefore, they are not
considered to be feasible treatment alternatives. Appli-
cable control technologies include the use of a bag filter
system or a wet scrubber unit. Characteristics of each unit
have been discussed in the Control/Disposal Practices sec-
tion. Because of excessive water use in wet scrubbers,
baghouses are more feasible.
Table 41 presents capital and operating costs, effi-
ciencies, and expected emissions from the two control alter-
natives .
TABLE 41. CONTROL ALTERNATIVES FOR
STACK GAS FROM COAL DRYING (32,33)
Basis: 0.8 MACFM (377 nT/sec) at 140°F (60°C) with a grain loading of
0.4 gr/acf (0.65 mg/nP) (712 ppm)
Cost
Treatment
Capital
($1000)
Operating
Efficiency
Emission
After
Treatment
Secondary
Waste
Baghouse
Wet scrubber
1000
380
Not available
$28,000
99.9%
98.5%
0.7 ppm
10.7 ppm
Dust
Wastewater
Thickener underflow has been previously quantified in
the process material balance (3,432 TPD [3,120 Mg/day]). It
is routed to a tailings pond along with coal pile runoff.
The combined flow of the two streams has been calculated to
be approximately 0.8 MGPD (3,179 m3/day) with coal pile
runoff comprising only about 2 percent of the total hydraulic
flow.
A number of factors which must be considered in the
design of a tailings pond include the following (35):
153
-------
(1) Adequate detention time must be provided (4-6
hours).
(2) Sludge storage should be provided. This volume
should not be included in the calculation of the
volume required for adequate detention (estimate 1
month storage volume)
(3) Adequate volume should be provided to store the 10
year storm (estimate 5.1 inches or 12.9 cm).
(4) Approximately 2 feet (0.6 m) of freeboard should
be provided in the pond.
In addition to the above criteria, the cost per acre of
the basin is important. There is a wide range of depths
which fits the above, but the cost of basins ($/ acre) has
been observed to increase with depth. Approximately 15 feet
(4.5 m) is the maximum depth which should be considered.
Table 42 lists two alternative basin designs based on cost.
A liner is included in the cost analysis because of the
nature of the wastes discharged to the pond.
TABLE 42. TAILINGS POND (4)
Costs ($1000)
Alternative I Alternative II
Pond
Hand Dress Slopes
Anchor Ditches
Liner (PVC)
Liner Installation
Contingency
Total
(4047 nT, 4.1 m deep)
27.0
0.419
0.298
5.68
0.67
3.4
37.42
(8094.0 m , 2.4 m deep)
11.6
0.360
0.440
10.350
1.22
5.99
29.97
154
-------
6.3 Hydrogenation Module
6.3.1 Module Description
Hydrogenation is a process whereby the coal molecule,
under high temperature and pressure, is broken down into a
number of active free radicals which can combine with hydro-
gen to produce a mixture of hydrocarbon products. When the
pressure ranges from 200 to 2000 psig (1.4-14.0 MPa), no
catalyst is needed in this process. A flow diagram of the
hydrogenation process is shown in Figure 24 (23).
In the hydrogenation process, the resultant coal/slurry
mixture from the coal preparation area is first injected
with hydrogen gas. The hydrogen gas is a mixture of recycle
hydrogen and synthesis gas from the hydrogen production
module, and has a total hydrogen content of 97% by volume.
The gas/slurry stream is pumped to a dissolver preheater
elevating the pressure to about 1700 psig (11.9 MPa). The
preheater increases the temperature to approximately 850°F
(454°C). The preheater is fired by fuel gas (23) .
The heated mixture is then introduced into a dissolver
where the coal is depolymerized and hydrogenated. The sol-
vent is hydrocracked to form hydrocarbons of lower molecular
weight, ranging from light oil to methane; organic sulfur is
hydrogenated to form hydrogen sulfide. The temperature and
pressure in the dissolver are about 850°F (454°C) and 1700
psig (11.7 MPa), respectively (23).
The resultant product stream contains gases, liquids,
and solids. It is removed from the dissolver reactor and
transferred to a series of vessels to separate various
products. The estimated composition of the product stream
is given in Table 43.
6.3.2. Process and Waste Streams
Module input and output streams are shown in Figure 25.
Stream compositions are given in Table 44. Preheater fuel
gas is the only continuous waste stream discharged from the
hydrogenation module. Fuel gas and flue gas compositions
also are given in Table 44. There is also a possibility of
hydrocarbon vapor leakage from the reactors and transient
spills. Leaks and spills would be controlled by proper
maintenance procedures and spill contingency plans as out-
lined in section 5.9.2.
155
-------
Oi
COAL/SOLVENT
MIXTURE
HYDROGEN
FLUE GAS
PHASE GAS
^ SEPARATION
PROCESSES
/
SLURRY
PREHEATER
\
A
V
^
DISSOLVER
FUEL
Figure 24. Hydrogenation Module Flow Diagram
-------
TABLE 43. HYDROGENATION REACTOR EFFLUENT
Compound Quantity (Mg/day)
(TPD)
Liquid Product 49142.0 44674.5
Residue and Ash 3062.0 2783.6
Light and Heavy Oils 3491.8 3174.4
Hydrogen Sulfide 469.0 426.4
Ammonia 60.0 54.5
Nitrogen 18.5 16.8
Carbon Monoxide 397.3 361.2
Carbon Dioxide 288.8 262.6
Unconsumed Hydrogen 563.7 512.5
Water 3346.6 3042.4
Gaseous Hydrocarbons 3545.9 3223.5
157
-------
©
©-
2
•*•*_-•
**~^»
3
HYDR06ENATION
© ©
•©
1. Coal/solvent slurry
2. Water
3. Synthesis gas from hydrogen production
4. Hydrogen from gas purification
5. Vapor discharge
6. Product (gas/liquid/solid)
7. Accidental material spills
8. Fuel gas
9. Air
10. Flue gas
*Streams may not balance due to roundoff.
QUANTITY*
(TPD) (Mg/day)
66408 54916
2652
734
592
2411
667
538
NOT QUANTIFIABLE
64386 58532
NOT QUANTIFIABLE
760 691
13998 12725
14758 13416
Figure 25. Hydrogenation Module Process and Waste Streams
158
-------
TABLE 44. HYDROGENATION MODULE STREAM COMPOSITIONS
STREAM
1. Coal/ Slurry Solvent
Coal
Solvent
3 Synthesis gas
H2
CO
co2
H2S
8 Fuel Gas
N9
CO
co2
CH4
C2H6
10 Flue Gas
N,
°2
co2
H20
(TPD)
20408.0
40000.0
321.0
321.0
73.1
18.5
.03
6.1
102.1
1.0
399.9
251.0
11105.3
664.1
2058.7
929.8
QUANTITY*
(Mg/day)
18552.7
36363.6
291.8
291.8
66.5
16.8
.03
5.5
92.8
0.9
363.5
228.1
10095.8
603.7
1871.6
845.2
"Streams may not balance due to roundoff
159
-------
6.3.3. Control Equipment Specification and Cost Estimation
The main environmental discharge from the hydrogenation
module is flue gas from the preheater. This amounts to
approximately 14,758 TPD (13416 Mg/day) for a fuel gas
usage of 760 TPD (691 Mg/day). No controls are applied
to this waste stream prior to discharge since it contains
only nitrogen, oxygen, carbon dioxide, and water.
Hydrocarbon vapors from pressure release valves will be
generated and will be routed to a flare system (See Flare
system). Accidental material spills generated from such
operations as reactor cleanouts can be prevented by fol-
lowing the practices outlined in Section 5.9.2.
6.4 Phase (Gas) Separation Module
6.4.1 Module Description
The phase (gas) separation module separates hydrocarbon
vapors and other gaseous products from the dissolver effluent
slurry stream and directs the solids/liquid portion of the
coal slurry to other processing areas. There are five
processes within this module: high pressure separation,
condensate separation, intermediate flashing, intermediate
pressure condensate separation, and low pressure condensate
separation. A module flow diagram is shown in Figure 26.
The processed coal/solvent slurry from the dissolver is
first introduced into a high pressure separator where the
hot vapor is separated from the slurry under dissolver
outlet pressure (i.e., 1650 to 1700 psig [11.4-11.7 MPaJ).
The temperature is maintained at about 550°F (292°C) . Since
the influent slurry is usually around 850°F (454°C), an air
cooled heat exchanger may be used ahead of the separator to
aid in reducing the slurry temperature. The separated gases
are then directed through a water cooled condenser to a high
pressure condensate separation vessel along with hydrogen
sulfide, nitrogen, ammonia, carbon monoxide and carbon
dioxide. The uncondensed vapors are sent to gas purifi-
cation and the condensate is directed to a low pressure
condensate separator. The remaining solid/liquid slurry
from the high pressure separator is directed to an inter-
mediate flash vessel (36).
160
-------
HIGH PRESSURE
SEPARATOR
AIR COOLED
HEAT EXCHANGER
DISSOLVER
EFFLUENT
V
WATER
COOLED
CONDENSER
GAS
PURIFICATION
MODULE
VAPOR
VAPORS f*
CTi
SOLID/LIQUID
SLURRY
COAL
PREPARATION
MODULE
INTERMEDIATE PRESSURE
FLASH SEPARATOR
SOLID/LIQUID
SLURRY
HIGH PRESSURE
CONDENSATE
SEPARATOR
VAPORS
CONDENSATE
WATER
COOLED
CONDENSER
SOLID/LIQUID
SEPARATION
MODULE
VAPORS
WATER
COOLED
HEAT
EXCHANGER
LIQUID
(HEAVY
HYDROCARBONS)
INTERMEDIATE PRESSURE
CONDENSATE SEPARATOR
LIQUID
(LIGHT HYDRO-
CARBONS)
FRACTIONATION
MODULE
LOW PRESSURE
CONDENSATE
SEPARATORS
WATER
TO
PHENOL
RECOVERY
Figure 26. Phase (Gas) Separation Module
-------
The solids/liquid slurry from the high pressure flash
separator enters an intermediate flashing vessel where the
pressure is decreased to approximately 500 psig (3.4 M£a;
under a constant temperature of 550°F (292°C) (36) The
reduced pressure vaporizes numerous hydrocarbons which are
discharged to the intermediate pressure condensate separator.
The remaining slurry consisting mostly of original_solvent,
dissolved coal, and undissolved coal solids is split into
two streams. The majority of the slurry flow (40,000 TPD
[36,363 Mg/dayj) is recycled back to the coal preparation
module. The remaining slurry is routed to the solids separa-
tion module.
The vapors from the intermediate pressure flash separa-
tor are directed through a water cooled condenser prior to
entering the intermediate pressure condensate separator.
Heavier-than-water hydrocarbons are separated from water and
lighter hydrocarbons and routed to the fractionation module.
Uncondensed gases are directed to the gas purification
module. The water and light hydrocarbon stream is combined
with the vapor stream from the filter feed flash unit
(solids separation module) and gas-liquid stream flows
through another condenser. The condensed mixture is charged
to a low pressure condensate separator in which the hydro-
carbon, water, and gaseous phases are separated. The light
hydrocarbons are routed to the fractionation module. Sour
water is directed to by-product recovery processes. The
uncondensable gases flow to the gas purification module for
the removal of hydrogen sulfide and carbon dioxide.
6.4.2 Process and Waste Streams
Three continuous process streams are discharged from
the phase gas separation area: product slurry to filtra-
tion, condensate to fractionation, and acid gas to gas
purification. Sour water is a by-product stream which is
directed to ammonia and phenol recovery.
Since the phase gas separation module is operated as a
closed system, there are no waste streams discharged on a
regular basis. Two potential sources of material discharge
from this module are fugitive vapor discharge and discharge
from accidental spills. A flow diagram depicting process
streams and potential waste streams is given in Figure 27
Stream compositions are listed in Table 45
162
-------
(-©
G>
PHASE (GAS)
SEPARATION
-------
TABLE 45. PHASE (GAS) SEPARATION MODULE STREAM COMPOSITIONS
STREAM
2 Flash Gas
H2S
H2
CO
co2
H2°
NH3
Hydrocarbons
4 Gases to Purification
H2
H2S
H2
H20
NH3
CO
co2
Hydrocarbons
6 Sour Water
H2°
Phenol
NH3
H2S
QUANTITY*
TPD
11.1
45.8
63.7
9.6
1.0
7.5
898.0
568.7
424.1
18.5
40.0
0.2
397.3
288.8
3545.9
3306.6
37.8
59.8
44.9
(Mg/day)
10.1
41.6
57.9
8.7
0.9
6.8
816.4
517.0
385.5
16.8
36.4
0.2
361.2
262.5
3223.5
3006.0
34.4
54.4
40.8
"Streams may not balance due to roundoff.
164
-------
6.4.3 Control Equipment Specification and Cost Estimation
Two potential intermittent discharges from the phase
(gas) separation module are vapor release due to pressure
build-up or emergency operating conditions, and accidental
material spills. These discharges are attenuated by proper
flaring and by following proper maintenance and spill con-
tingency procedures, as outlined in section 5.9.2. Flare
system specification and cost information is given in sec-
tion 6.14.
6.5 Solids Separation Module
6.5.1 Module Description
The slurry product stream from the phase (gas) separ-
ation module consists of the dissolved coal solution, light
hydrocarbons, and undissolved solids. Undissolved solids
consist mainly of unreacted coal, char, and mineral matter.
The slurry may also contain some dissolved H2S. The solids
separation module separates the undissolved solids from the
dissolved coal solution. The position of this step in the
overall system varies somewhat, according to what design is
used. The original Parson's design has solids separation
before the fractionation module (23). The SRC II pilot
plant design incorporates solids separation by vacuum flash-
ing after fractionation (37). The latest SRC design by
Ralph M. Parsons Company also has the solids separation step
following fractionation (38). This report was based on the
original Parsons' design and therefore has the solids separ-
ation module before fractionation. In future revisions of
this report, the solids separation module will be described
as following fractionation, if this arrangement is found to
be satisfactory. The environmental discharges resulting
from both system arrangements are expected to be similar.
Besides alternate system arrangements, a number of
alternatives are available for the solids separation itself,
e.g, rotary precoat filtration, vacuum flashing, centrifug-
ation, and solvent de-ashing. Studies have indicated that
efficient separation is difficult, due to the size distri-
bution of suspended particles (1-300 microns) and the high
viscosity of the dissolved coal solution (39).
165
-------
Although rotary precoat filtration has been used some-
what successfully in SRC production, it is considered
expensive and has frequent scheduled downtime. Centrifugation
of the slurry has had limited success. Vacuum flashing
has been used successfully in the SRC-II process. The sol-
vent de-ashing technique has been under bench-scale investi-
gation for some time; however, no pilot plant scale data are
available in the literature.
Data from rotary precoat filters have been used in the
material balance, since material balances have been obtained
only from design studies using this separation technique.
Material balances will be somewhat similar when using other
solids separation methods.
A flow diagram of a hypothetical solids/liquid separ-
ation module is shown in Figure 28. In the process, the
hydrogenated coal slurry from phase (gas) separation is
charged to a feed flash vessel. The vapor released is let
down through a control valve to condensate separation in the
phase (gas) separation module. The liquid effluent from the
feed flash vessel flows to the solids separation unit, i.e.,
a filter, vacuum flash, centrifuge, or solvent de-asher.
The solids stream is sent to a secondary vacuum flash or a
dryer to concentrate the residue, depending on the method of
solids separation. Since vacuum flashing is used in this
design, secondary flashing is required rather than drying.
Recovered solvent is routed to the fractionation module.
Most of the residue stream from the secondary flash is
routed to the solidification module. Any additional re-
covered solvent is combined with the main solvent stream and
routed to fractionation.
6.5.2 Process and Waste Streams
Process and waste streams entering and leaving the
solids separation module are shown in Figure 29. Stream
constituents are quantified in Table 46. There are essen-
tially no wastewater streams in the solids separation area
other than the drainage of accidental spills during main-
tenance operations.
The only continuous atmospheric waste stream is the
flue gases from residue drying. Vapor discharges from pres-
sure relief valves will be routed to flare. Accidental
material spills and fugitive vapors will be attenuated by
following preventative procedures and spill contingency
p J- 3»X1 S •
The liquid residue stream from solids separation is
p?oduct^° solidification module for cooling into a solid
166
-------
SLURRY FROM
PHASE (GAS) SEPARATION
MODULE »
FLASH GAS TO
PHASE (GAS)
SEPARATION
MODULE
FEED FLASHING
-•J
WASH SOLVENT ^-
FROM
FRACTIONATION MODULE
(OPTIONAL)
SOLVENT TO
FRACTIONATION
MODULE
SECONDARY
FLASHING
SOLIDS
SEPARATION
RESIDUE TO
HYDROGEN GENERATION
MODULE
RESIDUE TO DISPOSAL
Figure 28. Process Flow Schematic Solids Separation Module
-------
4.
5.
6.
7.
8.
9.
SOLIDS
SEPARATION
MODULE
INPUTS W (&
1. Slurry from Phase (gas) Separation Module
2. Wash solvent
3. Fuel gas & air mixture
OUTPUTS
Residue to Solidification
Solvent to fractionation module
Flash gas to phase (gas) separation module
Flue gas
Vapor discharge
Accidental Material Spills
QUANTITY*
(TPD) (Mg/day)
13241 12037
NOT QUANTIFIED
10777 9798
5575 5069
6080 5527
1037 943
10777 9798
NOT QUANTIFIABLE
NOT QUANTIFIABLE
*Streams may not balance due to roundoff.
Figure 29. Solids Separation Module Process and Waste Streams
168
-------
TABLE 46. PROCESS AND WASTE STREAM CONSTITUENTS
IN THE SOLIDS SEPARATION MODULE
STREAM
3 Fuel Gas and Air Mixture
Fuel Gas N2
CO
co2
CH,
C2H6
Air
7 Flash Gas to Phase (Gas)
H2S
H2
CO
C02
HC
H2°
NH3
8 Flue Gas
N,
C02
H2°
°2
QUANTITY*
TPD
4.4
74.5
0.7
292.0
183.3
10222.4
Separation
11.1
45.8
63.7
9.6
898.0
1.0
7.5
8110.0
1503.4
679.0
485.0
—
(Mg/day)
4.0
67.7
0.6
265.5
166.6
9293.1
10.1
41.6
57.9
8.7
816.4
0.9
6.8
7372.7
1366.7
617.3
440.9
__ — — — - — •—
Streams may not balance due to roundoff,
169
-------
6.5.3 Control Equipment Specification and Cost Estimation
There is only one continuous waste stream discharged from
the solids separation module, which is flue gas from mineral
drying. There are no controls which must be applied to the
flue gas prior to ultimate disposal since it contains only
nitrogen, oxygen, water, and carbon dioxide.
6.6 Fractionation Module
6.6.1 Module Description
The main functions of the fractionation module are:
(1) to separate the high boiling liquid SRC product from
lower boiling fractions; (2) to combine light streams for
fractionation into light products; and (3) to separate wash
solvent for recycling to the solids separation module.
Separations are accomplished in two unit operations, i.e., a
vacuum flash and an atmospheric distillation.
In the operation, the main solvent stream from the
solids separation module flows through a gas-fired preheater
in which it is heated to a temperature of 800-875°F (427-
467°C) (23). The hot stream is charged to a vacuum flash
drum, in which the lighter fractions (gas) are separated
from the high boiling SRC. The SRC stream is routed to
product storage. The flash gas is condensed and charged to
the light ends fractionation tower. Additional feed streams
to light ends fractionation include the light and heavy oils
from phase (gas) separation. Raw naphtha and fuel oil are
taken off as fractionation products and routed to hydro-
treating. An optional side-stream may be taken off and
recycled to the solids separation module for use as a wash
solvent. A schematic of the fractionation module may be
seen in Figure 30.
6.6.2 Process and Waste Streams
Process and waste steams entering and leaving the
fractionation module are shown in Figure 31. Fuel and flue
gas constituents are quantified in Table 47.
There are two major waste streams emanating from the
fractionation module, i.e. preheater flue gas, and either
steam ejector condensate or vacuum pump emission, depending
on which type of equipment is used for evacuating the flash
vessel. The preheater flue gas will contain carbon dioxide,
carbon monoxide, water, and trace amounts of unreacted
hydrocarbons. Steam ejector condensate and vacuum pump
emissions both contain significant quantities of organics.
Steam ejector condensate flows to wastewater treatment.
Vacuum pump emissions should be flared.
170
-------
MAIN SOLVENT /
STREAM FROM /
SOLIDS SEPAR-
ATION MODULE
•» FLUE GAS
\
FUEL GAS & AIR
LIQUID SRC
LIGHT & HEAVY OILS FROM
PHASE (GAS) SEPARATION MODULE
NAPHTHA TO HYDROTREATING
FUEL OIL TO HYDROTREATING
WASH SOLVENT
TO SOLIDS
SEPARATION MODULE
(OPTIONAL)
Figure 30. Process Flow Schematic Fractionation Module
-------
FRACTIONATION
MODULE
•H7.
INPUTS
1. Main stream from solids separation
2. Light & heavy oils from phase (gas)
separation
3. Fuel gas and air mixture
OUTPUTS
4. Accidental material spills
5. Raw naphtha to hydrotreating
6. Raw fuel oil to hydrotreating
7. Product SRC
8. Wash solvent to solids separation
module
9. Vapor discharge
10. Flue gas from preheater
QUANTITY*
(TPD) (Mg/day)
6080 5527
3454 3140
2291
2083
NOT QUANTIFIABLE
577 525
2877 2615
6080 5527
NOT QUANTIFIED
NOT QUANTIFIED
2291 2083
*Streams may not balance due to roundoff.
Figure 31. Fractionation Module Process and Waste Streams
172
-------
TABLE 47. FUEL GAS AND FLUE GAS CONSTITUENTS
QUANTITY*
STREAM TPD (Mg/day)
Preheater Fuel Gas
CH4 62.1 56.4
C2H6 39.0 35.4
CO 15.9 14.4
C02 0.2 0.1
No 0.9 0.8
Preheater Flue Gas
C02 319.7 290.6
H20 144.4 131.2
02 103.1 93.7
1724.3 1567.5
"Streams may not balance due to roundoff
173
-------
6.6.3 Control Equipment Specification and Cost Estimation
The fractionation module generates one continuous waste
stream, i.e. flue gas from the solvent preheater. The flue
gas is generated from the combustion of product SNG; there-
fore, it is relatively contaminant free. It is vented, un-
treated, to the atmosphere at a rate of 2291 TPD (2083
Mg/day). As with previous modules, vapor discharges from
pressure relief valves will be flared. Material leaks and
accidental spills will be handled by proper maintenance
procedures and spill contingency plans, as outlined in
section 5.9.2.
6.7 Solvent Hydrotreating Module
6.7.1 Module Description
Hydrotreating involves the reaction of raw hydrocarbon
streams with hydrogen to remove contaminants such as organic
sulfur and nitrogen compounds, and to improve combustion
characteristics so that they may meet commercial specifi-
cations. In the operation, organic sulfur and nitrogen
compounds are converted to hydrogen sulfide and ammonia,
which are stripped from the product stream. The hydro-
genation reaction also serves to increase the hydrogen-to-
carbon ratio, which improves the smoking characteristics of
the fuel.
In the flow schematic shown in Figure 32, raw naphtha
and fuel oil streams from the fractionation module are mixed
with synthesis gas from the hydrogen production module (85%
H2 by volume) and pumped through a gas fired preheater into
an initial catalyst guard reactor to permit the deposition
of any remaining carbon on low surface-to-volume pelletized
catalyst in order to prevent plugging of the main hydrotreating
reactor. From the guard reactor, the fuel oil or naphtha
stream is fed into a three section downflow hydrotreating
reactor. Quench hydrogen injection points are spaced along
the length of the reactors at appropriate locations for
temperature control (40). Hydrotreating catalysts, such as
cobalt molybdate are used. Space velocity is typically
between 0.5 and 2 hour-1 (41). y
The gas-liquid product is cooled in a heat exchanger
and fed to a high pressure flash drum where fuel oil or
naphtha, water, and gas separation occurs. Approximately 60
percent of the gas is recycled into the hydro?reate?s while
the remainder is routed to the gas purification module (40).
174
-------
FLUE GAS
RAW FUEL OIL
HYD
30GEN
A
-A ^
V^
PREHEATER
'
f^
V
RAW NAPHTHA-
I FUEL GAS
TO & AIR
PARALLEL
TRAIN
Ul
CATALYTIC
HYDROTREATER
HYDROGEN
GUARD
REACTOR
TO GAS PURIFICATION
MODULE
HEAT
EXCHANGER
FLASH
DRUM
OIL-WATER
SEPARATOR
TO GAS
PURIFICATION
MODULE
STRIPPER
PRODUCT FUEL
OIL TO STORAGE
PRODUCT NAPHTHA
TO STORAGE
WASTEWATER
Figure 32. Process Flow Schematic Hydrotreating Module
-------
About half the separated fuel oil or naphtha is re-_
cycled to the hydrotreaters. The remainder is depressunzed
into a receiving tank where the water fraction is separated
from the solvent. The solvent fraction is pumped into a
stripping tower where hydrogen sulfide and ammonia are taken
off the top (40). The gas product of the stripper is sent
to gas cleanup. Product fuel oil and naphtha streams are
routed to product storage facilities.
Water formed by the hydrotreating reaction is separated
from the hydrocarbon phase in the decanter. The^water may
contain substantial amounts of ammonia and organics. ^This
wastewater is routed to the ammonia stripping column in the
by-product recovery module. Any remaining hydrogen sulfide
or ammonia in the main product stream is stripped and the
off-gas is routed to gas purification.
6.7.2 Process And Waste Streams
Process and waste streams entering and leaving the
hydrotreating module are shown in Figure 33. Constituents
in specific process and waste streams are shown in Table 48.
Several atmospheric, aqueous and solid wastes emanate from
the hydrotreating module. Flue gas from the preheater is
expected to contain carbon dioxide, water, and trace amounts
of carbon monoxide and unreacted hydrocarbons.
A solid waste stream consisting of carbon deposited on
spent catalyst packing will be generated from the guard
reactor. It may be possible to recover the carbon or re-
generate the catalyst; however, the feasibility has not been
explored.
A spent catalyst stream also is generated from the main
catalytic hydrotreater as are non-condensible gases; these
are routed to the gas purification module to remove water,
hydrocarbons, hydrogen sulfide, and ammonia.
6.7.3 Control Equipment Specification and Cost Estimation
The solvent hydrotreating module has two continuous
waste streams, flue gas from the solvent preheater and
wastewater from an oil-water decant drum. Flue gas is
vented to the atmosphere at the rate of 1697 TPD (1543
Mg/day). The decanter wastewater is combined with other
wastewater streams and flows to the wastewater treatment
facility, which is described later in this section.
Hydrocarbon vapors and material spills will be gener-
ated on an intermittent basis. There will be two inter-
mittent solid waste streams emanating from the guard reactor
and the main hydrotreater. They will be composed of spent
catalyst and carbon residue. Disposal alternatives for
these solid wastes can be found in Chapter 5.
176
-------
HYDROTREATING
MODULE
INPUTS
-Kio)
1. Synthesis feed gas
2. Raw naphtha
3. Raw fuel oil
4. Fuel gas & air to preheaters
5. Water
OUTPUTS
6. Carbon residue and spent catalyst from guard
reactors
7. Spend catalyst from mine hydrotreating
8. Decanter wastewater
9. Accidental material spills
10. Product fuel oil to storage
11. Product naphtha to storage
12. Flash gas and stripper gas to gas purification
13. Flue gas from preheater
14. Vapor discharge
QUANTITY*
(TPD) (Mq/day)
297 270
577
2877
1697
853
525
2615
1543
NOT QUANTIFIED
NOT QUANTIFIED
874 795
NOT QUANTIFIABLE
2850 2591
570 518
310 282
1697 1543
NOT QUANTIFIABLE
*Streams may not balance due to roundoff.
Figure 33. Hydrotreating Module Process and Waste Streams
177
-------
TABLE 48. PROCESS AND WASTE STREAM
CONSTITUENTS IN THE HYDROTREATING MODULE
QUANTITY*
(TPD)
4.
Synthesis feed gas from
hydrogen production module
H2
CO
C02
Fuel gas and air mixture
Fuel gas
CH4
CO
C02
N2
Air
130.0
130.0
29.5
7.2
0.1
46 . 0
28-9
11.7
0.1
0.7
1609.8
(Mg/day)
118.2
118.2
26.8
6.5
0.1
41.8
26.3
10.6
0.1
0.6
1463.4
8.
12.
Decanter wastewater
H20
H2S
NH3
Flash gas and stripper gas
to gas purification
853.0
10.0
11.0
*Streams may not balance due to roundoff,
178
775.5
9.1
10.0
H2
CO
H20
hydrocarbons
N2
H2S
13. Flue gas from preheaters
C02
H20
N2
02
28.0
36.6
6.0
232.0
7.2
trace
236.8
106.9
1277.1
76.4
25.5
33.3
5.5
210.9
6.5
215.3
97.2
1161.0
69.4
-------
6.8 Solidification Module
6.8.1 Module Description
The function of the solidification module is to cool
the liquid residue stream into solid product suitable for
gasification. There are a number of different solidifica-
tion units available, the most promising being the metal
belt, rotating drum, and rotating shelf types (42). The
solidification process involves feeding the liquid stream
onto a moving heat transfer surface. The surface may be in
the form of a metal belt, drum, pan, or shelf. Cooling
water is sprayed on the other side of the heat transfer
surface to initiate cooling. Additional cooling may be
provided by passing refrigerated air over the product stream
(42) . The cooled solid residue is scraped off the heat
transfer surface with a knife and is transferred to gasifi-
cation and/or disposal by screw conveyor.
Figure 34 shows schematics of two types of solidifica-
tion units.
6.8.2 Process and Waste Streams
Process and waste streams entering and leaving the
solidification module are shown in Figure 35. A large
portion of the solid residue must be routed to disposal,
which substantiates a significant environmental discharge.
Alternates for recovery and disposal for the residue stream
are given in the next section.
The only other waste stream in the solidification
module consists of particulates and hydrocarbon gases va-
porized from the SRC during cooling.
6.8.3 Control Specification and Cost Estimation
Approximately 4075 TPD (3705 Mg/day) of residue,
containing significant quantities of polynuclear aromatics,
unreacted coal, and mineral-matter, must be disposed of or
utilized in the plant. Considering the large quantity of
carbon which would be lost if the residue were landfilled
directly, it is more feasible to gasify the remaining resi-
due to produce low-grade fuel gas which can be utilized as
fuel within the plant. In addition to producing a useful
product, gasification of the residue would also signifi-
cantly reduce the volume of solids which must ultimately be
disposed of in a landfill. Assuming the residue to be
179
-------
LIQUID FEED ON
KNIFE
COOLANT
SCREW CONVEYORTO GASIFICATION
AND/OR DISPOSAL
I. STEEL BELT SOLIDIFICATION
(SANDVIK SYSTEM)
LIQUID
FEED
COOLANT SPRAY
SCREW CONVEYOR
TO GASIFICATION
AND/OR DISPOSAL
II. ROTARY DRUM SOLIDIFICATION
Figure 34. Solidification Units
180
-------
SOLIDIFICATION
MODULE
-K3
-K4
INPUTS
1. Liquid Residue From Solids
Separation Module
OUTPUTS
2. Vapors and Particulates From
Cooling Unit
3. Solid Residue to Gasification
4. Solid Residue to Disposal
TPD
5575
Not Quantified
1500
4075
Mg/DAY
5069
1364
3705
Figure 35.
