U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-78-019
Office of Research and Development Laboratory . e\^o
Research Triangle Park. North Carolina 27711 February 1978
ENVIRONMENTAL ASSESSMENT
OF COAL LIQUEFACTION:
Annual Report
Interagency
Energy-Environment
Research and Development
Program Report
z
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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 seven series.
These seven broad categories were established to facilitate further
development and application of environmental technology. Elimination
of traditional grouping was consciously planned to foster technology
transfer and a maximum interface in related fields. The seven 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
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from
the effort funded under the 17-agency Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
environmentally—compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses 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 environmental issues.
This document is available to the public through the National Technical
Information Service, Springfield, Virginia 22161.
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EPA-600/7-78-019
February 1978
ENVIRONMENTAL ASSESSMENT
OF COAL LIQUEFACTION:
Annual Report
by
Ken T. Budden and Werner H. Zieger
Hittman Associates, Inc.
9190 Red Branch Road
Columbia, Maryland 21045
Contract No. 68-02-2162
Program Element No. EHB623A
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, O.C. 20460
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ABSTRACT
Fourteen of the most prominent coal liquefaction
systems have been studied in terms of background, process
description, major operations, input and output streams,
status, and schedule of system development. Four systems -
SRC, H-Coal, Exxon Donor Solvent, and Synthoil - have been
selected for indepth study. The first Standards of Practice
Manual is under preparation for the SRC-I system which will
include descriptions of modules, control/disposal practices,
environmental emissions, and control/disposal costs.
Must of the information presented in this report re-
presents work that is still in progress. As a result,
the information is preliminary and should be used only
as an indication of what is to come in future publications.
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TABLE OF CONTENTS
Page
Abstract ii
Table of Contents
List of Tables
List of Figures ix
ACKNOWLEDGEMENTS x
INTRODUCTION xi
MANAGEMENT SUMMARY xii
A. Current Technology Background 1
1. System Information 2
a. Catalytic Liquid Phase Hydrogenation... 2
(1) Synthoil System 2
(2) H-Coal System 4
(3) Bergius System 6
b. Noncatalytic Liquid Phase Hydrogenation 7
(1) Solvent Refined Coal System 7
(2) COSTEAM System 10
c. Pyrolysis and Hydrocarbonization 11
(1) Char-Oil-Energy Development (COED)
System 11
(2) Coalcon System 13
(3) Clean Coke System 15
(4) TOSCOAL System 16
(5) ORC (Garrett) System 18
d. Other Systems 20
(1) Fischer - Tropsch System 20
(2) Donor Solvent System 22
(3) Methanol System 24
iii
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TABLE OF CONTENTS (cont'd)
Page
(4) Supercritical Gas Extraction
System 26
2. Schedules 28
a. Catalytic Liquid Phase Hydrogenation... 30
(1) Synthoil System 30
(2) H-Coal System 30
(3) Bergius System 30
b. Noncatalytic Liquid Phase Hydrogenation 31
(1) Solvent Refined Coal System 31
(2) COSTEAM System 31
c. Pyrolysis and Hydr©carbonization 31
(1) COED System 31
(2) Coalcon System 31
(3) Clean Coke System 31
(4) TOSCOAL System 32
(5) ORC (Garrett) System 32
d. Other Systems 32
(1) Fischer-Tropsch System 32
(2) Donor Solvent System 32
(3) Methanol System 32
(4) Supercritical Gas Extraction System 32
3. Status 33
a. Synthoil System 33
b. H-Coal System 34
c. Solvent Refined Coal System 34
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TABLE OF CONTENTS (cont'd)
Page
d. Donor Solvent System 36
e. Clean Coke System 38
f. Bergius System 39
g. Char-Oil-Energy Development (COED)
System 39
h. COSTEAM System 40
i. Coalcon System 40
j . TOSCOAL System 41
k. Occidental Research Corporation
(Garrett) System 41
1. Fischer-Tropsch System 43
m. Methanol System 43
n. Supercritical Gas Extraction System.... 44
4. Priorities for Further Studies 44
a. Air Pollution Control 45
b. Water Pollution Control 45
c. Solid Waste Control 48
B. Current Environmental Background 50
a. Potential Pollutants and Impacts in All
Media 51
2. Federal/State Standards, Criteria 56
a. Federal Policy 57
b. Selected State Policies 58
3. Other Regulatory Requirements (New or
Pending) 66
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TABLE OF CONTENTS (cont'd)
Page
C. Environmental Objectives Development 68
1. Criteria for Prioritizing 68
2. Methodologies Being Developed 69
D. Environmental Data Acquisition 71
1. Existing Data for Each Process 71
2. Identify Sampling and Analytical Techniques. 73
a. The Phased Approach 73
(1) Level 1 Sampling and Analysis 74
(2) Level 2 Sampling and Analysis 75
b. Multimedia Sampling 75
(1) Classification of Streams for
Sampling Process 75
(2) Sampling Point Selection Criteria. 76
(3) Stream Prioritization 79
c. Data Requirements and Pre-Test Planning 79
(1) Process Data Needs 79
(2) Pre-Test Site Survey 80
(3) Pre-Test Site Preparation 81
d. Sampling Equipment and Methodology 81
3. Test Program Development 90
a. Introduction 90
b. Test Plan for the SRC Pilot Plant 90
c. SRC Combustion Test 92
4. Input-Output Materials Characterization:.... 94
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TABLE OF CONTENTS (cont'd)
Page
a. Reported Material Balances 95
b. Use of Reported Sample Analysis 95
c. Physical-Chemical Relationships 95
d. Analogies With Other Processes 96
e. Comparisons With Other Industries 96
f. Conceptualized Modeling of Missing
Process Modules 96
E. Technology Transfer (Input-Output) 102
1. Standards of Practice Manual 102
APPENDIX A - Process Flow Diagrams A-l
APPENDIX B - Federal and Selected State Regulations B-l
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LIST OF TABLES
Table Page
1 Control Systems Assessment Requirements .......... 47
2 Input-Output Materials for 50,000 bbl/day
Synthoil System .................................. 98
3
4
5
Input-Output Materials for 50,000 bbl/day
H-Coal System
Input-Output Materials for 50,000 bbl/day
Exxon Donor Solvent System
Input-Output Materials for 50,000 bbl/day
99
, . . 100
SRC System ....................................... 101
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LIST OF FIGURES
Figure Page
1 Process Development Operation Schedule 29
2 Basic Level 1 Sampling and Analytical Scheme for
Particulates and Gases 77
3 Basic Level 1 Sampling and Analytical Scheme for
Solids, Slurries and Liquids 78
4 High Pressure Line Grab Purge Sampling Apparatus. 82
5 Low Pressure Grab Purge Sampling Apparatus
(for Less than 2 Atmospheres Pressure) 83
6 Evacuated Grab Sampling Apparatus (for Subatmos-
pheric Pressure) 84
7 Source Assessment Sampling Schematic 86
8 Expanded View of Connections of XAD-2 Cartridge
to High Volume Sampler 87
9 Plug Collector for Fugitive Water Sample 88
10 Sampling Apparatus for HPHT (High Pressure High
Temperature) Lines 89
T,X
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ACKNOWLEDGEMENTS
The preparation of this Coal Liquefaction Annual Report
was accomplished through the efforts of the staff of the
Environmental Engineering Department, Hittman Associates,
Inc., Columbia, Maryland under the overall direction of Mr.
Dwight B. Emerson, Department Head and Mr. V. Bruce May,
Acting Head of the Synthetic Fuels Section. Direction of
the day-to-day work on the program was provided by Mr.
Werner H. Zieger, Task Leader.
Also, our appreciation is extended to the staff of the
Environmental Engineering Department of Hittman Associates,
Inc. for their assistance during this program. Specifically,
our thanks to:
Mr. Ken G. Budden, Environmental Engineer
Mr. Dewey I. Dykstra, Senior Chemical Engineer
Dr. Homer T. Hopkins, Senior Scientist
Mr. Craig J. Koralek, Chemical Engineer
Dr. C. Leon Parker, Senior Chemical Engineer
Mr. John E. Robbins, Technical Information Specialist
Mr. Kevin J. Shields, Chemical Engineer
Mr. Roger S. Wetzel, Civil Engineer
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INTRODUCTION
Extensive research into the hydrogenation of coal was
performed in the nineteen-twenties and thirties in Germany
to utilize their large coal reserves for the production of
liquid fuels. Interest in the United States was sporadic
until the nineteen-sixties and seventies when it was realized
that alternate sources of fuel were needed to augment the
limited remaining reserves of petroleum.
Hittman Associates, Inc., is currently under contract
to the Environmental Protection Agency to perform an envir-
onmental assessment of coal liquefaction technology. In
order to accurately perform this assessment, individual
studies have been initiated to further define the potential
environmental effects of coal liquefaction. These individual
studies have included; 1) an overview report of fourteen
coal liquefaction systems which included process descriptions,
major operations, input and output streams, process status,
and process development schedules; 2) an indepth study of
four processes (SRC, H-Coal, Synthoil, and Exxon Donor
Solvent); 3) environmental field sampling of coal emissions
from the burning of SRC fuel; 4) development of generalized
process assessment criteria and techniques for prioritizing
processes for generalized environmental assessments, and 5)
acquisition of coal liquefaction product and waste stream
data to estimate the environmental effects to be expected.
These generalized study categories are the basis of this
report and are explained in greater detail in the following
sections.
Must of the information presented in this report re-
presents work that is still in progress. As a result, the
information is preliminary and should be used only as an
indication of what is to come in future publications.
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MANAGEMENT SUMMARY
A. CURRENT TECHNOLOGY BACKGROUND
Estimates of current petroleum reserves indicate a
limited remaining life for useful production of fuels. This
has generated renewed interest in technology for producing
liquid hydrocarbons from coal, with the primary objective of
producing clean liquid fuels. Coal liquefaction is not a
new technology, but dates back to the early part of the
twentieth century and in principle even further than that.
With the entry into an era of declining petroleum re-
serves, reduced discoveries, escalation of prices, and real
or induced shortages, coal liquefaction technology has once
more assumed a major role as a potential solution to liquid
fuel problems. Currently some twenty-odd systems are in
various stages of development by industry and federal agencies,
Four major generic processes of coal liquefaction technology
can be identified. These are:
• Catalytic Liquid Phase Hydrogenation
• Noncatalytic Liquid Phase Hydrogenation
• Pyrolysis and Hydrocarbonization
• Other Systems
Each of the generic processes includes several specific
processes.
1. CATALYTIC LIQUID PHASE HYDROGENATION
a. Synthoil System
The intent of the SYNTHOIL Process development was
to show that, under the right conditions, reaction of coal
with hydrogen will promote desulfurization and minimize
additional hydrogenation of the products from the primary
liquefaction. Work on such a process was initiated by the
United States Bureau of Mines at the Pittsburgh Energy
Research Center in 1969. It has led to a process in which
coal is liquefied and desulfurized in a single step by
catalytic hydrotreatment in a highly turbulent, co-current,
up-flow, packed-bed reactor. Experimental work was carried
xi-i
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out on various coals including Pittsburgh, Indiana No. 5,
Middle Kittanning, Ohio No. 6, and Kentucky coal. All of
these types of coal were satisfactorily converted to low-
sulfur fuel oil with no appreciable attrition of catalyst or
loss of catalyst desulfurization activity.
The Synthoil process is currently in the lab-
oratory stage with construction of a process development
unit underway. Operation of the process development unit is
projected to begin in 1978 and continue into 1980. No firm
plans for a pilot plant have been announced.
The Foster wheeler Energy Corporation is respon-
sible for the design and management of the construction of a
9.1 megagram (10-ton) per day process development unit to
test the Synthoil process. However, recent communications
from ERDA indicate that the process development unit may not
be used for the Synthoil process. Pittsburgh Energy Re-
search Center (PERC) is conducting support research for the
design of the process development unit, PERC is also moni-
toring laboratory research on various aspects of the Syn-
thoil process being conducted by ERDA's Sandia Laboratories
and by the Argonne National Laboratory. Research on the
Synthoil process is also being conducted by the Exxon Re-
search and Engineering Laboratories and by the Battelle
Memorial Institute Laboratories. These projects are being
monitored by the Morgantown, Energy Research Center (MERC)
in West Virginia.
The Hittman Associates, Inc. laboratories are
running analyses of (1) the Synthoil product, (2) residue
removed from the product by centrifugation, and (3) the
stripping solution that had been used to remove hydrogen
sulfide, ammonia and organic vapors from the off gas vented
from the process. These materials were produced from a
blend of four Kentucky bituminous coals.
b. H-Coal System
The direct hydrogenation process developed by
Bergius in Germany for conversion of coal to liquid products
led to later development in the U.S. of the H-Coal process.
It was developed by Hydrocarbon Research, Incorporated (HRI)
as a further application of the H-Oil process ebullating bed
technology originally employed to convert heavy oil residues
into lighter fractions. The ebullating bed catalytic re-
actor converts about 90 percent of the carbon contained in
coal to a liquid. The feed to hydrogen manufacture is
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liquid rather than solid. The reactor configuration offers
better temperature control, constant catalyst activity and a
consistent quality of liquid product. An external hydrogen
source is required. However, direct catalytic processes use
less hydrogen in converting coal to liquids than do the
noncatalytic or indirect catalytic hydrogenation processes.
The H-Coal process is being developed by Hydro-
carbon Research, Inc. under the joint sponsorship of (1)
ERDA, (2) a private industry consortium composed of Electric
Power Research Institute, Ashland Oil, Inc., Conoco Coal
Development Company, Mobil Oil Corporation and Standard Oil
Company (Indiana), and (3) the Commonwealth of Kentucky.
The overall objectives of the project are to further develop
the H-Coal process and to demonstrate its technical and
economic feasibility on a larger scale. Specific objectives
are to, (1) conduct laboratory research on all phases of the
H-Coal process using the existing bench-scale unit and
process development to establish design criteria, (2)
design a pilot plant capable of converting 545 megagrams
(600 tons) of coal per day to 318 cubic metres (2,000 barrels)
per day of low sulfur boiler fuel and (3) procure equipment
and materials for the pilot plant. Objective (1) is con-
tinuing. Objective (2) has been realized as the ground was
broken December 15, 1976 at Cattlettsburg, Kentucky. Deter-
mination of the feasibility of commercial production of
liquid hydrocarbons from coal is the objective of this
ninety-million dollar pilot plant.
c. Bergius System
Developed by Germany to produce aviation fuel and
diesel oil during World War II, the Bergius process was one
of the forerunners in coal liquefaction technology and has
led to the recent development in the United States of the H-
Coal and Synthoil processes.
The Bergius process is the ERDA "disposable
catalyst" process. Construction of a process development
unit is in progress and initial operation is planned for
late 1977. No pilot plant plans currently exist.
2. NONCATALYTIC LIQUID PHASE HYDROGENATION
a. Solvent Refined Coal (SRC) System
The SRC process was originally developed by Spencer
Chemical Company for the United States Department of the
Interior, Office of Coal Research. Subsequently Gulf Oil
x^v
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acquired Spencer Chemical Company and development continues
to the present under the Pittsburgh and Midway Coal Mining
Company, part of Gulf Oil.
The SRC process requires no catalyst and low
amounts of hydrogen relative to most alternative processes.
The solid product is low in sulfur and ash, and has a high
heating value. The major difficulties lie in operating
costs for filtration and development of handling methods of
the solid product.
Presently, there are two pilot plants operating,
one in Wilsonville, Alabama and another in Fort Lewis near
Tacoma, Washington. The plant at Wilsonville, Alabama will
operate through 1977. A decision is to be made late in that
year whether or not to continue operation.
Operational data from the Ft. Lewis plant will
provide opportunities for (1) further study and development
of the process, (2) accumulation of engineering and cost
data for evaluation of commercial possibilities and design
of demonstration or commercial plants, and (3) product
evaluation and market development. Operation of the Fort
Lewis, Washington facility is planned to extend into 1981.
In addition, a demonstration plant is being con-
sidered by the Kentucky Center for Energy Research but no
schedule is available.
b. COSTEAM System
The Bureau of Mines has developed a new process,
COSTEAM, that does not use hydrogen directly. In this
process coal reacts with carbon monoxide and steam instead
of hydrogen. It does not require a catalyst to convert low
rank coals, such as lignite, into a low sulfur liquid fuel.
There is usually enough water in lignite to supply the needs
of the process. The water or steam supplies active hydrogen
by reaction with the carbon monoxide. Alkaline carbonates
are naturally occurring catalytic agents in lignite.
A process development unit was scheduled for com-
pletion in 1976. Operation beginning in 1977 and continuing
into 1981 is planned.
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3. PYROLYSIS AND HYDROCARBONIZATION
a. Char-Oil-Energy Development (COED) System
In the COED process, coal is heated in several
types of fluidized bed at increasingly higher temperatures.
This enables the process to handle caking coals without the
preoxidation or recirculation of char usually necessary to
prevent agglomeration in the system. This feature permits
the achievement of high yields of oil with minimum sized
equipment. An additional advantage is that the process
operates at low pressure, less than 0.70 kg/cm^ TO.63 Atm.)
which permits the use of conventional oil processing equip-
ment.
The COED project has been completed through the
pilot plant stage. Dismantling of the pilot plant has been
completed. No further work is projected for this process.
b. COALCON System
The Coalcon process is based on hydrocarbonization
of coal. When heated in a hydrogen atmosphere, coal pro-
duces liquid, gaseous, and solid products. These materials
are separated and treated to produce the final clean pro-
ducts. The solid material or char is then gasified with
oxygen to produce a portion of the hydrogen rich gas re-
quired for hydrocarbonization.
Although originally planned for near term con-
struction, ERDA is considering suspension of the project due
to marginal economics and technical problems with fluid-bed
carbonizers. Further work is proceeding to eliminate scale-
up problems involved in fluidized bed and a decision will be
made late in 1977 as to the fate of this project.
c. Clean Coke System
The Clean Coke process is being developed by USS
Engineers and Consultants, Inc., a subsidiary of United
States Steel Corporation, under the sponsorship of ERDA.
The work was initiated in 1972 under the auspices of the
Office of Coal Research (OCR, now a part of ERDA). The
objective of the project is to design a pilot plant that is
capable of converting low-grade, high-sulfur coal to low-
sulfur, low-ash metallurgical coke, chemical feedstocks, and
liquid and gaseous fuels.
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The Clean Coke process combines coal carbonization
and hydrogenation to produce solid, liquid, and gaseous fuel
products. Char produced by carbonization is converted to
coke which eliminates the problem of char use and disposal.
No mechanical separation equipment is used to separate the
solids from liquid product. Hydrogenation is noncatalytic
and no external hydrogen is required. However, the hydro-
genator operates at a very high pressure.
Laboratory and bench scale development studies on
Illinois No. 6 Seam coal have been underway since 1969.
Various aspects including coal preparation, carbonization/
desulfurization of coal in fluidized beds, and high pressure
hydrogenation reactions have been the subjects of these
investigations. Process development units have been built
and are now operating. Two additional types of coal are
scheduled to be processed. Information obtained from the
process development units will be used for the design of 218
megagrams (240 ton) per day pilot plant.
d. Occidental Research Corporation (Garrett) System
The Garrett Process is a solid phase hydrocarbon-
ization process in which pulverized coal is almost com-
pletely converted to liquid and gaseous products in less
than one minute. The process involves very rapid heating
and devolatilization of pulverized coal in the absence of
air, a short residence time in an entrained flow reactor,
and a quick quench which prevents degradation of the liquid
and gaseous products. Product distribution is strongly
influenced by pryolysis temperature, with lower temperatures
favoring liquid formation. The pyrolysis products can be
further refined and purified to obtain synthetic crude oil,
char which is suitable for combustion in an electric utility
boiler, pipeline gas, and elemental sulfur.
Occidental Research Corporation (ORC) and the
Commonwealth of Kentucky are in a joint venture for the
purpose of preparing a detailed design for a 227-Mg (250-
ton) per day pilot plant. A municipal waste processing
plant of the same capacity is being constructed in San Diego
County, California. ERDA's schedule calls for continued
evaluation via process development unit operation into
Fiscal Year 1978.
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4. OTHER SYSTEMS
a. Fischer-Tropsch System
At this time, in the United States, studies based
on the Fischer-Tropsch synthesis are of a fundamental re-
search nature. No concrete plans have been made yet for
process development or pilot studies in this country. A
second large production plant is to be constructed in the
coal fields of the Eastern Transvaal region in South Africa.
b. Donor Solvent System
Research was begun in 1966 to develop the basic
Exxon Donor Solvent (EDS) process. It included studies on
both hydrogenated and unhydrogenated recycle solvents.
Equipment was tested in an integrated pilot plant system of
454 kilograms (one half ton) per day capacity. Techniques
were developed for analyzing product and intermediate streams.
Studies of process variables are continuing in a 907 kilogram
(one ton) per day pilot plant.
The Energy Research and Development Administration
and Exxon Research and Engineering Company of Florham Park,
New Jersey have signed an agreement totaling $240 million to
develop a process for producing liquids from coal. The
project is based on Exxon's donor solvent coal liquefaction
process. The program will involve both small-scale R&D
work, and the design, construction and operation of a pilot
plant with a capacity of 250 tons per day. The pilot plant
will be built adjacent to an Exxon refinery at Baytown,
Texas. The new agreement runs through December 31, 1982.
The project is designed to bring donor solvent coal lique-
faction technology to a stage where commercial plants could
be designed and built by private industry.
c. Methanol System
Natural gas, reformed to synthesis gas, is cur-
rently preferred for methanol production in countries where
it is available as a cheap feedstock. Prior to the advent
of natural gas, solid fuels had been the major source for
synthesis gas for methanol production. In the United States
natural gas is no longer readily available and alternate
sources for synthesis gas are being evaluated. Abundant
coal reserves present in the United States may play an
important role in synthesis gas production.
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Some of the first generation systems that have
been used to convert coal to synthesis gas are Koppers-
Totzek, Lurgi and Winkler. The three systems employ dif-
ferent features and operating conditions, and each produces
a gaseous product of different composition. A number of
second generation processes are under development.
d. Supercritical Gas Extraction System
Two major problems facing advancement of coal
liquefaction to commercialization are operability of solid-
liquid separation equipment and high hydrogen consumption.
The Supercritical Gas Extraction Process (SGE), now under
development by National Coal Board in England seems to have
solved these problems. Catalytic, Inc., a subsidiary of Air
Products and Chemicals, Inc. is evaluating the technical
feasibility of this process for United States coals. This
process is at such an early stage of development that no
plans beyond conception have been announced.
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B. CURRENT ENVIRONMENTAL BACKGROUND
Based on the available literature with respect to
potential pollutants resulting from coal liquefaction sys-
tems and conjunctive developments, Hittman Associates has
attempted to identify the classes of major organic and
inorganic substances (including organometallies) emanating
from gaseous, aqueous, and solid waste emissions and ef-
fluents. Division of the pollutants into the organic and
inorganic (or organometallic) groups is reasonable because
these two groups differ in their chemical and physical
properties; these properties in turn influence the envir-
onmental effects of the various pollutants. The physical
and chemical properties of the organics have been discussed
in terms of their classes. An effort was made to generalize
on the known concentration of about seven inorganic, twenty-
two trace and heavy metal elements, and nine major organic
compounds, expected in nine major environmental compart-
ments, (soil, rock, freshwater, seawater, air, plants,
marine, terrestrial, and animals) as an aid in estimating
whether the increased inputs of these elements when released
in the ash, etc. from coal liquefaction, would significantly
increase the level in the environment.
One of the more significant aspects of the ongoing en-
vironmental assessment effort by Hittman Associates has
involved the critical analysis of natural physical-chemical
processes that effectively dissipate or enhance the toxic
effects of known biological stressors in aqueous and solid
waste effluents. Another important effort refers to the
attempt made by Hittman Associates to identify those living
organisms judged by the 96-hour LD5Q, to be the most sen-
sitive vis-a-vis such organic pollutants as benzene, acena-
pthene, anthracene, chrysene, toluene, 3,4-benzopyrene-
isophorone, and benzidine, among others. Organisms were
identified among the marine microorganisms (algae, bacteria,
etc.) fresh-water algal, terrestrial microorganisms, selected
higher plants, marine invertebrates, freshwater inverte-
brates , marine and freshwater fishes, amphibians, and non-
human mammals. One of the least studied areas relates to
the additive interactions between mixtures of such aqueous
pollutants as phenols, metals, ammonia, and mixtures of
ammonia, phenol, zinc, copper and cyanide. An effort was
made to demonstrate more clearly the synergistic and anta-
gonistic interactions of a number of compounds.
xx
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Present indications as to chronic effects of major
pollutants, based on the study of coal-derived products, are
as follows:
41
• Sulfur-containing constitutents (in the reduced
state) are present in a much greater variety and,
in some cases, larger quantities than was anti-
cipated. The ecological and health effects of
reduced sulfur compounds has not been studied
intensively.
• Concentrations of polynuclear aromatic hydro-
carbons are very high. A detailed study of this
fraction is called for to properly estimate the
general threat of industrial carcinogensis. BaP
concentrations in aqueous liquors suggest an
environmental hazard.
• Concentrations of weakly acidic components, sus-
pected tumor promotors or co-carcinogens, are
substantial and a wide variety occur.
• Nitrogen heterocyclics are present at substantial
levels suggesting the need for additional studies.
High indole/skatole concentrations suggest the
possible presence of carcinogenic dibenzacridine.
Consistent with the objective of evaluating coal lique-
faction systems, a review of existing environemtal require-
ments was made at the Federal and State government levels.
The study of state laws was restricted to those states which
have the demonstrated coal reserves necessary to provide
sites for commerical coal liquefaction facilities in the
near and far term. The states which have been addressed are
Alaska, Arizona, Colorado, Illinois, Indiana, Kentucky,
Montana, New Mexico, North Dakota, Ohio, Pennsylvania, South
Dakota, Texas, Utah, West Virginia and Wyoming.
