United States Industrial Environmental Research EPA-600/7-78-190
Environmental Protection Laboratory October 1978
Agency Research Triangle Park NC 27711
Applicability of
Petroleum Refinery
Control Technologies
to Coal Conversion
Interagency
Energy/Environment
R&D 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 m 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
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This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-190
October 1978
Applicability of Petroleum
Refinery Control Technologies
to Coal Conversion
by
M. Ghassemi, D. Strehler, K. Crawford, and S. Quinlivan
TRW, Inc.
One Space Park
Redondo Beach, California 90278
Contract No. 68-02-2635
Program Element No. EHE623A
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park. NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington. DC 20460
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ABSTRACT
This report has been prepared as part of a comprehensive program for the
environmental assessment of high Btu gasification technology. The program is
being directed by the Fuel Process Branch of EPA's Industrial Environmental
Research Laboratory, Research Triangle Park, North Carolina.
Due to certain gross similarities which exist between refinery and coal
conversion waste streams and the considerable experience which exists in re-
finery pollution control, the evaluation of the applicability of refinery con-
trol technologies to coal conversion is a logical step in the assessment of
coal conversion control technology needs. Lurgi, Koppers-Totzek and COED pro-
cesses were examined as example processes for high-Btu, low/medium-Btu and
liquefaction coal conversion processes, respectively. The process/waste
streams from these processes were characterized and those streams having refin-
ery counterparts were identified. As part of the program, toxicological and
health effects data on select waste stream constituents were also collected.
The control technologies currently used in refineries for the management of
the identified streams were evaluated and their applicability to counterpart
coal conversion streams was assessed.
The results of the study indicate that, despite a number of similarities
between the refinery process/waste streams and their coal conversion counter-
parts, there are significant composition differences between the analogous
streams which would affect applicability and design of a control technology.
Many of the refinery processes which appear to have applicability to coal con-
version process/waste streams have not been tested in such applications and
additional testing would be necessary to generate data needed for a more accu-
rate determination of their applicability.
11
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CONTENTS
Abstract ii
Figures vi
Tables vi
Acknowledgement 1x
1.0 Introduction 1
2.0 Summary and Conclusions 2
3.0 Recommendations 11
4.0 Characteristics of Petroleum Refinery Waste Streams 12
4.1 Gaseous Waste Streams 12
4.1.1 Stream No. 1, Process Sour Gases 15
4.1.2 Stream No. 2, Catalyst Regenerator Off-Gases .... 18
4.1.3 Stream No. 3, Fugitive Emissions 21
4.1.4 Stream No. 4, Condenser Off-Gas 22
4.1.5 Stream No. 5, Transient Emissions 22
4.1.6 Stream No. 6, Flue Gases 23
4.1.7 Stream No. 7, Air Blowing Gas 23
4.2 Liquid Waste Streams 24
4.2.1 Stream No. 1, Sour Waters 24
4.2.2 Stream No. 2, Spent Caustic 27
4.2.3 Stream No. 3, Oily Waters 28
4.2.4 Stream No. 4, Clean Waters 30
4.2.5 Stream No. 5, Slop Oil 30
4.3 Solid Waste Streams 31
4.3.1 Stream No. 1, Process Solids 31
4.3.2 Stream No. 2, Waste Treatment Solids 34
4.3.3 Miscellaneous Nonprocess .Solids 36
5.0 Characteristics of Coal Conversion Waste Streams 38
5.1 Coal Conversion Processes 38
iii
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CONTENTS (CONTD)
5.2 Gaseous Waste Streams 40
5.2.1 Stream No. 1, Raw Product Gas 40
5.2.2 Stream No. 2, Acid Gases 43
5.2.3 Stream No. 3, Raw Fuel Gas from Liquefaction .... 44
5.2.4 Stream No. 4, Acid Gases from Hydrotreating .... 45
5.2.5 Stream No. 5, Fugitive Air Emissions 46
5.2.6 Stream No. 6, Flue Gas 46
5.2.7 Stream No. 7, Cooling Tower Gas 47
5.2.8 Stream No. 8, Coal Preparation Vent Gases 47
5.2.9 Stream No. 9, Feed and Ash Hopper Vent Gas 48
5.3 Liquid Waste Streams 48
5.3.1 Stream No. 10, Quench and Condensate Waters from
Gasification 48
5.3.2 Stream No. 11, Waste Liquor Purge from Product
Separation 50
5.3.3 Stream No. 12, Separated Water from Hydrotreating . 51
5.3.4 Stream No. 13, Waters from Shift and Methanation . . 51
5.3.5 Stream No. 14, Miscellaneous Plant Waste Waters . . 52
5.3 Solid Waste Streams 52
5.4.1 Stream No. 15, Spent Catalysts 52
5.4.2 Stream No. 16, Sludges 53
5.4.3 Stream No. 17, Particulates from Coal Preparation . 53
5.4.4 Stream No. 18, Ash or Char from Coal Conversion . . 53
5.4.5 Stream No. 19, Ash from Coal Burning 54
6.0 Refinery Control Technologies and Their Applicability to Coal
Conversion Systems 55
6.1 Gas Processing and Control of Gaseous Emissions 55
6.1.1 Acid Gas Treatment Processes 55
6.1.2 Sulfur Recovery 59
6.1.3 Tail Gas Treatment 62
6.1.4 Incineration (Flaring) of Waste Gases 66
6.1.5 Control of Fugitive Emissions and Odors 67
6.2 Aqueous Waste Processing and Water Pollution Control ... 68
1v
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CONTENTS (CONTD)
6.2.1 Sour Water Stripping 59
6.2.2 Oil and Suspended Sol Ids Removal 70
6.2.3 Dissolved/Particulate Organics Removal by Biological
Oxidation 73
6.2.4 Dissolved Organics Removal by Activated Carbon
Adsorption 77
6.2.5 Chemical Oxidation of Organics and Reduced
Inorganics 79
6.2.6 Treatment of Slop Oil and Sludges 80
6.2.7 Approaches to Waste Volume and Strength Reduction . 82
6.3 Solid Waste Management 84
6.3.1 Resource Recovery 84
6.3.2 Incineration 85
6.3.3 Land Disposal 86
7.0 Health and Ecological Effects of Selected Constituents in Refinery
and Coal Conversion Process/Waste Streams 90
7.1 Purpose and Scope 90
7.2 Polycycllc Aromatic Hydrocarbons (PAH) 98
7.3 Heavy Metals and Organometallic Compounds 101
7.4 Aromatic Compounds 102
7.5 Control Technologies 108
8.0 References 112
FIGURES
Number Page
4-1 Major Refinery Process and Gaseous Waste Streams 13
4-2 Gas Treatment and Sulfur Recovery Operations 17
4-3 Refinery Liquid Waste Streams - 25
5-1 Generalized Flow Plan for Coal Conversion Process 41
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TABLES (CONTD)
Number Page
2-1 Similar Refinery and Coal Conversion Wastes Streams 6
2-2 Refinery Control Technologies and Their Applicability to
Coal Conversion 8
4-1 Characteristics of Pertinent Process/Waste Gaseous Streams
in a Refinery and Applicable Control Technologies 14
4-2 Gas Treatment and Sulfur Recovery Stream Compositions .... 16
4-3 Sour Gas Treating Stream Composition, Vol %' MEA-Claus
System 17
4-4 Sour Gas Treating Stream Composition, Vol %i 2-Stage and
3-Stage Claus 18
4-5 Sour Gas Treating Stream Composition, Vol %'> Claus Plant with
SCOT, Beavon, Wellman-Lord, IFP-1, Chiyoda Thoroughbred 101
and Sulfreen Tail Gas Treatment Systems 19
4-6 Composition Range for Fluid Bed Catalytic Cracking Regenerator
Off-Gas 20
4-7 Refinery Liquid Waste Streams 26
4-8 Sour Water Characteristics 27
4-9 Refinery Oily Water Characteristics 29
4-10 Refinery Solid Waste Streams 32
4-11 Process Solids Characteristics 33
4*-12 Effluent Treatment Solids Characteristics 35
4-13 General Wastes Characteristics 37
5-1 Coal Conversion Processes Reviewed 39
5-2 Major Gaseous Waste Streams from Coal Conversion Processes . . 42
5-3 Comparison of the Compositions of Coal Gasification Quenched
Raw Product Gas and Refinery Sour Gas 43
5-4 Comparison of the Recovered Acid Gases from Rectisol and
Benfield with Those in Refineries 44
5-5 Characteristics of Hydrotreating Acid Gases for the COED
Process 45
5-6 Major Liquid Waste Streams from Coal Conversion Processes . . 49
5-7 Comparison of the Condensates from Gasification and
Refineries 49
5-8 COED Waste Liquor Purge Stream Composition 50
5-9 Hydrotreating Separated Water Composition 51
5-10 Solid Waste Streams From Coal Conversion Plants 52
vi
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TABLES (CONTD)
Number page
5-11 Ash and Char Characteristics 54
6-1 Key Features of Solvent Processes Used in Refineries for Acid
Gas Removal 57
6-2 General Characteristics of Claus and Stretford Sulfur Recovery
Processes 61
6-3 Key Features of Sulfur Recovery Plant Tail Gas Treatment
Processes 64
6-4 Efficiency of Biological Treatment for Petroleum Refinery
Effluents 73
6-5 Solids Concentration Obtained by Various Sludge Concentrating
Processes 81
7-1 Principal Constituents of Refinery Streams Having Counterparts
in Coal Conversion Waste Streams 91
7-2 Summary of Hazardous Properties of Some Ubiquitous Constituents
of Refinery and Coal Conversion Wastes 92
7-3 Classes of Known or Suspencted Carcinogenic PAH and Analog
Compounds Associated with Processing and Utilization of
Petroleum and/or Coal and Toxicity Data 99
7-4 Summary of Toxicological and Environmental Data for Major Heavy
Metals Associated with Refinery and Coal Conversion Operations 103
7-5 Toxicological Data on Select Organometallies Associated with
Refinery and/or coal Conversion Waste Streams 106
7-6 Summary of Toxicological and Environmental Data for Select
Aromatic Compounds Associated with Refinery and/or Coal
Conversion Wastes 109
vtt
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ACKNOWLEDGEMENT
The project is deeply indebted to the EPA Project Officer, Mr. William J.
Rhodes, for his continuing advice and guidance during the course of the effort.
Those on the project staff wish to express their gratitude to the process
developers/licensors who supplied data for use in the report.
Special thanks are due to Mr. Charles F. Murray, the TRW Program Manager,
for interfacing with EPA and for providing project support services. The
authors wish to express their sincere gratitude to Mrs. Maxine Engen for her
editorial review and secretarial services.
vltf
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1.0 INTRODUCTION
Recognizing the dwindling domestic supplies of natural gas and crude oil
and the importance of reducing the country's current dependence on foreign
sources of energy, government and private industry are currently expending
considerable effort to develop alternate sources of domestic fuel. Because
of the abundance of mineable coal reserves in the U.S., the greater use of
coal, directly or after conversion to substitute natural gas or oil products,
is one of the alternatives receiving serious consideration. Development of a
viable synthetic fuel industry must be accompanied by efforts to anticipate
environmental problems, identify control technology needs, and develop appro-
priate controls and bases for establishing regulations.
In response to the shift in the U.S. energy supply priorities from
natural gas and oil to coal, the Environmental Protection Agency has initiated
a comprehensive assessment program to evaluate the environmental impacts of
synthetic fuels from coal processes having a high potential for eventual com-
mercial application. This overall assessment program is being directed by
the Fuel Process Branch of EPA's Industrial Environmental Research Laboratory,
Research Triangle Park (IERL-RTP). The primary objectives of the EPA synthe-
tic fuels from coal program are to define the environmental effects of synthe-
tic fuel technologies with repsect to their multimedia discharge streams and
their health and environmental impacts and to define control technology needs
for an environmentally sound synthetic fuel industry. The synthetic fuel
technologies being addressed in the EPA program include high Btu gasification,
low/medium Btu gasification and coal liquefaction. Under a contract with EPA,
TRW is currently conducting an environmental assessment of high Btu gasifica-
tion technology. One element of this program involves the evaluation of the
applicability of petroleum refining control technologies to the production of
synthetic fuels from coal.
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The potential for the application of refinery controls to synthetic fuel
production stems from certain gross similarities which exist between the waste
streams in the two industries. Petroleum refining is a well-established in-
dustry. Many types of pollution control equipment and systems are in use in
refineries and the industry has been very active in developing new environ-
mental control technologies and improving the existing ones to minimize dis-
charges and to meet environmental regulations. The objective of this program
has been to identify and review those refinery control technologies which
would have application to coal conversion process/waste streams. The effort
has consisted primarily of a review of the available data to (a) determine and
characterize refinery process/waste streams which have counterparts in coal
conversion facilities; (b) review control technologies which have been applied
to the identified refinery waste streams and other refinery control techno-
logies which may be applicable to coal conversion streams not having counter-
parts in petroleum refining; and (c) evaluate the applicability and adapt-
ability of the refinery control technologies to coal conversion. In addition,
data were collected on toxicological and health effects of potentially hazard-
ous components in analogous refining and coal conversion waste streams.
The data used for process/waste stream characterization and for control
technology evaluation were obtained from several sources including (a) pub-
lished and unpublished EPA documents, (b) open literature, (c) process devel-
opers and EPA/DOE contractors, and (d) authorities in industry and academic
institutions. Based on the preliminary review of the collected data, a
number of coal conversion and related processes, which were judged to have a
greater likelihood of being employed in commercial facilities, were selected
and analyzed in more detail. For each coal conversion process and refinery
control technology reviewed, a data sheet was prepared presenting key infor-
mation items and thereby imparting high visibility to engineering "facts and
figures," allowing ready comparison between alternate processes, and under-
lining specific areas where significant gaps existed in the available data.
To assure the completeness and accuracy of the information, where applicable,
the data sheets on the processes reviewed were forwarded to the process devel-
opers/licensors for review and comment. A complete set of the data sheets
prepared has been incorporated as Appendices to a separate document entitled
"Environmental Assessment Data Base for High-Btu Gasification Technology,"
2
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prepared for EPA under the current contract. The sources used in the pre-
paration of the data sheets have been identified in each sheet. In this re-
port the references to the sources of data which were extracted directly from
the data sheets have not been repeated.
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2.0 SUMMARY AND CONCLUSIONS
As a first step in the determination of the applicability of the refinery
control systems to coal conversion waste streams, the refinery waste streams
were reviewed and those likely to have counterparts in coal conversion were
characterized. Based on the considerations of (a) availability of data on
waste stream characteristics, (b) attainment of or nearness to commercial
status, (c) representation of integrated operations producing upgraded or re-
fined gaseous or liquid products, and (d) avoidance of duplicity in related
EPA programs, three coal conversion processes were selected as examples of
high-Btu gasification, low/medium-Btu gasification and liquefaction techno-
logies. These processes are Lurgi, Koppers-Totzek and COED. The process/
waste streams from these processes were characterized and those streams having
refinery counterparts were identified. The refinery control technologies were
then evaluated from the standpoint of applicability to counterpart waste
streams in coal conversion.
Compared to the relatively large amount of actual data available for
many refinery waste streams, very few data are available for waste streams
generated in integrated commercial coal conversion plants. The insufficiency
of characterization data on coal conversion waste streams, which constitutes
a major obstacle to accurate and detailed assessment of the applicability of
refinery control technologies to coal conversion waste streams, stems pri-
marily from the nonexistence of commercial SNG and liquefaction facilities in
the U.S. and from the nonapplicability of some of the data from U.S. pilot coal
conversion facilities to large-scale operations. For many of the unit opera-
tions where some discharge stream characterization data are available, such
data are not comprehensive in that not all streams are addressed and not all
potential pollutants and toxicologlcal and ecological properties are defined.
Commercial gasification and liquefaction facilities in operation in foreign
countries do not generally incorporate design and operating features which
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would likely be employed in a facility in the U.S. to minimize waste genera-
tion and to control discharge. Moreover, the coals used at these facilities
differ from those which will be employed at commercial plants in the U.S.
Although many of the unit operations for gas and liquid processing which may
have applications in commercial coal conversion have been tested or used com-
mercially in other industries, their performance in coal conversion service
has often not been evaluated.
Based on the review of the available data and from a control technology
applicability viewpoint, a limited number of refinery and coal conversion
process/waste streams appear to have certain similar characteristics. These
streams and the basis for their similarities are listed in Table 2-1. Despite
the noted similarities, there appears^ to be significant composition differ-
ences between the analogous streams which would affect applicability and de-
sign of a control technology. For example, while both the refinery process
sour gases and the quenched product gas from coal gasification contain hLS
and (XL, the H«S concentration is considerably higher and the COg level is
significantly lower in most refinery sour gases (16%-65% vs. l%-2% and 2%-S%
vs. 7%-32%j respectively). Even when selective H«S removal processes are used,
the treatment of the coal conversion raw product gas results in the production
of a concentrated acid gas stream with COg levels much higher than those in
refinery sour gases. Unlike sour waters from refineries which contain high
levels of both sulfides and ammonia, most coal conversion condensates con-
tain low levels of sulfide and moderate levels of ammonia. Because of the
differences in the nature of the raw material (crude oil vs. coal) and the
processing steps employed, the dissolved and particulate organics (oils, tars,
organic acids, etc.) found in coal conversion wastes are different than those
in refinery wastewaters. The organics in coal conversion wastes are gener-
ally more aromatic while those in refineries are largely aliphatic. These
differences in wastewater characteristics also are reflected in the charac-
teristics of oily sludges and biosludges resulting from wastewater treatment.
In comparing coal conversion waste streams with their analogues in refineries.
it should be noted that there can be wide differences between stream composi-
tions from different coal conversion plants depending on the coal processed,
conversion process used and on-site product upgrading methods employed.
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TABLE 2-1. SIMILAR REFINERY AND COAL CONVERSION WASTE STREAMS
Coal Conversion Counterparts
Major Similarities
Gaseous
Process sour gas
Catalyst regenerator
off-gas
Fugitive emissions
Liquid
Sour waters
Oily waters
Solid
Spent catalysts
Sludges
Quenched product gas, add gas and
fuel gas (from liquefaction)
Raw product gas and char combus-
tion flue gas
Fugitive emissions
Raw product gas quench condensate
waste liquor purge (from lique-
faction) and shift condensate
Raw product gas quench condensate
and waste liquor.purge (from
liquefaction
Spent shift, methanation, hydro-
treating, and Claus plant catalysts
Oily and biosludges
High HgS and aimonia content;
presence of
High CO and particulates, NOX and N2
Hydrocarbons, sulfur compounds,
ammonia
Ammonia, sulfide, phenols, oils and
grease/tars
Oil and grease/tar; phenols
Metals (Ni, Co, Mo, etc.), bauxite
Oil and grease/tar,, inerts, biomass,
refractory organlcs!
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The refinery control technologies which may find application to coal
conversion are listed in Table 2-2. Some of the control processes (e.g.,
sulfur recovery plant tail gas treatment processes) would be applicable to
waste streams in a coal conversion plant and their design may be essentially
the same as in refinery applications. Other processes such as Stretford,
Claus and steam stripping would require extensive modifications to account for
differences in waste compositions. Because of limited data on certain waste
characteristics (e.g., biodegradability of organics and settleability of sus-
pended solids in wastewaters), the applicability and efficiencies of processes
such as bio-oxidation, flotation, sludge dewatering, and emulsion breaking in
coal conversion application cannot be accurately assessed at this time. With
the exception of very few processes which have been tested in coal conversion
applications (e.g., Rectisol and DGA acid gas treatment processes and Stret-
ford tail gas treatment process), the processes listed in Table 2-2 have not
been employed in such an application. For the processes which have been used
in coal conversion, only limited data are available on process design and per-
formance. Even though the processes listed in Table 2-2 appear applicable to
coal conversion wastes, the true test of applicability and definition of cri-
teria for large-scale design and cost estimation require additional testing.
It should also be noted that the suitability of a control process for use in
coal conversion plants cannot be determined separately from other processes
and waste treatment operations within an integrated coal conversion facility.
The selection of a specific control process is merely an element in the over-
all .waste management plan for a facility which includes considerations of
overall emissions/effluent limitations, energy and raw material availability
and costs.
Some of the components in refinery and coal conversion wastes are impor-
tant from the standpoint of presenting potential occupational health hazards
to plant workers and adverse health impact on the general population. Several
of the hazardous waste components, i.e., HgS, CO and mercaptans, are not
unique to refinery or coal conversion wastes and are emitted from a variety
of other industrial and nonindustrial sources. The hazardous characteristics
of many of these commonplace substances are generally well documented. The
hazardous chemicals which are unique to coal conversion and refineries fall
into three categories: polynuclear aromatics, heavy metals and organometallic
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TABLE 2-2. REFINERY CONTROL TECHNOLOGIES AND THEIR APPLICABILITY TO COAL
CONVERSION
Refinery Control Technology
Applicability to Coal Conversion Waste Stream
Acid Gas Treatment
Amine Solvents
(DEA, Fluor Econamine,
ADIP, etc.)
Physical Solvents
(Selexol, Rectisol, etc.)
Sulfur Recovery
Claus
Stretford
Tail Gas Treatment
IFP-1, Sulfreen
SCOT, Beavon and Cleanair
Potentially suitable for non-selective re-
moval of H£S and C0£ from product gases from
atmospheric/low pressure gasification/lique-
faction. Also suitable for hydrocarbon re-
moval from concentrated acid gases and for
concentrating dilute ^S streams for feeding
to Claus plant. Extensive solvent degrada-
tion may be encountered in coal application.
Potentially suitable for selective removal
of H2S and C02 from product gases. Best
suited to high pressure application. The
resulting concentrated acid gas stream may
contain high levels of hydrocarbons, thus
requiring further treatment prior to sulfur
recovery.
Split-flow mode applicable to coal conver-
sion acid gases containing more than 10%
H2$. Sulfur burning mode applicable to
feeds containing as low as 5% H2$. Removal
of ammonia and hydrocarbons from feed gases
would be required to prevent ammonium bi-
carbonate scaling and carbon deposition on
catalyst, respectively.
Most existing applications are to acid gases
containing low levels (around 1%) of H2S.
High C02 levels necessitate pH adjustment
and result-in high blowdown rates. Rela-
tively large unit sizes would be required
with high C02 gases. Process does not
remove non-H2S sulfur compounds.
Suitable for Claus plant tail gas treatment;
cannot achieve very low levels of total sul-
fur in the off-gas which may be required by
emission regulations. Efficiency decreases
with increasing C02 level in the feed.
Sulfur removal efficiencies decrease and CO?
levels in tail gas increase when acid gases
contain high COg levels
8
(continued)
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TABLE 2-2. CONTINUED
Refinery Control Technology
Applicability to Coal Conversion Waste Stream
Tail Gas Treatment (contd)
Chiyoda Thoroughbred 101,
Wellman-Lord, IFP-2 and
Shell CuO
Fugitive Emissions and Odor
Control
Vapor recovery, incineration,
source elimination
Sour Water Stripping
Conventional Stripping and
Chevron WWT Process
Oily Water Treatment
API Separator and Flotation
Biological Wastewater Treatment
Carbon Adsorption and Chemical
Oxidation
Slop Oils and Sludge Treatment
(thickening, centrifugation,
emulsion breaking, drying beds)
In-Plant Waste Volume and
Strength Reduction
Resource Recovery
Incineration
Land Disposal
Potentially suitable. Requires feed incin-
eration to convert reduced sulfur to S02-
Applicable to analogous sources.
Applicable to coal conversion sour waters.
The design must be modified to allow for the
lower sulfide and often higher ammonia
levels in coal conversion sour waters.
Applicable; units must be designed based
on specific wastewater characteristics.
Generally applicable; blodegradability of
coal conversion waste components not
established.
Should be applicable; design basis must be
established for the specific wastewater.
Generally applicable; design basis must
be established for the specific waste.
Applicable.
Applicable to spent catalysts for material
recovery; sale of tars/oils
Applicable to organic wastes, incinerator
and emission control designs would be feed
specific.
Applicable.
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compounds, and low molecular weight aromatic substances. Many of the control
technologies used in both refineries and coal conversion plants should result
in partial or total removal of the hazardous waste components. The fate of
many of the hazardous components in pollution control processes is not well-
known, and the requirements for additional controls cannot be defined at this
time.
10
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3.0 RECOMMENDATIONS
Additional data on the characteristics of waste streams from coal conver-
sion plants are needed and should be obtained from process developers and
through sampling and analysis at commercial and pilot plant facilities.
Very few performance data are available on certain control units which
are known to be in operation at a number of specific refineries. Data
available on these units should be solicited from the plants. If ade-
quate data are not currently available, a sampling and analysis program
should be conducted to generate the needed data.
A few refinery control technologies have been used in coal conversion and
similar applications (e.g., coke and natural gas industries). Engineering
and actual performance data on these processes should be obtained from
owners/licensors or through plant monitoring.
The performance of refinery control technologies which appear applicable
to coal conversion waste streams should be evaluated through laboratory,
bench- and pilot-scale testing using actual or simulated coal conversion
wastes. Such testing should generate the necessary data for scale-up and
cost estimation and should enable more accurate definition of process
capabilities and limitations.
Because of the reported wide variations in stream compositions among re-
fineries, it is possible that a stream composition in some refineries may
be closer to its counterparts in a coal conversion plant than a similar
stream in another refinery. Asssitance should be solicited from refin-
eries or their trade association to Identify such streams and to obtain
performance data on any control technologies applied.
11
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4.0 CHARACTERISTICS OF PETROLEUM REFINERY WASTE STREAMS
Gaseous, liquid and solid discharges from petroleum refining operations
are identified and characterized in this chapter. Only the refinery streams
which may correlate with those expected from coal conversion processes are
characterized. Thus, some significant sources of petroleum refinery emissions
may not be detailed in this chapter because similar streams are not likely to
be encountered in coal conversion processes.
Rates and characteristics of emissions from petroleum refineries may vary
significantly because of differences in the nature of crude oils refined and
in the operating conditions and/or processes employed. The waste streams
identified and characterized in this chapter generally represent those for a
"typical" modern refinery and are based on information published in the
literature.
4.1 GASEOUS WASTE STREAMS
Figure 4-1 shows a typical modern refinery with major product and gaseous
waste streams. Seven categories of gaseous process/waste streams (numbered
1 through 7), which constitute the major emissions from a refinery, are iden-
tified. General descriptions of these streams, including their sources,
major contaminants and control technologies currently used (if any), are pre-
sented in Table 4-1.
The seven streams listed in Table 4-1 were reviewed from the standpoint
of (a) similarity of composition to the process/waste streams in coal conver-
sion facilities, and (b) applicability of the currently used refinery control
technologies to a process/waste stream in coal conversion plants. Based on
composition similarity considerations, two streams (Stream Nos. 1 and 2) were
determined to have possible counterparts in coal conversion. Detailed com-
position data were collected for these two streams.
12
-------
MISCELLANEOUS
EMISSIONS
ATMOSPHERIC
DISTILLATION
CRUDE
CO
-» LUBE OIL
-* ASPHALT
» COKE
ASPHALT/RESIDUUM
VACUUM DISTILLATION
ZJJCTFUEL
ALKYLATE
SPENT ACID
DIESEL FUEL
GASOLINE
NONCONDENSABLES
Figure 4-1. Major Refinery Process and Gaseous Waste Streams^1!) ($ee Table 4-1 for Waste Stream
Descriptions)
-------
TABLE 4-1. CHARACTERISTICS OF PERTINENT PROCESS/WASTE GASEOUS STREAMS IN A REFINERY AND APPLICABLE
CONTROL TECHNOLOGIES^)
Stream
No.
Process/Waste Stream
Source(s)
Major
Contaminants
Existing Control
Technology
1
2
3
4
5
6
7
Process sour gases
Catalyst regenerator
off-gas
Fugitive emissions
Condenser off-gas
Transient emissions
Flue gases
Air blowing gas
Process units (e.g.,
hydrotreating, frac-
tionating, etc.)
