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EPA-600/7-77-015
February 1977
MONITORING ENVIRONMENTAL IMPACTS OF THE COAL AND OIL SHALE INDUSTRIES
Research and Development Needs
by
D. C. Jones
W. S. Clark W. F. Holland
J. C. Lacy E. D. Sethness
Radian Corporation
P.O. Box 9948
Austin, Texas 78703
Contract No. 68-02-1319, Task 25
Project Officer
Robert K. Oser
Office of Program Management and Support
Environmental Monitoring and Support Laboratory
Las Vegas, Nevada 89114
Jf .& €nwronmenta! Protection Agency
RegwitS.Uferary (PH?J>
77 West JaeJeson Boulevard, 12th
, IL 60504-3590
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
ENVIRONMENTAL MONITORING AND SUPPORT LABORATORY
LAS VEGAS, NEVADA 89114
-------
DISCLAIMER
This report has been reviewed by the Environmental Monitoring and
Support Laboratory - Las Vegas, U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents
necessarily reflect the views and policies of the U.S. Environmental Pro-
tection Agency, nor does mention of trade names or commercial products
constitute endorsement or recommendation for use.
ii
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FOREWORD
Protection of the environment requires effective regulatory actions
which are based on sound technical and scientific information. This
information must include the quantitative description and linking of pol-
lutant sources, transport mechanisms, interactions, and resulting effects
on man and his environment. Because of the complexities involved, assess-
ment of specific pollutants in the environment requires a total systems
approach which transcends the media of i|ir, water, and land. The Environmental
Monitoring and Support Laboratory-Las Vegas contributes to the formation and
enhancement of a sound integrated monitoring data base through multidisciplinary,
multimedia programs designed to: j
. develop and optimize systems kid strategies for monitoring
pollutants and their impact on: the environment
. demonstrate new monitoring systems and technologies by
applying them to fulfill special monitoring needs of the
Agency's operating programs
]
This report describes existing and developing technologies associated
with the extraction and processing of c6al and oil shale, identifies the
pollutants likely to be produced by these technologies, discusses the potential
impacts of these emissions, and recommeilds monitoring systems research and
development to help alleviate the impacts. The report is intended to assist
organizations responsible for promulgating monitoring research and development
programs relevant to coal and oil shale resource development. If additional
information is desired, contact Mr. Robert K. Oser, Office of Program Management
and Support, Environmental Monitoring aftd Support Laboratory in Las Vegas,
Nevada 89114.
Jfiotge "B. Morgan
4^ting Director
Environmental Monitoring and Support Laboratory
] | Las Vegas
iii
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CONTENTS
Page
LIST OF FIGURES iv
LIST OF TABLES vii
I- INTRODUCTION
II. SUMMARY
III. CONCLUSIONS.
IV. RECOMMENDATIONS FOR RESEARCH AND DEVELOPMENT 6
MONITORING NEEDS ..................... ........ 7
PREDICTIVE TECHNOLOGY NEEDS ........ '. '. '. .' .' .' '.'.'.'.'.'.'.['.'.I'.'.'. H
V. TECHNOLOGY DESCRIPTIONS ........... 14
COAL EXTRACTION ................ '.'.'.'.'.'. .................. 14
COAL CLEANING ................ ....... ................... 21
COAL SLURRY PIPELINE ........ ......... .................. 25
COAL GASIFICATION ............ ......... .................. 27
COAL LIQUEFACTION ............. '.'.'.'.'.'.'.'. .................. 49
OIL SHALE TECHNOLOGY ........... '.'.'.'.'.'.'.'.'.'.'.'.'.'.'.I'.'.'.'.'. 63
VI. IDENTIFICATION OF EMISSIONS AND IMPACTS 80
COAL EXTRACTION .................. ........... 8Q
COAL CLEANING ................. ...'.'' ..................... 93
COAL SLURRY PIPELINE ........ '.'.'.'.'. ....................... 96
COAL GASIFICATION ............. ......................... 1Q2
COAL LIQUEFACTION ................ ...... ................. 120
OIL SHALE DEVELOPMENT ........... .'.'.'.'.'.'.' ................. i27
POTENTIAL IMPACTS OF EMISSIONS ........ '.'.'.'.'.'.'.'.'.'.'.'.'.'.'.'.'.'. 143
REFERENCES ............ 1£0
.............................. ioB
APPENDIX A .........................................
APPENDIX B
iv
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CIST OF FIGURES
V
Number Pa§e
1 The three types of access used in underground coal
mines [[[ I-5
2 Illustration of room and pillar mining using conventional
blasting and continuous mining techniques ..................... 16
3 Illustration of longwall mining technique ...................... 16
4 Area strip mining with concurrent reclamation .................. 1'
5 Steps involved in area strip mining operations ................. 19
6 Conventional contour mining .................................... 19
7 Physical coal-cleaning plant processing diagram ................ 22
8 Flow sheet for Meyers process .................................. 24
9 Schematic of hydrothermal coal process showing reactions
9 r
and product stream ............................................ L->
10 Schematic of coal slurry pipeline .............................. 27
11 Simplified process flow diagram of typical high-Btu
coal gasification complex ..................................... 28
12 Lurgi gasifier ................................................. 31
13 HYGAS coal gasification process ................................ 32
14 IGT pilot plant hydrogasif ication reactor section .............. 33
15 Synthane coal gasification process . ... ......................... 34
16 BI-GAS coal gasification process .... ........................... 35
17 C02 acceptor process for coal gasification ..................... 36
18 Hydrane coal gasification process .............................. 37
19 Applied Technology Corporation two step gasification
system [[[ 38
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Number
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
Koppers-Totzek coal' gasification process
Winkler coal gasification process
Wellman-Galusha gasifier process....
U-GAS© process.
Westinghouse fluidized-bed coal gasification process....
U.S. Bureau of Mines gasifier
lS}
H-Coal Process for fuel oil production — devolatilization
plant
Synthoil coal liquefaction process
Gulf catalytic coal liquids process
Solvent refined coal process
Con'sol synthetic fuel process
The Costeam Process
Fischer-Tropsch coal liquefaction process
COED coal liquefaction process
TOSCOAL process
Steps involved' in oil shale surface mining
Shale sizing operations
Typical shale oil process
Classification of retorting processes
TOSCO II retorting procedure
The Paraho retort process
The Lurgi Ruhrgas oil shale retorting process
U.S. Bureau of Mines Gas Combustion retorting process.
Union Oil Company retort
Petrosix Process flow diagram
Pacrp
44
45
45
46
47
48
53
54
55
57
57
58
59
61
62
64
65
66
67
70
71
72
73
74
75
legistered Trademark
-------
Number
Page
47 Flow diagram of Institute of Gas Technology oil shale
process • • ' "
X
48 Flow diagram of Superior oil shale process 76
49 Schematic representation of an in-situ retorting operation... 78
50 Room and pillar coal mine „ 83
51 Strip mining coal module 89
52 Overall material balance for liquefaction plant 121
53 Major wastewater streams in a coal liquefaction plant 122
54 Solid waste streams for a demonstration plant making clean
boiler fuels from coal • 123
55 Shale oil module 137
56 Exposure pathways by which trace elements
can enter the biosphere
vii
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Number
LIST OF TABLES
Estimated Bituminous and Lignite Production for
1973.
viii
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Comparison of Conventional, Continuous, and Longwall
Mining
Summary of Commercial Coal Slurry Pipelines
High-Btu Coal Gasification Technology
Low-Btu Coal Gasification Technology
Coal Liquefaction Technology
Characteristics of Crude Shale Oils
Characteristics and Yields of Untreated Retort Gases
Water Quality Data from Selected Refuse Sites
Summary of Atmospheric Emissions
Module Emissions for Room and Pillar Coal Mine
Emission Factors for Burning Refuse Piles
Comparison of Emissions from Extraction Modules
Summary of Atmospheric Emissions: Strip Mining Coal
Module
Module Emissions (Strip Coal Mining Module Basis: 6,300
Ton/Day R.O.M. Coal)
Acid Mine Drainage Neutralization
Ultimate Analyses of an Illinois Coal
Environmental Effects of Coal Pipeline Construction
Activities
Primary Environmental Aspect of Coal Slurry Pipeline
Secondary Environmental Aspects of Coal Slurry Pipelines
Summary of Environmental Effects of an Electrically-Operated
Coal Slurry Pipeline
-L<4
18
26
30
43
52
68
69
81
83
84
84
86
88
90
93
94
97
98
99
101
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Number Page
22 Land Use Requirements for Coal Slurry Pipeline ................ 101
23 Components in Gasif ier Gas , ppm ............................. ... 105
($)
24 Rectisol Off-Gas Composition ................................. 105
25 By-product Water Analysis from Synthane Gasification of
Various Coals ............................................... 107
26 Trace Elements in Condensate from an Illinois No. 6 Coal
Gasification Test ........................................... 108
27 Mass Spectrometric Analyses of the Benzene-Soluble Tar,
Volume-Percent .............................................. 109
28 Compounds Tentatively Identified in Waste Effluents of
29
30
31
32
33
Loss of Trace Elements from Solid Phase during HYGAS
Gasification
Trace Components in Gas and Tar
Environmental Impact of SNG— From— Coal
Environmental Impacts of Low— Btu Coal Gasification
Environmental Impacts of Medium-Btu Gasification of
Western Coal
Ill
111
112
115
116
34 Range of Trace Elements for 250 Million STDFT3 Gasification
Plant [[[ 118
35 Gas Analyses (Expressed in Volume Percent) in Koppers-
Totzek Plant ................................................ 119
36 Estimated Wastewater Effluent Concentration for
Demonstration Plant ......................................... 122
37 Environmental Impacts of Coal Liquefaction Module. Feed:
Western Coal ................................................ 125
38 Summary of Environmental Impacts of Coal Liquefaction
Module [[[ 126
39 Summary of Atmospheric Emissions of Oil Shale Room and
Pillar Mining Module ........................................ 129
40 Specific Source Emissions (Lb/Day) for Oil Shale Room and
-------
Number Page
41 Summary of Atmospheric Emissions for Oil Shale Surface
Mining Module 132
42 Source Emissions (Lb/Day) for Oil Shale Surface Mining
Module 133
43 Summary of Environmental Impacts of Shale Oil Retorting
and Upgrading Module 134
44 Possible Environmental Problems from In-situ Production
of Shale Oil 140
45 Summary of Atmospheric Emissions for In-situ Shale Oil
Production Module 140
46 Characteristics of Gases from In-situ Retorting 141
47 Summary of Potential Water Pollution Problems caused by
Spent Oil Shale Residues ; 144
48 POM Compounds Identified in Benzene Extract of Carbonaceous
Shale Coke from Green River Oil Shale 145
49 Comparison of Trace Element Concentration in an Area of
Known Damage to Missouri Livestock to Similar Measurements
in Other Soils 153
x
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SECTION I
INTRODUCTION
The utilization of the vast coal and oil shale resources of the United
States offers the potential for supplementing the dwindling supplies of
petroleum and natural gas. Concurrent with increased emphasis on developing
domestic energy resources is concern for improving the control of air and
water pollution.
Considerable effort is being expended to develop methods that will con-
vert coal and oil shale into clean, convenient fuels. If successful, these
conversion processes will provide new fuels that will help to meet energy
demands and, at the same time, be environmentally acceptable. However, these
conversion processes may themselves present sizeable pollution problems.
Therefore, it is important to determine the environmental consequences of
large-scale coal and oil shale utilization. Monitoring and predictive tech-
nology are necessary aspects of such a determination.
The objective of this study was to elucidate the important needs for
the measurement and prediction of the impacts of coal and oil shale extraction,
processing, and conversion on air quality, water quality, and land use. The
measurement needs are limited to ambient monitoring techniques. Accurate
ambient monitoring helps to establish causes of environmental impacts and to
determine the success of pollution control procedures. Ambient monitoring is
also useful in assessing and modifying modeling techniques.
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SECTION II
SUMMARY
This report presents the results of a study whose objective was to
identify important monitoring and predictive technology needs relative to the
conversion of coal to clean fuels and to the production of oil from oil shale.
The extraction, processing, and conversion of these fuels were examined in
considerable detail with regard to their impacts on air quality, water quality,
and land use. The transportation of coal by a slurry pipeline was also in-
cluded in the study.
The work performed in this study divides into the following three
areas: (1) the identification of technologies, (2) the identification of
environmental impacts, and (3) the identification of monitoring and predictive
technology needs.
The first phase of the study involved the identification of promising
technologies for the extraction, processing, and conversion of coal and oil
shale. A review of the present technological position (state-of-the-art) of
each of these technologies is provided in Section V. Discussions are pro-
vided for coal extraction, coal slurry pipelines, coal cleaning, coal gasifi-
cation, coal liquefaction, oil shale extraction, oil shale retorting, and shale
oil upgrading. With respect to coal, the emphasis of this report is on the
processes that convert coal into clean fuels. Coal extraction and cleaning
processes were included because the huge demand for coal in the future will
greatly increase their environmental impacts. Coal slurry pipelines were
included in this report because they are a promising new technological develop-
ment. Coal combustion and coal-product combustion processes are not included
in this study.
Section VI of the report discusses emissions and other impacts for each
of the technologies described in Section V. For each technology, data are
provided on air emissions, water emissions, thermal emissions (water only),
solid wastes, land use, and water requirements. In order to achieve a common
basis for comparison, it is assumed that the amount of fuel handled per day is
equivalent to 1012 British thermal units.* Air emissions are given in pounds
per day for the criteria pollutants. For coal gasification and liquefaction,
information on emissions of trace materials such as ammonia, hydrogen cyanide,
phenols, benzene, oils and tars, trace metals, and trace organics is provided.
The pollution potential of coal gasification and liquefaction is discussed in
both general terms and with respect to specific processes. The known and
potential environmental emissions of specific chemical species are identified
and quantified to the extent possible from available literature.
The last half of Section VI discusses potential impacts from the
emissions. Due to a lack of full-scale coal conversion plants .or oil shale
*
English units are commonly used for the processes discussed in this report.
For conversion of English units to modern metric units, see Appendix A.
-------
plants, no data are available on specific impacts; however, correlations are
drawn with other industries, and specific cases are discussed. The importance
of exposure pathways and the dependence of the pathways on the design and
location of the individual facilities are discussed first. This is. followed by
discussions of the potential impacts of sulfur dioxide, sulfates, particulates,
hydrogen sulfide, hydrogen cyanide, and ammonia. It is generally concluded
that only the sulfates and particulates are likely to present problems.
Next, potential impacts of trace metals are discussed in some detail,
but information on impacts is insufficient to permit definite conclusions to
be drawn. Some suggested studies are described which will help determine
whether trace metals are a problem and to what extent they should be monitored.
Trace organics and their potential impact are discussed next. Again, a
lack of carefully-studied operating systems prevents a knowledge of the exact
species emitted and a historical record of their impacts. The known impacts
of some specific organic compounds are discussed, and recommendations for
studies which will shed light on long-term monitoring needs are presented.
The information in Section VI concerning the potential environmental
impacts of coal and oil shale processes provides the basis for identifying
monitoring and predictive technology needs. Section IV lists recommendations
for improving monitoring and predictive technology with respect to the coal
conversion and oil shale industries. Successful implementation of these re-
commendations will, however, be applicable in many areas other than just the
two developing industries. Both monitoring and predictive technology needs
are divided into air and water categories. Two particularly important items
are the need to develop monitoring techniques for continuously measuring low
concentration species such as trace elements and trace organics in the ambient
environment and the need to develop accurate techniques for monitoring the
quality of ground water. Improved particulate monitors and remote sensing
instrumentation are also areas that deserve research and develo*pment.
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SECTION III
CONCLUSIONS
Significant environmental impacts could result if proper pollution
control techniques are not provided during the development of the nation's
coal and oil shale resources. Both coal conversion and oil shale industries
require the processing of huge amounts of raw material. For the two industries,
many species are likely to be emitted for which no regulations presently exist.
Some of these may be hazardous as emitted, or may subsequently undergo some
transformation which renders them hazardous. Processes for converting fossil
fuels into clean fuels could themselves become major sources of pollution. To
avoid significant environmental impacts, careful assessment of these tech-
nologies is necessary.
The refinement and development of monitoring and predictive technology
are essential elements of pollution control to avert major environmental im-
pacts from coal and oil shale industries. Section IV discusses monitoring
and predictive technology needs.
The coal and oil shale industries could be significant contributors to
low-level pollution by the emission of trace elements and trace organics.
Improved monitoring systems and research programs are necessary to cope with
the long-term effects of low ambient concentrations of pollutants.
Trace metals and trace organics occur at low concentrations; thus, long
sampling periods followed by sample preparation and laboratory analysis has
typically been the only measurement technique. Rapid feedback, field measure-
ment techniques are needed for trace organics, both in air and in water.
The above comments about trace metals and trace organics apply particu-
larly to emissions from coal conversion facilities, but also apply to many
other industries and problems. If additional information could be obtained
regarding the role of various hydrocarbon species or classes of hydrocarbon
species in photochemical smog, more effective ambient air hydrocarbon standards
could be developed. This information would allow the expenditures for controls
to be channeled to the most effective areas.
Additional data are also needed regarding the fate of pollutants in
the environment and their long-term effects on plant and animal life. This
information would permit the most effective standards to be determined, and
would allow expenditures on control systems to be used most effectively.
After determining the variation in composition of waste streams using
developing technologies, appropriate monitoring and modeling programs can be
established.
The coal and oil shale industries are potentially large-scale industries
with sizeable environmental impacts, but they are both in early stages of
development which allow them to be responsive to pollution control techniques
to effectively minimize these environmental impacts. Development of improved
-4-
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monitoring and modeling technology should occur simultaneously with and
complement the development of new technologies.
-5-
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SECTION IV
RECOMMENDATIONS FOR RESEARCH AND DEVELOPMENT
Regulations presently define the particular species for which monitoring
is needed and also establish the standards for the monitoring. Averaging-time
is an example of the way regulations affect monitoring. A one-hour standard
is specified for ozone (03), while an annual standard is specified for nitrogen
dioxide (NC;^). Measurement of ozone once during each hour for a year would
provide little confidence that the maximum one-hour value actually was observed.
Measurement of N02 once each hour, however, would provide an adequate statis-
tical description of the N02 level for the one year period. Thus the need for '
a continuous analyzer is greater in the case of ozone than in the case of N02.
The specified concentration also influences monitoring needs. The stand-
ards for sulfur dioxide (S02) require sensing of levels of 30 parts per billion
(ppb); however, sensing of levels of 9000 ppb is sufficient for carbon monoxide
(CO). Sensitivity is thus much more important in the case of S02•
Research on monitoring methods must not await the defined need pro-
vided by regulations. To a greater extent, regulations are being defined by
health effects studies, and once a clear cut need is established, there is not
time for a lengthy research and development program to provide adequate
monitoring methods. This work should anticipate or parallel the health effects
studies. In fact, the studies themselves would be greatly expedited if they
were not constrained by laborious and time-consuming manual collection and
manual laboratory analyses of samples.
The case of ground water monitoring provides an example. Almost no
regulations for monitoring of ground water currently exist. Over 90 percent
of the nation's available water is ground water, and the fact that reclamation
of a polluted aquifer ranges from difficult to impossible provides ample
justification for development of monitoring techniques for ground water. The
availability of such techniques would help shape any required regulations to
protect this valuable resource.
In the case of coal conversion and oil shale industries, many species
are likely to be emitted for which no regulations presently exist. Some of
these may be hazardous as emitted, or may subsequently undergo some trans-
formation which renders them hazardous.
The monitoring and predictive technology needs for the coal and oil
shale industries will be discussed in the following paragraphs. These needs
are divided into air and water monitoring categories.
A list of recommended research and development efforts is provided for
each category, but special emphasis should be given to the following items:
Automatic, continuous or semi-continuous field monitors are needed
to provide detailed analyses of trace organics and trace elements
under ambient conditions.
-6-
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Accurate techniques should be developed for monitoring the quality
of ground water.
Improved particulate analyzers are needed.
Further development of instruments to make remote measurements of
air or water quality would be invaluable.
These and other recommendations will be discussed in more detail below.
MONITORING NEEDS
Air Monitoring
In the monitoring instrumentation area, the greatest needs are for
automatic, continuous or semi-continuous field monitors to provide a detailed
analysis of trace organics and trace metals. In the case of the trace metals,
it is important to be able to distinguish particular oxidation states and
particular compounds.
Coal conversion and oil shale plants are potential emitters of hazardous
trace metals and trace organics. These potential emissions could significantly
contribute to low ambient concentrations of hazardous pollutants. Low-
concentration, ambient pollution, presently a matter of great concern, is poorly
understood. Improved monitoring systems are necessary to cope with the long-
term effects of low concentrations of pollution. Because of the huge amounts
of raw material needed for coal conversion and oil shale plants, large
quantities of trace elements will be processed. The same is true for trace
organics which are either contained in the original material or are formed by
thermal treatment. The ability to monitor these species in the ambient environ-
ment is a necessary step toward insuring that pollution control procedures are
working properly.
Analysis of trace metals generally is not done under field conditions or
on a continuous basis, since present techniques require sample concentration
procedures. Adequate monitoring of these species will require development of
techniques which can be used under field conditions, which provide continuous
or rapidly updated results, and which can distinguish oxidation states and
preferably, particular compounds. A big difference between coal-using plants
of today and future coal conversion facilities relates to the oxidation-reduction
conditions. Presently, coal is burned in a largely oxidizing environment.
Coal conversion processes provide a reducing environment, and species emitted
from such processes are less likely to be stable in air than is presently the
case for coal-burning facilities. In terms of monitoring, this means that a
real-time, field analysis system is needed to adequately determine what species
are found initially, and to monitor their transformations. Many trace elements
are most hazardous in their lower oxidation states, the form in which they
may be emitted from coal conversion facilities.
As with trace metals, trace organics occur at low concentrations; thus,
long sampling periods followed by sample preparation and laboratory analysis
has typically been the only measurement technique. Rapid-feedback field
—7—
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measurement techniques are needed to identify and quantify trace organics in
air and in water.
The above comments about trace metals and trace organics apply particu-
larly to emissions from coal conversion and oil shale facilities, but also
apply to many other industries and problems. If additional information could
be obtained regarding the role of various hydrocarbon species or classes of
hydrocarbon species in photochemical smog, more realistic ambient air hydro-
carbon standards could be developed. This would allow the expenditures for
controls to be channeled to the most effective areas. The development of
monitoring devices for trace elements and trace organics is, therefore, a
necessary area of research.
Automated particulate analyzers which can measure short-term particulate
averages are needed. Some beta particle detectors of this type are becoming
available; however, they are almost prohibitively expensive as replacements
for the High Volume Method samplers. A possible approach to this problem might
be to separate the collection and analysis functions, i.e., to have one beta
particle analyzer support many field collection devices. This will require
that the collected samples be transportable without loss of the particulates.
Particulate monitoring devices are also needed which classify the collected
particulates according to size. Such particulate analyzers would be valuable
in assessing the impacts of the huge extraction and material-handling problems
associated with developing coal and oil shale resources.
There also is a real need for an air monitoring rationale, i.e., how
many stations should be used, how should they be sited, should they be moved
seasonally,etc. It is presently difficult to compare results from various
networks due to uncertainties resulting from the network designs. The siting
rationale must be flexible enough to allow for different monitoring goals.
Most monitoring methods in use today are quite site-specific, i.e., they
represent the air quality at a given point. Techniques are needed to charac-
terize air quality over broader areas. When monitoring particulates at an open
pit mine or hydrocarbons around a refinery, it is difficult to describe the
air quality in general since moving the monitor a short distance may cause a
significant change in the levels. A number of downwind plume measurements are
needed for area sources and for cities so that meaningful comparisons can be
made of air quality from year to year. These considerations are particularly
important in the western United States where the major new sources of coal and
oil shale are located. In many cases, the topography is extremely important
in developing an air monitoring network.
Along similar lines, there is a real need for further development of
instruments to make remote measurements of air or water quality. Even a very
expensive device could be cost-effective if it could be used to obtain large
area coverage rapidly. Remote sensing devices would be valuable for making
measurements of pristine areas in the West where coal and oil shale development
is proposed. These devices could help to rapidly establish baseline data for
regions that are presently almost inaccessible.
Additional work is needed in techniques for collection and preservation
of trace organics. In many cases, it is not known to what extent collected
-8-
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samples change as a result of the collection or preservation procedures. Over
the short term, field collection and concentration of samples, followed by
analysis in a laboratory, seems to present the best approach to monitoring of
many trace organic species. This is a slow and expensive procedure, and un-
certainties due to the sampling and preservation must be minimized.
Data are needed regarding the fate of pollutants in the environment and
their long-term effects on plant and animal life. Such data would permit the most
realistic standards to be determined and would allow expenditures on control
systems to be made most effectively.
Better methods of tracing pollutants in the atmosphere are needed. With
a wide number of easily detectable tracers, the contributions of many local
sources to the air quality in an area could be determined and would allow the
optimum control strategy to be developed. Tracers would also aid in studying
the fate of pollutants in the environment.
Monitoring instruments for the criteria pollutants need improvement in
their sensitivity. This would aid baseline studies in pristine areas and
would allow better evaluation of the influence of species such as nitric oxide
(NO) and nitrogen dioxide (N02) on formation of photochemical smog.
There is a constant need for improvement in calibration systems and
the long-term stability of calibration standards. The drift rates, mean time
between failure, and temperature sensitivity of most automated instruments
need improvement.
Water Monitoring
It is assumed in this report that there will be little or no dis-
charge of waste water to surface streams from coal conversion or oil shale
plants. Most facilities being planned are based upon a zero discharge concept.
Nevertheless, some effluents could still find their way to surface streams
through ground water (springs), stormwater runoff, or accidental overflows or
discharge.
There is considerable potential for contamination of ground water by
both coal conversion and oil shale facilities, and the monitoring needs are
greatest in this area. In-situ processes offer the greatest possibilities
for direct ground water pollution. The massive amounts of waste solids in
the coal and oil shale industries offer another source of contamination. The
slag, char, and ash generated in coal conversion plants and the spent shale
from retorting facilities probably will contain enriched amounts of trace elements.
There is also the possibility that carcinogenic organic compounds may be
present, as has been demonstrated for some types of spent shale. Leaching
of trace elements or trace organics from these waste solids could contaminate
ground water. Over ninety percent of the nation's available water is ground
water; in many of the areas which will be most impacted by the development of
coal and oil shale, the ground water is especially important because of the
limited availability of surface water. A polluted aquifer is nearly impossible
to reclaim.
— 9—
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There is a definite need for a rapid and accurate technique for
determining from one well the direction and rate of ground water movement.
This would aid in siting monitoring wells and in choosing locations for dis-
posal sites.
Also needed is a technique to monitor the movement of trace metals and
trace organics in solids in both saturated and unsaturated zones. There
are indications that some soils will strongly absorb many trace metals; how-
ever, the capacity of a given volume of soil may be low, or some subsequent
change in the soil environment might cause the metals to be displaced. Better
sample collection devices and procedures are needed for ground water in both
saturated and the unsaturated zones. In addition, better definition of well
drilling and well completion procedures are needed for monitoring wells. In
some cases, the monitoring well itself makes it almost impossible to obtain
a representative ground water sample. An example is a well drilled with a
bentonite drilling fluid. The bentonite becomes caked in the formation
surrounding the well bore, and subsequently removes trace organics and trace
metals from ground water flowing into the well bore.
The number of parameters which can be monitored continuously in both
ground water and surface water must be increased. Specific ion electrodes
represent the greatest advance in this area, but their long term stability
needs improvement. Along these same lines, methods for automatic cleaning and
calibration of water monitors need improvement. It would be desirable to
utilize a blank prepared from the stream being monitored with only the monitored
species removed. The effect of interferences would thus be eliminated during
the calibration.
Other monitoring techniques for ground water, such as soil temperatures
measurement, shallow earth resistivity measurement, and down-hole geophysical
methods should be explored further to ascertain their applicability and limi-
tations in defining flow and/or quality.
Similarly, the type of pollutants to be nationally monitored for a
specific type of energy facility need to be defined. This effort must account
for a range in reactivity likely to exist in the ground-water or surface-
water influent. For example, the chloride anion is considered conservative and
may be a good indicator of the extent of potential contamination, but more
deleterious and insidious contaminants, such as trace elements, in the geo-
hydrologic environment may be attenuated, i.e., retarded along the flow path
of the influent water. Other constituents' of the mixed geohydrologic fluid
may show different amounts of attenuation, especially in various geologic
settings. A monitoring program may be designed to consider the variable re-
activity of different pollutants that are monitored to define the contamination
enclave.
As was the case for air monitoring, there is a definite need for further
development of instruments to make remote measurements of water quality.
A reliable, inexpensive method for monitoring or otherwise ascer-
taining the integrity of pond liners should be developed. Similarly,
pre-treatment and operational procedures oriented toward maintaining the
-10-
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integrity of various liner types are desirable.
PREDICTIVE TECHNOLOGY NEEDS
Air Modeling
Broadly speaking, the fundamental limitations in the ability to
predict pollutant transport and transformations in the atmosphere are imposed
by an incomplete understanding of the chemical and photochemical kinetics
associated with pollutant transformations and the so-called closure problem
(TE-197) associated with characterizing atmospheric turbulence. It is
recognized that recommendations have a subjective bias conditioned by prior
experience in various areas. Moreover, there is a question of reconciling
the relevance of an effort on a fundamental level with the pragmatic exigen-
cies of solving air pollution problems. Finally, a large amount of effort is
currently being expended in smog chamber studies, wind tunnel studies,
modeling studies, full-scale atmospheric and monitoring studies.
Specific recommendations relating to improvements in current physico-
chemical grid models have recently been suggested (SE-105). These recommenda-
tions relate to development of a validated kinetic mechanism for characterizing
ozone production in the presence of oxides of nitrogen (NO ) and hydrocarbons.
Additional recommendations (SE-105) are made to improve the theoretical and numeri-
cal features of models used for simulating reactive transport in an urban are'a.
Apart from the recommendations in the references cited, it is suggested
that additional validation studies be performed to assess the accuracy of grid
models under controlled conditions.
A recent evaluation (NA-237) of various models indicates that models
previously regarded as quite accurate are less accurate in predicting spatial
trends than in predicting temporal trends previously evaluated. It should be
noted that the evaluation was based on predictions of CO, an inert pollutant,
for which uncertainties in kinetic mechanisms do not arise.
Models are available to treat certain aspects of transport in rugged
terrain. A complete characterization is unavailable, however, due to uncer-
tainties concerning the terrain-induced turbulence. Although a number of
studies concerning terrain-induced effects have been performed, definitive
results are difficult to obtain. Because of the importance of environmental
considerations in development of western energy resource sites, many of which
are located in complex terrain, a program designed to address the problem of
terrain-induced effects on pollutant transport is considered to be of para-
mount importance.
Micro-meteorological modeling is needed for box canyons which have
been proposed as the depositories for spent shale.
Transport of pollutants emitted from low level, relatively cold sources
(as opposed to tall hot stacks) needs to be better understood, and better models
need to be developed. Examples of low-lying sources are fugitive hydrocarbon
losses from refineries, coal conversion plants, and similar facilities.
-11-
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An important issue in relation to environmental impact studies is
whether postulated kinetic mechanisms can adequately describe transformations
inside a plume issuing from a point source. An important unknown is the
degree of mixing and dispersion which occurs in the plume and the degree to
which turbulence fluctuations affect the chemical reaction rates. There are
indications that turbulent fluctuations can influence the rates of reaction
(ES-009), although such influences are not considered in present models.
Tracer studies to characterize the stack-induced turbulence would be useful in
this regard.
Current emphasis in reactive transport modeling has been placed
primarily on the problem of photochemical smog production. The problem of
specifying the fate of reactive species has received little attention. An
adequate characterization of expected concentration of these species requires
the development of a rate mechanism which accounts for their sources, trans-
formations, and loss mechanisms. Accurate modeling of area-wide air quality
requires a knowledge of the sources, both natural and man-made, and the
mechanisms for pollutant removal from the atmosphere. Natural sources of the
various pollutants and the loss mechanisms for pollutants in general are
probably the most neglected areas of air pollution research.
Long-range transport of pollutants is not well understood. Long-range
is defined to be distance greater than several tens of miles or transport times
greater than a few hours.
Related to the above is the area of atmospheric aerosol formation and
sulfate and nitrate problems in particular. The formation, transport, and
loss mechanisms for these species are not fully understood, and meaningful
modeling is almost impossible.
Long-term degradation of visibility is an apparent problem and should
be investigated.
Techniques for the inclusion of terrain effects in dispersion models
should be improved. This applies to both advection and diffusion.
Better techniques for the inclusion of time varying meteorological
fields in dispersion models are needed.
Water Modeling
The existence and temperature dependence (over a significant range,
e.g., 0-100°C) of important ion pairs and higher complexes in natural water
systems are needed for implementing geochemical solution-dissolution models.
A reliable guide to the calculation or determination of dispersion
coefficients for ground water is needed.
A methodology and identification of important parameters must be made to
aid in the development of low-flow frequency analyses of surface water in
ungaged locations.
-12-
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More definitive techniques must be developed to measure and model the
existence and effect of nonpoint-source pollution parameters.
The numerical simulation of flow in the unsaturated zone is necessary
to adequately model ground water quality on a basin-wide scale. Similarly
changes in the quality of water moving through the unsaturated zone are of
extreme interest as this zone is where most water quality changes occur.
Flow in layered, anisotropic strata of different permeabilities must
be modeled so that a comparison with the existing technique of assuming
average conditions and homogeneous and isotropic media can be made to determine
the reliability and applicability of these assumptions.
Improved finite-difference algorithms for nonlinear equations should be
developed to improve three-dimensional matrix techniques.
Better data and prediction of thermal stratification are needed.
Procedures for treating sub-grid scale phenomena in three dimensional
matrix problems needs development.
More emphasis should be placed on the practical validation of predictive
numerical models. Many models are in use without validation of the available
options.
Most models of ground-water flow and quality consider only the hydraulic
head as the driving force. Other potentials (osmotic-pressure, adsorption,
thermal, chemical) need to be evaluated to determine under what circumstances
they are significant in ground-water flow.
The geochemical environment that causes desorption of previously sorbed
contaminants for various wastes from energy facilities needs to be defined,
and the possiblity that such environments may be achieved during or after
waste disposal should be assessed. Desorption can result in the release to
ground water of so-called "slugs" of relatively concentrated, toxic consti-
tuents to ground waters. The fate of such slugs also should be investigated.
-13-
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SECTION V.
TECHNOLOGY DESCRIPTIONS
COAL EXTRACTION
The two types of mining operations are underground and surface mining.
Underground mining techniques are conventional room and pillar, continuous
room and pillar, and longwall. Surface mining techniques are open-pit mining,
strip mining, and auger mining. Open-pit mining, commonly used in the metals
industry to mine deep, very thick deposits of ore, is not used to mine coal.
The 1973 production rates for the various mining methods are given in TABLE
1.
TABLE 1. ESTIMATED BITUMINOUS AND LIGNITE
PRODUCTION FOR 1973 (SOURCE: NI-036)
Mining Operation Millions of Tons Percent of Total
Underground:
Continuous room and pillar 181.0 30.7
Conventional room and pillar 102.0 17.3
Longwall 8.0 1.3
Surface:
Strip mining 283.0 48.0
Auger mining 16.0 2.7
Total 590.0 100.0
Underground gasification techniques can also be considered potential
methods of extracting coal energy. Underground coal gasification is in the
experimental phase of development.
Underground Mining
Underground mining applies to mining methods involving the construction
of a tunnel or shaft to access an underground resource deposit. Once this
access shaft is established, mining of the deposit can be attempted by any
one of several means. From 1973 statistics, continuous room and pillar mining
-14-
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accounted for 62.3 percent of all underground mined coal, conventional room
and pillar 35.1 percent, and longwall 2.6 percent (NI-036).
The development of all three types of underground mines follows the
same procedures. First, at least three main accesses or shafts are strate-
gically driven to the coal bed. Three types of access, (1) drift, (2) slope,
and (3) shaft, are shown in Figure^l. Once the main accesses have been
DRIFT SLOPE SHAFT
Figure 1. The three types of access used in
underground coal mines. (Source: TR-049)
constructed, two parallel main entries into the coal bed are driven in the
direction of the mining operation. Panel entries are driven from the main
entries to divide the coal seam into blocks. Finally, from the panel entries,
butt entries are made into the coal seam resulting in the formation of "pil-
lars" which support the roof. Butt entries are the headings made into the
panels for the systematic removal of the coal. This is room and pillar or
advance mining which will recover approximately 50 percent of the coal. If
the ground can be allowed to subside, an additional 35 percent of the total
amount of coal can be removed by retreat mining. Instead of the butt entries
a longwall technique can be used in which the entire side of the panel is
mined at once, leaving no pillar. Longwall mining removes 80 to 85 percent
of the coal in the mine (TR-049).
The two types of room and pillar mining (conventional and continuous) •
are shown in Figure 2. In conventional methods, the coal seam is blasted,
loaded by electric loaders on shuttle cars or conveyors, and hauled to the
main conveyor or mine rail car. With the electric continuous miner, the
coal is scraped from the seam, loaded directly on a conveyor or shuttle car,
and transported to the main conveyor or mine rail car. The roof in the
room and pillar mine is usually supported by roof bolts but can also be sup-
ported by roof trusses (TR-049).
The longwall mining process is shown in Figure 3. The electric longwall
miner advances laterally down the panel scraping and shearing the coal from
the seam. The coal is automatically loaded in a self-advancing conveyor and
transported to the main conveyor or mine rail car• The roof is supported
at the mine tace by a self-advancing hydraulic system. Behind the supports,
-15-
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5 SOCf SOU
(Bt CONTINUOUS
MINING
Figure 2. Illustration of room and pillar mining using conventional
blasting and continuous mining techniques. (Source: TR-049)
LONGWALU MINING
REQUIRES MULTIPLE ENTRY
DEVELOPMENT ON EACH
SIDE OF THE PANEL TO PROVIDE
VENTILATION, ACCESS, AND
CONVEYOR ROUTES.
TAILPIECE
LONGWALL
PANEL
LONGITUDINAL
ADVANCEMENT
SELF-ADVANCING
' : HYDRAULIC
ROOF SUPPORTS
BELT
CONVEYOR
HEADPIECE
Figure 3. Illustration of longwall mining technique. (Source: TR-049)
-16-
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the roof is allowed to collapse. The subsidence is sometimes enhanced by
blasting to ensure a more controlled cave-in rate (TR-049).
The advantages and disadvantages of room and pillar and longwall mining
are given in TABLE 2.
Surface Mining
In 1972 over 595 million tons (540 million metric tons) of bituminous
coal were mined; 49 percent of this tonnage was by surface mining methods
(GR-156), Surface mining refers to any method involving the removal of sur-
face material (overburden) to expose an underground resource deposit. Strip
and auger mining are the surface techniques applicable to coal extraction.
In strip mining the overburden is removed in narrow bands, one cut at a time.
The two strip mining methods for coal are area and contour. Strip mining has
a recovery rate of 80 to 90 percent with coal losses mainly due to spillage
and transit methods (ST-166). Strip mining is the most efficient technique
from a resource recovery aspect since this type of mining does not require that
a certain fraction of the coal be left behind as do underground methods.
Area strip mining is employed on gently rolling to relatively flat
terrain and is commonly found in the Midwest and West (GR-156). Topsoil
and overburden are first removed and placed in separate storage areas. After
the exposed coal seam is mined, overburden and topsoil are replaced and
reclamation activities begin. -In an established area strip mine, both mining
and reclamation activities occur on a simultaneous basis, as shown in Figure
4. The steps involved in an area strip mine are shown in Figure 5.
..•..•V v
i
..-_^ ORIGINAL SURFACE - ~l_r\ J^l—.
-.•£ -"'.77 .' 'COAL BED •
.^rSPOIL JfBAHK
STRIPPING BENCH —=-—
Figure 4. Area strip mining with concurrent reclamation. (Source: GR-156)
-17-
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TABLE 2. COMPARISON OF CONVENTIONAL, CONTINUOUS, AND LONGWALL MINING (SOURCE: TR-049)
Longwall
Continuous Room
and Pillar
Conventional
Room and Pillar
Advantages . Increases production
. Eliminates some permanent
room support cost
. Cuts cost of ventilation,
storage, and rock dusting
by 45%.
. Provides better ventilation,
roof support.
. Requires less supervision.
. Safer-superior method where
roof conditions are poor.
Involves fewer work cycles, less
equipment, and normally produces
more per man than conventional
mining.
Permits more concentrated mining
with fewer supervisory and venti-
lation problems.
Effective in coal-
beds with high hard-
ness ratings, large
partings* and varying
dimensions.
Produces less fine
coal.
Efficient where roof
and floor planes
undulate.
Disadvantages
i
M
CO
Requires large, level,
straight blocks of coal free
from obstructions with seam
height minimum of 39".
Requires high capital in-
vestment for equipment.
Involves costly equipment
moves (30-150 man-shifts to
move 300 tons of equipment).
Not effective where hardness
ratings are high, partings are
large*, floor and ceiling
planes undulate, and roof
conditions are poor.
Not effective where seam heights
vary greatly.
Cannot be used where coal size
is critical.
Provides inefficient face haulage.
. Requires numerous
work cycles.
. Involves larger crew
and more equipment
with attendant super-
visory and maintenance
problems.
. Produces less per man.
. Provides inefficient
face haulage.
. Not efficient where
roof conditions are
poor.
Partings are impure bands in coalbeds.
-------
Top soil
Removal
r
Overburden
Removal
'
f
Overburden
Replacement
i
r
Grading and
Replacement
Co a 1
Extraction
i
Mine
Drainage
Revegetation
Crushing
and
Grinding
Waste
Water
Treatment
1
Rec la tried
Water
^. Con I
Storage
i
Coal Tile
Runoff
Product
Co.l 1
Figure 5. Steps involved in area strip mining operations. (Source: RA-150)
Contour strip mining is used on terrain ranging from undulating to
very steep. Overburden is removed from the coal seam, starting at the out-
crop and proceeding along the hillside so that the cut appears as a contour
line. Overburden is stacked along the outer edge of the bench that forms.
After the uncovered seam is removed, successive cuts are made until the depth
of the overburden becomes too great for economical recovery of the coal.
Figure 6 illustrates contour mining. Slope reduction, box-cut, head-of-hollow
fill, mountain-top removal and block are contour mining methods for mining
on steep slopes (GR-156).
NO DIVERSION
DITCH
TO.XIC MATERIAL,
BRUSH & TREES IN Fill SECTION
Figure 6. Conventional contour mining. (Source: GR-156)
-19-
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Auger mining is usually associated with contour strip mining. When the
side walls of a contour mine become too steep for strip mining, augers are
used to recover additional coal. Augering produces coal by boring horizon-
tally into the coal seam, and the coal is recovered in chips similar to wood
chips from a drill bit (GR-156). Large augers may drill in excess of 200 feet
into a coal seam (EN-096).
Underground Coal Gasification
Underground coal gasification is a concept for converting coal deposits
into fuel gas by reaction with oxygen and steam. Present work in this area is
in the experimental and developmental stages. Despite decades of research in
several countries, no viable process has been produced, and formidable tech-
nical problems must be overcome before underground gasification can be com-
mercialized. Both physical and indicated economic successes have been so
limited that future large production facilities are unforeseen in the near
future. Therefore, underground gasification and its impacts will be only
briefly discussed in this report.
The first step in underground coal gasification is the preparation of
the coal bed by linking the inlet and outlet boreholes or shafts driven into
the coal seam. Linking processes increase the permeability of the coal bed
to allow for a smoother, faster gasification process. Some coal seams are
naturally quite permeable and do not require this preparation, but the major-
ity require pretreatment. Methods of linking the desired points in the bed
include electrolinking, pneumatic linking, and fracturing by hydraulic pre-
sure, explosives, or nuclear reaction (GA-104, HU-079, KA-124).