The major conclusion of the review is that no legis-
lation currently exists directly pertinent to coal lique-
faction processes. Prior to commercialization such legis-
lation will be needed at the federal, state and local levels.
Additionally, existing standards governing related fossil
fuel technologies could serve as the foundation on which
standards for liquefaction facilities will be based. How-
ever, at this time it is impossible to project how stringent
and how comprehensive environmental regulations will be
specific to commercialized coal liquefaction systems.
xxi
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C. ENVIRONMENTAL OBJECTIVES DEVELOPMENT
In conjunction with the development of Environmental
Characterizations, a preliminary effort was completed to
establish study priorities for the development of coal
liquefaction technologies and control needs. The candidate
systems were those most advanced from a development stand-
point and those considered to be of possible interest to
commercial developers and industrial users. The result of
this prioritization is a comparative rating and evaluation
of the systems established on the basis of projected needs
for detailed study and environmental characterization. The
order of ranking for the candidate systems in coal lique-
faction technology is as follows:
Solvent Refined Coal
H-Coal
Exxon Donor Solvent
Synthoil
COED
COSTEAM
Clean Coke
Fischer-Tropsch
ORC (Garrett)
Coalcon
Methanol Synthesis
TOSCOAL
Bergius
IERL-RTP is currently developing an environmental
assessment methodology especially related to the Federal
Interagency Energy/Environment R&D Program in support of
standards develoment. The environmental assessment method-
ology will consist of various methodology components being
developed with the assistance of participating contractors.
One such specialized component is the development of process
assessment criteria which will be used to set priorities
with regard to the selection of processes for further study
in environmental assessment. Hittman Associates' task,
called Process Assessment Critiera, consists broadly of:
• delineating criteria to be considered in eval-
uating processes (to set priorities for further
study),
• assigning these criteria a normalized set of re-
levance weights, based on a rational decision
analysis method, and
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• preparing step-wise instructions which will permit
application of this methodology component for a
generalized environmental assessment.
D. ENVIRONMENTAL DATA ACQUISITION
Existing data for the environmental discharges on the
different systems are fragmentary and usually may be char-
acterized as (1) product and waste descriptions based on
hydrocarbon chain length, boiling point ranges, viscosities,
and element contents (sulfur, nitrogen, carbon-hydrogen
ratios, metals, etc.), (2) qualitative analysis for specific
organic compounds, often for known carcinogenic effects, and
(3) out-of-date and/or partial quantitative analysis of
products. Since there is no available overall quantitative
analysis of product and waste discharges from an existing
coal liquefaction systems, Hittman Associates is currently
preparing reports which will provide a preliminary estimate
of such discharges for four systems - Solvent Refined Coal,
Synthoil, H-Coal and Exxon Donor Solvent.
At this point in the input characterization develop-
ment , the similarities should be stressed rather than dif-
ferences. For example, the bottoms fraction from the EDS
process consist of 4,866 tons per day, while the Synthoil
process has only 3,536 tons per day of char after pyrolysis
through a multiple hearth furnace (conceptualized by Syn-
thoil developers). Pyrolysis or other treatment of EDS
bottoms could reduce the amount of bottoms to a lower figure
comparable to the Synthoil char. Similar treatment could
reduce the 5482 tons per day of solid wastes from the H-Coal
process. The similarity is that all four processes have
3500 to 5500 tons per day of solid and residue waste for
use/treatment/disposal. This quanity of solid and residue
waste represents a significant area of environmental dis-
charge which needs to be given priority attention. Similar
attention needs to be given to treatment/control equipment
for process wastewater and air emissions.
Hittman Associates is currently preparing an envir-
onmental characterization report which will discuss the
literature and other available data on the environmental
effect of the products from coal liquefaction systems.
Environmental effects for coal liquefaction facilities may
be expected from (1) atmospheric emissions of particulates,
sulfur and nitrogen compounds, and other volatiles, (2)
wastewater contaminants such as acids, phenols, organics,
cooling tower chemicals and inorganic compounds, (3) solid
and residue wastes such as ash, still bottoms, char, spent
xxiii
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catalyst, and filtered solids, and (4) the products. Most
of the existing data for environmental effects are for the
product, or the solid and residue wastes. As laboratory
analysis of product and waste streams for quantitative
measurement of toxic and hazardous chemicals becomes avail-
able, Hittman Associates will attempt to estimate the
environment effects to be expected from quantified dis-
charges .
During the past year work was performed on two major
test programs. A suggested sampling plan for the Ft. Lewis,
Washington Solvent Refined Coal Pilot Plant, operated by
Pittsburgh and Midway Coal Mining Company, is nearing com-
pletion. The purpose of this plan is to provide guidance in
a multimedia sampling program. Much of the information was
exerpted from the IERL-RTP Procedure Manual: Level 1 Environ-
mental Assessment (EPA-600/2-76-160a). The phased approach
and sampling methodologies were the basis for the document.
A test plan was also developed for a combustion test at
Georgia Power Company's Plant Mitchell where Solvent Refined
Coal was burned for the first time in a commercial utility
boiler. The test occurred, and samples were collected. A
paper on the subject was delivered at the EPA Symposium on
Environmental Aspects of Fuel Conversion Technology, III in
Hollywood, Florida. The major portion of the analysis is
currently being performed and a final report of the test
will be prepared when these results are available.
E. TECHNOLOGY TRANSFER
The first Standards of Practice Manual for a coal
liquefaction systems is under preparation by Hittman Asso-
ciates, Inc., Columbia, Maryland. The Standards of Practice
Manual is designed to furnish environmental guidelines and
best control/disposal options for liquefaction processes
currently under development.
The SRC-1 system was chosen for the study. A pilot
plant for the system has been operated by ERDA at Fort
Lewis, Washington since September 1974. It was felt that a
definitive study of the process and its waste streams, and
their optimum treatment methodologies would provide a ser-
vice to the future commercialization of this process.
Progress includes completion of material balances for
the process and waste streams. From this basis, written and
schematic descriptions of process modules and control/disposal
modules were added. Best control/disposal practices have
been selected for all wastestrearns. Partially complete are
descriptions of environmental emissions and factors achievable
and control/ disposal costs.
xxiv
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Remaining work includes a detailed description of the
basic process, which will outline control options for specific
emissions and their respective costs for each process module.
A large portion of this effort will consist of assembling
information from previous sections of the manual and summar-
izing them into clear, succinct unit operations for each
process module.
xxv
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A. CURRENT TECHNOLOGY BACKGROUND
With the entry into an era of declining petroleum
reserves, reduced discoveries, escalation of prices, and
real or induced shortages, coal liquefaction technology has
once more assumed a major role as a potential solution to
liquid fuel problems. Currently some twenty-odd processes
are in various stages of development by industry and federal
agencies. Four major generic processes of coal liquefaction
technology can be identified. These are:
• Catalytic Liquid Phase Hydrogenation
• Noncatalytic Liquid Phase Hydrogenation
• Pyrolysis and Hydrocarbonization
• Other Systems
Each of the generic processes includes several specific pro-
cesses.
A wide range of process conditions and configurations
exist within the liquefaction technology. Characterization
of the more important processes is presented in the re-
mainder of this section. Flow diagrams for each system
discussed can be found in Appendix A.
1. SYSTEM INFORMATION
a. Catalytic Liquid Phase Hydrogenation
(1) Synthoil System*
The intent of the SYNTHOIL Process develop-
ment was to show that, under the right conditions, reaction
of coal with hydrogen will promote desulfurization and
minimize additional hydrogenation of the products from the
primary liquefaction. Work on such a process was initiated
by the United States Bureau of Mines at the Pittsburgh
Energy Research Center in 1969. It has led to a process in
which coal is liquefied and desulfurized in a single step by
catalytic hydrotreatment in a highly turbulent, co-current,
up-flow, packed-bed reactor. The initial work used a
reactor with an internal diameter of 0.79 cm. (0.3125 in)
* (Ref. Fig.l, App. A.)
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with daily feed rates of 22 kg (48 Ib.) of coal or 54 kg
(120 Ib.) of slurry. Experimental work was carried out on
various coals including Pittsburgh, Indiana No. 5, Middle
Kittanning, Ohio No. 6, and Kentucky coal. All of these
types of coal were satisfactorily converted to low-sulfur
fuel oil with no appreciable attrition of catalyst or loss
of catalyst desulfurization activity. Other parameters
investigated were hydrogen flow rate, coal content of feed
slurry, recycle of product oil, and the effects of hydrogen
sulfide on recycle gas. A larger bench-scale unit, 2.8 cm
(1.1 in.) internal diameter and 4.42 m (14.5 ft) long, was
operated at daily feed rates up to 181 kg (400 Ib.) of coal
and 454 kg (1/2 ton) of slurry. Reactor pressure was varied
from 145 to 290 kg/cm^ (140 to 280 atms.) at temperatures up
to 450°C (840°F). High yields of low sulfur (0.19 to 0.3
percent) and low-ash (one percent) fuel oil ranged from 525
to 700 liters per metric ton of coal (3 to 4 barrels per
ton) . The lower reactor pressure corresponded to lower
values of yield, heating value and hydrogen consumption.
Sulfur and ash content of the low pressure oil were higher
than those of the oil made at 290 kg/cm2 (280 atm.). Opera-
tion at the lower pressure is desirable provided an environ-
mentally acceptable product can be made. An 11 metric-ton
per day process development unit is under construction.
Coal feed for the SYNTHOIL Process is pre-
pared by drying and then grinding to 90 percent through 60
mesh or 65 percent through 200 mesh. The ground coal is
thoroughly mixed with recycled product oil to form a paste
or slurry containing about 40 percent coal and 60 percent
oil. The slurry, together with recycled and makeup hydro-
gen, is preheated and then passed to the reaction zone. The
reactor is packed with eighth-inch pellets of a commercial
catalyst of the type used in desulfurizing petroleum deriva-
tives. Under operating conditions of 140 to 280 kg/cm2 (136
to 271 atm.), 450°C (840°F) and a superficial gas velocity
of 1.83 m (6 ft) per sec., hydrogen liquefies the coal and
removes sulfur, oxygen, and nitrogen from it.
The major portion of the coal is hydrogenated
to gas and oil which are separated by a pressure reduction.
The oil stream containing SYNTHOIL, residue, and mineral
matter is treated to separate the oil and solids. The oil
is divided into two streams, one of which is returned to
feed preparation and the other withdrawn as product. Resi-
due and oil are separated; the oil is sent to product stor-
age and the residue goes to the hydrogen production area.
The gaseous mixture from the reaction contains unused hydro-
gen which can be recycled through the reactor. However, it
also contains hydrogen sulfide and ammonia. These two
contaminants are removed by absorption in the gas purifica-
tion system. The hydrogen sulfide is sent to a sulfur
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recovery unit and the ammonia is used to produce ammonium
sulfate. Sulfuric acid also may be produced.
Coal and residue from the reactor are used to
produce a rich hydrogen (97.5 percent) mixture to use in the
liquefaction reaction.
Major Operations and/or Modules
• Sizing, drying and slurrying
• Hydrogenation
• Separation
• Hydrogen production
Input and Output Streams
• Input Streams
Coal
Catalyst - Co-Mo/Si09-Al90~
Hydrogen z z J
Monoethanolamine (MEA)
Water
• Output Streams
SYNTHOIL
Sulfur
Ammonium Sulfate
Sulfuric Acid
Ash
Carbonaceous residue
Water from coal drying
Dust from crushing
Fuel gas
Tar
Spent catalyst
Spent MEA
Waste liquids, oil, and water
Slowdown and sludge from:
• Power plant
• Water treatment
• Cooling tower
(2) H-Coal System*
The direct hydrogenation process developed by
Bergius, in Germany, for conversion of coal to liquid products
* (Ref. Fig.2, App.A.)
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led to later development in the U.S. of the H-Coal process.
It was developed by Hydrocarbon Research, Incorporated (HRI)
as a further application of the H-Oil process ebullating bed
technology originally employed to convert heavy oil residues
into lighter fractions. The ebullating bed catalytic
reactor converts about 90 percent of carbon contained in
coal to a liquid. The feed-to-hydrogen manufactured is
liquid rather than solid. The reactor configuration offers
better temperature control, constant catalyst activity, and
a consistent quality of liquid product. An external hydro-
gen source is required. However, direct catalytic processes
use less hydrogen in converting coal to liquids than do the
noncatalytic or indirect catalytic hydrogenation processes.
Major Operations and/or Modules
• Sizing. Drying, and Slurrying. The coal
is crushed to about 18 mm (3/4 in; and stockpiled. For feed
preparation, it is dried to 4 percent moisture, and then
ground to minus 60 mesh. Crushed coal is mixed with re-
cycled oil to form a slurry feed for the high pressure
hydrogenation module.
• Hydrogenation. Coal slurry and hydrogen
are passed through a preheated furnace and then fed to the
bottom of the reactor. The liquid slurry is hydrogenated as
it comes in contact with the ebullating bed of catalyst.
The reaction takes place at a temperature of about 455°C
(850°F) and pressure of about 206 kg/cm2 (200 atm) . Fresh
catalyst is added to replace the used catalyst on a semi-
continuous basis which permits reactor operation at a con-
stant equilibrium activity level.
• Product Separation. Gases and vapors
are withdrawn from the top of the reactor and passed through
condensers. Condensed oil vapors are sent to an atmospheric
distillation unit. Further cooling of gases condenses a
large amount of sour water containing ammonia, hydrogen
sulfide, phenols, light oil, and suspended solids. Uncon-
densed gases are passed through an acid gas removal unit
where hydrogen sulfide is removed and further processed to
elemental sulfur. Fart of the clean gas is used as plant
fuel and part is recycled to the main reactor system. Fresh
hydrogen is added to achieve the required concentration for
use in the main reactor.
• Solids Separation. The heavier portion
of the product oil leaves as a sidestrearn from the lique-
faction reactor. It contains particulates such as mineral
matter and unreacted coal which must be removed. The hot
oil is flashed in a separator and the vapors are condensed
and pumped to an atmospheric distillation unit.
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• Distillation. The bottoms product from
the flash separator is further separated with a hydrocyclone,
a liquid-solid separator, and a vacuum still. The overhead
is a heavy oil refinery feedstock. The stream removed from
the bottom of the vacuum tower contains heavy liquid residue
together with some particulates. The bottoms product from
the distillation unit is recycled for slurry preparation and
the overhead stream of light liquid hydrocarbons is further
refined as necessary. Synthesis gas for use in making
hydrogen can be generated by using the slurry bottoms from
the vacuum tower as feed to a slagging type gasifier.
Supplemental coal feed may be needed.
Input and Output Streams
• Input Streams
Coal
Stream
Air
Catalyst
Absorption solvent
• Output Streams
Synthetic oil
Sulfur
Ammonia
Ash
Residue
Spent catalyst
Spent solvent
Water from coal drying
Dust from coal crushing
Fuel gas
Tar
Waste liquids, oil, and water
Slowdown and sludges from:
• Power plant
• Water treatment
• Cooling tower
(3) Bergius System*
Developed by Germany to produce .aviation fuel
and diesel oil during World War II, the Bergius process was
one of the forerunners in coal liquefaction technology and
has led to the recent development in the United States of
the H-Coal and Synthoil processes. Coal from the stockpiles
(Ret. Fig.3, App.A.)
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is dried and finely ground. It is then mixed with process
derived hydrocarbon liquid to form a paste containing ap-
proximately 40 percent coal. The paste is pressurized to
about 700 kg/cm^ (677 atm.) and heated to a temperature of
430°C (810°F). The heated paste and the recycled hydrogen-
rich gas are then fed to a catalytic reaction zone.
The products from the first reaction are
separated into an overhead gaseous stream, a light oil
stream, and a heavy oil stream which contains unreacted coal
and mineral matter. The overhead hydrogen rich gas is
scrubbed to remove any particulate matter and recycled to
the reactor. The light oil stream is further treated over a
catalyst to produce materials similar to petroleum. The
heavy oil stream is treated to separate untreated coal,
catalyst, and mineral matter from the oil. Recovered oil is
recycled to the paste preparation area.
Major Operations and/or Modules
• Drying, Sizing, and Pasting
• Hydrogenation
• Separation
Input and Output Streams
• Input Streams
Coal
Hydrogen
Water
Catalyst
• Output Streams
Carbonaceous residue
Light oil
Middle oil
Wastewater
Spent catalyst
Sulfur
Ammonia
Dust
Fuel gas
Tar
Waste oil
Slowdown and sludges from:
• Power generation
• Water treatment
• Cooling towers
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b. Noncatalytic Liquid Phase Hydrogenation
(1) Solvent Refined Coal System*
Two alternatives are being pursued for
electric power generation. One is to burn coal directly and
remove particulates and S02 by scrubbing the stack gases;
the other is to refine or clean the coal by removal of
sulfur and ash or mineral matter before it is fired in the
utility steam generator and, thus, obviate the need for
stack gas cleaning. Solvent Refined Coal (SRC) represents
the second alternative and is receiving prominent consid-
eration. The process requires no catalyst and low amounts
of hydrogen relative to most alternative processes. The
solid product is low in sulfur and ash and has a high heating
value. The major difficulties lie in operating costs for
filtration and development of handling methods of the solid
product.
Major Operations and/or Modules
• S iz ing, Drying, and Slurrying. As the
coal is received, it is separated according to lump size.
Lumps smaller than three- by six-inches are sent to a
primary crushing step which reduces the size to three-
quarters of an inch. Large lumps are crushed to three- by
six-inches and returned to the primary crushing step. Sized
coal, three-quarters of an inch, from the primary crushing
step is stored. The stored coal is transferred to the pul-
verizer system. This system simultaneously grinds the coal
to about 200 mesh size and dries it to one- to three-percent
moisture. Fines less than 200 mesh size from both primary
and pulverizing, can be used to produce hydrogen for the
hydrogenation step. The pulverized dry coal is slurried
with solvent.
Hydrogenation. A 70 to 85 percent
2 is added to t
hydrogen gas mixture is added to the coal/solvent slurry.
These materials are first preheated and subjected to the
conditions of the hydrogenation operation. Depending on the
nature of the coal and its sulfur content, the temperature
range is 425° to 495°C (800° to 925°F) and the pressure
range is 70 to 140 kg/sq. cm. (68 to 136 atm.). Other
variables which affect this operation are the partial
pressure of hydrogen, the residence time, and the solvent-
to-coal ratio. These variables are not independent, i.e, a
change in one may cause changes in the others. This helps
to provide flexibility to the process, permitting the output
* (Ref. Fig.4, App.A.)
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of a heavier or lighter product; the lighter product having
the higher hydrogen content.
The hydrogenation or liquefaction opera-
tion produces a mixture of gases, vapors, liquids, and
solids. This mixture is cooled to 290°C (550°F) and the
vapor and gases are separated from the liquids and solids by
a series of pressure reductions. The vapors, consisting of
light hydrocarbons, heavy hydrocarbons and water, are con-
densed and collected.
• Solids Separation. The mixture of coal
solution and solids is separated by filtration or centrifuga-
tion. The solids contain mineral matter and undissolved
coal. This residue is cooled to 38°C (100°F) and stored.
It can be gasified to produce the hydrogen required in the
process.
• Solvent Recovery. Liquid material from
the solids-liquids system separation is heated to 425° to
470°C (800° to 875°F) at about 7 kg/cm2 (6.8 atm.). All the
unused process solvent and lighter liquids are vaporized.
The remaining material is the molten solvent refined coal.
The molten product is cooled from 316°C (600°F) to about
66°C (150°F) at which temperature it is solid.
• Gas Cleaning. In the hydrogenation
operation, most of the sulfur in the coal is converted to
hydrogen sulfide and other gaseous compounds. Excess hydro-
gen is used in the operation and unused hydrogen can be
recycled. However, it must first be "cleaned" to remove
gaseous sulfur compounds. A number of patented processes
are available for this purpose, some remove carbon dioxide
as well as hydrogen sulfide. After the hydrogen sulfide is
removed from the gas stream, the solution used to absorb it
is stripped to yield a concentrated hydrogen sulfide gas
from which elemental sulfur is produced.
Input and Output Streams
• Input Stream"
Coal
Steam, water
Air
Start-up solvent
Absorption solvent
• Output Streams
Solvent refined coal
Ash slag or ash
8
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Hydrocarbon gases
Water (process, storm drainage from coal
storage, and preparation)
Spent catalyst
Sulfur
Ammonia
Coal dust
Tar
Waste liquids, oil, and water
Slowdown and sludges from:
• Power plant
• Water treatment
• Cooling towers
(2) COSTEAM System*
The Bureau of Mines has developed a new
process, COSTEAM, that does not use hydrogen directly. In
this process coal reacts with carbon monoxide and steam
instead of hydrogen. It does not require a catalyst to
convert low rank coals, such as lignite, into a low sulfur
liquid fuel. There is usually enough water in lignite to
supply the needs of the process. The water or steam supplies
active hydrogen by reaction with the carbon monoxide.
Alkaline carbonates are naturally occurring catalytic agents
in lignite.
Lignite is pulverized and mixed with some of
the product oil. This slurry is fed to the reactor which
operates at a temperature of 380° to 400°C (720° to 790°F)
and a pressure of 210 to 280 kg/cm2 (203 to 271 atm.).
Synthesis gas or carbon monoxide is fed to the reactor at
high pressure. Synthesis gas or carbon monoxide reacts with
water contained in the lignite to produce hydrogen which
then reacts with lignite to form a liquefied coal product.
Product gas is separated from the product
liquid stream in a pressure reduction step. The liquid fuel
product stream contains unreacted solids and ash which are
removed by centrifugation. The unreacted solids residue can
be utilized to produce the synthesis gas required by the
process. The product fuel oil can also be further hydro-
genated to obtain gasoline.
Major Operations and/or Modules
• Sizing and Slurrying
• Hydrogenation
• Solids separation
• Synthesis gas manufacture
(Ref. Fig.5, App.A.)
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Input and Output Streams
• Input Streams
Coal
Water
Synthesis gas
• Output Streams
Fuel oil
Unreacted solids
Product gas
Residue
Coal dust
Tar
Waste liquids, oil, and water
Slowdown and sludges from:
• Power plants
• Water treatment
• Cooling tower
c. Pyrolysis and Hydrocarbonization
(1) Char-Oil-Energy Development (COED) System*
In the COED system, coal is heated in several
stages of fluidized beds at increasingly higher temperatures.
This enables the process to handle caking coals without the
preoxidation or recirculation of char usually necessary to
prevent agglomeration in the system. This feature permits
the achievement of high yields of oil with minimum sized
equipment. The foregoing are the major advantages of the
COED process. An additional advantage is that the process
operates at low pressure, less than 0.70 kg/cm2 (0.68 atm.)
which permits the use of conventional oil processing equip-
ment.
Major Operations and/or Modules
• Sizing and Drying. Coal is crushed and
dried simultaneously^This operation reduces the particle
size to about 1.6 mm (1/16 in.) and removes from 60 to 70
percent of the moisture in the coal. The remaining moisture
is evolved in the first stage of pyrolysis. The milling
operation takes place in a gas swept atmosphere under a
slight vacuum, at 70°C (160*F).
*(Ref. Fig.6, App.A.)
10
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• Pyrolysis. A mixture of combustion and
recycled gases fluidizes and heats the coal to about 175°C
(350°F) in the first pyrolysis stage. The coal is partially
devolatilized and the gases evolved are scrubbed with re-
cycled liquor and cooled.
The partially devolatilized coal from Stage
I (Fig.7, App.A.) is passed to Stage II. Stages II, III,
and IV (Fig.8, App.A.) are located on successively descending
levels and are coupled closely to minimize heat losses and
pressure drops. The cascaded arrangement permits gravity
flow of the char between the stages. Superheated steam and
oxygen are injected at the bottom of Stage IV. Stage IV
operates at 815°C (1500°F) and the hot gases pass counter-
currently through Stages III and II, providing the fluidizing
medium. Stages II and III operate at about 430°C (810°F)
and 540°C (1000°F) respectively.
All stages are equipped with internal parti-
culate separation systems to remove entrained solids from
the exit gases. Most of the volatile matter contained in
the coal is evolved in the second stage. The rest of the
volatile matter evolves in the third and fourth stages. The
pyrolysis gases and oil vapors from the second stage pass
through an external particulate separation system to remove
solids which would otherwise collect in and plug subsequent
processing steps. They are treated next in an absorption
system which removes the oil vapors, treated for removal of
hydrogen sulfide and carbon dioxide, and then used as
product gas.
Oil and water condensed from the pyrolysis
gas/vapor stream are separated into two oil fractions, one
heavier and one lighter than water, and an aqueous fraction.
The two oil fractions are dehydrated and sent to filtration.
The aqueous phase is cooled and recycled to the scrubbers.
Hot char is discharged from Stage IV to a fluidized bed
cooling step which generates high pressure steam. Recycled
gas from Stage 1 is used to fluidize the cooling char.
• Filtration. Oil from the product re-
covery system may contain some char particles which would
plug the catalyst bed in the hydrotreating operation. These
particles are removed by filtration. Hot filter cake con-
sisting of char, oil, and filter aid is discharged to char
storage. Filtered oil goes to the hydrotreating area.
• Hvdrotreating. The filtered oil con-
tains small amounts of sulfur, nitrogen, and oxygen as
impurities. To improve its properties the oil is treated
with hydrogen. This treatment also converts the impurities
into hydrogen sulfide, ammonia, and water which are then
separated from the product oil.
11
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Input and Output Streams
• Input Streams
Coal
Steam
Air
Oxygen
Catalyst
Absorption solvent
• Output Streams
Synthetic oil
Sulfur
Ammonia
Ash
Spent catalyst
Spent solvent
Low-Btu gas
Char
Filter cake
Pyrolysis gas
Wastewater
Tar
Waste oil
(2) Coalcon System*
The Coalcon system is based on hydrocar-
bonization of coal. When heated in a hydrogen atmosphere,
coal produces liquid, gaseous, and solid products. These
materials are separated and treated to produce the final
clean products. The solid material or char is then gasified
with oxygen to produce a portion of the hydrogen-rich gas
required for hydrocarbonization.