Catalyst regenerators
Compressors, drains,
vacuum jets, storage
tanks, and loading
facilities; waste
effluent handling and
sludge disposal
Barometric or surface
condensers
Various units opera-
ting in a non-steady
state mode (e.g.,
start-up, shut-down,
malfunctions, etc.)
Boilers, furnaces,
heaters, etc.
Air blowing
See Tables 4-2
through 4-12
See Table 4-6
HC, odors
HC, odors
HC, odors
HC, SOX, NOX, and
particulates
HC, odors
Collection and treatment
for sulfur recovery
CO boilers and electro-
static precipitators
Design improvements and/
or vapor collection and
recovery
Incineration (flare)
Incineration (flare)
Fuel substitution and/or
operational modifications
Process modification
(e.g., use of mechanical
agitators)
-------
The refinery control technologies used on Streams 3, 4 and 5 (vapor recov-
ery and incineration) were identified to have possible applications in coal
conversion plants for hydrocarbon control from vents, storage tanks, etc.
The vapor recovery and incineration technologies and the control technologies
associated with Streams 1 and 2 and their applicability to coal conversion
process/waste streams are evaluated in Section 6.1.
Stream 6 (flue gas) has counterparts in coal conversion, but the refinery
control (use of clean fuel and operational modification) would have very
limited applicability to coal conversion (see Section 5.2.6). Stream 7, air
blowing off-gas, has no counterpart in coal conversion plants.
Brief descriptions of the seven streams listed in Table 4-1 and the ratio-
nale for the selection of streams/refinery technologies for technology appli-
cability evaluation follows.
4.1.1 Stream No. 1, Process Sour Gases
Sour gases containing hydrocarbons and sulfur impurities are sent to a
sour gas treating unit for sulfur removal (see Section 6.1). The "sweetened"
(cleaned) gas can then be used to fire process heaters, furnaces and boilers
without requiring flue gas cleaning.
Figure 4-2 presents a schematic diagram of gas treatment and sulfur re-
covery, identifying the input, intermediate and product streams. The input
stream (No. 1) which originates from various refinery process vessels varies
considerably in composition. (In a refinery, the gas treating units are often
located near the process units and may handle gases from only one or several
nearby units.) The input sour gas is generally high in HgS content (a range
of 16% to 62% has been reported, see below) and contains a significant amount
of hydrocarbons.
°' F~OA> FBOMfr.
PROCESS UNITS W
1
FUEL GAS TO
t PROCESS UNITS
«
GAI
r« ATMS NT
PLANT
A pm nAflvs ^
1A
SULPUR
PLANT
TAIL O " ^
IB P
TAIL-OAS I
CLEAN UP r
PLANT J
* *
TO ATM ^
1C
IP fc
SULPUR TO SALES
Figure 4-2. Gas Treatment and Sulfur Recovery Processes (stream numbers refer
to compositions shown in Tables 4-2 through 4-5)
15
-------
Several different processes are currently used in refineries for sour
gas treatment, sulfur recovery and sulfur plant tail gas treatment (see Sec-
tion 6.1). The compositions of the intermediate and product streams (Stream
1-A, 1-B, 1-C, 1-D and 1-E in Figure 4-2) from these operations would depend
on the nature of the processes employed as well as the composition of the in-
put sour gas. Only limited waste stream data have been reported for a few
of the process combinations which are currently in use. These data are sum-
marized in Table 4-2 and are detailed in Tables 4-3, 4-4, and 4-5 for the pro-
cess combinations identified.
TABLE 4-2. GAS TREATMENT AND SULFUR RECOVERY STREAM COMPOSITIONS^'4'9'5'6*7)
Parameter
Components , Vol . %
H2S
S02
Sg vapor/mist
COS
CS2
C02
H20
N2
H2
CO
NH3
Methane
Ethane
Propane
Isobutane
N-Butane
Pentane
Hexane
Total HC
Temperature
Pressure
Gas Treatment
1
16.4 - 62.5
1.9 - 4.9
8.4
4.36 - 5.2
4.6
2.5
7.5
3.4
1.0
48°C
1A
50.3 - 91.9
4.6 - 46.1
0.1
0.95 - 2.0
40 °C
Sulfur Plant
IB
0.5 - 1.20
0.25 - 0.60
0.01 - 0.02
0.03 - 0.05
0.03 - 0.50
0.04 - 3.5
26 - 33.9
56 - 65
1.6 - 2.5
1.0
140°C
0.15 MPa | 0.15 MPa
Tail Gas
1C
0.0 - 0.03
10 - 250 ppm
0.1-1 ppm
3.05 - 19
5.0 - 7.0
80.8 - 88.9
0.96
40 °C
0.10 PMa
16
-------
TABLE 4-3. SOUR GAS TREATING STREAM COMPOSITIONS, VOL %: MEA-CLAUS SYSTEM
^
Gas Stream
Components/Parameters
H2S
so2
co2
N2 + inerts
Methane
Ethane
Propane
Isobutane
N-Butane
Pentane
Hexane
HC
Stream Designation*
1
62.5
4.9
--
8.4
5.2
4.6
2.5
7.5
3.4
1.0
1A
91.4
--
8.15
--
0.45
IB
1.07
0.89
--
3.35
32.31
62.38
--
--
--
*See Figure 4-2 for stream definitions
17
-------
TABLE 4-4. SOUR GAS TREATING STREAM COMPOSITION, VOL % ; 2-STAGE AND 3-STAGE
CI_AUS(4)
Gas Stream
Components /Parameters
H2S
so2
s
co2
H20
N2
°2
Methane
NH3
HC
2-Stage
1A*
50.3
--
46.1
1.0
2.5
Glaus*
IB
0.7
0.3
0.2
21.8
25.5
51.5
--
2-Stage
1A
83.5
--
11.5
4.0
0.4
0.5
0.1
Claust
IB
0.8
0.4
0.3
4.4
33.9
60.2
--
3 -Stage Claus
1A IB
90.0 1.0
0.5
__
3.0 3.5
30
65
__
2
*Stauffer Chemical Co., Baytown, Texas refinery
tStauffer Chemical Co., Long Beach, Ca. refinery
*1A and IB refer to streams shown in Figure 4-2.
As discussed in Section 5.2, the counterpart of the refinery sour gas in
a coal conversion plant is the quenched product gas which in a commercial facil-
ity will be treated for the removal of sour components. The composition of
the quenched product gas differs from that of the refinery sour gas (Stream 1,
Figure 4-2) primarily with respect to the concentrations of C02, H2S, CO and
. The quenched product gas generally contains a considerably smaller con-
centration of H2S and significantly higher concentrations of C02, H« and CO.
4.1.2 Stream No. 2, Catalyst Regenerator Off -Gases
The typical composition range for the fluid catalytic cracking off-gas
is presented in Table 4-6. As indicated in this table, the off-gas generally
18
-------
TABLE 4-5. SOUR GAS TREATING STREAM COMPOSITIONS, VOL X; CLAUS PLANT WITH SCOT, BEAVON, WELLMAN-LORD,
IFP-1, CHIYODA THOROUGHBRED 101 AND SULFREEN TAIL GAS TREATMENT SYSTEMS(4)
Gas Stream
Components/Parameters
H2S
so2
Sg vaporHnlst
S
COS
csz
CO
co2
HC (W:30)
"2
HjO
2
Ethane
°2
Tenperature
Pressure
Gas Treating
(type unknown)
1A«
89.9
~
~
-
--
--
4.6
--
--
5.0
~
0.5
--
310°X (104°F)
0.15 HPa(21 psla)
Claus
IB
0.85
0.42
0.05
--
0.05
0.04
--
0.22
1.60
33.10
61.30
..
--
410°K (284«F)
0.15 HPa(21 psla)
SCOT
1C
0.03
--
--
--
10 ppm
1 ppm
--
3.05
0.96
7.00
88.9
--
310°K (104"F)
Q.10 HPa(15 psla)
Beavon
1C
10 ppm
0.0
--
0.0
75 ppm
75 ppm
0.29
4.49
0.08
0.30
6.59
88.24
--
0.0
310"K (104T)
0.1 HPa(15 psla)
Hel Iran-Lord
1C
--
250 ppm
--
--
--
--
5.33
--
--
8.88
83.98
--
1.81
316°K (110°F)
0.1 MPa(15 psla)
IFP-1
1C
0.085
0.042
--
0.050
0.050
0.075
0.219
2.376
1.607
33.990
61.545
--
--
390°K (247'F)
--
Chlyoda
Thoroughbred
101
1C
--
0.10
-
"
4.928
--
15.582
77.822
--
1.579
330°K (130°F)
0.1 NPa(15 psla)
SulfrMn
1C
0.180
0.085
0.013
0.051
0.050
0.222
2.39
1.62
33.44
61.93
--
310"K (284"F)
0.1 HPa (15 psla)
MA, IB and 1C refer to streans shown In Figure 4-2.
-------
contains significant concentrations of particulates and carbon monoxide. In
refinery practice the carbon monoxide is converted to carbon dioxide in a "CO
boiler" (which also recovers the sensible heat) and the particulates are re-
moved by an electrostatic precipitator prior to the discharge of this stream
to the atmosphere.
TABLE 4-6. COMPOSITION RANGE FOR FLUID BED CATALYTIC CRACKING REGENERATOR
OFF-GAS*
Constituents
so2
S03
Aldehydes
Organic Acids
HC (as Hexane)
Particulates
C02 (dry)
CO (dry)
02 (dry)
N2 (dry)
Moisture
Temperature
Pressure
Mole %
0.12 - 0.16
less than 0.001
0.001 - 0.005
0.01 - 0.035
0.0005 - 0.002
0.1 - 0.3
0.7 - 35 g/Nm3 (0.3-15 grains/scf)
6-9
6 - 7
1 - 3
81 - 87
10 - 35
873-943°K (100-1250°F)
0.13 - 0.37 MPa (5-40 psig)
*The concentrations shown (excluding particulates, C02 and CO) are those
reported by the Los Angeles Air Quality Management District based on tests
of local refineries(10; ; other pollutant concentrations are from Reference
11.
20
-------
The closest counterparts of the refinery catalytic regenerator off-gas in
a coal conversion plant are the raw (quenched) product gas, the vent gases
from lockhoppers, and char combustion flue gases in processes such as Cogas.
The similarity to these coal conversion gases relates primarily to the pre-
sence of CO and high temperature and the particulate content of the gas. Un-
like the raw product gas in a coal conversion plant which is generally high in
COg and contains reduced sulfur compounds, the regenerator off-gas is rela-
tively low in C02 content and contains oxidized sulfur species (mostly S02).
The refinery control technology (use of electrostatic precipitators) probably
would not be applicable to the processing of coal conversion product gas due
to the potential for explosion and the fact that the quenching of the raw pro-
duct gas which immediately follows gasification results in the removal of
particulates. Furthermore, electrostatic precipitators are not generally
suited to high pressure applications.
As indicated in Table 4-6, the regenerator off-gas contains a high con-
centration of nitrogen. When nitrogen is used for lockhopper pressurization
in a coal conversion plant, the lockhopper vent gas is expected to be similar
to the regenerator off-gas since it would contain a relatively high concentra-
tion of nitrogen in addition to its high temperature and particulate content.
High temperature electrostatic precipitators, which are sometimes used for the
fo\
treatment of regenerator off-gasv , may be applicable to the control of lock-
hopper vent gases.
4.1.3 Stream No. 3. Fugitive Emissions
Fugitive emissions consist primarily of hydrocarbons and odors which are
emitted from a variety of sources in a refinery such as pumps, compressors,
storage tanks, drains, open piles, wastewater and sludge processing units,
etc. Controls employed on this type of emission depend on the source. For
example, fugitives from open drains are commonly controlled by covering the
drain and providing a liquid seal to reduce emissions. For pumps, the fugi-
tive emission control consists of using mechanical (rather than packed) seals.
For storage tanks either floating roof or vapor recovery systems are used
depending on the vapor pressure of stored materials).
21
-------
The characteristics and quantities of fugitive emissions vary within a
refinery and among different refineries depending on the emission source
(pumps, tanks, etc.), properties of the material handled (volatility, viscosity,
pressure, temperature, etc.), age of the equipment and maintenance practices.
Since some of the equipment and facilities used in refineries will also be
employed in coal conversion plants, such plants are expected to have some of
the same sources of fugitive emissions as those encountered in refineries.
Although the composition of the fugitive emissions from coal conversion plants
might be somewhat different that those from refineries (due to the differences
in equipment, products handled and operating conditions), some of these same
types of controls will be applicable to coal conversion plants (see Chapter 6.0).
4.1.4 Stream No. 4t Condenser Off-Gas
Barometric condensers are used in refineries (along with vacuum jets) to
obtain the vacuum required to operate some process equipment. Mater is brought
into direct contact with the gas. Mainly for water pollution control reasons,
the trend in refining practice has been to replace barometric condensers with
surface condensers (indirect cooling); surface condensers are also used in all
new U.S. refineries. Unless controlled, the lighter hydrocarbons that are not
condensed are released to the atmosphere. Incineration is generally used for
(2)
the control of these hydrocarbonsv '.
The off-gas from barometric or surface condensers does not have a counter-
part in coal conversion plants. The incineration control technology which is
employed in refineries for the management of the off-gas, however, may have
applications in coal conversion.
4.1.5 Stream No. 5, Transient Emissions
Transient emissions are generally associated with start-up and shutdown
of equipment and with equipment failures and emergencies. The characteristics
of these emissions would vary with the specific type of transient condition
and the type of operation/equipment involved. Transient emissions can be
minimized by preventive maintenance, proper design for their control and use
of appropriate operating procedures. In current refinery practice, transient
emissions are controlled by the use of flares. The use of flares for emis-
sion control is briefly reviewed in Section 6.1.4.
22
-------
4.1.6 Stream No. 6, Flue Gases
In refineries, flue gases are emitted from furnaces, boilers and heaters
contained in process units or used in steam plants. Because of the process
requirements, many of the refining units employ individual, direct-fired,
heaters. Accordingly, depending on the size of the refinery, the type of
operation employed, and the number of units involved, a large number of rela-
tively small sources of flue gas emissions may exist in a refinery. The quan-
tity and nature of pollutants from each source depend on the type of fuel
used and the operating conditions. The types of fuel most commonly used in
refineries are internal products, by-products and waste products (e.g., off-
gases from sour gas treatment, oily wastes, product oil) and natural gas. In
the United States, refinery practice for the control of flue gas emissions
has been to use clean fuels and/or modify combustion conditions (e.g., use of
excess air, burner modification, etc.).
The flue gases encountered in a coal conversion plant and the general
nature of the problem and control requirements differ from those for refin-
eries primarily in two respects. First, the types of fuel used in coal con-
version plants will be significantly different than those employed in refin-
eries. The probable fuel types in a coal conversion plant will include coal,
conversion products (e.g., high and low Btu gas, liquified product) and waste
and by-products (e.g., char and coal fines). Second, in a coal conversion
plant a centralized utility plant will probably be used to generate steam
and/or electric power for the entire complex, in which case the flue gas con-
trol technology would be that which has been developed for and used in the
utility industry. Accordingly, the flue gas characterization and review of
applicable control technology have been eliminated from further consideration
in this report.
4.1.7 Stream No. 7. Air Blowing Gas
Air blowing is used in some refineries for "brightening" and agitation
(2\
of petroleum products or oxidation of asphalt^ '. Venting of air used for
air blowing results in the emission of entrained hydrocarbon vapors and mists,
and malodorous compounds. This type of operation would have no counterpart
in a coal conversion facility.
23
-------
4.2 LIQUID WASTE STREAMS
Figure 4-3 shows liquid waste streams from a typical petroleum refinery.
Nearly all refinery designs incorporate a wastewater segregation scheme where-
by the process waste streams, which are contaminated with oils, are directed
to an "oily waters" sewer and the nonoily process and nonprocess waters are
diverted to the "clean waters" sewer. To permit material recovery and pollu-
tion control at the "source," the oily process waste streams are further seg-
regated (e.g., sour waters and spent caustics) and treated individually.
Based on the flow diagram shown in Figure 4-3, five major waste streams
are identified for a typical refining operation. The general descriptions of
these streams (designated Stream Numbers 1 through 5) including their source(s).
major contaminants and control technologies currently employed on these streams
are presented in Table 4-7. The five liquid waste categories have been re-
viewed from the standpoint of (a) similarity of major contaminants to the
waste streams found in coal conversion facilities and (b) applicability of the
currently used refinery control technologies to waste streams from coal conver-
sion plants. Based upon criteria (a) and (b), Streams 1 (sour waters), 3 (the
combined plant oily waters to API separator), 4 (clean waters), and 5 (slop
oil) have been determined to have counterparts in coal conversion facilities.
Stream 2 (spent caustic) has no counterpart in coal conversion plants.
Brief descriptions of the streams listed in Table 4-7 and the ratio-
nale for the selection of streams and/or technologies for evaluation of appli-
cability to coal conversion facilities follows. The technologies themselves
are evaluated and their applicabilities to coal conversion are discussed in
Section 6.2.
4.2.1 Stream No. 1, Sour Waters
Process steam is used in refineries for a range of applications includ-
ing fractionation and separation of oil products, catalyst regeneration and
removal of impurities from products/by-products. Subsequent condensation of
steam which has come into contact with products/by-products results in the
production of a wastewater which in many cases is characterized by relatively
high concentrations of sulfides, ammonia, mercaptans, phenolics and small
amounts of organic acids, nitrogen bases and cyanides (see Table 4-8). These
waters are referred to as "sour" or "foul" waters. Principal sources of sour
24
-------
ro
CJI
MAKE-UP
WATER
TREATMENT
REFINERY
PROCESS
UNITS
TO FURTHER
TREATMENT
UNITS
1 SOUR WATERS
2 VENT CAUSTIC
3 COMBINED OILY WATERS TO
API SEPARATOR
4 CLEAN WATERS
6 SLOP OIL
Figure 4-3. Refinery Liquid Waste Streams
-------
TABLE 4-7. REFINERY LIQUID WASTE STREAMS*12'13*
Stream
No.
Stream
Source(s)
Major Contaminants
Existing
Control Technology
1
ro
a*
Sour Waters
Spent Caustic
Oily Waters
Clean Waters
Slop Oil from
API Separator
Reflux drums, (crude
distillation, coking,
and cracking) vacuum
distillation over-
head drum, etc.
From caustic scrubs
used in removing
impurities from pe-
troleum products
Process units, sour
water treating,
neutralization,
filtration and mis-
cellaneous oily
waters
Boiler blowdown,
cooling tower blow-
down, etc.
API separator
Oils, sulfides, phenols,
ammonia, acids
Alkali, oils, phenols,
organic acid, sulfides,
TDS
Sulfides, phenols, mer-
captans, ammonia, and
miscellaneous oils and
solvents
Moderate amounts of TSS,
phosphate, sulfate,
small amounts of heavy
metals
Oils, phenols
Stri ppi ng,oxi dati on
Neutralization,
recovery of crude
phenol
API-type separators,
flotation
Direct discharge or
maybe treated for
process use
Emulsion breaking
and recycle to pro-
cess, water from
breaking to water
treatment
-------
waters are condensates from accumulators, reflux drums and knockout pots in
catalytic reformers, cracking, hydrocracking, coking and crude distillation
units
(12).
TABLE 4-8. REFINERY SOUR WATER CHARACTERISTICS^14'15^
PH
Specific Resistance, ohm-cm
Alkalinity, ppm as CaCCL
Total Dissolved Solids, ppm as CaC(L
H«S, ppm as S
NH~, ppm as N
Phenol ics, ppm as phenol
CN, ppm
Suspended Solids, ppm
Temperature, °K (°F)
Typical Value
8.6
440
1180
1310
1150
390
365
4
<8
308 (95)
Range
7.5 - 9.0
-
-
-
32 - 17,000
5 - 19,000
75 - 2400
nil - 28
-
-
In refineries, sour waters are generally treated (by stripping or oxida-
tion) for the removal of the bulk of the contaminants (sulfides, phenols and
ammonia) before they are discharged into the plant "oily waters" sewer for
additional treatment.
In coal conversion facilities, sour waters result primarily from the
quenching of product gas. The characteristics of these sour waters are de-
pendent on the properties of the raw product gas and the quench system em-
ployed. The characteristics of these sour waters are presented and compared
with those for refinery sour waters, in Section 5.3.
4.2.2 Stream No. 2, Spent Caustic
Typical uses of caustic chemicals in refineries are to neutralize and ex-
tract acidic materials that occur in crude oil or in crude fractions, acidic
reaction products and acid materials formed during catalytic or thermal crack-
ing (e.g., H2S, phenolics and acids used as process chemicals/catalysts).
27
-------
Spent caustic solutions, therefore, may contain sulfides, mercaptans, sulfates,
sulfonates, phenolates, naphthenates and other similar organic and inorganic
compounds.
Spent caustic is usually treated by neutralization to recover phenols
("acid oils") prior to discharge into the oily waters sewer. In some refin-
eries (usually the smaller ones) the spent caustic is sold to larger reclaimers.
A spent caustic stream similar to the refinery spent caustic waste is
not anticipated in a coal conversion facility. Accordingly, the characteriza-
tion and management of spent caustic wastes have been eliminated from further
consideration in this report.
4.2.3 Stream No. 3, Oily Waters
Sources of oily waters are various process units (desalters, barometric
condensers, etc.), sour water stripper bottoms, water from treated spent caus-
tics and tank drawoff waters. These waters, which are generally characterized
by their content of oils, sulfides, ammonia,and oxygen consuming organics
(BOD/COD), are discharged into the oily waters sewer and treated subsequently
as a single waste stream. Table 4-9 presents data on the characteristics of
the oily wastewater from refineries. Because of the composite nature of the
waste and the differences in the processing units employed, types of crude
oils handled, and refinery waste management practices employed in different
refineries, there are significant variations in the reported composition of
the oily wastewaters from different refineries. The composition is also sub-
ject to hourly, daily and seasonal fluctuations due to changes in operations
(resulting from changes in product mix), the type of crude oil handled, the
batch nature of some of the operation steps and the weather conditions (occur-
rence of rain, etc.).
The closest counterparts of the refinery oily waters in a coal conversion
plant are the quench waters from quenching of raw product gases, condensates
formed as a result of gas cooling and oily waters from scrubbing of oil pro-
ducts (in coal liquefaction). The composition of the oily waters in a coal
conversion plant would differ from that for refinery oily waters. The sources
of oily waters in coal conversion plants would be fewer in number and less
varied, and these waters'are expected to be more uniform in composition.
28
-------
TABLE 4-9. REFINERY OILY WATER CHARACTERISTICS^16'17^
Parameter
Oil
NH3
Sulfide (as H2S)
Phenols
BOD
COD
TOC
TSS
Alkalinity
Ca++
Mg++
Si02
cr
so4=
Total P04=
N02-
CuL
Ffi+2 & +3
Zn++
Conductance
PH
Temperature
Range (mq/1)
100 - 2600
160 - 6550
Trace - 8250
10 - 1000
230 - 1000
250 - 9600
32 - 119
6 - 28
80 - 560
0.3 13
0.5 - 14
1.3 - 4.4
1.5 - 260
16 - 125
0.5 - 3
0 - 276
0.2 - 0.12
0.6 - 1.6
250 - 1200 ymhos
6.8 - 9.6
Average Value
(mg/1)
975
1930
3550
200
540
3100
75
20
320
5
3.6
2
82
60
2
176
0.06
0.9
0.0
560 ymhos
8.2
290-320°K (68-1 22°F) 308°K (95°F)
29
-------
Furthermore, because of the differences in the nature of the raw materials
(coal vs. crude oils), the coal conversion oily waters contain a signifi-
cantly higher concentration of tars than refinery oily waters. There will
also be some differences in the chemical composition of oils found in the
two waste streams. Coal-derived oils tend to be highly aromatic in nature
while petroleum oils are primarily paraffinic.
In oil refineries, the common treatment sequence for the processing of
oily waters consists of gravity separation (in API type separators), flotation
and biological treatment. These control methods and their applicability to
coal conversion oily waters are discussed in Section 6.2.
4.2.4 Stream No. 4, Clean Waters
Clean waters are considered to be those that have not contacted oil and
are not subject to other contamination for which treatment must be provided.
Examples of sources of clean waters include blowdown from cooling towers and
boiler, once through cooling waters from surface condensers, etc.
Since these waters contain very little oil, they are usually disposed of
directly or reused (e.g., use of boiler blowdown for cooling water make-up),
without treatment. In modern refinery practice, however, a small separator
or surge pond is used to remove any accidentally introduced oils from these
(12)
waters before dischargev . Minimizing the contamination of the clean waters
with oils, process chemicals and other wastes is part of a good housekeeping
practice at refineries (see Section 6.2.7). Refinery "clean waters" would
have counterparts in coal conversion plants and similar control technologies
would be applicable.
4.2.5 Stream No. 5. Slop Oil
Slop oils from API-type separators contain oils and oil soluble materials
(e.g., phenols). In refineries this stream is generally concentrated by emul-
sion breaking; the concentrated oil is recycled to the refining operation and
the separated water 1s sent to the biological waste treatment facility.
The counterpart of the refinery slop oil in a coal conversion plant
would be the product or by-product oils/tars separated from quench waters or
condensates. In most coal conversion facilities the separated oil/tar stream
30
-------
would be further refined (e,g,, in hydrotreating of the COED oil), recycled
to the gasifier (e.g., in the Lurgi process), combusted on-site for heat re-
covery or sold. Since for most coal conversion systems the slop oil would be
a product or by-product stream and not a waste stream per se, this stream has
not been considered for further evaluation.
4.3 SOLID WASTE STREAMS
The solid wastes produced in petroleum refineries fall into three general
waste stream categories: process solids, waste treatment solids and miscel-
laneous nonprocess solids. The sources of major contaminants in and the exist-
ing refinery control technologies for these three categories of waste are
listed in Table 4-10.
4.3.1 Stream No. 1, Process Solids
The process solid wastes originate from various refinery subunits/opera-
tions (e.g., crude oil storage, alkylation, hydrotreating, etc.). The chemi-
cal composition of the process sludges is a function of the source/operation
and in some cases would vary among refineries depending on the type of crude
oil processed (e.g., composition of sludges from crude oil storage). Some
median values and ranges of concentration for selected constituents for three
process wastes (spent catalyst, coker fines and crude oil storage bottom sedi-
ments) are presented in Table 4-11. As indicated in this table, these solid
wastes contain heavy metals, phenols and oils (in the case of crude oil stor-
age tank bottoms). In addition to the constituents shown in the table, both
the spent catalyst and the coker fines are expected to contain a variety of
organic constituents, including some highly hazardous substances (see Chapter
7.0).
The nature and quantities (production per unit of raw material handled)
of process solids produced in a refinery would differ from those in a coal
conversion plant primarily because of the differences in the nature of the
raw materials used (oil vs. coal) and the greater diversity and complexity of
the processing steps employed in the refinery. Because of the simpler nature
of the operation, there would be fewer sources of process solid wastes in a
coal conversion plant and these would Include coal preparation wastes (refuse),
coal/char fines and ashes produced in the gasification step and spent catalysts
31
-------
TABLE 4-10. REFINERY SOLID WASTE STREAMS
(16)
Stream
No.
Process/Waste
Stream
Major Sources
Major Constituents/
Contaminants
Existing Control
Technology
1
Process solids
ro
Waste treatment
solids
Miscellaneous non-
process so'iids
Crude oil, intermediate
and product storage
tank bottom sludges;
spent catalysts from
catalytic cracking and
hydrotreating; fines
from cokers, acid and
alkali sludges from
sweetening and pro-
cessing (e.g., alkyla-
tion); miscellaneous
process chemicals
API separator and flo-
tation sludges;
sludges from biologi-
cal treatment; chemi-
cal sludges (lime,
alum, etc.) from waste
water treatment; cool-
ing tower sludge;
sludges from air pol-
lution control pro-
cesses (e.g., scrub-
bing for SOg control)
Process and cooling
water treatment
sludges; maintenance
wastes, general plant/
office refuse
Oils, trace elements
(As, Cd, V, Pb, Se,
etc.) phenols, acids,
alkali, miscellaneous
process chemicals;
inerts (silt, clay,
etc.), water
Oils, phenols, heavy
metals, waste treat-
ment chemicals, bio-
mass (biological flow),
inerts, water
Inerts (silts, sand,
etc.) water treatment
chemicals/precipitates
(lime, calcium carbon-
ate, etc.), oil,
metals, papers, etc.