The gasification of the coal seam includes the introduction of the
gasifying agents, contact of the agents with the coal, recovery and purifica-
tion of the combusion products, and control of the process. The gasifying
agents are oxygen, steam, and carbon dioxide. These gases, introduced in
varying proportions, react with the pretreated coal seam to produce an exit
gas containing carbon monoxide (CO) , carbon dioxide (C02) , methane (CHi,) ,
hydrogen (H2), water vapor (H20), nitrogen (N2), and various volatile organics
from the coal seam (GA-104). The raw gas also contains heavy entrained hydro-
carbons and hydrogen sulfide (H2S) and must be purified.
Experience with coal gasification has revealed the following disadvan-
tages (GA-104, HU-079, KA-124):
(1) The heating value of the gas is low and generally
decreases with time.
(2) Gases leak out of the gasification area.
(3) The percentage of coal energy recovered is small.
(4) Ground water can penetrate the gasification zone
and extinguish the fire.
(5) The burned-out area can collapse causing surface
subsidence problems.
-20-
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(6) Direction of the flame front is hard to control.
(7) Coal beds often lack uniformity which produces a
poor burning front.
Despite these disadvantages, underground coal gasification has the following
advantages over conventional mining (GA-104):
(1) Equipment cost is much less,
(2) Underground labor and the inherent hazards are eliminated.
(3) Coal seams which are deep and not minable can be recovered
by underground gasification.
Further development of the technology will determine the extent of
eventual application of underground coal gasification.
COAL CLEANING
Physical Coal Cleaning
Physical coal cleaning involves crushing, grinding, sizing, solid
separation, washing, and flotation in various combinations designed to reduce
inorganic matter. These methods are applied at the mine site. Physical coal
cleaning is a proven industrial technique used to remove portions of the sul-
fur and ash contents of coal. Although the sulfur present in coal exists in
both inorganic and organic forms, physical cleaning is only effective in
removing inorganic sulfur. In addition to reducing the coal sulfur content,
physical cleaning results in an increase in the per pound heat content of the
coal due to the partial removal of ash.
The physical cleaning of coal in this study is based on dense media
washing. Run-of-mine coal is crushed to a top size of three inches and sent
to a dense media washing unit. In this unit the coal is separated into two
layers by washing with a liquid of 1.6 specific gravity. The heaviest frac-
tion, which contains the ash and refuse material, is removed from the bottom
of the unit. The so-called "float material" is removed and crushed to a top
size of 3/8 inch. Screening of this material yields two fractions. The smaller
fraction is sent to a dense media cyclone where it is treated with a liquid of
1.35 specific gravity. The float coal of density less than 1.35 from the dense
media cyclones is washed, wet ground to 30 mesh x 0 and centrifugally dried. The
30 mesh x 0 fraction from the "float material" screening is sent to a froth
floatation unit where the fines are frothed (after treating with alcohols, pine
oil or kerosene to render the coal particles nonwettable and to facilitate
agglomeration), skimmed, thickened and vacuum-filtered. The two 30 mesh x 0
streams are combined to yield the physically-cleaned coal product (RA-150, ZI-014)
Refuse from the process is collected and stored until time of disposal.
The liquid effluent streams, containing large quantities of suspended solids,
are sent to holding ponds where the solids settle and the clear supernatant
-21-
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liquid is returned to the process. Figure 7 is a block diagram of the
physical coal-cleaning process.
Breaker or
Crusher
FloatPCoai Classifying & y. ^ ^ Impact
* Screens S , • » crusher
I 1
Dense Media
Washer
S?. -i. - 1.6
y x p Classifying
1
refuse 3/8" * °
1
I
Classifying
Screens
1n»..h.n CS0J.lo"tlng JO Mesh x a Two Stage .
and Pumps ' Hydrocyclones ^ High SuUul Rejects
3/8" it 30 mesh
Dense Media
Cyclones
sp. gr. - 1.35
1.6 x 1.35
sink Wet Grindlna . fi "'^l,* ° Fr°th .T,iiino,
-.' Mills * Clasiirlar flotation >Tallings
Units |
-1.35 sp.gr. 1
Floar foal . 1
Centrifugal
Dryer
3/8" i
Vacuum
Filter
i 30 mesh , 3/5" r 0 Pnysically
Coal Product
Figure 7. Physical coal-cleaning plant processing diagram. (Source: RA-150)
Current physical coal-cleaning processes remove about 50 percent of the
pyritic sulfur and lose some 10 percent of the coal (KA-124) .
Chemical Coal-Cleaning
Chemical coal-cleaning or desulfurization involves treating coal with a
reagent capable of converting the sulfur to a soluble or volatile form. A wide
variety of possible leaching solutions such as nitric acid (HN03), hydrofluoric
acid (HFl) , chlorine (Cl) , molten caustic, aqueous caustic, ammonia (NHs), steam,
and organic solvents have been tested (BA-234) . Although several of these methods
have been reported to be successful, chemical coal-cleaning is not currently em-
ployed commercialy. Several experimental studies are in progress however.
Two important processes being developed are the Meyers and Battelle processes.
Descriptions of the two processes follow.
Meyers Coal Desulfurization Process
The Meyers process uses an aqueous solution of ferric sulfate [Fe2 (80^)3]
at about 100°C to remove pyritic sulfur (S) from coal. Ferrous sulfate (FeSOiJ ,
excess sulfate as sulfuric acid (H2SOit), and elemental sulfur (S) are formed
during the reaction. The elemental sulfur is removed by dissolution in a warm
naphtha bath. The coal slurry from the sulfur extraction vessel goes to a
-22-
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washer, filter, and dryer where the coal is separated from the aqueous solution
which retains the sulfate. Ferric sulfate is regenerated from ferrous sulfate
by reaction with air or oxygen. The excess ferric and ferrous sulfate are
removed from the system. Figure 8 diagrams the Meyers process. The overall
leaching reaction, regeneration reaction, and net overall reaction are shown
in equations 1 through 3 respectively:
Fe S2 + 4.6 Fe2(SO^)3 + 4.8 H20 -»• 10.2 FeSO^ + 4.8 H2S04 + 0.8 S (1)
9.6 FeSCU + 4.9 HaSOt, -I- 2.4 02 •*• 4.8 Fe2(S0lt)3 + 4.8 H20 (2)
FeS2 + 2.4 02 -*• 0.2 Fe2(SOO3 + °'6 FeSO" + °'8 S
This process removes 90 to 95 percent of the pyritic sulfur with a loss
of less than 5 percent of the coal; the heat content of the product coal is
also increased because there is less ash. Only organic sulfur is left in
the coal (CA-190, KA-124).
Battelle Hydrothermal Process
In this process, hydrothermal technology is applied to extract sulfur
from coal using an aqueous caustic solution as the leachant. The process
involves heating a water slurry of coal and sodium hydroxide to convert both
pyritic and organic sulfur and part of the ash to soluble species. The five
stages of the process are (1) coal preparation, (2) hydrothermal treatment,
(3) fuel separation, (4) fuel drying, and (5) leachant regeneration. Figure
9 outlines the process. Temperatures on the order of 430 to 650° F and pres-
sures of 350 to 2,500 pounds per square inch (psi) are used (WO-055).
In the sulfur removal autoclave, almost all the pyritic sulfur and up
to 70 percent of the organic sulfur are dissolved, primarily as sodium sulfide.
Part of the ash and about 5 percent of the coal also dissolve. The final
product is a dry, granular solid (HA-319, WO-055).
Regeneration of the spent leachant begins by sparging the solution with
carbon dioxide to convert the sodium sulfide to hydrogen sulfide and sodium car-
bonate. The released hydrogen sulfide can be converted to elemental sulfur for
recovery. Next, the sodium carbonate reacts with lime to form a sodium hydroxide
solution and a precipitate of calcium carbonate. This solution can then be
filtered, concentrated and recycled. The lime can be recovered by calcining the
limestone.
The Battelle process has been tested in a small, continuous operation
plant processing 500 pounds of coal per day. The next step will be the test-
ing of a 50 ton-per-day pilot plant.
-23-
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OXYGEN
(AIR)
COAL
I
N3
-p-
LEACH
SOLUTION
LOW-SULFUR
COAL
Figure 8. Flow sheet for Meyers process,
-------
HIGH-SULFUR
COAL
REGENERATED
CHEMICAL.
(NaOH)
LOW-
SULFUR
COAL
CHEMICALS
FUEL
METALS
CaCOj
Figure 9. Schematic of hydrothermal coal process showing reactions
and product stream.
COAL SLURRY PIPELINE
Coal slurry pipeline technology has proven to be a commercially success-
ful alternative for coal transport. Constructed by Consolidated Coal Co., the
first multi-station coal slurry pipeline began operation in Ohio in 1957 and
ran for six years. It achieved an availability factor of better than 98%.
In August 1970 the Black Mesa pipeline began transporting coal 273 miles from
a mine in northeastern Arizona to the Mohave Power Plant in Southern Nevada.
The availability factor of this four-station line was greater than 99% in 1972
and in 1973 (MO-113).
The success of the Black Mesa pipeline has led to the planning and
construction of new coal slurry pieplines for the development of new energy
reserves. Planned and constructed coal slurry pipelines are summarized in
TABLE 3. The impending expansion of the coal slurry piepline system requires
discussion in this report.
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TABLE 3. SUMMARY OF COMMERCIAL COAL SLURRY PIPELINES
(SOURCE: EN-140, EN-202, WA-139)
Status
System or
location
Annual
thruput
Length Diameter (millions Initial
(miles) (inches) tons/year) operation
Constructed Consolidated Coal Co.
108
10
1.3
1957
Black Mesa
Planned Nevada Power Co.
(Utah to Nev.)
Salt River
(N. Mex. to Ariz.)
273
180
180
Houston Power & Light Co.1100
(Colo, to Tex.)
Energy Transportation 1030
Systems, Inc.
(Wyo. to Ark.)
Canada 500
Gulf Interstate - 800
Northwest Pipeline
(Wyo. to Wash.)
18
24
16
18
38
24
30
4.8
10
25
12
16
1970
Planned
Planned
Planned
Planned
Planned
Planned
The hydraulic transport of solids is a well-developed technology
(AD-021, AU-006, BA-233, DU-061, GO-055, PI-044., SK-024, ST-188). Materials
transported by slurry pipelines include coal, limestone, magnetite, gilsonite,
copper concentrate, phosphate, and tailing. Flow regimes have been identi-
fied and classified; their characteristics are well understood and can be
predicted by laboratory tests and mathematical models.
Figure 10 is a schematic of a coal slurry pipeline showing the rela-
tionship of the pipeline to the coal source and to the coal user. At the
coal slurry preparation plant, the coal is broken, washed, ground to a maxi-
mum size of 14 mesh, and slurried. The sizing of the coal is accomplished
by dry crushing and by wet grinding and rod mill pulverization (LO-084, MO-103,
MO-126). In the rod mills, water is introduced to the pulverized coal to
form the slurry. The concentration of coal, by weight, is in the range of
45-55% (WA-043, WA-140). The weight percent solids of the Black Mesa pipe-
line is actually held at 46.5 ± 0.1% (KA-124). The slurry is pumped into
mechanically-agitated storage tanks where an average concentration of solids
is maintained. Then the slurry is fed into the pipeline from the storage tanks
by a centrifugal charge pump, followed by a high pressure positive displacement
pump. The Black Mesa pipeline has a 1000-foot loop circling the preparation
plant where the behavior of the slurry is monitored before leaving the plant
-26-
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WATER
COAL-
COAL
CLEANING
DEWATERING
PLANT
SLURRY
PREPARATION
PIPELINE
AND
PUMP STATIONS
DEWATERED
COAL
TANKAGE
COAL
USER
WATER
Figure 10. Schematic of coal slurry pipeline.
boundaries. An average flow velocity of 5.0 ft/sec is maintained throughout
the pipeline by pumps that are spaced along the line (WA-125, WA-126). Pump
stations are spaced at 60-100 mile intervals (AU-019, CO-197, HU-088, WA-153).
The pipeline terminates at a power plant where the slurry is discharged to
holding tanks. This is followed by dewatering through centrifuges and further
size reduction by conventional ball mills. The pulverized coal is then injected
into the boilers. Coal slurry pipelines can, of course, be used to deliver
coal to other users such as gasification plants. Most of the new gasification
processes require a fine feed, but the Lurgi process cannot use coal that has
been ground as fine as is necessary for pipeline transport.
COAL GASIFICATION
Coal gasification is a technique by which solid coal is converted to
a gaseous product by reaction with air, oxygen, steam, carbon monoxide,
hydrogen, or mixtures of these gases. The two categories of gasification
processes, classified according to the heating values of the synthesis gases,
are (1) high-Btu gasification and (2) low-and-intermediate-Btu gasification.
High-Btu gas has a heating value of about 950 to 1000 Btu/scf (standard cubic
foot) while low-Btu gas has a value of about 135 to 200 Btu/scf. High-Btu
gasification is aimed toward developemnt of a substitute for natural gas
which can be economically piped over long distances. Low-Btu gas is less ex-
pensive and will be used for producing a clean fuel for utility plants or
industrial sites.
Several factors are important in determining the heating value of
the synthesis gas. One such factor is whether air or oxygen is used as the
oxidizing agent in the gasification step. Pure oxygen is used to produce
high-Btu gas and air is used to produce low-Btu gas. Another factor is the
presence or absence of upgrading facilities. Upgrading the synthesis gas
by shift conversion and methanation produces a high-Btu gas. The methanation
-27-
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step developed in one gasification project presumably could be used with
other gasification processes. Therefore some gasification processes could
be placed in either category depending upon the process details.
Gasification processes may also be classified according to gasifier
characteristics such as dry-ash moving bed, slagging moving bed, dry-ash fluid
bed, ash agglomerating fluid bed, entrainment, slagging entrainment, and
molten bath.
In the following two sections, high-and-low-Btu gasification and the
processes normally associated with each are described briefly. No attempt is
made to provide complete, detailed descriptions of the processes since these
are available in the literature.
High-Btu Coal Gasification
The objective of all high-Btu coal gasification processes is the con-
version of coal to essentially pure methane or substitute natural gas (SNG).
The heating value of this pipeline-quality gas is about 1,000 Btu/scf.
All SNG-from-coal processes utilize some kind of a gasifier to produce
a synthesis gas which contains CEU , CO, H20, H2, and C02. After leaving the
gasifier, the synthesis gas goes through several processing steps to upgrade
it to pipeline quality gas. Figure 11 is a general schematic of the gasifica-
tion process. Technology common to all the processes are solids separation
I 4 COOLIIIO _ HAUUP H,0
^^ rnutae ^^ *
AU-.
COAL—»
(NH,)j SO,
Figure 11. Simplified process flow diagram of typical high-Btu
coal gasification complex.
and cooling, shift reaction, acid gas removal, sulfur recovery, catalytic
methanation, and drying. While the specific means of accomplishing the gas
processing steps may vary from process to process, the basic principles of
-28-
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each step are common to all processes. The major distinguishing feature of
the various high-Btu gasification processes is the design of the gasifier.
The catalytic shift and methanation reaction steps are the only SNG-
from-coal process operations which have not yet been demonstrated on a com-
mercial scale. Lurgi reactor technology has been proven in several foreign
installations. Current research and development activities in this country are
concerned mainly with the development of competitive gasification reactor designs.
The following paragraphs briefly describe current high-Btu coal gasifi-
cation processes. The Lurgi gasifier is the only process ready for commercial
application. The ad hoc panel on "Evaluation of Coal Gasification Technology"
of the National Academy o'f Engineering has judged the HYGAS steam-oxygen,
Synthane, BI-GAS, and COa Acceptor processes as the most advanced of the other
processes and should be rapidly developed to the demonstration plant stage so
that a decision can be made as to their commercial applicability. The panel
also judged the U.S. Bureau of Mines Hydrane Process to be promising (NA-115).
Of course, this does not mean that the other processes, which are generally
more proprietary, cannot become commercial realities. Available information
on specific development plans for each of the emerging gasification technologies
is summarized in TABLE 4. The advantages, disadvantages, or economic aspects
of the processes are not evaluated in this report.
The major distinguishing feature of the various gasification processes
lies in the gasifier section. In this section raw coal reacts to produce
a synthesis gas which can be upgraded to pipeline quality gas. The differ-
ences among the processes are found in the operating temperatures, pressures,
mechanical characteristics of the gasifier and the means of supplying heat for
the gasification reactions. These reactions for high-Btu gasification are
shown in equations 4 through 7:
Coal -> CHi+ + Char + Heat (4)
C + 2H2 ->• CH^ + Heat (5)
C + H20 + Heat -* CO + H2 (6)
2C + 02 -" 2CO + Heat (7)
Lurgi Process
The Lurgi gasifier is a moving bed, steam-oxygen gasifier. Noncaking
or slightly caking coal is crushed, fed through a lock hopper, and distributed
in the gasifier via a revolving grate. Steam and oxygen injected at the bot-
tom of the gasifier are distributed through a second revolving grate which
also provides bed support and regulates the ash removal rate. Ash is removed
from the gasifier via a lock hopper and water quenched. Figure 12 shows the
Lurgi gasifier.
The steam and oxygen react with char to produce heat and synthesis gas.
This gas rises while the coal bed moves downward. As the coal enters the top
of the gasifier, the coal devolatilizes and forms more methane. The process creates
three zones in the gasifier: (1) the coal preheat zone, (2) the reaction zone,
-29-
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TABLE 4. HIGH-BTU COAL GASIFICATION TECHNOLOGY
Process Name and Developer Development Status
Development Plans
Lurgi
Lurgi Mineralotechnik
G.m.b.H.
HYGAS
Institute of Gas
Technology
BI-GAS
Bituminous Coal Research,
Inc.
Several commercial-scale Demonstration of technol-
plants, approximately ogy on commercial scale
250-MM scfd capacity,
are under construction
75 tons per day (tpd)
pilot plant is opera-
tional
Methanation reactor
tests being performed
Preliminary design of
80-MM scfd demonstration
plant completed
Operation of 120 tpd pilot
plant
Synthane
U.S. Bureau of Mines
C02 Acceptor
Consolidation Coal Co.
Hydrane
U.S. Bureau of Mines
ATGAS
Applied Technology Corp.
Molten Salt
M. W. Kellogg Co.
COGAS
Cogas Development Co.
Union Carbide Process
Union Carbide-Battelle-
Chemico
75 tpd pilot plant
operational
Demonstration size plane
40 tpd plant operational Demonstration size plant
12 Ib/hr process devel-
opment unit operational
Batch testing on bench
scale
Tested in 5-in diameter
reactor
Components of process
tested during 1960's
Scale up to 10-30 tpd
pilot plant
Testing in 30-in-. diameter
reactor
Pilot plant to be used in
conjunction with COED
process
Operation of 25 tpd pilot
plant
Solution Gasification
Stone and Webster/
General Atomic
GRD Process
Garrett Research and
Development
EXXON Process
EXXON Corp.
Tested on bench scale
Tested in 50 Ib/hr unit
Demonstration plant using
nuclear reactors to pro-
vide heat for hydrogen
generation
Seeking support for 250
tpd pilot plant
Tested in 1/2 tpd unit Construction of demonstra-
tion plant deferred
-30-
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COAL LOCK
HOPPER
GAS
DISTRIBUTOR
GRATE
Figure 12. Lurgi gasifier.
and (3) the ash zone. The temperature at the bottom of the gasifier is about
1800°F, while the temperature at the top of the gasifier is about 1100°F.
The Lurgi gasifier operates at a pressure of 300-500 psi (FE-068). About
86% of the coal is gasified and the remaining 14%, mostly carbon, is burned
in the combustion zone to provide the overall heat for the gasification and
devolatilization reaction (MO-150).
HYGAS Process
The HYGAS Process gasifies coal by direct hydrogenation at high pres-
sures. The Institute of Gas Technology (IGT) has developed three methods for
generating the hydrogen to be used in the gasifier. These three processes
are the electrothermal, steam-iron, and steam-oxygen processes. The National
Academy of Engineers has judged the steam-oxygen process to have the greatest
potential for success (NA-115), and IGT has chosen this to be the first method
integrated with the HYGAS unit (LE-133) . Figure 13 illustrates the HYGAS
process and associated steam-oxygen process.
The HYGAS gasifier section consists of (1) coal pretreatment, (2)
slurry preparation, (3) a fluidized-bed, two-stage gasifier, and (4) hydrogen
production.
Crushed coal is fed to the pretreater where the caking tendencies of
the coal are destroyed by a hot air stream. The treated coal mixes with a
light oil formed in the gasifier and is injected into the top of the gasifier
-31-
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1 symnesis oas
Coal
Slurry
Raw Coal
i
Fuel „
Gas
•>.
-(Coal
latm Pretreater
l?508Fl(fluidized!
Hot I
Air
Recycled
Light •-
Oil
Cool
Slurry
Preparation
O
^ i
W
?
' S"
*T~
\
fi-.—
b,
•^
J~
1L
. . .
L_ M — ., -»J
[Stage I |
Kfluidized))
^v - j
\
^, ,
/
"sTSgeT
(fluidized)
I700-
i;
V
Chor
30C
f?
L
— *•
)°F
^ —
^
urying oea
L
-(fluidiied)
600°F
Hydrogasifier
I300-!50C"F
lQOO-l500psia
Wurfrnn£srt C3I/-K f^r^f
x^~^N
I850-
2500°F
IOOO-
ISOOpsi.
Suspension
Gcsifier
Oxygen S Steam
Ash
|—Water
T
Water-Ash
Slurry
Figure 13. HYGAS coal gasification process. (Source: KA-124)
in a slurry form. At the top of the gasifier the light oil evaporates and the
dried coal falls into the upper part of the gasifier. The coal reacts with
rising hot synthesis gas at a temperature of 1300-1500°F.
The hydrogen-rich gas and steam injected into the bottom of the gasifier
react with the char formed in the upper stages of the gasifier to form methane
concurrently with the formation of CO and H2 from the steam-carbon reaction.
The lower portion of the gasifier operates at 1700-1800°F. The gasifier pres-
sure is 1000-1500 psi. Figure 14 gives a more detailed diagram of the gasifi-
cation section.
Unreacted char from the bottom of the gasifier is sent to a hydrogen-
rich gas generator where it reacts with steam to yield'Hz and CO. In the
steam-oxygen process, heat for the reaction of steam with char to form RZ and
CO is supplied by combustion of a portion of the char with oxygen in a fluid
bed (BO-117, LE-133, SC-249).
A 75 ton/day pilot plant was finished in 1971, which included an elec-
trothermal gasifier (FE-068). A 2 ton/day fluidized bed reactor utilizing
steam and oxygen to produce a hydrogen-rich gas has also been constructed.
The design and evaluation of a HYGAS demonstration plant using steam-oxygen
gasification for hydrogen generation is in progress, and it is possible that
a commercial plant could be ready for operation before the end of 1980
(LE-133, SC-249).
-32-
-------
INLET FOR SLURRY V
OF CRUSHED COAL \
AND UCHT OIL /~~
FLUI01ZEO BED IN \
WHICH SLURRY OIL IS \
VAPORIZED BY RISING, \
HOT GASES AS f"
COAL DESCENDS /
DRIED COAL FEED \
FOR FIRST -STAGE /—
HYOROGASIFICATION /
HKH VELOCITY GAS \
FROM SECOND -STAGE f~
WXES WITH DRIED COAL /
CHAR FROM FIRST STAGE \
FEEDS INTO SECOND- 1
STASE FLUIDIZED BED /
HYDROGEN - RICH GAS \
SECOND - STAGE/
RAW GAS OUTLET
TO QUENCH CLEANUP r, .
AND METHANATION STEPS ~ /^l1^.
NITROGEN. PRESSURIZED
OUTER SHELL ~~~
' ~ — —
HOT GAS RISING
INTO DRIER '
HYDROGASIFICATION
IN COCURRENT FLOW —«•».
OF GAS AND SOLIDS
— —- -
HOT GAS RISING
INTO FIRST -STAGE — —
RISING GASES CONTACT
CHAR FOR FURTHER '
HTOROGASIFICATION
HYDROGASIFIED CHAR
FROM SECOND -STAGE ~~~~
FEEDS INTO STEAM.
OXYGEN GASIF1ER
STE*»— ==a^
OXYGEN— ==^"[
H* n
\ / SLURRY
__[_, f DRIER
L, J
jwil"1 ^ GAS - SOLIDS
(It > DISENGAGING
' j sEaicw
V ^
'1^-l\ FIRST -STAGE
1 N | HYOROGASIFI-
\| 1 ) CATION
~-^i U
^ ^ ff
£L \
'^StCONO-MAIlE
MTORCGASIFI-
CATION
;prRijK
JJ !
j \STEAM-OXYGENI
[ f GASIFIER
VJ
ASH
Figure 14. IGT pilot plant hydrogasification reactor section.
(Source: LE-133)
Synthane. Process
The Synthane Process, developed by the U. S. Bureau of Mines, converts
bituminous coal, sub-bituminous coal, and lignite into SNG. The process uses
a two-stage, fluidized-bed gasifier with a free-falling pretreatment stage.
Pretreatment of caking coals and gasification occur in one reactor.
Crushed coal, fed into the top of the gasifier, reacts with steam and
oxygen in a free-falling manner that destroys the caking properties of the
coal in addition to partially devolatilizing the coal. After pretreatment the
coal enters the hydrogasification stage of the gasifier and then the gasifica-
tion section. Both of these stages operate as a fluidized bed. At the bottom
of the gasifier, steam and oxygen are injected and char and ash are removed.
The steam, oxygen, and char react to produce a synthesis gas. * The gasification
stage operates 1750-1850°F and the hydrogasification stage operates at 1100-
1450°F. The entire gasifier is under 600-1000 psi pressure (US-109, FO-059).
Figure 15 is a schematic of the Synthane Process.
The Synthane Process development started in 1961 in a study of pre-
treating caking coals in a fluid bed. Work was also done to develop a
suitable methanation reactor. Two systems were studied: (1) a hot gas
recycling process and (2) a tube wall reactor process. Forney and McGee
(FO-050) have discussed research results and prototype plant design. Con-
struction of a 72 ton/day pilot plant was completed in the fall of 1974. A
-33-
-------
previous study for the EPA has evaluated pollution control for the process
(KA-142).
Crushed
Cool
I
("Stock
I I Hopper
N/
Synthesis
Gas
Fluid
Bed
Pretreat
Gasifier
600-JOOOpsi
Steam •
Oxygen •
\Dense
\ Bed
1100-14501
°F
Dilute
Fluidized
Bed
I750-I850°F,
Sfeam •
Oxygen
Chor Recycle
BI-GAS Process
9 Lock
Hopper
Figure 15. Synthane coal gasification process,
(Source KA-124)
The BI-GAS Process uses a two-stage, high-pressure oxygen-blown
gasifier with an entrained bed. Pulverized coal and steam are fed into the
first stage of the entrained flow gasifier. Upon contact with the hot syn-
thesis gas rising from Stage 2, the coal rapidly undergoes devolatilization
to produce methane and an active carbon char, which reacts with steam to yield
more synthesis gas. The char and gas are swept out of the top of the gasifier
to the char separation cyclone where the char is removed and returned, along
with steam and oxygen, to the second stage of the gasifier. In this lower
stage of the gasifier, the carbon char is gasified to produce a hot synthesis
gas which rises to the first stage and provides heat for further production
of synthesis gas. Molten slag is removed from the bottom of the gasifier and
water quenched. The Stage 1 reaction temperature is about 1700°F, while the
Stage 2 temperature is 2700°F. The gasifier operates at 1000-1500 psi
(BO-117, FE-068, GR-109, GR-162). Figure 16 schematically shows the BI-GAS
system. The gasifier may also be operated with air rather than oxygen at
moderate pressures to produce a low-Btu raw gas (BO-117).
The BI-GAS Process was developed by Bituminous Coal Research. After
laboratory testing, a 5 Ib/hr process and equipment development unit was con-
structed to test the second stage of the gasifier (GR-162). A 5 ton-per-hour
-34-
-------
pilot plant has been completed and is in operation (FE-068)
Slurry
Feeflf
Cyclone
Seporotor
Pulverized
Cool
Quench
Water
Recycle
Gas
• Synthesis
Cos
Cold
Wafer
Quench
Slog to Disposal Pond
Figure 16. BI-GAS coal gasification process.
(Source KA-124)
Acceptor Process
The COa Acceptor Process, specifically developed for lignite and sub-
bituminous coal, is characterized by three f luidized-bed reactors and a
circulating system of calcined dolomite. The basic function of this process
is to provide heat for the reaction of coal and steam by using an acceptor
which reacts exothermally with the COa formed. The product gas stream is
then uncontaminated by the products of combustion. The COa Acceptor Process
uses the exothermic reaction between calcium oxide (CaO) (obtained from calcined
dolomite) and C02 to provide the heat of gasification (KA-124). Removal of COa
also enhances the exothermic reactions of CO-shift and methanation (BO-117) .
Crushed and dried coal, steam, calcined dolomite and synthesis gas are
fed to the f luidized-bed devolatilizer. The coal undergoes devolatilization
and a steam-carbon reaction. Heat for the formation of CO and Ha is sup-
plied by the reaction of calcined dolomite with carbon dioxide. The lignite
char formed also reacts with hydrogen to form more methane. The synthesis
gas exiting the devolatilizer is upgraded downstream into SNG, while the re-
maining lignite char is sent to the gasifier. Here, more steam and calcined
dolomite are added to produce synthesis gas for addition to the devolatilizer.
Unreacted char from the gasifier is burned in the regenerator and the heat is
used to recalcine the spent dolomite from the gasifier and devolatilizer. The
-35-
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system pressure is 150-300 psi, the gasifier and devolatilizer temperature
is 1500° F, and the regenerator temperature is 1900° F (FE-068). This process
produces a gas low in carbon dioxide, carbon monoxide, and sulfur. The up-
grading procedure is therefore somewhat easier than with some other processes.
Figure 17 illustrates the C02 Acceptor Process.
HEAT RECOVERY
OEvoumizfa
\Kt'r
2UKIO
k
MOLES
N2 65
C02 31
CO 2
H20 1.5
>
1900 "t
300PSIG
^
A
f
h
~^
MOLE%
H2
CO
H20
CH,,
C02
NHj
SO %
IS
18
10
S
,i
HjS
Nj
PH2
DHjS
.017
.25
• 143
.05
%
HAWGAi
TO PURIFICATION
AND MUHAftATION
MEAT RECOVtHY
CASIflEB
ISJS'F
MOLE%
«2
CO
CH4
H20
C02
HjS
PH2
'H^
dewpt
52 %
11
3
28
6
0.03
• 154
a.oa
=1 330"F
o
Figure 17. C02 acceptor process for coal gasification (ST-310).
The C02 Acceptor Process was developed by Consolidated Coal Company in
conjunction with the Office of Coal Research (OCR) and the American Gas Associa-
tion (AGA). Bench-scale studies have been completed and a 30 ton per day pilot
plant is now in operation. The process is nearing the point of commercial
consideration.
Hydrane Process
The Hydrane'Process, being developed by the U. S. Bureau of Mines, is
designed to produce a high initial methane concentration by the reaction of
raw coal with hydrogen.
Pulverized coal of any rank is fed into the first stage of the gasifier
which is the coal-hydrogenation reactor or hydrogasifier. A concurrent gas
stream from the second stage containing equal parts of methane and hydrogen
also enters this chamber which is operated at 1650° F and 1000 psi. The coal
devolatilizes and forms some methane. The char then enters the second stage
(fluid-bed hydrogenation) reactor where it contacts fresh hydrogen to form
-36-
-------
more methane. The methane-hydrogen mixture formed in the second.stage (char-
hydrogenation) reactor flows to the first stage to react with the fresh coal
feed. Char from the gasifier's second stage flows to a hydrogen generator
where the hydrogen for the process is produced. Since no oxygen is introduced
into the gasification system, the only carbon oxides in the gas are those from
the oxygen of the coal. The hydrogen is made in a separate reactor by steam-
oxygen gasification of the residual char from the fluidized bed. This reduc-
tion in carbon oxides simplifies the acid-gas removal and final methanation
steps (BO-117, FE-093, KA-124, NA-115, YA-044). The schematic for the Hydrane
Process is shown in Figure 18.
COAL
PIPELINE
GAS
GAS
FROM
FLUID
BED
STAGE 1
ENTRAINED
FLOW
STAGE 2
FLUIDIZED
HYDROGEN-RICH
STEAM-
GAS
SYNTHESIS
GAS
PRODUCER
CHAR
STEAM & CHAR
Figure 18. Hydrane coal gasification process.
ATGAS Process
The ATGAS Process, developed by the Applied Technology Corporation, is
based on the simultaneous carbonization with coal and decarbonization with air
or oxygen of a molten iron bath (KA-156).
Crushed coal is injected deeply into a molten iron bath while oxygen is
injected near the iron-bath surface. Coal volatiles are cracked into CO and
H2 and released into the off-gas. The remaining carbon dissolves in the bath
where.it is oxidized with steam and oxygen to yield CO and H2. A limestone
slag floating on the molten iron prevents SOz from entering the off-gas. The
sulfur in the coal dissolves in the molten iron, diffuses to the slag, and
reacts to form calcium sulfide. The slag is continuously withdrawn, desul-
furized to yield elemental sulfur, and returned to the gasifier. Operating
-37-
-------
conditions of the gasifier are about 2600° F and 5 pounds per square inch
absolute (psia) (BO-117, KA-124, LA-176, NA-115, US-109).
Figure 19 illustrates the ATGAS process. The process can be adapted
to make low-Btu gas by using air instead of oxygen and eliminating the CO-
shift and methanation steps. In such a case, the off-gas would go to a power
plant boiler for use rather than being upgraded 'to pipeline quality. The
ATGAS process is one of three processes that the Applied Technology Corpora-
tion is developing on the basis of molten iron-coal gasification.
COAL —
LIMESTONE
STEAM
SLAG TO
STORAGE
Figure 19. Applied Technology Corporation two step gasification system.
-38-
-------
Molten Salt Process
The Kellogg Co. Molten Salt Process is based on the gasification of
coal in a molten sodium carbonate bath with simultaneous injection of steam and
oxygen. The sodium carbonate strongly catalyzes the basic coal-steam reaction
permitting essentially complete gasification of coal at a sufficiently reduced
temperature to allow appreciable methane production but no tar formation. The
molten salt also supplies heat to the coal being gasified. The sulfur in the
coal forms sodium sulfide and reaches an equilibrium level at which point the
sodium sulfide reacts with carbon dioxide and water to regenerate sodium car-
bonate and release sulfur in the form of hydrogen sulfide in the gas phase.
The hydrogen sulfide can then be scrubbed from the raw gas. The gas leaving
the gasifier is processed to recover entrained salt and heat and then further
processed for conversion to high-Btu gas. Ash accumulates in the molten salt
and leaves the gasifier with a bleed stream of salt that is processed to re-
move the ash and to recover sodium carbonate for recycling. The bleed stream
is quenched with water to dissolve sodium carbonate and the coal ash is removed
by filtration. The sodium carbonate solution is carbonated to precipitate
sodium bicarbonate (NaHC03). The bicarbonate is filtered out and calcined
to restore the carbonate salt which is then recycled to the gasifier (BO-117,
BO-145, CO-193, CO-289, KA-124). Figure 20 illustrates the Kellogg Molten
Salt process for high-Btu coal gasification.
Cool
Lock
Hoppers
Steam a
Oxygen
*
T
1
^ Carbonate
(Lock
I Hoppers
r
'
•x
1700-F
1200
psia
*- Synthesis Cos
Steam a
Oxygen
LOO'F Saturated Sodium
Wash Water
Ash Filter
Sodium
Carbonate
Solution
|—"-Vent Gas
Carbonation
Tower
Carbon
Dioxide
Sodium
Carbonate
to Gasifier
Calciner
1003
30psia
Figure 20. Kellogg Molten Salt coal gasification process. (Source: KA-124)
-39-
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Union Carbide Process
This process being developed by Battelle, Chemico, and Union Carbide
is referred to as the Union Carbide Process or as the agglomerating Burner-
Gasification Process. This is a pressurized, two stage, fluidized-bed system
involving coal or char combusion in one fluidized bed, and steam gasification
of coal in a separate fluidized bed. Heat for the carbon-steam reaction is
provided by circulating hot coal-ash agglomerates from the burner to the gasi-
fier. Temperature and velocity are regulated so that fly ash is agglomerated
in a controlled way into free-flowing, inert solid pellets which provide a
moving, direct-contact, heat-transfer medium (CO-208).
Crushed coal and steam enter the lower part of the gasifier. Hot ash
agglomerates from the combustor and enters near the top to provide heat for the
gasification reaction as it descends through the fluidized bed. The bed is
fluidized by steam and gasification products. Part of the ash agglomerated
in the bottom of the gasifier is recycled to the combustor. Char is contin-
uously removed from the top of the gasifier and burned with air in the com-
bustor. Raw product gas from the gasifier passes through heat-recovery,
purification, and upgrading stages (BO-117, CO-208, KA-124).
COGAS Process
The COGAS Process converts coal to gas and oil products by using a
multi-stage, fluidized-bed pyrolysis of coal and the steam reactivity of the
char from the pyrolysis. The pyrolysis step is essentially the COED Process
which produces gas, oil, and char. The incorporation of an additional step
to convert the by-product char to synthesis gas by reaction with steam is
the COGAS Progress (BO-117, SE-112).
A gasification-combustion procedure, used in the char gasification,
involves burning some char with air in a combustor In order to supply the
heat for reactions in the gasifier. Separate pilot plants are testing two
versions of the gasification-combustion step. Pyrolysis gas, stripped of light
hydrocarbons, is processed along with synthesis gas from the char gasification.
For production of high-Btu gas, the COGAS Process consists of the
following eight steps (BL-057):
(1) coal sizing and drying
(2) coal pyrolysis to produce a synthetic crude oil,
light hydrocarbons, a gas containing carbon monoxide
and hydrogen, and a reactive char
(3) gasification of carbon in product char
(4) compression of raw gases to an intermediate pressure
for processing
(5) shift conversion
(6) purification of the combined gases from coal pyrolysis
and char-gasification to remove sulfur-containing com-
pounds and carbon dioxide
(7) catalytic methanation to yield high-Btu gas
(8) compression for pipeline use.
-40-
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EXXON Process
The EXXON Gasification Process is based on the coal-steam reaction in
a fluidized-bed gasifier at 1500-1700°F. Heat for the gasification reactions
is provided by circulating a stream of hot char. Char is withdrawn from the
gasifier, partially burned with air in a char heater, separated from the
resulting flue gas, and returned to the gasifier as a direct-contact, heat
transfer medium (EP-011, SW-023). The process has been tested on a one-half-
ton-per-day unit, but the construction of a 500 ton-per-day gasifier has
been deferred. Smaller scale research and engineering studies are continuing.
GRD Process
The GRD Coal Gasification Process is being developed by the Garrett
Research and Development Company (GRD) to convert coal into pipeline-quality
gas. The process employs an entrained-bed pyrolysis reactor operating at high
temperature and low pressure.
Pulverized coal entering the gasifier contacts steam and hot, recycled
char. The hot char provides the pyrolysis heat (1500-1700°]?) which devola-
tilizes the entrained coal. The process produces a pyrolysis gas which has
a high heating value (600-650 Btu/scf) because of the high direct yield of
hydrocarbons. This gas can then be upgraded to high-Btu gas by shift conver-
sion, purification, and methanation. After separation from the pyrolysis
gas, part of the char is withdrawn as a solid fuel product. The remainder is
partially combusted with air in a combustion unit (gasifier) separated from
the combustion gas, and recycled to the gasifier to provide heat (MC-
098.
Other Processes
Several other processes are also being investigated as possible sources
of high-Btu gas.
Stone and Webster Corporation and Gulf General Atomic Co. are cooperating
in a venture to use nuclear reactors to provide heat for hydrogen generation.
Coal, slurried in a solvent, is treated with hydrogen to dissolve and hydro-
crack it. A pipeline-quality gas is produced without oxygen, steam, or an
additional methanation step.
Columbia University is experimenting with the reaction of steam with
coal carbon in an electric arc at 10,000°C. Proper reaction and quench condi-
tions produce substitute natural gas (SNG) without an additional methanation step.
With the proper upgrading facilities, such conventional processes as
the Koppers-Totzek, Winkler, and Wellman-Galusha processes can be used to
produce high-Btu gas.
Low-Btu Gasification Processes
Low-Btu gas is a CO and Ha rich mixture which is produced from the
reaction of coal with steam and oxygen. If air is used as the source of
oxygen, a low-Btu gas (150-300 Btu/scf) is produced, whereas if pure oxygen
-41-
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is fed to the gasifier, a medium-Btu gas (300-450 Btu/scf) results. Low-Btu
fuel gas is well suited for use in combined cycle power generation facilities,
Once a raw low-Btu gas is produced, it must undergo processing steps
to make it usable as a fuel. First, entrained solids and/or liquids must be
removed by cooling and/or washing. Following cooling and solids-removal,
C02 and/or hydrogen sulfide (H2S) must be removed. In addition to the gas
cleaning equipment just described, facilities must also be provided for the
treatment of liquid waste streams and recovery of ammonia and hydrocarbon by-
products. A typical low-Btu gasification scheme is shown in Figure 21.
COAL
ASH
SULFUR
Figure 21. Typical low-Btu gasification diagram.
The major distinguishing feature of the various low-Btu gasification
processes is the design of the gasification reactor. In this vessel, coal
reacts with oxygen to produce a raw gas rich in CO and H2 which can be
purified and used as a boiler fuel. The difference among the processes
are found in the operating temperatures, pressures and mechanical character-
istics of the gasifier.
A large number of low-and intermediate-Btu gasification processes are
being studied. Many of these are still in the developmental stage. Available
information on the status of various low-Btu gasification processes is summarized
in TABLE 5.
Lurgi Process
The Lurgi gasifier is the same for both high-and low-Btu gasification.
The main differences in the processes are that for low-Btu gasification, air is
substituted for oxygen and upgrading facilities are not used.
-42-
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TABLE 5. LOW-BTU COAL GASIFICATION TECHNOLOGY
PROCESS NAME AND DEVELOPER
Lurgi
Lurgi Mineralotechnik
G.m.b.H.
DEVELOPMENT STATUS
Process widely used to make
synthesis gas and fuel gas.
DEVELOPMENT PLANS
Synthesis gas for SNG
production.
Koppers-Totzek
Koppers-Totzek Co.
Feedstock for ammonia
synthesis.
Upgrading of synthesis
gas to pipeline gas.
Winkler
Davy
Powergas Co.
Synthesis gas production,
commercially proven.
Wellman-Galusha
McDowell Wellman Co.
Commercially proven syn-
thesis gas production,
OJ
i
BOM Producer Gas
U.S. Bureau of Mines
Pilot plant gasifier 42
inches in diameter in
Cooperative efforts with
G.E. and TVA.
U-Gas®
Institute of Gas Technology
Entrained Gasifier
Combustion Engineering Co.
GEGAS
General Electric Co.
HRI Process
Hydrocarbon Research, Inc.
PAMCO Gasification
Bituminous Coal Research, Inc.
Molten Salt Process
Rockwell International Corp./
Atomics-International Division
Unnamed
Westinghouse Electric Corp.
Unnamed
Foster Wheeler Energy Corp.
Unnamed
Babcock and Wilcox Co.
Small pilot plant with 1 ft
diameter reactor.
Preliminary tests completed
Tested at 50 Ib/hr rate.
