&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

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     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

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     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.

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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

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     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

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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

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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

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     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

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     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

-------
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

-------
                              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

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     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

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     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

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   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

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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

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                                     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

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                      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.

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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

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 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

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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

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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

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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

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           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

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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

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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

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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

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                                                 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

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     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

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                     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

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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

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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

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     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

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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

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      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

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     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

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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

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   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

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     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)
                            86

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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.
                               87

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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.
                               90

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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.
                               91

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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.
                               92

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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.
                              93

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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.
                              94

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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).
                             95

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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.
                              96

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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.
                               97

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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.
                               99

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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

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•    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

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    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

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     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

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•    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

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          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

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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

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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

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     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

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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

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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

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      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

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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

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     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

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    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

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     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

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              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

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     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

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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

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      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

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     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

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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

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   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

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 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

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                                    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

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                                    (-©
              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

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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

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    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

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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

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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

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        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

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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

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             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

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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

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                             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

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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

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                                    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

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      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

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     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

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               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

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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

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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

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 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

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    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

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                     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

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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

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       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

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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

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     •    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

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                    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

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     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

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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

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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

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 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

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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

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             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

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   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

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       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

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   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

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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,
     Austin, Texas.

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.
9.   U.S. Environmental Protection Agency.  1974.  Technology
     Transfer:  Process Design Manual
     and Disposal^  EPA" 625/1-74-006.
10.  U.S. Environmental Protection Agency.  1974.  Technology
     Transfer: Process Design Manual for Suspended Solids
     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,
     New York.

13.   Liptak, B.C. ed.  1974.  Environmental Engineers'
     Handbook, Volume I: WaterTbliution.  Chilton Book
     Company, Radnor, Pennsylvania.

14.   Liptak, B.C. ed.  1974.  Environmental Engineers'
     Handbook. Volume III: Land Pollution.  Chilton Book
     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

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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

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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

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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

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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,
Volume (7): No. 120.

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
Treatment Facilities.UTS. Environmental Protection Agency
Water Pollution Control Research Series No. 17090 DAN 10/71.

Perry, R.H. and C.H. Chilton.  eds.  1973.  Chemical Engineer's
Handbook, 5th Edition, McGraw-Hill Book Company, New York.

Popper, Herbert, ed.  1970.  Modern Cost-Engineering Techniques,
McGraw-Hill Book Company, New York.

Prussner, R.D. and L.P. Broz.  1977.  Air pollution control:
hydrocarbon emission reduction systems.  Chemical Engineering
Progress.  August 1977: 69-73.
                              277

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Public Health Service Drinking Water Standards 1962, U.S.
Department H.E7W~]

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
Btu Coal Gasification and Related Environmental Controls!
Volume II - Appendices A-F.

Reddy, G. Narender.  "Environmental Aspects of Coal Conversion
Plant Siting and Cost of Pollution Control."  Presented at
the Third Annual International Conference on Coal Gasification
and Liquefaction, School of Engineering, University of
Pittsburgh, Pittsburgh, Pennsylvania, August 3, 1976.

Rubin, Edward S. and F.L. McMichael.  1975.  Impact of regula-
tions on coal conversion plants.  Environmental Science and
Technology.  February 1975: p. 112.

Schiller, J.E.  1977.  Composition of coal liquefaction
products.  Hydrocarbon Processing, 56(1):147-152.

Slack, A.V., and G.A. Hollinden.  1975.   Sulfur Dioxide
Removal from Waste Gases, 2nd Edition.  Noyes Data Corporation,
Park Ridge, New Jersey, p. 166-

Smith, Curtis, W.  1977.  Toxic substance control is there.
Hydrocarbon Processing.  January 1977:213.

Stecher, P.G. ed.  1968.  The Merck Index; An Encyclopedia of
Chemicals and Drugs, 8th ed.  Merck & Company, Inc., Rahway,
New Jersey.

Tchobamoglous, George.  1973.  "Wastewater Treatment for Small
Communities."  Presented at the Conference on Rural Environ-
mental Engineering, Warren, Vermont, September 1973.

U.S. Department of the Interior.  1973.   Demonstration Plant,
Clean Boiler Fuels From Coal; Preliminary Design/Capital Cost
Estimate, R&D Report No. 82-Intenm Report No. 1, The RalpH
M. Parsons Company, Los Angeles, California.

U.S. Energy Research and Development Administration.  1977.
Development of a Process for Producing an Ashless. Low-Sulfur
Fuel fromToaT, Vol, III - Pilot Plant Development Work,
Part 3:  Startup and Operation of the SRC~Pilgt PlantTFE
496-TI3.Pittsburgh and Midway Coal Mining Co., Merriam,
Kansas.
                              278

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U.S. Energy Research and Development Administration.  1977.
Solvent Refined Coal (SRC) Process Quarterly Report, January-
March 19TTFE 496-134~^The Pittsburgh and Midway Coal
Mining Company, Merriam, Kansas.

U.S. Environmental Protection Agency.  1975.  Assessment pj
Industrial Hazardous Waste Practices: Storage and Primary
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. ,
Columbia, Maryland.

U.S. Environmental Protection Agency.  1977.  Water Conservation
and Pollution Control in Coal Conversion Processes.  EPA
600/7-77-065.  Water Purification Associates, Cambridge,
Massachusetts.

U.S. Environmental Protection Agency.  1973.  Compilation
°f Air Pollution  Emission Factors, 2nd ed.   (AP-42).

Wall, J.   1975.   Gas processing  handbook.  Hydrocarbon
Processing 54(5): pp. 9-79.

Whitaker,  Ralph.  1976.  Clean coal: what  does it cost at
the busbar?   EPRI Journal No. 9, November  1976.
                               279

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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

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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

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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

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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

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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

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           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

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     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

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     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

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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

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     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

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1.   FEDERAL REGULATIONS
           291

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         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

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2.   SELECTED STATE POLICIES
             296

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     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

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      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

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           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

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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

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     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

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       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

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            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

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        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

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     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

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       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

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           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

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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

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          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

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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

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           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

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     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

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       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

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       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

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            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

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     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

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     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

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     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

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            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

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        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

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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

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          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

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           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

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        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

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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

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     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

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        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

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           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

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    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

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           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

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     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

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          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

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           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

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         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

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                     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

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                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

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         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

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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

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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

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     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

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     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

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      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

-------
     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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