Process and Waste Streams in the
Solidification Module
181
-------
35 percent ash which will be converted to slag, and the
solids content of the slag is 60 percent, then the volume of
slag with moisture which would require transport to a land-
fill is approximately 2377 TPD (2161 Mg/day). Trans-
portation costs for the disposal of the slag to a landfill
are $1 to $8 per ton C$0.9-7.0/Mg) for distances up to 150
miles (14). The costs, therefore, would range from $2,377
to $19,016 per day.
The only other continuous waste stream consists of the
hydrocarbon fumes and dusts generated during residue solidi-
fication. No data are in the literature to quantify this
stream. However, it is believed to carry a substantial
waste load. Pollution control equipment sizing will depend
partially on flow rate requirements for collection hoods.
Operating data for the Sandvik cooling belt system, one way
of solidifying the residue, are as follows (43):
Maximum belt length = 160 ft (48.8m)
Operating belt speed = 200 ft/min (61.0m/min)
SRC cake thickness = 3/16 inch (0.5 cm)
Contact width of 59"
belt = 55" (139.7 cm)
Using the above operating conditions, it has been cal-
culated that a total of eight cooling belt units are re-
quired, each unit requiring collection hood dimensions of 6
ft x 162 ft (1.8 m x 49.4 m) . The following equation has
been used to calculate design flow rates for low canopy
hoods, as applied to hot processes (39).
Vt- 6.2b4/3 Dt5/12
where*
Vt = design flow rate, cfm
L = length of collection area, ft
b = width of collection area, ft
Dt = temperature difference between hot
product and surrounding air, °F
*Metric conversion factors are given in the Appendix.
In the calculations, an average temperature difference
of 300°F (149.0°C) is assumed, based on an ambient air
temperature of 75°F (23.9°C) and an average product tem-
perature of 375°F (190.5°C) (43). The calculations indicate
a flow rate of 117,942 cfm/ unit (55.8 m3/sec) with a total
182
-------
combined flow rate of 943,536 cfm (443.5 m /sec). It was
not possible to calculate grain loading since losses during
solidification have not been quantified.
Treatment alternatives are similar to the dust control
units selected in the coal preparation module, i.e., cyclone
and baghouse, high efficiency cyclones, or wet scrubbers.
Due to the lack of information on particulate loading,
equipment costs and emissions after treatment could not be
quantified.
6.9 Gas Purification Module
6.9.1 Module Description
The phase (gas) separation module and the hydrotreat ing
module generate gases contaminated with hydrogen sulfide,
ammonia, carbon dioxide, and small amounts of carbon disul-
fide and carbonyl sulfide. The substances are formed from
the hydrogenation of phenols, aromatic amines, and mercap-
tans and sulfides naturally present in the parent coal.
Reaction of the coal polymer and hydrogen yields these con-
taminant gases along with more saturated hydrocarbon mole-
cules (desired product) . Most of the contaminated gases
also contain significant amounts of unreacted hydrogen and
light hydrocarbon fractions. The gas purification module
removes ammonia, hydrogen sulfide, carbon disulfide, carbon
dioxide, and carbonyl sulfide from the gas stream, and
leaves a purified gas which can be separated into hydrogen
for recycle synthetic natural gas, liquid petroleum gas and
light oils.
Figure 36 presents a schematic flow diagram of the gas
purification module. The module consists of a number of
parallel process trains, each train carrying out a similar
function. A representative process train is depicted in
this figure.
Generally, a gas stream entering the module would first
be pumped to the acid gas removal section, consisting of an
amine absorber. The gas stream is passed counter currently
through a 15-20% solution of monoethanolamine (MEA) in the
amine absorption tower (44). Hydrogen sulfide and carbon
dioxide, present along with trace amounts of carbon disulfide
and carbonyl sulfide, form complexes with the MEA, described
by the following reactions:
183
-------
PURIFIED GAS TO
CRYOGENIC SEPARATION
00
OFF-GAS FROM PHASE
(GAS) SEPARATION
MODULE; FUEL OIL
HYDROTREATIiMG AND
NAPHTHA HYDROTREATING
TO
PARALLEL
TRAINS
CQ
CtL
O
oo
CQ
-------
(1) HOCH2CH2NH2 + H2S i^izr HOCH2CH2NH3HS
(2) HOCH2CH2NH2 +
(3) HOCH2CH2NH2 +
(4) HCOH2CH2NH2 + COS - » HOCH2CH2NH2COS
Only reactions (1) and (2) are reversible. The ab-
sorption process is essentially insensitive to the partial
pressures of acid gases. Removal efficiencies have been
estimated to be approximately 99.6 percent for H9S and 88
percent for carbon dioxide (44) .
The MEA absorbent is regenerated by thermal decom-
position at elevated temperatures. Only hydrogen sulfide and
carbon dioxide can be absorbed in this manner, with CS2 and
COS forming nonregenerable compounds with the amine. Off-
gas from the amine regenerator, containing almost all of the
hydrogen sulfide and carbon dioxide, is sent to sulfur
recovery (23) .
The nonregenerable organic complexes are removed by a
purge stream from the reclaimer. Caustic added to the re-
claimer to precipitate metals also forms non-volatile salts
with the amine complexes, which are discharged as blowdown.
Pure MEA is distilled off the reclaimer and recycled to the
regeneration unit (23) . The purified gas flows into the
cryogenic separation unit where it is separated into hydro-
gen for recycle, synthetic natural gas, liquified petroleum
gas, and light oils.
6.9.2. Process and Waste Streams
Process and waste streams entering and leaving the gas
purification module are shown in Figure 37. Stream con-
stituents are quantified in Table 49. The major wastewater
streams are the blowdown from the amine regenerator and the
ammonia scrubber effluent. An intermittent wastewater
stream is backwashed from the amine filter in the acid gas
removal unit. Frequency of backwash will depend on the ± low
rate and solids content of the amine stream. Accidental
spills will also be a source of intermittent wastewater
generation.
185
-------
GAS
PURIFICATION
MODULE
-•m
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
INPUTS
Off-gas from phase (Gas) separation
and hydrotreating
Make-up water to anrine system
Additives to amine system
Steam to amine regenerator
OUTPUTS
QUANTITY*
(TPD) (Mg/day)
5583.0 5080.0
3.0 3.0
0.9 0.8
NOT QUANTIFIED
Acid gas to sulfur recovery 775.0
Purified gas to cryogenic separation module 4812.0
Wastewater from acid gas removal
Filter backwash wastewater
Accidental material spills
Fugitive atmospheric emissions
Vents from storage and sump facilities
705.0
4374.0
6.0 6.0
NOT QUANTIFIED
NOT QUANTIFIABLE
NOT QUANTIFIABLE
NOT QUANTIFIED
*Streams may not balance due to roundoff.
Figure 37. Process and Waste Streams in the
Gas Purification Module
186
-------
TABLE 49. PROCESS AND WASTE STREAM CONSTITUENTS
IN THE GAS PURIFICATION MODULE
QUANTITY*
TPD
1.
Off-gas from Phase (gas)
Separation
H2
H2S
N2
H20
HC
CO
C02
563.7
424.1
18.5
40.0
3545.9
0.2
397.8
288.8
Flash gas from Hydrotreating
H2 28.0
CO 36.6
H20 6.0
HC 232
N2 7.2
H2S trace
4. Additives to Amine System
Monoethanol Amine (MEA) 0.6
Polyrad 1110A 0.003
(Corrosion inhibitor)
Oleyl Alcohol 0.007
(Anti-foam)
Sodium hydroxide 0.3
6. Acid gas to sulfur recovery
(Me/day)
511.9
385.5
16.8
36.4
3223.5
0.2
361.6
25.5
33.3
5.5
210.9
6.5
0.5
0.003
0.007
0.3
H2S
HoO
LL J \J
HC
CO
C02
422.4
11.0
56.0
1.4
284.4
384.0
10.0
50.9
1f\
.3
258.5
Streams may not balance due to roundoff.
187
-------
TABLE 49. PROCESS AND WASTE STREAM CONSTITUENTS
IN THE GAS PURIFICATION MODULE (Continued)
QUANTITY*
TPD (Mg/day)
7. Purified gas to cryogenic
separation module
H2 591.7
N2 25.7
H20 35
HC 3721.9
NH-3 0.2
CO 433.0
C02 4.1
8. Wastewater from acid gas removal
537.9
23.4
3383.5
0.2
393.6
3.7
H20
H2S
C02
MEA
Polyrad 1110A
Oleyl Alcohol
NaOH
3.2
1.7
0.3
0.6
0.003
0.007
0.3
2.9
1.5
0.3
0.5
0.003
0.007
0.3
t
Streams may not balance due to roundoff.
188
-------
Wastewater from the gas purification will contain sub-
stantial amounts of dissolved and suspended hydrocarbons;
monoethanolamine; suspended solids; sodium salts of mono-
ethanolamine and carbon disulfide or carbonyl sulfide com-
pounds, metals, ammonia, and other minor constituents.
Large quantities of caustic, ammonia, and amine will result
in an alkaline wastewater.
Atmospheric emissions will consist of gas leakage from
sumps and storage vents, and fugitive emissions during
maintenance operations. No attempt has been made to quan-
tify specific constituents. All volatile constituents
appearing in Table 12 are potential atmospheric contamin-
ants.
6.9.3 Control Equipment Specification and Cost Estimation
Two wastewater streams are generated in the gas puri-
fication module: blowdown from the amine scrubber (6.0
TPD, or 5.5 Mg/day) , and filter backwash wastewater (not
quantified) . The first stream is routed to the wastewater
treatment plant.
Gaseous emissions include fugitive vapors and vent
gases from storage and sump facilities. These waste streams
should be directed to the flare system for combustion (See
Flare Systems, Section 6.14).
6.10 Cryogenic Separation Module
6.10.1 Module Description
Purified gases entering the cryogenic separation module
are separated into recycle hydrogen ( 99% pure), synthetic
natural gas, liquified petroleum gas, and light oils. A
flow diagram of a theoretical cryogenic separation module is
shown in Figure 38.
Generally, purified gas from the gas purification
module flows to a series of cryogenic separators. The gas
stream is first compressed and condensed in a multistage
refrigeration unit, then charged to a flash tower. The
liquid stream consists of light oils, water, and dissolved
ammonia. The liquid stream is charged to a fractionation
tower where various hydrocarbon streams are taken off as
product. The water and ammonia are removed as a separate
side stream and routed to wastewater treatment. The flash
gas contains lighter hydrocarbons, hydrogen, nitrogen,
carbon dioxide, and carbon monoxide. The flash gas is
compressed and condensed in another multistage refrigeration
unit and is charged to a de-ethanizer column. Liquefied
petroleum gas (propane and butane) is taken off the bottom,
while the overhead gases are charged to another refrig-
eration unit and distillation column (41,44).
189
-------
MULTISTAGE
REFRIGERATION
H2 TO RECYCLE
MULTISTAGE
REFRIGERATION
GASES
FROM
PURIFICATION
MODULE
COMPRESSOR'
LIQUEFIED
PETROLEUM1
GAS i
SYNTHETIC
; NATURAL |
GAS i
LIGHT OIL FRACTIONS
WATER & AMMONIAi
REBOILERi
STEAM l
Figure 38. Cryogenic Separation Module Process Flow Schematic
-------
Pure hydrogen is taken off the top and combined with
hydrogen from gasification for recycle to the hydrogenation
module. Synthetic natural gas consisting mostly of methane,
ethane, and carbon monoxide is taken off as the condensed
stream and used for fuel gas or is sold as product.
The process scheme above is one of several alternatives
for the cryogenic separation module, depending on the desired
end products.
6.10.2 Process and Waste Streams
Process and waste streams entering and leaving the
cryogenic separation module are shown in Figure 39. Com-
positions of input and output streams are given in Table 50.
The only known wastewater stream is the water and ammonia
sidestream from light oil distillation, containing a sub-
stantial amount of phenols and dissolved hydrocarbons. A
conservative estimate of these concentrations are 1 percent
phenols and 0.2 percent hydrocarbons.
6.10.3 Control Equipment Specification and Cost Estimation
The only wastewater stream generated in cryogenic
separation consists of an ammonia-water sidestream from the
light oil distillation (36 TPD or 33 Mg/day). It flows to
the ammonia stripping unit in by-product recovery, so no
control equipment specification is necessary here.
6.11 Hydrogen Production Module
6.11.1 Module Description
Hydrogen is an essential component of the SRC process.
In order to produce liquid fuels from coal, it is necessary
for the hydrogen/carbon ratio by weight in coal to be on the
order of 1:(6-10) (45). Since the hydrogen/carbon ratio in
unprocessed coal is only about 1: (15-20), hydrogen must be
supplied on site either by generation from the gasification
of coal, carbon residues, and/or char or by the recovery of
hydrogen from gases generated during the liquefaction pro-
cess (45). This module involves the production of hydro-
gen from coal and coal products. Figure 40 shows the hydro-
gen production module unit (46).
Four main operations steps employed in the production
of hydrogen from coal are gasification, quenching, shift
conversion, and hydrogen compression. Numerous pollution
control devices are also used to purify the hydrogen gas
stream prior to its distribution to hydrogenation and
hydrotreating operations.
191
-------
CRYOGENIC
SEPARATION
MODULE
INPUTS
1. Purified gas from Gas purification
module
10. Steam
OUTPUTS
2. Fugitive discharge
3. Hydrogen to recycle
4. Synthetic natural gas
5. Liquefied petroleum gas
6. Light oils
7. Wastewater
8. Accidental material spills
9. Steam condensate
-K3.
-K4
QUANTITY*
(TPD) (Mg/day)
4812 4374
NOT QUANTIFIED
NOT QUANTIFIABLE
592
3225
903
57
36
538.
2932
821
52
33
NOT QUANTIFIABLE
NOT QUANTIFIED
*Streams may not balance due to roundoff.
Figure 39. Cryogenic Separation Module Process
and Waste Streams
192
-------
TABLE 50. PROCESS AND WASTE STREAM CONSTITUENTS IN
THE CRYOGENIC SEPARATION MODULE
QUANTITY*
(TPD) (Mg/day)
1.
3.
4.
Purified gas from gas
purification
H2
N9
HoO
HC
NH3
CO
C02
.Hydrogen to recycle
Synthetic natural gas
C9Hfi
No6
GO
C02
5. Liquefied petroleum gas
6.
7.
Light oils
Wastewater
591.7
25.7
35.0
3721.9
0.2
433.0
591.7
1697.0
1065.0
25.7
433.0
4.1
637.8
265.0
56-7
NH3
Hydrocarbons
Phenols
537.9
23.4
31.8
3383.5
0.2
393.6
3.7
537.9
1542.7
968.2
23.4
393.6
3.7
579-8
240.9
51'5
0.07
^
^Streams may not balance due to roundoff
193
-------
STEAM
DRUM
STEAM
COOLING
WATER
COAL &
WASTE
HEAT
BOILER
KOPPERS
TOTZEK
GASIFIER
RESIDUE
OXYGEN!
RECYCLE
WAtER TO
COOLING
TOWER
STEAM
VAPOR LEAKAGE
AMINE
SOLUTION
H2S, C02, AND
TRACE COMPOUNDS
TO STRETFORD PROCESS
PROCESS
KNOCKOUT
DRUM
QUENCH
WATER
— SPILLS
FOUL WATER
TO BYPRODUCT
RECOVERY
STEAM
TO VENTi
SOUR WATER TO
BYPRODUCT !
RECOVERY
DISSOLVER
PREHEATER
AMINE SOLUTION
HYDROTREATING
U- O
SLAG TO i
DISPOSAL1
HYDROGEN i
COMPRESSION:
a;
UJ
CO
AUXILIARY
PROCESSES
WASTEWATER
Figure 40'. Hydrogen Generation'
-------
Mineral residue from the solids /liquid separation area
which contains heavy products, ash, and undissolved coal is
mixed with coal and subsequently introduced into a Koppers
Totzek gasification unit. Oxygen and steam are injected
into the coal/residue mixture prior to entering the gasi-
fier. The gasifier operating conditions are 3330-3500°F
(1815-1927°C) and 14.7 psig (0.1 MPa) (46).
A mixture of hydrogen, carbon monoxide, carbon dioxide
hydrogen sulfide, water, and other trace gases are produced'
in this process. Approximately 50 percent of the slag also
produced in this process is carried along with the product
gas (46) . The remainder drops to the bottom of the gasifier
where it is water quenched. The slag slurry is then sent to
a clarifier where it is concentrated.
Prior to entering a venturi scrubber, the high tem-
perature gasifier product gas produces steam in a waste heat
boiler. Cooling water recirculated from the slag clarifier
is introduced into the scrubber to remove 99+ percent of the
remaining slag from the product gas (46) . This slag slurry
is then mixed with the slag from the gasifier and concen-
trated in a clarifier prior to removal to a landfill.
The gas is then water quenched to remove impurities
such as tar acids, ammonia, hydrogen sulfide, carbon dio-
xide, and slag. The sour water stream is sent to by-product
recovery.
The quench tower effluent process stream is further
processed in a CO shift operation where carbon monoxide
reacts with steam to produce hydrogen and carbon dioxide.
This operation supplements the hydrogen already present in
the product gas stream. Temperatures and pressures in the
shift reactor are expected to range from 645-700°F (340-
371°C) and 140-1400 psig (9.7 MPa) (36). A catalyst is _
needed in this process. Foul water from the shift reaction
is directed to by-product recovery.
An amine scrubbing unit removes both hydrogen sulfide
and carbon dioxide from the clean product gas stream. ^
subsequent CO? scrubbing unit removes most of the remaining
C02. The gases removed from the first unit are sent to a
Stretford sulfur recovery unit while the C02 removed from
the second scrubbing unit is vented to the atmosphere.
The clean product gas is then compressed and distri-
buted to hydrotreating and hydrogenation operations.
195
-------
6.11.12 Process and Waste Streams
Figure 41 shows the hydrogen production module influent
and effluent process and waste streams. Stream compositions
are enumerated in Table 51.
It has been estimated that approximately 2.5 percent
hydrogen by weight per ton of coal is needed to produce
liquid products C23). Usually, 5.0 percent hydrogen^is
supplied to ensure completion of hydrogenation reactions.
For 20,000 tons of processed coal per day (18182 Mg/day),
about 1,000 tons (909 Mg) of hydrogen are needed (23).
The amount of hydrogen which must be generated on-site
to meet the specified hydrogen requirements depends on the
volume of hydrogen recycled to the hydrogenation reactor
from gas purification and the amount of hydrogen required
for hydrotreating operations. The material balance shown in
Figure 41 was based on returning 321 TPD (292 Mg/day)
hydrogen to the hydrogenation reactor and 130 TPD (118 Mg/day)
to hydrotreating. The remaining hydrogen needed in the
hydrogenation reactor is provided by the recycled synthesis
gas from gas purification.
Several water and gaseous waste streams are discharged
during the production of hydrogen including the following:
• Sour water and foul water waste streams are dis-
charged continuously from the hydrogen production
module. These streams may contain ammonia, tar,
and oils with the foul water containing higher
quantities of these constituents. Both of these
streams are directed to the wastewater treatment
facilities at a rate of approximately 883 TPD
(803 Mg/day).
• Sulfur compounds and carbon dioxide are discharged
from an amine scrubbing unit to the Stretford
process at a rate of approximately 6366 TPD (5787
Mg/day) (36). Other impurities such as S02, HCN,
COS, NO, NH3, argon, and ash are also discharged
along with the hydrogen sulfide and carbon dioxide.
They amount to approximately 43 TPD (39 Mg/day).
Purge wastewater streams from these operations are
directed to the wastewater treatment facilities.
• Carbon dioxide is vented to the atmosphere from
the C02 scrubber at a rate of 752 TPD (684 Mg/day).
196
-------
©@®@
J
1) "•**
) >
j
r
, >
HYDROGEN
PRODUCTION
Kz
QUANTITY*
STREAM
1. Residue and Coal
2. Oxygen
3. Steam
4. Water
5. Slag and Water (60% slag)
6. MEA Solution
7. Wastewaters
8. Acid Gas
9. C02 from Scrubber
10. Product Gas
11. Fuel Gas
12. Air
13. Flue Gas
14. Recycle Water to Cooling Towers
*Streams may not balance due to roundoff.
Figure 41. Hydrogen Production Module
(TPD)
3021
2806
4470
738
1692
1
883
6409
752
1031
58
1069
1119
269
(Mg/day)
2753
2551
4064
671 .
1538
0.9
803
5826
684
937
52
965
1017
245
197
-------
TABLE 51. HYDROGEN PRODUCTION MODULE STREAM COMPOSITION
STREAM QUANTITY*
(TPD) (Mg/day)
3. Steam
To gasifier 1,208.0 1,098.2
To shift converter 3,262.0 2,965.4
4. Water
Gasifier 510.0 463.6
Quench tower 225.0 204.5
Acid gas removal (MEA solution) 1.8 1.6
Carbon dioxide removal (MEA
solution) 1.2 1.1
6. MEA Solution
To Acid-Gas Recovery
MEA
NaOH
Polyrad
Alcohol
COS
To C02 Removal
MEA
Polyrad
Alcohol
7 . Wastewaters
Quench operation
Shift
Acid gas (MEA solution)
C02 removal (purge) (MEA
Solution)
8. Acid Gas
H2S
C02
S02
HCN
NO
NH3
Ash
Argon
0.4
0.3
0.002
0.005
0.92
0.3
0.001
0.003
225.2
653.5
3.4
1.4
96.2
6,270.0
0.2
1.5
0.006
0.7
4.4
36.1
0.4
0.3
0.002
0.005
0.3
0.001
0.003
204.7
594.1
3.1
1.3
87.4
5,700.0
0.1
1.4
0.006
0.6
4.0
32.8
-J-
Streams may not balanced due to roundoff.
198
-------
TABLE 51. HYDROGEN PRODUCTION MODULE
STREAM COMPOSITIONS (Continued)
STREAM QUANTITY*
(TPD) (Mg/day)
10 Product gas
Ho 451.0 410.0
CO 451.0 410.0
N2 25.7 23.4
CO? 102.6 93.3
H2S 0.4 0.4
*No" °-5 °-4
CO 7.7 7.0
C09 0.07 0.07
CH? 30.3 27.5
Cz&fi 19.0 17.3
13 Flue Z™ 156.1 141.9
°2 842.0 765.4
50.4 45.8
20 70.5 64.1
14 Water to cooling tower 269.0 244.5
^Streams may not balanced due to roundoff
199
-------
• Flue gas is discharged at a rate of 1128 tons per
day (1025.4 Mg/day) as a result of the operation of
the gasifier.
• Spent catalyst is occasionally discharged from the
shift converter to a regeneration operation.
• Slag, removed from the gasifier and venturi scrub-
bers, is concentrated in a clarifier for disposal
at a rate of 1692 TPD (1538 Mg/day). Water is
recirculated from the clarifier to the venturi
scrubbers at a rate of 6000 TPD (5454.5 Mg/day).
Excess water is returned to the cooling tower
circuit from the clarifier at a rate of 269 TPD
(245 Mg/day).
• Other discharges from the hydrogen production area
include hydrocarbon vapor leakage and spills in
the vicinity of the quench tower.
• Spent MEA solutions from the amine and C02 scrub-
bing units are to be discharged along with the
slag at a rate of 4.0 TPD (3.6 Mg/day) (36).
6.11.3 Control Equipment Specification and Cost Estimation
There are several waste streams discharged to the
environment from the hydrogen production module. Table 52
lists the various waste streams, volumes, and applicable
control measures.
TABLE 52. HYDROGEN PRODUCTION WASTE STREAMS
Waste
of Waste
Control Measure
Carbon dioxide from
scrubber
Flue gas from gasifier
Spent MEA solution
from amine and C02
scrubbing units
Slag from venturi
scrubbers and gasifier
Spent catalyst from
shift conversion
Spills
752.0
684.5
1,128.0 1,025.4
4.0 3.6
1,692.0 1,538.2
not quantifiable
not quantifiable
Vent to atmosphere
Vent to atmosphere
Add to gasifier slag
and dispose of in
landfill
Dispose of in
landfill
Dispose of in
landfill
Dike spill-prone
areas, collect spills
in sump, and return
spills to process or
wastewater treatment
plant _
200
-------
The costs associated with landfilling sludges produced
during hydrogen generation are given in Table 53.
TABLE 53. SLUDGE LANDFILLING (14)
Process
Sludge transport
Landfill costs
Cost
$/ton
$3.00
$8.50
Annual
Total Cost
$
49,338.75
139,793.13
Total 189,131.88
It is anticipated that the spent MEA solutions will be mixed
with the slag sludges prior to landfilling.
In addition to the wastes listed in Table 52, there are
also two wastewater streams amounting to 883 TPD (803 Mg/day)
which are discharged to the wastewater treatment facilities,
and a gaseous waste stream amounting to 7366 TPD (6696 Mg/day)
which is directed to the Stretford process. No control
measures are applied to these streams in route.
Carbon dioxide from the C02 scrubber and flue gas from
the gasifier, totaling 1821 TPD (1655 Mg/day), are vented to
the atmosphere without any controls as they are non-toxic.
Spills and vapor leakage are controlled by dikes and proper
maintenances, respectively. Since these wastes are non-
quantifiable, costs of controls could not be generated.
6.12 Auxiliary Processes Modules
6.12.1 Introduction
In addition to the main process modules previously
discussed, there are numerous auxiliary processes which must
be incorporated into the overall SRC-II system in order to
transform coal into suitable end products. These processes
are used for the recovery of by-products, such as sulfur,
ammonia, and phenol from waste streams, to furnish necessary
utilities such as water, steam, and power, and to furnish
feed materials such as oxygen.
201
-------
6.12.2 Ammonia Recovery
6.12.2.1 Process Description
Ammonia may be recovered from numerous coal lique-
faction operations such as hydrogen production, hydrotreat-
ing, and cryogenic separation. Wastewater streams con-
taining ammonia from each of these operations are directed
to a two-stage ammonia recovery stripping tower system (4) .
A typical ammonia recovery process is shown in Figure 42
(4).
In order to remove ammonia from the combined wastewater
stream, the pH must first be raised to approximately 11.0 by
the addition of calcium oxide. The wastewater then passes
through a clarifier, to remove any excess lime as sludge,
prior to entering the first stripping tower. This sludge is
recycled through a lime recovery unit to the lime slaker
hopper.
In the first stripping tower, the ammonia wastewater
stream flows downward through a packing media where it con-
tacts counter-currently with air. This air stream removes a
significant portion of the ammonia from the wastewater.
A second tower is used further to increase the quantity
of ammonia recovered from the wastewater. Upwards of 90
percent ammonia removal may be expected with this system
(4).
6.12.2.2 Process and Waste Streams
Process and waste streams are shown in Figure 43.
Stream compositions are given in Table 54. Effluent waste-
water from the stripping towers is the only waste stream
discharged from the ammonia recovery process. The gaseous
ammonia product discharged from the towers is directed to
by-product storage.
6.12.2.3 Control Equipment Specification and Cost Estimation
Effluent wastewaters from the ammonia recovery process
are directed to the wastewater treatment facilities; con-
sequently, there are rio pollution control measures which
must be implemented here.
202
-------
AMMONIA RECOVERY
O
LO
WASTEWATER
CaO ;
SLAKER
RAPID
MIX
CLARIFIER
TANK
LIME
SLUDGE
LIME
RECOVERY
STRIPPER
AIR, NH3 tAIR, NH3
AIR
NH3
STRIPPER
WASTEWATER
TO TREATMENT
PLANT
AIR
Figure 42. Ammonia Recovery
-------
AMMONIA
RECOVERY
1. Wastewater
2. Calcium hydroxide solution
3. Air
4. Ammonia stream
5. Wastewater
QUANTITY*
(TPD) (Mg/day)
4279
8
16264
16335
4217
3890
7
14786
14850
3833
*Streams may not balance due to roundoff.
Figure 43. Ammonia Recovery Process and Waste Streams
204
-------
TABLE 54. AMMONIA STRIPPING STREAM COMPOSITIONS
Stream Quantity*
(TPD) (Mg/day)
1. Wastewater
Water 4,194.6 3,813.3
H2S .54.9 49.9
NH3 71.0 64.5
HC 2.42.2
Phenol 0.8 0.7
4. Ammonia Stream
Air 16,264.5 14,785.9
NH3 70.3 63.9
5. Wastewater
Water 4,201.5 3,819.5
NH3 0.7 0.6
H?S 54.9 49.9
HC 2.4 2.2
Phenol 0.8 0.7
Ca(OH)2 1-4 1-3
^Streams may not balance due to roundoff
205
-------
6.12.3 Phenol Recovery
6.12.3.1 Process Description
One of the most common methods used for recovering
phenol is solvent extraction. It is proposed to use product
naphtha to recover phenol in the by-product recovery area.
Approximately 99 percent of the phenol is expected to be
removed (7). A typical phenol recovery auxiliary process is
shown in Figure 44 (7) .
The pH of the phenolic water from phase (gas) separ-
ation is first adjusted to about 4.0 by the addition of
hydrochloric acid. The acidic wastewater is then directed
through a series of vessels where it contacts naphtha sol-
vent. The naphtha solvent and wastewater streams pass
counter-currently through the vessels so that the most con-
centrated solvent stream is contacted by the most concen-
trated phenolic wastewater stream. The amount of phenol
which can be removed is dependent upon the number of vessels
and the ratio of phenol to solvent flow. Economic con-
siderations determine the number of vessels and solvent flow
rate to be used. Since economic analyses are not considered
here, it was assumed that the solvent flow rate would be
equal to the phenolic wastewater flow rate and that an
unspecified number of vessels would be required to remove 99
percent of the phenol. The effluent from the extraction
process is directed to the wastewater treatment facilities.
In addition to extracting phenols, the solvent also
extracts other hydrocarbons from the wastewater. In the
process of extracting hydrocarbons, however, a small portion
of the naphtha is partitioned into the wastewater, since it
is slightly soluble in water.
The phenol/solvent stream is sent to a fractionation
tower where the phenol is separated from the solvent. The
solvent is recycled back to the extraction process, and the
phenol is directed to by-product storage.
6.12.3.2 Process and Waste Streams
Process and waste streams are shown in Figure 45
Stream compositions are given in Table 55. Effluent waste-
water from the extraction towers is the only waste stream
discharged from the phenol recovery process. Recovered
phenol is directed to by-product storage
206
-------
HASTEWATER FROM PHASE (GAS) SEPARATION
HCL
MIXING
TANK
t"O
o
o
< c£.