Major Operations and/or Modules
• Sizing and Drying. Coal is received,
unloaded, and stockpiled. It is then crushed and ground to
60 to 325 mesh. The coal is dried to about 1 percent
moisture.
• Hydrocarbonization. The prepared coal
is preheated and is injected into the reaction zone with
pressurized hydrogen. In the reaction zone the temperature
is 560°C (1040°F) and the pressure is 39 kg/cm2 (37.8 atm.).
Other variables that affect the yield of products are
residence time, partial pressure of hydrogen, and superficial
gas velocity. Solid particles carried out by the gas stream
are recovered and combined with the char.
* (Ref. Fig.9, App.A)
12
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• Product Recovery. The gas and vapors
are separated into gas, light oil, heavy oil, and wastewater
streams. A portion of the heavy oil is recycled to the
scrubbing step which removes any solids which may have
escaped with the gas. The recycled mixture is then frac-
tioned into a heavy fuel stream and overhead stream. The
heavy oil product is cooled and pumped to storage. Ammonia
generated in the process is recovered as a by-product. The
acid gas removal step absorbs C02, H2S, and aromatics from
the gas. The H2S is recovered as elemental sulfur.
• Hydrogen Generation. Gas from the acid-
gas removal step is processed by cryogenic separation into a
purified hydrogen stream, which will be recycled to the
hydrocarbonization reactor; a synthesis gas stream, which is
further processed to make substitute natural gas; and a
liquefied hydrocarbon stream.
Char from the hydrocarbonization step is
gasified with steam and oxygen to generate hydrogen.
Input and Output Streams
• Input Streams
Coal
Steam
Oxygen
Absorption solvent
Ammonia recovery solvent
Hydrogen
• Output Streams
Heavy fuel oil
Light fuel oil
Ammonia
Sulfur
Substitute natural gas
Liquefied hydrocarbon gas
Ash
Spent catalyst
Waste liquids, oil, and water
Aromatic chemicals
Slowdown and sludges from:
• Power plant
• Water treatment
• Cooling tower
13
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(3) Clean Coke System*
The United States Steel Engineers and Con-
sultants, Inc., a subsidiary of United States Steel Corpora-
tion, is developing a system to convert low grade, high
sulfur coal to clean metallurgical coke, chemical feedstocks,
and liquid and gaseous fuels. The system is known as the
Clean Coke Process and is sponsored by ERDA.
The process can be divided into carbonization
and hydrogenation sections. Required hydrogen is produced
within the process itself. The process design provides for
operating the plant as a closed system thus eliminating some
of the environmental problems.
Run of mine coal is dried, crushed, and
ground. Approximately half of the prepared coal is conveyed
to the carbonization section and the rest to the hydro-
genation section.
In the carbonization section, coal is pyro-
lyzed in a fluidized bed zone operating at temperatures of
705° to 760°C (1300° to 1400°F) and pressures of 7 to 10
kg/cm2 (6.8 to 9.7 atm.). The fluidizing medium is hydro-
gen-rich recycled gas. The products from the carbonization
section are char, a liquid stream which is directed to the
liquid processing section; and a hydrogen-rich gas which is
recycled to the reactor. The char is pelletized with pro-
cess derived heavy oil, and the pellets are heated in the
absence of oxygen to produce low sulfur metallurgical coke
and a hydrogen-rich gas. Part of the gas is recycled to the
carbonization step and the rest is sent to gas clean up.
In the hydrogenation section, prepared coal
is mixed with a process derived oil to form a coal/oil
slurry. The slurry is fed to a high pressure, noncatalytic
hydrogenation zone along with hydrogen from the gas cleanup
section. The hydrogenation section operates at pressures of
207 to 310 kg/cm2 (200 to 300 atm.). The slurry feed is
converted to a chemical rich liquid and a gas rich in light
paraffins. These products are separated from the uncon-
verted coal and mineral matter. Condensate from the vapor
goes to a processing section where light, medium, and heavy
oil are separated. Light oil is further processed to obtain
chemical feedstocks, which include gasoline, benzene, napthalene,
and residual tars. Medium oil is used for slurry prepara-
tion. Part of the heavy oil is used in the pelletizing
step, with the rest being fed to the carbonization section.
Uncondensed gases are sent to the gas treatment section for
*(Ref. Fig.10, App.A.)
14
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separation into chemical feedstocks, which include ethylene
and propylene, ammonia, sulfur, and fuel gas. Recovered
hydrogen is recycled to the hydrogenation section.
Major Operations and/or Modules
• Sizing and Drying
• Carbonization
• Hydrogenation
• Product separation
Input and Output Streams
• Input Streams
Coal
Water
Hydrogen
• Output Streams
Metallurgical coke
Chemical feedstocks
Ash and unreacted coal
Waste liquids, oil, and water
Tar acids
Tar bases
Oil
Organic chemicals
Gasoline
Sulfur
Fuel gas
Ammonia
Hydrogen
Slowdown and sludges from:
• Power plants
• Water treatment
• Cooling tower
(4) TOSCOAL System*
The Oil Shale Corporation (TOSCO), in coopera-
tion with other private industries, has developed a process
for retorting oil shale, known as the TOSCO II process.
This process has been adapted to use coal. Run of mine coal
received in the coal preparation and handling is unloaded,
crushed, and stored in piles. The coal is then ground,
*(Ref. Fig.11, App.A.)
15
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dried, and preheated. The coal is partially devolatilized
and fines carried over are removed from the vapors in a gas
solid separation system. The vapor is passed to a scrubbing
system and the preheated coal is sent to a pyrolysis reac-
tor. Here the coal is heated to carbonization temperatures
of 427° to 537°C (800° to 1000°F) by contact with hot
ceramic balls.
The char product leaves the pyrolysis zone
and is subsequently cooled and sent to storage. Cool,
ceramic balls are returned to a ball heating system. Pyro-
lysis vapor is cooled to condense oil and water and to
separate gaseous products. Oil and water are separated.
The oil is distilled to yield gas oil, naphtha, and re-
siduum. Uncondensed gas is used as fuel for heating the
balls.
Major Operations and/or Modules
• Sizing and Drying
• Pyrolysis
• Product separation
• Gas purification
Input and Output Streams
• Input Streams
Coal
Air
Water
• Output Streams
Char
Fuel oil
Fuel gas
Wastewater
Flue gas
Naphtha
Gas oil
Coal dust
Ash
HoS
C02
Slowdown and sludges from:
• Power plant
• Water treatment
• Cooling tower
16
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(5) ORC (Garrett) System*
The ORC Process is a solid phase hydrocar-
bonization process in which pulverized coal is almost com-
pletely converted to liquid and gaseous products in less
than one minute. At 141 kg/cm2 (136 atm.) and 500°C (930°F),
the yield is up to 30 percent distillable liquid, 40 percent
tar, and the balance gas. The reaction is faster if a
solution of ammonium molybdate is spread on the coal. Tests
using a 15 percent stannous chloride catalyst indicate
conversion in a few seconds to 55 percent liquid, 40 percent
gas, and 5 percent tar. Coal feed size is about 200 mesh.
The fast reaction time should permit savings in capital
costs for reactors.
ORC's coal pyrolysis system is being de-
veloped with the aim of maximum liquid yield. The process
involves very rapid heating and devolatilization of pul-
verized coal in the absence of air, a short residence time
in an entrained flow reactor, and a quick quench which
prevents degradation of the liquid and gaseous products.
Product distribution is strongly influenced by pyrolysis
temperature, with lower temperatures favoring liquid forma-
tion. The pyrolysis products can be further refined and
purified to obtain synthetic crude oil; char, which is
suitable for combustion in an electric utility boiler;
pipeline gas; and elemental sulfur.
Coal is first dried and pulverized as it
would be for a utility boiler. The coal is then conveyed
pneumatically with recycled product gas to the pyrolysis
reactor. The reactor is an entrained flow vessel where
recycled char is mixed with coal. Heated char provides the
energy input for pyrolysis. The coal is heated to its
decomposition temperature within one-tenth second at a
reactor temperature of about 595°C (1100°F). Volatile
products are separated from char by cyclones and are rapidly
quenched to avoid secondary decomposition. Part of the char
is transported to a char heater where the temperature of the
char is raised to about 650° to 870° (1200° to 1600°F) by
adding a controlled amount of air at the bottom of the
heater. The heater is also an entrained flow vessel and the
short residence time inhibits formation of carbon monoxide,
improving process thermal efficiency. Combustion gas from
the heater passes through cyclones where unreacted char is
separated and returned to the pyrolysis reactor.
*TRet. Fig.12, App.A.)
17
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The gases from the reactor are cooled and
scrubbed to collect product tar. A portion of the gas
stream is used to transport pulverized coal and heated char
to the pyrolysis reactor. The rest is treated to remove
acid gas and recover sulfur. The product gas can be up-
graded to produce pipeline quality gas or it can be used as
a hydrogen source for hydrotreating the tar product to a
synthetic crude oil or a low sulfur fuel oil. Hydrotreating
is carried out under pressure.
Remaining char, not passed to the char heater,
can be used as a solid boiler fuel. The char is already
dried and pulverized which offers an advantage over raw
coal. Boiler modifications will be necessary due to the
sulfur content of the char.
Major Operations and/or Modules
Sizing and Drying
Pyrolysis
Product separation
Hydrotreating
Gas processing and sulfur recovery
Input and Output Streams
• Input Streams
Coal
Air (
• Output Streams
Synthetic crude oil
Char
Sulfur
Pipeline gas
Flue gas
Tar
Tar acids
Waste liquids, oil, and water
Coal dust
Ammonia
Slowdown and sludges from:
• Power plant
• Water treatment
• Cooling tower
18
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d. Other Systems
(1) Fischer - Tropsch System*
In 1922, Franz Fischer engaged in studies of
the hydrogenation of carbon monoxide at low pressures with
iron or cobalt catalysts activated by oxides of chromium,
zinc, copper, and alkali metals. In 1925, at the Max Planck
Institute, Franz Fischer and Hans Tropsch synthesized liquid
hydrocarbons for the first time. Technical development of
this synthesis was continued at Ruhrchemie beginning in
1934. The purpose, to produce motor fuel, was realized with
an output of 675,000 metric tons per year in Germany from
nine plants. An equal number of plants were built in other
countries. Many of these plants were destroyed during World
War II. Changes in the energy market discouraged continued
synthesis of motor fuels from coal and the last German plant
at Bergkamen closed in 1962. Because of increasing coal
prices, new plants in Europe were not attractive. In
addition the plants are difficult to operate, requiring much
maintenance. However, in the Union of South Africa, the
situation was more conducive to coal based Fischer-Tropsch
Synthesis. A Fischer-Tropsch plant was constructed near
Johannesburg and began operation in 1955. A second plant is
now under construction in the Transvaal Region.
Major Operations and/or Modules
• Sizing. The coal is crushed, ground,
and wet screened. The minimum size feed that can be used is
about 6 mm. Fines, about 25 percent, are used for steam
generation.
• Gasification and Gas Purification. The
raw gaseous mixture formed by the reaction of coal with
steam and oxygen is cooled and oil and tar are separated.
The raw gas is further purified by scrubbing with methanol.
The Fischer-Tropsch catalyst is very sensitive to sulfur so
the gas must be treated to remove all sulfur. The hydrogen-
to-carbon monoxide ratio is adjusted by the CO Shift re-
action.
• Synthesis. Fresh synthesis gas combined
with recycled gas is fed to the reaction zone where it mixes
with catalyst. A mixture of gases, vapors, and liquids is
formed. These products must be separated from the catalyst
which must remain in the zone.
*(Ref. Fig.13, App.A.)
19
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• Product Separation. Gas and vapors
separate from the heaviest hydrocarbons in the reaction
zone. Cooling causes vapors to condense from the product
gas stream. These liquids are sent to the refinery for
separation. Part of the gas is used for recycle.
The product of the Fischer-Tropsch
system is not a synthetic crude oil. It is a mixture of
relatively simple hydrocarbons in a semi-refined state and
is completely free of sulfur and nitrogen compounds.
Input and Output Streams
• Input Streams
Coal
Steam
Oxygen
Catalyst
Methanol
• Output Streams
Fuel gas
Propane/propylene
Butane/butylene
Gasoline
Methylethyl ketone
Light furnace oil
Waxy oil
Methanol
Ethanol
Propanol
Butanol
Pentanol
Acetone
Naphtha
Waste acids
Benzene
Toluene
Diesel oil
Tar
Creosote
Ammonium sulfate
Sulfur
Spent catalyst
Wastewater
Waste oil
Waste liquids, oil, and water
20
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Slowdown and sludges from:
• Power generation
• Water treatment
• Cooling tower
• Gas reforming
Ash and ash conveying water
(2) Donor Solvent System*
The conversion of coal to liquid fuels by the
high pressure, Bergius process was used in Germany for 15
years or more. It operates in the pressure range of 225 to
600 kg/cm2 (218 to 581 atm.). Disadvantages of high pre-
ssure processes are the expense of high pressure vessels and
of hydrogen compression. Systems operating below 100
kg/cm2 (96.8 atm), however, generally use either direct
catalysis, or indirect catalysis, via a recycle solvent.
Exxon is developing an indirect catalyst method. In the
Exxon Donor Solvent (EDS) system, the donor solvent is
prepared in a separate, fixed bed, catalytic hydrogenation
step.
Prepared coal feed, hydrogen, and recycle
solvent are inputs to the liquefaction area. These materials
react to produce raw coal liquid, gases, and a heavy bottoms
stream containing unreacted coal and mineral matter. The
recycle solvent is separated from this mixture in the separa-
tion area. The solvent goes to the solvent hydrogenation
area where it is regenerated catalytically. Heavy bottoms
from the separation area are used to produce additional
hydrogen or fuel gas in the hydrogen manufacturing area.
Gas generated in the liquefaction area is used as fuel or
for hydrogen manufacture. The raw coal liquids may be
further hydrotreated depending on the end use. The donor
solvent is prepared from the middle fraction of the coal
liquefaction product which is treated by selective catalytic
hydrogenation. The main function of the solvent is to
provide hydrogen to free radicals formed by thermal "cracking1
of coal "molecules". The solvent also carries the coal into
the reactor, helps to dissolve the coal particles, and
improves operability as compared to unhydrogenated solvent.
The addition of hydrogen to the liquefaction step was found
to reduce solvent requirements.
*(Ref. Fig.14, App.A.)
21
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Major Operations and/or Modules
• Sizing and Drying. Coal, bituminous or
subbituminous, is dried, ground, and screened to minus 30
mesh. Prepared feed coal is supplied to the slurry pre-
paration system. The coal/solvent slurry is metered con-
tinuously to the hydrogenation1systems.
• Hydrogenation. The slurry feed stream
is preheated before it enters the reaction zone. Hydrogen
gas is also preheated and fed to the reaction zone, either
separately or mixed with the slurry feed. Conditions fo*
the liquefaction operation are: pressure 102 to 178 kg/cm^
(98.7 to 172.3 atm.) temperature 370° to 380°C (700° to
715°F) solvent-to-coal ratio of 1.2 to 2.6, and residence
time of 15 to 140 minutes.
• Separation. The material from the
liquefaction operation consists of gas, raw coal liquids,
and a heavy stream containing unreacted coal and mineral
matter. The pressure on this material is decreased in
several depressurizing steps. In the first step some gas
and water vapor are removed. This gas is sent to the
recycle gas cleanup operation for recovery of hydrogen and
re-use in liquefaction.
In the second depressurizing step more
gas is released, containing heavier hydrocarbons, suitable
for fuel gas. In the third step the remaining liquids and
solids are heated and flashed under vacuum. This releases
additional gas and vaporizes light oil containing some gas.
The bottoms material contains the solids residue; i.e.,
unreacted coal, mineral matter, and heavy tars.
• Solvent Hydrotreating. The light vacuum
gas oil, combined with other liquid hydrocarbon streams, is
catalytically hydrotreated. Gaseous and liquid products
from this reaction are separated. The liquid is a mixture
of liquefied coal product, a heavier fraction with a higher
boiling point, and a lighter fraction with a lower boiling
point. The solvent fractionation operation separates the
desired liquefied coal product from the higher and lower
boiling fractions of the hydrotreated liquid product. Some
of this mid-range solvent is recycled to the slurry pre-
paration area and the rest is sent to product storage.
22
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• Hydrogen Manufacture. The gas streams
from the first depressurizing step and the hydrotreating
area are scrubbed with monoethanolamine to remove hydrogen
sulfide and carbon dioxide. If the hydrogen content is not
high enough, high purity makeup hydrogen is added. This
stream is then compressed and sent to the hydrogenation and
solvent hydrotreating areas.
High purity hydrogen can be made from
fuel gas and solids residue from the separation section.
Input and Output Streams
• Input Streams
Coal
Cobalt-molybdate, catalysts
Monoethanolamine
Water
• Output Streams
Low sulfur fuel oil
Naphtha
Fuel gas
Sulfur
Residue
Ammonia
Coal dust
Tar
Spent catalyst
Spent MEA
Waste liquids, oil, and water
Slowdown and sludges from:
• Power plant
• Water treatment
• Cooling tower
(3) Methanol System*
Production of methanol from coal is a two-
stage process. In the first stage, coal is gasified to
produce raw synthesis gas. The raw synthesis gas contains
compounds other than H£ and CO and usually more CO than H2-
It must be treated to remove extraneous materials and the
ratio of H£:CO must be adjusted to 2:1. The clean synthesis
gas is then ready for methanol synthesis. The methanol
synthesis reaction is favored by high pressure, and synthesis
*(Ref. Fig.15, App.A.)
23
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gas from first generation gasification processes must be
compressed. Other disadvantages of some first generation
processes are the restriction to the use of noncaking coals,
and to particle sizes greater than 6 mm (1/4 in.).
The second generation gasification systems
produce better quality synthesis gas requiring less treat-
ment prior to methanol synthesis. They also operate at high
pressures eliminating the need for compression.
Raw coal from storage is crushed and dried to
a specific size and moisture content, depending on the type
of gasification system. The coal is then preheated, if
necessary, and conveyed to the gasification reactor. Steam
and oxygen are injected and the coal is converted to a
mixture of gases, liquids, and tars. The hot gases gen-
erated leave the reaction zone. A heat recovery system
generates high pressure steam and heats boiler feedwater.
Part of the steam is used in the process and the rest
provides energy for product gas compression. Particulates
carried out with the gas are removed by a separation system.
Gas from the Lurgi gasification system requires processing
to remove tars, heavy oils, and phenols. Gas from the
Koppers-Totzek and Winkler gasification systems must be
compressed before the ratio of hydrogen-to-carbon monoxide
is adjusted to 2-to-l by the CO shift reaction. The shifted
gas is treated in an acid gas removal system to remove C02
and H2§. C0£ is rejected to the atmosphere and t^S is
further treated to recover elemental sulfur.
The purified gas goes to the methanol synthesis
zone. The Lurgi process will require compression at this
step. Operating conditions for methanol synthesis vary from
53 to 315 kg/cm" (51 to 305 atm.) and 260° to 426°C (500° to
800°F), depending on catalyst and conversion per pass
desired. Higher temperatures and pressures increase the size
reactions and produce lighter materials, such as ethers, and
heavier alcohols in the crude methanol stream. The crude
methanol from the synthesis reaction is condensed and puri-
fied by distillation. Unconverted gas is returned to the
reaction zone. High, medium, and low pressure processes are
available for methanol synthesis.
Major Operations and/or Modules
• Sizing and Drying
• Synthesis gas generation
• Synthesis gas treatment
• Methanol synthesis and purification
24
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Input and Output Streams
• Input Streams
Coal
Water
Air
Oxygen
Catalyst
• Output Streams
Methanol
Ash
Coal sludge
Wastewater
Sulfur
Tars
Heavy Oils
Tar acids
Spent catalyst
Coal dust
Ammonia
Blowdown and sludge from:
• Power plant
• Water treatment
• Cooling tower
(4) Supercritical Gas Extraction System*
The solvent power of a gas or vapor increases
with density and, for a given gas at a given pressure, the
greatest density is obtained at its critical temperature.
With proper conditions the level of supercritical extraction
can be high, and increases of up to 10,000 fold in volatility
of slightly volatile substances have been experienced.
Therefore, if a gas or vapor is chosen having a critical
temperature slightly below the temperature at which the
extraction is to be carried out, it is possible to extract
substances of low volatility at temperatures well below
their normal boiling points. This principle has been applied
to extract liquids that are formed when coal is heated. The
extractant gas can be recovered by reducing the pressure of
the extracted liquid vapors and, thereby, separating them in
solid form.
*(Ref. Fig.16, App.A.)
25
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Some of the potential advantages of the
Supercritical Gas Extraction (SGE) system over more con-
ventional coal liquefaction systems are:
• No high pressure gas supply is required.
• The coal extracts contain more hydrogen
and are of lower molecular weight than
the products of other processes, and
this facilitates their conversion to
hydrocarbon oils and chemicals.
• The char or residue is a noncaking,
porous product having a significant
volatile material content making it
ideal for gasification.
• Products separate readily from the
extractant since only solid and vapor
phases are involved during extraction.
Filtration of a high viscosity fluid is
avoided.
The process does, however, produce more char
than conventional processes. Using toluene, extraction of
up to one-third of the coal feed has been effected. Re-
maining coal is recovered as a solid. This would require
that a commercial production plant would need either a
market for the char or facilities to convert it into gaseous
fuels. Catalytic, Inc. has developed a conceptual design
and prepared a study of the economics of a plant with coal
feed capacity of 10,000 ton/day.
Coal received from the mine is crushed,
dried, and pulverized to 200 mesh size. The pulverized coal
is fed to the extractor where it is mixed with recovered and
makeup toluene and heated to about 395°C (750°F) at 100
kg/cm2 (97 atm.) pressure. Overhead vapors consisting of
toluene, extract, water vapor, and hydrocarbon gases are
cooled to condense solvent and extract. Uncondensed hydro-
carbons are used as fuel gases. The condensed liquid pro-
duct is flashed to separate solvent toluene and water vapor
as overhead and extract liquid product as bottoms. Toluene
is separated from water and recycled to the extractor.
Water is treated in the wastewater treatment unit. The
residue in the reactor is removed mechanically, depressurized,
and steam stripped to recover entrained toluene. The char
can be used as fuel. The liquid extract product is frac-
tionated to remove any remaining entrained toluene. The
extract product, which is rich in hydrogen and has low
molecular weight, can be readily converted to hydrocarbon
oils and chemicals.
26
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Major Operations and/or Modules
The system includes the following major
operations:
• Sizing and Drying
• Supercritical extraction
• Solvent and extract recovery
• Auxiliary facilities
Input and Output Streams
• Input Streams
Coal
Toluene
• Output Streams
Extract product
Char
Fuel gases
Wastewater
Flue gases
Sulfur
Ammonia
Tar
Tar acids
Blowdown and sludges from:
• Power plant
• Water treatment
• Cooling tower
2. SCHEDULES
Most of the systems discussed in this document are
funded by ERDA. In some cases, ERDA is jointly funding the
effort either with other agencies or with private industry.
Several projects, however, are not currently recipients of
federal support. In these cases, projections as to future
program/project plans are not available.
Schedules for process development unit and pilot plant
operations are shown in Figure 1. Only processes which have
progressed to the process development stage have been in-
cluded in Figure 1.
27
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ro
CD
CATALYTIC LIQUID PHASE HYDROGENATION
Synthoil: Process Development Unit
H-Coal: Process Development Unit
Pilot Plant
Bergius: Process Development Unit
NCNGAIALYnC LIQUID PHASE HYDROGEHATION
Solvent Refined Coal: Pilot Plant, 6 TPD
Pilot Plant, 50 TPD
00-Steam: Process Development Unit
FYRDLYSIS AND
Coalcon: Demonstration Plant
Clean Coke: Process Development Unit
Occidental Res. Corp. : Process Dev. Unit
OTHER
Donor Solvent: Process Development Unit
Pilot Plant
1^78
, 1?79
, 1?80
Construction
——— Operation
Re-evaluation
Figure 1. Process Development Operation Schedule
-------
The two solvent refined coal pilot plants are the only
liquefaction plants in operation as of December 1977. An H-
Coal pilot plant, now tinder construction, will not be opera-
tional before the third quarter of 1978.
Brief discussions of the status of each process under
development follow:
a. Catalytic Liquid Phase Hydrogenation
(1) Synthoil System
The Synthoil process is currently in the
laboratory stage with construction of a process development
unit underway. Operation of the process development unit is
projected to begin in 1978 and continue into 1980. No firm
plans for a pilot plant have been announced.
(2) H-Coal System
Based on the data obtained from the bench-
scale and process development units, design and engineering
of a 544-Mg (600-ton) per day pilot plant were initiated
under the current ERDA contract in December 1973. The final
design of the pilot plant is complete and construction is
underway at Catlettsburg, Kentucky. Ashland Synthetic
Fuels, Inc., Ashland, Kentucky, and Hydrocarbon Research,
Inc., Morristown, New Jersey are the prime contractors.
Operation is scheduled for September 1, 1978 to June 1,
1980. The plant is to be dismantled and disposed of by the
end of 1980.
Ashland Synthetic Fuels will be responsible
for construction and operation of the pilot plant. HRI will
monitor the construction and operation of the plant to
ensure that data suitable for a commercial plant design is
obtained. A separate subcontractor will design the solids/
liquids separation system to be installed in the pilot
plant. Product characteristics will be determined and
operational problems identified.
(3) Bergius System
This is the ERDA "disposable catalyst" pro-
cess. Construction of a process development unit is in
progress and initial operation is planned for late 1977. No
pilot plant plans exist.
29
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b. Noncatalytic Liquid Phase Hvdrogenation
(1) Solvent Refined Coal System
Two pilot plants are operating. The plant at
Wilsonville, Alabama will operate through 1977. A decision
is to be made late in that year whether or not to continue
operation. Operation of the Fort Lewis, Washington facility
is planned to extend into 1981.
In addition, a demonstration plant is being
considered by the Kentucky Center for Energy Research but no
schedule is available.