Landfill ing and land-
spreading (primarily
for oily wastes), on-
site or off-site pro-
cessing for material
recovery (e.g., cata-
lyst reclamation),
storage in lagoons and
evaporation ponds,
energy recovery (e.g.,
incineration of oily
wastes)
Processing to reduce
volume (e.g., filtra-
tion, thickening), land-
filling and landspread-
ing; incineration;
storage in lagoons,
evaporation ponds and
drying beds
Storage in lagoons and
evaporation ponds, land-
fill ing, incineration
(for refuse)
-------
TABLE 4-11.
PROCESS SOLIDS CHARACTERISTICS
[MEDIAN VALUE (RANGE)]
(18)
Constituents
mg/kg (dry)
Spent Catalyst
Coker Fines
Crude Oil Storage
Tank Sediment
CO
CO
Phenol
Cyanide
Se
As
Hg
Be
V
Cr
Co
Ni
Cu
Zn
Ag
Cd
Pb
Mo
Ammonium Sulfate (as
NH4+)
Benzo-a-Pyrene
Oil (wt %)
Water (wt %)
2.1 (0.3-72)
0.12 (0.01-1.44)
0.01 (0.01-19.1)
1.0 (0.05-4.0)
0.0004 (0.0005-0.16)
0.5 (0.025-1.4) i
240 (74.4-1724)
71 (12.3-190)
6.6 (0.25-37)
241 (47.5-1000)
17.5 (4.1-336)
39 (19-170)
1.8 (0.5-3.0)
0.003 (0.001-0.5)
50 (10-195)
6.3 (0.5-21.6)
0.1
0.005 (0.0002-1.5)
0.21 (0.01-0.81)
0
2.0 (0.4-2.7)
0.001 (0.00025-0.001)
0.01 (0.01-1.6)
2.0 (0.2-10.8)
0.04 (0.0004-0.2)
0.005 (0.0025-0.5)
455 (500-3500)
0.02 (0.02-7.5)
4.0 (0.2-9.2)
580 (350-2200)
4.0 (3.5-5.0)
14 (0.2-20)
0.01 (0.01-3.0)
1.0 (0.015-2.0)
13.0 (0.5-29)
0.1 (0.1-25)
0.7
0.002 (0.002-0.005)
0.001 (0.001-1.34)
0
15.8 (6.1-21)
0.0012 (.00025-0.8)
0.03 (0.01-1)
21.1 (5.8-53)
0.0026 (0.0013-0.25)
0.0026 (0.0013-0.25)
17.4 (5-62)
19.4 (1.9-75)
14.8 (3.8-37)
16.2 (12.8-125)
65.4 (18.5-194)
145 (22.8-425)
0.19 (0.03-1.3)
0.31 (0.25-0.42)
18.9 (10.9-338)
6.3 (0.25-95)
2
0.11 (0.03-0.06)
47.4 (21-83.6)
13.3 (1-20)
-------
and sludges from gas purification and upgrading. Even though some of the pro-
cess solids encountered in refineries would not have very close counterparts
in coal conversion plants, the existing refinery control technologies (land-
filling, incineration and material recovery) would be applicable to the manage-
ment of certain solid waste streams in a coal conversion plant (see Section
6.3).
4.3.2 Stream No. 2, Waste Treatment Solids
As indicated in Table 4-12, major sources of waste treatment solids in
a refinery are sludges from API separators, flotation units, biological waste-
water treatment, water treatment and air pollution control. Table 4-12 pre-
sents some median values and ranges of composition of three types of waste
treatment solids in a refinery (API separator, air flotation and waste bio-
sludge). As indicated in the table, a range of values have been reported for
the listed constituents, reflecting differences in the nature of wastewaters
generated and the operating conditions in different refineries. For example,
the reported oil and water contents of the API separator sludges vary from 3 ;
to 60 wt % and from 7 to 98 wt %, respectively. The sludges from the API
separator and flotation units are characteristically high in the content of
oil, phenols and certain heavy metals (e.g., chromium which is used largely for
corrosion control).
When biological processes are employed for the treatment of aqueous
wastes, the degradation of organics and the physical entrapment and settling
of suspended particles result in the production of the "biosludge." Sludges
produced in the activated sludge and trickling filtration processes are
settled in the "final" clarifiers which follow the aeration tank or the filter.
In the activated sludge process a portion of the settled sludge is recycled
to the aeration tank and the "excess" sludge is "wasted." Sludges removed
from final clarifiers typically contain 2% to 5% solids with the solids gen-
erally containing 50% to 70% "volatile" matter. When lagoons and stabiliza-
tion basins are used for biological treatment, the biological sludge produced
and the settleable matter in the raw wastewater settle to the bottom; the
degradable material in the settled sludge undergoes aerobic and/or anaerobic
decomposition. Depending on the nature and quantity of the solids in the raw
wastewater and the lagoon design, periodic cleaning of the lagoons to remove
34
-------
TABLE 4-12.
EFFLUENT TREATMENT SOLIDS CHARACTERIZATION
[MEDIAN VALUE (RANGE)]
,(18)
Constituents
mg/kg (dry)
API Separator Sludge
Air Flotation Residue
Waste Biosludge
en
Phenol
Cyanide
Se
As
Hg
Be
V
Cr
Co
Ni
Cu
Zn
Ag
Cd
Pb
Mo
Ammunium Sulfate (as
NH4+)
Benzo-a-Pyrene
Oil (wt %)
Water (wt %)
13.6 (3.8-156.7)
0.001 (6x10-5-51.4)
0.001 (0.0005-7.6)
6.2 (0.1-32)
0.4 (0.04-6.2)
0.0025 (0.0012-0.24)
9,8 (1.0-48.5)
253 (0.1-6790)
5.7 (0.1-26.2)
19.3 (0.25-150.4)
18.6 (2.5-550)
298 (25-6596)
0.45 (0.05-3)
0.42 (0.024-3)
26 (0.29-1290)
5 (0.25-30)
6.5 (0.05-30)
0.004 (0.0025-4.5)
22.6 (3.3-59.8)
53 (7-98)
6.5 (3.0-210)
0.28 (0.01-1.1)
2.0 (0.1-4.2)
2.0 (0.05-10.5)
0.27 (0.07-0.89)
0.0025 (0.0012-0.25)
0.05 (0.05-0.15)
140 (28-260)
2.0 (0.13-67.5)
0.025 (0.025-15)
710 (0.05-21.3)
85 (10-1825)
0.25 (0.0013-2.8)
0.005 (0.0025-0.5)
7.5 (2.3-1250)
0.05 (0.025-2.5)
9 (8.5-210)
0.002 (0.004-1.75)
12.5 (2.5-16.9)
82 (30-99)
4.5 (1.7-10.2)
0.001 (0.0001-19.5)
0.01 (0.01-5.4)
3.8 (1.0-6.0)
0.18 (0.004-1.28)
0.0013 (0.0013-0.002)
0.05 (0.012-5.0)
300 (0.05-475)
0.2 (0.05-1.4)
0.025 (0.013-11.3)
9.5 (1.5-11.5)
122 (3.3-225)
0.3 (0.1-0.5)
0.3 (0.15-0.54)
5.0 (1.2-17)
2.5 (0.25-2.5)
21 (6.5-30)
0.003 (0.002-0.005)
0.28 (0.01-0.53)
87 (56-95)
-------
the settled sludge may be necessary. Certain elements (e.g., heavy metals)
and refractory organics which may be present in the raw wastewater at rela-
tively low concentration levels tend to concentrate in the biosludges. High
concentrations of such substances in the sludge may eliminate certain options
for sludge disposal (e.g., use as fertilizer on agricultural soils). Bio-
sludges from refineries have been reported to contain Cr and Zn values of 540
and 200 mg/kg of dry sludge, respectively^18^. Heavy metal concentration is
especially pronounced when anaerobic digestion is used for the stabilization
and thickening of "primary" and "secondary" sludges.
The characteristics of the biosludges from coal conversion facilities
are expected to be generally similar to those of petroleum refinery biosludges.
However, coal conversion biosludges may contain refractory organics which are
chemically different from petroleum biosludges. The inorganic component of
coal conversion biosludges (e.g., trace elements) may also differ. Despite
differences in the composition of refinery and coal conversion waste treatment
solids, the existing refinery control technologies (sludge concentration
followed by landfilling, landspreading or incineration) would be applicable
to the management of waste treatment solids in coal conversion plants. (See
Section 6.3.)
4.3.3 Miscellaneous Nonprocess Solids
Table 4-13 presents waste characterization data for four types of miscel-
laneous nonprocess solid wastes in a refinery (lime sludge from boiler water
treatment, maintenance waste, cooling tower sludge and sediments from settling
of surface runoff from the plant areas). Except for some contamination with
certain substances associated with the refining operations (e.g., oils,
phenols and heavy metals), the characteristics of these waste streams and the
technology for their controls would be similar to their counterparts in other
industries (including coal conversion). Those technologies which are also
applicable to the management of process and waste treatment solids (storage in
lagoons, landfilling, etc.) are reviewed in Section 6.3.
36
-------
TABLE 4-13.
GENERAL WASTES CHARACTERISTICS
[MEDIAN VALUE (RANGE)]
(18)
Constituent
mg/kg
Spent Lime from Boiler
Feed Water Treatment
Maintenance Waste
Silt from Storm
Water Runoff
Cooling Tower Sludge
Phenol
Cyanide
Se
As
Hg
Be
V
Cr
Co
Ni
Cu
Zn
Ag
Cd
Pb
Mo
Ammonium Salts
(as NH4+)
Benzo-a-Pyrene
Oil (wt %)
Water (wt %)
2.1 (0.05-3.6)
0.001 (2xlO-5-1.28)
0.01 (0.01-12.2)
0.1 (0.05-2.6)
0.04 (0.004-2.73)
0.0012 (0.001-0.002)
0.05 (0.007-31.6)
2.2 (0.025-27.9)
0.005 (0.002-1.3)
2.5 (0.13-22.5)
3.8 (0.22-63.2)
15.0 (2.0-121)
0.05 (0.05-0.7)
0.003 (0.0012-0.3)
3.8 (0.01-7.3)
0.025 (0.0025-0.05)
0.015 (0.005-5.0)
0.002 (0.002-0.002)
0.32 (0.04-0.49)
59 (5-91.8)
13.3 (8-18.5)
1.7 (0.0004-3.3)
27.2 (2.4-52)
10.6 (10.2-11)
1.9 (0.13-3.6)
0.20 (0.05-0.34)
25 (0.7-50)
311 (310-311)
1.6 (0.2-3.0)
116 (61-170)
71 (67-75)
194 (91-297)
0.005 (0.0007-0.01)
1.3 (1.0-1.5)
78 (0.5-155)
6.5 (1-12)
8 (5-11)
2.2 (0.7-3.6)
10.7 (8.3-13)
53 (42-64)
7.5 (6.3-8.6)
1.72 (0.34-3.1)
1.7 (1.1-2.2)
5.5 (1.0-10.0)
0.30 (0.23-0.36
0.0019 (0.0012-0.0025)
69 (25-112)
354 (32.5-675)
11.2 (11.0-11.3)
85 (30-140
28.3 (14.8-41.8)
230 (60-1000)
0.5 (0.5-0.5)
0.22 (0.01-0.42)
53.3 (20.5-86)
6.9 (6.3-7.5)
1.0
1.27 (0.03-2.5)
3.9 (2.2-5.5)
25 (20-29.7)
3.5 (0.6-7.0)
0.1 (0.0005-17.2)
0.15 (0.01-2.5)
8.2 (0.7-21)
0.09 (0.004-3.35)
0.0013 (0.001-0.2)
7.8 (0.12-35)
554 (181-1750)
1.3 (0.38-7)
6.8 (0.25-50)
50 (13-363)
675 (118-1100)
0.28 (0.01-1.6)
0.3 (0.06-0.6)
38 (1.2-89)
1.1 (0.25-2.5)
6.3 (0.07-14)
0.004 (0.003-0.8)
0.44 (0.07-4.0)
75.4 (50-883)
-------
5.0 CHARACTERISTICS OF COAL CONVERSION WASTE STREAMS
The characterization of coal conversion waste streams was undertaken to
identify those streams which have counterparts in petroleum refining, and/or
can be processed by the refining control technologies.
5.1 COAL CONVERSION PROCESSES
Of a significantly large number of processes which have been suggested
for the production of low/medium Btu gas, high Btu gas and liquid fuel from
coal, only a few have attained or are approaching commercial status. Many of
the processes, especially those which are still in early developmental stages,
have not been operated on a meaningfully large scale or for a sufficient length
of time to allow detailed and meaningful characterization of waste streams
associated with any commercial scale process application.
To establish the processes of interest to the program, nine low/medium
Btu gasification, eight high Btu gasification and three liquefaction processes
were reviewed (see Table 5-1). Based on the considerations of (a) availability
of data on waste stream characteristics, (b) attainment of, or nearness to
commercial status, (c) representation of integrated operations producing up-
graded or refined fuels and (d) avoidance of duplication with other EPA pro-
jects, three processes were selected for detailed review of the available data
on waste stream characteristics. These processes are Koppers-Totzek (low/
medium Btu gasification), dry ash Lurgi (high Btu gasification) and COED (lique-
faction). It is recognized that because of the differences among the individ-
ual processes in the three technology categories, there would be significant
differences in the types and characteristics of the waste streams from the pro-
cesses in each category and that no single process can represent the category.
For example, in the case of liquefaction, the waste streams from hydrogenation
processes, such as the H-Coal process, could drastically differ from those
from pyrolysis processes such as COED. The selection of COED as an example of
38
-------
liquefaction processes is for analysis purposes only and does not imply that
the COED wastes necessarily typify liquefaction wastes.
TABLE 5-1. COAL CONVERSION PROCESSES REVIEWED
Low/Medium Btu
Gasification
Chapman (Wilputte)
Coalex
Foster Wheeler/Stoic
Koppers-Totzek
Reiley Morgan
Texaco
Wellman-Galusha
Winkler
High Btu
Gasification
Bigas
C02~Acceptor
Cogas
Hydrane
Hygas
Lurgi (dry ash)
Lurgi (slagging)
Self-agglomerating ash
Liquefaction
COED
SRC
H-Coal
The Koppers-Totzek (K-T) process is considered to be one of the most
likely low-medium Btu gasification processes to be used in commercial appli-
cations in the U.S. for synthesis gas production. Commercial installations
using the K-T process have been in operation in other countries for a number
of years and some process/waste stream composition data are available for
this process.
The dry ash Lurgi is considered a commercial process and, compared to any
of the other processes, considerably more operating experience is available on
this process. Essentially all proposed designs for commercial SNG facilities
in the U.S. are based on the Lurgi technology.
COED was selected as the example for the liquefaction technology since
not only are considerable data available for the process but the proposed de-
signs also feature several processes (e.g., product separation and hydrotreat-
ing) which would be used in connection with a number of other liquefaction
schemes. The COED process, moreover, produces liquid fuel(s) which can be
processed to produce petroleum fuel substitutes. The Solvent Refined Coal
(SRC) process was not selected to represent the liquefaction technology because
most of the available pilot plant data for the process are for the "SCR-I"
which produces a solid fuel and is considered essentially a coal deashing/
39
-------
desulfurization operation; also it is being treated in-depth by related EPA
studies. The "SCR-II" process, which is designed to produce liquid fuel as
the primary product, is in the very early developmental stage and few data are
currently available on this version of the SRC process.
Figure 5-1 presents a generalized flow diagram for coal conversion sys-
tems with the major waste streams identified (numbered 1 through 18). A brief
review of the characteristics of the identified streams and comparison of
their characteristics with their refinery counterparts follow.
5.2 GASEOUS WASTE STREAMS
Table 5-2 lists the gaseous streams identified in Figure 5-1 along with
their source(s) and major contaminants. Stream No. 1 (Raw Product Gas) is
not a waste stream; it has, however, been included here because in some re-
spects it is similar to the refinery process sour gases (see Section 4.2.1).
The coal conversion gaseous streams which have been found to have possible
counterparts in refineries are: raw product gas, acid gases, raw fuel gas,
fugitive emissions, flue gas and cooling tower gas. Streams 8 and 9 have no
refinery counterparts.
5.2.1 Stream No. 1, Raw Product Gas
Before the quenched raw product gas is further processed or consumed
directly, it is usually necessary to remove the sulfur compounds in the pro-
duct gas. Table 5-3 presents the characteristics of raw product gases (after
quenching and dust removal) from the Lurgi and K-T gasifiers. For comparison
purposes, the composition data for process sour gases from petroleum refin-
eries are also given.
As can be seen from the data in Table 5-3, despite certain general simi-
larities (e.g., presence of H2S and C02) there are significant differences in
the characteristics of the quenched product gas and refinery process sour
gases. In general, the quenched product gas:
Contains higher levels of H2, CO, and COp
t Has much lower levels of H«S
Is at a much higher temperature and (in the case of Lurgi) at higher
pressure
40
-------
STEAM
SHIFT
AND
METHANATION
GASIFICATION
MODULE
(INCLUDING QUENCH
AND DUST REMOVAL)
ACID GAS
TREATMENT
LOW:MEDIUM BTU
PRODUCT GAS
COAL
PREPARATION
MODULE
LIQUEFACTION
MODULE
PRODUCT
SEPARATION
HYDROTREATING
HYDROGEN
CONTAINING
GAS
HYDROCARBON
LIQUID
HIGH BTU
PRODUCT
GAS
LIQUID
PRODUCTS
UTILITIES
FUEL| |AIR A
STEAM
OXYGEN
ELECTRICITY
HYDROGEN
COOLING
WATER
t
1
2
3
4
6
6
7
AIR
RAW PRODUCT GAS
ACID GASES
RAW FUEL GAS
ACID GASES
FUGITIVE EMISSIONS
FLUb GAS
COOLING TOWER GAS
8 VENT GAS
9 FEED AND ASH HOPPER VENT GAS
QUENCH AND CONDENSATE WATERS FROM
GASIFICATION
11 WASTE LIQUOR PURGE
12 SEPARATED WATER
13 WATER FROM SHIFT AND METHANATION
14 MISC PLANT WATERS
15 PARTICULATES FROM COAL PREPARATION
16 ASH OR CHAR FROM COAL CONVERSION
17 ASH FROM COAL BURNING
18 SPENT CATALYSTS
Figure 5-1.
Generalized Flow Plan for Coal Conversion Process (not all input or discharge lines are
applicable to all processes)
-------
As will be discussed in Section 6.1, these differences in gas characteristics
would require the use of different gas processing methods for the removal of
sulfur components from the raw and by-product acid gas streams.
TABLE 5-2. MAJOR GASEOUS WASTE STREAMS FROM COAL CONVERSION PROCESSES
Stream
No.
Stream
Source(s)
Major Contaminants
1
3
4
5
6
7
8
Raw Product Gas
Acid Gases
(gasification)
Raw Fuel Gas
(liquefaction)
Acid Gases
(liquefaction)
Fugitive
Emissions
Flue Gas
Cooling Tower
Gas
Vent Gas
Feed and Ash
Hopper Vent
Gas
Product of gasification
of coal after quench
and dust removal
Acid gas removal module
Product separation
Hydrotreating
Compressors, drains,
storage tanks, etc.
Utility boilers
Cooling towers
Coal preparation
(including crushing,
drying and storage)
Pressurization of feed
and ash lockhoppers
Primarily sulfur com-
pounds, HCN and naphtha-
lene (in high Btu gasi-
fication C02 is consid-
ered a contaminant and
is removed in the acid
gas treatment section)
Sulfur compounds, CO,
hydrocarbons and
solvents
Sulfur compounds and HCN
Sulfur compounds
Hydrocarbons
S02, CO, HC, NOX and
particulates
Volatile hydrocarbons,
H2S and NH3
Particulates, flue gas
constituents
Particulates, volatile
hydrocarbons, CO and
sulfur compounds
42
-------
TABLE 5-3. COMPARISON OF THE COMPOSITIONS OF COAL GASIFICATION QUENCHED RAW
PRODUCT GAS AND REFINERY SOUR GAS*
Gas Stream
Components/Parameters
H2
°2
CO
CH4
co2
C2H6
H2S
CH3SH
COS
N2 + Ar
NH3
HCN
Naphthalene
Temperature, °K (°F)
Pressure, MPa (psia)
Lurgi
39.1
0.6
17.3
9.4
31.2
0.7
1.1
-
-
0.6
0.18
2.8
0.68
727 (850)
2.1 (300)
K-T
32.74
-
57.35
-
7.05
-
1.59
-
0.114
1.16
-
-
-
1750 (2700)
0.1 (15)
Refinery Process
Sour Gasest
-
-
-
8.4
1.9 - 4.9
4.36 - 5.2
16.4 - 62.5
-
-
-
-
-
-
320 (122)
0.15 (22)
*Except as noted, all values in mole %.
fFrom Table 4-2.
5.2.2 Stream No. 2, Acid Gases
The processes presently in use to remove acid gases from coal gasifica-
tion plant raw product gases generally involve the chemical or physical ab-
sorption of the acidic components in a suitable liquid with subsequent desorp-
tion at a lower pressure (and in some instances at a higher temperature).
Two of the acid gas treatment processes which have been used in connec-
tion with gasification processes and for which some operating data are
43
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available are the Rectisol and Benfield processes. The characteristics of the
recovered gas streams from these processes are presented in Table 5-4 and com-
pared with their refinery counterpart. As can be seen, large differences
exist in the concentrations of C02 and H2S in the acid gases from coal gasifi-
cation and refineries. These differences in composition will require different
processes or different operations for both sulfur recovery and tail gas clean-
up than those in use at refineries (see Section 6.1).
TABLE 5-4. COMPARISON OF THE RECOVERED ACID GAS FROM RECTISOL AND BENFIELD
WITH THOSE IN REFINERIES
Characteristics
C02, mole %
H2S, mole %
COS, mole %
Temp., °K (°F)
Press. , MPa (psia)
Rectisol
(Operating on
K-T Gas)
75
22
3
313 (105)
0.1 (15)
Benfield
(Operating on
Lurgi Gas)
98
2
_t
383 (230)
2.1 - 7.6
(300 - 1100)
Refinery*
(Range for Different
Processes)
4.6 - 46.1
50.3 - 91.4
-
313 (105)
0.15 (22)
*From Table 4-2
Dash indicates no data on this compound has been reported.
5.2.3 Stream No. 3, Raw Fuel Gas from Liquefaction
In the liquefaction of coal, raw fuel gases (i.e., gases which are
usually used either to fire process and utility units or are sold) are sep-
arated from the liquid product, and solid wastes, in the "product separation
module." The amount of gas present varies with the specific liquefaction
process (values of 54, 52 and 12 wt. %, based on input to the product sep-
aration module, have been reported for COED, SRC and H-Coal processes, re-
spectively). The raw fuel gas will have to be treated for removal of sulfur
compounds prior to use. In terms of its major constituents, the liquefaction
raw fuel gas is expected to be similar to Stream No. 1, raw product gas.
44
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5.2.4 Stream No. 4, Acid Gases from Hydrotreating
In the COED liquefaction process acid gases are generated as a result of
hydrotreating of the liquid product. (The H-Coal and SRC processes do not
incorporate hydrotreating.) The objective of hydrotreating is to reduce sul-
fur, oxygen and nitrogen compounds and to hydrogenate unsaturated hydrocarbons
and aromatics. Sour gas is produced which should be similar to that from re-
finery hydrotreating operations.
Table 5-5 presents the composition of gases produced by hydrotreating
COED product oil. This stream is very small (less than 2.7 Mm /min for a
22,000 tonne/day plant or 100 scfm for a 24,000 ton/day plant) and in a com-
mercial facility would probably be combined with other gas streams for
treatment.
TABLE 5-5. CHARACTERISTICS OF HYDROTREATING ACID GASES FOR THE COED PROCESS*
Component
N2
co2
CO
H,
CH4
NH3
Temp., °K (°F)
Press., MPa (psia)
wt «t
0.82
2.15
8.82
74.69
4.77
5.95
0.69
2.10
315 (100)
0.1 (16)
*Actual comparative data not available for the hydrotreating acid gases
produced in refineries.
^Except for temperature and pressure.
45
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5.2.5 Stream No. 5, Fugitive Air Emissions
A variety of sources may account for fugitive emissions in coal conver-
sion plants. Among these are: compressors, valves, flanges, wastewater and
solids handling units, etc. The major pollutants present in these emissions
consist of the materials handled (primarily hydrocarbons, sulfur compounds,
CO, etc.). Similar sources of emissions are present in refineries. The actual
compositions of the fugitive emissions vary widely, depending primarily on the
emission source and the nature of product handled.
Control technologies to reduce fugitive emissions will depend on the
source. Certain sources, such as vents and storage tanks, may be controlled
by the use of vapor collection and recovery techniques which are currently
employed in some refineries and other industrial facilities.
5.2.6 Stream No. 6, Flue Gas
Flue gases in coal conversion plants would originate primarily from the
central steam plant. Some process sections (e.g., hydrotreating in the COED
liquefaction scheme) contain small heaters or boilers which would also gener-
ate flue gas emissions. The composition of the flue gas would depend pri-
marily on the type of fuel used. Process developers may choose to use some
of the "clean" coal conversion products as the fuel or burn coal or char
directly. The flue gas emission controls required in a coal conversion plant
would be dependent on the type of fuel used.
The utility boiler and process furnaces in a refinery are generally oil
or fuel gas fired; characteristics of the flue gas emissions from these units
would be different from those encountered in coal conversion plants. Accord-
ingly, the flue gas control technology used in refineries would not be
directly applicable to the management of flue gas emissions in coal conversion
plants. The required technologies for the control of flue gas emissions from
the combustion of coal and char in coal conversion plants would be those which
have been developed in other industries, primarily the utility industry. Be-
cause of the inapplicability of the refinery control technology, Stream No. 6
has been omitted from further consideration in this report.
46
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5.2.7 Stream No. 7, Cooling Tower Gas
Emissions from cooling towers primarily contain water vapors and mists.
Depending on the source of the makeup water used, the emissions may also con-
tain volatile organics, H2S and NH~. (In some refineries, treated process
wastewaters, such as stripped sour waters or effluent from biological treat-
ment, are used as the cooling water makeup.) The water vapors and mists
emitted in the drift can contain salts and organics. In refineries, the emis-
sions from cooling towers are controlled through proper cooling tower design
and control of the quality of the water used as makeup. In coal conversion
plants, treated process wastewaters would also likely be used as cooling
water makeup, and the cooling tower emissions can be controlled in a similar
manner.
5.2.8 Stream No. 8, Coal Preparation Vent Gases
For the Lurgi, Koppers-Totzek and COED processes, the coal preparation
operations include crushing, drying and storage. The coal preparation require-
ments generally vary with the specific coal conversion process. For instance,
Lurgi requires no coal drying while, depending on the coal used, both K-T and
COED may require coal drying. The composition of vent gases from coal pre-
paration would also vary depending on the characteristics of the feed coal
and the degree of crushing and drying reuqired. (The coal sizes for K-T and
COED processes vary from less than 0.07 mm to 45 mm.)
Although no actual data have been reported on the composition of the
vent gases for pretreatment operations, these gases are expected to contain
such classes of contaminants as: particulates, volatile hydrocarbons, S02>
CO and NO . Gases from crushing and storage will primarily contain particu-
rt
lates, while those from drying would also contain combustion products. The
quantities would depend upon the fuel used and the operating conditions of
the heater.