ClL LU
X O
tu i—
o
CO
z: LU
LU CE:
:c i—
Q. t/)
WASTEWATER
TO TREATMENT
PLANT
o
I-H
I—
O
RECYCLE
SOLVENT
SOLVENT
PHENOL TO
BYPRODUCT
STORAGE
*There are a number of towers in series
Figure 44. Phenol Recovery
-------
0
PHENOL RECOVERY
•*(6
STREAM
1. Wastewater from phase (gas) separation
2. Solvent - Naphtha
3. HC1 solution
4. Phenols
5. Wastewater
6. Naphtha
QUANTITY*
(TPD)
3449
2447
34
37
3414
2445
(Mg/day
3136
2225
31
34
3104
2222
*Streams may not balance due to roundoff.
Figure 45. Phenol Recovery Process and Waste Streams
208
-------
TABLE 55. PHENOL RECOVERY STREAM COMPOSITIONS
Stream Quantity*
(TPD) (Mg/day)
1. Wastewater from phase (gas) separation
Phenol 37.8 34.4
Water 3,306.6 3,006.0
NH3 59.8 54.4
H2S 44.9 40.8
5. Wastewater
Water 3,306.6 3,006.0
Phenol 0.4 0.4
H2S 44.9 40.8
up 2.4 2.2
SL 59.8 54.4
*Streams may not balance due to roundoff.
209
-------
6.12.3.3 Control Equipment Specification and Cost Estimation
Effluent wastewaters from the phenol recovery process
are directed to the wastewater treatment facilities; con-
sequently, there are no pollution control measures which
must be implemented here.
6.12.4. Sulfur Recovery
6.12.4.1 Process Description
Acid gas from the gas purification module contains
approximately nine percent by volume hydrogen sulfide. It
is feasible to convert the hydrogen sulfide gas to elemental
sulfur, using the Stretford sulfur recovery auxiliary pro-
cess.
The Stretford process is applicable to gases with a
H2S content no greater than 15 percent. Concentrations as
low as 5-10 ppm H2S can be achieved for industrial gases,
using the Stretford process in combination with the high
temperature hydrolysis recovery system (47).
In the process shown in Figure 46, feed gas passes
through a packed absorber where H2S is absorbed in the
Stretford solution. The solution consists mainly of sodium
metavanadate, sodium anthraquinone disulfonate (ADA), sodium
carbonate, and sodium bicarbonate in water. The absorbed
H2S is oxidized to elemental sulfur by the reduction of
sodium metavanadate. The reduced vanadium compound is in
turn oxidized by anthraquinone disulfonate. The ADA is
regenerated by air oxidation in an oxidizer tank. Sulfur is
floated to the surface as a froth and can be processed by
either filtration or centrifugation. Filtrate and wash
waters from sulfur separation are returned to the absorption
unit.
About 400 percent excess air is used to facilitate
oxidation and flotation. The overall process reaction is
described below (47):
H2S + 1/2 02 * S + H20
210
-------
TREATED TAIL GAS
FEED GAS
ABSORBER,
Y
REAGENT SALTS
TO RECYCLE
FUEL GAS
AIR
WATER
HYDROLIZER
SURGE
TANK
EVAPORATOR
OXIDIZER VENT
OXIDIZER
SETTLING
TANK
AIR
PRECONCENTRATOR
SOLIDS
SEPARATION
SULFUR
FILTRATE
Figure 46. Stretford Sulfur Recovery With High Temperature Hydrolysis
-------
A properly designed Stretford absorber and oxidizing
tank will lose about 1 percent of its sulfur production to
sodium thiosulfate formation, as shown by the following
overall reaction (47):
2 H2S + 2 Na2C03 + 202 »• Na2S203 + 2 NaHC03 + H20
Hydrogen cyanide present in the feed gas will be com-
pletely converted to sodium thiocyanate in the following man-
ner:
+ NaHC03
+ NaOH
HL.IN -t- lNa2OU0 •
MnfM 1 MnTTC1 -L 1 / 9 f"l
iNaLN T jNario T ii z L»2
MiiTTrTl -L. IST-intT
^ iNaoiN
^ MnPMq
Sulfur dioxide present in the feed gas will be con-
verted to sodium sulfite in the absorber and oxidized to
thiosulfate form in the oxidizer, as follows:
2 Na2C03 + S02 + H20 - ^ Na2S03 + 2 NaHC03
1/20
Continuous purging of the Stretford solution stream
prevents the build-up of sodium thiocynate and sodium thio-
sulfate to the crystallization point. The purge stream has
a total salt content of 20-25 percent (47) .
The Stretford solution purge stream is decomposed by a
high temperature hydrolysis technique, in which vanadium is
recovered in solid form, along with sodium carbonate and
some sodium sulfide and sulfate. Hydrogen cyanide is com-
pletely converted to C02, H20, and nitrogen, while sodium
thiosulfate is converted to H2S and water.
In the process, the liquid is first concentrated in an
evaporator. The concentrated solution is fed to a cocur-
rent, high temperature hydrolyzer, where the solution is
evaporated to dryness and decomposed in a high temperature
reducing atmosphere. The reducing atmosphere is produced by
the stoichiometric combustion of fuel. Gases leaving the
process are cycloned to remove recyclable solids and are fed
to the Stretford absorber. The solids containing vanadium
and sodium are dissolved and recycled to the Stretford
plant.
The nitrogen and water formed during the hydrolysis
step are recycled along with the gas stream through the
absorber and are eventually vented to the atmosphere in the
tail gas.
212
-------
6.12.4.2 Process and Waste Streams
Process and waste streams entering or leaving the
Stretford unit are shown in Figure 47. Stream compositions
are shown in Table 56. The Stretford process, when coupled
with high temperature hydrolysis recovery, yields one major
waste stream, i.e. the off-gas from the absorber. This off-
gas will contain mostly water, carbon dioxide, oxygen, and
nitrogen with trace amounts of hydrogen sulfide, carbon
monoxide, ammonia, and NOX. The oxidizer vent gas is the
only other emission from the unit; it consists of air and
water vapor.
6.12.4.3 Control Equipment Specification and Cost Estimation
The Stretford sulfur recovery unit generates a large
gaseous waste stream (1,2172 TPD or 1,1065 Mg/day) con-
taining light hydrocarbons, hydrogen sulfide, carbon monox-
ide, nitrogen oxides, and ammonia. Concentrations of gaseous
components can be found in Table 57. The major pollutant in
the Stretford tail gas consists of the light hydrocarbon
component, which is present at a concentration of 5,536 ppm
by volume. Illinois standards for petrochemical plants
require that hydrocarbon concentrations are less than 100
ppm; therefore, some form of hydrocarbon removal is re-
quired. Concentrations of H2S (10.2 ppm) and carbon monox-
ide (143 ppm) are compatible with existing New Mexico stand-
ards for H2S emissions from coal gasification plants (10
ppm) and below Illinois regulations for petrochemical plants
(200 ppm), respectively. Nitrous oxides and ammonia are
present in significant concentrations and may require pollu-
tion control technology.
Feasible alternatives for hydrocarbon control include
direct flame incineration and carbon adsorption systems._
Condensation systems are only used when vapor concentrations
are high, and are therefore not applicable for Stretford
tail gas treatment. As mentioned earlier, catalytic in-
cineration is not believed to have an adequate hydrocarbon
removal efficiency.
Table 58 presents cost data, removal efficiencies,
emissions, and secondary wastes for direct flame incinera-
tion and carbon adsorption systems. It is apparent that
carbon adsorption does not meet the Illinois standards for
hydrocarbon emissions, and can no longer be considered a
feasible treatment alternative.
213
-------
SULFUR RECOVERY
STRETFORD PROCESS
STREAM
1 Gas from gas purification
2 Gas from hydrogen production
3 Water
4 Air (for oxidation)
5 Fuel gas
6 Air with fuel gas
7 Effluent gas
8 Sulfur
9 Flue gas
QUANTITY*
(TPD) (Mg/day)
775
6503"
81
53040
"9"
169
12077"
488"
169"
705
5912"
74
4822
154
10979
444
154
*Streams may not balance due to roundoff
Figure 47. Process and Waste Streams In The
Sulfur Recovery System
214
-------
TABLE 56. SULFUR RECOVERY STREAM COMPOSITIONS
Stream
Quantity*
(TPD) (MR/day)
1. Gas from Gas Purification
H2S
H20
HC
CO
C02
422.4
11.0
56.0
1.4
284.4
384.0
10.0
50.9
1.3
258.5
Gas from Hydrogen Production
H2S
C02
HCN
S02
NO
NH3
Ash
Argon
96.2
6,270.0
1.5
0.2
0.006
0.7
4.4
6.1
87.5
700.0
1.4
0.2
0.006
0.7
4.0
Fuel Gas and Air
Fuel Gas
N2
CO
C02
CH4
Air
0.07
1.2
0.01
4.6
2.9
160.3
0.07
1.0
0.01
4.2
2.6
145.7
Effluent Gas
H2S
HC
CO
C02
N2
02
NO
H20
Ar
0.1
56.0
1.4
6,556.8
4,085.1
974.1
0.006
0.7
366.9
36.1
0.1
50.9
1.3
5,960.0
3,713.7
885.5
0.006
0
333
,7
,5
32.8
215
-------
TABLE 56. SULFUR RECOVERY STREAM COMPOSITIONS
(Continued)
Stream Quantity*
(TPD) (Mg/day)
9. Flue Gas
Ash
N2
C02
02
H20
4.4
127.1
23.6
7.7
10.6
4.0
115.5
21.5
7.0
9.6
^Streams may not balance due to roundoff.
216
-------
TABLE 57. COMPONENTS IN STKETFORD TAIL GAS
COMPONENT g-moles/day Concentration
N£ 1.32 x 108 41.9%
C02 1.35 x 108 42.7%
02 2.76 x 107 8.7%
H20 1.85 x 107 5.8%
Hydrocarbons (as ethane) 1.75 x 10 5,536 ppm
Argon
8.20 x 105 3,000 ppm
NH 3.54 x 104 112 ppm
4.54 x 104 143 ppm
CO
H s 3.27 x 103 10 ppm
NO (as NO) 1.82 x 102 0.6 ppm
X
217
-------
TABLE 58. HYDROCARBON TREATMENT ALTERNATIVES FOR STRETFORD TAIL GAS (48,49)
Basis: 173,900 scfm (82.1 m3/sec)
hydrocarbon cone. = 5,536 ppm (as ethane)
t-0
M
00
Cost
Treatment Capital Operating
($1000) (Annual)
($1000)
Direct-Flame 572 4,083
Incineration
Carbon 1,843 3,546
Adsorption
with
Incineration
(AdSox)
Emission
After
Efficiency Treatment (98%)
98+% H2S 0.2 ppm
S02 17.7 ppm
HG 79.0 ppm
NO 96.6 ppm
CO 2.5 ppm
C02 43.6 %
NH3 2.0 ppm
up to 99% H2S =9.5 ppm
*HC =278 ppm
C02 =42.9 ppm
CO =12.7 ppm
NO =0.6 ppm
NH3 = 111 ppm
Secondary
Waste
Water and carb<
dioxide from cc
bust ion.
Water and carbc
dioxide from ir
cineration
"Exceeds Illinois Standard
-------
6.12.5 Oxygen Generation
6.12.5.1 Process Description
The hydrogen production process used in a SRC plant to
produce make-up hydrogen for the hydrogenation reactors, re-
quires large quantities of oxygen which must be produced on
site. A cryogenic air separation system, consisting of air
compression, cooling, and purification, air separation by
distillation, and oxygen compression, is normally used to
produce the required volume of oxygen. Figure 48 depicts a
conventional air separation system (50).
In a conventional cryogenic air separation system, air
is introduced into a four stage compression chamber which
compresses the air to approximately 2940 psig (20.3 MPa)
(50). The gas is cooled between each compression stage and
condensed water is removed. The compressed gas passes
through a water quench tower and reversible heat exchanger
where the gas is cooled and contaminants are deposited
within the exchanger. The gas is then further cooled to
about -30°C by ammonia refrigeration (50). The cooled gas
enters the combined liquefier-distillation chamber where the
temperature is decreased to -191°C and the liquid oxygen and
nitrogen separated (50). The products are returned to the
heat exchanger. Nitrogen is discharged as a waste product
along with trace contaminants such as C02, argon, xenon,
radon, krypton, oxygen, and water. The purified oxygen is
compressed, cooled, and forwarded to the gasifiers.
Studies have indicated that about 1,5 tons (1.4 Mg) of
oxygen must be provided per ton of carbon and hydrogen pro-
cessed in the gasifiers (30). Based on this factor and
3,000,tons per day (2727 Mg) of coal and residue con-
taining 61 percent carbon and hydrogen, approximately
2,745 tons (2,495 Mg) of oxygen must be separated per
day.
6.12.5.2 Process and Waste Streams
Influent and effluent process and waste streams are
shown in Figure 49. Stream constituents are given in Table
59.
Only one waste stream, containing mostly nitrogen,
is discharged as a result of oxygen production processes.
Based on an oxygen demand of 2,745 TPD (2495 Mg/day),
this waste stream amounts to approximately 9,997 TPD
(9,088 Mg/day).
219
-------
to
to
o
AIR FILTER
FOUR-STAGE AIR COMPRESSION AND COOLING
AIR
CONDENSATE
TO COOLING
TOWER
D
COOLING
1
I COOLING
WATER
h
u
r~ - —
COOLI
NG
I 1
JPOOLINGl
T WATER 1
h
u
cooLir
X
\s
4G
1 1
ICOOLINGII
* WATER '
(DOUBLE-COLUMN
RECTIFIER)
A
CONDENSATE
WATER WASTE
o
I — I
•=c
UJ
V / "^ / _^k '
-------
OXYGEN
STREAM
1. Air (50% humidity, 60°F)
2. Cooling water
3. Condensate water
4. Product gas
5. Waste nitrogen itream
6. Cooling water out
-0
•—-,
5
©
QUANTITY*
(TPD) (Mg/day)
12815 11650
16404
12
2806
9997
16404
14913
11
2551
9088
14913
*Streams may not balance due to roundoff.
Figure 49. Oxygen Generation
221
-------
TABLE 59. OXYGEN GENERATION PROCESS AND WASTE STREAMS
Stream Quantity*
(TPD) (Mg/day)
2. Cooling Water
Air Compression Stages 9,004.0 8,185.4
Water Quench Tower 5,424.0 4,930.9
Oxygen Compression Stage 1,976.0 1,796.4
4. Product Gas
Oxygen 2,745.0 2,495.0
Argon 36.1 32.8
Nitrogen 25.2 22.9
3. Waste Nitrogen Stream
Nitrogen
Argon
Carbon Dioxide
Hydrogen
Neon, Xenon, Krypton
Water
Oxygen
9,601.8
129.3
6.4
1.3
6.4
52.06
200.0
8,728.9
117.5
5.8
1.2
5.8 *
47.3
181.8
^Streams may not balance due to roundoff.
222
-------
6.12.5.3 Control Equipment Specification and Cost Estimation
Since the waste nitrogen stream discharged from the
oxygen plant contains only natural components of air, there
are no control measures which must be applied to this stream.
Of the 12,815 tons (11,650 Mg) of air which must be pro-
cessed daily, approximately 9,997 tons per day (9,088
Mg/day) are returned to the environment.
6.12.6 Raw Water Treatment
6.12.6.1 Process Description
A continuous supply of water is needed in the lique-
faction process for makeup water in the cooling towers and
for boiler feedwater softening and demineralization opera-
tions. It is also needed in the waste disposal treatment
facilities and as a general supply of potable, fire, and
domestic water. Water usage is dependent upon the size of
the plant, housekeeping practices, process operations, and
pollution control technologies. A typical raw water treat-
ment process is shown in Figure 50 (24). Characteristics of
raw water taken from the Wabash River are given in Table 60.
Raw water is usually pumped to a treatment plant after
being screened to remove large debris. Chemicals are then
added to the raw water in a rapid mix chamber as aids in
settling out suspended matter and heavy metals in subsequent
flocculation, sedimentation, and filtration unit operations.
Softening agents are also added in the rapid mix chamber.
The water usually drains from the sand filters to a clear
well where it is lifted to a raw water storage tank. Water
is pumped from the storage tank to the cooling towers and
potable water storage area as needed. Chlorination injec-
tion facilities are located on the outlet end of the raw
water storage tank pumps.
6.12.6.2 Process and Waste Streams
Process and waste streams are shown in Figure 51.
Stream constituents are given in Table 61.
The major waste stream discharged from the raw water
treatment facility is sludge removed from the clarifiers.
This sludge contains metal complexes, carbonate compounds,
suspended solids, and other trace compounds which were
present in the raw water.
Sand filter filtrate is expected to be returned to the
clarifier.
223
-------
CHEMICAL f—|
INJECTION I I
SYSTEM
RAW WATER
INTAKE
RAW HATER
PUMP
STATION
CLARIFIER
SOLIDS
SAND FILTER
N5
FILTRATE
COOLING
TOWER
SYSTEM
CHLORINE;
STORAGE
RAW WATER
STORAGE TANK
PUMP
L
SAND FILTER
EFFLUENT
PUMP
STATION
POTABLE
WATER
STORAGE
Figure 50. Raw Water Treatment
-------
TABLE 60. TYPICAL CONSTITUENTS IN WHITE COUNTY, ILLINOIS
RAW WATER SUPPLY
Parameter
Specific Conductance
(umhos)
Temp (°F)
pH (units)
Calcium
Magnesium
Bicarbonate
Carbonate
Sulfate
Chloride
Fluoride
Nitrate
Phosphorous
Dissolved Solids
(Residue at 180°C)
Hardness as CaCOo :
Calcium, Magnesium
Non-Carbonate
Detergent (MBAS)
Suspended Solids
Range (mg/1)
207-794
34-86
68-74
29-94
16-32
110-228
0
36-180
8-42
0.2-0.4
0.6-24
0.21-1.3
201-508
134-350
44-153
0.0-0.1
Ave . (mg / 1 )
535
61
7.6
66.5
24
199
0
83
25
0.3
12.3
0.75
355
242
97
0.1
40
225
-------
RAW WATER
TREATMENT
STREAM
1. Raw Water Input
2. Chemicals
3. Sludge (5% solids)
4. Cooling Tower Water
5. Direct Water Use In Plant
6. Water Used For Steam Production
QUANTITY*
(TPD) (Mg/day)
32,057
35,263
15
407
25,401
4,331
5,145
14
370
23,092
3,937
4,677
*Quantity of water needed in operations (does not include weight of
contaminants present in water).
Figure 51. Raw Water Treatment Process and Waste Streams
226
-------
TABLE 61. RAW WATER TREATMENT STREAM COMPOSITIONS
1.
2.
3.
4.
Stream
Raw water input (avg. cone)
Illinois Area
Specific conductance (umhos)
Temperature (°F)
pH
Ca
Mg
HC03
S04
Cl
Fluoride
N03
P04
Detergent
Suspended solids
Chemicals
Lime
Sludge
Water
CaC03
Mg(OH)2
Ca5(OH)(P04)3
Detergent
Suspended Solids
Cooling Tower Water
Ca
MS
ii&
S04
Cl
Fluoride
N03
P04
Water
Na
Quantity*
(mg/1)
535.0
61.0
7.6
66.5
24.0
199.0
83.0
25.0
0.3
12.3
0.8
0.1
40.0
(TPD) (Mg/day)
7.6 6.9
7.7 7.0
(TPD) (Mg/day)
386.8 351.6
17.6 16.0
1.0 0.9
0.04 0.04
0.0003 0.00003
1.4 1.3
Cmg/1)
12.0
12.2
83.0
f\ C f\
25.0
0.3
12.3
0.08
25,401.3* (23,092.1)
82.6
*Units in TPD as noted
** Streams may not balance due to roundoff.
227
-------
6.12.6.3 Control Equipment Specification and Cost Estimation
The main waste stream discharged from the raw water
treatment facilities is sludge from the clarifiers. Con-
sidering the diluted sludge which is withdrawn from the
clarifiers (approximately 5 percent), it is economically
essential to remove some of the moisture from the sludge
prior to trucking it to a landfill. It may also be eco-
nomically feasible to recover lime from the sludge after it
is dewatered.
Various sludge dewatering methods are discussed in
Chapter 5 under solid waste disposal. It was indicated that
sludge dewatering equipment is capable of reducing the
moisture content of sludges from 95 to 40 percent. An
analysis of sludge dewatering followed by sludge transport
Vs. wet sludge transport is necessary to determine which
method is most cost effective.
Recalcination of lime sludges may prove to be more
effective than dewatering processes, considering the cost of
chemicals and sludge transport. This process not only
recovers valuable chemicals but also reduces the moisture
content of the sludge by a factor of 10, much greater than
the moisture reduction provided by dewatering equipment.
Costs of lime sludge disposal alternatives are given in
Table 62. Alternative II appears to be more cost effective.
6.12.7 Cooling Water System
6.12.7.1 Process Description
Cooling water, an essential component of a coal lique-
faction plant, is continuously needed to cool reactor ves-
sels within the plant and to cool directly various process
streams. Cooling towers maintain a continuous supply of
cooling water. In addition to the basic cooling tower
structure, piping, and other appurtenances, water treatment
facilities are also essential components of the cooling
tower system since the effective operation of towers can
only be maintained by recirculating relatively clean water.
A flow diagram of a typical cooling tower system is shown in
Figure 52 (52).
Cooling water is directed from the cooling tower through
closed piping to plant heat exchangers. Before recirculation
back to the cooling tower, a portion of the cooling water is
directed through a sidestream treatment operation (blowdown)
This ls incorporated into the process to maintain a constant'
228
-------
TABLE 62. LIME SLUDGE DISPOSAL (14,51)
Process
Costs
Capital Operating (Annual)
($1,000) ($1.000)
Alternative I
Lime recalcination
Sludge transport (5.4 TPD)
Sludge landfill (5.4 TPD)
Savings on lime costs
(by recovery based on
lime costs of $40/ton)
Alternative II
Cost of lime ($40/ton)
Thickener (20% solids out)
100 TPD
Centrifuge (60% solids out)
(53.3 TPD)
Sludge transport
Sludge landfill (53.3 TPD)
890 (1977)
60.0
60.9
60.0
108.96 (1967)
5.913 (1977)
11.826 (1977)
110.67 (1977)
110.67 (1977)
Cost of Chemicals N/A
Cost of power N/A
58.4
116.7
N.A. = Not Available
229
-------
DRIFT AND
EVAPORATION
MAKEUP
WATER ;-
RECIRCULATED
BOILER*—
SLOWDOWN
SIDE STREAM
TREATMENT
TREATMENT
FACILITY
DISCHARGE
TO OUTFALL
(SLOWDOWN)
COOLING WATER
COOLING WATER
TO PLANT USE
PLANT
Figure 52. Plant Cooling Water System
-------
level of dissolved solids in the recirculating cooling water
stream. With sidestream treatment, typical blowdown rates
are 3-5 percent of the makeup water rate (52). Sidestream
treatment facilities commonly used are reverse osmosis,
electrodialysis, or ion exchange. The wastewater from the
treatment process is generally discharged to the river. Raw
water is added to the cooling tower influent as makeup water
to replace the water lost by heat dissipation (evaporation)
in the cooling towers, by cooling tower blowdown, and by
leakage. Evaporation represents the most significant source
of cooling water lost in the system.
6.12.7.2 Process and Waste Streams
Process and waste streams are shown in Figure 53.
The main waste stream discharged from the cooling
towers is blowdown containing suspended solids, dissolved
solids, chromium, and other trace metals. This stream is
treated by ion exchange, electrodialysis, or reverse osmosis
and discharged to the receiving stream. Regeneration waste-
waters from this operation are disposed of off-site.
Cooling tower drift and evaporation represent possible
contaminant discharges to the atmosphere. This amounts
to approximately 24,529 TPD (22,299 Mg/day).
6.12.7.3 Control Equipment Specification and Cost Estimation
There are two environmental discharges resulting from
the operation of the cooling towers: drift and evaporation
and blowdown.
No control measures can be undertaken to control drift
and evaporation from the cooling towers except through the
initial design of the towers. The concentration of chemi-
cals which may be discharged with the drift and evaporation
may, however, be controlled by varying the rate of blowdown
and/or by increasing the degree of raw water treatment.
Since the option of increasing raw water quality has not
been included in this report, only the former control method
can be implemented. Cooling tower drift and evaporation
amounts to approximately 24,529 TPD (22,299 Mg/day).
A portion of the circulating cooling water is contin-
uously purged in order to maintain a dissolved solids level
of about 50,000 ppm. The purge stream or blowdown is nor-
mally discharged directly to the river from a cooling tower
side stream treatment system such as ion exchange, reverse
osmosis, or lime softening. Controls are not usually applied
to this discharge. For the model SRC plant, approximately
762 TPD (693 Mg/day) of blowdown is discharged to the
river.
231
-------
COOLING
TOWER
STREAM
1. Makeup water
2. Boiler blowdown
3. Recirculated water
4. Chlorine and chromates
5. Drift and evaporation
6. Cooling water
7. Side stream treatment (Blowdown)
8. Recycle water from slag .clarifier in
hydrogen production
9. Recycle water from treatment plant
10. Water to plant use
QUANTITY*
(TPD) (Mg/day)
25,401 23,092
15 14
1,260,000 1,145,455
NOT QUANTIFIED
24,529 22,299
1,260,000 1,145,455
762 693
269
5,075
5,469
245
4,614
4,972
*Streams may not balance due to roundoff.
Figure 53. Cooling Water Process and Waste Streams
232
-------
6.12.8 Steam and Power Generation
6.12.8.1 Process Description
Steam and electric power are usually generated on-site
in order to make a coal liquefaction plant self-sufficient.
There may be times, however, when it is more cost effective
to purchase the required power off-site than to produce it.
In this model, it is assumed that power will be purchased.
This significantly reduces the on-site coal consumption,
cooling water requirements, and gaseous emissions to the
environment. It is estimated that about 110 MW are required
for a 20,000 ton per day (18,182 Mg/day) SRC plant (23).
The quantity of steam which must be produced on-site is
dependent upon the volume of steam produced by various pro-
cesses and the volume of steam which is consumed.
Steam may be produced indirectly in waste heat boilers
located throughout the plant. This reduces the volume of
steam which must be produced and provides a means of cooling
hot effluents from various unit operations. Usually 600
psig steam (4.1 MPa) is produced in coal-fired boilers to ful-
fill the plant steam requirements (23) .
Most steam produced in the plant is recycled to the
boilers in a closed conduit for reuse. In some instances,
however, steam is introduced directly into reactor vessels
where it becomes part of the process stream. Makeup water,
therefore, must be continuously added to the steam gener-
ating facilities.
Typical steam generation facilities are shown in Figure
54 (23). Since boiler water must be of high purity, raw
makeup water is demineralized prior to entering the boiler
water circuit. In order to maintian relatively low concen-
trations of dissolved solids in the circuit, a blowdown
stream also is continuously discharged. This stream is
directed to the cooling tower system. Blowdown rates are
approximately 0.1 to 1.0 percent of the steam flow (52).
6.12.8.2 Process and Waste Streams
Process and waste streams are shown in Figure 55.
Stream compositions are given in Table 63.
Flue gas is the most significant discharge from the
boilers, amounting to about 13,145 TPD (11,950 Mg/day).
This gas must be cleaned before being discharged to the
environment. A smaller waste stream discharged from the
steam generation facilities is ash from the boilers. Ash
233
-------
RECYCLE CONDENSATE
SLOWDOWN TO
COOLINGTOWER
RAW WATER
MAKEUP
FLUE GAS
STEAM TO
PROCESS
BOILER
AIR"'
COAL
ASH
DEMORALIZATION
REGENERANT
WASTEWATER
TO DISPOSAL
Figure 54- Steam Generation Facilities
234
-------
STEAM
GENERATION
© ©
STREAM
1. Recycled water
2. Makeup water
3. Coal
4. Stack gas
5. Steam
6. Ash
7. Air
8. Boiler Slowdown to cooling tower
9. Waste from demineralization operations
QUANTITY*
(TPD)
14680
5145
1024
13145
19810
73
12195
15
(Mg/day)
13345
4677
929
11950
18009
66
11087
14
MOT QUANTIFIED
*Streams may not balance due to roundoff
Figure 55. Steam and Power Generation Process and Waste Streams
235
-------
TABLE 63. STEAM AND POWER GENERATION STREAM COMPOSITIONS
Stream Quantity*
(TPD) (Mg/day)
4. Stack Gas
C02 2554.7 2322.5
H20 451.5 410.5
S02 69.7 63.3
02 656.7 597.0
N2 9362.7 8511.6
NOX 9.2 8.4
CO 0.5 0.5
HC 0.2 0.1
particulates 40.3 36.6
^Streams may not balance due to roundoff.
236
-------
is discharged at a rate of 73.0 TPD (66.0 Mg/day). Boiler
blowdown is directed to the cooling towers.
6-12.8.3 Control Equipment Specification and Cost Estimation
The combustion of coal for steam and power generation
results in one of the major atmospheric pollutant streams in
a SRC facility. A component analysis of the boiler flue gas
can be found in Table 64.
Principal pollutants include S02 (2465 ppm), NOX (6946
ppm as NO), particulates (1.77 grains/scf.), and carbon
monoxide (45.2 ppm).
Illinois emission standards for coal-fired boilers
require that pollutant concentrations do not exceed the
following levels (53):
• Sulfur Dioxide - 1.2 Ib/MM Btu coal. Total allow-
able daily emissions are 16 tons (14.5 Mg/day),
based on coal consumption of 1022 TPD (929.1
Mg/day) at 12,820 Btu/lb.
• Nitrogen Oxides - 0.7 Ib/MM Btu coal. Total
allowable daily emissions are 9 tons (8.2 Mg/day).
• Carbon Monoxide - 100 ppm based on 50% excess air.
Concentration for 25% excess air has been calcu-
lated to be 125 ppm.
Illinois standards for particulates in the petrochemi-
cal plant require that not more than 1.0 TPD (0.9 Mg/day) be
discharged. Coal-fired boilers may not have particulate
emissions exceeding 0.5 TPD (0.5 Mg/day) (based on a coal
consumption at 1022 TPD [929 Mg/day] at 12,820 Btu/lb).
In Table 65, the removal efficiencies needed to meet exist-
ing regulations are presented, along with applicable control
equipment.
Wet scrubbing techniques remove S02 and particulates
simultaneously and therefore are judged to be the most
feasible means of control. NOX interferes with wet S02
scrubbing processes, and therefore should be controlled by
combustion modification techniques. Table 66 presents re-
moval efficiencies, capital and operating costs, and emis-
sions after treatment for some commercially available wet
scrubbing techniques. Because of a relative lack^of data,
no process could be singled out as the most efficient.
Capital and operating costs for each process were very
similar.
237
-------
TABLE 64. CONSTITUENTS IN FLUE GAS FROM STEAM GENERATION
Total flow rate = 22,500 scfm (10.6 nT/sec)
Constituent
TPD*
Lb Moles /Day
Concentration
N2
C02
H20
°2
NO (As NO)
X
so2
Hydrocarbons
(as ethane)
Particulates
9363.
2555.
452.
657.
9.
70.
0.
40.
0
0
0
0
0
0
2
0
668,
116,
50,
41,
6,
2,
760
120
170
040
140
180
10
--
75.
