EPA-600/7-78-063
P A J-S- Environmental Protection Agency Industrial Environmental Research EPA'600/7
"•" • *» Office of Research and Development Laboratory .. ^n^o
Research Triangle Park, North Carolina 27711 ApNl 1978
SYMPOSIUM PROCEEDINGS:
Environmental Aspects of Fuel
Conversion Technology, III
(September 1977, Hollywood, Florida)
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-063
April 1978
SYMPOSIUM PROCEEDINGS:
Environmental Aspects of Fuel
Conversion Technology, III
(September 1977, Hollywood, Florida)
Franklin A. Ayer and Martin F. Massoglia, Compilers
Research Triangle Institute
P. O. Box 12194
Research Triangle Park, N. C. 27709
Contract No. 68-02-2612
Program Element No. EHE623A
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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FOREWORD
The proceedings for the symposium on "Environmental Aspects of
Fuel Conversion Technology, III" is the final report submitted to the
Industrial Environmental Research Laboratory for the Environmental
Protection Agency Contract No. 68-02-261 2. The symposium was
held at the Diplomat Hotel, Hollywood, Florida, September 13-16,
1977.
The main objective of the symposium was to review and discuss
environmentally related information on coal conversion technology.
Papers were presented that covered a summarization of major
environmental programs and contaminants in coal, process
technology, control technology, process measurements, sampling
and analytical information pertinent to coal gasification and liquefac-
tion, and product usage.
Mr. William J. Rhodes, Chemical Engineer, Industrial Environmental
Research Laboratory, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, was the Project Officer and
General Chairman of the Symposium.
Mr. Franklin A. Ayer, Manager, Technology and Resource Manage-
ment Department, Center for Technology Applications, Research
Triangle Institute, Research Triangle Park, North Carolina, was the
Symposium Coordinator and Mr. Ayer and Dr. Martin F. Massoglia of
the same Department were Compilers of the proceedings.
ii
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13 September 1977
Table of Contents
Page
Keynote Address 1
Frank T. Princiotta
Session I: PROGRAM APPROACH 5
Forest 0. Mixon, Session Chairman
The Synthetic Fuels Program Of the Fuel Process Branch of the IERL-RTP 7
T. Kelly Janes
Environmental Assessment Methodology for Fossil Energy Processes 15
R. P. Hangebrauck
Development of Multimedia Environmental Goals (MEG's)
for Pollutants From Fuel Conversion Processes 53
Carrie L. Kingsbury
A Non-Site Specific Test Plan 76
Karl J. Bombaugh
Organic Analysis for Environmental Assessment .' 95
L. D. Johnson, R. G. Merrill
Environmental Aspects of Fossil Energy Demonstration Plants 105
James C. Johnson
Protecting Worker Safety and Health in Coal Conversion 106
Murray L. Cohen
Environmental Research Related to Fossil Fuel Conversion 113
Gerald J. Rausa
14 September 1977
Session II: ENVIRONMENTAL ASSESSMENT 131
E. C. Cavanaugh, Session Chairman
Low-Btu Gasification-Environmental Assessment 133
William E. Corbett
High Btu Gasification Environmental Assessment —
Work Status and Plans 144
Charles F. Murray, Masood Ghassemi
Flue Gas Sampling During the Combustion of Solvent
Refined Coal in a Utility Boiler 152
Craig S. Koralek, V. Bruce May
iii
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Environmental and Engineering Evaluation of the Kosovo
Coal Gasification Plant, Yugoslavia 166
Becir Salja, Mira Mitrovic
Fate of Pollutants in Industrial Gasifiers 191
Gordon C. Page
Liquefaction Environmental Assessment 208
Dwight B. Emerson
A Program for Parametric Evaluation of Pollutants
From a Laboratory Gasifier 220
John G. Cleland
Gasification Process/Environmental Characterization
From Pilot Plant Data 242
David V. Nakles, Michael J. Massey
Trace Elements in the Solvent Refined Coal Process 266
R. H. Filby, K. R. Shah, C. A. Sautter
15 September 1977
Analytical Techniques and Analysis of Coal Tars, Waters, and Gases 283
C. M. Sparacino, R. A. Zweidinger, S. Willis
A Comparison of Trace Element Analyses of North Dakota
Lignite Laboratory Ash With Lurgi Gasifier Ash
and Their Use in Environmental Analyses 292
Mason H. Somerville, James L. Elder
Combined-Cycle Power Systems Burning Low-Btu Gas 316
F. L. Robson, W. A. Blecher
Cross-Media Environmental Impacts of Coal-
to-Electric Energy Systems 333
Edward S. Rubin, Gary N. Bloyd, Paul J. Grogan, Francis Clay McMichael
Session III: CONTROL TECHNOLOGY DEVELOPMENT 359
A. G. Sliger, Session Chairman
Selection of Acid Gas Treating Processes for Coal Converter Outputs 361
S. E. Stover, F. D. Hoffert
A Coal Gasification-Gas Cleaning Facility 375
J. K. Ferrell, R. M. Felder, R. W. Rousseau, D. W. Alexander
Control Technology Development for Products/
By-Products of Coal Conversion Systems 387
Sohrab M. Hossain, John W. Mitchell, Alfred B. Cherry
IV
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Specific Environmental Aspects of Fischer-Tropsch
Coal Conversion Technology 409
B. I. Loran, J. B. O'Hara
Control Technology Development for Fuel Conversion Systems Wastes 424
Louis E. Bostwick
Volatility of Coal and Its By-Products 431
J. K. Kuhn, D. Kidd, J. Thomas, Jr., R. Cahill,
D. Dickerson, R. Shiley, C. Kruse, N. F. Shimp
Treatment of Phenolic Wastes. 447
Stanley L. Klemetson
Composition and Biodegradability of Organics
in Coal Conversion Wastewaters 461
Phillip C. Singer, Frederic K. Pfaender, Jolene Chinchilli, James C. Lamb, III
Biological Treatment of Coal Conversion Condensates 487
Irvine W. Wei, D. J. Goldstein
Solubility and Toxicity of Potential Pollutants
in Solid Coal Wastes 506
R. A. Griffin, R. M. Schuller, J. J. Suloway,
S. A. Russell, W. F. Childers, N. F. Shimp
Applicability of Coke Plant Water Treatment
Technology to Coal Gasification 519
William A. Parsons, Walter Nolde
Future Need and Impact on the Particulate Control
Equipment Industry Due to Synthetic Fuels 528
John Bush
Future Needs and the Impact on the Water and
Waste Equipment Manufacturing Industry Due to the
Use of Synthetic Fuels 535
E. G. Kominek
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KEYNOTE ADDRESS
Frank T. Princiotta
Office of Energy, Minerals, and Industry
U.S. Environmental Protection Agency
Washington, D.C.
It is a pleasure to participate in the Third
Symposium on the Environmental Aspects of
Fuel Conversion Technology. I would like to
thank John Burchard and Robert Hangebrauck
for their kind invitation, and I hope I can make
some remarks relevant to the important work
you are engaged in. Since many of you are con-
cerned with environmental pollution from
various fuel conversion technologies, I think it
might be relevant if I would discuss the recently
signed into law Clean Air Amendments of
1977.
These Amendments supercede the Clean Air
Amendments of 1970. At the time the 1970
Amendments were enacted into law, this was
considered the most significant piece of en-
vironmental legislation in the United States'
history. The 1977 Amendments build upon the
1970 Amendments and in many ways supple-
ment or strengthen the earlier legislation. At
the outset, I should point out the complexity of
this new law and the fact that EPA is only now
attempting to interpret this legislation. In many
ways our EPA Air Programs Office is the
equivalent of a biblical scholar, attempting to
understand and interpret the Clean Air Amend-
ments as the scholar would the Bible.
Although I will attempt to summarize some
of the more important aspects of this new law,
with emphasis on those provisions that relate
to energy sources, I strongly suggest you
carefully read the Act for yourselves.
The Amendments are divided into four titles.
Title I concerns itself primarily with stationary
sources, Title II provides guidance on mobile
pollution sources, and Titles III and IV are more
in the miscellaneous category. I would like to
discuss several of the important Sections in
Title I relating to stationary sources. Specifi-
cally, I would like to summarize what the new
Act says regarding new source standards of
performance (Section 109), the standards for
hazardous air pollutants (Section 110),
unregulated pollutants (Section 120), preven-
tion of significant deterioration (Section 127),
and nonattainment areas (Section 129).
New Source Standards of
Performance (Section 109)
This section amends the existing Section
111 and expands the concept of setting
technologically based standards for the control
of air pollution from new pollution sources.
The section requires that major new sources
use the best technological continuous emission
controls to meet new source standards of per-
formance. Essentially this eliminates the use of
intermittent or alternative control measures
and the use of low sulfur fuel as an acceptable
control approach. Specifically, this section
states that the best adequately demonstrated
technology, (including pre-combustion clean-
ing or treatment of fuels) is to be the basis of
the standard. It requires the Administrator to
take into account energy requirements in deter-
mining which technologies have been ade-
quately demonstrated. Also, the Administrator
must consider nonair quality, health, and en-
vironmental impacts in making the determina-
tion.
This section activates a timetable for the
consideration of setting standards for addi-
tional sources of air pollution. Specifically, the
Amendments allow one year for additional
listing of sources and at least one-quarter of the
standards must be promulgated at the end of
the second year of listing, at least three-
quarters by the end of the fourth year of listing.
The Administrator is also asked to consider the
adequacy of existing new source performance
standards at least every four years. The im-
plication of this is that as the control
technology improves, standards should be
tightened.
Guidance is provided for the setting of new
source performance standards specifically for
fossil fuel-fired boilers. The Act calls for pre-
sent standards to be revised and to include a
percentage emission reduction in pollution from
untreated fuel as well as a standard of per-
formance. In calculating the percentage reduc-
tion requirement, the Administrator is authoriz-
ed to give credit for accepted mine mouth and
other precombustion fuel cleaning processes,
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whether they occur at, or are achieved by, the
source of by another party.
Waiver for Technology
Innovation (Section 109)
The Amendments provide a mechanism for
the Administrator to grant waivers of up to 7
years after the date on which the first waiver is
granted or 4 years after commencement of
operation, from Federal new source perfor-
mance standards to permit a source to use in-
novative continuous emission control
technology.
In order to grant such a variance, the Ad-
ministrator must find:
1. A substantial likelihood that the new
technology will achieve greater emis-
sion reduction than that required under
the new source performance standard,
or equivalent reduction at lower
economic, energy, or environmental
costs;
2. The new technology will not cause or
contribute to an unreasonable risk to
public health, welfare, or safety;
3. The governor of the state in which the
source requesting variance is located
consents to the waiver;
4. The waiver will not prevent the attain-
ment or maintenance of any national
ambient air quality standard;
5. The proposed system has not been
adequately demonstrated; and
6. In determining the substantial
likelihood of a new system achieving
greater emission reduction, the Ad-
ministrator must take into account any
previous failures of the system.
Hazardous Design
Standards (Section 110)
This provision amends the old Section 1 1 2
of the existing law to allow the specification of
design, equipment, or operational standards for
the control of the source of hazardous emis-
sions, where an emission limitation is not possi-
ble or feasible.
Unregulated Pollutants
(Section 120)
EPA has 1 year to determine whether cad-
mium, arsenic, and polycyclic organic matter (2
years for radioactive pollutants) cause or con-
tribute to air pollution and endanger public
health, before regulating them under this act.
Also, within 1 year the Administrator must con-
sider the promulgation of a short term N02 am-
bient air quality standard for a period not to ex-
ceed 3 hours.
Prevention of Significant
Deterioration (Section 127)
The Clean Air Amendments of 1970 ac-
tivated a schedule that aimed at improving air
quality in polluted areas so that health and
welfare were protected. However, the Act did
not contain a provision for protecting airsheds
that were not beyond those pollution levels
considered detrimental to health and welfare.
The Amendments of 1977 add an important
provision for the prevention of significant air
quality deterioration in areas where pollution
levels are lower than existing standards. This
provision defines three air quality categories.
Class 1 allows only a small increment of addi-
tional pollution; Classes 2 and 3 allow cor-
responding greater amounts of pollution. The
Act classifies the following as mandatory Class
1 Federal areas:
1. International parks;
2. Wilderness areas (in access of 5000
acres);
3. National memorial parks (in excess of
5000 acres); and
4. National parks (in excess of 6000
acres).
Initially all other areas are considered Class 2
areas. However, states can in certain cir-
cumstances redesignate such areas as Class 1
or as the less restrictive Class 3 category.
This section delineates allowable increments
of pollution above baseline concentration for
each of the three classes for sulfur dioxide and
particulates. Within 2 years, states must sub-
mit plans establishing increments or other
means of preventing significant deterioration
from the other criteria pollutions, namely:
nitrogen oxides, hydrocarbons, carbon monox-
ide, and oxidants. EPA must approve the plan
within 4 months if it meets applicable re-
quirements; otherwise EPA must propose a
plan for the rejected state within 4 months of
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the disapproval. States may exempt certain
emissions such as those from facilities con-
verting from oil or gas to coal, natural gas cur-
tailments, temporary construction, and foreign
sources from being counted against the incre-
ment.
In order to protect Class 1 areas which could
be affected, no major emitting facility can be
constructed without a permit establishing
emission limitations. Extensive studies will be
required in order for permits to be issued for
major emitting facilities that could affect Class
1 areas. For example, the EPA must: require an
analysis of the ambient air quality, climate and
meteorology, terrain, soils and vegetation, and
visibility at the site of the proposed major
emitting facility; and in the area potentially af-
fected by the emissions from such a facility for
each pollutant regulated under this act, deter-
mine the degree of the continuous emission
reduction which could be achieved by such a
facility.
Requirements for Nonattainment
Areas (Section 129)
Another area that was not dealt with in the
1970 Amendments was the question of siting
new plants in nonattainment areas, i.e., those
areas that are polluted above those levels being
necessary to protect health and welfare. What
the new legislation does is essentially validate
the offset policy published by EPA in
December, 1 976. In order to issue a permit to a
major new source in a nonattainment area, the
state must show that total emissions from all
sources in the region will be sufficiently less
than the total emissions allowed for existing
sources prior to the construction of the major
new source. Thus the baseline for calculating
offsets is the total emissions al-
I
lowed in the implementation plan without tak-
ing the new source into consideration. As a
condition for permitting major new stationary
sources to locate in nonattainment areas, the
states are required to have approved revised
implementation plants. The plans must provide
for attainment of primary ambient standards
(health-related standards) no later than
December 31,1 982, although attainment can
be delayed until December 31, 1987 with
respect to photochemical oxidants and carbon
monoxide. The State Implementation Plan (SIP)
must, among other things, provide for utilizing
"all reasonably available control measures as
expeditiously as practicable." It must also
specifically identify and quantify all emissions
which will result from the construction and
operation of a major new or modified stationary
source. The SIP revision must include a permit
program for stationary sources to allow a
source-by-source or area-wide tradeoff policy;
new sources must achieve "lowest achievable
emission rate." reflecting the most stringent
emission limitation that is contained in the SIP
of any state for such class or category of
source, or the most stringent emission limita-
tion that is achieved in practice, whichever is
more stringent.
In conclusion, I have attempted to give you a
flavor for the content, importance, and the
complexity of this new legislation. Even now
the EPA lawyers and technical people are trying
to interpret this intricate piece of legislation.
Although it is too early to quantify the impact
of the law, it is clear to me that the effect of
this legislation will be far-reaching and will be a
major factor in influencing the development
and utilization of emerging energy tech-
nologies.
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Session I: PROGRAM APPROACH
Forest O. Mixon
Chairman
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THE SYNTHETIC FUELS PROGRAM
OF THE FUEL PROCESS BRANCH
OF THE IERL-RTP
T. Kelly Janes
Fuel Process Branch,
Industrial Environmental Research
Laboratory-RTP,
U.S. Environmental Protection Agency
Research Triangle Park, N.C.
The Industrial Environmental Research
Laboratory conducts a contractual and in-
house research, development, and demonstra-
tion program dealing with the control of emis-
sions/discharges from energy related
technologies and industrial processes.
The Laboratory is divided into three technical
divisions (figure 1):
1. Utilities and Industrial Power Division
which primarily addresses the emis-
sions controls for the combustion of
fossil fuels to generate steam and elec-
trical power.
2. Energy Assessment and Control Divi-
sion which develops improved combus-
tion techniques for nitrogen oxide con-
trol, advanced combustion systems,
and the environmental effects and con-
trol techniques for coal processing and
conversion of coal to synthetic liquids
and gases.
3. Industrial Processes Division which ad-
dresses the emission and controls from
industrial operations. Additionally, in
this Division, analytical and sampling
techniques are developed.
The Fuel Process Branch in the Energy
Assessment and Control Division conducts pro-
grams addressing two major areas (figure 2):
1. Coal Cleaning. Development of
physical and chemical techniques to
remove contaminants from coal;
assessment of the environmental con-
sequences from the utilization of coal
cleaning processes; and the develop-
ment of control technology to avoid
adverse discharge effects.
2. Synthetic Fuels. The assessment of
the multimedia discharges and control
technique development for technol-
ogies converting coal to gaseous, liq-
uid, and refined solid fuels.
Both programs deal with the multimedia (air,
water, and solid) discharge effects. However,
the coal cleaning program has the additional
responsibility to develop the basic processing
technology. On the other hand, the synthetic
fuel program only deals with the potential en-
vironmental effects and control technology.
There is a direct interface of the two programs
since characterizations of coal and physical
coal processing are both involved in the conver-
sion of coal to synthetic fuels.
The activities in the synthetic fuels program
are divided into six major categories (figure 3):
1. Environmental Assessment. The iden-
tification and quantification of the
multimedia discharges, and the poten-
tial health and ecological effects of
these discharges.
2. Control Technology Development.
Development of process modification
and new control processes that would
eliminate any adverse effects of these
multimedia discharges.
3. Special Studies. Studies addressing
particular problems and specific
technologies.
4. Bench Scale Facilities. Integrated
facilities to evaluate generic control
systems, evaluations of modifica-
tion/new technologies, and quantifica-
tion of multimedia discharges.
5. Pilot Plant Activities. Evaluation of the
composition and quantities of the
multimedia emissions/discharges, their
potential environmental effects, and ef-
fects of feedstock/process variations
on the quality of discharges.
6. Commercial Activities. Evaluation of
existing commercial operations as to
emissions/discharges, efficiencies of
control systems, and effects of plant
variations.
Each environmental assessment contractor
(figure 4) deals with a specific technology for
converting coal to synthetic fuels and relates to
one of the following categories:
1. Low-Btu Gasification,
2. High-Btu Gasification, and
3. Coal Liquefaction.
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The assessments are 3-year studies that will
enable the contractor to develop into a center
of expertise in each specific area and will ad-
dress the following types of areas:
1
on current process
2.
3.
4.
5.
Background
technology,
Environmental data acquisition,
Current environmental background,
Control technology development, and
Environmental analysis/evaluation.
The control technology development con-
tractors are the same type, and have the same
rationale as the assessment contractors-that
is, to develop centers of expertise. Both groups
of contractors are responsible for broad
technical input and guidance for the synthetic
fuels program. However, the control tech-
nology contractors' responsibilities are struc-
tured differently than those in the environmen-
tal assessment area. The control technology
contractors relate to specific sections of the
conversion plant which will allow the maximum
applicability of control development to the
following three conversion technologies being
addressed (figure 5):
1. Converter Output Cleanup. Process
units that deal with the removal of
undesirable contaminants from the raw
gas or liquids.
2. Products/Byproducts. Process units
that convert the cleaned gas or liquids
into marketable products, and recovery
of byproducts material, such as sulfur.
3. Waste, Water, Fugitive Emis-
sions. Process technology that deals
with broad multisource discharge
streams.
The special studies activities address par-
ticular problem areas and/or technologies.
These studies normally rely upon specific ex-
pertise or capabilities in various organizations.
Figure 6 depicts the types of studies conducted
in this area. These studies range from
laboratory evaluations and bench scale process
development to broad paper studies.
The bench scale facilities (figure 7) are based
on research grants to identify problems, to
evaluate generic control technology and new or
modified control techniques. The Research
Triangle Institute is conducting a comprehen-
sive chemical analysis of the discharges from a
small gasifier that can be operated in a
nonisothermal mode. This study attempts to
correlate operating parameter versus the com-
position of the off gases. The North Carolina
State University will install a 22.5-kg/hr
(50-lb/hr) gasifier capable of evaluating various
raw gas cleanup techniques and various high
and low temperature acid gas purification
systems. The University of North Carolina is
studying water treatment systems.
The pilot plant activities (figure 8) interface
with various pilot plant operations in the private
and Federal sectors. These activities vary from
development of recommended test programs
and procedures to sampling and analysis.
The commercial activities (figure 9) deal with
data acquisition at operating commercial
facilities to quantify the multimedia discharges
and effects of process variations on the com-
position or quality of the discharges. The
evaluation of the Kosovo Lurgi Gasification
Plant in Yugoslavia is the largest and most com-
prehensive of these activities.
Details of these above programs will be dealt
with during this symposium.
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IERL-RTP
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FUEL PROCESS BRANCH
COAL CLEANING
— PHYSICAL COAL CLEANING
— CHEMICAL COAL CLEANING
— ENVIRONMENTAL ASSESSMENT
1— CONTROL TECHNOLOGY DEVELOPMENT
SYNTHETIC FUELS
— ENVIRONMENTAL ASSESSMENT
1— CONTROL TECHNOLOGY DEVELOPMENT
Figure 2. Fuel process branch.
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SYNTHETIC FUELS PROGRAM
ENVIRONMENTAL ASSESSMENT
CONTROL TECHNOLOGY DEVELOPMENT
SPECIAL STUDIES
BENCH SCALE
FACILITIES
PI LOT PL ANT
ACTIVITIES
COMMERCIAL
ACTIVITIES
Figure 3. Synthetic fuels program.
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LOW-BTU GASIFICATION - RADIAN CORPORATION
HIGH-BTU GASIFICATION - TRW ENERGY SYSTEMS
COAL LIQUEFACTION - HITTMAN ASSOCIATES
Figure 4. Environmental assessment.
CONVERTER OUTPUT CLEANUP - HYDROCARBON RESEARCH, INC.
PRODUCTS AND BYPRODUCTS - CATALYTIC
WASTE, WATER, FUGITIVE EMISSIONS - PULLMAN/KELLOGG
Figure 5. Control technology development.
12
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COMBINED CYCLES ENVIRONMENTAL PROBLEMS
CONVERSION RESIDUES LEACHANT
SYNTHETIC FUEL WATER REQUIREMENT
ADVANCED FUEL CONTAMINANT REMOVAL CHEMISTRY
DESULFURIZATION/DINITROGENATION OF LIQUIDS
Figure 6. Special studies.
NONISOTHERMAL POLLUTANT IDENTIFICATION
RAW AND ACID GAS CLEANUP FACILITIES
WATER TREATMENT FACILITIES
Figure 7. Bench scale facilities.
13
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RI LEY-STOKER
ERDA INTERAGENCY
SOLVENT REFINED COAL
SLAGGING GASIFIER
WELLMAN GALUSHA
Figure 8. Pilot plant activities.
KOSOVO LURGI GASIFICATION PLANT
WILPUTTEGASIFIERS
ERDA INDUSTRIAL GASIFIER DEMONSTRATIONS
Figure 9. Commercial activities.
14
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ENVIRONMENTAL ASSESSMENT
METHODOLOGY FOR
FOSSIL ENERGY PROCESSES
by
,R. P. Hangebrauck
Director, Energy Assessment and Control
Division
Industrial Environmental Research
Laboratory/RTP
Office of Energy, Minerals, and Industry
Environmental Protection Agency
Research Triangle Park,
North Carolina 27711
Abstract
IERL/RTP is conducting a number of pro-
grams involving environmental assessment and
control technology development for both
energy and industrial processes. However, this
report focuses on one particular aspect; i.e.,
the status of some IERL/RTP efforts to develop
Environmental Assessment Methodology,
especially as it relates to the Federal Interagen-
cy Energy/Environment R&D Program.
For purposes of brevity in presentation of a
large number of concepts relating to formula-
tion of Environmental Assessment
Methodology, this paper is formatted as a
series of figures or tables which outline the
essential features of Environmental Assess-
ment Methodology being developed for fossil
•e'nergy processes. It should be noted that the
approaches indicated are developing and
therefore subject to substantial change, but
certain components are better established than
others.
The efforts to develop Environmental
•Assessment Methodology involve several par-
ticipating environmental assessment contrac-
tors who, as a part of their overall activities,
have been assigned tasks to develop one or
more of the specialized environmental assess-
ment .methodology components. The various
components when complete will constitute the
overall environmental assessment
methodology protocol. This methodology is
needed on a reasonably near-term basis to
eliminate large gaps, inefficiencies and pro-
liferation of techniques for evaluating or com-
paring environmental effectiveness. However,
the potential value and usefulness of the ap-
proaches developed have such significance for
the Agency that it would be undesirable to pro-
ceed in other than a logical and orderly fashion.
An Environmental Assessment Steering Com-
mittee is in operation (see Appendix A for
members) to support certain methodology
tasks and provide review and consultation on
others.
ACKNOWLEDGMENTS
The author acknowledges the direct input
and/or availability of information developed by
IERL/RTP personnel and their contractors, and
personnel of other laboratories in EPA's Office
of Research and Development.
SUMMARY AND CONCLUSIONS
Environmental assessment and control
technology development programs are under-
way as part of the Interagency Energy/Environ-
ment R&D Program. The Industrial Environmen-
tal Research Laboratory at the Research
Triangle Park, North Carolina, is conducting
work in the fossil energy area in connection
with this effort. The environmental assessment
work underway is organized on an industry
basis and provides for a multipollutant,
multimedia analysis of problems and solutions
in support of the standards setting and
regulatory functions of EPA. Substantial need
exists for environmental assessment
methodology to support this rather ambitious
undertaking.
This presentation outlines a number of the
approaches or components comprising the en-
vironmental assessment methodologies. The
approaches, because of their complexity in
dealing totally with such entities as complex ef-
fluents, are only partially developed at this
time. However, enough progress has been
made to illustrate the overall approach and
several facets which are important com-
ponents. These include:
15
-------
1. Gathering and analyzing of existing
process data on energy systems.
2. Phased (Levels 1, 2, and 3) com-
prehensive chemical/biological testing
of process effluents.
3. Techniques for defining when and
which more costly detailed chemical
analysis is needed.
4. Compiling and organizing information
on control/disposal approaches.
5. Control assays to provide standardized
laboratory procedures to be used in
conjunction with Level 1 sampling and
analysis to define the best potential
control options.
6. Use of existing health and ecological ef-
fects and other data to define
Multimedia Environmental Goals
(MEG's).
7. Source analysis models to evaluate en-
vironmental alternatives by utilizing
MEG's to determine potential degree-
of-hazard or toxic unit discharge rate
for a given control option or plant.
8. Formats for information to be included
in standards of practice manuals which
provide part of the research documen-
tation from the Office of Research and
Development as input to EPA's pro-
gram offices. Such manuals will consist
of an integrated, multimedia, industry-
oriented, single-package review of the
environmental requirements, guide-
lines, and best control/disposal op-
tions.
The methodologies being developed as a part
i f the environmental assessment program are
^ extreme importance to the Agency in that
they represent prototype approaches to
multimedia, multipollutant problem identifica-
tion and control effectiveness evaluation for
complex effluents. They are prototypes of
potential future regulatory approaches that can
handle the whole problem and are aimed at
preventing problems before they occur.
Hopefully they will allow resolution of existing
problems on other than a one-pollutant-at-a-
time basis, a basis which is fraught with
endless studies, only partially effective results,
and high cost at all levels of implementation.
ENVIRONMENTAL ASSESSMENT
Current Process Technology Background
Environmental Data Acquisition
Current Environmental Background
Environmental Objectives Development
Control Technology Assessment
Environmental Alternatives Analysis
CONTROL TECHNOLOGY DEVELOPMENT
Gas Treatment
Liquids Treatment
Solids Treatment
Final Disposal
Process Modification
Combustion Modifications
Fuel Cleaning
Fugitive Emissions Control
Accidental Release Technology
TECHNOLOGY AREAS
Conventional Combustion
Nitrogen Oxide/Combustion Modification
Control
Fluid Bed Combustion
Advanced Oil Processing
Coal Cleaning
Synthetic Fuels
OUTPUT OBJECTIVES FOR
ENVIRONMENTAL ASSESSMENT
Defined Research Data Base for Stand-
ards
Quantified Control R&D Needs
Quantified Control Alternatives
Quantified Media Degradation Alter-
natives
Quantified Nonpollutant Effects and
Siting Criteria Alternatives
16
-------
IERL/RTP STANDARDS DEVELOPMENT SUPPORT RSD
IERL Develops
Standards Support
Plan (SSP) for Each
Energy Process
IERL Industry
Environmental
Assessment
IERL Develops Standards of
Practice Manual (SPM) for~
Criteria Pollutants. Developed
for Each Uniquely Different Basic
Energy Process (at the Commer-
cial or Demonstration Stage)
IERL Conducts
Control Technology RD6D
Standards Development
Research Data Base
Reports Developed by
IERL for Each Energy
Process
IERL Develops a Standards
of Practice Manual (SPM)
for All Other Multimedia
Pollutants of Concern and/or
Complex "Effluents of Concern
EPA Program Office Priori-
tization Studies for Standards
Setting
EPA Program Offices Develop Plan
for Detailed Standards Develop-
ment for Specific Energy Proc-
esses and Organize Working
Group
EPA Program Offices Conduct
Engineering Study to Develop
Background Document
EPA Program Offices Conduct Detailed
Internal and External Reviews,
Propose in Federal Register,
Conduct Further Reviews, and
Promulgate Standard
-------
PRIMARY USERS OF PROGRAM
ACTIVITIES/RESULTS
EPA
IERL/RTP (several inputs to internal pro-
gram)
OEMI/OR&D (inputs for planning, in-
tegrated assessments, OMB, Con-
gress)
Health and Ecological Effects Groups
(samples, source characterization,
ecological testing needs, pollutant ef-
fects data needs, test facilities)
Environmental Sciences (analytical
needs, pollutant transport/transforma-
tion study needs, test facilities,
samples)
Policy and Planning (development of
basis for technology/environmental
alternatives and costs)
Regional Offices (information on prob-
lems and control options on a
multimedia basis; technical assistance)
Enforcement (control information)
STATE AND LOCAL REGULATORY
Multimedia integration of industry en-
vironmental considerations
NIOSH
Information
Samples
Sharing of Data Acquisition Burden
Common Control Technology Iden-
tification
DOE
Environmental Input to On-going Pro-
gram
Independent Environmental Review of
DOE's Technology Development
Environmental Assessment Method-
ology
- Control Technology Recommendations
- Design Reviews
- Proposal Reviews
FEA
Energy Related Aspects of Environmen-
tal Control Approaches
MAS
- Environmental Inputs to National
Academy of Sciences/National
Academy of Engineering Studies
ENVIRONMENTAL GROUPS
- Environmental Alternatives and Control
Option Information
INDUSTRY
- Process Developers
- Control Technology Developers/Sup-
pliers
Environmental Engineers/Consultants
- Coal and Oil Processors/Users
- Equipment Suppliers/Servicers
GENERAL PUBLIC
Guidelines for Direct Use of Indi-
viduals
- Information on Problems/Control
STATE OF
DEVELOPMENT/COMMERCIAL-
IZATION AFFECTS APPROACH TO
ENVIRONMENTAL ASSESSMENT AND
CONTROL TECHNOLOGY DEVELOPMENT
Existing Energy Technologies
Commercial/Private Sector Capacity
Emerging Energy Technologies
ERDA/Department of Energy
velopments
- Private Sector Developments
De-
18
-------
U.S. DEPARTMENT OF
ENE?GY
U.S. ENVIRONMENTAL
PROTECTION AGENCY
FBC SYSTEMS AND
PROCESS DEVELOPMENT
ENVIRONMENTAL ASSESSMENT
AND CONTROL TECHNOLOGY
DEVELOPMENT
OPTIMUM ENVIRONMENTALLY
ACCEPTABLE FBC SYSTEMS
FOR COMMERCIALIZATION
EMERGING TECHNOLOGIES--PARALLEL EFFORTS IN PROCESS DEVELOPMENT
AND ENVIRONMENTAL ASSESSMENT
(Example for Fluidized Bed Combustion)*
*Ref. Murthy, K. and H. Nack, "Progress in EPA's Fluidized Bed Combustion
Environmental Assessment and Control Technology Development Program,"
Presented at the Fluidized-Bed Combustion Technology Workshop, Reston,
Virginia (April 1977).
19
-------
ENVIRONMENTAL
ASSESSMENT DEFINITION
An environmental assessment, as defined for
IERL/RTP studies of fossil energy processes, is
a continuing iterative study aimed at:
1. Determining comprehensive multi-
media environmental loadings and en-
vironmental control costs, from the ap-
plication of existing and best future
definable sets of control/disposal op-
tions, to a particular set of sources,
processes, or industries; and
Comparing the nature of these loadings
with existing standards, estimated
multimedia environmental goals, and
bioassay specifications as a basis for
prioritization of problems/control needs
and for judgment of environmental ef-
fectiveness.
20
-------
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Environmental assessment/control technology development diagram.
-------
ENVIRONMENTAL ASSESSMENTS
SERVE AS PARTIAL INPUT TO
INTEGRATED ASSESSMENTS
The Purpose of the Integrated Assess-
ment for Coal-Based Energy Tech-
nologies Is:
- To identify, describe, compare, and
quantify where possible the range and
magnitude of biophysical, socio-
economic, and energy impacts of alter-
native mixes, rates, levels, and timing
of the development and deployment of
coal-based energy technologies, supply
systems, and end uses.
- To identify and comparatively analyze
technological and institutional methods
of avoiding or mitigating undesirable
impacts.
- To recommend alternative policies that
will achieve the best balance of en-
vironmental quality, energy efficiency,
economic costs, and social benefits,
and to propose strategies for policy im-
plementation.
GENERAL STATUS OF ENVIRONMENTAL
ASSESSMENT METHODOLOGY
Developing (partly established, partly con-
ceptual)
Environmental Assessment Methodology
assignments made to specific E. A. con-
tractors
Because of timing, methodology
developed in parallel with preliminary en-
vironmental assessment
First compilation of methodology to be
available near end of 1 977.
ENVIRONMENTAL ASSESSMENT
Current Process Technology Background
Environmental Data Acquisition
Current Environmental Background
Environmental Objectives Development
Control Technology Assessment
Environmental Alternatives Analysis
CURRENT PROCESS
TECHNOLOGY BACKGROUND
Process Assessment Criteria include such fac-
tors as:
• Commercial status
• Existing capacity
• Schedules for construction, development,
etc.
• Priorities
• Quantities and types of residual emissions
• Projected process costs
• Energy efficiency and form of energy.
(This was considered a cost factor with
independent significance.)
• Applicability; i.e., the extent of projected
markets
• Rate of availability; i.e., how fast
technology can be brought to commercial
availability and applied
• Probability of success in development
(includes a variety of considerations; e.g.,
the scale on which the process has been
operated; the magnitude of the invest-
ment for commercial plants; how it will
fare in the competition among
technologies)
ENVIRONMENTAL DATA ACQUISITION
Unit Operations Organization
for Study of Pollutant
Sources (Examples)
• Raw Material Storage
- Windblown dusts
- Water runoff
- Leakage and venting
• Transportation
- Windblown dusts
- Open conveyor
- Transport liquids (water, organics)
Other handling losses
- Vehicular transport
• Raw Material Preparation
- Fuel or raw material drying
22
-------
- Grinding, pulverization
- Particulate collectors
- Coal washing
- Pretreatment steps
- Vents
Reactors/Convertors/Combustors
- Raw material feed mechanism
- Chemical/physical transformations
- Leakage and venting
- Flue gas from combustion/power
steam generation from fuel or fuel
residues
- Product utilization
Process Stream Separation/Clean-
ing/Treatment
- Raw gas cleanup
- Gas purification systems
- Catalyst/sorbent regeneration
- Claus sulfur plant tail gas treatment
- Flue gas desulfurization units
- Vents and flares
- Particulate collectors
- Tar oil/water separators
- Waste water treatment
- Leaks
- Cleaning agents and additives
Products and By-Products
- Product upgrading and recovery
- Sulfur and other by-product recovery
- Handling and storage losses
- Utilization
Final Disposal
- Flyash, ash, and slag
- Spent catalyst and sorbent disposal
- Hazardous solid wastes
- Ponds
- Landfills
- Piles
- Thermal cooling (air, water, heat, cool-
ing water, blowdown, drift)
Auxiliary Facilities
- Oxygen plant
- Hydrogen plant
Accidental/Transient Release
ENVIRONMENTAL DATA
ACQUISITION
A phased approach:
Level 1 - Comprehensive Screening
("Criteria pollutants" included)
Level 2 - Directed Detailed Analysis Based
on Level 1
Level 3 - Process Monitoring on Selected
Priority Pollutants Based on Levels 1 and
2
ENVIRONMENTAL DATA ACQUISITION
Level 1 Sampling and Analysis
Effluent Samples:
Liquids
Solids
Evaluated for Discharge to Media:
Air
Water
Land
Analyses:
Physical
Chemical
Biological
Key Environmental Parameters:
Health
Ecological
ENVIRONMENTAL DATA ACQUISITION
Level 1 Sampling*
Sample
Stream size
Gas 30 m3
Liquid 10 1
Location
Ducts, stacks
Lines or tanks
Sampling
procedure
SASS train
Tap or valve sam-
pling
Open free-flowing Dipper method
streams
Solids 1 kg
Storage piles
Conveyors
Coring
Full stream cut
* Environmental Assessment Sampling and Analysis: Phased
Approach and Techniques for Level 1, EPA-600/2-77-115
(NTIS No. PB 268563/AS), June 1977.
23
-------
Field
Samples
PHYSICAL
Solids Morphology
INORGANIC
Elemental Anal/sis
(Spark Source Mass
and Atomic Absorption
Spectroraetry)
ORGANIC
Liquid Chromatography
Infrared and Low
Resolution Mass Spectrometry
BIOASSAY
in vitro Cytotoxicity;
Bacterial Mutagenicity;
Ecological Testing;
in vivo Toxicity
LEVEL 1 ANALYSIS*
*Environmental Assessment Sampling and Analysis: Phased Approach
and Techniques for Level 1, EPA-600/2-77-115 (NTIS No. PB 268563/AS)
June 1977.
24
-------
ENVIRONMENTAL DATA ACQUISITION
DRAFT BIOASSAY PROTOCOLS*
LEVEL I - MINIMAL TEST MATRIX
fO
en
Sample Type
Water and Liquids
Solids (Aqueous Extract,
Feed, Product, Waste)
Gases (Grab Sample)
Particulates
Sorbent (Extract)
Microbial
Mutagenesis
Microbial
Mutagenesis
Microbial
Mutagenesis
Microbial
Mutagenesis
Health Effects Tests
Rodent Acute Algal
Toxicity Bioassay
Rodent Acute Algal
Toxicity Bioassay
(Rodent Acute Cyto-
Toxicity)** toxicity
Cyto-
toxicity
Ecology Effects Tests
Static Soil
Bioassays Microcosm
Static Soil
Bioassays Microcosm
Plant Stress
Ethylene
Soil
Microcosm
*IERL-RTP Procedures Manual: Level 1 Environmental Assessment; iJiological Tests
for Pilot Studies, EPA-600/7-77-043 (NTIS No. PB 268484/AS) April 1977.
**Reconmended test not specified because of limited sample availability of
secondary priority.
-------
LEVEL 1 - BIOASSAY TESTS ORGANISMS
Health Effects Tests
• Microbial Mutagenesis
- Salmonella typhimurium
• Cytotoxicity
- Rabbit Alveolar Macrophages (RAM)
- Human Lung Embryo Fibroblasts (Wl-
38)
• Rodent Acute Toxicity
- Rats
Ecological Effects Tests
Fresh Water
• Algae Bioassay
- Selenastrum capricornutum
- Microcystis aeruginosa
- Amacystis cyanea
- Anabaena fos-Aquae
- Diatom-Cyclotella
- Diatom-Nitzschia
• Static Bioassay
- Fathead minnow
- Daphnia pulex
Marine
• Marine Algae Bioassay
- Skeletonema costatum
• Static Bioassay
- Juvenile sheepshead minnows
(cyprinodon variegatus)
- Adult grass shrimp (Palaemonetes
pugio or P. vulgaris)
Terrestrial
• Plant Stress Ethylene Test
- Soybean
• Soil-Litter Microcosm
- Soil organisms
26
-------
ENVIRONMENTAL ASSESSMENT MEASUREMENT AND EVALUATION SUMMARY
Environmental
Assessment
Measurement
Levels
Level 1
(Coraprehens ive
Screening)
Level 2
(Directed Detailed
Anal/sis Based on
Level 1)
Level 3
(Process Measurements
on Selected Priority
Pollutants Based on
Levels 1 and 2}
Sampling
Accuracy
Low
Higher
Highest
Analysis
Chemical
Accuracy/
Specificity
Low
Higher
Highest
Cone.
Level
Measured
Effluent
Effluent
Effluent
Bioassay
Accuracy/
Specificity
Low
Higher
Highest
Effect
Level
Measured
Acute
Exposure
Acute
Exposure
Chronic
Exposure
Media
Measured
Effluent
Effluent
Effluent
Environmental Alternatives Analysis
Assessment
Alternatives
(Multimedia
Environ. Goal
Sets Used)
MATE*
MATE*
(EPC**
ES***>
(EPC**
ES***)
Source
Analysis
Models
Used
SAM/IA
SAM/IA
SAM/I
SAM/ I I
SAM/ I I
Media
Evalua-
ted
Effluent
Effluent
(Est.
Ambient
(Est.
Ambient)
Effect
Level
Evalua-
ted
Acute
Exposure
Acute
Exposure
Chronic
Exposure
Chronic
Exposure
IS)
•vj
* MATE (Minimum Acute Toxicity Effluent)
** EPC (Estimated Permissible Concentrations)
*** ES (Existing Standards)
-------
ANALYTICAL CHEMICAL TECHNIQUES APPLICABLE
IN LEVEL 2 FOLLOWING LEVEL 1 SURVEY OF STREAM CONTENTS*
Category A
Wet Chemical Methods
(e.g., S04, N03, F, total phenolics)
Elemental Analysis
Spark-Source Mass Spectrometry
Atomic Absorption Spectrometry
Arc and Spark Emission Spectrometry
Neutron Activation Analyses
X-Ray Fluorescence
Organic Materials
Infrared Spectrometry
G.C. - Mass Selective Detector
G.C. - Selective Detector
(e.g., Flame lonization, Flame
Emission, Electron Capture)
Chemi-lonization Mass Spectrometry
Category B
Separation Techniques
High-Performance Liquid
Chromatography
Gas Chromatography
Ion Exchange
Solvent Extraction
Structure Elucidation
Nuclear Magnetic Resonance
High-Resolution Mass Spectrometry
Photoelectron/Inner Shell
Electron Spectrometry (Surface
Inorganics)
Infrared Spectrometry
Quantitative Measurement
If not achieved in Separation
or Structure Elucidation,
utilize Category A.
*This is not an all inclusive or an exclusive list. Choice of the most cost/
information effective methods will vary from sample to sample. Environmental
Assessment Sampling and Analysis: Phased Approach and Techniques for
Level 1, EPA-600/2-77-115.. (NTIS No. PB 268563/AS), June 1977.
28
-------
Utilize Source
Analysis Model to
Determine Impact
Level 1
QMMical
Analysis on
Each Sample
}
Effluent
Concentration
of Level 1
Chemical Analy-
sis Compound
Class
N)
CO
Level 1
Bioassay
on Each
Sample
3
Level 1
Bioassay
Results
(+, -. ECSO)
•y
7*
For Each
Compound., Could
Effluent Cone.
Exceed the MATE,
If Total Weight
of Class Present
was the MEG Compound?
Ar
MEG
Compounds
Present
Above
Levels of
cern?
Analysis Only
for MEG Sub-
tially Present
at Concentra-
Is
Effluent
Toxic Upon Acute
(Short Term)
No
' J
General
Level 2
Chemical
Analysis
and/or
Level 2
Bioassay
(Priority
Samples
Only) to
Determine
Nature of
Problem
Finished
DECISION LOGIC FOR PHASED LEVEL 1-LEVEL 2 ANALYSIS
-------
CURRENT ENVIRONMENTAL
BACKGROUND
REPORTS
- Potentially Hazardous Emissions from
the Extraction and Processing of Coal
and Oil (Battelle) (EPA-650/2-75-038,
NTIS No. PB 241 803, May 1 975}
- Summary of Key Federal Regulations
and Criteria for Multimedia En-
vironmental Control (RTI) (Draft, June
1977}
- Estimation of Permissible Concentra-
tions of Pollutants for Continuous Ex-
posure (RTI) (EPA-600/2-76-155,
NTIS No. PB 253959/AS, June 1 976)
- Preliminary Format for Compilation of
Ambient Trace Substances Data (RTI}
(August 1976}
ACTIVITIES
- Compilation of Existing Physical,
Chemical, and Toxicological Data for
Specific Pollutants
- Gathering of Information on
Transport/Transformation Models
- Compilation of Ambient Trace
Substances Data
FEDERAL REGULATIONS APPLYING
QUANTITATIVE LIMITATIONS TO
SPECIFIC, POTENTIAL ENVIRON-
MENTAL POLLUTANTS
• EPA Effluent Standards
• EPA Toxic Pollutant Effluent Standards
(Proposed)
• EPA Pesticide Limits
• Standards for Protection Against Radia-
tion
• Criteria for the Evaluation of Permit Ap-
plications for Ocean Dumping of
Materials
ENVIRONMENTAL OBJECTIVES
DEVELOPMENT
(Multimedia Environmental Goals)
General Classes
Organic and Inorganic Totals
Organic Compounds
Inorganic Compounds
Physical Agents
Complex Effluent Assays
Heat
Noise
Microorganisms
Radionuclides
Nonpollutant Factor (e.g., water use, land
use)
SELECTION FACTORS FOR CHOICE OF
CHEMICAL SUBSTANCES AND
PHYSICAL AGENTS TO BE INCLUDED
IN MEG CHART
National Primary and Secondary Am-
bient Air Quality Standards
Occupational Safety and Health Ad-
ministration Standards for Air Con-
taminants
National Emission Standards for Hazard-
ous Air Pollutants
New Stationary Source Performance
Standards
Emissions Standards for Control of Air
Pollution from New Motor Vehicles and
New Motor Vehicle Engines
National Interim Primary Drinking
Water Regulations
Supplement: 1962 Public Health Service
Regulations on Drinking Water
PRIMARY SELECTION FACTORS
• Known or Suspected as an Emission from
Coal or Oil Processing
• All Classes of Compounds/Substances
Represented
SECONDARY SELECTION FACTORS
• Found as Pollutant in the Environment
• Highest Toxicity
PRIORITIZING FACTORS
• Standards or Criteria Proposed or Set
(Ambient, Emission, or Occupational)
• TLV or LD50 Known
30
-------
• On EPA Ordered NIOSH Carcinogen List Categories Classes Substances
• On EPA Consent Decree List Organics Portion 26 45 350
Inorganics Portion 59 -- 300
Approximate makeup of organic and in- — — —
organic categories and classes of substances •" 45 650
on the list thus far:
31
-------
MULTIMEDIA POTENTIAL POLLUTANT LIST
ORGANIC-COMPOUND CATEGORIES AND CLASSES
Category
1 - Aliphatic Hydrocarbons
2 - Alkyl Halides
3 - Ethers
4 - Halogenated Ethers
5 - Alcohols
6 - Glycols, Epoxides
7 - Aldehydes, Ketones
8 - Carboxylic Acids & Derivatives
9 - Nitriles
10 - Amines
11 - Azo Compounds, Hydrazine, & Deriv.
12 - Nitrosamines
13 - Mercaptans, Sulfides & Disulfides
14 - Sulfonic Acides, Sulfoxides
15 - Benzene, Substituted Benzene
Hydrocarbons
16 - Halogenated Aromatic Hydrocarbons
17 - Aromatic Nitro Compounds
18 - Phenols
19 - Halophenols
20 - Nitrophenols
21 - Fused Aromatic Hydrocarbons'&
Derivatives
22 - Fused Non-Alternant Polycyclic
Hydrocarbons
23 - Heterocyclic Nitrogen Compounds
24 - Heterocyclic Oxygen Compounds
25 - Heterocyclic Sulfur Compounds
26 - Organometallics
Class
Alkanes and Cyclic Alkanes
Alkenes, Cyclic Alkenes, and Dienes
Alkynes
Saturated Alkyl Halides
Unsaturated Alkyl Halides
Ethers
Halogenated Ethers
Primary Alcohols
Secondary Alcohols
Tertiary Alcohols
Glycols
Epoxides
Aldehydes, Ketones
Carboxylic Acids with Additional
Function Groups
Amides
Esters
Nitriles
Primary Amines
Secondary Amines
Tertiary Amines
Azo Compounds, Hydrazine, & Deriv.
Nitrosamines
Mercaptans
Sulfides, Disulfides
Sulfonic Acids
Sulfoxides
Benzene, Substituted Benzene
Hydrocarbons
Halogenated Aromatic Hydrocarbons
Aromatic Nitro Compounds
Monohydrics
Dihydrics, Polyhydrics
Hydroxy Compounds with Fused Rings
Halpphenols
Nitrophenols
Fused Aromatic Hydrocarbons &
Derivatives
Fused Non-Alternant Polycyclic
Hydrocarbons
Pyridine & Substituted Pyridines
Fused 6-membered Ring Heterocycles
Pyrrole & Fused Ring Derivatives of Pyrrole
Nitrogen Heterocycles Containing Additional
Hetero Atoms
Heterocyclic Oxygen Compounds
Heterocyclic Sulfur Compounds
Alkyl or Aryl Organometallics
Sandwich Type Organometallics
Metal Porphyrins & Other Chelates
32
-------
MULTIMEDIA POTENTIAL POLLUTANT LIST
INORGANIC CATEGORIES
(Element category ircludes zero valence species, ions of the element, and certain
specific compounds)
Group
IA
IIA
IIIA
IVA
VA
VIA
VIIA
HIE
IVfc
VB
VIB
VIIB
VIII
27 - Lithium
28 - Sodium
29 - Potassium
30 - Rubidium
31 - Cesium
32 - S-iryllium
33 - xajnes-iura
34 - Calcium
35 - Strontium
36 - Barium '
37 - Boron
32 - Aluminun
39 • Gal Hun
4C - Indium
41 - Thallium
42 - Carbon
43 - Silicon
44 - Germanium
45 - Tin
46 - Lead
47 - Nitrogen
48 - Phosphorus
49 - Arsenic
50 - Antimony-
Si - Bismuth
52 - Oxygen
52 - Sulfur
54 - Seleniur.
SS - Telluriun
56 - Fluorine
S't - Chlorine
5£ - Bromine
53 - Iodine
60 - Scandium
61 - Yttrium
53 - Titaniuw
63 - Zircaniun:
64 - He.fr.iai!
65 - Vsnadium
66 - Niobium
67 - Tantalum
65 - Chromium
€9 - Molybdenum
70 - Tungsten
71 - Majaiese
72 - Iror,
73 - RutheniuTi
74 - Cobalt
75 - *htoiura
76 - Nickel
77 - Platinum
Group
IB
IIB
Category
78 - Copper
79 - Silver
30 - Gold
81 - Zinc
82 - Cadmium
83 - Mercury
34 - Lathanides
85 - Actinides
33
-------
MULTIMEDIA ENVIRONMENTAL GOALS
Emission Level Goals
AIR
WATER
LAND
Based on Best Technology
Existing Standards
NSPS, BPT, BAT
Developing Technology
Engineering Estimates
(R§D Goals)
Based on Ambient Factors
Minimum Acute
Toxicity Effluent
Based on
Health
Effects
Based on
Ecologi-
cal
Effects
Ambient Level Goal
Based on
Health
Effects
Based on
Ecologi-
cal
Effects
Elimination of
Discharge
Natural Background
Ambient Level Goals
AIR
WATER
LAND
Current or Proposed Ambient
Standards or Criteria
Based on
Health
Effects
Based on
Ecological
Effects
Toxicity Based on Estimated
Permissible Concentration
Based on
Health
Effects
Based on
Ecological
Effects
Zero Threshold Pollutants Estimated
on Permissible Concentrations
Based on Health Effects
-------
CATEGORY; 15 WLN; R
S£32EN|^ CgHg (benzol, phenylhydride, phene). STRUCTURE:
A clear, colorless liquid.
PROPERTIES:
Molecular wt: 78.11; mp: 5.5; tap: 80.1;
d: 0.87863|°; vap. press: 100 tin at 26.1" C; vap. d: 2.77;
solubility 1n water: 1,780 mg/t it 25" (ref. 52); soluble 1n tUsu« Itplds
NATURAL OCCURRENCE. CHARACTERISTICS. ASSOCIATED COMPOUNDS;
Benzene cccurs 1n straight-run petroleum distillates and in eo«1-tir distillates. Rural background
for benzenu Is reported as 0.1 ppbe (ref. 1). This Is equivalent to 0.017 ppb or 0.054 pg/m3. The
odor recognition level Is 10.5 to 210 mg/m3 {ref. 3). Benzene participates to a very limited
degree In photooxldatlon reactions (ref. 3). Benzene has been Identified In at least one drinking
water supply 1n the United States In concentrations as high as 10 ug/i (ref. 13). There Is a
strong Indication th«t plants may perform a major role in the degradation and synthesis of benzene
In the environment (ref. 52).
TOXIC PROPERTIES. HEALTH EFFECTS;
Senzene IT an acute and cnronic poison. It Is absorbed through the skin, but most often
poisoning occurs through Inhalation. The rate of absorption of benzene through the skin has
been reported to be 0.4 mg/cm2/hr (ref. 53). It Is estimated that 50 percent to 70 percent
of benzene Inhaled may be absorbed through the lungs (ref. S3). In acute poisoning, benzene
acts as a narcotic. Chronic poisoning 1s characterized by damage to the blood-forming tissues
and changes 1n body organs. Including the lymph nodes (ref. 54). Inhalation of 210 ppm has
resulted 1n blood disorders for exposed workers (refs. 4.2,9). Benzene can Induce chromosomal
aberrations 1n humans (ref. 54).
Benzent 1s listed 1n the NIOSH Suspected Carcinogens List. The EPA/NIOSH ordering number
Is 7222. Inhalation of 2,100 mg/nr for 4 years has resulted In cancer In an exposed worker,
and large doses of benzene painted repeatedly on the skin of mice have resulted In some Incidence
of skin carcinomas. TO^'s associated with these tests are extremely high and are probably not
Indicative of the true carcinogenic potential of benzene. An epidemiologies! study conducted by
•SIOSH Indicates that the Incidence of leukemia 1n workers exposed to benzene is at least five
times the expected Incidence (ref. 54).
Benzene 1s toxic to aquatic life: 96 hours. TLm's are reported ranging from 10-100 ppm (ref. 2).
REGULATORY ACTIONS. STANDARDS. CRITERIA. RECOGNITION. CANDIDATE STATUS FOR SPECIFIC REGULATION!
TLV: 33 mg/m3 (10 ppm). ACGIH classified benzene as an Occupational Substance Suspected of Oncogenlc
Potential for workers. (Evidence linking benzene to leukemia was limited at the time the TU was established.)
Benzene appears on EPA Consent Decree List with an assigned priority of 1.
Benzene is the subject of a NIOSH Criteria Document (ref. 55).
The Labor Department has issued emergency temporary standards limiting worker exposure to benzene to 1 ppm as an
8-hour tire-weighted average concentration, with a celling level of 5 ppm for any 15-minute period during the 6-hour
day (ref. 54). The emergency standard Is based'on conclusive evidence that exposure to benzene presents a
leukemia hazard (ref. 54). The standard also prohibits repeated or prolonged skin exposure to liquid benzene.
MINIMUM ACUTE TOXICITV CONCENTRATIONS;
*1r, Health: 3.0 x 103 ug/m3
Hater, Health: 15 x 3.0 x 103
• 4.5 x 10* vg/t
Land, Health: 0.002 x 4.5 x 10 • 90 pg/g
Air, Ecology:
Water, Ecology: 100 x 10 • 1.0 x 103 pg/i
Land, Ecology: 0.002 x 1.0 x 103 • 2 ug/g
ESTIMATED PERMISSIBLE CONCENTRATIONS!
EPC^, • 103 x 30/420 • 71.4 ug/m3
EPCAH1* ' 10/42° " °-024 ppm
EPCHH, • 15 x 71.4 • 1,071 pg/i
tPCm • 13.8 x 30 » 414 pg/i
EPCLH • 0.002 x 414 • 0.83 pg/g
EPCAC1 • 103 x 3/420 -7.1 pg/m3
EPCyj » 15 x 7.1 • 107 pg/t
EPCLC • 0.002 x 107 • 0.21 pg/g
EPCgn • 50 x 10 • 500 pg/i
EPCLE • 0.002 x 500 - 1 ug/g
35
-------
MULTIMEDIA
ENVIRONMENTAL
GOALS
X
15
BENZENE
(ppm Vol)
Witir.pg/l
tporowt)
Land, pg/g
(ppmWt)
EMISSION LEVt-L GOALS
1. StMd on B«it Technology
A. fitonf S»ndw4t
NSPS, BPT. 6AT
B. Duilopinf Txlmolew
tn»o»ihn( Etnmim
IRdOOailil
II. BiMd on Ambitnt Fteton
A. Minimum Acull
TOMCIIV Ei::utnl
Hul«i tlltm
3.013
4.5E4
9.0E1
Burton
leolo»«l
1.0E3
2.0EO
B, Ambimt LiMl Q«l-
Bwdon
H»l*> CHKU
7.1
107
0.21
BMrt«n
Iff MB
500
1
c. .»..«
»»*•«»_*•
0.054
lot
•To b« multtplitd by dilution fictor
AMBIENT LEVEL GOALS
Air,jig/m3
(ppm Vol)
V»n>r,p«/l
(pprnVVt)
Lind. inlt
(ppm W«)
1. Currtnt or PropoMd Ambltnt
StmdardiorCridfli
A. kMdon
Ht«l«i (HMM
B. Biudon
iMloilul Etfin
II. Toxieliy BtMd Eitlmntd
Nnnlpibl* CeneMlratlon
At MIM on
Multn KflMft
71.4
(0.024)
414
0.83
B. Btudcfl
InlDllMl IH.CH
500
1
•m«MHNl«ilf«Hn
7.1
107
0.21
tMaximum concentration Identified 1n drinking water.
36
-------
CONTROL TECHNOLOGY ASSESSMENT
Control System and Disposal Option Infor-
mation and Design Principles
Control Process Pollution and Impacts —E.
A. Contractors Plus Special Facilities
Accidental Release, Malfunction, Tran-
sient Operation Studies
Field Testing in Related Applications
Define Best Control Technology Recom-
mendations
CONTROL TECHNOLOGY ASSESSMENT
Multimedia Environmental Control
Engineering Manual
(Control Approach Categories):
Gas Treatment
Liquids Treatment
Solids Treatment
Final Disposal
Process Modification
Combustion Modification
Fuel Cleaning
Fugitive Emissions Control
Accelerated Release Technology
CONTROL APPROACHES
Gas Treatment
Mechanical Collection
Electrostatic Precipitators
Filters (fabric, granular, etc.)
Liquid Scrubbers/Contactors (aqueous,
inorganic, organic)
Condensers
Solid Sorbents (mol sieves, activated
carbon)
Incineration (direct and catalytic)
Liquids Treatment
Settling, Sedimentation
Precipitation, Flocculation, Sedimenta-
tion
Centrifugation and Filtration
Evaporation and Concentration
Distillation, Flashing
Liquid-Liquid Extraction
Gas-Liquid Stripping
Neutralization
Biological Oxidation
Wet Thermal Oxidation
Activated Carbon Absorption
Ion Exchange System
Cooling Tower (wet and dry)
Chemical Reaction and Separation
Solids Treatment
Fixation
Recovery/Utilization
Processing/Combustion
Chemical Reaction and Separation
Oxidation/Digestion
Physical Separation (specific gravity,
magnetic, etc.)
Final Disposal
Pond Lining
Deep Well Reinjection
Burial and Landfill
Sealed-Contained Storage
Dilution
Dispersion
Process Modifications
Feedstock Change
Stream Recycle
Combustion Modification
Flue Gas Recycle
Water Injection
Staged Combustion
Low Excess Air Firing
Optimum Burner/Furnace Design
Alternate Fuels/Processes
Fuel Cleaning
Physical Separation (specific gravity,
surface properties, magnetic)
Chemical Refining
Carbonization/Pyrolysis
Liquefaction/Hydrotreating (HDS,
HDN, Demetallization)
Gasification/Separation
Fugitive Emissions Control
Surface Coatings/Covers
Vegetation
Leak Prevention
Accidental Release Technology
Containment Storage
Flares
Spill Cleanup Techniques
37
-------
MULTIMEDIA ENVIRONMENTAL CONTROL ENGINEERING MANUAL
(Example of Specific Device Form)
CLASSIFICATION
Fuel Cleaning
ICENKRIC DCVICC on pRoccta
I Physical Separation - Pent* M»d1» S>n«ratar of Ccal
DCVICC OR PRQCC34
Belknap Calc urn Chloride Hasher*
tUMICM
7.1.1.3
POLLUTANTS
pOMTROLLIO
OA8E9
AIR
PARTICULATga
DISSOLVED
WATER
LCACKAtLC
LAND
nwmytptisT
OR9ANIC
IMOH9AHIC
50,
IHE
NO)
PROCESS DESCRIPTION8
Figure 1 shows a schematic diagram of the Belknap calcium
chloride washer. Preslzed and prewetted raw coal enters at
the surface qf the washer solution and 1s separated'accord-
Ing to the various specific gravities.C Refuse settles to
the bottom and Is removed by a screw conveyor running paral-
lel to the refuse conveyor." Solution within the washer Is
circulated by two opposing Impellers.
The Belknap washer uses calcium chloride solutions ranging
In specific gravity from 1.T4 to 1.25. These solutions are
circulated through the washer In an upward direction'to pro-
duce an effective specific gravity of 1.40 to 1.60. Both
flow and density are carefully controlled to provide the
desired separation.
A second method which could be used to control the specific
gravity within the washer 1s to wash the coal product with a
calcium chloride solution to remove any suspended solids
(slimes). This dense solution Is then recycled to the washer
to maintain the right specific gravity. In this case, the
calcium chloride Is used more.as « stabilizing agent than
the dense media Itself. If the suspended solids from the washed coal product can be recycled back to the,
washer, the amount of calcium chloride required for density control can be reduced. In this way, the solids
which naturally occur In the coal can be used to maintain the heavy density medium. Considerations of this
type could Improve the economics of this systems.over other dense medium systems which utilize material from "
an outside source for density control, e. g. Magnetite Processes.
The washed coal product leaving the system has a considerable amount of entrained calcium chloride solution.
This entralnment can reduce potential problems In coal dusting and freezing. The loss of calcium chloride,
however, may limit the economic application of the process to coarser sizes of coal.
Figure 1. THE BELKNAP CALCIUM WLORIOE
MASHER (1)
20
PRMiURC
Iftl
KPt
VOLUMCTRIC RATE
MAM RATC
miner RATC
J/f
APPLICATION RAN6E
The -effective specific gravity within the washer can be
adjusted from 1.40 to 1.60 by varying the solution density or
reclrculatlon rate. Consequently, the range of physical separa-
tion Is limited to a specific gravity within this range.
Feed sizes can range from 8-1n. (20.3 cm) to 3/8 In. (.95 on),
however the feed to a single unit should not fluctuate very much. The size range that can be washed In a
standard washercan be varied up to a 4:1 ratio, put should be limited to 3:1 or 2:1 If possible.
38
OPfRATMO RANCU
11 7 Ml
IVhr
-------
.
Ci'-FITA.i. CCS1S
CrFICICNCiei
The recovery efficiency for coal coarser than 1/4-
Inch Is 95 to 99% of the laboratory float sink tests.
Trace elements association and removal characteristics
for the physical separation of coal In general are
shown 1r» Table 1. The level of fluorine, which 1s pre-
sent as part of the mineral apatite, would also be re-
duced. The chlorine and bromine contaminants (as well
is the? sodium and potassium associated with them) which
are contnonly present as the mineral halite would be
removed along with other matter removed during coal
benefication, (3).
Table 1. TRACE ELEMENT ASSOCIATION ANQ
REMOVAL CHARACTERISTICS
NOTES
A) For other dense red-la separators, see all devices
under 7.1.1 and 7.1.2.
B) Based on Information from the Process Machinery
Division of the Arthur G. McKee 4 Co., (reference 1)
This device can also be used 1n a secondary circuit
to separate sink product from e primary separator
Into middlings and refuse.
0) Units can be designed with the separating compart-
ment divided Into two parallel sections. Each sec-
tion would be equipped with Individual medium cir-
culation systems thus making 1t possible to wash a
much wider range In one machine.
Association
Organic
Mora organic
More mineral
Mineral
Trace Elements Expected Removal
Ge, Be. B and U None
P. Ga, T1, .V, and Sb Small Amount
Co. N1, Cr, Se and Cu Partial
Hg. Zn, Cr, Cd, As,
Pb, Mo, and Mn
Slgnflcant
ENVIRONMENT*!. PROBLEMS
Coal preparation reduces stack gas emissions but may
also create pollution problems 1n the following areas.
1) land pollution created by refuse disposal.
2) water pollution from the leaching of oxidized
refuse material.
3) air pollution from the spontaneous combustion of
refuse piles.
MANUFACTURER? SUPPUEn
ASV Engineering Ltd.
GEOMIN
Minerals Processing Co., D1v. of Trojan Steel Co.
Process Machinery Division, Arthur G. McKee & Company
1) Mitchell, David R., and Leonard, Joseph w., ed. Coal Preparation. AIME, New York, Second Edition, (1950)i
Third Edition, (1968). . rjj
2) Lawry, H. H., ed.. Chemistry of Coal Utilization, John Wiley and Sons, New York, First Edition, (1945);
Second Edition (196171 ,,,
3) Mezey, E. J., Singh, ,S., and Hlssong, 0. W., "Fuel Contaminants: Volume I, Chemistry EPA 600/2-76-177a,
(1976).
39
-------
coal cleaning
Properties
(physical,
of
CONTROL TECHNOLOGY ASSESSMENT
Multimedia Environmental Control Engineering
Manual (Stepwise guidance for defining
specific control options for specific situations):
• Medium Phase (gas, liquid, solid)
• Medium Description (combustible
gases, black water,
waste, etc.)
• Medium Physical
(temperature, pressure)
• Pollutant Species Present
• Pollutant Concentration
• General Technology
chemical treatment; prevention
pollutant formation; final disposal)
• Generic Device (ESP, dry inertia! collec-
tor, etc.)
• Specific Device (commercial devices
and specifications)
STANDARDS OF PRACTICE MANUALS
• Subject
A uniquely different basic energy proc-
ess (at the commercial demonstration
stage) in a particular industry
• Example
Low-Btu Gasification - Wellman
Galusha
• Aim
Provide an integrated, multimedia,
industry-oriented, single-package
review of the environmental re-
quirements, guidelines and best con-
trol/disposal options. Accounts for
variations needed for different regional
site alternatives.
CONTROL TECHNOLOGY ASSESSMENT
Standards of Practice Manual Outline
• Summary
Outline of Basic Process
Process Modules
Control/Disposal Modules
Control/Disposal Costs
Variations Resulting from Regional
Siting Factors
Existing Environmental Requirements
Existing Standards
Air
Water
Land
Other Environmental Requirements
Environmental Guidelines
Regional Considerations
Environmental Emissions and Factors
Achievable
Criteria
MEG (Pollutant)
MEG (Nonpollutant)
Best Control/Disposal Practice
Gas Treatment
Liquids Treatment
Solids Treatment
Final Disposal
Combustion Modification
Fuel Cleaning
Fugitive Emissions Control
Accidental Release Technology
Regional Variations
Detailed Definition of Basic Process
Process Module No. 1
Source Unit Operations (Unit
Operations Pollutant Sources)
Control Options/Emissions/
Costs
Commercially Operated
Commercially Operated on a
Different Process/Industry
Pilot Data Available
Process Module No. 2, 3 ...
Process Module No. n
40
-------
I }
Level 1
Waste
Water
Sample
I
CONTROL TECHNOLOGY ASSESSMENT
Contro1 Assay Example
Portion 1
_ Po.ZJ.ion
I
I _Pprt_iprL_n
Water
Bioassay(s)
Negative
Stop
Positive (Evaluate Control
Option)
Control
Assay (e.g..
Lab Biologi-
cal Oxidation)
Water
Bioassay(s)
Negative*
Stop
Positive (Evaluate Another
Control Option)
Control
Assay (e.g.,
Lab Wet
Oxidation)
Water
Bioassay(s)
Negative y
Stop
Positive (Evaluate Another
Control Option)
41
-------
ASSESSMENT ALTERNATIVES USING
ASSESSMENT ALTERNATIVES
Air
Water Land
BT
EPC
<
r
.
NB
SD
MATE
0 Existing standards.
0 Developing technology
- 19S3
- 1988
- 1993
e Current vs Proposed Ambient
Stds or Criteria
- Based on Health Effects
- Based on Ecological Effects
0 Toxicity Based Estimated
Permissible Concentration
- Based on Health Effects
- Based on Ecological Effects
0 Zero Threshold Pollutants
Est. Perm. Cone.
- Based on Health Effects
° Elimination of Discharge
- Based on Natural Background
* Significant Deterioration
~ Based on Regional Average
Backgrounds
0 Minimum Acute Toxicity Effluent
- Based on Health Effects
- Based on Ecological Effects
MEG Types
1A
3A
4A
5A
7A
8A
9A
10A
11A
12A
»
2W
3W
4W
5W
6W
TV
8W
9W
10W
11W
12W
75¥
it
2L
3L
4L
SL
IE
7L
|T
9L
10L
1U,
12L
TUT
42
-------
ENVIRONMENTAL ALTERNATIVES
ANALYSES
Source Analysis Models tSAM's)
SAM/IA For Rapid Screening
SAM/I For Screening
SAM/11 General Approach to
Evaluating any U.S. Regional Site Alter-
native
Source (a, b, c...)
(gas, liquid, solid)
Air Effluent Streams
Water Effluent Streams > (k^, k k ...)
Land Effluent Streams ^ (kQ, k., k ...)
SCHEMATIC IDENTIFICATION OF
SOURCES/CONTROL-OPTIONS/EFFLUENTS
ENVIRONMENTAL ALTERNATIVES
ANALYSES
Assessment Alternatives
Best Technology (BT)
• Minimum Acute Toxicity Effluent
(MATE)
• Existing Ambient Standards (ES)
• Estimated Permissible Concentration
(EPC)
• Natural Background/Elimination of
Discharge (NB)
• Significant Deterioration (SD)
ENVIRONMENTAL ALTERNATIVES ANALYSIS
Source Analysis Model SAM/IA
(For Rapid Screening)
• Effluent Concentration Basis
• Assessment Alternative: (MATE)
• No Transport/Transformation Analysis
• Degree of Hazard Calculation
• Toxic Unit Discharge Rate Calculation
ENVIRONMENTAL ALTERNATIVES ANALYSIS
Source Analysis Model
Basic Calculations
For a specific MEG pollutant:
H = degree of hazard (severity) =
For a complex effluent:
Toxic Unit Discharge Rate =
C pollutant
CMEG
(mass or volumetric discharge rate) X / _, H
43
-------
i
i
Category
14B Oir-fthy1, sulfoxide
i
15 F?nzene
Air JJR/'
-,lt.
8.14E2
3.00E3
CD
'. Toluene 3.75F.3
(100)
16A
Ethyi benzene
Styrene
Propyl bpnzene
Isopropyl benrene
Buiyibenzene
Biphenyl
4 , 4 ' -Dipheny Ibiphenyl
Xylenes
Dialkylbenzenes
Tetrahydronaphthalenes
Dihydronaphthalenes
Terphenyls
Tri.Tiethy IHr - :enes
Tetramethylbenzenes
Chlorobenzene
Bromo and Dibromobenzenes
Broniochlorobenzenes
4.3SE5
(100)
4.20E5
(100)
2.17E5
5.30E4
2.25E5
1.00E3
N
4.35ES
(100)
2.25E5
1.29E5
1.27E5
9.00E3
(1)
3 , ,
n vppn)
Water
i
Hcolo.-y i Heslth
1.22E3
4.SOE4
5.63E6
6.53E6
6.30E6
3.25E6
9.45E5
1 3.38E6
! 1.5E4
N
6.53E6
3.33E6
1.94E6
1.91E6
y
f
______ __.F
sample Pag
ugA
Ecology
N
1.00E3
1.00E3
1.00E3
1 . OOE3
1.00E3
1.00E3
N
N
N
1.00E3
1 . OOE3
1.00E3
N
N
Land vg/t
2.44EO
2.00EO
2.00EO
2.00EO
2.00EO
2.00EO
2.00EO
6.76E3
3.00E1
N
2.00EO
2.00EO
2.00EO
3.82E3
2.70E2
(DOAFT-- 5/10/77)
MINIMUM ACUTE TOXICITY
EFFLUENT (MATE)
VALUES FOB ORGANIC AND INORGANIC
COMPOUNDS FROM FOSSIL ENERGY PROCESSES
A Subset of Multimedia
Environmental Goals
for Environmental Assessment Use in
Rapid S
_
cre-sning o
1
f Effluent
s
44
-------
SAM/IA SUMMARY SHEET
1. SOURCE «HO APPLICABLE CONTROL OPTIONS
2. PROCESS THROUGHPUT OR CAPACITY
3. USE THIS SPACE TO SKETCH A BLOCK DIAGRAM OF THE SOURCE AND CONTROL ITEMS SHOWING ALL EFFLUENT
STREAMS INDICATE EACH STREAM WITH A CIRCLED NUMBER USING 101 !99 FOR GASEOUb STREAMS. 201-299
FOR LIQUID t-TREAMS AND 301-399 FOR SOLID WASTE STREAMS.
4. LIST AND DESCRIBE GASEOUS EFFLUENT STREAMS USING RELEVANT NUMBERS FROM STEP 3,
101 ,
102 . ,—.
103 _—
5. LIST AND DESCRIBE. LIQUID EFFLUENT STREAMS USING RELEVANT NUMBERS FROM STEP 3.
201 , —
202 .
203 _
6. LIST AND DESCRIBE SOLID EFFLUENT STREAMS USING RELEVANT NUMBERS FROM STEP 3.
301 ___ —
302 . •
7 FO.I EACH t'FLUENT STRtAM COMPLETE FOfJM IA02.
45
-------
8 !.!ST SUVS ?ROW l.'NE 7, FORMS IA02, IN TA3LE FIEIOW
TOXIC DISCHARGE UNITS OY EFFLUENT STREAM
GASEOUS (m'/St'C)
;>V> £•-.'.!
COCt
L
A
TOXIC PI3C»AHGE
UNITS
HEALTH
BASED
B
ECOL.
BASED
C
LIQUID (I/SEC)
STREAM
CODE
0
TOXIC DISCHARGE
UNITS
HEALTH
OASEO
E
ECOL.
8ASED
F
SOLID (2/SSC)
STREAM
CODE
G
TOXIC DISCHARGE
UNITS
HEALTH
BASED
H
ECOL
BASED
1
9. SUM SEPARATELY GASEOUS. LIQUID AND SOLID TOXIC DISCHARGE UNITS FROM TABLE IN LINE 8
(I.E., SUM COLUMNS):
TOTAL TOXIC DISCHARGE UNITS
GASEOUS
LIQUID
SOLID
HEALTH BASED
(I Col. 8) 9a ,
(2 Col. E) 9b
(Z Col. H) 9c
ECOLOGICAL BASED
(I Col. C) 9»'
(E Col. F) 9b'
(S Col. I) 9c'
10. NUMBER OF EFFLUENT STREAMS
GASEOUS 10a
LIQUID lOb
SOLID lOc.
11. AVERAGE TOXIC DISCHARGE UNIT RATES
HEALTH BASED
GASEOUS (9a/10a) ll'a
L Q'JID (9b/10b) lib
SOLID (9c/10c) lie __
ECOLOGICAL BASED
(9aV10a) lla1
<9b'/lOb) lib'
(9cV10c) lie'
12. IJST ruLLUTANT SrLCIES KNOWN OR SUSPECTED TO BE EMITTED FOR WHICH NO MATES ARE AVAILABLE.
46
-------
1
1. SCUftCE/CONTROL OPTION
Z. -EFFLUENT STREAM
COiE .- NAME
3. EFFLUENT STREAM FLOW RATc
Q-,
(air = mVsec — liquid = I/sec — solid - g/sec)
4. CQVPLETF THE FOLLOWING TABLE FOR THE EFFLUENT STREAM OF LINE 2 CUSE BACK CF FORM FOR SCRATCH Wi.:"K:
i A B ! C D E F
fi H i J ! K !~ i. 1
i
i
r\
fOUUT#NT
SPECIES
UV7S
P r
t.
EMISSION
MCTOS
POLLUTANT
R.CW RATE
(B X CAPACITY)
D
fOLLUTANT
CONCENTRATION
IC/UNE 3)
E
HEALTH
MAT£
CONCENTRATION
5. EFFLUENT STREAM TOXIC UNIT CONTENT
HEALTH MATE BASED (£ COL G) 5a ., _
ECOLOGICAL MATE BASED (I COL H) 5b_
F
ECOLOGICAL
MATE
CONCENTRATION
:
G
DEGREE O.r
HEALTH
HA/ARO
(C/E)
_____
H
DEGREE OF
ECOLOGICAL
HAZARD
(D/F)
___
i
CHECK i\/t If
HEALTH MATE
LXCEtOED
_-.,
j I K 1
CHEC^,i™^^J
ECOLOGICAL j (iitALTH
'••Aft • 8Ascru
EXCEEOED 1 ;G x UNE 3)
-?
i
i
. . i .
1
:
«
i
I
i
TOX'" UN;T
FLC* «/*rr
1 (CCC,.OGlC*t
! B>:^-
(H ) .I.NE 3)
6. NUMBER Of
POLLUTANTS COM-
PARED TO MATES
N-
7. TOXIC UNIT DISCHARGE RATE
HEALTH BASED (LINE 3 X UNE 5a -t
ECOLOGICAL BASED (LINE 3 X LINE
N) 7a
5b * N) 7b
-------
ENVIRONMENTAL ALTERNATIVES ANALYSIS
Outlines for the More Detailed Proposed
Source Analysis Models
• Source Analysis Model (SAM/I) - (For
Screening)
Effluent Concentration Basis
Assessment Alternatives: 3t, Es, EPC,
NB, and SD
Effluent Transport/Transformation
Analysis (ETTA) - (very approximate)
Remaining Steps, Starting with Degree-
of-Hazard Calculation or other Ratios,
are Similar to SAM/IA
• Source Analysis Model (SAM/11)
-(General Approach to Evaluating any
U.S. Regional Site Alternative)
Ambient Concentration Basis
Assessment Alternatives: BT, ES, EPC,
NB, and SD
Recommended Transport/Transforma-
tion Models
Remaining Steps, Starting with Degree-
of-Hazard or Other Calculations, Are
Similar to SAM/IA
Application of Other Factors or Deci-
sion Criteria
PRELIMINARY EXAMPLES OF CONTROL/
CONTROL DEVELOPMENT NEEDS FOR
SYNTHETIC FUELS (EXCLUDING PHYSICAL
COAL CLEANING PRETREATMENT)
• Gas Treatment
Paniculate control from coal convey-
ing, load and discharge hoppers, gas
purges on transport, coal thermal
pretreatment, and coal burning for
power
Particulate control in converter via baf-
fles, velocity gradients
Particulate control in raw gas via water
scrubbing cyclones
Tar and oil removal from raw gas via li-
quid scrubbing
Tar and oil removal from raw gas via
cooling
Gaseous contaminants (H2S, COS,
NH3, trace metals) removal from raw
gas via liquid scrubbing
Sulfur compound removal from pre-
final product gas via guard chamber
(physical or chemical)
Contaminant removal from vents via
scrubbing or combustion
Product "polishing" via activated car-
bon
Use or disposal of volatiles from
pretreatment
Liquid Treatment
Treatment of run off from storage and
process areas via holding ponds
Boiler and cooling tower blowdown
water treatment
Heat exchange for liquid temperature
control
Treatment of water from tar/oil liquid
separators
Treatment of water from scrubbers
Stripping of constituents from liquids
Filtration of liquid products/by-
products
Contaminant removal from products
and by-products
By-product separation from water
(e.g., phenolsolvan)
Effluent pH control
Effluent biological treatment
Effluent carbon "polishing"
Solids Treatment
Sulfur from Claus or Stretford
Char recovery and beneficiation
Sludge treatment for valuable constit-
uents
Treatment of sludge from biox for fixa-
tion or neutralization
Sludge fixation from holding ponds
Used filter precoat and filtered material
recovery and treatment for heating
value or constituent recovery
Catalyst recovery of deposited
materials and/or disposal
Final Disposal
Containment of solid waste disposal
area leachate contaminants
48
-------
Control of airborne contaminants from
solid waste area (e.g., odors)
Land reuse guidelines
Site maintenance/surveillance
Process Modifications
Selective pretreatment of coal for con-
trol of input to the converter via
physical, chemical, or pretreatment
condition changes
Converter operating condition changes
for pollutant chemical or physical form
change
Utilization of alternate technologies for
conversion or treatment
Improved COS removal technique
Improve mechanism for coal feed to
converter for reduction of pollutant
release
Closed circuit liquid cooling
Minimization of coal drying and use of
water in converter for hydrogen
Combustion Modifications
NOX, SOX, and other pollutant control
for char combustion
NOX control for high nitrogen liquid fuel
products
Control for low-Btu, COS containing
waste gases
Flare improvement for upset conditions
Fuel Cleaning
Selective removal of pollutant consti-
tuents or pollutant forming catalysts in
pretreatment
Beneficiation of char for combustion
HDS/HDN for liquid fuels
Fugitive Emissions Control
Coal piles, product and by-product
storage for solids via protective cover-
ings or coatings
Liquid storage or holding areas via
chemical or physical means
Improved maintenance and/or equip-
ment for seals, transfer points
Accidental Release Technology
Contingency containment of liquids
Burst discs leading to control
mechanisms or expansion chambers
Emergency cleanup procedures
Evaluation of special cold climate ef-
fects on failure probabilities (e.g.,
freezing of drains)
49
-------
en
o
CONTROL APPROACHES:
t ,
1
€*yiROMME«T4L ,— ,-jp,
j
I6AS
TREATMENT
f
f
I
1
i SPECIFIC / 1
\ CONTROL / '
\ DEFINED/ /
| /
PRELIMINARY /
CONTROL
APPROACH
SELECTION
LIQUIDS
TREATMENT
SOLIDS
TREATMENT
FINAL
DISPOSAL
process
MODIFICATIONS
COMBUSTION
MODIFICATIONS
FUEL
CLEANING
FUGITIVE
EMISSIONS
CONTROL
ACCIDENTAL
RELEASE
TECHNOLOGY
;\
it \
i\
l\
» \
\ \
BASIC AND APPLIED H&O
• BENCH AND PILOT EXPERIMENTAL
STUDIES TO ASSESS GENERIC TYPES
FOR EFFECTIVENESS & SECONDARY
ENVIRONMENTAL PROBLEMS
• FUNDAMENTAt STUDIES
•'' !' 1
\ v *
. *
i
\
\
\
\
\
\
\
\
\
ENGINEERING ANALYSIS .
• REVIEW COBJTMl TECH. ALTERNATIVES
BASED QN PHYS/CHEM. CONDITIONS.
POLLUTANT CONC., ETC.
• ASSESS POTENTIAL FOR APPLICATION
(NEW. RETROFIT. SIZE, ETCJ
• PRELIMINARY DESIGN & COST STUDIES
• SYSTEMS COMPARISONS
1 t
SPECIFIC CONTROL PROCESS
DEVELOPMENT. EVALUATION
• CONCEPTUAL DESIGN ft COST STUDIES
• OPTBMZEO INTEGRATION IN SYSTEMS
TO BE CONTROLLED
• PILOT » DEMONSTRATION STUDIES
• ntlO TBTUM OP STATE OP THE ANT
ANORIlATIOIYtTtlBI
\ QUANTIFIED
, Bt\ EFFECTIVENESS,
\ ECONOMICS, I
\ENERGYCOSTSj
TECHNOUOGY
TRANSFER
MULTIMEDIA
ENVIRONMENTAL
CONTROL
ENGINEERING
• ADDITIONS
• REVISIONS •
RELATIONSHIP OP CONTROL TEOMOLOGY DEVELOPMENT TO ENVIRONMENTAL ASSESSMENT DIAGRAM
-------
APPENDIX A
ENVIRONMENTAL ASSESSMENT
STEERING COMMITTEE
Robert P. Botts
Ecosystems Modeling & Analysis Br.
Environmental Research Laboratory
Environmental Protection Agency
200 SW 35th Street
Corvallis, Oregon 97330
FTS: 8-420-4679
Dale A. Denny
Industrial Processes Division, MD-62
Industrial Environmental Research Laboratory
Environmental Protection Agency
Research Triangle Park, N.C. 27711
FTS: 8-629-2547
James A. Dorsey
Industrial Processes Division, MD-62
Industrial Environmental Research Laboratory
Environmental Protection Agency
Research Triangle Park, N.C. 27711
FTS: 8-629-2557
Robert P. Hangebrauck
Director, Energy Assessment & Control
Division, MD-61
Industrial Environmental Research Laboratory
Environmental Protection Agency
Research Triangle Park, N.C. 27711
FTS: 8-629-2825
919/541-2825
Clyde J. Dial
Director, Program Operations Office
Industrial Environmental Research Laboratory
Environmental Protection Agency
5555 Ridge Avenue
Cincinnati, Ohio 45268
FTS: 8-684-4438
Stan Hegre
Environmental Research Laboratory
Environmental Protection Agency
South Ferry Road
Narragansett, R. I. 02882
FTS: 8-834-4843, ext. 240
Bill Horning
Newtown Fish Toxicology Station
3411 Church Street
Cincinnati, Ohio 45244
FTS: 8-684-8601
Joellen Huisingh
Health Effects Research Laboratory, MD-82
Environmental Protection Agency
Research Triangle Park, N.C. 27711
FTS: 8-629-2537
Norbert Jaworski
Deputy Director, Industrial Environmental
Research Laboratory, MD-60
Environmental Protection Agency
Research Triangle Park, N.C. 2771 1
FTS: 8-629-2821
Larry D. Johnson
Industrial Processes Division, MD-62
Industrial Environmental Research Laboratory
Environmental Protection Agency
Research Triangle Park, N.C. 27711
FTS: 8-629-2557
Julian W. Jones
Utilities & Industrial Power Division, MD-61
Industrial Environmental Research Laboratory
Environmental Protection Agency
Research Triangle Park, N.C. 2771 1
FTS: 8-629-2489
Walt Sanders
Environmental Research Laboratory
Environmental Protection Agency
College Station Road
Athens, Ga. 30601
51
-------
Jerry Stara
Health Effects Research Laboratory
Environmental Protection Agency
Cincinnati, Ohio 45268
FTS: 8-684-7406
Commercial: 513/684-7407
Martin Stepanian
Industrial Environmental Research Laboratory
Environmental Protection Agency
5555 Ridge Avenue
Cincinnati, Ohio 45268
FTS: 8-684-4439
W. Gene Tucker
Special Studies Staff, MD-63
Industrial Environmental Research Laboratory
Environmental Protection Agency
Research Triangle Park, N.C. 27711
FTS: 8-629-2745
Jerry Walsh
Environmental Research Laboratory
Environmental Protection Agency
Sabine Island
Gulf Breeze, Florida 32561
FTS Operator: 8-946-2011
Commercial: 904/932-5311
Mike D. Waters
Health Effects Research Laboratory, MD-82
Environmental Protection Agency
Research Triangle Park, N.C. 27711
FTS: 8-629-2537
52
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DEVELOPMENT OF MULTIMEDIA
ENVIRONMENTAL GOALS
(MEG's) FOR POLLUTANTS
FROM FUEL CONVERSION
PROCESSES
By
Carrie L. Kingsbury
Research Triangle Institute
Research Triangle Park, N. C.
Abstract
The presentation will highlight the progress
to date in developing a systematic approach to
describe multimedia environmental goals for
chemical substances associated with fuel con-
version processes. Discussion will focus on (1)
the various types of information pertinent to
environmental goals and available for a
multiplicity of potential chemical contaminants
and (2) models designed to incorporate
available data in the prediction of permissible
ambient or emission concentrations for each
substance. The validity of combining various
models in order to assign priorities or to com-
pare distinctly different toxicants based on
their respective environmental goals will be ad-
dressed. Comments on future work directed
toward refinement and expansion of the
methodology will a/so be included.
INTRODUCTION
Multimedia Environmental Goals (MEG's) are
levels of contaminants or degradants (in am-
bient air, water, or land or in emissions or ef-
fluents conveyed to ambient media) that are
judged to be (1) appropriate for preventing cer-
tain negative effects in the surrounding popula-
tions or ecosystems, or (2) representative of
the control limits achievable through
technology.
Establishing Multimedia Environmental Goals
is an integral part of the environmental assess-
ment methodology that is currently being
developed under the guidance of the Fuels
Process Branch of IERL/EPA at RTP. En-
vironmental assessment involves:
1) The determination of contaminant
levels associated with emissions and
effluents from a point source.
2. Comparison of those determinations
with desirable control levels.
The need for MEG's arises in this latter aspect
of environmental assessment.
The MEG's project has been conceived to
supply sets of control goals for specific
chemical contaminants, complex effluents, and
non-chemical degradents based on some of the
criteria options that might be considered in
defining "desirable control levels." These sets
of goals, then, provide the values to be com-
pared with actual contamination levels for en-
vironmental assessment purposes.
The first year of MEG's development was
devoted largely to selecting the options to be
used as MEG's criteria and to investigating
ways to approach the problem of defining
MEG's for a large number of chemical
substances. Initially, the objective of this work
was to describe MEG's for chemical pollutants
associated with coal conversion processes.
However, the value of an expanded list of con-
taminants was recognized, and the potential
for extended application of a MEG's
methodology called for the development of a
broad, systematic, and adaptable approach for
addressing a much larger number of chemical
and non-chemical pollutants. Hence the scope
of the MEG'sproject has been expanded to en-
compass a broad range of objectives which in-
clude the following:
1) Compiling a Master List of all chemical
contaminants, complex effluents/mix-
tures, and non-chemical degradants
(such as visual effects, subsidence,
heat, and noise) to be addressed by
MEG's. (The list is to include but should
not be limited exclusively to con-
taminants from fossil fuels processes.)
2) Arrangement of the chemical
substances appearing on the Master
List into a practical catalog to provide a
useful tool for environmental assess-
ment.
3) Design of a format conducive to the
concurrent presentation of sets of
Emission Level Goals and Ambient
Level Goals. (The format should allow
ready comparison of the MEG's within
a set as well as facilitating comparison
of different substances.)
53
-------
4) Determination of the kinds of data per-
tinent to desirable control levels and
the availability of that data. A format
for presenting background information
should be established to accompany
MEG's specified for each chemical
substance.
5) Development of a methodology to
establish meaningful values to serve as
MEG's for each chemical substance on
the Master List. (The methodology
should incorporate as MEG's those
Federal standards, criteria, and recom-
mendations pertinent to chemical
substances.)
6) Presentation, according to the format
prescribed, of a set of Emission Level
Goals and Ambient Level Goals for
each chemical substance appearing on
the Master List. (These MEG's should
be accompanied by qualitative sup-
porting data.)
The central purpose of the project remains
the derivation of Multimedia Environmental
Goals as estimates of desirable levels of control
for those chemical contaminants and non-
cher, ical degradents included in a master list.
COMPILATION OF THE MASTER LIST
OF CHEMICAL SUBSTANCES AND
PHYSICAL AGENTS
A Master List of more than 600 chemical
substances and physical agents has been com-
piled using selection factors prescribed by EPA.
Primary emphasis has been placed on con-
taminants from fossil fuels processes (par-
ticularly coal gasification and liquefaction), and
the Master List has been compiled largely on
the basis of the literature pertinent to these
processes. Process streams were characterized
both qualitatively and quantitatively wherever
possible to provide insight for selecting
substances likely to be present but not men-
tioned specifically in the process literature.
Three levels of priority were assigned to the
selection factors to determine what substances
(of all possible chemical substances and
physical agents that might be described as en-
vironmental contaminants) would be entered
on the Master List for MEG's. The selection fac-
tors are outlined below:
Primary Selection Factors
1) The pollutant is associated with fossil
fuels processes.
All those individual substances or classes of
substances known or suspected to be present
in the emissions or effluents from fossil fuels
processes must appear on the Master List.
Secondary Selection Factors
1) Federal standards or criteria exist or
have been proposed (ambient, emis-
sion, or occupational).
2) A TLV has been established or an LD50
has been reported.
3) The substance has been listed as a
suspected carcinogen.
4) The substance appears on the EPA
Consent Decree list.
Compounds that meet any one of the four
secondary selection factors and are repre-
sentative of a class of compounds associated
with fossil fuels processes must appear on the
Master List.
Tertiary Selection Factors
(Optional)
1) The substance is present as a pollutant
in the environment.
2) The substance has been identified as
being highly toxic.
Consideration for inclusion in the Master List is
also to be given to certain additional pollutants,
not necessarily associated with fossil fuels
processes, provided they satisfy either of the
tertiary selection factors.
ORGANIZATION OF THE
MASTER LIST
To organize the more than 600 Master List
entries, a system for ordering the substances
had to be developed. The approach ultimately
determined to meet the need for organization
most effectively involves clustering substances
into categories based on chemical functional
groups for organic compounds and on principle
element for inorganics. The categories are therj
arranged to provide a coordinated framework
for the list. This categorization scheme, besides
54
-------
organizing the list of chemical contaminants in-
to manageable chunks, emphasizes logical rela-
tionships between groups of substances so
that each category is characterized by tox-
icologically and chemically similar substances.
A total of 85 categories (26 organic and 59
inorganic) are required to logically organize
specific chemical contaminants included in the
Master List for MEG's.
Generalizations and extrapolations are often
valid among the compounds included within a
category, allowing data gaps to be filled in
some instances. Substances likely to occur
together or to behave similarly in an organism
may become apparent through the categoriza-
tion scheme. Also, methods of detection for
compounds within a specific category are likely
to be similar, and analysis of a category as a
whole may in some cases be practical for broad
screening applications.
The categorization scheme allows one seek-
ing information on a particular substance to
find material of value associated with a related
compound or element, should the particular
item of interest be missing from the compila-
tions. The utility of isolating related compounds
by categorization has become very evident dur-
ing the course of data collection for the current
MEG's work. For example, phenolic com-
pounds are addressed collectively by water
quality recommendations;1 since phenols are
grouped as a category in the compilations, it is
easy to comprehend the intended subject of the
recommendation.
An alphabetical arrangement of Master List
entries, although in some ways the simplest ap-
proach to organizing the list, has been avoided
since it would provide no means of associating
related compounds (unless of course their
names begin with the same letter).
THE MULTIMEDIA
ENVIRONMENTAL
GOALS CHART
A MEG's chart has been designed to display
concurrently Emission Level Goals and Ambient
Level Goals for any specific chemical contami-
nant in a consistent, easy to use format. The
current version of the chart is shown in Figure
1.
The MEG's chart consists of two interrelated
tables, one addressing Emission Level Goals
and one addressing Ambient Level Goals. Each
table is divided into columns devoted to
specific criteria for describing desirable control
levels (for example, Toxicity Based Ambient
Level Goals [Based on Health Effects]). Within
each column, space is provided for concentra-
tion levels to be specified for air, water, and
land in units consistent with those indicated in
the index column at the left. Only numbers will
appear within the MEG's charts. The name of
the substance addressed, its category num-
ber, and appropriate toxicity indicator (based
on human health effects associated with the
substance as an air contaminant) are all
presented in bold letters in the upper right hand
corner of each chart.
Emission Level Goals
Emission Level Goals presented in the top
half of the MEG's chart actually pertain to
gaseous emissions to the air, aqueous effluents
to water, and solid waste to be disposed to
land. These Goals may have as their bases
technological factors or ambient factors.
Technological factors refer to the limitations
placed on control levels by technology, either
existing or developing (i.e., equipment
capabilities or process parameters). The Stand-
ards of Performance for New Stationary
Sources2 provide an example of promulgated
Emission Level Goals based on technology.
Since there is obviously a relationship
between contaminant concentrations in emis-
sions and the presence of these contaminants
in ambient media, it is imperative to consider
ambient factors when establishing emission
level goals. Ambient factors included in the
MEG's chart as criteria for Emission Level Goals
include:
1) Minimum Acute Toxicity Effluents
(MATE'S) —concentrations of pol-
lutants in undiluted emission streams
that would not adversely affect those
persons or ecological systems exposed
for short periods of time.
2) Ambient Level Goals —i.e. estimated
permissible concentrations (EPC's) of
pollutants in emission streams which,
after dispersion, will not cause the level
55
-------
MULTIMEDIA
ENVIRONMENTAL
GOALS
EMISSION LEVEL GOALS
Category
Air, *ig/m3
(ppm Vol)
Water, ng/\
(ppm Wt)
Land, M9/9
(ppm Wt)
1. Based on Best Technology
A. Existing Standard)
NSPS, BPT, BAT
B. Developing Technology
Engineering Estimates
(R&D Goals)
II. Based on Ambient Factors
A. Minimum Acute
Toxicity Effluent
Based on
Health Effect!
Based on
Ecological
Effects
8. Ambient Level Goal*
Based on
Health Effects
Based on
Ecological
Effect!
C. Elimination of
Discharge
Natural Background*
*To be multiplied by dilution factor
Air, fig/m
(ppm Vol)
Water, yg/l
(ppm Wt)
Land, «j/9
(ppm Wt)
AMBIENT LEVEL GOALS
1. Current or Proposed Ambient
Standards or Criteria
A. Based on
Health Effects
B. Based on
Ecological Effects
II. Toxicity Based Estimated
Permissible Concentration
A. Based on
Health Effects
B. Based on
Ecological Effects
III. Zero Threshold Pollutants
Estimated Permissible Concentration
Based on Health Effects
Figure 1. Current version of multimedia environmental goals chart.
56
-------
of contamination in the ambient receiv-
ing medium to exceed a safe con-
tinuous exposure concentration.
3) Elimination of Discharge (EOD) —
concentrations of pollutants in emis-
sion streams which, after dilution, will
not cause the level of contamination to
exceed levels measured as "natural
background."
Although technology based Emission Level
Goals are highly source specific, goals based
on ambient factors can be considered univer-
sally applicable to discharge streams for any in-
dustry. The Emission Level Goals based on
EPC's for example, correspond to the most
stringent Ambient Level Goals (dilution factor
to be applied) appearing in the MEG's chart,
regardless of source of emission. This format
for presentation of Emission Level Goals has
evolved during the course of the MEG's project
and is significantly different from the initial
chart introduced some 1 8 months ago. Elimina-
tion of Discharge, as a criteria for Emission
Level Goals, was added about a year ago. In
another interim version, columns specifying
dilution factors in multiples of ten were includ-
ed under the Emission Level Goals based on
ambient factors. Later, Minimum Acute Toxici-
ty Effluents (MATE'S) were incorporated and
the dilution factor columns deleted. It is likely
that the chart will be further altered as the
MEG's become more refined, but the format
presented here serves well for displaying
MEG's at this stage of development.
Ambient Level Goals
The lower half of the MEG's chart is designed
to present three classifications of Ambient
Level Goals; all of these goals describe
estimated permissible concentrations (EPC's)
for continuous exposure. The Ambient Level
Goals presented in the chart are those based
on:
1) Current or proposed Federal ambient
standards or criteria.
2) Toxicity (acute and chronic effects
considered).
3) Carcinogenicity or teratogenicity (for
zero threshold pollutants).
The term zero threshold pollutants is used to
distinguish contaminants demonstrated to be
potentially carcinogenic or teratogenic. The
concept of thresholds is based on the premise
that there exists for every chemical substance,
some defineable concentration below which
that chemical will not produce a toxic response
in an exposed subject.3 The existence of
thresholds for carcinogens, teratogens, and
mutagens has been widely debated and is still
unresolved. In using the term "zero threshold
pollutants," we do not wish to imply that we
have chosen sides in the debate; rather, we use
the nomenclature as a convenience.
BACKGROUND INFORMATION
SUMMARIES FOR
CHEMICAL SUBSTANCES
An obvious need in the field of environmental
assessment has been for a useable instrument
bringing together data related to environmental
aspects of various chemical substances. The
format developed for supplying summarized
background information to accompany and
substantiate MEG's charts addresses this need,
providing a large volume of information in a
consolidated, consistent, workable arrange-
ment. This format serves to organize available
data in a logical framework, yet at the same
time remains flexible enough to allow incor-
poration of data as it becomes available.
Specific items of information are arranged in a
consistent pattern, and presented in conjunc-
tion with the corresponding MEG's chart. This
allows the user to survey the data quickly and
to relate multimedia environmental goals to
physical and chemical properties, and tox-
icological characteristics of the chemical
substance of interest.
Space is provided on each Background Infor-
mation Summary to supply the following types
of data:
• Identifying Information
• Properties
• Natural Occurrence, Characteristics,
Associated Compounds
• Toxic Properties, Health Effects
• Regulatory Actions, Standards,
Criteria, Candidate Status for Specific
Regulation
Table 1 lists the specific items of information
included in the Background Information Sum-
57
-------
TABLE 1
INFORMATION PRESENTED IN BACKGROUND INFORMATION SUMMARIES
General Heading
Specific Items
IDENTIFYING INFORMATION
PROPERTIES
NATURAL OCCURENCES, CHARACTERISTICS, AND
ASSOCIATED COMPOUNDS
TOXIC PROPERTIES AND HEALTH EFFECTS
REGULATORY ACTIONS, STANDARDS, CRITERIA,
RECOGNITION AND CANDIDATE STATUS
FOR SPECIFIC REGULATIONS
Category number, Preferred name, Synonyms,
Empirical chemical formula, Structure,
Wiswesser Line Notation, Physical description
Molecular 01 atomic weight, Atomic number
Periodic group, Boiling point. Melting point,
Density, Vapor density, Vapor pressure,
Dissociation constant
Background levels in air, Odor levels,
Photochemical activity, Background levels in
water, Occurence associations. Dietary intake,
Characteristic chemical reactions, Metabolic
fate, Background levels in soil
Animal toxicicy information:
LD50 - lethal dose (50Z kill)
LCSO - lethal concentration (50% kill)
LDT - lowest published lethal dose
Lo
LC, - lowest published lethal concentration
Lo
Human health effects data:
acute effects, chronic effects, biological
half-life
Data pertinent to carclnogenicity or
teratogenicity:
EPA/NIOSH ordering number, Affected animal
species, Recorded human effects, Lowest
effective dosages. Adjusted ordering number
v
Aquatic toxicity information:
LC,Q - lethal concentration (50% kill)
Bioaccumulation, or biomagnification
(potential). Reported tainting levels,
Phytotoxicity (plant toxicity) data
National Primary and Secondary Ambient Air
Quality Standards (40 CFR, Part 50).
National Emissions Standards for Hazardous
Air Pollutants (40 CFR, Part 61).
OSHA Standards for Hazardous Substances
(29 CFR, Part 1910).
National Interim Primary Drinking Water
Regulations (40 CFR, Part 141).
Public Health Service Drinking Water
Standards (42 CFR, Part 72).
EPA Toxic Pollutant Effluent Standards
(40 CFR, Part 405-460).
Regulations for Protection Against
Radiation (10 CFR, Pact 20).
FDA Declaration
EPA National Emissions Standards for
Hazardous Air Pollutants, Candidate List.
EPA Toxic Pollutant Effluent Standards,
Candidate List.
EPA Consent Decree List.
NCI List of Carcinogens to Man.
ACGIH designation as carcinogen, simple
asphyxiant, or nuisance particulate.
EPA Star Document subject.
NIOSH Criteria Document subject.
Chemical Industry Institute of Toxicology
Priority Chemical Lists.
58
-------
maries under each of these headings. In addi-
tion to these items, calculations of MATE'S and
EPC's are also presented in the summaries.
MEG' METHODOLOGY
A methodology for evaluating and ranking
pollutants for the purpose of environmental
assessment, has been developed which can be
used to delineate MEG's for a large number of
compounds. The system requires certain em-
pirical data which are extrapolated through
simple models to yield EPC's or MATE'S. The
methodology addresses both Ambient Level
Goals and Emission Level Goals based on am-
bient factors.
Existing or proposed Federal standards,
criteria, or recommendations are acknowledg-
ed as previously established goals and have
been utilized wherever applicable. For those
substances not addressed by current
guidelines, consideration in arriving at MEG's
goals has been given to the following: (1)
established or estimated human threshold
levels; (2) acceptable risk levels for lifetime ex-
posure to suspected carcinogens or
teratogens; (3) degrees of contamination con-
sidered reasonable for protection of existing
ecosystems; (4) cumulative potential in aquatic
organisms, livestock, and vegetation; and (5)
hazards to human health or to ecology induced
by short term exposure to emissions. It is
recognized that there are several other criteria
pertinent to MEG's that have not been incor-
porated into the methodology developed thus
far (for example, quality of the receiving media
before introduction of the substance,
characteristics of transport and dispersion of
emissions, consideration of location and abun-
dance of sources emitting a given pollutant,
numbers of populations affected, synergisms,
antagonisms, and other secondary pollutant
associations); new research is needed before
more refined models of estimation can be
developed to allow inclusion of these criteria.
Three distinct aspects of MEG's
methodology development have been ad-
dressed so far. These are:
1) assembling and collating all existing or
proposed Federal guidelines pertinent
to each chemical substance on the
Master List.
2) defining models to translate empirical
data into EPC's) estimated permissible
concentrations for continuous ex-
posure to chemical toxicants in air,
water, and land).
3) defining models to translate empirical
data into values describing MATE'S
(minimum acute toxicity effluents safe
for short term exposure; such effluents
may be gases, liquids, or solids).
Federal Guidelines
Investigation of Federal Guidelines has
yielded not only values to serve as MEG's, but
also insight into the variety of approches ap-
plied in standard setting thus far. For example,
the National Emissions Standards for Hazar-
dous Air Pollutants established for mercury and
beryllium take into consideration estimated
safe ambient levels of these pollutants (1 ^g/3
for Hg, 0.01 /ig/m3 for Be).4 Emission
guidelines may be expressed in many different
units such as the ratio of mass or volume of
pollutant to the mass of feedstock or product.
Ambient guidelines may also be expressed in
units other than concentration units, for exam-
ple, certain water quality criteria for protection
of aquatic life specify application factors to be
applied to the 96-hr LC50.
Existing Federal Guidelines fall far short of
providing MEG's for all the chemical sub-
stances of concern. In fact, our survey of the
Federal guidelines showed only about 40
specific contaminants receive attention by
more than one set of emissions or ambient
guidelines. The MEG's list, as mentioned
earlier, includes more than 600 specific
chemical substances.
Estimated Permissible
Concentrations (EPC's)
To delineate Multimedia Environmental Goals
a defined frame of reference for each substance
must be established as a common reference
point to allow comparison of various char-
acteristics among similar and diverse sub-
stances. Translation of various forms of data
into EPC's meets this need.
Two types of EPC's are generated through
modeling. Empirical data concerning the effects
of chemical substances on human health and
the ecology are translated into a set of toxicity-
59
-------
based EPC's. Another set of EPC's is supplied
by a system relating carcinogenic or
teratogenic potential to media concentrations
considered to pose an acceptable risk.
The methodology defines a total of 22 dif-
ferent kinds of EPC's, many of them inter-
related (EPC's for water, for example, may be
derived from EPC's for air). Although multiple
EPC's are calculated on the background infor-
mation summaries, only the most stringent EPC
for a given media/criteria combination will ap-
pear on the MEG chart for a given substance.
EPC's have been coded by subscripts for
easy identification. EPCAH|, for example, is the
toxicity based EPC for air based on human
health effects (derived from air model #1);
EPCWEi applies to water and is based on
ecological effects (water model #1 is used);
EPCAC| is for air and is based on carcinogenic
potential (established by carcinogen model
#1).
Several of the models incorporated were
developed or suggested by previous re-
searchers; other models were designed or
modified specifically for MEG's application.
The significance of the methodology lies not in
any specific model, but in the array of models
which allows MEG's to be defined on the basis
of a variety of data items. Empirical data re-
quired for the various health based EPC's and
interrelationships defined in the methodology
are listed in Table 2. EPC's based on ecological
effects are defined in Table 3. Most specific
types of data required have been compiled
previously by others and are largely available in
tabulated form within secondary sources of in-
formation.
Minimum Acute
Toxicity Effluents (MATE's)
The system established to describe MATE
values as Emission Level Goals is analogous to
that developed for EPC's. The basic difference
is that the MATE'S refer to concentrations ap-
propriate for short term exposure whereas
EPC's consider lifetime continuous exposure.
Fourteen different kinds of MATE values are
defined currently.
APPLICATION OF
METHODOLOGY FOR
DESCRIBING MEG's
Presentation in detail of all the models sup-
porting the EPC and MATE derivations is
beyond the scope of this paper. However, a
few general comments are required to permit
some perspective into the methodology. First,
a'! of the modeling schemes require that certain
assumpt'ons be mede and a worst case ap-
proach has been taken to keep the MEG values
conservative, 'n some instances, arbitrary con-
stants are incorporated in an effort to correlate
the variojs sets of EPC's. Efforts have been
made to incorporate judgments of others
relative to the levels of pollutants safely
tolerated by human beings. In this regard,
heavy reliance in the methodology has been
placed on TLV's established by the American
Conference o* Governmental Industrial
Hygionists (ACGIH).6
So far, 216 chemical substances from the
MEG's Master List have been addressed utiliz-
ing the previously cescribed format and
methodology. While the rapid increase in
volume of date accessible in recent months has
increased the reliability of assessment schemes
based on modeling techniques, data gaps re-
main a problem over a wide range of the en-
tries. These gaps make ;t impossible to provide,
for si/ery substance addressed, goals for each
medium on the basis of all the applicable
models. However, when provision is made for
utiliz'ng data ;n a variety of forms, it becomes
possible to describe MEG's which are
reasonable based on at least some of the
selected criter'a. As a result of th's adaptability,
the methodology provides a practical, workable
system for determining goals in an ever increas-
ing percentage of cases. 0* the 216 sub-
stances addressed, only 6 emerge with no
numerica' MEG va'ues, providing a good 'ndica-
tion that the methodology is sufficiently broad
in its bases tc provide the comparison criteria
needed for en\/ironmental assessment.
Six samples taken from the MEG's compila-
tions follow the text.
60
-------
TABLE 2
DERIVATION OF HEALTH BASED EPC's
Data
TLV or NIOSH Recommendation
(occupational exposure)
M50- ^LO
Bioassay data (carcinogen testing)
Bioassay data (teratogen testing)
"so
Interrelationship
TLV oc
EPCWH
EPCwc
EPCWT
EPCLH
EPCLC
EPCLT
^50*
" EPCAH**
. EPCAC**
' EPCAT**
ttEPCWH
ttEPCwc
ttEPCWT
Specific EPC Derived
EPCAH1' EPCAC1
EPCAH2
EPCAC2
EPCAT
EPCWH1
EPCWH2
EPCwc
EPCWT
EPCLH
EPCLC
EPCLT
O)
* Relationship established by Handy and Schindler. -.
** Relationship suggested by Stokinger and Woodward.
Subscript Key: A (air); W (water); L (land); H (health effects); C (carcinogenicity);
T (teratogenicity); numbers refer to specific models.
-------
TABLE 3
DERIVATION OF ECOLOGY BASED EPC's
Data
Interrelationship
Specific EPC Derived
o>
to
Air concentration causing an effect
in vegetation
LC-- or TLm
Tainting Level
Cumulative Potential
Application Factor*
Hazard Level*
EPCLE ' EPCWE
EPCAE
EPCWE1
EPCWE2
EPCWE3
EPCWE4
EPCWE4
EPC
LE
* Value supplied in Water Quality Criteria
Subscript Key: A (air); W (water); L (land); E (ecological effects);
numbers refer to specific models.
-------
CONCLUSIONS
The MEG's project represents an important
step in EPA's efforts to systematically address
a multiplicity of chemical substances for the
purpose of establishing priorities in en-
vironmental assessment programs. MEG's pro-
vide a ranking system furnishing the decision
criteria needed in source assessment. The
MEG's may also be used for establishing
priorities among the pollutants to be ultimately
addressed by regulations, and thus, may in-
fluence control technology development in the
future. In every case care has been taken to ar-
rive at conservative but reasonable figures bas-
ed upon the array of possible options supplied
by the methodology.
It is expected that this initial work addressing
Multimedia Environmental Goals will provide a
springboard for further research in developing
MEG's and that it will stimulate exploration into
more sophisticated approaches that make use
of empirical data evolving from research efforts
currently in progress.
REFERENCES
t. Environmental Protection Agency. Quality
Criteria for Water. EPA 440/9/76-023
(1976).
7.
Environmental Protection Agency. Stan-
dards of Performance for New Stationary
Sources, Title 40 Code Federal Regula-
tions Part 60.
Herbert E. Stokinger. Concepts of
Thresholds in Standards Setting. Arch En-
viron Health, 25 (Sept. 1972), 153.
Environmental Protection Agency. Na-
tional Hazardous Emissions Standards for
Hazardous Air Pollutants. Federal
Register, 36, 234, (Dec. 7, 1971),
23239.
American Conference of Governmental In-
dustrial Hygienists. Threshold Limit
Values for Chemical Substances and
Physical Agents in the Workroom Environ-
ment with Intended Changes for 1976.
American Conference of Governmental
Hygienists, Cincinnati, Ohio (1976).
R. Handy and A. Schindler. Estimation of
Permissible Concentration of Pollutants
for Continuous Exposure. Prepared by
Research Triangle Institute under Con-
tract 68-02-1325 for Environmental Pro-
tection Agency Research Triangle Park,
N.C. EPA-600 12-76-155 (1976).
Herbert E. Stokinger and Richard L. Wood-
ward. Toxicologic Methods for
Establishing Drinking Water Standards.
Journal of American Water Works
Association, 515 (1958), 515.
63
-------
CATEGORY: loc
WIN: L66J CZ
STRUCTURE!
2-AMINONAPHTHALENE: C^HgN (2-naphthylamine,
S-naphthylamine).
White crystals that darken on exposure to light and air; volatile with steam.
PROPERTIES:
Molecular wt: 143.19; mp: 113; bp: 306; d: 1.0614^8; vap. press.: 1mm
at 108" C; volatile in steam; slightly soluble in cold water.
NATURAL OCCURRENCE. CHARACTERISTICS. ASSOCIATED COMPOUNDS:
2-Naphthylamine does not occur as such in nature, but 1s formed by the pyrolisls of nitrogen-containing
organic matter. It has been isolated from coal-tar (ref. 44). It has, 1n general, the characteristics of
primary aromatic amines. It is a weak base.
TOXIC PROPERTIES. HEALTH EFFECTS:
Ep1dem1ological studies have shown that occupational exposure to 2-aminonaphthalene is strongly associated
with the occurrence of bladder cancer. There is no doubt that the compound is a human bladder carcinogen
(ref. 44). 2-Aminonaphthalene is also reported to cause cancer in several animal species.
The EPA/NIQSH ordering number is 7628. The lowest dose to induce a carcinogenic response is reported
as 18 mg/kg. The adjusted ordering number is 423.8.
L050 Coral, rat): 727 mg/kg.
Aquatic toxicity: Tim 96: 10-1 ppm (ref. 2).
REGULATORY ACTIONS. STANDARDS. CRITERIA. RECOGNITION. CANDIDATE STATUS FOR SPECIFIC REGULATION;
2-Am1nonaphtha1ene is recognized by ACGIH as a carcinogenic agent 1n humans. No TLV has been assigned.
3-tephthylamine was the subject of a HIOSH Hazard Review Document (ref. 43).
OSHA standards dealing with exposure of employees to 2-naphthylam1ne has been established taking into
consideration substantial evidence that 2-naphthylamine is known to cause cancer (ref. 17).
MINIMUM ACUTE TOXICITY CONCENTRATIONS:
A1r, Health: 7 x 10*/423.8 - 165 yg/m
Water, Health: 15 x 165 > 2.5 x
Land, Health: 0.002 x 2.5 x 103 « 5 yg/g
103 yg/i
Air, Ecology:
Water, Ecology: 100 x 1 • 100 ug/4
Land, Ecology: 0.002 x 100 - 0.2 yg/g
ESTIMATED PERMISSIBLE CONCENTRATIONS:
EPC
EPC,
'AH2
'AH3
3
0.107 x 727 » 78 ag/mj
0.081 x 727 « 59 yg/m
EPCyH] • 15 x 59 - 3,500 yg/*
EPCWH2 * °-4 x 727 « 291 vg/t
EPC,_H • 0.002 x 291 -0.6 yg/g
EPCAC2 • 103/C6 x 423.8) - 0.4 yg/m3
EPCyC • 15 x 0.4 • 6 yg/i
£PCLC • 0.002 x 6 • 0.012 ug/g
EPCWE1 » 50 x 1 « 50 yg/l
EPCL£ - 0.002 x 50 » 0.1 yg/g
64
-------
MULTIMEDIA
ENVIRONMENTAL
GOALS
x
10C
2-AMINONAPHTHALENE
EMISSION LEVEL GOALS
Air.pg/m3
(ppm Voll
Water, pg/l
(ppm Wt)
Land, pg/g
(ppmWt)
I. Based on Beit Technology
A. Exiiting Standardi
NSPS, BPT, BAT
8. Davtloping Technology
Engineering Ettimitm
(R8.DGo.lil
II. Based on Ambient Factors
A. Minimum Acute
Toxlcity Effluent
Bated on
Hialth Effectt
1.65E2
2.5E3
5.0EO
Ba»d on
Ecological
Effecti
1.0E2
2.0E-1
B. Ambiant U«l QoaC
Bund on
Health Effwn
0.4
6
0.012
Baled on
Ecological
Effecti
50
0.1
C. Elimination of
Ditehwge
Natural Background"
•To be multiplied by dilution factor
AMBIENT LEVEL GOALS
Air.Mfl/m3
(ppm Vol)
Water, jig/l
(ppm Wt)
Land,pQ/g
(ppm Wt)
1. Current or Propotad Ambient
Standard! or Criteria
A. BUM! on
Health Effect*
B. Bawd on
Ecological Effect.
II. Toxicity Bated Estimated
Permissible Concentration
A. Band on
Health Effecti
59
291
0.6
B. Bated on
Ecological Effecti
50
0.1
III. Zero Threshold Pollutants
Estimated Permissible Concentration
Bated on Health Effects
0.4
6
0.012
65
-------
CATEGORY;
ISA
CgH4OHCH3 (cresylic add, methylphenol, hydroxytoluene),
CRESOLS:
m-cresol:
o-cresol:
p-cresol:
PROPERTIES:
Molecular wt: 108.37; density^.
vap. d: 3.72; soluble In water.
colorless or yellowish liquid, phenolic odor;
crystals or liquid, phenolic odor;
crystals, phenolic odor.
4 • 1.034-1.047;
ortho
meta
m-cresol
o-cresol
p-cresol
tip
vap. press.
11
30
35.5
202
191
201.3
0.153 mm at 25°C
0.245 m at 25°C
0.103 ran at 25°C
NATURAL OCCURRENCS. CHARACTERISTICS. ASSOCIATED COMPOUNDS:
Cresols are methyl-substituted hydroxy benzene compounds, I.e. methyl phenols. Ortho,
meta and para compounds occur. The meta isomer predominates in mixtures (ref. 24)
Odor recognition level for cresols ranges from 0.9 to 1.21 mg/m or 0.20 to 0.27 ppm
(ref. 3).
The odor threshold in air for p-cresol is reported as 0.001 ppm or 4 ug/m (ref. 29).
Cresols are obtained from coal tar (ref. 24). Due to the low vapor pressure and dis-
agreeable odor, cresols usually do not present an acute inhalation hazard (ref. 63).
Cresols are highly resistant to biological oxidation (ref. 67).
TOXIC PROPERTIES. HEALTH EFFECTS:
Toxic properties of cresols are similar to those of phenol. Cresols may be absorbed through the skin.
Respiratory hazard is low because of low volatility. Absorption may cause damage to liver, kidney and
nervous system (ref. 9). Order of toxicity beginning with most toxic is reported to be as follows:
p-cresol; o-cresol; phenol; m-cresol (ref. 4)
m-cresol
o-cresol
p-cresol
LD5Q (oral, rat)
242 mg/kg
121 mg/kg
207 mg/kg
Toxicity to aquatic life: tainting of fish may result from concentrations of 0.07 mg/l of mixed cresol
isomers (ref. 28). The toxic concentration of p-cresol is 5 ppm for rainbow trout (ref. 36). The 96-hour
LC50 for p-cresol is reported as 19 mg/i (ref. 68). For mixed cresol isomers, the 96-hour TUn Is reported
as 10-1 ppm (ref. 2).
REGULATORY ACTIONS. STANDARDS. CRITERIA. RECOGNITION. CANDIDATE STATUS FOR SPECIFIC REGULATION:
TLV for Cresol (all isomers): 22 mg/m (5 ppm).
EPA 1976 Water Quality Criteria (proposed): 1 ug/i of phenol (including phenolic compounds) for domestic
water supply (welfare) and to protect against fish flesh tainting (ref. 33).
NAS/NAE 1972 Water Quality Criteria: 1 ug/z of phenolic compounds in public water supply sources to
prevent odor from chlorinated phenols. To prevent tainting and toxic effects 1n aquatic life: Concentration
no greater than 100 ug/c.at any time or place; application factor of o.OS (for phenols) (ref. 28).
U.S. Public Health Service Drinking Water Regulations, 1962—Levels for alternate source selection:
1 ag/i (for phenols) (ref. 65).
MINIMUM ACUTE TOXICITY CONCENTRATIONS:
Air, Health: 2.2 x 104 ug/m3 (5 ppm)
Water, Health: 5x1-5 ug/i
Land, Health: 0.002 x 5 » 0.01 ug/g"
ESTIMATED PERMISSIBLE CONCENTRATIONS:
ftJ .. ^O /jlOrt _ C1 — /«*
Air, Ecology:
Water, Ecology:
Land, Ecology:
100 x 5 * 500 ug/i
0.002 x 500 • 1 ug/g
EPC
EPC
flH1
AHU
10J x 22/420 • 52 ug
5/420 = O.Olppm
EPCyH1 « 15 x 52 ' 780 ug/z
EPCyH2 = 13.8 x 22 = 304 yg/z.
EPC,.,S * 1 ag/i (phenolic compounds)
EPCLH - 0.002 x 1 = 0.002 ug/g
'WEI
EPC,JC1 « 50 x 1 « SO ug/i
70 ug/i
100 ag/i (phenolic compounds)
EPCLE » 0.002 x 50 * 0.1 ug/g
66
-------
MULTIMEDIA
ENVIRONMENTAL
— — — — — — • — — — .. ^1 1 L.OU I_O
EMISSION LEVEL GOALS
Air, pg/m3
(ppm Vol)
Water, pg/l
(ppm Wt)
Land, M9/9
(ppm Wtl
1, Based on Best Technology
A. Existing Standard!
NSPS, BPT, BAT
B, Developing Technology
Engineering Estimates
(R&D Goalil
II.
A. Minimum Acute
Toxicitv Effluent
Based on
Health Effecn
2.2E4
5.0EO
l.OE-2
Based on
Ecological
Effect!
5.0E2
l.OEO
Based on Ambient Factors
B. Ambient Level Goal*
Based on
Health Effects
52
(0.01)
1
0.002
Bated on
Ecological
Effecn
70
0.1
C. Elimination of
Discharge
Natural Background*
•To be multiplied by dilution factor
AMBIENT LEVEL GOALS
Air, M9/m
(ppm Vol)
Water, pg/l
(ppm Wt)
Land, Mfl/9
(ppmWt)
1. Current or Proposed Ambient
Standards or Criteria
A. Band on
Health Effects
It
B. Band on
Ecological Effect!
loot
II. Toxicity Based Estimated
Permissible Concentration
A. Baied on
Health Effect!
52
(0.01)
304
0.002
B. Based on
Ecological Effect!
50
0.1
III. Zero Threshold Pollutants
Estimated Permissible Concentration
Based on Health Effects
tPhenolic compounds,
67
-------
CATEGORY: 21 WLN: LB666J
PHENANTHRENE: C14H1Q. STRUCTURE:
Monocllnic crystals from alcohol; solutions exhibit
faint blue fluorescence.
PROPERTIES:
Molecular wt: 178; mp: 101; bp: 340; d: 0.9800 ; vap. press.: 1 mm at 118.3; vap. d: 6.14}
Insoluble In water; solubility may be enhanced by surfactant Impurities 1n water (ref. S3);
I1p1d solubility: 2 percent solution 1n o!1v« oil (ref. 72).
NATURAL OCCURRENCE. CHARACTERISTICS. ASSOCIATED COMPOUNDS;
Phenanthrene Is among the lower molecular weight polycycllc hydrocarbons comprising the volatile
portion of the benzene-soluble fraction of coal tar (ref. 4). Concentrations of 0.6102 ug/1,500 m3
and 6 ug/1,000 m3 In urban air are reported (ref. 1). This 1s equivalent to 0.0004 to 0.006 ug/m3.
Phenanthrene 1s associated with paniculate po1ycvc11c aromatic hydrocarbons, PPAH, (ref. 71). The
following concentrations of PPAH have been estimated or reported: A1r (urban environment 1n winter
1n seven selected U.S. cities): 21.6 ng/m3 - 14fr ng/m3 (ref. 71); groundwatar and surface-treated
water: 0.001 ug/£ • 0.025 yg/£ (ref. AAS); upper layer of Earth's crust: 100 ug/kg - 1,000 ug/kg
(ref. 58).
TOXIC PROPERTIES. HEALTH EFFECTS;
LD50 (oral, mouse): 700 mg/kg.
Phenanthrene may be present 1n soot, coal tar, and pitch, which are known to be carcinogenic to man.
Carcinogenic polycyclic aromatic hydrocarbons may Induce tumors at the site of application (ref. 59).
Phenanthrene 1s Included in the NIOSH Suspected Carcinogens List. The EPA/NIOSH ordering number 1s
3121. The lowest dose to Induce an oncogenlc response 1s reported as 71 mg/kg. The adjusted ordering
number is 44.
REGULATORY ACTIONS. STANDARDS. CRITERIA. RECOGNITION. CANDIDATE STATUS FOB SPECIFIC REGULATION!
Phenanthrene appears on EPA Consent Decree List with an assigned priority of 1.
TLV (coal-tar pitch volatlles): 0.2 mg/m3. [The specification Includes naphthalene, anthracene,
acrldlne, Phenanthrene, and fluorene, collectively. The purpose of the TLV 1s to minimize concen-
trations of higher weight polycycllc hydrocarbons which are carcinogenic (ref. 4)].
MINIMUM ACUTE TOXICITY CONCENTRATIONS;
A1r, Health: 7 x 104/44 • 1.59 x 103 ug/m3 A1r, Ecology:
Water. Health: 15 x 1.59 x 103 • 2.39 x 104 ug/i Mater, Ecology:
Land, Health: 0.002 x 2.39 x 104 • 47.8 ug/g Land, Ecology:
ESTIMATED PERMISSIBLE CONCENTRATIONS!
EPCAH2 * 0>107 x 70° * 75
EPCAH3 • 0.081 x 700 - 57 ug/m3
EPC,^ • 15 x 57 • 855 vg/t
EPCWH2 " °'4 x 70° " 28° U9/*
EPC. u • 0.002 x 280 * 0.56 ug/g
LH » *
EPCAC2 • 103/(6 x 44) • 3.8 ug/m3
EPCUC • 15 x 3.3 « 57 uq/t
EPCLC • 0.002 x 57 - 0.114 wg/g
68
-------
MULTIMEDIA
til* iKwnivicraiMi. 2'\
.GOALS PHENAWTHRPWP
Air,*i9/m3
(ppmVoll
Wntr. tig/1
(ppmWti
Land,M«/9
(pprnWt)
EMISSION LEVEL GOALS ~ I
1. Bated on Bet
A. Existing Standards
NSPS, BPT, BAT
B. Dtnloping Technology
Engineering Estimetes
IR&O Goals!
II. Based on Ambient Factors
A. Minimum Acute
Toxicity Effluent
Based on
Health Effect!
1.59E3
2.39E4
4.8E1
Based on
Ecological
Effects
B. Ambient Level Goal'
Based on
Healtti Effects
3.8
57
0.114
Based en
Ecological
Effect!
C. Elimination of
Discharge
Natural Background*
•To to multiplied by dilution factor
AMBIENT LEVEL GOALS
Air.tig/m3
(ppmVoO
Wrar.M9/l
(ppmWt)
Lmd,/4/g
(ppmWt)
1. Currant or Proposed Ambient
Standard! or Criteria
A. Based on
Health Effactl
B. Bated on
Ecological Effecta
II. Toxicity Based Eitimated
Permissible Concentration
A. Bated on
Health Effect!
57
280
0.56
B. Based on
Ecological Effects
III. Zero Threshold Pollutann
Estimated Permiuible Concentration
Based on Health Effect!
3.8
57
0.114
-------
CATEGORY: 21
BENZ(a)ANTHRACENE: C18H12 (benzo(b)phenanthrene,
1,2-benzanthracene, 2,3-benzophenanthrene, BA).
Crystallizes in the form of plates from ethanol.
Solutions exhibit greenish-yellow fluorescence.
PROPERTIES:
Molecular wt.: 228.28; mp: 158-9; bp: 400° C; sublimes;
WLN:
STRUCTURE:
L 06 B666J
insoluble in water; solubility
may be enhanced by surfactant impurities in water (ref. 58); lipid solubility:
neutral, sterile olive oil (ref. 72).
NATURAL OCCURRENCE. CHARACTERISTICS. ASSOCIATED COMPOUNDS:
0.6 mg/0.2 ml
8enz(a)anthracene occurs in coal tar and is associated with particulate polycyclic aromatic
hydrocarbons, PPAH. The lowest urban air concentration reported for benz(a)anthracene is
44.59 ug/m3 (ref. 1). This is equivalent to 0.029 ug/m3.
Concentrations of BA In soils (nonindustrial areas) ranging from 5-20 ug/kg have been
reported (ref. 73).
Other concentrations of BA are reported as follows: (a) drinking water - 23.2 ug/m ,
(b) cooked meat or fish - 189 ug/kg; (c) vegetables - 230 ug/kg; (d) roasted coffee -
14.2 ug/kg (ref. 73).
TOX!C PROPERTIES. HEALTH EFFECTS;
LQ|_0 (intravenous, mouse): 10 mg/kg.
8enz(a)anthracene may be present in soot, coal tar, and pitch, which are known to be
carcinogenic to man. Carcinogenic polycyclic aromatic hydrocarbons may induce tumors at
the site of application (ref. 59). Benz(a)anthracene is included in the NIOSH Suspected
Carcinogens List. The EPA/NIOSH ordering number is 3124. The lowest dose to Induce a
carcinogenic response is reported as 2 mg/kg. The adjusted ordering number is 1562.
REGULATORY ACTIONS. STANDARDS. CRITERIA. RECOGNITION. CANDIDATE STATUS FOR SPECIFIC REGULATION:
TLV ' 0.2 mg/m [for particulate polycycllc aromatic hydrocarbons (PPAH). This TLV recognizes
the carcinogenic potential of PPAH collectively].
8enz(a-)anthracene appears on the EPA Consent Decree List with an assigned priority of 1.
MINIMUM ACUTE TOXICITY CONCENTRATIONS:
Air, Health: 7 x 104/1,562 * 44.8 ug/m3
Water, Health: 15 x 44.8 » 672 yg/£
Land, Health: 0.002 x 672 »1.34 ug/g
Air, Ecology:
Mater, Ecology:
Land, Ecology:
ESTIMATED PERMISSIBLE CONCENTRATIONS:
EPC
EPC
AH2
'AH3
0.107 x 10
0.081 x 10
EPCWH1 • 15 x 0.81
EPCWH2 * °'4 x 10 *
EPCLH ' 0.002 x 4 =
» 1.07 ug/mj
* 0.81 ug/m'
12.2 ug/i
3
o.oos ug/g
EPC
AC2
EPC
1C
» 10V(6 x 1,562) = 0.11 ug/nT
15 x 0.11 = 1.65 Vg/t
0.002 x 1.65 ' 0.003 ug/g
70
-------
MULTIMEDIA YY
ENVIRONMENTAL *?
GOALS 21
• VI^LJ BENZfalANTHRACENE
Air, pg/m3
(ppm Volt
Water, pg/l
(ppm Wt)
Land, Mfl/9
(ppm Wt)
EMISSION LEVEL GOALS
A. Exitting Standard!
NSPS, BPT, BAT
8. Developing Technology
Engineering Eitimatei
IR8.D Goili)
II. Based on Ambient Factors
A. Minimum Acute
Toxicity Effluent
Sued on
Health Effect!
4.5E1
6.7E2
1.3EO
Sued on
Ecological
Effects
B. Ambient Level Goal*
Baied on
Health Effect!
0.11
1.65
0.003
Bated on
Ecological
C. Elimination of
DiKharge
Natural Background*
0.029t
0.0231
0.02
•To be multiplied by dilution factor
AMBIENT LEVEL GOALS
Mr.ng/m3
(ppm Vol)
Water, pg/l
(ppm Wt)
Land, M9/9
(ppm Wt)
1. Current or Proposed Ambient
Standard) or Criteria
A. Bated on
Health Effect!
B. Baied on
Ecological Effect!
II. Toxicity Bated Estimated
Permissible Concentration
A. Bated On
Health Effect!
0.81
4.0
0.008
B. Bated on
Ecological Effect!
III. Zero Threshold Pollutants
Estimated Permissible Concentration
Bated on Health Effect!
0.11
1.65
0.003
tReported for urban air. No rural concentration is reported.
lorinking water.
71
-------
CATEGORY! 54 WLN: H2 SE
HYDROGEN SELENIDE: H.Se (selenium hydride). ««.„.,,.-.
* STRUCTURE:
Colorless poisonous gas; disagreeable odor of decayed
horseradish. H j
PROPERTIES;
Molecular wt: 80.98; mp: -60.4; bp: -41.5; gas density: 3.664760
(air); vap. press: 10 atm at 23.4° C; solubility In water: 270
mi/100 mi at 22.5°.