(2) COSTEAM System
A process development unit was scheduled for
completion in 1976, operation beginning in 1977 and con-
tinuing into 1981 is planned.
c. Pyrolysis and Hydrocarbonization
(1) COED System
The COED project has been completed through
the pilot plant stage. Dismantling of the pilot plant has
been completed. No further work is projected for this
process.
(2) Coalcon System
Although originally planned for near-term
construction, ERDA is considering suspension of the project
due to marginal economics and technical problems with fluid-
bed carbonizers. Further work is proceeding to eliminate
scale-up problems involved in fluidized bed, and a decision
will be made late in 1977 as to the fate of this project.
(3) Clean Coke System
Operation of a process development unit
during 1977 is planned. There are no current plans for
pilot facilities.
30
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(4) TOSCOAL System
This process is not currently funded by ERDA.
A facility has been tested using coal in past studies but no
information on future plans is available.
(5) ORC (Garrett) System
Occidental Research Corporation (ORC) and the
Commonwealth of Kentucky are in a joint venture for the
purpose of preparing a detailed design for a 227-Mg (250-
ton) per day pilot plant. A municipal waste processing
plant of the same capacity is being constructed in San Diego
County, California. ERDA's schedule calls for continued
evaluation via PDU operation into Fiscal Year 1978.
d. Other System
(1) Fischer-Tropsch System
At this time, studies based on the Fischer-
Tropsch synthesis are of a fundamental research nature. No
concrete plans have been made yet for process development or
pilot studies in this country. A second large production
plant is to be constructed in the coal fields of the Eastern
Transvaal region in South Africa.
(2) Donor Solvent System
Operation of the Exxon Donor Solvent process
development unit is planned through 1977. Current scheduling
calls for pilot plant construction to begin late in 1978
followed by operation in 1980.
(3) Methanol System
ERDA studies of methanol are directed to its
use as a feedstock for catalytic conversion to gasoline.
Synthesis of methanol from synthesis gas is
being planned as a commercial venture.
(4) Supercritical Gas Extraction System
This process is at such an early stage of
development that no plans beyond conception have been
announced.
31
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3. STATUS
All stages of development including laboratory studies,
process laboratory, process development unit, pilot plant,
and demonstration plant scale projects are represented in
the current status of coal liquefaction technology.
a. Synthoil System
Development of the Synthoil system, initiated by
the U.S. Bureau of Mines, is currently being managed by ERDA
through the Pittsburgh Energy Research Center (PERC) at
Bruceton, Pennsylvania. The objective of this project is to
determine the technical and economic feasibility of the
process for scaleup to commercial use.
The Foster Wheeler Energy Corporation is respon-
sible for the design and management of the construction of a
9.1 megagram (10-ton) per day process development unit to
test the Synthoil process. However, recent communications
from the ERDA Synthoil process Project Manager indicate that
the process development unit may not be used for the Syn-
thoil process. PERC is conducting support research for the
design of the process development unit. PERC is also mon-
itoring laboratory research on various aspects of the Syn-
thoil process being conducted by ERDA's Sandia Laboratories
and by the Argonne National Laboratory. Research on the
Synthoil process is also being conducted by the Exxon
Research and Engineering Laboratories and by the Battelle
Memorial Institute Laboratories. These projects are being
monitored by the Morgantown Energy Research Center (MERC) in
West Virginia.
The initial work on the Synthoil process used a
reactor with an internal diameter of 8 mm (5/16 in.) in a
bench-scale plant that processed 2.3 kilograms (five pounds)
of slurry per hour. Experimental testing was conducted on
various coals, such as Pittsburgh seam, Indiana No. 5,
Middle Kittaning, Ohio No. 6 and Kentucky strip coal. All
of these types of coal were satisfactorily converted to low-
sulfur fuel oil with no appreciable attrition of catalyst or
loss of catalyst desulfurization activity. Other parameters
investigated were hydrogen flow rate, coal content of the
feed slurry, recycle rate of the product oil, hydrogen flow
rate, coal content of the feed slurry, recycle rate of the
product oil, and the effects of hydrogen sulfide in the
recycle gas.
To demonstrate the broad applicability of this
Synthoil process, a 227-kilogram (500-pounds) per day bench
scale unit was constructed. This unit used a 28-mm (1.1-
inch) internal diameter by 4.4-m (14.5-foot) long reactor
configuration made of stainless steel. Operations were
32
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conducted on several types of coal at reactor pressures of
142 to 284 parcels (140 to 280 atmospheres) and at tempera-
tures up to 450°C (840°F). High yields of low-sulfur and
low-ash fuel oil were obtained.
Operation at the lower pressure is desirable
provided an environmentally acceptable product can be made.
Synthoil produced from a West Virginia bituminous coal has
been analyzed, and the results were published by the Grand
Forks Energy Research Center. The Hittman Associates Inc.
laboratories are running analyses of: (1) the Synthoil pro-
duct; (2) residue removed from the product by centrifugation;
and (3) the stripping solution that had been used to remove
hydrogen sulfide, ammonia, and organic vapors from the
offgas vented from the process. These materials were
produced from a blend of four Kentucky bituminous coals.
b. H-Coal System
The H-Coal system is being developed by Hydro-
carbon Research, Inc. under the joint sponsorship of: (1)
ERDA; (2) a private industry consortium composed of Electric
Power Research Institute; Ashland Oil, Inc., Conoco Coal
Development Company; Mobil Oil Corporation and Standard Oil
Company, (Indiana); and (3) the Commonwealth of Kentucky.
The overall objectives of the project are to further develop
the H-Coal process and to demonstrate its technical and
economic feasibility on larger scales. Specific objectives
are to: (1) conduct laboratory research on all phases of the
H-Coal process using the existing bench-scale unit and
process development to establish design criteria; (2) design
a pilot plant capable of converting 545 megagrams (600 tons)
of coal per day to 318 cubic metres (2,000 barrels) per day
of low sulfur boiler fuel; (3) procure equipment and materials
for the pilot plant. Objective (1) is continuing. Object-
ive (2) has been realized and the ground was broken December
15, 1976 at Cattlettsburg, Kentucky. Determination of the
feasibility of commercial production of liquid hydrocarbons
from coal is the objective of this ninety-million dollar
pilot plant.
c. Solvent Refined Coal System
The system was originally developed by Spencer
Chemical Company for the United States Department of the
Interior, Office of Coal Research. Subsequently, Gulf Oil
acquired Spencer Chemical Company and development continues
to the present under the Pittsburgh and Midway Coal Mining
Company, part of Gulf Oil.
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In 1972 an all-industry group, presently con-
sisting of The Electric Power Research Institute and South-
ern Companies Services, initiated a pilot plant project to
study the technological feasibility of the SRC Process.
Early operations were performed at fixed conditions to
establish process reliability. Later operations were
conducted to study the effect of process variables such as
temperature, pressure, retention time, solvent-to-coal
ratio, and hydrogen consumption. Operating information from
this pilot plant has been used to design and build a 45.4
megagram (50-ton) per day pilot plant at Ft. Lewis near
Tacoma, Washington. This project, funded by ERDA, is being
developed by the Pittsburgh and Midway Coal Mining Company.
Operational data from the Ft. Lewis plant will
provide opportunities for:
• Further study and development of the process.
• Accumulation of engineering and cost data for
evaluation of commercial possibilities and
design of demonstration or commercial plants.
• Product evaluation and market development.
The Ft. Lewis pilot plant has been in operation
since October 1974. It has recently been operated to
produce about 2,750 mtons (3,000 tons) of SRC which was used
for functional product testing in a 22 Mw boiler.
The SRC process concept involves noncatalytic
hydroliquefaction. Modifications of the SRC process include
SRC-II and the Gulf Catalytic Coal Liquid Process. A
process demonstration unit (PDU) using SRC technology is
being operated by the University of North Dakota at Grand
Forks, North Dakota, under ERDA sponsorship. The unit is
designed to process one-half metric ton of lignite per day.
Recent modifications at the Ft. Lewis plant now permit
operation in the SRC-II mode.
In March 1972, the Edison Electric Institute and
the Southern Company Services, Inc. began a joint project to
study the key steps in the SRC process. Consequently,
Catalytic, Inc. designed, built, and is operating the six-
ton per day pilot plant. The facility was completed in
August 1973. The Electric Power Research Institute (EPRI)
assumed the responsibilities of the Edison Electric In-
stitute for utility industry sponsorship in April 1973.
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The pilot plant began operation in January 1974,
and by the end of 1975, had been in operation for more than
7,800 hours, including periods of 45 and 75 days of sus-
tained operation; one subbituminous and four bituminous
coals have been tested. SRC products meeting plant specifica-
tions of 0.16 percent maximum ash and 0.96 percent maximum
sulfur have been produced from each coal.
In January 1976, ERDA joined EPRI as a co-sponsor
of the pilot plant operation. To simulate operation at the
Ft. Lewis SRC pilot plant, a mixture of coals from the
Kentucky Nos. 9 and 14 seams were used for plant operation.
Coal feed rates as high as 75 pounds of coal per hour per
cubic foot of dissolver volume, almost three times the
design feed rate, were achieved. Material balance data for
ten runs were obtained, allowing correlation of the results
from both the Wilsonville and Ft. Lewis pilot plants.
Empirical models to aid in scaling up to larger plants were
developed for predicting conversion, sulfur removal, and
filtration rates for operation with Kentucky Nos. 9 and 14
coals. Conversion efficiencies on an MAF basis as high as
95 percent have been achieved.
d. Donor Solvent System
Research was begun in 1966 to identify the basic
Exxon Donor Solvent (EDS) system. It included studies on
both hydrogenated and unhydrogenated recycle solvents. Con-
ditions ranged from 400° to 425°C (750° to 800°F) at pre-
ssures of 2.0 to 2.5 MPa (290 to 365 psi), to 425° to 480°C
(800° to 900°F) at 10 to 20 MPa (1,450 to 2,900 psi). A
number of different solid/liquid separation methods were
studied. Equipment was tested in an integrated pilot plant
system of 454 kilograms (one-half ton) per day capacity.
Techniques were developed for analyzing product and inter-
mediate streams. Based on these studies the separation
operation chosen was vacuum distillation, and a hydrogenated
recycle solvent operation was selected for further develop-
ment.
Studies of process variables are continuing in a
907 kilogram (one ton) per day pilot plant. It is designed
to permit use of different coal feeds and to provide a
variety of products.
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Evaluation of several process alternatives have
begun, including development of a computerized process
alternative model to be used as a basic tool for the process
engineering and economic studies which are planned. Engin-
eering studies have been initiated to identify and develop
equipment and engineering data needed for a safe, operable,
and reliable EDS commercial plant.
The following news release was made July 28, 1977:
"The Energy Research and Development Admin-
istration (ERDA) and Exxon Research and Engin-
eering Company (ER&E), of Florham Park, New Jersey
have signed an agreement totaling $240 million to
develop a process for producing liquids from coal.
The cooperative agreement calls for ERDA to
fund 50 percent of the program, with the remaining
$120 million provided by the private sector,
according to Dr. Philip C. White, ERDA's Assistant
Administrator for Fossil Energy.
The Carter Oil Company, an Exxon affiliate;
the Electric Power Research Institute (EPRI); and
the Philips Petroleum Company have agreed to
support the private sector's share of the funding.
ER&E is negotiating separate agreements for the
participation of EPRI and Philips. It is anti-
cipated that other private sector firms will
participate in the program.
The project is based on Exxon's donor solvent
coal liquefaction process, a result of independent
research since 1966. The program will involve
both small-scale R&D work, and the design, con-
struction and operation of a pilot plant with a
capacity of 250 tons per day. The pilot plant
will be built adjacent to an Exxon refinery at
Baytown, Texas. ER&E's principal coal research
laboratory is located nearby. Additional lab-
oratory and engineering will be conducted at ER&E
and affiliated facilities at Linden and Florham
Park in New Jersey and Baton Rouge, Louisiana.
Through 1975, ER&E had spent about $32 million
to formulate and develop the donor solvent process.
The research, primarily at Baytown; and engineering,
primarily at Florham Park, resulted in the basic
process design and cost estimate for the 250 tons
per day pilot plant. Additional R&D, intended
primarily to confirm certain aspects of the basic
design, has continued under a $12.7 million con-
tract funded by ERDA, EXXON, and EPRI.
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The new agreement runs through December 31,
1982. The project is designed to bring donor
solvent coal liquefaction technology to a stage
where commercial plants could be designed and
built by private industry. Many of its features
are based on technology already proven in the
petroleum refining industry.
In the process, coal is liquefied in a non-
catalytic reactor at moderate temperature and
pressure. The hydrogen required for a reaction is
supplied in both gaseous form and by transfer from
a donor solvent. The donor solvent is an inter-
nally generated coal liquid stream which is hydro-
genated in a separate catalytic reactor before
being mixed with the coal feed.
The process produces liquids suitable for
motor gasoline blending stocks, low-sulfur oil,
and utility fuel. Liquid yields range from 2.5 to
3 barrels per ton of coal. The system produces
both the hydrogen and fuel needed to sustain the
process."
e. Clean Coke System
The Clean Coke system is being developed by USS
Engineers and Consultants, Inc., a subsidiary of United
States Steel Corporation, under the sponsorship of EKDA.
The work was initiated in 1972 under the auspices of the
Office of Coal Research (OCR, now a part of ERDA). The
objective of the project is to design a pilot plant that is
capable of converting low-grade, high-sulfur coal to low-
sulfur, low-ash metallurgical coke, chemical feedstocks, and
liquid and gaseous fuels.
The Clean Coke process combines coal carbonization
and hydrogenation to produce solid, liquid, and gaseous fuel
streams. Char produced by carbonization is converted to
coke which eliminates the problem of char use and disposal.
No mechanical separation equipment is used to separate the
solids from the liquid product. Hydrogenation is noncatalytic
and no external hydrogen is required. However, the hydro-
genator operates at a very high pressure.
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Laboratory and bench-scale development studies on
Illinois No. 6 Seam Coal have been underway since 1969.
Various aspects, including coal preparation, carboniza-
tion/ desulfurization of coal in fluidized beds, and high
pressure hydrogenation reactions have been the subjects of
these investigations. Process development units have been
built and are now operating. Two additional types of coal
are scheduled to be processed. Information obtained from
the process development units will be used for the design of
a 218 megagrams (240 ton) per day pilot plant.
f. Bergius System
The Bergius system was one of the forerunners in
coal liquefaction technology. It was used by Germany to
produce aviation fuel and diesel oil during World War II.
There were 18 Bergius plants producing about 4.77 Mm3 (30
million barrels) of oil per year. The process uses cataly-
tic liquid phase hydrogenation to produce liquid fuels. The
major problem involved was the operation of high pressure
solids/liquids separation equipment. The conversion effi-
ciency was low due to the unavailability of better catalysts
in the past. External hydrogen was required. Though there
are no commercial Bergius plants operating currently, they
have led to the recent developments in the United States of
the H-Coal and Synthoil processes.
g. Char-Oil-Energy Development (COED) System
The COED system converts coal to low sulfur
synthetic crude oil, clean fuel gas, and char. The oil
product can be used directly as fuel oil or as a feedstock
for oil refining.
Project COED was initiated in 1962 when the FMC
Corporation, under sponsorship of the Office of Coal Re-
search, Department of the Interior, started research work to
upgrade coal to more valuable products. Following bench-
scale studies, operation of a 45-kg/hr (100-lb/hr) process
development unit was undertaken during 1965 to 1967. Western
and midwestern coals were processed in a multi-stage, fluidized
bed, pyrolysis system.
A small, bench-scale hydrotreating study was
performed by the Atlantic Richfield Company and economic
evaluations for a conceptual commercial design were made.
Promising results from these preliminary studies led to the
design, construction, and operation of a 32.7-Mg (36 ton)
per day pilot plant at the FMC Corporation's Research and
Development Center in Princeton, New Jersey. The plant was
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completed in August 1970, and the first successful 30 day
run was made in December 1970. The pilot plant completed a
number of long-term runs with good operating reliability.
The plant processed about 18,144-Mg (20,000 tons) of a wide
variety of American coals, including the highly caking
types. Sufficient engineering data were obtained for the
design of a commercial plant. All project objectives were
completed, and the pilot plant was shut down in April 1975.
It has since been dismantled.
The Seacoke system is a similar process, using a
five-stage, fluidized bed, pryolysis process. The Seacoke
products are syncrude, char, and fuel gas. The Seacoke
system operates at atmospheric pressure and in the tempera-
ture range of 315° to 870°C (600° to 1600°F).
h. COSTEAM System
In 1921, F. Fischer and H. Schrader reported the
use of carbon monoxide as a reducing agent in the solubili-
zing of coal. Interest in this discovery was lacking at
that time because of low yields of heavy products and a
greater interest in motor fuels. Since the late 1960s the
work has been extended, modified, and improved. The process
now has good commercial potential. This later work in-
dicated the importance of using a solvent with a coal which
has not been subjected to aging, drying, or oxidation.
Carbon monoxide, water, and coal at 380° to 400°C (715° to
750°F) yielded a benzene soluble solid or semi-solid pro-
duct. More recently work has been conducted to substitute
synthesis gas for carbon monoxide and to make a product with
sufficient fluidity for use as a coal slurry vehicle.
i. Coalcon System
Union Carbide has been involved in coal conversion
studies since 1936. The extent of this work includes opera-
tion of several pilot plants and a fully integrated 454-Mg
(500-ton) per day processing facility, which used a liquid
phase catalytic hydrogenation process. The plant operated
over a period of about six years in the mid 1950's. At the
same time extensive research was carried out to convert coal
to chemical products by pyrolysis of coal in the presence of
hydrogen. The process, termed hydrocarbonization, was
evaluated in a 18.4-Mg (20 ton) per day pilot plant oper-
ation. A 4536-Mg (5000 ton) per day conceptual design was
made in the mid 1960's, but the economics did not favor
chemical production via coal conversion and interest in the
program waned.
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In the early 1970's, problems with petroleum
supply caused Union Carbide to re-evaluate its coal conver-
sion experience. It was concluded that the hydrocarboniza-
tion route to convert coal to liquid fuels had potential
application and a joint venture known as Coalcon was formed
with Chemical Construction Corporation.
In January 1975, the Department of the Interior
through its Office of Coal Research chose Coalcon to build
and operate the Clean Boiler Fuels Demonstration Plant. The
preliminary design phase is near completion. However, ERDA
has reported that the economics are marginal and technical
problems with the fluid bed carbonizer are greater than
first believed. Latest reports indicate that only the
design phase will be completed at this time and that addi-
tional research and development is required on the process.
j. TOSCOAL System
The Oil Shale Corporation (TOSCO), in cooperation
with other private industries, has developed a process for
retorting oil shale, known as the TOSCO II process. A semi-
works facility was constructed at Grand Valley, Colorado to
test the feasibility of the process. The capacity of this
plant is 907 mton (1000 tons; per day.
The technology of oil shale retorting has been
applied to the low temperature carbonization of coal. A
pilot plant for processing 22.5 mton (25 tons) per day of
subbituminous coal has been operating at the Rocky Flats
Research Center near Golden, Colorado.
Subbituminous coal has been processed yielding a
low sulfur char product of half the weight of coal with
higher heating value than coal and low sulfur liquid fuel.
Hydrogen generation is not required and the process uses the
generated flue gases for preheating the dry coal. Hauling
and transferring of hot, ceramic balls, which provide heat
for pyrolysis, cause a major problem.
k. Occidental Research Corporation (Garrett) System
Garrett Research and Development (now the Occiden-
tal Research Corporation), (ORC), initiated a coal research
program in 1969 to explore the feasibility of converting
coal to liquid fuels. Garrett is a wholly-owned subsidiary
of the Occidental Petroleum Corporation. Because of its
involvement in the petroleum industry, and the fact that
conversion of coal to liquid fuel then appeared more economi-
cal than its conversion to gas, emphasis was placed on a
40
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study of coal liquefaction processes. Coal pyrolysis was
selected from the alternatives because pyrolysis offered the
simplicity and relatively low cost needed for rapid commer-
cialization.
The initial laboratory scale results were quite
encouraging and, in 1971, a 3.6-Mg (4 ton) per day facility
was constructed at LaVerne, California. Although it was
built for the study of coal pyrolysis, during the first two
years, it processed solid waste materials only.
During this period, a variety of solid waste feed-
stocks were converted to liquid fuel oil. The pilot facili-
ty began processing coal in 1974. The operation has been
relatively free of problems largely due to operating exper-
tise developed during the solid waste program. Caking and
non-caking coals have been successfully tested. Based on
these results, a 227-Mg (250 ton) per day municipal waste
processing plant is being constructed in San Diego County.
The Occidental Research Corporation will evaluate
the commercial potential of its flash pyrolysis coal lique-
faction process under the sponsorship of ERDA.
The main objectives of the program are to:
• Demonstrate that caking coals can be pro-
cessed continuously in a specially designed
single-stage pyrolysis reactor without oxi-
dative pretreatment, and that this method
will result in a significantly higher yield
of liquids than other proposed pyrolysis
processes.
• Conduct extended runs in the three-ton-per-
day process development unit (PDU) in order
to obtain steady state heat and material
balances.
• Produce and recover large quantities of the
primary tar, and to evaluate methods for up-
grading this material to a clean fuel or
synthetic crude oil.
• Continue development of specific areas of the
pyrolysis and liquids collection systems to
ensure a technologically sound basis for
future scale-up.
• Obtain sufficient process and environmental
data for detailed design of a larger plant
and conduct an assessment of the potential
commercial viability of the process.
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ORC and the Commonwealth of Kentucky have a cost-
sharing joint venture aimed at providing a detailed design
for a 250-tons-per-day pilot plant using the process.
Research and development on solid phase hydro-
carbonization under an ERDA contract is underway by Rock-
etydne Division of Rockwell International at Canoga Park,
California.
1. Fischer-Tropsch System
Interest in the synthesis of liquid hydrocarbons
goes back to 1913 when patent applications described the
reaction of hydrogen with carbon monoxide at high temp-
erature and pressure and the hydrogenation of coal under
pressure. In 1927, the hydrogenation of coal was undertaken
on an industrial scale by I.G. Farben. This resulted from
the development of catalysts with adequate activity and
sulfur resistance.
A Fischer-Tropsch plant was constructed near
Johannesburg and began operation in 1955. A second plant is
now under construction in the Transvaal Region. It will
have a consumption of 12.9 teragram (14 million tons) of
coal per year.
m. Methanol System
Methanol was first produced commercially from
wood. Natural gas, reformed to synthesis gas, is currently
preferred for methanol production in countries where it is
available as a cheap feedstock. Prior to the advent of
natural gas, solid fuels had been the major source for
synthesis gas for methanol production. In Europe, Asia, and
South Africa where natural gas was not available, coal
became the primary source for synthesis gas. In countries
where economics still favor this route, methanol is produced
from coal.
In the United States, natural gas is no longer
readily available and alternate sources for synthesis gas
are being evaluated. Abundant coal reserves present in the
United States may play an important role in synthesis gas
production. Technology for methanol production is available
and can be updated to suit the United States' needs.
Some of the first generation processes that have
been used to convert coal to synthesis gas are Koppers-
Totzek, Lurgi, and Winkler. The three processes employ dif-
ferent features and operating conditions, and each produces
a gaseous product of different composition. A number of
second generation processes are under development.
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n. Supercritical Gas Extraction System
Two major problems facing advancement of coal
liquefaction to commercialization are operability of solid-
liquid separation equipment and high hydrogen consumption.
The Supercritical Gas Extraction system (SGE), now under
development by National Coal Board in England seems to have
solved these problems. Catalytic, Inc., a subsidiary of Air
Products and Chemicals, Inc. is evaluating the technical
feasibility of this process for United States coals.
4. PRIORITIES FOR FURTHER STUDIES
Initially, the types and classes of pollutants probably
present in waste streams were determined. This was based on
available documentation on liquefaction emissions and con-
sideration of discharges from related industries such as
coal-fired power plants and petroleum refineries.
Next, the pollution controls were evaluated to deter-
mine their capabilities and limitations. Among factors
considered were:
• The types of pollutants controlled by the specific
technology.
• Physical properties of the pollutants that might
affect selection of controls.
• Chemical properties of the pollutants that might
affect selection of controls.
• Efficiency of controls.
• Contaminants in the waste stream that could limit
or prevent use of a specific type of control.
• The local environment including climate, water
availability, soil characteristics, etc.
When possible, controls were matched with anticipated
effluents. Specific factors needed to determine which
technology was best suited were noted. These are indicated
by an asterisk in the margin.
The following discussion on air, water, and solid waste
controls was based upon this procedure.
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a. Air Pollution Control
It is well recognized that no uniform gas cleaning
method exists that will satisfy all problems and conditions.
In the selection of control systems, both physical and
chemical properties must be considered. The degree of
efficiency of different control options also must be a basis
for selection.
For example, in particulate control, coarse dust
particles are separated by dry inertial separators; whereas,
fine dusts, etc. require the use of fabric filters, scrubbers
or electrostatic precipitators. To meet a specific level of
emission, highly efficient removal systems such as pre-
cipitators are required for controlling streams with large
amounts of fine particulate. Cyclones might be applicable
for removal of less concentrated, coarse particles. Part-
iculate properties basic to the performance and selection of
gas cleaning equipment are particle size distribution,
structure, density, composition, electrical conductivity,
and agglomeration properties. Also needed to be taken into
consideration are gas properties such as temperature, mois-
ture content, total gas flow, and chemical composition. For
example, particulate removal efficiency for precipitators
increases with increasing sulfur content greater than two
percent in the waste stream. Fine particulates will pro-
bably need a better control than now exists.
Where flares are used to control hydrocarbon
emissions, a major problem is the availability of sufficient
combustible waste gases to maintain combustion. The pres-
ence of trace metals in the gas stream needs to be invest-
igated as well.