13.
5.
4.
0.
0.
11.
1.
67,
17o
77o
670
77o
27o
(6946 ppm)
(2465 ppm)
3 ppm
77
grains /scf
k
Only English units are provided due to space limitations.
Metric conversion factors are given in the Appendix.
238
-------
TABLE 65. REQUIRED REMOVAL EFFICIENCIES TO MEET
ILLINOIS EMISSION STANDARDS FOR COAL-FIRED BOILERS
Constituent
Emission Before
Treatment
Illinois
Emission Std,
Required
Removal
Efficiency
Applicable
Control
Technology
S02 69.7 TPD
NO 9.2 TPD
15.6 TPD
9.1 TPD
77.61%
2.0%
Wet Scrubbing
Wet Scrubbing
Boiler Modification
Particulates 40.3 TPD
CO
0.54 TPD
0.5 TPD (45.2 ppm) 125 ppm
98.65% Wet Scrubbing
Electrostatic
Precipitator
*0nly English units are provided due to space limitation. Metric conversion
factors are given in Appendix A.
-------
TABLE 66. COSTS, EFFICIENCIES, AND FINAL EMISSIONS FOR COMMERCIALLY
AVAILABLE SOo WET SCRUBBING PROCESSES (54)
Basis: Coal-fired boiler flue gas
220,500 scfm (103.6 m3/sec) at 2465 ppm S02; 3
6,946 ppm NOX, and 1.77 grains/scf fly ash (245.0 gm/m )
N>
-P-
O
Process
Lime Slurry
Scrubbing
Soda- limes tone
Double-.aklali
MgO Scrubbing
(recovery)
Limestone
Scrubbing
Potassium Sulfit-e-
Bisulfite Scrub-
bing
Wet activated
charcoal absorption
Cost
Captial | Operating (Annual)
20.56
26.81
29.04
24.65
27.53
*
12.01
13.21
13.14
12.16
11.89
*
Removal Efficiencies
S02 | Particulates
90%
*
90%
70-80%
907.
80%
99+%
up to 99%
99.5%
99%
*
*
NOX
*
*
*
*
*
*
Emissions After Treatment
S02 IParticulates
6.97 TPD
*
6.97 TPD
17.42 TPD
6.97 TPD
13.94 TPD
0.70+ TPD
0.70 TPD
0.35 TPD
0.70 TPD
*
*
NOX
*
*
*
*
*
*
* Data Not Available
-------
NO. r^™' n° in?ormation whatsoever was found on
NOx removal efficiencies in SO? scrubbing processes Ti- i«
believed that quantities of NO* (more tnl/tSe 27. "iqulred)
TiiLr6 rem?ved.by mof of the wet S02 processes. Lime and
limestone slurries and MgO have been used as scrubbing
hpfSp°nun J0*,?11?* Plfnt rem°val systems. As mentioned
before, NOX actually interferes with wet S02 regenerable
processes^ It converts sulfite to sulfate. The regenera-
tion step is usually based on sulfite decomposition and is
either not effective on sulfate or is effective only at
added costs.
'x
Dependence on the wet S02 removal process also for NO
removal would mean a large nonregenerable sulfate purge
stream. Proper control of NOX should be done by combustion
modification. Flue gas recirculation and two-stage com-
bustion are the most applicable. No information on costs
for the two alternatives could be found.
Generally, mist elimination will be required after wet
scrubbing in order to meet stack opacity requirements. Most
commercially available wet scrubbing systems have a mist
elimination section within the apparatus and do not require
additional equipment.
Particulate emission standards have not been met by two
of the SOo removal processes (double-alkali and limestone
scrubbing). MgO scrubbing with a removal efficiency of
99.5% has met requirements. Since the removal efficiency of
lime slurry is more than 99%, it may meet emission standards
for particulates. However, without a specific number for
removal efficiency, no conclusion can be drawn.
6.12.9 Froduct/By-Product Storage
6.12.9.1 Process Description
There are a number of products and by-products stored
on-site such as liquid petroleum gas, naphtha, SRC fuel oil,
sulfur, ammonia and phenols. Pipeline gas is also produced
but sent directly into a gas pipeline grid for distribution.
Liquefied petroleum gas is normally stored and shipped in
atmospheric pressurized tankage. All storage tanks have gas
vents which return hydrocarbon vapors to the gas purifica-
tion area. This system prevents hydrocarbon vapor leakage
in the storage area. Solid SRC is stored in hoppers.
Various by-products such as sulfur, ammonia, and phe-
nols are removed from process waste streams, purified, and
also sent to storage. Ammonia and phenols are stored in
tanks; sulfur is stored outdoors in piles.
241
-------
6.12.9.2 Process and Waste Stream
A summary of the expected products and by-products is
given in Table 67.
Waste discharges from the product/by-product storage
area will generally result from spills, infrequent tank
cleaning, and fugitive vapor losses. Sulfur dust may also
be discharged to the environment from sulfur storage piles.
6.12.9.3 Control Equipment Specification and Cost Estimation
Emissions from product and by-product storage facili-
ties include vapor leakage from tanks and transfer lines and
particulate emissions from SRC storage. Vapor leakage can
be controlled by following proper engineering practices as
outlined in Chapter 5. Particulate emissions from SRC
storage have not been quantified. Dust control equipment
that would be applicable to SRC storage is similar to those
options mentioned in Section 6.1.3. Because of the lack of
information on dust quantities, equipment size and cost data
could not be specified.
6.13 Wastewater Treatment Facilities
Liquid wastes are discharged from numerous process
areas within a SRC-II liquefaction plant, including hydrogen
production, gas purification, cryogenic separation, auxil-
iary facilities (i.e., cooling towers), hydrotreating, and
phase (gas) separation. Prior to being directed to waste-
water treatment facilities, several of the waste streams are
sent to by-product recovery for the removal of ammonia,
sulfur, and phenol. The by-product recovery step not only
economically recovers various chemicals but also reduces the
toxicity from phenols in the wastewaters, prevents odor
problems, and eliminates the inclusion in the treatment
facilities of costly equipment for the removal of nitrogen.
Typical anticipated wastewater constituents include ammonia,
hydrogen sulfide, phenols, organic compounds (oils), trace
heavy metals, sulfates, organic nitrogen and sulfur, and
alkalinity.
Table 68 lists two alternative methods of treating SRC
process wastewaters to acceptable levels for plant reuse
along with anticipated influent and effluent stream com-
positions. The treatment units common to both alternatives
are presented first, followed by alternative biological
treatment schemes. These alternatives were formulated
based on the following considerations: '
242
-------
TABLE 67. PRODUCT/BY-PRODUCT STORAGE
Products Quantity
(TPD) (Mg/day)
SNG
LPG
Naphtha
Fuel Oil
SRC
1434.1
902.8
570.0
2850.0
6080.0
1311.6
820.7
518.2
2590.9
5527.0
By-Products
Phenol 37.40 34.0
Ammonia 70.3 63.9
Sulfur 486.5 442.3
243
-------
TABLE 68. COMMON TREATMENT PROCESSES TO ALL ALTERNATIVE
TREATMENT DISPOSAL METHODS
Process
Common Units for Alternatives
Stream Stripping of NH3
recovery wastes for
removal of I^S and
NH.
3
API Separator for
stripped wastewater
(for H2S and NH3) and
phenol recovery
wastewater r
Equalization -
Add sour water from
hydrogen production
to effluent from
API Separator
Dissolved Air Flotation
Alternative I
Biological Treatment
Extended Aeration
Filtration
Alternative II
Biological Treatment
Aerated Lagoon
Settling Basin
Parameter (TPD)
in
out
in
out
in
out
in
out
in
out
in
out
in
out
in
out
NH
-J
0.7
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
Trace
Trace
Trace
0.2
Trace
Trace
Trace
H7S
54.7
0.2
.2
.2
.2
.2
.2
.2
.2
Trace
Trace
Trace
.2
Trace
Trace
Trace
Phenol
0.8
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.03
0.03
0.03
0.5
0.03
0.03
0.03
ss
0.0
0.0
0.0
0.0
0.7
0.7
0.7
0.4
0.4
0.2
0.2
0.1
0.4
0.2
0.2
0.1
HC
2.4'
1.9
1.9
1.9
1.9
0.2
0.2
0.01
0.01
0.01
0.2
0.01
0.01
0.01
Flow
4201.0
4201.0
4201.0
4201.0
5079.0
5079.0
5079.0
5079.0
5079. 0
5079.0
5079.0
5079. 0
5075.0
5075.0
5075.0
5075.0
BOD
1.7
0.1
0.1
0.1
1.7
0.8
0.8
0.1
-------
• It is more cost effective to segregate and treat
individual waste streams when specific stream com-
ponents must be removed (i.e., oils and hydrogen
sulfide).
• Influent suspended solids were not high enough to
warrant inclusion of suspended solids removal
equipment.
• Neutralization of wastewaters may be effected most
satisfactorily by the mixing of various waste
streams in an equalization basin.
• Selection of biological treatment systems was
based on required performance and reliability.
• The treated wastewater effluent is acceptable for
reuse without further treatment.
Table 69 includes costs for the alternatives listed in Table
68. Alternative 1 appears to be more cost effective.
The treatment schemes listed in Table 68 have been ex-
tensively used in the petroleum industry for wastewaters
containing oils and grease, hydrogen sulfide, ammonia,
phenols, and suspended solids. Coal liquefaction publica-
tions to date have also indicated that these treatment units
are expected to be employed in commercial facilities when
built. At present, the Fort Lewis SRC pilot p,l'ant waste-
water treatment facilities consist of a surge reservoir,
waste disposal treater and flottazur (physical-chemical
treatment), a biological treatment system, sand filter,
carbon filter, and incinerator. The sand filter and carbon
filter are needed at this plant because the wastewater is
discharged into a "no-discharge" pond.
The physical-chemical treatment process is provided to
remove suspended solids. These are included in this report
because suspended solids are expected in wastewater from the
dissolved air flotation unit and the biological treatment
processes. The sand and carbon filters are not necessary
when the effluent is recycled to the cooling tower for plant
reuse. Fort Lewis pilot plant effluents have been observed
to be better and/or equal to the limits specified in Table
70.
245
-------
TABLE 69. COSTS OF TREATMENT PROCESSES
Based on Wastewater flow =1.23 MGD
PROCESSES
Common Units for Alternatives
Steam Stripping
API Separator (3703 gallons)
COSTS
'Capital
(§1000)
480.0
69.0
Operating
(Annual)
($1000)
81.654
1.0
Equlization Basin
Aerators (.86 HP)
and Basin (.0129 MG)
Dissolved Air Flotation
Flotation Unit (Rectangular 4376 Gallons)
Chemicals
Alternative I
Extended Aeration
Basin (1.23 MG)
Air (diffused-5400 cfm)
Clarifier (.31 MG)
Chemicals (Phosphorus)
Installation
Filtration Options
Pressure
Gravity (upflow)
Alternative II
Aerated Lagoon
Basin C6.15 MG) and Aerators
(411 HP)
?Chemicals (Phosphorus)
Settler (.31 MG)
60.0
90.0
N/A
62.0
100.0
08.0
100.0
87.5
104.5
813.0
88.0
0.163
14.0
N/A
17.4 (TOTAL)
2.263
4.083
67.12 (TOTAL)
2.263
-------
TABLE 70. FORT LEWIS PILOT PLANT EFFLUENT LIMIT (36)
Parameter Quantity (mg/1)
pH 6.0-8.5
BOD5 40
COD 150
SS 50
phenol 0.5
oil and grease 10
sulfates 235
Solids wastes, in the form of excess activated sludge,
also may be discharged from the treatment facilities period-
ically. This sludge is normally trucked to a suitable dis-
posal site.
6.14 Flare Systems
SRC production, like petroleum refining and chemical
processing industries, must dispose of small quantities of
continuous hydrocarbon waste gas streams from the process
units such as the hydrogenation reactor, flash drum separ-
ators and the fractionation column. In case of accidential
release due to equipment failure, large flows of gases must
be disposed. The common practice of disposal is the use of
a flare. Elevated combustion flare systems will be most
applicable for the liquefaction plant, since large gas flows
are involved. Air inspiration with steam will be utilized
to achieve smokeless combustion (1) .
Combustion in smokeless elevated flares is essentially
complete with the CC-2 to CO to hydrocarbon ratio of stack
gas being 100:4:0.002. On a dry basis, carbon monoxide
levels would be 4,000 ppm and hydrocarbon levels would be
only 2 ppm (59).
The amount of gases to be flared and the composition of
these gases can be assumed to be that of a refinery proces-
sing 50,000 bbl/day (7,950 m3/day) of oil. The stack height
will be in the range of 33 to 100 meters depending upon the
247
-------
location of the plant and meterological conditions C1)-
Also, the amount of the duct work required will depend on
the flare system distance from the processing units. itiese
factors will affect the cost of the flare system. Steam it
not available from the process plant, will add to the operat-
ing cost.
Elevated flare system costs vary considerably because
of the disproportionate costs for auxiliary and control
equipment and the relatively low cost of the flare stack and
burner. As a result, equipment costs are rarely diameter-
dependent. Typical installed costs for elevated flares
range from $30,000-$100,000. Operating costs are determined
chiefly by fuel costs for purge gas and pilot burners, and
by steam required for smokeless flaring. On the basis of 30
cents per million Btu's fuel requirement, typical elevated
stack operating costs are about $1,500 per year (59).
The cost of an elevated flare system for a 50,000
bbl/day (7,950 m3/day) SRC plant has been roughly estimated
from the cost of a flare system for a 350,000 bbl/day (55,650
m3/day) refinery. The 55,650 m3/day refinery flare system
incorporates two elevated flares, each costing $100,000, and
one ground flare, costing $200,000. The waste gas collection
system was valued at $250,000. Total capital cost for the
refinery was $750,000 (59).
Figure 56 presents average load to flare with respect
to refinery throughput in bbl/day. From the line drawn
through the data, (55,650 m3/day) plant would have a flare
loading of 200,000 Ib/day (90.9 Mg/day) and a 50,000 bbl/day
(7,950 m3/day) plant would have a flare loading of approxi-
mately 30,000 Ib/day (13.6 Mg/day).
Using six-tenth factor analysis and assuming a similar
scaled down version of the 350,000 bbl/day refinery flare
system, the cost of a flare system for the 50,000 bbl/day
SRC plant has been approximated. Results are listed below
in Table 71.
TABLE 71. ESTIMATED COSTS FOR FLARE SYSTEM OF
A 50.000 BBL/DAY SRC PLANT (59)
Unit Capital Cost Operating Cost
Elevated Flares (2)
Ground Flare (1)
Waste Gas Collection
System
Total
$64,100
64,100
80,000
$208,200
$3,000/yr
1,500/yr
_
$4,500/yr
248
-------
400,000
K>
100.000
200,000
Refinery Throughput (bbl/cd)
300,000
400,000
Figure 56. Crude P,un vs Flare Loading (59)
-------
7.0 Environmental Emissions and Factors Achieved
7.1 Introduction
In this chapter estimated concentrations of specific
pollutants in air, water, and solids waste streams after
treatment are compared with Multimedia Environmental Goals
(MEG's). Those MEG levels used for comparison are minimum
acute toxicity effluent levels based on health effects. It
is noted when the constituent level in the treated stream
exceeds the MEG. Future studies may be warranted to determine
ways to reduce the emissions to acceptable levels. This
could consist of either process or control modifications.
7.2 Multimedia Environmental Goals
Multimedia Environmental Goals (MEG's) are levels of
contaminants (in ambient air, water, or land) as in emissions
or effluents conveyed to ambient media that are judged to
be (1) appropriate for preventing certain negative effects
on the surrounding populations or ecosystems or (2) repre-
sentative of the control limits achievable through techno-
logy (60). A comparison of MEG's with emission characteris-
tics is an integral part of the environmental assessment
methodology being developed by the Fuel Process Branch of
IERL/EPA at RTF. This assessment includes a comparison to
MEG s of contaminant levels associated with emissions and
effluents from a point source.
^The MEG's provide sets of control goals for specific
chemical contaminants, complex effluents, and nonchemical
SrJ^fS8 SS* °Vome °f the criteria options that might
be considered in defining "desirable control levels " These
levels fo^vSol0*? ^ COmPared with actual contaminat^
levels tor environmental assessment purposes. A master
list of more than 600 chemical substances and physical
substances is being completed using prescribed selection
factors. At this time MEG's which fScus on fossil fuel
?o?Cll6'o?a^iCUlarl? C?al conve^°n, have been preyed
tor 216 of these contaminants. Three levels of prioritv
were assigned to the selection factors to determine which
substances should be included in the master liSTfor^G^s
250
-------
• Primary Selection Factors - The pollutant is
associated with fossil fuel processes.
• Secondary Selection Factors - Substances typical
of fossil fuel processes and
Federal ambient, emission, or occupational
criteria exist or have been proposed
A TLV has been established or an U)$Q has
been reported
The substance is a suspected carcinogen
The substance appears on the EPA Consent
Decree List.
• Tertiary Selection Factors (optional) - Consid-
eration is also given the substances present as a
pollutant in the environment and/or identified as
being highly toxic.
The current version of a typical MEG chart is shown in
Figure 57. The chart has been designed to display, in inter-
related tables, Emission Level Goals and Ambient Level Goals
for a specific chemical contaminant. Each table is divided
into columns devoted to specific criteria for describing
desirable control levels [for example, Toxicity Based
Ambient Level Goals (Based on health effects)]. Within each
column, space is provided for concentration levels to be
specified for air, water, and land in units consistent with
those indicated in the index column at the left. Only
numbers will appear within the MEG's charts. The name of
the substance addressed, its category number and appropriate
toxicity indicator (based on human health effects associated
with the substance as an air contaminant) are all presented
in bold letters in the upper right-hand corner of each
chart.
7.2.1 Emission Level Goals
Emission Level Goals presented in the top half of the
MEG's chart, actually pertain to gaseous emissions to the
air, aqueous effluents to water and solid waste to be dis-
posed to land. These Goals may have as their bases techno-
logical factors or ambient factors. Technological factors
refer to the limitations placed on control levels by tech-
nology, either existing or developing (i.e., equipment
capabilities or process parameters). The Standards of
Performance for New Stationary Sources2 provide an example
of promulgated Emission Level Goals based on technology.
251
-------
MULTIMEDIA
ENVIRONMENTAL
GOALS
ISA
PHENOL
EMISSION LEVEL GOALS
Air. ug/m
(ppm Vol)
Water, aj/1
(ppm Wt)
Land, jjg/g
(ppmWt)
1. Based on Best Technology
A. Existing Standaidl
NSPS, BPT, BAT
8. Developing Technology
Engineering Estimates
IR&D Goals)
II. Based on Ambient Factors
A. Minimum Acute
Toxicity Effluent
Based on
Health Effects
1.9E4
(5)
5.0EO
l.OE-2
Based on
Ecological
Effecu
5.0E2
l.OEO
B. Ambient Level Goal*
Based on
Health Effects
45
(0.01)
1
0.002
Based on
Ecological
Effects
100
0.2
C. Elimination of
Discharge
Natural Background*
•To be multiplied by dilution factor
AMBIENT LEVEL GOALS
Air, ^g/m
(ppm Vol)
Wrar, pg/l
Ippm Wt)
Land, jjg/g
tppm Wt)
1. Current or Proposed Ambient
Standards or Criteria
A. Based on
Health Effect!
It
B. Based on
Ecological Effects
lOOt
II. Toxicity Based Estimated
Permissible Concentration
A. Based on
Health Effects
45
(0.01)
260
0.002
B. Bawd on
Ecological Effects
500
0.2
Phenolic compounds.
III. Zero Threshold Pollutants
Estimated Permissible Concentration
Based on Health Effects
Figure 57. A Typical MEG Chart
252
-------
Since there is obviously a relationship between contami-
nant concentrations in emissions and the presence of these
contaminants in ambient media, it is imperative to consider
ambient factors when establishing emission level goals.
Ambient factors included in the MEG's chart as criteria for
Emission Level Goals include:
(1) Minimum Acute Toxicity Effluents (MATE's)--concen-
trations of pollutants in undiluted emission
streams that would not adversely affect those
persons or ecological systems exposed for short
periods of time.
(2) Ambient Level Goals--i.e., estimated permissible
concentrations (EPC's) of pollutants in emission
streams which, after dispersion, will not cause
the level of contamination in the ambient re-
ceiving medium to exceed a safe continuous expo-
sure concentration.
(3) Elimination of Discharge (EOD)--concentrations of
pollutants in emission streams which, after dilu-
tion, will not cause the level of contamination to
exceed levels measured as "natural background."
Although technology based Emission Level Goals are
highly source specific, goals based on ambient factors can
be considered universally applicable to discharge streams
for any industry. The Emission Level Goals based on EPC's
for example, correspond to the most stringent Ambient Level
Goals (dilution factor to be applied) appearing in the MEG's
chart, regardless of source of emission. This format for
presentation of Emission Level Goals has evolved during the
course of the MEG's project and is significantly different
from the initial chart introduced some 18 months ago. Elim-
ination of Discharge, as a criterion for Emission Level
Goals, was added about a year ago. In another interim
version, columns specifying dilution factors in multiples of
ten were included under the Emission Level Goals based on
ambient factors. Later, Minimum Acute Toxicity Effluents
(MATE's) were incorporated and the dilution factor columns
deleted. It is likely that the chart will be further altered
as the MEG's become more refined. The format presented here
serves well for displaying MEG's at this stage of develop-
ment.
253
-------
7.2.2 Ambient Level Goals
The lower half of the MEG's chart is designed to present
three classifications of Ambient Level Goals. All of these
goals describe estimated permissible concentrations (EPC s;
for continuous exposure. The Ambient Level Goals presented
in the chart are those based on:
(1) Current or proposed federal ambient standards of
criteria.
(2) Toxicity (acute and chronic effects considered).
(3) Carcinogenicity or teratogenicity (for zero thresh-
old pollutants).
The term "zero threshold pollutants" is used to dis-
tinguish contaminants demonstrated to be potentially carcino-
genic or teratogenic. The concept of thresholds is based on
the premise that there exists for every chemical substance,
some definable concentration below which that chemical will
not produce a toxic response in an exposed subject. The
existence of thresholds for carcinogens, teratogens and
mutagens has been widely debated and is still unresolved.
The term "zero threshold pollutants" is used as a convenience,
For the purposes of this report estimated constituent
levels after controls were matched with the Minimum Acute
Toxicity Effluent factors. In all cases the lower, or more
stringent, MATE was employed for the comparison.
If the level after controls exceeds the MATE value, the
potential exists for emission of excessive quantities of
specific contaminants. Further study might be warranted to
determine alternatives such as control or process modifica-
tions to reduce these levels.
7.3 Criteria
Estimates of pollutant levels were derived from a
variety of sources. The information used includes results
of sampling at the Fort Lewis pilot plant, emission data on
similar processes found in other industries, and engineering
calculations based on material balances included in this
report. It should be noted that all estimates of constituent
levels are only indicative of the quantities that might be
found in the specific waste streams. Until additional
sampling data is available from the pilot plant (or pre-
ferably a demonstration or commercial facility) accurate
profiles of the emissions cannot be developed.
254
-------
Tables 72, 73, and 74 show estimated air emissions from
three units in the coal preparation module (27). It was
assumed that the trace composition of the particulates
emitted was identical to that of raw coal (see Table 3) and
that total particulate loading was as calculated in the
previous chapter. Trace metals were determined for each
control option, based on the respective estimated effi-
ciencies. Estimated emissions were found to be at least
one order of magnitude lower in most cases. Chromium and
was found to exceed the MEG's by factors of 2.0-12.0 using
the high efficiency cyclone or wet scrubber. Aluminum also
exceeded MEG values by a factor of 1.1-1.6 using these
options. No MEG's were exceeded when using the cyclone and
baghouse combination. No trace metal MEG's were exceeded
by flow dryer emissions.
In addition to trace metal levels in the flow dryer
stream, the C02 emission level was calculated, based upon
material balances prepared for this report, and compared
with the corresponding MEG.
Emission Level MATE, health
1.9 x 108 ng/m3 9 x 106 ng/m3
The concentration in the stream exceeds the MEG by two
orders of magnitude. However, this should not impose any
serious health effects at this time.
An estimate of the Stretford tailgas composition and
concentration is matched with MEG's in Table 75. Pollutant
levels after both incineration and carbon adsorption are
compared. These levels were estimated using the material
balance from engineering calculations outlined in Chapter 6.
It is apparent that carbon adsorption emissions exceed MEG
values for H2S and NH3. Incineration only exceeds the MEG
for CC-2, and therefore presents a more acceptable alternative.
In Table 76, MEG's and corresponding air emissions from
the steam plant are listed (60,61). The polynuclear aromatic
hydrocarbon (PNA) data were based on data found in the cited
literature. It should be noted that the type of coal com-
busted was not specified in the literature. The trace metal
data were based upon controlled emissions, while the reported
PNA levels were based upon uncontrolled emissions. Effi-
ciencies of the various control options were used to calculate
final emission levels. Both PNA's and trace metals were
assumed to consist entirely of particulate matter in these
calculations. It is apparent that chromium and vanadium levels
exceed MEG's when using even the most efficient SOX wet scrub-
bing techniques. MEG's for chromium are exceeded by factors
of 9.2-18 while MEG's for vanadium are exceeded by factors of
4-8.1.
255
-------
TABLE 72. A COMPARISON OF ESTIMATED AIR EMISSIONS
FROM COAL RECEIVING AND MEG'S - TRACE METALS
Element
Ti
Mg
B
F
Zn
(fa
Sr
Zr
Ba
As
Cu
V
Cr
Ni
Se
Pb
MD
Ge
Co
Sn
Sb
Be
Cd
Sm
Yt
Hg
Ag
Al
Br
Ca
Ce
Cs
Cl
Dy
Eu
Ga
Hf
In
I
Fe
La
Lu
P
K
Kb
Sc
Si
Na
Ta
•11
Tl
Hi
W
U
All values
MEG
6 x 103
6 x 103
3.1 x 103
4 x 103
5 x 103
3 x 103
5 x 102
2x10°
2 x 102
5 x 102
1x10°
1.5 x 101
2 x 102
1.5 x 102
5 x 103
5.6 x 102
5 x 101
5 x 102
2x10°
1 x 101
1 x 101
1 x 101
5.2 x 103
5.0 x 103
1.0 x 102
0
2.0 x 10J
5.3 x 103
1.0 x 102
1.0 x 103
9.0 x 10°
are in u2/m .
Cyclone &
R^phouse
2.9 x 101
2.1 x 101
6.0 x 10°
3.0 x 10°
1.8 x 101
2.0 x 10°
2.0 x 10°
2.0 x 10°
4.6 x 10°
2.0 x Kf1
5.0 x 10"1
1.4 x 10°
8.0 x Kf1
9.0 x Kf1
9.0 x Kf 2
1.1 x 10°
4.0 x 101
2.0 x 10" L
3.0 x 10" L
2.0 x Kf 1
4.0 x Kf 2
6.0 x Kf2
2.0 x Kf1
5.0 x 10"2
2.0 x Kf2
1.0 x Kf2
1.0 x 10~3
5.6 x 102
6.0 x 10"1
3.2 x 102
5.0 x 10" l
5.0 x 10~2
6.7 x 101
4.0 x 10"2
1.0 x Kf2
1.0 x 10"1
2.0 x Kf2
6.0 x Kf3
8.0 x Kf2
7.8 x Kf2
1.9 x 10°
7.1 x 101
7.0 x Kf1
1.0 x Kf1
1.1 x 103
2.8 x 101
7 0 x 10~3
7.0 x 10"3
3.0 x 10"2
2.2 x 10°
3.0 x 10"2
7.0 x Kf 2
High
Exceeds Efficiency
MEG Cyclone
2.9 x 102
2.1 x 102
5.9 x 101
3.0 x 101
1.8 x 102
2.0 x 101
2.0 x 101
2.0 x 101
4.6 x 101
2.0 x 10°
5.0 x 10°
1.4 x 101
8.0 x 10°
9.0 x 10°
9.0 x Kf1
1.1 x 101
4.0 x 102
2.0 x 10°
3.0 x 10°
2.0 x 10°
4.0 x Kf1
6.0 x 10"1
2.0 x 10°
5.0 x 10"1
2.0 x Kf1
1.0 x 10"1
1.0 x 10"2
5.6 x 10 3
6.0 x 10°
3.2 x 103
5.0 x 10°
5.0 x 10"1
6.7 x 102
4.0 x 10"1
1.0 x 10"1
1.0 x 10°
2.0 x Kf1
6.0 x Kf 2
8.0 x 10"1
7.8 x 103
1.9 x 101
7.1 x 102
7.0 x 10°
1.0 x 10°
1.1 x 104
2.8 x 102
7.0 x Kf2
7.0 x 10"2
3.0 x 10"1
2.2 x 101
3.0 x 10"1
7.0 x Kf 1
Exceeds Wet
MEG Scrubber
4.3 x 101
3.1 x 102
8.9 x 101
4.5 x 101
2.7 x 102
3.0 x 101
3.0 x 101
3.0 x 101
6.8 x 101
3.0 x 10°
7.0 x 10°
2.1 x 101
X 1.2 x 101
1.3 x 101
1.3 x 10°
1.6 x 101
6.0 x 10°
3.0 x 10°
4.0 x 10°
3.0 x 10°
6.0 x Kf1
9.0 x 10"1
3.0 x 10°
7.0 x Kf1
3.0 x Kf 1
1.0 x Kf1
1.0 x Kf2
X 8.4 x 103
9.0 x 10°
4.8 x 103
7.0 x 10°
7.0 x 10"1
1.0 x 103
6.0 x Kf1
1.5 x Kf1
1.5 x 10°
3.0 x Kf1
9.0 x Uf2
1.2 x 10°
1.2 x 104
2.8 x 101
1.1 x 103
1.0 x 101
1.5 x 10°
1.7 x 104
4.2 x 102
1.0 x Kf1
1.0 x 10"1
4.0 x Kf 1
3.3 x 101
4.0 x Kf1
1.0 x 10°
Exceeds
MEG
X
X
X
•V^^HMHHMB
256
-------
TABLE 73. A COMPARISON OF ESTIMATED AIR
EMISSIONS FROM COAL RECLAIMING AND CRUSHING
WITH MEG's - TRACE METALS
Element
Ti
Mg
B
F
Zn
Mn
Sr
Zr
Ba
As
Cu
V
Cr
Ni
Se
Fb
bt>
Ge
Co
Sn
Sb
Be
Cd
Sn
Hg
Ag
Al
Br
Ca
Ce
Cs
Cl
Dy
Eu
Ga
Hf
In
I
Fe
La
Lu
p
K
Rb
Sc
Si
Ha
la
Tb
Tl
Th
W
u
MEG
•j
6 x icr
•a
6 x HT
3.1 x 103
4 x 103
5 x 103
3 x 103
5 x 102
2x10°
2 x 102
5 x 102
1x10°
1.5 x 101
2 x ID2
1.5 x 102
5 x 103
5.6 x 102
5 x 101
5 x 102
2x10°
1 x 101
1 x 101
1 x 101
5.2 x 103
5 x 103
1 x 102
2 x Id3
5.3 x 104
1 x 102
1 x 103
9 x 10°
Cyclone &
Baghouse
n
7 x 10U
n
5 x 10U
1.4 x 10°
6 x 10"1
4 x 10°
5 x 10"1
4 x 10"1
5 x 10"1
1.1 x 10°
6 x 10"2
1 x 10"1
3 x Hf1
2 x 10"1
2 x 10"1
2 x HI"2
3 x 10"1
9 x 10" 2
6 x ICf 2
7 x Hf2
5 x ICf 2
1 x 10~2
2 x ICf 2
4 x 10"2
5 x 10~2
2 x 10" 3
3 x 10"4
1.4 x 102
2 x 10"1
7.9 x 101
1 x 10"1
1 x 10"2
1.6 x 101
1 x ICf2
3 x ICf3
3 x ICf2
5 x ICf3
1 x ICf3
2 x 10"2
1.9 x 102
7 x ICf2
8 x ICf4
5 x 10"1
1.7 x 101
2 x ICf1
3 x 10"2
2 x 102
6.8 x 10°
2 x 10~3
2 x ICf3
7 x ICf3
2 x 10"2
7 x 10~3
2 x ICf2
High
Exceeds Efficiency Exceeds
MEGS Cyclone MEG
i
7 x 1(T
i
5 x 10
1.4 x 101
6x10°
4 x 101
5x10°
4x10°
5x10°
1.1 x 101
6 x 10"1
1x10°
3x10°
2 x 10° X
2x10°
2 x 10"1
3x10°
9 x 10"1
6 x Kf1
7 x 10"1
5 x Hf 1
1 x Kf1
2 x Hf1
4 x 10"1
1 x 10"1
2 x 10"2
3 x Hf3
1.4 x 103
2x10°
8 x 102
1 x 10°
1 x 10"1
1.6 x 102
1 x 10"1
3 x Hf 2
3 x 10"1
5 x 10"2
1 x 10"2
2 x 10"1
1.9 x 102
7 x 10"1
8 x Hf 3
5x10°
1.7 x 102
2x10°
3 x Hf1
2.8 x 103
6.8 x 101
2 x Hf 2
2 x 10"2
7 x Hf 2
2 x 10"1
7 x 10"2
2 x 10'1
Wet Exceeds
Scrubber MEG
o
1.1 x 10
i
7.5 x HT
2.1 x 101
9 x 10°
6 x 101
7.5 x 10°
6x10°
7.5 x 10°
1.7 x 101
9 x 10"1
1.5 x 10°
4.5 x 10°
3 x 10° X
3x10°
3 x 10*1
4.5 x 10°
1.4 x 10°
9 x 10"1
1x10°
8 x 10"1
2 x Hf 1
3 x Hf 1
6 x 10"1
2 x 10"1
3 x 10"2
5 x Hf 3
•5
2.1 x 10J
3x10°
0
1.2 x 10J
ri
1.5 x 10°
2 x Hf 1
2.4 x 102
2 x 10" 1
5 x 10"2
5 x 10"1
8 x 10"2
2 x 10"2
1
3 x 10 L
•5
2.9 x 10
n
1 x 10°
1 x 10" 2
n
7.5 x 10°
0
2.6 x 10Z
n
3 x 10°
5 x 10"1
4.1 x 103
2
1.0 x 10
3 x 10"2
3 x 10"2
1 x 10"1
3 x 10"1
1 x 10"1
3 x 10"1
All values are in pg/m .