No counterpart to coal preparation vent gases has been identified in
refining operations. The control technologies which would be used for the
vent gases would most likely be those commonly employed in the mining and
utility industries. Examples of such technologies include use of filter bags
47
-------
for participate control, incineration for the destruction of organics and
combustion modification for the control of NO emissions.
A
5.2.9 Stream No. 9, Feed and Ash Hopper Vent Gas
Gases used to pressurize feed and ash lockhoppers may contain particu-
lates, volatile hydrocarbons and components present in the gasifier gas. A
feed lockhopper is not used in processes which employ pneumatic feeding (e.g.,
COED) or operate at atmospheric pressure (e.g., Koppers-Totzek).
No counterparts to lockhopper vent gases appear in refineries (or in
other industries). Control of emissions from this source would, by necessity,
be of unique design incorporating return of the gases to the main gas stream
as well as the use of inert gases (e.g., carbon dioxide) for pressurization.
5.3 LIQUID WASTE STREAMS
Table 5-6 lists the major liquid waste streams associated with coal con-
version systems (the stream numbers correspond to those in Figure 5-1). Only
the first stream listed in the table (Stream No. 10, quench and condensate
waters from gasification) would have a counterpart in petroleum refining.
Stream Nos. 11 and 12 have similar composition to refinery wastewaters; how-
ever, the technologies proposed for use in the coal liquefaction system (i.e.,
injection of these waters into the pyrolyzer) is very unique and different
from the refinery control technologies. Stream No. 13 has no counterpart in
refineries (see Section 5.3.4). Stream No. 14 has counterparts in refineries
and in many other chemical process industries, and their control is not unique
to coal conversion plants or refineries.
Discussions of each of the streams listed in Table 5-6 follows.
5.3.1 Stream No. 10, Quench and Condensate Waters from Gasification
The condensate stream from coal gasification processes includes quench
waters as well as condensates removed in gas cooling. The composition of
condensate waters from coal gasification is dependent upon the conditions
within the gasifier. In general, gasifiers (e.g., K-T) which operate at
higher temperatures produce less tars and oils than lower temperature gasi-
fiers. Table 5-7 presents the compositions of condensate waters from the
Lurgi and K-T processes. The table also contains the characteristics of
48
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TABLE 5-6. MAJOR LIQUID WASTE STREAMS FROM COAL CONVERSION PROCESSES
Stream
No.
Stream
Source(s)
Major Contaminants
10
11
12
13
14
Quench and condensate
waters from gasification
Waste liquor purge from
product separation
(liquefaction)
Separated water from
hydrotreating
(liquefaction)
Water from shift and
methanation
Miscellaneous plant
waters
Quenching and gas
cooling
Product separation
and recovery
Hydrotreating
Shift and
methanation
Storm water run-
off, boiler blow-
down, etc.
--
Phenols, ammonia, sul-
fur compounds and
heavy metals
Phenols, oils, ammonia,
sulfates, and heavy
metals
Ammonia, sulfates,
and heavy metals
Dissolved gases,
traces of sulfur,
nitrogen, hydrocarbons
and heavy metals
Small amounts of
solids, phosphates,
sulfates and heavy
metals
TABLE 5-7. COMPARISON OF THE CONDENSATES FROM GASIFICATION AND REFINERIES
Characteristic
PH
TDS, mg/1
Sulfide, mg/1
Ammonia, mg/1
Carbonate, mg/1
Cyanide, mg/1
Chloride, mg/1
Phenols, mg/1
Lurgi
Inlet to
Tar
Separator
9.8
2770
47
1700
5644
4
128
2200
__
Inlet to
Oil
Separator
8.5
1570
831
17650
29110
16
71
1900
K-T
Combined
Stream
8.9
2769
15
681
0.01
284
Refinery*
Sour
Water
8.6
1310
2172
390
5244
365
Oily
Water
8.2
3550
1930
320
--
82
200
*From Tables 4-8 and 4-9.
49
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refinery wastewaters for comparison. The major differences between coal gasi-
fication condensate and refinery wastewaters are in the amounts of phenols,
ammonia and sulfides present. Generally, low to medium temperature gasifica-
tion and liquefaction processes (e.g., Lurgi and COED) generate condensates
with higher levels of ammonia and phenols and lower levels of sulfide than
found in refinery sour waters. For high temperature gasification processes
(e.g., K-T), low levels of ammonia are usually found in condensates (presum-
ably coal nitrogen is oxidized in the gasifier).
5.3.2 Stream 11, Waste Liquor Purge from Product Separation
In the COED process the waste liquor purge from product separation con-
tains waters generated in the pyrolysis stages. Estimates of the composition
of these waters are presented in Table 5-8. Major contaminants in these
waters are phenols, oils and heavy metals, nitrogen and sulfur compounds. In
refineries a close counterpart of this stream does not exist due to the high
levels of certain contaminants present in the purge stream which are unique
to coal (e.g., heavy metals).
TABLE 5-8. COED WASTE LIQUOR PURGE STREAM COMPOSITION
Constituent
Nitrogen (wt. % N)
Sulfur (wt. % S)
Phenol (wt. %)
Entrained Oil (wt. %)
Suspended Solids (wt. %)
PH
1st Stage Pyrolysis
0.05
0.07
0.00
0.49
3.6
2nd Stage Pyrolysis
0.93
0.18
0.38
0.00 - 0.5
1.09
9.3
The purge gas pollution control technologies expected to be incorporated
in the design of coal conversion plants would also be different than any tech-
nology used in the refining industry. For example, the COED process developer
(the FMC Corporation) expects to recycle these waters to one of the pyrolysis
stages.
Based on the consideration of the waste characteristics and the unique-
ness of the control technology suggested for use in conjunction with the COED
process, Stream No. 11 has been eliminated from further consideration.
50
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5.3.3 Stream No. 12. Separated Water from Hydrotreating
Hydrotreating is used to remove sulfur and nitrogen from the product oil
and to hydrogenate unsaturated compounds. Water separated from this process
generally contains considerable quantities of sulfur and nitrogen compounds
(see Table 5-9). This stream, like Stream No. 11, waste liquor purge, is ex-
pected to be recycled to the pyrolyzers and its sulfur and nitrogen components
would eventually appear in waste liquor from product separation.
TABLE 5-9. HYDROTREATING SEPARATED WATER COMPOSITION
Constituent
Carbon, wt %
Nitrogen, wt %
Sulfur, wt %
PH
Value
0.8
5.0
8.7
9.3
5.3.4 Stream No. 13, Waters from Shift and Methanation
Essentially no characterization data have been reported for raw waste-
waters produced as a result of shift conversion and methanation of the pro-
duct gas from coal gasification. Shift conversion and methanation waters are
expected to be relatively "clean" because of the nature of the operation and
the gas handled. Most major pollutants in the product gas (e.g., ammonia,
tars, oil, etc.) have been removed prior to shift conversion and methanation.
Small amounts of dissolved gases with traces of sulfur, nitrogen and hydro-
carbon (other than methane) compounds may be present. The counterpart of
Stream No. 13 in refineries would be the refinery "clean" waters.* Because
of the "clean" nature of Stream No. 13, the control technology for the stream
in a coal conversion plant will be minimal. The stream will probably be
added to the wastewaters after oil-water separation and treated jointly in
the biological treatment plant, or treated for use as boiler or cooling tower
makeup.
*When on-site hydrogen production is employed in refineries (for hydrotreat-
ing), shift and methanation would be used in the hydrogen plant. The con-
densate from such shift and methanation, however, is a very "clean" stream
since protection of the catalyst requires that nearly all sulfur and nitro-
gen compounds be removed from the feed gas by prior treatment.
51
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5.3.5 Stream No. 14, Miscellaneous Plant Wastewaters
Miscellaneous sources of wastewater in coal conversion plants include:
boiler blowdown, cooling tower blowdown, storm water runoff, and sanitary sew-
age. Similar streams exist in refineries and the methods of handling and Con-
trolling these wastewaters (e.g., settling in retention ponds, use as process
water, biological treatment, etc.) would not be unique to coal conversion
plants or to refineries but are used in a variety of industrial production
facilities.
5.4 SOLID WASTE STREAMS
Solid waste streams identified in Figure 5-1 are listed in Table 5-10.
The source(s) and major constituents of these streams are also presented.
Streams No. 15 and 16 (spent catalyst and sludges, respectively) are the only
streams with refinery counterparts. Each of the coal conversion solid waste
streams listed in Table 5-10 is discussed in the following subsections.
TABLE 5-10. SOLID WASTE STREAMS FROM COAL CONVERSION PLANTS
Stream
No.
Stream
Source(s)
Major Contaminants
15
Spent Catalyst
16
17
18
19
Sludges
Particulates from
coal preparation
Ash or char from
coal conversion
Ash from coal
burning
Shift, methanation
hydrotreating
Wastewater
treatment
Coal preparation
Gasification or
liquefaction
Boilers
Base metals, hydrocarbons,
miscellaneous accumulated
contaminants (such as sul-
furic and organic nitrogen
compounds
Tars/oils, biosludge
Coal fines, inerts
Ash and heavy metals
Ash
5.4.1 Stream No. 15, Spent Catalysts
Some of the catalysts used in coal conversion are the same as those used
in refining operations. For example, cobalt-molybdate catalysts are used in
the hydrotreating of product oil in the COED process and in refinery hydro-
treating. The contaminants, which will be present on the spent hydrotreating
52
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catalysts, would differ considerably between coal conversion systems and re-
fineries due to feedstream differences (coal-derived products vs. products
derived from crude oil). The technologies presently employed by refiners
(resource recovery, landfilling, landspreading) will most likely find appli-
cation in coal conversion plants.
5.4.2 Stream No. 16. Sludges
Tar and oily sludges are produced in the treatment of oily wastewaters
by gravity separation and/or flotation and in emulsion breaking. Depending
on the system design and the nature of the raw wastewater and emulsions,
these sludges can contain a substantial amount of water. Sludges from the
API separators in petroleum refineries have been reported to contain from 7%
to as much as 93% oil" '. The characteristics of the organic fraction of
the sludge would be similar to the bulk tars and oils produced in coal conver-
sion processes. Because tars and oils are removed from the raw gas in a
quenching operation, tar and oily sludge would contain high levels of coal-
derived organic and inorganic particulate matter.
5.4.3 Stream No. 17, Particulates from Coal Preparation
The source of particulates from coal preparation will be the particulates
removed by equipment used to control emissions from crushing, handling and
storage operations. The composition of this stream will be somewhat similar
to the feed coal composition. Some coal conversion processes can take these
particulates (mostly coal fines) as feed; in other processes, the coal fines
are rejected as waste or incinerated for heat recovery.
There is no refinery counterpart to coel preparation particulates. Con-
trols to be used in coal conversion plants may include: briquetting and using
as feed to the coal conversion processes, burning in a pulverized coal boiler
or disposing with the ash or char from the conversion process.
5.4.4 Stream No. 18, Ash or Char from Coal Conversion
The ash or char remaining after coal conversion will comprise the major
solid waste from coal conversion plants. The volume involved will be very
large (dependent upon the ash content of the feed coal and the carbon convex
sion efficiency of the process). Data on the composition of the ash from the
Lurgi process and the elemental analysis of char from the COED process are
53
-------
presented in Table 5-11. Due to differences in feedstocks (coal vs. oil) and
operations, no counterpart to the ash or char stream exists in refineries.
However, the solid waste management technologies employed in refineries and
other industries (e.g., landfilling and landspreading) would be applicable to
the control of the waste stream in coal conversion plants. Char generated in
coal conversion plants may be used as a fuel for steam, for electricity genera-
tion, or further gasified (as in the Cogas process).
TABLE 5-11. ASH AND CHAR CHARACTERISTICS*
Constituent (wt. %)
Carbon
Si02
A12°3
Fe2°3
CaO
MgO
S
Cl
H
0
P
Lurgi (ash)
3.2
49.6
20.5
17.2
2.1
1.0
1.3 (as S03)
0.01
--
--
COED (char)
80.9
--
--
0.5 (as S)
1.3
0.4
1.4
*No data available on the composition of the slag slurry
for the K-T process; the composition of the slag, however,
is expected to be similar to that of coal ash.
5.4.5 Stream No. 19, Ash from Coal Burning
Where coal is used as the boiler feed for steam and/or electricity gene-
ration, ash is the solid waste stream. The characteristics of this stream
are dependent upon the type and composition of the coal employed and the
boiler type used. Since refineries do not use coal for steam/electricity
generation, Stream No. 18 has no counterpart in refineries. In coal conver-
sion plants, the ash from coal burning can be disposed of (along with the ash
from coal conversion) using such methods as landfilling.
54
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6.0 REFINERY CONTROL TECHNOLOGIES AND THEIR APPLICABILITY TO COAL CONVERSION
SYSTEMS
In this chapter the processes used by petroleum refineries for the con-
trol of gaseous, liquid and solid wastes are discussed and their applicabili-
ties to coal conversion waste streams are evaluated.
6.1 GAS PROCESSING AND CONTROL OF GASEOUS EMISSIONS
Refinery gas processing and emission control technologies which may find
applications in coal conversion plants include: acid gas treatment, sulfur
recovery and tail-gas treating processes; incineration (flaring); and control
devices for fugitive emissions.
6.1.1 Acid Gas Treatment Processes
In petroleum refineries, acid gas treatment consists of removal of H«S
and other sulfur compounds from (a) sour gases to produce clean-burning fuel,
and (b) from feed gases to protect downstream unit operations. The removal
of acid gases from the raw product gas in coal gasification and from raw fuel
gas in coal liquefaction are carried out primarily to achieve the following:
Removal of H2S and other sulfur compounds to produce "clean
fuels" and to protect downstream gas processing catalysts (e.g.,
methanation catalyst in high Btu gas production)
Removal of COg to produce high Btu gas suitable for long dis-
tance pipeline transportation.
H«S and C02 may be removed either simultaneously ("nonselective") or
separately ("selective"), depending on the specific acid gas removal process
chosen and its design.
Selective processes produce a concentrated H^S stream which can be
treated in a Claus plant for sulfur recovery. In coal gasification applica-
tions where the feed gas has a high COp/H^S ratio, nonselective processes
would generate a stream containing nearly the same COg/HgS ratio as the feed
gas and hence require treatment by processes other than Claus (e.g., Stretford,
55
-------
which can handle dilute H2$ levels). In general, sulfur recovery from concen-
trated streams offers considerable economic advantage. The CO^ stream generated
in the selective processes may contain too high a level of residual H-S for
atmospheric discharge and hence may require additional treatment. The specific
acid gas treatment process (selective or nonselective) to be used in a coal
conversion plant should be selected with due consideration to the integration
of the process with sulfur recovery and/or tail gas treatment and the overall
economics of the sulfur management scheme.
Processes which are used in refineries for bulk acid gas removal from
sour gases generally use solvents or solutions for the removal of acid gases.
Depending on the process, the spent solution is regenerated by heating, de-
pressurization or oxidation. The regeneration results in the production of
a concentrated by-product gas stream which can be processed for sulfur re-
moval and/or recovery. Solvent processes may be broadly classified as physi-
cal solvent processes, chemical solvent processes (amine based and carbonate
based) and mixed solvent processes. The processes used in refineries and
conversion facilities in each category and their key features are presented
in Table 6-1. Redox systems such as Giammarco-Vetrocoke process, which are
suitable for bulk acid gas removal and have been used for this purpose in
the natural gas industry, are not considered here as no such applications
have been reported in refineries. Redox systems, however, are used in refin-
eries for tail gas treatment (see Section 6.1.3). As shown in Table 6-1,
physical solvents offer good selectivity for removal of H«S over COg and can
remove other sulfur and nitrogen compounds, water vapor, and some organics.
Physical solvents are more effective and economical when high partial pres-
sures of acid gases are encountered. Amine solvents are generally less selec-
tive than physical solvents and have higher energy requirements for regenera-
tion. As the partial pressure of acid gas in the gas stream increases, the
economy of amine systems declines. Mixed solvents show low selectivity for
H2$ over C02.
The choice of an acid gas treatment process for use in coal conversion
plants is influenced by the processes used for subsequent tail gas treating
and/or for sulfur recovery. In addition, in the production of high Btu gas,
factors such as residual sulfur, CtL, organics, and moisture levels in the
56
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TABLE 6-1. KEY FEATURES OF SOLVENT PROCESSES USED IN REFINERIES FOR ACID GAS REMOVAL
Process Name
PHYSICAL SOLVENTS
PJ>J- f- 4 »ft1
KcCllSO 1
Selexol
Purl sol
Fluoi* cnlvpnt
r i uui au i vcn v
-Estasolvan
CHEMICAL SOLVENTS
Sulflban
HDEA
ADIP
Fluor Econamlne
Alkazld
MIXED SOLVENTS
Sulflnol
Ami sol
Solvent/Regeant
«J J.L . 1
ncuianoi
Dimethyl ether of
polyethylene glycol
N-nethyl
2-pyrrolldone
Propy l ene
carbonate
Trl-n-butyl
phosphate
Monoethanolamlne (HEA)
Mathvl*riio+hjinft1 .
ncuijr i vu i c tnanu i
amlne
01 1 sopropanolamt ne
01 glycol amlne (OGA)
Dimethyl or dlethyl
glydne
Cyc 1 otetramethy 1 ene
sulfone and dllsopro-
panolamlne
Hethanol and mono- or
dlethanol amlne
Operating Pressure
(add gas partial
pressure)
High
High
High
U1nh
n ign
High
Low
1 r»rf
LOW
Low
Low
Low
Moderate
Moderate
Selectivity
H2S/C02 C02/HC
Good Poor
Good Moderate
Good Moderate
HnHaiMt t A !4V\Hov*ji fro
nooera te noaera te
Moderate Moderate
Poor Good
lfcufAf*»tA A/w\H
noaerQLc uuoa
Poor Good
Poor Good
Moderate Good
Poor Moderate
Poor Moderate
Component Distribution*
Higher Water
COS C$2 RSH KH-j HCN Organ tcs Vapor
a.b a,b a.c.d c.d a.c.d a,b,c,d d
a.b a,b a.d a,d a, c.d a.b, c.d d
a.b a.b a.d a.d a.c.d a.b.d d
e e a.b.d a.d e a,d d,g
d.b a.b a.b.d a.d e a.d d.g
a.b a.b a.b.d a,d e a.d d.g
f.g f.g d.9 a.d e a.d d.g
a.b a.b a.b a.d a,d a.b.d d.g
a.b a.b a.d a.d a.d a.b.d d.g
Solvent losses
(Replacement
Requirement)
High
Low
Low
Low
Low
High
Moderate
Moderate
Low
Low
Low
High
\
Utility
Requirements'^
Moderate/ Low
Low
Low
Low
Low
Very high
High
High
High
High
Moderate
Moderate
cn
*a with acid gas stream after simultaneous CO; and H2S removal
CO? stream after separate C02 and H2sVanovat
H2S stream after separate C02 and H2S removal
with
with
with aqueous or organic liquid phase prior to or integral with process
degrades solvent
hydro!yzes
remains with treated gas
^Depends on acid gas partial pressure, selective vs. non-selective design, and residual sulfur
with <10 ppm residual H2S In treated gas.
allowed; rating Is for moderate to high pressure application
-------
treated gas influence the design of methanation and associated guard systems.
Based on the published data for various acid gas treatment processes and the
results of several other studies evaluating acid gas treatment systems for
(19 20 21 31)
coal conversion applicationv ' ' ' , the following conclusions can be
drawn:
0 Physical solvent processes are the most likely candidates for use
in coal conversion plants where acid gases are at high pressures
and selective H£S removal is desired (e.g., in the Lurgi and Hygas
gasification processes). Processes such as Rectisol and Selexol
offer high selectivity toward H2S and would be economical (com-
pared to amine and mixed solvent processes) for high pressure
operation. In SNG production, residual sulfur and C02 levels
obtained are consistent with methanation catalyst protection
requirements (i.e., only small sulfur guard beds would be required).
Also, water vapor and organics which can deactivate either the sul-
fur guard or the methanation catalyst are largely removed.
Amine based processes are not likely to be commercially employed
for bulk acid gas removal in SNG production but may be used in con-
junction with the production of fuel or synthesis gas. MEA and
DEA suffer both excessive degradation and vaporization losses.
Even the more stable and less volatile solvents (e.g., DIPA, DGA)
are uneconomical at high pressures and are not selective enough
toward H2S. The use of such processes would result in an acid
gas stream containing as low as 0.3% H2$ and the remainder C02-
This presents a major problem for subsequent sulfur recovery/
removal. Amine based processes are suitable for nonselective
applications to low pressure feed gases such as the low/medium
Btu gas from Koppers-Totzek and Wellman-Galusha gasifiers and
fuel gas from low pressure liquefaction processes (e.g., COED).
One amine solvent (ADIP) has been proposed for use in a commer-
cial SNG facility for the purpose of recovery of hydrocarbons
and concentration of f^S from the concentrated acid gas stream
from a physical solvent process (Rectisol).
Mixed solvents (e.g., Sulfinol) have generally the same advant-
ages and disadvantages as the amine system. Since mixed solvent
processes incorporate some of the advantages of the physical sol-
vent, they can be more economical than the amine system for medium
pressure application.
Even though all the processes listed in Table 6-1 are reported to have
been used in refinery applications, nearly all the data published in the lit-
erature on the performance of these systems pertain to applications in natural
gas desulfurization. The amine systems are more widely used in refineries
than other acid gas treatment systems, primarily because the feed gases are
58
-------
generally at relatively low pressures and temperatures and contain high con-
centrations of H2S (high H2$/C02 ratio). In refinery applications, the amine
systems can produce a concentrated acid gas suitable as Claus plant feed. As
discussed in Section 5.2.1, the product gas in coal conversion processes con-
tains a much lower HgS level and a much higher level of COg and hence is not
suitable for processing by amine systems. Moreover, since amine systems are
not suitable for processing hot gases, the product gases from coal conversion
require more extensive cooling than when processes such as Selexol are used;
such cooling would constitute a thermal penalty. In addition, coal conversion
gases contain higher levels of components such as HCN, NH,, COS and tarry mate-
rials which can cause a more rapid degradation of the amine solution. In re-
finery applications, the amine systems have been shown to be capable of pro-
ducing a product gas containing a few ppm ^S and several hundred ppm COg (cor-
responding to removal efficiencies of more than 99.9% and 99%, respectively).
The Sulfinol and the Selexol processes, which are reported to have been
used for the treatment of refinery acid gases, have been used or are planned
for use in coal conversion applications. The Sulfinol process has been used
at a Koppers-Totzek facility in Turkey. The Synthane pilot plant at Bruceton,
Pa., and the Texaco pilot plant at Montebello, Ca., feature Selexol units for
the removal of HgS from product gas. No operating data are currently avail-
able on the performance of these processes in either refinery or coal conver-
sion applications.
Although some of the refinery acid gas treatment processes have been
used in or would have applications to coal conversion, a number of other pro-
cesses have been developed or are under development specifically for the
treatment of coal conversion acid gases. These processes, which are not dis-
cussed in this report, are Rectisol and Benfield solvent processes and hot
gas treatment systems using solid sorbents.
6.1.2 Sulfur Recovery
Processing of concentrated sour gases from acid gas treatment units and
sour water strippers for the recovery of sulfur in elemental form is widely
practiced in refineries using the Claus sulfur recovery process. Sulfur re-
cover from dilute sour gases (less than 10% HS) is also practiced in a few
59
-------
refineries using the Stretford sulfur recovery process. Key features of the
Claus and Stretford processes are summarized in Table 6-2.
As indicated in Table 6-2, the Claus process is generally applicable to
feed streams containing a minimum of 10%-15% H^S, whereas the Stretford and
G-V processes are applicable to feeds containing around 1% HgS. (Some Claus
plants have been designed and are operating on feeds containing as low as 5%
KLS. The Stretford process has also been used with feeds containing more than
10% HpS. At these high concentration levels, however, the Stretford process
is not economically competitive with the Claus process.) The treated gas from
the Claus process generally contains several thousand ppm of sulfur compounds
(primarily hLS), whereas the treated gas from Stretford contains less than a
few ppm of HpS. The Claus process is a dry, high temperature process in which
HpS is catalytically reacted with S0« (produced by air oxidation of the H^S)
to form elemental sulfur. When processing gases with very high hLS con-
centrations (e.g., in most refinery applications), Claus plants are generally
designed for "straight through" operation. In this operation mode the entire
volume of the gas and a stoichiometric quantity of air to oxidize only one-
third of the HpS to SOo are passed through the catalytic reactor. The Stret-
ford is a liquid-phase oxidation system using aqueous solutions of alkaline
metavanadate/anthraquinone disulfonic acid. While other reduced forms of sul-
fur (e.g., C$2 and COS) are partially removed by the Claus, they are not re-
moved by the Stretford process. Since the Claus process operates at a rela-
tively high temperature, it is also capable of oxidizing some of the hydro-
carbons. High concentrations of hydrocarbons, hydrogen cyanide and ammonia
(when C02 levels are high) can result in Claus catalyst fouling, product sul-
fur contamination, and equipment corrosion (in the case of HCN).
The Claus process is likely to find wide application for sulfur recovery
in coal conversion facilities when selective H«S removal from gases is prac-
ticed. The "split flow" and the "sulfur-burning" designs are likely to be
employed for coal conversion applications rather than the "straight through"
mode commonly employed in refineries since the high CO^ levels found in most
coal conversion acid gases result in unstable flame conditions in the
"straight through" Claus reactor. In the split flow mode, the acid gas
stream is divided in the ratio of 2:1 and the smaller stream is oxidized
60
-------
TABLE 6-2. GENERAL CHARACTERISTICS OF CLAUS AND STRETFORD SULFUR RECOVERY PROCESSES
Process
Claus
Stretford
Process
Principle
Catalytic
oxidation
of HzS to
elemental
sulfur
Liquid phase
oxidation of
H2S to ele-
cental sul-
fur In an
alkaline
solution of
oetavanadate
and anthra-
qutr.one dt-
sulfonlc acid
(ADA) salts.
Limits of
Applicability
Straight- through
system utilized
for higher HjS
concentrations.
Spllt-strean
system utilized
for lower HjS
concentrations.
Minimum of 10-151
sulfur in feed
stresn.
Maximum of 10 to
151 sulfur In
feed stream.
Present applica-
tions are gen-
erally for U
sulfur or less.
Control Efficiencies (X)
H#
90 - 95
99.9 or
greater
COS/CSj
90
0
R-SH
95
0
HCM
Partially
oxidized
-100
(converted
to SCH- In
Stretford
solution)
NH3
Partially
oxidized
0
KC
90
0
By-Product
Elemental
liquid
sulfur
Elemental
sul fur
Effect of CO?
Can adversely
affect sulfur
renoval ability
and therefore
increase pl;nt
size. If C02
exceeds 30 and
KH3 exceeds 500
ppnv, catalyst
plugging pro-
ble-s may occur.
High COj concen-
trations will
decrease absorp-
tion efficiency
by lowering solu-
tion alkalinity.
Increasing absor-
ber toner height
and base addition
are required.
Commercial
Applications
Widely erolojed In
pctroleur refinery.
natural g;s , tri
b)-nrodjc: cc-.e
tndjstry. ',o known
applications to
ccal ossification.
Prirarily natural
gas service, a few
applications to ptt-
rcleun refining jrd
by-product cove in-
dustries. A unit is \
under coistrj:ticn
at the Lurgi gasifi-
cation facility at
Sasol, So. Africa.
CT»
-------
with air and recombined with the larger stream to produce elemental sulfur in
the catalytic converters. In the "sulfur-burning" mode, liquid sulfur is
added to the feed along with air to produce the SCL needed for the Claus re-
action. Claus plant design and operation in coal conversion applications may
require modification to handle high hydrocarbon concentrations in the concen-
trated acid gas stream resulting from the use of processes such as Rectisol.