Sulfur recovery operation selection is limited by
the composition of the acid gas feed stream. When the
Stretford process is used, most mercaptans, carbonyl sulfides,
and carbon dioxide pass through the absorber into the exit
gas. Glaus plant efficiency, on the other hand, requires a
minimum concentration of approximately ten to fifteen volume
percent of H2S. High levels of C0£ water vapor and hydro-
carbons in the acid gas feed also reduce the efficiency.
Availability of water also can determine which
control should be selected. In water-short regions, dry
methods of controlling emissions should be considered.
Detailed analyses of waste stream composition and
concentration combined with aforementioned properties of air
pollution controls are needed to provide adequate data to
select the proper control system to limit environmental
impact.
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b. Water Pollution Control
All process wastewater streams have different
characteristics. The characteristics vary from one stream
to another. For some, variations may be small, but for
others a marked difference may exist. The selection of best
control technology for these wastewater streams will depend
on the level of information that exists for each individual
stream.
The species of interest for an environmental
assessment for wastewater can be divided into classes such
as dissolved gases, organics, trace elements, phenols, and
sulfur and nitrogen compounds. Gross characteristics such
as BOD, COD, TOC, suspended solids, pH, and oil and grease
of each wastewater stream are also essential.
The characteristics of wastewater streams can be
used to determine the type of control technology required.
It may be possible that two or more wastewater streams can
be treated by a common treatment method. The variation in
characteristics of wastewater streams and capability of
control systems to handle such variations can be evaluated
by change in the feedstock and operating variables. The
concentration levels of recoverable compounds such as
ammonia and phenols will determine the feasibility of
recovery. Combination physical/chemical methods may serve
to remove some materials such as phenols. The performance
of biox systems in the presence of toxic metals is not fully
known and requires evaluation.
The complete wastewater control system will be a
combination of physical, chemical, and biological treatment
processes. The combination sequence of the individual
treatment processes will affect the degree of contaminant
removal. Table 1 shows the important characteristics of
wastewaters that could influence the choice of wastewater
treatment and control systems.
c. Solid Waste Control
The term, bulk solid waste, includes various
materials. Ash consists of a variety of metallic oxides and
trace element compounds. Coal and char particles contain
organic and mineral materials. Elemental sulfur may be
generated as solid waste from hydrogen sulfide control
technologies. Limestone sludges, primarily calcium sulfite,
and calcium sulfate may be alternately generated. Zinc
sulfide, the primary constituent of spent sulfur guard
reactor absorbents, also may be present as will spent cata-
lysts from applicable processes. Wastewater treatment
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TABLE 1. CONTROL SYSTEMS ASESSMENT REQUIREMENTS
Control Method
Equalization
Neutralization
Temperature Adjustment
Nutrient Additions
Sedimentation
Dissolved air-flotation
Activated Sludge
Aerated Lagoon
Oxidation Pond
Trickling Filter
Chemical Mixing Floccula-
tion and Clarification
Dissolved Air-flotation
with Chemicals
Activated Carbon Absorp-
tion
Stripping
Important Characteristics
Flow variability
Extreme pH values
Extreme pH values
Nutrient deficiency
Settleable suspended solids
Oils, tars, suspended solids,
and other floatable matter
Organic content
Organic content
Organic content
Organic content
Dissolved solids, colloids,
metals or precipitable or-
ganics, and emulsified oils
Oils, colloids, tar, and
chemically coalesced mater-
ials
Trace amounts of organics
and color, taste, and odor-
producing compounds
Dissolved gases, variable
organics, and materials that
can be chemically converted
to gases
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sludges, a mixture of coal tar residues, sand, coal fines,
and treatment by-products may also contain untreated quanti-
ties of phenols, ammonia, cyanides, and other potentially
dangerous materials.
Wastewater treatment will generate sludges requir-
ing proper disposal. Sludge characteristics depend on the
type of wastewater and the treatment method applied. It is
important to identify hazardous materials that may be leached
by groundwater. The volume and type of sludge will determine
the disposal method that can be used. Sludge with high
water content requires pretreatment. The presence of toxic
materials must be assessed and positive indications will
make it necessary to find control means for preventing their
entry into the environment.
The discussion of solid waste component materials
has been a general one, necessitated by the limited existing
knowledge. Chemical analysis must be utilized to identify
the specific composition of solid waste materials and to
determine the concentration of these materials. The en-
vironmental impacts of these materials will need to be
determined. All leachable materials present in concentra-
tions exceeding environmentally acceptable standards must be
identified.
The problems associated with disposal of solid
waste must be resolved to the desired goal to minimize
environmental degradation. Landfilling and minefilling
techniques will require additional sophistication to con-
fidently prevent contamination of the surrounding area.
Undesirable ash constituents can re-enter the environment as
a result of groundwater leaching. Little is known of the
fate of landfilled trace elements, spent catalysts, or spent
absorbents. Upon identification of hazardous, leachable
materials present in solid waste, leaching studies will be
needed to determine the available alternatives to minimize
detrimental effects upon the environment. Impervious liners
may be used as a physical means of preventing groundwater
percolation which, in turn, prevents leaching. Chemical
stabilization, to render leachable constituents insoluble or
inert, may be necessary control methods in some instances.
A combination of physical and chemical control methods may
be the required technique.
Subsidence, the gradual settling of landfill
materials, is another problem. In some cases, compaction of
wastes reduces subsidence effects, allows more waste dis-
posal per unit volume of storage space, and reduces permeability
of landfilled wastes. This, in turn, reduces leaching
problems, and is currently under consideration as a means of
improving solid waste disposal techniques. More information
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is needed regarding the subsidence and compaction properties
of the bulk solid wastes generated by liquefaction pro-
cesses.
Although no secondary wastes are anticipated after
landfilling, light hydrocarbon gases may be generated due to
reaction of organic materials present. Furthermore, com-
bustible materials may generate gases as well as cause
underground fires. Unsuspected or undetected materials may
undergo groundwater leaching. Periodic sampling and analy-
sis of landfill materials and surroundings will be required
to determine if secondary wastes are generated and, if
necessary, to develop control technology modifications which
will prevent the generation of such wastes.
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B. CURRENT ENVIRONMENTAL BACKGROUND
Based on the available literature with respect to
potential pollutants resulting from coal liquefaction
systems and conjunctive developments, Hittman Associates has
attempted to identify the classes of major organic and
inorganic substances (including organometallies) emanating
from gaseous, aqueous, and solid waste emissions and efflu-
ents. Division of the pollutants into the organic and
inorganic (or organometallic) groups is reasonable because
these two groups differ in their chemical and physical
properties. These properties, in turn, influence the en-
vironmental effects of the various pollutants. The physical
and chemical properties of the organics have been discussed
in terms of their classes.
Two major classes of organic compounds associated with
coal liquefaction systems have been identified: the aliphatic
and the aromatic. Among the aliphatics, there are light-
chained compounds (e.g., methane through dodecane) and all
stereoisomers plus the alkenes and alkynes of the above, and
the heavy-chained aliphatics. Of the aliphatic class of
compounds, n-dodecane is reported to be a carcinogen.
Among the aromatic compounds are the one- and two-ring
compounds: benzene (implicated in leucogenesis and Hodgkins
disease); napthalenes (implicated as co-carcinogens);
benzidine, and the aromatic amines known or suspected as
carcinogenic; another large group of polynuclear aromatic
compounds (e.g., dibenzo(a,i)pyrene, chrysene, and benzo (e)
pyrene) all of which are reported as carcinogenic, and
finally, the polynuclear aza-heterocyclics such as benz (c)
acridine, and dibenzo(a,i)acridine, also known to be car-
cinogenic. Certain of the polynuclear aromatics are known
to be noncarcinogenic.
While a concerted effort has been made to identify
potential pollutants by classes and by discrete compounds,
and further to quantify these on a multimedia basis, the
reader should recognize that these data cannot be used to
indicate specific impacts on plants, animals, and man at
specific sites.
Information on the identity, distribution, and level of
occurrence of potential pollutants throughout the entire
fuel cycle and for all media is essential for the future
development of guidelines, criteria, and regulatory require-
ments at the federal, state, and local levels. Ideally, it
would be most advantageous, in this context, to establish
the levels of the most toxic pollutants that would be
expected after use of the best treatment technologies.
Desirable as this may be, the current information generally
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does not permit such an effort. For example, the polycyclic
aromatic hydrocarbons, although composing the smallest
amount of the organic load in wastewaters, are expected to
have a wide range of removal efficiencies. For organics, in
general, there appears to be an inverse relationship between
removal efficiency and the molecular weight of the compound -
the greater the number of rings, the more difficult the
removal. Similarly, both microbial degradation and adsor-
ptive sedimentation processes are highly dependent upon
molecular size. Thus, microbial degradation proceeds far
more slowly for the high molecular weight organic compounds,
while adsorption becomes important only above the 2-ring
compounds. In the multi-ring compounds, the substitution of
N or S heteroatoms acts to retard microbial oxidation. Ap-
parently, nonaromatic amines and thiophenes may be removed
from wastewaters as much by volatilization during aeration
as by microbial degradation. Thus, significant amounts of
multi-ring aromatic compounds may pass undegraded through
wastewater treatment practices known to be very efficient in
removing phenols.
1. POTENTIAL POLLUTANTS AND IMPACTS IN ALL MEDIA
An effort was made to generalize on the known con-
centrations of about seven inorganic and twenty-two trace
and heavy metal elements expected in nine major environ-
mental compartments, (soil, rock, freshwater, seawater, air,
plants, marine, terrestrial, and animals), as an aid in
estimating whether the increased inputs of these elements
when released in the ash, etc. from coal liquefaction, would
significantly increase the level in the environment. Essen-
tially, the same thing was done for nine major organic
compounds, except that the following compartments were used:
industrial and municipal effluents, natural waters, drinking
water supplies, and finished drinking waters.
Estimates were made of the quantities and process dis-
charges expected as emissions to air (organics and inorganics),
as aqueous effluents (phenols, tars, benzene, etc.), as
waste solids and residues (land destined wastes, sludges,
etc.) and as the products of the liquefaction process,
including organics and inorganics.
One of the more significant aspects of the ongoing en-
vironmental assessment effort by Hittman Associates has
involved the critical analysis of natural, physical-chemical
processes that effectively dissipate or enhance the toxic
effects of known biological stressors in aqueous and solid
waste effluents. For example, benzene, toluene, and naptha-
lene may be volatilized into the atmosphere; whereupon they
may enter the hydrosphere by various means such as washout
50
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in rain, dry deposition, or by direct diffusion into water
surfaces. Such atmospheric removal is considered as con-
tributing significantly to organic loadings in the hydro-
sphere. Other studies suggest that napthalene concentrates
in sediment and is not readily desorbed back in the water
column; further work is needed to confirm this finding.
Other considerations relate to the fact that sediment ad-
sorption is more pronounced for larger multi-ring compounds
and that volatilization is most important as a removal
(i.e., environmental dissipation) mechanism for the nonpolar
molecules having one and two rings. Other studies suggest
that polycyclic compounds may possess turnover times of
months or years in soils and bottom sediments.
In the consideration of the biological cycling (bio-
concentration, excretion, metabolism, and biodegradation) of
pollutants resulting from coal liquefaction processes, an
effort was made to assess the possible environmental fate
and effects of about twelve organic compounds on microor-
ganisms, plants, aquatic invertebrates, aquatic vertebrates,
and mammals. On the basis of preliminary data, the biocon-
centration factor of polynuclear aromatic hydrocarbons is
reported to increase by an order of magnitude for each 50-
to 60-unit molecular weight increase. Further work is
required to confirm this.
The assessment of the potential impacts of coal lique-
faction processes was made in terms of potential for water
pollution of a facility consuming about 22,680 megagrams
(25,000) tons of coal and 45,360 megagrams (50,000) tons of
water each day; this would include acid drainage from coal
storage piles, extensive soil erosion, and sedimentation
resulting from surface mining and construction of the
facility, noise, exposure of area residents to new occu-
pational hazards, and the acute and chronic effects of low
levels of pollutants released during coal liquefaction.
With reference to chronic effects, interest centers on car-
cinogenicity, mutagenicity and, possibly, teratogencity of
chemicals known to be a part of coal liquefaction and other
processes. Major reliance for the foreseeable future must
be placed on extrapolation from laboratory and field data on
animals to man.
Present indications as to chronic effects of major
pollutants, based on the study of coal-derived products, are
as follows:
• Sulfur-containing constituents (in the reduced
state) are present in a much greater variety and,
in some cases, larger quantities than were anti-
cipated. The ecological and health effects of
reduced sulfur compounds have had little study.
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• Concentrations of polynuclear aromatic hydro-
carbons are very high. A detailed study of this
fraction is called for to properly estimate the
general threat of industrial carcinogenesis. BaP
concentrations in aqueous liquors suggest an
environmental hazard.
• Concentrations of weakly acidic components, sus-
pected tumor promoters or co-carcinogens, are
substantial and a wide variety occur.
• Nitrogen heterocyclics are present at substantial
levels suggesting the need for additional studies.
High indole/skatole concentrations suggest the
possible presence of carcinogenic dibenzoacridines.
In connection with the toxicity data, it was reported
that the toxicity of an ion or compound depends on the
following factors: the species of test animals, the prior
exposure (e.g., adaptation) of the test species, the pH,
temperature, water alkalinity and hardness, dissolved oxygen
level, salinity, presence of other toxicants, route of
administration, and whether a static or flowing system was
used. The use of acute toxicity data to predict 'chronic or
subacute effects appears all too frequently to be based on
assumptions that are highly questionable.
The toxicity of various inorganic anions and cations
was reported under four headings, as follows:
• Very toxic - effects seen below 1 ppm, and the
LD^o occurs at a dietary level of 1-10 mg/kg body
weight.
• Moderately toxic - effects seen at 1-100 ppm, and
the LD5Q at the 10-100 mg/kg body weight.
• Slightly toxic - effects seen rarely in plants or
microorganisms, and the LDso at a dietary level of
100-1000 mg/kg body weight.
• Relatively harmless - the LD50 occurs at a level
greater than 1000 mg/kg body weight.
Elemental cations judged "very toxic" to microorganisms
included: copper, tin, silver, and mercury. Cations judged
"very toxic" to higher plants included: beryllium; copper;
mercury; tin; and, possibly, cobalt; nickel; and lead.
For animals, the "very toxic" elemental forms included-
arsenic (III), thallium, tellurium, selenium (IV), and
plutonium (IV-VI). The more toxic trace elements'stressed
52
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in this report include: Be, Cr, Ni, Cu, Zn, As, Se, Cd, Sb,
Hg, Tl, Sn, Co and F.
Another important effort refers to the attempt made by
Hittman Associates to identify those living organisms judged
by the 96-hour LD5Q, to be the most sensitive vis-a-vis such
organic pollutants as benzene, acenapthene, anthracene,
chrysene, toluene, 3,4-benzopyrene-isophorone, and benzi-
dine, among others. Organisms were identified among the
marine microorganisms (algae, bacteria, etc.), fresh-water
algal, terrestrial microoganisms, selected higher plants,
marine invertebrates, fresh-water invertebrates, marine and
fresh-water fishes, amphibians, and nonhuman mammals.
With reference to the potential health effects of
various pollutants on humans, it was noted that carbon
monoxide, acting on hemoglobin to form carboxyhemoglobin
levels ranging from 3.0 to 6.5 percent, resulted in diminished
exercise performance and diminished alertness of healthy
persons. Other evidence implicating levels of carboxyhemo-
globin below 10 percent have appeared to increase the risk
of arteriosclerosis, impaired fetal development, and altered
drug metabolism. These results are still inconclusive and
suggest the need for further study. Information was also
provided on the relative eye irritation potential of several
hydrocarbons. It was suggested that eye and respiratory
tract irritation could serve an early warning of dangerous
exposure to such pollutants as n-butane, n-hexane, benzene,
isopropyl benzene, and p-xylene. Among several hydrocar-
bons, differing in structure, 1,3-butadiene was more ir-
ritating to the eye than the multialkyl-benzenes.
One of the least studied areas relates to the additive
interactions between mixtures of such aqueous pollutants as
phenols, metals, ammonia, and mixtures of ammonia, phenol,
zinc, copper, and cyanide. An effort was made to demon-
strate more clearly the synergistic and antagonistic in-
teractions of a number of compounds. For example, no
interactions were found between phenol, ammonia, and zinc
when the zinc comprised greater than 74 percent of the total
predicted toxicity.
The sublethal effects of concern, both from the ecolog-
ical and human health standpoints, relate to the carcinogenic
and mutagenic effects by polynuclear aromatics and other
organics.
Although carcinogencity in mammals is almost exclusively
limited to 4-, 5- and 6-ring polycyclics and some methylated
derivatives, no definite structure-effect relationship has
yet been determined. Moreover, the presence of N or S
heteroatoms in basic polycyclic hydrocarbon structures has
been demonstrated in different cases either to intensify or
53
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lessen carcinogenic effects. Because N- and S-containing
polycyclic compounds are more water-soluble than the corres-
ponding hydrocarbons, they may be present in effluents at
greater levels than those of the polyaromatic hydrocarbons;
their hazards may, therefore, equal or exceed those of
nonsubstituted polycyclics.
The carcinogenicity to mammals of polycyclic compounds
is dramatically altered by co-exposure to other aliphatic or
aromatic hydrocarbons or to phenols. Concentrations which
produce effects may be lowered by several orders of mag-
nitude when present in combination with other organic com-
pounds. Virtually nothing is known, however, of subacute
interactions between compound classes at the low levels
anticipated in effluents. Potential hazards exist for both
aquatic organisms and human populations exposed through
either water consumption or ingestion of fish and shellfish.
The scarcity of information on carcinogenic and mutagenic
effects of heteroatomic polyaromatic compounds, potential
interactions between compound classes and complete absence
of information on effects of trace levels to aquatic organ-
isms of all polycyclic compounds, indicate the urgent need
for more research in these areas.
The following compounds are known or suspected to be
carcinogenic and may be in the effluent streams of coal
liquefaction plants: benzidine, nitrosamines (at 0.2 moles/
kg), nickel (in the form of nickel carbonyl), chromium
(especially in the form of chromic trioxide or chromate
salts), beryllium (example: beryllium oxide), arsenic
(example: tricalcium arsenate), selenium (example: selenide
salt), cobalt (example: cobalt sulfide), lead (example: lead
chromate), zinc (example: zinc chromate), mercury (example:
elemental mercury), cadmium (example: cadmium sulfide),
anthracenes (example: 9,10-dimethylanthracene), chrysenes
(example: chrysene whose carcinogenicity is uncertain),
benzanthracenes (example: benzo(a) anthracene), fluoran-
thenes (example: benzo (j)), fluoranthene and benzo(b)
fluoranthene, cholanthrenes (example: 20-methylcholanthrene),
benzopyrenes (example: benzo(a)pyrene), dibenzopyrenes
(example: dibenzo(a,h)pyrene), mono- and dibenzacridines
(example: dibenz(a,h)acridine), benzocarbazoles (example:
7H~benzo(c)carbazole), dibenzocarbazoles (example: 7H-
benz(c,g)carbazole), benzanthrones (example: 7H-benz(d,e)
anthracene-7-one), aminoazobenzenes (example: 4-dimethyl-
aminoazobenzene), and naphthylamines (example: alpha-naphthy-
lamine.
The chemical composition of products from coal-lique-
faction systems suggests that they will exhibit considerable
carcinogenicity. Benzo(a)pyrene concentrations ranged from
40-50 ppm in coal-derived products as compared to 1 ppm for
carcinogenic condensed tobacco smoke. Concentrations of
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PAH are usually 10-100 times the level found in smoke; and
compounds of known tumor-initiating, tumor-promoting, and
co-carcinogenic activity, such as pyrene and alkalynaphthalenes
are present. Chromatographic surveys of gaseous and aqueous
samples associated with conversion processes further illustra-
te the existence of a potential environmental and/or health
threat. Gaseous samples from one process were found to
contain considerable concentrations of H2S, COS, thiophene,
and methyldisulfide. An aqueous separator liquor from one
process contained sulfur-bearing constituents, phenolics,
and a measurable (ppb) concentration of benzo(a)pyrene. A
stack gas sample from one process was found to contain at
least fifty low molecular weight organic compounds.
In the absence of medical data, compounds with boiling
points above 250°C should be handled with caution. In
general, these are the compounds with the higher molecular
weights, large number of aromatic rings, lower water solu-
bility, and higher potential for relative persistence and
bioaccumulation in organisms.
2. FEDERAL/STATE STANDARDS. CRITERIA
Consistent with the objective of evaluating coal lique-
faction systems, a review of existing environmental re-
Juirements was made at the federal and state government
evels. The study of state laws was restricted to those
states which have the demonstrated coal reserves necessary
to provide sites for commercial coal liquefaction facilities
in the near and far term. The states which have been ad-
dressed are: Alaska, Arizona, Colorado, Illinois, Indiana,
Kentucky, Montana, New Mexico, North Dakota, Ohio, Pennsyl-
vania, South Dakota, Texas, Utah, West Virginia, and Wyoming.
The major conclusion of the review is that no legisla-
tion currently exists directly pertinent to coal liquefac-
tion systems. Prior to commercialization, such legislation
is needed at the federal, state, and local levels. A review
of existing standards and guidelines does provide an idea of
long-range goals in the area of environmental policy.
Additionally, existing standards governing related fossil
fuel technologies could serve as the foundation on which
standards for liquefaction facilities will be based.
However, at this time it is impossible to project how
stringent and how comprehensive environmental regulations
will be specific to commercialized coal liquefaction sys-
tems.
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a. Federal Policy
The Clean Air Act outlines existing federal policy
concerning air quality standards that have been established
for several types of emissions, including: particulates,
hydrocarbons, and sulfur oxides. These standards are sum-
marized in Table 1 of Appendix B.
Additionally, standards for new sources have been
established. Specifically, the standards for coal pre-
paration, plants, petroleum liquid storage vessels, and
fossil fuel-fired steam generators may be similar to the
standards which will be established for corresponding areas
of coal liquefaction facilities. The steam generator data
may be more applicable to production utilization than it is
to production. Possibly applicable new source standards are
discussed in Table 2 of Appendix B.
National emission standards for air pollutants
deemed hazardous are established in conjunction with the
Environmental Protection Agency (EPA). Currently, standards
exist for mercury, beryllium, and asbestos. Although none
of these are likely to affect coal liquefaction, future
standards for hazardous air pollutants may be applicable.
The Federal Water Pollution Control Act has estab-
lished long-range national goals to limit point source
effluent concentrations. The act requires "application of
the best practicable control technology currently available"
not later than July 1, 1977. Six years later, "application
of the best available technology economically achievable"
will be required to meet the national goal of "eliminating
the discharge of all pollutants."
Effluent guidelines and standards exist for several
industries which have operations similar to those proposed
for liquefaction plants. Table 3 of Appendix B includes
standards and guidelines for coal preparation and storage
facilities and coking operations. Coking operations are
more directly applicable to liquefaction processes based on
pyrolysis. In addition, a comprehensive system of standards
has been established for petroleum refinery operations.
Effluent limitations for refineries are functions of overall
refinery size and the capacities and pollution potentials of
the refinery unit processes. A similar system may be
developed for liquefaction plants, the factors of plant size
and process type making the effluent limitations as equitable
as possible.
The characterization of solid waste materials
leaving coal conversion plants is incomplete. It is possible
that hazardous wastes are present. For this reason, subsequent
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discussions of solid waste disposal shall include hazardous
waste disposal, although the necessity of such measures is
not certain.
The Resource Conservation and Recovery Act of 1976
replaced the Solid Waste Disposal Act as a statement of
National Solid Waste Policy. Guidelines for landuse and
ultimate disposal of solid wastes are not as advanced as the
legislation governing emissions to air and water. The most
applicable EPA requirements and recommendations are described
in Table 4 of Appendix B.
Not all constitutents of the products, by-products,
and wastes generated by the liquefaction process are known.
The Toxic Substances Control Act was established to provide
regulation and testing of new and existing materials which
could cause unreasonable health and environmental conse-
quences. Testing may be prescribed for cumulative or
synergistic effects, carcinogenicity, mutagenicity. birth
defects, and behavioral disorders. Should any liquefaction
process components be characterized as toxic, the develop-
ment of technology capable of isolating and disposing of
those components will be necessary. The potential impact is
difficult to assess because of incomplete characterization
of process components and incomplete determination of sub-
stances and concentrations of those substances which should
be considered toxic.
b. Selected State Policies
• Alaska. Ambient air quality standards and
standards for industrial process emissions have been estab-
lished. Table 5 of Appendix B shows the standards and
reference conditions. Emissions standards for industrial
processes are described in Table 6 of Appendix B.
Water quality parameters are dependent on
water uses, which range from potable water to industrial
water. Table 7 of Appendix B defines the standards required
for various parameters such as pH, dissolved organics, etc.
for these water use classifications.
Regulations for the management of solid waste
are directed primarily toward municipal wastes rather than
those of an industrial nature. Should leaching or perma-
frost prove a problem, special disposal procedures must be
submitted to the Department of Environmental Conservation.
A minimum of two feet of earth must be maintained between
solid wastes and the anticipated high groundwater table.
Surface drainage must be prevented from contacting the
landfill area. Solid waste may be landfilled in layers of
not more than two feet prior to compaction.
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• Arizona. In addition to ambient air quality
standards, Arizona has source emissions standards for parti-
culates, sulfur compounds, and volatile organic compounds.
These values are presented in Tables 8 and 9 of Appendix B.
State goals for ultimate achievement have also been established;
they are included in Table 8 of Appendix B.
Water standards are established for surface
waters with specific uses. Applicable standards for domestic
and industrial waters are compiled in Table 10 of Appendix
B.
Solid waste legislation lags the other areas.
Daily landfill cover up 6 to 12 inches are required. Final
cover must be a minimum of two feet deep.
• Colorado. Colorado has enacted standards of
performance for new stationary sources. Of these, the
standards of performance for petroleum refineries are
probably most indicative of future legislation. These
standards are reviewed in Table 11 of Appendix B. Of
particular interest is Colorado legislation pertaining to
oil-water separators. Several liquefaction processes,
including currently operating solvent refined coal (SRC)
pilot plants use similar equipment. One or more of the
following vapor loss controls is required: a solid cover, a
floating roof, a vapor recovery system, or special equipment
which can demonstrate equal or superior efficiency.