Concept developed at City
University of New York.
Construction of 100 Ib/hr
development unit.
Tested in 200 Ib/hr pilot
unit at 1 atm.
Construction of 15 tpd
pilot unit.
Tested in experimental
unit.
Design underway for pilot
plant.
Operation of 120 tpd pilot
unit .
Operation of 12 tpd pilot
unit.
Operation of 10 tpd pilot
unit .
Construction of 120
pilot plant.
Construction of 55 tpd pilot
plant and combined cycle
demonstration facility.
Construction of 36 megawatts
gasification combine cycle
pilot plant
Registered Trademark
-------
Koppers-Totzek Process
The Koppers-Totzek gasifier is a single stage, entrained flow, ash
slagging gasifier capable of treating all types of coal. Pulverized coal is
fed to the gasifier with steam and air through coaxial burners at each end of
the gasifier. The reaction temperature at the burner discharge is about
3300°F. At this temperature the components react instantaneously to produce
carbon monoxide, hydrogen, and molten slag. No tars, condensable hydrocar-
bons, or phenols are formed. Part of the coal ash is removed from the bottom
of the gasifier as molten slag. The remaining ash exits with the raw gas
through the top of the gasifier. The gas is water-quenched to solidify en-
trained molten ash, passed through a waste-heat boiler, scrubbed to remove
entrained solids, and purified to remove hydrogen sulfide and carbon dioxide
(BO-117, FA-097, KA-124, RA-150). Figure 22 illustrates the Koppers-Totzek
process.
Steom
end
Oxygen
Approx. 27SO"
Atm.Pressure
n
Goiifier
|
Ash
Figure 22. Koppers-Totzek coal gasification process..
(Source: UN-025)
Winkler Process
The Winkler gasifier is a fluid bed, steam-air gasifier. Crushed
coal is dried and fed by screw conveyors to the gasifier. The coal undergoes
reactions to yield a raw gas rich in CO and H2. The gasifier reaction tem-
perature is 1500-1850°F and the pressure is about atmospheric. Thirty percent
of the coal ash is removed from the bottom of the gasifier while about 70
percent is carried overhead with the raw gas. Above the fluid bed, additional
steam and air are injected to react with the remaining carbon. The resultant
gas is processed and utilized. Air, rather than oxygen, is used for low-Btu
gas applications (BA-329, BO-117, DA-108, RA-150). Figure 23 illustrates the
Winkler process.
Wellman-Galusha Process
The Wellman-Galusha gasifier (Figure 24) is a moving bed, steam-air
gasifier. Crushed coal is fed to the gasifier through a lock hopper and
distributed over the coal bed by a rotating arm. The coal bed moves downward
-44-
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Winkler
Fluidized E
Gosifier
Crushed
Cool I
f
v
Jed
s*
""I
Soot
1500 -"
I800°F
1 Atm.
\ ^
— Woler
x
/ /
/
Steam
Steam
\
•AA^
i
•AA/-
-AA/-
High
•- Supe
Slea
*- Woler
•*— Air or C
_,
Pressure
rheoted
m
2
350° F
»- Synthesis
Gas
Cyclone
Ash
Process
Sieom
Figure 23. Winkler coal gasification process. (Source: KA-124)
ASH
Figure 24. Wellman-Galusha gasifier process. (Source: ZA-042)
through the gasification zone, forming char and some methane. As the resulting
char leaves the gasification zone and enters the combustion zone, it contacts
steam and oxygen from air injected at the bottom of the gasifier and forms
CO and Ha. A revolving eccentric grate at the bottom of the gasifier allows
for bed support and ash removal. A rotating agitator arm, located just below
the coal bed, is used when handling slightly caking coals. Strongly caking
coals must be pretreated to destroy their caking tendencies before gasifica-
tion can be accomplished. The
low-Btu gas flows countercurrently to the
coal bed and is removed from the top of the gasifier at approximately 1250°F.
The gasifier operates at essentially atmospheric pressure (BA-260, RA-150).
-45-
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(TV,
U-GAS^' Process
The U-GA? process, developed by the Institute of Gas Technology,
uses an ash-agglomerating, fluidized-bed gasifier to produce a clean gas
with a heating value of about 140 Btu/scf.
Crushed coal is fed to the gasifier from a lock hopper. Coals with
caking tendencies are first pretreated with air at 800° F in a separate ves-
sel. Partial oxidation of the coal destroys its caking properties, and the
pretreated coal and gas flow, into the fluid-bed gasifier operating at 35
psi and 1900° F. Air and steam, injected into the bottom of the gasifier,
react with the coal to form the synthesis gas. The ash agglomerates, settles
to the bottom, and is removed through lock hoppers. Gases produced in the
pretreater and gasifier are combined and passed through cyclones where coal
fines are removed and returned to the gasifier. The raw gases then pass
through a heat recovery system, a sulfur removal system, and a power recovery
turbine before being used as a low-Btu gas (BO-117, KA-124, LO-115). The
U-GAS^ process is shown in Figure 25.
2nd Stage
Dust
Removal
Presentment
for Bituminous
Cools
Steam
Generation
Air 8.
Steam
^Synthesis
Gas
Figure 25. U
-GAS®
Ash Lock
Hopper
(Water-Filled)
process. (Source: KA-124)
Registered trademark
-46-
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GEGAS Process
The General Electric Co. (GEGAS) Process employs a fixed bed gasifier.
A unique feature of the process is the injection of coal into the high-pressure
gasifier by extrusion. This procedure allows coal fines to be compacted with
a tar binder into a solid bar which is injected into the gasifier and chopped
into chunks under pressure. The extrusion process eliminates gas losses
associated with lock hoppers, allows the gasifier to operate at high pres-
sures, and solves some of the problems caused by coal fines. Another unique
feature of the pro.cess is the use of liquid membranes for acid gas removal
(BU-173, GE-069).
Westinghouse Process
The Westinghouse Process is a two-stage, fluidized-bed process. The
fluidized-bed subsystems are the devolatilizer/desulfurizer and the gasifer/
agglomerator. Air, steam, and coal react in the gasification process and
sulfur is removed from the high temperature gases with a limestone sorbent
(Figure 26).
Dolomite
Low Btu Gas
Ash
Figure 26. Westinghouse fluidized-bed coal gasification process,
(Source: UN-025)
Crushed coal is fed into the bottom of the devolatilizer/desulfurizer
at 1600-1800° F. Devolatilization, desulfurization, and partial hydrogasifica-
tion produce gas and char. Sulfur is removed by the reaction of limestone or
dolomite with hydrogen sulfide in the fuel gases to form calcium sulfide. The
char is withdrawn and transferred to the gasifier/agglomerator where the char
is gasified with air and steam at 2100° F. Ash agglomerates at this temperature
and is removed from the system. Reactions in this vessel provide the process
heat. The hot gases produced in the gasifier/agglomerator are introduced
into the devolatilizer/desulfurizer. The raw product gas from the devolatilizer/
desulfurizer passes through a cyclone to remove fines (AR-055, BO-117, HO-238).
-47-
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U.S. Bureau of Mines Stirred Fixed-Bed Process
This U.S. Bureau of Mines Process employs a fixed-bed gasifier that
has a stirrer mounted in the center (Figure 27). The stirrer both rotates and
moves vertically to prevent any caking. Crushed coal is fed into the top of
the reactor and falls onto a rotating grate. Steam and air enter below the
grate and ash is removed at the bottom. The stirred fixed bed gasifier is
essentially a modified Lurgi gasifier that allows strongly caking coals to
be used (KA-124).
n ^
•p Agitator Drive
Grate Drive
Steam
Rupture Disk
Figure 27. U.S. Bureau of Mines gasifier. (Source: KA-124)
Other Processes
Hydrocarbon Research, Inc. is developing a conical, fluidized-bed
gasifier. This process uses a high, superficial gas velocity which allows
-48-
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the gasifier to operate at temperatures above the ash softening point (2200-
2300° F).
In addition to BI-GAS, Bituminous Coal Research, Inc. is also developing
a multiple fluidized-bed gasification process that yields a gas stream free of
liquids. The Btu content of the product gas depends on whether air or oxygen
is fed into the system with the steam and coal.
Combustion Engineering Company is developing a process in which pul-
verized coal is entrained in air and steam for feeding to a gasifier which
will operate at 1 to 10 atmospheres. The gasifier is comparable to a pulverized
coal-fired boiler with similar fuel injection, gas flow patterns, and heat ex-
change surfaces. The gasifier, however, has a two-level firing arrangement in
which recycled char is fired through combustor nozzles of the lower zone and
in which fresh coal, steam, and air are injected through reductor nozzles.
Gasification occurs in the upper zone (KA-124).
The Atomics International Division of Rockwell International Company
developed a process in which coal contacts air but no steam in a molten sodium
carbonate bath at about 1800° F and 5 to 10 atmospheres. The basis of the
process is oxidation of carbon to carbon monoxide and partial pyrolysis and
distillation of volatile material. Sulfur and ash are removed via the molten
salt.
The Kellogg Company has a molten salt process for producing low-Btu
.gas. The gasification step is similar to that for high-Btu gas but the low-
Btu process uses air instead of oxygen and requires no steam.
Submerged Coal Combustion and PATGAS are two processes developed by
the Applied Technology Corporation. Both processes use a gasifier with a
molten iron bath. PATGAS is similar to ATGAS but uses air instead of oxygen
and requires no shift conversion or methanation. The Submerged Coal Combus-
tion process gasifies coal with air and does not use steam.
Foster Wheeler Energy Corporation is designing and developing a two-
stage, air blown, pressurized, entrained flow, slagging gasifier. The gasi-
fier operating at 1800° F will produce low-Btu gas for use in a combined-cycle
power generating system.
Under the proper operating conditions, low-Btu or intermediate-Btu
coal gasification can be obtained from other previously described processes
such as BI-GAS, Synthane, HYGAS, Garrett pyrolysis, and Columbia University
processes.
COAL LIQUEFACTION
Coal liquefaction is the conversion of coal into clean, synthetic hydro-
carbon liquids.
Liquefaction processes may be separated into two basic groups: (1)
processes relying solely on heat to crack the coal (carbonization processes)
and (2) processes providing hydrogen in some form to facilitate the dissolution
-49-
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of the coal. The appeal of carbonization processes is the apparent sim-
plicity involved with just heating the coal. The advantage of adding
hydrogen is that the amount of liquid product is not limited by the low
hydrogen content of the coal.
Processes utilizing hydrogen can be classified according to how the
hydrogen is added. Three types of coal liquefaction utilizing hydrogen are:
(1) direct hydrogenation processes, (2) solvent hydrogenation processes, and
(3) gasification-synthesis processes.
Common Technology
Much common technology is used in the different liquefaction processes.
Most coal liquefaction processes differ in the reaction or dissolution step
where new technology is involved. Apart from the reaction step, the opera-
tions associated with coal liquefaction are accomplished with existing tech-
nology. Coal processing prior to the reaction consists of essentially the
grinding and drying procedures used in the coal industry, whereas gas/liquid
processing (after reaction) is accomplished with conventional petroleum
refining techniques. The general processing steps are (1) coal preparation,
(2) reaction and solid separation, (3) fractionation, (4) gas recovery and
treating, (5) sulfur recovery, (6) naphtha or light oil hydrotreating, and
(7) heavy oil hydrotreating. In addition to these main processing steps, a
liquefaction plant will have many auxiliary operations, including power genera-
tion, ammonia separation, and water treatment facilities.
Steps in coal liquefaction processes where common processing is
utilized are (1) coal preparation, (2) gas-liquid separation, (3) acid gas
removal and sulfur recovery, (4) liquid product separation, and (5) product
desulfurization.
In addition to these similarities, processes which add molecular hydro-
gen (direct hydrogenation and solvent hydrogenation) have the same basic steps
throughout the dissolution process. Areas of similarity among these processes
are as follows:
(1) coal preparation
(2) slurrying coal
(3) preheat and dissolution
(4) cooling and removal of gases
(5) pressure let-down and removal of vapors
(6) separation of solids
(7) gasification of char
(8) hydrotreating filtrate
(9) separation of products and solvent for recycle.
-50-
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The gasifier in these processes serves the two-fold purpose of complete
utilization of solids, and hydrogen production for the dissolution step.
Areas in which problems exist for coal liquefaction processes are as
follows: (1) thermal efficiency, (2) water management, (3) solids separation,
(4) solvent-to-coal ratio, (5) solvent generation, (6) preheating, (7) pressure
let-down, and (8) hydrogen production.
Liquefaction Processes
TABLE 6 lists and summarizes- the level of development of various lique-
faction processes.
The main differences in coal liquefaction occur in the dissolution or
reaction step. Due to the various conversion processes which may be utilized
(direct hydrogenation, solvent hydrogenation, gasification-synthesis, and
carbonization), the reactors may differ considerably. Reactors employed in
liquefaction processes include open vessels, stirred vessels, fixed beds, and
fluidized beds. Operating conditions change according to reaction mechanisms
and reactor types. Solid handling facilities and miscellaneous support
facilities also depend upon the reaction procedure employed.
The following descriptions of liquefaction processes are divided into
hydrogenation and pyrolysis processes.
Hydrogenation Processes
Direct hydrogenation processes feed a stream containing molecular hydro-
gen into the reactor with a coal slurry.
Solvent hydrogenation, another kind of coal liquefaction process,
physically dissolves coal in a recycled hydrocarbon solvent. Coal dissolution
allows removal of insoluble ash and insoluble sulfur from the extract. Any
hydrogenation that occurs during extraction also converts soluble organic
sulfur to a removable form. The coal extract is processed to remove ash,
sulfur, and other impurities; to recover solvent; and possibly to further
hydrogenate and purify the liquid product.
Some overlap can exist between direct hydrogenation and solvent hydro-
genation processes since direct hydrogenation processes use a recycled solvent
to slurry the coal to the reactor.
Gasification-synthesis processes produce liquid fuels by first gasifying
the coal and then converting the gas to a liquid by a Fischer-Tropsch synthesis.
The hydrogen is introduced into the system as steam to the gasifier.
•/N
Process
The H-Coal Process, jointly developed through the efforts of Hydro-
carbon Research, Inc. (HRI) and the Office of Coal Research (OCR), is carried
out in an ebullated bed reactor in the presence of hydrogen and a cobalt molyb-
date catalyst. The ebullated bed reactor is the heart of the process. The
Registered Trademark
-51-
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TABLE 6. COAL LIQUEFACTION TECHNOLOGY
I
Ul
Process Name & Developer
Development Status
Development Plans
Solvent Refined Coal (SRC)
Pittsburgh and Midway Coal
Mining Co.
Tested on 6 tpd pilot plant.
Construction and operation
50 tpd pilot plant.
Consol Synthetic Fuel Process
Consolidation Coal Company
Tested on 20 tpd pilot plant.
Char Oil Energy Development
(COED)
H-CoalK>
Hydrocarbon Research, Inc.
Synthoil
U.S. Bureau of Mines
Gulf Catalytic Coal Liquids
-Gulf Research & Development
Garrett Flash Pyrolysis Process
Garrett Research & Develop-
ment Co.
Lurgi-Ruhrgas
Lurgi-Ruhrgas
UOP
Universal Oil Products Co.
EXXON Solvent Donor Process
EXXON Corporation
TOSCOAL
The Oil Shale Corporation
Zinc Halide Process
Conoco
Clean Coke Process
U.S. Steel Corporation
Tested on 36 tpd pilot plant.
Tested on 3 tpd pilot plant.
Tested on % tpd pilot plant.
Tested on 120 Ib/day bench
scale.
Tested on 3% tpd pilot plant.
Operated 1600 tpd unit.
Tested on small scale.
1% tpd pilot plant.
Tested on 25 tpd pilot plant.
Certain process components
tested on % tpd scale.
Word directed toward utili-
zation of char; pilot plant
to test COGAS process for
gasification of COED char.
Construction and operation
of 600 tpd pilot plant.
Construction and operation
of 8 tpd pilot plant.
Construction and operation
of 1 tpd pilot plant.
300 tpd demonstration plant
Bench scale testing of 100
Ib/hr process development
unit,
Construction and operation
of 10 tpd pilot plant.
Registered Trademark
-------
fluidized bed concept allows a catalyst to be used without the plugging
problems inherent with a fixed bed reactor (JO-135).
A flow diagram for the H-Coal Process is shown in Figure 28.
Ground coal is slurried with a recycled solvent, mixed with hydrogen, and
routed through a preheater to the reactor. Upward passage of the coal and
reaction products maintains the catalyst in a fluidized state. Unreacted
solids are removed at the top of the reactor along with the liquid product
but the coarser catalyst is retained in the reactor. The catalyst can be
added and withdrawn continuously in order to maintain catalytic activity.
Turbulence is insured by an internal slurry recycle. The reactor operation
at 800-900° F and at 1500-3000 psig. Solids separation is accomplished by
hydrocyclones followed by a rotary drum filter. Conversion for the bituminous
coal is at 89.3 weight percent (wt.%) and conversion for the subbituminous
coal is at 81.4 wt.%. Products typically would be a naphtha and a fuel oil
(JO-135, KA-124).
HYDROGEN
COAL
1
HYDROGEN RECYCLE
HYDROCARBON GASES
RECYCLE GAS
PURIFICATION
LIGHT DISTILLATE
REACTOR
V
HOI
REC
V
OIL
YCLE
VATE
rS
>>^-X
ATMOSPHERIC
DISTILLATION
PREHEATER
HEAVY
DISTILLATE
HYDROCLONE
VACUUM
DISTILLATION
BOTTOMS SLURRY
(R)
Figure 28. H-Coal^" Process for fuel oil production-
devolatilization plant. (Source: ST-310 )
®
Registered Trademark
-53-
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Synthoil
The Synthoil Process pilot plant, operated by the U.S. Bureau of Mines,
employs a direct hydrogenation process. A slurry of coal and recycle solvent
is mixed with hydrogen, preheated, and injected into the reactor. The reactor
contains a fixed bed packed with pellets of a cobalt molybdate catalyst. The
reactor is normally operated at 840° F and 2000-4000 pounds per square inch gage
(psig) . Over 90% of the coal is dissolved. The turbulent flow of hydrogen
and short residence time prevents the coal from excessive plugging of the
catalyst bed. The coal is converted to a heavy hydrocarbon liquid and the
sulfur is eliminated as hydrogen sulfide. The product liquids, solids, and
gases are separated. The solids are sent to a pyrolizer which yields more
fuel oil and a carbonaceous residue. This residue is fed to a steam-oxygen
gasifier to produce make-up hydrogen for the process. The gas stream is
purified to remove ammonia, hydrogen sulfide, water, and gaseous hydrocarbons.
The purified hydrogen is combined with fresh hydrogen and returned to the
reactor (AK-011, AK-014 , YA-040) . A flow diagram of the Synthoil Process is
shown in Figure 29. The degree of hydrogenation determines the product
characteristics and uses.
Rich Recycle Gas
High- Pressure
Oil- Gas
Separation
Gas
Cleanup
H2S
Fixed-Bed
Catalytic
Reactor
850"
2,000-
4,000 psi
Recycle Oil
Figure 29, Synthoil coal liquefaction process. (Source: UN-025)
Gulf Catalytic Coal Liquefaction
Another direct hydrogen process is Gulf Catalytic Coal Liquefaction,
developed by Gulf Research and Development Company. The process uses a fixed-
bed, catalytic reactor designed to avoid plugging. Ground coal is slurried
with a recycle solvent, is mixed with hydrogen, and then passes through a
preheater to the reactor. Reactor conditions are 800-900° F and 3000 psig.
Approximately 91% of the coal is dissolved. The product goes to a gas-
liquid separator where hydrogen is recovered for recycling. Solid separation
is achieved with hydrocyclones followed by rotary filters. Approximately 75%
-54-
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of the product is a heavy fuel oil with the remaining 28% being equivalent
to a distillate fuel cut. A flow diagram of the Gulf process is shown in
Figure 30. This process routes the filter cake to a coker rather than to a
gasifier. Hydrogen production is
reformer (GU-049, KA-124, MA-3.98,
accomplished with a steam-hydrocarbon
MC-112, RA-150).
Heat Recovery
\ Exchanger
"S
AI
4-
/3000\
(pSgJ-
FireH
^->
Fixed
Bed
Catalytic
Reactor
Let-down
& Flash
System
Preheater
Y
Water
Reforming
H2
Hydrocarbons
Ammonia
Sulfur
Coke
Product
6 Mineral
Matter
Hydro-
gen
Recycle
C Distillation J
Liquid Product
Figure 30. Gulf catalytic coal liquids process. (Source: KA-124 )
EXXON Solvent Donor
The EXXON Solvent Donor Process employs a catalyst and donor solvent.
Crushed coal is slurried with recycle solvent, preheated to 800° F, and
pumped into the liquefaction reactor (2000 psig). Preheated hydrogen is
also added to the reactor. The product is then separated by distillation
into gas, naphtha, recycled solvent, distillate, and unconverted coal and
ash. The recycled solvent is hydrogenated catalytically and slurried with
fresh coal. The raw liquid product is upgraded by hydrogenation. The
heavy bottoms and solids go to a gasifier for hydrogen production (SW-023).
UOP Coal Liquefaction
Universal Oil Products Company is developing a coal liquefaction
process that will yield four barrels of liquid product per ton of high sulfur
coal. Pulverized coal is mixed with a solvent and hydrogen and is piped to a
reactor operating at high temperatures and pressures. Ash is separated and
the resulting hydrocarbon stream is catalytically hydrotreated. Usable gas
by-products including light hydrocarbons are also formed.
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Coalcon
Coalcon Company is a joint venture of Union Carbide and Chemico to
build a coal-to-clean-fuels demonstration plant. The plant is designed to use
a hydrocarbonization process to convert 2,600 tons of coal per day into 3,990
barrels of liquid product and 22 million cubic feet of pipeline-quality gas.
Pulverized coal is preheated and then hydrogenated in a hydrocarbonization
vessel at modest pressure. The products are cooled and separated. The gases
are purified to yield methane and other light hydrocarbon fuels. The char is
gasified with oxygen in an agglomerating bed unit to produce make-up hydrogen.
Solvent Refined Coal
Pittsburgh and Midway Coal Mining Company's Solvent Refined Coal Process
(SRC) was originally developed to produce a de-ashed and desulfurized solid
for power plant fuel. Recent work has modified the process to yield liquid
products.
Coal is pulverized and mixed with a recycled solvent similar to anthra-
cene oil. The slurry, typically 2 to 3 parts solvent with 1 part by weight
coal, is mixed with hydrogen and routed to the reactor. Reactor conditions
are approximately 850° F and 1050 psig. The SRC process differs from the other
direct hydrogenation processes in that no catalyst is employed in the reactor.
The reactor consists of four vertical tubes in series with upflow of both
liquid and gas. Initially, the solvent is absorbed by the coal resulting in
a significant increase in slurry viscosity. As the residence time of the coal
increases, dissolution begins to occur. Over 90% of the coal is dissolved.
Solid separation is accomplished by rotary drum filters. A flow diagram of
the SRC process is shown in Figure 31. Liquid products consist of a naphtha,
fuel oil, and a residual oil (RA-150).
Consol Synthetic Fuel
The Consol Synthetic Fuel (CSF) process uses a coal liquefaction
scheme designed by the Consolidation Coal Company. It is a solvent extrac-
tion process combined with a catalytic hydrogenation step (UN-025). Figure
32 is a diagram of the CSF process.
The Consol process employs a hydrogen donor solvent to dissolve the
coal. Feed coal is dried and crushed in a coal preparation step, slurried
with the recycled solvent, and fed through the preheater to the reactor.
Only solvents capable of transferring hydrogen are effective for dissolution
of the coal. The reaction takes place in a stirred vessel. Since turbulence
cannot be provided by the H2 gas stream, the agitation is needed to insure the
presence of the hydrogen donor solvent whenever a coal molecule is cracked.
The reactor operating conditions are 700-750° F and 400 psig. Approximately
80% of the coal is dissolved (KA-124).
Vapors produced in a stirred extraction vessel are sent to a fractiona-
tion section. Unreacted coal and the liquid product are separated in hydrocy-
clones. Liquid passes to the fractionation section and solids to a carboni-
zation unit. After removal of light ends and solids from the reactor effluent
the liquid stream must be hydrotreated. The hydrotreating step not only
-56-
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Distillate
Naptha
Hydrogen (from Lurgi Char-Gosifier)
Hydrotreatment,
(800°F 3000
psig)S Distillation
Fuel Oil
Figure 31. Solvent refined coal process. (Source: UN-025)
Hydrogen
Recycled Gas
Figure 32. Consol synthetic fuel process, (Source: UN-025)
-57-
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desulfurizes what will be the product streams but, by partial hydrogenation,
regenerates the recycle solvent. Hydrogenation is achieved in a fixed bed
reactor containing cobalt molybdate catalyst, operating at 775-850° F and at
3000-4200 psig. Hydrogen for this operation is produced by partial oxidation
of char from the carbonization unit. The hydrotreater effluent is separated
by distillation into recycled solvent and the product streams of gas, naphtha,
and fuel oil (BO-117, KA-124, PH-025, RA-150).
Costeam
The Costeam Process is based on the reaction of coal with steam and
carbon monoxide or synthesis gas to produce oil without the aid of a catalyst.
The objective is to develop a liquefaction process for lignite.
Figure 33 is a flow diagram for the Costeam Process. Pulverized lignite
is slurried with a process-derived recycled oil. The slurry feed, along with
carbon monoxide or synthesis gas, is fed into the reactor operating at 4000
psi and 800° F. Water contained in the lignite provides the source of hydro-
gen for the liquefaction through the water-gas shift reaction in which carbon
monoxide and water react to form hydrogen and carbon dioxide. The raw product
is sent to a product separator where gas is separated from the liquid-solid
mixture. This mixture is fed. to a centrifuge or filter for solids removal.
The final product is a low-sulfur, low-ash fuel oil (HA-260).
LIGNITE.
RECYCLE
OIL
1
f
FEED
TANK
SYNTHESIS
GAS
i
i. ^
i
REACTOR
800° F
4000 psi
PRODUCT
CAS
f
|
PRODUCT
RECEIVER
^ CENTRIFUGE
4
SOLIDS
OIL
Figure 33. The Costeam Process.
Zinc Halide
Conoco is developing a coal liquefaction process based on catalytic
hydrocracking with a zinc chloride catalyst. The process is designed to
produce a 90 octane (lead-free) gasoline from coal. Early tests have been
successful, but catalyst deactivation and loss are major problems.
Fischer-Tropsch
The Fischer-Tropsch process is the basis for a gasification-synthesis
-58-
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system. The process is a catalytic conversion which produces hydrocarbon
liquids from coal-derived, intermediate-Btu synthesis gas. A Fischer-Tropsch
liquefaction diagram is shown in Figure 34. Coal.liquefaction in a Fischer-
Tropsch plant is divided into (1) coal preparation, (2) coal gasification,
(3) raw gas quenching and purification, (4) Fischer-Tropsch synthesis and
products separation, (5) catalytic conversion of tail gas to produce additional
methane, (6) clean-up section for the final removal of residual carbon dioxide
and water from by-product SNG.
Coal
Liquid
Products
Oxygen—-»|Gasificotion}—»
Ash
Tail Gas
Liquid
Products
Figure 34. Fischer-Tropsch coal liquefaction process. (Source: UN-025)
The gasification-synthesis system is the only procedure currently being
used to produce liquid fuels from coal on a commercial scale. A 10,000 ton
per day commercial plant was built by the South African Coal, Oil and Gas
Corporation (SASOL) in the Republic of South Africa.
In the SASOL process, the coal is gasified in a Lurgi reactor with steam
and oxygen at approximately 1500° F and 380 psi. A gas consisting primarily
of hydrogen, carbon monoxide, carbon dioxide, and methane is produced. The
gas is purified by a methanol wash for removal of sulfur compounds and carbon
dioxide. The purified gas is then reformed with high purity oxygen and steam
over a nickel catalyst to reduce the methane content. The reforming reactions
are as follows :
CH2 + H20 -*• CO + 2H2
&2 "*• CO + 2H2
The carbon monoxide and the hydrogen from the reformer are then converted to
liquid products by means of a Fischer-Tropsch synthesis. A simplified overall
reaction may be expressed as follows :
SCO + 17 H2 ->- C8Hi8 4- 8H20
Two types of reactors are used in the SASOL plant, a German "arge" unit and
the American Kellogg Process. The arge process is a fixed bed process which
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primarily yields heavy fuel oils and diesel oils. The Kellogg process is a
fluidized bed process which produces lower boiling materials such as LPG,
gasoline and furnace oils. The Fischer-Tropseh synthesis takes place at
600 F and 350 psi over an iron catalyst. The reformer effluent gas is
split and routed through both Fischer-Tropseh processes to produce a full
range of liquid products (HO-207, RA-150).
Other Hydrogenation Research
In addition to the processes described, several research projects on
liquefaction are currently underway. These projects are based upon hydro-
genation processes. The Colorado School of Mines is determining the effects
of process variables on the removal of sulfur from coal by treatment with
hydrogen (GA-105). The University of Utah^s studying intermediate coal
hydrogenation processes in which tertralin solvent is used in lignite hydro-
genation/extraction. The University of North Dakota is conducting research
on deriving premium fuels from lignite. Various projects on solvent refining
of coal are underway at the University of Kentucky, the University of Michigan,
and Auburn University.
Carbonization Processes
Carbonization refers to the liquefaction of coal by pyrolysis. Pyrolysis
is the transformation of a compound into another substance or substances by
heat alone. Coal is simply heated in reactors to produce volatile hydrocar-
bons or char residue. The hydrocarbons are recovered as process gas and
liquid oils while char remains as a by-product of the process. The apparent
simplicity of carbonization has always intrigued process developers. Unfor-
tunately, several problems exist which prevent carbonization from being a
matter of simply heating the coal. These problem areas are (1) residence
time in the reactor, (2) caking coals, and (3) heat requirements.
COED
The Char Oil Energy Development Process (COED) is based on multi-stage
fluidized-bed coal pyrolysis and converts coal into a synthetic crude oil,
gas, and char. The gas can be used as a fuel or it can be processed for
conversion to hydrogen. The char can also be burned as a fuel or gasified.
The COED process was developed by FMC Corporation to minimize agglomera-
tion by heating coal in stages. It uses four fluidized-bed reactors or heat-
ing stages, each operating at a successively higher temperature. A flow dia-
gram is shown in Figure 35.
In the first stage the coal is dried and heated to approximately 600° F
with steam and combustion gases. This stage allows the softening point of the
coal to be increased. The coal is subsequently fed to the second reactor where
it is heated to about 850° F by recycle char and gas from the third stage. The
overhead gases from the second stage contain the product gases and liquids.
This overhead is scrubbed and routed to distillation for product recovery.
Registered Trademark
-60-
-------
Coal
Flue Gasj
1000° F
Steam
Oxygen
Figure 35. COED coal liquefaction process. (Source: UN-025)
Meanwhile, the char from the second stage is routed to the third reactor.
The char is heated to approximately 1000° F by a combination of oxygen and
hot gases from stage four. The char from stage three is routed to the fourth
and final stage where it is heated to 1600° F with oxygen. The last stage
produces hydrogen which is needed to hydrotreat the product tar. Synthesis
crude oil produced from the COED process has a very high viscosity and must
be hydrotreated rather severely to allow the oil to be pumped (BO-117, KA-124,
RA-150, ZA-042).
U.S. Bureau of Mines Entrained Bed
The U.S. Bureau of Mines Entrained Bed Process avoids many of the problems
associated with carbonization processes by pneumatically injecting coal into a
reactor with air. The gas velocity is sufficiently high so that the coal moves
up the reactor in plug flow. Short residence time provides high liquid yields.
Agglomeration is avoided by contacting the coal with air during the carboniza-
tion step which partially oxidizes the surface of the coal particles. Unfor-
tunately, the off-gases from this process are so diluted with nitrogen that
they cannot be used for pipeline gas (RA-150).
Lurgi-Ruhrgas
The Lurgi-Ruhrgas Process uses a mechanical mixer to intimately con-
tact coal and recycled hot char. The hot char supplies the heat for reaction.
Agglomeration is no longer a problem since not only does the char act as a
diluent, but the mixer also helps break up large particles. The liquid yield
is fairly high since the residence time in the mixer is only a few seconds.
-61-
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Product vapors leave overhead. Char from the mixer is superheated for recycling
by reacting it with air in a. transport reactor (RA-150).
Garrett Flash Pyrolysis
i
Garrett Research and Development Company is developing a flash pyrolysis
coal liquefaction process that uses an entrained bed reactor. The process is
based on partial gasification in which the direct yield of methane and other
hydrocarbons is obtained by rapid coal pyrolysis. Pulverized coal is conveyed
by recycled gas to the entrained bed reactor which is heated by recycled char
from a char heater and maintained at 1100° F. Reactor effluent passes through
cyclones to separate the char from the gas. Some of the char is cooled as a
by-product. The remaining char goes to a char heater where some is burned to
reheat the char to approximately 1400° F for recycling in the reactor. The
gas stream is cooled and the tar (liquids) separated. The gas is separated
into three streams. One stream is used to entrain the coal fed to the reactor.
Another stream is routed to the product after acid gas is removed. The remain-
ing gas is used in the production of hydrogen for hydrotreating the process tar.
At the hydrotreater the tar is upgraded to obtain a synthetic crude oil (RA-150).
TOSCOAL
_ The Oil Shale Company (TOSCO) has investigated the application of its
oil shale retorting technology to the low-temperature carbonization of coal.
This application to processing coal is designated the TOSCOAL process. The basic
feature is that the required heat is provided b^ hot ceramic balls. The pro-
cess is shown in Figure 36. Crushed coal is preheated with hot flue gas and
H2S
Coal
Air and
Fuel
Figure 36. TOSCOAL process. (Source: UN-025)
-62-
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is then transferred to a rotating pyrolysis drum where it is heated to the
carbonization temperature by contact with hot ceramic balls. A trommel screen
is used to separate the ceramic balls from the char product. The balls are
conveyed to a heater and recycled. With about 50% of the weight of the raw
coal feed and about 80% of the raw coal heating value, the char can be used
as a fuel. Pyrolysis vapors are condensed and liquid products are fraction
ated into gas oil, naphtha and residuum. Uncondensed gas is used as a fuel
in the ball heater (BO-117, CA-215, KA-124).
OIL SHALE TECHNOLOGY
Oil Shale Extraction
Oil shale mining procedures consist of the same techniques used in
coal mining. The main differences between the two industries result from
the massive solids handling problems associated with oil shale extraction.
Approximately 73,700 tons per day of raw oil shale containing 30 gallons of
oil per ton of shale must be extracted to support a 50,000 barrels-per-day
refinery. Significant differences in the mining techniques also arise be-
cause oil shale deposits are often much thicker than coal seams and oil shale
is considerably harder than coal.
Oil shale production methods include underground (room and pillar)
mining, surface mining, and in-situ oil shale processing. In-situ methods
will be discussed in the processing section. Depending upon the physical
characteristics at the particular oil shale site, oil shale may be mined by
either surface or underground methods. Most actual experience involves under-
ground mining which is more universally applicable to the various oil shale
deposits than surface mining.
Underground Mining
Room and pillar mining is the most efficient method for mining oil shale
underground. The oil shale deposit is entered via a tunnel dug into the side
of a valley where an outcrop appears. Pillars of ore are left in place at
appropriate intervals within the mine to provide roof support. Due to the
large amount of shale that must be extracted in order to produce a significant
amount of oil, room and pillar shale mining is more like an underground quar-
rying operation. A typical raw shale bed is 40 feet thick with a density of
90 pound/foot3 (US-093). Underground extraction is estimated to be capable
of removing approximately 65% of the shale from a typical mine (HI-083).
Extraction is accomplished by drilling and blasting the shale. The
broken shale is loaded onto diesel trucks and transported to a portable
crusher. Crusher discharge is conveyed to underground storage bins. From
the storage bin, shale is transported to secondary crushers on the surface.
Surface Mining
Surface mining consists of removal of the overburden followed by mining
of the underlying oil shale in a quarry-like operation. Factors affecting the
suitability of surface mining are the ratio of the overburden to the shale to
be mined and the availability of a disposal area for the overburden. In com-
-63-
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parison with underground mining, surface mining is capable of extraction at
a lower cost, requires less manpower (HI-083), and is inherently safer. Un-
fortunately, potential sites for surface mining are limited, and there is a
high land impact since all of the spent shale and solid waste must be handled
on the surface.
Overburden at potential surface mining sites ranges from 100 feet to
800 feet in depth, averaging approximately 450 feet. Due to the required mine
depth, several bench levels must be provided to develop sufficient working
faces to meet production rates. An average mine slope of 45° with a working
slope of 35° is typical (US-093). Overburden and shale are extracted by
drilling and blasting. Blasted raw shale is hauled by trucks to primary
crushers in the pit. Shale from the crusher is removed from the mine by con-
veyor to secondary crushing and screening facilities. The secondary crushing
and screening facilities may be located at the upgrading plant site. Major
processing steps associated with a surface mining operation are shown in
Figure 37.
WATER FOR
DUST CONTROL
MINE
DRAINAGE
PRODUCT
SHALE
SPENT
SHALE
Figure 37. Steps involved in oil shale surface mining.
Sizing Operations
Sizing operations which may be performed on raw shale include primary,
secondary, and tertiary crushing, screening, and briquetting. The amount of
sizing required depends upon the specific retorting process being used. Re-
torts that rely on solids-to-solids heat transfer require a smaller size
feed than retorts relying on gas-to-solids heat transfer. The TOSCO II (The
Oil Shale Company) retort requires shale ground to less than 0.5 inches while
-64-
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Union and Gas Combustion Company retorts can accommodate ore up to 3.5 inches.
Operations which may potentially be employed in a shale sizing facility are
shown in Figure 38.
Primary crushing
| - 1 Vibritory l«d<>
N. ^x^Pnmjiy cruiMr Secondary crushing
Tertiary crushing
Vibntonr i««
-------
hydrocarbon (shale oil). This heating step or retorting process is a basic
requirement of all shale oil processes. The various oil shale processes are
characterized by the manner in which the shale is retorted and the mechanism
by which the necessary heat is supplied. The second processing stage is the
upgrading of the shale oil for transportation and use. The upgrading is
accomplished with conventional petroleum refining techniques and requires
essentially the same facilities for all-shale oil processes. Figure 39 is
a flow diagram for a typical shale oil process.
TO PLANT
FUEL
RAW
SHALE
SULFUR
HYDROGEN
NAPHTHA
SPENT
SHALE
•*» GAS OIL
TO GAS
TREATING
COKE
TO GAS
TREATING
TO PLANT
FUEL
Figure 39. Typical shale oil process.
Oil Shale Retorting
The retorting step is the heart of the shale oil process. Most of the
differences that exist between processes are a result of the retorting pro-
cedure. The first distinction of the processes depends on whether the retort-
ing is accomplished on the surface or underground (in-situ). Surface processes
are more advanced and are nearing commercialization while in-situ processes
-66-
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are still in the developmental stage. Within these two broad categories, shale
oil processes can be further distinguished by retorting procedures. Basic re-
torting methods are shown in Figure 40.
SURFACE
RETORTING
GAS-SOLID
HEAT TRANSFER
INTERNAL
GAS COMBUSTION
OIL SHALE
RETORTING
IN SITU
RETORTING
SOLID-SOLID
HEAT TRANSFER
EXTERNAL
HEAT GENERATION
Gas Combustion
Union Oil
Paraho
Petrosix
IGT
TOSCO II
Lurgi-Ruhrgas
Occidental Petroleum
U.S. Bureau of Mines
Figure 40. Classification of retorting processes.
Surface retorting processes are distinguished by the retorting vessel
and in particular by the method in which the necessary pyrolysis heat is
supplied. Current processes involve either solid-solid or gas-solid heat
transfer (HE-100).
Processes that use solids-to-solids heating rely on heated solids such
as ceramic balls, sand, or spent shale particles to supply the retorting
heat. These processes heat the particles in an external heater and then mix
them with the raw shale in the retort. After retorting, the heated solids
must be separated for recycling from the spent shale.
Processes which involve gas-to-solids heating use either internal gas
combustion or external heat generation (HE-100, RA-150). Processes using
internal gas combustion inject air directly into the retort. The heat liber-
ated by the resulting combustion of fuel gas and carbon residue provides the
retorting temperature. Processes using external heat generation rely on
external heaters to provide a high-temperature recycled gas which may be
routed into the retort. Some processes using internal gas combustion include
-67-
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plans or capabilities to use external heating of recycled gas to provide the
retorting heat (PF-003, LI-094).
Operating conditions of the different retorts vary and this effects
the product streams. A comparison of the effluent oil from three retorts
is show in TABLE 7.
TABLE 7. CHARACTERISTICS OF CRUDE SHALE OILS
Gas
Gravity, °API
Sulfur, weight-percent (wt-pct)
Nitrogen, weight-percent
Pour point, °F
Viscosity, SUS @100° F
Retorting Process
Combustion Union
19.7
0.74
2.18
80
256
20.7
0.77
2.01
90
223
2
TOSCO
28.0
0.80
1.70
75
120
1 Typical of product from original Union process.
Unpublished information submitted by Colony Development Company indicates
TOSCO crude shale oil may have gravity as low as 21° API and sulfur content
of 0.75 wt-pct.
Gases produced in shale oil processes vary significantly, depending
on retort type. Gases from internal combustion retorts are diluted with com-
bustion products and the inert components of the air. As a result the gas
has a low heating value, 100 Btu/scf, and cannot be economically transported
any significant distance. Gas from retorts which utilize indirect heating
is composed only of undiluted components from the kerogen and has a sub-
stantially higher heating value, 800 Btu/scf. A comparison of gases from
internal combustion and indirect heat retorts is shown in TABLE 8.
Physical properties and quality of the spent shale also change with the
retort. The amount of carbonaceous material remaining on the shale is in-
versely proportional to the retort temperature. The low temperature shale
from a TOSCO retort contains 5%-6% carbonaceous material, intermediate tem-
perature gas combustion 3%, and high temperature shale from the Union retort
contains essentially none.
In-situ processing proposes to retort the shale in place, and thus
avoid the solids handling problems associated with more conventional mining
techniques. In-situ processing involves fracturing the shale, injection of
retorting fluids, retorting of the shale in-place, and recovery of the product.
Potential methods for fracturing the shale include hydraulic, electrical, chem-
ical explosive, and nuclear methods.
In-situ oil shale processing is still in the development stage. The
two potential in-situ processes are the U.S. Bureau of Mines horizontal sweep
method and the Occidental Company mine and collapse method.
-68-
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TABLE 3. CHARACTERISTICS AND YIELDS OF UNTREATED RETORT GASES
(Source: US-093)
Composition, vol. pet
Nitrogen I/
Carbon monoxide
Carbon dioxide
Hydrogen Sulfide
Hydrogen
Hydrocarbons
Internal
2/
60.1
4.7
29.7
0.1
2.2
3.2
Type of
Combustion
2/
62.1
2.3
24.5
0.1
5.7
5.3
Retorting Process
Indi
As
Produced
—
4.0
23.6
4.7
24.8
42.9
rectly Heated
When
Desulfurized
__
4.2
24.8
(0.02)
26.0
45.0
Gross Heating Value,
Btu/scf 83 100 775 815
Molecular Weight 32 30 25 24.7
Yield, scf/bbl oil J3/ 20,560 10,900 923 880
_!/ Includes oxygen of less than 1.0 volume percent.
27 First analysis reflects relatively high-temperature retorting in comparison
with second, promoting higher yield of carbon oxides from shale carbonate and
relatively high yield of total gas.
2_/ Oil from the retort
In-situ oil shale processing is still in the development stage. The
two potential in-situ processes are the U.S. Bureau of Mines horizontal sweep
method and the Occidental Company mine and collapse method.
