United States Industrial Environmental Research EPA-600/7-78-184b
Environmental Protection Laboratory September 1978
Agency Research Triangle Park NC 27711
Environmental
Assessment Data Base for
Coal Liquefaction
Technology:
Volume II. Synthoil,
H-Coal, and Exxon Donor
Solvent Processes
Interagency
Energy/Environment
R&D Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. 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 INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology, Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect the
views and policies of the Government, 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.
-------
EPA-600/7-78-184b
September 1978
Environmental Assessment
Data Base for Coal
Liquefaction Technology:
Volume II. Synthoil, H-Coal,
Exxon Donor Solvent Processes
by
C. Leon Parker and Dewey I. Dykstra, Editors
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
-------
ABSTRACT
This report was prepared as part of an overall environ-
mental assessment program for the technology involved in the
conversion of coal to clean liquid fuels. The program is
being directed by the Fuel Process Branch of the Environ-
mental Assessment and Control Division of the Industrial
Environmental Research Laboratory at Research Triangle Park,
North Carolina. The two volumes of this report plus the
Standards of Practice Manual (SPM) for the Solvent Refined
Coal Liquefaction Process, EPA-600/7-78-091, represent the
current data base for the environmental assessment of coal
liquefaction technology. Volume I, Systems for Fourteen
Liquefaction Processes, provides a summary of pertinent
information about 14 of the prominent coal liquefaction
systems now under development. It provides a brief process
description, a diagram of the system, and a list of the
materials entering and leaving the system. The processes
required to produce clean liquid fuels from coal are divided
into discrete operations. Each of these operations is then
further divided into discrete modules, with each module
having a defined function and identifiable raw materials,
products, and discharge streams. Volume II, Detailed
Discussion of Synthoil, H-Coal, and Exxon Donor Solvent
Processes, is an environmental characterization report
covering three selected coal liquefaction systems. It
provides documentation and evaluation of existing environ-
mentally significant data.
ii
-------
Environmental characterization for the three systems -
Synthoil, H-Coal, and Exxon Donor Solvent (EDS) - includes
an integrated multimedia assessment of the discharges to the
3
environment from conceptualized 7,950 m (50 kbbl) per day
systems. Estimations are given for the raw waste streams,
treatment and control processes, treated waste stream dis-
charges, and the effects of these discharges on the environ-
ment .
Conclusions:
The carbon-containing residues resulting from process
phase separations represent a major area for potential envi-
ronmental problems. With the exception of the solid carbon-
containing residues resulting from phase separation opera-
tions, established treatment and control technology exists
for the removal of most major waste components such as
sulfur dioxide, hydrogen sulfide, phenols, and ammonia.
However, the efficiency of this technology to the control of
coal liquefaction waste streams must be tested.
There has been less attention addressed to the trace
organic and inorganic compounds, many of which are toxic or
are suspected of adverse biological activity (carcinogenic,
mutagenic, teratogenic). There is a major need for quan-
tification of coal liquefaction environmental discharges
through actual sampling and analysis of multimedia waste
streams. The analysis should be centered on the deter-
mination of known toxic and hazardous chemicals.
Both process economics and environmental concern indi-
cate the need for further work in the use and control of
these wastes. A difficult environmental or health char-
acterization area is the assessment of the effects of coal
iii
-------
liquefaction products and wastes on workplace personnel.
This workplace assessment suffers from the dual handicap of
undefined plant discharges and the lack of sufficient human
health information.
iv
-------
CONTENTS
Abstract ii
Figures vii
Tables xi
Acknowledgment xix
Executive Summary
1. Introduction 1
2. Technology Assessments and Comparisons ... 4
Introduction 4
Present process status 5
Comparison of processes 9
Evaluation of processes 16
Treatment and control needs 19
3. The Synthoil Process 28
Introduction 28
Process description 29
Description of process modules 38
4. The H-Coal Process 65
Introduction. . . 65
Process description 66
Description of process modules 75
5. The Exxon Donor Solvent Process 108
Introduction 108
Process description 109
Description of process modules 118
6. Common Operations and Processes 147
Introduction 147
Coal preparation 148
V
-------
CONTENTS (continued)
Hydrogen generation process 164
Oxygen generation process 174
Steam and power generation processes . . 177
Cooling towers 180
Raw water treatment 182
Product and by-product storage 184
7. Treatment and Control Technology 186
Introduction 186
Air pollution control technology .... 190
Wastewater treatment and control
technology 215
Environmental discharges after
application of treatment and control
technology 237
8. Environmental Effects After Treatment .... 243
Introduction 243
Coal composition and wastes 248
Quantities and composition of process
and nonprocess waste discharges 257
Factors influencing environmental
distribution 302
Biological cycling 321
Biological impacts ........... 338
Estimated effects on contacted
ecosystems 393
References 404
Appendices
A. SI (Metric) Conversion Factors 441
B. Sieve Series 444
C. SI Prefixes 445
vi
-------
FIGURES
Number Page
1 Process alternatives for hydrogenation systems . . . xxii
2 Overall synthoil process flow schematic 30
3 Synthoil process flow diagram - hydrogenation
module 40
4 Synthoil hydrogenation module process and waste
streams 42
5 Synthoil process flow diagram - gas separation
module 48
6 Synthoil gas separation module process and waste
streams 49
7 Synthoil process flow diagram - solids separation
module ..... 53
8 Synthoil char de-oiling process flowsheet 54
9 Synthoil solids separation module process and
waste streams 56
10 Synthoil process flow diagram - acid gas removal
process 61
11 Synthoil acid gas removal process and waste
streams 63
12 Overall process flow schematic for a conceptual
H-Coal plant operating in the fuel oil mode . . 68
13 H-Coal process flow diagram - hydrogenation
module 77
14 H-Coal reactor 80
15 H-Coal hydrogenation module process and waste
streams 82
vii
-------
FIGURES (continued)
Number Page
16 H-Coal process flow diagram - gas separation
module 85
17 H-Coal gas separation module process and waste
streams 87
18 H-Coal process flow diagram - solids separation
module 90
19 H-Coal solids separation module process and
waste streams 92
20 H-Coal process flow diagram - fractionation
module 96
21 H-Coal fractionation module process and waste
streams 97
22 H-Coal process flow diagram - acid gas removal
process 102
23 H-Coal acid gas removal process and waste
streams 105
24 Exxon Donor Solvent coal liquefaction process
schematic 110
25 EDS process flow diagram - slurry preparation
and hydrogenation module 120
26 Tetralin as hydrogen donor 122
27 EDS slurry preparation & hydrogenation module
process and waste streams 123
28 EDS process flow diagram - gas separation module . 126
29 EDS gas separation module process and waste
streams 127
30 EDS process flow diagram - solids separation
module 129
31 EDS solids separation module process and waste
streams 131
viii
-------
FIGURES (continued)
Number Page
32 EDS process flow diagram - hydrotreating
module 134
33 EDS hydrotreating module process and waste
streams 136
34 EDS process flow diagram - fractionation module . 138
35 EDS fractionation module process and waste
streams 139
36 EDS process flow diagram - acid gas removal
process 144
37 EDS acid gas removal module process and waste
streams 145
38 Process schematic - coal preparation module . . . 150
39 Synthoil process and waste streams from dry coal
preparation 155
40 H-Coal process and waste streams from dry coal
preparation 156
41 Exxon Donor Solvent process and waste streams
from coal preparation 157
42 Hydrogen generation using Koppers-Totzek Process
(K-T brochure) 167
43 Hydrogen generation module with acid gas removal
process and waste streams 168
44 Oxygen generation facilities (American Air Linde,
Inc.) 175
45 Steam generation with coal-fired boilers 178
46 Cooling water facilities 181
47 Raw water treatment 183
48 Two views of a typical cyclone 193
49 Commonly used filter types 194
50 Electrostatic precipitator 196
ix
-------
FIGURES (continued)
Number Page
51 Venturi scrubber schematic 198
52 Surface area of a packed bed scrubber 199
53 Typical impingement scrubber design 199
54 Typical spray chambers 200
55 Benfield acid gas removal process 202
56 Selexol acid gas removal process 204
57 Claus sulfur recovery process 208
58 Stretford sulfur recovery process 210
59 Beavon tail gas cleanup process 212
60 SCOT Process 213
61 Schematic of corrugated plate interceptor oil-
water separator 221
62 Flow scheme for phenol extraction - Phenosolvan
Process 223
63 Two-Stage all distillation process for ammonia
separation 226
64 Wastewater treatment with activated carbon .... 232
65 Particulate emissions from coal preparation and
handling 236
66 Application of control and treatment technology to
coal liquefaction process wastewaters .... 240
67 Effect of carbonizing temperature on composition
of tar (laboratory retort; medium caking
coal: 86 percent carbon) 236
68 Potential environmental interactions between a
town, coal mine, and conversion plant .... 394
69 Plant, mine and town areas (shown in approximately
correct size relationship) 395
x
-------
TABLES
Number Page
1 Gaseous Discharges from Coal Liquefaction
Systems xxiv
2 Aqueous Discharges from Coal Liquefaction
Systems xxv
3 Residue and Solid Waste Discharges from Coal
Liquefaction Systems xxvi
4 Comparison Between Petroleum Crude, Coal Tar,
and Syncrude from Liquefaction xxxi
5 Comparison of Fuels Resulting from Two
Liquefaction Modes of Operation with Petroleum
Crude xxxi
6 State of Development in Coal Liquefaction .... 6
7 Plans for Future Efforts in Coal Liquefaction . . 8
8 Comparison of Coal Liquefaction Technologies by
Process Modules 12
9 Coal Liquefaction Technology Process Conditions . 17
10 Comparison of Coal Liquefaction Technologies by
Potential Environmentally Significant
Effluents 18
11 Potential Organic-Compound Pollutants ...... 20
12 Potential Inorganic Pollutants 21
13 Potential Pollutant Sources 26
14 Control Approaches 27
15 Material Inventory - Synthoil process 33
16 Overall Material Balance-Synthoil Process , , . . 36
xi
-------
TABLES (continued)
Number Page
17 Heating Value of Selected Products and
Materials in the Synthoil Process 37
18 Synthoil Hydrogenation Module Process and Waste
Streams 43
19 Light Oil Composition - Synthoil Process 44
20 Major Structural Types in Heavy Oil from Synthoil
Process 45
21 PAH-Compounds in Synthoil Oil 45
22 Organic Sulfur Compounds in the Synthoil Products
of Coal Hydrogenation 46
23 Synthoil Gas Separation Module Process and Waste
Streams 50
24 Synthoil Solids Separation Module Process and
Waste Streams 57
25 Analysis of Residues from Pyrolysis of
Centrifuged Solids - Synthoil Process .... 58
26 Analysis of Aromatics in Heavy Oil Product from
Pyrolysis of Centrifuged Solids Synthoil
Process 58
27 Trace Elements in the Centrifuged Residues -
Synthoil Process 59
28 Synthoil Acid Gas Removal Process and Waste
Streams 64
29 Material Inventory for the H-Coal Process .... 70
30 Overall Material Balance-H-Coal Process 74
31 Heating Value of Products and Materials Utilized
in the H-Coal Process 78
32 Composition by Weight Percent of a Typical Fuel
Gas Utilized in the H-Coal Process ...... 79
33 H-Coal Hydrogenation Module Process and Waxte
Streams 83
xii
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TABLES (continued)
Number Page
34 Catalyst Characteristics 84
35 H-Coal Gas Separation Module Process and Waste
Streams 88
36 H-Coal Solids Separation Module Process and
Waste Streams 93
37 H-Coal Fractionation Module Process and Waste
Streams 99
38 Composition of H-Coal Products by Boiling Point
Fractions 101
39 Overall Product Inspections of H-Coal Liquids
(C/ and Greater) Derived from Illinois No.
6 Coal 103
40 H-Coal Acid Gas Removal Process and Waste
Streams 106
41 Material Inventory-Exxon Donor Solvent Process . . 113
42 Illinois No. 6 Coal Analysis 115
43 Overall Material Balance - EDS Process 116
44 Heating Value of Products and Materials in the
EDS Process (Flow Rates from Table 41) .... 117
45 EDS Slurry Preparation and Hydrogenation Module
Process and Waste Streams 124
46 EDS Gas Separation Module Process and Waste
Streams 128
47 EDS Solids Separation Module Process and Waste
Streams 132
48 EDS Hydrotreating Module Process and Waste
Streams 140
49 EDS Fractionation Module Process and Waste
Streams 141
50 EDS Product Analyses 142
xiii
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TABLES (continued)
Number Page
51 EDS Acid Gas Removal Process and Waste
Streams 146
52 Comparison of Dry Versus Wet Coal Cleaning
Processes 151
53 Comparison of the Process Requirements for Coal
Preparation 154
54 Run-of-Mine (ROM) Illinois No. 6 Coal Analysis . . 159
55 Average Ash Analysis of Illinois No. 6 Coal . . . 159
56 Typical Trace Element Composition of Illinois No.
6 Coal 160
57 Characteristics of Coal Pile Runoff 161
58 Fuel and Flue Gas Compositions from the Coal
Preparation Module 163
59 Synthoil Hydrogen Generation Module Process and
Waste Streams 169
60 H-Coal Hydrogen Generation Module Process and
Waste Streams 170
61 Exxon Donor Solvent Hydrogen Generation Module
Process and Waste Streams 171
62 Utilization of Liquefaction Residues 173
63 Waste Streams from H-Coal Synthoil and EDS
Processes 187
64 Potential Control Technology for Air Emissions from
Coal Liquefaction Processes 190
65 Characteristics of Particulate Control Systems . . 191
66 Operating Characteristics of Sulfur Recovery and
Tail Gas Cleanup Processes 205
67 Potential Control Technology for Coal Conversion
Wastewater 216
68 Acid Gases Before and After Treatment 237
xiv
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TABLES (continued)
Number Page
69 Wastewater Characterization Before and After
Treatment 238
70 Commonly Determined Trace Elements in Coal (ppm) . 249
71 Trace Elements in Coal That Are Not Commonly
Determined (ppm) 251
72 Summary of Trace Elements in Coal 252
73 Concentration (ppm) of Elements in Various Coal-
Associated Waste Products 255
74 Trace Elements in Coal Liquefaction Waste Products
Which Are Not Commonly Determined (ppm) ... 256
75 Concentrations of Elements in Various Receivers of
Effluents 258
76 Concentration (ppb) of Organic Compounds in
Various Effluents and Receivers of Effluents . 260
77 Leaching Characteristics of H-Coal Solid Waste . . 261
78 Element Concentration Ratios - Solid Waste: Feed
Coal and Product Oil/Feed Coal 262
79 Concentration of Potential Organic Pollutants in
the Wastewater Effluent from the Synthoil
Process, Compound Concentration (ppm) .... 267
80 Oxidation of Various Carcinogens by Activated
Sludges 268
81 Chemical Composition of Equilibrium Aqueous
(1:1 Wt/Vol) Extracts from Fly Ash 269
82 Inorganic Elements in the Ash from Lurgi Gasifier
and the Mineral Residue from the H-Coal
Process Utilizing Illinois No. 6 Coal .... 272
83 Conversion Catalysts 275
84 Polynuclear Hydrocarbon Concentrations - Units A
and B (Micrograms Per GJ Input) 276
85 Chemical Waste Characteristics of Coal Pile
Drainage (ppm) 278
xv
-------
TABLES (continued)
Number Page
86 Shawnee Pond Data 280
87 Shawnee Disposal Demonstration Input Sludge
Analysis Record 280
88 Comparisons of Products and Process Parameters
of Coal Liquefaction Plants and Similar
Industries 282
89 Inspection of Products from Illinois No. 6 and
Wyoming Subbituminous Coals 288
90 Composition of Condensable Compounds from Coal
Gas 291
92 Chemical Analyses of Petroleum 293
92 H-Coal Product Composition 293
93 Major Structural Types in Heavy Oil and Asphaltene
Fractions from Synthoil Product 294
94 PAH Compounds in Synthoil Samples 294
95 PAH in COED Samples 294
96 Estimation of PAH Concentrations in Coal-Derived
Materials 295
97 Polynuclear Hydrocarbon Content of Particulate
Matter Emitted by Incineration and Open-
Burning Sources 296
98 Quantitative Data for Methyl Chrysenes in a Coal
Liquefaction Product 297
99 Trace Element Composition in Various Feed Coals
and Resultant Distribution After a Laboratory
Liquefaction Process in an Autoclave 298
100 Estimate of Sulfur Levels in Combined Liquid and
Solids Products from Liquefaction Processes. . 299
101 Distribution of Sulfur in Petroleum Fractions . . 300
102 Organic Sulfur Compounds in Synthoil Product . . . 301
xvi
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TABLES (continued)
Number Page
103 Boiling Points of Selected Elements Associated
with Coal - °C 303
104 Leachability of Inorganic Elements from Coal
Refuse and Spoil Piles 313
105 Solubility of Polynuclear Aromatic Hydrocarbons
in Water 314
106 Physiochemical and Related Data for Metals .... 316
107 Interactions of Selected Inorganic Elements in
Soils 322
108 Routes of Absorption and Excretion for Various
Elements 327
109 Bioconcentration Factors for Various Elements in
Various Groups of Organisms 333
110 Environmental Distribution of Specific PAH .... 338
111 Toxicity Potential and Potential for
Bioaccumulation of Elements in Process
Streams 342
112 Elements Which Exceed Recommended Water Quality
Levels Utilizing a Ten Percent Solution of
Lurgi Ash or H-Coal Residue (Concentrations
in ppb) 344
113 Adverse Effects of Elements on Animals 346
114 Adverse Effects of Several Organic Compounds and
Elements on Humans 347
115 Human Toxicity and Threshold Limit Values of Some
Potential Pollutants from Coal Conversion
Processes 348
116 General Toxic Effects of Elements to Plants,
Animals, and Microorganisms 352
117 Standards and Acceptable Levels of Trace
Elements 358
118 Reduction of Toxic Effects of One Trace Element
by Another 361
xvii
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TABLES (continued)
Number Page
119 Adverse Effects for Selected Organic Compounds
Potentially Emitted by Liquefaction
Plants 363
120 Most Sensitive Organisms to Various Organic
Chemicals 364
121 Summary of Environmental Information on Classes
of Inorganic Coal Conversion Effluents .... 373
122 Unadjusted Ratios of Predicted to Observed LD50
Values of 350 Pairs of Chemicals Mixed 1:1
by Volume 374
123 Known or Suspected Carcinogens Which Hay Be in
the Effluent Streams of Coal Liquefaction
Plants 378
124 Specificity of Carcinogenic Activity 381
125 Aquatic Toxicity of PAH 385
126 Temperature Range of Carbonizing Chambers and
Excess of Lung Cancer Reported 388
xviii
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ACKNOWLEDGEMENTS
This report was prepared by the staff of Hittman
Associates, Inc., Columbia, Maryland, under the direction of
Mr. Wayne Morris, Program Manager.
For their contributions and assistance, our apprecia-
tion is extended to the following members of Hittman Asso-
ciates' Technical Staff:
Vincent Di Pasquale
David Dow
John Duck
Homer Hopkins
Efim Livshits
Kathleen McKeon
Subhash Patel
John Robbins
Anthony Shemonski
Kevin Shields
Carolyn Thompson
Earl Weir
xix
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EXECUTIVE SUMMARY
The three coal liquefaction processes given environ-
mental characterization in this report - H-Coal, Exxon Donor
Solvent, and Synthoil - have similar products and wastes
within the estimation accuracy allowed by available informa-
tion. These products and wastes are dictated in general
amount and composition by:
(1) Ash and inert residues in the feed coal
(.2) Sulfur, oxygen, and nitrogen content of the feed
coal
(3) Operations and auxiliary processes such as coal
preparation; generation of needed hydrogen, oxy-
gen, steam, and electricity; and by-product
recovery
(4) Treatment and control technology used for waste
treatment in all media
(5) Treatment and control technology in all media
waste generation (e.g., sludges from biological
treatment of wastewaters and wastes from sulfur
dioxide removal technologies)
(6) Operating conditions for the process
xx
-------
(7) Treatment, use, and disposal options for residues,
chars, bottoms, and other solid or high-boiling
fractions.
In general, the factors above are expected to have more
influence on the environmental discharges, impacts, and
needed safeguards than the specific liquefaction process
involved.
Figure 1 shows the general modular diagram for hydro-
genation coal liquefaction systems. This diagram applies to
the three systems covered in this report, and the Solvent
Refined Coal System, all of which use hydrogenation tech-
nology.
For the purposes of this report, the three coal lique-
faction systems have been divided into two portions:
(1) General operations and processes which may be
expected to be common to all three systems
(2) Operations and processes specific to each system
The division above makes it possible to discuss spe-
cific operations and processes individually and in detail
while the general operations and processes can be covered in
one discussion common to all three systems.
General operations, processes, and facilities include
coal preparation; heat and power generation; cooling water
provision; hydrogen and oxygen generation; storage for raw
materials; waste treatment and control installations; and
personnel and process-related buildings, storage, and trans-
portation facilities. Environmental discharges, with the
xxi
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-COAL LIQUEFACTION —
-SYSTEM OPERATIONS —
_PRODUCT UPGRADING,.
AND RECOVERY
CONTROL | AUXILIARY
- EQUIPMENT 4-— PROCESSES
FACILITIES I
| FlHAl ]
— DISPOSAL
I PROCESSES 1
HATER
SUPPLY
X
slurrying
AMD
PREHEATIH6
RECfUEi
SOLVENT
VACUUM
DISTILLATION
12
1
COKING
13
SOLIDS J—" TO 6 OR 19
GASEOUS
WASTE
TREATMENT 17
/wfine\
"FROOIXTy^O 25
WASTEWATER
TREATMENT
SOL 10
UASTE
TREATMENT 19
TRANSIENT
WASTE
TREATMENT 20
STEAM AND
POWER
GENERATION 24
MISCELLANEOUS
DISPOSAL
PRACTICES u
MISCELLANEOUS
BY-PRODUCT
RECOVERY 28
HYDROGEN
PRODUCTION
Figure 1. Process
alternatives for
hydrogenation systems
-------
possible exception of hydrogen generation, can be estimated
directly from similar installations in other industries.
Operations and processes specific for each system
include hydrogenation, phase separations, and acid gas
treatment. Other operations and processes will be present
for specific system variations. The product and waste
stream discharges from this portion of the system were not
estimated from a similar facility, since there is none.
Instead, product and waste stream discharges for this por-
tion of the system have been estimated from information
available as of September 1977 for bench-scale, PDU, and
pilot plant units.
The estimated raw and treated waste discharges for
3
7,950 m (50 kbbl) per day conceptualized systems using the
three liquefaction processes covered in this report are
summarized in Tables 1, 2, and 3.
Gaseous emissions from coal liquefaction processes can
be estimated reasonably well for the major contaminants.
Most of the major contaminants of the process gas stream
such as hydrogen sulfide, ammonia, and carbon dioxide have
to be largely removed as part of processing requirements.
Therefore, it is estimated that these components will be
reduced to low levels in the gaseous emissions, as shown in
Table 1. Whether these levels are sufficiently low to
avoid environmental or health problems is under study through
the EPA.
Process wastewater, from sour gas scrubbing, acid con-
densates, and other sources for the studied processes, is
estimated roughly as 3,785 (1 mgal) per day. The estimated
xxiii
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TABLE 1. GASEOUS DISCHARGES FROM COAL LIQUEFACTION SYSTEMS
(EXTRACTED FROM SECTIONS 3,4, & 5)
For Conceptualized 7,950 m (50 kbbl) per day plants
Source + *
Syntholl
Process
H-Coal
EDS
law wastes
After treatment**
Raw wastes
After treatment**
Raw wastes
After treatment**
Metric
tons/day
(tons/day)
Metric
tons/day
(tons/day)
Metric
tons/day
(tons/day)
Metric
tons/day
(tons/day)
Metric
tons/day
(tons/day)
Metric
tons/day
(tons/day)
Acid gas (process)
Total
1,662
(1,832)
1,169
(1,289)
1,201
(1,325)
659
(727)
854
(941)
553
(610)
V
623
(687)
2-10ppm***
680
(749)
2-10ppm**
* 300
(331)
2-10ppm***
HH-
5.7
(6.3)
5.7
(6.3)
0.5
(0.6)
0.5
(0.6)
7.5
(8.3)
7.5
(8.3)
c°2
988
(1,090)
988
(1,090)
493
(544)
493
(544)
541
(597)
540
(596)
Hydrocarbons
42
(46)
42
(46)
20
(22)
20
(22)
3.9
(4.3)
3.9
(4.3)
>2°
2.4
(2.7)
133
(147)
8.6
(9.5)
145
(160)
N.A.
N.A.
Acid gaa (hydrogen
production)
Total
8,530
(9,404)
8,395
(9,255)
8,932
(9,847)
8,789
(9,690)
6,245
(6,885)
6,146
(6,776)
133
(1*7)
2-10ppm***
140
(154)
2-10ppm***
98
(108)
2-10ppm***
TO
0.9
(1)
0.9
(1)
0.9
(1)
0.9
(1)
0.6
(0.7)
0.6
(0.7)
»!
8,346
(9,201)
8,346
(9,201)
8,738
(9,633)
8,738
(9,633)
6,110
(6,736)
6,110
(6,736)
so2
0.2
(0.23)
****
0.2
(0.24)
**»*
0.15
(0.17)
****
HCN
2
(2.2)
trace
21
(2.3)
trace
1.5
(1.6)
trace
M2
48
(53)
48
(53)
50.8
(56)
50.8
(56)
35.4
(39)
35.4
(39)
HO
X
trace
trace
trace
trace
trace
trace
Flue gas (heat
& power)
Total
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
s°2
376
(414)
18.7
(20.7)
N.A.
N.A.
N.A.
N.A.
HO
X
63.6
(70.2)
N.A.
N.A.
N.A.
N.A.
N.A.
X
x
<
Until thorough environmental sampling and analyses of all streams have been performed, these lists will not be complete.
* Emissions fro» coal preparation, fugitive emissions from leaks and spills, and other miscellaneous atmospheric discharges have not been quantified.
** Acid gaa streams are combined before treatment.
*" Released as S02, after flaring.
****leleasad as SO2, after flaring; quantities not available.
¦•A.- Mot available.
-------
TABLE 2. AQUEOUS DISCHARGES FROM COAL LIQUEFACTION SYSTEMS
(EXTRACTED FROM SECTIONS 3, 4, & 5)
3
For Conceptualized 7,950 m (50 kbbl) per day plants
Source"1"
Process
Synthoil B-Coal EDS
Raw wastes After treatment** Rav wastes After treatment** Raw wastes After treatment**
Metric Metric Metric Metric Metric Metric
tons/day (tons/day) tons/day (tons/Jay) tons/day (tons/day) tons/day (tons/day) tons/day (tons/day) tons/day (tons/day)
Sour water (process)
Total (in- 3,556
eluding water)
10.9
HjS
Oil
Phenols
MK,
9
125
(3,920)
(12)
(10)
(138)
3,411 (3,760) 4,557
0.15ppn 175
0.1 ppm
10 ppm
23.6
103
(4,913)
(193)
(26)
(114)
4,154 (4,580) 1,974
0.15ppa
0.1 ppa
10 ppa
18
180
(2,176) 1,776 (1,958)
N.A. 0.15ppa
(20) 0.1 ppm
(198) 10 ppa
X
X
<
Hydrogen generation****
Clarifler 235 (259)
overflow
Other wastewater 1,150 (1,268)
N.A. 419 (462) 419 (462) 172 (190)
N.A. 1,204 (1,327) 1,204 (1,327) 841 (927)
N.A.
N.A.
Cooling tower blowdown
Total 621
(685) 621 (685)
563
(621)
563
(621)
N.A.
N.A.
Coal preparation
Total
Water
Tailings
Coal pile •**
runoff
63.5
(70) 63.5 (70)
63.5
(70)
63.5
11,000**
7,109
3,828
(70) 63.5
(12,127)**
(7,837)
(4,220)
(70)
63.5
N.A.
N.A.
N.A.
(70)
Until thorough environmental sampling and analyses of all streams have been performed,
these lists will not be complete.
* Using dry coal preparation.
** Dsing water technique for extensive coal preparation.
*** Rainfall estiaate (based on Illinois rainfall).
****Koppers-Totrek process described in Section 7.
N.A. - Hot available
Table values are those developed in Sections 4 through 8.
-------
TABLE 3. RESIDUE AND SOLID WASTE DISCHARGES FROM
COAL LIQUEFACTION SYSTEMS (EXTRACTED FROM SECTIONS 3,4, & 5)
3
For Conceptualized 7,950 m (50 kbbl) per day plants
Source +
Process
Synthoil
H-
¦Coal
EDS
Metric
tons/day
(tons/day)
Metric
tons/day
(tons/day)
Metric
tons/day
(tons/day)
Residues (process)*
Total
206
(227)
1,444
(1,592)
2,106
(2,332)
Organic
98
(108)
722
(796)
1,445
(1,593)
Ash
108
(119)
722
(796)
661
(729)
Hydrogen generation
Total ash sludge**
3,526
(3,887)
1,889
(2,082)
2,600
(2,866)
Process related
1,620
(1,786)
1,116
(1,230)
689
(760)
Ash from added coal
495
(546)
none
362
(399)
Water
1,411
(1,555)
773
(852)
1,548
(1,707)
Heat & power
generation
(Boiler ash)
557
(614)
none
none
SC>2 scrubber sludge
4,744
(5,230)
use fuel
gas
Treatment/control
wastes
N.A.
N.A.
N.A.
Coal preparation
Total
1,279***
(1,410)***
1,007***
(1,110)***
7,175****
(7,910)****
Dry refuse
1,270
(1,400)
998
(1,100)
1,451
(1,600)
Wet refuse and
tailings
N.A.
N.A.
5,715
(6,300)
Dust
oarticulates
9
(10)
9
(10)
9
(10)
+ Until thorough environmental sampling and analyses of all streams have been performed,
these lists will not be complete.
* Based on excess from that needed for hydrogen generation. See Section VII for detail*.
Does not include spent catalyst and other miscellaneous solid wastes. Specific to
Sections 4, 5, and 6 coals.
** Includes asfi from Che process residue, ash from the make-up coal and quench water.
*** Using dry coal preparation, removal of debris only.
**** Using water techniques for extensive coal preparation. See Section 7 for
rationale.
N.A. Not available.
XJCVi
-------
waste load before and after treatment is given in Table 2.
Some raw wastes, such as hydrogen sulfide and ammonia,
present in the process gas streams may be removed by existing
technology. The major unknown factor for process gas
streams and emissions is the effect of volatile or particu-
late trace contaminants specific to coal liquefaction processes
on both the composition of the discharges and the conceptu-
alized treatment and control technology performance. The
presence and amount of volatile metals; metallic compounds
such as carbonyls, particulates, organics; and other possible
trace contaminants in gaseous process streams and emissions
have not been determined. Furthermore, the presence and
amount of these trace contaminants will depend on other
factors such as treatment and control technologies used,
leaks and spills, and process design. The potential hazard
from these emissions is a matter of grave concern.
Conceptualized treatment for process wastewater in-
volves oil separation, phenols extraction, and ammonia
stripping to remove these components and is followed by bio-
logical treatment and carbon adsorption. The technology
most often used for removing soluble organics from wastewater
is biological treatment. This technology biodegrades some
of the organics but others go through the system unchanged.
Carbon adsorption or another treatment technology may be
needed to remove these residual organics.
The oils, phenols, ammonia and biodegradable portions
of the process wastewater streams may be expected to be
removed to the approximate levels given in Table 2. The
refractory and trace pollutants that will go through the
conceptualized liquid treatment system, or require use of
other or additional treatment technology, still need to be
xxvii
-------
defined. Based on very limited information and rough ap-
proximations discussed in Section 7, both refractory organ-
ics and inorganic trace elements remaining after treatment
may be below current or projected regulatory limits for
these materials. However, this is not meant to dismiss any
concern regarding potential hazards. Exact status needs to
be determined by sampling and physical, chemical, and bio-
logical evaluations.
Cooling tower blowdown from the 7,950 m (50 kbbl) per
day conceptualized processes is roughly estimated at 568 m
(150,000 gal) per day. In addition to the chemicals added
for corrosion and biological growth control, leaks and other
sources of contamination by the process streams are pos-
sible. Conventional treatment technologies used at coal-
fired steam electric plants or other such facilities (e.g.,
refineries) should be applicable to handling blowdown if
process contamination is not too severe. Here again there
is concern for the potential hazards, and their extent
should be determined. Significant wastewater, approximately
3
1,514 m (400 kbbl) per day, is also generated in the hydro-
gen generation module. Table 2 summarizes these waterborne
wastes and the major pollutants involved.
Flue gas from power generation is the major nonproduct
discharge from coal liquefaction systems. According to
the aforementioned SPM (EPA 600/7-78-091), an 18,200 metric
ton (20,000 tons) per day SRC plant has an estimated flue
gas output of 12,000 metric tons (13,150 tons) per day.
Residues and solid waste constitute additional nonproduct
discharges from the system. The amounts of carbon-contain-
ing components in the solid wastes and residues depend on
the conceptualized processes employed. For a 7,950 m (50
kbbl) per day system, all three liquefaction processes of
this report have approximately 4,536 metric tons (5,000 tons)
xxviii
-------
per day of residue containing a mixture of high-boiling
organics and inorganic materials. To date, no one has
reported actually using this residue for any purpose. The
most prevalent concept is to pyrolyze the residue to remove
additional liquid product, leaving a carbon-containing
mixture of char and inorganic inerts. The carbon-containing
mixture is then used as fuel in the hydrogen generation
module. The nature of these discharges has a significant
impact on the expected environmental effects. Using the ash
as an example, if the organic component of the residues from
the phase separation operation has been removed by subse-
quent combustion in a furnace or gasifier, the remaining ash
may be expected to be similar to that for coal-burning
furnaces, and the problems of ash disposal would be expected
to be similar. If significant organic material remains in
the waste, then it must be considered potentially hazardous
to human health, and extra disposal precautions would have
to be taken. This might involve incineration, secure land-
filling, or other applicable technology.
Treatment of liquefaction process carbon-containing
solid wastes and residues presents a process development
challenge that appears to need additional attention. Sig-
nificant improvements of product yields may be possible
through pyrolysis or other technologies. Combustion of the
solid waste to generate hydrogen, steam, fuel gas, or other
products is a possibility. Presently, however, this solid
waste must be considered as potentially hazardous to human
health.
In addition to the carbon-containing solid wastes and
residues resulting from phase separation and hydrogen gen-
eration operations and processes, large quantities of
sludges (see Table 3) may also be generated by sulfur dioxide
treatment and control processes. Sludge will also be
xxix
-------
generated from physical and biological wastewater treatment
processes.
Coal liquefaction products themselves are a source of
significant concern. Table 4 shows a comparison of petrol-
eum, coal tar, and liquefied coal products. Coal tar and
coal liquefaction products contain 85 and 73 weight percent
aromatic and cyclic hydrocarbons, respectively, while petro-
leum has only 35 weight percent. The remaining 65 percent
of petroleum is aliphatic hydrocarbons. The aromatic hydro-
carbon content, which is significantly higher in coal tar
and liquefied coal products than in petroleum, is the source
of the most biologically active (carcinogenic, mutagenic,
teratogenic) compounds. Therefore, leaks, spills, handling,
transportation, storage, and use of products may well re-
quire attention similar to coal tar chemicals and other
known biologically active substances.
For some compounds, coal tar is not a good model. The
reported benzo(a)pyrene (a known carcinogenic material)
level in syncrude, is closer to that in petroleum than in
coal tar. There is a definite need for independent analy-
tical data on the level of known toxic substances in coal
liquefaction products.
Liquefaction products vary with the envisioned end use.
For example, SRC products are primarily intended as fuel for
plants generating electricity. As such, the main emphasis
has been on removal of sulfur and any other feed coal com-
ponents that would cause problems in meeting current regu-
lations. Operating in the SRC-I mode, solids product is
made. More stringent hydrogenation and molecular breakdown
of the feed coal can be achieved, however, to give liquid
fuels (SRC-II mode). Like the SRC process, the three pro-
cesses of this report may be modified to give a range of
XXX
-------
TABLE 4. COMPARISON BETWEEN PETROLEUM CRUDE,
COAL TAR, AND SYNCRUDE FROM LIQUEFACTION
Category
Liquefaction
syncrude (1,2)
(approx. wt %)
Petroleum
crude (3,4,5,6)
(approx. wt %)
Coal
tar (5,7,8,9)
(approx. wt %)
Nonaromatic
25
65
7
Aromatic (other than
below)
33
35
85
%
PAH and hetrocyclics
40
Phenols
2
1-5.0
Sulfur
0.5
0.5
1.0
Nitrogen
0.2
1.0
1.2
Benzo(a)pyrene
0.005
0.003
0.2-2.0
*PAH = polynuclear aromatic hydrocarbons
TABLE 5. COMPARISON OF FUELS RESULTING FROM
LIQUEFACTION MODES OF OPERATION WITH PETROLEUM
(WT PERCENT OF MAF* COAL)
TWO
CRUDE
Illinois coal
Normalized
product distribution
Low-sulfur
fuel oil (1)
Synthetic
crude (1)
Petroleum
crude (6,10)
C^-C^ hydrocarbons
6
12
1
C.-400°F distillate
4
14
19
20
400-650°F distillate
22
31
30
650-975°F distillate
20
21
35
975°F + residual oil
34
11
14
Unreacted ash-free coal 8
6
__
*Moisture and ash-free basis.
XXX i
-------
different products. Table 5 compares the compositions of H-
Coal process products for two modes of operation to that of
petroleum crude. At relatively mild hydrogenation condi-
tions, the H-Coal process low-sulfur fuel oil of Table 5 has
42 weight percent of unreacted coal and bottoms residue. At
more severe hydrogenation conditions, the H-Coal process
synthetic crude (Table 5) has only 17 weight percent un-
reacted coal and bottoms residue and is beginning to resemble
petroleum crude in its product boiling point distribution.
Therefore, it is necessary to know the involved processing
mode before environmental discharges can be determined.
Oftentimes the mode and conditions of process operation for
the process will have more influence on the environmental
discharges than the selection of liquefaction process
itself.
In line with earlier discussion on available technology
to remove or control wastes such as hydrogen sulfide, sulfur
dioxide, ammonia, and phenols, the most critical concerns
over environmental potential effects are with the lesser-
volume waste and product components such as trace elements
and biologically active organics. This is partially true
because while some attention is being addressed to the high-
volume pollutants, neither the presence nor the effects of
these lesser-volume substances can be quantified at this
time. Section 8, however, is devoted to a detailed dis-
cussion of current knowledge regarding their possible pres-
ence, known behavior, and potential for environmental
impact. On the basis of very limited information, it
appears that the environmental effects of discharges from
coal liquefaction complexes will lie between those from
petroleum refineries and those from coal tar facilities.
A difficult environmental or health characterization
area is the assessment of the effects of coal liquefaction
xxxii
-------
products and wastes on workplace personnel. Since some
environmental discharges will also be potential problems of
workers, coordination of programs by various groups is
important. This workplace assessment suffers from the dual
handicap of undefined plant discharges and the lack of
sufficient human health data to predict their effects even
in the instances where some definition is possible. Section
8 represents an attempt at partial definition of the expected
environmental effects resulting from a conceptualized com-
mercial coal liquefaction facility. Overall assessment
indicates that extensive attention will need to be given to
minimizing leaks, spills, and other fugitive emissions which
can affect the worker and the environment.
To supplement this environmental or health character-
ization study, it is recommended that the following investi-
gative priority be established:
(1) Quantify process wastewater streams and their
composition, using the control assay procedure
approach of IERL/RTP methodologies. Laboratory
experiments should first be run on samples of
these streams for such simple tests as oil separa-
tion, suspended solids removal, soluble organics,
phenol extraction, and carbon adsorption. Analy-
sis should then be made for the oil, water, and
solid phase compositions, particularly for trace
elements and biologically active organics.
(2) Similarly quantify gas stream compositions both
before and after treatment. Special attention
should be given primarily to trace components
while also obtaining data on major constituents
such as hydrogen sulfide, ammonia, and carbon
dioxide.
xxxiii
-------
(3) Determine product, solid waste, and residue compo-
sitions. Analysis should be primarily aimed at
known toxic and hazardous chemicals using the
MEGs list (11).
(4) Assemble all known information, plus the results
of (1), (2), and (3) above, to form a data base
and model for determining plant discharges to the
environment.
(5) Supplement information present in MEGs with other
known information on the toxicological properties
of identified product and waste constituents (11).
(6) Perform environmental assessment of coal lique-
faction processes, based on information collected
in (1) through (5) above.
xxx iv
-------
SECTION 1
INTRODUCTION
The purpose of this report is to establish a technical
base that is expert in the environmental aspects of the coal
liquefaction technology. The report describes the necessary
technical process information and emphasizes the environ-
mental considerations. It includes flow diagrams, equipment
descriptions, and input and output of operations for all streams
including intermittent discharges, by-products, and emissions.
It also includes product yields, energy efficiencies, material
inventories, and balances.
On the basis of preliminary prioritization studies
(see pg. 4), four coal liquefaction processes have been
selected for detailed environmental study in subsequent
phases of the contract. These four processes are Solvent
Refined Coal (SRC), H-Coal, Synthoil, and Exxon Donor Sol-
vent (EDS). Since initiating this study, events have
occurred which indicate Synthoil may not be developed to
a larger scale; however, since work was already completed
on this process, the information is presented here.
The Solvent Refined Coal process is being covered in a
separate report (SRC Standards of Practice Manual). The
other three processes are covered in this environmental
characterization report. Coverage includes process and ma-
terial balance descriptions for each; definition of products
1
-------
and wastes, auxiliary processes such as coal preparation,
and treatment and control technology; environmental effects
of process effluents; and technology assessments and com-
parisons .
Environmental characterization of product and waste
discharges from coal liquefaction facilities can only be
estimated at this time. Since there is no commercial-sized
installation, expected discharges for such installations
must be extrapolated from bench-scale equi/pment, process
development unit, and pilot plant findings. In addition to
being subject to scale-up extrapolations, discharge estimates
are also hampered because most available data centers on
the process modules that are essential to coal liquefaction
and product recovery and not on waste treatment, control, or
utilization. In most cases, these waste-related modules
have neither been defined nor incorporated in PDU and pilot
plant facilities. Another factor hampering accurate estimates
of process discharges is the virtual absence of information
on the quantitative composition of the product and waste
streams as related to environmental effects. There is a
lack of performance data from operating facilities.
In the context of the above restrictions, this report
provides documentation and evaluation of existing data prior
to more exhaustive subsequent studies in environmental
assessment reports (EARs) and standards of practice manuals
(SPMs).
The basis used to estimate and quantify product and
3
waste discharges was to conceptualize 7,950 m (50 kbbl) per
day commercial installations for the H-Coal, EDS, and Synthoil
coal liquefaction processes and discuss their environmental
2
-------
effects. The data input was that available as of September
1977. With the rapidly evolving data base and technology
development expected from coal liquefaction operations
during the next 1 to 2 years, it is anticipated that period-
ic updating and expansion of this environmental character-
ization report will be needed.
It is also anticipated that coal liquefaction plants
will be integrated industrial complexes similar to present
petroleum refineries and petrochemical installations. In
addition to the basic coal liquefaction process itself,
other large operations and processes such as coal cleaning
and preparation, hydrogen and fuel gas generation, heat and
power generation, oxygen generation, waste recovery, treat-
ment and control installations, fractionations, chemical pro-
duction, and storage and handling facilities will be included.
It is hoped that this report will show the areas of potential
environmental discharge problems and the challenges and
opportunities for their solution.
3
-------
SECTION 2
TECHNOLOGY ASSESSMENTS AND COMPARISONS
INTRODUCTION
A data base from existing literature has been estab-
lished for prioritization and environmental characterization
of systems in the technology of coal liquefaction. Few
original sources were found where environmental factors were
addressed, especially in the areas of waste treatment and
control installations. For any continuation of the assess-
ments and comparisons, it thus becomes necessary to con-
ceptualize major portions of processes. Some similarity of
wastes and discharge streams has therefore been imposed
because of the meager existing data. This report provides
an evaluation of the more prominent schemes for coal lique-
faction, with greater emphasis on the Synthoil, H-Coal, and
Exxon Donor Solvent processes.
Because limited resources preclude the environmental
evaluation of all the processes identified in the litera-
ture, four were selected as the best possibilities for
evaluation. They include the Solvent Refined Coal (SRC)
Process in addition to the three named above. The SRC
process evaluation is contained in a Standards of Practice
Manual. Criteria used for the selection of the four processes
include some sixteen factors ranging from the stage of
development to the hazard potential of residual emissions.
4
-------
Since work began on this study, the schedule for devel-
opment of the Synthoil Process has been interrupted and
development may not be resumed. However, because the ma-
terial was already assembled and because the Synthoil Pro-
cess is representative of the several processes in its
category, the information is included in this report.
PRESENT PROCESS STATUS
State of Development
Overall Status-
Table 6 provides information regarding the current
status of coal liquefaction processes. Development of most
of these is partially sponsored by the United States Depart-
ment of Energy (DOE). The only pilot plants now in opera-
tion are the SRC units, one at Ft. Lewis, Washington, and
the other at Wilsonville, Alabama. There are no demonstration
plants now in operation. The only commercial coal lique-
faction plant currently operational is in the Sasol Fischer-
Tropsch complex in South Africa.
Processes Selected for Study--
Bench-scale operations have been performed for the
Synthoil process. Analyses of product and waste products
have been made. A PDU designed for the Synthoil process is
nearing completion, but technology other than Synthoil will
be utilized for its operation.
For the H-Coal process, operations have been conducted
in bench-scale and PDUs. A 544-metric ton per day pilot
plant is under construction at Catlettsburg, Kentucky (12).
5
-------
TABLE 6. STATE OF DEVELOPMENT IN COAL LIQUEFACTION
Specific process
Status
Synthoil (12)
H-Coal (12)
EDS (12) SRC (12)
Bergius (12)
Costeam (14)
COED (14)
Conoco/DOE
ZnCl? (12)
Demonstrated scale*
0.45
2.7
0.9 45
2040
Lab
33
Lab
Development plan*
Continued
evaluation on
bench scale
544
227 Evaluation Completed
of SRC-II
Evaluation
Completed
PDU
Availability
•>
1978
1981 1980
Now
?
Now
1980
Applicability
(i.)(g.)(h.)
(i.Hg.Hh.)
(i.Hh.) (i.)(g.)
(1.)(j.)(k.)
(g.)
(i.)(1.)
(1.)
Waste treatment/
control demonstration
No
No
No Yes
Unknown
No
No
No
Commercial status
No
No
No No
Yes
No
No
No
Type of process
(a.)
(a.)
(e.) (b.)
(a.)
(b.)
(c.)
(a.)
Status
Clean Coke (12)
Toscoal (15)
Occidental
Research
Corporation (ORC) (12)
Fischer-Tropsch (13)
Supercritical
Gas
Extraction (SGE)
(16)
Methanol
Synthesis
Demonstrated scale*
0.45
22.5
3.2
6000
Lab
Completed
Development plan*
7
225
Completed
Evaluation
Completed
Availability
•>
1
?
Now
?
Now
Applicability
(g.Mk.)
(i.)(h.)
(i.)
(k.)(g.)(h.)(i.)(j.)
(k.)(i.) (j . )
(l.)(j.)(k.)
Waste treatment/
control demonstration
No
No
No
Yes
No
1
Commercial status
No
No
No
Yes
No
Yes
Type of process
(c.)
(c.)
(c.)
(d.)
(f.)
(d.)
(a.) Catalytic liquid phase hvdrogenation
(b.) Noncatalytic liquid phase hydrogenation
(c.) Pyrolysls & hydrocarbonization
(d.) Catalytic synthesis
(e.) Doctor Solvent
(f.) Extraction
* Nominal capacity in metric tons per day
(g.) Electric utility fuel production
(h.) Industrial fuel production
(i.) Synthetic crude production
(*.) Domestic fuel production
(k.) Industrial cheraical production
(1.) Transportation fuel production
-------
Studies of process variables have been made for the
Exxon Donor Solvent system during operation of a PDU (12).
Little has been published on this proprietary technology.
The SRC pilot plants are in operation, and the Ft.
Lewis facility provided fuel for a combustion test in June
1977 in a conventional steam generation boiler.
Plans For Future Effort
Overall Plans-
Table 7 provides information regarding future plans for
coal liquefaction development projects.
Funding for the four processes selected for study
currently totals $258 million, which far outweighs any other
identified coal liquefaction expenditure. These are accumu-
lated costs plus the costs expected to complete projected
plans through 1980 (12).
The next pilot plant expected to become operational is
the H-Coal installation scheduled for FY 1978. The next
operational pilot plant after that will probably be the
Exxon Donor Solvent installation planned for operation in FY
1980 (12).
Sasol-II, a large commercial Fischer-Tropsch Process
plant in South Africa, is scheduled to begin operation in
1980 (17).
Plans For The Selected Processes--
For the Synthoil process, bench-scale operations are
continuing; however, the 9.1-metric ton per day PDU now
nearing completion will definitely not be used for the
7
-------
TABLE 7. PLANS FOR FUTURE EFFORTS IN COAL LIQUEFACTION
Specific pTocesa
Statu* Syittholl (12)
IKotfl (1?)
KDS (12)
Bcrglus
(l?)
SRC-11
(17) C.<*t<-na
(|/i) 0>ED
(14)
Conoco/DOE
ZnCl2 (12)
Vuadloi sources:
Govtraainc
Industry
100X
4/5
1/5
1/2
1/2
_______
1001
7/8
1/8
Present funding
$ * 106
27.9
179
12.7
0
62.1 ?
0
6.4
Type of process:
Proprietary
Govt. funded
-
Scale-up
undervay
No
Pilot plant
under con-
^t ruction
No
No
No 1
No
PDU under
construc-
tion
Scale-up
planned
No
No
Design pilot No
plant
No »
No
No
Operational
status:
Active
Inactive
Ac t Ivc.
Active
Active
Znactlve
Active Active
Inactive
Active
Future plants Lab studies
Pi lot plant
operation
Pilot plant None
operation
Pilot None
plant oper-
ation thru
FT 80
None
PDU operation
thru FY80
Status
Clean coke (12) Toscoal
(12) ORG (12)
Plscher-Tropsch (17)
Methanol
Synthesis
Supercritical
Gas
Extraction (16)
Funding sources:
Government
Industry
7/10
3/10
—
loot
The
Coal
Corp
South African
» Oil & Gas
. Ltd. (SASOL)
None
National Coal
Board (G6)
Catalytic, Inc.
Present funding
* * I06
11.8
Unknown
3.8
1.5 billion +
Unknown
Unknown
Type of process:
Proprietary
Govt, funded
....
...
.
British Govt.
Scale-up planned
No
No
Ho
TTcs
No
No
Scale-up underway
No
No
No
Yes
No
No
Operational atacus
Active Active
Inactive
Inactive
Active
Active
Inacttvo
Inactive
Future plans
Development None
studies
Development
fCudle*
A new 14-iaiUlon
too/jr plane
None
Unknown
-------
Synthoil process (personal communication from DOE). At this
time, it appears that no future scale-up or pilot plant
activity will be forthcoming.
Operation of the 544-metric ton per day H-Coal pilot
plant is scheduled for the period FY 78 through 1980 (12).
A 227-metric ton per day Exxon Donor Solvent process
pilot plant is planned for construction at Baytown, Texas
(12). Operation is scheduled for FY 80 to 82.
The SRC pilot plant is scheduled for operation through
FY 80 (12).
The H-Coal, SRC, and EDS pilot plants should offer the
best sources for environmental assessment of coal lique-
faction plant discharges within the next 2 to 3 years.
COMPARISON OF PROCESSES
Overall Modular Analysis
Types of Processes-
All liquefaction processes achieve the objective of
producing liquids by yielding a material having a higher
hydrogen content than coal. Hydrogen is present in coal at
a level of about 5 percent. In high-Btu gas it is roughly
25 percent. Fuel oils contain 9 to 11 percent hydrogen and
gasoline contains about 14 percent.
In general, liquefaction processes offer several ad-
vantages over gasification of coal. Overall thermal
efficiency is usually higher, and, as indicated above,
hydrogen requirements on a weight percent basis are much
9
-------
lower than in gasification. Liquid fuels have much higher
mass and energy densities than fuel gases. These advantages
should cause more rapid development and commercialization of
new liquefaction rather than new gasification processes.
Currently, approximately 20 coal liquefaction processes
are in various stages of development by industry and federal
agencies. The major categories of coal liquefaction techno-
logy can be identified as follows:
• Hydrogenation, Category 1
• Pyrolysis and Hydrocarbonization, Category 2
• Catalytic Synthesis, Category 3
• Donor Solvent, Category A
• Extraction, Category 5
Each of these categories includes several processes.
In Category 1, the crude liquid from the initial re-
action is suitable for utility fuel after desulfurization
and may be used where production costs and environmental
concerns, rather than specific fuel requirements, have
priority. Upgrading by hydrotreating (further hydrogena-
tion) is required to produce higher quality fuels. Synthoil
and H-Coal are catalytic hydrogenation processes wherein the
hydrogen is introduced directly to the liquefaction zone in
the presence of the catalyst. SRC is also a direct hydro-
genation process but no catalyst is added (although con-
stituents in the coal may act as a catalyst). The donor
solvent processes are so called because a major part of the
hydrogen is supplied to the liquefaction zone via the
10
-------
solvent material, which gives up its hydrogen for use in the
liquefaction process.
Pyrolysis and hydrocarbonization processes, Category 2,
also yield a crude liquid which requires hydrotreating.
Such treatment also reduces sulfur, nitrogen, and oxygen.
Varying amounts of carbon remain unreacted as a char,
depending upon the process. In some processes, the char is
separated from the product and used to generate hydrogen via
the steam-carbon reaction. Other processes produce such a
high proportion of char that it must be considered by-
product fuel. Synthesis gas is used in place of hydrogen
in several processes. Synthesis gas is a mixture of hydro-
gen and carbon monoxide in varying proportions and can be
generated via the reaction of carbon with oxygen and steam.
Carbon for this purpose may be obtained from fresh coal
feed, from carbonaceous residues produced by the process
itself, or a combination of the two. Synthesis gas is used
in catalytic synthesis processes, Category 3, to produce
liquid fuels and chemicals without additional input of
coal. Category 4 processes use a hydrogenated solvent which
"donates" hydrogen to the liquefaction reaction in donor
solvent processes. Category 5 processes remove fuel liquids
from the coal via extractants.
Process Modules-
Table 8 compares coal liquefaction technologies in
terms of ten common process operations and processes. Four
of the ten processes or modules are used in all of the fifteen
processes listed. These four are: coal preparation, sep-
aration, gas cleaning, and auxiliaries. Twelve of the
fifteen processes use the hydrogen/synthesis gas generation
module. Hydrogenation is used in ten processes, fractiona-
tion is used in nine, pyrolysis in five, catalytic synthesis
11
-------
TABLE 8. COMPARISON OF COAL LIQUEFACTION
TECHNOLOGIES BY PROCESS MODULES (18)
Specific
Process
Module or process
CO
e
•H
CO
o
to
•H
e
•H
0)
c
co
o
¦P
0
-i
4-J
w
O
a)
aj s
<0
a.
60
O
4J
•H
T—1
60 > >>
CO
•C
u
co
>N Cfl
3
a
X
P4 XI
X
U
p4
Pm
o
EE 60
<
Synthoil
+
+
-
-
+
+
-
+
+
H-Coal
+
+
_
+
+
+
+
¦IC
O CO
¦U OJ
tn
W CO
a) _
M
-------
in five, and hydrotreating in at least five. The combina-
tion of ten modules and fifteen processes provides for 150
possible similarities. Actual similarities amount to 106.
Comparison of the Selected Processes
Solvent Refined Coal Process--
This process, noncatalytic hydrogenation, was initially
designed with the objective of producing a low-sulfur solid
fuel suitable for use in coal-fired electric generating
plants. The sulfur content is reduced during hydroliquefac-
tion so that burning of the product in conventional utility
boilers emits less sulfur dioxide. It was hoped that this
would eliminate the necessity for flue gas scrubbing to
remove sulfur dioxide. As evidenced by its solidification
after cooling, the molecular structure of the coal is
affected less in the SRC-I process than in any of the other
selected technologies. The SRC-I process also is concep-
tually the most simple. Coal is dissolved, the sulfur and
other undesirable components are extracted, and the modified
coal is recovered in solid form. This concept uses mild
hydrogenation conditions, and, since the final product is
solid SRC, fractionation is not required to obtain different
products. Usable products are recovered by phase separations.
More recently, however, the SRC process has been
operated in a modified mode identified as SRC-II. It
produces liquid fuel. This requires more stringent modifi-
cation of the coal molecules and brings the process into
closer comparison with the other three priority processes
which also produce liquid fuel.
The SRC process is the only selected process developed
through the pilot plant stage. The pilot plant includes
waste treatment and control facilities. Therefore, at this
13
-------
time, it offers the best source for assessment of the dis-
charges of a coal liquefaction process to the environment.
Materials issuing from this process include products
which can be either solid or liquid fuel or both, ash and
mineral matter, hydrocarbon gases, waste liquids (oil and
water), spent catalyst, sulfur, ammonia, coal dust, tar,
blowdown, and sludges from auxiliary operations.
Synthoil Process--
From its conception the Synthoil process, a catalytic
hydrogenation, was designed to produce liquid fuel. A fair
amount of information is available for this process and the
wastes and products formed (9). The major problem with
conducting an environmental assessment of this process is
that only relatively small-scale equipment has been used and
except for the heart of the process (hydrogenation units,
phase separators, etc.), little work has been performed.
Treatment and control modules, auxiliary processes, and
other nonproduct-oriented process portions as presented in
this report are concepts only. Since the PDU will not use
Synthoil technology, inclusion of this technology as a
selected process may need future reevaluation.
Materials issuing from the coal by this method of
processing include sulfur, ammonia, ash, carbonaceous residue,
coal dust, tar, waste liquids (oil and water), spent catalyst,
blowdown, and sludges from auxiliary operations.
H-Coal Process--
The H-Coal process, catalytic hydrogenation, also
produces liquid fuel. More data and information for this
process and the wastes and products formed should be avail-
14
-------
able within the next two years when the pilot plant begins
operation. It will have waste treatment facilities.
It is anticipated that materials issuing from the
processing of coal by the H-Coal system will include crude
oils, residues, ash, sulfur, ammonia, spent catalyst, waste
liquids (oil and water), coal dust, tar, blowdown, and
sludges from auxiliary operations.
Exxon Donor Solvent Process--
This process differs from the other three in that it
uses hydrogen transferred from the solvent to the coal as a
major source of hydrogen for liquefaction of the coal. The
donor solvent is hydrogenated catalytically and then
stripped of hydrogen in the liquefaction reactor in cyclic
fashion. Whenever possible, the Exxon Donor Solvent process
uses technology developed in the petroleum industry. There
is little information available, however, on the details of
the process, products, or wastes.
This process is expected to produce crude oil, hydro-
carbon gas, naphtha, sulfur, residue, ammonia, coal dust,
tar, spent catalyst, spent solvent, waste liquids (oil and
water), blowdown, and sludges from auxiliary processes.
Emissions Treatment and Control Technology
As expressed in the introductory statements of this
section, the current literature data base compiled for this
study shows a lack of useful information on the environ-
mental aspects of coal liquefaction. Information required
for the identification of more than general areas of treat-
ment and control technology is nonexistent. Problems
associated with the development of the process aspects of
15
-------
liquefaction have apparently been sufficient to occupy the
full attention of those engaged in this field.
EVALUATION OF PROCESSES
Similarities and Differences
Table 9 provides additional detailed information for
comparison on the basis of process conditions within the
main process module. The reactor temperatures for two of
the four processes, Synthoil and SRC, are in the 450°C to
480°C range, while the other two, H-Coal and Exxon Donor
Solvent, are somewhat lower, in the 370°C and 380°C range.
Comparing reactor pressures, three processes have pressures
in the 10 to 20 MPa range while the Synthoil process is
somewhat higher at 29 MPa. Since reaction products are
controlled by operating conditions such as temperature,
pressure, residence time, and free radical concentrations,
it is interesting to note the similarities of at least two
of the pertinent variables. Residence time and hydrogen-
to-coal ratios would also be valuable for estimating product
compositions where analytical data are not available, but
these have not been included, usually because of a lack of
readily available information necessary for their calculation.
More detailed studies on product and waste composition as a
function of operating variables should include these parameters
Pollution Potential
A great many organic and inorganic categories and
classes of substances may be contained in the output streams
listed in Table 10 and in the generalized listings of
16
-------
TABLE 9. COAL LIQUEFACTION
TECHNOLOGY PROCESS CONDITIONS (18)
Reactor Reactor
Specific temperature pressure
process °C MPa Phase
Synthoil
450
29
L,S,G*
H-Coal
370
20
L, S,G
Bergius
430
69
L, S , G
SRC-1
480
10
L, S,G
SRC-II
457
20
L, S , G
COSTEAM
400
28
L, G
COED
870
0.06
S, G
Coalcon
560
4
L, S, G
TOSCOAL
540
0.1
L,S,G
Occidental
Research Corp.
500
14
L, S, G
Fischer-
Tropsch
340
2.9
L, G
Exxon Donor
Solvent
380
18
L, S, G
Supercritical
Gas Extraction
400
10
S, G
Methanol
Synthesis
425
31
L, G
*L = liquid, S = solid and G = gaseous
products, by-products, and wastes in Sections 4 through 6.
These substances are either known or suspected as emissions
from coal or oil processing. Currently the list consists of
(12):
Categories Classes Substances
Organics 26 45 350
Inorganics 59 -- 300
85 45 650
17
-------
TABLE 10. COMPARISON OF COAL LIQUEFACTION TECHNOLOGIES
BY POTENTIAL ENVIRONMENTALLY SIGNIFICANT EFFLUENTS* (18)
Ef fluent
Specific Process
Ammonia
Synthetic oil
Me thano1
Su1 fur
Ash
Carbonaceous
res idue
Hydrocarbon
Rases
Tar
Spent catalyst
Spent MEA
Waste liquids,
oil & water
Klowdown & sludge
f rum:
• power plant
• water treatment
• cooling tower
Spent solvent
Dust from coal
Tar acids
Organic chemicals
Gasoline
Flue gas
Naphtha
Totals
U)
r.
7.
>-
to
0 w
0
r-H
3
<
o
<
0i
c u
•H
w
o
c
C
c.
u
0
&0
H
Q
03
CJ
u
r,
. r~ »j
p
u
CJ
CO
w
<
CD
CO
os
w
C
C
1
o
ce;
O
C
c
.—I
O
o
•H
O
O >,
C/)
X
CO
CO
u
CJ
o
O
H
o
U-
Q
4
+
4
4
4
4
4
4
4
+-
4
4
4
4
4
4
4
+
+
4
4
+
+
4
+
4
4
4
4
4
4
4
+
+
4
+
4
4
4
4
4
+
4
4
4
4
4
4
4
4
4
4
+
+
4
4
4
4
4
4
4
+
4
+
4
4
+
4
4
4
4
4
4
4
4
4
+
4
4
4
4
4
4
+
4
+
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
+
4
4
4
4
4
+
4
4
4
4
+
4
+
4
4
4
+
4
4
4
4
4
4
4
4
4
4
4
+
4
4
4
4
4
4
4
-f
4
4
4
4
4
4
4
+
4
4
+
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
14
14
12
13
10
U
11
1 5
1 1
13
15
13
*Only those output streams common to two or more of the specific processes are listed.
18
-------
Table 11 lists the organic categories and Table 12 lists the
inorganic categories. The hazard potential of approximately
216 specific materials has been addressed (20). Of this
number, 140 are relatively nonhazardous, 37 are hazardous,
24 are very hazardous, and 15 are most hazardous to human
health.
In liquefaction the various constituents in the coal
feed could form potential pollutants. With such an array of
possibilities, it becomes very important to determine the
fates of known hazardous materials. Such materials as
sulfur, oxygen, nitrogen compounds, and other minor or trace
elements may be converted to materials that are soluble in
the oil or water, may remain with the gas, may be deposited
on the catalyst, or may remain associated with the ash,
residue or mineral matter. Compounds such as arsine, HF,
and similar materials may be formed. Much of the nitrogen
in the coal may appear as ammonia which can be removed by
scrubbing with water, but amines may also form and appear in
the water layer. Phenolic and other oxygenated compounds
will probably be present.
TREATMENT AND CONTROL NEEDS
Solids Disposal
More work is needed to define methods of disposal that
do not create problems due to leaching of acids, organics,
metals, or sulfur. Leachates could contaminate natural
water. Existing information and technologies on ash and
sludges from boiler, power plant, and other conventional
combustion facilities will be useful for this purpose.
19
-------
TABLE 11. POTENTIAL ORGANIC-COMPOUND POLLUTANTS (21)
Category
Class
1 - Aliphatic hydrocarbons
2 - Alkyl halides
3 - Ethers
4 - Halogenated ethers
5 - Alcohols
6 - Glycols, epoxides
7 - Aldehydes, ketones
8 - Carboxylic acids & derivatives
9 - Nitriles
10 - Amines
11 - Azo compounds, hydrazine, & deriv.
12 - Nitrosamines
13 - Mercaptans, sulfides & disulfides
14 - Sulfonic acids, sulfoxides
15 - Benzene, substituted benzene
hydrocarbons
16 - Halogenated aromatic hydrocarbons
17 - Aromatic nitro compounds
18 - Phenols
19 - Halophenols
20 - Nitrophenols
21 - Fused aromatic hydrocarbons &
derivatives
22 - Fused non-alternant polycyclic
hydrocarbons
23 - Heterocyclic nitrogen compounds
24 - Heterocyclic oxygen compounds
25 - Heterocyclic sulfur compounds
26 - Organometallics
Alkant's and cyclic alkanes
Alkencs, cyclic alkenes, and
dienes
Alkynes
Saturated alkyl halides
Unsaturated alkyl halides
Ethers
Halogenated ethers
Primary alcohols
Secondary alcohols
Tertiary alcohols
Glycols
Epoxides
Aldehydes, ketones
Carboxylic acids with additional
function groups
Amides
Esters
Nitriles
Primary amines
Secondary amines
Tertiary amines
Azo compounds, hydrazine, & deriv.
Nitrosamines
Mercaptans
Sulfides, disulfides
Sulfonic acids
Sulfoxides
Benzene, substituted benzene
hydrocarbons
Halogenated aromatic hydrocarbons
Aromatic nitro compounds
Monohydrics
Dibydrics, polyhydrics
Hydroxy compounds with fused rings
Halophenols
Ni trophenols
Fused aromatic hydrocarbons 6.
derivatives
Fused non-alternant polycyclic
hydrocarbons
Pyridine & substituted pyridines
Fused 6-membered ring heterocycles
Pyrrole & fused ring derivatives
of pyrrole
Nitrogen heterocycles containing
addition hetero atoms
Heterocyclic oxygen compounds
Heterocyclic sulfur compounds
Alkyl or aryl organometallics
Sandwich type organometallics
Metal porphyrins & other chelates
20
-------
TABLE 12. POTENTIAL INORGANIC POLLUTANTS (20)
Group
Category
Element
Group
Category
Element
1A
27
Lithium
VIIA
57
Chlorine
28
Sodium
58
Bromine
29
Potassium
59
Iodine
30
Rubidium
IIIB
60
Scandium
31
Cesium
61
Yttrium
IIA
32
Beryllium
IVB
62
Titanium
33
Magnesium
63
Zirconium
34
Calcium
64
Hafnium
35
Stront ium
VB
65
Vanadium
36
Barium
66
Niobium
IIIA
37
Boron
67
Tantalum
38
Aluminum
VIB
68
Chromium
39
Gallium
69
Molybdenum
40
Indium
70
Tungsten
41
Thallium
VIIB
71
Manganese
IV A
42
Carbon
VIII
72
Iron
43
Silicon
73
Ruthenium
44
Germanium
74
Cobalt
45
Tin
75
Rhodium
46
Lead
76
Nickel
VA
47
Nitrogen
77
Platinum
48
Phosphorus
IB
78
Copper
49
Arsenic
79
Silver
50
Antimony
80
Gold
51
Bismuth
IIB
81
Zinc
VIA
52
Oxygen
82
Cadmium
53
Sulfur
83
Mercury
54
Selenium
IIIB
84
Lanthanides
55
Tellurium
85
Actinides
VIIA
56
Fluorine
21
-------
In addition, adequate controls are needed with regard
to the potential dust nuisance and washing away of particu-
lates. In many cases the material may be suitable for
landfill with revegetation. Although there is already
substantial background on this subject, specific information
is needed on each coal and for each specific location in
order to allow thorough planning to ensure that the disposal
will be environmentally sound.
Liquefaction
In the liquefaction operation it is important to
determine more about the fate of various constituents in the
coal feed such as sulfur, oxygen, and nitrogen compounds, and
other minor or trace elements.
In order to clarify environmental aspects, considerable
additional information is needed on the formation of crit-
ical minor and trace compounds. The identity and amount for
each of these should be determined since it can have a major
effect on the selection of cleanup and disposal methods on
the oil, water, and gas streams, as well as solid wastes.
Gas Cleaning
Desirable objectives for an acid gas removal process
include: (a) effective removal of all forms of sulfur to
yield a stream with a high sulfur concentration suitable for
processing in a Claus sulfur plant, (b) effective CO2
removal while producing a vent stream satisfactorily low in
sulfur and pollutants, (c) low utility and energy consumption,
(d) no waste streams that present a disposal problem (22).
Amine scrubbing, proposed for use with the Synthoil and
Exxon Donor Solvent processes, is not effective on carbonyl
22
-------
sulfide, while contaminants such as cyanide interfere with
regeneration of the scrubbing liquid. Hot carbonate systems
do remove carbonyl sulfide, but it is often difficult to
provide a highly concentrated stream of I^S to send to the
sulfur plant. In addition, the CC^ stream vented to the
atmosphere may contain too much sulfur. Adsorption and
oxidation systems are often ineffective on carbonyl sulfide.