257
-------
TABLE 74. A COMPARISON OF ESTIMATED AIR EMISSIONS
FROM THE FLOW DRYER AND MEG'S - TRACE METALS
Element
Ti
Mg
B
F
Zn
Mn
Sr
Zr
Ba
As
Cu
V
Cr
Ni
Se
Pb
Mo
Ge
Co
Sn
Sb
Be
Cd
Sm
%
Ag
Al
Br
Ca
Ce
Cs
Cl
Dy
Eu
Ga
Hf
In
I
Fe
La
Lu
P
K
Rb
Sc
Si
Na
Ta
Tb
Tl
Th
W
U
MEG
6 x 103
6 x 103
3.1 x 103
4 x 103
5 x 103
3 x 1Q3
5 x 102
2x10°
2 x 102
5 x 102
1.5 x 101
1.5 x 101
2.0 x 102
1.5 x 102
5 x 103
5.6 x 102
5 x 101
5 x 102
2x10°
1 x 101
1 x 101
1 x 101
5.2 x 103
5 x 103
1 x 102
2 x 103
5.3 x 104
1 x Id2
1 x 103
9 x 10°
Baghouse
5 x 10"1
4 x ICf1
1 x 10"1
5 x ICf 2
3 x 10"1
4 x ICf2
3 x ICf2
4 x ICf2
8 x ICf2
4 x ICf3
1 x Hf 2
2 x ICf2
1 x 10"2
2 x 10"2
2 x Id"3
2 x ICf 2
7 x 10"3
< 4 x ICf3
5 x 10"3
3 x 10"3
7 x ICf4
1 x ICf3
<3 x 10"3
9 x ICf4
1 x ICf4
2 x ICf5
1 x 101
1 x ICf2
5.7 x 10°
1 x ICf2
9 x 104
1.2 x 10°
7 x ICf4
2 x 10~4
2 x ICf3
4 x ICf4
1 x ICf4
1 x ICf3
1.4 x 101
5 x ICf3
6 x ICf5
3 x ICf2
1.3 x 10°
1 x ICf2
2 x ICf 3
2 x 101
5 x ICf1
1 x ICf4
1 x ICf4
5 x ICf4
2 x ICf3
5 x ICf4
1 x in"3
Exceeds Wet Exceeds
MEG Scrubber MEG
7.6 x 10°
6.1 x 10°
1.5 x 10°
8 x ICf 1
4.6 x 10°
6 x 10"1
5 x ICf1
6 x 10"1
1.2 x 10°
6 x ICf2
2 x ICf1
3 x 10"1
2 x 10"1
3 x ICf 1
3 x ICf2
3 x 10"1
1 x ICf1
<6 x Hf2
8 x ICf2
5 x ICf2
1 x ICf2
2 x ICf2
< 5 x ICf2
1 x ICf2
2 x ICf3
3 x llf 4
1.5 x 1C2
2 x 101
8.7 x 101
2 x ICf1
1 x ICf2
1.8 x 101
1 x ICf2
3 x ICf3
3 x ICf2
6 x ICf3
2 x ICf3
2 x ICf2
2.1 x 102
8 x ICf2
9 x ICf4
5 x 10"1
2 x 101
2 x ICf L
3 x ICf2
3.1 x 102
7.6 x 10°
2 x ICf3
2 x ICf3
3 x ICf3
3 x ICf2
S x ICf3
•>. y. in"2
All values are in (/g/m'
258
-------
TABLE 75. A COMPARISON OF ESTIMATED STRETFORD TAIL GAS EMISSIONS AND MEG's
Oi
Exceeds
MEG j^^n^ni-in-n MEG Carbon Adsorption
H2S 1.5 x 102 7.1 3.8 x 102
S02 1.3 x 103 0
HC 2.7 x 103 9.8 x 103
NO 3.3 x 103 2.2 x 101
CO 4 x 104 8.3 x 101 4.2 x 103
C02 9 x 106 2.2 x 107 X 2.2 x 107
NH3 3.5 x 102 3.9 x 101 2.2 x 103
Exceeds
MEG
X
X
X
-
All values are in
-------
TABLE 76. A COMPARISON OF ESTIMATED AIR EMISSIONS
Trace Metals
Sb
As
Be
Cd
Cr
Cu
Fe
Pb
Hg
Ni
V
Zn
MEG
5 x 102
2x10°
1 x 101
1x10°
2 x 102
1.5 x 102
1.0 x 101
1.5 x 101
1x10°
4 x 103
Lome Slurry
or
Soda Limestone
or Exceeds
Limestone Scrubbing MEG
5.6 x 10"1
7.8 x 10"2
3.4 x Hf1
1.1 x 101
1.8 x 101 X
1.2 x 10°
1.6 x 103
4.2 x 101
2.0 x 10°
4.0 x 101
8.1 x 10° X
8.5 x 101
MgO Exceeds
Scrubbing MEG
2.8 x 10"1
3.9 x 10"2
1.7 x 10"1
5.7 x 10°
9.2 x 10°
5.9 x 10'1
8.4 x 102
2.1 x 101
9.8 x 10"1
2.0 x 101
4.0 x 10°
4.2 x 101
X
X
Organic Compounds
benzo (a)pyrene
pyrene
fluoranthene
benzo (a) -
anthracene
2 x 10"2
2.3 x 106
9 x 104
4.5 x 101
5.4 x 10"3
4.3 x 10"3
5.2 x 10~3
5.4 x 10~4
2.7 x 10"4
2.1 x 10"3
2.6 x 10"3
2.7 x 10"4
All values in
260
-------
The S02 levels, calculated from the material balance
and efficiencies of scrubbers, are below. No MEG is cur-
rently available for S02-
Limestone Potassium Activated
Lime Slurry MgO Scrubbing Sulfite - Bisulfite Charcoal
0.7 |ag/m3 0.7 |ag/m3 1.8 ng/m3 0.7 ng/m3 1.4 ^g/m3
The estimated trace metal composition of the slag
generated during the gasification of the mineral residue is
compared with MEG's in Table 77 (60). Information on the
residue makeup was available for the Fort Lewis pilot plant
(62) . It should be realized that instead of Illinois #6
coal, Kentucky coal was used during the sampling. This
would affect the actual composition of the stream, but the
data available does provide some indication of the makeup of
the stream. The estimates present maximum concentrations in
the slag assuming no leaching of metals into the clarified
quench water purge stream. Actual concentrations are ex-
pected to be at most an order of magnitude lower. Mercury
and bromine are expected to be volatized and carried with
the product gas, hence they are not expected to appear in
any significant concentrations. Even when given an order of
magnitude leeway, MEG's for all available metals except
scandium and strontium are exceeded.
Table 78 shows wastewater constituent levels (60,62).
Influent data on organics is also from a sampling program at
Fort Lewis. Compared to the hypothetical plant herein, the
Fort Lewis facility does not generate hydrogen, produce
process steam, or always use similar control or process
technologies. For purposes of calculation, removal effi-
ciency for PNA's was assumed to be 50 percent. Trace metal
analyses from another sampling program at the pilot plant
were collected for the effluent from the wastewater treat-
ment plant and are listed in Table 79 (60,63). Unlike in
Table 77, less than half the MEG's are exceeded.
Table 80 presents MEG's and rough estimates for concen-
trations of other compounds found in the wastewater as
calculated from material balances presented in this report.
Insufficient information prevented an accurate determination
of concentrations. Hence, comparisons to MEG's could not be
accomplished.
261
-------
TABLE 77. A COMPARISON OF SLAG FROM THE
•GASIFIER AND MEG'S - TRACE METALS (62)
Element
Na
Fe(%)
Cr
Co
Ni
Sc
Ba
Sr
La
Ce
Nd
Sm
Eu
Tb
Yb
Lu
Hf
Ta
Ih
Rb
Cs
As
Sb
2n
*Br
Se
*Hg
Residue & Coal
Before
Gasification
1.7 x 106
7.8 x 10°
8.4 x 101
1.9 x 101
7.1 xlO1
8.7 x 10°
1.4 x 102
1.8 x 102
2.8 x 101
5.6 x 101
2.7 * 101
5.3 x 10°
1.1 x 10°
6.6 x 10"1
2.1 x 10°
3.1 x 10"1
1.4 x 10°
3.8 x 10"1
6.0 x 10°
6.6 x 10°
3.4 x 10°
4.4 x 101
4.4 x 10°
7.3 x 101
4.3 x 10°
1.2 x 101
8.3 x 10"2
Slag After
Gasification
(Max. Cone.)
5.1 x 106
2.3 x 101
2.5 x 102
5.7 x 101
2.1 x 102
2.6 x 101
4.2 x 102
5.4 x 102
8.4 x 101
1.7 x 102
8. 1 x 101
1.6x 101
3.3x 10°
2.0 x 10°
6.3 x 10°
9.3 x 10"1
4.2 x 10°
1.1 x 10°
1.8 x 10L
2.0 x 101
1.0 x 101
1.3 x 102
1.3 x 101
2.2 x 101
3.6 x 101
MEJG
5 x 10"1
1.5 x 10'1
2.0 x 10"2
1.6 x 103
5x10°
9.2 x 101
1 x 10"1
4 x 10"1
2 x 10'1
5 x 10"2
2 x 10'2
Exceeds
MEG
X
X
X
X
X
X
X
X
X
All concentrations are in
*Not expected to be present in significant quantities due to volatilization.
262
-------
TABLE 78. A COMPARISON OF ESTIMATED EFFLUENTS FROM THE WASTEWATER
TREATMENT PLANT AND MEGS - ORGANIC COMPOUNDS (60.62)
indane
methylindene
tettalin
dimethyltetralin
naphthalene
" 2-methylnaphthalene
dimethylnaphthalene
dimethylnaphthalene
2-isopropylnaphthalene
1-isopropylnaphthalene
biphenyl
aeenapthylene
dimetnylbiphenyl
dimethylbiphenyl
dibenzofuran
xanthrene
dibenzothiophene
methylbenzothiophene
dlmethyUbenzothiophene
thioxanthene -
fluorene
Before
Treatment
1.5 x 104
<1 x 102
5x 102
5 x 103
2 xlO3
3x 102
2x 103
7 x 102
2x 103
2 x 102
<1 x 102
5xl02
2 x 102
6 x 102
2 x 102
1.5 x 103
<1 x 102
<5 x 101
1 x 102
3 xlO2
After
Treatment
7.5 x 103
< 5 x 101
2.5 x 102
2.5 x 103
Ix 103
1.5 x 103
1 x 103
3.5 x 102
Ix 103
Ix 101
< 5 x 101
2.5 x 102
1 x 102
3 x 102
5 x 101
7.5 x 102
<5 x 101
<2.5 x 101
<5x 101
1.5 x 102
m;
1 x 103
lxlOA
1.5 x 10A
Exceeds
IfE
9-methylfluorene
1-methylfluorene
anthracene/phenanthrene
methyl phenanthrerie
1-nethyl phenanthrene
Cj-anthracene
fluoranthene
dihylropyrene
pyrene
n-octane
n-undecane
n-dodecane
n-tridecane
n-tetradecame
n-pentadecane
n-hexadecane
n-heptadecane
-n^elcosane
Befcre
Treatment
3 x 102
2 x 102
l.lx 103
3 xlO2
2x 102
< 5 x 101
4 xlO2
<5 x 101
6x 102
2.3 x 103
3 x 102
3 x 102
4x 102
3 x 102
2 x 102
2 x 102
2 x 101
2 x 101
After
Treatment
1.5 x 102
Ix 102
5.5 x 102
1.5x 102
1 x 102
<2.5x 101
2 x 102
<2.5 x 101
3 x 102
MX3
8.4 x 103/2.39 x Ifl4
1.4 x 106
3.45 x 106
Exceeds
MEG
All values in pg/1.
-------
TABLE 79. A COMPARISON OF ESTIMATED EFFLUENT
CONSTITUENTS FROM THE WASTEWATER TREATMENT
PLANT AND MEG'S - TRACE METALS (60.63)
Component
As
Sb
Se
Mg
Bi
Ni
Co
Cr
Fe
Na
Rb
6*
K
Sc
Tb
Eu
Sm
Cl
La
Sr
Ba
Th
Hf
Ta
Ga
Zn
Cu
Emission Level
<1 x 10°
2x 10°
1.2 x 10°
3.2 x 103
3.2 x 104
1.3 x 101
4.1 x 10"1
1.5 x 102
1.25 x 103
8.3 x 103
5.2 x 102
2 x 10"2
1.26 x 103
1 x 10"2
1 x 10~2
1 x 10"2
<6 x 10~2
<2 x 10"2
5 x 10"1
<4 x 101
<4 x 101
<1 x 10"2
<1 x 10"2
<1 x 10"2
<4 x 10'2
<4 x 10"2
<1 x 101
MEG
5 x 101
2 x 102
2.5 x 101
1 x 101
1 x 101
2.5 x 102
2.5 x 102
3 x 104
8x10°
4.6 x 104
2.5 x 10°
7.4 x 104
Exceeds MEG's
X
X
•x
X
All concentrations are in ug/1.
264
-------
TABLE 80. A COMPARISON OF OTHER ESTIMATED EMISSIONS
FROM THE WASTEWATER TREATMENT
PLANT AND MEG'S (60)
Component
NH
H2S
Phenol
Emission Levels
Trace
Trace
<2.6 x 10"5
MEG
5 x 10"5
1 x 10"5
5 x 10"6
Exceeds MEG
Not determinable
Not determinable
Not determinable
All values are in yg/1.
265
-------
8.0 Emission Variations for the SRC I System
In the SRC I system, the main product is a low sulfur
and ash solid rather than a liquid product. The production
of a solid product requires certain basic changes in the SRC
system, which are listed below:
• Hydrogenation in the SRC-I mode of operation
requires less hydrogen. The hydrogen:coal slurry
ratio is 50 to 67 percent lower than the SRC-II
ratio (64).
• Vacuum flashing is not incorporated as the main
process in the solids separation module. A separa-
tion technique producing a higher ash residue will
most probably be used. Feasible solids separation
processes include rotary pre-coat filtration,
solvent de-ashing, and centrifugal techniques.
• The fractionation module produces a wash solvent
for filtration, process solvent for slurry prepara-
tion, and only a small amount of by-product light
oil relative to by-product oils from SRC-II pro-
cessing (6.77o of the total coal feed as compared
to 17.1% for SRC-II) (64).
• Process solvent rather than slurry will be re-
cycled to the coal preparation module. The
solvent stream will be recycled from the fractiona-
tion module rather than from the phase (gas)
separation module.
• Wash solvent is recycled to the solids separation
module (only when precoat filtration is used) from
fractionation.
• Since the by-product light oil quantity is less,
the capacity of the hydrotreating module will be
lower than that of an equivalent SRC-II facility
(64).
• The solidification module will have a much greater
capacity since it will handle the main product
stream rather than a residue stream.
266
-------
• The gas purification module will be slightly
smaller because less acid gas will be produced.
This is also true for the cryogenic separation
module and sulfur recovery.
• Less hydrogen is needed; therefore, the capacity
of the hydrogen production module will be lower.
These modifications in the basic system will result in
different emissions in SRC-I relative to those of SRC-II.
Since the solidification module will undergo a more than
two-fold capacity increase, the dust stream flowrates
emanating from this module can be expected to be more than
twice as large (64). This stream has a high dust loading
and is expected to be a major control problem in the SRC-I
system.
The use of lower hydrogen:slurry feed ratios will cause
less of the coal polymer to be broken down. Less hydrogen
sulfide, mercaptans, light hydrocarbons, and ammonia will be
produced. Less carbon dioxide and carbon monoxide have also
been observed when lower hydrogen hydrogen:slurry feed
ratios are used.
The utilization of lower hydrogen:slurry ratios means
that hydrogen production operations do not have to be as
large. Therefore, less waste material will be generated in
the hydrogen production module. Lower quantities of acid
gas, C02, flue gas, and wastewater will be produced. Any
changes in slag production are difficult to predict, because
the change in modular capacity must be balanced against
changes in concentration of mineral matter in the gasifier
feed mixture, which depends on residue characteristics and
mix ratio.
The solids residue stream from solids separation will
be reduced by about seven percent (64). It is expected to
contain a greater percentage of mineral matter and undis-
solved coal particles. It may be suitable as a component of
the feed to the gasifier; however, it may have to be mixed
with a slightly larger quantity of coal to control slagging.
There is uncertainty with respect to whether there will be
an increase or decrease in slag production from gasification
of the SRC-I residue, because of the lack of information on
the concentration of mineral matter in the residue, and the
uncertainty with respect to how much residue can be used.
Also, because of these uncertainties it is difficult to
predict the relative amount of residue that must be land-
filled.
267
-------
Since the hydrotreating, gas purification, and cryogenic
separation modules will be slightly smaller, quantities of
waste streams from these modules are expected to be slightly
lower. Also, waste quantities from sulfur recovery, steam
generation, and oxygen generation will be decreased because
of the decrease in the capacity of hydrogen generation.
Storage and transportation of solid SRC presents a
significant and expensive dust control problem while liquid
SRC storage facilities would have to be accommodated with
vapor recovery systems. Transportation of liquid SRC does
not seem to have the control problems that occur when trans-
porting a solid product.
268
-------
9.0 Acknowledgement s
The preparation of this Standards of Practice Manual
was accomplished by the staff of the Environmental
Engineering Department, Hittman Associates, Columbia,
Maryland under the overall direction of Mr. Dwight B.
Emerson, department head. Mr. Bruce May, acting head,
Synthetics Fuel Section; and Mr. Craig Koralek, task
leader, shared direction of the day-to-day work on the
program.
Our appreciation is extended to the staff of the
Environmental Engineering Department of Hittman Associates
for their assistance during the preparation of this manual.
Special thanks are given to the following major contributors
to the document:
Pamela A. Koester, Environmental Engineer
Paul J. Rogoshewski, Chemical Engineer
Roger S. Wetzel, Civil Engineer
Other department members involved in the preparation
of this document include:
Dewey I. Dykstra, Chemical Engineer
Subhash S. Patel, Chemical Engineer
John E. Robbins, Technical Information Specialist
Kevin J. Shields, Chemical Engineer
Mr. William J. Rhodes, project officer, Industrial
Environmental Research Lab., Office of Research and Develop-
ment, through his assistance, leadership, and advice has
made an invaluable contribution to the preparation of this
report. Mr. Rhodes provided organizational and technical
direction in the preparation of this document.
Appreciation is extended to Mr. C. Harold Fisher,
Department of Energy; Mr. Walter Hubis, Gulf Mineral Re-
sources; and Ms. Carrie L. Kingsbury, Research Triangle
Institute; for providing invaluable information and recom-
mendations. Without their cooperation, it would have been
impossible to have prepared this manual.
We are also indebted to the pollution control equipment
vendors, listed in the References, for providing us with
information concerning the applicability and costs of the
different pollution control equipment. These individuals
spent considerable time and effort to provide us with up-to-
date and accurate information.
269
-------
10.0 References
1. Liptak, B.C., ed. 1974. Environmental Engineers'
Handbook, Volume II: Air Pollution^Chi1ton Book
Company, Radnor, Pennsylvania.
2. Cheremisinoff, P.N., and R.A. Young, eds. 1976.
Pollution Engineering Practice Handbook, Ann Arbor
Science Publishers, Inc., Ann Arbor, Michigan.
3. Cheremisinoff, Paul N. 1976. A special staff report:
control of gaseous air pollutants. Pollution Engineering.
8(5):30-36.
4. Metcalf & Eddy, Inc. 1972. Vastewater Engineering:
Collection, Treatment, Disposal"! McGraw Hill Book
Company, New York.
5. U.S. Environmental Protection Agency. December 1976.
Methods to Control Fine Grained Sediments Resulting
from Construction Activity, EPA 440/9-76-02^
6. Radian Corporation. 1975. Water Pollution Control of
Pollution Control Technology for"Fossil Fuel^Fired
Electric~Generating Stations, Radian Corporation,
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7. American Petroleum Institute. 1969. Manual on Disposal
of Refinery Wastes. Volume on Liquid Wastes. American
Petroleum Institute, Washington, DC.
8. U.S. Environmental Protection Agency. 1974. Technology
Transfer; Process Design Manual for Upgrading Existing
Wastewater Treatment Plants. EPA~l>25/l-71-004a.
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Removal. EPA 625/l-75-003a~:
11. U.S. Environmental Protection Agency. 1973. Technology
Transfer: Process Design Manual for Carbon Adsorption.
EPA 625/l-7l-002a.
270
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12. Weber, W.J., Jr. 1972. Physiochemical Processes for
Water Quality Control. Wiley-Interscience Publishers,
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13. Liptak, B.C. ed. 1974. Environmental Engineers'
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14. Liptak, B.C. ed. 1974. Environmental Engineers'
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Company, Radnor, Pennsylvania.
15. Cook College (Rutgers University). 1976. Ultimate
Disposal of Organic and Inorganic Sludge, Seminar Course
Series Sponsored by EPA Region II.
16. U.S. Environmental Protection Agency. 1977. Draft
Technology Overview of Coal Cleaning Processes and
Environmental Controls. Contract No. 68-02-2163.
17. Johnson, C.A. and J.Y. Livingston. 1974. "H-Coal®
How Near to Commercialization," Presented at the Symposium
on Coal Gasification and Liquefaction: Best Prospects for
Commercialization, University of Pittsburgh, School of
Engineering, August 6-8, 1974.
18. McGraw-Hill Mining Publications. 1974. 1974 Keystone
Coal Industry Manual. McGraw-Hill, Inc., New York.
19. U.S. Energy Research and Development Administration.
May 1977. Solvent Refined Coal (SRC) Process: Annual
Report 1976"FE 496-129. Pittsburgh and Midway Coal
Mining Company, Merriam, Kansas.
20. Stern, Arthur, C. ed. 1968. Air Pollution: Volume III;
Sources of Air Pollution and Control"! Academic Press,
New York.
21. D'Alessandro, P.L., and C.B. Cobb. 1976. Oil spill
control. (Part 1). Hydrocarbon Processing. 55(2):121-
124.
22. D'Alessandro, P.L., and C.B. Cobb. 1976. Oil spill
control (Part 2). Hydrocarbon Processing 55(3):145-
23. U.S. Department of the Interior. 1973. Demonstration
Plant, Clean Boiler Fuels from Coal; Preliminary
Design/Capital Cost Estimate, R&D Report No. 82 - Interim
Report No. 1. " TEe~Ralph M. Parsons Company, Los Angeles,
California.
271
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24. Hammer, Mark J. 1975. Water and Vastewater Technology.
John Wiley & Sons, Inc., New York.
25. United States Geological Survey. 1970. The National
Atlas of the United States. Department of the Interior,
Washington, DC.
26. United States Environmental Protection Agency. 1975.
Characterization and Utilization of Municipal and Utility
Sludges and Ashes7~Volume III: Utility Coal Ash. Dayton
University, Dayton, Ohio.
27. United States Environmental Protection Agency. 1977.
Trace Elements in Coal: Occurrence and Distribution.
EPA-600/7-77-0637 TTTTnois State Geological Survey,
Urbana, Illinois.
28. Teen-Yung, C.J., R. Ruane, and G.R. Steiner. 1976.
"Characteristics of Wastewater Discharge from Coal-Fired
Power Plants." Presented at the 31st Annual Purdue
Industrial Waste Conference, Purdue University, West
Lafayette, Indiana, May 4-6, 1976.
29. U.S. Environmental Protection Agency, Office of Air
Planning and Standards. 1973. Air Pollution
Engineering Manual.
30. Cost information provided by Mr. Mark Shuy. The Dow
Chemical Company, Dowell Division, Tulsa, Oklahoma.
31. Cost Information on cyclones provided by Mr. Phil
O'Connell, Torit Co., Towson, Maryland, October 19, 1977.
32. Cost Information on baghouses provided by Mr. Andrew
Brown, American Air Filter, Baltimore, Maryland, October
19, 1977.
33. Hanf, E.W., and J.W. MacDonald. 1975. Economic evalua-
tion of wet scrubbers. Chemical Engineering Progress.
71(3):48-52. fi * S
34. Cost Information on storage silos provided by Mr. John
Schum, John Kulg Corporation, Rochester, New York.
35. Parker, C.L. 1975. Estimating the cost of wastewater
treatment ponds. Pollution Engineering. November 1975.
272
-------
36• V'S. Energy Research and Development Administration.
1975. Development of a Process for Producing an Ashless,
Low Sultur Fuel from Coal, Volume~TlTT"Pilot Plant
Development Work. Part 2 - Construction of Pilot Plant.
Pittsburgh and Midway Coal Mining Company, Merriam^
Kansas.
37. Schmid, B.K., and D.M. Jackson. 1976. "The SRC-II
Process." Presented at the Third Annual International
Conference on Coal Gasification and Liquefaction,
University of Pittsburgh, August 3-5, 1976.
38. U.S. Energy Research and Development Administration. 1977
Oil/Gas Complex: Conceptual Design/Economic Analysis,
R&D Report No. 114, Interim Report No. 4.The Ralph M.
Parsons Company, Los Angeles, California.
39. Electric Power Research Institute. 1976. Coal
Liquefaction Practices Design Manual. EPRI-AF-199.
Fluor Engineers and Constructors, Inc., Los Angeles,
California.
40. U.S. Environmental Protection Agency. 1977. Draft
Report Technology and Environmental Overviews: Coal
Liquefaction. Contract No.68-02-21^2^Hittman
Associates, Inc., Columbia, Maryland.
41. Nelson, W.L. 1958. Petroleum Refinery Engineering.
McGraw-Hill Book Company, New York.pp. 305-309.
42. Perry, R.H. and C.H. Chilton eds. 1973. Chemical
Engineer's Handbook, 5th Edition. McGraw-Hill Book
Company, New York.
43. Design information provided by Mr. Joseph O'Brien,
Sandvik Corporation, Fairlawn, New Jersey.
44. American Gas Association. 1965. Gas Engineers Handbook.
Industrial Press, Inc., New York.
45. U.S. Environmental Protection Agency. 1977. Draft
Report Technology and Environmental Overview: Coal
Liquefaction. Contract No. bX-UZ-'ZlW. HTftman
Associates, Inc., Columbia, Maryland.
273
-------
46. Farnsworth, J.F., D.M. Mitsak and J.F. Kamody. "Clean
Environment with Koppers-Totzek Process." Presented at
the EPA Symposium on Environmental Aspects of Fuel
Conversion Technology, St. Louis, Missouri. May 1974.
47. U.S. Environmental Protection Agency. 1976. Draft;
The Stretford Process, A Report for the Environmental
Protection Agency"! Catalytic, Inc., Wilsonville,
Albama.
48. Cost Information on incinerators provided by Mr. Ralph
Stettendenz, The Air Preheater Company, Inc., Wellsville,
New York.
49. Cost Information on carbon adsorption systems provided
by Ray Solv, Incorporated, Linden, New Jersey.
50. Riegel, E.R. 1942. Industrial Chemistry. Reinhold
Publishing Company, New York.
51. Cost Information on lime recalcination systems, clarifiers,
pressure filters and gravity filters provided by the
Permutit Company, Silver Spring, Maryland. October 18,
1977.
52. Rice, J.K. and S.D. Strauss. April 1977. Water
pollution control in steam plants. Power 120(4):51-
520.
53. Bureau of National Affairs, Inc. Environmental Reporter
- State Water Laws.
54. McGlamery, G.G. and R.L. Torstrick. 1974. "Cost
Comparisons of Flue Gas Desulfurization Systems."
Presented at the Symposium on Flue Gas Desulfurization,
Atlanta, Georgia. November 1974.
55. Cost Information on steam strippers provided by
Harrington-Rogg Company, Lawrence, New Jersey, October
12, 1977.
56. Cost Information on dissolved air flotation provided by
Denver Equipment Company, Denver, Colorado. October
10, 1977.