Current oil shale processes are described in the following sections.
TOSCO II
The TOSCO II process features a rotary retort which uses ceramic balls
to supply the retorting heat by a solids-to-solids heat transfer. A flow
diagram of the TOSCO II process is shown in Figure 41.
Raw oil shale, crushed to less that %-inch, is fed into a fluidized bed
where it is heated to approximately 500° F by hot flue gas from the ceramic
ball heater. The preheater effluent is routed to settling chambers and cyclones
in order to separate the preheated shale from the flue gas. Following shale
separation, the cooler flue gas, which has been incinerated within the preheat
system to reduce trace hydrocarbons, is passed through a high energy venturi
to remove shale dust before being vented to the atmosphere at a temperature
of 125-130° F.
Preheated raw shale from the cyclone separators is fed to the horizontal,
rotating retort and mixed with hot ceramic balls (%-inch diameter). The balls
are heated to about 1200° F in a furnace fired by product fuel gas. Pyrolysis
occurs because a temperature of 900° F is maintained by the transfer of heat
from the balls to the shale. An internal pressure of 5 psig is maintained
to prevent the entrance of air. The rotating retort is essentially a ball mill-
as the kerogen decomposes, the oil shale loses strength and is pulverized by
-69-
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or externally heated recycled gas to achieve the retorting temperature
(PF-003). Coarsely ground shale oil is introduced at the top and flows by
gravity down through the vertical retort. Combustion air and recycled gas
(or heated gas) are introduced at several points in the retort, flowing up-
ward countercurrent to the shale. Combustion of these gases with the residual
carbon on the shale liberates the heat necessary for retorting. If heated re-
cycled gas is utilized, then steam will provide the heat necessary for retort-
ing. Spent shale is removed from the bottom of the retort. A discharge grate
improves the downward flow of shale over the unit cross-section and provides
for a careful distribution of incoming gases (HE-100). Shale oil vapors
exit overhead, passing through an electrostatic precipitator and then to
a gas recovery unit. A portion of the noncondensible gas is returned to the
retort as combustion gas with the remainder routed to a waster heat boiler.
The Paraho retort step is shown in figure 42.
RAW PRODUCT
VAPORS
OIL/GAS
SEPARATION 4
RECOVERY
GAS/AIR
MIXTURE
GAS/AIR
MIXTURE
GAS/AIR
RECYCLE
SHALE OIL
GAS
MIXTURE
SPENT
SHALE
Figure 42. The Paraho retort process.
Lurgi-Ruhrgas
The Lurgi-Ruhrgas Process shown in Figure 43 uses small solids such
as sand, coke particles, or spent shale to heat incoming oil shale. The
solids are preheated and mixed with raw shale in a sealed screw-conveyor that
-71-
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acts as the retort (HE-100). The effluent from the retort is discharged into
a bin for separation. Solids are removed from the lower part of the bin for
recycling. Product vapors containing dust and condensation are removed over-
head (GA-107, RA-150).
SEPARATOR
\
1 p»
CYCLONE
>•
WASTE HEAT
RECOVERY
i
WASTE
FLUE GAS
' WASTE
SOLIDS
HOT
SOLIDS
GAS
PRODUCT
SHALE
' OIL
- AIR + FUEL
(if required)
Figure 43. The Lurai Ruhrgas oil shale retorting process.
U.S. Bureau of Mines Gas Combustion
The U.S. Bureau of Mines Gas Combustion retort is a vertical, refrac-
tory-lined vessel. Coarsely ground oil shale is introduced at the top and
flows by gravity downward through the retort. Although no physical barriers
are present in the vessel, the retort may be considered to consist of four
sections for shale preheating, retorting, combustion, and cooling.
Combustion air and recycled gas are injected into the combustion zone,
approximately 1/3 of the way up the retort. Combustion of the gases with
residual carbon on the spent shale liberates the heat necessary for retorting.
Combustion temperature is approximately 1200-1400° F. Retorting occurs above
the combustion zone. Product vapors from the retorting section are cooled by
the incoming shale and withdrawn. Heat exchange between product vapors and
raw shale preheats the shale prior to retorting. Following combustion, spent
-72-
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shale in cooled and removed from the bottom of the retort. Recycled gas
entering at the bottom of the retort is used to cool the spent shale (KA-133,
RA-150). The Gas Combustion retorting process is shown in Figure 44.
Raw Shol«
Shale
Preheating
Retorting
Combustion
Recycle
Cos
Preheat
Oil-Lean
Oil Mist Go»
Separator} """~*-'
Blower
GO» _-
Processing
Dilution Cos
•Air
Figure 44. U.S. Bureau of Mines Gas Combustion
retorting process.
Union Oil
The Union Oil Company Process uses internal gas combustion to provide
the retorting heat. The retort is a vertical refractory-lined vessel in the
shape of an inverted cone. The top of the retort is open to the atmosphere.
Air enters from the top while shale is introduced at the bottom by a rock
pump. Combustion of the organic matter remaining on the shale heats the
shale by direct gas-to-solids exchange. Maximum shale temperature in this
process is approximately 1800° F. Spent shale solids overflow the vessel at
the top. The product oil is cooled by the incoming shale and removed through
an outlet at the bottom of the retort. The advantage of this design is that
oil products cannot drip down to hotter parts of the retort and leave heavy
residues that must be removed (UN-025). The Union Oil Company retort is shown
in Figure 45. Union Oil Company is also working on an alternative configura-
tion with external heat generation (HE-100,LI-094).
-73-
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Air
•Overflow
Burning i
Zone
Retorting
Zone
Condensation
Zone
Oil 8 Gas
Oil 8 Gas
f /Rcw
RQW /Shale
Shale /Hopper)
Burned
Shale
Figure 45. Union Oil Company retort.
Petrosix
The Petrosix Process is similar to the gas combustion process used
by the U.S. Bureau of Mines except that the Petrosix Process injects externally-
heated recycled gas into the vertical kiln retort rather than combustion air.
Crushed shale enters at the top and moves down through zones of preheating,
retorting, and cooling. Recycled gas, heated in a separate furnance, is in-
jected into the retorting area of the vessel (FR-115). Since heat generation
is external, a combustion zone is not present in this retort. Retorting pro-
ducts moving upward in the vessel are cooled by incoming raw shale prior to
leaving the retort. An unheated recycled gas stream is injected at the bottom
of the retort to recover sensible heat and cool the spent shale. Spent shale
is removed at the bottom of the vessel and slurried to a disposal area. A
diagram of the Petrosix Process is shown in Figure 46.
-74-
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Oil SIIALE
SEAL GA:
GAS
PRODI tCT
LIGHT
•SHALE
OIL
WASTE
WATER
WATER —]
RETORTED SHALE SLURRY
(to disposal)
Figure 46. Petrosix Process flow diagram.
IGT Retort
The key feature of the Institute of Gas Technology (IGT) retort is
the moderate-pressure hydrogen atmosphere. The vertical retort is internally
divided into three zones. Shale passing downward is prehydrogenated and pre-
heated in the top zone, hydroretorted in the middle zone, and cooled in the
bottom zone. One hydrogen stream picks up some heat from the spent shale and
after additional heating, is used to preheat incoming raw shale. A second
hydrogen stream is internally heated and passes through the middle retorting
zone to hydroretort the kerogen. Varying the reaction temperature varies the
ratio of liquid to gaseous products (GA-107, HE-100). Figure 47 is a flow
diagram of the IGT Process.
Superior
The Superior Oil Company Process for shale oil recovery differs from
other oil shale ventures because the emphasis is not on the retort design.
The key feature of this process is the simultaneous recovery of associated
minerals. The Superior Oil Company Process depends on oil shale that contains
the minerals nahcolite (naturally occurring sodium bicarbonate) and dawsonite
(a sodium aluminum carbonate). The oil shale can be processed into low sul-
fur fuel oil, natural sodium bicarbonate, soda ash, and aluminum compounds
(WE-163, WE-164, WE-166). Since four products result from the Superior Process,
it is an integrated process. Figure 48 is the flow diagram for the Superior
Process.
-75-
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HYDROGEN RECYCLE
GAS PRODUCT
*- OIL PRODUCT
Figure 47. Flow diagram of Institute of Gas Technology
oil shale process.
\ '
UNDERGROUND
MINING
REFUSE
UNDERGROUND
to CRUSHING 4
~~ NAHCOLITE
SEPARATION
!
NAHCOLITE
J
I
SOUR
WATER
RETORTING
& PARTIAL
REFINING
\
1
FUEL
OIL
SPENT
SHALE
DISPOSAL
J
i
ALUMINUM
& SODIUM
COMPOUND
RECOVERY
1
t "
A1203 A1(OH)3
1
Na2C03
Figure 48. Flow diagram of Superior oil shale process.
-76-
-------
After mining, raw nahcolite is separated from the oil shale by a mechan-
ical crushing and screening process. The oil shale is very difficult to frac-
ture, but the nahcolite is very brittle and fractures easily (WE-163).
The closed system retort is proprietary, but here the oil shale contain-
ing dawsonite is pyrolized. The retort is called a circular grate retort. The
circular retort which is easily sealed passes the shale through several proces-
sing zones. In each zone, the shale is treated differently in preparation for
the extraction of alumina and soda ash. The four zones in the retort are the
loading and unloading, retorting, cooling, and residual carbon recovery zones.
The hydrocarbon product is withdrawn as a vapor and fed to a fractionator for
upgrading. The initial processing of the dawsonite begins in the retort where
the sodium aluminum carbonate decomposes to sodium carbonate and a soluble
aluminum compound. These two compounds remain in the spent shale when it is
discharged from the retort and fed to a light caustic leach (WE-163, WE-166).
As the spent shale is removed by filtration, the soluble aluminum com-
pound and the sodium bicarbonate dissolve in the caustic solution which is
beneficiated by countercurrent decantation. Next, aluminum trihydrate is
separated from the liquor by carbonation and filtration. The carbonate-rich
liquor is evaporated for soda ash recovery, and the condensed water is recycled.
Although the shale increases in volume during processing, it can be re-
turned to the mine for disposal because about 50 percent of the originally
mined material is removed during the processing.
U.S. Bureau of Mines In-Situ Process
In the U.S. Bureau of Mines In-Situ Process, parallel rows of wells
(injection and production) are drilled along two opposing sides of an oil
shale deposit, and the shale is fractured along horizontal planes (BU-123,
UN-025). Once the shale is fractured, a retorting fluid (hot gas or steam)
is introduced through injection wells. The gas is injected at a rate suffi-
cient to maintain a satisfactory temperature and/or flame front within the
shale formation. The shale is brought to the retorting temperature (900° F),
and the kerogen is decomposed. The hot gases create a pressure differential
within the formation forcing the shale oil vapors into the producing wells.
The row of production wells brings to the surface a gas with entrained liquid.
Liquid which may gather at the bottom of the shale bed is pumped out. A
schematic of this process is shown in Figure 49. The process operates like
a horizontal retort in which retorted shale oil is pushed toward the product
point by an advancing combustion zone.
Conventional processing is used after the liquid is pumped from the
shale bed. Liquid is also recovered from the gas stream. The gas stream,
which has a heating value of about 30 Btu/scf is primarily recycled into
the shale formation. The gas which cannot be injected is treated for acid
gas removal and flared.
Occidental In-Situ Process
The Occidental Petroleum Company In-Situ Process, developed by its
subsidiary, Garrett Research and Development Company, involves a limited amount
-77-
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AIR AND GAS INJECTION
OIL AND GAS RECOVERY
OIL
SHALE
OVERBURDEN
COOL GASES
\ HOT GASES
SHALE OIL
/ TEMPERATURE \
-Burned Out—h-Fire——Retorting
Figure 49. Schematic representation of an in-situ
retorting operation. (Source: UN-025)
of conventional mining, blasting of the remaining shale to form the retort,
and retorting in-place using air and underground combustion (HE-100).
Conventional mining techniques are used to excavate rock just below
the target zone, and collector pipes are subsequently installed on the floor of
the mined area. Explosives are then used to fracture the overlying oil shale
to form a large underground retorting room. Combustion is initiated at the
top using an outside fuel source. The combustion heat retorts the top shale
to yield shale oil, some gas, and residual carbon. Off-gas is recirculated
to control oxygen concentration and burning rate. Shale oil drains to the
bottom of the retort where it is collected and removed for upgrading.
Shale Oil Upgrading
The second stage of oil shale processing is upgrading the shale oil
recovered from the retorting step.
Shale oil upgrading is common to all oil shale technologies and is
similar to the initial stages of crude oil refining. Upgrading is accomplished
near the retorting site. Steps involved in the upgrading include oil recovery
and fractionation, gas recovery and treating, sulfur recovery, heavy fractions
cracking, naphtha and gas oil hydrotreating, ammonia separation, delayed coking,
and water treating. Although the effluent stream from each type of retort dif-
fers, the same upgrading processes can be used for each retorting procedure.
A detailed description of a typical shale oil upgrading sequence can be found
-78-
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elsewhere (RA-150). Regardless of the retort types, all processes utilize
cracking and hydrotreating processes to upgrade the retort oil to distillate
fuel quality.
-79-
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SECTION VI.
IDENTIFICATION OF EMISSIONS AND IMPACTS
COAL EXTRACTION
Coal mining operation and equipment choices are extremely varied and in
general are determined by the local geology and other natural conditions. As
a result no single mining procedure can be presented as representative of the
entire industry. The exact environmental effects will therefore depend upon
the chosen mining technique and the prevailing geological and geochemical
characteristics. In the following sections the environmental impacts of the
different mining methods are discussed, followed by a general discussion of
acid mine drainage which, although more prevalent for underground mining, is
common to both surface and underground mining. To facilitate comparison,
estimates are based whenever possible upon the production of 1012 Btu/day
of primary fuel product. The primary fuel product in the mining modules is
assumed to be run-of-tnine (R.O.M.) coal.
Underground Coal Mining
The main environmental problem of underground coal mining is acid mine
drainage. The average output of acid mine water per ton of coal produced in
1970 in the Appalachian bituminous coal mining region was calculated to be
353 gallons per ton of mined coal. This environmental problem will be dis-
cussed in more detail in the section on acid mine drainage.
Land Disturbance
Land requirements for any mining operation include the space occupied
by the mine site itself and by processing and loading facilities. Underground
mining also requires surface space for waste disposal in the form of refuse
piles. The effects of solid waste disposal other than land use will be dis-
cussed in more detail below. The land used or disturbed by underground mining
has been estimated to average 0.00034 acres per ton of coal mined (HI-083).
Subsidence is another form of land disturbance associated with under-
ground mining. Improved mining techniques have increased the percentage of coal
recovered and have therefore left less support at mine level in the form of
remnant pillars. Subsidence of the ground surface due to the loss of sub-
surface support has resulted in a large amount of damage to property in some
areas (AC-010). Although three years are required to reclaim surface-mined
land in Illinois, an additional two years are allocated to underground-mined
land prior to the start of reclamation activities to allow for subsidence
(RA-150). Mining subsidence can affect ground water, alter hydrological con-
ditions, affect water utilization, and create drainage problems (WO-035).
-80-
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Water Effects
Process water requirements for underground mining operations include
that used for dust control in the crushing plant and along haul roads. If
physical cleaning facilities are located on site, these will also require
water. This will be discussed in a section on physical coal cleaning.
Water effluents are generally acid mine drainage from the mine site itself
and run-off from refuse piles. The water pollution from refuse consists of
acid mine drainage and siltation. TABLE 9 lists water quality data from four
refuse sites. This data illustrates the variability of effluent from refuse
(MA-411).
Table 9. WATER QUALITY DATA FROM SELECTED REFUSE SITES (SOURCE: MA-411)
Parameter
PH
Conductivity
Acidity*
Alkalinity
Sulfate (SOO
Sodium (Na)
Magnesium (Mg)
Aluminum (Al)
Potassium (K)
Calcium (Ca)
Manganese (Mn)
Iron (Fe)
Nickel (Ni)
Copper (Cu)
Zinc (Zn)
Lead (Pb)
Luzerne
County
Penna.
3.0
4400
690
-
3000
100
250
87
4.8
340
50
30
1.7
0.14
2.8
-
Pike
County
Ky.
6.9
880
7
135
690
115
26
1.8
8.1
50
3.5
6.2
-
-
0.1
-
Muhlenburg
County
Ky.
2.5
6800
7020
-
7800
270
195
440
13
300
72
3400
3.0
-
8
0.12
Sullivan
County
Ind.
2.4
6400
6500
-
9500
200
285
340
3.0
350
120
2600
1.6
0.16
7.2
0.30
Acidity to pH 7.3
Notes:
(1) All values expressed in milligrams/liter (mg/1) except pH in standard units
and conductivity in ohm" -cm~ .
(2) Data taken from single grab samples taken in April and May 1974.
-81-
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Solid Wastes
Solid wastes are generated during underground mining, crushing, and
washing processes. Mine disposal of underground mining refuse is generally
not practiced. Solid wastes are produced in an Illinois underground mining
operation at a rate of 99.3 tons per 1012 Btu coal extracted (HI-083, footnote
1350). These solid wastes are found in refuse piles and present both air and
water pollution hazards.
Refuse piles can ignite spontaneously and are difficult to quench. The
U.S. Bureau of Mines examined 292 burning coal refuse piles throughout the
nation's coal-producing regions in 1968. These coal waste fires, extending
over 3,200 acres, produced particulate matter and fumes high in sulfur oxides.
This posed a threat to health and safety in surrounding areas, damaged vege-
tation, and caused the deterioration of nearby structures (MC-096).
Refuse piles also cause water pollution in the form of acid mine drainage
and siltation. Siltation is influenced by the steepness, compaction, drainage
control structures, and cover material of the pile (MA-411). Refuse piles are
also aesthetically displeasing.
The U.S. coal waste disposal problem is largely limited to the eastern
coal fields where past practices have resulted in refuse piles that adversely
affect the region's air and water quality and human health conditions (AT-052).
Air Emissions
Air emissions for underground mining operations are based on a previously
developed room-and-pillar mining module (CA-246). Longwall mining emissions
should be approximately equivalent to room-and-pillar emissions. A physical
coal cleaning operation is included in calculating the emissions.
The basis for the room-and-pillar coal mining module is a cleaned coal
production rate of 5,000 tons per day. Assuming a 20 percent waste removal
in the physical coal cleaning operation and a thermal dryer fuel demand of
1.3% of the thermally dried coal, the run-of-mine coal is determined to be
6,300 tons per day. In 1972, 70% of all coal mined underground was mechanically
cleaned (US-144). A summary of the emissions from the room-and-pillar mining
module is shown in TABLE 10. Two sets of emissions are presented for the room-
and-pillar mine. The difference between the two is the inclusion of emissions
from burning refuse piles in one set. Figure 50 is a schematic of the mining
operation.
The following assumptions are used in establishing the room-and-pillar
module:
(1) The coal mine emits methane at a rate of 200 ft3/ton
of coal mined (DE-148).
(2) Ventilated air dust emissions will meet the Federal
effluent air quality standard concentration of 2.0
milligrams per cubic meter (mg/m3) (HI-097).
-82-
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TABLE 10. SUMMARY OF ATMOSPHERIC EMISSIONS (SOURCE: CA-246)
Room and Pillar Mining Coal Module
Basis: 6,300 ton/day R.O.M. Coal
Air Emissions
Ib/day
Ib/day
Particulates
SO 2
NO
x
CO
Hydrocarbons
936
1,290
690
88.2
43,200
12,700
18,900
6,490
35,300
59,100
Includes emissions from burning refuse piles.
-^ VENTILATED AIR
FLUE GAS
FINAL COAL
P80DOCT
LOADING AND
SHIPPING
Figure 50. Room and pillar coal mine.
-83-
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(3) The run-of-mine coal has a heating value of 12,000
Btu/lb and a sulfur content of 3.0 wt.% (HI-083) .
(4) Twenty percent of the run-of-mine coal is removed
as ash refuse in the coal cleaning operation.
These values are based on national averages.
In the room-and-pillar mine module there are six possible sources of
air emissions: (1) mine ventilation system, (2) thermal dryer, (3) final
coal product loading operations, (4) refuse transfer system from the prepara-
tion plant, (5) diesel-powered vehicles, and (6) refuse burning. The module
emissions from the various sources are shown in TABLE 11.
TABLE 11. MODULE EMISSIONS FOR ROOM AND PILLAR COAL MINE (SOURCE: CA-246)
Emissions (Ib/day)
Source
Ventilated Air
Thermal Drying*
Coal Loading
Transfer & Refuse
Vehicle Emissions
Burning Refuse
ROUNDED TOTAL
Particulates
180
505
18
230
3.1
11,750
12,700
S02
-
1,280
-
-
6.4
17,600
18,900
CO
-
35
-
-
53.2
35,200
35,300
Hydrocarbons
53,200
17
-
-
10.4
5,850
59,100
NOX
-
603
-
-
87
5.800
6,500
99% controlled if wet scrubber used.
Note:
Basis: 6,300 ton/day R.O.M. Coal
The emission factors for burning refuse piles given in Table 12 are
calculated from 1968 data on burning refuse piles (US-144, CO-168). The emis-
sions from refuse piles are not necessarily related to a refuse production
rate, but rather to the total amount of refuse accumulated. The emission
factors in TABLE 12 are based on average values.
TABLE 12. EMISSION FACTORS FOR BURNING REFUSE PILES
(SOURCE: CO-168, US-144)
Emission Factor
Pollutant (Ib/ton of Refuse)
CO 17.8
NO 2.95
x
Hydrocarbons 2.95
S02 8.89
Particulates 5.94
-84-
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It should be emphasized that these values are based upon national
averages. The true emissions for any given mine will, of course, vary depend-
ing upon the coal region and such coal characteristics as the heating value
per ton. Details of the above air emissions, are found in reference CA-246.
Comparisons to other energy extraction processes are given in TABLE 13 on the
basis of 1012 Btu/day.
Other Environmental Factors
Blasting can fracture rock strata and create fissures in the bed rock,
causing acid or saline pollution of the ground water. Blasting can also dis-
rupt the flow of water to aquifers and create noise and vibration problems.
In 1971 the U.S. Bureau of Mines reported the results of an environmental
noise survey made to determine the noise levels to which underground coal miners
are exposed. The investigation revealed that the shift exposures of 20 percent
of the miners studied were in excess of the safe standards (LA-048).
Surface Mining
The principal environmental effects of surface mining operations are
mine drainage and land disturbance. Among the adverse environmental effects
of surface mining of coal are (BA-234):
(1) destruction of the vegetative covering
(2) creation of massive piles of spoils
(3) drastic reshaping of the terrain
(4) sliding of spoils and blockage of streams
(5) pollution of streams with sulfuric acid and silt
(6) destruction of economic and aesthetic value of the land.
However, emphasis has been shifting to surface methods as demands for
clean air have increased mining activities in low-sulfur strippable coal deposits
in the western United States. Pollution problems arising from these operations
will differ considerably from those in eastern coal regions. Pollution from
western mining is not well characterized.
The pollution from area mines generally is not as severe as that from
contour mines because silt from erosion can often be confined to the mining area
(GR-156). Contour mining creates more possible environmental hazards such
as sediment slides, exposure of toxic materials, land disturbance, and acid
mine drainage. Auger mining disturbs less surface area than either contour
or area mining but may provide access to underground mines for the entrance
or exit of water, creating a source of acid mine drainage.
-85-
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TABLE 13. COMPARISON OF EMISSIONS FROM EXTRACTION MODULES (SOURCE: CA-246)
Air Emissions, Ib/day
Coal Extraction
Pollutant
Particulates
S02
CO
NO
x
Hydrocarbons
°£ Adjusted from
1 fTnm nVivs i pa 1
Strip
11,900
251
2,100
3,440
397
1
(15
( 8
( 2
( 7
Room and
,200)
,730)
,490)
,670)
542)
6,300 tpd run-of-mine
crta~\ flpannnp.
6,
•8,
4,
352,
,coal
190
530
583
560
000
Pillar2
( 84,000)
(125,000)
(233,000)
( 42,900)
(391,000)
(12,000 Btu/lb).
In-Situ3
5
30
65
,500
NA
,000
NA
,000
Emissions in
Oil Shale Extraction
Surface1*
64 , 800
640
5,400
8,800
1,000
parentheses
Room and
Pillar5 In-Situ6
13,100
35.
307
504
57.
include
127
7 239
414
19.6
1 718
emissions
2Adjusted from 6,300 tpd run-of-mine coal (12,000 Btu/lb). Mining emission values include emissions
from physical coal cleaning. Emissions in parentheses include emissions from burning refuse piles.
3Adjusted from 10 Btu/day fuel gas produced. Data on SOX and NOX emissions were not available (NA).
''Adjusted from 50,000 bbl/day of upgraded shale oil capacity (5.6 x 106 Btu/bbl) .
5Adjusted from 50,000 bbl/day of upgraded shale oil capacity (5.6 x 106 Btu/bbl).
6Adjusted from 50,000 bbl/day of upgraded shale oil capacity (5.6 x 106 Btu/bbl).
Note:
Basis: 1012 Btu/day Fuel Output.
-------
Land Disturbance
The average amount of land used or disturbed by surface mining is 0.0003
acres/ton of coal mined (HI-083). The actual amount of land used varies from
one geographical region to another depending upon such factors as the coal seam
thickness and overburden thickness. For a typical western U.S. strip mine, less
than an acre of land is disturbed to produce 1012 Btu of run-of-mine coal.
Nearly seven acres are disturbed by strip mining for Illinois coal. The dif-
ference is due to the much greater thickness of the western U.S. coal seams (RA-150)
In addition to the mine site itself, land requirements for a mining
operation will include the space occupied by processing and loading facilities,
haul roads, and reclamation activities.
Solid Wastes
No solid wastes are assumed to be generated as a result of surface
mining operations since waste solids can be returned to the mine and disposed
along with overburden material. This, of course, depends upon maintenace of land
reclamation as an integral part of the mining operation. If reclamation is not
practiced, toxic materials may be exposed to the environment. Removal and place-
ment of the overburden are critical in environmental control. The nontoxic, non-
acid, and fertile material should be stockpiled for later spreading or placed
on the less desirable spoils already mined (GR-156).
Water Effluents
The only process water requirements are the water used for dust
control in the crushing plant and along haulage roads. Reclamation water
requirements may be significant in the case of western surface mining (NA-172).
The coal deposits of the western United States are located in arid to
semi-arid regions, and coal seams are generally aquifers and principal sources
of fresh water. Mining may therefore cause alteration of ground water distri-
bution by aquifer disruption (GR-156).
In strip mining, natural drainage channels are often interrupted. Unless
the water is diverted around the mine, it enters the mine and becomes a possible
pollution source. Cutting into abandoned or inactive underground mines can re-
sult in the discharge of large volumes of stored polluted water (GR-156).
Mine drainage from surface mining may cause serious pollution in a
physical form such as sediment, or in a chemical form such as acid mine drainage,
or in a combination of both forms (GR-156). Significant pollutants are silt,
sulfuric acid, iron, and trace elements such as arsenic, copper, lead man-
ganese, and zinc (BA-234)."
Sediment and Erosion
Sediment causes more off-site damage than any other aspect of strip
mining. Indiscriminate dumping of overburden on the downslope during contour
mining and on coal haul roads contributes to stream sedimentation from strip mining.
-87-
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Sediment can destroy crops and farmland, damage buildings, cause
flooding, decrease stream and reservoir capacities, and seriously degrade
water quality by destroying habitats for aquatic life and increasing the
toxic content of water sources.
Strip mining accelerates the natural processes of erosion and sedimen-
tation. With the removal of ground cover, water flowing through a mining
area removes soil and creates gullies. The susceptibility of strip-mined
land to erosion depends on (1) physical characteristics of the overburden,
(2) degree of slope, (3) length of slope, (4) climate, (5) amount and rate
of rainfall, and (6) type and percent of vegetative ground cover (GR-156).
Air Emissions
Air emissions for surface mining operations are based on a strip
mining module (CA-246). Auger mining emissions should be approximately
equal to strip mining emissions.
The strip mine module is examined for mining without physical coal
cleaning and with physical coal cleaning. The module basis is 5,000 tons
per day of cleaned coal. A 20 percent waste removal in the physical coal
cleaning operation and a thermal dryer fuel' demand of 1.3 percent of the
thermally dried coal are assumed. Run-of-mine coal is used for the module
without coal cleaning. The equivalent coal production rates allow convenient
comparison of module emissions. In 1972, 31.6 percent of all the coal ex-
tracted by strip mining was mechanically cleaned (US-144). A summary of
emissions from both of the strip mining modules (with and without physical
cleaning) is shown in TABLE 14.
TABLE 14. SUMMARY OF ATMOSPHERIC EMISSIONS:
STRIP MINING COAL MODULE
(BASIS: 6,300 TON/DAY R.O.M. COAL)
(SOURCE: CA-246)
Air Emissions (lb/day)*Without PhysicalWith Physical
Coal Cleaning Coal Cleaning
Particulates
S02
NOX
CO
Hydrocarbons
1,800
38
520
317
60
2,300
1,320
1,160
376
82
*The difference in air emissions results from the thermal dryer and diesel-
powered equipment associated with the physical cleaning operation.
-88-
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The strip mine module is considered to be in steady-state operation.
This means that the mine pit has already been opened and the mine is in
production. In this module, any overburden excavated on a continuous basis
is moved to the rear of the mine and refilled as a reclaiming operation.
The coal strip mine module is shown in Figure 51.
FLUE GAS
PRODUCT
COAL
Figure 51. Strip mining coal module.
Assumptions used in the strip mining modules include the following:
(1) The preparation plant•is located 3.0 miles from the
coal production site (ST-166).
(2) The average depth of overburden is 48 feet and has
a density of 100 pounds per cubic foot (HI-083).
(3) The average coal seam is 5.2 feet thick and has a
density of 81 pounds per cubic foot (HI-083).
(4) A typical strip mine pit is 100 feet wide by 2,000
feet long (HI-083).
(5) The run-of-mine coal has a heating value of 12,000
Btu/lb and a sulfur content of 3.0 weight percent
(HI-083).
(6) 20 percent of the run-of-mine coal is removed as ash
refuse in the coal cleaning operation.
These values are based on national averages. Emissions related to specific
coals will vary from the emissions presented in this section depending on
coal quality and physical layout of the plant. Western coals have a lower
quantity of ash associated with the coal (less than 10 percent ash).
-89-
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A strip mining operation without a mechanical cleaning facility would probably
be used for low ash and low sulfur western coal.
Four possible sources of air emissions are associated with the strip
mining module. They are as follows:
(1) Emissions from diesel-powered vehicles
(2) Particulate emission from the preparation plant and
loading facilities
(3) Fugitive dust emissions from the operations within
the mine
(4) Emissions from thermal drying (if used).
Emissions from the various sources are given in TABLE 15.
TABLE 15. MODULE EMISSIONS
(STRIP COAL MINING MODULE
BASIS: 6,300 TON/DAY R.O.M. COAL)
(SOURCE: CA-246)
Emissions (Ib/day)
Source Particulates
Vehicle Emissions
Overburden Removal*
Primary Crushing*
Loading and Unloading
Plant at the Preparation
Loading in the Pit*
Vehicular Travel*
Thermal Drying**
Vehicle Emissions from
Refuse Hauling Operations
ROUNDED TOTAL
18.3
1160
126
39
506
40
505
1.4
2,400
S02
38
—
—
—
—
—
1290
2.9
1,300
CO
317
—
—
—
—
—
35
24
380
Hydrocarbons
60
—
--
—
—
—
17
4.5
82 1
NOX
520
—
—
—
—
—
603
39
,200
* 80 percent particulate control by water spraying and dust control techniques,
**90 percent particulate control by wet scrubbers.
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Details of the calculations of the air emissions are given in
Reference GA-246.
Comparisons to other energy extraction processes are given in Table 13
on the basis of 1012 BTU/day.
Other Environmental Factors
Blasting can fracture rock strata and create fissures in the bed rocks,
causing acid or saline pollution of the groundwater. Blasting can also dis-
rupt the flow of water to aquifers, and create noise and vibration problems
(GR-156).
Surface mining is also aesthetically displeasing because of the land
disturbance and unsightly spoil banks.
Acid Mine Drainage
Acid mine drainage, a significant environmental problem of coal mining,
results when naturally occurring pyrite (FeS2; in the coal seam and wastes is
oxidized in the presence of air and water to form sulfuric acid and soluble
iron [Fe(II) and Fe(III)] sulfates. Such mine drainage is typically very
acidic (pH 2 to 3) and must be treated for pH and dissolved iron before
release to surrounding water courses. At these low pH's, heavy metals (e.g.,
iron, manganese, cadmium, copper, zinc, lead, etc.) are more soluble and
create further water pollution problems.
The acid drainage of bituminous and anthracite coal mines in the
United States has been a major source of inorganic pollution to the streams
in these mining areas. Increased demands for water has made the deteriorated
water quality caused by these wastes more noticeable (CL-044).
Continuous acid discharges have a serious effect on aquatic ecosystems.
Acid waters containing high concentrations of dissolved heavy metals support
only limited water flora, such as acid-tolerant molds and algae, and will not
support fish. In 1967, more than a million fish were killed by mine drainage,
ranking this type of pollution as one of the primary causes of fish kills in
the United States (ST-149). Such water also corrodes metal structures,
harms municipal and industrial water supplies, and makes water unfit for
recreation.
The amount and rate of acid formation and the quality of water dis-
charged are functions of the amount and type of pyrite in the overburden and
in the coal, time of exposure, characteristics of the overburden, and amount
of available water (MO-141). Acid mine drainage is less of a problem in the
arid, western coal mining regions where the sulfur content of the coal is
less, but represents a significant environmental problem in portions of the
Appalachian region (BI-014). The average output of acid mine water produced
in the Appalachian bituminous coal mining region in 1970 was calculated to be
353 gallons per ton of coal mined (BA-234).
Coal mine refuse can also be a source of acid drainage. Acid runoff
from refuse piles can be controlled by covering the wastes with soil,
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establishing a vegetative cover, and providing adequate drainage to minimize
erosion (KO-105).
The best method for preventing acid mine drainage is good planning,
mining, and reclamation. The amount of time wastes are exposed should be
minimized to prevent pyrite oxidation. Water contact with the mine area
should be minimized to reduce the water available for flushing oxidation
and erosion products (GR-156).
If acid mine drainage cannot be prevented or the discharge controlled,
the water must be neutralized. Most treatment processes involve (1) neutrali-
zation, (2) aeration, (3) sedimentation of precipitated solids, and (4) sludge
disposal. Alkaline reagents that may be used are ammonia, sodium carbonate,
sodium hydroxide, limestone, and lime.
The advantages and disadvantages of neutralization are given in Table
16. Neutralization has its own environmental impacts because the water still
contains large amounts of dissolved solids and a sludge must be disposed.
Neutralization and sludge disposal techniques are objects of continued
research (AK-006, BI-014, BI-047, DA-077, PH-038). No single dewatering system
has been found best for all acid mine drainage sludges (AK-006). The nature
of sludge, disposal techniques, sludge conditioning, dewatering techniques,
and sludge banding were discussed in a comprehensive report on solid waste
disposal. Three case studies of acid coal mine drainage treatment plants
are included in the study.
Underground Gasification
Present work in underground coal gasification has been in experimental
and developmental stages. Environmental data on these in-situ processes is very
limited. Moreover, on the basis of technical and economic experience to date,
it is difficult to foresee when commercial operations will be a reality.
Land disturbance by underground gasification will be much less severe
than by strip-mining and surface gasification. It will require much less land
space for surface facilities. The ash from underground gasification will re-
main underground. The amount of surface subsidence will vary with the seam
thickness of the gasified coal, the depth of the coal, and the nature of the
strata overlying the coal (HU-079).
Potential environmental problems associated with underground gasifica-
tion are ground-water pollution and leakage of toxic gases such as carbon
monoxide. There is the possibilty that ground-water pollution similar to acid
mine drainage may be caused by the entrance of ground water into coal seams
depleted by gasification (HU-079).
The only anticipated air emissions from underground coal gasification
are fugitive emissions from high pressure equipment and from vehicular move-
ment around the surface facilities. However, if an underground gasification
process becomes commercial, gas cleaning procedures would probably be used.
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TABLE 16. ACID MINE DRAINAGE NEUTRALIZATION
(SOURCE: GR-156)
Advantages
Disadvantages
(1) Neutralization removes acidity
(1) Hardness is not. reduced and may be
increased-
(2) Neutralization removes heavy
metals; as the pH increases,
the solubility of heavy metals
decreases.
(3) Ferrous iron is removed as
ferric iron at higher pH
levels.
(4) Sulfate can be removed. In
highly acidic acid mine
drainage, it may be necessary
to add enough calcium iron to
exceed the solubility of calcium
sulfate.
(2) Sulfate is usually not reduced to
a low level and usually exceeds
2,000 mg/liter.
(3) Iron concentration is not usually
reduced to less than 3 to 7 mg/liter.
(4) Total dissolved solids concentra-
tion is increased.
(5) A waste sludge to be disposed of
is produced.
COAL CLEANING
Physical Coal Cleaning
The environmental consequences of physical coal cleaning have been
examined by Radian (RA-150), Hittman (HI-083)* Battelle (BA-234), and the
University of Oklahoma (UN-025). Some aspects of physical coal cleaning were
discussed in the previous section on underground mining.
Most studies have examined the type of coal cleaning process previously
described. However, other processes in various stages of development may
become environmentally important. One of these is an oil agglomeration pro-
cess in which substantial amounts of many trace elements are removed from the
coal during beneficiation (CA-152). These elements are concentrated in the
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tailings from the coal cleaning plant. This removal diminishes the potential
for adverse effects from coal combustion, but the refuse from the cleaning
facility must therefore be more carefully controlled.
Water and land estimates for a physical coal cleaning facility vary
widely (UN-025). Some water requirements are estimated to be as high as
1,500 to 2,000 gallons per ton of coal processed (BA-234, UN-025), while
others are as low as 524 gallons per ton (UN-025). Land requirement
estimates vary from 90 acres including settling ponds (BA-234, UN-025) to
400 acres including settling ponds (UN-025).
Ultimate analyses of Illinois coal, both before and after cleaning, are
given in Table 17. The ash and sulfur concentrations of the coal are reduced
by cleaning. These components will be in the water effluents and solid wastes,
TABLE 17. ULTIMATE ANALYSES OF AN ILLINOIS COAL
(SOURCE: RA-150)
Before Cleaning After Cleaning
c
H2
N2
02
s
Ash
H20
Heating Value
61.0
5.2
1.4
6.8
3.6
11.0
11.0
100.0
11,000
65.2
5.6
1.1
7.7
2.1
6.9
11.5
100.1
11,500
Note: All numbers are wt % except heating value which is Btu/lb coal.
If proper pollution controls are not implemented, water pollution at a
cleaning facility may result from discharged process water or runoff from
refuse piles. This water may contain acid, suspended solids, and dissolved
solids. Although water streams within the coal-cleaning process may contain
high levels of suspended and dissolved solids, all liquid waste streams are
routed to holding ponds to allow settling of the suspended solids. The clear
supernatant liquid is then recycled to the process. Thus, no liquid effluents
result from the cleaning process.
Solid wastes from the coal cleaning process result from a loss in pro-
cess feed. The amount of solid wastes depends upon the operating conditions
but will be in the range of 10 to 21 pounds per 106 Btu of plant output (BA-234)
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Any solid waste that cannot be returned to the mine site for disposal will
accumulate in refuse piles.
Air emissions from the coal-cleaning process are rather limited. Par-
ticulates may be emitted during the handling process. Coal burned to operate
thermal dryers may release some particulates such as N0x, S02, and CO. New
coal cleaning plants are assumed to be completely enclosed and to utilize
baghouses to control particulate emissions. Spontaneous ignition of refuse
piles may also release noxious emissions of S02, NO , and hydrocarbons.
Chemical Coal Cleaning
The technical feasibility of chemical coal cleaning has been established,
but the economic feasibility is still to be proven. Both the Meyers and
Battelle processes have been tested at bench-scale and pre-pilot plant levels.
Because they are still in developmental stages, there is little direct infor-
mation about the environmental effects of these processes.
The Meyers' process contains the following probable sources of waste-
water, air pollution, and solid wastes (BA-234):
(1) Spent leachate solution from leaching circuit
(2) By-product iron sulfate from leaching circuit
(3) Elemental sulfur from sulfur recovery circuit
(4) Solvent-vapor loss from sulfur recovery circuit.
An evaluation of pollution control has been conducted for the Meyers'
process (MA-473). Effluent streams, process alternatives and improvements,
and technology needs were identified. It was noted that the large quantity
of iron sulfate to be disposed of.creates a potential problem and the purge-
water streams need to be better defined with respect to dissolved solids and
organics. The buildup of potentially hazardous trace elements in the treat-
ment plant was cited as a possible problem. Although the leaching of trace
elements is beneficial with respect to utilization of the product, the leach-
ing concentrates these elements in a small area. Disposal techniques there-
fore are more important. Another important finding in the above evaluation
was that some coal, even after treatment, may still have an unallowable sulfur
concentration.
The hydrothermal process by Battelle contains the following four
probable sources of wastewater, air pollution, and solid wastes:
(1) Spent solution that cannot be recycled because of
a buildup of impurities
(2) Fugitive emissions of hydrogen sulfide and sulfur
dioxide from the sulfur recovery circuit
(3) Particulate emissions from grinding step
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(4) By-product sulfur.
The hydrothermal process extracts several potentially hazardous metals
from coal (e.g., beryllium, arsenic, barium, and lead) which, if not removed,
might be emitted into the air during coal combustion. This is a favorable
impact in the utilization of the coal, but it also means that the effluent
streams in the cleaning process must be carefully controlled so that the
impacts of these metals will not be transferred to a new location.
COAL SLURRY PIPELINE
The impending expansion of the nation's coal slurry pipeline system
necessitates a consideration of the ensuing environmental effects. The
Coal Pipeline Act of 1974 is designed to facilitate the construction of coal
pipelines. This act amended the law governing issuance of rights-of-way over
Federal lands for oil and gas pipelines to include coal pipelines. The
environmentally responsible Federal law applicable to rights-of-way now
applies to coal pipelines on Federal lands. The act also authorizes the
Federal Power Commission (FPC) to give a right of eminent domain over private
property to the operator of a coal pipeline after the operator meets stan-
dards and obtains an FPC certificate (CO-197). The granting of rights-of-
way for the proposed Wyoming-Arkansas coal pipeline is presently a con-
troversial matter in certain Midwestern states.
TABLE 18 summarizes the environmental effects and corresponding mitiga-
tion procedures encountered in building a coal slurry pipeline. The effects
are basically the same as for any major pipeline. Generally the land at any
point should be disturbed by construction for only 2 to 6 weeks. When the
construction is finished, revegetation and other forms of reclamation should
begin.
TABLES 19 and 20 summarize the primary and secondary environmental
impacts of coal slurry pipeline systems. Operational impacts are associated
with the following three areas: (1) coal preparation, (2) main slurry pipe-
line and pump stations, and (3) dewatering systems (GR-177). Except for the
disposal of slurry water, the environmental effects of the dewatering system
are similar to those for coal preparation. If not used as process water or
if improperly disposed of, this water could be an environmental problem.
Because future development of energy resources will be concentrated
in the western regions of the United States, manpower requirements should be
considered in environmental assessments. Coal slurry pipelines require re-
latively few operating and maintenance personnel. The Black Mesa pipeline
system requires only 55 men (MO-113). Coal slurry pipelines allow the coal
processing or utilization facilities to be removed from the source and placed
closer to urban centers where the relative socio-economic impact on the sur-
rounding community will be lessened.