NATURAL OCCURRENCE. CHARACTERISTICS. ASSOCIATED COMPOUNDS:
Hydrogen selenlde 1s formed by the action of dilute adds on metallic selenldes. Selenium will combine
directly with hydrogen at temperatures below 250" C to form HjSe. Hydrogen selenlde unites directly with
most ratals to form metal selenldes. The odor recognition level for hydrogen selenlde Is 1.00 mg/m3
(ref. 3). Hydrogen selenide gas 1s Important as an air contaminant. Because the gas Is highly soluble
1n water, 1t 1s also a potential water contaminant.
TOXIC PROPERTIES. HEALTH EFFECTS:
Systemic poisoning as well as pulmonary Irritation may result from exposure to hydrogen selenlde.
Liver damage Is reported from exposed experimental animals (ref. 4). It 1s generally considered to be
more toxic than elemental selenium. The lowest toxic dose affecting the central nervous system of a
human 1s 0.2 ppm. See also Selenium and Selenium Compounds.
LC (Inhalation, guinea pig): 1 mg/m3/8 hr.
REGULATORY ACTIONS. STANDARDS. CRITERIA. RECOGNITION. CANDIDATE STATUS FOR SPECIFIC REGULATION;
TLV » 0.2 mg/mj (0.05 ppm).
Standards and criteria applicable to selenium compounds Include the following:
Selenium 1s a candidate for the 11st for Toxic Pollutant Effluent Standards (ref. 10). It 1s Included In the
EPA Consent Decree List, Priority III.
flatlonal Interim Primary Drinking Water Standards: 0.01 mg/i, as Se (ref. 102).
U.S. Public Health Service Drinking Mater Standards, Levels for Source Rejection: 0.01 mg/t, as Se (ref. 66).
EPA 1976 Water Quality Criteria (proposed): For domestic water supply (health)--10 ug/i; for marine and
freshwater aquatic life—application factor: 0.01 (to be applied to 96-hr LC,0) (ref. 33).
NAS/HAE Hater Quality Criteria, 1972: For public water supply sources—0.Or mg/* for marine aquatic life:
hazard level—0.01 mg/z; minimal risk of deleterious effects— 0.005 mg/t; application factor—0.01 (to be
applied to the 96-hr LCSO); for Hvestock—0.05 mg/i; for Irrigation—0.02 mg/i for continuous use on all
soils (ref. 28). 9U
MINIMUM ACUTE TOXICITY CONCENTRATIONS;
Air, Health: 200 ug/mj (O.OS ppm) Air, Ecology:
Hater, Health: S x 10 * 50 vg/i, as Se Water, Ecology: 5 x 5 « 25 ug/i. as Se
Land, Health: 0.002 x 50 » 0.1 wg/g, as Se Land. Ecology: 0.002 x 25 • 0.05 ug/g, as Se
ESTIMATED PERMISSIBLE CONCENTRATIONS:
EPC^ • 103 x 0.2/420 • 0.5 ug/m3
EPCAH1a • 0.05/420 > 0.0001 ppm
EPC^, • 15 x 0.5 • 7.5 ug/i
13.8 x 0.2 - 2.8 wg/i
10 ug/t EPCWES • 5 wg/t
EPC,H « 0.002 x 10 » 0.02 ug/g EPCL£ « 0.002 x 5 * 0.01 wg/g
72
-------
MULTIMEDIA xx
ENVIRONMENTAL **
GOALS HYDROGEN SPI PW.ni:
Alr,Mj/m3
(ppm Vol)
Watar, Mt/l
(ppm Wt)
Land, MQ/g
(ppmWt)
EMISSION LEVEL GOALS ~~ \
1. Buad on Bait Technology
A. Exlltlnj Slandardi
NSPS, BPT, BAT
B. Dtviloping Ttcnndogv
Engtnatrlng EitlmatM
(R8.0 Qotli)
II. Baiad on Ambiant Factor*
A. Minimum Aoutt
Toxlcltv Effluant
Baiad on
2.0E2
(0.05)
5.0E1
l.OE-1
BiMdon
Ecological
Effacti
2.5E1
5.0E-2
B. Amblant Livtl Goal'
BaMd on
He«l* Efftett
0.5
(0.0001)
10
0.02
BtMdon
Ecological
Eff.cn
5
0.01
C. Elimination of
Olichnga
Natural Background*
•To b« mul«pll«d by dilution factor
AMBIENT LEVEL GOALS
A!r,M/m3
(ppm Vol)
W«ir,n9/l
(ppm Wtl
Land, MB/9
(ppm Wt)
1, Cucrant or Piopoxd Ambiant
Stanoardi or Criteria
A. BtMdon
Hllltfl EffMi
10
i. AlMf. on
Booiotieai £HiMd on
MMIth Effteti
0.5
(0.0001)
0.02
6. BiMdon
Eoologleil Efftoti
0.01
III. Zaro Thrmhold Pollutants
Eitlmatad Parmiuibla Conoantratlon
BaMd on Hailth Effaett
73
-------
CATEGORY: 73
WLN:
COPPER AND COPPER COMPOUNDS (AS COPPER). Cu (cuprum): STRUCTURE:
An orange, ductile, malleable metal. + +?
Cu Cu Cu
PROPERTIES: Atomic number: 29; group Ib; atomic wt: 63.546;
mp: 1,083 ±.0.1; bp: 2336; d: 8.92; Insoluble; vap. press:
1 mm at 1628°C.
NATURAL OCCURRENCE. CHARACTERISTICS. ASSOCIATED COMPOUNDS:
Copper forms two series of compounds, cuprous (Cu+1) and cuprfc (Cu*2). CupHc compounds are the
more stable. They Ionize In aqueous solution.
Rural background concentration in air is reported as 0.01 to 0.41 yg/m3 (ref. 1). Another source
reports concentrations ranging from 0.06 to 0.078 as a constituent of suspended particulates in non-
urban air (ref. 3). Copper salts are in the form of dusts and mists: metallic copper may occur as
fume (ref. 4).
Concentration in freshwater as indicated from hydrologlc benchmark samples ranges from zero to
40 ug/i; out of 126 samples 87 were zero (ref. 64). Another report Indicates that the average fresh-
water copper concentration in U. S. surface water is 13.8 ug/i with a range of 0.8-280 ug/i (ref. 28).
Natural concentration in seawater is reported as 0.001 mg/i (ref. 28) to 0.02 mg/i (ref. 24). Copper
imparts a taste to water in concentrations as low as 1 mg/i (ref. 33). Occurrence in earth's crust is
70 ppm (ref. 24). Copper is found in soils at about 20 ug/g (ref. 128).
Copper Is an essential element in plants and animals; adult intake of copper is from 2 to 2.5 mg
daily (ref. 4).
TOXIC PROPERTIES. HEALTH EFFECTS;
Copper in the form of salts may cause irritation to the gastrointestlnaT tract if ingested;
chronic exposure may result in anemia. Exposure to metallic copper fume may cause respiratory
Irritation, and eye and skin Irritations. Damage to the liver, kidneys, and nervous system may
result from exposure to copper (ref. 4,9).
LDjQ (intraperitoneal, mouse): 3500 ug/i.
LOso (oral, rat): 140 mg/kg for CuClj; this 1s equivalent to 66 mg/kg as Cu .
Aquatic toxicity: Copper has a synerglstic action with zinc, cadmium, and mercury. Concentration
of calcium and magnesium Influence the toxicity of copper.
The 96 hr LCgg for Piephales promelas (fathead minnow) is 0.05 ppm for CuS04 in soft water, 1.4 ppm
in. hard water (ref. 28). Copper" inhibits photosynthesis of giant kelp, at 0.06 mg/i and it is toxic
t°J°?s^«s at 0-1 m9/1 (ref' 28'- :t has * concentration factor of 30,000 in marine phytoplankton,
and 1,000 in marine fish (ref. 28).
Phytotoxicity: Copper concentrations of 0.1 to 1.0 mg/i 1n nutrient solutions are toxic to a
number of plants (ref. 28).
REGULATORY ACTIONS. STANDARDS. CRITERIA. RECOGNITION. CANDIDATE STATUS FOR SPECIFIC REGULATION:
TLV (metallic copper fume): 0.2 mg/m3.
TLV (dusts and mists): 1 mg/m3.
Copper is included on EPA Consent Decree Priority III List.
U.S. Public Health Service Drinking Water Regulations, 1962, Levels for Alternate Source
Selection: 1.0 mg/i (ref. 66).
EPA 1976 Water Quality Criteria (proposed): For domestic water supplies (welfare): 1.0 mg/i-
for freshwater and marine aquatic life: application factor— 0.1 (to be applied to 96-hour LC«n
nonaerated bioassay)(ref. 33). 3U*
NAS/NAE 1972 Water Quality Criteria: For public water supply sources: 1 mg/i; for freshwater
aquatic life: application factor--0.1 (to be applied to 96-hour LCso); for marine aquatic life-
hazard level— 0.05 mg/i; minimal risk of deleterious effects— 0.01 mg/i; application factor—
0.01 (to be applied to 96-hour LC5g); for livestock: O.S mg/i; for irrigation: 0.20 mg/i for
continuous use on all soils (ref. 28).
Recommendation of U. S. Department of Agriculture and Land Grant Institutions: Copper concentra-
tion for most soils~250 kg/hectare (ref. 112).
MINIMUM ACUTE TOXICITY CONCENTRATIONS:
Air, Health: 200 ug/m
Water, Health: 5 x 1000 • 5,000 ug/i
Land, Health: 0.002 x 5,000 * 10 ug/g
ESTIMATED PERMISSIBLE CONCENTRATIONS:
Air, Ecology:
Water. Health:
Land, Ecology:
5 x 10 » 50 yg/i
0.002 x 50 • 0.1 ug/g
EPC
AH1
X °'2/420
EPCUH1 « 15 x 0.5 * 7.5 ug/i
EPCWH2 * 13.8 x 0.2 = 3 ug/i
EPC
EPC
MHS
1,000 ug/i
0.002 x 1000
EPC
EPC
yES
LE
- 10 ug/i
0.002 x 10 * 0.2 ug/g
74
-------
MULTIMEDIA
ENVIRONMENTAL
GOALS
xx
78
Air, M9/m3
(ppm Vol)
Water, (jg/l
(ppm Wt)
Land, jjg/g
(ppm Wt|
. \s**jr r t-n
EMISSION LEVEL GOALS
1. Based on Best Technology
A. Existing Standard!
NSPS, BPT, BAT
B. Developing Technology
Engineering Estimates
(R&D Goals)
II. Based on Ambient Factors
A. Minimum Acute
Toxicity Effluent
Based on
Health Effects
2.0E2
5.0E3
1.0E1
Based on
Ecological
Effects
5.0E1
l.OE-1
B. Ambient Lewi Goal*
Based on
Health Effects
0.5
1,000
2
Based on
Ecological
Effecn
10
0.2
, C. Elimination of
Discnv9i
Natural Background*
0.01 to 0.41
13.8
1 to 20t
20
*To be multiplied by dilution factor
AMBIENT LEVEL GOALS
Air, M9/m
(ppm Vol)
Water, ^g/l
(ppm Wt)
Land, pg/g
(ppm Wt)
1. Current or Proposed Ambient
Standards or Criteria
A. Based on
Health Effects
1,000
B. Based on
Ecological Effects
10
II. Toxicity Based Estimated
Permissible Concentration
A. Based on
Health Effects
0.5
2
B. Ba»d on
Ecological Effects
0.2
III. Zero Threshold Pollutants
Estimated Permissible Concentration
Based on Health Effecn
tFor seawater.
75
-------
A NON-SITE-SPECIFIC
TEST PLAN
Karl J. Bombaugh
Radian Corporation
Austin, Texas 78766
Abstract
An environmental assessment of a fuel con-
version technology, such as Low-Btu Gasifica-
tion, requires a test plan that addresses all
areas of that technology. Such a plan can not
be site-specific since it must be applicable to
the many processes and varied operations
within the technology. The plan must therefore
be broad in scope. However, it must also be
specific in content so that it will be applicable
to the needs and problems of an actual test.
To meet this requirement, a non-site-
specific test plan manual has been developed
for use with low-Btu coal gasification. The
manual provides basic information and pro-
cedural guidelines for the preparation and im-
plementation of environmental assessment test
plans. It defines four basic operations in test
plan development. These are:
• an engineering analysis,
• the definition of test purpose and test
method,
• the selection of sampling methods,
and
• the selection of analysis methods.
Emphasis is placed on the development of
the test method which involves defining the
test's requirements and relating these re-
quirements to the available information sources
to formulate a practical test plan.
This presentation will provide a description
of a non-site-specific test plan and will show
how the plan can be used for a site-specific
test.
INTRODUCTION
An environmental assessment of a fossil
energy conversion facility should be based on
valid data which accurately defines the emis-
sions from the operation in terms of the mass
and composition of the pollutants emitted. To
be valid, the data used for the assessment must
have been obtained under representative
operating conditions by skilled technicians us-
ing reliable sampling and analytical procedures.
When such data are not available in the
technical literature, it must be obtained by
means of an onsite test.
A program for an onsite test consists of four
basic tasks involving:
• preparation,
• sampling,
• analyses, and
• data interpretation.
The preparation task is of major importance
because without adequate preparation major
oversites can occur which can impede the pro-
gram, magnify costs, and contribute to ques-
tionable results. The preparation task should be
done prior to initiating the sampling and
analyses tasks.
The preparation task can be broken down in-
to four subtasks as follows:
• defining the problem,
• reviewing the available process data,
• inspecting the plant, and
• preparing a site-specific test plan.
Major attention must be devoted to problem
definition in order to avoid false starts and
wasted effort.
A poorly defined problem can result in a test
plan with inadequate methods, resulting in a
site test that produces little useable data. Since
sampling and analysis procedures are relatively
problem specific they must be chosen to fit the
application and to provide the level of accuracy
that is required. Process data must be studied
to gain an understanding of the process after
which the concepts should be validated by a
plant visit.
Because of the many different unit opera-
tions within a Low-Btu gasification and utiliza-
tion process, the many types of processes for
each operation and the many variations within
any given process, a large number of site-
specific test plans will be needed to assess the
entire Low-Btu technology. In order to maintain
a semblance of consistency in the test ap-
proach a philosophy and strategy for testing
has been defined in a non-site-specific test
manual. This document was developed to serve
as a guide for the preparation of environmental
assessment test plans for low- and medium-
76
-------
Btu gasification plants. This manual does not
provide the actual procedures required for a
given test. It provides instead, background in-
formation and procedural guidelines which will
serve as the foundation for the development
and implementation of successful site-specific
test plans.
This presentation will provide a description
of a test plan which in this case is non-site-
specific and will describe how the test plan
manual is used in the preparation of a test plan
for a specific site.
TEST PLAN PREPARATION
The preparation of a test plan involves opera-
tions in four areas of endeavor as follow:
• engineering analysis,
• definition of test purpose and test
method,
• selection of sampling methods, and
• selection of analysis method.
The relationship between these four opera-
tions is illustrated diagramatically in Figure 1.
The engineering analysis is needed to provide
information about the plant such as its physical
layout and its process chemistry. This informa-
tion must be reduced to a useable form. The
engineering analysis includes three steps:
• review and simplify process
flowsheets,
• define process modules, and
• identify streams of interest and their
probable composition.
The test purpose defines the test objectives
which may be any or all of the following:
• an environmental assessment,
• a control technology assessment,
• a material balance to deter-
minetransport and fate of selected
species, and
• a characterization of stream composi-
tion.
Although the purpose of the test is fixed by
the information needs of a program, it has a
profound effect on the detail of the test method
which defines:
• the streams to be sampled,
• the species to be analyzed,
• sampling frequency,
• sampling duration,
• precision and accuracy during sampl-
ing, and
• process conditions during sampling.
The test method in turn establishes a basis
for selecting methods for sampling and
analysis, since the respective methods must
meet the requirements set by the test method.
The sampling plan must address four major
areas of activity as follows:
• preparation which includes:
equipment,
manning,
check-out, and
scheduling.
• sample collection requiring considera-
tion of:
source type,
sample composition,
process conditions, and
information sought.
• sample preservation, and
• adaptation to deal with the unex-
pected.
The analysis plan must take into considera-
tion the following:
• location - onsite or offsite analyses,
• type of samples,
• preseparations required,
• techniques of identification or quan-
tification, and
• data validations and interpretation
while on site.
The completed test plan however is not just a
combination of an engineering analysis, a test
method, a sampling plan, and an analysis plan.
Although each of these areas of activity is
distinct, they are interdependent as illustrated
by the diagram in Figure 1. The decisions
within each area are influenced by the test pur-
pose and the test method which is in turn in-
fluenced by the limitations that are inherent
within any or all of the involved areas.
Because of this interdependency between
the respective areas, the respective plans
should be prepared concurrently using correc-
tive feedback such that the selections made for
each area are made with full regard for the
potential interaction with other areas. Since the
scope of a site-specific test plan is defined by
the test method, first attention should be
devoted to its preparation. However, little can
77
-------
INFORMATION
NEEDED
00
ENGINEERING
EVALUATION/
PLANT
INSPECTION
SAMPLING
METHODS
ANALYSIS
OF
METHODS
TYPE OF TEST
TEST METHODS
MAJOR AREAS IN PLAN PREPARATION
SITE SPECIFIC
TEST PLAN
Figure 1. Information flow diagram for the preparation of a site-specific test plan showing the interdependency of
the major areas of endeavor.
-------
be done without adequate information about
the site to be tested. This information can be
gained from the engineering analysis of ap-
propriate flow sheets in the technology file us-
ing the guidelines presented in the test plan
manual.
ENGINEERING ANALYSES
The engineering analysis is begun with a
review of process flow sheet. If flow sheets for
the specific site are not available during the in-
itial phase of test plan development, generic
diagrams of similar processes can be used until
they can be replaced by authenic ones from the
test site or until the generic plans can be
authenticated by a site visit. In this presenta-
tion a diagram from a Lurgi plant will be used to
illustrate the steps in an engineering analysis.
The plans shown in Figure 2 represent a Lurgi
Low-Btu coal gasification plant. In the form
shown the diagram is too cumbersome to be
used effectively in preparing a test plan for an
environmental assessment. It should be
simplified. Simplification can be accomplished
by dividing the complex integrated process into
unit operations and modules, e.g.
• process operations:
coal pretreatment and handling,
coal gasification,
gas cleaning and purification, and
gas utilization.
• effluent control operations:
air pollution controls,
water pollution controls, and
solid waste controls.
The operation should then be subdivided into
modules. For example, coal preparation can be
divided into the following modules:
• drying,
• partial oxidation,
• crushing and sizing,
• pulverizing, and
• briquetting,
or the gas purification operation can be di-
vided into:
• particulate removal,
• gas quenching, and
• acid gas removal.
,Any emission control module that is
associated with an operation can also be iden-
tified in this step. Detailed flow sheets for each
Operation of interest should be acquired in
order to identify all influent and effluent
streams as well as the types of emissions that
are anticipated. The concept is illustrated by
Figure 2. The area within the block in Figure 2
identifies the gas purification process that is
expanded into a detailed flow sheet in Figure 3.
The flow sheet is used to prepare a schematic
diagram of the type shown in Figure 4 which
identifies the types of emissions from each
module. An analytical block diagram of the type
shown in Figure 5 is then prepared for each
module identifying each influent and effluent
stream as either a process or an emission
stream. (The analytical block diagram is a key
tool in the engineering analyses because it pro-
vides the maximum amount of relevant infor-
mation in the simplest form.) In this step the
emission streams are identified and character-
ized as far as is possible using the data that are
available.
DEFINITION OF THE
TEST PURPOSE AND TEST METHOD
Test Purpose
The first and major step in the preparation of
a test plan for an environmental assessment is
to define the purpose of the test that may be re-
quired to obtain any or all of the following types
of information about the site of interest:
• pollutant emission level,
• transport and fate of selected
pollutants as they advance through
the process,
• control response characteristics of
operating units, and
• characterization of stream composi-
tion.
Specific requirements unique to each
category, must be met by the test plan in order
to obtain each type of information. (That is to
say, a different type of test is needed to obtain
each type of information.) For example, to
determine pollutant levels one should first
establish that pollutants are present. For this
purpose, a comprehensive survey type of test
is needed. (In such a test only minor emphasis
need be placed on process conditions, sampl-
ing or analytical accuracy.) Then to obtain in-
formation on the transport and fate of a known
pollutant, a more sophisticated test is needed.
79
-------
TO ATMOSPHERE
COAL
•
GAS
/A5
ACID ftAS
CONTAMINA7EO
Cit'AH 6AS
LIQUOR
BLOHDOUN-+
6AS
Figure 2. Flow diagram of a coal gasification plant.
7D-//O/-2
-------
ABSORBS/I
ACID &A5
-+ €
PAEWASH
TOUEK
•FEED GAS
HAPTHA
C.IV.
EXPANSION
GAS
»>
fLASH
TANK
^
\
^
I
^
R l
n
ft ASH
AZEOr/
COLU*
t
Xff
\N
L
Jk
T
ME THAN
COLUMN
fe. p
Jf/CH HfS
"ACID GAS
HOT
MAKE-UP
~* METHANOL
PKOC f-SS COMDENSA /£"
Figure 3. Gas purification and refrigeration.
7O-//OO-?
-------
LEGEND
oo
NO
1 ^
1
< ^ f^ \
. PART1CULATE J PRODUCT \
^ REMOVAL " ^1 GAS / *"
""T"" ^ — ^
w, GAS »./ COOLED \
QUENCHING \ GAS /
' — QUENCH LIQUOR
1 COOLING WATER
ACID GAS
REMOVAL
SORBENT OR REACTANT *
~| AIR EMISSIONS
~T Q LIQUID EFFLUENTS
-K SOLID WASTES
1
j
N?
_k.
•J PRODUCT \
— WLOW/ MEDIUM)
\ BTU GAS I
L
Figure 4. Flow diagram for the modules in the gas purification process.
-------
Shifted Crude Low BTU Gas
Gas
Cooling
I
Crude Cooled Shifted Crude
_Low BTU Gas
Oily Gas Liquor
Crude Low STTT Gas
Coal Lock. Ga«
Coal Lock Gas Recycle
Gas
Cooling
II
Cooled Crude Low .BTU Gas
Recycle
Conden-
sate
Oily Gas
Liquor
BFW
Lean
H2S
Gas
Rich
H2S
Gas
Cooled Crude Low JiTD Gasv
Make-Up Methanol
Gas
Purification
Expansion
Gas
Low BTU Products Gas
„ Naphtha
Condensate
Figure 5. Analytical modules for the gas purification operation at the El Paso Burnham complex.
83
-------
This test should be made at conditions that are
as near to steadystate as is feasible. Samples
should be composited in order to level out the
effects of minor variations. Replicate samples
should be taken to increase credibility and
analyses methods of high accuracy should be
used so that the material balance can be closed
(i.e. input = output). In contrast to either of the
above, a control response test can best be done
with a continuous monitor or with high fre-
quency sampling to identify process variations.
When possible the process operating condi-
tions should be varied around the control point
in order to identify trends and establish the ef-
fects of the control variables on emissions. In
many cases, analysis methods providing com-
paratively low accuracy can be used for this ap-
plication. Indeed methods of low accuracy and
only acceptable reproducibility, but with rapid
response, are preferred to highly accurate
methods which cannot be used continuously or
in real time. While an attempted material
balance focuses on a fixed point in time (just as
a balance sheet in a business operation), the
control response test is carried out over an ex-
tended period of time and focuses on the rela-
tionship between control variables and emis-
sion response.
These concepts are illustrated diagramically
in Figure 6. The concept of the control function
and the balance are illustrated in Figure 6C and
6B respectively. The diagram in Figure 6A il-
lustrates the emission level test in which atten-
tion is focused on the magnitude and type of
emission without an intrinsic need for the infor-
mation on the composition of either the
feedstock or product. As a practical matter
however, feedstock and product analyses are
often included in a test program because most
test programs are designed to serve a broad
purpose and thereby obtain more than one type
of information. Each of the various types of in-
formation is considered separately here in order
to focus attention on the test's requirements
which establishes its identity. Although tests
for each type of information can be done
separately, in practice they may be done con-
currently with varying degrees of overlap.
When they are integrated into a single program,
care must be taken to satisfy the test re-
quirements for each type of information sought
lest the results be invalid.
Test Method
The test method defines the criteria for the
test. These criteria must be met in order to ob-
tain valid data from each of the respective in-
formation areas specified by the test's pur-
pose. The test criteria include:
• level of accuracy and reproducibility,
• process operating conditions,
• process data requirements,
• stream selection,
• sampling frequency and duration, and
• analysis parameters.
Although the test purpose is intrinsically
related to an environmental or a control
technology assessment the data requirement
and therefore the test criteria will vary with the
data needs.
THE PHASED APPROACH
OF ENVIRONMENTAL TESTING
The objective of an environmental test is to
assess the pollution potential of a source. A
comprehensive multimedia environmental
assessment requires a comprehensive and
potentially costly test program. It requires
highly accurate test methods capable of
characterizing a wide range of samples for a
potentially broad spectrum of species from a
wide variety of sources. As a means of ap-
proaching the problem in a cost effective man-
ner, the Environmental Protection Agency has
established a phased approach to environmen-
tal assessment testing which enables the tester
to locate the problem area before expending
costly effort to characterize it. The approach
utilizes three levels of testing which are
characterized as follows:
Level I: Identify problem areas using survey
methods of moderate accuracy.
Level II: Characterize problem areas by iden-
tifying and accurately quantifying
hazardous species in order to
assess environmental burden.
Level III: Monitor selected indicator com-
pounds to facilitate the establish-
ment of a control technology.
This phased approach is intended to avoid
the costly pitfall in an environmental assess-
84
-------
00
CJ1
Feed
Emission Measurement
Gaseous
Solid Liquid
Control Responses
t"
Process
\
E2
, E2, Ej -/(F) + ]f(P)
B
Material Balance
b
h r i •
I
1. Steady State - simultaneous sampling
2. Time phased sampling
Influent must produce effluent
Stream Composition
Stream Composition - what is in it.
Major compounds -
Minor compounds -
Trace compounds -
Sub Traces
600 compounds of MEG
Figure 6. Diagramatic illustration of the four types of information identifying the test's purpose.
-------
ment test program, e. g.
• wasted effort on pollutant free emis-
sion streams or sought after pollutants
that were not present,
• missed pollutants because of over-
sights in test planning and preparation.
The following text provides a discussion of
the interrelationship between the EPA phased
approach and the Non-Site-Specific Test Plan.-
The Non-Site-Specific Test Plan utilizes the
phased approach and uses the criteria defined
by the Procedures Manual (L8501) for a Level I
assessment as the basis for the initial phase.
The criteria for the second and third phases of
the EPA approach are at present undefined.
The Non-Site-Specific Test Plan therefore pro-
vides guidelines that are based on established
test procedures such that when a data need is
defined and the streams of interest identified,
the test specifications can be set and the
respective sampling and analyses procedures
chosen.
The EPA Level III test has characteristics in
common with the control technology test as
defined by the Non-Site-Specific Test Plan.
Test methods for a control technology assess-
ment are needed to determine the effectiveness
of an emission control module.* Such a test is
problem specific as well as site-specific. The
Non-Site-Specific Test Plan provides a means
of defining test parameters. In addition to the
criteria listed previously, attention must be
directed to the following factors:
• cause-effect relationships,
• process purterbations — controlled vs
uncontrolled variations,
• process response time,
• interactions — dependent vs indepen-
dent variables,
• process hysteresis,
• process design limitations,
• analysis response time, and
• prioritization of control variables.
The material balance is also a valuable tool
for a control technology assessment since the
fate of a pollutant is an integral concern with a
pollution control module. At the present time
use of the material balance is limited to
strategic elements such as sulfur, nitrogen, and
phosphorous as well as the more toxic so-
called trace elements*.
Relationship Between Approaches
The three levels of the phased approach can
be harmonized with the four types of informa-
tion that characterize the test purpose. The
relationship is shown in Table 1.
A question mark has been placed under
stream composition because it is not clear
whether this type of analysis will fit into the
EPA strategy. An analysis of this type is highly
problem specific. It can vary from a need to
identify a multitude of species in a complex
mixture to the need to seek out a trace of an ob^
jectionable component that interferes with the
performance of an emission control module.
Stream characterization can be a costly task
and should be done with discretion.
Test Method Preparation
The first step in the actual preparation of the
test method is to utilize the data from the
engineering analysis which should enable the
planner to:
• anticipate pollutants,
• identify potential fugitive emission
sources,
• predict the effects of operating condi-
tions on the flow rates and the com-
position of relevant streams, and
• determine if the data available is ade-
quate to proceed to a more advanced
test phase, e.g. Level II or III.
Based on the results from the engineering
analysis the planner progresses with the
development of the test method by defining the
criteria for the test. He must bear in mind the
potential restrictions that may be imposed by
the sampling and analytical methods as well as
by the emission source itself.
SAMPLING METHODS
Following the definition of the criteria for the
test, the next major step is to develop a detaijed
sampling plan for the site that is to be tested.
'Consideration should also be given to the use of the proc-
ess as a control module. See Figure 6C. Indeed a strategic
control variable can exert a profound effect on the emis-
sion rate of a pollutant from a process. Several processes
used in Low-Btu technology are subject to such a relation-
ship.
86
-------
TABLE 1
RELATIONSHIP BETWEEN THE TYPE OF
INFORMATION SOUGHT AND THE TEST LEVEL
Type of
Information 1
Pollutant level X
Fate of pollutant
Control response
Stream composition
Level
2
X
X
-
7
3
_
-
X
-
The task involves specifying the locations of
sampling points and selecting sampling
methods. It should also include processes for
sample handling.
Some considerations for sample port loca-
tions are:
• accuracy level defined by the test
method,
• locations of existing ports, valves,
and monitors,
• sampling practice in the test site,
• stream characteristics,
• effect of sampling on process opera-
tion, and
• safety and work area requirements.
Some considerations for sampling methods
are:
• criteria defined by the test method,
• sample source,
• sample type,
• sampling techniques,
• analyses parameters, and
• external limitations.
These considerations may be expanded as
follows:
• criteria defined by the test method
- level of accuracy required,
• sample source
- type of stream - process stream,
regular or fugitive omission,
- composition of stream,
- temperature,
- pressure,
- flow,
- type of vehicle - pipe, duct, tank, or
sluice,
- location - accessability,
- type of port,
valve port,
hatch,
blind flange,
gas duct,
conveyor,
outflow pipe or wier,
open pit, sump, or pond.
• sample type
- gas, liquid, solid or a mixture e.g.
• gas and vapor,
• gas and particulate,
• liquid and solid (slurry),
- regular or fugitive emissions.
• sampling techniques to get a
representative sample
grab,
grab and composite,
impinger,
- continuous monitor.
• analytical parameters
- collection via fixation,
preservation - storage and transport,
- free from contamination,
- optimization for the analysis.
• other limitations
- time,
- manpower,
cost,
- equipment,
- safety,
- plant regulations.
Provision must also be made to obtain rele-
vant sampling data which should include the
following:
• stream data
- flow rate,
- port location,
- stream temperature.
• stream pressure
date and time of collection,
- quantity of sample,
- sampling method,
- sampling handling and technique
utilized for preparation,
- sample preservation (if any).
ANALYSIS METHODS SELECTION
The final step in the preparation of the test
plan is the selection of methods for the
87
-------
analyses. Several factors must be considered
during the selection process e.g.
• the criteria fixed by the test method
level of accuracy,
species of interest,
type of assessment (Level 1, 2, or
3).
• the concentration level of the species
of interest,
• the presence of interfering species,
• the sampling method,
• time limitations,
• Equipment limitations, and
• cost factors.
If a Level 1 assessment is being made, the
methods of analyses are specified by the Level
1 Environmental Assessment Manual (L8501).
The diagram in Figure 7 outlines the approach
of the Level 1 method. The diagrams in Figures
8 and 9 outline the respective approaches to in-
organic and the organic analyses. These
methods are still in a state of evaluation and are
subject to modification. The methods for Level
2 analyses have not yet been specified.
However, as greater specificity and accuracy is
required, methods must be selected that are
capable of meeting the higher requirements. In
place of spark source mass spectrometry,
which is an ideal survey tool for trace elements,
a combination of techniques may be required.
The diagram in Figure 10 shows an approach
that can be used to determine 31 different
elements on samples such as those obtained
from a Low-Btu gasification process.
The approach to the determination of in-
dividual species of organic compounds is even
more complex than that for inorganic species.
A worthy objective is to preseparate the
samples into acidic, basic, and neutral fractions
for subsequent analyses of "volatile and
semivolatile" species by GC-MS. This ap-
proach provides access to the extensive com-
puterized data banks that are commercially
available. Nonvolatile substances of interest
can be further characterized by auxilliary
techniques. Following separation by High Per-
formance Liquid Chromatography, fractions
can be characterized by IR, FTIR, NMR, and UV
and fluorescence spectrometry or such other
techniques as are justified.
This approach, outlined in Figures 11 and
12, is completely modular and separates the
sample into 9 fractions, seven of which (with
the exception of macromolecules) can be
characterized to a large extent by GC-MS.
Whether the approach be to characterize a
sample in order to determine "what it con-
tains" or to analyze it for specified environmen-
tally hazardous species, the modular scheme
provides a most versatile approach that can be
adapted to a wide range of conditions.
SUMMARY
The Non-site-specific Test Plan provides a
systematic approach to environmental test
preparation. This approach makes it possible to
anticipate many of the problems that would be
encountered at a test site. It also makes it
possible to give prior considerations to the
potential solutions to these problems. A
manual has been developed that provides
guidelines for these considerations.
REFERENCES
1. James M. Harless and Karl J. Bombaugh.
A Non-site Specific Test Plan Manual for
the Characterization of Low/Medium-Btu
Gasification Facilities. EPA Contract No.
68-02-2147. Radian Project No.
200-143-10. Radian Corporation,
Austin, Texas, July 1977.
2. J. H. Hamersma, S. F. Reynolds, and R. F.
Maddalene, IERL-RTP Procedures Manual:
Level 1 Environmental Assessment.
Report No. EPA 600/2-76-160A. EPA
Contract No. 68-02-1412, Task 18.
Redondo Beach, Ca. TRW Systems
Group, June 1976.
88
-------
LEVEL 1
SAMPLE
GASES
LIQUIDS
SOLIDS
INORGANIC
• GC - SO2, H2S, COS, CO.
CO2. O2. NH3, HCN,
(CN)2
• NOX- CHEMILUMINESCENCE
. IMPINGERS
- SSMS
- WFT CHEMICAL
1
ORGANIC
• GC FOR CrC6
• XAD-2 EXTRACT
-GC FORC7-C12
- IR
- LC/IR/LRMS
00
CD
INORGANIC
• ELEMENTS
- SSMS
- WET CHEMICAL
• LEACHABLE MATERIAL
REGULATED BY EPA-
REAGENT TEST KITS
ORGANIC
EXTRACTS
• GC FOR C7-C12
• IR
• LC/IR/LRMS
INORGANIC
ELEMENTS
- SSMS
- WET CHEMICAL
SELECTED ANIONS
AQUEOUS
- SELECTED
WATER TESTS
ORGANIC
EXTRACT AQUEOUS
SAMPLES WITH
CH2CI2
GC FOR C7-C12
IR
LC/IR/LRMS
Figure 7. Outline of Level 1 analysis.
-------
LEVEL 1
INORGANIC ANALYSIS
GASES
LIQUIDS
CD
O
SSMS
ELEMENTAL
ANALYSIS OF
SORBENT TRAP
GC FOR CO, COj,
S02, 02, N2, H2S,
COS NH), HCN, (CN)
NOX BY
CHEMILUMTNESCENCE
SSMS ELEMENTAL
ANALYSIS
WET CHEMICAL
ANALYSIS
FOR Hg, Sb, As
WET CHEMICAL
ANALYSIS
FOR HR, Sh, As
WATER ANALYSIS
pH, ACIDITY.
ALKALINITY, BOD,
COD, DISSOLVED
OXYGEN,
CONDUCTIVITY,
DISSOLVED AND
SUSPENDED SOLIDS,
SPECIES ANALYSTS
SOLIDS
SSMS ELEMENTAL
ANALYSIS
WET CHEMICAL
ANALYSIS
FOR Hg, Sh, As
LEACHABLE MATERIAL SSMS
ELEMENTAL ANALYSIS
REAGENT ANALYSIS KITS-
SPECIES ANALYSIS
Figure 8. Outline of Level 1 inorganic analysis.
-------
* _J
INFRARED
ANALYSIS
LOW RESOLUTION
MASS SPECTRA
ANALYSIS
Figure 9. Outline of level 1 organic analyses.
91
-------
STANDARD
ADDITION
ORGANIC
EXTRACTION
XRF
BAKI'/X
SPECTROMETRY
GEMUKIUM
FLUORESCENCE
HCA-AA
SELENIUM
LEAD
Figure 10. Analysis of inorganic elements.
92
-------
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ORGANIC ANALYSIS FOR
ENVIRONMENTAL ASSESSMENT
L. D. Johnson
R. G. Merrill
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina
September 1 977
Abstract
A survey analysis approach for organic
materials is presented. The scheme presented
is relatively simple and inexpensive, yet pro-
duces useful information which can be utilized
to decide whether more sophisticated and ex-
pensive methods are justified. A selection of
Level 1 data from environmental samples is
presented.
A brief discussion of Level 2 analysis tech-
niques is also included.
INTRODUCTION
Two of the major responsibilities of EPA's In-
dustrial Environmental Research Laboratory in
North Carolina (IERL/RTP) are control
technology development and environmental
assessment. Due to a growing awareness and
concern over the effect of pollution in our sur-
roundings, the current emphasis is on en-
vironmental assessment.
Worldwide energy shortages have added
momentum to development programs for alter-
nate or modified energy or fuels production. It
is particularly important that these emerging
technologies be evaluated, as they develop, for
their potential environmental insult. By means
of such early investigation, problem processes
may be modified at the most effective and
economical stage, or control technology may
be developed in parallel with production
technology.
Only a few existing industrial processes have
been reasonably well characterized with
respect to their release of a few selected
pollutants. Far fewer, if indeed any, processes
have been adequately studied for a wide range
of potentially harmful materials. For this
reason, control technology needs will remain
undefined until the potential environmental ef-
fects are estimated.
Environmental assessment is a formidable
task, technically difficult, and extremely expen-
sive. In order to help maximize the information
gain of such programs and to minimize the
costs, special approaches have been developed
to sampling and analysis programs for en-
vironmental assessment. This paper discusses
one part of such an approach: organic analysis
employed in Level 1 of an environmental
assessment.
FUNDAMENTALS
Before discussing the organic analysis ap-
proach employed in Level 1 of an environ-
mental assessment, it is appropriate to con-
sider some of the pertinent terminology. To say
that an environmental assessment is a project
involving problem definition with regard to
pollutant source environmental insult is con-
venient, but perhaps an oversimplification. A
longer, but more complete, description is that
an IERL/RTP environmental assessment con-
tains: (1) a systematic evaluation of the
physical, chemical, and biological char-
acteristics of all streams associated with a
process; (2) predictions of the probable effects
of those streams on the environment; (3)
prioritization of those streams relative to their
individual hazard potential; and (4) identifica-
tion of any necessary control technology pro-
grams.
Examination of several strategies for en-
vironmental assessment sampling and analysis
led to the conclusion that a phased approach
was the most cost and information effective.
The phased approach has been discussed in
several recent publications (1, 2, 3, 4). This
strategy makes use of three levels of sampling
and analysis: Level 1 is a survey phase; Level 2
is a directed detailed analysis, based on Level 1
information; and Level 3 involves monitoring of
priority pollutants selected by use of informa-
tion generated during the two previous phases.
Level 1 sampling and sample preparation pro-
cedures are dealt with in several publications
(5, 6, 7, 8). A flow chart of the Level 1 analysis
scheme, shown in Figure 1, contains four major
divisions of analysis: physical, inorganic
chemical, organic chemical, and biological.
Organic analysis will be the primary topic
discussed from this point on.
95
-------
-------
ORGANIC ANALYSIS
OVERVIEW
Current analytical technology makes it possi-
ble to identify and quantify virtually all of the
organic constituents of even the most complex
mixture, given sufficient sample, funds, and
time. Obviously all three will not be available
for every case; hence, adjustments must be
made in the degree of information expected
from the sample. Specific compound identifica-
tion should not, in general, be expected at
costs commensurate with the Level 1
philosophy. Therefore, the scheme presented is
relatively simple and inexpensive, yet produces
information which can be utilized to decide
whether more sophisticated and expensive
methods are justified. The Level 1 organic
analysis produces data in terms of chro-
matographic classes of compounds and
characteristic infrared absorption bands. The
Level 1 organic analysis strategy shown in
Figure 2 shows four analytical operations that
are central to the scheme.
Liquid chromatographic separation (Appen-
dix A. 1) is the heart of the whole approach. It is
an analytical step (in that behavior of a given
class of compounds is predictable) as well as a
separation step (since the fractions may be fur-
ther analyzed much more readily than the
original mixture). The behavior of selected
classes of compounds with respect to the
chromatographic analysis is shown in Figure 3.
Distribution of a few selected compounds is
shown in Figure 4.
The second analysis operation is determina-
tion of total organics content. This operation
allows quantisation of the organics in each of
the chromatographic fractions as well as ali-
quot size selection for optimum column opera-
tion. The original Level 1 scheme (8), as well as
the first revision (5), depended entirely upon
reduction to dryness and weighing for total
organics determination. Recent data show that
many materials in the boiling range below
275°C may be partially lost by that approach
(9). Accordingly, a gas chromatography pro-
cedure for volatile organics has been adopted
as a part of the Level 1 strategy (Appendix
A.2). Total organic content is obtained by addi-
tion of the gravimetric results and the total
chromatographable organics (TCO).
The third analysis operation is infrared ab-
sorption spectrophotometry. This classical
technique is often overlooked in today's mass-
spectrometry-dominated laboratory, but still re-
mains a powerful tool which provides con-
siderable information at moderate cost. Infra-
red spectra of the eight chromatographic frac-
tions may be used to confirm the absence or
presence of particular compound classes or
functional groups as indicated by the
chromatograhic data. It is occasionally possible
to obtain specific compound identification from
the infrared spectra; but as previously men-
tioned, the complexity of most environmental
samples makes this the exception rather than
the rule.
The fourth analytical operation of the Level 1
organic scheme is low resolution mass spec-
trometry (LMRS). This particular tool, sitting
firmly in the middle of the transition zone
between Levels 1 and 2, causes many
philosophical problems concerning its proper
utilization. The original Level 1 scheme did not
contain LRMS (8); but, it was included in the
modified strategy (5) to prevent potential trig-
gering of Level 2 efforts based on large
amounts of suspicious, but innocuous,
organics. LRMS can be a very powerful tool,
especially when combined with the other Level
1 components. In many cases, compound iden-
tification and quantification are possible when
the entire scheme is applied. What, then, are
the philosophical problems?
The first and foremost problem is cost. One
LRMS application including interpretation costs
about $100, not a large sum compared to
overall Level 1 costs. If LRMS is necessary on
only one or two fractions, then costs are
nominal, information gain is considerable, and
cost effectiveness is high. In the worst case,
however, one may be forced to apply LRMS to
all eight fractions and employ both probe and
batch modes of sample introduction. The re-
sultant LRMS cost is $1600 per sample, a
significant increase. The cost impact of such a
per-sample increase may be forcefully il-
lustrated by the following hypothetical exam-
ple.
If three flue gas samples are taken with a
Source Assessment Sampling System (SASS)
at each of 50 plants, the resulting number of
subsamples requiring Level 1 organic analysis
97
-------
CH2CI2 EXTRACT PREPARED
AS USUAL: 100-2000 ml
TOTAL VOLUME
YES
ALIQUOT
FORIR
ALIQUOT
FORLC
CONCENTRATE AS
NECESSARY
(ROTAVAPOR, K-D, ETC.;
TCO + GRAV
SMOOmg/ml
NO
1
CONCENTRATE TO NOT
GREATER THAN 100 mg/ml
BUT NOT LESS THAN 2 ml
ALIQUOT FORLC
SOLVENT EXCHANGE
YES
ImlHEXANEPLUS
SILICA GEL
LC
I I I
1 2 3
EACH FRACTION:
i i rn
TCO + GRAV
IR ON GRAV SAMPLE
LRMS BY BATCH AND PROBE. (OPTIONAL)
Figure 2. Modified level 1 organic analysis procedure.
98
-------
PARAFFINS
AROMATIC
HYDROCARBONS
POLYAROMAT1C
HYDROCARBONS
to
(O
HETEROCYCLIC
SULFUR COMPOUNDS
ESTERS, ALCOHOLS.
KETONES
PHENOLS, AMIDES
CARBOXYL1C ACIDS
SULFONATES
Figure 3. Liquid chromatographic fractions v. class types.
-------
COMPOUND
HEXADECANE
CUMENE
DICHLOROBIPHENYL
ACENAPTHENE
TETRACHLOROETHANE
o-NITROTOLUENE
BENZALOEHYDE
DIHEXYL ETHER
N-METHYL ANILINE
QUINOLINE
DIETHYLPHTHALATE
2-ETHYL HEXANOL
PHENOL
± L
85 15
82
25 69
69
81
2.
17
5
31
19
30
22
18
£ JLJL
70
75 3
77 4
3 94
100
100
99
100
J.
2
0.7
Figure 4. % Distribution in LC fractions (ref. 9).
is 700. A $1600 cost increase on 700
samples amounts to $1.7 million. In fact, since
four of the seven SASS subsamples usually
contain no significant amount of organic
material, the expensive part of the scheme is
seldom reached. The potential worst case cost
must, nonetheless, be seriously considered.
The second strategical problem encountered
when considering LRMS for inclusion in Level 1
is that the technique appears to be an
"overkill" approach to what was originally a
very modest analytical goal. In other words,
one probably doesn't need that much informa-
tion at Level 1 in order to make the necessary
decisions. At present, LRMS is included in
Level 1 as an option to be used on an "as
needed" basis.
It should also be briefly discussed why LRMS
is employed rather than the more powerful high
resolution mass spectrometry (HRMS) or the
more popular gas chromatography/mass spec-
trometry (GCMS). HRMS is roughly 4 times as
expensive as LRMS. The detailed information
and compound specificity available from this
technique are far beyond the original goal of
Level 1, and HRMS is not readily available for
the quantity of samples envisioned. GCMS is
also more expensive than LRMS and it has the
added disadvantage of detecting only
chromatographable materials. Both HRMS and
GCMS are considered excellent Level 2 tech-
niques.
ILLUSTRATIVE LEVEL 1 DATA
Level 1 SASS subsamples will typically in-
volve results from extraction of paniculate,
porous polymer, or condensate. An example of
this type of data for an electric arc furnace par-
ticulate sample is discussed below.
ELECTRIC ARC FURNACE PARTICULATE
Sample Treatment
Particulate (11.500 g) was extracted for 8
hours with 100 ml of methylene chloride in a
Soxhlet extractor. Total chromatographable
organic analysis (TCO) of the crgde extract in-
dicated 1 mg/ml of the C7 - C16 boiling range.
Gravimetric (Grav.) analysis indicated an addi-
100
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TABLE 1
LEVEL 1 LC COLUMN RECOVERIES
Fraction
1
2
3
4
5
6
7
8
Weight, mg
7.2
1.5
2.0
1.9
1.8
3.3
1.4
0.1
tional 13.8 mg of organic material present in
the extract. The initial TCO + Grav. showed
that the sample could be taken to dryness in the
later steps of Level 1 without significant loss of
sample.
Sample Fractionation
The recovered weights of material from the
Level 1 LC column, that resulted from applying
the total extracted sample (evaporated to
dryness), are given in Table 1.
Infrared Analysis
Infrared results from fraction 6 were the
most valuable. Strong or medium bands are
reported in Table 2 with their assignments.
The IR of fraction 1 contained only hydrocar-
bon bands. The spectrum of fraction 3 contain-
ed bands at 2925, 2915, and 2830 crtr1, in-
dicative of aliphatic substitution. Infrared
analysis of fractions 3 through 7 showed that
the organic content of the sample was aromatic
in nature with a variety of functional groups in-
cluding multiple ring structures and oxidation
products such as ketones and acids. No LRMS
was performed on these samples since the
quantity of material in any of the fractions was
less than the threshold amount.
CONCLUSION
The objective in Level 1 organic analysis is to
provide a cost effective screening scheme for
source assessment. The electric arc furnace
particulate example above shows many of the
benefits of this approach. In particular, that all
TABLE 2
INFRARED BAND ASSIGNMENTS (FRACTION 6}
Band, cm
-1
Assignment
3500
1710
1510
1455, 1460, 1380
830, 750
A broad band indicating hydroxyl,
Aromatic or conjugated ketone.
Aromatic carbon stretch.
Carbon/carbon scissor and wag.
Substituted aromatic.
101
-------
fractions from the LC separation after the sec-
ond fraction are aromatic in nature and that the
boiling point range for the sample is greater
than C16 shows that the source potentially
emits polycyclic organic material (POM) in the
toxic and carcinogenic range. The weight and
class distribution in the fraction causes the
source to be of further interest. Level 2 analysis
is indicated for POM by GC/MS or HPLC in com-
bination with LRMS or HRMS.
REFERENCES
1. J. A. Dorsey, L. D. Johnson, R. M. Stat-
nick, and C. H. Lochmuller, "Environ-
mental Assessment Sampling and
Analysis: Phased Approach and Techni-
ques for Level 1", EPA-600/2-77-1 1 5
(NTIS No. PB-268 563), June 1977.
2. R. M. Statnick and L. D. Johnson,
"Measurements Program for Environ-
mental Assessment", Symposium Pro-
ceedings: Environmental Aspects of Fuel
Conversion Technology, II (December
1975, Hollywood, Florida), EPA-600/
2-76-149 (NTIS No. PB-257 182), June
1976.
3. J. W. Hamersma and S. L. Reynolds,
"Field Test Sampling/Analytical
Strategies and Implementation Cost
Estimates: Coal Gasification and Flue Gas
Desulfurization", EPA-600/2-76-093b
(NTIS No. PB-254 1 66), April 1 976.
J. Vlahakis and H. Abelson, "Environ-
mental Assessment Sampling and
Analytical Strategy Program", EPA-
600/2-76-093a (NTIS No. PB-261 259),
May 1976.
J. W. Hamersma, S. L. Reynolds, and R. F.
Maddalone, "IERL-RTP Procedures
Manual: Level 1 Environmental
Assessment", EPA-600/2-76-1 60a
(NTIS No. PB-257 850), June 1976.
D. B. Harris, W. B. Kuykendal, and L. D.
Johnson, "Development of a Source
Assessment Sampling System",
presented at Fourth National Conference
on Energy and the Environment, Cincin-
nati, Ohio, October 1976.
C. H. Lochmuller, "Analytical Techniques
for Sample Characterization in En-
vironmental Assessment Programs",
Symposium Proceedings Environmental
Aspects of Fuel Conversion Technology,
II, (December 1975, Hollywood, Florida),
EPA-600/2-76-149 (NTIS No. PB-257
182), June 1976.
P. W. Jones, A. P. Graffeo, R. Detrick, P.
A. Clarke, and R. J. Jakobsen, "Technical
Manual for Analysis of Organic Materials
in Process Streams", EPA-600/2-76-072
(NTIS No. PB-259 299), March 1976.
Arthur D. Little, Inc., Monthly Progress
Report on EPA Contract 68-02-2150,
April 1977. To be published in a
forthcoming EPA report.
102
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APPENDIX A
SELECTED LEVEL 1
PROCEDURES
A. 1 Procedure for Liquid Chroma tograph y Col-
umn Preparation
Column: 200 mm x 10.5 mm ID,
glass with Teflon stopcock.
Adsorbent: Davison Silica Gel, 60-200
mesh, Grade 950, (Fisher
Scientific Company). This
adsorbent is activated at
110°C for 2 hours just prior
to use. Cool in a desiccator.
A. 1.1 Dry-pack the chromatographic col-
umn, plugged at one end with glass wool, with
6.0 g of freshly activated silica gel. A portion of
properly activated silica gel weighing 6.0 ±
0.2 g occupies 8 ml in a 10 ml graduated
cylinder. Vibrate the column for 1 minute to
compact the gel bed. Pour pentane into the sol-
vent reservoir positioned above the column and
let the pentane flow into the silica gel bed until
the column is homogeneous throughout and
free of any cracks and trapped air bubbles*.
The total height of the silica bed in this packed
column is 10 cm. The solvent void volume of
the column is 2 to 4 ml. When the column is ful-
ly prepared, allow the pentane level in the col-
umn to drop to the top of the silica bed so that
the sample can be loaded for subsequent
chromatographic elution.
Table A1 shows the sequence of the
chromatographic elution. In order to ensure
adequate resolution and producibility, maintain
the column elution rate at 1 ml per minute.
A.1.2 Loading Sample on the Column
Place 1 5 ml of CH2CI2 extract containing
15 - 100 mg (preferably 100 mg) of solute
(TCO + GRAV) in a graduated centrifuge tube
or K-D receiver. Add 200 mg of silica gel
prepared as for the LC column. Evaporate if
necessary to reduce volume to 1 ml. Add 1 ml
of hexane and mix by gentle agitation. Again
reduce the volume to 1 ml by evaporation. Add
1 ml more of hexane and mix. Again reduce the
* A water jacketed column run between 1 8 and 22°C will
help avoid this problem.
volume to 1 ml. Transfer the hexane and silica
gel to the top of the previously prepared LC col-
umn.
Run the column as directed, rinsing the
graduated receiver with fresh solvent as they
are introduced in the elution sequence.
A. 1.3 Chromatographic Separation into
Eight Fractions
The volume of solvents shown in Table A1
represents the solvent volume collected for
that fraction. If the volume of solvent collected
is less than the volume actually added due to
evaporation, add additional solvent as
necessary. In all cases, however, the solvent
level in the column should be at the top of the
gel bed (i.e., the sample-containing zone) at the
end of the collection of any sample fraction.
After the first fraction is collected, rinse the
original sample, weighing the funnel with a few
ml of the fraction 2 solvent (20% methylene
chloride/pentane) and carefully transfer this
rinsing into the column. Repeat as necessary
for fractions 3 and 4.
A.2 Total Chromatographable Organic
Analysis (TCO)
Analyze a 11>\ aliquot of solution by GC using
a flame ionization detector. A 6 ft x 1 /8 in. O.D.
column of 10% OV-101 on 100/120 mesh
Supelcoport has been used successfully for this
analysis. Other silicon phases (OV-1, etc.) may
work as well, but a 10% loading is recom-
mended. The GC should be operated isother-
mally at about 30° C — or room temperature
— for 5 minutes after sample injection and then
programmed at approximately 20°C per
minute to 250°C and held at 250°C as long as
necessary for complete elution of sample.
Integrator should be set to begin integration
at a time intermediate between the hexane (C6)
and heptane (C7) peak maxima (i.e., C6 5) and
terminate at the peak maxima of the hep-
tadecane (C17) peak, as determined from
calibration standards. In this manner the in-
tegrated area will cover material in the boiling
range of C7 - C16.
Calibration should utilize a mixture contain-
ing a homologous series of hydrocarbons from
C7 to C16. Standards should be prepared to
cover the concentration range to be studied.
103
-------
TABLE A1
LIQUID CHROMATOGRAPHY ELUTION SEQUENCE
No. Volume
Fraction Solvent Composition Collected, ml
1 Pentane 25
2 20% Methylene chloride in pentane 10
3 50% Methylene chloride in pentane 10
4 Methylene chloride 10
5 5% Methanol in methylene chloride 10
6 20% Methanol in methylene chloride 10
7 50% Methanol in methylene chloride 10
8 Cone. HC1/Methanol/Methylene
chloride (5 + 70 + 30) 10
104
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ENVIRONMENTAL ASPECTS
OF FOSSIL ENERGY
DEMONSTRATION PLANTS
James C. Johnson
Energy Research and Development
Administration
Washington, DC
Abstract
This paper described the full range of en-
vironmental activities which are undertaken in
con/unction with Fossil Energy's demonstra-
tion plant program. These activities address
key environmental problems generic to any
Fossil Energy demonstration plant: resource
limitations (e.g., water availability), socio-
economic impacts (e.g., housing shortages);
new and potentially harmful pollutants;
existing environmental standards; and future
environmental standards.
In order to provide a background for the
discussion of specific environmental activities,
the paper first described the overall Fossil
Energy Demonstration Program, including pro-
gram objectives, ERDA 's role, industry's role,
and funding. The paper then defined the three
developmental phases of demonstration plants
(Phase I: preliminary and detailed plant
engineering; Phase II: plant construction; and
Phase III: plant operation, testing, and evalua-
tion), since specific environmental activities
occur at each phase.
During Phase I, environmental activities in-
clude the preparation of site specific en-
vironmental impact assessments (Elft's) and/or
environmental impact statements (EIS's),
development of environmental control
strategies, design of environmental monitoring
and control systems, compilation and review of
public comments, and securing of necessary
permits. During the design phase data describ-
ing ambient environmental conditions at pro-
spective sites also are collected.
During Phase II, environmental monitoring
and control systems are constructed for inclu-
sion in the demonstration plant. During con-
struction ambient air and water quality data are
collected in order to assess the impacts of con-
struction on the local environment. Worker
health and safety surveillance programs are
established, and potentially hazardous plant
areas are pinpointed.
A comprehensive program to monitor air
emissions, water effluents, and worker health
and safety is implemented during Phase III. A
comparison of air and water monitoring data
with background ambient data collected during
Phase I will allow changes in the local environ-
ment to be assessed. Data also are collected to
ensure compliance with environmental stand-
ards, and tests are carried out which will lead to
improvements in environmental control
technology.
105
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PROTECTING WORKER SAFETY
AND HEALTH IN
COAL CONVERSION
Murray L. Cohen
National Institute for
Occupational Safety and Health
Rockville, Maryland
Abstract
The National Institute for Occupational Safe-
ty and Health (NIOSH) is responsible for
developing recommended standards for oc-
cupational exposures to chemical and physical
hazards, including those which arise in newly
developing technology. An assessment of the
potential deleterious impact on the occupa-
tional environment by coal conversion
technologies is in progress, including the iden-
tification of possible hazardous exposures to
workers and the development of strategies for
control of these exposures.
NIOSH has developed occupational safety
and health guidelines for coal gasification pilot
plants and is preparing recommended stan-
dards for coal conversion processes that will
likely be commercialized in the U.S. by
1985. The methodology includes a world-wide
literature survey, visits to operational facilities,
and evaluation of the occupational safety and
health practices and records in coal conversion
plants.
A unique process orientation forms the basis
of the occupational safety and health recom-
mendations, with emphasis on real-time
monitoring of indicator substances to identify
problem areas and fugitive emissions.
Engineering controls, safe work practices, in-
dustrial and personal hygiene, medical ex-
aminations and recordkeeping, and personal
protective equipment complete the recom-
mended standard.
The need to simultaneously develop control
technology and advance process engineering
for coal conversion technologies is evident.
Potential occupational health and safety
problems can be prevented by proper attention
to these considerations in the design of synfuel
plants.
PROTECTING WORKER SAFETY
AND HEALTH IN COAL CONVERSION
The National Institute for Occupational Safe-
ty and Health (NIOSH) is responsible for
developing recommended standards for oc-
cupational exposures to chemical and physical
hazards, including those which arise in newly
developing technology. Since April 1976, the
Institute has been involved in a project to iden-
tify potential hazardous exposures to workers
in coal gasification plants. Strategies for con-
trol of these exposures are also being
developed.
The project has been divided into two parts.
Recommended Health and Safety Guidelines
for Coal Gasification Pilot Plants have been
developed, and will be transmitted to the
Energy Research and Development Administra-
tion (ERDA) later this year for consideration for
implementation in the ERDA research and
development facilities. In August, work began
on the Criteria for Recommended Standards
for Occupational Exposures in Coal Gasification
Plants. This NIOSH criteria document will ad-
dress coal gasification processes that will likely
be commercialized in the United States by
1985. In May 1978, the recommended stan-
dards will be transmitted to the Department of
Labor Occupational Safety and Health Ad-
ministration for consideration for rulemaking.
It is important to note that the development
of criteria documents includes substantial
review at five different stages of drafting.
Reviewers include NIOSH staff and con-
sultants, other federal and state agencies, and
representatives of industry, labor unions, and
academia.
The protocol followed in the development of
each of these documents includes a world-wide
literature survey and review, visits to opera-
tional facilities, and evaluation of the occupa-
tional safety and health practices and records in
coal gasification plants. The recommendations
for control of hazardous exposures have in all
cases been based upon the operational ex-
periences of existing facilities. Similar data
from industries with analogous exposures,
such as coke ovens and coal liquefaction
106
-------
plants, have also been considered in the iden-
tification of potential hazards to workers.
A process oriented approach is being used in
the development of these recommended stan-
dards, as opposed to the more traditional single
hazard approach. The processes are divided in-
to operational units characterized by certain
hazards. Recommendations for control of ex-
posures are then designed in unit packages that
are specific for each process unit. The recom-
mendations emphasize real-time monitoring of
indicator substances to identify problem areas
and fugitive emissions. Engineering controls,
safe work practices, industrial and personal
hygiene, medical examinations and recordkeep-
ing, and personal protective equipment com-
plete the recommendard standard.
PILOT PLANT DOCUMENT
The pilot plant worker may be exposed to
toxicants by inhalation of gases or airborne par-
ticles, skin deposition of airborne material, con-
tact with contaminated surfaces, and acciden-
tal ingestion. In maintenance operations, liquid
and solid residues may be encountered that
would not ordinarily constitute normal opera-
tional hazards (NIOSH 1977).
The range of toxicants and possible health ef-
fects is extremely wide, from simple chemicals
like carbon monoxide to complex mixtures of
organic carcinogens. This complexity is further
complicated by the special problems
associated with carcinogens: long latent
period, doubt about "safe" levels, and un-
predictable multiagent interactions (NIOSH
1977).
These conditions cannot be met by protec-
tive measures, monitoring procedures, and
medical tests that are simply the sum total of
controls for each individual toxicant. The com-
plexity of the potential hazards calls for in-
novative control strategies (NIOSH 1977).
Few data are available concerning the
workplace environment and other occupational
health factors in coal gasification plants. The
somewhat better documented health hazards
of coke ovens, coal liquefaction, and similar
plants are relevant, but not fully acceptable as
models for coal gasification (NIOSH 1977).
The structure of the document includes a
detailed description of a representative
process, identification of toxicants and poten-
tially hazardous operations, a review of health
effects associated with the toxicants and
diseases observed in association with coal
processing, recommendations for worker pro-
tection, monitoring procedures, safety con-
siderations, and recommendations for research
to meet identified gaps in knowledge and
technology for worker health and safety pro-
tection.
The coal gasification processes used as
references are seen in Table 1. Synthane is the
representative process for development of con-
trol strategies, and significant differences or
unique characteristics of the other processes
are noted in the document.
The unit processes for which specific control
strategy packages have been developed are
coal preparation, pretreatment and gasifica-
tion, quench and scrubbing, CO shift conver-
sion, acid gas scrubbing, methanation, sulfur
recovery and waste water treatment, and the
handling of condensable hydrocarbons, ash,
and char.
Health effects data that serve as the basis for
the recommendations are reviewed for the
following toxicants:
Aliphatic hydrocarbons
Ammonia
Aromatic Amines
Aromatic hydrocarbons
Arsine
Carbon disulfide
Carbon monoxide
Carbonyl sulfide
Heterocyclic aromatics
Hydrogen chloride
Hydrogen cyanide
Hydrogen sulfide
Mineral dust and ash
Nickel carbonyl
Nitrogen oxides
Nitrosamines
Phenols
Polycyclic aromatic hydrocarbons
Sulfur oxides
Trace elements
Other types of data essential for develop-
107
-------
TABLE 1
COAL GASIFICATION SYSTEMS USED S REFERENCES
Process
HYGAS. Steam-Oxygen
C02 Acceptor
MERC Unit
Synthane
§Bi-Gas
Agglomerating Burner
Steam-Iron
Pressure, psig
1000s
1000-1500*
1503
150-300C
200*
Atmos-300c
10003
600-1 000C
Upper stage (entrained flow)
1000-1500
Lower stage (vortex flow)
1000-15000
Atmos-100
1000-1200
Temperature, °F
1300-1900
IBOO-ISSO*'
Combustion zone
2400-2500
Gas off take
1000-1200
1500*
1400-1 800C
1400-1700
2800
1800
Hydrogasifier
1300-1700
Producer
2000-3000
Product
Gas Quality Liquids
Medium or high Light oil
and tar
Medium or high None
Low, medium, or Light oil
high and tar
Medium or high6 Light oil
and tar
Medium or high6 (Doubtful)
Medium or high (Questionable)
Hydrogen None
Coal Feed
Lignite
Sub-bituminous
Bituminous6
Lignite
Sub-bituminous
Lignite
Sub-bituminous
Bituminous
Lignite
Sub-bituminous
Bituminous6
Lignite
Sub-bituminous
Bituminous
Lignite
Sub-bituminous
Bituminous*
Char
Status
(Dec. 1976)
Operational
Operational
Operational
Start-up
Start-un
Start-up
Under
construction
Type
Pilot
Pilot
Pilot
Pilot
Pilot
PDU
Pilot
'Normal operating pressure.
*Must prelreat agglomerating bituminous coal.
cOptimal range.
dCoat bed 1500°F, regenerator 1840°F.
'Can be convened to low-Btu gas production.
Source: NIOSH Recommended Health and Safety Guidelines for Coal Gasification Pilot Plants.
-------
JOB HAZARD
BREAKDOWN
DESCRIPTION
COMPONENT
JHB NU M H E '
SUII.DING
REVIEWED BY
INDUSTRIAL. SAFETY
PREPARED BY
DATE
INITIALS
REVIEW DATES
SAFETY EQUIPMENT REQUIRED | TOOt-S a EQUIPMENT REQUI»EO
JOB PREPARATION
HAZARDOUS MATERIALS
RELATED REQUIREMENTS
KTION WORK PROCEDURE YES|"~| NO I I
HUCI.CAR SAFETY SPEC.
JOS STEP
SAFETY RUL.ES ANO SAFE PRACTICES
PAGE I
4-1000-12.9 (1-70)
Figure 1. Job safety analysis sample form.
109
-------
ment of recommendations on a unit process
basis include health effects studies for the coal
liquefaction and coke oven industries, and
engineering data that serve to predict potential
problem areas in coal gasification plants.
Stream analyses, material balances, and
process flow sheets from the existing pilot
plants were extremely useful in this regard.
Recommendations for worker protection are
prescribed in the document, and include safe
work practices, engineering controls, protec-
tive equipment, workplace monitoring, medical
examinations, recordkeeping, health education
program, personal hygiene, and regulated
areas.
Figure 1 is a sample job safety analysis form,
and represents a safe work practice that should
be required for all routine operations.
Maintenance tasks should also include safe
work permits signed in advance by both the
shift supervisor and safety officer. Figure 2
shows a sample pump and shutoff valve ar-
rangement that constitutes a simple but highly
effective engineering control. Medical monitor-
ing should include a full preemployment
physical, regular checkups, long-term followup
of high risk individuals, and full recordkeeping
for all workers in the plant. An effective health
education program must both teach the
employees the hazards associated with their
work, and cor t;nually remind them of the im-
portance of the health and safety protection
program.
Figure 3 is a sample layout for clean and dirty
locker rooms that can assure good personal
hygiene. The important points are that no con-
taminated work clothing or gear can be mixed
with clean street clothing, or be taken from the
plant facility. Figure 4 shows signs that can be
used to enforce the regulated areas recommen-
dations.
Effective workplace monitoring can be ac-
complished by continued monitoring of in-
dicator substances such as CO or H2S. This
concept allows for real-time detection of leaks,
indicates the time when measurements of
specific substances that cannot be analyzed in
real-time should be made, and easily "flags"
periods when precautions for exposure to
substances that are difficult or impossible to
analyze at prevailing concentrations should be
taken.
The characteristics of a good indicator
substance are as follows: easily monitored in
real-time, suitable for analysis where resources
are limited, presence in ambient air at low or
consistent concentrations, free from interfering
substances in process stream or ambient air,
and a regulated agent that must be measured
anyway (NIOSH 1977).
These characteristics are the criteria for
choosing a specific indicator substance in a
specific process or work area. "Tailor-made"
workplace monitoring programs can then be
developed according to process conditions in a
specific coal gasification plant.
COAL GASIFICATION
CRITERIA DOCUMENT
This program is just getting underway, with
an anticipated publication date of June 1978.
lit
<=
Figure 2. Pump and shutoff valve.
110
-------
TO
a
uj
s
-------
The criteria document will focus on the follow-
ing coal gasification processes that will likely
be commercialized in the United States by
1 985: high-BTU (LURGI), low-BTU (bituminous
or lower grade coals), and low or medium-BTU
(anthracite or non-tar producing). Hazard con-
trol recommendations will be developed from a
unit process perspective for each of these
classes of operation and will be similar to the
types of recommendations developed for the
pilot plants. Since few commercial coal
gasification facilities are currently operational
in the U.S., the recommendations will em-
phasize engineering controls and design criteria
for built-in margins of safety.
It is hoped that these NIOSH documents will
serve as handbooks for use in developing effec-
tive comprehensive safety and health programs
in the building of the coal gasification industry.
The philosophy of the program is based on the
principle that before a new technology is in-
troduced or an existing technology is modified,
its occupational health and safety impact
should be evaluated. Historically, advances in
technology have been accompanied by new
hazards which are often apparent only many
years later, after workers become sick or die.
The styrene-butadiene rubber industry is an ex-
ample. In the 1 940's, with 90 percent of the
natural rubber supply cut off, the Federal
government financed the building of fifteen
styrene-butadiene rubber plants (Morton,
1973). Three decades later, we are finding that
styrene-butadiene rubber employees have a
six-fold risk, as compared with other rubber
workers, of dying of cancer of the lymphatic
and hemopoietic systems (McMichael et al.
1976). If occupational health and safety are
properly considered in developing coal conver-
sion technologies, then these plants, hopefully,
should not contribute to serious health
problems twenty to thirty years from now for
today's workers.
REFERENCES
1. M. Morton (ed), Rubber Technology -
Second Edition. W. M. Saltman, Styrene-
Butadiene Rubber, Ch. 7: 178-198. Van
Nostrand Rheinhold Co., New York,
1973.
2. A. J. McMichael et al., Mortality Among
Rubber Workers: Relationship to Specific
Jobs. JOM, 18:3, 178-185. March
1976.
3. National Institute for Occupational Safety
and Health. Recommended Health and
Safety Guidelines for Coal Gasification
Pilot Plants. NIOSH, Washington, D.C.
1977. (In preparation)
112
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ENVIRONMENTAL RESEARCH
RELATED TO FOSSIL
FUEL CONVERSION
by
Gerald J. Rausa
Environmental Scientist
Energy Coordination Staff
Office of Energy, Minerals, and Industry
U.S. Environmental Protection Agency
Washington, D.C. 20460
Abstract
The taxonomy of environmental research
developed by the CEQ-OMB Interagency Work-
ing Group on Health and Environmental Effects
of Energy Use is used to convey the ongoing
environmental research related to conversion
of solid fossil fuels to liquids and/or gases. The
inventories of activities in the interagency
(pass-thru) program and in the base programs
of the contributing agencies is discussed.
Research for all modules of the fuel cycle is ad-
dressed. As a consequence, some research
which is generally applicable to all fossil fuel
cycles is included in the discussion.
INTRODUCTION
Some difficulty is encountered in the attempt
to categorize the environmental research which
is solely applicable to fossil fuel conversion,
since some aspects of environmental research
are related in common to a number of in-
dustries, including the energy industry and its
associated technologies. In particular, the
various fossil fuel conversion cycles have
problems in common with other fuel cycles as
well as having technology-specific problems. In
order to convey the scope of environmental
research related to fuel conversion (liquefaction
or gasification), it is appropriate to discuss the
generally applicable environmental research as
well as that which is process-specific.
It is debatable whether or not energy related
environmental research can be partitioned into
mutually exclusive categories that are accept-
able to all interested parties. For example, one
such grouping of tasks could be according to
environmental agents, i.e., physical, chemical,
and biological stressors. Another possibility
could be a sorting according to the environmen-
tal media into which the agents are ini illy in-
troduced, i.e., air, water, and land A th,, ' son
could be according to the targets of concern,
i.e., human health, environmental quality,
ecological systems, social systems or
economic systems.
In this presentation, the taxonomies
developed by the two OMB-CEQ working
groups'1'21 in the planning of energy related ?n-
viromental research will be used to categorize
the research activity to be discussed. The sub
ject working groups were Assembled to re
spond to an inquiry as to whether or not energv
related environmental researcl. was being
undertaken on a schedule compatible wit.i the
development of energy technology, snd to in-
dicate the additional environrranta. ret. *arch
needed. The categories utilized by thn two
working groups are displayed in Figure . Tue
"Gage Committee" addressed the engin ering
aspects of control systems while the
"King/Muir Committee" address^ i the en-
vironmental processes and effects aspects of
the energy systems. The categ ries were
developed by the interagency wot king groups
to provide a planing structure that could ')e us-
ed by each agency in order to permit he in-
dividual components of activity to L- ag-
gregated within the overall interagency (pass-
thru) program, while still permitting each agen-
cy to fit the "pass-thru" component within its
own base program structure. In essence, the in-
teragency program is supplemental to the base
programs of energy related environmental
research of the individual agencies.
The interagency planning structure is
depicted in Figure 2. For each major fuel cycle,
the additional research needs for the working
groups were listed for each module of the cy-
cle. Common problems and pertinent research
requirements were then aggregated and
priorities were established according to the
following major processes and effects
categories:
1. Pollutant Characterization, Measure-
ment and Monitoring (CM&M)
The objective of this research is to provide
113
-------
ENERGY/ENVIRONMENT RESEARCH AND DEVELOPMENT PROGRAM
GAGE REPORT
ENVIRONMENTAL CONTROL TECHNOLOGY
ENERGY RESOURCE EXTRACTION
PHYSICAL AND CHEMICAL COAL CLEANING
FLUE GAS CLEANING
DIRECT COMBUSTION
SYNTHETIC FUELS
NUCLEAR
THERMAL
IMPROVED EFFICIENCY
ADVANCED SYSTEMS
KING^UIR REPORT
HEALTH AND ENVIRONMENTAL EFFECTS
POLLUTANT CHARACTERIZATION,
MEASUREMENT AND MONITORING
ENVIRONMENTAL TRANSPORT PROCESSES
ECOLOGICAL EFFECTS
HEALTH EFFECTS
INTEGRATED ASSESSMENT
Figure 1. OMB-CEQ working groups on energy-related environmental research.
-------
«•'•
MULTIFUEL AND/OR NON-FUEL SPECIFIC
CONSERVATION
NUCLEAR
OIL SHALE
I 2 | OIL AND GAS
1 j COAL
FUNCTIONAL
AREAS:
POLLUTANT
IDENTIFICATION
TRANSPORT
AND FATE
HEALTH
EFFECTS
ECOLOGICAL
EFFECTS
INTEGRATED
TECHNOLOGY
ASSESSMENT
CONTROL
TECHNOLOGY
ENERGY CYCLE COMPONENT:
EXTRACTION
PROCESSING
CONVERSION
UTILIZATION
^^^^•B
Figure 2. Interagency planning structure.
-------
reliable and accurate measures of the quantities
and characteristics of released pollutants,
transformed products and indices of en-
vironmental impacts. The major subcategories
of research include instrumentation develop-
ment, source characterization, ambient
monitoring and quality assurance.
2. Environmental Transport
Processes (ETP)
The objective of research in this category
(also occasionally titled Pollutant Transport,
Transformation and Fate - TT&F) is to provide
reliable estimates of the spatial and temporal
relationships between emissions and ambient
environmental quality which represents the ex-
posures to the targets of concern. The major
categories of research include atmospheric
pathways, aquatic pathways, terrestrial
pathways, and biological pathways (Figure 3).
3. Ecological Effects (E E)
The objective of this research is to determine
the acute and chronic impacts to ecosystems
and the components thereof - specifically the
nature and extent of response to various stimuli
associated with energy production. The com-
ponents of concern include the habitats,
populations, and processes in the atmospheric,
aquatic, and terrestrial ecosystems.
4. Health Effects (HE)
The objective of this research is to provide
reliable qualitative and quantitative estimates
of effects on human health due to energy
related agents - for long term, low level ex-
posure, for all modules of energy production
and use, and for susceptible occupational and
general population groups. The major sub-
categories of research include:
1. The development of more rapid in-
dicators for dose and biological
damage;
2. The identification of hazardous agents
associated with energy systems;
3. The development of understanding of
biological mechanisms of metabolism
and fate;
4. The development of understanding of
mechanisms of damage, repair, and
recovery in biological systems from
energy related agents;
5. The development of estimates of risk to
human health evaluated through
human health studies and animal tox-
icological studies, and by improvement
of techniques for extrapolation of data
from animal to man and from high
levels of exposure to low levels of ex-
posure.
Figure 4 indicates the relationships amongst
these areas of research.
5. Integrated Assessment (IA)
The objective of this research is to provide
the methods for, and to undertake comprehen-
sive evaluation of the impact of energy produc-
tion and use on the total "human environment"
from local, regional, and/or national perspec-
tive. To this end the subcategories of activity
include:
1. integration of information;
social and welfare effects analysis;
cost/risk/benefit evaluation;
analysis of alternative methods of im-
Tgntation of strategies; and
siting analysis.
2.
3.
4.
5.
ENERGY/ENVIRONMENT
PROGRAM EMPHASIS
Before elaborating upon the research ap-
plicable to fuel conversion, it is appropriate to
convey some perspective regarding the
magnitude of the effort, and the emphasis be-
ing undertaken for all federally supported,
energy related environmental research which is
listed in two available data files.13'41 The data
bases used for this perspective include the EPA
coordinated interagency program data file and
the ERDA FY-76 inventory of energy related
environmental research. The ERDA inventory
may not have captured all of the subject
research tasks because of the lack of a precise
definition of the phrase "energy related en-
vironmental research," and the subsequent in-
terpretation of that phrase by the respondents.
In the EPA coordinated interagency en-
vironmental processes and effects program,
the relative emphasis has remained reasonably
116
-------
r
i
i
i
SOLID
WASTE
TERRESTRIAL
ECOSYSTEM
FOOD
FACILITY
LIQUID
WASTE
~L~
AQUATIC
ECOSYSTEM
RECREATIONAL
WATER
DRINKING
WATER
MAN
GASEOUS
WASTE
ATMOSPHERIC
ECOSYSTEM
AIR
Figure 3. Environmental pathways model.
-------
oo
HUMAN RISK
ASSESSMENT
MECHANISM
STUDiES
i SfiLsMS $Jt tfHais
SCREENING
STUDIES
DEVELOPMENT OF
DOSE & DAMAGE
INDICATORS
Figure 4. . Relationships amongst
Jroalth research subcategories.
-------
stable for FY-75, FY-76, and FY-77 (Figure 5),
with the major emphasis, approximately 32
percent, upon health effects research. A com-
parable evaluation for the total energy related
environmental research program (base pro-
grams and interagency pass-thru program),
which was obtained from the ERDA FY-76 in-
ventory, is displayed in Figure 6. Comparison
to the pass-thru program indicates that the sup-
plemental interagency effort increased the
relative emphasis on measurement and
monitoring and on ecological effects research.
Disaggregation of the relative emphasis
(FY-76) of the interagency program, according
to components of the fuel cycles for all energy
systems, indicates a relatively uniform em-
phasis for extraction, processing, and utiliza-
tion (Figure 7). For the base programs the em-
phasis according to the same modules is 23
percent, 15 percent, and 62 percent, respec-
tively. The emphasis on utilization is related to
the research to resolve the nuclear waste
management problem.
The distribution of effort for all energy
related environmental research, categorized ac-
cording to energy technology, was displayed in
the ERDA inventory and is reproduced in Figure
8. As expected, the major efforts are for
nuclear and fossil systems with an additional
component applicable to several fuel cycles. A
similar analysis for the supplementary pass-
thru program indicates that most of that par-
ticular funding has been allocated to research
applicable to fossil fuel technologies.
A more comprehensive breakdown of the
emphasis in environmental research applicable
to fossil fuel technology for both the interagen-
cy pass-thru program and for the base pro-
grams is presented in Figure 9. The data in-
dicate that, while approximately 46 percent of
the base funding for processes and effects proj-
ects are related to fossil fuel technology, ap-
proximately 92 percent of the pass-thru pro-
gram was applicable thereto, thus making 52
percent of the total FY-76 funding reported ap-
plicable to fossil fuel technology. The data in-
dicate that the major emphasis and the largest
number of projects being undertaken address
health effects issues. On the other hand, the
largest average cost per task is for ecological
effects research, while the lowest average cost
per task is for health effects research.
ENVIRONMENTAL RESEARCH FOR
ADVANCED FOSSIL FUEL CYCLES
As suggested previously, the advanced fossil
fuel cycles will require resolution of some prob-
lems in common with the conventional fossil
fuel cycles. The problems in common are those
primarily associated with the extraction and/or
utilization module of the full cycle. Examples of
such common problems include the following:
1. Impacts upon water quality due to mine
drainage or leaching from disposal of
solid waste, and subsequent impact
upon aquatic ecosystems;
2. Impacts upon water supply associated
with aquifier disruption (mining),
revegetation requirements or slurry
transport;
3. Impacts upon air quality and
weather/climate modification (local and
regional) from surface mining and com-
bustion;
4. Impacts upon health related to coal
dust and waste products of combus-
tion (SOX, NOX, hydrocarbons, par-
ticulates, trace metals, organo-
metallics), and their environmentally
transformed products;
5. The need to develop measurement
tools and techniques and obtain the
baseline information for likely sites; and
6. Comparative evaluation of alternative
futures for likely sites and the address-
ing of "boom town" problems.
Specific problems within each of the
categories are as follows:
Characterization Measurement and Monitor-
ing the process specific concerns associated
with advanced fossil fuels systems stems from
the spectrum of agents anticipated to be
associated with the variety of proposed proc-
esses and products. Of major concern is the
variety of organic agents in the products and
waste streams. An example of a variety can be
seen in the chromatogram of a coal liquefaction
product, made by M. Guerin of Oak Ridge Na-
tional Laboratory,I5) is displayed in Figure 10. II-
119
-------
35-
HE
30-
EE
HE
EE
EE
HE
25-
20-
CM&M
CM&M
CM&M
ro
o
15-
10-
ETP
IA
ETP
IA
ETP
IA
5-
1975 ($53M)
1976 ($44.2M)
1977 f$40M)
Figure 5. Interagency (pass-thru) energy/environment processes and effects program-funding by major categories
(FY-75/76/77).
-------
$M
CM&M
ETP
EE
HE
IA
5 15 25 35 45 55 65 75 85 95 105
10 20 30 40 50 60 70 80 90 100
PROGRAM TOTALS BASE: $236.9M IAP:40.2M TOTAL: 277.1M
Figure 6. Total FY-76 federal funding - energy for related environment and safety biomedical and environmental subcategory.
-------
40
35
30
25
20
15
10
5
EXTRACTION
32.4%
CM&
ETP
HE
IA
PROCESSING
31.4%
'CM& ™
MJTP
EE Hi
lA
UTILIZATION
36.2%
CM&
HE
IA
to
40
35
30
25
20
15
10
5
CHARACTERIZATION
MEASUREMENTS
MONITORING
20.2%
EXT
UTIL
ROC
ENVIRONMENTAL
TRANSPORT
PROCESSES
11.8%
EXT
PROC
UTIL
ECOLOGICAL
EFFECTS
28.4%
EXT^UTIL
HEALTH
EFFECTS
32.0%
PROC
UTIL
EXT
INTEGRATED
ASSESSMENT
7.6%
Figure 7. FY-76 interagency (pass-thru) energy/environment program by fuel cycle module.
-------
OTHER TECHNOLOGIES
3.4%
33.5%
10
CO
5.8%
fCONSERVATION
I SOLAR
\ GEOTHERMAL
(^HYDROELECTRIC
GENERAL
SCIENCE
13.4%
MULTI-
TECHNOLOGY
18.4%
OIL SHALE
FUSION
9*
25.5%
Figure 8. FY-76 base & pass-thru funding for energy/environment program - according to technology.
-------
CHARACTERIZATION
MEASUREMENT & MONITORING
ENVIRONMENTAL TRANSPORT
PROCESSES
ENVIRONMENTAL EFFECTS
HEALTH EFFECTS
INTEGRATED ASSESSMENT
FOSSIL FUEL TOTAL
PROGRAM TOTAL
BASE
#OF
PROJECTS
166
289
236
594
233
$M
17.4
22.8
40
29.6
17.3
106.7
236.9
%
7.3
9.6
8.2
12.4
7.3
45.8
100
INTERAGENCY
PROGRAM (IAP)
#
129
16
52
148
14
$M
7.5
4.6
10.8
11.4
2.9
36.9
40.2
%
18.6
11.4
27.1
27.7
7.3
92.0
100
TOTAL
(ERDA INVENTORY)
4
295
305
288
742
247
$M
24.9
27.4
30.4
40.7
20.2
143.6
277.1
%
9.0
9.9
11.0
14.7
7.3
51.9
100
Figure 9. FY-76 federal base & pass-thru program - fossil fuel emphasis for each environmental research category.
-------
to
U1
I I
W CONDENSED CIGARETTE SMOKE
(W COAL LIQUEFACTION PRODUCT
(c) PAH STANDARD «
44
TIME | (hr)
Figure 10. Gas chromatographic profiles of polynuclear aromatic hydrocarbon isolates.
-------
lustrations of the various organic molecules in a
chromatogram of condensed cigarette smoke
and a polycyclic aromatic hydrocarbon stand-
ard are also displayed for purposes of com-
parison. Several attempts'671 have been made
to categorize the agents in the waste steams
and products. Gehrs, et al.,161 have suggested
that five groups may be sufficient to categorize
the organics associated with aqueous wastes
as follows:
1. Phenols,
2. Arylamines,
3. Alliphatic Hydrocarbons,
4. Mono and Polycyclic Hydrocarbons,
and
5. Sulfur containing compounds (thio-
phenes and mercaptans).
More detailed listings of the variety of agents
known or suspected to be associated with syn-
thetic fuels have been developed. The an-
ticipated adverse biological effectiveness of
such agents have also been listed.I7|8'9)
Several recent literature surveys
(10,11)
sug-
gest that quantitative chemical characterization
of the agents in the various products and waste
streams associated with each of the several ad-
vanced fossil fuel processes is still a major ac-
tivity. The fractionation, chemical characteriza-
tion, and bioassay of several products and
waste streams have been accomplished. A
listing of such materials is presented in Figure
11.
The problem area of characterization,
measurement and monitoring has stimulated
the following:
1. The development and use of more ac-
curate analytical instrumentation for
the quantification of the agents in the
waste streams and in the ambient en-
vironment;112'131
2. The obtaining of baseline information
at likely sites;
3. The development of a systematic
monitoring meteorology for organic
compounds;
4. A procurement of some surrogate
standard reference materials.
Surrogate standard reference materials have
been developed and distributed by NBS as part
of a quality assurance program. The surrogates
for polycyclic aromatic hydrocarbons, phenols
and for N-heterocyclics have concentrations in
the range of 100 ppm in the carrier (water or
hexane).
Environmental Transport Processes - A major
item of concern with respect to environmental
transport processes is the fate of the organics
in the various waste streams. Studies have
been undertaken to develop models for ter-
restrial sorption of shale, oil, or aquatic
transport and transformation (photo- and bio-)
models of the organics in liquid effluents. There
does not appear, however, to be an appreciable
effort regarding phototransformation of the
organics in gaseous waste streams or prod-
ucts.14'14'
Ecological Effects - In the ecological effects
research area, the subjects of major concern
specific to synthetic fuels and receiving em-
phasis include the determination of toxicity of
the organics to aquatic species and the bioac-
cumulation in the food web. Studies under-
taken have reflected this concern as indicated
by the toxicity studies on zooplankton and
various species of fish, using whole effluents
and fractions thereof from conversion proc-
esses. Bioaccumulation of metals and organics
in aquatic species is also under active in-
vestigation.(15)
Health Effects - The agents in the products
and waste streams associated with synthetic
fuel production and use cause an increase in
concern for the adverse health effects of car-
cinogenicity, mutagenicity, and teratogenicity.
The health endpoints of behavioral modifica-
tion, biochemical changes, pathophysiological
changes and system dysfunction have also
been under investigation. Targets of concern
under investigation have ranged from
subcellular components to whole animal for a
variety of tissues and body fluids. All routes of
administration (inhalation, ingestion, injection,
and immersion) have been utilized in the ex-
perimental studies, but not for all. agents of
concern, nor for all of the species of interest.
Integration of the information obtained from
the variety of studies in the various disciplines
(bioscreening, animal toxicology, cellular tox-
icology, clinical and epidemiological studies) to
obtain estimates of risk to various population
groups represents the most formidable aspect
of the health problem, in view of the variety of
126
-------
PRODUCTS
- COED SYNCRUDE PRODUCT OIL
- SYNTHOIL
- SHALE OIL
- SWEET CRUDE
AQUEOUS BY-PRODUCTS
- SYNTHANE CONDENSATE
- COED SEPARATOR LIQUOR
- OIL SHALE RETORT WATER
- SOLVENT REFINED COAL PROCESS
GASEOUS BY-PRODUCT
- COED STACK GAS
Figure 11. Characterized advanced fossil fuel products and wastes.
scientific opinions regarding the proper inter-
pretation of the data.
As indicated previously, toxicity and
mutagenicity evaluations have been under-
taken for a number of products and by-
products (aqueous and gaseous). The
mutagenicity studies performed by Epler et
al.,n6' indicate that all crudes and synfuels
show some mutagenic potential, with the
relative total varying over two orders of
magnitude, and with the mutagenic activities
of the natural crudes appearing to be ap-
preciably less than those of the synfuels. The
interpretation of these results regarding the
hazard to man is still under active investigation,
and considerable research is considered
necessary before extrapolation is appropriate.
With respect to carcinogenicity. research ef-
forts are addressing the problems of dosimetry
at the cellular and organ level, the impact of
multiple stressors, the impact of rates of ex-
posure and the development of protocols for
retrospective epidemiological studies of oc-
cupational population groups. Some in-
vestigators are now convinced that a linear
non-threshold dose response model is ap-
propriate to use for estimating impacts from
primary chemical carcinogens.117'181
Integrated Assessment - Most integrated
assessments regarding advanced fossil fuel
systems suffer from the lack of precise data
and require a regular updating.
The first phase of an integrated assessment
of energy development in the Western United
States1191 confirms the concern that such
development may well produce regional as well
as local air pollution problems. This study has
cast doubt on the need for large quantities of
water for synfuel production.
Integrated assessments are also underway
127
-------
for other regions (Southeast, Pacific North-
west, Ohio River Basin) as well as on a national
(i.e., electric utility ITA, National coal utilization
assessment) or local scale.
Some Problems
As indicated previously, a major problem that
exists is the lack of precise data that is useful
for integrated assessments. Part of this prob-
lem stems from the lack of sufficient
understanding of the most appropriate in-
dicators to use for the assessment. This lack of
understanding is reflected in the quantity and
variety of data that are being obtained at great
expense, in some cases, but of relatively little
value. There appears to be a lack of integration
of the data on a regular basis for each of the
major items of concern. Some estimate of the
uncertainties associated with the assessments
should be made on a regular basis to assist
planning of future research necessary to reduce
the uncertainties.
In the health effects area, a major problem is
the procurement of sufficiently large quantities
of well-characterized pollutants, products, and
environmentally transformed materials to
engage in statistically valid in vivo ex-
periments. Some efforts are underway to
develop a repository at Oak Ridge National
Laboratory under an interagency agreement
between EPA and ERDA. Cooperation from all
of those engaged in developing energy
technologies will be necessary in order for the
repository to function in a useful manner on a
time scale compatible with the developing
techniques.
An additional item of major concern is the
lack of information pertaining to the modifica-
tion of the spectrum of agents that are re-
leased, that occurs as a consequence of scaling
up of processes and control systems. The
developers of the processes and technologies
consistently argue that the spectrum of agents
from a full-scale commercial facility will be
vastly different than those from a model.
Those engaged in health and ecological ef-
fects research could be more helpful to the
designers of energy and control systems if a
cooperative attack on the problem was utilized
during the early stages of development.
REFERENCES
1. Report of the Interagency Working Group
on Health and Environmental Effects of
Energy Use, November, 1974, CE-
O/OMB.
2. Report of the Interagency Working Group
on Environmental Control Technology for
Energy Systems, November, 1974, CE-
O/OMB.
3. Fiscal Year 1 976 Health and Environmen-
tal Effects Research Program Abstracts
-Interagency Energy - Environment
Research and Development Report EPA-
600/7-77-004.
4. Inventory of Federal Energy-Related En-
vironment and Safety Research for FY-
1976, ERDA-77-50.
5. M. R. Guerin and J. L. Epler, "Determining
Emissions Measurements Needs for an
Emerging Industry - Advanced Fossil
Fuels Utilization," Oak Ridge National
Laboratory, presented at First Conference
on "Determining Fugitive Emissions
Measuring Needs," May 17-19, 1976,
Hartford, Connecticut.
6. S. E. Herbes, G. R. Smithworth, and C. W.
Gehrs, "Organic Contaminants in
Aqueous Coal Conversion Effluents: En-
vironmental Consequences and Research
Priorities," in proceedings of the Tenth
Annual Conference on Toxic Substances
and Environmental Health, June, 1976.
7. G. Cavannaugh et al., "Potentially Haz-
ardous Emissions from Extraction and
Processing of Coal and Oil," EPA-650/2-
75-038, 1975.
8. M. R. Kornvich, "Coal Conversion Proc-
esses: Potential Carcinogenic Risk," MTR
7155, MITRE Corporation, March, 1976.
9. C. W. Gehrs et al., "Coal Conversion,"
ORNL 5192 (special), USERDA, August
1976.
10. E. Pellizzari, "Identification of Com-
ponents Energy Related Wastes and Ef-
fluents," Research Triangle Park, EPA
Contract #68-03-2368, Final Report
5/77.
11. James Ryan, "Identification of Com-
ponents of Energy Related Wastes and Ef-
128
-------
12.
13.
14.
15.
16.
17.
18.
19.
fluents - Update," Gulf South Research
Institute, Quality Progress Reports, EPA
Contract #68-03-2487, 2/77, 5/77.
E. D. Pellizzari, "The Measurement of Car-
cinogenic Vapors in Ambient At-
mospheres," Research Triangle Institute,
EPA-600-7-77-055, June, 1977.
Proceedings - Second Conference on En-
vironmental Quality Sensors, EPA-600/9-
76-031.
Second National Conference on the In- j
teragency Energy/Environment R&D Pro- I
gram - Abstracts, Sheraton-Park Hotel,
Washington, DC, June 6-7, 1977.
Environmental Effects of Energy
Abstracts of Selected Projects Supported
by EPA Funds, EPA-600/7-77-048, April,
1977.
J. Epler et a!., "Analytical and Biological
Analyses of Test Materials from Synthetic
Fuel Technologies," Oak Ridge National
Laboratory, Submitted to Mutation
Research, August, 1977.
"AUA-ANL Workshop on Carcinogens
and Mutagenesis by Energy Related
Hydrocarbons," communication by Dr.
Roy Albert, NYU Medical Center, April
18, April 20, 1977.
NIEHS Science Seminar, communication
by Dr. D. Hall, Chapel Hill, North Carolina,
June 2-3, 1977.
I. L. White, et al., "Energy From the West
- A Progress Report of a Technology
Assessment of Western Energy Resource
Development," University of Oklahoma
and Radian Corporation, EPA-600/7-77-
072, July, 1977.
FIGURES
1. OMB-CEQ WORKING GROUPS ON
ENERGY-RELATED ENVIRONMENTAL
RESEACH.
2. INTERAGENCY PLANNING STRUCTURE.
3. ENVIRONMENTAL PATHWAYS MODEL.
4. RELATIONSHIPS AMONGST HEALTH
RESEARCH SUBCATEGORIES.
5. INTERAGENCY (PASS-THRU) ENERGY/
ENVIRONMENT PROCESSES AND EF-
FECTS PROGRAM-FUNDING BY MAJOR
CATEGORIES. (FY-75/76/77)
6. TOTAL FY-76 FEDERAL FUNDING
-ENERGY FOR RELATED ENVIRONMENT
AND SAFETY BIOMEDICAL AND EN-
VIRONMENTAL SUBCATEGORY.
7. FY-76 INTERAGENCY (PASS-THRU)
ENERGY/ENVIRONMENT PROGRAM BY
FUEL CYCLE MODULE.
8. FY-76 BASE & PASS-THRU FUNDING
FOR ENERGY/ENVIRONMENT PROGRAM
- ACCORDING TO TECHNOLOGY.
9. FY-76 FEDERAL BASE & PASS-THRU
PROGRAM - FOSSIL FUEL EMPHASIS
FOR EACH ENVIRONMENTAL RESEARCH
CATEGORY.
10. GAS CHROMATOGRAPHIC PROFILES OF
POLYNUCLEAR AROMATIC HYDROCAR-
BON ISOLATES.
11. CHARACTERIZED ADVANCED FOSSIL
FUEL PRODUCTS AND WASTES.
129
-------
Session II: ENVIRONMENTAL ASSESSMENT
E. C. Cavanaugh
Chairman
131
-------
LOW-BTU
GASIFICATION-ENVIRONMENTAL
ASSESSMENT
William E. Corbett
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78758
Abstract
Radian Corporation is under a 3-year con-
tract to EPA's Industrial Environmental
Research Laboratory at Research Triangle Park,
North Carolina, to perform a comprehensive en-
vironmental assessment of low-Btu gasification
and its utilization. The period of this contract is
March 1976 through March 1979. In this
paper, the scope and current status of Radian's
effort on this program as well as a general sum-
mary of the results achieved to date are
presented.
Basically, Radian's technical activities have
fallen into three general task areas: en-
vironmental assessment, data acquisition and
program support. To date, the bulk of the pro-
gram effort has been expended in compiling
and assessing current data on low-Btu gasifica-
tion process technology and its related en-
vironmental impacts. As part of this effort, a
data base containing over 10,000 articles and
contact reports has been compiled and assess-
ed.
Concurrently, a significant effort has been
directed toward making arrangements for con-
ducting environmental tests at operating
gasification plants both in this country and
abroad. The candidate commercial test sites
being considerd in this country are all equipped
with fixed-bed, air-blown, atmospheric
pressure gasifiers. Efforts to expand the range
of gasifiers and coal types tested have led to a
consideration of ERDA-sponsored as welt as
overseas facilities as candidate test sites. While
final arrangements for site testing activities are
not yet complete, future program effort is ex-
pected to be concentrated in the area of acquir-
ing and analyzing environmental test data.
INTRODUCTION
This paper is based upon information com-
piled in an ongoing EPA program whose objec-
tive is a comprehensive environmental assess-
ment of low/medium-Btu gasification and
utilization technology. This three-year assess-
ment program was initiated in March 1976. Ra-
dian's program efforts are therefore about half
complete at this point.
One of the first questions that one faces
when dealing with a very broad subject area
such as environmental assessment is: "What is
an environmental assessment?" Since this sub-
ject is covered in detail by Bob Hange-
brauck in another paper, I will not dwell on this
issue. However, I would like to reiterate some
of the key elements of EPA's overall approach
to environmental assessment since this will
provide some very important background infor-
mation on Radian's program efforts.
ENVIRONMENTAL ASSESSMENT
PROGRAM GUIDELINES
Basically, EPA's overall environmental
assessment program objectives, as defined by
Hangebrauck1 are:
1. to determine the multimedia en-
vironmental loadings and costs
associated with the application of alter-
native control methods to potential
low/medium-Btu coal gasification plant
emission sources; and
2. to compare the magnitudes of those
projected loadings with appropriate
target values established through
surveys of existing regulations,
estimates of multimedia environmental
goals or the results of bioassay screen-
ing tests.
Ultimately, this effort should result in a
specification of:
1. potential emission sources of en-
vironmental concern in a coal gasifica-
tion facility;
2. the effectiveness and cost of control-
ling those emissions to varying levels
through the application of candidate
control methods; and
3. areas in which existing controls appear
to be inadequate for purposes of con-
trolling hazardous pollutant emissions
to acceptable levels.
Development needs identified as a result of
this effort will be expressed such that control
133
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technology development priorities are clearly
indicated.
The specific tasks which have been defined
by the EPA as being necessary to complete an
environmental assessment are the following:
1. Current Process Technology Back-
ground;
2. Environmental Data Acquisition;
3. Current Environmental Background;
4. Environmental Objectives Develop-
ment;
5. Control Technology Assessment; and
6. Environmental Alternatives Analysis.
The general types of activities which will
take place in each of these task areas are fairly
obvious from the task titles. For a more detailed
description of these tasks, the reader should
refer to the previously referenced Hangebrauck
document1.
Radian's program activities to date have
been concentrated in the first two of the six
task areas listed above. Our first iteration at
assessing the current status of and significant
trends in low/medium-Btu gasification and
utilization technology was marked by the
release of a draft document by Cavanaugh, et
al., June 19772. Significant effort has also
been devoted toward making arrangements for
conducting environmental tests at pilot and
commercial scale gasifiers located both in this
country and abroad. At the present time, one
major testing campaign has been completed at
an existing commercial U.S. site and several
other tests are planned.
Because the bulk of our program progress
has been made on the Current Process
Technology Background and the Environmental
Data Acquisition tasks, this paper will concen-
trate on the results of our efforts in these two
task areas. While our work in the other task
areas has started, to date these efforts have
mainly taken the form of working in conjunc-
tion with the EPA and other prime contractors
to establish methodologies and examples of
useful outputs from these tasks.
More specifically, this paper will concentrate
on the following aspects of Radian's en-
vironmental assessment program. First, the en-
vironmental data base which we have ac-
cumulated to date on low/medium-Btu gasifica-
tion technology will be summarized. As part of
this discussion, the resources used to compile
this data base, the environmental problem
areas identified and the driving forces which
appear to be controlling the commercialization
of the technology will be described. This
discussion will naturally lead to a discussion of
the guidelines we have used in formulating
priorities for our environmental data acquisition
program. Finally, I will describe the test site op-
portunities we have identified and our overall
strategy and timetable for conducting mean-
ingful environmental tests.
CURRENT PROCESS
TECHNOLOGY BACKGROUND
The approach which we have taken in trying
to gain an insight into the current status of
low/medium-Btu gasification technology has
involved an aggressive campaign to procure
available information from two major sources:
1. the open literature; and
2. contacts with experts.
Obtaining information from the first of these
two resource areas involved an extensive
literature survey utilizing both computer-aided
and manual search techniques. Abstracts of
publications relating to all aspects of this pro-
gram were systematically screened,
catalogued and cross-referenced using
keywords established by project personnel. To
facilitate this effort, a special project library
was set up to support the activities of the
technical members of the project team. To
date, a gasification process environmental data
base containing over 10,000 articles, news
releases and contact reports has been
systematically compiled as a result of this ef-
fort. The approach used in setting up this infor-
mation handling system is documented in an in-
terim project technical report.3
Although the open literature has provided a
considerable amount of useful information on
this program, efforts to establish a dialogue
with persons who have active interests in
gasification technology application and
development have been far more fruitful in
helping our project team to develop a mean-
ingful perspective of current trends. This effort
has also helped considerably in the area of iden-
134
-------
tifying candidate sites for environmental
testing. This aspect of the project will be sum-
marized in a later section of this paper.
Modular Approach
One of the major problems which was faced
on this program was related to the question of
how you represent a very complex technology
composed of a large number of candidate proc-
esses which can be arranged in many different
ways. In its most simplified form, low/medium-
Btu gasification technology can be represented
by the following block diagram
COAL
GASIFICATION
TECHNOLOGY
GASEOUS
FUEL
but, this approach does not provide a very
meaningful mechanism for organizing and inter-
preting process and control technology infor-
mation. One approach to this problem of
analyzing a complex technology which has
proven itself to be useful in several previous
EPA programs is a modular or unit operations
approach.
With this approach, a complex technology or
industry is broken down into its generic unit
operations, each of which is characterized as
having specific input and output streams. On
this basis, the production of low/medium-Btu
gas can be assumed to require the process
operations shown in Figure 1.
Each of these unit operations can in turn be
represented by a series of optional process
modules as shown in Figures 2, 3 and 4.
Now, while a technology can be represented
in a general sense by block diagrams such as
those shown in Figures 1-4, site-specific en-
vironmental determinations must be based
upon an analysis of a specific coal feed which is
converted into a product which is consumed by
a specific end user. For this reason, it is impor-
tant to consider the potential end uses of
low/medium-Btu gas as well as the specific
processes which appear to be best suited to
producing the required product gas.
Significant End Use
Options for Low/Medium-Btu Gas
Potential end uses for low/medium-Btu gas
which apear to be commercially significant at
present are:
1. as a fuel for direct firing of process
heaters requiring a clean fuel gas. This
is a very likely near-term application for
the technology;
2. as a fuel for process heaters and steam
boilers which cannot economically be
converted to direct coal-fired units.
This option is most attractive in a situa-
tion where a gasification system can be
used to supply large number of remote
users;
3. as a gas turbine fuel, including use in
combined cycle units. One potentially
attractive approach here is the use of a
gasifier and storage system to supply
fuel for a utility peaking turbine,- and
4. as a synthesis or reducing gas. This end
use option would not be competitive
with liquid fuel reforming in most ap-
plications.
Coal,
Feed
Coal
Pretreatment
H
I Coal
Gasification
Gas
Purification
Product
^ Gas
Utilization
Figure 1. Coal gasification process unit operations.
135
-------
COAL
FEED'
GO
en
DRYING
H
PARTIAL
OXIDATION
TRANSPORT*
& STORAGE
CRUSHING
AND
SIZING
SIZED>
COAL
BRIQUETTING
To ON-SITE COMBUSTION,
SALE OR DISPOSAL
PULVERIZING
To
FIXED-BED
GASIFIER
To FLUIDIZED-
OR ENTRAiNED-
BED GASIFIER
*THESE MODULES CAN BE EMPLOYED AT ANY POINT
ON THE ABOVE PROCESSING SEQUENCE,
Figure 2. Process modules—coal pretreatment operation.
-------
AIR
AIR
SEPARATION
02
-, PRETREATED
ss COAL
FUEL
H20
COAL
FEEDER
GASIFIER
BOILER
STEAM
RAW
PRODUCT
GAS
ASH
REMOVAL
SYSTEM
h
ASH
ELECTRIC
POWER
Figure 3. Process modules—coal gasification operation.
-------
RAW
PRODUCT
GAS
PARTICULATE
REMOVAL
i
PARTICULATES
ACID GASES
GAS
COOLING
T
TARS
PROCESS CONDENSATE
ACID
GAS
REMOVAL
PRODUCT
GAS
Figure 4. Process modules—gas purification operation.
-------
All of these end uses for clean gaseous fuels
have traditionally been satisfied by natural gas
consumption. As this country's natural gas
supplies diminish, however, many industrial
users of natural gas are finding that
low/medium-Btu gas is becoming an increas-
ingly attractive alternative to the complete
replacement of existing gas-fired facilities.
Significant Processing
Options
The gasification processes that appear to be
best suited to satisfying near-term needs for
low/medium-Btu gas are listed in Table 1. While
this is by no means a complete list of available
processes, it does include most of the systems
for which there appears to be considerable
commercial or governmental agency support.
As shown in Table 2, these promising
gasification systems fall into six different
groups when classified on the basis of their
significant design features. This classification
scheme is also significant from an environ-
mental standpoint because the product, by-
product and emission streams associated with
these various gasifiers will vary considerably as
functions of the process design features listed.
For example, relative to high temperature,
TABLE 1
PROMISING LOW/MEDIUM-BTU
GASIFICATION SYSTEMS
Commercial
Widespread Use
Commercial
Limited Use
Developmental
Koppers-Totzek
Lurgi
Well man-Galusha
Winkler
Woodall-Duckham/
Gas Integrals
Chapman (Wilputte)
Riley Morgan
Bi-Gas
BGC Slagging
Lurgi
Foster Wheeler/
Stoic
GFERC Slagging
MERC Pressurized
Wellman-Galusha
Texaco
entrained-bed systems, fixed-bed systems will
tend to produce a product gas that contains
significantly greater quantities of coal
devolatilization products. This will create more
of a tar/oil fraction handling and disposal prob-
lem. Relative to dry ash systems, slagging
systems will produce a fused ash material
TABLE 2
PROMISING LOW/MEDIUM-BTU GASIFICATION SYSTEMS
Classification By Gasifier Type
Fixed Bed Dry Ash Atmospheric
Pressurized
Slagging Pressurized
Entrained Bed Slagging Atmospheric
Pressurized
Fluid Bed Dry Ash Atmospheric
Chapman (Wilputte)
Foster Wheeler/Stoic
Riley Morgan
Wellman-Galusha
Woodall Duckham/GI
Lurgi
MERC
BGC Lurgi
GFERC
Koppers-Totzek
Bi-Gas
Texaco
Winkler
139
-------
which should exhibit significantly different
leaching characteristics.
The requirements of the coal pretreatment
module are generally dictated by the properties
of the feed coal and the feed specifications of
the gasifier used. Gas purification process re-
quirements are determined by the specifica-
tions of the intended end use process. Again,
these process constraints are environmentally
significant. Potential emissions of volatile
organics from coal drying and partial oxidation
processes appear to be a troublesome problem.
By the same token, gas cooling and low
temperature acid gas removal processes
generate a tar/oil stream and a process conden-
sate which are difficult to dispose of in an en-
vironmentally sound manner. Applications
which can utilize hot, raw gasifier product gas
directly can avoid this troublesome problem, a
consideration which explains one of the main
drivinp forces behind efforts to develop high
temperature acid gas removal processes.
A factor which is not addressed in this paper,
but one which must be kept in mind, is that
process economics will ultimately dictate the
choice of a coal feedstock, process configura-
tion and process operating conditions for a
given application. This choice must take into
account the environmental tradeoffs and con-
trol technology requirements associated with
various process options, but, in the final
analysis, process and control technology op-
tions will both be selected on an economic
basis.
Environmental
Problem Areas
In addition to providing a more detailed
breakdown of the modules required to satisfy
the requirements of the three major process
operations. Figures 2, 3, and 4 also provide a
useful starting point for the identification of
potential gasification plant environmental prob-
lem areas. In the coal pretreatment operation,
there are three major classes of emission prob-
lems:
1. coal dust emissions from all coal hand-
ling and storage operations;
2. volatile component emissions from all
modules that involve the thermal treat-
ment of coal (drying, partial oxidation
and possibly briquetting and storage);
and
3. water runoff from coal storage areas or
from the use of water sprays for dust
suppression.
Qualitatively, the coal dust emitted from coal
handling operations would be similar to the coal
feed material, but good techniques for
calculating dust emission rates as functions of
coal properties and the characteristics of the
process hardware are not available. Some data
on coal devolatilization products have been
reported, but much of this information is of
limited use to this program. The leaching
characteristics of a variety of specific coal
types are probably better defined than some of
these other problem areas, but additional work
on specific coals which appear to be reasonable
candidates for gasification process feed
materials is needed.
In the coal gasification operation the major
sources of environmental emissions are:
1. gasifier start-up vent;
2. leaks and other fugitive emissions of
raw product gas, e.g., through the coal
feeding device;
3. ash handling procedures which can
generate ash dust; and
4. leached ash components (associated
with rainfall or ash sluice water) which
are a problem in wet ash handling
systems.
The gasifier start-up vent stream would nor-
mally be flared. One question related to this
operation for which no data exist is, "Are
hazardous raw gas components adequately
controlled using this approach?" This question
of hazardous component behavior in combus-
tion processes is a much broader issue,
however. The fate of both tar and low/medium-
Btu gas components in combustion processes
warrants considerable further study since this
issue impacts:
1. the emissions of hazardous com-
ponents from many candidate
product/by-product utilization proc-
esses; and
2. the adequacy of incineration or flaring
as a control technique for hazardous
hydrocarbon vapors.
In the gas purification operation, the major
sources of emission streams are:
1. particulate removal processes which
remove tar aerosols and coal fines from
the hot raw product gas;
140
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2. quenching operations which usually
produce condensed organic (tar/oil)
and aqueous (process condensate)
materials. Disposal or treatment of
these materials is a very troublesome
problem because of the wide range of
pollutants they contain;
3. acid gases removed from the product
gas; and
4. fugitive emissions from handling all of
these materials.
As a general statement, it can be said that a
significant amount of data are available on en-
vironmental problems associated with coal
gasifier operations. These data are inadequate
for purposes of making comprehensive en-
vironmental and control technology
assessments, however. Of particular impor-
tance to this program are data which
• provide more detailed characterizations
of the types of emissions streams just
discussed,
• specify levels of hazardous com-
ponents present in those streams as
functions of key process variables, and
• predict the fates of those components
in utilization and/or treatment proc-
esses.
It is these objectives which are now guiding
our current efforts to expand our environmental
data base through meaningful test programs at
operating gasification sites.
ENVIRONMENTAL DATA
ACQUISTION
In this section, the concerns which are
guiding Radian's overall data acquisition effort
are described. Our current approach to con-
ducting environmental tests at a specific site is
summarized in a paper by Bombaugh4, so this
issue will not be addressed here.
Sites which were considered to be potential
candidates for environmental testing include:
• domestic facilities
— operating commercial-scale units
— developmental/demonstration
units
• foreign facilities
— a wide range of commercial-scale
test opportunities is represented by
this group.
Commercial scale gasifiers which are
presently operating in this country are shown in
Table 3. Of this group, only the Holston gasifier
has been tested to date. Environmental testing
of a Wellman-Galusha gasifier at Glen-Gery's
York, Pennsylvania plant is planned for early
1978 in conjunction with ERDA's industrial
gasifier test program. No firm plans exist for
conducting tests at the other two sites listed,
although extensive discussions of test
possibilities have been held with the two
groups involved.
Several limitations in the test possibilities af-
forded by these commercial gasifiers are ob-
vious from the data presented in Table 3. All of
these sites use fixed-bed, air-blown gasifiers.
The only particulate removal technique utilized
is a hot cyclone. Only one site has gas quench-
ing and tar/condensate handling facilities. Only
one gasifier uses a variety of coal types.
Because of these limitations in commercial
sector test opportunities, consideration of
alternate domestic sites for environmental
testing is justified. Some of the possibilities
here are
• EPA-sponsored test units at Research
Triangle Institute and North Carolina
State University which will study
gasification process pollutant genera-
tion and control technology effec-
tiveness,
• ERDA-sponsored development units at
MERC and GFERC,
• ERDA-funded gasifiers which will be in-
stalled at a variety of domestic sites,
and
• privately-funded development units.
The EPA-sponsored test units are not yet
operational. Discussions have been held with
MERC and GFERC representatives concerning
possibilities for cooperative EPA/ERDA test
programs, but no specific agreements have
been reached. The first ERDA-sponsored in-
dustrial gasifier to be started up will be Glen-
Gery's York, Pennsylvania unit. The next
gasifier is not scheduled for startup until at
least the third quarter of 1978. Discussions
with a large number of private sponsors of
gasification-related R&D programs have been
held, but, to date, no promising test oppor-
tunities in that area have been identified.
Because of this further limitation in the
141
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TABLES
CANDIDATE DOMESTIC TEST SITES-OPERATING COMMERCIAL GASIFIERS (ALL LOW-BTU)
Site
Holston Army
Ammunition
Plant
Holston, TN.
Glen-Gery
Brick Co.
4 Sites in
Eastern PA.
National Lime
Carey,
Ohio
Riley Stoker
Demonstration
Unit
Worcester, MA.
Gasifier and Coal Type
Chapman
Bituminous
Wellman-Galusha
Anthracite
Wellman-Galusha
Bituminous
Riley-Morgan
Variable
Cleanup
Hot Cyclone
Water Quench
Two Stages of
Water Scrubbing
Hot Cyclone
Hot Cyclone
Hot Cyclone
• Utilization
Low-Btu Gas-Burned
in Process Furnace
Tar-Burned in Boiler
Gas Burned in Crick Kiln
Gas Burned in a Lime
Gas Flared
Kiln
availability of viable developmental sites in this
country, a number of commercial sites in
foreign countries have been considered as can-
didates for environmental testing. Process and
emission data will be obtained from a medium-
Btu gasification facility located in Kosovo,
Yugoslavia sU, ting in the fall of this year.
Details of this program are described in a paper
by Mitrovic5. The possibility of conducting en-
vironmental tests in Europe and Africa is being
jointly pursued by Radian and TRW, but, to
date, no firm developments in this area can be
reported.
SUMMARY AND CONCLUSIONS
The conclusions which can be drawn from
the results of Radian's program efforts to date
fall into three general areas:
• Current Technology Status
• Need for Environmental Data Acquisi-
tion
• Test Opportunities
On the subject of the current status of
low/medium-Btu gasification, there is very
clearly a significant interest in the near-term ap-
plication of this technology in the United
States. The most promising potential market
appears to be associated with supplying the
gaseous fuel needs of existing industrial proc-
esses which can no longer depend upon tradi-
tional sources of natural gas. Use of
low/medium-Btu gas as a gas turbine fuel or as
a synthesis/reducing gas may be feasible in
some applications, but widespread usage of
gasification technology to satisfy these
demands is not anticipated to be significant in
the near term.
Radian's survey of available data on the en-
vironmental aspects of low/medium-Btu
gasification processes has shown that existing
data are not sufficient to support the level of
analysis required to produce the desired end
products of this assessment program. Major
deficiencies are found in the areas of
characterizing the emissions of minor and trace
contaminants from gasification processes (par-
ticularly trace organics). There is also a general
lack of information on fugitive emissions and
minor process vent streams.
Available U.S. test sites will provide oppor-
tunities for gathering useful environmental data
142
-------
on fixed-bed, atmospheric pressure systems
using anthracite and bituminous coal
feedstocks. Efforts to expand the range of
gasifiers and coal types available for testing has
led us to push for involvement in both ERDA-
sponsored and overseas test programs. Radian
participation in these programs will be a key
element in the development of an ability to 3.
predict the impact of coal feedstock and proc-
ess variable changes upon control technology
needs.
REFERENCES 4.
Hangebrauck, R. P., Status of IERL-RTP
Program to Develop Environmental
Assessment Methodology for Fossil
Energy Processes. Working Document. 5.
Research Triangle Park, NC, Industrial En-
vironmental Research Laboratory,
February 1977.
Cavanaugh, E. C., et al.. Technology
Status Report: Low/Medium-Btu Coal
Gasification and Related Environmental
Controls, Volume I & II. Radian DCN
77-200-143-15, Radian Contract No.
200-143-08, EPA Contract No.
68-02-2147. Austin, TX, Radian Corp.,
June 1977.
Phillips, Nancy P., and S. M. Bell, Sum-
mary Report for Technical Information
System. Radian DCN 77-200-143-01,
EPA Contract No. 68-02-2147, TD-7.
Austin, TX, Radian Corp., 12 January
1977.
Bombaugh, Karl J., "A Non-Site Specific
Test Plan," Presented at Environmental
Aspects of Fuel Conversion Technology,
III, Hollywood, Florida, 13-16 September
1977.
Mitrovic, Mira, "Kosovo Gasification Pro-
gram," Presented at Environmental
Aspects of Fuel Conversion Technology,
III, Hollywood, Florida, 13-16 September
1977.
143
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HIGH BTU GASIFICATION
ENVIRONMENTAL ASSESSMENT -
WORK STATUS AND PLANS
Charles F. Murray, Program Manager
Masood Ghassemi, Senior Project
Engineer
Environmental Engineering Division
Energy Systems Group of TRW, Inc.
Redondo Beach, California 90278
Abstract
This recently initiated 3-year study is aimed
at environmental assessment of high-Btu coal
gasification including identification of the con-
trol technology needs for the industry. The ef-
fort consists of: (a) evaluation of existing proc-
ess and environmental data and the data which
are being generated by other EPA/ERDA con-
tractors working in related areas; (b) acquisi-
tion of supplementary data through samp/ing
and analysis of process/waste streams at
selected gasification facilities; and (c) en-
vironmental assessment and necessary proc-
ess engineering support studies.
The program activities fall into three work
areas: Environmental Assessment, (Field) Data
Acquisition, and General Program Support. The
work areas are broken down into a total of 17
iterrelated tasks. To provide program flexibili-
'y, a "work package " approach is used by EPA
to cjthorize work relevant to specific tasks in
the program. A total of nine Technical Direc-
ives have been issued by EPA authorizing work
elevant to 10 tasks.
Most of the effort in the program to date has
been in connection with two technical direc-
tives, Acquisition and Analysis of the Data
Base, and Site Locations and Information. A
large number of pertinent background
documents have been acquired. Nine gasifica-
tion processes have been selected for de-
tailed analysis. A "modular" approach has
been chosen for analysis and presentation of
data on gasification, gas treatment, pollution
control, and integrated facilities. Draft
"gasification data sheets"have been prepared
for six of the nine processes considered.
Preliminary discussions have been held with
ERDA and a number of private process
developers to enlist their cooperation in identi-
fying poten tial sites for en vironmental sampl1
and in arranging for such sampling.
INTRODUCTION
Under a contract awarded to TRW in May
1977 by EPA/IERL-RTP, TRW is currently
working on a 3-year program to (a) characterize
the waste streams associated with the opera-
tion of commercial high-Btu gasification
facilities using current and developmental con-
version technologies, (b) identify the control
technology required to reduce or eliminate
waste discharges, and (c) estimate the en-
vironmental impacts at selected sites. The
study will provide input to the EPA effort for
developing and demonstrating control
technologies for emerging industries and for
establishing the technical basis for drafting
new source performance standards for
gasification plants.
Because the program has only been started
very recently, sufficient results are not
available for presentation at this time. This
paper will present a description of the program
in terms of its structure and the mechanism by
which tasks in the program are initiated. The
objectives of and the preliminary ac-
complishments in the few tasks that have been
initiated will also be reviewed.
GENERAL STUDY APPROACH AND WORK
BREAKDOWN STRUCTURE
The technical approach for achieving the pro-
gram objectives consists of the following ac-
tivities:
1. Generation of a gasification/gas
upgrading, control technology, and im-
pact assessment baseline.
2. Definition of information gaps and defi-
ciencies and areas for productive ap-
plication of engineering analysis.
3. Conduct of field sampling and analysis
programs aimed at filling data gaps and
providing needed information.
4. Conduct of selected engineering
analyses to supplement available proc-
ess and control equipment information.
144
-------
5. Integration of all information and data
into assessment and technology over-
view documents.
For planning purposes and to provide for ef-
fective program management, the program has
been divided into three work areas: Work Area
A, Environmental Assessment; Work Area B,
Data Acquisitions; and Work Area C, General
Program Support. A brief description of the ac-
tivities in and the specific objectives of each
work area follows.
Work Area A - Environmental Assessment
The overall objective of Work Area A is to
assess the environmental impacts associated
with commercial-scale high-Btu gasification
operations. The environmental assessment will
be based upon (a) review of the published
literature on gasification processes and related
control technologies; (b) data which are being
generated by other EPA contractors working in
related areas (e.g., low/medium Btu gasifica-
tion environmental assessment; coal liquefac-
tion environmental assessment, etc.); (c) data
to be acquired from process developers and
government agencies; and (d) data to be
generated in Work Area B through environmen-
tal sampling at high-Btu gasification sites, in
Work Area A through process engineering, and
in Work Area C through support studies. More
specifically, the efforts in and the objectives of
Work Area A are as follows:
• Evaluation of available data relative to
gasification, gas processing
technology and economics, input
material characteristics, current control
technologies, and process/equipment
environmental characteristics.
• Preparation of a technology overview
document.
• Prioritization, in order of projected com-
mercial viability, of gasification proc-
esses.
• Identification and prioritization of emis-
sions data and information gaps.
• Evaluation of the potential of
developmental control technologies.
• Process engineering studies to aid in
evaluation of data validity; resolution of
data conflicts and filling data gaps.
• Integration of the Work Area B data in-
to technology overview and impact
assessment documents.
• Projection, on a common production
basis, of the impact data base ; com-
mercial scale.
To accomplish the above-listed objectives,
and for planning purposes. Work Area A has
been subdivided into a total of nine interrelated
tasks. A listing and brief description of these
tasks are presented in Table 1.
Work Area B - Data Acquisitions
To be meaningful and technically valid, the
environmental assessment of high-Bt', gasin -a-
tion should be based, as far as practicable, on
actual process and emissions data for existing
commercial and pilot plant facilities. Since only
a limited amount of such data is currently
available, in the present program co isid^'able
emphasis is placed on datu acquisitions
through comprehensive environmer.tal sam-
pling and analysis at selected pilot plan 'co,,i-
mercial facilities. Reflecting this err ^hasis and
for planning purposes, about 40 pen ent of the
program funds and manpower hai been ear-
marked for data acquisitions. The sa nplin ;i and
analysis program will be aimed primarily at
generating data to fill some of the gaps iden-
tified in Work Area A. More specifically Work
Area B involves the following activities, 'bjec-
tives:
• Identification of representative can-
didate high-Btu gasification process,
gas cleaning and upgrading sampling
sites, and assessment of the likelihood
of gaining access to these sites for
sampling purposes.
• Ranking of candidate sites, based upon
operator cooperation, process stage of
development, and other factors.
• Organization, cost and planning of the
field and laboratory sampling, and
analysis efforts associated with each
selected site.
• Implementation of field and laboratory
data acquisition programs at the
selected sites.
To accomplish the above-listed objectives in
an orderly manner, Work Area B has been sub-
145
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TABLE 1
WORK AREA A TASK DESCRIPTIONS
Task
Description
A1 - Technology Overviews
A2 - Impact Assessments
A3 - Input Material
Characterizations
A4 - Process Engineering
A5 - Control Technology
Evaluation
A6 - Accidental and Transient
Pollutant Releases
A7 - New Control Technology
A8 - Revised Impact
Assessments
A9 - Revised Technology
Overviews
Overview report on status and technical/
environmental aspects of gasification
processes.
Preliminary impact assessments to identify
data needs.
Review of physical/chemical characteristics
of process input materials.
Material/energy balances and other
engineering analyses to characterize integrated
facilities, resolve data conflicts and verify
data accuracy.
Review of pollution control technologies
applicable to gasification.
Identification of potential sources and nature
and quantities of pollutant emissions during
accidents and transient operations.
Conceptual designs of applicable new control
technologies and in-plant changes, and/or
modifications of existing control technologies.
Detailed environmental assessment incorporating
the data generated in the program.
Updated technology overviews, incorporating
additional data and findings.
divided into a total of six tasks as described in
Table 2.
Work Area C - General Program Support
Major activities in Work Area C include: (a)
collection and maintenance of background data
on the technology and environmental aspects
of high-Btu gasification including preparation
and periodic updating of an "analysis of the
data base" document; (b) performance of
miscellaneous document reviews, surveys and
special studies on an as required basis to sup-
port program activities in Work Areas A and B;
and (c) providing program management and
control functions, including reporting to EPA
and coordination with other EPA contractors
working in related areas. For planning pur-
poses. Work Area C has been subdivided into
three tasks described in Table 3.
Work Authorization Via Technical Directives
To provide maximum program flexibility and
to accommodate changes in program emphasis
which may become necessary as the program
proceeds, a "work package" approach is used
by EPA to authorize work in a specific task or
elements of one or more tasks. The scope of
the effort in each work package, the funding
level and the performance period are specified
in work authorization "Technical Directives"
(TD's) which are issued by the EPA Project Of-
ficer. To date, a total of nine TD's have been
received authorizing work relevant to Tasks 1
through 5 in Work Area A; Tasks 1 and 2 in
Work Area B; and Tasks 1, 2, and 3 in Work
Area C (see Tables 1, 2, and 3 for task descrip-
tions.) These TD's, the relevant tasks covered,
the TD issue dates, and performance periods
are listed in Table 4.
146
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TABLE 2
WORK AREA B TASK DESCRIPTIONS
Task Description
B1 - Site Locations and Identification of potential domestic and
Information foreign test sites and establishment of
initial contacts.
B2 - Data Possibilities Test site screening and prioritization and
identification of sampling opportunities.
B3 - Test Program Preparation of detailed sampling plan for
Development ' Level 1 environmental assessment for
selected sites.
B4 • Cost Estimates Estimation of sampling/analysis costs.
B5 • Testing Field testing and laboratory analyses.
B6 - Data Analysis and Reduction and evaluation of the test data.
Reporting
TABLE 3
WORK AREA C TASK DESCRIPTIONS
Task Description
C1 - Background and Collection and evaluation of background
Evaluations engineering/environmental data, and identification
of data gaps and conflicts; special studies/surveys
in support of program activities.
C2 - Reporting and Preparation of reports and coordination with
Coordination EPA, EPA contractors and other agencies.
C3 - Program Management Program management including financial control.
147
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TABLE 4
TECHNICAL DIRECTIVES, RELEVANT TASKS, ISSUE DATES,
AND PERFORMANCE PERIODS
TD #
001
002
003
004
005
006
007
008
009
Title
Work Plan Preparation and
Coordination
Acquisition and Analysis of
the Data Base
Technology Overview
Process Engineering
Site Locations and Information
Program Management,
Coordination, and Reporting
Applicability of Petroleum
Refining Control to Gasification
and Other Synfuel Processes
Data Possibilities
Preliminary Impact Assessment
Input Material Characterization
Review and Evaluation
Relevant
Task(s)*
C-2
C-1
A-1
A-4
B-1
C-3
C-2
A-5
B-2
A-2
A-3
C-1
Date
Issued
5-3-77
6-22-77
6-22-77
6-22-77
6-22-77
7-18-77
8-23-77
8-23-77
8-25-77
Performance
Period
5 mo.
6 mo.
6 mo.
7 mo.
6 mo.
7 mo
9 mo.
3 mo.
6 mo.
*See Tables 1, 2, and 3 for task descriptions
STATUS OF WORK AUTHORIZED
UNDER TECHNICAL DIRECTIVES
The work authorized under TD 001 has now
been completed. The effort consisted of
preparation of a work plan and initial coordina-
tion with other EPA contractors by attending an
"all-contractors" meeting. TD 002 and TD
004 will be discussed in more detail below. TD
003 authorizes the preparation of a Tech-
nology Overview Report (Task A-1, see Table
1) and the conduct of necessary process
engineering studies to support activities
authorized under other TD's. Since the
Technology Overview Report will be based
upon the data base being developed under TD
002, the preparation of this document has
been intentionally delayed until significant pro-
gress is made in connection with the acquisi-
tion and analysis of the data base (TD 002).
Because the program has been started only
recently, there has been little need to date for
process engineering support activities.
However, as the work progresses, there will be
an increased demand for process engineering
support. The work performed under TD 005
has been primarily concerned with program
management including reporting to and coor-
dination with EPA.
Many of the control technologies which have
been developed for use in petroleum refining
would be applicable (in certain cases with some
modification) to the synfuel processes. TD 006
authorizes a detailed evaluation of such ap-
plicability as part of the control technology
evaluation effort in Task A-5. As indicated in
Table 4, TD 006 has been issued only very
recently. The limited work which has been car-
ried out under this TD consists of collection and
review of pertinent key documents on refinery
waste/process streams and control tech-
nologies.
TD 007, TD 008, and TD 009 have just been
issued; the work authorized under these TD's
has been restricted to planning activities. Most
of the effort in the program to date has been in
148
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connection with TD 002, Acquisition and
Analysis of the Data Base, and TD 004, Site
Locations and Information. Brief descriptions of
the accomplishment under these two TD's
follow.
TD 002, Acquisition and Analysis of
the Data Base.
The acquisition and analysis of the data base
are considered the first steps toward detailed
environmental assessment of high-Btu gasifica-
tion. The overall objectives of the effort are to
identify the gaps which exist in the available
data and the additional data needed for detailed
environmental assessment. The activities
which have been carried out under TD 002 fall
into two categories: data base development
and data analysis.
The data base development effort has con-
sisted of identification and acquisition of perti-
nent documents and establishment of a cen-
tralized "high-Btu gasification library" for use
by the project personnel. The current library
holdings stand at 415 documents consisting
primarily of EPA/ERDA reports, symposium
proceedings, and journal articles. A system of
key word indexing has been developed and us-
ed in a computer program which permits easy
information retrieval.
Nine gasification systems have been selected
as the minimum for detailed analysis in this pro-
gram. These are Hygas, Bigas, Cogas,
Hydrane, Synthane, Texaco, C02-Acceptor,
Self-agglomerating Ash, and Lurgi. A
"modular" approach has been selected for
evaluation and presentation of information on
these processes. The "modules" which will be
addressed are "gasification module," "gas
treatment module," "pollution control
module," and "integrated facilities." A "data
sheet" outline (see Table 5) has been drafted
for the presentation of information on the
gasification module. Separate "data sheet"
outlines are being prepared for the presentation
of information on gas purification, pollution
control, and integrated facility modules. The
use of the data sheet format, which omits
lengthy and general process descriptions, is
believed to be an excellent means for presenta-
tion of key information items, imparting high
"visibility" to the engineering "facts and
figures," allowing ready comparison of dif-
ferent processes, and underlining areas where
significant gaps exist in the available data. The
first draft of the gasification data sheet has
been completed for six of the nine processes
considered (Synthane, Texaco, C02-Acceptor,
Lurgi, Cogas, and Hydrane). These draft sheets
will be updated and revised as more data
become available to the program. To assure the
accuracy and completeness of the information,
it is planned to forward these data sheets to the
process developers (ERDA, Texaco Develop-
ment Company, American Lurgi, and CONOCO)
for review and comments.
TD 004, Site Locations, and Information.
As was indicated above, because of the
heretofore lack of extensive environmental
data on high-Btu gasification processes, the
present program places a very strong emphasis
on data acquisition through environmental
sampling at gasification sites. Obtaining access
to a significant number of "important" sites is
considered the key to the success of the pro-
gram. Since six of the nine gasification pro-
cesses considered are ERDA processes which
are being or have been tested at domestic sites,
a concentrated effort is currently being directed
at exploring sampling opportunities at the ER-
DA sites. A preliminary meeting has been held
with ERDA in Washington to enlist that agen-
cy's support for the program. Two possibilities
for sampling are being explored: (a) indepen-
dent sampling at gasification sites and (b)
where applicable, "piggybacking" existing
and/or planned ERDA environmental sampling
and assessment programs (e.g., in connection
with Synthane and Bigas Processes). Sampling
opportunities at several overseas commercial
gasification sites and at one domestic facility
operated by a private developer are also cur-
rently being explored. Even though the
gasification operations at some of these
facilities (e.g., the Modderfontein plant in
South Africa which uses the Kopper-Totzek
Process) result in the production of low-
medium Btu gas, these plants have features
and processing steps similar to those employed
in the production of high-Btu gas.