Alternatively, hydrocarbon removal from Claus feed (and HgS enrichment) may
be accomplished by use of processes such as ADIP. It is likely that overall
Claus plant sulfur recovery efficiency will be somewhat lower in coal conver-
sion applications than in refinery applications, primarily because of the less
concentrated FLS feed stream. To minimize catalyst fouling, ammonia and HCN
must also be removed from the Claus plant feed. Claus plants have not been
used in any of the existing commercial coal conversion facilities but are
featured in some of the designs for proposed commercial facilities in the U.S.
The Hygas high Btu gasification pilot plant in Chicago reportedly includes
a small Claus unit for the treatment of acid gases from a DGA acid gas
(22}
treatment unitx '. No operational data, however, are available on this unit.
The Stretford process is very likely to be employed for sulfur recovery
where (a) low sulfur coals are used as feed in coal conversion facilities,
(b) nonselective HgS removal from gases is practiced, and/or (c) where selec-
tive HpS removal results in the generation of a CCL-rich stream containing
levels of HgS too large for direct atmospheric discharge. These high C(L (and
other constituent) levels in coal conversion acid gas streams will necessitate
design and operational modifications to those versions of the Stretford pro-
cess which have been employed in refineries. The modifications include (a)
larger towers and more gas/liquid contact surfaces to achieve high ^S re-
moval efficiencies, (b) caustic addition to maintain proper pH levels, and
(c) high rates of solution blowdown to prevent dissolved solids buildup and
subsequent precipitation in the system and to maintain solution activity when
degradants such as HCN are present in the feed.
6.1.3 Tail Gas Treatment
Depending on the influent gas characteristics and the specific sulfur
recovery process employed, the treated gas from a sulfur recovery system may
require additional treatment before discharge to the atmosphere. Such
62
-------
additional ("tail gas") treatment may be necessary to achieve a higher level
of H2S removal (e.g., when the Claus process is used for sulfur recovery) and/
or for the removal of hydrocarbon and other forms of sulfur (e.g., COS, C$2>
etc.). As with the sulfur recovery processes, the tail gas removal systems
have not been used in connection with coal conversion, but many of them are
used in refineries (mostly new refineries) to meet air pollution emission
regulations.
Table 6-3 summarizes the key features of the sulfur recovery tail gas
treatment processes which have been used in refineries. The processes listed
in this table fall into three general categories: (a) processes such as IFP-1
and Sulfreen, which are essentially extensions of the Claus process; (b) pro-
cesses such as Beavon, Cleanair and SCOT, which catalytically reduce the more
oxidized sulfur compounds (e.g., S02, CS2> and COS) to hydrogen sulfide which
is recycled to the sulfur recovery systems; and (c) processes such as Chiyoda
Thoroughbred 101, Wellman-Lord, IFP-2 and Shell CuO, which involve the removal
of S02 by scrubbing and require feed incineration to convert all sulfur com-
pounds to S02.
The first category of processes has been employed exclusively for Claus
plant tail gas treatment and is capable of reducing the sulfur level to less
than 500 ppmv. As with the Claus process, these processes can tolerate high
concentrations of C02 in the feed gas. In the Beavon, SCOT and Cleanair pro-
cesses, hydrogen or synthesis gas is used for the reduction of oxidized sul-
fur; the reduction is carried out over a cobalt-molybdate catalyst. In exist-
ing refinery applications, the product hydrogen sulfide in the tail gas from
the Beavon and Cleanair processes is treated for H2S removal/sulfur recovery
by the Stretford process. The alkanolamine process is used for H2S recovery
in the SCOT process. Total sulfur levels of less than 100 ppmv have been
achieved by the application of Beavon-Stretford and SCOT-alkanolamine systems
(although levels of 250 ppmv are more common). In constrast to the first
category of processes (processes which extend the Claus reaction), the reduc-
tion processes are adversely affected by high levels of C02 in the feed gas.
The C0? in the feed gas reduces the efficiency of the catalytic reduction of
COS and CS« and impairs the effectiveness of the Stretford and alkanolamine ab-
sorption systems. The third category of processes, which involve Incineration
63
-------
TABLE 6-3. KEY FEATURES OF SULFUR RECOVERY PLANT TAIL GAS TREATMENT PROCESSES
Tall Gas
Removal
Process
Chlyoda
Thoroughbred
101
Beavon
Cleanalr
IFP-1
IFP-2
Process Principle
Thermal oxidation
of sulfur com-
pounds to SO?.
followed by liquid
absorption
Catalytic reduction
of sulfur compounds
to H?S. followed
by Stretford
process
Catalytic reduction
of sulfur com-
pounds to HgS,
followed by a con-
tinuation of the
Claus reaction and
Stretford process
Liquid phase con-
tinuation of Claus
reaction at a low
temperature
Incineration of
tall gas. followed
by annonla scrub-
bing. Solution Is
evaporated to pro-
duce a concentra-
ted SO? strean
which is returned
to the Claus plant.
Feed Stream
Requirements/
Restrictions
Incinerated Claus tall
gas; no specific
requlrenent on H,S:SO-
ratlo * i
Sulfur recovery pro-
cess tall gas 1s
heated upstream of
catalytic reactor; no
specific H2S:S02
ratio required
H2S:S02 ratio can
vary up to 8:1 with-
out affecting effi-
ciency; designed
specifically for
Claus tall gas
H2S:S02 ratio main-
tained In the range
of 2.0 to 2.4
HgSiSOj ratio main-
tained In the range
of 2.0 to 2.4
Sorbents/
Solvents
21 (by wt.)
sulfurlc acid
solution
Stretford
Process
solution
Unknown aque-
ous solution
and Stretford
process
solution
Polyalkallne
glycol
Aqueous
ammonia solu-
tion
Product
Gypsum
(CaS04-2H,0)
5 to 201 '
moisture
content
Elemental
sulfur
Elemental
sulfur
Elemental
liquid
sulfur
Elemental
liquid
sulfur
Utility
Requirements
Very high
Low
Very low
Very low
High
COS and CS2
Removal
Largely oxidized
by Incineration,
not absorbed by
solution
Catalytlcally
converted to
H2S
Catalytlcally
converted to
H2S
Not removed In
catalytic reactor
Oxidized by In-
cineration, not
removed In cata-
lytic reactor
Efficiency
951 S02 or less
than 300 ppmv
99.81 removal
for Claus tall
gas containing
41 equivalent
II2S
Plant effluent
normally guar-
anteed to con-
tain less than
250 to 300 ppm
S02 equivalent
Capable of re-
ducing sulfur
species In Claus
tall gas to 2000
ppm as S02
Capable of re-
ducing sulfur
species In Claus
tall gas to less
than 500 ppm
Effect of CC^
In Feed Gas
No effect
Reduces conversion
efficiency by
catalyst; decreases
H2S absorption by
Stretford solution
Reduces conversion
efficiency of
catalyst; decreases
H2S absorption by
Stretford solution
No effect
No effect
(continued)
-------
TABLE 6-3. CONTINUED
Tall Gas
Removal
Process
Sul freen
Shell
Copper
Oxide
Wei Inn-
Lord
SCOT
Process Principle
Solid phase con-
tinuation of Claus
reaction at a low
temperature
Thermal oxidation
of sulfur com-
pounds to S02.
followed by adsorp-
tion by CuO; a con-
centrated SO;
stream Is produced
by desorptlon with
a reducing gas (Hz)
Thermal oxidation
of sulfur com-
pounds to SOz,
followed by liquid
absorption; concen-
trated SOz 1s pro-
duced and recycled
to Claus plant
Sulfur species are
catalytlcally re-
duced to H?S; H2S
1s scrubbed In a
regenerate amlne
system
Feed Stream
Requirements/
Restrictions
Optimum performance
requires HzS:SOz
ratio of 2:1
Incinerated Claus
tall gas; no specific
requirement on H?S:
SOz ratio
Incinerated Claus
tall gas; process can
handle SO? concentra-
tions well over
10,000 ppm
Applicable to Claus
tall gas
Sorbents/
Solvents
(tone; sulfur
vapor conden-
sation process
utilized
Copper oxide
Concentrated
sodium
sulflte. bi-
sulfite
solution
Al kanol ami ne
solution
Product
Elemental
liquid
sulfur
Concentrated
S02 stream
Concentrated
SO? stream
(up to 90S
SOz content)
Concentrated
H^S stream
Utility
Requirements
Very low
No data
available
High
Moderate
COS and CS.
Removal
Not appreciably
removed
Oxidized by
Incineration
Oxidized by
Incineration,
not removed
by process
Catalytlcally
reduced to
H2S
Efficiency
Capable of re-
moving 80 to
85t of sulfur
. In the tall oas
90S SOg removal
Can remove In
excess of 95S
of SOz
Can remove 97X
of sulfur
species
Effect of CO.
1n Feed Gas'
No effect
1
No effect
Reduces conversion
efficiency by
catalyst; high COj
levels reduce
efficiency of
al kanol amlne
system
Ol
-------
followed by SO- recovery, has been applied to Claus plant tail gas and to
utility boiler flue gases. These processes are capable of removing over 90%
of the total sulfur in the feed gas. The Chiyoda Thoroughbred 101 and the
Shell-CuO processes which employ sulfuric acid and CuO as sorbents, respec-
tively, are not affected by high levels of COg in the feed gas. In the
Wellman-Lord process the sorbent is an alkaline solution of sodium sulfite/
bisulfite whose capacity for S02 absorption may be affected by very high levels
of COp in the feed gas. (Use of the Wellman-Lord process for S02 removal has
been successfully demonstrated on flue gases from coal-fired utility boilers
which would contain over 10% v CO^.)
With the exception of the catalytic reduction processes (Beavon, Cleanair
and SCOT) which may not perform well on high C02 tail gases,* all of the pro-
cesses listed in Table 6-3 are likely candidates for Claus plant tail gas de-
sulfurization in coal conversion facilities. The processes which remove sul-
fur as S0« require incineration of the tail gas to convert sulfur compounds to
SOp. Use of these systems in an integrated commercial coal conversion plant
would be attractive if desulfurization of boiler flue gases is also required
since the desulfurization can possibly be combined in a single operation. It
may also be possible to treat the gases separately for S02 absorption, but
regenerate S02-rich absorbents in a single unit. The choice of individual
processes will be dictated by overall economics and specific emission limita-
tions at the plant site.
6.1.4 Incineration (Flaring) of Haste Gases
Flaring of waste gases is commonly practiced in refineries as a safety
and emission control technique. The primary purpose of flaring is to convert
organics, carbon monoxide, and reduced sulfur and nitrogen compounds to less
hazardous forms (e.g., COp, S02> NO ). Most flares in refinery service are
elevated above ground level to provide for improved pollutant and heat dis-
persion. Steam (or other inert gas) is injected in the combustion zone of
the flare to enhance turbulent mixing of waste gas and air and to suppress
smoke formation. Since the quantity and composition of refinery waste gases
*Union Oil Co., the vendor-licensor of the Beavon process, however, intends
to offer a 250-ppmv performance guarantee for the process in coal gasifica-
tion applications(23).
66
-------
vary widely over short periods of time, modern flares incorporate sensors and
feedback controls to regulate air and steam feed rates in response to changing
waste gas combustion characteristics.
Because of the highly variable nature of waste gases commonly flared, it
is generally difficult to achieve the proper combustion conditions consistent
with minimum emissions of oxidizable substances. Thus, even with sophisticated
flare control systems, emissions of CO, unburned hydrocarbons, and odors are
generally higher from flares than from other stationary combustion sources of
a comparable heat rating. Although some noise is inherent in the release
of steam through flare orifices, the venting of combustion products to the
atmosphere, and the combustion process itself, such noise can be minimized by
proper flare design (e.g., reducing the size of steam injection orifices) and
operating conditions (e.g., using a minimum amount of smoke suppressant).
Waste gases in coal conversion facilities which would be treated by flar-
ing are primarily those associated with transient operations. Such waste gases
would be highly variable in composition and quantity and hence a high degree
of combustion control is needed for effective emission control.
6.1.5 Control of Fugitive Emissions and Odors
Fugitive hydrocarbon emissions can be a major source of air pollution in
petroleum refineries. Major sources of such emissions which would have
counterparts in coal conversion plants inlcude storage vessels, loading and
transportation, pump and compressor seals, pressure relief valves, pipeline
valves and flanges, pipeline blind changing and sampling lines. In new plants
many of these emissions can be significantly reduced by proper design and
equipment selection. For example, highly volatile products such as butane
and naphtha must be stored in pressure tanks; less volatile materials such as
kerosene and crude oil can be stored in floating-roof and variable vapor space
tanks. It has been shown that centrifugal pumps with mechanical seals have
approximately 33% lower hydrocarbon emissions than centrifugal pumps with
packed seals' . Fugitive emissions caused by leaks from pumps, valves,
etc. can be minimized through routine equipment maintenance. Although these
control methods are not unique to refineries, the extent of control required
would depend on the number of sources and magnitude of emissions which would
vary from industry to industry and from plant to plant depending on the size
67
-------
of the operation, process employed, materials handled, age of the equipment
and maintenance programs. In comparison to refineries, most coal conversion
plants are expected to have a more restricted range of liquid and gaseous pro-
ducts and on an equivalent product basis fewer sources of fugitive emissions.
Furthermore, coal-derived liquids would have less of the more volatile compounds
than crude oil and petroleum-derived products (e.g., syncrude vs. crude oil).
The refinery add-on fugitive hydrocarbon emission control methods which
may be applicable to coal conversion include use of refrigeration and scrub-
bing vapor recovery systems on storage tanks, and disposal of collected hydro-
carbon vapors by thermal or catalytic incineration.
As in refineries, production of odorous compounds (e.g., H^S, NH~) would
be associated with the operation of almost all coal conversion plants. Be-
cause of the highly odorous nature of some of these compounds (e.g., mercap-
tans and heterocyclic aromatics such as pyridine and thiophene), their release
to the atmosphere, even in very small quantities, can present significant odor
problems. As with the hydrocarbon emissions, options for the control of odor
are limited to source control, incineration and carbon adsorption. Since in
an integrated facility fugitive emissions (e.g., from spills and leaks) and
emissions from nonprocess sources (e.g., cooling towers and wastewater treat-
ment units) can contribute significantly to the total odor emissions, good
housekeeping practices, proper operating procedures and routine maintenance
are essential to minimize the odor problem.
6.2 AQUEOUS WASTE PROCESSING AND WATER POLLUTION CONTROL
The major refinery aqueous waste treatment processes which may be appli-
cable (in some cases with certain design and operational modifications) to
coal conversion waste streams are sour water stripping for hydrogen sulfide
and ammonia removal; gravity separation, flotation and emulsion breaking for
the removal of oil from oily and tarry wastewaters; lagooning, biological
treatment, chemical oxidation and carbon adsorption for the removal of organ-
ics; and thickening, centrifugation, filtration, and drying for sludge
dewateri ng.
68
-------
6.2.1 Sour Water Stripping
Stripping is widely used in petroleum refineries for the removal of dis-
solved gases (primarily H«S and NH-) from sour waters. Stripping enables re-
covery of valuable products (ammonia and hydrogen sulfide) and significantly
reduces the waste loading on downstream treatment units. Stripping of dis-
solved gases can be effected by contacting the wastewater with a stripping
medium such as steam* flue gas, nitrogen, air, and carbon dioxide. The most
common stripping medium in refineries is steam, and the stripping operation is
usually conducted in a tower (packed or trays) with countercurrent (steam up,
water down) flow pattern. Acid (for H2S removal) or alkali (for NH3 removal)
may be added to the raw wastewater to improve stripping efficiency. Depending
on,,the HpS and NH, concentrations of the overhead vapors, the stripped gases are
sent to an acid gas treatment unit for further concentration before sulfur re-
covery; processed directly for recovery of sulfur (e.g., in a Claus plant),
sulfuric acid, anhydrous or aqueous ammonia or ammonium sulfate; or disposed
of by flaring. The flaring of stripper off-gases is generally being phased
out due to S0« and NO emission limitations.
£ n
Conventional steam stripping of the refinery sour waters can achieve
greater than 99% removal of H2$, and up to 95% removal of NH-. Since low
molecular weight phenols are somewhat volatile, sour water stripping can also
(25)
result in the partial removal of phenols (up to 90% in refinery applications^ ',
One major problem with conventional steam stripping is the difficulty in
recovering ammonia. One patented application of steam stripping which gen-
erates separate concentrated H0S and NH~ streams and has been used recently
(26^
in refineries is the Chevron WWT processv '. In the Chevron process separate
towers, which operate under different pressures and temperatures, are used
for H«S and NH3 stripping. Since the product ammonia stream contains some
residual H2S, this stream is scrubbed with liquid ammonia prior to pro-
cessing to convert the gaseous ammonia to anhydrous or aqueous ammonia or to
ammonium sulfate. The treated wastewaters from the Chevron process can have
residual H2S and ammonia as low as 5 and 50 mg/1, respectively.
The coal conversion wastes which would contain high levels of H2S and
NH3, and hence would be treatable by stripping, include raw gas quench waters
and partlculate scrubber waters from gasification, waste liquor purge from
69
-------
liquefaction, separated waters from hydrotreating, and condensates generated
in hydrogen production units. Some of these streams contain smaller quantities
of hydrogen cyanide and carbonyl sulfide which, because of their volatility,
would also be partially or totally removed by stripping. The fate of these
compounds depends upon the subsequent processing of the stripper off-gas.
When the off-gas is incinerated, these substances are expected to be largely
destroyed. When acid gas treatment is employed, these substances may be de-
stroyed (e.g., in the Benfield process) or may become components of the con-
centrated acid gas stream, the treated gas stream or the process solvent.
In the treatment of the concentrated acid gas stream (or the stripper off-gas)
for sulfur recovery, HCN is largely destroyed while carbonyl sulfide is par-
tially destroyed (e.g., in the Claus process) or unaffected (e.g., in the
Stretford process).
Neither the Chevron process nor conventional stripping has been employed
at pilot coal conversion facilities in the U.S. to date. Conventional steam
stripping with ammonium sulfate recovery, however, has been used at the Sasol
coal conversion complex in South Africa. A recent engineering study by C. F.
Braun and Company comparing various stripping processes for application to
coal gasification indicate that the Chevron process has higher capital and
operating costs than conventional steam stripping without by-product re-
(27)
coveryv . The value of recovered ammonia, however, significantly offsets
the added cost.
6.2.2 Oil and Suspended Solids Removal
In refineries, gravity separation is usually the first step in the treat-
ment of oily wastewaters for the removal of bulk separable oil and suspended
solids. API separators, which are gravity separators designed in accordance
with the criteria suggested by the American Petroleum Institute (API), are
(12)
widely used in petroleum refineries for this purposev . Gravity separation
is also used following biological or chemical treatment for the removal of
biological and chemical floes. In gravity separation the wastewater is
allowed to undergo "quiescent settling" in a basin. The oil globules, which
are lighter than water, float to and are collected at the surface; the settle-
able solids settle to the bottom and are recovered as sludge. The settling
basins are usually rectangular or circular in shape with "accessories" for
70
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the introduction of raw wastewater and collection of effluent, sludge and/or
oil. To maximize space utilization, the settling basin design may incorporate
use of inclined parallel plates/tubes, each representing a "mini basin" within
which solid-liquid separation takes place. The efficiency of gravity separa-
tion depends on the wastewater characteristics and the hydraulic ("surface
area") loading of the basin. The following ranges of removal efficiencies
have been reported for the API separators in refinery oil-water separation
applications: 10%-50% suspended solids; 50%-99% free oil, 5%-35% BOD and 5%-
30% COD.
Although also applicable to and used for the separation of solids heavier
than water, dissolved flotation is most widely used in lieu of or as a supple-
ment to conventional gravity separation for the removal of separable oils from
oily wastewaters. Air is dissolved under pressure in a portion of the raw or
treated wastewater or in the entire volume of the raw wastewater. In all
cases, the total wastewater volume is subsequently discharged to an open basin
(the flotation basin) where minute air bubbles which are released attach them-
selves to the oil particles and float them to the surface at a faster rise
rate than would be achieved otherwise. The reported data for refinery appli-
cations indicate that without the addition of chemicals, flotation can result
in 7Q%-9Q% removal of separable oils, 5%-25% BOD removal, 5%-20% COD removal
(28)
and 103»-40% suspended solids removalv . In designs for the gasification of
coal using the Lurgi process, the tar/oil separator operates on the flotation
principle.
Chemicals such as iron and aluminum salts and polymeric organics are often
added as coagulants or coagulant aids to improve the efficiency of gravity
separation and flotation operations. When added to wastewaters, these chemi-
cals can destabilize colloidal particles and agglomerate fine particles into
larger floes which settle or rise at a faster rate. Particle growth is often
facilitated by gentle mechanical mixing (flocculation). When used in conjunc-
tion with API separators or air flotation units, coagulation/flocculation can
increase removal efficiencies and/or enable higher throughput rates.
When very high levels of oil and suspended solids removal are desired
(e.g., for certain reuse applications), the conventional treatment such as
gravity separation and chemical treatment may be followed by filtration
71
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through a bed of inert solids such as sand, diatomaceous earth or anthracite.
The suspended solids trapped in the filter are periodically removed through
filter backwashing. As a polishing step for the API separator effluent, sand
filtration has been reported to achieve the following removal efficiencies:
70%-75% suspended solids, 52%-83% free oil, 25%-44% COD and 36%
Gravity separation and flotation would probably be the most suitable first
step for the treatment of oily wastewaters and wastewaters containing settle-
able solids in coal conversion plants. As discussed in Section 5.3, such
wastewaters include raw gas quench waters and waste liquor purge from product
liquids separation. Depending on the availability, cost and the quality of
the plant raw water and the effluent discharge requirements, the wastewater
treatment system for integrated coal conversion facility may incorporate chemi-
cal coagulation and/or filtration of the API separator effluent or the efflu-
ent from biological wastewater treatment units to produce an effluent water
suitable for recycling. The design of the API separator, flotation units and
chemical coagulation and filtration operations should be tailored to the parti-
cular wastewaters which are to be treated. The design of full scale units
should be based on the criteria (e.g., surface area loading for gravity sep-
aration units, air-to-solids ratio for flotation and hydraulic loading and
backwash requirements for the filtration units) developed in bench/pilot scale
tests, using actual coal conversion wastewaters or wastewaters having composi-
tions approximating those anticipated from a given coal conversion design.
The wastewater treatment at the Sasol , South Africa, coal conversion
plant uses (a) API separators for the treatment of the gas reforming plant
condensate; (b) Lurgi process tar/oil separators which operate on the flota-
tion principle; (c) flocculation of oily wastewaters from the Fisher-Tropsch
oil production and refining units; and (d) sand filtration for the treatment
(29)
of the trickling filter effluent^ . No data are currently available on the
composition of the wastewater handled at the Sasol plant and the performance
of the treatment units. The designs of high Btu gasification plants which
have been proposed for the U.S. incorporate gravity settling of ash quench
water (in the El Paso Burnham, New Mexico and ANG, North Dakota plants), API
separation for the raw gas quench water and air flotation of the API separator
effluent (in the Wesco, New Mexico plant)^30'31 *
72
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6-2.3 Dissolved/Particulate Organics Removal by Biological Oxidation
Following the removal of bulk HgS and NH3 from sour waters by stripping
and the removal of oil and settleable solids from oily and other process waste-
waters by gravity separation and flotation, in most large refineries the com-
bined plant effluent is treated by biological oxidation before discharge into
natural waters or municipal sewers or reuse. In biological treatment, the
dissolved and/or collodial organics are converted to inorganic end products
and microbial cells by the action of microorganisms. The resulting biomass
(sludge) is subsequently removed by gravity separation. Although biological
oxidation can be conducted under anaerobic (in the absence of oxygen) conditions,
aerobic (in the presence of oxygen) treatment is preferred for most applications
because of the high efficiency and lower costs. Anaerobic treatment is usually
used for concentrated organic wastewaters and sludges.
Table 6-4 lists the most commonly used biological treatment systems in-
cluding reported efficiency ranges far the removal of BOD, COD, SS, oil,
phenols and sulfide in applications to refinery wastewaters. As noted in the
table, biological treatment can result in up to 90% removal of the biologically
oxidizable compounds.
TABLE 6-4. EFFICIENCY OF BIOLOGICAL TREATMENT FOR PETROLEUM REFINERY EFFLUENTS*
Biological Treatment
Method
Activated sludge
Trickling filters
Waste stabilization
pond (aerobic)
Aerated lagoon
Cooling tower oxida-
tion (air stripping)
Spray irrigation
BOD
88-90
60-85
40-95
75-95
90+
99+
COD
60-85
30-70
30-65
60-85
90+
90+
SS
-
50-80
20-70
40-65
-
99+
Oil
-
50-80
50-90
70-90
-
70-90
Phenols
95-99+
-
-
90-99
99.9
99.9
S=
97-100
-
-
95-100
-
99+
*The ranges of values reflect differences in wastewater characteristics and
system design and operating conditions.
tThiocyanates are approximately 70% removed by these processes.
73
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Evaporation and retention ponds are widely used in the petroleum industry
for ultimate disposal of raw or treated wastewaters, as tertiary treatment
basins following biological treatment or as temporary storage ponds for con-
trolled effluent discharge. Although not classified strictly as waste stabili-
zation ponds, these ponds do achieve some biodegradation of organics. These
ponds, which are also referred to as "holding basins," "lagoons," "oxidation
ponds," "settling basins," etc., are usually natural or man-made earthen res-
ervoirs into which wastewaters are discharged. These ponds may be lined with
impermeable materials (plastic, clay, asphalt, etc.) to prevent infiltration.
The retention of the wastewater in the pond provides for natural evaporation,
settling of solids, biological decomposition of organics and loss of the more
volatile components of the waste to the atmosphere. In geographic regions
where annual evaporation exceeds precipitation, the ponds are generally de-
signed to have no effluent discharge. Ponds can also be used for temporary
waste storage and controlled discharge during high flows in the receiving
waters. Evaporation/retention ponds require minimum maintenance and, when
large land areas are available, can be the most economical method for waste-
water disposal. The Sasol gasification complex in South Africa uses a set-
tling pond for polishing treatment of the total plant effluent before discharge
into a river. Settling ponds are also used at all U.S. coal conversion pilot
plants and have been featured in all proposed designs for commercial SNG faci-
lities in the U.S.
The use of pure oxygen (in place of air) in the biological treatment of
wastewaters by the activated sludge process has received considerable atten-
tion in recent years and a number of pure oxygen activated sludge plants are
currently in operation handling municipal sewage and a variety of industrial
wastewaters. Compared to a conventional air activated sludge process, the
pure oxygen process is claimed to have several advantages, including higher
efficiency and loading rate, less sludge production, superior characteristics
of the sludge, and lower overall costs. In coal conversion facilities which
employ on-site oxygen production for process use (e.g., for high Btu gasifica-
tion using processes such as Lurgi), the use of an oxygen activated sludge
process would be attractive since a source of oxygen would be available for
wastewater treatment.
74
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Although not specifically used for biological wastewater treatment, cool-
ing towers havo been used at several refineries for biological treatment of se-
lected waste streams. The use of cooling towers for biological treatment has
also been demonstrated at the Sasol, South Africa, gasification plant. Cool-
ing towers provide ideal temperatures and surfaces for biological activity.
The oxygen required by microorganisms is provided by the extensive aeration
which accompanies the cooling process. In refinery applications, phenolic
wastewaters have been used as cooling water make-up and more than 99% destruc-
tion of phenols has been reported^ '. In a demonstration program at the
Sasol plant, the ammonia stripper bottoms have been used as cooling tower
(33)
make-upv . In this program the bioactivity, foaming, fouling and corrosion
which may be expected from the use of this wastewater for cooling water make-up
have been evaluated and the results have been used as a basis for the design
of a cooling/oxidation tower system for the proposed El Paso Burnham plant in
New Mexico.