In any event they do not remove CO2 as required, and addi-
tional processing is needed. The available systems for acid
gas removal have very high utility requirements, causing a
significant loss in thermal efficiency for conversion of
coal to clean fuel products. In addition there is often a
waste stream of chemical scrubbing medium which may be
difficult and expensive to dispose of. Systems based on
physical solvents such as methanol appear to give a CO2 vent
stream that is excessively high in combustibles such as
hydrocarbons and CO (22).
Wastewater Treatment
The need for a simple, effective method to clean up
sour water for reuse is common to most fossil fuel conver-
sion operations. Sour water generally contains sulfur
compounds, ammonia, l^S, phenol, thiocyanates, cyanides, and
traces of oil. These are usually present in too high a
concentration to directly route to biological oxidation, but
their concentration is often too low to make recovery at-
tractive. Particulates, if present, further complicate the
processing of sour water. Usual techniques for cleanup
include sour water stripping to remove l^S and ammonia, and
in addition, extraction may be required to remove phenols
and similar compounds. Such operations require large
amounts of electricity and, therefore, have a large effect
on overall thermal efficiency.
23
-------
Wastewater is discharged as cooling tower blowdown.
Detailed study of the requirements for cleaning this water
will be needed. Makeup water will contain dissolved solids
including sodium and calcium salts. Calcium salts may be
precipitated during the water treating operation to form a
sludge which can be disposed with the other waste solids,
but the fate of the sodium salts in the makeup water requires
future study. These will leave with the blowdown from the
cooling tower. If the concentration of dissolved solids is
too high to allow discharging, then some suitable method of
disposal will have to be worked out.
Trace Elements
Information is needed on the amount of trace elements
vaporized and what happens to them, where they separate out
and in what form, so that techniques can be devised for
recovery or disposal. Specific information in this respect
is needed for each coal and for each coal conversion process
since operating conditions differ. In some cases, the trace
elements may tend to recycle within the system and build up
in concentration. The toxic nature of many of the volatile
elements should be given careful consideration from the
standpoint of emissions to the environment, as well as for
protection of personnel during plant operation and main-
tenance. Carcinogenicity of polynuclear aromatic and
other compounds present in trace amounts or formed during
startup or upsets should also be evaluated. Clarification
is needed regarding potential problems associated with trace
elements in various plant effluents, such as spent catalyst
from liquefaction and shifting or chemical purge streams
from acid gas removal, tail gas cleanup, and stack gas
scrubbing (22).
24
-------
Protection of personnel, especially during maintenance
operations, should be given careful attention. It will
require additional information about the fate of trace
elements. For example, toxic elements that vaporize in the
gasifier may condense in equipment such as piping and ex-
changers. They could create hazards during cleaning opera-
tions (22) .
Summary
In general it appears that each specific plan will
require its own evaluation of environmental effects and
control measures.
A list of potential pollutant sources is presented in
Table 13. A list of examples of control approaches has
been drawn up and is presented in Table 14. These approaches
do not involve research and development of new ideas but
rather the application of existing techniques.
25
-------
TABLE 13. POTENTIAL POLLUTANT SOURCES (21)
Coal storage & handling
- Windblown dusts
- Water runoff
- Leakage and venting
- Open conveyors
- Transport liquids
- Vehicular transport
Coal preparation
- Coal drying
- Grinding, pulverizing
- Particulate collection
- Coal washing
- Pretreatment steps
- Vents
Main process module
- Raw material feed mechanism
- Chemical/physical transformations
- Leakage and venting
- Flue gas
Separation/cleaning/treatment
- Gas cleaning
- Catalyst/sorbent regeneration
- Claus plant
- Vents and flares
- Particulate collectors
- Tar oil/water separators
- Waste water treatment
- Leaks
- Cleaning agents and additives
Products and by-products
- Hydrotreating
- By-product recovery
- Handling and storage
- Utilization
Waste disposal
- Flyash, ash, and slag
- Spent catalyst
- Residues
- Ponds
- Landfills
- Piles
- Sludges
26
-------
TABLE 14. CONTROL APPROACHES (21)
• Gas treatment
- Mechanical collection
- Electrostatic precipitators
- Filters (fabric, granular, etc.)
- Liquid scrubbers/contactors
(aqueous, inorganic, organic)
- Condensers
- Solid sorbents (mol sieves,
activated carbon)
- Incineration (direct and
catalytic)
• Liquids treatment
- Settling, sedimentation
- Precipitation, flocculation,
sedimentation
- Centrifugation and filtration
- Evaporation and concentration
- Distillation, flashing
- Liquid-liquid extraction
- Gas-liquid stripping
- Neutralization
- Biological oxidation
- Wet thermal oxidation
- Activated carbon absorption
- Ion exchange system
- Cooling tower (wet & dry)
- Chemical reaction and separation
• Solids treatment
- Fixation
- Recovery/utilization
- Processing/combustion
- Chemical reaction and separation
- Oxidation/digestion
- Physical separation (specific
gravity, magnetic, etc.)
• Final disposal
- Pond lining
- Deep well reinjection
- Burial and landfill
- Sealed-container storage
- Dilution
- Dispersion
• Process modifications
- Feedstock change
- Stream recycle
• Combustion modification
- Flue gas recycle
- Water injection
- Staged combustion
- Low excess air firing
- Optimum burner/furnace design
- Alternate fuels/processes
• Fuel cleaning
- Physical separation (specific
gravity, surface properties,
magnet 1c)
- Chemical refining
- Carbonization/pyrolysis
- Liquefaction/hydrotreating (HDS,
UDN, demetallization)
- Gasification/separation
• Fugitive emissions control
- Surface coatings/covers
- Vegetation
- Leak prevention
• Accidental release techno]ogy
- Containment storage
- Flares
- Spill cleanup techniques
27
-------
SECTION 3
THE SYNTHOIL PROCESS
INTRODUCTION
The Synthoil coal liquefaction process involves cata-
lytic hydrogenation of slurried coal. It is aimed specifi-
cally toward the conversion of high sulfur coals into non-
polluting, low sulfur liquid fuels for the electric utility
industry (24).
Development of the Synthoil process was initiated by
the U.S. Bureau of Mines in 1969 at the Pittsburgh Energy
Research Center (PERC). Currently, the work is being man-
aged by DOE. The initial work on the process used a reactor
with an internal diameter of 8 mm in a bench-scale plant
that processed 2.3 kg of slurry per hour. Experimental work
was carried out on various coals, such as Pittsburgh Seam,
Indiana No. 5, Middle Kittanning, Ohio No. 6, and Kentucky
Homestead mine. All were satisfactorily converted to low
sulfur fuel oil (24).
To demonstrate the broad applicability of the process,
a 0.46-metric ton per day unit was constructed that used a
reactor of 28.2 mm internal diameter made of two lengths
of 4.4-m interconnected stainless steel pipes. The opera-
tions were carried out on various types of coal at reactor
pressures of 14.2 and 28.4 MPa at 450°C. High yields of low
sulfur and low ash fuel oil were obtained (25).
28
-------
At the lower reactor pressure (14.2 MPa), the calorific
value and yield of product oil were lower, hydrogen con-
sumption was lower, and the sulfur and ash content of the
product oil were higher than that of the oil produced at 28.2
MPa (26).
The overall design package for the 9.1-metric ton per
day PDU was completed during the second quarter of 1975 by
Foster Wheeler Energy Corporation, Livingston, New Jersey,
which is also responsible for the construction management of
the unit. This unit is expected to start operation in
1978. Laboratory research has been conducted on the Syn-
thoil Process by Sandia Laboratories, Argonne National
Laboratory, Battelle Memorial Institute, and Exxon Research
and Engineering Company.
At this time, the only available information for the
Synthoil process comes from the 0.46-metric ton per day
bench-scale unit. Since this unit consists only of a
reactor, gas separation devices, and a centrifuge for solids-
liquid separations, process modules such as hydrogen produc-
tion, and treatment and control can only be conceptualized,
and the design for the 7,950-m per day commercial facility
is based on data from the bench-scale unit.
PROCESS DESCRIPTION
Overall Process and Operating Conditions
Figure 2 depicts the overall flow pattern for the
Synthoil process, including both process and waste streams
(27).
29
-------
SPENT CATALYST
CO
o
Figure 2. Overall synthoil process flow schematic (27).
-------
In the coal preparation module, the coal is crushed,
pulverized, and dried. In some cases it may also be washed.
The processed coal, of 70-mesh screen size, is mixed with
recycled oil to form a coal-oil slurry. The slurry is then
mixed with preheated hydrogen and passed through a preheat-
ing system and into the reactor. The effluent from the
reactor is a mixture of gases, liquids, and solids. This
mixture passes through a series of pressure-reducing receiv-
ers where the gases are separated. The remaining liquid and
unreacted solids enter a centrifuge where most of the oil is
separated and sent to product storage and recycling. The
oily char from the centrifuge passes through a char de-
oiling process where the mineral residue is stripped of most
of the remaining oil via multihearth pyrolysis. Some fuel
gas by-product is also produced when the mineral residue is
pyrolyzed. The remaining oil, along with the remaining
mineral residues, is sent to the hydrogen production
module.
The gases, separated by flashing in the hot high pres-
sure flash drums, enter cold high pressure flash drums where
light oil and water are further separated from the gas.
Light oil is sent to the cold low pressure flash drums and
from there to the recontact tower and product storage. In
the recontact tower, the recycle portion of the light oil
absorbs light hydrocarbons from the gases entering the gas
purification module for recycling. After the light hydro-
carbons are removed, the hydrogen-rich gas passes through
acid gas removal treatment and is sent, together with the
make-up hydrogen, to the hydrogenation module.
Numerous waste streams are produced in the Synthoil
process. The gases separated from the oil are directed to a
gas purification system where they are cleaned and recycled.
Wastewater streams are directed to by-product recovery and
31
-------
then to the wastewater treatment facilities. Sludges and
ash from hydrogen production are usually transported to
landfills and minefills, respectively. Auxiliary facilities
consist of steam and power generation, raw water supply,
cooling towers, product and by-product storage, and oxygen
generation. Each of these facilities also generates waste
materials.
Overall Material Balance
The material balance for this process is based on the
use of run-of-mine (ROM) coal from western Kentucky. The
free moisture content of the coal is 7 to 10 percent before
drying and 0.5 percent after drying. The following is the
analysis of the coal after pulverizing and drying (27):
Component wt (percent)
c
60.72
H
4.77
N
1.19
S
5.45
0
11.37
Ash
16.5
100.00
The liquid product from the Synthoil process consists of
heavy and light species of fuel oil. Physical charac-
teristics of heavy oil produced in the bench-scale unit
are (27):
Specific gravity at 15.6°C = 1.04
Viscosity at 25.°C = 4500 SSU
Viscosity at 82°C = 102 SSU
32
-------
TABLE 15. MATERIAL INVENTORY - SYNTHOIL PROCESS (27)
Stream
description
Number*
coal
1
Prepared
coal
Slurry
to
hydrogenatIon
Reactor
effluent
Gas to
purification
Light
oil
product
Sour
water
Sour
water
Quench
oil
Oil to slurry
mixing
10
Composition
Coal
Water
Oil
Residue
Gases
Total
25,183
25,183
15,041
82
15,123
15,037
82
27,228
842
43,189
1,731
44,633
4,440
12.763
63,567
10
265
11.247
11,522
1,545
1.0
1,546.0
3,412
9.4
137
3,558.4
30.8
0.2
0.2
31.2
8,080
252
8,332
27,228
843
28,071
Stream
description
Huaber*
Product
oil
11
Fuel gas
(by-product) Off gas
12
13
Sour water
No. 1
14
Char
15
Off gas
composite
16
Off gas
17
Gas to
sulfur
recovery
18
Kecycle
H2
19
Make-up
®2
20
U>
CO
Composition
Coal
Hater
Oil
Besidue
Gases
Total
6,111
138
6,249
661
661
0.1
0.1
768
768.2
3,361
9.2
136.7
3526.9
3,208
3,208
0.3
842
842.3
0.2
2.4
8.2
254
12.0 1.680.5 10,377
12.2 1,682.9 10,639.2
1,378
1,378
Streaa
description
Huaber*
Composition
Coal
Hater
Oil
Residue
Cases
Total
Sludge
21
1,411
2,116
3,527
Oxygen
22
3.514
3,514
Coal
to H2
Wastewater
from acid
Wastewater
froa H2
to H2 xrom acia iron n2 Water Injection Spent Effluent from it™ cu«
production Steaa gas removal production (into gas stream) catalyst gas separation preparation
23 24 25
Wastewater
from coal
2,987
15
3,002
9.6
4,990
9.6
26
1,385
1,385
27
1,727
1,727
28
N.A.**
29
31
46,072
4,441
12.2
50,556.2
30
N.A.**
•Refers to Figure 2. Based on an output of 7,950 m of Synthoil per day. All values are in metric tons/day.
"Not available.
(continued)
-------
TABLE 15. (continued)
Stream
description
Number*
Acid
gas from H2
production
31
Excess
char to
disposal
32
By-product Water to
light oil H2 production CO2
33 34 35
Composition
Coal
Water 1,341
Oil 21 1,135
Residue 369
Gases 8,532 1.8 1,002
Other 9.2
Total 8,541.2 390 1,136.8 1,341 1,002
*Refers to Figure 2. Based on an output of 7,950 m of Synthoil per day. All values
are in metric tons/day.
-------
Typical properties of light oil produced are (27):
API gravity = 30-40°API
Initial boiling point = 38°C
Normal boiling point = 177 to 193°C
In addition, liquid and gas by-products of unknown qualities
are produced in the process. The gaseous by-product is
assumed to consist mostly of hydrogen and methane. The
liquid by-product is expected to have characteristics sim-
ilar to those of the light oil produced. These by-products
may be used internally in the plant for power generation,
steam production, other thermal conversion, or may be sold
as fuels.
Table 15 presents a material inventory for the Synthoil
process, including coal feed for hydrogenation and hydrogen
production, products and by-products, and major waste
streams before treatment. Waste streams leaving the plant
after treatment as well as materials recovered from the
wastes are discussed and quantified in Section 8. The
design of the 9.1-metric ton per day pilot plant served as
a basis for scale-up of the process and waste streams (27).
Both the material balance for the pyrolysis of centrifuged
residue and the steam requirements were taken from the
3
conceptual design of the 7,950-m per day commercial plant
(28). Some modifications are based on the results of labora-
tory studies of the Synthoil process.
A material balance is shown in Table 16.
35
-------
TABLE 16. OVERALL MATERIAL BALANCE-SYNTHOIL PROCESS* (27)
Input
Output
Material
Metric tons
per day
Material
Metric tons
per day
Coal to hydro- 15,123
genation
Coal to hydrogen 3,002
production
Coal to steam and 3,480
electricity pro-
duction
Oxygen 3,514
Cooling water 23,043
make-up
Process water 1,727
injection
Steam 4,990
Water requirements 1,341
for hydrogen
production
Boiler feedwatex 390
Total 56,610
Heavy fuel oil
Light oil
Liquid by-product
Sour water from the
process
Wastewater from
hydrogen production
Sludge from hydrogen
production
Excess char from the
solid-liquid separation
Phenols
Sulfur
Ammonia
Waste gas (including
evaporation and drift)
Cooling water blowdown
Miscellaneous wastes
(including wastes from
steam and power gen-
eration)
Total
*Based on a production rate of 7,950 m^/day.
6,248 (6,267
1,546 (1,682 m )
1,137
3,397
1,385
3,526
390
9
712
125
27,599
621
9,915
56,610
36
-------
Material and Energy Considerations
Process Material Yields--
The product yield in unit weight of product oil plus
light oil per unit weight of coal prepared for liquefaction
is 0.52. The yield based on total coal (including utility
needs) used is 0.31.
Process Thermal Efficiency--
The thermal efficiency* serves as a means of measuring
the effectiveness of the process for making clean fuels from
coal. The process thermal efficiency is defined as:
The heating value of all clean products (joules)
The heating value of coal to the reactor + the
heating value of make-up gas (joules)
= 253 + 63 (TJ) _ 316 (TJ) „ nn _ C9,
354 + 73 (TJ) 467 (TJ) x 100 68/0
The data in Table 17 indicate the heating values for prod-
ucts and materials used in the Synthoil process.
TABLE 17. HEATING VALUE OF SELECTED PRODUCTS
AND MATERIALS IN THE SYNTHOIL PROCESS (26,28)
Input
Metric TPD
MJ/kg
TJ/day
Coal
21,605
26.5
563
Output
Product oil
6,248
40.5
253
Light fuel oil
1,546
40.5
63
Liquid by-product
1,137
40.5
46
By-product gas
729
51.2
37
*This calculation is a first law thermodynamics efficiency.
It considers only heat quantity values.
37
-------
Overall Thermal Efficiency--
The overall thermal efficiency permits an estimate of
the overall heat utilization as the result of the process
and required auxiliary operations. The overall thermal
efficiency is defined as:
The heating values of the products + the heating values
(joules) of the combustible by-products
The heating values of all raw materials consumed by the
process and auxiliary facilities (joules)
= 399 (TJ) x 10Q = 70%
563 + 11.2 (TJ)
Heat consumed in the direct fired heaters and preheaters
throughout the process is assumed to be 2 percent of total
coal feed energy input (26), or 11.18 TJ.
DESCRIPTION OF THE PROCESS MODULES
The Synthoil process can be divided into several
modules, each of which serves a specific function in the
overall process. This division serves a dual purpose in
this report:
• It facilitates comparison of different liquefac-
tion processes and eliminates redundant descrip-
tion of interchangeable modules;
• It facilitates identification and classification
of waste streams originating in the process and
selection of control and treatment technologies.
The following modules and processes have been identi-
fied in the Synthoil process:
38
-------
• hydrogenation
• gas separation
• solids separation
Auxiliary processes include hydrogen generation, acid gas
removal, steam generation, raw water supply, oxygen genera-
tion, by-product recovery, and wastewater treatment facilities.
The modules above, with the exception of auxiliary
facilities, are discussed in the following subsections of
the report. Auxiliary facilities are discussed in Section
6. Gas separation and solids-liquid separation are two
arbitrarily selected parts of one operation - separation of
the phases.
Hydrogenation Module
A simplified description is presented herein to illus-
trate the operations in the hydrogenation module, shown in
Figure 3. The prepared slurry of slurried coal and solvent
is pumped into the preheater and reactor at a working pres-
sure of 32.06 MPa. Make-up hydrogen, added to the recycle
gas, makes up the reactor feed gas. The reactor feed gas is
split into two streams (27).
About 20 percent of the reactor gas is introduced into
the slurry feed at the outlet of the slurry feed pump. The
other 80 percent of the reactor gas is heated first by heat
exchange with reactor effluent and then by a fired heater to
about 563°C. The combined gas and slurry stream is then
heated to about 232°C, well below the plastic range of
slurry, by heat exchange with the reactor effluent. The two
streams are then mixed to bring the resultant mixture
quickly through the plastic range of slurry to 382°C, and
39
-------
REACTOR GAS (Hg) 60°C 33.5 MPa
Figure 3. Synthoil process flow diagram -hydrogenation module (27)
-------
the mixture is further heated in the reactor feed heater to
the reaction temperature, 432°C (460°C maximum) (27).
From the reactor feed heater the mixture flows to the
prehydrogenator, a drum packed with inert cylinders, and
then through the reactor. The reactor consists of four beds
(each with a maximum depth of 15 feet) of hydrogenation
catalyst. Each catalyst bed is housed in a separate vessel.
Used in the reactor is a Co-Mo catalyst on an alumina
support (1/8 x 1/8 in. pellets of Harshaw 0402T). In the
reactor, part of the sulfur, oxygen, and nitrogen compounds
in the coal are hydrogenated, and organic coal constituents
are simultaneously hydrogenated into a less viscous liquid.
Flow through the prehydrogenator and the reactor is upward.
Quench oil is injected between the prehydrogenator and the
reactor and between reactor catalyst beds to control bed
inlet temperatures and limit the overall temperature rise
across the reactor to 23°C (27).
Heat in the reactor effluent is recovered by heat
exchange with reactor gas and then with feed slurry plus 20
percent reactor gas in separate heat exchangers. Reactor
effluent can also be switched, using swing elbows, to go
through the reactor effluent bypass cooler instead of the
heat recovery exchangers when heat recovery is not used.
Reactor effluent is then further cooled and flows into the
hot high pressure separator, where the gas in the reactor
effluent is separated from the liquid and solids (27).
Process and Waste Streams-
Module streams are shown in Figure 4. Stream constit-
uents are quantified in Table 18. While the hydrogenation
module has no direct continuous discharge to the environ-
ment, the materials of environmental significance which
41
-------
© 0 ©
SYNTHOIL
HYDR06ENATI0N
MODULE
¦©
¦0
STREAM
1. SLURRY
2. QUENCH OIL
3. RECYCLE GAS
4. MAKE-UP H2
5. FLUE GASES
6. REACTOR EFFLUENT
7. VAPOR LEAKAGE
8. TRANSIENT SPILLS
METRIC TONS
PER DAY
43,194
8,332
10,639
1,378
NOT QUANTIFIED
63,537
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 4. Synthoil hydrogenation module
process and waste streams
appear in subsequent or downstream modules are formed or
released from the coal during hydrogenation.
Most of the nitrogen and sulfur in the coal are largely
hydrogenerated to ammonia and hydrogen sulfide. The liquid
hydrocarbon product from the hydrogenation module contains a
wide range of organic compounds acknowledged to be hazardous
to the environment. Analyses of the compounds identified in
light species from the Synthoil process are given in Table 19.
42
-------
TABLE 18. SYNTHOIL HYDROGENATION MODULE PROCESS
AND WASTE STREAMS (EXTRACTED FROM TABLE 15)
Metric tons
Stream* per day
1. Slurry of coal and
recycle oil
Coal 15,041
H2O 82
Oil 27,227
Residue 842
43,192
2. Quench oil
Oil 8,080
Residue 252
8,332
3. Recycle gas
H20 8.2
H2 4.910
HC 5,171
CO 290
CO2 5-6
Oil (light) 254
10,638.8
4. Make-up gas (H2)
Ho 603
CO 603
COo 137
N? 35
1,378
6. Reactor effluent
H2O 1,731
Hydrocarbons 5,781
H2S 625
NH3 132
H2 4,910
CO 291
CO2 994
Oil 44,633
Solids 4,440
63,537
*Refer to Figure 4.
43
-------
TABLE 19. LIGHT OIL COMPOSITION - SYNTHOIL PROCESS (29)
FRACTION I* FRACTION III* FRACTION IV*
Coapound(s)
Weight (Z)
Compound(s)
Weight (X)
Coapound(s)
WelRht «)
cyclohexane
3.9
cyclohexane
0.1
benzene
0.3
it-heptane
1.9
me t hy 1 cy c lo hexene
.3
2-pentanone
.2
aethylcydohexane
6.5
3 or 4-aethylcyclohexene
.6
toluene
8.0
2-»ethy Iheptane
1.4
toluene and 1-aethylcyclohexene
1.4
3-hexanone
.2
2,4~di»ethylhexane
1.4
I,2-diaethylcyclohexene
.7
unknown
.6
a—octane
5.7
L-ethy Icy c lohexene
.5
dinethylhexane
4.7
dlsethylcyclohexane
10.6
n-propylbenzene
3.4
phenol plus a C^-benzene
4.9
n-nonane
9.2
isopropylbenzene
8.9
indan
5.1
isopropylcyclohexane
9.0
C^-benzene
3.9
cresol plus oethylindan
6.3
trana-bicyclo 4.3.0 nonane
2.6
indan and propyltoluene
13.2
cresol
9.5
n-decane
6.1
1-ae thy 1 indan
4.0
sethylindan
2.7
cia-bicyclo 4.3.0 nonane
5.5
5-ttethylindan
3.8
tr*ns-decalin
1.2
4-«ethylindan
2.7
xylenol plus nethylindan
2.6
tt~butylcyclohejcane
3.4
tetralin
6.0
xylene1 plus tetralin
7.7
•ethylbicyclo 4.3.0 nonane
3.4
1,6-d laethyllndan
1.9
xylenol
3.8
n-undecane + els decalin
5.1
naphthalene
.8
naphthalene
5.5
¦ethyldecalln
2.4
2-»ethyltetralin
2.5
2-*ethylnaphthalene
2.6
aethyldecalin
.7
C^-benzene
1.3
1-methylnaphthalene
1.0
n-dodecane
.9
6-«ethyltetralin
U.Q
^-naphthalene
.5
n-tridecane
.1
2-aethylnaphthalene
2.1
C2-naphtha1ene
.3
ethyldecalin
.3
l-»ethylnaphthalene
.8
C^-naphchalene
.6
n-tetradecane
trace
ethylnaphthalene
1.3
biphenul
.2
(balance unidentified)
81.3
diaethylnaphthalene
1.2
dibenzofuran
.1
d isethy Inaphthalene
.7
b iphenylaethane
.2
diaethylnaphthalene
.9
tetrahydrocarb&zole
.3
Cj-naphthalene
.5
methyltetrahydrocarbazole
.2
C,-naphthalene
4
.2
nethyltetrahydrocarbazole
.J_
(^-naphthalene
.2
(balance unidentified)
68.4
tetrahydrophenanthrene or
. 1
tetrahydroanthracene
68.0
(balance unidentified)
•The light oil was separated
while Fractions XI, HI, and
Into fractions
IV were 9, 28
by chromatography. Fraction I constituted
and 19 percent, respectively.
UUX of the oil
MOTE: Fraction II contained only saturated components similar to tboae detected In Fraction I and, therefore,
la not shotm.
-------
Table 20 lists major structural types identified in the
heavy oil fraction from the Synthoil process, while Table
21 shows concentrations of polynuclear aromatic hydrocar-
bons in the product oil.
TABLE 20. MAJOR STRUCTURAL TYPES IN HEAVY OIL
FROM SYNTHOIL PROCESS (30)
Structural types* Percent
Alkylbenzenes 11
Indenes 7
Indans 9
Naphthalenes 6
Acenaphthylenes 12
Biphenyls 21
Anthracenes; phenanthrenes 6
Phenylnaphthalenes 5
4-rings, peri-condensed 5
4-rings, cata-condensed 3
5-rings, peri-condensed 4
5-rings, cata-condensed 1
6-rings, peri-condensed 1
Phenols 9
^Including alkyl derivatives.
TABLE 21. PAH-COMPOUNDS IN SYNTHOIL OIL (31)
Concentration
Compound
in ppm
phenanthrene
413
benzo(a)anthracene
18
benzo(a)pyrene
41
Table 22 lists organic sulfur compounds identified in
the products of hydrogenation of Kentucky and Indiana coals.
45
-------
TABLE 22. ORGANIC SULFUR COMPOUNDS IN THE SYNTHOIL PRODUCTS
OF COAL HYDROGENATION (31)
Hoi.
form
Indiana #5 coal
Identification*
Mol.
form
Kentucky coal
Identification*
Light oil
w
Benzothiophene
SV
Methylthiophene
w
Methylbenzothiophene
C6H10S
Diallysulfide
cioHios
Dimethylbenzothiophene
C6H10S
Diallysulfide
Product oil
sv
Methylthiophene
C14fl8S
Benzo def dibenzothiophene
C8H10S
Tetrahydrobenzothiophene
C16H10S
Naphthobenzothiophene
cnHios
Benzylthiophene
C17H12S
Methylnaphthobenzothiophene
C12H8S
Dibenzothiophene
C20H12S
D inaphtho thiophene
C13H10S
Methyldibenzothiophene
C21S14
Methyldinaphthothiophene
C14H8S
Benzo def dibenzothiophene
C16H10S
Naphthobenzothiophene
C17H12S
Methylnaphthobenzothiophene
C20H12S
Dinaphthothiophene
Asphaltenes
Spectrum not well resolved
C16H10S
Naphthobenzothiophene
C20H12S
Dinaphthothiophene
1
Based upon molecular formula determined by high-resolution mass
possible in some instances.
spectrometry. Other isomeric forms
-------
Gas Separation Module
Module Description--
The gas separation module separates light hydrocarbons
and other gaseous products from the reactor effluent. In
it, lighter oils and sour water are also separated. This is
achieved in a series of pressure and temperature-reducing
flashing and condensing steps. Figure 5 depicts the flow of
process streams through the module and shows the inter-
connections .
Reactor effluent flows into the hot high pressure
separator where a portion of gas is separated, cooled, and
sent to the cold high pressure separator. Water injected
into this gas stream scrubs out some ammonia and hydrogen
sulfide and leaves the cold high pressure separator as sour
water. The overhead gas from the cold high pressure sep-
arator still contains environmentally significant components
which are partially removed in the light ends absorber, a
packed bed tower.
In the light oil stripper, Figure 5, most of the
ammonia, hydrogen sulfide, and other environmentally sig-
nificant components are stripped out of the light oil and
sent to acid gas removal. Sour water is removed from the
bottom of the light oil decanter. Light oil from the light
oil decanter is directed to the product storage; however, it
may require hydrotreatment to remove sulfur compounds. Off
gases from this unit contain significant amounts of I^S,
NH^, and other environmentally significant components.
All off gases from this module are routed to acid gas
removal. Three units produce sour water which is routed to
wastewater treatment.
47
-------
Figure 5. Synthoil process flow diagram- gas separation module (27)
-------
Process and Waste Streams-
Module streams are shown in Figure 6. Stream constit-
uents are quantified in Table 23. The only continuous
wastewater stream leaving the module is the combined sour
water which comes from the bottom streams of the cold high
pressure separator, light oil decanter, and flash drum.
This sour water will contain l^S, NH^, and soluble oil
compounds (see waste streams, Table 23).
METRIC TONS
STREAM PER DAY
1.
REACTOR EFFLUENT
63,537
2.
OIL AND SOLIDS TO SEPARATION
50,555.3
3.
SOUR WATER
3,526.3
4.
PURGE OIL FROM SOLIDS-LIQUID-
SEPARATION
3,759.0
5.
LIGHT OIL TO STORAGE
1,546.0
6.
FLUE GASES
NOT QUANTIFIED
7.
OFF GASES TO ACID GAS REMOVAL
768
8.
PARTIALLY PURIFIED GAS TO ACID
GAS REMOVAL
11,522.1
9.
WATER INJECTION
1,727.0
10.
BY-PRODUCT LIGHT OIL
1,136.8
11.
VAPOR LEAKAGE
NOT QUANTIFIABLE
12.
TRANSIENT SPILLS
NOT QUANTIFIABLE
Figure 6. Synthoil gas separation module process
and waste streams
49
-------
TABLE 23. SYNTHOIL GAS SEPARATION MODULE PROCESS
AND WASTE STREAMS (EXTRACTED FROM TABLE 15)
Metric tons
Stream* per day
1. Reactor effluent
H2O 1,731
Hydrocarbons 5,781
H2S 625
NH3 132
H2 4,910
CO 291
CO2 994
Oil 44,633
Solids 4,440
63,537
2. Oil and solids to solids
separation module
HoO 31
Oil 46,072
Solids 4,440
Hydrocarbons 8.2
H0S 4.1
50,555.3
3. Sour water
H20 3,381
H2S 11
NH3 125.1
Oil (phenols) 9.2
3,526.3
4. Purge oil
Oil 3,759
5. Light oil to storage
Oil 1,545
h2s 1
1,546
7. Off gases to acid gas removal
H20 0.1
Ho 128.6
H2S 183
NH3 3.6
HC 453
—7WT5
(continued)
50
-------
TABLE 23 (continued)
Stream*
Partially purified gas to acid
gas removal
H20
H2
HoS
HC
NH3
CO
C02
Light oil
Metric tons
per day
10.3
4,781.7
425.5
4,750.7
3.0
291.2
994.5
265.2
11,522.1
9. Water injection
h2o
10. By-product light oil
Oil
h2s
1,727
1,135
1.8
1,136.8
*Refer to Figure 6.
Table 19 showed the expected composition of light oil
product from the Synthoil process. Compounds that may be in
the sour water stream are phenol, cresols, and xylenols.
All are slightly soluble in water. They will comprise most
of the estimated 9.4 metric tons per day oil species discharged
with the sour water. Small amounts of other constituents of
the light oil may be emulsified in the sour water.
Organic sulfur compounds identified in the light oil
from the Synthoil process are methylthiophene, diallyl-
thiophene and diallylsulfide (when Kentucky coal was hydro-
genated). Diallylsulfide is slightly soluble in water, and
only trace amounts of it may be discharged with the sour
water.
51
-------
Since all of the off gases are sent to the acid gas re-
moval, there are no continuous gas emissions to the atmos-
phere from this module. Hydrocarbon vapor leakage and
accidental spills are two potential intermittent emission
sources.
Flue gas from the preheater should be environmentally
clean, since the fuel gas produced in the solids-liquid
separation module is used. This gas consists of hydrogen
and methane with minor amounts of impurities.
Solids Separation Module
Module Description--
The purpose of the solids separation module is to
separate the undissolved coal and mineral matter from the
coal liquefaction product. The first process in the module
is a centrifuging to remove suspended particles of mineral
matter and partially reacted coal from the liquid product.
The solids that are separated by centrifuging are permeated
with oil. To recover this oil, the solids are pyrolyzed at
temperatures of about 149°C in a second process.
Both processes were successfully tested on the bench-
scale unit and in laboratories. Appreciable quantities of
oil, amounting to as much as 53 weight percent of the solids
on an ash-free basis, were recovered by pyrolyzing. Figure
7 represents an overall flowsheet for the module, while
Figure 8 shows the equipment and technological procedures
employed in the pyrolyzing.
Liquid and solids from the bottom of the letdown flash
drum are sent to the centrifuge, where oily char is separated
from oil and sent to the char de-oiling process (see Figure
7). This oily char is fed to the multiple hearth roaster
52
-------
Figure 7. Synthoil process flow diagram - solids separation module (27)
-------
i_n
4>
PRODUCT
OIL
12:
RECYCLE
BLOWER
FUEL GAS
i r™
MATER
COOLER
COOLER
PUMP
BFW
PUMP
DE-OILED CHAR
TO CHAR GASIFICATION
HYDROGEN PRODUCTION
Figure 8. Synthoil char de-oiling process flowsheet (28)
-------
where oil is separated (complete separation of oil is
assumed). As shown in Figure 8, recycled fuel gas (by-
product) is used to cool the de-oiled char.
Oil separated by centrifugation is pumped through a
preheater to the product oil stripper. About 20 percent of
the oil is vaporized in the preheater. This vapor-liquid
mixture enters the product oil stripper. The vapor rising
within the stripper is cooled and partially condensed by the
refluxed liquid.
The vapor leaving the stripper contains water, I^S,
ammonia, and light oil vapors. This vapor is cooled and
sent to the product oil stripper separator, where condensed
light oil is sent back to the product oil stripper (part of
it is taken off as purge oil). Condensed water is removed
from the bottom as sour water. Off gases from the separator
are sent to acid gas removal.
Process and Waste Streams--
There are three continuous waste streams generated in
the module: sour water from the product oil stripper
separator, excess de-oiled char, and flue gases from the
preheaters. Figure 9 shows the module input-output streams.
Table 10 gives the stream constituents.
The sour water composition is expected to be similar to
that of the sour water generated in the phase separation
module, because it is separated from the same type of light
oil as in the product stripper separation (Table 23).
Hence, discussion of the composition of sour water from
phase separation is applicable to this stream.
55
-------
1
2
3
4
5
6
7
8
9
10.
11.
©
STREAM
© ® © ©
SYNTHOIL
SOLIDS
SEPARATION
MODULE
© ©
©
©
¦©
METRIC TONS PER DAY
OIL AND SOLIDS FROM GAS
SEPARATION
CHAR TO HYDROGEN PRODUCTION
SOUR WATER
PRODUCT OIL
OIL TO SLURRY PREPARATION AND
QUENCHING
PURGE OIL
FLUE GASES
OFF GAS TO ACID GAS REMOVAL
FUEL GAS
VAPOR LEAKAGE
TRANSIENT SPILLS
50,555.3
3,392.0
31.2
6,249.0
36,403.0
3,749
NOT QUANTIFIED
12
661
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 9. Synthoil solids separation module
process and waste streams
56
-------
From the total of 3392 metric tons per day of char
leaving the module after cooling (Table 24), 3002 metric
tons per day is used in the hydrogen production.
TABLE 24. SYNTHOIL SOLIDS SEPARATION MODULE PROCESS
AND WASTE STREAMS (EXTRACTED FROM TABLE 15)
Stream* Metric tons per day
1. Oil and solids from gas
separation
H2O 31
Oil 46,072
Solids 4,440
Hydrocarbons 8.2
HoS 4.1
50,555.3
2. Char to H2 production
Solids 3,208
Oil 184
3,392
3. Sour water
H2O 30.8
NH3 trace
H2S 0.2
Oil and phenols 0.2
3T7?
4. Product oil to storage
Oil 6,111
Residue 138
¦k
6,249
5. Oil to slurry preparation and
quenching
Oil 35,308
Residue 1,095
36,403
6. Purge oil 3,759
8. Off gas to acid gas removal
H2O 0.2
Hydrocarbons 8.2
H?S 3.9
T2TT
9. Flue gas 661
Refer to Figure 9.
57
-------
Excess char at the rate of 370 metric tons per day is dis-
posed of as solids waste. The ultimate analysis of this
char is given in Table 25.
TABLE 25. ANALYSIS OF RESIDUES FROM PYROLYSIS
OF CENTRIFUGED SOLIDS - SYNTHOIL PROCESS (32)
Component
Ultimate analysis
percent
Hydrogen
2.5
Carbon
34.5
Nitrogen
0.4
Sulfur
8.7
Ash
54.3
The char is contaminated with traces of remaining
heavy oil and tars. Analysis of aromatics in heavy oil
product from pyrolysis of centrifuged liquids is given in
Table 26.
TABLE 26. ANALYSIS OF AROMATICS IN HEAVY OIL PRODUCT
FROM PYROLYSIS OF CENTRIFUGED SOLIDS SYNTHOIL PROCESS (32)
Structural type
Percent of
total
Benzenes
o
o
i—i
Naphthalenes
12.3
Anthracenes, phenanthrenes
5.7
Acenaphthylenes, fluorenes
8.5
Phenylnaphthalenes, methylene
phenanthrene
3.6
4-ring cata-condensed, benzofluorenes
2.3
4-ring peri-condensed, benzofluorenes
3.6
Indenes
10.2
Acenapthalenes, biphenyls
12.6
Indans, tetralins
15.7
Phenols
12.6
Dihydric phenols
3.1
58
-------
Table 27 shows expected concentration of some trace
elements in the centrifuge residues. Since the volatility
of these elements at the temperature of pyrolysis is neg-
ligible, it is assumed that most of these trace elements
will be discharged with the char from pyrolysis.
TABLE 27. TRACE ELEMENTS IN THE
CENTRIFUGED RESIDUES - SYNTHOIL PROCESS (33)
Concentration ppm
Element
by weight
Cr
84
Mn
180
Ni
53
Cd
1
Pb
18
Previous Tables 20 through 22 give some expected
structural types of organic compounds in heavy oil separated
in the centrifuge, organic sulfur compounds in the products
from the Synthoil process, and concentrations of PAH com-
pounds in the product (heavy) oil.
Acid Gas Removal Process
Process Description--
The gas separation module and the solids separation
module generate gases contaminated with hydrogen sulfide,
ammonia, carbon dioxide, and small amounts of carbon disul-
fide, and carbonyl sulfide. These substances are formed
from the hydrogenation of phenols, aromatic amines, mer-
captans, and sulfides naturally present in the parent coal.
Reaction of the coal and hydrogen yields these contaminant
gases along with more saturated hydrocarbon molecules
(desired product). In the acid gas removal process most of
the carbon disulfide, carbon dioxide, and carbonyl sulfide
59
-------
are removed from the gas stream, leaving a purified gas
which can be recycled into the reactor.
Figure 10 presents a schematic flow diagram of the acid
gas removal process. The process consists of a number of
parallel process trains, each train carrying out a similar
function. A representative train is shown.
A gas stream entering the process would be pumped to
the amine absorber. The gas stream is passed counter cur-
rently through a 15 to 20 percent solution of monoethanol-
amine (MEA) in the amine absorption tower. Hydrogen sulfide
and carbon dioxide, present along with trace amounts of
carbon disulfide and carbonyl sulfide, form complexes with
the MEA as described by the following reactions:
(1) hoch2ch2nh2 + h2s ^zi!"hoch2ch2nh3hs
(2) iioch2ch2nh2 + co2^zzThoch2ch2nh3co3
(3) H0CH2CH2NH2 + CS2 *HOCH2CH2NH2CS2
(4) HOCH2CH2NH2 + COS -HOCH2CH2NH2COS
Only reactions 1 and 2 are reversible. The absorption
process is essentially insensitive to the partial pressures
of acid gases. Removal efficiencies have been found to be
approximately 99.6 percent for H2S and 88 percent for C02>
The MEA absorbent is regenerated by thermal decom-
position at elevated temperatures. Only H2S, C02, and NH^
can be desorbed in this manner, with CS2 and COS forming
nonregenerable compounds with the amine. Off gas from the
amine regenerator, containing most of the H2S, C02, and NH^,
is sent to sulfur recovery.
60
-------
SWEETENED GAS
TO RECYCLE
OFF GAS FROM GAS
SEPARATION AND
2 SOLIDS/LIQUID
SEPARATION
TO
PARALLEL
TRAINS
MAKE-UP AMINE
MAKE-UP
WATER
VENT
AM IN
FILTER
FILTER
BACKWASH
o
I—
-------
The nonregenerable organic complexes are removed by a
purge stream from the reclaimer. Caustic added to the
reclaimer 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.
Process and Waste Streams--
Process and waste streams entering and leaving the acid
gas removal process are shown in Figure 11. Stream con-
stituents are quantified in Table 28.
The major wastewater stream is the blowdown from the
amine regenerator. An intermittent wastewater stream is
backwash from the amine filter in the acid gas removal unit.
Frequency of backwash will depend on the flow rate and
solids content of the amine stream. Accidental spills will
also be a source of intermittent wastewater generation.
Wastewater from 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. The nature of the emission will
depend on the source of leak; therefore, no attempt has been
made to quantify specific constituents. All volatile
constituents appearing in Table 28 are potential atmospheric
contaminants.
62
-------
1
2
3
4
5
6
7
8
9
10
11
0 © ©
d>
®"
©
&
STREAM
SYNTHOIL
ACID GAS
REMOVAL
PROCESS
© © ©
©
METRIC TONS PER DAY
GAS TO PURIFICATION
MAKEUP WATER
ADDITIVES
STEAM
ACID GAS
PURIFIED RECYCLE GAS
PURGE
FILTER BACKWASH WATER
VENT GASES
VAPOR LEAKAGES
TRANSIENT SPILLS
12,301.8
7.3
2.0
NOT QUANTIFIED
1,682.9
10,639
9.0
NOT QUANTIFIED
NOT QUANTIFIED
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 11. Synthoil acid gas removal
process and waste streams
63
-------
TABLE 28. SYNTHOIL ACID GAS REMOVAL PROCESS AND
WASTE STREAMS (EXTRACTED FROM TABLE 15)
Stream* Metric tons per day
1. Gas to purification (combined
streams - gas separation and
from solids separation)
H20 10.2
Ho 4,910
H2S 613
NH3 6.6
CO 291
CO2 994
Hydrocarbons 5,212
Oil (light & vapor) 265
12,301.8
2. Make-up water to amine system 7.3
3. Additives to amine system
Monoethanolamine (MEA) 1.3
Polyrad 1110 A (corrosion 0.006
inhibitor)
Oleyl alcohol (anti-foam) 0.02
Sodium hydroxide 0.6
17575
5. Acid gas to sulfur recovery
H2S 612
NH3 6.6
H20 2.4
Hydrocarbons 72
CO 0.9
C09 989
1,682.9
6. Purified gas (recycle)
H?0 8.2
H2 4,910
Hydrocarbons 5,171
CO 290
CO2 5.6
Oil (light & vapors) 254
10,638.8
7. Purge from amine regenerator
H2O 7.3
Sulfates 0.3
Monoethanolamine 0.7
NaOH 0.7
23L
'''Refer to Figure 11.
64
-------
SECTION 4
THE H-COAL PROCESS
INTRODUCTION
The H-Coal process is a catalytic hydroliquefaction
process developed by Hydrocarbon Research, Inc. (HRI), for
converting coal to liquids and fuel gas. The feasibility of
the process has been demonstrated on two 11 to 45-kg per day
bench-scale units and on a 2.7-metric ton per day PDU. Thus
far, research has indicated that the process can produce a
synthetic crude which can be further refined to gasoline and
furnace oils by conventional methods. This mode avoids the
troublesome operation of filters and centrifuges by using
vacuum distillation for product recovery. Alternatively,
the process can produce a fuel oil with 0.5 percent sulfur,
naphtha with less than 0.2 percent sulfur, and a fuel gas.
While the latter mode of operation uses less severe operating
conditions and a significantly reduced hydrogen consumption,
it has proven more costly because of the need to remove
unconverted coal and ash from the residuum and heavy oil via
centrifugation. Depending upon the feed coal type and
process operating conditions, the process may convert up to
96 percent of the organic matter in coal to gaseous and
liquid products (34) .
Fourteen coal types have been tried up to this point,
and all have been satisfactorily converted by the H-Coal
65
-------
process. The coal types examined include eastern, midwestern,
and western bituminous coals; western subbituminous coals;
lignites from Texas and North Dakota; and brown coal from
Australia. The total experience with processing these coal
types, in bench-scale and PDUs, over the past twelve years,
represents more than seven years of cumulative process
development experience (34).
The H-Coal process is now undergoing its next stage of
development, a pilot plant to be constructed in Catletts-
burg, Kentucky. This plant will be capable of processing a
nominal 544 metric tons per day of coal with an output of
O
some 1,289 m /day of fuel oil or 181 metric tons per day for
112 m /day of synthetic crude. Phase I or "design" of the
H-Coal facility is essentially complete at this time. The
"construction" phase is underway. It is anticipated that
construction will be completed in 1978 and that the plant
will operate until 1980. Design and construction funding is
shared by the Department of Energy and participating in-
dustrial organizations.
PROCESS DESCRIPTION
Overall Process and Operating Conditions
The commercial H-Coal facility described in this report
is a hypothetical plant designed to produce a nominal 7,950
3
m /day of liquid product by the fuel oil mode of operation,
in which severity is increased no further than that needed
to liquefy the coal with a minimum of hydrogen.
66
-------
An overall process flow schematic is depicted in Figure
12. It shows the interconnections between the various
modules.
For the H-Coal process, coal is first dried to less
than 2 percent moisture and ground to less than 20 mesh.
The dry pulverized coal is then mixed with a slurrying oil
containing a solids-liquid slurry recycle and a distillate
recycle stream. The weight ratio of coal to slurry oil is
about 1:2.
The coal is hydrogenated in an ebullated bed catalytic
reactor at a pressure of 20.7 MPa and a temperature of
450°C. Internal mixing is provided to maintain the catalyst
in an ebullated state.
Material Balances
The material balances for this report were based on a
dry, pulverized coal input of 17,347 metric tons per day of
Illinois No. 6 coal. The coal was assumed to have the
following ultimate analysis.
It was assumed that 91 percent of the organic matter in
coal was converted into liquid and gaseous products.
Bench-scale and PDU operations have shown that conversion
may be as high as 96 percent.
Component
Ultimate analysis
weight - percent
C
H
N
0
S
Ash
71.0
5.2
1.0
9.0
4.5
9.3
67
-------
CATALYST
CT>
00
Figure 12. Overall process flow schematic for a conceptual H-coal
plant operating in the fuel oil mode (35)
-------
The H-Coal commercial evaluation prepared by Fluor
Engineers (35) was used extensively in preparation of the
mass balances for this report. In addition, data presented
by Johnson et al. (34), Kang and Kydd (36), and OCR (37)
from bench-scale and PDU studies were utilized.
Table 29 gives the quantities in tons per day of var-
ious components to be found in input, process and discharge
3
streams for a conceptualized 7,950 m /day H-Coal process.
The stream numbers correspond to the process streams de-
picted in Figure 12.
The data in Table 29 cover those streams which are
generated in the process modules and in by-product recovery.
Waste and process streams generated in auxiliary facilities
are quantified in Section 7 and are also enumerated in
Figure 12. Available data did not permit quantification of
particulates which are emitted from the process gas streams.
Organics that are discharged in sour water effluents could
not be characterized from available data with much certainty.
This area is further addressed in Section 8.
Material and Thermal Efficiency
The overall material and utility balance is depicted in
Table 30. Coal, oxygen, and water are the only raw materials
required in the process for the conversion of coal to
liquid products. Fuel gases produced in the process to-
gether with a portion of the heavy oils and solids are
adequate to supply all the energy demands of the system
except for the start-up; natural gas or LPG may be needed
then. Makeup water is the only utility which will be
required from an outside source.
69
-------
TABLE 29. IIATERIAL INVENTORY FOR THE H-COAL PROCESS (33)*
Stream
description
Feed
coal
Recycled
slurry
Coal/oil
slurry
Makeup Catalyst
gas added
Solids-liquid
slurry
Reactor Quench
vapors HjO
Solids-
liquid
to recycle
Solids-liquid
to
separation
Acid
gas
Recycle
gas
Number*
1
2
3
4 5
6
7 8
9
10
11
12
Composition
H2
631.4
186.9
795.8
146.0
836.0
H2
29.0
6.4
52.2
17.2
41.3
CO
631.4
122.5
643.6
257.4
507.2
C02
1.5
1.5
142.9
156.0
468.8
1.5
0.7
386.6
109.4
h2s
2.4
2.4
0.5
110.7
616.0
1.4
0.7
459.5
42.5
"S
23.6
80.7
Trace
0.1
0.4
Cx - Cj gas
671.3
1,737.3
1,321.01
999.9
h2o
384.6
1,214.7 1,563.2
0.2
1.7
18.4
3.2
C4
2.1
2.1
84.4
204.1
2.1
0.8
133.5
23.0
C5 - 205°C***
164.4
164.4
863.4
708.0
164.2
57.6
0.8
1.8
204-260°C***
866.8
866.8
789.3
417.8
447.4
146.5
260-525°C**»
23,914.0
23,914.0
24,942.0
4,881.7
13,694.0
5,488.6
Above 525°C
8,207.7
8,207.7
11,481.6
8,207.7
3,273.6
Ash
1,536.9
1,536.9
3,006.3
1,445.1
1,561.2
Unreacted Coal
17,400
1,145.8
18,493.2
2,537.6
1,236.5
1,301.1
Other
8.5
Total
17,400
35,841.6
53,189.0
1,435.2 8.5
45,366.6
11,820.7 1,563.2
25,200.1
11,832.6
2,729.31
2,574.:
* Based on a production rate of 7,950
** Refers to Figure 12.
of fuel oil per day, all values are in Metric tons/day.
***Denotea boiling point upper range for product mix.
(continued)
-------
TABLE 29 (continued)
Stream
description
Product oil
to Sour
fractionation Ho0
Light
ends Heavy
Makeup Vent to oil to
antlsolvent Steam gas fractionation storage
Heavy
bottoms
Middle Heavy
Naphtha distillates Fuel oil
Waste to to to
water Steam storage storage storage
Number*
13
14 15
16
17
18
19
20
21
22
23
24 25
Composition
H2
CO
0.7
1.5
(X>2
8.3
118.4
0.6
0.1
0.1
0.2
h2s
48.1
174.5
0.5
0.2
0.5
0.2
NH3
0.18
103.7
0.1
- C3 gas
88.0
h2°
2.3
3,136.9
638.7
0.1
1.1
639.3
383.0
C*
139.5
0.6
0.2
53.9
Cj - 205°C
1,336.2
11.5
57.2
0.3
1.0
1,378.8
3.9
204-260°C
609.8
3.1
141.1
4.4
1.0
85.9
384.6 93.0
260-525°C
10,638.4
2.7
1,626.3
2,489.2
1,371.0
1.1
1,753.1
Above 525°C
1,840.4
1,433.0
0.3
Ash
4.3
1,556.9
Unreacted Coal
2.9
1,298.2
Other
44.5
(Decane)
16.7
(Decane)
0.3
(Decane)
27.5
(Decane)
16.5
(Decane)
0.2
(Decane)
Total
12,873.98
3,550.8 44.5
638.7
1.9
1,842.9
4,341.8
5,686.6
642.7
383.0
1,535.7
389.1 1,846.1
(continued)
-------
TABLE 29 (continued)
•vj
ro
Streaa
description
Number*
Composition
2
CO
CO.
H2S
HH3
C1 " C3 8"
H2°
Cj - 205 C
204 - 260°C
260 - 525°C
Other
Total
Recycle
oil
26
Makeup oil
to gas
separation
27
Acid
gas
28
Sour
»2°
29
Makeup
water
30
Sour gas
to
sulfur
recovery
31
Sweetened
fuel
gas
32
198.8
10,441.8 77.7
0.7
1.5
8.1
47.3
0.2
87.7
4.5
75.4
10,640.6
77.7
225.4
0.1
0.4
381.5
0.8
0.5
1.2
384.5
2.9
374.9
504.7
0.5
20.0
8.6
146.7
17.2
258.8
17.4
1.8
1,388.4
17.3
198.5
Waste from
amine unit
33
3.4
2.9
908.7
2,046.1
0.8
(Mea, Polyrad)
4.2
MEA
solution
34
0.9
(Mea, Polyrad)
0.9
(continued)
-------
TABLE 29 (continued)
CO
Strean
description
Number*
Sour
water
35
Sludge
froti
clarlfler
36
CO2 from
acid gas
reaoval
37
Acid gas
to sulfur
recovery
38
Solvent
blowdovn
39
Fuel
gas to
utilities
40
Excess
bo t tons
not sent
to g&slfler
41
Water to
wastewater
treatment
42
Ammonia
recovered
43
Phenol
recovered
44
Co^>osition
H2/Argon
CO
CO,
h2s
C1 " C3
V
1,203.8
772.9
Cj - 205 C
204 - 260°C
260 - 525°C
Above 52S°C
Ash/slag
Unreacted Coal
Other
Total
1,159.4
1,048.7
SO.5
8,738.9
139.5
1.0
5.4
2.3
1,203.8 1,932.3 1,048.7
(S0?, HO, HCH)
8,937.6
5.0
5.0
145.6
17.1
256.7
17.3
1.8
1,378.9
17.2
197.2
2,031.8
340.9
336.0
393.9
320.1
1,390.9
118.5
174.9
103.7
5,631.5
13.3
4.9
5.0
0.3
103.6
6,052.1
103.6
20.7
(Phenol)
20.7
Sulfur
recovered
45
1,639.6
(Sulfur)
1,639.6
-------
TABLE 30. OVERALL MATERIAL BALANCE FOR THE H-COAL
PROCESS (EXTRACTED FROM TABLE 29)
Inputs Outputs
Metric Metric
Material tons/day Material* tons/day
Coal to reactor
17,400
Heavy oil (39,176.0 bbd)
6,598
Oxygen to gasifier
3,552
Naphtha (10,834.0 bbd)
1,540
Water to process
2,593
Fuel gas for export
14.2
Water to utilities
24,984
Treated wastewater
5,361.5
Total
48,529
Water from blowdown
1,701.0
Sludge from hydrogen pro-
1,932.3
duction
Heavy bottoms not used
1,444.2
in gasifier
Phenols
20.7
Sulfur
639.6
Ammonia
103.6
Waste gas**
28,707.9
Clarifier overflow
419.1
Miscellaneous wastes
45.9
Total
48,528.0
* Output materials include 91.5 metric tons/day of fuel gas of which
77.3 tons/day are used for power and steam generation.
**Waste gas included evaporation and drift from the cooling tower,
tail gases, vent streams, etc.
Process Material Yields--
Utilizing the data in Table 30, material yields of the
process can be calculated. The yield of heavy oil in unit
weight per unit weight of coal is 6,598/17,400 =0.38. If
74
-------
Overall Thermal Efficiency--
The overall thermal efficiency permits an estimate of
the overall heat utilization as the result of the process
and required auxiliary operations. Conceptual designs for a
commercial facility indicate that the plant will be com-
pletely self-sufficient, including all utilities except
makeup water. The overall thermal efficiency is defined as:
The heating values of the products + the heating values
of the combustible by-products (joules)
The heating values of all raw materials consumed
by the process and auxiliary facilities (joules)
0.74 + 62.0 + 270.3 (TJ) , nn _ -,n„
477.6 (TJ) x 100 " 70/o
Nearly all of the fuel gas produced in the process is util-
ized by the plant for fuel gas and electricity production.
Only 0.74 MJ of fuel gas is considered a product or by-
product.
DESCRIPTION OF THE PROCESS MODULES
The following modules and processes are considered to
be inherent to the H-Coal process:
• Hydrogenation
• Gas Separation
• Solids Separation
• Fractionation
75
-------
• Auxiliaries include coal preparation; acid gas
removal; the generation of hydrogen, oxygen, steam
and electric power; raw water treatment; product
storage; solid, liquid, and gaseous waste treat-
ment; cooling towers; by-product recovery; and
sulfur recovery.
Auxiliaries are discussed in Sections 6 and 7.
The operating units in each module are based upon a
conceptualized design. Undoubtedly some units will be modi-
fied before the commercial facility is completed as a result
of new methods for improving process efficiency and pollu-
tion control.
Coal Hydrogenation
Module Description-
Figure 13 is a flow diagram of the H-Coal hydrogenation
3
module. Coal hydrogenation for a 7,950 m /day H-Coal facil-
ity requires a total of six parallel reactors, each with its
own feed heater and hydrogen heater for independent tem-
perature control (35).
In the H-Coal process, the coal-oil slurry resulting
from coal preparation is brought to reactor pressure and
mixed with a portion of the makeup hydrogen. The slurry is
then preheated and charged with the required hydrogen to
each reactor. Hydrogenation is accomplished in an ebullated
bed reactor using a cobalt-molybdate catalyst. The operat-
ing conditions are a pressure of 20.68 MPa and a temperature
of 454°C. The reaction zone temperature can be kept nearly
constant by controlling the temperatures of the incoming
streams, which may be 66-93°C lower than the temperature in
the reactors. At these conditions, more than 90 percent of
76
-------
-vl
RECYCLE H2
MAKEUP H2
COAL/OIL
SLURRY
RECYCLE VAPOR
FEED PREHEATER
MAKEUP H
COAL/OIL
SLURRY FEED
PREHEATER
S\
M
SLURRY
RECYCLE Hr
LURRY FE
PREHEATER
ED
7W
RECYCLE VAPOR
FEED PREHEATER
CATALYST —
VAPORS
h2-rich
GAS
H-COAL
REACTOR
20.68 MPa
LIQUID/SOLID
SLURRY
RECYCLED
SPENT
CATALYST
CATALYST¦
h2-rich
GAS
VAPORS TO GAS
SEPARATION MODULE
VAPORS
H-COAL
REACTOR
20.68 MPa
TO GAS
LIQUID/SOLID SLURRY SEPARATION MODULE
RECYCLED OIL
SPENT
CATALYST
Figure 13. H-Coal process flow diagram - hydrogenation module (35)
-------
naphtha is included the yield is (6,598 + 1,540)/17,400 =
0.47.
Process Thermal Efficiency--
The thermal efficiency* serves as a means of measuring
the effectiveness of the process for making clean fuels from
coal. The process thermal efficiency is defined as:
The heating value of all clean products (joules)
The heating value of coal to the reactor + the heating
(joules) value of the makeup gas
_ 106.6 + 69.1 + 277.6 (TJ) „ n
477.6 + 93.6 (TJ) x 100 " 79/0
The data in Table 31 indicate the heating values for pro-
ducts and materials used in the H-coal process.
TABLE 31. HEATING VALUE OF PRODUCTS AND MATERIALS
UTILIZED IN THE H-COAL PROCESS (35)
Input
Metric
tons/day**
MJ/kg
TJ/day
Dry coal to reactor
17,400
27.45
477.6
Fuel gas for power and
steam generation
2,032
51.98
105.6
Make-up gas from
gasifier
1,440
64.97
93.6
Output
Fuel gas***
2,046.1
51.98
106.6
Naphtha
1,541
44.88
69.1
Heavy fuel oil
6.598
42.08
277.6
* This calculation is a first law thermodynamics erticiency.
It considers only heat quantity values.
** From Table 29.
***0nly 0.74 TJ/day of fuel gas are exported. The process
fuel gas is used for steam and power generation.
78
-------
the carbon in coal is converted to liquid and gaseous prod-
ucts. A detailed picture of the ebullated bed reactor is
shown in Figure 14.
The hydraulics of the reactor are such that the cat-
alyst bed occupies a well-defined portion of the reactor at
the base, above which a catalyst-free zone of liquids,
solids, and gases exists. As a result it is possible to
remove and add catalyst without shutting down the reactor.
Two separate outlet streams discharge from the hydro-
genation module to the gas separation module, as is shown in
Table 32. The compositions of the vapor stream and the
liquid/solids slurry leaving the reactor are quantified in
Table 29 as streams 7 and 6, respectively.
TABLE 32. COMPOSITION BY WEIGHT PERCENT OF A TYPICAL
FUEL GAS UTILIZED IN THE H-COAL PROCESS (35)
Fuel gas produced in acid gas removal process
H2
N2
CO
C02
H2S
7.2% (by weight)
Hydrocarbons
H20
0.8
12.6
1.0
0.1
77.5
0.8
mz
Typical flue gas discharged from process heaters
N2
H20
02
C02
S02
N0X
75.7% (by weight)
6.9
5.2
12.2
0.007
Trace
1OT
79
-------
CATALYST
INLET
SOLID-LIQUID
LEVEL
CATALYST
LEVEL
RECYCLE
TUBE
COAL/OIL SLURRY
Figure 14. H-Coal reactor (36)
CLEAR
LIQUID
LIQUID
SOLID
SETTLED
CATALYST
LEVEL
CATALYST f
OUTLET
DISTRIBUTOR
PLENUM
CHAMBER
GAS INLET
80
-------
The vapor stream contains a large percentage of the
light hydrocarbons, hydrogen sulfide, ammonia, carbon mon-
oxide, carbon dioxide, and water vapor. This stream leaves
the top of the reactor, essentially devoid of solids and
heavy oils. The solids-liquid slurry contains the uncon-
verted coal and the ash. It passes up through the catalyst
bed and also leaves the top of the reactor.
Process and Waste Streams-
Modular influent and effluent streams are shown in
Figure 15. Most of the hydrocarbons which make up the
gaseous and liquid products are formed in this module.
Potential pollutants may be converted to other forms that
are suitable for removal. Only one continuous waste stream,
the flue gas from the preheaters, is discharged from the
hydrogenation module. There is also the possibility of
hydrocarbon vapor leakage from the reactor and transient
spills. It is noted in Table 33 that the fuel gas utilized
is the sweetened fuel gas produced in the gas purification
module. A typical flue gas is also depicted. The weight
percent of the various components found in the fuel gas and
flue gas is quantified. Table 33 gives the process and
waste stream constituents for the hydrogenation module.
While the catalyst is not discharged continuously, it
is replaced at the rate of 8.48 metric tons per day. This
is in agreement with bench-scale studies, which have shown
that greater than 1,043 kilograms of coal per kilogram of
catalyst can be processed without affecting process effi-
ciency or quality of the product (36). The character-
istics of the cobalt-molybdate catalyst are listed in Table
34. Analyses of spent catalyst indicate that some metallic
contaminants are deposited on the catalyst. Whether such
contaminants adversely affect the process is questionable
(36).
81
-------
© © ©
©-
©-
©-
-©
-
-------
TABLE 33. H-COAL HYDROGENATION MODULE PROCESS
AND WASTE STREAMS (EXTRACTED FROM TABLE 29)
Stream
Metric
No.*
tons per day
6
Reactor vapor stream
H2
795.8
»2
52.2
CO
643.6
C02
468.8
H2S
616.0
NHo
80.7
h2o
1,214.7
Hydrocarbons
7,948.8
Solids
0.0
11,820.6
7
Reactor solid-liquid slurry
H2
186.9
n2
6.4
CO
122.5
C02
156.0
H2s
110.7
NKL
23.6
H25
384.6
Hydrocarbons
38,831.9
Solids
5,543.9
45,366.4
9
Spent catalyst
Cobalt-molybdate catalyst
8.48
*Stream numbers correspond to those numbers in Figure 15.
Streams 1 through 5 are input streams. They are not quan-
tified in this table, but may be found in Table 29.
83
-------
TABLE 34. CATALYST CHARACTERISTICS (37)
Physical properties of
fresh catalyst
Composition of
spent catalyst
Al, Ti
Mo, Fe, B, Co
V, Si, Ca
Ni, Cr, Mg, Sn
Cu, Mn, Ag, Zn
1.6 mm diameter extrudates
12.7 mm maximum length
15% Mo03
3% CoO on alumina
(Si02 on alumina may also
be present)
Spectrographic composition
range from benzene washed
sample
10 - 100%*
1 - 10%
0.1 - 1%
0.01 - 0.1%
0.01%
^Alumina levels between 10 and 100 percent would be expected
insofar as the catalyst is alumina based; this is not a
contaminant from the coal. Likewise, cobalt, molybdate,
and silica are components of the catalyst, and not con-
taminants.
Gas Separation Module
Module Description--
The gas separation module is shown in Figure 16. The
feed streams to the gas separation module include both the
vapor stream from the reactor and the solids-liquid slurry
from the reactor. The gas separation module then separates
fuel gas from the reaction mixture. Gas separation also pro-
vides a hydrogen-rich stream for recycle to the reactor. This
module also yields a solids-free oil for fractionation,
the slurry stream for recycle back to the reactor, and the
84
-------
Figure 16. H-Coal process flow diagram - gas
separation module (35)
85
-------
slurry stream which contains the net unreacted coal and ash.
The latter is sent to the solids-liquid separation module.
The gases from the high pressure absorber flash drum, the
low pressure absorber flash drum, the low pressure flash gas
separator, and the distillate flash drum are all diverted to
the gas purification module for cleanup.
The solids-liquid slurry leaving the low pressure flash
drum is fed to a series of hydroclones to concentrate the
solids. Hydroclone overhead is recycled back to the reactor
in order to maintain a specified concentration of residuum
(524+°C) material in the reactor effluent. The overhead is
substantially reduced in solids. Bench-scale data has
served as the basis for obtaining the desired quantity of
residuum to be recycled. By reducing the quantity of dis-
tillates recycled and utilizing the heavy residuum recycle
stream, the yield of residuum produced in the reactor is
decreased (36). The ratio of residuum to distillates in the
recycle slurry is determined by the need for a low residuum
yield without a high solids buildup in the reactor, which
could cause unstable operating conditions. Hydroclone
bottoms are sent to the solids-liquid separation module.
Quench water used in the flash drums emerges as sour
water streams bearing ammonia and hydrogen sulfide.
Process and Waste Streams--
The process and waste streams from the gas separation
module are denoted in Figure 17. Constituents of the
process and waste streams of the gas separation module are
shown in Table 35. The process streams from this module
include three recycle streams: the hydrogen-rich stream
recycled to the reactor, the hydroclone overhead slurry
recycled to the slurry mix tank, and a quench slurry en-
tering the phase separation module. The acid gas streams
86
-------
1
2
3
4
5
6
7
8
9
10
11
® © ©
STREAK
REACTOR VAPORS
REACTOR SOLIDS-LIQUID SLURRY
QUENCH WATER
SOLIDS-LIQUID TO RECYCLE
SOLIDS-LIQUID TO SOLIDS SEPARATION
MODULE
ACID GAS TO GAS PURIFICATION MODULE
H2 RICH GAS TO RECYCLE
PRODUCT TO FRACTIONATION
SOUR WATER
VAPOR LEAKAGE
TRANSIENT SPILLS
METRIC TONS
PER DAY
11,820.6
45,366.4
1.563.2
25,199.98
11,832.69
2,711.26
2.564.3
12,872.98
3,551.1
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 17. H-Coal gas separation module
process and waste streams
87
-------
TABLE 35. H-COAL GAS SEPARATION MODULE
PROCESS AND WASTE STREAMS (EXTRACTED FROM TABLE 29)
Stream*
Metric tons
per day
4
Solids-liquid recycle stream
co2
1.5
h2s
1.4
h2o
0.18
Hydrocarbons
22,515.3
Solids
2,681.6
25,199.98
5
Solids-liquid slurry to
solids separation module
co2
0.7
H2s
0.7
nh3
0.09
h20
1.7
Hydrocarbons
8,967.2
Solids
2,862.3
11,832.69
6
Acid gas to gas purification
module
H2
146.0
n2
17.2
CO
257.4
co2
368.6
H2S
459.5
nh3
0.36
h20
18.4
Hydrocarbons
1.443.8
2,711.26
(continued)
88
-------
Stream'
*
TABLE 35 (continued)
H2-Rich gas to recycle
H2
n2
CO
CO 2
h9s
NH~
h2o
Hydrocarbons
Metric tons
per day
836.0
41.3
507.2
109.4
42.5
999.9
3.2
24.8
2,564.3
Product oil to fractionation
h2
CO
C02
h9s
NH~
h2o
Hydrocarbons
0.7
1.5
8.3
48.1
0.18
2.3
12,811.9
12,872.98
Sour water
C02
H,S
NH,
hJ
Hydrocarbons
118.4
174.5
103.7
3,136.9
1%, 6
3,551.1
*Stream numbers correspond to number in Figure 17, Streams 1
through 3 are input stream to the module and consequently are
not included in this table. They may be found in Table 29.
89
-------
HEAVY FUEL OIL
TO PRODUCT
STORAGE
Figure 18. H-coal process flow diagram
solids separation module (35)
-------
and the sour water streams are laden with contaminants and
are sent to the gas purification module and to wastewater
treatment, respectively. Other process streams include:
hydroclone bottoms to solids-liquid separation and a product
oil stream routed to fractionation. Two additional tran-
sient sources of emissions from this module are hydrocarbon
vapor leakage and accidental spills.
Solids Separation Module
Module Description--
The solids separation module is designed to recover the
heavy hydrocarbon fractions from the unreacted coal and ash.
Feed to this module is the underflow from hydrocloning. The
module flow diagram is shown in Figure 18. Equipment in
this area consists of flash drums, pumps, stripping and
fractionating columns, accumulators, air cooled heat ex-
changers, direct-fired heaters, reactors and settlers.