In connection with TD 004 and in conjunc-
tion with the efforts which are or will be carried
149
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TABLE 5
OUTLINE FOR GASIFICATION OPERATIONS DATA SHEET
1.0 GENERAL INFORMATION
1.1 Operating Principles
1.2 Development Status
1.3 Licensor/Developer
1.4 Commercial Applications
2.0 PROCESS INFORMATION
2.1 Bench-Scale/Process Development Unit
(Figure, Flow Diagram)
2.1.1 Gasifier
Equipment
- Construction
- Dimensions
- Bed type and gas flow
- Heat transfer and cooling
- Coal feeding
- Gasification media introduction
- Ash removal
- Special features
Operating Parameters
- Gas outlet temperature
- Coal bed temperature
- Gasifier pressure
- Coal residence time in gasifier
Raw Material Requirements
- Coal feedstock
Type
Size
Rate
- Coal pretreatment
- Stream
- 02/air
- Other materials
Utility Requirements
- Water
Boiler
Quench
Cooling
- Electricity
Process Efficiency
- Cold gas efficiency
- Overall thermal efficiency
Expected Turndown Ratio
Gas Production Rate/Yield
2.1.2 Coal Feed/Pretreatment
2.1.3 Quench and Dust Removal
2.1.4 Miscellaneous Operations
2.2 Pilot Plant (Figure, Flow Diagram)
(Subheadings same as under 2.1 above)
2.3 Demonstration/Commercial Facilities
(Subheadings same as under 2.1 above)
3.0 PROCESS ECONOMICS
4.0 PROCESS ADVANTAGES
5.0 PROCESS LIMITATIONS
6.0 INPUT STREAMS
6.1 Coal
• Type/origin
- Size
- Rate
- Composition
Moisture
Volatile matter
Ash
C, etc.
Minor and trace elements
- HHV (dry)
- Swelling number
- Caking index
6.2 Steam (temperature and pressure)
6.3 Oxygen/Air
6.4 Other Inputs (properties and composition)
7.0 DISCHARGE STREAMS (including unit production
rates)
7.1 Gaseous
- Stream (x): product gas
- Stream (y), etc.
7.2 Liquid
7.3 Solid
8.0 DATA GAPS AND LIMITATIONS
9.0 RELATED PROGRAMS
REFERENCES
150
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out under TD 002 (Acquisition and Analysis of diagram, waste/process stream accessibility,
the Data Base) and TD 007 (Data Possibilities), operating conditions, schedule, etc., for the
information is being collected on the plant flow candidate gasification test sites.
151
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FLUE GAS SAMPLING DURING
THE COMBUSTION OF SOLVENT
REFINED COAL IN A
UTILITY BOILER
Craig S. Koralek and V. Bruce May
Hittman Associates, Inc.
9190 Red Branch Road
Columbia, Maryland 21045
Abstract
Solvent Refined Coal was burned in a com-
mercial utility boiler. Flue gas samples were col-
lected using EPA-5, ASME and Source Assess-
ment Sampling System (SASS) trains and grab
sampling methodologies. Results of available
analyses are reported.
SUMMARY
On June 10th, 1977 Solvent Refined Coal
(SRC) was burned in a commercial utility boiler
for the first time, for the purpose of determin-
ing whether SRC could replace coal as a
primary fuel in a pulverized coal-fired boiler. In
addition to boiler efficiency tests, flue gas
samples were collected using EPA-5, ASME,
and Source Assessment Sampling System
(SASS) trains.
In previous phases of this program, coal was
burned in the same boiler. Similar tests were
performed; results were compared with the
Phase III SRC test. The results of the com-
parison indicate that SRC can be used as a
replacement for coal in a conventional pul-
verized coal-fired boiler. Results of the grab
sample analysis indicated no detectable levels
of CT -C6 hydrocarbons. S02 and NO, emis-
sions/million Btu were approximately the same
as those from burning low sulfur coal. Higher
concentrations of NOX were probably at-
tributable to high combustion temperature or
higher organic nitrogen in the fuel, although
emissions of NOX were essentially the same as
for coal.
A combustion test at Georgia Power Com-
pany's Plant Mitchell, located near Albany,
Georgia, was performed to determine whether
(SRC) can be burned in a pulverized coal-fired
boiler. This three-phase test marked the first
time that SRC has been burned in a utility
boiler. In addition to boiler and precipitator effi-
ciency tests, a detailed inventory of air emis-
sions, including polynuclear aromatic hydrocar-
bons, was performed.
In Phase I of this program, low sulfur Ken-
tucky coal was burned in the existing, un-
modified 22-1/2 MW pulverized coal boiler.
Following replacement of the original burners
with dual register burners and accompanying
modifications, Phase II of the test was con-
ducted. In this phase, as in Phase I, the boiler
was fired with low sulfur Kentucky coal. In
Phase III, discussed in detail in this report,
following adjustment of the burners and the
pulverizers, SRC was burned. This SRC had
been produced at the Fort Lewis pilot plant
from Western Kentucky coals having a sulfur
content of approximately 4 percent and ash
content of 10 to 1 2 percent. Sulfur and ash in
the SRC as produced were approximately 0.6
percent and 0.1 to 0.2 percent, respectively.
At the time of the combustion test the SRC had
been stored onsite in the open for approximate-
ly one year. Analytical results showed essen-
tially the same sulfur content but an average
ash content of approximately 0.6 percent.
However, after removal of certain surface con-
tamination by washing, the ash content of the
bulk SRC was in the same range as the ash
determination in the material shipped. Further
investigation is underway to determine the
cause of this difference. In each of the three
phases of the program, the boiler was operated
at full (~ 21 MW), medium (~ 14MW), and
low (~ 7 MW) load conditions.
Precipitator efficiency tests were run, ash
resistivity was determined, and air emission
levels were evaluated using EPA-5 and ASME
trains. In addition to particulates, a number of
gases, including C02, CO, NOX, 02, and SO2
were monitored.
During Phases II and III, additional flue gas
sampling was conducted using a SASS train to
collect samples for a modified EPA Level 1
laboratory analysis. Grab samples also were
obtained for on-site analysis for C^ - C6
hydrocarbons, SO, N2, CO, C02,and O2.
A diagram of the SASS train is shown in
Figure 1. This sampling device includes
152
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:K T.C.
<
HEATER
CON-
TROLLER
SS PROBE
1
,„ !
• iu,u i
CONVECTION
OVEN
FILTER
GAS COOLER
w
1
w
n
i
i
i
i
i
.j
GAS
TEMPERATURE
T.C.
DRY GAS METER ORIFICE METER
CENTRALIZED TEMPERATURE
AND PRESSURE READOUT
CONTROL MODULE
XAD-2
CARTRIDGE
OVEN
T.C.
IMP/COOLER
TRACE ELEMENT
COLLECTOR
CONDENSATE
COLLECTOR
10 CFM VACUUM PUMP
Figure 1. Source assessment sampling schematic.
-------
cyclones and a filter to collect participates, a
sorbent trap to collect C7 - C16 hydrocarbons,
impingers, and associated temperature con-
trols, pumps, and meters. The sample is ob-
tained from the flue gas duct by means of a
probe inserted through the duct work and posi-
tioned to intersect the gas flow at a point hav-
ing flow characteristics representative of the
bulk flow.
Particulates are removed from the sample
first, passing it through a series of cyclones.
For the SRC tests, these cyclones were main-
tained at a temperature of 400 F. Particulates
are collected in three size ranges, > 10n , 3 to
10fi , and 1 to 3/i , respectively. The cyclones
are followed by a standard fiberglass filter,
which collects a fourth size range, < 1/t .
Gas leaving the filter is cooled to approx-
imately 68°F and passed through a cartridge
containing XAD-2 resin. This resin absorbs a
broad range of organic compounds. Conden-
sate produced when the gas is cooled is col-
lected in a condensate trap.
A series of three impingers follows the resin
cartridge. The first contains hydrogen peroxide
solution, which removes reducing components
to prevent deterioration of the following
impinger solutions. The second and third
impingers, containing ammonium thiosulfate
and silver nitrate, collect volatile inorganic
trace elements.
Next, the gas passes through a dehydrating
agent, to protect the pump which follows.
Finally, the gas flow rate is metered, and the
gas is vented.
Using the SASS train, each test run provided
a total of nine samples, all of which included
solids fractions, condensate, resin, impinger
liquids, and rinses. After weighing, several of
the initial samples were combined for further
analysis. Results will indicate the presence or
absence of several classes of organic com-
pounds as well as inorganic components and
trace elements. In addition to the abbreviated
Level 1 anaysis, the samples will be analyzed to
determine whether or not selected polynuclear
aromatic compounds, having carcinogenic
properties, were present.
Grab samples of the flue gas were collected
using a Tedlar bag and a stainless steel probe.
The samples were extracted from the stack by
means of varistaltic pump, which can obtain
leak-free samples over a short period of time.
On-site analysis was performed (usually within
thirty minutes of sampling) by injecting gases
captured in the sample bag into a gas
chromatograph. Parameters identified included
C-| - C6 hydrocarbons, CO, S02, 02, N2, and
C02.
Daily composites of the coal used during
Phase II and the SRC used during Phase III were
also prepared. Bottom ash samples were col-
lected as well.
Participants in the SRC combustion tests in-
cluded:
• Southern Company Services — co-
sponsor and owner
• ERDA — co-sponsor and supplier of
SRC
• Southern Research Institute (SRI)-
SASS Train Sampling and Resistivity
• TRW — Grab sampling and on-site
analysis for CO, CO2, S02, N2, 02, and
C1 - C6 hydrocarbons.
• York Research — EPA-5 and ASME
trains, gaseous emissions, precipitator
efficiency
• Babcock & Wilcox — Boiler efficiency
• Rust Engineering (Subsidiary of
Wheelabrator-Frye) with SRI — Resist-
ivity;
• Wheelabrator-Frye — modeling of
precipitator for control of SRC combus-
tion particulates
• Hittman Associates, Inc. — Develop-
ment of sampling plan for the SASS
train and grab samples, coordination of
these efforts, and responsibility for
subsequent SASS train sample analysis
and interpretation.
Figure 2 depicts the location of the
precipitator and sampling ports. Boiler #1 was
the test boiler. Load conditions (i.e., full,
medium, and low) were varied daily. During the
first nine days of testing, samples were col-
lected at the inlet and outlet of precipitator #1.
Test ports A,, A2, Bv and B2 were used for
this emission testing. ASME and EPA-5 trains
were used simultaneously to collect samples
both at inlet ports AT or A2, and outlet ports BI
or B2. SASS train samples and grab samples for
on-site analysis were collected either at inlet
154
-------
INLET SAMPLING PORTS
BOILER NO. I
BOILER NO, 2
BOILER NO. ?
PRECIPITATIOR NO.
PRECIPITATOR NO. 2
PRECIPITATOR NO. 4
>NTINUOUS
X SAMPLER
OUTLET
B2 SAMPLING
PORTS
OUTLET
SAMPLING PORTS
PRECIPITATOR NO. 3
INLET SAMPLING
PORT
Figure 2. The location of the boilers, precipitators and
sampling ports at Plant Mitchell.
-------
port A1 or outlet port B-\. Point X indicates the
location of the continuous sampler for monitor-
ing gases such as S02 and NOX.
Since precipitator #1 is a 1946 vintage
Research Cottrell unit with perforated plates,
Rust Engineering and Wheelabrator-Frye re-
quested that two additional days of tests be
performed on precipitator #3, a newer, more
up-to-date,unit. Data gathered could be used in
the future for modeling purposes. To facilitate
these tests, boiler #2 and precipitators #1 and
#2 were shut down. Samples were collected at
ports C, D, ET and E2. ASME and EPA-5
samples were simultaneously collected at ports
C, E1f and E2. SASS train and grab samples for
on-site analysis were collected at outlet port D.
PHASES II & III TESTING
In both Phase II, coal combustion, and Phase
III, SRC combustion, the boiler was operated at
full, medium and low load conditions. In addi-
tion, at the conclusion of Phase III, the boiler
was operated "wide open", approximately
23.5 MW, for several days.
Because only one SASS train was available,
it was impossible simultaneously to collect
samples at both the inlet and outlet ports to the
precipitator. During each phase the SASS train
location was varied to permit sampling at both
ports. During each SASS run, a grab sample for
on-site analysis was collected at the same loca-
tion. EPA-5 and ASME trains operated concur-
rently at both the inlet and outlet of the
precipitator being tested and while the SASS
train was in operation.
The schedules for Phases II and III were
developed by Mr. Richard McRanie of Southern
Company Services after consultation with par-
ticipants. The load condition and test
precipitator were designated for each day of
testing. Tables 1 and 2 indicate these
schedules as well as the sampling location for
the SASS train.
During Phase II, which began May 24, 1 977,
low sulfur Kentucky coal was burned in the
boiler. No significant operational problems
were noted during this phase. The burners
operated as expected and flue gas samples
were collected. Phase II concluded on June 6,
1 977, after eleven days of testing.
Combustion of SRC, Phase III, began on June
10th, 1977. Sampling began on June 13,
1977 and continued through June 24, 1977.
A few additional days of testing were sched-
uled starting June 25th; however SASS and
grab samples were not collected because of the
experiments being conducted. The schedule
called for variation in load levels, air to SRC
feed ratios, and precipitator rapping. Because
TABLE 1
PHASE II • COAL COMBUSTION TEST SCHEDULE
Date
May 24
May 25
May 26
May 27
May 28
May 29
May 30
May 31
June 1
June 5
June 6
Load Condition
Full
Medium
Low
Full
Full
Medium
Medium
Low
Low
Full
Full
SASS Train
Sampling Location
Outlet ESP #1
Outlet ESP #1
Outlet ESP #1
Outlet ESP #1
Inlet ESP #1
Inlet ESP #1
Outlet ESP #1
Outlet ESP #1
Inlet ESP #1
Outlet ESP #3
Outlet ESP #3
TABLE 2
PHASE III • SRC COMBUSTION TEST SCHEDULE
Date
June 13
June 14
June 15
June 16
June 17
June 18
June 19
June 20
June 21
June 22
June 23
June 24
Load Condition
Full
Medium
Low
Full
Full
Low
Low
Medium
Medium
Full
Full
"wide open"
SASS Train
Sampling Location
Outlet ESP #1
Outlet ESP #1
Outlet ESP #1
Outlet ESP #1
Inlet ESP #1
Inlet ESP #1
Outlet ESP #1
Inlet ESP #1
Outlet ESP #1
Outlet ESP #3
Outlet ESP #3
Outlet ESP #1
156
-------
of the short duration of these conditions, it was
impossible to complete a SASS train run which
typically is of five-hour duration.
ANALYTICAL RESULTS
Results of the SASS train analyses are not
available at this time. Figure 3 shows the
planned analytical procedures. Samples from
both Phase II (coal) and Phase III (SRC) runs will
be analyzed. One coal and one SRC sample also
will be tested for trace elements.
Results which are available at this time in-
clude the on-site analyses presented in Tables
3 and 4. Analyses of the coal and SRC, and
calculated emissions are presented in Tables 5,
6, and 7.
The C-| to C6 hydrocarbons were determined
by means of a flame ionization detector in a
Perkin-Elmer gas chromatograph. During the
first three days of Phase II, the test limits were
5 ppm due to improper grounding of the instru-
ment. During the remainder of the tests, the
detectable limit was 0.5 ppm. The 02, N2,
CO and C02 and S02 levels were measured
with a thermal conductivity detector in an
A.I.D. portable gas chromatograph. The ac-
curacy of this instrument is ± two percent of
the reading taken.
NOX and S02 were continuously monitored.
Thermo electron analyzers were used to
measure nitrogen oxides and sulfur oxides. The
accuracy of these instruments is
± 10 ppm.
Results of the on-site analysis of grab
samples are included in the following section of
this report. The following conclusions can be
drawn about SRC combustion:
• When compared on a pounds of S02
per million Btu basis, SRC flue gas
shows only approximately 67 percent
as much S02 discharge as does coal
flue gas, during the course of this test.
• When the coal sulfur content was ap-
proximately the same as the SRC sulfur
content, SO2 emissions per million Btu
were equivalent.
• Pounds of NOX per million Btu are lower
in the SRC flue gas than in the coal flue
gas, by approximately 1 5 percent, dur-
ing the course of this test.
• 02 levels during SRC runs ran slightly
below levels measured in coal combus-
tion. This is directly related to control
room operations. Control room data
will be available later.
• S02 and NOX concentrations were
highest at full load and lowest at low
load conditions.
• f
^1 - C6 hydrocarbons were not
detected during either Phase II or Phase
III. The detection limit for these com-
ponents was 0.5 ppm.
OBSERVATIONS AND CONCLUSIONS
No major problems were encountered with
the combustion of SRC. Generally, the boiler
operated smoothly. On Wednesday, June
1 5th, however, fire was lost in the boiler for
about one hour and the SASS train run was
lost. The cause of the problem was believed to
be failure of the fuel to reach the burner. This
could not directly be attributed to the SRC.
Another run was lost when pieces of
polyethylene sheet, upon which the SRC was
stored, were accidentally scooped up by the
front end loader removing the SRC from the
storage pile, and fed into the pulverizers. The
pulverizers jammed and the run was cancelled.
Results of the test are limited at this time.
Future analytical results will be incorporated in
a final report. The following preliminary obser-
vations can be made. These observations were
made either in the field or during preparation of
samples for shipment to the laboratory.
• Particulates collected by the SASS train
during combustion of SRC were ap-
proximately seventy percent carbon.
This compares with a typical coal fly
ash carbon content of less than ten per-
cent. The high level of carbon is
probably due to the boiler type. This
22-1/2 MW boiler was originally
designed to burn oil, later modified to
burn coal, and further modified prior to
Phase II testing. In addition, since the
ash content of SRC is much lower than
that of coal, identical combustion effi-
ciencies for coal and SRC would result
in a proportionately higher carbon con-
tent in the fly ash, even though the
157
-------
SAMPLE
c^nAnrAHiinir ...,
(jKAB jAMrLL
mrvn OMF
SfYflONF ,._,.,. .,
If*\fft f^> K, ir ______
rii TTP „__. , ,.
PROBE WASH etc ,,
AMU / L.AK 1 KIUL7L ^^
AOUEOUS CONDENSATE —
/*> t> f* A Kl 1 f l?l MC,r . ._
ORGANIC RIN.C COMB(NE
crrr»Mn AKin THIPH
U
1
U~
d"4 z
J^ CO
U UJ
- < ^
£ o o
•— Q£ UJ
^ o £
Q£ *^ ^
s S I
:~
SPLIT
X
"^
\/ \/ COMBINE AND SPLITTING
\ A A OF SAMPLES
v
) )j> SOXHLET EXTRACTION
C"
— O-
) GCFORC7-C,2
> LC-IR-LRMS
PARR/ACID DIGESTION
SSMS
As/Hg/Sb (WET CHEMISTRY
> POLYNUCLEAR AROMATIC
on n
^^ i~\
O~
n ^% ^N
u
IMPINGERS
SRC OR COAL
O — o
Figure 3. Analytical schematic.
158
-------
TABLE 3
ON-SITE ANALYSIS OF GRAB SAMPLES PHASE II • COAL COMBUSTION
MAY 24 TO JUNE 6, 1977
01
to
On-Site
Date
5/26
5/31
6/02
5/25
5/29
5/30
5/24
5/27
5/28
6/05
6/06
r (4) f- (4
Li 4
ND ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
NO'
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
CO'3'
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Gas Chromatograph
13.31%
14.24%
14.91%
15.73%
13.70%
12.60%
13.78%
11.25%
12.14%
11.16%
co2(1)
7.40%
7.50%
6.56%
5.5H
7.59%
7.35%
6.65%
9.86%
9.31%
9.69%
Analysis
N2 ^ !
79.29%
78.26%
78.53%
78.76%
78.71%
80.05%
79.66%
78.89%
78.55%
79.15%
Continuous
Sampler
254
329
174
413
209
413
311
381
214
210
260
360
200
500
220
400
745
330
330
200
180
110
110
100
170
160
150
225
215
220
170
110
Time
1500
1140
0300
1400
1400
1240
1200
1530
1420
1330
1030
Load
Condi
tion
Low
Low
Low
Med
Med
Med
Full
Full
Full
Full
Full
Sample
- Loca-
tion
0-1
0-1
1-1
0-1
1-1
0-1
0-1
0-1
1-1
0-3
0-3
0-3 - Outlet to precipitator - 3
S0x and NO values are in ppm
ND - None Detected
1-1 - Inlet to precipitator - 1
0-1 - Outlet to precipitator - 1
(1) - +_ 2% of total concentration
(2) - +_ 10 ppm
(3) - 40 ppm detectable limit
(4) - 5 ppm detectable limit 5/25, 5/26, and 5/27, 0.5 ppm detectable limit 5/28 through 6/06
-------
TABLE 4
ON-SITE ANALYSIS OF GRAB SAMPLES PHASE III
JUNE 13 TO JUNE 24. 1977
SRC COMBUSTION
On-Site Gas
_,
o>
0
Date
6/15
6/18
6/19
6/14
6/20
6/21
6/13
6/16
6/17
6/22
6/23
6/24
f* \ ' 1
Cl
ND
ND
ND
ND
__
—
ND
ND
ND
ND
ND
ND
c2«>
ND
ND
ND
ND
—
—
ND
NO
ND
ND
ND
ND
c3<"
ND
NO
ND
ND
—
—
ND
ND
ND
ND
ND
ND
c,"'
ND
ND
ND
ND
._
--
ND
ND
ND
ND
ND
ND
C5
ND
ND
ND
ND
—
--
ND
ND
ND
ND
ND
ND
<6("
ND
ND
ND
ND
..
—
ND
ND
ND
ND
ND
ND
co(3)
ND
ND
ND
ND
__
—
ND
ND
ND
ND
ND
ND
Chromatograph Analysis
2
14.79%
13.25%
14.00%
13.65%
11.39%
10.62%
11.11%
11.20%
10.75%
10.76%
co2
5.88%
6.73%
6.26%
7.53%
9.86%
9.12%
9.15%
9.25%
8.90%
9.29%
,,">
79.33%
80.02%
79.74%
78.82%
78.75%
80.26%
79.74%
79.55%
80.35%
79.95%
*>x(1)
198
216
218
248
371
410
404
400
393
449
Continuous
Sampler
».<2)
225
220
235
260
325
335
345
345
325
380
»„"'
125
120
125
160
190
190
190
200
220
260
Time
1030
1200
1230
1200
1300
1145
1100
1030
1000
1100
Load
Con-
dition
Low
Low
Low
Med
Med
Med
Full
Full
Full
Full
Full
23.5
Sample
Location
0-1
1-1
0-1
0-1
0-1
1-1
0-1
0-1
1-1
0-3
0-3
0-1
ND - None Detected
1-1 - Inlet to precipitator-1
0-1 - Outlet to precipitator-1
(1) - +_ 2% of total concentration
(2) - +_ 10 ppm
(3) - 40 ppm detectable limit
(4) - 0.5 ppm detectable limit
0-3 - Outlet to precipitator-3
SOX and NO values are in ppm
-------
TABLE 5
SRC COMBUSTION TEST - PHASE II. COAL
Date
5/26
5/31
6/2
5/25
^5/29
5/30
5/24
5/27
5/28
6/5
6/6
% Sulfur
0.64
1.05
NA
1.09
0.62
1.15
1.34
0.73
0.72
0.66
0.64
Proximate
% Nitrogen
1.38
1.81
NA
1.29
1.82
1.82
1.19
1.51
1.45
1 .60
1.81
Analysis
S0?, ppm
Heating ^
Value. Btu/lb Load
14935
14723
NA
14648
14923
14725
14720
14802
14797
NA
14931
Low
Low
Low
Med
Med
Med
Full
Full
Full
Full
Full
Grab Sample
254
329
174
413
209
403
NA
311
381
214
210
Continuous
Analyzer
260
360
200
500
220
400
745
330
330
200
180
N0y, ppm
110
110
100
170
160
150
225
215
220
170
no
NA - Not Available
(1) Moisture and Ash Free Basis.
-------
TABLE 6
SRC COMBUSTION TEST - PHASE III. SRC
Proximate Analysis
ppm
ppm
Date
6/15
6/18
6/19
% Sulfur
0.70
0.74
0.66
% Nitrogen
1.54
1.80
1.82
Heating (1)
Value, Btu/lb
15742
NA
15668
Load
Low
Low
Low
Grab Sample
198
216
218
Continuous
Analyzer
225
220
235
125
120.
125
o>
to
6/14
0.72
1.62
15729
Med
248
260
160
6/13
6/16
6/17
6/22
6/23
6/24
0.73
0.73
0.72
0.70
0.64
0.66
2.02
1.77
1.47
1.37
1.37
1.71
15591
15602
15775
15647
15534
15505
Full
Full
Full
Full
Full
Wide Open
371
410
404
400
395
449
325
335
345
345
325
380
190
190
190
200
220
260
NA - Not Available
(1) Moisture and Ash Free Basis
-------
oo
TABLE 7
RUN NUMBER, PRECIPITATOR NUMBER 1
Run Number, Preclpltator Number 1
Conditions
Coal
Date
Load, MW
Fuel Feed, Ib/hr
S00 lb/106 Btu
N0x lb/1061 Btu
SRC
Date
Load, MW
Fuel Feed, Ib/hr
S02 lb/106 Btu
NO lb/106 Btu
X
1
5/24
21
22,300
2.33
0.50
6/13
21
17,500
0.99
0.41
2
5/25
14
15,300
1.86
0.45
6/14
14
12,000
1.02
0.45
3
5/26
6
7.400
1.50
0.46
6/15
7.5
7,200
1.21
0.48
4
5/27
21
21,000
1.03
0.48
6/16
21
17,800
0.97
0.39
5
5/28
21
20,000
1.06
0.51
6/17
21
17,600
1.01
0.40
6
5/29
14
15,000
1.84
0.50
6/18
7.5
7,400
1.05
0.41
7
5/30
14
15,000
1.84
0.50
6/19
7.5
7,400
1.13
0.41
8
5/31
7.5
9,400
2.38
0.52
6/20
14
12,000
1.11
0.49
9
6/1
7.5
9,700
1.39
0.50
6/21
14
12,200
1.04
0.45
-------
total carbon in the ash might be the
same.
• The total quantity of fly ash produced
from SRC combustion is approximately
ten percent of that resulting from the
coal normally used at this facility.
• The aerodynamic particle size of SRC
ash was much smaller than that of coal
fly ash. It is estimated that two to five
percent of coal fly ash collected in
Phase II was less than one micron.
Comparably, approximately twenty
percent of the SRC fly ash was col-
lected on the filter following the one
micron cyclone.
It should be noted, however, that due
to the low density of the SRC ash, par-
ticles which should have been collected
by the one micron cyclone instead may
have passed through the cyclone and
collected on the filter. The cyclones in
the SASS train were designed to collect
particles having the density of coal fly
ash, i.e., 1 g/ml. SRC fly ash is approx-
imately one-fifth as dense as coal fly
ash. It was observed that, with SRC,
the filter had to be changed frequently
during each daily test, indicating that
after a certain volume of particulate
was collected in the cyclone, particles
began passing through the 1 micron
cyclone or the particulates collected
were agitated and suspended in air,
finally collecting on the filter.
• The efficiency of precipitator #1 with
SRC ash was estimated by the ERDA
Sampling Team to be at best twenty
percent. The hoppers to the
precipitator were checked and no ash
had been collected. The low efficiency
of the precipitator is probably due to
the low resistivity and density of the
high carbon fly ash.
During the latter part of Phase III, when
precipitator #1, boiler #2, and
precipitator #2 were shut down, the ef-
ficiency of collection by precipitator #3
was significantly higher than observed
with precipitator #1. Partical loading at
the outlet totaled approximately 1
gram. This compares with about 25
grams for a similar full load test at the
outlet to precipitator #1. The filter
following the cyclones did not have to
be changed during tests at the outlet to
precipitator #3. Up to five filter
changes had been needed during tests
at both the inlet and the outlet to
precipitator #1.
There was a visible plume on all SRC
combustion tests using precipitator #1.
The opacity was estimated at
Ringelman 2. However, when only
precipitator #3 was functioning, there
were no visible emissions. During coal
combustion, there was evidence of a
plume on occasion. Boiler #2, which
was shut down when tests were run
around precipitator #3, may be the
cause of the visible plume. It was sug-
gested that without boiler #2 flue gas
feeding into precipitator #3, the unit,
which is oversized, was effective.
• Although approximately equal volumes
of ash were collected from both coal
and SRC combustion, about 50 percent
less fly ash, by weight, was collected
during the SRC tests.
• Some dusting was noted during
handling of SRC. A front end loader
was used to load a dump truck which in
turn emptied into the feed hopper. It
was difficult to assess accurately the
potential magnitude of this problem,
since this method of handling is not
standard operating procedure at the
plant.
Generally, the SASS train performed ade-
quately. On most occasions, representative
flue gas samples were collected. There were,
however, several problem areas.
• The SASS train equipment proved to be
very cumbersome. This problem was
aggravated by space limitations.
• An electrical generator had to be rented
in order that an adequate supply of
electricity (45 amps) was available.
Two runs on Phase III were lost when
the generator broke down.
• The entire SASS train operation, in-
cluding preservation of samples and
preparation of the equipment for the
164
-------
next run, required 10 to 12 hours.
Three men were required for this labor
intensive effort.
As mentioned earlier, the cyclones
were designed to collect particulates
with a density comparable to coal fly
ash. SRC fly ash, which has one-fifth
the density of coal fly ash, may have
passed through the cyclones. This may
explain why filters had to be changed
so frequently. Each time a filter had to
be changed, the run had to be stopped,
the filter cooled and removed, and the
oven reheated. Each filter change re-
quired a delay of up to thirty minutes.
This may have caused an erroneous
particle size distribution since particles
may have passed through to the next
smaller cyclone or to the filter.
Because the particulates were extreme-
ly light and fine, small amounts of par-
ticulate were lost during the subse-
quent transfer to the plastic sample
containers.
Because of the time constraints, it was
impractical to soak the SASS train in
1:1 nitric acid following each run. If
this procedure, prescribed in the
operator's manual, had been followed,
it would have been impossible to both
preserve the samples and prepare for
the next day's operation.
165
-------
ENVIRONMENTAL AND
ENGINEERING EVALUATION OF
THE KOSOVO COAL
GASIFICATION PLANT,
YUGOSLAVIA
by
Becir Salja and Mira Mitrovic
Kombinat Kosovo, Obilic-Pristina
snd
Mining Institute, Beograd-Zemun
Yugoslavia
Abstract
Lignite gasification is presently a worldwide
process. Around the world, researchers are in-
volved in obtaining an improved form of power
from all kinds of coal as well as a more efficient
and economical recovery of the coal substance
itself. In the United States there is also a great
interest in producing a low- and medium-Btu
gas from coal. In this context, an assessment
of environmental problems arising from such
technological processes coupled with the
development of techniques for their reduction
or elimination are of great importance. The En-
vironmental Protection Agency has initiated
and is carrying out a broad research program on
the above problems together with various cor-
porations in the United States.
Within the range of operations of the pro-
gram on Scientific-Technological Cooperation
between the United States and Yugoslav
governments, EPA has also initiated such in-
vestigations in Yugoslavia. Yugoslavia harbors
substantial lignite reserves that are primarily
used for electric power generation. In addition,
great efforts are devoted to the development of
an extremely adequate and economical
technology for lignite processing. In Obilic,
near Pristina, a commercial plant has been
erected and put on stream for gas production
from Kosovo lignite according to the Lurgi Proc-
ess.
This paper outlines the research program car-
ried out in the plant for the production of gas
under pressure with a net heating value of
3600 kcal/mft on the basis of lignite dried by
the Fleissner Process. The plant consists of six
Lurgigasifiers, each 3.6 m in diameter. The an-
nual output is 480 mil mft of clean gas. The
research program includes: process description
(ratio of masses and composition of major
charges and output streams); description of
measurement points; sampling; analysis and
identification of major and minor pollutants;
evaluation of resulting data and methods used
in the investigations; determination of the
amounts of individual pollutants; preparation of
gasification process thermal balance and
preparation of sulphur material balance.
Analysis and identification of pollutants is per-
formed on emissions discharged into the at-
mosphere, waste waters, and solid residues of
the gasification process (dust, slurry, and slag).
Three ambient samples are also analysed.
In addition, the paper indicates the problems
encountered during the conversion of low-
heating value Kosovo lignite into gaseous fuel
by the Lurgi Process.
INTRODUCTION
An accelerated effort is currently underway
in the United States to develop advanced coal
gasification technology to provide an alternate
source of energy. Inherent in the application of
this developing technological area is the need
to assess the environmental problems of these
processes and to develop techniques to reduce
or eliminate these problems.
The first phase of this assessment is the
identification and quantification of pollutants in
existing similar processes. Presently, there are
no commercial coal gasification plants
operating within the United States; therefore,
any investigation must be conducted outside
the borders of the U.S.A.
Preliminary data acquisition from pilot opera-
tions has indicated that a multiplicity of
pollutants are emitted by the gasification reac-
tor. Materials found in effluent and process
streams include major pollutants, such as
sulfur, nitrogen, NH3+ particulate tars and oils,
and minor pollutants, such as trace elements
and hydrocarbons. A comprehensive analysis
providing the composition and levels of major
and minor pollutants found in the process and
various effluent streams will provide a basis for
the determination of the potential environmen-
tal degradation accompanying the gasification
166
-------
process and for the evaluation of currently
utilized clean-up and purification systems.
By initiating test programs in foreign coun-
tries EPA is currently utilizing the various coal
gasification processes and steps are being
taken to develop the methodology and
necessary pollutant control equipment before
the construction of commercial full scale
gasification plants in the U.S.A.
Data acquired in these foreign studies will
supplement information currently being ac-
quired in pilot plant test programs in U.S.A.
In Yugoslavia similar efforts are underway.
Yugoslavia has in situ considerable deposits-
resources of lignite. Although lignite is used
primarily as a fuel to generate heat and power,
at the present time, the research is underway
to develop the most adequate and economical
process technology for conversion of lignite
(fuel of low caloric value) to synthetic gas and
liquid fuels.
In Socialist Autonomous Province Kosovo a
commercial gasification plant has been erected
and is in operation using Lurgi procedure for
gas production from Kosovo-lignite.
All above mentioned facts prove the
significance of the problem. On the basis of the
agreement about scientific and technological
cooperation between American and Yugoslav
Governments, the following organizations:
• Environmental Protection Agency from
the United States of America,
• Rudarski Institut - Beograd, and
• REMHK Kosovo - Obilic, Socialist
Autonomous Province Kosovo,
made out a programme and agreed upon the
project statement for the research project en-
titled: "Environmental and Engineering Evalua-
tion of the Kosovo Coal Gasification Plant."
The research work under this project will be
carried out by:
• Research and Development Depart-
ment REMHK Kosovo - Obilic, and
• Rudarski Institut - Mineral Dressing
Department, Beograd.
The project is to be completed within 3 years
from the date of signing. The project officer is
Mr. Kelly Janes, chemical engineer from EPA,
USA.
The principal researcher is Mr. Becir Salja,
dipl. chem. from REMHK Kosovo-Obilic.
Mrs. Mira Mitrovic, chemical engineer is
responsible for the part of work carried out at
Rudarski Institut.
The objective of the research is therefore to
identify and quantify pollutants in existing
gasification processes in order that improved
techniques can be developed to reduce or
eliminate environmental injury resulting from
implementation of one such technology.
Specific objectives will be the identification of
composition and levels of major and minor
pollutants of all process streams and the iden-
tification and levels of all pollutants in the
various effluent streams or materials (air,
water, solids). Determination of the fate of
pollutants, allowing for the evaluation of poten-
tial environmental degradation, and a study of
the effectiveness of present day clean-up and
purification systems will also be made. Priority
will be given to quantification of major
pollutants, i.e., sulfur, nitrogen, NH^ par-
ticulate tars, and oils in the initial phase (I).
Subsequent investigations will study the minor
or trace pollutants in phase II.
The investigations should result in the selec-
tion of sample analysis methods to be applied.
The following text is comprised of:
• date of Kosovo Lignite Gasification
Plant by Lurgi Procedure,
• investigation Programme (Phase I and
Phase II) and Methodology for deter-
mination of gaseous, liquid, and solid
pollutants contained in air, water, and
solid wastes, and
• observed problems relevant for above
theme.
GAS PRODUCTION FROM
LIGNITE KOSOVO
In Obilic, near Pristina, Socialist Autonomous
Province Kosovo, a plant was erected and
started up for the production of gas under
pressure (clean gas net heating value 3600
Kcal/mjJ) from dried Kosovo lignite (Lurgi
generators, Dia 3.6 m). The plant capacity is
480 million m^ of clean gas per annum,
representing only the first phase of Kosovo
gasification plant. According to the long-term
development program for this coal basin, total
167
-------
gas production should reach approximately
1 500 million mjj per year.
The specific purpose of the gas as a power
fuel for the requirements of Steel Works Skopje
and surrounding industry, i.e., as a raw
material for nitrogen fertilizer production in
Obilic, was significant in deciding on the erec-
tion of the gasification plant in Kosovo Basin.
The Kosovo Basin Gasification Plant includes
the following sections:
• gas generators: 6 generators with a
capacity of 18,000 mfg of crude gas
each, with coal feeding and slag
disposal arrangements,
• condensation,
• "rectisol" installation for gas cleaning
with gas delivery station,
• air decomposition plant,
• tar and medium oil separation,
• "phenosolvent" installation for phenol
separation, and
• installation for biological wastewaters
cleaning.
Gasification plant feed consists of dried
lignite according to the "Fleissner" method
with a size range -60 + 6 mm.
Of the mentioned amount (480 • 10
m^/year), 77 percent is further processed in
order to remove the hydrogen required for am-
monia synthesis. The residue is a methane
enriched fraction mixed with the remaining
clean gas. This mixture (256 • 106 nr^/year)
represents the pipeline gas with a net heating
value of 4000 Kcal/m^/year, supplied into the
gasline system.*
Material and Power Balances of Kosovo Lignite Gasification*
Feed
6
86t/h
688,000 t/year
Dried coal
(-60+6 mm)
95 percent 11,560 Nm3/h 92.5 x 106 Nm3/year
oxygen
Steam,
30atm
Electric
74 t/h
9,730 kWh
592,000 t/year
77,840 MWh/year
power
Phenosolvent
(diizopropi-
lether)
Methanol
Hydrocloric
acid
Sodium-
hydroxide
Aluminum
sulphate
Output
Cleaned gas
Tar
Oil
Crude gasoline
Gas water
4kg/h
2.5 kg/h
2.5 kg/h
60,000 Nm3/h
2.2 t/h
1.0 t/h
7.5 t/h
90 Nm3/h
Carbon dioxide 25,000 Nm3/h
"Data taken from the project.
32 t/year
20 t/year
20 l/year
480x106Nm3/year
17,600 t/year
8,000 t/year
60,000 t/year
720,000 m3/year
200x106Nm3/year
Note:
a.
56 kg/h
448 t/year
PROGRAM OF INVESTIGATION
The research program includes the following
tasks:
Phase I:
1. Process description (ratio of masses
and composition of major feeds and
outlet streams),
2. Sampling and analysis of major
pollutants occurring in large quantities,
determination of mass ratios and com-
positions of major feeds and outlet
streams.
Sampling is carried out simultaneously
on all measurement points while the
plant is operating under constant condi-
tion over an 8-hour period. The
samples are divided and processed in
two laboratories,
b. Sampling campaign completed accord-
ing to the following schedule:
• test run,
• first campaign,
• second campaign,
• third campaign, and
• repeated testing if required.
3. Evaluation of test data acquired by pro-
cessing the pollutants occurring in
large quantities and the methods used
during the tests.
4. Identification of trace pollutants (Phase
II).
5. Evaluation of data acquired by process-
168
-------
ing the pollutants occurring in small
quantities and evaluation of the effec-
tiveness of methods used for analyses
(Phase II).
6. Heat Balance for Gasification Process
on the basis of determined statistical
data on the amounts and heating value
of the coal consumed for:
a . gasification (dried lignite)--
generators
b . heat generation (raw mine coal)--
steam production for the
generators, etc.
as well as for:
c . the heat consumed in the gasifica-
tion process, and on the basis of
determined calories in:
d . the produced gas, and
e . liquid products.
Lignite heat recovery will be calculated for
the Lurgi process of gasification.
7. Sulphur material balance in the process
of Kosovo lignite gasification:
a . Feed:
• Coal
b . Outputs:
• synthesis gas and medium BTU
gas,
• tar (storage),
• medium oil (storage),
• gasoline (storage),
• phenol (storage),
• discharges into the at-
mosphere,
• waste waters,
• gasification slag (disposal
area), and
• heavy tar and coal dust
(disposal area).
8. Final report with the evaluation of the
technological process and environmen-
tal pollution, from Kosovo lignite
gasification by "Lurgi" procedure and
possible improvement proposals.
Pollutants determination includes:
a . Control of Air Emissions
Analyses:
H2S
Phenols
Ammonia
Particulate
C02
sox
COS
NOX
Hydrocarbons
b . Control of Generator Wastewaters
Analyses:
COD
BODs (dilution method)
Permanganate Value
Phenols, volatile and nonvolatile
Ammonia, free and fixed
Cyanide
Hydrogen sulfide
Tar oil (ether extracts)
Suspended solids
Dry solids (105° C and 850° C)
pH value
Chloride
Sulfates
Rhodanate, Thiosulfates
Fluorides, Nitrites, Nitrates,
Sulfites
c . Control of Solid Wastes from the
Coal Gasification Process (Sludges
and Dusts from Gas Purification
Slag and Ash)
Analyses:
Moisture
Dry solids (105° C and 850° C)
Ash composition
Phenol, total and volatile, in water
filtrate
Elementary analysis of dry material
(105° C)
COD (water filtrate)
BOD (water filtrate)
Notice'. All pollutants will be determined as to
ASTIM procedure.
In studying the foregoing research program,
due consideration should be paid to the follow-
ing:
• Location of sampling points, fitting the
required sampling connections, and in-
stallation of platforms and accesses for
sampling.
• Repair and calibration of all equipment,
purchased and borrowed, in order to
secure adequate operation.
• Preparation of test schedule, together
with a list of sampling methods,
169
-------
methods for sample preparation and
selection of analysis methods (ASTM).
• Compilation of plant operative data
over the test period.
• Provision of the equipment required for
the analysis of samples, representative
samples will be taken and appropriately
preserved. Repeated double analyses
will be performed.
• Regular preparation of reports on the
results of works during a reasonable
period upon analyses completion.
Specific key streams will be sampled in the
Kosovo Coal Gasification Plant, and ap-
propriate analyses will be carried out in
accordance with the information supplied
below:
Figure 1 --Sampling points (plant streams and
ambient)
The samples presented in Figure 1, found
enclosed, are considered the most useful ones
for initial research in this plant. A total of 19
sampling points has been located for gaseous,
liquid, and solid samples. Table 1 (enclosed) in-
cludes the sample to be taken, required stream
measurements, analyses of trace elements and
trace organic materials, GCMS, HPLC, and AA
analyses and size comprise determinations.
General locations of area sampling points are
also indicated on Figure 1. Three area samples
are to be taken at locations to be selected.
In area samples (three), the following com-
ponents will be determined by use of ap-
propriate methods:
ANALYSIS
CO
NOX
S02
H2S
COS
CS2
Mercaptans
HC
Particulates
Organ ics
METHOD
NDIR
Chemi luminescent
FPD/GC
FID/GC
Hi Vol
XAD-2/GCMS
DESCRIPTION OF THE
TECHNOLOGICAL PROCESS AND
SAMPLING POINTS IN COAL
GASIFICATION PLANT KOSOVO
Figure 1 presents the flow sheet of Coal
Gasification Plant Kosovo and the sampling
points in the process streams and area.
Sampling will be carried out in the following
plant sections:
• Generators (Figure 2),
• Condensation and tar separation
(Figures 3 and 4),
• Rectisol (Figure 5),
• Phenols separation (Figure 6),
• Cooling water air cooling system, and
• Storage (Figure 7).
In addition, three area samples will be taken
on plant site.
Sections not included in sampling:
• Coal drier,
• Air decomposition,
• Biological water cleaning,
• Heating plant, and
• Water preparation.
Generator Section
The Generator Section (Figure 2) performs
the gasification of coal according to the Lurgi
process. The dried coal of class -60 + 6 mm is
fed by conveyor belts to the coal bin (1). In the
bin, the coal is protected by nitrogen at-
mosphere. By the coal lock bucket (2) the coal
is fed into coal lock (3) and further into
generator (4). In the generator, the coal is
gasified in the presence of stream and oxygen.
The crude gas formed is lead first through the
cooler with direct water injection (5), and then
through two indirect coolers (6) and (7) and
supplied to the Condensation Section. From the
raw gas, condensates and high boiling points
(tar) are separated in the coolers, as well as one
part of the carried dust and contained water
vapour. This tar gas liquor is fed into the gas
liquor tank (15) and gas liquor gate (16) at
start, i.e., directly to the tar separation section.
The ash and a part of unreacted coal are
discharged from the generator through the ash
lock (9) and ash chamber (10) into the
quenching bath, and then to the disposal area.
Since the locks (3) and (9) are under pressure,
their charging i.e., discharging requires partial
170
-------
LESC«O:@ SAMPLING fOINr {?} AHSIEHT AIR
Figure 1. Process flow diagram for gasification process in Remhk Kosovo.
171
-------
TABLE 1
SAMPLE SCHEDULE
1 Coal Feed
2 Co.il drying - vent gases
2A Coal drying • condcnontc
3 Coal bin vent gases
CASIFIER
It Lou Raw Can
5 Ash
QUENCH SYSTEM
7 CJ3 to Incinerator
8 Oil
9 Tar
10 llc.ivy tar + sol Ida
11 Raw gaii utter cooler
RECTISOL
12 HjS vent gas
13 C0» vent gas
14 Clean gaa
15 Condcnsatc
19 Benzene/light oil
PIIESOSOLVAN
16 Inlec water
17 Outlet water
18 Vent
Sample
Composite
F+C
Composite
F+C
F4C
Comjioslte
FHC
Composite
Composite
Compoottc
FtC
F+C
F-t-C
F+C
Composite
Composite
Composite
Composite
C
Flow
X
.
-
X
X
X
GO
X
X
X
jxl
X
X
X
X
X
X
-
LU
Trace
elements
6 SMS
X
X
X
X
X
X
-
X
X
X
X
-
-
X
X
-
X
X
•
Trace
organlcs
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
CCM5 HPLC
.
X
-
-
-
-
X
X
X X
X X
X X
X
X
X
X
X
X X
X X
X
Particle
M size
X
grain
X -loading
only
X
X
X
-
X
X
X
grain
X X -loading
only
-
-
0
-
-
X
-
» •
QTJ - If possible.
(x) - Particles shall be collected and nnalyzed only If particleo are found In the produce gas at Point 11.
F+C - Sampling train vlth filter and XAD-2 cartridge.
C - Cartridge only.
-------
TO WASTE GASES
INCINERATOR
RAW GAS 70
COQLING SECTION
GENERATOR
PI ANT VENT
WATER+ DUST
COAL LOCH
8UCKfT
VENTURI
SCPUBBR
>D 6 AS
LIQUOR
GAT£
14 WAJEff
FEdDINGS
STATION
ATER FROM
WASHING
WASTE WATER TO RIVER SITNICA
ASH CHAMBf-R
ASH TO
DUMP
WASTE WAJCK ' rUMSFEU POINT
TO TAff SEMVAT/OU
P LAN*
Figure 2. Process flow diagram and sampling points in generator plant.
-------
decompression. During coal lock decompres-
sion, prior to charging with coal, the gases are
lead through venturi scrubber (8) to waste
gases incinerator (up to a pressure of about 2
atm), and then through generator vent (up to
atmospheric pressure). Coal lock bucket
decompression is carried out through a
separate vent at each coal charge. Before ash
discharge from the ash lock, decompression is
carried out through wet dedusting cyclone
(11). For the dedusting of transfer points dur-
ing the feed of coal bunkers, a ventilation
system is provided with wet dedusting of the
suction gases in cyclone (14).
The wastewaters from cyclones (11), (14),
ash quenching baths, belt washing at the I ash
transfer point (12) and feed water station are
collected in a common sump and delivered to
the River Sitnica.
The grade of lignite -60 + 6 mm, dried by
"Fleissner" method, is as follows:
Proximate and ultimate analysis:
Moisture
Ash
S total
S bound
Coke
Cfix
Volatile:
Combustibles
Heating value
Gross Kcal/kg
Net, Kcal/kg
Carbon
Hydrogen
S combustion
N + 0
Operating
moisture
26.62
14.78
0.97
0.80
40.37
25.59
33.01
58.60
3,647
3,358
40.17
2.91
.0.17
15.35
Operating Moisture Moisture
moisture free & ash free
22.0
17.71
1.03
0.85
42.91
27.20
35.09
62.29
3,877
3,604
42.70
3.10
0.18
16.31
—
20.14
1.32
1.09
55.01
34.87
44.99
79.86
4,970
4,775
54.74
3.97
0.23
20.92
—
—
1.66
1.37
43.67
43.67
56.33
100.00
6,223
5,979
68.55
4.97
0.29
26.19
(Dried Kosovo lignite, size -60 + 6
Operating moisture
Tar
Gas water
Semi coke
Gas + losses
7.20*
5.82
9.00
62.30
15.68
mm)
"
6.27
9.70
67.13
16.90
"Partly dried sample.
Analysis of dried Kosovo lignite ash, size - 60
+ 6 mm:
Analysis of dried Kosovo lignite ash, size
Components
Si02
Fe203
AI203
CaO
MgO
S03
P2O5
Ti02
Na20
K20
MnO
-60 +6 mm:
%
25.01
6.84
6.73
36.03
6.33
16.13
0.34
0.51
1.58
0.40
0.14
Base-to-acid ratio = 1.58
Ash fusibility:
(oxidative atmosphere)
Initiation of sintering
Softening temperature
Hemisphere temperature
Flow temperature
970e C
1130°C
1290° C
1300°C
Low-temperature carbonisation analysis ac-
cording to Fischer at 520° C:
Each generator unit consists of six generator
vessels, 1, 2 through 7, 9, and 10, an ash
bath, vents of coal lock buckets and generator
vents, two dedusting cyclones 14 and one
vessel 8, 15, 16, 11, one ash transfer point,
one feed water station and one generator sec-
tion vent (forced expansion vent).
The research program includes determina-
tions of the composition of gases from:
• Coal lock bucket vent (3.1)
174
-------
• Dedusting cyclones (2.2)
• Generator vents (3.2)
• Generator section vent (3.3)
• Ash lock expander cyclone (3.5)
• Tar gas water vent (3.4) and gases to
waste gas incinerator (3.6).
Pollution determinations will also be made for
coal supply rooms (2.1) and the surroundings
of uncomplete ash lock decompression (1 2.1).
In addition, determinations will be made of the
amount and composition of ash (12.2), and
quality of wastewater from the generator sec-
tion (12.3).
Information on the sampling points in the
plant is given below.
Sampling points - Section Generators
1. Sampling point No. (2.1): in coal supply
room:
• major pollutants: escaped dust and
possibly gases form coal bunker,
• cause of pollution: supply of finer
coal fractions and insufficient ef-
ficacious dust removal system from
critical points,
• measurement magnitudes: dust
content in the air and air analysis,
• measuring points: transfer point on
level 37 m, transfer point on level
35 m.
Note: Periodically pollution is very high.
2. Measurement point No, (2.2):
Dedusting cyclone discharge into the
atmosphere:
• major pollutants: as under item 1,
• cause of pollution: insufficient ef-
ficacious dedusting and possible
escaped gases from the
generators,
• measurement point: on fan house
roof, two fans, discharge tube Dia
1 500 mm, and
• measurement magnitudes: dust
concentration and air analysis.
Note: Current system of six united and con-
nected suction points on a single fan insuffi-
ciently efficacious, resulting in low discharge
into the atmosphere.
3. Measurement point No. (3.1): coal lock
bucket decompression:
• major pollutants: water vapour,
gases from generators, and coal
dust,
• cause of pollution: technological
solution of discharging the gases
into the atmosphere,
• measurement point: outlet into the
atmosphere designed on building
roof, but current outlet on level 25
away from the building on the plat-
form. Sampling point pipe Dia 3".
Steam discharged under pressure.
4. Measurement point No. (3.2):
Generator vent (small flare):
• major pollutants: flue gases upon
treatment inclusive cooler AK II 2 h
after start, gases from generators
during coal lock expansion from 2
kp/cm2 to atmospheric pressure
and flue gases upon generator ex-
tinguishing (burning out after water
vapour action in absence of air or
oxygen about 24 h after shut
down), gases from coal lock during
every coal charging,
• measurement point: outlet into the
atmosphere on generator section
roof, but more suitable sampling
point on level 25 in pipe straight
run, requiring fitting.
5. Measurement point No. (3.3):
Generator Section vent (large flare):
• major pollutants: gases from
generator during startup feeding
the first amount of coal into the
generator and until pressure
reaches 6 atm. (up to 7 days), and
waste gases from tar gas liquor
tank into which the condensed pro-
ducts are returned collecting all
spoiled waters from the Generator
Section,
• cause of pollution: technological
solution of discharging the gases
into the atmosphere,
• measurement point: platform on
level 35 m outdoors, and
• measurement magnitude: gas com-
position.
Note: According to the design, the Generator
Section vent is used for all the six generators
and collects all other gases from leaking valves.
6. Measurement point No. (3.4): Vsnt
175
-------
from tar gas liquor and all Generator
Section waste waters tanks:
• major pollutants: phenols and
higher hydrocarbons, H2S,
• cause of pollution: technological
solution of discharging the gases
into the atmosphere, and
• measurement point: on Generator
Section roof (unsuitable) or TGV
outlet.
7. Measurement point No. (3.5): Vent
from lock expander cyclone:
• major pollutants: gases from ash
lock expander and finer ash,
• cause of pollution: technological
solution providing the discharge of
ash lock expander cyclone into the
atmosphere,
• measurement point: on Generator
Section roof, or outlet of cyclone
on 9 m level, and
• measurement magnitudes: gas
composition.
Note: Technological design provides one ex-
pander for six ash locks with cyclone
dedusting.
8. Measurement point No. (3.6): Coal lock
expansion gases— major pollutants:
generator gas during start (above 6
atm) and gases from coal lock during
expansion to 2 atm:
• measurement point: ahead of ven-
turi scrubber, and
• measurement magnitude: gas com-
position.
9. Measurement point No. (12.1): Pollu-
tion due to incomplete ash lock decom-
pression:
• major pollutants: gases from ash
lock and ash,
• cause of pollution: inadequate solu-
tion of the system for ash lock
pressure control,
• measurement point: ash quenching
bath, level 0, and
• measurement magnitude: gas com-
position and ash content in the gas.
10.Generator Section wastewaters
(12.3): water from ash quenching
baths, dedusting cyclones, expander
cyclones, ash lock, ash belt washing
water at I transfer point and cleaned
water from fire hydrant system are
combined in a very unsuitable sump, so
that wastewaters' quantity determina-
tion is impossible, but the quality may
be determined quite readily.
11. Gasification slag (12.2): Measurement
of the amount of slag may be perform-
ed by removing from the belts or at the
first transfer point, when sampling can
be made.
Gas composition at AKII outlet
C02
H2S
CmHn
CO
H2
No
NH3
NCH
Sorg
Gasoline
Tar
Medium oil
Dust
Water
29 - 32 vol. - %
0.6 vol. - %
0.75 vol.-%
12-15 vol.-%
40 - 42 vol. - %
3 vol. - %
0.25 vol. - %
o
5 - 7 g/100 Nm on dry basis
5-7g/100Nm3ondrybasis
20 g/100 Nm3 on dry basis
7g/100Nm3ondrybasis
21 - 25 g/100 Nm3 on dry basis
18-20 g/100 Nm3 on dry basis
0.1 g/100 Nm3 on dry basis
400 - 500 g/100 Nm3 on dry basis
Condensation Section
In the Condensation Section, Figure
3, cooling and cleaning of the
generator gas takes place. The section
consists of three identical units, each
containing a tar separator, four parallel
countercurrent coolers, and a drop
separator. The gas is further fed to the
Rectisol Section, while the two
separated intermediate products are
supplied for tar, i.e., medium oil extrac-
tion.
According to the technological flow-
sheet there is no direct environmental
176
-------
COOLING WATER
RAW GAS FROM
GENERATOR PLANT
I TAR SEPARATOR
II. III. IV, V COOLERS
VI DROP COLLECTOR
a
1
m
3D
I
r
1
1
FAR + PHENOLIC WATER
RAW GAS TO RECTISOL
. MEDIUM OIL + PHENOLIC WATER
Figure 3. Cooling section process flow diagram
-------
pollution, except in the case of natural
expansions and possible leakages.
Tar Separation Section
1n the Tar Separation Section, Figure
4, liquid products from the Generator,
Condensation, and Rectisol sections
are separated. Tar and phenolic water
of high pressure (from WK, AK I, and
AK II) flow through preexpander {1}
and expander (2) into the tar separator
(3), while the other waters, including
the cyanidic water from Rectisol Sec-
tion, are fed directly to the tar
separator. From the tar separator, the
lightest tar fraction is delivered to the
-------
6ASES
TAR
PHfHOUC WA TEH
MSDH/M OIL
RETURN
TAR TO
GENCMTOR
PLANT
TO D(/MP
TO TAR
STEAM
VENT
'14 UMPURE OIL
RfCIRtUlATEO
V£NT
COOlIMC WATCH
5AT£
VCfIT
TAR
VENT
MEDIUM OIL
TAHK
JO
FHOM REC7I30L
COOLING WATfft
Wj
-w
O
o
RflfASFO 6ASfS
TO IHCINtRATOf(
VCNT
i_JS>
TANK
WAT£ft
70
PLAHT
JAR TO STOffAOt
Vtvr
TANK
)
J
on
To
Figure 4. Process flow diagram and sampling points in tar separation plant.
-------
point: vent on platform on level 3 m,
pipe Dia 1 50 mm.
RECTISOL SECTION
The Rectisol Section (Figure 5) performs gas
cleaning with water and methanol primarily
from gasoline, C02 and H2S, as well as the
regeneration of spent methanol.
The gas delivered from the Condensation
section passes through the drop separator (1)
and flows into first stage gas cooling in the bot-
tom section of column (2). According to the
design, the gas should be washed with a mix-
ture of gasoline and water, but currently only
cold water is used. From the bottom section of
column (2), the gas flows to the second cooling
stage with methanol and purified gases in
cooler (3) and column (2) upper section.
Methanol with gas condensates from the lower
part of column (2) upper section serve as the
cooling and antifreezing agent in cooler (3)
where the clean gas is heated. The cooling
methanol for column (2) upper section comes
from the bottom of column (5). The cooled gas
freed of gasoline is fed for further cleaning
(primarily from H2S) to column (4). The
methanol for above washing also comes from
the bottom of column (5). Further gas cleaning
develops in column (5) primarily of C02. The
methanol for cleaning in column (5) comes
from the bottom of regeneration column (14),
i.e., from the bottom of the fourth stage of
regeneration column (15) and the bottom of
column (6). The clean medium heating value
gas may be delivered from column (5) to the
gas station being previously heated in heat ex-
changer (3), or fed for purification in column
(6). The methanol for gas purification in column
(6) is freshly added, or supplied from the bot-
tom of column (14) and the fourth stage of col-
umn (1 5).
The water containing gasoline from the lower
part bottom of column (2) is fed to separator
(7), and the gasoline is delivered through tank
(8) to the storage, and the water together with
cyanic water to the tar separation section. The
expansion gases from separator (7) are lead to
the collection line of rich waste gases.
The methanol containing gasoline from the
bottom of heat exchanger (3) is supplied to ex-
pander (9) and then to extractor (10). The
gasoline fraction is separated from the water-
methanol solution in the extractor. The
gasoline is fed to tank (8) and the methanol
water solution first to distillation column (11)
to remove the residual gasoline, and then to the
rectification column (12) to separate the
methanol from water. Stripping nitrogen is fed
to the top of column (12), and NaOH through
the bottom primarily to neutralize the free
hydrocyanic acid. The impure methanol
vapours are fed to expander (9), and the clean
methanol fumes to column (14).
The methanol from the bottom of column (4)
is supplied to column (13) for regeneration in
succession to stages I, II, III, and IV. The expan-
sion gases from column (13) first stage are
combined with those in the rich waste gases
line, and the waste gases from the remaining
stages into the common H2S gases line. Into
the upper section of column (13) fourth stage
the gas-released waste gas in column (14) is in-
cluded. The methanol from column (1 3) fourth
stage bottom, the condensed methanol from
column (14) waste gases and water vapour and
methanol fumes from the top of column (12)
are fed to column (14). The purified methanol
from the bottom of column (14) serves for gas
cleaning in columns (6) and (5). The waste
gases from column (14) are fed the upper part
of column (13) fourth stage. The methanol
from column (5) bottom is partially supplied to
columns (2) and (4), and partially to regenera-
tion column (15). Column (15) is divided into
four stages, and the methanol passes through
all the stages in succession. The expansion
gases from column (1 5) first section are lead to
the common rich waste gases line. The waste
gases from remaining stages are combined and
fed to the C02 waste gases vent. The amount
of above waste gases may be obtained by sum-
mation of the amounts of gases from FR 39 and
measured amounts at fitted measurement
points FE 33 and FE 28. The rich waste gas
amount consisting of expansion gases from
column (9), separator (7) and first stages of
columns (1 3) and (1 5) may be read on recorder
FR 27. The amount of H2S waste gas may be
determined by summing the measurements at
fitted points FE 21, FE 22, and FE 23.
180
-------
HjS GAS TO
^ INCINERATOR
TO CO2 VENT
CLEAN GAS
TO NH3 SYNTHESIS
Cyanic Water
to Tar Separation
CONDENSATE
flAW GASOLINE
EVAPORATED METHANOL
Figure 5. Process flow diagram and sampling points in Rectisol plant.
-------
Having in view that the lines of rich waste
gas and waste H2S gas are combined and lead
to the waste gases incinerator, their amount
may be obtained by summing individual gas
streams. The program of activities provides for
the determination of the quality of inlet and
outlet gases of Rectisol Section, C02 waste
gases, H2S waste gases, and waste gases
under Rectisol Section incinerator.
Sampling points data are as follows:
Sampling Points-Rectisol Section
1. Measurement point No. (7.1): H2S
waste gas:
• major pollutants: H2S, metha-
ne,and other hydrocarbons,
• cause of pollution: technological
solution providing combustion of
the gases by waste gases in-
cinerator before discharge into the
atmosphere,
• measurement magnitudes: gas
composition and volume, and
• measuring point: methanol recycle
line at E4/5, level 0, connection
line on valve dia 8 for analysis. The
amount of gases obtainable by
summing the amounts of gases
measured at fitted measurement
points FE 23, FE 22, and FE 21.
Platforms available on level 10 for
mounting the measurement in-
struments.
2. Measurement point No. (7.2): C02 -
vent line:
• major pollutants: in addition to
C02, methanol, H2S and higher
hydrocarbons.may be present,
• cause of pollution: direct discharge
of the gases into the atmosphere,
• measurement magnitudes: gas
composition and amount,
• measuring points: analysis sample
at G5, Dia 10 mm. The amount of
gases obtainable by summing the
values measured at fitted measur-
ing points FE 28, FE 33, or by
measuring the total amount by a
Pitot tube in the line at G5,
dia. 1000, level 0 (fitting required).
3. Measurement point No. (7.3): Rectisol
Section incinerator:
• major pollutants: during proper in-
cinerator operation no pollutants
should be generated,
• cause of pollution: technological
solution provided burning the gases
from generators if Rectisol Section
out of operation, or cleaned gases if
further gas transport prevented,
burning of evaporates from
gasoline, methanol, and two
"slop" tanks,
• measuring points: (when in-
cinerator unoperative) gas at rec-
tisol inlet - sample at PRCX, dia.
10, i.e., clean gas at E1, dia. 10,
i.e., methanol and benzene fumes,
and
• measurement magnitude: gas com-
position.
The Rectisol Section has no direct discharges
of waters into the surroundings.
Expected H2S waste gases composition at
measurement point 7.1.
C02 57.25-49.75 vol.-% i.e.
CmHn 0.575 - 0.675 vol. - % i.e.
02 0.175-0.3vol.-%i.e.
CO 3.225-7.050 vol.-% i.e.
H2 18.35-36.9 vol.-% i.e.
CH4 9.45 -15.6 vol. -% i.e.
N2 1.8-2.2 vol.-% i.e.
H2S 1,034- 629 g/100 Mm3
NHV 2,170-2,252 Kcal/Nm3
37-88 vol.-%
0.5 • 1.2 vol.-%
0.1-0.3vol.-%
0.9 - 7.2 vol. - %
1.4-39.6 vol. -%
6.6-15.6 vol.-%
1.8-2.2vol.-%
682-1,920
g/100 Mm3
970 - 2,680
Kcal/Nm3
Expected composition of gases to C02 vent
at measurement point 7.2.
co2
CmHn
°2
CO
H2
54 - 86 vol. -
0.4 - 1 vol. - <
0.1 -0.3vol.
6.6 - 2.8 vol.
19.8- 3.8 vol
182
-------
CH4 17.4-6.7 vol.-%
N2 2.8-0.2 vol.-%
H2S 400-1,200g/100Nm3
Designed composition of the gas at Rectisol
Section inlet: measurement point 7.3.
co2
H2S
CHn
m n
CO
H2
CH4
N2
°2
NH3
HCN
S
Gasoline
Medium
oil
Dust
Water
29 - 86 vol. - %
0.60 vol. - %
0.75vol. -%
12 -15 vol. -%
40 - 42 vol. - %
11 -13vol. -%
3 vol. • %
0,35vol. %
5-7g/100Nm3
5-7g/100Nm3
20g/100Nm3
7 g/Nm3
2 g/Nm3
0.1 g/Nm3
1.3 -1.4 g/Nm3
Designed quality of pipeline gas at measure-
ment point 7.3.
co2
H2S
CH4
CmHn
m n
CO
H2
N2
NHV
2.0 vol. - %
2.0 vol. - ppm
16.1 vol. -%
0.5 vol. - %
19.4 vol. - %
58.2 vol. - %
3.8vol. -%
3,800 Kcal/Nm3
C02 approx. 61 - 37 vol. - %
H2 approx. 24 - 39.6 vol. - %
CH4 approx. 10.4-15.6vol.-%
CmHn approx. 0.6-0,5 vol.-%
02 approx. 0.2 - 0.3 vol. - %
CO approx. 4-7.2vol.-%
H2S 1,100-682g/100Nm3
NHV approx. 2,000 - 2,680 Kcal/Nm3
Expected composition of gases from column
(1 3) and column (1 5) first stage:
CO2
CmHn
°2
CO
H2
CH4
N2
H2S
NHV
46 - 88 vol. - %
0.5- 1.2vol.-%
0.1 -0.3vol.-%
0.9 - 6.6 vol. - %
1.4-28.8 vol. -%
6.6 - 15.6 vol. - %
1.8-2.2 vol. %
835- 1,910 g/100Nm3
2,680-970 Kcal/Nm3
Expected composition of gases from ex-
pander (7) and separator (7) combined:
PHENOSOLVAN SECTION
The Phenosolvan Section (Figure 6) serves
primarily for the removal of a major part of
phenol from phenolic waste water prior to final
biological treatment. According to the design,
butylacetate should be used as the extracting
agent, but currently diisopropylether is used in
REMHK Kosovo for phenol extraction.
The phenolic water is fed into cyclone (1) for
treatment with C02 (currently no C02 injection)
and then passed to tank (2) for the separation
of residual oil and tar from phenolic water. The
impure oil is delivered through tank (3) to the
storage, while the tar is directly fed to the Tar
Separation Section. The phenolic water is sup-
plied through sand filters (4) to two surge tanks
(5) and then upon heating in heat exchanger (6)
to degasing column (7). Reheating of phenolic
water takes place in column (7) lower section.
Prior to entering column (9) upper section.
183
-------
PRECLEANING
YEHT
ff/vr
VENT
SEfflRAION
OHZOfROP/LETfd
EXTRACTION
15
00
ro a/o
13
12
veivr
01/20fIfOflLiTf/H PHENOL
(I « I)
fVAPORATEO OUZOPRQPIlFTZt
I I 120
Di$TlLLAT\oN
17
PHEVOL,
ro
19
A - J; - r\
VI Nl
OU20PtOPILrfEfl_
23
i)
Figure 6. Process flow diagram and sampling points in Phenosolvan plant.
-------
where additional gases release is completed,
the phenolic water is cooled in cooler (8). The
phenolic water from "slop" tank (10) is also
fed to column (9) upper section. The cold
phenolic water, free of gases, is fed for extrac-
tion to extractors (11), and then to heat ex-
changer (12) for heating and distillation from
conveyed diisopropilether in distillation column
(13). From column (13) the cleaned phenolic
water is delivered through cooler (14) to the
section for biological waste waters treatment.
The diisopropilether fumes are condensed in
cooler (15) and fed combined with the
diisopropilether from surge tank (21) to the ex-
tractor. The raw phenol extracted in
diisopropilether is supplied through surge tank
(16) for heating in heat exchanger (17) and
then to rectification columns (18) and (19).
The diisopropilether fumes are condensed in
cooler (20). The condensed and fresh
diisopropilether supplied from tank (22) are fed
to tank (21) and supplied to the extractor. The
raw phenol from the bottom of rectification col-
umn (1) is delivered through cooler (23) and
tank (24) to the storage.
The gases from column (7) lower section are
partially condensed in cooler (25) and am-
monium fumes in column (26). Tank (27) is
provided for aqueous ammonium solution. Cur-
rently, units (26) and (27) are inoperative and a
water vent was fitted between units (25) and
(26). Condensate water fraction is recycled to
column (7) lower section, and the oil one to
tank (3). Units 1, 2, 3, 5, 7 (upper section)
directly and the lower one through coder (25),
(9) (upper section), 10, 22 and 24 are con-
nected by vents with the atmosphere, and our
program of activities envisages the determina-
tion of discharge gases composition.
Information on section sampling points:
Sampling Points-Phenosolvan Section
• Cause of pollution: technological solu-
tion providing the discharge of the
gases into the atmosphere through
separate vents.
1. Measurement point No. (14.1):
Cyclone vent (Figure 6):
• major pollutant: phenol fumes,
• measuring point: cyclone vent at
top of K2, and
• measurement magnitude: gas com-
position.
2. Measurement point No. (14.2): gas
liquor tank (Figure 6) separation of tar,
oil, and phenolic water:
• major pollutants: phenol, oil, tar,
and ammonium evaporations,
• measuring point: tank roof lid, Dia.
500 mm, and
• measurement magnitude: gas com-
position.
3. Measurement point No. (14.3): Impure
oil tank (Figure 6):
• major pollutant: oil evaporations in-
cluding H2S,
• measuring point: filling funnel, level
0, Dia. 200 mm, and
• measurement magnitude: gas com-
position.
4. Measurement point No. (14.4):
Phenolic water tank (Figure 6):
• major pollutant: volatile phenols,
• measuring point: lid on tank roof,
dia. 500 mm.
5. Measurement point No. (14.5): column
vent (Figure 6):
• major pollutants: ammonium, H2S
phenols,
• measuring point: vent on column
top, dia. 250 mm, and
• measurement magnitude: gas com-
position.
Note: The amount of gaseous products is also
determinable from the material balance on the
basis of water composition. According to our
free assessment, column K1 vent is the major
pollutant of Phenosolvan Section.
6. Measurement point No. (14.6): vent
(Figure 6 between 25 and 26):
• major pollutant: ammonium fumes,
• measuring point: vent at section
top, dia. 50 mm, and
• measurement magnitude: gas com-
position.
7. Measurement point No. (14.7): column
vent (Figure 6):
• major pollutants: similar as at K1,
• measuring point: vent on column
top, dia. 250 mm, and
185
-------
• measurement magnitude: gas com-
position.
8. Measurement point No. (14.8):
Phenosolvan Section waste waters
tank (Figure 6/10):
• major pollutants: volatile matter of
oil, tar and phenol,
• measuring point: vent on level 0,
dia. 3", and
• measurement magnitude: gas com-
position.
9. Measurement point No. (14.9): raw
phenol tank (two units) (Figure 6/24):
• major pollutants: phenol fumes,
• measuring point: lid on tank roof,
dia. 500 mm, and
• measurement magnitude: gas com-
position.
10.Measurement point No. (14.10):
diisopropilether tank (Figure 6/22):
• major pollutant: diisopropileher
fumes,
• measuring point: tank vent, level 0,
dia. 3", and
• measurement magnitude: gas com-
position.
According to the design, the Phenosolvan
Section has no discharge into the sewerage
system.
Note: The section for biological waste waters
treatment is inoperative. The amount of water
currently discharged directly into River Sitnica
stream is measurable at the inlet into aeration
pools. (Attention to be paid to the amount of
diisopropilether.)
STORAGE
The storage, Figure 7, consists of seven
tanks and a pump station. The gasoline, tar, im-
pure and medium oil may be used for the mix-
ture for burning supplied to the Power Genera-
tion Plant via a pipeline, or individually supplied
for shipment. All tanks are connected with the
atmosphere directly by vents, and the program
provided the determination of discharge gases
composition.
Phenol is stored in the ammonium tank, and
other changes are also made as required.
Approximate composition of medium oil:
water content
creosates content
• paraffine content
naphatalene content
NHV
0.5- 1.5%
28 - 32%
0.3%
2-3%
8,500-8,700 Coal/kg
Approximate composition of tar:
asphalt content
• paraffine content
creosate content
NHV
13-23%
3 - 4%
26 - 32%
8,500 - 8,600 Coal/kg
Sampling points data follow below:
Sampling Points-Storage
1. Measurement point No. (1 5.1): vent on
tar tank (two units):
• cause of pollution: designed con-
nection with the atmosphere by
vents,
• major pollutants: H2 higher
hydrocarbons,
• measuring point: lid on tank roof,
dia. 500 mrn, and
• measurement magnitude: gas com-
position.
2. Measurement points No. (15.2) and
(1 5.5): vents on medium oil tanks (two
units):
• cause of pollution: designed con-
nection with atmosphere by
separate vents,
• measuring point: lids on tank roofs,
dia. 500 mm,
• measurement magnitude: gas com-
position, and
• major pollutants: medium oil
fumes, H2S.
3. Measurement point No. (15.3):
Gasoline tank:
• cause of pollution: designed
discharge directly into the at-
mosphere,
• major pollutants: highly evaporable
gasoline fractions,
• measuring point: lid on tank roof,
dia. 500 mm, and
186
-------
VENT VENT
COOLING
WATER
oo
3
to
VENT
TO POWER
STATION
VENT
PUMP STATION
LOADING
VENT
oc
<
VENT
VENT
Figure 7. Process flow diagram and sampling points in. storage.
-------
• measuring magnitude: gas com-
position.
4. Measurement point No. (1 5.4): Phenol
tanks (two units):
• cause of pollution: designed con-
nection with atmosphere by vents,
• major pollutants: highly evaporable
phenols,
• measuring point: lid on tank roof,
dia. 500 mm, and
• measuring magnitude: gas com-
position.
Cooling Water Coolers-Sampling Points
1. Measurement point No. (19.1): air
discharge from the coolers:
• cause of pollution: leakage from ex-
changers in gasification plant sec-
tions,
• major pollutants: evaporable com-
ponents,
• measuring point: air outlet from the
coolers, and
• measurement magnitude: gas com-
position.
Expansion Gases Main Incinerator-Sampling
Points
1. Measurement point No. (20.1): Gases
to main incinerator:
• cause of pollution: designed burn-
ing of expansion gases from
Generation Section, Tar Separa-
tion, and H2S waste gases from
Rectisol Section,
• major pollutants: higher hydrocar-
bons, H2S (S02),
• measuring point: line before the in-
cinerator at the location of conden-
sate separation, level 0, incinerator
inlet, and
• measurement magnitude: gas com-
position.
Expected composition of expansion gases at
incinerator:
co2
H2
CO
CH4
N2
CmHn
H2S
°2
Gasoline
Sorg
NH3
Water
Tar
Medium oil
Dust
40vol. •%
35 vol. • %
12vol. -%
10 vol. - %
2.5vol. -%
0.7 vol. - %
0.6 vol. - %
0.2 vol. • %
7 g/Nm3
20g/100Nm3
5-7g/100Nm3
70 g/Nm3
21 - 25 g/Nm3
18 -20 g/Nm3
0.1 g/Nm3
Area Samples (Figure 1)
Area samples will be taken at three points on
plant site:
1. Measurement point No. (1): Area
around the Generator Section:
• cause of pollution: gas production
according to "Lurgi" procedure,
• major pollutants: CO, NOX, S02,
H2S, COS, CS2, mercaptans, CH,
particulates and organics,
• measurement point: level 0 around
Generator Section, and
• measurement magnitude: air com-
position.
2. Measurement point No. (2): Area
around the water cooling section:
• cause of pollution: exchanger
leakage in Gasification Plant sec-
tions,
• major pollutants: volatile com-
ponents,
• measurement point: level 0 around
water cooling section, and
• measurement magnitude: air com-
position (CO, NOX, S02, H2S, COS,
CS2, mercaptans, CH, particulates,
and organics.
188
-------
3. Measurement point No. (3): Area sur-
rounding Tar Separation Section:
• cause of pollution: technological
design providing direct connection
of all vessels with atmosphere by
vents,
• major pollutants: volatile phenols,
H2S and higher hydrocarbons,
• measurement point: level 0 near
tank vents or level 3 on the plat-
form near the vents, and
• measurement magnitude: air com-
position {CO, NOX, SO2, H2S, COS,
CS2, mercaptans, CH, particulates,
and organics).
PROBLEMS
As already stated, the reported program of
research should be completed over a 3-year
period. In accordance with this and by gaining
insight into all problems connected with the
designed works, a Dynamic Time Schedule was
made for the realization of the program and
enclosed here in table form.
By to-date investigations the following was
observed:
Kosovo lignite falls into a group of younger
coals and has high contents of moisture (50
percent) and ash (about 30 percent at 105 °C).
The coal substance consists of macerals tex-
tinite, ulminite, atrinite, and densinite and it is
banded by mineral matters the principal
representatives of which are clay, marly
limestone, and locally pyrite. When exposed to
atmospheric precipitations over a longer
period, the coal substance decomposes to
dust.
Prior to use in the gasification process,
Kosovo lignite is dried by the "Fleissner" pro-
cess down to a moisture content of approx-
imately 24 percent and screened, so that
"Lurgi" generators are fed with class-60 + 6
mm. The dried coal-60 + 6 mm contains
about 20 percent of ash and some 1.4 percent
of total sulfur (at 105°C).
The content of volatiles in the product
amounts about 56 percent, that of carbon
68.5 percent, hydrogen approximately 5 per-
cent, and nitrogen + oxygen about 26 percent,
calculated on pure coal substance (moisture
and ash free).
In the process of transportation and
transfer,substantial amounts of dust are form-
ed due to its high fragmentation propensity. Its
Micum test equals 74 percent. Consequently,
particles below 0.5 mm are predominant in
undersize - 6 mm. Due to above facts, a large
quantity of fine dust occurs in our plant prior to
generator feed. This dust causes difficulties in
the generator during the gasification process.
At generator discharge, thick masses of tar and
dust are formed, as well as Ca phenolates,
decreasing the diameter of raw gas discharge
lines.
The produced raw gas contains a high
percentage of various solid, liquid, and gaseous
pollutants (dust, tar, lower, and higher
hydrocarbons, NCN, H2S, NO, etc.). The
realization of the designed program will result
in accurate data on the amounts and kinds of
pollutants discharged into the air, water, and
solid wastes.
Fusibility of dried Kosovo lignite ash occurs
at approximately 1290°C in oxidative at-
mosphere. Consequently, the slag is discharg-
ed from the generators in unmelted form.
Chemical composition of the slag is such that it
reacts with water and forms a basic medium of
about pH = 11. It is particularly interesting
that it contains, in addition to various trace
elements, 0.4 percent of stroncium oxide and
0.27 percent of manganese oxide.
The tar produced starts to distill at 264 °C,
and the fraction yields are as follows:
264 - 300° C
300 - 335° C
+ 335° C
9.0 percent (water free)
23.0 percent (water free)
68.0 percent (water free)
The tar solidification temperature is 48 °C.
The rate of pollution in the Tar Separation Sec-
tion is very high due to discharges from the
tanks through vents directly into the at-
mosphere.
The analyses of clean gas used for separating
the hydrogen required for ammonium synthesis
indicate that clean gas contains hydrocarbons
(C3H6,C3H8) and nitrogen oxides, so that its
use for ammonium production is questionable.
189
-------
The cause of environmental pollution from
Kosovo Coat Gasification Plant in Obilic should,
naturally, primarily be looked for in the grade of
available raw material which we are forced to
process, as well as in the technological
processes and facilities designed and selected
at the time when little consideration was paid
to environmental pollution, i.e., when preven-
tive solutions were not required.
We are sure that the results of our investiga-
tions will be of overall usefulness and advan-
tage, and particularly for us in Socialist
Autonomous Province Kosovo, since this
knowledge will enable us to improve the opera-
tion of individual existing facilities and pro-
cesses, as well as to select more efficient and
more adequate procedures in possible future
construction of gas production plants leading
to efficacious protection of our living environ-
ment.
Thanks for your attention!
190
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FATE OF POLLUTANTS
IN INDUSTRIAL GASIFIERS
By
Gordon C. Page
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78758
Abstract
There is currently a growing interest in using
low-Btu gas produced from coal as a combus-
tion fuel for industrial boilers, kilns, and fur-
naces. In light of this, the Environmental Pro-
tection Agency has initiated a comprehensive
assessment program with Radian Corporation
to evaluate the environmental impacts
associated with this growing technology.
The purpose of this paper is to present the
current data on the fate of pollutants from in-
dustrial gasifiers used to produce low-Btu com-
bustion gas from various types of coal. The two
gasification systems considered in this paper
use atmospheric, fixed-bed, single-stage
gasifiers; one produces a hot gas, the other a
cooled or quenched low-Btu gas.
Data on the fate of sulfur and nitrogen
species, organics, trace elements, and par-
ticulate matter are presented. Analyses of
these data indicate that: a) 81 to 97% of the
coal sulfur can be converted to H2S and COS in
low-Btu gas produced from high volatile
bituminous coals and lignite having the lower
sulfur conversion, b) the amount of NOx formed
by combusting low-Btu gas should be lower
than direct-firing of coal; however, there may
be a potential for incomplete combustion of
NH3 and HCN in the low-Btu gas, c) there are
small amounts of organics in the gasifier ash
and cyclone dust (20 to 380 ppm, respec-
tively); however, quench liquors will contain
high concentrations of organics consisting
primarily of phenols, d) from trace element
analysis of the gasifier ash, cyclone dust,
quench water, and by-product tar, the cyclone
dust had the highest amounts of Pb, Se, As,
and Fl while the by-product tar was highest in
Hg, and e) the physical and chemical
characteristics of the particulate matter en-
trained in the low-Btu gas are highly dependent
on coal type and gasifier operating parameters.
INTRODUCTION
In recent years the nation's energy picture
has changed drastically due to increasingly
severe shortages of oil and natural gas.
Because of these shortages, there is currently a
growing interest in using low-But gas (-150
Btu/scf) produced from coal as a combustion
fuel for industrial boilers, furnaces, and kilns. In
response to this, the Environmental Protection
Agency has contracted Radian Corporation to
perform a multimedia environmental and con-
trol technology assessment for low/medium-
Btu gasification technology.
To date, there are little actual data on the en-
vironmental and health effects of the discharge
steams from low-Btu gasification systems,
along with the technology used to control these
streams. In light of this, one of the main objec-
tives of the low-Btu environmental assessment
program is to characterize the nature of the
waste streams generated by commercial low-
Btu gasification plants.
The purpose of this paper is to present cur-
rent data on the fate of pollutants from in-
dustrial gasifiers producing low-Btu gas. The
two gasification systems considered in this
paper use atmospheric, fixed-bed, single-stage
gas producers with one system producing a hot
combustion gas and the other a cooled/
quenched gas. The coal feedstocks considered
for these systems include anthracite, high
volatile bituminous, low volatile bituminous,
and lignite. The sulfur concentrations of these
coals ranged from 0.6 to 3.7 weight percent.
The information given in this paper deals
with the fate of sulfur and nitrogen species in
low-Btu gasification systems along with the
nature and content of organic compounds,
trace elements, and particulate matter in the
multimedia discharge streams. Conclusions
that can be drawn from these data and recom-
mendations for further work are also dis-
cussed.
System I
System I for producing low-Btu gas from coal
is illustrated in Figure 1. This system contains
the following three process modules: a) an at-
mospheric, fixed-bed, single-stage gasifier, b) a
hot cyclone, and c) a combustion process.
191
-------
COAL
FEEDER VENT
GAS
COMBUSTION
PROCESS
Figure 1. Low-Btu gas production.
-------
Coal is fed into the gasifier where it is reacted
with steam and oxygen to produce a hot
(~870°K, 1100°F) low-Btu gas having a
higher heating value of approximately 150
Btu/scf. The hot gas then enters the cyclone
where entrained particulate matter is removed.
The particulate-free gas is then combusted.
The discharge streams from this gasification
system include both gaseous emissions and
solid wastes. The gaseous emissions are the
coal feeder vent and combustion gases. The
solid wastes are the gasifier ash and the par-
ticulate matter collected by the cyclone
(cyclone dust).
System II
Figure 2 illustrates System II for producing
low-Btu gas from coal. This gasification system
contains the same process modules as System
I with three additional modules: a) a gas
quench, b) a tar/liquor separator, and c) a tar
combustion process. This system also has a
water pollution control module, forced
evaporation, to control the spent quench liquor.
As in System I, coal is reacted with steam
and oxygen to produce a hot, low-Btu gas. The
particulate matter in the gas exiting the gasifier
is removed by a hot cyclone. The particulate-
free gas is then quenched and cooled to remove
the tars and oils and sent to the gas combustion
process. The tar is separated from the quench
liquor in a separator and sent to the tar combus-
tion process. The quench liquor from the
separator is then recycled to the gas quenching
process. Any liquor build up in the system is
sent to a force evaporator where volatile liquids
are vaporized and vented to the atmosphere.
The discharge streams from this gasification
system include gaseous emissions, liquid ef-
fluents and solid wastes. The gaseous emis-
sions are the coal feeder and tar/liquor
separator vent gases; and the flue gases from
the low-Btu gas and tar combustion processes.
The liquid effluent is the spent quench liquor
while the gasifier ash and cyclone dust are the
solid wastes.
COAL FEEDSTOCKS
The data presented in this paper were ob-
tained during the production of low-Btu gas
from six different coal feedstocks. The prox-
imate and ultimate analyses and the higher
heating values for these coals are given in Table
1. These feedstocks include anthracite-,
bituminous-, and lignite-type coals which are
representative of the various types of coals
which are or will be used to produce low-Btu
gas on a commercial scale.
POLLUTANTS FROM LOW-BTU
GAS PRODUCTION
In this section the fate and characteristics of
the pollutants from the two gasification
systems producing low-Btu gas from various
coal feedstocks are discussed. The fate of coal
sulfur and the concentrations of specific sulfur
species in the (ow-Btu gas are presented. The
fate of coal nitrogen and specific nitrogen con-
taining compounds in the product gas are
discussed along with data concerning the com-
bustion of these nitrogen-containing com-
pounds. The nature and content of organics
and trace elements in liquid and solid waste
streams are presented followed by a discussion
of the physical characteristics of the particulate
matter entrained in the product gas.
Sulfur Series
The fate of sulfur species during the gasifica-
tion of high volatile A (HVA) bituminous and
lignite coals is given in Table 2. According to
these data, approximately 97 percent of the
HVA bituminous coal sulfur was converted to
H2S and COS while only 81 percent of the
lignite sulfur was converted. This variation is
probably due to the chemical characteristics of
the lignite ash since alkaline ashes will retain
significant amounts of sulfur. This is ex-
emplified by the high sulfur content (14.2%)
found in the ash from gasifying lignite. This
phenomenon! has also been demonstrated in
fluidized-bed combustion tests for lignite.4
The actual amounts of sulfur species in the
process and discharge streams from gasifica-
tion systems I and II are given in Table 3. There
are no data on five of the discharge streams
from these systems: a) the coal feeder vent
gases, b) the tar/liquor separator vent gases, c)
tar combustion gases, d) low-Btu gas combus-
193
-------
Figure 2. System II—Low-Btu gas production.
-------
TABLE 1
COAL FEEDSTOCK ANALYSES FOR FIXED-BED. ATMOSPHERIC GASIFICATION SYSTEMS
to
Proximate
Analysis (wt %)
Moisture
Ash
Volatile Matter
Fixed Carbon
Ultimate Analysis
(wt %, dry)
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
Ash
HHV (Btu/lb
as received)
Anthracite
3.6
8.0
3.6
84.8
86.6
2.0
}2.3
0.8
8.3
11,430
5.5
7.1
30.8
56.6
80.0
5.1
}6.6
0.8
7.5
13,405
High Volatile
A Bituminous
3.5
4.5
29.1
62.9
81.0
5.0
1.5
3.9
0.7
—
14,335
2.3
5.0
36.4
56.3
—
—
—
0.6
—
13,960
High Volatile
C Bituminous
7.2
15.7
34.4
42.7
62.3
4.7
1.0
5.7
3.7
—
11,315
Medium
Volatile
Bituminous
7.1
5.0
21.4
66.5
852
4.7
}4.0
0.7
5.4
13,830
Litnite
32.1
7.6
29.0
31.3
64.8
4.5
1.5
17.0
1.0
11.2
7327
Sources: R*fs. 1,2, 3.
TABLE 2
FATE OF COAL SULFUR IN ATMOSPHERIC,
FIXED-BED, SINGLE-STAGE, LOW-BTU
GASIFICATION SYSTEMS
Cod Sulfur toal Type
Converted To HVA Bituminous IJpite
HjStwtK)
COS(wt%)
Tar Sulfur (wt%)
Cyclone Oust Sulfur (wtS)
Gesifier Ash Sulfur (wt%)
95.1
2.0
2.1
0.7
ttl
100.0
78.4
3.1
3.3
1.0
14.2
100,0
-------
TABLE 3
SULFUR SPECIES IN THE PROCESS AND MULTIMEDIA DISCHARGE
STREAMS FROM LOW-BTU GASIFICATION SYSTEMS
Coal Type
Anthracite
_ HVA
co
o> Bituminous
HVA
Bituminous
HVC
Bituminous
Medium
Volatile
Bituminous
HVA
Bituminous
Lignite
Gasification
System
1
1
II
II
1
II
1
Coal
Sulfur
(wtXrfry)
0.8
0.8
0.7
3.7
0.7
0.8
0.91
Low-Btu
Gas Sulfur
(ppmv)
H2S = 900
COS = 60
^=1200
H2$= 11,000
H2S=1213
COS = 50
—
COS =133
Tar/Oi
Sulfur
(wt%)
— .-
0.5
0.5
1.6
—
520 ppm*
1.3
Cyclone
Dust.
Sulfur
(wtX)
_
0.7
—
—
—
0.67
2.0
Gasifier
Ash
Sulfur
(wtX)
—
0.01
—
—
—
250 ppm*
4.1
•SSMS Analysis
Sources; Ref*. 1,2.3.
-------
tion gases, and e) the vapors from the forced
evaporation of the quench liquor.
The data in Table 3 indicate that the amount
of COS formed during the gasification of all the
coals is approximately 4 volume percent of the
total gaseous sulfur species. This amount of
COS in the product gas will affect the selection
and design of an acid gas removal process to
remove H2S from low-Btu gas. The sulfur con-
tent of the tar produced in gasifying lignite was
two to three times greater than for gasifying
HVA bituminous coals having similar amounts
of sulfur. This would indicate that the sulfur
emissions from a combustion process using tar
produced from lignite would be significantly
greater than using tar produced from HVA
bituminous coal having the same amount of
sulfur. There were also higher concentrations
of sulfur in the cyclone dust and ash produced
in gasifying lignite compared to gasifying HVA
bituminous coals.
Nitrogen Species
In this section the formation of gaseous
nitrogen species during coal gasification and
the subsequent combustion of these com-
ponents is discussed. The two gaseous
nitrogen species of importance are ammonia
and hydrogen cyanide. The date, there are
minimal data on the amount of HCN in the pro-
duct low-Btu gas with no data on the amount of
HCN in the following discharge streams: coal
feeder and tar/liquor separator vent gases,
forced evaporator vapors, and combustion
gases from burning the low-Btu gas. However,
there are data on the concentration of ammonia
in low-Btu gas along with estimates on the fate
of ammonia during low-Btu gas combustion.
The current data on the formation of NH3 and
HCN during the gasification of high and
medium volatile bituminous coals are given in
Table 4. These data indicate that there can be a
significant variation in the amount of ammonia
formed during the gasification of the same coal
feedstock. These variations can probably be at-
tributed to the following operating parameters:
• Amount of steam used to gasify the
coal
• Surface moisture content of the coal
• Time-temperature history of the coal
particle in the gasifier.
The first two variables affect the hydrogen
partial pressure inside the gasifier which is
directly proportional to the amount of NH3
TABLE 4
COAL NITROGEN CONVERTED TO NH3 AND HCN
Coal
Nitrogen
(wt%)
Ammonia
Concentration
in Low-Btu Gas
(ppmv)
Hydrogen Cyanide
Concentration
in Low-Btu Gas
(ppmv)
Molar Conversion
of Coal Nitrogen
to Ammonia
(X)
High Volatile
A Bituminous
High Volatile
A Bituminous
Medium
Volatile
Bituminous
1.5
1.54
1.0
109
1940
622
385
666
486
658
452
113
107
129
35.0
12.0
5.2
9.0
5.3
7.2
6.8
Source*; Reft. 1, 2,
197
-------
formed. The last variable would affect the
amount and characteristics of nitrogen in-
termediates formed in the gasifier.
The data in Table 4 also show the molar con-
version of coal nitrogen to ammonia. For all
tests except one where the molar conversion
was 35.0 percent, the conversions were fairly
consistent with the average molar conversion
of coal nitrogen to NH3 being approximately 8
percent.
The amount of HCN in the product low-Btu
gas is also significant and deserves special at-
tention when designing low-Btu gas cleaning or
combustion processes. Hydrogen cyanide will
affect the performance of certain acid gas
removal processes that are currently being pro-
posed for cleaning low-Btu gas produced from
high sulfur coals. For example, HCN will cause
a build up of thiocyanates in the solvent used in
a Stretford process.
The fate of nitrogen species during the com-
bustion of low-Btu gas has been investigated
with respect to the amount of NH3 converted
to NOX2. These studies indicated that the con-
version of coal nitrogen to NOX in low-Btu
gasification systems was approximately 3 to 4
percent. This is much lower when compared to
the direct combustion of coal where 10 to 15
percent of the coal nitrogen is emitted as NOX.
There are, however, two other aspects to be
considered in assessing the characteristics of
nitrogen species in combustion gases. These
are the amounts of NH3 and HCN not converted
to NOX. The amount of ammonia emitted in the
combustion process flue gas can be estimated
from Figure 3. For example, if the NH3 concen-
tration in the low-Btu gas is 500 ppmv, 54 per-
cent will be converted to NOX while 46 percent
will be emitted as NH3. There are currently no
data on the amount of HCN converted to NOX in
a low-Btu gas combustion process. Therefore,
the quantity of HCN in*the combustion gases is
unknown.
Organic Species
The information presented in this section is
primarily concerned with the amount and
characteristics of the organic compounds in the
following process and discharge streams from
low-Btu gasification systems:
• Quench liquor
• Cyclone dust
• Gasifier ash
• By-product tar
The first three of these streams represent
discharge streams while the byproduct tar is
the feed to the tar combustion process.
Total Organics - Grab samples of the quench
liquor, cyclone dust, and ash were collected
from a gasification plant represented by
System II as shown in Figure 2. The feedstock
to this plant was a high volatile A bituminous
coal. The total amount of organics in these
three streams is presented in Table 5. The
values for the total amount of organics were
determined using the methods specified by the
EPA Level 1 Environmental Assessment pro-
cedures3 plus an additional ether extraction for
the quench liquor. From the data in Table 5, the
spent quench liquor contains a significant
quantity of organics (-4000 mg/l). Since this
liquor is sent to a forced evaporator, there is a
potential for significant vapor emissions.
However, there are no data on the emissions
from this evaporator.
Organic Characteristics - The characteristics
of the organic species in the quench liquor, by-
product tar, and cyclone dust are shown in
Figure 4. These results were obtained by using
the extraction, column chromatography, and
infrared (IR) spectra analysis methods specified
by the EPA Level 1 Environmental Assess-
ment5.
The organic components in the quench liquor
consisted primarily of phenols with smaller
amounts of acids. The by-product tar contained
TABLE 5
ORGANIC CONCENTRATIONS IN AQUEOUS AND
SOLID WASTE DISCHARGE STREAMS FROM
LOW-BTU GASIFICATION SYSTEMS
Discharge Stream
Organic Concentration
Spent Quench Liquor
Cyclone Dust
Gasifier Ash
3865 mg/l
381 ppm
18ppm
Source: Ref. 3.
198
-------
x
o
z
100
90
80-
70 -
60 -
X
z
u.
o
z
o
W
en
LU
z
o
u
50 -
40 -
30 -
20-
10-
200 400 600 800 1000 1200 1400 1600 1800 2000
NH3 CONCENTRATION IN LOW-BTU GAS (ppmv)
SOURCE: L-2137
Figure 3. Conversion of ammonia to NO. in a turbulent-diffusion flame.
199
-------
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QUENCH LIQUOR
ORGANICS
ELUTED FRACTION
TAR/OIL
ORGANICS
ELUTED FRACTION
CYCLONE DUST
ORGANICS
Figure 4. Results of Level 1 organic extraction, column chromatography,
and IR analysis (bituminous coal).
-------
a wide range of organic compounds including
phenols, alcohols, acetates, acids, esters, etc.
The organic constituents extracted from the
cyclone dust were primarily paraffinic
hydrocarbons and possibly cyclic alcohols. It
should be emphasized that using IR spec-
troscopy to identify the nature of organic
species is subject to doubt, especially for com-
plex mixtures. Therefore, caution must be exer-
cised in interpreting the spectra of these mix-
tures.
Trace Elements
Grab samples of the ash, cyclone dust,
quench liquor, and byproduct tar were col-
lected and analyzed for trace elements using
Spark Source Mass Spectrometry (SSMS).
These samples were taken from a gasification
plant similar to System II. The results of these
analyses are presented in Tables 6 through 9. A
summary of the data in these tables is given in
Table 10. From the data in Table 10, the trace
element concentrations in the byproduct tar are
higher than the quench liquor except for
selenium and sulfur.
The six trace elements highlighted in Table
10 indicate certain important aspects of trace
element distribution in these samples. The
levels of Pb, Hg, As, Fl, and B are higher in the
tars compared to the quench liquor while Se
levels are essentially the same, Hg levels in the
tar are also higher than in the cyclone dust.
In order to identify which trace elements
need to be controlled in the spent quench
TABLE 6
TRACE ELEMENTS IN GASIFIER ASH BY SSMS
Element
Uranium
Zirconium
Lead
Rubidium
Tungsten
Arsenic
Lutetium
Zinc
Erbium
Cobalt
Terbium
Chromium
Samarium
Scandium
Cerium
Chlorine
Cesium
Silicon
Tin
Sodium
Silver
Beryllium
ppm
w/w
56
430
7
120
10
4
2
26
8
61
4
510
28
29
260
230
10
MC
4
MC
<0.3
22
Element
Niobium
Bismuth
Strontium
Rhenium
Selenium
Hafnium
Gallium
Thulium
Nickel
Dysprosium
Manganese
Europium
Titanium
Praseodymium
Potassium
Barium
Phosphorus
Antimony
Magnesium
Cadmium
Boron
Lithium
ppm
w/w
82
0.4
MC
0.3
20
10
66
1
120
17
680
5
MC
42
MC
MC
MC
1
MC
3
130
190
Element
Thorium
Yttrium
Thallium
Bromine
Tantalum
Germanium
Ytterbium
Copper
Holmium
Iron
Gadolinium
Vanadium
Neodymium
Calcium
Lanthanum
Sulfur
Iodine
Aluminum
Indium
Fluorine
Molybdenum
ppm
w/w
86
260
0.5
12
2
4
12
540
11
MC
10
MC
56
MC
280
250
0.3
MC
STD
=*56
22
MC • MajbV Component
Note • Any element not listed • Concentration < 0.2 ppm by wt
Carbon, hydrogen, nitrogen & oxygen are excluded from these enalyses.
Source: Ref. 3.
201
-------
TABLE 7
TRACE ELEMENTS IN CYCLONE OUST BY SSMS
Element
Bismuth
Lead
Mercury*
Terbium
Gadolinium
Europium
Samarium
Neodymium
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Antimony
Tin
Indium
Cadmium
Silver
Molybdenum
Mobium
Zirconium
Yttrium
Strontium
Rubidium
Bromine
Selenium
ppm/wt
2
60
0.01
9
2
1
9
21
5
45
45
460
1
4
8
2
STD
<2
3
14
12
80
70
340
33
20
24
Element
Arsenic
Germanium
Gallium
Zinc
Copper
Nickel
Cobalt
Iron
Manganese
Chromium
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Boron
Beryllium
Lithium
ppm/wt
27
5
130
85
130
30
16
MC
120
90
100
MC
12
MC
MC
720
MC
MC
MC
MC
MC
MC
=*720
70
6
27
•Flameless atomic absorption
MC = Major Component
Note: Any element not listed - concentration < 0.2 ppm by
wt
Carbon, hydrogen, nitrogen and oxygen are excluded
from these analyses.
Source: Ref. 3.
202
-------
N)
o
co
TABLE 8
TRACE ELEMENTS IN QUENCH LIQUOR BY SSMS
Element
Lead
Mercury
Neodymum
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Antimony
Tin
Indium
Cadmium
Molybdenum
Xirconium
Yttrium
Strontium
Rubidium
Bromine
[Selenium
Arsenic
Geranium
Lithium
MB/I
0.04
0.007
<0.01
0.005
0.01
<0.01
0.1
1
0.5
0.1
0.02
Std
<0.02
0.06
0.01
0.004
0.2
0.03
0.2
* I
0.2
<0.02
0.2
Element
Gallium
Zinc
Copper
Nickel
Cobalt
Iron
Manganese
Chromium
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Boron
M9/I
0.006
0.07
0.1
0.1
<0.008
3
0.03
0.03
0.004
0.05
<0.006
MC
MC
0.3
MC
MC
7
1
2
MC
~2
2
•Flameless atomic absorption
MC = Major Component
Note: Any element not listed - concentration < 0.004
Carbon, Hydrogen, nitrogen and oxygen are
excluded from these analyses.
Source: Ref. 3.
TABLE 9
TRACE ELEMENTS IN TAR BY SSMS
Element
Lead
Mercury*
Neodymium
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Antimony
Tin
Molybdenum
Zirconium
Yttrium
Strontium
Rubidium
Bromine
Selenium
Arsenic
Germanium
Gallium
Zinc
ppm
10
0.12
0.6
0.3
0.5
0.6
27.0
0.1
1
0,8
0.9
1
0.7
<0.2
10
0.2
2
3
4
1
8
7
Element
Copper
Nickel
Cobalt**
Iron
Manganese
Chromium
Vanacium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Boron
Beryllium
Lithium
ppm
3
5
5
120
0.9
3
0.8
29
0.7
630
100
6
520
17
170
25
23
71
— 22
19
0.1
4
*Flameless atomic absorption
"Heterogeneous
MC = Major Component
Note: Any element not listed - concentration < 0.004 ppm
Carbon, hydrogen, nitrogen, and oxygen are excluded
from these analyses.
Source: Ref. 3.
-------
TABLE 10
TRACE ELEMENTS IN GRAB SAMPLES BY SSMS
Uranium
Bismuth
Lead
Mercury
Barium
Antimony
Cadmium
Molybdenum
Selenium
[Arsenic
Zinc
Copper
Nickel
Chrorr' n
Vandii .,i
Titanium
Chlorine
Sulfur
Fluorine
Boron
Beryllium
Lithium
Ash
56
0.4
7
NR
MC
1
3
22
20
4
26
540
120
510
MC
MC
230
250
^56
130
22
190
Cyclone
Bottom
Dust
<2
60
0.01
460
8
<2
14
24
27
85
130
30
90
100
MC
720
MC
="270
70
6
27
Liquor
_..
—
0.04
0.007
0.1
0.1
<0.02
0.06
4
0.2
0.07
0.1
0.07
0.03
0.004
0.05
0.3
MC
— 2
2
—
0.2
Tar
—
—
10
0.12
27
0.8
—
1
3
4
7
3
5
3
0.8
29
6
520
~22
19
0.1
4
NotL. All values expresses as ppm except liquor in which values are expressed as M9/ml.
MC = Major Component
liquor, trace element standards for surface, ir-
rigation, and public intake waters are compared
to the trace element concentrations found in
the quench liquor. These comparisons are
given in Table 11. From these data, the most
important trace element requiring control is
selenium since the concentration of selenium is
approximately 400 times greater than the stan-
dards set for surface and public intake waters
and 80 times greater than for irrigation water
standards.
Particulate Matter
The physical characteristics of the par-
ticulate matter entrained in the low-Btu gas
produced using various coal feedstocks is
presented in Table 12. From these data, the
physical characteristics of the particulate mat-
ter depend upon both the coal feedstock and
gasifier operating conditions.
The particulates collected by the cyclone
varied with respect to all three physical
characteristics analyzed (average particle
diameter (dp), ash content, and bulk density).
The particulates collected from the gasification
system using anthracite coal had the highest
values for all three physical characteristics. The
system gasifying lignite coal had the lowest
average particle diameter while the system
used to gasify bituminous coal had the lowest
particulate matter ash content and bulk densi-
ty. From these data, the particulate
characteristics for the gasification of
bituminous coals varied significantly which in-
204
-------
TABLE 11
LEVELS OF TRACE ELEMENTS IN LIQUIDS FROM THE QUENCH LIQUOR
AND BY-PRODUCT TAR VERSUS WATER QUALITY STANDARDS
Element
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Fluorine
Mercury
Lead
Manganese
Molybdenum
Nickel
| Selenium
Vanadium
Zinc
Copper
Surface
Water
—
0.05
1.0
_.
1.0
0.01
0.05
—
—
0.05
0.05
-
—
0.01
—
5.0
1.0
Irrigation
Water
_.
1.0
—
_
0.75
0.005
5.0
~
...
5.0
2.0
0.005
0.5
0.05
10.0
5.0
0.2
Public
Water
Intake
^___
0.1
—
...
1.0
0.01
0.05
._
0.002
0.05
0.00
—
_.
0.01
...
5.0
1.0
Liquor
Mg/i
0.1
0.2
0.1
...
2.0
<0.02
0.03
2
0.007
0.04
0.03
0.06
0.07
4
—
0.07
0.1
Tar
ppm
0.8
4
27
0.1
19
...
3
22
0.12
10
0.9
1
5
3
...
7
3
TABLE 12
CHARACTERISTICS OF THE PARTICULATE MATTER ENTRAINED IN LOW-BTU GAS
Collected by the Cyclone
Coal Type
Bituminous
Bituminous
Anthracite
Lignite
Average
dp 04
170
95
200
70
Ash
Content
(wt%)
10.2
15.4
47.3
23.0
Bulk
Density
0.40
0.53
0.93
...
Not CoHected'bv the Cyclone Suspended in Tar
Ash
Average Content
dp(ju) (wt%)
...
20» 10.4
-------
dicates the dependency of these character-
istics on the gasifier operating parameters.
The particulate matter collected after the
cyclone consisted of particulates that settled in
or escaped from the main product gas line. The
particulates in the tar were collected by solu-
tion filtration. The particulates not collected by
the cyclone were agglomerated. However, this
may not be representative of the actual
characteristics of the particular matter passing
through the cyclone.
These results indicate that the physical
nature of the particulate matter carried over in
the product low-Btu gas will probably vary from
site to site depending on the type of coal
feedstock and the operating parameters of the
gasifier. Therefore, the design of cyclones and
other particulate collecting devices wll be site
specific since the design of these devices is
highly dependent upon these physical
characteristics.
CONCLUSIONS
Data currently available on multimedia
discharge streams is not sufficient to make a
completely accurate assessment of the health
and environmental effects and control
technology requirements for producing low-Btu
gas from coal. However, judgments on some of
these discharge stream characteristics can be
made from th- data presented in this paper.
The following are specific conclusions and
recommendations derived from this study.
Sulfur Species
1) The amount of coal sulfur that is con-
verted to gaseous sulfur species (H2S
and COS) is primarily dependent upon
the ash characteristics of the coal
feedstock. For example, the amount of
feedstock sulfur converted to H2S and
COS in gasifying lignite will usually be
significantly less than in gasifying high
volatile bituminous coals. This is due to
the alkalinity of the lignite ash which re-
tains and/or collects sulfur species.
2) The ratio of COS to the total amount of
sulfur species in the low-Btu gas was
not highly dependent upon coal
feedstocks and remained at about
0.04. This may indicate that the
mechanisms for H2S and COS forma-
tion during coal gasification are directly
related. If this relationship is valid, the
amount of COS in this product gas can
be estimated for various coals which
can be used as a factor in selecting and
designing sulfur recovery processes for
low-Btu gasification systems.
3) The concentration of sulfur in the by-
product tar is dependent upon the
nature of the coal feedstock. Sulfur
concentrations were found to be two to
three times greater in tar produced
from lignite than from high volatile
bituminous coal. This would affect the
amount of sulfur emissions if the tar is
to be used as a combustion fuel.
Nitrogen Species
1) The amount of ammonia produced dur-
ing coal gasification is dependent upon
the quantity of steam used, coal
feedstock moisture content, and the
time-temperature history of a coal par-
ticle in the gasifier. Generally, less that
10 mole percent of the coal nitrogen is
converted to NH3 in systems designed
to produce low-Btu gas for combustion
fuel.
2) The amount of NOX formed during the
combustion of low-Btu gas is a function
of the NH3 concentration in the product
gas and the combustion process
operating parameters. Past studies
have indicated that NOX formation
would be two to three times lower
when burning low-Btu gas compared to
burning the coal feedstock directly.
3) There may be significant quantities of
NH3 and HCN in the flue gases from
low-Btu combustion processes. The
current data indicate that up to 50 per-
cent of the NH3 in the product gas can
be emitted in the combustion gases
while there is no actual data on the
amount of HCN emitted.
Organics
1) The liquor used to quench low-Btu gas
will contain significant quantities of
206
-------
organic compounds consisting primari-
ly of phenols. Forced evaporation of
large quantities of spent quench liquor
will cause a significant quantity of
organics to be emitted into the at-
mosphere.
2) The ash produced from coal gasifica-
tion will contain very small quantities of
organics (~ 20 ppm) while the organics
in the particulate matter entrained in
the product gas will be much higher
(-400 ppm).
Trace Elements
1) Concentrations of Pb, Se, As, and Fl
were highest in the cyclone dust com-
pared to the ash, quench liquor, and by-
product tar while the Hg concentration
was highest in the by-product tar.
2) The levels of trace elements in the
quench liquor equaled or exceeded the
levels listed in the Federal Water Quali-
ty Standards for nearly every element.
The largest deviation was shown by
selenium at 4 ppm (400 times greater
than the standard for surface water).
Particulate Matter
1) The particulate matter entrained in the
low-Btu gas had different particle size
distributions, bulk density, and ash
contents. These physical and chemical
properties seem to be dependent on
coal type and the gasifier operating
characteristics. These variations will
significantly affect the operation of
cyclones and other collection devices
used to remove particulate matter from
the product gas.
RECOMMMENDATIONS
The characteristics of certain discharge
streams should be determined. There are cur-
rently no data on the composition of the follow-
ing streams: coal feeder and tar/liquor
separator vent gases, vapors from the forced
evaporation of spent quench liquor, and tar
combustion gases. There are some data on the
flue gases produced during the combustion of
low-Btu gas; however, the fate of trace con-
stituents such as HCN in these combustion
processes has not been determined. The
organic constituents in the spent quench liquor
need to be further characterized and leaching
tests for the ash and cyclone dust need to be
performed.
In conjunction with further characterization
of the multimedia waste streams from low-Btu
gasification systems, methods to determine the
health and environmental effects of these
streams need to be developed. These methods
will provide the goals for control technology im-
plementation and development along with
defining technologies necessary to minimize
worker exposure to hazardous fugitive emis-
sions from these processes.
REFERENCES
1. A. H. Rawdon, R. A. Lisauskas and S. A.
Johnson, "Operation of a Commercial
Size Riley-Morgan Coal Gasifier",
Presented at the American Power Con-
ference, Chicago, II, 19-21 April 1976.
2. A. H. Rawdon, R. A. Lisauskas and S. A.
Johnson, "NOX Formation in Low and In-
termediate BTU Coal Gas Turbulent-
Diffusion Flames", Presented at the NOX
Control Technology Seminar, sponsored
by Electric Power Research Inst., San
Francisco, CA, 5-6 February 1976.
3. Karl J. Bombaugh, Draft Report on Some
Analyses of Grab Samples from Fixed-Bed
Coal Gasification Processes. Radian DCN
77-200-143-14, EPA Contract No.
68-02-2147. Austin, TX, Radian Corp.,
25 May 1977.
4. Gerald M. Goblirsch and Everett A. Son-
dreal, "Fluidized Combustion of North
Dakota Lignite," Presented at the 9th
Biennial Lignite Symposium, Grand Forks,
ND, 18-19 May 1977.
5. J. W. Hamersma, S. L. Reynolds, and R. F.
Maddalone, IERL-RTFProcedures Manual:
Level 1 Environmental Assessment. EPA-
600/2-76-160a, EPA Contract No.
68-02-1412, Task 18. Redondo Beach,
CA, TRW Systems Group, June 197G.
207
-------
LIQUEFACTION
ENVIRONMENTAL ASSESSMENT
Dwight B. Emerson
Hittman Associates, Inc.
91 90 Red Branch Road
Columbia, Maryland 21045
August 1977
Abstract
Part of Hittman Associates environmental
assessment of coal liquefaction processes has
been the development of functionally discrete
unit modules, composed of an aggregation of
unit process operations. This paper presents an
overview of the current liquefaction process
technology and applicable control technology
based on the unit module approach. Eleven unit
modules are developed including: Coal
Preparation, Hydrogenation, Pyro/ysis/Hydro-
carbonization, Hydrotreating, Catalytic Syn-
thesis, Supercritical Gas Extraction, Phase
Separation, Fractionation, Acid Gas Removal,
Hydrogen/Synthesis Gas Generation, and Aux-
iliaries/Utilities.
INTRODUCTION
With the entry into an era of declining
petroleum reserves, reduced discoveries,
escalation of prices, and real or induced
shortages, coal liquefaction technology has
once more assumed a major role as a potential
solution to liquid fuel problems. Currently some
wenty-odd processes are in various stages of
development by industry and federal agencies.
All liquefaction processes achieve the objec-
tive of producing liquids by yielding a material
having higher hydrogen content than coal.
Hydrogen is present in coal at a level of about 5
percent. In high-Btu gas it is roughly 25 per-
cent. Fuel oils contain 9 to 11 percent
hydrogen and gasoline about 14 percent.
Whether the required hydrogen increase is ob-
tained by adding hydrogen to the coal com-
ponents or by stripping the hydrogen-rich com-
ponents from the coal depends upon the par-
ticular process. It also affects the yield of liquid
from the process.
Environmental Assessment
Definition
In their efforts to assist in the development of
an environmental assessment methodology
protocol, the EPA IERL-RTP supported contrac-
tors have used the term environmental assess-
ment to mean a continuing iterative study
aimed at:
(1) determining the comprehensive multi-
media environmental loadings and en-
vironmental control costs, from the ap-
plication of the existing and best future
definable sets of control/disposal op-
tions, to a particular set of sources,
processes, or industries; and
(2) comparing the nature of these loadings
with existing standards, estimated
multimedia environmental goals, and
bioassay specifications as a basis for
prioritization of problems/control needs
and for judgement of environmental ef-
fectiveness.
Included-in Hittman Associates' liquefaction
environmental assessment program are six
basic components. They are: (1) Current Proc-
ess Technology Background, (2) Environment-
al Data Acquisition, (3) Current Environmental
Background, (4) Environmental Objectives
Development, (5) Control Technology Assess-
ment, and (6) Environmental Alternatives
Analysis. This paper presents an overview of
the modular approach used during Hittman's
initial efforts at current process technology
description and control technology assess-
ment.
UNIT MODULES
Although significant technical differences ex-
ist between the liquefaction processes, many
individual unit and process operations are com-
mon to two or more processes. Further, at the
present stage of development, most published
process designs are only conceptual, and
significant differences between the current
design and future commercial plants are certain
to arise.
To avoid the redundancy of studying each
unit operation in each process, and the hazards
associated with conceptual designs, unit
operations were grouped within a series of
208
-------
functional modules. Each module was struc-
tured to perform a specific function, for exam-
ple, hydrotreating, to remove S, N and 0 from
liquid hydrocarbons.
Each module is composed of one or more in-
dividual unit operations or unit processes.
Because of the functional orientation, the
streams entering and leaving a module will be
essentially the same, even though the in-
dividual components of the module may be
slightly different for different processes.
Process streams are defined as any stream
entering a module and any stream leaving a
module having as its destination another
module. Waste streams are defined as those
streams leaving a module having as destina-
tions either a control system or the environ-
ment. Eleven modules were developed to
characterize the unit operations contained in
coal liquefaction processes.
Coal Preparation
Module
Operations which are performed in the coal
preparation module include crushing, grinding,
pulverizing, screening, drying, slurry prepara-
tion, and preheating. In general, crushing,
grinding, drying, and screening will be included
in the module for all processes. Pulverizing is in-
cluded as well for several processes, and all of
the hydrogenation processes which use a sol-
vent will use slurry preparation and preheating.
Process streams leaving this module are
either prepared coal or heated coal/oil slurry.
Waste streams include particulates from
mechanical operations and stack gas from dry-
ing. Processes which slurry and preheat the
coal will have an additional stack gas stream as
well as potential venting of gases.
Hydrogenation Module
In this module hydrogen is added to the "coal
molecule." Portions of the coal which can be
converted to soluble compounds dissolve leav-
ing an insoluble carbon residue and mineral
matter in suspension.
Variations include catalytic, non-catalytic,
and donor solvent systems. Since these opera-
tions are usually carried out at high pressure, a
pressure reducing operation may be included.
The crude liquid/solid leaving the reactor may
be cooled using waste heat boilers or heat ex-
changers.
There are only two process streams . -aving
the module. These are the crude COFi liquu and,
in some processes, a gas stream. No waste
streams are generated continuously, but occa-
sional venting may occur, and periodic replace-
ment of the catalyst will be necessary.
Pyrolysis/Hydrocarboniza tion
Module
High temperature gases are used to strip
volatiles from and/or to chemically add
hydrogen to coal in this module. Pyrolysis re-
quires introduction of steam and oxygen to
react with the coal while hydrouarbonization
uses heated hydrogen.
Vapor leaving the pyrolysis or lydrocar-
bonization reactor is cooled by q jenching with
either water or oil. Non-condensibles are used
elsewhere in the process. Waste heat rer jvery
may precede the quench. The condensed .'quid
may contain an aqueous phase as well as par-
ticulates, and a separation step may je includ-
ed in the module.
Process streams leaving the mod Je arj the
crude quenched liquid, noncondensible gas,
and the char. Waste streams may include vater
used to cool the char and excess quench water.
Hydrotreating Module
The purposes of hydrotreating are to remove
sulfur, nitrogen, and oxygen compounds via
conversion into hydrogen sulfide, ammonia,
and water and to further hydrogenate the cruae
oil.
Hydrotreating is a high pressure and high
temperature process. Heat is supplied by plant
fuel gas to preheat the crude and the reaction
itself is exothermic. The reactor product is
depressurized and cooled. An oil and an
aqueous phase are formed. The oil is stripped
to remove hydrogen sulfide and ammonia.
Process streams leaving the section are a
sour gas stream from depressurization, the
sour stripping stream, and the purified oil.
Waste streams include stack gas, sour water,
intermittent vents, and periodic catalyst
disposal or regeneration.
209
-------
Catalytic Synthesis
Module
This module catalytically converts synthesis
gas into liquid hydrocarbons or methanol.
Operations are heating and pressurizing the
feedstock, catalytic conversion, cooling the
raw product, and separating byproduct gases
and water from the raw product. A sulfur guard
reactor may be used to protect the catalyst.
Prr cess streams are liquid hydrocarbons and
I 'dro arbon gases. Waste streams are water,
; ent .atalyst, spent sulfur guard absorbent,
c. stack gas.
Supercritical Gas
Extractic ? Module
This module performs a function similar to
.he hydrogen^tion module via a completely dif-
ferent route.
A solvent, above its critical temperature and
pr ssure, is used to extract soluble and fusible
ci nponents from coal. Operations required are
compression and heating of the solvent,
separation of the solvent/solute mixture from
remaining coal material, reduction of mixture
p essure, and finally, separation of the extract
and solvent.
Phase Separation
Module
Solids, liquids and gases are separated in
numerous different unit operations. In coal
liquefaction processes, situations arise involv-
ing two, three, and four phases. The phase
separations are gas/solid, gas/liquid, liq-
uid/solid, liquid/liquid, gas/liquid/solid, and
ga ;/liquid/liquid/solid.
Operations include cycloning, filtering, cen-
trifuging, decanting, settling, and depressuriz-
ing.
Depending upon where in the process the
module is located, process streams and waste
streams may be solids, liquids, and gases.
Process streams generally will be oils, carbon
containing residues, and fuel gases. In general,
waste streams will be water, ash or slag, and
tars or other heavy residuals. Phase separation
modules may be incorporated as an operation
in other modules. Under that circumstance,
they are not treated as a separate module.
Fractionation Module
The fractionation module separates crude
feedstock into product and byproduct com-
ponents.
Primary operations used may be distillation,
vacuum flashing, and stripping. In addition,
heat must be supplied, depressurization may be
necessary, and cooling is required.
Process streams are: product and byproduct
to further processing or storage, recycle proc-
ess solvent, fuel gases, and solvents. Waste
streams may include water and gases, and in
rare instances liquid hydrocarbons and solid or
semisolid residues.
Acid Gas
Removal Module
This module separates hydrogen sulfide from
hydrocarbon gas streams. In some instances,
carbon dioxide may be separated also.
Operations in the primary section consist of
one or more gas/liquid or gas/solid contacts,
appropriate temperature and pressure adjust-
ment, and demisting, when necessary. Sup-
porting operations are absorbent regeneration
and make up.
Product gas, free of acidic constituents is the
main process stream in this module. The
primary waste stream is regenerator off gas,
hydrogen sulfide, carbon dioxide, or both.
Depending upon the system used, spent solid
absorbent or solution will also be a waste
stream.
Hydrogen/Synthesis Gas
Generation Module
The purpose of this module is to produce a
reducing gas composed of hydrogen and car-
bon monoxide. In the case of Fischer-Tropsch
and methanol synthesis, the gas is used in
catalytic synthesis to produce liquid hydrocar-
bons. In the other liquefaction processes, the
gas is used for either hydrogenation and/or
hydrotreating.
Coal gasification, paniculate removal, CO-
shift, and gas cleanup are the major operations
in this module. In addition, there are quenching,
cooling, and drying operations. Waste heat
recovery is included.
The only process stream leaving the module
210
-------
is the synthesis gas. Because of the numerous
operations included in this module, waste
streams predominate. Ash, slag, or char will be
discharged from the gasifier. Water streams
originate in the quench and cooling operations.
Particulates are removed from the gas and tars,
oils, and other organics are present. A carbon
dioxide/hydrogen sulfide stream exits the gas
cleanup operation. Spent catalyst will be
periodically removed.
Process operations involved in hydrogen
generation are the same as those in synthesis
gas generation except in two respects: carbon
residue or char, supplemental with coal, is used
instead of coal alone; and the CO-shift reaction
is controlled to produce a much higher
hydrogen content. All equipment, operations,
process streams, and waste streams are the
same as in synthesis gas generation.
Auxiliaries and
Utilities Modules
These include the oxygen generation
module, where nitrogen is the only waste
stream; the make up water module in which
waste streams include sludges, brines, and
spent regenerant solutions; the cooling water
module where waste streams are cooling tower
blowdown, evaporation and drift; the stream
power generation module where waste streams
include stack gas, boiler blowdown and ash;
the the product storage module in which the
waste streams are intermittent and fugitive
losses of vapors, liquids, and particulate during
loading and storage periods.
Unit Modules Summary
Table 1 presents a summary of the modules
and module components contained in nineteen
coal liquefaction processes. Some modules are
present in all liquefaction processes. Other
modules are specific for particular liquefaction
processes, such as catalytic synthesis and
supercritical gas extraction.
CONTROL TECHNOLOGIES
Liquefaction processes produce a range of
airborne, waterborne, solid, and transient
wastes. The data acquisition phases of our en-
vironmental assessment program are being
structured to provide a more quantified picture
of liquefaction related pollutant constituents
than that presently available. The modular ap-
proach will provide the framework upon which
pollutant control technologies can be com-
paratively assessed.
Air Emissions
The predicted sources and characteristics of
air emissions within each process module are
specified in Table 2. Flue gas emissions include
carbon monoxide, nitric oxides, sulfides, am-
monia, and unburned hydrocarbons. The
preparation of the coal for further treating can
produce particulates and possibly hydrocarbon
vapors. Cataly t removal and replacement may
be a source of particulates, ammonia, and
hydrogen sulfide. In fractionation, uncon-
densed gases such as H2S and C02 may be
emitted. Cooling tower drift and blowdown
contains biocides, anti-corrosive agents, and
other solids found in the circulating cooling
water. Combustion of fuels may produce air
emissions such as NOX, SOX, hydrocarbons,
particulate, and fly ash, depending upon the
fuel type used. Hydrocarbons, sulfides, sulfur
dioxides, ammonia, and particulates all may be
found in the vapors emitted from flash drums
used in the phase separation module. From acid
gas removal, C02 gases are emitted. These
gases may include some CO, hydrocarbons and
sulfides.
There is a variety of equipment available to
control different types of emissions. Table 3 in-
dicates some of the more common
technologies. Control of air emissions may
result in increased water pollution or solid
waste. Particulates containing hydrocarbons,
organic and inorganic sulfur compounds, heavy
metals, cyanides, etc., must be disposed of.
Scrubber wastes include sludges and water
containing similar contaminants.
Water Emissions
Almost all modules reject a wastewater
stream. The volume and characteristics of
water from each module is process specific,
but similarities exist among constituents of
wastewater from a particular module for all
processes utilizing the module. Water re-
quirements for coal liquefaction processes vary
211
-------
TABLE 1
MODULE COMPONENTS CONTAINED IN MAJOR LIQUEFACTION PROCESSES
LIQUEFACTION PROCESS
^•-^LIQUEFACTION
MODULE/ ^X. ~
MODULE COMPONENT ^X^ ^
1.
A.
B.
C.
D.
E.
2.
A.
B.
3.
A.
B.
C.
D.
4.
A.
B.
C.
D.
5.
A.
B.
C.,
6.
A.
B.
7.
A.
B.
C.
8.
A.
B.
9.
A.
B.
10.
COAL PREPARATION
Crushing
Drying
Pulverizing
Slurry Preparation
Preheating
HYDROGENATION
Catalytic
Non-catalytic
PYROLYSIS
Direct
Hydrocarbonization
Cooling
Quenching
HYDROGEN/SYNTHESIS
GAS-GENERATION
Coal Gasification
Char Gasification
Particulate Removal/
Quenching
Shifting
CATALYTIC SYNTHESIS
Trace Sulfur Removal
Synthesis Reaction
Cooling
PHASE SEPARATIONS
Vapor & Gas Separation
Solids Removal
HYDROTREATING
Preheating
Catalytic Reaction
Cooling
FRACTIONATION
Product Separation
Condensation
ACID GAS REMOVAL
' Absorption
Regeneration
SUPERCRITICAL GAS
EXTRACTION
4
0
0
0
0
0
+
0
0
0
4
0
0
0
4
4
4
X
u
a:
to
•1
0
4
0
0
0
0
4
X
0
0
0
4
X
0
0
0
4
4
4
4
X
_J
o
o
1
I-
0
X
0
o
o
0
0
X
0
0
o
-
X
0
0
0
X
0
0
4
X
g
X
X
UJ
H
X
0
0
0
0
X
0
0
0
+
4
1
X
SYNTHOIL
*
0
X
0
0
0
0
X
0
0
0
X
0
0
0
X
0
0
4
4
X
o
i "
UJ Z
o »- <:
UJ U.
-------
TABLE 1 (Continued)
LIQUEFACTION PROCESS
v.
^^LIQUEFACTION
^XPROCESS
MODULE/ \. o o §
MODULE COMPONENT ^\^ 5 % =
Mater Treatment
Storage
SOURCES AND
Module
Coal Preparation
Hydrogenation
Pyrolysis and Hydro-
carbonization
Hydro treating
Catalytic Synthesis
Extraction
Phase Separation
Fractionation
Gas Cleaning Module
Synthesis Gas/Hydrogen
Generation
Auxiliary Systems
and Utilities
tiJ
&
S 5R
o £ a " 5
EZ IU 14- l/> IjJ
tn 8 o 8 d
TABLE 2
CHARACTERISTICS Of
Source
Grinding, Pulverizing,
and Drying
Preheater Flue Gas
Preheater Flue Gas
Preheater Flue Gas
Catalyst Removal and
Replacement
Heater Flue Gas
None
Flash Drum Vapors
Uncondensed Gases
From Condenser
C02 Gas Stream
Acid Gas C02 Stream
Driers Flue Gas
Cooling Tower Drift
Boiler Combustion
2
p: ui2
ix £ 1 *. II i
«/>O OC cC t- tO — » 4A OC ^JO O
•-« OC •£ O (A! O O «C UJ O >- •—
1 AIR EMISSION
Emission Characteristic
Paniculate, Hydro-
carbon vapors
CO, NOX, H2S, NH3,
hydrocarbons
CO, NOX, H2S, NH3,.
hydrocarbons
CO, NOX, H2S, NH3,
hydrocarbons parti-
culates, NH3, H2S
CO, NOX, N2S, NH3,
hydrocarbons
None
Hydrocarbons, sulfides,
Sulfur dioxide, Ammonia,
paniculate
H2S, C02
C02, H2S, CO, Hydro-
carbons, Sulfides
C02, CO, Hydrocarbons,
Sulfides, CO, NOX,
H2S, NH3, hydrocarbons
Biocides, Anticorrosive,
Agents, Solids, NOX,
Gases
SOX, Hydrocarbons,
Fly ash
213
-------
TABLE 3
COMMON CONTROL TECHNOLOGIES
Paniculate Controls
S02 Controls
Wet Limestone Scrubbing
Limestone Injection
Dry inertial separators
cyclones
multiclones
baffle chambers
settling chambers
impingement separators
gravity settling chambers Sulfur Recovery
Electrostatic precipitators Claus Plants
Bag (Fabric Filters) Houses Stretford Plants
Wet Scrubbers
NOxControl
Gaseous Pollutant Control
Reduction in excess air Flares
and temperature Absorbtion
Evaporation Controls (Mainly Hydrocarbons)
Storage tank modifications
Inspections and maintenance
Vapor collection and recovery equipment
and wastewater may be treated and reused. In
such cases, less of the water utilized will leave
the plant as effluent. The type of control and/or
treatment required depends on the physical,
chemical, and biological properties of the
waste stream. All waste streams do not have
the same characteristics thus the control
technology applicable to waste streams from
certain modules will be more extensive than
from others. Wastewater streams from some
modules may be combined prior to treatment or
pretreated separately and then combined for
further treatment and discharge.
The sources and characteristics of
wastewater streams are shown in Table 4. Coal
storage piles have large surface areas and prob-
lems may arise as a result of stormwater
runoff. Water may react with coal and minerals
to form acids or to extract organics, sulfur, and
soluble inorganics. Suspended matter are com-
monly carried by runoff water.
In the pyrolysis and hydrocarbonization
module, a significant amount of foul water is
generated by the quench operation. Such water
contains phenols, tar, light oil, ammonia,
sulfides, chlorides, phenolics, and any other
products of coal pyrolysis. Vapors separated
from pressure let down systems are condensed
and such condensates form waste streams also
containing phenols, ammonia, light hydrocar-
bons, and dissolved salts, however the concen-
tration of dissolved salts is lower than that of
quench water. Water from the overhead con-
denser of the hydrotreater has ammonia and
sulfides as the primary contaminants but
phenols also may be present. Condensate
water from fractionation contains sulfides, am-
monia, oil, phenols, and dissolved solids. Cool-
ing tower and boiler blowdown may contain
high levels of dissolved solids.
Trace elements may appear in both the pro-
duct and waste streams. Most of the heavy
metals will remain in the ash but some of the
trace elements will volatilize and may build up
in the quench water. Others may be further car-
ried over with acid gases and then appear with
purge streams from the acid gas removal
module. Of particular interest is the possibility
of mercury, selenium, arsenic, molybdenum,
lead, cadmium, beryllium, and fluorine in
wastewater streams.
The complexity of the wastewater streams
from coal liquefaction indicates a need for the
utilization of a broad control technology which
includes the various treatment processes
shown in Table 5. The best practical control
technology currently available (BPCTCA) will
be a combination of some of these processes.
Again, some waste streams will be treated
through only part of the whole treatment
system depending on the origin of the stream
and its characteristics.
Wastewater from the coal preparation
module is sent to a separate retention pond to
permit the settling of suspended solids.
Coagulants may be added for better removal ef-
ficiency. Acidity can be controlled by adding
limestone. A low biological activity in the reten-
tion pond will control any organics that may be
present. Higher concentrations of pollutants
can be avoided by good housekeeping and by
use of silos for storage of small quantities of
coal on a day-to-day basis and by covering the
coal storage piles with a coating of polymer or
asphalt.