Both effluent limitations and water quality
standards have been promulgated. As Table 12 of Appendix B
shows, the standards are very stringent for all classes of
water. Effluent limitations are also presented in Table 13
of Appendix B. Solid waste requirements are not as rigorous.
Compaction of wastes is required.
• Illinois. Environmental legislation in
Illinois is among the most comprehensive of all the states
considered. Both air quality standards and stationary
sources standards have been promulgated. Table 14 of
Appendix B describes air quality standards. Those emissions
standards which are most applicable are discussed in Table
15 of Appendix B.
Illinois water quality standards are depen-
dent upon water use classification. Lake Michigan is treated
as an independent classification. Effluent standards also
exist. A mixing zone of a circle of a 600 foot radius is
allowed when quality standards are more stringent then the
corresponding effluent standard. Table 16 of Appendix B
summarizes the applicable standards for water quality, and
Table 17 of Appendix B highlights applicable effluent'standards
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Disposal of hazardous wastes must be author-
ized by permit. No hazardous waste regulations are specified.
Also, noise control legislation exists which might effect
plant operations. The levels of allowable sound are discus-
sed in Table 18 of Appendix B.
• Indiana. In addition to ambient air quality
standards (Table 19 of Appendix B), Indiana has laws con-
trolling the storage and handling of volatile hydrogen
liquids. A vapor recovery system, floating roof or alter-
native system which meets approval of the proper state
agencies is required. Volatile organic liquid-water sep-
arators require either a solid cover or one of the previously
discussed vapor control methods required for storage systems.
Indiana water quality standards state criteria
to be considered in determining a mixing zone but prescribe
no absolute zone, reasoning that too many variables are
involved. Pertinent water quality criteria are outlined in
Table 20 of Appendix B.
Prior to the issuing of permits to operate
landfills, a detailed plan of the operation must be sub-
mitted to, and approved by the appropriate state agencies.
• Kentucky. Air quality standards are listed
in Table 21 of Appendix B. Note that Kentucky has a stand-
ard for hydrogen sulfide as well as sulfur dioxide. The
standards of performance for petroleum refineries have been
compiled in Table 22 of Appendix B.
Kentucky water quality standards vary with
stream use classification. Table 23 of Appendix B shows the
most stringent standards, which would be applicable in a
multiple-use situation. Solid waste requirements include
providing more than two feet of compacted soil between solid
waste and maximum water table, two feet or more of compacted
earth between solid waste and bedrock, solid waste layers of
two to three feet, and a final daily cover of six inches to
prevent waste dispersion. A final cover of two feet of
compacted soil is required to be followed by revegetation.
• Montana. Montana has adopted the federal new
source performance standards to supplement its own ambient
air quality standards. Applicable ambient standards are
presented in Table 24 of Appendix B.
Water quality policy consists of general
water quality criteria and specific water quality criteria
which correspond to the various water-use classifications.
Table 25 of Appendix B describes criteria for the most and
least stringent classifications to give an idea of the range
of conditions permitted.
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Site approval is required for solid waste
disposal when hazardous wastes are involved. Daily cover of
six inches and final cover of two feet or more are also
required. Disposal sites shall not be located near springs
or other water supplies, near geologic formations which
could cause leaching problems, in areas of high groundwater
tables, or within the boundaries of 100 year flood plains.
• New Mexico. New Mexico is presently the only
state that has promulgated emission standards applicable to
coal conversion facilities; specifically, coal gasification
plants. Stacks at least ten diameters tall, equipped with
enough sampling ports and platforms to perform accurate
sampling, are required. Particulate emissions requirements
exist for briquet forming areas, coal preparation areas, and
the gasification plant itself - with an additional require-
ment for gas burning boilers. Limits have been placed on
dischargeable concentrations of sulfur, sulfur dioxide,
hydrocarbons, ammonia, hydrogen chloride, hydrogen cyanide,
hydrogen sulfide, carbon disulfide, and carbon oxysulfide as
well. These limits are compiled in Table 26 of Appendix B.
There are stringent criteria, relative to
most of the states reviewed. However, a review of New
Mexico air laws pertaining to petroleum refineries reflects
an interest in environmental preservation, not a distrust of
new technology. Emissions standards for ammonia and hydro-
gen sulfide, for example, are the same for both industries.
In fact, refineries have additional limits on mercaptan and
carbon monoxide not presently included in gasification
legislation. These requirements, as well as New Mexico
Ambient Air Quality Standards are presented in Table 27 of
Appendix B. The ambient air criteria for heavy metals and
the difference in dischargeable carbon monoxide concen-
trations between new and existing refineries should be
noted. Water quality standards are very specific. For
example, the Rio Grande Basin is divided into fifteen
sections, each with independent water quality standards.
Table 28 of Appendix B presents applicable water quality
criteria for selected areas.
Solid waste regulation is not as advanced or
as complicated as corresponding air and water controls.
State requirements include six inches of daily cover,
compaction of wastes to smallest practical volume, and a
minimum final cover of two feet of earth. Landfill bottoms
must be a minimum of 20 feet above groundwater level.
• North Dakota. Table 29 of Appendix B de-
scribes applicable ambient air quality standards of North
Dakota. These have been established in accordance with the
state air quality guidelines which call for preservation of
the health of the general public, plant and animal life air
Visibility, and natural scenery. The guidelines also '
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require that ambient air properties not change in any way
which will increase corrosion rates of metals or deterioration
from industrial processes. For particulates, the equation
governing process industries in Arizona is the same for
North Dakota. Sulfur dioxide emissions are limited to three
pounds per million Btu of heat input.
Water quality is dependent upon water classi-
fication. Applicable criteria for Class I waters are dis-
cussed in Table 30 of Appendix B. Mixing zone guides are
described in preference to defining a mixing zone applicable
to every situation.
North Dakota regulations specify a daily
cover of six inches and a final cover of twelve inches for
sanitary landfill operations.
• Ohio. Ohio legislation to preserve air
quality includes both ambient and emission standards.
Ambient standards are in Table 31 of Appendix B. Emissions
regulations for industrial processes which might be applica-
ble have been promulgated for particulates, sulfur oxides,
nitrogen oxides, hydrocarbons, carbon monoxide, and photo-
chemical oxidants. Additionally, priority zones have been
established. These zones do not presently meet EPA stan-
dards for sulfur dioxide, nitrogen dioxide, and particulates.
The sulfur dioxide and particulate emissions limits are
mathematical functions of total emissions discharged, and
process throughput, respectively. Carbon monoxide from
petroleum refinery processes must go through an afterburner
prior to discharge. Standards for storage of hydrocarbons
are in line with those previously mentioned. Photochemical
oxidants must be incinerated to a minimum of 90 percent
oxidation prior to discharge to the atmosphere.
Effluent discharge requirements are variable.
Water quality standards depend on water-use and mixing zone,
which are formulated for specific discharges and locations,
rather than a generalized definition. Criteria for public
water supply, the most stringent classification, are high-
lighted in Table 32 of Appendix B. Dissolved oxygen and pH
levels for streams supporting aquatic life are included.
Table 33 of Appendix B describes general standards.
Plans for all sanitary landfill sites and
operations must be approved in advance. A complete descrip-
tion of site terrain and subterrain must be specified as
well as soil chemistry and local hydrology data. A six-inch
daily cover and a two-foot final compacted soil cover are
also required. Semi-annual well monitoring for chlorides,
chemical oxygen demand, total organic carbon, and total
dissolved solids is an additional requirement.
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• Pennsylvania. Hydrocarbon emissions are
limited by controls requiring either a vapor recovery system
or floating roof for storage tanks; the former required for
hydrocarbon loading equipment, the latter for hydrocarbon-
water separators. Applicable ambient standards are shown in
Table 34 of Appendix B. Standards for particulate emissions
are included in Table 34.
Pennsylvania water quality criteria, based
upon water use are in Table 35 of Appendix B. Applicable
criteria are given for the Monogahela River, as specific
criteria are different for each stream and, in many cases,
different for sections of the same stream.
The solid waste legislation of Pennsylvania
is among the most evolved of any of the states considered.
In addition to the general solid waste discussions of most
states, Pennsylvania has promulgated rules and regulations
governing coal refuse disposal. The rules prohibit disposal
which will promote fire, subsidence, or leaching problems.
The state has also published a statement of guidelines and
acceptable procedures for the operation of such disposal
areas. Generally, two feet of final cover is required. The
landfill shall be a minimum of six feet above the seasonal
high water table. Disposal cells may not exceed eight feet
with compacted solid wastes layers of two feet or less.
Hazardous waste disposal plans must be approved by the
appropriate state agencies.
• South Dakota. The ambient air quality stand-
ards of South Dakota are shown in Table 36 of Appendix B.
South Dakota has reserved the right to set emissions stand-
ards for any source which may be exceeding the ambient
standards. Standards for fuel burning installations and
general process industries are listed in Table 37 of Appendix
B.
Water quality criteria for three types of
waters are presented in Table 38 of Appendix B. It is
obvious that the intended water-use provision of several
state laws, including South Dakota, will be an important
point to consider in site selection for commercialized coal
conversion facilities. Mixing zones are dependent on stream
characteristics. Lakes are not allowed a mixing zone.
South Dakota solid waste regulations are in
line with those of the states previously mentioned with
regard to operations. Of greater interest are the require-
ments pertaining to site locations. Landfills are not
permitted within 1,000 feet of any lake or pond, or within
300 feet of any stream or river. Also, a minimum of six
feet between waste and groundwater table must be preserved
Such requirements, promulgated specifically to prevent
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leaching to groundwater, may provide an .applicable basis for
future regulatory control of disposal of solid wastes from
liquefaction processes.
• Texas. All national primary and secondary
ambient air quality standards are applicable in Texas. An
additional ambient standard for inorganic fluoride com-
pounds, specifically hydrogen fluoride gas, has also been
promulgated. This standard, along with net ground level
concentrations for applicable compounds, is presented in
Table 39 of Appendix B. Emission rates for particulates and
sulfur dioxide have been promulgated; both are functions of
effective stack height. Additional emission concentration
limits for particulates, sulfur dioxide, and nitrogen oxides
in fossil fuel burning steam generators are also discussed
in Table 39. Visibility requirements prohibit exceeding 20
percent opacity, 15 percent for stationary flues with total
flow rates exceeding 100,000 acfm. These opacity limits are
for five minute periods and do not include opacity due to
uncombined water mists.
Texas water standards consist of three parts:
general criteria, numerical criteria, and water uses. The
latter two are highly specific, similar to the Pennsylvania
legislation. Water quality parameters and uses for the San
Antonio River Basin are shown in Table 40 of Appendix B. It
should be noted that Texas has one of the warmest climates
among those states considered. Water temperatures may
naturally exceed 96°F. For this reason, the 90 degree
maximum temperature suggested by the National Technical
Advisory Committee is not applicable. A maximum temperature
increase of 3°F (1.7°C) is permitted for fresh waters, and
5°F, (2.8°C) for saline waters.
Three classifications of industrial solid
waste exist. These can be characterized as: hazardous,
naturally decomposable organics and inorganics, and inert
materials. All plans and specifications relevant to site
selection, design, and operation of industrial waste dis-
posal operations must be reviewed and approved by appropri-
ate state authorities.
• Utah. Utah has no ambient air or new source
standards at this time. Current federal standards are ap-
plicable. The Utah Air Conservation Regulations note that
the Utah Air Conservation Committee and the State Board of
Health do not agree with most of the federal standards.
There is no indication of the types of standards these
organizations favor. Future legislation will have to answer
that question. State emissions standards have been set for
particulates requiring 85 percent control. Sulfur emissions
must meet federal ambient and new source standards.
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Stream quality criteria are dependent upon
stream classification. Class "A" waters are, without pre-
treating, to be suitable for a variety of uses including
domestic water supply and propagation of fish and wildlife.
Such waters are to be free from organic substances measured
by biochemical oxygen demand. A pH range of 6.5 to 8.5 is
to be maintained. Physical characteristics and chemical
concentration standards are the same as prescribed by
"Public Health Service Drinking Water Standards, 1962."
These are described in Table 41 of Appendix B. All solid
waste disposal operations must meet approval of the Utah
State Division of Health.
• West Virginia. A brief review of West
Virginia state air laws provides a good idea of the relative
importance of the coal mining industry there. Air pollution
control legislation has been promulgated for refuse dis-
posal, preparation, and handling operations. These re-
gulations and particulate limits for manufacturing process
operations are detailed in Table 42 of Appendix B. Ambient
air quality standards are detailed in Table 43 of Appendix
B.
Water quality criteria, based on water use
similar to the Pennsylvania criteria are highlighted in
Table 44 of Appendix B. Criteria for the Gauley River and
tributaries were chosen for presentation due to the fact
that it is acceptable for all water use classifications.
West Virginia has three solid waste classifi-
cations, analagous to those previously described in the
Texas solid waste laws. Requirements for disposal of wastes
of a hazardous nature shall be determined on a case-by-case
basis. Class II decomposable wastes are subject to six
inches of daily cover and two feet of final cover.
• Wyoming. Table 45 of Appendix B defines the
state ambient air quality standards. Emissions standards,
primarily applicable to fossil fuel burning installations,
are presented in Table 46 of Appendix B. Wyoming has
additional regulations governing hydrocarbon storage and
handling. Waste disposal combustion systems for vapor
blowdown or emergency situations are to be burned in smokeless
flares. Pressurized tanks, floating roofs of vapor recovery
systems, are required for storing hydrocarbons.
Water quality standards which may impact
future liquefaction operations are summarized in Table 47 of
Appendix B. Wyoming waters are classified as having poten-
tial to support game fish (Class I), potential to support
nongame fish (Class II), or as not having the potential to
support fish (Class III). In addition, waters designated as
part of the public water supply must meet the most recent
Federal Drinking Water Standards. These are described in
•Table 48 of Appendix B.
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The Wyoming Department of Environmental
Quality reviews construction and operating plans of all
industrial or hazardous waste disposal operations. Indus-
trial waste disposal sites shall not be located in areas of
low population density, land-use value, and groundwater
leaching potential. Monitoring wells must be installed
prior to commencement of operations. Disposal sites may not
be located near drinking water supply sources. It is
suggested, but not required, that disposal sites with imper-
meable soil be selected.
3. OTHER REGULATORY REQUIREMENTS (NEW OR PENDING)
In order to maintain a data base of existing environ-
mental requirements directly and indirectly applicable to
coal liquefaction processes, references such as the Environ-
ment Reporter must be reviewed periodically. Also, in
addition to new and pending legislation, a keen awareness of
new developments which may affect future legislation is
necessary. This section discusses recent developments which
could directly or indirectly influence future policy regula-
tory coal liquefaction processes.
One change is in the legislation governing coal prepara-
tion facilities, essential to all liquefaction processes.
Previously, coal preparation facilities were subject to
zero-discharge effluent limitations. Instead, EPA revised
the regulations and coal preparation plants are now subject
to the same effluent limitations as the coal mining point
source category, with different effluent concentration
analogous to those for alkaline and acidic mine drainage.
Appreciable quantities of benzene, toluene, and xylene
and their derivatives (BTX) are presumed to be generated by
all liquefaction processes. EPA has recently identified
benzene as a hazardous air pollutant under the Clean Air
Act. Benzene exposure has been linked to leukemia by studies
conducted by the National Institute for Occupational Safety
and Health (NIOSH). The Occupational Safety and Health
Administration (OSHA) has advocated reduced exposure levels
in the workplace. While no standards have been established
at this time, EPA has made a tentative statement that benzene
emission levels would impact petroleum refining and coke
oven operations, which implies a possibility of impacting
coal liquefaction operations.
Recently, the Environmental Defense Fund (EOF) petitioned
EPA to list arsenic as a hazardous air pollutant under the
Clean Air Act, citing reports by the National Academy of
Sciences and NIOSH which link arsenic to skin and lung
cancer. Shale oil, petroleum refining, and coal combustion
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are all sources of arsenic emissions to the atmosphere.
Coal combustion accounts for 12 percent of all arsenic
emissions. Should arsenic emission levels be established,
they may impact coal liquefaction as well as other fossil
fuel processing industries.
Another development is a report by the National Academy
of Sciences (NAS) which warns that continued use of fossil
fuels as a primary energy source for more than 20 to 30 more
years could result in increased atmospheric levels of carbon
dioxide. The greenhouse effect and associate global tempera-
ture increase and resulting climate changes could, according
to NAS be both "significant and damaging." The findings,
although not conclusive, demonstrate the need for positively
identifying the long-range effects of using fossil fuels to
provide energy needs. The impacts on coal utilization for
energy, including coal liquefaction, are obvious. For this
reason, the Energy Research and Development Administration
(ERDA) established a research office to assess the possible
environmental effects of increased levels of carbon dioxide
in the atmosphere. As well as conducting its own research,
the office will function as a central contact point for
other scientific research organizations and government
agencies.
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C. ENVIRONMENTAL OBJECTIVES DEVELOPMENT
1. CRITERIA FOR PRIORITIZING
In conjunction with the development of Environmental
Characterizations, an effort was completed to establish
priorities for the development of coal liquefaction techno-
logies and control needs. The candidate systems were those
most advanced from a development standpoint and those
considered to be of possible interest to commercial develop-
ers and industrial users. The criteria selected follow.
• Stage of Development
• Schedules for Construction, Development, etc.
• Potential for Emissions
• Process Similarities
• Resource Conservation
• Potential Hazard of Residual Emissions
• Impact/Use Potential
• Quantity of Residual Emissions
• Rate of Availability, i.e., how fast can the
technology be brought to commercial use?
• Energy Efficiency
• Priorities for Construction, Development, etc.
• Demonstrated Scale of Production
• Probability of Success in Development
• Projected Process Development Costs
• Applicability, i.e., extent of projected markets
All available information concerning the criteria was
assembled for all processes. Each system was then assigned
a relative value with respect to each criterion. When it
was possible to define an ideal situation, points were
awarded on the basis of a fractional approach to the ideal.
In other cases, only relative comparisons were possible.
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The point values were then totaled vertically for each
criterion and normalized. For each process, the normalized
values were totaled, horizontally, to establish the priori-
tized rankings, the greatest number of points being assign-
ed the No. 1 ranking. The result is a comparative rating
and evaluation of the systems established on the basis of
projected needs for detailed study and environmental charac-
terization. The order of ranking for the candidate systems
in coal liquefaction technology is as follows:
Solvent Refined Coal
H-Coal
Exxon Donor Solvent
Synthoil
COED
COSTEAM
Clean Coke
Fischer-Tropsch
ORC (Garrett)
Coalcon
Methanol Synthesis
Toscoal
Bergius
This ranking has served as an initial guide; however, the
ranking system is undergoing further development as dis-
cussed in the next section.
2. METHODOLOGIES BEING DEVELOPED
IERL-RTP is currently developing an environmental
assessment methodology especially related to the Federal
Interagency Energy/Environment R&D Program in support of
standards development. The environmental assessment method-
ology will consist of various methodology components being
developed with the assistance of participating contractors.
One such specialized component is the development of process
assessment criteria which will be used to set priorities
with regard to the selection of systems for further study in
environmental assessment. Hittman Associates' task, called
Process Assessment Criteria, consists broadly of:
• delineating criteria to be considered in evaluating
systems (to set priorities for further study),
• assigning these criteria a normalized set of re-
levance weights, based on a rational decision
analysis method, and
• preparing step-wise instructions which will permit
application of this methodology component for a
generalized environmental assessment.
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Environmental assessment is defined as a continuing,
iterative study at: (1) determining the comprehensive
multimedia environmental control costs, from the application
of the existing and best future definable sets of control/-
disposal options, for a particular set of sources, pro-
cesses, or industries; and (2) comparing the nature of these
loadings with existing standards, estimated multimedia and
environmental goals, and bioassaying specifications as a
basis for prioritization of problems/control needs and for
judgement of environmental effectiveness.
In developing the generalized methodology, the effort
was focused on several elements:
Criteria Identification. A set of measurable
factors was identified which, together, could be used to
determine quantitatively the need for immediate further
attention to systems being considered for a generalized
environmental assessment. These measurable factors charac-
terize the timing, general nature, magnitude, and likelihood
of commercialization and potential environmental degradation
resulting from subject systems. Also, with the knowledge
that a criteria weighting process would be applied, it was
attempted to ensure that all significant criteria were
listed and that overlap between criteria was minimized.
Criteria Weighting Factors. A decision model was
used to apply the judgement of knowledgeable individuals to
the generation of weighting factors quantifying the relative
importance of the criteria. The procedure was repeated as
necessary for subcriteria under each criteria. The decision
model used was DARE (Decision Alternative Rational Evaluation)
Use of Weighted Criteria. Generalized instruct-
ions were prepared to guide Process Assessment Criteria
users in applying the weighted criteria to actual systems.
These instructions addressed the quantification of each
criterion for candidate systems and the procedure for
applying the given weighting factors to those criteria to
obtain total Process Assessment Criteria scores. These
instructions are integral to the complete DARE decision-
making process. The DARE-derived scores may be used to rank
order, choose subsets, or otherwise prioritize candidate
systems for an environmental assessment.
Work on Process Assessment Criteria is continuing.
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D. ENVIRONMENTAL DATA ACQUISITION
1. EXISTING DATA FOR EACH PROCESS
Generally, the data pertinent to definition of environ-
mental effects of coal liquefaction systems fall into one of
two categories:
(1) What are the discharges to the environment
from coal liquefaction facilities?
(2) What effects will these discharges have on
the environment?
Since there is no commercial-sized coal liquefaction
facility in the U.S. today, answers to both questions are
conjectural at this time.
The best-known historical use of coal liquefaction
technology occurred during the World War II era when Germany
produced commercial quantities of aviation gasoline using
the Bergius process. Under these circumstances, a study of
environmental discharges and effects would be expected to
have low priority. Also, coal liquefaction technology has
changed and improved to such an extent that most of the
existing data would be of little environmental usefulness.
During the period after World War II, various coal
liquefaction processes were investigated, but were abandoned
as being uneconomic to compete with petroleum and natural
gas fuel sources. Data on environmental discharges and
effects for these systems are sparse. Bench-scale and pilot
plant investigations were designed to solve technical
process problems and did not usually include much treatment/
control technology equipment.
It was not until the late 1960's and early 1970*s that
economics of coal liquefaction were reviewed and efforts
again started on various process developments. Again,
however, investigations have been centered on solving
technical process problems and do not usually include much
treatment/control technology developments.
Existing data for the environmental discharges on the
different systems are fragmentary and usually may be char-
acterized as:
• Product and waste descriptions based on hydro-
carbon chain length, boiling point ranges, vis-
cosities, and element contents (sulfur, nitrogen,
carbon-hydrogen ratios, metals, etc.)
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• Qualitative analysis for specific organic com- •
pounds, often for known carcinogenic effects.
• Out-of-date and/or partial quantitative analysis
of products.
Since there are no available overall quantitative
analyses of product and waste discharges from any existing
coal liquefaction system, Hittman Associates is currently
preparing reports which will provide a preliminary estimate
of such discharges for four processes - Solvent Refined
Coal, Synthoil, H-Coal, and Exxon Donor Solvent. Input-
output materials characterizations for these reports are
described in subsection D-4. In addition, sampling and
analytical techniques and a test program development for
future definition of environmental discharges are described
in subsections D-2 and D-3, respectively.
Environmental effects for coal liquefaction facilities
may be expected from:
• Atmospheric emissions of particulates, sulfur and
nitrogen compounds, and other volatiles.
• Wastewater contaminants such as: acids, phenols,
organics, cooling tower chemicals, and inorganic
compounds.
• Solid and residue streams such as: ash, still
bottoms, char, spent catalysts, and filtered
solids.
• The products.
Most of the existing data for environmental effects are
for the product, or the solid and residue wastes.
There is voluminous information on the presence of bio-
logically active organic (carcinogenic, etc.) compounds in
the products. Since most of these organic compounds are
formed in the hydrogenation step of the process, they could
be found throughout the plant as a result of leaks, spills,
and other sources of contamination. Considerations of the
biological activity would also have to be given during
handling, transportation, storage, and use of these pro-
ducts. Hittman Associates is currently preparing an envir-
onmental characterization report which will discuss the
literature and other available data on the environmental
effect of the products from coal liquefaction systems.
In addition to the products, biologically active and
toxic pollutants have been identified in the solid and
71
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residue wastes and wastewater contaminants. Since most of
the hazardous organics and inorganics from the coal lique-
faction process are relatively nonvolatile, they may be
expected to be present in the solid and residue wastes.
Limited data on still bottoms have shown that biologically
active organics are present. Analysis of ashes show that
metals and metallic compounds are concentrated in this
process waste. Phenols and organics have been similarly
identified in the wastewater.
Although the presence of biologically active and toxic
substances in the products and process wastes have been
documented, the environmental effects have not. Data are
usually not available on the amounts that would be dis-
charged to the workplace or environment. This stems from
the fact that the problems and products themselves have not
been adequately defined, treatment/control technology has
not been specified, and compositions and biological and
toxic effects for given product and waste compositions have
not been established.
As laboratory analysis of product and waste streams for
quantitative measurement of toxic and hazardous chemicals
becomes available, Hittman Associates will attempt to esti-
mate the environmental effects to be expected from quanti-
fied discharges.