Where soil, climate and hydrological conditions are favorable, biological
treatment may also be accomplished by the application of partially treated
wastewaters to soils. Microbiological processes in the soil can result in the
degradation of most biodegradable organics and the oxidation of ammonia, sul-
fide, and other pollutants. In addition, physical adsorption and filtration
results in the removal of phosphorus and most metalic elements. Depending on
the particular soil, the geographic location, and the rate of wastewater appli-
cation, net runoff or percolation may or may not be generated. Continued
application of wastewaters containing high levels of dissolved solids to soils
can result in salinity and/or alkalinity buildup to the point of adversely
affecting plant growth. The accumulation of certain trace elements and organ-
ics in soils may also present toxicity problems for plants or herbivores.
When improperly sited, designed and oeprated, land application of wastewaters
may present odor problems or result in the contamination of surface waters
and groundwaters.
In comparison to chemical and physical treatment processes (e.g., acti-
vated carbon adsorption, stripping, etc.), biological processes are signifi-
cantly more sensitive to wide fluctuations in wastewater characteristics.
When such fluctuations are anticipated (e.g., discharge from batch and
75
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transient operations), the biological treatment should be preceded by storage/
mixing facilities for equalization of flow and strength. Certain biological
treatment processes, such as the waste stabilization pond, aerated lagoon, and
completely mixed activated sludge process, can tolerate limited and short dura-
tion variations in wastewater characteristics since they feature near complete
mixing and large volume and retention time. Nutrients such as nitrogen (N)
and phosphorus (P) compounds are necessary for microbiological growth. A BOD:
N:P ratio of approximately 100:5:1 is generally necessary for the biological
treatment of most industrial wastewaters. When a wastewater is deficient in
nutrients, they must be added to the raw wastewater prior to biological treat-
ment. Coal conversion wastewaters are expected to have a sufficient amount
of nitrogen (in the form of ammonia) but be deficient in phosphorus content.
At the Sasol plant, South Africa, which uses trickling filtration for bio-
logical wastewater treatment, phosphate is added to the raw wastewater to
allow efficient operation.
In a coal conversion plant, biological oxidation would most likely be used
after the bulk of organics, reduced inorganics (e.g., ^S, NFL) and particu-
late matter have been removed by processes such as gravity separation, coagu-
lation/flocculation, flotation, phenosolvan and stripping. Several factors
affect the applicability and performance of biological oxidation for the pro-
cessing of coal conversion wastewaters. These factors relate to wastewater
constituent biodegradabi1ity, toxicity, pH, nutrient content and fluctuations
in characteristics. In contrast to the organics in refinery wastewaters which
are primarily aliphatic and mostly biodegradable, the organics in coal conver-
sion wastewaters tend to be highly aromatic. While certain aromatic com-
pounds such as simple phenols are readily degradable (at relatively dilute
levels), the more complex and substituted phenols, polycyclic hydrocarbons
and heterocyclic organics are generally less readily degradable or essentially
nonbiodegradabie (e.g., pyridine). Some of the organics (e.g., phenols at
high concentration levels), trace elements (e.g., arsenic and mercury) and
inorganic anions (e.g., cyanide and thiocyanate) can be toxic to microorganisms
at high concentration levels. Biological processes are generally most effi-
cient when the pH of the wastewater is in the 6-8 range. The pH of the waste-
water also affects toxicity of certain wastewater constituents. For example,
the toxicity of sulfide increases with decreasing pH. Provided that adequate
76
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nutrients are added, the wastewater pH is maintained near optimum and the wide
fluctuations in raw wastewater characteristics are prevented, coal conversion
wastewaters should be treatable by biological means either alone or in combina-
tion with sanitary sewage.
As noted above, the Sasol plant in South Africa employs trickling filters
for the treatment of combined plant and municipal wastewater. Oxidation towers
are featured in the proposed designs for the El Paso Burnham and Wesco SNG
plants in New Mexico for the treatment of ammonia stripper bottoms and bio-
logical treatment effluent, respectively. An oxidation tower is also proposed
for the ANG (North Dakota) SNG plant for the treatment of stripped gas liquor.
Since no commercial coal liquefaction or high Btu coal gasification facility
currently exists in the U.S. and very little data are available on wastewater
characteristics and efficiency of treatment processes at foreign facilities
(in terms of concentrations of specific pollutants in the influents and efflu-
ents of biological treatment units), the optimum design criteria and operating
conditions for the biotreatment of coal conversion wastes cannot be defined
at this time. Several studies ^34~3'> are currently under way which are aimed
at the characterization of coal conversion wastewaters and evaluation of the
biotreatability of such wastes.
6.2.4 Dissolved Organics Removal by Activated Carbon Adsorption
Several refineries have installed activated carbon adsorption systems for
the treatment of effluents from biological treatment or API separator. Acti-
vated carbon (in granular and powdered form) has also been used for the treat-
ment of municipal and a variety of industrial wastewaters. In comparison to
biological processes, carbon adsorption is unaffected by the presence of toxic
constituents in the wastewater and the fluctuations in wastewater characteris-
tics.* Granular carbon is used in fixed or moving columnar beds with either
upward or downward wastewater flow. Powdered carbon is generally mixed with
the wastewater and is subsequently removed by flocculation and/or filtration.
*When granular carbon is used in beds, some biological growth becomes estab-
lished in the bed which contributes to the overall organic removal efficiency
(via biodegradation). In this case the treatment efficiency would be affected
by the presence of toxic chemicals or by wide fluctuations in wastewater
characteristics.
77
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Because of its relatively high cost, the use of activated carbon adsorption
for wastewater treatment would generally be limited to (a) removal of residual
organics from the biological treatment effluents, when such removal is neces-
sary; (b) treatment of wastewaters containing high levels of refractory organics
or toxic chemicals; (c) in combination with chemical coagulation and filtra-
tion in a "physical-chemical" combination treatment scheme in lieu of biologi-
cal treatment; and (d) recovery of by-products (e.g., phenols) from the waste-
waters. Except when used for by-product recovery (e.g., for the recovery of
phenols from dilute wastewaters), the spent carbon is usually regenerated by
thermal treatment. In polishing of biologically treated refinery wastes, re-
moval efficiencies of up to 75% COD, 77% TOC and over 99% phenols have been
(38)
reported for granular carbon adsorptionv .
The use of activated carbon adsorption in commercial coal conversion
facilities would probably be limited to effluent polishing for water reuse
or discharge into receiving waters. Because of the relatively high cost of
activated carbon adsorption and the availability of alternative treatment/
disposal methods, the proposed commercial coal conversion plants for the U.S.
do not incorporate use of activated carbon adsorption. Because of the land
availability and the goal of attaining zero discharge, the proposed plants
are to use evaporation ponds (supplemented by distillation using process heat)
for ultimate wastewater disposal or water recovery. Due to the differences
in the characteristics of the coal conversion and refinery wastewaters (speci-
fically with regards to the types of organics present), the performance of
carbon adsorption in treating coal conversion wastewaters cannot be accurately
determined based on the performance data reported for refinery waste treatment.
In general, for any type of wastewater, the efficiency of activated carbon
adsorption, the most suitable type of carbon, and the criteria for the design
of large scale units are determined through laboratory adsorption isotherm
tests and laboratory/bench-scale column experiments. In certain coal conver-
sion processes (e.g., Synthane and COED) the use of carbon adsorption is
attractive because a char which is produced may have some capacity for sorp-
tion of organics. Studies by DOE-PERC have indicated that the Synthane char
has adsorptive properties similar to those of commercial activated carbon' .
Even though the char may have a much lower adsorption capacity than activated
78
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carbon, it may provide an economical source of carbon for wastewater treatment
at coal conversion plants. The spent char would be combusted/gasified in the
normal manner.
6.2.5 Chemical Oxidation of Organics and Reduced Inorganics
Chemical oxidation processes using oxidants such as oxygen (air), ozone
and compounds of chlorine have been used in industry for the treatment of
cyanide, sulfide, phenolic and thiocyanate wastes or their conversion into
biologically degradable substances. Air oxidation of foul waters having a
high sulfide content and spent caustic solution is being practiced at several
refineries using patented processes (e.g., Sulfox Process). In these cases
the wastewaters do not contain economically recoverable quantities of ammonia
or ^S to justify treatment by stripping with subsequent by-product recovery.
Air and steam (for temperature control) are mixed with the wastewater under
pressure and the wastewater is passed through a sulfide oxidation column which
provides the necessary contact time for oxidation. Air oxidation results in
the conversion of sulfide to thiosulfate and partial conversion of thiosulfate
to sulfate. Air oxidation thus lowers the oxygen demand of the sour water for
subsequent biological oxidation or discharge to receiving waters. Air oxida-
tion would probably be inapplicable to the treatment of coal conversion sour
waters because many of such wastewaters contain relatively large quantities
of ammonia which can be recovered as a valuable by-product. Furthermore,
when ammoniacal sour waters are treated by air oxidation, the ammonia would be
released in the column off-gases and may present an air pollution problem.
In addition, the oxidation of sulfides to thiosulfate and sulfate may be un-
desirable since it increases the total dissolved solids in the wastewater,
thus prohibiting further uses of water for certain purposes.
Ozone has been reportedly applied in the treatment of refinery waste-
waters as a cleanup step following biological oxidation and sedimentation.
Reductions in phenol concentrations from 0.16-0.4 mg/1 to less than 0.003 mg/1
have been reported^ '. Under proper conditions, ozonization should be effec-
tive in destroying most biologically refractory organics, including many of
those present in coal conversion wastewaters. Bench scale ozone treatment
of Synthane raw gas quench condensate indicates that complex organics (e.g.,
quinolines and indanols) and inorganics (e.g., SCN~) can be largely removed
79
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139)
with adequate ozone dosagev . Because of the high cost of ozonization
(compared to other residual organic removal techniques such as carbon adsorp-
tion and oxidation with chlorine compounds), the application of ozonization
to coal conversion wastes would probably be limited to polishing treatment to
meet effluent discharge requirements or for reuse.
6.2.6 Treatment of Slop Oil and Sludges
Slop oil (i.e., the oil separated from wastewaters by gravity separation
and flotation) still contains a large amount of water (mostly in emulsified
form) which may require removal prior to incineration or processing for oil
recovery. Emulsions can be "broken" by a number of methods including heat
treatment with or without chemical addition, precoat filtration, distillation,
centrifugation and electrolytic coagulation. It is expected that some of these
methods, particularly heat treatment and distillation, will find application
in commercial coal conversion facilities for the treatment of tars and oils
removed from raw gas quench waters.
Sludges generated as a result of physical, chemical or biological treat-
ment require further treatment for concentration and volume reduction (dewater-
ing) prior to disposal. Sludge dewatering is necessary to enable economical
land disposal or incineration. Sludge concentration methods which have been
used in refineries include gravity thickening, centrifugation, vacuum filtra-
tion, filter presses, and use of drying beds. These methods have also been
widely used in municipal and other industrial wastewater treatment practice
and considerable experience with them is available in a variety of applica-
tions. Table 6-5 presents reported data on solids concentration levels ob-
tained by use of various sludge concentrating processes handling chemical and
biological sludges. Chemicals such as lime, ferric salts and synthetic organic
polymers may be added to sludges to improve dewaterability. In general, bio-
logical sludges tend to be more difficult to dewater than inorganic sludges.
Biological sludges and some concentrated organic wastes can also be further
concentrated by use of anaerobic digestion whereby a portion of the organic
material is converted to methane and carbon dioxide. In addition to the re-
duction in sludge volume, anaerobic digestion improves sludge dewaterability
and filterability.
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TABLE 6-5. SOLIDS CONCENTRATION OBTAINED BY VARIOUS SLUDGE CONCENTRATING
PROCESSES*
Process
Gravity thickening
Centrifugation
Vacuum filtration
Drying beds
Type of Sludge Processed
Activated sludge
Activated sludge
Lime softening sludge
Activated sludge
Primary and activated
Solids Concentration
Obtained (%)
5-8
6-10
53-57
15-20
-40*
*The ranges of values reflect differences in sludge properties,
system design and operating conditions.
""After 15 days of drying, for one specific application.
The efficiency and cost of sludge concentration and dewatering are deter-
mined primarily by such sludge characteristics as concentration, size, shape and
chemical composition of solids and by viscosity and chemical composition of the
sludge liquid. For application to sludges for which previous experience does
not exist, the criteria for the design of full scale units and the determina-
tion of the optimum operating conditions are usually determined by laboratory
experiments and bench-scale studies (e.g., column settling tests for gravity
thickening and "leaf" filter tests for vacuum filtration).
Sludges in coal conversion plants which may require thickening and de-
watering prior to ultimate disposal include ash quench sludges, sludges from
air pollution control systems and chemical and biosludges from wastewater
treatment. Based on expected gross similarities between these sludges and
the sludges encountered in refineries and in the treatment of municipal and
other industrial wastewaters, conventional sludge thickening and dewatering
methods such as gravity thickening, centrifugation, vacuum filtration and dry-
ing beds should be applicable to the processing of coal conversion sludges.
Since no integrated commercial coal conversion facility currently exists in
the U.S. and no data are available on the characteristics of the sludges from
commercial coal conversion facilities abroad, the preferred process and the
optimum operating conditions for the treatment of coal conversion sludges can-
not be determined at this time. Because significant variations in sludge
characteristics are expected from plant to plant (reflecting differences in
81
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the type of coal processed; coal conversion, product purification and upgrading
operations used; and the air and water pollution control processes employed),
the selection of the optimum sludge processing method should be on a case-by-
case basis. The Sasol coal conversion plant in South Africa uses gravity
thickening for concentration of ash quench sludge, anaerobic digestion for
conditioning of biosludges from trickling filter units and drying beds for the
ultimate disposal of the anaerobically digested sludge. Detailed sludge char-
acteristics data and performance information are not available for the opera-
tion at Sasol. The raw wastewater handled at the Sasol plant is a combination
of municipal and coal conversion plant wastes and hence the sludges would be
expected to be different from those for a plant handling solely coal conversion
wastes.
6.2.7 Approaches to Waste Volume and Strength Reduction
Several approaches are used in petroleum refineries for wastewater volume
and strength reduction. These approaches, which include or provide for waste-
water segregation, by-product recovery, water reuse and recycling and good
housekeeping practices can also be incorporated in the design and operation
of integrated commercial coal conversion facilities to lower wastewater treat-
ment requirements and costs.
Most refineries use a system of segregated sewers for separate collection,
transportation and treatment of sour waters, oily waters, relatively "clean"
process waters and storm runoff. Such separation of dilute and concentrated
wastewaters and wastewaters of significantly different composition provides
for more effective and economical treatment of the separated streams (e.g.,
steam stripping of the sour waters and removal of oil from oily waters), re-
covery of valuable by-products (e.g., recovery of phenols from spent caustic
solutions), and water reuse/recycle (e.g., use of sour water stripper bottoms
as the make-up water for cooling towers).
Wastewater segregation systems similar to those used in refineries are
used in existing coal conversion plants abroad and are included in the designs
for the proposed high Btu commercial gasification facilities in the U.S. The
system for the proposed Burnham (New Mexico) SNG facility, for example, allows
for the separation and separate treatment of the following streams: tar-rich
aqueous condensates, oil-rich aqueous condensates, methanation condensate,
82
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and raw water treatment brines, sludges and ash quench water. The segrega-
tion of condensates containing large quantities of organics from other waste-
waters in a coal conversion plant is especially important in those facilities
which use processes such as Lurgi, H-coal, COED, Synthoil, etc. which generate
significant quantities of tars and oils. In these facilities, the waste sep-
aration enables recovery of tars and oils from relatively small wastewater
volumes and reduces the load on the downstream processing units. The separated
tars and oils may be incinerated on-site as fuel, injected into the gasifier/
pyrolysis units, used for briquetting of coal fines, or sold for chemical re-
covery or fuel use. In many Lurgi facilities, wastewater treatment for tar/oil
removal is followed by the use of the Phenosolvan process for the recovery of
crude phenols. Recovery of phenol as a by-product would also be applicable to
raw gas quench condensate in other gasification and liquefaction processes
(e.g., Hygas, COED) which generate significant quantities of phenols. The
recovery of tars, oils and phenols from condensates generates an effluent
which can be steam stripped, alone or in combination with other plant sour
waters, for the recovery of NH- and H2S. Another example of by-product re-
covery at a gasification plant which would be possible through waste segrega-
tion and separate treatment is the recovery of char fines from raw gas quench
condensates (e.g., in the CO^-Acceptor process) and/or cyclone slurries (e.g.,
in the Hygas process) via settling and dewatering.
Examples of water reuse/recycling possibilities in an integrated commer-
ical coal conversion plant include the use of boiler blowdown steam and knock-
out drum condensates and ammonia stripper bottoms as cooling water makeup;
use of clean condensates (e.g., methanation condensate in high Btu gas produc-
tion) for boiler feed waters; use of cooling tower blowdown and raw water
softening brines as ash quench water makeup; recycling of the settled raw gas
quench water to the quench tower; recycling of the settled ash quench water
to the wash transport system; and treatment of waste brine by distillation
and use of distillate as boiler feed water. To minimize water wastage and
wastewater generation, it is essential that good housekeeping and water con-
servation measures be incorporated in the design of integrated facilities
and be observed during the operation of such plants. Such measures may in-
clude elimination of leaks, routine equipment maintenance and personnel
education.
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6.3 SOLID WASTE MANAGEMENT
Resource recovery, incineration and land disposal (landfilling and land
spreading) are used in refineries for the management of solid wastes. The
following is a brief review of these solid waste management methods and their
applicability to coal conversion wastes.
6.3.1 Resource Recovery
From an environmental standpoint and when applicable, recovery of by-
products from a waste or use of the waste as feedstocks in other processes
would be the most desirable solid waste disposal option. In certain cases
the value of the recovered material offsets the cost of the resource recovery
operation. Processing of spent catalysts (especially those containing precious
metals and chromium, nickel, and zinc) for catalyst rejuvenation or recovery
of metals for reuse is commonly performed in a number of industries; catalyst
reclamation is currently an established industry. Waste solvents can also be
processed (e.g., by distillation) for solvent recovery or incinerated for heat
recovery.
Catalysts used in refineries fall into three categories: noble metal
catalysts containing platinum and palladium used in hydrogenation, alkylation
and reforming; non-noble metal catalysts containing nickel, cobalt, molybdenum
and tungsten used in hydrocracking, hydrotreating, and hydrorefining; and
"inert" catalyst such as silica and alumina used in catalytic cracking and
Claus plants. Because of the high price of noble metal catalysts, the first
category of catalysts is almost invariably processed for metal recovery. The
"inert" catalysts, which are relatively inexpensive, are commonly disposed of
by landfill ing. Some of the non-noble metal catalysts (catalysts in the
second category) are currently processed for reuse and the interest in recy-
cling other non-noble metal catalysts is growing due to increased catalyst
usage, increasing metal values and stringent disposal regualtions' .
The coal conversion catalysts which should be suitable for material re-
covery and recycling include shift and methanation catalysts in high Btu gasi-
fication and hydrotreating catalyst in coal liquefaction. The shift and
hydrotreating catalysts are generally cobalt molybdate-based and the methana-
tion catalysts are nickel-based materials. To date very few shift and
84
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methanation tests have been conducted on coal-derived gases. Because of the
proprietary nature of catalyst formulations used in these tests, very few data
are available on the metal content of spent catalysts and catalyst life and quan-
tities which determine the suitability and economics of catalyst processing
for material recovery. Spent methanation catalyst, although deactivated as
far as catalytic activity for methanation is concerned, has considerable capa-
city for adsorption of sulfur compounds and can conceivably be used as a sul-
fur guard for the removal of trace sulfur in the methanator feed prior to
ultimate disposal or processing for metal recovery. The suitability of spent
catalyst for use as a methanation guard has not been evaluated.
Another specific example of resource recovery in petroleum refineries,
which would have potential application in coal conversion, is the return of
the oil recovered from wastewaters to the refinery for reprocessing. In coal
conversion facilities which generate wastewaters containing appreciable quan-
tities of oils and tars (e.g., coal gasification plants using the Lurgi tech-
nology and coal liquefaction plants), tars and oils recovered from the waste-
waters can be returned to the process (e.g., injected into the gasifier or
used for briquetting coal fines). The recovered tars and oils can also be
incinerated on-site as fuel or sold for fuel use.
6.3.2 Incineration
Refinery wastes which have been reportedly disposed of by incineration
include API separator bottoms, dissolved air flotation float, slop oil emul-
sion solids and waste biosludge^ '. Major types of incinerators which are
in commercial use for the disposal of municipal and industrial wastes are
rotary kiln, multiple hearth furnace, fluidized bed and multiple chamber.
Fluidized bed incineration is believed to be the most desirable incineration
system for application to refinery wastes and has been reported to have been
used in some refineries^2 . Fluidized systems can provide adequate detention
time, stable combustion temperatures, sufficient mixing and high heat transfer
efficiency. Because of mixing and temperature uniformity in the fluidized
bed, the volatilized hydrocarbons are ignited, thereby reducing or eliminating
the possibility of creating an extremely dangerous explosive mixture of gas-
eous hydrocarbons and air. Experience with the incineration of refinery wastes
indicates that a heating value of 4000 kcal/1 (29,000 Btu/gal) is necessary
85
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for self-sustaining combustion^8'. The normal range of operating temperatures
is 977°K to 1088°K (1300°F to 1500°F).
Incineration can reduce the waste to an ash which, because of its small
volume and inertness, can be more conveniently disposed of (e.g., in landfills).
Incineration has proven to be very reliable and efficient and has been widely
used for the disposal of a variety of industrial sludges and solids and munici-
pal refuse and biosludges from the treatment of sanitary sewage. Nearly com-
plete destruction of organics can be achieved in properly designed and operated
incinerators. Compared to land disposal methods, incineration requires very
little space. Except for potential air pollution problems, which can be con-
trolled by use of good designs, afterburners and particulate control devices,
and a possible fuel penalty when handling wastes with inadequate heat values,
incineration is the most desirable disposal option (when resource recovery is
inapplicable), especially for the destruction of hazardous organics.
Major coal conversion wastes which may be disposed of by incineration
include tar and oil sludges, coal fines, chars and biosludges. The incinera-
tion of these wastes can be combined with on-site power generation or be
carried out in a separate waste disposal incinerator. The type of incinerator
most suitable for the disposal of these wastes, the optimum operating tempera-
ture and combustion residence time, and the required pollution control equip-
ment must be established through bench-scale studies or test burns of the
waste at existing commercial incinerators.
6.3.3 Land Disposal
Land disposal methods which have been used for refinery wastes include
application of sludges to soils ("land spreading"), disposal of sludges and
solid wastes in landfills and isolated burial of containerized and/or chemi-
cally fixed wastes.
When large land areas are available and the climate (rainfall, evapora-
tion) and hydrogeological conditions (distance to groundwater; groundwater
flow, type of soil and geological formation) are favorable, some organic and
inorganic sludges may be disposed of by application to soil. The sludge is
applied to the soil by "spreading" or "flooding," and is disked under and
worked into the top soil. The organic component of the sludge undergoes
86
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biodegradation in the soil and eventually becomes part of the soil humus.
Sludge disposal by application to soils has been used for the disposal of oily
sludges from production and refining of crude oil and for the disposal of bio-
sludges from refinery wastewater treatment^41*42'. Coal conversion plant
wastes which may be suitable for disposal by landspreading include bottom
sludges from API separator, flotation and emulsion breaking units; oil stripper
bottoms (e.g., in coal liquefaction and in some high Btu gasification proc-
esses); and biosludges. Although tar and oil sludges from petroleum refineries
have been shown to be degradable when applied to soils, such sludges from coal
gasification plants may be more resistant to degradation in the soil environ-
ment because of the highly aromatic nature of the organics in these sludges.
The degradability of specific coal conversion wastes in the soil environment,
the possible need for addition of supplementary nutrients and amendments to
soil and the appropriate rate and frequency of sludge application to soil
would have to be determined using experimental plots representative of the
disposal site. As with the application of wastewaters to soils (see Section
6.2.3), sites for land disposal of sludges can present an odor problem or re-
sult in the contamination of surface waters and groundwaters unless such sites
are properly located, designed and operated.
Landfilling is the most widely used practice for the disposal of refinery
process sludges and solid wastes. Landfills may be located on site (on or
near the plant) or the waste may be hauled away in trucks to off-site munici-
pal or industrial landfills.
In conventional landfilling (i.e., use of sanitary landfills) the waste
is deposited in layers on land, compacted and covered with a layer of dirt.
Sanitary landfills are widely used for the disposal of municipal and industrial
refuse. Co-disposal of biological wastewater treatment sludges and municipal
refuse is also practiced at a number of landfills. Provided that adequate
measures are taken to reduce potential for the contamination of groundwaters and
surface waters and to minimize nuisances associated with landfill operation,
sanitary landfill ing can be an environmentally acceptable and cost-effective
method for solid waste disposal. To minimize the potential for the contamina-
tion of groundwaters andsurface waters, landfills must be located in areas
where the subsurface formation is relatively impervious to infiltration (e.g.,
87
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dense clays) and where the distance to the groundwater table is significantly
large. The landfill surface area should also be properly contoured to divert
surface runoff from the site. When the subsurface formations do not provide
adequate barriers against leachate infiltration, the use of artifical barriers
such as plastic, asphalt, concrete or clay materials for lining the landfill
may be necessary. The intercepted leachate would be pumped to a surface faci-
lity for treatment. Observation wells should also be installed downstream of
the landfill site (in the direction of groundwater flow) to detect leachate
migration.
Land burial is essentially one form of landfill ing whereby the waste is
deposited in a natural or man-made cavity in the ground and usually covered
with dirt. In some applications ("pit disposal"), a wet sludge may be deposi-
ted in a pit and allowed to dry before the pit is covered with dirt and a new
pit is excavated.
When highly hazardous wastes are to be disposed of in landfills, pretreat-
ment of wastes involving chemical fixation and/or encapsulation may be used
to minimize the potential for the release of waste components in the landfill
environment via solubilization or chemical or biological processes. Both
organic and inorganic materials have been used as chemical fixing agents. The
fixing agents include: asphalt, epoxies, tars, Portland and other lime-based
cements, and proprietary formulations (e.g., in the Chem-fix process). Raw or
chemically fixed sludges can also be encapsulated in plastic, metal or concrete
containers or coated with self-setting resins prior to disposal. Considerable
effort is currently in progress on the amenability of various wastes to chemi-
cal fixation and on the effectiveness of various chemical fixation processes
to reduce the Teachability of the waste. The chemical fixation processes are
generally expensive and their applications limited to small-volume high-
toxicity wastes. An engineering estimate for the chemical fixation of flue
gas desulfurization sludge, including final disposal, indicates a cost of $8
to $13/tonne ($9 to $14/tonr In coal conversion, the most likely candi-
date waste stream for chemical fixation would be the spent catalysts which
cannot be processed for material recovery.
When a coal conversion plant is located at some distance from the coal
mine and suitable land is available, conventional landfilling would likely be
-------
employed for the disposal of bulk or chemically fixed solid wastes and sludges.
When a plant is located within a reasonable transportation distance from the
mine, return of the coal conversion solid wastes and sludges to the coal mine
would be an attractive means for the disposal of such wastes, especially when
area surface mining is practiced. Disposal in surface mines would essentially
be one form of landfill ing where the overburden material would be used as the
cover material. The operation would be subject to the same restrictions cited
above for sanitary landfills. When coal is deep mined, there would be a
greater time delay before the waste can be deposited in the mine. In the case
of deep mining, the physical operation of returning the waste to the mine
would also be more difficult, requiring certain changes in mine design and
operation to accommodate the space and equipment for returning the wastes.
The return of ash and flue gas desulfurization sludges to the mines would have
the potential benefit of reducing acid mine drainage formation. This would
especially be the case in eastern mines where acid mine drainage is a major
pollution problem.