214
-------
TABLE 4
SOURCES AND CHARACTERISTICS OF WASTEWATER STREAMS
Module
Source Description
Wastewater Stream
Constituents
Coal Preparation
Hydrogenation
Pyrolysis and
Hydrocarbonization
Hydrotreating
Synthesis Gas
Generation
j^ Catalytic Synthesis
Phase Separation
Fractionation
Gas Cleaning
Hydrogen
Generation
Supercritical
Gas Extraction
Auxiliary Systems
and Utilities
Coal storage piles, crushing
and grinding operations
Cooling and quenching operation
Cooling and quenching operation
Condensing overhead vapors
Cooling and quenching operation
Shifting Operation
Condensing overhead vapors
Two or three stage pressure reduction
Cooling overhead vapors
Absorption and regeneration operations
Cooling and quenching operation
Shifting Operation
Char quenching operation
Cooling towers and boiler
Plant yard area
Storm water runoff
Foul water from quench
Foul water from quench
Condensate
Foul water from quench
Condensed unraacted water
Condensate
Condensate from overhead
condenser
Condensate
Purge Flows
Foul water from quench
Condensed unreacted water
Foul water from quench
Slowdown
Storm water runoff
Suspended particles, dissolved solids
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Phenols, ammonia, sulfides
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Phenols, ammonia, sulfides
Oils, light hydrocarbons, phenols,
ammonia, dissolved sulfides
Light hydrocarbons, dissolved salts
Dissolved sulfides in gas removal
solvent
Phenols, tars, ammonia, thiocyanates,
sulfides, and chlorides
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Dissolved solids
Suspended particles, dissolved solids,
traces of phenols, oils and tars
-------
TABLE 5
WASTEWATER TREATMENT PROCESSES
Physical
Sedimentation
Flotation
Oil Separation
Stripping
Solvent Extraction
Adsorption
Combustion
Filtration
Chemical
Neutralization
pH Adjustment
Coagulation
Precipitation
Oxidation
Ion Exchange
Biological
Activated Sludge
Trickling Filter
Aerated Lagoons
Waste Stabiliza-
tion Ponds
For oily waste streams containing high
amounts of phenols and ammonia, recovery is
generally desired. Ammonia is recovered by
stripping. After the oil is separated, phenols are
recovered by solvent extraction. A probable se-
quence of processing steps and control proc-
ess(es) to clean up sour water is as follows:
Removal of H2S, NH3, C02, light gases
• Stripper
Initial oil and solids removal
• API separators
• Baffle plate separators
Further oil and solids removal
• Clarifiers
• Dissolved air flotation
• Filters
Organic waste removal
• Activated sludge
• Aerated lagoons
• Oxidation ponds
• Trickling filters
• Activated carbon
• Combination
Solid Wastes
Of the many waste streams rejected from
various coal liquefaction modules, five basic
types of solids waste can be identified. These
are particulate coal, ash and slag residues,
char, spent catalyst and spent absorbents.
Treatment sludges are considered as solid
waste generated by control technologies and
are discussed below. Particulate coal is
generated in the coal preparation module of
each liquefaction process. Unreacted coal par-
ticles are present in the existing waste streams
of other modules as well. Ash consists primari-
ly of metallic oxides, compounds of silicon,
aluminum, calcium, iron, magnesium, titanium,
sodium, potasium and nickel being the major
constituents. In addition, a variety of trace
elements are present. Char, although utilized as
fuel and to synthesize other process reactants,
exits certain modules as waste in minute quan-
tities. Spent catalyst is periodically discharged
from modules utilizing them, as is spent absor-
bent from modules which use absorbents to
protect catalysts from acid gases. The solid
wastes exiting each module are summarized in
Table 6.
Several modules have similar solid waste
streams exiting. Spent catalyst and/or spent
absorbent are the only solids exiting the
hydrogenation, hydrotreating, catalytic syn-
thesis, and gas cleaning modules. Both of these
wastes are discharged intermittently. Some
catalysts will need changing only every two to
three years. The synthesis gas generation,
phase separation, fractionation, and hydrogen
generation modules will continuously reject ash
residue with small amounts of coal and char
particles. These streams are the major source
of solid waste generated during coal liquefac-
tion process.
In addition, control technologies will
generate solid waste streams, including
limestone sludges from sulfur dioxide removal
systems and water treatment sludges. Calcium
sulfite and calcium sulfate are the primary com-
ponents of limestone sludges. The wastewater
sludges will consist primarily of coal tars, sand,
coal fines, and water treatment byproducts.
Coal dust particles are generated in the coal
processing module. Bag house filters are
generally considered the best method of con-
trolling particulate emissions during processing
operatons such as grinding and crushing.
However, for transferring coal within the
preparation module, other vacuum cleaning
systems may be preferred. All remaining solid
waste streams may be collected without
specialized equipment.
Landfilling is the primary technique utilized in
solid waste disposal. Ideally, landfill sites will
216
-------
TABLE 6
MODULAR SOLID WASTE DISCHARGES
Solid Waste
1
3,
Module
Coal Preparation
Hydrogenation
Pyrolysis/Hydrocarbonization
Hydrotreating
Synthesis Gas Generation
Catalytic Synthesis
Extraction (Supercritical
Gas Extraction)
Phase Separations
Fractionation
Gas Cleaning (Acid gas
removal)
Hydrogen Generation
Auxiliary Systems
Utilities
a
3
i
+
0
+
0
+
0
0
+
+
0
+
+
s
I
0
+
0
+
+
+
0
0
0
0
+
0
S-
11 *
< S o
0 0
0 0
+ +
0 0
+ +
0 0
+ 0
+ +
+ +
0 0
+ +
+ +
~jj s
|8|
0
0
0
0
0
+
0
0
0
+
0
0
Remarks
Spent catalyst not continuously generated
Spent catalyst particles in gas or liquid stream
Spent catalyst not continuously generated
Small amounts of unreacted char/oil may be present
Solids from donor solvent processes only
Some systems use sulfur guard absorbents
Particulate product losses during handling, ash and
particulates from coal/char burning boilers
+ denotes waste stream is generated in module
0 denotes waste stream is not generated in module
-------
naturally prevent horizontal or vertical migra-
tion of solid waste constituent materials to
ground or surface waters. Impervious liners
may be necessary to assure this. Periodic
sampling and analysis of potential leachates is
an additional preventive measure.
Utilization of solid wastes to produce useful
byproducts is also being considered, with
primary emphasis on utilizing ash as a constit-
uent of construction materials, such as asphalt
and concrete blocks. Ash has also been used
successfully, in the revegetation of mined-out
areas. Scrubber sludges, elemental sulfur,
phenols, naphtha, and ammonia are other
byproducts which could be used beneficially.
Transient Pollutants
Waste streams produced during normal proc-
ess operation are expected and provisions are
made for their disposition on a continuous
basis. Consideration must also be given to
waste streams generated as a result of intermit-
tent occurrences. These releases may be
unplanned or accidental, caused by leaks,
spills, upsets, startups, shutdowns, power
failure, process equipment failures, slugging,
surging, and overloading. They may also be
caused by or occur during maintenance opera-
tions. Such releases have been termed tran-
sient pollutants. Because of their nature they
are difficult to sample, analyze, and classify.
However, if some thought has been given to
these events, it is more likely that the impact of
fugitive emissions can be minimized when they
do occur. In many cases the best disposition of
the waste stream is to return it to the process.
Spills and leaks will occur and provisions for
cleanup and containment should be made.
Pumps and valves are known sources of leaks.
Solids handling equipment can cause problems.
Belt conveyors or bucket elevators can break or
jam causing spills or fires. In such cases, it may
be necessary to dump materials in order to
make repairs for resumption of normal opera-
tions. Vacuum cleanup trucks could be used to
reclaim the spilled solids for reuse. Water
flushing can be provided to wash residual
solids and to flush oil spills to an "oily water"
sewer system for recovery.
During startup, shutdown, or a plant upset,
off specification products may be made. Rather
than dispose of these materials through the
waste treatment facilities, it will probably be
much more desirable to store them and rework
them into the proper specifications. This pro-
cedure, however, will require adequate
storage. Enclosed storage will be needed for
many of the liquids removed at shutdown.
Vapors and particularly odors may be released.
Water layers from separations will contain
various sulfur, nitrogen, and oxygen com-
pounds that should not be allowed to escape to
the atmosphere. These liquids can be stored
until a subsequent startup and used for
recharge or they can be worked off through the
wastewater treating systems.
Before maintenance is performed, the equip-
ment or system will have to be purged to
remove toxic and combustible gases. Purge
gases should be sent to an incinerator or fur-
nace. This will also be true for shutdowns. Cer-
tain catalysts or carbonaceous materials may
be pyrophoric at high temperatures. Inert gas
purge and cooling will be required to prevent
fire.
In the case of plugging, it may be necessary
to flush the system with a light oil or with
water. Provision must be made to collect and
store the cleaning stream until it can be either
recycled or treated for disposal. Slugs of liquids
may be sent to the flare because of upsets or
surges. Serious fires or explosions could be
caused if separators are not sized to prevent
entrainment.
In general, inspection, monitoring, and
maintenance programs are an essential part of
controlling transient pollutants.
SUMMARY
A generally applicable modular approach to
dividing coal liquefaction processes into group-
ings of unit operations based on function is pro-
posed. The approach promises to be an effec-
tive way of comparatively assessing the waste
streams from the wide variety of liquefaction
processes. The advantages over alternative, in-
218
-------
dividual process approaches are the ability to ACKNOWLEDGMENTS
comparatively evaluate waste streams from
dissimilar unit operations on the basis of The paper presented summarizes some of the
module function and to allow for process initial efforts on a comprehensive study entitled
designs changes as they evolve from concep- Environmental Assessment of Effluents from
tual pilot scale to full commercial size. Coal Liquefaction. The study is supported by
the Environmental Protection Agency under
Contract No. 68-02-2162.
219
-------
A PROGRAM FOR PARAMETRIC
EVALUATION OF POLLUTANTS
FROM A LABORATORY GASIFIER
John G. Cleland, Project Leader
Research Triangle Institute
P.O. Box 12194
Research Triangle Park,
North Carolina 27709
Abstract
Pollutants from gasification processes are
being evaluated utilizing a small semibatch
reactor. Emphasis is placed on analyzing the
production of trace contaminants, especially
those presenting potentially pronounced toxic
or carcinogenic hazards. Research is progress-
ing in three phases: (1) Chemical screening
analyses of the scope of pollutants produced;
12) Evaluation of controlling reactor parameters
to reduce specific compounds; and (31 Reactor
kinetics studies of first-priority pollutants.
Design and construction of the reactor facility
and initial baseline tests have been completed.
INTRODUCTION
Work was begun this year at the Research
Triangle Institute to investigate some particular
pollution problems associated with coal con-
version. The research is funded by the En-
vironmental Protection Agency/RT. The pro-
gram has recently moved into data accumula-
tion, and the following discussion describes,
for the most part, preparation that has been
made for the experimental and theoretical
research to follow.
With the program still in the early stages,
research goals, as determined n coordination
with EPA, are being continually defined. Major
priorities of this work are, however, cle.jr at
present. Emphasis will be placed upon the
assessment and analysis of trace po'lurants
possibly associated with coal conversion o'oc-
esses which have received 'ittle attention in the
past. This includes particularly investigation of
many organic compounds which are assoc ated
with carcinogenic cr highly tox;c properties.
Other compounds presenting potential hazards
to human health, such as some of the trace
elements, will also be included.
When full-scale synthetic fuels plants (e.g.,
20,000 tpd of coal) are considered, even trace
constituents may be present in significant
amounts, Such plants are capable of producing
daily (1? more than * 5 railroad tank cars of tars
and heavy liquids; (2) byproduct waters direct-
ly downstream from the reactor containing as
much as 340,000 pounds of ammonia, 6,000
pounds of thiocyanates, and 800,000 pounds
of phenol; and (3) hazardous contaminants in
raw gases, licuids, or solids from the reactor
that can possibly find their way into the en-
vironment or the synthetic fue1 product.
The RTI researc^ is primarily concerned with
the n jcleus of any coal conversion plant, the
reactor, which -eceives and evolves most of
the process sfeams of environmental interest.
Whi'e there are certainly other pollution prob-
lems n the gas beneficiation and cleanup
modi'les of a p'ant, the reactor is the major
source of compounds go'ng to both product
gastf? and effluent streams.
As indicated 'n Figure 1, we are also con-
ceneded with the ash, char, particulates, tars,
enc' 'iqu'ds in reactor outputs. These, along
with re?actcr nputs and product gas, constitute
the major mess flows at the front end of any
coal conversion system. Research in this area
complements /') other efforts being directed
toward environmental control for coal conver-
sion in the Research Triangle area (discussed in
other papers at this Symposium) and (2) the in-
tensive on-site sampling and analysis, control
options evaluations, and other environmental
assessment end control technology develop-
ment being carried out by prime contractors for
EPA; see Figure 2. RT' findings will be com-
pared with EPA ana'yses being done on a much
larger scale, e.g., 'r joint programs with ERDA
or at the Kosovo, Yugoslavia Lurgi gasification
plant.
The research at RTI was prompted by several
reeds end interests of t^e Environmental Pro-
tection Agency
1. There has been increased emphasis on
invest;gation of toxic constituents in
the environment wh ch, in many cases,
may be present in relatively low con-
centrations. This emphasis has been
fostered by more extensive and suc-
cessful cancer research and other
related health and medical studies. The
220
-------
REACTOR STREAMS
COAL
REACTOR
GAS
STEAM
^CH;
GAS
TARS
LIQUIDS
I ASH \ / • CHAR
] V_T_
METHANATION
CLEAN UP
PRODUCT
GAS
OTHER
EFFLUENTS
EMISSIONS
Figure 1. Reactor streams.
-------
EPA
to
N>
INHOUSE, RELATED
CONTRACTS AND
MULTI-AGENCY
RESEARCH
GRANTS RESEARCH
REACTOR POLLUTANT ASSESSMENT
ACID GAS CLEANUP
WATER POLLUTANT CONTROL
(SOLID WASTE DISPOSAL)
PRIME COAL CONVERSION
CONTRACTS
ENVIRONMENTAL ASSESSMENT
CONTROL TECHNOLOGY
DEVELOPMENT
Figure 2. EPA program.
-------
association of oncogenic activity with
environmental causes is now widely
accepted.
Increased environmental concern in the
nation has necessarily extended into
new areas of environmental problems.
Improved chemical analytical tech-
niques, which have made it possible to
quantify substances at nanogram levels
and parts per trillion concentrations,
have influenced the increasing list of
potential pollutants. Table 1 lists some
potentially hazardous substances taken
from an investigation of more than 200
substances.1 These are grouped in
terms of increasing hazard potential
based upon both carcinogenic and tox-
ic effects (it may be noted that some
compounds, such as SO2, are not in-
cluded when considerations of quan-
tities in the environment are ignored).
2. EPA recognizes that there are large in-
formation gaps concerning highly toxic
substances associated with coal con-
version. The problems, whether real or
imagined, must be verified, or
eliminated. Certainly, claims of en-
vironmental dangers associated with
synthetic fuels which slow the pro-
gress of the industry must be ad-
dressed. A general example of the force
of such claims is a settlement agree-
ment resulting from litigation against
EPA by various environmental
organizations. The agreement sets a
time table for new source performance
standards, effluent guidelines and
pretreatment controls for a list of more
than 300 specific point source
categories or industries. Commonly
referred to as the Consent Decree,2 this
document now has been modified to in-
clude more than 100 substances which
must be addressed for pollutant con-
trol.
3. Regulatory and standard setting proc-
esses are encompassing a larger
number-of pollutants. A new source
performance standard under EPA
review would designate control levels
for sulfur species and hydrocarbons in
the areas of coal gasifier lockhoppers,
coal gas purification facilities,
byproduct recovery. gas/liq-
uid separation facilities, and sour water
stripping facilities.3 The fairly recent
OSHA standard for hydrocarbon con-
trol in the vicinity of coke ovens
(primarily concerned with carcinogenic
activity) set an important precedent.
This organization has also legally
established threshold limits for about
500 different substances in the
workroom atmosphere.4
4. Research on coal conversion reactors
and associated toxic substances is con-
sidered an important factor in develop-
ing control technologies in these areas.
Processes for direct burning of product
gases from low Btu gasifiers, followed
only by particulate cleanup, have been
proposed. Both high- and low-Btu con-
version processes often call for com-
bustion of chars and tars for process
heat and steam. These feedstocks
must be analyzed to insure that in-
cineration will accomplish complete
destruction of hazardous materials.
The most important control option to
be observed at the RTI experimental
facility will be that of the reactor itself.
The concept of utilizing the reactor for
pollutant control through parametric
variations is not an original one, but has
received little previous development.
The Environmental Protection Agency
is interested in the idea of utilizing
process variations or modification of
process modules in order to effect en-
vironmental control. Where this is
possible, of course, redundance and/or
retrofitting of additional control
systems is avoided. It is at the same
time essential that any variations in
process operation not severely limit
production or result in unfavorable cost
tradeoffs between process variation
223
-------
TABLE 1
SUBSTANCES RECEIVING TOXIC INDICATORS
2-Ch loro-2,3-epoxy propane
Formaldehyde
Acrolein
Phthalic acid
Monomethyl hydrazine
Aminotoluenes
2-Aminonaphthalene
4-Aminobiphenyl
1-Aminonaphthalene
N.N'Dimethylhydrazine
a-Chlorotoluene
1-Chloro-2-Nitrobenzene
1-Chloro-4-Nitrobenzene
2,4-Dichlorophenol
2,4,6-Trinitrophenol
Anthracene
Chrysene
Dibenzo( b,def) chysene
Benzo(b)fluoranthene
Pyridine
Dibenz(a,j)acridine
Dibenz(a,h)acridine
Dibenz(c,g)Carbozole
Tetraethyl lead
Organotin
Nickeocene
PPAH (Collective)
Lithium
Lithium hydride
Barium
Germanium
Bismuth
Hydrogen sulfide
Tellurium
Vanadium
Nickel carbonyl
xx
N-Nitrosodimethylamine
N-Nitrosodiethylamine
Ethyleneimine
Diazomethane
PCB's
4,6-Dinitrocresol
Benz(a)anthracene
Dibenzo( a,i} pyrene
3-Methylcholanthrene
Tetramethyl lead
Thallium
Lead
Hydrazine
Phosphorus
Phosphine
Antimony
Antimony Trioxide
Ozone
Cobalt
Nickel
Silver
Uranium
xxx
4-Nitrobiphenyl
Dibenzo(a,h) anth racene
Benzo(a) pyrene
Alkyl Mercury
Beryllium
Arsenic
Arsine
Arsenic Trioxide
Selenium
Chromium
Cadmium
Mercury
224
-------
and simply adding control tech-
nologies.
5. Benefits may accrue through operation
of a small and versatile system where a
number of system variations can be
assessed inexpensively. The bench-
scale approach developed is quite flexi-
ble, allowing changes in the course of
research where indicated to be pro-
fitable. This avoids the difficulties and
expense incurred in attempting the
same approach with a pilot- or full-
scale unit and allows rapid response to
reassessed needs and prior results.
6. Finally, some facets of this program
mark a continuation of an earlier project
supported by EPA in the area of reac-
tion kinetics associated with coal con-
version.6 The main emphasis of this
previous work was on desulfurization
kinetics and involved a nonisothermal
approach which will be followed up on
a broader scale. This approach holds
some promise and could produce at
least some predictions of probabilities
of formation for compounds of interest.
RESEARCH APPROACH
The research program is intended to progress
in the three complimentary phases: screening
studies, parametric control evaluations, and
reaction kinetics research.
The first phase of efforts, screening studies,
will be first associated with broad qualitative
chemical analyses of a large number of com-
pounds produced during gasification reactions.
Attempts will be made to gasify a variety of
U.S. coals through a range of reactor condi-
tions, primarily to provide the opportunity for
production of practically any substance which
might be associated with gasification. It is
probable that up to 300 different compounds
will be screened following many of these tests.
Qualitative screening, which will emphasize
detection of the presence of the higher
molecular weight organics already mentioned
and particular compounds designated as hav-
ing high toxic potential. The screening will also
produce relative quantifications for selection of
particular compounds that are present in gross
enough quantities to warrant further investiga-
tion. Work will also be concerned with the
isolation of chemical groups, such as
polynuclear aromatics.
Screening studies will then move into the
quantitation of selected compounds which,
because of their relatively high concentrations
balanced with their health hazard potential, are
specified as important gasification pollutants.
Confidence in this approach will be built
through reproduction of the same substances
under similar conditions while utilizing more
specific and rigorous analysis.
Figures 3a and 3b (Figure 3a is an overlay)
demonstrate one approach for estimating the
amount of sample which must be taken from
the products or byproducts from the gasifier to
insure that possibly hazardous pollutants have
been detected at levels which may be en-
vironmentally significant. Parameters taken in-
to consideration include:
1. For a full scale plant—average stack
heights, average wind speeds and
weather conditions within the U.S.
(primarily based on the states with high
coal reserves), plant production (a
20,000 ton/day of coal plant was con-
sidered here), and a maximum concen-
tration for any specific pollutant
calculated using a dispersion model.
2. For the experimental setup—test dura-
tion, amount of coal input, duration of
the sampling period (variable), and the
percent of product/byproduct stream
sampled during the same period
(variable). The latter were multiplied to
form a composite variable.
3. For the potential pollutants —an
estimated permissible concentration
(variable) has been derived for over
200 potential pollutants from fossil
fuel processes.1 Parameters 'nvolved in
the derivation of these permissible con-
centrations (which in this case only in-
cluded EPC's for ambient air consider-
ing effects on human health) were
threshold limit values, LD50's and
225
-------
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RF/T-D
2 x 1012 2 x 1011 2 x 1010 2 x 109 2 x 108 2.5 x 107
10,000
5,000
2,000
1,000
500
t-x 200
(sec) 1QO
50
to
ro
detection limit (grams)
Estimated Permissible Con-
centration
experimental reactor coal
feed (grams)
test duration (hours)
sample period (seconds)
fraction of main stream sampled
20
101-EPC =
5
2
1
0.5
0.2
EPC ug/nT
Figure 3b. Sampling required for proper environmental assessment.
-------
human breathing rates, or in some
cases, carcinogenic potential, human
consumption rates, or ecological ef-
fects.
The overlay with Figure 3 shows those
pollutants which fall into a specific sampl-
ing—i.e., sample percent ranges associated
with their particular estimated permissible con-
centrations. These sampling ranges are further
subdivided by the parameters of the experimen-
tal tests that are possible with the RTI synthetic
fuels reaction system.
An important part of both qualitative and
quantitative screening will be the development
of improved analytical techniques for analysis
of coal conversion products and byproducts.
(Developments to date will be discussed in
another paper at this Symposium.)
Throughout testing, quantitative meas-
urements will be made on-site of fixed gases,
sulfur species, and hydrocarbons up to CQ.
These analyses will be made by gas
chromatograph and, at a later date, continuous
gas monitors for the major product gases
associated with gasification.
The second phase of research, concerned
with parametric studies, involves application of
the gasification reactor to the control of poten-
tial pollutants. Parameters to be considered for
investigation include those listed in Table 2. To
these could also be added the parameters of
bed type (fixed, entrained, fluidized) and reac-
tor type (batch, semibatch, plug flow, mixed
flow) which should receive attention as
research progresses. A statistical approach for
optimization of parametric combinations to
minimize the number of tests required while in-
vestigating all possible influences is currently
being undertaken.
Results from parametric testing will be con-
tinuously compared with those from chemical
analyses so that influential variables can be
more extensively assessed as testing pro-
gresses. It is obvious that, unless the test plan
is directed by previous engineering data , the
number of tests could burgeon to orders of
103-104.
Other researchers6 have noted the influence
of different reactor configurations on the pro-
duction of byproducts of possible environmen-
tal significance. Results of this nature are
scarce, however, and extrapolations are dif-
ficult. The literature7'8'9'10-11 describes some
established effects of the variation of reactor
TABLE 2
POSSIBLE REACTOR PARAMETERS
COAL TYPE
GRIND SIZE
GASES
COMPOSITION
FLOW RATE
STEAM
PRETREATMENT
CATALYST
BED DEPTH
TEMPERATURE
PRESSURE
RESIDENCE TIMES
228
-------
conditions on major gasification kinetics. Some
examples follow:
Pretreated chars may be several orders of
magnitude less reactive in terms of oxidation
than raw or mildly pretreated coals. The rate of
the endothermic reaction
C + H20 - CO + H2
varies widely for different coals. Char-C02
gasification and hydrogasification contribute
little to coal conversion in low pressure
steam/oxygen gasifiers. High temperatures
favor CO production in the exothermic water-
gas shift reaction, while hydrogen is more evi-
dent at lower temperatures. Conversion of coal
sulfur to gaseous species is a rate-limited
phenomenon, and is generally promoted by
conditions that lead to high carbon conversion.
Product distribution through pyrolysis or
volatilization is a strong function of both the
final reaction temperature and the time taken to
reach it. For example, at high heating rates on
the orders of 10,000-50,000° C/s-rates
typically attained in continuous fluidized bed
and entrained bed gasifiers—the yield of
volatiles at a given temperature and the tar-to-
gas ratio of the product are both higher than at
lower heating rates. Packed beds, larger par-
ticles, and elevated gasifier pressures tend to
diminish yields of tar and augment yields of
char and light hydrocarbon gases during
pyrolysis. Observations indicate that char, in
general, is less reactive than carbon in
nondevolatilized coal in reaction with such
species as steam, oxygen, or hydrogen.
Another factor, which can be particularly im-
portant in an experimental nonproduction
system such as the RTI reactor, is that of
nonsteady state conditions. Also, steady-state
production of major gases (CO2, CO, H2, CH4)
is not an assured indication of a steady output
of trace constituents.
Possible relationships of formation prob-
abilities to process parameters will be further
evaluated in the kinetics phase of the RTI
studies. Some tests in this phase will include:
1. Development of analytical methods,
2. Ascertaining appropriate level of
stratification of pollutants,
3. Conducting experimental nonisother-
mal tests, and
4. Reduction, tabulation, and analysis of
data and application to pollutant reduc-
tion.
Data obtained through the nonisothermal
measurement technique is applicable to any
chemical reaction. Nonisothermal techniques
are somewhat controversial, and options for
reverting to isothermal studies will be retained.
In the analysis of coals and coke, nonisother-
mal measurements are advantageous because,
in isothermal studies, the large effect of heating
to a given reaction temperature is controlling
the competing reactions and consequently the
results. For the nonisothermal method, the
reaction rates are to be studied at a
preprogrammed rate of heating of the solid
samples.
Figure 4 depicts the reaction velocity con-
stants for the decomposition of hydrocarbons
and petroleum fractions associated with
petroleum refining. On this figure is superim-
posed the typical reaction velocity curve as a
function of temperature obtained from some
previous studies utilizing nonisothermal reac-
tion kinetics. It is obvious from this simple ex-
ample that if the reaction velocity can be ob-
tained as a function of temperature, the
operating conditions can be selected to favor
the desired reactions and to minimize the
undesired ones.
One theoretical procedure for obtaining
changing concentration (for first order kinetics)
as a function of temperature is given in equa-
tions below.
If JL = X, -dt = dX
J_
dt = T2 dT
1
t =
1
K
dV
Vf - V
= - k0 exp f -
229
-------
THEKMAL CKACKIXG AN1> DECOMPOSITION" PKOC1CSS
\
I- fimeisec}
x-percenloge decomposed
i TYPICAL ;
GASIFICATION j
KINETICS !
0.001
0.0003
0.0 OO6
0.0 OO5
0.0004
0.0 OO3
0.0 OO
O.OOOI
0.00008
0.00006
0.00005
0.00004
O.OO003
0.00002
0.00001
TOO 750 BOO 850 900 1000 1100 1200
Temperature, °F
I40O 1600
O.OOOOI
i c iJ3, 55,000 cal
K = 1.6 x 10 /sec exp 2
RT - °K
Figure 4. Reaction velocity constants for the decomposition of hydrocarbons
and petroleum fractions into various products.
230
-------
~v
In-
koR / E \ k0R[ E~|
-—exp(--x) =--2- exp- —
E V R ) _ E [ RTj
In
Vf-V
- In
In
k0R
E
RT
This approach, properly conducted, permits
the simultaneous determination of the sets of
two parameters in the typical Arrhenius expres-
sions for the reaction velocity constants for
pollutants of interest. An example of a plot for a
first order test is shown in Figure 5.
Knowledge of the kinetics of formation can
be utilized to suggest changes in the operating
conditions of a synthetic fuels conversion
system to minimize pollutant formation. Such
changes can then be confirmed, for example,
on the RTI gasifier. The results from the use of
chemical reaction theories will be related to the
corresponding experimental and chemical
analytical studies.
Although the thermodynamics and kinetics
of coal pyrolysis, gasification and desulfuriza-
tion have received attention, these areas are
still not well defined. Complexities of the
materials and the reactions involved make a
unifying theory most elusive. Descriptions of
Intercept =
slope = -5-
1
T
Figure 5. First-order test plot.
231
-------
devolatilization have, for the most part, treated
the combined volatile fractions. This
necessitates such approaches as Gaussian
distribution estimation of the activation
energies, semi-empirical results for determining
rate constants, mean activation energy and
standard deviations, and some rather com-
plicated rate expressions. Devolatilization rate
may be controlled by kinetics or mass and heat
transfer, and the product distribution is often
provided by coupled effects. Also, reactive
volatile products such as tars may undergo
secondary cracking or polymerization reac-
tions.
For gasification, mechanisms and rates of the
reactions involved have been postulated. Rate
laws of the Langmuir type and also more
simplified forms have been proposed for the
primary carbon/steam mechanism. Van-
Fredersdorff and Elliott7 have proposed a
Langmuir-Hinselwood rate law given by equa-
tion
PCO PH20
Ik PH2PC02
1 + KAPC02 + KRPCO
Wen12 uses a simpler form of the rate law, a
reversible second order expression.
A literature survey has been carried out to ex-
plore these and other efforts describing coal
gasification kinetics, including the reactions
leading to the generation of H2S, CS2, and
COS. While these studies provide some ex-
emplary approaches to solving reaction kinetics
problems, it is recognized that the same ap-
proaches may not be applicable to formations
of trace constituents of interest and that indeed
problems involved in the latter effort may be
much more difficult.
IMPLEMENTATION OF APPROACH
The unique requirements of the program
have demanded extensive additions of hard-
ware, facilities, and analytical equipment. The
opportunity of close coordination with the En-
vironmental Protection Agency and familiarity
through previous programs with the en-
vironmental problems of coal conversion proc-
esses have facilitated progress.
Attempts have been made initially to avoid as
many problems as possible. Initial testing will
investigate the gasification area of fossil fuels
conversion only. A simple experimental system
has been devised that is much less complex
than a full-scale plant design yet, hopefully, of-
fers good approximation of the reactor opera-
tion of such facilities.
The coal conversion reactor, Figure 6, top-
ped by the tubular coal feed hopper, extends
only approximately nine feet in height. Under
operating conditions, the reactor is encased in
a vertical furnace which allows preheat of inter-
nal inert gases or reactor wall heating of the
coal bed and gases during reaction.
The reactor operates in a semibatch
mode —i.e., the entire charge of coal to be
gasified is injected into the reactor, and steam,
Figure 6. Gasification reactor.
-------
along with other gases, is continuously passed
through the bed during a test run. Sucn an ap-
proach obviously relieves i:he expe,'mer.i;al
work of the complications of continjous coal
feed and ash/char removal. Consequently a
porous,temperature-resistant ceramic f,ow
distributor, Figure 7, which supports the coal
bed in the reactor itself, is situated in the reac-
tor. This allows a reasonably homogenous
fixed bed or, on the other hand, a truly fluiaized
bed as opposed to many of the suspended or
highly entraining beds associated with nany
pilot-scale processes. The flow distributor is
designed to eliminate channeling around the
circumference and to present a pressure orop
conducive to optimized fluidization should the
reactor be operated in this mode.
Coal beds in the reactor are fixed a; present.
It is hoped that reasonable results and simula-
tions can be obtained with fixed bed rdac^on
since this will eliminate the modeling dif-
ficulties associated witn fluidized beds, e.g.,
Dabbling. The primary concern is to simulate
the reaction history of coal particles introduced
into gasification reactors, particularly those
phases which might be most closely associated
with the production of contaminants. These
phases include (1) surface evaporation of
voiatiies —prooably zero order, low activation
energy; (2) diffusional evaporation of
voiatiies —probably first order, low activation
energy; (3) surface cracking—complex order,
high activation energy; and (4) organic sulfur
deoomposit;on and removal—two ranges, first
o;der, high activation energy. A comparison of
•cne differences between continuous and batch
feed in terms of coal particle history and reac-
tion analysis is given in Table 3.
While investigating some of the fundamental
questions associated with the possible produc-
tion of toxic materials in this experimental
gasifier, it is at the same time essential that the
experimental procedures offer a real approx-
imation of gasification processes which exist or
2.625
2.1875
1.625
ZIRCAR
ALUMINA
MATERIAL
2.0
Figure 7. Flow distributor
233
-------
fO
s
TABLE 3
COMPARISON OF REACTOR CHARACTERISTICS
BATCH
CONTINUOUS
FEED MATERIAL REQUIRED
LENGTH OF RUN
BEST APPLICATION
INDEPENDENT VARIABLE
(CHEMICAL REACTIONS)
TYPICAL RATE EQUATION
USUAL MEASUREMENTS
ONE REACTOR VOLUME
ABOUT 1 REACTOR TIME
EXPERIMENTATION
TIME
j£ = K[T{t)]c(t)
c(t)
MANY REACTOR VOLUMES
MANY REACTION TIMES
PRODUCTION
DISTANCE; AND TIME
UNTIL STEADY STATE
ujj!= K[T(x)]c(x)
c at x = o; x = L
-------
have been proposed for operation in the United
States. The laboratory gasifier has been design-
ed to cover a wide range of operating condi-
tions to provide some simulation of large-scale
gasifiers. Mass ratios of gases or steam to coal
ratios, internal pressures, reactor gas and coal
bed temperatures, bed types, particle sizes,
and other parameters can be matched. The
reactor is presently intended to gasify up to
two kilograms of coal (noncaking or pretreated
coals), and operate in pressure ranges from am-
bient to 1,000 psig (depending upon
temperature) and temperatures to 1950° F.
Nominal testing ranges at present are 200-300
psig, maximum temperatures to 1900° F, and
coal masses of less than one kilogram.
All gas flow and pressure control is maintain-
ed at a single control panel. Steam generation
and steam superheating to injection
temperatures (up to 1 500° F) are accomplish-
ed through a series of remotely controlled fur-
nances fed by high-pressure, low-flow meter-
ing pumps.
Temperature control within the reactor itself
is accomplished in one of two ways:
1. Controlling the level of oxygen flow
and, therefore, combustion within the
coal bed, and/or
2. Varying current supply to the remotely
controlled vertical furnace and a
separate strip heater near the top
flange of the reactor.
Internal temperatures are measured in the
reactor in the axial direction during testing. Ver-
tical temperature gradients scheduled for
observations are quite possibly an important
parameter in the generation of particular
gasification contaminants. Provision has been
made for remote control of the three zones of
the vertical furnance utilizing a Datatrack pro-
grammer. This allows graphical inputs describ-
ing a desired temperature profile to be followed
during test runs. Therefore, during nonisother-
mal kinetic studies, a temperature profile can
be selected to eliminate nonlinearities in the
solutions to proposed rate equations and allow
simplified extrapolation and solution for rate
constants and activation energies.
An operational schematic of the mechanics
of the experimental laboratory gasifier system
is shown in Figure 8.
Product gases from the gasifier pass through
a series of traps designed to eliminate par-
ticulates, tars, water, and other condensates
before the gases pass to the gas sampling train.
Substances remaining in the traps are analyzed
primarily by GC/mass spectrometry and high
pressure liquid chromatography.
The RTI sampling train in use at present is
shown in Figure 9. Discrete gas samples are
currently being taken for on-site analyses by
gas chromatography of fixed gases (N2, 02,
CO, C02), sulfur species (e.g., H2S, COS), and
hydrocarbons (less than C6). On-site con-
tinuous gas monitors will be added in the near
future for fixed gases and methane. This is, of
course, most important to assure reasonable
simulations by the laboratory reactor of real
gasification processes. Heavy organics and
other constituents are being adsorbed by XAD2
and Tenax cartridges. The XAD2 cartridges are
sufficiently large to allow passage of the entire
product gas stream through them throughout a
test to provide an integrated sample of all con-
taminants, while the Tenax cartridges are
valved to be individually selectable so that
sampling may also be associated with discrete
test times.
The sampling system is presently con-
structed of stainless steel. A glass sampling
system is being planned.
All sampling and analysis areas are contained
under ventilated hoods. The entire reactor
facility area has been well ventilated to prevent
worker exposure to hazardous contaminants.
An on-site signal processing unit has been in-
cluded to manage both the large amount of
data from the numerous sensors included in the
experimental system and that data from on-site
chemical analysis. This unit includes a 64 K
core with compatible disk & orage. Rea- ' ne
functioning is included which will allow ieactor
and sampling system control, automatic safety
shut-off and on-line analysis during test
periods. All data will be processed, stored, and
analyzed through this system. The signal proc-
essing unit is backed up by multipoint and
analog strip chart recorders and digital
displays.
INITIAL TESTING
Experimental evaluations have just begun us-
ing the reactor system. A period of pregasifica-
235
-------
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Figure 8. Process schematic
-------
ro
Tenax
Cartridge
Sampling
Ports
Tenax
Cartridge
Sampling
Ports
iASEOUS \SAMPLIN6 MANIFOLD
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Figure 9. Gaseous sampling manifold.
-------
tion testing has included the following:
1. Calibrations of pumps, flow meters,
thermocouples, pressure transducers,
gas chromatographs, temperature con-
trollers, digital displays, strip chart
recorders, furnace responses, gauges
and metering valves.
2. Heat up tests for steam generation,
reactor internal temperature control,
and particulate, tar and condensate
trap temperature control.
3. Overall system flow tests using inert
gases, and pressurization of all system
modules.
4. Evaluation of radial temperature pro-
files within the reactor at various gas
flow rates and flow distributor posi-
tions.
5. Fluidization tests in a plexiglass "reac-
tor" with various coals of different
mesh sizes.
The first reactor tests have been carried out
primarily to ascertain the proper functioning of
the system and the logistics of the sampling
and analysis techniques. To facilitate matters,
a Western Kentucky FMC char, low in volatiles
and free-swelling index, has been used. A first
test took a 175-gram sample of this char to
nearly complete combustion with about 43
grams of ash remaining at the end of the test.
Char-ash analyses are given in Table 4. Both
air/coal and steam/coal mass ratios were near
1:1 to begin with and, air flow was increased at
discrete intervals over the two-hour test.
Temperatures did not exceed 800° C.
Chemical analyses were not done for the prod-
ucts of this test.
A second test included much less complete
reaction of the char, about 67 percent. Some
gross chemical analyses done on the products
of this test indicated lower carbon monoxide
and higher hydrocarbon yields, which would be
expected to be associated with the lower reac-
tion temperatures of this test. Gas production
was still increasing at the end of the sampling
period, indicating that steady state conditions
for gasification were not reached. Results from
these tests remain qualitative, and more de-
tailed assessment remains to be done. One in-
dication from these and other tests is that inter-
TABLE 4
CHAR/ASH ANALYSES
Analyzed For
Char
Sample Air
Ash
Sample A1C
BTU/lb.
Moisture, %
Ash, %
Volatile Matter, %
Fixed Carbon, %
Sulfur, %
Carbon, %
Hydrogen, %
Oxygen, %
FSI
Ash Fusion Temp.
Nitrogen (TKN), %
11 ,090
1 .0
19.7
7.8
71 .5
1 .8
74.02
1 .48
1.7
<1 .0
2,600
1 .3
570
0.9
91 .0
6.9
1.2
0.2
13.82
0.82
<0.1
<1.0
2,610
0.3
238
-------
nal reactor temperatures could be reasonably
controlled by varying power input to the sur-
rounding vertical furnace. Therefore, a more re-
cent experiment investigated gasification of a
small amount of char, 1 75 grams again, in the
absence of combustion.
This last experiment was carried out utilizing
the Datatrack programmer to provide a ramp
function for control of vertical furnace
temperatures. Furnance and reactor
temperatures were initially increased to approx-
imately 700° C before char was injected into
the bed. Steam was continuously passed
through the bed following injection. Steam
flow was supplemented by a carrier gas (N2) to
improve flow and temperature stability of the
injected steam.
It has been demonstrated in all tests that heat
conduction and gas flow convection through
the bed allow reasonably short heat-up times to
increase char bed temperatures to those
originally in the preheated reactor. Increased
flow through the bed has been demonstrated to
shorten this heat-up time. Internal reactor and
coal bed temperatures were also demonstrated
in the last mentioned test to closely follow the
signal input for signal temperature control from
the Datatrack program. These results are
shown in a general fashion in Figure 10.
Few problems have been encountered to
date in this simple and low risk system design.
Some recognized problems, however, have in-
cluded the difficulty of flow control at very low
rates (for example, less than 1 standard liter
per minute) and high pressures, placement of
the flow distributor within the reactor which
will completely prevent channeling and conse-
quent oxygen breakthroughs, coordination of
metering valve controls with back pressure
regulation at very low gas flow rates, place-
ment of sufficient thermal insulation in small
spaces where high heat losses are possible,
maintaining upper reactor temperatures to pre-
vent condensation of exit gases before passage
through the proper traps, and maintaining
superheat steam temperatures at very low flow
rates. Most of these problems have been
solved, all or in part.
PLANNED RESEARCH
During the final quarter of the first year of
research, several brief tests are planned which
are concerned with improving system con-
trollability as indicated by results from early
gasification tests. Reevaluation of system com-
ponents is also being carried out.
As soon as confidence has been developed in
the capability of the RT! reactor to provide
reasonable simulation of coal gasification
characteristics, a second phase of gasification
testing will be entered. Different coals and
reactor parameters will be used, and extensive
screening evaluations of all products and
byproducts will be carried out. Intentions are at
this time to begin with a representative eastern
coal (e.g., Kentucky, Illinois, or Pittsburgh).
This coal will be of a reasonably large mesh size
such as the 10 by 80 char size used to date.
Testing on the eastern coal will be followed
by gasification of a western subbituminous
coal such as Montana Rosebud. Again, a large
mesh size will be used. Both coal samples will
be gasified during separate tests at two dif-
ferent temperatures. Future comparisons will
be made with real gasification processes.
Further tests will be carried out using smaller
mesh sizes. This will be done first to evaluate
the coal supply system with these sizes,
secondly to investigate bed flow through or
fluidization problems, and finally to examine
the effects upon pollutant production.
All future plans are dependent upon direc-
tions from the Environmental Protection Agen-
cy. Some likely improvements will include in-
house coal preparation including grinding ancl
screening and possibly in-house sample
analyses to include proximate, ultimate, and
more intensive analyses. It was mentioned
previously that continuous gas monitors will be
added to give real time assessment of product
gases. A number of safety features and alarms
are planned. Preliminary investigations have
been begun into utilizing gamma ray detection
for measurement of fixed or fluidized bed levels
within the reactor. Hopefully, in-house
pretreatment of caking coals will be added.
239
-------
1100
TIME-TEMPERATURE
HISTORIES
1000
900
800
cc
Ul
a.
ui
700
600
SOO
U * UPPER ZONE OF COAL BED
M - MIDDLE ZONE
L - LOWER ZONE
400
•ir
90 120
tfminutcsl
150
180
210
240
Figure 10. Early gasification tests.
-------
Some extensions of the research discussed
which seem potentially valuable:
1. Simplified experimental reactions to
provide better correlation with
theoretical analyses, e.g., reaction of
thin coal wafers to provide a one-
dimensional approximation and the
observation of the action of very small
coal samples in conjunction with ther-
mogravimetric analysis tied to con-
tinuous mass spectromery.
2. Investigation of byproduct or contami-
nant production following the incinera-
tion of gasifier tars and chars.
3. Continuous coal feed to the reactor to
evaluate discrepancies produced by
this method with the results obtained
during batch operations.
4. Determination of the effects of fluidiza-
tion and entrainment on the production
of toxic or other trace constitutents
presenting health hazards.
5. Comparison of contaminants analyzed
for and samples taken from different
regions of the coal conversion reactor.
It is hoped that the present and future
research plans described will begin to produce
some profitable scientific results in the upcom-
ing year and be made available to those in-
terested in coal conversion. It is also hoped that
these results will alleviate concern over en-
vironmental problems associated with coal
utilization.
REFERENCES
1. J. G. Cleland, and G. L. Kingsbury,
Multimedia Environmental Goals for En-
vironmental Assessment, Research
Triangle Institute. Draft of Environmental
Protection Agency, January 1977.
2. Settlement Agreement and the U.S.
District Court for the Disrict of Columbia,
Civil Actions No's. 2153-73, 75-0172,
75-1698, 75-1267. Defendents En-
vironmental Protection Agency, plaintifs
Natural Resources Defense Council, Inc.
Environmental Defense Fund, Inc.
Businessmen for the Public Interest, Inc.
National Audubon, Inc.; Citizens f - Bet-
ter Environment. Agreement e .ecut, I on
June 7, 1 976.
3. J. G. Cleland, "Environmental Assess-
ment and Regulation for Coal Conver-
sion," Presented at the Third Annual Con-
ference on Coal Utilization, University of
Pittsburgh, 1977.
4. U.S. Department of Labor. Occupational
Safety and Health Standards. Toxic and
Hazardous Substances. Title 29, Cod" of
Federal Regulations, Part 1 910.1000. Air
Contaminants. May 1975.
5. A. L. Yergey, et al., GasificaCon of Fossil
Fuels Under Oxidative, Reductive, and
Pyrolytic Conditions. Prepared I / Scien-
tific Research Instruments for the En-
vironmental Protection Agercy, PB
228-668, EPC-650/2-73-r 42.
December 1973.
6. D. V. Nakles, et al., "Influence of L:yn-
thane Gasifier Conditions on Eff jent and
Product Gas Production," U.S. ERDA
Technical Information Center. )ecer iber
1975.
7. C. G. vonFredersdorff, and M. A. F"iott,
"Coal Gasification," in Chemistry o> Coal
Utilization, Supplementary Volume, . . H.
Lowry, ed., Chapter 20, 1963.
8. S. J. Stinnett, D. P. Harrison, and R. W.
Pike, "Fuel Gasification, Prediction of
Sulfur Species Distribution by Free Energy
Mineralization," Env. Sci. Technol. 8,
441, 1974.
9. J. Fischer, R. Lo, S. Nandi, J. Young, and
A. Jonke, ANL-75-77, 1975.
10. D. B. Anthony, and J. B. Howard, "Coal
Devolatilization and Hydrogasification,"
A.I.C.h.E.J. 22, 625, 1976.
11. R. L. Zahradnik, and R. A. Glenn, Fuel 50
77, 1971.
12. C. Y. Wen, "Optimization of Coal
Gasification Processes," EPA Report PB
235-783/95T, April 1972.
241
-------
GASIFICATION PROCESS/
ENVIRONMENTAL
CHARACTERIZATION
FROM PILOT PLANT DATA
by
David V. Nakles
Research Associate, Chemical Engineering
Carnegie-Mellon University
Michael J. Massey
\ssiotant Professor, Chemical Engineering/
Engineering & Public Policy
Carnegie-Mellon University
INTRODUCTION
low and for the foreseeable future, pilot
plant-scale effluent characterization data
necessarily must serve as the only resource for
ivironmental assessment in high Btu coal
gasification processing. However, meaningful
collection and interpretation of such data are
complicated, since little if any effluent treat-
ment is usually performed and large sections of
these plants are typically nonscalable. In the
absence of a data base and any established
regulatory guidelines or standards, specifica-
tion of an appropriate set of effluent
characterization parameters is also com'
plicated. The challenge in coal gasification en-
vironmental assessment is therefore two-fold:
1. to identify the set of effluent monitor-
ing parameters, sampling/preserva-
tion/analytical procedures, and control
characteristics appropriate to a com-
prehensive environmental characteriza-
tion; and
2. to develop an effluent characterization
strategy (both predictive and ex-
perimental) which properly addresses
both the vagaries of measurements
from small-scale plant operations and
the sharp contrasts in effluent
characteristics from process to pro-
cess.
ERDA has assembled a combination of en-
vironmental contractors (see Figure 1) and a
coordination contractor (Carnegie-Mellon
University) to address these issues in an en-
vironmental assessment of its high BTU coal
gasification pilot plant program. Details re-
garding the structure and operation of the pro-
gram have been published elsewhere.11'21 In the
present paper, program methodology is
discussed, available field data are presented,
and preliminary trends in the effluent data base
are explored in relation to evolving evidence of
the fundamental relationship between process
variables and effluent production.
BASIC STRUCTURE OF PROGRAM
ENVIRONMENTAL ASSESSMENT PLANS
In the absence of any reference data base,
assessment plans at each pilot plant are being
formulated in two stages. Initially preliminary
test plans have been developed to address
basic issues of prioritization in stream and ef-
fluent parameter selection, alternative sampl-
ing methodologies, and validation of sample
preservation and analysis techniques. Ex-
ploratory effluent characterization efforts have
also been undertaken to identify significant ef-
fluent characteristics for later more com- -
prehensive, quantitative investigations.
Background analysis and preliminary test plans
have been completed and documented for two
pilot plants, Hygas and C02-Acceptor;12-31
similar efforts are now in progress at the other
participating plants.
Stream Sampling and Effluent
Parameter Selections
Stream Sampling Selection
Plant streams are selected for sampling for
one of three purposes (in decreasing order of
importance): (1) to provide a baseline
characterization of pilot plant effluent produc-
tion scalable to larger plant sizes; (2) to provide
material balances for specific effluent consti-
tuents; and (3) to determine pilot plant-specific
environmental impacts. The critical issue of
stream scalability is discussed below. First
priority constituents for material balancing in-
clude sulfur, nitrogen, and trace metals. Stream
characterization for pilot plant environmental
impacts is receiving only minor attention in the
program.
Pilot-scale versions of a process rarely reflect
either the structural or the operational practices
242
-------
ERDA FOSSIL ENERGY HIGH BTU COAL GASIFICATION
PROGRAM
HYGAS
*
IGT
XX
IGT
C02 ACCEPTOR
x xx
ICONOCOIRADIAN
CO
BIGAS
PHILLIPS
xx
PEC
SYNTHANE
*l
l
Jxx
PERC
SLAGGER
X
GFERC
xx
GFERC
PROGRAM ANALYSIS-, COORDINATION
CARNEGIE-MELLON UNIVERSITY
x- Process Developer
•xx Environmental Contractor
Figure 1. Structure of ERDA Pilot Plant effluent characterization program.
-------
TABLE 1
SUMMARY OF MAJOR ENVIRONMENTALLY SCALABLE AND NONSCALABLE SECTIONS
OF PARTICIPATING HIGH BTU COAL GASIFICATION PILOT PLANTS
Scalable Plant Sections
Nonscalable Plant Sections
BI-GAS PILOT PLANT
Coal preparation
Coal slurry dryer
Raw product gas (prior to quenching)
Gasifier ash
High pressure gas washer
Water gas shift reactor
Selexol purification system
C02-ACCEPTOR PILOT PLANT
Raw product gas (prior to quenching)
Regenerator offgas (prior to quenching)
Product gas quench system
GRAND FORKS PILOT PLANT
• Raw product gas (prior to quenching)
• Product gas quench system (with certain
modifications)
Coal pretreater (tar, oil, wastewater,
offgas streams)
Raw product gas (prior to quenching)
Product gas quench system
Gasifier ash
HYGAS PILOT PLANT
Atmospheric vent washer
Wastewater handling and disposal system
Regenerator offgas quench system
Regenerator offgas SC^-scrubber system
Coal preparation
Coal venturi scrubber system
Regenerator ash
Wastewater handling and disposal system
Product gas purification system
Wastewater handling and disposal system
Oil stripper
Product gas purification system
Coal preparation
Wastewater handling and disposal system
Coal venturi scrubber system
244
-------
of subsequent commercial, versions. In the
specific case of existing coal gasification pilot
plants, few if any plant effluent-bearing
streams are processed as they would be in a
larger commercial plant. As a result, conven-
tional environmental sampling at the outfalls
(air, water, land) of gasification pilot plants
does not yield meaningful information. Instead,
process stream sampling must be concentrated
at points where effluent stream characteriza-
tions are scalable. Note that results of such
sampling reflect process effluent production
not emission levels, since sampling is under-
taken upstream of any effluent treatment.
As shown in Table 1 the locations of scalable
effluent streams vary widely among the four
participating pilot plants in the environmental
assessment program. With the exception of the
Bi-Gas plant, coal preparation areas yield
essentially no scalable effluent streams; virtual-
ly none of the plants have scalable wastewater
handling and disposal systems; only the Bi-Gas
plant operates a scalable product gas purifica-
tion system; and only the Hygas plant operates
a scalable coal pretreatment system. As a
result, first priority scalable sampling efforts
are concentrated on streams immediately link-
ed to the primary gasification step, viz., raw
product gases, gasifier quench condensates,
and gasifier ash. Beyond these points, sampling
efforts are tailored to the special scalable
features of a given plant, e.g.,
• Coal pretreatment effluent data are be-
ing generated at the Hygas plant.
• Product gas purification performance
data will be generated at the Bi-Gas
plant.
• Coal slurry dryer performance data will
be generated at the Bi-Gas plant.
Effluent Parameter Selection
Procedures for the identification, grouping,
and ranking of effluent parameter priorities
have been published elsewhere;12'41 a summary
of current priorities is provided here in Table 2.
Essentially all of the parameters listed in Table
2 either have or will be surveyed during the
course of initial plant screening efforts. The
subset of parameters found to be significant in
this screening will be retained in subsequent
more comprehensive sampling and analysis ef-
forts.
TABLE 2
SUMMARY OF FIRST PRIORITY EFFLUENT
PARAMETERS IN THE EROA ENVIRONMENTAL
ASSESSMENT PROGRAM
Wastewater Effluent Parameters <2-4>
• pH
• TSS
• BODS
• COD
Phenols
TOC
Grease and Oil
f
S"
• CN'
• NH3-
• N05-
• POl
N
N
Trace Wastevwter Effluent Parameters'2'41
Al
As
Cd
Cr
Cu
Fe
Hg
Mn
• Ni
• Pb
• Sn
• Zn
Gaseous Effluent Parameters
(2.5)
• Sulfur Species: S02, S03, COS, CS2, H2S
• Other Acid Gases: NOX, HC1, HCN, HF
• Other Inorganic Constituents: NH3
• Other Organic Constituents: nonmethane HC's,
6, C4H10,
Stream Sampling Strategy
Major types of stream sampling method-
ologies include grab, composite, and con-
tinuous sampling. Typically one or more of
these methods are combined to yield a working
sampling strategy. Selection of the appropriate
sampling strategy requires some knowledge of
the nature of systematic and random variations
in stream composition as well as an under-
standing of the use to which sample data will
be put. For purposes of screening characteriza-
tion, although a stream may be highly variable
in composition, the large coefficient of varia-
tion of a grab sample may be adequate, and
would certainly be the lowest cost sampling
strategy. By contrast, sampling for material
balance purposes may require a particular com-
bination of grab and composite sampling
strategy which yields a relatively lower coeffi-
cient of variation.
245
-------
Use of Time Series Samp/ing
The systematic variability of an effluent
stream composition with time can be determin-
ed by time series study of the behavior of
selected effluent parameters. As illustrated in
Figure 2 for three Hygas wastewater streams,
the nature and the degree of variability differs
significantly from stream to stream. Much of
this variability (or in certain cases, the lack of it)
can often be explained in terms of factors
unrelated to actual effluent production. For ex-
ample, operating practice accounts for a signifi-
cant fraction of the variability in Hygas
pretreater condensate composition.161 Ap-
propriate normalization of the data can often
filter out some of this variability. A certain frac-
tion of stream variability may represent actual
changes in effluent production, which in turn
are related to basic changes in process
operating conditions.
Naturally, a sampling methodology designed
to identify process variable/effluent production
relationships would differ from that designed
for simple screening characterization.
However, given adequate time series data,
statistical procedures available and described
elsewhere17-81 are adequate in either case for the
selection of an appropriate combination of grab
and composite sampling.
Specialized Samp/ing Requirements
Note that a low measured effluent stream
coefficient of variation does not necessarily im-
ply stable effluent production. For example, the
large inventory (-2,000 gallons) of recir-
culating quench water at Hygas and its
dampening effect are responsible for the low
observed variability of Hygas quench conden-
sate. Determination and correlation of the ac-
tual variability of effluent production with time
requires the sampling of raw product gases
prior to quenching. C-MU has developed and
described elsewhere121 an apparatus for the
sampling of such raw product gases.
Preliminary shakedown tests were recently
completed successfully. Exploratory time
series sampling is scheduled to begin in Oc-
tober.
Validation of Sample Preservation
and Analysis Procedures
Preliminary C-MU/IGT experimentation with
Hygas wastewaters at the outset of the en-
vironmental assessment program pointed to
the importance of prompt sample preservation
and indicated potential problems with several
traditionally recommended procedures for the
preservation and analysis of coal and oil pro-
cessing wastewaters.191 Subsequent investiga-
tions by C-MU/Radian and C-MU/GFERC with
C02-Acceptor and Grand Forks condensates,
respectively, revealed additional evidence of
analytical problems.12' In particular, major
analytical interferences of oils in the determina-
tion of thiocyanate were observed (Table 3) as
well as the simultaneous degradation of
cyanide and production of thiocyanate with
time in unpreserved samples of gasifier quench
condensate (Figure 3). Consequently, an ongo-
TABLE3
CMS' OIL INTERFERENCE12'
Procedure
Millipore
Filtration Only
No. of Tests
3
3
CNS" Spike,
mg/1
0
50
Measured CNS"
Mean
96.4
151.8
Level, mg/1
Std. Dev.
1.6
2.1
Millipore 3
Filtration and Hexane Extraction 3
0
50
32.3
94.1
5.4
13.8
246
-------
PRETREATER QUENCH CONDENSATE
RUN 60
( Illinois No. 6 Cool)
2000
1000F
Coeff. of var. » 0.307
o TOC
o Ammonia
8000
PRODUCT QUENCH CONDENSATE
RUN 57
(Montana Sub-Bituminous Coal)
I
Coeff. of var. = 0.091
OIL STRIPPER BOTTOMS
RUN 58
o TOC (Montana Sub-Bituminous Coal)
o Ammonia
Coeff. of var. - 0.630
O
a.
0 3000
2000
1000
0*2 ~4 ~6 ~8 "ib 12 14 16 18 20 22 24 26 28 30 32 34
ELAPSED TIME. Hours
Figure 2. Time-series analysis: total organic carbon and ammonia contents of three major
wastewater streams produced in the Hygas Pilot Plant.
Cotff. of var. « 0.741
247
-------
o>
•*
Z
Q
^
h-
iij
o
O
o
Preserved
A AUnpreserved
-20
o>
15
10
u
o
o
i
o
4
Time Span For
Preservation
Unpreserved
10 20 30 40 50 60
TIME FROM SAMPLING, Hours
70 80
Figure 3. Time stability of cyanide and thiocyanate in preserved and unpreserved samples
of gasifier quenchwater: Co2-acceptor run 42.
248
-------
ing effort of the program involves the investiga-
tion of the preservation techniques and
analytical methods for the major liquid effluent
parameters in coal gasification wastewaters. A
set of recommended procedures for preserva-
tion and analysis has evolved from these initial
investigations and is published elsewhere.1101
Research is also continuing on the complex
relationships between cyanide and thiocyanate
in these waters. Reaction mechanisms and
kinetics for the conversion of cyanide to thio-
cyanate have been explored and the active
sulfur species involved in the conversion has
been investigated in both synthetic and actual
gasification wastewaters. The results of these
studies will be presented in the near future.1111
SUMMARY OF AVAILABLE PROGRAM DATA
The major emphasis of the first year of the
environmental assessment program has been
on the characterization of the liquid effluents
from the pilot plants. As noted, substantial
work has been completed at the Hygas and
C02-Acceptor pilot plants while initial efforts
have just begun on the Bi-Gas, Synthane, and
slagging fixed bed processes.
Characterization of Liquid
Effluent Production
The initial characterization of the pilot plant
liquid effluents, consistent with the overall pro-
gram methodology, focused on those effluent
streams which:
1. represent the bulk, by mass, of the
total plant effluent production, and
2. have a direct and measureable linkage
to the major process variables.
The liquid effluent streams in gasification
which satisfy these criterion are the quench
condensates of the gasification and/or pretreat-
ment process steps. However, each pilot plant
possesses liquid effluent flow patterns unique
to its design and the determination of the total
pilot plant effluent production may also involve
other streams. The liquid flow patterns for the
C02-Acceptor and Hygas pilot plants are
shown in Figures 4 and 5, respectively, as are
the major effluent streams which were sampled
to yield the total liquid effluent production.
The total plant effluent production of these
pilot plants for 10 major parameters (tars, oils,
TSS, TOC, COD, Phenol, CIST, CNS-, NH3,
and S=), normalized per pound of moisture and
ash-free feed coal, is presented in Table 4. Also
shown in Table 4 are the available normalized
effluent production rates for the Lurgi-
Westfield semi-plant and slagging fixed bed
gasifier in Grand Forks. These normalized data
are very amenable to analysis for the initial
review of the effluent potential of the proc-
esses and the comparison and evaluation of
these potentials among the existing plants.
Similarities and Differences in
Pilot Plant Liquid Effluent Production Data
A cursory review of Table 4 reveals signifi-
cant similarities and differences in the produc-
tion of both organic and inorganic liquid ef-
fluents in the various pilot plants. For example,
both the Lurgi and the slagging fixed bed plants
exhibit quite similar tar production, - 60 to 80
Ibs/ton coal, MAF; the Hygas and Lurgi proc-
esses produce similar quantities of phenol,
-11-12 Ib/ton coal, MAF; the cyanide and
sulfide production data for the Lurgi and C02-
Acceptor plants are quite comparable, ranging
from -0.01 to 0.05 and 0.2 to 0.4 Ib/ton
coal, MAF respectively; and ammonia produc-
tion is very similar for all the processes at - 1 5
Ib/ton coal, MAF.
However, at the same time, there are also
dramatic differences in the liquid effluent pro-
duction data. In particular, tar, oil, and phenol
production range from negligible to 80, 60, and
-15 Ib/ton coal, MAF, respectively. Also,
significant variations in cyanide, thiocyanate,
and sulfide production are evident in Table 4,
ranging from negligible to 0.04, 0.12 to 5.6,
and 0.2 to 7.4 Ibs/ton coal, MAF, respectively.
This large degree of variability is not surpris-
ing given the stage of development of the liquid
effluent data base. Differences in coal feed
type, sampling methodology, and sample
preservation and analysis can possibly explain
some of the variation, e.g., cyanide/thio-
cyanate interaction. However, some of the
dramatic differences demonstrated by the
hydrocarbon constituents, viz., tar, oil, and
phenol, could not be accounted for in this man-
249
-------
Vant/Mathanaiion
to
s
•H.O
-25 flpm
Staam/Racycla
Gas
Procaas Watar Holding Pond
Figure 4. Liquid effluent flow patterns of the CO2-acceptor coal gasification pilot plant.
-------
to
(71
Water Wash
Slowdown
To Wa«l*wat«r Tr«atm«nl
__*. Vent/
NUthanatloi
*. To
Cond«n««
Figure 5. Liquid effluent flow patterns of the Hygas coal gasification pilot plant.
-------
TABLE 4
SUMMARY OF NORMALIZED LIQUID EFFLUENT PRODUCTION FROM OPERATING COAL GASIFICATION PILOT
PLANTS
froc«..v
Co.1 T»p» lle.^ t«r»
Clmharold Ufnltc 3» fell.
•etl.
0.45 + 0.25 2.9 t °-" 0.05 1 O.QZ 0.028 + .005 O.U + 0.1* 21+15
0.39 + 0.21
Utnlt«(c) 37
*•.»>
Illlnol* Me. 6W)
55
*6
5*
5»
to
- 4.7 :_ 2.0
fO
W
N)
, .
Illinois Bo. 6
61+3
M + 1*
78 + 39
*0+ 5
10+4
1* * 5
nttibarfh Po. 8
02+4 18 + 1*
56 + 15 I*.*+ 3.0 0.01 + 0.001 0.12 + 0.1*
52+2 I2.C + 1.6 0.0* + O.OJ 0.31 + 0.08
44+3 12.4+0.1 0.02+0.01 0.35 + 0.0*
29+1 7.9 + 0.9 0.02 + 0.02 0.54 +O.U
11.9 + 6.7 0.4 i 0.2
16.8 + 1.8 0.3 < 0.1
16.6 + 4.2 0.4 + 0.2
13.4+ 0.7 0.2+0.1
Sl«MiB« Find M
». D.
•. D.
74+1
M + 7
15.4 + «.*
1.4 + 1.9
7.5 + 0.2 5.t + 0.2
«.<+. O.t
(•) The Bl-Ctt ad Syntlum pilot
tibl*. Bmtiir, « Jul ml i»l
:!,,
U. 13.
i ftlot
to tUs
-------
ner. Such differences can only be explained by
the inherent processing differences exemplified
by each of the processes. The correlation of
these process differences with the subsequent
differences in effluent production is a com-
plicated task. For example, why does the C02-
Acceptor process simultaneously produce
negligible quantities of tar, oil,2 and phenol
while the Hygas process, which also produces
insignificant amounts of tar, yields significant
amounts of oil and phenol? Or, why does the
Lurgi process produce quantities of oil and
phenol comparable to the Hygas process, yet
produce much more tar? Understanding such
phenomena requires the identification of the
major gasification process variables which in-
fluence effluent production and subsequently,
the specific relationships between these proc-
ess variables and effluent production
characteristics.
DEVELOPMENT OF PROCESS
VARIABLE/EFFLUENT PRODUCTION
RELATIONSHIPS FOR THE INTERPRETATION
OF PROGRAM DATA
A combination of bench-scale, PDU-scale,
and pilot scale experimental studies have been
initiated to define the relationships between the
process variables and liquid effluent production
as an aid in interpreting the pilot plant effluent
data bases.
Structure of Process Variable/Effluent
Production Studies
Research initiated jointly by C-MU and the
Pittsburgh Research Energy Center (PERC) in
1974 provides the framework for the com-
prehensive studies of the relationships be-
tween process variables and liquid effluent pro-
duction.
Identification of Critical
Process Variables
During a sequence of 19 controlled ex-
periments on the Synthane pilot development
unit, seven effluent production parameters
(tar/oil, phenols, COD, TOC, TIC, CN~, and
CNS~) were monitored both as a function of
time and as a function of changing coal injec-
tion geometry (free fall, shallow, and deep bed-
injection).112'131 The typical response of the
hydrocarbon effluents or indicators (tar/oil,
phenols, TOC, COD) to the changes in feed
geometry are demonstrated by the phenol pro-
duction data shown in Figure 6. Note the
dramatic reduction of phenol production as the
coal was injected deeper into the fluidized bed.
At the same time, significant changes in critical
process variables also occurred as the point of
fresh coal injection was altered from free fall to
shallow and deep bed-injection:
1. Product gas residence time: Volatile
materials evolved from the coal during
its initial heatup were now forced to
pass through the hotter, fluidized bed
portion of the gasifier thereby increas-
ing their residence time at conditions
more conducive to attaining chemical
equilibrium.
2. Gas-solid mixing: Coal injection now
occurred in a region of intimate gas-
solid contacting encouraging reaction
of the volatilized species both with
hydrogen and the highly reactive,
potentially catalytic, char surfaces.
3. Mean reaction temperature: Longer
residence times in the fluidized bed por-
tion of the gasifier effectively increased
the mean reaction temperature of the
devolatilized coal species, and
4. Coal heat-up rate: Coal injection into
the hotter fluidized bed effectively in-
creased the heatup rate of the coal par-
ticles to their final temperature.
Table. 5 summarizes the major impacts of
changes in process variables on liquid effluent
production demonstrated in that study. Ex-
amination of this table reveals that the largest
percentage reduction in gasifier tar production,
viz., 86 percent, resulted from the shift from
free fall to shallow bed-injections of lignite. Ac-
companying this shift were major changes in
coal heat-up rate, gas-solid mixing, and product
gas residence time. However, increasing the
depth of injection of lignite from 1 -112 to 4-112
feet in the fluidized bed portion of the gasifier
(deep bed-injections) and hence increasing the
product gas residence time even more, resulted
in an additional reduction of only 38 percent.
253
-------
Coal Feed
M
2
Carbonization
Zone
6 ft. High,
10" I.D.
Fluidized Bed
6 ft. High
Steam/Oxygen
i~700°C
"Raw Product Gas
Free Fall Coal Injection
'~5 ft. Above Fluidized Bed
" O.D. Dip Tube
900°C Deep Bed-Injection
20
15
10
5
o
E
1
o
c
o
.a 15
Shallow Bed-Injecton
- 1 j f t. Below the Surface of 2 1 °
the Fluidized Bed
o
o
o
or
a.
§20
ui
a! 15
\ /
~4-|- ft. Below the Surface of
the Fluidized Bed
10
5
1
Tchar 0
Figure 6. Influence of coal feed injection geometry on effluent production in the synthane pilot development unit.
2345
TIME, Hours
-------
TABLE 5
RELATIVE IMPACTS OF CHANGES IN MAJOR PROCESS VARIABLES
ON SYNTHANE GASIFIER EFFLUENT PRODUCTION
Process Variables
Decrease in Effluent Production
Nature of Increase
Tar/Oil
TOC
Phenol
COD
(a)
Reaction Temperature
Coal Heat up Rate
Residence Time* '
Gas/Solid Contacting
Reaction Temperature'3'
Coal Heatup Rate
Residence Time"1'
Gas/Solid Contacting
SHALLOW VS FREE FALL-INJECTION
Major
Major
Moderate
Major
86%
78%
71%
85%
DEEP VS SHALLOW BED-INJECTION
Minor
Negligible
Major
Negligible
38%
44%
Notes:
(a) Mean reaction temperatures varied from 828° C (free fall) to 789° C (shallow bed) to 773° C (deep bed).
(b) Effective product gas residence time varied from zero (free fall) to 2.8 (shallow bed) to 6.6 seconds (deep bed).
Similar trends in chemical oxygen demand
(COD) and total organic carbon (TOC) of
aqueous effluents are apparent; COD's are
reduced by 85 and 69 percent, TOC's by 78
and 44 percent, respectively. Interestingly, the
above pattern does not hold for phenol produc-
tion. Shifting from free fall to shallow bed-
injections of lignite results in a 70 percent
reduction in phenol production; however, in-
creasing the product gas residence time by
shifting from shallow to deep bed-injections of
lignite results in a further reduction of 86 per-
cent! Such evidence strongly suggests that dif-
ferent mechanisms may be responsible for
observed reductions in various steady state ef-
fluent production rates with changes in fresh
coal injection geometry.
Potential Mechanisms Governing
Hydrocarbon Production
On the basis of the Synthane PDU test
results, the following tenative mechanisms are
proposed as major determinants in gasifier
hydrocarbon formation and decomposition:
1. Phenols are inherently formed during
the initial stages of coal heating and
devolatilization, after which they are
subject to decomposition by thermal
cracking.
2. By contrast, tar/oil formation is strong-
ly influenced by conditions and interac-
tions during initial coal heat-up and
devolatilization, e.g., gas-solid mixing,
coal heat-up rate and hydrogen partial
pressure. Formed material is then sub-
ject to decomposition by thermal crack-
ing.
The first mechanism suggests that the deter-
mining factors in phenol production are reactor
temperature and product gas residence time.
The second mechanism suggests that net
tar/oil production rates are the result of two
contrasting process variable interactions: the
first governs the extent of tar/oil formation and
depends upon such variables as gas-solid con-
tacting, hydrogen partial pressure, and coal
heat-up rate; the second governs tar/oil decom-
position and depends upon reactor temperature
and product gas residence time.
255
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Investigation of Hydrocarbon
Formation/Decomposition Mechanisms:
Experimenal Strategy
There are advantages and disadvantages to
the study of the process variable/effluent pro-
duction relationships at any single experimental
scale. However, a judicious distribution of ex-
periments across a range of scales affords an
opportunity for maximum utilization of the ad-
vantages of each scale. Accordingly, as shown
in Figure 7, a mixture of bench-scale, PDU-
scale, and pilot scale experiments were design-
ed to screen the major mechanisms influencing
the formation/decomposition of hydrocarbons
in coal gasification. In particular, information
was sought to determine:
1. The susceptability of phenol to decom-
position under gasification conditions,
and
2. The relative impacts of formation
phenomenon and thermal decomposi-
tion on the existence of tar/oils.
Studies of Phenol Formation-
Decomposition
The postulated mechanism of intrinsic
phenol production with subsequent decom-
position by thermal cracking was examined on
both the bench-scale and pilot plant scale.
1. Bench Scale Phenol Studies
The effect of reactor temperature and prod-
uct gas residence time on the decomposition of
phenolic compounds is amenable to examina-
tion using bench-scale apparatus operated
under simulated gasifier conditions. C-MU and
PERC recently completed initial experiments of
this type on a model compound, phenol, and
verified a thermal decomposition mech-
anism."91
The bench-scale experiments were con-
ducted at atmospheric pressure in a
homogeneous gas phase reactor (Figure 8) in
which the reaction gas temperature, residence
time, and composition were varied and the rate
of phenol decomposition and the nature of the
decomposition products were monitored. The
range of conditions covered in these ex-
periments included:
• Nominal reactor temperatures from
300 to 975° C, with primary emphasis
on the range from 750 to 950° C,
• Nominal reaction gas residence times
from 2 to 4 seconds, and
• Nominal hydrogen partial pressures of
0.0, 0.2, and 0.5 atmospheres, water
partial pressure of approximately 0.5
atmospheres.
In addition to the homogeneous tests, two
heterogeneous tests were also completed us-
ing gasifier char from the previous Synthane
PDU tests. From this mixture of homogeneous
and heterogeneous tests it was demonstrated
that:
1. Phenol decomposition proceeds rapidly
(2 to 4 seconds) by thermal cracking,
at rates which are independent of reac-
tion gas composition, particularly
hydrogen partial pressure (Figure 9),
2. Phenol decomposition product distribu-
tion is a strong function of system
hydrogen partial pressure, tar produc-
tion increasing with decreasing partial
pressure, and
3. The presence of solid surfaces reduces
by at least 200° C (975 to 775° C)
the reaction gas temperature required
to accomplish rapid and essentially
complete phenol decomposition (see
Figure 9).
Future experiments are in progress to explore
the decomposition kinetics of other prominant
phenolic compounds (e.g., cresols) found in
gasifier quench condensates. Additional at-
mospheric and possibly higher pressure ex-
periments under heterogeneous reaction condi-
tions will also be conducted.
2. Pilot Plant Phenol Studies
Very small amounts of phenol are produced
in the C02-Acceptor process (Table 4). If
phenol behaves as postulated, increasing
phenol levels would be expected as process
gas is sampled closer and closer to the coal in-
jection point at the base of the gasifier. C-MU
designed a sample probe to complete this ex-
periment and it has been described in a
previous document.1141 Preliminary sampling
results have identified the presence of phenols
at the point of coal injection in the C02-
256
-------
Formation Followed by
Ml Decomposition
le
Pilot Plant
M
SI
Formation/Decomposition
of Hydrocarbons
Paring Coal Gasification
Inhibited Formation
During Devolatilization
Phenol Decomposition
at
Gaaification Conditions
Phenol susceptible to theraal de-
composition in homogeneoua gas phase
at 700 to 900°C and 2-4 seconds
residence time
991 Decomposition observed at 970°C
residence time of 2 to 4 seconds
ition of _
• Char catalyses dec
phenol: 99Z decomposition at 750"C
and a residence time of 2 to 4 seconds
Sampling
Acceptor Gasifier
Pilot Plant
PDU-Scale
Segregation of Besidence
Time/Devolatilization
Conditions on Hydrocarbon
Production
Preliminary results indicate the
presence of phenol and other organics
at the point of coal feed injection;
hovever, quantitative analysis not
yet available
• Heavy hydrocarbons (80% boil over
400°C) are very sensitive to gas/
solid mixing and temperature at the
point of devolatilization: 95%
reduction by increasing both para-
meters on IDU gasifier
• Oil (boiling point 100-400°C) and
phenol not influenced by gas-solid
contacting and temperature at point
of devolatilization
Figure 7. Preliminary screening of major mechanisms influencing the formation/decomposition of
hydrocarbons in coal gasification.
-------
Slide-wire
thermocouple
Thermocouple
Reoctor
Reactor ends
Reactor outlet
TC) To furnace zone
JC) Temperature
Controllers
Furnace zone
heating elements
urnace
Phenolic steam
inlet
Reoctant gas inlet
Figure 8. Thermal decomposition reactor and furnace configuration
for phenol decomposition studies.
258
-------
NJ
CJ1
co
Q>
O
0>
O.
g»
5
O
o
a.
o
o
UJ
o
-o- 2 second residence time
3.5
in the presence of char
-- Extrapolated
I , I
^ 40 -
20 ~
0
600
700 800 900
AVERAGE REACTOR TEMPERATURE,°C
1000
Figure 9. Measured phenol decomposition as a function of average reactor temperature for 2, 3, and 4 second
nominal residence times.
-------
Acceptor gasifier; however, further results are
required before an extensive quantitative
analysis can be done.
Studies of Tar/Oil Formation-
Decomposition
It is believed that both formation and decom-
position phenomena play an integral part in dic-
tating the production of hydrocarbons produc-
ed during the thermal processing of coal.
Bench-scale equipment are not adequate for
the segregation of these formation/decomposi-
tion interactions since (1) the multicomponent
nature of the tars and oils make it difficult to
simulate these compounds for bench-scale
decomposition studies and (2) studies based on
simulated materials preclude the effects of
process variables on the formation of tar/oils
during devolatilization. Larger scale systems,
operating on fresh coal and capable of examin-
ing both the effects of devolatilization condi-
tions and thermal decomposition on tar yields,
are required. This led to the initiation of two ex-
perimental programs - one on the Synthane
PDU and the other on the CO-Acceptor pilot
plant gasifier - to segregate the relative impacts
of tar/oil formation and thermal decomposition
on the existence of tar/oils under gasification
conditions.
/. PDU-Scale Tar/Oil Studies
The use of a PDU-scale equipment train for
the examination of process variable effects on
tar/oil production and composition has some
obvious advantages and disadvantages. While
it provides a scale sufficient to preserve
material balance capabilities and flexibility
regarding changes of process conditions, it is
very difficult to totally decouple individual
process variables effects. However the pur-
pose of the study was not to specifically isolate
the effects of individual process variables; but
rather, to dissociate the impact of tar/oil forma-
tion phenomenon and tar/oil decomposition on
the existence of tar/oils. While the result of
such a study may not yield quantitative
mechanisms to explain the observed
phenomenon, it should provide semi-
quantitative empirical relationships which are
quite amenable to scale-up and extrapolation.
The isolation of the decomposition and for-
mation phenomenon in the Synthane PDU was
accomplished by injecting the feed coal of the
Synthane PDU gasifier directly onto the top of
the fluidized bed (Figure 10). This provided
devolatilization conditions similar to the
shallow and deep bed-injection trials of the
previous studies, e.g., gas-solid contacting,
final reaction temperature, and coal heat-up
rate, and at the same time essentially
eliminated the residence time of the devolatiliz-
ed species in the hot, fluidized bed.
Preliminary effluent production rates for
these PDU trials have been summarized in a
previous document1201 and are shown in Table 6
for tars (80 percent with boiling point
>400° C), oils (boiling point between 100
and 400° C) and phenols:
Trial
Description
Free Fall-
Injection
Top Bed-
Injection
Mean
Hydrocarbon Production
PertMffSirt" (Ibs/ton Coal, MAP)
(Micron)
50
50
Tan
13±4
<6)<«>
0.6±0.3
(3)
Oils
48±10
(2)
49138
(6)
Phenols
8±2
(6)
9+6
(8)
lumber of Observation!
These data are significant since they suggest
that the tar reductions observed during the
previous shallow and deep bed-injection trials
were largely a result of the enhanced gas-solid
contacting and temperature at the point of coal
devolatilization. This statement results from
the fact that a 95 percent reduction in heavy
tar was accomplished with negligible product
gas residence time in the fluidized bed (top bed-
injection trials provide effectively no residence
time for the product gas in the hot fluidized
bed).
The mechanisms responsible for the tar
reduction during coal devolatilization are not
discernable from the PDU trials. However,
enhanced gas-solid contacting and temperature
during devolatilization have the potential to in-
fluence the secondary reactions of the
devolatilized species. In particular, tar produc-
tion could be reduced by (1) enhancing the
reaction of the devolatilized species with
260
-------
Cool feed
Corbonization zone
-6ft high,IO inches i.d.
Fluidized bed
~6ft high,4 inches i.d.
Chor
removol system
Product gas and
condensible effluent
K Free fall coal injection
I >— point ~5ft above the
fluidized bed
3/4"O.D. dip tube
~ 700 °C
top bed-injection
~900°C
•*— Steam /oxygen
Chor
Figure 10. Synthane PDU gasifier: top bed-injection of feed coal.
261
-------
TABLE 6
PROCESS VARIABLE AND EFFLUENT PRODUCTION PATTERNS
FOR SELECTED COAL GASIFICATION PROCESSES
Process Variable
Process
Lurgi-Westfield
Hygas
COo-Acceptor
Gas-Solid Contacting
During Devolatilization
Minimal
Extensive
Extensive
Residence Time at
Temperature
Minimal
Minimal
Extensive
Analogous Synthane PDU
Coal Feed Geometry
Free Fall-Injection
Top Bed-Injection
Deep Bed-Injection
Effluent
Production
Tars
High
Negl.
Negl.
Oils
High
High
Negl.
Phenol
High
High
Negl.
hydrogen, thereby reducing repolymerization,
or (2) providing additional surface area of the
potentially catalytic char solids which may
serve as sites for tar deposition/decomposition.
Enhancing the stabilization of the devolatilized
species by reaction with hydrogen would be ex-
pected to increase the quantity of lighter oils
produced. Examination of the oil production
reveals no such change (48±10 versus
49 ± 38 for the 50 micron free fall and top bed-
injection trials, respectively). Hence, deposition
and/or decomposition of the tar species on the
char surfaces may be the dominate mechanism
of tar reduction. However, there is no data to
verify or refute this hypothesis. Regardless of
the mechanism, an empirical relationship has
been identified between heavy tar production
and gas-solid contacting during coal
devolatilization at gasification temperatures
(700° C). Thermal cracking or decomposition
beyond this initial devolatilization point appears
to contribute very little to the overall yield of
heavy tar in gasification.
Not surprisingly, phenol production was
statistically invariant (95 percent confidence
level) for the change in injection geometries in-
corporated in this study. Both of the coal injec-
tion geometries used in the experiments provid-
ed no gas residence time in the fluidized bed
and accordingly, phenol production for all the
tests were aproximately equivalent. These
data, combined with the previous bench-scale
results, strongly support the original postulate
that phenol is inherently formed during
gasification and its destruction occurs via ther-
mal decompositon.
2. Pilot-Scale Tar/Oil Studies
As with phenol, the C02-Acceptor pilot plant
produces essentially no tar/oil effluent. Conse-
quently, using the gasifier sample probe
discussed earlier for sampling at the point of
coal injection in the CO2-Acceptor gasifier
could also provide information concerning the
relative impacts of formation and decomposi-
tion phenomenon on tar/oil existence.
Preliminary data indicate the presence of some
heavier hydrocarbons; however, the specific in-
dentification of these components has not yet
been completed nor have their production rates
been determined.
Preliminary Interpretation of Pilot
Plant Liquid Effluent Data
Based on the bench-scale, PDU-scale, and
pilot scale experimental studies completed at
this time, it would appear that:
1. Phenol is indeed inherently formed dur-
ing the heat-up and devolatilization of
coal. Consequently, phenol production
during gasification is directly related to
the extent of thermal decomposition
that occurs in the gasifier. This in turn,
is influenced by residence time and
temperature in the gasifier, and the
presence of char solids, and
2. Heavy tar production, on the other
hand, is dramatically influenced by
devolatilization conditions, particularly
262
-------
gas-solid contacting, and does not ap-
pear to be influenced by thermal
decomposition phenomenon.
These semi-quantitative observations are quite
useful in understanding the liquid effluent pro-
duction of the various pilot plants presented
earlier in Table 4 as well as providing the initial
tools for the prediction of liquid effluent pro-
duction levels for full scale commercial plants.
The relationships between process variables
and liquid effluent production identified in the
bench-scale and PDU-scale experiments are
also demonstrated by the major gasification
pilot plants. The free-fall, top bed-injection, and
deep bed-injection coal feed geometries of the
PDU effectively simulated the devolatilization
conditions, i.e., gas-solid contacting and
temperature, and product gas residence time
conditions of the Lurgi, Hygas, and C02-
Acceptor gasifiers, respectively. Accordingly,
these pilot plants demonstrated qualitatively
the same liquid effluent production
characteristics as the equivalent feed
geometries in the PDU (Table 6):
• Minimal gas-solid contacting/
temperature and product gas residence
time - high tar, oil, and phenol produc-
tion,
• Extensive gas-solid contacting/
temperature and minimal product gas
residence time - low tar, high oil, and
high phenol production, and
• Extensive gas-solid contacting/
temperature and product gas residence
time - low tar, oil, and phenol produc-
tion.
The ability to correlate these process variables
to liquid effluent production on the pilot plant
scale represents a significant first step for the
interpretation and prediction of liquid effluent
production in full scale commercial facilities. In
addition, this initial screening has indicated the
direction for more detailed experimental work
which will further define the critical relation-
ships identified at this point. Perhaps more im-
portantly, the methodology used to identify
these process variable/effluent production rela-
tionships, that is, the process engineering ap-
proach to the collection of environmental data,
may prove to be an invaluable tool necessary
for the simultaneous development of new
technologies and environmental regulatory
policies in the United States.
FUTURE WORK
In the initial year of the ERDA coal gasifica-
tion environmental assessment program,
primary emphasis has been placed on activities
which should lead to well-designed en-
vironmental test plans at each pilot facility. In
field work at the pilot plants, this has led to an
emphasis on wastewater studies, due to the
lack of factual information concerning coal
gasification wastewaters and the potential im-
portance of such wastewater effluents.
Although the$e studies are not yet completed,
initial efforts have developed and verified
wastewater sampling and analytical methods,
and have produced a preliminary data base.
Comprehensive environmenal assessment test
plans for the ERDA pilot plants can now be bas-
ed on the preliminary information obtained in
these wastewater studies, as well as on infor-
mation available from related and previous
studies characterizing gas/liquid/solid waste
streams from coal gasification.
With the completion of activities closely
related to test plan formulation, emphasis in the
next year can shift to the following priorities:
• Media emphasis will be refocused from
wastewater studies to a balanced em-
phasis on all the media. In particular,
characterization of gas streams and
waste solid streams is seen as a priori-
ty. The characterization work includes
efforts to measure the distribution and
form of sulfur in coal gasification ef-
fluents, as well as efforts involving
characterization of selected trace
metals in effluent streams.
• Emphasis in planning activities will shift
from environmental and process-
related parameters (e.g., S02 in gas
streams, COD in liquid effluents) tc
those parameters useful fo
characterization of potential occupa
tional health problems in coal gasifica
tion (e.g., trace organics, hydrocarboi
condensates). Efforts will be made t
develop and verify basic methods fc
characterization of these parameters
263
-------
as well as carry out screening analyses
in typical pilot plant streams.
• Data-gathering programs at the pilot
plants are to emphasize the
characterization of effluent streams
which will have a counterpart in larger-
scale facilities, for a range of important
gaseous, wastewater, and waste solid
components.
REFERENCES
1. M. J. Massey, and R. W. Dunlap, "En-
vironmental Assessment Activities for the
ERDA/AGA High BTU Coal Gasification
Pilot Plant Program," presented at the 8th
Annual Synthetic Pipeline Gas Sym-
posium, October 18-20, 1976, Chicago,
Illinois.
2. M. J. Massey et al., "Environmental
Assessment in the ERDA Coal Gasifica-
tion Development Program," Report to
ERDA from the Environmental Studies In-
stitute, Carnegie-Mellon University, NTIS
No. FE-2496-6. March 1977.
3. M. J. Massey et al., "Characterization of
Effluents from the Hygas and CO2-
Acceptor Pilot Plants," Report to ERDA
from the Environmental Studies Institute,
Carnegie-Mellon University, NTIS No. FE-
2496-1, November 1976.
4. R. G. Luthy et al., "Analysis of
Wastewaters from High BTU Coal
Gasification Plants," presented at the
32nd Purdue Industrial Waste Con-
ference, Lafayette, Indiana, May 10-12,
1977.
5. R. W. Dunlap and M. J. Massey, "Gas-
Phase Environmental Data from Second
Generation Coal Gasification Processes,"
Report to ERDA from the Environmental
Studies Institute, Carnegie-Mellon Univer-
sity, NTIS No. FE-2496-2, February
1977.
6. A. K. Koblin and M. J. Massey,
"Preliminary Investigation: Time Variabili-
ty of the Pretreater Condensate Composi-
tion at the Hygas Pilot Plant," Report to
ERDA from the Environmental Studies In-
stitute, Carnegie-Mellon University, NTIS
No. FE-2496-7, July, 1977.
7. A. H. Koblin etal., "Exploratory Analysis
of Variations in Aqueous Gasification Ef-
fluent Characteristics with Time," Report
to ERDA from the Environmental Studies
Institute, Carnegie-Mellon University,
NTIS No. FE-2496-4, February 1977.
8. A. H. Koblin and M. J. Massey, "Influence
of Time Variability on the Design of
Sampling Strategies for Coal Gasification
Wastewaters," presented at the Second
Pacific Chemical Engineering Congress,
Denver, Colorado, August 28-31, 1977.
9. M. J. Massey et al., "Analysis of Coal
Wastewater Analytical Methods: A Case
Study of the Hygas Pilot Plant," Report to
ERDA from the Environmental Studies In-
stitute, Carnegie-Mellon University, NTIS
No. FE-2496-3, February 1977.
10. R. G. Luthy, "Methods of Analysis of Coal
Gasification Wastewaters," Environmen-
tal Studies Institute, Carnegie-Mellon
University, Pittsburgh, Pennsylvania,
February 18, 1977.
11. R. G. Luthy et al., "Interaction of Cyanide
and Thiocyanate in Coal Gasification
Wastewaters," for presentation at the
50th Annual Water Pollution Control
Federation Conference, Philadelphia, Pen-
nsylvania, October 2-7, 1977.
12. D. V. Nakles et al., "Influence of Syn-
thane Gasifier Conditions on Effluent and
Product Gas Production," Pitts-
burgh Energy Research Center, U.S.
Energy Research and Development Ad-
ministration, Pittsburgh, Pennsylvania,
PERC/RI-75/6, December 1975.
13. M. J. Massey et al., "Role of Gasifier Pro-
cess Variables in Effluent and Prod-
uct Gas Production in the Synthane Pro-
cess," Symposium Proceedings: En-
vironmental Aspects of Fuel Conversion
Technology II (December 1975,
Hollywood, Florida), EPA-600/2-76-149,
June 1976.
14. R. W. Dunlap et al., "Characterization of
Effluents from the C02-Acceptor Coal
Gasification Process," Environmental
Studies Institute, Carnegie-Mellon Univer-
sity, Pittsburgh, Pennsylvania, January
14, 1977.
1 5. "Environmental Assessment of the Hygas
264
-------
Process," Report to ERDA from the In-
stitute of Gas Technology, NTIS No. FE-
2433-8, May 1977.
16. "Environmental Assessment of the Hygas
Process," Report to ERDA from the In-
stitute of Gas Technology, NTIS No. FE-
2433-13, August 1977.
17. "Trials of American Coals in a Lurgi
Gasifier at Westfield, Scotland," Report
for ERDA from Woodall Duckham Ltd.,
Sussex England, Report No. 105, 1974.
18. R. C. Ellman et al., "Current Status of
Studies in Slagging Fixed-bed Gasification
at the Grand Forks Energy Research
Center," presented at the 1977 Lignite
Symposium, Grand Forks, North Dakota,
May 18-19, 1977.
19. J. P. Fillo et al., "Decomposition
Characteristics of Phenolic Compounds
Under Synthane Gasifier Conditions," Pit-
tsburgh Energy Research Center, U.S.
Energy Research and Development Ad-
ministration, Pittsburgh, Pennsylvania,
PERC/RI-77/1, March 1977.
20. D. V. Nakles, "Significance of Process
Variables on Liquid Effluent Production in
Coal Gasification," Ph.D. Thesis,
Carnegie-Mellon University, Pittsburgh,
Pennsylvania, August 1977.
265
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TRACE ELEMENTS IN THE
SOLVENT REFINED COAL
PROCESS
By
R. H. Filby, K. R. Shah
Nuclear Radiation Center
Washington State University
Pullman, WA 99164
and
C. A. Sautter
Physics Department
Concordia College
Moorhead, MN
Abstract
Results are presented of a study of the
distribution and fate of 34 trace elements in the
Solvent Refined Coal Process Pilot Plant
located at Fort Lewis, Washington and
operated by the Pittsburg & Midway Coal Min-
ing Co. under contract with the U.S. Energy
Research and Development Administration.
Neutron activation analysis was used to deter-
mine Ti, V, Ca, Mg, Al, Cl, Mn, As, Sb, Se, Hg,
Br, Co, Ni, Cr, Fe, Na, Rb, Cs, K, Sc, Tb, Eu,
Sm, Ce, La, Sr, Ba, Th, Hf, Ta, Ga, Zr, and Cu in
feed coals, process solvent. Solvent Refined
Coal (SRC-I) mineral residues, wet filter cake,
sulfur, by-product solvents, process and ef-
fluent waters and by-product sulfur. A
materials balance or budget was calculated for
each element from the concentration data and
the yields of each process fraction in the SRC
process. The SRC-I and insoluble residue ac-
count for more than 90% of the input of each
element, with other process fractions con-
tributing little to the trace element balance. Ex-
cept for Cl, Br, and Ti, each element was
substantially lower in the SRC-I compared to
the original feed coal. Two separate sets of
samples were taken when the pilot plant had
operated continuously for 7 days and com-
posite samples were collected for each process
fraction over a 24-hour period. The materials
balance for each element {averaged for the two
data sets) expressed as a percentage of the
elemental input were: Ti (163), V (139), Ca
(146), Mg (71), Al (97), Cl (84), Mn (136), As
(106), Sb (127), Se (103), Hg (104), Br(159),
Ni (133), Co (122), Cr (117), Fe (109), Na
(127), Rb (119), K (100), Cs (97), Sc (120),
Tb (112), Eu (100), Sm (108), Ce (110), La
(108), Ba (108), Th (112), Hf(121), Ta (114),
Ga (98), Zr (115), and Cu (132). The contents
of all trace metals, including Hg, in plant ef-
fluent waters showed little variation from
background level.
Coal liquefaction is a means of producing low
sulfur, low ash fuels from coal which is a
relatively dirty fuel for power generation com-
pared to residual fuel oil. As the future energy
needs of the United States are going to be met
in large part by coal and coal-derived products
in order to reduce dependence on petroleum,
coal conversion will play an important role in
the U.S. energy picture of the future. Both
gasification and liquefaction processes are now
under development and are at various stages of
commercialization. Coal liquefaction is ex-
pected to provide chemical and refinery
feedstock materials in addition to boiler fuels
for energy generation, although this aspect of
coal conversion is at present less attractive
economically than the production of boiler
fuels.
The Solvent Refined Coal Process (SRC-I
process) developed by Pittsburg & Midway
Coal Mining Company under contract with the
U.S. Energy Research and Development Ad-
ministration is presently at an advanced stage
and a 50 ton/day Pilot Plant is operating at Fort
Lewis, Washington. This pilot plant has
undergone extensive testing and production
runs of solid Solvent Refined Coal (SRC-I) have
been made for power plant burning studies of
the SRC-I product. The first successful com-
mercial power generation from SRC-I was com-
pleted in the first half of 1 977.
The widespread construction and use of coal
conversion plants requires an evaluation of the
environmental hazards associated with each
process and plant. Among such hazards is the
problem of potential emissions of toxic forms
of some tVace elements, for example As, Hg,
Sb, or Se. An important objective of liquefac-
tion processes is to remove much of the sulfur
and mineral content of coal so that the resulting
fuel can be burned without expensive stack
scrubbers and meet stack emission specifica-
tions. It is thus important that the fate and
266
-------
distribution of trace elements in the SRC-I
process be determined to assess the pollution
potential of the fuel (SRC) and the environ-
mental effects of emissions and effluent
disposal. The distribution of trace elements
present in the coal during liquefaction is also
important in determining trace element
materials balances in the process and to
evaluate the effects of coal type, autocatalytic
effects, temperature, pressure, solvent com-
position, degree of hydrogenation on the
materials balance.
The objective of the study reported in this
paper was to apply the technique of neutron ac-
tivation analysis to the determination of trace
elements in the SRC-I process. Neutron activa-
tion analysis was chosen as the method of
trace element analysis because of the high sen-
sitivity for many elements, good precision and
accuracy, the multielement nature of the
technique, and the capability of analyzing very
different matrix types. This latter advantage is
significant for the SRC-I project where very
diverse materials are encountered, e.g. coal,
SRC-I, filter aids, residues, process waters and
volatile solvents.
Material balances have been measured for
the elements Ti, V, Ca, Mg, Al, Cl, Mn, As, Sb,
Se, Hg, Br, Co, Ni, Cr, Fe, Na, Rb, Cs, K, Sc, Tb,
Eu, Sm, Ce, La, Sr, Ba, Th, Hf, Ta, Ga, Zr and
Cu. A preliminary study was carried out when
the SRC-I pilot plant was operating at non-
steady state conditions and the data from this
study have been reported previously1'2. Later
two material sets were collected after the pilot
plant had operated continuously for at least 7
days and these are referred to as equilibrium (or
steady state) sets (1 and 2) and the trace ele-
ment data obtained are discussed in this paper.
The Solvent Refined
Coal (SRC-I) Process
A schematic diagram of the SRC-I process is
shown in Figure 1. Coal is crushed, ground and
dried, mixed with a solvent (recycled in the
process) to form a slurry which is hydrogenated
in a reactor at 455°C at 1 500 psig. After the
reactor, process gases (C} - C4 hydrocarbons,
C02, H2S, CO, H2, etc.) are flashed off and the
liquid is filtered through pre-coated rotary drum
filters to remove unreacted coal and mineral
matter. Light oils and process solvent are flash-
ed off the liquid to give a solid product, SRC-I,
and the solvent recycled back into the system.
In this process the coal is dissolved in the sol-
vent and, depolymerized to give smaller
molecules in the presence of hydrogen.
Much of the organic sulfur is converted to
H2S and some of the FeS2 is converted to FeS
+ H2S
i.e. FeS2 + H2 - FeS -I- H2S
R-S-R1 + 2H2 - H2S + R-H + R^H
Approximately daily rates of production of
trace elements in the 50 ton/day pilot plant are
shown in Table 1. The fate of trace elements
present in the coal during the process is de-
pendent on a) the nature of the element and b)
the chemical bonding of the element in the coal
matrix i.e. organically bound or inorganically
present as mineral species. Under the reducing
process conditions (high H2 pressure, 455°C,
1 500 psig) several elements may be volatile or
form volatile species, e.g. Hg°, H2Se, AsH3,
SbH3, HBr, Fe(CO)5, and Ni(CO)4, among
others. Whether such species will be formed
will depend largely on the nature of the host
mineral (or maceral) and whether this mineral is
reactive under the liquefaction/hydrogenation
conditions. In addition to the volatile species
that might escape in gaseous emissions or con-
dense with distillate products, there is the
possibility of reaction with the organic matrix
to form organometallic compounds, many of
which are extremely toxic and some of which
are volatile. Many of the transition metals (e.g.
Ti, Fe, Mn, Ni, Co, etc.) form a number of stable
organometallic compounds with hydrocarbons
or hydrocarbon-like molecules, for example the
cyclopentadienyl compounds e.g. ferrocene
Fe(C5H5)2, titanocene Ti (C5H5)2 and the many
derivatives of the metallocenes, e.g. carbonyls,
hydrides, salts, etc. Many of these are toxic
and relatively volatile species and Table 2 lists
some compounds that, if present, could be of
environmental concern.
Unfortunately we have very little information
on the fate of trace elements in coal during li-
quefaction, although it is obvious that the final
molecular species of an element may be quite
different from these encountered in coal
because of the highly reactive conditions and
267
-------
TABLE 1
PRODUCTION OF TRACE ELEMENTS IN 50 TON/DAY SRC-I Pll OT PLANT
8
Minor
Elements
Fe
S
Al
T1
Ca
Mg
K
Na
Concentration in
Coal (ppm)
2A%
3.8%
1.1%
547
630
860
1260
124
Production
Kg/day
1200
1900
540
28
32
44
64
6.3
Trace
Elements
As
Sb
Hg
Se
Cl
Br
N1
Co
Cr
Cu
Concentration in
Coal (ppm)
11.6
1.0
0.113
2.2
286
5.8
18.0
5.3
10
22
Production
Kg/day
0.6
0.05
0.006
0.1
15
0.3
0.9
0.3
0.5
1.1
-------
TABLE 2
POSSIBLE ENVIRONMENTALLY IMPORTANT FORMS OF
SOME TRACE ELEMENTS DURING LIQUEFACTION
Element
Volatile Species
Organic Species
As
Sb
Hg
Se
Fe
Ni
Ti
RAsH2, RR AsH
SbH3, SbCl3, SbBr,
SbOCl
Hg metal, HgBr2
H2Se, Se°
Fe(CO)5
Ni(CO)4
TiCl.
RSbH2, RRSbH, R
R2Hg, RHg+X
R-Se-R1; R-SeOgH
Fe(C6H5)2(CO)x
Ni-asphaltene
bonds
Ti(C5H5)2
the complex chemical system of the dissolu-
tion/hydrogenation process.
Trace Element Balances
in Liquefaction
Very little information is available on the
distribution of trace elements in coal conver-
sion processes, although a number of
preliminary studies have been made for
gasification processes. Forney et al.3 have
studied the distribution of trace elements
around the Synthane gasifier at PERC using
mass spectroscopy. The results ranged from
218% recovery for F to 1103% for Pb and no
reliable mass balances could be derived. Jahnig
and Magee4 presented some limited data on
trace elements in SRC-I and related coals but no
mass balances were calculated, nor were other
process streams analyzed.
The work reported here is thus the first at-
tempt at calculating trace element balances in
the SRC-I process.
ANALYTICAL METHODS
Sample Collection
and Preparation
In order to evaluate the fate of elements in
the coal liquefaction process, the sample col-
lection procedure is critical. Samples collected
should not only cover various important
process parameters but also be representative
of the process stream sampled. After discus-
sions with pilot plant personnel, twelve dif-
ferent points in the pilot plant were selected as
the sample collection points. These points and
materials collected are listed in Table 3 and
shown on Figure 1. These points effectively
269
-------
TABLE 3
PILOT PLANT SAMPLE COLLECTION POINTS
Sampling
Point
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
Description
Raw coal
Dried/pulverized
coal
Dust collector
Recycle solvent
Solvent refined
coal
Mineral residue
Elemental sulfur
Light ends
Filter-aide
Process water
Treated effluent
water
Fresh Wash
Solvent
Matrix
solid
solid
solid
organic
solvent
solid
solid
solid
organic
solvent
solid
aqueous
aqueous
organic
solvent
Amount
50 gm
50 gm
10 gm
1000 ml
100 gm
50 gm
100 gm
2 quart
50 gm
350 ml
350 ml
1000 ml
270
-------
SOLVENT REFINED COAL PROCESS
SULFUR
COAL
SOLVENT
RECOVERY
UNIT
PRODUCT
AND SOLVENT
SOLVENT REFINED COAL
Numbers refer to sampling
points in Table 3.
-------
covered all input, output, and other important
process streams. Laboratory prepared samples
were also analyzed to check any contamination
of plant products by the process.
A representative sample was essential for
this study. All samples should be collected
when the plant is operating under a 'steady
state' condition. This is very hard to achieve
and as a compromise it was decided that the
plant should be operating at least seven days
without interruption prior to the sample collec-
tion. In order to nullify any effect of momentary
fluctuation of the process conditions, all
samples were collected for a period of 24 hours
(every 4 hours) from each collection point.
Final composites of samples were prepared by
mixing samples collected during the 24-hour
collection period for each point. Run conditions
for equilibrium sets 1 and 2 are shown in
Tables 4 and 5.
Samples collected for elemental analysis
were divided into three groups depending upon
sample matrix. They were a) solid samples, e.g.
SRC-I, coal, residues, etc. b) organic solvents,
and c) aqueous samples. Each type of sample
required different procedures for the sample
preparation, storage, and analysis. These pro-
cedures were:
Solid Samples: Solid samples such as SRC-I,
ground coal, pyridine insolubles, etc., were col-
lected in cleaned glass or polyethylene con-
tainers. These containers were soaked in dilute
nitric acid for about 4 hours and then cleaned
with double distilled water prior to use. The
procedure was necessary to remove any sur-
face contamination,
Organic Solvents: Solvents were collected in
pre-cleaned brown glass containers, cleaned as
above.
Aqueous Samples: Collection and shipping of
aqueous samples required special attention. It
is known that many elements are readily ad-
sorbed on the wall of containers (plastic or
glass) from the aqueous phase. The rate of ad-
sorption varies from element to element and is
often an irreversible process. It was found that
if the aqueous samples were frozen immediate-
ly after the collection and kept frozen until
analysis, the elemental adsorption process was
kept to a minimum. It was also necessary that
aqueous samples be free of suspended matter.
In order to avoid both problems a special sam-
ple collection and shipping procedure was
developed. Immediately after the collection,
aqueous process streams were filtered through
clean Nucleopore 0.4 ^m filter in a Teflon filter
assembly. The filtered samples were then
quickly frozen. The aqueous filtered samples
were collected in cleaned polyethylene bot-
tles(200 ml) and in four different Playtex thin-
walled polyethylene bags (each containing ap-
prox. 50 ml). These samples were shipped
frozen by air freight to Washington State
University.
Neutron Activation
Analysis
Neutron activation analysis was used to
determine the total of 34 elements, Ti, V, Mg,
Ca, S, Al, Cl, Mn, As, Br, Na, K, Sm, La, Ga, Cu,
Sb, Se, Hg, Ni, Co, Cr, Fe, Rb, Cs, Sc, Tb, Eu,
Ce, Sr, Ba, Th, Hf, Ta, and Zr in all samples.
Details of the procedures have been described
elsewhere1'2.
RESULTS AND DISCUSSION
The elements Ti, V, Ca, Mg, Al, Cl, Mn, As,
Sb, Se, Hg, Br, Ni, Co, Fe, Cr, Na, Rb, K, Cs, Sc,
Tb, Sm, Ce, La, Sr, Ba, Th, Eu, Hf, Ta, Ga, Zr
and Cu were determined in the samples from
the two equilibrium sets and from the SRC-I
process pilot plant. The concentrations ob-
tained in the important process fractions are
shown in Tables 6 and 7 for Equilibrium Set 1.
Due to lack of space the concentration data for
equilibrium set 2 are not included, neither are
the error values associated with each deter-
mination. In most cases, however, the relative
standard deviations of each value (counting
statistics) are less than 10% and in many cases
are less than 5%.
Several points should be made concerning
the concentration data. The concentration of
each element in SRC-I is much lower than in the
feed coal, except for Br which is the only ele-
ment to show an increase. The percentage
reduction in the SRC-I relative to the ground
feed coal for equilibrium sets 1 and 2 are
shown in Table 8. Bromine shows an increase
in both equilibrium sets and it is not clear where
the source of Br lies. Another point of interest,
pertinent to the question of materials balances,
272
-------
TABLE 4
RUN CONDITIONS FOR EQUILIBRIUM SETS
CONDITION
RAW COAL FEED
WATER REMOVED FROM COAL
NET DEHUMIDIFIED COAL FEED
MOISTURE FREE COAL FEED
SOLVENT FEED FROM AREA 04
SLURRY RECYCLE FEED
SLURRY FEED TO PREHEATER
SOLV.& REC. SLURRY TO DEH. COAL RATIO
PERCENT SLURRY RECYCLE
RECYCLE/TOTAL FEED RATIO
HYDROGEN-RICH GAS FEED
GAS FEED PURITY-MOL. PCT. H2
HYDROGEN FEED
HYDROGEN FEED
SLURRY PREHEATER INLET PRESSURE
SLURRY PREHEATER OUTLET TEMPERATURE
DISSOLVER A PRESSURE
SET 1
3422.
233.
3188.
3129.
4635.
0.
7823.
1.45
0.0
0.00
201.
97.6
164.
30855.
1623.
742.
1545.
SET 2
3488. #/HR
219. #/HR
3269. #/HR
3241. #/HR
4240. #/HR
0. #/HR
7509. £/HR
1.30
0.0 PCT.
0.00
164. #/HR
98.7
140. #/HR
26306. SCFH
1631. PSIG
752. DEGF
1498. PSIG
DATE
3/1/76
^14/76
273
-------
TABLE 5
YIELD DATA FOR EQUILIBRIUM RUNS
Product
H2
N2
Cl
CO
C2
C02
C3
C4
H2S
LT. OIL
H20
WSH SOLV
PROC SOL
SRC
ASH
UNREA. C
COAL
Yield
Equil. Set 1
-2.75
0.02
2.54
0.02
1.00
1.38
1.16
0.54
1-65
2.53
5.00
7.77
-8.90
69.48
11.88
6.12
-100.03
% MFC
Equil. Set 2
-1.92
0.00
1.91
0.79
0.76
1.65
0.92
0.48
1.92
2.90
5.00
3.11
-6.93
71.13
12.31
6.00
-100.02
TOTAL 0.00 0.00
274
-------
TABLE 6
CONCENTRATIONS OF SEVEN ELEMENTS IN SRC-I STREAMS
CO
^j
01
El ement
T1 (ppm)
V (ppm)
Ca (ppm)
Mg (ppm)
Mn (ppm)
Al (%)
Cl (ppm)
GC
530.1
30.1
330
1160
34.0
1.18
260.1
SRC
465.0
4.63
72.8
89.0
20.3
0.02
159.5
PI
3350
195.2
6300
4000
185.0
7.72
759.6
WFC
1490
140.6
3015
4345
140.0
5.5
1641.0
LO
2.04
0.050
<10
<10
0.18
50 ppm
16.9
PRS
19.1
0.445
<10
<10
2.09
43.9ppm
127
WS
0.92
0.052
<5
<7
0.2
11 .6ppm
92.2
S
<90.0
8.2
<600.0
<300.0
8.0
<6 ppm
<40.0
GC Ground coal
WFC Wet filter cake
PRS Process recycle
solvent
PI Pyridine insolubles
LO Light oil
WS Wash solvent
S Sulfur
-------
TABLE 7
EQUILIBRIUM SET 1, RAW MATERIALS & PRODUCTS
As (npm)
Sb (ppm)
Se (ppm)
Hg (opb)
Br (ppm)
Ni (npm)
Co (ppm)
Cr (pom)
Fe (X)
Na (ppm)
Rb (ppm)
Cs (ppm)
K (ppm)
Sc (ppm)
Tb (ppm)
Eu (ppm)
Sm (ppm)
Ce (ppm)
La (ppm)
Sr (ppm)
Ba (ppm)
Th (ppm)
Hf (ppm)
Ta (ppm)
Ga (ppm)
Zr (ppm)
Cu (ppm)
GC
12.5
0.76
2.0
113
4.56
14.9
5.88
13.7
2.11
137
<4.0
0.75
1550
2.59
0.39
0.26
2.62
20.9
7.55
88.6
53.0
2.00
0.51
0.14
3.56
62.9
19.9
SRC
2.00
0.06
0.12
39.6
7.74
<3.0
0.22
1.64
0.03
4.23
<0.5
0.02
4.72
0.57
0.045
0.055
0.29
0.45
0.13
<6.0
5.75
0.22
0.084
0.046
1.79
16.0
2.07
PI
85.7.
7.21
16.5
508
12. f)
142
40.7
106
16.8
1020
66.5
5.08
11100
14.8
2.06
1.48
16.9
156.0
59.8
456.0
347.0
12.8
3.30
0.71
19.4
500.0
189
WFC
62.1
5.35
11.3
346
20.7
82.4
26.5
69.2
11.7
623
37.1
3.20
6660
9.26
1.34
0.96
8.16
102
35.2
453
185.0
7.70
2.20
0.42
11.3
246
138
LO
0.011
<0.4*
51.6*
18.5
0.015
<0.03
*
< 3.0
*
37.3
if
2.90
0.60
<0.01
*
1.06
<0.1
*
0.15
it
<0.13
<0.01
<0.01
<0.004
<0.01
<0.6
<0.1
<0.001
<0.001
*
<0.4
<0.01
0.07
0-03
PRS
0.24
8.2*
24.0*
1.45
1.0
0.4
*
40.7
3590*
it
211
0.50
0.02
*
0.25
*
32.8
*
3.75
<0.01
0.02
<0.004
0.01
<0.2
1.14
0.012
0.003
*
2.53
0.06
0.71
0.68
WS
0.011
<0.4*
14.4*
10.5
0.02
<0.03
*
1.43
41.3*
it
' 11.2
0.45
<0.01
*
0.91
<0.1
0.19
jf
<0.13
<0.01
<0.01
< 0.003
<0.01
0.74
<0.07
<0.001
<0.001
*
<0,3
<0.01
<0.1
0.03
s
<2.n
-------
TABLE 8
TRACE ELEMENT REDUCTION SRC COMPARED TO COAL
Element
Ti
V
Ca
Mg
Alt*)
Cl
Mn
As
Sb
Se
Hg
Br
Ba
Th
Hf
Ta
Ga
Zr
Cu
Na
Rb
Cs
K
Ni
Co
Cr
Fe
Sc
Tb
Eu
Sm
Ce
La
SRC/G.Coal
0.88
0.15
0.22
0.08
0.02
0.61
0.60
0.16
0.08
0.06
0.35
1.70
0.11
0.11
0.16
0.39
0.50
0.25
0.10
0.03
0.03
0.003
0.04
0.12
0.01
0.22
0.12
0.21
o.n
0.02
0.02
% Reduction
12
85
78
92
98
39
40
84
92.
94
65
+70
89
89
84
61
50
75
90
97
97
100
96
88
99
78
88
79
89
98
98
Element
Ti
V
Ca
Mg
A1(S)
Cl
Mn
As
Sb
Se
Hg
Br
Ba
Th
Hf
Ta
Ga
Zr
Cu
Na
Rb
Cs
K
Ni
Co
Cr
Fe
Sc
Tb
Eu
Sm
Ce
La
SRC/G.Coal
0.74
0.47
0.22
0.03
0.34
0.40
0.07
0.04
0.03
0.41
1.33
0.10
0.12
0.29
0.19
0.08
0.08
0.04
0.02
0.001
0.05
0.37
0.01
0.15
0.09
0.14
0.07
0.02
0.01
* Reduction
16
53
78
97
66
60
93
96
97
59
+33
90
88
71
81
92
92
96
98
99.9
95
63
99
85
91
86
93
98
99
277
-------
is that only SRC and fractions derived from the
mineral residues (i.e. mineral residue, pyridine
insolubles) show significant concentrations of
trace elements.
The high concentrations of Ti in the SRC-I are
only slightly lower than in the original coal. In
SRC-I from equilibrium set 1 the concentration
is 465 (in set 2 it is 490 ppm) and this
represents only a 1 2% reduction compared to
coal (10% for set 2). It is not known why Ti
behaves so differently from all other metals
studied but possible explanations are:
a) Ti is present in coal as an extremely
finely divided oxide (TiO2) which
passes through the rotary drum filters.
b) Ti is present as an organometallic
species in coal, soluble in the process
solvent.
c) Ti is present in an inorganic combina-
tion (i.e. mineral form) but reacts to
form an oil-soluble compound (TiCI4) or
an organometallic species) during the
hydrogenation reaction.
There is some evidence5 that suggests the
presence of an organometallic species in SRC-I,
but the form of Ti in SRC-I is outside the scope
of this paper.
Materials Balance
Calculations
One of the main objectives of this study was
to determine the fate of trace elements in the
SRC-I process and to determine a materials
balance for each element, particularly those
known to be, or suspected of being toxic. To do
this, it is necessary to know the elemental con-
centration of each process fraction and the
weight yield (in % from original coal) of each
fraction. The run data shown in Table 5 pro-
vides information on the yields of SRC-I, Light
Oils (LO), Wash Solvent (WS), Process Water
(PW), and Sulfur (from H2S yields). However, it
is difficult to assign a contribution to the re-
cycle process solvent yields so that we have ar-
bitrarily assigned a value of 5% for this frac-
tion. In quantitative terms, the recycle process
solvent contribution to the overall materials
balances is negligible and the error associated
with the assigned yield is small. A more difficult
problem concerns the contribution of the
filtered residue to the materials balance.
Several residues were analyzed viz: pyridine in-
solubles (PI), mineral residue, wet filter cake
(WFC) and ash of pyridine insolubles. We have
chosen to base the "residue" component of
the materials balance on the pyridine insolubles
because a) the solvent-soluble material has
been washed out compared to the filter cake,
and b) no elements have been lost by ashing
(very important for Hg, Se, and As) as com-
pared to the ash of the pyridine insolubles. The
pyridine insolubles thus represent inorganic
mineral matter and any unreacted coal.
However, we did not have run data on pyridine
insolubles. Consequently we computed the PI
contribution by assuming that 100% of K from
the coal is in the PI and this appears reasonable
considering the very low K content of SRC-I
compared to the input coal. When computed in
this way the PI yield per unit of coal is 1 3.9%
for Run 1 and 1 8.1 % for equilibrium set 2. The
proportions of each fraction (coal = 1.0) for
the two equilibrium sets are shown in Table 9.
The material balance for each element in per-
cent of input from coal are given in Table 10.
In these calculations we have assumed that
the only contributions to the trace element in-
put is the coal. This assumption naturally does
not take into account contributions from the
recycle process solvent (small), H2 gas (small)
or from corrosion and wear of the construction
materials (possibly important for some
elements). For equilibrium set 2 the balances
range from a low value of 82.3% (CD to a high
of 293% for Ca. Except for Ca, Ni, Ti, V, and Cr
all balances lie within the range 83 - 145%
which may be regarded as excellent given the
assumptions made and the errors associated
with obtaining representative samples of the
process streams. For equilibrium set 1 the
values range from 53% (Mg)to 259% (Rb). Ex-
cept for Mg (53%), Rb (259%) and Br(172%)
all values lie within the range 85 - 1 50% which
may be considered excellent.
Of particular significance are the materials
balances for Hg, As, Se, Sb and Br. For Hg, a
volatile element, the materials balances are
98% and 109% for sets 1 and 2 and this
shows that all the Hg in the process is ac-
counted for. It should be noted that the recycle
process water of equilibrium set 1 accounts for
10% of the total. Mercury is the only element
278
-------
TABLE 9
PROCESS FRACTION CONTRIBUTIONS
TO MATERIALS BALANCES
Process Fraction
Contribution
Equilibrium Set 1 Equilibrium Set 2
Coal
1.00
1.00
SRC
PI
PRS
LO
WS
RPW
S
TOTAL
0.695
0.139
0.05
0.023
0.05
0.05
0.016
1.02
0.711
0.187
0.05
0.03
0.05
0.05
0.016
1.09
for which the RPW accounts for more than 1 %
of the total. Arsenic, antimony and selenium in
equilibrium set 1 all balance well. For set 2 the
very high As value is accounted for by an
anomalously high concentration of As in the PI.
This is being investigated. For Sb, and Se the
balance is again good. For both sets, Br is high
and there may be an external source of Br
(probably solvents). Titanium is also high,
149% and 176% for sets 1 and 2 respectively.
This may be due to corrosion of equipment or
some other source. The high values for set 2
for Cr, Ni, and B may be due also to equipment
corrosion. These three elements balance nor-
mally for equilibrium set 1.
Aqueous Environmental
Samples
Several aqueous samples were analyzed in
this study to determine the buildup of trace
elements in the process water, treated effluent
water and Hamer Marsh water (into which the
plant effluent drains). Although there are
significant concentrations of Hg, Se, As, and
Cu in both process waters, these elements had
been reduced to very low levels in the treated
effluent water and in Hamer Marsh water. The
efficient removal of these elements in the
biotreatment plant appears to be primarily
responsible for the low elemental concentra-
tions in the plant effluent. High values of Se
(6.3 ppm) and Hg (8.7 ppm) are found in the
bio-sludge of equilibrium set 2 indicating the ef-
ficient removal of Hg and Se. Table 11 shows
the concentrations of some important elements
in samples from equilibrium set 2 because the
set 1 samples did not include the biosludge.
The analytical data for aqueous samples from
set 1 are similar to those of set 2.
ACKNOWLEDGMENTS
This work was supported under a contract
with Pittsburg & Midway Coal Mining Company
279
-------
TABLE 10
MATERIALS BALANCES FOR EQUILIBRIUM SETS
Element
Ti
V
Ca
Mg
Al
Cl
Mn
As
Sb
Se
Hg
Br
Ni
Co
Cr
Fe
Set 1(%)
149
101
146
53
92
85
129
106
137
119
98
172
133
129
117
112
Set 2(%)
176
177
293
88
102
82
143
-
118
88
109
145
248
115
272
105
Element
Na
Rb
Cs
K
Sc
Tb
Eu
Sm
Ce
La
Ba
Th
Hf
Ta
Ga
Zr
Cu
Set 1(%)
142
259
97
100
95
81
94
97
105
112
99
97
101
94
no
128
140
Set 2(%)
112
119
98
100
145
143
105
119
115
104
118
127
141
135
86
102
123
-------
10
CO
TABLE 11
SRC PILOT PLANT, AQUEOUS SAMPLES, EQUI. SET 2
Process Treated Effluent
Water Water
As (ppb)
Sb (ppb)
Se (ppb)
Hg (ppb)
Br (ppb)
Ni (ppb)
Co (ppb)
Cr (ppb)
Fe (ppm)
Na (ppm)
Rb (ppb)
Cs (ppb)
K (ppm)
10.7
1.0
914.3
20.7
18.3
14.0
0.43
11.30
1.34
5.1
0.77
0.04
0.73
<1.0
0.64
0.37
5.5
16.0
0.36
10.1
0.41
8.0
1.36
0.06
<.10
Hamer Marsh Bio-Sludge
Water
<5.0
0.5
0.45
0.38
28.1
7.0
0.26
6.2
0.36
42.4
0.91
0.05
<8
<12.0
1.21
6.28
8.75
8.57
12.0
4.48
47.33
12,000
9630
2.66
0.19
<200.0
Note: All concentrations in the BioSludge are in ppm, not ppb
-------
under an inter-agency agreement between the
U.S. Energy Research and Development Ad-
ministration (ERDA) and the Environmental Pro-
tection Agency (EPA). The authors would like
to express their appreciation to Mr. S. R. Khalil
for much of the analytical work and to Mr. C. A.
Palmer for assistance in the computer reduc-
tion of data. The cooperation of Mr. R. E. Per-
russel at the SRC Pilot Plant is gratefully
acknowledged.
1.
REFERENCES
R. H. Filby, K. R. Shah and C. A. Sautter,
Proc. 1976 Intern. Conf. Modern Trends
in Activation Analysis, Vol. I, 644
(1976).
2. R. H. Filby, K. R. Shah and C. A. Sautter,
J. Radioanal. Chem. 37 693 (1977).
3. A. J. Forney, W. P. Haynes, S. J. Gasior,
R. M. Kornosky, C. E. Schmidt and A. G.
Sharkey. Proc. Symposium Environmental
Aspects of Fuel Conversion Technology II,
EPA600/2-76-149 p 67 (1976).
4. C. E. Jahnig and E. M. Magee. EPA
650/2-74-009f (1975).
5. R. N. Miller. Proc. 1977 Intern. Cont. Ash
Deposits and Corrosion from Impurities in
Combustion Gases, Engineering Founda-
tion Cont. (in press).
6. Pittsburg & Midway Coal Mining Co.
brochure.
282
-------
ANALYTICAL TECHNIQUES AND
ANALYSIS OF COAL TARS,
WATERS, AND GASES
by
C. M. Sparacino,* R. A. Zweidinger,
and S. Willis
Chemistry and Life Sciences Divison
Research Triangle Institute
P.O. Box 12194
Research Triangle Park,
North Carolina 27709
Abstract
Analytical techniques applicable to coal
gasification waste products (tars, waters, and
gases) are described. Methodology for the
qualitative analysis of these samples involves
solvent partition, hplc, and gc-ms.
INTRODUCTION
One of the problems inherent in the in-
vestigation of a fuel conversion process such
as coal gasification, is the development of
analytical methodology that will permit an ade-
quate assessment of the potential pollutants
from such a process. In the case of laboratory
scale gasifiers, this methodology can also be
applied as a means of studying the effects of
different coals and/or parametric variations on
gasification. The need therefore is to develop a
scheme which is reproducible, reasonably
fast, and which can be applied to both volatile
and nonvolatile pollutants (for gasification,
those materials collected in tar and water traps
located immediately after the reactor are con-
sidered nonvolatile, while those materials car-
ried downstream with the gas are considered
volatile).
Our appproach utilizes mass spectrometry as
a basic means of identification. For volatile
materials, components are collected directly
from the gas stream onto polymer sorbents
from which they are solvent extracted or ther-
mally desorbed and transferred to a gas
chromatograph-mass spectrometer-computer
(gc-ms-comp). Nonvolatiles are subjected to a
solvent partitioning process to separate the
mixture into chemically similar groups. Each
group is then either analyzed directly by mass
spectrometry (ms) or is chromatographed using
high performance liquid chromatographic (hplc)
techniques and then subjected to ms analysis.
VOLATILES-QUALITATIVE ANALYSIS
Methodology pertinent to the collection and
analysis of organic volatiles has been
developed in our laboratories in relation to air
pollution studies, and has been described in
detail elsewhere.1 By this process, the volatile
organics are collected from the gas stream
directly by passage of a portion of the stream
through a glass cartridge containing Tenax GC
(poly-p-2,6-diphenyleneoxide). The adsorbed
materials are then removed in toto from the
Tenax by thermal desorption and helium purge
to a cooled (liquid 'nitrogen) capillary trap
(Figure 1). The vapors are then released from
the trap by rapid heating to 175°C, and
transferred onto a high resolution capillary gc
column. This column is interfaced to a double
focusing mass spectrometer. Upon initiation of
a run, the mass spectrometer continuously
scans the column effluent from 28-400 amu
approximately every 7 sec. The information
from all scans is then accumulated by an on-
line computer onto magnetic tapes. The data
acquired includes peak intensities, total ion cur-
rent (TIC) values and Hall probe signals (instru-
ment calibration indicators). Up to approx-
imately 1,000 spectra can be stored during a
single analysis.
Processing the mass spectrometric data in-
volves extraction of the TIC data and plotting
TIC against the spectrum number. This yields a
chromatogram which will generally indicate
whether the run is suitable for further process-
ing since it will give some idea of the number of
unknowns in the sample and the resolution ob-
tained using the particular gc column condi-
tions. The computer is then directed to
generate mass spectral plots of compound(s)
represented by individual peaks in the TIC plot.
Mass spectral plots consist of a plot of mass vs
ion intensity and represent the characteristic
mass spectra of the component(s).
Identification of resolved components can be
283
-------
COMPRESSION SPAING
VALVE POSITION A
(SAMPLE DESOHPTIOH)
ALUMINUM
HEATlN
OATH
SIX-PORT
TWO POSITION
VALVE
HEATING CARTRIGE
CARRIER GAS
«* TO GLC CAPILLARY
HEATING AND COOLING BATH
Nl CAPILLARY TRAP
CARRIER
GAS
PURGE
GAS
VENT
VALVE POSITION 8
(SAUPLC INJECTION)
CARRIER
GAS
punce
GAS
Figure 1. Thermal desorption inlet-manifold.
achieved by comparing the mass cracking pat-
terns of the unknown mass spectra to an eight
major peak index of mass spectra.2 Individual
difficult unknowns can be searched by use of
various computerized systems such as Cornell
University's PMB or STIRS systems, or the EPA
MSSS. When feasible, the identification can be
confirmed by comparing the unknown cracking
pattern and elution temperature on two dif-
ferent gc columns with authentic compounds.
The treatment of volatile organics in the man-
ner discussed has been applied not only to air
samples, for which the process was developed,
but to in situ coal gasification effluents. For the
latter, some 200 neutral components have
been identified. The method is reasonably sen-
sitive; successful identification can be achieved
with - 200 ng of individual component
transferred onto the capillary column.
NONVOLATILES-QUALITATIVE ANALYSIS
The nonvolatile organics comprise those
materials associated with the condensed tars
and waters as isolated by in-line traps. These
substances are exceedingly complex3 and re-
quire fractionation before direct analysis can be
undertaken. Other investigators have utilized
either of two procedures for this process, col-
umn chromatography or solvent partition.
Chromatographic methods separate the crude
material into fractions of like polarity and can
function as a useful means of reducing a com-
plex sample into one or more manageable pro-
portions.4 Solvent partition schemes have been
devised, most notably by researchers from the
tobacco industry6, in which group separations
are accomplished on the basis of similar
chemical properties, e.g., acids, bases, etc.
284
-------
CII,C]2 Solution ut Mr
«i:l» 1M NaOll
CIUC1., layer--
Washed 2X with
H-0
X.ir-t Jjyor
Washed with CH,C1,
1
CiUCJ,,
layer
\
Nai'H layer
Adjust to pH 2 with
i:« HCl. Extract with
C!I,CJ,
1,012 layer--•
'.-.'ashed with
0.2M 1101
H,0 layer | Oru.iui. .Vi>lr.|
'.v'ushcJ '.-i:h cyclolioxane
Ai)
Cyclohexane layer 11,0 layer
(1) Evaporated to
dryp.uss
(2) Dissolved in r,
CH,C1,
Adjust to ptl 2 ui:Ii IN tiCl.
Extract 3X with CII,C1,
I
CfUCl, layer -
[Orranic Ac ills)
AQ
Washed 2X with H20
lid layer
Washed with CH,C1,
CH,C1, layer
IIC1 layer
Adjust to p>l I2'uitli IN Na
Extract IX vi:li CII,C1 ,
Cyclohexani!
InsoJuhlcs
Cl
Cil
,C17 layer---- lljO layer (pli=5)
Evaporated to Wjshed 5X vie
(Irvnitee _. , .. _ .....
2CJ, Extract U--CH2C1, layer
(1) Arid o,l
cyclohexane
(2) W.ishud 3X
with 4:]
h CllnCl,
11,0 layer
Adjust to |«ll 12 with 1M N.iOH
Extract 3X with CH7C12
| |
CI!, OH/11,0 fii>r;MnLO Bases | AQ
I
Cycluluixanc lavx-r
(1) Cimr.encratu
(2) Wished 6X with
CII2OII/1I,0 layer
Unshed iX with cyclohexane
Cyclohexauc layer
1
CM ;:D
.
Lye lolit'xjne layer
Evaporatod to drynuss
[i'AII'sl • ff.'on-l'plar Heiitra'La
layer
i.
frvur.o dried
Evaporated to dryness IPnl.ir Noutr.ils]
Figure 2. Tar sample partition scheme.
285
-------
The latter approach seems more practical, par-
ticularly if fractions are to be derivatized or
chromatographed further. The basic procedure
adapted for use in our laboratories is depicted
in Figure 2, and is a modification of a method
utilized by Novotny6 for air particulate extracts.
Application of the scheme to three different
gasifier coal tars produced the product distribu-
tion shown in Table 1. That the scheme pro-
vides generally good reproducibility was
demonstrated by application of the process to
identical aliquots from the same tar samples.
With the sample thus divided into chemically
similar groups, derivatization and chromat-
ographic techniques are applied as dictated by
class properties or complexity of individual
fractions. Thus the organic acid fraction is
treated with diazomethane and dimethyl
sulphate to convert carboxylic acids to esters
9nd aromatic hydroxyls to methyl ethers. The
compounds are then sufficiently volatile for gc
analysis.
The remaining fractions are in most cases not
amenable to direct gc analysis either because
of the large number of components present or
because of the presence of nonvolatile
materials. Liquid chromatographic techniques
are indicated here, especially hplc. This tech-
nique embraces virtually all forms of liquid
chromatography, i.e., adsorption partition, ion-
exchange and gel permeation, and is desirable
chiefly because of the relatively high efficien-
cies obtainable with currently manufactured
hplc columns. Although reverse-phase modes
of chromatography have been shown to be
TABLE 1
CLASS DISTRIBUTION OF COAL TAR SAMPLES
AFTER SOLVENT PARTITION (WGT. %)
Sample
H-1
B-1
B-2
Acids
Bases
Cyclohexane Insolubles
Polar Neutrals
Non-Polar Neutrals
PNA Hydrocarbons
14.2
1.3
13.6
12.1
3.2
18.2
3.4
41.9
13.5
5.6
7.5
22.8
2.7
1.5
4.4
8.6
20.1
38.9
very useful with regard to the separation of cer-
tain types of environmentally important com-
pounds, the use of aqueous solvents is general-
ly undesirable if the sample is to be recovered
for further work. Consequently, we have ex-
plored primarily the use of adsorption and gel
permeation modes as a means of further frac-
tionating the partitioned samples.
Silica gel columns provide separation of the
components of a given fraction based on the
relative polarities of the individual compounds.
Columns can be easily tailored for specific use
by varying the column dimensions, the nature
(and hence activity) of the silica packing, and
the diameter of the particles used. Thus to ef-
fect a rapid clean-up of the PNA fraction (Figure
2), a large particle (37-75 micron) column of
modest efficiency is sufficient for effecting the
separation of PNA compounds, as a group,
from more polar, non-PNA materials. This
chromatographic step enriches the PNA frac-
tion by removing approximately 1 /3 of the total
mass associated with the fraction. This greatly
reduces problems relating to the analysis of the
PNA's themselves. A sample of this enriched
fraction was analyzed at this point by gc-ms.
The ion plot is shown in Figure 3. Although
many individual PNA compounds were iden-
tified from the mass spectra generated from
this run, a better resolved chromatogram is
desirable particularly from a standpoint of
quantitation.