57. Cost information on API Separators provided by AFL
Industries, Inc., Chicago, Illinois, October 12, 1977.
274
-------
58. Cost information on aeration equipment provided by
Infilco Degremont, Inc., Richmond, Virginia. October
20, 1977.
59. U.S. Environmental Protection Agency. 1976. Flare
Systems Study. EPA 600/2-76-079.
60. Cleland, J.G., and G.L. Kingsbury. November 1977.
Multimedia Environmental Goals for Environmental
Assessment, Volume I and Volume II: MEG Charts and
Background Information. U.S. Environmental Protection
Agency. EPA-600/7-77-136a and EPA-600/7-77-136b.
61. U.S. Energy Research and Development Administration.
1977. Toxic Trace Pollutant Coefficients for Energy
Supply and Conversion. Contract No! EX-77-C-03-1296.
Hittman Associates, Inc., Columbia, Maryland.
62. U.S. Energy Research and Development Administration.
1976. Quarterly Report, Characterization of Substances
in Products, Effluents and Wastes from Synthetic Fuel
Production Tests. BNWL~T2"24. Battelle Pacific Northwest
Laboratories, Richland, Washington.
63. Filby, R.H., K.R. Shah, and C.A. Sautter. Trace
Elements in Solvent Refined Coal Process, A Renewal
Proposal Submitted to Pittsburgh and Midway Coal Mining
Company by the Nuclear Radiation Center, Washington
State University, Pullman, Washington.
64. Electric Power Research Institute. 1975. Status of
Wilsonville Solvent Refined Coal Pilot Plant, Research
Project 1234: Interim Report. Southern Services, Inc.,
Birmingham, Alabama.
65. Bureau of National Affairs, Inc., Environmental Reporter-
Federal Laws and Regulations.
275
-------
11.0 Bibliography
Braunstein, H.M., E.D. Copenhaver, and H.A. Pfuderer, eds.
1977. Environmental, Health and Control Aspects of Coal
Conversion!An Information Overview (2 Volumes). Oak Ridge
National Laboratory, Oak Ridge, Tennessee.
Canessa, W. 1977. Chemical retardants control fugitive
dust problems. Pollution Engineering 7(7):24-26.
Cuffe, S.T., R.W. Gerstle, A.A. Orning, and C.H. Schwartz.
1964. Air pollutant emissions from coal-fired power plants;
Report No. 1, Journal of the Air Pollution Control Association.
14(9):353-362.
The Bureau of National Affairs. Environmental Reporter.
Fleming, D.K. 1975. "Purification of Intermediate Streams
from Coal Gasification." Presented at the IGT Symposium on
Clean Fuels from Coal, Chicago, Illinois, June 23-27, 1975.
Filby, R.H., and K.R. Shah. 1977. "Trace Elements in the
Solvent Refined Coal Process." Presented at the EPA Symposium
on Environmental Aspects of Fuel Conversion Technology III.
September 13-16, 1977. Hollywood, Florida.
Fossil Energy Research and Development Administration. 1977.
Environmental Review: Solvent Refined Coal Pilot Plant, Fort
Lewis, Washington. FERDA, Washington, DC.
Gehrs, C.W. 1977. "A Conceptual Approach to Evaluating
Liquid Effluents from Synthetic Fuel Processes." Presented
at the Symposium on Management of Residuals from Synthetic
Fuels Production. Denver Research Institute, May 23-27, 1977.
Green, R. 1977. Utilities scrub out SOx. Chemical
Engineering. 84(11):101-103.
United States Environmental Protection Agency. 1975.
Characterization and Utilization of Municipal and Utility
Sludges and Ashes. Volume III - Utility Coal Ash. Dayton
University, Dayton, Ohio.
Hutchins, R.A. 1975. Thermal regeneration cost. Chemical
Engineering Progress, 71(5).
276
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Klemetson, S.L. 1977. "Treatment of Phenolic Wastes,"
Presented at the EPA Symposium on Environmental Aspects of
Fuel Conversion Technology III, September 13-16, 1977
Hollywood, Florida.
Kuhn, J.K., D. Kidd, J. Thomas, et al. 1977. "Volatility
of Coal and Its By-Products." Presented at the EPA Symposium
on Environmental Aspects of Fuel Conversion Technology,
September 13-16, 1977, Hollywood, Florida.
Leonard, J.W. and D.R. Mitchell, eds. 1968. Coal Preparation.
The American Institute of Mining, MetallurgicaT~and Petroleum
Engineers, Inc., New York.
Lund, Herbert F. ed. 1971. Industrial Pollution Control
Handbook. McGraw-Hill, New York"!
Michel, R.L. 1970. Costs and manpower for municipal
wastewater treatment plant operation and maintenance, 1965-
1968. Journal WPCF, 42 (11).
Morrison, R.T., and R.N. Boyd. 1959. Organic Chemistry.
Allyn and Bacon, Inc., Boston, Massachusetts.
Papamarcos, John. 1977. Stack gas cleanup, Power Engineering,
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Parker, C.L. and C.V. Fong. 1976. Estimation of operating
costs for industrial wastewater treatment facilities. AACE
Bulletin, December 1976.
Parker, C.L. 1976. Investment cost estimation for environ-
mental impact analysis. AACE Bulletin.
Patterson, W.L. and R.F. Banker. 1971. Estimating Costs
and Manpower Requirements for Conventional Vastewater
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Water Pollution Control Research Series No. 17090 DAN 10/71.
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McGraw-Hill Book Company, New York.
Prussner, R.D. and L.P. Broz. 1977. Air pollution control:
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277
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Public Health Service Drinking Water Standards 1962, U.S.
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Radian Corporation. 1977. Assessment of Technology for
Control of Toxic Effluents from the Electric Utility Industry
(EPA Draft).
Radian Corporation. 1977. Technology Status Report: Low/Medium
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Volume II - Appendices A-F.
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the Third Annual International Conference on Coal Gasification
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Fuel fromToaT, Vol, III - Pilot Plant Development Work,
Part 3: Startup and Operation of the SRC~Pilgt PlantTFE
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U.S. Energy Research and Development Administration. 1977.
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March 19TTFE 496-134~^The Pittsburgh and Midway Coal
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Batteries~lndustries, EPA SW 102C.
U.S. Environmental Protection Agency. 1976. Methods to
Control Fine-Grained Sediments Resulting from Construction
Activity" EPA 440/9-7-76, Hittman Associates, Inc. ,
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and Pollution Control in Coal Conversion Processes. EPA
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279
-------
12.0 Glossary
Auxiliary Process: Processes associated with a technology
which are used tor purposes that are in some way incidental
to the main functions involved in transformation of raw
materials into end products. Auxiliary processes are used
for recovery of by-products from waste streams, to furnish
necessary utilities, and to furnish feed materials such as
oxygen which may or may not be required depending on the
form of the end product which is desired; e.g., the auxiliary
processes for low-and medium-Btu gasification technology
include: (1) oxygen plant which is used only for medium-Btu
gas; (2) the Stretford plant used to recover sulfur compounds
from gaseous waste streams, etc.
By-Product Streams: Discharge streams from which useful
materials are recovered to: (1) eliminate undesirable environ-
mental discharges; or (2) recover valuable materials which are
most economically isolated from process input stream after it
has been physically or chemically transformed; e.g., sulfur
is recovered as a by-product from coal gasification to prevent
pollution while vanadium is recovered from the ash generated
by the burning of residual oil to produce electricity because
it is profitable to do so.
Closed Process; For the purposes of this report, a closed
process signifies a process which has no waste streams.
Coefficient of Runoff: An empirical constant developed for
the purpose of predicting the amount of stormwater runoff
as a function of average rainfall intensity and drainage
areas. The mathematical relationship is as follows:
Q = CIA
where: Q = maximum rate of runoff, cubic feet per second
(cubic meters per second).
C = coefficient of runoff based on type and character
of surface
I = average rainfall intensity, inches per hour
(centimeters per hour)
A = drainage area, acres (square meters).
280
-------
Control Equipment: Equipment whose primary function is to
reduce the offensiveness of waste streams discharged to the
environment. It is not essential to the economic viability
of the process, e.g. if the recovery of sulfur from gas
cleaning operations associated with coal gasification involves
the use of a Stretford plant. The Stretford process is an
auxiliary process and is not control equipment. An incinera-
tor used to clean the tail gas from the Stretford unit would
be considered control equipment.
Discharge: The release of pollutants to the environment in
the most general sense. Usually applied to intermittent or
accidental releases.
Effluent: A discharge of pollutant into the environment.
Usually applied to continuous wastewater streams.
Emission: A discharge of pollutants into the environment.
Usually applied to continuous atmospheric waste streams, but
can be applied to water and solid waste streams also.
Energy Technology: A technology is made of systems which
are applicable to the production of fuel or electricity from
fossil fuels, radioactive materials, or natural energy
sources (geothermal or solar). A technology may be applicable
to extraction of fuel, for example, underground gasification;
or processing of fuel, for example, coal liquefaction, light
water reactor, conventional boilers with flue gas desulfuri-
zation.
Final Disposal Process: Processes whose function is to
ultimately dispose of solid or liquid waste containing
materials which have potential for environmental contamina-
tion. The waste materials treated emanate from the collection
of process waste streams for final disposal or from treatment
of waste streams using control equipment to collect and
concentrate the potential pollutants which are subsequently
sent to final disposal. Examples of final disposal processes
are landfills, lined ponds, etc.
Flottazur; Dissolved air flotation unit.
Fugitive Emissions: Those emissions of air pollutants not
directed through ducts or stacks and not amenable to measure-
ment by established source sampling methods.
281
-------
Input Streams: Materials which are supplied to a process
in performance of its intended function. Input materials
will consist of primary raw materials, secondary raw materials,
or intermediate products.
Intermediate Products: Process output streams that feed from
one process to another within a technology for further pro-
cessing with another technology; for example, for the low-
and medium-Btu gasification technology, gasification converts
pretreated coal into raw gas which is an intermediate product
input to gas cleaning. Where an intermediate product is
further processed using a different technology it becomes a
secondary raw material which is described below.
LD5Q (Lethal dose, 50%): That quantity of a substance ad-
ministered either orally or by skin contact necessary to kill
50% of exposed animals in laboratory tests within a specified
time.
Opacity Rating: A measurement of the opacity of emissions,
defined as the apparent obscuration of smoke of a given
rating on the Ringelmann chart.
Operation: A specific function, associated with a technology
in which a set of processes are employed to produce similar
products starting from the same input material; e.g., some
operations associated with the technology for coal lique-
faction are: (1) coal preparation where the processes employed
are receiving, crushing and sizing, drying, and slurry mixing.
These processes will be used in different combinations dictated
by the type of coal processed; (2) hydrogenation which can be
accomplished using any of six hydrogenation processes; and
(3) gas purification, where different processes are employed
for pressurized vs. atmospheric systems, cleanup of gases
containing tar vs. cleanup of tar-free gas, etc.
Output Streams: Discharges from a process which are either
end products, intermediate products, by-product streams or
waste streams. '
Plant: An existing system which has been defined with the
specificity necessary to make it workable under conditions
SffSS? rLlPa?±CUlarf Site' Any Plant or system may use
H™?^ Combinations of Processes as illustrated above
However, all will be comprised of some combination of nro-
tlchnoiogyhe C°mbinatio* of Pl-nts and systems^ke^p'the
282
-------
Primary Raw Materials; Materials which are extracted (coal,
ores, etc.) or grown and harvested (trees, corn, etc.) and
processed to yield intermediate or end products. For energy
technologies the principal raw materials are fossil fuels,
ores for nuclear fuels, geothermal deposits, sunlight.
Process: Processes are basic units which make up an operation
A process is employed to produce chemical or physical trans-
formations of input materials into end products, intermediate
products, or by-products. Every process has a definable set
of waste streams which are, for practical purposes, unique.
The term used without modifiers is used to describe generic
processes. Where the term is modified, such as, for example,
in the term "Lurgi process", reference is made to a specific
process which falls in some generic class consisting of a
set of similar processes; for example, the low-and medium-
Btu gas technology includes the fixed-bed, atmospheric, dry
ash gasifier as one of the gasification processes. Specific
processes which are included in this generic class are
Wellman-Galusha, Woodhall-Duckham/Gas Integrale, Chapman
(Wilputte), Riley-Morgan, and Foster-Wheeler Stoic.
Process Module: A representation of a process which is used
to display input and output stream characteristics. When
used with other necessary process modules, they can be used
to describe a technology, a system or a plant.
Residuals: Uncollected discharges from control equipment used
to treat waste streams or discharges from final disposal pro-
cesses which are used for ultimate disposal of waste material;
for example, traces of pollutant that pass through a scrubber
cleaning the tail gas from the Glaus plant used in coal
gasification are residuals. If a scrubber is used to clean
the Glaus unit tail gas and a bleed stream is sent to a
lined pond serving as a final disposal process, any runoff
to the environment would be a residual.
Ringelmann Chart: A chart used in air pollution evaluation
for assigning an arbitrary number, referred to as the smoke
density, to smoke emanating from any source.
283
-------
Secondary Raw Materials: Materials which are output from one
technology and input for another. For the technology with
which it is produced, it is an intermediate product. For
the technology associated with further processing, it is a
secondary raw material; for example, liquid fuel from coal
is an intermediate product from coal liquefaction and,
if it is burned utilizing a technology associated with^
production of electricity, it is a secondary raw material.
Six-tenths Factor: A logarithmic relationship between equip-
ment size and cost, used to adjust one set of estimates to
a different design size. The simple form of the six-tenths
factor is
where Cn is the new cost, C is the previous cost, and r is
the ratio of new to previous capacity.
System; A set of operations which are representative of a
unique combination which is likely to be employed to accomplish
a specific objective of a technology; e.g., for coal lique-
faction technology, over twenty systems make up the technology.
Examples include SRC, H-Coal, and Exxon Donor Solvent Systems.
Threshold Limit Value (TLV) : A set of standards established
by the American Conference of Governmental Industrial Hygienists
for concentrations of airborne substances in workroom air.
They are time-weighted averages based on conditions which it is
believed that workers may be repeatedly exposed to day after
day without adverse effects. The TLV values are intended to
serve as guides in control of health hazards, rather than
definitive marks between safe and dangerous concentrations.
Waste Streams: Nonproduct output streams from which no by-
products are recovered. Waste streams may contain potential
pollutants for the air, water or land. The consumption of
products results in generation of waste streams. Both pro-
cesses and auxiliary processes produce waste streams which go
directly to a final disposal process or are cleaned with con-
trol equipment which collects pollutants which are sent to a
final disposal process.
284
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APPENDICES
A. METRIC CONVERSION FACTORS
B. FEDERAL AND STATE REGULATIONS
285
-------
APPENDIX A. METRIC CONVERSION FACTORS
To Convert From
ft/a'
To
Acceleration
2 2
metre per second (m/s )
Multiply By
3.048-000 E-01
Area.
Acre (U.S. survey)
ftg
in9
yd2
12
metre
metre
metre
metre^ (m9)
2;
{^2^
metre" (m )
Energy (Includes Work)
British thermal unit
(mean) joule (J)
Calorie (kilogram, mean) joule (J)
kilocalorie (mean) joule (J)
foot
inch
yard
grain
grain
pound (Ib avoirdupois)
ton (metric)
ton (short, 2000 Ib)
lb/ft'
Length
metre (m)
metre (m)
metre (m)
Mass
kilogram (kg)
kilogram (kg)
kilogram (kg)
kilogram (kg)
kilogram (kg)
Mass Per Unit Area
/
kilogram per^metre'
(kg/D/)
4.046 873 E+03
9.290 304 E-02
6.451 600 E-04
8.361 274 E-01
1.055 87 E+03
4.190 02 E+03
4.190 02 E+03
3.048 000 E-01
2.540 000 E-02
9.144 000 E-01
6.479 891 E-05
1.000 000 E-03
4.535 924 E-01
1.000 000 E+03
9.071 847 E+02
4.882 428 E+00
286
-------
APPENDIX A. METRIC CONVERSION FACTORS (Continued)
To Convert From
To
Ib/ft
Ib/in
Mass Per Unit Length
kilogram per metre (kg/m)
kilogram per metre (kg/m)
Mass Per Unit Time (Includes Flow)
Ib/h
Ib/min
ton (short)/h
kilogram per second (kg/s)
kilogram per second (kg/s)
kilogram per second (kg/s)
Multiply By
1.488 164 E+00
1.785 797 E+01
1.259 979 E-04
7.559 873 E-03
2.519 958 E-01
Mass Per Unit Volume (Includes Density & Mass Capacity)
3 33
Ib/ft kilogram per metre-, (kg/mo)
Ib/gal (U.S. liquid) kilogram per metre, (kg/m,,)
Ib/yd3 kilogram per metre (kg/m )
Btu (thermochemical)/h
Btu (thermochemical)/h
cal (thermochemical)/
min
cal (thermochemical)/s
Power
watt (W)
watt (W)
watt (W)
watt (W)
Pressure or Stress Choree Per Unit Area)
atmosphere (standard) pascal (Pa)
foot of water (39.2°F) pascal (Pa)
Ibf/ft2 pascal (Pa)
lbf/in2 (psi) pascal (Pa)
1.601 846 E+01
1.198 264 E+02
5.932 764 E-01
2.930 711 E-01
2.928 751 E-01
6.973 333 E-02
4.184 000 E+00
1.013 250 E+05
2.988 98 E+03
4.788 026 E+01
6.894 757 E+03
degree Celsius
degree Fahrenheit
degree Fahrenheit
degree Rankine
Kelvin
Temperature
Kelvin (K)
degree Celsius
Kelvin
Kelvin
(K)
(K)
degree Celsius
tor + 273.15
=(t0?-32)/1.8
.67)/l,8
; 8
287
-------
APPENDIX A. METRIC CONVERSION FACTORS (Continued!
To Convert From
ft/h
ft/min
ft/s
in/s
centipoise
centistokes
poise
stokes
acre-foot (U.S. survey) metre:
barrel (oil, 42 gal) metre;
ft3 metre:
gallon (U.S. liquid) metre:
litre* metre'
To
Velocity (Includes Speed)
metre per second (m/s)
metre per second (m/s)
metre per second (m/s)
metre per second (m/s)
Viscosity
pascal second (Pa-s)~
metre^ per second (m /s)
pascal second (Pa-3)2
metre^ per second (m /s)
Volume (Includes Capacity)
T -3
~j / -j \
ft~/min
ftj/s
Volume Per Unit Time (Includes Flow)
3 3
metre-, per second (m^/s)
metre,, per second (m^/s)
gal (U.S. liquid/day) metre- per second (m^/s)
gal (U.S. liquid/min) metre per second (m/s)
Multiply By
8.466 667 E-05
5.080 000 E-03
3.048 000 E-01
2.540 000 E-02
1.000 000 E-03
1.000 000 E-06
1.000 000 E-01
1.000 000 E-04
1.233 489 E+03
1.589 873 E-01
2.831 685 E-02
3.785 412 E-03
1.000 000 E-03
4.719 474 E-04
2.831 685 E-02
4.381 264 E-08
6.309 020 E-05
*In 1964 the General Conference on Weights and Measures adopted
the name litre as a special name for the cubic decimetre.
Prior to this decision the litre differed slightly (previous
value, 1.000028 dm3) and in expression of precision volume
measurement this fact must be kept in mind.
288
-------
APPENDIX B. FEDERAL AND STATE REGULATIONS
The following consists of two sections: (1) Federal
regulations, and (2) Selected state regulations. Federal
regulations have been discussed in Chapter 4 of this report.
Emission standards and effluent guidelines for air and water
pollutants and solid wastes are given in Tables 81 through
84.
Section 2 presents environmental policies of 16 states,
other than Illinois, abundant in coal reserves and therefore
possessing potential for commercial siting of an SRC plant.
Emphasis is placed on standards and guidelines which are
more stringent than their federal counterparts or are in-
volved with areas for which no federal legislation exists.
Regulations applying to environmentally sensitive areas with
state boundaries are also included.
289
-------
Key to symbols and abbreviations applicable to all
tables of the Appendix.
max
AAM
AGM
*
JTU
COH/10QO LM
COH/1000 LF
Denotes maximum
Denotes Annual Arithmetic Mean
Denotes Annual Geometric Mean
Denotes that the maximum values is not
to be exceeded more than once per year.
Denotes Jackson Turbidity Units
Denotes Coefficient of Haze per 1000
linear meters
Denotes Coefficient of Haze per 1000
linear feet
290
-------
1. FEDERAL REGULATIONS
291
-------
TABLE 81 NATIONAL PRIMARY AND SECONDARY AMBIENT
AIR QUALITY STANDARDS (65)
Constituent
Concentration
Metric English
Remarks
Sulfur Oxides
primary
secondary
Particulates
primary
secondary
Carbon Monoxide
primary and
secondary
Photochemical Oxidants
primary and
secondary
Hydrocarbons
primary and
secondary
Nitrogen Dioxide
primary and
secondary
80 ug/m3
365 ug/m:;
1300 ug/nr
75 ug/m-
260 ug/mg
60 ug/rru
150 ug/nr
3
10 ug/mq
40 ug/nr
160 ug/m3
160 ug/m3
100 ug/m3
9. 4x1 0~~ grain/yd3
4.3x10 '^grain/yd:;
1 .5x10" grain/yd
8.8xl0^grain/yd3
3. 1x10", grain/yd-
7.1x10 ,,grain/ydo
1.8x10" grain/yd
0.12 grain/yd3,
0.79 grain/yd15
1.9xlO"3grain/yd3
1.9xlO"3grain/yd3
1.2xlO"3grain/yd3
A. A.M.
24 hr max*
3 hr max*
A.G.M.
24 hr max*
A.G.M.
24 hr max*
8 hr max*
1 hr max*
1 hr max*
3 hr max*
(6-9 A.M.)
A. A.M.
Reference Conditions: Temperature = 25°C = 77°F
Pressure = 760 mm Hg = 29.92 in Hg = 1 atmosphere
292
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TABLE 82. FEDERAL NEW SOURCE PERFORMANCE
STANDARDS OF RELATED TECHNOLOGIES (65)
Coal Preparation - Particulates
Type of Equipment
Thermal Dryers
Coal Cleaning
Processing. Convevina
and Storage
Fossil Fuel Steam Generators
Constituent
Particulates
Metric
0.057 mg/m-
0.033 mg/m
Metric
0.17 kg/10*?
Standard
English
2.2xlO-jgrain/yd^
1.3xlO"Vain/ydJ
Standard
English
kcal 0.10 Ib/lO^Btu
Opacity
20%
10%
?n°/
C.\Jh
Opacity
20% (1)
Sulfur Dioxide (solid fuels) 2.07 kg/10^kcal 1.21 Ib/lCEBtu
Nitrogen Oxides (solid fuels) 1.21 kg/10 kcal 0.70 lb/10 Btu
Petroleum Liquid Storage Vessels
Constituent
Hydrocarbons
Vapor Pressure
Requirement
Metric
78-570 mm Hg
570 mm Hg
English
3.0-22.4 in Hg
22.4 in Hg
(2)
(3)
(1) 40% opacity allowed 2 minutes/hr
(2) floating roof or vapor recovery system or equivalent
(3) vapor recovery system or equivalent
293
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TABLE 83. FEDERAL EFFLUENT GUIDELINES AND
STANDARDS FOR NEW SOURCES (65)
Coal Preparation
Concentration
Constituent
Total Iron
Total Manganese
Total Suspended Solids
1 day
mg/1
7.0
4.0
20.0
maximum
grain/gallon
0.41
0.23
1.17
30 day
mq/1
3.5
2.0
35.0
average
qrain/qallon
0.20
0.12
2.04
pH range: 6.0-9.0
By-Product Coking
Constituent
Cyanide A
Phenol
Ammonia
Sulfide
Total Suspended
Solids
pH range: 6.0-9.0
Concentration
1 day maximum
kg/kkgTb/ton
30 day average
3 x 10
-4
3 x 10
3.12 x 10
-4
-2
7.26 x 10
-4
kg/kkg
1 x 10
-4
7.26 x 10
7.55 x 10
-4
-2
1.04x10
-4
-2
Ib/ton
2.42 x 10
-4
6 x 10"4 1.45 x 10"3 2 x 10"4 4.84 x 10"4
1.26 x 10"2 3.05 x 10"2 4.2x 10"3 1.02 x 10"3
1 x 10"* 2.42 x 10"4
2.52 x 10
-4
294
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TABLE 84. SOME EPA REQUIREMENTS AND
RECOMMENDATIONS FOR SOLID WASTES (64)
Aspect of Disposal
Requirement
Recommendations
Design
approval by
professional engineer
and responsible
agency
analysis of solid
waste materials;
maintenance program;
projection of
subsquent use
Water Quality
compliance with Federal
Water Pollution Control
Act
projections of solid
waste-soi1-groundwater
relationship
Air Quality
compliance with clean
air act, state and
local laws
dust control program
Gas Control
on-site control of
decomposition gases
preventing gas from
concentrating to
prevent explosions
and toxicity hazards
Cover Material
cover shall be applied
as necessary to
minimize fire, odors,
dust, etc.
minimum of 2 ft.
final cover
Compaction
compaction to the
smallest practicable
volume
maximum depth of
solid waste layers
(2 ft)
2-95
-------
2. SELECTED STATE POLICIES
296
-------
ALASKA C53)
Ambient air quality standards and standards for indus-
trial process emissions have been established. Table 85
shows the standards and reference conditions. Emissions
standards for industrial processes are described in
Table 86.
Water quality parameters are dependent on water uses,
which range from potable water to industrial water. Table
87 defines the standards required for various parameters
such as pH, dissolved organics, etc. for these water use
classifications.
Regulations for the management of solid waste are
directed primarily toward municipal wastes rather than
industrial. Should leaching or permafrost prove a problem,
special disposal procedures must be submitted to the Depart-
ment of Environmental Conservation. A minimum of two feet
of earth must be maintained between solid wastes and the
anticipated high ground water table. Surface drainage must
be prevented from coming into contact with the landfill
area. Solid waste may be landfilled in layers of not more
than two feet prior to compaction.
ARIZONA (53)
In addition to having ambient air quality standards
Arizona has source emissions standards for particulates,
sulfur compounds, and volatile organic compounds. These
values are presented in Tables 88 and 89. State goals for
ultimate achievement have also been established. They are
included in Table 88.
Water standards are established for surface waters with
specific uses. Applicable standards for domestic and in-
dustrial waters are compiled in Table 90.
Solid waste legislation lags behind the other areas.
Daily landfill covers 6 to 12 inches are required. The
final cover must be a minimum of two feet deep.
297
-------
TABLE 85. AMBIENT AIR QUALITY STANDARDS IN ALASKA
Constituent
Particulates
Sulfur Oxides
Carbon Monoxide
Photochemical Oxidants
Nitrogen Dioxide
Reduced Sulfur Compounds
Maximum Concentration Allowed
Metric
60 ug/m3
150 ug/m3
80 ug/m3
365 ug/m3
1300 ug/m3
10 ug/m3
40 ug/m3
160 ug/m3
100 ug/m3
50 ug/m3
English
7.1xlO"4grain/yd3
1.8xlO"3grain/yd3
9.4xlO~4grain/yd3
4.3xlO"3grain/yd3
1.5xlO"2grain/yd3
0.12 grain/yd3
0.47 grain/yd3
1.9xlO"3grain/yd3
1. 2x1 0"3gra in/yd3
6.0xlO"4grain/yd3
Remarks
A.G.M.
24 hr max*
A. A.M.
24 hr max*
3 hr max*
8 hr max
1 hr max
1 hr max
A. A.M.
30 min max
Reference Conditions: Temperature = 21°C = 70°F
Pressure = 1.03 kg/cnT = 14.7 psi = 1 atmosphere
298
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TABLE 86. EMISSIONS STANDARDS FOR INDUSTRIAL
PROCESSES AND FUEL BURNING EQUIPMENT IN ALASKA
Visible Emissions
20% opacity+
Participate Matter
(coal burning equipment)
4.24 mg/m3 (0.05 grain/ft3)
Sulfur Compounds (as S02) 500 ppm
+denotes that the standard may not be exceeded for a total of more
than three minutes in any hour.
299
-------
TABLE 87.. WATER QUALITY CRITERIA OF ALASKA
Parameter
Dissolved Oxygen
Water Classification
Potable Water
industrial Water
75% saturation or 5 mg/T = 0.29 grain/gal
5 mg/1 =0.29 grain/gal for surface water
pH and (pH change)
6.5-8.5 (0.5 units)
6.5-8.5 (0.5 units)
Turbidity
5 JTU
No interference with
water supply treatment
Temperature
16°C = 60°F
21°C = 70°F
Dissolved Inorganic
Substances
500 mg/1 = 29 grain/gal
low enough to prevent
corrosion, scaling
and process problems
Residues, Oils,
Grease, Sludges, Other
Physical and Chemical
Criteria
essentially free from;
may not exceed 1962
USPHS Standards
(see Table 87)
No visible evidence
of residue, may not
impact public health
300
-------
TABLE 88. AMBIENT AIR QUALITY STANDARDS OF ARIZONA
Constituents
Particulates
Sulfur Dioxide
Non-Methane Hydrocarbons
Photochemical Oxidants
Carbon Monoxide
Nitrogen Dioxide
Air Quality Goals
Constituent
Particulates
Non-Methane Hydrocarbons
Carbon Monoxide
Photochemical Oxidants
Standard Conditions:
Concentration
Metric
60 ug/m3
150 ug/m3
50 ug/m3
260 ug/m3
1300 ug/m3
160 ug/m3
160 ug/m3
40 mg/m
10 mg/m
100 ug/m3
Metric
100 ug/m3
80 ug/m3
7 mg/m
80 ug/m3
Temperature = 16°C
Pressure = 1.03
English
7.1xlO"4grain/yd3
1.8xlO"3grain/yd3
6.0xlO"4grain/yd3
3.1xlO"3grain/yd3
1.5xlO~2grain/yd3
1.9xlO"3grain/yd3
1.9xlO~3grain/yd3
0.47 grain/yd
0.12 grain/yd3
1.2xlO"3grain/yd3
English
1.2xlO"3grain/yd3
9.4x10 grain/yd
0.083 grain/yd
9.4x10 grain/yd
= 60° F
2
kg/cm = 14.7 psi
Remarks
A.6.M.
24 hr max
1 yr max
1 day max
3 hr max
3 hr max
(6-9 A.M.)
1 hr max
1 hr max
8 hr max
1 yr max
Remarks
24 hr max
3 hr max
(6-9 A.M.)
8 hr max
1 hr max
301
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TABLE 89. INDUSTRIAL EMISSIONS STANDARDS IN ARIZONA
Particulate Emissions - Process Industries - General
E = 55.0 p°J1-40 (E = 17.31 p°'16 for Phoenix-Tucson Air Quality
Control Region)
where
E = max allowable emissions rate (Ib m/hr)
P = process weight rate (ton m/hr)
For commercial SRC plants
20,000 ton/day ,,
E = 55.0 (24 hr/day) "-40 = 75.2 Ib m/hr = 165.4 kg/hr
E = 17.31 p°'16 = 50.8 Ib m/hr = 111.9 kg/hr (Phoenix-Tucson)
Sulfur -other industries
Requirement: a minimum of 90% removal
Storage of volatile organic compounds
(for storage capacities of 65,000 gallons or greater)
Requirement3 A floating roof is required for compounds with vapor
pressures greater than 2 Ib/in but less than
2
12 Ib/in . Equipment of equal efficiency may be
substituted. The pressure range in metric units
is from 0.1406 kg/cm2 to 0.8436 kg/cm2.