2. IDENTIFY SAMPLING AND ANALYTICAL TECHNIQUES
The Process Measurements Branch of IERL-RTP has develop-
ed a three-phased approach to performing an environmental
source assessment. In this phased approach, three dis-
tinctly different sampling and analytical procedures are
envisioned. The Level I Procedure Manual outlines this
phased approach, and describes Level I sampling and analytical
techniques. A suggested sampling plan for the SRC Pilot
Plant at Ft. Lewis, Washington is being prepared and is
based upon these techniques. The SRC combustion test at
Plant Mitchell, Georgia, utilized a modified Level I Tech-
nique. Both of these programs will be discussed in Section
3.
a. The Phased Approach
The phased approach requires three separate levels
of sampling and analytical effort. The first level (Level
I) utilizes quantitative sampling and analysis procedures
accurate within a factor of 2 to 3 and provides preliminary
environmental assessment data; identifies problem areas; and
formulates the data needed for the prioritization of streams
within a process, components within a stream, and classes of
72
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materials for further consideration in the overall assess-
ment. The second (Level 2) sampling and analysis effort,
after having been focused by Level I, is designed to provide
.additional information that will confirm and expand the
information gathered in Level I. This information will be
used to define control technology needs. The third phase
(Level 3) utilizes Level 2, or better, sampling and analysis
procedures as well as continuous monitoring.
The phased approach recognizes that it is impossible
to prepare for every conceivable condition in the first
sampling or analysis effort. In some cases, unknown condi-
tions and components of streams will result in unreliable
information and data gaps that will require a significant
percentage of the sampling or analysis effort to be repeated.
There is a possibility that many streams or even
the entire installation may not be emitting hazardous sub-
stances in quantities of environmental significance. Con-
versely, certain streams or sites may have such problems
that a control technology development program can be initiated
in parallel with a Level 2 effort. If either of these
situations could be determined by a simplified set of sampling
and analysis techniques, considerable savings could result
in both time and funds.
The phased approach offers potential benefits in
terms of the quality of information that is obtained for a
given level of effort and in terms of the costs per unit of
information.
(1) Level 1 Sampling and Analysis. The Level 1
sampling and analysis goal is to identify the pollution
potential of a source in a quantitative manner with a target
accuracy factor of + 2 to 3. At the initiation of an envir-
onmental assessment, little is known about the specific
sampling requirements of a source both practically and
technically, and hence the emphasis is on survey tests. For
this reason, no special procedure is employed in obtaining a
statistically representative sample and the chemical, physical,
and biological testing has survey and/or quantitative ac-
curacy consistent with the characteristics of the samples.
At this level, the sampling and analysis is
designed to show within broad general limits the presence or
absence of, the approximate concentrations of, and the
emission rate of inorganic elements, selected inorganic
anions, and classes of organic compounds. Thfe particulate
matter is further analyzed through size distribution as well
as microscopic examination in order to determine gross
physical characteristics of the collected material. Biotest-
ing is designed to obtain information on the human health
effects and biological effects of the sample.
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(2) Level 2 Sampling and Analysis. The Level 2
sampling and analysis goal is to provide definitive data re-
quired in the environmental assessment of a source. The
basic questions and major problem areas to be addressed have
been defined in Level 1 to optimize cost and schedule effi-
ciency. Consequently, Level 2 sampling and analysis is
characterized by obtaining statistically representative
samples, accurate stream flow rates, and identification and
quantification of specific organic and and inorganic elements,
species, and/or classes. Biotesting in selected areas is
expanded.
b. Multimedia Sampling
Multimedia sampling refers to a philosophy that
considers all material discharges, to air, water, or land,
to have pollution potential. A Level 1 control technology
assessment must investigate all discharge points in addition
to feed streams and any internal recycle streams required to
establish a baseline for evaluation of control effectiveness.
(1) Classification of Streams for Sampling Purposes
The basic multimedia sampling strategy has been organized
around the five general types of sampling found in industrial
and energy producing processes.
The five sample types are:
• Gas/Vapor - These are samples for light
hydrocarbon and inorganic gas analysis.
They include samples from input and
output process streams, process vents,
and ambient air.
• Liquid/Slurry Streams - Liquid streams
are defined as those containing less
than 5 percent solids. Slurries are
defined as those containing greater than
5 percent solids. Non-flowing pastes
are considered solids.
• Solids - These include a broad range of
material sizes from large lumps to
powders and dusts, as well as non-
flowing wet pastes.
• Particulate or Aerosol Samples - These
are gaseous streams containing particu-
lates or liquid droplets.
74
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• Fugitive Emissions - These are gaseous
and/or particulate emissions from the
overall plant or various process units.
Flow diagrams which show the overall relation-
ship of the samples to the analysis scheme are shown in
Figures 2 and 3.
(2) Sampling Point Selection Criteria. The
selection of sampling points relies on the concept previously
stated: that Level 1 sampling is oriented towards obtaining
quantitative data with relaxed accuracy requirements for
determination of the pollution potential of a source, whereas
Level 2 sampling is intended to acquire more accurately the
data necessary for a definitive environmental assessment on
prioritized streams. For example, gas stream parameters
such as flow rates, temperature, pressure and other physical
characteristics will be obtained at a single point under
pseudokinetic conditions. This means that the sample is
acquired at the point of average velocity which has been
determined by a velocity traverse taken at typical points in
the stream. At Level 2, however, where quantitative data
are required, isokinetic samples must be withdrawn using a
full traverse with a port in specific locations away from
ducting bends and other obstructions in order to ensure a
sample representative of the actual effluent.
Similar considerations apply to site selection
for sampling liquids and solids. At Level 1, liquid samples
can be taken from tanks or other containers without depth
integration and from pipes using a simple tap sample rather
than using a multiported probe to take a time integrated
sample. In slurry streams, an effort should be made to
sample a turbulent or well mixed area, but this and other
requirements can be relaxed considerably for Level 1 site
selection.
In the case of solids sampling, the standard
procedures used in sampling piles and stationary containers
are relaxed on Level 1 both by taking fewer increments to
make a composite and by relaxing or eliminating the require-
ments for depth-integrated sampling. For moving solid
streams, a simplified sample is obtained by reducing or
eliminating the number of increments required for the time-
averaging aspect of the sampling procedure.
In most cases, Level 1 sampling methods
generally encompass approved standard EPA, ASTM, and API
techniques. Modifications are then made to these techniques
to adapt them to the time and cost constraints consistent
with the Level 1 sampling philosophy. These modifications
75
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ELEMENTS AND
SELECTED ANONS
PHYSICAL SEPARATION
INTO FRACTIONS,
LC/W/MS
Aft SO UPTON
SELECTED ANIONS
PHYSICAL SEPARATION
PARTICULATE I
MATTER |
SOURCE
OPACITY
(STACKS)
CAS
CHEMILUMINESCENCE
INORGANIC ION-STE GAS
\rViii I CHROMATOGRAPHY OR
IOKABI I APPROVED ALTERNATIVE
ORGAN 1C
XAD-2
ABSORBER
MATERIAL* >C, Igg^Ss^
H ORGANICION-SITE GAS
MATERIAL C, -CA[ CHROMATOGRAPHY
•WEIGH INDIVIDUAL CATCHES
EXTRACTION
PHYSICAL SEPARATION
110 ASSAY (SEE CHAPTER X
ORGANIC*
OBCANICS
*C
I2
ALIQUOT FOR GAS
CHROMATOGRAPHIC
ANALYSIS
PHYSICAL SEPARATION
INTO FRACTIONS,
LC/IR/MS
Figure 2. Basic Level 1 Sampling and Analytical Scheme
for Particulates and Gases
76
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LEACHABLE
MATERIALS
SELECTED ANIONS
PHYSICAL SEPARATION
INTO FRAOIONS
LC/IR/MS
SUSPENDED
SOLIDS
ELEMENTS AND
SELECTED ANIONS
SEE SECTION 7.2.6,
CHAPTER VII
QA PHYSICAL SEPARATION
INTO FRAOIONS LC/IR/MS
ELEMENTS AND
SELECTED ANIONS
iKiner AMI<-< I ELEMENT* AND
INORGANICS | SEUCTED ANIONS
PHYSICAL SEPARATION
JORGANICS IINTO FRACTIONS
I I LC/IR/MS
PHYSICAL SEPARATION
INTO FRACTIONS,
LC/IR/MS
ALIQUOT FOR GAS
CHROMATOCRAPHIC
ANALYSIS
Figure 3. Basic Level 1 Sampling and Analytical Scheme for
Solids, Slurries and Liquids
77
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include: 1) reducing point selection criteria; 2) eliminating
the requirements for traversing, continuous isokinetic
sampling, and replicate sampling in the collection of parti-
culate matter; and 3) use of grab samples for gaseous,
water, and solid samples.
(3) Stream Prioritization. Industrial processes
are highly complex systems consisting of a wide variety of
interrelated components. Level 1 sampling may show that
many influent and effluent streams have no environmentally
significant impact. These data can be used to substantially
reduce the number of samples required for Level 2, and can
permit reallocation of resources. Thus, comprehensive
stream prioritization based on the Level 1 sampling and
analysis effort will identify streams with widely varying
environmental priorities. In many cases, the Level 1 informa-
tion will be sufficient to eliminate certain streams entirely
from the Level 2 effort. In other cases, limited resources
may require the omission of certain low priority streams.
c. Data Requirements and Pre-Test Planning
The final decision to test a particular plant will
be the result of the prioritization studies of the preliminary
selection process based on the site selection criteria of a
given program, and on the data requirements of the overall
program or general EPA objective.
Before the actual sampling and analysis effort is
initiated, the data requirements must be established and
used to help identify test requirements as well as any
anticipated problems. The following paragraphs present a
feneral summary of these requirements and the planning
unction which must be applied or expanded to meet the needs
of the individual tests to be performed.
(1) Process Data Needs
Before travelling to a plant for a pre-test
site survey, it is necessary to become familiar with the
process used at the site. This involves understanding the
chemistry and operational characteristics of the various
unit operations as well as any pollution control processes.
It is particularly important to know that detailed relevant
process data are necessary for the sampling and analysis
effort as well as for the overall environmental assessment.
The reasons for this are:
• From a knowledge of the process and the
composition of input materials and
78
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products, conclusions about pollutants
likely to be found in waste streams can
be drawn.
• One must know where to look for waste
streams, including fugitive emissions.
• One must know how plant operating condi-
tions are likely to affect waste stream
flow rates and compositions.
• Thorough familiarity with the process
permits design of a proper sampling
program.
• Thorough knowledge of the interrelation-
ships among process variables permits
extrapolation to conditions in other
sizes of the system being assessed, and
• Detailed process data are the basis from
which control technology development
programs proceed, should environmental
assessments indicate such need.
Familiarization with the process is also necessary so that a
checklist of the requisite data can be developed, including
temperatures, pressures, flow rates, and variations of
conditions with time for the pre-test site survey.
(2) Pre-Test Site Survey
After establishing the necessary process data
needs and making a tentative selection of sampling points, a
pre-test site survey should be performed. At the site, the
survey team should meet with the plant engineer to verify
the accuracy of the existing information and arrange for the
addition of any missing data. Using this information, the
survey team will then proceed to select the actual sampling
sites with the following criteria in mind:
• The sampling points should provide an
adquate base of data for characterizing
the environmental impact of the source
on the environment within a factor of 2
to 3.
• When possible, each sampling point
should provide a representative sample
of the effluent streams. (This is a
desirable but not a strict requirement
of Level 1 sampling.)
79
-------
• The sampling site must have a reasonably
favorable working environment. The
survey personnel must consider the
temperature and noise level in the
sampling areas, if protection from rain
or strong winds exists, and whether safe
scaffolding, ladders, pullyes, etc., are
present.
The identification of support facilities and
services is an essential aspect of the site survey. If
electrical power and water are not available for hook-up to
a mobile test van, it must become self sufficient and these
services designed into the van.
The results of the pre-test survey must be
sufficiently detailed so that the field test problem of
sampling the correct process stream at the proper sampling
location, using the appropriate methodology will be completely
defined prior to approval of the field test and team at the
source site.
(3) Pre-Test Site Preparation
It is assumed that any site or sample point
preparation will be completed before arrival of the sampling
team. This would include: erection of scaffolding, avail-
ability of electrical power, fitting of sample ports and
nozzles at the required locations, etc. The sampling team
is responsible for final mating of the sample device to the
port, and should be equipped with miscellaneous valves,
fittings, other devices, and tools for adaptation.
d. Sampling Equipment and Methodology
For the purpose of Level 1 assessment of gas/vapor
streams, a single grab sample is sufficient although planning
is necessary to ensure that sample acquisition is made at a
reasonably representative plant in the stream or process
cycle. The grab sample may be taken in one of these ways,
depending on the pressure of the steam in question. The
three grab samples types are high pressure line, grab purge,
and evacerated grab samples and are illustrated in Figures
4, 5, and 6.
To collect gaseous steams containing particulates,
a source assessment sampling system (SASS) train is recom-
mended for Level 1.
80
-------
, PYREX
WOOL
PLUG
STYROFOAM
PROTECTOR
DUCT
FLOW
1 1
1 1 1 1 1 1 1 1 1 1\
Figure 4. High Pressure Line Grab Purge Sampling Apparatus
-------
DUCT
FLOW
oo
ro
_
n O
STYROFOAM
PROTECTOR
PYREX
WOOL
PLUG
Figure 5. Low Pressure Grab Purge Sampling Apparatus
(for Less than 2 Atmospheres Pressure)
-------
TEFLON TUBE TO ACT AS NOZZLE
STYROFOAM
PROTECTOR
00
LO
PYREX WOOL PLUG
EVACUATED
3 LITER
VESSEL
Figure 6. Evacuated Grab Sampling Apparatus (for Subatmospheric Pressures)
-------
A diagram of the SASS train appears in Figure 7.
This sampling device includes cyclones and a filter to
collect particulates, a sorbent trap to collect Cy - GI£
hydrocarbons, impingers, and associated temperature con-
trols, pumps, and meters. The sample is obtained from the
flue gas duct by means of a probe inserted through the duct
work and positioned to intersect the gas flow at a point
having flow characreristics representative of the bulk flow.
Particulates are removed from the sample first,
passing it through a series of cyclones. For the SRC tests,
these cyclones were maintained at a temperature of 400°F.
Particulates are collected in three size ranges, >10/*, 3 to
10 M , and 1 to 3At , respectively. The cyclones are followed
by a standard fiberglass filter, which collects a fourth
size range, < 1M .
Gas leaving the filter is cooled to approximately
68°F and passed through a cartridge containing XAD-2 resin.
This resin absorbs a broad range of organic compounds. Con-
densate produced when the gas is cooled is collected in a
condensate trap.
A series of three impingers foHowes the resin
cartridge. The first contains hydrogen peroxide solution,
which removes reducing components to prevent deterioration
of the following impinger solutions. The second and third
impingers, containing ammonium thiosulfate and silver nitrate,
collect volatile inorganic trace elements.
Next, the gas passes through a dehydrating agent,
in order to protect the pump which follows. Finally, the
gas flow rate is metered, and the gas is vented.
During Level 1 sampling, fugitive air emissions
are usually sampled utilizing a high volume sampler with an
XAD-2 absorbent trap for collecting gaseous hydrocarbons.
See Figure 8. This method is used when a specific source
such as a coal pile generates a highly diffuse cloud over an
extensive area. When a specific source generates an emission
that might be broadly classified as a plume, a SASS train is
used. In the case of waterborne emissions, plug collectors
(see Figure 9) are used for collecting surface runoff.
Liquid and slurry samples are collected by heat
exchange, trap sampling, or dipper sampling. Figure 10
shows the heat exchanger system recommended for high temp-
erature lines. Solids are collected by either shovel grab
samples or boring techniques. Level 1 a single grab samples
is taken. During Level 2 a composite is made of a series of
grab samples gathered.
84
-------
00
Ui
STACK T.C.
HEATER
CON-
TROLLER
CONVECTION
OVEN
FILTER
GAS COOLER
IMP/COOLER
TRACE ELEMENT
COLLECTOR
CONDENSATE
COLLECTOR
DRY.GAS METER ORIFICE METER
CENTRALIZED TEMPERATURE
AND PRESSURE READOUT
CONTROL MODULE
10 CFM VACUUM PUMP
Figure 7. Source Assessment Sampling Schematic
-------
1/4 INCH
SWAGE LOK
BULKHEAD
COPPER
TUBING
WALL
Figure 8. Expanded View of Connections of XAD-2
Cartridge to High Volume Sampler
86
-------
GROUND WATER
SEEPAGE
SURFACE WATER
ENTRANCE
Figure 9. Plug Collector for Fugitive Water Samples
87
-------
00
oo
COOLING COILS
TO
SAMPLE
COLLECTION
PROCESS LINE
NATURAL CIRCULATION SAMPLING SYSTEM
(HIGH PRESSURE, HIGH TEMPERATURE)
RESERVOIR
PROCESS LINE
FORCED INJECTION SAMPLING SYSTEM
(SUBATMOSPHERIC PRESSURE, HIGH TEMPERATURE)
Figure 10. Sampling Apparatus for HPHT (High Pressure High Temperature) Lines
-------
3. TEST PROGRAM DEVELOPMENT
a. Introduction
During the past year work was performed on two
major test programs. A suggested sampling plan for the Ft.
Lewis, Washington Solvent Refined Coal Pilot Plant, operated
by Pittsburgh and Midway, is nearing completion. The pur-
pose of this task is to provide guidance in a multimedia
sampling program. Much of the information was exerpted from
the IERL-RTP Procedure Manual: Level 1 Environmental Assess-
ment (EPA-600/2-76-160a). The phased approach and sampling
methodologies were the basis for the document.
A test plan was also developed for a combustion
test at Georgia Power Company's Plant Mitchell where Solvent
Refined Coal was burned for the first time in a commercial
utility boiler. The test occurred, and samples were collected.
A paper on the subject was delivered at the EPA Symposium on
Environmental Aspects of Fuel Conversion Technology, III in
Hollywood, Florida. The major portion of the analysis is
currently being performed and a final report of the test
will be prepared when these results are available.
b. Test Plan for The SRC Pilot Plant
The coal liquefaction plant at Ft. Lewis, originally
designed to operate via the SRC process, has been modified
to the "SRC-II" configuration. The SRC process removed
essentially all of the ash and pyritic sulfur and more than
half of the organic sulfur contained in the coal feed. It
made a solid product that could be pulverized and burned in
the same manner as the coal. The SRC-II process recycles a
portion of the product slurry as solvent which increases the
conversion of coal to lower molecular weight fuels thus
making a liquid rather than a solid product. It is less
complex than the original process and eliminates the dif-
ficult filtration step to remove ash from the coal.
All process and waste streams including fugitive
emissions were identified in the plant. A comprehensive
test plan was outlined for all of these solid, liquid and
gaseous streams. However due to time and economic con-
straints, a limited number of streams can be sampled under
this program. In order to select streams for,the sampling,
the various process and waste streams were categorized as
follows:
• Category I: This category includes all air,
water, and solid waste streams that directly
89
-------
impact the environment. Included in this
category are vents, fugitive emissions,
effluents from the wastewater treatment plant
and solids to be disposed of in landfills.
Also included in this category are the streams
feeding the flare, product streams, and raw
water.
• Category II: In this category are all waste
streams prior to treatment or combination
with other streams, and subsequent discharge
into the environment. "Treatment" includes
incineration, particulate removal, wastewater
treatment and other control technologies.
• Category III: All identified process streams,
except product streams, fall into this cate-
gory.
Only Category I streams will be sampled under
Phase I of this test program. Should additional testing
occur, some Category II streams may be sampled, in addition
to more intensive testing of some of the Category I streams.
At this time it is anticipated that no Category III streams
will be included by EPA during this sampling program. It
would be valuable if these streams could be tested by ERDA
in the course of the pilot plant program and preferably at
the same time as the environmental sampling.
Level 1 testing will provide a basis for selecting
which streams should be sampled again, the type of sampling
program, and what specific analyses should be performed.
Streams with high concentrations of hydrocarbon, particulates,
toxic compounds, trace metals, BOD's etc. will be identified.
Some streams may be eliminated from further study. The
Phase II program will be used to prepare an environmental
assessment of the Ft. Lewis Facility.
Samples and subsequent analyses performed during
Phase II will be directed toward those streams selected for
more study, measuring actual discharge rates and levels of
specific components found in Phase I. These samples will
consist of continuously withdrawn sample streams, weight or
volume proportioned composites, or other representative
portions of the streams under study. Where continuous moni-
toring is feasible this may prove to be a preferred tech-
nique .
During the sample period, stream data must be
obtained as well. Flow rates, including the variation in
flow rate must be known to prepare representative composites.
This is necessary to determine the total discharge quantity
of the constitutents under study. Where the stream flow
90
-------
varies, continuous recording of the instantaneous flow may
be necessary.
In addition to flow rates, stream conditions and
properties must be determined. Temperature and pressure
obviously must be known. It will be necessary to know the
density, also if volumetric flows are recorded. Ultimately,
the properties which will be of interest will be determined
by the specific streams under study.
In Phase II streams that have not been sampled
during Phase I may be sampled. This situation could arise
if, for example, a control module having multiple feed
streams (which were not sampled in Phase I) shows an un-
expected component in its discharge. In such as case it may
be necessary in Phase II to sample all of the streams feeding
the module to determine the component source.
Sampling during Phase II should extend over a rep-
resentative time span. The minimum period would be on the
order of one shift. In some cases it may be as long as
several days to a week, and run throughout all three shifts.
This will ensure the plant operating variations are included
in the sample period.
Phase II analysis will be quantitative instead of
qualitative. It will focus on a few components of interest.
Results of the Phase II effort will define quantities of
specific materials being discharged and point out areas
needing additional control technology development.
Identification and quantification of constituents
suspected of being present will be performed. Specific
polynuclear aromatic hydrocarbons, trace metals, and in-
organic compounds such as cyanides are likely pollutants to
be tested for.
With the sampling and analysis results, an assess-
ment of effluents from the Fort Lewis SRC pilot pant can be
prepared. This information would prove invaluable in anti-
cipating pollutant levels at a full size commercial SRC
facility. Planning and design of the commercial facilities
can be partially based upon these results.
c. SRC Combustion Test
On June 14th, 1977 Solvent Refined Coal was burned
in a commercial utility boiler for the first time, for the
purpose of determining whether SRC could replace coal as a
primary fuel in a pulverized coal-fired boiler. In addition,
to boiler efficiency tests, flue gas samples were collected
and analyzed.
91
-------
Both EKDA and its contractors, and EPA and its
contractors including Hittman Associates) Inc., were in-
volved in this combustion test. Preliminary results have
been obtained and Hittman Associates, Inc., has prepared a
paper discussing these data. The test was conducted in
three phases.
In Phase I of this program, low sulfur Kentucky
coal was burned in the existing, unmodified 22-1/2 Mw pulver-
ized coal boiler. Following replacement of the original
burners with dual register burners and accompanying modifica-
tions, Phase II of the test was conducted. In this phase,
as in Phase I, the boiler was fired with low sulfur Kentucky
coal. In Phase III, following adjustment of the burners and
the pulverizers, SRC was burned. In each of the three
phases of the program, the boiler was operated at full
(approximately 21 MW), medium (approximately 14 MW) , and low
(approximately 7 MW) load conditions.
Precipitator efficiency tests were run, ash resis-
tivity was determined, and air emission levels were evalu-
ated using EPA-5 and ASME trains. In addition to particulates,
a number of gases, including CC>2, CO, N2, ®2> an<* S02 were
monitored.
In addition, during Phases II and III, flue gas
sampling was conducted using a SASS train to collect samples
for laboratory analysis, using a modified EPA Level I proce-
dure. Grab samples were obtained for on-site analysis for
GI - G£ hydrocarbons, SOX, N2, CO, and ©2-
Results of the SASS train analyses are not pre-
sently completed. No bioassays will be performed. However,
in addition to the remainder of the standard Level 1 analyses,
all samples collected that contain organics will be analyzed
for a selected group of polynuclear aromatic hydrocarbons.
Analytical results of the grab samples and contin-
uous monitor indicate that:
• There were no detectable levels of GI - Cg
hydrocarbons.
• SOX and NOX levels were roughly equivalent
with those from low sulfur coal combustion.
• SOy and NO concentrations were highest at
full load and lowest at low load.
92
-------
Observations made during the test include:
• Particulates collected by the SASS train
during combustion were approximately seventy
percent carbon as compared with a typical
coal fly ash of less than ten percent.
• Particle size of SRC ash was much smaller
than that of coal fly ash.
• Precipitator efficiency was drastically
reduced probably due to the high resistivity
of the high carbon ash
Once results of SASS train sample analyses are available, a
detailed report will be prepared interpreting these results.
4. INPUT-OUTPUT MATERIALS CHARACTERIZATION
Available input-output materials characterization for
coal liquefaction processes is usually incomplete or not in
a form suitable for environmental assessments. Since commer-
cial coal liquefaction facilities do not exist, most studies,
whether for economic analysis, engineering projection,
process assessment, or environmental consideration, have had
to use conceptualized models for solid waste and residue
use/disposal, treatment/control technology, auxiliary facil-
ities, liquid/ solid separation, and other modules necessary
for full-scale operation. Basing input-output materials
characterization on conceptualized models gives only esti-
mates of the environmental discharges, but it is the only
method currently available.
Input-output materials characterization for coal lique-
faction processes may be put in a form suitable for environ-
mental assessments by use of the following available data:
• Reported material balances
• Use of deposited sample analyses
• Physical-chemical relationships
• Analogies with other processes
• Comparisons with other industries
• Conceptualized modeling of missing process
modules.
93
-------
These data sources are discussed in the following paragraphs.
a. Reported Material Balances
Material balances, either actual or conceptual,
have been reported for several coal liquefaction processes.
Coal compositions are also available from various reported
sources. Partial material balances in the form of effic-
iencies, or barrels of products per ton of coal, have also
been published. Putting all of this published information
together provides a framework for overall environmental
characterization of the processes.
b. Use of Reported Sample Analysis
Reports of products and/or waste stream analyses
go all the way back to the German Bergius process of World
War II. Although these data are incomplete, they can be
used to provide a more detailed description of the environ-
mental discharges than can be obtained from material balance
information. Invariably the analysis has shown that coal
liquefaction product and residue waste streams contain large
quantifies of aromatics, particularly polynuclear aromatic
hydrocarbons. Wastewater streams contain phenolics, organ-
ics, and inorganics.