Further separations can be accomplished by
injection of the enriched fraction onto a high ef-
ficiency (10,000-15,000 plates/meter), silica
column, and collecting individual cuts for gc-
ms analysis. The results of this hplc run are
shown in Figure 4. Detection of eluting com-
ponents was accomplished by monitoring uv
absorbance (254 nm). The gc-ms analysis of
the collected and concentrated cuts is not yet
available. Although silica gel columns were
used here and can in all probability be applied to
other fractions, other materials such as alumina
or bonded phase columns may also prove effec-
tive.
Another chromatographic procedure can be
utilized to simplify the complex fractions as ob-
tained from the partition scheme. Gel permea-
tion has been used by many workers6 7 and has
in the past been characterized by low efficien-
286
-------
z
ID
I-
2
2
O
30,000
20,000
10.000
0
I 1~ T i r -™ • ~^ i =•—i 1 1 1 1 1 1 (
7,000 7.050 7.100 7,150 7,200 7,250 7,300 7,350 7,400 7,450 7,500 7.550 7,600 7,650 8,000
SPECTRUM NUMBER
Figure 3. Ion plot of PNA enriched fraction. OV-101 capillary.
-------
to
to
CO
\ .J " — - v '
1 _A — -S"
\
5
i i < i I
10 15 2Q 25 30
TIME (MIN.)
iliii
35 40 45 5G 55
Figure 4. Hplc (silica) of PNA fraction.
-------
cies and long run times. Recent developments
in column technology now bring the advan-
tages of hplc to this mode of chromatography.
Thus fractions from the partition scheme can
be subjected to gpc directly with compound
separations made on the basis of molecular
size. Since in a given chemical class molecular
size correlates well with volatility, some infor-
mation pertinent to subsequent gc-ms or ms
analysis can be obtained from the
chromatography. When the PNA fraction was
chromatographed on a single gpc column.
(/iStyragel® - 100A pore size), the chro-
matogram depicted in Figure 5 was obtained.
The large number of components and the con-
tinuum of molecular sizes combined to produce
only a single undefined major peak, however ar-
bitrary cuts of the column effluent will un-
doubtedly provide greatly simplified samples
for subsequent analysis.
The coal gasification process produces by-
product water in sizeable quantities and, since
this water can be used as recycle cooling
water, methods for its purification are being ex-
ABSORBANCE (280 nm)
m
O> -
00 -
(0 -
Figure 5. Gpc (/xStyragel) of PNA enriched fraction.
289
-------
30,000 -,
20.000 -
to in
8 z
111
10,000
0
9,000
T 1—
9,050 9.100
n 1 1 1 1 1 1
9,150 9.200 9,250 9,300
SPECTRUM NUMBER
9,350 9.400 9.450 9.500
Figure 6. Ion plot of condensed water extract following derivatization Carbowax capillary.
-------
plored. This involves a detailed knowledge of
the contaminants which can comprise from
0.6-2.4 percent (by weight) of the condensate.
This extractable material appears to be largely
phenolic.3 Thus after solvent extraction
(methylene chloride) of a portion of the col-
lected waters, the residue is subjected to treat-
ment with diazomethane and dimethyl sulphate
which converts the phenolic materials to
aromatic methyl ethers. These compounds are
amenable to high resolution gc-ms analysis,
and can be thus analyzed without further proc-
essing. Treatment of a sample of condensate
waters in our laboratories by the method
described resulted in the TIC plot shown in
Figure 6. Cursory examination of selected mass
plots identified several aromatic alcohols in-
cluding seven alkylated isomers of phenol.
Other types of materials such as alkyl and
aromatic ketones, carboxylic acids, and
nitrogen-containing aromatics (1-2 ring) were
also identified. Future runs will employ gc col-
umns of increased resolution and selectivity.
The methodology for the condensate waters
appears adequate at this point for the tasks of
identifying the contaminants of byproduct
waters.
CONCLUSIONS
Although optimization of the methodological
schemes presented above has yet to be final-
ized, the basic procedures have been shown to
be practical and can be summarized as follows.
Volatiles: Methodology consists of collection
of volatile components on polymer sorbents,
transfer to high resolution gc-ms-comp
systems for identification, and quantitation.
Nonvolatiles-Tars: Methodology consists of
separating tars into groups of chemically
similar materials by solvent partition. Organic
acids are derivatized then analyzed by gc-ms.
Other groups are further fractionated by hplc
using either gpc or partition chromatography,
Collected subfractions are then analyzed by gc-
ms or ms.
Nonvolatiles-Waters: Methodology consists
of derivatization of extracted material followec
by gc/ms analysis.
Much work remains before the approaches
detailed here can be considered as complete
and final. This is particularly true of the ta
samples. Specific problems requiring additiona
fundamental research efforts include the stud\
of materials that are too thermally labile or toe
nonvolatile for gc-ms analysis, and the problen
of quantitation of individual components. Botl
of these topics will be the subject of futur
work relating to the analysis of environmental!
important materials produced during coe
gasification.
1
REFERENCES
Pellizzari, E. D., Carpenter, B. H., Bu
ch, J. E., Sawicki, E., Environ. S<
Tech., 9, 556 (1975).
2. Aldermaston Eight Peak Index of Ma
Spectra, Vol. I (Tables 1 and 2), Vol.
(Table 3). Mass Spectrometry Da
Centre: AWRE, Aldermaston, Readin
UK, 1970.
3. Sharkey, A. G. Carcinogenesis, Vol.
Polynuclear Aromatic Hydrocarbon
Chemistry, Metabolism and Cc
cinogenesis, edited by R. I. Freudentr
and P. W. Jones, Raven Press, N
1976.
4. Schiller, J. E. and Mathiason, D. I
Anal.Chem., 49, 1225 (1977).
5. Snook, M. E., Chamberlain, W.
Severson, R. F. and Chortyk, 0.
Anal. Chem., 47, 1155 (1975).
6. Novotny, M., Lee, M. L, Bartle, K. I
J. Chrom. Sci., 12, 606 (1974).
7. Stedman, R. L., Miller, R. L., Lakritz,
and Chamberlain, W. J., Chem. and
d., March, 1968, pg. 394.
291
-------
A COMPARISON OF TRACE
ELEMENT ANALYSES OF
NORTH DAKOTA LIGNITE
LABORATORY ASH WITH LURGI
GASIFIER ASH AND THEIR USE
IN ENVIRONMENTAL ANALYSES
Mason H. Somerville
James L. Elder &-:-
Engineering Experiment Station
University of North Dakota
Grand Forks, North Dakota
Abstract
A series of analyses of laboratory prepared
ashes of Dunn County, North Dakota, lignite
are compared with analyses of Mercer County,
North Dakota, lignite gasifier ash from SASOL
gasification test for 73 elements. The analyses
demonstrate that a need for laboratory ashing
technique that simulates gasifier ash probably
exists. Of the 73 elements, 33 were found to
be common to the leachate of both the gasifier
and laboratory ash samples; nine of the 33
were more teachable in the gasifier ash. Ap-
proximately 50 of the 73 elements are found in
both coals while approximately 20 elements
were below the detection limit of 0.1 ppm in
both coals.
The use of this data for environmental
assessment of groundwater impact is analyzed.
It is concluded that this data probably cannot
be used to support existing analytical ground-
water models due to system complexities and
unknowns. An alternative worst case en-
vironmental analysis is presented. It is recom-
mended that worst case analyses be pursued
rather than sophisticated analytical modeling
techniques.
INTRODUCTION
The continuing energy problem is gradually
forcing the major investors and Industries of
the United States to turn to coal conversion
technologies for the development of sources of
supply of liquid and gaseous fossil fuels and
feedstocks. Although the time scale and extent
of this development are unknown, it is likely in
the author's view, that several coal conversion
facilities will be operable by the end of the cen-
tury. These facilities will probably include major
250 MMSCFD dry ash Lurgi gasification
facilities.
Presently, plans for four such facilities are at
the detailed design stage. These facilities are El
Paso Gasification Company, Wesco Coal
Gasification Company, ANG Coal Gasification
Company, and Natural Gas Pipeline Company
of America. El Paso and Wesco are located in
New Mexico while ANG and Natural are located
North Dakota. All four have filed Environmental
Assessment Reports. The Department of the
Interior (DOI) has issued final Environmental
Impact Statements for El Paso and Wesco. DOI
has issued a draft Environmental Impact State-
ment for ANG. Natural has issued only an En-
vironmental Assesment Report. All of the com-
panies have studied, to varying degrees, the
environmental impacts associated with
disposal of the gasifier ash and its entrained
water. This paper addresses one of those im-
pacts.
The work reported here deals with the possi-
ble leaching of the trace elements from dis-
posed gasifier ash. Although it may be possible
to mitigate this potential impact to within ac-
ceptable limits through the use of disposal
techniques, it is difficult, if not impossible, to
conclusively demonstrate that the disposed ash
and sludges will behave in a given manner once
actually disposed of in the mined area. This is
true, In spite of the current mathematical
models that exist, largely because of widely
varying boundary conditions and the very com-
plex chemical systems that may exist in the
post-mining environment.
Because of these difficulties it is probably ad-
visable to attack the question of potential en-
vironmental imact utilizing a worst case ap-
proach. This approach does not address the
question of actual impact, but does allow one
to estimate the maximum impact that can
reasonably be expected.
The fate of trace and major constituents dur-
ing gasification has been addressed by Somer-
ville, etal. (1977)1, (1976>2, and by Attari, et
al. (1976)3, (1973)4. At the conclusion of the
work cited above, the authors noted that the
analyses of the laboratory prepared ashes and
its leachates were considerably different than
those of the Lurgi generated ashes and its
leachates.
Data are presented below which specifically
292
-------
compare laboratory and actual gasifier ash and
their leachates.
It should be pointed out that the data col-
lected were for the purpose of supporting two
different Environmental Assessment Reports
which at the time of the data collection were
unrelated. Consequently, the authors did not
have the opportunity to gather all the control
data that are desirable.
OBJECTIVES
The study, under which this data was
generated, was made to assess the en-
vironmental impact associated with a 250
MMSCFD Lurgi dry ash coal gasification facility
utilizing Dunn County, North Dakota lignite.
This paper assesses the applicability and use of
laboratory ashing techniques to determine the
probable trace element emissions from a coal
gasification facility.
METHODS
General
Two different lignites, Mercer County and
Dunn County, North Dakota, were analyzed for
major and minor elemental constituents. The
Mercer lignite sample was obtained from the
coal gasified as part of an operational test at
Sasolburg, South Africa (SASOL). The Dunn
County samples were obtained by coring as
part of a resource evaluation program. Dunn
County and Mercer County, North Dakota are
approximately 45 miles apart; both are in the
Fort Union Coal Reserve (e.g., the same
geological strata).
The Mercer County lignite ash samples uti-
ized were obtained during the SASOL test. The
Dunn County lignite samples were ashed and
the ash analyzed using ASTM D2795-69,
"Mineral Analysis of Coal and Coke Ash".
Leachate tests were performed on both ash
samples.
The Sasolburg Test
The chemical analyses of the Mercer County
lignite reported were taken from samples ob-
tained when 12,000 tons were gasified in the
Lurgi gasifier at Sasolburg, South Africa in
1974 by Michigan-Wisconsin Gas Pipeline
Company. Samples of the lignite charged to the
gasifier, and the ash from the gasifier were ob-
tained.
The coal feed rate during each test was ap-
proximately 26 tons/hr with a mass balance
test lasting for about 8 hours. The following
sample collection intervals were used: hourly
for the coal, and each dump for the gasifier ash.
Analytical Procedures
The sample analyses were performed using
the following techniques: spark source mass
spectrometry (SSMS), atomic absorption (AA),
flameless atomic absorption (FAA), ion-
selective electrode methods (IE), colorimetric
(C), standard mineral analysis (MA), and
several wet chemical methods (WC). The
details of the procedures and methods used are
described in Appendix A. All raw data obtained
from the tests and referenced in this paper may
be found in Somerville et al. (1 976).'
Leaching Study
Since it was suspected that many of the
elements found in coal would probably be re-
tained in the gasifier ash and plans called for
the disposal of the ash in the mined area, an ex-
periment was designed to study the leaching
characteristics of the ash (both laboratory and
SASOL). The methods selected purposefully at-
tempted to maximize the quantity of the ele-
ment leached in an attempt to predict the upper
bound of the impact. The general method con-
sisted of grinding the ash to a fine powder, and
refluxing a sample for 16 to 24 hours at the
boiling point of demineralized water. This is
thought to yield the worst case (maximum
leachate concentration) because:
1. Refluxing subjects the ash to far more
water than the annual rainfall ever
would. It may take many years before
moisture ever reaches the buried ash.
2. The use of distilled-demineralized
water subjects the ash to harsher
leaching conditions than the actual
groundwater (which is basic) is ex-
pected to.
3. The refluxing of the leachate at the boil-
ing point of water greatly increases the
solubility of the elements in the sol-
vent. Groundwater temperatures are
considerably lower than this.
4. The procedure used small particle size
293
-------
samples, which increases the solubility
rather than the ash of much larger parti-
cle size resulting from operation.
Table A-1 of Appendix A lists the element
and analytical method used for determination
of the concentration of that element in the par-
ticular sample. The following abbreviations
were used to identify the type of analysis:
SSMS - spark source mass spectrometry
AA - atomic absorption
FAA flameless atomic absorption with
double gold amalgamation
C - colorimetric
IE - USGS method specific ion electrode
MA - ASTM-2795-69 - mineral analysis
U - ultimate analysis
G - gravimetric
NR - not reported, if present
<0.1 ppm wt gasifier ash
< 0.001 /xg/ml gasifier ash leach
The leaching procedure which was used con-
sisted of the following steps:
1. The samples were crushed to 60 mesh
and the 10 g of material being exam-
ined were weighed. Coal samples were
weighed air dry and ash samples were
weighed dry. 50 ml of deionized water
was added.
2. The above mixture was refluxed for 1 6
to 24 h at the boiling point of water.
The solution was filtered and/or
decanted until clear and the laboratory
examination performed on the clear
solution.
3. The liquid to solid ratio (5 to 1) was
maintained if a larger quantity was
used for leaching.
RESULTS AND DISCUSSION
Elemental Analyses were run on the follow-
ing samples:
*Mercer County lignite and its ash from the
SASOL gasification test. (See Table 1}
* Mercer County lignite ash leachate from the
SASOL gasification test ash. (See Table 2)
Dunn County lignite and its laboratory ash for
two coal samples: 441 1 and 441 3. (See Table
2)
Since gasifier ash using Dunn County lignite
was not available for leaching tests, laboratory
ash was used in its place. Analyses were per-
formed, on each of the samples identified
above. The results of those analyses are
presented in Tables 1 and 2.
The data of Table 2 can be reduced by
calculating the percent leachable which Is
determined with the following formula:
% leachable = (CL * 5/CA) * 100
where
CL = concentration of element in the
leachate, /ig/ml
CA = concentration of the element in the
ash, ppm
5 = ratio of water leach base to material
weight
Table 3 presents the leachable percentages
for each of the 73 elements and also reports
the ratio of Mercer gasification ash percentage
leachable to Dunn's laboratory ash percent
leachable.
Tables 4 and 5 present the upper bounds for
the estimated effluent rates from a proposed
gasification facility (Somerville et al <1976)2>
and the maximum leachate rates that can be
expected. Table 4 presents the elements found
to be more soluble from gasifier ash, Table 5,
elements more soluble from the laboratory
prepared ash. Table 6 presents the ratio of the
elements for the two lignites, their ashes and
ash leachates. Table 7 examines the similarity
of element concentrations between the
lignites, their ashes and ash leachates by re-
porting the cumulative probability of occur-
rence as a function of ratio range.
A visual examination of the element concen-
trations of Table 1 for the Dunn and Mercer
lignites reveals that they are similar. This obser-
vation is also supported by our experience with
Fort Union Lignites which indicates that they
are generally similar (Sondreal et al. (1968)5).
It is not obvious that the ash element conceh*
trations reported in Table 1 are similar.. This
may be due to the different environment that
Mercer ash experienced during gasification as
opposed to laboratory ashing environment. The
difference becomes even more pronounced in
the ash leachate data reported in Table 2. This
difference is further amplified when the per-
centage of the element that is leachable is
calculated and the ratio of the Mercer to Dunn
percentage leachable is calculated. These
294
-------
TABLE 1
COMPARISON OF TRACE ELEMENT AND MAJOR CONSTITUENTS IN MERCER COUNTY
AND DUNN COUNTY NORTH DAKOTA LIGNITE AND THEIR ASHES, ppm
Element
Ag
Al
As
Au
B
Ba
Be
Bi
Br
Ca
Cd
Ce
Cl
Co
Cr
Cs
Cu
Dy
Er
Eu
F
Fe
Ga
Gd
Ge
Hf
Hg
Ho
I
Ir
Dry
Mercer Co.
5,666°
8
56
616f
0.27
<0.1
0.27
16,225°
34.6
26.7
1.2
5.3
4
10.6
0.67
<0.1
0.4
29. 39
7,936°
5.3
0.8
0.27
T.21
0.4
0.13
<0.1
Coal3
4411
11
135
113
0.
1.
24
92
10.
490
1.
73
,b
Dunn Cq
4413
9
39
81
8 0.3
5 0.75
15f <0.15
11
39
7 4.5
7.5
1 ' <0.15
17
0.3 0.3
259 249
8
<0.
3
0.
0.
3
1 <0.1
0.9
141 0.11
15 0.3
Avg./12
Samples
6,697d'6
10.13
62.95
229.82
0.31
<0.1
1.71
16,108d'S
f 0.21f
14.06
46.62
4.98
65.26
0.26
22.92
-------
TABLE 1 (Continued)
Element
Dry Coala'b
Mercer Co.
Dunn Co.
Ashb
Mercer Co.
4411 4413 Avg./12
Samples
K
La
Li
Lu
Mg
Mn
Mo
Na
Mb
Nd
Ni
OS
P
Pb
Pd
Pr
Pt
Rb
Re
Rh
Ru
S
Sb
Sc
Se
Si
Sm
Sn
Sr
Ta
268°
16
0.67
<0.1
3,877°
70.7
4
6,994°
4
2.7
6.7
<0.1
236°
2.7
<0.1
1.3
<0.1
6.7
<0.1
<0. i
-------
TABLE 1 (Continued)
Element
Tb
Te
Th
Ti
Tl
Tm
U
V
w
Y
Yb
Zn
Zr
Dry
Mercer Co.
0.67
0.27
4
193°
<0.1
<0.1
4
21.3
<0.1
13.3
<0.1
6.7
85.3
Coal
4411
<0.
9
6
61
3
54
23
184
a,b
Dunn Co.
4413
1 <0.1
1.5
1.5
14
0.6
42
23
68
Avg./12
Samples
0.15
<0.1
3.64
301d'e
<0.1
<0.1
3.15
21.93
0.58
23.11
<0.1
10.87
68.42
Ash
Mercer Co.
3
-------
TABLE 2
ASH AND ASH LEACHATE ANALYSES,
MERCER COUNTY LIGNITE AND DUNN COUNTY LIGNITE
Mercer County
Dunn County Lignite
jj.ignite
SASOL Gasification
Test
Element
\g, silver
M , aluminum
As , arsenic
Au, gold
B, boron
Ba, barium
Be, beryllium
Bi, bismuth
Br, bromine
Ca, calcium
Cd , cadmium
Ce , cerium
Cl , chlorine
Co , cobalt
Cr, chromium
Cs, cesium
Cu, copper
Dy, dysprosium
Er , erbium
Eu, europium
F, fluorine
Fe, iron
Ga, gallium
Gd, gadolinium
Ge, germanium
Hf, hafnium
Hg, mercury
Ho, holmium
I, iodine
Ir, iridium
K, potassium
Ash
(PPM)
<1
63,400
74
1,680
8,270
6
3
181,600*
0.7
190
67
13
140
9
27
8
4
4
78,800a
53
5
2
4
5
2
4,600a
Leachate
(Ug/ml)
230
3
36.6
0.01
0.3
19
38
0.02
0.07
0.02
0.05
0.3
1
0.005
0.2
110
4411 Lab Ash
(ppra)
<0.3
94,000
36
380
3,800
0.3
0.3
0.3
236,000
<1
37
15
6
35
0.9
18
2
0.5
0.5
220
MC*
12
0.9
4
0.9
0.02
0.6
11,200
298
Leachate
(ug/ml
8
0.02
13.5
<1
0.01
380
<0.01
0.007
2
<0.009
0.2
0.06
0.2
<1.5
0.5
0.02
0.004
0.002
414
4413 Lab Ash
(ppm)
<0.3
110,000
30
450
10,200
0.5
0.3
0.6
300,000
<1
85
62
6
17
0.4
27
3
1
0.8
250
MCb
0.5
2
7
0.9
0.04
0.9
8,200
Leachate
(ug/ml)
130
0.07
12.5
<1
0.01
95
<0.01
3
£0.03
0.2
0.04
0.4
2.8
1
0.5
<0.03
0.003
393
-------
TABLE 2 (Continued)
Mercer County
Dunn County Lignite
jjignxw
3
SASOL Gasification
Element
La, lanthanum
Li, lithium
Lu, lutetium
Mg, magnesium
Mn, manganese
Mo, molybdenum
Na, sodium
Nb, niobium
Nd, neodymium
Hi, nickel
Os , osmium
P, phosphorous
Pb, lead
Pd, palladium
Pr, praseodymium
Pt, platinum
Rb, rubidium
Re, rhenium
Rh, rhodium
Ru, ruthenium
S, sulfur
Sb, antimony
Sc, scandium
Se, selenium
Si, silicon
SKI, samarium
Sn, tin
Sr, strontium
Ta, tantallum
Tb, terbium
Te, tellurium
Test
Ash
(ppm)
74
45
Leachate
(pg/ml)
0.002
0.5
42,100a
760
12
58,604a
37
18
25
3,500a
58
8
35
12,600a
4
33
0.
118,100a
7
4
12,900
<0.
3
<0.
0.2
0.006
1
7,100
0.009
0.9
0.007
1
1,205
0.01
<0.003
5 0.02
900
0.003
0.09
2
3
4411 Lab Ash
(ppm)
16
8
0.1
MC15
MC
6
114,000
10
3
30
MCb
32
2
17
29,300
1
16
0.2
138,000
2
2
40,000
-------
TABLE 2 (Continued)
Element
Th, thorium
Ti, titanium
Tl, thallium
Tin, thulium
U, uranium
V, vanadium
W, tungsten
Y, yttrium
Yb, ytterbium
Zn, zinc
Zr, zirconium
Mercer County
Lignite
SASOL Gasification
Test
Dunn County Lignite
Ash
(ppm)
45
3,420a
5
0.5
7
150
2
320
4
10
520
Leachate
(yg/ml)
0.1
8
0.04
<0.02
0.02
4411 Lab Ash
(ppm)
8
610
0.2
7
28
0.9
34
1
70
100
Leachate
(yg/ml)
0.3
0.3
0.03
0.1
0.3
4413 Lab Ash
(ppm)
31
MC*
0.2
8
20
0.8
48
2
30
94
Leachate
(wa/ml)
0.4
0.2
0.05
0.4
Method of Analysis ASTM D2795-69, Mineral Analysis of Coal and Coke Ash, Part 19, 1974.
Analyses not performed on these ashes. Composite of lower beds 3, 4, 5, and 6 is avail-
able and gives: iron, 64834 ppm; titanium, 2704 ppm; magnesium, 45274 ppm; and
phosphorous, 1177 ppm.
300
-------
TABLE 3
PERCENT OF ELEMENT LEACHABLE FROM MERCER COUNTY
GASIFIER ASH AND DUNN COUNTY LIGNITE LABORATORY ASH
Element
Ag, silver
Al, aluminum
As, arsenic
Au, gold
B, boron
Ba, barium
Be, beryllium
Bi, bismuth
Br, bromine
Ca, calcium
Cd, cadmium
Ce, cerium
Cl, chlorine
Co, cobalt
Cr, chromium
Cs,. cesium
Cu, copper
Dy, dyspros ium
Er, erbium
Eu, europium
F, fluorine
Fe, iron
Ga, gallium
Gd, gadolinium
Ge, germanium
Hf, hafnium
Hg, mercury
Ho, holmium
I, iodine
Ir, iridium
K, potassium
La, lanthanum
Mercer County
1.3
0.91
50
12
Dunn County
SASOL Ash
% Leachable
0.5
1.8
20.3
10.9
0.0006
50
0.05
283a
0.77
0.25
1.1
0.93
Lab Ash
% Leachable
(Avg. of 4411, 4413)
0.32
0.74
15.9
<0.09
13
0.49
<5
0.09
46
1.6
4.4
42
7
Ratio
Mercer/Dunn
5.63
27.43
0.69
>0.01
3.85
.102
0.48
0.06
0.03
0.13
10.2
0.002
9.4
4.5
<0.4
5.4
2.27
>0.01
1.74
4.4
21.3
0.19
>1
0.21
0.56
301
-------
TABLE 3 (Continued)
Li, lithium
Lu, lutetium
Mg, magnesium
Mn, manganese
Mo, molybdenum
Na, sodium
Nb, niobiun
Nd, neodymium
Ni, nickel
Os, osmium
P, phosphorous
Pb, lead
Pd, palladium
Pr, praseodymium
Pt, platinum
Rb, rubidium
Re, rhenium
Rh, rhodium
Ru, ruthenium
S, sulfur
Sb, antimony
Sc, scandium
Se, selenium
Si, silicon
Sm, samarium
Sn, tin
Sr, strontium
Ta, tantallum
Tb, terbium
Te, tellurium
Th, thorium
Ti, titanium
Mercer County
SASOL Ash
% Leachable
0.02
0.002
0.004
41.7
60.6
0.18
0.13
0.06
14.3
47.8
1.3
0.05
20
3.8
0.4
0.003
Dunn County
Lab Ash
% Leachable
(Avg% of 4411, 4413)
11
<0.25
92
37.1
1.4
<0.5
0.31
.75
59
84
<0.66
<34
<0.02
0.71
0.002
>0.02
0.45
1.63
0.13
>0.26
0.19
0.24
0.57
>0.08
>0.59
>190
0.004
0.01
<2.3
>0.004
302
-------
TABLE 3 (Continued)
Element
Tl, .thallium
Tm, thulium
\}f uranium
V, vanadium
W, tungsten
V, yttrium
Yb, ytterbium
Zn, zinc
Zr, zirconium
Mercer County
SASOL Ash
% Leachable
26.7
10
0.03
Dunn County
Lab Ash
% Leachable
(Avg> of 4411, 4413)
Ratio
Mercer/Du
5.2
24
3.7
1.5
5.13
0.42
0.27
Irrational number, unexplained error.
303
-------
TABLE 4
ESTIMATED MAXIMUM SOLUTION RATES FOR
ELEMENTS MORE SOLUBLE FROM GASIFIER ASH8
Ratio of
to
Mercer/Dunn
Ash Leachate
Rates
Dunn Co.
Estimated
Effluent
(Ibs/day)
aluminum
arsenic
bromine
fluorine
gallium
germanium
silicon
sodium
vanadium
5.63
27.43
3.85
2.27
1.74
>1.0
>190
1.63
5.13
243,600
339
61
513
168
22
393,200
86,000
800
Laboratory
Dunn County Ash,
% Leachable
0.32
0.74
13
4.5
5.4
£1.3
<-02
37.1
5.2
Estimated
Maximum
Leachate Rate
(Ibs/day)
780
2.5
7.9
23.1
9.1
<0.3.
78.6
31,906
41.6
Mercer County coal processed at Sasolburg, South Africe.
Based upon Somerville, et al (1976) . Data is for a 250 MMSCFD Dry Ash Lurgi
Gasification Plant.
304
-------
TABLE 5
ESTIMATED MAXIMUM SOLUTION RATES FOR
ELEMENTS MORE LEACHABLE FROM LABORATORY PREPARED ASH"
Element
boron
barium
calcium
cobalt
chromium
cesium
copper
iron
mercury
potassium
lithium
manganese
molybdenum
nickel
phosphorous
lead
rubidium
sulfur
scandium
selenium
strontium
titanium
tungsten
zinc
Ratio of
Mercer to
Dunn Ash
Leachate
0.69
>0.01
.102
0.48
0.06
0.03
0.13
>0.01
0.21
0.56
0.002
>0.02
0.45
0.13
>0.26
0.19
0.24
0.57
>0.08
>0.59
0.004
>0.004
0.42
0.27
Dunn Co.
Estimated
Effluent
(Ibs/day)
2,303.5
8,188.7
588,800
178.19
2,349.5
9.48
789.7
236,250.5
0.10
16,650.2
45.29
9,098.6
691.9
397.1
4,658.4
177.01
147.62
56,048.9
288.18
4.32
37,815.9
9,827.4
21.37
299.3
%
Leachable
15.9
<0.09
0.49
1.6
4.4
42
7
<0.4
4.4
21.3
11
<0.25
92
1.4
<0.5
0.31
59
84
<0.66
<34
0.71
<2.3
24
3.7
Estimated
Maximum
Leachate Rate1*
(Ibs/day)
366.3
7.4
2,885
2.9
103.4
4.0
55.3
<1, 053.0
0.0
3,546.5
5.0
£22.75
636.5
5.6
<23.3
0.5
87.1
47,081.1
<1.9
<1.5
268.5
<226.0
5.1
11.1
Dunn County Coal, samples 4411 and 4413, processed in the laboratory.
Based upon Somerville et al (1976). Data is for a 250 MMSCFD Dry Ash Lurgi Gasification
Plant.
305
-------
TABLE 6
RATIO OF ELEMENT CONCENTRATION IN MERCER COUNTY
LIGNITE, ASH AND ASH LEACHATE TO THOSE OF DUNN COUNTY
Element
Ag, silver
Al, aluminum
As, arsenic
Au, gold
B, boron
Ba, barium
Be, beryllium
Bi, bismuth
Br, Bromine
Ca, calcium
Cd, cadmium
Ce, cerium
Cl, chlorine
Co, cobalt
Cr, . hromium
Cs, cesium
Cu, copper
Dy, dysprosium
Er, erbium
Eu, europium
F, fluorine
Fe, iron
Ga, gallium
Gd, gadolinium
Ge, germanium
Hf, hafnium
Hg, mercury
Ho, holmium
I, iodine
Ir, iridium
K, potassium
La, lanthanum
Li, lithium
Lu, lutetium
Mg, magnesium
Lignite
i.oob'c
0.85°
0.80
i.ooc
0.64
6.35
0.49
1.00°
0.24
i.oic
6.67
1.98
0.41
0.16
0.02
6.40
0.24
6.70°
i.ooc
1.33
1.20
1.10°
0.96
8.00
0.14
1.00 °
1.60
4.00
0.58
1.00 °
c
0.58
3.05
0.18
c
1.00
c
0.77
Ash"
3.00
0.62
2.24
N
4.05
1.18
15.00
N
6.66
0.68
0.50
3.11
1.74
2.17
5.38
13.85
1.20
3.20
5.33
6.15
0.81
N
8.48
3.45
0.36
4.44
1.83
6.67
N
N
0.47
2.96
3.21
3.33
N
Ash Leachate
N
5.63
27.43
N
0.69
>0.01
N
N
3.85
.102
N
N
N
0.48
0.06
0.03
0.13
N
N
N
2.27
>0.01
1.74
N
>1.00
N
0.21
N
N
N
0.56
N
0.002
N
N
306
-------
Element
Mn, manganese
Mo, molybdenum
Na, sodium
Nb, niobium
Nd, neodymium
Ni, nickel
Os, osmium
P, phosphorous
Pb, lead
Pd, palladium
Pr, praseodymium
Pt, platinum
Rb, rubidium
Re, rhenium
Rh, rhodium
Ru, ruthenium
S, sulfur
Sb, antimony
Sc, scandium
Se, selenium
Si, silicon
Sm, samarium
Sn, tin
Sr, strontium
Ta, tantallum
Tb, terbium
Te, tellurium
Th, thorium
Ti, titanium
Tl, thallium
Tm, thulium
U, uranium
V, vanadium
W, tungsten
Y, yttrium
Yb, ytterbium
TABLE 6
Liqnitea
0.34
0.08
c
2.92
0.64
3.38
0.29
c
1.00
c
1.80
0.57
c
1.00
1.30
c
1.00
0.99
c
1.00
c
1.00
c
1.00
c
0.92
0.40
0.80
0.38
c
0.83
2.35
0.03
1.76
N
6.70
c
2.70
0.76
c
0.64
1.00°
1.00°
1.07
0.57
0.06
0.28
1.00°
(Continued)
Ash3
3.62
1.50
0.41
2.74
3.27
1.11
N
N
1.78
N
2.67
N
3.33
N
N
N
0.53
2.67
2.13
0.83
0.89
3.50
0.89
0.39
1.33
3.75
1.50
2.31
5.61
N
2.50
0.93
6.25
2.35
7.80
2.67
Ash Leachate
>0.02
0.45
1.63
N
N
0.13
N
>0.26
0.19
N
N
N
0.24
N
N
N
0.57
N
>0.08
>0.59
>190
N
N
0.004
N
N
N
N
>0.004
N
N
N
5.13
.42
N
N
307
-------
TABLE 6 (Continued)
Element
Zn, zinc
Zr, zirconium
Lignite
0.29
0.68
Ash"
0.20
5.36
Ash Leachate
0.27
N
N,
Not calculable due to missing data.
a
Calculated on the basis of the average of 4411 and 4413 unless otherwise noted.
b
Number calculated on basis of a less than or greater than number. See tables
1 and 3.
c
Calculated on the basis of an average of 12 Samples instead of an average of
4411 and 4413.
TABLE 7
CUMULATIVE PROBABILITY OF COMMON OCCURANCE
OF ELEMENTS, IN MERCER AND DUNN COUNTY LIGNITES
THEIR ASHES AND ASH LEACHATES AS A FUNCTION
OF CONCENTRATION RATIOS
Concentration
Ratio Range
0.5 through 2.0
0.25 through 4.0
0.10 through 10.0
Total samples
Total ratio range
Lignite
Ash
Ash Leachate
Number Qf
Elements
43
57
68.
73
Percent
58.9
78.1
_?3_.A
100.0
Number of1
Elements
17
44
57_
59
Percent
28.8
74.6
96.1
100.0
Number of
Elements
7
14
22.
33
Percent
21.2
42.4
66.7
ioo.o
0.02 through 8.0
0.20 through 15
0.002 through 190
The ratio reported is the ratio of the Mercer County sample concentration in ppm
to the Dunn County samples in ppm. See Table 6 for ratios for individual elements.
308
-------
results, in Table 3, show wide variability with
little similarity between the fraction teachable
from the Mercer gasified ash and Dunn
laboratory ash.
In examining Table 3, two things are ap-
parent, neither of the samples (Dunn nor
Mercer) are dominant in the leach tests and the
variation in the ratio of the Mercer to Dunn per-
cent teachable is large (0.002 to 190). Only
five of the 33 elements common to both
samples fall within plus or minus 50 percent of
one another (ratio of .5 to 1.5). The variability
of the results leads one to postulate, and
perhaps conclude, that laboratory prepared ash
is not representative of gasifier ash. This result
was anticipated by the authors because of the
differences in the previous chemical en-
vironments (particularly temperature) of the
laboratory prepared ash and gasifier ash.
Twenty-four of the 33 elements reported in
Table 3 show that Dunn County lignite
laboratory prepared ash is more leachable than
gasifier ash while nine were less leachable.
Consequently, in the majority of cases (73%)
the maximum solution rate is given by the
laboratory prepared ash. These maximum solu-
tion concentrations and their rates are not to be
confused with the actual field leachate concen-
trations and would be expected to be con-
siderably lower than (1 /10 to 1 /1000 -authors'
judgment) the maximum value reported. Fur-
thermore, as time proceeds the actual leach
rates and concentrations will decline due to in-
creased compaction of the returned overburden
and the progress toward chemical equilibrium
between the ash and infiltrated groundwater.
In spite of the above, an estimate of the max-
imum initial solution rates in pounds per day
has been made. The results of this analysis are
shown in Tables 4 and 5. These data were
generated using Table 3 (columns 1 and 3) and
data from Somerville, et al. (1976)2. The
results of the analysis have been separated into
two tables (4 and 5) to show which elements
were more leachable from the gasifier ash and
which were more leachable from the laboratory
prepared ash. The first table, 4, presents the
results for the gasifier ash; the second, 5, for
the laboratory ash. The results indicate that the
sulfur, sodium, calcium, potassium, and iron
have the highest potential to enter the ground-
water system through the leaching process.
The pH of the ash leachates always indicated a
basic solution compatible with Fort Union
Lignite. All of these elements presently exist in
the groundwater of Dunn County.
The similarity of the two coals can be ex-
amined by forming the ratio of the concentra-
tions for each element in the lignites, their
ashes, and of the percentage leachable in the
ashes. These ratios are reported in Table 6. A
ratio value of unity means that the same con-
centration (dry coal basis) exists in both coals.
Consequently, many ratio values close to unity
imply a basic similarity between the two groups
of samples. Examination of Table 6 shows that
Mercer and Dunn County lignites are quite
similar. This is also borne out by Table 7 which
shows that 59 percent of the elements had a
ratio value that fell between 0.5 and 2.0.
Based upon our experience and others (See
Table 10 of Gluskoter et al. (1 977)6) this level
of variability is typical of coals including
western coals. On the other hand, examination
of the ash and ash leachate columns indicates a
general decrease in similarity. This is particular-
ly true of the ash leachates which show only
67 percent of the elements falling within an
order of magnitude of one another (ratio range
of 0.1 to 10). A similar divergence from the
lignite samples, although not as pronounced,
can also be observed in the ash samples.
Trace Elements and
Environmental Analysis
of Groundwater Impact
There are several reasons, why the above
data are not well suited to environmental
analyses dealing with groundwater impact of
mine disposed solids. Some of the principal
reasons are:
*The chemistry of the element in the coal,
ash, and ash leachate is completely undefined.
*A basic understanding dealing with the
chemistry of trace metal components in the
geochemical setting is missing.
*The physical system setting is immensely
complex; it includes a short term (years), vary-
ing, ill-defined geology, particularly during
post-mining conditions. Further, the geochem-
istry varies with depth and topography and the
surface experiences a random distribution and
water influx (rain).
*The potentially complex chemistry of the
309
-------
ash when combined with other disposed solids
and sludges is not well understood, (e.g., cool-
ing tower blowdown, biotreatment sludges (if
any) and water treatment plant sludges).
*The general lack in terms of both quality
and quantity of the geological field data re-
quired by the sophisticated mathematical
models that possess the potential, although
presently not the capability, to predict post-
mining groundwater chemistry and ground-
water impact.
In spite of the above, the data are somewhat
useful in determining what elements are likely
to not have significant impact from a quantity
view point. Additionally, the analyses can nar-
row considerably the breadth of investigation
required to assess the potential impact.
CONCLUSIONS
The data presented indicate that Mercer and
Dunn County lignite are basically similar in
terms of trace element constituents. Although
not entirely conclusive, the same is not true of
their ashes and ash leachates. Assuming that
their ashes and ash leachates should show the
same basic similarity, one has to conclude that
the processes the two lignites and their ashes
were exposed to are responsible for differences
in elemental constituents. Consequently, it is
probable that the laboratory ashing procedure
(ASTM D 271-68) does not simulate the
gasification process well enough to allow use
of the laboratory data in environmental
analyses.
Further, the quantity and variability of the
data reported, as well as the reasons cited
above, indicate that use of analytical data of
this type in a mathematical model will be dif-
ficult, if not impossible. Use of "worst case"
experimental biological screening analyses may
be the only near term solution to this problem.
It is clear that use of trace element analyses
alone do not address the groundwater impact
question.
RECOMMENDATIONS
The following recommendations are those of
the authors and do not necessarily represent
the position of either the Engineering Experi-
ment Station or the sponsor.
1. Groundwater monitoring wells should be
established in and adjacent to the mine and
waste disposal areas. The wells should be
sampled and samples analyzed for trace and
major inorganic elements and organic com-
pounds.
2. Trace element emissions from a gasifica-
tion facility should not be regulated until their
impact is well understood and adequate and in-
expensive instrumentation is developed.
3. Samples of Mercer County lignite should
be obtained, ashed under ASTM D 271-68 and
leached. Elemental analysis qf the ash and its
leachate should be completed and compared
with the data of this report.
4. A laboratory ashing technique that
simulates the Lurgi dry ash gasification en-
vironment should be developed.
The first recommendation is obvious, and
this would probably be required under existing
laws. The second is justified in the authors.'
view by the following:
*The results of .this study indicate that even
under "worst case" conditions trace element
impact will be minor.
* There have been .only spattered instances
of negative trace element impact in several
decades of successful power plant operation A
gross environmental impact has rvot been
observed.
*The measurement techniques for both trace
element determinations and their impacts- are
still being developed and are expensive and dif-
ficult to complete.
* Monitoring of trace element emissions
(gaseous, solid, or liquid) would be1 very dif-
ficult to carry put on a continuous basis'with
existing equipment.
The third recommendation would complete
the baseline data missing from this paper. The
fourth action is needed to allow prospective
developers to make reasonable assessments of
the potential impact of disposed gasification
ash in the mined area.
ACKNOWLEDGMENTS
The authors express their sincere apprecia-
tion to the sponsor, the Natural Gas Pipeline
Company of America, for the release of the pro-
prietary data and the financial support required
to carry out this study. The sponsof should be
310
-------
recognized for the contribution they have made
to society for supporting this work. The
authors commend the sponsor for this support.
REFERENCES
M. H. Somerville, J. L. Elder, and R. G.
Todd, "Trace Elements: Analysis of Their
Potential Impact From a Coal Gasification
Facility", Engineering Experiment Station,
University of North Dakota, Bulletin
#77-05-EES-01, (1977).
M. H. Somerville, J. L. Elder, R. G. Todd,
A. P. Moran, and R. J. Peterson, "Trace
Elements: Overburden, Plant Effluents,
and Biological Availability", Volume VI of
"An Environmental Assessment of a Pro-
posed 250 MMSCFD Dry Ash Lurgi Coal
Gasification Facility Located in Dunn
County, North Dakota", Engineering Ex-
periment Station, University of North
Dakota, Bulletin #76-1 2-EES-01, (1976).
3. A. Attari, "Fate of Trace Constituents of
Coal During Gasification". EPA
Technology Series, EPA-650/2-73-004,
31 pp (1973).
4. A. Attari, J. Pau, and M. Mensinger,
"Fate of Trace and Minor Constituents of
Coal During Gasification", Environmental
Protection Technology Series, EPA
600/2-76-258, 39 pp, (1976).
5. Everett A. Sondreal, W. R. Kube, James
Elder, Analysis of the Northern Great
Plains Province Lignites and Their Ash: A
Study of Variability, U. S. Dept. of the In-
terior, Bureau of Mines Report of In-
vestigation 71 58, 1968.
6. H. J. Gluskoter, R. R. Ruch, W. G. Miller,
R. A. Ghill, G. B. Dreher, and J. K. Kuhn,
"Trace Elements in Coal: Occurrence and
Distribution", Environmental Protection
Technology Series, EPA 600 7-77-064.
311
-------
APPENDIX A, ANALYTICAL METHODS USED
IN DETERMINING TRACE ELEMENT CONCEN-
TRATIONS IN THE LIGNITE AND ASH
SAMPLES
Analytical Methods
Several independent methods were used in
the analysis of the samples resulting in some
duplication for certain elements. In cases
where the survey analysis, Spark Source Mass
Spectrometry (SSMS) for a particular element
was duplicated by a more precise analysis only
the latter results are reported. The methods of
analyses utilized were: spark source mass
spectrometry, atomic absorption, ion-specific
electrode, ultimate analysis and mineral
analysis using gravimetric, volumetric, and col-
orimetric procedures.
SSMS has several advantages for trace ele-
ment surveys and has become a commonly
used analytical tool for the analysis of fossil
fuels. SSMS allows the simultaneous deter-
mination of approximately 80 elements with
typical detection limits for the majority of
elements in the order of 50 to 100 parts per
billion. An advantage of the spark source mass
spectrograph is that it utilizes a small amount of
sample. This fact can be a benefit when the
samples are limited but is a disadvantage when
tonnage quantities are to be represented by a
spark source trace element scan. Sample
preparation is extremely important in SSMS,
but, as in any trace element analysis, large
scale samples cannot be accurately repre-
sented unless great attention is paid to sample
preparation.
The procedure for coal analysis includes
reduction of the size of the sample particles to
-200 mesh. The gasifier ash leach samples
were thermally ashed at 350°C in a quartz
boat in a laboratory oven. A portion of the sam-
ple was then mixed with an equal weight of
high purity compactable graphite. An internal
standard, indium, was added along with a few
drops of redistilled ethyl alcohol. The mixture
was slurried with redistilled alcohol in an agate
mortar and pestle. The sample-graphite slurry
was dried using infrared lamps. The procedure
was then repeated, slurrying and drying, until a
homogeneous electrode mixture was assured.
The sample-graphite mix was then packed into
holes drilled in a specially cleaned polyethylene
slug. This slug was then inserted into a metal
die and subjected to about 1 5 to 18 tons of
force. The sample-graphite electrodes were
then mounted in the machine for sparking.
The mass spectrum produced on the
photoplate is a summation of the elemental
components of the electrode. The ion intensity
of a spectral line is related directly to the con-
centration of the components at least over a
concentration range of 105:1. Therefore, by
running a series of decreasing exposures, the
relative concentration of elements from a major
to a trace can be established by knowing the
concentration of the internal standard added
during sample preparation. Analysis by spark
source mass spectrometry will not report
elements with concentrations greater than
1,000 parts per million wt. Elements above this
amount are reported as major components
(MO.
Mineral analyses were performed by pro-
cedure listed ASTM D-2795-69, Gaseous
Fuels: Coal and Coke: Atmospheric Analysis,
Analysis of Coal and Coke Ash, part 26,
November 1974. Due to the small amount of
whole dry coal available for analysis, an addi-
tional source of data for the mineral analyses of
coal samples from the same mine was sought.
A report by the U.S. Bureau of Mines, Rl 71 58,
containing average values from 22 sample
locations in the North American Mine at Zap,
North Dakota, was used to support, and in
some cases supplement, values obtained for
the coal sample analyzed in this study (Son-
dreal et al. 1968)6. The following elements
were determined in the coal and gasifier ash
from the mineral analysis: aluminum, calcium,
iron, magnesium, phosphorus, potassium,
silicon, sodium, sulfur, and titanium. The con-
centrations of 14 elements in several of the
samples were determined individually by wet
chemical methods.
Mercury was determined in all samples by
flameless atomic absorption with a double gold
amalgamation using the following procedure.
The sample was burned in a quartz tube and the
mercury was collected on a gold coil. The gold
coil was heated and the mercury transferred to
a second gold coil. The second gold coil was
heated and the mercury passed through a cell in
312
-------
the light path of the atomic absorption spec-
trometer. The two transfers serve to remove
hydrocarbon interferences. The equipment was
standardized by injecting known amounts of
mercury vapor into the system.
Fluorine was determined in all samples using
the USGS method of analysis. The samples
were ashed in a slurry of magnesium oxide and
magnesium nitrate and then fused with sodium
hydroxide. The dissolved fusion was buffered
with ammonium citrate, and the fluorine was
determined using a fluoride specific-ion-
electrode.
Cadmium was determined in all samples via
atomic absorption using the following pro-
cedure. The samples were put into solution us-
ing aqua regia and hydrofluoric acid. They were
then stabilized with boric acid and analyzed via
atomic absorption versus aqueous standards
having the same boric acid content.
Barium and strontium were analyzed for by
atomic absorption, using the procedure out-
lined above, in the dry coal ash and gasifier ash.
Boron was analyzed in the gasifier ash and
gasifier ash leach by the following methods.
The gasifier ash was washed in sodium car-
bonate and then fused to obtain a solution
followed by a distillation to remove in-
terferences. The solution was then analyzed via
a curcumin colorimetric analysis. The gasifier
ash leach was run directly with boron deter-
mined by the curcumin colorimetric method.
Leaching Method
Since it was suspected that many of the
elements found in coal would probably be re-
tained in the gasifier ash, and plans for burial of
the ash in the mine area, an experiment was
designed to study the leaching characteristics
of the coal ash and gasifier ash.
Ten grams of gasifier ash, ground to pass a
-60 mesh screen, were slurried with 50 ml of
distilled-demineralized water. The solution was
refluxed for 16 to 24 h with the temperature
held at the boiling point of water. At the conclu-
sion of the refluxing the leachate was analyzed
with the following tests performed.
1. Survey Analysis - Spark Source Mass
Spectrometry
2. Fluorine - USGS Method Ion-Specific Elec-
trode
3. Mercury - Flameless Atomic Absorption
4. Boron - Atomic Absorption
5. Sodium - Atomic Absorption
6. Strontium - Atomic Absorption
7. Barium - Atomic Absorption
8. Aluminum - Atomic Absorption
9. Calcium - Atomic Absorption
10. Silicon - Atomic Absorption
11. Potassium - Atomic Absorption
12. Cadmium - Atomic Absorption
1 3. Sulfur - Gravimetric
Table A-1 reports the method used for each
of the 73 elements.
313
-------
TABLE A-1
ELEMENTS CONSIDERED AND ANALYTICAL
METHOD USED FOR CALCULATIONS*
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
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.
47.
48.
49.
Elements
Ag, silver
Al , aluminum
As , arsenic
Au, gold
B, boron
Ba, barium
Be , beryllium
Bi , bismuth
Br, bromine
Ca, calcium
Cd, cadmium
Ce , cerium
Cl , chlorine
Co , cobalt
Cr, chromium
Cs, cesium
Cu, copper
Dy, dysprosium
Er, erbium
Eu, europium
F, fluorine
Fe , iron
Ga, gallium
Gd, gadolinium
Ge , germanium
Hf, hafnium
Hg , mercury
Ho , holmium
I , iodine
Ir, iridium
K, potassium
La, lanthanum
Li , lithium
Lu, lutetium
Mg, magnesium
Mn, manganese
Mo, molybdenum
Na, sodium
Mb, niobium
Nd, neodymium
Ni, nickel
Os, osmium
r, phosphorus
Pb, lead
Pd , palladium
Pr , praseodymium
Pt , platinum
Rb, rubidium
Re , rhenium
Whole
Coal
NR
MA
SSMS
NR
SSMS
AA
SSMS
NR
SSMS
MA
AA
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
NR
SSMS
IE
MA
SSMS
SSMS
SSMS
NR
FAA
SSMS
SSMS
NR
MA
SSMS
SSMS
NR
MA
SSMS
SSMS
MA
SSMS
SSMS
SSMS
NR
MA
SSMS
NR
SSMS
NR
SSMS
NR
Gasifier
Ash
SSMS
MA
SSMS
NR
C
AA
SSMS
NR
SSMS
MA
AA
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
IE
MA
SSMS
SSMS
SSMS
SSMS
FAA
SSMS
SSMS
NR
MA
SSMS
SSMS
SSMS
MA
SSMS
SSMS
MA
SSMS
SSMS
SSMS
NR
MA
SSMS
NR
SSMS
NR
SSMS
NR
Ash
Leach
SSMS
AA
SSMS
NR
C
AA
NR
NR
SSMS
AA
AA
NR
AA
SSMS
SSMS
SSMS
SSMS
NR
NR
NR
IE
SSMS
SSMS
NR
SSMS
NR
FAA
NR
SSMS
NR
AA
NR
SSMS
NR
SSMS
SSMS
SSMS
AA
NR
NR
SSMS
NR
SSMS
SSMS
NR
NR
NR
SSMS
NR
314
-------
TABLE A-1 (Continued)
Elements
50. Rh, rhodium
51. Ru, ruthenium
52. S, sulfur
53. Sb, antimony
54. sc, scandium
55. Se, selenium
56. Si, silicon
57. Sm, samarium
58. Sn, tin
59. Sr, strontium
60. Ta, tantalum
61. Tb, terbium
62. Te, tellurium
63. Th, thorium
64. Ti, titanium
65. Tl, thallium
66. Tin, thulium
67. U, uranium
68. V, vanadium
69. W, tungsten
70. Y, yttrium
71. Yb, ytterbium
72. Zn, zinc
73. Zr, zirconium
Whole
Coal
NR
NR
we
SSMS
SSMS
SSMS
MA
SSMS
SSMS
AA
NR
SSMS
SSMS
SSMS
MA
NR
NR
SSMS
SSMS
NR
SSMS
NR
SSMS
S.SMS
Gasifier
Ash
NR
NR
MA
SSMS
SSMS
SSMS
MA
SSMS
SSMS
AA
SSMS
SSMS
SSMS
SSMS
MA
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
SSMS
Ash
Leach
NR
NR
we
SSMS
SSMS
SSMS
AA
NR
SSMS
AA
NR
NR
NR
NR
SSMS
NR
NR
NR
SSMS
SSMS
SSMS
NR
SSMS
NR
*
Analytical procedure used, meaning of symbols:
C - curcumin colorimetric analysis
AA - atomic absorption versus aqueous
IE - ion-selective
electrode
MA - standard mineral analysis, ASTM
NR - not reported
standards
D2795-69
WC - wet chemical or gravimetric
FAA - flameless atomic absorption
SSMS - spark source mass spectrometry, detection limit considered <0.1
ppm
315
-------
COMBINED-CYCLE POWER
SYSTEMS BURNING LOW-BTU
GAS
F. L. Robson" and W. A. Blecher**
United Technologies Research Center
East Hartford, Connecticut
Abstract
Future power systems will be required to
burn coal in an environmentally acceptable
manner. One of the most attractive advanced
technology power systems is the combined gas
turbine and steam turbine system, the combin-
ed cycle, which offers higher efficiency and
lower capital costs than the more conventional
steam system. These advantages will enable
the combined-cycle system to be used in con-
junction with expensive fuel treatment pro-
cesses such as gasification and subsequent
pollutant cleanup resulting in reduced emis-
sions while producing electrical power at costs
projected to be significantly less than conven-
tional coal-fired steam plants with stack gas
cleanup.
Deceptions of the gasification process, fuel
gas cleanup and power systems are given with
pertinent characteristics. The estimated emis-
sions of the various systems are tabulated and
the costs of the integrated gasification/power
plant are compared with those for a conven-
tional steam plant with stack gas cleanup.
INTRODUCTION
One of the major energy goals set by the
present Carter Administration is that of in-
creased use of coal in industrial and utility ap-
plications. Historically, coal usage has been in-
creasing slowly, < 3 percent/yr, and by 1985
would reach approximately 800 million
ton/year (Figure 1). By emphasizing the use of
coal, it is projected that 1.1 billion tons/yr
could be used. While it is not clear that this goal
can be achieved, the utility industry has in-
* Chief, Utility Power Systems
* 'Senior Research Engineer
dicated that it will meet its obligations by in-
creasing the demand for coal from 430 million
tons/yr to 790 million tons/yr in 1985.
This increased use of coal must be done in an
environmentally acceptable manner and, thus,
between now and 1985, emphasis will be
placed upon low-sulfur western coals and upon
flue gas desulfurization. In the years beyond
1985, it is hoped that more efficient and less
costly coal-burning power systems having
lower emissions of S02 and NOX will become
commercially feasible. One of the most attrac-
tive of these advanced power systems is the
combined gas turbine and steam turbine
system (combined cycle) used in conjunctin
with coal gasification and fuel gas cleanup
which produce clean low-Btu gases, i.e., gases
having heating values on the order of 1150
kcal/m3 (1,000 kcal/kg, 130 Btu/ft3).
To achieve the potential savings in capital
and in fuel use, the power system and the fuel
processing system must be closely integrated
such as shown in Figure 2. In this power plant,
air from the gas turbine is used in the coal
gasifier while steam generated by cooling the
hot fuel gas is used in the power system. Other
configurations are possible including the use of
oxygen rather than air in the gasifier and the
use of a variety of cleanup systems.
During the past several years, under EPA
auspices, United Technologies Research
Center, in conjunction with Foster Wheeler
Energy Corp., Fluor Engineers and Construc-
tors and Hittman Associates, Inc., have in-
vestigated the technical, economic, and emis-
sion characteristics of power plants based
upon a number of gasifier types with both low-
and high-temperature sulfur cleanup systems
and advanced technology combined-cycle
systems. The current paper will describe only a
two-stage, entrained-flow gasifier with both
low-temperature and high-temperature sulfur
cleanup used with a combined-cycle system
having a 1425° C (2600° F) gas turbine.
POWER SYSTEM
The power system is of nominal 1000-MW
size and consists of 4 advanced gas turbines
generating a total of 720 MW and a conven-
tional heat recovery steam system generating
316
-------
1,100
1.000
900
a.
to
800
700
600
500
400
PRES, CARTER'S GOAL
HISTORICAL TREND
1960
196?-
1970
1975
1980
1985
1390
Figure 1. U.S. bituminous coal production.
317
-------
H». JTM
FROM JACKET
AND M.f. BOILER
CONDENSATE
GASIFICR
Figure 2. Air-blown BCR/Selexol
-------
445 MW. The net output power (using low-
temperature cleanup) is 1088 MW and the
estimated overall efficiency, coal pile-to-busbar
is 43.7 percent.
Gas Turbine
A number of studies (1-2'31 have indicated that
the gas turbine portion of the combined-cycle
system in the integrated coal gasifica-
tion/power station must operate at tem-
peratures of approximately 1325° C
(2400° F) or above in order to achieve attrac-
tive overall efficiencies or heat rates. Prior
UTRC work l3 4) has been based upon turbines
of 1425° C turbine inlet with relatively high
pressure ratios, e.g., 24:1. These turbines
were assumed to have ceramic stators and
other static structure requiring essentially no
cooling combined with air-cooled rotating
blades. While this projected use of ceramics
results in attractive performance, a number of
problems have been identified I5) and it is
perhaps more realistic to identify a cooling
scheme for the stators and other static struc-
tures which would require less development ef-
fort and which could be used in commercial ser-
vice in the 1980's.
Current commercial engines operate in the
1000° C to 1100° C range with air-cooled
stators and blades. However, when an air-
blown gasifier is used, some 1 5-1 7 percent of
the compressor discharge air is diverted to the
gasifier and is unavailable for turbine cooling or
combustion dilution. Thus, the use of another
coolant medium such as water becomes advan-
tageous. The gas turbine used in the present
study is based upon advanced versions of large
industrial turbines such as the prototype
100-MW UTC/Stal Laval FT50/GT200 (Figure
3), but using water-cooled static structures
with air-cooled blades.
The major modification of the gas turbine
resulting from the use of low-Btu fuel gas oc-
curs in the combustor section. Because of the
smaller amount of air available for cooling in
systems using air-blown gasifiers, the com-
bustor design must be one that minimizes the
surface to volume ratio since this requires less
coolant. The configuration which best fulfills
the various requirements is the annular burner
which resembles two concentric barrels sur-
rounding the gas turbine between the com-
pressor discharge and the turbine inlet (Figure
4).
A second combustor modification occurs in
the fuel injector. Normal practice would have a
single injector or perhaps several small injec-
tors for each burner can. Because of the higher
volume flow rate required for the low-Btu gas,
much larger injector areas are necessary. Tests
carried out by UTC and Texaco l6'71 have in-
dicated that a premix injector, one in which the
fuel gas and air are intimately mixed prior to
combustion, would significantly lower the pro-
duction of NOX while lowering the peak
temperatures within the burner can. Such a
configuration is shown in Figure 4. The emis-
sions characteristics of this combustor will be
discussed in a later section.
Steam System
The steam system operates at conventional
levels, i.e., 163 atm/510° C/5100 C (2400
psi/950° F/9500 F). While it would be
possible to operate at throttle temperature of
535° C (1000° F), trade-off studies bet-
ween heat exchanger size and materials versus
small increases in performance indicate the
lower temperature system would result in
lower costs of electricity.
FUEL PROCESSING SYSTEM
The fuel processing system consisting of the
coal gasifiers and the fuel gas cleanup system
processes 31 7,460 kg/hr (700,000 Ib/hr) of Il-
linois No. 6 coal into a clean fuel gas having a
heating value of 1,584kcal/m3 (178 Btu/ft3).
Although there is a wide variety of coal
gasification processes currently under study,
e.g., fixed-bed, entrained-flow, fluid-bed, and
molten-bed, the present paper will emphasize
only the entrained-flow gasifier. In particular, a
two-stage gasifier based upon the Bituminous
Coal Research, Inc., (BCR) BiGas design, but
modified for air-blown fuel gas production by
Foster Wheeler Energy Co., will be discussed.
Similarly, a number of low-temperature sulfur
removal systems are commercially available
which could be applied to the cleaning of fuel
gas at low temperatures131 i.e., < 120° C
(250° F). However, only the Selexol physical
319
-------
Figure 3. FT50 gas turbine.
-------
CO
to
MIXING ZONE OF FUEL AND AIR
COMPRESSOR DISCHARGE
GASIFIER FEED DUCTS
COMBUSTOR CASE
Figure 4. Potential pre-mix combustor layout.
-------
absorbent process of the Allied Chemical Cor-
poration will be discussed.
Although high-temperature sulfur cleanup
processes are still in the laboratory-scale stage,
they are potentially attractive from an overall
power plant efficiency viewpoint. Thus, a
calcium carbonate-based process developed by
the Consolidation Coal Company, division of
Continental Oil Corporation (CONOCO) will be
described.
Coal Gasifier
A schematic of the two-stage, entrained-
flow gasifier including the flow rates and
operating parameters is given in Figure 5. In
order to increase the efficiency of the system,
the steam-to-coal ratio should be minimized
since the energy in the steam consumed during
gasification cannot be effectively recovered. A
reduction in the steam consumption also
enhances the performance of the high-
temperature cleanup system as will be shown
in a later section of this paper.
Fuel Gas Cleanup
The fuel gas coming from the gasifier must
be cleaned not only to meet the EPA standards
(Table 1), but also to meet restrictions set by
the gas turbine. The latter are often more
stringent as can be seen in Table 2.
Low-Temperature Cleanup - Many of the
commercially available cleanup systems
operate with comparable removal efficiencies
TABLE 1
EMISSION STANDARDS FOR COAL-FIRED
POWER PLANTS
Conventional Plant
Proposed
gas turbines*
S02 0.57 kg/GJ (1.2 lb/106 Btu) 100 ppm
NOX 0.33 kg/GJ (0.7 lb/106 Btu) 75 ppm
Particulates 0.047 kg/GJ (0.1 lb/106 Btu) NA
For all fuels and at ISO conditions with 15%
exhaust
in
and operating characteristics. The Selexol
system selected for discussion uses a physical
solvent having a high degree of selectivity for
H2S. A typical configuration for H2S removal is
shown in Figure 6. In those cases where the
combination of coal and gasifier type results in
significant quantities of COS, or when that
component must be scrubbed to a low level,
the solvent flow rate must be increased and a
flash tank must be added along with a com-
pressor to recycle the flashed gas to the ab-
sorber. While this increased flow minimizes the
amount of C02 in the Selexol stripper off-gas,
thereby benefiting the sulfur recover system, it
adds to cost and utility requirements.
The absorber is generally run at temperatures
slightly lower than ambient and, thus, requires
some refrigeration. While this results in an in-
TABLE 2
GAS TURBINE REQUIREMENTS FOR
FUEL GAS CLEANUP
Low-Btu Gas
Typical Current Spec
Sulfur
Particulates
Metals
Vanadium
Nitrogen
0.05 Mol % or Less Than
Amount to Form 0.6 ppm
Alkali Metal Sulfate
4 ppm Weight or 0.0012
gr/ft3 > 2M
< 0.003 ppm Weight
See Sulfur Spec
500 ppm as NH3
< 1.0 Mol % or Less Than
Amount to Form 5 ppm Alkali
Metal Sulfate
30 ppm or 0.01 gr/ft3
< 0.02 ppm Weight
< 0.6 ppm
322
-------
COAL
6779 kcal / kg
(12,200Btu/lb)
FUEL GAS
HHV=1524 kcal /m3
171.2
MOL.WT. =24.35
GAS 3.79m3/kg coal
60.7 (scf/lb coal)
1
Y
FEED
HOPPER
I
TRANSPORT GAS
150°C I300°F)
31atm
450 psia
0.09kg/kg coal
AIR •
427CI800F!
30atm
(425 psia)
2.78 kg/kg coal
SLAG HOPPERS
26atm (380psia)
GASIFIER STAGE I
1,255°K (1,800°FI
GASIFIER
STAGE I
QUENCH WATER
X
AIR
CYCLONE
SEPARATOR
V
CHAR HOPPER
STEAM
234CI453F)
31 aim
(435 psia I
(0.1 44 kg/kg coal I
SLAG (0.087 kg/kg coal I
Figure 5. BCR entrained flow gasifier.
323
-------
CLEAN
FUEL GAS
SOLVENT COOLER
8
FUEL GAS
FROM WATER WASH
ABSORBER
POWER
RECOVERY
TURBINE
SOLVENT-SOLVENT
EXCHANGER
SOLVENT PUMP
ACID GAS
CONDENSATE
TANK
CONDENSATE
Figure 6. Setexol low-temperature desutfurization.
-------
crease in power consumption over ambient ab-
sorber temperatures, solvent flow rate and
therefore steam consumption and capital cost
are less. The effect of operating temperature on
utilities and cost is given in Table 3 for two dif-
ferent fuel gas compositions, one with a low
COS concentration requiring only an H2S-
based design and the other with a significant
amount of COS requiring a COS-based design.
In each case, the differences clearly indicate
that low-temperature operation is preferable.
For a Selexol desulfurization system
operating with the BCR gasifier, a comparison
of COS- and H2S-based designs is given in
Table 4. Both designs would result in emissions
significantly less than current EPA regulations.
The comparison in Table 4 gives an indication
of the cost associated with the removal of
sulfur to relatively low levels.
High-Temperature Cleanup - The high-
temperature cleanup systems offer the advan-
tage of providing a hot fuel gas directly to the
gas turbine, thereby utilizing the fuel gas sensi-
ble heat in the topping cycle without the need
for costly regenerative heat exchangers and
without the losses associated with the heat ex-
change processes. As an example of one of the
more attractive processes, the Conoco half-
calcined dolomite process was selected for
TABLE 3
LOW VS. AMBIENT-TEMPERATURE
SELEXOL OPERATION
Equipment Designed for H2$ Removal
Ambient-Temperature Low-Temperature ;A
Steam - kg/hr
Net Power • kW
Cost - $106
114,545
4,270
26
48,273
17,400
16
66,272
13,000
10
Equipment Designed For COS Removal
Ambient-Temperature Low-Temperature A
Steam - kg/hr
Net Power • kW
Cost • $106
345,454
25,530
72.6
138,636 206,818
38,940 13,400
47 25.6
TABLE 4
COMPARISON OF H2S AND COS BASED DESIGNS
BCR-TYPE GASIFIER-SELEXOL
CLEANUP PROCESS
H2§ in clean gas-ppm
COS in clean gas-ppm
Emissions KgS02/GJ
Power - kW
Steam - kg/hr
Cost - $106
H2S- Based
Design
38
447
0.186
20,400
59,773
26.3
COS-Based
Design
13
52
0.0252
39,500
153,500
53.8
Based on coal feed rate of 317,460 kg/hr and
low-temperature absorbent.
discussion. The desulfurizer operates at
temperatures in the 850-900° C range. Both
H2S and COS react with the CaC03 component
of the dolomite in a fluidized bed accord-
ing to the following reactions:
(CaC03«MgO)
(CaCo3«MgO)
C0
(1)
(2)
NOTE: This data should not be used to compare H2S vs
COS removal.
Regeneration of the sulfided acceptor is ac-
complished in a fluidized reactor at 700° C us-
ing a stream of carbon dioxide and water vapor.
Makeup dolomite is supplied at 2 percent of the
recirculation rate. A schematic of the process is
shown in Figure 7. It includes a liquid-phase
Claus plant as well as a converter for the spent
dolomite.
The desulfurizer reactions are reported to be
virtually at equilibrium and performance im-
proves with increased temperature and
decreased concentration of the reaction prod-
ucts, C02 and H2O. Temperature is limited by
C02 partial pressure which must be high
enough to prevent calcination of the acceptor.
For the BCR gasifier, desulfurization perform-
ance at two possible operating conditions is
shown in Table 5. The primary difference
between the two cases is the steam-to-coal
ratio. At the lower ratio, oxidant feed is re-
325
-------
BOILER
GO
ro
05 HOT FUEL GAS
MAKE-UP
CO2
DESULFURIZER
SPENT ACCEPTOR
LOCK HOPPER
CO2
WATER
SPENT ACCEPTOR
CONVERTERS
ACID GAS
DOLOMITE
SLURRY
ACID-GAS
STREAM
LIQUID-PHASE
CLAUS PLANT
SULFUR
STACK GAS
CO2 +H2O TO
REGENERATOR
Figure 7. Conoco high-temperature desulfurization.
-------
TABLE 5
EFFECT OF STEAM/COAL RATIO ON CONOCO DESULFURIZATION
High Steam/Coal Ratio
Desulfurizer Desulfurizer
In Out
Low Steam/Coal Ratio
Desulfurizer Desulfurizer
In Out
CH4-Mol/hr
HZ
CO
C02
H2S
COS
NH3
N2
H20
Steam/Coal Ratio
Desulfurizer Temperature
Sulfur as S02 - kg/GJ
5099.5
18538.8
25582.2
11669.7
685.7
143.5
609.0
65634.5
14338.1
142301.0
.567
- C 927
.27
5099.5
19270.9
24851.3
13289.7
68.7
8.6
609.0
65634.5
14222.4
143054.5
.144
815
.042
3775.0
15314.8
32189.6
3396.1
751.0
75.6
478.8
53753.3
2212.6
111946.9
3775.0
15894.5
31610.0
4863.4
9.5
2.5
478.8
57353.3
2374.5
112762.5
duced to maintain a fixed gasifier temperature
and both C02 and H20 concentrations are
quite low. The net result is a marked reduction
in both. H2S and COS concentrations in the
clean gas. Fortunately, reduced steam feed
rates have a favorable effect on both power
conversion efficiency and sulfur removal.
Because the fuel gas would not be cooled, a
water wash for the removal of ammonia and
particulates is not feasible. Therefore, other
provisions for handling these constituents must
be made. In the case of paniculate matter, the
sensitivity of turbine materials and coatings
dictates a very high degree of removal. Thus,
the use of high-temperature desulfurization is
contingent on the development of a high-
temperature and high efficiency particulate
removal device. Such a device will undoubtedly
be used in conjunction with conventional
cyclones as a "final filter." Several filtration
type devices are under development using
various concepts such as a porous metal or a
sand bed.'81
Ammonia presents a somewhat different
problem in that it can either be removed prior to
being burned in the gas turbine or it may be
possible to modify the combustor to provide an
environment where it will be decomposed to IM2
and H2. Conventional burners will convert as
much as 80 percent of the NH3 to NO which
makes some type of removal system or com-
bustor modification necessary.'31
EMISSIONS
The emisions from the integrated gasification
combined-cycle offer the potential to be
significantly lower than those from conven-
tional steam systems with FGD.
Sulfur Oxides
Previous discussion has indicated that the
amount of fuel sulfur compounds (H2S and
COS) removed during cleanup is a function of
several variables such as type of cleanup,
operating temperature, etc. However, no mat-
ter which cleanup system is used, the emis-
sions of S02 are well below the current regula-
tion for coal-fired steam system (See Figure 8)
and below the levels usually removed during
flue gas desulfurization.
On the basis of emissions per unit of output
(kg/kWhr), the integrated gasification/
327
-------
1.2
1.0
Ib SO2/
Million Btu
w
NJ
CO
0.6
0.4
0.2
COAL-FIRED
POWER STATION RULE
PROPOSED GT
STANDARD
RANGE
OF
CLEANUP
200
150
at 15% 02
100
50
GASIFIED COAL/
COMBINED-CYCLE
CONVENTIONAL
STEAM/FGD
Figure 8. SO2 emissions.
-------
combined-cycle system would emit between
2.1 and 13.7 x 10'4 kg/kWhr versus
27.5 x 1CV4 kg/kWhr for conventional steam
with a 90 percent effective FGD system.
Nitrogen Oxides
The formation of nitrogen oxides results from
two sources; thermal NOX from the oxidation of
atmospheric nitrogen at high temperature dur-
ing combustion, and NOX from the oxidation of
nitrogen compounds in the fuel. Thermal NOX
can be controlled by combustors such as that
previously described. Estimates of emissions of
thermal NOX are given in Figure 9.
Unfortunately, it is difficult to estimate the
NOX which could result from fuel-bound
nitrogen in low-heating value fuel gases. The
amount of nitrogen compounds, usually ex-
pressed in terms of ammonia, vary as a func-
tion of gasifier type and operating temperature.
It is possible to remove a very large fraction of
any ammonia in the fuel gas by water wash and
in the H2S removal system which may have
some affinity for fuel-bound nitrogen com-
pounds. Thus, with low-temperature systems it
is possible to remove the major portion of the
nitrogen prior to combustion.
Some consideration has been given to com-
bustor modifications'9' which might be made to
reduce the emissions due to fuel-bound
nitrogen. At this time, this type of combustor
modification would appear to result in corn-
bustor configurations which would not bo prac-
tical for use in advanced combined cycle
systems.
COST OF ELECTRICITY
Overall generating costs are affected primari-
ly by capital and fuel costs and by performance.
In the case of low-Btu gasified coal power
systems, performance affects the capital cost
as well as the fuel cost contribution to overall
cost. For a fixed coal feed rate, improved per-
formance means that the capital cost of the
fuel processing section can be spread over a
greater number of installed kilowatts. As men-
tioned earlier, continued analyses and small-
scale experimentation have led to reduced
estimates for steam feed rates to the gasifier.
The effect of a reduced steam-to-coal feed ratio
and reevaluation of the transport gas re-
quirements are shown in Table 6. The net im-
provement in gasifier performance is on the
order of 6 percent. As an additional benefit, the
heat previously required to raise gasifier steam
would now be utilized in the power system.
The busbar generating efficiencies of the
overall systems are estimated to be 43.7 per-
cent for the low- and 45 percent for the high-
temperature cleanup system. Table 7 gives the
net power produced, capital cost, and
generating costs for the two systems. The
costs are based on previous studies13'41 and are
currently being updated. However, it presently
appears that there should be little difference.
This comparison of high- and low-temperature
cleanup shows a lesser difference than did
earlier studies. The improvement in gasifier per-
formance, especially the reduced quantity of
water vapor in the fuel gas, results in a marked
increase in the low-temperature system perfor-
mance. The high-temperature system, which
TABLE 6
EFFECT OF STEAM/COAL RATIO
Component
CH4
H2
CO
C02 •
H2S
COS
N2
NH3
H20
Other Characteristics
HHV-kCal/m3
Air/
Coal Ratio
Steam/
Coal Ratio
Transport gai/
Coal Ratio
Cold Gas Eff.
High Steam
Feed Rate
Mol%
3.65
12.88
18.38
8.26
0.48
0.10
46.04
0.4
9.81
1228
3.09
.567
.426
78.5%
Low Steam
Feed Rate
Mol%
3.37
13.68
28.75
3.03
0.67
0.07
48.02
0.43
1.98
1524
2.78
.144
.088
83%
329
-------
Q8
Q6
Ib
Million Btu
0.4
0.2
COAL-FIRED
POWER STATION
RULES
PROPOSED GT
STANDARD
100
75
at 15%C>2
50
25
GASIFIED-COAL/
COMBINED-CYCLE
CONVENTIONAL
STEAM
Figure 9. NO. emissions.
-------
does not require cooling and reheating of the
fuel gas, does not benefit from the reduced
steam feed rate to the same extent.
The costs for the steam station are those
associated with a twin 500-MW station
(957-MW net output) with limestone FGD. The
cost of power shown in Table 7 is approximate-
ly 1 5 percent higher than for the integrated
gasification/combined-cycle systems.
The potential attractiveness of the relatively
simple fuel processing section and the
somewhat lower generating costs associated
with the high-temperature process are
predicated on the availability of a high-
temperature particulate removal device and
also on a gasification system that will produce
low levels of ammonia in the fuel gas. It is
hoped that efforts will continue in those areas.
SUMMARY
The integration of the combined-cycle power
generating system with a pressurized air-blown
gasifier makes it possible to economically
remove sulfur compounds prior to combustion.
The majority of the sulfur in the fuel gas ap-
pears as H2S at a relatively high partial
pressure, thus making possible the use of
physical as well as chemical sorbents.
In addition to being at pressure, the total gas
flow rate through the desulfurization process is
reduced by more than a factor of two when
compared to the flue gases from a coal-fired
boiler. Thus, for a gas turbine cycle having a
pressure ratio of 16:1, the cleanup system
volumetric flow rate is reduced by over 32:1
when compared to a flue gas desulfurization
system.
As a result of the high-pressure operation,
high removal efficiency is possible. Also, most
processes produce an acid gas stream that is
rich in H2S thereby providing an excellent feed
to a Claus sulfur recovery plant.
The capital costs associated with sulfur
cleanup also appear to favor the integrated
system. For example, estimates of the fuel gas
cleanup and sulfur recovery system costs show
that for a removal effectiveness of approx-
imately 94 percent, the associated cost per
Ib/hr of S removed is $1075; for over
99-percent removal, the cost is $2070. In
comparison, the costs for 90 percent effective
flue gas desulfurization systems are $2600
Ib/hr of S for limestone slurry1101 and $10,000
Ib/hr of S for citrate1111 systems. None of the
foregoing include credit for sulfur recovery or
costs for offsite waste disposal.
While sulfur removal costs do not tell the
whole story, they are indicative of overall
power costs; e.g., estimates of busbar costs
for the advanced combined-cycle systems14'121
TABLE 7
PERFORMANCE AND COST SUMMARY
Gasifier & Cleanup System
Cost • $
Power System Cost • $
Total Cost - $
Net Plant Output - MW
Overall Rant Efficiency - %
Generating Costs - mills/kwh
Owning Costs
Operation and Maintenance
Fuel ($1.00/MMBtu)
Total Generating Cost • mills/kwh
BCR-Selexol
Low-Temp
231,300,000
285,300,000
516,600,000
1088
43.5
13.2
4.4
7.8
25.4
BCR-Conoco
High-Temp
210,800,000
296,500,000
507,300,000
1126
45.0
12.5
4.1
7.6
24.2
Conventional Steam
FGD
94,000,000
415,400,000
509,400,000
957
36.5
14.7
4.0
9.6
28.3
331
-------
are as much as 1 5 percent lower than that of a
conventional steam plant with limestone FGD.
REFERENCES
1. D. H. Brown, and J. C. Corman, Volume II
Advanced Energy Conversion Systems,
Part 1 Open-Cycle Gas Turbine. Energy
Conversion Alternatives Study. General
Electric Phase, Final Report, February
1976.
2. D. T. Beecher et al.. Summary and Com-
bined Gas-Steam Turbine Plant with an In-
tegrated Low-Btu Gasifier. Energy Con-
version Alternatives Study. Westinghouse
Phase II Final Report, November 1976.
3. F. L. Robson et al., Fuel Gas Environ-
mental Impact: Phase Report. EPA-600/2-
75-079, November 1975.
4. F. L. Robson et al., Fuel Gas Environment
Impact: EPA 600/2-76-1 53, June 1 976.
5. J. J. Burke (Editor), Ceramics for High Per-
formance Applications. Proceedings of
Second Army Materials Technology,
Conf. November 1973.
6. W. B. Crouch et al., Recent Experimental
10.
11
12.
Results on Gasification and Combustion
of Low-Btu Gas for Gas Turbines. Com-
bustion, April 1974.
W. B. Crouch, and R. D. Klapatch, Solids
Gasification for Gas Turbine Fuel, 100
and 300 Btu Gas. Intersociety Energy
Conversion Engineering Conference.
Paper 769034, September 1976.
G. G. Poe et al., Evaluation of Ceramic
Filters for High-Temperature/High-
Pressure Fire Particulate Control. EPA-
600/2-77-056, February 1977.
M. P. Heap et al.. Environmental Aspects
of Low-Btu Gas Combustion. Proceedings
Sixteenth Symposium (International) on
Combustion, August 15-20, 1976.
Timothy Devitt, Simplified Procedures for
Estimating FGD Systems Costs. EPA
600/2-76-150. 1976.
R. S. Madenburg et al.. Citrate FGD
Process to Be Tested at Coal-Fired In-
dustrial Power Plant. 1977 Energy
Management Guidebook.
W. D. Blecher et al., Fuel Gas Environmen-
tal Impact Study. EPA Contract
68-02-21 79. Report under Preparation.
332
-------
CROSS-MEDIA ENVIRONMENTAL
IMPACTS OF COAL-TO-ELECTRIC
ENERGY SYSTEMS
Edward S. Rubin
Gary N. Bloyd
Paul J. Grogan
Francis Clay McMichael
Department of Engineering
and Public Policy
Carnegie-Mellon University
Pittsburgh, Pennsylvania 15213
Abstract
The types and rates of pollutant emissions
from coal utilization systems depend on proc-
ess design, coal characteristics, and en-
vironmental control technology. The latter is
strongly influenced by environmental
regulatory policy which has historically focused
on pollutant emissions to a single environmen-
tal medium (air, land, or water) without
rigorous analysis of the energy and secondary
environmental impacts that follow. It thus re-
mains unclear as to whether regulations requir-
ing stringent control of single pollutants in a
single medium may actually be counterproduc-
tive to overall environmental quality when
energy and cross-media impacts are con-
sidered. The present paper describes an ap-
proach being developed at Carnegie-Mellon
University to systematically address such
issues in the context of conventional and ad-
vanced technologies producing electricity from
coal. Analytical models are described which
compute system residuals to air, land, and
water as a function of coal parameters and
system design after all ancillary energy
penalties are accounted for. Included are
models of a coal cleaning plant, flue gas
desulfurization system, dry paniculate collec-
tor, wastewater control system, and low-Btu
gasification plant coupled to either a conven-
tional or combined cycle power generation
system. Application of these models is il-
lustrated in the context of alternative
regulatory strategies for sulfur dioxide emission
control. Methodologies for assessing cross-
media tradeoffs in the context of societal value
judgments are also discussed.
INTRODUCTION
Increasing interest in the use of coal as an
energy source has sharpened our awareness of
the close relationship between energy
technology development and environmental
regulatory policy. Environmental regulations
limiting gaseous and liquid discharges from
coal utilization systems can have significant
ramifications on the cost and feasibility of
specific processes. At the same time, adequate
environmental control is imperative if the
adverse effects of coal utilization are to be
mitigated. The goal of informed public policy is
to develop regulations and standards that pro-
vide acceptable environmental protection in a
way that is equitable to competing energy proc-
esses. This requires that environmental
regulatory policy be sensitive to adverse ef-
fects in all environmental media (air, land, and
water), and that it also be sensitive to the im-
pact specific regulations can have on the
viability of alternative coal technologies. Both
concerns suggest the need for a comprehen-
sive "systems" view of the environmental im-
pacts of coal conversion technologies. This
paper describes the status of work at Carnegie-
Mellon University to develop such a model for
coal-to-electric systems, including advanced
coal conversion processes. Results are
presented following a review of current
regulatory policy for coal conversion
technologies.
REVIEW OF CURRENT.REGULATORY POLICY
A 1975 paper by Rubin and McMichael'1'
summarized the nature and status of regula-
tions and standards affecting coal utilization
processes. For air and water pollutants two
types of standards exist: standards of ambient
environmental quality, and standards limiting
source emissions. For air, environmental qual-
ity standards include national primary and
secondary ambient air levels designed to pro-
tect human health and welfare. Special stand-
ards also prevent the significant deterioration
of superior air quality. For water, environmental
333
-------
quality standards are similarly designed to pro-
tect human health and welfare as well as
aquatic species in streams and rivers. While
ambient air quality standards apply uniformly
across the nation (except where state and local
standards are more stringent), ambient water
standards vary markedly from stream to
stream. They are set principally by state and
local agencies subject to federal approval.
Uniform standards for drinking water,
however, now apply nationally.
Discharge standards for air and water
pollutants are the principal enforcement tool for
achieving standards of environmental quality.
Existing sources are regulated by state and
local agencies. New sources of certain in-
dustrial categories are regulated federally via
New Source Performance Standards (NSPS)
promulgated by the U.S. Environmental Protec-
tion Agency (EPA). These require the use of
Best Available Control Technology (BACT) for
specified air and/or water pollutants. For most
processes, they pose an important design con-
straint which adds to the cost of technology.
At the present time, no NSPS regulations ex-
ist for synfuel processes, though regulation of
process sulfur emissions from Lurgi N-Btu
gasification plants is being considered by
EPA.121 Table 1 summarizes the air and water
pollutants currently regulated by NSPS for coal-
fired steam-electric generators, petroleum
refineries and '-y-product coke plants. The lat-
ter two may be suggestive of future coal
refineries producing synthetic gas or liquid
from coal. Regulation of solid waste effluents
from coal utilization systems is currently sub-
ject to state and local standards only. Federal
regulations in the solid waste area is limited to
special situations such as mining and ocean
dumping, although increased regulation is likely
as a result of the 1 976 Solid Waste Recovery
Act.
Multimedia Impact of NSPS Regulations
The choice of technology and the energy
penalty incurred in meeting New Source Per-
formance Standards gives rise to what we call
"cross-media" environmental impacts. This
refers to situations in which the reduction of a
pollutant emission to one environmental
medium (air, land, or water) increases the pollu-
TABLE1
POLLUTANTS REGULATED BY FEDERAL
NEW SOURCE PERFORMANCE STANDARDS
Steam-Electric Petroleum
Substance Generators Refineries
AIR POLLUTANTS
Carbon Monoxide
Hydrocarbons
x
x
By-Product
Coke Plants
Nitrogen Oxides x
Paniculate Matter x
Sulfur Dioxide x
Total Sulfur
Hydrogen Sulfide
WATER POLLUTANTS
Ammonia
Biochem, Oxygen demand
Chemical Oxygen demand
x
x
P
P
x
X
X
P
x
X
Chlorine Residual x
Chromium x
X
Corrosion Inhibitors x
Cyanides
X
Heat x
Oil and Grease x
pH x
Phenols
Sulfide
Total Organic Carbon
Total Suspended Solids x
Zinc x
X
X
X
X
X
X
X
X
X
X
X
X
X
Copper x
Iron x
Phosphorus x
P = Proposed
tant burdens in other media. Some examples of
this are well known; e.g., solid waste disposal
problems resulting from FGD systems at elec-
tric power plants. Other cross-media impacts
may be less obvious. Control systems that re-
quire additional steam or electricity to operate
cause additional fuel to be burned resulting in
increased emissions to the air, water, and land.
Current environmental regulatory policy does
not generally incorporate such cross-media im-
pacts in a rigorous way. Rather, regulations
334
-------
typically focus on only a single pollutant emit-
ted to a single medium.
An example of this is the NSPS for sulfur
dioxide emissions from new steam generators.
The current standard of 1.2 pounds per million
Btu heat input to the boiler precludes direct
combustion of coal without some type of pre-
treatment or post-treatment process in most
cases. Currently available options are coal
beneficiation (mechanical cleaning) and flue
gas desulfurization (FGD). Alternative
technologies are coal conversion processes
producing clean gaseous or liquid fuels, such as
low-Btu gas which can be burned directly as a
boiler fuel or used in a combined cycle electric
generating station. No NSPS yet exists limiting
S02 emissions from combustion of gaseous
fuels derived from coal. However, Table 2
shows that existing local, State, and Federal
standards for other types of low-Btu gas con-
taining hydrogen sulfide restrict emissions to
levels an order of magnitude less than the
NSPS for coal. This reflects the availability of
technology to desulfurize low-Btu gas more ex-
tensively than is possible in combustion gases.
A policy requiring best available control
technology when burning low-Btu gas would
substantially reduce S02 emissions relative to a
conventional coal-fired system. However, one
price of doing so might be a more energy inten-
sive (as well as more expensive) technology,
.with greater multimedia impacts. This is il-
lustrated quantitatively later in the paper.
, Finally, current new source standards do not
necessarily regulate the same pollutant in the
same way in different processes. An example is
the difference in the way wastewater effluent
limitations are imposed on petroleum refineries
and by-product coke manufacturing plants,
two currently regulated processes that bear
similarities to coal conversion plants. Table 3
shows that in most respects the structure of
current regulations for these two processes dif-
fer substantially even though most of the
regulated pollutants are identical, and the level
of allowable emissions are similar when nor-
malized on the input fossil fuel energy content.
The structure of future regulations for coal
gasification and liquefaction plants is more
uncertain since the zero discharge goal of the
J972 Federal Water Pollution Control Act may
TABLE 2
SELECTED S02 EMISSION STANDARDS
FOR COMBUSTION OF FOSSIL FUELS
Source
Category
Maximum Allowable Emission
ObsS02/106Btu)*
Solid
Liquid
Gas
Federal Standards (NSPS)
Fossil-fueled steam 1.2
Generators
Petroleum refinery
plant gas
State and Local Standards
Coke oven gas
(Allegheny County, PA)
Fossil-fueled Steam
generators
(New Mexico) 0.34
(Wyoming) 0.2
0.8
0.11A
0.19B
0.16C
AFrom H2S combustion assuming 250 Btu/scf (9.3 mJ/m3)
BFrom HjS combustion assuming 700 Btu/scf (26.1 mJ/m3)
.-i
^For power plant associated with coal gasification plant
*1.0lb/106 Btu = 0.430 kg/gj
TABLE 3
COMPARISON OF FEDERAL WASTEWATER
EFFLUENT STANDARDS
PetroJeum Refineries
By-Product Coke Plants
Limits on 1-day and 30-day
max.
Based on emission per unit
of plant feedstock input
Limits vary with plant size
and complexity
Limits applicable to "end-
of-pipe" (includes total
plant)
Limits on 1-day and 30-day
max.
Based on emission per unit
of plant feedstock output
Same limits for all plant
sizes and complexity
Limits applicable only to
coking process (not total
integrated steel mill)
require complete recycling of all wastewaters
from these facilities. Again, cross-media en-
vironmental impacts (on land and air) will result
from wastewater control strategies. These
must be anticipated in the design of
wastewater regulations.
335
-------
METHODOLOGICAL NEEDS FOR
REGULATION DEVELOPMENT
The discussion above suggests a number of
policy research questions that the authors have
raised previously in the context of regulatory
policy implications for synthetic fuel plants.111
These include questions as to how plant type,
size, complexity, and product mix should enter
the regulatory picture; whether limits on pollu-
tant discharge should be established for in-
dividual unit operations or for larger systems,
including the total plant; whether environmen-
tal regulations can be structured so as to
reward process improvements that reduce en-
vironmental impact; and whether a multi-media
approach that minimizes overall environmental
impact can be developed into a workable
regulatory scheme.
Evaluation of environmental tradeoffs,
however, is a difficult task. An idealized
framework for such an analysis is suggested in
Figure 1. The three principal elements involve:
(a) characterizing the rates and types of emis-
sions to air, water, and land as a function of the
coal feed type and the characteristics of proc-
ess and environmental control technologies; (b)
examining how these emissions are transferred
through various media (air, land, and water) to
receptors in the environment (humans, plants,
and animal life); and (c) evaluating the damage
incurred by these receptors from exposure to
the various pollutants. This type of
methodology would yield a benefit/risk/cost
analysis of alternative regulatory standards, in
contrast to the existing philosophy of NSPS
which is based only on best available
technology. The framework is idealized,
however, since our current state of knowledge
is simply inadequate to actually perform this
type of analysis. Indeed, even the characteriza-
tion of coal conversion process emissions can-
not yet be done rigorously in many cases.
Three research programs in progress at
Carnegie-Mellon University (CMU) seek to im-
prove methodologies for assessing coal conver-
sion plant environmental impacts and
regulatory policies. One effort involves the
measurement and characterization of waste
streams from ERDA pilot plants producing high-
Btu gas from coal.131 This program will con-
tribute a substantially improved data base for
assessing advanced technologies and the im-
plications of alternative policy formulations. A
CHARACTERISTICS OF
- PROCESS TECHNOLOGY
- COAL FEEDSTOCK
- ENV. CONTROL TECH.
(REGULATORY POLICY)
- ENERGY PLANT °
REQUIREMENTS
DOSE OR
CONCENTRATION OF
SPECIES IN AIR,
WATER, LAND
EFFECTS ON HUMAN
HEALTH, VEGETATION"
FISH & ANIMALS,
MATERIALS, ETC.
PROCESS
E;-; i ssi ON
MODELS
ENVIRONMENTAL
DISPERSION 2.
INTERACTION
ENVIRONMENTAL
DAMAGE
MODELS
•at-
EMISSIONS TO
AIR, WATER ?
LAND
POLLUTANT TRANSPORT
'£ TRANSFORMATION
PROCESSES FOR- AIR,
WATER 8 LAND
VALUE OF ENVIRONMENTAL
DAMAGE
Figure 1. An idealized framework for standards development.
336
-------
second program is directed at assessing the en-
vironmental damage of pollution with particular
emphasis on the role of uncertainty. To date,
this research has focused on the health effects
of sulfur dioxide emissions from coal-fired
power plants.141 A third effort, which is the sub-
ject of the present paper, involves the develop-
ment of a systematic framework for
characterizing air, water, and land emissions
from coal utilization technologies as a function
of four factors:
• coal characteristics,
• process and environmental control
technology characteristics,
• environmental regulatory constraints,
and
• useful product or output.
This represents the first module in Figure 1.
The emission inventories derived from this
analysis are basic to any subsequent approach
to integrate their impact on air, land, and water.
Currently, work is focused on conventional and
advanced coal-to-electric systems, which
represent the greatest potential for coal use in
the near term.
COAL-TO-ELECTRIC SYSTEMS MODEL
A systematic framework for comparing alter-
native coal-to-electric technologies is il-
lustrated in Figure 2. The figure applies to a
mine mouth situation using run-of-mine (hOM)
coal in one of several ways. One is to burn the
coal directly in a conventional steam-electric
generator using once-through cooling and no
flue gas cleanup. This would represent an en-
vironmentally uncontrolled or "base case"
situation. A system designed to meet en-
vironmental standards would be more complex.
To meet water effluent standards for heat,
suspended solids, organics, and other chemical
species a wastewater treatment system in-
cluding cooling towers or pond vould replace
simple once-through cooling. To meet air pollu-
tion standards, a flue gas treatment system or
coal cleaning prior to combustion would be re-
quired. Flue gas treatment could include a
desulfurization system (FGD) and/or a par-
ticulate removal device (mechanical collector,
electrostatic precipitator or baghouse).
Precombustion cleanup could include
COAL
PREPARATION
PLANT
LOW-BTU
GAS PLANT
LIQUEFACTION
PLAfjT
ELECTRIC
POWER
PLANT
-CONV. STM.
-COMB. CY.
-FL. BED
COOLING &
PROCESS
WATER
I I ELECTRIUTY. ^_.
NORMALIZATION BASIS: 1000 f'WE
NET OUTPUT
Figure 2. CMU systems model of coal-to-electric technologies.
337
-------
mechanical coal cleaning or conversion of coal
to a clean gaseous or liquid fuel. Advanced
technologies such as fluidized bed boilers offer
the potential for direct combustion of coal with
simultaneous pollutant removal.
All the alternatives above have two impor-
tant characteristics. First, in meeting en-
vironmental regulations for air and water
pollutants additional residual streams appear
that may pose new environmental problems.
Secondly, each component or system alters the
hermal efficiency of the coal-to-electric cycle,
irecily affecting all material flow rates
\.iicludiny effluents to air, land, and water)
associated with the production of power. From
an environmental point of view, the systems
model in Figure 2 asserts that the proper basis
for comparing different coal-to-electric
generating systems is on the ability to produce
the same amount of electricity for sale after all
ancillary energy needs are accounted for. For
convenience this quantity is taken as 1000
MW. Electricity is thus viewed as a socially
desirable commodity and the environmental im-
pacts of different systems producing it are
compared on the basis of a common net out-
put. From this perspective, a number of
technical and policy issues can be addressed as
indicated in Table 4. The goal of on-going
research at CMU is to develop computerized
TABLE 4
EXAMPLES OF ENVIRONMENTAL IMPACT TRADEOFF ISSUES
ADDRESSED BY PARAMETRIC ANALYSIS USING CMU MODEL
Useful
Electrical
Output
Coal
Characteristics
Emissions
Contraints
Process and
Env. Control Tech.
Characteristics
Types of Questions Addressed
Constant
Varied
Constant
Derived
Constant
Constant
Constant
Constant
Derived
Varied
Constant
Constant
Varied
Derived
Constant Varied
Constant Derived
Derived
Varied
Constant
Constant
Derived
Varied
What process and/or control technology
characteristics are needed to comply
with fixed emission constraints for
various coals? What are the associated
coal production rates, costs, and emis-
sions of pollutants to air, land and
water from producing a fixed amount of
electricity for sale?
What coals can be used to comply with
given emission regulations for different
processes or facility configurations?
What are the associated costs and
emissions?
What coals can be used at a given type
of facility as emission constraints are
changed? What are the associated costs
and emissions?
What regulations are required in order
to use certain types of coal at a given
facility? What are the associated costs
and emissions?
What facility characteristics are required
to process a given coal for various emission
constraints? What are the associated costs
and emissions?
What must the emission constraints be for
various facilities in order to process a
given coal? What are the associated costs
and emissions?
338
-------
analytical models of the modules in Figure 2
which are sufficiently detailed to capture all
pertinent factors, but which are also sufficient-
ly simple and flexible so that a wide range of
parameters can be examined easily. The follow-
ing paragraphs present highlights of the models
currently developed. Following this is an il-
lustration of their use to examine the multi-
media impacts of alternative formulations of
S02 regulations for coal-based electric power
systems.
Coal Feedstock Parameters
Four coal characteristics are the principal
parameters of the model. These are the coal
higher heating value, ash content, sulfur con-
tent, and pyrite fraction expressed on a dry
mass basis. More detailed data on coal com-
position (ultimate analysis) is used to model the
performance of FGD and low-Btu gasification
systems. The electrical energy penalty required
to mine-eoal (applicable to underground mining)
is also an optional parameter of the model.
Coal Preparation Plant
Mechanical cleaning of coal prior to combus-
tion is modeled in terms of either a "simple"
plant, designed principally for ash reduction
with maximum energy yield and some sulfur
reduction, or a "complex" plant providing
greater sulfur reduction but with higher
material and energy losses. Figure 3 shows the
latter configuration. Wash circuits are provided
for coarse and fine coal, with the fine stream
reporting to a thermal dryer to achieve an ac-
ceptable moisture content in the final coal mix-
ture. In the analytical model, ash, sulfur, and
energy recovery are functions of the overall
material yield (which depends on bath specific
gravity) and the crushed coal top size. The
model employs coal-specific washability curves
of the type reported by the U.S. Bureau of
Mines for various domestic coal seams.151 Elec-
trical energy is required by the plant for coal
crushing, particulate control equipment,
materials handling, liquid pumping, and
wastewater treatment. These requirements are
evaluated and modeled in proportion to the coal
flow in various circuits. The thermal dryer in-
curs an additional energy penalty modeled as a
fraction of the ROM coal input. Air pollutant
emissions from the dryer incorporate empirical
data on adsorption of S02 on the dried coal and
levels of NOX emissions. Dryer TSP emissions
are controlled to the NSPS level assuming use
of a wet scrubber. Solid waste from the clean-
ing plant occurs as a dewatered sludge prin-
cipally containing ash, sulfur, and coal refuse.
All other waters are assumed to be completely
recycled.
Figure 4 illustrates the sulfur reduction
achieved for three eastern coals "processed"
through the CMU coal cleaning plant model. In
this case the plant was designed to recover 90
percent of the input coal mass with coal
crushed to 3/8" top size. 63-68 percent of the
sulfur was pyritic. The plant achieved an overall
reduction of 38 to 41 percent in total sulfur ex-
pressed as equivalent S02 per unit energy con-
tent of coal. Between 3 and 8 percent of the
coal energy was lost as plant refuse.
Steam-Electric Generator
The nominal steam-electric system assumed
in the CMU model employs a pulverized coal
boiler designed to achieve NSPS levels of NOX
emissions. The primary electrical conversion
efficiency is represented as a gross cycle heat
rate, defined as the electrical generator output
excluding any energy needed to run coal pro-
duction and environmental control systems.
The primary coal pulverizer is treated separate-
ly since its energy requirement decreases when
coal is mechanically cleaned prior to combus-
tion. A penalty for nitrogen oxide control can be
included if boiler modifications such as air
preheater bypass are needed to achieve emis-
sion standards.
Coal ash and sulfur streams are partitioned
between the bottom ash and flue gas streams
whle thermal heat loss is divided between air
and water. This determines the emissions of an
uncontrolled plant. Emissions of carbon
monoxide, hydrocarbons and nitrogen oxides
are calculated from empirical emission factors
for the assumed boiler type. Solid waste
streams from an uncontrolled plant are assum-
ed to occur as boiler bottom ash and sludge
from the feedwater treatment unit. These are
calculated by mass balance and empirical ef-
fluent factors, respectively. Uncontrolled ef-
fluents to receiving waters include thermal and
339
-------
RDM
COAL
WASTE
WATERS
GASES
^ WET , _J
SCRUBBER
COAL
TO POWER
PLANT
Figure 3. Schematic of coal cleaning plant model.
(90% material yield, 3/8" top size)
6.n
5^65
5.0
X-,
" 1.0
r>
rH
in
3 3.0
t;
§ ? n
LJ £«u
Cvl
o
1 L0
0.0
_
-
,'" "*' . "- -*/.
"**"*" r *-. r
*•"*•• * * *
//..'•• •':•"'.
1 1 RUN-OF-MINE
2.01
"^-
' "• " •*•"
|Ay-/'| CLEANED
2.11
1.52
s;?s
• .' * . '. 1 . •
PIHSBUR6H LOHFR INDIANA
COBBED FPEEPORT no. vn
3s = 3.30 2.30 l.K
SA = 11.0 10.1 12.0
HHV • 13,153 13^231 12,537
Figure 4. Sulfur content of three eastern coals "cleaned" by model plant.
340
-------
chemical discharges plus suspended solids.
These are estimated from available data on
power plant characteristics.
Paniculate Collection System
Flyash is assumed to be collected in a dry col-
lection system and/or a wet scrubber incor-
porated as part of an FGD system. The dry col-
lector can be an inertial separator, baghouse, or
electrostatic precipitator. Performance is
represented in terms of a collection efficiency
with an associated energy penalty expressed
as a fraction of gross power plant output. The
mass flow rate of solid waste is determined by
a mass conservation algorithm that includes a
specified moisture content for slurried
systems.
Flue Gas Desulfurization System
The performance of an FGD system can be
modeled simply by specifying an S02 removal
efficiency and associated energy penalty.
Alternatively, a detailed analytical model has
been developed which calculates FGD energy
requirements for a nonregenerative limestone
system, which is the most prevalent FGD
technology today. This model is similar to one
developed by the Tennessee Valley Authority
(fVA) for cost estimation in lime/limestone
FGD systems,161 and employs performance cor-
relations developed by Bechtel and TVA. The
schematic of Figure 5 shows the major
elements of the model. Where dry particulate
collection is used, partial bypass of the scrub-
ber can be implemented to achieve current S02
emission standards by treating only a fraction
of the gas to a higher S02 removal efficiency
than needed if the entire flue gas stream is
scrubbed. Sensitivity analyses have shown
that this can result in significant energy as well
as cost savings.171 Energy penalty calculations
incorporate raw material and sludge-handling
costs as well as electrical requirements for all
gas-phase and liquid-phase fans and pumps
plus steam requirements for gas reheat.
Figure 6 illustrates the fact that FGD energy
requirements increase nonlinearly as S02 emis-
sions are decreased. The figure also indicates
how higher sulfur coals incur greater energy
penalties to achieve a given S02 emission
standard. The absolute level of energy needed
depends on a number of coal, plant, and
system parameters as suggested in Table 5.
The principal secondary enviromental impact of
lime/limestone technology is sludge consisting
principally of calcium sulfate, calcium sulfite,
flyash, and limestone with appreciable
moisture content. Regenerative systems that
eliminate sludge disposal incur a significantly
larger energy penalty. This increases the air
OPTIONAL BYPASS
80JLFR
TO STACK
LIMESTONE
SLURRY
FGD
SLUDGE
Figure 5. Schematic of limestone FGD system.
341
-------
§
I\.Q
- 3.5
c5
3.0
2.0
PITTSBURGH SEAM•
LOWER FREEPORT
INDIANA NO. VII-
ROM
3.0
2.5
2.0
•1.5
1.0
0.5
0.0
POHER PLANT S07 EMISSIONS (LE/10E PTU)
Figure 6. FGD system energy requirements for three eastern coals.
TABLE 5
EFFECT OF SYSTEM PARAMETER VARIATIONS ON
LIMESTONE FGD SYSTEM ENERGY REQUIREMENTS
(Ref. 6)
Parameter
Stack exit temperature
Coal heating value
Coal sulfur content
S02 emission regulation
Entrain ment at de mister
One Percent Resulting Percent
Increase in Increase in
Nominal Value FGD Energy*
1.75°F 2.3
105 Btu/lb -1.6
0.035% 0.7
0.012 lb/106Btu 0.52
0.001% gas wt. 0.45
Scrubber inlet temperature 3.0°F
Gross plant heat rate
90 Btu/KWH
-0.4
-0.1
pollutant and ash emissions per unit of net elec-
trical output.
Water Treatment System
Water treatment systems for conventional
steam-electrical power plants are designed to
achieve effluent standards for heat, suspended
solids, and other chemical constituents (see
Table 1). The principal component is a cooling
tower which transfers waste heat from the
water to the air. This system incurs an energy
penalty modeled principally in terms of the
water pumping head, cooling range, and in-
crease in turbine back-pressure imposed by the
tower. Schemes for the treatment of chemical
wastes are modeled in different forms depend-
ing on whether the cooling water treatment
342
-------
PRECIPITATION
DISCHARGE
DISCHARGE
INTAKE
SLOWDOWN
^COAGULANTS MAY BE ADDED
INCLUDES BOILER SLOWDOWN, EQUIPMENT CLEANING WASTES (BOILER TUBES, BOILER
FIRESIDE, AIR PREHEATER, STACK, COOLING TOWER BASIN), RAINFALL RUNOFF,
SANITARY WASTES, PLANT LAB AND SAMPLING STREAMS, INTAKE SCREEN BACKWASH,
AND FLOOR DRAINS.
Figure 7. Water treatment for a controlled plant using a recirculating system.
system is of the recirculating or once-through
type. One example is shown in Figure 7. Note
that treatment of chemical waste transforms
potential wastewater effluents into sludges to
be disposed on land.
Coal Gasification/Combined
Cycle System
A potential alternative for using coal to pro-
duce electricity is to first gasify it, then use the
low-Btu gas either as a boiler fuel in a conven-
tional Rankine cycle or in a combined cycle
system having the advantage of a higher ther-
modynamic efficiency. Although commercial
low-Btu gasif iers are available the combined cy-
cle approach has yet to be successfully
demonstrated. Nonetheless, electricity from
coal via low-Btu gas could become an attrac-
tive alternative to direct combustion if
theoretical efficiency advantages can be realiz-
ed economically.
A generic model of a low-Btu gasification
plant (Figure 8) has been developed from
published studies of various processes.18121
Run-of-mine coal first enters a preparation
stage where it is crushed and sized. Pretreat-
ment (mild oxidation) may also occur at this
point when using agglomerating coals. Coal is
then introduced into the gasifier with additional
water (steam) and air to generate crude product
gas. This gas is cooled in a quench stage to
remove heavy liquids, particles, and other im-
343
-------
Figure 8. Energy and mass flows for low-Btu coal gasification/combined cycle model.
CUAL
COAL-*- PREP -*»• GAS IF
t tf t
WASTE WASTE WASTE
SOLIDS GASES SOLIDS
L
1 *< •
KEY
UTILITY
~1
t « T
1
*
I
' * ! ^*
I Y
1 ' HASTEWATER
, ^ TREATMENT *""
SYSTEM h_
ACID
REMOVAL _^
n
- M T
? r
. t
1 t \
. ELECTRIC
"~~l
POWER
4
• STEAM -|
•
.kJVASTE ' 1
GASES '
^ T ? f 1
T t r**-^
SULFUR ->-su
lAILbAS SYS 1 til *"
-d S S S
T ^ T
WASTE WASTE WASTE
SOLIDS GASES WATER
l^ ^
T Y
WASTE WASTE
SOLIDS GASES
LFUR
SOME POTENTIAL POLLUTANTS FROM
AIR
so2
TSP
NOX
CO
CXHY
H2S
COS
NH3
HCL
HCN
TRACE METALS
CARCINOGENS
SYNTHETIC FUELS PLANT
WATER
NH3
4>OH
CN
SCN
BOD
COD
TOD
TSS
TDS
PH
HEAT
OILS
LAND
ASH SLURRIES
FINES
DRY RESIDUES
WASTE TREATMENT
SLUDGES
SPENT CATALYST
SLAGS
344
-------
purities. The cleaned gas then proceeds to the
acid gas removal step where the sulfur concen-
tration is reduced to an acceptable level dic-
tated by environmental regulatory policy. The
gas can then be fired in a boiler or utilized in a
combined cycle system to produce electric
power. Waste gases are exhausted to the at-
mosphere just in a conventional plant. The two
major environmental control systems introduc-
ed by the low-Btu gasification process are the
wastewater treatment system and the sulfur
removal/recovery system.
Wastewater Treatment. The characteristics
of raw wastewaters from advanced coal
gasification plants are not yet well character-
ized although some pilot plant data are becom-
ing available.113'14' Table 6 suggests that while
there is some simlarity among gasification
process effluents there are also marked dif-
ferences from one process to another that can
significantly affect the level of type of
wastewater treatment technologies. In general,
treatment will include oil-water separation;
steam stripping to remove hydrogen sulfide
(which is sent to the sulfur recovery system);
ammonia (recovered as a by-product) and other
acid-producing dissolved gases; and removal of
organic compounds, particularly phenols, using
an absorption system (for wastewaters with
low organic content) and/or a biological oxida-
tion system (for wastewaters with high
organics). A polishing process may also follow.
It remains unclear, however, as to what level of
treatment will apply to commercial gasification
plants. Presently, these are subject only to
State and local standards, which vary con
siderably. Rubin and McMichael111 showed that
Federal NSPS standards for by-product coking
and petroleum refinery —two processes
resembling coal gasification plants- are similar
when compared on the basis of fossil fuel
energy input to the process (Table 7). It re-
mains speculative as to whether this might also
apply to coal gasification processes. Several
processes under development call for the com-
plete recycle of wastewaters to improve the
process design as well as to comply with
potential zero discharge requirements for liquid
waste.
In terms of the cross-media problem, the fm-
portant point to emphasize is that control or
elimination of wastewater constituents ag-
gravates air and land problems indirectly via the
need to produce additional electricity and
steam, as well as directly through the produc-
tion of gaseous and solid waste discharges
(sludges) from various unit operations. Elec-
trical energy penalties are incurred in pumping
wastewaters through the various treatment
steps, while steam is needed for stripping
TABLE 6
WASTEWATER CHARACTERISTICS OF THREE
COAL CONVERSION PROCESSES
(Ref. 14)
POLLUTANT
Ammonia
Phenol
Chemical Oxygen Demand
Total Organic Carbon
Cyanide
Thiocyanate
Tar
Light Oil
Total Dissolved Solids
Synthane Process
PDU,
(North Dakota Lignite)
19.5 ± 3.0
11.9 ±1.2
77.7 ± 14.4
22.0 ± 3.0
Negligible
0.05 ± 0.08
74.1+27
N/A
N/A
Hygas Process
Pilot Plant
(Montana Lignite)
13.1 ±0.3
11.4 ±2.4
N/D
39.1 ± 15.4
Negligible
2.5 + 0.2
~0
N/A
12.4 ±0.06
By-Prod uct Coke
Comm'l Plant
(Bituminous)
8.5
0.9 - 1.0
4.0-5.5
1.6-2.0
0.02 - 0.05
0.3-0.4
93
33
N/A
345
-------
TABLE?
ADJUSTED NEW SOURCE PERFORMANCE
STANDARDS FOR BY-PRODUCT COKE MAKING
AND PETROLEUM REFINING
(30-Day Maximum) (Ref. 1)
(pounds of pollutant per 10^ Btu feedstock)
Pollutant
BODS
TSS
COD
Oil & Grease
Phenolic*
Ammonia as N
Sulfide
Total Chromium
Hexavalent Chromium
Cyanides amenable
to Chlorination
Petroleum
Refineries
210-2900
140-1920
1050-20,000
70-890
1.5-19
40-1700
1.1-16
3.5-47
0.06-0.80
N/A
By-Prod uct
Coke Making
N/A
600
N/A
240
12
240
5.8
N/A
N/A
5.8
* Assumes heating values of 6.5 million Btu/bbl for crude
oil and 12,000 Btu/lb for coal, with a coke yield of 0.69
Ib coke/lb coal.
N/A = not applicable.
6.Or
5.0
2 | H.Q
•^z a
=3 LU
C/5 UU
sr u_
o
(_> UJ
s s 3-°
Q± t
LU CO
2.0
LU CO
operations. This steam may or may not repre-
sent an energy penalty, depending on details of
process design. This is illustrated quantitatively
later in this paper. In all cases, the magnitude of
the ancillary energy demand is proportional to
the quantity of wastewater treated.
Sul'fur Removal and Recovery. Whereas high-
Btu gasification processes must remove virtual-
ly all gaseous sulfur to prevent poisoning of
catalysts and maintain gas quality, removal of
sulfur from low-Btu gas producing steam or
electricity is needed only to comply with en-
vironmental standards. As many as three unit
operations may be involved in controlling sulfur
emissions: acid gas removal, primary sulfur
recovery, and tail gas cleanup system. Figure 9
shows how the energy penalty for increased
desulfurization increases nonlinearly for one
acid gas removal system in widespread use.1151
Table 8 shows the overall energy requirement
incurred in product gas desulfurization using
several systems analyzed for the EPA. En-
vironmental impacts of desulfurization may oc-
cur as gaseous emissions notably sulfur com-
pounds from the tailgas treatment system and
solid waste generation in the form of sludges
-, 10.0
nominal process
"hi-pure" process
_L
_L
±
X
200
4
8.0 ^
6.0
1,0
2.0
CQ
a
ID
a.
ZD
O
Q.
11-
O
5
1000 800 600 400
H2S IH CLEAIJ GAS (PPM)
Figure 9. Thermal energy requirement for acid gas removal (Benfield Process) (Ref. 20).
346
-------
TABLE 8
LOW-BTU GASIFICATION PLANT
4.5% Sulfur Feedstock, 137 x 103 GJ/day
ENERGY REQUIREMENTS FOR SULFUR REMOVAL/RECOVERY*
(As a percent of product gas output)
Process
Component
Hot Potassium
+Claus Plant
-f-Beavon Tailgas
Hot Potassium
+ Claus Plant
+Wellman-Lord TG
Iron Oxide
+Allied Plant
+Beavon Tailgas
Sulfur Content:
0.7 KG/GJ
(0.3lbS02/106Btu)
0.7 KG/GJ
(0.3lbS02/106Btu)
3.0 KG/GJ
(1.2lbsS02/10GBtu)
SULFUR RECOVERY
Electricity
Steam
Sub-Total
TAILGAS CLEANUP
Electricity
Steam
Auxiliary Fuel
Sub-Total
Total Gas Energy
GJ/103 KG S Removed
Plant Cost-tf/GJ
«106Btu)
1.91
9.34
11.25
0.28
0.04
0.61
0.93
12.2%
64.7
20.2
21.3
1.91
9.34
11.25
0.48
0.17
5.11
5.76
17.0%
92.0
24.3
25.6
9.60
-
9.60
0.12
0.02
0.09
0.22
9.8%
59.0
32.4
34.2
•Derived from Ref. 9 assuming efficiencies of 40% for electricity, 85% for steam and 100% for auxiliary fuel.
and spent catalyst. Additional liquid waste may
be generated and sent to the wastewater con-
trol section.
APPLICATION OF ANALYTICAL MODELS
Impact of SO2 Emission Regulations
The models described above can be used to
systematically compare the multimedia impacts
of different technologies generating electricity,
as well as the cross-media effects of alternative
regulatory strategies. To illustrate this, con-
sider the regulation of sulfur dioxide emissions
from a conventional power plant burning a high
sulfur eastern coal (Pittsburgh seam, Figure 4).
Define a "base case" plant configuration as
one with no desulfurization technology and no
cooling tower or water treatment system pro-
ducing 1000 MW net output. Compare this to
an equivalent environmentally controlled plant
that meets Federal new source standards for
water pollutants, and controls S02 emissions to
some specified value expressed as mass emis-
sion per unit heat input to the boiler. Figure 10
shows that water pollutants are now virtually
eliminated while the S02 mass emission is
reduced up to 90 percent depending on the
emission level that is specified.
Cross-media consequences of these emis-
sion reductions are shown in Figures 11-15,
assuming use of cooling towers and limestone
FGD.
Figure 11 shows an increase in the net cycle
heat rate of the power plant corresponding to a
decrease in overall thermal efficiency from
about 38 percent for the base case plant to
about 33 percent for a controlled plant meeting
NSPS levels for water and S02 emissions
(Figure 12). If the coal is mechanically cleaned
before combustion the FGD energy penalty is
reduced but the overall cycle heat rate (mine-
to-busbar) is still higher because approximately
347
-------
50
CO
1
U-
-100
POWER FLINT SOo EMISSIONS (LBS/100 BTU)
S02 MASS EMISSIONS
TO AIR
HEAT AND OTHER
)T POLLUTANTS TO WATER
Figure 10. Effect of emission standards on base case S02 and water pollutant emissions.
(Pittsburgh seam coal)
, oa
10,000
9,000
FGD+CLEANlNfi
ROM 3.5
5.65
3.0 2.5 2.0 1,5 1.0
POWER PLMT S02 EMISSION STANDAIW (LPS/10G BTU)
0.5
0,0
Figure 11. Effect of S02 emission standard on net cycle heat rate.
(Pittsburgh coal)
348
-------
140
120
100
| 80
£
^ 60
S
8
5
° 40
70
0
(a)
GASEOUS EMISSIONS
FROM A 1000 fit PLANT
ICEI1NG NCH SOURCE
STANDARDS
(rilTStUBGH SEAM COAL)
—
11.9
81.0
1'tO.l
1 | FGD ONLY
(•r.V'.| FGD « CLEANING
1.2 0
PARTICIPATE NITROT.EN SULFUR HYDRO- CAHBON
HATTER
OXIDES DIOXIDE CARBONS MONOXIDE
(c)
1500 r- SOLID WASTE FROK
.14
.12
.10
P
1 .03
£
5 .06
§
v»
5
.04
g
.02
.00
-
-
-
_
.-OH ,
.15?
1400
(b)
KASTEWATER EFFLUENTS
FROM A 1000 m PLANT 12K1
ItElING NEW SOURCE
STANDARDS £
(KECIIICULATING COOLING SYSTEM) ^
B 1000,
c
S
i soo
i
* ECO
.055 i
5
i .»
, iCU
200
.002 .002
• 1 ' i 0
1000 HK PLATT ^eTIF
A
5 NDI
SOUSCE STASDAKS 1487
(PITTSEURSH SEAM COAL)
| "I F«D ONLY
[yj^ FGD • CLEANING
—
503
_
".'•"• .'•'•••'r
•;'•£•'•' •'•
* * *•**• • " '
:.•:••':>:
''»'''••'.!•'.
...V ;••'.•••'
:'••':-:.:
•^•i-:-
" .1 1* • •• '•
1 "" *' '•*• '*
• ;*.*»* * * ".
*» ••*..'>•..
2C4
115
•.:'.:'•?.-':"•'
.'•"• '.'•••'•'.' j'
CHLORIDE IUSPENDED OIL AMD COPPER "OH CLEANING IOTTOH
SOLIDS GREASE ...„„ ....
716
4ns
-i'f^.v"-^'
'.•-' :(-!;!:;
'"*". '•ta.*'*"
• ' *"**«"' *
r;. i"V\" •
710
'. A'»* ••••'',
•.: :^«*t
"." • * r '•
..'• *J*"*.''
1 * * . * 1 *'
• • '- V '
• • *
'• ' -*T
••"•'..'Vv..
FLYASH FCD
iLimfir
Figure 12. Multimedia pollutant emissions for a plant meeting NSPS levels at 1000 MW net output with
Pittsburgh seam coal.
349
-------
I/O
-------
5 percent of the coal energy is lost during the
cleaning process. Figure 1 shows how this is
reflected in increased coal tonnage that must
be mined to maintain the same net power out-
put. Although more coal must be mined using
cleaning, the mass of coal delivered to the
power plant decreases since washing concen-
trates the recovered energy in less mass. As
the SO2 regulation becomes more stringent
more coal must be fired to maintain the same
net power plant output because of the increas-
ing ancillary energy needed for FGD and clean-
ing plant equipment.
As a result of increased coal demand, par-
ticulate (TSP) and nitrogen oxide (NOX) mass
emissions also increase nonlinearly as the S02
regulation is tightened (Figure 14). Both TSP
and NOX are assumed to meet the current NSPS
levels in all cases. Since these are given in
terms of boiler energy input, the absolute mass
emission still increases as more coal is fired to
the boiler. Figure 1 5 shows that solid waste
generation increases most dramatically as S02
emission levels are lowered. In this Figure, solid
waste is taken to include the sum of all cleaning
plant refuse plus all power plant wastes (prin-
cipally FGD sludge, flyash, and bottom ash). On
a dry basis, the quantity of solid waste in-
creases approximately 1 80 percent as sulfur
emissions are reduced from their uncontrolled
value to the NSPS value using this particular
coal. This does not include the substantial loss
of water that also occurs since cleaning plant
and FGD sludge typically contain only 40-50
percent solids by weight.
Interpretation of BACT
Another aspect of S02 regulatory policy hav-
ing cross-media implications concerns the re-
cent Congressional requirement that best
available control technology (BACT) be used to
reduce power plant sulfur emissions. Two com-
mon interpretations of BACT include a fixed
emission standard less than the present NSPS
(e.g., 0.6 pounds of SO2 per million Btu), or a
constant percent reduction in sulfur (e.g., an
80 percent FGD efficiency, reflecting 90 per-
cent S02 removal with 90 percent reliability).121
Figures 16 and 17 show the impact on dry
solid waste and sulfur dioxide mass emissions
when these two interpretations of BACT are
applied using three eastern coals (from Figure
4), and assuming limestone FGD with and
without coal cleaning. Mass emissions are
displayed as a function of the fired coal sulfur
content expressed as equivalent sulfur dioxide
per unit energy input.
One sees that as the input sulfur content
decreases, a standard calling for constant
removal efficiency results in less S02 emissions
to the atmosphere as opposed to the fixed
emission standard. For the coals modeled here,
the lowest sulfur levels are obtained only by
cleaning coal prior to combustion. For coals of
higher sulfur content the constant FGD removal
efficiency yields greater S02 emissions than
the fixed emission level. This suggests that if
an overriding objective of national environmen-
tal policy is to minimize sulfur dioxide emis-
sions, regulations should require the more str-
ingent of a constant removal efficiency and fix-
ed emission standard. In such a case, the prac-
tical limitations of FGD technology may require
higher sulfur coal to be washed prior to com-
bustion. High sulfur coals with no appreciable
pyrite content (hence, not subject to washing)
could become unusable. '
The cross-media impacts associated with
BACT were illustrated earlier for one particular
coal. Figure 1 shows one effect (on total solid
waste generation) for three eastern coals, with
and without coal washing. Note that while the
combined solid waste of the cleaning and
power plants decreases when the high sulfur
(Pittsburgh seam) coal is washed before com-
bustion, the reverse is true for the lowest sulfur
(Indiana No. VII) coal. Total waste using the
median sulfur coal also increases slightly when
both FGD and cleaning are used. In all cases
more total solid waste is generated when
washing is used to achieve a given inlet S02
content. Details of solid waste impacts will
vary with the types and washability
characteristics of local coals and their
. geographical relationships to mine and power
plant.
Comparison of Conventional and
Gasification Combined Cycle Systems
Though the lack of data for operating
gasification/combined cycle systems precludes
351
-------
ZUU
>—
s
£ 150
CO
o
c?1
CO
u- 100
o
a
CO
CO
5 50
CO
CO
g
0.6 IBS S02/106 BTU
30' FGD EFFICIENCY
_
*'
^ ^t
_ ,»** » FGD
^"^ ONLY
• - , rf"' /.
FGD + / A^***''*^
- CLEANING *~*-^
\ ^-O
». A^
...... i I i i i 1—
0.0 1.0 2.0 3.0 1.0 5.0 6.0
S02 COillEHT OF COAL TO POWER PLANT (LBS/106 BTU)
Figure 16. Effect of SO2 regulation on SO2 mass emissions for three eastern coals (1000 MW nei
3000
1
2530
I
« 2000
o
CO
•eg.
B
1500
0.6 LBS S02/106 BTU
'80% FGD EFFICIENCY
FGD +
CLEANING
• PITTSBURGH SEAM
• LOWER FREEPORT
A INDIANA NO. VII
0.0 1.0 2.0 3.0 1,0 5.0 6,0
SO, CONTENT OF COAL TO POWER PLANT (LBS/10f BTU)
Figure 17. Effect of S02 emission regulation on total solid waste generation for three eastern coals
(1000 MWnet)
352
-------
rigorous comparisons with a conventional
steam-electric plant it is illustrative to examine
the environmental consequences implied by
typical current designs. Table 9 shows the ef-
fect of component energy penalties on the net
cycle heat rates for two conventional systems
and two gasification system designs. For the
gasification system the "best case" design
assumes that all steam and electrical re-
quirements needed for desulfurization and
wastewater treatment are supplied by recovery
or use of waste heat. The "worst case" design
assumes that no waste heat can be
economically utilized so that all steam and elec-
tricity requirements for environmental control
systems incur an energy penalty that requires
additional coal input to maintain the same net
plant output. The wide bounds suggest the
TABLE 9
EFFECT OF SYSTEM ENERGY PENALTIES ON
NET CYCLE HEAT RATE FOR A PLANT PRODUCING 1000 MW NET OUTPUT
(Btu per KWH)
(Assuming Pittsburgh Seam Coal and 0.6 Ibs S02/10® Btu Coal Input)
System or
Component
Electric Power
Generation
Coal Mining
Equipment
Coal Preparation:
Equipment
Coal Refuse
Primary Coal
Pulverizer
Coal Gasifierc
Flyash Collection
Sulfur Removal &
Recovery System''
Water Cooling
and Treatment6
Conv. Plant
w/Limestone
FGD
8,980
55
0
0
25
-
20
345
195
Conv. Plant
w/cleaning
8. FGD
8,980
60
55
715
15
-
20
300
190
Current Gasification/Comb. Cycle
Best Case8
7,795
55
95
0
-•
2,440
10
165
70
Worst Caseb
8,365
75
130
0
-
3,175
20
1,515
795
Net Cycle Heat Rates:
Based on coal
energy mined
Based on coal
input to plant
Based on fuel gas
fromgasifier
9,620
9,565
n/a
10,220
9,505
n/a
10,630
10,575
8,190
14,075
14,000
11,315
8Assumes all energy for desulfurization and wastewater systems is supplied using waste heat.
^Assumes all energy for desulfurization and wastewater systems incurs a penalty requiring additional coal input.
cModeled after Bureau of Mines air-blown stirred bed gasif ier.
^For conventional plant, includes limestone FGD system and its auxiliaries. For gasification plant, includes Benfield acid gas
removal, Claus recovery plant and Wellman-Lord tailgas plant.
Includes cooling tower penalty for all Rankine power cycles, plus ammonia recovery, h^S stripping and biological oxidation
for gasification plant.
353
-------
sizable impact that environmental control
system design and performance could have on
the viability and environmental impact of
gasification-based technologies. If efficient
designs can indeed be implemented the overall
efficiency of current gasification/combined cy-
cle technologies comes quite close to that of
conventional systems (based on coal energy in-
put to the plant). If current designs cannot be
realized, gasification is far less efficient than
conventional practice. Table 9 suggests that
other perspectives of the cycle thermal efficien-
cy are also possible depending on how one
chooses to define the "system."
In terms of environmental impact, com-
parisons between gasification and conven-
tional technologies will depend significantly on
future regulatory policy. If coal gasification
cycles are subject to the same standards now
applicable to direct coal-fired plants the S02
mass emissions will depend on the net cycle
heat rate (thermal efficiency) based on coal
energy input. Figure 18 shows that the current
NSPS would result in higher S02 emissions us-
ing present gasification technology, which is
less efficient than conventional technology.
Lower emissions would result with future,
more efficient designs. On the other hand, if
best available control technology must be
used, even current gasification processes
would achieve lower S02 emissions than con-
ventional plants using FGD. TSP emissions
would also be virtually eliminated, as it must be
to prevent turbine blade erosion. NOX levels
would be less than half current NSPS limits for
coal-fired boilers if gas-fired standards could be
achieved. However, there is considerable
uncertainty about NOX emissions; they may
well be as large or larger than from present
coal-fired plants.191 Finally, less efficient proc-
esses will also incur increased coal mining and
associated solid waste generation impacts
described earlier.
ANALYSIS OF CROSS-MEDIA TRADEOFFS
Given an ability to characterize environmen-
tal effluents from different regulatory
strategies, the key issue becomes one of defin-
ing the levels that are acceptable in light of the
tradeoffs that are known to occur. To do this
rigorously (Figure 1) requires considerably
more knowledge than we have today concern-
ing the transport and transformation of
pollutants in the environment and their
resulting effects on human health and the
ecology. Clearly, more scientific research is
needed to provide a stronger basis for policy
decisions.
Development of regulations and standards,
however, has seldom been hampered by a lack
of scientific knowledge. Where data are lack-
ing, personal and societal value judgments play
an increasingly important part in public policy.
These reflect people's concerns and percep-
tions regarding levels of environmental risk,
economic costs, aesthetic values, political
judgments and other concerns that are not
often articulated in the development of en-
vironmental policy. One aspect of the CMU
research on cross-media impacts and tradeoffs
concerns the development of methodologies
that incorporate both scientific and nonscien-
tific criteria. Two approaches are currently be-
ing explored.
Weighted Emissions Inventory
One approach being pursued involves the use
of subjective and objective weighting factors
for pollutant species and environmental media.
This approach was devised by Reiquam, et al.,
at Battelle Memorial Institute1161 and yields a
numerical parameter called the Environmental
Degradation Index (EDI). This weighted inven-
tory technique was refined by Dunlap artd
McMichael at CMU to explicitly display the con-
sequences of alternative values and scientific
judgments.1171 The result is a "strategy
preference plot," illustrated in Figure 1 9 for an
industrial wastewater control problem. Follow-
ing the Battelle methodology, the EDI varies
with judgments as to the relative importance of
air, land, and water as a depository for wastes
(reflected by an allocation of 1,000 points).
Assumptions regarding the relative damage of
pollutant emissions are also incorporated into
this methodology. The important point is that
when sensitivity analyses are used to explore a
wide range of uncertainty in the value of key
parameters, the conclusion repeatedly reached
for this particular problem is that an in-
termediate rather than a high level of control is
354
-------
w
01
CJl
O
V)
to
140
120
100
80
60
3 40 _
O-
ct±
§
20
1.2
80
CONVENTIONAL PLANT
'WITH LIMESTONE FGD
(9,565 BTU/KWH)
1.0
(ASSUMES 1000 nw NET
ELECTRICAL OUTPUT
USING PITTSBURGH
SEAM COAL)
LOW-BTU/COMB. CYCLE
BEST CASE" DESIGN
WITH 99.42 S-RECOVER
(10.575 BTU/KWH)
\
I
85
0.3
0.6
90
O.I!
0.2
- 1 LBS S02/
0.0 106 BTU
95
100
S02 EMISSION LEVEL AT POWER PLANT ONLY
REMOVAL
0 200 100 600 300 1000
VALUE ASSIGNED TO WATER MEDIUM
(REMAINING VALUE DIVIDED EQUALLY TO AIR AND LAND)
5
5
Figure 18. Comparison of SO2 emissions from present conventional
and low Btu/combined cycle plants.
Figure 19. Strategy preference plot for an industrial
wastewater problem.
-------
the optimal strategy for minimizing en-
vironmental degradation. This is in contrast to
current regulatory policy which requiries the
highest level of control for wastewater constit-
uents, but ignores the substantial negative im-
pacts on other enviornmental media that are in-
troduced. Articulation of such tradeoffs and
their relationship to value judgments is an im-
portant step in developing regulatory policies
that are in the best interests of overall en-
vironmental quality.
Multi-Attribute Utility Theory
Recently we have also begun to examine the
applicability of multi-attribute utility theory
(MAUT) to the cross-media problem. This
refers to a quantitative body of theory
developed during the past decade that ad-
dresses the problem of making decisions to
complex problems when there are multiple
desirable objectives, all of which are not
simultaneously obtainable. Practical applica-
tions of this theory have been relatively limited
but have proved useful in the identification of
policy tradeoffs into other types of
problems.I18'20) The application of MAUT to
cross-media analysis is in the explicit
preference characterization for different levels
of selected pollutants reaching different en-
vironmental media. To date, such preferences
have either been mandated by law (e.g., new
source standards and ambient quality stand-
ards) or have been decided on a case-by-case
basis. Disagreement over preferences have
usually revolved around the relative importance
of multiple specific goals. In power plant siting
issues, for example, there is little disagreement
that reduction of adverse environmental im-
pacts is a worthwhile goal; rather, there is
disagreement as to how much reduction is ap-
propriate in light of expected adverse impacts
and other nonenvironmental considerations.
Multi-attribute utility theory provides a
framework which can explicitly describe the
values or preferences of different groups or in-
dividuals, indicating where and by how much
they differ. From this clearer understanding the
magnitude of differences can frequently be
reduced during further discussions to arrive at
optimal decisions. Implementation of MAUT in-
volves a structured interview/questionnaire
with "decision-makers" from various parties as
interest. At CMU, preliminary research has
been conducted with representatives of electric
utility companies, state environmental control
agencies, and local citizen groups treating the
cross-media problem in the context of siting a
new coal-fired power plant. Focusing on
tradeoffs among S02, heat and particulates to
air, ash and FGD sludge to land, and heat to
water, this preliminary work showed that the
"utility functions" (quantitative value system)
of these groups could indeed be characterized
using the interview format that was devised.
This work remains in progress and will be
reported on at a future time.