Slurry pipelines have an esthetic advantage over other modes of coal
transportation. Although the preparation plant, pumping stations, and de-
watering plant are above ground, the pipelines are buried 2% to 3 feet under-
ground and therefore out of sight.
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TABLE 18. ENVIRONMENTAL EFFECTS OF COAL PIPELINE
CONSTRUCTION ACTIVITIES (SOURCE: GR-177)
Activity
Environmental Effects
Mitigation Measures
(1) Clearing and
grading
(2) Ditching
Destroys wildlife habitat Revegetate quickly
Encourages runoff and Slow runoff
erosion Leave screening
Degrades esthetics vegetation
(3) Hauling and
Stringing Pipe
(4) Welding Pipe
(5) Coating Pipe
(6) Backfill
(7) Clean-up
(8) Testing System
Potential runoff from
spoil pile
Covering top soil may
produce rock rubble
Increased truck
traffic
None
Accidental spill of
coating materials
Extra top soil or
ditch "padding" soil
may be needed
Erosion of right-of-
way
Requires large volumes
of water
Close ditch as soon as
possible
Separate top soil and
set aside
Haul to appropriate
disposal site
Limit haul hours and
route
None
Normal care in operation
and availability of
cleanup materials
Use existing or properly
sited borrow pits
Adequate revegetation
program
Restore drainage
patterns
Monitoring of recovery
Careful selection of
water source and discharge
The risk of spills from coal slurry pipelines is considered to be
slight. The control and prevention of pipeline corrosion is a developed
technology because of extensive work with petroleum, natural gas, and other
underground pipeline systems. Particle attrition and significant pipeline
wear should be negligible in long-distance coal slurry pipelines because the
particles are in turbulent flow and in suspension rather than saltating along
the bottom of the pipe. No measurable particle attrition has been observed
with either the Consolidated Coal Company system or the Black Mesa pipeline
system (WA-127).
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TABLE 19: PRIMARY ENVIRONMENTAL ASPECTS OF COAL
SLURRY PIPELINE SYSTEMS
(SOURCE: GR-177)
SYSTEM COMPONENTS
ENVIRONMENTAL ASPECTS
MITIGATING MEASURES
Well water field and collection
system
Slurry preparation system
Possible changes in ground and
surface water use.
Possible land use changes.
Accidental water release.
Regulation of quantity and use of water
and coordinate water needs with existing
water use plans and policies.
Coordinate water use changes with exist-
ing regional land use plans and policies.
Develop back-up safety system.
Water pump station
Water supply pipeline
Coal cleaning system
Noise.
Power use.
Accidental water release.
Noise.
Water use.
Fugitive dust.
Power use.
Design and shield unit to minimize noise
Unavoidable.
Develop back-up safety system.
Design and shield unit to minimize noise
Design system to reduce water loss.
Design air pollution control system(s).
Unavoidable.
Noise.
Water use.
Fugitive dust.
Accidental slurry release.
Power use.
Design and shield unit to minimize noise.
Design system to reduce water loss.
Design air pollution control system(s).
Develop back-up safety system.
Unavoidable.
Slurry pipeline
Accidental slurry release.
Land clearing.
Develop back-up safety system.
Revegetate.
Slurry pump stations and
related facilities
Noise.
Water us"e.
Power use.
Accidental slurry release.
Slurry storage containment
failure.
Design and shield unit to minimize noise.
Design system to reduce water loss.
Unavoidable.
Develop back-up safety system.
Develop back-up safety system.
Dewatering system
Noise.
Fugitive dust.
Water use.
Power use.
Accidental slurry release.
Slurry storage containment
failure.
Water quality from dewater
process.
Design and shield unit to minimize noise.
Design air pollution control system(s).
Design system to reduce water loss.
Unavoidable.
Develop back-up safety system.
Develop back-up safety system.
Design storage and treatment facilities.
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TABLE 20. SECONDARY ENVIRONMENTAL ASPECTS OF
COAL SLURRY PIPELINES
(SOURCE: GR-177)
System Components
Environmental Aspects
Mitigating Measures
Coal Supply (Coal
Mining Development)
Water use.
Land use.
Socioeconomic change.
Regulate mining to meet
water use and water quality
standards.
Observe mined land re-
clamation rules .and
regulations.
Analyze community conditions
and recommend community
development strategies re-
lated to increased mineral
development.
Population Increase
Housing demand and com-
munity facility demand.
Inventory community capacity
and recommend housing and
community development
strategies.
Power Use
Economic and population
growth.
Analyze future regional
energy supply and demand
characteristics and recommend
regional economic and
population development
strategies.
Assessments of the environmental effects of coal slurry pipelines
have been made for a pipeline design of a specific capacity and a pipeline
module with an equivalent throughput of 1012 Btu/day (RA-150). A 1,000-
mile-long, 38-inch diameter pipeline is the example of a specific capacity;
this size also corresponds very closely to a projected pipeline between
Wyoming and Arkansas (EN-202). This size pipeline would be able to move
25 millions tons of Western United States coal per year. This is equivalent
to 1.21 x 1012 Btu/day of energy transported, based on a western coal heat-
ing value of 8806 Btu/lb. A coal slurry pipeline with an equivalent throughput
of 1012 Btu/day is approximately 83% as large.
The environmental effects of an electrically-operated coal slurry pipe-
line system were computed on the basis of the following major assumptions
(RA-150):
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(1) A 1,000-mile-long, 38-inch diameter pipeline with an
annual throughput of 25 x 106 tons of coal will be
used (CO-129, HU-088, EN-202, WA-127)
(2) One pumping station every 100 pipeline miles will be
installed (CO-129, HU-088)
(3) The required water (12 gallons/106 Btu) will be
available
(4) Electrical energy equivalent to 300 x 109 Btu/100
miles-year will be used (AU-019)
(5) The pipeline system will be operational 365-days/
year
(6) A heating value of 8806 Btu/lb for western coal
will be met
(7) A thermal efficiency reduction of about 2% will
occur as a result of the slurry water that remains
in the boiler feed (HI-090, SO-039).
Assumptions 1 through 6 were applied to the specific coal slurry pipeline
length called for in this study.
Some of the environmental effects of a 1,000-mile coal slurry pipeline
system will change with the length of the pipeline. The parameters that will
be affected are the ancillary energy and the land use. These parameters can
be adjusted for any desired length of the pipeline, using an approach outlined
in a previous report (RA-150).
The environmental effects of a 1,000-mile coal slurry pipeline and a
1012 Btu/day pipeline are summarized in TABLE 21 and discussed in the follow-
ing sections.
Land Use
A land use of 14,000 acres for a typical 1,000 mile, 38-inch diameter
coal slurry pipeline system includes acreage of several items, such as
those shown below in TABLE 22 (CO-197, HU-088).
The coal slurry pipeline module requires 1.02 x 104 acres of land
(RA-150).
With respect to land use, it should be remembered that the coal slurry
pipeline will be buried 2% to 3 feet underground.
Water Requirements
A typical coal slurry pipeline has a water requirement of 12 gallons
of water per million Btu delivered (EN-202).
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TABLE 21. SUMMARY OF ENVIRONMENTAL EFFECTS OF
ELECTRICALLY-OPERATED COAL SLURRY PIPELINES
(SOURCE: RA-150)
Air Emissions (Ib/hr)
Water Emissions (Ib/hr)
Thermal (Btu/hr)
Solid Wastes (tons/day)
Land Use (acres)
Water Requirements (gal/day)
Efficiency (%) (Primary)
Ancillary Energy (Btu/day)***
Estimated Design*
(1,000 Miles)
0
0
0
0
1.40 x 10"
1.45 x 107
98
8.22 x 109
Module
(1012 Btu/day**)
0
0
0
0
1.16 x
1.20 x
98
6.79 x
10"
107
109
* Based on an annual throughput of 25 x 10 tons of coal per year (1.2 x 10
Btu/day) and a 1,000-mile, 38-inch pipe.
** Module based on energy transported.
***In the form of electric energy transported.
12
TABLE 22. LAND USE REQUIREMENTS
FOR COAL SLURRY PIPELINE
Description of Use
Acres
Slurry Pipeline Right-of-Way
(104-foot right-of-way)
Coal Preparation Plant
Dewatering Plant
Slurry Pipeline Pump Stations
(10 stations)
Water Supply Gathering Pipeline
Right-of-Way
Water Supply Pump Station
Water Supply Wellhead Facilities
TOTAL
12,550
100
200
470
610
60
1£
14,000
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Air Emissions
Since a coal slurry pipeline system is electrically operated, it does
not directly produce any form of air emissions during its operation.
Water Emissions
Water used in the slurry transport is clarified and used as a part
of the terminal process or power plant make-up water requirements (AU-019,
CO-197, EN-140, EN-202, HU-088).
Experience gained from the Black Mesa coal slurry pipeline system
indicates that the clear water from the settling tank contains about 25
ppm of coal solids (SO-039). The water quality is the major factor con-
sidered in deciding whether to use the water for cooling tower make-up,
or ash handling, or to be discharged into evaporation ponds. The Black
Mesa coal slurry pipeline provides about 15% of the plant water require-
ments (WA-153, EN-202).
In view of the foregoing discussion, it is concluded that a coal slurry
pipeline does not discharge any form of pollutant that may degrade water
bodies.
Thermal Emissions
A coal slurry pipeline system in operation does not produce signifi-
cant thermal emissions.
Solid Wastes
Solid wastes in the form of coal solids of about 25 ppm in the clarified
water are ultimately discharged into the evaporation ponds. Since these
minute quantities of solid wastes are contained in the ponds, they do not
produce any adverse effects in the environment.
COAL GASIFICATION
The purpose of coal gasification is to convert an environmentally un-
acceptable fuel into a clean, convenient gas which when used as a fuel will-
not degrade environmental quality. Consideration must be given to the
environmental effects of gasification facilities which could be sizeable.
The potential emissions may be greater than 1,000 ton/day from a plant
producing 250 million scfd of SNG from high-sulfur coal (FE-068). There-
fore, it is important not to transfer the environmental impact of conventional
coal utilization facilities to that of coal gasification facilities. A
careful assessment of coal gasification techniques is needed while most
are still in the development stage. Information on the environmental im-
pact of coal gasification is currently rather limited and general.
In the following sections, possible pollutants from gasification pro-
cesses will be examined, high-Btu gasification, and low-intermediate-Btu
gasification will be discussed in general terms, and aspects of individual
processes will be discussed.
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Potential Pollutants
The major concerns of gasification processes thus far have been with
sulfur compounds and other criteria pollutants. However, the emissions of
various trace pollutants, both organic and inorganic, may have to be con-
trolled. The initial gasification step will largely determine the possible
pollutants, whatever their fate in subsequent processing steps. Coal pre-
paration, product processing, and on-site auxiliary fuel combustion will
also contribute to the total amount of pollution.
A previous study (CA-204) has compiled an extensive list of specifi-
cally identified, potentially hazardous materials which may be associated
with coal gasification. Potential pollutants were classified according to
their chemical species and their potential for harmful impact. The listing
is broken down into the different stages involved in gasification processes.
Potentially hazardous trace organics and trace elements are included as well
as more common species. It was determined that coal gasification is likely
to produce substances as dangerous as those produced by a coke plant, but
the substances produced by gasification will probably be more contained.
It was also found that the quenching and cooling of gasifier off-gas and
the tar separation unit are the most important potential sources of toxic
emisssions in a coal gasification plant.
The thermal treatment of coal causes the formation of numerous organic
compounds, many of which are potentially hazardous. For example, coke ovens
thermally treat coal and emit several types of polynuclear aromatics, such
as benzopyrene. The possible formation and fate of such organic compounds
in gasification plants is largely unknown. Coal also contains many types of
trace elements. The fates of the trace elements are not well established.
Gas streams in gasification facilities may contain sulfur dioxide,
hydrogen sulfide, nitrogen oxides, ammonia, carbon monoxide, hydrocarbons,
hydrogen cyanide, particulates, and odorous compounds. Process water streams
may contain phenols, cresols, light aromatics (e.g. benzene-toluene-zulene
compounds), oils, tars, ammonia, sulfur compounds, hydrogen cyanide, coal
char, ash, and high molecular-weight organics.
The total quantity of potential emissions within major chemicals cate-
gories is illustrated below for a gasification plant producing 250 million
scfd of pipeline gas from Illinois No. 6 coal (3.7% sulfur). Ranges are
indicated because of variations between the different gasification processes
and because of uncertainties in some yields (FE-068).
Sulfur (primarily as H2S) 300-450 long tons/day
Ammonia 100-150 tons/day
Hydrogen Cyanide 0 to possibly 2 tons/day
Phenols 10-70 tons/day
Benzene 50-300 tons/day
Oils and Tars Trace to 400 tons/day
Mercury Less than 5 Ib/day
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Gasification operations produce a high-ash content residue of 1,000 to
3,000 ton/day or a char remainder of 4,000 to 5,000 tons/day. The C02 Accep-
tor Process will also contribute about 900 tons/day of spent dolomite.
The gasification of coal takes place in a closed system, which makes
it easier to prevent the emission of pollutants to the atmosphere or water
(NA-183). However, associated operations (e.g., coal handling and processing,
gas purification, ash handling and disposal), presence of toxic pollutants,
and fugitive emissions create potential environmental hazards and must be
considered. The nature and magnitude of the pollution problems will depend
on the coal to be used, its sizing, the disposition of fumes and dust, the
gasification technique involved, and the pollution controls used.
Air Emissons
Because coal gasification occurs in a closed system, it should be easier
to control the emission of pollutants to the atmosphere. However, processing
steps, auxiliary equipment, and fugitive emissions present possibilities for
air emissions, and it is important to know the possible gaseous compounds.
Important sources of emissions are fugitive losses from the gasification
and processing steps. Fugitive emissions escape from sources such as valve
stems, flanges, loading racks, equipment leaks, pump seals, sumps, etc. Be-
cause gasification facilities are closed systems the fugitive losses may be
the major source of emissions. Gasification processes also operate under
pressure which increases the potential for fugitive emissions. The assessment
of fugitive emissions is difficult because there is no operating experience
with gasification plants on the commercial scale envisioned for future use.
Sulfur dioxide, nitrogen oxides, particulates, and carbon dioxide will
be the major emissions to the air. Sulfur dioxide emissions can come from
the sulfur recovery plant tail gas and the stack gases of auxiliary combustion
systems. In some instances it may be necessary to clean these stack gases by
scrubbing, depending on the sulfur content of the combusted material. Emis-
sions of nitrogen oxides are a result of fuel combustion in boilers and process
heaters. Particulate matter can enter the atmosphere as fugitive dust from
coal handling operations or as stack gas emissions from combustion or pro-
cess unit operation. Carbon dioxide is also emitted to the air from the pro-
cessing operations. Hydrocarbon emissions occur by evaporation of hydrocarbon
liquid dissolved in liquid waste or in cooling streams, fugitive emissions,
and incomplete combustion at auxiliary plant facilities. Carbon monoxide,
although produced in large quantities during gasification, is principally
emitted because of incomplete combustion in auxiliary facilities.
In addition to the large quantities of H2, CO, C02, CHi, and ethane
(C2H5) made in the gasifier, a number of trace components also occur and are
of interest. Sulfur compounds formed during all gasification processes are
hydrogen sulfide, carbonyl sulfide, carbon disulfide, thiophenes, and mercaptans.
Hydrogen sulfide is the predominant sulfur species. Light weight benzene-toluene-
xylene (BTX) components are also formed. TABLE 23 gives the concentrations of
these components in the gas stream of a Synthane gasifier (FO-026). Although
these compounds should be removed in the processing steps, they may be dis-
charged to the air by fugitive emissions, incomplete stripping of the process
-104-
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TABLE 23. COMPONENTS IN GASIFIER GAS, PPM (SOURCE: FO-026)
H2S
Carbonyl sulfide (COS)
Thiophene
Methyl thiophene. ....
Dimethyl thiophene...
Benzene.
Toluene
C$ aroraatics
so?
Carbon disulfide(CS2)
Methyl mercaptan. ....
Illi-
nois
No. 6
Coal
9,800
150
31
10
10
340
94
24
10
10
60
Illi-
nois
Char
186
2
.4
.4
.5
10
3
2
1
.1
Wyoming
Subbi-
tumi-
nous
Coal
2,480
32
10
-
434
59
27
6
.4
Western
Kentucky
Coal
2,530
119
5
—
100
22
4
2
33
North
Dakota
Lignite
1 750
65
13
11
1,727
167
73
10
10
Pitts-
burgh
Seam
Coal
860
11
42
7
6
1 050
185
27
10
8
/B\
TABLE 24. RECTISOL OFF-GAS COMPOSITION (SOURCE: CA-161)
Component
C02
H2S
Ethene (C2H4)
CO
H2
CIU
C2H6
Nitrogen (N2) + argon (Ar)
TOTAL
Mol %
97.63
0.75
0.24
0.07
0.43
0.56
0.32
-
100.00
Registered Trademark
-105-
-------
exhaust streams, and evaporation from scrubbing water at cooling towers. TABLE
24 gives the approximate composition of the off-gas from the Rectisol® solvent
regeneration section in El Paso's Burnham coal gasification complex (CA-161).
This illustrates that some hydrogen sulfide is still emitted to the atmosphere.
Nitrogen in the coal is responsible for the formation of compounds such
as ammonia and hydrogen cyanide which are found in both the gaseous and liquid
processing streams. Other gaseous compounds of interest are hydrogen chloride,
hydrogen fluoride, trace elements that vaporize, and trace organics. The
latter two groups of species will be discussed elsewhere. Ammonia, hydrogen
cyanide, hydrogen chloride, and hydrogen fluoride should be removed by scrubbing.
But they may be emitted by evaporation from cooling or scrubbing liquors in
which they are dissolved or from fugitive emissions.
Water Effluents
Process wastewater treatment and subsequent handling represent one of
the major problem areas in meeting environmental requirements. Environmental
objectives are to be met by so-called "zero discharge" operations. This requires
that the gasification facilities treat their process water for reuse or send it
to lined solar evaporation ponds for disposal. Therefore, no liquid effluents
should leave the boundary of the gasification plant.
Gasification processes are net consumers of water and, ideally, all
streams could be recycled for use in the process. Effluent streams occur in
practice because it is often technically or economically unfeasible to recycle
all wastewaters consumptively, and to control all stream flows to yield the
stoichiometric water requirement.
Principal pollutants in the effluent streams are hydrogen sulfide.,
ammonia, hydrogen cyanide, phenols, benzenes, and oils. In a proposed com-
plex, 320 gallons per minute (gpm) of condensate from the gasifier is separated
because of its high halogen, phenol and other organic compound concentrations
and is sent to solar evaporation ponds. The high solids condensate is estimated
to contain a high percentage of the chloride and fluoride in the coal (CA-161).
A good example of the condensate from a gasification process is given
in TABLE 25 for the by-product water analysis from Synthane gasification.
TABLE 26 gives an analysis of the trace elements in the water effluent for
one type of coal in the Synthane process (FO-026).
Tars and oils are separated from wastewater by specific gravity; other
organics such as phenols must be solvent extracted from the wastewater. TABLE
27 gives the analysis of tars obtained during Synthane gasification (FO-026).
Solid Wastes
Coal gasification processes produce large quantities of solid wastes.
Most solid waste is due to the ash content of the coal and the sulfur removal
processes.
Trace Organics
The coal gasifier output may contain all of the products commonly
Registered Trademark
106
-------
TABLE 25. BY-PRODUCT WATER ANALYSIS FROM SYNTHANE GASIFICATION
OF VARIOUS COALS [rag/liter, EXCEPT pH] (SOURCE: FO-026)
Coke Illinois Wyoming Illi- North Western Pittsburg
Plant No. 6 Subbi- nois Dakota Ken- Seam
Coal tumi- Char Lignite tucky Coal
nous Coal
Coal
pH
Suspended Solids
Phenol
Chemical Oxygen
Demand
Thiocyanate
Cyanide
Chloride
Carbonate
Bicarbonate
Total Sulfur
9
50
2,000
7,000
1,000
100
5,000
_
_
—
-
8.6
600
2,600
15,000
152
0.6
^lOO
500
26,000
211,000
31,400
8.7
140
6,000
43,000
23
0.23
9,520
-
-
-
-
7.9
24
200
1,700
21
0.1
2,500
31
-
-
-
9.2
64
6,600
38,000
22
0.1
7,200
-
-
-
-
8.9
55
3,700
19,000
200
0.5
10,000
-
-
-
-
9.3
23
1,700
19,000
188
0.6
11,000
-
-
-
-
1 85 percent free «^3.
2 Not from same analysis,
S
sol
400
300
S203
1,400
1,000
associated with pyrolysis, carbonization, and coking of coals in addition to
oxygenated products associated with partial combustion. Several classes of
compounds may be present. Various heavier organic compounds may be classified
as tar (including phenols, cresols, pyridines, anilines, catechols), inter-
mediate and high-boiling aromatics (naphthalenes), saturates, olefins, and
thiophenes. Another group of organic compounds might be designated light oil
and/or naphtha, including BTX, naphthalene, thiophene and condensable light
hydrocarbons and disulfide carbon.
In a study of the effluent from an experimental coal gasification plant,
certain organic components were extracted and tentatively identified. TABLE
28 lists these components. The particular distribution of organic compounds
in raw gasifier gas will depend on the composition of the feed coal and the
operating conditions of the gasifier.
At this time, conclusions as to the ultimate fate of trace organics in
coal gasification plants must generally be estimates based on the composition
of the coal, processing conditions, and data on actual emissions from processes
such as boilers or coke ovens.
Processing conditions will affect trace organic effluents from a coal
gasifier. The temperature and pressure in the gasifier and associated equip-
ment could influence the fate of trace organics since the two major sources of
trace organics are those originally present in the coal and released through
-107-
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TABLE 26. TRACE ELEMENTS IN CONDENSATE FROM AN
ILLINOIS NO. 6 COAL GASIFICATION TEST (SOURCE: FO-026)
Parts per million (ppm) :
Calcium
Iron
Magnesium
Aluminum
Parts per billion (ppb) :
Selenium
Potassium
Barium
Phosphorus
Zinc
Manganese
Germanium
Arsenic
Nickel
Strontium
Tin
Copper
Columbium
Chromium
Vanadium
Cobalt
Sample
No. 1
4.4
2.6
1.5
0.8
401
117
109
82
44
36
32
44
23
33
25
16
7
4
4
1
Sample
No. 2
3.6
2.9
1.8
0.7
323
204
155
92
83
38
61
28
34
24
26
20
5
8
2
2
Average (by weight)
4
3
2
0.8
360
160
130
90
60
40
40
30
30
30
20
20
6
6
3
2
volatilization or leaching, and those formed by chemical reaction. For
example, cracking of the hydrocarbons might occur in gasifiers operating at
higher temperatures and pressures.
The results of the study of coke oven emissions indicate the presence of
carcinogenic organic compounds in relatively heavy concentrations in the tar.
Several classes of organic compounds are present in the tar from both a coke
oven and a gasifier. Coke ovens also operate in the same temperature range
as some gasification processes, but at a much lower pressure. Some of the
hazardous hydrocarbons present in coke oven tar might also be present in
gasifier tar since some similarities exist between the processes and contents
of the tars.
Sampling and analyses, of bench-scale Synthane gasifier effluents in-
dicate trace organics might be present in the gasifier gas, tar, and by-product
water streams. However, although these effluent streams are reported to be
representative of those which will be obtained from a commercial operation,
the applicability of this data to a commercial operation has not been proven.
Some potentially hazardous trace organics will probably be emitted by a coal
gasification process, but the ultimate fate of trace organics cannot be
assessed at this time.
-108-
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TABLE 27. MASS SPECTROMETRIC ANALYSES OF THE
BENZENE-SOLUBLE TAR, VOLUME-PERCENT
(SOURCE: FO-026)
Structural type
(includes alkyl
derivatives)
Benzenes
Indenes
Indans
Naphthalenes
Fluorenes
Acenaphthenes
3-ring aromatics
Phenylnaphthalenes
4-ring pericondensed
4-ring catacondensed
Phenols
Naphthols
Indanols
Acenaphthenols
Phenanthrols
Dibenzofurans
Dibenzothiophenes
Benzonaphtho thiophenes
B-heterocyclics
Run HP-1
No. 92,
Illinois1
No. 6 coal
2.1.
28.6
1.9
11.6
9.6
13.5
13.8
9.8
7.2
4.0
2.8
(2)
.9
-
2.7
6.3
3.5
1.7
(10.8)
Average molecular weight 212
Spectra indicate traces of 5-ring
2 Includes any naphthol
3Data on N-free basis
present (not
since isotope
Run HPL
No. 94,
lignite
4.1
1.5
3.5
19.0
7.2
12.0
10.5
3.5
3.5
1.4
13.7
9.7
1.7
2.5
-
5.2
1.0
-
(3.8)
173
aromatics .
resolved in
corrections
Run HPM No. Ill,
Montana
subbituminous
coal
3.9
2.6
4.9
15.3
9.7
11.1
9.0
6.4
4.9
3.0
5.5
9.6
1.5
4.6
.9
5.6
1.5
-
(5.3)
230
these spectra) .
were estimated.
Run HP-118
No. 1181,
Pittsburgh
seam coal
1.0
26.1
2.1
16.5
10.7
15.8
14.8
7.6
7.6
4.1
3.0
(2)
.7
2.0
—
4.7
2.4
—
(8.8)
202
Trace Elements
Although several potentially hazardous pollutants exist in coal only in
trace amounts, gasification facilities will be processing 15 to 25 thousand
tons of coal per day, which makes it necessary to investigate trace element
species during gasification.
A gasification facility producing 15 to 20 trillion cubic feet of methane/
year would require over one billion tons of coal/year. This conversion process
could result in the production of the following trace elements in pounds/year:
arsenic, 28 million; cadmium, 2 million; lead, 20 million; manganese, 108 million;
mercury, 400 thousand; and nickel, 30 million (RH-008). These quantities could
be emitted in concentrated areas.
Published data on the fate of trace elements in coal gasification systems
-109-
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TABLE 28. COMPOUNDS TENTATIVELY IDENTIFIED IN WASTE
EFFLUENTS OF COAL GASIFICATION PILOT PLANT
(SOURCE: MC-130)
Restructured
Gas
Chromato graph
Peak Best Match Second Best Match
1 Phenol Phenol
2 £-Cresol m-Cresol
3 m-Cresol £-Cresol
4 2,5-Dimethylphenol 2,6-Dimethylphenol
5 3,4-Dimethylphenol 3,4-Dimethylphenol
6 2,4-Dimethylphenol 3,4-Dimethylphenol
7 a-Naphthol 1,2-Dihydroxy-
1,2-Dihydro-
naphthalene
is limited. Attari (AT-042) has reported some data for the HYGAS pilot plant.
The concentrations of 11 trace elements were measured in the solid streams en-
tering and leaving each of the 3 stages of the HYGAS pilot plant.
Because the pilot plant was not operational during the period when the
analytical work was performed, coal and char samples accumulated over several
years of bench-scale research were used in the analysis. The emphasis of the
project was placed on trace element analytical methods since sampling and
operating criteria of the pilot plant were not discussed. The relative
amounts of the trace elements found in the raw feed coal and the spent
char from the gasifier are presented in TABLE 29. The loss values represent
the removal of the trace elements from the solid streams. The data indicate
substantial removal of mercury, selenium, arsenic, tellurium, lead, and
cadmium from the coal during the gasification process. Most of the antimony,
vanadium, nickel, and beryllium, and all of the chromium remained in the solid
phase. Certain trace elements were definitely lost from the residue during
gasification, but it was not known into which effluent stream the elements
entered (AT-042).
As indicated earlier, trace elements were analyzed in the condensate
from the Synthane gasifier. The data are presented in TABLE 26. Other trace
elements analyses of the Synthane process performed on the gas and tars for
hydrogen cyanide, arsenic, and mercury are presented in TABLE 30. The mercury
was present in the gasifier gas but not in the final high-Btu gas product. The
mercury and arsenic in the tars will probably enter the stack gas if the tar
is burned (FO-026).
-110-
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TABLE 29. LOSS OF TRACE ELEMENTS FROM SOLID PHASE
DURING HYGAS GASIFICATION (SOURCE: AT-042)
Element
Hg
Se
As
Te
Pb
Cd
Sb
V
Ni
Be
Cr
Percent Lost
96
74
65
64
63
62
33
30
24
18
0
Note: Coal-feed was Pittsburgh No. 8 bituminous coal.
TABLE 30. TRACE COMPONENTS IN GAS AND TAR (SOURCE: FO-026)
Gas (by volume) Tar (by weight)
HCN, ppb Mercury, ppm Mercury, ppm Arsenic, ppm
Illinois Char
Illinois No. 6 Coal
Western Kentucky Coal
North Dakota Lignite
5
20 0.00001 0.003
11
3 — —
_
0.7
-
_
Wyoming Subbituminous Coal
The trace elements of primary concern in coal gasification are the follow-
ing:
antimony chromium selenium
arsenic copper sulfur
barium fluorine tellurium
berryllium lead uranium
boron mercury vanadium
cadmium molybdenum zinc
chlorine nickel
-111-
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The chemical forms and ultimate fate of trace elements leaving the
gasifier need to be known.
High-Btu Gasification
The data in this section summarize the impacts of a representative
high-Btu coal gasification process producing 1012 Btu/day of gaseous product
(RA-150).
The SNG-from-coal module emissions and impact are developed using two
coal feeds, a western subbituminous coal and an Illinois coal. Where dif-
ferences occur in the module due to the different coal feeds, both situations
are explained. Otherwise, a general SNG-from-coal module is characterized.
TABLE 31 summarizes the emissions and impact of SNG-from-coal plants which
utilize Western and Illinois coal.
TABLE 31. ENVIRONMENTAL IMPACT OF SNG-FROM-COAL
(SOURCE: RA-150)
(BASIS: PRODUCTION OF 1012 Btu/DAY OF SNG)
Impact
Western Coal
Illinois Coal
Air (Ib/hr)
Particulates
S02
N0y
cox
HC
NH3
Water (Ib/hr)
Suspended Solids
Dissolved Solids
Organic Material
Thermal (Btu/hr)
Solid Wastes (tons/day
Coal Requirements (tons /day
Water Requirements (gal/day)
727
1,800
7,110
377
115
34.7
0
0
0
Negligible
5,560
83,000
25 x 105
944
10,400
7,770
414
126
54.7
0
0
0
Negligible
7,930
66,900
25 x 106
ing:
The nine processing steps in Radian's SNG-from-coal module are as follow-
(1) coal pretreatment and thermal drying
-112-
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(2) gasification
(3) cooling and solids removal
(4) catalytic shifting
(5) acid gas removal
(6) sulfur recovery
(7) catalytic methanation
(8) ammonia recovery
(9) product drying and compressing.
An auxiliary boiler, a steam superheater, a water treatment unit,
oxygen plant and ammonia and sulfur storage facilities are required in SNG-
coal processing. Specific processes are assumed for some of the processing
units, although there are other alternatives available which could meet the
process requirements. These alternatives should, however, exhibit environ-
mentaly similar impacts.
Land Use
Land requirements for an SNG-from-coal plant may include areas for
processing equipment, coal storage, solar evaporation ponds and solid waste
disposal. It has been estimated that 165 acres are required for a plant cap-
able of producing 236 x 109 Btu/day of SNG (AI-013). On a 1012 Btu/day basis,
plant land requirements are 700 acres. The amount of land needed for evapora-
tion ponds will depend upon the plant's geographic location and the pan
evaporation rates of the region. Additional land may have to be used for dis-
posal of solid wastes if these wastes cannot be returned to the mine for dis-
posal. Based on an assumed solid waste density of 150 lb/ft3, 30-foot high
storage piles and a 30-year lifetime of the plant, 580 additional acres are
required for a western coal feedstock and 820 additional acres are required
for an Illinois coal feedstock (RA-150).
Air Emissions
Air emissions for the SNG-from-coal module come mainly from the second-
ary parts of the system. The auxiliary boiler, steam superheater, coal dryers
and sulfur recovery system account for almost all of the emissions. None of
the gasification train units should emit any pollutants directly to the air.
There may, however, be fugitive emissions.
Water Emissions
Liquid wastes from an SNG-from-coal plant producing 275 x 109 Btu/day
of SNG are emitted at the rate of 450,000 Ib/hr or 900 gallons per minute (gpm)
(EL-052). On a 1012 Btu/day basis approximately 1,640,000 Ib/hr of liquid
wastes are produced. These wastes contain high levels of dissolved solids,
hazardous organic and trace inorganic compounds, and possible carcinogenic,
organic species (RA-150).
-113-
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Because of the presence of these hazardous compounds in a gasification
plant's liquid wastes, these facilities are assumed to operate in a so-called
"zero liquid discharge" manner. Therefore, provisions must be made to
safely dispose of these wastes or incorporate them in a total water recycling
plan. At the present time, the exact composition of these liquid wastes is
not known. Thus, possible schemes for treating and recycling wastewater have
not been devised.
Where possible, solar evaporation ponds will be used. Wastex^ater from
primary water treatment, boiler blowdown, cooling tower blowdown and other
contaminated streams are sent to these evaporation ponds. Since these streams
contain high levels of dissolved solids and other pollutants such as phenols,
the ponds are lined to prevent leakage of pollutants into underground water
tables. In areas where evaporation ponds are not feasible, the liquid wastes
must be treated and reused.
Solid Wastes
Solid wastes from an SNG-from-coal plant include ash, primary water
treatment sludge and wastes from the ammonia recovery unit. Any sludges re-
sulting from biological treatment of liquid streams can probably be used as
fuel for the auxiliary boiler. The amounts of coal ash and slag produced
are calculated from coal rates and compositions. The amount of particulates
emitted to the air is subtracted from the total ash present in the coal feed.
Ammonia still wastes are assumed to be 115 tons/day for a plant capable of
producing 250 x 109 Btu/day of SNG (HI-083). This is then scaled to an out-
put of 1012 Btu/day of SNG. The amount of primary water treatment sludge is
calculated from (1) intake water requirements, (2) the assumption that 500
parts per million (ppm) of suspended solids are present in the make-up, and
(3) all suspended solids are removed by chemical treatment.
The SNG-from-coal plant is assumed to be a mine-mouth operation and,
hence, all solid wastes are expected to be disposed of as mine fill.
Thermal Discharges
Thermal discharges into water bodies are eliminated by utilizing wet
cooling towers. If an adequate supply of water is not availble, air cooled
condensers could replace cooling towers.
Low-Btu Gasification
The data in this section, developed in a previous study (RA-150), sum-
marize the impacts of a representative low-Btu gasification process.
Low-Btu gasification module emissions and impacts are developed using
two coal feeds, a western subbituminous coal and an Illinois coal. Air is
assumed to be utilized in the gasifier as the source of oxygen for the low-
Btu gasification module. TABLE 32 summarizes the emissions and impacts of
low-Btu gasification plants which utilize western and Illinois coal.
Medium-Btu gasification module emissions are developed using only a
western coal. In this analysis, the medium-Btu and low-Btu processes differ
-114-
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only in the manner in which oxygen is supplied to the gasifier. For medium-
Btu gasification, 98%+ oxygen is the oxygen source. If not specifically
mentioned in a section, medium-Btu gasification process features can be
assumed to be those defined for the low-Btu gasification of western coal.
TABLE 33 is a summary of the emissions and impacts of a medium-Btu gasifi-
cation plant using western coal.
TABLE 32. ENVIRONMENTAL IMPACTS OF LOW-BTU COAL GASIFICATION
(Source: RA-150)
(Basis: Production of 1012 Btu/day of Low-Btu Fuel Gas)
Impacts
Air (Ib/hr)
Particulates
S02
NO
cox
HC
NH3
Western
Coal
0.86
580
1130
32..3
32.6
56.8
Illinois
Coal
0.86
2250
1130
32.3
32.5
45.4
Water (Ib/hr)
Suspended Solids
Dissolved Solids
Organic Material
Thermal (Btu/hr)
Solid Wastes (tons/day)
Water Requirements (gal/day)
Coal Requirements (tons/days)
0
0
0
0
0
0
negligible negligible
5350 7320
11 x 106 11 x 106
74,900 60,000
The processing units for Radian's low-Btu gasification module consist
of the following:
(1) coal pretreater
(2) gasifier
(3) solids and liquids removal
(4) acid gas removal and sulfur recovery.
In addition, an auxiliary boiler, gas liquor treater, ammonia recovery unit
and storage facilities are included.
-115-
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TABLE 33. ENVIRONMENTAL IMPACTS OF MEDIUM-BTU GASIFICATION
OF WESTERN COAL (Source: RA-150)
(Basis: Production of 1012 Btu/day of Medium-Btu Fuel Gas)
Air (Ib/hr)
Particulates
S02
NO
x
CO
HC
NH3
0.86
568
1130
32.3
32.6
54.8
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr) negligible
Solid Wastes (tons/day) 5200
Water Requirements (gal/day) 13 x 106
Coal Requirements (tons/day) 74,400
Air Emissions
Air emissions from a low-Btu gasification system come from the sulfur
recovery unit, the auxiliary boiler, storage facilities, and fugitive emissions,
Water Emissions
Water pollutants are considered to be nonexistent due to the use of
solar evaporation ponds. Wastewater from primary water treatment, cooling
tower blowdown and other contaminated streams are sent to these evaporation
ponds. Since these blowdown streams contain high levels of dissolved solids
and other pollutants, such as phenols, the ponds are lined to prevent leakage
of pollutants into underground water.
Solid Wastes
Solid wastes from a low-Btu gasification plant consist of coal ash,
primary water treatment sludge, ammonia-still wastes and limestone scrubber
sludge.
If the gasification plant is a mine-mouth operation, all solid wastes
would be disposed of as mine fill. If the gasification plant is not a mine-
mouth operation, then provisions must be made to dispose of the solid wastes.
Thermal Discharges
Thermal discharges to water bodies are eliminated by utilizing wet
-116-
-------
cooling towers. If an adequate supply of water is not available, air cooled
condensers could replace wet cooling towers.
Specific Gasification Processes
The previous discussions were generally applicable to all gasification
processes. There is a limited amount of information on the environmental
aspects of specific gasification processes. The Environmental Protection
Agericy has a series entitled "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes" which includes studies of several gasification pro-
cesses (KA-142, JA-090, JA-121, MA-294, SH-149). Reports in this series
define input and effluent streams and their compositions, examine pollution
control facilities, suggest modifications in technology, and provide mass
and energy balances. Some environmental aspects of various processes are
discussed below.
The environmental aspects of SNG production by Lurgi coal gasification
have been discussed in a report by EXXON Research Corporation (SH-149), in the
environmental impact statements for the proposed El Paso and Wesco facilities,
and in discussions by Berty (BE-218) and Cameron (CA-161).
The gas stream leaving the Lurgi gasifier contains coal dust, naphtha,
phenol, ammonia, tar, tar oil, ash, char, and other constituents (SH-149).
Possible air emissions include nitrogen oxides, sulfur dioxide, hydro-
gen sulfide, other possible sulfur-containing species, particulates, carbon
monoxide, hydrocarbons, ammonia, hydrogen fluoride, and trace elements. The
nitrogen oxides result from fuel combustion processes in the superheater/
incinerator, the power plant and associated equipment. The sulfur dioxide
comes from the boiler, gas turbines, and other combustion equipment at the .^
gasification plant. Other sulfur species will be released from the Rectisol^
plant and by fugitive emissions. Large quantities of water vapor will also
be emitted. Although not a pollutant, water can cause problems by fog forma-
tion or through reactions with other emissions (SH-149).
Control of water pollution is a major problem at Lurgi gasification
plants. The plants are designed for zero water effluents so that no water
is released beyond the plant boundaries. The major sources of water pol-
lution are ammonia, phenols, organic by-products, hydrogen sulfide, hydrogen
cyanide, hydrogen fluoride, carbon dioxide, fatty acids, biological oxygen de-
mand, and suspended solids. Soluble phenols are removed by the Phenolsolvan*-
process. Inorganic compounds are removed by sour water treatment. Biological
treatment is used to remove fatty acids, biological oxygen demand, and suspended
solids. Even after extensive treatment, trace amounts of some species such as
organic by-products may still remain. Traces of carcinogenic organic materials
could enter the environment in the water spray from cooling towers (SH-149).
Due to a lack of direct information, the fate of trace elements in a
Lurgi gasification plant is unknown. Most of the trace elements will pro-
bably end up in the ash, but the more volatile trace elements may be quenched
and end up in the gas liquor system or may be adsorbed on particulate matter
Registered Trademark
-117-
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and emitted. Trace metals may be present as elements, inorganic compounds, or
organic compounds. The range of trace elements that can be produced in a 2500-
million stdft3 Lurgi gasification plant using Navajo coal is shown in TABLE 34.
In addition to trace elements, other trace pollutants may be heavy, condensed
ring aromatic compounds that are either present in the coal or formed during
the conversion process.
TABLE 34. RANGE OF TRACE ELEMENTS FOR 250 MILLION
STDFT3 GASIFICATION PLANT (SOURCE: SH-149)
Trace Elements
Antimony
Arsenic
Bismuth
Boron
Bromine
Cadmium
Fluorine
Galium
Germanium
Lead
Mercury
Nickel
Selenium
Zinc
Minimum
(Ib/hour)
0.65
0.22
0.00
130
0.86
0.43
432
1.1
0.13
3.0
0.43
6.5
0.17
2.4
Maximum
(Ib/hour)
2.6
6.5
0.43
324
0.9
0.86
1690
17
1.1
8.6
0.76
65
0.45
58
ROUNDED TOTAL 580 2,200
Koppcra-Totzek
Compared to other coal conversion processes, the Koppers-Totzek coal
gasification plant is very clean. Problems with objectionable and hazardous
organic compounds are circumvented because the extreme gasifier temperatures
are not conducive to the formation of organic compounds. Only minute quanti-
ties of organics are expected to form. Gasifier effluent streams will contain
sulfur compounds (COS, H2S, CS2, S02), ammonia, cyanide, and trace elements.
No gaseous streams are released to the atmosphere from the gasifier.
The major air effluent streams are the slag quench and gas-cooling
system cooling towers, treated sulfur recovery tail gas and utility boiler
flue gas. The cooling towers associated with the slag quench and gas cooling
systems are expected to emit dissolved gases picked up from the gasifier
product gas. These gases may include carbonyl sulfide (COS), H2S, CS2, S02,
NHa, and HCN. The treated tail gas from the sulfur recovery unit will contain
100 parts per million volts (ppmv) of sulfur species, which are predominantly
-118-
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COS, and 10 pprav H2S. Utility boiler flue gas is expected to contain
particulates, N02, and S02 at levels near the national standard. The flue
gas will also contain some trace elements introduced with the coal. Studies
have identified very small quantities of polynuclear compounds in the flue
gas of coal-fired boilers.
In TABLE 35, the gas analyses at various processing stages indicate
the possible contaminants and their concentrations (FA-024).
TABLE 35. GAS ANALYSES (EXPRESSED IN VOLUME PERCENT)
IN KOPPERS-TQTZEK PLANT (SOURCE: FA-024)
Component
CO
C02
'CHi,
H2
N2
H2S
COS
HCN
NH3
H20
Ar
S02
NO
Particulates
(g/scf)
Gasif ier
Outlet
37.36
7.13
0.08
25.17
0.30
0.23
178 ppmv
288 ppmv
0.17
29.19
0.32
22 ppmv
7 ppmv
11.57
To Compression &
Acid Gas Removal
49.50
9.42
0.11
33.35
0.40
0.30
235 ppmv
300 ppmv
0.22
6.20
0.42
15 ppmv
7 ppmv
<0.002
Product
Gas
53.16
9.44
0.12
36.51
0.44
3 ppmv
1.5 ppmv
1 ppmv
1 ppmv
160 ppmv
0.46
0.5 ppmv
3 ppmv
<0.002
The most significant aqueous effluent stream is the ammonia cooler
condensate containing approximately 70 weight percent water and 30 weight
percent methanol. Water analyses of the various gas cooling and cleaning
steps can be found in reference FA-024.