Process and Waste Streams-
The input-output diagram for the solids separation
module is shown in Figure 19. The resultant liquid streams
from this module include the heavy product oil, the anti-
solvent which is largely recovered for recycling, and a
small naphtha stream sent to the fractionation module. The
vent gas from the low pressure accumulator is flared.
Process and waste stream constituents are given in Table 36.
The sour water stream generated in this module contains
only trace quantities of ammonia and hydrogen sulfide. It
also contains an unquantified amount of emulsified oils.
Consequently, the COD of this waste stream cannot be speci-
fied.
91
-------
@ © © ©
0-
G>
d>
H-COAL
SOLIDS
SEPARATION
MODULE
© ©
STREAM
1. SOLIDS-LIQUID FROM GAS SEPARATION
2. STEAM
3. MAKE-UP ANTISOLVENT
4. FUEL GAS & AIR
5. VENT GAS
6. LIGHT ENDS TO FRACTIONATION
7. HEAVY FUEL OIL TO STORAGE
8. HEAVY BOTTOMS TO GASIFIER
9. SOUR WATER
10. FLUE GAS
11. HEAVY BOTTOMS NOT UTILIZED BY
GASIFIER
12. VAPOR LEAKAGE
TRANSIENT SPILLS
•©
O
*—
METRIC TONS
PER DAY
11,832.7
638.7
44.5
1,073.3
1.88
1,842.9
4,341.8
4,265.5
642
1,073.2
1,421.0
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 19. H-Coal solids separation module
process and waste streams
92
-------
TABLE 36. H-COAL SOLIDS SEPARATION MODULE
PROCESS AND WASTE STREAMS (EXTRACTED FROM TABLE 29)
Stream*
Metric tons
per day
5
Vent gas
co2
0.6
h2s
0.5
nh3
0.09
h2o
0.09
Hydrocarbons
0.6
1.8
6
Light ends to fractionation
module
co2
0.1
H2s
0.2
h20
1.1
Hydrocarbons
1,841.5
1,842.9
7
Heavy fuel oil to storage
Hydrocarbons
4,334.6
Solids
7.2
4,341.8
8
Heavy bottoms to gasifier
Hydrocarbons
2,124.5
Solids
2,141.0
4,265.5
9
Sour water
h2o
639.3
Hydrocarbons
3.4
642.7
(continued)
93
-------
TABLE 36 (continued)
Stream*
Metric tons
per day
11
Heavy bottoms not used
in gasifier
Hydrocarbons
Solids
707.0
714.0
1,421.0
^Stream numbers refer to number in Figure 19 and do not include
input streams 1 through 4. Information on these streams is
given in Table 29.
The solids-containing residuum fraction generated in the
fuel oil mode of the H-Coal process has been a subject of
research at HRI for a number of years. The conceptual
design for a commercial plant (35) suggests that some 5,400
metric tons per day of an approximate 50 percent solids
residue could be utilized as feed for the hydrogen plant.
Our calculations have shown that roughly 75 percent of this
stream could be utilized to produce the hydrogen required
for the process. The details of the Texaco Partial Oxida-
tion Process, which HRI intends to use in the hydrogen
production module, are proprietary. Consequently, an
alternative method for producing hydrogen has been utilized
in the report. Should operational data prove that the
Texaco Partial Oxidation Process can utilize the entire
nominal 5,400 metric tons per day, an alternative means for
disposing of or utilizing the solids-containing residue will
not be required.
If the remaining 25 percent of the solids-containing
residue is not needed for hydrogen production, it is con-
94
-------
ceivable that the excess gas could be utilized as fuel gas.
A second possibility is that the heavy oil may be recovered
from the solids, increasing the net product yield of the
plant. As a third way to handle the remaining heavy bottoms,
they could be sent to flakers and cooled to ambient tempera-
ture on a steel belt by indirect heat exchange using cooling
water. The material then would be stored for disposal (38).
Flaked residuum will be generated in the Catlettsburg
pilot plant. Plans are to analyze it for chemical and
physical properties. The tests will suggest possible
resource values of the residue and also its leachability
(38).
Fractionation Module
Module Description--
The fractionation module separates a combined feedstock
into fuel gas, naphtha, middle distillates, and heavy dis-
tillates and stabilizes the naphtha fraction. The module is
depicted in Figure 20. Equipment in this area consists of
fractionating and stripping columns, heat exchangers, direct-
fired heaters, pumps, feed tanks and accumulators.
Process and Waste Streams--
The input-output diagram for the fractionation module
is shown in Figure 21. The major waste streams from this
module are the sour water generated in the naphtha stabil-
izer feed drum, the fuel gas from the heater, and the acid
gas stream sent to the gas purification module. The sour
water generated in this module is a steam ejector condensate
and will have a significant COD. Hydrocarbon vapor leakage,
though not a constant source of pollution, will be responsi-
ble for transient emissions. The liquid effluent streams
from fractionation are sent to product storage or are used
95
-------
FRACTIONATION MODULE
AIR COOLER
PRODUCT OIL
FROM GAS SEPARATION
SOLIDS/LIQUID
SEPARATION AND
GAS PURIFICATION
FRACTIONATOR
FEED TANK
5
J-1
TO ACID
GAS MODULE
FLUE GAS
A
AA.
yw
FEED
HEATER
FUEL
GAS
CSC.
o
I—
<£
Z
o
c
a:
c
NAPHTHA
STABILIZER
FEED DRUM
SOUR
WATER
STEAM
ros 1
-------
1
2
3
4
5
6
7
8
9
10
11
12
13
14
© ® ©
£
©¦
H-COAL
FRACTIONATION
MODULE
© © ®
STREAM
LIGHT AND MIDDLE OILS FROM GAS
SEPARATION
LIGHT AND MIDDLE OILS FROM SOLIDS-
LIQUID SEPARATION
STEAM
FUEL GAS + AIR
NAPHTHA TO PRODUCT STORAGE
MIDDLE DISTILLATES TO PRODUCT STORAGE
HEAVY FUEL OIL TO STORAGE
RECYCLE HEAVY FUEL OIL
ACID GAS
SOUR WATER
FLUE GAS
MAKEUP OIL TO GAS SEPARATION MODULE
VAPOR LEAKAGE
TRANSIENT SPILLS
Figure 21. H-Coal fractionation module
waste streams
97
METRIC TONS
PER DAY
12,873.0
1,842.9
383.0
1,638.4
1,535.64
388.96
1,846.1
10,697.7
230.26
384.59
1,638.4
77.7
NOT QUANTIFIABLE
NOT QUANTIFIABLE
process and
-------
in the process as recycled oil streams. The quantity of the
product oils which is lost in transient spills and leaks
cannot be quantified. The process and waste stream com-
positions from the fractionation module are given in Table
37.
The composition of product oils from the H-Coal process
has been determined, although this analysis was not avail-
able for the boiling point fractions as they have been shown
in the mass balances for this report. Table 38 shows the
composition of product oils for a 204 to 343°C fraction and
for a 343 to 493°C fraction at similar operating conditions
(36). Product inspection obtained from continuous flow,
bench-scale operations for Illinois No. 6 coal is shown in
Table 39 (34).
Gas Purification Module
Module Description--
The purpose of the gas purification module is to remove
hydrogen sulfide and carbon dioxide from the gaseous input
streams and to produce a sweetened fuel gas for process and
utility use. Figure 22 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 shown.
The gas separation module and, to a lesser extent, the
fractionation module generate gases contaminated with hydro-
gen sulfide, carbon dioxide, and traces of ammonia. Small
quantities of carbonyl sulfide and carbon disulfide may be
present, but these gases could not be quantified from avail-
able data. Hydrogen sulfide and ammonia are formed under
the reducing conditions of the reactor, while carbon dioxide
98
-------
TABLE 37. H-COAL FRACTIONATION MODULE PROCESS
AND WASTE STREAMS (EXTRACTED FROM TABLE 29)
Metric tons
Stream* per day
5 Naphtha to product storage
C02 0.09
H2S 0.45
Hydrocarbons 1,535.1
1,535.64
6 Middle distillates to product
storage
C02 0.18
H2S 0.18
Hydrocarbons 388.6
388.96
7 Heavy fuel oil to product
storage
Hydrocarbons 1,846.1
1,846.1
8 Recycle heavy fuel oil
Hydrocarbons 10,697.7
10,697.7
9 Acid gas to gas purification
module
H2 0.73
CO 1.45
C02 8.1
H2S 47.2
NH3 0.18
H20 9.5
Hydrocarbons 163.1
230.26
(continued)
99
-------
TABLE 37 (continued)
Metric tons
Streak per day
10 Sour H2O
C02 0.73
H2S 0.36
H20 381
Hydrocarbons 2. 5
384.59
12 Makeup oil to absorber in
gas separation module
Hydrocarbons 77.7
77.7
^Stream numbers refer to streams in Figure 21, module
input streams are not included.
100
-------
TABLE 38. COMPOSITION OF H-COAL PRODUCTS BY
BOILING POINT FRACTIONS (37)
Composition of 4Q0-650oF Fraction
Saturated Compounds
Component wt %
n-paraffins 4.8
i-paraffins 1.7
Monocycloparaffins 14.0
Dicycloparaffins 7.9
Tricycloparaffins 2. 6
3170
Composition of 650-919°F Fraction
Saturated Compounds
Component
wt %
Paraffins
1.4
Monocycloparaffins
3.1
Bicycloparaffins
0.6
Tricycloparaffins
0.7
Tetracycloparaffins
0.4
Pentacycloparaffins
0.2
Hexacycloparaffins
0.1
Phenyls
0.3
6.8
Unsaturated Non-Aromatics
Unsaturated Non-Aromatics
Component
Monocycloparaffins
wt % Component wt 7.
4.3 Paraffins 0.0
4.3 Monocycloparaffins 0.5
Bicycloparaffins 0.3
Tricycloparaffins 0.2
Tetracycloparaffins 0.2
Pentacycloparaffins 0.1
Hexacycloparaffins 0.1
Phenyls 0.2
175
Aromatic Compounds
Component wt °L
Alkyl Benzene 12.6
Indans & Tetralins 30.8
Indenes 5.7
Naphthalene 0.2
Napthaienes 3.5
Acenaphthenes 6.2
Tricyclics 0.4
(CnHjn-lS) 59.4
Aromatic Compounds
Component wt 7,
Alkyl Benzene 3.0
Indans & Tetralins 0.5
5-ringed Compounds 3.5
Napthalenes 21.5
Phenanthrenes 28.1
Chrysenes 8.6
Benzphenanthrenes 5.2
Pyrenes 5 ¦ 9
Phenols
Phenols
Component
108 (MW)
122
136
150
164
178
wt 7.
0.04
0.52
0.98
0.38
0.07
0.01
77TO
Component
Undefined
wt %
1.5
Non-Hydrocarbon
wt 7.
1770
Non-Hydrocarbon
wt 7.
1371
101
-------
SWEETENED FUEL GAS
OFF-GAS FROM PHASE
(GAS) SEPARATION
MODULE; FRACTIONA-
TION MODULE
TO
PARALLEL
TRAINS
ACID GAS TO
SULFUR RECOVERY
TO SKIMMER
DRAIN
CAUSTIC
STEAM
FILTER
BACKWASH
BLOWDOWN
Figure 22. H-Coal process flow diagram - acid gas removal process (35)
-------
TABLE 39. OVERALL
LIQUIDS (C4 AND GREATER)
PRODUCT INSPECTIONS OF H-COAL
DERIVED FROM ILLINOIS NO. 6 COAL (34)
IBP Cuts
API Gravity
Sulfur, %
IBP-204°C
27.1
0.1
204-316°C
15.4
343-524°C
-4.4
0.5
524°C
-16.6
is generated almost exclusively in the gasifier supplying
the hydrogen-rich makeup gas.
Generally, a gas stream entering the module would first
be pumped to the acid gas removal section, consisting of an
amine absorber and regenerator. The gas stream is passed
counter-currently through a 15 to 20 percent solution of
monoethanolamine in the absorption tower. Hydrogen sulfide
and carbon dioxide form complexes with the MEA as described
by the following reactions:
(1) hoch2ch2nh2 + h2s zzr hoch2ch2nh3hs
(2) HOCH2CH2NH2 + C02 zn!: H0CH2CH2NH3C03
(3) HOCH2CH2NH2 + CS2 -HOCH2CH2NH2CS2
(4) HOCH2CH2NH2 + COS *HOCH2CH2NH2COS
Only reactions 1 and 2 are reversible. Removal effi-
ciencies have been found to be approximately 99.6 percent
for hydrogen sulfide and 88 percent for carbon dioxide (39).
The MEA absorbent is regenerated by thermal decomposition
at elevated temperatures. Only hydrogen sulfide and carbon
103
-------
dioxide can be desorbed in this manner, with carbon disulfide
and carbonyl sulfide forming non-regenerable 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.
The non-regenerable organic complexes are removed from
the reclaimer by a purge stream. Caustic added to the
reclaimer to precipitate metals also forms non-volatile
salts with the amine complexes that are discharged as
blowdown. Pure MEA is distilled off the reclaimer and
recycled to the regeneration unit.
The sour gas contains nearly all the hydrogen sulfide
and carbon dioxide. It is routed to the sulfur recovery
unit. The product, sweetened fuel gas, is routed to process
and auxiliary units to be used as fuel gas.
Process and Waste Streams--
Process and waste streams entering and leaving the gas
purification module are shown in Figure 23. Stream con-
stituents are quantified in Table 40. The wastewater
streams are the blowdown from the amine regenerator and the
backwash from the amine filter in the acid gas removal unit.
Frequency of backwash will depend on the flow rate and
solids content of the amine stream. Accidental spills will
also be a source of intermittent wastewater generation.
Atmospheric emissions will consist of gas leakage from
sumps and storage vents, and fugitive emissions during main-
tenance operations. The nature of the emission will depend
on the source of leakage; therefore, no attempt has been
made to quantify specific constituents.
104
-------
1
2
3
4
5
6
7
8
9
10
11
12
STREAM
OFF-GAS FROM GAS SEPARATION MODULE
OFF-GAS FROM FRACTIONATION MODULE
STEAM
MAKE-UP WATER TO THE AMINE SYSTEM
MAKE-UP ADDITIVES
ACID GAS TO SULFUR RECOVERY
SWEETENED FUEL GAS
WASTEWATER FROM ACID GAS REMOVAL
FILTER BACKWASH WASTEWATER
VAPOR LEAKAGE
TRANSIENT SPILLS
VENTS FROM STORAGE AND SUMP
FACILITIES
METRIC TONS
PER DAY
2,729.2
225.3
NOT QUANTIFIED
2.9
0.84
908.65
2,046.1
4.2487
NOT QUANTIFIED
NOT QUANTIFIABLE
NOT QUANTIFIABLE
NOT QUANTIFIED
Figure 23. H-Coal acid gas removal process
and waste streams
105
-------
TABLE 40. H-COAL ACID GAS REMOVAL PROCESS
AND WASTE STREAMS (EXTRACTED FROM TABLE 29)
Streanf^
6
8
Acid gas to sulfur recovery
co2
h2s
nh3
Hydrocarbons
h2o
Sweetened fuel gas
H2
n2
CO
C02
H2S
Hydrocarbons
h2o
Waste from acid gas removal
H2°
MEA
NaOH
Corrosion inhibitor
Anti-foam (oleyl alcohol)
Metric tons
per day
374.9
504.7
0.45
20.0
8.6
908.65
146.7
17.2
258.8
17.4
1.8
1,586.9
17.3
2,046.1
3.4
0.53
0.31
.0027
.006
4.2487
*Stream numbers correspond to numbers in Figure 23. Streams
1-5 are input streams and are quantified in Table 29. Streams
9-11 have not been quantified.
106
-------
The composition in weight percent of the gas pro-
duced is, according to bench-scale data (37):
Methane 29 to 36
Ethane 25 to 34
Propane 33 to 38
The olefin content of the C^-C^ gas products is very low.
Ethylene content is near the limit of detection (approxi-
mately 0.2 weight percent of coal). Propylene content is
also low, with the average yield being about 0.05 weight
percent of coal.
The fraction contains 10 to 20 percent isobutane,
with the remainder being straight chain compounds. Roughly
15 to 20 percent of the straight-chain fraction was
olefinic in bench-scale units, while only 5 to 15 percent
was olefinic in the 3 ton per day PDU. Presumably, this
reflects the ability of the PDU to hydrogenate recycled
butane in the recycle hydrogen-rich gas stream.
107
-------
SECTION 5
THE EXXON DONOR SOLVENT PROCESS
INTRODUCTION
The Exxon Donor Solvent (EDS) process is a noncataly-
tic* coal liquefaction process that produces a versatile
combination of fuel gases, light and heavy naphthas, kero-
sine, diesel oil, and fuel oils. The yields can be varied
according to the desired end-products. Host of the process
research data is limited to the utilization of Illinois No.
6 bituminous coal. However, studies are in progress to
obtain operational data on Wyoming subbituminous coals and
lignites.
The first phase of Exxon's research, in the period
1966 to 1973, resulted in the development of a basic process
flow sheet and the determination of the general operating
parameters. The second phase began in 1973 and is ongoing.
Its goals are to define the optimum operating conditions and
process module arrangements for the process (40).
The third phase began in July 1977, with the decision
to build a 227 metric-ton per day pilot plant. The plant
will be located in Baytown, Texas, and is scheduled for
completion by early 1980. Additional research is underway
*Non-catalytic for liquefaction; catalysts are used for
saturating solvent and upgrading products.
108
-------
utilizing the existing 22.7 and 45.4-kg per day Recycle Coal
Liquefaction Units (RCLU) and the 0.91 metric-ton per day
Coal Liquefaction Pilot Plant (CLPP) to gather necessary
process data for the scaled-up pilot plant design (41).
PROCESS DESCRIPTION
Overall Process and Operating Conditions
EDS process development is entering the pilot plant
stage. Thus, a complete process description is unavailable.
Using other liquefaction processes as a guide, a concep-
tualized 7,950-m per day plant for donor solvent lique-
faction has been designed based on information in references
40 and 42.
The process schematic of the hypothetical facility is
shown in Figure 24. In the EDS process, coal is dried to 2
percent moisture and ground to minus 8 mesh. The prepared
coal is mixed with donor solvent recovered from the process,
at approximately 2 parts solvent to one part coal on a
weight basis. The slurry is mixed with hydrogen-rich gas
from the hydrogen generation module, preheated, and sent to
the hydrogeneration reaction vessel.
Coal has been liquefied over a range of temperatures
and pressures. For this study the liquefaction module is
assumed to operate at 450°C and 12.5 MPa. This reaction
produces a mixture of gaseous, liquid, and solid products
which require further processing.
Gas separation operations receive the raw hydrogenation
products. Noncondensible gases are removed and sent to the
gas purification module. Light naphtha is condensed and
109
-------
TO SULFUR RECOVERY
FEED
COAL
STORAGE
1
r^~ i.-
33
slurry
PREPARATION
0>~
&
SOLVENT HrDROTREATINR
{ V^V
I HOT HIGH PRESSURE SEP. \ \yl
DEA
==
DEA
luti i
(
HOT LOW PRESSURE SEP.
J"
~V@H>
SOLIDS
SEPARATION
LflJ
/
W
r
^Tn?
fll
n
CATALYST
GUAM)
REACTOR
V
TO WASTE
WATER
TREATMENT
r^3-
'
u/
Co/Mo
CATALYST
PHASE SEPARATOR
BOTTOKS TO FLEXICOKIW AND HY0W6EK GEICRATION
TO WASTEVATE®
TREATMENT
_ b
- 1^~
I IL-
LIQUID
PRODUCT
Figure 24. Exxon donor solvent coal liquefaction process schematic (40)
-------
sent to the hydrotreating module. This high pressure
separation operation occurs at 250°C and 12.5 MPa. Heavier
liquids and solids are sent to a low pressure separator
operating at around 200°C and 101 kPa. This separator
removes heavy naphthas and water. Heavy naphtha is sent to
the hydrotreating module. The water, possibly containing
some ammonia and phenolic compounds, is sent to the waste-
water treatment facilities. Heavier liquid products and
solids pass from the low pressure separator to the solids
separation module.
A vacuum distillation unit, operating at 370°C and 3.3
kPa, removes solids from the heavy hydrocarbon liquids,
thereby preparing them for hydrotreating. The solids
consist of ash, char, and heavy tar residues. Utilization
and disposal options for the bottoms from vacuum distilla-
tion are discussed in Section 6.
Heavy liquids from the solids-liquid separation are
combined with the naphthas from gas separation and pre-
heated. The preheated stream enters the hydrotreating
module. Hydrotreating regenerates the donor solvent which
provides most of the hydrogen in the hydrogenation. Further
upgrading of the liquid products also is performed in this
module. The hydrotreated product is separated into three
phases: a gas phase which is removed and sent to the gas
purification module, an aqueous phase which is sent to the
wastewater treatment facilities, and the hydrotreated pro-
duct liquids which are sent to the fractionation module or
product storage.
Fractionation separates the mixture of liquids into
useful products by distillation. Fractions are collected at
specified boiling point ranges. The solvent needed for
liquefaction is recycled from this point to slurry preparation.
Ill
-------
The excess solvent is sent to product storage. Overhead gas
from fractionation is sent to the gas purification module
along with the gases from the hydrotreating and gas separa-
tion modules.
Gas purification separates the feed gas into a highly
concentrated acid gas stream and a sweet gas stream. The
sweet gas has a significant heating value and may be used
on-site as fuel. Acid gases are sent to sulfur recovery
operations with acid gases from the hydrogen generation
module and wastewater treatment operations. In addition to
hydrogen sulfide, ammonia and phenols also are present in
process wastewaters. These constituents are recovered by
stripping and extraction processes, respectively.
Auxiliary facilities are needed to provide steam,
electric power, and makeup hydrogen-rich gas for the process.
They will be located in the liquefaction complex. Auxiliary
facilities are discussed in detail in Section 7.
Overall Material Balance
Table 41 is a compilation of all EDS process stream
flow rates in metric-tons per day. The stream numbers in
Table 41 correspond with the stream numbers shown in Figure
24.
Table 42 gives the proximate, ultimate, and ash analysis
of Illinois No. 6 coal. These coal characteristics were
applied to the feed coal assumed in the material balances of
the hypothetical 7,950-m3/day EDS facility described in
Figure 24 and Table 41.
Table 43 gives an overall material inventory.
112
-------
TABLE 41. MATERIAL INVENTORY-EXXON DONOR SOLVENT PROCESS*
StreaoB
description
Feed
coal
Donor
solvent
Makeup
gas
Bydrogenation
products
Overhead
gases
Light
naphtha
law liquid
product
Separator
product
Heavy liquids
and solids
Muaber**
Heavy
liquids
10
U>
Composition
Goal (2X moisture)
Donor solvent
¦2
Cl
C2
C3
C4
Light naphtha
Heavy naphtha
Kerosine
Diesel oil
Rwl oil
Heavy fuel oil
Tar residue
Char
¦2°
»2
TOTALS
Stress
description
14,385
28,199
14,385 28,199
Bottoas Bydrotreater
residue feed
28,199
28,199
28,199
34
34
34
41
131
131
46
46
27
27
18
18
292
292
1,321
1,321
2,183
2,183
2,183
2,183
2,543
2,543
2,543
1,069
1,069
1,069
277
277
277
1,787
1,787
1,787
1,339
1,339
1,339
1,351
1,351
1,351
1,817
1,817
1,817
trace
310
310
141
141
7
8
7
292
82
42,893
714
41,886
4,000
38,748
Haste
Heavy
Total feed to
Makeup
Hydrotreated
Gas to
water (2)
naphtha
hydrotreater
8«s
product
Water
purification
13
14
15
16
17
18
19
28,199
28,199
408
34
34
501
516
516
20
20
43
43
11
292
700
1,321
1,321
2,268
2,183
2,543
4,932
1,069
277
43
28,199
2,183
2,543
1,069
277
172
34,443
Feed to
f ractionation
11
Composition
Donor solvent
H2
Cl
C2
C,
<=4
Light naphtha
Heavy naphtha
Kerosine
Diesel oil
Fuel oil
Heavy fuel oil
Tar residue
Our
Ash
H20
h2s
hb3
»2
TOTALS
12
28,199
1,615
1,339
1,351
4,305
2,183
2,543
1,069
277
172
20
28,199
11
700
2,268
4,932
43
172
34,443
1,585
1,585
1,321 36,056
(continued)
0.4
909.4
91
39
39
24
36,959
91
91
24
637
36,153
-------
TABLE 41 (continued)
Stress
description
Wastewater
Number**
Gases to
purification
Light
naphtha
Heavy
naphtha
Middle
distillate
21
22
23
24
25
Heavy
fuel oil
26
Fuel
gas***
27
h •
I-1
4>
Coaposition
Donor Solvent
««2
Cl
C2
C3
C4
Light naphtha
Heavy naphtha
Kerosine
Diesel oil
Heavy fuel oil
Phenolics
BjO
HjS
HH3
TOTALS
28,199
11
700
2,268
4,932
18
18
181
39
256
11
700
2,268
33,131
43
II
74
67
326
66
71
29
559
* Calculated frem data in (40,42-44).
** Refer to Figure 24.
***Contains approximately 298 metric tons per day of combustible hydrocarbons.
All flowrates in metric tons per day based on a production rate of 7,950 v? per day.
-------
TABLE 42. ILLINOIS NO. 6 COAL ANALYSIS* (42)
Moisture
Ash
Volatile
Fixed carbon
Sulfur
Alkalies as Na20
Higher heating value,
Mega joules/kg
Proximate analysis
As received Dry
16.5
8.0 9.58
35.24 42.21
41.79 50.05
3.50 4.19
0.15 0.18
24.9 29.8
Ultimate analysis
As received
Dry
Moisture
16.50
...
Carbon
58.17
69.67
Hydrogen
4.22
5.05
Nitrogen
1.54
1.84
Chlorine
0.18
0.22
Sulfur
3.50
4.19
Ash
8.00
9.58
Oxygen
7.89
9.45
Ash Analysis - ignition basis
Phosphorous as P2®5 0.11
Silica, Si02 43.82
Ferric oxide, Fe^^ 24.69
Alumina, A1203 17.19
Titanium, Ti02 0.88
Lime, CaO 4.96
Magnesia, MgO 1.02
Sulfur trioxide, SOj 4.29
Potassium oxide, K20 1.61
Sodium oxide, Na20 1.21
Undetermined 0.22
*% by weight
115
-------
TABLE 43. OVERALL MATERIAL BALANCE - EDS PROCESS
(EXTRACTED FROM TABLE 41)
Inputs
Outputs
Metric
Metric
Material
tons/day
Material
tons/day
Coal to process
14,384.8
Hydrogen
67.0
Coal to H2
2,198.6
Fuel gases C^-C^
270.3
generation
Light naphtha
700.7
Coal to utilities
3,628.7
Heavy naphtha
2,267.8
Donor solvent
28,199.6
Middle distillate
4,932.3
Oxygen
2,571.4
Heavy fuel oil
43.0
Hydrogen
441.5
Bottoms (char, ash,
4,476.5
Process water
91.0
tar, residue)
51,515.6
Wastewater
r-*
•
00
*
Ammonia
179.6
Phenol
17.7
Hydrogen sulfide
383.6
Donor solvent
28,199.6
Miscellaneous wastes,
8,228.8
blowdowns, and sludges
51,515.6
Material and Energy Considerations
Process Material Yields--
The product yield in unit weight of products (middle
distillate plus heavy naphtha) per unit weight of coal is
0.50 using values shown in Table 43. The coal requirement
for steam and electrical power generation is estimated to be
3600 metric tons per day. If this is added to the coal used
in the process, the yield is 0.40.
116
-------
Process Thermal Efficiency--
The process thermal efficiency* is defined as:
The heating value of products (joules) nn«
The heating values of coal feed and
make-up gas (joules)
133.3 + 209.5 (TJ) 1 ftfyy — 342.8 (TJ) — f,o i"/
428.7 + 62.6 + 4.46
-------
- 100
= 614 .*3 8$ x 100 = 58%
Process heat requirements are assumed to be two percent of
the heating value of the total coal feed ® (0.02)(602.3 TJ/day)
=* 12.0 TJ/day
By comparison with the H-Coal process thermal effi-
ciency of 707o, 58% seems to be too low. However, two fac-
tors may explain this difference. First, EDS uses additional
coal for H2 generation. If it were assumed that the char
and tar could be used, this might help to increase thermal
efficiency. The other factor is the difference between the
heating values of the coal feed for the two processes.
DESCRIPTION OF THE PROCESS MODULES
To simplify discussions of process operations, the EDS
process is considered to consist of modules, each of which
performs specific functions. The primary modules of the
EDS process are:
• Slurry preparation and hydrogenation
• Gas separation
• Solids separation
• Hydrotreating
• Fractionation
These five modules, supplemented by the necessary auxil-
iary facilities to provide material and energy inputs to the
systems, represent the EDS process. Brief discussions of
118
-------
each module, relating them to the other modules as well as
the overall process, are provided.
Slurry Preparation and Hydrogenation Module
Module Description--
Figure 25 shows a flow diagram for this module. Within
the hydrogenation module, coal and hydrogen are reacted
under conditions of elevated temperature and pressure. The
hydrogenation reaction increases the overall hydrogen-
to-carbon ratio. Complex organic compounds contained in
coal are converted to simpler, lighter compounds. Many of
the new compounds are liquids at ambient temperature and
pressure.
Using a donor solvent to supply hydrogen permits effec-
tive operation at milder conditions than in processes which
use gaseous hydrogen alone or with a catalyst. The reactor
used in the EDS process operates at about 450°C and 12.4
MPa. The mild conditions permit selecting construction
materials that may result in less expensive equipment costs
compared to other liquefaction processes (40).
Feed coal at minus 2.38 mm and 2 percent moisture
content is continuously mixed with hydrogenated donor sol-
vent at a ratio of 2 parts solvent to 1 part coal by weight.
The donor solvent is a recycled process product in the
middle distillate boiling range of 200 to 230°C IBP and
consists of a complex mixture of aromatic hydrocarbons. The
coal/donor solvent slurry is injected with hydrogen to
improve the flow characteristics of the mixture and improve
the yield efficiency of the liquefaction module.
The slurry is preheated before proceeding to the lique-
faction reactor. Studies are currently in progress to
119
-------
DRIED COAL
MINUS 8 MESH
2% MOISTURE
REACTOR EFFLUENT
TO GAS PHASE
SEPARATION
MODULE
FEED
COAL
STORAGE
(C
CL
z:
rj- ¦-
o
£
u_ o
UJ (—
=> CJ
a<
t—i LU
_j a:
RECYCLED DONOR
SOLVENT
SLURRY:
2 PARTS SOLVENT^
1 PART COAL BY
WEIGHT
HYDROGEN-RICH GAS .
SLURRY
PREPARATION
FLUE GAS
SLURRY
PREHEATER
COAL-SOLVENT-Hr
SLURRY 1
A
HEATED SLURRY
FUEL
Figure 25. EDS process flow diagram - slurry preparation
and hydrogenation module (40)
120
-------
determine the relative merits of preheating the hydrogen and
slurry separately versus preheating the combined hydrogen-
slurry mixture. Following preheating, the hydrogen-slurry
mixture is fed into the liquefaction reactor.
The configuration of the liquefaction reactor is pro-
prietary, and little information about it has been published.
It is thought to be a tubular reactor design. The use of a
hydrogen donor solvent in the liquefaction reactor in place
of molecular hydrogen is the primary difference between the
EDS process and the other liquefaction processes. The donor
solvent materials are well known and comprise aromatic
hydrocarbons which are partially hydrogenated, generally
having one or more of the nuclei at least partially satu-
rated. Several examples of such materials are tetralin,
dihydronaphthalene, dihydroalkylnaphthalenes, dihydrophen-
anthrene, dihydroanthracene, dihydrochrysenes, tetrahydro-
pyrenes, tetrahydrochrysenes, tetrahydrofluoranthene, and
other hydrogenated polynuclears. Of particular value are
the hydrophenanthenes and hydroanthracenes. These materials
are obtained directly from distillation of the process
stream.
In donor solvent hydrogenation, the donor molecule
transfers hydrogen atoms to a coal fragment. Figure 26, using
tetralin as an example, illustrates what happens to the
donor and a hypothetical coal fragment. The spent donor
solvent (in this case, naphthalene) travels through the
process as a component of the product stream. When the
product stream undergoes hydrotreating (a second hydrogen-
ation to upgrade the product), the spent solvent is regen-
erated. The fraction of the product stream containing most
of the regenerated donor solvent is distilled off and
recycled to the reaction.
121
-------
H
CO
LIQUEFACTION
4 4H
H
TETRALIN
(Donor Molecule)
SOLVENT HYDROGENATIO
NAPHTHALENE
(Spent Solvent)
+ OONOR H
LIQUEFACTION
(Hypothetical Coal Fragment)
LIQUID PRODUCT
Figure 26. Tetralin as hydrogen donor (42)
Further design work is in progress on the liquefaction
reactor. A two-stage liquefaction process is being investi-
gated, Two-stage liquefaction is a process in which bottoms
(residue) from the coal liquefaction reactor are charged
with fresh solvent and hydrogen to a second liquefaction
reactor. Bench-scale studies and preliminary RCLU work
indicate that this technique will increase liquefaction
yields. This increased conversion is greater than would be
expected from the additional residence time of the residue
in the first-stage reactor. The reactor products leaving
the first-stage liquefaction reactor are stripped with
hydrogen at 204®C to separate 80 to 90 percent of the spent
donor solvent and coal liquids from the residue. The resi-
due with fresh solvent and hydrogen passes to the second-
stage liquefaction reactor for further processing.
Process and Waste Streams--
In addition to the hydrogenation reactor, other hard-
ware being developed by Exxon for the EDS process is pro-
prietary. Detailed drawings for the purpose of illustration
122
-------
are not available. Figure 27 shows the process and waste
streams for the module. Where possible, process stream
flow rates are quantified in Table 45.
0 0
0
0
0
EDS SLURRY
PREPARATION &
HYDROGENATION
MODULE
STREAM
1. FEED COAL
2. DONOR SOLVENT
3. HYDROGEN
4. PREHEATER FUEL
5. PREHEATER FLUE GAS
6. HYDROGENATION PRODUCTS
7. VAPOR LEAKAGE
8. TRANSIENT SPILLS
¦0
0 0
METRIC TONS PER DAY
14,385
28,199
82
NOT QUANTIFIED
NOT QUANTIFIED
42,892
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 27. EDS slurry preparation &
hydrogenation module process and waste streams
123
-------
TABLE 45. EDS SLURRY PREPARATION AND HYDROGENATION
MODULE PROCESS AND WASTE STREAMS (EXTRACTED
FROM TABLE 41)
Metric tons
Stream* per day
1. Feed coal 14,385
2. Donor solvent 28,199
3. Make-up hydrogen H2~34, C-^-41, ^-8 82
4. Reactor effluent 42,892
donor solvent-28,199; 1^-34; C^-C^-222
light naphtha-292; heavy naphtha-1,321
kerosine-2,183; diesel oil-2,543; fuel
oil-1,069
heavy fuel oil-277; tar & char-3,126;
ash-1,351
H20-l,817; H2S-310, NH3-141; N2-7
*Refer to Figure 27.
Hydrogenation in the liquefaction reactor liberates
organic sulfur, nitrogen, and oxygen by a substitution
reaction involving the fragmentation of the carbon poly-
meric structure of the coal and the replacement of sulfur,
nitrogen, and oxygen with hydrogen. The products of the
reaction consist of lower molecular weight hydrocarbons,
hydrogen sulfide, ammonia, and water.
Gas Separation Module
Module Description--
The gas phase separation module takes the raw product
of the hydrogenation module and begins the series of opera-
tions which remove undesirable components in the raw product
124
-------
and upgrade the product into a useful, saleable com-
modity.
Figure 28 depicts the flow of process streams through
the module and shows the interconnections.
The raw product from the reactor contains gaseous,
liquid, and solid components. This product stream is sep-
arated into components in the two-stage gas separation
module. The first stage operates at 250°C and 12.4 MPa.
It removes the gas phase and light naphtha as one stream.
This stream is cooled, and the light naphtha is separated out
in a flash drum. Hydrogen, fuel gases, hydrogen sulfide,
ammonia, carbon monoxide, carbon dioxide, and some water
vapor remain.
The product slurry liquids proceed from the first-stage
to the second stage hot low pressure separator, operating at
202°C and 101.3 kPa pressure. This stage removes the
naphtha (boiling point 70 to 202°C) and water from the
product slurry. The heavy naphtha and water stream are
cooled and separated in a flash drum. The crude coal
naphtha may contain up to 15 weight percent phenolic com-
pound, depending on the percent yield of heavy naphtha in
the liquefaction product.
Process and Waste Streams--
Figure 29 shows the process and waste streams for this
module. Stream constituents are quantified in Table 46.
The only continuous wastewater stream leaving this module is
that from the Stage II flash drum. It will contain traces
of H2S, NHg, phenolics, cresols and phenols, and other
hydrocarbons.
125
-------
RAW PRODUCT COOLER
RAW PRODUCT
MIXTURE FROM
REACTOR
n rrwuv^i v
RAW PRODUCT GAS
& LIGHT NAPHTHA
RAW PRODUCT
GAS TO ACID
GAS REMOVAL
PROCESS
STAGE I
HOT HIGH PRESSURE SEP,
250°C 12.5 MPa
PRODUCT SLURRY
LIQUIDS
, STAGE II
I HOT LOW PRESSURE SEP.
V 202°C 101 kPa
RAW LIQUID
PRODUCT,
MINERAL MATTER
AND CHAR
—
GAS/LIGHT
NAPHTHA
COOLER
HEAVY NAPHTHA
COOLER
——
HEAVY NAPHTHA
AND WATER
Y
HEAVY NAPHTHA
TO HYDROTREATING
LIGHT
NAPHTHA
w
TO WASTE
WATER
TREATMENT
Figure 28. EDS process flow diagram - gas separation module (40)
-------
©©©©
©•
EDS GAS
SEPARATION
MODULE
© 0
STREAM
1. HYDROGENATION PRODUCTS
2. ACID GAS TO GAS CLEANING
3. LIGHT NAPHTHA TO HYDRO-
TREATING
4. HEAVY NAPHTHA TO HYDRO-
TREATING
5. WASTEWATER
6. SOLIDS-LIQUID TO
SEPARATION
7. VAPOR LEAKAGE
8. TRANSIENT SPILLS
METRIC TONS PER DAY
42,653
714
292
1,321
1,585
34,444
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 29. EDS gas separation module process
and waste streams
127
-------
TABLE 46, EDS GAS SEPARATION MODULE
PROCESS AND WASTE STREAMS (EXTRACTED FROM TABLE 41)
Stream*
Metric tons
per day
1.
Hydrogenation products
42,653
2.
Acid gas
H0-34, C,-C.-222, H S-310, NH.-141,
Nz_? i 2 -5
714
3.
Light naphtha
292
4.
Heavy naphtha
1,321
5.
Wastewater
1,585
6.
Process stream to solids-liquid
separation module
34,445
donor solvent-28,193; kerosine-2,183;
diesel fuel-2,543; fuel oil-1,069;
heavy fuel oil-277; tar residue-180
81,010
*Refer to Figure 29.
There are no continuous gas emissions to the atmosphere
from this module. All off gases are sent to acid gas
removal. Vapor leakage and spills are two potential inter-
mittent emission sources.
Solids Separation Module
Module Description--
The solids phase separation module removes suspended
solids materials such as unreacted coal, mineral matter, and
char. The resulting raw liquid product is suitable feed for
the hydrotreating module. Figure 30 depicts the flow of
process streams through the module and shows the intercon-
nections. In the EDS process, solids separation is performed
128
-------
TO HYDRO-
TREATING
MODULE
SEPARATOR
VACUUM
DISTILLATION
UNIT
FLUE GAS
/PRI
PREHEATER
HEAVY LIQUIDS
AND SOLIDS
EFFLUENT
FROM STAGE II
OF GAS SEPARATION
MODULE
370°C
3.3kPa
/
FUEL
MINUS
A
540°C
B.P. « ,
HYDRO-
CARBONS
PLUS 540°C B.P.
HYDROCARBONS
BOTTOMS TO FLEXICOKING AND HYDROGEN GENERATION
Figure 30. EDS process flow diagram - solids
separation module (40)
129
-------
by a vacuum distillation unit. The liquid from the low
pressure flash separator passes through a preheater and into
the vacuum still. The still operates at 370°C in the flash
zone. Operating pressure is low: 3.3 kPa. Hydrocarbons
with boiling points below 540°C are volatilized and sent to
a separator, leaving bottoms product consisting of the
suspended solids, and a residue of hydrocarbons with boiling
points greater than 540°C.
Some hydrocarbons with boiling points greater than
540°C do exit the vacuum still. The separator collects
them, and they are combined with the vacuum still bottoms.
Lighter hydrocarbon liquids pass from the separator to the
hydrotreating module.
The gas-liquid phase from vacuum distillation is
returned to atmospheric pressure and the heavy oils are sepa-
rated by flashing at 370°C. Depending on product needs, the
heavy oils can be sent to storage, recycled for further
processing, or combined with the overhead flash stream and
sent to solvent hydrotreating. The overhead flash stream
with or without recombined heavy oils is mixed with both the
light naphtha fraction from the first-stage phase separator
and the heavy naphtha from the second-stage separator. The
combined product streams are preheated to 380°C and sent to
solvent hydrotreating. It should be noted that the spent
donor solvent is present in the product stream from the
solids separation module.
Process and Waste Streams--
A diagram of the solids separation module with all
input and output streams is shown in Figure 31. Stream
constituents are quantified in Table 47. The waste streams
are flue gas and solids residue or bottoms from the vacuum
distillation unit.
130
-------
0 0
0
EDS SOLIDS
SEPARATION
MODULE
-------
TABLE 47. EDS SOLIDS SEPARATION MODULE PROCESS
AND WASTE STREAMS (EXTRACTED FROM TABLE 41)
Stream* Metric tons per day
1. Heavy liquids-solids 38,748
4. Solids residue
Tar residue 1,615
Char 1,339
Ash 1,351 4,305
5. Products to hydrotreating
Donor solvent 28,199
Kerosine 2,183
Diesel oil 2,543
Fuel Oil 1,069
Heavy fuel oil 277
Tar residue 172 34,443.0
*Refer to Figure 31
The bottoms product has some energy content, recover-
able by methods including gasification and pyrolysis. Exxon
is currently developing a proprietary process to recover
energy from the bottoms product of the vacuum still. This
process is called flexicoking.
Although used commercially in the petroleum industry,
flexicoking is still in the design and development stage for
use on coal liquefaction bottoms products. However, esti-
mates indicate a maximum yield of liquid and gas products of
40 weight percent of bottoms, exclusive of the inorganic ash
component. In this report the remaining coke, containing an
estimated 40 to 50 weight percent ash, is mixed with coal
and used for hydrogen generation. Hydrogen is generated by
simultaneously mixing carbon monoxide with oxygen and
shifting carbon monoxide and steam to carbon dioxide and
132
-------
hydrogen as illustrated below.
(1) 2C + 02
(2) CO + H20
~ 2 CO
- H2 + C02
Hydrotreating Module
Module Description--
In the hydrotreating module, liquid hydrocarbons react
with hydrogen at elevated temperatures and pressures. Some
of the nitrogen, oxygen, and sulfur in the liquid fuels are
converted to ammonia, water, and hydrogen sulfide, respec-
tively. In the case of the EDS process, hydrotreating has
an additional function. The donor solvent, which provides
hydrogen for reaction with coal, is resaturated with hydro-
gen and recycled to the hydrogenation module.
A flow diagram of the hydrotreating module is shown in
Figure 32. Liquid hydrocarbons pass through a preheater to
an initial catalyst guard reactor. The guard reactor
permits deposition of coke, which can cause plugging prob-
lems in the main hydrotreating reactor. Hydrogen is injec-
ted along the length of both reactors for temperature
control. The two reactors commonly operate at 380°C and
12.5 MPa.
The final choice of catalyst has not been made. How-
ever, commercially available hydrogenation catalysts have
been tested by Exxon in three bench-scale hydrogenation
units over a range of temperatures, pressures, space velo-
cities, and hydrogen treater rates. Partially hydrogenated
creosote oil at 200 to 370°C simulates the spent solvent in
the EDS process.
133
-------
FRESH
CATALYST
FRESH
FLUE GAS
PREHEATER
LIQUID
HYDRO-
A
CARBONS
FUEL
COMBINED
HYDROTREATOR
FEED FROM
SEPARATIONS
MODULES
HYDROGEN
RICH GAS
380°C
12.5 MPa
CATALYST
GUARD
REACTOR
! \
LYST
K il
380 C
12.5 MPa
SPENT
CATALYST
HYDRO-
TREATING
REACTORS
SPENT
CATALYST
Co/Mo
CATALYS1
WATER
GAS TO
ACID GAS
REMOVAL
LIQUID
PRODUCTS
TO FRACTION-
ATION MODULE
Figure 32.
TO WASTEWATER
TREATMENT
EDS process flow diagram
module (40)
- hydrotreating
134
-------
Current data indicate that the nickel/molybdenum (NiMo)
catalysts possess about twice the hydrogenation activity of
the cobalt/molybdenum (Co/Mo) catalysts. In addition, the
hydrogenation activity of Co/Mo catalysts is significantly
increased by the addition of sulfur (about 0.5 weight per-
cent H2S of liquid feed) to the feedstock. For the bench-
scale runs, carbon disulfide or butanethiol is added to the
hydrogenated feedstock at the start of each process run to
produce hydrogen-sulfide gas which converts the metal
catalyst from the oxide to the more active sulfide form.
Removal of this sulfur "spike" resulted in higher desul-
furization activity, although the denitrogenation, deoxygen-
ation, and hydrogenation activities were significantly
reduced. Addition of the sulfur "spike" restored the lost
activities. The above effects were also observed to a
lesser degree with the Ni/Mo catalyst.
These findings suggest that recycling some hydrogen
sulfide with the hydrogen-rich gas to the EDS process sol-
vent hydrotreater will increase catalyst activity and thus
reduce the required hydrotreater size and cost. Studies are
currently underway to test the effects of recycling on
hydrogen donor solvent under operational conditions. Addi-
tional data will be required to establish the effects of
higher levels of carbon dioxide and ammonia in the hydro-
treater reactor on the catalyst activity and life.
Process and Waste Streams--
Figure 33 shows the process and waste streams for the
hydrotreating module. The streams are quantified in Table
48. Light hydrocarbons, hydrogen sulfide and, possibly,
ammonia are formed in the hydrotreating module. Preheater
flue gas is another waste stream of the hvdrotreating
module. The hydrotreater effluent is sent to a phase sepa-
ration vessel, such as an oil-water separator. Three phases
135
-------
© 0 @
G>
0-
EDS
HYDROTREATING
MODULE
STREAM
METRIC TONS PER DAY
1. COMBINED HYDROTREATER
FEED FROM SEPARATIONS
MODULES
2. MAKEUP HYDROGEN-RICH GAS
TO HYDROTREATERS
3. WATER TO HYDROTREATER
PRODUCTS SEPARATOR
4. GAS TO GAS CLEANING
5. WASTEWATER
6. LIQUID PRODUCTS TO FRAC-
TIONATION
7. FUEL TO PREHEATER
8. PREHEATER FLUE GAS
9. FRESH CATALYST
10. SPENT CATALYST
11. VAPOR LEAKAGE
12. TRANSIENT SPILLS
35,765
933
91
710
220
36,148
NOT QUANTIFIED
NOT QUANTIFIED
NOT QUANTIFIED
NOT QUANTIFIED
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 33. EDS hydrotreating module process
and waste streams
136
-------
exit the separator. The first phase is noncondensible gases
which are sent to the gas cleaning module. The second phase
is wastewater removed from the bottom of the separator.
This water contains some dissolved organics and ammonia.
The third phase consists of hydrocarbon liquids removed from
the oil-water separator above the water-organic phase boun-
dary. The hydrocarbons are pumped to the preheater of the
fractionation module. A spent catalyst waste stream will be
generated periodically.
It should be noted that process research, development,
and design work is not yet in the final stage. Catalyst
studies are being performed to determine which catalyst type
is best. After phase separation, part of either the liquid
or gaseous effluent (or both) may be recycled to the hydro-
treating module. Additional study is required to determine
the optimum processing scheme for the hydrotreating module.
Fractionation Module
Module Description--
The fractionation module refines raw synthetic oil
from hydrotreating into fractions of specified boiling ranges,
just as natural crude petroleum is fractioned in existing
refinery operations. Figure 34 is a flow diagram for the
fractionation module.
Process and Waste Streams--
A diagram of the module with all input and output
streams is shown in Figure 35. The hydrotreated syncrude is
preheated and fed to a distillation column. The fractiona-
tion process should yield the following products: overhead
gases (C^ to C^), light and heavy naphthas, a middle oil
(which includes the donor solvent), and a heavy fuel oil.
Part of the middle oil stream is returned to the process for
137
-------
FUEL GAS
TO ACID
GAS REMOVAL
DISTILLATION
COLUMN
LIGHT NAPHTHA
TO PRODUCT
STORAGE
HEAVY NAPHTHA
- TO PRODUCT
STORAGE
FLUE GAS
PREHEATER
FEED FROM
HYDRO-
TREATING
MODULE
A
FUEL
MIDDLE OIL
TO PRODUCT
STORAGE
DONOR SOLVENT
TO SLURRY
PREPARATION
HEAVY FUEL
OIL TO
PRODUCT
STORAGE
Figure 34. EDS process flow diagram - fractionation
module (40)
138
-------
1
2
3
4
5
6
7
8
9
10
0 0 0
0
EDS
FRACTIONATION
MODULE
STREAM
© 0 ®
FEED FROM HYDROTREATING
MODULE
PREHEATER FUEL
PREHEATER FLUE GAS
FUEL GAS
LIGHT NAPHTHA
HEAVY NAPHTHA
MIDDLE OIL
HEAVY FUEL OIL
VAPOR LEAKAGE
TRANSIENT SPILLS
METRIC TONS PER DAY
36,148
NOT QUANTIFIED
NOT QUANTIFIED
11
655
2,268
32,219
43
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 35. EDS fractionation module process
and waste streams
139
-------
TABLE 48. EDS HYDROTREATING MODULE PROCESS AND
WASTE STREAMS (EXTRACTED FROM TABLE 41)
Metric tons
Stream* per day
1. Combined hydrotreater feed 35,765
from phase separations
modules
2. Makeup hydrogen-rich gas to 933
hydrotreaters
3. Water to hydrotreater pro- 91
ducts separator
4. Gas to gas cleaning module 710
5. Wastewater 220
6. Liquid products to frac- 36,148
tionation module
donor solvent 28,194
C4 u
light naphtha 655
heavy naphtha 2,268
diesel oil 4,932
heavy fuel oil 43
*Refer to Figure 33.
hydrogenation. The light hydrocarbon overhead stream is
sent to the acid gas removal module. Other fractions are
sent to product storage. These streams are quantified in
Table 49. Product characteristics are summarized in Table
50. Preheater flue gas is the only waste stream generated
during normal system operations. However, abnormal wastes,
such as leaks and spills can be serious, especially during
140
-------
TABLE 49. EDS FRACTIONATION MODULE PROCESS AND
WASTE STREAMS (EXTRACTED FROM TABLE 41)
Metric tons
Stream* per day
1. Feed from hydrotreating module 36,148
4. Gas to gas purification module 11
5. Light naphtha to product 655
storage
6. Heavy naphtha to product 2,268
storage
7. Middle oil (approximately 85% 32,219
recycled to hydrogenation
module as donor solvent; re-
mainder to product storage)
8. Heavy fuel oil to product 43
storage
*Refer to Figure 35.
141
-------
TABLE 50. EDS PRODUCT ANALYSES (42)
Heavy Naphtha*
Fuel Oil
Raw
Hydrotreated
Raw
Hydrotreated
Liquid
Liquid
Liquid
Liquid
Nominal Boiling Range, °C
Distillation, 15 to 5°C:
10 wt. %
50 wt. %
90 wt. %
Density, g/cu. cm
Elemental Analysis, wt. %
C
H
0
N
S
Higher Heating Value,
Mega joules/kg
70/200 70/200 200/540 200/540
106 92 247 239
180 157 368 . 347
199 182 433 412
0.87 0.80 1.08 1.01
85.60 86.80 89.40 90.80
10.90 12.90 7.70 8.60
2.82 0.23 1.83 0.32
0.21 0.06 0.66 0.24
0.47 0.005 0.41 0.04
42.6 44.9 39.8 42.1
*Excludes Cq/70°C Naphtha Cut
-------
startup and shutdown and during periods of maintenance. At
such times all fugitive materials, including products, can be
considered environmentally significant wastes.
Acid Gas Removal Module
Module Description--
This module separates acid gases (l^S and CC^) from
noncondensible hydrocarbons. The resulting sweet gas is
acceptable as fuel gas. The acid gas stream is a suitable
feed for sulfur recovery operations. The diethanolamine
(DEA) acid gas removal process has been selected for appli-
cation to the EDS process in this study. A flow schematic
of the DEA process is shown in Figure 36. Gas is fed to the
absorber. The DEA solution absorbs hydrogen sulfide and
carbon dioxide. Sweetened gas exits the top of the absorber.
The DEA solution is passed to a regenerator which causes
release of the acid gases from the solution. Regenerated
DEA is returned to the absorber. The DEA process is capable
of reducing the hydrogen sulfide content of the sweetened
gas to a few ppm by volume. A block diagram of the acid
gas removal module showing module input and output streams
is shown in Figure 37.
Process and Waste Streams
DEA solution blowdown is the major process waste
stream. Acid gases are sent to primary sulfur recovery
operations. Process and waste streams are quantified in
Table 51.
143
-------
DIETHANOLAMINE (DEA) SYSTEM
Figure 36. EDS process flow diagram - acid gas removal process (40)
-------
0-
G>
STREAM
EDS ACID
GAS REMOVAL
©
1. RAW GAS
2. MAKE-UP DEA SOLUTION
3. DEA SOLUTION BLOWDOWN
4. ACID GAS TO SULFUR
RECOVERY
5. FUEL GAS TO STORAGE
6. VAPOR LEAKAGE
7. TRANSIENT SPILLS
-©
-------
TABLE 51. EDS ACID GAS REMOVAL PROCESS AND
WASTE STREAMS (EXTRACTED FROM TABLE 41)
Stream*
Metric tons
per day
1.
Acid gas streams from gas separation,
hydrotreating and fractionation
modules
1,437
2.
Makeup DEA solution
3.
DEA solution blowdown
4.
Acid gas to sulfur recovery**
847
5.
Fuel gas to storage
590
*Refer to Figure 37
**Does not include acid gas treated in hydrogen generation
module.
146
-------
SECTION 6
COMMON OPERATIONS AND PROCESSES
INTRODUCTION
Many of the operations and processes for coal lique-
faction are common to all of the three systems covered in
this report. These common elements include:
• Coal preparation
• Hydrogen generation
• Oxygen generation
• Steam and power generation
• Cooling towers
• Raw water treatment
• Product and by-product storage
All of the abovementioned, with the exception of hydrogen
generation, are given a general treatment in this discussion
since only scale-up or scale-down is required for them to be
directly applicable to each liquefaction process; however,
hydrogen generation, warrants more detailed discussion since
it uses liquefaction residues as a raw material; and the
carbon, hydrogen, and ash content of these residues varies
with each process.
Even though the common operations and processes are
presented as separate entities, some of them can be considered
147
-------
part of the liquefaction operations and probably will be
when large-scale plants are built. This is particularly
true of hydrogen generation, where it is almost certain that
no single hydrogen generation process will be used for all
liquefaction systems. Each liquefaction system will most
likely develop its own method of hydrogen generation based
on individual needs and variables.
COAL PREPARATION
Coal preparation is an established, reliable technology
that is in full-scale commercial use in coal-fired power
plants. Minor modifications in the module may be made in
order to meet the feed requirements of various coal lique-
faction processes (e.g., the maximum mesh size below which
the coal is pulverized or the maximum moisture content of
the coal). Major simplification of the module occurs if a
specific liquefaction process does not require coal cleaning
with water and can utilize dry processing. However, the
more extensive water cleaning procedures are detailed in the
following material balances. Major coal liquefaction proc-
ess waste reductions also occur if the initial coal cleaning
takes place outside the plant or at the mine.
The major objectives of coal preparation in a process
plant are: 1) sizing coal to meet specific particle size
limitations, and 2) drying coal to the specified moisture
content. In its basic form, coal preparation includes dry
processes, water processes, and dense media processes.
Presently, these coal preparation processes rely almost en-
tirely on the difference in the specific gravity between
mineral materials and coal as the basic principle by which
coal is separated from refuse. One exception is the com-
monly used Bradford Breaker. This unit relies on the
148
-------
difference in hardness between rock and coal for its opera-
tion. The hard rock does not tend to break and is dis-
charged through the end of the breaker drum and discarded
(45) .
The more general case, which also includes separation
of refuse material and heavy media beneficiation, is des-
cribed in this section. Dense medium separations include
coal preparation processes which clean raw coal by immers-
ing it in a fluid having a density between those of clean
coal and reject. As there is a general correlation between
ash content and specific gravity, it is possible to achieve
the required degree of removal of ash-forming impurities from
a raw coal by regulating the specific gravity of the separ-
ating fluid. Such processes are utilized when the most
rigorous degree of coal beneficiation is desired and can be
justified economically. In general, the feed requirements
for the coal liquefaction processes do not necessitate the
elaborate and expensive dense media coal preparation (45).
The coal preparation module shown in Figure 38 and
detailed in this report utilizes water as the primary clean-
ing medium, in conjunction with a jig-hydrocyclone circuit.
Approximately 60 to 70 percent of the pyritic sulfur can be
removed during this kind of processing (46). The resulting
reduction in mineral and sulfur content is lower than that
achieved by heavy media cleaning, but is greater than that
resulting from dry methods of sizing and cleaning.
When the liquefaction process does not require signifi-
cant reduction in ash or sulfur content of the feed coal,
dry processing the coal is an alternative to be, considered.
Table 52 lists some of the general advantages and disadvan-
tages of utilizing water in coal preparation in comparison
to dry processes.
149
-------
R0I1 COAL
Lrt
O
TO TAILING
POND
Figure 38. Process schematic - coal preparation module (47)
-------
TABLE 52. COMPARISON OF DRY VERSUS WET
COAL CLEANING PROCESSES (45)
Wet processing
Dry processing
Ash remaining in coal 7%
15%
Slight reduction
less
Pyritic sulfur
Loss of carbon (heat)
reduced 60-70%
greater
Loss of mineral content greater
less
Thermal energy required
for drying
Dust particulates
Water effluents
greater
greater
less
greater
less
less
Process Description
Figure 38 presents a schematic flow diagram of coal
preparation facilities. Only the major pieces of equipment
are shown. The module receives run-of-mine (ROM) coal and
processes it into a feed size suitable for slurry preparation
(approximately minus 841y ). The module can be divided into
a number of process steps, i.e., receiving, reclaiming,
and rotary breaking; storage, crushing, drying and pulverizing,
and slurry mixing. Each step is discussed under separate
subheadings. Quantities given under the subheadings are for
a 7,950 m /day coal liquefaction plant.
Coal Receiving--
ROM coal is dumped from railroad cars into a hopper
below rail level. ROM coal can also be received from mine
trucks. A vibratory feed 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
151
-------
the length of a belt, forming a stockpile on one or both
sides of the belt. The stockpile will hold 86,000 metric
tons of ROM coal, while the stockpiling system will handle
up to 1,200 metric tons of ROM coal per hour. This stock-
pile does not represent total storage capacity, since minus
7.6 cm coal (after reclaiming and crushing) is also stored.
Reclaiming and Rotary Breaking--
Reclaiming coal from the ROM stockpile is accomplished
by a bucketwheel system feeding a transverse conveyor to one
or two belt conveyors. A transverse conveyor takes the coal
from either of the conveyors and delivers it to a 300-ton
capacity receiving hopper. The reclaiming system will
handle up to 1,200 metric tons of coal per hour. Coal is
discharged to a 150 cm reciprocating plate feeder onto a 120
cm belt-driven conveyor, fitted with a magnet to remove
tramp iron. The coal is conveyed to a 7.6 cm scalping
screen, which separates out oversize coal (plus 7.6 cm) and
allows broken coal (minus 7.6 cm) 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. The broken coal is placed on a 120
cm belt conveyor, where it is combined with the undersize
coal from the scalping screens and discharged to a 9,100
metric ton storage pile (45,47).
Storage Pile--
Two storage piles are incorporated into the coal
preparation module: the ROM stockpile and the broken coal
working storage of about 95,000 metric tons of coal. The
ROM stockpile represents 30 to 45 days' supply; and, pos-
sibly, up to 120 days' supply will be maintained for insur-
ance against interruptions such as labor negotiations. A
polymer coating may be applied to the stockpile to minimize
oxidation.
152
-------
Most rainfall coming in contact with such a coating will run
off, while only a small percentage will infiltrate. The
working storage represents about 2 to 3 days of live storage.
Drying and Pulverizing--
Coal is withdrawn from the minus 7.6 cm ground coal
storage pile and conveyed to the washing plant, where a
series of jigs, screens, centrifuges, cyclones, and roll
crushers clean the coal and reduce it to minus 3.2 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 3.2 cm inch coal
is then dried in a flow dryer and reduced in pulverizers.
The pulverized coal is suitable for slurry feed mixing.
The size to which the coal is pulverized and the maximum
recommended moisture content of the dried coal vary with
the liquefaction process. Table 53 shows a comparison of
such parameters for the three processes under consideration
in this report. Variation in the requirements of the process
feed coal could make alternate methods of coal preparation
more desirable. For example, the Synthoil process will
operate on ROM coal with up to 20 percent ash. Mineral
matter in the ROM coals varies with seam and mining methods.
Currently, however, most eastern coals, after preliminary
mine-mouth cleaning to remove mine debris, contain 12 to 20
percent ash. Such coals could be processed without ash
reduction and without water cleaning. Adequate coal prepara-
tion would therefore consist of rotary breaking (with removal
of rock and tramp iron), crushing and pulverizing to the
required mesh size (70 percent minus 0.074 mm), and drying
with a stream of hot combustion gas.
153
-------
TABLE 53. COMPARISON OF THE PROCESS REQUIREMENTS
FOR COAL PREPARATION (EXTRACTED FROM SECTIONS 3, 4 AND 5)
Synthoil
H-Coal
Exxon
Donor Solvent
Size of pulverized coal
70% < 74^m
100% < 250 /j,m
<841 um
<595 um
Moisture content of
dried pulverized coal
0.5%
2%
1%
Ash content of dried
pulverized coal used for
process descriptions
16.5%
9.3%
9. 5%
Maximum ash with which
process will operate
20%
not reported
not reported
Description of coal used
Western
Kentucky
Illinois
No. 6
Illinois
No. 6
Slurry Mixing--
The dried pulverized coal is transferred by conveyer to
the coal/solvent tank where it is mixed with the solvent.
The resultant slurry, with a weight ratio of approximately
1.8 metric tons of solvent per ton of coal, is then pumped
to the preheater.
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
diagrams for the three priority processes (Figures 39, 40,
and 41). The process and waste streams for the Synthoil dry
coal preparation are given in Figure 39.
154
-------
Figure 39. Synthoil process and waste streams from dry coal preparation
(see Table 53 for coal description)
-------
Figure 40. H-Coal process and waste streams from dry coal preparation
(see Table 53 for coal description)
-------
Figure 41.
Exxon Donor Solvent process and waste streams from coal preparation
(see Table 53 for coal description)
-------
Potentially, the H-Coal process also can operate with a
minimum of coal cleaning, and under certain conditions does
not require coal washing. The process and waste streams of
the dry coal preparation which meet the process requirements
of H-Coal process are shown in Figure 40.
The water processing presented in the Exxon Donor
Solvent module shown in Figure 41 represents a "worst case"
situation with regard to potential environmental effluents
from coal preparation. If water is eliminated as an integ-
ral part of the coal cleaning, the associated problem of
controlling the aqueous effluents is substantially reduced.
With dry processing, however, particulate discharge to the
environment would be elevated in importance and would
require extensive controls.
Waste streams that have been numbered in the block flow
diagrams (Figures 39, 40, and 41).
Dust from coal receiving, storage, reclaiming, and
crushing--Coal dust is generated during transfer of
coal from shipping to receiving bins, and during storage
(wind action), conveying, stacking, reclaiming, and crushing
operations. Dust is composed of coal particles, typically
from 1 to 100 microns, with composition similar to that of
the parent coal. Proximate and ultimate analyses of a
typical Illinois No. 6 seam coal can be found in Table 54,
while an ash analysis is presented in Table 55. A trace
element analysis for Illinois No. 6 coal is given in Table
56. Dust generated from the operations above has been
estimated at approximately 22 metric tons per day for a
18,200-metric ton per day plant (47).
158
-------
TABLE 54. RUN-OF-MINE (ROM) ILLINOIS NO. 6
COAL ANALYSIS (47)
Proximate analysis (weight percent):
Moisture
2.70
Ash
7.13
Volatile matter
38.47
Fixed carbon
51.70
Heating value
29.8 MJ/kg
Ultimate analysis (weight percent):
Carbon
70.75
Hydrogen
4.69
Nitrogen
1.07
Sulfur
3.38
Oxygen
10.28
TABLE 55. AVERAGE ASH ANALYSIS OF
ILLINOIS NO. 6 COAL (46)
Component
Percent of ash
Si02
44.4
A1203
21.0
FeoOo
22.1
Ti02
1.1
P205
0.1
CaO
5.2
MgO
1.0
Na£0
0.5
KoO
2.0
s63
1.7
Coal pile runoff--Coal pile runoff is generated from
rainfall and the infiltration waters that come into contact
with the stored coal. The resulting leachate may contain
oxidation products of metallic sulfides and is frequently
acidic, with relatively high concentrations of suspended
and dissolved 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
159
-------
TABLE 56. TYPICAL TRACE ELEMENT COMPOSITION *
OF ILLINOIS NO. 6 COAL (48)
Number of
Geometric
Unbiased
Nuiiber of
individual
Arithmetic
standard
"less than"
Name
Synbol
analyses
mean
mean
deviation
Ranae
values
Aluminum
A1
44
13,500.0
13,200.0
3,070.0
10,000-30,400
Antimony
Sb
44
0.98
0.67
1.03
0.20-4.9
Arsenic
As
44
5.9
4.1
6.9
1.0-32.0
Barium
Ba
29
111.0
78.0
135.0
5.0-750.0
Beryllium
Be
44
1.5
1.4
0.69
0.70-3.9
Boron
B
35
135.0
126.0
48
34-230
Bromine
Br
44
15.0
13.0
7.9
l.S-52.6
Cadmium
Cd
25
4.0
0.69
13.3
0.50-65.0
Calcium
Ca
44
7.690.0
6.480.0
5,000.0
2.100-26,700
Ceriun
Ce
29
13.0
12.0
5.8
4.4-27.0
Cesium
Cs
29
1.2
1.1
0.60
0.60-3.6
Chlorine
CI
44
1,600.0
900.0
1.600.0
100-5,400.0
Chromium
Cr
44
20.0
18.0
10.0
7-60
Cobalt
Co
44
6.6
5.9
3.1
2.5-15
Copper
Cu
44
13.0
13.0
4.0
6.0-26
Dysprosium
Py
29
1.0
1.0
CN
O
0.57-1.8
Europium
Eu
29
0.25
0.24
0.065
0.19-0.40
Fluorine
F
44
63.0
61.0
18.0
42.0-120.0
Galliun
Ga
44
3.1
3.0
0.67
1.6-4.5
Germanium
Ge
44
5.6
3.7
5.3
20-26
10
Hafnium
Hf
29
0.52
0.48
0.21
0.20-1.1
Indium
In
29
0.14
0.12
0.058
0.10-0.23
11
Iodine
I
29
1.9
1.6
1.2
1.0-5.8
8
Iron
Fs
44
18,600.0
17.600.0
5,900.0
4,500-35.000
tanthamm
la
29
7.0
6.8
2.0
4.3-12.6
2
lead
Pb
44
27.0
14.0
37.0
1.10-210.0
2
Lutetiuu
Lu
29
0.08
0.07
0.027
0.02-0.15
Mafjiesiuri
Hg
44
510.0
490.0
160.0
200-1,110
Manganese
Hi
44
53
44
34
13-180.0
Mercury
Hk
44
0.18
0.16
0.10
0.04-0.52
tfclybdenxm
Mo
44
9.2
7.3
6.0
1.0-29.0
T " ' '¦
Nickel
Ni
44
22.0
21.0
8.0
12-42.0
Phosphorous
P
44
45.0
33.0
44.0
10.0-260
5
Potassium
K
44
1,700.0
1,700.0
270.0
1200-2400
Rubidiim
Kb
29
16.0
15.0
6.7
7.0-42.0
Samariun
Sm
29
1.2
1.1
0.58
0.78-3.8
Scandiun
Sc
2.6
2.6
0.67
1.4-4.1
Selenion
Sc
44
2.2
2.0
1.2
1.2-7.7
Silicon
St
44
26,800.0
26,400.0
4,945.0
18,900-46,300
Silver
Ag
11
0.03
0.03
0.01
0.02-0.06 "
Sodium
Na
44
660.0
510.0
460.0
150-2,000
Strontiun
Sr
29
36
31
24,0
10,0-130.0
2
•. Tantalun
Ta
29
0.16
<5. IS
0.063
0.10-0.30
Thalliun
T1
24
0.67
0.59
0.32
0.12-1.3
Thorium
Th
29
2.2
2.1
0.66
1.2-3.8
Tin
Sri
16
4.7
0.94
9.0
" 0740-30
"10
Terbiun
Tb
24
0.17
0.15
0.098
0.04-0.45
Titaniun
Ti
44
700.0
640.0
170.0
500.0-1.500
Tungsten
W
29
0.70
0.55
0.52
0.04-2.1
Uraniun
U
29
1.6
1.3
1.0
0.50-4.5
2
Vanadium
V
44
33
31
9.7
17.0-55.0
Ytterbiun
... .