CONCLUSION
The environmental impact of coal utilization
technologies is a complex function of process
design, coal properties, and environmental con-
trol technology. Regulatory policy for en-
vironmental control is a key element in this
equation. Historically, regulations and stand-
ards limiting the emission of pollutants to air,
land, and water have been promulgated
without rigorous analysis of the secondary im-
pacts and cross-media effects that adversely
influence environmental quality. This paper has
described an approach being developed at
Carnegie-Mellon University to systematically
address such issues as they apply to conven-
tional and advanced technologies producing
electricity from coal. Illustrations showed the
effect of different S02 constraints on the
secondary production of pollutants that offset
the improvements due to S02 reduction alone.
Preliminary comparisons of conventional plants
and gasification/combined cycle systems were
also given. The continuing focus is on careful
assessment of the system residuals emitted to
various environmental media as a function of
process design, coal characteristics, en-
vironmental control technology, and en-
vironmental regulatory policy. Future efforts
will couple this with a cross-media analysis in-
corporating value judgments and economics to
provide greater insight as to the nature of op-
timal environmental regulatory policy for coal
utilization technologies.
356
-------
ACKNOWLEDGMENTS
This research is supported by the U.S.
Energy Research and Development Administra-
tion (Brookhaven National Laboratory), the
Pennsylvania Science and Engineering Founda-
tion, and the Middle Atlantic Power Reseach
Committee.
REFERENCES
1. E. S. Rubin and F. C. McMichael, "Impact
of Regulations on Coal Conversion
Plants," Environmental Science and
Technology, Vol. 9, No. 2, February
1975.
2. Private Communication, U.S. En-
vironmental Protection Agency, Durham,
North Carolina, 1977.
3. M. J. Massey and R. W. Dunlap, "En-
vironmental Assessment Activities for the
ERDA/AGA Hi-Btu CoalGasification Pilot
Plant Program," Paper presented at 8th
Annual Synthetic Pipeline Gas Sym-
posium, Chicago, Illinois, October I976.
4. M. G. Morgan, et al., "A Probabilistic
Methodology for Estimating Air Pollution
Health Effects from Coal Fired Power
Plants," to appear in Energy Systems and
Policy, 1978.
5. J. A. Cavallaro, et al., "Sulfur Reduction
Potential of the Coals of the United
States: A Revision of Report of Investiga-
tions 7633," U.S. Bureau of Mines, Rl
8118, Pittsburgh, Pennsylvania, 1976.
6. R. L. Torstrick, "Shawnee Limestone-
Limestone Scrubbing Process," Summary
Description Report, Tennessee Valley
Authority, Muscle Shoals, Alabama,
1976.
7. D. R. Carnahan, et al., "Optimum Energy
Utilization in Limestone Flue Gas
Desulfurization Systems," Department of
Mechanical Engineering,Carnegie-Mellon
University, Pittsburgh, Pennsylvania,
February 1977.
8. "Evaluation of Pollution Control in Fossil
Fuel Conversion Processes," Series of
reports prepared by Exxon Research and
Engineering Company, EPA-650/2-74-
009a through EPA-650/2-74-009m,
U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina,
January 1974 through October 1975.
9. F. L. Robson, et al., "Fuel Gas En-
vironmental Impact," Report No. EPA-
600/2-76-153, Prepared by United
Technologies Research Center, for U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina,
June 1976.
10. "Comparative Assessment of Coal
Gasification Emission Control Systems,"
Report No. 9075-030, Prepared by Booz-
Allen Applied Research, for the Industrial
Studies Branch, U.S.E.P.A., October
1975.
11. "Economics of Current and Advanced
Gasification Processes for Fuel Gas Pro-
duction," Report No. EPRI AF-244, Pro-
ject 239, Prepared by Fluor Engineers and
Constructors, Inc., for Electric Power
Research Institute, Palo Alto, California,
July 1976.
12. "Evaluation of Background Data Relating
to New Source Performance Standards for
Lurgi Gasification," Report No. EPA-
600/7-77-059, Prepared by Cameron
Engineers, Inc., for U.S. Environmental
Protection Agency, Research Triangle
Park, North Carolina, June 1977.
13. R. G. Luthy, et al., "Analysis of
Wastewaters from High Btu Coal Gasifica-
tion Plants," Paper presented at the 32nd
Purdue Industrial Waste Conference,
Lafayette, Indiana, May 1977.
14. M. J. Massey, et al., "Characterization of
Effluents from the Hygas and C02 Accep-
tor Pilot plants," Report No. FE-2496-1,
U.S. ERDA, Washington, D.C., November
1976.
1 5. Private Communication, Benfield Corpora-
tion, Pittsburgh, Pennsylvania, 1977.
16. H. Reiquam, et al., "Assessing Cross-
Media Impacts," Environmental Science
and Technology, Vol. 9, No. 2, February
1975.
17. R. W. Dunlap, and F. C. McMichael,
"Reducing Coke Plant Effluent," En-
vironmental Science and Technology,
Vol. 10, No. 7, July 1976.
357
-------
18. R. L. Keeney, "A Decision Analysis with Criteria Decision Making. New York:
Multiple Objectives: The Mexico City Air- Springer-Verlag, 1 976, pp. 293-302.
port," Bell J. Econ. Manag. Sci.,
4:101-117, 1973. 20. W. Edwards, "How to Use Multiattribute
19. R. L. Keeney, "Quantifying Corporate Utility Measurement for Social Decision-
Preferences for Policy Analysis," in H. making," IEEE Trans. Syst. Man and
Thiriez and S. Zionts (eds.) Multiple Cyber.. SMC-7:326-340, 1977.
358
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Session III: CONTROL TECHNOLOGY DEVELOPMENT
A. G. Sliger
Chairman
359
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SELECTION OF ACID GAS
TREATING PROCESSES FOR COAL
CONVERTER OUTPUTS
S. E. Stover and F. D. Hoffert
Hydrocarbon Research, Inc.
Research and Development Division
Lawrence Township, New Jersey 08648
Abstract
Many factors must be evaluated in the selec-
tion of acid gas removal processes for coal-
derived converter output gases. Some of these
considerations, among others, include the
gasification process, the sulfur content of the
coal, the presence of other contaminants and
their effects, the end use of the product, and
the multitude of clean-up processes and their
economics. While the limited scope of this
paper will not permit an in-depth examination
of such a complex subject, some generalization
will be discussed and applied to some typical
cases. One aspect to be discussed is the in-
fluence of the sulfur content of coal on the
selection process for different converter
systems. Typical situations to be examined in-
clude a high pressure (WOO psi) case for SNG,
an intermediate pressure (400 psi) case for tur-
bine fuel, and a low pressure (atmospheric
pressure or slightly above) for industrial fuel,
Generalization for the selection of acid gas
treating processes on coal converter output
gases is not easily made. Many different fac-
tors must be evaluated in order to select from
an expanding list of available acid gas removal
processes. It will only be possible to examine a
few of these aspects within the limited scope
of this paper.
One of the most important factors, the sulfur
content of coal, provides a starting point for
this discussion. Sulfur reports to the output gas
primarily as H2S almost proportionately to its
content in coal. The particular process used for
gasification of the coal has a relatively minor in-
fluence.
In contrast, the carbon dioxide content of gas
is greatly dependent on the gasification
system. A generalized gasifier performance
chart illustrating the carbon dioxide fraction of
carbonaceous product gases as a function of
H2/CO ratio is given in Figure 1. In some cases,
reactions like the water gas reaction, combus-
tion and methanation proceed further and con-
tribute to variation in product composition.
The difference in the way that sulfur and car-
bon report is significant because the H2S/C02
ratio and the carbon dioxide partial pressure in
the converter output gas is relevant to acid gas
removal process selection. Solution oxidation
processes such as Stretford or Takahax, which
remove H2S and convert it directly to sulfur, re-
quire a high pH in the absorbent solution. High
C02 concentration lowers the solution pH, and
in turn, the rate of H2S mass transfer in the
Stretford solution. As a result, many Stretford
process absorbers have ended up being ex-
tremely large towers to compensate for low
mass transfer rates. The Holmes version of the
Stretford process uses an improved gas-
solution contacting technique, but even so,
high C02 concentrations must still be con-
sidered carefully when using this process.
The general practice of industry for bulk acid
gas clean-up has been to absorb the acid gas
from the product gas, convert the H2S to sulfur
by the Glaus process and now, to meet en-
vironmental demands, clean-up the Claus tail
gas with a third process. To become the
favored method for bulk acid gas clean up, the
selected step-wise approach was undoubtedly
governed by economics, and the effect of the
gas on solution pH certainly was a contributing
factor. Because the Claus process has been so
important in most acid gas removal schemes,
the influence of sulfur in coal and converter
output on the Claus process must be factored
into the selection of acid gas removal proc-
esses.
Let's look at some typical converter output
gas compositions in Table 1. A general, but
perhaps not all inclusive, range of gas composi-
tions from low to high C02 contents are shown
for both oxygen and air blown converters. The
data is presented on a dry and sulfur-free basis.
Bi-Qas and Wilputte data have been included
for later use.
A stoichiometric conversion of sulfur in coal
to H2S in the output gas may be used to
develop an equation for an H2S/C02 ratio in the
raw product gas as a function of percent sulfur
361
-------
LEGEND
0.7 i
0.6 -
E
0.5 -
+ 0.4 _
o
o
04
O
0.3 -
CM
O
o
0.2 _
oc
CM
O
O
A
O
D
©
H
O
Ri ley-Morgan
WMputte
Winkler
Woodal 1-Duckham/Gas Integrale
Wei Iman-Galusha
Koppers-Totzek
Lurgi
Fixed Bed Generator (Anthracite)
Morgantown, W. Va. Data
e
0.1 -
—I
3.0
0.5
1.0
1.5 2.0
H2/CO Ratio
2.5
Figure 1. Generalized performance of gasifiers.
362
-------
TABLE 1
TYPICAL CONVERTER OUTPUT GAS COMPOSITIONS
DATA SOURCE
C02 CONTENT
COMPONENTS, VOL.
co2
CO
H
OXYGEN BLOWN PROCESSES
KOPPERS BI-GAS LURGI
-TOTZEK
LOW
57
35
22
29
32
CM/,
16
HIGH
32
17
AIR BLOWN PROCESS
WELLMAN- WILPUTTE LURGI
GALUSHA
LOW
HIGH
10
3
29
15
50
3
6
23
17
50
4
15
15
2*
40
6
BASIS: DRY AND SULFUR-FREE GAS
363
-------
in coal. This ratio designated by the letter Y in
Table 2 will later be used to provide a guide for
determining the need for selective H2S
removal. To correct for losses to other sulfur
outlets such as tar or ash, a correction factor,
Sr, has been applied. The conversion efficien-
cy, E, used by the equation is the percent of
output gas Btu content divided by the Btu con-
tent of the process coal. For simplicity, the
sulfur recovery and efficiency factors have
been arbitrarily set at values of 100 and 75 in
the remaining discussion. A sample calculation
for a 5 percent sulfur coal is also shown in
Table 2.
In Figure 2, a plot of the H2S ratio versus per-
cent sulfur in coal has been made using points
calculated from the M2S/C02 ratio equation as
boundary lines. Data taken from actual gasifier
operation have been plotted to support the
theoretical analysis. Note that the Koppers-
Totzek points fall just about on the upper line.
The other data points fall within the general
area of these arbitrary boundaries to form a
typical area of operation.
Two horizontal lines equivalent to 1 0 and 1 5
percent H2S in acid gas have been incorporated
on the H2S ratio graph in Figure 3. These
values1 were chosen because the economic use
of the Claus process probably becomes
marginal at about this range. One point evident
from this chart is that selective absorption of
H2S will, in many cases, be necessary when us-
ing the Claus process. Physical solvents are
well known for their selective absorption
capabilities and will, consequently, find ap-
propriate applications in coal gasification.
Some chemical solvents do have some selec-
tive absorption capability and this aspect will
have to be taken carefully into account in coal
gasification applications.
Now let's take a few coal gasification cases
and examine what might be considered in the
selection of acid gas removal processes. As
might be expected, it will not be possible to
present a cookbook approach to an undisputed
choice for acid gas removal, but some points to
be taken into account will be covered including
selections using a recently published
guideline.2 The cases which were made to
represent typical future situations are:
I. Coal gasification at the 1000 psi level for
SNG manufacture and shown in Tables 3
and 4.
II. Coal gasification at the 400 psi level for
turbine fuel and shown in Tables 5 and 6.
III. Coal gasification just above atmospheric
pressure for industrial fuels and shown in
Tables 7 and 8.
Process recommendations which were il-
lustrated in Tables 4, 6, and 8 were physical
solvent acid removal processes for the two
high pressure cases and a chemical conversion
process for the low pressure application. The
major missing ingredient in this discussion is
comparative economics. The reason is that this
information is so difficult to obtain and has
such a fragile nature when available. It depends
so much on the specifics of the particular ap-
plication, the environmental constraints, the
periods of time and even individual discretion in
process and cost estimation. However, some
guidelines have been demonstrated and, in par-
ticular, a look at the estimated acid gas com-
position from coal and its impact on process
selection has been illustrated by examples.
REFERENCES
1. R. F. Robards, et al., Evaluation of H2S
Removal Process for Desulfurization of
Coal Gas, Fourth Energy Resource Con-
ference, January 7-8, 1 976, University of
Kentucky, Lexington, Kentucky.
2. R. N. Tennyson and R. P. Schaaf,
"Guidelines Can Help Choose Prop-
er Process for Gas-Treating Plants," Oil
and Gas Journal, January 10, 1977.
3. B. S. Lee, "Hygas Pilot Plant Yields
Operating Data," Oil and Gas Journal,
February 11,1 974.
4. J. F. Farnsworth, et al., "Coal Gasifica-
tion System Could Ease Energy Supply
Pinch," 33 Magazine/The Magazine of
Metal Producing, August 1973.
5. L. L. Newman, "Oxygen In the Production
of Hydrogen or Synthesis Gas," Industrial
and Engineering Chemistry, Vol. 40, No.
4, April, 1948.
6. HRI Files on Lurgi data collected in
technical mission to Europe after World
War II. (Hydrocarbon Research, Inc. is a
wholly owned subsidiary of Dynalectron
364
-------
TABLE 2
SULFUR RATIO IN CONVERTER OUTPUT GAS
AN EQUATION FOR THE RATIO OF HYDROGEN SULFIDE TO
CARBON DIOXIDE IN CONVERTER OUTPUT GAS IS:
11.82 [ScSrHg
(Sc Sr Hg )
\C E He/
WHERE:
Y = H2S TO COa RATIO IN RAW OUTPUT GAS
Sc = PERCENT BY WEIGHT SULFUR IN COAL
Sr = PERCENT SULFUR REPORTING TO OUTPUT GAS
Hg = HIGH HEATING VALUE OF THE OUTPUT GAS
C = PERCENT BY VOLUME C02 IN OUTPUT GAS
E = COAL TO GAS PERCENT EFFICIENCY
He = HIGH HEATING VALUE OF THE COAL
ASSUMPTION: ALL SULFUR IN OUTPUT GAS AS H2S
EXAMPLE CALCULATION:
Y- 11.82 I5.Q x 100 x 300A = 0.281
(5.0 x 100 x 300]
\7 x 75 x 12,000^
H2S/C02 Ratio
365
-------
0.3
LEGEND
HYGAS3
KOPPERS-TOTZEK**
LURGI5' 6» 7
RI LEY-MORGAN
0.2
Q
O
a:
Q.
7^ C02 IN GAS
751 COAL TO GAS EFFICIENCY
100% SULFUR RECOVERY IN GAS
CM
O
CO
CS
0. :
0.0
32% C02 IN GAS-
60% COAL TO GAS EFFICIENCY
75% SULFUR RECOVERY IN GAS
GENERAL AREA OF
GASIFIER OPERATION
1 2 3
PERCENT SULFUR IN COAL
Figure 2. Sulfur transfer to gas in coal gasification.
366
-------
0.3 T
0.2
Q
O
o
o
to
es
0.1 .
0.0
DESIRABLE RANGE FOR
CLAUS PLANT FEED
IN ACID GAS
7% C02 IN GAS
COAL TO GAS EFFICIENCY
100% SULFUR RECOVERY IN GAS
MARGINAL RANGE FOR
CLAUS PLANT FEED
IN ACID GAS
UNDESIRABLE RANGE FOR
CLAUS PLANT FEED
60% EFFICIENCY
75% SULFUR RECOVERY
2 3
PERCENT SULFUR IN COAL
Figure 3. Sulfur transfer to gas in coaJ gasification.
367
-------
TABLE 3
EXAMPLE I - GAS REMOVAL SELECTION FACTORS
STUDY BASIS: CONVERTER PRESSURE SULFUR IN COAL END USE
BI-GAS ~1000 PSI k% SNG
GENERAL CONSIDERATIONS
0 LOW LEVELS OF H2S AND C02 ARE REQUIRED
0 CONSERVATION OF GAS HEAT CONTENT IS DESIRABLE
STRETFORD PROCESS CONSIDERATIONS
0 CONVERTER OUTPUT C02 IS 22% OR /V200 PSI PARTIAL PRESSURE
0 C02 PARTIAL PRESSURE IS TOO HIGH
CLAUS PROCESS CONSIDERATIONS
Y = 11.82 fsc Sr Hg\ = 11.82 x 4 x 100 x 360 = 0.086
VC E He/ 22 x 75 x 12,000
0 H2S PARTIAL PRESSURE IN PRODUCT GAS - ~20 PSI
0 H2S PERCENT OF TOTAL ACID GAS = B%
0 SELECTIVE ABSORPTION IS REQUIRED FOR CLAUS ECONOMY
368
-------
TABLE 4
EXAMPLE I - ACID REMOVAL PROCESS RECOMMENDATIONS
STUDY BASIS: CONVERTER PRESSURE SULFUR IN COAL END USE
BI-GAS ~1000 PS I l*% SNG
GUIDELINE2 CHOICES
0 SIMULTANEOUS REMOVAL OF H2S AND C02
ABOVE 75 PS I ACID GAS PRESSURE IN FEED AND BELOW 1 PS I ACID
GAS PRESSURE IN PRODUCT - ECONOMINE, HIGH LOADING DEA OR
SELEXOL
0 SELECTIVE H2S REMOVAL IN PRESENCE OF C02
3 TO 60 PS I H2S PRESSURE - ADIP
ABOVE 60 PS I H2S PRESSURE - RECTISOL OR SELEXOL
0 COMMENT: USE SELECTIVE ABSORPTION TO IMPROVE CLAUS FEED
SPECIAL CONSIDERATIONS (COAL DERIVED GAS PROCESSED TO SNG)
0 ADIP - PARTICULATES, TARS AND OILS CAN CAUSE FOAMING
- CS2, MERCAPTANS, COS CAUSE SOLVENT LOSSES
0 RECTISOL - APPLIED AT SASOL PLANT
- REMOVES COS, CS2 AND HCN
- REFRIGERATION: EXPENSIVE AND HEAT LOSSES
0 SELEXOL - SOLVENT NOT DEGRADED BY IMPRUITIES
- REMOVES SOME COS, CS2, NH3 AND HCN
RECOMMENDATIONS ,
0 SELEXOL WOULD BE A GOOD SELECTION AND IT HAS BEEN CHOSEN FOR
BI-GAS PILOT PLANT AT HOMER CITY
0 FINAL DECIDING FACTOR DEPENDS ON ECONOMICS AND TEST RESULTS
369
-------
TABLE 5
EXAMPLE II - ACID GAS REMOVAL SELECTION FACTdRS
STUDY BASIS: CONVERTER PRESSURE SULFUR IN COAL END USE
AIR BLOWN LURGI s^kOQ PS I k% TURBINE FUEL
GENERAL CONSIDERATIONS
0 SULFUR REMOVAL REQUIREMENTS LESS STRINGENT THAN FOR SNG
0 CONSERVATION OF GAS HEAT CONTENT IS DESIRABLE
0 C02 REMOVAL IS UNDESIRABLE
STRETFORD PROCESS CONSIDERATIONS
0 CONVERTER OUTPUT C02 IS 15* OR "^60 PSI PARTIAL PRESSURE
0 C02 PARTIAL PRESSURE IS PROBABLY TOO HIGH
0 LOWER HEAT EFFICIENCY THAN HIGH TEMPERATURE PROCESSES
HIGH TEMPERATURE PROCESS CONSIDERATIONS
0 FRODINGHAM AND OTHER DRY IRON OXIDE PROCESSES
- UNDER DEVELOPMENT OR NOT YET PROVEN
- S02 BY-PRODUCT
0 HOT CARBONATE PROCESS
- ALKALI METAL CARRY-OVER IS VERY DAMAGING TO TURBINE
- BEING TESTED FOR THIS APPLICATION AT POWERTON PLANT IN ILLINOIS
CLAUS PROCESS CONSIDERATIONS
Y = 11.82 fsc Sr Hg\ = 11.82 x k x 100 x 180 = 0.063
VC E Hey 15x75x 12,000
H2S PARTIAL PRESSURE IN PRODUCT GAS » /%/A PSI
H2S PERCENT OF TOTAL ACID GAS = 6%
370
-------
TABLE 6
EXAMPLE II - ACID GAS REMOVAL PROCESS RECOMMENDATIONS
STUDY BASIS: CONVERTER PRESSURE SULFUR IN COAL END USE
AIR BLOWN LURGI ~400 PS I k% TURBINE FUEL
GUIDELINE2 CHOICES
0 SELECTIVE H2S REMOVAL IN PRESENCE OF C02
3 TO 60 PS I H2S PRESSURE - AD IP
BELOW 3 PS I H2S PRESSURE - STRETFORD, VETROCOKE OR AD IP
SPECIAL CONSIDERATIONS (COAL-DERIVED GAS PROCESSED TO TURBINE FUEL)
0 AD IP - PARTICULATES, TARS AND OILS CAN CAUSE FOAMING
- CS2, MERCAPTANS, COS CAUSE SOLVENT LOSSES
0 VETROCOKE - CONTAINS ARSENIC AND ALKALI SALTS
FRODINGHAM - NOT ESTABLISHED AND S02 PRODUCT
o
0 HOT CARBONATE - POTENTIAL PROBLEM WITH ALKALI SALT
RECOMMENDATIONS
0 PHYSICAL SOLVENT PROCESS
0 FINAL DECIDING FACTOR WOULD PROBABLY DEPEND ON ECONOMICS
371
-------
TABLE 7
EXAMPLE III - ACID GAS REMOVAL SELECTION FACTORS
STUDY BASIS: CONVERTER PRESSURE SULFUR IN COAL END USE
WILPUTTE ABOVE ATMOSPHERIC k% INDUSTRIAL FUEL
GENERAL CONSIDERATIONS
0 SPECIFIC END USE WILL BE INFLUENTIAL
0 SULFUR REMOVAL REQUIREMENTS LESS STRINGENT THAN FOR SNG
0 C02 REMOVAL PROBABLY NOT NECESSARY
STRETFORD PROCESS CONSIDERATIONS
0 SATISFACTORY FOR LOW H2S PARTIAL PRESSURES
0 SELECTIVELY REMOVES H2S
0 LOW C02 PARTIAL PRESSURE IS AVAILABLE
CLAUS PLANT CONSIDERATIONS
Y = 11.82 fsc Sr Hg\ = 11.82 x k x 100 x 160
\C E He J 6 x 75 x 12,000
0 H2S PARTIAL PRESSURE IN PRODUCT GAS = ~ 0.2 PS I
0 H2S PERCENT OF TOTAL ACID GAS = 12%
0 SELECTIVE ABSORPTION SUGGESTED FOR CLAUS ECONOMY
372
-------
TABLE 8
EXAMPLE III - ACID GAS REMOVAL PROCESS RECOMMENDATIONS
STUDY BASIS: CONVERTER PRESSURE SULFUR IN COAL END USE
WILPUTTE ABOVE ATMOSPHERIC k% INDUSTRIAL FUEL
GUIDELINE2 CHOICES
0 SELECTIVE H2S REMOVAL IN PRESENCE OF C02
BELOW 3 PS I H2S PARTIAL PRESSURE - STRETFORD, VETROCOKE OR AD IP
SPECIAL CONSIDERATIONS (COAL-DERIVED GAS TO INDUSTRIAL FUEL)
°ADIP - PARTICULATES, TARS AND OILS CAN CAUSE FOAMING
- CS2, MERCAPTANS, COS CAUSE SOLVENT LOSSES
0 VETROCOKE - CONTAINS ARSENIC
0 STRETFORD: ADDITIONAL POINTS FOR THE APPLICATION
- PREVIOUSLY APPLIED TO COAL DERIVED GASES
- NITROGEN COMPOUNDS, IF TOO HIGH TO BE TOLERATED,
CAN BE REMOVED BY PRETREATMENT
- MAKES ELEMENTAL SULFUR
RECOMMENDATION
0 SOLUTION OXIDATION PROCESS SUCH AS STRETFORD
373
-------
Corporation.) 8. A. H. Rawdon, et al., NOX Fbrmation in
R. E. Morgan, et al., Lurgi-Gasifier Tests Low and Intermediate Btu Coal Gas
of Pennsylvania Anthracite,. Bureau of Turbulent-Diffusion Flames, Proceedings
Mines, Report of Investigations 5420, N0x Control Technology Seminar, EPRI,
1958. San Francisco, February 1976.
374
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A COAL GASIFICATION —
GAS CLEANING TEST FACILITY
J. K. Ferrell, R. M. Felder,
R. W. Rousseau, D. W. Alexander
North Carolina State University
Department of Chemical Engineering
Raleigh, North Carolina 27607
Abstract
A general purpose coal gasification - gas
cleaning facility is being constructed at North
Carolina State University for research on ef-
fluents from coal gasification processes. The
facility consists of a continuous, fluidized bed
gasifier; a particulates, condensables, and
solubles removal system; and an acid gas
removal system. The gasifier operates at
pressures up to WOpsig, has a capacity of 50
pounds of coal per hour, and can be run with
either air or oxygen. The acid gas removal
system is modular in design so that alternative
absorption processes can be studied.
The facility is described in detail, the objec-
tives of the research program are outlined, and
details of the experimental plan are presented.
INTRODUCTION
Methods to gasify coal and to purify the
resulting synthesis gas have been available for
decades; several dozen commercial gasification
processes are currently operable, and many
more are in advanced developmental stages. At
present, however, there is still inadequate
knowledge of the environmental effects
associated with the widespread large-scale im-
plementation of coal gasification technology.
In recognition of this problem, the En-
vironmental Protection Agency has contracted
for the construction of a pilot plant coal
gasification-gas cleaning test facility at North
Carolina State University, to be operated by
faculty and staff of the Department of Chemical
Engineering. The facility consists of a con-
tinuous fluidized bed gasifier, a system for
removing particulates, condensables, and solu-
ble matter (PCS) from the raw synthesis gas,
and an acid gas removal system (AGRS). The
gasifier operates at pressures up to 100 psig,
has a capacity of 50 Ib coal/hr, and can run
with either steam -02 or steam-air feed mix-
tures. The AGRS is modular in design, so that
alternative absorption processes may be
evaluated with a minimal amount of system
modification being required.
The overall objective of the project is to
characterize completely the gaseous and con-
densed phase emissions from the gasification-
gas cleaning process, and to determine how
emission rates of various pollutants and
methanation catalyst poisons depend on ad-
justable process parameters.
Specific tasks to be performed are as follows:
1. Identify and measure the gross and
trace species concentrations in the
gasifier product, including concentra-
tions of sulfur gases (H2S, COS), con-
densable organics (e.g. BTX and
polynuclear aromatic hydrocarbons),
water-soluble species (e.g. ammonia,
cyanates, cyanides, halides, phenols,
sulfates, sulfides, sulfites, and thio-
cyanates), and trace metals (e.g. an-
timony, arsenic, beryllium, bismuth,
cadmium, lead, mercury, selenium, and
vanadium).
2. Correlate measured emission levels
with coal composition and gasifier
operating variables, particularly
temperature, pressure, and solid and
gas phase residence time distributions.
3. Perform material balances around the
gasifier, the raw gas cleanup (PCS)
system, and the acid gas removal
system, and determine the extent to
which selected species are removed
from the synthesis gas in each of the
components.
4. Correlate measured removal efficien-
cies for various species with system
operating variables, including
temperatures, pressures, holdup times,
and solvent circulation rates.
5. Evaluate and compare the performance
characteristics of alternative acid gas
removal processes, considering both
C02 and H2S removal capabilities and
the degrees to which the processes
remove trace pollutant species from the
sour synthesis gas. Evaluate the
375
-------
buildup of contaminates in the various
acid gas removal solvents.
6. Use the results obtained in the above
studies to develop models for the
gasification and the gas cleanup pro-
cesses. The models will take as input
variables the composition and feed rate
of the coal, bed depth, steam and air (or
oxygen) feed rates and inlet
temperatures, gasifier pressure, and
operating conditions (temperatures,
pressures, solvent flow rates, etc.) for
the gas cleaning systems, and will
predict the coal conversion and the
product gas flow rate and composition,
including trace pollutant levels. The
model will be used as a basis for op-
timizing the pilot plant operating condi-
tions, and for estimating emission
levels for scaled-up versions of the pro-
cesses investigated.
The sections that follow will present a brief
description of the facility, the experimental pro-
gram, and methods of analysis.
THE FACILITY
A sketch of the pilot plant facility is shown in
Figure 1. The sketch is approximately to scale
and shows the location of the major com-
ponents of the plant and the important piping.
Although no scale is indicated on the figure, the
acid gas stripping column is the tallest unit and
is approximately 13.5 meters (44 feet) in
height.
The facility can be divided into nine sub-
systems as listed below:
1. Gasifier, Coal Feed, and Char Handling
2. Particulates, Condensibles, and Sol-
ubles Removal (Raw gas cleaning)
3. Acid Gas Removal
4. Product and By-Product Disposal
5. Sampling and Analysis
6. Measurement and Control
7. Safety
8. Synthetic Gas Mixture
9. Support
Only Items 1, 2, and 3 will be described in
any detail here.
Schematic diagrams of the system are
shown in Figures 2 and 3 and a drawing of the
gasifier is shown in Figure 4. The gasifier is a
fluidized bed unit and was designed by person-
nel at the Illinois Institute of Gas Technology; it
is essentially a copy of a gasifier now in opera-
tion at IGT. Although the gasifier, coal feed
hopper and char receiver vessels are designed
for much higher pressures, the remainder of the
system limits the operation of the gasifier - PCS
system to approximately 100 psig.
The internal dimensions of the gasifier allow
fluidized bed dimensions of 6 inches in
diameter and up to 5 1/2 feet in height. Coal is
fed at the top by a screw feeder from a
pressurized coal feed hopper and char is re-
moved from the bottom into a pressurized char
receiver. The gasifier is instrumented with a
bed height detector, and temperature and
pressure sensors are located at several posi-
tions within the bed. A preheated air-steam or
02-steam mixture is introduced into the bottom
of the gasifier bed.
The raw gas goes to a cyclone separator for
removal of most of the particulates and then to
a venturi scrubber where it is cooled and water
soluble and condensable compounds are
removed. A portion of the effluent is subjected
to further cooling and condensate removal, and
is then sent to the acid gas removal system.
The AGRS consists of an absorber column
for removal of the acid gases, primarily C02
and H2S, and a stripper column for regenera-
tion of the solvent. At least four processes will
be studied: refrigerated methanol, hot
potassium carbonate, monoethanolamine and
Dimethylether of Polyethyleneglycol. Table I
shows the operating conditions expected in
each process. The first process investigated
will use methanol which will also be used for
the plant shakedown and startup runs.
For the methanol system the cool, dry sour
gas is compressed to 500 psig and fed to the
bottom of the absorber column where the C02
and H2S are absorbed. The methanol is in-
troduced into the top of this column at approx-
imately minus 30 degrees Fahrenheit. The acid
gases are stripped with nitrogen in the stripper
column operating at approximately 1 5 psig and
0°F. Although the AGRS is not designed to
duplicate a commercial system, it has sufficient
flexibility to cover the full range of operating
parameters applicable to commercial units.
376
-------
COAL QASinOOION FACILITY
Figure 1
377
-------
Air
M
Compressor
00
o.
N.
Steam
Gasifier
Preheater
Super
Heater
Cyclone
Scrubber
Tank
Figure 2. Gasifier and gas quench system.
-------
Sweet
Gas
Sour
Gas
CO
>4
co
Dehydrator
Absorber
Product Gas
Compressor
Heat
Exchanger
Flash lank Acid
Gas Gas
Flash
Tank
-^-
Solvent
Chiller
1
Stripper
Rich Liquor
Filter
Nitrogen
Lean Liquor
Pump
Figure 3. Acid gas removal system.
-------
Gas Outlet
24in. Schedule 80
Carbon Steel Pipe
Char Inlet
6 in. Schedule 40
316 SS Pipe
Inlet Gas
Distributor
Figure 4. Gasifier cut-away.
380
-------
TABLE 1
ACID GAS REMOVAL SYSTEM OPERATING CONDITIONS
Absorber
Solvent
MeOH
OMPEG
K2C03
MEA
Pressure
(psia)
315-
515
315-
515
115-
315
115-
315
Temperature
(°F)
-30
20
230
120
Stripper
Pressure
(psia)
15-
45
15-
45
20-
55
20=
55
Temperature
(°F)
0
30
230
260
Flash Tank
Pressure
(psia)
115-
215
115-
Not
Used
Not
Used
Composition
Percent
C02
1.7
3.0
0.45
Trace
PPM
H2S
700
500
200
Trace
The excess raw gas, the sweet gas, and the
sour gas are recombined and sent to an in-
cinerator for disposal.
The facility is instrumented so that approx-
imately 100 of the process variables,
temperatures, pressures, flow rates, and liquid
levels, and some chemical compositions are
available in real time for the data acquisition
system. Process control is implemented by a
Honeywell TDC 2000 digital control system.
A schematic diagram of the data acquisition
system is shown in Figure 5. The system also
has the capability of presenting process
variables in engineering units on a real time log
for operator information, computing mass flow
rates, and performing material and heat balance
calculations.
THE EXPERIMENTAL PROGRAM
The experimental program will begin when
the facility is turned over to North Carolina
State University in the late spring or early sum-
mer of 1978.
The first phase of the program will be
devoted to testing the acid gas removal system
using synthetic feed gas mixtures, and
operating the gasifier with a pretreated coal or
char feed—first alone, then in combination with
the AGRS. At the conclusion of this phase of
the program, the following objectives should be
achieved:
The analytical chemical procedures to
measure all gross and trace com-
ponents of interest will be standard-
ized.
Mass transfer coefficients and vapor-
liquid equilibrium parameters for the
methanol absorption system will be
measured, and the C02 and H2S
removal capabilities of the system will
be determined as functions of the
operating temperatures and pressures
of the absorber and stripper units. Also
measured will be the degree to which
the CO and H2 are removed from the
sour synthesis gas, and the rate at
which methanol is lost due to entrain-
ment and evaporation.
The gasifier startup, operating, and
data collection procedures will be
standardized.
The gross and trace emissions from the
gasifier will be measured, and their
levels will be correlated with operating
conditions. Material balances will be
obtained, and the operating
characteristics and efficiency of the
particulate condensation and scrubbing
system will be determined.
The operation of the integrated gasifier
- gas cleaning system will be tested at
several conditions, and the degree to
which the system performance can be
381
-------
VIDEO
DISPLAY
CO
00
ro
85
PROCESS
VARIABLES
A/D
CONVERTER
&
MULTIPLEXER
MICRO-COMPUTER
FLOPPY
DISK
STORAGE
(DPERATOR'S
CONSOLE
Figure 5. Schematic of data acquisition system.
-------
predicted from the models and correla-
tions established in the previous
studies will be determined.
Upon the completion of these studies, the
program will shift to the more difficult task of
operating with a non-pretreated, non-caking
coal. A detailed experimental plan for this stage
of the program will be developed in light of the
first-stage results.
During the first week of operation, the com-
plete gasification facility will be pressure tested
and inspected for physical integrity. Later,
flooding velocities will be determined for the
absorber and stripper at anticipated operating
pressures.
In the remaining six months detailed ex-
perimental work will begin. We will determine
C02, H2S, COS, CO, and H2 transfer rates as
functions of absorber and stripper
temperatures and pressures, solvent circulation
rate, and feed gas inlet temperature. Later the
gasifier will be operated using a pretreated
char. The emission rates of principal synthesis
gas components, sulfur-containing gases,
volatile organics, and trace elements will be
determined. The emission levels will be cor-
related with various operating parameters in an
attempt to develop predictive emission models.
Near the end of the six month period, the
gasifier and AGRS system will be operated as
an integrated unit. These runs will be used to
check the consistency of the results with
predictions based on operation of the individual
system components.
At least three sets of operating conditions for
the gasifier and two sets for the AGRS will be
tested in all six possible combinations: the par-
ticular conditions will be chosen based on the
results of the previous studies.
Sampling
Duplicate grab samples will be obtained from
the sampling points shown in Figure 6. The
sampling will be done during steady state
operation of the pilot plant. Composite sam-
pling will be required for some streams, such as
the aqueous condensate obtained from sam-
pling point 7. Gas samples will be taken using a
sampling train like that shown in Figure 7.
Analytical Procedures
The various chemical species to be
monitored in the gasification unit are shown in
Table II. Elemental analyses will be limited to
those elements in the first two columns of
Table II. The bulk element balances ensure that
the entire stream has been accounted for
before any other analyses are made. The trace
elements selected are those expected to have
the most adverse impacts on the environment
adjacent to a coal gasification facility.
The water-borne compounds and ions of in-
terest include hazardous species such as-
cyanide and cyanate, and industrially important
species, such as benzene, toluene, xylene, and
phenols.
The analysis samples can be classified into
four major types:
1. Solid samples - coal, char, and par-
ticulates.
2. Aqueous liquid samples - feed water,
water condensate, and scrubber water.
TABLE 2
ANALYSES OF INTEREST IN
THE COAL GASIFICATION PROCESS
Trace
Elements
As
Be
Bi
Cd
Hg
Pb
Sb
Se
V
Cr
Bulk
Elements
C
H
N
0
S
Water- Borne
Compounds
ON'
CNO=
CNS=
cr
s=
S03=
S04=
NH4+
Benzene
Toluene
Zylene
Phenols
Gaseous
Compounds
H2
H2
CO
C02
S02
H2S
H20
CH4
C2H6
COS
CH3OH
383
-------
Sweet Flash
Gas Gas
Flash
Tank
Represents a Sample Point
Stripper
Figure 6. Location of sample points.
-------
Gas Line
Particulate
Filter
Rotameter
^_
Temperature
Gauge
-N—o-
/) Pressure
Gauge
(71
Condensing
Bubblers
-N-
»
>
s
S
k • .
"^ """"•
t
Ik
k • b
•""^^ "^ 1
s
s
s
N
t
X X X X
X X X X V V X
-N-
Gas Sampling
Bottles
Figure 7. Prototype gas sampling train.
-------
3. Organic liquids AGRS liquors, organic
fraction of tars.
4. Gaseous samples - product gas, sweet
gas, flash gas, and acid gas.
Whenever applicable, standard ASTM1,
APHA2 and EPA3 methods and procedures will
be used initially; more highly automated
methods of analysis may be substituted for the
manual methods in later stages of the program.
The standard methods will then serve to check
the accuracy and reliability of the instrumental
procedures.
Several instrumental analyses are currently
being developed for use in the program. Trace
elements will be determined by atomic absorp-
tion spectroscopy, neutron activation analysis,
and colorimetric procedures. Gas analyses will
be performed using gas chromatography. Some
water analyses will be performed by atomic ab-
sorption spectrophotometry and selective ion
electrode methods. Total carbon and total
organic carbon in water will be determined us-
ing an FID-based instrumental analyzer. In-
struments that will be used in later stages of
the program include an automated C, H, N, 0, S
analyzer for solid and liquid samples, an
automated titrater, and a microprocessor-
based specific ion electrode meter, and
possibly a mass spectrometer and a liquid
chromatograph.
REFERENCES
1. American Society for Testing and
Materials, 1976 Annual Book of ASTM
Standards.
2. American Public Health Association,
American Water Association, and Water
Pollution Control Fed., Standard Methods
for the Examination of Water and
Wastewater, 14th ed., Washington,
D. C., American Public Health Assoc.,
1976.
3. Environmental Protection Agency,
Methods for Chemical Analysis of Water
and Wastes, Report No. EPA
625/6-74-003, Washington, D. C., Of-
fice of Technology Transfer, 1 974.
386
-------
CONTROL TECHNOLOGY
DEVELOPMENT FOR PRODUCTS/
BY-PRODUCTS OF COAL
CONVERSION SYSTEMS
Sohrab M. Hossain, John W. Mitchell,
and Alfred B. Cherry
Catalytic, Inc., Philadelphia, Pennsylvania
Abstract
The objective of developing control
technologies for the products and by-products
of coal conversion systems is to permit the
fullest utilization of these materials while con-
trolling environmental pollution within ac-
ceptable levels. Products are defined as the
primary marketable materials such as low,
medium and high Btu gas; liquefied and so/vent
refined coal. By-products are all other potential-
ly usable components of coal conversion
systems.
Coal gasification and liquefaction processes
were studied to establish the expected slate of
products and by-products. Most processes pro-
duce recoverable quantities of sulfur, am-
monia, phenol, naphtha, tars, tar oils, and char
by-products. Lower temperature gasification
processes produce a wide range of by-
products; whereas higher temperature
processes produce fewer by-products. The
operating pressure of the gasifiers is a sec-
ondary variable. Almost all coal liquefaction
processes yield a full slate of by-products.
Potential pollutants from products/by-
products and their control needs are presented.
A number of existing and developing
technologies for upgrading by-products and for
control of effluents are reviewed. On-going
work on environmental data acquisition and
control technology assessment are discussed.
INTRODUCTION
The economics and environmental impact of
coal liquefaction and gasification systems in
the U.S.A. will depend to a large extent on ef-
fective lecovery and use of by-products. Such
coal conversion by-products generally include
phenol, tar, ammonia, char, ash, and sulfur.
The U.S. Environmental Protection Agency
awarded a three-year contract to Cata..- : -:
in September, 1976 to conduct a jroc-a-
aimed at development of control technciog, ;;-
the products and by-products of fuel cor.e'-
sion and utilization systems based on coal. '- s
paper outlines the project scope, analyzes fue
conversion products and by-products and :Heir
pollution control needs, and reviews pertmerr
recovery and pollution control technolog as.
For the purpose of this project, the following
definitions apply: coal conversion systems are
coal gasification and liquefaction processes.
Products are the primary marketable fuel and
feedstock materials such as low, medium, and
high Btu gas; and solid and liquid hydrocarbons
derived from coals. By-products are all other
potentially usable components of coal conver-
sion system yields.
PRODUCTS AND BY-PRODUCTS
OF FUEL SYSTEMS
Figure 1 for coal gasification and Figure 2 for
coal liquefaction define the major boundaries of
products and by-products for these coal con-
version systems. As indicated, basic process
modules such as methanation, compression
and dehydration, sulfur recovery, fractionation
and hydrotreatment fall within the products
and by-products area. Any other process and
control techniques that might be applied for the
recovery and upgrading of any product or by-
product from such coal conversion systems
would also be within the project's scope.
Coal Gasification
Table 1 shows coal gasification processes of
current and potential interest along with their
expected products and by-products. Principal
subdivisions of coal gasification processes are
in the low, intermediate, and high temperature
operations. These may be further subdivided by
operating pressure. Table 2 illustrates the
quantities of products and by-products
generated by a few selected processes.
A definite pattern emerges from examination
of Table 1. The low temperature gasification
processes tend to show a complete product
and by-product slate, extending from fuel gas
to ash or slag. As the temperature of gasified
tion increases, recoverable quantities or
387
-------
Corf Storage, Preparation A
MB SysfMI
Cmmlti Output
Piorfnrt» »nrf By PtorfucH
Corf
Wttfr
Sludw
Coal
Preparation
j
Corf
Ston*
1
Corf
PratiMtmenl
Dopes*
Stodfi
«-. 1
1
4—
A. „
Corf
Gasification
A* and
Char
Coofe*
t
^
i
»
SMi
i t
Catalnt
4
S^^H,
1
Contaminated
Warn
i
Water
TMHflM^AK*
noiBjicm
I
I
— _ .— j
^" "*
J
Water
Treatment
•
i
•^
i
Coohnf
,,
f*
L- f
«v
1
Solution
Reijeneialion
A
1
1
SepiKlion
*
1
i
Purification
-*
, A
Sullm 1 J T«ifM
RKmrery | | Tnntmont
+ -I
Compievion
Mariianition • *""
Mivrtrauon
i T I
Coirfyft Ptprfinc SNG
Tan and (Ml
Utiliration
Phenol and
Ammonia
Figure 1. Hypothetical gasification flow diagram.
-------
Coil Stengc. Prtpwition A
Ftfding ind System Wastes
Converter Output
Products and By Product!
CO
00
CO
Figure 2. Hypothetical liquefaction flow diagram.
-------
CO
(O
TABLE 1
COAL GASIFICATION PROCESSES PRODUCT/BYPRODUCT AND FUEL SYSTEM SIMILARITIES
LEGEND:
P - Product/By-Product
present in recoverable
quantities.
Neg. - Negligible or small
amounts present.
— Stream present in traces.
N.A. - Information not
available, not com-
plete, or not reported
at this time.
tVoducts/By-Products
High BTU Gas - SNG
Low (Intermediate)
BTU Gas
H2S - Acid Gas/Sulfur
Ammonia
Phenols
Naphthas/Benzenes
Tar Oils/Light Oils
Tars
Char/Unreacted Coal
Ash/Slag
CLASSIFICATION OF FUEL SYSTEMS
Low Temperature
Fixed Bed
Low
Pressure
«
.e
«9
3
TO
CD
I
c:
CO
1
P
P
P
P
P
N.A.
P
-
P
-
Intermediate
Pressure
1"
P
P
P
P
P
P
P
P
-
P
BGC/Lurgi
Slagging Gasifier
P
P
P
P
P
P
P
P
-
P
Pressurized Stirred Fixed
Bed - Morgantown
-
P
P
P
P
-
P
P
P
P
Intermediate Temperature
Fluidized Bed
Low
Pressure
h.
o>
_^
c
3
P
P
P
NA
Neg.
-
-
-
P
-
Inter-
mediate
Pressure
in
co
O
1
3
-
P
P
P
Neg.
N.A.
Neg.
Neg.
P
-
High Pressure
a>
1
*-*
c
>•
>-
P
-
P
P
P
P
P
-
P
-
High Temperature
Entrained Bed
Low
Pressure
J£
O>
S
o
*I
o>
Q.
o.
o
H
P
P
P
Neg.
-
-
-
-
-
P
High
Pressure
CJ
3
CN
O
O
P
-
P
P
N.A.
N.A.
N.A.
N.A.
P
-
nghouse-Advanced
er
s 5
o> to
£ a
-
P
P
N.A.
-
-
-
-
-
P
Coal
Pyrolysis
intrainec
nter.
"emp.
.ow
'ressure
II
' S
a. E
0, 0
£ S
m 5"
OD <
P
P
P
P
-
-
-
-
-
P
luid Bed
nter.
'emp.
nter.
'ressure
Garretts Coal
Gasification
P
P
P
N.A.
-
-
-
P
P
-
-------
TABLE 2
PRODUCTS/BYPRODUCTS OF DIFFERENT COAL GASIFICATION PROCESSES
Products/By-Products
Product Gas, SCFD
Sulfur, Ib/hr
Tars, Ib/hr
Tar Oil, Ib/hr
Phenol, Ib/hr
Ammonia, Ib/hr
to (anhydrous)
Hydrocarbon, Ib/hr
Char/Ash, Ib/hr
(Slag)
Coal, Ib/hr
Feed
Wellman-
Gallusha
28.4MM
(170 BTU/SCF)
777
1,153
120
219
1,768
(ash)
21,000
Bitum.
3.9% S
Lurgl
288 MM
(SNG)
15,600
88,800
48,600
11,300
21,400
20,000
(naphtha)
476,000
(ash)
1.94 MM
1.07% S
K-T
524 MM
(290 BTU/SCF)
23,600
neg.
neg.
neg.
neg.
24,400
(ash, slag)
0.7MM
3.8% S
Bumines
Stirred Bed
995 MM
(160 BTU/SCF)
24,200
75,600
11,100
114,100
(ash)
0.7MM
W. Ky.#9
3.9% S
Wlnkler
912 MM
(280 BTU/SCF)
50,400
neg.
to claus
(BTJj
372,500
(char)
Synthane
250 MM
(SNG)
11,400
43,200
4,000
13,200
7,400
,naphta)
362,000
(char)
1.68 MM 1.18 MM
Lignite Pitts. Seam
3.3% S 1.6% S
Hygas
260 MM
(SNG)
55,500
1,300
11,300
39,800
139,000
(char)
1.06 MM
111. #6
4.75% S
-------
heavier tars begin to disappear in favor of
lighter products. For the high temperature
gasification processes, essentially the only
product is fuel gas or products for synthesis;
other by-product quantities are too low for
recovery to be economic.
Operating pressure also changes yields, as
shown in Table 1. As the pressure increases,
the product slate becomes heavier. For exam-
ple, in intermediate temperature processes,
products such as naphthas, tar oils, and tars
proceed from zero or negligible quantities to
significant quantities as operating pressure in-
creases.
For some reason naphtha doesn't appear in
the reported products from the Stirred Fixed
Bed Process and the Wellman-Galusha
process1'2-3'4'7'8. From analogy with the other
low temperature and intermediate temperature
processes, a naphtha cut would be anticipated
from both these systems. It is surmised that
either the data available are incomplete, or
perhaps the yields as reported include the
naptha fraction as part of the tar oil stream. The
pattern shown in this table indicates that the
product slate for other coal gasification
processes could be predicted by comparing the
gasifier operating conditions with those listed.
Coal Liquefaction
Table 3 shows the relationship between
various coal liquefaction processes and the
product slates from these processes. In this
table distinct patterns of product slates do not
readily emerge as in the coal gasification proc-
esses. However, the following observations
can be made.
• All the liquefaction processes produce
an acid gas stream which will contain
sulfur and other contaminants. In this
regard, they are similar to coal gasifica-
tion processes, which also produce an
acid gas stream. Consequently, H2S
removal and sulfur recovery will be re-
quired for all coal processing plants.
• The liquid product distribution shows a
range from syncrudes to naphtha and
gas oils. However, all will contain vary-
ing amounts of sulfur, nitrogen, and
metal contaminants which will have to
be removed by subsequent upgrading
treatments.
• Only the solvent refined coal (SRC)
process yields a solid fuel. In all other
processes, additional hydrogenation
results in the formation of liquid pro-
ducts.
• Almost all the processes produce a
char (coke and unreacted coal com-
bined with ash) by-product with some
fuel value. These by-products will re-
quire additional processing (e.g.,
specifically-designed combustion
units) to utilize the carbon value and,
thereby, increase the energy efficiency
of the conversion process.
• Phenols and/or ammonia will be
present in the aqueous waste streams
in most cases and could be recovered
as by-products.
Of all the liquefaction processes, solvent
refined coal is the most developed. Two SRC
pilot systems, 6 and 50 tons/day, are currently
operating with various coals. Based on these
results, salable product and by-product
distribution for a nominal 20,000 ton/day plant
using a Kentucky coal, containing 3.45 percent
sulfur and 10.4 percent ash on dry basis, was
calculated as follows:
Product
Quantity, Ton/day (*)
SRC 9,950
Light Oils (IBP-3500 F) 750
Medium Oils (350-450° F) 2,210
Heavy Oils (450-780° F)' 166
Fuel Gas 361
Sulfur 450
Ammonia (25%) 37
Phenolics 28
("I Based on input coal (2% moisture) of 21,011 ton/day.
Effect of Coal Type
While the type of coal charged will not
significantly affect the kinds of products and
by-products generated by conversion, it will
significantly affect how their quantities are
distributed. For a particular process, coals with
higher sulfur and nitrogen concentrations
would obviously give higher proportions of S
and NH3 by-products. More information and
testing with different coals will be necessary to
establish the effects of coal type on the
392
-------
u
- Negligible or small amounts
present.
N.A. — Information not available,
not complete, or not reported
at this time.
Products/By -Products
High B.T.U. Gas - SNG. LPG. ethylene.
hydrocarbon, product gas.
.ow (Intermediate) 8TU Gas -
Fuel Gas. Synthesis Gas
H2S Acid Gas/Sulfur
Ammonia
Phenols
Benzenes
Naphtha, Gasoline
Syncrudes
Middle Distillates. Fuel Oil
Gas Oils, Neutral Oils, Chemical Oils
Residual Fuel Oils
Tars (Tar Acids and Tar Bases)
Solvent Refined Coal
Char/Coke/Unreacted Coal
Ash/Slag
CLASSIFICATION OF FUEL SYSTEMS
Catalytic Hydrogenation
"5
o
u
I
P
-
P
P
Neg.
N.A.
P
P
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distribution of products and by-products for
each coal conversion process.
POLLUTION CONTROL NEEDS
A variety of chemical compounds are
generated in the form of products, by-
products,and wastes during coal gasification
andliquefaction processing. Many are toxic
pollutants. For example,
• Sulfur compounds such as H2S, S02,
mercaptans, COS
• Nitrogen compounds such as NH3,
HCN, NOX
• Hydrocarbons, polynuclear aromatics,
heterocyclic compounds.
The objective of control technology develop-
ment is to permit the fullest utilization of the
different products and by-products while con-
trolling environmental pollution within ac-
ceptable levels.
Products and By-products
As Fuel. The purpose of coal conversion
systems is to produce fuels and chemical
feedstocks. Combustion gases from the fuel
products should preferably be capable of direct
discharge to the atmosphere with no further
treatment. This will generally require prior
removal of sulfur compounds and particulates
in the coal conversion process. In addition,
nitrogen compounds will also have to be
removed tobring NOX emissions after combus-
tion within acceptable limits.
For example, high temperature H2S cleanup
processes for the purification of low and
medium Btu gas will increase the overall energy
efficiency of the coal conversion process, but
will create NOX emission problems. The
nitrogen compounds (e.g. ammonia) in the raw
gas are not removed by these cleanup
processes, so if the "purified" fuel gas is
charged directly to a furnace, the nitrogen com-
pounds will be converted to NOX and exit in the
flue gas. This calls for development of control
technology that can be used in conjunction
with high temperature gas purification
processes for removing the nitrogen com-
pounds prior to combustion.
A number of by-product streams may also
serve as fuel. These include tail gas streams.
tarry and oily liquids and chars. Control tech-
niques will be required for sulfur, particulates,
and NOX emissions in these cases also.
As Chemical Feedstocks. Almost all products
and by-products from coal conversion units
may be used as chemical or petrochemical
plant feedstocks. For example, low and
medium Btu gas from coal gasification may be
used as the starting material for production of
hydrogen, ammonia, methanol, or Fischer-
Tropsch liquids. For all these processes,
pretreatment of the feed to remove the sulfur
contaminant is necessary.
The liquids from coal conversion plants can
serve as feedstocks for production of benzene,
toluene, and xylene as well as for higher
aromatics such as naphthalene. In addition,
specialty solvents with high aromatic content
may be produced. The coal-derived liquids used
for aromatic production may be charged either
to catalytic reforming units or dealkylation
units. Before catalytic reforming, the liquid
must be pretreated to remove sulfur and
nitrogen impurities. Dealkylation takes place
simultaneously with gasification of con-
taminants. The gaseous contaminants must be
removed by control techniques such as scrub-
bing.
Gaseous Wastes
Generally, gaseous emissions from coal con-
version plants originate from the following
sources: raw material handling and pretreat-
ment; vent gases from startup, shutdown and
lock hopper operations; by-product recovery,
storage and upgrading; waste treatment; acid
gas removal and sulfur recovery; catalyst
regeneration; and power generation. Various
sulfur, nitrogen, hydrocarbon compounds, and
particulates are present in air emissions.
Air emissions are controlled by the following
four basic control modules:
• Sulfur control
• Particulate control
• Hydrocarbon control
• Nitrogen oxide control
At present, sulfur is the only by-product
recovered from gaseous emissions to any large
extent.
394
-------
Liquid Wastes
The liquid waste (gas liquor) contains tars,
tar oils, phenols, and ammonia as well as vir-
tually every contaminant found in the fuel con-
version systems. Large amounts of par-
ticulates, C02, H2S, chloride and sulfate are
present. Cyanide and ferrocyanide occur in the
aqueous layer. Reported trace elements include
antimony, arsenic, boron, bromine, cadmium,
fluorine, lead, mercury, and nickel.
Little information exists as to how these con-
taminants will be distributed throughout the
recovered by-products. Many contaminants
will probably appear in the crude by-products.
These pollutants would have to be removed for
environmental protection.
At least five different by-product streams are
produced from typical Lurgi plant liquid wastes:
tar, tar oil, crude phenol, ammonia, and sulfur.
The foregoing by-products are recovered from
a gas liquor with the following typical composi-
tion:
Component Approximate Composition, ppm
Phenols 3,000-4,000
Ammonia (free) 500-750
Ammonia (fixed) 100-200
Sulfides (total) 200-250
Suspended tar, oil 5,000
Cyanides 50
C02 10,000
Fatty acids 500
The proposed El Paso Burnham complex
Lurgi plant will produce 288 million SCFD syn-
thetic pipeline quality gas, gasifying 1.07%
sulfur coal at the rate of 1.944 million Ib/hr.
Figure 3 shows the distribution of the various
by-products from this plant. A sizable portion
of the by-products are absorbed in, or con-
dense out with, the organic and aqueous con-
densates as the gases are first quenched with
water and then cooled. The heavier tars
separate out first in the gasifier waste heat
boiler and are called "tarry gas liquor." Further
downstream, in the gas cooling section, the tar
oils with the remaining tars condense out form-
ing the "oily gas liquor." In the acid gas
removal step, H2S and naptha separate out.
Naphtha goes directly to a storage tank. H2S-
containing acid gases are processed further to
recover the sulfur. Table 4 gives the material
balance for the gas liquor treatment5.
Ammonia and sulfur will be recovered as
commercial-grade materials, but further
upgrading will be required to meet demands for
explosives and fertilizers. Other by-products
will also require upgrading6.
Solid Wastes
Solid wastes are composed of the ash
residue plus the accompanying unrecovered
carbon or hydrocarbons from the coal charge. If
filtration is used in the liquefaction process for
ash separation, filter precoat will also be
present.
To make coal processing economic, the car-
bon values from char should be recovered. Two
recovery possibilities are on-site combustion of
char for steam generation or for hydrogen
manufacture. When used in this manner,
removal of particulates and sulfur will be re-
quired to clean up the stack gases before
discharging to atmosphere.
Solid residues such as ash and filtercake will
contain trace metals from coal. Recovery of
some of these minerals may be possible in the
future. If not, then the solid wastes must be
disposed of in ways that protect the environ-
ment.
In considering pollution control needs, it is
necessary to stay cognizant of the inter-
relationships existing among liquid, gaseous
and solid wastes. For example, spent catalysts
can present a solids disposal problem if not
reused, or cause an air pollution problem when
regenerated. The contaminants that normally
deactivate catalysts are sulfur compounds,
nitrogen compounds, and heavy metals.
Catalyst activity can be maintained or lengt^-
ened by burning these contaminants off *^3
catalysts. The off gases from catalyt regenera-
tion will contain sulfur, nitrogen, and hydrocar-
bon compounds and will also require controls
to meet air pollution emission requirements.
CONTROL TECHNOLOGY
This section reviews some of the important
existing control technologies or classes of
technologies.
Earlier discussion established that a full slate
of products, extending from fuel gas to ash.
395
-------
GAS
COAL
STEAM
OXYGEN
ION
BY PRODUCT
TREATMENT
BY PRODUCT
STORAGE
1
1
^-
GAS LIQUOR
SHIFT
^h
T
GAS
COOLING
V T
/\ '
CONTAMINATED
v ^ WATER
TO METHANATION
VENT
Figure 3. By-product from Lurgi plant.
-------
3
«M
TABLE 4
MATERIAL BALANCE FOR GAS LIQUOR TREATMENT
Stroaa Description
fill HUM. Ih/hr
II. 1
Tarry Gas
Honor
11.2
Oily Gas
US""
11.3
{(pension
11.4
Process
Condeittate
II. S
Tar
on
II. *
lar
II. 1
Contaminated
fias
llouor
n.a
Crude
Phenol
II.*
AcM
Gas.
11.10
Clean
Maur
11.11 11.12
il* mutha
Hater
lar
Tar Oil
•acoverahle Crude Phenol
Unrecoverable Phenol I Organic
CO,
CO
Nenekydrlc Phenols
Polyftydrlc Phenols
Other Organlcs
Contained Sulfur
•aphtha
Total Dry Gas. Ib/hr
liquid Phase. Ih/hr
2.030
8.870
59.700
70
SO
no
8.5/0
S2.16S
17.720
Hater
lar
lar Oil
Recoverable Crude Phenol
Unrecoverable Phenol a On
•jnnnla
MjS
coz
CO
CM,
Nomhydrtc Phenols
Polyhydrlc Phenols
Other Organic!
Contained Sulfur
Total liquid. Ib/hr
165.000 1
79.900
14.600
210
fanlc 130
—
30U
17.200
70
40
—
--
--
277.450 1
.100.000
8.900
34.000
11.100
4.100
21.600
300
54.800
•-
..
—
—
.314.01)0
MOTE: Crude estlMte based on follwlng assumptions:
1 Nonohydrlc phenol s'reduccd to 20 PI* per lurgl
2 601 of inlyhydrlc phenols recovered
1 151 of other organlcs recovered
4 Crude phenol strean contains 51 other oruintcs
S Phenols recovered are 501 •uiiohydrlc
101.000
164.000
•8.800
48.600
3 4.100
70 1.600
60 SCO
1.190.000 <2.noO
240 21.400
10
J.660
24
WO
3,200
(73) (240)
103.000 48.600 80.HOO 164.133 11.260
20.000
1.1*4.364 107.070 20.000
A»wptlons 2-4 Mere presented by Bcychok tn reference (I) for • crude deteralMtlon of oisirictlion effluent co>«wsltlon.
-------
can be obtained from either the gasification or
liquefaction process. Furthermore, the im-
purities in these streams are generally similar,
including sulfur and nitrogen compounds,
heavy metals, and particulates.
Identical products from coal gasification and
coal liquefaction processes will contain the
same contaminants and therefore, may be
processed in similar type pollution control
systems. For example, sulfur contamination of
fuel gas or phenol contamination of aqueous
wastewater, whether from coal gasification or
coal liquefaction, could have similar treatment
and recovery units.
It makes sense then to discuss control
technologies primarily in terms of the class of
contaminants. Product/by-product identifica-
tion can serve as a secondary variable while
coal gasification or liquefaction is of incidental
importance. Control technologies discussed
here will be limited to the following classes of
contaminants:
• Sulfur and nitrogen compounds
• Particulates
• Heavy metals/trace contaminants
Other pertinent control technologies are
touched on briefly, but many such as for
hydrocarbon, phenol removal, and wastewater
treatment, cannot be covered in depth at this
time.
Sulfur and
Nitrogen Compounds
Combined sulfur and nitrogen in the products
and by-products from coal conversion plants
can be converted to H2S and NH3 by
hydrogenation, or to S02 and NOX by oxida-
tion.
H2S can be scrubbed from the gaseous
products and converted to elemental sulfur.
Similarly, SO2 can be removed from the gases,
either by dry or wet scrubbing. The scrubbed
S02 may then be converted to a variety of dif-
ferent forms, such as elemental sulfur,
sulfates, or bisulfites, for disposal or utilization.
Control of NOX compounds by similar
scrubbing processes are in the state of develop-
ment. Currently, various combustion modifica-
tions are the best means to control NOX.
Hydrogenation. In the presence of hydrogen,
hydrogenation of the sulfur and nitrogen can
occur either thermally (as in coal gasification
plants) or catalytically (as in catalytic coal
liquefaction plants). For example, the gasifica-
tion of residue and chars to produce hydrogen
results in the formation of H2S and NH3.
Catalytic hydrotreating is a well established
process in the petroleum- industry for the
removal of sulfur and nitrogen contaminants. It
has been found in the petroleum industry that
the operating conditions required for
denitrification are much more severe than
those required for desulfurization, especially if
organic nitrogen is present in thermally cracked
stocks. Also, special design care is required for
treating some light distillates (as from ethylene
plants) because of the gum-forming tendencies
of these stocks.
Distillates derived from ethylene plants ap-
pear to be the most analogous to those from
coal for catalytic hydrogenation treatments.
The process flow module should be similar,
with hydrotreating followed by fractionation or
stripping to remove the H2S, NH3/ and H20
formed in the reactors. Prevention of equip-
ment plugging from gum formation is an impor-
tant design consideration in both cases.
When heavey distillates are hydrotreated in
fixed bed reactors, the process module is
similar to that for catalytic treating of light
distillates-hydrotreating followed by fractiona-
tion or stripping. However, the hydrotreating
conditions of temperature, total pressure,
hydrogen partial pressure, and space rate are
more severe than those used for light
distillates. At these more severe conditions,
and with higher concentrations of sulfur and
hydrogen in the process streams, high alloy
materials of construction are required.
Desulfurization achieved in these units is in the
range of 75 to 90%.
The problem with the use of fixed beds for
hydrotreating heavy distillates is rapid deac-
tivation of the catalyst caused by heavy metals
build-up. Thus, some means of maintaining the
catalyst activity by total or partial replacement
of the catalyst is necessary. Other reactor
designs, such as fluidized or ebullating beds,
may circumvent this difficulty. With these
designs spent catalyst can be continuously
removed from the reactor and replaced by fresh
catalyst. Regardless of reactor design, the
398
-------
general overall processing module of
hydrotreating followed by stripping would be
the same.
Hydrotreating of coal-derived heavy dis-
tillates would be expected to follow the same
process modules as for petroleum-de-
rived heavy distillates. The concentration of
heavy metals in the distillate cut would dictate
the type of reactor design necessary. Heavy
distillate from both coal gasification and coal
liquefaction plants would require hydrotreating
units having similar modules.
The catalysts used for hydrotreating are of
the cobalt-molybdenum type which resist
catalyst poisoning. Catalyst deactivation
results from buildup of carbonaceous deposits
or heavy metals. Carbonaceous matter can be
readily removed from the catalyst in-situ, by
steam-air oxidation. Heavy metals cannot be
removed. But in the case of light distillates,
they are not present in significant concentra-
tions, and should not present a contamination
problem. Additionally, catalyst will become
deactivated over a long period by loss of active
surface area due to time-temperature effects.
H2S Removal and Sulfur Reco very. A number
of commercial processes are available for
removing sulfur from fuel gas, as shown in
Table 5. These operate at low temperature, so
if the scrubbing unit is followed by methana-
tion, the scrubbed gas must be reheated.
To avoid reheating, and thereby increase the
energy efficiency of the process, new high
temperature H2S cleanup units are under
development (Table 6). One disadvantage of
high-temperature cleanup schemes is omission
of the initial quench step, which removes NH3
and particulates from the raw gas. So, removal
of the ammonia from fuel gas at high
temperature requires further development.
High temperature removal of the particulates
may be affected by one of the processes
shown in Table 7.
Numerous sulfur recovery processes of the
direct conversion type exist. These can be
classified as either dry oxidation or liquid phase
oxidation. The principle of operation involves
the oxidation of sulfur compounds to elemental
sulfur. The two most widely used direct con-
version processes are the Claus (dry oxidation)
and the Stretford (liquid phase oxidation)
processes.
The commercial Stretford process recovers
inorganic sulfur from acid gases containing less
than 15% H2S. A packed absorber removes
H2S from acid gases, using Stretford solution
absorbent, which is mainly sodium meta-
vanadate, sodium anthraquinone disul-
fonate (ADA), sodium carbonate, and bicar-
bonate in water. Sulfur recovery between
98%-99% is possible. This process is insen-
sitive to H2S/C02 ratio, and operates over wide
pressure ranges. Temperature limitations are
between ambient to 1 20° F.
The process does not remove organic sulfur,
and it requires pretreatment removal of large
quantities of S02, HCN or heavy hydrocarbons.
It produces a purge wastewater stream con-
taining spent Stretford solution, which will re-
quire treatment9.
The Claus process effectively controls sulfur
emissions and recovers elemental sulfur from
gas streams containing high concentrations of
H2S (at least 10-15%). In most cases, tail gas
treatment is also necessary.
Tail Gas Treatment. Tail gas cleanup proc-
esses, when combined with a Claus unit, can
provide an overall sulfur removal efficiency of
up to 99.9%. Commercially available tail gas
cleanup processes include:
Process Name Type
SCOT Catalytic hydrogenation of
Beavon sulfur compounds to H2S and
Cleanair then removal by absorption
Cataban processes or recycle to a Claus
Trencor-M unit.
Sulfreen Continuation of Claus reaction
CBA at low temperatures (245-
270° F)
An alternative to tail gas treatment is to in-
cinerate the gases and then scrub the resulting
S02. This set of processes was developed to
handle tail gases from furnaces, smelters, and
pulp mills, where S02 is the main pollutant
rather than H2S.
S02 scrubbing systems have several advan-
tages over the H2S processes. The scrubbers
are less affected by process upsets, are not
susceptable to catalyst poisons, and can scrub
SO2 from very dilute mixtures. But scrubbing
399
-------
TABLE 5
LOW TEMPERATURE H2S CLEANUP PROCESSES
PROCESSES
Chemical Solvent Type
MEA
DEA
TEA
Alkazid
Benfield
Catacarb
Physical Solvent Type
Sulfinol
Selexol
Rectisol
Direct Conversion
Stretford
Townsend
Drybed Type
Iron Sponge
ABSORBENT
Monoethanolamine
Diethanolamine
Triethanolamine
Potassium dimethyl
amino acetate
Activated potassium
carbonate solution
Activated potassium
carbonate solution
Sulfolane +
di-isopropanolamine
Polyethylene glycol
ether
Methanol
Na-CO. + anthraquinone
sulfonic acid
Triethylene glycol
Hydrated
STATUS
Commercial
Commercial
Commercial
Commercial
Commercial
Commercial
Commercial
Commercial
Commercial
Commercial
Commercial
Commercial
400
-------
PROCESS
Bureau of Mines
TABLE 6
HIGH TEMPERATURE H2S CLEANUP PROCESSES
ABSORBENT
Sintered pellets of
Fe00, (25%) and fly
Babcock and Wilcox
CONOCO
Air Products
Battelle Northwest
IGT-Meissner
Air Products
ash
Half calcined dolomite
Calcined dolomite
Molten carbonates
(15% CaC03)
Molten metal
(proprietary)
STATUS
Pilot
Experimental
Pilot
Abandoned
Pilot
Conceptual
Experimental
401
-------
TABLE 7
HIGH TEMPERATURE PARTICULATE REMOVAL SYSTEMS
TYPE OF REMOVAL SYSTEM
Mechanical Collectors
Cyclones
Tornado
Bed Filters
Granular
Panel
Rex
Sonic Agglomeration
Collection Systems
Alternating Velocity
Precipitator
Scrubbers
Fused salts
Filters
Metal and Ceramic
Electrostatic
Precipitators
MANUFACTURER
Buell, Ducon & Others
Aerodyne
Combustion Power Co.
Ducon
C.TJ.N.Y.
Rexnord
STATUS
Commercial
Commercial
Under Development
Under Development
Under Development
Commercial
Braxton
Battelle
Selas and Others
Research-Cottrell
and others
Under Development
Under Development
Commercial
Commercial
402
-------
processes are more expensive than other tail
gas treatment methods.
Ammonia Recovery. NH3 formed by the
hydrogenation reactions can be scrubbed from
the reaction gases by water and subsequently
recovered by steam stripping. Several
processes are available, for example--
Chevron, Phosam-W, and others based on lime
treatment to free fixed ammonia for later steam
stripping.
Phosam-W, a U.S. Steel Corp. developed
process, uses aqueous acid ammonium
phosphate solution to scrub ammonia from
gases. The scrubbed sour water is then
stripped of ammonia with steam and the acid
ammonium phosphate solution is recycled.
The Chevron process separates ammonia,
carbon dioxide, and hydrogen sulfide from li-
quid waste streams. Another system, con-
sisting of a pairing of Phosam-W and Firma Carl
Still, recovers hydrogen sulfide (for sulfuric
acid manufacture) and ammonia from sour
water10.
Particulates
Equipment for controlling particulates in gas
streams includes cyclones, bag filters, elec-
trostatic precipitators, and wet scrubbers. Par-
ticle size distribution is one of the important
parameters necessary to predict the separation
efficiency of these devices. High temperature
removal of particulates may be effected by one
of the processes shown in Table 7.
Heavy Metals/
Trace Contaminants
Heavy metals and trace contaminants are so
numerous, and cover such a wide field of
physical and chemical properties, that any
discussion of control methods should be on an
individual basis. Therefore, this paper offers
only a few generalized remarks on this class of
contaminants.
Determination of the concentration and
distribution of heavy metals in the coal feed
and in the effluents and product streams of the
coal conversion plant is of prime importance.
Some preliminary estimate of these values can
be attempted by consideration of the physical
and chemical characteristics of these elements,
and of the compounds they may form in the
system. However, ultimate testing and analysis
in plant studies will be necessary to establish
these distributions. These may then be com-
pared to the allowable safe concentration
limits, as set by EPA.
Another concern with regard to heavy metals
is their effect on catalyst activity. Heavy metals
contained in the feed to catalytic units often
will be adsorbed on the surface of the catalyst,
causing its deactivation. If, in a particular situa-
tion, this occurs at a very slow rate, the
catalyst is merely discarded when its activity
has fallen to an uneconomic level. In other
cases, the catalyst may be protected by placing
guard cases ahead of it, or by periodically or
continuously drawing off some spent catalyst
and replacing it with fresh catalyst. It should be
noted here that spent catalyst may have high
concentrations of heavy metals or other con-
taminants, and if regeneration is attempted,
these contaminants could be released in a short
period of time at high concentrations, causing a
health problem.
Additional Control
Technologies
A large number of other control technology
techniques not covered here are applicable in
upgrading operations of products and by-
products. Examples include methanation,
catalytic synthesis, catalytic cracking,
hydrocracking, catalytic reforming, and frac-
tionation. The other broad control areas are the
gas, liquid, and solid waste treatment tech-
niques. These and other control approaches are
shown in Table 811.
CONTROL TECHNOLOGY
ASSESSMENT AND DATA
ACQUISITION
Little operating data on control technology
for either pilot or commercial scale coal conver-
sion systems exist in the literature. Data ac-
quisition by actual field testing, therefore,
should be given top priority for control
technology.
In this regard, EPA has initiated projects to
(1) design laboratory units needed to evaluate
feasible controls for coal conversion products
and by-products streams, and (2) develop
laboratory treatability screening procedures to
403
-------
TABLE 8
o Gas Treatment
CONTROL APPROACHES
o Process Modification
Mechanical Collection
Electrostatic Precipitators
Filters (fabric,
granular, etc.)
Liquid Scrubbers/Contactors
(aqueous, inorganic, organic)
Condensers
Solid Sorbents (mol sieves,
activated carbon)
Incineration (direct and
catalytic)
o Liquids Treatment
Settling, Sedimentation
Precipitation, Flocculation,
Sedimentation
Evaporation and Concentration
Distillation, Flashing
Liquid-Liquid Extraction
Gas-Liquid Stripping
Neutralization
Biological Oxidation
Wet Thermal Qxidation
Activated Carbon Adsorption
Ion Exchange System
Cooling Tower (wet & dry)
Chemical Reaction and Separation
Centrifugation and Filtration
o Solids Treatment
Fixation
Recovery/Utilization
Processing/Combustion
Chemical Reaction and
Separation
Oxidation/Digestion
Physical Separation (specific
gravity, magnetic, etc.)
o Final Disposal
Pond Lining
Deep Well Reinjection
Burial and Landfill
Sealed-Contained Storage
Dilution
Dispersion.
Feedstock Change
Stream Recycle
o Combustion Modification
Flue Gas Recycle
Water Injection
Staged Combustion
Low Excess Air Firing
Optimum Burner/Furnace
Design
Alternate Fuels/Processes
o Fuel Cleaning
Physical Separation
(specific gravity,
surface properties,
magnetic)
Chemical Refining
Carbonization/Pyrolysis
Liquefaction/Hydrotreating
(HDS, HDN, Demetallization)
Gasification/Separation
o Fugitive Emissions Control
Surface Coatings/Covers
Vegetation
Leak Prevention
o Accidental Release Technology
Containment Storage
Flares
Spill Cleanup Techniques
404
-------
TABLE 9
R & D ACTIVITIES TO UPGRADE COAL CONVERSION PRODUCTS/BYPRODUCTS
Investigator
Arco Chemical Co.
Bartlesvile Energy
Research Center
The Dow Chemical Co.
and Pittsburgh Energy
Research Center
Exxon Research and
Engineering Co.
Hydrocarbon Research,
Inc.
M.I.T.
Pittsburgh Energy
Research Center
Sandia Labs
Universal Oil
Products, Inc.
Air Products
Project Title
Catalytic Hydrotreating of
Coal-Derived Liquids
Refining Process Technology
Chemicals from Coal
Liquids
Chemical Properties of
Synthoil Products and Feed
Demetallization of Heavy
Residual Fuel Oils
Catalytic Desulfurization
and Denitrification
Petrochemicals from
Synthesis Gas
Mechanisms of Deactivation
and Reactivation of Catalysts
Characteristics of Coal-
Derived Liquids
Characteristics of SRC Liquids
Funding
ERDA
(Project
Completed)
ERDA
ERDA
ERDA
Exxon
EPA
EPA
ERDA
ERDA
ERDA
ERDA
405
-------
TABLE 10
LIST OF PRODUCTS/BYPRODUCTS AND SOME
OF THEIR FINAL PRODUCT POSSIBILITIES
Products/By-Products
1. Aqueous wastewater containing
ammonia, phenol and tar, etc.
2. Crude phenol
3. Tar and tar oil
4. Naphthas
5. H2S Acid Gas/Sulfur
6. Spent Catalyst
7. Char
8. Ash
9. Low BTU gas, medium BTU gas
10. High BTU gas
11. Syncrudes
12. Middle distillate oil
13. Gas oils
14. Residual fuel oils
15. SRC
Examples of Final Product Possibilities
Ammonia, crude phenol and tar
Natural phenol, refined cresylics,
phenolic pitch
Benzene, toluene and xylene (BTX)
Ethylene
Sulfur/Sulfuric Acid
Regenerated catalyst
Hydrogen, or fuel gas
Recovered heavy metals
SNG, fuel, feedstocks for chemicals
such as NH and CH OH
SNG, chemical feedstock
Refinery products such as gasoline
and fuel oil
Fuel oil
Lubricants, cat-cracker feedstock
Coke, fuel oil
Coal fuel, high purity coke
406
-------
determine how an environmentally harmful
stream can be made less harmful through ap-
plication of appropriate control techniques.
Most of the control technologies discussed
earlier are being used in the petroleum,
petrochemical, and coke oven by-products in-
dustries. It is of utmost interest to know how
these technologies are working, and whether
their performance characteristics can be
duplicated in the synthetic fuels industry.
For this reason, EPA is currently sponsoring a
study of the coke oven by-products industry
control techniques to determine which are ap-
plicable to the coal conversion industry. This
work was begun recently and will be reported
later. A companion study is being conducted to
determine which of the control techniques from
the petroleum industry are applicable to coal
conversion systems.
A number of research and development ac-
tivities are being funded by EPA and ERDA to
upgrade coal conversion products and by-
products. Some of these are shown in Table 9.
The impetus for engaging in these activities is
illustrated in Table 10 which presents ex-
amples of the many marketable chemicals
potentially recoverable from the upgrading of
coal conversion products and by-products.
CONCLUSIONS
The economic justification of coal conversion
systems depends to a large extent on being
able to develop technology (1) that will permit
upgrading products and by-products into addi-
tional marketable chemicals and (2) that will
accomplish this goal without substantive
adverse impact on the environment.
Generally, product and by-product utilization
will require removal of sulfur and nitrogen con-
taminants before their use as fuel or chemical
feedstocks. Some of the more important con-
trol needs include H2S, SO2, NOX, hydrocarbon
and particulate removal from gaseous ef-
fluents; removal of phenol, ammonia, sulfide,
dissolved organics, heavy metals, and cyanides
from aqueous waste streams; and prevention
of solid waste leachate problems. When such
pollutants are removed from waste streams
and converted to usable products, downstream
waste treatment problems and environmental
impacts are automatically improved.
By-product recovery and upgrading control
technologies are, therefore, an important part
of the overall environmental management pro-
gram.
Little operating data on control technology
for either pilot or commercial scale coal conver-
sion systems exist in the literature. At the
present, most of the control technologies that
are applicable for the products and by-products
of coal conversion systems are being used in
the petroleum, hydrocarbon, and coke oven in-
dustries. However, their applicability and
limitations have yet to be determined by actual
use and field testing with different coal conver-
sion systems.
ACKNOWLEDGMENT
The information on which this paper is based
was drawn from work carried out by Catalytic,
Inc. under EPA Contract 68-02-2167. The
authors particularly wish to acknowledge the
valuable guidance and support provided by T.
K. Janes, Branch Chief, and by C. A. Vogel,
Project Officer, Fuel Process Branch, EPA-IERL-
RTP.
REFERENCES
1. Battelle-Columbus Laboratories, "En-
vironmental Aspects of Retrofitting Two
Industries to Low and Intermediate Energy
Gas From Coal," EPA-600/2-76-102.
2. D. Ball et al., "Study of Potential
Problems and Optimum Opportunities in
Retrofitting Industrial Processes to Low
and Intermediate Energy Gas from
Coal,"EPA-650/2-74-052.
3. Skeist Laboratories, "Coal for Chemical
Feedstocks," October 1 975, p.383-385.
4. F. L. Robson et al., "Fuel Gas En-
vironmental Impact," EPA-600/2-75-
078.
5. J. E. Sinor (Editor), "Evaluation of
Background Data Relating to New Source
Performance Standards for Lurgi Gasifica-
tion," EPA-600/7-77-057.
6. R. Serrurier, "Prospects for Marketing
Coal Gasification By-Products," Hydro-
carbon Processing, September 1976.
407
-------
7. McDowell Wellman Engineering Com-
pany, "Wellman-Galusha Gas Pro-
ducers," Form No. 576, Company
Brochure, Cleveland, Ohio, 1976.
8. Dravo Corporation, Handbook of Gasifiers
and Gas Treatment Systems, Final Report
No. FE-1772-11, ERDA Contract No.
E(49-18)-1772, Pittsburgh, PA, February
1976.
9. Catalytic, Inc., "The Stretford Process"
(a report prepared for the Environmental
Protection Agency, IERL Lab, Research
Triangle Park, N.C.), Philadelphia, PA.,
December 1976.
10. L. J. Colaianni, "Coke-Oven Offgas Yields
Fuel, Chemical Byproducts," Chemical
Engineering, March 29, 1976.
11. R. P. Hangebrauck., EPA-RTP, Internal
project communication to contractors.
408
-------
SPECIFIC ENVIRONMENTAL
ASPECTS OF FISCHER-TROPSCH
COAL CONVERSION
TECHNOLOGY
by
B. I. Loran and J. B. O'Hara
The Ralph M. Parsons Company
Pasadena, California
Abstract
A preliminary design of a commercial-scale
Fischer-Tropsch plant producing liquid
hydrocarbons plus substitute natural gas by in-
direct coal liquefaction has been completed.
The units and processes utilized are reviewed
to highlight the progressive removal from the
streams of compounds or materials capable of
contributing to air and water pollution. All final
effluents released to the environment are
estimated to be in compliance with applicable
or related Federal and State standards.
Methods of environmental control for the
following specific areas are discussed:
• Fate of trace elements present in coal.
• Formation and destruction of metal car-
bonyls.
• Cyanide formation, partitioning among
effluent streams, and final decomposi-
tion.
• Formation of coal-tar carcinogens and
biohazards involved.
There still exist some environmental aspects
specific to coal conversion for which additional
experimental data are required. Research and
development programs that can provide this
additional information are defined.
INTRODUCTION
Development of viable coal conversion
technology is a national priority. A prime
responsibility for development of this
technology rests with the Energy Research and
Development Administration—Fossil Energy
(ERDA-FE). The Ralph M. Parsons Company is
assisting ERDA-FE in reaching this objective by
developing preliminary designs and economic
evaluations for commercial coal conversion
facilities. Preliminary commercial designs for
four of these facilities have been completed so
far, namely for a Demonstration Plant produc-
ing clean boiler fuels from coal, for a complex
producing oil and power by COED (Coal Oil
Energy Development) based pyrolysis coal con-
version, for an Oil/Gas Plant using integrated
coal conversion technology, and for a Fischer-
Tropsch facility producing liquid hydrocarbons
plus substitute natural gas by indirect coal li-
quefaction.
The definition of facilities and procedures to
assure that environmentally acceptable plants
can be designed and operated is integral to the
design effort. The basis for establishing en-
vironmental control facilities and operating pro-
cedures is the many coal conversion process
development units and pilot plants being
operated in the United States plus experience
gained from related industries such as
petroleum processing.
This paper concerns specific environmental
aspects of a Fischer-Tropsch facility. The
technology involved, outlined in Figure 1, con-
sists of coal gasification to produce a carbon
dioxide/carbon monoxide/hydrogen syngas,
purification of this gas to remove carbon diox-
ide and hydrogen sulfide, adjustment of com-
position to increase the hydrogen content, and
catalytic conversion of the gas to form prin-
cipally hydrocarbon liquids. Part of the
unreacted syngas is upgraded by methanation
to substitute natural gas (SNG). A version of
this technology is presently applied on a com-
mercial scale in the Republic of South Africa.
The Parsons conceptual commercial design
incorporates advanced technology such as a
high temperature-high pressure gasifier based
on Bi-Gas principles and a flame-sprayed
catalytic reactor for Fischer-Tropsch conver-
sion. Both of these are in the development
stage and require further work prior to the
design and construction of commercial plants.
Successful application of these technologies
could lead to conversion of coal to liquid and
gaseous fuels with an overall thermal efficiency
of 70 percent. A report describing the concep-
tual design and economic analysis of the facili-
ty has been published.1
As conceived, the plant will be located adja-
cent to a coal mine in the Eastern Region of the
409
-------
SNG
STEAM OXYGEN
ALCOHOLS
Figure 1. Simplified block flow diagram, Fischer-Tropsch conceptual plant.
Figure 2. Artist's concept, Fischer-Tropsch plant.
410
-------
Interior (coal) Province of the United States.
The design is based on use of 27,000 metric
tons per day (MgPD) [corresponding to 30,000
U.S. tons per day (TPD)] of cleaned bituminous
coal, containing 1.1 percent nitrogen and 3.4
percent sulfur. The premium products obtain-
ed, containing nil sulfur or nitrogen, consist of
2,200 MgPD (2,400 TPD) naphthas, 1,900
MgPD (2,100 TPD) of diesel fuel, 650 MgPD
(700 TPD) of fuel oil, and 6,000 MgPD (6,600
TPD) of SNG. Heat recovery provides all power
and steam required to operate the complex; ex-
cess electric power for sale (140 megawatts) is
also produced. An artist's concept of the
Fischer-Tropsch complex is shown in Figure 2.
AIR POLLUTION ABATEMENT
The major air pollution abatement effort is
aimed at desulfurizing the gases generated dur-
ing the coal conversion process to make the
fuels produced environmentally acceptable. In
a Fischer-Tropsch plant, environmental and
process goals coincide because the presence of
sulfur inhibits the effectiveness of Fischer-
Tropsch catalysts.
The air pollution abatement procedure is
outlined in Figure 3, which shows the nature
and amount of all streams vented to the air;
these streams consist for the major part of inert
gases (nitrogen and carbon dioxide). The ef-
fluent gases are shown vented separately to
the air to identify the contribution of specific
process units. In reality, however, all streams
with the exception of the particulates from the
coal drying plant are combined into a single
stack before venting to the air.
The coal grinding and drying unit is the only
source of paniculate emissions. A baghouse
system removes most of the particulates from
the vent streams, with emissions to the air
meeting both the Federal standard for thermal
dryer gases and other standards related to coal
gasification plants. The source of heat for the
drying process is excess steam from the
Fischer-Tropsch plant; no combustion gases
are generated by the operation.
The coal gasifier receives powdered coal,
steam, and oxygen and generates hydrogen,
carbon monoxide, carbon dioxide, methane,
hydrogen sulfide, and minor amounts of am-
monia, carbon oxysulfide, cyanides, and sulfur
dioxide. The reactor operates at high pressure
(3.5 MPa, 500 psia) and temperatures (1 650°
C, 3000° F in the lower stage and 930° C,
1 700° F in the upper stage). At these elevated
temperatures, nil oils or tars are produced.
The gaseous stream carries all the char and
ash produced on gasification of the coal; the
largest part of these materials is removed by a
series of cyclones, followed by a hot elec-
trostatic precipitator. Recovered char is return-
ed to the lower section of the gasifier, where
char gasification occurs by reaction with steam
and oxygen while the accompanying ash melts
and is removed as slag. The small amount of
char and ash particles still accompanying the
gases after passing through the cyclones and
hot precipitator is removed by two wet scrub-
bers followed by a cold electrostatic
precipitator. All the ammonia and part of the
hydrogen sulfide present are also removed by
the scrubbers.
The next treatment step concerns the
removal of acid gases (carbon dioxide and
hydrogen sulfide). A physical solvent process
removes these gases from the main stream,
then, on selective regeneration, releases a
stream of hydrogen sulfide containing part of
the carbon dioxide. The hydrogen sulfide
stream is sent to the sulfur recovery plant. The
carbon dioxide stream is vented to the air
together with very small amounts of carbon
monoxide and hydrogen sulfide.
The sulfur recovery plant oxidizes 95 percent
of the hydrogen sulfide to high-purity elemental
sulfur. The remaining 5 percent is present in
the tail gas, which is treated in a tail gas unit
where all sulfur species are reduced to
hydrogen sulfide, then absorbed by an alkaline
solution, and oxidized to also give high-purity
sulfur. The final vent gas contains carbon diox-
ide plus traces of carbon oxysulfide, hydrogen
sulfide, and carbon monoxide. The sulfur
balance for the plant is detailed in Table 1; a
total of 98 percent of the coal sulfur content is
recovered as elemental sulfur.
The purified gas is now suitable for conver-
sion to hydrocarbon fuels in a Fischer-Tropsch
reactor. Carbon dioxide generated at the same
time is removed by absorption in a caustic solu-
tion and is then vented to the air on regenera-
411
-------
MMTKUIATE BEHOV»1. SYSTEM. RAW SYNTHESIS GAS
1. CvdMK J. HolEhctnuilcPnciMmif:
4. CMaCmnnaiiePnniAMoi
SULFUH. 53 TPO
UOUID
" HVOROCADBC
Figure 3. Block flow diagram, air pollution abatement. Fischer-Tropsch plant (1 TPD = 0.9 MgPD)
-------
TABLE 1
SULFUR BALANCE
Sulfur Contributions
MgPD
TPD
Total Input from the Typical Feed Coal 925.3 1,020.0
Outputs: As Elemental Sulfur from
Coal Gasifier Gas
As Reduced Sulfur Emissions
(19%H2S,81%COS)
As Sulfur Dioxide Emissions
(actually emitted every six
months on regeneration of
917.5 1,011.4
0.7
0.8
the shift catalyst)
In the Ash
0.7
6.4
925.3
0.8
7.0
1,020.0
tion of the absorbent. The vent stream contains
traces of carbon monoxide together with traces
of light boiling hydrocarbons and methane (a
nonpollutant). The Fischer-Tropsch catalyst ab-
sorbs the last traces of sulfur present;
therefore, all fuels produced, gaseous and li-
quid, and the chemical byproducts (alcohols)
contain nil sulfur.
The streams released to the air are combined
in a single stack before venting. The overall
amounts and concentrations are shown in
Table 2.
Source Emission Standards for coal conver-
sion plants have not been issued by the Federal
Government. Guidelines for hydrocarbon (100
ppm) and sulfur dioxide (250 ppm) have been
TABLE 2
COMBINED GASEOUS EFFLUENTS
Gaseous Effluent
MgPD
TPD
ppm
Carbon Dioxide
Carbon Monoxide
Carbon Oxysulfide
Organics(C2-C6
Hydrocarbons)
Hydrogen Sulfide
36,688
9.9
1.3
1.0
0.12
42,647
10.9
1.4
1.1
0.13
306
18
21
3
proposed by EPA for Lurgi coal gasification
plants. These guidelines are not applicable to
the Fischer-Tropsch plant because a different
technology is utilized; they are, however, met
by the plant effluents.
Of the states, only New Mexico has issued
specific regulations covering coal gasification
plants; these regulations can be considered for
illustrative purposes only because the Fischer-
Tropsch plant, as conceived, would be located
in the U.S. Eastern Interior (coal) Region. The
State of Illinois has issued standards for
petrochemicals; this technology is somewhat
related to a Fischer-Tropsch operation. Federal
standards. for petroleum refinery sulfur
recovery plants have been proposed;3 Fischer-
Tropsch technology utilizes similar sulfur
recovery procedures. For illustration purposes
only, the Federal, Illinois, and the New Mexico
source emission standards are compared in
Table 3 with the emissions from the conceptual
Fischer-Tropsch coal conversion plant. As
shown in the table, all estimated emissions are
projected to either meet or be below the
standards.
A dispersion modeling study, using average
atmospheric conditions and the EPA-developed
PTMAX computer program, was carried out;
the results obtained show that the Fischer-
Tropsch emissions can meet ambient air quality
standards after atmospheric dispersion.
As shown in Table 2, significant carbon diox-
ide emissions would be generated by the
Fischer-Tropsch commercial plant; therefore, it
appeared desirable to investigate the possible
effects of these emissions. Carbon dioxide is
not toxic, and the natural background concen-
tration in the atmosphere has been estimated at
300 to 500 ppm.
Global weather modification effects have
been attributed to increased carbon dioxide
generation by fossil-fuel combustion. A gradual
warming trend on the order of 0.5° C in 25
years has been predicted; however, actual
temperature trends have shown a cooling of
0.3° C from 1 945 to the present.
On a localized scale, no micrometeorological
effects due to increased carbon dioxide have
been reported. Emissions from the Fischer-
Tropsch facility could approximately double the
average atmospheric carbon dioxide concentra-
413
-------
TABLE 3
COMPARISON OF GASfOUS EMISSIONS WITH FEDERAL, ILLINOIS, AND NEWMEXICO SOURCE EMISSION STANDARDS
(State standards are expressed in the units issued. 11b * 453.6 g; 1 gr = 64.8 mg; 1 Btu = 10S5 J;
1 ft3 « 0.028 m3; MM - milion; HKV = higher heating value; L - lower.)
Pollutant
Federal Standards,'
Petroleum Refinery
Sulfur Recovery Plant
Illinois Standards,
Petrochemical Plant
New Mexico Standards,
Coal Gasification Plant
Gaseous Effluents,
Fischer-Tropsch Plant
Paniculate Matter
Sulfur Dioxide
Carbon Monoxide
Nitrogen Oxides
Organics (methane excluded)
Total Reduced Sulfur
(H2S + COS + CS2)
Hydrogen Su If id e
Hydrogen Cyanide
Hydrogen Chloride/
Hydrochloric Acid
Ammonia
Gas Burning Process Boilers,
Part icu late Matter
Gas Burning Process Boilers,
Sulfur Dioxide
Total Sulfur
. - 78 Ib/hr
250 ppm 1.2 Ib/MM Btu
- 200 ppm, 50% xs air
0.7 Ib/MM Btu
- 100 ppm
300 ppm (CH4 equivalent)
10 ppm -
- -
— —
- -
— —
- -
0.03 gr/ft3
^
-
100 ppm
10 ppm
10 ppm
5 ppm
25 ppm
0.03 Ib/MM Btu, LHV
0.1 6 Ib/MM Btu, LHV
0.008 Ib/MM Btu of feed
67 lb/hr(a), 0.03 gr/ft3
164 ppm(c)
Nil
55 ppm
21 ppm
3 ppm
Nil
Nil
Nil
J«
0.003 Ib/MM Btu(e)
'a' From coal-drying plant.
'b' 47.4 tons of sulfur dioxide emitted twice a year, over 24-48 hours, on . --generation of the catalyst of each shift reactor (six reactors
total). If this value were averaged out over the year, it would correspond to 0.004 Ib/MM Btu/day.
'c' Value obtained on application of the 50% excess air correction to the streams originating from the acid gas removal unit and from
the sulfur plant.
"*' Not applicable (none included in the design).
'*' Includes the sulfur dioxide emitted occasionally on regeneration of the shift reactor catalyst (see Note* ' above).
-------
tions to 600 to 1000 ppm in the vicinity of the
plant. The lowest concentration at which some
physiological effects (dyspnea and headache)
have been observed is 30,000 ppm; therefore,
no effects are expected at the levels men-
tioned. However, vegetable life has been
reported to benefit from increased atmospheric
concentrations of carbon dioxide.
AQUEOUS EFFLUENTS
The plant design is based on availability of an
adequate supply of water. The wastewater
treatment is therefore a combination of recycl-
ing and discharge of aqueous effluents. The
most heavily contaminated streams are con-
centrated by evaporation, with residuals
undergoing thermal destruction in the coal
gasifier. The medium-contaminated streams
are purified by oxidation and then reused as
makeup for boiler feedwater. The lightly
polluted streams are treated to make them ac-
ceptable to the environment and then are
discharged to a river. The generation and con-
trol of aqueous contaminants is outlined in
Figure 4, which shows the sources of
wastewater (listed on the left-hand side) and
their progressive treatment and disposition.
The river water supply provides 2,725 m3/hr
(12,000 gpm) of raw water, which, after
purification by settling and sand filtration, is
used for cooling water makeup and, after fur-
ther deionization, for boiler feedwater makeup.
Potable and sanitary water is supplied by wells.
The water supply from the river is not used for
coal sizing and handling (a captive system
feeding on a mine-based pond is used for this
unit) or for coal grinding and drying, where no
wet systems are employed.
One of the major contaminated streams is the
sour water generated by the wet scrubbers
cleaning the gases produced by the coal
gasifier. The major contaminants present are
hydrogen sulfide, ammonium sulfide, oil,
phenols, thiocyanates, cyanides, and solids
(ash and char particles). After removal of any
oily materials by extraction, most of the
gaseous contaminants (hydrogen sulfide and
ammonia) are removed by a reboiler-stripper,
and then conveyed to the sulfur plant where
the hydrogen sulfide is converted to elemental
sulfur and the ammonia is oxidized to nitrogen.
The stripped aqueous stream is now treated in
an cxidizer with oxygen at high pressure to
convert most of the organics present to in-
organic gases such as carbon dioxide, nitric ox-
ide, and sulfur dioxide. These are led back to
the coal gasifier; the reducing atmosphere
prevailing there is expected to reduce nitric
acids and sulfur dioxide to nitrogen and
hydrogen sulfide. After settling and filtration,
the aqueous effluent stream from the oxidizer is
deionized and reused as boiler feedwater
makeup.
The Fischer-Tropsch reactor produces,
besides the desired hydrocarbon fuels, a
number of alcohols and organic acids. When
the product stream is purified by treating with
caustic, a waste stream containing alkaline
salts of low-molecular weight organic acids is
produced. This stream is combined with the
boiler water blowdown and the solids slurry ob-
tained as a residue from the settling of the
treated sour water, and then concentrated in a
triple-effect evaporator. The evaporator con-
densate is used for boiler feedwater, while the
residue is sprayed on the feed coal at the en-
trance to the coal dryer. A more thorough
evaporation occurs in the latter unit; the
organic materials are then destroyed when the
coal is fed to the gasifier, while the inorganic
materials are removed with the ash.
The cooling-tower blowdown stream is the
largest in volume, and is only lightly con-
taminated by corrosion inhibitors (zinc salts
and inorganic phosphates) and scale control
agents (organic phosphate esters); this stream
is mixed with deionizer wastes containing
mainly sodium sulfate and other inorganic
salts. After neutralization, this stream is treated
with lime in a settler-clarifier. The lime sludge,
containing most of the zinc and phosphates, is
disposed of in a landfill, while the treated
stream is returned to the river.
Any oily water streams produced during
plant operation are combined with laboratory
wastewater, and then passed through a sand
filter to coalesce the oil particles. After physical
separation of the oil (returned to the gasifier),
the aqueous effluent is led to a biopond, where
the organic materials present are converted to
inorganics by bacterial activity. The biopond
415
-------
do uitfur recovery unit)
ItOflMifierl
, NO, S02
(to nawnlitiiion)
200*
9% organic ult lolution
(•prayed on coal at
entrance to coal dryer)
to ilag quench, coat
•»- preparation & mine duit
control w required
spray. 300 gpm 4man)
evaporation, 8400 gpm
boiler fwdwaiir
makeup, 1600 gpm
12,000 gpm _
SETTLER
-4 1 200 jpm
SAND
FILTER
cooling water
mikiup. 10.200 gpm
Urn
/ \
COOLING
TOWER
Idown. 1500 a
cooling
(to nxitmimion)
Figure 4. Block flow diagram, water treatment and supply, Fischer-Trapsed plant (1 gpm = 0.227 m3/hr)
-------
also receives a minor stream from the sewage-
treatment plant, and is used as firewater sup-
ply, with any overflow discharged to the river.
Strict housekeeping is expected to contain con-
tamination of stormwater to very small
volumes; any contaminated water is collected
in a stormwater pond (not shown in Figure 4)
for subsequent metered feeding to the biopond
for treatment.
No aqueous effluent standards specifically
addressed to coal conversion plants have been
issued by the Federal government or by state
legislatures. Standards that are somewhat
related to a Fischer-Tropsch process are the
Federal standards issued for petroleum refin-
ing. Average obtainable concentrations that
were the base for such standards are reported
in Table 4, together with the corresponding
values for the aqueous effluents estimated for
the Fischer-Tropsch plant. As shown in the
table, these estimated values are either the
same or lower than the Federal parameters.4
The State of Illinois has issued aqueous ef-
fluent standards applicable to all sources
discharging to the natural waters of the state.
TABLE 4
COMPARISON OF AQUEOUS EFFLUENTS WITH
FEDERAL PETROLEUM REFINERY STANDARDS*
Parameter
BODS
COO
Total Organic
Carbon
Suspended
Solids
Oil and Grease
Phenol
Ammonia-N
Sulfide
Cr. Tertiary
Cr. Hexavalent
Federal Standards,
Petroleum
Refinery
15
100
33
10
5
0.1
80% removal
0.1
0.25
0.005
Aqueous Effluents,
Fiseher-Tropsch
Plant
10
100
33
10
5
nil
nil
nil
nil
nil
These standards are reported for illustration
purposes in Table 5. All Fischer-Tropsch ef-
fluents are estimated to either meet, or be
lower than such standards.
SOLID WASTES
The Fischer-Tropsch plant generates two
main types of solid waste materials: slagged
ash from the coal gasifier, and sludges from
various wastewater treatment units. All of the
ash produced during coal gasification is return-
ed to the bottom of the gasifier together with
carbon residues (char); on combustion of the
char with oxygen, the temperature produced is
sufficient for melting the ash to a slag, which is
withdrawn from the bottom of the gasifier. It is
estimated that 2132 MgPD (2350 TPD) of slag
are produced. On quenching with water, the
TABLE 5
AQUEOUS EFFLUENT STANDARDS,
STATE OF ILLINOIS
Constituent
Maximum Concentration
(mg/1)
Average attainable concentrations from the application of
best practicable control technology currently available4.
Arsenic (total) 0.25
Barium (total) 2.0
BOD-5 10.0
Cadmium (total) 0.15
Chromium (total hexavalent) 0.3
Chromium (total trh/alent) 1.0
Copper (total) 1.0
Cyanide 0.025
Fluoride (total) 15.0
Iron (total) 2.0
Iron (dissolved) 0.5
Lead (total) 0.1
Manganese (total) 1.0
Mercury (total) 0.0005
Nickel (total) 1.0
Oil (hexane solubles or equivalent) 15.0
pH range 5-10
Phenols 0.3
Selenium (total) 1.0
Silver 0.1
Zinc (total) 1.0
Total Suspended Solids 12.0
417
-------
slag is fragmented into vitrified granules, which
are returned to the mine for burial with the mine
spoils. If outlets exist nearby, this material
could also be utilized as filler in aggregates for
construction blocks or road building.
The sludges from the wastewater treatment
units contain mainly inorganic salts, such as
calcium and zinc phosphates, which are added
to cooling water as corrosion inhibitors. If these
sludges were buried with mine spoils, possible
contamination of groundwater by zinc could
result; they are therefore disposed of in a
secure landfill.
The mining and coal cleaning and sizing
operations generate sizable amounts of solid
wastes which are disposed of at the mine site.
The surface mining operation proceeds in an
orderly fashion, following an environmentally
sound mining plan. The topsoil is removed and
stored, then the overburden is stripped and
used for refilling of the previous pit, in combina-
tion with the inorganic wastes from the coal
cleaning and sizing plant (rocks, clay, and mud)
and the vitrified ash from the coal gasifier. The
mined out area is restored to approximately the
original surface contour, then the topsoil is
replaced, fertilized, and reseeded, completing
the land reclamation cycle.
The coal cleaning and sizing plant is located
in proximity of the mine. This arrangement
minimizes the exposure to the air of mine
spoils, with consequent negligible oxidation of
coal pyrites to oxygenated sulfur acids.
FATE OF TRACE ELEMENTS PRESENT
IN COAL
Due to its organic origin and its intimate com-
mixture with crustal formations, coal contains
a large number of elements in minor or trace
quantities. Actually, out of 92 known nontran-
suranic elements, only 14 (shown in Figure 5)
have not yet been found in coal.
Average amounts of trace and other
elements for 82 coals from the Eastern Region
of the Interior Coal Province are shown in Table
6. These values were developed during a re-
cent study5 carried out with thorough analytical
procedures; the coals analyzed were mainly
composite face channel samples.
A number of studies have analyzed the
TABLE 6
MEAN ANALYTICAL VALUES FOR 82 COALS FROM
THE ILLINOIS BASIN (FROM REFERENCE 5)*
Constituent
As
B
Be
Br
Cd
Co
Cr
Cu
F
Ga
Ge
Hg
Mn
Mo
Ni
P
Pb
Sb
Se
Sn
V
Zn
Zr
Al
Ca
Mean
14.91 ppm
113.79 ppm
1.72 ppm
15.27 ppm
2.89 ppm
9.15 ppm
14.10 ppm
14.09 ppm
59.30 ppm
3.04 ppm
7.51 ppm
0.21 ppm
53.1 6 ppm
7.96 ppm
22.35 ppm
G2.77 ppm
39.83 ppm
1.35 ppm
1.99 ppm
4.56 ppm
33.13 ppm
313.04 ppm
72.10 ppm
1.22 %
0.74 %
Constituent
Cl
Fe
K
Mg
Na
Si
Ti
ORS
PYS
SUS
TOS
SXRF
AOL
MOIS
VOL
FIXC
ASH
Btu/lb
C
H
N
0
HTA
LTA
Mean
CM
0.15
2.06
0.16
0.05
0.05
2.39
0.06
1.54
1.88
0.09
3.51
3.19
7.70
10.02
39.80
48.98
11.28
12,748.91
70.69
4.98
1.35
8.19
11.18
15.22
Abbreviations other than standard chemical symbols:
organic sulfur (ORS). pyritic sulfur (PYS), sulfate sul-
fur (SUS), total sulfur (TOS), sulfur by X-ray fluores-
cence (SXRF), air-dry loss (AOL), moisture (MOIS).
volatile matter (VOL), fixed carbon (FIXC), high-tem-
perature ash (HTA), low-temperature ash (LTA).
behavior of trace elements in coal-fired power
plants.6'7 In general, the elements have been
divided into two groups, the ones appearing
mainly in the bottom ash (elements or oxides
having lower volatility) and the ones appearing
mainly in the fly ash (elements or oxides having
higher volatility). For power plants using dry
particulate collection devices (e.g., elec-
trostatic precipitators), it was believed that the
418
-------
1 °
H
1.00797
Li
6.939
Na
22.9898
Be
9.0122
12
Mg
24.305
5
B
10.811
13
Al
26.9815
6 A
C
12.01115
14
Si
28.086
7 °
N
14.0067
15
P
30.9738
8 °
0
15.9994
16
s
32.064
9 °
F
185984
17
Cl
35.453
19
K
39.102
20
Ca
40.08
21 A
Sc
44.956
22
Ti
47.90
23 A
V
50.942
24 A
Ci
51.996
25
Mn
54.9380
26 A
Fe
55.847
27 A
Co
58.9332
28
Ni
58.71
29
Cn
63.54
30
Zn
65.37
31
Ga
69.72
32
Ge
72.59
33 A
As
74.9216
34
Se
78.96
35
Bi
79.909
37
Rb
85.47
38
Si
87.62
39 A
Y
88.905
40 A
Zi
91.22
41 *
Nb
92.906
42
Mo
95.94
45
Rh
102.905
46
Pd
106.4
47 A
Ag
107.870
48
Cd
112.40
49
In
114.82
50
Sn
118.69
51
Sb
121.75
52
Te
127.60
53
I
126.9044
55 •
Cs
132.905
56 A
Ba
137.34
57
La
138.91
A
72 A
Hi
178.49
73
Ta
180.948
74
w
183.85
78 A
Pt
195.09
79 A
Au
196.967
80 •
Hg
200.59
81 *
Tl
204.37
82 *
Pb
207.19
83
Bi
208.980
84
Po
[210]
86 °
Rn
[222]
88
Ra
[226]
90
Th
232.038
92 *
u
238.03
*58-71
Lanthonide
Typ. 4f
58 A
Ce
140.12
59
Pi
140.907
60 A
Nd
144.24
62 A
Sm
150.35
63 A
Eu
151.96
64 A
Gd
157.25
65
Tb
158.924
66 A
Dy
162.50
67
Ho
164.930
68 A
Ei
167.26
70 *
Yb
173.04
71
Lu
174.97
Figure 5. Periodic table of the elements. The elements shaded have NOT been found in coal.
-------
most volatile elements, such as mercury and
selenium, could actually-escape at the elemen-
tal state with the flue gas. Wet scrubbers,
however, were believed capable of removing
most of the elements from the gas streams and
transferring them to the liquid effluent.
Very few data are available for coal conver-
sion plants. A study on trace element disposi-
tion for the Sasol (South Africa) facility,
reported by the Los Alamos Scientific
Laboratory8 was able to follow the partitioning
of trace elements between solid residue (ash),
liquid streams, and gases. Among the elements
studied, lead, arsenic, and beryllium were
found mainly in the ash, selenium and tellurium
in the liquid streams, fluorine two-thirds in the
ash and one-third in the liquids. Mercury was
found present in all phases, but concentrated
mainly in the gas; however, 50 percent of the
mercury and 1 7 percent of the beryllium could
not be accounted for.
The possibility of leaching of trace metals
from the ash into ground or surface waters has
been questioned. Experimental studies have
been carried out on the leaching of power plant
fly ash or unslagged bottom ash;9 the studies
showed that selenium, chromium, and boron,
and occasionally mercury and barium, were
released on simulated leaching, and the con-
centrations reached exceeded the values
recommended by EPA for public water sup-
plies.
An on-going study at the University of Mon-
tana10 is investigating leaching of trace
elements from solid residues of coal conversion
plants under neutral, acidic, and basic condi-
tions. Preliminary results indicate that
manganese, mercury, and nickel are occa-
sionally released in amounts exceeding recom-
mended potable water standards. The study is
hampered by the unavailability of typical
residue specimens.
In the Fischer-Tropsch process, essentially
nil particulates from coal combustion escape in-
to the atmosphere. Particulate streams, wet or
dry, are returned to the bottom of the gasifier,
where ash and salts melt and are removed as
slag. Any eventual dispersion of the elements
present in the slag depends on the possibility of
leaching. Possibly, slagged ash features a glass
matrix which would inhibit leaching. Leaching
experiments using the slag generated by a slag-
ging gasifier, such as the Bi-Gas pilot plant or a
Koppers-Totzek unit, would be very useful.
The major concern, therefore, is to identify
trace elements which may be occurring in the
gaseous state. The reducing atmosphere pre-
sent in the middle and top part of the gasifier
may also favor different combinations, absent
in the oxidizing atmosphere of a power plant
boiler.
Among the trace elements present in coal
with recognized toxic properties, high volatility
elements (beryllium, mercury, and lead), do not
form gaseous hydrides, will condense on cool-
ing, and will very likely be removed by the
aqueous condensates formed in gas cooling
and/or purification. Arsenic, antimony, and
selenium have lower volatility but can form
gaseous (covalent) hydrides; arsine, stibine,
and hydrogen selenide. These hydrides
however, have stability characteristics which
preclude their formation at the temperature and
pressure prevailing in the Fischer-Tropsch
gasifier. From general chemical principles, it
would appear, therefore, that harmful trace
elements are not released to the atmosphere.
Experimental confirmation, however, is
desirable, especially for mercury, and should be
obtained from specific pilot plant studies.
FORMATION AND DESTRUCTION
OF METAL CARBONYLS
Metal carbonyls form by reaction of carbon
monoxide with free metals in the 40-300° C
(100-570° F) temperature range. Carbonyls
form with all transition metals; nickel, cobalt,
and iron carbonyls are most significant since
the metals from which they are derived are
used as catalysts or for structural
equipment.11'12 Higher pressures [of the order
of 100 MPa (1 5,000 psi)] and the presence of
hydrogen favor their formation, while oxygen
represses it. They decompose readily in air with
half-lives estimated at 10-15 seconds for
cobalt carbonyl, 10 minutes for nickel car-
bonyl, and a few hours for iron carbonyl.
These carbonyls are volatile liquids at room
temperature. They all exhibit toxicity, directed
at the respiratory system. The most harmful
among the three carbonyls is the nickel
420
-------
TABLE 7
SUGGESTED EXPOSURE GUIDELINES
FOR METAL CARBONYLS (FROM REFERENCE 11)
Metal Cartaonyl
Air Concentration (ppm)
Single Short Term
Exposure Eight-Hour Day
Ni(CO)4
Co(CO)x + CoH(CO)4
Fe{CO)5
0.04
0.10
0.10
0.001
-
0.01
derivative; for this carbonyl only, chronic ef-
fects and carcinogenic activity have been
observed. Suggested exposure guidelines and
chemical formulas are reported in Table 7.
Iron, nickel, and cobalt catalysts are used in
the Fischer-Trosch process, and low carbon
steel is employed for structural equipment.
However, at the relatively low pressures and
high temperatures prevailing, nil metal car-
bonyls are expected to be formed. In shutdown
operations, however, conditions under which
metal carbonyls can form may be experienced
for short periods of time. In these cases the
normal safe practice of flaring vent streams,
along with operation of all contaminant
removal systems, will prevent release of car-
bonyls to the atmosphere. Plant personnel who
may be entering vessels or handling catalysts,
however, will need to be trained in the proper
procedures and supplied with adequate protec-
tive equipment to safeguard their health.
FORMATION, PARTITION, AND DISPOSITION
OF CYANIDE
The question of the generation of cyanide, a
highly toxic ion, and of its possible release to
the environment, was explored for the Fischer-
Tropsch process. Under the chemical and
physical conditions experienced in the coal
gasifier, nearly all of the nitrogen content of the
coal is converted to molecular nitrogen. The re-
mainder is distributed between ammonia and
hydrogen cyanide, according to an equilibrium
relationship.
This relationship was investigated using a
Parsons-modified computer program for the
calculation of complex chemical equilibrium
compositions, originally developed by NASA13
for aerospace applications. The equilibrium
calculations were made over the 930° C
(1700° F, upper stage) to 1650° C (3000° F,
lower stage) temperature range and at the 3.5
MPa (500 psia) pressure which are represent-
ative of the conditions expected in the gasifier.
The equilibria considered involved a series of
molecular and ionic components compatible
with the elemental analysis of the charge to the
gasifier and with the probability of their occur-
rence in the effluent gas.
The results obtained, plotted in Figure 6,
show that very small amounts of cyanide, of
the order of 0.7 mole/hour, are produced at the
outlet temperature (930° C, 1700° F) of the
gasifier. Even if complete equilibrium were not
achieved but were equivalent for example to
that calculated for 1100° C (2000° F), the
quantities of cyanide in the gases would still be
quite small.
When the effluent gas undergoes wet scrub-
bing, most of the cyanide remains in the gas
1700 2000
2600
3000°F
IMP
12SO 160b°C
TEMPERATURE
Figure 6. Ammonia-cyanide equilibria.
421
-------
stream because the sour water generated is on-
ly slightly alkaline. It is then absorbed, together
with hydrogen sulfide, by the physical solvent
process; on regeneration, it is conveyed to the
sulfur recovery plant, where it undergoes ther-
mal oxidation to nitrogen and carbon dioxide.
The cyanide fraction which had remained in the
aqueous stream is treated, together with other
organics, with oxygen at high pressure in the
oxidizer unit; there these compounds are con-
verted to inorganic gases such as carbon diox-
ide and nitric oxide. These are led back to the
coal gasifier, where under the prevailing reduc-
ing conditions nitric oxide is expected to be
reduced to nitrogen.
It appears therefore that very little cyanide is
generated, and any amounts produced are
destroyed within the Fischer-Tropsch process,
so that nil cyanide is released to the environ-
ment.
FORMATION OF COAL TAR CARCINOGENS
AND BIOHAZARDS INVOLVED
Of particular interest in coal conversion pro-
jects is the possible formation of carcinogenic
compounds on hydrogenation and pyrolysis of
coal. These compounds are polynuclear
aromatic hydrocarbons and heterocyclics
usually found in coal tar. Nil coal oils and coal
tars are expected to be produced under the
operating conditions of the entrained coal
gasifier used in the Fischer-Tropsch plant.
Carcinogenic activity for laboratory animals
has been observed for distillation residuals ob-
tained from petroleum refining.14 Similar frac-
tions are obtained on distillation of the liquid
hydrocarbons produced by the Fischer-Tropsch
reactor, and Fischer-Tropsch oils boiling above
250° C (480° F) were found carcinogenic in
mice.15 However, the carcinogenic activity is
much smaller than observed for coal tar pro-
ducts because Fischer-Tropsch fuels consist
essentially of aliphatic compounds. Crudes also
contain less aromatics than coal oils and tars;
the refining process occurs in close systems,
so that very little contact of workers with pro-
ducts occurs; equipment handling residual oil is
often color coded, so that workers are warned
to avoid direct contact. As a consequence,
cancer frequency in oil refinery workers is the
same as for other industrial occupations. Equal-
ly efficient occupational safety procedures will
be maintained in Fischer-Tropsch operations,
thereby minimizing any environmental risks.
ACKNOWLEDGEMENT
We gratefully acknowledge the support and
guidance of ERDA-FE in our work, and the con-
tribution of the many people at Parsons who
participate in coal conversion activities.
REFERENCES
1. J. B. O'Hara et al., "Fischer-Tropsch
Complex: Conceptual Design/Economic
Analysis. Oil and SNG Production," R&D
Report No. 114 - Interim Report No. 3.
Energy Research and Development Ad-
ministration, Washington, D.C., January
1977.
2. "Draft Standards Support and En-
vironmental Impact Statement, Volume I:
Proposed Standards of Performance for
Lurgi Coal Gasification Plants," EPA Of-
fice of Air Quality Planning and Stand-
ards, Research Triangle Park, North
Carolina, November 1976 (will be
reissued as "Guidelines" in late 1977).
3. "Proposed EPA Performance Standards
for Petroleum Refinery Sulfur Recovery
Plants," Federal Register, 41, 43866,
October 4, 1976.
4. "Development Document for Effluent
Guidelines and New Source Performance
Standards for the Petroleum Refining
Point Source Category," U.S. En-
vironmental Protection Agency, Report
EPA-440/1-74-014a, Washington, D.C.,
April 1974.
5. R. R. Ruch et al., "Occurrence and
Distribution of Potentially Volatile Trace
Elements in Coal," Illinois State
Geological Survey. Environmental
Geology Note No. 72, August 1974
(NTIS Report No. PB 238091).
6. J. W. Kaakinen et al., "Trace Element
Behavior in Coal-Fired Power Plant," En-
viron. Sci. Technol., 9, 862-869 (1 975).
422
-------
7. D. H. Klein et al., "Pathways of Thirty-
Seven Trace Elements Through Coal-Fired
Power Plant," Environ. Sci. Technol., 9,
973-979 (1975).
8. W. S. Bennett et al., "WESCO Coal
Gasification Plant: Navajo Considera-
tions." Los Alamos Scientific Laboratory
Report No. LA-6247-MS, February 1976.
9. W. F. Holland et al., "The Environmental
Effects of Trace Elements in the Pond
Disposal of Ash and Flue Gas Desulfuriza-
tion Sludge," Research Project 202 by
the Radian Corp. for the Electric Power
Research Institute, Sept. 1975 (NTIS
Report No. PB 252090/6WP).
10. W. P. Van Meter and R. E. Erickson, "En-
vironmental Effects from Leaching of Coal
Conversion By-Products," ERDA Report
Series FE-2019, 1977.
11. R. S. Brief et al., "Metal Carbonyls in the
Petroleum Industry," Archives of En-
vironmenal Health, Amer. Ind. Hygiene
Assn., 23, 373-384 (1971).
12. J. Brinestad, "Iron and Nickel Carbonyl
Formation in Steel Pipes and Its
Prevention-Literature Survey," Oak Ridge
National Laboratory Report No.
ORNL/TM-5499, September 1976.
13. S. Gordon, and B. J. McBride, "Computer
Program for Calculation of Complex
Chemical Equilibrium Compositions,
Rocket Performance, Incident ,and
Reflected Shocks, and Chapman-Jouguet
Detonations," NASA Special Publication
SP-273, Washington, D.C., 1 971.
14. E. Bingham, "Carcinogenic Investigation
of Oils from Fossil Fuels," University of
Cincinnati Kettering Laboratory, Cincin-
nati, Ohio, 1974.
15. W. C. Hueper, "Experimental Car-
cinogenic Studies on Hydrogenated Coal
Oils. II. Fischer-Tropsch Oils," Industrial
Medicine and Surgery, 25, 459-62
(1956).
423
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CONTROL TECHNOLOGY
DEVELOPMENT FOR FUEL
CONVERSION SYSTEM WASTES
Louis E. Bostwick
Pullman Kellogg
a Division of Pullman Incorporated
Houston, Texas
Abstract
Pullman Kellogg's contract with the En-
vironmental Protection Agency concerns con-
trol technology development for fuel conver-
sion system waste utilization and disposal, for
coal storage, preparation, and feeding, and for
waste water treatment. The program includes
assessment of available and developing control
technology as applied to fuel conversion ef-
fluents/emissions/wastes and relationship to
present and proposed environmental regula-
tions, continues with theoretical and ex-
perimental development of promising alternate
control technologies, then concludes with an
overall comparative analysis of all technologies
and an engineering design and cost estimate
for those control methods judged to be ap-
propriate for integration into conversion
system flow schemes.
Since the program has been operating for
only five of its scheduled 36 months, this paper
may be considered as a progress and planning
report.
Pullman Kellogg's contract with EPA has as
its objective the development of control
technology for fuel conversion system waste
utilization and disposal, for coal storage,
preparation, and feeding, and for wastewater
treatment. The 36-month project involves
assessment of available and developing control
technology, development of control technology
and evaluation of control technology. The work
is designed to interface with other studies in
the EPA synthetic fuels program for inter-
change of information and definition of
problems.
THE PROJECT PROGRAM
The program began in April 1977 with
literature searches and data surveys directed
toward definition of the emission streams in
fuel conversion processes by quantity and
composition, assessment of available and
developing control technology and identifica-
tion of existing and proposed environmental re-
quirements. The results of these efforts are the
base for the steps of the program that follow:
1. Projection of new or more stringent en-
vironmental standards.
Hazardous or environmentally
dangerous constituents of conversion
plant waste streams are evaluated and
new or more stringent regulations are
projected with emphasis on health ef-
fects, land use considerations and
geography. These criteria serve as
guides for development of control
technology.
2. Identification of control needs.
Controls required to meet existing and
proposed standards and criteria for
conversion processes are determined
by comparison of the pollutant stand-
ard with effluents from available or
developing control processes. Areas re-
quiring better control technology are
then defined.
3. Identification of new data needs.
Comparison of the review of control
technology with the identification of
control needs defines the areas in
which data are insufficient or
unavailable for assessment of needs for
available technology or control
methods.
4. Field data acquisition.
Data to at least partially fill the gaps
defined as new data needs are gathered
during field trips to observe control
processes in fuel conversion processes
or in similar control processes in other
industries. Compositions and quantities
of emissions streams are determined
and sampling and analysis of control
process influent and effluent streams
are accomplished.
5. Economic analysis of available and
developing control technology.
Capital and operating costs for in-
dividual control processes are deter-
mined and then used to predict costs
for environmental control for fuel con-
version processes.
424
-------
6. Program emphasis for development of
control technology.
In accordance with the overall EPA ob-
jectives, a multiyear control technology
development plan is formulated, time-
phased to coincide with fuel conversion
technology development.
7. Evaluation of alternate control
technology.
Theoretical studies of control
technology that are available in the
literature are reviewed for mechanisms
that show promise and might be
developed for areas where new
technology is needed. Assembly of
conceptual flow diagrams of promising
control routes Is followed by cost
evaluations and comparison of pro-
posed processes with existing proc-
esses. With consideration of the pro-
gram emphasis philosophy, the field of
new processes is narrowed to those
most attractive, technically and
economically, for further development.
8. Laboratory and bench-scale develop-
ment.
Accurate definition of objectives and
analysis of means of attaining the ob-
jectives leads to formulation of a pro-
gram for experimentation to establish
conditions of operations required to
achieve the desired level of control.
The laboratory work is seen as a
screening mechanism to establish the
range of control process operations
which aids in selection of operating
methods for bench-scale development.
9. Integration of process with needed
control technology.
This check point ensures that proc-
esses under development in the
laboratory fit the specific situations
they are Intended to control. New
laboratory data are compared with the
concepts developed during evaluation
of promising alternate technology.
10. Overall comparative analysis of control
processes.
Existing available control processes, as
required by fuel conversion processes,
are compared according to costs, level
of control, applicability and other ad-
vantages and disadvantages. After
laboratory and bench work are com-
plete, promising developing control
technology is evaluated by the same
criteria and with such additional con-
siderations as costs of remaining
development programs and risks.
11. Design preparation,
Several control processes are selected
from the results of the overall com-
parative analysis and capital invest-
ment and operating costs are
developed for each complete control
process.
PROGRESS IN THE PROGRAM
Literature Search for Conversion
Process Information
As originally conceived, information on the
quantities and compositions of the effluents
and wastes from each coal conversion process
would be collected and grouped as solid, liquid,
or gas in order to define the areas for applica-
tion of control technology. However, a lack of
useable information on conversion process
emissions became apparent very early in the
survey of published reports and articles con-
cerning the processes because the emphasis in
development of conversion processes had been
almost entirely on the processes themselves
and much less attention had been given to col-
lecting data on their emissions. Some small
amount of information was published on emis-
sions, derived mainly from laboratory and
bench-scale process development work, and
some information was available in reports on
conceptual conversion process designs, but
the total was insufficient for definition of re-
quired control technology. The problem was
compounded by the one- to two-year time in-
terval between completion of a report of work
on a particular process and its publication and
procurement.
Literature searches were conducted through
EPA, NTIS, and Chemical Abstracts data banks
and the microfiche library of Oak Ridge National
Laboratory reports at Rice University in
Houston. The search continues through weekly
monitoring of NTIS abstracts and Chemical
Abstracts for the life of the project.
425
-------
TABLE 1
AVAILABLE INFORMATION ON EMISSIONS FROM
COAL GASIFICATION PROCESSES
niiST PI .j'F!iT t4^
P A
A P A
P
A A P
P P
A A A
A A
A A Q
PA A
A A Q
Q
Q
Q
A A
A
A A
A A
Q A
P P
P P P
A
A
P
Q
P
Stream Analyses (1)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16
CO, Acceptor
Synthane
HyGas (Steam/Ox.)
HyGas (Steam/Iron)
Lurgi (Dry Ash)
Lurgi (Slag Ash) (2)
Bi-Gas
Battelle •'Agglomerating Ash (3)
COGAS (4)
Hydrane
Koppers-Totzek
Winkler
Westinghouse (15)
Foster Wheeler (6)
AI Molten Salt (7)
Combustion Engineering (8)
Riley-Morgan
Wellman-Galusha
U-Gas
Babcock & Wilcox (9)
ERDA/MERC (10)
Texaco (2)
BCR (11)
Woodall-Duckham (12)
(1) A = Analysis, either real or conceptual; P = Partial analysis;
Q = Quantities only.
( 2) Proprietary. No data released to date. Possible future release.
( 3) PDU operation expected late 1977. Effluent data available possibly
in early 1978.
( 4) Development mostly proprietary, very little effluent data. Now being
evaluated by ERDA vs. Slagging Lurgi.
( 5) Emphasizes turbine development. Little effluent data available.
( 6) Conceptual design only. No data. Used Bi-Gas gasifier.
( 7) PDU scheduled for 1978-9 operation. Very limited data mostly on process.
( 8) Pilot plant effluent data expected in six-twelve months.
( 9) Will not be built. Bi-Gas is very similar and was built by B$W.
(10) Process development with no published effluent data.
(11) Pilot Plant. No effluent data.
(12) Commercial operation. No published effluent data.
Q
A
P
P
Q
Q
A A
A
A
A
A
Q
A
A
A
426
-------
TABLE 2
AVAILABLE INFORMATION ON EMISSIONS FROM
COAL LIQUEFACTION PROCESSES
AnsnnTi.rNT ( i j j__
10
fpfiF"
iV\i :vr niAf.r
CATALYST 1 1J K'ViTP
ft.UE CA3 f-j- iiiX
I'pr.r.i '•
IOITT-ACTION ::'.r,M!A
pifoniirTinr; CHAR
AfJD rrnir-
b
ATT'if)
Lll -Gi.
Uli ' MT_ I .'J
>.-A?TIv HATER ll-J^
'ARTICL'IjATES fJ-^r'
St]
fjnp WATPR ( 1 f^
(UL r'V vr.rii (17)
I *
T '"'AS CAS ( IB)^
nnM f1 UNIFICATION PHOIHJCT
jiir-r
n ,n;p sin.rrp _Ll ^
ITCOVHRY rHODu::T
In PAN (21
FLUF. GAS
cream Analyses (1)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
P Q P Q
Q Q
Q
A
A A Q A Q A
Q
P A P Q A
Q P Q Q
Q A Q Q
COED (2)
Clean Coke (3)
SRC (4)
H-Coal (5)
Synthoil (6)
Donor Solvent (7)
(1) A = Analysis, either real or conceptual; P = Partial analysis;
Q = Quantities only.
(2) Information from conceptual design for COED combined with COGAS.
(3) No published effluent information to date. Data expected by end of 1977
(4) Information from conceptual design of SRC II process.
(5) Pilot plant construction to be completed in 1978, operation scheduled
into 1980.
(6) PDU operation to start in 1978.
(7) No published effluent information to date. Environmental Assessment
scheduled for late 1977 completion.
-------
Results of the Literature Search for
Conversion Process Information
The literature searches were supplemented
by direct contact with conversion process
developers or with ERDA, whichever was ap-
plicable, to ascertain process status and
availability of reports that would contain emis-
sions data. The results of the data search are
summarized in Table 1 for gasification proc-
esses and Table 2 for liquefaction processes.
The data gaps, the status of the processes and
the projections for process development in the
future emphasize the validity of one of the
basic concepts of the Fuel Process Branch of
EPA: that the level of environmental concern
may be relatively low during the initial in-
vestigations of promising fuel conversion pro-
cesses and should increase to comprehensive
programs as the conversion processes are
developed during the pilot plant and larger
operations. Thus, lack of published emissions
data on a relatively new, bench-scale process is
understandable and is not a cause of great con-
cern for the moment. Lack of any plans for
gathering emissions data from a process, or
lack of access to any data that may be
reported, are both causes for concern from the
standpoints of being aware of progress of
development of the conversion process and of
outlining for special attention any unusual
emissions problems. For these reasons, efforts
in monitoring literature and in maintaining con-
tacts with process developers are planned as a
continuous update of emissions information
through the project.
Gasification Process Categorization
The premise that conversion processes fed
with the same coal and operating under the
same or similar conditions will have the same or
similar emissions has been applied to the coal
gasification processes. The groupings that
result allow application of emissions informa-
tion among processes within each group in
order to close the information gaps.
Coal gasification processes were divided into
"clean" processes, in which little or no oils,
tars, and phenols are produced, and "dirty"
processes that produce oils, tars, and phenols.
The effect of the grouping on the availability of
data within the group is shown in Table 3.
Classifying gasification processes according
TABLE 3
CATEGORIZATION OF COAL
GASIFICATION PROCESSES
Clean Proc-
esses 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16
C02 Acceptor P A A A A A A
Bi-Gas P P P P P P P
Koppers-Totzek A A A
Winkler A P A
Westinghouse
Foster Wheeler
Combustion Q Q
Engineering
U-Gas Q A Q Q A
Babcock& A A A A
Wilcox
CONSENSUS APAAAP AAAPAA
Dirty Proc-
esses
AP A AA
P AA
Synthane
HyGas
(Steam/Ox.)
HyGas
(Steam/Iron)
Lurgi (Dry Ash)
Lurgi (Slag Ash)
Battelle Agglomerating P P P
Ash
COGAS
Hydrane A
Riley Morgan P P
Wellman-Galusha P
A
Q A A
AAPPA A Q A A
P P AA Q Q QA
P P P P
A
A
A
CONSENSUS AAAAAAQA PPAA
•A = Analyses, either real or conceptual; P = Partial analysis;
Q.= Quantities only.
to their production of oils, tars, and phenols is
useful because these components eventually
appear in the waste water streams. Their
presence requires the use of additional treat-
ment units (for example, biological oxidation or
phenol recovery) while their absence means
significantly less intense water treatment will
be needed. In addition, production of these
contaminants generally reflects gasifier
operating conditions, which in turn determine
the form of solid waste produced (slag or dry
ash).
428
-------
Oils, tars, and phenols may be formed during
the gasification of coal. However, by increasing
the gasifier temperature, the residence time or
the average bed temperature (by operating in
the entrained flow mode or injecting the coal
feed into the hot bottom part of the gasifier),
production of oils, tars, and phenols is reduced
or eliminated.
It is noteworthy that the "clean" processes
have either entrained-flow or fluidized-bed
gasifiers operating at temperatures of 1900° F
or higher and produce ash as a slag or as ag-
glomerates. In contrast, the "dirty" processes
have either fixed bed or fluidized-bed gasifiers
operating at temperatures below 1900° F.