89
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7.0 HEALTH AND ECOLOGICAL EFFECTS OF SELECTED CONSTITUENTS IN REFINERY AND
COAL CONVERSION PROCESS/WASTE STREAMS
7.1 PURPOSE AND SCOPE
Some of the components of refinery and coal conversion wastes have been
shown to be highly hazardous due to their toxicity, carcinogenicity, mutageni-
city and/or teratogenicity. Knowledge of the sources of these constituents,
and their fate in the refinery and coal conversion processes and control opera-
tions, are necessary to assess the adequacy of the conventional control tech-
nologies for the removal of these constituents and the additional control
technology requirements. As part of the present program for the assessment
of the applicability of refinery control technologies to coal conversion, the
major hazardous constituents common to both refinery and coal conversion were
identified and their hazardous characteristics reviewed. The adequacy of the
refinery control technologies judged to be applicable to coal conversion
plants for the control of these constituents was assessed.
Table 7-1 lists the principal constituents of refinery streams which were
identified in Section 4 as having counterparts in coal conversion plants.
Many of these constituents (e.g., NO , H2S, SOp and phenol) are not unique
to refinery or coal conversion wastes and are emitted from a variety of indus-
trial and nonindustrial (e.g., automobile) sources. Although some of these
constituents are hazardous (some at very high concentration levels), they are
not discussed in this section in any great detail because of their commonplace
nature. The available data on health and environmental hazards associated
with these ubiquitous chemicals, however, are summarized in Table 7-2, along
with some pertinent occupational and environmental regulations.
Certain of the chemicals listed in Table 7-1 are relatively unique to
refinery and coal conversion wastes and are highly hazardous. These chemicals
fall into three classes, namely polynuclear aromatic hydrocarbons (PAH),
heavy metals and organometallic compounds, and low molecular weight aromatic
90
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TABLE 7-1. PRINCIPAL CONSTITUENTS OF REFINERY STREAMS HAVING COUNTERPARTS
IN COAL CONVERSION WASTE STREAMS
Stream
Constituents
Gaseous
Sulfur-containing species
Nitrogen-containing species
Carbon oxides
Organics
Miscellaneous
Liquid
Dissolved gases
Inorganic anions
Inorganic cations
Organic compounds
Other parameters
Solid
Organics
Heavy metals
Miscellaneous species/
parameters
H,,S, S00, SO,, CS0, COS, SQ (vapor/mist)
L. £. J C. O
NH3, NOX
CO, C02
Alkanes (methane through hexane)
Aldehydes (e.g., HCHO)
Acids (e.g., propionic acid)
Low molecular weight aromatics (e.g.,
benzene, toluene and xylene)
Particulate matter, including PAH; organo-
metallics
NH3, H2S, HCN
cr, so4=, po4=,
++
, Fe,
Phenol ics, mercaptans, oil, low molecular
weight aromatics (e.g., benzene, toluene,
xylene)
TSS, TDS, alkalinity, radioactivity
Phenols, benzo-a-pyrene, other PAH and aromatic
compounds
Ni, V, Co, Mo, As, Se, Hg, Be, Cr, Cu, Zn, Ag,
Cd, Pb
Si02, acids, alkali, miscellaneous process
and treatment chemicals, biomass, inerts,
radioactivity
91
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TABLE 7-2. SUMMARY OF HAZARDOUS PROPERTIES OF SOME UBIQUITOUS CONSTITUENTS OF REFINERY AND COAL
CONVERSION WASTES(44,45)
Property
Constituent
H2S
S02
SO,
vo
MEG Category*
MEG Hazard Indicated
Toxic Dosage*
Toxicology
Toxic Hazard Rating*
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
F1re Hazard**
Explosion Hazard**
Disaster Hazard**
Standards and Regulations
OSHA
Air, celling cone.
Air, peak cone.
Air. TLV
Air, THAt+
N10SH Criteria Documents
Air, THAft
Air, celling cone.
53
NH
Inhalation,human-LCLo,600 ppn/30 mln.
Inhalation.rat-LC50,713 ppm/1 hr.
Inhalat1on,mouse-LC50.673 ppm/1 hr.
An irritant and asphyxiant.
High concentrations result In
dizziness, diarrhea, and dysurla.
Paralysis of the respiratory
system may be fatal.
Irritant- 3
Inhalation- 3
U
Inhalation- 3
Dangerous
Moderate
Highly dangerous (may emit SOX
fumes; can react vigorously with
oxidizing materials)
20 ppm
SO ppm/10 mln.
10 ppm (-15 mg/ro3)
53
Inhalation,human-TClo.3 ppm/5 day
Inhalation,rat-LCLo,611 ppm/5 hr.
Inhalation.mouse-LCLo.763 ppm/20 mln.
Inhalation.guinea pig-LCLo.5000 ppm/5 mln.
Concentrations of 6-12 ppm cause irrita-
tion of nose and throat.
t Concentrations of 20 ppm and greater are
Irritating to the eye.
Affects upper respiratory tract and
bronchial tubes.
400-500 ppm may be fatal.
Irritant-3; Inhalation - 3; Ingestion-3
U
Irritant-2; Inhalation-2
U
Dangerous; reacts with water/steam to
product toxic fumes
53
Aquatic toxlcity,TLm 96:100-10 ppm
Irritant-3; Inhalation - 3; Ingestion-3
U
Irritant-2; Inhalation-2
U
Dangerous; reacts with steam to produce
H2S04
5 ppm
2 ppn
(continued)
-------
TABLE 7-2. CONTINUED
Property
Constituent
CS2
COS
CO
MEG Category*
MEG Hazard Indicator1
Toxic Dosage*
Toxicology
\O Toxic Hazard Rating1
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
F1re Hazard**
Explosion Hazard**
Disaster Hazard**
Standards and Regulations
OSHA
Air, celling cone.
Air. peak cone.
Air. TLV
Air. TWAft
NIOSH Criteria Document:
A1r. TWAft
Air, celling cone.
53
NH
Oral.human-LDLo, 14 mg/kg
Intraper1toneal.rat-LDLo.400 mg/kg
Subcutaneous.rabblt-LDLo,300 mg/kg
Aquatic tox1c1ty,TLm96:1000-100 ppm
Inhalation,human-LCLo,4000 ppm/30 mln.
Inhalation,human-TCLo.50 mg/m3/7 yr.
Acute poisoning may result In de-
pression, stupor, followed by
unconsciousness and possibly death.
Chronic poisoning causes distur-
bances of central nervous system.
Irritant- 1
Ingest1on-3; Inhalation-3; Skin
Absorption- 3
Ingestlon-3; Inhalation-3; Skin
Absorption- 3
Highly dangerous
Severe
Highly dangerous; emits SOX fumes;
can react vigorously with oxidizing
materials
30 ppm
100 ppm/30 mln.
20 ppm
53
NH
Inhalat1on.mouse-LCLo.2900 pnn
Narcotic 1n high concentrations.
Irritant-1; Ingest1on-l; Inhalation-1
Inhalation - 3
Irritant- 1; Inhalation- 1
Inhalation- 3
Dangerous
Moderate
Dangerous; reacts with oxidizing
materials; may emit H2S.
42
NH
Inhalation.dog-LCLo.3841 ppm/46 mln.
Inhalation.cat-LCLo,8730 ppn/35 hr.
Inhalation,guinea plg-LCSO.2444 ppm/4 hr
Inhalation,human-LCLo,4000 ppm/30 mln.
Inhalation,rat-LC50,1807 ppm/4 hr.
Inha1at1on.mouse-LC50.5718 ppm/4 hr.
Inhalation,human-TCLo.650 ppm/45 mln.
Combines with hemoglobin, resulting
In asphyxia.
Concentrations of 4,000 ppm fatal
In less than an hour.
Chronic exposure results In auditory
disturbances, glycosurla. and heart
Irregularities.
Inhalation- 3
0
Inhalation- 1
Dangerous
Severe
50 ppn
35 ppn
200 nwi
(continued)
-------
TABLE 7-2. CONTINUED
Property
C02
Constituent
NO
to
MEG Category*
MEG Hazard Indicator*
Toxic Dosage*
Toxicology
Toxic Hazard Rating1
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
F1re Hazard**
Explosion Hazard**
Disaster Hazard**
Standards and Regulations
OS HA
Air, celling cone.
Air, peak cone.
A1r, TLV
A1r, TWAft
tt
NIOSH
Air, TWA
Air, celling cone.
42
NH
Inhalation,rabbit-TClo,10 pph/7-12 days
Inhalation,rat-LCLo,657.190 ppn/15 nin
Considered a simple asphyxiant;
symptoms Include headache, dizzi-
ness, muscular weakness, and
drowsiness.
Contact of COg "snow" may cause
skin "burns."
Inhalation- 1
0
Inhalation- 1
Slight
-5000 ppn
47
Inhalation,rabbit-TCLo.10,066 ppm/hr
Inhalation,human-LCLo, 10,000 ppm/3 hr.
Inhalat1on.mouse-LC50.1037 ppn/1 hr
Inhalation,human-TCLo, 20 ppm
Aouatlc tox1c1ty,TLm96:lO-l ppm
Irritating to the eyes and mucous
membranes of respiratory tract.
Symptoms Include Irritation of the
eyes, conjunctivitis. Irritation
of the nose and throat, coughing
and vomiting.
Irritant-3; Ingestlon- 3; Inhalation-1
U
Irritant-1
U
Moderate
Moderate
Moderate; emits toxic fumes
50 ppm
50 ppn
47
Inhalat1on,mouse-LCLo,320 ppm
Inhalat1on.rabb1t-LC50.315 ppm/15 mln.
Irritant-3
Ingestlon-3; Inhalation-3
U
Ingestlon-2; Inhalation-2
Dangerous; reacts with reducing
materials
25 ppn
25 ppn
(continued)
-------
TABLE 7-2. CONTINUED
Property
Constituent
NO;
HCHO
CH3CH2C02H
to
CJ1
MEG Category*
MEG Hazard Indicator*
Toxic Dosage*
Toxicology
Toxic Hazard Rating1
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
F1re Hazard**
Explosion Hazard**
Disaster Hazard**
Standards and Regulations
OS HA
Air. celling cone.
Air, peak cone.
Air. TLV
A1r. THAtf
NIOSH Criteria Documents
Air, TWAft
Air. ceiling cone.
47
Inhalation. human-TCLo, 64 Dpm
Inhalation.rat-LCSO,83 ppn/4 hr.
Inhalation,mouse-LCLo,220 ppm/30 min.
Inhalation,nonkey-LCLo,44 ppn/6 hr.
Inhalation,rabb1t-LC50,315 ppm/lS min.
Irritant- 3
Ingestion-3; Inhalation-3
U
Ingestlon-2; Inhalation -2
Dangerous; reactive with
reducing materials
0 ppn
7A
X
Inhalation,human-TCLo.13.8 ppm
Inhalation,rat-LCLo.250 ppm/4 hr.
Inhalat1on,nouse-LCLo,900 mg/nH/2 hr
Aquatic toxicity, TLm96:100-10 ppm
Inhalatlon.cat-LCLo.820 mg/nr>/8 hr.
Oral.rat-LD50.800 mg/kg
Toxic effects are mainly those
of Irritation.
Ingestlon causes violent vomit-
ing and diarrhea.
A suspected carcinogen of the
lung.
Irritant-3; Allergen-1
Ingestlon-3; Inhalation-3
Allergen - 1
U
Moderate
Dangerous when heated above
flash point
Moderately dangerous
5 ppn
10 ppn/30 nln/0 hr
3 ppo
8A
Aquatic toxicity. TUn96:1000-100 ppn
Oral.rabbit-LD50,1510 mg/kg
Low toxicity based on animal
experiments.
Irritant- 2
Ingestlon- 1
Irritant- 1
Ingestlon- 1
Moderate
Slight; emits acrid fumes
(continued)
-------
TABLE 7-2. CONTINUED
Property
Constituent
SiO?
Phenol
CH3SH
VO
o>
MEG Category*
MEG Hazard Indicator*
Toxic Dosage*
Toxicology
Toxic Hazard Rating*
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
F1re Hazard**
Explosion Hazard**
43
Intraperltoneal-rat, LCLo-400 mg/kg
Chief cause of Industrial
pulmonary dust disease.
t Results In slUcosIs and
modular flbrosls In the lungs.
Inhalation- 2
0
Inhalation- 3
Inhalation- 1
Moderate
ISA
NH
Oral,human-LDLo,14 mg/kg
Oral,human-LDLo,140 mg/kg
Oral,rat-LD50,414 mg/kg
Subcutaneous,rat-LDLo,650 mg/kg
Aquatic tox1c1ty-TUn96:100-10 ppm
In acute poisoning, major effect
Is on central nervous system;
damage to kidney, liver, pancreas,
spleen and edema of lungs may
result. May be fatal.
Chronic poisoning may result 1n
diarrhea, digestive disturbance,
nervousdlsorders and skin erup-
tions.
Irritant-3; Ingestlon-3; Inhalation-3
Ingestlon-3; Inhalation-3; Skin
Absorption- 3
Irritant- 2
Ingestion-2; Inhalation - 2; Skin
Absorption - 2
Dangerous; may react with oxidizing
materials.
13A
NH
Inhalation.rat-LCLo,10,000 ppm
Subcutaneous,mouse-LD50,2.4 mg/kg
Irritant- 2
Ingestion-2; Inhalation-?
U
U
Unknown
Dangerous; on decomposition, emits
SOX fumes; will react with water,
steam or acids to produce toxic and
flammable vapors; can react vigorously
with oxidizing materials.
(continued)
-------
TABLE 7-2. CONTINUED
Property
Constituent
S10,
Phenol
CH3SH
Standards and Regulations
OSHA
Air, celling cone.
Air, peak cone.
Air, TLV
Air. THAtf
Nlosh Criteria Documents
Air. THAtf
Air. celling cone.
10 ppn
60 mg/ra3/XS102
5 ppn (skin)
to
Multimedia Environmental Goals (MEGs) are levels of significant contaminants or degradents (In ambient air. water, or land or In emissions or efflu-
ents conveyed to the ambient media) that are judged to be (a) appropriate for preventing certain negative effects 1n the surrounding populations or
ecosystems. or'U>) representative of the control limits achievable through technology. EPA has published MEG values for more than 650 pollutants(50).
A rating system has been developed by EPA for assigning Indicators (X - hazardous, XX very hazardous; XXX most hazardous; or NH - nonhazardous)
to designate potentially hazardous substances based on values generated by the MEGs methodology! *>]. A dash (--) Indicates substances for which
hazard rankings have not yet been developed. A revised and expanded system of categorization and hazard ranking 1s currently being developed for
EPA by Research Triangle Institute (57); the revised MEG system for organic compounds Is expected to be completed within 1-2 months, while the
revised system for Inorganic compounds will be completed at a later date.
*LCLo - lowest published lethal concentration; LC50 - lethal concentration. 50 percent kill; LD50 - lethal dose, 50 percent kill; LDLo - lowest
published lethal dose; TCLo - lowest published toxic concentration; TDLo - lowest published toxic dose.
'Toxic hazard rating code:
0 - None: (a) no harm under any conditions; (b) harmful only under unusual conditions or overwhelming dosage.
1 - Slight: causes readily reversible changes which disappear after end of exposure.
2 - Moderate: May Involve both Irreversible and reversible changes not severe enough to cause death or permanent Injury.
3 - High: May cause death or permanent Injury after very short exposure to small quantities.
U - Unknown: No Information on humans considered valid by authors (Reference 45).
**Hazard applies to conditions of exposure to heat or flame.
ftTWA - time weighted average.
-------
compounds, and are discussed in the following sections. The discussion ad-
dresses the sources, characteristics and health effects of these chemical
classes, and control technology requirements.
7.2 POLYCYCLIC AROMATIC HYDROCARBONS (PAH)
As indicated in Table 7-1, PAH emissions are generally associated with
gaseous and solid waste streams in petroleum refineries. In petroleum refin-
ing the primary source of PAH emissions is the regeneration of the cracking
catalysts. Regeneration consists of combusting the carbonaceous material
that accumulates on the catalyst surface. PAHs are discharged both from the
regenerator unit and from the regenerator unit incinerator waste heat boilers.
The majority of PAH compounds generated are adsorbed on particulate matter.
PAH compounds have also been detected in high boiling petroleum-derived oils
(b.p. 370°C) obtained from crude oil by catalytic cracking. Petroleum crude
is also estimated to contain approximately 1 ppm of the PAH compound benzo(a)-
pyrene'46-47'.
Since the organic portion of coal is largely composed of polynuclear aro-
matic structures, it is not surprising that polynuclear aromatic hydrocarbons
are present in coal conversion wastes. In addition to particulate matter,
PAHs are associated with the heavier and more aromatic fractions of coal con-
version streams (e.g., tars, oils, etc.). The formation of PAHs in coal con-
version processes has been documented^ ' and several studies have been under-
taken for their identification and characterization in a number of waste
streams at pilot gasification plants. PAHs have been detected in atmospheric
particulate matter at coal liquefaction plants' . Mass spectroscopic anal-
yses of tars produced in a Synthane gasifier have indicated the presence of
PAHs^ . In general, the quantities, chemical structures and fate of PAHs
in coal conversion operations are not well-defined and are expected to vary
among different plants depending on the type of coal used, coal conversion
process employed and operating conditions.
PAH compounds are of particular environmental concern because of their
carcinogem"city. Table 7-3 presents seven classes of PAH compounds which are
known or suspected carcinogens and which are associated with coal conversion
processes and/or refineries and some toxicity data for these compounds. The
98
-------
TABLE 7-3. CLASSES OF KNOWN OR SUSPECTED CARCINOGENIC PAH AND ANALOG COMPOUNDS ASSOCIATED WITH
PROCESSING AND UTILIZATION OF PETROLEUM AND/OR COAL AND TOXICITY DATA*(49,44)
Compound Class
Polynuclear Aromatic Hydrocarbons, PAH
Anthracenes
Chrysenes
Benzanthracenes
Fluoranthenes
Cholanthrenes
Benzopyrenes
Dlbenzpyrenes
Heterocycllc and Oxidized Analogs
of PAHs (N. S. and 0-Conta1n1ng
Compounds)
Mono -and dlbenzacrl dines
Benzocarbazoles
Olbenzocarbazoles
Benzathrones
Representative Compound
anthracene
chrysene
benzo(a)anthracene
benzo(j)fluoranthene
20-methylchlolanthrene
benzo(a)pyrene
d1benzo(a,h)pyrene
d1benz(a,h)acr1d1ne
7H-benzo(c )carbazole
7H-d1benz(c,g)carbazole
7H-benz(d,e)anthracen-7-one
Structure
000
0550
00?
U O
J£&
Cui? '
o55^
ff#
o^y
(o^5)
000
Toxic Dosage*
Oral, rat-TDLo, 18 g/kg/78 wks;
subcutaneous. rat-TDLo, 3300 mg/kg/33 wks
Subcutaneous .mouse-TDLo, 300 mg/kg;
skin, mouse-TDLo, 99 mg/kg/31 wks
Skin, mouse-TDLo, 2 mg/kg;
1ntraveneous.mouse-LDLo.10 mg/kg;
parenteral, mouse-TDLo, 8 mg/kg;
1mplant,mouse-TDLo,80 mg/kg
Sk1n.mouse-TOLo.228 mg/kg/24 wks
Oral .rat-TDLo, 280 mg/kg;
oral .mouse-TDLo. 40 mg/kg;
sk1n,mouse-TOLo,l3 mg/kg/42 wks
Oral .rat-TDLo. 4563 mg/kg/53 wks;
skin, rat-TDLo. 44 mg/kg/22 wks;
Intraveneous. rat-TDLo, 39 mg/kg/6 days
Sk1n.mouse-TDLo.l65 mg/kg/24 wks
Oral.mouse-TOLo.18 g/kg/89 wks;
sk1n,mouse-TDLo,700 mg/kg/29 wks;
subcutaneous, mouse-TDLo. 450 mg/kg/24 wks;
Intraveneous, mouse-TDLo, 10 mg/kg
Subcutaneous, mouse-TDLo, 120 mg/kg/12 wks
Subcutaneous, rat-TDLo, 150 mg/kg/17 wks;
oral, mouse-TDLo, 400 mg/kg/23 wks;
intraveneous, mouse-TDLo, 10 mg/kg
Intraperi toneal ,mouse-LDLo,1000 mg/kg
1
*See footnotes to Table 7-2 for definition and explanation of terms.
MEG
Category
21
21
21
22
22
21
21
23B
23C
23C
24
MEG Hazard
Indicator
NH
NH
XX
NH
NH
XXX
NH
X
-
X
NH
VO
10
-------
data in the table include the EPA Multimedia Environmental Goals (MEG) and
MEG Hazard Indicators for each class of compounds (see footnotes to Table
7-2). One of the best characterized PAH compounds is benzo(a)pyrene, which
has been determined to be extremely carcinogenic to experimental animals, can
induce a cancerous skin tumor in mice when only 0.25 mg is injected subcutane-
ously and has recently been established as a human carcinogen. Benzo(a)pyrene
is the most widely accepted indicator of PAH content and biological activity.
In addition to PAHs there are numerous heterocyclic and oxidized analogs of
PAH compounds, some of which may be found in petroleum and coal conversion
wastes (see Table 7-3).
Most of the available epidemiological and laboratory studies relating to
the carcinogenic properties of PAH have been in connection with the coking in-
dustry and other coal carbonization/hydrogenation processes. Comparatively
little epidemiological work has been reported on petroleum refinery workers.
A number of epidemiological studies and laboratory testing (mostly in connec-
tion with coal hydrogenation and Fischer-Tropsch synthesis) are reviewed in
Reference 49.
Several recent investigations of the toxicological and biological signi-
ficance of PAH have centered on synfuel-related materials. Two such studies
(471
are conducted at Oak Ridge National Laboratory, Oak Ridge, Tennesseex ' and
at the National Cancer Institute, Bethesda, Md.* '. At Oak Ridge the carcino-
genic activity has been observed for three-, four- and five-ring PAHs from
synfuels materials. The specific activity has been found to be the greatest
for the four-ring and five-ring PAH fractions containing the most common
known carcinogens (e.g., benzo(a)pyrene, benzo(c)phenanthrene, 3-methyl-
cholanthrene, etc.). At the National Cancer Institute, the carcinogen!city
activation mechanism, metabolism, macromolecular binding, cellular effects,
and miltagenicity of PAHs are under study. These studies include in vitro
testing and analytical methods development. As indicated above, PAH com-
pounds in gaseous streams are generally associated with particulate matter.
Particulates by themselves can also be hazardous to human health by virtue
of their fine size which allows them to penetrate deep into the lungs.
NIOSH has recently developed criteria and recommended a standard for
(52)
occupational exposure to coal tar products, including PAHV . The recommended
100
-------
2
standard is 0.1 mg/m of a cyclohexane extract fraction of a coal tar sample,
determined as the time-weighted average concentration for up to a 10-hour work
shift in a 40-hour work week. Several Federal, state and local air quality
standards have also been promulgated for control of particulate emissions per
se. These include New Source Performance Standards for particulate matter
for petroleum refineries, which restrict particulate emissions to 1.0 kg/1000
kg of coke burn-off in catalyst regeneration.
7.3 HEAVY METALS AND ORGANOMETALLIC COMPOUNDS
As indicated in Table 7-1, heavy metals and organometallic compounds are
found in liquid, solid and gaseous waste streams generated at petroleum re-
fineries. The refinery solid wastes having the highest concentrations of
heavy metals are the spent catalysts, coker fines and crude oil storage sedi-
ments. Noble and non-noble heavy metals are utilized as catalysts in refin-
ery operations. Noble metal catalysts such as platinum and palladium are
recycled and/or recovered because of their economic value. Non-noble metals
(e.g., cobalt, molybdenum, chromium, tungsten, nickel and vanadium) are some-
times reprocessed, depending upon catalyst price, or may be discharged as
solid wastes. Coker fines and crude oil storage sediments contain arsenic
and heavy metals listed in Table 7-1. Heavy metals may also be discharged as
volatile or particulate emissions in refinery operations (e.g., during cata-
lyst regeneration and fuel combustion). The quantities and composition of
heavy metals discharged in the various gaseous, solid and liquid waste streams
in refinery operations are primarily functions of both the composition of the
crude oil processed and the catalysts employed.
The chemical nature of coal combined with the conditions under which it
is gasified or liquefied are conducive to the release of numerous heavy metals
and their compounds. (Elemental analyses of a variety of coals have revealed
the presence of over one-half the elements of the periodic table, many of
them heavy metals.) As with refinery waste streams, heavy metals are present
in liquid, gaseous and solid streams from coal conversion operations. Solid
wastes containing heavy metals will include coal/char fines and ash produced
in gasification, and spent catalysts and sludges from gas purification and
upgrading operations. Spent catalysts from shift conversion operations are
primarily cobalt molybdate based materials that are contaminated with coal
101
-------
derived trace elements and occluded high molecular weight organics. Spent
methanation catalysts are primarily nickel-based materials, and also may be
contaminated with organics and trace-elements from coal. Coal/char fines,
ash and process sludges will contain coal-derived metals, especially less
volatile elements (Ni, Be, and Cr). As with refinery operations, heavy metals
may also be discharged as volatiles or particulates.
Heavy metals are of particular environmental concern because of their
toxicological properties and their known or suspected carcinogenicity. Table
7-4 presents major metallic elements associated with refineries and coal con-
version processes, and some toxicity data for these elements.* Several of
these metals are known or suspected carcinogens as indicated in Table 7-4.
In general, the toxicities and properties of heavy metals and heavy metal
compounds vary widely and cannot be generalized.
Petroleum refining and coal gasification and liquefaction are conducive
to the formation of a variety of organometallic compounds. Little work has
been performed to date to elucidate the nature and toxicological effects of
organometallics that may be produced in these processes. Some of the major
types of organometallic compounds that may be formed are: metal carbonyls;
metallocenes; arene carbonyls; metal alkyls; metal porphyrins; metal hydrides;
and metal chelates. To date, only metal porphyrins and metal carbonyls have
been detected in petroleum refinery streams. However, the presence of the re-
maining organometallics cannot be completely discounted. Descriptions of
(53}
these organometallic compounds can be found in the literaturev .
Table 7-5 presents toxicity data on specific organometallic compounds
which are representative of several of the seven classes mentioned above, and
which have been detected or are likely to be present in petroleum refinery
and coal conversion wastes.
7.4 AROMATIC COMPOUNDS
The third category of chemical compounds which poses environmental haz-
ards in both refinery and coal conversion operations is low molecular weight
aromatic compounds. As indicated in Table 7-1, low molecular weight aromatics
(e.g., benzene, toluene, xylene and related compounds) are associated primarily
*Although in chemical terminology arsenic is not considered a metal, it is
grouped with metallic elements here for discussion purposes.
102
-------
TABLE 7-4. SUMMARY OF TOXICOLOGICAL AND ENVIRONMENTAL DATA FOR MAJOR HEAVY METALS ASSOCIATED
WITH REFINERY AND COAL CONVERSION OPERATIONS(44,45)
Parameter*
Metal
As
Co
Ni
O
CO
MEG Category
MEG Hazard Rating
Toxic Dosage
Toxicology
Carcinogenic
Toxic Hazard Rating
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
Fire Hazard
Explosion Hazard
Disaster Hazard
Standards and Regulations
OSHA
Air, TWA
Criteria Document
Air, ceiling cone.
49
XXX
Intramuscular,rat-LDLo,25 mg/kg
Subcutaneous,rabbit-LDLo,300 mg/kg
Intraperltoneal,guinea plg-LDLo. 10 mg/kg
Subcutaneous,guinea p1g-LDLo,300 mg/kg
Considered highly toxic
Acute As poisoning results 1n stomach
Irritation and Intestinal problems
with nausea, vomiting and diarrhea.