29
0.54
0.51
0.16
0.27-0.89
Zinc
Zn
44
420.0
120.0
990.0
13.0-5,300
Zirconium
Zr
35
52.0
46.0
28.0
16.0-120.0
*Canpoaiticma in ppm
160
-------
used; history of the pile; and the rate, duration, frequency,
and pH of precipitation. An analysis of runoff from two
coal piles is presented in Table 57.
TABLE 57. CHARACTERISTICS OF COAL PILE RUNOFF (49)
Parameter
Cone entr at ion*
Plant J Plant L
Acidity (total) as CaC03
Chemical oxygen demand
Conductance, S/cm
Dissolved solids (total)
Hardness, as CaC03
pH, unit
Suspended solids (total)
Turbidity, JTU
1,700
240
2,400
3,200
600
1.2
500
300
270
350
2,100
1,500
980
0.023
810
Aluminum 190
Arsenic 0.01 0.009
Barium 0.1
Beryllium 0.01
Cadmium 0.001 0.006
Calcium 240 350
Chromium 0.001 0.006
Copper 0.56 0.18
Iron 510 830
Lead 0.01 0.023
Magnesium 1.2 0.023
Mercury 0.0002 0.027
Nickel 1.7 0.32
Selenium 0.03 0.003
Silicon (dissolved) 91
Sodium 4.1
Sulfate 2,600
Titanium 1
Zinc 3.7 1.0
^Concentration in ppm unless otherwise indicated
Assuming a runoff coefficient (fraction of rainfall
which will run off the working storage pile rather than
permeate it) of 0.7, the daily mass flow rate of coal pile
161
-------
runoff waters (67 metric tons per day) has been calculated
based on the average annual rainfall for Illinois (1.08 m)
o
and the area of the working coal storage (32.4 km ) .
Refuse from reclaiming and rotary breaking--Refuse from
the reclaiming and crushing operations is composed chiefly
of tramp iron, slate, and coal, and was assumed for material
balance purposes to be 5 percent of ROM coal. With the
exception of tramp iron, these materials are naturally
present in the coal seam. The particle size is greater than
three inches.
Refuse from pulverizing and drying--Refuse from pulveriz-
ing and drying is generated after screening with the double-
decker refuse screen. This stream contains slate, coal,
and the water added during screening. Both aforementioned
refuse streams are stockpiled before being removed to the
mine for burial. The discarded refuse was assumed to be
13.3 percent of the ROM coal which, together with a 6.7
percent discard in the tailing pond (2:1 ratio), constitutes
a 20 percent decrease in ROM coal.
Wastewater--Wastewater is generated from a number of
unit operations, and has a combined flow of 10,940 metric
tons per day. The suspended solids loading is approximately
1,914 metric tons per day which corresponds to a concentra-
tion of 35 percent suspended solids. The wastewater is
expected to contain a substantial quantity of coal-derived
organic constituents prior to wastewater treatment.
Gland water--Gland water is generated from leaks in the
piping system. Hence, it has not been quantified. It may
contain substantial concentrations of particulate and or-
ganic matter. Gland water may be collected in sumps and
pumped to treatment.
162
-------
Gaseous emissions from drying--This waste stream carries
4,536 metric tons per day of moisture, which has been removed
from the ground coal during drying. Significant concentrations
of coal-derived organics are also expected to be present in
this stream. Particulate concentration is expected to be
low and subject to control. Flue gas from drying is composed
of carbon dioxide, water, nitrogen, and oxygen, with minor
amounts of carbon monoxide and unreacted hydrocarbons. The
composition of a typical fuel gas and the resultant flue gas
is shown in Table 58.
TABLE 58. FUEL AND FLUE GAS COMPOSITIONS FROM
THE COAL PREPARATION MODULE (47)
Flue gas to flow dryer 227 metric tonsAday
Combustion air 4,536 metric tons/day
Flue gas from flow dryer 4,763 metric tons/day
Composition by weight % of typical fuel
gas used in flow dryer
H2 7.2%
N2 0.8
CO 12.6
C02 1.0
H2S 0.1
HC 77.5
H9O 0.8
TOTAL TUWo
Composition by weight % of typical flue gas
discharged from flow dryer
N2 75.7%
H20 6.9
02 5.2
CO2 12.2
SO? 0.007
TOTAL 100%
163
-------
HYDROGEN GENERATION PROCESS
Currently developed pilot plants use natural gas to
generate hydrogen. Obviously a full-scale plant could not
afford such a luxury.
Most conceptions of full-scale plants envision the
generation of hydrogen by the gasification of the carbon-
rich residue left over from the liquefaction step. This
residue, because of its physical properties and high ash
content, may need to be mixed with coal before gasification.
Gasification processes that are suited for the production of
hydrogen from this residue or residue/coal mixture include
the BIGAS, Texaco Partial Oxidation, and the Koppers-Totzek.
The Koppers-Totzek process was selected for use in this
study for several reasons:
• Unlike the Texaco Partial Oxidation and the BIGAS
processes, the Koppers gasifier is a proven com-
mercial process (in continuous use since 1951).
More operating data are available for the Koppers
process than for any other.
• The Koppers process uses an entrained bed reactor,
and has a high throughput, which minimizes the
number of reactors that must be constructed.
• Due to the high reaction temperature, inert residues
such as chars can be gasified.
• The process is simple and relatively clean; no
tar, oils, or phenol is produced.
164
-------
This is not to say that the Koppers process will actu-
ally be used in full-scale plants, or that plans are being
made to use it for hydrogen generation. The process simply
formed a convenient basis for estimating the types of waste
products to be expected from gasifiers in general. The
scope and size of this report do not justify a detailed
comparison of the different available gasification processes.
Process Description
A flow diagram of a conceptualized Koppers-Totzek
process is shown in Figure 42. Numerous pollution control
devices are used to purify the hydrogen gas stream prior to
its distribution, including acid gas removal, which may be
a separate system from that used for removal of acid gases
from the main liquefaction process stream. The gasifier
operating conditions are 1830 to 1930°C and 101 kPa.
A mixture of hydrogen, carbon monoxide, carbon dioxide,
hydrogen sulfide, water, and other trace gases leave the
gasifier. Approximately 50 percent of the slag produced in
the gasifier is carried along with the product gas. The
remainder drops to the bottom of the gasifier where it is
water quenched. The high temperature gasifier product gas
produces steam in a waste heat boiler prior to entering a
venturi scrubber. Cooling water is introduced into the
scrubber to remove more than 99 percent of the remaining
slag from the product gas.
The scrubber slag slurry is then mixed with the slag
from the gasifier, and the resulting mixture is concentrated
in a clarifier prior to removal to a landfill. The bulk of
the water from the clarifier is recycled to the scrubbers.
Clarifier overflow is sent to the cooling tower circuits.
165
-------
The gas is then water quenched to remove impurities
such as acids, ammonia, hydrogen sulfide, carbon dioxide,
and additional entrained slag. The sour water stream is
sent to wastewater treatment.
The quench tower effluent stream is further processed
by the water gas shift. Temperatures and pressures in the
shift reactor are expected to range from 340 to 370°C and
0.96 to 9.6 MPa, tending to increase the amount of hydrogen
present in the product gas stream. Shifting is aided by a
catalyst.
A knockout drum, operating at reduced pressure after
use of the shift converter, causes water vapor and other
condensable vapors to drop out of the gas stream. An amine
scrubbing process removes both hydrogen sulfide and carbon
dioxide from the product gas stream. Should entrained
particulates still be present in the gas stream, they will
be removed by the amine scrubber and will exit in the blow-
down stream. Product gas from the MEA unit is sent to
another MEA unit to remove additional carbon dioxide, thereby
increasing the hydrogen concentration of the final product
gas. Figure 42 combines both MEA units into one symbol.
The acid gases removed from the process are sent to the
sulfur recovery unit. The CO2 removed in the MEA units is
vented to the atmosphere. The clean product gas is then
compressed and distributed.
Process and Waste Streams
Figure 43 shows overall process and waste streams.
Material inventories for these streams are given in Tables
59, 60, and 61 for the Synthoil, H-Coal, and EDS processes,
166
-------
Figure 42. Hydrogen generation using Koppers-Totzek Process (K-T brochure)
-------
1
2
3
4
5
6
7
8
9
10
11
12
13
14
CD-
CD-
4
G>
S> © © ©
HYDROGEN
GENERATION
MODULE WITH
ACID GAS REMOVAL
•CD
-CD
-CD
-CD
¦©
STREAM
RESIDUE & COAL
OXYGEN
STEAM
WATER
MEA SOLUTION
SLUDGE
SOUR WATER
BLOWDOWN
CLARIFIER OVERFLOW
ACID GAS
co2
PRODUCT GAS
VAPOR LEAKAGE
TRANSIENT SPILLS
METRIC TONS PER DAY
SYNTHOIL H-COAL EDS
6,004 4,266 4,394
3,514 3,540 2,572
4,991 6,321 3,683
1,340 873 982
1 11
3,527 1,932 2,581
1,150 1,204 841
5 5 4
235 419 172
8«432 8,932 6,246
1,001 1,049 733
1,377 1,405 1,376
NOT QUANTIFIABLE
NOT QUANTIFIABLE
Figure 43. Hydrogen generation module with acid gas
removal process and waste streams
168
-------
TABLE 59. SYNTHOIL HYDROGEN GENERATION MODULE
PROCESS AND WASTE STREAMS (EXTRACTED FROM TABLE 15)
Scream
Metric Tons Per/Day
8
9
10
11
12
Residue
Coal
Oxygen
Steam
To gasl£ler
To shift converter
Water
To gaslfier slag quench
Water scrub quench
In MEA solution
MEA solution
MEA
Polyrad
Alcohol
Sludge from clarlfier
Water
Solids
Sour water
Quench operation
Knockout drum
Solvent blowdown
Clarlfier overflow
Acid gas
H2S
C02
SOo
HCN
NO
nh3
N2
C02 from acid gas removal
Product gas
o3
N2
C02
H2S
3,002
3.002
T!m
3,514
631
4.360
4 991
1,063
273
4
0.858
0.004
0.011
U7TT73"
1,411
2.116
274
876
XTTO
4.8
235
33.3
8,347
0.21
1.99
0.008
.91
48.2
8,*31.6
1,001
603
603
34.3
136
0.536
1,376 r
169
-------
60. H-COAL HYDROGEN GENERATION MODULE PROCESS
AND WASTE STREAMS (EXTRACTED FROM TABLE 29)
Stream Metric Tone Per/Day
1 Residue 4,266
2 Oxygen 3,540
3 Steam
To gasi£ier 1,756
To shift converter 4,565
fi! 321
4 Water
To gasifier slag quench 582
Water scrub quench 287
In MEA solution 4.1
57371
5 MEA solution
MEA 0.90
Polyrad 0.004
0.012
-w-
6 Sludge from clarifier
Water 773
Solids 1.159
l! 932
7 Sour water
Quench operation 287
Knockout drum 917
1,204
8 Solvent blowdown 5.03
9 Clarifier overflow 419
10 Acid gas
H2S 139.5
CO2 8,739
S02 0.22
HCN 2.08
NO 0.008
NH3 .95
N-? 50.51
8,932.2—
11 C02 from acid gas removal 1,049
12 Product Gas
H2 631
CO 631
N2 142.9
CO2 0.5
1,405.4—
170
-------
TABLE 61. EXXON DONOR SOLVENT HYDROGEN GENERATION
MODULE PROCESS AND WASTE STREAKS (EXTRACTED FROM TABLE 41)
Scream
Metric Tons Per/Day
1
Residue and coal
Residue
Coal
2,197
2.197
4! 394
2
Oxygen
2,572
3
Steam
To gasifier
To shift converter
3,191.7
3.191.7
6,383.4
4
Water
To gasifier slag quench
Water scrub quench
In MEA solution
778.3
200.4
2.9
981.6
5
MEA Solution
MEA
Polyrad
Alcohol
0.628
0.0029
0.0079
- 0.6388
6
Sludge from clarifier
Water
Solids
1,032
1.549
2*581
7
Sour water
Quench operation
Knockout drum
200.4
640.9
841.3
8
Solvent blowdown
3.51
9
Clarifier overflow
172.0
10
Acid gas
H2S
C02
S02
HCN
NO
NH3
N2
97.5
6.110.4
0.15
1.45
0.0057
0.664
35.32
6.245.5
11
C02 from acid gas removal
733.1
12
Product gas
«2
CO
Ik
h2s
441.5
416.5
25.1
100.2
393
1>376.3
171
-------
respectively. The inventories for the Synthoil process were
based on 603 metric tons per day of product hydrogen, 631
metric tons per day for the H-Coal process, and 442 metric
tons per day for the EDS process.
The degree to which the liquefaction residues are amen-
able to gasification was a major consideration in setting
the stream compositions. The Koppers Company is currently
investigating this question, but results are not yet available.
A major problem with gasifying liquefaction residues is that
the mineral matter content of the residue may be too high to
permit satisfactory operation of the gasifier. For operating
under these conditions, a one-to-one mixture of coal and
residue has been suggested (50) .
Another problem stems from the possibility of using
pyrolysis or coking to recover oil from the Synthoil and EDS
residues. Oil recovery would significantly reduce the
carbon content of the residue while raising its ash content.
It has been assumed that the EDS and Synthoil residues will
need to be mixed with coal, while the H-Coal residue, because
of its high carbon content (70.2 percent), and relatively
low ash content (27.3 percent), can be gasified by itself.
The numbers presented were obtained by extrapolating
figures from References 47, 51, and 52. Steam and oxygen
requirements for the gasifier were calculated by performing
a carbon and hydrogen mass balance around the gasifier. The
carbon, hydrogen, and ash content of the Synthoil residue
were taken from Reference 53, which gives an analysis of the
residue after pyrolysis for 20 minutes at 305°C. Because of
the lack of any information on the EDS coking operation, the
EDS residue was assumed to have a composition similar to
that of the Synthoil residue.
172
-------
It should be noted that, for all processes, excess
residue that cannot be gasified will need to be either
disposed of by landfill or utilized for its heating value.
Table 62 presents the quantities of residue and coal used
for each process, and the quantities of residue left.
Calculations for the EDS process assume that 50 weight
percent of the tar in the residue will volatilize during the
coking operation.
TABLE 62. UTILIZATION OF LIQUEFACTION RESIDUES
Process
Residue
produced
Residue
to gasifier
Coal to
gasifier
Residue
left
Reference
Synthoil
175
3002
3002
173
Table 15
H-Coal
5710
4226
0
1421
Table 29
Exxon Donor
Solvent
4305
2197
2197
2107
Table 41
Values in metric tons per day
Several water and gaseous waste streams are discharged
during the process. They are as follows:
• Sour water streams are discharged continuously
from the knockout drum and quench tower. These
streams may contain ammonia and oils, with the
quench tower waste containing higher quantities.
Both of these streams are directed to treatment.
• Hydrogen sulfide and carbon dioxide are discharged
from an acid gas removal unit to the Stretford
process. Other impurities such as sulfur dioxide,
173
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hydrogen cyanide, nitrous oxides, and ammonia are
also discharged along with the hydrogen sulfide
and carbon dioxide. The MEA solvent blowdown from
this operation either may be distilled to recover
chemicals, or it may be disposed of by incinera-
tion.
• 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.
Water is recirculated from the clarifier to the
venturi scrubbers, while excess clarifier overflow
is returned to the cooling tower circuit.
• Other discharges from the hydrogen production area
include hydrocarbon vapor leakage and spills in
the vicinity of the quench tower.
OXYGEN GENERATION PROCESS
Process Description
Hydrogen production in all three liquefaction processes
requires 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 oxygen at the conditions required. Figure 44
depicts a commercial air separation system (54).
174
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NITROGEN
Figure 44. Oxygen generation facilities (American Air Linde, Inc.) (54)
-------
The entering air is filtered, compressed, and scrubbed
with MEA to rfemove CC^ and dust. The purified air is cooled
by heat exchange with the outgoing gaseous products (oxygen,
nitrogen, and waste gas). Most of the air stream is then
expanded causing the temperature to drop nearly to the dew
point of the gas (-170°C). The cooled gas enters the com-
bined liquefier-distillation chamber where the temperature
is lowered to about -193°C and the liquid oxygen and nitro-
gen are separated. The products are returned to the heat
exchanger. Most of the nitrogen is discharged as a waste
product along with carbon dioxide, argon, xenon, radon,
krypton, and water vapor. The purified oxygen is compressed,
cooled, and forwarded to the gasifiers (54).
Process and Waste Streams
Only one waste stream, primarily containing nitrogen,
is discharged from the oxygen production process. This
stream is of the following composition:
Component Weight percent
98.0
1.3
0.065
0.013
0.065
0.54
This waste gas will be discharged at a rate of about 3.2
metric tons per metric ton of oxygen produced. The average
oxygen demand of the three liquefaction processes is 3,334
metric tons per day.
Nitrogen
Argon
Carbon dioxide
Hydrogen
Neon, xenon, krypton
Water
176
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STEAM AND POWER GENERATION PROCESSES
Process Description
Large quantities of steam and electricity are required
by the liquefaction processes. Electric power may be gen-
erated on site but, more likely, will be purchased. Steam
will almost always be produced on-site. In the following
discussion, it has been assumed that both steam and elec-
tricity will be produced at the site of the liquefaction
plant.
Low pressure steam may be produced indirectly in waste
heat boilers located throughout the plants. This reduces
the volume of steam which must be produced and provides a
means of cooling hot effluents from various unit operations.
Although much of the low pressure steam requirements may be
met in this manner, high pressure steam and some low pres-
sure steam will need to be produced by a coal-fired boiler.
Most steam produced in the plant is condensed and
recycled to the boilers in a closed circuit 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 generating facilities.
Typical steam and electrical power generation facil-
ities are shown in Figure 45. Although separate boilers
will be used for steam generation and electricity produc-
tion, the process diagrams are the same except for the
destination of the steam.
177
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FLUE GAS
Figure 45. Steam generation with coal-fired boilers (55)
178
-------
Process and Waste Streams
Since boiler water must be of high purity, raw makeup
water is demineralized prior to entering the boiler water
circuit. If needed to maintain relatively low concentrations
of dissolved solids in the circuit, a blowdown stream is
continuously discharged. This stream is directed to the
cooling tower system. Blowdown rates are as much as 33
litres per metric ton of steam generated (55). High pressure
boilers used for electricity generation will have higher
blowdown rates than boilers used for process steam. Wastes
from demineralizer regeneration range from 8 to 50 litres
per metric ton of water treated (51), which is about 3 to
17 litres per metric ton of steam produced. Each liquefaction
process requires approximately 725 metric tons of steam and
an electrical generating capacity of about 360 TJ. This is
a total requirement of about 980 metric tons of steam.
Based on this steam production rate, boiler blowdown will be
as much as 785 metric tons per day and demineralizer regenera-
tion wastes will range from 195-1180 metric tons per day.
The major waste streams from steam and electricity pro-
duction are flue gases, fly ash, and bottom ash. If feed
coal is burned to produce steam and power, these streams
will be relatively large, since all three processes use high
sulfur and ash coals. Assuming that the coal heating value
is 26 MJ/kg, 725 metric tons of steam per hour requires 2,510
metric tons of coal per day while 360 TJ of electricity
requires 980 metric tons of coal per day. Assuming a sulfur
and ash content for the dry coal of 5 percent and 10 percent
respectively, 345 metric tons per day of sulfur dioxide and
348 metric tons per day of ash will be generated. If a lime
scrubbing system is installed, an extrapolation of available
179
-------
data (56) shows that 1,180 metric tons per day of sludge
will be produced. It should be noted that in some instances
it may be more desirable to burn the liquefaction product
rather than coal. In this case, quantities of waste products
will be drastically reduced.
COOLING TOWERS
Process Description
Cooling water is an essential component of a coal
liquefaction plant in that it is continuously needed to
maintain temperatures of vessels within the plant and to
cool various process streams. Cooling towers provide a
continuous supply of water suitable for cooling. In addition
to the basic cooling tower structure, piping and other
components, water treatment facilities are essential elements
of the cooling tower system since the effective operation of
towers can only be maintained by recirculating relatively
clean water. A flow diagram of typical cooling water facili-
ties system is shown in Figure 46.
Process and Waste Streams
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 is incorporated into the process
to maintain a constant level of dissolved solids in the
recirculating cooling water stream. With sidestream treat-
ment, typical blowdown rates are 3-5 percent of the makeup
water rate. Side stream treatment facilities commonly used
are reverse osmosis, electrodialysis, or ion exchange. The
180
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Figure 46. Cooling water facilities
-------
wastewater from the treatment process is generally dis-
charged.
Raw water is added to the cooling tower influent as
makeup water. It replaces the water lost by evaporation, by
cooling tower blowdown, and through leakage. Evaporation
represents the most significant loss of cooling water in the
system.
Based on 22,680 metric tons per day of cooling tower
makeup, cooling tower blowdown will be approximately 1135
tons per day.* This waste will contain suspended solids,
dissolved solids, biocides, and other trace metals. Evap-
oration may be taken as the difference between makeup and
blowdown, or about 21,590 metric tons per day.
RAW WATER TREATMENT
Process Description
A continuous supply of water is needed in the lique-
faction process as makeup water in the cooling towers and in
boiler feedwater softening and demineralization operations.
In addition, the Synthoil and H-Coal processes inject water
for process needs. Water is also needed in the waste dis-
posal treatment facilities and for potable and fire uses.
Water usage is dependent upon the size of the plant, house-
keeping practices, process operations, and pollution control
technologies. A typical raw water treatment system is shown
in Figure 47.
^Assuming 5% makeup.
182
-------
CHEMICAL 1—|
INJECTION I 1
SYSTEM
ob
RAW WATER
IMTARE
RAW HATER
PUMP
STATION
oo
u>
SAND FILTER
EFFLUENT
PUMP
STATION
Figure 47
CLARIFIER
SAND FILTER
COOLING
TOWER
SYSTEM
SOLIDS
FILTRATE
SURGE
TANK
RAW WATER
STORAGE TANK
&
PUMP
POTABLE
WATER
STORAGE
Raw water treatment
-------
Process and Waste Streams
Raw water is pumped to a treatment plant after being
screened to remove debris. Chemicals are then added to the
raw water in a rapid mix chamber to aid in settling out
suspended matter and heavy metals in subsequent floccula-
tion, sedimentation, and filtration unit operations. Sof-
tening agents are also added in the rapid mix chambers. The
water goes to sand filters and then 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 injection facilities
are located at the potable water storage.
The major waste stream discharged from the raw water
treatment facility is sludge removed from the clarifiers.
This sludge contains metal complexes, lime, carbonate com-
pounds, suspended solids, and other trace compounds which
were present in the raw water. The amount of lime and other
chemicals added to the clarifier depends largely on the
quality of the intake water. Consequently, the amount of
sludge generated will vary significantly. A raw water
typically found in the Midwest contains about 360 ppm of
dissolved solids, 40 of suspended solids, and 240 ppm of
hardness. About 10 metric tons of sludge will be produced
for every thousand metric tons of this water that is treated.
Based on typical water requirements of 27,200 metric tons
per day for the liquefaction processes, about 272 metric
tons per day of sludge can be expected.
PRODUCT AND BY-PRODUCT STORAGE
There are a number of products and by-products stored
on-site including naphtha, fuel oils, sulfur, ammonia, and
184
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phenols. Fuel gas is also produced but it does not need
storage. As it is produced, it is sent directly to a gas
pipeline grid for distribution or burned internally in
direct-fired heaters in the liquefaction plants.
All storage tanks have gas vents which return hydro-
carbon vapors to the gas purification area. This system
prevents hydrocarbon vapor leakage in the storage area. No
other emissions occur except in cases of accidents. Various
by-products such as sulfur, ammonia, and phenols are removed
from process waste streams, purified, and also sent to
storage. Ammonia and phenols are stored in tanks, and
sulfur is stored outdoors in piles.
185
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SECTION 7
TREATMENT AND CONTROL TECHNOLOGY
INTRODUCTION
Treatment and control technologies are applied to
either process or effluent streams of liquefaction pro-
cesses. The objective is to permit the fullest utilization
of all the recoverable products and by-products while con-
trolling environmental pollution within acceptable levels.
Because of them the Synthoil, H-Coal, and EDS coal lique-
faction processes should be able to meet acceptable environ-
mental performance criteria while converting coal to a
convenient energy source.
The waste streams exiting the Synthoil, H-Coal, and EDS
processes are shown in Table 63. The air emissions, waste-
waters, and solid wastes are similar in that control tech-
nologies must be specified to control effluent components
common to each of the processes. A brief description
follows of the generalized waste types encountered, including
common components requiring control.
186
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TABLE 63. WASTE STREAMS FROM H-COAL, SYNTHOIL,
AND EDS PROCESSES* (EXTRACTED FROM TABLES 15, 29, AND 41)
Stream
H-Coal
Synthoil
EDS
Sour water
5,780
4,710
1,805***
Solids residue & char
1,480
1,190
2,106
Flue gases
8,190
Not quantified
Not quantified
Sludge (slag or ash
1,930
3,525
2,580
and water)
Acid gases
10,130
10,195
6,550
Spent catalysts
8
Not quantified
Not quantified
MEA solvent blowdown
Not quantified
15
Not quantified
Particulates (coal
260
260
229
preparation)**
* All values are in metric tons per day and are extracted from the section
dealing with the respective process.
** Before treatment
***Does not include sour water from hydrogen generation. This value
should be considered as a rough estimate and may be at least twice
as great when all sour water streams are identified.
Gaseous Emissions
• Emissions from coal preparation: Particulate
emissions enter the atmosphere as a result of coal
cleaning and sizing operations. Coal drying is
performed by passing hot flue gas over the coal.
The drying may result in volatilization of some
light organic components of the coal. Additional
particulate matter may become suspended in the
flue gas.
• Raw product gas from hydrogenation generation:
This gas, the raw product gas from the Koppers-
Totzek gasifier, contains entrained particulates
which should be removed prior to acid gas removal.
187
-------
• Acid gases: Hydrogen sulfide is the primary con-
stituent, although organic sulfur gases such as
carbonyl sulfide and carbon disulfide may be
present. Acid gases are generated in the gas
separation and hydrogen generation modules
and will be stripped from sour waters in the
ammonia recovery units.
• Combustion gases from heaters, preheaters and
boilers: These units burn fossil fuels to provide
energy inputs to liquefaction process operations.
Possible emissions requiring control include
sulfur oxides, nitrogen oxides, carbon monoxide,
and particulates, depending upon the fossil fuel
type combusted.
• Miscellaneous emissions: This includes transient
emissions during process startup or shutdown,
leaks or other fugitive emissions, and process
vents, such as the vent gases from solids-liquid
separation in the H-Coal process.
Wastewater Effluents
• Wastewater from gas separation: The liquid prod-
uct from the reactor is flashed in gas separators.
The vapors released are condensed and a wastewater
stream having dissolved ammonia, hydrogen sulfide,
phenols, and light hydrocarbons is generated.
• Wastewater from solids separation: A wastewater
stream contaminated mainly with light oil, some
dissolved organics, and gases is generated from
solids separation units.
188
-------
• Wastewater from fractionation: Separation of
liquid products is carried out by fractionation.
Some light oils and hydrocarbons may enter the
condensed water stream. Small amounts of hydrogen
sulfide and ammonia will also be present.
• Wastewater from hydrogen generation: A mixture of
coal and solids residue from solids separation is
gasified in the Koppers-Totzek or an alternate
gasifier. The gasifier operates at a high tempera-
ture which eliminates the presence of organics in
the raw gas. The raw gas, however, is quenched
with water which contains dissolved gases such as
hydrogen sulfide and carbon dioxide.
Solid Wastes
Of the many waste streams rejected from various coal
liquefaction modules, five basic types of solid wastes can
be identified. These are particulate coal, ash and slag
residues, char and other organic-containing residues, spent
catalyst, and spent absorbents. Particulate coal is gen-
erated in the coal preparation module of each liquefaction
process. Coal dust particles are generated in coal processing.
Unreacted coal particles are present in the waste streams
from process modules as well. Ash and slag residues consist
primarily of metallic oxides, compounds of silicon, aluminum,
calcium, iron, magnesium, titanium, sodium, potassium, and
nickel. A variety of trace elements are present. Char and
other organic residues, although conceptually utilized as
fuel and to synthesize other process reactants, exit certain
modules as waste. Spent catalyst is periodically discharged
from modules utilizing them, as are spent absorbents from
modules which use absorbents to protect catalysts from acid
gases.
189
-------
Control technologies themselves will generate solids
waste streams, including limestone sludges from sulfur
dioxide removal systems and water treatment sludges. Cal-
cium sulfite and calcium sulfate are the primary components
of limestone sludges. The wastewater sludges will consist
primarily of coal tars, sand, coal fines, and water treat-
ment by-products.
AIR POLLUTION CONTROL TECHNOLOGY
Table 64 lists some control technologies applicable to
the treatment of emissions to air. Some of the technologies
with possible application to coal liquefaction technology
are discussed in the following subsections. Reference 57
provides a more complete listing of potential control tech-
nology.
TABLE 64. POTENTIAL CONTROL TECHNOLOGY FOR AIR EMISSIONS
FROM COAL LIQUEFACTION PROCESSES (58)
Pollutant
Particulates
Applicable control methods
Mechanical methods
cyclones
multiclones
settling chambers
baffle chambers
impingement separators
Electrostatic precipitators
Fabric filters
Industry usage
Extensive
Moderate
Moderate
Moderate
Moderate
Moderate
Common
Extensive
Wet scrubbers
wet cyclones
venturi scrubbers
spray chambers
impingement scrubbers
packed bed scrubbers
fluidized bed scrubbers
Common
Common
Common
Moderate
Moderate
Moderate
(continued)
190
-------
Pollutant
TABLE 64. (continued)
Applicable control methods
Industry usage
Hydrogen sulfide
Sulfur dioxide
Nitrogen oxides
Hydrocarbons
Primary sulfur recovery
plant
Secondary sulfur recovery
plant
Wet scrubbing (with limestone)
Limestone injection
Combustion modifications
Flares
Adsorption
Common
Common
Common
Moderate
Common
Common
Moderate
Particulate Control
Three particle collectors are applicable to coal lique-
faction. They are mechanical collectors, wet collectors,
and precipitators. These collector types are compared in
Table 65. A description of each particulate control tech-
nology type is given in the following Table.
TABLE 65. CHARACTERISTICS OF PARTICULATE
CONTROL SYSTEMS (59)
Collector type
Efficiency %
Minimum particle Installed cost,
size, microns $/km^/sec*
Mechanical collectors
Cyclones 65-95
Filters (bag house)
high temperature 99
low-medium 99
temperature
0.19 - 0.24
0.71 - 1.42
0.35 - 0.71
(continued)
191
-------
TABLE 65. (continued)
Collector type
Efficiency %
Minimum particle
size, microns
Installed cost,
Electrostatic precipitators
Single-stage
Two-stage
Wet collectors
50-99.9
75-99.9
Submicron
Submicron
$/km3/
sec"
0.35 - 1.18
0.59 - 1.65
Spray chambers 80+
Venturi scrubbers 80-95+
10
0.8
0.12 - 0.24
0.24 - 0.94**
0.47 - 1.42***
* Standard cubic meters per second (measured at 15.6 C and 101.353 kPa)
** mild steel
*** stainless steel
Mechanical Collectors--
Cyclones--Cyclones remove particulates by centrifugal
force generated by spiraling gas flow. A typical cyclone
schematic is shown in Figure 48.
Mechanical simplicity and low energy requirements are
the primary advantages of cyclones. The primary disadvantage
lies in limited collection ability. Cyclones are usually
impractical for collecting particles with diameters less
than five microns. Collection efficiency increases with gas
velocity, specific gravity of particles, and inlet load.
Viscosity changes in gases reduce efficiency with increased
temperature.
Filters--Fabric filters, or bag houses, have been used to
control dust particles in the mining industry throughout the
Twentieth century. Figure 49 shows a typical bag house.
Bag houses are a highly efficient, moderately priced way to
control particules.
192
-------
ZONE OF INLET
INTERFERENCE
DUST-LADEN
GAS INLET
INNER VORTEX
OUTER
VORTEX
PARTICLES THROWN
TO WALL OF
COLLECTOR BY
CENTRIFUGAL FORCES
TOP VIEW
CLEAN GAS
OUTLET
GAS INLET
OUTER
VORTEX
CLEAN GAS
RISE THROUGH
VORTEX CREATED
BY CYCLONIC
ACTION
DUST OUTLET
SIDE VIEW
BODY
fv INNER
\ CYLINDER
(TUBULAR
GUARD)
INNER VORTEX
CONE
Figure 48. Two views of a typical cyclone (59)
193
-------
DAMPER "SHUT
PANEL OR ENVELOPE FILTER
Figure 49. Commonly used filter types (59)
194
-------
Filter use has spread to a variety of industries.
Filters remove particulates by interception and inertial
collection. Filters must periodically be cleaned of built
up filter cake to maintain filter resistance. Filters are
more effective than cyclones in controlling smaller sized
particles but are unsafe for high temperature (greater than
260°C) applications (60).
Electrostatic Precipitator--
Electrostatic precipitators remove suspended particu-
lates from gases by utilizing electrical effects. The
particulate-laden gas is passed between oppositely charged
electrodes. The particulates are ionized while passing
through the electrical field. A collecting electrode, of
opposite charge, attracts and collects the ionized parti-
cles. Periodically, the collected paxticles are neutralized
and removed from the system. Figure 50 shows a typical
electrostatic precipitator.
Electrostatic precipitators are high-efficiency col-
lectors. Furthermore, submicron-sized particles can be
collected. Although operating costs are relatively low, one
disadvantage of the electrostatic precipitator is a high
initial capital investment. Its large space requirement is
another disadvantage.
Wet Collectors--
These devices utilize liquids, usually water or oil, to
collect entrained particulates. Particulate removal by wet
collectors employs one or more of the mechanisms of inter-
ception, impingement, gravity, diffusion, electrostatic
forces, and temperature gradients. These collectors can be
generally characterized as high efficiency, high energy
means of particulate removal. Wet scrubbers and spray
chambers are the most common wet collector types.
195
-------
Figure 50. Electrostatic precipitator (59)
196
-------
Wet scrubbers--The term, wet scrubber, defines a large
segment of wet collectors. Among the various wet scrubbers
are venturi, surface area, and impingement, shown respec-
tively in Figures 51, 52 and 53. The venturi scrubbers are
among the most common. In the venturi section, particle-
laden gas is wetted. At the venturi throat, gas flow veloc-
ity is greatly increased, which produces a shearing force
which atomizes the wet liquor. Impacted liquid droplets and
particulates, and subsequent agglomeration of the droplets
due to gas deceleration, remove entrained solids. The
agglomerated particulate liquor droplets are collected in
the bottom of the scrubber. The gas then passes through a
packed bed section where final particulate removal is ac-
complished by countercurrent liquor flow. Collection effi-
ciency increases when either the energy input or liquor-to-
gas ratio is increased. Proper design allows collection of
subraicron-sized particles.
Spray chambers--Spray chambers are generally designed
for collecting particles greater than five microns. Proper
design minimizes pressure drops. As a result, high collec-
tion efficiency is possible at low operating costs.
Nozzles within the spray chamber atomize water droplets
which collect particulates the same way a venturi scrubber
does. Agglomerated droplets settle, then exit the bottom of
the chamber while the clean gas rises and exits from the top
of the chamber. Three typical spray chambers are shown in
Figure 54.
Acid Gas Removal
All liquefaction processes will generate acid gases in
the gas separation module. These acid gases are associated
with hydrogen which does not react to form hydrocarbons, and
197
-------
SLURRY
OUTLET
Figure 51. Venturi scrubber schematic (59)
198
-------
LIQUOR
DISTRIBUTOR
PACKING
MATfWAl'
OAS fk
INLET ^
ENTRAPMENT
SEPARATOR
LIQUOR
INLET
RETAINING
GRID
STAQE t
SUPPORT
ORID
STAGE I
HUMIOIflCATION
SPRATS
MAKE-UP
LIQUOR
LIQUOR
OUTLET
Figure 52. Surface area of a packed bed scrubber (61)
CLEAN OAS
OUTLET
IMPINGfMENT
Mint n*it
STAGES
SPRAYS ...
DfRTVGAifc.
INLET
ENTRAPMENT
¦ SEPARATION
S1ACC
u SCRUBBING
WATER INLET
^ HUMIDIFKATION
=* *- WATER
MR TY WATER
JUTLST
Figure 53. Typical impingement scrubber design (61)
199
-------
(B> ^0)
—0
(a) clean gas outlet
(J) DIRTY GAS INLET
© WATER AND SLUDGE DRAIN
(d) SUPPLY WATER PIPING
©—(0)
Figure 54. Typical spray chambers (59)
200
-------
carbon monoxide which is produced in the hydrogenation re-
actors. The recovery of hydrogen is essential since the
economics of the liquefaction process are partly governed by
hydrogen requirements and its costs. The Multimedia Envi-
ronmental Assessment (MEA) acid gas removal process has been
applied in each of the three coal liquefaction processes of
this report. However, a number of other candidate acid gas
removal processes exist which should be given consideration
before finalizing any design for a commercial coal lique-
faction facility. Among those processes are the following
(developers in parentheses):
• ADIP (Shell Development Company)
• Benfield (The Benfield Corporation)
• Purisol (American Lurgi Corporation)
• Rectisol (American Lurgi Corporation)
• Selexol (Allied Chemical Corporation)
• Sulfinol (Shell Development Company)
Overviews of the Benfield and Selexol processes are pre-
sented for comparison with MEA process operations.
Benfield Process—
The Benfield process uses hot potassium carbonate as a
sorbent in removing acid gas constituents. A number of
Benfield units are used commercially for sweetening natural
gas and substitute natural gas. The Benfield process has
also been used in a medium-Btu coal gasification plant in
Westfield, Scotland, thereby demonstrating its applicability
to coal conversion processes, including acid gas cleanup, in
coal liquefaction.
Figure 55 is a flowsheet of the Benfield process. Raw
gas is fed to an absorber column and contacted with a potassium
201
-------
COOLING
WATER
Figure 55. Benfield acid gas removal process (62)
-------
carbonate solvent containing proprietary Benfield additives.
The absorber typically operates at around 120°C and 4 MPa,
although operating pressures approaching 14 MPa are acceptable.
Purified gas exits the top of the absorber. The rich potassium
carbonate solvent solution, with absorbed carbon dioxide,
hydrogen sulfide, and organic sulfur species, is lowered to
approximately atmospheric pressure and fed to an air absorber
tower where absorbed gases are released. The lean solvent
is then recycled to the absorber. The acid gas is sent to
sulfur recovery.
The maximum control efficiency claimed for the process
is that product gases of 2 ppm hydrogen sulfide by volume
can be achieved. In addition the hot potassium carbonate
solvent is effective in removing hydrogen cyanide. It may
be present in appreciable quantities in coal liquefaction
processes.
Selexol Process--
The Selexol process has been used in commercial gas
purification operations. The process is considered applicable
to coal conversion operations, although such applicability
has not yet been demonstrated.
A flow diagram of the process is shown in Figure 56.
Polyethylene glycol dimethyl ether is the Selexol solvent.
Raw gas contacts the Selexol solvent in an absorber which
operates at about 4°C and 6.8 MPa. The solvent removes
hydrogen sulfide, carbon dioxide, and, if present, organic
sulfur compounds such as carbon disulfide, carbonyl sulfide,
and mercaptans. Product gas exits the top of the absorber.
A combined stripper/separator regenerates the solvent and
added gas, after passing through the separator, is ready for
sulfur recovery. The final separator treatment minimizes
solvent losses.
203
-------
ACID GASES
Figure 56. Selexol acid gas removal process (62)
-------
The Selexol process can reduce the level of in the
product gas to around 5 ppm by volume. It is not designed
to treat gas with low acid gas concentrations. Typical feed
contains 60 ppm l^S. Although the Selexol solvent is expen-
sive, its low vapor pressure minimizes solvent losses (62).
Sulfur Recovery and Tail Gas Cleanup--
The treatment of acid gases to separate hydrogen-rich
gas from them can be done by one of the many processes that
are currently employed in the petrochemical industry. The
acid gas removal processes also furnish proper feed to the
sulfur recovery process. Sulfur can be recovered from
hydrogen sulfide either in the elemental form or as sulfuric
acid. If the Claus sulfur recovery process is used, its
tail gas will also need treatment to limit the emission of
sulfur compounds. Table 66 describes the operating char-
acteristics of sulfur recovery and tail gas cleanup processes
most likely to be integrated in coal liquefaction facilities.
The Claus and Stretford processes are described in this
section. They are the two major sulfur recovery processes
currently in use. The tail gas cleanup processes which are
discussed are the Beavon and the Shell Claus Off-Gas (SCOT)
treating processes.
TABLE 66. OPERATING CHARACTERISTICS OF SULFUR
RECOVERY AND TAIL GAS CLEANUP PROCESSES (59)
Sulfur recovery
Claus Stretford
Tail gas cleanup
Beavon
SCOT
Sulfur removal efficiencies
H2S
C0S/CS2
R-SH
Hydrocarbons
90-95%
99.9%
NR*
NR*
NR*
99.9%
98%
NR*
NR*
99.8%
98%
NR*
NR*
90%
95%
90%
(continued)
205
-------
TABLE 66. (continued)
Sulfur recovery Tail gas cleanup
Claus Stretford Beavon SCOT
Secondary pollutants
Gases Yes No Yes No
Liquids No No Yes Yes
Solids Yes No No No
Recovery as elemental
sulfur Yes Yes Yes No
Required energy/material
inputs
Electricity No Yes Yes Yes
Steam No Yes Yes Yes
Cooling water No Yes Yes No
Chemical additives Yes Yes Yes No
Fuel gas No No Yes Yes
*NR denotes efficiency not reported
Claus process--In the early 1880's, English chemist
C.F. Claus discovered that elemental sulfur could be recovered
from hydrogen sulfide gas when it was mixed with air and
oxidized over iron or bauxite catalysts at elevated tempera-
tures. Around 1937, I.G. Farben devised two modifications
of the original direct oxidation scheme. The first, split
flow, involved precombustion of one-third of the hydrogen
sulfide gas to sulfur dioxide, followed by reaction over
bauxite catalysts with the rest of the hydrogen sulfide
stream. The second variation was called straight through. It
consisted of noncatalytic partial oxidation of 60 percent of
the hydrogen sulfide to elemental sulfur, followed by
conversion of hydrogen sulfide in the remaining flue gas in
206
-------
a catalytic reactor. Both Farben improvements reduced
exothermic heat evolution in the catalytic reaction stage,
the major drawback to the direct oxidation mode.
Among the more recent process modifications are sulfur
recycling and sulfur condensation. Sulfur recycling is used
when feed streams contain insufficient hydrogen sulfide to
maintain reaction temperature. Product sulfur is burned to
generate sulfur dioxide gas and makeup heat. Sulfur con-
densation is used to increase efficiency. Elemental sulfur
is condensed and removed between Claus stages to maintain
reaction equilibrium conditions favoring increased sulfur
formation in subsequent stages. The process modification
selected depends on the particular application of the pro-
cess, specifically the hydrogen sulfide content of the gas
to be treated. Figure 57 illustrates a typical present-
day Claus configuration.
The Claus process, proven and commercialized, has
several advantages. It recovers sulfur in elemental form,
which may provide income from sale of the recovered by-
product. The process also effectively reduces concentrations
of organic sulfur gases as well as hydrogen sulfide. Tail
gas from the Claus plant contains one to three percent of a
mixture of H^S, SC^, COS, CS2, and elemental S vapor and
liquid. The primary disadvantage of the Claus process is
its ineffective treatment of low hydrogen sulfide feed
gases. Feed gases containing below 10 to 15 mole percent
hydrogen sulfide cannot supply the reaction heat required to
maintain process temperature (58).
Stretford process--The Stretford process, developed by
Peabody Engineering (62), has been used commercially to
purify coke oven gas and to remove hydrogen sulfide from
207
-------
f
I
I
I
SULFUR
CONDENSER
NJ
O
00
I
k. 1
REACTION
1 t/
r
FURNACE
r*
BFW
s
Alfl
NOTES: SOLID LINES INDICATE FLOW PATHS
FOR PARTIAL COMBUSTION PROCESS
CONFIGURATION
DASHED LINE INOICATES ADDITIONAL
STREAM PRESENT IN TI4E SPLIT
STREAM PROCESS CONFIGURATION
£ ADDITIONAL CONVERTERS'CONOENSERS
TO ACHIEVE ADDITIONAL RECOVERV OF
ELEMENTAL SULFUR ARE OPTIONAL AT
THIS POINT
TAIL GAS
SPENT CATALYST
SULFUH
Figure 57. Claus sulfur recovery process (62)
-------
natural gas. In this process, hydrogen sulfide reacts with
sodium carbonate solution to form sodium bicarbonate and
sodium hydrosulfide. Catalytic sodium vanadate solution
reacts with the NaHS to form elemental sulfur. Air blowing
with sodium anthraquinone disulfonate (ADA) regenerates the
sodium vanadate catalyst. The ADA is regenerated by oxidation.
The reaction sequence is:
1) H2S + Na2C03 ~NaHS + NaHCC>3
2) 4NaV03 + 2 NaHS + 2H20 ~ Na^Og + 2S + 4NaOH
3) Na2V4Og+2NaOH + H20+ADA —~ 4NaV03 + 2ADA (reduced
state)
4) 2ADA (reduced state) +02—^2ADA + H20
Reaction 1) occurs in the absorber, 2) and 3) in the
hold tanks, and 4) in the oxidation tank. Figure 58 shows a
typical Stretford process configuration.
The Stretford Process can reduce the hydrogen sulfide
content of the exiting tail gas to less than 1 ppm by volume.
Chemical requirements are low. The Stretford process is
limited to feed gas.es of 15 percent hydrogen sulfide or
less. Overloading or low pH feeds can result in nonregener-
able thiosulfate formation. Additionally, Stretford is
ineffective in removing organic sulfur compounds.
Beavon process--This process, named for D.K. Beavon,
was developed by the Ralph M. Parsons Company. Final exit
gas concentrations in the range of 40 to 80 ppm sulfur (as
S02) have been reported for the process.
209
-------
ELEMENTAL
SULFUR TO
RECOVERY
-------
In the Beavon Process, entering tail gas is mixed with
hot flue gas. The gas is passed through a catalytic reactor
containing a cobalt-molybdate catalyst. Sulfur compounds
are hydrogenated to form hydrogen sulfide. The gas is then
cooled. Water vapor condenses, leaving a cool, dry gas.
The gas is then passed to a Stretford section where hydrogen
sulfide is converted to elemental sulfur. The process flow
sheet is shown in Figure 59.
The Beavon Process effectively recovers sulfur from
carbonyl sulfide and carbon disulfide as well as from hydrogen
sulfide. It also recovers sulfur in its elemental form.
The process condensate may require further treatment prior
to discharge.
SCOT Process—The SCOT Process, developed by the Shell
Development Company, catalytically converts organic sulfur
to hydrogen sulfide and removes it with a special scrubbing
system.
Figure 60 shows a simplified SCOT process flow chart.
The catalytic reactor converts organic sulfur to hydrogen
sulfide according to the following reactions:
COS + h2o
•~h2s + co2
CS2 + 2H20
#-2H2S + C02
Sulfur dixoide and free sulfur react as follows:
S02 + 3H2
*-H2S + 2H20
S + h2
^H2S
211
-------
TREATED
TAIL OAS
FUEL OAS J-
AIR f-
LINE
BURNER
N>
I—1
N>
(§H>-
CATALYTIC
REACTOR
COOLER
ABSORBER
STRETFORD UNIT
OXfOIZER VENT
V /
s
<.—
MAKE-OP MAKE-UP
WATER CHEMICALS
jy
c.w.
REACTION
HOLD
TANK
c
K>
sunoE
TANK
< SETTLING ^
TANK J
OXIDIZER
TC
AIR
SOnBENT
SLOWDOWN
CONDENSATE TO
SOUR WATEn
STnippEn
ELEMENTAL
SULFUR
TO RECOVER
Figure 59. Beavon tail gas cleanup process (62)
-------
N>
M
U>
Figure 60. SCOT Process (62)
-------
Alkanolamine scrubbing removes the hydrogen sulfide
from the tail gas stream. The hydrogen sulfide can be
recovered in a stripper and recycled to the sulfur recovery
process. Reports indicate that treated tail gases have a
total sulfur content of 200 to 500 ppm by volume. The SCOT
process requires additional fuel gas to provide reducing gas
and heat for the reactor section. The equipment utilized is
proven and removal efficiencies higher than reported are
theoretically possible.
NO Control--
X
Control of oxides of nitrogen, nitrous oxide (^0) ,
nitric oxide (NO), and nitrogen dioxide (NO2) is a problem
without a well-defined solution. Thermal NO , the combustion
product of molecular nitrogen, is formed in every combustion
system using air. Additionally, combustion of fuel-bound
nitrogen compounds converts them to NO .
X
Several approaches have been considered to control
thermal NO formation. All are combustion modifications,
contrived to reduce NO formation by temperature or equilib-
rium control. Reduction in combustion zone temperature,
combustion zone residence time, or excess air, as well as
premixing of air with fuel, water injection, flue gas recir-
culation, staged combustion, and modified combustor geometry
are all being studied to determine their potential to reduce
N0X emissions. Reduced turbine efficiency is generally
associated with such modifications.
Controlling fixed NO from fuel-bound nitrogen is of
greater interest when considering combined gas and steam
(COGAS) cycle power generation. In COGAS systems utilizing
214
-------
low temperature cleanup processes, water scrubbing can
remove most of the fuel-bound nitrogen. Currently no high
temperature cleanup process is capable of removing combined
nitrogen constituents from fuel gas. Research efforts have
investigated, without success, the possibility of using
catalyst to decompose ammonia, the primary source of
fuel-bound NO , into molecular nitrogen and hydrogen. Such
a composition increases the overall Ng content.
WASTEWATER TREATMENT AND CONTROL TECHNOLOGY
Water requirements for coal conversion plants are high.
Wastewater streams are generated from gas separation, solids
separation, and fractionation modules, and from the acid gas
removal process. Raw gas from the gasifier in the hydrogen
generation module is scrubbed with water, and this results in
a wastewater stream. Some of the pollutants in the wastewaters
include hydrogen sulfide, carbon dioxide, hydrocarbons,
phenols, ammonia, cyanides, and acidic or basic substances.
All wastewater streams may not need the same treatment since
the complete overall wastewater treatment depends on char-
acteristics of each individual wastewater stream. The
principal difference among the various liquefaction processes,
as far as the wastewater treatment is concerned, is the
chemical characteristics of the process condensates generated
in the phase separation module. The concentration of pollu-
tants in the wastewaters will vary for all processes. Treat-
ment of wastewater effluents can be accomplished by
a great number of processes. However, in order to select
and implement an efficient waste management program, it is
necessary to evaluate the control and treatment techniques
against specific factors applicable to each case. Table 67
is a list of control techniques for potential pollutants
from coal conversion plants. The table contains, for various
215
-------
TABLE 67. POTENTIAL CONTROL TECHNOLOGY FOR COAL CONVERSION WASTEWATER (63)
Pollutant
Hexavalent
chromium
Cyanide
N5
t-*
Treatment method
Limitations
Applicable
concentration
range, ppm
Level after
removal,ppm
Industry
usage
+3
Reduction to chromium
(III) with SO,, NaHSO,
or FeSO, at pH below
3 followed by preci-
pitation at pH 8.5-9.5
Adsorption on anion
exchanger
Evaporative recovery
Oxidation to cyanate
with chlorine at pH
above 10
Oxidation to cyanate
with chlorine at pH
above 10 followed by
acid hydrolysis to
CO2 and N2 at pH 2-3
Decomposition to COy
and N- via cyanate
with chlorine at pH
8-8.5
Electrolytic decomposition
to C09 and N, via cyanate
at 200°F
Ozonation
Storage of waste
at ambient temperature
Reduction is not
conplete. Rate
depends on pH,
reducing agent
and contact time.
Recovery process
Recovery process
Increases total
dissolved solids
and treatment
costs
Toxic cyanogen
chloride may be
liberated, a large
excess of chlorine
is required.
Interference by
sulfate
Only partial
decompostion
to CO2 and N2
Incomplete
treatment
100-500
200
500
100-1000
100-1000
1000
100-1000
100-1000
0.05-1
0.05
C.l
Complete
removal
0.1-0.A
after 7-18
days
Complete
removal
70-90%
after 4-8 days
Common
Moderate
Not
practiced
Not
practiced
Moderate
Common
Common
Moderate
Coking
industry
Precipitation as
ferro ferricyanide
with iron salt
Incomplete
treatment
100-1000
0.5-12.3
Wot
practiced
Adsorption on
activated carbon
Biological treatment
Oxidation with hydrogen
peroxide to cyanate
(Kastone process)
Incomplete
treatment
Proprietary
information
(continued)
100-1000
100
100-1000
0.6-1.4
70-90^ removal
Hot
practiced
-------
Pollutant
Treatment method
Fluoride Precipitation with
lime as calcium
fluoride at pH 11
Coagulation by alum
Adsorption on
hydroxylapatite bed
Adsorption on
aluminum saturated
cation exchanger
Adsorption on
activated
alumina bed
Oxidation to Fe
by aeration followed
by precipitation as
FE(OH)3 at pH 7
Oxidation to Fe+^
by chlorine followed
by precipitation as
Fe (0H)3 at pH 7
Deep well disposal
fO
H*
Iron (11)
Tar and Oil Gravity separation
Centrifugation
Heating
Precoat Filtration
Coagulation or de-
emulsification with
chemicals, followed
by air flotation or
settling
TABLE 67. (continued)
Limitations
Applicable
concentr at ion
range, ppm
Level after
removal,ppm
Industry
usage
Slow rate of
precipitation
720
10-20
Common
Applicable only 20
to low hardness
water
Presence of 20
chlorine increases
cost of bed regeneration
Expensive 20
1
0.5-1.5
Hot
practiced
Water
treatment
Hot
practiced
4% of bed is
lost in each re-
generation cycle
20
Below 0.5
Sot prac-
ticed wato:
treatment
technology
Common
0.5
Moderate
Steel
industry
Does not remove
emulsion
60-99% of
floated oil
Common
Common
Not
practiced
5-20 Common
Addition of alum 50-90% Common
forms sludge
which is diff-
cult to dewater
(continued)
-------
TABLE 67. (continued)
Pollutant
Treatment method
Limitations
Applicable
concentration
range, ppm
Level after
removal,ppm
Industry
usage
pH Control
Phenols
Dissolved
Solids
Biological treatment
Neutralization with
chemicals
Benzene-caustic
dephenolization
process
Counter-current
extractor
(Chemizon process)
Pulsed column
extractors
Phenosolvan
dephenolization
(Lurgi)
IFAQOL dephenolization
(Carl Still)
Light oil extraction
(Koppers)
Incineration
Oxidation ditch
Trickling filter
Activated sludge
Oxidation with
ozone
Activated carbon
bed
Oxidation with
chlorine
Concentration and
evaporation
Cost depend on
buffer capacity
of waste
Expensive when
waste contains
more than 5 mg/1
500
500
500
500
500
1500
7000
50-500
50-500
50-500
50
50
50
to
100,000
15
Neutral pH
210-240
100
30
4.5-10
40
10-30
Complete
99%
98%
99%
0.35
0.005
Complete
removal
Common
Common
Common
Common
Common
Common
Common
Common
Not
practiced
Conmon
Common
Common
Limited
usage
Common
Common
Common
(continued)
-------
Pollutant
Treatment method
TABLE 67. (continued)
Limitations
Applicable
concentration
range, ppro
Level after
removal,ppm
Industry
usage
Reverse osmosis
1,000-2,000
50-95%
Increasing
Suspended
Solids
Sedimentation
Chemical coagulation
Filtration
90-95%
95-99%
95%
Extensive
Moderate
Extensive
N>
»-»
v£>
Anemia
Chloride
Sulfide
Thiocyanate
Stripping at pH
of 10-11
Biological
nitrification
Ion exchange
Deep well injection
Evaporation ponds
Biological oxidation
to sulfate
Biological oxidation
Ion exchange
Hater adsorbs
CO,-may lead to
scale formation
Hutrient may be
required
Limited by geo-
graphical location
and land availability
Excess anmonia
lower efficiency
Excess ammonia
lower efficiency
1250
60
50-90%
2
80-95%
Ultimate
disposal
Complete
removal
Complete
oxidation
907.
90%
Extensive
Extensive
Hot
practiced
Moderate
Extensive
Moderate
itot
practiced
-------
treatments, a brief description, limitations, the applicable
concentration range efficiency, and the extent of industrial
usage. It should be emphasized, however, that many of the
methods listed have been developed specifically for product
recovery and, as such, are not applicable to control of
pollutants present in the wastewater in low concentrations.
Oil-Water Separation
The wastewaters from gas separation and solids separation
units will be combined and sent to a gravity separator. The
lighter oil layer which floats on the top is removed and
sent to storage. The heavier aqueous layer, which contains
dissolved organics along with ammonia and hydrogen sulfide,
is sent to phenol extraction. A schematic of a corrugated
plate interceptor oil-water separator is shown in Figure 61.
The control effectiveness, process advantages, and process
disadvantages of the oil-water separator are given below:
Control Effectiveness
• Removes, oils with 60-997o efficiency
• Removes solids with 10-50% efficiency
Process Advantages
• Simple and effective way to remove nonemulsified
oils and solids from wastewater
• Low energy consumption
• High reliability
220
-------
ADJUSTABLE
OUTLET WEIR
ADJUSTABLE
INLET WEIR
OIL SKIMMER
CONCRETE
/I
CLEAN WATER
OUTLET CHANNEL
CONCRETE
SEDIMENT TRAP
PLATE ASSEMBLY CONSISTING
OF 24 OR 48 CORRUGATED
PARALLEL PLATES
SLUDGE PIT
Figure 61. Schematic of corrugated plate interceptor oil-water separator (62)
-------
Process Limitations
• Requires large amounts of space
• Effluent streams require further control
• Only effective for separation of nonemulsified
oils
Other Alternatives
• Air flotation
• Gravity separation plus air flotation
• Filtration
• Centrifuging
• Filtration or centrifuging plus heating
Phenol.Extraction
Removal of phenols from wastewater streams is generally
done by liquid-liquid extraction. The most applicable
process will probably be the Phenosolvan process which has
been used for all Lurgi process plants. The flow scheme for
the Phenosolvan process is shown in Figure 62. The liquid
is mixed with an organic solvent (isopropyl ether) in an
extractor in order to dissolve the phenol. The phenol
solvent mixture is collected and fed to solvent distillation
columns where crude phenol is recovered as the bottom product
and the solvent as the overhead product. The solvent is
then recycled to extractors after removing some of the
222
-------
Figure 62. Flow scheme for phenol extraction
- Phenosolvan Process (62)
-------
the water. The raffiriate is stripped with fuel gas to remove
traces of solvent which were picked up in the extraction step.
The fuel gas is scrubbed with crude phenol product to recover
the solvent. Finally, the phenol solvent mixture is distilled
in the solvent recovery stripper to produce the crude phenol
product, and the solvent is recycled to the extraction step.
The solvent-free raffinate is heated and steam stripped to
remove carbon dioxide, hydrogen sulfide, and ammonia (62).
The control effectiveness, process advantages, and
process limitations are as follows:
Control Effectiveness
• 99.5% removal of monohydric phenols
• 60.0% removal of polyhydric phenol
• 15.0% removal of other organics
Process Advantages
• General - economically attractive technique for
phenol removal and recovery
• Specific - solvent has:
Relatively low volatility
Low solubility in water
High distribution coefficient
Process Limitations
Solvent is soluble enough in water to require its
recovery
-------
• Initial process investment is substantial.
Alternative Processes
• Absorption, counter-current liquid extraction
Benzene or light process
Tricresyl phosphate process
Holley-Mott Process (horizontal flow)
Lowenstein Low Process
• Adsorption on solid media
• Vapor phase dephenolization
• Ion exchange resins
Ammonia Recovery
Dephenolized wastewaters and the wastewaters from
purification units and the hydrogen generation module are
combined and sent to the ammonia recovery unit. The first
step in the treatment of the sour water is to selectively
remove the acid gases H^S and CC^. Ammonia can be tied up
with the water by controlling the pH. If the pH is about
5, almost all the ammonia will be tied up as a salt, and
only acid gases will be stripped off. The Phosam-W process
and the Two-Stage All Distillation process are generally
for ammonia recovery. The Two-Stage All Distillation process
is described in the following subsections.
Two-Stage All Distillation Process
A flow diagram for the Two-Stage All Distillation process
is shown in Figure 63. The control effectiveness, process
225
-------
HYDROGEN SULFIDE
Figure 63. Two-Stage all distillation process for ammonia separation (2)
-------
advantages, and process limitations are as follows:
• Control Effectiveness
Depends upon process operation; however, typical
results are as follows:
Stripped water is 99.970 water by wt.
NH^ in stripped water is only 50 ppm.
HgS in stripped water is only 10 ppm.
• Process Advantages
Does not require high pressure as does refinery
equipment
Facilitates the recovery of and NH^ for
further processing as by-products
Already proven in commercial applications
Capital and operating costs are moderate
Can utilize previously existing equipment
• Process Limitations
Process is proprietary, and a royalty must be
paid for its use
Discharge streams require further environmental
control
-------
Biological Oxidation
In biological treatment of wastewater, dissolved and
colloidal organic matter are subjected to action by bacteria
and other microorganisms. Organic matter is removed from
water by conversion, partly to carbon dioxide and partly to
a settled organic sludge consisting mostly of dead and
live microorganisms which have fed on the organic matter.
Various biological treatment systems can be used to degrade
the organics in wastewaters from coal conversion processes.
A feed of nearly constant characteristics can eliminate the
upsets due to shock loads or abrupt changes in composition.
Constant load is essential for treating high-strength waste-
waters by biological means. For coke plant wastewaters it
has been recommended that a storage capacity equal to five
or more days of feed liquor be provided for equalization.
The effectiveness of various methods, the process
selectivity factors, and the advantages and limitations of
biological oxidation processes are given below (62):
Effectiveness of Methods
Range of % removal
Sulfides
BOD
COD
Suspended
solids
Oil
Phenols
Activated sludge
97-100
88-90
60-85
95-99+
Trickling filters
-
60-85
30-70
50-80
50-80
Waste stability
ponds (Aerobic)
-
40-95
30-65
20-70
50-90
Aerated lagoons
95-100
75-95
60-85
40-65
70-90
90-99
Cooling tower
oxidation (air
stripping)
9CH-
90+
99.9
Thiocyanates
70% removed by all processes
228
-------
Process Sensitivity
• Temperature: Biological oxidation of dissolved
organics is optimum in the temperature range of
15-40°C. In this range, as the temperature increases
so does the amount of dissolved organics which are
oxidized. However, when the maximum temperature
is exceeded the microorganisms are adversely af-
fected and the stability of the biological oxidation
process is upset.
• pH: The pH level of the waste stream influences
the efficiency of biological oxidation. The
optimum pH level is 7.0; when the pH is below 5.5
or above 9.5, the microorganisms cannot exist.
The pH level also influences the efficiency of
thiocyanate removal.
• Presence of oxygen: Oxygen is required for oxida-
tion of organics in the waste stream. The greater
the amount of available, the more able the
process is to resist shock organic loadings.
• Organic and hydraulic loading: Biological oxida-
tion is highly dependent upon both organic and
hydraulic loadings. As the organic loading in-
creases, the total amount of organic material
oxidized increases, however, the percent of total
material oxidized decreases. The optimum feed-
to-microorganism ratio is 0.2 - 0.5:1.0. An
excessive hydaulic loading results in a foaming of
trickling filters and a decrease in efficiency of
biological oxidation.
229
-------
Heavy metals: The presence of heavy metals can
have an adverse effect on the efficiency of the
biological oxidation process, particularly if a
rapid change in their concentration occurs.
Process Advantages
Effectively reduces the BOD and phenol level in
industrial wastewater
Has wide applicability to industrial applications
and has been proven in several applications
Comparatively inexpensive water treating process
Removes some amounts of trace metals, ammonia, and
cyanides that may be present in waste (small when
compared to phenol)
Process Limitations
Highly sensitive to pH levels
Highly sensitive to presence of heavy metals
Strongly influenced by organic and hydraulic
loadings; consequently, susceptible to operational
upsets
In instances where ponds and lagoons are used,
large tracts are required
Highly dependent on oxygen supply
230
-------
• Requires the presence of nutrients (62)
Activated Carbon Adsorption
Carbon adsorption could be utilized as a tertiary
treatment method for polishing the effluent water from the
biological treatment system. Some organics, such as cyanides,
may not be completely destroyed by the biological treatment.
Also, if a specific wastewater stream has a high concentra-
tion of cyanides and trace elements that are harmful to
microorganisms, this water should be treated directly by
activated carbon adsorption. A flow schematic of activated
carbon adsorption is shown in Figure 64. The control effective-
ness and process advantages and disadvantages are as follows
(62):
Control Effectiveness--
Adsorption has performed so well in removing dissolved
organics from wastewater streams that it is normally used
when a water of high quality is desired. Adsorption has
exhibited the following removal efficiencies:
• Phenol - 99%
• * COD - 81%
• Cyanide - 1%
Process Advantages
General - Adsorption makes it economically possible to
purify streams that contain only small amounts of
impurities that would otherwise be impossible to clean.
231
-------
MARKUP CAR HON
N>
U>
to
EXIT
QUENCH
WATER
Figure 64. Wastewater treatment with activated carbon (62)
-------
Specific
• Adsorption has high ability to reduce impurity
concentration at ambient conditions
• Adsorption is not affected by slight temperature
change, fluctuations in organic loading, or toxicity
• Adsorption has wide applicability to many industrial
wastewater problems
• Adsorption is not upset by fluctuations in hydraulic
rates
Process Disadvantages
• Adsorption does not facilitate recovery of adsorbed
dissolved organics; consequently, regeneration of
the adsorbent is necessary
• Regeneration of adsorbent generates aqueous and
gaseous streams that may require further control
• Regeneration of adsorbent may not be complete;
therefore, the removal efficiency of the adsorbent
may decrease with time
• High operating costs are sustained due to frequent
regeneration of adsorbent
Solids Waste Controls
Solids waste controls by coal liquefaction will involve
various technologies, including:
233
-------
• Pyrolysis
• Incineration
• Recovery and use
• Land disposal
• Landfilling
• Pond storage
• Chemical fixation
Pyrolysis--
The solids waste removed from the phase separation
module of the three coal liquefaction systems described in
this report includes large quantities of carbon containing
tars and other high-boiling residues. Process economics
require that these residues be pyrolyzed, or otherwise
treated, to recover additional liquid product. Multimedia
and other style furnaces have been utilized or suggested for
this purpose.
Incineration--
The carbon-containing residues, both before and after
pyrolysis, still contain sufficient carbon content to make
removal through some combustion process economically and
environmentally desirable. The most commonly suggested com-
bustion or incineration method is to use these residues for
hydrogen production.
Recovery and Use--
Recovery of by-products such as sulfur, phenol, and
ammonia, and regeneration of spent catalysts serve as examples
of process wastes that may be converted into useful products.
Processes for sulfur, phenol, and ammonia have been covered
in preceding sections. Catalyst regeneration is specific to
the process involved.
234
-------
Land Disposal--
One of the most economical methods of solids waste dis-
posal is to put it on surface land, or in mine pits or other
existing underground cavities. Mining, smelting, and ferti-
lizer industries which have large quantities of solids
waste use this technique. It is anticipated that coal
liquefaction systems will also use this approach.
Landfilling--
Landfilling ranges in costs and complexity from simple
to secured categories. Simple landfilling consists of
placing the solids waste in a prepared pit and covering it
with soil. Secured landfilling involves impervious pit
liners, monitoring the pit area for leachate, drainage
provisions, pit covers, indexing the waste location, per-
petuity maintenance, and other factors which increase land-
filling costs by at least an order of magnitude.
Pond Storage--
Solids waste which is naturally waterborne (such as
suspended solids) or can be handled in this fashion (such
as mine tailings) is often settled and stored in ponds. Ash
is a particular solids waste that is so handled. Since ash
will probably be a major solids waste from the hydrogen
generation, it is anticipated that pond storage will be a
control technology utilized in coal liquefaction.
Chemical Filtration—
Various processes have been developed for changing
liquid or slurry wastes into less water soluble solids.
Hazardous and toxic wastes such as radioactive residues,
some chemicals, and biologically active substances, have
been controlled in this fashion. The costs for this techno-
logy normally limit its range of usefulness.
235
-------
SOURCES
UNCONTROLLED
EMISSION
CONTROL
METHODS
CONTROLLED
EMISSION
ROM COAL
2.4 ton/hr
FROM
20,4 00' ton/day
COAL HANDLING
FACILITY
• ENCLOSURES OR HOODS
• OUST COLLECTORS
- VACUUM CLEANING SYSTEMS
- LOUVER TYPE COLLECTOR
- CYCLONES
- WET SCRUBBERS
- FABRIC FILTERS
- ELECTROSTATIC PRECIPITATORS
• WATER SPRAYS
}
}
• MINIMIZE UNCOVERED STORAGE
• SPRAYING OF WATER SOLUBLE
ACRYLIC POLYMER
• PROPER HANDLING ft DISPOSAL
LESS THAN
545 Jb/hr
THERMAL
DRYERS
}
9J5 ton/hr
}
(ASSUMING DUST LOAOING
OF 100 GRAINS PER ACTUAL
CUBIC FEET AND GAS VOLUME
OF 100,000 ACTUAL CUBIC
FEET)
• CYCLONES
• WET SCRUBBERS
• BAG FILTERS
. LESS THAN
70 Ib/hr
Figure 65. Particulate emissions from coal preparation
and handling (61)
236
-------
ENVIRONMENTAL DISCHARGES AFTER APPLICATION OF TREATMENT
AND CONTROL TECHNOLOGY
Presently there are no environmental standards for coal
conversion plants. However, establishing environmental
standards seem inevitable. New standards will be set for
hazardous or environmentally dangerous constituents from
conversion plants with emphasis on health effects, land use,
and geography. These standards will probably be based on
the existing standards for petrochemical, coke manufactur-
ing, and power plants. They will most likely add to the
need for treatment and control of wastes. Although the
identification of multimedia waste streams for coal lique-
faction processes is necessary for estimating environmental
discharges, it is the after-treatment discharges that have
environmental significance. This section gives estimates of
these environmental discharges.