There are several exceptions to the
generalization. The C02 Acceptor gasifier
operates at less than 1900° F but is "clean"
because the gasifier design provides for long
residence time. The Winkler gasifier also
operates at less than 1900° F but is "clean"
because the feed coal is injected into the bot-
tom of the gasifier to yield a higher average bed
temperature. Not much is known at this time
concerning the Battelle Agglomerating Ash
Process, however, sources indicate that no tars
or oils are produced but that some heavy in-
organics may be present.1 The Al Molten Salt
Process is a special case in that no oils, tars, or
phenols are produced, but the reaction system
may produce effluents significantly different
from the other gasification processes.
From the consensus of each of the process
groups a first approximation of the quantities
and concentrations of emission streams may be
deduced. Used with caution, the deductions
will serve as a basis for evaluation of the effi-
ciency of the application of available and
developing control technology to the pollutants
by comparison with existing and proposed en-
vironmental standards and criteria for emis-
sions from conversion plants.
The weaknesses in the categorization
method for deduction of emission stream quan-
tities and compositions are apparent.
Strengthening of the information is needed to
'it should be noted that "heavy inorganics" are present in
all processes due volatility of such components in the
coal, e.g., Cd, Zn, Cl, Hg, F, As. etc. Also nitrogen
compounds In the coal will appear as ammonia and
cyanides/cyanates in all processes.
make as firm as practicable the foundation for
the subsequent steps of the program.
Therefore, plans have been formulated for
monitoring literature and implementing per-
sonal contacts to gather and correlate data as
developed on the processes that are developing
rapidly and that offer the most promise for
generating useable effluent data:
C02 Acceptor (Clean, High-Btu)
Koppers-Totzek and/or Winkler (Clean,
Low, or Medium-Btu)
Synthane, Lurgi and HyGas (Dirty. High-
Btu)
Riley-Morgan and Wellman-Galusha (Dirty,
Low-Btu)
Liquefaction Process Categorization
Grouping of coal liquefaction processes ac-
cording to operating conditions in order to
deduce the composition and quantity of each
emission stream was not as successful as with
coal gasification processes due to lack of
meaningful data. As a first approximation, the
processes were separated into two groups:
Process Temperature Pressure
Group 1: Pyrolysis/Hydrocarbonization
COED 550-1500°F
Clean Coke 880-900
Group 2: Solvent Hydrogenation
SRC 800-900° F
H-Coal 850
Donor 700-900
Solvent
Synthoil 850
Spsig
150
1500
2000-4000
1450-2450
Phase*
S,G
S,G
L,S,G
L,S,G
US
2000-4000 L,S,G
*L= Liquid; S = Solid; G = Gas
In general, coal liquefaction processes are
more nearly alike than are coal gasification
processes. For example, since all liquefaction
processes produce hydrocarbon liquids, it is in-
evitable that there will be effluent streams con-
taining tars, phenols, and oils and that these
streams will require effluent control systems
similar to those applicable to the fixed bed
("dirty") gasification processes.
Hydrogen for coal liquefaction can be
generated either by .light hydrocarbon reform-
429
-------
ing or by gasification of residue/char. The
general statement may be made that hydrogen
production by similar methods yields similar ef-
fluents and requires similar control methods for
that process step.
In Group 1, the byproduct char from the
COED process is gasified to produce hydrogen
and fuel gas. Studies on the gasification of the
char have led to the development of the
COGAS process, and COGAS now includes
COED. The Clean Coke process produces a
coke substitute from the byproduct char. Both
processes use low-pressure staged fluid bed
reactors to pyrolyze/hydrocarbonize coal into
char and oil.
The processes in Group 2 liquefy coal by
combining it with a recycle oil stream to form a
slurry, adding hydrogen and heating the mix-
ture at high pressure to yield oil and a residue of
undissolved coal and ash. SRC does not use a
catalyst. Donor Solvent catalytically
hydrogenates the recycle solvent. H-Coal and
Synthoil use a catalyst in the liquefaction reac-
tor. The residue may be disposed of by com-
bustion, coking or gasification.
An attempt to utilize the effect of the group-
ing on the availability of data within the group
is ineffective, due to the lack of data in many
areas and the lack of definition of the means of
disposal of residue. Monitoring literature and
implementation of personal contacts in order to
gather and correlate information as it is
developed are recognized as being of para-
mount importance and are being vigorously
pursued.
Compilation of Existing and Proposed
Environmental Requirements
Environmental regulations, standards, and
related restrictions have been collected,
organized, reviewed, and synopsized. Sources
were State, regional, and Federal publications
and, wherever applicable, international
agreements. Detailed evaluation was limited to
those constituents of effluent, emission, and
waste streams which best judgment indicated
will be hazardous or environmentally
dangerous due to inherent properties or to con-
centrations. The Multimedia Environmental
Goals that are currently under development by
IERL-RTP are included in the evaluation, since
these establish a concentration for each consti-
tuent which estimates a level of concern for
assessment purposes.
The draft report of the compilation and
evaluation of the environmental requirements is
scheduled for completion by the end of
September. Monitoring of source material will
be a continuing effort through the project.
430
-------
VOLATILITY OF COAL
AND ITS BY-PRODUCTS
By
J. K. Kuhn, D. Kidd, J. Thomas, Jr.,
R. Cahill, D. Dickerson, R. Shiley,
C. Kruse, N. F. Shimp
Illinois State Geological Survey
Urbana, Illinois
Abstract
A number of projects are underway to assess
the relationship of trace and minor elements to
the volatile and residual products formed dur-
ing the pyrolysis of coal. Physical and chemical
demineralization of coals has shown that, with
the exception of organic sulfur, all or nearly all
of the trace and minor elements are associated
with the mineral matter. Since the minerals
cannot be totally removed with current com-
mercial cleaning procedures, their volatility is
as important to coal processing as that of the
organic constituents.
Internal surface area measurements of coals
and the chars produced upon pyrolysis show
that the surface area is at a minimum at 350 ° C
to 450°C. At this temperature range, most of
the volatile matter has been expelled, and the
greatest rate of sulfur loss occurs. The surface
area increases (to the original area) above this
temperature until the original structure is
destroyed at 750°C to 800°C.
Six coals were pyro/yzed at 450°C and
700°C. Significant losses of some trace
elements occurred at the lower temperature,
whereas only slightly increased loss occurred
at the higher temperature. Of the elements
determined, S, In, Cl, Sn, Sb, As, Se, and Hg
showed considerable volatization, whereas
others such as Cd and Zn exhibited a lesser
degree of loss.
INTRODUCTION
The volatility of coal and the elements con-
tained in it are of concern both environmentally
and economically. The possible release of trace
elements during power generation and conver-
sion processes such as liquefaction and
gasification may endanger the environment and
be deleterious to catalysts in coal conversion.
A large portion of the many elements con-
tained in the mineral matter of coal may be
removed by physical cleaning. The determina-
tion of the association of these elements with
the organic and inorganic portions of coal is
necessary to assess the value of pretreatment
procedures. Both the physical characteristics
of the coal and the mode of occurrence of the
elements in coal have significant effects on the
volatility of products formed during power
generation and conversion. The projects
reported here are directed toward finding infor-
mation that can be used in evaluating problems
in coal utilization.
Organically Associated Trace Elements
The type of association or combination in
which an element occurs in natural materials
can influence its reactivity or volatility.
Analyses of fractions of coals obtained by
specific gravity methods have produced data
showing whether elements are associated with
the mineral or the organic fractions of coal. A
total separation of the mineral matter from the
organic matter cannot be made by gravity
methods alone, however. Consequently, we
have combined physical and chemical methods
to achieve more complete separation. Direct
analysis of an almost entirely organic fraction
should yield definitive information on those
elements that are associated with organic mat-
ter. If the amounts of elements are sufficiently
large, the volatilities of organically combined
trace elements might be determined separately
from the volatilities of the mineral elements.
To accomplish this, mineral matter was
removed from cleaned coal by means of selec-
tive chemical dissolution, in which the coal
organic fraction was relatively unaltered. A
brief summary of the demineralization pro-
cedure follows:
1. Raw coal floated at 1.40 specific grav-
ity
2. 2-hr reflux with 10 percent HN03
3. 2-hr digestion with 48 percent HF at
70°C
4. 1-hr digestion with 25 percent HCI at
70° C
5. Vacuum-dry fractions
This procedure may oxidize some of the organic
matter; however, any major effect should be in-
dicated by a change in the organic sulfur con-
431
-------
tent. Table 1 shows the extent of elemental ex-
traction over time for major, minor, and trace
elements. The values were normalized for loss
of weight from removal of mineral matter.
The data show that acid extraction removes
most of the mineral phases from coal. Removal
of the mineral matter has little or no effect on
the organic sulfur content of the coal; thus, we
believe that for most coals the organic portion
of the coal is nearly unaltered. After extraction,
a total trace element concentration (including
Si, Al, and others, but excluding S) of only
about 250 ppm remains in most coals.
Table 2 shows the mode (the concentration
occurring most frequently) and minima and
maxima of the concentrations of some major,
minor, and trace elements in the 25 raw and
chemically cleaned coals studied in this project.
In general, results of these analyses have con-
firmed conclusions drawn from earlier
float/sink studies; e.g., Ge, Be, Sb, and Br have
high organic associations in coal; Ni, Cu, Cr,
and Hg tend to be in both organic and inorganic
combinations; and Zn, Cd, As, and Fe are
primarily associated with coal mineral matter.
Boron is absent in the chemically cleaned coal,
but float/sink data indicate that B is associated
mainly with the organic fraction of coal.
Therefore, we believe the chemical treatment
removes B from the organic matter, perhaps as
a fluoride.
Results of chemical extraction of mineral
matter from coal are in relative agreement with
tho ,j obtained by gravity separations, except
that the concentration levels of most trace
elements in the chemically extracted coals (i.e.,
organically associated trace elements) are
significantly lower than those contained in the
lighter, organic-rich float fractions from the
same coal. This raises the question of which
values more nearly represent the organic por-
tions of coal; those in chemically cleaned coals
may be low and those in light gravity fractions
may be high.
Recently we have compared some of the
data on trace elements from chemically cleaned
coals with the concentrations of organically
combined trace elements estimated from
washability and "organic affinity" curves. The
following description of the manner in which
such values are calculated was taken from
Trace Elements in Coal: Occurrence and
Distribution by Gluskoter et al. (1977). Figure
1 presents both unadjusted (standard) and ad-
justed, normalized washability curves for zinc
in a sample of the Herrin (No. 6) Coal Member.
In thestandard (unadjusted) washability curve
(Figure 1a), the extrapolated ordinate intercept
is approximately 4.5 ppm. The adjusted curve
intercepts the ordinate at zero, and the curve
reaches the zero zinc value at approximately 90
percent recovery (90 on the abscissa). A por-
tion of the mineral matter estimated to be in-
separable has been subtracted from the normal
curve to produce the adjusted curve; the ad-
justed cumulative curve (Figure 1b) was con-
structed after the value, F, was determined, as
in the following example for zinc, and sub-
tracted from each of the 5 datum points.
LTA(Light)
F = Z.7/M1.60S)
xZn(1.60S)
6.10
= 77.80
= 19.6 ppm
250 ppm
LTA(Light) is the percentage of low-
temperature ash in the lightest float frac-
tion.
LTA("\.GQ S) is the percentage of low-
temperature ash in 1 .60 sink fraction
Zn(1 .60 S) is the concentration in 1 .60
sink fraction (ppm).
If the value of a datum point was negative
after F was subtracted from the reported con-
centration, the value was taken to be zero. A
fourth-order polynomial curve was drawn to
best fit the data points. Thus, in the case of Zn,
the net effect was a general lowering of the
curve. The area beneath the curve is propor-
tional to the element's organic affinity, and the
intersection of the curve with the vertical axis
is an estimate of the Zn concentration
associated with organic material.
Tables 3, 4, and 5 are typical examples of
element concentrations in raw coals and their
respective organic-rich fractions which were
432
-------
TABLE 1
EFFECT OF PHYSICAL AND CHEMICAL TREATMENT
ON THE CONCENTRATIONS OF SOME ELEMENTS
IN AN ILLINOIS NO. 6 COAL SAMPLE
Element
Al
Si
Ca
K
Na
Cl
S
Fe
Ti
Organic S
P
As
Pb
Br
Cu
Ni
Zn
V
Rb
Cs
Ba
Sr
Sc
Cr
Co
Ga
Se
Sb
Hf
W
La
Ce
Sn
Eu
Dy
Lu
Yb
Tb
Th
U
Mo
Hg
Mn
Raw
%
1.40
3.20
.51
.13
.04
.05
6.45
2.60
.06
2.55
coal
ppm
50
3.4
<.l
3.5
13
24
43
36
23
2.0
54
28
4.1
21
5.5
2.4
4.3
.49
1.1
.59
6.1
25
.86
.26
1.2
<.02
.84
.45
3.6
1.9
18
.23
60
1.40
%
1.08
2.15
.094
.11
.027
.02
3.59
.90
.08
2.66
float
ppm
13
2.8
<.l
3.4
13
7.5
20.5
28
10.3
.66
42
10.3
2.8
16.8
3.7
2.8
1.4
.19
.46
.28
3.4
7.3
.8
.19
.56
.02
.46
.09
1.9
.46
3.5
.066
10.3
1-hr
treatment
% ppm
124
250
33
1
7
390
2.64
170
25
2.64
9.7
.088
<.l
2.4
3.4
2.5
8.8
6.1
<1
<.l
21
1.80
.88
8.8
.35
.88
.18
.088
.088
.088
.88
1.8
.44
.09
.53
.03
.22
.09
.88
.18
.53
.044
.35
2-hr
treatment
% ppm
35
41
25
1
5
390
2.52
66
11
2.52
<1.0
.062
<.l
2.9
2.1
<1
4.4
3.5
<1
<.G1
3.6
1.3
.53
6.2
.35
.62
.26
-088
.088
.052
.61
1.5
.35
.088
.44
.02
.20
.09
.88
.09
.44
.044
.26
NOTE: All values normalized to raw coal.
433
-------
TABLE 2
MODES, MAXIMA, AND MINIMA OF CONCENTRATIONS
OF ELEMENTS FOR 25 RAW AND CHEMICALLY CLEANED COALS
Element
Al
Si
Ca
K
Na
S
Organic S
Fe
Ti
P
As
Pb
Mo
Cu
Ni
Zn
V
Ba
Cr
Br
Mn
Co
Ga
Se
Sb
Hg
Sr
Mode
% ppm
1.10
2.59
.51
.14
.04
1.43
.77
1.95
.06
50
4
4
14
12
18
46
36
78
16
15
42
7
2.4
2.0
.4
-.14
32
Raw coal
Maximum
% ppm
1.60
3.47
3.30
.21
.15
6.45
2.52
2.96
.08
200
9.4
56
26
92
29
328
62
500
46
33
69
15
3.8
4.3
2.5
.23
190
Mineral-free coal
Minimum
% ppm
.36
.71
.18
.02
.01
.49
.25
.31
.02
10
1.2
<.l
.7
2.1
2.9
16
5.4
41
6
.9
12
.6
.8
1.1
.19
.06
23
Mode
% ppm
41
37
18
4
5
.79
.79
86
18
4.5
.25
.7
.44
3.4
2.1
4
3.5
10
3
7
.28
.34
.47
.26
.28
.055
4.6
Maximum
% ppm
143
62
57
200
25
2.52
2.52
110
35
19
.50
1.1
.55
8.8
4.6
4.6
6.4
20.9
7
24
.7
1.5
1.0
.7
.46
.060
15
Minimum
% ppm
22
26
7
<1
<1
.28
.28
66
2.1
<1
.046
<.l
.37
.7
<1
<1
2
2.9
.28
.1
.19
<.04
.38
<.l
.088
.044
<1.3
-------
(la)
30.4
N
O.O
20.5
16.4-
~ 12.3 H
E
Q.
Q.
O
C
N
8.2i
4.1-
0.0
20
40 60
Percent recovery
Herrin (No.6) Coal
80
100
1
I
-1 - [-— I
20 4O 60 80
Percent recovery -adjusted
Herrin (No.6) Coal
100
Figure 1
435
-------
TABLE 3
ELEMENTAL CONCENTRATIONS
IN AN EASTERN COAL (C-18820)
Element
Al
Ca
Fe
K
Si
Ti
Mg
Na
Organic S
Br
P
V
Mn
Sn
B
Cu
Co
Ni
Be
Cr
Mo
Sr
Pb
Zn
Cd
As
Ga
Se
U
Ba
Ce
Hf
La
Lu
Rb
Cs
Sc
Sm
Tb
Dy
I
Ta
Yb
Te
Th
W
Eu
Sb
ISA
Raw Coal
% ppm
1.41
.56
.56
.23
2.51
.12
.06
.07
.50
24
26
22
14
.3
12
20
7.5
12
.88
20
4.6
96
1.6
12
<.l
15
4.2
5.8
1.0
180
31
1.5
19
.12
<.l
2.0
3.3
1.5
.4
2
2.6
.12
.6
.3
6.2
.5
.47
4.6
F/S EXT
% ppm
0.0
.11
.34
.0
.0
.01
.00
.00
.60
27
13.7
.00
1.6
1.0
2.0
6.7
7.9
12
.94
3.5
1.7
82
.6
1.1
.09
.29-
1.1
1.1
.15
118
7.5
.19
5.8
.04
0.0
.0
.9
.76
.13
.86
.05
.24
.53
.43
.19
.36
129 m2/g
MMF
% ppm
69
34
72
<10
56
19
18
.5
.47
16
.1
1.5
.5
<.l
9.7
6.5
6.5
5
.11
6.3
<1.0
50
LD
.3
<.l
<.5
.7
1.0
.2
33
.1
.2
5
.05
<.l
.2
2.0
.9
.27
.9
1.4
.09
.06
<.l
1.1
.12
.2
<.4
436
-------
TABLE 4
ELEMENTAL CONCENTRATIONS IN
AN ILLINOIS NO. 6 COAL (C-18560)
Element
Al
Ca
Fe
K
Si
Ti
Mg
Na
Organic S
Br
P
V
Mn
Sn
B
Cu
Co
Ni
Be
Cr
Mo
Sr
Pb
Zn
Cd
As
Ga
Se
U
Ba
Ce
Hf
La
Lu
Rb
Cs
Sc
Sm
Tb
Dy
I
Ta
Yb
Te
Th
W
Eu
Sb
ISA
Raw Coal
% ppm
1.40
.51
2.60
.13
3.20
.06
.06
.04
1.87
13.4
50
36
62
.4
200
13
7.2
24
1.4
20
11
33
<1
57
<.l
3.4
2.4
4.3
1.9
54
25
1.1
6.1
.1
23
2.0
4.1
.86
.1
1.2
1.2
.12
.84
1.
3.6
.6
.26
.5
P/S EXT
% ppm
0.0
0.0
0.0
.02
0.0
.01
0.0
.01
2.36
24
0.0
34.5
0.0
0.0
38
2.3
1.42
5.5
.68
21
1.7
.03
.0
0.0
0.0
0.0
0.0
5.3
0.0
0.0
.05
0.0
.02
0.0
.01
.57
.11
.61
.03
.05
.33
.05
.47
173 m2/g
MMF
% ppm
41
25
66
<1.0
41
20
21
6
1.81
3.3
<1.
3.5
.3
<.l
6.6
2.1
.36
<1.0
.03
6.8
.52
1.5
<1
1
<.l
<.07
.73
.26
.09
.2
.1
.11
.72
.03
<1.0
.1
.65
.41
.1
.5
<.8
.09
.23
<.l
1.0
.06
.1
.09
437
-------
TABLE 5
ELEMENTAL CONCENTRATIONS
IN A WESTERN COAL (C-19000)
Element
Al
Ca
Fe
K
Si
Ti
Mg
Na
Organic S
Br
P
V
Mn
Sn
B
Cu
Co
Ni
Be
Cr
Mo
Sr
Pb
Zn
Cd
As
Ga
Se
U
Ba
Ce
Hf
La
Lu
Rb
Cs
Sc
Sm
Tb
Dy
I
Ta
Yb
Te
Th
W
Eu
Sb
ISA
Raw Coal
% ppm
1.40
.46
.40
.02
1.40
.06
.07
.17
.38
.9
120
7.1
8.3
<.2
37
4.7
.9
2.6
.39
3.4
—
204
LD
3
<.l
1.1
2.3
1.6
.7
265
5.9
.64
6.0
.08
1.20
.11
1.3
.80
.10
.65
.61
.10
.84
.6
1.4
1.2
.15
.35
F/S EXT
% ppm
0.0
.64
.27
.00
0.0
0.0
.06
.15
.38
1.2
91
8.1
.68
0.0
37
2.0
.5
1.14
.33
.98
__
111
0.0
4.7
.09
0.0
0.0
.43
.13
218
3.6
.11
1.36
.03
.34
.0
.50
.06
.03
.39
.01
.05
.00
.03
.03
.09
240 m2/g
MMF
% ppm
87
20
65
<10
87
54
<20
1.4
.32
1.0
<4
<5
.4
<.2
5.3
<3
.5
<1.5
.03
1.4
__
LD
<.5
<.l
.2
.15
.6
.05
15
1.2
.20
1.3
.03
<1.0
<.05
.42
.03
.07
LD
.3
.LD
.23
.2
0.6
.LD
.05
.18
438
-------
estimated from adjusted washability curves
(F/S EXT) and from analysis of the acid-washed
mineral-matter-free (MMF) residues. Data are
given for an eastern U.S. coal, the Illinois Herrin
(No. 6) Coal and a western U.S. coal. Com-
parison of concentrations for F/S EXT and MMF
shows that the majority are in close agreement.
Exceptions include Ca, Fe, Be, and B in the
eastern coal; Br, V, Be, U, and Sb in the No. 6
Coal; and Ca, Fe, Mg, Na, P, B, Be, Zn, and Ba
in the western coal. It is likely that minor
elements, i.e., major ash-forming elements
such as Ca, Fe, Mg, and perhaps P, are for the
most part inorganic but are incompletely
removed during float/sink gravity separations.
It is also likely that Na and Ba in the western
coal; Br in the No. 6 Coal; B and Be in all three
coals; and, perhaps, Se in somelllinois coals
(not shown) are actually organic, as indicated
by float/sink tests, but appear to be inorganic
from the acid extraction evidence. That is,
these elements may be loosely combined with
the organic coal material and easily displaced
from it by the acid treatment.
Although these data are still being combined
with results from on-going pyrolysis and
volatility studies, some preliminary conclusions
can be drawn. Table 6 summarizes the means
and correlations of the sulfur values determined
for the mineral-free material and the values for
organic sulfur obtained using the standard
ASTM method (D2492) for analysis of raw
coal. The means are in close agreement, which
indicates that for the 25 coals analyzed in this
study, the pyritic sulfur is quantitatively re-
moved by the ASTM procedure.
The correlations between organic sulfur and
the other elements determined in the coal
samples are listed in Table 7. It is apparent that
correlation with organic sulfur is not an in-
dicator of the organic association of other
elements. The data show that a significant cor-
relation exists only if those elements were in-
troduced into the coal-forming swamp at or
near the same time as the organic sulfur or if
the geochemical properties were sufficiently
similar to cause deposition under similar condi-
tions.
Table 8 shows the mean and standard devia-
tion of the concentrations of 11 mineral-
matter-free Illinois No. 6 Coal samples. Since
some of the deviations equal or exceed the
mean concentration, each coal must be
evaluated separately in order to make predic-
tions about organic associations and their ef-
fect on reactions during processing.
Finally, the data imply that most of the
organically associated elements are rather
weakly bound, having been deposited after the
formation of the coal. Moreover, for the
elements studied, no more than a very few
parts per million can be considered an inherent
part of the organic molecules. Therefore, it can
be presumed that pollution or problems in coal
combustion, liquefaction, or other processes
will for the most part be associated with the in-
organic matter in the coal. It is still possible,
however, that enhanced volatility of an
organically associated trace element could lead
to its concentration in a process steam (gas or
liquid effluent).
VOLATILE PRODUCTS
FROM PYROLYSIS OF COAL
Volatilized constituents—organic and in-
organic—from coal can be obtained by means
of devolatilization of coal at low (<250° C)
and medium (250° C to 650° C) temper-
atures. Determination of these constituents
and their relation to variations in the physical
and chemical characteristics of different coals
should yield information concerning the struc-
ture of coal as related to carbonization,
gasification, and liquefaction. For this purpose,
we have used several pyrolysis systems; Figure
2 shows the system as recently modified.
Chars were prepared from 1 2 different coals by
heating at temperatures ranging between
200° C and 900° C in 50° C-to-1000 C
steps. Analyses of the char and comparison
with analysis of the whole coal yielded the
following results:
1. Most coals exhibited similar behavior.
For example, the Herrin (No. 6) Coal
from Illinois, heated in steps to 700°C,
showed a reduction of sulfur from 4.5
percent in the raw coal to 1.5 percent
in the char, a 66 percent loss of sulfur
on a whole-coal basis. Most of the
sulfur was lost while the coal was
heated between 300°C and 400°C.
439
-------
TABLE 6
CONCENTRATIONS OF SULFUR IN 25 COAL SAMPLES
Mean percentage Mean percentage
Number of organic sulfur of sulfur
Type of coal
Eastern
Western
Illinois
Illinois
No. 6
No. 5 to No. 2
NOTE: Values have been
of samples in whole coal in MMF coal
5
5
11
4
.99
.43
1.70
1.26
.95
.42
1.71
1.26
Correlation
coefficient
1.00
.96
.98
.99
normalized to the same weight basis.
TABLE
7
CORRELATION BETWEEN ORGANIC SULFUR AND OTHER
Element
Al
Br
Ca
Fe
P
K
Si
Ti
V
Mg
Mn
Na
Sn
Correlation
coefficient
-.16
-.22
.26
-.14
-.12
.03
-.21
-.21
-.16
.14
.08
.01
.06
Element
B
Cu
Co
Ni
Be
Cr
Mo
Sr
Zn
As
Ga
U
Ba
TABLE
CONCENTRATIONS OF ELEMENTS IN
Element
Al
Br
Ca
Fe
P
K
Si
Ti
V
Mg
Mn
Na
S
Sn
B
Mean
(ppm)
60
3.9
42
63
4.3
8.4
56
30
7.1
28
.4
6.4
1.70
.9
7.6
Standard
Deviation
14
2.4
28
3.5
15
20
15
4.4
9.8
.2
3.8
.48%
1.0
1.4
Correlation
coefficient
.33
.24
-.35
-.28
-.18
-.04
.07
.12
.12
-.13
.44
.00
.04
8
ELEMENTS
Element
Ce
Hf
Te
La
Lu
Eu
Cs
Sc
Sm
Dy
I
Th
Sb
Correlation
coefficient
.10
-.14
-.06
-.14
-.35
-.10
-.50
-.27
-.01
-.45
-.21
.12
.07
1 1 MMF ILLINOIS NO. 6 COALS
Element
Cu
Co
Ni
Be
Cr
Mo
Sr
Pb
Zn
Cd
As
Ga
Se
U
Mean
(ppm)
3.5
.4
5.7
.04
6.4
.8
4.2
1.8
1.7
.5
.15
.6
.4
.2
Standard
Deviation
1.6
.2
5.4
.03
2.2
.5
3.3
3.2
1.3
.5
.07
.1
.2
.1
440
-------
Revised Pyrolysis Unit
Retort modification June 24, 767-48
Furnace modification June 28, 767-58
Collection modification July I, 767-71
Asbestos
tape packing
Chrome I Alumel
Couple
6 8 Inches
Figure 2
-------
2. Only a small amount of sulfur was lost
while the char was heated to 700°C.
The greatest rate of sulfur loss oc-
curred over the same temperature
range (300° C to 400° C) at which
the coal char exhibited maximum
Gieseler fluidity and minimum internal
surface area (ISA).
3. The internal surface area of pyrolysis
residues increased slightly when a coal
was heated to about 300 °C; ISA then
exhibited a rapid decrease, reaching a
minimum at 350° C to 400° C. As
the coal was further heated to about
700° Cto 750° C, the ISA increased
to approximately its original level.
Heating above 750°C completely
destroyed the original coal structure,
and the ISA decreased. Thus, we may
conclude that a coal changes continual-
ly as it is heated to higher temperatures
in an inert atmosphere (nitrogen); the
greatest change occurs as the coal
passes through the 350°C-to-450°C
range, at which it reaches maximum
Gieseler fluidity, minimum surface
area, greatest rate of sulfur loss, and
release of the majority of volatile
organics.
Because of the typical pyrolysis pattern
observed, it has been concluded that for our
studies the two most important temperatures
for which volatility data need to be obtained are
450°C and 700°C. At 450°C reactivity is
highest and most volatile products are re-
leased; at 700°C all volatile products are
released but the coal structure (ISA) is still in-
tact.
From iron-sulfide-phase equilibria studies, it
is known that pyrite breaks down to pyrrhotite
and sulfur at 743°C; however it appears that
the pyrite contained in coal is converted to
pyrrhotite at 450°C or lower in a nitrogen at-
mosphere. This is shown by X-ray diffraction
analysis and scanning electron microscopy
with energy-dispersive X-ray analysis of the
mineral matter from the raw coals and of the
chars produced by pyrolysis. Chemical
analyses also indicate a greater loss of sulfur
from the pyrite than organic sulfur at low
temperatures, whereas the reverse is true at
high temperatures (>450°C).
Determinations of trace elements for the
whole coals and the resulting chars indicate
that certain trace elements are lost through
heating. The importance of assessing the levels
and fate of trace elements volatilized during
coal utilization is of concern from both
economic and environmental standpoints.
Highly volatile species may be lost from some
conventional power plant emission control
devices. The extent to which volatile species
will create new hazards in coal conversion is
unknown, and the effect of trace elements on
conversion catalysts is still uncertain.
Six coals (Table 9) are currently being
studied for trace-element volatility during
pyrolysis under an inert gas (N2) flow at 450°C
(and later at 700°C) in order to simulate condi-
tions in gasification and liquefaction. The
percentage weight loss during pyrolysis is
given in Table 10. Table 9 lists preliminary
results of energy-dispersive X-ray fluorescence
(XES) analyses of both the raw coals and the
char residues. (Char values have been cor-
rected for apparent concentrating effects from
losses of volatile matter.) Indium, Sn, and Sb
are volatilized and lost during pyrolysis, and Cd
and Zn appear to be volatilized to a lesser
degree. Support for this comes from atomic ab-
sorption analyses that indicate very small
amounts of Cd are present in the trapped
volatile fraction. Results based on instrumental
neutron activation analysis (INAA) and
wavelength-dispersive X-ray fluorescence
(XRF) analysis indicate that As, Cl, Br, S, and
Se are also lost in varying degrees while most
other elements remain in the residue or are lost
in amounts too small to be detected.
Direct analysis of the condensed volatiles
from the pyrolysis system has proved to be dif-
ficult. The condensate is a tarlike material that
is difficult to process without risk of con-
tamination or loss. The quantities of trace
elements are so low that lack of sensitivity is a
problem in the determination of some elements
by XRF methods. Such a material can also pre-
sent a problem for INAA during irradiation in a
nuclear reactor. Charcoal traps have been used
to collect volatile species; however, with this
442
-------
TABLE 9
PRELIMINARY XES DATA FOR PYROLYSIS OF SIX COALS
C-18440 C-18571 C-18571-F C-18847 C-18857 C-18185
Raw Raw Raw Raw Raw Raw
Element Coal 450°C Coal 450°Ca Coal 450°C Coal 450°C Coal 450°C Coal 450°C
Cd
In
Sn
Sb
Te
I
Cs
Ba
La
Ce
Zn
Br
Rb
Sr
2.3
2.6
5.0
5.6
1.3
3.9
9.2
337
8.1
8.7
3.7
2.3
4.9
241.
2.3
0.72
1.0
2.0
4.4
8.5
26. 9b
1205
10.7
13.6
14.3
2.8
6.4
245.1
3.3
1.7
6.9
5.2
0.7
2.7
2.7
44
8.8
9.2
84.5
7.2
12.1
27.5
1.6
0.10
0.18
0.07
0.56
1.4
3.8
48.5
48.3
10.0
11.1
30.4
1.8
1.9
5.1
5.8
0.9
1/4
2.9
34.3
6.3
9.7
21.8
10.1
10.3
21.7
0.8
<0.1
0.8
1.0
0.3
0.8
2.0
35.1
4.9
7.0
18.3
7.1
8.6
19.6
1.4
2.0
3.9
5.0
1.5
3.2
8.6
202
13.5
20.4
13.7
2.7
14.0
68.2
0.9
<0.1
<0.1
<0.1
1.4
3.0
8.4
241
13.9
24.7
12.1
1.9
10.9
59.3
1.9
0.9
2.2
1.9
0.8
1.8
3.3
51
10.8
10.0
35.3
9.1
12.3
29.8
0.75
<0.1
.68
<0.1
1.1
1.4
3.3
53.8
8.9
11.5
45.7
5.7
10.0
26.4
7.0
0.8
1.4
3.3
0.5
2.5
2.4
40
4.9
8.9
323
4.4
9.2
22.0
7.0
<0.1
<0.1
<0.1
1.8
2.8
8.9b
302
8.1
12.3
246
5.0
9.4
27.5
NOTE: All values expressed as ugr/gr.
aAverage of two determinations
Interference from Ba
TABLE 10
PERCENTAGE VOLATILE MATTER LOST DURING PYROLYSIS
Sample number
C-18857
C-18571
C-18571F
C-18440
C-18185
C-18847
Seam and state
No. 6 Illinois
No. 6 Illinois
No. 6 Illinois
Lignite North Dakota
No. 5 Illinois
Blue Creek Alaska
Percentage weight
32.2
27.5
30.3
33.9
27.0
8.4
loss at 450°C
443
-------
approach total entrapment is never certain, and
the blank levels in the charcoal itself are often
high and variable.
Consequently, work is progressing on a new
laboratory trapping system of greater capacity.
The system consists chiefly of a Parr reactor
vessel; a water-jacketed, large-bore glass col-
umn packed with small pieces of plastic tubing
to slow the gas stream and decrease the size of
the bubbles; and the associated cold traps
<-30°C and -80°C). The column through
which the volatile gases are bubbled contains
acetone and methanol to dissolve organics and
dimethoxypropane to react with any water in
the system to form acetone and methanol,. A
resin for adsorbing organics has been used, but
no trace elements were detected in it. With this
system, when high volatile "A" coals were
pryolyzed, thick condensed tars have tended to
collect and plug the gas inlet from the Parr reac-
tor. In addition, some gas is still lost from the
final cold trap when it is warmed to room
temperature.
Attempts are being made to concentrate the
volatile trace elements, if any, by burning the
trapped organic material and then retrapping
the released trace elements in a scrubber from
which they can be precipitated. For some very
volatile gases, it may be possible or even
necessary to pass them directly from the
pyrolysis unit to a combustion unit for trapping
the trace elements. The volatile organic
material given off contains innumerable com-
pounds. Efforts are being made to identify
those that contain sulfur by subjecting the sam-
ple of volatile organics to an acid-base-neutral
compound separation. The three fractions thus
obtained are then analyzed for the relative
distribution of sulfur compounds by means of a
gas liquid chromatograph equipped with a
sulfur-specific flame-photometric detector. As
expected, the major portion of the sulfur-
containing compounds are in the neutral frac-
tion. A few are in the basic fraction and fewer
still in the acid fraction. An attempt is being
made to identify the more clearly separated
compounds by gas chromatography-mass
spectroscopy.
Because the concentrations of some volatile
trace elements are very low, a continuous-feed
pyrolysis furnace is under construction. This
unit will allow the pyrolysis of coal in sufficient
amounts that concentrations of traces of addi-
tional volatile components can be detected and
quantified.
BENEFICIATION OF CHAR
Three coal samples have undergone various
pyrolytic treatments in a preliminary study to
determine the effect of heat on the composition
of the char produced and on subsequent
beneficiation of the charred residues. The first
of these, a Herrin (No. 6) Coal sample from
Illinois, was heated under nitrogen in a Parr
pressure reactor at 600 °C for 48 hours, and
the residue was separated into magnetic and
nonmagnetic fractions (coal A, Table 11). The
second sample, also from the Herrin (No. 6)
Coal Member, was heated in the Parr pressure
reactor at 650°C for 20 hours and again
separated into magnetic and nonmagnetic frac-
tions. (In addition, samples of this char are cur-
rently being subjected to Mossbauer, electron
probe, and scanning electron microscope
analyses to determine various mineral phases.)
Differences in the composition of the
magnetic and nonmagnetic fractions of these
two coals, as determined by X-ray
fluorescence, are shown in Table 11. Percen-
TABLE 11
PERCENTAGE IRON CONCENTRATION IN MAGNETICALLY
SEPARATED, HEATED COALS
Coal A
Coal B
Coal C
Original char
Nonmagnetic fraction
Magnetic fraction
1.19
.61
1.28
1.05
.63
1.50
2.07
1.28
3.06
444
-------
TABLE 12
PYROLYTIC CONVERSION OF PYRITE TO PYRRHOTITE
Treatment
(°C/hr)
175/6
(Whole Coal)
650/48
(Char)
650/48
(HC1-
extracted
Char)
Wt. Loss
0.5
—
33.0
—
33.0
Total S
4.27
4.37
2.39
3.04
1.03
1.21
Pyritic S
1.82
1.86
0.08
0.10
0.04
0.05
SOn Sulfur N
.36
.37
0.94
1.19
0.01 1.00
0.01 1.18
Ash
15.0
15.3
20.6
—
12.6
NOTE: Upper values determined on analyzed basis; lower values on moisture-free
and ash-free basis.
tage recoveries are not given and differences in
elemental concentrations cannot be directly
compared. Nevertheless, the results show a
significant quantity of magnetic iron resulting
from conversion of pyrite (nonmagnetic) topyr-
rhotite (magnetic) during heat treatment.
Table 12 shows the nearly total disap-
pearance of pyritic sulfur in the two partially
pyrolyzed coals (chars) and the reduction of
total sulfur (from 3.04 to 1.21 percent) in the
HCI-extracted char. Hydrochloric acid usually
removes little sulfur from coal (only the sulfate
sulfur and low concentrations of sulfides other
than pyrite are soluble in HCI). In this case,
however, pyritic sulfur has been extracted from
the char by means of conversion to pyrrhotite,
which is soluble in HCI. Future tests with the
continuous-feed pyrolysis furnace should in-
dicate the potential for producing cleaner chars
by controlling parameters that will allow more
efficient beneficiation of the products of
pyrolysis systems.
MOSSBAUER SPECTROSCOPY STUDIES
Through a cooperative effort of Southern
Illinois University with the Illinois State
Geological Survey, a study of the kinds of iron
in pyrolyzed coal residues has been made using
Mossbauer spectroscopy. Samples of whole
coal, coal pyrolyzed at 175°C for 6 hours, at
405°C for 48 hours, and at 550°C for 48
hours were supplied by the Survey to G. V.
Smith, Professor of Chemistry at Southern
Illinois University, for the Mossbauer study. In
addition, a sample of unpyrolyzed vitrain and
fusain were supplied. All samples were from
the Herrin (No. 6) Coal Member.
Because of the high sensitivity and
noninterference of Mossbauer effects, the
presence of several iron species were
demonstrated in whole coal and in its pyrolyzed
residues. Differences in isomer shifts and
quadrapole splitting between pure pyrite and
pyrite in coal indicate that there may be an in-
teraction between the pyrite and the organic
coal matrix (Smith, 1977). Recent investiga-
tions by A. Volborth (1977) support this con-
clusion, which may well have been first
postulated by G. Cady (1935). The association
appears to break down when the coal is heated
to temperatures even as low as 175°C. Any
amorphous iron sulfide present (isomer shifts
indicate this possibility) in the whole coal is
converted to pyrite at low temperatures. Fur-
ther, advances in instrumentation and data
reduction techniques have made it possible to
identify four Fe + 2 species in heat-treated coal
samples. Previously, two types of iron were
recognized in whole coal samples.
For our samples, the total quantity of iron
species in different coal lithotypes are about
the same, but have different distributions. The
single fusain sample had the least amount of
Fe + 2 when compared to the vitrain or whole
coal sample used. Two types of pyrrhotite have
445
-------
been identified in the heat-treated samples.
One is unstable and contains dissolved sulfur,
which is apparently liberated as the tem-
perature is increased. The heat treatment in an
inert, atmosphere tends to produce little
change in Fe + 2 species. It has been observed,
however, that when a coal has been evacuated
for the determination of these Fe species, then
subsequently reexposed to air, and finally
reevacuated, the types of iron change
dramatically. This phenomenon may result
from the removal of protective gases from the
pores in the coal; the significance of this event
in relation to spontaneous combustion is being
investigated further.
REFERENCES
1. G. H. Cady, 1935, Distribution of Sulfur
in Illinois Coals and its Geological Implica-
tions: Illinois Geological Survey Report of
Investigation 35, p. 25-39.
H. J. Gluskoter, R. R. Ruch, W. G. Miller,
R. A. Cahill, G. B. Dreher, and J. K. Kuhn,
1977, Trace Elements in Coal: Occur-
rence and Distribution: Illinois State
Geological Survey Circular 499, 1 54 p.
G. V. Smith, J. Liu, M. Saporoschenko,
and R. H. Shiley, 1 977, Mossbauer Spec-
tropic Investigation of Iron Species in
Coal: Fuel, v. 56.
A. Volborth, G. E. Miller, C. K. Gardner, P.
A. Jerabek, 1977, Oxygen Determination
and Stoichiometry of Some Coals:
Preprint, Division of Fuel Chemistry, ACS
Annual Meeting, August 29, 1977.
446
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TREATMENT OF PHENOLIC
WASTES
Stanley L. Klemetson, Ph.D., P.E.
Associate Professor
Environmental Engineering Program
Engineering Research Center
Foothills Campus
Colorado State University
Fort Collins, Colorado 80523
Abstract
The treatment of phenolic compounds from
coal gasification plants using ultrafiltration and
hyperfiltration is presented. Dynamically form-
ed hydrous zirconium (IV) oxide membranes on
several types of supports were the focus of the
investigation. The pH variations of 6.5 to 11,
pressure variations of 250 to WOOpsig (1 724
to 6895 kPa) and concentration variations of 1
to 400 mg/l were examined. Phenol reductions
greater than 95 percent were obtained with
several membranes, and flux rates were greater
than 100 gpd/sq ft (4.08 cu m/day/sq mi.
INTRODUCTION
The energy problems which have developed
recently in the United States have made it
desirable to examine new methods of utilizing
the lignite coal that is present in abundant
quantities in western North and South Dakota,
Montana and Wyoming. One of the solutions to
this problem is seen in the conversion of coal to
a clean fuel by the use of a coal gasification
process. By gasifying the coal, a synthetic
natural gas can be produced which is basically
free of the sulfur present in the coal and is
cleaner to use. A primary concern is that the
treatment and/or conversion process that
generates the clean fuel does not itself become
a major pollution source. While the potential
pollutants can be expressed in any or all of the
three possible states of air emissions, solid
wastes, and liquid effluents, all of them
ultimately contribute to the wastewater ef-
fluents of the plant and its site. If coal gasifica-
tion plants are to be constructed, the pollutants
which are generated during their operation
must be dealt with if their environmental ef-
fects are to be minimized.
Various types of processes have been
developed to produce synthetic natural gas.
Since the Lurgi gasification process is currently
being planned for several sites in western North
Dakota, the wastewater effluent concentra-
tions produced by the Lurgi process was used
as a basis of this study. However, the results
should be applicable to many of the other
processes also.
The purpose of this study was to determine
the feasibility of utilizing hyperfiltration
(reverse osmosis) or ultrafiltration to reduce the
phenolic concentrations in the wastewater ef-
fluents for a coal gasification plant. Dynamical-
ly formed hydrous zirconium (IV) oxide mem-
branes were the focus of the investigation. The
applicability of Selas ceramic, Millipore and
Acropor wrapped stainless steel, and carbon
membrane supports were studied in relation-
ship to the effects of pH variation, pressure
variation, and phenolic compound concentra-
tions.
COAL GASIFICATION PROCESS
The Lurgi coal gasification plants planned for
construction in the United States are being
designed to produce 250 million standard
cubic feet (7.0 M cu m/day) of medium to high
Btu synthetic natural gas that will yield about
970 Btu/std cu ft (36.14 MJ/cu m). The
average consumption of coal in these plants is
about 1000 to 1500 tons per hour (252 to
378 kg/s), and the annual water usage is about
1 7,500 acre-ft (21.58 M cu m).1
The coal is gasified with oxygen and
superheated steam in the Lurgi pressure
gasification process. The gasifier vessel con-
sists of zones in which various gasification
reactions take place. The combustion of the
coal produces methane in a three-stage reac-
tion: preheating and carbonization, gasification
or devolitilization, and partial combustion. The
temperature ranges from about 1 150 to
1400° F (621 to 760° C) and the pressure
ranges from about 350 to 400 psig (2413 to
2758 kPa).2
Most of the potentially hazardous materials
are produced in the gasifiers, but there are no
direct liquid or gaseous emissions of these
materials from the units. Coal ash is the only
direct waste discharge from the gasifiers. The
447
-------
ash is generally water quenched to cool and to
prevent the production of airborne dust. The
quenching water is considered a minor
wastewater stream. A simplified flow diagram
for wastewater treatment in the coal gasifica-
tion process is shown in Figure 1.
The crude gas leaving the gasifier has a
temperature of 700° to 1100° F (371° to
593° C), depending upon the type of coal us-
ed, and is under a pressure of about 400 psig
(2758 kPa). It contains the carbonization pro-
ducts such as tar, oil, naphtha, phenols, am-
monia, and traces of coal ash and dust. The
crude gas is quenched by direct contact with a
circulating gas liquor in a scrubber-decanter
tower. The gas liquor effluent is sent to the*gas
liquor separator for the removal of tars and oils.
Following the removal of some of the tars
and oils from the gas liquor in the Tar-Gas Li-
quor Separation unit, the water effluents are
further treated in the Phenosolvan unit for the
removal of phenolic compounds by passing
through a multistage countercurrent extractor
using isopropyl ether as the organic solvent.
The waste effluent of the phenol recovery unit
is subjected to ammonia recovery by fractiona-
tion and condensation to produce anhydrous
ammonia.
Following this initial processing, the
wastewater is to be subjected to further
purification systems, such as ultrafiltration and
hyperfiltration. Ideally, a wastewater cleaning
system should be designed so that the water
can be reclaimed for use as either boiler feed
water or cooling tower makeup water. The
removed and concentrated contaminants
would also require a final safe disposal.
In the coal gasification operation the major
sources of wastewater are the scrubber-
decanter which follows immediately after the
gasifier, and the condenser following the shift
converter. The quantity of wastewater which
will be produced is approximately as follows:
3.3 mgd (1 2.49 k cu m/day) will be generated
in the scrubber-decanter, 1.1 mgd (4.16 k cu
m/day) by the condenser following the shift
converter, and 0.8 mgd (3.08 k cu m/day) by
the steam stripping of the scrubber-decanter
water to remove ammonia. Thus, approximate-
ly 5.3 mgd (19.68 k cu m/day) is produced
which will require treatment. There are also
some other relatively minor sources.3
WASTEWATER CHARACTERISTICS
During the gasification process, the by-
products from the gasifiers are condensed
along with the water. Oil and tar are separated
from the aqueous phase of the gas liquor, and
the latter eventually mixes with the phenol con-
taining wastewaters from other parts of the
plant. This effluent was considered "raw
wastewater." Usually the raw wastewater
goes through a filtration process, extraction of
phenols, and the removal of ammonia. After
this initial amount of treatment the effluent
Crude gas
Gas
Add
condenser
water
Raw
Coal
Gasifier
t
h
Scrubber
Decanter
(
i
Tar/gas
liquor
separator
i
t
Filtration,
phenol
extraction,
& anrnonia
scrubber
Wastewater
treatment
Treated
Water
I
I
I
J
Goal ash Sludge Residuals Residuals
Figure 1. Flow diagram for wastewater treatment system.
448
-------
"processed wastewater." When the processed
wastewater had been subjected to biological
treatment, it was designated as "bio-treated
wastewater."
The concentration of phenolic compounds in
the wastewater effluents of the Lurgi process
plant of the South African Coal, Oil, and Gas
Corp. Ltd., Sasolburg, South Africa (Sasol) has
been reported by De W. Erasmus.4 A typical
analysis for their processed wastewater is
1-10 mg/l for monohydric phenols (Kop-
peschaar method), and 1 70 to 240 mg/l for the
total phenols. Experience at Sasol has shown
that the ratio of multihydric to monohydric
phenols is reasonably constant and on the
order of 20 to 40:1.
Sources from the Lurgi gasification plant of
Stein Kollingas A. C. at Dorsten, German
Federal Republic, reported 12-56 mg/l of
monohydric phenols and 228-390 mg/l of total
phenols. Cooke and Graham5 also reported that
in the processed wastewater from a Lurgi
plant, the monohydric phenols (mostly phenol)
comprise a minor part of the total phenols,
while catechol and resorcinol (dihydric) ac-
count for the most of the fraction.
Barker and Hollingsworth6 reported that
catechol, resorcinol, hydroquinone, and their
methylated derivatives in ammonical liquor are
quite similar in composition to Lurgi processed
effluent. They also indicated that trihydric
species of phenol were also present in the same
effluent.
Chambers et al.7 made a study of the
biochemical degradation of various phenol
derivatives by bacteria adapted for the decom-
position of phenol. They found that dihydric
phenols may be oxidized quite easily along with
monohydric phenols, while trihydric phenols
were plainly resistant to decomposition by
these bacteria.
Samples of the raw and processed
wastewaters for the gasification of North
Dakota lignite coal were obtained from Sasol by
North Dakota State University. The analysis of
the samples were conducted by Fleeker8 and
the biological oxidation of the processed water
was performed by Bromel.9 The rate of
degradation of phenols was determined for a
mixture of four Arthrobacter species and one
Pseudomonas specie. From an initial total
phenol concentration of 322 mg/l the bacteria
reduced the concentration to 69 mg/l in a
twenty-four hour period, and to 50 mg/l in five
days; approximately 80 percent reduction. The
monohydric phenols were reduced an
equivalent amount from 69 mg/l to 8.3 mg/l.
Bromel also reported that the residual
recalcitrant compounds, possibly the
multihydric phenols, may represent a potential
problem in the effluents that will require
chemical or physical treatment beyond
biological treatment.
Although most of the phenols will be reduced
in concentration to relatively low levels by the
biological treatment methods, there will still be
a large enough concentration remaining in the
processed wastewater to potentially cause ex-
tensive contamination of the groundwater
system. The standard recommended for phenol
concentrations in potable water is 0.001
mg/l.10 Phenols are highly toxic and increasing-
ly so when chlorine is added to the water as
most water treatment facilities do.11 Concen-
trations of phenol on the order of 10 to 100
/tg/l can cause undesirable tastes and odors.
Trace amounts approaching 1 /tg/l can impart
an objectionable taste to a water following
marginal chlorination.12
HYPERFILTRATION AND ULTRAFILTRATION
Osmosis and Reverse Osmosis
Osmosis is defined as the spontaneous
transport of a solvent from a dilute solution to a
concentrated solution across an ideal
semipermeable membrane. The membrane acts
as a barrier to the flow of molecular or ionic
species and permits a high permeability for the
solvent, water, and a low permeability for the
other species. If the pressure is increased
above the osmotic pressure on the concen-
trated solution side, the solvent flow is revers-
ed. Pure solvent will then pass from the solu-
tion into the solvent. This phenomenon is refer-
red to as reverse osmosis.
Hyperfiltration and Ultrafiltration
Filtration separation can be classified into
four families: (1) screening - removal of large
particles; (2) filtration - removal of smaller par-
ticles; (3) ultrafiltration - removal of colloidal
449
-------
particles; and (4) hyperfiltration - removal of
low-molecular-weight dissolved materials. The
boundaries between the various classes are not
precisely defined.
Much of the ultrafiltration mechanism can be
interpreted in terms of selective sieving of par-
ticles through a matrix of pores of suitable
dimensions. The removal of low molecular
weight molecules cannot be reduced to
geometric terms because there is no significant
difference in the size of water molecules and
the size of many inorganic ions. Therefore,
ultrafiltration is unsuitable in this size range.
The hyperfiltration membrane thus affects the
thermodynamic and transport properties of
solutes and solvents by forces, i.e., Van der
Waals or Coulombic. These do not depend
primarily on the difference in size of the ions
and molecules to be separated. Hyperfiltration
is commonly referred to as reverse osmosis,
since there are substantial differences in
osmotic pressure between feeds and filtrates
which must be exceeded when appreciable dif-
ferences of weight concentration of low-
molecular-weight solutes exists.
Ultrafiltration and hyperfiltration differ
primarily because ultrafiltration is not impeded
by osmotic pressure and is effective at low
pressure differentials of 5 to 100 psig (34.5 to
689 kPa). The osmotic pressure plays a larger
role as the molecular size decreases. The term
"hyperfiltration" is also applicable to the
separation of solutes with different permeation
rates when the solution is forced through a
membrane under pressure. The term is descrip-
tive even if the solute to be removed is a trace
concentration and does not contribute
significantly to the osmotic pressure.13
Membranes
Hyperfiltration membranes can be classified
into two basic categories: neutral and ion-
exchange. Both approaches to membrane
development were recognized at about the
same time. But because of the favorable prop-
erties of a specific neutral type (the Loeb-
Sourirajan cellulose acetate membrane13); the
cellulose acetate membranes have received
most of the attention. Both flux and rejection of
cellulose acetate membranes were high com-
pared to those observed wkh available ion-
exchange membranes which were designed for
low water permeability. Since flux is inversely
proportional to thickness, a much thinner ion-
exchange layer was needed to realize the
potential flux advantages that a more loosely
structured membrane filtering by ion exclusion
could provide.
Several membrane configurations have been
proposed and tested. Many configurations in-
volve preformed or precast membranes which
require equipment disassembly for installation
and removal. The type of membrane of concern
in this paper is dynamically formed and does
not require disassembly for formation or
removal. Dynamically formed membranes are
formed at the interface of a solution and a
porous body from materials added to the solu-
tion as it circulates under pressure past the
porous body.13 Only limited success of
dynamically formed membranes from neutral
additives has been reported.15
The dynamic formation technique has made
possible the development of thin dynamically
formed ion-exchange membranes. Thus, the
high permeability of 1400 gpd/sq ft (57.12 cu
m/day/sq m) with a rejection of about 50 per-
cent that was expected of thin ion-exchange
membranes can be attained, particularly if they
are formed with fast circulation of feed past the
porous supports or with high turbulence.13J6-17
Several types of polyelectrolyte additives
were found to form this type of ion-exchange
membrane, e.g., synthetic organic polyelec-
trolytes,18-19 hydrous oxides,20'21 and natural
polyelectrolytes such as humic acid.19 Mem-
brane formation is not limited to soluble
polyelectrolytes or colloidal dispersions. It was
found that particulates such as clays could
form membranes as well.19'22
In many cases salt removal is unnecessary,
or even undesirable; consequently, a mem-
brane which passes salt while concentrating
other matter is preferred. Several dynamically
formed ultrafiltration membranes using
hydrous oxide and polyvinyl priolidone have
been tested successfully.23
Many materials can be used as porous sup-
ports: filter sheets such as Millipore and
Acrepor, porous metal, carbon tubes19;
ceramic tubes24; and woven fabric.25 For most
types of ion-exchange membrane additives, the
favorable pore size range lies between 0.1 and
1.0 microns.13
450
-------
Some attractive features of many dynamical-
ly formed membranes include the ability to
operate at elevated temperatures, allowing
treatment of waste streams at process
temperatures and recycle of the hot water. A
negative aspect is a deterioration of perfor-
mance from polyvalent counter ions in feed.13
Membrane regeneration can be relatively sim-
ple and inexpensive, since the deposit of active
membrane can be removed by flushing and
reformed by pumping through a dilute suspen-
sion of active material. Also, the higher fluxes
that can frequently be obtained allow the use of
tubular geometries without undue sacrifice in
production rate per unit volume.26
EXPERIMENTAL
Procedure
The test equipment was so constructed that
a pressurized solution, containing selected ad-
ditives during membrane formation and con-
sisting of the effluent to be studied during
membrane evaluation, could be circulated past
porous supports under controlled conditions of
temperature, pressure, pH, and circulation
velocity.
The feed solutions, a synthetic representa-
tion of the coal gasification wastewater, were
prepared with reagent-grade phenol, resor-
cinol, o-cresol, and catechol. Tests included
feed concentration variations of 1 to 100 mg/l
for solutions prepared with all four phenolic
compounds. Tests conducted solely with
phenol ranged in feed concentration from 1 to
400 mg/l. Reagent grade pentachlorophenol
was also used as a feed solution at 10 mg/l.
The range of pH used in testing varied from
test to test between 5 and 1 2, and similarly the
pressure ranged from 200 to 1000 psig (1 379
to 6895 kPa). The temperature variation ex-
amined was 25° to 55° C for the ultrafiltration
tests, and the hyperfiltration tests were con-
ducted at a constant 30° C. Ultrafiltration tests
were maintained at a constant pressure of 200
psig (1379 kPa). A constant flow rate past the
membranes of 1 5 ft/sec (4.57 m/s) was main-
tained for all tests. Concentrated nitric acid and
one normal sodium hydroxide were used to ad-
just the pH of the feed solution.
In each experimental run, the observed rejec-
tion was determined on the basis of salt con-
ductivity and solute concentrations, and the
results were expressed as a percent rejection.
The flux or permeation rate through the mem-
branes was determined and expressed as
gpd/sq ft of membrane surface. While most of
the test runs were conducted at specific
operating conditions and were for a limited
duration, several apparent optimum operating
conditions were .chosen for some extended-run
experiments designed to measure the
deterioration of the membrane with operating
time.
Equipment
All of the experimental work conducted on
this project was done at the Oak Ridge National
Laboratory in Oak Ridge, Tennessee. The
hyperfiltration loop at that facility is shown
photographically and schematically in Figure 2.
Feed solution was drawn from feed tank G by
the Milroyal type C triplex pump C (5 gpm
(0.32 l/s) at 1 500 psig (10.34 MPa) capacity)
and forced under pressure into the circulation
pump B, a 100-A Westinghouse centrifugal
pump which was rated at 100 gpm (6.31 l/s) at
100 psig (689 kPa) head. This pump circulated
the feed solution through the loop and past the
membrane supports, which were placed in test
sections A and A' (only one test section is
shown in the photograph). The test sections
were designed to direct the feed solution
through the annular region between a tubular
porous support, upon which the membrane
was formed, and the wall of a stainless steel
cylindrical pressure jacket (Figure 3). Flow
velocities past the membrane surfaces, typical-
ly 10 to 35 ft/sec (3.05 to 10.67 m/s), were
monitored by meters at D, the temperature of
the feed was controlled by the tube-in-tube
heat exchanger E, and the pressure was
regulated by a pneumatically controlled valve in
the letdown line which returned the feed to the
tank at atmospheric pressure. The product
which permeated the membranes was
monitored as to flux and composition, and was
returned to the feed container to maintain cons-
tant feed composition.
All of the materials used in the loop were
corrosion-resistant to minimize interference of
corrosion products with the formation of the
451
-------
TEST SECTIONS (A
FEED TANK
Figure 2. Hyperfiltration Loop.
-------
Solution
Out
/—Porous Ceramic Tube
t
r
3/4 inch-pipe
(19 nun-pipe)
Product
^
Hater
\ \ \
.
: X Soluti
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5/16 inch-tube
(8 mm-tube)
Figure 3. Mounting of typical test section with ceramic tube support.
membranes. The loop was designed to
eliminate stagnant side volumes in which
material might collect and contaminate subse-
quent experiments. The ultrafiltration loop con-
sisted of a configuration similar to the hyper-
filtration loop.
Porous Supports
Several different porous support materials
were used. Acropor AN sheets, a copolymer of
polyvinyl chloride and polyacrylonitrile on a
nylon substrate made by Gelman Instrument
Company, Ann Arbor, Michigan; and mem-
brane filter sheets made from mixed esters of
cellulose by Millipore Filter Company, Bedford,
Massachusetts, were wrapped around 5/8 inch
(15.9 mm) porous stainless steel tubes (pore
size - 5 /mi). Porous carbon tubes, Union Car-
bide Corporation's 563-6C (6.0 mm I.D.,
10.25 mm O.D., undetermined pore size) and a
porous ceramic tube, the Selas Ceramic filter
element made by Selas Flotronics Corporation,
Spring House, Pennsylvania, were also used.
Membrane Formation
The membranes were formed in carefully
cleaned equipment to eliminate the possible in-
terference of contaminants. Between each test
run, the loop was cleaned by using a one molar
sodium hydroxide wash, followed by a one
molar nitric acid wash, and then distilled water.
The porous supports were inserted into the
test sections. A solution of 0.04 molar sodium
nitrate and 0.0001 molar zirconium oxide
nitrate (ZrO(N03)2, adjusted to a pH of 4, was
circulated through the loop. As the hydrous ox-
ide was deposited on the supports, the
pressure increased. Once full pressure (900
psig (6205 kPa) to 1000 psig (6894 kPa)) was
achieved, the salt rejection was monitored until
it reached a value greater than 30 percent,
which usually took an hour or more. Then a
solution containing 50 mg/l of polyacrylic acid
(PAA, Acrysol A-3 by Rohm and Haas) was ad-
ded to the loop, and the pH was adjusted to 2.
This solution was circulated past the mem-
brane for about 30 minutes. After this time, the
pH was raised to about 3, maintained there for
another 30 minutes, and again raised a unit or
so. This stepwise increase in pH was repeated
until the solution was near neutral. At that
time, the formation of the membrane was con-
sidered complete.
Two variations of the formation procedure in-
cluded omitting the polyacrylic acid layer and
substituting a silicate layer for the polyacrylic
acid by adding 50 mg/l of sodium metasilicate
(Na2Si03).
Analytical Procedures
Routine monitoring of salt (observed) rejec-
tion was by conductivity with a conductance
bridge and a cell with a precalibrated cell con-
stant. Supplemental chloride analysis with a
Buchler-Corlove chloridometer was performed
in which the chloride ion concentration was
453
-------
determined by coulometric-amperometric titra-
tion with silver ion. This was done to check the
mechanical integrity of the membrane for the
absence of defects.
Phenol and phenolic compound combination
concentrations were monitored by two
methods. For test runs in which the feed con-
centration was greater than 10 mg/l phenol,
the phenol concentration was determined by
carbon analysis with a Beckman Model 915
Total Organic Carbon Analyzer. In this ap-
paratus, the solution sample was injected into a
high temperature (950° C) catalytic combus-
tion chamber where the total carbon in the
sample is oxidized in pure oxygen carbon diox-
ide which is analyzed by a Beckman Model IR-
215A nondispersive infrared analyzer. In-
organic carbon was determined in a similar
manner by injecting a sample into a 150° C
combustion chamber and analyzing the carbon
dioxide produced. The total organic carbon
(TOO was obtained from the. difference be-
tween the total carbon and the inorganic car-
bon. Most of the feed solutions and many pro-
duct solutions contained insignificant amounts
of inorganic carbon. The analysis of total car-
bon was therefore essentially total organic car-
bon.
For a test run or a series of test runs in which
the feed concentration of phenol was less than
10 mg/l, the Direct Photometric Method was
used.12 The principle of the method involved
the reaction of phenol with 4-amino antripyrine
at a pH of 10.0 ±0.2 in the presence of
potassium ferricyanide. The absorption of the
prepared samples was measured on a Bausch
and Lomb Spectronic 20 spectrophotometer at
a wavelength of 510 nm. A standard calibra-
tion curve for phenol was prepared.
The color of the product and feed streams
was determined with a Bausch and Lomb Spec-
tronic 20 spectrophotometer at a wavelength
of 465 nm and compared against platinum-
cobalt standards.12
Pentachlorophenol concentrations were
determined with a Gary Recording Spec-
trophotometer, Model 11 MS. The visible ab-
sorption spectra were scanned upward from
3000 angstroms to determine the exact
wavelength for maximum absorption. This was
found to be 3200 angstroms. All spectral
measurements were made in a 10-cm silica
glass cell. A calibration curve was prepared.
EXPERIMENTAL RESULTS
Hyperfiltration
The first hyperfiltration experiment utilized
the zirconium oxide-polyacrylic acid (Zr(IV)-
PAA) membrane with a feed solution composed
of 100 mg/l each of phenol, catechol, resor-
cinol, and o-cresol. Six membrane support
materials were tested. Three of these support
materials, 6C carbon tube, 0.27-/* Selas
ceramic tube, and 0.47-/t Acropor sheet on
stainless steel tube, were used for the data
presented in Figure 4. The tests were con-
ducted at 25° C.
The results in the first three columns of
Figure 4 indicate that the type of membrane
support material has little effect on the perfor-
mance of the dynamic membrane. The data are
presented to show the effects of both pressure
and pH on the operation of the membrane. The
production of product water or flux rate is
significantly increased by the increase of
pressure, but the variation of pH has little effect
on the flux rate.
The solute rejection rate increases from
about 45 percent at a pH of 6.5 to about 80
percent at a pH of 10. It was expected that a
pH of about 9.5 to 10 would produce the most
significant reduction in the phenolic com-
pounds because the phenolic compounds are
sufficiently ionized at this pH to react favorably
with the ion exchange properties of the mem-
brane.
The salt rejection produced the opposite
results by the rejection rate from about 92 per-
cent to 85 percent as the pH is raised from pH
6.5 to 10. The maximum rejection of salt is
best achieved near neutral pH. This
characteristic is quite beneficial where the
desire is to reduce the phenolic concentration
without trying to remove all of the salt in the
wastewaters.
The fourth column of Figure 4 presents data
on the effect of different concentrations of the
solute on the performance of the membrane.
The Acropor membrane support produces a
better flux rate than the other support
materials, however, the variations in the con-
454
-------
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Pressure, MPa
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Pressure, psig Pressure, psig Pressure, psig Concentration, mg/1 Operating Time, hrs
Figure 4. Hyperfiltration of Phenolic compounds (100 mg/l).
-------
centration have little effect on the flux rate. The
maximum flux rate is about 140 gpd/sq ft (5.7
cu m/day/sq m). The solute rejection and salt
rejections remained constant at about 90 per-
cent.
The final column of Figure 4 provides infor-
mation about the long term effects of treatment
on the operation of the membranes. The flux
rate increased initially and then stabilized at
about 1 50 gpd/sq ft (6.1 cu m/day/sq m). The
solute rejection rates remained constant over
the operating interval at about 90 percent. Salt
rejection dropped slightly from 90 to 85 per-
cent.
The next series of tests examined the
suitability of zirconium oxide-polyacrylic acid
(Zr(IV)-PAA), zirconium oxide-sodium silicate
(Zr(IV)-Si), and zirconium (Zr(IV)) alone as
membranes for the hyperfiltration of 10 mg/l of
pentachlorophenol feed solution. The results
are presented in Figure 5.
The first column of Figure 5 indicates that pH
does have a significant effect on the flux rate of
pentachlorophenol. While the zirconium mem-
brane produced the highest flux rates, the
solute rejection and salt rejection was far below
the other membranes. The rejection of pen-
tachlorophenol approaches 100 percent.
The second column of Figure 5 shows that
the flux rate is virtually unchanged as pH in-
creases, however, the solute rejection rate
does increase with pH. The third column of
Figure 5 indicates that flux rate rises with
pressure. While the zirconium-silicate mem-
brane produces the highest flux rate, the
zirconium-polyacrylic acid provides the highest
solute rejection at about 80 percent. The final
column of Figure 5 again indicates that the
membranes are stable for extended periods of
time.
Ultrafiltration
Similar experimental parameters were ex-
amined under Ultrafiltration. With a feed solu-
tion of 100 mg/l each of phenol, resorcinol,
o-cresol, and catechol, tests were performed
on three types of membranes on Selas ceramic
supports: zirconium oxide (Zr(IV)), zirconium
oxide-sodium silicate (Zr(IV)-Si), and silicate
(Si). Figure 6 depicts a pH scan with the ex-
pected rejection increase at the higher pH.
There is very little difference between the
solute rejection rate for each type of membrane
as the pH is increased. The data would indicate
that it is the ionic state of the solute rather than
the membrane that is the controlling factor in
the rejection rate. The 75 percent solute rejec-
tion is below the 80 percent indicated on Figure
5 at a pressure of 950 psif (6.5 MPa).
As shown in column two of Figure 6,
temperature of the feed water has a significant
effect on the flux rate for some membranes.
The flux for the zirconium oxide membrane in-
creased from 60 gpd/sq ft (2.45 cu m/day/s-
q m) at 25° C to 160 gpd/sq ft (6.53 cu
m/day/sq m) at 55° C. However, the salt and
solute rejections appeared to be unaffected by
the temperature changes.
Operating the filtration process for extended
periods of time indicated a slight reduction of
flux rate with time initially, followed by a long
period of stable flow. The solute and salt rejec-
tions were unaffected by the operating time.
The sensitivity of the operation to variations
in concentration was evaluated. Over a range
of 1 mg/l to 400 mg/l of phenol, not significant
variations in the data were noted.
A final test of the membranes, as shown in
column five of Figure 6, was a pH scan from
6.5 to 12. Destruction or deterioration of the
membranes was expected at the high pH
values. The flux rate declined slightly as the pH
was increased. The solute rejection increased
significantly as the pH was increased above 8,
but started to fall beyond pH 11. The salt rejec-
tion rate was the greatest at about a pH of 9,
and fell down in both directions. In general the
zirconium membrane outperformed the silicate
membrane for the solute being tested.
CONCLUSIONS
The points of most general importance which
have emerged from the foregoing studies are,
briefly, as follows:
1. The carbon support tube produced
slightly better rejection rates, but lower
flux rates.
2. Increasing the pH of the feed increased
the solute rejection rate, decreased the
salt rejection rate, and had little effect
on the flux rate.
456
-------
01
100
3 8°
o
"I 60
a 40
m
* 100
O
o
01
01
4J
o
CO
O1
a
80
60
160
120
80
x 40
3
Pressure, HPa
246
Pentachlorophenol
950 psig
e.s e
Phenol
950 psig
Phenol
pH 10
O Zr(IV)-PAA, Carbon Support
Q Zr(IV)-PAA. Selas Support
• Zr(IV)-Si, Selas Support
• 7.r(IV) only, Selas Support
Phenol
950 psig, pH 10
£
tr
m
>,
•o
a
o
K
X
9
9
pH
10 11 6.5 8
9 10 11 250 500 750 950
pH Pressure, psig
0 40 80 120 160 200
Operating Time, hrs
Figure 5. Hyperfiltration of pentachlorophenol and phenol (10 mg/l).
-------
o
01
K
VI
c
o
•H
4J
U
01
80
60
40
20
80
60
40
t| 20
iH
O
(0
tn
oo
160
120
J 80
4J
«
x 40
Phenolic Compounds
25°C, 100 mg/1
===8
Phenolic Compounds
100 mg/1, pH 10
Phenolic Compounds
25°C, 100 mg/1, pH 10
Phenol
25°C, pH 10
O Zr(IV), Selas Support
GJ Si, Selas Support
• Si, Selas Supports
J
Phenol
25°C, 400 mg/1
T
e
OF*
•o
4 3
O
0)
X
3
6.5 8 9 10 25 35 45 55 0 40 80 120 1602001 10 50 100 4006.5 8 9 10
pH Temperature, °C Operating Time, hrs Concentration, mg/1 pH
11 12
Figure 6. Ultrafiltration of phenolic compounds and phenol (200 psig, 1.38 MPa).
-------
3. Increasing the pressure of the feed
significantly increased the flux rate but
had little effect on the solute and salt
rejection rates.
4. Variations in concentration produced
little change in rejection rates but did
cause a slight decrease in flux rates as
concentration increased.
5. Long-time operation of the processes
indicated that the rejection rates and
flux rates stabilize after a short period
of time.
6. Increasing the temperature of the feed
resulted in an increase in the flux rate
but very little change in the rejection
rates.
7. The best rejection of the phenolic com-
pounds was obtained with a pH of 10,
pressure of 950 psig (6.5 MPa), and
zirconium oxide-polyacrylic acid on car-
bon supports.
ACKNOWLEDGMENTS
The authors wish to express their thanks to
the Oak Ridge National Laboratory, operated by
Union Carbide Corporation for the United
States Energy Research and Development Ad-
ministration, for the use of their hyperfiltration
and ultrafiltration equipment and their
laboratory facilities. A special thanks is due to
Dr. James S. Johnson and his co-workers for
their guidance during this project.
The project was funded in part by a National
Science Foundation Research Initiation Grant
Number ENG75-10251. Thanks are also due
to Dr. Arthur A. Ezra, Program Director, Na-
tional Science Foundation, Water Resources,
Urban and Environmental Engineering,
Engineering Division.
REFERENCES
1. S. L. Klemetson, "Climatic Effects on
Waste water Treatment," Symposium
Proceedings: Environmental Aspects of
Fuel Conversion Technology, II, EPA-
600/2-76-149,241-251 (1976).
2. S. L. Klemetson, "Pollution Potentials of
Coal Gasification Plants," presented at
the 31st Annual Purdue Industrial Waste
Conference, Purdue University, West
Lafayette, Indiana, May 1976.
3. G. E. Stout (ed.), Proceedings of the
Workshop on Research Needs Related to
Water for Energy, Water Resources
Center, University of Illinois at Urbana-
Champaign, Urbana, Illinois (1974).
4. H. B. De W Erasmus, Letter SFL-104,
South African Coal, Oil, and Gas Corpora-
tion, Limited (1974).
5. R. Cooke and 0. W. Graham, "The
Biological Purification of the Effluent from
a Lurgi Plant Gasifying Bituminous
Coals," J. Air and Water Poll 9 (1965).
6. L. Barker and N. W. Hollingsworth, "The
Composition of Ammonical Liquors, II.
Analysis of the Phenolic Content by
Chromatography," J. Appl. Chem. 9
(1959).
7. C. W. Chambers, "Degradation of
Aromatic Compounds by Phenol Adapted
Bacteria,"./. Water Poll. Control Fed. 35
(1963).
8. J. R. Fleeker, "Water Quality and Water
Disposal I. Chemistry of Gasifier Wastes
from the Lurgi Process," North Dakota
State University, Department of
Biochemistry (unpublished)U 976).
9. M. C. Bromel, Natural Gas Pipeline Com-
pany of America's Environmental Impact
Report on the Lignite Gasification Project
at Dunn County, North Dakota. North
Dakota State University, Department of
Bacteriology (unpublished)! 1976).
10. R. G. Bond and C. P. Straub, Handbook of
Environmental Control-Water and Treat-
ment III, Cleveland, Ohio, CRC Press
(1973).
11. R. E. Rosfjord, R. B. Trpttner, and <"1 N.
Cheremisinoff, "Phenol, a Water Control
Assessment," Water and Sewage Works
123, No. 3, 96-99 (1976).
1 2. Standard Methods for the Examination of
Water and Wastewater, American Public
Health Association, 13th Ed. (1971).
13. J. S. Johnson, Jr., L. Dresner, and K. A.
Kraus, Chapter 8, K. S. Spiegler, ed., Prin-
ciples of Desalination, Academic Press,
New York (1966).
14. A. J. Shor, K. A. Kraus, J. S. Johnson,
Jr., and W. T. Smith, Jr., Ind. Eng. Chem.
Fundam. 7, 44 (1968).
459
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15. D. C. Moore et al.. Oak Ridge National 22.
Laboratory Report ORNL-NSF-14 (1972).
16. D. G. Thomas and J. S. Watson, Ind. Eng. 23.
Chem. Process Des. Development 7, 397
(1968).
17. D. G. Thomas, Environ. Sci. Techno!. 4, 24.
1129 (1970).
18. K. A. Kraus et al.. Science 151. 194 25.
(1966).
19. K. A. Kraus, A. J. Shor, and J. S.
Johnson, Jr., Desalination 2, 243 26.
(1967).
20. A. E. Marcinkowsky, J. Am. Chem. Soc.
88, 5744 (1966).
21. A. J. Shor, K. A. Kraus et al., Ind. Eng.
Chem. Fundam. 7, 44 (1968).
E. R. Brownscombe and L. R. Kern, U.S.
Patent 3, 331, 772.
R. E. Minturn, et al., Oak Ridge National
Laboratory Report ORNL-NSF-EL-72
(1972).
J. J. Perona et al.. Environ. Sci. Tech. 1,
991 (1967).
J. A. Dahlheimer, D. G. Thomas, and K. A.
Kraus, Ind. Eng. Chem. Process Des.
Develop. 9, 565 (1970).
R. E. Minturn, Advanced Techniques for
Aqueous Processing and Pollution Abate-
ment, final report, Oak Ridge National
Laboratory Report, ORNL-NSF-EP-72
(1974).
460
-------
COMPOSITION AND
BIODEGRADABILITY OF
ORGANICS IN COAL
CONVERSION WASTEWATERS
Philip C. Singer, Frederic K. Pfaender,
Jolene Chinchilli, and James C. Lamb, III
Department of Environmental Sciences
and Engineering
School of Public Health
University of North Carolina
Chapel Hill, North Carolina 27514
INTRODUCTION
Several technologies for producing synthetic
fuels from coal are under development. While
most of the emphasis has centered upon devel-
opment of efficient process technology to pro-
duce high energy, clean, synthetic fuels,
little information is available with respect to the
nature of the waste materials produced and the
environmental impact of byproduct waste
streams from the various gasification and li-
quefaction processes.
Wastewaters from coal conversion proc-
esses can originate from a variety of sources
depending upon the specific processes
employed. The composition of the wastewater
depends upon the process technology,
operating conditions, and nature of the feed
coal. Some characteristics of these waste-
waters are shown in Table 1. Many coal con-
version technologies employ byproduct
recovery systems for phenol and ammonia, two
of the major constituents of the wastewater as
shown in the table. Phenol concentrations in
the solvent-extracted liquor, however, are still
appreciable and further treatment of the waste
streams is still required.
Most coal conversion technologies incor-
porate or project aerobic biological waste treat-
ment processes (e.g., activated sludge, aerated
lagoons, etc.) as the principal means of treating
the residual phenol and other organic impurities
in the wastewater. However, the nature and
biodegradability of these other organic
materials, which are included in Table 1 as part
of the COD (chemical oxygen demand) are not
known. Hence, the extent to which these COD
components can be removed by biological
treatment cannot be predicted.
Since even well-operated biological treat-
ment processes typically remove only 85-95
percent of the influent BOD (biochemical ox-
ygen demand) and a significant portion of the
wastewater organics may not even be bio-
degradable, it is doubtful that biological treat-
ment alone can provide an environmentally ac-
ceptable discharge.
In view of these considerations, a need
exists:
a. to identify the nature and char-
acteristics of aqueous discharges from
coal conversion processes and to as-
sess their environmental impact, and
b. to develop satisfactory means for the
treatment of these wastewaters in
order that they may be disposed of in
an environmentally acceptable fashion.
Accordingly, this paper presents the results of
a survey aimed at determining the chemical
characteristics of coal conversion wastewaters
and at identifying specific organic con-
taminants which might be found in such
wastewaters. The constituents have been iden-
tified by reviewing the published literature,
visiting coal gasification and liquefaction
research and demonstration installations, and
analyzing reports and project documents from
a variety of coal conversion operations. A
preliminary assessment of the aquatic impact
of these wastewaters and of their biological
treatability is also presented.
CHARACTERISTICS OF COAL
CONVERSION WASTEWATERS
Table 1, presented earlier, shows the results
of an analysis conducted by Forney, et al.,
(1974)1 of the condensate wastewater gen-
erated from the Synthane gasification of six dif-
ferent types of coal. The wastewater char-
acteristics of the weak ammonia liquor from a
coke plant are also presented for purposes of
comparison. The waste condensate streams
appear to be somewhat alkaline and contain
rather substantial amounts of ammonia. The
concentration of organic material, represented
by the chemical oxygen demand (COD), ap-
pears to consist, for the most part, of phenol.
461
-------
TABLE 1
BYPRODUCT WATER ANALYSIS FROM SYNTHANE GASIFICATION
OF VARIOUS COALS. (AFTER FORNEY ET AL. (1974).1)
(ALL VALUES IN mg/l EXCEPT pH.)
o>
CO
PH
Suspended Solids
Phenol
COD
Thiocyanate
Cyanide
NH3
Chloride
Carbonate
Bicarbonate
Total Sulfur
Coke
Plant
9
50
2,000
7,000
1,000
100
5,000
-
-
-
-
Illinois
No. 6
Coal
8.6
600
2,600
15,000
152
0.6
8,100
500
6,000
11,000
1,400
Wyoming
Subbituminous
Coal
8.7
140
6,000
43,000
23
0.23
9,520
Illinois
Char
7.9
24
200
1,700
21
0.1
2,500
31
North
Dakota
Lignite
9.2
64
6,600
38,000
22
0.1
7,200
-
Western
Kentucky
Coal
8.9
55
3,700
19,000
200
0.5
10,000
—
Pittsburgh
Seam
Coal
9.3
23
1,700
19,000
188
0.6
11,000
—
-------
TABLE 2
PERCENTAGE OF COD ATTRIBUTABLE TO PHENOL IN SYNTHANE
GASIFICATION BYPRODUCT WATER. (RAW DATA FROM FORNEY ET AL. (1974).1
Component
Chemical Oxygen
Demand, mg/1
Phenol, mg/1
Phenol, mg/1
equiv. of COD
en Phenol, % of
COD
Sample
7,000 15,000 43,000
2,000 2,600 6,000
4,760 6,188 14,280
68.0
41.2
33.2
1,700 38,000 19,000 19,000
200 6,600 3,700 1,700
476 15,708 8,806 4,046
28.0
41.3
46.3
21.3
Column 1 contains wastewater data from a coke plant; Columns 2-7 contain wastewater data from
the gasification of several different types of coals (see Table 1).
-------
Table 2 indicates, however, that phenol ac-
counts for only 21 to 46 percent of the COD in
the condensate samples; the remaining 54 to
79 percent of the COD is apparently due to the
presence of other organic components of the
waste streams. Table 2 was developed by
calculating the COD-equivalent of the phenol
concentrations given in Table 1 , using a
stoichiometric factor of 2.38 g of COD per g of
phenol from the equation
C6H5OH
phenol
7 02 - 6C02 + 3H20 (1)
Bromel and Fleeker (1976)2 examined some
general properties of raw and processed
wastewater from the Lurgi process plant at
Sasolburg, South Africa. Table 3 shows that
the raw Lurgi wastewater is similar to that from
Synthane in terms of its alkaline pH and high
ammonia and COD concentrations. The raw
wastewater consists of the condensate from
the gasifier (gas liquor) after tar and oil separa-
tion. The processed wastewater refers to the
gas liquor following phenol and ammonia ex-
traction.
In order to determine the nature of the
organic species comprising the COD and total
organic carbon (TOO, Bromel and Fleeker con-
ducted a series of chromatographic separations
and identified and quantified the components
reported in Table 4. It is apparent that, of the
specific organic compounds identified, phenol
and its methyl substituents, the cresols
(methylphenols) and xylenols (dimethyl-
phenols), are the major organic components of
the condensate. Polyhydric phenols were not
analyzed for. The other major classes identified
are the fatty acids (aliphatic acids) and the
aromatic amines consisting of pyridine and its
methyl derivatives, and aniline. Quinoline and
alkyl amines were found in lesser amounts. It is
apparent from the table that the phenol extrac-
tion step is relatively efficient in separating the
monohydric phenols and even the aromatic
amines from the gas liquor.
In order to determine what fraction of the
COD and TOC reported in Table 3 could be ac-
counted for by the specific organics identified
in Table 4, a series of calculations was per-
formed to determine the COD and TOC-
equivalents of the compounds listed in Table 4.
The basis for these calculations is shown in
Table 5, and the TOC and COD-equivalents of
the organic constituents are listed in Table 6. In
the raw wastewater, the total COD of the con-
stituents listed is 6738 mg/l of which the
monohydric phenols comprise 5915 mg/l. The
TABLE 3
SOME GENERAL PROPERTIES OF RAW AND PROCESSED WASTEWATER
FROM THE LURGI-PROCESS PLANT AT SASOLBURG, SOUTH AFRICA.
(AFTER BROMEL AND FLEEKER (1976).2)
Values
Parameter
Chemical Oxygen Demand
(mg/l)
Organic Carbon (mg/l)
Total Dissolved Solids (mg/l)
PH
Ammonia (mg/l)
Raw
Waste
Water
12,500
4,190
2,460
8.9
11,200
Processed
Waste
Water
1,330
596
8.2
150
, not determined.
464
-------
TABLE 4
CONCENTRATION OF ORGANIC COMPOUNDS FOUND IN RAW AND
PROCESSED WASTEWATER FROM THE LURGI-PROCESS PLANT AT
SASOLBURG, SOUTH AFRICA. (AFTER BROMEL AND FLEEKER (1976)2.)
Concentration (mg/1)
Raw Processed
Compound Waste Water Waste Water
Fatty Acids
Acetic Acid 171 123
Fropanoic Acid 26 30
Butanoic Acid 13 16
2-Methylpropanoic Acid 2 5
Pentanoic Acid 12 7
3-Methylbutanoic Acid 1 5
Hexanoic Acid 1 8
Monohydric Phenols
Phenol 1,250 3.2
2-Methylphenol 340 <0.2
3-Methylphenol 360 <0.2
4-Methylphenol 290 <0.2
2, 4-Dimethylphenol 120 NFA
3, 5-Dimethylphenol <50 NF
Aromatic Amines
Pyridine 117 0.45
2-Methylpyridine 70 <0.05
3-Methylpyridine 26 <0.05
4-Methylpyridine 6 <0.05
2, 4-Dimethylpyridine <1 NF
2, 5-Dimethylpyridine <1 NF
2, 6-Dimethylpyridine <1 NF
Aniline 12 NF
, not found.
465
-------
TABLE 5
COD AND TOC-EQUIVALENTS OF ORGANIC CONSTITUENTS
OF SASOL WASTEWATER
Chemical Oxygen Total
Demand, Organic Carbon,
Reaction gm 0?/gm org. gm C/gm org.
Phenol
CeHsOH + 7 02 + 6C02 + 3H20
Me L lylpheno 1 (ere sol)
C-jEiO + 8. 5 02+ 7C02 + 4H20
Dimethylphenol (xylenol)
C8r.10° + 10 °2-*- 8C02 + 5H20
Pyridine
C5H5N • 5.5 02+ 5C02 + H20 + NHs
Methylpyridine
C6HyN + 7 02+ 6C02 + 2H20 + NH3
Dimethylpyridine
CyHgN + 8.5 02-*- 7C02 + 3H20 + NH3
Aniline
CeHyN + 7 02 -t. 6C02 + 2H20 + NH3
Acetic Acid
CHaCOOH + 2 02+ 2C02 + 2H20
Propanoic Acid
CH3CH2COOH + 3.5 Q2 + 3C02 + 3H20
Butanoic Acid
CH3(CH2)2COOH + 5 02 + 4C02 + 4H20
Methylpropanoic Acid
C4Hg02 + 21/4 02 + 4C02 + 9/2 H20
Pentanoic Acid
C5H1002 + 6.5 02 + 5C02 + 5H20
Methylbutanoic Acid
C5Hn02 + 27/4 02 - 5C02 + 11/2 H20
Hexanoic Acid
C6H1202 + 8 02 = 6C02 + 61^0
2.35
2.52
2.62
2.23
2.41
2.54
2.41
1.07
1.51
1.82
1.89
2.04
2.10
2.21
0.77
0.78
0.79
0.76
0.77
0.79
0.77
0.40
0.49
0.60
0.54
0.59
0.58
0.62
466
-------
monohydric phenols contribute 1 866 mg/l of
TOC out of the total TOC of 2143 mg/l ac-
counted for by the indicated constituents.
However, if the COD and TOC of the identified
organic components of the Sasol wastewater
from Table 6 are compared to the total concen-
trations reported for the same sample in Table
3, Table 7 shows that 46.1 percent of the COD
and 48.9 percent of the TOC of the raw
wastewater is not accounted for. Similarly, a
very small percentage of the COD (and, also
probably of the TOC) of the processed
wastewater is attributable to the residual
aliphatic acids following phenol extraction.
It should be noted that the data presented in
Tables 3 and 4 were derived from single
samples of the aqueous gas liquor and the
phenol-extracted gas liquor. The age of the
TABLE 6
CONCENTRATION OF ORGANIC COMPOUNDS, AS COD AND TOC,
FOUND IN THE RAW AND PROCESSED WASTEWATER FROM THE
LURGI-PROCESS PLANT AT SASOLBURG, SOUTH AFRICA.
RAW DATA FROM BROMEL AND FLEEKER (1976)2.)
Concentration, mg/l
Compound
Raw Wastewater
COD
TOC
Processed Wastewater
COD TOC
Fatty Acids
acetic acid
propanoic acid
butanoic acid
2-methylpropanoic acid
pentanoic acid
3-methylbutanoic acid
hexanoic acid
68.4
12.7
7.8
1.1
7.1
0.6
0.6
98.3
131
Monohydric Phenols
phenol
2-methyIphenol
3-me thyIphenol
4-methyIphenol
2, 4-dimethyIphenol
3, 5-dimethyIphenol
963
265
277
226
95
139.5
1866
7.6
<0.5
<0.5
<0.5
9.1
2.5
<0.2
<0.2
<0.2
3.1
Aromatic Amines
pyridine
2-methyIpyridine
3-methylpyridine
4-methylpyridine
2, 4-dimethylpyridine
2, 5-dimethyIpyridine
2, 6-dimethyIpyridine
aniline
TOTAL
1.0
<0.12
<0.12
<0.12
6738
2143
0.34
<0.04
<0.04
<0.04
467
-------
TABLE 7
PERCENTAGES OF UNIDENTIFIED COD AND TOC IN SASOL
WASTEWATER (RAW DATA FROM BROMEL AND FLEEKER (1976)2.)
Parameter
Total COD, mg/1
COD of Identified Constituents, mg/1
% of COD Unidentified
Total TOC, mg/1
TOC of Identified Constituents, mg/1
% of TOC Unidentified
Raw Wastewater Processed Wastewater
12,500
6,738
46.1
4,190
2,143
48.9
1,330
269
79.8
92
samples was not accurately known, but is
believed to have been less than 6 months for
the raw wastewater and less than 1 month for
the processed wastewater. The analyses were
completed within 4 months following receipt of
the samples (Bromel and Fleeker, 1976)2.
It is apparent from Tables 2 and 7 that many
other organic species are present in coal con-
version wastewaters, and that a need exists for
further identification and quantification of
these constituents.
Along these lines, Schmidt, Sharkey, and
Friedel (1974)3 employed mass spectrometric
methods to determine the nature of the organic
contaminants in condensate waters from the
Synthane gasification of coal. (The Synthane
process produces about 0.4 - 0.6 tons of con-
densate water per ton of coal gasified (Forney
et al., 1 9.74.1) The condensate waters from the
gasification of six different coals were ex-
tracted with methylene chloride and were iden-
tified using high resolution mass spectrometry,
combined gas chromatography-mass spec-
trometry, and low-voltage mass spectrometry.
Table 8 summarizes the results of these spec-
trometric analyses for the six different coals
gasified. Again, phenol appears to be the major
organic component of the condensate waters
and, along with the other monohydric, dihy-
dric,and polyphenols, constitutes approximate-
ly 60 to 80 percent of the methylene chloride
extract. Several other classes of organics ap-
pear to be represented, including heterocyclic
compounds such as the pyridines and furans,
and polycyclic components such as indenols,
indanols, naphthols, quinolines, and indoles. It
is interesting to note that, regardless of the
type of coal gasified, the composition of the
condensate water, in terms of the component
organics and their concentrations, is relatively
uniform. It should also be noted that the con-
stituents reported by Bromel and Fleeker
(1976)2 in Table 4 are consistent with the
listing by Schmidt, Sharkey, and Friedel
(1974)4inTable8.
Expanding on this effort to identify organic
constituents in wastewaters from coal gasifica-
tion and coal liquefaction operations from
various sources, Table 9 is a summary of infor-
mation gathered from the eight different
references cited. The organics have been
grouped into various classes and include
monohydric and dihydric phenols, polycyclic
hydroxy compounds (polyphenols), monocyclic
and polycyclic nitrogen-containing aromatics
(including heterocyclic compounds such as the
pyridines, quinolines, indoles, acridines and
carbazoles, and the aminobenzenes), aliphatic
acids, and a group of miscellaneous other com-
pounds. The check (^) marks indicate that the
compound in question has been identified but
not quantified. The range notation ( I ) in-
dicates that the concentrations given are for a
group of compounds, but that the individual
components within the group have not been
quantified, e.g., 140-1170 mg/l for column 1
468
-------
TABLE 8
CONTAMINANTS IN PRODUCT WATER FROM SYNTHANE
GASIFICATION OF VARIOUS COALS. (AFTER SCHMIDT ET AL. (1974).3)
(ALL CONCENTRATIONS IN mg/l.)
Phenol
Cresols
Illinois No.
3,400
2,840
1,090
110
250
70
150
60
160
90
—
6 (hvBb)
2,660
2,610
780
100
540
100
100
110
110
90
—
Montana
(Sub)
3,160
870
240
30
130
80
140
-
160
70
10
N. Dak.
(Lig)
2,790
1,730
450
60
70
60
110
-
140
50
10
Wyo.
(Sub)
4,050
2,090
440
50
530
100
110
60
80
60
—
W. Ky.
(hvBb)
2,040
1,910
620
60
280
50
90
50
160
80
—
Pgh.
(hvAb)
1,880
2,000
760
130
130
70
120
80
170
20
110
Dihydrics
Benzofuranols
o> Indanols
Ace tophenones
Hydroxy-
benzaldehyde
Benzole Acids
Naphthols
Indenols
Benzofurans
Dlbenzofurans - - - - - - -
Biphenols 40 20 - 40 20 60
Benzothio-
phenols 110 60 - 10 20 70 20
Pyrldines - 60 270 220 120 30 540
Quinolines - 20 10 - 10
Indoles - 20 70 30 20 40 40
-------
TABLE 9
SUMMARY: ORGANIC CONSTITUENTS IN COAL
CONVERSION WASTEWATERS (ALL CONCENTRATIONS IN mg/l).
20-150
MONQHYDRIC PHENOLS
PHENOL
o-CRESOL
N-CRESOL
P-CRESOL
2. 6-XYLENOL
3, 5-XYLENOL
2. 3-XYLENOL
2. 5-XYLENOL-
I. 4-XYLENOL
2, 4-XYLENOL
o-ETHYLPHENOL
M-ETHYLPHENOL
p-ETHYLPKENOL
3-HETHYL, 6-ETHYLPHENOL
2-METHYL, 4-ETHYLPHENOL
4-METHYL, 2-ETHYLPHEHOL
5-METHYL, 3-ETHYLPHEHOL
2, I, 5-TRIME1HYLPHENOL
O-ISOPROPYLPHENOL
D1HYDR1C PHENOLS
CATECHOL y
3-METHYLCATECHOL
4-METHYLCATECHOL
3, 5-DIMETHYLCATECHOL
3, 6-DIMETHYLCATtCHOL
METHYLPYROCATECHOL •
RESORC1NOL y
5-METHYLRESORCIHOL
4-METHYLRESORC1NOL
2-METHYLRtSORCINOL
2. 4-DIMETHYLRESORC1NOL
HYDROOUINONE S
POLYCYCL1C HYDROXY COMPOUNDS
T -NAPHTHOL ~f
30-290
,t,
SYNTHANE OIL SYN- LURGI- SYN- LURGI- HYDRO-
TPR-86 SHALE THANE COED SRC WESTFIELD THANE SASOL CARBONIZ. COED
(1) (2) (3) U) (5) (6) (7) (8) (9) (10)
1000-4480 10 2100
T 30 670
530-3580 T T
t*m
30 1800
230
30
140-1170 250
100
30
2100
650
T
18^0
240
40
220
900
30
1250-3100 T 1250
153-343 2209 340
170-422 '
160-302
I
100-393
360
290
50
i
2185
120
i
66
10
190-555
30-394
110-385
y
0-45
176-272
40-64
0-36
2000
i
4-7
• -NAPHTHOL
HETHYLHAPHTHOL
INDENOL
CI-INDENOL
4-INDANOL
CI-INDANOL
BIPHENOL
10
30
2010
0-110
66
470
-------
TABLE 9 (Continued)
SYNTHAflE OIL SYN- LURGI- SYN- LURGI- HYDRO-
TPR-86 SHALE THANE COED SRC HESTFIELD THANE SASOL CARBONIZ.
HOHOCYCL1C N-AROHAT1CS
PYRIDINE
HYDROXYPYRIDINE
HETHYLHYDROXYPYRIDINE
HETHYLPYRIDINE
DIMETHYLPYRIDINE
ETHYLPYRIDIHE
C3-PYR1DINE
CjfPYRlDINE
AHALKIE
HETHYLANILINE
DIKETHYLANILINE
POLYCYCLIC N-AROHATICS
OUINCLINE
HETHYLQUINOLINE
DIHETHYLQUINOLIHE
ETHYLOUINOLIfNE
BENZOQUINCLINE
NETHYLBENZOOU1NOL1NE
TETRAHYDROQUINOLINE
fETHYLTETRAHYDROQUINOLINE
1SOOUINOLINE
INDOLE
HETHYLINDOLE
DIfETHYLINDOLE
BENZOINDOLE
HETHYLBENZOINDOLE
CARBAZOLE
HETHYLCARBAZOLE
ACRIDINE
ICTHYLACRIDINE
(1)
I
(2) (3) («) (5)
(6)
30-580
i
0-100
0-110
i
s
s
s
S
S
s
s
(7) (8)
117
104
(9)
10
10
COED
(10)
21
9
11
7
27
12
63
471
-------
TABLE 9 (Continued)
Synthane Oil Syn- Lurgi- Syn- Lurgi- Hydro-
TPR-86 Shale thane COED SRC Westfield thane Sasol carboniz. COED
(1) (2) (3) (4) (5) (6) (7) _J8) (9) (10)
Aliphatic Acids
Acetic Acid 600 620 600 171
Propanoic Acid 210 60 90 26
n-Butanoic Acid 130 20 40 13
2-Methylpropanoic Acid - - 2
ri-Pentanoic Acid 200 10 30 12
3-Methylbutanoic Acid - 1
n-Hexanoic Acid 250 20 30 1
n-Heptanoic Acid 260
n-Octanoic Acid 250
n-Nonanoic Acid 100 - -
n-Decanoic Acid 50 - -
Others
Benzofurans 10-110
Benzofuranols 50-100
Benzothiophenols 10-110
Acetophenones 90-150
Hydroxybenzaldehyde
or Benzole Acid 50-110
-------
for the C2-phenols which include the isomers of
xylenol (dimethylphenol) and ethylphenol.
Where a range of values is given, e.g.,
1000-4480 mg/l for phenol in column 1, this
indicates that several samples have been
analyzed and the concentrations measured are
within the given range.
Column 1 is derived from the previously
discussed methylene-chloride, mass spec-
trometric analysis by Schmidt, Sharkey, and
Friedel (1974)3 for the condensate waters from
the Synthane gasification of six different types
of coal under different process conditions. Col-
umns 2, 3, and 4 include date from Ho, Clark,
and Guerin (1976)4 and were obtained by gas
chromatography using Tenax columns and
flame ionization detection. Identifications were
made from comparisons of the chromatograms
with retention time data for reagent grade com-
pounds. Some identifications were confirmed
by gas chromatography-mass spectrometry.
Quantitation was made by integrating peak
areas from the chromatogram and comparing
with standards of known concentration. The oil
shale byproduct water (column 2) was ob-
tained by centrifugation of an oil/water emul-
sion product from a simulated in-situ retort run
made by the Laramie (Wyoming) Energy
Research Center. The gasification byproduct
water (column 3) was a sample of filtered con-
densate water from the Synthane process, pro-
vided by the Pittsburgh (Pennsylvania) Energy
Research Center. The coal liquefaction by-
product sample (column 4) was filtered water
from the first-stage gas scrubber of the COED
(Char Oil Energy Development) liquefaction
process, provided by PMC Corporation, of
Princeton, New Jersey.
The information in column 5 was obtained
from a characterization of organics in coal-
derived liquids from the Ft. Lewis, Washington
Solvent Refined Coal Plant by Fruchter et al.,
(1977).5 The constituents of the raw process
water were separated into acidic, basic,
neutral, and polyaromatic fractions and each
fraction was separated further by gas
chromatography. Gas chromatography/mass
spectrometry was then employed to identify
the components. The constituents indicated in
column 5 have been positively identified, but
not yet quantified.
Column 6 contains data collected by Janes
and Rhodes (1 977)6 from the Lurgi gasification
facility in Westfield, Scotland. The data were
obtained for tar water and oil water samples
from old plant records, and the analytical and
sample-handling procedures were not reported.
Nevertheless, the constituents and the concen-
trations appear to be consistent with the other
reports.
Column 7 is derived from an M.S. thesis by
Spinola (1976)7 and contains data for a con-
densate sample from the Synthane gasification
of an Illinois No. 6 coal. The organic content
was analyzed by direct gas chromatography of
acidic and basic fractions and identification
was based on relative retention time data.
The data in column 8 for the Lurgi facility in
Sasolburg, South Africa is from the report by
Bromel and Fleeker (1976)2 discussed above in
connection with Tables 3-7.
The information in column 9 is from an
analysis by Jolley, Pitt, and Thompson (1977)8
of an aqueous stream from the product scrub-
ber of a bench-scale hydrocarbonization coal li-
quefaction operation. The samples were
analyzed by high pressure liquid chro-
matography, and the separated constituents
were identified by a multiple analytical pro-
cedure involving gas chromatography and
mass spectrometry.
Column 10 cites specific organics identified
in an aqueous sample from the product
separator (2nd stage liquor) of the COED coal li-
quefaction pilot plant (Shults, 1976).9 The
constituents were separated by high resolution
anion exchange chromatography, and a variety
of different analytical techniques were
employed for identification and quantification.
With reference to the material contained in
Table 9, it is important to note that the com-
ponents identified and the concentrations
reported are from grab samples of process
streams collected from the various facilities
and locations cited. The analyses are not com-
plete, and the fact that they are analyses of
grab samples from processes still under
development means that the concentrations
may not be truly representative of on-line, com-
mercial, steady-state gasification and liquefac-
tion operations. Additionally, the number and
type of organic compounds listed are limited, in
473
-------
part, by the analytical methodologies employed
for extracting, separating, and identifying the
constituents of the waste streams.
While it might have been predicted, a priori,
that the composition of wastewaters from coal
conversion facilities would vary depending
upon the specific process technology
(operating temperature and pressure, mode of
contact between coal and steam, process se-
quence, gas cleanup and separation
technology, etc.) and type of feed coal
employed, Table 9 suggests that the composi-
tion of coal gasification and liquefaction
wastewaters is relatively uniform, especially
with respect to the phenolic constituents. Less
information is available regarding the presence
of specific N-containing aromatics, other
polycyclic and heterocyclic compounds, and
polynuclear aromatic hydrocarbons. Table 10
lists some of the PAH's identified by Fruchter et
al., (1977)5 in the raw process wastewater
from the Solvent-Refined Coal facility in Ft.
Lewis, Washington, but the quantification and
widespread occurrence of these PAH's in coal
conversion wastewaters have not been
established.
In any case, the similarity in composition of
coal conversion wastewaters from different
developing technologies suggests that the en-
vironmental impact of such wastewaters from
TABLE 10
POLYNUCLEAR AROMATIC HYDROCARBONS IN SRC RAW
PROCESS WATER. (AFTER FRUCHTER ET AL. (1977).5}
PNA
METHYLINDANE
TETRALIN
DIMETHYLTETRALIN
NAPHTHALENE
2-NAPHTHALENE
DIMETHYLNAPHTHALENE
2-ISOPROPYLNAPHTHALENE
1-ISOPROPYLNAPHTHALENE
BIPHENYL
ACENAPHTHALENE
DIMETHYLBIPHENYL
DIBENZOFURAN
XANTHENE
DIBENZOTHIOPHENE
METHYLDIBENZOTHIOPHENE
DIMETHYLDIBENZOTHIOPHENE
THIOXANTHENE
FLUORENE
9-METHYLFLUORENE
1-METHYLFLUORENE
ANTHRACENE/PHENANTHRENE
METHYLPHENANTHRENE
C2-ANTHRACENE
FLUORANTHENE
DIHYDROPYRENE
PYRENE
CONCENTRATION
(mg/1)
15
<0.1
0.5
5
2
0.3-2
0.7
2
0.2
<0.1
0.2-0.5
0.6
0.1
1.5
<0.1
<0.05
0.1
0.3
0.3
0.2
1.1
0.2-0.3
<0.05
0.4
<0.05
0.6
IDENTIFIED BUT NOT
YET QUANTITATED
METHYLPYRENE
BENZOFLUORENE
C2-PYRENE
C2-FLUORANTHENE
TETRAHYDROCHRYSENE
CHRYSENE
METHYLBENZOFLUORENE
C3-PYRENE
C3-FLUORANTHENE
METHYLCHRYSENE
METHYLBENZANTHRACENE
CHOLANTHRENE
TETRAHYDROBENZOFLUORANTHENE
TETRAHYDROBENZOPYRENE
BENZOPYRENE
METHYLBENZOPYRENE
METHYLBENZOFLUORANTHENE
BENZOFLUORANTHENE
474
-------
different sources, and the treatability of these
wastewaters will be similar.
AQUATIC IMPACT OF ORGANIC
CONSTITUENTS OF COAL
CONVERSION WASTEWATERS
Although there is general agreement that
most coal conversion processes will produce
relatively contaminated wastewaters, little
data are available concerning the biological im-
pact such wastes will have upon receiving
waters. The lack of information reflects the fact
that coal conversion technology has only
recently emerged, and no commercial systems
have yet been constructed in the United States.
As such, efforts to assess the environmental
impact of coal conversion wastewaters are in a
predictive rather than descriptive stage. While
ultimate evaluation of the environmental im-
pact of these streams must await the construc-
tion and continuous operation of large scale
conversion systems, interim predictive efforts
are mandated by the number of highly toxic,
carcinogenic, and mutagenic compounds
known or anticipated to occur in coal conver-
sion wastes.
Currently, prediction of the impact that coal
conversion wastewaters will have on aquatic
environments can only be based on a knowl-
edge of the impact of effluents thought to be
similar in composition to such wastewaters, or
from an analysis of toxicity data on the con-
stituents of the wastes. Towards this latter
end, Table 11 shows threshold concentrations
of various phenolic constituents of coal conver-
sion wastewaters to selected lower aquatic
organisms. If these threshold concentrations
are compared to the wastewater concentra-
tions shown in Table 9, it is obvious that a
substantial level of wastewater treatment must
be accomplished before the discharge can be
considered acceptable from an aquatic impact
point of view.
Estimated permissible concentrations for a
number of hazardous pollutants were recently
calculated and compiled by Cleland and
Kingsbury (1977).11 Ambient level goals (see
Table 12) were calculated based upon
estimated permissible concentrations in order
to avoid detrimental health and ecological ef-
fects, and emission level goals (see Table 1 3)
were computed based upon treatment tech-
nology and the ambient level goals. Several
TABLE 11
THRESHOLD CONCENTRATIONS OF VARIOUS PHENOLICS TO
LOWER AQUATIC ORGANISMS (mg/l)
(AFTER MCKEE AND WOLF I1963).10}
DAPHNIA
MICROREGMA
COMPOUND (MICROCRUSTACEAN) (PROTOZOAN)
PHENOL
o-CRESOL
m-CRESOL
p-CRESOL
3, 4-XYLENOL
2, 4-XYLENOL
2, 5-XYLENOL
RESORCINOL
HYDROQUINONE
PYROCATECHOL
QUINONE
16.0
16.0
28.0
12
16
24.0
10.0
0.8
0.6
4.0
0.4
,0
.0
30.0
50.0
20.0
10.0
10.0
70.0
50.0
40.0
2.0
6.0
2.0
SCENEDESMUS
(ALGA)
40.0
40.0
40.0
6.0
40.0
40.0
40.0
60.0
4.0
6.0
6.0
E. COLI
(BACTERIUM)
>1000
600
600
>1000
500
>100
>100
>1000
50
90
50
475
-------
TABLE 12
AMBIENT LEVEL GOALS FOR KNOWN CONSTITUENTS OF COAL
CONVERSION WASTEWATERS. CONCENTRATION IN
(AFTER CLEVELAND AND KINGSBURY, (1977.11)
ZERO THRESHOLD
CURRENT OR PROPOSED TOXICITY BASED POLLUTANTS ESTIMATED
AMBIENT STANDARDS ESTIMATED PERMISSIBLE PERMISSIBLE CONCENTRA-
OR CRITERIA CONCENTRATION TION
COMPOUND BASED ON BASED ON BASED ON BASED ON
HEALTH ECOLOGICAL HEALTH ECOLOGICAL
EFFECTS EFFECTS EFFECTS EFFECTS
BASED ON HEALTH
EFFECTS
PHENOL
CRESOLS
XYLENOLS
ALKYL CRESOLS
CATECHOL
INDANOLS
PYRIDINE
METHYL PYRIDINES
QUINOLINE
METHYL QUINOLINE
ACRIDINE
INDOLE
CARBAZOLE
ANILINE
METHYL ANILINE
DIMETHYLANILINE
1
1
1
1
1
1
100
1-100
100
100
100
100
<5000
<500
207
316
14
492
800
400
80
69
303.
345
3.9
known constituents of coal conversion
wastewaters were included, as shown. The
number of categories for which no data exist il-
lustrates the limited amount of information
available concerning health and ecological ef-
fects of coal conversion wastewater constit-
uents. The few standards based upon
ecological effects are limited to the phenolics;
in all cases, these standards are derived from
concentrations that produce tainting of fish
flesh. The lack of information in Table 1 3 re-
garding best treatment technology reflects the
fact that treatment standards are currently
based on gross organic parameters such as
BOD, COD, and TOC, and generally not on in-
dividual constituents even if these constituents
are known or suspected aquatic toxicants or
carcinogens. Additionally, the treatment stand-
ards have generally been developed for stand-
ard industrial categories and, to date, no such
category has been established for coal conver-
sion wastewaters.
The report by Cleland and Kingsbury is not
complete, and is currently being expanded.
Nevertheless, comparisons between the con-
centrations listed in Tables 12 and 13, and
those reported in Table 9 again support the
need for a relatively substantial degree of
wastewater treatment in order to achieve an
environmentally acceptable discharge.
In addition to the specific organic con-
stituents of concern, as discussed above, it is
significant to note the high concentrations of
oxygen-demanding impurities (as implied by
the high COD) associated with these
wastewaters (see Tables 1 and 3). These
476
-------
TABLE 13
EMISSION LEVEL GOALS FOR KNOWN CONSTITUENTS OF COAL
CONVERSION WASTEWATERS. CONCENTRATIONS IN
(AFTER CLELAND AND KINGSBURY, (1977.11)
COMPOUND
PHENOL
CRESOLS
XYLENOLS
ALKYL CRESOLS
CATECHOL
INDANOLS
PYRIDINE
METHYL PYRIDINES
QUINOLINE
ISOQUINOLINE
METHYL QUINOLINE
ACRIDINE
INDOLE
CARBAZOLE
NAPHTHALENE
BASED ON BEST TECHNOLOGY BASED ON AMBIENT FACTORS
EXISTING DEVELOPING AMBIENT LEVEL GOAL
TECHNOLOGY TECHNOLOGY
BPT BAT
1-100
1
1-100
1-100
1-100
1-100
207
14-500
690-3800
oxygen-demanding impurities result in the
depletion of dissolved oxygen in the receiving
water, thereby making the water unsuitable for
many types of aquatic organisms, including
fish. From this standpoint alone, a significant
degree of wastewater treatment is required.
BIODEGRADABILITY OF ORGANIC
CONSTITUENTS OF COAL
CONVERSION WASTEWATERS
In considering various alternatives for the
treatment of coal conversion wastewaters, it is
likely that aerobic biological treatment proc-
esses, such as activated sludge systems or
aerated lagoons, will play a significant role in
the overall treatment scheme. In order to
assess the feasibility of using such biological
processes for treating coal conversion waste-
waters, it is first necessary to determine if the
constituents of the wastewaters are biological-
ly degradable and, if so, whether or not the
wastewater as a whole is biologically treatable,
given the actual concentrations of the constit-
uents. In conventional biodegradability studies,
very low concentrations (5-10 mg/l) of the test
compound are often used in order to avoid the
problem of toxicity. While the test compound
might prove to be biodegradable under these
circumstances, the compound might be toxic
to microorganisms at the concentration level at
which it is found in the wastewater of interest.
Of the many compounds that are listed in
Table 9 as constituents of coal conversion ef-
fluents, the microbial degradation of only one
class of these compounds, the phenolics, has
been extensively investigated. However,
review of this work provides information about
the microbial degradation of aromatic com-
pounds in general, since phenols are major in-
termediates in the degradation of aromatics.
Therefore, an understanding of the metabolism
of phenols is basic to the study of the degrada-
tion of other aromatic compounds. Additional-
477
-------
ly, phenolic compounds comprise the major
portion of the total organic carbon content of
coal conversion effluents.
It is important to note, however, that the ma-
jority of the work on microbial degradation of
these organic compounds and the identification
of metabolic pathways has been done with
pure cultures and single substrates, under
highly controlled laboratory conditions. The
microbial cultures employed were often main-
tained and manipulated solely for the purpose
of degrading a particular substrate. It is
therefore important to recognize that the
degradation of a compound under these condi-
tions does not imply that it will be readily
biodegradable in a natural or waste treatment
situation. Also, lack of degradation or pathway
information does not necessarily mean that the
compound is not biodegradable, as many com-
pounds identified in coal conversion
wastewaters have not been studied.
Many bacteria and fungi can utilize aromatic
hydrocarbons as a sole source of carbon and
energy. Specialized metabolic pathways con-
vert initial aromatic substrates to aliphatic
cellular intermediary metabolites. The initial
reaction in the bacterial oxidation of aromatic
hydrocarbons is believed to be the formation of
c/s-dihydrodiols (Gibson, 1 976).12 These com-
pounds then undergo further oxidation to yield
dihydric phenols which are substrates for ring
fission enzymes. This process has been
demonstrated for compounds ranging in size
from benzene to benzo(a)pyrene.
It is generally recognized that metabolism of
benzenoid compounds is dependent on the
presence of molecular oxygen. While molecular
oxygen acts as a terminal electron acceptor, it
is also a specific substrate for those enzymes
which catalyze the introduction of hydroxyl
groups and the fission of suitably hydroxylated
rings. Therefore, such pathways are strictly
aerobic.
In order for ring cleavage to occur, the
primary substrate must initially be converted to
either an ortho or para dihydric phenol. Two of
the most important of these compounds are
catechol and protocatechuic acid, both ortho
dihydric phenols. Figure 1 shows initial se-
quences for bacterial metabolism of various
substrates that converge on catechol, including
phenol. The initial metabolism of m- and
p-cresols along with other benzenoid com-
pounds may result in the formation of pro-
tocatechuic acid. Figure 2 illustrates the con-
vergence of some aromatic hydrocarbons on
this ring fission substrate.
The third important ring cleavage substrate is
gentisic acid. This is a /cwa-dihydric phenol
formed from such primary substrates as /3-
naphthol (see Figure 3).
The importance of the position of the two
hydroxyl groups on the ring should not be
overlooked. For example, in the metabolism of
resorcinol (a mefa-dihydric phenol), ring fission
does not occur until the compound is first
hydroxylated to form a 1, 2, 4-trihydric phenol
(Ribbons and Chapman, 1 968; Chapman and
Ribbons, 1976).13-14
The modification of a substituent group may
or may not occur before ring cleavage de-
pending on bacterial species, nature of the
primary substrate and position on the ring
relative to other substituents. In the case of the
methyl group, some species of bacteria hydrox-
ylate the nucleus of cresols leaving the methyl
group intact (Bayly et al., 1 966),15 while others
oxidize the methyl group initially to a carboxyl
group (Hopper and Chapman, 1971).16 In the
former case the fission substrate is then a
methyl-catechol, whereas in the latter case the
intermediate formed is either gentisic or pro-
tocatechuic acid. The dimethylphenols
(xylenols) act similarly. Depending on the posi-
tion of the methyl groups on the ring,
metabolism results in either protocatechuic
acid or a methylgentisic acid (Hopper and
Chapman, 1971; Chapman and Hopper,
1968).16-17
Alkyl side chains possessing two or more
carbons may also undergo modification. Car-
boxylic acids are formed by the oxidation of the
terminal methyl group. The larger carboxylic
alkyl chains may then undergo j3-oxidation, but
sometimes may remain intact on the ring
cleavage substrates. Generally, carboxyl
groups remain intact prior to ring cleavage, but
they may be eliminated as in the metabolism of
benzoic acid to catechol (Reiner and Hegeman,
1971).18
Once the primary substrate has been con-
verted to one of the ring fission substrates,
478
-------
PHENANTHRENE
ANTHRACENE
TOLUENE
NAPHTHALENE
TRYPTOPHAN
I
CHxCH-COOH
HCOOH +
FORMIC ACID
CH5
C«0 4
H
ACETALDEHYDE
SUCCINIC ACID
c«o
I
COOH
PYRUVIC
ACID
INTERMEDIARY .METABOLISM
I
4- HL0
Figure 1. Schematic diagram illustrating catechol as a primary ring fission substrate in the
microbial metabolism of various aromatic compounds.
479
-------
TOLUIC ACID
BENZOIC ACID
COOH
VANILLIC ACID
OH
p-HYDROXYMANDELIC
ACID
HOH-COOH
COOH
HCOOH +
FORMIC ACID
COOH
SUCCINIC ACID
INTERMEDIARY METABOLISM
CO,. 4
Figure 2. Schematic diagram illustrating protocatechuric acid as a primary ring fission substrate
in the microbial metabolism of various aromatic compounds.
480
-------
B-NAPHTHOL
ANTHRANILLIC ACID
COOH
•-HYDROXYBENZOIC
AGIO
SALICYLIC ACID
COOH
OH
COOH
MALIC ACID
INTERMEDIARY METABOLISM
I
Figure 3. Schematic diagram illustrating gentisic acid as a primary ring fission substrate
in the microbial metabolism of various aromatic compounds.
481
-------
cleavage can then occur. Bacteria employ two
different modes of enzymatic ring cleavage,
known respectively as ortho and meta fission.
Figures 1 and 2 show both types of fission for
catechol and protocatechuic acid. Ortho fission
is the splitting of the bond between the two
carbon atoms bearing hydroxyl groups. This
results in the formation of dicarboxylic acids.
The other pathway, meta fission, leads to
either an aldehydo-acid or keto-acid by
cleavage of a carbon-carbon bond where only
one carbon bears a hydroxyl group. Usually, a
particular microbial species employs only one
method of ring fission for a certain primary
substrate. The method of ring fission varies
with species, structure of the dihydric phenol,
and the substrate upon which the microbial
culture has been maintained. This last condi-
tion has been demonstrated by Hopper and
Taylor (1975)19 for the cresol isomers. When
bacteria were grown on p-cresol, p-cresol was
degraded by the orMo-fission pathway, but
when the same culture had been maintained on
m-cresol, p-cresol was degraded via meta-
fission.
Figure 3 shows the fission pathway for gen-
tisic acid. Fission occurs at the carbon-carbon
bond where one carbon bears a hydroxyl group
and the other carbon bears the carboxyl sub-
stituent.
The trihydric ring fission substrate 1, 2,
4-trihydroxybenzene, found in the degradation
of resorcinol, undergoes ort/?o-fission (Larway
and Evans, 1965)20 with the ultimate products
being acetic and formic acids. Other trihydric
phenols undergo mete-fission.
The ultimate ring fission products of most
phenolics undergo either fatty acid metabolism
or enter the tricarboxylic acid cycle of the
microorganisms.
As indicated above, these metabolic
pathway studies were carried out with pure
cultures of microorganisms under controlled
laboratory conditions. For the most part, these
studies were conducted in order to discover the
enzymes and mechanisms by which
microorganisms metabolize aromatic com-
pounds for energy and growth. While pure
culture work is important for a basic under-
standing of biodegradation, it is necessary in
relation to biological treatment of wastewaters
containing these compounds, to focus atten-
tion on mixed microbial communities, such as
soil, sewage, and activated sludge. Another
concern that is usually not considered in
metabolic pathway studies is the rate at which
the substrate is metabolized.
Much of the data that exist on the
biodegradability of phenolics in mixed cultures
in wastewaters is based on oxygen uptake
measurements. Early determinations of
biodegradability were done by means of the
standard biochemical oxygen demand (BOD)
test. A summary of this type of data for a large
number of pure organic compounds included
many phenols (Heukelekian and Rand,
1955).21 The majority of the studies were done
with unacclimated sewage as seed. Under
these conditions, the data revealed that phenol,
at concentrations below 500 mg/l, was readily
degraded. Ortho- and mefa-cresol were de-
graded at approximately the same rate as
phenol, as were a- and /3-naphthol. Para-cresol
and 3, 4-xylenol gave somewhat lower oxygen
demands and the BOD's of hydroquinone and
3, 5-xylenol were only one-half that of phenol
after five days.
Respirometric studies with acclimated ac-
tivated sludge demonstrate the behavior of
compounds of similar chemical structure, and
the ability of microorganisms adapted to a
given substrate to oxidize related compounds.
The data of McKinney, Tomlinson, and Wilcox
(1956)22 show that organisms acclimated to
phenol, o-cresol or m-cresol metabolized
phenol, the three cresol isomers, benzoic acid
and p-hydroxybenzoic acid to approximately
33 percent of their theoretical oxygen demand
(ThOD) in 12 hours. However, the phenol-
acclimated sludge oxidized catechol to only 1 3
percent of its ThOD, while the o-cresol and
m-cresol-acclimated sludges metabolized
catechol to the same extent as the other com-
pounds (33 percent of ThOD). In the phenol-
acclimated system, cresols were oxidized to
about the same extent as phenol. The 3, 4- and
2, 4- and 2, 6- and 3, 5-methyl substituted
phenols showed progressively less oxidation
than phenol, indicating the importance of
substituent position on the ring.
These results were later verified in a major
study of the decomposition of phenolic com-
482
-------
TABLE 14
OXIDATION AND REMOVAL OF VARIOUS PHENOLIC
COMPOUNDS BY PHENOL-ACCLIMATED BACTERIA.
{AFTER TABAK ET AL. (1964.23)
Test compound
Phenol
Phenol
Phenol
Catechol
Rgsorcinol ...
Quinol ....
Phloroglucinol . . .
flt-Chlorophenol
p-Chlorophenol
2 4-Dichlorophenol
2 6-DichloropLenol
2,4,6-Trichlorophenol. . .
o-Cresol
m-Cresol
p-Cresol
2 6"D5in€thylpn6nol
3 5-Diinethylphonol
2 4-I3iroethylphenol . .
3,4-Dimethylphenol
Orcinol
Thymol
6-Chloro-w-cresol
6-Chloro-2-methylphenol
4-Chloro-2-raethylphenol
4-Chloro-3-methylphenol
0.^1 itrophenol
jn-Nitrophenol
p-Nitrophenol
2 4-Dinitrophenol
2 6~Dinitrophenol
2,4,6-Trinitrophenol ....
4 6-Dinitro-o-cresol . . . •
2,4,6-TrinitroresorcinoI .
2,4,6-Trinitro-m-cresol. .
4-Chloro-2-nitrophenol . .
2-Chloro-4-mtrophenol . .
2,6-t>ichloro-4-nitro-
phenol
m-Dinitrobenzene
p-Dinitrobenzene
tn-Nitroaniline
2,4-Dinitroaniline
m-Nitrobenzaldehyde. . .
3,5-Dinitrobenzoic acid.
T«tt concn
Initial
ppm
100
80
60
100
100
100
60
100
100
60
100
100
100
100
100
100
100
100
100
100
100
80
80
SO
60
100
100
100
60
60
100
100
60
60
100
60
100
100
100
100
100
100
100
Lost
ppm
99
79
59
97
98
86
3
50
66
18
35
70
97
97
97
69
37
81
90
36
44
51 .
37
50
46
49
39
32
19
8
28
60
13
8
64
7
9
25
20
31
39
27
13
Amt of Ot
consumed'
(endogennu*
corrected)
Mttfari
319
252
186
255
252
149
12
66
. 80
46
39
5G
417
457
306
40
70
126
189
72
48
81
66
90
113
48
65
54
66
51
22
31
6
14
123
51
, 35
42
32
70
53
38
48
* Baaed on 180 min result*
483
-------
pounds by phenol-adapted bacteria (Tabak,
Chambers, and Kabler, 1964).23 In addition to
respiration measurements, chemical analysis
for residual substrate was also performed.
Some of the results of the study are presented
in Table 14 and Figures 4 and 5. The data in-
dicate that phenol itself is immediately and
rapidly degraded and that dihydric phenols are
oxidized to the same extent as phenol. The
presence of more than two hydroxyl groups on
the ring (e.g., phloroglucinol) increases
resistance to degradation. The addition of one
methyl group (cresols) appeared to stimulate
total oxygen uptake for ortho- and meta-
cresol. Total oxygen uptake for p-cresol was
the same as that for phenol although there was
a rapid initial uptake. Again, the effect of posi-
tion of substitution on the ring was illustrated
by the dimethylphenols. Nitro-, chloro-
substituted, and trihydric phenols were
relatively resistant to oxidation.
Summary of Biodegradability Review
As indicated in the above discussion, there is
a significant body of literature available concer-
ning the microbial degradation of phenols,
especially in pure cultures of microorganisms
and in single-substrate systems. This is
especially true for both mono- and dihydric-
phenols. Less information is available,
however, with regard to the biodegradability of
the more highly substituted phenols, or of the
other complex aromatic constituents of coal
conversion wastewaters, such as the mono-
and polycyclic nitrogen-containing aromatics,
the oxygen- and sulfur-containing
heterocyclics, and the polynuclear aromatic
hydrocarbons. Furthermore, little information is
IATMN OP UNKMNKTEO COMPOUNDS tOOffm
FlW
I I I I I I
CONCMTNATION OP ALL COMPOUNDS I00»pn
TIM! IM MINUTES
Figure 4. Oxidation of dihydric phenols.
(From Tabak etal (1964.23}
Figure 5. Oxidation of cresols and other
methylphenol derivatives. (From Takak
etal. (1964.23)
484
-------
available regarding the biodegradation of
specific phenolic compounds in complex mix-
tures such as those characteristic of coal con-
version waste waters. Additionally, considering
the needs from a wastewater treatment view-
point, there is also little information available
regarding the rate at which these compounds
are microbially degraded in mixed cultures, and
the concentrations at which these compounds
become inhibitory to microbial degradation.
CONCLUSIONS
An attempt has been made to determine the
chemical characteristics of byproduct
wastewaters from coal gasification and coal li-
quefaction processes. Approximately 60-80
percent of the total organic carbon appears to
be phenolic in nature, consisting of
monohydric, dihydric, and polyphenols. The re-
mainder of the organic material consists of
mono- and polycyclic nitrogen-containing
aromatics, oxygen- and sulfur-containing
heterocyclics, polynuclear aromatic hydrocar-
bons, and simple aliphatic acids. The composi-
tion of the wastewaters appear to be relatively
uniform, especially with respect to the phenolic
constituents, regardless of the specific process
technology and type of feed coal employed. At
the concentrations reported, the discharge of
these wastewaters would have an adverse im-
pact on aquatic life and, as a result, a signifi-
cant degree of wastewater treatment is
necessary. While aerobic biological processes
appear to be among the methods of choice for
treating these wastewaters, the following
types of information are required in order to
assess the biological treatability of these coal
conversion wastewaters and to develop
suitable design and operating guidelines: (a) an
assessment of the biodegradability of the con-
stituent compounds, as reviewed above; (b)
biokinetic information describing the rate at
which degradation of the constituents takes
place; (c) the concentration levels at which
microbial degradation of the constituents is in-
hibited; and (d) how the constituents will
behave in a composite mixture representative
of coal conversion wastewaters. In view of the
paucity of information available regarding the
microbial degradation of many of the constit-
uents identified in coal conversion
wastewaters, an experimental program to pro-
vide such information is underway.
REFERENCES
1. A. J. Forney, W. P. Haynes, S. J. Gasior,
G. E. Johnson, and J. P. Strakey. 1974.
Analysis of Tars, Chars, Gases, and Water
in Effluents from the Synthane Process.
U.S. Bureau of Mines Technical Progress
Report 76, Pittsburgh Energy Research
Center, Pittsburgh, Pennsylvania.
2. M. C. Bromel, and J. R. Fleeker. 1976.
Biotreating and Chemistry of Waste
Waters from the South African Coal, Oil,
and Gas Corporation (Sasol) Coal
Gasification Plant. Department of
Bacteriology, North Dakota State Univer-
sity, Fargo, North Dakota.
3. C. E. Schmidt, A. G. Sharkey, and R. A.
Friedel. 1974. Mass Spectrometric
Analysis of Product Water from Coal
Gasification. U.S. Bureau of Mines
Technical Progress Report 86, Pittsburgh
Energy Research Center, Pittsburgh,
Pennsylvania.
4. C. H. Ho, B. R. Clark, and M. R. Guerin.
1976. Direct Analysis of Organic Com-
pounds in Aqueous Byproducts from
Fossil Fuel Conversion Processes: Oil
Shale Retorting, Synthane Coal Gasifica-
tion and COED Liquefaction. J. Environ.
Sci. Health, All(7), 481-489.
5. J. S. Fruchter, J. C. Laul, M. R. Peterson,
and P. W. Ryan. 1977. High Precision
Trace Element and Organic Constituent
Analysis of Oil Shale and Solvent Refined
Coal Materials. Symposium on Analytical
Chemistry of Tar Sands and Oil Shale,
Division of Petroleum Chemistry.
American Chemical Society, New
Orleans, Louisiana.
6. T. K. Janes, and W. J. Rhodes, Industrial
Environmental Research Laboratory, En-
vironmental Protection Agency, personal
communication.
7. A. A. Spinola, 1976. Ozonation of Pro-
cess Wastewaters from the Production of
Synthetic Natural Gas Via Coal Gasifica-
tion. M.S. Report, Department of Civil
485
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Engineering, University of Pittsburgh,
Pennsylvania.
8. R. L. Jolley, W. W. Pitt, and J. E. Thomp-
son. 1977. Organics in Aqueous Process 16.
Streams of a Coal Conversion Bench-
Scale Unit Using the Hydrocarbonization
Process: HPLC and GC/MS Analysis. En-
vironmental Technology Annual Technical
Meeting of the Institute of Environmental 1 7.
Sciences, Los Angeles, California.
9. W. D. Shults. 1976. Preliminary Results:
Chemical and Biological Examination of 18.
Coal Derived Materials. ORNL/NSF/EATC-
18, Oak Ridge National Laboratory, Oak
Ridge, Tennessee.
10. J. E. McKee, and H. W. Wolf. 1963.
Water Quality Criteria. 2nd Ed. California
State Water Quality Control Board. 19.
Sacramento, California. Publ. No. 3-A.
11. J. G. Cleland, and G. L. Kingsbury. 1977.
Multimedia Environmental Goals for En-
vironmental Assessment. Draft report. 20.
Submitted to U.S. EPA, Industrial En-
vironmental Research Laboratory,
Research Triangle Park, North Carolina. 21.
1 2. D. T. Gibson. 1976. Initial reactions in the
bacterial degradation of aromatic
hydrocarbons. Zentralbl. Bakteriol. (Orig.
6.1162:157-168. 22.
13. D. W. Ribbons, and P. J. Chapman. 1 968.
Bacterial metabolism of orcinol. Biochem,
J. 106:44P.
14. P. J. Chapman, and D.W. Ribbons. 1976. 23.
Metabolism of resorcinylic compounds by
bacteria: Orcinol pathway in
Pseudomonas putida. J. Bact.
125(3):975-984.
1 5. R. C. Bayly, S. Dagley, and D. T. Gibson.
1966. The metabolism of cresols by
species of Pseudomonas. Biochem. J.
101:293-301.
D. J. Hopper, and P. J. Chapman. 1971.
Gentisic acid and its 3- and
4-methylsubstituted homologues as in-
termediates in bacterial degradation of
m-cresol, xylenol. Biochem. J. 122:1-6.
P. J. Chapman, and D. J. Hopper. 1968.
The bacterial metabolism of xylenol.
Biochem. J. 110:491-498.
A. M. Reiner, and G. D. Hegeman. 1971.
Metabolism of benzoic acid by bacteria.
Accumulation of cyclohexadiene - diol
-carboxylic acid by a mutant strain of
Alcaligenes eutrophus. Biochemistry.
10:2530-2536.
D. J. Hopper, and D. G. Taylor. 1975.
Pathways for the degradation of m-cresol
and p-cresol by Pseudomonas putida. J.
Bact. 122:1-6.
P. Larway, and W. C. Evans. 1965.
Metabolism of quinol and resorcinol by a
soil Pseudomonas. Biochem. J. 95:52P.
H. Heukelekian, H. and M. C. Rand. 1955.
Biochemical oxygen demand of pure
organic compounds. Sewage and In-
dustrial Wastes. 27(9): 1040-10 53.
R. E. McKinney, H. D. Tomlinson, and R.
L. Wilcox. 1956. Metabolism of aromatic
compounds by activated sludge. Sewage
and Industrial Wastes. 28:547-557.
H. H. Tabak, C. W. Chambers, and P. W.
Kabler. 1964. Microbial metabolism of
aromatic compounds. I. Decomposition of
phenolic compounds and aromatic
hydrocarbons by phenol-adapted
bacteria. J. Bact.. 87:910-919.
486
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BIOLOGICAL TREATMENT OF
COAL CONVERSION
CONDENSATES
Irvine W..Weit and D. J. Goldstein
Water Purification Associates
238 Main Street
Cambridge, Massachusetts 02142
Abstract
Biochemical oxidation is an important way to
remove organic contamination from foul con-
densates in coal conversion plants. The design
considerations are discussed; oxygen is recom-
mended in preference to air, and a test with
mutated bacteria is recommended. Reactor
configurations are also discussed. When the
organic contamination is high, the use of oxy-
gen requires forced cooling and a combined
cooling tower/trickling filter is suggested for
the test. Preliminary plant designs are given for
two situations in a Hygas plant: one when
lignite is fed and one when a bituminous coal is
fed.