The gasifier fly ash and gasifier slag sludges are expected to contain
the bulk of the trace elements. These sludges will also contain dissolved
sulfur compounds, ammonia, and cyanides. Fly ash, slag, and waste limestone
sludge from the utility boiler are expected to contain trace elements and
polynuclear organics generated from coal combustion.
BI-GAS
The BI-GAS Process produces no appreciable amounts of tar, naphtha,
or phenols (JA-121). The principal by-products are ammonia, sulfur and
slag. Carbonyl sulfide, carbon disulfide, thiophene, and hydrogen sulfide
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must be removed from the product gas. For each 12,000 tons of coal gasified
per day, 844 tons of slag will be produced (GR-109). The slag, the exact
nature of which is unknown, poses a disposal problem. Ammonia which can be
stripped by conventional means is the principal contaminant in the process
water.
C02 Acceptor
The C02 Acceptor Process is for use on low-sulfur western coals. At
least one-half of the sulfur release within this process occurs at a point
different from that in any other coal gasification process. Coal ash and
spent dolomite acceptor, which exit overhead from the regenerator vessel,
carry bound sulfur. The calcium content of the lignite and the lime portion
of the dolomite bind much of the sulfur as calcium sulfide. Before burial
in the mine area, these spent materials must be stabilized by treating them
with water and carbon dioxide to displace hydrogen sulfide and form calcium
carbonate. The carbon dioxide can be from the carbon dioxide/hydrogen sulfide
scrubbing system. Thus, both the gas streams which contain hydrogen sulfide
can go to the sulfur recovery plant (FE-068).
Effluent from the sour water stripper will contain traces of phenols,
tar, and naphthalene which must be removed. Small amounts of trace elements
may also volatilize in the gasifier effluent (JA-090). The principal environ-
mental problem with the C02 Acceptor Process is the disposal of spent dolomite.
Synthane
From an environmental standpoint, the Synthane Process is perhaps the
most studied of all the gasification schemes. Environmental studies have
been performed in conjunction with the engineering development (FO-026, FO-040,
KA-142). Analyses of the tar, chars, gases, and water in the effluent streams
are listed in TABLES 25, 26, 27, 28, and 30. These results are for bench-
scale experiments. The prototype plant is now operating and initial results
on the trace elements, are available (FO-040). The Synthane Process produces
a substantial quantity of char.
COAL LIQUEFACTION
As in coal gasification, one of the concerns of coal liquefaction is
that, in the attempt to convert coal to a clean liquid fuel, sizeable en-
vironmental impacts are not transferred from conventional coal utilization
facilities to liquefaction plants. Coal liquefaction facilities will process
less coal than gasification plants but will still have the potential for a
sizeable impact. Important considerations in determining the impacts of a
coal liquefacation facility are the composition of the coal processed and the
effects of operating conditions on the chemical formation of possible pol-
lutant species.
The Ralph M. Parsons Company has defined some of the environmental
factors in designing a 10,000 tons/day coal liquefaction plant (OH-006,
PA-139). Such a plant would produce two low-sulfur fuels, some naphtha,
and by-product sulfur. Figure 52 (OH-006) gives the overall material balance
of the liquefaction plant and shows the waste streams.
-120-
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Principal gas streams are from the oxygen plant, C0_-removal unit, sulfur-
removal unit and auxiliary equipment. Sulfur dioxide occurs in sulfur plant
tail gas and in emissions from auxiliary combustion. Nitrogen oxides, carbon
monoxide, and hydrocarbons are caused by incomplete combustion in utility
systems. Carbon dioxide and small amounts of hydrogen sulfide are also emitted
to the atmosphere. Approximately one billion cubic feet/day of various gas
streams are exhausted to the atmosphere (OH-006).
WASTE GAS 19,430 TONS/DAY
COAL 10,000 TONS/DAY
OXYGEN (FROM AIR)
1980 TONS/DAY
WATER
21,760 TONS/DAY
t
LIQUEFACTION
PLANT
I
LIQUID BOILER FUEL
(0.2% S) 1440 TONS/DAY
HEAVY LIQUID BOILER FUEL
(0.5% S) 2920 TONS/DAY
PLANT FUEL 2260
TONS/DAY
NAPHTHA (1 PPM S)
270 TONS/DAY
SULFUR 320 TONS/DAY
WASTE WATER 6390 TONS/DAY
SLAG 710 TONS/DAY
Figure 52. Overall material balance for liquefaction plant.
About 1,060 gallons/ minute of wastewater are discharged from the
liquefaction complex. Wastewater comes from cooling tower blowdown,
sanitary wastewater, boiler blowdown, treated oily water, and stripped sour
water (Figure 53, OH-006). Potential pollutants in the water streams in-
clude phenols, ammonia, acid oil, naphtha, suspended solids, and trace elements.
Some liquefaction facilities will initially treat wastewater, send it to a
holding pond for further treatment, and then discharge it from the complex.
TABLE 36 summarizes the estimated wastewater treatment data and contaminants
in the effluent stream leaving the complex (OH-006). Other liquefaction facil-
ities, however, will operate on a so-called "zero discharge" basis and not
have a liquid discharge stream leaving the complex boundaries (RA-150, KA-154).
These plants will employ solar evaporation ponds to hold the liquid effluents.
The selection of the method is very important in assessing the environmental
impacts of a liquefaction plant.
-121-
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TABLE 36. ESTIMATED WASTEWATFR EFFLUENT
CONCENTRATIONS FOR DEMONSTRATION PLANT
Constituents
Biological Influent
Ib/day ppm
Biological Effluent
Ib/day ppm
Sulfide 1.48
Ammonia 24
Oil 72
TOC 60
BOD 538
Suspended Solids 660
Phenol 96
COD 1,920
Phosphate 145
PH 6-9
Chr ornate 91
Zinc 45
Coliform
Organism
Rr.rvnv UATITD ^
TO PROCESS
PHENOLIC AND ABSOf
NONPHENOLIC > STRIF
SOUR WATER UNITS
0.12 0.06
1.88 1.45
5.63 8.64
4.69
42 134.5
51.6 165
7.5 4.8
150 576
11.3 1.45
6-9 6-9
7.1 91
3.5 45
15/100 ml
^' ACID GAS TO SULFUR
RECOVERY PLANT
HER
PER
V
'
0
0
10
12
0
45
0
0
.11
.68
_
.5
.9
.38
.11
6-9
7
3
.1
.5
15/100 ml
OILY
WATER
COALESCER
SAND FILTER
UNITS
SANITARY
SEWAGE
BOILER SLOWDOWN
COOLING TOWER
SLOWDOWN —
SPENT CAUSTIC —
NONOILY FILTER —
BACKWASH WATER
SEWAGE
TREATMENT
PLANT
NEUTRALIZATION
BASIN
TREATED
EFFLUENT
Figure 53. Major wastewater streams in a coal liquefaction plantr
-122-
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The production of solid wastes is shown in Figure 54.
COAL
COAL
PREPARATION
REJECT SOLIDS
"RETURN TO MINE
I
LIQUEFACTION
DISCHARGE
PROCESS UNITS
REQUIRING
CATALYSTS
'CATALYST WASTES
I
BOILER FUEL
PRODUCTS
Figure 54. Solid waste streams for a demonstration plant making
clean boiler fuels from coal.
The possible environmental impacts identified in this report to this
point have been very limited and idealized. Potential pollutants other than
those previously mentioned may exist. The exact pollutants will be determined
by the coal composition and the operating conditions of the liquefaction reactor.
The fate of these species will be determined by the product processing steps,
control and treatment facilities, and the likelihood of fugitive emissions.
For example, liquefaction reactors operate completely in a closed system so that
ideally there should be no stream discharge to the atmosphere, but because they
operate at high pressures, leaks and fugitive emissions can cause serious
pollution problems.
Potential pollutants that may arise in one or more effluent streams are
sulfur oxides, reduced sulfur compounds, ammonia, hydrogen cyanide, phenols,
carbon oxides, tars, oils, and trace elements. Carbonyl sulfide and carbon
disulfide are more difficult to remove than hydrogen sulfide and may be emitted
to'the air (HI-080).
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The fate of trace elements is very important in liquefaction processes.
Their impacts may be important in effluent streams from the liquefaction
plant and in the utilization of the liquefaction product. Information on the
environmental relevance of trace elements in coal liquefaction is still very
limited, but available data indicate the need for continued research in this
important area.
The minor components, sulfur and nitrogen, and the trace element
selenium have been used as examples for identifying the problems associated
with determining the fate of trace elements in liquefaction processes (LO-090).
Organically-bound selenium may leave the process in the liquid product or as
hydrogen selenide in the gas phase. Hydrogen selenide can decompose to metallic
selenium which has a high vapor pressure. Hydrogen selenide can also dissolve
in aqueous streams and is a moderate reducing agent. Selenium may also be
found in an inorganic ash phase as selenides, selenites, or selenates (LO-090).
Therefore, a trace element may have many possible fates. The fate of trace
elements in coal liquefaction will be determined by the interaction of coal
constituents and processing conditions.
The importance of trace elements in coal liquefaction has been outlined
in a study of the Solvent Refined Coal Process (SRC) (JA-096). The SRC pro-
duct contains appreciable amounts of certain trace elements, especially titanium
which may reach a concentration as high as 300 ppm. Although titanium is not
a very toxic element, its high content in the product is both unusual and im-
portant and may suggest the formation of organometallic compounds. Vanadium,
nickel, beryllium, cobalt, copper, and lead also are contained in significant
amounts in the product. However, the importance and need for more research
has been established for trace elements in liquefaction processes.
The next section will be devoted to the calculation of a liquefaction
module.
Liquefaction Module
The module calculations discussed here are based on a coal liquefaction
plant producing 1012 Btu/day of primary liquid fuels. For a coal liquefaction
plant these primary fuels include naphtha, fuel oil, and residual oil. The
thermal efficiency* selected for this module, 62.5%, is the efficiency given
for the modified Solvent Refined Coal Process by Pittsburgh and Midway Mining
Company (PA-139). This efficiency is chosen since the SRC Process appears
to be under serious consideration for commercial operation, with a 50 ton per
day (tpd) pilot plant under construction and the design of a 10,000 tpd demon-
stration plant completed. In addition, the demonstration plant designed by
Ralph M. Parsons Company (PA-139) provides a good source for checking the
heat and mass flows associated with a liquefaction process. Liquefaction
modules are analyzed for a western coal with a heating value of 8,806 Btu/lb
and an Illinois coal with a heating value of 10,820 Btu/lb. TABLES 37 and
38 summarize the emissions from the two liquefaction modules.
Thermal Efficiency = Heating Value of Primary Fuels
y Heating Value of Coal Feed
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TABLE 37 ENVIRONMENTAL IMPACTS OF COAL LIQUEFACTION MODULE
FEED: WESTERN COAL
Air (Ib/hr)
Particulates
S02
NOX
CO
HC
Water (Ib/hr)
Suspended Solids
Dissolved Solids
Organic Material
Thermal (Btu/hr)
Solid Wastes (tons/day)
Land Use (acres)
Water Requirements (gal/day)
633
1493
8507.5
340
2607.6
0
0
0
Negligible
5519
3254
33.3 x 106
Notes: (1) Modules based on 1012 Btu/day output of liquid fuel.
(2) Heating value of western coal is 8806 Btu/lb.
The processing facilities considered to be part of the liquefaction
module are as follows:
coal stockpiling facilities
coal preparation facilities
coal slurrying tank
coal preheater and reactor
flash system
filtration system
fractionation
naphtha hydrotreater
fuel oil hydrotreater
char gasifier
acid gas removal unit
shift conversion unit
methanation unit
oxygen plant
Glaus plant
tail gas treating unit
ammonia separation facilities
power generation unit
steam generation boiler
water treatment facilities
product tankage
The major processing steps are coal dissolution, product fractionation,
naphtha hydrotreating, fuel oil hydrotreating, char gasification, acid gas
removal, shift conversion, methanation, oxygen plant, and sulfur recovery.
The facilities and processing sequences are the same in both western and
Illinois coal modules.
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TABLE 38. SUMMARY OF ENVIRONMENTAL IMPACTS OF
COAL LIQUEFACTION MODULE
FEED: ILLINOIS COAL (10,820 BTU/LB)
(BASIS: 1012 BTU/DAY OUTPUT LIQUID FUEL)
Air (Ib/hr)
Particulates 612
S°2 1957.7
N0x 8507.5
co 340
Hc 2607.6
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (Btu/hr) Negligible
Solid Wastes (tons/day) 8423
Land Use (acres) 3254
Water Requirements 33.3 x 106
Air Emissions
Air emissions from the module result from fuel combustion, coal prepara-
tion, sulfur recovery, ammonia storage, petroleum storage and miscellaneous
hydrocarbon losses.
Fuel combustion emission sources are assumed to be the following:
liquefaction reactor preheater
product fractionator
fuel oil hydrotreater
naphtha hydrotreater
char gasifier
shift converter
cower generation
steam generation.
Water Effluents
Water effluents are nonexistent since the module is assumed to operate
with zero discharge (HI-083).
Thermal Emissions
Thermal discharge to water bodies is zero since no water is discharged
rrom the module.
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Solid Wastes
Solid wastes are determined from-the amount of ash in the coal and solids
in the make-up water. Radian assumed there are 500 ppm solids in the make-up
water. Solid wastes resulting from silt in the make-up water is 70 tpd. Ash
produced by the module is 5449 tpd for western coal and 8353 tpd for Illinois
coal. Total solid wastes for the western coal module are 5519 tpd and wastes
from the Illinois coal module are 8423 tpd.
OIL SHALE DEVELOPMENT
Oil shale development has the potential to cause a number of adverse
environmental consequences. Research has been undertaken to determine what
the possible adverse impacts are and what pollution control measures can be
applied to prevent or minimize these effects. The most,comprehensive study
to date has been the Final Environmental Statement for the Prototype Oil
Shale Leasing Program (US-093). Important elements of this work have been
summarized in a paper discussing proposed legislation concerned with oil
shale development (CO-229). This study assesses the technology, environmental
impact, alternatives, and public and private reactions of the oil shale leas-
ing program. Concerning the environment, it discusses land and water require-
ments, effects on air and water quality, and socioeconomic effects. The en-
vironmental impact statement did not discuss the fate and potential impact of
inorganic trace elements and/or polyaromatic compounds. A summary of the
environmental studies of the oil shale industry has been assembled by the
Rocky Mountain Oil and Gas Association (RO-201).
Colony Development Corporation has prepared an environmental impact
analysis for a proposed oil shale complex (CO-175), and the United States
Bureau of Mines is preparing an environmental impact statement for this com-
plex. Colony is also taking environmental baseline data and studying pollu-
tion control measures (HE-129).
The following sections will discuss the environmental aspects of oil
shale mining, processing, and waste disposal. The mining and processing
impacts of oil shale are interrelated because both steps are performed in
conjunction with each other and share the waste disposal problem. Although
spent shale is generated in the processing step, the environmental impacts
of spent shale including disposal requirements, are•generally enumerated
along with those for mining. The major environmental impact of oil shale,
the disposal of spent shale, greatly affects both land and water resources.
Because of the size of this problem, waste disposal warrants a separate
disucssion.
Oil Shale Extraction
Oil shale extraction in this discussion will consider the mining and
crushing operations. Both underground and surface mining are considered.
jJnderground Mining
Water Requirements
Water requirements for underground mining are negligible. Tho nrimary
-127- . '' y
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requirement, dust suppression, is satisfied by using the water collected in
the mined areas. Water used for dust suppression in the crushing operation
is expected to amount to 3 to 5 percent of the total water used in an oil
shale development (UN-025).
Water Effluents
The effects of underground mining on water pollution should normally
be negligible. A major environmental aspect is the possibility of encounter-
ing large volumes of saline water during mining. Inadequate control of this
water could pose significant problems including adverse effects on ground
water conditions (HU-079). Improper disposal of the highly saline water
could pollute stream water. Dewatering a mine may also depress the level of
ground water tapped by wells.
Solid Wastes
Solid wastes produced during underground mining consist of overburden
rock removed to reach the oil shale. Spent shale from the processing stage
will be returned to the mining area along with the overburden. These aspects
will be discussed later in the report.
Land Use and Disturbance
Due to the large quantity of solids involved in oil shale mining, one
of the major problem areas is solid waste disposal and land requirements. The
fixed land requirement for an underground mine is only about 10 acres of sur-
face land; however, land must be available for disposal of both the overburden
from the mine opening and the spent shale from the retort (assuming spent shale
is disposed of at the mine site). With compacting, it is estimated that about
60 percent of the spent shale can be returned underground with the remaining
40 percent being disposed of on the surface (US-093).
The land requirement has been quantified using an underground mining
module based on a raw shale production of 1012 Btu/day. The module is
defined for a 30 gallon/ton grade of shale with a heating value of 3765
Btu/lb (RA-150). Land requirements for the module are determined from
estimates for an underground mine supplying shale for a 50,000 bbl/day
shale oil facility (US-093). An estimate of the land impact for an under-
ground mining module producing 1012 Btu raw shale/day is as follows:
(1) mine development: 20 acres
(2) solid waste disposal assuming 60% return of
processed shale underground: 51 acre/year
(3) crushing facilities: 40 acres.
Assuming a 30-year mine life, the total land impact is 1,590 acres (RA-150).
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Air Emissions
Estimates of the air emissions are to be based upon the oil shale
necessary to produce 50,000 bbl/day of shale oil and adjusted to 10 2 3tu/
day so that the estimate may be compared to other, extraction procedures.
The 50,000 bbl/day module is chosen because this is the commercial-size
facility that has been chosen for most planning purposes; the 10 Btu/day
module is the most commonly used basis of comparison for energy modules.
The room and pillar mine module is based on a removal rate of 73,700
tons of oil shale per day. This is enough to produce 50,000 bbl/day of
shale oil (US-093). The oil shale has an oil content of 30 gallon/ton of
shale. This value is believed to be near the minimum allowable oil content
to make oil shale processing economically feasible (US-093). A summary of
the environmental impact is given in TABLE 39.
TABLE 39. SUMMARY OF ATMOSPHERIC EMISSIONS
OF OIL SHALE ROOM AND PILLAR MINING MODULE
(BASIS: 73,700 TON/DAY OF PROCESSABLE OIL SHALE)
Air Emissions Ib/day
Particulates 3,680
S02 10
NOX 141
CO 86
Hydrocarbons 16
There are four possible sources of emissions from the room and pillar
oil shale mine: (1) blasting and primary crushing in the mine, (2) secondary
and tertiary crushing and screening operations, (3) vehicular emissions, and
(4) miscellaneous fugitive dust emissions. Emissions from the specific
sources are listed in TABLE 40.
The air emissions for underground mining have been converted to a module
basis of 1012 Btu shale/day and listed in TABLE 13 for comparision with emis-
sions from other energy extraction methods.
Surface Mining
Water Requirements
Water is required for particulate control and solid waste reclamation.
The actual mining operation and the crushing operation require, respectively,
about 2 percent and 3 to 5 percent of the total water used in oil shale develop-
ment. Solid waste reclamation requires a much large amount.
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U)
?
TABLE 40. SPECIFIC SOURCE EMISSIONS (LB/DAY) FOR
OIL SHALE ROOM AND PILLAR MINING MODULE
(Basis: 73,700 ton/day of Processable Oil Shale)
Activity Paritculates S02 CO Hydrocarbons NO
Blasting & Primary 360 -
Crushing
Secondary & Tertiary 3,100 -
Crushing & Screening*
Vehicular Emissions
Miscellaneous
Dust**
Fugitive
TOTAL
5.0 10 86 16
220 -
3,685 10 86 16
141
-
141
* 99 percent controlled by either fabric filters or wet scrubbers
** 80 percent controlled by dust control techniques
-------
Water Effluents
Water pollution is a more serious problem in surface mining than in
underground mining because runoff can pollute streams. The effects of such
pollution have been considered negligible (HI-083, UN-025), but commercial-
scale control procedures have not been demonstrated. Water from reclamation
sites may be highly saline and contain trace elements and trace organics.
The impacts of accidental discharge are still largely unknown.
Solid Wastes
Solid wastes originating from surface mining consist of the overburden
removed to expose the oil shale deposit. The amount of solid wastes depends
on the depth of the overburden; a more shallow overburden produces less solid
wastes. Spent shale from the retorting process is returned to the mine site
and constitutes part of the solid wastes.
Land Use and Disturbance
Surface mining of oil shale has a high land impact since all of the
spent shale and solid waste must be handled on the surface. The large quantity
of solids involved in surface mining and the return of spent shale to the mine
site create major problems in solid waste disposal. The land requirement for
developing a surface mine is 30 to 85 acres/year. During the initial phases
of the operation, permanent disposal of overburden is off-site. After the
first few years, the overburden and spent shale may be returned to mined por-
tions of the land.
The land requirement has been quantified using a surface mining module
based on a raw shale output of 1012 Btu/day from the crushers. The module is
defined for a 30 gallon/ton oil shale with a heating value of 3,765 Btu/lb
with a 450-foot overburden (RA-150).
Land requirements for the surface mining module is determined from esti-
mates for a surface mining operation with a 50,000 bbl/day shale oil facility
(US-093). An estimate of the land impact for a surface mining module pro-
ducing 1012 Btu raw shale/day is as follows:
(1) mine development:' 5 acre/year
(2) permanent overburden disposal: 1,000 acres
(3) low-grade shale storage: 150 acres
(4) disposal of spent shale: 145 acre/year.
Assuming a 30-year mine life, the total land impact is 7,150 acres (RA-150).
Reclamation activities for surface-mined oil shale are difficult be-
cause of the great volume of waste solids and large expanse of land. Re-
clamation involves disposal in the proper terrain, water management and
water pollution control, and revegetation. The water consumption is the
primary environmental concern in reclamation of land associated with surface-
mined oil shale.
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Air Emissions
Estimates of the air emissions will be based on the oil shale necessary
to produce 50,000 bbl/day of shale oil, and this will be adjusted to 1012 Btu/
day so that it may be compared to other extraction procedures.
The shale oil surface mining module is based on a removal of oil shale
equal to 73,700 tons per day. This is enough oil shale to produce 50,000
bbl/day of upgraded shale oil. The oil shale has an oil content of 30 gallon/
ton of shale. A summary of the environmental impact is give in TABLE 41.
TABLE 41. SUMMARY OF ATMOSPHERIC EMISSIONS
FOR OIL SHALE SURFACE MINING MODULE
(BASIS: 73,700 TONS/DAY OF PROCESSABLE OIL SHALE)
Air Emissions Ib/day
Particulates 18,000
S02 !78
N0x 2,440
C0 1,490
Hydrocarbons 284
The surface mining oil shale module is assumed to be in steady-state
operation. This means the mine has been opened and oil shale is being re-
moved at a rate of 73,700 ton/day. The oil shale bed is assumed to be 40
feet thick with a density of 90 lbs/ft3 (US-093). The overburden is assumed
to be 450 feet with a density of 0.05 ton/ft3 (HE-083). The overburden
is also removed by trucks to a reclaiming site assumed to be one mile away.
There are four possible sources of air emissions from the oil shale
production module: (1) excavation and blasting, (2) fugitive dust emissions
from transporting the oil shale and overburden, (3) vehicle emissions from
the combustion of diesel fuel, and (4) primary, secondary, and tertiary
crushing and screening operations. Emissions from the various sources are
listed in TABLE 42.
The air emissions for a 1012 Btu/day surface mining module are com-
pared with the emissions from other extraction techniques in TABLE 13.
Oil Shale Processing
Shale oil upgrading will be considered in the discussions of both the
surface and in-situ processes.
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u>
OJ
I
TABLE 42. SOURCE EMISSIONS (LB/DAY) FOR OIL SHALE SURFACE MINING MODULE
Basis: 73,700 ton/day of Processable Oil Shale)
Excavation & Blasting*
Transporting Fugitive
Dust
- Truck Loading &
Unloading*
- Truck Hauling*
- Conveying
Vehicle Emissions
Primary Crushing*
Secondary & Tertiary
Crushing**
ROUNDED TOTAL
Particulates SO CO Hydrocarbons
1,460
11,800 -
61
negligible ~
86 178 1,485 284
1,470 -
3,100 -
18,000 178 1,490 284
. N0x
-
-
2,440
-
—
2,440
* 80 percent dust control from fugitive dust control techniques
** 99 percent dust control from bag houses or wet scrubbers
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Surface Processing
Environmental effects directly associated with oil shale processing
result from retorted or burned shales, water that has been produced or
used in processing, and gaseous emissions. The actual impacts will vary de-
pending upon the oil shale handling methods, retort design, retort operating
conditions, and upgrading facilities. The following discussion will consider
an oil shale process based upon the TOSCO II process developed by the Oil
Shale Corporation. This approach has been used in similar studies (HI-083.
UN-025).
The module calculations are based on an oil shale processing plant
producing 10 Btu per calendar day of the primary liquid fuels, naphtha,
distillate oil, and/or a residual oil. The thermal efficiency selected for
the oil shale processing moduel is 66.7% (HI-083). This value is the
efficiency given for the TOSCO II process which appears to be the most
advanced process and the most likely to reach commercial operation. In
addition, the environmental impact analysis for the TOSCO II plant at
Parachute Creek, Colorado, provides a good source of information on emission
sources and fuel requirements (CO-175). Using a 66.7% primary efficiency, a
charge rate of approximately 199,100 tons/day of raw shale (3,765 Btu/lb) is
determined. A summary of emissions from the oil shale plant is presented in
TABLE 43.
TABLE 43. SUMMARY OF ENVIRONMENTAL IMPACTS OF
SHALE OIL RETORTING AND UPGRADING MODULE (SOURCE: RA-150)
(BASIS: 1012 Btu OUTPUT LIQUID FUEL)
Air (Ib/hr)
Particulates 454
S02 5320
NOX 1970
CO , 175
HC 2650
Water (Ib/hr)
Suspended Solids 0
Dissolved Solids 0
Organic material 0
Thermal (Btu/hr) Negligible
Solid Wastes (tons/day) 164 x 103
Land Use (acres) 2000
Water Requirements (gal/day) 21.1 x 106
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The main processing steps involved with the shale oil module are as
follows:
(1) retorting
(2) gas recovery and treating
(3) sulfur recovery
(4) delayed coking
(5) hydrogen generation
(6) naphtha hydrotreating
(7) gas-oil hydrotreating
(8) ammonia separation unit.
The processing sequence with effluent streams is shown in Figure 55.
In addition to these processing units, support facilities such as utility
boilers and water treating facilities are also included.
Water Requirement s
Water requirements for this module are based on TOSCO II estimates
(CO-175). Water demands associated with the oil shale industry cannot be
accurately defined due to the uncertainty of water requirements for revegeta-
tion. TOSCO II water demands range between 4,790 gallons per minute (gpm)
and 5,600 gpm depending upon the amount of water allocated for revegetation.
The module water requirement is calculated using the following TOSCO II
demands as a basis:
Make-Up to Water Treatment 3,055 gpm .
Make-Up to Pyrolysis Unit 820 gpm
Dust Control for Processed Shale 250 gpm
Water for Revegetation 700 gpm
4,825 gpm
A module water requirement of 21.1 x 105 gallon/day is thus calculated (RA-150).
Lack of data concerning water for revegetation causes considerable dis-
crepancies in information about the water demands of an oil shale industry. A
summary of water usage estimates for a million-barrel-per-day oil shale industry
is as follows (RA-150):
Cameron and Jones(1959) 130,000 acre-ft/yr
Denver Research Institute (1954) 145,000 acre-ft/yr
United States Department of Interior(1973) 155,000 acre-ft/yr
Colony Development Operation (1974) 175,000 acre-ft/yr
Because of the increase in estimations, a figure of 200,000 to 250,000 acre-
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feet of water per year is used for a million-barrel-per-day oil shale
industry (GA-107).
Land Use
Land requirement for the module is determined from information in
the Final Environmental Statement for the Prototype Oil Shale Leasing Program
(US-093). 320 acres is assumed necessary for a shale oil facility producing
50,000 bbl/day. This land requirement is for retorting, upgrading, and off-
site facilities. The land requirement for the TOSCO II Parachute Creek
plant for these facilities is 315 acres. This figure does not include land
required for mining, transportation, and spent shale disposal.
An equivalent land impact of 320 acres is assumed due to land require-
ments for expansion, for water containment (evaporation ponds), and for green-
belt. A basis of 640 acres for a 50,000 bbl/day facility is thus estimated
for the module. Land required for the 1012 Btu/day module is estimated to be
2,000 acres.
Water Effluents
Water effluents are considered nonexistent since the module is assumed
to operate with zero discharge (HI-083). Although large quantities of water
are used [with the exception of the Superior process (WE-164)] and large
quantities of wastewater are generated, it is assumed that no process water
will be discharged into the river systems. Wastewater from retorting will
be treated and used for particulate control, to moisturize spent shale, and
for reclamation activities.
Retorting oil shale produces water both from heating the shale and from
burning the fuel when internal combustion is used for heating. Because the
water has been in contact with shale oil, the water contains substantial amounts
of organic material from the kerogen and inorganic ions from the minerals in the
shale (HE-129). Therefore, it is very important to insure that process water
is properly treated and controlled.
The treatment, control, and recycling of water in an oil shale complex
has not yet been demonstrated on a commercial-size basis. The concept of
zero discharge does not consider the possible contamination of ground water.
An important water environmental problem will be the prevention of a
salinity increase in the Colorado River. Removal of 2.2 x 108 m3 or 180,000
acre-feet per year of water from the upper rivers of the system is expected
to increase the salinity at Hoover Dam by about 1.4 percent (HU-079). These
estimates are based on the projected size of the oil shale industry in 1985
(HU-079).
Thermal
Thermal discharge to water bodies is zero since no water is discharged
from the module.
Solid Wastes
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OJ
-J
I
199,100 tpd
Spcnc Shale
164,300 tpd
**- Sulfur
117.76 tpd
•>-Hjrdrogcn
1.475,000 scfd
O-Kaphcha
38,700 bpd
To riant Fuel
*- Gas Oil
133,000 bpd
Coke
Figure 55. Shale oil module.
-------
Solid wastes are determined from the amount of spent shale in a
typical shale oil process (US-093). This value of 60,000 tons per day of
spent shale for a 72,700 tpd raw shale process is extrapolated to 164,300
tpd spent shale for the module. This waste is normally returned to the
mine site for disposal.
Air Emissions
Air emissions result from solids handling, shale moisturizing, sulfur
recovery, ammonia storage, fuel combustion, miscellaneous hydrocarbon emis-
sions, and fugitive emissions from retorting.
A major source of emissions will be the combustion of low-Btu gas pro-^
duced by retorting. Combustion of this gas for power generation produces sul-
fur oxides, nitrogen oxides, and carbon oxides.
Important sources of emissions are fugitive emissions from the retorting
and upgrading facilities. In the retorting step, these fugitive emissions may
contain sulfur compounds, ammonia, nitrogen oxides, trace elements, or mis-
cellaneous hydrocarbons. The nature of these species depends on the operating
conditions of the retort. Hydrocarbon emissions are the dominant fugitive
emissions in the upgrading facilities. Fugitive emissions escape from sources
such as valve stems, flanges, loading racks, equipment leaks, pump seals, sumps,
and American Petroleum Institute (API) separators. These types of losses are
discussed in Radian's refinery siting report (RA-119). Based on literature
data, the miscellaneous hydrocarbon emissions amount to about 0.1 weight per-
cent of refinery capacity for a new, well-designed, well-maintained refinery.
This value of 0.1 weight percent is used to determine miscellaneous emissions
from the shale oil upgrading facilities. Upgrading capacity is considered
the feed to the distillation tower. Crude shale oil from the TOSCO II retort
is approximately 20° American Petroleum Institute (US-093). The composition
of these hydrocarbons can be expected to be a composite of all volatile inter-
mediate and refined products. The emissions are assumed to occur at a height
of 5 feet. A detailed air quality assessment has been made of the oil shale
development program in the Piceance Creek Basin (EN-204).
Another consideration of the air emissions is the offensive and long-
lasting odor produced by retorting oil shale.
In-Situ Processing
In-situ processing minimizes the solid wastes problem, but other en-
vironmental impacts are less well-defined because these processes are still
being developed. Some possible environmental problems that may occur during
in-situ oil shale processing are listed in TABLE 44. The different methods
of in-situ retorting will produce different impacts on the environment. For
example, the Occidental Company process produces a much larger solid waste
problem than the United States Bureau of Mines process.
Water Requirements and Water Quality
Water requirements for in-situ processing have not been estimated.
Water generated from the United States Bureau of Mines process requires
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primary treatment before further use or discharge. It must still be deter-
mined what effect leaching of the retorted shale and produced water will
have on ground water.
Land Requirements
It is estimated that a United States Bureau of Mines facility pro-
ducing 1012 Btu/day will require over 1,000 acres over a 30-year period.
Requirements for the Occidental Company process are not known because
solid waste disposal and reclamation techniques have not been established
(UN-025). Subsidence of the land surface is a possibility if in-situ retort-
ing is practiced on a commercial scale.
Solid Wastes
One of the advantages of in-situ processing is that it does not
require the disposal of large quantities of retorted or burned shale. Some
solids are produced during the drilling of the injection and production wells
for the United States Bureau of Mines process. The Occidental Company pro-
cess produces waste rock with a volume equal to 15 to 20 percent of the oil
shale processed. Although this creates a sizeable disposal problem, the
amount is less than 15 percent of the volume produced during surface pro-
cessing.
Air Emissions
Estimates of the air emissions will be based on the production of
50,000 bbl/day of upgraded shale oil. These figures will then be adjusted
so that the process can be compared to other extraction procedures. The
United States Bureau of Mines process is the model for the module. The
summary of the module air emissions are given in TABLE 45.
The four essential steps of in-situ retorting are the following:
(1) drilling of wells in front of the retorting zone
(2) fracturing of the oil shale
(3) injection of air and recirculation gas and formation
of a temperature and pressure gradient within the
oil shale
(4) recovery of the product.
A major source of air emissions from the in-situ retorting process is
the flared low-Btu gas from the gas/oil separation and recovery plant. The
expected composition of this gas before treating is listed in TABLE 46 (US-093)
The H2S, assumed to be reduced to a 250 ppm concentration (EN-204),
is combusted to S02 in the flare or incinerator. The CO in the gas is assumed
to be reduced by 99 percent during incineration (EN-204). The particulate
emissions factor from the flared gas is assumed equal to the emission factor
for the firing of a fuel gas, 0.02 lb/1,000 scf (EN-071). The gas flow rate
for a 50,000 bbl/day operation is approximately 1,485 x 109 scf/day (US-093).
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TABLE 44. POSSIBLE ENVIRONMENTAL PROBLEMS FROM
IN-SITU PRODUCTION OF SHALE OIL (SOURCE: HU-079)
Circulation of hot fluids
Circulation of solutions or
solvents
Underground combustion
Nuclear chimney retorting
Loss of fluid to atmosphere
Loss of fluid through fractures
S02, N0x, and particulates in flue gas
Displacement of saline ground water
Odorous off-gases
Loss of volatiles to atmosphere
Loss of solution to adjacent areas
Contamination of aquifers
S02, N0x, and particulates in off-gas
Odors in off-gas
Loss of fluids to adjacent areas
Contamination of aquifers
All problems common to underground com-
bustion
Blasting Shockwaves detrimental to con-
ventional mines and other installations
Nuclear contamination of aquifers, air,
and products
TABLE 45. SUMMARY OF ATMOSPHERIC EMISSIONS FOR
IN-SITU SHALE OIL PRODUCTION MODULE
(Basis: 50,000 bbl/day of Upgrade Shale Oil)
Air Emissions
Particulates
S02
N0x
CO
Hydrocarbons
Ib/day
29,700
59,500
12,400
2,570
14,500
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The hydrocarbon emission factor for the flared low-Btu gas is assumed to be
equal to the hydrocarbons resulting from combustion of an equivalent amount
(heating value) of natural gas. This value is calculated by multiplying the
hydrocarbon emission factor for natural gas by the ratio of the heating value
of the low-Btu gas to that of a fuel gas (EN-071). This calculated emission
factor is 0.0008 lb/1,000 scf. The nitrogen oxide emissions are estimated
at 12,400 Ib/day (EN-204).
TABLE 46. CHARACTERISTICS OF GASES FROM IN-SITU RETORTING1 (SOURCE: US-093)
Component Concentration/Volume-Percent
Nitrogen
Oxygen
Propane
Carbon Dioxide
Carbon Monoxide
Hydrogen Sulfide
Butanes
Methane
Ethane
73.7
3.4
0.2
21.4
0.1
0.1
0.1
0.5
0.5
1 Heating value approximately 30 Btu/scf
Yield from operation at level of 50,000 barrels per day upgraded (bbl/day)
Shale oil approximately 1,458 x 10s standard cubic feet per day (scf/day)
Miscellaneous fugitive gas emissions at the wellhead are estimated at
0.22 volume percent of the fuel gas. This emission factor comes from a
Battelle report for miscellaneous gas losses occurring at gas wells (BA-230).
Due to the large gas flow rates, fugitive gas emissions will be substantial.
Fugitive dust emissions are estimated at 5.5 Ib/day (EN-204).
TABLE 13 shows the comparison of in-situ air emissions with the emis-
sions from other extraction modules based on 1012 Btu/day.
Solid Waste Disposal
A major problem associated with oil shale development involves solid
wastes, i.e., the handling and ultimate disposal of spent shale. This problem
significantly affects both'land and water resources. Since a typical shale
deposit contains 30 gallons of oil per ton, approximately 80-90 weight percent
of the extracted shale must be disposed as spent shale. A 50,000 bbl/day
shale oil facility would require about 73,000 tons/day of 30 gallons/ton
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oil shale and would produce over 60,000 tons of spent shale. Moreover, this
waste shale occupies a volume about 40 percent greater than the original shale;
even with maximum compaction, the shale increases in size by about 12 volume
percent during processing (US-093). The handling and disposal of such large
weights and volumes of spent shale presents a formidable task.
Most oil shale development plans call for the spent shale from the
retort to be disposed at the mine site. An advantage of underground
extraction over surface mining is that the spent shale may, to some extent,
be disposed underground. About 60% of the processed shale may be backfilled
in an underground mine, thus substantially reducing the surface impact. The
exact amount of backfill depends on the type of spent shale, degree of com-
paction, moisture content, and mine volume used. The portion of the spent
shale that cannot be placed underground must undergo surface disposal and
reclamation. When surface mining is performed, overburden as well as pro-
cessed shale must be disposed on the surface. Initially, overburden and
spent shale are hauled to containment areas; when mined-cut areas of the pit
become available, backfilling can begin. Since the solid waste cannot be
placed underground, the land impact associated with surface mining is higher
than room-and-pillar mining.
Surface disposal of solid waste may be achieved by either containment
(box canyons) or reclamation. Land reclamation and revegetation are desirable
for reducing the land impact of the shale oil industry; however, procedures
required to properly restore and revegetate the land have not been adequately
defined. Total cost, time, and water requirements have not been accurately
established.
The texture of the spent shale is determined by the retorting conditions
and must be considered in establishing disposal techniques. Spent shale from
a Gas Combustion Company retort is pebbly, but TOSCO II processed shale is powdery
(UN-025). Once the shale has been retorted, the organic binding is destroyed
and the rock is easily crushed. Soluble minerals may then be exposed and
leached (HU-079).
The disposal of spent shale can significantly affect both water use
and water quality. Processed shale disposal accounts for 40 percent of the
total water requrements at the Colony facility (HE-129). Methods for prevent-
ing spent shale wastes from contaminating water supplies have been devised,
but their practicality has not been demonstrated on a large scale. Materials
that may be leached from shale disposal sites must be contained and prevented
from entering the natural water systems. Without revegetation, intense,
short-period rains could leach soluble compounds from the spent shale; benzo-
a-pyrenes have been claimed to be present in the leachate from such sites.
Leachate from disposal sites may increase the salinity, sediment, dissolved
solids, and heavy metals in natural waters. The work of J. C. Ward (WA-103)
on the water pollution potential of spent oil shale residues has been sum-
marized (HU-079) and is shown in TABLE 47.
Both trace inorganics and organics are of increasing concern in pollu-
tion. The potential impact of inorganic trace elements in spent shale has
not been adequately established. Work is in progress to determine the impact
of polynuclear organic compounds present in carbonaceous shale ash (SC-239).
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The composition of the spent shale depends on the type of retorting
process and the retorting conditions. If high temperatures such as 1800° F as
in the Union Oil Company process are used, decomposition of the carbonates
occurs, and the spent shale is almost completely free of organic carbon.
However, trace elements and soluble salts may still be present. Retorting
at lower temperatures such as 900°-1000° F causes little mineral decomposi-
tion and yields a spent shale containing residual organic carbon (SC-239).
Intermediate temperatures produce less organic carbon content. TOSCO II
retorting results in the processed shale being coated with a thin carbon
film (HE-129). These carbonaceous spent shales may contain polynuclear
aromatic hydrocarbons, aza-azarines, and other high molecular weight organic
compounds.
Polyaromatic hydrocarbons and aza-azarines have been identified in
benzene soluble fractions extracted from carbonaceous oil shale. These
fractions contain compounds with experimentally demonstrated carcinogenic
effects. TABLE 48 lists some of the compounds identified in carbonaceous
spent shale (SC-239).
Preliminary data indicate that a large number of polycyclic aromatic
compounds can be leached from the carbonaceous shale residue and migrate with
the saline water. This water has a polyaromatic hydrocarbon content which
may be at least 3 to 4 order of magnitudes higher than natural ground water
or surface water (SC-239). Although the presence of possible carcinogenic
compounds has been established, the extent of this problem has not been de-
termined, and research in this area is continuing.
POTENTIAL IMPACTS OF EMISSIONS
The coal conversion and oil shale processes discussed in this report
are largely untried under conditions approximating commercial application.
Consequently, although a number of potential pollutants have been identified
which may be expected as by-products of the processes, it is impossible at
this point to predict in what combinations and in what form they will come
into contact with living organisms. In the following sections, the ecological
relationships of each of fifteen major pollutants or types of pollutants will
be discussed, as much as possible in terms of the pathways by which organisms,
including man, may be exposed to them.
Exposure Pathways
The method by which contaminants may enter the biosphere will depend
very much on the design and location of individual plants. The dispersal of
airborne contaminants depends on terrain and synoptic air flow patterns, and
their impact upon pre-existing ambient conditions. The method chosen for
disposing process wastewater and solid wastes will determine the likelihood
and probable means of environmental contamination. In view of the national
goal of zero pollution discharge by 1985, it is likely that process-waste
streams, including condensate from the conversion process, slurried ash or
chars, and cooling water or boiler blowdown, will be impounded at the site.
Contaminants may leave these ponds and enter the environment via overflow
during periods of excessive runoff or flash flooding, or through a broken
or imperfect seal. Many plants are likely to be built adjacent to a strip
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TABLE 47. SUMMARY OF POTENTIAL WATER POLLUTION PROBLEMS CAUSED BY
SPENT OIL SHALE RESIDUES
1. Leaching tests show a definite potential for high concentrations of Na~*~,
Ca , Mg , and S01J in the runoff from spent oil shale. With proper-
compaction, the piles become essentially impermeable to rainfall, but
snowfall eliminates the compaction in the top 20 to 40 cm and the top
half meter of the residue becomes permeable to water.