Air Emissions
Table 68 shows estimated acid gas emissions for the
three processes of this report. Particulate emissions from
coal preparation and handling are given in Figure 65.
Emissions from other portions of the systems, such as steam
and power generation, will add additional emissions.
TABLE 68. ACID GASES BEFORE AND AFTER TREATMENT**
(EXTRACTED FROM SECTIONS 4, 5 & 6)
In i i i ¦
Synthoil H-Coal EDS
Component
Before
After
Before
After
Before ,
After
H,S
757
2-10*
819
2-10*
398
2-10*
fa
ppm
ppm
ppm
h2°
2.4
133
8.6
145
70
NH3
6.6
6.6
1.5
1.5
8.2
8.2
Hydrocarbons
41.4
41.4
20
20
3.9
3.9
(continued)
237
-------
TABLE 68. (continued)
Synthoil H-Coal EDS
Before After Before After Before After
CO
1.0
1.0
CO
9,336
9,336
9,232
9,232
6,652
6,652
"2
48.3
48.3
51
51
35.2
35.2
so2
0.1
*
0.22
*
0.15
*
HCN
1.99
trace
2.1
trace
1.5
trace
N°x
trace
trace
trace
trace
trace
trace
Total feed
10,195
9,566
10,134
9,449
8,000
6,769
Sulfur recovered
716
775
377
* Released as SO2 after flaring.
**Values in metric tons per day except where otherwise indicated.
Wastewater Effluents
Figure 66 shows the application of control and treat-
ment technology to coal liquefaction system wastewaters.
Table 69 gives the sour water characterization before and
after treatment for the H-Coal, Synthoil, and EDS systems.
Other wastewater discharges from coal storage and prepara-
tion, steam and power generation, cooling tower blowdowns,
and raw water treatments are covered elsewhere in the report.
TABLE 69. WASTEWATER CHARACTERIZATION BEFORE AND
AFTER TREATMENT *(EXTRACTED FROM SECTIONS 4,5 & 6)
Component
H
2
C0„
H2S
NH„
H-Coal
Before After
Synthoil
Before After
EDS
Before After
4,155
118
175
104
4,155 3,411
Completely
Removed
<0.15
ppm
10 ppm
11
125
3,411
<0.15
ppm
10 ppm
1,776 1,776
Not <0.15
quantified ppm
180 10 ppm
(continued)
238
-------
TABLE 69. (continued)
Component H-Coal Synthoil EDS
Before After Before After Before After
Phenols) 24 <0.1 ppm 9.4 <0.1 ppm 17.7 <0.1 ppm
Oils I <5 ppm <5 ppm <5 ppm
Recovered by-products 24 9.3 14
Phenols & oils 24 9.3 14
Ammonia 104 104 173
*Values in metric tons/day except where otherwise noted.
Solids Waste
The solids waste includes various constituent materials.
Ash consists of a variety of metallic oxides and trace
element compounds. Coal and char particles contain organic
and mineral materials. Elemental sulfur may be generated as
solids waste from hydrogen sulfide control technologies.
Limestone sludges, primarily calcium sulfite and calcium
sulfate, may be alternately generated. Zinc sulfide, the
primary constituent of spent sulfur guard reactor absorbents,
also may be present as will spent catalyst from applicable
processes. Wastewater treatment sludges, a mixture of coal
tar residues, sand, coal fines, and treatment by-products
may also contain untreated quantities of phenols, ammonia,
cyanides, and other potentially hazardous materials (62).
About 25 percent of the raw coal input is disposed of
as waste. For a coal conversion plant processing 18,500
metric tons per day of prepared coal, the coal refuse will
amount to 4,650 metric tons per day. The coal refuse consists
of waste coal, slate, carbonaceous and pyritic shales, and
clay associated with a coal seam. There are two basic types
of coal refuse: coarse and fine. The coarse refuse is
239
-------
WASTEWATER
SOURCE
CONTROL & TREATMENT
METHOD
END USE/DISPOSAL
GAS SEPARATION
SOLIDS-LIQUID
SEPARATION
FRACTIONATION
HYDROGEN
generation
OIL-WATER
SEPARATOR
(API SEPARATOR)
PHENOL
REMOVAL
(PHENOSOLVAN
PROCESS)
AMMONIA
STRIPPING
(TWO-STAGE ALL
DISTILLATION
PROCESS)
BIOLOGICAL
OXIDATION
(ACTIVATED
SLUDGE
PROCESS)
OIL TO STORAGE
PHENOLS TO STORAGE
ACID GASES TO
SULFUR RECOVERY
AMMONIA TO
STORAGE
TREATED WATER FOR
REUSE OR TO
DISPOSAL
ADSORPTION
(ACTIVATED
CARBON)
TREATED WATER
FOR REUSE
Figure 66. Application of control and treatment
technology to coal liquefaction process wastewaters (59)
240
-------
separated mainly by crushing the lump coal to a smaller
size; the fine refuse is mainly separated from the thickeners
as underflow and impounded by settling ponds. The coarse
refuse is normally disposed of in an embankment (62).
Chemical analysis must be utilized to identify the specific
composition of solids waste materials and to determine the
concentration of these materials. If necessary, the environ-
mental impacts of some materials may need to be determined.
In effect, all leachable materials present in concentrations
exceeding environmentally acceptable standards should be
identified.
The problems associated with solids waste disposal must
be resolved to reach the desired goal of minimized environ-
mental degradation. Landfilling and minefilling techniques
will require additional sophistication to confidently prevent
contamination of the surrounding area. Undesirable ash
constituents can re-enter the environment as a result of
groundwater leaching. Little is known of the fate of land-
filled trace elements, spent catalysts, or spent absorbents.
Upon identification of hazardous leachable materials present
in solids waste, leaching studies may be needed to determine
the alternatives available to minimize detrimental environ-
mental effects. Impervious liners may be used as a physical
means of preventing groundwater percolation. They, in
turn, prevent leaching. Chemical stabilization, to render
leachable constituents insoluble or inert, may be a necessary
control method in some instances. A combination of physical
and chemical control methods may be the required technique
(62).
Subsidence, the gradual settling of landfill materials,
is another problem. In some cases, compacted wastes reduce
subsidence effects, allow more waste disposal per unit
241
-------
volume of storage space, and reduce permeability of land-
filled wastes. Compacted wastes have fewer leaching pro-
blems , and are currently under consideration as a means of
improving solids waste disposal techniques. More information
is needed regarding the subsidence and compaction properties
of the bulk solids waste generated by liquefaction processes.
Although no secondary wastes are anticipated after
landfilling, light hydrocarbon gases may be generated due to
reaction of organic materials present. Furthermore, combus-
tible materials may generate gases as well as cause under-
ground fires. Unsuspected or undetected materials may
undergo groundwater leaching. Periodic sampling and analysis
of landfill materials and surroundings will be required to
determine if secondary wastes are generated and, if necessary,
to develop control technology modifications which will
prevent the generation of such wastes (62).
242
-------
SECTION 8
ENVIRONMENTAL EFFECTS AFTER TREATMENT
INTRODUCTION
In general, the pollution expected from a coal lique-
faction plant differs from the pollution expected from a
coal combustion plant in that the reducing atmosphere of the
liquefaction plants should give off pollutants in their
reduced rather than their oxidized state. In addition, coal
liquefaction synthetic oil products differ from those for a
petroleum refinery in that they will probably have more
aromatic condensed ring and carcinogenic substances than the
natural crude oil products. These will be important aspects
for users and handlers of such products to remember. The
potential hazards remain to be determined.
Air pollutants from coal liquefaction processes and
auxiliary operations may result from flue gas emissions,
fugitive emissions, uncondensed gases, evaporation from the
wastewater storage and biotreatment ponds, and emissions
from coal cleaning and preparation. All of these may be
possible sources of particulates and volatilized organic and
nonorganic compounds. Ash will be cleared from the gaseous
effluents mainly during treatment a.nd control operations,
and only residual particulates will be left.
243
-------
Flue gas emissions may include carbon monoxide, ammonia,
and unburned hydrocarbons as well as nitrogen and sulfur
oxides. Fugitive emissions may include wind-blown dust from
the coal piles; dust from the coal drier, cyclones, and
screening and washing fines; dust from the stacker-reclaimer;
coal conveyors, waste fines transfer, waste storage, reactor
charging, ash discharging; pipe and valve leaks in liquid
waste transfer; evaporation from liquid waste storage, waste
dust and ash transfer, waste dust and ash storage, or sulfur
pile storage. Fugitive emissions from the grinding, pul-
verizing, and drying of coal include particulates and hydro-
carbon vapors. The vent stream from acid gas removal con-
tains sulfur and combustibles. Evaporation from storage
ponds and biotreatment ponds contains phenols and other
wastes. The cooling towers are a source of heat and mists.
Cooling towers can also be a source of atmospheric emissions
of pollutants picked up from leaks of sour water, oil streams,
and acid gas wastes.
Some offensive odors may originate in the vicinity of
the coal conversion plant. Also, when the plant is closed
for cleaning, some odors not normally detected may become
apparent, since parts of the plant, which normally operate
as a sealed system, may be open to the outside air.
Coal conversion plants use and produce large quantities
of water, which become either a component of gas and waste-
water streams from process and auxiliary operations, vapor
evaporated to the atmosphere, or a component of sludge or
moist wastes. There are several sources of pollutants for
the process water circulating throughout the plant. These
include blowdowns, nonoily filter backwash, stormwater
effluent, ash and fly ash contacts, treatment ponds, and
possible product or process spillage or leakage.
244
-------
Outside storage of coal at or near the site will be
necessary to assure continuous plant operation. Coal is
stored either in active piles or storage piles. Active
coal piles are open, and contact with air and moisture
results in sulfuric acid from oxidation of the metal sulfides
in the coal. The precipitation seeps into the coal piles.
When rain falls on these piles, the acid is washed out and
eventually winds up in the coal pile runoff. Storage piles
are sometimes sprayed with a tar to seal their outer surface.
In such cases, the precipitation runs down the side of the
pile.
The waterborne wastes may contain phenols; sulfur;
nitrates; trace metals; ammonia; cyanides; trace amounts of
carboxylic acids; significant amounts of acetic acid; light
hydrocarbons including benzene, toluene, and xylene; alkylated
benzenes; naphthalene; fatty acids; phenols; cresols; thio-
cyanates; alkyl substituted phenols and napthols; suspended
particulates; dissolved solids, tars, oil, ash, dust; and
floor scrubbing detergents. While phenols are anticipated
to provide the bulk of the organic load in the aqueous
effluents from the process itself, they also are the most
easily removed. Thiophenes, on the other hand, are produced
in smaller quantities, but the removal efficiency by waste-
water treatment is unknown. The polycylic aromatic hydro-
carbons (PAH) are expected to compose the smallest fraction
of the organic load with a wide range of expected removal
efficiencies. In general, the removal efficiency for PAH by
biodegradation is inversely proportional to the molecular
weight of the compound; the greater the number of rings, the
more difficult the removal.
245
-------
Land-destined wastes include excess residue, quenched
ash, sulfate sludges from the power plant scrubbers, elemental
sulfur (if it is not sold), spent catalyst, effluent water
biotreatment sludge, sanitary sewage biotreatment sludge,
water clarifier sludge, the mine and associated coal pre-
paration by-products (mainly tailings), and community and
related industrial wastes.
A typical biological oxidation system will produce
large amounts of cellular material in the form of sludge
which must be disposed of, for example, by landfilling or
incineration. This may introduce some pollutants, particu-
larly trace elements, into the atmosphere and waterways. The
sludge from the biological oxidation unit may also create
odor problems.
Coal tars and derivatives have a long history of car-
cinogenicity including occupational cancer among chimney
sweeps in London in the late 1700s, recognition of car-
cinogenicity of coal tar, and occurrence of cancer among
coke plant workers. Direct hydrogenation of coal to produce
coal liquids has particular potential for producing environ-
mentally and occupationally troublesome materials.
The very structure of coal, and the hydrogenating
conditions used for liquefaction, indicate that more poly-
cyclic compounds will be formed than found, for example, in
petroleum products. The coal liquefaction products will be
more analogous to coal tar industry products than to petro-
leum products. In general, many of the polycyclic compounds
are known to be carcinogenic and therefore potentially more
hazardous to the environment than the aliphatic hydrocarbons
that constitute most of the petroleum fractions.
246
-------
Several known inorganic carcinogenic substances (e.g.,
nickel, arsenic, etc.) will also be present in coal lique-
faction products and waste products. These inorganics may
appear either as volatile or particulate emissions, con-
taminants of coal chemicals, and/or components of the
carbonization residue.
Inorganic trace elements in the waste products of coal
liquefaction may be present in several chemical forms. The
biological origin of coal indicates that porphyrin-type
compounds may be present and may survive the liquefaction
process. Porphyrins are important carriers of vanadium and
nickel in crude oil. The relatively high partial pressures
of carbon monoxide may also result in the formation of
traces of carbonyls, especially in the cases of the transi-
tion series metals. Nickel, iron, and cobalt carbonyls are
the most significant carbonyls in the petroleum industry.
With the exception of ferrocene, Metallocenes (metal atoms
sandwiched between two aromatic rings), if formed, will
probably decompose, especially in the cases of nickel,
chromium, vanadium, tantalum, molybdenum, and tungsten.
Some metals form arene carbonyls (metal atoms sandwiched
between an aromatic ring system and carbon monoxide) which
may be more stable than their metallocene counterparts and
must be considered as one of the most likely types of
organometallics to be found in coal liquids. The possible
presence of metal alkyls must not be overlooked. Several
metal and metalloid elements form relatively stable organic
hydrides of the general formula RnMH^_n where R represents
an organic group, M represents a metal, and H represents
hydrogen. These hydrides may be formed in the reducing
atmosphere of the liquefaction process and, once formed, are
relatively stable. The possibility that metal chelates
(with phenolic OH, carboxylic acid, and amine acid groups)
may be present should be considered.
247
-------
The discussion of the effects of sulfur and nitrogen
oxides is limited, since these compounds are essentially
associated with fossil-fuel combustion and would not be
expected to be formed in the reducing atmosphere of the coal
liquefaction processes.
One aspect of coal liquefaction that does have potential
for significant sulfur and nitrogen emissions is the plant
combustion of fuel for power and steam generation. High-
sulfur bituminous coal may be used without processing as the
fuel source for steam generation. Considerable controls
would be required to reduce sulfur oxides emission to
levels acceptable for meeting present pollution standards
for similar industries.
COAL COMPOSITION AND WASTES
Coal is a complex organic material including inorganic
trace metals and metallic compounds, bound nitrogen and
sulfur, inert earth-like gangue, and high molecular weight
carbon-containing matrices. Tables 70 and 71 give typical
concentrations of various elements in coal. The numbers in
parentheses are the range of data. The data of Table 72
summarize the data in Tables 70 and 71, providing some
statistical treatment.
Tables 73 and 74 give the concentrations of elements
that have been found in various coal-associated waste products.
References to "filtered aqueous COED effluent dryer stage
liquor" and "filtered aqueous COED effluent product separator
liquor" in Tables 73 and 74 refer to aqueous effluents of a
single experimental run of a coal conversion plant. The
248
-------
TABLE 70. COMMONLY DETERMINED TRACE ELEMENTS IN COAL (PPM)
Reference
64
65
66
67'
68
£
53 Coals from
the Eastern
Interior Sea ion
51 Coals from
the Northern Great
Plains Region
13 Coals frm
the AppiUchitn
3egioA
Washington
State
UAiv. Study
West
Virginia
Penn.
Eist
*.».
Ala
va.
Tenn.
m.
West
*/• j
)nd.
Mont.
Kyo.
New
Me*.
am.
AliflBtrw* (At)
Antiaony ($6)
3.2*1.3
Arseoic (As)
8.02*0.3
9
16
6
13
10
9
6
7
7
<6
1
2
2
Barii* (Be)
366*35
70
79
110
99
120
49
44
31
380
170
270
39
Seryiliy® (Be)
2.5
1.5
2.5
3.2
0.8
1.5
0.74
1.1
0.58
1.3
1.4
1.7
1.5
2.4
0.94
O.o?
Bora" JB)
*
Ufi
25
15
19
30
U
24
81
70
85
60
36
43
49
firontne (Br)
21.4*0.7
Umim (U)
2.9
<0.1
0.46
<2.6
<0.54
Calcftc (Ca)
U%im (Cs)
Chlorine (CI)
1020*90
Chreaiua (Cr)
20
7
13
21*2
19
24
19
19
20
19
29
18
19
3
5.8
11
9.7
CoUU (Col
18
2.7
5.1
6.1*0.4
17
IB
15
18
14
13
15
16
24
7.7
5.2
15
Copper (Cu)
11
15
15
11
13
11
14
13
tl
8.3
8.8
9.7
3.2
4.4
5.9
4.?
Europ't* (Cu)
0.33*0.04
Fluorine (F)
70
90
30
90
50
120
59
50
70
160
16U
70
GiUit* (6a)
4.1
5.5
4.9
fienMMlvB (te)
13
1.6
5.8
Hlfiriwi (Mf)
0.74*0.08
MiM (I)
Iran (F«)
8920*40
UtifeMN* (U)
5.1
9.5
9.4
11.9*0.5
L**4 (ft)
4.9
5.2
4
3.7
6.1
4.9
33
6.4
7.2
4.6
0.61
4.7
3.9
(Li)
44
64
78
75
34
36
45
16
24
27
19
16
19
•Ugnesii* (*ti)
Manganese (Ma)
21
21
26
19
42
23
73
19
26
57
14
19
9. *
Mercury (H9)
0.12
0.2©
0. IB
0.08
0.0?
0.05
0.06
0.^
MolyDdeeu* (Mo)
4.3
1.7
3.5
6.2
9.6
5.2
11
8.3
7.8
8.8
7.4
5.2
4.8
2.2
2.0
0.97
Nickel (Hi)
IS
7.2
14
21*3
16
20
16
17
22
16
25
16
33
3.3
4.1
8.1
4.9
Phosphorus (P)
PoUSSttM (It)
3300*1100
Miiiia (lb)
23*2
(Sc)
3.90*0.38
SelMiH ($e)
3.66*0.4
3.4
3.7
3.1
5.1
4.4
4.9
2
3.1
4
3
0.8
Z.O
Z.I
Silicon (Si)
SoOtiM (Via)
424*19
$tro*tiu« (Sr)
142*20
Sulfur (S)
TmUIm (Ta)
0.33*0.05
tovrim (Th)
3.3*0.2
Tie (Sn)
1.3
0.9
0.4
1,5
1.1
4.6
2.2
7.3
1.8
2.6
2.5
0.74
1-1
1.4
1.9
0.97
7it«niitfc (Ti)
4S0
591
3V)
1135*56
Uroniwi (0)
toMdiw (V)
35
16
21
40*5
30
33
29
31
33
34
35
32
35
1?
15
25
9.7
tttrim (V)
7.7
13
14
2i«c (Zft)
17
22
15
2?
23
23
140
48
73
42
37
19
9- 7
linmim (2r)
44
M
7.*
63
6B
CO
56
44
45
Bt
17
100
77
39
no
39
(continued)
-------
TABLE 70. (continued)
Rfftrence
6
6a
69
70t
71
r '.ewwt
*V.H' . - v
C#4l«
Utah Coal
Ppit.
Coal
Standard
Illinois
Basin
Apoa'achtar
Coal Fields
'J. 5
P
t.. na N»ne
tian
Lo**?r Oefcoven
*>w.
Will Scarlett
fine. in.
Minimj City
,'frv
KCTtjCk-y
111inois
Frrtv-*'Oht
*nr If
an)
32 '<0.8-220)
5.9 (c 1.0-18)
3.4 (<0.70-9.0)
~0.02
*0.02
<0.02
35
l»t*»u«i {Li)
Nagnesi** ftta)
<2,000
<1.000
<10.000
4.400
500 (100-1.700)
600 (200-1.500)
1,400 (300-3.900)
500
(Hn)
5
1.42
2S.2
53 {6.9-210)
18 (2.4-61)
49 '<1.4-220)
12
125
4
50
'Vlury (hg)
0.012
0.05
3.73
0.2 (0.0J-J.6)
0.20 { 0-06-0.47)
0.09 (0.1)2-0,63)
0.2
Mo1>t>deftu« {Ho)
5
1.65
3.73
8.1 ( f.3-29)
4.6 ( 0.10-22)
2.1 (<0 10-30)
0.06
12
4
5
3.1
Nickel (*i>
15
121
4.400
20
21 (7.6-66)
1$ (6.1-26)
5.0 (1.5-18)
12
25
4
20
i;
Phosphorus (P)
*4 (<10-340)
150 (15-1,500)
130 (10-510)
70
PottSSil* (M
1.000
2.800
5.000
3.300
3.700 (400-5.600)
2.500 (600-6,800)
500 (100-3,200)
1.600
ftubidiun (11b)
100
<5
28.8
23
19 ('2.0-46)
22 (9.0-63)
4.6 (<0.30-29)
5candiu» (Sc)
s
Mi
n?
3.9
2.7 {1.2-7.7)
5.1 {1.6-9.3}
1.8 (0.50-4.5)
Selefiuw (S«)
3
10.4
7.2
3
2.2 (0.4-7.7)
4.0 (1>1-8.1)
1.4 (0.»0-2.7)
2
Silicor. (Si)
24.000 (5.800-47.000)
28.000 (10.000-63.000)
17,000 (3,800-47.000)
25,000
Sodiu* (la)
2.000
10.3CO
1.900
«2G
500 (--2.000)
400 (100-800)
1,400 (100-6.0001
5.000
2,500
150
500
5ta»nt>i*» (Sr)
150
35 (<10-130)
130 (20-550)
260 (93-500)
Sul'uf (*)
36.(W (5,600-64.000]
23.000 (5,500-50,000)
7.600 0.400-19.000)
Tantalus (fa)
0-3
0.15 (0.07-0.3)
0.33 (0.12-).))
0.15 (0.04-0.33/
ThOTfti* (T|»)
3
2,1 (0.71-5-1)
4.5 (1.8-9.0)
2.3 (0.62-5. 7)
tin (5i»)
3.3 {<0.2-51)
2.0 (<0.20-8.0)
1.9 (<0.10-15)
5
1.3
Titanfu" (Ti)
1.100
600 (200-1.500)
900 (500-1.600)
500 (200-!.*00)
75
400
450
700
250
(UJ
1
1.0'
2.03
1.5 (0.31-4.6)
1.5 (0.40-2.9)
1.2( *-0. 30-2 5)
Vanadim (»)
?<>
40
32 (il-90)
38 (14-73)
14 (4.3-43)
12
50
4
30
13
Utrit* (!)
7.4
ZiK U«)
50
19.0
42.9
250 (10-5.300)
25 (2.0-120)
7.0 (<0.30-17)
25
125
<0.05
270
108
(Zr)
1
47 (12-130)
45 (6.0-88)
31 (12-170>
70
-------
TABLE 71. TRACE ELEMENTS IN COAL THAT ARE NOT COMMONLY DETERMINED (PPM)
Average (Range)
Reference
48
67
68
Element
Illinois
Basin
Appalachian
Coal Fields
Western
U.S.
L'tah
Penn.
Wyo.
New
Hex.
Ariz.
Cerium (Ce)
14 (4.4-46)
25 (11-42)
11 (2.8-30)
Dysporsium (Dy)
1.1 (0.5-3.3)
2.3 (0.74-35)
0.63 (0.22-1.4)
Gold (Au)
0.03
0.06
Indium (In)
0.16. (<0.01-0.63)
0.23 (0.13-0.37)
0.10 (<0.01-0.25)
Lutetium (Lu)
0.09 (0.02-0.44)
0.22 (0.04-0.40)
0.07 (<0.01-0.43)
Samarium (Sm)
1.2 (0.4-3.8)
2.6 (0.87-4.3)
0.61 (0.56-2.2)
Silver (Ag)
0.03 (0.02-0.08)
0.02 (0.01-0.06)
0.03 (0.01-0.07)
Tellurium (Te)
0.025
0.03
<0.02
Terbium (Tb)
0.02 (0.04-0.65)
0.34 (0.06-0.63)
0.21 (0.06-0.58)
Thallium (Tl)
0.66 (0.12-1.3)
Tungsten (W)
0.82 (0.04-4.2)
0.69 (0.22-1.2)
0.75 (0.13-3.3)
Ytterbium (Yb)
0.56 (0.27-1.5)
0.83 (0.18-1.4)
0.38 (0.13-0.78)
-------
TABLE 72. SUMMARY OF TRACE ELEMENTS IN COAL (FROM TABLES 70 AND 71)
Element
Number
of
samples
Arithmetic
mean
Geometric
mean
Standard
deviation
Standard error
of the mean
Range
AlumLnun
4
13000
12,761
2900
1500
10,000-17,000
Antimony
8
2.1
1.6
1.5
0.5
0.48-5
Arsenic
22
9.4
6.5
8.1
1.7
0.8-34.9
Barium
19
188
131
158
36
31-500
Beryllium
24
1.3
1.1
0.6
0.1
0.2-2.5
Boron
24
49
37
34.
7.
7-116
Bromine
8
16
14
10
3
4.7-36.1
Cadnium
14
2.6
1.1
4.1
1.1
0.1-16.2
Calcitm
7
7500
6200
4900
1800
2000-17000
Cesiun
5
1.1
0.75
0.84
0.37
0.11-2.0
Chlorine
6
1100
990.
490
200
300-1700
Chromium
29
16
14
8.4
1.6
1.5-39.4
Cobalt
28
10
8.0
6.6
1.2
1.02-25
Copper
27
12
11
5.2
1.0
3.2-25
Europiun
5
0.32
0.31
0.12
0.054
0.2-0.52
Fluorine
16
81
74
37
9
30.-160
Gallium
9
4.2
3.9
1.7
0.56
2.0-7
Germanium
9
5.3
4.0
3.7
1.2
0.91-13
Hafniun
5
0.81
0.79
0.24
0.11
0.54-1.2
Iodine
3
1.3
1.1
0.68
0.39
0.52-1.7
Iron
9
13000
11000
7400
2500
2890-24300
(continued)
-------
TABLE 72. (continued)
Element
Number
of
samples
Arithmetic
mean
Geometric
mean
Standard
deviation
Standard error
of the mean
Range
Latharon
12
9.5
9.0
3.3
0.95
5.1-15
Lead
20
8.3
2.6
11
2.5
0.02-35
Lithitxn
13
38
33
22
6.1
16-78
Magnesiixn
8
2600
1400
3300
1200
500-10,000
Manganese
23
31
21
28
5.8
1.42-125
Mercury
15
0.15
0.10
0.17
0.04
0.012-0.73
Molybdenum
27
5.2
3.9
3.2
0.61
0.08-12
Nickel
29
170
17
830
150
3.3-4480
Phosphorus
4
104
97
43
22
64 -150
Potassium
9
2400
2000
1400
460
500-5000
Rubidium
8
28
19
30
11
4.6-100
Scandiun
8
3.7
3.4
1.6
0.57
1.43-5.89
Selenium
22
3.6
3.1
2.1
0.44
0.8-10.4
Silicon
4
23500
23000
4700.
2300
17000-2800C
Sodium
12
2100
1100
2900
840
150-10300
Strontium
5
140
120
80
36
35-260
Sulfur
3
22000
18000
14000
8200
7600-36000
Tantalum
5
0.25
0.24
0.094
0.042
0.15-0.33
Thorium
5
3.0
2.9
0.95
0.43
2.1-4.5
(continued)
-------
TABLE 72. (continued)
Element
Number
of
samples
Arithmetic
mean
Geometric
mean
Standard
deviation
Standard error
of the mean
Range
Concentrations in ppm
Tin
19
1.8
1.6
1.0
0.24
0.4-4.6
Utaniun
12
600
510
310
90
75-1135
Uranium
6
1.4
1.3
0.38
0.16
1 -2.03
Vanadium
26
27
24
11
2.2
4 -50
Yttrium
3
12
11
3.4
1.9
7.7-14
Zinc
23
57
27
73
15
<0.05-270
Zirconium
20
59
52
24
5.4
7.6-110
Cerium
3
17
16
7.4
4.3
11-25
Dysporsiun
3
1.3
1.2
0.86
0.50
0.63-2.3
Gold
2
0.045
0.042
0.021
0.015
0.03-0.06
Indiun
3
0.16
0.15
0.065
0.037
0.10-0.23
Lutetian
3
0.13
0.11
0.081
0.047
0.07-0.22
Samarium
3
1.5
1.2
1.0
0.59
0.61-2.6
Silver
3
0.027
0.026
0.0058
0.0033
0.02-0.03
Telluriim
3
0.025
0.025
0.0050
0.0029
<0.02-0.03
Terbiun
3
0.19
0.11
0.16
0.093
0.02-0.34
Thallium
4
0.375
0.34
0.21
0.10
<0.02-0.66
Tbngsten
3
0.75
0.75
0.065
0.038
0.69-0.82
Ytterbiim
3
0.59
0.56
0.23
0.13
0.38-0.83
-------
TABLE 73. CONCENTRATION (PPM) OF ELEMENTS IN VARIOUS
COAL-ASSOCIATED WASTE PRODUCTS
Reference
72
73.74
67
75
Element
West
Virginia
coal refuse
Anthracite
ash
Law-volatile
bicuminous ,
aah
Medium-
volatile
bituminous
ash
High-volatile
bituminous
ash
Lignite
ash
Coal
lique-
faction
"fly ash"
Filtered
aqueous COED
effluent-dryer
stage-liquor
Filtered
Aqueous COED
effluent-product
separator-liquor
Aluminum (A1)
>25,000
0.3
3.0
Antimony (Sb)
6.9+0.5
0.003
0.007
Arsenic (As)
60.7+2.4
0.2
0.04
Barium (Ba)
866
740
896
1253
5027
2700+200
0.02
0.02
Beryllium (Be)
0.2-3
9
16
13
17
6
<0.0005
0.001
Boron (B)
90
123
218
770
1010
1.0
1.0
Cadmium (Cd)
0.25-1.0
<0.003
0.01
Calcium (Ca)
50-2000
Chromium (Cr)
3-25
304
221
169
193
54
128+5
0.03
0.6
Cobalt (Co)
3-25
81
172
105
64
45
41.8+1.3
0.005
0.5
Copper (Cu)
12-50
405
379
313
293
655
0.02
5.0
Gallium (Ga)
3-25
42
41
40
23
<0.005
<0.005
Germanium (Ge)
<20
<20
0.005
0.001
Hafnium (Hf)
7.0+1.1
<0.005
<0.001
Iron (Fe)
7500-41,000
6.25+0.2
15.0
790.0
lathanum (La)
142
110
83
111
62
82+2
<0.001
0.05
Lead (Pb)
20-150
81
89
96
183
60
0.003
1.0
Magnesium (Ha)
500-8000
1.0
50.0
Manganese (Hn)
65-1300
270
280
1432
120
688
496+12
0.003
15.0
Nickel (Ni)
25-250
220
141
263
154
129
0.03
10.0
Potassium (K)
500-1200
1.72+0.00
Rubidium (Rb)
125+10
0.005
0.06
Scandium (Sc)
3-25
61
50
56
32
18
27.3+1.0
< 0.001
<0.001
Silicon (Si)
>25,000
Silver (Ag)
0.3-2.5
<1
<1
<1
<1
<1
<0.005
<0.005
Sodium (Na)
150-375
3200+300
Strontium (Sr)
177
818
668
1987
4660
1700+300
Tantalum (Ta)
1.67+0.13
<0.1
<0.1
Thorium (Th)
2.54+1.5
<0.001
<0.01
Tin (Sn)
962
92
75
171
156
<0.005
0.1
Titaniun (Ti)
300-3000
7400+300
0.05
0.3
Vanadium (V)
25-250
248
278
390
249
125
235+15
0.003
0.02
Ytterbium (Yb)
8
10
9
10
4
<0.003
<0.005
Yttrium (Y)
3-25
106
152
151
102
51
Zinc (Zn)
30-85
231
195
310
0.2
5.0
Zirconium (Zr)
3-25
688
458
326
411
245
1 0.01
g.l ,
-------
TABLE 74. TRACE ELEMENTS IN COAL LIQUEFACTION
WASTE PRODUCTS WHICH ARE NOT COMMONLY DETERMINED (PPM) (75)
Element
Filtered
aqueous COED effluent
dryer stage liquor
Filtered
aqueous COED
effluent product
separator liauor
Gold
<0.005
<0.5
Bismuth
<0.002
0.07
Bromine
<0.005
0.05
Cerium
<0.001
<0.01
Cesium
<0.005
<0.005
Dysprosium
<0.003
<0.005
Europium
<0.003
<0.005
Mercury
< 0.003
0.007
Indium
< 0.001
<0.003
Iridium
<0.003
<0.003
Lithium
<0.003
<0.003
Lutetium
<0.003
<0.005
Molybdenum
0.05
0.5
Niobium
<0.003
<0.005
Neodymium
< 0.003
<0.003
Polonium
< 0.0005
<0.001
Praseodymium
<0.001
<0.05
Radium
< 0.01
<0.01
Selenium
0.003
0.3
Samarium
< 0.003
<0.003
Terbium
<0.003
<0.003
Tellurium
<0.003
<0.003
Thallium
<0.003
< 0.003
Uranium
0.003
0.01
Tungsten
0.002
0.03
256
-------
"dryer stage liquor" is the condensate from the drying of
coal. The "product separator liquor" is water produced
during the hydrogenation process.
Table 75 gives the background levels or "normal" concen-
tration ranges of various elements in the environment which
can be used to estimate whether the increased input of the
elements resulting from the coal liquefaction will signifi-
cantly increase the levels in the environment. Unfortunately,
these tables are based on general data and cannot be used to
indicate definite effects at specific sites.
Table 76 gives the concentration of various organic
compounds found in different effluents and receivers. It
can be used in a manner similar to Table 75 with similar
restrictions. The presence and distribution of each in-
dividual pollutant in the air, water, land-destined wastes,
or product are discussed below.
Table 77 shows factors for various elements which can
be used to estimate the expected concentration of the element
in the. coal-associated waste product or the amount leached
per day if the concentration in the coal or the amount in
the associated receiving body of water or stream is known.
Table 78 provides information on 13 elements regarding
their relative concentrations in the feed coal, product oil,
and solids waste from liquefaction processing.
QUANTITIES AND COMPOSITION OF PROCESS AND NONPROCESS WASTE
DISCHARGES
An attempt is made to quantify the various wastes from
auxiliary processes discharged after receiving commonly
257
-------
TABLE 75. CONCENTRATIONS OF ELEMENTS IN VARIOUS RECEIVERS OF EFFLUENTS
Element
Igneous rock
(pp«n)
Soils
(ppn)
Fresh water
(ppra)
Sea water
(ppm)
A
Marine
plants
(ppm)
J! 1
V)
Marine
animals
(ppm)
land
animals
(ppm)
References
Aluninum
82,000
10,000-300,000
0.24
0.01
<3
60
0.5-4000
10-50
4-100
76,77
Antimony
0.2
2-10
1.3-9. SxlO"4
2.1-5.1x10"^
<0.004
0.016-0.260
0.06
0.006-0.011
0.006
76
Argon
3.5
0.6
0.6
9300
76
Arsenic
1.8
0.1-40
0.000003-267
0.002-0.03
< 0.01
0.7-142.0
0.01-31.9
0.005-150
<0.1-0.8
76,77,78,79
Barium
425
100-3000
0.054
0.000001-0.03
23-30
14-4000
1
o
0.75
76,77
Beryllium
2.8
0.01-40
0.00001-0.0012
6-20x10 ~7
<0.0001
0.001-0.66
0.01-2.00
0.01-0.36
<0.0003-0.002
76,79
Bisraath
0.17
1.7x10"5
0.06
0.04-0.3
<0.004
76
Boron
10
2-100
0.013
4.6
120
50
20-50
0.5
76
Bromine
2.5
1-10
0.2
65
740
15
60-1000
6
76
Cacbiun
0.2
0.01-0.7
<0.005-0.012
l.lxlO"4
5-20
0.4
0.04-0.5
0.01-151.6
<0.5
76.77.78,79
Calcium
41,500
7000-500,000
15
400
< 2
10,000-300,000
18,000
1500-350,000
200-85,000
76
Cerium
60
50
4xHf4
320
<0.03
76
Cesium
1
0.2-25
2x10"'*
5x10"^
0.07-0.39
0.01-22
0.064
76,77,80
Chlorine
130
100
3.9-2,019
19,000-20,000
1.2
4700
2000
5000-90,000
2800
76,79
Chraniiin
100
5-3000
a.onoi-0.050
5xl0~5
<0.002
1-6
0.18-224
0.2-108
0.075
76,77,79,80
Cobalt
25
1-40
9x10"'*
2.7x10"4
<7xl0"4
0.7-12
0.04-2.8
0.5-5
0.03
76,78,80
Copper
55
2-100
<0.001-0.01
0.003
< 0.02
11
0.5-56
0.73-2208
2.4
76,79
Fluorine
625
30-300
0.09
1.3
<0.01
4.5
0.5-40
2
150-1500
76
Galliun
15
0.4-300
<0.001
3xl0~5
0.5-1
0.06
0.15-0.5
<0.006
76,77
Germanium
5.4
1-50
7xlO"5
0.3
76
Hafniun
3
3-6
< 8xl0~6
<0.4
<0,01
0.04
76
Helios
0.008
6.9xl0"6
5.2
76
Iron
56,300
1360-550,000
0.67
0.01
<3
200-3370
50-1420
400
160
76,80
fairtuwn
30
1-5000
1.2xl0"5
0.05-10
0.085-370
0.1
0.001-0.27
76
Lead
12.5
2-200
<0.001-0.890
0.00002-0.0081
0.2
6.7-8.4
2.7
0.1-42
0.2-2
76,77,79
Lithium
20
7-200
0.0011
0.18
5.4
0.1
1
<0.2
76,77
Magpesium
23,300
600-6000
4.1
1350
<1
5200
3200
5000
1000
76
Manganese
950
100-4000
0.012
0.002
<0.01
53
630
1-60
0.02
76
Mercury
0.08
0.01-180
8xl0"!>-4.0
3x10"12.2
0.03
0.01-10.68
0.005-1.57
0.008-67.9
76,77,79
Molybdenun
1.5
0.2-5
3.5X10"4
0.01
< 0.0005
0.45
0.9
0.6-2.5
<0.2
76
(continued)
-------
TABLE 75. (continued)
1
Ejfiwnt
Igneous rock
(ppn)
Soils
(ppm)
Fresh water
(ppn)
Sea water
(PF«a)
Air
Oig/n?)
Marine
plants
(ppn)
Land
plants
(ppn)
Marine
animals
(ppm)
Land
animals
(ppn)
Reference
Iteodyndim
28
5
<460
0.5
Nickel
75
6-40
0.01
<0.001-0.130
<0.002
3-17
0.05-134
0.03-25
0.8
14
20
1x10" 3
0.3
<0.001-300
76,77,79
nioepboxus
1050
650
0.005
0.07
3500
2300
4000-18,000
17,000-44,000
76
Pblanius
2*10"iu
76
Potass iun
20,900
400-30.000
2.3
380
52,000
14,000
5000-30,000
7400
76
Praseodjraiiii
Radius
8.2
fcdlf7
8xl0"7
3.9x10"10
6xl0"U
9x10"®
s46
10"9
S0.5
0.7-15x10"®
7xl0"9
76
76
Baden
4JC10"13
1.7x10"15
6x10"16
76
Ai>ldiuB
90
5-100
0.0015
0.12
7.4-47
1-115
20
17
76,77,80
Sawriun
6
0.0055-23
0.04-0.08
0.01
76
ScandLun
22
0.5-9
4k10'6
0.07-0.45
0.001-3.3
6xlO"5
76,80
Selmiin
0.05
0.05-12.0
0.0001-9
0.00005-0.00011
0.84
0.2
0.5-4
1.7
76,77,80
MHmi
281.500
330.000
6.5
3
<4
1500-20.000
200-5000
70-1000
120-6000
76
Silver
0.01-0.09
l3d0"6-260
bd0"6-19.6
0.01-2.42
0.02-2.7
1x10"4-83.6
76
Sodiim
23.600
750-7500
6.3
10,500
1.1
33,000
1200
4000-48,000
4000
76
Strontiua
375
300
0.08
8.1
260-1400
26
20-500
14
76,77
Tar>f-a1i«n
2
<2.5xl0"6
410
76
Telluruin
0.001
2-25
76
Uialliiai
0.45
0.1
<0.001-0.130
<1.4x10" ""-0.0130
<0.4
76.77.79
Thoriun
9.6
5
2xl0"5
5xl0"5
0.45
0.003-0.03
0.003-0.2
76,80
Till
2
2-200
4xl0"5
0.003
<0.01
1-17
<0.3
0.2-20
0.15
76,77
Titaniim
5700
5000
0.0086
0.001
<0.01
12-80
1
0.2-20
<0.2
76,77
Ungsten
1.5
1
0.0001
0.035
0.07
0.0005-0.05
0.00025-0.005
76
Ucaniim
2.7
1
0.001
0.003
0.038
0.004-3.2
0.013
76
Vfradim
135
100
0.001
0.002
<0.001
2
1.6-3.5
0.14-2
0.15
76,77
Ytterbim
3
<0.0015-23
0.02
1.2x10"*
76
Yttriim
33
50
3xl0"4
<0.6-830
0.1-0.2
0.04
76
Zinc
70
10-805
0.0003-5
0.001-0.0500
<0.07
38-150
1-840
0.5-1500
160
76,79,80 •
Ziroonim
165
300
0.0026
2.2xl0"5
<20
0.64
0.1-1
<0.3
76 1
-------
TABLE 76. CONCENTRATION (PPB) OF ORGANIC COMPOUNDS IN
VARIOUS EFFLUENTS AND RECEIVERS OF EFFLUENTS (79)
Compound
Industrial effluent
Municipal
eff1uent
Natural
waters
Drinking
water
supplies
Finished"
drinking
water
Acenapthene
+
1.7
Fluoranthene
+
0.352-16.35
0.140-0.360
0.026-0.169
0.015-0.090
Isophorone
275 metric tons/yr
<0.02
Ethyl benzene
12,300 metric tons/yr
+
+
Toluene
691,800 metric tons/yr.
(40-280 ppb)
<1-150
+
<0.1-0.7
Benzene
87,000 metric tons/yr
<0.2-40
18-40
+
<0.1-0.3
Phenol
24,235 metric tons/yr
(43,300-4,347,000 ppb)
ca. 100
<1.3-360
Naphthalene
252 metric tons/yr
(780-32,000 ppb)
3-50
1.0-1.4
Benzidine
0.0045-140 ppb
<0.1
<0.2
<0.2
+ » detected but not quantified.
-------
TABLE 77. LEACHING CHARACTERISTICS OF H-COAL SOLID WASTE (81)*
Argon
Air
pH 'Value
pH Value
Element
11.31
8.50
5.53
2.30
8.83
8.16
5.01
3.14
Aluninum
8.7xl0-5
2.9*10-5
8.7xlO"5
3.3xl0-4
1.7xl0-4
< 2.9xl0~5
< 2.9xl0-5
3.2xl0-4
Aatlaony
< 0.3
<0.3
<0.3
<0.3
<0.3
< 0.3
< 0.3
< 0.3
Arsenic
< 0.67
<0.67
<0.67
<0.67
<0.67
< 0.67
< 0.67
< 0.67
Barlw
< 2.5xl0-3
< 2.5xl0~3
<2.5xl0~3
< 2.5xl0~3
<2.5xl0-3
< 2.5xl0~3
< 2.5xl0"3
< 2.5xl0-3
Beryllium
< 5.6x10"3
< 5.6xl0~3
<5.6xl0~3
<5.6xl0"3
<5.6xl0-3
< 5.6x10"3
< 5.6xl0-3
< 5.6xl0~3
Baron
3.7xl0-2
A.lxlO"2
4.3xl0~2
S.OxlO-2
3.7xl0~2
4.3xl0"2
3.9xl0"2
4.5xl0"2
Cadaitai
0.075
0.075
0.075
0.075
0.075
0.075
0.075
0.075
Calclw
1.7xl0~2
2.0xl0-2
5.4xlO~2
6.2xl0-2
1.4xl0~2
2.2xl0"2
4.8xl0"2
6.3xl0~2
Chlorine
7.8xl0~2
7.0xl0-2
7.5xl0"2
6.4X10"2
7.5xl0"2
7.1xl0"2
6.7xl0~2
7.5xl0~2
ChrcaluB
< 7.3xl0~4
<7.3xl0"4
< 7.3xl0"4
1.8xl0-3
< 7.3xl0~4
< 7.3xl0-4
< 7.3xl0-4
l.lxlO-3
Cobalt.
< 0.022
<0.022
< 0.022
< 0.022
< 0.022
< 0.022
< 0.022
< 0.022
Copper
< 3.6xl0~3
<3.6xl0"3
< 3.6xl0-3
< 3.6xl0"3
< 3.6xlO~3
< 3.6x10"3
< 3.6xl0-3
< 3.6xlO"3
Fluorine
7.0xl0~3
1.2xl0-2
8.5xl0-3
8.4xl0-3
l.OxlO-2
1.2xl0~2
6.0xl0"3
8.6xl0~3
Iron (total)
< 4.2X10"6
<4.2x10"®
2.7xlO"4
3.8xl0-3
< 4.2xl0-6
< 4.2xl0-6
5.9xl0-4
1.3xl0-3
Lead
< 3.0x10'3
<3.QxlO"3
4.7xl0~3
6.QxlO-3
< 3.0xl0~3
< 3.0xl0-3
6.0xl0~3
7.8xl0"3
Magneslim
7.1xl0~4
9.5xl0"4
3.6xl0"3
4.7xl0-3
5.9xl0~4
7.IxlO-4
3.2xl0~3
4.7xl0-3
Manganese
< 2.6xl0"4
5.2X10"4
2.2xl0~2
3.5xl0"2
< 2.6xlO-4
1.3xl0"3
2.4xl0-2
3. 3xlO-2
Molybdenum
< 0.03
<0.03
< 0.03
< 0.03
< 0.03
< 0.03
< 0.03
< 0.03
Nickel
< 3.3*10'3
< 3.3xl0~3
< 3.3xl0~3
1.2xl0"3
< 3.3xlO~3
< 2.3xl0-3
< 3.3x10"3
< 3.3xl0"3
PotaaaiuB
4.8xl0-4
6.0xl0-4
8.0xl0-4
l.OxlO"3
5.6X10"4
5.6xl0-4
8.4xl0~4
l.lxlO"3
Silicon
< 2.5x10"5
<2.5xl0-5
< 2. 5x10""'
< 2.5xl0'5
< 2.5xl0-5
< 2.5xl0"5
< 2.5xlO-5
7.6xl0-5
Sodiun
l.lxlO-2
l.lxlO"2
l.SxlO"2
l.lxlO-2
l.lxlO-2
1.2xlO-2
1.5xl0"2
Strontiun
6.7xl0-3
8.7xl0-3
1.3xl0~2
1.6xl0~2
6.7xl0"3
8.0xl0-3
l.lxlO"2
1.7xl0"2
Sulfate
0.109
0.110
0.118
0.123
0.109
0.114
0.248
0.161
Thallium
< 0.2
<0.2
< 0.2
< 0.2
< 0.2
A
O
< 0.2
< 0.2
Tin
< 2
<2
< 2
< 2
< 2
< 2
< 2
< 2
Titanlua
< 5.9xl0~4
<5.9xl0~4
< 5.9X10"4
< 5.9xl0~4
c 5.9xl0~4
< 5.9xl0"4
< 5.9xl0-4
< 5.9xl0-4
Vanadium
< 0.02
<0.02
< 0.02
< 0.02
< 0.02
< 0.02
< 0.02
< 0.02
Zinc
2.8X10-4
2.8xl0~4
1.7xl0~3
l.lxlO"2
1.4xl0"4
1.4xl0~4
8.5xl0~4
3.8xl0"3
*TJ* values In table 77 ace ratio* of the eleaent concentration in the supernatent liquor of a 10%
aqueous slurry of H-Coal solid waste to the element concentration in the sedinent or precipitate. The
slurry was adjusted dally to the pH shown until the pH remained constant. This took about 3 months.
Only then was the supernatent concentration aeasured. Atmosphere in the saaple container was either
argon or air as shown.
-------
TABLE 78. ELEMENT CONCENTRATION RATIOS - SOLID WASTE:
FEED COAL AND PRODUCT OIL/FEED COAL (82)
Ratios
Element
Solid residue/
feed coal
Product oil/
feed coal
Beryllium
Boron
Cadmium
4.6(2.0-10.0)
4.6(2.1-6.0)
1.6(1.0-2.5)
6.5(1.0-125)xl0~3
7.2(4.3-12.5)xl0~3
Chromium
Cobalt
Copper
2.2(1.0-3.2)
2.6(0.5-5.0)
3.8(2.1-5.7)
2.3(0.8-4.1)xl0~3
2.4(0.83-4.8)xl0"3
1.4(1.2-1.7)xl0"3
Manganese
Molybdenum
Nickel
8.2(2.1-20.0)
4.2(3.3-5.0)
2.8(0.4-5.0)
5.9(1.0-12.5)xl0"3
4.2(0.0-8.3)xl0"4
7.7(3.2-12.5)xl0~3
Sodium
2.9(0.2-5.3)
2.7(1.0-6.0)xl0~3
Titanium
Vanadium
Zinc
1.8(0.5-2.8)
5.0(2.1-10.0)
2.0
2.8(0,11-6.7)xl0"2
3.7(1.0-5.0)xl0~3
2.9(1.0-4.8)xl0~3
262
-------
available treatment methods. Quantities and compositions
are discussed in the multimedia context - airborne, waterborne,
and solids waste emanating from the H-Coal, Synthoil, and
EDS processes. The auxiliary processes include sulfur
recovery, oxygen and hydrogen generation, water treatment
and utility plants, and water cooling. An attempt is also
made to characterize the major contaminants in liquefaction
products and by-products.
Process Related Wastes, After Treatment
Essentially all materials entering the coal lique-
faction plant may be accounted for in the final products or
in the gas, liquid, or solids effluents. Because the lique-
faction process development is in its early stages, however,
detailed balances are not possible. These balances would
give the quantity and chemical composition of the various
inorganic and organic contaminants that may be discharged
into, and ultimately interact with, the biotic and abiotic
environments. Instead, the aim has been to make order of
magnitude estimates and, wherever possible, state estimates
as a jrange of values.
Airborne Wastes - Process Related--
The main point source for discharging process-related
airborne wastes is in the tail gas streams from the sulfur
recovery plant. Detailed composition of these streams is
given in Section 7 (Table 66). Trace quantities of carbonyl
sulfide (0.01 to 0.04 mole percent), and carbon disulfide
(0.01 to 0.05 mole percent) could also be present (82).
Process-related flue gases are not likely to be a major
source of airborne pollutants if by-product fuel gas is used
in the preheaters and for process heat. This gas is purified
263
-------
by acid gas treatment and is relatively free of contaminants.
If the preheaters are coal-fired, pollution control technology
would most likely be needed to meet regulatory standards for
new coal-fired stationary sources.
Waterborne Wastes - Process Related--
Efficiencies for removing pollutants from -waste-waters
were discussed in Section 7 and are very useful for the
quantification of contaminants entering water and land
environments around coal liquefaction plants. In spite of
the very efficient removal of some organics, such as phenols,
from wastewaters in biological oxidation treatment ponds,
multi-ring aromatic compounds, including the simplier poly-
cyclics such as naphthalene, will likely pass undegraded
through the biotreatment plant. Furthermore, substituting
nitrogen or sulfur heteroatoms in multi-ring compounds or
the alkylation of benzene retards microbial oxidation rates
(33,84). Similarly, monohydric phenols are more fully
degraded than polyhydric compounds. The polyaromatic phenols
would be expected to be degraded even more slowly (83).
Thus, both microbial oxidation and adsorption of organics to
sediment appear highly dependent upon molecular size, with
adsorption being significant only for compounds of two rings
or higher (83).
Table 72 gave mean concentrations of trace elements in
a number of U.S. coals. One distribution of selected elements
(85) shows that most will be found in the process residues
and in the final product. Based on the initial concentration
of selected trace elements in the feed coal, the percentage
discharged in the scrubber effluent from the Synthoil bench-
scale unit is shown below (85):
264
-------
Element
Cu
Cr
Mn
Ni
Cd
Pb
percent of initial
concentration in
the feed coal
2.7
2.1
0.04
0.3
3.1
14
Calculations using these data and the arithmetic average
initial concentrations of elements for the coal given in
Table 72 show that the concentration of these elements in
the sour water from the Synthoil process is:
Element
Cu
Cr
Mn
Ni
Cd
Pb
Concentration
(ppm)
0.3
0.3
0.01
0.5
0.08
1.2
Some of this metal content, along with the sludges generated,
will be removed in the biological treatment system. Whether
the residual metal content in the process wastewater will
still be high enough to require treatment cannot be deter-
mined at this time. Analysis of process wastewaters is
needed. Based on the concentrations above, the quantities of
the trace elements discharged with 3,785 m /day of process
related wastewater will be:
Element
Cu
Cr
Mn
Ni
Cd
Pb
Quantity
discharged
(kg per day)
1.1
1.1
0.04
1.8
0.3
4.4
Besides the trace inorganic elements present in the
wastewater as a result of their concentration in the feed
coal, minute quantities of inorganic gases formed in the
265
-------
process would be dissolved in the wastewater discharged
after treatment. After stripping and wastewater treatment,
concentrations of hydrogen sulfide and ammonia are assumed
to be less than 10 ppm and 2 ppm respectively. Thus, for
3,785 m /day of wastewater discharged, total hydrogen sulfide
and ammonia discharged with the process related wastewater
are less than 0.04 and 0.006 metric tons per day, respectively.
Organic compounds (mostly phenols) will be present in
the wastewater as dissolved and emulsified components,
primarily of the lighter portion of the product oil.
Tables 19 and 37 show the constituents of the lighter fractions
of the product oils from the Synthoil and H-Coal processes.
The only conclusive data on the presence of specific organics
in the process wastewater before and after treatment is
available for the phenolics. All other organics are usually
categorized as oil and grease (86). For this report, treat-
ment by stripping, and biological oxidation and carbon
adsorption is assumed. From Reference 65 and calculations
in Section 8 (Table 69), residual concentrations of phenolics
in the wastewater discharged after treatment will be about
0.1 ppm; that is, 0,04 kg lbs for each 3,785 m of wastewater
discharged.
Table 79 gives residual concentrations in the effluent
from the wastewater treatment of selected constitutents of the
light fraction of the Synthoil product. The assumptions for
the columns are that 10, 20, or 40 ppm of light oil passes
unchanged through the treatment system. Table 79 indicates
that individual nonpolar aromatic compounds in wastewater
will generally be present in less than 1 ppm concentration.
Also, treatment should make the actual concentrations of these
266
-------
TABLE 79. CONCENTRATION OF POTENTIAL ORGANIC
POLLUTANTS IN THE WASTEWATER EFFLUENT FROM THE
SYNTHOIL PROCESS, COMPOUND CONCENTRATION (PPM) (29)
Total Light Oil
Compound
10 ppm*
20 ppm*
40 ppm*
Benzene
0.1
0.2
0.4
n-dodecane
0.03
0.06
0.12
Naphthalene
0.01
0.02
0.04
Toluene
0.15
0.3
0.6
n-propylbenzene
0.01
0.02
0.04
Indan and propyltoluene
0.36
0.72
1.44
Isopropylbenzene
0.2
0.4
0.8
*This amount of oil is assumed to pass unchanged through the
treatment system.
compounds much lower. Again, analytical results are required
for wastewater samples to pinpoint organic composition and
content more accurately.
In addition to light oil organics, it is likely that
known polycyclic carcinogens may be present at ppb levels.
Table 80 shows the extent of the oxidation of some of these
materials. Data are given as a percentage of the amount of
compound originally present which was degraded by three
different activated sludges after 144 hours. These data
suggest that biodegradation is not uniform and cannot be
depended upon to reduce the level of any specific compound
in the effluent streams. Also, the oxidation of any one
compound does not necessarily imply that the carcinogenic
activity has been reduced. In some cases, metabolic oxida-
tion of PAH in other systems has been known to increase the
carcinogenic potential; in others, it has decreased the
potential (87).
A typical biological oxidation system will produce
large amounts of cellular material in the form of sludge
267
-------
TABLE 80. OXIDATION OF VARIOUS CARCINOGENS
BY ACTIVATED SLUDGES* (87)
Ashland"
City
Nashville
Franklin
Mean
Cocpound
B-Propiolactone
55.9
T
T
18.6
Thiourea
T
5.7
1.9
Ethylcaibamate
T
T
T
0.0
2-Thiouracil
T
12.8
6.2
6.3
4-Ethoxyphenylurea
T
9.4
20.6
10.0
Benzidine
X
T
1.9
0.6
4,4'-Dihydraxy[ a, fc] diethyls tilbene
T
T
5.0
1.7
2-Naphthylamdne
T
T
T
0.0
4,4' -Bis ( dimethylamino) benzophenone
0.6
4.9
4.5
3.3
p-Phenylazophenol
T
T
T
0.0
p-Fhenylazoaniline
T
T
T
0.0
9,10-Wmethylanthracene
0.0
19.5
1.6
7.0
1,2-Benzanthrscene
0.3
2.1
1.6
1.3
7-Methyl[l,2]benzanthracene
0.4
3.1
T
1.2
9,10-Dlinethyl[l, 2]benzanthracene
0.5
12.7
0.5
4.6
1,2,5,6-Dibenzanthracene
T
7.9
0.9
2.9
3,4-9enzopyrene
1.7
2.7
6.1
3.5
1,2,4,5-Dibenzpyrene
T
1.8
T
0.6
20-Methylcholanthrene
T
9.3
4.4
4.6
2-Nitrofluorene
T
13.7
12.4
8.7
2-Fluorenamine
T
T
T
0.0
N- 2-Fluorenylacetand.de
T
6.3
12.3
6.4
7,9-Diroethylbenz[0]acrldine
T
4.1
T
1.4
7,10-Dime thylbenz [ 0] acrldine
T
4.3
1.1
1.8
Wben2[
-------
which must be disposed of, for example, by incineration
(84). This may introduce some pollutants, particularly
trace elements, into the atmosphere. Also, the sludge from
the biological oxidation unit may create odor problems (84).
Thiophenes appear in smaller quantities than phenols.
The efficiency of their removal by wastewater treatment is
unknown. The PAH are expected to compose the smallest quantity
of the organic load with a wide range of removal efficiencies
expected. In general, the removal efficiency is inversely
proportional to the molecular weight of the compound; the
greater the number of rings the more difficult the removal.
In addition to pollutants in process wastewater, waterborne
discharges to the environment could also be present through
leaching of disposed residues, ashes, and bottoms. Some
indication of the equilibrium concentrations of 14 inorganic
elements in aqueous extracts of fly ash (1:1 wt/vol) is
presented in Table 81. The equilibrium concentrations of the
various elements shown are rather innocuous, except for
fluoride's 5 ppm.
TABLE 81. CHEMICAL COMPOSITION OF EQUILIBRIUM AQUEOUS
(1:1 WT/VOL) EXTRACTS FROM FLY ASH*
(CONCENTRATIONS IN PPM) (88)
Chemical
Concentration
Chemical
Concentration
Ca
632
Mn
0.04
Na
41.25
Cu
0.03
K
8.2
Zn
0.025
A1
11
Mo
0.02
B
3
Hg
0.0005
F
4.7
Cd
0.005
As
0.0002
Se
0.002
"^Collected in a cyclone precipitator in the stack of the
Corette Plant of the Montana Power Co. in Billings, Montana.
269
-------
Solid Wastes-
Carbonaceous solid wastes emanating from coal lique-
faction processes generally require some treatment before
disposal. For example, the char and heavy oil residuals may
be sent to gasification and converted either to fuel gas or
to hydrogen-rich gas. The residual mineral matter can then
be sent to the ash pond. In lieu of this, the heavy residuum
plus char may be treated (e.g., flaked) and disposed of in
a suitable landfill. Excess oil may be recovered from the
residuum before disposal of the waste. Whichever approach
is used, the heavy residuum plus chars cannot go directly to
landfill without prior treatment, since they are considered
to contain potentially hazardous organic and inorganic
substances.
Other process-related solid wastes include coal dusts
and fines (particulates) from cyclone separators, fabric
filters, and electrostatic precipitators; mineral debris
from coal processing; mineral residues from water processing;
spent catalyst and water treatment chemical residues; ash
and fly ash; and slags (82). Solid wastes of major importance
to coal conversion processes include the ash, filter cake,
particulates, and spent catalyst. Waste gypsum sludge (the
lime-limestone mixture used in tail gas scrubbing) will be
about 2,5 times the normal coal ash disposal tonnage. Possible
uses for the ash and sludge combination wastes from tail gas
scrubbing are as mineral aggregates or as pozzolana (82).
Ash--Ash from the conversion process may be either dry (as
fly ash and particulates), melted (as slag), or softened (self-
agglomerates) (89). The daily output of ash from a coal
3
conversion plant producing about 7,950 m /day of oil will
range between 1,600 and 3,600 metric tons per day. Ash composi-
tion will vary, depending upon the origin and rank of the coal
270
-------
and the operating conditions in the conversion process. Major
ash constituents include SiC^ (46 percent), Al^O^ (26 percent)
and Fe20g (18 percent). As shown in Table 82, numerous in-
organic elements may appear in coal ash. They include
mercury, cadmium, selenium, fluorine, arsenic, copper, lead,
and thallium.
Particulate matter (e.g., soot and fly ash) is reported
to be environmentally significant as adsorption sites for
PAH (82). Leachates of coal ash comprise a significant
source of trace metal contaminants. This source was discus-
sed and shown in Tables 77 and 81. Radioactive uranium and
thorium are known to occur in fly ash but pose no health
hazard. However, recovered fly ash may contain large quan-
tities of alpha-emitting radionuclides which could have
adverse health effects if the necessary precautions are not
taken during disposal (82) .
Mineral matter, such as ash or slag, would be generated
in large quantities in all liquefaction facilities. The
following chart indicates that the sources and quantities
(metric tons per day) may differ substantially.
Stream Synthoil H-Coal Exxon Donor
Process ash (not sent 108.0 393.7 661.3
to hydrogen generator)
Ash from hydrogen 2,115.6 1,159.4 1,548.6
generation
Ash from utilities 556.1 none not specified
(use fuel gas)
Note: The above numbers are from Section 7 and represent those
from conceptualized 7,950 nn/day commercial plants using
carbon-containing residues for hydrogen generation.
271
-------
TABLE 82. INORGANIC ELEMENTS IN THE ASH FROM LURGI
GASIFIER AND THE MINERAL RESIDUE FROM THE H-COAL
PROCESS UTILIZING ILLINOIS NO. 6 COAL (89)
Element
Concentration
(ppm5
Name
Symbol
IfVirgi-
H-Coal
Aluminum
A1
108,121
17,253
Antimony
Sb
4.2
1.2
Arsenic
As
3
1.5
Barium
Ba
950
40
Beryl Hum
Be
12
1.8
Boron
B
355
300
Bromine
Br
<1.0
6.7
Cadmium
Cd
<1.6
<0.4
Calcium
Ca
16.652
7.862
Cerium
Ce
140
16
Cesium
Cs
11
1.7
Chlorine
CI
100
1.000
Chromium
Cr
212
27.5
Cobalt
Co
34
4.45
Copper
Cu
57
14
Europium
Eu
1.9
0.69
Fluorine
F
<10
100
Gallium
Ga
2.6
4.6
Germanium
Ge
7.0
4.9
Gold
Au
<0.001
Hafnium
Hf
6.1
0.86
Iron
Fe
143,780
23,662
Lanthanum
La
47
9.8
Lead
Pb
45
32
Lithium
Li
42
Lutecium
Lu
1.5
0.024
Maenes ium
Mr
3.739
844
Manganese
JMn
1,859
77
Mercury
Hg
0.05
6.4
Molybdenum
Mo
30
Nickel
Ni
89
21
Phosphorus
P
87
44
Potassium
K
14.611
2.490
Rubidium
Rb
162
16
Samarium
Sm
10
2.3
Scandium
Sc
29
4.1
Selenium
Se
<1
Silicon
Si
229,946
39,641
Silver
Af?
<0.4
0.16
Sodium >
Na
1,929
619
Strontium
Sr
370
- 30
Sulfur
S
18.000
Tantalum
Ta
1.1
Tellurium
Te
<0.1
Thallium
T1
4.6
1.7
Thorium
Th
Z1
3.5
Tin
Sn
0.6
Titanium
Ti
6.295
1,019
Tungsten
W
1.5
4.4
Uranium
U
17
5.7
Vanadium
V
184
33
Ytterbium
Yb
1.0
Yttrium
Y
2.9
Zinc
Zn
400
71
Zirconium
Zr
170
41
272
-------
Ash generation is significantly lower in the H-Coal process
because fuel gas is used for utilities, and residue is sub-
stituted for coal in hydrogen generation.
From burning of solid fuel, combustion wastes consist of
fly ash and slag or bottom ash. In coal-fired power plants
and utility boilers, the slag is roughly 30 percent of the
total ash and is almost completely recovered from the bottom
of the boiler. About 99.5 percent of the remaining fly ash is
assumed to be retained by pollution abatement equipment (89).
In general, trace elements tend to partition and concen-
trate themselves during combustion as follows:
• Class I. Elements that are not volatilized in the
combustion zone, but instead form a rather uniform
melt that becomes both fly ash and slag. These
elements include Al, Ba, Ca, Ce, Co, Eu, Fe, Hf,
K, La, Mg, Mn, Rb, Sc, Si, Sm, Sr, Ta, Th, and Ti
(89).
• Class II. Elements that are volatilized on combus-
tion, and condense or adsorb on the fly ash as the
flue gas cools, leading to depletion from the slag
and concentration in the fly ash. These elements
include As, Cd, Cu, Ga, Pb, Sb, Se, and Zn (89).
• Class III. Elements that remain almost completely
in the gas phase. These elements include Hg, CI,
and Br (89).
Some elements in coal could not definitely be assigned to
either Class I or II on the basis of the data obtained in the
study (89).
273
-------
Filter cake--Filter cake is produced in the solids-
liquid separation module of some liquefaction processes.
Combustion of the filter cake produces a slag that requires
disposal to landfill or minefill.
Spent catalysts--Catalysts can be discharged as spent
catalyst, lost through abrasion and escape into the ash, or
become incorporated into product streams as ultrafine parti-
culate matter (90). Typical catalysts are cobalt-molybdate
and nickel-tungsten. A general list is shown in Table 83
(82). The most severe catalyst losses are for dolomite in
the CO2 Acceptor process reported to be two percent of the
input (91). Replacement catalyst for an H-Coal process
pilot plant was reported to be about 0.05 percent of the
charged initial weight (90).
Auxiliary Process Wastes
Airborne Wastes--
The airborne wastes from auxiliary operations include
coal preparation discharges, wastes from the hydrogen and
oxygen plants, stack gases and particulates from the utility
boiler after stack gas cleanup, and moist cooling tower drift
(22). As shown in Section 7, Figure 38, dusts generated from
the coal receiving, coal storage and coal beneficiation units
amount to about 32 metric tons per day. The waste stream
from the oxygen generation plant consists largely of inert
nitrogen and noble gases. Hydrogen generation facility
wastes are discussed in detail in Section 6.
PAH concentrations in fly ash collectors at a coal-fired
power plant are shown in Table 84; the PAH are considered to
be products of the incomplete combustion of coal. The first
seven compounds are of interest in that several are considered
274
/
-------
TABLE 83. CONVERSION CATALYSTS (82)
Catalysts
Use
0* Activated carbon
Purification
0 Iron oxide
Purification
* Methanol
Purification
* Propylene carbonate
Purification
+ Sodiun carbonate
Purification
+ Potassiun carbonate
Purification
* Amines
Purification
Monethanolandne
Purification
Diethanolandne
Purification
Diglycolamine
Purification
0 Zinc oxide
Purification
Cobalt-mo lyb derm
Shift conversion, liquefaction
(hydrotreating), purification
0 Limestone-dolomite
Sulfur recovery
+ Molten salt
Nickel
Methanation or liquefaction
Vanadium
0 Dolomite
Purification
Bauxite
Sulfur recovery
Iron
Shift conversion or liquefaction
* Isopropyl ether
Phenol recovery
* n-Methyl-2-pyrrolodine
Purification
* Dimethyl ether polyethylene glycol
Purification
KjAsOj
Liquefaction
Tungsten
Liquefaction
Zinc chloride
Liquefaction
* Sodiun sulfite
Purification
Co-Mo/Si02-Al203
Liquefaction
Sulfoxide
Sulfur recovery
Chelated iron salt
Sulfur recovery
Nickel-tungsten
Liquefaction (hydrotreating)
Butheniun
Methanation
*Not catalysts as used
+ Enter into chemical reaction
0 Primarily (if not exclusively) adsorbents
275
-------
TABLE 84. POLYNUCLEAR HYDROCARBON CONCENTRATIONS -
UNITS A AND B* (MICROGRAMS PER GJ INPUT) (92)
Compound b a
Unit A**
Full load
b a b a b
Partial
a
load
b
a
Unit B
Test No. 3
Full load
a
Fluoranthene 341 NA
171 190 NA 180 303
360
1422
72
209
Pyrene 133
123 171 114 171
209
749
64
114
Benzo(a)pyrene 47
21 17 17 54
48
379
114
17
Anthanthrene 15
30
Benz(a)anthracene
35 44
95
Benzo(ghi)perylene
18
142
72
Benzo(e)pyrene
31
36
218
68
Coronene
4
Anthracene
91
Phenanthrene
701
19
Perylene
58
3
* A and B refer to operating steam generating units.