Waters that condense and are removed from
a coal conversion plant will often be highly con-
taminated with organic matter. The level of
contamination depends on the process and on
the coal. Condensate from Solvent Refined
Coal, Synthoil, or H-Coal can be expected to be
very dirty. From gas plants the contamination
seems to be higher from a lower temperature
and a shorter residence time. Thus Lurgi and
probably Synthane will give quite dirty water,
Hygas will give less dirty water, and Bigas the
least dirty. The coal rank is very important.
Condensate from a Hygas plant fed lignite is
many times more contaminated than conden-
sate from the same plant fed a bituminous coal.
Dirty Condensate will have to be treated for
reuse. Reuse possibilities include makeup to a
wet flue gas desulfurization system, use for
dust control, and makeup to a cooling tower.
The first in line of the commonly assumed
treatments is solvent extraction. If the extrac-
* Irvine W. Wei is also Assistant Professor of Civil Engineer-
ing, Northeastern University, Boston, Massachusetts
02115.
table concentration is high enough that its
value as a fuel or as crude phenol can partially
offset cost, then solvent extraction, or a treat-
ment accomplishing the same result, should be
used. For lower levels of contamination solvent
extraction will probably not be economically
justifiable. Most condensates will next have to
be treated to remove ammonia and many will
require removal of hydrogen sulfide. After am-
monia separation the next treatment in series
will often be biological oxidation. The con-
tamination in many waters seems to be
biodegradable. Phenol, a common, high level
contaminant, is biodegradable.
It is the purpose of this paper to put forward
preliminary designs for biological oxidation
plants for these waters. Biological oxidation
and solvent extraction are both treatments to
accomplish the same objective, to remove
organic contamination. They are not mutually
exclusive. If solvent extraction is not economic
and is not used, biological treatment will usual-
ly be required. But if solvent extraction is used
its cost is quite dependent on the level of con-
tamination acceptable in its effluent and it may
pay to follow solvent extraction with biological
oxidation. When treated condensate is to be
used as makeup to a cooling tower, biological
treatment has some disadvantages.
Phosphorus will have to be added and will not
be all used up in the treatment. Dissolved C02
and suspended solids are increased by
biological treatment. Possibly residual am-
monia, which is necessary as a nutrient in
biological treatment, will be higher than need
be left after ammonia stripping. We are not, at
the moment, able to say whether biological
treatment should be reserved for situations
where solvent extraction is not used, or
whether biological treatment will be useful
subsequent to solvent extraction.
DESIGN CONSIDERATIONS
Major design considerations for biochemical
oxidation include:
A. Reactants
a . Phenols and other organics
b . Other required nutrients
c . Oxidants
B. Biological Agents
C. Reactor Configurations
487
-------
A. fieactants
During biological treatment the organic con-
stituents of wastewaters, such as phenols, are
oxidized and utilized as the sources of carbon
and/or energy while the reaction is mediated by
biological agents. Phenol is usually considered
biodegradable. However, if the phenol concen-
tration exceeds a certain threshold level,
phenol itself can inhibit the bio-oxidation. This
threshold concentration of phenol has been
reported to be 500 mg/l1 and 1,000 mg/l;2
these concentrations are unlikely to be exceed-
ed in the completely mixed bioreactor of an ac-
tivated sludge system. Should the phenol con-
centration become inhibitory, a proper scheme
of dilution may be needed. Dilution can be
achieved by internal recirculation of treated
water or by adding an external dilutant.
Other organics, particularly those refractory
in nature, may significantly affect the perfor-
mance of biological treatment and consequent-
ly the dilution requirement. Although this
category of organics may be measured by the
difference between COD and BOD, its effect on
bio-oxidation appears to be poorly understood
and requires pilot testing with the specific
waste water to be treated.
To satisfy nutritional requirements of the
biological agents responsible for bio-oxidation,
certain inorganic macro and micro nutrients
may have to be provided. Macro nutrients such
as nitrogen and phosphorus are required in pro-
portion to phenol content. A typical weight
ratio as used at Bethlehem Coke Plant3 is
phenol:N:P = 70:5:1. Excess N is available in
the condensates, so the ammonia concentra-
tion will be reduced to the required nutritional
level by proper ammonia recovery prior to
biological treatment. Phosphorus will have to
be supplied by adding phosphoric acid or
equivalent. Various trace nutrients such as
manganese, copper, zinc, and other metals
might not be available in the wastewater but
are required by biological agents.4
For the ultimate oxidant for bio-oxidation,
molecular oxygen is the most common choice,
whether it comes from compressed air .or high-
purity oxygen gas. The use of high purity oxy-
gen rather than air has gained increasing ac-
ceptance in aerobic biological treatment. In ad-
dition to certain advantages in treatment per-
formance,5 it has been reported that the use of
high purity oxygen appears to be more energy-
effective in the transfer of oxygen.6 The total
energy required to separate oxygen from air,
and then dissolve the oxygen in water, is less
than the energy required to dissolve directly in
water the same amount of oxygen from air.6
Othmer6 reported that normal aeration under 1
atmosphere required about 0.5 kW-hr of
energy to dissolve 1 pound of oxygen from air,
whereas this requirement dropped to less than
0.05 kW-hr to dissolve 1 pound of commercial
oxygen. For the high purity oxygen activated
sludge plant designs given later, the energy for
dissolution is 0.09 kW-hr/lb 02. For oxygen
production the energy is about 0.165 kW-hr/lb
02,11 totaling about 0.26 kW-hr/lb 02. Further-
more, since oxygen is required and produced in
many coal conversion plants, it can be made
available for biological treatment at the
cheapest possible price. Approximately 3,000
tons per day of oxygen will be needed in a
standard size SNG plant, and the amount of
oxygen required for the high purity oxygen
activated sludge (HPOAS) system may be
about 10 percent or less of that required for
coal conversion, depending on the amount of
BOD to be removed in the biological treatment.
B. Biological Agents
The use of specially prepared bacteria for
more effective biological treatment of certain
industrial wastes has been recently publicized.7
These bacteria are prepared from the parent
strain through induced mutation, which may in-
volve exposing the parent strain to programm-
ed radiation, and subsequently through proper
enrichment allowing for the buildup of a large
population of mutant bacteria. The mutant
baceria so produced are far more efficent in
degrading certain pollutants than the parent
strains occurring in nature or the mixed culture
commonly used in activated sludge process.
For instance, the mutated Pseudomonas sp.,
commercially marketed as PHENOBAC, could
increase the rate of degradation by about
twofold. When parent strains and mutant
strains were exposed to 500 mg/l of phenol in a
laboratory test, the time for 100 percent
degradation (as measured by ring disruption)
was 25 hours and 8 hours respectively.8
488
-------
In another laboratory study simulating the
treatment of aqueous effluents (using a syn-
thetic solution of phenol with other additives)
from coal conversion processes,2 the ac-
climated activated sludge from the Bethlehem
Coke Plant and PHENOBAC were used as the
biological agents. In terms of phenol degrada-
tion, the efficiency of the mutated bacteria was
noted to be about two times that of the ac-
climated sludge.9 It was also found convenient
to handle the predried and packaged mutant
bacteria which could be reactivated by immer-
sion in 100° F water for about an hour.2'7 The
cost of PHENOBAC, which comes in
25-100-lb. packages, is about $ 16 per pound.
In addition to the laboratory tests reported
above, mutant bacteria have also been found
useful in certain full-scale High Purity Oxygen
Activated Sludge (HPOAS) facilities. In the
treatment of a number of petrochemical and
refinery wastewaters, the performance of
PHENOBAC was compared in parallel with that
of ordinary activated sludge, and PHENOBAC
was found to achieve:10
1. better process stability;
2. enhanced removal of TOC; and
3. reduction of foaming in bioreactors and
liquid-solids separators.
In view of the above information available
from various independent sources, the use of
mutant bacteria warrants serious consideration
in the future pilot facilities treating coal conver-
sion wastes. A side-by-side comparison on the
performance of mutant bacteria, acclimated
sludge, and ordinary activated sludge would be
highly desirable.
C. Reactor Configurations
The most common configurations of bioreac-
tors include: trickling filters, where fixed
biological growth is maintained, and activated
sludge systems, where suspended growth is
utilized. In general, trickling filters have been
used for their simplicity and low cost of opera-
tion, resilience to shock loads and toxic
substances, while activated sludge has been
known for its high treatment efficiency, better
control and reliability.
It is not a new idea to combine the desirable
attributes of trickling filter and activated sludge
processes into the most cost-effective system
by use of dual biological processes (using a
combination of trickling filter and activated
sludge) for industrial wastewater treatment.12
Success in the treatment of wastewaters form
organic chemical manufacturing, petrochem-
ical refining, and meat processing industries
has been reported.12'13 In most of the reported
cases, the water contaminants of primary con-
cern have been phenols and BOD.
Since the use of HPOAS (high purity oxygen
activated sludge) appears to have significant
advantages at coal conversion plants, it is
essential to consider the control of water
temperature in the covered bioreactors. Oxida-
tion of hydrocarbons are exothermic reactions.
The oxidation of C, CH, and CH2 can
theoretically lead to 1 ° F temperature rise per
184, 170, and 161 mg/l BOD removed,
assuming 100 percent biodegradability. For
phenol, this temperature rise will be about 1 ° F
per 165 mg/l BOD removed. Therefore, con-
sidering the various heat losses in the bioreac-
tors, it may be reasonably assumed that the
removal of 200 mg/l BOD will cause an in-
crease in water temperature of 1 ° F.
Biological agents are known to be
temperature sensitive. It has been recom-
mended14 that the water temperature in the
aerobic biological treatment of coke plant
wastes be 95-100° F throughout the year.
Consequently, when a high level of BOD
removal is to be achieved by HPOAS, the
temperature rise may become excessive and a
means of cooling may become necessary,
To take the advantages of dual biological
treatment processes and to satisfy the cooling
requirement, we suggest merging a trickling
filter with a cooling tower as an integral unit
when HPOAS is used. In the treatment of refin-
ing wastes it has for more than two decades
been found economical and desirable to
achieve bio-oxidation and water cooling in a
cooling tower structure.16 Functionally, the
cooling tower in this case is analogous to the
trickling filter in terms of organic removal.
Whether this unit should be designed as a
trickling filter or a cooling tower depends on
which function will be limiting.
489
-------
EXEMPLARY WASTEWATER
CHARACTERISTICS
Two examples will be used in the following
design studies, based on Hygas plants using a
lignite and a bituminous coal feed. Details are
given on Table 1.
ALTERNATIVE PROCESS TRAINS
7. Air Activated Sludge
The air activated sludge (AAS) system is
probably the most common treatment system
used for wastewaters with constituents similar
to coal conversion wastewaters, e.g., coke
plant wastes. An extensive literature review on
the biological oxidation of coke plant wastes
was reported by Barker and Thompson18 in
1973. Among the treatment systems dis-
cussed, AAS is the predominant treatment
system of success. Laboratory studies27
abroad have also indicated that AAS systems
can satisfactorily treat the coal conversion
wastes with the following characteristics:
Total ammonia ~ 1,500ppm
Total phenols - 300 ppm
Thiocyanate ~ 1 50 ppm
Chloride - 2,500 ppm
Among the full-scale AAS facilities treating
coke plant wastes, the one at Bethlehem Coke
Plant, Bethlehem, Pennsylvania, has been in
operation since 1962, and seems to have the
most complete data available in the literature.3
Since there has been no pilot tests for the treat-
ment of coal conversion wastes by AAS in the
United States, we begin by basing a preliminary
design on the data available from the
Bethlehem AAS system and essentially scale
up from this existing treatment facility.
The scaled design is based on the assump-
tion that the biodegradability of coal conver-
sion wastewaters is identical with that of the
coke wastewater. This assumption is open to
question. No data on COD of the coke
wastewater is available in Reference 3.
However, an analysis of an average coke plant
waste indicated that the theoretical oxygen de-
mand due to phenols, which are readily
biodegradable, constitute about 68 percent of
the measured COD while for coal conversion
TABLE 1
WATER ANALYSES AND FLOWS FROM TWO HYGAS PLANTS
BODs (mg/1)
COD (mg/1)
Phenol as C$H5OH (mg/1)
NH3 as N (mg/1)
Plow, 103 Ib/hr
106 gals/day
m3/sec
Lignite feed
13,000 - 18,000
25,000 - 30,000
3,000 - 5,000
- 290
295
0.85
0.037
Bituminous
_coal feed
2,000 - 3,'QOO
~ 3,000
300 - 500
~ 30
535
1.5
0.066
Analysis from References 5 and 16. Ammonia is reduced to
the listed .level by prior treatment. Flow for the lignite
feed from Reference 5 and for the bituminous feed from Ref-
erence 17.
490
-------
wastewater phenol averaged about 40 percent
of the COD.19 Although the question of
biodegradability can only be fully answered by
pilot testing, the above comparison indicates
certain differences in chemical composition
between coke plant and coal conversion
wastewaters. It is essentially unknown at this
point whether arrd how this will affect the
design of biological treatment. Should the
assumption of biodegradability become invalid
to any extent, there would be corresponding
limitation on the usefulness of the preliminary
design.
One of the most important design considera-
tions regarding biological treatment of coke
plant wastes is to determine if the waste con-
tains any inhibitory constituents which may
render the biological treatment system totally
or partially unfunctional. If these constituents
exist, it is essential to determine their threshold
concentrations and thus the dilution required
for the influent to the biological treatment
system. Some inhibitory constituents and their
threshold concentrations found in our literature
search include:
Phenol = 5001 - 1,0002 mg/l
Ammonia = 1,20018 - 2,0003 mg/l
Chloride = 2,00018mg/l
Phenol will normally be kept at a low enough
level in the mixed reactor. Ammonia will have
to be reduced by prior treatment. Chloride will
not usually reach toxic level.
The following rules were used to produce the
scaled design. Most numerical values came
directly from the Bethlehem AAS experience3
while the four biokinetic coefficients, k, Ks, Y,
and kd were evaluated by us on the basis of
data from Reference 3.
Nutrients such as nitrogen and phosphorus
are essential for biological treatment. The re-
quired weight ratio is assumed to be invariant
and is phenol:N:P = 70:5:1. Excess N is
available in the wastewater, and the ammonia
nitrogen concentration will be reduced to the
proper level by ammonia recovery prior to
biological treatment. Phosphorus will have to
be supplied by adding phosphoric acid or
equivalent.
The design of bioreactors was based on a
biokinetic model developed by Lawrence and
McCarty.20 This model is based on an empirical-
ly developed relationship between the rate of
growth of microorganisms and the rate of con-
sumption of degradable contaminants.
Degradable contaminants are called
"substrate" as they are "food" for the
microorganisms. The relationship is
dX _
dt
= Y
dS
dt
(11
where
X = concentration of microorganisms
t =time
Y =growth yield coefficient; weight of
microorganisms produced per weight of
substrate removed
S = concentration of substrate or degradable
contaminant
kd = microorganism decay coefficient, time"1.
If Eq. (1) is divided by X we obtain
I dX = Y^^S _ k
X dt X dt d
(2)
In Eq. (2) each term has the dimension
(time M and compatible units must be used. The
left hand side of Eq. (2), which is the rate of in-
crease of concentration of microorganisms per
unit concentration, may also be written 1/9C,
where 0C is called the mean cell residence time
or sludge age. The first term on the right hand
side of Eq. (2) includes the quantity 3- —which
X dt
is the rate of decrease of concentration of
substrate per unit concentration of micro-
organisms. This quantity is a function of the
concentration of substrate and the Lawrence
and McCarty model assumes the function
1 dS = kss
X dT i
-------
p _ XV
rx~ «—
px
w= —
(7)
(8)
The meaning of all symbols used is shown in
the schematic flow diagram in Figure 1. The
four basic coefficients were evaluated from in-
formation given in Reference 3. In this
reference are tabulated experimental values of
(Ib phenol removed)/(lb microorganismsMday),
which is — —, as a function of the phenol con-
centration, S. These values are plotted in Figure
2 and'the curve so obtained is fitted to Eq. (3)
by noting that k is the value of — —when S is
X dt
large and Ks is the value of S when ^ —= k/2.
X Ol
Also from Reference 3 the — — can be
x dt
calculated. On Figure 3 is plotted- —against
X dt
— — 'rom which the coefficients Y and kd are
/\ Qt
determined.
The values of the coefficients determined in
this way are:
k =0.9 Ib C6H5OH/lb MLSS-day = 2.14 Ib
BOD/lbMLSS«day
Ks =0.17 mg/l C6H5OH = 0.4 mg/l BOD
Y =0.4 Ib sludge/lb C6H5OH processed =
0.1 7 Ib sludge/lb BOD processed
kd =0.1 7 (day)'1
These coefficients were evaluated in terms
of phenol removal and then converted to BOD
based on the theoretical oxygen demand of
2.38 units per unit of phenol.
The aerator power requirement is taken to be
proportional to the BOD or phenol removed. At
Bethlehem Coke Plant the power requirement is
based on 1 8.2 Ib phenol removed/(day)(hp) or
43.3 Ib BOD/(day)(hp), which compares close-
ly with typical values in the literature of 45-50
Ib BOD removed/(day)(hp).21
The best way to size the clarifier is to deter-
mine experimentally the relationship between
initial settling velocity and suspended solids
concentration.22'23 This typically takes the form
shown in Figure 4.24 The aeration vessel
volume and solids separator volume can then
be determined for series of concentrations of
microorganisms, X, and the optimum concen-
tration of microorganisms determined. We
have no data to plot Figure 4 and have,
therefore, used the one available point from
Reference 3, namely X = 2,600 mg/l and the
clarifier overflow rate is 685 gal/(day)(ft2). For
use in Eq. (6) we also assumed the same value
of Xr/X = 3.44. The value of Xr/X is a function
of the performance of the solids separator.
Subsequent treatment of waste sludge
depends on the means of ultimate disposal and
the method of transport to the disposal site.
Sludge is beneficial when added to coal ash and
this seems to be an attractive means of
ultimate disposal as the nutrient content of
waste sludge will be conducive to the revegeta-
tion process. The sludge may be transported by
tank truck or pipeline, and the final selection is
dictated by the economics of these operations.
The method of transport will in turn determine
whether any sludge treatment is desirable. The
objective of sludge treatment in our designs is
primarily volume reduction. For assumed
transportation by tank truck, dissolved air flota-
tion (DAF) thickening followed by vacuum
filtration is included. These sludge treatment
processes are sized according to the following
criteria: 20 Ibs dry solids per square foot per
day for the DAF thickener, and 120 Ibs dry
solids per square foot per day for vacuum
filters. These values are assumed,25 not scaled,
because Bethlehem Coke Plant discharges its
sludge to a sewage plant and provides no
sludge treatment.
The results of the calculations for the two ex-
emplary waste waters described on Table 1 are
given on Table 2. For each water calculations
are presented for a two-stage process with 95
percent removal in each stage and an
equivalent single stage process with 99.75
percent removal. The volumes are insignificant-
ly different, showing that the reaction is zero
order in the range of concentrations of BOD of
interest. Complete calculations are, therefore,
presented for 95 percent and 99.75 percent
removal, in single stages, for each water. The
results for the lignite at 99.75 percent removal
are also shown in Figure 5.
Some preliminary comments can be made.
The clarifier diameters are small and with very
little increased investment larger diameters can
be used and the somewhat high overflow rate
492
-------
Q, S0
v,X,Si
(Q + q)
X,
Xr, Si
(Q - w)
V
Q = flow rate of liquid waste to be treated biologically,
volume/time;
q = flow rate of recycled sludge, volume/time;
w = flow rate of wasted sludge, volume/time;
So = influent substrate concentration, mass/volume;
Si = effluent substrate concentration, mass/volume;
X = microbial mass concentration, mass/volume;
X = microbial mass concentration in the clarified overflow from
6 the solids separator, mass/volume;
X = microbial mass concentration in the underflow from the solids
r separator, mass/volume;
P = power requirement for aeration, energy/time;
P = excess microorganisms production rate, mass/time.
Figure 1. Air activated sludge model.
493
-------
assumed can be reduced. The hydraulic
residence times listed are not unreasonable.
The quantity called F/M on Table 2 is - —in
X dt
Eq. (2) and is calculated from the equation
F/M =
-------
this exceeds 200 mg/(l)(hr). Suppose, first,
that surface aerators are used and that the
aeration basins are made 15 ft deep. The
horsepower for the aerators is found to be ap-
plied at a rate of about 1 20 hp/103ft2. If power
were to be applied at this rate the energy to
transfer each pound of oxygen would probably
increase unacceptably. Potential remedial
measures include: (1) use of shallower basins,
such as a basin depth of 9 feet instead of 1 5
feet, this will lead to an energy application of
less than 75 hp/103ft2; (2) use of oxygenation
systems which are more efficient than surface
aerators, such as submerged aerators or using
high purity oxygen rather than ordinary air as
the source of oxygen.
2. High Purity Oxygen Activated
Sludge (HPOAS)
As discussed previously HPOAS has the ad-
vantages of energy effectiveness and the ready
availability of high purity oxygen at most coal
conversion facilities. The following preliminary
HPOAS design for lignite feed is based on the
information supplied by Union Carbide Corpora-
tion.
No kinetic coefficients were used in the
de.sign of HPOAS. Instead, an empirical ap-
proach using F/M ratios and MLVSS data based
on past experience with similar industrial
wastewaters was followed. It is felt that in the
treatment of high stength industrial
wastewaters the process design may frequent-
0.2 i—
0.1 —
- —
X dt
0.1 —
0.2 *—
z- k, - 0.17 day
Ib sludge
Ib phenol processed
Figure 3. Sludge growth rate vs. substrate utilization rate (based on date from Ref. 3).
495
-------
J5
4J
•H
U
O
-H
rH
4J
4-1
(U
(0
•H
•P
•H
C
H
100
10
0.1
v. - ax.
-n
0.001
0.01
0.1
x., Initial Solids Concentration, Ib/lb
Figure 4. Typical settling velocity vs. solids concentration.
496
-------
TABLE 2
CALCULATIONS ON AIR ACTIVATED SLUDGE PLANTS
Lignite Feed
Bituminous Coal Feed
S0 . mg/1
Q, 106 gal/day
B! , mg/1
6 , days
XV, 109 (mg)(gal)/l
V, 106 gals
Total V, 106 gals
r
q, 10e gal/day
PX, 10 3 Ib/day
w, 106 gal/day
P, hp
D, hw
Clarifier area, ft2
Clarifier dia. , ft
DAF thickener, ft2
Vacuum filter, ft2
Residence Time, days
r lb BOD
First Second
95% 95%
18,000 900
0.85 0.85
900 45
5.16 5.25
6.80 0.34
2.61 0.13
2.75
0.17
0.14
11.0
0.15
2800
2080
1240
40
550
96
3.1
- 2.1
99.75%
18,000
0.85
45
5.25
7.20
2.77
0.16
0.13
12.6
0.17
2940
2190
1240
40
630
110
3.3
2.1
First Second
95% 95%
3,000 150
1.5 1.5
150 7.5
5.19 5.70
2.00 0.11
0.77 0.04
0.81
0.37
0.55
3.2
0.043
820
610
2190
53
160
28
0.51
2.1
99.75%
3,000
1.5
7,5
5.70
2.21
0.85
0.37
0.55
3.2
0.043
860
640
2190
53
160
28
0.54
2,0
497
-------
2I92KW
AIR
NUTRIENTS
COOLED EFFLUENT 0.85 xlO*8oli. /day ^
^M AMMONIA 290*9* NHfN*
EQUALIZATION
£.3xl04ooli.
T _ AERATION ^/n««,
i
, - wr.ifl-^1,. -: |240
s
CATION
fr2
_X
r
RETURN SLUDGE
. EFFLUENT
•>" FROM BIOLOGICAL
TREATMENT
0.17x10 gall./day
CD
00
SLUDGE ^ .
DISPOSAL ^
6.31 tonv/day
@20%iolid
VACUUM
FILTRATION
110ft4
^ f DAF
^ I THICKENING
\ 630ft2
V ^
Figure 5. Air activated sludge system (AAS) for Hygas plant with lignite feed (from Table 2).
-------
ly be dictated by considerations other than
biokinetics, such as oxygen transfer and/or
solids separation. However, if biokinetic data
can be obtained and compiled properly by using
an appropriate reaction model, we should be
able to expand our data base and make rational
designs easier in the future.
The HPOAS system design consists of
multitrains in parallel, with each train con-
sisting of multistages to obtain a quasi-plug
flow condition. High purity oxygen is fed to the
space above the liquor level in each stage of the
oxygenation basin, and oxygen transfer is ac-
complished by use of surface aerators or
equivalent. The dissolved oxygen concentra-
tion in the mixed liquor will be maintained at
about 5 mg/l rather than 2 to 3 mg/l as com-
monly used in the AAS system. As with the
AAS system, two steps of HPOAS treatment
are used with each step achieving about 95
percent removal of BOD.
Two key parameters for the design of ac-
tivated sludge systems are mean F/M (food to
microorganism) ratio and MLVSS (mrxed liquor
volatile suspended solids). The F/M ratios for
step 1 and step 2 differ because of the dif-
ference in BOD loading; F/M is 0.8 in step 1
and 0.3 in step 2. The MLVSS will be substan-
tially larger than that for the AAS system
because of improved settling velocities of the
oxygen sludge, and the MLVSS in this case is
assumed to be 7,300 mg/l in step 1 and 4,500
mg/l in step 2. The clarifiers are designed on
the basis of an overflow rate of 400
gals/(day)(ft2) in step 1 and 300 gals/(day)(ft2)
in step 2. These overflow rates are expected to
give low suspended solids concentration in the
overflow. The design is summarized on Table
3.
The oxygen requirement, pounds of oxygen
required per pound of BOD removed, is a func-
tion of F/M and COD/BOD ratios.26 The effect
of COD/BOD ratio may be particularly signifi-
cant in this case as the fate of COD in the
biological treatment of coal conversion wastes
is unknown at present. The oxygen require-
ment is assumed to be 1.03 Ib/lb BOD removed
in step 1 and 1.21 Ib/lb BOD removed in step 2.
Whenever COD needs to be evaluated in the
biological treatment, the removal of COD is
assumed to be equal to that of BOD; this
assumption is conservative and should lead to a
design on the safe side.
The average oxygen utilization in the ox-
ygenation basin depends on the purity of the
oxygen in the gaseous mixture which essential-
ly consists of feed oxygen and the carbon diox-
ide produced as a result of the biochemical ox-
idation. Therefore the average oxygen utiliza-
tion percentage will increase as the feed BOD
concentration decreases and is assumed to be
79 percent in step 1 and 80 percent in step 2.
Based on the oxygen requirement and average
oxygen utilization efficiency, the amount of ox-
ygen to be transferred can be calculated.
The energy requirement is estimated as
follows. The surface aerators consume about 1
hp-hr for 7.8 Ib oxygen supplied, or
0.0956-kW-hr/lb oxygen supplied. Air separa-
tion consumes about 0.165 kW-hr/lb ox-
ygen.11
A major design consideration is the control of
water temperature in the oxygenation basin. As
discussed previously, the removal of 200 mg/l
BOD will cause an increase in water
temperature of 1 ° F. Since the removal of BOD
in step 1 is 95 percent of 1 8,000 mg/l, this will
result in a temperature rise of about 85° F. To
maintain the temperature at 95-100° F in the
oxygenation basin, it will be necessary to recy-
cle 3.4 x 106 gal/day of the mixed liquor at a
temperature of about 97° F and to reduce its
temperature to 80° F in a cooling tower, as
shown in Figure 6. The temperature of the
0.85 x 106 gal/day feed is assumed maintained
at 80° F from the equalization basin. The
broken line in Figure 6 shows the recycling of
the clarified water through the cooling tower
for more flexible operation.
3. Activated Trickling Filter-High
Purity Oxygen Activated Sludge
(ATF-HPOAS)
In Figure 6, showing the HPOAS system, the
cooling would usually be accomplished by
passing the return flow through coils situated in
a spray tower. Water from the clarifier overflow
can be sprayed onto the outside of the coils and
a forced air draft used to evaporate some of the
water and so cool the return flow. It would be
convenient to simply spray the return flow
itself into the spray cooling tower, achieving
499
-------
TABLE 3
DESIGN OF THE HPOAS SYSTEM8
Design Basis
Flow, 106 gal/day 0.85
BOD5, Ibs/day 127,600
BOD5, mg/1 18,000
COD, mg/1 28,000
COD/BOD5 1-56
Wastewater temperature, °F 80°F
pH Adjusted as required
Nutrients Phosphorus to be added
System Design Step 1 Step 2
Flow, Q (106 gal/day) 0.85 0.85
Retention time, hrs (based on feed flow) 74 16
MLSS, mg/1 7,800 5,100
MLVSS, mg/1 7,300 4,500
Sludge Recycle Rate, %Q 35 35
Mean biomass loading, Ibs BODs/Ub MLVSS) (day) 0.8 0.3
Volumetric organic loading, Ibs BODs/(103ft3)(day) 364 84
Average D.O. level, mg/1 5.0 5.0
Oxygen supplied, tons/day 79.0 4.6
Average oxygen utilization efficiency, % 79 80
Secondary clarifier overflow rate, gal/(day)(ft2) 400 300
Recycle suspended solids concentration, wt % 2.0 2.0
b
Effluent Soluble BODs, mg/1 900 45
Preliminary information supplied by Union Carbide on the basis
of assumptions provided by WPA.
Used as basis for determining oxygen requirement.
500
-------
CCOUD tt R.UENT
FIOM AMMONIA
11111
8
Figure 6. High purity oxygen activated sludge (HPOAS) system for Hygas plant with lignite feed.
-------
cooling by forced evaporation. The
unanswered question'is whether spraying will
also break up and damage the biological floes.
This requires testing. Even if spraying to make
droplets proves not satisfactory, it may be
possible to distribute the return flow over a fill
placed in the tower. This fill may be a type of
cooling tower fill called "film type" (as distinct
from "splash type") over which the descend-
ing water flows in a film. Most manufacturers
of cooling towers make film type fill. Such a
filled tower will inevitably turn into a trickling
filter. Munters Corporation makes a plastic fill
that has been used, in separate situations, in a
cooling tower and in a trickling filter.
In Figure 7 is shown a possible scheme with
a combined cooling tower/trickling filter. The
new unit will be designated as an activated
trickling filter (ATF). An activated trickling filter
as used here is a trickling filter of plastic
medium loaded continuously with the mixed li-
quor from the HPOAS units, as shown in Figure
7. The ATF is expected to achieve the follow-
ing objectives:
1. Reduce BOD by about 30 percent as a
pretreatment to the HPOAS system;
2. Reduce the temperature of the recycled
mixed liquor from the HPOAS system
from about 95° to 80° F;
3. Strip off the excessive carbon dioxide
from the recycled mixed liquor.
Qualitatively, the use of an ATF-HPOAS
system may be expected to have the following
advantages over the use of an HPOAS system
alone:
1. Less energy required. The energy re-
quired to pump water and drive the air
fans in the ATF may be lower than that
to transfer the large quantities of air or
to generate and transfer adequate ox-
ygen for the activated sludge process;
2. Less capital and operating costs;
3. Less system upsets and higher treat-
ment reliability. This is due to the fact
that fixed biological growth is less
susceptible to loss of the biota activity
through shock loadings of either
hydraulic feed, BOD concentration, or
toxicants. Recycling of the mixed liquor
may also contribute to the treatment
reliablity.
In the design of ATF we used the
BOD removal relationship for trickling
filters of plastic medium, and the
details of calculation have been
reported elsewhere.5 However, the use
of ATF in combination with an HPOAS
system in the manner shown in Figure
7 results in an extremely high organic
loading of about 8,000 Ib BOD/(103ft3
of mediumHday) compared to current
practice of having high organic
loadings in the range of 1,000-1,400
Ib BOD/(103ft3)(day). This occurs
because the BOD concentration in the
feed water is high and, also, because
the recirculation rate is determined by
the cooling requirement of step 1 of the
HPOAS sysem and is not adjusted to
control the BOD loading of the trickling
filer. Also, there are contaminants in
the coal conversion wastewater other
than phenol which may inhibit
biochemical oxidation in the ATF to
some extent. For these reasons, the
usual trickling filter design equation has
been modified by assuming that the
reduction in BOD obtained is only 30
percent instead of the 80 percent
found by use of the standard design
equation. Furthermore, forced ventila-
tion is used to avoid oxygen transfer
limitation. In our preliminary design
modular units of ATF designed for ease
of counter-flow ventilation, each 20
feet in diameter and 1 8 feet in height,
have been used.
According to B.F. Goodrich General Prod-
ucts, who manufactures plastic medium for
trickling filters, no difficulty is anticipated in
running the mixed liquor through the filter
medium as long as the MLSS does not exceed
10,000 mg/l and the diameter of solid particles
is less than 0.5 inches. Nevertheless the de-
tailed configuration of ATF remains to be better
defined in the future pilot tests. The critical
considerations may be how to prevent plugging
of the filter medium by excessive biological
growth and how to avoid the anaerobic condi-
tion when oxygen transfer becomes limiting. In
spite of these uncertainties we strongly recom-
mend experimenting with ATF as successful
502
-------
NUTRIENTS
COOLED EFFLUENT ^
FROM AMMONIA .„ ,na . , '^
trill Q85«IO°80|«-/doy
(71
8
1
STEP 2
CLARIFICATION
2835ft.2
SLUDGE
DISPOSAL
Figure 7. Activated trickling filter-high purity oxygen activated sludge system (ATF-HPOAS) for Hygas
plant with lignite feed.
-------
applications of a similar system have been
reported.15
CONCLUSIONS
Among the three preliminary designs des-
cribed above, the ATF-HPOAS system appears
to be the most cost-effective and energy-
effective5 for treating high-strength wastes,
such as those from Hygas plants using lignite
feed. With bituminous coal feed the BOD con-
centration will be much smaller, and the cooling
of mixed liquor from step 1 of the HPOAS
becomes unnecessary. The use of HPOAS may
be preferred to AAS where oxygen is also uti-
lized in the coal conversion process. The use of
mutated bacteria and experimenting with ATF
are recommended for future pilot tests.
REFERENCES
1. C. N. Sawyer and P. L. McCarty,
Chemistry for Sanitary Engineers,
McGraw-Hill Book Co., 1967.
2. C. D. Scott, C. W. Hancher, D. W. Holla-
day, and G. B. Dinsmore, "A Tapered
Fluidized-bed Bioreactor for Treatment of
Aqueous Effluents from Coal Conversion
Processes," presented at Symposium on
Environmental Aspects of Fuel Conver-
sion Technology II, Hollywood, Fla.,
December 15, 1975, Environmental Pro-
tection Agency, Research Triangle Park,
N.C., EPA-600/2-76-149.
3. P. D. Kostenbader and J. W. Flecksteiner,
"Biological Oxidation of Coke Plant Weak
Ammonia Liquor," Journal Water Pollu-
tion Control Federation, 41(2), 199-207,
February 1969.
4. C. E. Adams, "Treatment of a High
Strength Phenolic and Ammonia
Wastestream by a Single and Multi-stage
Activated Sludge Process," Proceedings
of the 29th Annual Industrial Waste Con-
ference, Purdue University, W. Lafayette,
Ind., May 1974, pp. 617-630.
5. D. Goldstein and D. Yung, Water Purifica-
tion Associates, "Water Conservation
and Pollution* Control in Coal Conversion
Process," EPA 600/7-77-05, Research
Triangle Park, N.C., June 1977.
6. D. F. Othmer, "Oxygenation of Aqueous
Wastes: the PROST System," Chemical
Engineering, June 20, 1977, pp.
117-120.
7. T. G. Zitrides, "Using Customized Bugs
for Biological Waste Treatment," Plant
Engineering, June 23, 1977, pp.
117-119.
8. A. M. Wachinski, V. D. Adams and J. H.
Reynolds, "Biological Treatment of the
Phenoxy Herbicides 2,4-D and 2,4,5-T in
a Closed System," Research Report to
U.S. Air Force, Utah Water Research
Laboratory, Utah State University, March
1974.
9. C. W. Hancher, Oak Ridge National
Laboratory, Personal Communication,
July 7, 1977.
10. K. Tracy, Exxon Corp., Personal Com-
munication, July 8, 1977.
11. J. T. Hugill, "Cost Factors in Oxygen Pro-
duction," presented at Symposium on Ef-
ficient Use of Fuels in Metallurgical In-
dustries, Institute of Gas Technology,
Chicago, III., Dec. 1974.
1 2. E. H. Bryan, "Two-stage Biological Treat-
ment Industrial Experience," Proceedings
of 11th Southern Municipal & Industrial
Waste Conference, N. Carolina State
University, 1962.
13. R. M. Smith, "Some Systems for the
Biological Oxidation of Phenol-Bearing
Waste Waters," Biotechnology and
Bioengineering, Vol. 5, pp. 275-286,
1963.
14. C. E. Adams, Jr., R. M. Stein, and W. W.
Eckenfelder, Jr., "Treatment of Two Coke
Plant Wastewaters to Meet EPA Effluent
Criteria," presented at 27th Purdue In-
dustrial Waste Conference, May 1974.
15. E. F. Mohler, Jr. and L. T. Clere, "Bio-
oxidation Process Saves H2O," Hydrocar-
bon Processing, October 1973.
16. R. G. Luthy, M. J. Masse^, and R. W.
Dunlop, "Analysis of Wastewaters from
High Btu Coal Gasification Plants,"
presented at 32nd Purdue Industrial
504
-------
Waste Conference, Lafayette, Ind., May
1977.
17. Water Purification Associates, unpub-
lished work underway on EPA Contract 23.
68-03-2207, EPA, Research Triangle
Park, N.C.
18. J. E. Barker and R. J. Thompson,
"Biological Removal of Carbon and 24.
Nitrogen Compounds from Coke Plant
Wastes," EPA-R2-73-167, April 1973.
19. "Analyses of Tars, Chars, Gases and
Water Found in Effluents from the Syn-
thane Process," Bureau of Mines
Technical Progress Report, p. 3. January 25.
1974.
20. A. W. Lawrence and P. L. McCarty,
"Unified Basis for Biological Treatment
Design and Operation," Journal Sanitary 26.
Engineering Division, American Society of
Civil Engineers, 96, 757, 1970.
21. Process Design Techniques for Industrial 27.
Waste Treatment, AWARE, Inc., Enviro
Press, Nashville, Tenn. 1974.
22. R. I. Dick, "Role of Activated Sludge Final
Settling Tanks," Journal Sanitary
Engineering Division American Society of
Civil Engineers, 96, SA2, 423-436, April
1970.
R. I. Dick, "Gravity Thickening of Waste
Sludges," Proceedings Filtration Society,
Filtration and Separation, 9(2), pp.
177-183, March/April 1972.
R. I. Dick and K. W. Young, "Analysis of
Thickening Performance of Final Settling
Tanks," Proceedings of the 27th In-
dustrial Waste Conference, Purdue
University, W. Lafayette, Ind., pp. 33-54,
1972.
"Cost Curves for Basin Plans," Division
of Planning and Research, State Water
Resources Control Board, State of Califor-
nia, January 1973.
Oxygen Activated Sludge Wastewater
Treatment Systems, EPA Technology
Transfer, August 1973.
R. Cooke and P. W. Graham, "The
Biological Purification of the Effluent from
a Lurgi Plant Gasifying Bituminous Coal,"
Int. J. Air Wat. Poll., 9, pp. 97-112,
1965.
505
-------
SOLUBILITY AND TOXICITY
OF POTENTIAL POLLUTANTS
IN SOLID COAL WASTES
By
R. A. Griffin1, R. M. Schuller1, J. J.
Suloway2,
S. A. Russell1, W.F.Childers2,
and N. F. Shimp1
'Illinois State Geological Survey
Illinois Natural History Survey
Urbana, Illinois
Abstract
Chemical and mineralogical characteristics of
a LURGI gasification ash and an H-Coal
liquefaction residue from the Illinois Herrin (No.
6) Coal Member are related to chemical solubili-
ty at several pH's and to biological toxicity of
aqueous supernatant solutions. Chemical
analyses were performed for some 60 constit-
uents. The major constituents in the solid
residues were Al, Ca, Fe, K, and Si. Large quan-
tities of Mg, Mn, Na, S, and Ti and significant
quantities (10-1000ppm) of trace metals were
also present.
The minerals detected in the liquefaction
solid wastes included quartz, pyrrhotite,
sphalerite, calcite, anhydrite, wollastonite, and
clay minerals. A small amount of quartz and
calcite reacted to form wollastonite, and nearly
all the pyrite present in the feed coal was con-
verted to pyrrhotite during conversion. The
minerals detected in the LURGI ash included
quartz, mullite, plagioclase feldspar, and
hematite. Nearly all the pyrite present in the
feed coal was converted to hematite during
gasification. Clays were converted to mullite,
and other accessory minerals were apparently
converted to feldspars.
Of the approximately 60 chemical con-
stituents measured in the raw LURGI ash, only
15 were found to be soluble enough to excede
recommended water quality levels, even at pH
values as low as 3. Six of these con-
stituents—Al, Cr, Co, Cu, Fe, and Zn—exceed-
ed the recommended values for natural waters
only when the pH was quite acid. Over the pH
range 3-10, the remaining nine—B, Ca, Cd, K,
Mn, NHj, Pb, SO4, and Sb-exceeded the
recommended levels in all solutions. These 9
are thought to pose the highest potential pollu-
tion hazard.
The results of 96-hour static bioassays in-
dicated that the water-soluble constituents in
equilibrium with the wastes were not acutely
toxic to young fathead minnows at near-neutral
pH's (7.0-8.5); however, in both the high- and
low-pH solutions all the minnows died. Mortali-
ty may have been the combined result of pH
and total ion content. Further studies of the
causes of the fathead minnow mortality are be-
ing conducted.
INTRODUCTION
The potential need for development of a coal
gasification and liquefaction industry in the
United States has been dramatically
demonstrated by the widespread shortages of
natural gas and fuel oil during the winter of
1977. Because the production of clean fuel
from coal is not without environmental im-
pacts, assessment of potential impacts of coal
conversion pJants is underway (e.g., Sather et
al., 1 975; Forney et al., 1 975; and Jahnig and
Bertrand, 1976). Such studies have empha-
sized the effects of coal conversion upon air
pollution. Although these problems are serious,
they have tended to overshadow another im-
portant matter—the potential pollution of water
resources.
Solid Coal Wastes
As Sources of Pollutants
One by-product of coal conversion is the
generation of solid wastes For example, a
commercial coal gasification plant with a
capacity of 250 million cubic feet of gas per
day will use about 8 million tons of coal and will
generate about 2.3 million tons of ash and dry
refuse per year (Sather et al., 1975). The
amount of residue generated by a single coal
gasification plant has been estimated to occupy
an area of 625 acre feet per year and in 20
years would cover 1 250 acres to a depth of 10
feet (Seay et al., 1972, and Asburg and
Hoglund, 1974). The disposal of these huge
amounts of solid waste is unprecedented, and
successful commercial production of synthetic
506
-------
gas by these processes will depend, in part, on
the environmental acceptability of disposal of
the solid-waste residues.
Interest in the potential pollution hazard from
the accessory elements contained in the solid
wastes is increasing. About 60 of these
elements are found in concentrations of less
than 1 ppm to several percent (Gluskoter et al.,
1977). These accessory elements in the coal
are either retained in the gasifier ash or are
removed by downstream scrubbing of the raw
gases. The ultimate disposal of the ash and
downstream processing wastes will probably
be in tailings ponds and landfills. The types and
quantities of solid wastes from several pro-
posed gasification processes are given in Table
1.
Consideration must be given to undesirable
accessory elements that might be leached from
the wastes during handling in water slurries.
Even those wastes handled dry will ultimately
be exposed to leaching by ground water when
TABLE 1
SOLID WASTES PRODUCED BY SEVERAL COAL
GASIFICATION PROCESSES
Process
BI-GAS
CO 2 Acceptor
HYGAS
Koppers-Totzek
LURGI
SYNTHANE
U-GAS
Winkler
Type of Solid Waste
Water quenched Slag
Water cool, Char/Spent
Acceptor
Water cool, lock hoppers
Ash/Char
Water quenched Slag
Water cool, ash locks Ash
Dry let-down, fluid bed
Char
Water cool, venturi throat
Char
Water-cooled screw conveyor
Char
Quantity
of Solid3
(Ib/hr)
68,400
496,800
138,900
111,500
314,000
362,200
86,400
372,500
SOURCE: Magee, 1976.
alf individual values are used, Magee (1976) should be
consulted to determine the original basis of computation.
landfilled. Potentially severe contamination
from accessory elements contained in the ash
may also result from the disposal of refuse from
the cleaning of coal prior to gasification or
liquefaction. It is well-known that iron sulfates
and acids are produced from the oxidation of
pyritic minerals contained in the refuse when
exposed to air (e.g., Singer and Stumm, 1 969;
Smith et al., 1969; and Jones and Ruggeri,
1969). Garrels and Thompson (1960) con-
cluded that the rate of oxidation was chiefly a
function of oxidation-reduction potential (Eh)
and was independent of total Fe content.
Similarly, Bell and Escher (1969) found that
production of acidic iron salt from pyrite was an
almost immediate response to the atmospheric
gas composition in contact with the water.
Reversing the gases from air to nijrogen caused
the acid formation to decrease, and reversal
from nitrogen to air caused the acid formation
to increase. There is also some evidence that
oxygenation of Fe (II) can be affected by the
catalytic responses of trace constituents such
as copper (Stauffer and Lovell, 1969).
These results have far-reaching implications
for those proposals that recommend the use of
alkaline gasification ashes to neutralize acid
mine refuse or disposal of the ash and refuse
together as landfill in strip mines. It is likely that
accessory elements in the ash and refuse will
be extracted by the acid solution and that these
trace elements may actually catalyze the fur-
ther formation of acid.
The chemical form of the accessory elements
in gasification ashes and slags is important but
has not been investigated thoroughly. Data on
fly ashes and slags produced in coal-fired fur-
naces may not be pertinent because the
gasification ashes and liquefaction residues are
produced under different conditions, namely,
at high temperatures and pressures and usually
in a reducing atmosphere rather than in an ox-
idizing one. Significant alterations in
mineralogy and chemical form of the feed coal
may affect the solubility of accessory elements
in the ash and thus affect their potential as
pollutants.
Solid Coal Wastes
As Resources
Another problem facing the United States is a
507
-------
minerals deficit that will exceed the energy
deficit by the year 2000. The U.S. Department
of the Interior estimates the trade deficit in
minerals to be $100 billion within 25 years.
The United States is almost completely depen-
dent on foreign sources for 22 of the 74
nonenergy minerals considered essential for a
modern industrial society. Of the 12 con-
sidered crucial, 7 are imported in large quan-
tities (>50 percent of use) (Malhotra, 1976).
Previous studies (Ruch, Gluskoter, and
Shimp, 1974, and Gluskoter et al., 1975) have
shown that certain minor and trace elements
are concentrated in coal ash. For example, zinc
occurred in certain coal ashes in concentrations
as high as those mined as commercial sources.
Thus, the high quantities of solid waste
generated from coal gasification and liquefac-
tion processes may be used as ore in the future.
It is conceivable that the acid mine waters may
be used to extract recoverable amounts of cop-
per, nickel, zinc, iron, and other minerals from
the solid wastes. Although some studies have
been made in this general area (EPA, 1971),
much more work is necessary to predict both
the positive and negative potential environ-
mental effects of coal conversion processes.
CURRENT STUDIES OF ACCESSORY
ELEMENTS IN COAL GASIFICATION
AND LIQUEFACTION RESIDUES
Obtaining data concerning the accessory ele-
ment content, mineralogy, solubility, and tox-
icity of leachates from coal solid wastes is a
necessary first step in assessing the en-
vironmental aspects of coal utilization; it has
not always been among the first steps taken,
however (DiGioia et al., 1974). The project
reported here grew out of an ongoing research
effort at the Illinois State Geological Survey in-
volving the characterization of coal and coal
residues.
Data on the chemical analyses and sum-
maries of the geological significance of over
170 coals have been published by the Illinois
State Geological Survey (Ruch, Gluskoter, and
Kennedy, 1971; Ruch, Gluskoter, and Shimp,
1973; Ruch, Gluskoter, and Shimp, 1974;
Gluskoter et al., 1977). Current investigations
are expanding these studies to include the feed
coals and residues from coal conversion
processes. Complete chemical, physical, and
mineralogical characterizations of slags, ashes,
chars, cleaning wastes, and residues from
various coal gasification and liquefaction
processes are being made. These chemical and
mineralogical characteristics are then being
related to chemical solubilities at several pH's
and to biological toxicity of aqueous extracts of
the solid-waste residues. This report presents
some recent data obtained from a LURGI
gasification ash and an H-Coal liquefaction
residue from an Illinois No. 6 Coal.
Sources of Gasification Ash
and Liquefaction Residue
During 1973 and 1974, the American Gas
Association and the Office of Coal Research
studied the performance and suitability of
various American coals for gasification by the
LURGI process. Four different coals were sent
to Scotland, where they were gasified in the
LURGI plant at Westfield. Among the four coals
were 5000 tons of Herrin (No. 6) coal from Il-
linois that was gasified; the unquenched waste
ash was then sent back to the United States for
analyses. The sample of LURGI ash from the
No. 6 Coal, for which data is reported here,
was supplied by Peabody Coal Company's Cen-
tral Laboratory at Freeburg, Illinois.
The coal liquefaction residue was obtained
from Hydrocarbon Research, Inc., Trenton,
New Jersey. The residue comprised the
vacuum still bottoms generated during produc-
tion of a fuel oil product using an Illinois No. 6
Coal and the H-CoalR PDU at the HRI Trenton
Lab on May 3, 1976.
Chemical and
Mineralogical Characterization
The chemical composition of the H-Coal
residue and the LURGI ash has been determined
for approximately 60 constituents and is sum-
marized in Tables 2 and 3. The major con-
stituents found were Al, Ca, Fe, K, and Si.
Large quantities of Mg, Mn, Na, S, and Ti and
significant quantities (10-1000 ppm) of trace
metals were also present.
The minerals detected in the LURGI ashes by
X-ray diffraction included quartz, mullite,
hematite, and plagioclase feldspar. Nearly all
508
-------
TABLE 2
CHEMICAL COMPOSITION OF LURGI ASH AND SLURRY SUPERNATANT SOLUTIONS
OF THE ASH FROM AN ILLINOIS NO. 6 COAL AT SEVERAL pH'S
Chemical Composition of 10Z
Constituents
pH
Ag
Al
Au
Aa
B
Ba
Be
Br
Ca
Cd
Ce
Cl
CODC
MCE'
Cr
Co
Cu
Ca
Eu
r
FeTotal
Pe+2
Ga
Ge
Hf
•Hg
I
La
LI
U
Hg
Hn
Ho
Na
HH4
Nl
P
4
Rb
hotal
SO.
4
Sb
7.55*
_
ND"
.
ND
4.0
ND
ND
-
290
.02
.
ND
2
28
ND
ND
.01
-
•*
.31
.06
.03
••
«•
-
ND
42
—
1.8
10.5
.45
ND
34
17
.03
.1
_
ND
-
ND
820
.2
Air
5.10
_
2
-
ND
4.5
ND
ND
-
480
.03
-
ND
2
28
.02
.05
.02
•
-
.30
.19
.11
~
-
-
ND
49
••
1.9
14
1.94
ND
37
8
.13
.1
—
ND
~
ND
943
.3
Slurry Suoernatant (nt/1)
Argon
3.82
_
14
-
ND
4.5
ND
.01
-
400
.03
-
ND
2
0
.05
.08
.13
-
•
.09
.24
.10
"
~
-
ND
51
—
2.0
15
2.7
ND
38
12
.23
.1
•
ND
"
ND
808
.3
2.68
_
132
-
ND
5.5
ND
.03
-
570
.06
.
ND
81
23
.12
.19
.73
~
-
.04
560
533
~
™
-
ND
26
~
2.0
22
3.8
ND
40
11
.50
.2
"
ND
™*
ND
338
.6
8.821
_
ND
-
ND
4.5
ND
ND
-
440
.01
-
ND
2
10
.01
ND
.01
~
~
.51
.06
.13
~
~
"
ND
39
~
1.6
9.5
.11
ND
32
10
ND
ND
"
ND
"
ND
730
.3
7.20
_
ND
.
ND
3.0
ND
ND
-
370
ND
-
ND
2
3
.01
ND
.05
~
~
.34
.11
.05
"*
""
~
ND
43
~
1.8
11
.90
ND
37
10
.04
ND
~
ND
ND
735
.3
5.35
_
ND
-
ND
4.5
ND
ND
-
430
.02
-
ND
16
6
.06
ND
.01
™
~
.16
101
110
~
~
NB
46
"
1.9
13.5
2.3
ND
37
10
.14
.1
"
ND
ND
700
.3
3.79
_
92
-
ND
8.0
ND
.01
-
500
.05
-
ND
140
4
.16
.17
.05
~
.02
880
865
_
™
ND
61
_
2.1
23
3.7
ND
40
17
.42
.2
ND
ND
710
.5
Recommended Water
Quality Levels (mg/1)
6.0 - 9.0
.05
.1
-
.1
.75
1.0
.1
-
50
.01
-
250
50
-
.05
.05
.2
_
1.0
.3
_
-.--
.0002
5
.
2.5
_
50
.05
.01
20*
.02
1.
.03
—
.05
_
.002
250
.05
Solid Ash
Content (ng/kg)
-
<.4
108,121
<.001
3
355
950
12
<1.0
16,652
<1.6
140
100
-
-
212
34
57
11
1.9
<10
143,780
26
7.0
6.1
.05
14,611
47
42
1.5
3.739
1,859
30
1,929
~
89
45
87
"
162
6,100
1,500
8,100
4.2
509
-------
TABLE 2 (Continued)
Sc
Se
SI
Sm
Sn
Sr
Ta
Te
Th
Tl
Tl
U
V
W
Yb
Zn
Zr
EC (mhos/cm)
Eh (electrode mv)
-
5
-
ND
1.8
-
ND
-
ND
ND
^
-
-
-
.12
-
1.17
+223
_
29
-
KB
1.9
-
ND
.
ND
ND
-
-
-
-
5.5
-
1.50
+246
-
60
-
ND
2.1
-
ND
-
ND
ND
I
-
.
-
12
-
1.95
+407
-
130
-
ND
2.9
-
ND
-
ND
ND
.
- -
-
-
17
-
5.60
+349
-
4
-
ND
1.5
-
ND
-
ND
ND
-
-
-
-
.01
-
1.20
+109
-
9
-
ND
1.7
-
ND
-
ND
ND
;
-
-
-
.11
-
1.39
+161
-
27
-
ND
1.9
-
ND
-
ND
ND
-
-
-
-
6.5
-
1.80
+102
.01
120
-
ND
2.6 50.
-
ND
-
ND
ND
-
0.1
-
-
20 .2
-
5.20 18
+243
29
<1
229,946
10
-
370
1.1
-
21
6,295
4.6
17
184
1.5
2.9
400
170
-
-
'Natural pH of «upernat«nt bNot detectable'chenlcal oxygen demand Methylene chloride extractable *Por low Na diet; 250 ppn for taste
TABLE 3
CHEMICAL COMPOSITION OF H-COAL LIQUEFACTION WASTE AND SLURRY SUPERNATANT
SOLUTIONS OF THE WASTE AT SEVERAL pH'S
Chemical Cocu>oeitlon of 10%
Constituents
pH
Ag
Al
Au
As
B
Ba
Be
Br
Ca
Cd
Ce
Cl
CODb
Cr
Content (mg/kg) Air
8.83* 8.16 5.01
0.16
17,253 3.0 <.5 <.5
_.
1.5 <1 <1 <1
300 11.0 13.0 11.6
40 <0.1 <0.1 <0.1
1.8 <.01 <.01 <.fll
6.7
7862 110 175 380
<.4 <.03 <.03 <.03
16
1000 75 71 67
15 9 7
27.5 <.02 <.02 <.02
3.14
—
5.5
—
<1
13.6
<0.1
<.01
—
497
<.03
~
75
15
.03
Slurry Supernatant (me/I)
Argon
11.31* 8.50 5.53
-_
1.5 <.5 1.5
—
<1 <1 <1
11.0 12.2 12.9
<0.1 <0.1 <0.1
<.01 <.01 <.01
—
133 155 425
<.03 <.03 <.03
—
78 70 75
24 8 2
<.02 <.02 <.02
2.30
—
5.7
—
<1
15.0
^0. 1
<4 Ql
..
487
<.03
—
64
24
.05
Decomended Watir
Quality Levels (mg/1)
6.0 - 9.0
.05
.1
—
.1
.75
1.0
.1
_
50
.01
—
250
50
.05
510
-------
TABLE 3 (Continued)
Co
Cu
Cs
Eu
F
FeTotal
Ga
Ge
Hf
K
La
Li
Lu
Mg
Mn
Ho
Na
tnU
Ni
Fb
F
F0»
Rb
STotal
S"1
SO,
Sb
Sc
Se
Si
SB
Sn
Sr
T«
Te
Th
Tt
11
U
V
V
Yb
Zn
Zr
EC (rahoi/cn)
Eh (electrode ov)
4.45
14
1.7
0.69
100
23,662
4.6
4.9
0.86
2490
9.8
—
.024
844
77
6.4
619
—
21
32
44
—
16
18,000
300
600
1.2
4.1
—
39,641
2.3
0.6
30
0.17
<0.1
3.5
1019
1.7
5.7
33
4.4
1.0
71
41
_
—
<.05 <.05 <.05 <.05 <.05 <.05 «.05 <*05 '"
— — ~~
1-00 1.15 0.60 0.86 0.70 1.20 0.85 0.84 1~0
l U 3l-5 <•! <.l 6.5 90 '3
<>l <>l " 29-5 <.l <.l .9 90
—
— _ _. — ... ~~
<.0002 <.0002 <.0002 <.0002 <.0002 <.0002 <.0002 <.0002 .0002
ll4 '•* 2-1 2.8 1.2 1.5 2.0 2.5 5
—
<.01 .01 .02 .02 <.01 .01 .02 .02 2.5
—
0.5 0.6 2.7 4.0 0.6 0.8 3.0 4.0 50
*-02 .04 1,67 2.68 <.02 0.10 1.83 2.52 .05
<.2 <.2 <.2 <,2 <.2 <.2 0.2 <.2 .01
6.7 7.0 7.5 9.3 6.5 6.8 109C 9.0 20d
9688 8575 .02'
<.07 <.07 <.07 <.07 <.07 <,07 <.07 .25 1.0
<0.1 <.l .2 .25 <.l <.l .15 .2 .03
—
<.025 <.025 <.025 <.025 <.025 <.025 <.025 0.1 .05
—
_
<.2 <.2 <.2 <.2 ^.2 <.2 <.2 <.2 .002
65.5 68.5 148.5 96.5 65.5 66.0 70.5 73.5 250
<.4 <.4 <.4 <.4 <.4 <.4 <.4 <.4 .05
..
<.5 <.5 <.5 <.5 <.5 <.5 <.5 <.5 .01
<1 <1 <1 3 <1 <1 <1 3
—
<1.0 <1.0 <1.0 <1.0 <1.0 <1.0 <1.0 <1.0
.20 .24 .34 .50 .20 .26 .38 .48 50
..
<.5 <,5 <.5 <.5 <.5 <.5 <.5 <.5
_.
<.6 <.6 <.6 <.6 <.6 <.6 <.6 <.6 -
<.4 <.4 <.4 <.4 <.4 <.4 <.4 <.4
„
<.5 <.5 <.5 <.5 <.5 <.5 <.5 <.5 0.1
—
„
.01 .01 .06 .27 .02 .02 .12 .76 .2
_ — — — — — — —
O.OS 0.87 2.18 2.83 0.68 1-00 2.51 3.49 18
+202.8 +235 +295.1 +419.6 +13.9 +178.9 +233.7
•B.tur.1 pH of .up.cmic.nt bCh«l«l oxygen denand "N.OH added for pH adju.tment "W low N. diet; 250 pp. for ta.t.
511
-------
the pyrite present in the feed coal was con-
verted to hematite during gasification. The clay
minerals present in the feed coals were not
detected in the ash and were apparently con-
verted to mullite, a high-temperature-phase
aluminosilicate. The other accessory minerals
were apparently converted to a feldspar,
The minerals detected in the H-Coal residue
samples by X-ray diffraction included quartz,
pyrrhotite, sphalerite, calcite, anhydrite, illite,
kaolinite, and some expandable clay minerals.
Wallastonite (CaSi03), undetected by X-ray dif-
fraction, was found by the scanning electron
microscope with the energy-dispersive X-ray
analyzer in polished and etched samples of
heavy minerals from the H-Coal residues.
Several minerals participate in chemical reac-
tions during coal conversion processes. For ex-
ample, in the H-Coal process, a small amount of
quartz and calcite reacted to form wollastonite.
More importantly, nearly all the pyrite present
in the feed coal was converted to pyrrhotite in
the solid waste. This occurred at temperatures
lower than would be expected from com-
parisons with published data on reactions of
pure iron sulfides at equilibrium conditions.
These reactions could have occurred in the
slurry preheaters or in the liquefaction process
reactors. The pyrite-to-pyrrhotite conversion
might have been a result of the cobalt-
molybdate catalyst, which is used for conver-
sion of organic constituents to a fuel oil product
in the H-Coal process, but the effect of the
catalyst on the mineral interactions is not
known. We have also studied other liquefaction
process residues and the change from pyrite to
pyrrhotite also occurred without the aid of the
catalyst in the Solvent Refined Coal (SRC) proc-
ess. The SRC process does not use a catalyst.
In the three liquefaction processes studied
(H-Coal, SRC, and SYNTHOIL), nearly all pyrite
in the feed coals was converted to pyrrhotite in
the solid residues, This conversion may be the
result of intimate association of the hydrogen in
the liquefaction system with the pyrite in the
coal slurry. Established phase relationships in
closed systems cannot be directly applied to
mineral matter in the liquefaction processes
because of the undefined interactions of the
components and the removal of vapor from the
system during reactions. Therefore, mineral
reactions must be deduced from a thorough
study of the coal mineral matter before and
after coal conversion.
Aqueous Solubility
Probably the single most important factor af-
fecting the solubility of the accessory elements
in coal solid wastes is pH. Many coal wastes
contain sulfide minerals that can acidify upon
exposure to air. In terms of heavy metals, solid
wastes disposed of in acidic strip or
underground mines are potentially more soluble
than wastes disposed of under neutral or
alkaline conditions.
The oxidation potential (Eh) is also an impor-
tant factor affecting the solubility of minerals
(Carrels and Christ, 1965). When solid wastes
are buried underground or in water-saturated
materials, anaerobic (oxygen deficient) condi-
tions usually develop. Studies of the effect of
Eh and pH on the solubilities of coal solid
wastes could produce data that would allow
prediction of potential pollution hazards or, on
the other hand, prediction of optimum condi-
tions for extraction of the potentially valuable
elements contained in the wastes.
The current experimental design involved
making 10% aqueous slurries of each of the
solid wastes studied. The slurries were set up
in series that had been adjusted to four in-
dividual pH values over the range 2 to 11. The
pH values of the slurries were monitored daily
and readjusted to the specified value if
necessary. Chemical equilibrium was assumed
when the pH values remained constant. This
process took approximately 3 months;
however, studies with LURGI ashes from three
different coals showed that chemical
equilibrium was more than 90 percent com-
plete in one week.
Duplicate sets of slurries were used. One set
was equilibrated under an argon (oxygen and
C02 free) atmosphere and the second set was
equilibrated under an air (oxidizing) at-
mosphere. The results for a LURGI ash and an
H-Coal residue obtained from an Illinois No. 6
Coal are reported in Tables 2 and 3. Tables 2
and 3 contain the measurements for some 63
chemical constituents measured in the solid
ash and in the aqueous supernatant solutions.
Also included in the tables is a summary of
512
-------
recommended water quality levels (EPA, 1973}
for as many constituents for which data could
be found. This was done for comparison with
the water solubility levels found under condi-
tions given in Tables 2 and 3.
Potential Pollutants
Of the approximately 60 chemical constit-
uents measured in the raw LURGI ash and
H-Coal residue (Tables 2 and 3), about 31 were
found to be present at concentrations that
could present a potential hazard. The remainder
were present at such low levels that, even if
completely soluble, they would pose no par-
ticular problem. Of the 31 that were a potential
problem, 16 were found to be in forms soluble
enough to exceed recommended water quality
levels in some samples at pH values between 3
and 8. These 16 constituents are listed in Table
4. Seven of the constituents-AI, Cr, Co, Cu, F,
Fe, and Zn—exceeded the recommended levels
in water only under certain pH conditions,
generally when the pH was quite acid. The
other nine constituents-B, Ca, Cd, K, Mn,
NH4, Pb, S04, and Sb—exceeded the recom-
mended levels in all LURGI ash solutions over
the pH range 3 to 9. These nine constituents
are thought to represent the highest potential
pollution hazard. Discharges of the 16 con-
stituents listed in Table 4 at the levels found in
this study could cause some environmental
degradation and require some form of
wastewater treatment.
Toxicity Studies
The acute toxicities of the water-soluble con-
TABLE4
ELEMENTS EXCEEDING RECOMMENDED WATER QUALITY LEVELS
Constituent
Al
B"
C8»
Cd«
Cr
Co
Cu
F
Fe
K8
Mna
NH48
Pb8
S048
Sb8
Zn
LURGI
Ash Solubility
pH3
(mg/l)
132.
5.5
570.
0.06
0.12
0.19
0.75
...
560.
26.
3.80
11.
0.20
338.
0.60
17.00
pHB
(mg/l)
<0.5
4.0
290.
0.02
<0.02
<0.10
0.01
_.
0.06
42.
0.45
17.
0.10
820.
0.20
0.12
H-Coal
Residue Solubility
pH3
(mg/l)
5.5
13.6
497.
—
_.
~
_.
0.86
31.50
-.
2.68
8.
0.25
—
0.27
PH8
(mg/l)
<0.5
13.0
175.
-
-
_
-
1.15
<0.10
-
0.04
6.
<0.10
*"*
0.01
Recommended
Levels
(mg/l)
0.10
0.75
50.
.01
0.05
0.05
0.20
1.00
0.30
5.00
0.05
0.02
0.03
250.
0.05
0.20
'HighMt pollution potential
513
-------
stituents in the solid-waste leachates from coal
conversion were assayed, used fathead min-
nows, Pimephales promelas. Three-to-six-day-
old free-swimming fatheads were used for the
96-hour static bioassays. These studies were
performed under controlled conditions in an en-
vironmental chamber, using procedures sug-
gested by the Committee on Methods for Tox-
icity Tests with Aquatic Organisms (1 975). All
bioassays were replicated one or more times.
The toxicities of the water-soluble com-
pounds in equilibrium with the H-Coal liquefac-
tion residue and the LURGI gasification ash at
various pH values are shown in Figure 1. The
waste leachates do not appear acutely toxic to
young fathead minnows at near-neutral pH's
(7.0-8.5); however, 100 percent mortality oc-
curred in both the high- and low-pH solutions
(Figure 1). To test only the pH effect on the
mortality of the fathead minnows, bioassays
were conducted using buffered solutions of
reconstituted water ranging in pH from 5.0 to
11.0. The results of these bioassays iFigure 1)
were similar to those found for the waste
leachates. It is possible that most of the mor-
tality observed was the result of pH values.
However, the higher mortality observed in the
alkaline range for the H-Coal leachate than for
the reconstituted wate: indie, .« a toxicity that
is not accounted for b1/ pH values.
Attempts were made to decrease the mortal-
ity due to pH effects by neutralizing some of
the acidic leachate solutions with NaOH. In all
cases 100 percent mortality occurred even
though the pH was neutral. All the neutralized
solutions had specific conductance values
greater than 7.00 mmhos/cm. We hypothe-
sized that the high total ion concentration
resulted in ionic shock and was responsible for
the mortality in the neutralized solutions. This
conclusion was verified by a study in which the
specific conductance of several solutions of
reconstituted water was varied by the addition
of NaCI. The results are shown in Figure 2.
RECONSTITUTED
WATER
Figure 1. Effect of pH on the mortality of fathead minnows in LURGI ash leachate, H-Coal residue
leachate, and reconstituted water.
514
-------
100-
80
20-
34567
Specific conductivity (mmhos/cm)
—i—
8
—r~
9
10
Figure 2. Effect of specific conductance on the mortality of fathead minnows in reconstituted water.
Solutions with a specific conductance greater
than 6.10 mmhos/cm caused 100 percent
mortality.
The LC-50's were determined for the waste
leachates and are presented in Table 5. The
LC-50 is the number of milliliters of waste
material per 1 00 milliliters of total volume that
results in the death of 50 percent of the test
organisms during 96 hours. For example, if the
LC-50 is 5.0 ml/1 00ml, then a solution of 5.0
ml of waste leachate and 95.0 ml of
reconstituted water will kill 50 percent of the
fathead minnows. If the LC-50 is greater than
100ml/100ml, a solution of undiluted leachate
will not kill 50 percent of the minnows. The ap-
proximate LC-50 values for the H-Coal and
LURGI ash leachates of various pH's are listed
in Table 5. Very acidic solutions (pH <4.0)
must be diluted 20 or more times to decrease
mortality to 50 percent, whereas full-strength
near-neutral solutions were not toxic.
These studies indicate that the water-soluble
constituents in equilibrium with wastes at near-
neutral pH's (7.0-8.5) are not acutely toxic to
young fathead minnows. Both pH and total salt
concentration do appear to be important fac-
tors that affect the observed mortality of the
young minnows. Further studies are being con-
ducted to determine the interactions of pH,
total ion concentration, and toxic compounds
extracted from the wastes.
RECOMMENDA', ONS
The potential environmental and economic
consequences associated with the disposal of
the solid wastes generated by even a single
large-scale coal conversion facility is im-
pressive because of the sheer magnitude of the
wastes generated. The major solid wastes are
the refuse from coal cleaning; ashes, slags, and
chars from the conversion process; and
sludges from water cleanup. Clearly, careful
planning is required to mitigate adverse en-
515
-------
TABLE 5
PERCENTAGE MORTALITY AND APPROXIMATE LC-50'S FROM BIOASSAYS OF
FATHEAD MINNOWS FOR LURGI ASH AND H-COAL LEACHATES
pH
7.5
7.1
7.1
5.1
4.9
3.9
3.8
2.6
LURGI
Mortality
(%)
0
0
0
100
100
100
100
100
LC-50
(ml/1 00 ml)
>100
>100
> 100
25-50
5-25
5-25
<5
<5
PH
8.8
8.3
7.7
7.6
6.0
5.9
3.3
3.1
H-COAL
Mortality
(%)
100
15
0
0
100
100
100
100
LC-50
(ml/1 00 ml)
50-100
>100
>100
> 100
50-100
50-100
<5
<5
vironmental impacts; however, planning can be
effective only when an adequate data base is
available.
Specific research needs include the
qualitative and quantitative characterization of
coal conversion solid wastes:
1. Quantitative determination of the ac-
cessory elements contained in the
wastes
2. Determination of the solubility of the
accessory elements under a variety of
environmental conditions
3. Establishment of the effects of coal
characteristics and process operating
variables on the character of the solid
wastes generated by a given process
4. Determination of methods for recover-
ing valuable metals from the solid
wastes
5. Determination of the ultimate fate of
waterborne pollutants resulting from
solid-waste materials
6. Characterization and quantification of
both the acute and chronic biological
toxicity and public health hazard
associated with pollutants from coal
solid wastes
7. Pursuit of research to establish en-
vironmental standards that will main-
tain the integrity of the environment
within realistic bounds
The energy demands of the nation are such
that construction of large-scale coal gasifica-
tion and liquefaction plants will be undertaken.
The process designs are at the pilot plant stage
of development and demonstration plants will
undoubtedly be built within the next decade.
There are few precedents with which to predict
the environmental impact of the disposal of
waste products on a scale this large. It is ex-
pected that valuable trace elements can be
recovered from many wastes if proper planning
is provided. Basic and applied research is need-
ed to develop the technical information
necessary to formulate those strategies and
disposal options necessary to avoid serious
problems that could appear suddenly in large-
scale operations. Further, the research must be
begun soon so that the data will be available for
the planning of the initial large-scale coal con-
version facilities.
ACKNOWLEDGMENTS
We gratefully acknowledge the U. S. En-
vironmental Protection Agency, Energy
Assessment and Control Division, Fuel Process
Branch, Research Triangle Park, North
516
-------
Carolina, for partial support of this work under
Contract 68-02-2130, Characterization of
Coal and Coal Residue. We also are indebted to
the Peabody Coal Company, Freeburg, Illinois,
and to Hydrocarbon Research, Inc., Trenton,
New Jersey, for supplying us with samples.
The authors wish to thank A. K. Au, H. D.
Glass, and the Analytical Chemistry Section of
the Illinois State Geological Survey, under Dr.
R. R. Ruch, for assistance in portions of this
research.
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14. E. M. Magee, Evaluation of Pollut on Con-
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518
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APPLICABILITY OF COKE PLANT
WATER TREATMENT
TECHNOLOGY TO COAL
GASIFICATION
William A. Parsons, Director,
Corporate Environmental Services,
Arthur G. McKee & Company,
Cleveland, Ohio
Walter Nolde, Technical Manager,
By-Product Plants, McKee-Otto Engineers
and Constructors, Cleveland, Ohio
Abstract
Historically, some of the most profound early
waste treatment research was performed in
Europe on liquors from coke and gas plants.
The early studies demonstrated that
wastewater technology developed for coal gas,
producer gas, and by-product coke plants was
transferable. It follows that much of
wastewater treatment technology developed
recently for by-product coke plants will be
transferable to tar-producing coal gasification
processes. It is expected that the development
of virgin wastewater treatment technology will
be required for coal gasification processes that
operate under tar-free conditions.
Activated sludge technology is adaptable to
treatment of condensates from tar-producing
coal conversion processes. The application of
the data base available from coke plant waste
treatment will reduce a research project to a
developmental project at a vast saving in time
and effort. Coal condensates may be deficient
in trace element nutrients such as
phosphorous, magnesium, and potassium.
Evaluation of nutrient adequacy is recommend-
ed in developmental studies. Effluent polishing
by dissolved air flotation is worthy of con-
sideration inasmuch as the process is more
capable of handling slugs of suspended solids
than are filters. In addition, the float separated
from the flotation process is a concentrate
rather than a dilute filter backwash.
Preliminary absorption of halides is a concept
that has potential for improving water manage-
ment at coal gasification facilities. The separa-
tion of a low volume, high salt concentrate
would reduce disposal problems and increase
the feasibility of water reuse.
Gas lighting with coal-derived gas and water-
borne collection of sewage commenced in the
cities and towns of England in the early nine-
teenth century. The technology soon spread
throughout Europe and to the Americas. The
adoption of gas and sewage technology in con-
junction with a large increase in population
resulted in gross pollution of receiving waters.
A Royal Commission on Sewage Disposal was
appointed in 1898 to report on methods for the
treatment and disposal of sewage and trade
wastes. Not surprisingly, coal gas plant liquors
were among the trade wastes included in the
early investigations. The evolution of the
studies has been documented elsewhere1 2'3.
A review of highlights of previous studies
would show that near the turn of the century
studies with biological filters had determiped
that spent ammonia liquor from a gas plant
could be treated as a 0.5 percent admixture
with domestic sewage. By 1911, it had been
demonstrated experimentally that gas plant
ammonia liquor could be treated for substantial
periods on biological filters by recirculation of
effluent without a requirement for dilution with
sewage. The experiments employed recircula-
tion ratios of up to 19 to 1 and preceded by 25
years the frenzied rush in the domestic sewage
field to patent every conceivable recirculation
scheme for biological filtration.
The treatment of coke plant ammonia still
waste in admixture with domestic sewage was
tested early in the evolution of the activated
sludge process. Based on experiments at
Milwaukee in 1920 and subsequent studies,
Mohlman4 concluded that admixtures contain-
ing 30 to 40 mg/l of phenol were acceptable
for the activated sludge process. He also con-
cluded that admixtures containing 25-35 mg/l
phenol were acceptable for intermittent sand
filtration. Nolte5 in the early Thirties, employed
the addition of nutrient phosphate to ammonia
liquor to enable experimental treatment by ac-
tivated sludge without domestic sewage dilu-
tion.
The recognition of the nutritional deficiency
of ammonia still waste was an important obser-
vation inasmuch as the performance of
biological treatment on undiluted waste had
been unreliable over sustained periods of
operation. Prototype activated sludge plants
were installed at coke plants in Europe and
519
-------
North America in the early Sixties6'7'8-9. The
treatment performance has been highly im-
pressive but problems have been experienced
in regard to consistency. Activated sludge in-
stallations at coke plants have proliferated in
recent years.
Thus an analysis of early research on
biological treatment of ammonia liquor sug-
gests that the trend of original studies tended
to be on liquors from coal gas plants. The result
of the studies were somewhat inconsistent but
were shown to be transferable to coke plants
and to producer gas plants. It follows that
many of the refinements in biological treatment
more recently developed at coke plants will be
transferable to tar producing coal gasification
technology. Tar-free coal conversion processes
are expected to require the development of
virgin waste treatment technology.
Improved gas cleaning technology is being
installed at modern coke plants. Coke plant gas
cleaning technology is expected to be ap-
plicable to the cleaning of cooled producer gas
for industrial consumption, but modification
would generally be required for the production
of substitute natural gas from coal for in-
terstate pipeline transmission.
CURRENT STATUS
Gas Cleaning
Upgraded gas cleaning and water treatment
technology have been employed in recent coke
plant installations. A generalized block diagram
representative of coke plant gas cleaning is
given as Figure 1. Primary cooling to about
90° F is advocated to provide for early removal
of naphthalene to minimize deposition of
naphthalene during gas transport. High effi-
ciency electrostatic tar removal with back-up
capability is employed to protect subsequent
by-product processes. The selection of the am-
monia recovery process depends upon projec-
tions of marketability of the recovered by-
products, and gas quality criteria. Some recent
plants employ the Phosam process for indirect
recovery of ammonia as anhydrous am-
monia—which offers maximum flexibility for
the marketing of the by-product. However, the
simpler recovery of ammonia as ammonium
sulfate is still the most popular method. When
coke plants recover sulfur as sulfuric acid,
some of the acid can be consumed in the am-
monium sulfate by-product operation.
The trend at modern coke plants for
desulfurization has been to employ neutraliza-
tion processes using ammonia liquor or other
alkalies as absorbent, or oxidation processes
such as Stretford. A myriad of desulfurization
process alternatives exist commercially, but
processes applicable to coal gas desulfurization
are restricted to those that operate efficiently in
the presence of extraneous sulfur and cyanide
compounds. The selection of the desulfuriza-
tion process is dependent upon the design of
the gas treatment system and the desired by-
product (e.g., H2S04 or S). Neutralization proc-
esses are normally designed to achieve gas
residuals of 0.1 to 0.3 gr/dscf hydrogen
sulfide, whereas oxidation processes can be
designed to achieve residuals of 0.01 gr/dscf
hydrogen sulfide. Most of the demonstrated
desulfurization processes are of limited effec-
tiveness for the removal of organic sulfur com-
pounds (e.g., COS and CS2).
Ammonia Stripping
The ammonia contained in the flushing liquor
condensate separated during primary cooling is
recovered by steam stripping. If the coal feed
contains appreciable chlorides, a substantial
fraction of the ammonia in the flushing liquor
will be present as ammonium chloride or other
fixed ammonia. Alkaline stripping is required to
spring fixed ammonia. Modern ammonia stills
at coke plants are usually designed for a
residual of about 50 mg/l of total ammonia in
the still bottoms. A two-stage stripping opera-
tion is usually employed with lime or caustic
soda being added to the second stage to spring
ammonia from strong acid anions.
Some modern stripping processes, such as
Chevron in the petroleum industry and Cyam of
U. S. Steel, employ controlled pH in the first
stage to preferentially separate weak acid
gases (HCN, H2S, and C02). The result is im-
proved biological plant effluent quality in-
asmuch as cyanide is somewhat refractory to
biological processes. In addition to the
previously mentioned processes, Bethlehem
Steel Company10 has developed a single-stage
alkaline stripping process that features low
520
-------
RAW
GAS
U1
ro
PRIMARY
COOLER
k-
TAR
EXTRACTOR
AMMONIA
ABSORBER
PRIMARY CONDENSATE
AND TAR
SULFUR
PRODUCT(S)
TAR AND
PRIMARY CONDENSATE
AMMONIA
PRODUCT(S)
HYDROGEN
SULFIDE
ABSORBER
*-
FINAL
COOLER
WASH
OIL
SCRUBBER
SECONDARY CONDENSATE
AND NAPHTHALENE
LIGHT OIL
CLEAN
Figure 1. Schematic of coke plant gas purification.
-------
steam consumption and improved ammonia
stripping efficiency.
Wastewater Treatment
The present trend at coke plants for
wastewater treatment is towards the activated
sludge process. The process features
remarkable removal of phenol to sub mg/l levels
but usually provides somewhat less impressive
removal of thiocyanates and cyanides. The
limitations of the process include effluent color
and occasional inconsistencies in respect to
discharge of suspended solids, thiocyanates,
and cyanides. Efficient removal of ammonia in
the stripping operation will encourage con-
sistent degradation of thiocyanate and cyanide.
Process Performance
The composition of the primary condensates
from tar-producing coal gasification processes
are basically similar to primary condensates
from coke plants operating on similar coal. The
gas volume per ton of coal is much larger from
gas plants than from coke plants which results
in lower concentrations of impurities in the gas
and larger units for gas purification. The larger
gas volume would also be expected to produce
a larger volume of a more dilute primary con-
densate per ton of coal feed.
The combination of similarity in composition
and historical record of similar treatability
characteristics should enable the transfer of
sufficient gas cleaning and waste treatment
technology to justify the substitution of a
development study for a much more involved
research study. That is, for purposes of ex-
perimental design, it can be projected: (a) that a
biological process will perform well in the 80 to
95° F range, (b) that pure culture processes
are impractical, (c) that the food-to-
microorganism ratio will be less than 0.2 Ib
BOD/lb volatile suspended solids, (d) the yield
of cell substance will be from 0.2 to 0.5 Ib/lb
BOD removed, and (e) that the final clarifier unit
solids loading will be from 20 to 30 lb/day = sq
ft. It can be further projected that the following
concentration ranges will be representative of
the settled effluent: (a) suspended solids 60 to
200 mg/l, (b) phenol 0.05 to 0.5 mg/l, (c) thio-
cyanate 1 to 10 mg/l, (d) cyanide 1 to 10 mg/l,
(e) sulfide 0.01 to 0.3 mg/l, and (f) BOD 50 to
1 50 mg/l. The availability of such guideline in-
formation limits the scope of investigative ef-
fort and is therefore of great assistance in the
design of developmental studies to rapidly
verify expected process performance on
specific waste flows.
Biological processes are capable of produc-
ing a range of effluent qualities. The penalties
associated with increased performance are
larger aeration units, larger clarification units,
and increased energy consumption. Energy
consumption is derived primarily from power
expended for aeration and agitation of
culture —plus heat requirements to maintain ac-
ceptable culture temperature in cold weather. It
is important that aeration/agitation
methodology not adversely affect settleability
of the activated sludge culture. Research is in-
dicated to identify optimized design concepts
that achieve process objectives at low energy
consumption and minimum cost.
Process Development
A vast literature of inconsistent study
findings is available to designers of activated
sludge processes for coke plants and gas
plants. Some degree of rationalization of study
findings is sometimes possible by interpreta-
tion of literature information within the con-
straints of process principles. Parenthetically, it
should be recognized that coal gas conden-
sates are highly colored and chemically com-
plex so as to pose analytical enigmas. Reported
values of biochemical oxygen demand (BOD)
may reflect interference due to toxicity.
Developmental analytical techniques are
recommended for reliable determination of
BOD n. Chemical oxygen demand tests, using
dichromate or permanganate, are subject to in-
terference from chlorides which often are
present in abundance. Compensation for
chloride interference was tedious prior to
modification of the COD test in 1963. The
primary condensates contain a host of phenolic
substances which may or may not be reported
by particular analytical methodology employed
in literature studies. Free cyanide will be in
equilibrium with metal cyanide complexes and
thiocyanate. Therefore, the concentration
registered by analysis may depend upon the
processing of the sample. Thus, discretion is in-
522
-------
dicated in the interpretation of literature infor-
mation. Improved interpretation of previous
studies would be possible if reliable correla-
tions between parameters were developed
through research.
Most studies of biological treatment of am-
monia still wastes have concluded that
phosphate is the only mineral nutrient supple-
ment required; whereas some studies advocate
addition of phosphate, magnesium, and
potassium12. Process fundamentals suggest
that the waste substrate should supply the
microorganisms with the mineral composition
required for synthesis of cell substance,
possibly similar to the guideline composition
given in Table 1. The elements carbon,
hydrogen, oxygen, nitrogen, and sulfur are in-
herently available in adequate quantity with ac-
tivated sludge treatment of ammonia still
waste. The elements phosphorous, sodium,
potassium, calcium, magnesium, and iron are
normally present in flushing liquor in low con-
centrations unless opportunity is provided for
leaching from gas-borne particulates. Ample
calcium is present after stripping in a lime still,
but the process effects virtually complete
precipitation of magnesium and phosphate.
Stripping in a caustic still induces precipitation
of calcium and magnesium.
Table 2 presents a hypothetical comparison
of approximate quantities of the nutrients pres-
ent in Synthane coal gasification process con-
densate and coke plant ammonia still feed, ver-
sus bacterial Composition from Table I
TABLE 1
REPRESENTATIVE ELEMENTAL COMPOSITION
OF DRY BACTERIAL PROTOPLASM
c
H
0
N
P
S
Wt%
50
5.8
27
12
2.5
0.7
Ma
K
Ca
Mg
Fe
Wt%
0.7
0.5
0.7
0.5
0.1
Adapted from: R. E. McKinney (13)
elements contained in Table 2 are of low
volatility and therefore tend to report to the
char and fines during gasification or coking.
The concentration levels in the condensate are
presumably dependent upon the degree of
leaching from the fines. The coke plant am-
monia still feed reflects contributions from
Phosam purge and light oil refining as well as
flushing liquor. The indicated calcium defi-
ciency would become a surplus if lime were
utilized in the ammonia stripping operation. The
indicated iron deficiency is generally less at
coke plants where higher concentrations of
cyanides are present and there is more oppor-
tunity for leaching of fines. The difference be-
tween the requirement and presence of potas-
sium in the condensate suggests a deficiency,
but most coke plant biological treatment proc-
esses perform well without supplemental
potassium nutrient. It is conceivable that at
coke plants potassium is leached from fines or
present in other feeds connected to the
biological plant.
To date, biological treatment of coke and gas
plant wastes has been characterized by limited
process stability. Until such occasional prob-
lems are resolved, the possible role of trace
nutrients should be kept under considera-
tion—especially in view of the variability in coal
feeds and the importance of magnesium as an
enzyme constituent. Most studies have in-
dicated that phosphate is the only nutrient ad-
dition required for biological treatment of
wastewater from coke and gas plants, but high
efficiency ammonia stripping may lower
residuals of magnesium and calcium (caustic
stills) and revisions in gas cleaning may reduce
the opportunity for leaching from gas-borne
particulates. Lower gas cyanide levels could
also limit the leaching of metals from par-
ticulates. Nutrient requirements for biological
processes can be evaluated relatively simply by
experimental procedures involving several
culture transfers in developmental type deter-
minations of BOD rates11. Such evaluations are
recommended on a case-by-case basis pending
resolution of the question.
Dilution of wastewater is sometimes ad-
vocated for biological treatment of coke plant
wastes. Dilution will lower the exposure of the
microorganisms to refractory substances such
523
-------
TABLE 2
HYPOTHETICAL COMPARISON OF TRACE NUTRIENT COMPOSITION VS.
INDICATED BACTERIAL REQUIREMENT FOR SYNTHANE CONOENSATE
AND COKE PLANT AMMONIA STILL FEED
Ca
Fe
K
Mg
Na
P
Indicated
Requirement
lb/1, 000 tons
10
2.8
14
14
20
70
Synthane Condensate9
Indicated
Present
lb/1 ,000 tons
5.1
0.28
0.78
1.6
19
0.12
Still Feed
Indicated
Present
lb/1 ,000 tons
5.9
3.2
16
3.5
95
57
"Illinois #6 Coal, Forney, A. J. et al. (14).
as salts and hard organics, but in the complete-
ly mixed activated sludge process, degradable
substances are present at effluent concentra-
tion levels —suggesting minimum justification
for dilution. Dilution can assist in the control of
calcium sulfate precipitation resulting from
reaction between residual calcium from lime
stills and sulfate formed during aeration by bio-
oxidation of thiocyanate and reduced sulfur
compounds.
Effluent Polishing
High dissolved solids in the feed to activated
sludge processes has been associated with in-
creased effluent suspended solids. In addition,
the culture of activated sludge systems
sometimes loses its ability to settle which
results in increased discharge of suspended
solids with the effluent. Such periods are
sometimes termed "upsets." However, if the
process is .viewed as operating in dynamic
equilibrium rather than in steady state, it is con-
ceivable that periods of loss of culture set-
tleability could be a part of the normal spectrum
of operations. In any event, the discharge of ex-
cess suspended solids is often difficult, and
sometimes impossible, to correct by adjust-
ment of plant operational practices. The im-
plementation of effluent polishing may be re-
quired to achieve effluent suspended solids
levels associated with domestic sewage ac-
tivated sludge plants. Granular media filtration
has been employed for effluent polishing, but
lamella dissolved air flotation has been
demonstrated as superior for the capture of
significant overages of suspended solids15. The
flotation process was capable of clarifying
feeds with 300 mg/l suspended solids to the
25 to 35 mg/l range. Dissolved air flotation
was also advantageous in that the captured
solids are collected in a low volume float in-
stead of a large volume backwash.
Research Trends
Preliminary absorption of halides is a concept
that has potential for improving water manage-
ment of coal conversion processes. The con-
cept, illustrated in Figure 2, features a con-
trolled temperature—controlled volume scrub-
bing operation followed by demisting to cap-
ture strong acid salts in a low volume purge.
The asset of the concept is that subsequent
condensates are low in strong acid salts and
therefore more applicable to incorporation in
recycle circuits. The low volume characteristic
of the purge concentrate will facilitate disposal
524
-------
RAW
GAS
DRY
CYCLONE
CHAR FINES
TAR
SCRUBBER
T
TAR
Ol
10
CJI
WET
SCRUBBER
MIST
ELIMINATOR
HIGH SALT PRIMARY CONDENSATE & TAR
INTERMEDIATE
COOLING
T
ADDITIONAL
->• GAS
CLEANING
LOW SALT
INTERMEDIATE CONDENSATE
Figure 2. Schematic of preliminary absorption of halides.
-------
or recovery, but the fate of the concentrate is
an unresolved aspect of the concept.
SUMMARY AND CONCLUSIONS
Modern coke plants provide fuel gas that is
highly acceptable for many industrial purposes.
Prior to use, the gas is processed for removal of
particulates, naphthalene, ammonia, hydrogen
sulfide, and light oils. The proven process
technology employed for coke oven gas clean-
ing is adaptable to the cleaning of cooled pro-
ducer gas for industrial consumption, but proc-
ess revisions would be required for the cleaning
of substitute natural gas. On a per ton of coal
basis, larger volumes of gas and larger volumes
of a more dilute condensate will be derived
from producer gas operations than from coke
plant operations.
The activated sludge process is commonly
employed for wastewater treatment at modern
coke plants. The process can be designed to
provide excellent removal of phenol, thio-
cyanate, BOD, and cyanide. The limitations of
activated sludge treatment of coke plant waste
are dark color in the effluent and occasional in-
consistencies in performance relative to thio-
cyanates, cyanides, and suspended solids. Ef-
fluent polishing by dissolved air flotation is
worthy of consideration inasmuch as the proc-
ess is better able to handle slugs of suspended
solids than filters. In addition, the float
separated from the flotation process is a con-
centrate rather than a dilute filter backwash.
Activated sludge technology is adaptable to
treatment of condensates from tar producing
coal conversion processes. The application of
the data base available from coke plant waste
treatment will reduce a research project to a
developmental project at a vast saving in time
and effort. Coal condensates may be deficient
in trace element nutrients such as magnesium
and potassium. Evaluation of nutrient ade-
quacy is recommended as part of develop-
mental studies. The nutrient situation may dif-
fer depending upon the efficiency of processes
for the removal of particulates and ammonia.
Preliminary absorption of halides is a concept
that has potential for improving water manage-
ment at coal gasification facilities. The separa-
tion of a low volume, high salt concentrate
would reduce disposal problems and increase
the feasibility of water reuse.
REFERENCES
1. H. H. Lowry, ed.. Chemistry of Coal
Utilization Volume II, John Wiley & Sons,
Inc., New York, 1945.
2. W. Rudolfs, Industrial Waste Treatment,
Reinhold Publishing Corp., New York,
1953.
3. B. A. Southgate, The Treatment and
Disposal of Industrial Waste Water,
H.M.S.O., London, 1948.
4. F. W. Mohlman, "Sewage Treatment with
Ammonia Liquor," American Journal
Public Health 19, 1. 145-154 (1929).
5. E. Nolte, H. J. Meyel, and E. Fromke,
"The Use of the Activated Sludge Process
in the Case of Industrial Sewage," GWF
das Gas und Wasserfach 8, Pt 1, pp.1 26-
47,1934.
6. D. G. Brinn, "A Select Bibliography on Ac-
tivated Sludge Plants," National
Technical Information Service, PB-236
358, August 1974.
7. G. L. Jones and J. M. Millar, "The
Biological Treatment of Coke-Oven Waste
Liquor," Steel & Coal, pp. 176-178, July
26, 1963.
8. P. D. Kostenbader and J. W. Flecksteiner,
"Biological Oxidation of Coke Plant Weak
Ammonia Liquor," Blast Furnace and
Steel Plant, 56, pp. 475-480, June
1968.
9. J. E. Ludberg and G. D. Nicks, "Removal
of Phenol and Thiocyanate from Coke
Plant Effluents at Dofasco," Water and
Sewage Works, 116 pp. 10-13, Nov.
1969.
10. E. M. Rudzki, K. R. Bureau, and R. J.
Horst, "An Improved Process for the
Removal of Ammonia from Coke Plant
Weak Ammonia Liquor," Iron and Steel
Magazine, pp. 28-33, June 1977.
11. H. E. Orford, M. C. Rand, and I. Gellman,
"A Single Dilution Technique for B.O.D.
Studies," Sewage and Industrial Wastes,
25, 3, pp. 284-289, 1953.
12. R. Jablin and G. P. Chanko, "A New Proc-
ess for Total Treatment of Coke Plant
526
-------
Waste Liquor," Water 1973, AlChE- Sharkey, "Trace Element and Major Corn-
Symposium. Series, 70, 136, 713, 22, ponent Balances Around the Synthane
1974. PDU Gasifier," National Technical Infor-
13. R. E. McKinney, Microbiology for Sanitary mation Service PERC/TPR-75-1, August
Engineers, McGraw-Hill Book Company, 1975.
Inc., New York, 1962. 15.' W. A. Parsons, "Activated Sludge Plant
14. A. J. Forney, W. P. Haynes, S. J. Gasior, Effluent Polishing," Proc. of 32nd In-
R. M. Kornosky, C. E. Schmidt, A. G. dustrial Wastes Conference, Purdue
University, May 10-12, 1977,
527
-------
FUTURE NEED AND IMPACT ON
THE PARTICULATE CONTROL
EQUIPMENT INDUSTRY DUE
TO SYNTHETIC FUELS
John Bush
Research-Cottrell, Inc.
Bound Brook, New Jersey 08805
Abstract
The growing demand for coal conversion
processes requires a concurrent assessment of
the equipment and systems needed for the con-
trol- of discharge pollutants entering the en-
vironment. The particulate control equipment
industry wilt be affected by the increased coal
consumption, by the advanced processes being
developed, and by the limitations of existing
collection systems. This paper presents an ex-
trapolation of the total energy growth in the
United States, its impact for coal consumption,
and the need for particulate control in each
process. Process control conditions are ex-
amined to show whether existing equipment
designs are adequate and to show where new
and developing designs are needed. The future
presents a continuing demand for particulate
control with greater emphasis on fine par-
ticulate collection and with new control condi-
tions for the advanced coal processes that are
expected to be commercialized by 1985.
INTRODUCTION
Energy consumption within the United States
has been increasing at a rapid growth rate, and
is expected to continue in the near future at the
same pace. By the year 2000, following this
extrapolated growth rate, the total energy con-
sumption1 will be double that amount presently
used during 1976 (Table 1). This increase in
energy demand can only be met through in-
creased coal production and through construc-
tion of nuclear energy plants. The coal produc-
tion required for a doubling of energy will be a
three-fold level above current production, in-
creasing from 13.5 quadrillion Btu to a new
level of 52 quadrillion Btu in 2000. This pro-
duction and use of coal could result in substan-
tial environmental damage, unless control
TABLE 1
ENERGY USE BY SOURCE (1015 Btu)*1)
Petroleum
Natural Gas
Coal
Nuclear
Hydro
Other
TOTAL
1976
34.9
20.2
13.6
2.1
3.0
....
73.8
2000
55
62.
34
3
6
150
technology is developed and applied now for
each developing coal process.
Coal conversion processes are being directed
along three major routes: (1) combustion to
produce heat and electricity; (2) gasification
which can result in either a high Btu synthetic
natural gas or in a low Btu producer gas for
nearby industrial use or for combined cycle
electrical generating; and (3) liquefaction to
produce oil and chemical feedstocks as a sup-
plement to diminishing supplies of petroleum
resources. Immediate production will em-
phasize combustion systems using available
burners and boiler systems. Following technical
development and ' environmental assessment
through 1985, advanced combustion systems
will be built, with a lesser impact due to the
gasification and liquefaction processes. All of
these processes will require particulate emis-
sion control and gaseous emission control,
with the degree of control specified by each in-
dividual conversion process and operating con-
ditions.
For any process the selection of a control
system must be based first on feasibility and
finally on economics. This selection procedure
(Figure 1) has three steps: (1) knowledge of
regulated emission levels and the amount and
type of pollutants present to be controlled; (2)
a description of all process streams with total
characterization of gas and particulate; and (3)
design choice alternatives for each particulate
control system. The emission standards are
established by Federal and State regulatory
agencies based on possible health and
ecological effects in the environment for each
528
-------
SELECTION PROCESS
EMISSION STANDARD
DESIGN EFFICIENCY
PROCESS
EQUIPMENT ALTERNATIVES
PLANT
FACILITY
COST
SELECTION
Figure 1. Participate control equipment selection procedure.
529
-------
individual pollutant. Each coal conversion proc-
ess has different designs, different operating
characteristics and different control locations
depending on downstream process equipment
and products. In each stream the gas and par-
ticulate need to be characterized for their
physical and chemical properties—a partial
listing is included in Table 2—that can affect
collection mechanisms and design specifica-
tions for a control system.
Using the detailed characterizations, each
alternative control system can be evaluated,
first, for a practical operating design, second,
for plant facility limitations of heat recovery,
waste treatment, space, water availability, pro-
duct recovery, and third for total costs based
on capital expenditures, power costs,
maintenance, and waste disposal. Using these
final costs a comparison of each control alter-
native and a final selection can be made.
COAL CONVERSION PROCESSES
Looking now at the individual processes, the
particulate control operating conditions and
design requirements can be evaluated for those
ranges where existing designs may be suffi-
cient and those where new designs must be
developed. Coal combustion has three major
process systems (Figure 2A): (1) direct com-
bustion of pulverized coal in a conventional
utility or industrial boiler; (2) atmospheric
TABLE 2
PARTICULATE CHARACTERISTICS
Ignition Point
Size Distribution
Abrasiveness
Hygroscopic Nature
Electrical Properties
Grain Loading
Density
Shape
Physical Properties
Explosiveness
GAS STREAM CHARACTERISTICS
Volume
Temperature
Pressure
Moisture
Corrosiveness
Composition
Odor
Explosiveness
Viscosity
Ionic Mobility
Thermal Conductivity
fluidized bed combustion; and (3) pressurized
fluidized bed combustion. The utility and in-
dustrial boiler designs are commercially
available and use "conventional" stack-gas
cleaning systems. Particulate control systems
have operated at gas conditions ranging bet-
ween 250° F and 800° F to collect fly ash par-
ticulate. Temperature varies with the location
in the process stream. Major design changes
reflect increased requirements for "fine" par-
ticulate removal and for cost reductions. At-
mospheric fluidized bed combustion produces
higher heat transfer coefficients for steam
generation and provides for S02 removal in the
reactor bed. Particulate removal will occur in a
stack gas clean-up system, similar to that used
for pulverized coal boilers. Emphasis for design
requirements is placed on the different par-
ticulate characterization. Pressurized fluidized
bed combustion is being developed for com-
bined cycle power generation utilizing a gas tur-
bine on the outlet gases. In this process, which
is expected for commercialization after 1985,
particulate collection must occur ahead of the
gas turbine, thus protecting the blades from
erosion by large particulate and from attack by
the higher alkali content of the fine particulate.
Operating conditions for particulate removal
will occur between 1500° F and 2200° F at
pressures above 10 atmospheres. This is a new
process operating range and will require exten-
sive development of control technology as the
process advances towards commercialization.
Gasification of coal (Figure 2B) is needed to
produce a clean fuel gas. The high Btu proc-
esses manufacture a synthetic natural gas that
will be piped via the existing natural gas
pipeline to individual customers. In this process
with the gas at a pressure of 1000 psi, par-
ticulate removal will occur prior to the catalytic
steps ugrading the gas. Operating temperature
are currently planned between 200° F and
800° F for particulate removal, with the higher
temperatures above 500° F preferred for solid
char removal and the lower temperatures
200-500° F required for tar mist removal. The
development of catalysts and acid-gas removal
systems that could operate at higher
temperatures would change the temperature
level required for particulate removal/Commer-
cial high Btu gasification will not make a major
530
-------
A. COMBUSTION
/
COAL
PREPARATION
/
\
1 \
PULVERIZED
COAL
BOILER
ATMOSPHERIC '
FLUIDIZED
BED BURNERS
CLEAN
UP
CLEAN
UP
•••^•^
STACK
STACK
PRESSURIZED
FLUIDIZED
BED BURNER
ft F AN
UP
TURBINE
B. GASIFICATION
COAL
PREPARATION
HIGH
BTU
GASIFIER
CLEAN
UP
SHIFT &
METHANATION
CATALYST
ATMOSPHERIC
LOW BTU
GASIFIER
CLEAN
UP
USER
PROCESS
PRESSURIZED
LOW BTU
GASIFIER
CLEAN
UP
TURBINE
OR USER
PROCESS
C. LIQUEFACTION
COAL
PREPARATION
SOLVATION
CLEAN
UP
SEPARATION
HYDROGEN-
ATI ON
CLEAN
UP
HYDRO
TREATMENT
&
SEPARATION
Figure 2. Coal conversion processes.
531
-------
impact before 1984. Atmospheric low Btu
gasification, a second process type, is ex-
pected to develop more rapidly, with some
commercial designs already in use in Europe
and Africa. For this process the gas is cleaned
and sent to a nearby industrial process or
boiler, with the degree of clean-up determined
from the end use requirements. Temperatures
for clean-up will range from 200-500° F for tar
droplets to 500-1100° F for char removal. Par-
ticulate collection systems are commercially
available for the low temperature range and can
be extended to the higher temperatures with
advanced material selection. Pressurized low
Btu gasification will be used (1) to either supply
more distant industrial users in a local pipeline
network or (2) in combined cycle power
generation. For the former end use, particulate
clean-up will occur at pressures from 10 to 30
atmospheres and for a temperature range bet-
ween 100° F and 600° F. For the combined
cycle system entering a combuster and gas tur-
bine, particulate removal under the same high
pressure must be performed at higher
temperatures above 1 200° F. The maximum
temperature will be controlled by the com-
bustor inlet conditions to prevent auto-ignition.
Coal liquefaction (Figure 2C) follows two
processes: (1) solvent extraction and (2)
catalytic hydrogenation. In the former, a
hydrogen donor solvent extracts the smaller
coal molecules producing a variety of tars, oils,
and gases and leaves a residue of char and
minerals. The gases, tars, and oils must be
separated and cleaned, usually under pressure
and at temperatures below 400° F. In the se-
cond hydrogenation reaction, the larger coal
molecules are split into smaller molecules pro-
ducing a higher concentration of lighter oils.
Purification and separation again occurs under
pressure at low temperatures.
In all of the above processes, particulate col-
lection is required in the main gas stream. In ad-
dition, secondary streams from residue com-
bustion, regeneration processes, and coal
preparation steps will require particulate con-
trol. Conditions found in the secondary streams
are generally similar to the established process
conditions with some variation in temperatures
or pressures. Commercially available equip-
ment with extended temperature limits and im-
proved performance designs will meet the re-
quirements for atmospheric pressure coal
systems currently preparing for commercializa-
tion. New designs and development are needed
for the higher temperature (500 to 2000° F)
and pressure (10-70 atm) collection re-
quirements found with pressurized fluidized
bed combustion, pressurized low Btu gasifica-
tion, and high Btu gasification processes that
are expected to be ready for commercialization
by - 1985.
PARTICLE CONTROL EQUIPMENT
Having examined the general operating
characteristics of the coal conversion proc-
esses, the particulate equipment to meet these
conditions can now be described. Particulate
control equipment choices fall into four major
classes (Figure 3): mechanical collectors, wet
collectors, filters, and electrostatic
precipitators. Each of these classes have ex-
isting commercial designs and developing
designs to meet the coal conversion process re-
quirements. New designs combining
mechanical, wet scrubbing, and electrostatic
mechanisms are being studied for fine par-
ticulate collection and evaluated to reduce size
and cost of an individual system.
Mechanical collectors usually consist of
cyclones or centrifuges which can be con-
nected in a series arrangement to attain higher
efficiencies. This class of collectors is limited to
the collection of particles larger than 5
MECHANICAL COLLECTORS
CYCLONES
CENTRIFUGES
WET COLLECTORS
SCRUBBERS
FILTERS
BAGHOUSES
GRANULAR BED FILTERS
ELECTROSTATIC PRECIPITATORS
Figure 3. Particulate control equipment alter-
natives.
532
-------
microns, and is generally used for a first stage
as a precollector of large paniculate.
Mechanical collectors can be designed for
essentially all of the temperatures and
pressures found in coal conversion.
Wet collectors such as scrubbers or wet elec-
trostatic precipitators can effectively collect
particulate at low temperatures. Both scrub-
bers end precipitators have been applied at high
pressures to 60 atmospheres in past commer-
cial designs. Consideration must be given to
the need and cost of additional waste water
treatment when applying these systems.
Temperature is a limiting factor for the liquid
being used as the spray or scrubbing media, in
that the gas must be saturated for efficient
operation with condensing droplets.
Filters operate by particulate collection on
fibers or granular beds. Baghouses consisting
of woven fabrics have operated at essentially
atmospheric pressure with temperatures rang-
ing to 550° F on industrial boilers and recently
on utilities. Material bag life is presently limited
in use to the temperatures below 600° F.
Granular bed filters and panel bed filters are
new designs developed primarily for high
temperature and pressure applications. These
filters collect fine particular by building a
"filter cake" from the collected particulate on-
to the granular bed. High pressure drops have
usually been found with these systems.
Electrostatic precipitators (wet or dry) have
long been in use for efficient collection of tar
and various types of dust in both industrial and
utility applications. New designs being funded
by industry, EPA, and utilities are aimed at im-
proving performance and reducing costs—both
capital and operational. Past experiences in
precipitation have found applications for at-
mospheric systems from 200 to 900° F and
for high pressure systems from 1 to 60 atm at
temperatures generally below 300° F.
Operating data is limited for each of the
above classes at the combined high
temperature and pressure needed for the
developing coal process conditions that exceed
existing control ranges, Several companies
under contract to EPA and ERDA are develop-
ing new designs and concepts for high
temperature and pressure particulate removal.
Consolidated Coal Company and Mechanical
Technology, Inc., are developing high efficien-
cy cyclones using a high pressure drop that col-
lects particulate above 5 microns. Series of
three to four cyclones are expected to be re-
quired to attain high collection performance.
Gravel bed or panel bed systems are being
developed and evaluated by Rexnord, Inc.,
Duccon (used at Exxon's miniplant), Air Pollu-
tion Technology, Inc., and Combustion Power
Company. Acurex Corporation/Aerortherm is
developing a ceramic bag filter for use at high
temperature and pressure. Westinghouse is
evaluating a ceramic membrane filter under
similar conditions. Air Pollution Technology is
evaluating a scrubber to be used at high
pressures and moderately high temperatures.
Research-Cottrell is developing high
temperature and pressure electrostatic
precipitators for use under all expected
operating conditions. Each developing control
system is being evaluated under laboratory and
pilot operation. Currently, performance predic-
tions and design criteria are poor or lacking at
these high temperatures and pressures. Both
gaseous and particulate characteristics are
essentially unknown. Pilot and demonstration
scale systems are needed to provide reliable
design data and material selection for long life
on all new particulate equipment. At high
temperatures, the efficiency of all control
equipment for any given size can be expected
to decrease due to the increasing value of the
gas viscosity; however, electrostatic
precipitators are unique in their collection
mechanism in that the migration velocity and
thus efficiency increases with an increasing ap-
plied voltage. Research-Cottrell is conducting a
precipitator program evaluating conditions to
500 psi and to 2000° F in air, combustion
gas, and a simulated fuel gas. These results
have found precipitation to be very favorable
for the higher gas densities found with high
pressures that maintain substantially higher ap-
plied voltages. These higher voltages are
capable of increasing precipitator efficiency
and reducing its size and cost. Corona current
was stable in all gas mixtures evaluated.
FUTURE IMPACT
Advanced designs and future control re-
quirements are evolving towards a higher col-
533
-------
lection efficiency of fine paniculate, minimal
energy consumption, control ranges at a varie-
ty of temperatures and pressures, and the
capability of handling changing particulate
properties due to variations in chemical com-
position and operating conditions. Catalytic
steps and turbine operation require clean-up
locations at the higher temperatures and
pressures leaving the coal conversion reactor.
Comparative performance evaluation com-
bined with capital investment, operating costs,
and maintenance will ultimately determine a
final control choice for any one process. The
varying process conditions will result in control
equipment systems being designed for specific
operating conditions, based on economics and
collection mechanisms.
In summary, coal conversion processes will
continue to require particulate removal, with
the particulate control equipment industry
growing at approximately the same pace as
coal use. Advanced developments requiring
high temperature and pressure particulate
removal will become commercialized around
1985. Atmospheric combustion processes in
utilities and industry will continue to grow prior
to that time. Each new design concept will be
required to efficiently remove fine particulate
under the given process conditions, rxew
design and process optimization between con-
trol system and conversion process will be re-
quired to minimize costs and improve perfor-
mance. Particulate control development must
occur now with the developing advanced coal
conversion processes if commercialization is to
be achieved at a minimal cost by 1 985.
REFERENCES
1. S. B. Alpert, "Commercialization of
Technology," Presented at 4th Annual
Conference on Coal Gasification, Li-
quefaction, and Conversion to Electricity,
August, 1977.
2. Bush, Feldman, Robinson— "High
Temperature, High Pressure Electrosatic
Precipitation"—to be published.
3. J. M. Marchello, Control of Air Pollution
Sources, Marcel-Dekker, Inc., (1976).
4. W. Straus, Air Pollution Control, Part I,
Wiley-lnterscience, 1971.
5. A. B. Walker, "Electrostatic Precipitators
and Fabric Filters—Changing Needs and
Solutions," June, 1977.
534
-------
FUTURE NEEDS AND THE IMPACT
ON THE WATER AND WASTE
EQUIPMENT MANUFACTURING
INDUSTRY DUE TO THE USE
OF SYNTHETIC FUELS
E. G. Kominek, P.E.
Technical Director, Water and Waste
Envirotech Process Equipment Division
Envirotech Corporation
Salt Lake City, Utah
Probably the most important needs of the
water pollution control equipment industry are
coal conversion wastewater characterizations
which can be used more specifically for the
design of chemical and/or biological waste
treatment systems. These should include
analyses which differentiate between organics
which are readily biodegradable, as indicated
by BOD5 analysis, slowly biodegradable com-
pounds which report as BOD2o and COD or
TOC determinations which would indicate by
difference the approximate concentration of
nonbiodegradable organic compounds.
Total Kjeldahl nitrogen determinations would
also be important for consideration of nitrifica-
tion—and possibly denitrification of plant ef-
fluents in the waste treatment plant designs.
Whenever possible, cell yield coefficients and
endogenous rate coefficients should be deter-
mined so that food/microorganism ratios and
sludge ages can be correlated for activated
sludge aeration basin design calculations.
Treatability factors for contact media unit
design would also be helpful for evaluation pur-
poses.
If laboratory facilities are available at pilot
plant installations, biological treatability tests,
including nitrification, should be made.
Denitrification studies would also have long-
range benefits. There are many cyclic organics
and metal salts which may interfere with
nitrification or denitrification and it may be
necessary to pretreat to remove metal salts, or
to feed powdered activated carbon into the
biosystems to adsorb organics which could in-
terfere with the biological processes.
The DuPont Waste Treatment Plant at their
Chambers Works in New Jersey and the API
study recently made at the Texaco plant, Port
Arthur, Texas, have demonstrated the benefits
of powdered activated carbon in activated
sludge systems treating organic chemical
wastes and petroleum-petrochemical wastes.
This may also be true of coal gasification and li-
quefaction wastewaters.
The evaluation of biosystem plant design
must take into consideration the potentially
toxic effect of high concentrations of chemicals
resulting from spills or upsets in the plant
operations. The recovery time of a biosystem
can be long —so this is an important operational
consideration.
The need for surge and also backup treat-
ment units must be evaluated for each system
being considered. Before going into final
design, pilot plant tests under the worst condi-
tions which can be anticipated may indicate a
preferred waste treatment process.
Biological sludge disposal can be an impor-
tant factor. Excess biological sludge production
varies appreciably. With 30-day sludge age and
temperature of 10° C-30° C, it will range
from 0.3 to 0.41 Ibs of sludge being produced
per Ib. of BOD removed. The biosludge can only
be concentrated to about 3 percent to 4 per-
cent without filtration—so the volume is ap-
preciable.
It would be to ERDA's advantage to in-
vestigate:
Anaerobic treatment of strong wastes
Aerobic treatment using contract
media and activated sludge
With atmospheric oxygen
With pure oxygen
Wet air oxidation of strong wastes
Backup facilities required ,o hanHie
upsets.
This should include granular ac-
tivated carbon and reverse osmosis
as polishing operations.
Characterizations of inorganic wastes are
also important. Segregation of inorganic
wastes can simplify treatment and save
money. Most heavy metals in cationic form will
precipitate to very low residual concentration
as hydroxides or sulfides. Chemical treatment
will release and allow precipitation of metal
complexes, at least when treating waste solu-
tions from boiler-cleaning operations.
535
-------
Cooling tower blow-down can be minimized
by appropriate makeup water of sidestream
treatment. In many cases, the silica concentra-
tion of the cooling water determines required
blow-down. It would help to have complete
mineral analysis of the raw waters and
knowledge of the planned cycles of concentra-
tion for optimizing the design of cooling
systems to reduce blow-down.
Spent ion exchange regenerants in boiler
blow-down should be kept out of the
wastestreams which require biological treat-
ment. The systems can be designed for partial
recovery of ion exchange regenerants and rinse
waters, thereby reducing the wastewater ef-
fluent volume.
As gasification and liquefaction processes
become more refined, evaluations of water and
waste treatment methods under comparable
conditions will help in selecting the most cost
effective methods based upon capital cost and
energy requirements. They will also provide
reasonable assurance of reliable operations
under the varying wastewater characteristics
from gasification or liquefaction plant opera-
tions which are inevitable.
And now, for a discussion of the projected
impact of the synthetic fuels industry on the
water pollution control equipment industry.
The production of synthetic fuels will have an
impact. However, it appears at this time that
any major effects of coal conversions will not
be felt until the mid-1980's or later. Current
coal conversion processes are directed toward
pilot plant or demonstration plant testing. Ap-
parently this will continue until about 1 980.
According to ERDA's F'78 Fossil Energy
Research Program1, there are ten coal liquefac-
tion, five pyrolysis, eight high Btu coal gasifica-
tion, and nine low Btu coal gasification projects
budgeted for further tests. ERDA's budget proj-
ects an increase from about $350 million in
F'77 to $448 million in F'78 to maintain the
coal program. $53 million in expenditures are
projected for demonstration plants in
F'77 —and only $50 million, in F'78.
The Fossil Energy Coal Program has five
categories of projects:
1. Laboratory bench-scale
2. Process development units
3. Pilot plants
4. Demonstration plants
5. Commercial demonstration plants
The only two which will involve significant
expenditures for liquid waste treatment are:
• Demonstration plants operating a
single modular unit using commercial
sized components to demonstrate and
validate economic environmental and
production parameters;
• Commercial demonstration plants to
establish actual economic factors and
environmental feasibility. These will be
three to five times the capacity of
demonstration plants by combining
modular production units.
The larger installations projected include the
H Coal Direct Hydrogenation Process Pilot Plant
at Ashland Synthetic Fuels, Catlettsburg, Ken-
tucky. This plant has a coal input of 600 TPD.
It is in the procurement and construction stage
and operation is projected through the third
quarter of F'80.
The Solvent Refined Coal Liquefaction Proc-
ess, budgeted at $ 1 6 million in F'78 includes a
pilot plant with a capacity of 50 TPD coal at
Pittsburgh and Midway Coal Mining, Ft. Lewis,
Washington.
The Donor Solvent Liquefaction Process
budget is scheduled for $30.3 million in F'78.
Exxon Research and Engineering, Baytown,
Texas, will operate a process development unit
through the third quarter of F'81. A pilot plant
is scheduled for design and construction over a
2.5-year program in operation from F'80
through three quarters of F'81.
The major budgets for High Btu Gasification
Processes are:
Bi-Gas - 120 TPD coal pilot plant,
Bituminous Coal Research,
Homer City, Pennsylvania. Pilot
plant operation scheduled
through third quarter F'79.
Synthane - 75 TPD coal pilot plant, Pitts-
burgh Energy Research Center,
Pittsburgh, Pennsylvania.
Operation scheduled through
middle of F'79.
Hy-Gas - 80 TPD pilot plant, Institute of
Gas Technology, Chicago, Il-
linois. Project evaluation by end
of F'79.
536
-------
C02
Acceptor - 40 TPD coal pilot plant, Con-
solidation Coal/Conoco Coal
Development, Rapid City,
South Dakota. Project evalua-
tion by end of F'79.
The major budgets for Low Btu Gasification
Projects are:
Lurgi combined cycle test facility for
Commonwealth Edison at Pekin, Il-
linois, capacity 480 TPD coal. The
plant is to operate through F'82.
Hydrogen from coal facility, capacity
200 TPD coal is projected to operate
from F'81 for about three years.
Combustion Engineering, Windsor,
Connecticut, has a 120 TPD at-
mospheric entrained bed gasification
unit in operation. It is scheduled for
evaluation in F'79.
R. Antonsen2, Assistant Program Director,
Division of Major Facility Program Management
of the ERDA, has reported that:
"Two pipeline gas projects are in the
conceptual design phase. It is
estimated that an evaluation of the two
projects will be made in about June
1978. The estimated input of one of
the projects is 3800 TPD of coal.
The other project involves a con-
ceptual design of a pipeline gas plant
using the IGT Hy-Gas Process. This is
projected to use 7500 TPD of coal.
A fuel gas project under considera-
tion plans to use 2800 TPD of coal.
Another involves 2270 TPD of coal.
An atmospheric fluidized bed com-
bustion unit is planned using 1 600 TPD
of coal.
A solvent-refined coal project is pro-
jected using 600 TPD of coal."
It is significant that several contractors had
submitted proposals for demonstration plants
in 1976. However, as of July 1 977, these pro-
posals were still being evaluated.
ERDA's Office of Commercial Applications
advised that any projects which require finan-
cial assistance from the Federal government
would need funds voted by Congress after
review and approval by the Department of
Energy. There apparently are not commercial
size gasification or liquefaction projects that
are being prepared for presentation to Con-
gress for funding in F'78. It would appear that
unless projects are funded by industry, the
processes currently being publicized will have
to go through the demonstration plant stage
with ERDA assistance before full-scale plants
are considered.
Pilot plant or demonstration plants in the 400
to 600 TPD coal capacity range would
probably have commercial scale water and
waste treatment plants. The others would be
more or less in the pilot waste treatment
category. It therefore does not seem likely that
the United States will be far beyond the com-
mercial demonstration plant stage before 1 985
unless an international crisis or the need for a
major project to stimulate the U.S. economy, or
a program to reduce an unfavorable trade
balance through and accelerated synthetic fuel
program, changes the priorities.
But, if we ignore the question of "when,"
the following provides some indication of the
potential long-range impact of the water and
waste treatment needs of coal gasification and
liquefaction plants.
C. F. Braun made a comprehensive study
which is detailed in the Interim Report, "Fac-
tored Estimates for Western Coal Commercial
Concepts"3, prepared for ERDA and the
American Gas Association. This report was
published in October 1 976. These plants were
evaluated on a comparable basis, with coal
consumptions of approximately 8 million
tons/year per plant, each with a capacity to
produce about 250 million cubic feet/day of
synthetic gas.
Coal gasification plants use considerable
water. Table 14 lists the estimated water re-
quirement for a Lurgi Process plant processing
21,800 TPD of coal. Based upon 5100gpm in-
put, 79.8 percent of the water is consumed in
proccess or is lost by evaporation. The makeup
water requirements of the six processes vary as
shown on Table 2. Note that the estimated raw
water usage of the six systems range from
about 114,000 to 203,000 GPH.
Table 3 shows the estimated water treat-
ment costs, ranging from $285,000 to
$580,000, to clarify or lime-soften the
makeup water. Granular media filtration tnd
537
-------
TABLE 1
WATER REQUIREMENTS AND DISPOSITION OF A LURGI COAL
GASIFICATION PLANT PROCESSING 21,800 TPD OF COAL
PROCESS CONSUMPTION
TO SUPPLY HYDROGEN 1,120
PRODUCED AS METHANATION BYPRODUCT -600
NET CONSUMPTION 520 10,2
RETURN TO ATMOSPHERE
EVAPORATION:
FROM RAW WATER PONDS 420
FROM COOLING TOWER 1,760
FROM QUENCHING HOT ASH 150
FROM PELLETIZING SULFUR 250
FROM WETTING OF MINE ROADS 750
w m 3'310
VIA STACK GASESU):
FROM STEAM BLOWING OF BOILER TUBES 200
FROM STACK GAS S02 SCRUBBERS
TOTAL RETURN TO ATMOSPHERE 3,350 69,6
'DISPOSAL TO MINE RECLAMATION
IN WATER TREATING SLUDGES 100
IN WETTED BOILER ASH 30
IN WETTED GASIFIER ASH 300
TOTAL DISPOSAL TO MINE 430 8,4
OTHERS
RETAINED IN SLURRY POND 20
MISCELLANEOUS MINE USES 580
TOTAL OTHERS 600 11,8
GRAND TOTAL 5,100 100,0
NOT INCLUDE WATER DERIVED FROM
BURNING OF BOILER FUEL
boo
-------
TABLE 2
PROCESg
IGT STEAM OXYGEN HY-GAS
IGT STEAM IRON HY-GAS
CONOCO C02 ACCEPTOR
BCR BI-GAS
PERC SYNTHANE
LURGI
RAW WATER
GPH
114,000
203,000
136,000
129,000
150,000
146,OOn
demineralization equipment was estimated to
range from $709,000 to $2,450,000. Adding
the estimated costs for deaeration equipment,
sodium exchange for low pressure boilers and
ion exchange equipment for condensate
polishing, the estimated equipment cost ranged
from $1,742,000 to $3,335,580. The
estimated installed costs ranged from $3.5 to
$6.7 million.
It has been predicted that two SNG coal-
based plants will be in operation and producing
0.16 x 1015 Btu per year by 19855. Another
forecast indicates 0.4 x 1015 Btu per year,
which would indicate the need for five plants,
each processing 8 million tons of coal/year. If
we assume that the water treatment equipment
for these plants would be purchased in 1981 or
1982, the estimated cost of the water treat-
ment equipment in 1977 dollars would be in
the range from $3.5 to $6.7 million for two
plants and $8.5 to $ 17 million for five plants.
Table 4 compares the costs of waste treat-
ment equipment and auxiliaries for the six proc-
esses studied by Braun. The estimated cost of
equipment for chemical coagulation, flotation
to remove tars and oils and staged activated
sludge treatment, together with aerobic diges-
tion, thickening and vacuum filtration of waste
sludge would range from about $2.6 to $5.3
million per plant. With pumps and tanks added,
the estimates range from about $3 to $6.1
million. Estimated installed costs assume that
the civil works would be about 80 percent of
the total costs—or in the range fronr $ 1 " .3 to
$30.5 million.
The estimates are all based upon the ise of
western coal. The type of coal used v/ou 1 have
a significant effect upon the '--astewater
analyses as shown in Table 56. However, as
there are many other variables whic i would in-
fluence the cost of waste treatment plants at
the time when they are considered for final
design, any closer estimates would have to be
made on a case by case basis, using the latest
technologies for coal conversion and for vaste
treatment.
It is assumed that on a comparable coal ton-
nage basis, the wastewater from coal liquefac-
tion processes would have about the same
pollution load as the coal gasification projects
and that the treatment costs would be in the
same order of magnitude. The estimation of
either two or five plants by 1 985 would have a
moderate impact. However, the water and
waste treatment equipment manufacturing in-
dustry should be operating at a high level in the
early 1980's because of equipment ex-
penditures for compliance with the EPA's BAT
standards which are scheduled to go into effect
in 1983. As the present guidelines will
probably be supplemented by additional stan-
dards for compliance with the Toxic
Substances Control Act, the impact of an addi-
tional $6 million to $30 million in waste treat-
ment equipment and appurtenances for coal
conversion plants would not be significant.
539
-------
TABLE 3
WATER TREATMENT
DRY COAL TO PROCESS
TONS/HR
RAW WATER
GAL/HR
LIME SOFTENING -
g CLARIFICATION
0
FILTERS AND
DEMINERALIZERS
DEAERATORS
SODIUM EXCHANGERS
CONDENSATE POLISHERS
TOTAL
ESTIMATED INSTALLED
COSTS
IGT STEAM
OXYGEN HYGAS
568
114,000
$ 285,000
980,000
212,000
105,000
160,000
$1,742,000
$3,500,000
IGT STEAM
IRON HYGAS
742
203,000
580,000
2,450,000
295,000
340,000
250,000
3,335,580
6,700,000
CONOCO
C02 ACCEPTOR
699
136,000
330,000
1,470,000
185,000
—
220,000
2,205,000
4,400,000
BCR
BIGAS
578
129,000
350,000
1,310,000
330,000
290,000
350,000
2,630,000
5,300,000
PERC
SYNTHANE
929
150,000
345,000
790,000
420,000
340,000
—
1,895,000
3,800,000
LURGI
632
146,000
435,000
900,000
255,000
510,000
—
2,100,000
4,200,000
-------
TABLE 4
WASTEWATER TREATMENT
DRY COAL TO PROCESS
TONS/HR
RAW WATER
GAL/HR
ORGAN I CS REMOVED BY
BIOLOGICAL TREATMENT
LBS/HR
EQUIPMENT
TANKS
PUMPS
TOTAL
ESTIMATED INSTALLED
COST
WASTEWATER
EVAPORATORS
IGT STEAM
OXYGEN HYGAS
568
114,000
6,600
$ 3,992,000
382,000
150,000
$ 4,524,000
$22,620,000
$ 5,800,000
IGT STEAM
IRON HYGAS
742
203,000
8,000
5,311,000
507,000
283,000
6,101,000
30,505,000
15,000,000
CONOCO
C02 ACCEPTOR
699
136,000
6,400,000
BCR
BIGAS
578
129,000
9,800,000
PERC
SYNTHANE
929
150,000
5,100
3,305,000
285,000
146,000
3,736,000
18,680,000
8,100,000
LURGI
632
146,000
1,200
2,631,000
288,000
150,000
3,069,000
15,345,000
8,800,000
-------
TABLE 5
BYPRODUCT WATER ANALYSIS FROM SYNTHANE GASIFICATION
OF VARIOUS COALS, MG/L (EXCEPT pH)
SUSPENDED SOLIDS
PHENOL, .,..,,,,,
COD ,
THIOCYANATE,
CYANIDE
NHg 1 1 1 1 1 1 i 1 1 1 1 1 1
CHLORIDE
CARBONATE ,,
BICARBONATE
TOTAL SULFUR,,,,
COKE
PLANT
9
50
2,000
7,000
1,000
100
5,000
-
-
-
-
ILLINOIS
NO, 6
COAL
8,6
600
2,600
15,000
152
0,6
^,100
500
26,000
2IL,000
31,400
WYOMING
SUBBI-
TUMI-
NOUS
COAL
8,7
v/« 1
140
6,000
zi3 nnn
23
0,23
9,520
-
-
-
-
ILLI-
NOIS
CHAR
7 9
/ , j
24
200
1 700
-L,/ UU
21
0,1
2,500
31
-
-
-
NORTH
DAKOTA
LIGNITE
9 2
jit.
64
6,600
38 nno
•J\jj UUU
22
0,1
7,200
-
-
-
-
WESTERN
KENTUCKY
COAL
8 Q
Oi J
55
3,700
IQ mn
X3,uuu
200
0,5
10,000
—
—
_
-
PITTS-
BURGH
SEAM
COAL
Q 3
Jtj
23
L700
10 finn
j~3,mu
188
0,6
1LOOO
-
_
_
-
3s=
]85 PERCENT FREE NH3
2NOT FROM SAME ANALYSIS
= 400
SOf = 300
sqf = 1,400
s2oj = 1,000
542
-------
The reference previously cited also forecasts
2.5 x 1015 Btu per year for synthetic gas pro-
duced from coal in the year 2000. If correct,
there would be a need for about 31 plants each
having a gas production capacity of 250 million
cubic feet/day. This would have a major impact
on the water and waste equipment manufactur-
ing industry and on the entire economy
because of the general stimulus it would have
on industry. Each coal conversion plant in
terms of 1976 dollars, was estimated by C. F.
Braun to range in total cost from $0.87 to
$1.28 billion.
A survey by Frost and Sullivan, Inc.7
estimated that 20 plants would be in operation
by 1990, producing 1.6 trillion cubic feet of
gas/year. This is reasonably close to the 1.8
trillion cubic feet which would be the capacity
of 20 plants each having capacity of 250
million cubic feet/day.
Attempting to relate projected expenditures
for coal conversion plants to total sales for
water and waste treatment equipment is dif-
ficult. Accurate information regarding the
market for water and wastewater equipment
has been virtually impossible to obtain since
the Office of Business Research and Analysis of
the Bureau of Domestic Commerce of the U.S.
Department of Commerce discontinued main-
taining summaries of water supply and
wastewater disposal treatment equipment
shipments. Annual reports of the major com-
panies are consolidated and do not help very
much. Published reports of expenditures or
forecasts are either based upon total installed
costs, including civil works, or do not indicate
what is classified as equipment. In addition, the
forecasts seldom indicate what dollars are used
in the forecasts.
There have been predictions that equipment
expenditures for water and waste treatment
will be in the range between $1.5 and $2.0
billion in the 1980-1985 period. What may oc-
cur after that is highly speculative because
water shortages in certain geographical areas
probably will necessitate major expenditures
for treatment of sewage plant effluents for in-
dustrial use. Enforcement of the zero effluent
concept would also add appreciably to waste
treatment equipment expenditures, so the long-
range impact of coal conversion plants on the
demand for water and waste treatment equip-
ment cannot be predicted at this time.
REFERENCES
1. MOR/8 "Wastewater Treatment Plant
Design," p. 237, Water Pollution Con-
trol Federation, Washington, D.C.,
1977.
2. "Fossil Energy Research Program of
the Energy Research and Development
Administration", F'78, ERDA 77-33,
April 1977.
3. "The Developing Demonstration Plant
Program", ERDA-Fossil Energy, R. An-
tonsen, July 14, July 14, 1 977.
4. "Factored Estimates for Western Coal
Commercial Concepts, Interim
Report", Roger Detman, October
1976, Prepared for the United States
Energy Research and Development Ad-
ministration and the American Gas
Association, Under Contract No.
E(49-18)-2240.
5. "Coal Gasification by the Lurgi Proc-
ess", S. F. Kreminik, AlChE 11th An-
nual Meeting, Los Angeles, California,
April 16, 1974.
6. "Industrial Energy in the United States-
The Role of Coal, Natural and Synthetic
Gas and Nuclear Power", D. G. Gambs,
Volume 60, No. 8, August 1977/TAP-
Pl.
7. "Analysis of Tars, Chars, and Water
Found in Effluents from the Synthane
Process", A. J. Forney, W. P. Haynes,
et al., U.S. Department of the Interior,
Technical Progress Report 76, January
1974.
8. "Energy Roundup", Business Week,
August 24, 1974.
543
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TECHNICAL REPORT DATA
(Please read Inziructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-78-063
3. RECIPIENT'S ACCESSION NO.
4 T,TLE AND SUBTITLE SYMPOSIUM PROCEEDINGS: Environ-
mental Aspects of Fuel Conversion Technology, HI
5. REPORT DATE
1978
April
(September 1977, Hollywood, Florida)
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Franklin A. Ayer and Martin F. Massoglia,
Compilers
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Research Triangle Institute
P.O. Box 12194
Research Triangle Park, North Carolina 27709
10. PROGRAM ELEMENT NO.
E HE 62 3 A
11. CONTRACT/GRANT NO.
68-02-2612
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD CC
Proceedings; 4/77-2/78
COVERED
14. SPONSORING AGENCY CODE
EPA/600/13
15 SUPPLEMENTARY NOTESIERL-RTP project officer is William J. Rhodes, Mail Drop 61,
919/541-2851.
16. ABSTRACT
The report covers EPA's third symposium on the environmental aspects of
fuel conversion technology. The symposium was conducted in Hollywood, Florida,
September 13-16, 1977. Its main objective was to review and discuss environmen-
tally related information in the field of fuel conversion technology. Specific topics
were program approach, environmental assessment, and control technology
development.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COS AT I Field/Croup
Air Pollution
Fuels
Conversion
Environmental
Engineering
Environments
Process Variables
Industrial Processes
Control
Measurement
Air Pollution Control
Stationary Sources
Environmental Assess-
ment
Control Technology
13B 13H,07A
21D
14B
05E
3. DISTRIBUTION STATEMEN1
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
549
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
544
. GOVERNMENT PRINTING OFFICE: 1978-740-26V 340
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