2. Soluble salts are leached readily from spent shale columns.
3. Effluent concentrations from spent shale columns, may be predicted by
equilibrium relationships between water and soluble and exchangeable
ions in soils.
4. Sediment in -runoff water from spent oil shale residue will be detrimental
to water quality unless removed by settling.
5. Sediment in the runoff water may be settled by the addition of small
amounts of aluminum sulfate and/or by long periods of quiescent detention.
6. The dissolved solids concentration in snowmelt water is increased signi-
ficantly by contact with oil shale residue, but not as much as in runoff
from rainfall.
7. The long contact with snowmelt results in water percolation into a
a bed of oil shale residue and subsequent saturation.
8. Saturation eliminates compaction of oil shale residue.
9. Weathering of oil shale residue increases the likelihood of per-
colation.
10. Percolation caused by snowmelt may result in creep and slides,
11. Water percolating through oil shale residue is very high in total dis-
solved solids.
12. Both the composition and concentration of dissolved solids in snowmelt
runoff water from oil shale residue change with the cumulative volume
of runoff.
13. Precipitation in the form of snow will not all appear in runoff.
14. Saturation ot the oil shale retorting residue is not required for
percolation by snowmelt.
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TABLE 48. POM* COMPOUNDS IDENTIFIED IN BENZENE EXTRACT OF
CARBONACEOUS SHALE COKE FROM GREEN RIVER OIL SHALE (SOURCE: SC-239)
Name of Compound Potential Carcinogenicity
Phenanthrene
Fluoranthene —-
Pyrene —
Ananthrene (dibenzo [cdjk] pyrene) —
Benz[a]anthracene (1,2-Benzanthracene) +
Benzo [a] pyrene -t-H-
7,12 - dimenthyl[a]anthracene ~H~H"
Perylene
Acridine
Dibenz[a,j]acridine (1,2-
7,8-dibenzacridine) -H-
Phenanthridine
Carbazole
*POM - polynuclear organic matter
-------
coal mine. In these cases, solid wastes, including precipitated solids from
evaporation ponds, can be disposed of in mine pits before regrading and re-
clamation. Since many of the western coals are either themselves aquifers
or lie above or below water-bearing strata, the regraded spoils of a reclaimed
strip mine, with their improved permeability, may act as a localized zone of
ground-water recharge. Soluble materials disposed in the mine can enter the
aquifer and reappear in springs or surface streams. Since in the Western states
a large proportion of the base flow of many streams comes from springs,
aquatic ecosystems may be affected by wastes even if no surface discharge
occurs.
The design of the individual plant, its pollution control strategies
and its geohydrologic setting will influence the extent and occurrence of
pollution pathways. In some cases, proper design and careful site selection
may render all types of contamination of surface and ground water insignificant.
In others, there may be a possibility of measurable pollution.
An example of a reaction which might occur under the proper conditions
is the precipitation of metals as sulfides formed in the presence.of H2S. At
the same time, the highly toxic gas arsine may be formed wherever nascent hydro-
gen comes into contact with a solution containing arsenic. Chlorine mixes
readily with phenols, forming toxic and very stable compounds. Microbial
oxidation of organics of all kinds will be influenced strongly by the dissolved
oxygen content of the impounded waste; the incorporation of oxygen content is
a crucial step in the breakdown of many organic molecules.
Large impoundments of water have a tendency to attract wildlife; the
number and types of which may be expected to vary greatly with the ecosvstem,
the time of year, the species of wildlife present and the composition of the
water itself. Thus, the likelihood of direct exposure of wildlife to im-
pounded effluents cannot be generally specified. The greatest probability
of direct wildlife contact would probably occur in ponds containing relatively
low concentrations of solutes. Such ponds would be far more likely to be
visited by terrestrial wildlife than would ponds containing highly concentrated
solutions, although waterfowl may continue to land even on relatively sterile
waters.
This brief, qualitative discussion provides an idea of the major alter-
native routes by which the effluents characteristic of coal conversion or oil
shale plants may enter the environment, as well as demonstrating their sensi-
tivity to site, process and design. The large degree of uncertainty involved
in exposure pathways places limitations on the conclusions which may legitimately
be drawn from the subsequent paragraphs.
S02 and Particulates: New Perspectives
Data concerning the direct toxicity of S02 to plants, animals, and humans
abound, and Federal ambient air quality standards have been set to fall con-
servatively below the level at which adverse effects begin to be observed.
Recently, attention has been focused on the products formed by S02 in the atmos-
phere. Evidence that these products may be more significant both biologically
and economically than S02 itself is beginning to accumulate.
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The natural sulfur cycle includes a number of transformations, both in-
organically and biologically mediated. An understanding of the fundamental
features of this cycle will provide a sound basis for determining at which points
it will be desirable to monitor sulfur, and for interpreting the results of
these measurements and others already made.
Sulfur dioxide enters the atmosphere mainly from the decay of organic
matter, releasing H2S which is oxidized to S02, from volcanoes, or from the
combustion of fossil fuels. Sulfur dioxide in the air is slowly oxidized to
SOs, which then reacts rapidly with water to form HaSCK or with ammonia or
metallic oxides to' form a variety of sulfate compounds and particulate sul-
fates (EN-292, WE-191). Although field or laboratory data validating these
reaction pathways are generally lacking, it is thought that most sulfates have
an atmospheric residence time of 1 to 7 days (WO-063).
Sulfates and sulfuric acid regularly fall as rain from the atmosphere,
entering the pool of sulfate in sediments and soils. Sulfur dioxide is ab-
sorbed directly by plants in which, after oxidation to sulfate, the 50%
can supply part of a plant's sulfur requirements. From the plant, sulfur may
pass in turn into the soil through root exudates, leaf leachate or decomposi-
tion of litter. The soil sulfate pool is represented in the cycle as the
central wheel of oxidation and reduction reactions. These reactions are
generally mediated by specialized microorganisms, drawing on sulfur in the
form of reduced iron sulfides in deep sediments. A connection to the phosphorous
cycle exists through these compounds; when iron sulfides are formed, phosphorous
in sediments is converted from an insoluble to a soluble form (OD-011).
From the point of biological interactions, the critical points in this
cycle occur principally at the conversion of S02 to sulfate, at the transfer
o-f sulfates of H2SOi, from the atmosphere to land, and with the reactions of
these products with soils and living vegetation. Except for extreme cases,
the effects of sulfur added by man to the cycle may be thought of as being
more adverse in the atmospheric phase and more beneficial in the soil/sedi-
ment phase.
Sulfates formed in the atmosphere differ greatly in size and chemical
composition, and their direct effect upon human "health, in the aggregate,
is not completely understood. West (WE-191) reviewed the subject of sulfur
and selenium compounds and commented that the response of man to particulate
sulfates is "not traumatic" and that the sulfate species probably represent
little risk to human health. Amdur and Corn (AM-148), however, showed
zinc ammonium sulfate was perhaps 20 times as effective in increasing flow
resistance in the lung as equivalent amounts of SOz used in other experiments.
Frank et al. (FR-161) have also shown particulate sulfate to be a stronger
irritant that S02 for guinea pigs. Baruch (BA-369) has recently reviewed the
literature on atmospheric sulfates and concluded that there is reason to be
concerned not only about sulfates in general, but also about the individual
species present in the air, citing Uron, et al. (UR-016) and Butcher and
Charison (BU-084).
Acid sulfate, sulfuric acid and S02 dissolved in aerosols presently
appear to be the best documented sulfate pollutants with respect to health
147
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effects. All three act as irritants and can produce various increases in
resistance to lung flow, an irritation apparently related to acidity.
Very little direct information on particulate sulfate is available.
Concern over sulfates themselves is largely based on negative or circumstantial
evidence. For example, mortality statistics in New York City over the period
1969-1972 showed little change, although S02 levels in the air decreased by
60% during the same period (SC-278). A long-term study of the effects of
typical urban concentrations of S02 on cynomolgus monkeys and guinea pigs,
particularly sensitive laboratory animals, indicated no detrimental effects
(HA-370). This same series of studies, however, indicated a much greater
sensitivity to sulfuric acid mist. This kind of observation has led investi-
gators to suggest that SOz may be an indicator of air pollution, but that
suspended acid sulfates constitute the actual damaging species.
Some evidence has begun to accumulate which suggests that the toxic
effects of sulfate are related synergistically to fine particulate loading
in the air. Although not conclusively demonstrated, this hypothesis is
supported by both laboratory and epidemiological data. Studies undertaken
by the EPA's Community Health and Environmental System (CHESS) have shown
a Relationship between asthma attacks in New York city and suspended par-
ticulates and suspended sulfates when minimum temperatures were below 30°~
50° F. No relationship to S02 was observed. Morbidity excesses appeared when
daily sulfate levels reached 7.3 yg/m3 and minimum temperatures fell below
50° F (EN-292). Sodium chloride (Nad) aerosols mixed with S02 has a syner-
gistic effect on the lungs of guinea pigs (AM-147). Solution of S02 gas by
deliquescent aerosols, which subsequently exhibit reduced pH, has been sug-
gested as a significant pathway by which irritant acid sulfates may be
formed and enter the lung (AM-147, FR-161, MC-113). Atmospheric chemistry
studies (WR-Q09) indicate that the presence of manganese, vanadium or iron
salts in the air will promote the conversion of S02 to sulfuric acid. In ad-
dition, some circumstantial evidence exists relating S02 and general levels of
particulates in the air to chronic bronchitis and respiratory disease (CO-322,
CH-261, FR-162, SH-220).
The implications of this evidence for future areas of concern in en-
vironmental monitoring strongly show the need for direct measurement of re-
spirable particles (less than 5y), especially aerosols, as well as of sus-
pended sulfates. Baruch (BA-369) concludes that because of the possible
interaction between fine particulates and sulfates which permit them to
enter the lung, often with enhanced acidity, hazards to human health and
welfare can occur when existing emissions and ambient air quality standards
are met. Since standards do not presently take into account particle size,
further quantitative study is definitely needed in this field.
In addition to the health effects of sulfates, some very strong corre-
lations have been made between the pH of rainfall and reductions in the
productivity of forest vegetation and increasing acidity in lakes leading
to fish kills (LI-087, NI-057, WH-062). At a recent International Symposium
on Acid Precipitation (Columbus, Ohio in May 1975) the most prevalent opinion
was that sulfur and nitrogen oxides from industrial areas may cause acid
148
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rainfall, and that the widespread dispersal of these acid-forming species in
the atmosphere extends their effects far from the original source. In the
present context, however, it should be pointed out that, in general,
documented cases of damaging acid rainfall have occurred downwind of large
industrial complexes rather than individual plants (with the exception of
certain smelting operations with an extremely high S02 output). While there
exists a possibility that large industrial complexes may develop near some
coal conversion facilities, there is no reason to conclude that harmful
decreases in the pH of rainfall could be produced by any one isolated facility
independent of other sources. Although monitoring the pH of rainfall around
and especially downwind of a conversion complex would be useful in document-
ing the validity of this supposition, and probably should be undertaken as a
means of expanding our understanding of the cause of acid rains, it probably
will not be considered a critical monitoring task.
Neutral and alkaline soils apparently absorb S02 rapidly (AG-015, TE-
142). Acid soils, however, absorb only small amounts. Absorption of S02 in-
creases the acidity of soils in industrial regions (BO-163). Direct soil
absorption of S02, as opposed to contribution by plants, probably assumes more
significance in areas with sparse vegetation or in winter. Up to a point, sul-
fates entering the soil have a beneficial effect by increasing the amount of
sulfur available to plants. In excessive quantities, however, changes in soil
pH induced by sulfates in the soil can result in leaching of soil nutrients.
The likelihood of soil leaching developing around a properly controlled single
coal-conversion plant seems, like the possibility of acid rain, to be very
small based on current understanding of the problem. Consequently, monitoring
of soil pH may be considered more valuable in expanding our knowledge than
controlling anticipated pollution problems.
Non-Criteria Air Pollutants
In addition to sulfur dioxide, nitrogen oxides and particulates, coal
conversion and oil shale processes are likely to emit significant amounts of
ammonia, principally from storage and loading of by-product ammonia, as well
as small quantiies of hydrogen sulfide (H2S) and hydrogen cyanide (HCN) en-
countered as minor fugitive losses largely within the plant and near the
ground.
All three of these compounds are readily absorbed by soil (BU-069,
KA-194), and ammonia is strongly absorbed by plants (HI-132). Both ammonia
and hydrogen sulfide are part of naturally-occurring material cycles, so that
their presence in very slightly increased quantities need not be considered
as contamination.
Fugitive H2S and HCN emissions constitute an almost exclusively in-plant
problem which is unlikely to affect the surrounding environment. Quantities
of ammonia emitted, however, may be on the order of 30 to 35 pounds per hour
for a complex producing 1,000 million cubic feet per day (MMcfd) of SNG; with
this much ammonia, it is possible that under certain circumstances vapor could
escape beyond the plant boundaries. Unlike H2S, ammonia is lighter than air
and tends to rise, which will facilitate its transport from the original emission
site. Although the lethal concentration (LC) listed for ammonia (CH-217) is 2000
149
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ppm, much smaller quantities can be harmful or annoying. Ammonia in air at levels
of 0.15 to 0.25 ppm elicited complaints about odor in one Japanese studv, with
such subjective symptoms as headache, sore throat, eye irritation, coughing, and
nausea (OG-013) . Harm to grazing animals is not likely to result from ordinary
fugitive losses. Dayan (DA-155) exposed calves 7.5 hours to ammonia concentrations
as high as 100 ppm without observing significant changes in blood pH, pC02 , P02,
ammonia, and urea nitrogen, which could be related to inhalation of ammonia.
The sharp odor of ammonia will also likely act as a deterrent, preventing animals
from remaining long in the presence of noticeable amounts of the substance.
Trace Elements
Trace elements may be expected to leave the plant as air or water emis-
sions. Relatively significant amounts of mercury, lead, cadmium, arsenic,
and selenium are volatilized during the combustion or pyrolysis of coal (BO-
109, HA-232). Mercury, lead, cadmium, arsenic and selenium removed from raw
gas subsequently appear in the aqueous condensate stream. Therefore, these
elements must be considered both as potential air and water pollutants. Other
trace elements with important toxic properties, including beryllium, vanadium,
zinc and nickel, are normally retained in ash.
In general, the wastewater streams of coal conversion facilities are
expected to contain a sufficiently complex mixture of hazardous organic and
inorganic substances to make zero-discharge designs desirable. The national
goal of pollution discharge elimination by 1985 will also necessitate the
eventual design of zero discharge for all facilities expecting to operate
beyond that date. Therefore, trace elements from these sources have not been
considered to be a direct threat to the quality of surface waters. The follow-
ing discussion will, therefore, concern itself with trace elements as air
pollutants. Although trace elements entering the biosphere as soil contaminants
will, m time, enter surface and ground waters, the processes involved in this
gradual diffusion are generally so slow and the amounts involved so small
that there now appears to be no cause for concern that significant contamina-
tion of surface waters by trace elements will take place.
Concentrations of trace elements were measured in surface soil and sage-
brush along a transection extending 53.8 kilometers (km) (86.6 miles) from the
Dave Johnston Power Plant near Casper, Wyoming in the direction of the pre-
vailing winds (KI-111). A linear relationship was found between the log" of
str^MumT Y th^8 °f dOWnWlnd dlStanCe f°r Selenium> vanadium aid
0 Tprobabi?if 1°° dlfffences Which were statistically significant at the
ciuded in rh y ?V urS6niC ^ merCUry W6re not *n«ly«d; lead was in-
Mother studv XT OS^' T^ ^ si§nificant correlation with distance.
Another study (KL-059) gave evidence for soil enrichment of heavy metals at
a distance of several miles from a power plant on the shores of Lke Michigan-
(TVA) ThnfmilarA^UdycWaS C0nducted around the Tennessee Valley Authority's
(TVA) Thomas A. Allen Steam Plant at Memphis, Tennessee (BO-109, OA-006)
to thP ^ ?0t? n° a?°malies in soil concentrations which could be attributed
to the plant along a 40-mile transection beginning 1 mile from the plant The
researchers also analyzed for trace elements in mosses, which oft en atsorb
and accumulate pollutants such as lead from the atmosphere, but hey obtained
150
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a similarly negative result. Modelling of particulate fallout indicated that
even with no particulate removal, a concentration factor of 1.5 would not be
detected in surface soils unless the concentration of a particular trace
element in fly ash was 100 times greater than that in soils. In the Memphis
area, very few elements show a concentration in fly ash of more than 10 times
that in soils. The study concluded that soil enrichment from particulate
fallout probably would not occur more than a mile from the plant.
Several factors may play a role in the difference between the Allen
Plant results (BO-109, OA-006) and those of Kieth, et al. (KI-111) and Klein
and Russell (KL-059). As pointed out in BO-109, the degree of enrichment
observed in the soil depends on the ratio of the concentration of a particular
element in fly ash to its concentration in soil. In the alluvial sediments
of the Mississippi Valley, trace elements are present in much larger concen-
trations than in soil typical of Michigan. Also the Michigan samples were
taken beneath trees, which not only act as particulate collectors, but
typically lose relatively significant amounts of absorbed materials back to
the soil as leaf leachate during rainstorms. Although these considerations
might permit the assumption of a large fly ash-to-soil ratio of trace element
concentrations, the ranges measured downwind from the Allen Plant lie within
the same order of magnitude, and often closely match those found in soil
samples of the Powder River Basin taken as part of the U.S. Geological Survey
(USGS) research effort (TI-029). Furthermore, the vegetation around Casper,
Wyoming is principally gramagrass-needlegrass-wheatgrass prairie with very
few trees, although the sagebrush sampled could share some of the same func-
tions to a lesser degree. It is possible, too, that lower precipitation in
the Powder River Basin allows trace elements from fallout to build up to a
greater extent than in Tennessee.
The USGS investigators, however, included only 12 samples compared to
40 in the Oak Ridge study, some of which were split into one-inch and six-
inch-deep subsamples. Although the values of selenium, vanadium and strontium
measured in this study showed a statistically significant correlation with
sample distance from the power plant, all values measured fell within the
ranges given for the Powder River Basin as a whole (TI-029).
These three studies by themselves do not present an adequate basis for
concluding whether or not fallout of fly ash from coal or oil shale processing
results in trace element buildup in soil or vegetation. Each study deals
with a different combination of vegetation soil and climatic regime, and
uses different means of assessing and handling the data collected. None
of the studies has conclusively answered the basic question. A definitive
assessment of trace element hazards from this source may not be possible
without reference to local conditions, and in any event must await a more
rigorous investigation.
The major problem in interpreting the results of these investigations
is to determine when a statistically significant trend in trace element con-
centrations is also biologically significant. A number of studies have
addressed this problem; many have dealt with accumulator or indicator organ-
isms from the point of view of geochemistry (SH-217, SH-218) while others
have dealt with the specific toxicity and epidemiological problems of par-
ticular trace elements (HU-126, RO-209, SH-216). In some cases, it has been
151
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possible to identify the concentrations of trace elements in range plants as
the causative agents in livestock poisonings, and to relate these concentrations
in^turn to concentrations in soils. In others, very noticeable effects on
animals apparently caused by imbalances of trace elements in the diet have
proved very difficult to explain because of the small quantities involved and
the enormous influence of natural biological accumulation processes. An
example of such an instance is given in a paper on geochemical anomalies
of a clay pit area in Missouri (EB-008). Investigators were alerted to a
possible geochemical problem by reports of breeding failures and poor conditions
among cattle pastured in the vicinity of a worked-out pit. After extensive
sampling of vegetation, soils and water, and a thorough epidemiological study
of the herds involved, no single trace element was found to be responsible
for^the^interference syndrome, nor was any single chain or pathway of accumu-
lation isolated. Anomalously high concentrations of copper, beryllium, molyb-
denum and nickel were observed in both sediments and plants, as well as evidence of
rapid mobility of cobalt, copper and nickel. The symptoms observed in the
cattle corresponded more closely to chronic molybdenosis. From these observa-
tions, the investigator suggested that the most likely cause of the inter-
ference syndrome was an imbalance in the complex relationship between cooper
and molybednum, which is possibly influenced by other elements that are present
in anomalous concentrations and that can, in themselves, influence metabolism
of cattle. Similar syndromes have been noted in cattle from California, Florida,
Nevada, Canada, Europe and Australia. In comparing these results to similar
imbalances being induced by trace elements from fallout, it is worth noting
that concentrations of copper and nickel in surface soils in the Powder River
Basin (KI-111) fell within the same range as those recorded in the contaminated
sediments near the clay pile and that vegetation levels of molybdenum were
comparably high. Although molybdenum and nickel were not sampled around the
Allen Station, copper values showed a similar range. These data and typical
values given by Bowen (BO-165) are shown in TABLE 49.
In the absence of clearcut, repetitive patterns of uptake, accumulation
and subsequent damage, a general discussion of the significance of trace ele-
ment inputs needs to take into account all of the various pathways by which
the elements may enter the biosphere, and the environmental conditions govern-
ing the expression of these pathways. Figure 56 is a generalized diagram of
the pathways which can be important in the distributuion, accumulation, and
recycling of trace elements from coal or oil shale processing.
Among the potential imports of trace elements to the biosphere, agri-
cultural chemicals constitute a major source. Mercury-containing compounds
have been very widely used as seed treatments to prevent fungal attack and to
protect tubers, bulbs and corms of various kinds, and these uses have con-
tributed large quantities of mercury to soils (GO-135). Arsenic-containing
compounds, all of which are toxic, have also been used as pesticides, re-
sulting in some very high levels of arsenic in soils (SM-106, AN-119).
Cadmium is often found as a trace contaminant in fertilizers (SC-279).
Trace elements added to soils by agricultural chemicals can in some places
far outweigh the influence of trace elements from aerial fallout. The typical
concentration of arsenic in soils reported by Bowen (BO-165), for example, was
6 parts per million (ppm); most soils contain several parts per million. A
soil from New York State contaminated by calcium arsenate used for insect con-
152
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TABLE 49. COMPARISON OF TRACE ELEMENT CONCENTRATIONS IN AN AREA OF
KNOWN DAMAGE TO MISSOURI LIVESTOCK TO SIMILAR MEASUREMENTS IN OTHER SOILS
Missouri1
Powder River
Tennessee
Element Cla
Native Vegetation Native Soil Near "Typical" Values
Soil (Shrubs) Soil Vegetation Allen Stn. Soils Land Plants
Copper:
Range 30-150
Avg.
Geom. Mn
50-1000
12
3.3-67
15
15-64
2-100
20*
14.0
I Molybdenum
Ul
I
Avg.
Range
Geom. Mn
<3-15
U -
Avg. 14 -
Geom . Mn -
40 30
References:
1 EB-008
2 KI-111
3 BO-109, OA-006
4 BO-165
These values are cited as typical but not necessarily global averages,
-------
rr
i
M
-P-
L
FERTILIZERS
. PESTICIDES
MICROORGANISMS
(METHYLATION)
LITTER, DECAY
DECAY
DECAY
SO
sim
METALLIC VAPOR
AEROSOL COMPOUNDS
IL
PACE
CHELATION
1
CONTAMINATED
PARTICULARS
RUNOFF
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j
ION EXCHANGE,
ADSORPTION ON COLLOIDS
INCLUSION IN LATTICE
SOIL SOL'N
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UPTAKE i CONCEN.
PRIMARY C
(INSECTS,
CRAZING A
ONSUMERS
BIRDS,
HIMAI.S)
SECONDARY CONSUMERS
(PREDATORY OR CARRION-
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1
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l 1 p. T SURFACf
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METAL-CONTAINING
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UATEBS
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•» IN SEDIMENT •- J 1
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i
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. ,v ™ VfiMTH Ati-iir DECAY
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HAN
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FISH i SHELLFISH
SIGNIFICANT PATHWAY WITH RESPECT TO ACCUMULATION
. LESS SIGNIFICANT PATHWAYS
Figure 56. Exposure pathways by which trace elements
can enter the biosphere.
-------
trol, however, had levels of up to 37 to 38 ppm (AN-119). (It is pertinent
to note here that in this study, greenhouse experiments indicated that 69.5^
ppm arsenic applied as arsenite were required to induce significant growth in-
hibition in low-bush blueberry (Vaccinium angustifolium) and that arsenic
accumulation was greater in roots than in edible fruits, stems or leaves.)
Just as agricultural chemicals can dominate the trace element imports
in some areas, airborne contaminants other than those released in coal pyroly-
sis can also locally raise background levels to a point where inputs from
coal would be obscured by a very low ratio of concentrations in fly ash to
soil levels. Smelters have been, at least in the past, well-known sources
of trace elements in harmful concentrations (e.g., OY-002, BI-068). It
has been shown that in areas with significant aerial contamination, plants
may absorb a significant proportion of their total cadmium burden from the
air (LA-198). Kitamura (cited in FR-163) measured cadmium deposition within
500 meters (m) from a smelter at 6.2 mg/m2/month over a six-month period.
Lead aerosols are also accumulated by the waxy cuticles of many plant leaves
(AR-062). The trace metal content of trees is apt to be a function of aerial
composition (WA-208).
Once in the soil or deposited upon its surface, the fate of most trace
elements is very poorly known. The factors governing uptake and accumulation
in vegetation, and the natural cycling or dissipation of trace elements, lie
at the heart of any attempts to understand the significance of their accidental
introduction into the biosphere. The complexities of the interactions of these
factors, however, present a formidable task to the investigator. Most research
has dealt with the dynamics of relatively simple laboratory and experimental
systems often focused on only one trace element. Most of the factors which
in nature will vary simultaneously are held constant to allow the experimenter
to observe the responses of the system to a single one. Much of this work,
as related to agricultural applications, has been reviewed by several authors
in a compendium edited by Mortvedt, et al. (MO-173). It is possible to discuss
qualitatively the various major soil and plant processes which govern the move-
ments of trace elements, as well as the environmental parameters influencing
them. Attempts to predict their relative significance in specific situations,
however, must rely largely on expert judgment rather than on modeling or cal-
culation.
The mechanisms of many observed phenomena, particularly those of the
interference of one trace element with the uptake and translocation of another
in plants, are far from being adequately demonstrated or agreed upon in
theory by investigators. In the absence of many connecting links, any-
thing approaching a generalized theory of trace element movement cannot be
attempted. Furthermore, the wide range of phenomena observed by different
authors points strongly to the dominant role of plant species and local
geochemistry in determining the fate of trace elements introduced into
soil/plant systems.
A thorough and detailed discussion of what is now known, from various
sources, about trace elements in soil/plant systems and their significance
in human or other food chains, has not yet been published, to our knowledge.
Such a compendium, directed at interpreting the relative significance of
155
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trace element inputs by man, would be a very useful tool, not only in eval-
uating the potential for pollution problems from the new coal processing
technologies, but in providing clearcut guidelines enabling the design of
further research to fit into and extend an existing framework of knowledge
bearing on critical processes.
The moisture in the soil is the key to most of these processes since
it provides the medium by which materials can enter, move within the system
and leave through leaching or plant uptake. Equilibria between the solid
and aqueous phases of the soil also govern the degree to which materials can
be immobilized in the soil as solid precipitates, absorbed onto colloidal
particles by ion exchange, or altered in chemical form, such as by chelation
with organic molecules (LI-123). Biological mediation, particularly by bacteria,
can enter into many of these processes.
The availability of trace elements in soils may be influenced by a
number of variables. Perhaps the greatest influence will be the physical
structure of the soil itself. Soil texture and organic matter content not
only affect permeability and infiltration rate; they also determine the
quantity of ions such as calcium cations (Ca^), phosphate (P0~3), and zinc cations
\,Zn ) which can be held by the soil and the degree and the rate at which they
may become mobile in the soil moisture.
Trace elements tend to be absorbed and immobilized by most soils.
Numerous studies have shown that only small amounts of the boron, arsenic,
nickel, cobalt, cadmium, zinc, antimony, silver and mercury absorbed by
soils from polluted air in urban and industrial areas is actually available
to plants (KA-194, LA-196, LA-197, PA-185, RO-130). Uptake and accumu-
lation in aerial plant parts are reduced by ion inactivation through in-
organic and organic equilibria, accumulation at the soil surface above
the root zone, and by exclusion at the root surface or immobilization in
roots themselves (BO-163). The degree to which different metallic ions are
inactivated in soils varies considerably between reports, but soils appear to be
more effective in removing Cu>Pb>Zn>Cd>Ni (SH-218). Alkaline'soils appear
to be more effective in removing copper, zinc, and lead than acid soils
(BO-164, JO-157), although liming does not affect cadmium contents of plants
(JO-156). Bohn (BO-163), reviewing the subject of soil absorption of air
pollutants, states that "except in circumstances of protracted and heavy
fallout near.smelters and other industrial sources of air pollutions, the
accumulation of heavy metal in soils from air pollution probably does not
lead to plant concentrations of these ions which are hazardous to the plants,
grazing animals, or man."
The subject is not quite closed, however, by such a general statement.
Direct toxicity by trace metals is only the acute expression of trace element
pollution; imbalances are basically a nutritional problem and may occur be-
cause of very small changes in the chemical composition of soils and plants.
Because these chronic, synergistic effects exist, and are as yet so poorly
accounted for, it is necessary also to look at processes going on in the
soils after a trace element has been absorbed and what can cause it to be
remobilized. Although in the short run contaminants may seem to disappear
into soils, they are not lost from the system but are held immobile by com-
156
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plex chemical equilibria which respond to changes in their activity in soil
solution. The significance of these equilibria in the continual availability
of ions to plants which are removing them from soil solution and recycling
them, should be readily apparent.
The availability of trace ions in the soil is mediated principally by
three types of interactions: formation of very slightly soluble inorganic
salts, adsorption onto soil colloids, and chelation or complexation with
organic matter. Many metal cations will occupy exchange sites only until
precipitation reactions occur which reduce their activity in soil solution.
When this happens, they are drawn off into the soil solution, precipitate
as insoluble salts, and are replaced at the exchange sites by more common
cations such as calcium, manganese, sodium or potassium. These metals may
eventually find their way into the lattice structures of crystalline minerals
(LI-123). Metals tend to be more available in acid soils; their activities
may decrease as much as a hundredfold for each unit increase in pH.
Chelation or complexation with organic matter, however, may enhance
the availability of metals by preventing their precipitation while at the
same time holding them in a form from which they may be more easily released
(LA-199, NO-063). Field and experimental data have shown that the distri-
bution of ionic mercury in soils is controlled largely by humus; humus-rich
portions of soils sorb up to twice as much mercury as clay-rich portions
(TR-068). Humic and fulvic acids have strong mercury-binding properties,
which retard leaching (GO-135). Biological action can also increase the^
availability of certain trace metals by converting them to soluble organic
forms. Arsenic, mercury and selenium all have a tendency toward biologic
methylation (HA-232) which can be carried out by a variety of microorganisms.
Jernelov (JE-046) reports that methylation in. aquatic sediments can be re-
lated directly to general microbial activity, and hence to conditions favor-
ing the growth of various bacteria and fungi. Although methylation can occur
in both aerobic and anaerobic systems, rates of methylation are higher under
aerobic conditions. In nature, anaerobic conditions will tend to cause the
formation of insoluble sulfide through reaction with hydrogen sulfide (H2S).
All those factors which govern the amount of a given substance in the
soil solution, such as pH, quantity and kind of organic matter, and cation
exchange capacity, affect its uptake. Other ions present in the soil may
also influence the amounts absorbed by plants. For example, soils with large
amounts of available phosphate often produce, by a poorly understood mechanism,
crops which are deficient in zinc, and similarly interfere with the uptake of
other metallic ions such as iron, copper, and nickel. Nitrogen and sulfur
can have similar effects. Interactions of a more complex nature may also
take place among ions during and after uptake; zinc is known to interact
with both cadmium and copper in this way. This subject has been reviewed
in detail by Olson (OL-034). Soil moisture and aeration may also influence
the uptake of materials by plants. Rooting depth, especially in soils where
ions are distributed in distinct horizons, can also influence uptake and
accumulation, especially as the plants grow and their roots extend deeper.
Once within the plant, some substances are more easily accumulated
than others; in acid soils, for example cadmium is easily transported to
157
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plant tops. Metals may also accumulate to varying levels in different parts
of the same plant — roots often retain relatively large quantities of heavy
metals while fruits and grains may accumulate comparatively little. The age
of the plant and the time of year may also influence accumulation. Different
species of plants exhibit different accumulation patterns, and variations be-
tween varieties of the same species can be as great as those among species.
The decomposition of crop residues leads to the liberation of significant
amounts of trace elements (LA-199). Microbial activity tends to promote che-
lation of metal ions, while newly formed humic substances can act as solubil-
izers. Soil organic matter tends to form highly mobile complexes with metals
which may account for the greater part of the metals available in the soil
profile. In this way, trace metals may accumulate and recycle in the ter-
restrial environment, especially because deep-rooted plants tend to take up
ions which have leached into the lower layers of the soils and redeposit them
on the soil surface as litter.
The above discussion of the fate of trace metals from air pollution in
the terrestrial ecosystem illustrates some of the complexities governing this
interaction. Although information at all levels is vitally needed, certain
areas are particularly crucial to understanding the mechanisms by which trace
elements from air pollution can affect the biosphere. This information will,
in turn, determine the extent to which particular trace element species should
be monitored on a long-term basis. These may be summarized as follows:
(1) The potential significance of trace element deposition
has not been established. Studies of deposition
around power plants have produced conflicting views
of the likelihood of trace element enrichment from
fallout. It is clear, however, that concentrations
in both soil and vegetation have a strong influence
on the detection of significant increases in different
geographical area. Monitoring the deposition rates
of trace elements from coal or oil shale processing
would aid in assessing the risk of contamination of
various soils, and would allow comparisons to be made
with documented cases of industrial metal contamination
for which such data are available. Future research
could profitably investigate, using mathematical
models together with field monitoring, the ratios
of concentrations in fly ash to concentrations in
soils which must be achieved before significant soil
enrichment may take place in those geographic areas
most likely to be affected by the development of coal
conversion technology. Data indicate that trace elements
may not be released by coal processing in sufficient
quantities to produce significant increases in concentra-
tions in many soils. This needs to be verified, especially
in the areas to be affected.
(2) The relationship between small increases of trace element
concentrations and the development of nutritional problems
in livestock needs to be better understood. Data available
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on the toxicity of individual elements indicate that, in general,
the soil concentrations required to produce immediate toxic
responses in plants and animals are much higher than those
found in normal soils. The likelihood of trace elements
emitted by coal conversion processes enriching soil to
these levels seems less than that of contamination by
agricultural chemicals or ore sintering and smelting.
This does not rule out the possibility of chronic nutritional
imbalances resulting from very small changes in the trace
element balance of soils. As a first step, documented cases
of such imbalances, like the one cited above, should be re-
viewed. Also, the plant and trace element concentrations
implicated in the imbalances should be compared with ex-
isting baseline data for areas such as the Powder River
Basin.
(3) Indicator plants, known to accumulate trace elements,
should be reviewed for possible use in long-term monitor-
ing. The influence of such environmental conditions as
moisture, temperature and season on the uptake and
accumulation of trace elements should be well understood
both for plants to be used as indicators and for accumulator
plants which may become problems because of their consumption
by livestock.
(4) The synergistic effects of trace elements in producing
chronic damage to vegetation, especially through inter-
ference phenomena affecting uptake, need to be evaluated
with special reference to the likelihood of fallout from
coal conversion processes contributing to the development.
of such problems on marginal soils. Special attention
should be given to range plants and crops grown in areas
most likely to be affected.
(5) The contribution of trace elements from coal arid oil shale
industries is relative to that which may be produced by
increased automobile traffic, associated industry,
etc., which are likely to accompany regional develop-
ment and should be carefully examined. It is the cumula-
tive impacts of resource exploitation which will actually
be felt by a region's biota; evaluating the influence of
basic industry alone does not present a complete pic-
ture.
Trace Organics
A number of potentially hazardous organic substances are produced in
coal gasification and liquefaction processes and in oil shale retorting, and
a portion of these materials will end up in the waste streams. The primary
hazard arising from the production of organic wastes is from their disposal
in evaporation ponds for contaminated wastewater streams.
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As explained earlier, pathways by which these substances may enter
the biosphere depend largely on site-specific and design-specific factors.
It is likely that direct contamination of surface waters through leakage or
overflow will_be strictly controlled. The following discussion will be
oriented principally around the risks of contact or accidental ingestion by
terrestrial organisms of substances in fairly concentrated form, rather than
the effects of low-level contaminants on aquatic communities. It is possible,
of course, that some aquatic organisms, particularly highly tolerant algae
and invertebrates, could survive in wastewater evaporation ponds if the ponds
are sufficiently dilute. This depends, however, on so many unknown factors
of design and wastewater chemistry that speculation is fruitless. Therefore,
the entire question of colonization of evaporation ponds by organisms other
than bacteria and fungi has not been considered.
Exposure to a broad variety of chemical agents has been shown to
result in cancer in laboratory animals and has been implicated in human can-
cers; more chemicals are suspected of having carcinogenic or mutagenic pro-
perties. The majority of these are small molecules with molecular weights of
less than 500, whose carcincgenicity is thought to be related to their electro-
philic properties (MI-181). These include simple alkylating agents, aromatic
amines and amides, aliphatic nitrosamines and nitrosamides, aza-arenes, halo-
genated aliphatic and alicyclic hydrocarbons, complex pyrrolizidine alkaloids
and many polycyclic aromatic hydrocarbons. In addition, compounds of beryllium,
cadmium, chromium, cobalt, lead, nickel and selenium have been identified or
are suspected of being carinogens (CL-067, MI-180, SH-219). Some trivalent
arsenic compounds have also been implicated in the induction of skin cancer
and possibly in other organs through prolonged contact, but experimental
evidence fails to support this view (AN-120). Most authors agree that the
most potentially dangerous compounds are the polycyclic aromatics, of which
the benyopyrenes are especially potent and well documented (HO-222) .
Much of the literature of chemical carcinogenesis deals with uptake by
respiration, particularly products of incomplete combustion of organic
materials such as gasoline and tobacco. Ingestion and direct contact of
carcinogens with the skin, however, have also been strongly implicated in
cancers of laboratory animals and man (HE-152, LI-122, MA-455, WO-062). A
large number of agents must be metabolized before their carcinogenetic
properties, actually the properties of metabolic derivatives, are expressed
(MI-181). The role of the environment is being increasingly recognized as
one of the major factors in the etiology of cancer. Environmental factors
may be important causative agents in some 80% to 90% of human cancers (HI-131).
The process of carcinogenesis is not simple. The carcinogen need not
be continuously present for tumor formation to result. A long latent period
frequently ensues, the length of which is related to the original dose. Suf-
ficiently large doses of polycyclic aromatics will induce the complete car-
cinogenic process in mouse skin in a matter of months; very low doses will
initiate the early stages of the process, but the rate at which it proceeds
will be so slow as to make it impossible to complete during the mouse's
normal lifetime (HE-152). Prolonged exposure or higher dose rates will
also increase frequency of tumor-bearing animals in an experimental popula-
tion as well as the total number of tumors (DR-045, MI-181). Combinations of
160
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strong carcinogens with other, weaker carcinogens can either increase or
reduce the potency of the strong carcinogen (FA-112). Other chemicals,
which are themselves not carcinogens, may be involved in completing the pro-
cess initiated by carcinogens as tumor promoters. Although the initiation
stage is essentially irreversible and rapidly completed, promotion is apparently
reversible, and takes place over a much longer period (MI-181). A third group
of compounds, including N-alkylated indoles and carbazoles, can enhance the
activity of known carcinogens if applied simultaneously, although they do not
initiate carcinogenesis themselves. These apparently inhibit the natural
detoxification of carcinogens by the organism (HO-222, WY-008). Many factors,
including dose, frequency, route of administration, species, sex, age, hormonal
status, viral infection and intrinsic species susceptibility govern the rate
at which chemically induced tumors appear in a population.
In addition to their presence in evaporation ponds, organics such as
polycyclic aromatics (PAH) may disperse directly into the environment from
industrial installations. The potent carcinogen, benz (a) pyrene, was found
to be present in soils around an oil refinery in concentrations more than
60 times that in the soils of surrounding residential and farming areas
(SH-215). The significance of soil contamination by polycyclic aromatics,
however, must be evaluated in the light of natural processes involving these
compounds. Mallet (MA-456) found considerable amounts of PAH in terrestrial
vegetation and this was originally thought to be the result of air pollution.
It is now known, however, that bacteria, algae and higher plants manufacture
PAH (GR-178, MA-457, BO-109). Some aerobic soil bacteria degrade PAH, as
well. It, therefore, appears that, at least in the soil/plant system, a
natural equilibrium probably exists between the production and degradation
of PAH. It has been stated that the slightest change in molecular con-
figuration renders carcinogenic PAH inactive. This statement might be tem-
pered with the Millers' concept (MI-181) of carcinogenicity that changes in con-
figuration render the molecule less electrophilic and reduces its carcin-
ogenicity. In any event, although some PAH can induce cancer, by no means do
all of them, and PAH breakdown by soil bacteria undoubtedly converts many
molecules with carcinogenic properties to harmless or less potent forms.
In addition to carcinogens, organic compounds may exist or be formed
in evaporation ponds used to contain wastes which are themselves toxic or
irritating. The most prominent of these may be phenols, which have demonstrated
dermal toxicity when dissolved in water (CO-323), as well as being toxic when
inhaled or ingested. Some phenols and related compounds are known to be
potent plant growth and germination inhibitors (RI-092).
An important aspect of assessing potential problems resulting from the
disposal of hazardous organics concerns their breakdown in the environment.
Virtually all hydrocarbons of the aliphatic, olefinic, aromatic or naphthenic
series may be oxidized by microbes if properly dispersed (ZO-011) . Molecular
structure, however, determines the ease with which these oxidations are
accomplished. In general, aliphatic compounds are oxidized most rapidly,
with long-chain molecules attacked more readily, within limits, than short
chains. Cycloalkanes, aromatic and naphthenic compounds are more resistant
to oxidation (DU-091, MC-178, 00-002). Isoalkanes are highly recalcitrant,
and alkanes with multiple methyl branches, methyl branches too close to the
161
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end of the chain, or with branches larger than methyl groups are not
attacked (DU-091).
A reliable prediction of what hazards may arise from the disposal of
organic contaminants in large evaporation ponds will have to await the avail-
ability of such wastes themselves from pilot projects or commercial operations.
Until such time as actual disposal situations can be studied, a number of
basic topics need to be investigated so that a basis will exist for predicting
and dealing with the effects of disposal. Areas which could be profitably
studied include the following:
(1) The extent to which known carcinogens, particularly
PAH, are attenuated in soils should be investigated
with special reference to such factors as temperature,
pH, organic matter, and moisture and aeration which
may mediate the process.
(2) The possibility of using bacteria as agents to degrade
organics, especially PAH, in coal-conversion waste-
waters, should be investigated. A large amount of
literature (NE-080) exists on the use of micro-
organisms to degrade spilled petroleum under both
aerobic and anaerobic conditions. A mixed culture
of soil and activated sludge organisms has been used
to remove phenol by bio-oxidation. However, in a
recent study (ST-299) a population of aerobic bacteria
present in the waters of a tip-lagoon system being
used to purify a coke-oven effluent was shown to play
a very doubtful role in the process. This was thought
to be related to a deficiency of orthophosphate and to
poor aeration. It may, therefore, be worth consider-
ing the possibility of innoculating waste ponds with
specially tailored bacteria, or adding materials to
the waste mix which may promote bacterial growth.
Techniques used in sewage treatment processes should
be investigated for their applicability to coal-
conversion wastes. The large amounts of trace metals
which may be present in wastewaters may tend to inhibit
bacterial growth; this factor should be examined.