**Units A and B produced 453.6 Mg steam at 13.1 MPa and 538°C, coal-fired power plant.
b = before fly-ash collectors a = after fly-ash collectors
NA — No analysis due to loss of sample. A blank Indicates that the component was not detected
in the sample.
-------
to be carcinogenic. According to Cuffe et al. (92), fly ash
collectors can effectively remove 85 to 90 percent of the
particulates, and essentially the same efficiency was seen
in the removal of common trace and heavy metal compounds
such as Ba, Be, Fe, Pb, Cr, Cu, Sn, Sb, Mn, Ni, Mo, V, Ti,
Zn and Co.
As discussed in Section 7, the airborne wastes emanat-
ing from the steam and power generation units will discharge
345 metric tons per day of sulfur dioxide and traces of NOg
before treatment. This is based on the use of 3,480 metric
tons per day of coal for steam and electricity production,
and the assumption that the sulfur content was 5 percent.
Evaporation from the cooling tower was estimated at about
21,600 metric tons per day, assuming that the cooling tower
makeup was 22,700 metric tons per day (see Section 7).
Waterborne Auxiliary Process Wastes--
Coal pile drainage--Chemical wastes and inorganic
elements characteristic of coal pile drainage are shown in
Table 85. Amount of drainage depends on area rainfall.
Composition of the drainage depends on factors such as coal
composition and whether or not the pile is covered.
Hydrogen generation wastewater--The hydrogen generation
facilities for a 7,950 m /day coal liquefaction plant will
have approximately 1,500 m^/day of wastewater, roughly
similar in composition to the liquefaction process waste-
water. In actual practice, wastewater streams from the
liquefaction process and hydrogen generation will probably
be combined and treated.
277
-------
TABLE 85. CHEMICAL WASTE CHARACTERISTICS OF COAL PILE DRAINAGE (PPM) (68)
Arithmetic
Geometric
Standard
Standard Error
Characteristic
n*
mean
mean
deviation
of the inean
Ranee
Alkalinity
8
20.0
0.0
28.1
9.9
0-36.41
BOD
4
3.3
0.0
4.7
2.4
0t10
as
5
820
615
434
194
85-1,099
"total solids
6
11,200
5,070
17,000
6,900
1,330-45,000
"total dissolved solids
7
12,600
3,600
17,000
6,500
247-44,050
"total suspended solids
7
830
340
1,140
430
22-3,302
AhdcuIzi
5
0.69
0.00
0.82
0.37
0-1.77
Nitrate
5
1.31
0.93
0.94
0.42
0.3-2.25
Phosphorus
2
0.72
0.53
0.69
0.48
0.23-1.2
TXirbixlity
5
200
32
270
120
2.77-505
Acidity
5
9,900
216
13,700
6,000
8.68-27,810
Total hardness
4
800
430
840
420
130-1,850
Sulfate
8
6,900
2,200
8,800
3,100
133-21,920
Chloride
4
130
19
240
118
3.6-481
Almrfraw
2
1,000
990
260
190
825-1,200
ChroBriim
6
2.7
0.0
6.4
2.6
0.0-15.7
Copper
4
2.1
2.0
0.9
0.4
1.6-3.4
Iron
9
10,900
4
30,800
10,300
0.06-93,000
Magpesiun
2
130
124
60
42
89-174
Zinc
7
5.9
1.0
8.9
3.3
0.006-23
Sodiun
3
890
630
630
370
160-1,260
PH
11
4.4
4.0
2.1
0.6
2.8-7.8
- ember of samples.
-------
Solid Nonprocess Wastes--
Mining waste and coal preparation tailings--Approxi-
mately 18,000 metric tons per day of coal will be cleaned of
rock, pyritic sulfur, and other wastes. In addition, as
much as 50 percent of the mine extract in an underground
mine may be waste. While there is little problem with
backfilling strip-mining wastes into the mined area, under-
ground backfilling is hazardous and costly.
Ash--The largest quantities of ash are generated in
hydrogen generation and in the utilities. The quantities of
auxiliary process ash generated were discussed previously in
the process solid waste subsection. Once ash has been
buried in a landfill or the coal mine, its constituent
elements and compounds may leach into groundwater.
Flue gas desulfurization sludge--Removal of sulfur
dioxide from flue gases is a support service required for
all coal liquefaction processes via their steam and electric
power generation facilities and for direct-fired heaters.
Removal methods include at least two processes which result
in a waste sludge by-product. The sludge, composed mainly
of calcium sulfite, calcium sulfate, and water, is dewatered
to about 50 percent solids, and then is transferred to
settling ponds. Often a portion of the fly ash will be
mixed with limestone scrubber sludge in order to make the
mixture easier to handle (93).
As can be seen in Table 86, the solids content varies
with scrubber type. Table 87 shows the sludge composition
following the treatment designated in Table 88. Ponds A and
D represent untreated sludge samples. Treatment with the
Dravo, IUCS, and Chemfix processes represent chemical fixa-
tion methods. Differences in the sludges are more likely
to manifest themselves in leachate compositions (93).
279
-------
TABLE 86. SHAWNEE POND DATA (93)
Pond
designation
Scrubber Sludge Solids Treatment
type absorbent/source content, wt% contractor
Venturi/spray
tower
Lime/filter cake
46
Untreated
Turbulent con-
tact absorber
Limestone/clarifier
underflow
38
Dravo
D
Venturi/spray
tower
Turbulent con-
tact absorber
Lime/centrifuge cake 55
Limestone/clarifier
underflow
38
XU conversion
systems
Untreated
Turbulent con-
tact absorber
Limestone/clarifier
underflow
38
Chemfix
TABLE 87. SHAWNEE DISPOSAL DEMONSTRATION INPUT
SLUDGE ANALYSIS RECORD (93)
Pond "A"*
Sample date 9-23-74 Not given 10-5-74
Liquor analysis:**
pH 8.80 8.35 7.95
Total akalinity
61
Chloride
3,604
4,600
4,833
Conductivity
10.0
12
12.4
Dissolved solids
7,110
8,560
9,460
Sulfate
974
1,525
1,488
Arsenic
0.024
Boron
44.0
Calcium
1, 980
2,100
2,675
Lead
0.49
Magnesium
313
290
212
Mercury
<0.0001
Selenium
0.005
Sulfite
64
4.3
32
Sodium
56
79
Solids analysis:***
Total solids
15.7
24.3
Calcium sulfite
46.5
38.6
Calcium sulfate
11.8
14.1
Calcium carbonate
3.4
3.9
Fly ash
42.5
46.9
(continued)
280
-------
TABLE 87. (continued)
Pond "D"*
Sample date
10-3-74
10-21-74
1-15-75 Not given 2-5-75
Liquor analysis: (mg/1)
PH
9.05
8.80
7.80 8.21 7.15
Chloride
2,694
2,765
1,
560 1,450 1,843
Conductivity
4.9
5.2
3.05 5.7 5.35
Dissolved solids
6,400
6,845
3,
010 5,852 3,700
Sulfate
1,491
1.700
2,
253 2,500 2,484
Arsenic
.24
Boron
90
Calcium
1,780
1,920
917 1,100 1,330:
Lead
.26
Magnesium
253
262
395 255 332
Mercury
<0,0001
Selenium
0.040
Sulfite
48
72
24 16 24
Sodium
56
58
41 42
Solids analysis: (wt.%)
Total solids
36.5
37.2
33.3
Calcium sulfite
30.4
33.1
30.9
Calcium sulfate
14.5
17.7
16.6
Calcium carbonate
31.8
19.7
16.9
Fly ash
37.9
34.7
38.3
Pond
"E"*
Pond "C"* Pond "B"*
4-13 and
Sample date
Not given 4-6-75
4-23-75 4-15-75
Liquor analysis:
pH
9.43
8.35
7.75 7.08
Chloride
2,450
2,871
5,566 2,375
Conductivity
6.4
10.0 5.43
Dissolved solids
5,960
6,980
11,010 6,140
Sulfate
1,175
1,672
1,578 1,368
Calcium
1,995
3,275 1,368
Magnesium
165
309 387
Sulfite
72
88 120
Solids analysis:
Total solids
25.1
22.2 40.6
Calcium sulfite
40.8
38.5 31.8
Calcium sulfate
12.5
15.4 18.6
Calcium carbonate
3.6
3.8 20.9
Fly ash
46.1
46.5 34.8
* See Table 86
** All liquor concentrations in ppm
***A11 solids analyses in weight percent
281
-------
TABLE 88. COMPARISONS OF PRODUCTS AND PROCESS PARAMETERS OF COAL LIQUEFACTION
PLANTS AND SIMILAR INDUSTRIES (EXTRACTED FROM SECTIONS 2 THROUGH 9)
Data from
Exxon
other liquefac-
Petroleuie
By-Product
Synthoil
H-Coal
Donor
tion processes
refining
coking
Gasification
Process temperature
460°C
454°C
450°C
450°C
50°C*
1500°C
1850°C
tot tor pressure
27.6 MPa
20.7 MPa
12.4 MPa
345 kPa
103 kPa
103 kPa
Ash Z In feed
16.5
9.3
9.6
8.0
Ash Z in product oil
0.1
0.0
Nitrogen Z in feed
X.2
1.0
1.84
0.1
1.5
1.4
litrojeo Z in oil
Maptha Oil
0.06 0.24
Sulfur Z in feed
5.5
4.5
4.2
0.5
1.0
3.5
Sulfur Z in gas
0.1
0.01
Sulfur Z in light oil
0.2
0.1
0.005
0.1
0.1
Sulfur Z in heavy oil
0.4
0.5
0.04
1.0
Sulfur Z char, tar or
8.7
7.2
2.5
2.7
reslduua
Ben*o(d)pyr«e I in oil
0.004
0.005
0.003
0.2-2.0
Product distribution
Table 5
Table 5
Figure 53
Metric tons/day based on
7,950 a3 barrels
Gas
662
2050
590
Light oil
1542
Naphthas
Naphthas
1542
2966
Liquid by-product
1134
Middle dis-
Middle dis-
tilate 390
tilate 4935
Heavy oil
6250
6187
53
Char, tar or residuw
(extra)390
5688
4309
Table Bog.
16
30
43
5**
5,91**
Figure 53,90
Composition tables
General composition
93
89,92
Crude oil analysis
Fuel gas analysis
32
Light oil analysis
19
89
¦aphthas 50
Heavy oil analysis
22,24,93
89
Oil 50
Kesidue analysis
25-27,93
Carcinogenic compounds
98,123
PAH analysis
26,94
96
Trace elements
99
Sulfur analysis
22
39
91,92
'Atmospheric distillation 30-60°C (138-414 kPa)
thermal cracking conditions 480-603°C (4.1-6.9 KPa)
Hydrotreating 314-427°C (0.7-20.7 KPa)
"•Data not based on 7,950 «3/day production.
No entries mean data was either not available, not applicable, or not
Included In reference reports.
-------
On the basis of sulfate sludge generated in support of
gasification facilities, a reasonable estimate has been made
of the quantities of sludge to be formed in support of
liquefaction facilities. A BI-GAS gasification plant util-
izing 0.6 x 10 kg/hr of steam and 42 MW of electricity will
cause the generation of 484 metric tons per day of spent
limestone sludge through the operation of its utility power
plant (93). Considering the utility requirements for the
coal liquefaction processes under study, this figure may
represent the average quantity of sludge generated for all
the processes.
Bio-Pond sludge--Twenty-seven metric tons per day of
bio-pond sludge is expected to be generated. This amount is
nominal, compared to the total volume of solids waste gener-
ated by a conversion plant. However, the bio-pond will
treat phenols, ammonia, cyanides, COD, thiocyanates, and
other environmentally significant wastes, so proper disposal
of the sludge is imperative. When the sludge has formed and
has been removed from the pond, it will contain coal tars,
sand, coal fines, and bio-treatment by-products. Prior to
disposal, it will probably be de-oiled and either air-dried
or centrifuged.
Water treatment sludge--The water clarification unit
may treat water containing chemicals from some of the cyclic
processes within the plant. The sludge produced will con-
tain some of these chemicals, as well as lime and settled
suspended solids.
Products and By-Products Composition
In evaluating the potential environmental impact of
coal liquefaction processes, it is important to consider not
only the wastes but the product as well. Product streams
283
-------
are important because their components can be potential
environmental pollutants. Components of the products
(gases, tars, and oils) may appear in the waste streams from
incomplete product or by-product recovery. Hydrocarbons may
be emitted to the atmosphere via incomplete combustion;
through leaks in hydrocarbon storage vessels; from aqueous
effluents of cooling streams; during slurry mixing; or by
emissions of flue gases from coal, char, and oil combustion.
The various liquefaction processes generally produce
products consisting of a gas, light and heavy oils, tars,
and char. The proportion and composition of these products
are affected by variations in the conversion operating
conditions such as temperature and pressure, hydrogen input,
and catalyst, as well as by the constituents in the coal
feed. The interaction and impact of all such variables on
the product character is beyond the scope of this work;
however, the effect of varying any one particular parameter
may be discussed generally. Comparison of liquefaction
process conditions to those utilized by other industries,
such as coking, can also be examined in terms of the
resulting product and its potential hazard to man and the
environment. A summary of comparisons among processes and
products of various fuel conversion and fuel processing
industries is given in Table 88.
Table 88 is a summary of data contained in Sections 2
to 8 of this report. The sources of these data are given
(via table numbers) where the data originally appeared. The
proportion of products distilling off at various fractiona-
tion temperatures varies with the conditions mentioned
above. The product distribution among gas, light oil, heavy
oil, tars, and chars of the processes under examination is
284
-------
given in Table 88. Generalizing from the data gives the
product distributions roughly as: gas, 2 to 10 percent;
light oil, 10 to 25 percent; middle oil, 5 to 50 percent;
and heavy oil, 1 to 45 percent. Such wide variation in
product fractions from the different processes illustrates
the versatility of coal liquefaction technology and the
complexity of assessing its potential environmental impact.
In addition to variation in the amounts of product
fractions, there are variations in the composition of pro-
ducts. The lower boiling fractions consist of products
suitable for gasolines, while the higher boiling fractions
can be utilized as fuel oils. Analyses of product types
from the liquefaction processes are also summarized in Table
88.
One conversion condition that significantly influences
the distribution and composition of products is the process
temperature. The temperature-composition relationship is
illustrated by comparison of high-temperature tars (such as
those produced in by-product coking) and the low-temperature
tars (produced by process temperatures of less than 500°C).
The process temperature affects the proportion of various
types of products (gas, light oil, tars, and coke). This is
illustrated in Figure 67 (94). The chemical composition of
such products also changes with temperature. The tars
produced at low temperatures vary widely in composition with
the nature of the coal and the specific carbonization equip-
ment that is, the temperature program, residence time, and
maximum temperature (95). Such variables compound the
problem of quantitatively characterizing liquid fuels from
coal liquefaction. The one outstanding chemical character-
istic that can be cited for low-temperature tars is the
small amount of any individual compound, a situation common
285
-------
70
65
60'
55
50
45
40
35
30
25
OL
< 20
u_
O 15
UJ
1 10
o
>
>- 5
ca
v? 0
20
15
10
5
0
2
0
t r
PITCH
(RESIDUE BOILING ABOVE 350°C)
H 1 1 H i f-
TriTAi
HYDROCARBONS
naphthalene
OLEFINS
PARAFFINS NAPHTHFNFS
i i
LOWER TAR ACIDS
PHENOL .
3 600 700 800 900 1000 1100
CARBONIZING TEMPERATURE (°C)
e 67. Effect of carbonizing temperature on composition
of tar (laboratory retort; medium caking coal:
~36 percent carbon) (94)
286
-------
to petroleum and shale oil, but completely different from
coke-oven tars in which a single compound like naphthalene
can account for as much as 10 percent of the tar. With low-
temperature tars it is rare for any one compound to con-
stitute as much as one percent of the tar (96). Analysis of
the constituents found in various fractions of liquefaction
products have been presented in Tables 16, 19, 21, 22, 26,
38, and 42. By comparing coal liquefaction products with
crude petroleum and coal tar, the potential hazard of lique-
faction oils can be assessed relative to that of the other
liquid fuels. Semiquantitative analysis of fuel products
from the H-Coal process is shown in Table 89 (97).
Varying the pressure of the reactor also influences the
nature of the products. The effect of increasing or de-
creasing the reactor pressure was demonstrated with the
Synthoil process by comparing the product variation when the
conversion pressure was run at 14,2 MPa versus the results
obtained with 28.4 MPa. The product variation for the two
reactor pressures indicated that the higher pressure caused
an increase in yield and in heating value. The higher
pressure was also accompanied by an increase in hydrogen
consumption. The product from the higher pressure operation
had a lower sulfur content than the product from the lower
pressure operation. Ash yield was higher with the lower
pressure operations (24). The effect of changing the oper-
ating conditions by increasing reactor space velocity in the
H-Coal process greatly reduces consumption of hydrogen per
ton of coal processed. This results in a fuel oil product
instead of a synthetic crude. The various fractions resul-
ting from the two modes of operation were given in Table 5.
The rank and origin of the coal feed influence the
product yield, distribution, and composition. Table 89
287
-------
TABLE 89. INSPECTION OF PRODUCTS FROM ILLINOIS NO. 6
AND WYOMING SUBBITUMINOUS COALS (97)
Compound
Component
We1ght
percent
Total
weight
percent
C4 - 204QC fraction
A
B
A
B
Saturated compounds
nCu
ic5
nCs
^6 " C12
0.10
0.20
0.69
11
0.20
0.20
0.88
13.42
11.99
14.70
Alky! benzenes
^6 - C12
17.55
14.16
17.55
42.91
Saturated naphthenes
Monocycloparaff 1 ns
Dicycl oparafflns
Tr1cycloparaff1ns
42.64
8.50
0.19
36.82
6.09
51.33
16.66
Unsaturated naphthenes
Monocyc1opara ff1ns
Dlcycloparafflns
Tricycl oparafflns
5.32
4.98
0.90
7.71
7.28
1.67
11.20
14.16
Other compounds
Indans
Naphthalenes
Phenols (mol. v»t) - 108, 122,
136, 150
6.4s
0.59
1.0
5.11
0.79
1.71
7.93
7.61
Olefins, dloleflns, etc.
C=
0.02
4.22
4.24
Cs - Cu
204-343°C frelation
100.00
100.3
Saturated compounds
n-paraff1ns
1-paraffins
Monocycloparafflns
Dlcycloparaffins
Tricycl oparafflns
4.8
1.7
14.0
7.9
2.6
8.8
2.1
7.5
2.7
1.1
31.0
22.2
Unsaturated nonaromatfc
Monocycloparafflns
4.3
4.5
4.3
4.5
Aromatic compounds
Alkyl benzenes
Indans & tetrallns
Indenes
Naphthalenes
Naphthalenes
Acenaphthenes (CH )
Acenaphthenes (CX""Y*)
Tricyclics (CnH2|J.J^16
12.6
30.8
5.7
0.2
3.5
4.0
2.2
0.4
6.7
23.2
8.7
12.3
12.7
1.7
0.5
59.6
65.8
Other compounds
Phenols (mol. wt) - 108, 122,
136, 150, 164, 178
Other nonhydrocarbons
2.0
3.10
2.8
4.7
5.10
100.00
, M
100.0
(continued)
288
-------
TABLE 89. (continued)
Total
Compound
Wei ght
weight
Component
percent
percent
S43-493°C fraat-ion
A
B
A
B
Saturated compounds
Paraffins
1.4
7.2
Monocyc1opa ra ffi ns
3.1
1.4
Bi cycloparaffins
0.6
0.4
Tricycloparaffins
0.7
0.6
Tetracycloparaffins
0.4
0.5
Pentacyclopa raffi ns
0.2
0.3
Hexacycloparaffins
0.1
0.3
Phenyls
0.3
6.8
11.1
Unsaturated nonaromatic
Paraffins
0.0
0.6
Monocyc loparaf fins
0.5
0.7
Bicycloparaffins
0.3
0.1
Tricycloparaffins
0.2
Tetracycloparaffins
0.2
Pentacycloparaffins
0.1
Hexacycloparaffins
0.1
0.1
Phenyls
0.2
1.6
1.5
Other compounds
Alkyl benzenes
3.0
0.2
Indans and/or tetralins
0.5
Other aromaticsa
72.8
74.0
Phenolic compounds
1.5
0.6
Other nonhydrocarbons
13.3
12.6
91.6
87.4
100.00
100.0
Illinois No. 6 coal
Wyoming subbituminous coal
JAn approximate breakdown
Component type
Naphthalenes •
Phenanthrenes
Chrysenes
1-2 Benzanthracenes
3-4 Benzphenanthrenes
Pyrenes
5-Ring compounds
of aromatic-type
MilUmoles
A per 1009
93.4
91.1
21.9
14.6
15.4
5.1
compounds is:
n Hillimoles
" per 100 q
91.7
116.7
26.1
15.2
19.2
5.1
289
-------
illustrates the product variation as a result of using
Illinois No. 6 and Wyoming subbituminous coal (97).
A major concern with regard to the effect of process
temperatures on product composition is that higher tempera-
tures tend to produce greater quantities of compounds known
or suspected to be carcinogenic. Such information is signi-
ficant in assessing the potential hazard of coal liquefac-
tion products in comparison to other fuels and chemical
source materials such as petroleum crude and coal tars. It
has been observed that coal tars produced at higher tempera-
tures are far more carcinogenic than those produced at lower
temperatures. Studies have shown that carcinogenic agents
were formed in very small amounts below 450°C, increased
rapidly between 450 and 560°C, and continued to increase at
a lower rate over the range 560 to 1250°C (94,98). This
increase in carcinogenicity is generally considered to be a
result of the increase in PAH with the increase in tempera-
ture. An illustration of the increase in aromatic (and
potentially in the PAH compounds) with higher process tem-
peratures is shown in Table 90; the composition of conden-
sable compounds from coal gas is compared when the source is
a high-temperature coke oven versus a low-temperature
retort. The oil from low-temperature carbonization resembles
that of crude petroleum in being highly paraffinic whereas
that derived from coke oven gas is predominantly aromatic.
Epidemiology studies reveal a greater incidence of cancer
among coke plant workers than for the general population of
the same area. No increased cancer incidence was found
among petroleum refinery workers.
As an example of an industrial chemical concentration,
benzo(a)pyrene (BaP), a well-studied carcinogen in coal tar,
has been found in coal liquefaction products at much lower
concentration than has been noted for coal tar. Analyses of
290
-------
TABLE 90. COMPOSITION OF CONDENSABLE COMPOUNDS
FROM COAL GAS* (99)
Coke**
oven
Low-temperature
retort***
Mono-olefins
1.64
16.26
Dienes
2.48
1.36
Cyclo-olefins
5.37
9.55
Paraffins
0.34
46.53
Naphthenes
0.21
8.00
Aromatics
85.26
15.56
Indene
1.13
0.15
Carbon disulfide
0.40
0.06
Thiophenes
0.67
0.66
Other compounds
2.50
1.87
* Percent by volume
** Coke ovens generally operate at temperatures around 1500°C
***Less than 500 or 600°C
various oils have determined BaP levels for coal tar; coal
liquefaction oil, and petroleum of 0.2 to 2.0 percent,
0.005 percent, and 0.003 percent, respectively (100,101).
The carcinogenic significance of the similar BaP levels for
petroleum crude and coal liquefaction oil versus the much
higher level in coal tar has not been demonstrated in labora-
tory animal studies. That is, the carcinogenic potential of
the product oil or coal tar as a whole has not been shown to
be directly correlated with the level of any one individual
291
-------
carcinogen. Such studies are underway and are expected to
elucidate this area. Whether the relatively low process
temperatures of coal liquefaction actually produce fewer
specific carcinogens in the fuel product than are formed at
higher temperatures in similar products from the coking
industry has not been determined.
Data on the chemical compositions of petroleum- and
coal-derived products are given in Tables 91 through 96.
Table 91 gives the chemical analyses of four petroleum
crudes by the categories of aromatic, naphthalene, and
paraffin, with similar data for H-Coal products given in
Table 92. The analytical data illustrate the relatively low
aromatic content of crude oils in comparison to that found
in the liquefaction product oils, as well as the general
tendency to have larger percentages of aromatic compounds in
the higher boiling fractions. Table 93 gives the comparison
between the compound structural types found in heavy oil and
asphaltene fractions of Synthoil product, and illustrates
the general pattern of the higher boiling fractions having a
greater percentage of PAH. Tables 94, 95, and 96 give
estimates of PAH concentrations in various coal-derived
materials. These PAH levels in liquefaction product oil can
be compared to the levels found in particulate matter
emitted by incineration and open burning. Generally, the
levels of the PAH compounds determined for Synthoil product
were in the range of those found for the emitted particu-
lates from some commercial incinerators as shown in Table
97.
292
-------
TABLE 91. CHEMICAL ANALYSES OF PETROLEUM"* (6)
1. Qxizny ("W#i
paraffin"), 45.3 per
omt at 411°C
2. Grozny ("paraffin-
free i4>per level"),
40.9 percent at 411°C
3. Oklahoma (Daven-
port) , 64 percent at
4ll°C
4. California (Hunt-
ington Beach) 34.2
percent at 411°C
Fraction
°c
Aromatic
Naphthme
Paraffin
Aromatic
Naphthene
Paraffin
Aromatic
Naphthene
Paraffin
Arccatic
Naphtliene
Paraffin
60-95
3
25
72
4
31
65
5
21
73
4
31
65
95-122
5
30
65
8
40
52
7
28
65
6
48
46
122-150
9
35
56
13
52
35
12
33
55
11
64
25
150-200
14
29
57
21
55
24
16
29
55
17
61
22
200-250
18
23
59
26
63
11
17
31
52
25
45
30
250-300
17
22
61
35
57
8
17
32
51
29
40
31
*A11 values given in weight percent
^ TABLE 92. H-COAL PRODUCT COMPOSITION (97)
vO
LO
Component
204-343°C fraction
(weight percent)
343-492°C fraction
(weight percent)
Saturated nonaromatics
31.0
6.8
Unsaturated nonaromatics
4.3
1.6
Aromatics
59.4
76.3
Phenols
2.0
1.5
Ifonhydrocarbon
3.3
13.8
-------
TABLE 93. MAJOR STRUCTURAL TYPES IN HEAVY OIL AND
ASPHALTENE FRACTIONS FROM SYNTHOIL PRODUCT* (102)
Structural types**
Total heavy oil
Total asphaltene
Alkylbenzenes
11
9
Indenes
7
4
Indans
9
2
Naphthalenes
6
2
Acenaphthylenes
12
8
Biphenyls
21
11
Anthracenes; phenanthrenes
6
4
Phenylnaphthalenes
5
6
4 rings, pericondensed
5
11
4 rings, catacondensed
3
9
5 rings, pericondensed
4
15
5 rings, catacondensed
1
5
6 rings, pericondensed
1
10
Phenols
9
4
* by percent
**Includes alkyl derivatives
TABLE 94. PAH COMPOUNDS IN SYNTHOIL SAMPLES (103)
Compound Concentration (ppm)
Phenanthrene 413
Benzo(a)anthracene 18
Benzo(a)pyrene 41
TABLE 95. PAH IN COED SAMPLES (103)
Sample type
Product separator
liquor
Drier liquor
Syncrude
Unfiltered raw oil
Filtered raw oil
Concentration (ppm)
Benzo(a)pyrene
8.0
9.3
51
107
96
Concentration (ppm)
Benzo(a)anthracene
Trace
42
52
294
-------
TABLE 96. ESTIMATION OF PAH CONCENTRATIONS IN
COAL-DERIVED MATERIALS (104)
Coal-Derived Material
Component
~it
A
B C
(ppm)
D
Naphthalene
347
486
341
247
2-Methylnaphthalene
1325
1508
1070
1102
1-Methylnaphthalene
383
531
438
330
Azulene
ND*
30
7
28
Biphenyl
89
271
113
213
2, 6-Dimethylnaphthalene
328
333
220
224
1, 3-Dimethylnaphthalene
181
428
338
284
1, 5- and/or 2, 3-dimethylnaphthalene
202
254
165
169
Acenaphthalene
20
50
36
21
Acenaphthene
61
112
53
,IR*
Fluorence
205
540
244
IR
9-Methylfluorence and/or
octahydroanthracene
94
84
46
IR
9, 10-Dihydrophenathrene
IR
IR
36
IR
1-Methylfluorence
•152
IR
IR
IR
Phenanthrene and/or 1,3,6-
Trimethylnaphthalene
IR
IR
213
IR
2-Me thylanthracene
245
131
21
68
1-Methylphenanthrene
107
16
IR
30
2-Phenylnaphthalene
IR
IR
22
IR
9-Methylanthracene
42
14
ND
15
1, 2-Dihydropyrene
ND
IR
37
IR
FluoTanthene
ND
IR
19
IR
Pyrene
IR
IR
73
IR
1, 2-Benzofluorene
ND
IR
29
IR
4-Methylpyrene
IR
IR
33
IR
1-Me thylpyrene
IR
65
IR
IR
1, 2-Benzanthracene
21
IR
18
IR
Chrysene and/or triphenvlene
35
40
12
61
Triphenlylbenzene
47
56
ND
25
*ND - not detected; IR - incomplete resolution.
^Reference 104 identifies A and B as two "Coal-derived
products" and C and D as two "different preproduct samples"
from the process for making B.
295
-------
TABLE 97. POLYNUCLEAR HYDROCARBON CONTENT OF PARTICULATE MATTER
EMITTED BY INCINERATION AND OPEN-BURNING SOURCES* (105)
Group 1
Group 2
BaP
Pyrene BeP
Perylene
BghiP
Anthanthrene Coronene
Anthracene
Phenanthrene
Fluoranthene UaA
Source
Umber
Type of Unit
Sailing do
lit
(ne/eram of
particulate)
20
!*xiicipal Incinerators
226.S metric-eon/day
Multiple chanfcer
*
Breeching
(before set
Cling charia
0.016
er)
1.9
0.08
0.06
9.8
2.2
2.5
0.09
21
45.4 metric ton/day
Multiple chanfcer
Gonmerical incinerator
Breeching
(before
scrubber)
5tack (afte
scrubber)
S
3.3
r 0.15
28
3.6
6.5
0.97
19
1.1
8.2
1.1
5.5
0.26
22
4.8 metric ton/day
Single chaiber
stack
58
350
49
3.3
98
7.1
23
51
150
240
5.0
23
2.7 metric ton/day
Multiple chanfcer
Open-Burning
stack
180
2600
180
36
540
45
130
53
62
2400
210
24
Mnicipal refuse
fa smoke
5 lune
11
29
4.5
4.7
13
25
Automobile tires
1100
1300
450
72
660
53
81
110
450
470
560
26
Grass clippings,
leaves, branches
35
120
21
5.4
4.7
110
25
27
Automobile bodies
270
670
210
33
150
12
15
220
160
450
40
*A blank in the table for a particular carpomd Indicates that it was not detected in the sanple.
-------
Other carcinogenic compound types which have been
identified in coal liquefaction products are methyl chry-
senes. Table 98 gives quantitative values found in product
sample.
TABLE 98. QUANTITATIVE DATA FOR METHYL CHRYSENES
IN A COAL LIQUEFACTION PRODUCT (106)
Compound
Concentration
(ppm)
Chrysene
98
1-Methyl chrysene
2-Methyl chrysene
102
3-Methyl chrysene
106
4-Methyl chrysene
5-Methyl chrysene
(19)*
6-Methyl chrysene
64
Total methyl chrysenes
272
^Estimation of maximum possible concentration of 4-plus
5-methyl chrysene.
The fate of trace metals during liquefaction is also of
interest and concern. Table 99 illustrates the level of
some key inorganic compounds in various coal feeds and their
redistribution to residue and oil products from the lique-
faction process. The major portion of the inorganics re-
mains in the ash and residue, with generally less than one
297
-------
TABLE 99. TRACE ELEMENT COMPOSITION IN VARIOUS FEED COALS AND
RESULTANT DISTRIBUTION AFTER A LABORATORY LIQUEFACTION PROCESS
IN AN AUTOCLAVE* (69)
B
Co
V
Ni
Ti
Ma
Na
Pb
Zn
Cr
Cu
Cd
Be
1. Feed coal
12
25
12
12
75
tr.
5000
n.d.
25
12
25
12
0.2
0.4
Solid resuidue
25
12
25
5
150
25
1000
n.d.
50
25
25
25
0.5
0.8
Oil
0.15
0.12
0.06
0.15
5
0.08
5
0.02
0.12
0.05
0.05
0.02
--
0.0004
2. Feed coal
25
12
50
25
400
12
2500
n.d.
125
125
25
25
4
0.8
Solid residue
150
40
150
80
1100
40
8000
n.d.
—
300
80
90
4
2
(Ml
0.12
0.01
0.25
0.08
6
0.01
2.5
n.d.
0.12
0.12
0.02
0.03
-
0.01
3. Feed coal
7
4
4
4
450
4
150
n.d.
n.d.
4
1.5
7
1.4
0.2
Solid residue
40
20
40
20
240
20
800
n.d.
100
80
20
40
2.7
2
Oil
0.03
0.004
0.004
0.03
0.5
n.d.
0.9
n.d.
0.05
0.05
0.05
0.01
--
0.0009
30 B Sean, King Mine, Utah, PSOC-239
1. Mineral natter, dry basis, 12.9%. High Vol. B. Total S, 0.52 0.13) Ash content of oil, 150 ppm.
lower Dekoven Seam, Will Scarlett Mine, Illinois, PS0C-284
2. Mineral Matter, 25%. High Vol. A. Total S, 5.2% 4.0) Ash content of oil, 250 ppm.
Mining City Seam, Jerry Mine, Kentucky. PS0C-221
3. Mineral Matter, 7.3%. High Vol. A. Total S, 3.9% 0.13) Ash content of oil, 90 ppm.
^Compositions in ppm
-------
part per million of any element distributed in the product
oil (69).
A primary concern with liquefaction of coal is reduc-
tion of the sulfur content of the fuel. Sulfur contamina-
tion in fuels is a significant environmental concern and has
made the burning of coal unacceptable in many cases.
Bituminous coals vary widely in sulfur content, ranging from
roughly 1 to 5 percent by weight. The high sulfur coals
expected to be utilized in coal liquefaction average about
4.5 percent sulfur. The sulfur content of crude petroleum
is generally lower than that of coal, with an average level
of 0.75 percent, varying from 0.20 to 3.70 percent. During
the liquefaction process there is a redistribution of the
sulfur, resulting in sulfur levels in the product oil of
about 0.5 percent, with lesser percentages in the gases and
light oils and progressively greater percentages in the
heavier oils and tars. The estimated sulfur levels in
various liquefaction solids and liquid streams from several
coal conversion processes are detailed in Table 100. Sulfur
redistribution during refining of petroleum crude is shown
in Table 101.
TABLE 100. ESTIMATE OF SULFUR LEVELS* IN
COMBINED LIQUID AND SOLIDS PRODUCTS FROM LIQUEFACTION
PROCESSES (107)
Process
Original
coal**
Liquid
product
Solids
Combined
product
Solvent refined coal
H-Coal
Consol
Bureau of Mines
Hydrodesulfurization
3.5-4.3
5.0
4.2
3.0
1.0
0.20
0.30
0.31
4.6-7.0
7.2
5.2
2.1
1.7-2.3
1.7
2.6
0.8
* Percent by weight
**For bituminous coals
299
-------
TABLE 101. DISTRIBUTION OF SULFUR IN
PETROLEUM FRACTIONS (108)
Fuel gas
1.4
Claus off-gas
1.5
FCC regeneration
7.3
LPG
0
Gasoline
3.2
Kerosine & jet fuel
2.0
Diesel
9.2
No. 2 fuel oil
9.2
No. 6 fuel oil
23.3
Asphalt (finished)
13.9
Coke (equivalent)
8.0
Sulfur
27.7
Sulfur is in the product oils as various compounds.
Table 102 illustrates the organic sulfur compounds in the
products of coal hydrogenation and specifies the quantities
of sulfur compounds found in various fractions of Synthoil
oil.
300
-------
TABLE 102. ORGANIC SULFUR COMPOUNDS
IN SYNTHOIL PRODUCT (102,103)
m/e*
Molecular
formula
Identif ication**
Light oil
134
148
162
Heavy oil
98
138
174
184
198
208
234
248
284
Sample or subfraction
W
w
C10H10S
C5H6S
C8H10S
CliH10S
C12V
C13H10S
CuV
C16H10S
c17H12S
C20H12S
Benzothiophene
Methylbenzothiophene
Dimethylbervzothiophene
Methylthiophene
Tet rahydrobenzo thiophene
Benzylthiophene
Dibenzothiophene
Methyldibenzothiophene
Benzo(def)dibenzothiophene
Naphthobenzothiophene
Methylnaphthobenzothiophene
Dinaphthothiophene
Number of sulfur compounds
observed in GLC profile
Synthoil oil
>40
Neutral PAH fraction
>20
3-membered rings PAH subfraction
>20
4-membered rings PAH subfraction
none
5-membered rings PAH subfraction
none
* This is a term used in mass spectrometry. It means mass per unit change.
**Based upon molecular formula determined by high-resolution mass
spectrometry. Other isomeric forms are possible in some instances.
301
-------
In summary, the products of coal liquefaction should be
considered potentially hazardous, particularly the higher
boiling fraction and residuum. The hazard of liquefaction
products relative to that of crude petroleum and coal tar
has not been established. However, it is believed that
liquefaction oils will be less carcinogenic than coal tars,
but more hazardous than petroleum crude. With regard to
sulfur levels, liquefaction oils are within the range of
that of refined petroleum products. Nitrogen levels in coal
liquefaction oils are much higher than in petroleum products.
FACTORS INFLUENCING ENVIRONMENTAL DISTRIBUTION
Airborne Wastes
Physical-Chemical Characteristics--
Volatilization is the most important process for
introducing small molecules into the atmosphere. Some of
the emissions such as hydrogen sulfide and ammonia are gases
at process temperatures. Others such as trace elements can
be volatilized by the reducing conditions coupled with the
high temperature and pressure which are characteristic of
various coal liquefaction processes. Trace elements such as
mercury can occur as a vapor in their elemental forms;
others can be converted to volatile compounds such as hydrides
of arsenic, antimony, selenium, chlorine and fluorine; or
volatile carbonyls (iron, nickel, and cobalt) (84). Table
103 lists the boiling points under normal atmospheric pressure
for selected trace metals either in their elemental state or
in combinations. Depending upon such factors as the reactor
configuration and bed type, type of coal utilized and pre-
treatmerit procedures, type of coal feed system, and process
operating conditions, the trace elements will leave the
liquefaction unit either with the product, as part of the
solids residue streams, or as a component of the gas stream.
302
-------
TABLE 103. BOILING POINTS OF SELECTED ELEMENTS ASSOCIATED
WITH COAL - °C (109)
Element
Elemental form
Hydride
Sulfide
Oxide
Aluminum
2057
1500 (subl.)
2980
Antimony
1380
-17.1 (gas)
1150
1550
Arsenic
615 (subl.)
-116.3 (gas)
565-707
457
Beryllium
2970
3900
Boron
2550
-92.5 (gas)
1860
Cadmium
767
980
900-1000
Chromium
2480
4000
Copper
2595
1800
Cesium
670
800
Lead
1515
Lithium
1317
1200 (at 8(
kPa)
Mercury
357
Q
Nickel
2730
d. 600
Selenium
685
-41.5 (gas)
d.a300
Silver
1950
Thallium
1457
1800
Vanadium
3000
Zinc
907
1185 (subl.)
decomposes
NOTE: At atmospheric pressure unless noted otherwise.
Trace elements that occur in coal as aluminosilicates have
very high vaporization temperatures and generally remain
with the fly ash and slag. The current paucity of information
makes it difficult to compute a mass balance for trace
metals between the coal and gaseous, liquid, and solids
process discharges.
If steam for the coal liquefaction process is generated
in a coal-fired boiler, then trace elements may be volatilized
either in the elemental state or as metal oxides. The
appropriate boiling points are listed in Table 103. Elements
such as arsenic, bromine, chlorine, cadmium, cesium, mercury,
selenium, and zinc may be volatilized. Small quantities of
these elements may escape the scrubber in the stacks. Other
303
-------
possible sources of trace element contamination associated
with coal liquefaction plants include chromates present in
cooling tower blowdown, volatile fluorides in sour water,
and chemical purges from acid gas removal which may contain
arsenic and vanadium (84).
Organic compounds vary greatly in their volatility
depending on their molecular weight and structure. Some are
volatile and may be expected to become air emissions whenever
present in waste streams; others, for reasons of polarity
and/or high molecular weight, will not. Examples of some
organic compounds found in coal liquefaction processes are
given below.
Benzene--Benzene is a volatile compound (12.7 kPa at
25°C) and is readily transferred from water surfaces to the
atmosphere (110). Mackay and Wolkoff (110) have calculated
the evaporative half-life of benzene in water to be 37 minutes
for one square meter of water at a depth of one meter.
Naphthalene--Previous studies indicate that naphthalene
is readily volatilized from the aqueous phase to the atmo-
sphere. One study observed as much as 50 percent of dissolved
naphthalene to volatilize in four days (111) . Volatilization
rates in the environment will depend on a number of factors,
such as air and water temperature, wind speed, and wave
action.
Fluoranthene--Fluoranthene has a vapor pressure of 1.33
Pa at 25°C. Volatility studies have reported losses to the
atmosphere of 36 percent after three weeks and 92 percent
after one year (79).
304
-------
Phenol--Phenol has a moderately low vapor pressure
(130 Pa at 40.1°C). Due to its high solubility in water, it
will remain in solution in natural waters under most conditions
with low losses because of volatilization (79).
Polynuclear Aromatic Hydrocarbons (PAH)--The volatility
of PAH compounds at 25°C is very low, ranging from 0.9 MPa
for phenanthrene (three rings) to 20 MPa for coronene (seven
rings). Therefore it is unlikely that significant amounts of
these organic compounds will be discharged as vapor phase
emissions. Also, the adsorption of PAH compounds to particles
in either air or water reduces their activity and therefore
makes it unlikely that significant quantities of these com-
pounds will pass from the water to the air by codistillation
(112).
Physical-Chemical Removal Processes--
Inorganic materials generally occur in the atmosphere as
aerosols, adsorbed to particulate matter, or as particulate
matter, and are removed from the atmosphere through rain or
dry deposition. Atmospheric particles resulting from air
pollution by heavy metals (lead, selenium, zinc, antimony,
vanadium, arsenic, cesium, and chromium) generally have small
diameters (0.1 to 1 ym) and are thus characterized by dry
deposition velocities less than 0.7 cm/sec. Particles
derived from soil or coal dust occur in larger diameters
(1 to 100 urn) and consequently have dry deposition velocities
greater than 0.7 cm/sec. In addition, air pollution usually
obeys a power law of dilution by dispersion such that concen-
tration decreases very rapidly away from the point source.
For example, a smelting operation in Sudbury, Ontario yielded
the following relationship (113):
305
-------
where y is the metal content of the soil (ppm)
x is the distance from the smelter (km)
a is a site specific constant related to the
concentration at the source (ppm)
b is a site specific constant related to factors
such as the inverse of stack height (km~^)
Using this type of relationship for metal concentration in
surface soil, Pearson's (114) product moment correlation
(r),* with 9 degrees of freedom was 0.771 for nickel (p less
than 0.01), 0.934 for copper (p less than 0.001), 0.560 for
cobalt (p less than 0.1), 0.609 for iron (p less than 0.05),
0.531 for zinc (p less than 0.1) and 0.653 for lead (p less
than 0.05). The factor, "b", in the above equation ranges
from 0.007 for zinc to 0.077 for copper. The "p" referred
to above is the probability that the relationship found
exists solely due to chance.
One consequence of the power law of pollutant dilution
by dispersion is that the concentration increases exponentially
toward the point source. A result is that flora appear to
exhibit an ecological threshold response. In actuality, the
flora exhibit a variety of sublethal effects related to the
heavy metal distribution. Since the pollutant concentration
is changing exponentially, the loss of a particular flora
component from the community occurs over a relatively short
distance from the pollution source.
^Pearson's product moment correlation is a common statistical
test used to determine if two sets of data are correlated
by some simple linear equation. In this case, the linear
equation is lny = bx+a.
306
-------
Vegetation alters the composition of aerosols by impac-
tion and subsequent adsorption of heavy metals on floral
surfaces. Precipitation is altered during contact with and
partial adsorption or desorption and internal transport of
pollutants by the flora through adsorption and leaching.
Ultimately the soil and, secondarily, the floral biomass will
be the repository of the heavy metals generated by coal
liquefaction technologies.
The aerosols and larger particulate matter emanating
from coal liquefaction plants can be altered by oxygen in
the atmosphere or by photochemical reactions. For example,
metallic antimony combines with oxygen to form antimony
trioxide, which is then subject to photoreduction (115). Of
the carbonyls formed under reducing conditions, octa(carbonyl)-
dicobalt is unstable in air, iron carbonyl oxidizes rapidly
in air, and nickel carbonyl oxidizes slowly in air. The
carbonyls that are either unstable or rapidly oxidized in
air probably will not pose an air pollution problem. Fly
ash from the steam generation plant is likely to contain
calcium oxide which reacts with water vapor to form calcium
hydroxide. The latter, upon contact with the carbon dioxide
in the atmosphere, will form either calcium carbonate or
calcium bicarbonate. Metallic mercury has a vapor pressure
of 0.16 Pa and a saturation concentration in air of 13.2
micrograms per cubic meter at 20°C (116). The atmosphere is
the most important global transport path for mercury. The
vapor pressure of selenium at room temperature is 1.2 Pa
and thus it volatilizes fairly readily from soils, leaves of
living plants, the lungs of animals, and water.
The dearth of information on the chemical form of the
trace element pollutants that enter the atmosphere from coal
liquefaction plants makes it difficult to describe the
307
-------
removal mechanisms in detail. In past studies of smelting
operations, organisms, usually higher plants or lichens,
living adjacent to point sources of pollution have been used
as indicators. Researchers have found it difficult to
separate the influence of the acid moieties (sulfate, nitrate,
or chloride) from that of the heavy metals on the distribu-
tion of indicators. The air pollution associated with coal
liquefaction plants may pose the same type of problem.
Many aromatic constituents of coal conversion effluent
streams are subject to photochemical oxidation under naturally
occurring illumination. Carcinogenic PAH compounds such as
benzo(a)pyrene and 1,2-benzanthracene are rapidly photo-
oxidized in aqueous solutions containing a large amount of
acetone, a singlet oxygen photosensitizer (83).
In the global atmosphere, most carbon monoxide is
produced by hydroxyl radicals oxidizing methane that eman-
ates from natural sources. The same hydroxyl radicals
account for a large amount of global carbon monoxide loss.
These two competing formation and destruction processes can
account for the 0.1 year residence time of carbon monoxide
estimated by radiocarbon measurement. While important in
explaining the global balance, oxidation of carbon monoxide
by hydroxyl radicals is insignificant in polluted atmospheres,
being unable to compete with the much faster reactions of
hydrocarbons with hydroxyl (117).
Aerated soil is capable of removing hydrocarbons from
dilute auto exhaust. These hydrocarbons in the dilute
auto exhaust include acetylene, ethylene, propene, butane,
toluene, pentanes and 42 other gases. The percentage of
these individual gases is unknown (118).
308
-------
Benzene, toluene, naphthalene, and other compounds may
be removed from the atmosphere and enter the hydrosphere by
various means; possibilities are washout in rain, dry
deposition, or direct diffusion into the water surfaces.
Such atmospheric removal systems are believed to contribute
significantly to hydrospheric contamination by these compounds
(79).
Waterborne Wastes
Physical-Chemical Characteristics--
For inorganic elements, a key factor affecting the
aqueous environmental fate is the leachability of trace
metals from coal piles, tailing wastes, and gasification-
liquefaction ashes. The interaction of the released trace
elements in the receiving water systems depends on such
factors as the redox potential, alkalinity, suspended and
dissolved solids concentrations, biogeochemical cycling, and
bottom sediment characteristics. These characteristics are
site specific in and only very general statements can be
made regarding their influence.
Since most of the trace elements are associated with
the solids waste products rather than the liquid or gaseous
products, a number of workers have conducted laboratory
studies on the leachability of trace elements from various
kinds of solids associated with the coal liquefaction process.
The results of such studies are also a function of experi-
mental conditions such as method of sample preparation,
method of leaching (batch or column-reflux), solids-liquid
ratio, particle size distribution, temperature and pH condi-
tions, sample composition, time for leaching, and origin of
solid material. Inasmuch as the information on the holding
pond treatment for these solids is not well defined at
309
-------
present, the laboratory studies can only provide a range of
postulated impacts of coal liquefaction-associated solids on
receiving waters.
The concentrations of the constituents in water after
contact with the piles of storage coal are not well known.
They are presumed to be a function of the type of coal,
extent of exposure to local climatic conditions, acidity of
rainfall, temperature within the pile, and length of contact
time between the water and coal. The runoff water from
eastern coal piles is likely to be acidic due to the inter-
action of water with the sulfur oxides originally present in
the coal or formed by the action of atmospheric oxygen with
other sulfur-containing compounds in the coal. This inter-
action will result in the formation of sulfuric and sulfurous
acids. The runoff from western coal will probably be less
of a problem in this regard, since western coals usually
contain less sulfur, and the receiving land and waters are
usually slightly alkaline which will tend to neutralize the
acidic components.
In addition to coal piles, the huge quantities of
residue which will be produced from liquefaction plants will
also be potential sources of leachates. The leachability of
the constituents of H-Coal liquefaction residue at varying
pHs is illustrated in Table 77. This table shows that the
leaching of aluminum from H-Coal residue under argon increases
with a decrease in pH from 5.53 to 2.30. The leaching of
calcium and lead from H-Coal residue under air increases
with a decrease in pH. Under both anaerobic and aerobic
conditions, magnesium, potassium, strontium, and silicon are
more readily leached from H-Coal residue at lower pH.
310
-------
This same pH range has little effect on the leachability
of boron, cadmium, chlorine, chromium, fluorine, sodium,
sulfur, aluminum (under aerobic conditions only), and silicon
(under anaerobic conditions only). Under anaerobic conditions
with the indicated change in pH, the amount of iron leached
increases by a factor of more than 900, manganese by a
factor of more than 130, and zinc by a factor of about 40.
In this same experiment under aerobic conditions, the factors
are 300, more than 120, and 27, respectively.
From Table 77, we can estimate that waters in contact
with H-Coal residue for a long period of time under anaerobic
conditions will be likely to contain more than one percent
of the concentration of the solids residue of boron, cadmium,
calcium, chlorine, fluorine, manganese (only if the water
has a pH less than 5.5), nickel (if the pH of the water is
2.3), sodium, strontium (pH less than 5.5), sulfur (as
sulfate), and zinc (pH less than 2.3). Under aerobic con-
ditions, the list is essentially unchanged except that
nickel and zinc are deleted. One would expect these elements
to be found in runoff water from the H-Coal solids residue.
For most studied runoff from coal piles and associated
solids, the COD is higher than the BOD which suggests that
much of the organic matter is refractory in nature. Fortu-
nately, the soluble carbonates leached from the tailings,
coupled with the high pH of groundwater in mining areas,
tend to precipitate heavy metals, thereby reducing their
potential impact. In addition, hard water generally diminishes
the toxicity of many heavy metals. However, the humic acids
and small aromatic compounds possess a capability for complex-
ing heavy metals, thereby facilitating their mobilization
into a soluble phase. It is presumed that in most freshwater
311
-------
receiving bodies carbonate and/or hydroxide equilibria will
dominate organic complexation reactions (119).
Solids formed during liquefaction are referred to as
char, and much of this material is cycled to the hydrogen
generation unit which produces slag and ash as solids resi-
dues. The slag will be transported directly to a landfill,
while the ash passes through a clarifier or settling pond
after which the ash is dewatered prior to its disposal. The
gasification condensate and sour water from the liquefac-
tion-gasification are processed in some of the following
steps to remove potential toxigenic, mutagenic, teratogenic,
and carcinogenic substances. The steps include tar-oil-
water separation, phenol extraction, ammonia stripping,
activated carbon treatment, pH adjustment, and biological
oxidation. Much of the treated water produced is recycled
while some will be released into the environment (120).
The interplay of these factors is reflected by the wide
range of values in Table 104, showing the concentrations (in
ppm) of various elements, the conductivity (in ^5), the pH,
and the acidity of several samples ("n") of runoff from coal
refuse and spoil piles in different areas of the eastern
United States.
Table 105 gives the solubility of various polynuclear
aromatic hydrocarbons in water. Some of the PAH are signifi-
cantly water soluble (up to greater than 30 ppm) and could
be expected to present definite pollutant and treatment and
control problems.
312
-------
TABLE 104. LEACHABILITY OF INORGANIC ELEMENTS FROM COAL
REFUSE AND SPOIL PILES* (121)
Arithmetic Geometric Standard Standard error
n**
mean
mean
deviation
of the mean
Range
Acidity***
32
6572
8396
1484
7-34300
PH
32
3.2
3.1
1.0
0.2
2.1-6.9
Conductivity
26
5863
4035
4636
909
640-16500
Sulfate
32
6899
9432
1667
310-40500
Iron
32
1961
333
2799
495
1-13500
Aluminum
23
231
59
331
69
1-1014
Manganese
26
58
27
102
20
3-545
Calcium
16
236
188
130
32
30-450
Magnesium
16
199
135
192
48
26-680
Sodium
13
183
87
230
64
14-780
Potassium
12
12
7
12
3
1-42
Zinc
11
1.8
0.8
2.0
0.6
0.1-7.2
Copper
3
0.16
0.16
0.02
0.01
0.14-0.18
Nickel
7
0.9
0.8
0.6
0.2
0.25-1.7
* Taken from different areas of the eastern U.S.
**Number of samples
***Acidity as ppm CaCO^
-------
TABLE 105. SOLUBILITY OF POLYNUCLEAR AROMATIC
HYDROCARBONS IN WATER (122,123,124)
PAH compound
Experimental conditions
Solubility (ppb)
Phenanthrene
1,2-D1fcenzanthracene
Pyrene
Shaking crystals 1n distilled
•.vater for 3 months at 25"C
1,600
10
175
Anthracene
Cnrysene
'inphthaceie
•
/b
6
1.5
1 ,2 ,-5,6-Gibenzanthracenc
2-Methy!naphthalene
Naninthal ene
Standard hydrocarbons dissolved
in hexane added to doubly distilled
P.6
24,500
31,300; 22,000
(dw) (sw)
3ip'ienyl
Acenaphthene
Phenanthrene
watsr or artificial ;ea water and
shaken for 12 hours at 25°C.
7,450; 4,760
(dw) (sw)
3,470
1 ,070; 710
(dw) (sw)
Mixtures of Naphthalene and
Phenanthrene (Solubility of
Phenanthrene)
Mixtures of Biphenyl and
Phenanthrene
Mixtures of Acenaphthene and
Phenanthrene
1,060
910
1,010
Mixtures of 2-Methylnaphthalene
and Phenanthrene
Mixtures of Naphthalene and
Acenaphthene and Phenanthrene
(Solubility of Phenanthrene)
Phenanthrene
Nephelometric Method at 27°C (Crystals
80C
1,010
1.600
4,5-Methylphenanthrene
Fluoranthene
Pyrene
of hydrocarbons added)
1,100
240
165
Anthracene
9-Methyl-1,2-Benzanthracene
1'-Methyl-1,2-Benzanthracene
75
66
10-Hethyl-l,2-Benzanthracene
1,2-Benzanthracene
fi-Methylchrysene
11
65
5-Methylchrysene
Chrysene
5.6-Dlinethylchrysene
62
1.5
25
5-Methyl-3,4-benzopyrene
3,4-Benzopyrene
20-Methylcholanthrene
0.8
4
1.5
Cholantnrene
Plcene
Perylene
3.5
2.5
<0.5
Napnthacene
1,2,7,8-Dlbenzanthracene
1.2.5.6-Dibenzanthracene
1.0
12
0.5
9.10-0imethyl-1,2-benzanthracene
10-Amyl-l,2-benzanthracene
10-Ethyl-l,2-benzanthracene
43
0.8
45
314
-------
Physical-Chemical Removal Processes--
When trace elements are transported to receiving water
bodies, they can be removed by sediment-water interactions,
geochemical interactions, storage in biological tissues, and
conversion by metabolic processes. In the abiotic compart-
ments of ecosystems, trace elements are present in dis-
solved, colloidal, or particulate form. Generally, except
for iron, the colloidal component represents a small frac-
tion of the total trace element load transported. For small
streams the dissolved component is usually predominant,
while rivers flowing over flat, flood-plain regions contain
a major fraction in the suspended solids.
Table 106 presents, for aquatic systems, the solubility
products of the major geochemical reactions that control
the solubility of trace elements. Under reducing conditions,
the formation of highly insoluble sulfides controls the
equilibrium concentrations of dissolved trace elements.
According to Bowen (76), the order of solubility products of
the sulfides is antimony, mercury, copper, lead, cadmium,
cobalt, nickel, zinc, iron, manganese, tin, magnesium and
calcium. The smaller the solubility product, the more
insoluble the precipitate is and the lower is the equilibrium
concentration of the dissolved, reduced species of the
element.
Several other factors influence physical-chemical removal.
Under oxidizing conditions, the soluble concentration is
controlled by the anion with the lowest solubility product,
other factors being constant. The stability constants
between the trace element and potential inorganic or organic
complexing agents also influence the equilibrium concentration.
For organic chelates, stability decreases in the following
order: mercury, copper, nickel, lead, cobalt and zinc,
315
-------
TABLE 106. PHYSIOCHEMICAL AND RELATED
DATA FOR METALS (77)
i:ir. In.-
Solubility product , ,
Umlaut (A'srX
Slul.ilit v
iic^ii-
Ionic
COIIHtilllt
Mrlul
tivily
pnti'lll ia 1
on -
Hl'()4«-
sn,!~
ScOj'-
(•"K K)c
Anl immiy
1 Hi
H If,Ci)*
—
lir4l(j,
—
10 ¦l3(.i)
--
lir " (Aid))
l(r! (<•;,)
—
Aiscnic
'» '2(1
1
—
—
—
-
Mr" (<':.)
Mr» (Mr)
—
Murium
(1.1(7
1 UK.!)
10"8
i(r',j)
10-",!)
—
-
10
Ml :° (M>;)
Mr" (!•'<•(:)))
7.H(l)
111'l\l 1111 in
1 >7
r, 7
—
lir",:)
_
Kr'Y..,
—
Mr 30 (I'VCI))
10"' (Mn(->))
—
Mi-S II lilt ll
1 .07
:J i ¦*'(:!)
—
nr®"(j)
—
io-",3,
10
10 =9 (Mm(->))
—
1.4(3)
<'nilnimni
1 Mi
Mr"
Mr»(3,
—
Mr"
10 =",,,
—-
—
10.««)
( Vmiiim
(I.S(i
(1 (!()(1)
—
—
—
•—
—
—
—
Chromium
i ,r> e
*.77(:i)
IT",!).
io-3»,a)
Mr",,,
(in Ilium
1 HLi
t kw:!)
—
—
-
—
•-
—
-
—
(i i - r 11 i.'ii li Li in
'» ()•»
7 0
-
—
—
—
-
-
—
-
I ..•¦¦nl
1 . VI
1 117 (-')
mi ",,,
lir",:i
nr»,2,
Mr",,,
10 :\;)
10 V,
—
—
in.:((•*)
1 .i 11, i U<)
Nickel
1 75
'» ()(>(•. is
H 00(1)
--
—
__
—
—
—
Si I \ .']¦
1. (•>
(1 Kll(l)
10",,)
"r8,!,
_
mi '¦„>
10
—
—
—
7.:«(!)
St nuil Mim
((.!(!)
1 7!l('.')
i"
i (it(i)
K(-"(J)
—
10
—
—
—
—
Tit a niu in
V anailniin
1 IH
! l.i
r, iSh (i j
H !«(.->)
I
lir'V..,.
.
Mr",,.
I
I
n.:»(3)
l-'.7(-.>)
/in "ilium
1
r, (»i(i)
-
l'r",,,
Hr!Vl
Mr",,,
Mr'8',,,
_
-
-
—
?">.!>(:})
1N.HS)
*!>.!>(-»)
^Numbers in parenthesis are the valence states for the
elements.
cadmium, iron, manganese, magnesium, and calcium (79).
Chelation tends to increase the soluble concentration of a
trace element over that which would prevail without chelation.
For a simple equilibrium between dissolved and particulate
forms of copper, for example, the soluble concentration
under aerobic conditions is a function of the degree of
316
-------
solubility of copper carbonate and the stability of the
complexes formed with carbonate and hydroxide ions, amino
acids, humic acids, polyphosphate and nitrilotriacetic acid
moieties from anthropogenic discharges. Copper is also
adsorbed to sediments and suspended particulate matter
(especially clays).
The partitioning of a trace element between different
solids and dissolved phases is a function of a variety of
environmental factors that can only be effectively dealt with
on a site-specific basis. Even at a specific site, the form
of an element is important in determining its environmental
fate. This is illustrated by the affinity of trivalent
chromium for attachment to particulate matter, while hexavalent
chromium remains primarily in solution.
There are also synergisms of interest. The uptake by
bottom sediment can interact with other factors to reduce
the amount of trace elements in solution. For example, a
study of Irwin Creek in North Carolina demonstrated that the
arsenic concentration was 1000 ppm at the discharge, but had
been decreased to 10 ppm at the first sampling station due
to sediment uptake and microbial production of volatile
organoarsines (125,126).
Ammonia, when added to water, is strongly sorbed to
particulates and colloidal particles. This is especially
true in alkaline waters with a high humate content. Ammonium
nitrate loss from ponds is believed to result primarily from
denitrification of nitrate in the bottom sediments and
volatilization of ammonia across the air-water interface
(127).
317
-------
Certain compounds have distinct characteristics making
them good candidates for removal by physical-chemical pro-
cesses. Studies indicate that naphthalene may be slightly
concentrated in bottom sediments (by one to two orders of
magnitude) (128,129). However, it is generally agreed that
naphthalene is not significantly taken up from bottom sedi-
ments by macroorganisms (130). The main route of uptake
seems to be from the water surrounding the organisms.
Adsorption onto soils and sediments is more pronounced
for the larger multi-ring, organic compounds. Centrifugable
solids in natural waters accumulate polycyclic aromatic
hydrocarbons (PAH) several thousand-fold over the levels
found in water on a weight:weight basis (83,131). The
multi-ring compounds include those containing nitrogen,
phosphorous, or sulfur in addition to carbon and hydrogen
and are referred to as the heterocyclic group (a PAH subgroup).
PAH compounds, in general, are readily adsorbed onto a
wide variety of particulate matter (132,133). Studies of
the photodecomposition of benzo(a)pyrene adsorbed onto
calcium carbonate in aqueous solutions demonstrated that the
process is a first order decay reaction that is accelerated
by higher light intensity, temperature, and oxygen levels.
The decomposition reaction under the experimental conditions
employed was independent of pH and ionic strength (133).
While adsorption is more pronounced for larger multi-
ring compounds, volatilization is most important as a re-
moval mechanism for relatively nonpolar small molecules
(i.e., 1- and 2-ring compounds) (83). Microbial degradation
is undoubtedly a major mechanism for compound removal in
sediments, although levels found in river bottoms and
318
-------
degradation rates measured in soils each suggest that poly-
cyclic compounds may possess turnover times of months or
years (83).
Solids Waste and Residues
Physical-Chemical Characteristics--
The major route of disposal for solids waste from coal
liquefaction plants will involve utilization of landfills
either for direct disposal or for disposal of solids removed
from settling ponds. The leachability of trace elements
from various solids residue generated during coal lique-
faction or its auxiliary has already been discussed. In a
landfill operation the physical characteristics of the solid
residue are important in influencing such parameters as
water permeability, compaction, moisture content, and
specific weight. The dearth of information on the quan-
tities and physical characteristics of the solids residue
generated during coal liquefaction makes analysis difficult
at present. The characteristics of the soil in the landfill
play an important role in influencing erodibility and the
capacity of the soil for confining potentially toxic chemi-
cals to the landfill. For example, the three-layer alumino-
silicate clays (smectities) can absorb much more water and
have a higher ion exchange capacity than the two-layer
aluminosilicate clays (kandites).
Physical-Chemical Removal Processes-
Inorganic ions and organic molecules are needed for
forming soluble complexes. Much higher levels of these
agents are available in soil than in water. Also the
microbial populations in soil are much denser than those
found in most aquatic systems. The grazing activities of
319
-------
the soil fauna keep the microbial populations in an active
state of growth and physiological activity.
The inorganic and organic complexing reactions greatly
increase the soluble concentration of trace metals in the
soil. This may be offset somewhat by the activities of the
soil microflora as they convert trace elements to a less
available form through reduction or formation of sulfide
ions under anaerobic conditions. On the other hand, those
activities may facilitate the leaching of trace elements
with subsequent passage into lower soil layers.
The soil particles themselves influence trace elements
through their ion exchange capacity. Ion exchange occurs
when the trace element is adsorbed and calcium, magnesium,
or alkaline earth cations are released into the soil water.
Soils have a much greater exchange capacity for cations than
anions. This exchange capacity is exerted primarily by clay
particles and organic colloids which tend to trap added
trace elements in the surface layers of the soil. Trace
metals with vacant "d" orbitals, such as copper, iron, zinc,
manganese, and molybdenum, tend to be bound to soil organic
matter. The movement of the trace elements is a function of
cation exchange, water flow rate, pH, Eh, migration of soil
fractions, and existing concentration of that trace element
in the soil.
Certain precipitation reactions occur at the surfaces
of solids phases in the soil and are difficult to separate
from adsorption reactions. For example, cobalt and nickel
may form hydrous oxides on the surface of iron hydrous
oxides or clay particles. For magnesium in the soil an
equilibrium exists between water soluble magnesium (II),
exchangeable magnesium (II), colloidal hydrated magnesium
320
-------
oxide or magnesium dioxide and inert magnesium dioxide. The
divalent form of magnesium is soluble in acid soils, while
the tetravalent form can be hydrated and reduced (either
chemically or biologically) to the insoluble oxide at pH
above 7.5 (134). As a consequence, for trace elements such
as magnesium and nickel, acidic soils make more of the
element available to plants.
Table 107 presents a compilation of some of the biotic
and abiotic factors influencing the environmental transport
of trace elements in soils. The key factors are the avail-
ability of trace elements for uptake and potential bio-
accumulation by plants, ability of trace metals to travel
through soil to groundwater, and immobilization of trace
metals in surface layers of soil from which it can be trans-
ported to nearby ecosystems by surface runoff, erosion, or
wind-blown dust. Most non-point pollution sources can be
attributed to the transport of contaminated sediments. Most
cationic trace metals are immobilized in soil and are pre-
sent in concentrations which would not pose a threat of
groundwater contamination unless they are methylated, but
the anionic groups pose a potential hazard. A theoretical
study of the potential impact of a coal gasification plant
on the trace element levels in the surrounding soil after a
40-year period of operation identified copper, mercury,
molybdenum, and tin as elements whose endogenous soil levels
would be greatly exceeded (78).
BIOLOGICAL CYCLING
This section will consider the biological cycling of
trace elements and organic compounds from effluents and
321
-------
TABLE 107. INTERACTIONS OF SELECTED INORGANIC ELEMENTS IN SOILS
Table : Interactions Of Selected Inorganic Elements In Soils
Solubilized by
Poor soil
Microbial oxidation
Bound by soil
acid production
drainage increases
Element
- reduction
organic matter
or chelation
availability
Reference
Zinc
+ (a)
+
76
Vanadium
+
+
76,77
Thallium
+
76
Tellurium
+
76
Tin
+
+
76,77
Selenium
+
+
76
Nickel
+
+
76,77
Molybdenum
+
+
76
Mercury
+
16
Manganese
+
+
76
Magnesium
+ (a)
76
Lead
+
+
76
Iron
+
+
76
Iodine
+
+
76
Germanium
+
76
Chromium
+
lb
Copper
+
+
76
Cobalt
+
+
76,77
Cadmium
+
+
76
Calcium
+ (a)
76
Bromine
+
76
Aluminum
+
76
Arsenic
+
-(b)
+
76
Sulfate
+
76
Nitrate
+
—
76
Borate
—
+
76,77
Phosphate
+
+
76
(a) Relatively easy to leach from soil organic matter.
(b) Sulfate, nitrate and borate apparently are not bound by
soil organic matter.
-------
emissions of coal conversion facilities. Little is known
about the potential hazards to the general public from coal
conversion processes. The potential effects of processing
oil and coal have been summarized as follows:
Fugitive losses were identified as the major source of
emissions in the refinery. The compositions of the
fugitive emissions are difficult to quantify. Among
the four assessed coal and oil processes, coking is the
most offensive one. Coal gasification is likely to
produce equally dangerous materials as the coke plant,
but they will probably be somewhat more contained than
coke oven emission. The environmental impact of coal
liquefaction is not well defined. However, the lique-
faction products will probably be more hazardous than
crude oil products, and their refining and utilization
will be worse offenders than the corresponding petro-
leum operations. (135).
There is evidence that aqueous wastes from coal con-
version may contain appreciable amounts of phenols, organo-
sulfur, and other organic compounds as well as some heavy
metals. Also, the ash produced from coal conversion will be
greater than from petroleum refining. Yet there is essen-
tially no information available about the effects of
chronic, low-level exposure to such materials. There is no
clear information about the potential effects of chronic
exposures to the products and effluents from coal conversion
technology on the health of the general public (136). The
following discussions illustrate the multitude of potential
biological cycling and impacts of these products and
effluents.