302
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TABLE 90.. ARIZONA WATER QUALITY CRITERIA
Substance
Arsenic
Ban" um
Cadmium
Chromium (Hexavalent)
Copper
Cyanide
Mercury
Lead
Phenol
Selenium
Silver
Zinc
Limiting
mg/1
0.05
1.0
0.01
0.05
1.0
0.2
0.005
0.05
0.001
0.01
0.05
5.0
Concentration
grain/gallon
0.0029
0.0584
0.0006
0.0029
0.0584
0.0117
0.0003
0.0029
5.8xlO"5
0.0006
0.0029
0.2921
For waters supporting aquatic life the following standards exist:
pH; 6.5 to 8.6 with no discharge causing a change in pH of more
than 0.5 pH units.
Temperature: maximum temperature= 34°C = 93°F
maximum temperature increase= 2.8°C = 5°F
303
-------
COLORADO (53)
Colorado has enacted standards of performance for new
stationary sources. Of these, the standards of performance
for petroleum refineries is probably most indicative of
future legislation. These standards are reviewed in Table
91. Of particular interest in Colorado legislation pertaining
to oil-water separators. SRC pilot plants use similar
equipment. One or more of the following vapor loss controls
is required: a solid cover, a floating roof, a vapor recovery
system, or special equipment which can demonstrate equal or
superior efficiency.
Both effluent limitations and water quality standards
have been promulgated. As Table 92 shows, the standards are
stringent for all classes of water. Effluent limitations
also are presented in Table 93. Solid waste requirements
are not as rigorous. Compaction of wastes is required.
INDIANA (53)
In addition to legislating ambient air quality standards
(Table 94) Indiana has laws controlling the storage and
handling of volatile hydrocarbon liquids. A vapor recovery
system, floating roof or alternative system which meets
approval of the proper state agencies is required. Volatile
organic liquid - water separators require either a solid
cover or one of the vapor control methods required for
storage systems.
Indiana water quality standards state criteria to be
considered when determining a mixing zone but prescribe no
absolute zone, reasoning that too many variables are in-
volved. Pertinent water quality criteria are outlined in
Table 95.
Prior to the issuing of permits to operate landfills, a
detailed plan of the operation must be submitted to and
approved by the appropriate state agencies.
304
-------
TABLE 91, STANDARDS OF PERFORMANCE FOR PETROLEUM
REFINERIES IN COLORADO
Parti ciilates
1 kg/metric ton = 1 lb/1000 Ib
30% opacity for greater than 3 minutes in any hour is not allowed.
Failure to comply due to uncombined water is not a violation.
Carbon Monoxide
Discharge gases may not contain greater than 0.050% carbon
monoxide by volume.
Sulfur Dioxide
Emissions may not exceed those resulting from fuel gas containing
230 mg/dscm (0.1.0 grain/dscf) of hydrogen sulfide.
305
-------
TABLE 92. COLORADO WATER QUALITY STANDARDS
Water Classification
Standard
Settleable Solids,
Al
Free From
A2
Free From
Bl
Free From
B2
Free From
Floating Solids,
Taste, Odor, Color,
and Toxic Materials
Oil and Grease
No film or No film or No film or No film or
discoloration discoloration discoloration discoloration
Turbidity Increase
10 J.T.U.
10 J.T.U. 10 J.T.U.
10 J.T.U.
Dissolved Oxygen
(minimum)
6 mg/1
0.35 grain/
gallon
5 mg/1 6 mg/1
0.29 grain/ 0.35 grain/
gallon gallon
5 mg/1
0.29 grain/
gallon
pH Range
6.5-8.5
6.5-8.5
6.0-9.0
6.0-9.0
Temperature, Maximum 20°C
68°F
32°C
90° F
20°C
68° F
32°C
90°F
Temperature
Maximum Increase
2°F
Streams
2.8°C
5°F
Lakes
1.7°C
3°F
2°F
Streams
2.8°C
5°F
Lakes
1.7°C
3°F
306
-------
TABLE 93. COLORADO EFFT.TTF.NT DISCHARGE CRITERIA
Parameter 7 day avg. 30 day avg.
mg/1 grain/gal. mg/1 grain/gal
BOD5 45 2.63 30 1.75
Suspended Solids 45 2.63 30 1.75
Residual Chlorine 0.5 mg/1 = 0.03 grain/gal.
Oil and Grease 10 mg/1 = 5.84 grain/gal.
pH range 6.0-9.0
307
-------
ILLINOIS (53)
Comprehensive air and water standards have been promul-
gated by the Illinois Pollution Control Board. _New fuel_com-
bustion emissions sources encompassing sulfur dioxide, nitro-
gen oxides, carbon monoxide, fugitive particulate matter and
particulate emissions are listed in Table 96. Regulations
regarding the emissions of organic materials from oil/water
separators, storage tanks, and loading operations have also
been adopted. Air quality standards for Illinois are given
in Table 97.
Water quality standards and effluent standards are
given in Tables 98 and 99, respectively. The rules and
regulations indicate that dilution of the effluent from a
treatment works or from any wastewater source is not accept-
able as a method of treatment of wastes in order to meet the
effluent standards. It is further stated, that the most
technically feasible and economically reasonable treatment
methods should be employed to meet the effluent limitations
specified in Table 99.
Treated effluents are expected not to exceed 30 mg/1
BOD5 and 37 mg/1 suspended solids.
KENTUCKY (53)
Air quality standards are listed in Table 100. Note
that Kentucky has a standard for hydrogen sulfide as well as
for sulfur dioxide. The standards of performance for petroleum
refineries have been compiled in Table 101.
Kentucky water quality standards vary with stream use
classification. Table 102 shows the most stringent standards,
which would be applicable in a multiple-use situation.
Solid waste, requirements include providing more than two
feet of compacted soil between solid waste and maximum water
table, two feet or more of compacted earth between solid
waste and bedrock, solid waste layers of two to three feet
and a final daily cover of six inches to prevent waste
dispersion. A final cover of two feet of compacted soil is
required, to be followed by revegetation.
308
-------
TABLE 94. INDIANA AMBIENT AIR QUALITY STANDARDS
Concentration
Constituent
Sulfur Dioxide
primary
secondary
Parti culates
primary
secondary
Carbon Monoxide
primary and
secondary
Photochemical Oxidants
primary and
secondary
Hydrocarbons
primary and
secondary
Nitrogen Dioxide
primary and
secondary
Metric
0
80 ug /nr
365 ug /m3
60 ug /m3
260 ug /m3
1100 ug/m3
75 ug/m3
260 ug./m3
60 ug /m3
1 50 ug /m
10 mg/m3
40 mg/m
160 ug/m3
1 60 ug /m3
100 ug/m3
English
_A Q
9.4x10 Vain/yd13
4.3xlO"3grain/yd3
7.1xlO"3grain/yd3
3.1xlO"3grain/yd3
? 3
1.3x10 grain/yd
8.8x10 grain/yd
3.1xlO"3grain/yd3
7.1xlO"4grain/yd3
1.8xlO"3grain/yd3
0.12 grain/yd3
o
0.47 grain/yd
1.9xlO"3grain/yd3
1.9xlO"3grain/yd3
1.2xlO"3grain/yd3
Remarks
A. A.M.
24 hr max*
A. A.M.
24 hr max*
1 hr max*
A.G.M.
24 hr max*
A.G.M.
24 hr max*
8 hr max*
1 hr max*
1 hr max*
3 hr max*
(6-9 A.M.)
A. A.M.
Reference Conditions:
Temperature = 25°C = 77°F
Pressure = 760 mmHg = 14.7 psi = 1 atmosphere
309
-------
TABLE 95. WATER QUALITY CRITERIA OF INDIANA
pH: between 6.0 and 8.5
Toxic Substances: shall not exceed one-tenth of the 96-hour median
tolerance limit
Dissolved Oxygen:
Temperature:
5 mg/1 daily average, never less than 4 mg/1
(equivalent to 0.2921 grain/gal and 0.2336 grain/gal
respectively)
Maximum Values Allowed
Month
January
February
March
Apri 1
May
June
July
August
September
October
November
December
Ohio
°C
10
10
16
18
27
31
32
32
31
26
18
14
River
op
50
50
60
70
80
87
89
89
87
78
20
57
St.
°C
10
10
13
18
24
29
29
29
29
18
16
10
Joseph River
°F
50
50
55
65
75
85
85
85
85
70
60
50
°C
10
10
16
18
27
32
32
32
32
26
18
14
Others
°F
50
50
60
70
80
90
90
90
90
78
70
57
Maximum Temperature Rise is: 2.8 °C = 5°F for streams
1.7 °C = 3°F for lakes and reservoirs
(Note: certain parameters are more stringent for waters where natural
reproduction of trout and salmon is to be protected.
310
-------
TABLE 96. APPLICABLE ILLINOIS EMISSIONS REGULATIONS
New Fuel Combustion Emission Sources
Sulfur Dioxide
For actual heat input > 250 M BTU/hr resulting from the
burning of solid fuel exclusively, S02 emissions must not
exceed 1.2 Ib/M BTU.
Nitrogen Oxide
For actual heat input >250 M BTU/hr resulting from the
burning of solid fuel exclusively, NO emissions must not
exceed 0.7 Ib/M BTU.
Carbon Monoxide
For actual heat input i10 M BTU/hr, CO emissions must
not exceed 200 ppm corrected to 50 percent excess air.
Fugitive Particulate Matter
Emissions should not exceed 0.1 Ib/M BTU actual heat
input using solid fuel exclusively over a period of one hour.
Particulates
Discharge of particulates from new process sources during
a one hour period shall not exceed the allowable emission rates
specified by the following equations:
Process weight rate < 450 tons/hr n --,
E = 2.54 (P)0'^
Process weight rate 450 tons/hr n ,,
E - 24.8 (P)°-i6
where
E = allowable emission rate in pounds/hour
P = process weight rate in tons/hour
Waste Gas Disposal
Organics
Emissions from any petroleum or petrochemical manu-
facturing process should not exceed 100 ppm equivalent
methane.
311
-------
TABLE 97. ILLINOIS AIR QUALITY STANDARDS
FOR PARTICULATE MATTER
Standard
Concentrations
Annual Geometric
Mean
Max. 24 hour*
Primary
grain/yd"
75
9.0 x 10
-4
260
3.1 x 10
-3
Secondary
grain/yd'
60
7.1 x 10
-4
150
1.8 x 10
-3
Not to be exceeded more than once per year.
312
-------
TABLE 98. ILLINOIS WATER QUALITY STANDARDS
CONSTITUENT
Ammonia Nitrogen (as N)
Arsenic (total)
Barium (total)
Boron (total)
Cadmium (total)
Chloride
Chromium (total hexavalent)
Chromium (total trivalent)
Copper (total)
Cyanide
Fluoride
Iron (total)
Lead (total)
Manganese (total)
Mercury (total)
Nickel (total)
Phenols
Selenium (total)
Silver (total)
Sulfate
Total Dissolved Solids
*7 — « -*
Zinc
STORET
NUMBER
00610
01000
01005
01020
01025
00940
01032
01033
01040
00720
00950
01045
01049
01055
71900
01065
32730
01145
01075
00945
00515
01090
CONCENTRATION
(Ms/1)
1.5
1.0
5.0
1.0
0.05
500.
0.05
1.0
0.02
0.025
1.4
1.0
0.1
1.0
0.0005
1.0
0.1
1.0
0.005
500.
1000.
1.0
313
-------
TABLE 99. ILLINOIS EFFLUENT STANDARDS
CONSTITUENT
CONCENTRATION (mg/1)
Arsenic (total)
Barium (total)
Cadmium (total)
Chromium (total hexavalent)
Chromium (total trivalent)
Copper (total)
Cyanide
Fluoride (total)
Iron (total)
Iron (dissolved)
Lead (total)
Manganese (total)
Mercury (total)
Nickel (total)
Oil (hexane solubles or equivalent)
PH
Phenols
Selenium (total)
Silver
Zinc (total)
Total Suspended Solids
(from sources other than those covered
by Rule 404)
Total Dissolved Solids
0.25
2.0
0.15
0,3
1.0
1.0
0.025
15.0
2.0
0.5
0.1
1.0
0.0005
1.0
15.0
range 5-10*
0.3
1.0
0.1
1.0
15.0
The pH limitation is not subject to averaging and must be
met at all times.
l+JL*
'"Total Dissolved Solids (STORET Number 00515) shall not be
increased more than 750 mg/1 above background concentration
levels unless caused by recycling or other pollution abate-
ment practices, and in no event shall exceed 3500 mg/1 at any
time; provided, however, this Rule shall not apply to any
effluent discharging to the Mississippi River, which, after
mixing as set forth in Rule 201, meets the applicable water
quality standard for Total Dissolved Solids.
314
-------
TABLE IQQ, AMBIENT AIR QUALITY STANDARDS IN KENTUCKY
Constituent
Sulfur Dioxide
primary
secondary
Particulates
primary
secondary
Particulates
(Soiling Index)
primary
secondary
Carbon Monoxide
primary and
secondary
Photochemical
Oxidants
standard
Hydrocarbons
standard
Metric
80 ug/m~
365 ug/trio
1300 ug/nr
75 ug/m-
260 ug/m:;
60 ug/nu
150 ug/nT
19.7 COH/1000 LM
1.3 COH/1000 LM
1.6 COH/1000 LM
1.0 COH/1000 LM
3
10 ug/nu
40 ug/m
160 ug/m
160 ug/m
Concentration
English
9.4x10"!! grain/yd3,
4.3x10";; grain/yd:?
1.5x10" grain/yd
8.8x10"^ grain/yd3
3.1x10"? grain/yd:;
7.1xlO"~ grain/yd-
1.8xlO~J grain/yd13
6.0 COH/1000 LF
0.4 COH/1000 LF
0.5 COH/1000 LF
0.3 COH/1000 LF
0.12 grain/yd3
0.47 grain/yd
1.9xlO"3 grain/yd3
1.9xlO"3 grain/yd3
Remarks
A. A.M.
24 hr max*
3 hr max*
A.G.M.
24 hr max*
A.G.M.
24 hr max*
24 hr max*
A. A.M.
3 month max
24 hr max*
8 hr max*
1 hr max*
1 hr max*
3 hr max*
(6-9 A.M.)
Nitrogen Dioxide
standard
100 ug/m"
1.2xlO"3 grain/yd3
A.A.M.
315
-------
TABLE 100. AMBIENT AIR QUALITY STANDARDS IN KENTUCKY
(Continued)
Constituent
Concentration
Metric English
Remarks
Hydrogen Sulfide
standard
Gaseous Fluoride
(HF)
primary
Total Fluorides
primary
14 ug/mv
0.82
1.64 ug/rrC
2.86 ug/m,
3.68 ug/nr
40 ppm
60 ppm
80 ppm
1.7xlO"4 grain/yd3
9.7x10"^ grain/yd3
1.9x10"? grain/yd^
3.4xlO~£ grain/yd,
4.3x10"° grain/yd6
1 hr max*
1 month max*
1 week max*
1 day max*
12 hr max*
6 month avg.
2 month avg.
1 month avg.
Reference Conditions: Temperature - 25°C = 77°F
Pressure = 760 mm Hg = 29.92 in Hg = 1 atm.
316
-------
TABLE 101. STANDARDS OF PERFORMANCE FOR PETROLEUM
REFINERIES IN KENTUCKY
Particulates
1.0 kg/metric ton feed
1.0 lb/1000 Ib feed
Carbon Monoxide
0.050% by volume
Sulfur Dioxide
Emissions may not exceed the equivalent of combustion of fuel gas
containing 230 mg/dscm of hydrogen sulfide.
(230 mg/dscm = 0.10 grain/dscf)
317
-------
TABLE ...102. KENTUCKY WATER QUALITY STANDARDS
Concentration
Constituent mg/1 grain/gallon
Arsenic
Barium
Cadmium
Chromium (hexavalent)
Cyanide
Fluoride
Lead
Selenium
Silver
0.05
1.0
0.01
0.05
0.025
1.0
0.05
0.01
0.05
0.0029
0.0584
5. 84x1 O"4
0.0029
0.0015
0.0584
0.0029
5. 84x1 O"4
0.0029
Dissolved Oxygen: 5 mg/1 = 0.2921 grain/gallon daily average
never the less than 4 mg/1 = 0.2336 grain/gallon
Dissolved Solids: 500 mg/1 = 29.21 grain/gal monthly average
never more than 700 mg/1 = 40.89 grain/gallon
Temperature: never to exceed 32°C = 89°F
Maximum Temperature Rise: 2.8°C = 5°F for streams, 1.7°C = 3°F for epilimnion
of thermally stratificated waters
Maximum Monthly Temperature:
Month Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec.
°C 10 10 16 21 27 31 32 32 31 27 ~~2~T 14
°F 50 50 60 70 80 87 89 89 87 78 70 57
318
-------
MONTANA (53)
Montana has adopted the federal new source performance
standards to supplement its own ambient air quality standards.
Applicable ambient standards are presented in Table 103.
Water quality policy consists of general water quality
criteria and specific water quality criteria which correspond
to the various water-use classifications. Table 104 describes
criteria for the most and least stringent classifications to
given in an idea of the range of conditions permitted.
Site approval is required for solid waste disposal when
hazardous wastes are involved. A daily cover of six inches
and final cover of two feet or more are also required.
Disposal sites shall not be located near springs or other
water supplies, near geologic formations which could cause
leaching problems, in areas of high groundwater tables or
within the boundaries of 100-year flood plains.
NEW MEXICO (53)
New Mexico is presently the only state that has promul-
gated emissions standards applicable to coal conversion
facilities, specifically coal gasification plants. Stacks
at least ten diameters tall and equipped with enough sampling
ports and platforms to perform accurate sampling are required.
Particulate emissions requirements exist for briquet forming
areas, coal preparation areas, and the gasification plant
itself - with an additional requirement for gas burning
boilers. Limits have been placed on dischargeable concentra-
tions of sulfur, hydrocarbons, ammonia, hydrogen chloride,
hydrogen cyanide, hydrogen sulfide, carbon disulfide, and
carbon oxysulfide as well. These limits are compiled in
Table 105.
These are stringent criteria, relative to most of the
states reviewed. However a review of New Mexico air laws
pertaining to petroleum refineries reflects an interest in
environmental preservation, not a distrust of new technology.
Emissions standards for ammonia and hydrogen sulfide, for
example, are the same for both industries. In fact, re-
fineries have additional limits on mercaptan and carbon
319
-------
TABLE 103.. AMBIENT AIR QUALITY STANDARDS IN MONTANA
Constituent
Sulfur Dioxide
Hydrogen Sulfide
Fluorides
Settled Particulates
Reactive Sulfur
(so3)
Concentration
0.02 ppm
0.10
0.25
0.03 ppm
0.05 ppm
1.0 ppb
Metric English
2 2
5.26 kg/kmp/month 15 ton/mi ~/month
10.53 kg/km/month 30 ton/mi/month
0.25 mg/100cm2/day 0.036 grain/ft^/day
0.50 mg/1 00cm /day 0.072 grain/ftVday
Remarks
A. A.M.
(1)
(2)
(3)
(4)
24 hr max
(5)
(6)
A. A.M.
1 month max
Metric (ug/nr)
English (grain/yd )
Total Suspended
Particulates
Suspended Sulfate
Sulfuric Acid Mist
Lead
75
200
4.0
12.0
4.0
12.0
30.0
5.0
8.8 x 10"?
2.4 x 10"^
4.7 x 10 ~J
1.4 x 10~Z
4.7 x 10"?
1.4 x 10"J
3.5 x 10";
5.9 x 10"5
A.G.M.
(7)
A. A.M.
(8)
A. A.M.
(8)
1 hr max (8)
3 day max
(1) Not to be exceeded over 1% of the days in avg. 3 month period
(2) Not to be exceeded for more than one hour in avg. 4 consecutive days
(3) Not to be exceeded more than twice in avg. five consecutive days
(4) Not to be exceeded more than twice per year
(5) 3 month average - residential areas
(6) 3 month average - industrial areas
(7) Not to be exceeded more than 1% of the days in avg. year
(8) Not to be exceeded more than 1% of the time
320
-------
TABLE 104. SELECTED WATER QUALITY CRITERIA OF MONTANA
Parameter
E-F Classification
Metric English
A-Closed Classification
Dissolved Oxygen
(minimum value)
3 mg/1 0.18 grain/gal
No decrease allowed
pH
6.5-9.5
No change allowed
pH variation allowed 0.5 pH units
Not allowed
Turbidity, Temperature, Shall cause no adverse
Sediments effects
No increase allowed
Toxic/Deleterious
Substances
Less than demonstrated
hazardous concentration
No increase allowed
Additionally, Montana waters shall comply with the 1962 U.S. Public Health
Service Drinking Water Standards (see Table 48).
321
-------
TABLE 105. NEW MEXICO EMISSIONS STANDARDS
FOR COMMERCIAL GASIFIERS
Constituent/Operation
Standard
Particulates
Briquetting
General Operations
Gas Burning Boilers
Hydrogen Sulfide,
Carbon Disulfide,
Carbon Oxysulfide
(Any Combination)
General Operations
Hydrogen Cyanide
General Operations
Hydrogen Chloride
General Operations
Ammonia
General Operations
Storage
Sulfur Dioxide
Gas Burning Boilers
Sulfur
General Operations
Metric
English
69 mg/scm
69 mg/scm
0.054 kg/10f
Kcal
0.03 grain/scf
0.03 grain/scf
0.03 lb/106Btu
Remarks
Based on heat
input to boile
100 ppm (Total) All ppm
10 ppm (Hydrogen Sulfide) by volume
10 ppm
5 ppm
25 ppm
0.29 kg/106 kcal 0.16 lb/106Btu
0.014 kg/106kcal 0.008 lb/106Btu
Vapor control
required
Based on heat
input to boiler
Based on heat
input of feed
322
-------
TABLE 105. NEW MEXICO EMISSIONS STANDARDS FOR
COMMERCIAL GASIFIERS (Continued)
Hydrocarbons
o
Storage - For a vapor pressure greater than 0.1055 kg/cm (1.5 psi),
a floating roof, vapor recovery and disposal system or
equivalent control technology is required.
Loading Systems - Vapor collection adapters are required.
323
-------
monoxide not presently included in gasification legislation.
These requirements as well as the New Mexico Ambient Air
Quality Standards are presented in Table 106. The ambient
air criteria for heavy metals and the difference in dis-
chargeable carbon monoxide concentrations between new and
existing refineries should be noted. Water quality standards
are specific. For example, the Rio Grande Basin is divided
into fifteen sections, each with independent water quality
standards. Table 107 presents applicable water quality
criteria for selected areas.
Solid waste regulation is not as advanced or as compli-
cated as air and water controls. State requirements include
six inches of daily cover, compaction of wastes to smallest
practical volume, and a minimum final cover of two feet of
earth. Landfill bottoms must be a minimum of 20 feet above
groundwater level.
NORTH DAKOTA (53)
Table 108 describes the applicable ambient air quality
standards of North Dakota. These have been established in
accordance with the state air quality guidelines which call
for preservation of the health of the general public, plant
and animal life, air visibility and natural scenary. The
guidelines also require that ambient air properties not
change in any way which will increase corrosion rates of
metals or deterioration rates of fabrics. Additionally,
emissions restrictions from industrial processes exist for
particulates and sulfur oxides. Sulfur dioxide emissions
are limited to three pounds per million Btu of heat input.
Water quality is dependent upon water classification.
Applicable criteria for Class I waters are discussed in
Table 109. Mixing zone guides are described in preference
to defining a mixing zone applicable to every situation.
North Dakota regulations specify a daily cover of six
inches and a final cover of twelve inches for sanitary
landfill operations.
324
-------
TABLE 106. AMBIENT AIR QUALITY STANDARDS IN NEW MEXICO
Concentration
Constituent
Metric
English
Remarks
Parti culates
Heavy Metals
150 ug/m3
110 ug/m3
90 ug/m3
60 ug/m3
10 ug/m3
1.8xlO"3grain/yd3
1.3xlO"3grain/yd3
l.lxlO"3grain/yd3
A O
7.1x10 grain/yd
1.2xlO~4grain/yd
1 day max
7 day max
30 day max
A.G.M.
Soiling Index
Sulfur Dioxide
Hydrogen Sulfide
Total Reduced Sulfur
Carbon Monoxide
Nitrogen Dioxide
Photochemical Oxidants
1.3 COH/1000 LM
0.10 ppm
0.02 ppm
0.003 ppm
0.100 ppm
0.003 ppm
8.7 ppm
13.1 ppm
0.10 ppm
0.05 ppm
0.10 ppm
0.05 ppm
0.4 COH/1000 LF
24 hr max
A.A.M.
1 hr max
1/2 hr max (1)
1 hr max
8 hr max
1 hr max
24 hr max
A.A.M.
24 hr max
A.A.M.
(1) This standard applies to the Pecos-Permian Basin Intrastate Air Quality
Control Region.
Emissions Standards for Refineries
Constituent
Mercaptan
Carbon Monoxide
Metric
0.11 kg/hr
500 ppm
20,000 ppm
Remarks
new facilities
existing
facilities
325
-------
TABLE lQ7t NEW MEXICO WATER QUALITY CRITERIA
Rio Grande
Basin Section
Parameter
Dissolved Oxygen, • mg/1
Dissolved Oxygen,
grain/gallon
pH Range
Temperature, °C
Temperature, °F
1
5.0
0.29
6.6-8.8
34
93.2
6
6.0 (1)
0.35(1)
6.6-8.8
20
68
San Francisco River
Basin Section
10
6.0 (1)
0.35(1)
6.6-8.8
20
68
1
5.0
0.29
6.6-8.8
32.2
90
3
6.0 (1)
0.35(1)
6.6-8.8
20
68
Total Dissolved Solids,
mg/1 2000
Total Dissolved Solids,
grain/gallon 116.8
Sulfates, mg/1 500
Sulfates,grain/gall on 29.2
Organic Carbon, mg/1
Organic Carbon,grain/gal
70
0.41
7.0
0.41
(1) 85% of saturation is alternatively allowable.
326
-------
TABLE 108.,
NORTH DAKOTA
Concentration
Constituent
Particulates
Sulfur Dioxide
Hydrogen Sulfide
Carbon Monoxide
Photochemical Oxidants
Hydrocarbons
Nitrogen Dioxide
Particulates (dustfall)
Soiling Index
Metric
English
Remarks
60 ug/mj
150 ug/m3
60 ug/m3
260 ug/m3
715 ug/m3
45 ug/m3
75 ug/m3
10 mg/m3
40 mg/m3
160 ug/m3
160 ug/m3
100 ug/m3
200 ug/m3
5.27 kkg/km2/month
10.53 kkg/km2/month
1.3 COH/1000 LM
7.1xlO"4grain/yd3
1.8xlO"3grain/yd3
7.1xlO"4grain/yd3
3.1xlO"3grain/yd3
8.4xlO~3grain/yd3
5.3xlO"4grain/yd3
8.8xlO"4grain/yd3
0.12 grain/yd3
0.47 grain/yd3
1.9xlO"3grain/yd3
1.9xlO"3grain/yd3
1.2xlO"3grain/yd3
2.4xlO"3grain/yd3
2
15 ton/mi /month
2
30 ton/mi /month
0.4 COH/1000 LF
A.G.M.
24 hr max*
A.A.M.
24 hr max
1 hr max
1/2 hr max (1)
1/2 hr max (2)
8 hr max*
1 hr max*
1 hr max*
1 hr max*
A.A.M.
1 hr max (3)
3 month max (4)
3 month max (5)
(1) maximum concentration is not to be exceeded more than twice in avg,
five days
(2) maximum concentration is not to be exceeded more than twice per
year
(3) maximum concentration is not to be exceeded more than one percent
of the time in any three month period
(4) applicable to residential areas
(5) applicable to industrial areas
Reference Conditions: Ternperature^C^^ ^
327
-------
TABLE 109- CLASS I WATER QUALITY STANDARDS IN NORTH DAKOTA
Parameter
Ammonia
Arsenic
Bariuir,
Boron
Cadmium
Chlorides
Chromium (Total)
Copper
Cyanides
Dissolved Oxygen (minimum)
Lead
Nitrates
Phenols
Phosphates
Selenium
Total Dissolved Solids
Zinc
Maximum Allowable
Metric (mg/ll
1.0
0.05
1.0
0.5
0.01
100.0
0.05
0.05
0.01
5.0
0.05
4.0
0.01
0.1
0.01
500.0
0.5
Concentration or Range
English
0.0584
0.0029
0.0584
0.0292
5.84 x
5.8
0.0029
0.0029
5.84 x
0.2921
0.0029
0.2326
5.84 x
0.0058
5.84 x
29.2
0.0292
(grain/gallon)
io-4
io-4
10"4
io-4
Temperature Increase
2.8°C
5°F
Maximum Temperature
29.4°C
85°F
7.0-8.5
Turbidity Increase
10 JTU
Sodium: 50% of total cations as milliequivalents/liter
323
-------
OHIO (53)
Ohio legislation to preserve air quality includes both
ambient and emission standards. Ambient standards are in
Table 110. Emissions regulations for industrial processes
have been promulgated for particulates, sulfur oxides,
nitrogen oxides, hydrocarbons, carbon monoxide and photo-
chemical oxidants. Priority zones also have been established.
These zones presently do not meet EPA standards for sulfur
dioxide, nitrogen dioxide, and particulates. The sulfur
dioxide and particulates emissions limits are mathematical
functions of total emissions discharged and process through-
put, respectively. Carbon monoxide from petroleum refinery
processes must go through an afterburner prior to discharge.
Standards for storage of hydrocarbons are in line with those
previously mentioned. Photochemical oxidants must be in-
cinerated to a minimum of 90 percent oxidation prior to
discharge to the atmosphere.
Effluent discharge requirements vary. Water quality
standards depend on water use and mixing zone which is
formulated for specific discharges and locations rather than
a generalized definition. Criteria for public water supply,
the most strigent classification, are highlighted in Table
116. Dissolved oxygen and pH levels for streams supporting
aquatic life are included. Table 112 describes general
standards.
Plans for all sanitary landfill sites and operations
must be approved in advance. A complete description of site
terrain and subterrain must be supplied as well as soil
chemistry and local hydrology data. A six inch daily cover
and a two foot final compacted soil cover also are required.
Semi-annual well monitoring for chlorides, chemical oxygen
demand, total organic carbon and total dissolved solids is
an additional requirement.
PENNSYLVANIA
Hydrocarbon emissions are limited by controls requiring
either a vapor recovery system or floating roof for storage
tanks, the former required for hydrocarbon loading equipment,
the latter for hydrocarbon-water separators. Applicable
ambient standards are shown in Table 113.