When waste streams become available for experimentation, a number of
very useful studies could be performed, including the following:
(1) The ability of mixed wastes, concentrated as they
might be in an evaportion pond, to support the
growth of noxious or disease-causing organisms
such as Clostridium botulinum, should be investigated.
(2) The ability of mixed wastes to cause cancer from
exposure by contact should also be examined and
related to the tendency of wastes to concentrate
over a period of time.
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(3) Bottom sludges from evaporation ponds should be
tested for carcinogenicity and evaluated in
light of the need for handling and ultimately for
disposal as solid waste.
(4) The possibility of the formation of toxic gases
or the evaporation of harmful materials from the
surfaces of evaporation ponds should also be in-
vestigated. The presence of metals as potential
catalysts and of microorganisms as biolc&-'.cal
mediators should be kept in mind in designing
experiments or in monitoring the conditions under
which toxins could be released into the air. These
studies should be oriented toward the use r»f ponds
by wildlife, especially waterfowl, and the occupa-
tional health of workers.
Bacteria in the Detection and Treatment of Acid Mine Drainage
A potential water pollution problem which can arise indirectly from the
development of coal conversion processes is the acidification of streams by
mine drainage. The principal cause of the low pH of mine drainage waters is
the oxidation of pyrite (FeSz). The fact that autotrophic bacteria of the
Thiobacillus-Ferrobacillus group can only grow by utilizing reduced iron and
sulfur compounds makes it possible, in theory, to use them in monitoring the
rate of pyrite oxidation in a mine. Dugan (DU-091) discusses experiments in
which the rate of oxidation of iron by bacteria in continuous culture was
related to the rate of cell production. Since a mine with a constant through-
put of water carrying bacterial cells away from the site of their production
behaves, in many ways, like a continuous culture experiment, it should be
possible to calculate, knowing the efficiency of the bacterial energy conversion
step to be between 10% and 30%, the flow rate of water out of the mine or its
refuse dumps, and the concentration of bacterial cells within the outflow waters,
how much pyrite is being oxidized per unit time.
It may also be possible to use another set of bacteria, the heterotrophic
Desulfovibrio-Desulfotomaculum group, which reduces sulfates, in the treatment
of acid mine drainage problems (DU-091, TU-037). These anaerobic bacteria
require a redox potential of -150 to -200 millivolt and a source of organic macter.
Conventional designs for anaerobic sewage digestion systems could be adapted
to this application using sawdust, wood chips, wastepaper or,waste vegetable
matter as an organic base (DU-091). Although antimicrobial agents have been
shown to be an effective means of handling iron and sulfur-oxidizing bacteria
in the laboratory, they may not be as well suited to use in abandoned drift
mines (TU-037).
Most of the coals being considered for large-scale conversion projects
are located in the Western States, where the low-pyrite content of the coals
and the generally alkaline surrounding strata prevent the development of acid
mine drainage problems. To the extent that eastern coals, particularly in
Kentucky and Pennsylvania are involved (HA-369), however, the development
of a biological treatment system may be worth pursuing.
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Summary of Potential Biological Impacts
A great many factors which may be expected to influence the biological
impacts of coal conversion plants cannot be determined at this time. Never-
theless, certain general conclusions may be drawn regarding the likelihood
and probable significance of such impacts as can be envisioned at this time.
In addition, certain gaps in our knowledge may be identified in which further
research is needed before impacts may be monitored, predicted or controlled.
These may be summarized as follows:
(1) Among criteria air pollutants, there is some evidence,
albeit somewhat inconclusive, that health effects are
more closely related to the combined and synergistic
effects of aerosols, fine particulates (especially
deliquescent salts) and atmospheric sulfates than to
sulfur dioxide alone. Similarly, ecological stress
from general air pollution may be in some areas largely
the result of acid rainfall, resulting from the rain-
out of atmospheric sulfates. Coal conversion plants
and other coal-burning industries will be developing,
if current trends continue, around the coal fields.
Therefore, the potential exists for significant in-
creases in airborne sulfates and particulates from many
new sources in a given airshed. It is suggested that
sulfates, fine particulate matter and aerosols, none
of which is currently governed by regulation, be monitored
over relatively large areas as development proceeds, and
correlated with any changes in frequency of respiratory
diseases or related health problems. Further study on
the basic nature of the relationship of sulfates and
aerosols/particulates to health is also needed both to
interpret subsequent measurements in the developing coal
regions and to determine what levels may be considered
acceptable for these contaminants.
Regular long-term monitoring of changes of the pH
of rainfall and of soils will also be informative
when compared to concurrent measures of atmospheric
sulfate levels. Serious acid rain problems have
usually been associated with very heavy sulfur
emitters of a much larger size than can presently
be envisioned for the coal regions of the U.S.
Given present regulatory constraints on sulfur
dioxide emissions and ambient levels, it does not
appear likely that a significant problem with acid rain
will develop in these regions.
(2) Intermittent emissions of H2S, HCN and NH3 will occur
in the plant as part of the process of coal pyrolysis.
These losses will be largely fugitive and will be
mainly confined to the plant site. There is a
chance that some odor may be noticeable, depending
164
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on the location of the plant with respect to occupied
dwellings, but in general these gases are not con-
sidered to pose a serious potential environmental
problem except for occupational exposure within the
plant itself.
(3) Trace metals, of which the most significant will pro-
bably be lead, mercury, cadmium, arsenic and selenium,
will be present in both air emissions and process waste-
waters. Other trace elements, including nickel, beryllium
and zinc, will largely remain in the ash. Recent studies
have presented evidence that the migration of these ele-
ments away from storage ponds will not pose a serious
problem because of the ease with which they are attenuated
by soil. It has, therefore, been assumed that the same
applies to ash disposed in depleted strip mines and
that these elements may be effectively contained.
Similarly, the movement of trace elements from waste-
water impoundments is not considered a serious problem,
and it is assumed that such ponds can be designed
as to effectively prevent excessive seepage or accidental
overflow. Therefore, trace elements were treated in this
report principally as air pollutants.
No definitive study of the significance of trace
emissions from coal-burning plants exists; reports
differ in their interpretation of the likelihood of
soil contamination from this source. Little attempt
has been made to determine the biological significance
of such contamination as can be predicted or observed.
In general, it appears that soil levels required to
promote acute intoxication in plants or animals are
unlikely to result from such emissions, and that such
problems as may reasonably be suspected of being related
to this source may be more in the nature of chronic micro-
nutrient imbalances affecting livestock metabolism.
It is suggested that further research be directed toward
a better definition (through rigorous field studies coupled
with mathematical modeling of particulate fallout) of the
parameters governing the deposition of trace elements on soils.
This is needed first to assess the actual likelihood of soil
contamination and then to compare expected levels to thos-e
which have been related to livestock problems in the past.
The synergistic effects of trace micronutrients, especially
as related to interference of one element in the uptake of
another, need also to be better understood as they affect
the growth of both plants and animals. An effort should
also be made to identify and calibrate indicator species
of plants, whose tendency to respond to trace element increases,
may be applied to long-term environmental monitoring.
Finally, it was emphasized that trace element emis-
165
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sions expected from other sources, such as gasoline
combustion which will increase should be considered
in assessing the overall likelihood of trace element
contamination.
(4) Organic by-products of coal and oil shale processes will
enter the environment principally as process wastewaters
impounded on the site and as fugitive losses. These
waste ponds will contain a mixture of hydrocarbons,
ammonia, phenols, hydrogen sulfide and trace elements.
exact composition, however, cannot be predicted on the basis
of the present level of process development, and will
depend in any case upon wastewater treatment methods
employed. Such wastewaters which may be impounded,
however, may be expected to be moderately to highly
toxic. In addition, bottom sludges formed in these
ponds present ultimate problems of solid waste disposal.
Several lines of inquiry are suggested recognizing that
some will have to await actual commercial development
of coal conversion facilities and the chance to observe
actual waste disposal situations. These include the
investigation of the ability of soils to filter or
attenuate known organic carcinogens. The use of
bacteria or other microorganisms to degrade the
hydrocarbon content of wastes should also be investigated.
A strong base for such an effort exists in prior work on
activated sludge treatment of municipal wastes and in
tailored bacteria used for the control of petroleum. When
actual wastes become available for experimentation, the car-
cinogenic properties of both wastewaters and bottom
sludges can be ascertained. Volatile substances or
evolved gases which may be present at the surface of
evaporation ponds may harm waterfowl and should
also be examined. Finally, the ability of impounded
wastes to promote the growth of noxious or pathogenic
microorganisms should be tested.
Because of our present lack of knowledge regarding
the compostion and properties of wastewaters from
coal conversion, an attempt to assess their environ-
mental impact is largely speculative. This and the
fact that known carcinogens will be among the waste
products argue for placing a high priority on research
in this area.
(5) Although most plans for gasification or liquefaction
of coal involve western coal resources, several have
also been proposed which will use coals from Kentucky
and Pennsylvania. The high pyrite content of these
coals and the surrounding strata make acid mine drainage
a serious problem. Bacterial counts may be used to
166
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monitor the rate of pyrite oxidation. Also, the
adaptation of an anaerobic treatment system using
another group of reducing bacteria shows some promise
as a means of lowering the acidity of mine waters.
Further pursuit of the possibility of using bacteria
both to monitor and control acid mine drainage is
recommended.
167
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168
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CL-044 Clark, C. Scott, "Oxidation of Coal Mine Pyrite," Proc. ASCE J
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CL-067 Clayson, D. B. , Chemical Carcinogensis , Boston, Mass., Little,
Brown, and Co., 1962, 467 pages.
CO-129 Council on Environmental Quality, Energy and the Environment :
Electric Power, Washington, D.C., 1973.
CO-168 Coalgate, Jerry L., David J. Akers , and Russell W. Frum, Gob
Pile Stabilization , Re c 1 amja t j.o n , Utilization, Interim Report
for Period: Feb. 1972 to May 1973, Morgantown, W. Va. , Coal
Research Bureau, W. Va. Univ., 1973.
CO-175 Colony Development Operation, Atlantic Richfield Co,, An
Environmental Impact Analysis for a_ Shale Oil Complex at
Parachute Creek, Colorado , Vol. 1, Pt. 1, Plant Complex and
Service Corridor, 1974.
172
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CO-193 Cover, A. E., W. C. Schreiner, and G. T., Skaperdas, "The
Kellogg Coal Gasification Process," ACS, Div. Fuel Chem.,
Prepr. 15 (3), 1-11 (1971).
CO-197 Coal Pipeline Act of_ 1974_, 93rd Congress, 2nd Session, Report
No. 93-1072, Washington, D.C., GPO, 1974.
CO-208 Corder, W. C. and W. M. Goldberger, "Status of the Battelle/
Union Carbide Coal Gasification Process Development Unit
Installation," presented at the 6th Synthetic Pipeline Gas
Symposium, Chicago, October 1947.
CO-229 Congressional Research Service, Library of Congress, Energy
from Oil Shale: Technical, Environmental, Economic, Legislative,
and Policy Aspects o_f an Undeveloped Energy Source, 93rd
Congress, 1st Session, Washington, B.C., 1973.
CO-289 Cover, A. E., W. C. Schreiner, and G. T. Skaperdas, "The
Kellogg Coal Gasification Process Single Vessel Operation,"
Clean Fuels from Coal, Chicago, Sept. 1973, Symposium Papers,
Chicago, Inst. of Gas Technology, December 1973.
CO-322 Cohen, A. A., et al., "Asthma and Air Pollution from a Coal-
Fueled Power Plant," Am. J_. Pub. Hlth 62, 1181-1188 (1972).
CO-323 Conning, D. M. and M. J. Hayes, "Dermal Toxicity of Phenol
And Investigation of the Most Effective First-Aid Measures,"
Brit. J.. Ind. Med. 27_, 155-159 (1970).
DA-077 Davis, D. W., T. S. Brown, and B. W. Long, "Dewatering Sludge
by Using Rotary Vacuum Precoating Filtration," Coal Mine
Drainage Research, Preprints o_f Papers Presented Before the
4th Symposium, Pittsburgh, Pa. , 1972. page 201.
DA-108 Davy Powergas Co., Power Gas from Coal Via the Winkier Process,
1974.
DA-155 Dayan, M. H., The Effects of Ammonia Inhalation ori Young Bovine
.Animals, PhD Thesis, Univ. Missouri, Columbia, 1973.
DE-148 "Degasification of Coal Beds: a Commercial Source of Pipeline
Gas," A.G.A. Monthly 56 (1), 4 (1974).
DR-045 Druckrey, H., Potential Carcinogenic Hazards from Drugs, R. Truhaut, ed. ,
Berlin, Springer-Verlag, 1967.
DU-061 Durand, R.,'Basic Relationships of the Transportation of Solids
in Pipes: Experimental Research," Proc. Minnesota International
Hydraulic Convention 1953, 89.
173
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DU-091 Dugan, P. R., Biochemical Ecology of Water Pollution. New
York, Plenum Press, 1972, 159 pages.
EB-008 Ebens, R. J., et al., "Geochemical Anomalies of a Claypit Area
Callaway County, Missouri, and Related Metabolic Imbalance in
Beef Cattle," U.S. Geol. Survey Pr£f. Paper 807 (1973).
EL-052 El Paso Natural Gas Co., Application of; El Paso Natural Gas
-5°.- 1°E £ Certificate of_ Public Convenience and Necessity
Dkt. No. CP73-131, El Paso, Texas, 1973.
EN-071 Environmental Protection Agency, Compilation of. Air Pollutant
Emission Factory, 2nd ed. , AP-42, Research TriangU PaTk—
N.C.,.1973.
EN-096 Environmental Protection Agency, Processes. Procedures, and
Methods to_ Control Pollution from Mining Activities, EPA-430/
9-73-011, Washington, D.C., EPA, 1973.
EN-140 Energy Transportation Systems, Inc., .Slurry Pipelines.
Innovation in Energy Transportation. 1974.
EN-202 Energy Transportation Systems, Inc., "The Coal Slurry Pipe-
line, A Summary of Social and Economic Benefits for the West
and for the Energy Consumer," Statement, to FEA Project In-
dependence Public Mtg., Denver, Colorado, August 1974.
EN-204 Engineering-Science, Inc., Air Duality Assessment of the Oil
shale Development Program in the Piceance Creek Basin, McLean
Va. , 1974. ' —
EN-292 Environmental Protection Agency, Information Center, Office of Public
Affairs. Estimated Changes in Human Exposure to Suspended Sulfate
Attributable to Equipping Light Duty Motor Vehicles with Oxidation
Catalysts. Publication 202-755-0890, 1974.
EP-011 Epperly, W. R., "Status of Coal Liquefaction and Gasification
Technology," draft, presented at the Guilford Center Engineering
Symposium, Greensboro, N.C., February 1974.
ES-009 Eschenroeder, A. Q., J. R. Martinez, and R. A. Nordsieck,
Evaluation of_ a. Diffusion Model for Photochemical Smog
Simulation, Final Report, EPA-R4-73-012a, Contract No. 68-
02-0336, Santa Barbara, Ca., General Research Corp., 1972.
FA-024 Farbwerke-Hoeschst, French Patent 1,566,070 (1969), Chemical
Abstracts 72: 33863y.
FA-097 Farnsworth, J. Frank, et al., "Production of Gas from Coal by
the Koppers-Totzek Process," Clean Fuels from Coal, Chicago,
174
-------
September 1973, Symposium Papers, Chicago, Inst. of Gas
Technology, December 1973.
FA-112 Falk, H. L., P. Kotin, and A. Mehler, "Polycyclic Hydrocarbons
as Carcinogens for Man," Arch. Environ. Hlth. 8, 721-730 (1964).
FE-068 Federal Power Commission, Synthetic Gas-Coal Task Force, Final
Report, the Supply-Technical Advisory Task Force-Synthet ic Gas-
Coal, Washington, B.C., 1973.
FE-093 Feldmann, Herman F., .Joseph A. Mima, and Paul M. Yavorsky,
"Pressurized Hydrogasification of Raw Coal in a Dilute-Phase
Reactor," Coal Gasification, Lester G. Massey, ed., 'Advances
in Chemistry Series 131, Washington, D.C., ACS, 1974, page 108.
FO-026 Forney, Albert J., et al., Analyses of Tars, Chars, Gases,
and Water Found In Effluents from the Synthane Process,
Technical Progress Rept. 76, Pittsburgh, Pa., Pittsburgh
Energy Research Center, 1974.
FO-040 Forney, Albert J. and W. P. Haynes, "The Synthane coal-to
gas Process: A Progress Report", ACS, Div. Fuel Chem. 1,5(3),
32-39 (1971).
FO-050 Forney, A. J. and J. P. McGee, "The Synthane Process-Research
Results and Prototype Plant Design," presented at the 4th
American Gas Association Synthetic Pipeline Gas Symposium,
Chicago, 111., October 1972.
FO-059 Forney, A. J., et al., "The Synthane Coal-to-Gas Process,"
Clean Fuels from Coal, Chicago, September 1973, Symposium
Papers, Chicago, Inst. of Gas Technology, December 1973.
FR-115 France, Alvaro, "Brazil Tries New Shale-Oil Process," Oil
Gas J. 1972 (September 11), 195.
FR-161 Frank, N. R., C. E. McJilton, and R. J. Charlson, "Sulfur Oxides
and Particles: Effects on Pulmonary Physiology in Man and
Animals," Prpc. Conference on Health Effects £f_ Air Pollutants,
National Academy' of Science, Prepared for the Committee on Public
Works, U.S. Senate, October 3-5, 1973.
FR-162 French, J. C., et al., "The Effect of Sulfur Dioxide and Sus-
pended Sulfates on Acute Respiratory Disease," Arch. Env.
Hlth. 27, 138 (1973).
175
-------
FR-163 Friberg, L., M. Piscator, and G. Nordberg, Cadmium in the
Environment, Cleveland, Ohio, Chemical Rubber Co. Press, 1971.
GA-104 Galland, J. M. and T. F. Edgar, Analysis and Modeling of Under-
ground Coal Gasification Systems, Energy Systems Labs.Tlept.
ESL-13, Austin, Texas',' University of Texas, Dept. Chemical
Engineering, 1973.
GA-105 Gary, James H., et al., Removal of Sulfur from Coal by Treatment,
with Hydrogen, Phase !_, the Effect of_ Operating Variables and
Raw Material Properties. Washington, D.C., Office of Coal
Research, 1973.
GA-107 Gary, James H., ed., Proceedings of the Seventh Oil Shale
Symposium, April 1974, Colorado School of Mines Quarterly 69
(2), 1974. ^~~
GE-069 "GE Gives Details of Low-Btu Gas Process," Chemical & Engineering
News 1975 (July 7), 25. "~ r~'
GO-055 Govier, G. W. , and K. Aziz, The Flow of Complex Mixtures in Pipes,
N. Y., Van Nostrand, 1972. ''~^~~
GO-135 Goldwater, L. J. and T. W. Clarkson, "Mercury," Metallic
Contaminants and Human Health, D. H. K. Lee, ed., New York,
Academic Press, 1972, 241 pages.
GR-109 Grace, R. J. and E. K. Diehl, "Environmental Aspects of the Bi-
Gas Process," presented at the EPA Environmental Aspects of Fuel
Conversion Technology Symposium, St. Louis, May 1974.
GR-156 Grim, Elmore C. and Ronald D. Hill, Environmental Protection in
Surface Mining of Coal, Final Report, PB 238 538, EPA 670/2-74^
093, Cincinnati, Ohio, EPA, NERC, October 1974.
GR-162 Grace, Robert J., "Development of the Bi-Gas Process,"
Clean Fuels from Coal, Chicago, September 1973, Symposium
Papers, Chicago, Inst. of Gas Technolgoy, December 1973.
GR-177 Gray, W. S. and P. F. Mason, "Slurry Pipelines, What the Coal Man
Should Know in the Planning Stage," Coal Age 1975 (August), 58.
GR-178 Graf, W. and H. Diehl, "Uber den Naturbedingten Normal-pegel
Kanzerogene, Poly Zyklischen Aromate and Seine Ursache,"
Arch. Hyg. Bakt. 15, 49-59 (1966).
GU-049 Gulf Oil Corp., Gulf News 1974 (June 7), Pittsburgh, Pa., 1974,
HA-232 Hall, H. J., G. M. Varga, and E. M. Magee, "Trace Elements and
Potential Pollutant Effects in Fossil Fuels," presented at the
176
-------
EPA Environmental Aspects of Fuel Conversion Technology Symposium,
St. Louis, May 1974,
HA-260 Harney, Brian M. , "Conversion of Coal to Oil and Other Liquids at
the Bureau of Mines," presented at the 6th Synthetic Pipeline Gas
Symposium, Chicago, October 1974.
HA-319 Hammond, Allen L., "Cleaning Up Coal, A New Entry in the Energy
Sweepstakes," Science 189, 128 (1975).
HA-369 Hale, D., "New Developments, New Problems Highlight Coal Gasi-
fication Activity," Pipeline and Gas-J. 202. 26-31 (1975).
HA-370 Hazleton Laboratories, Inc., Physiological Responses to Sulfur
Dioxide, Sulfurjc Acid Mist, Fly Ash and Their Binary and Ternary
Mixtures in Cynomolgus Monkeys and Guinea Pigs, Summary Report,
1974.
HE-100 Hendrickson, Thomas A., "Shale Oil-Process Choices," Chem. Eng.
.81(10), 66 (1974).
HE-129 Heley, William, "Processed Shale Disposal for a Commercial Oil
Shale Operation," Mining Cong. J. 60(5), 25 (1974).
HE-152 Hecker, E., "Cocarcinogenic Principles From the Seed Oil of
'Croton Piglium* and From Other Euphorbiaceae, Cancer Res. 28:
2338-2348 (1968).
HI-080 Hinderliter, C. R. , "Environmental Aspects of the SRC Process,"
presented at the EPA Environmental Aspects of Fuel Conversion
Technology Symposium, St. Louis, Mo., May 1974.
HI-083 Hittman Associates, Inc., Environmental Impacts, Efficiency, and
Cost of Energy Supplied By Emerging Technologies, Phase 2, Draft
Final Report, Tasks 1-11, HIT-573, Contract No. EQC 308, Columbia,
Md., 1974.
HI-090 Hittman Associates, Inc., Environmental Impacts, Efficiency, and
Cost of Energy Supply and End Use, Phase I, Draft Final Report,
HIT-561, Columbia, Md., 1973.
HI-097 Hill, Robert W., "Dust Control with Collectors on Continuous
Miners," Mining Cong, j;. 60_(7), 46 (1974).
HI-131 Higginson, J., "Present Trends in Cancer Epidemiology," Can. Cancer
Conf. 1, 40-75 (1969).
HI-132 Hill, A. C., "Vegetation, A Sink for Atmospheric Pollutants,"
j;. Air Poll. Contr. Assoc. 21, 341-346 (1971).
HO-207 Hoogendoorn, Jan C., "Experience with Fischer-Tropsch Synthesis
at Sasol," Clean Fuels from Coal.Chicago, September 1973, Sympo-
sium Papers, Chicago, Institute of ^as Technology, December 1973.
177
-------
HO-222 Hoffman, D. and E. L. Wynder, "Respiratory Carcinogens:
Their Nature and Precursors," International Symposium on
Identification and Measurement of Environmental Pollutants,
Ottawa, Ontario, Canada, 14-17 June 1971.
HO-238 Holmgren, J. D. and L. A. Salvador, "Low Btu Gas from the
Westinghouse System," CEP 71 (4), 87 (1975).
HU-079 Hughes, Evan E., Edward M. Dickson, and Richard A. Schmidt,
Control of Environmental Impacts from Advanced Energy Sources,
EPA 600/2-74-002, Contract No. 68-01-0483, Menlo Park,~Ca7;
Stanford Research Inst., 1974.
HU-088 Huneke, John M., "Statement to Committee on Interior and Insular
Affairs, U.S. Senate on S.2652 (Title IV) amendment," June 11,
1974.
HU-126 Huffman, E. W. D., Jr. and J. F. Hodgson, "Distribution of
Cadmium and Zinc-Cadmium Ratios in Crops from 10 States East
of the Rocky Mountains," J_. Env. Qual. 2_ (2), 289-291 (1973).
JA-090 Jahnig, C. E. and E. M. Magee, Evaluation of Pollution Control
in Fossil Fuel Conversion Processes, Gasification, Section 1,
"C02 Acceptor Process," Final Report, EPA 650/2-74-009-d, Contract
No. 68-02-0629, Linden, N. J., EXXON Research & Engineering Co.,
1974.
JA-096 Jahnig, C. E., Evaluation of Pollution Control in Fossil Fuel
Conversion Process, Liquefaction; Section 2, "SRC Process,"
EPA 650/2-74-009-f, Contract No. 68-02-0629, Linden, N. J.,
EXXON Research & Engineering, 1975.
JA-121 Jahnig, C. E., Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Gasification, Section 5, "Bi-Gas Process,"
PB243-694, EPA 650/2-74-009-g, Contract No. 68-02-0629, Linden,
N. J., EXXON Research and Engineering Co., May 1975.
JE-046 Jernelov, A., "Factors in the Transformation of Mercury." Environmental
Mercury Contamination. R. Hartung and B. D. Dinman, eds., Ann
Arbor, Ann Arbor Science, 1972, 349 pages.
JO-135 Johnson, Clarence A., et al., "Present Status of the H-Coal
Process," Clean Fuels from Coal, Chicago, September 1973,
Symposium Papers, Chicago, Inst. of Gas Technology, December
1973.
JO-156 John, M. K., H. H. Chuah, and C. J. Van Laerhoven, "Cadmium
Contamination of Soil and Its Uptake by Oats," Env. Sci. Tech.
6, 555-557 (1972).
178
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JO-157 John, M. K. and C. J. Van Laerhoven, "Lead Uptake by Lettuce
and Oats and Affected by Lime, Nitrogen, and Sources of Lead,"
J.. Env. Qual. 1 (2), 169-171 (1972).
KA-124 Katz, Donald L., et al., Evaluation of Coal Conversion Processes
to Provide Glean Fuels, EPRI 206-0-0, Final Report, Ann Arbor,
Mich., Univ. of Michigan, College of Engineering, 1974.
KA-133 Katell, Sidney and Paul Wellman, Mining and Conversion of Oil
Shale in a Gas Combustion Retort, Bureau of Mines Oil Shale
Program Tech. Progress Report 44, Morgantown, W. Va., Mineral
Resources & Environmental Development, 1971.
KA-142 Kalfadelis, C. D. and E. M. Magee, Evaluation of Pollution
Control in Fossil Fuel Conversion Processes; Gasification,
Section 1, "Synthane Process," Final Report, EPA 650/2-74-009b,
Linden, N. J., Esso Research and Engineering Co., 1974.
KA-154 Kalfadelis, C. E. and E. M. Magee, Evaluation of Pollution
Control in Fossil Fuel Conversion Processes, Liquefaction,
Section I, "COED Process," EPA 650/2-74-009-e, Contract No.
68-02-0629, Linden, N. J., EXXON Research and Engineering Co.,
1975.
KA-156 Karnavas, J. A., P. J. LaRosa, and E. A. Pelczarski, "Two-Stage
Coal Combustion Process," CEP 69 (3), 54-55 (1973).
KA-194 Kanivets, V. I., "Reaction of Hydrogen, Methane and Hydrogen
Sulfide with the Mineral Part of the Soil," Soviet Soil Sci. 2_,
294-301 (1970).
KI-111 Kieth, J. R., B. M. Anderson, and J. J. Conner, "Trace Metal
Variation in the Powder River Basin," Geochemical Survey of the
Western Coal Regions, Open-File Report No. 74-250, Denver,
U.S.G.S., 1974.
KL-059 Klein, D. H. and P. Russell, "Heavy Metals, Fallout around a
Power Plant," Env. Sci. Tech. 1_ (4), 357 (1973).
KL-060 Klein, D. H., "Mercury and Other Metals in Urban Soils," Env.
Sci. Tech. £, 560-562 (1972).
LA-048 Lamonica, J. A., R. L. Mundell, and T. L. Muldoon, Noise in
Underground Coal Mines, Bureau of Mines Report of Investigations
7550, Pittsburgh, Pa., Bureau of Mines, 1971.
LA-176 LaRosa, Paul and Ronald J. McGarvey, "Fuel Gas from Molten Iron
Coal Gasification (190-940 Btu/ft3)," Clean Fuels from Coal,
Chicago, September 1973, Symposium Papers, Chicago, Inst.of Gas
Technology, December 1973.
179
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LA-196 Lagerwerff, J. V., "Heavy-Metal Contamination in Soils,"
Agriculture and the Quality of our Environment, N. C. Brady ed.,
AAS Publ. 85, Washington, D. C., AAS, 1966.
LA-197 Lagerwerff, J. V. and A. W. Specht, "Uptake of Cadmium, Lead and
Zinc by Radish from Soil and Air," Soil Sci. Ill, 129-133 (1971).
LA-199 Lagerwerff, J. V., "Lead, Mercury and Cadmium as Environmental
Contaminants," Micronutrients in Agriculture, J. J. Mortredt,
P. M. Giorando, and W. L. Lindsay, eds., Madison, Wisconsin,
Soil Science Soc. of America, 1972,
LE-133 Lee, B. S. and P. B. Tarman, "Status of the Hygas Program,"
presented at the 6th Synthetic Pipeline Gas Symposium, Chicago,
October 1974.
LI-087 Likens, G. E. and F. H. Bormann, "Acid Rain, A Serious Regional
Environmental Problem," Science 184, 1176-1179 (1974).
LI-094 Litman, R., Private communication, Union Oil Co., 17 February
1975.
LI-122 Lijinsky, W. and S. S. Epstein, Nature (Lond.) 225, 21-23 (1970).
LI-123 Lindsay, W. L., "Inorganic Phase Equilibria of Micro-
nutrients in Soils," Micronutrients in Agriculture, J. J.
Mortredt, P. M. Giorando, and W. L. Lindsay, eds., Madison,
Wisconsin, Soil Science Soc. of America, 1972.
LO-084 "Longest Slurry Pipeline Passes Tests," Elec. World 1971
(Feb. 15), 44.
LO-090 Lowell, Philip S. and K. Schwitzgebel, "Potential By-Products
Formed from Minor and Trace Components in Coal Liquefaction
Processes," presented at the Environmental Aspects of Fuel
Conversion Symposium, St. Louis, Mo., May 1974.
LO-115 Loeding, John W. and Constantine L. Tsaros, "IGT U-Gas (Clean
Utility Gas) Process," Clean Fuels from CoajL, Chicago, Sept.
IJTj, Symposium Papers, Chicago, Inst. of Gas Technology,
December 1973.
MA-294 Magee, E. M., C. E. Jahnig, and H. Shaw, Evaluation of Pollution
Control in Fossil Fuel Conversion Processes, Gasification,
Section 1, "Koppers - Totzek Process," Linden, N. J., Esso
Research & Engineering Co., 1974.
MA-398 Malone, H. P., "The Characterization and Upgrading of Coal
Liquids to High Value Fuels and Chemicals," ACS, Div. Fuel
Chem. , Prepr. 20_(1) , 142 (1975).
180
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MA-411 Martin, John F., "Coal Refuse Disposal in the Eastern United
States," News of Environmental Research in Cincinnati 1974
(December 27).
MA-455 Magee, P. N. , Food Cosmet. Toxicol 9, 207-218 (1971).
MA-456 Mallet, L., "Pollution des Milieux Vitaux par les Hydro-
carbures Polybenzeniques du Type Benzo-3,4 Pyrene," Gaz.
Hop. 136, 803-808 (1964).
MA-457 Mallet, L., C. Lima-Zanghi, and J. Brisou, "Recherches sur les
Possibilities de Biosynthese des Hydrocarbures Polybenzeniques
du Type Benzo-3, 4 Pyrene par un Clostridium Putride en Presence
des Kipides du Planeton Marin," £. El. Hebd. Seances Acad. Sci.,
Paris 264, 1534-1537 (1967).
MA-473 Magee, E. M. , Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Coal Treatment, Section 1, "Meyers
Process," EPA 650/2-74-009-K, Linden, N. J., EXXON Research
and Engineering Co., September 1975.
MC-096 McNay, Lewis M., Coal Refuse Fires, 'an Environmental Hazard,
I. C. 8515, Washington, D. C,, Bureau of Mines, 1971.
MC-098 McMath, H. G., R. E. Lumpkin, and A. Sass, "Production of Gas
from Western Subbituminous Coals by the Garrett Flash Pyrolysis
Process," Presented at the 66th Annual AIChE Mtg. , Philadelphia,
Pa., 11-15 November 1973.
MC-112 Mcllvried, H. G., S. W. Chun, and D. C. Cronauer, The Gulf
Catalytic Coal Liquids Pro.cess, Rept. No. 621FE1678, Pittsburgh,
Pa., Gulf R&D Co., Process Research Div., 1974.
MC-113 McJilton, C. E. and N. R. Frank, "The Role of Relative Humidity
in the Synergistic Effect of SOz Aerosol Mixture on the Lung,"
Science 182 (4111), 503-4 (1973).
MC-130 McGuire, J. M., A. L. Alford, and M. H. Carter, Organic Pollutant
Identification Utilizing Mass Spectrometry, EPA-R2-73-234, Athens,
Ga., Southeast Environmental Research Lab., EPA, 1973.
MC-178 McKenna, E. J. and R. E. Kallio, "Hydrocarbon Structure, Its
Effect on Bacterial Utilization of Alkanes, Principles and
Applications of Aquatic Microbiology, H. Heukelekian and N.
Dondero, eds., N. Y. , Wiley, 1964, 452 pages.
MI-180 Miller, J. A. and E. C. Miller, "Natural and Synthetic Chemical
Carcinogens in the Etiology of Cancer," Cancer Res. 25, 1292-
1304 (1965). ~
181
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MI-181 Miller, E. C. and J. A. Miller, "Biochemical Mechanisms of
Chemical Carcinogenis," Molecular Biology of Cancer, H. Busch,
ed., New York, Academic Press, 1975, 638 pages.
MO-103 Montfort, J. G., "Black Mesa Coal Slurry Line is Economic and
Technical Success," Pipeline Ind. 1972 (March).
MO-113 Montfort, J. G. and E. J. Wasp, Coal Transportation Economics,
Flagstaff, Ariz., Black Mesa Pipeline, Inc., 1974.
MO-126 Montfort, J. G., "Black Mesa System Proves Coal Slurry Technology,"
Pipe Line Ind. 1974 (May), 30.
MO-141 Morth, Arthur H., Edwin E. Smith, and Kenesaw S. Shumate, Pyritic
Systems, A Mathematical Model, EPA-R2-72-002, Contract No. 14-12-
589, Washington, D. C., EPA, Pollution Control Analysis Branch,
1972.
MO-150 Moe, James M., "SNG (Substitute Natural Gas) from Coal via the
Lurgi Gasification Process," Clean Fuels from Coal, Chicago,
September, 1973 Symposium Papers, Chicago, Inst. of Gas Technology
September 1973.
MO-173 Mortvedt, J, J., P. M. Giordano, and W, L. Lindsay, eds.,
Micronutrients in Agriculture, Madison, Wis., Soil Science
Soc. America, 1972, 666 pages.
NA-115 National Research Council, Div. of Engineering, Ad Hoc Panel
on Evaluation of Coal Gasification Technology, Evaluation of
Coal Gasification Technology, Part I_, Pipeline Quality Gas,
RD Rept. No. 74, Interim Report No. 1, Contract No. 14-32-0001-
1216, Washington, D.C., 1973.
NA-172 National Academy of Engineering, Rehabilitation Potential of_
Western Coal Lands, Ford Energy Policy Project, Cambridge, Mass.,
Ballinger, 1974.
NA-183 National Academy of Engineering, Evaluation p_f_ Coal Gasification
Technology, Pt. 2_, Low and Intermediate - Btu Fuel Gases,
OCR R&D Rept. 74, Int. Rept. 2, Washington, B.C., 1974.
NA-237 Nappo, C. J., "A Method for Evaluating the Accuracy of Air Pollution
Prediction Models," presented at the Symposium on Atmospheric Diffu-
sion and Air Pollution, Santa Barbara, Ca., 1974.
NE-080 Nelson-Smith, A., Oil Pollution and Marine Ecology, N.Y.,
Plenum, 1973.
NI-036 Nielson, George F., ed., 1974 Keystone Coal Industry Manual,
N. Y., McGraw-Hill, Mining Publications, 1974.
182
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NI-057 Nisbet, I. C. T., "Acid Rain, Fossil Sulfur Returned to Earth,"
Techno!. Review 1974, 8-9.
NO-063 Norvell, W. A. "Equilibria of Metal Chelates in Soil Solution,"
Micronutrients in Agriculture, Mortvedt, J. J., P. M. Giordano, and
W. L. Lindsay, eds., Madison, Wis., Soil Science Soc. America,
1972.
OA-006 Bolton, N. E. , et al. , Trace Element Measurements ajt the Coal
Fired Allen Steam Plant, Progress Report, February, 1973 -
July, 1973, ORNL-NSF-EP-62, Oak Ridge National Lab., 1974.
OD-011 Odum, E. P., Fundamentals of Ecology, 3rd ed., Philadelphia,
Saunders, 1971, 547 pages.
OG-013 Ogata, M., et al., "The Results of the Investigation of Odors in
Mizushima District," An Outline of Countermeasures Against
Public Nuisance iri Kurashiki City, Kurashiki Munic, Office
(Japan), 1968, Abstracted in: Odors and Air Pollution, A
Bibliography with Abstracts, Office of Air Programs Publ. No.
AP-113, Washington, D.C., EPA, 1972.
OH-006 O'Hara, J. B., Environmental Factors in Coal Liquefaction Plant
Design, OCR R&E Rept. 82, Int. Report 3, Contract No. 14-32-0001-
1234, Ralph M. Parsons Co., 1974.
OL-034 Olson, S. R. "Micronutrient Interactions," Micronutrients in
Agriculture, J. J. Mortvedt, P. M. 'Giordano, and W. L. Lindsay,
eds., Madison, Wis., Soil Science Soc. of America, 1972.
00-002 Ooyama, J. and J. W. Foster, "Bacterial Oxidation of Cycloparafinic
Hydrocarbons," Antonie Von Leevwenkoek 31, 45-65 (1965).
OY-002 Oyanguren, H. and E. Perez, "Poisoning of Industrial Origin in a
Community," Arch. Dermatol. 91. 457 (1966).
PA-139 (Ralph M.) Parsons Company, Demonstration Plant, Clean Boiler
Fuels from Coal, OCR R&DRept. 82, Int. Rept. 1, 2 vols.,
Contract No. 14-32-0001-1234, Los Angeles, Ca., undated.
PA-185 Page, A. L. and T. J. Ganje, "Accumulation of Lead in Soils for
Regions of High and Low Motor Vehicle Density," Env. Sci. Tech.
_4, 140-142 (1970).
PF-003 Pforzheimer, H., "Paraho—New Prospects for Oil Shale," CEP 70(9)
62 (1974).
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183
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PH-038 Phillips, Nancy P. and R. Murray Wells, Solid Waste Disposal,
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184
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185
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ST-188 Steppanoff, Alexey J. , Gravity Flow p_f Bulk Solids and Transporta-
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UN-025 University of Oklahoma, Science and Public Policy Program,
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~~r"~l ""• J~"J" ~±~~r~ ~ ~L" »
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187
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188
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189
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APPENDIX A
190
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APPENDIX A
TABLE OF CONVERSION UNITS
To Convert From
To
Multiply By
Btu
Btu/pound
Cubic feet/day
Feet
Gallons/minut e
Inches
Pounds
Pounds/Btu
Pounds/hour
Pounds/square inch
Tons (short)
Short Tons/day
Kilogram - Calories 0.25198
Kilogram - Calories/Kilogram 0.55552
Cubic meters/day 0.028317
Meters 0.30480
Cubic meters/minute 0.0037854
Centimeters 2.5400
Kilograms 0.45359
Kilograms/calorie-kg 1.8001
Kilograms/hour 0.45359
Kilograms/square centimeter 0.070307
Metric tons 0.90719
Metric tons/day 0.90719
191
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APPENDIX B
192
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APPENDIX B
ABBREVIATIONS
AGA
°API
ave
bbl
BCD
BOD
Btu
Btu/lb
Btu/scf
COED
COD
CSE
ft:
ft/sec
geom. mn.
gpm
g/scf
IGT
Ib/day
LPG
mg/1
MM
OCR
PAH
POM
ppb
ppm
ppmv
psi
psia
psig
ROM
scf-
sft
SNG
SRC
SUS
TOC
TOSCO
wt-pct.
American Gas Association
American Petroleum Institute symbol fo
inverse of specific gravity
average
barrel
barrels per calendar day
biological oxygen demand
British thermal unit
Btu per pound
Btu per standard cubic foot
Char Oil Energy Development
Chemical Oxygen Demand
Consol Synthetic Fuel
cubic foot
feet per second
geometric mean
gallons per minute
grams per standard cubic foot
Institute of Gas Technology
pounds per day
liquid petroleum gas
milligrams per liter
million
Office of Coal Research
polynuclear aromatic hydrocarbons
polynuclear organic material
parts per billion
parts per million
parts per million by volume
pounds per square inch
pounds per square inch, atmospheric
pounds per square inch, gage
run-of-mine
standard cubic foot
standard cubic foot
substitute natural gas
solvent refined coal
Seybolt Universal unit for viscosity
total organic carbon
The Oil Shale Corporation
weight percent
193
*U.S. GOVERNMENT PRINTING OFFICE: 1977 - 784-483/67 Region No. 9-1
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-015
4. TITLE AND SUBTITLE
MONITORING ENVIRONMENTAL IM1
SHALE INDUJ
Research and I
7. AUTHOR(S)
D. C. Jones, W. S. Clark, W
E. D. Sethness
2. 3. RECIPIENT'S ACCESSION-NO.
5. REPORT DATE
'ACTS OF THE COAL *MD OIL February 1977
,_ _-,_ 6. PERFORMING ORGANIZATION CODE
3 TRIES !
Development Needs
8. PERFORMING ORGANIZATION REPORT NO.
F. Holland, J. C. Lacy,
9. PERFORMING ORGANIZATION NAME AND ADDRESS 10. PROGRAM ELEMENT NO.
Radian Corporation EHB 529
8500 Shoal Creek Boulevard, P.O. Box 9948 11. CONTRACT/GRANT NO.
Austin, Texas 78766 68-02-1319, Task 25
12. SPONSORING AGENCY NAME AND ADDRESS 13. TYPE OF REPORT AND PERIOD COVERED
U. S. Environmental Protection Agency -Las Vegas, NV Final Report
Environmental Monitoring and Support Laboratory ^'FpT/mfn/nn? EN°Y °ODE
P.O. Box 15027 Office of Energy, Minerals,
Las Vegas, Nevada 89114 anA ^,,=1-™
15. SUPPLEMENTARY NOTES
16. ABSTRACT
Recommendations are presented for monitoring and predictive technology
for the coal conversion and oil shale industries. The recommendations are
based upon a literature survey of the emissions and potential impacts of these
industries. Descriptions of the technologies are included.
17.
a. DESCRIPTORS
Coal Mining
Coal Gasification
Liquefaction
Oil Shale
Pollution
13. DISTRIBUTION STATEMENT
RELEASE "TO PUBLIC
KEY WORDS AND DOCUMENT ANALYSIS
b.lDENTIFIERS/OPEN ENDED TERMS C. COS ATI Field/Group
Monitoring 07C
Coal Slurry Pipeline 13B,H
Coal Cleaning 21D
Modeling 08G,H,I
*< ;., . , •• 19. SECURITY CLASS (This Report) 21. NO. OF PAGES
UNCLASSIFIED 204
20. SECURITY CLASS (This page) 22. PRICE
UNCLASSIFIED
EPA Form 2220-1 (9-73)
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