Trace Elements
Uptake, Metabolism and Excretion--
Microorganisms--Some compounds of antimony (137) ,
arsenic (138,139), lead (140), mercury, molybdenum, nickel,
323
-------
selenium, silver, sulfur, titanium, vanadium, and zinc
(76,79), or the elements themselves are subject to microbial
metabolism and undergo oxidation, reduction, methylation,
and/or demethylation. The methylated forms are highly
toxic, cross membrane barriers with relative ease, and are
more likely to become airborne because they are more volatile
than the elements themselves (79). Microbial action also
can affect the availability of many elements in soils and
waters. Silicate minerals are attached by the organic acid
liberated by Bacillus siliceus (76). Organic water fer-
mented by bacteria in the absence of oxygen can dissolve
considerable amounts of cobaltous oxide, cupric oxide,
ferric oxide, manganese dioxide, molybdenum trioxide, lead
dioxide, and zinc and smaller amounts of chromium trioxide,
nickel monoxide, titanium dioxide, and vanadium pentoxide
(76).
The kind and rate of microbial metabolism depends, in
part, on the chemical form of the trace element. For example,
alkylation of inorganic lead salts is considered a very
difficult reaction mechanism in view of the instability of
the postulated first intermediate, monomethyl lead salt.
However, the conversion of lead nitrate and lead chloride to
Me^Pb (tetramethyl lead) was reported for a mixed bacterial
culture from Lake Ontario (141). No such transformation was
detected with lead hydroxide, lead cyanide, lead oxide, lead
bromide, or lead palmate. The methylation of trimethyl lead
acetate (Me^PbOAc) to volatile tetramethyl lead (Me^Pb) is,
in contrast, a fairly simple transformation for bacteria
(142).
In the laboratory, bacterial methylation activity is
frequently higher under anaerobic conditions than under
aerobic conditions. However, in natural fresh water the
324
-------
reverse seems to be true. In sediments, where anaerobic
conditions are more likely to occur, hydrogen sulfide,
ubiquitous in the natural environment under anaerobic condi-
tions, combines with mercury to form insoluble mercuric
sulfide. Thus, under aerobic conditions in fresh water,
methylation rates are likely to be higher than under anaero-
bic conditions, where the formation of mercuric sulfide
binds mercury and hinders methylation (134).
Invertebrates--The amount of pollutant taken up by
bottom dwellers is a function of the type of sediment to
which the pollutant is absorbed. For example, a laboratory
study of the uptake of sediment-bound heavy metals by the
clam, Macoma balthica, (143), showed the clams could take up
silver most effectively from synthetic calcite (calcium
carbonate) and maganese oxides. Silver adsorbed to syn-
thetic calcite was the only sediment for which the organism
exhibited tissue silver levels with a bioconcentration
factor greater than one (dry tissue/dry sediment ratio
ranged from 3.7 to 6.1). The uptake of silver from amor-
phous iron oxides was greater for freshly prepared precipitates
than those which had been aged for 16 to 24 hours. The
lowest silver uptake occurred from biogenic calcium car-
bonate and organic detritus. The uptake of sediment-bound
silver was greater than that for zinc or cobalt. However,
the heavy metal uptake from sediment-bound metals is generally
lower than that observed for soluble metal forms (143).
The rate of uptake of metallic compounds may be strongly
influenced by temperature. Fowler and Benayoun (141)
observed a 400 percent increase in the rate of cadmium
uptake in shrimp over a 26-day period at 22°C as opposed to
8°C. On the other hand, mussels were not affected by the
change in temperature.
325
-------
Vertebrates--Table 108 gives the approximate amount of
various elements absorbed and excreted by various routes.
These data are based on laboratory experiments with a number
of mammal as well as human studies. Since the absorption
of trace elements depends on many factors, the numbers in
Table 108 are only indicative of general trends.
The absorption of an element depends upon its chemical
form. In general, univalent cations readily diffuse across
the gut wall, become more or less uniformly distributed in
the soft tissues, and are fairly rapidly eliminated in
urine. Divalent cations appear to be much less readily
absorbed across the gut wall. It is still uncertain how
efficiently major elements such as calcium and magnesium are
absorbed, since the reverse process may take place lower
down in the gut. Once absorbed, most divalent cations
concentrate in bone, and are relatively slowly eliminated in
the urine and feces. The affinity for bone is greatest for
those ions most closely resembling calcium. Thus barium,
lead, and strontium are notable bone-seekers; but copper,
cobalt, and nickel diffuse into the soft tissues, and a
sizeable percentage is excreted in the urine. Polyvalent
cations diffuse still less readily across the gut wall and
remain in the fecal material. It should be noted, however,
that the extent of absorption across the intestinal wall can
be profoundly modified by other components of the diet.
Well-known examples include the effects of Vitamin D on
calcium absorption, of sulfate on barium and molybdenum
absorption, and of aluminum on the absorption of phosphate
(76).
In addition to the information contained in Table 108,
lead and zinc cross gills; arsenic, mercury, nickel, selenium,
and thallium cross the skin but lead does not; zinc crosses
326
-------
TABLE 108. ROUTES OF ABSORPTION AND EXCRETION FOR VARIOUS ELEMENTS
Elenent
Excreted
in feces
Excreted
jn urine
Absorbed
in limg
Intestinal
absorption
Cnj^s placental
barrier
Reference
Antimony
+
I V
o
+
5-701 (little as
III or V)
76,79,144,145
Arsenic
+
i 10*
+
5-70%
76,146,140,147
Berylliun
largely
+
poor (« 5*)
76,79
Boron
+
+
> 70*
76
Bromine
+
t
> 70*
76
Cadmium
largely
+
poor (< 51)
+
146,148,149
Chlorine
+
+
> 70%
76
Chrwiun
+
+
> 70*
149
Cobalt
I 10%
5-70*
76
Copper
i 10%
+
5-70*
148,76,150
Fluorine
+
+
> 70*
76
Iodine
+
+
> 70*
76
Lead
largely
+
primarily
poor (5-10*)
+
76,148,146
Mercury
predominant
* 10%
50-lOOt
5-70*
+
76,148,146,151,149,152
Nickel
1 10%
t
5-70*
76,146,148,153,154
Phosphorus
i 10%
+
5-70*
76
Ruthenium
largely
+
< 5*
76
Selenium
50-80%
+
35-85%
146,79,155
Sulfur
1 v
o
+
5-70*
76
Tellurium
+
+
> 70*
76
Thai1i um
+
t
limited
76,79,74,156
Tin
largely
+
5-70*
76
Vanadium
+
¦f
> 70*
76
Z1nc
largely
~
+
« 5*
76,148,77,157
-------
the entire body surface of fish; and mercury and nickel are
excreted in the perspiration. Aluminum, americium, bismuth,
cerium, gallium, gold, indium, iron, lanthanum, manganese,
niobium, palladium, platinum, plutonium, polonium, protac-
tinium, ruthenium, scandium, tantalum, titanium, yttrium,
and zirconium all are poorly absorbed from the intestine
(less than 5 percent) and largely excreted in the feces.
Five to 70 percent of the barium, calcium, radium, stron-
tium, and tin is absorbed from the intestine; these elements
are mostly excreted in the feces. Five to 70 percent of the
cobalt, copper, magnesium, silicon, sulfur, and uranium is
absorbed from the intestine with at least 10 percent of
these elements being excreted in the urine. More than 70
percent of the germanium, molybdenum, nitrogen, silver, and
tungsten is absorbed from the intestine. Germanium, nitro-
gen (greater than 10 percent), silver, tungsten, molybdenum,
rubidium, osmium, and sodium are excreted in the urine (76).
Plants--
Through a comprehensive literature search, Vaughan et al.
(78) have determined that metal ions absorbed from the soil
by plants basically become either chemically reactive,
relatively unreactive, or capable of remobilization.
Elements which are chemically reactive remain concen-
trated in the roots and require an ion carrier to maintain
mobility. They show a log profile from root to shoot tip.
This accumulation may result from an exchange of the free
ion to cell wall fragments. Elements included in this group
are chromium, lead, selenium, tellurium, thorium, and
vanadium.
328
-------
The relatively unreactive ions become uniformly distri-
buted in the plant via the transpirational stream. The
mobile ions generally accumulate in leaves and to a lesser
extent in stem and reproductive tissues. These elements
include silver, arsenic, beryllium, cobalt, copper, man-
ganese, radium and zinc.
A few nonmetabolic ions such as cadmium and nickel appear
to be phloem mobile or capable of remobilization. These
ions tend to accumulate in seeds and fruit during plant
senescence.
The absorption of a trace element by plants is also in-
fluenced by the presence of other trace elements. For example,
zinc and aluminum slightly inhibited beryllium absorption,
whereas magnesium had no influence, and dinitrophenol enhanced
beryllium absorption (103).
Bioconcentration--
Bioconcentration refers to the ability of an organism
to accumulate a pollutant above the ambient level. This
phenomenon may result from an energy-requiring, active
transport mechanism by which the organism concentrates a
micronutrient from the environment. However, the phenomenon
also occurs if the pollutant is sequestered in the organism.
This sequestration may result from chemical reactions (for
example with protein sulfhydryl groups) or physical phen-
omenon (for example, a lipophylic compound dissolving in
high lipid tissue and thus removing itself from the aqueous
excretion process). Higher aquatic organisms such as fish
can incorporate arsenical compounds and metabolize them,
yielding high-molecular weight lipid material (139).
When soil concentrations of essential micronutrients
such as manganese, zinc, cobalt, copper, and molybdenum are
329
-------
increased, plants continue to accumulate them, sometimes to
toxic levels. Nonessential elements such as cadmium or
nickel may also be bioaccumulated. The uptake of nonessential
elements may be affected in part by the fertility of the
soil and, ultimately, by the general nutrition of the plant.
In a series of sand culture experiments, corn plants grown
with insufficient levels of phosphate accumulated 5 to 10
times more added lead (as lead nitrate) than did plants
grown with sufficient phosphate levels. Phosphate-sufficient
plants also were less sensitive to the lead that was ac-
cumulated. Lead was added in high enough quantities to
insure that decreased accumulation was not just the effect
of lead phosphate precipitation (68).
Other conditions such as plant growth period, age, or
water stress may affect uptake of trace elements, and plant
rooting characteristics are likely to be important as well.
For example, most of the acetic acid-soluble lead, cadmium,
and zinc were found in the upper 3 cm of heavily polluted
soils near a large lead and zinc smelting complex; and in
these soils, plants with shallow, spreading roots are probably
exposed to more toxic concentrations than deeper rooting
species. Also, plants with greater root surface area generally
have more potential for uptake (68).
Unfortunately, the bioconcentration ratio, even for a
single plant species is not constant, but is a function of
the available (total, extractable, or soluble soil fraction)
pollutant level in the soil. The bioconcentration level
generally increases with decreasing soil concentration. The
bioconcentration also depends on the uptake (minus the
amount lost) and, hence, is subject to all the variables
discussed previously. In addition, uptake rate appears to
reach a maximum in those experiments with sufficient data to
plot saturation kinetics.
330
-------
The bioconcentration factors for animals are also
functions of the difference between uptake and elimination
and are subjected to all the factors affecting uptake discussed
previously.
Weir (79), using the data of Mason and coworkers (158)
on mercury uptake by the oyster, Hermione hystrix, calculated
the following relationship between the bioconcentration
factor (which ranged from 441 to 1230) and the water concen-
tration, which ranged from 10 to 100 ppt:
y = 1300-9.4x (r=0.982)
where y = the bioconcentration factor (concentration in
the oyster/concentration in the water)
x = Concentration in the water (ppt)
z = Pearson's product moment correlation (discussed
previously)
Again, Weir (79) used data of Mason and coworkers (158) on
the bioconcentration factors of fathead minnows, Pimephales
promelas, exposed to methylmercury concentrations ranging
from 0.015 to 0.240 ppb. The bioconcentration factors
ranged from 45 to 98 and followed the following formula:
y = 19.4 - 18.7 lnx (r=0.997)
where: y = the bioconcentration factor (concentration
in the fish/concentration in the water)
x = concentration in the water (ppb)
These two equations demonstrate that bioconcentration factors
are not constant with differing water concentrations but are
related to the water concentrations in relatively complex
ways (158).
331
-------
Table 109 gives ranges of bioconcentrations found for
several classes of organisms. These ranges are broad because
different species are considered and the bioconcentration
factors are functions of the several variables discussed
previously. In addition to these variables, bioconcentration
factors are functions of inorganic and organic water chemistry
and food web dynamics (148). Bioconcentration is a complex
process dependent to a great extent on the organism in
addition to the physiochemical parameters such as competing
ions, ligands, complexes, colloidal suspensions, pH, and
temperature. Before the use of bioconcentration factors can
be relied upon, careful consideration must be given to the
species involved, its growth and nutrient requirements,
feeding habits, and metabolism in various environments.
Several elements show no consistent ability to bio-
concentrate. For them sediments contained higher content
than detrital eaters while detrital eaters and herbivores
contained higher concentrations than carnivores. The elements
are lead (148,167,171), selenium (148), copper (172),
chromium (173), arsenic (79), cadmium (174,148,175), and
nickel (176,177,178).
Organics
Uptake, Metabolism, and Excretion--
Microorganisms--Hydrocarbon uptake by microbes is ex-
plained by several theories, the most plausible of which is
the "micelle" theory. Micelles, which are thought to be
surface-active agents produced by microorganisms, solubilize
the hydrocarbon drops to an optimal size for microbial pino-
cytosis. Mixed hydrocarbons (e.g., oil) are first attacked
in the n-alkane range. Such selective attacks may cause PAH
enrichment of aged mixture samples (87).
332
-------
TABLE 109. BIOCONCENTRATION FACTORS FOR VARIOUS ELEMENTS IN
VARIOUS GROUPS OF ORGANICS
.Element
Microorganisms
including single-
celled algae,
fungi, bacteria
Aquatic plants
(includi ng
marine plants)
including the
kale, Brassica
oleraced
Nonaquatic
nonagronomic
plants
Agronomic
plants
Mari ne
invertebrates
Freshwater
inverte-
brates
Marine
verte-
brates
Freshwater
verte-
brates
References
Aluminum
1550-25000
0.01 '
76,78,77
Antimony
50
27-127
0.13-1.46
5
10
40
1
76,78,79
Arsenic
200-71000
50-71000
0.03
0.37-1.23
9-64,100
80-480
38-12,150 1-333
76,77,78,79 ,68,148,125
Barium
108-260
0.11
76,77,78
Beryllium
1000-1500
0.03
2-16
200
10
200
2
76,77,78,79
Bismuth
15
15
78
Boron
6.6
76
Bromine
2.8
¦
1
1
76
Cadmium
12500
1000-1620
5.3
0.21-1.47
10-250,000
200-30600
3000
30-2000
76,79,77,78,159,148
160.161
Calcium
0.5-10
13-265
76
Cerium
7100
0.5
70,77,73
Cesium
1-100
480
0.03
76,77,78
Chlorine
0.062-1.0
38
76
Chromium
0.5-17000
695-10,000
0.000-0.082
0.01-250
0.1-2000
20-3000
200-400
20-200
76,79,77,78,68,162
Cobalt
277-4600
4425
0.0-0.1
0.019-87
1000
200
100
20
76,77,78,68,162
Copper
100-17000
275
1000
0.02-90
50-10,000
1000
667
200
76,77,78,79,68
Fluorine
0.86
1
1
76
Gallium
4200-12000
0.04
76,77,78
Germanium
15-200
0.25
15,700
33
3300
3300
76,77,78
Iodine
1200-10000
370
76
Iron
2000-140,000
120-4935
76
Lathaniim
8300
76
Lead
360-70,000
0.04-2.3
0.44-12
1000-3500
100
300
300
76.77,78,79,163,68,164
lithium
8
1
76.77,78
Magnesium
0.59-0.96
17
1
76,77,78
Hanganese
750-9400
100-100,000
3000
0.41-3
100-10,000
40,000
600
100
76,77,78,68,134
(continued)
-------
TABLE 109. (continued)
Elenent
Microorganisms
including single-
celled algae,
fungi, bacteria
Aquatic plants
(including
marine plants)
including the
kale, Bvaesiaz
oZeraced
Nonaquatic Freshwater Marine Freshwater
nonagronomic Agronomic Marine inverte- verte- verte-
plants plants invertebrates brates brates brates
Mercury
Molybdenum
Nickel
Niobium
Phosphorus
Potassium
Radiurn
Rubidium
Scandi un
Seleniuai
Silicon
Silver
Sodi urn
Strontium
Tellurium
Thallium
Thorium
Tin
Titanium
Tungsten
Uranium
Vanadium
Yttrium
Z1ne
Zirconium
196-42000
11-1700
140-170u
450-1000
10,000-15,000
3-50
100-4500
5-50
1500-2600
2290-7230
120-17000
6-250,000
0.14-1.0
1.0-44
50
10
92-2900
3000-20,000
87
10
250-1900
100-1000
100-208,000
350-3000
12-5915
260-1700
7640
1600-5480
115 .
1230
0.5-2000
19
475
6680
41-2830
6230
0.05-42.8
0.42-900
0.014-1500
0.11
0.009-26.2 1-33,300
0.02
0.001
1-1000
0 09
0.004-0.18
0.09
0.001
0.008
55-582
0.008-331
10
0.08-1000
84.6-1787
0.05-10
100
1000
0.64-4.60 100,000
10.9-15,000
2000
0.0003-0.25 1000
2.3-24
30
0.011-2.65 50
100-100,000 1670
10 10
100 100
250
167
75
15,000
500
1000
10
3000
50
4000
1-200,000 0.7-1,400
30
10
45-70,000
10
100
50
30-167
0.7->700
400
10,000 10,000
10,000 30
3,000 3,000
1200
10
References
40 0.31-39.0 549-260,000 125-16,400 1050-35,400 39-2400
0.03-1.56 1.4
76,77,78,79,68,148
76,77,78
76,77,76,79,165,166,167
168
76,77,78
76,77,78
76
76.77
76,77,78
76,77,78
77,78,79,68
76
76
76,79
76,77,78
76,77,78
77.78
76,79,78
76,77,78
76,77,78
•76,77,78
76,78
76
76,77,78,169,170
76
76,77,78,79
76,77,78
-------
In general, phenols are subject to rapid microbial
degradation while monoaromatics undergo moderate microbial
degradation (83). PAH, aromatic amines, and thiophenes are
degraded by microbes at very slow rates if at all (83).
Acenapthene, anthracene, phenanthrene, diaminobenzene, 1,2-
benzanthracene, 1,2,5,6-dibenzanthracene, naphthol, pyridine,
and thiosulfate, but not nitrobenzene, are subject to microbial
metabolism (79,87).
The following polychlorinated biphenyls have been
degraded by at least one bacterial strain: biphenyl, 3,4,3-
trichlorobiphenyl, 2,4-dichlorobiphenyl, 2,3,4-trichloro-
biphenyl, 3,4-dichlorobiphenyl, 2,3-dichlorobiphenyl, 2,3,2-
trichlorobiphenyl, and 4,4-dichlorobiphenyl (87). Naphthalene,
anthracene, phenanthrene, diaminobenzene, 1,2-benzanthracene,
and 1,2,5,6-dibenzanthracene are subjected to microbial
degradation (103) as are pyridine, 4-carboxyl-l-methyl-
pyridinium chloride, 3-methyl pyridine and thiophene (87).
The following polychlorinated biphenyls are known to be
refractory to at least one strain of microbes known to
degrade other polychlorinated biphenyls. They may also be
refractory to microbial degradation in the environment. The
list includes 2,4,6-trichlorophenol, 2,4,2-tetrachlorobiphenyl,
2,4,6,2-tetrachlorobiphenyl, 2,3,4,5,2,3-hexachlorobiphenyl,
2,3,2- and 2,3,4-trichlorobiphenyl (87).
Specificity by some microorganisms has been noted. A
one- or two-atom change in some n-alkanes can mean the difference
between total or no bacterial degradation. For example,
Pencillium spinulosum, Fu sari vim oxysporum, and Aspergillus
niger all grow on n-dodecane, but not on n-decane, whereas
Aspergillus athecius grows on n-tetradecane, but not on n-
tridecane.
335
-------
Co-metabolism is an important process used by microorgan-
isms for degradation of oil hydrocarbons. Cyclohexane is
broken down after co-metabolic transformation by one of two
Pseudomonas strains, each of which is unable to metabolize
it independently. Alkylbenzenes having a methyl- or ethyl-
side chain can only be metabolized by co-metabolism.
Plants--Studies in southern California on PAH levels in
Valencia oranges reported that 1 to 12 percent of the 3-
methyl-cholanthrene; 1,2,6,7-dibenzanthracene; 3,4-benzopyrene;
and anthracene penetrated into the rinds of the orange and
had half-lives of 120 to 200 days in the field. Most of the
PAH compounds found in the air were rapidly degraded (half-
life of 1 to 2 days) and did not penetrate into the oranges.
No evidence was found of translocation into twig tissue
(179).
Invertebrates--Whereas PAH are readily metabolized by
fish, crabs, and zooplankton (Daphnia), shellfish apparently
are unable to degrade these compounds. Therefore, PAH may
accumulate to an extensive degree in the tissues of oysters,
clams, and other edible shellfish.
Vertebrates--The enzyme system primarily responsible
for PAH metabolism is a multicomponent, microsomal-bound
system of mixed-function oxidases (oxygenases), of which
aryl hydrocarbon hydroxylase (AHH) is the most important.
It is well established that these enzymes may either in-
activate or activate the PAH to more carcinogenic, terato-
genic, or mutagenic forms.
Gehrs gives information which indicates that the
bioaccumulation factor of PAH increases by an order of magni-
tude for each 50- to 60-unit molecular weight increase (136).
336
-------
This is reasonable since an increase in molecular weight
should increase the lipid solubility relative to the water
solubility, which should increase the bioaccumuiation factor
(180). However, these data are as yet too preliminary for
serious consideration as absolutely demonstrating that this
phenomenon is indeed occurring in this system.
Laboratory animal studies indicate that many PAH are
poorly absorbed from the gastrointestinal tract. When
incorporated into the diet or when administered in a single
dose to the rat, many PAH are excreted unchanged. Although
there is a distribution of values, only naphthalene, phen-
anthrene, and acenaphthene are not excreted directly.
Carcinogenic PAH such as benzo(a)pyrene and its metabo-
lites are excreted largely in the feces through the biliary
system and appear only sparingly in the urine. In studies
using mice, the rate of excretion of PAH varied according to
the compound; for example, twas 1—3/4 weeks for benzo(a)-
pyrene and 12 weeks for dibenzo(a,h)anthracene, and carcino-
genicity of the compound was directly proportional to the
retention time (136).
Aromatic hydrocarbons are highly lipophilic and readily
penetrate cells. Repeated topical application of PAH
dissolved in solvent to the skin of mice and rabbits caused
systemic effects, indicating that the PAH are absorbed
percutaneously. Pathological changes were observed in the
blood, spleen, lymph nodes, and bone marrow. Similarly,
Stowell and Maas found that 3-methylcholanthrene, repeatedly
painted on the backs of mice, produced inflammation of the
liver, kidneys and lungs in addition to other systematic
changes (146).
337
-------
Transport Paths and Rates--
There are no comprehensive studies in the literature on
the distribution of any PAH compound in the water, sediment,
and in various trophic levels within the biota. This is a
prerequisite for a discussion of transport paths and rates.
The Clipperton Lagoon study (181) gives a crude picture of
the environmental distribution of 3,4-benzopyrene and perylene
based on sparse sampling. Table 110 presents an overview of
this study:
TABLE 110. ENVIRONMENTAL DISTRIBUTION OF SPECIFIC PAH (181)
Component Benzopyrene (ppb) Perylene (ppb)
Water 1.6 3.05
Plankton 7.3 2.7
Aquatic plants 376 71.6
Intertidal crustaceans 536 856
Fish - skin 0.5-4 1.7-5
- muscle 13.6 - 26 25 - 30
Littoral fringe grass 71.5 219
Terrestrial plant trace trace
Terrestrial crustacean 119 288
BIOLOGICAL IMPACTS
The information in this section addresses potential
hazards and their influences. There are a number of materials
including phenols, PAH, organosulfur compounds, organometallic
compounds, and inorganic elements and compounds to which the
plant personnel and the general population (both human and
nonhuman) living in the vicinity of the plant will be exposed.
What follows is a discussion of the health effects of some
specific compounds to which such populations will be exposed.
Unfortunately, little is known about the synergistic and
antagonistic effects of materials in the complex mixtures
338
-------
produced during the conversion processes. Also, very little
is known about the long-term effects of low- or medium-level
exposure to such materials and mixtures.
Medical surveillance and epidemiological studies will
certainly be desirable. As long as coal conversion is in
the pilot plant stage the number of exposed individuals will
be too small to allow detection of any but the most obvious
and ubiquitous effects. Heavy reliance should be placed on
laboratory tests, in any case, to avoid unnecessary exposure
of industrial personnel.
Effects of low levels of materials released during coal
conversion and during the use of its products will be the
principal concern for the general public. Concern will
address acute and chronic effects, carcinogenicity, mutageni-
city, and possibly teratogenicity. Major reliance must be
placed on extrapolation from laboratory data to man. However,
despite the difficulties imposed by the expected low levels
of hazardous substances, epidemiological and clinical studies
of groups of individuals, especially those located near coal
conversion plants, may be of importance. This is particularly
true because the complexity of the products, or the possible
interactions between products, and the low level of the
individual effects may make it difficult to really duplicate
the situation in the laboratory. As for the industrial
workers, the polycyclic hydrocarbons would appear to be at
least one hazard of interest, but knowledge is too limited
to be sure that other materials may not be even more hazardous
to the general public.
339
-------
Trace Elements
Rationale for Selection of Potentially Toxic Trace Elements--
In view of the fact that at least 65 of the natural
elements have been found in coal, it would be fruitful to
concentrate attention on those elements which will be found
in toxic concentrations. Synergistic and antagonistic
effects may make such an approach inadequate. Moreover,
physical-chemical parameters play a very significant part in
determining toxic effects in that these parameters determine
the environmental location and concentration to which the
animal will be exposed.
A technique called multimedia environmental goals
(MEGs) is currently being developed by Cleland and Kingsbury
(11). The MEGs are based on a very thorough literature
search and represent concentrations which should not be
environmentally harmful. Separate MEGs are derived for
waste streams and environmental compartments (air, water,
and soil). At the time of writing this report, the MEGs are
not at a stage where they can be used to accomplish their
purpose. Source Analysis Models (SAMs) are a series of
techniques which utilize part of the MEGs, the Minimum Acute
Toxicity Effluent (MATE) to identify waste streams and
individual components of waste streams which are relatively
more severe and may cause environmental damage (182). Part
of the SAMs is called the Degree of Hazard (Health) and
Degree of Hazard (Ecological). These values are simply the
concentrations in the particular waste stream divided by the
MATE based on health effects or the MATE based on ecological
effects. For example, we know (from Table 111) that the
concentration of aluminum in condensate from coal drying is
300 ppb. The MATE for aqueous effluent streams for aluminum
based on health effects is 80,000 ppb, while the MATE based
340
-------
on ecological effects is 1,000 ppb. Thus, the Degree of
Hazard (Health) is 0.00375 and the Degree of Hazard (Ecological)
is 0.3. These Degrees of Hazard are less than one, which
indicates that the concentration in the waste stream is less
than the MATE. Since the MATE is that MEG value which
indicates the concentration in the waste stream which should
not cause environmental harm, a Degree of Hazard of one or
less indicates that this particular component is not likely
to have a significant environmental effect, while a Degree
of Hazard greater than one indicates that significant environ-
mental effect is to be expected. The Degrees of Hazard for
several trace elements in several effluent streams of coal
liquefaction processes have been calculated and are shown in
Table 111. Unfortunately, at the time of writing this
report, not enough information was available to do a complete
SAM/IA analysis (182). In the absence of available SAMs,
the rationale for choosing those inorganics which may prove
toxic is based upon very limited process data. In choosing
those elements which have a potentially toxic effect in coal
conversion facilities, the following data may be considered:
• Table 111 indicates the toxicity potential and
potential for bioaccumulation of elements detected
in process wastewater from a COED plant. The
potential toxicity of elements in process streams
was evaluated by dividing the observed concentration
in effluents by the lowest concentration found in
the literature to be toxic to freshwater biota
regardless of species. Elements were classified
as having low, medium, or high potential for
biological impact if the ratio of effluent concentra-
tion to toxic concentration ranged between 1 to
10, 11 to 100, and >100, respectively. The potential
341
-------
TABLE 111. TOXICITY POTENTIAL AND POTENTIAL FOR BIOACCUMULATION OF ELEMENTS
IN PROCESS STREAMS
COED process streams
Condensates from coal drying Process water H-Coal process water
Reference
76
184
184
76
184
184
87
184
184
76
76
Element
Cone,
(ppb)
Degree of
hazard
(health)
Degree of
hazard
(ecological)
Cone,
(ppb)
Degree of
hazard
(health)
Degree of
hazard
(ecological)
Cone,
(ppb)
Degree of
hazard
(health)
Degree of
hazard
(ecological)
Potential
toxicity
Potential
bioaccumulation
Aluminum
300
0.00375
0.3
3000
0.0375
3.0*
2500
0.03125
2.5
Medium
Medium
Arsenic
200
0.8
4.*
40.
0.16
0.8
Low
Barium
1000
0.2
0.4
10C0
0.2
0.4
Low
Bismuth
< 2
< 3.3x10-4
a
70
0.01
Cadmiim
< 3
< 0.06
<0.3
10
0.2
1.0
800
16*
80.*
Cobalt
< 5
< 0.007
<0.02
500
0.7
2.0*
1400
1.9*
5.6*
Medium
Medium
Chromium
30
0.12
0.12
600
2.4*
2.4*
100
0.4
0.4
High
High
Copper
20
0.004
0.40
500
0.1
10.
400
0.08
8.*
Low
High
Iron
Germanium
15000
5
a
5.9xl0~4
a
a
190000
10
a
0.001
a
a
1.2
a
a
High
High
Low
Mercury
3
0.3
0.12
7
0.7
0.28
700
70*
2.8*
High
Medium
Magnesium
1000
0.01
0.01
50000
0.56
0.57
700
0.007
0.008
Low
Low
Manganese
3
0.012
0.03
15
0.06
0.15
Medium
High
Nickel
50
0.2
0.5
500
0.002
0.005
2520
11.*
25.*
High
High
Lead
3
0.012
0.06
1000
4.*
20.*
2900
12.
58.
High
High
Selenium
< 3
< 0.06
< 0.12
300
6.*
12.*
High
Tin
5
0.003
a
100
0.07
a
High
Titanium
50
5.6xl0~4
0.06
300
0.02
0.37
1000
0.01
1.2*
Medium
Zinc
200
0.008
2.*
5000
0.2
50*
High
High
Sum of degree of
hazards
1.8
8.4
15.
100
110.
184.
*This number is greater than 1 indicating possible environmental hazards.
"MATES not available.
-------
for bioaccumulation was evaluated by the method of
Dawson (76). Hence, this represents a worst case
situation (i.e., untreated, undiluted process
water, and lowest toxic concentration). Comparative
raw process water for an H-Coal PDU plant indicates
that the process waste streams may not be comparable.
• Table 112 shows the solubility of metals as 10 per-
cent solutions of a Lurgi ash and an H-Coal residue
(81). Of approximately 60 chemical constituents
measured in the raw Lurgi ash and H-Coal residue,
about 31 were found to be present at concentrations
that could present a potential hazard. The remainder
were present at such low levels that, even if com-
pletely soluble, they would pose no particular
problem. Of the 31 that were a potential problem,
16 were found to be in forms soluble enough to
exceed recommended water quality levels in some
samples at pH values between 3 and 8. These 16
constituents are listed in Table 112. Seven of the
constituents--Al, Cr, Co, Cu, F, Fe, and Zn--ex-
ceeded the recommended levels in water only under
certain pH conditions, generally when the pH was
quite acid. The other nine constituents--B, Ca,
Cd, K, Mn, NH^, Pb, SO^, and Sb--exceeded the
recommended levels in all Lurgi ash solutions over
the pH range 3 to 9. These nine constituents are
thought to represent the highest potential pollu-
tion hazard. Discharges of the 16 constituents
listed in Table 112 at the levels found in this
study could cause some environmental degradation
and require some form of wastewater treatment. A
10 percent ash concentration is far more concentra-
ted than what would be observed, as has been shown
343
-------
TABLE 112. ELEMENTS WHICH EXCEED RECOMMENDED WATER QUALITY LEVELS UTILIZING A TEN PERCENT
SOLUTION OF LURGI ASH OR H-COAL RESIDUE (CONCENTRATIONS IN PPB) (81)
LURGI
ash solubility
H-Coal residue solubility
pH=3
pK=8
pH=3
pH=8
Degree of hazard
Degree
of hazard
Degree of hazard
Degree
of hazard
Recommended
Element
Concn.
(Health)
Ecological
Concn.
(Health)
Ecological
Concn.
(Health) Ecological
Concn.
(Health)
Ecological
levels (concn}
Aluminum
13200
1.65*
132.*
500
0.00625
0.5
5500
0.069 5.5*
500
0.0067 5
0.5
100
Antimony
600
0.08
3.*
200
0.027
1.
Boron
5500
0.12
0.22
4000
0.085
0.16
13600
0.29 0.54
13000
0.28
0.52
750
Calcium
570000
a
a
290000
a
a
497000
a a
175000
a
a
50000
Cadmium
60
1.2*
6.0*
20
0.4
2.0*
10
Chromium
120
0.48
0.48
20
0.08
0.08
50
Cobalt
190
0.25
0.76
100
0.13
0.4
50
Copper
750
0.15
15.*
10
0.002
0.2
200
Fluoride
860
a a
1150
a
a
1000
Iron
560000
a
a
60
a
a
31500
a a
100
a
a
300
Potassium
26000
0.87
0.60
42000
1.4*
0.98
>000
Manganese
3800
15.2*
38.*
450
1.8*
4.5*
2680
10.7* 26.8*
40
0.16
0.4
i 50
t
Amnonia
11000
4.4*
220.*
17000
6.8*
340.*
8000
3.2* 160.*
6000
2.4*
120.*
i 20
Lead
200
0.8
4.*
100
0.4
2.*
250
1. 5.*
100
0.4
2.0*
i 30
Sulfate
338000
a
a
820000
a
a
250000
Zinc
17000
0.68
170*
120
0.0048
1.2*
270
0.0108 2.7*
10
0.0004
0.1
200
Sua Degree
of Hazard
26.
590.
11.
350.
15. 200.
3.2
120.
*These numbers are greater than 1 and, therefore, constitute an environmental hazard according to the SAM methodology.
^he MATEs for this element have not been determined, hence calculation of the Degree of Hazard usinp SAM methodologv is not possible.
-------
by the dilute discharges from ash ponds. Hence,
this is, again, a worst case situation and is only
a basis for choosing the potential hazardous
compounds.
• Minimal information is available on those elements
which volatilize from coal liquefaction facilities.
On the basis of data from coal-fired steam and
electric plants, bromine, iodine, gallium, mercury,
selenium, and lead are thought to have significant
gas phase components (83). Low concentrations of
gallium and iodine in coal give these compounds a
low pollution potential.
Effects--
Several adverse effects of various elements on animals
and humans can be found in Tables 113 and 114. The data in
Table 115 are taken from Talmage (146) and show threshold
limit values and toxic effects of potential pollutants from
coal conversion plants. The values are based upon accidental
poisonings, occupational exposures, attempted suicides or
epidemiological studies; hence, they are based on heterogenous
populations in sometimes ill-defined situations.
The extrapolation of data such as these to the environ-
ment is complicated because the pollutants tend to interact.
Also bioconcentration tends to expose the organism to a
higher concentration than would be expected. The inter-
action of the various factors is difficult to predict.
The fact that the effects of trace elements are species-
specific and can vary with environmental conditions make
assessment of these effects on ecosystems difficult. This
is complicated by the fact that laboratory-determined values
345
-------
TABLE 113. ADVERSE EFFECTS OF ELEMENTS ON ANIMALS
Element
Reduces animal grwth
Teratogenic
Cardiovascular pathology
Lesions of the brain and spinal oord
Hepatic lesions |
emulative |
Eye pathology [
Carcinogenic potential 1
Adverse effect on reproduction
Cocarcinogenic potential
Pulmonary potential
Hypertension
Renal pathology
Skin pathology
Skeletal pathology
Dental pathology
Gastrointestinal pathology
Shortens life span
Weight loss |
Blood pathology 1
Inhibition of enzyme systems
Greater percentage of protein/animal
CUT activity stimulated I
Gill damage |
1 *
J5 i-i
o
g 6
Q SP
li
Skeletal nuscle pathology 1
Reticuloendothelial system pathology 1
React with SH pproups of proteins 1
Interferes with Immunological systems 1
References
Antimony
Copper
+ +
+ +
+ +
+ -
+ +
+
+
+
+ +
+ +
+ +
+ +
+ +
+ +
+ +
+ +
+
+
76
76,162,148,183-194,147
Qutmiiin
Lead
+ +
+ +
+
+
+
+ +
+
+
+
+
+
+
+ +
+ +
+
+ +
+
+
+
+ +
76,148,162,195-203
] 76,197,148,162,204-20®
Berylliun
Arsenic
+
+
+ +
+
+
+
+
+
+
+
+
+
+
+
+
+
+ +
+
+
+
+
76,148,162,209-213
76,14&,197,162,79,214-217
Cackniun
Cobalt
+ +
+ +
+
+
+
+ +
+ +
+ +
+ +
+ +
+ +
+
+ +
+
+ +
+
+ +
+
+ +
162,197,148,149,218-223
197,148,162,186
Iran
Nickel
+ +
+ +
+
+ +
+
+
+
+ +
+
+
+
+
+ +
-
+
+
+
197,162
197,148,76,162,178,224-237
Seleniim
Thalllun
+
+
+
+ +
+ +
+
+
+
+
+
+
+ +
+ +
+ +
+
+
+ +
+ +
+
-r
+
-L
+ +
+ +
+ +
197,148,238-245
246-258
Mercury
Zinc
+
+
+ +
+
+
+
+
+
+
+
+
+
+
+
+
+ +
+
+ +
+
+ +
+ +
+
+
+ +
76,162,148,259-262
148,79,162,263-266
-------
TABLE 114. ADVERSE EFFECTS OF SEVERAL ORGANIC COMPOUNDS
AND ELEMENTS ON HUMANS
•
0 *4
•a
>»
IJ
s*.
00
>v
O -H
> W
ii 3
o
>
JS
4J
OS
a
4J
O.
4J
m
9i
« >>
O
Si
u
a}
References
O •
c
•O -H
•o
«
a.
«
aj
4
•H O
aj
0)
CO
O 60
a
.e
4 4-»
c
i-H
8 R-
N
g
u
0)
W O
m
0 JS
04 U
u
•H
« «
>* M
td U
«
c
i-H
CU
4>
e
3
-------
TABLE 115. HUMAN TOXICITY AND THRESHOLD LIMIT VALUES OF
SOME POTENTIAL POLLUTANTS FROM COAL CONVERSION PROCESSES (146)
Pollutant
Threshold limit
values
Effects
(ppm)
(mg/m3)
Elements
Antimony
0.5
Dermatitis, keratitis, conjunctivitis, and nasal septum
ulceration by contact fumes or dust
Arsenic
0.5
Arsine
0.05
0.2
Dermatitis, bronchitis, skin cancer, gastrointestinal
disturbances (arsenic); inhalation of arsine produces
hemolysis; combines with sulfhydral enzymes and interferes
with cellular metabolism; powerful poison by inhalation or
ingestion
Barium
0.5
Skin and mucous membrane irritant; toxic by inhalation or
ingestion; ingestion produces convulsions by changing cell
membrane permeability, thus producing indiscriminate
stimulation of all muscle cells
Beryllium
0.002
Highly toxic by inhalation; produces berylliosis.
dermatitis, and conjunctivitis; suspected carcinogen
Boron oxide
10
Moderately toxic via ingestion, inhalation, and skin
adsorption
Cadmium (dust and soluble salts)
0.2
Cadmium oxide
0.05
Inhalation produces pulmonary emphysema hypertension, and
kidney damage; ingestion produces gastrointestinal
inflammation and liver and kidney damage; interferes
with Zn and Cu metabolism; cadmium oxide - possible
human carcinogen
Chromium
Chromic acid, chromates
0.1
Dermatitis and ulceration of the skin and nasal sinuses;
toxic by inhalation or ingestion; carcinogenic
(incidence of lung cancer increased up to 15 times
normal in workers exposed to dusty chromite, chromic
oxide, and ores)
Cobalt (metal fume and dust)
0.1
Dermatitis; ingestion produces goiter
Copper (fume dusts and mists)
0.2
Skin and mucous membrane irritant; inhalation causes lung
and gastrointestinal disturbances
Iron oxide fume
5
Contact fumes or inhalation produces conjunctivitis,
Pentacarbonyl
0.08
choroiditis, retinitis, and siderosis
Soluble salts
1
Lead fumes and dusts
0.15
Cumulative poison, produces behavioral disorders, brain
damage, convulsions, death
(continued)
-------
TABLE 115. (continued)
Threshold limit values
Pollutant
(ppm)
(mg/m3)
Effects
Manganese
5
Inhalation of dust or fumes produces a clearly
characterized disease with progressive deterioration of
the central nervous system
Mercury and mercuric compounds
o
0
~-*
1
o
»—4
Nephritis, gastrointestinal tract disturbances, nerve damage
and death; depresses cellular enzymatic mechanisms by
combining with (-SH) groups
Nickel (metal)
1
Dermatitis; probable nasal cavity and sinus carcinogen
Selenium (fumes and oxide fumes)
0.2
Gastrointestinal upset; respiratory tract and skin
irritation; ingestion damages most organs (industrial
"selenosis")
Tellurium fumes
0.1
Loss of appetite, garlic breath, liver
Thallium
0.1
Loss of hair, pains in extremities; route of uptake:
Tin
Tin oxide
ingestion or skin absorption
10
Inhalation produces benign pneumoconiosis
Organic compounds
0.1
Inorganic compounds
2
Conjunctiva and respiratory tract irritant
Vanadium (dust)
0.5
V20s fume
0.1
Zinc oxide fume
5
Low toxicity; may cause dermatitis; respiratory tract
irri tant
Hydrocarbons
Benzene
25
80
Inhalation produces dizziness, weakness, headache; large
amounts cause central nervous system and bone marrow
depression, fatty degeneration, and congestion of
organs
Toluene
100
375
Produces slight bone marrow damage and central nervous
system depression
Naphthalene
10
50
Dermatitis; eye irritant; hemolysis in susceptible
individuals
Nitrogen and amino compounds
Most form methemoglobin and are skin and mucous membrane
Ani1ine
5
19
Toluidine
5
22
irritants; some produce kidney and liver damage and are
Quinoline
central nervous system depressants
Benzidine
Skin sensitization; bladder tumors
B-Naphthamine
Bladder cancer
(continued)
-------
TABLE 115. (continued)
Threshold limit values
Follutant
(PP»>)
(mg/m3)
Effects
U>
Ul
o
Phenol and derivatives
Creosote
Resorcinol
Hydroquinone
Gases
Sulfur oxides
Sulfur dioxide
Nitrogen oxides
Nitric oxide
Nitrogen dioxide
Hydrogen sulfide
Carbon disulfide
Carbon dioxide
Carbon monoxide
Carbonyl sulfide
Mercaptans
Cyanides (HCN)
(Salts)
Thiocyanates
Hydrogen fluoride
Fluorine
Hydrogen chloride
Ammonia
Ozone
Coal dust
Fatal doses depend
on compound
5 13
(industrial exposure)
25
5
10
20
5000
50
20 - 250
10
25
0.1
Not established,
respirable dust
30
9
15
60
9000
55
11
5
2
2
7
18
0.2
2
Highly toxic by ingestion, inhalation or skin absorption;
skin and mucous membrane irritants; poison to all cells
directly by denaturing and precipitating cellular proteins
Combines with water to form corrosive acid; eye, skin, and
mucous membrane irritant
Corrosion and irritation of skin, eyes, digestive tract or
lungs following ingestion or inhalation
Irritant and anoxic effects; causes damage to the central
nervous system; inhalation causes pulmonary edema
Causes damage to the central nervous system, peripheral
nerves and hemopoietic system; highly toxic by ingestion,
inhalation, and skin absorption
Inhalation produces tissue anoxia as a result of
carboxyhemoglobin production
Inhalation: decomposes to carbon dioxide and hydrogen
sulfide
Inhalation causes nausea and headache; high concentrations
produce cyanosis and depression of cerebral function
Increased respiration and cell paralysis; inhalation
produces lung congestion and dizziness; poisons by
inhibiting cytochrome oxidase system for oxygen
utilization in cells
Ingestion produces psychotic behavior and depressed cell
metabolic activity
Inhalation causes inflammation and necrosis of mucous
membrane; skin contact produces severe burns
Acts as direct cellular poison by interfering with calcium
metabolism and enzyme mechanisms
Forms corrosive acid; irritant and poison by inhalation
and injection; irritant to mucous membrane of eyes and
respiratory tract; produces pulmonary edema
Injures cells directly by alkaline caustic action;
irritation of mucous membranes; highly irritant via
inhalation or ingestion
Pulmonary irritation and destruction from inhalation
Usually asymptomatic; produces pneumoconiosis and
silicosis
-------
for toxicity (for example, LC5Q, LD^g, TLm) do not necessarily
reflect the relative pollution potential of compounds. For
example, the data of Wilkens (148) on the toxicity of several
elements to Daphnia magua fit the following equations:
Y50% = °*689 x ("1865) r = 0.99961 p =<0.001
and
y16% = 0.456 x (-1948) r = 0.99818 p = <0.001
where: Y = level causing 50% or 16% reproductive
impairment
x = LC^q of the individual metals
r = Pearson's product movement correlation
p = The chance that the observed correlation
is due solely to chance.
This indicates that the LC^q is very useful in predicting
the relative pollution potential of these 19 elements.
However, the data of Katz (149) on LC^q and concentrations
that impaired conditioned avoidance response showed, for
arsenic, lead, mercury, and selenium on goldfish, no cor-
relation with a linear equation (r = -0.426), a power curve
(r = +0.460), an exponential curve (r = -0.033), or a
logarithmic curve (r = +0.192). This indicates that the LC^q
is useless in predicting the relative effect of these ele-
ments on this environmentally significant phenomenon.
Toxicity Levels--
The approximate toxicity of the trace elements is found
in Table 116. In this table, "very toxic" indicates that
the toxic effects are seen at concentrations below 1 ppm in
nutrient solution of plants or microorganisms or water for
351
-------
TABLE 116. GENERAL TOXIC EFFECTS OF ELEMENTS TO PLANTS,
ANIMALS, AND MICROORGANISMS
Element
Plant toxicity
Animal toxicity
Microorganism toxicity
References
Aluminum (Al)
moderately to most
plants
slightly
76,88
Antimony (Sb)
moderately
moderately
very as hydride
moderately
76,79
Argon (Ar)
not
not
76
Arsenic (As)
moderately
highly, esp. AsH^ to
moderately,
carcinogenic,
teratogenic
moderately
76,79
Barium (Ba)
moderately
slightly
76
Beryllium (Be)
very to moderately
very - carcinogenic
very to moderately
76,79,162
Bismuth (Bi)
moderately
moderately in soluble
form
76
Boron (B)
very to moderately
slightly
very to slightly
76,88,153,328
Bromine (Br)
Br2' very
Br-: relatively harm-
less
BrOx: moderately
Br2"- very
Br": relatively harm-
less, very as
hydride
very
Br": relatively harmless
76
Cadmium (Cd)
very to moderately
very to moderately,
cumulative in mammals
very in fish and
Daphnia magna
very to moderately
76,79,162
Calcium (Ca)
relatively harmless
relatively harmless
relatively harmless
76
Cesium (Cs)
relatively harmless
relatively harmless
relatively harmless
76
(continued)
-------
Element
Plant toxicity
Chlorine (CI)
Chromium (Cr)
relatively harmless as
CI", moderately to
highly toxic as CI2,
CIO" or CIO3
Cr(III): moderately
Cr(IV): highly
CR(VI): moderately
Cobalt (Co)
Copper (Cu)
very
very to moderately
Fluorine (F) moderately
Germanium (Ge) slightly
Hafnium (Hf)
Helium (He)
Iodine (I)
siightly
harmless
slightly
Iron (Fe) moderately to slightly
Lanthanium (La) slightly
Lead (Pb) very - moderately
iLE 116. (continued)
Animal toxicity Microorganism toxicity
References
see plants see plants
Hydride: very
Cr(III): moderate to very
veryyCr(IV): very,
carcinogenic;
Cr(VI): very to
moderately
invertebrates: very to very to slightly
slightly; fish: very*,
mammals: slightly to
moderately J
tadpoles: very
very to moderately moderately
slightly except as
GeHa which is highly
toxic in mammals
slightly slightly
harmless harmless
slightly
very toxic as hydride
slightly slightly
slightly slightly
very to moderately, very to slightly
cumulative in mammals
(continued)
76
76,79,84
76
76,84,323,
79,162,148
76
76
76
76
76,162
76
76
76,79,328,
162,148
-------
Element
Plant toxicity
Lithium (Li) slightly
Magnesium (Mg) relatively harmless
Manganese (Mn) moderately
Mercury (Hg) very
Molybdenum (Mo) moderately to rela-
tively harmless
Neodymium (Nd) scarcely
Nickel (Ni) very to moderately
Phosphorus (P) phosphates are rela
tively harmless
Polonium (Po)
Potassium (K) relatively harmless
Praseodymium slightly
(Pr)
Radium (Ra)
1.E 116. (continued)
Animal toxicity Microorganism toxicity
slightly, teratogenic
relatively harmless
moderately
very to moderately ,
cumulative
slightly
relatively harmless
moderately
very
moderately to slightly moderately
References
76,77
76
76
76,79,328
76,162
scarcely scarcely
invertebrates: very, very to moderately
fish: moderately to very
mammals: moderately but
Ni(CO)4 is highly toxic
and possibly carcino-
genic
white P4 and PH3 are phosphates are relatively
highly toxic to mammals; harmless
phosphates are rela-
tively harmless
highly
relatively harmless
slightly
relatively harmless
slightly
76
76,79,234,
329,154
76
76
76
76
the high toxicity to
mammals is probably due
to the radioactivity
76
(continued)
-------
TABLE 116. (continued)
Element Plant toxicity Animal toxicity Microorganism toxicity References
Radon (Rn)
the high toxicity to
mammals is probably due
to the radioactivity
76
Rubidium (Rb)
scarcely toxic in the
presence of K
see plants
oxides: very
see plants
76
Samarium (Sin)
slightly
76
Scandium (Sc)
slightly
slightly
slightly
76
Selenium (Se)
moderately
very to moderately
76,148
Silicon (Si)
slightly
slightly, but large
amounts in mammalian
lung are harmful
slightly
76
Silver (Ag)
very to moderately
very
very to moderately
79,76,162
Sodium (Na)
relatively harmless
relatively harmless
relatively harmless
76
Strontium (Sr)
slightly
slightly
76
Tantalum (Ta)
slightly
siightly
slightly
76
Tellurium (Te)
moderately
very
76
Thallium (T1)
moderately
very to moderately,
cumulative
moderately
76,79,148
Thorium (Th)
slightly
slightly
siightly
76
Tin (Sn)
very
very as SnH^
76
Titanium (Ti)
relatively harmless
relatively harmless
relatively harmless
76
Tungsten (W)
moderately
slightly
76
(continued)
-------
TABLE 116. (continued)
Element Plant toxicity Animal toxicity Microorganism toxicity References
Uranium (U) moderately moderately moderately 76
Vanadium (V) moderately moderately moderately 76
Ytterbium (Yb) slichtly slightly slightly 76
Yttrium (Y) slightly slightly slightly 76
Zinc (Zn) moderately fish: very to slightlyj very to slightly 76,79,328,
non-aquatic organisms: 162
slightly
Zirconium (Zr) moderately slightly 76
-------
aquatic animals, and the dietary LD^q of animals occurs in
the 1 to 10 mg/kg body weight. "Moderately toxic" indicates
that the toxic effects appear at levels of 1 to 100 ppm in
nutrient solutions for plants or microorganisms or water for
aquatic animals or the LD^q for animals lies in the 10 to
100 mg/kg range. "Slightly toxic" indicates that toxicity
is rarely seen in plants or microorganisms or aquatic animals,
and the LD^q for animals occurs at a dietary level of 100 to
1000 mg/kg body weight. "Relatively harmless" indicates
that the LD^q for animals is greater than 1000 mg/kg. More
specific information is available in the references indicated.
The toxicity refers to the toxicity of the element in a
biological rather than a radiological sense, unless specified
otherwise.
Obviously, elements or their compounds which are listed
as "very toxic" in Table 117 should have very stringent guide-
lines. This should be reflected in the MEGs of these com-
pounds. Analysis of the MEG methodology can be used to esti-
mate the value of the MEG called the "Maximum Acute Toxicity
Effluent" (MATE) and the value of the MEG called the "ambient
level goal." Elements or their compounds listed as "moderately
toxic" will probably eventually have an emission MATE greater
3 3
than 4.5 yg/m , an effluent MATE greater than 67.5 yg/m , and
a MATE for land-destined wastes greater than 0.135 ppm. The
ambient level goal for those elements and their compounds
listed as "moderately toxic" for air probably will be greater
than 0.011 yg/m , for water greater than 0.16 ppb, and for
soil greater than 0.0003 ppm. Elements and their compounds
listed as "slightly toxic" will probably have emission MATEs
3
greater than 45 yg/m , effluent MATEs greater than 675 ppb,
and MATEs for land-destined wastes greater than 1.35 ppm. The
ambient level goals for those elements and compounds listed as
"slightly toxic" for air will probably be greater than 0.11
357
-------
TABLE 117. STANDARDS AND ACCEPTABLE LEVELS OF TRACE ELEMENTS
Name
Drinking
water
standard
Of/i)
Standard as
critical con-
centration in
potable water (ng/1)
Maximum
acceptable
concentration
for livestock
drinking water-
(rag/1)
Estimated permissible
concentration
Air Water
(mg/m3) (mp,/l)
Acceptable
level
freshwater
"critical
concent rat ion"
(ng/l)
Acceptable
level
marine water
"critical
concentration"
(mp/1)
Derived
freshwater
standards
EPA pro-
posed basis
(trg/1)
Derived
marine
standards
EPA pro-
posed basis
(mg/l)
Alinrinun
0.01
Antimony
0.05
0.05
1.2
0.007
0.20
0.003
0.04
Arsenic
0.05
0.01
0.2
0.005
0.05
0.02
0.002
0.002
Bariun
1.0
1.
1.0
Bervlliurt
1.0
1.0
0.01
0.004
0.100
0.02
0.01
Bisnuth
0.1
0.1
0.002
Boron
1.0
7.4
0.043
Bromine
3.0
Cadmiun
0.01
0.01
0.05
0.12
0.010
0.00001
0.0004
0.0004-0.003a
0.0003
Chrcftiiun
0.05
0.02
1
0.12
0.05
0.005
0.00006
0.003
0.05
Cobalt
0.05
0.05
1
0.12
0.0007
0.100
0.003
Copper
0.1
0.01
0.5
0.02
0.001
0.0005
0.001
German iun
0.5
0.5
0.5
1.
Lead
0.05
0.01
0.1
0.36
0.05
0.01
0.005
0.01
0.01
Magnesiim
10
14
0.083
Manganese
0.05
0.01
12
0.05
0.01
0.002
0.1
Mercury
0.002
0.002
0.001
1.3
0.0003
0.001
0.00005
0.0002
0.0002
Nblybdemm
0.5
0.5
12
0.07
0.01
0.13
0.005
Nickel
0.05
0.05
0.24
0.001^
0.005
0.001
0.008
0.001
Radiun
0.001
Rubiditm
5
Selenium
0.01
0.01
0.05
0.5
0.01
n.ooi
0.002
0.0001
Silver
0.001
0.024
0.05
0.001
0.005
0.0005
Strcntiun
5.5
0.027
a Soft water value - hard water value
(continued)
-------
TABLE 117. (continued)
Naoe
Drinking
water
standard
(mg/i)
Standard as
critical con-
centration in
potable water (ing/1)
Maximum
acceptable
concentration
for livestock
drinking water
(ng/l)
Estimated permissible
concent ration
Acceptable
level
freshwater
"critical
concentration"
(rag/i)
Acceptable
level
marine water
"critical
concentrat ion"
(Mg/1)
Derived
freshwater
standards
EPA pro-
posed basis
(ng/i)
Derived
marine
standards
EPA pro-
posed basis
tog/l)
Air -
(ng/nr0
Water
(mg/1)
Hialliun
0.005
0.01
0.0001
0.005
Thoriua
0.0005
0.01
Tin
0.05
0.05
Titaniun
0.1
14
0.083
Tungstei
100
100
Uraniun
0.5
Vanadiun
0.1
0.1
0.1
1.2
0.007
0.05
0.01
0.025
Zinc
5
0.05
25
9.5
5
Zirconiun
1
Reference
149
78
78
330
78
-------
o
yg/m , for water probably greater than 1.6 ppb, and for land
probably greater than 0.003 ppm. The emission MATEs for
elements and their compounds listed as "relatively harmless"
3
will probably be greater than 450 yg/m . The effluent MATEs
will probably be greater than 6,750 ppb, and the MATEs for
land-destined wastes will probably be greater than 13.5
ppm. The ambient level goals for those elements and their
compounds listed as "relatively harmless" will probably be
greater than 1.1 ug/m for air, 160 ppb for water, and 0.03
ppm for land. Until more specific information is available,
these numbers can be used as the basis for developing stand-
ards. When the actual MEGs are prepared, they will probably
indicate that less stringent standards will be satisfactory.
While Table 116 presents the range of toxicity levels for
animals, plants, and microorganisms, Table 115 lists the
threshold limit values on humans for several compounds
likely to be present in coal conversion processes. It is
obviously impossible on the basis of available data to
determine the dietary intake of trace elements, or the
contribution of liquefaction processes to these intakes.
Table 117 lists standards and acceptable levels of
numerous trace elements found in liquefaction waste streams.
Such standards need to be compared with discharges and
runoff from treated wastes at various points distant from
the source. Only then can we accurately assess the pollution
potential from trace elements.
The toxicity data in Table 116 fails to take into account
antagonistic or synergistic action between pairs of trace
elements. Table 118 lists the reduction of toxic effects of
one trace element by another. The problem of synergistic
and antagonistic effects has been partly rectified by use of
gross effluent components of effluent streams such as fly ash
360
-------
TABLE 118. REDUCTION OF TOXIC EFFECTS OF ONE
TRACE ELEMENT BY ANOTHER
Carmen Name
Scientific Name I
Reference
Microbe
Vibrio aholerae Ogawa
Magnesium restored nickel inhibited
acid production and glucose utili-
zation
331
Plants
Nickel interferes with plant ab-
sorption of iron and sufficient iron
reduces the phytotoxicity of nickel
Selenium reduces the toxicity of
cadmium and mercury
77
103
Rac
Hattu8 sp.
Copper addition overcomes zinc
induced anemia and reduction of liver
catalyse and cytochrome oxidase
79
Rat
Rattue ep.
Calcium and phosphorous overcome
zinc's antagonistic effect on the
deposition of calcium gnd phos-
phorous in bone
79
Freshwater
algae
Chlorella
Toxicity of Ni eliminated by Ma2EDIA
and reduced by zinc
332
Oats
Avena ealiva
Both root and shoot weights were
restored when the plants were ex-
posed to nickel in the presence of
magnesium or calcium
333
Freshwater
algae
Anacystie nidulane
Anabaena variabilie
Anabena doliolum
In all three species, aliro? *rcwn in
media attaining sulfur were less
prone to the toxic effects
Chicks
Addition of dietary copper or silver
(1000 ppm) counteracted the toxic
effects of 40 ppm dietary seleniun
Selenitm to 5 ppm in diet has
mildly protective action against
toxic effects of lead.
33A
335
Rats
Selenium and mercury are mutually
antagonistic.
336
Hamsters
Sodiun selenate reduces teratogeni-
city of injected cadnium if injected
within 1/2 hour (both compounds at
2 ppm in mother. Sodiun selenate
not teratogenic at this concentra-
tion.)
Z'Ui
361
-------
or mine drainage waters. These studies lack the more
carefully controlled studies of a single pollutant but may
be more environmentally significant.
Organic Compounds
Organic compounds may affect organisms in a variety of
ways and to different degrees. The hazard presented by such
compounds may take such forms as subacute toxicity, acute
toxicity, chronic toxicity, carcinogenicity, mutagenicity
and teratogenicity. Some of these adverse effects are
listed in Table 119 for selected compounds potentially
emitted by liquefaction process plants. A plus sign (+) means
the effect is observed. A minus sign (-) means the effect is
not observed. Blank spaces are left when information is not
available so that the reader can fill in the blanks as infor-
mation becomes available.
Toxicity--The toxicity of coal liquefaction wastes and
product oils is an important concern in determining the
environmental impact of various liquefaction processes.
Table 120 lists the toxic effects of various organic compounds
to the "most sensitive organisms" found during a relatively
thorough literature search. These acute toxicities cannot
be used absolutely to predict chronic effects, partially
because the toxicities themselves are functions of numerous
variables but mainly because chronic effects usually occur
at levels far below the level exhibiting the acute toxicity.
The chronic effects may not even be accurately predicted by
the acute effects, as is illustrated in Table 121. A most
noteworthy case is the carcinogenic polynuclear aromatic
compounds which have a low acute toxicity but a high carcino-
genicity potential (83). In addition, acute toxicity tests
362
-------
TABLE 119. ADVERSE EFFECTS FOR SELECTED ORGANIC
COMPOUNDS POTENTIALLY EMITTED BY LIQUEFACTION
PLANTS (79,146)
Compound
Acute toxic effect
Carcinogen
Reticuloendothelial system
pathology
Gastrointestinal pathology
Reproductive system
pathology
Hepatic pathology
Renal pathology
Respiratory system
pathology
Hormonal pathology
Cocarcinogen
Mutagen
7, 12-Dimethylbenzo
[a]anthracene
+
+ + +
+
+
+
+ + +
Benzo[a ]pyrene
+
+
+
+
- or +
3-methylcholanthrene
+
+
+
+
+
Anthracene
-
Di benzo [<[,h]anthracene
+
n-dodecane
"
+
Dodecylbenzene
-
+
Decahydroriaphtha 1 ene
-
1 -dodecanol
+
1-phenyldodecane
+
Phenols
+
Formaldehyde
_
Furfura 1
+
Benzo[e]pyrene
-
3-hydroxybenzo[aJpyrene
-
+
Dibenzo[^,c]anthracene
-
.
D1benzo[a,h]anthracene
+
+
B-naphthylamine
+
Isophorone
+
+
Benzene
+
+
Ethylbenzene
Acenaphthene
+
Blank space - nothing found in available literature, reader can add in-
formation as it becomes available
+ - compound exhibits this characteristic
+++ = compound exhibits very potent effects of this characteristic
- - compound does not exhibit this characteristic
363
-------
This table is designed to list the concentrations at
which the biological effects have been observed with the
most sensitive organisms studied. It does not indicate safe
concentrations for these compounds since more subtle effects
may not have been observed as yet nor does it attempt to
list synergistic effects. This table does indicate concentra-
tions which will definitely alter the environment.
This type of information will be used to help determine
the MEGs and will be incorporated in the MEGs when they
become available.
TABLE 120. MOST SENSITIVE ORGANISMS TO
VARIOUS ORGANIC CHEMICALS (79)
Most Sensitive Marine or Estuarian Microorganisms
Acenaphthene: The red algae, Antithamnion plumulas showed a
3 percent growth inhibition in the sporelings at levels of
0.03 ppm (1.9xl0-6 molal) (337).
Anthracene: The red algae, Antithamnion plumula, showed in-
hibition of growth by 20 percent when exposed to levels of
300 ppm (1.7x10-3 molal) (337).
Benzene: The algae, Amphidinum aarterae, were inhibited by
0.001 ppm (1.3x10-8 molal) (338).
Chrysene: The red algae, Antithamnion plumula, showed
stimulation of growth by 58 percent when exposed to 0.300
ppm (1.3x10" molal) (79).
Naphthalene: The bacteria, Vibrio parahaemolyticus} suf-
fered 42 percent growth reduction at 5.8 ppm (4.5xl0"5
molal) (339).
Toluene: The phytoplankton, Skeletonema aostatum and
Cricosphaera oarteras3 showed reduced growth at 20 ppm
(2.2x10-4 molal) (340).
(continued)
364
-------
TABLE 120. (continued)
Most Sensitive Freshwater Microorganisms
Benzene: The green algae, Chlorella vulgaris 3 showed
inhibited growth at 25 ppm (3.2x10"^ molal) (341).
Naphthalene: The green flagellate, Chylamydomonas angulosa,
lost photosynthetic capacity when exposed to more than 0.010
ppm (7.8x10~8 molal) (342).
Phenol: The green algae, Chlorella vulgaris3 showed growth
inhibition when exposed 0.01 ppm (1.1x10"7 molal) (343).
Most Sensitive Nonaquatic Microorganisms
Acenapthene: Sordaria fimioola, Coniophora puteana, and
Aspergillus kanagawaensis all showed 100 percent inhibition
of increase in colony diameter or cell number at 80,000 +
20,000 ppm (0.52 [0. 39-0. 65] molal) (344).
3,4-Benzopyrene: The ciliate, Tetrahymena pyriformis s
suffered complete clearing of colonies at 0.010 ppm (4.0x10"^
molal) (345).
Fluoranthene: The ciliate, Tetrahymena pyriformis, exhi-
bited a medium inhibition at 0.100 (4.9xl0"7 molal) and
complete clearing at 0.200 ppm (9.9x10-7 molal) (346).
Isophorone: Cryptoooocus neoformans suffered complete
growth inhibition at 0.0025 ppm (1.8x10-8 moles/kg agar)
(347).
Toluene: The bacteria, Escherichia oolis suffered decreased
viability at 1.3 ppm (1.4x10"^ molal) (348).
(continued)
365
-------
TABLE 120. (continued)
Most Sensitive Plants
Ethylene: Exposure of tomatoes and pepper plants, orchids
and carnations to 0.1 ppm (3.6xl0"6 moles/air) for a few
hours affected flowers and caused epinasty and leaf abscis-
sion (349).
PAN (CH3 [C0]02N02): Exposure of spinach, romaine lettuce,
and certain flowers to 0.03 ppm (2.5x10"' moles/kg air)
produced bronzing of the lower leaf surface (with the upper
surface normal) and supressed growth. The younger leaves
appeared more susceptible (349).
pH: The rooted macrophyte, Lobelia dormanna, when grown at
pH 4.0 showed reduction of growth and oxygen production
reduced 75 percent and the flowering period was delayed 10
days when compared to controls grown at pH = 4.3-5.5 (350).
Toluene: Tomatoes were irreversibly damaged by exposure to
vapor containing 12 ppm (1.3x10"^ moles/kg vapor) for 15
minutes (351).
Most Sensitive Marine or Estuarian Invertebrates
Benzene: The marine grass shrimp, Palaemonetes pugio,
showed a 96-hour LC^q of 27 ppm (3.5x10"^ molal) (352).
Phenol: The tidal pool copepod, Tigriopus californieus3
showed a 48-hour LC^q of 0.5 ppm (5.3x10-6 molal) (354).
Toluene: The marine grass shrimp, Palaemonetes pugio,
showed a 96-hour LC^q of 9.5 ppm (1.0x10"^ molal) (355).
(continued)
366
-------
TABLE 120. (continued)
Most Sensitive Freshwater Invertebrates
Acridine: Water fleas, Daphnia pulex3 showed a 24-hour LCca
of 4.8 ppm (2.7x10-5 molal) (79). DU
Benz(a)acridine: Water fleas, Daphnia pulex, showed a 24-hour
LC^g of 0.4 ppm (1.7x10-6 molal) (79).
Benzene: The newt, Molge vulgaris, showed mitotic changes
when exposed to 0.135 mg/g (1.73x10-3 moles/kg) (356).
Naphthalene: The brown shrimp, Penaeus azteous, showed a
24-hour LC^g of 2.5 ppm (2.0xl0"5 molal) (357,298).
pH: The amphipod, Gammarus laaustris3 an important element
in the diet of trout in Norwegian lakes where it occurs, is
not found in lakes with pH less than 6.0. Experimental
investigations have shown that the adults of this species
cannot tolerate 24-48 hours of exposure to pH 5.0 (350).
Phenol: The freshwater snail, Helisoma tuvolis, showed in-
hibited oxygen consumption at 2 ppm (2.1xl0"5 molal) (358).
Most Sensitive Marine Or Estuarine Fish
Benzene: The striped bass, Monorone saxatilis, showed a 96
hour LC50 of 0.0096 ppm (1.2x10-7 molal) and decreases in
weight and percent fat 0.0031 ppm (3.9x10-8 molal) (359).
Naphthalene: Fingerling silver salmon were exposed to 3.2
ppm (2.5x10-5 molal). They showed a LT50 of less than 9.25
hours and a LT-^qq of less than 20.75 hours (360).
(continued)
367
-------
TABLE 120. (continued)
Phenol: The anchlorie, Stolevhorus purpurenus, showed a 12-
hour TLm of 0.51 ppm (5.4xl0~° molal) (361).
Most Sensitive Freshwater Fish
Benz(a)anthracene: Bluegills, Lepomis macrochirus3 were ex-
posed to 1 ppm (4.4xl0"6 molal) for a period of 6 months.
Eighty-seven percent of the animals died (79).
Benzene: The bluegill, Lepomis maoroehirus 3 showed a 96-
hour TLm °f 22.5 (95 percent confidence interval: 17.5-28.4)
ppm [2.9(2.2-3.6)xl0~4 molal] (362).
Benzidine: The fathead minnow, Pimephales pvomelas} showed
a 96-hour TLm of 2 ppm (1.1x10-5 molal) (79).
Ethylbenzene: The bluegill, Lepomis maavoohirus3 showed a
96-nour TLm of 32 ppm (3.0x10"^ molal) (211).
Naphthalene: The sheepshead minnow, Cyprinodon variegatus 3
showed a 96-hour LC^q of 2.4 ppm (1.9xl0"5 molal) (357).
pH: The smallmouth bass, Mioropterus dolomieui, walleye,
Stizostedion vitreum3 and burbot, Lota lota} stopped repro-
duction in the pH range of 6.0+ to 5.5 in acidic lakes of
the La Cloche Mountains near Sudbury, Ontario. If the
smallmouth bass and walleye are considered desired species,
then the pH must be greater than 6 (363) .