329
-------
TABLE 1.1Q. OHIO AMBIENT AIR QUALITY STANDARDS
Concentration
Constituent
Parti culates
Sulfur Dioxide
Metric
60
150
60
260
ug/m
ug/m
ug/m
ug/m
Engli
3
3
3
3
7.
1.
7.
3.
1x10
8x10
1x10
1x10
-4
-3
-4
-3
sh
grain/yd
grain/yd
grain/yd
grain/yd
Remarks
3
3
3
3
A.
24
A.
24
G.M.
hr max
G.M.
hr max
*
*
Carbon Monoxide
10 mg/nr
0.12
8 hr max*
Photochemical Oxidants
Hydrocarbons
Nitrogen Dioxide
119
79
40
126
331
100
ug/m
ug/m
ug/m
ug'm
ug'm
ug/m
3
3
3
3
3
3
1
9
4
1
4
1
.4x10
.5x10
.7x10
.5x10
.0x10
.2x10
-3
-4
-4
-3
-3
-3
grain/yd
grain/yd
grain/yd
grain/yd
grain/yd
grain/yd
3
3
3
3
3
3
!
4
24
3
24
hr max
hr max
hr max
hr max
(1)
*
(2)
hr max*
A. A.M.
(1) denotes the maximum concentration shall not be exceeded more than
one consecutive four hour period per year.
(2) denotes that ambient levels are to be monitored from 6 to 9 A.M.
Reference Conditions: Temperature = 21.1°C = 70°F
(dry gas)
Pressure = 1.03 kg/cm = 14.7 psi
330
-------
TABLE 111.. OHIO STREAM QUALITY CRITERIA
FOR PUBLIC WATER SUPPLY USE
Constituent
Arsenic
Barium
Cadmi urn
Chromium (hexavalent)
Cyanide
Dissolved Oxygen (1)
Dissolved Solids (2)
Fluoride
Lead
Mercury
Selenium
Silver
Metric
0.05
1.0
0.005
0.05
0.025
5.0
500
1.0
0.05
0.005
0.005
0.05
Concentration
(mg/1) English (grain/gallon)
0.0029
0.0584
2.92 x 10"4
0.0029
0.0015
0.2921
29.2
0.0584
0.0029
2.92 x 10"4
2.92 x 10"4
0.0029
(1) Dissolved oxygen concentrations are minimum values. The given values
are averages. A value of 4.0 mg/1 (0.2336 grain/gallon) is the
minimum acceptable value. These values are for waters designated
to support aquatic life.
(2) Value given is monthly average with a maximum allowable value of
750 mg/1 (43.8 grain/gallon) never to be exceeded.
331
-------
TABLE 112 GENERAL WATER STANDARDS APPLICABLE WITHIN
500 YARDS OF ANY PUBLIC WATER SUPPLY INTAKE IN OHIO
Constituent
Concentration Limit.
Metric (mg/1)
English (cirain/gallon)
Cyanide
Dissolved Iron
Dissolved Manganese
Dissolved Oxygen (1 )
Dissolved Solids (2)
Hexavalent Chromium
Nitrates
Phenols
pH Range
0.005
0.3
0.05
5.0
500
0.01
8.0
0.001
6.0-9.0
2.92 x 10"4
0.0175
0.0029
0.2921
29.2
5.84 x 10"4
0.4673
5.84 x 10"5
(1) 5.0 mg/1 (0.2921 grain/gallon) daily minimum average, never less
than 4.0 mg/1 (0.2336 grain/gallon).
(2) Dissolved solids level may exceed (a) or (b) but not both.
(a) 500 mg/1 (29.2 grain/gallon) monthly average, never to
exceed 750 mg/1 (43.8 grain/gallon).
(b) 150 mg/1 (8.8 grain/gallon) attributable to human activities,
332
-------
TABLE .113. AMBIENT AIR QUALITY STANDARDS
OF PENNSYLVANIA
Concentration
Constituent
Settled Parti culates
Lead
Sul fates
Fluorides
Hydrogen Sul fide
Metric
0.8 ug/cm /month
2
1 .5 ug/cm /month
5.0 ug/m3
1.0 ug/m3
3.0 ug/m3
3
5.0 ug/m
0
0
English
grain/in^/month
2
grain/ in /month
.005 ppm
.1 ppm
Remarks
A. A.M.
30 day max
30 day max
30 day max
24 hr max
24 hr max
24 hr max
1 hr max
Standards for Contaminants
Particulates - unspecified process
For effluent gas discharge rates greater than 8500 scm/min
(300,000 dscf/min), 458 mg/dscm (0.2 grain/dscf) is allowed.
Particulates - petroleum refineries
20 kg/metric ton (40 Ib/ton) of liquid feed
Visible Emissions - unspecified process
Opacity equal to or greater than 20% is not allowed for aggregate
periods of more than three minutes in any hour. Additionally,
60% opacity may never be exceeded. Opacity due to uncombined
water mists is excluded in determining opacity levels.
533
-------
Pennsylvania water quality criteria, based upon water
use, are in Table 114. Applicable criteria are given for
the Monogahela River; criteria differ for each stream, and,
in many cases, for sections of the same stream.
The solid waste legislation of Pennsylvania is among
the most extensive of any of the states considered. In
addition to the general solid waste legislation, Pennsylvania
has promulgated rules and regulations governing coal refuse
disposal. These rules may be more indicative of future
legislation regarding SRC generated residues. The rules are
general, prohibiting disposal which will promote fire,
subsidence, or leaching problems. The state also has
published a statement or guidelines and acceptable procedures
for the operation of such disposal areas. Generally, two
feet of final cover are required. The landfill shall be a
minimum of six feet above the seasonal high water table.
Disposal cells may not exceed eight feet with compacted
solid waste layers of two feet or less. Hazardous waste
disposal plans must be approved by the appropriate state
agencies.
SOUTH DAKOTA
The ambient air quality standards of South Dakota are
shown in Table 115. South Dakota has reserved the right to
set emissions standards for any source which may be exceeding
the ambient standards. Standards for fuel burning installa-
tions and general process industries are listed in Table 116.
Water quality criteria for three types of waters are
presented in Table 117. It is obvious that the intended
water use provisions of several state laws, including South
Dakota, will be an important point to consider in site
selection for commercialized SRC facilities. Mixing zones
are dependent on stream characteristics. Lakes are not
allowed a mixing zone.
334
-------
TABLE 114. WATER QUALITY STANDARDS FOR THE
MONONGAHELA RIVER IN PENNYSLVANIA
Concentration
Parameter
Dissolved Oxygen (1 )
Total Iron
Maximum Temperature
Temperature Increase (2)
Dissolved Solids (3)
Total Manganese
Phenols
pH Range
Metric
6.0 mg/1
1.5 mg/1
30.6°C
2.8°C
500 mg/1
1.0 mg/1
0.005 mg/1
6.0-8.5
English
0.3505 grain/gallon
0.0876 grain/gallon
87°F
5°F
29.2 grain/gallon
0.0584 grain/gallon
2.92xlO~4grain/gallon
(1) 6.0 mg/1 (0.3505 grain/gallon) is the minimum daily average.
5.0 mg/1 (0.2921 grain/gallon) is the minimum acceptable level.
For the epilimnion of stream sections where thermal stratification
occurs, the minimum daily average is 5.0 mg/1 (0.2921 grain/gallon)
and the minimum acceptable level is 4.0 mg/1 (0.2336 grain/gallon)
(2) A 5°F temperature rise may not cause a resulting stream temperature
of greater than 30.6°C (87°F). Also, a maximum hourly temperature
change of 1.1°C (2°F) is allowed.
(3) 500 mg/1 (29.2 grain/gallon) is the monthly average. 750 mg/1
(43.8 grain/gallon) may never be exceeded.
335
-------
TABLE 115. AMBIENT AIR QUALITY STANDARDS
OF SOUTH DAKOTA
Constituent
Sulfur Oxides
Particulates
Soil Index
Carbon Monoxide
Concentration
Metric English
60 mg/m3 7.1xlO"4grain/yd3
260 mg/m3 3.1xlO"3grain/yd3
60 mg/m3 7.1xlO"4grain/yd3
150 mg/m3 1 .8xlO"3grain/yd3
0.66 COH/1000LM 0.20 COH/1000 LF
10 mg/m3 0.12 grain/yd3
15 mg/m3 0.18 grain/yd3
Remarks
A. A.M.
24 hr max*
A.G.M.
24 hr max*
A.G.M.
8 hr max*
1 hr max*
Photochemical Oxidants
Hydrocarbons
Nitrogen Oxides
125 mg/nf
125 mg/m-"
100 mg/m'
250 mg/nT
1.5x10"3grain/yd3
1.5xlO"3grain/yd3
1.2xlO"3grain/yd3
2.9xlO"3grain/yd3
1 hr max*
3 hr max* (1)
A.A.M.
24 hr max*
(1) Monitored from 6-9 A.M.
Standard Conditions: Temperature = 20°C = 68°F
Pressure = 760 mm Hg = 29.92 in. Hg
1 atmosphere
336
-------
TABLE 116. SELECTED SOUTH DAKOTA INDUSTRIAL
EMISSIONS STANDARDS
Fuel Burning Installations
Particulates
0.54 kg/kcal of heat input = 0.30 lb/106 Btu of heat input
Sulfur Oxides
5.4 kg/kcal of heat input = 3.0 lb/106 Btu of heat input
Nitrogen Oxides
0.36 kg/kcal of heat input = 0.2 lb/106 Btu of heat input
General Process Industries
Particulates
E = 55.0 p0'11 - 40
where E = rate of emission in Ib/hr
P = process weight rate in ton/hr
337
-------
TABLE 117. APPLICABLE WATER QUALITY STANDARDS OF SOUTH DAKOTA
Concentration
u>
CO
Parameter
Total Dissolved
Solids
Nitrates
Nitrates
Ammonia
Chlorides (1)
Cyanides (total)
Cyanides (free)
Dissolved Oxygen
Dissolved Oxygen
Hydrogen Sulfide
Suspended Solids
Total Iron
Temperature
Turbidity
Metric
English
Water Use
1000 mg/1
2000 mg/1
10 mg/1
45 mg/1
0.6 mg/1
100 mg/1
0.02 mg/1
0.005 mg/1
6.0 mg/1
7.0 mg/1
0.002 mg/1
30 mg/1
0.2 mg/1
18.3°C
58.4 grain/gal
116.8 grain/gal
0.5841 grain/gal
2.6285 grain/gal
0.0350 grain/gal
5.84 grain/gal
0.0012 grain/gal
2.92 x 10"4 grain/gal
0.3505 grain/gal
0.4089 grain/gal
1.17 x 10"4 grain/gal
1.75 grain/gal
0.0117 grain/gal
65°F
Domestic Supply
Industrial Supply
Domestic Supply
Domestic Supply
Domestic Supply
Domestic Supply
Domestic Supply
All
Cold,
Water
Fish
Propagation
Remarks
As N
As NO.
mi n imum concentrati on
Spawning season
10JTU
(1) Additionally total chlorine is limited to 0.2 mg/1 (0.0117 grain/gal)
-------
South Dakota solid waste regulations, with regard to
operations, are similar to those of the states previously
mentioned. Of greater interest are the requirements per-
taining to site locations. Landfills are not permitted
within 1,000 feet of any lake or pond, or within 300 feet of
any stream or river. Also, a minimum of six feet between
waste and the groundwater table must be preserved. Such
requirements, promulgated specifically to prevent leaching
to groundwater, may provide an applicable basis for future
regulatory control of disposal of SRC solid wastes.
TEXAS (53)
All national primary and secondary ambient air quality
standards are applicable in Texas. An additional ambient
standard for inorganic fluoride compounds, specifically
hydrogen fluoride gas, has also been promulgated. This
standard, along with net ground level concentrations for
applicable compounds, is presented in Table 118. Emissions
rates for particulates and sulfur dioxide have been pro-
mulgated. Both are functions of effective stack height.
Additional emission concentration limits for particulates,
sulfur dioxide, and nitrogen oxides in fossil fuel burning
steam generators are also presented in Table 118. Visi-
bility requirements prohibit exceeding 20 percent opacity,
15 percent for stationary flues with total flow rates ex-
ceeding 100,000 acfm. These opacity limits are for five
minute periods and do not include opacity resulting from
uncombined water mists.
Texas water standards consist of three parts: general
criteria, numerical criteria and water uses. The latter two
are highly stream-specific, similar to the Pennsylvania
legislation. Water quality parameters and uses for the San
Antonio River Basin are shown in Table 119. It should be
noted that Texas has one of the warmest climates among those
states considered. Natural water temperatures may exceed
96°F For this reason the 90 degree maximum temperature
suggested by the National Technical Advisory Committee^does
not apply. A maximum temperature increase of 3°F (1.7°C) is
permitted for fresh waters, 5°F (2.8°C) for saline waters.
339
-------
TABLE 118. TEXAS AIR REGULATIONS
Ambient Air Quality Standards for Hydrogen Fluoride
4.5 ppb 12 hr max
3.5 ppb 24 hr max
2.0 ppb 7 day max
1.0 ppb 30 day max
Net Ground Level Concentrations for Applicable Emissions
Constituent
Concentration
Hydrogen Sulfide (1)
0.08 ppm
0.12 ppm
Remarks
30 min max
30 min max
Metric (ug/m )
English (grain/yd )
Sulfuric Acid
Parti culates
15
50
100
100
200
400
1.8xlO~H
5.9xlO"4
1.2x:Ur3
1.2xlO"3
2.4xlO"3
4.7xlO"3
24 hr max
1 hr max (2)
max allowed
5 hr max
3 hr max
1 hr max
(1) The first value is applicable only when residential areas are downwind
of the source of emissions.
(2) Denotes that the maximum value is not to be exceeded more than once
per 24 hour period.
340
-------
TABLE 118. TEXAS AIR REGULATIONS (Continued)
Emissions Limits for Fuel Burning Steam Generators (3)
Constituent
Particulates
Sulfur Dioxide
Nitrogen Oxides
Concentration
Metric Engl
0.54
0.18
5.40
1.26
0.90
0.45
kg/10b
kg/106
kg/106
kg/106
kg/106
kg/106
kcal
kcal
kcal
kcal
kcal
kcal
0
0
3
0
0
0
.3
.1
.0
.7
.5
.25
ish
lb/106
lb/106
lb/106
lb/106
lb/106
lb/106
Remarks
Btu
Btu
Btu
Btu
Btu
Btu
24
2
2
2
2
hr max
hr
hr
hr
hr
max
max
max
max
(4)
(5)
(6)
(3) applicable for heat inputs greater than 2500 million Btu/hr.
(4) solid fuel burners
(5) gas and liquid fuel burners
(6) standards" apply to opposed fire, front fired, tangential fired-
steam generators, respectively.
341
-------
TABLE 119. WATER USES AND QUALITY CRITERIA FOR THE
SAN ANTONIO RIVER BASIN
Water Use/Quality Parameter 1 2
Contact Recreation N 0
Non-Contact Recreation U U
Fish and Wildlife U U
Domestic Supply U U
Chlorides, mg/1 200 200
Chlorides grain/gal 11.7 11.7
Sul fates, mg/1 150 300
Sulfates grain/gal 8.8 17.5
Total Dissolved Solids, mg/1 700 900
Total Dissolved Solids, grains/gal 40.9 52.6
pH range 6.5-8.5 7.0-9.0
Temperature, °C 32 32
Temperature, °F 90 90
Dissolved oxygen, mg/1 5.0 5.0
Dissolved oxygen, grain/gal 0.29 0.29
N not currently useable
0 not currently useable, quality to be improved
U useable for given water use
(1 ) San Antonio River
(2) Cibolo Creek (Section 1)
(3) Cibolo Creek (Section 2)
(4) Medina River (Section 1)
(5) Medina River (Section 2)
(6) Medina Lake
(7) Medina River (Section 3)
(8) Leon Creek (Section 1)
(9) Leon Creek (Section 2)
3
U
U
U
U
40
2.3
75
4.4
400
23.4
7.0-9.0
32
90
5.0
0.29
4
U
U
U
U
120
7.0
120
7.0
700
40.9
7.0-9.0
32
90
5.0
0.29
5
U
U
U
U
50
2.9
75
4.4
400
23.4
7.0-9.0
32
90
5.0
0.29
342
-------
TABLE 119. WATER USES AND QUALITY CRITERIA FOR THE
SAN ANTONIO RIVER BASIN (Continued)
Water Use/Quality Parameter
Contact Recreation
Non-Contact Recreation
Fish and Wildlife
Domestic Supply
Chlorides, mg/1
Chlorides grain/gal
Sulfates, mg/1
Sulfates grain/gal
Total Dissolved Solids, mg/1
Total Dissolved Solids:, qrains/gal
pH range
Temperature, °C
Temperature, °F
Dissolved oxygen, mg/1
Dissolved oxygen, grain/gal
6
U
U
U
U
50
2.9
75
4.4
400
23.4
7.0-9.0
31
88
5.0
0.29
7
U
U
U
U
40
2.3
100
5.8
400
23.4
7.0-9.0
31
88
5.0
0.29
8
U
U
U
U
120
7.0
120
7.0
700
40.9
7.0-9.0
35
95
5.0
0.29
9
u
U
U
U
40
2.3
75
4.4
400
23.4
7.0-9.0
35
95
5.0
0.29
343
-------
Three classifications of industrial solid waste exist.
These can be characterized as hazardous, naturally decompos-
able organics and inorganics, and inert materials. All
plans and specifications relevant to site selection, design
and operation of industrial waste disposal operations must
be reviewed and approved by appropriate state authorities.
UTAH (53)
Utah has no ambient air or new source standards at this
time. Current federal standards are applicable. The Utah
Air Conservation Regulations note that the Utah Air Conserva-
tion Committee and the State Board of Health do not agree
with most of the federal standards. There is no indication
of the types of standards these organizations favor. Future
legislation will have to answer that question. State emissions
standards have been set for particulates requiring 85 percent
control. Sulfur emissions must meet federal ambient and new
source standards.
Stream quality criteria are dependent upon stream
classification. Class "A" waters are to be suitable without
pretreating for a variety of uses including domestic water
supply and propagation of fish and wildlife. Such waters
are to be free from organic substances measured by biochemical
oxygen demand. A pH range of 6.5 to 8.5 is to be maintained.
Physical characteristics and chemical concentration standards
are the same as prescribed by "Public Health Service Drinking
Water Standards, 1962." These are described in Table 120.
All solid waste disposal operations must meet approval of
the Utah State Division of Health.
WEST VIRGINIA (53)
A brief review of West Virginia state air laws provides
a good idea of the relative importance of the coal mining
industry there. Air pollution control legislation has been
promulgated for refuse disposal, preparation and handling
operations. These regulations and particulate limits for
manufacturing process operations are detailed in Table 126.
Ambient air quality standards are detailed in Table 122.
Water quality criteria, based on water use similar to
the Pennsylvania criteria is highlighted in Table 123.
Criteria for the Gauley River and tributaries was chosen for
presentation due to its acceptability for all water use
classifications.
344
-------
TABLE 120. WATER CRITERIA FOR CLASS "A" UTAH WATERS
(FROM PUBLIC HEALTH SERVICE DRINKING WATER STANDARDS. 1962)
Turbidity: 5 JTU
Concentration
Chemical Constituent
. Arsenic
Chlorides
Copper
Cyanide
Fluoride (1)
Iron
Manganese
Nitrates
Phenols
Sul fates
Total Dissolved Solids
Zinc
Metric (mg/lj
0.01
250
1.0
0.01
1.7
0.3
0.05
45
0.001
250
500
5.0
English (grain/gal)
5.84xlO"4
14.6
0.0584
5.84xlO"4
0.0993
0.0175
0.0029
2.63
5.84xlO"5
14.6
29.2
0.2921
(1) Fluoride concentrations is temperature dependent, the given value
being the maximum allowed at temperatures below 10°C (50°F).
345
-------
TABLE 121. APPLICABLE AIR POLLUTION REGULATIONS
IN WEST VIRGINIA
Coal Preparation, Drying and Handling
Particulates - for volumetric flow rates greater than
14,200 scm/m (500,000 scf/min.), the allowable emission
rate is 0.18 gm/scm (0.08 grain/scf).
Manufacturing Process Operations
Particulates - for process weight rates exceeding 45,500
kg/hr (100,000 Ib/hr) the allowable emission rate is
9.6 kg/hr (21.2 Ib/hr).
Smoke - No smoke darker than No. 1 on the Ringelmann
Smoke Chart is permitted. No smoke darker than No. 2
on the Ringelmann Smoke Chart is permitted for more
than five minutes in any sixty minute period.
346
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TABLE 122. WEST VIRGINIA AIR QUALITY STANDARDS
Concentration
Constituent
Sulfur Dioxide
primary
secondary
Particulates
primary
secondary
Carbon Monoxide
standard
Metric
80 mg/m3
3
365 mg/m
1300 mg/m3
75 mg/m
260 mg/m3
3
60 mg/m
150 mg/m3
10 mg/m3
3
40 mg/m
English
9.4xlO"4grain/gal
4.3xlO~3grain/gal
1.5xlO"2grain/gal
8.8xlO"4grain/gal
3.1xlO"3grain/gal
-4
7.1x10 grain/gal
1.8xlO~3grain/gal
0.12 grain/gal
0.47 grain/gal
Remarks
A. A.M.
24 hr max*
3 hr max*
A.6.M.
24 hr max*
A.G.M.
24 hr max*
8 hr max*
1 hr max*
Photochemical Oxidants
standard
Non-Methane Hydrocarbons
160 mg/m3 1.9xlO"3grain/gal 1 hr max*
160 mg/m3 1.9xlO"3grain/gal 3 hr max*
(6-9 A.M.)
Standard Conditions: Temperature = 25°C - 77°F
Pressure = 760 mmHg = 29.92 in Hg = 1 atmosphere
347
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TABLE 123. WATER QUALITY CRITERIA FOR THE GAULEY RIVER
' AND TRIBUTARIES IN WEST VIRGINIA
Dissolved Oxygen:
pH Range :
Temperature:
never less than 5.0 mg/1 = 0.2921 grain/gallon
6.0 - 8.5
Maximum increase 2.8°C = 5°F
Maximum Temperature
27°C = 81°F (May-November)
23°C = 73°F (December-April)
Chemical Constituent
Maximum Concentration
Metric (mg/1) English
(grain/gal )
Arsenic
Barium
Cadmium
Chloride
Chromium (hexavalent)
Cyanide
Fluoride
Lead
Nitrates
Phenol
Selenium
Silver
0.01
0.50
0.01
100
0.05
0.025
1.0
0.05
45
0.001
0.01
0.05
5.84xlO"4
0.0292
5. 84x1 O"4
5.84
0.0029
0.0015
0.0584
0.0029
2.63
5. 84x1 O"5
5.84xlO~4
0.0029
348
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West Virginia has three solid waste classifications,
analagous to those previously described in the Texas solid
waste laws. Requirements for disposal of hazardous wastes
shall be determined on a case-by-case basis. Class II
decomposable wastes are subject to six inches of daily cover
and two feet of final cover.
WYOMING (53)
Table 124 defines the state ambient air quality stan-
dards. Emissions standards, primarily applicable to fossil
fuel burning installations, are presented in Table 125.
Wyoming has additional regulations governing hydrocarbon
storage and handling. Waste disposal combustion systems for
vapor blowdown or emergency situations are to be burned in
smokeless flares. Pressurized tanks, floating roofs, or
vapor recovery systems are required for storage of hydro-
carbons .
Water quality standards which may affect future com-
mercial SRC operations are summarized in Table 126. Wyoming
waters are classified as having potential to support game
fish CClass I) , potential to support non-game fish (Class
II) , or as not having the potential to support fish (CLass
III). In addition, waters designated a part of the public
water supply must meet the most recent Federal Drinking
Water Standards. These are described in Table 127.
The Wyoming Department of Environmental Quality reviews
construction and operating plans of all industrial or hazard-
ous waste disposal operations. Industrial waste disposal
sites shall not be located in areas of low population density,
land use value and groundwater leaching potential. Monitoring
wells must be installed prior to commencement of operations.
Disposal sites may not be located near drinking water supply
sources. It is suggested, but not required, that disposal
sites with impermeable soil be selected.
349
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TABLE 124. WYOMING AMBIENT AIR STANDARDS
Concentration
Constituent
Particulates
Soiling Index
Total Settleable
Particulates
Sulfur Oxides
Hydrogen Sulfide
Photochemical Oxidants
Hydrocarbons
Nitrogen Oxides
Fluorides
Carbon Monoxide
Metric
60 mg/m
150 mg/m3
1.3 COH/1000
2
5 g/m /month
2
10 g/m /month
60 mg/m
260 mg/m3
1300 mg/m3
70 mg/m3
40 mg/m3
160 mg/m3
160 mg/m3
100 mg/m3
1 ppb
10 mg/m3
40 mg/m
English
-4
7.1x10 grain/gal
1.8xlO~3grain/gal
0.4 COH/1000 LF
2
59 grain/yd /month
2
118 grain/yd /month
7.1xlO~ grain/gal
3.1xlO~ grain/gal
_2
1.5x10 grain/gal
8.3xlO~4grain/gal
4.7xlO~3grain/gal
1.9xlO~3grain/gal
1.9xlO~3grain/gal
1.2xlO~3grain/gal
0.12 grain/gal
0.47 grain/gal
Remarks
A.G.M.
24 hr max*
A.G.M.
(1)
A. A.M.
24 hr max*
3 hr max*
1/2 hr max
1 hr max*
1 hr max*
3 hr max*
A. A.M.
24 hr max
8 hr max*
1 hr max*
(2)
(3)
Standard Conditions:
Temperature = 21 °C = 70°F
Pressure = 760 mmHg = 29.92 in.Hg = 1 atmosphere
(1) Values given include 1.7 g/m2/month (20.1 grain/yd2/month)
background settled particulates
(2) Hydrogen sulfide values are not to be exceeded more than twice per year.
(3) Monitored 6-9 A.M.
350
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TABLE .125.. APPLICABLE WYOMING EMISSIONS REGULATIONS
New Fuel Burning Equipment - Sulfur Dioxide
0.36 kg/106Kcal input =0.20 lb/106 Btu input
(applicable to coal burners)
New Fuel Burning Equipment - Nitrogen Oxides
1.26 kg/106Kcal input =0.70 lb/106 Btu input
(applicable to non-lignite coal burners)
Stationary Sources - Carbon Monoxide Requirement
Stack gases shall be treated by direct flame after burner
as required to prevent exceeding ambient standards.
Stationary Sources - Hydrogen Sulfide Requirement
Gases containing hydrogen sulfide s.hall be vented, in-
cinerated, or flared as necessary to prevent exceeding
ambient standards.
New Sources - Particulates
E = 17.31 p°'16 (for P 30 tons/hr)
where E = maximum allowable rate of emissions in Ib/hr
P = process weight rate in tons/hr
For a 50,000 bbl/day SRC plant
22.000 ton/day
E •—• J. / • -j J- ..v
(24 hr/day)
E = 17.31 (917)°-16 - 51.6 Ib/hr
351
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TABLE 126. WYOMING WATER QUALITY STANDARDS
Parameter
Concentration Limits
Remarks
Settleable Solids
Floating Solids
Toxic Materials
Turbidity
pH Range
Total Gas Pressure
free from
free from
free from
10 JTU increase
6.5 - 8.5
Not to exceed 110%
(of atmospheric pressure)
Metric English
Dissolved Oxygen
Oil /Grease
6 mg/1
5 mg/1
10 mg/1
0.3505 grain/gal
0.2921 grain/gal
0.5841 grain/gal
Class I water
Class II water
Temperature
The maximum temperature allowed is 26°C (78°F) for streams supporting
cold water fish and 32°C (90°F) for streams supporting warm water fish.
The maximum allowable temperature increase is dependent upon natural
water temperature. For streams with maximum natural temperatures of 20°C
(68°F) or less the maximum allowable temperature increase is 1.1°C (2°F)
For streams with maximum natural temperatures exceeding 20°C (68°F), the
maximum allowable temperature increase is 2.2°C (4°F).
352
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TABLE 127. EPA NATIONAL INTERIM PRIMARY
DRINKING WATER STANDARDS
Constituent
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Nitrate (as N)
Selenium
Silver
Fluorine
Maximum
Metric (mg/1 )
0.05
1.0
0.01
0.05
0.05
0.002
10
0.01
0.05
Temperature Concentration
- (UC)" (mg/1)
= •= =
12.1 & below 2.4
12.2 - 14.6 2.2
14.7 - 17.7 2.0
17.8 - 21.4 1.8
21.5 - 26.2 1.6
26.3 - 32.5 1-4
Concentration
English (grain/gallon)
0.0029
0.0584
5.84 x 10"4
2.92
0.0029
1.17 x 10"4
0.5841
5.84 x 10"4
0.0029
Temperature C.onr;pntratinn
(°F) (grain/gal)
53.7 & below 0.1402
53.8 - 58.3 0.1285
58.4 - 63.8 0.1168
63.9 - 70.6 0.1051
70.7 - 79.2 0.0935
79.3 - 90.5 0.0818
353
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-600/7-78-091
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Standards of Practice Manual for the Solvent Refined
Coal Liquefaction Process
5. REPORT DATE
June 1978
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
P.J.Rogoshewski, P.A.Koester, C.S.Koralek,
R.S.Wetzel. and K. J.Shields
8. PERFORMING ORGANIZATION REPORT NO,
9. PERFORMING ORGANIZATION NAME AND ADDRESS
H ittm an As s oc iates, Inc.
9190 Red Branch Road
Columbia, Maryland 21045
10. PROGRAM ELEMENT NO.
EHE623A
11. CONTRACT/GRANT NO.
68-02-2162
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 4-11/77
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES T£RL-RTP project officer is William J. Rhodes, Mail Drop 61,
919/541-2851.
16. ABSTRACT
The manual gives an integrated multimedia assessment of control/disposal
options, emissions, and environmental requirements associated with a hypothetical
50,000 bbl/day Solvent Refined Coal (SRC) facility producing gaseous and liquid fuels.
It gives an overall outline of the basic system, including module descriptions and
summaries on pollution control practices and costs. It also gives a survey of cur-
rently available and developing control/disposal practices that may be applicable to
waste streams from coal liquefaction technologies. In the detailed definition of the
basic system, it describes modules in detail, and quantifies input and output streams
It specifies applicable control/disposal practices in accordance with waste stream
characteristics and pertinent environmental requirements. For each treatment
option, it gives capital and operating costs, along with estimated post-treatment
emissions. Subsequently, it compares levels of specific pollutants in quantified
waste streams to Multimedia Environmental Goals (MEG's) developed by EPA's
IERL-RTP. Finally, it discusses emission variations in solid and liquid SRC pro-
duction.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Coal
Liquefaction
Industrial Processes
Industrial Wastes
Waste Disposal
Cnst Analysis
Pollution Control
Stationary Sources
Solvent Refined Coal
Multimedia Environ-
mental Goals (MEG's)
Environmental Assess-
ment.
13B
21D
07D
13H
14A
S. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
369
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
354
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