Chronic As poisoning produces loss of
appetite, cramps, nausea, constipation
or diarrhea. Liver damage may occur.
resulting In Jaundice.
i A recognized carcinogen of skin, lungs
and liver.
yes (suspected)
Irritant-2; Allergen-2; Ingest1on-3
Ingestlon-3; Inhalation- 3
Irritant- 2; Allergen- 3
Ingestlon - 3; Inhalation - 3
Moderate when 1n the form of dust
Slight, 1n the form of dust
Dangerous, can react vigorously on
contact with oxidizing materials
500 mg/mj
2 mg/m3
74
XX
Oral.LDLo-1500 mg/kg
Intramuscular,rat-TDLo,112 mg/kg
Intraperitoneal,mouse-LD50,22 mg/kg
Oral.rabbit-LDLo,20 mg/kg
Considered to have low human
toxldty when administered orally.
May result 1n hematologlc, diges-
tive and pulmonary changes In
humans.
yes (suspected)
Allergen- 1
Ingestlon-1; Inhalation-1
U
U
Moderate
100 mg/mj
76
XXX
Inhalation.rat-TCLo.15 mg/m3
Subcutaneous,rat-TDLo,15 mg/kg/6 wks
Intramuscular,rat -LDLo,25 mg/kg
Intratracheal,rat-LDLo.12 mg/kg
Oral .guinea plg-LOLo, 5 mg/kg
Inhalation,guinea pig-TCLo,15 mg/m3/9 wks
Intramuscular,hamster-TDLo,208 mg/kg/22 wks
Ingestlon of large doses causes intesti-
nal disorders, convulsions and asphyxia
I A recognized carcinogen of the nasal
cavity, paranasal sinuses and lungs.
i Chronic exposure may result in a form
of dermatitis.
yes (suspected)
Irritant- 1; Allergen- 1
Ingestlon-1; Inhalation-3
Irritant- 3; Allergen- 1
Inhalation-3; Ingestlon-3
1 mg/m3 (skin)
(continued)
-------
TABLE 7-4. CONTINUED
Metal
Parameter*
Cr
Pb
Zn
MEG Category
MEG Hazard Indicator
Toxic Dosage
Toxicology
Carcinogenic
Toxic Hazard Rating
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
Fire Hazard
Explosion Hazard
Disaster Hazard
Standards and Regulations
OSHA
Air. TWA
Criteria Document
Air. TWA
68
XXX
Inhalation,human-TOLo,4500 mg/m3/5yr
Intraveneous,rat-TDLo,2 rog/kg/6 wks
Implant,rat-TDLo.l mg/kg/6wks
Intraper1tonea1,mouse-LD50,l02 mg/kg
Essentially non-toxic In the
metallic form.
e Chromic add and salts have
corrosive action on the skin
and mucous membranes. Chromate
salts are recognized carcinogens
of the lungs, nasal cavity and
paranasal sinuses.
yes (suspected)
Irritant-3; Ingestlon-3; Inhalatlon-3
U
Irritant-3; Ingestlon-3; Inhalation-3
Ingestlon-3; Inhalation-3
Moderate. 1n the form of dust.
ng/«r
46
XX
Not available
Lead poisoning is one of the
commonest of occupational
diseases.
Is a cumulative poison
Common clinical types of lead
poisoning may be classified
as: (a) alimentary; (b) neuro-
motor; and (c) encephalic.
yes (suspected)
Inhalation-3; Inhalation-3
0
Ingestlon-3; Inhalation- 3; Skin
Absorption- 3
Moderate
Moderate
Dangerous; can react vigorously with
oxidizing materials.
200 no/n3
150 mg/(Pb)n3
81
NH
Intraperitoneal,mouse-LD50,15 mg/kg
i Not Inherently toxic; when
heated, may evolve a fume of
zinc oxide dust.
i In small doses, zinc salt', may
produce digestive disorders.
i Workers with zinc have been
reported as suffering from a
variety of non-specific Intestinal,
respiratory and nervous systems.
yes (suspected)
Moderate
Slight, when In the fora of dust.
(continued)
-------
TABLE 7-4. CONTINUED
o
in
Parameter*
MEG Category
MEG Hazard Indicator
Toxic Dosage
Toxicology
Carcinogenic
Toxic Hazard Rating
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
Fire Hazard
Explosion Hazard
Disaster Hazard
Standards and Regulations
OSHA
A1r, TWA
Criteria Document
Air, celling cone.
Metals
Mo
69
NH
Intraperltoneal,mouse-LD50,160 tag/kg
Subcutaneous,mouse-L050.266 mg/kg
No known cases of Industrial poison-
Ing by Mo have been reported.
t Not stored by the body, but Is
rapidly excreted.
No
Irritant- 1
U
u
Inhalation- 1
Moderate, 1n the form of dust.
Slight, 1n the form of dust.
65
X
Not available
V compounds act chiefly as
Irritants to conjunctiva! and
respiratory tract.
Prolonged exposures may lead
to pulmonary disorders, anemia,
pallor and emaciation, and
gastrointestinal disorders.
No
Moderate, in the form of dust.
*For definition of terms and explanation of ratings, see Table 7-2.
-------
TABLE 7-5. TOXICOLOGICAL DATA ON SELECT ORGANOMETALLICS ASSOCIATED WITH REFINERY AND/OR COAL
CONVERSION WASTE STREAMS(44,45)
Parameter*
MEG Category
NEC Hazard Indicator
Toxic Dosage
Toxicology
Carclnogenlclty
Toxic Hazard Rating
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
Fire Hazard
Explosion Hazard
Disaster Hazard
Standards and Regulations
OSHA
A1r. TWA
A1r. TLV
Compound
N1(CO)4
76
XX
Inhalation. rat -LC50.240 ng/m3/30 mln.
Subcutaneous, rat-LD50,63 mg/kg
Intraveneous.rat-LD50.66 mg/kg
Inhalat1on,mouse-LC50.67 mg/m3/30 mln.
Inhalatlon.dog-LCLo.360 ppm/90 mln.
Inhalat1on.cat-LC50.1900 mg/m3/30 mln.
Aquatic tox1c1ty.TLm96. 100-10 ppm
Toxic symptoms from Inhalation are
believed to be caused by both
nickel and CO when liberated In
the lungs.
In severe acute cases there Is
headache, dizziness, nausea,
vomiting, fever, and difficult
breathing.
0 Chronic exposure leads to cancer
of respiratory tract and nasal
sinuses.
Yes
Inhalation -3
Inhalation- 3
U
U
Dangerous
Moderate
Dangerous
7 mg/m3
--
Fe(CO)5
72
Inhalation, rat-LCLo. 33 ppm/330 mln.
Inhalation, mouse-LC50, 7 mg/m3
Oral, rabbi t-LDLO ,18 mg/kg
Sk1n.rabb1t-LD50.240 mg/kg
Intraveneous.rabblt-LOLo.17 mg/kg
Oral .guinea plg-LDLo.36 mg/kg
Oral.rabblt-LDSO.O.Ol mg/kg
Inhalation causes dizziness,
nausea, vomiting, followed by
unconsciousness.
In fatal cases, death occurs
from the 4th to llth day with
pneumonltis and Injury to
kidneys, liver and brain.
Less toxic than nickel carbonyl.
No
Irr1tant-l
Ingest Ion -3; Inhalation- 3; Skin
Absorption - 3
U
U
Dangerous
Moderate
Dangerous; can react vigorously
with oxidizing materials
__
10 ppb
Co4(CO)12
74
--
Inhalation, rat-LC50, 1400 mg/m3
t Highly toxic.
No
U
U
U
U
Dangerous
Moderate
Dangerous
Not known
(continued)
-------
TABLE 7-5. CONTINUED
Parameter*
Compound
Ferrocene
Tetraethyl Lead
MEG Category
MEG Hazard Indicator
Toxic Dosage
Toxicology
Carclnogenlclty
Toxic Hazard Rating
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
F1re Hazard
Explosion Hazard
Disaster Hazard
Standards and Regulations
OSHA
A1r, TWA
A1r, TLV
26B
NH
Oral,rat -LD50.1320 mg/kg
Intraperitoneal,rat-LD50,50 mg/kg
Oral,mouse-LD50,1550 mg/kg
Intraperitoneal,mouse-LD50,335 mg/kg
Toxldty considered low.
No
U
U
U
U
Moderate
Dangerous; emits toxic fumes when
heated.
Not Known
26A
X
Oral,rat-LDLo,17 mg/kg
Inhalation,rat-LC50,6 ppm
Intraperitoneal,rat-LDLo,10 mg/kg
Subcutaneous,mouse-LDLo,86 mg/kg
Skln.dog-LDLo.500 mg/kg
Intrayeneous,rabbit-LDLo,23 mg/kg
Aquatic-TLm96, under 1 own
A powerful poison and solvent
for fatty material.
0 Decomposes to form elemental
lead, which may accumulate in
body tissues.
Absorbed rapidly through the
skin and lungs, and may be
selectively absorbed by the
central nervous system.
Produces brittleness of red
blood cells.
Severe doses lead to several
types of poisoning; (a) alimen-
tary; (b) neuromotor; and (c)
encephalic.
Yes
U
U
U
U
Moderate
Dangerous; can react vigorously
with oxidizing materials.
For definition of terms and ratings,see Table 7-2.
107
-------
with the liquid and gaseous streams (e.g., sour waters and oily waters) in
both technologies. As discussed in Section 4.2.3, the liquid wastes contain-
ing low molecular weight aromatics generated in coal conversion processes will
differ in aromatic content from those in refineries. Oily waters and tars
generated in coal conversion operations will contain significantly higher
concentrations of complex tars and aromatic compounds than refinery oily
waters which contain primarily paraffinic and olefinic compounds.
Table 7-6 presents some of the available toxicological and environmental
data for the principal aromatic compounds of concern. Of the compounds listed
in the table, benzene and the aromatic amines (aminobenzenes, naphthylamines)
are known or suspected carcinogens. Aromatic amines, particularly low mole-
cular weight amines, are primarily associated with coal conversion processes
although aniline and other low molecular aromatic amines have been detected
in petroleum refinery wastes^ '. The majority of amines generated in refin-
ery operations are aliphatic rather than aromatic amines (e.g., diethylamine,
triethyl amine, tri-n-butyl ami ne, etc.).
Environmental, epidemological, and biological data and Federal regula-
tions and standards for low molecular weight aromatic compounds such as ben-
zene, toluene, xylene and related compounds are well developed. Recommended
standards of occupational exposure to many of these compounds have been prom-
ulgated by NIOSH* ' '. Benzene, toluene and xylene are chemicals for which
OSHA also has prepared or is currently preparing toxicity standards* .
7.5 CONTROL TECHNOLOGIES
Treatment of refinery and coal conversion waste streams by the technol-
ogies described in Chapter 6.0 should result in the removal of substantial
portions of many of the hazardous constituents. For example, treatment of
aqueous wastes with activated carbon should result in the removal of many of
the organics including low molecular weight aromatics, organometallics and
PAHs. Particulates containing PAHs, heavy metals and organometallic com-
pounds would be expected to be partially or totally removed by use of stan-
dard particulate control devices such as electrostatic precipitators, fabric
filters and venturi scrubbers. The fate of many of these hazardous consti-
tuents in waste treatment processes and the effectiveness of the conventional
control technology for their removal in refinery and coal conversion
108
-------
TABLE 7-6. SUMMARY OF TOXICOLOGICAL AND ENVIRONMENTAL DATA FOR SELECT AROMATIC COMPOUNDS ASSOCIATED
WITH REFINERY AND/OR COAL CONVERSION WASTES(44,45)
o
vo
Parameter*
NED Category
MEG Hmrd Indicator
Toxic Dosage
Toxicology
Carclnogenlclty
Toxic Hazard Rating
Acute Local
Acute Systemic
Chronic Local
Chronic Systemic
Fire Hazard
Explosion Hazard
Disaster Hazard
Standards and Regulations
OSHA
Air, TtIA
*
-------
TABLE 7-6. CONTINUED
Ptrt-vter*
MEG Category
MEG Hazard Indicator
Toxic Dosage
Toxicology
Carclnogentclty
Toxic Hazard Rating
Acute Local
Acute Syst*ilc
Chronic local
Chronic Systealc
Fire Hazard
Explosion Hazard
Disaster Hazard
Standards and Regulations
OSHA .
A1r, TWA
Air, ceiling cone.
Air. peak cone.
Criteria documents
Air, TWA
Air, celling cone.
Compound
Aniline
IOC
Nil
Oral .hunjn-LDlo, 350 ing/kg
Oral,rat-LD50,400 eg/kg
Inhalation, rat-LCLo, 250 ppm/4 hr.
Subcutaneous, rcuso-LDl.o,<80 mg/kg
Oral, cat-I.Cl.0, 1750 ing/kg
Sk1n.rabb1t-LD50,820 mg/kg
Aquatic to.idty, Tln96:100-10 ppa
Acute exposure results in for-
mation of ncthonoglobin, with
resulting anoxcraia and depres-
sion of central nervous system.
In less acute exposures, there
cay bo heoalysts of red blood "
cells, followed by stinulatlon
of the bone Karroo and atUapts
at regeneration.
Suspected
Allergen- 2
Ingestion-3; inhalation- 3;
Skin Absorption- 3
Allergen- 2
lngestton-3; Inhalation- 3;
Skin Absorption -3
Moderate
--
Dangerous
S ppo^(skln)
Naphthylamine ()
IOC
X
Oral, rat-LDSO, 775 ng/kg
Subcutaneous ,mouse-TOLo, 25 rag/kg
Subcutaneous, rabbit-LOLo, 300 mg/kg
Oral.guucialian-LOLo.4000 eg/kg
Suspected as cause af urinary
bladder cancer.
Yes
Irritant- Z
Ingestion- 3; Inhalation- 3;
Skin Absorption- 3
U
Ingestion-3; Inhalation- 3;
Skin Absorption - 3
Slight
--
-
--
--
~
4-d1nethyl Aninoazobenzene
IOC
--
Oral ,rjc-t.CM,2GO irg/kg
Sk1n,rat-TU.o,lSS ng/kg
Intraperttoncal.rat-LDSO.SOO ag/kg
Oral .mouse- TOLo.llg/kg
Oral.dog.TDLo.9740 ng/kg
Causes liver cancer on an
acute basis in rats and alee.
res
--
--
--
--
~
--
--
"~
"
--
U.S. Occupational Health
Standard: csrcfnooen
lijpMhi'cnc
21
-
Oral, huaun-LDLo, 100 ng/kg
Oraltr«t-'.Oj0.nM cxj/tg
Subcutaneous, rat- TOLo, 3500 r.g/kn/93 days,
Ir.trapcritncal ,jie-LM.o.l50 icg/kg
Ac,uJtlc tox1ctty,TLc';6:10-l ppa
Systenic reactions Include nausea.
headache, fever, ancnla, liver
di.Tjgc, convulsions and coca.
No
Irritant-?
Ingost1on-2; Inhalation- 2;
Skin Absorption- 2
Irritant- 1
Ingestion- 2; Inhalation- 1 ;
Skin Absorption- 2
Motferata
--
Xoderau
- 10 ppm
~~
For definition of tercs and ratings, see Table 7-2.
-------
application have not been studied. Accordingly, the need for additional con-
trol processes cannot be defined at this time.
Within a refinery or a coal conversion plant measures should be insti-
tuted to minimize worker exposure to hazardous chemicals. Such worker expo-
sure control measures would be an element of the overall industrial hygiene
program for the plant. Such programs are in effect in all U.S. refineries
and similar programs would most likely be utilized in coal conversion plants.
The following are examples of in-plant measures which would reduce worker ex-
posure to hazardous chemicals:
Elimination of spills and leaks through routine monitoring and
maintenance and use of proper cleanup procedures in the event
of accidental spillage
Minimization of dermal contact with raw materials, intermediate
products, and by-products through use of closed systems (where
possible), proper ventilation and protective clothing
Use of documentation systems for industrial hygiene data and
accidents.
Detailed recommendations and practices for industrial control of hazard-
ous substances are presented in numerous documents and manuals published by
NIOSH (e.g., Reference 44).
Ill
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8.0 REFERENCES
1. "Compilation of Air Pollution Emission Factors," AP-42, U.S. EPA, Washing-
ton, D.C., revised December 1975, pp. 9.1-2.
2. Murray, Robert C., "Petroleum Equipment," Air Pollution Engineering Manual
AP-40, U.S. EPA, Washington, D.C., May 1973, pp. 581-585.
3. McKetta, J. J., Jr., ed., "Advances in Petroleum Chemistry and Refining,"
Vol. 6, Interscience Publishers, New York, 1962, pp. 372-400.
4. Beers, W. D., "Characterization of Claus Plant Emissions," Process Research
Inc., EPA-R2-73-188, PB-220-376, April 1973, p. 69.
5. Naber, J. E., et.al., "New Shell Process Treats Claus Off-Gas," Chemical
Engineering Progress, Vol. 69, December 1973, pp. 29-34.
6. "Standards Support and Environmental Impact Statement. Vol. 1. Proposed
Standards of Performance for Petroleum Refinery Sulfur Recovery Plant,"
EPA-450/2-76-016A, September 1976.
7. Goar, B. G., "Cost, Air Regulations Affect Process Choice," The Oil and
Gas Journal. August 18, 1975, pp. 109-112.
8. Bibbo, P. P. and M. M. Peaces, "Use of 'Hot Side1 Precipitator with CO
Boiler Waste Heat Recovery," Hydrocarbon Processing, September 1975, pp.
149-150.
9. Rosebrook, D. D., "Fugitive Hydrocarbon Emissions," Chemical Engineering.
October 17, 1977, pp. 143-149.
10. Information supplied to TRW by R. Murray, South Coast Air Quality Manage-
ment District, January 1978.
11. "Manual on Disposal of Refinery Wastes: Volume on Atmospheric Emissions,"
American Petroleum Institute, Washington, D.C., API Publication 931,
450 p.
12. "API Manual on Disposal of Refinery Wastes: Volume on Liquid Wastes,"
Chapter 18 - Common Refinery Wastes and Process Summaries, American
Petroleum Institute, Washington, D.C., 1969.
13. Beychok, M. R., "Aqueous Wastes From Petroleum and Petrochemical Plants,"
John Wiley & Sons, New York, 1967.
112
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14. "1972 Sour Water Stripping Survey Evaluation," American Petroleum Insti-
tute, Washington, D.C., WBWC 3064, Publication No. 927, June 1973, 61 p.
15. PolHo, F. X., et.al., "Treat Sour Water by Ion Exchange," Hydrocarbon
Processing, May 1969, pp. 124-126.
16. "Assessment of Industrial Hazardous Waste Management, Petroleum Re-Refin-
ing Industry," U.S. EPA, Washington, D.C., SW-144c, 1977, 160 p.
17. Maguire, W. F., "Reuse Sour Water Stripper Bottoms," Hydrocarbon Process-
ing, September 1975, pp. 151-152.
18. Rosenberg, D. G., et.al., "Assessment of Hazardous Waste Practices in the
Petroleum Refinery Industry," Jacobs Engineering Co., Pasadena, Ca.,
PB-259-097, June 1976, 367 p.
19. Tennyson, R. N., et.al., "Guidelines Can Help Choose Proper Process for
Gas-Treating Plants," The Oil and Gas Journal. January 10, 1977, pp.
78-86.
20. Fleming, D. K., "Purification Processes for Coal Gasification," 81st
Meeting of the American Institute of Chemical Engineers, Kansas City,
Missouri, April 11-14, 1976.
21. Christensen, K. G. and W. J. Stupin, "Acid Gas Removal in Coal Gasifica-
tion Plants," Ninth Synthetic Pipeline Gas Symposium, Chicago, Illinois,
October 31-November 2, 1977.
22. Draft Test Plan for Environmental Assessment of Hygas Process, Institute
of Gas Technology, Chicago, Illinois, U.S. DOE Contract EX-76-C-01-2433.
23. "Control of Emissions from Lurgi Coal Gasification Plants," EPA OAQPS,
Research Triangle Park, No. Carolina, EPA-450/2-78-012, March 1978, 178 p.
24. Cavanaugh, E. C., et.al., "Environmental Problem Definition for Petroleum
Refineries, Synthetic Natural Gas Plants and Liquid Natural Gas Plants,"
Radian Corp., Austin, Texas, EPA 600/2-75-068, November 1975, 454 p.
25. Walker, G. J., "Design Sour Water Strippers Quickly," Hydrocarbon Process-
ing, June 1969, pp. 121-124.
26. Klett, R. J., "Treat Sour Water at a Profit," Hydrocarbon Processing,
October 1972, pp. 97-99.
27. Bonham, J. W. and W. T. Atkins, "Process Comparison Effluent Treatment
Ammonia Separation," C. F. Braun & Co., Alhambra, Ca., ERDA Document
Number FE-2240-19, June 1975, 9 p.
28. Bush, K. E., "Refinery Wastewater Treatment and Reuse," Chemical Engi-
neering. April 12, 1976, pp. 113-118.
113
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29. Information provided by South African Coal, Oil and Gas Corp., Ltd. to
EPA's IERL-RTP, November 1974.
30. "Final Environmental Impact Statement, El Paso Gasification Project,"
U.S. Department of Interior, Washington, D.C., 1977.
31. "Final Environmental Impact Statement, WESCO Coal Gasification Project,"
U.S. Department of Interior, Washington, D.C., 1976.
32. "Draft Environmental Impact Statement, ANG Coal Gasification Company North
Dakota Project," U.S. Department of Interior, Washington, D.C., 1977.
250 p.
33. Milios, P., "Water Reuse at a Coal Gasification Plant," Chemical Engi-
neering Progress, Vol. 71, No. 6, June 1975, pp. 99-104.
34. Massey, M. J. and D. V. Nakles, "ERDA's Coal Gasification Environmental
Assessment Program: A Status Report," Ninth Synthetic Pipeline Gas Sym-
posium, Chicago, Illinois, October 31-November 2, 1977, 18 p.
35. Johnson, G. E., et.al., "Treatability Studies of Condensate Water from
Synthane Coal Gasification," PERC/RI-77/13, Pittsburgh Energy Research
Center, Pittsburgh, Pa., 1977.
36. Gehrs, C. W., "Coal Conversion; Description of Technologies and Necsssary
Biomedical and Environmental Research," Oak Ridge National Laboratory,
Oak Ridge, Tenn., August 1976, 285 p.
37. "Environmental Review of Synthetic Fuels," U.S. EPA, Industrial Environ-
mental Research Laboratory, Research Triangle Park, No. Carolina, Vol. 1,
No. 1, January 1978.
38. Ford, D. L., "Current State-of-the-Art of Activated Carbon Treatment,"
presented at the Open Forum in Management of Petroleum Refinery Waste-
waters, Tulsa, Oklahoma, January 26-29, 1976, 500 p.
39. Neufeld, R. D. and A. A. Spinola, "Ozonation of Coal Gasification Plant
Wastewater," Environmental Science and Technology, Vol. 12, No. 4, April
1978, pp. 470-472.
40. Millensifer, T. A., "Recycling Spent Catalyst Becomes Attractive as Metal
Prices Rise," The Oil and Gas Journal, March 28, 1977, pp. 82-90.
41. Rosenberg, D. G., et.al., "An Assessment of Potentially Hazardous Wastes
in the Petroleum Refining Industry," presented at 82nd National AIChE
Meeting, Atlantic City, N. J., June 1976, 32 p.
42. "California Project Turning Sump to Soil," The Oil and Gas Journal.
September 11, 1972, pp. 58-59.
114
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43. Rossoff, J. and R. C. Rossi, "Flue Gas Cleaning Waste Disposal - EPA
Shawnee Field Evaluation," 6th EPA Symposium on Flue Gas Desulfurization,
New Orleans, Louisiana, March 8-11, 1976, pp. 605-645.
44. "Registry of Toxic Effects and Chemical Substances," U.S. Department of
Health, Education and Welfare, Rockville, Md., June 1976, 1245 p.
45. Sax, N.I., "Dangerous Properties of Industrial Materials," Van Nostrand
Reinhold Co., New York, 1975, 1258 p.
46. "Particulate Polycyclic Organic Matter," National Academy of Sciences,
Committee on Biologic Effects of Atmospheric Pollutants, Washington, D.C.,
p. 197.
47. Guerin, M.R.,et.al., "Polycyclic Aromatic Hydrocarbons from Fossil Fuel
Conversion Processes," Oak Ridge National Laboratory, Oak Ridge, Tenn.,
CONF-770963-1, 1977, 26 p.
48. Koppenaal, D. W. and S. E. Manahan, "Hazardous Chemicals from Coal Conver-
sion Processes," Environmental Science and Technology, Vol. 10, No. 12,
pp. 1104-07, November 1976.
49. "Carcinogens Relating to Coal Conversion Processes," TRW Systems and
Energy, Washington, D.C., FE-2213-1, June 1976, 129 p.
50. Cleland, J. G. and G. L. Kingsbury, "Multimedia Environmental Goals for
Environmental Assessment," Research Triangle Institute, North Carolina,
EPA-600/7-77-136a and b, November 1977, 817 p.
51. "Polycyclic Aromatic Hydrocarbons and Related Compounds," National Cancer
Institute, Bethesda, Md., International Cancer Research Data Bank, 1978.
52. "Criteria for a Recommended Standard: Occupational Exposure to Coal Tar
Products," SRI International, Menlo Park, Calif., NIOSH-78/107, September
1977, 200 p.
53. Sirohi, V. P., "Carbonyl Formation in Coal Gasification Plants," C. F.
Braun & Co., Alhambra, Ca., FE-2240-16, December 1974, 14 p.
54. "Criteria for a Recommended Standard: Occupational Exposure to Benzene,"
U.S. Department of Health, Education and Welfare, NIOSH, 1974, 90 p.
55. "Criteria for a Recommended Standard: Occupational Exposure to Toluene,"
U.S. Department of Health, Education and Welfare, NIOSH, Washington, D.C.,
1973, 98 p.
56. Payne, W. R., "Toxicology and Process Design," Chemical Engineering,
April 24, 1978, pp. 83-85.
57. Information supplied to TRW by G. L. Kingsbury, Research Triangle Insti-
tute, Research Triangle Park, No. Carolina, August 18, 1978.
115
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TECHNICAL REPORT DATA
(Please read /auructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-78-190
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Applicability of Petroleum Refinery Control
Technologies to Coal Conversion
5. REPORT DATE
October 1978
6. PERFORMING ORGANIZATION CODE
7 AUTHORIS)
8. PERFORMING ORGANIZATION REPORT NO.
M. Ghassemi, D.Strehler, K.Crawford, and
S.Quinlivan
9 PERFORMING ORGANIZATION NAME AND ADDRESS
TRW, Inc.
One Space Park
Redondo Beach, California 90278
10. PROGRAM ELEMENT NO.
E HE 62 3 A
11. CONTRACT/GRANT NO.
68-02-2635
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 7/77-8/78 ,
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES jERL-RTP project officer is William J. Rhodes, Mail Drop 61,
919/541-2851.
16. ABSTRACT The rep()rt gives results of an evaluation of the applicability of refinery
control technologies to coal conversion. It is part of a comprehensive program for the
environmental assessment of high-Btu gasification technology. Process/waste streams
from coal gasification and liquefaction processes were characterized. Streams with
refinery counterparts were identified. Toxicological and health effects data were also
collected on waste stream constituents. Control technologies used in refineries to
manage the identified streams were evaluated and their applicability to counterpart
coal conversion streams was assessed. Study results indicate that, despite similar-
ities between the refinery process/waste streams and their coal conversion counter-
parts , significant composition differences between the analogous streams would affect
applicability and design of a control technology. Many refinery processes, which
appear to have applicability to coal conversion process/waste streams, have not been
tested for such applications. Additional testing would be necessary to generate data
needed for a more accurate determination of their applicability.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COSATI Held/Group
Pollution
Petroleum Industry
Refining
Coal
Coal Gasification
Liquefaction
Toxicology
Industrial Processes
Pollution Control
Stationary Sources
Coal Conversion
Health Effects
13B
05C
13H
21D
07D
06T
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
124
20. SECURITY CLASS i This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
116
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