Phenol: The rainbow trout, Salmo gairdnerii, showed a 48-
hour LC50 of 7.5 ppm (8.0x10-5 molal) in hard water (290 ppm
CaC03) (79).
Toluene: The goldfish, Cavassius auratus3 showed a 96-hour
LC50 of 22.8 (95 percent confidence interval: 17.0-30.0) ppm
(2.5(l.8-3.31x10-4 molal) and a 720-hour LC50 of 14.6 (10.7-
20.0) ppm (1.6[l.2-2.2]xl0-^ molal) (330).
(continued)
368
-------
TABLE 120. (continued)
Most Sensitive Amphibians
Polynuclear Aromatic Hydrocarbons: Frogs, Rana pipiens,
developed renal neoplasms after exposure to 0.3-0.5 mg (1.1—
1.8x10-6 moles) of 1,2,5,6-dibenzanthracene (DMBA) while the
same concentration of 3,4-benzpyrene (BP), 5,7-dimethyl-l,
2-benzacridine or 3-methylcholanthrene (3MC) was lethal to
all treated frogs within 5 days. DMBA was more effective
than 3MC or BP in producing supernumerary fins and noto-
chords in Bufo arenarum tadpoles following chemical implan-
tation (148).
Most Sensitive Bird
Carbon monoxide: Chickens showed reduced hatching when
exposed to 425 ppm (0.015 moles/kg air) (117).
Most Sensitive Nonhuman Mammals
Acenapthalene; Mice, Mus sp., showed an oral LD50 of 2.1
g/kg (1.4x10-2 moles/kg) (364), and rats, Rattus sp., showed
an i.p. LD50 of 600 + 60 ppm (3.9(3.5-4.3}xl0~3 moles/kg)
(365).
Benzene: Laboratory Sprague-Dawley rats, Rattus sp., showed
significant decreases in white blood cell count when subjec-
ted to the following combination of conditions:
65 ppm (8.3x10"^ moles/kg air) for 26 out of 39 days
47 ppm (6.0x10"^ moles/kg air) 180 out of 240 days
for 7 hours/day.
No change in the white blood cell count was observed at 31
ppm (4.0x10-4 moles/kg air) for 7 hours/day 90 out of 126
days. Abnormalities of the lungs and spleen were noted
(366).
Laboratory Osborne-Mendel rats, Rattus sp., showed an oral
LD50 of 4080 (95 percent confidence interval: 3260-5100)
ppm (5. 2 [4. 2-6. 5]xl0"2 moles/kg) (367,368).
(continued)
369
-------
TABLE 120. (continued)
Benzidine: In Sprague-Dawley rats, Rattus sp. , 12 mg/rat
(6.5x10"5 moles/rat) is carcinogenic (369).
Benzopyrene: Rats, Rattus sp., showed a significant increase
in the number of resorbed or malformed fetuses when exposed
to oral or subcutaneous administration of 1-5 mg (0.4-
2.0x10~5 moles) of benzopyrene (79).
Carbon monoxide: Rats, Rattus sp., showed a decreased
ability of the liver to metabolize 3-OH benzon-alpha-pyrene
when exposed to 60 ppm (2.1xl0~3 moles/kg air) carbon
monoxide (117).
Pregnant rabbits, Sylvilagus sp., were exposed to 90 ppm
(3.2xl0~3 moles/kg air) for 30 days. Exposure during first
pregnancy resulted in carbonmonoxyhemoglobin concentrations
of 9 to 10 percent. Birth weight decreased 12 percent.
Neonatal mortality increased from 4.5 percent in controls to
10 percent in exposed. Mortality during the following 21
days increased from 13 to 25 percent (117).
Carbonmonoxyhemoglobin levels as low as 2 percent in animals
decreased the p02 of brain and liver (117).
1,2,5,6-Dibenzanthracene: Mice, Mus sp., showed 30 tumors
in 67 animals when exposed to 30 to 40 micrograms (1.1-
1.4x10"7 moles)/mouse (79).
Ethylbenzene: Rats, Rattus sp., showed toxic effects in the
kidney and liver when exposed to repeated 7-hour inhalation
exposure to 400 ppm (3.8x10"^ moles/kg air) over a period of
144 to 214 days (370).
Fluoranthene: Carworth-Wistar rats, Rattus sp., showed a
14-day oral LD^q of 2.0 mg/kg (9.9xl0~6 moles/kg) (371).
Fly ash: Guinea pigs showed inflammatory lesions in the
terminal bronchioles of the lung which were characterized
as moderate hyperplasia of the epithelium when exposed to
combination of fly ash (0.55 micrograms/cubic meter) and
sulfuric acid aerosol (117).
(continued)
370
-------
TABLE 120. (continued)
Gasoline: Mice, Mus sp., showed a significantly greater (p
less than 0.05) incidence of lung tumors when exposed to 24-
30 ppm unleaded gasoline in air (117).
Hydroquinone: ICR-JCL mice, Mus sp., showed a 6-day LD50 of
190 mg/kg(l.7x10~3 moles/kg) (79).
Hydroxyhydroquinone: ICR-JCL mice, Mus sp., showed a 6-day
LD^q of 122 ppm (9.7x10-4 moles/kg) (79).
Isophorone: The laboratory rat, Rattus sp., showed a 14-day
LD50 of 1.87 g/kg (0.014 moles/kg). Inhalation of 880 ppm
(6.4x10~3 mole/kg air) for one hour caused serious organ
damage. Rats died as a result of a 4-hour exposure to 1840
ppm (0.013 mole/kg air) but not at lower concentrations.
Rabbits, Sylvilagus sp., showed a cutaneous LD50 of
1.50 mg/kg (1.1x10-5 moles/kg) (283,372).
Naphthalene: Rats, Rattus sp., showed an oral LDcn of 9.43
mg/kg (7.4x10"^ moles/kg) (373).
N-nitroso compounds: Repeated doses of 2x10"^ moles/kg body
weight (circa 10 ppm for N-nitrosodimethylamine) have
induced a high incidence of tumors in rodents within their
lifetimes (79).
Phenol: ICR-JCL mice, Mus sp. , showed a 6-day LD,-n of 344
ppm (3.7xl0~3 moles/kg) (79).
Potassium phenylsulfate: ICR-JCL mice, Mus sp., showed a 6-
day LD50 °f 1890 ppm (8.9x10-3 moles/kg) (79).
Pyrocatecol: ICR-JCL mice, Mus sp., showed a 6-day LDRn of
247 ppm (2.2x10-3 moles/kg) (79).
Sulfuric acid: Mice, Mus sp., showed a reduced physical
clearance of radio-labelled streptococcus particles deposi-
ted in the nose and lungs when exposed to a concentration of
15 micrograms/cubic meter (3.7x10-3 ppm, 3.8x10-8 moles/kg
air) (117).
(continued)
371
-------
TABLE 120. (continued)
Toluene: Mice, Mus sp., showed decreased^wheel turning
activity after exposure to 1 ppm (l.lxlO-^ moles/kg air)
(374), and Sprague-Dawley rats, Rattus sp., showed an LDcn
of 9.43 ppm (7.4x10~5 moles/kg) (178).
Humans, Homo Sapiens
Particulates: Increased mortality was demonstrated from
chronic respiratory diseases and all causes when exposed to
an average concentration of 100 micrograms/cubic meter for 2
years. In addition, exposure to 80 to 100 micrograms/cubic
meter for 24 hours aggravated cardio-respiratory symptoms in
healthy persons and in elderly patients with heart and lung
disease as well as increasing asthma attacks in people with
that application. Best judgement estimates of the threshold
levels for increases in acute lower respiratory tract infec-
tions in children were 3 years of exposure to 102 micrograms/
cubic meter (117).
Benzene: An increase in incidence of Hodgkin's Disease was
shown after occupational exposure to 150-210 ppm (1.9-2.7
xl0"3 moles/kg air) for 1-28 years (117). Leukemia was also
associated with occupational exposure to benzene over a 10"
year period (117). Inhalation of 250-500 ppm (3.2-6.4x10-3
moles/kg air) induced signs and symptoms of mild poisoning
characterized by vertigo, drowsiness, headache, and nausea
(375).
_3
Ethylbenzene: One thousand ppm (9.4x10 moles/kg vapor)
induced transitory eye and respiratory tract irritation.
Vertigo and dizziness developed at a level of 2000 ppm
(1.9x10-3 moles/kg air) (117).
372
-------
are usually run on pure compounds precluding observation of
possible synergistic effects. However, when lacking informa-
tion on chronic effects, Table 120 can be used to indicate
the level of compound for which an adverse environmental
effect can definitely be expected.
TABLE 121. SUMMARY OF ENVIRONMENTAL INFORMATION
ON CLASSES OF ORGANIC COAL CONVERSION EFFLUENTS (83)
Class
Acute toxicity
Chronic effects
Phenols
High
Low
Monoaromatics
Moderate
Low
Polycyclic aromatics
Low
High
Aromatic amines
Moderate
High (?)
Thiophenes
Moderate
High (?)
The significance of synergistic and antagonistic effects
is illustrated in Table 122. The numbers in the table are
the ratio of the predicted to the observed LD^q of
various organic compounds when any two of the compounds are
administered together in one solution. The predicted LD^q
was calculated by assuming the toxicities to be additive,
i.e., if the LD^q for compound A were 2 ppm and the LD5Q for
compound B were 1 ppm, the for 1:1 dilution of each by
the other should be 1/2(2) + 1/2(1) =1-1/2. A ratio greater
than unity shows that the toxicity of one or both compounds
is increased by the presence of the other. For example, a
mixture of acetonitrile and acetone is much more toxic than
either compound alone.
In this table, the term, Ucon, is the trademark for a
series of polyalkane glycols and diesters. Tegital is the
trademark for a series of nonionic and anionic surficants,
and PEG is the abbreviation for polyethylene glycol. Cells
have been used as an abbreviation for cellulose. Certain
obvious trends have been observed relating toxicity to
373
-------
TABLE 122. UNADJUSTED RATIOS OF PREDICTED TO OBSERVED LD50 VALUES
OF 350 PAIRS OF CHEMICALS MIXED 1:1 BY VOLUME (376)
Ucon
LB250
Ucon
50HB260
Toluene
Tetrachlor
Tergitol XD
Propylene
oxide
Propylene *
glycol
PEC, 200
Phenyl
eel 1.
Nitrobenzene
Morpholine
IaOphorone
Formalin
Ethylene
Glycol
Ethyl
alcohol
Ethyl
acrylate
Ethyl
acetate
Dioxane
Diethan-
olamine
Carbon
tet .
Butyl
ether
Butyl cell.
Aniline
Acrylo-
nitrile
i C i -
DC ' -
4-1 C -
b - -
< C. < Z
Acetone
Aceconitrile
0.53 0.50
1.12 1.73
1.33 1.83
2.33 2.02
0.83 0.44
1.54 0.55
0.88 0.99
2.27 1.23
0.65 1.47
0.75 0.85
0.77 1.62
0.96 1.30
1.81 0.45
1,46 0.86
0.86 ¦.08
0.85 1.05
0.91 1.16
0.67 3.15
0.98 1.28
0.74 0.64
0.95 1.08
1.00 1.06
0.87 1.17
0.81 1.17
1.19 - h
3.31
Acetophenone
Acrylonitrile
0.45 0.63
1.00 0.96
1.84 328
1.40 1.47
0.87 0.50
1.56 0.50
0.67 0.62
0.76 0.88
0.66 0.96
1.08 0.82
1.01 0.51
0.45 1.04
1.32 0.58
1.10 0.77
2.15 0.78
0.55 1.08
1.57 }.S5
1.00 3-86
1.43 1.06
1.27 0.73
0.58 2.22
0.23 1.12
1.29 1.49
0.80 1.12
0.76 0.49
0.74
Aniline
Butvl cell
0.54 0.89
0.92 0.88
0.75 092
1.39 1.55
0.78 0.60
0.73 0.64
0.71 1.12
1.30 1.4*
0.75 1.32
0.50 0.85
0.31 0.60
1.35 1.12
0.71 0.54
1.21 0.89
0.S3 0.90
1.10 0.79
0.67 1.02
0.64 1.70
0.97 0.70
1.39
Butyl ether
CirSon
Tetrachloride
0.53 1.34
6: 0.ST
0.59 2.76
1.51 1.74
1.18 0.56 | 0.67 0.80
0.5^ 1.08 0.78 1.16
1.06 1.28
l.n 1.47
0.92 0.74
2.22 1.97
2.32 0.71
0.46 0.56
0.74 0.83
1 .09 1 78
0.90 0.83
0 41 1.21
0.92 1.67
1 17
Diethanolamine
Dioxane
0.89 0.80
0.70 0.40
0.94 0.72
0.90 2.83
0.71 0 74 1 0.89 1.29
0.60 0.70 j 0.51 0.54
0.76 0,70
0.86 1.39
0.93 0.71
0.6° 0.88
1.83 0.71
1.41 0.54
1.44 ).28
0.61 1.10
1.02 0.58
0.70
Ethyl acetate
Ethyl acrylate
0.72 0.87
0.53 1.19
0.53 1.31
0.80 1.06
0.39 1.22
1.03 0.84
1.15 0.71
1 13 1.25
0.75 0.97
0.78 1.07
0.76 1.14
(f) 0.84
2.70 0.58
1.00 0.80
0.72 ->.98
1.20
Ethyl alcohol
Ethylene glycol
0.62 Q.96
0.64 0.69
1.56 1.52
0.99 0.75
1.12 0.37
0.73 0.54
0.97 0.66
0.43 0.82
0.88 0.97
0.54 1.07
1.18 1.29
0.47 0.77
1.78 0.24
1.02
Formal in
Isophorone
1.36 0.84
0.50 0.50
2.02 1.38
0.80 1.35
1.90 0.63
0.65 0.41
1.38 0.70
1.51 0.90
1.10 1.20
0.46 0.62
0.93 0.85
1.16
Morpholine
Nitrobenzene
1.15 1.18
1.26 0.99
5 09 2.51
0.78 0.82
1.18 0.43
0.92 0.87
0.93 0.63
1.00 0.72
0.56 0.86
1.12
Phenyl cell. | 0.83 0.75
PtG 200 i 0.94 1.41
1.33 1.61
1.45 2.70
0.52 0.46
0.54 0.70
0.87 0.69
0.99
Propylene glycol
Propylene oxide
i 0..91 0.72
0.48 0.64
0.84 1.69
0.72 0.66
0.83 0.38
0.40
Tergitol XD
Tetrachlor
1.22 1.12
1.17 1.33
0.74 0.67
1.73
Toluene
Ucon 50HB260
0.64 0.94
1.06
-------
molecular weight and molecular structure. In reviewing
toxicity data on 1-, 2- and 3-ring aromatic hydrocarbons,
Herbes (83) graphically showed a spread of data points to be
two orders of magnitude between the most and least sensitive
aquatic organisms. He also showed, above a molecular weight
of approximately 90, a general 10-fold toxicity increase per
40 to 50 unit increase in molecular weight of PAH.
Comparison of data on benzene, toluene, and xylene
suggests that methylation may decrease toxicity. No
toxicity data are available for 4- and 5-ring PAH which
may be too insoluble to produce acute effects in fish;
indeed, anthracene, which is 20 times less soluble than
phenanthrene, is not toxic to fish even in super-
saturated solutions (83).
Toxicities of polyaromatic phenols have not been
investigated; however, LC50 values for 1- and 2-ring
phenols roughly parallel those of the aromatic hydro-
carbon analogs, and presumably polyaromatic phenols
would demonstrate similar behavior. As is true for
monoaromatic hydrocarbons, methylation somewhat decreases
toxicity. Increasing the numbers of hydroxyls also
appears to decrease phenol toxicity, although a low
LC50 range of hydroquinone may indicate high toxicity
of polar substituents in the para position (83).
The effect of increasing molecular weight on toxicity
of aromatic bases is marked. A 10-fold decrease in
LC50 values appear to occur with 30-40 unit molecular
weight increases. Primary and tertiary amines (e.g.,
aniline and pyridine) appear to be similar in toxicity.
The lower range of LC50 values closely parallels
arylamine concentrations observed in coking and other
industrial effluents, which suggests that acute toxici-
ties of both small and large aromatic amines may be of
equal concern (83).
Acute effects of thiophenes (sulfur analogs of aromatic
hydrocarbons) have not been studied sufficiently to
permit generalizations. Thiophene is 33 percent more
toxic to sunfish than is benzene, and thiophene and 2-
methythiophene are more toxic to mammals than are the
benzene analogs. Higher molecular weight thiophene
compounds may also be correspondingly more toxic than
polycyclic aromatic compounds (83).
375
-------
The phenols, while high in acute toxicity, are low both
in deleterious chronic effects and bioaccumulation potential.
Considering this, plus the relatively high efficiency of
their removal by wastewater treatment procedures and their
rapid degradation by microbial systems, the phenols can be
given a low priority rating for future environmental research.
However, a spill of phenol from a producing plant into a
Luxembourg river destroyed all of the aquatic flora and
fauna in a zone containing 10 ppm phenol and 3 g/1 sulfate
where the spillage induced an oxygen deficit of 90 to 100
percent. In a zone which suffered a transient contamination
of 3 to 10 ppm phenol and 2 to 3 g/1 sulfate, damage was
greatest to salmonid fish, but most other life forms did not
show toxic effects (366).
Additive interactions have been demonstrated among such
aqueous pollutants as phenol mixtures, metals, ammonia and
phenol, and mixtures of ammonia, phenol, zinc, copper and
cyanide. However, no interactions were found among phenol,
ammonia, and zinc when the latter toxicant comprised greater
than 74 percent of the total predicted toxicity. Results of
experiments to test the synergism between resorcinol and 6-
methylquinoline are contradictory (367).
Petrochemicals (including ethylbenzene) in high concen-
trations all cause similar symptoms in animals; immediate
excitation and great activity followed by an anesthesia-like
depression. Most of the petrochemicals studied showed a
special affinity for nerve tissue and acted as narcotics in
mammals (309).
Ethylene is the chief hydrocarbon gas that produces
adverse effects at known ambient concentrations. Plants are
more sensitive to ethylene than to other hydrocarbon gases.
376
-------
Acetylene, propylene, and vinyl chloride all cause phyto-
toxicity symptoms resembling those of ethylene. But 60 to
500 times the ethylene concentration is required to produce
comparable effects. Ranking according to toxicity are:
ethylene, acetylene, propylene, vinyl chloride (117).
Carcinogenicity--
The potential carcinogenicity of coal liquefaction
wastes, products, and by-products is a major environmental
concern. The following section will briefly outline types
of carcinogenic compounds which have been or may be associated
with the coal liquefaction process and the factors influencing
the carcinogenicity of such compounds.
The potential hazard of liquefaction waste discharge or
product oil, when considered as a whole, will be evaluated
in terms of laboratory data and epidemiological studies of
coal liquefaction plants or industries utilizing similar
technologies.
Coal liquefaction processes are known to produce carcino-
genic compounds . The extent of carcinogenic hazard, however,
has not been determined. Table 123 lists compounds, which
may be present in coal liquefaction effluent streams or
product oils and are known or suspected carcinogens.
Factors affecting carcinogenicity--Numerous factors in-
teract to influence the carcinogenicity of a substance; even
when analyses of the compounds present in a particular waste
stream are available, it is difficult to predict the environ-
mental impact of the waste stream as a whole. An example of
the intricacy of various factors influencing carcinogenic
potential of a compound can be illustrated with PAH. The
carcinogenicity of polycyclic compounds to mammals is
377
-------
TABLE 123. KNOWN OR SUSPECTED CARCINOGENS WHICH MAY
BE IN THE EFFLUENT STREAKS OF COAL LIQUEFACTION PLANTS
Comoound Type
Example
Reference
bicycllc compounds
benzidine
79
nitrosamines
368
nickel
nickel carbonyl
150,201,68
chromium
chronic trioxide or
chromate salts
150
beryllium
beryllium oxide
150,201
arsenic
tricalcium arsenate
150,201
selenium
selenide sale
150,201
cobalt
cobalt sulfide
201
lead
lead chromate
201
zinc
zinc chromate
201
mercury
elemental mercury
201
cadmium
cadmium sulfide
150,201
anthracenes
anthracene and 9,10-
dimethylanthracene
150,201
chrygenes
5-methyl cystein
201,150,79
benzanthracenes
benzo(a)anthracene
^7,201,79,150,
fluoranthene
benzo(J)fluoranthene
benzo(b)fluoranthene
201,147,98,79
cholanthrenes
20-methylcholanthrene
201
benzopyrenes
benzo(e)pyrene and
benzo(a)pyrene
201,79,150,147,
68,137
dibenzopyrenes
dibenzo(a,l)pyrene,
dibenzo(a,n)pyrene,
dibenzo(a,ijpyrene,
dibenzo(a,h)pyrene
201,150
mono- & dibenzacridines
dibenz(a.h)acridine
150,201
benzocarbazoles
7H-benzo(c)carbazole
201
dibenzocarbazoles
7H-benzo(c,g)carbazole
201
benzanthrones
benzo(a)anthrone and
7H-benz(d,e)xanthracene-
7-one
150,201
aminozobenzenes
4-dimethylaminoazobenzene
150
acenaphthenes
acenaphthene
79
naphthylaminas
alpha-naphthylamine
beta-naphthylamine
150,98
fine particulates
sulfur, coke
156
amines
diethyl amines
methylethyl amines
L50
monoaromatic
benzene
156
pyrenes
cyclopenta(c,d)pyrene
indeno(1»2,3- c, d)pyrene
98
135,150,147
378
-------
dramatically altered by co-exposure to other aliphatic or
aromatic hydrocarbons or to phenols (83,201). Concentrations
which produce effects may be lowered by several orders of
magnitude when present in combination with other organic
compounds.
Such compounds which by themselves are not carcinogenic
but which can promote multiplication of abnormal cells after
initiation of the conversion of a normal cell to a latent
tumor cell by a carcinogen are referred to as cocarcinogens.
Some substances which are thought to have cocarcinogenic
properties are phenols, long-chain hydrocarbons including
cresols, nonionic detergents, phorbal, myristate, acetate,
and anthralin (146,197). For example, coal tar itself is
more carcinogenic than its known individual carcinogenic
compounds, thus suggesting the presence of cocarcinogens in
coal tars. In an experiment performed in 1967, Tye and
Stemmer removed the phenols from coal tar, and observed that
the carcinogenic activity of the resulting material was
significantly decreased. In 1969 Conzelman discovered that
the skin cancer-inducing activities of benzo(a)pyrene and
benzo(a)anthracene were increased 1000 times when n-dodecane
was used as the solvent. In 1970, Laskin and co-workers
reported that inhaling benzo(a)pyrene alone did not produce
lung cancer in rats, while inhaling both sulfur dioxide and
benzo(a)pyrene did produce cancerous tumors (201).
The carcinogenic potential of certain PAH is greater in
solvents such as n-dodecane and dodecylbenzene than in
hydrocarbons of low molecular weight. Hydrocarbons which
increase the rate of cancer induction by a carcinogen are
capable of preconditioning the skin of mice to render it
more responsive to subsequent applications of a carcinogen.
379
-------
The accelerating solvents are effective promoters of car-
cinogenesis initiated by a single application of a car-
cinogenic material (146).
An unexpectedly high incidence of bronchogenic carcino-
mas in hamsters was induced by intratracheal injection of
benzo(a)pyrene attached to iron oxide (146). The enhanced
tumorigenicity of benzo(a)pyrene-iron oxide combinations may
be due to a reduction in carcinogen clearance rate. Benzo(a)-
pyrene proved to be a loosely bound soluble carcinogen,
which left the carrier particles and entered the upper
airway epithelial cells during clearance of the particles by
mucous and ciliary action. Thus, mainly epidermal carcinomas
of the major bronchi and trachea were produced (146).
Part of the confusion in predicting carcinogenic be-
havior is demonstrated in Table 124 which was taken from the
report of Guerin and co-workers (94). This table demonstrates
that a slight change in the chemical structure may alter the
carcinogenic potential drastically. The carcinogenic benzo-
(a)-pyrenes have one more fused benzene ring than noncarcino-
genic pyrene (4 more carbons). The addition of a methyl
group to chrysene can increase or decrease the carcinogenic
activity depending on whether the methyl group is added in
the 5- or the 6-ring position. The addition of a fused
benzene ring to fluoranthene can increase or not affect the
carcinogenic activity.
Examples of other situations in which the carcinogenic
potential of a compound is altered are given below:
380
-------
TABLE 124. SPECIFICITY OF CARCINOGENIC ACTIVITY (369)
Compound
Activity
Compound
Activity
Pyrene^
-
Fluoranthene"*"
1 2
Benzo(e)pyrene '
+
Benzo (b)f luoranthene^
2
Benzo(a)pyrene
+++
Benzo(j)fluoranthene^
Chrysene
+
Benzo(k)fluoranthene^
3
5-Methylchrysene
-H-+
Nap thai enes"*
3
6-Methylchrysene
-
Benzo (g,h, i)perylene^"
Shown cocarcinogenic
2,3,4
The compounds with the same numbers are stereoisomers
5
Shown tumor promoting
Relative carcinogenicity: not carcinogenic (-), carcino-
genic (+), moderately to very carcinogenic (++,+++)•
All studies use mouse skin model except for tumor-promoting
study of napthalenes.
• Seemingly minor structural differences can com-
pletely control bioactivity, e.g., catechol (1,2-
dihydroxybenzene) is a potent cocarcinogen; (2)
while resorcinol (1,3-dihydroxybenzene) is ap-
parently inactive (94).
• One toxicological study has demonstrated that
napthalene actually inhibits skin tumor produc-
tion when applied together with benzo(a)pyrene on
laboratory mice (282).
381
-------
The carcinogenic and mutagenic potential of N-
nitrosopiperidines is blocked by a substituent in
the alpha position (2,6-dimethyl; 2,2,6,6-tetra-
methyl). Substitution with a carboxyl group
eliminated both mutagenic and carcinogenic acti-
vity. It seems that activation at the alpha
position is necessary for both mutagenic and
carcinogenic activity (103).
Many polynuclear aromatic compounds are carcino-
genic while others are not (370). Carcinogenic
activity of coal tars was found to be concentrated
in the rogen, arsenic, and sulfur. It was sub-
sequently found that pyrolysis of hydrocarbons,
such as isoprene and acetylene, in a hydrogen
atmosphere produced carcinogenic coal tars (370).
Some natural compounds apparently suppress the
activity of PAH carcinogens. For example, Vitamin
A has been shown to markedly reduce the incidence
of respiratory tract tumors in hamsters when the
animals were injected intratracheally with a
mixture of benzo(a)pyrene and ferric oxide (a
cancer promoter). Vitamin A is thought to act by
inhibiting benzo(a)pyrene metabolic pathways,
especially those proceeding through an epoxide
intermediary. Like Vitamin A, selenium combined
with Vitamin E significantly reduced the number of
PAH-induced skin tumors in mice. Selenium may act
as an antioxidant. A number of antioxidants as
well as some weakly carcinogenic hydrocarbons have
been shown to exhibit anticarcinogenic properties
when applied with potent carcinogens (103).
382
-------
Specific carcinogenic compounds--Possibly the most
hazardous coal-derived compounds are PAH since many are
known animal carcinogens or suspected human carcinogens.
Although carcinogenicity in mammals is almost exclusively
limited to 4-, 5-, and 6-ring polycyclics and some methy-
lated derivatives, no definite structure-effect relationship
has yet been determined. Moreover, the presence of N or S
heteroatoms in basic polycyclic hydrocarbon structures has
been demonstrated in different cases either to intensify or
reduce carcinogenic effects. Because N- and S-containing
polycyclic compounds are more water-soluble than the corre-
sponding hydrocarbons, they may be present in effluents at
greater levels than those of the polyaromatic hydrocarbons;
their hazards may therefore equal or exceed those of non-
substituted polycyclics.
Virtually nothing is known, however, of subacute inter-
actions between compound classes at the low levels antici-
pated in effluents. Potential hazards exist for both
aquatic organisms and human populations exposed through
either water consumption or ingestion of fish and shellfish.
The scarcity of information on carcinogenic and mutagenic
effects of heteroatomic polyaromatic compounds, the poten-
tial interactions between compound classes, and the complete
absence of information on effects of trace levels of all
polycyclic compounds to aquatic organisms indicate the
urgent need for research in these areas.
Aromatic amines are another class of aromatic carcino-
gens found in coal tars which have the potential of being
formed in the liquefaction process. Amino azobenzenes and
napthylamines have been specifically identified in coal
tars, and benzidines and aminobiphenyls are suspected of
being present (201) . Di- and tri-aromatic hydrocarbons
383
-------
(naphthalene, anthracene, phenanthrene) present in coal tars
have not been shown to be carcinogenic. Coal tar hydro-
carbons containing six or more fused benzene rings tend to
be less active than pentacyclic hydrocarbons. One hexacy-
clic hydrocarbon known to be carcinogenic is dibenzo(a,h)-
pyrene. Other 6- and 7-ring hydrocarbons in coal tars
(anthanthrene, perylene, coronene) have been shown to be
inactive, or at most, weakly carcinogenic (201).
Table 125 shows the chronic effects (including carcino-
genesis) of several PAH on various aquatic organisms. Table
119 shows the acute and subacute effects of various PAH on
animals. Benzene exposure has also been associated with
leukemia and Hodgkin's Disease (79,117). Benzidine has been
implicated as a cause of human bladder cancer (371-375).
Process Waste and/or Product Considered As a Whole--
Coal liquefaction studies—Laboratory animal studies
have been performed to determine the carcinogenicity of
liquefaction product oil. Several streams and products of
the coal-hydrogenation process were painted on the skin of
mice to test their carcinogenic effect. The light-oil
stream and eight separate fractions of this stream were all
without tumorigenic action. The light- and heavy-oil pro-
ducts were mildly tumorigenic, producing predominately
papillomas. However, the streams boiling at higher tem-
peratures, the middle oil, light-oil stream residue, pasting
oil, and pitch product were all highly carcinogenic. The
degree of carcinogenicity increased, and the length of the
median latent periods decreased as boiling points rose. The
median tumor- or cancer-latent period is the time necessary
to reach a 50 percent tumor or cancer index. Tumor induction
384
-------
TABLE 125.
AQUATIC TOXICITY OF PAH (79)
Organlsr
Method
Qmlcal Vaed
(°C)
Exposure
time
(hours)
Dose
adninlstered
Nunber
of
deaths vithia
Effects
produced
Wlthla
Rana pipiene,
tnjectloo Into
Kidney
Si ?-dliwthyl-I,Z»bw»MtfctactM
3-«ethylcholanthr*M
14-16°
Single doM
0.3-0.5 mg
0.3-0.} mg
0.3-0.S mg
15/15
8/8
6/6
5 days
5 days
S days
p-nloMtobenceoe
0.3-0.5 mg
20/59
3 weeks
adeno-
carcinoma
In 232
3 wka-
7 months
lt2(S,HlbMunchr«ccM
0.3-0.5 mg
13/36
3 weeks
adenocar.
In 26Z
3 vfca-
1 BMtha
Bufo arenacum
lapUntetiott
into tail
•dbcutaneously
Ml «thy 1 Aoimhr»»
Single dose
Not given
(crystal*)
Super-
numerary
fins In
1/38
16 days
3,4-benzpyreae
Single dose
Not given
(crystals)
Sup. fins
in 1/62
26 days
7 v 12-dlmethylben*(a)
anthracene
Single dose
Not given
(crystal*)
Sup. fins
In 5/50
20 days
Lepomie macrochiruB
Flovthrough
bcnt(i)Mthr«c«M
€ months
1.0 ppm
87/100
6 months
Paraeentrctue libidua
Static
7,12-dlMthylbnt(«)
Mthr«c*oc
nmo (•) m—
18-20°
48 hours
1 x 10_? to
I x 10-* M
Develop-
mental
abnormali-
ties In
70-1002
tft hrs.
-------
periods were only slightly delayed by dilution of the
pasting oil, application of barrier creams, or applications
of various washing methods (146).
In the absence of medical data, organic compounds with
boiling points above 250°C should be handled with caution.
In general, these are the compounds with the higher mole-
cular weights, larger number of aromatic rings, lower water
solubility, and higher potential for relative persistence
and bioaccumulation in organisms (136).
The chemical composition of products from coal lique-
faction processes suggests that they will exhibit consider-
able carcinogenicity. Benzo(a)pyrene concentrations ranged
from 40 to 50 ppm in the coal-derived products as compared
to 1 ppm for carcinogenic condensed tobacco smokes. Con-
centrations of PAH are usually 10 to 100 times the level
found in smokes; and compounds of known tumor-initiating,
tumor-promoting, and cocarcinogenic activity such as pyrene
and alkylnaphthalene are present (369,376).
Observations at a large-scale coal liquefaction pilot
plant at Institute, West Virginia, indicated that workers
were exposed to a significant risk of cancer. The incidence
of skin cancer in workmen exposed to the coal hydrogenation
process was between 16 and 37 times greater than that of
West Virginia or United States as a whole. Benzo(a)pyrene
deposits on the skin of workers could often be traced to
exposure to high concentrations of airborne oil fumes.
Analysis of air samples for benzo(a)pyrene indicated that
pitch treatment or solids removal operations contributed
significantly to airborne contamination. Maintenance and
repair operations often resulted in direct dermal contact
with carcinogenic materials (197).
386
-------
Laboratory studies of the product oils from other
hydrogenation processes have also indicated carcinogenicity.
Experimental studies were performed on Bergius oils and
Fischer-Tropsch oils obtained from the experimental coal
hydrogenation-liquefaction operation of the U.S. Bureau of
Mines at Bruceton, Pennsylvania. All fractions were tested
for carcinogenicity by repeated application to the skin of
mice and rabbits and by intramuscular injection into the
thighs of rats. Eight of nine fractions of the Bergius oil
fractionation products were carcinogenic with the degree of
carcinogenic potency generally increasing with the increasing
boiling point. Fischer-Tropsch synthesis products were less
carcinogenic than Bergius products and appeared to have a
narrower species and tissue susceptibility spectrum (146).
Similar industry studies--Insight into the potential
carcinogenic hazard of coal liquefaction processes can be
gained by examining process variables of similar industries,
including by-product coking and petroleum refineries. Some
of the similarities and differences between these various
industries and their respective products were discussed and
are summarized in Table 88. Briefly, coal tars consist of
volatiles driven off coal which have been heated to very
high temperatures in the absence of air. By comparison,
liquefaction processes utilize relatively low temperatures
(less than 500°C), high pressures (13.8 to 27.6 MPa) and a
hydrogen-enriched atmosphere. These differences in pro-
cesses should be kept in mind when applying carcinogenic
studies using coal tar to liquefaction processes.
The varying carcinogenic potential of different fuel
conversion processes is demonstrated by a study of lung
cancer incidence among coke oven workers having five or more
years exposure. The data, shown in Table 126, suggest a
387
-------
possible relationship between the type of coke, oven and
coking temperature, and incidence of lung cancer. The
indication is that higher temperature processes tend to
produce a more potentially carcinogenic environment.
TABLE 126. TEMPERATURE RANGE OF CARBONIZING CHAMBERS AND
EXCESS OF LUNG CANCER REPORTED (201)
Type of
Temperature
Excess of lung cancer
carbonizing chamber
range, C
reported, percent
British vertical retorts
400 - 500
27
British horizontal retorts
900 - 1100
83
American slot-type coke
1200 - 1400
255
ovens
Japanese gas generators
1500
800
One difficulty in the quick identification of an agent
responsible for occupational and/or environmental human
cancer is the long latent period. The latent periods for
skin and lung cancer from tar and tar fumes have been esti-
mated to be 20 to 24 and 16 years, respectively. Latent
periods depend upon the relative potency of a particular
carcinogen, its physicochemical properties, the physico-
chemical and co- or anticarcinogenic properties of its
vehicle or its associated agents, the route of contact, the
intensity of the individual exposures, and the total dura-
tion of exposure. With increasing intensity of exposure, an
increase in the incidence of cancers and a shortening of the
latent period occurs (146).
The carcinogenic potential of coal tars and coke oven
emissions has been extensively studied and documented.
388
-------
Workers exposed to high levels of PAH-containing coal
volatiles show an increased incidence of skin and lung
cancers. Benzo(a)pyrene, a component of coal tar and an
identified carcinogen, is the most tested PAH and also the
compound most often chosen as the indicator compound for
monitoring PAH. It has been observed in synthetic oil
samples (41 ppm), coal and petroleum tars (2000 and 200
ppm), polluted air (38 ppb), surface water (0.01 to 0.1
ppb), groundwater (0.001 to 0.010 ppb), soil (40 ppb),
plants (1 to 10 ppb), and sediments undisturbed since the
year 3 A.D. (19.5 ppb). Benzo(a)pyrene has produced tumors
in rats, mice, hamsters, guinea pigs, rabbits, ducks, and
monkeys by oral, skin, and intratracheal administration
(136,103).
An unusual incidence of lung cancer was first reported
in Japanese (coal) gas producer workers by Kuroda and
Kawahata in 1936. The excess lung cancer risk for gas
producer workers was confirmed by British studies of death
certificates in England and Wales for 1921 to 1932. This
study also showed that other coal carbonization and by-
product workers experienced greater than expected lung
cancer mortality. An excess risk of bladder cancer was
observed among men employed at coal carbonization processes.
In 1946, Henry reported an average annual scrotal cancer
mortality rate of 21.1 per million in coke oven workers
during 1911 to 1938, as compared with a general population
rate of 4.2 (146).
Employees who work topside on coke ovens have an
increased rate of lung cancer (cause of death for 35 workers
was lung cancer when only 10.4 deaths were predicted for a
similar control population). Partial topside workers
showed seven deaths from lung cancer when 3.7 deaths were
389
-------
expected from a normal population. Side oven workers had 27
deaths when 19.4 were expected. Topside workers would be
exposed to a greater concentration of volatiles from the
coking process, and this is thought to be the explanation of
the above data (146).
A gradient in risk related to length and area of em-
ployment suggests the existence of a dose-response rela-
tionship between some carcinogenic substances, coke oven or
gas retort effluents, and the development of lung cancer.
In Japan, 21 men exposed to coal tar fumes in generator gas
plants developed lung cancer in a six-year period; the
longer the exposure to coal tar fumes, the greater the
mortality from lung cancer. In Allegheny County, Pennsyl-
vania, men employed at the coke ovens for at least five
years exhibited a mortality rate for lung cancer 3.5 times
the expected rate, while the rate of all coke oven workers
was 2.5 times that expected based upon mortality experience
for the general population. Because the greatest exposure
to coke oven emissions occurs at the top of the ovens, the
lung cancer mortality rate for men employed in that position
at least five years is seven times the expected rate, while
the rate for men employed at least five years exclusively at
the sides of the oven was twice the expected rate (197).
The mortality experience of groups of gas workers in
Great Britain over a 12-year period was examined. The
workers categorized as coal carbonizing process workers, had
a significant increase in deaths from lung cancer, bladder
cancer, and cancer of the skin and scrotum. The tarry fumes
that escaped from retorts contained extremely high concen-
trations of PAH. Heavy exposures to coal hydrogenation
materials were found to be capable of producing both benign
390
-------
and malignant skin tumors. The incidence of skin cancer in
workmen exposed to the coal hydrogenation process was
between 16 and 37 times greater than that of West Virginia
or the United States as a whole (197).
It is generally acknowledged that coal tar pitch plays
a role in inducing skin cancer. Squamous cell carcinoma
incidence of 2.8 percent was observed in pitch workers,
while an incidence of 0.4 percent was observed in an unex-
posed population. Incidences of intraepidermal carcinoma,
basal cell epithelioma, and numerous pre-cancerous lesions
(especially coal tar dermatosis) were observed to be higher
in pitch workers (197).
Analysis of particulates collected from coke oven
charging emissions indicates that carcinogenic materials are
generally present and include the following: benzo(a)-
anthracene, benzo(a)pyrene, benzo(e)pyrene, cholanthrene,
and isomers of benzofluoranthene.
Mutagenicity and teratogenicity--The following frac-
tions of COED Syncrude were found to be mutagenic using the
Ames test: water soluble strong acids, ether soluble bases,
hexane soluble fraction, hexane/benzene soluble fraction,
and the benzene/ether soluble fraction (377).
Epler and co-workers (338) studied the mutagenicity of
several coal-derived products using the Ames test. The
samples which were surveyed and their sources are: (1) a
coal liquefaction product from a process under development,
courtesy of the Pittsburgh Energy Research Center (Synfuel
A), or Coal A from ORNL respository; (2) coal liquefaction
product from the COED pyrolysis process, courtesy of FMC
391
-------
(Synfuel B), or Coal B from ORNL repository; (3) Louisiana-
Mississippi sweet crude oil, courtesy of Dr. J.A. Carter of
the Analytical Chemistry Division, Oak Ridge National Labora-
tory; (4) composite crude oil samples from materials ob-
tained through the courtesy of Dr. D. Latham of the Laramie
Energy Research Center.
The possibility exists that these samples may bear no
relationship to the processes as they may exist in the
future. These materials are not necessarily representative
of either all natural crudes or products from synthetic
fuels processes. They were used simply as appropriate and
available materials for the feasibility study (378).
The results from the two Synfuels show an increase in
total activity over the natural crude oils. Synfuel A
appears to contain significantly higher activity than all
other samples. Both Synfuels exhibit high-specific activity
components in the basic fractions; and both Synfuels show
considerable activity, again, in the neutral fraction.
Synfuel A appears also to possess appreciable activity in
the ill-defined NaOH fraction. All tests were carried out
in the presence of the rat-liver microsomal activation
system. Slight mutagenic activity without enzyme treatment
was occasionally noted (378).
N-nitrosopiperidines have been reported to be car-
cinogenic and mutagenic. In general, the carcinogenicity
and mutagenicity of N-nitrosopiperidine derivatives show a
high degree of correlation. Nitrosopiperidine (NP); 2-
methyl-NP, 3-methyl-NP, 4-methyl-NP, 3,5-dimethyl-NP, and
1,2,3,6-tetrahydro N-nitrosopyridine were effective mutagens,
on Saccharomyces cerevisiae when metabolic activation by rat
392
-------
liver microsomes was provided. 3,4-dichloro-NP was muta-
genic itself, and metabolic activation enhanced the effect.
2,6-dimethyl-NP was not a mutagen (136,103). Benzo(a)pyrene
is mutagenic to mammalian cells in culture when activated by
a microsomal activation system (136,103). Other reported
teratogens potentially produced during liquefaction pro-
cesses include nitrosamines (368) and benzene (79).
ESTIMATED EFFECTS ON CONTACTED ECOSYSTEMS
Overall Impacts
A coal conversion complex of the approximately 7,950
3
m /day size analyzed in this report may require up to 200
square miles of land development (379). This includes the
plant, mine, town growth, new industrial park, reservoir,
inter-connecting road and utilities, landfill, etc. Approxi-
mately 23,000 metric tons of coal and 45,000 metric tons of
water will also be needed every day over a 20- to 30-year
plant life (379).
The relative geographical makeup and general inter-
relationship of environmental compartments for such a 7,950
3
m /day coal liquefaction complex are shown in Figures 68 and
69 (379).
Environmental impacts of the coal conversion complex
will include:
• Increased air and water pollution in the region
surrounding the plant
• Diversion of 0.039 to 0.098 m3/sec of water from
other area requirements (379)
393
-------
Figure 68. Potential environmental interactions between a
town, coal mine, and conversion plant (379)
394
-------
Figure 69. Plant, mine and town areas (shown in
approximately correct size relationship (379)
395
-------
• Requirement for daily disposal of roughly 10,000
tons of solid waste
2
• Disturbance of up to 518 Mm of land; and the
soil, flora, and fauna
• Influx of perhaps 15,000 people with concomitant
social and economic perturbations (213)
• Exposure of area residents to new occupational
hazards
• A general, area-wide increase in ambient noise
• Aesthetic impacts from the appearance of rapid
growth and accompanying odors and noise
• Heavy demands on area transportation systems, and
construction of new ones.
While the main thrust of this report is aimed at the
environmental characterization of the coal liquefaction
portion of the overall conversion complex, it should be
recognized that the environmental impacts of the related
mining operations, coal cleaning and preparation wastes,
land and water requirements, transportation systems, utility
requirements, and population relocations may far outweigh
those for the liquefaction process and its discharges.
Liquefaction Process Discharges and Their Effects
In view of the early stage of commercial technology de-
velopment and the wide variety of potential pollutants for
coal liquefaction systems, there is a strong need for data
396
-------
on the actual environmental discharges, and their effects.
Until safe limits, based on hard data, have been estab-
lished, none of these potential pollutants can be ignored.
Therefore, only general estimates of the effects of dis-
charges from the priority liquefaction processes of this
report may be made. On the basis of the small amount of
data available, these estimates may be summarized as follows:
• Using existing or modified treatment and control
technology, potentially large-volumed pollutants
such as hydrogen sulfide, sulfur dioxide, phenols
and other hydroxylated aromatics, ammonia, and
carbon-containing residues, will probably be
controlled to emission limits similar to those
achieved in petroleum refineries and petrochemical
complexes.
• Trace constituents, sometimes highly toxic in the
discharge streams and solid wastes, will be of
prime concern and need to be identified, quanti-
fied, and their effects determined.
• Products and high-boiling carbon-containing pro-
cess residues are themselves a prime source of
ehvironmental concern.
The following discussion is restricted to the toxic
trace constituents in both wastes and products. Treatment
and control of large volume wastes are discussed in Section
7 of this report.
397
-------
Inorganic Materials--
Trace quantities of potentially hazardous inorganic
materials have been reported or conceptualized in coal
liquefaction discharges to all media. In preceding discus-
sions, based on coal composition and ash extractions, it has
been indicated that antimony, copper, chromium, lead,
beryllium, arsenic, cadmium, cobalt, iron, molydenum, nic-
kel, selenium, thallium, mercury, manganese, zinc, polonium,
radium, radon, silver, tellurium, tin, gold, uranium,
chlorine, bromine, and fluorine elements or compounds may
have significant environmental effects. Sodium, calcium,
aluminum, and sulfur compounds may also present environ-
mental problems by being present in large concentrations.
In general, the inorganic metals and most of their
compounds are solids at coal liquefaction temperatures and
may be expected to go through the process as inert material
with the ash residue. Elements such as fluorine, bromine,
and chlorine are also likely to form stable high-boiling
compounds which will go through the process unchanged.
There are a number of metals, metallic compounds, and
other inorganic substances, however, which are either re-
latively volatile or have high solubility in water. There-
fore, the distribution of the inorganic compounds in the
various media discharges can only be estimated at this time.
This has been done in previous sections of this report. The
estimated environmental effects of the inorganic discharges
are described in the following subsections.
Atmospheric discharges--The main source of environ-
mental discharge of process-related airborne wastes is the
treatment systems for acid gas streams. Discharge of vola-
tile inorganics such as mercury, selenium, metallic carbonyls,
398
-------
and metallic hydrides have been postulated; however, there
is a need to obtain data to support or refute these pos-
tulations. The relatively low reaction temperatures (for
hydrogenation reactions), water scrubbings, solvent absorp-
tions and other operations encountered by the acid gas
streams would all tend to reduce such inorganic discharges.
Also, many (but not all) of the metallic carbonyls and
hydrides are readily decomposed by air oxidation or water
contact. As a result, the overall environmental effect of
inorganics discharged to the atmosphere is not expected to
be great.
Aqueous effluents--Many inorganic materials are soluble
in water, and limited information is available on the pre-
sence of these materials in the process waste stream. Using
only the limited information, the environmental effect of
toxic or hazardous metals in the process wastewater would be
small. The wastewater treatment would still have to include
a lime precipitation step to reduce lead or other metal
content to regulatory limits. However, the effluent streams
need to be evaluated for constituents on which either no
data or insufficient data exist before the impact can be
evaluated.
Other wastewater streams connected with coal lique-
faction auxiliary operations such as coal preparation (coal
pile runoff and tailing ponds discharges) and hydrogen
generation (sour gas scrubbing and treatment and ash dis-
posal) , would be expected to have environmental effects
similar to those identified in the literature for these
auxiliary operations.
399
-------
Solids waste--Most of the inorganic trace elements in
coal may be expected to be concentrated in the ash from the
hydrogen generator. Sludges from sulfur dioxide scrubbers
also contain significant inorganic material. Since the
normal disposal for both of these is landfill, the signi-
ficant consideration is leachability of soluble components.
The environmental effects of leachability should be similar
to those for ash disposals for coal-fired furnaces, steam-
electric generating plants, coal gasification operations,
and other coal-burning facilities. However, not all of
these have been adequately evaluated. Environmental effects
of sludges from the sulfur dioxide scrubbers also should be
similar to those encountered for coal-fired utility plant
scrubber sludges. Detailed information on ash, sludges from
sulfur dioxide scrubbers, and coal refuse and spoil pile and
their leachates is given in Tables 73, 77, 81, 82, 87, 104,
and 116.
Products—On the basis of limited data (Table 77) ,
trace elements are expected to concentrate in the solids
waste rather than in the products.
Organic Compounds--
Atmospheric discharges--Toxic organic compounds in coal
liquefaction operations are generally either relatively non-
volatile (PAH) or water soluble (phenolics). Therefore,
they are concentrated in the products, high-boiling bottom
fractions, wastewater streams, and solids waste. The
gaseous discharge streams from the sour gas treatment are
not expected to contain major amounts of these toxic
substances.
Aqueous effluents--Table 79 shows that there are individ-
ual nonpolar single and double-ring aromatic compounds in
the wastewater from the Synthoil process and that concentra-
400
-------
tions less than 1 ppm are expected. Table 120 indicates
that the levels would not be expected to affect freshwater
organisms, with the possible exception of naphthalene causing
the green flagellate, Clylamydomonas anqulosa, to lose
photosynthetic capacity. Of course, the synergistic and
antagonistic effects of combinations of pollutants, as well
as chronic effects on biota, are impossible to predict using
present data. The concentrations of some of these organic
compounds would be toxic to certain marine or estuarine
organisms (see Table 120).
Some organics, such as phenols, are efficently removed
from wastewaters in biological oxidation treatment ponds;
however, some multiring aromatic compounds including naphtha-
lene and PAH are relatively refractory and will likely pass
undegraded through the biotreatment plant. Further, the
substitution of N or S heteroatoms in multiring compounds,
or the alkylation of benzene acts to retard microbial oxida-
tion rates. Similarly, monohydric phenols are more fully
degraded than polyhydric compounds, and the polyaromatic
phenols would be expected to be degraded even more slowly.
Fortunately, multiring aromatic compounds are absorbed
tenaciously by activated charcoal and should be removed if
subsequent activated charcoal treatment is employed.
Solids waste--Normally ash, whether from hydrogen
generation or other combustion operations, should be rela-
tively free of toxic organics. Carbon-containing solids
waste and residues, on the other hand, have significant
amounts of toxic organics. Therefore, handling and exposure
to carbon-containing solids waste either prior to use in
hydrogen generation or other use/disposal should be given
attention. There is also the possibility of incomplete
combustion of carbon-containing wastes. For example, the
401
-------
concentrations of PAH in two fly-ash collectors under var-
ious circumstances in a coal-fired power plant are shown in
Table 84.
The area of solids waste handling, combustion, and
disposal will need further attention as the conceptualized
coal liquefaction plants of today become future realities.
Products--Analysis of the constituents found in various
fractions of liquefaction products have been presented in
the following tables: 16, 19, 21, 22, 23, 24, 26, 32, 37,
38, 42, 89, 92, 93, 94, 95, 96, and 98.
Besides cocarcinogenic effects, the environmentally
significant organics seem limited to aromatic compounds.
Coal products have long been notorious for their carcino-
genicity, and recent studies have implicated PAH. Theor-
etical considerations of the structure of coal itself indi-
cate that PAH are likely to be produced as the coal is
depolymerized (especially by reduction); thus, we would
expect a higher carcinogenic potential of coal liquefaction
products as related to petroleum products. This prediction
is further substantiated by the levels of carcinogens (as
PAH) found in the product as related to petroleum products
(Tables 89, 91, 92, 93, 94, 95, 96, and 98).
In coal tars, carcinogenic agents were found in very
small amounts in tars formed below 450°C. The carcinogenic
agents increased rapidly between 450 and 560°C and continued
at a lower rate over the range of 560-1250°C. Since most
coal liquefaction processes are carried out in the range of
430-540°C, the waste materials and products would be
expected to vary considerably in their carcinogenic poten-
tial from approximately equal to natural crude oil products
402
-------
for material liquefied at 430°C to more hazardous for
material liquefied at 540°C.
In summary, the products of coal liquefaction should be
considered potentially hazardous, particularly the higher
boiling fractions and residues. The hazard of liquefaction
products relative to that of crude petroleum and coal tar
has not been established. However, it is believed that
liquefaction oils will be less carcinogenic than coal tars,
but more hazardous than petroleum crude. With regard to
sulfur levels, liquefaction oils are within the range of
that of refined petroleum products.
The environmental effects of toxic organics in coal
liquefaction products and high-boiling, carbon-containing
residues represent the area of greatest estimated concern.
Quantitative definition of the presence and effects of these
materials on workplace personnel, other impacted personnel,
and the ambient environment is essential.
This report has identified some of the potential pollu-
tion problems of coal liquefaction processes. This has been
done mainly from coal analyses currently available and from
the apparent process steps that will be required. However,
for an environmentally sound system, the fate of all potential
pollutants must be determined. This can only be accomplished
by the collection and evaluation of actual process and
effluent stream information.
403
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Hemopoietic Tissue Toxicity of Benzene Vapors."
Toxicology and Applied Pharmacology, Vol. 5, No. 2
(1963), pp. 201-226.
367. Jenner, P.M., et al. "Food Flavorings and Compounds of
Related Structure. I. Acute Oral Toxicity." Food and
Cosmetics Toxicology. Vol. 2, No. 3 (1964), pp. 327-
MT.
368. Taylor, J.M., P.M Fenner and W.I. Jones. "A Comparison
of the Toxicity of Some Allyl Propenyl and Propyl
Compounds in the Rat." • Toxicoloev and Applied Phar-
macology, Vol. 6, No. 4 (1966), pp. 378-387.
369. Smyth, H.F., Jr., et al. "An Exploration of Joint Toxic
Action. 27. Industrial Chemicals Intubated in Rats in
All Possible Pairs." Toxicology and Applied Pharmacology,
Vol. 15 (1969), pp. 340-347.
370. Wolf, M.S., et al. "Toxicological Studies of Certain
Akyllated Benzenes and Benzene." A.M.A. Archives of
Industrial Health, Vol. 14 (1956), pp. 387-398.
437
-------
371. Smyth, H.F. "Range-finding Toxicity Data: List VI."
American Industrial Hygiene Association Journal, Vol. 23,
No. 2 (1962), pp. 95-107:
372. Union Carbide Corporation. Isophorone. New York. In-
dustrial Medicine & Toxicology Dept., Union Carbide,
New York, 1971.
373. Union Carbide Corporation. Technical Data Sheet.
Toxicology Studies. Union Carbide, New York, T968.
374. Inoue, K. "Studies on Occupational Toluene Poisoning.
(2) An Animal Experiment Using Inhalation of Toluene
Vapor with Mice." Osaka Shiritsu Daigaku Igaku Zasshi,
Vol. 24, No. 10-12 (1975), pp. 791-833.
375. Occupational Safety and Health Administration. "Emergency
Temporary Standard for Occupational Exposure to Benzene;
Notice of Hearing." Federal Register, Vol. 42, No. 85
(1977), pp. 22516-22575"
376. Smyth, H.F., et al. "An Exploration of Joint Toxic Action.
27. Industrial Chemicals Intubated in Rats in All Pos-
sible Pairs." Toxicology and Applied Pharmacology, Vol.
14, (1969), pp. 340-347.
377. Krombach, H. and J. Barthel. "Investigation of a Small
Watercourse Accidentally Polluted by Phenol Compounds."
International Journal of Air and Water Pollution, Vol. 7
(1963), pp. 39-46.
378. Herbes, S.E. and J.J. Beauchamp. "Toxic Interaction of
Mixtures of Two Coal Conversion Effluent Components
(resorcinol and 6-methylquinoline) to Daphnia magna."
Bull. Environ. Contaminant Toxicology, 1977,p. 25.
379. Bolin, B. and E. Arrhenius. "Nitrogen - An Essential
Life Factor and a Growing Environmental Hazard." Ambio,
Vol. 6, No. 2-3 (1977), pp. 96-105.
380. Guerin, M.R., et al. "Chemical Characterization of Coal
Conversion Pilot Plant Materials." In: Proceedings of
. Environmental Protection Conference, Vol. 3, No. 2 (1975),
pp. 661-665.
381. Tipple A. Polynuclear Aromatic Carcinogens. Chapter 5
by C.E. Searle (Ed.), Chemical Carcinogens, Washington,
D.C.: ACS Monograph 171, 1976.
382. Rinde, E. and W. Troll. "Metabolic Reduction of Ben-
zidine-azo Dyes to Benzidine in the Rhesus Monkey."
Journal of National Cancer Institute, Vol. 55, No. 1,
(1975), pp. 181-182.
438
-------
383. Scott, T.S. "The Incidence of Bladder Tumors in a Dye-
stuffs Factory." British Journal of Industrial Medicine.
Vol. 9 (1952), pp. 127-132.
384. Zavon, M.R., U. Hoegg and E. Bingham. "Benzidine
Exposure as a Cause of Bladder Tumors." Archives of
Environmental Health, Vol. 27, No. 1 (1973), pp. 1-7.
385. Tsuchiya, K., T. Okubo and S. Ishizu. "An Epidemiologi-
cal Study of Occupational Bladder Tumors in the Dye
Industry of Japan." British Journal of Industrial
Medicine, Vol. 32 (1975), pp. 203-209.
386. Rinde, E. and W. Troll. Metabolic Reduction of Ben-
zidine-azo dyes to Benzidine in the Rhesus Monkey.
Journal of National Cancer Institute, Vol. 55, No. 1
(1975), pp. 181-182.
387. Kubota, H., W.H. Griest and M.R. Guerin. "Determination
of Carcinogens in Tobacco Smoke and Coal-derived Samples -
Trace Polynuclear Aromatic Hydrocarbons." Trace Sub-
stances in Environmental Health, Vol. 9 (1975), pp.
281-289.
388. Rubin, I.B., et al. "Fractionation of Synthetic Crude
Oils from Coal for Biological Testing." Environmental
Research, Vol. 12 (1976), pp. 358-365.
389. Epler, J.L. Analytical and Biological Analysis of Test
Materials from the Synthetic Fuel Technologies. I.
Mutagenicity of Crude Oils Determined by the Salmonella
typhimurium/microsomal Activation System. Submitted to
J. Toxicol. Environ, tfealth, 1977.
390. Broderson, A.B., R.G Edwards and W.P. Hanser. Social,
Economics and Environmental Impacts of Coal Gasification
and Liquefaction Planti"! In: Papers presented before
the 2nd Symposium on Coal Utilization, Louisville, KY.
National Coal Association, 1975.
391. American National Standard for Metric Practise ANSI/ASTM
E380-76, IEEE Standard 268-1976 for Annual Book of ASTM
standards. American Society for Testing and Materials,
Philadelphia, PA, 1976.
439
-------
APPENDICES
A. SI (METRIC) CONVERSION FACTORS
B. SIEVE SERIES
C. SI PREFIXES
440
-------
APPENDIX A. METRIC CONVERSION FACTORS (391)
To Convert From
ft/s'
To
Acceleration
2 2
metre per second (m/s )
Area
Multiply By
Acre (U.S. survey)
in9
yd
12
metre,
metre?
metre?
metre'
(m?)
(mf)
(m2)
(m )
Energy (Includes Work)
British thermal unit
(mean) joule (J)
Calorie (kilogram, mean) joule (J)
kilocalorie (mean)
foot
inch
yard
grain
grain
pound (lb avoirdupois)
ton (metric)
ton (short, 2000 lb)
lb/ft"
joule (J)
Length
metre (m)
metre (m)
metre (m)
Mass
kilogram (kg)
kilogram (kg)
kilogram (kg)
kilogram (kg)
kilogram (kg)
Mass Per Unit Area
/
kilogram per0metre'
(kg/m )
3.048-
•000
E-01
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
441
-------
APPENDIX A. METRIC CONVERSION FACTORS (Continued)
To Convert From
To
Multiply By
lb/ft
lb/in
Mass Per Unit Length
kilogram per metre (kg/m)
kilogram per metre (kg/m)
Mass Per Unit Time (Includes Flow)
lb/h
lb/min
ton (short)/h
kilogram per second (kg/s)
kilogram per second (kg/s)
kilogram per second (kg/s)
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 3 3
lb/ft kilogram per metres (kg/m^)
lb/gal (U.S. liquid) kilogram per metre, (kg/m.,)
Ib/yd3 kilogram per metre (kg/m )
Power
1.601 846 E+01
1.198 264 E+02
5.932 764 E-01
Btu (thermochemical)/h watt (W)
Btu (thermochemical)/h watt (W)
cal (thermochemical)/
min watt (W)
cal (thermochemical)/s watt (W)
Pressure or Stress (Force Per Unit Area)
atmosphere (standard) pascal (Pa)
foot of water (39.2°F) pascal (Pa)
lbf/ft2
lbf/in^ (psi)
pascal (Pa)
pascal (Pa)
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 (K)
Kelvin (K)
degree Celsius
tK to,
+ 273.15
tors=(t0-r.-32) /l. 8
t 2(to_|459.67)/l,8
t£ - tLyii 8
toc-tK-*73-15
442
-------
APPENDIX A. METRIC CONVERSION FACTORS (Continued)
To Convert From
f t/h
ft/min
ft/s
in/s
centipoise
centistokes
poise
stokes
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-s^
metre^ per second (m /s)
Volume (Includes Capacity)
acre-foot (U.S. survey)
barrel (oil, 42 gal)
ft3
gallon (U.S. liquid)
litre*
metre:
metre:
metre:
metre:
metre'
(m?)
(®o)
(mo)
(m*)
(mJ)
Volume Per Unit Time (Includes Flow)
3 3 3
ft-j/min metre^ per second (m~/s)
ft /s metre, per second (nu/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.
443
-------
APPENDIX B. SIEVE SERIES (60)
Nom tnal
Sieve designation
Sieve opening
w I rt'
diam.
in.
in.
(appro*.
(approx.
Tyler
equiva-
equiva-
equivalent
Standard
A1ternate
mm.
lents )
mm.
lents
designation
107.6 mm.
4.24 in.
107.6
4.24
6.40
0.2520
101.6 nun.
4 in.**
101.6
4.00
6.30
,2480
90.5 mm.
3- l/2in.
90.5
3.50
6.08
. 2394
76.1 mm.
3 in.
76.1
3.00
5.80
.2283
64.0 mm.
2-1/2 in.
64.0
2.50
5. 50
.2165
53.8 mm.
2.12 in.
53.8
2.12
5.15
.2028
50.8 mm.
2 in.**
50.8
2.00
5.05
.1988
45.3 mm.
1-3/4 in.
45.3
1.75
4.85
. 1909
38.1 mm.
1-1/2 in.
38.1
1. 50
4. 59
. 1807
32.0 mm.
1-1/4 in.
32.0
1. 25
4.23
. 1665
26.9 mm.
1.06 in.
26.9
1.06
3.90
. 1535
1.050 in.
25.4 mm.
1 in.**
25.4
1.00
3.80
. 1496
22.6 mm.*
7/8 in.
22.6
0.875
3.50
.1378
0.883 in.
19.0 mm.
3/4 in.
19.0
. 750
3.30
.1299
.742 in.
16.0 mm.*
5/8 in.
16.0
.625
3.00
.1181
.624 in.
13.5 mm.
0.530 in.
13.5
.530
2.75
. 1083
.525 in.
12.7 mm.
1/2 in.**
12.7
.500
2.67
. 1051
11.2 mm.*
7/16 in.
11.2
.438
2.45
.0965
.441 in.
9.51 mm.
3/8 in.
9.51
.375
2.27
.0894
.371 in.
8.00 mm.*
5/16 in.
8.00
. 312
2.07
.0815
2-1/2 mesh
6.73 mm.
0.265 In.
6.73
.265
1.87
.0736
3 mesh
6. 35 mm.
1/4 In.**
6.35
.250
1.82
.0717
5.66 mm.*
No. 3-1/2
5.66
.223
1.68
.0661
3-1/2 mesh
4.76 mm.
No. 4
4.76
. 187
1.54
.0606
4 mesh
4.00 mm.*
No. 5
4.00
. 157
1.37
.0539
5 mesh
3.36 mm.
No. 6
3.36
. 132
1.23
.0484
6 mesh
2.83 imn. *
No. 7
2.83
.111
1.10
.0430
7 mesh
2.38 mm.
No. 8
2.38
.0937
1.00
.0394
8 mesh
2.00 mm. *
No. 10
2.00
.0787
0.900
.0354
9 mesh
1.68 mm.
No. 12
1.68
.0661
.810
.0319
10 mesh
1.41 mm.*
No. 14
1.41
.0555
.725
.0285
12 mesh
1.19 mm.
No. 16
1.19
.0469
.650
.0256
14 mesh
1.00 mm.*
No. 18
1.00
.0394
. 580
.0228
16 mesh
841 micron
No. 20
0.841
.0331
.510
.0201
20 mesh
707 micron*
No. 25
.707
.0278
.450
.0177
24 mesh
595 micron
No. 30
.595
.0234
.390
.0154
28 mesh
500 micron*
No. 35
.500
.0197
.340
.0134
32 mesh
420 micron
No. 40
.420
.0165
.290
.0114
35 mesh
354 micron*
No. 45
.354
.0139
.247
.0097
42 mesh
297 micron
No. 50
.297
.0117
.215
.0085
48 mesh
250 micron*
No. 60
.250
.0098
.180
.0071
60 mesh
210 micron
No., 70
.210
.0083
.152
.0060
65 mesh
177 micron*
No.' 80
.177
.0070
.131
.0052
80 mesh
149 micron
No. 100
.149
.0059
.110
.0043
100 mesh
125 micron*
No. 120
. 125
.0049
.091
.0036
115 mesh
105 micron
No. 140
.105
.0041
.076
.0030
150 mesh
88 micron*
No. 170
.088
.0035
.064
.0025
170 mesh
74 micron
No. 200
.074
.0029
.053
.0021
200 mesh
63 micron*
No. 230
.063
.0025
.044
.0017
250 mesh
53 micron
No. 270
.053
.0021
.037
.0015
270 mesh
44 micron*
(Jo. 325
.044
.0017
.030
.0012
325 mesh
37 micron
No. 400
.037
.0015
.025
.0010
400 mesh
* These sieves correspond to those proposed as an International (I.S.O.) standard. It Is
recommended that wherever possible these sieves be Included In all sieve analysis data or
reports intended for International publication.
**These sieves are not in the fourth-root-of-2 series, but they have been Included because
they are In common usage.
444
-------
APPENDIX C. SI PREFIXES (391)
Multiplication factor
Prefix
Symbol
1 000
000 000 000 000
000
=
1018
exaa
E
1
000 000 000 000
000
=
1015
4. a
peta
P
1 000 000 000
000
=
1012
tera
T
1 000 000
000
=
109
giga
G
1 000
000
=
106
mega
M
1
000
=
103
kilo
k
100
=
102
hecto^
h
10
=
101
deka^
da
0.1
=
10"1
decib
d
0.01
=
10~2
centi^
c
0
.001
=
10~3
milli
m
0.000
001
=
10~6
micro
M
0.000 000
001
=r
10'9
nano
n
0.000 000 000
001
=
10"12
pico
P
0
.000 000 000 000
001
=
10"15
femto
f
0.000
000 000 000 000
001
=
10"18
atto
a
aAdopted by the CGPM in 1975.
^To be avoided where possible.
445
-------
TECHNICAL REPORT DATA
(Please read 1Hilnictions on the reverse before completing)
1 REPORT NO. 2.
EPA-600/7-78-184b
3. RECIPIENT'S ACCESSION NO.
4. title and subtitle Envjronmen^aj Assessment Data Base
for Coal Liquefaction Technology: Volume n. Synthoil,
H-Coal, and Exxon Donor Solvent Processes
5. REPORT DATE
September 1978
6. PERFORMING ORGANIZATION CODE
7. AUTHOfliS)
C. Leon Parker and Dewey I, Dykstra, Editors
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Hittman Associates, 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; 2/77-8/78
14. SPONSORING AGENCY CODE
EPA/600/13
15.supplementary notes IERL-RTP project officer is William J. Rhodes, Mail Drop 61,
919/541-2851.
.o.abstractvoiume report, prepared as part of an overall environmental asses-
ment (EA) program for the technology involved in the conversion of coal to clean
liquid fuels, and the Standards of Practice Manual for the Solvent Refined Coal Lique-
faction Process (EPA-600/7-78-091) represent the current database for the EA of
coal liquefaction technology. This volume is an environmental characterization of three
selected coal liquefaction systems: Synthoil, H-Coal, and Exxon Donor Solvent. It
documents and evaluates existing environmentally significant data. System character-
ization includes an integrated multimedia assessment of discharges to the environ-
ment from conceptualized 7,950 cu m (50,000 bbl) per day systems. Estimates are
given for the raw waste streams, treatment and control processes, treated waste
stream discharges, and the effects of these discharges on the environment. Conclu-
sions include: (1) carbon-containing residues from process phase separations are
major potential environmental problems; (2) except for solid carbon-containing resi-
dues from phase separations, treatment and controls exist for removing most major
waste components--however, their efficiency in controlling coal liquefaction waste
streams needs to be tested; and (3) less attention has been addressed to trace organic
^organic compounds. Volume I summarizes pertinent information about 14 pro-
minent liauefaction svstems now being develnned.
17- KEY WORDS AND DOCUMENT ANALYSIS
a- DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Coal Preparation
Liquefaction
Assessments
Waste Treatment
Pollution Control
Stationary Sources
Coal Liquefaction
Environmental Assess-
ment
13 B
081
07D
14B
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
480
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA form 2220-1 (9-73)
HHO
------- |