Ash samples contain metals and inerts. Residues
contain ash, char, and high boiling polynuclear aromatic
hydrocarbons. The combination of material balance quan-
tities with the reported stream compositions starts to
define environmental discharges.
c. Physical-Chemical Relationships
In the absence of any detailed information on
material balance and sample analysis data, physical-chemical
relationships may be used to predict the discharge pattern
of coal liquefaction products and wastes. Coal liquefaction
introduces a known composition and amount of coal and hydro-
gen into the liquefaction process. Inerts such as non-
volatile metals, rock and dirt will pass through the system
and emerge unchanged. Some of the coal and hydrogen will be
transformed into new organic products and wastes in the
hydrogenation module. All subsequent process operations
separate the effluent from the hydrogenation into desirable
fractions, usually through physical-chemical particle size,
flammability, thermal stability and other physical-chemical
relationships. Using a knowledge of these properties, the
environmental discharges from the coal liquefaction process
can be further refined.
94
-------
d. Analogies With Other Processes
Input-output characterization data from coal
liquefaction processes is often available in pieces. For a
given process, the amount and composition of one envir-
onmental effluent may be available, but not the others. For
another process, the amount and composition may be available
forgone or more of the other streams. By combining infor-
mation on analogous streams, effluent amounts and compositions
may be estimated for the overall processes. This method
also provides cross-checks on the similarity or differences
of products and wastes from the different processes.
e. Comparisons with Other Industries
Input-output materials characterizations can be
drawn from industries with similar products and wastes. The
most similar industry to coal liquefaction is the coal tar
industry. Prior to the advent of readily available and low
cost petrochemicals, the coal tar industry supplied most of
the inorganic chemicals for industrial purposes. Aromatic
and polynuclear compounds comprise: a large portion of coal
tar, which when fractionated yields products ranging from
benzene and phenols to tars and asphalts. It is expected
that many of the workplace and environmental problems with
coal liquefaction will be similar to those for coal tar
operations.
The petroleum industry is a second industry which
has analogies with coal liquefaction processes. Fractiona-
tion and recovery of products by physical-chemical tech-
nology, treatment/control of atmospheric, waterbome and
residue wastes has received extensive attention in this
industry and some of the developed technology is applicable.
Coal-fired utility boilers and coal gasification
operations have waste residues and ashes similar to coal
liquefaction. Metal and inert composition data on these
residues can be useful in defining the environmental dis-
charges expected from coal liquefaction and the solubility,
leachability and other characteristics of these wastes.
f. Conceptualized Modeling of Missing Process Modules
In the absence of defined process modules, it is
necessary to model the missing portions. Eventually, the
coal liquefaction processes may be expected to develop their
own fine structure, with all the complexity of a modern-day
petroleum refinery. The scale-up from bench scale, to PDU
status, to pilot plant size shows a marked proliferation in
95
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process equipment and function. A similar increase in
equipment complexity and specialized function may be expected
for commercial units. Similarly, development of processes
and commercialization may be expected to increase the effici-
ency of conversion from coal to products and reduce the
environmental discharges.
Three points can be made for this projected pattern:
• Conceptualized modeling of missing process
modules should given conservative environ-
mental discharge values.
• Until specific commercial processes are
available, conceptualized modeling using
general modules can be used to define environ-
mental discharges with satisifactory accuracy.
• To date environmental discharges have been
related to specific processes. In the future,
the definition of environmental discharges
will depend more on the product(s) desired
and the process variables needed to obtain
them than on the process itself.
Tables 2, 3, 4, and 5 give preliminary input-
output materials characterizations for four conceptualized
50,000 bbl/day commercial coal liquefaction facilities. At
this point in the input characterization development, the
similiarities should be stressed rather than the differences.
For example, the bottoms fraction from this EDS process
consists of 4,866 tons per day, while the Synthoil process
has only 3,536 tons per day of char after pyrolysis through
a multiple hearth furnace (conceputalized by Synthoil develop-
ers) . Pyrolysis or other treatment of EDS bottoms could
reduce the amount of bottoms to a lower figure comparable to
the Synthoil char. Similar treatment could reduce the 5482
tons per day of solid wastes from the H-Coal process. The
similarity is that all four processes have 3500 to 5500 tons
per day of solid and residue waste for use/treatment/disposal.
This quality of solid and residue waste represents a signifi-
cant area of environmental discharge which needs to be given
priority attention. Similar attention needs to be given to
treatment/control technology for process wastewater and air
emissions.
96
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TABLE 2. INPUT-OUTPUT MATERIALS FOR 50,000 BEL/DAY
SYOTHDIL SYSTEM (TONS/DAY)
In
1. Prepared coal 16,667
2. Water injection 1,904
3. Make-up gas (44% H2) 1,519
4. Make-up water (in the 61
acid gas removal)
5. Chemicals (make-up to 12
the anrine system)
TOTAL 20,163
Out
1. Heavy product 7,090
2. Light product 1,705
3. By-product (liquid) 1,254
4. By-product (gas) 729
5. Acid gas to sulfur 1,840
recovery
6. Char 3,536
7. Wastewater (total) 4,009
TOTAL 20,163
97
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TABLE 3. INPUT-OUTPUT MATERIALS FOR 50,000 BBL/DAY
H-OOAL SYSTEM (TONS/DAY)
1. Dry pulverized coal
2. Make-up gas (45%
TOTAL
Out
19,122 1. Ammonia 115
1,582 2. Sulfur 799
20,704 3. Phenol 13.5
4. Naptha 1,550
5. Product oil 8,000
6. Gases 2,600
7. Wastes 5,873.5
8. Water 1,753
TOTAL 20,704
98
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TABLE 4. INPUT-OUTPUT MATERIALS FOR 50,000 BEL/DAY
EXXON DONOR SOLVENT SYSTEM (TONS/DAY)
Li
1. Raw coal 18,181
2. Hydrogen 579
TOTAL 18,760
Out
1. Hydrogen sulfide
2. Anmonia
3. Phenols
4. OL
5. C2
6. C3
7. 04
8. Light naptha
9. Heavy naptha
10. Middle Distillate
11. Heavy fuel oil
12. Bottoms
13. H20
14. Hydrogen
TOTAL
485
227
20 (est)
134
84
89
37
886
2,866
6,234
54
5,441
2,118
85
18,760
99
-------
TABLE 5. INPUT-OUTPUT MATERIALS FOR 50,000 BEL/DAY
SRC SYSTEM (TONS/DAY)
1. RCM coal (5% moisture) 31,520
2. Oxygen 2J45
3. Water 45,774
TOTAL 80,039
Out
1. SNG 3,414
2. LPG 964
3, Naptha 786
4. Fuel oil 5,061
5. SRC 10,649
6. Sulfur 517
7. Ammnrpfl 70
8. Phenol 37
9. Residue & Slag 5,090
10. Water losses 39,528
11. Waste gases 13,923
TOTAL 80,039
100
-------
E. TECHNOLOGY TRANSFER (INPUT-OUTPUT)
1. STANDARDS OF PRACTICE MANUAL
The first Standards of Practice Manual for a coal
liquefaction process is under preparation by Hittman Associates,
Inc., Columbia, Maryland. The SPM is designed to furnish
environmental guidelines and best control/disposal options
for liquefaction processes currently under development.
The SRC-1 process was chosen for the study. A pilot
plant for the process has been operated by ERDA at Fort
Lewis, Washington since September 1974. It was felt that a
definitive study of the process and its waste streams, and
their optimum treatment methodologies would provide a
service to the future commercialization of this process.
Progress includes completion of material balances for
the process and waste streams. From this basis, written and
schematic descriptions of process modules and control/dis-
posal modules were added. Best control/disposal practices
have been selected for all wastestreams. Pertinent federal,
state and local environmental standards have been assembled
relative to a projected plant location. Partially complete
are descriptions of environmental emissions and factors
achievable and control/disposal costs.
Remaining work includes a detailed description of the
basic process, which will outline control options for
specific emissions and their respective costs for each
module. A large portion of this effort will consist of
assembling information from previous sections of the manual
and summarizing them into clear, succinct unit operations
for each module. Estimated completion date is October 31.
101
-------
APPENDIX A
Process Flow Diagrams
A-l
-------
COAL
SIZING
DRYING
&
SLURRYING
MAKE
UP
H20,
GASIFICATION
HYDROCARBON
GASES
RECYCLE H,
RECYCLE
OIL
SLURRY
FEED STREAM
SYNTHOIL
(HYDROGENATION)
GAS PURIFICATION
SYSTEM
CARBONACEOUS NH3*H2S'H2°
RESIDUES
GASES
PYROLYSIS
SOLIDS
PRODUCT
OIL
PRODUCT
STREAM
GAS
SEPARATION
LIQUIDS AND
UNREACTED
SOLIDS
SOLIDS
SEPARATION
LIQUIDS
PRODUCT
OIL
Figure 1. Synthoil System
A-2
-------
COAL
HYDROGEN
GENERATION
HYDROGEN
RECYCLE
HYDROGEN
RICH GAS
GAS
CLEAN-UP AND
SULFUR RECOVERY
I
AMMONIA
LIGHT
HYDROCARBONS
SIZING
AND
DRYING
SLURRY
PREPARATION
PREHEATING
H-COAL
(HYDROGENATION)
PRODUCT
SEPARATION
RECYCLE
OIL
^ LIQUID
PRODUCTS
HEAVY
BOTTOMS
SULFUR
Figure 2. H-Coil System
A-3
-------
o
CO
o
LU
o:
COAL
FeS,
I
DRYING
CATALYST
GRINDING &
PASTING
RECYCLE RAS
SCRUBBING
>
PREHEATING
MAKE-UP
H2
1
BERGIUS
;HYDROGENATION
GAS-LIQUID
SEPARATION
LIGHT OIL
DISTILLATION
SOLIDS
SEPARATION
CAKE
LIGHTS
COKING
I
MID-OIL
AND
GASOLINE
SOLIDS RECYCLE
Figure 3. Bergius System
A-4
-------
COAL
RECYCLE
SOLVENT
COAL PREPARATION
AND HANDLING
SRC
(HYOROGENATION)
SOLIDS
SEPARATION
FILTRATE
WASH
SOLVENT
RECYCLE
HYDROGEN
GAS CLEANUP
AND BYPRODUCT
RECOVERY
SOLVENT
RECOVERY
HYDROCARBONS
AND WATER
SULFUR
MINERAL
RESIDUE
SRC PRODUCT
LIGHT
LIQUIDS
KEY
SRC II
Figure 4. Solvent Refined Coal System
A-5
-------
LIGNITE
SYNTHESIS
GAS
OR
CO
SIZING
SLURRY
PREPARATION
COSTEAM
(HYDROGENATION)
(INDIRECT)
PRODUCT
SEPARATION
FUEL OIL
PRODUCT
GAS
SOLIDS
RESIDUE
Figure 5. COSTEAM System
A-6
-------
>
CRUSHED
COAL
COED GAS
PYROLYSIS
GAS
FLUIDIZING
GAS
GAS SCRUBBING
AND PROCESSING
OIL RECOVERY
AND FILTRA-
TION SECTION
COED OIL
H
FIXED-BED
HYDRO-
TREATMENT
PRODUCT
GAS(ES)
SYNTHETIC
CRUDE OIL
CHAR
PRODUCT
Figure 6. COED Syst
em
-------
PULVERIZED COAL
STORAGE
COED
STAGE I
(PYROLYSIS)
CHAR TO
STAGE II
RECYCLE
GAS
GASES AND
VAPORS
PARTICIPATE
REMOVAL
GAS SEPARATION
OIL TO
-»» SOLID-LIQUID
SEPARATION
(FILTRATION)
Figure 7. Stage I COED System
A-8
-------
CHAR FROM STAGE I
STAGE II
PARTICULATE
REMOVAL
STAGE III
STEAM
&
OXYGEN
OIL-WATER
SEPARATION
STAGE IV
CHAR COOLING
GAS TO
ACID GAS
REMOVAL
TO
PYROLYSIS
SECTION
OIL TO
SOLID-LIQUID
SEPARATION
(FILTRATION)
WATER TO
• GAS
SEPARATION
CHAR TO
STORAGE
Figure 8. Stages II, III and IV COED System
A-9
-------
COAL
SIZING
AND
DRYING
COALCON
(HYDROCARBON-
IZATION)
CHAR
HYDROGEN
RICH GAS
HYDROGEN
HYDROGEN
GENERATION
GAS-LIQUID
PRODUCT
SEPARATION
GAS CLEANUP
AND BY-PRODUCT
RECOVERY
TO METHANATION
FOR SNG
PRODUCTION
•»• ASH
•*- SULFUR
•+* AMMONIA
LIGHT OIL
PRODUCT
i
FUEL OIL '
PRODUCT
Figure 9. Coalcon System
A-10
-------
COAL
R!CH
RECYCLE
GAS
CC
(CARBONIZA-
TION)
CHAR
COKING
SIZING &
DRYING
LIQUID
PROCESSING
GAS CLEANUP
AND
BY-PRODUCT
RECOVERY
CC
(HYDROGENA-
TION)
SEPARATION
MEDIUM
OIL
ASH
CHEMICAL
FEEDSTOCKS
FUEL GAS
AND
BY-PRODUCTS
METALLURGICAL
COKE
Figure 10. Clean Coke (CC) System
A-ll
-------
COAL
H£S
GAS
SIZING
AND
DRYING
PREHEATING
COAL
i
PURIFICATION
SEPARATION
L
LIQUID
PRODUCTS
TOSCOAL
(PYROLYSIS)
CHAR
HOT
BALLS
BALL
HEATING
CHAR
COOLING
CHAR
HOT FLUE GAS
AIR
& FUEL
Figure 11. Toscoal System
A-12
-------
COAL
SIZING
AND
DRYING
HEATED
CHAR
AIR
ORC
(PY-ROLYSIS)
CHAR
HEATING
AND
SEPARATION
•*• FLUE GAS
PRODUCT
SEPARATION
GAS PROCESS-
ING AND
SULFUR
RECOVERY
TAR
HYDROTREATING
PIPELINE
*- GAS
SULFUR
_^ SYNTHETIC
CRUDE
Figure 12. ORC System
A-13
-------
COAL
SIZING
STEAM
OXYGEN
GASIFICATION
GAS
PURIFICATION
& SULFUR
RECOVERY
FISCHE3-
TROPSCH
SYNTHESIS
PRODUCT
SEPARATION
SULFUR
HYDROCARBON
PRODUCTS
__ PRODUCT
SNG
Figure 13. Fischer-Tropsch (F-T) System
\-
A-14
-------
COAL
RECYCLE
DONOR
SOLVENT
PRODUCT
STORAGE
SIZING
AND
DRYING
HYDROGEN
EDS
(HYDROGENATION)
SPENT
SOLVENT
SOLVENT
HYDROGENATION
SEPARATION
BOTTOMS
HYDROGEN
GENERATION
GAS (FOR FUEL
AND HYDROGEN
GENERATION)
RAW COAL
LIQUID
PRODUCT
ASH
Figure 14. Exxon Donor Solvent (EDS) System
A-15
-------
COAL
SIZING AND
DRYING
PREHEATING
GASIFICATION
SHIFT
CONVERSION
ACID GAS
REMOVAL
METHANOL
(SYNTHESIS)
SULFUR
RECOVERY
ASH
SULFUR
METHANOL
PURIFICATION
Figure 15. Mehtanol System
A-16
-------
COAL
CHAR-«-
SIZING AND
DRYING
SGE
(EXTRACTION)
SOLVENT
SEPARATIONS
•*• FUEL GAS
_^ EXTRACT
PRODUCT
Figure 16. Supercritical Gas Extraction (SGE) System
A-17
-------
APPENDIX B
Federal and Selected
State Regulations
B-l
-------
Key to symbols and abbreivations applicable to all tables of
i1
the Appendix.
max denotes maximum
AAM denotes Annual Arithemtic Mean
AGM denotes Annual Geometric Mean
* denotes that the maximum value is not to be exceeded
more than once per year.
JTU denotes Jackson Turbidity Units
COH/1000 LM denotes Coefficient of Haze per 1000 linear meters
COH/1000 LF denotes Coefficient of Haze per 1000 linear feet
B-2
-------
Table 1. National Primary and Secondary Ambient Air Quality Standards
Concentration
Constituent
Sulfur Oxides
primary
secondary
Particulates
primary
secondary
Carbon Monoxide
primary and
secondary
Photochemical Oxidants
primary and
secondary
Hydrocarbons
primary and
secondary
Nitrogen Dioxide
primary and
secondary
Metric
80 ug/m3
365 ug/m::
1300 ug/nT
75 ug/mi:
260 ug/m::
6C ug/mi
150 ug/nT
10 ug/m3,
40 ug/nr
160 ug/m
160 ug/m
100 ug/m
English
-4 3
9.4x10 ^grain/ydr
4.3xlO"«grain/yd,
l.SxlO'Vain/yd-3
S.SxlO'^grain/yd3
3.1xlO"fgrain/ydi
7. IxlO'-tg rain/yd^
1. 8x1 0~ ''grain/yd
0.12 grain/yd^
0.79 grain/ydj
1.9xlO~3grain/yd3
1.9xlO"3grain/yd3
1.2xlO"3grain/yd3
Remarks
A.A.M.
24 hr max*
3 hr max*
A.G.M.
24 hr max*
A.G.M.
24 hr max*
8 hr max*
1 hr max*
1 hr max*
3 hr max*
(6-9 A.M.)
A.A.M.
Reference Conditions: Temperature = 25°C = 77°F
Pressure = 760 mm Hg = 29.92 in Hg = 1 atmosphere
B-3
-------
Table 2 . Federal New Source Performance
Standards of Related Technologies
Coal Preparation - Particulates
Type of Equipment
Thermal Dryers
Coal Cleaning
Processing, Conveying
and Storage
Fossil Fuel Steam Generators
Constituent
Particulates
Sulfur Dioxide (solid fuels)
Nitrogen Oxides (solid fuels)
Petroleum Liquid Storage Vessels
Constituent
Hydrocarbons
Metric
.057 mg/m-
.033 mg/m
Standard
English (
2.2xlO-Jgrain/yd5
1.3xlO"^grain/ydJ
Jpacit
20%
10%
?n*
Standard
Metric English
0.17 kg/iojjkcal 0.10 Ib/lOJJBtu
2.07 kg/lOjkcal 1.21 lb/10:Btu
1.21 kg/10°kcal 0.70 lb/10°Btu
Opacity
20% (1)
Vapor Pressure
Requirement
Metric
78-570 mm Hg
570 mm Hg
English
3.0-22.4 in Hg
22.4 in Hg
(2)
(3)
(1) 40% opacity allowed 2 minutes/hr
(2) floating roof or vapor recovery system or equivalent
(3) vapor recovery system or equivalent
B-4
-------
Table 3 . Federal Effluent Guidelines and
Standards for New Sources
Coal Preparation
Concentration
Constituent
Total Iron
Total Manganese
Total Suspended Solids
pH range: 6.0-9.0
By-Product Coking
1 day maximum
mg/1 g
7.0
4.0
20.0
rain/gallon
0.41
0.23
1.17
30 day
mg/1
3.5
2.0
35.0
average
grain/gallon
0.20
0.12
2.04
Concentration
Constituent
Cyanide A
Phenol
Ammonia 1
Sulfide
1 day maximum
kg/kkg
3 x 10"4
6 x 10"4
.26 x 10"2
3 x 10"4
Ib/ton
7.26 x 10"4
1.45 x 10"3
3.05 x 10"2
7.26 x 10"4
30 day
kg/kkq
1 x 10"4
2 x 10"4
4.2x 10"3
1 x 10"4
average
Ib/ton
2.42 x
4.84 x
1.02 x
2.42 x
io-4
io-4
io-3
io-4
Total Suspended
Solids
pH range: 6.0-9.0
3.12 x 10
-2
7.55 x 10
-2
1.04x10
-2
2.52 x 10
-4
B-5
-------
Table 4 . Some EPA Requirements and Recommendation for Solid Wastes
Aspect of Disposal
Requirement
Recommendations
Design
approval by
professional engineer
and responsible
agency
analysis of solid
waste materials;
maintenance program;
projection of
subsquent use
Water Quality
compliance with Federal
Water Pollution Control
Act
projections of solid
waste-soi1-groundwater
relationship
Air Quality
compliance with clean
air act, state and
local laws
dust control program
Gas Control
On site control of
decomposition gases
preventing gas from
concentrating to
prevent explosions
and toxicity hazards
Cover Material
cover shall be applied
as necessary to
minimize fire, odors,
dust, etc.
minimum of 2 ft.
final cover
Compaction
compaction to the
.smallest practicable
volume
maximum depth of
solid waste layers
(2 ft)
B-6
-------
Table 5 . Ambient Air Quality Standards in Alaska
Constituent
Particulates
Sulfur Oxides
Maximum Concentration Allowed
Carbon Monoxide
Photochemical Oxidants
Nitrogen Dioxide
Reduced Sulfur Compounds
Metric
60 ug/m3
150 ug/m3
80 ug/m"
365 ug/m*
1300 ug/m3
10 ug/m*
40 ug/nT
160 ug/m*
100 ug/m*
50 ug/m*
English
7.1xlO"4grain/yd3
1.8xlO"3grain/yd3
-4 3
9.4x10 grain/yd
4.3xlO"3grain/yd3
1.5xlO"2grain/yd3
0.12 grain/yd3
0.47 grain/yd
1.9xlO~3grain/yd3
1.2x10"3grain/yd3
6.0xlO~4grain/yd3
Remarks
A.G.M.
24 hr max*
A.A.M.
24 hr max*
3 hr max*
8 hr max
1 hr max
1 hr max
A.A.M.
30 min max
Reference Conditions: Temperature = 21°C = 70°F
2
Pressure = 1.03 kg/cm = 14.7 psi = 1 atmosphere
B-7
-------
Table 6 . Emissions Standard for Industrial
Processes and Fuel Burning Equipment in Alaska
Visible Emissions
20% opacity +
3 3
Particulate Matter mg/m grain/ft
(coal burning equipment) 4.24 0.05
8.48 0.1
Sulfur Compounds (SO.,)
500 ppm
denotes that the standard may not be exceeded for a total of more
than three minutes in any hour.
B-8
-------
Table 7 . Water Quality Criteria of Alaska
Parameter
Dissolved Oxygen
Water Classification
Potable Water
Industrial Water
5 mg/1 =0.29 grain/gal
75% saturation or
5 mg/1 =0.29 grain/gal for surface water
pH and (pH change)
6.5-8.5 (0.5 units)
6.5-8.5 (0.5 units)
Turbidity
5 JTU
No interference with
water supply treatment
Temperature
16°C = 60°F
21°C = 70°F
Dissolved Inorganic
Substances
500 mg/1 = 29 grain/gal
low enough to prevent
corrosion, scaling
and process problems
Residues, Oils,
Grease, Sludges, Other
Physical and Chemical
Criteria
essentially free from;
may not exceed 1962
USPHS Standards
(see Table 43)
No visible evidence
of residue may not
impact public health
B-9
-------
Table 8 . Ambient Air Quality Standards of Arizona
Constituents
Particulates
Sulfur Dioxide
Concentration
Metric
60 ug/nf
150 ug/m3
*i
50 ug/m"
260 ug/m*
1300 ug/nT
English
7.1xlO"4grain/yd3
1.8xlO~3grain/yd3
-4 3
6.0x10 grain/yd
3.1xlO~3grain/yd3
1.5xlO~2grain/yd3
Remarks
A.G.M.
24 hr max
1 yr max
1 day max
3 hr max
Non-Methane Hydrocarbons
160
1.9xlO"3grain/yd3
3 hr max
(6-9 A.M.)
Photochemical Oxidants
Carbon Monoxide
160
40 mg/m
10 mg/iTf
1.9xlO"3grain/yd3
0.47 grain/yd*
0.12 grain/yd*
1 hr max
1 hr max
8 hr max
Nitrogen Dioxide
100
1.2xlO"3grain/yd3
1 yr max
Air Quality Goals
Constituent Metric
Particulates 100 ug/nf
Non-Methane Hydrocarbons 80 ug/m"
English
1.2x10" Vain/yd
9.4xlO"4grain/yd3
Remarks
24 hr max
3 hr max
(6-9 A.M.)
Carbon Monoxide
Photochemical Oxidants
7 mg/m"
80 ug/mj
0.083 grain/yd*
9.4xlO"4grain/yd3
8 hr max
1 hr max
Standard Conditions: Temperature = 16°C = 60°F
o
Pressure = 1.03 kg/cm = 14.7 psi
B-10
-------
Table 9 . Industrial Emissions Standards in Arizona
Participate Emissions - Process Industries - General
E = 55.0 p°'n-40 (E = 17.31 p°'16 for Phoenix-Tucson Air Quality
Control Region)
where
E = max allowable emissions rate (Ib m/hr)
P = process weight rate (ton m/hr)
For commercial SRC plants
20.000 ton/day ,,
E = 55.0 (24 hr/day) "-40 = 75.2 Ib m/hr = 16 £4 kg/hr
E = 17.31 p°*16 = 50.8 Ib m/hr = 111.9 kg/hr (Phoenix-Tucson)
Sulfur -other industries
Requirement: a minimum of 90% removal
Storage of volatile organic compounds
(for storage capacities of 65,000 gallons or greater)
Requirement3 A floating roof is required for compounds with vapor
2
pressures greater than 2 Ib in but less than
2
12 Ib/in . Equipment of equal efficiency may be
substituted. The pressure range in metric units
is from 0.1406 kg/cm2 to 0.8436 kg/cm2.
B-ll
-------
Table 10. Arizona Water Quality Criteria
Limiting Concentration
Substance mg/1 grain/gallon
Arsenic 0.05 0.0029
Barium 1.0 0.0584
Cadmium 0.01 0.0006
Chromium (Hexavalent) 0.05 0.0029
Copper 1.0 0.0584
Cyanide 0.2 0.0117
Mercury 0.005 0.0003
Lead 0.05 0.0029
Phenol 0.001 5.8xlO"5
Selenium 0.01 0.0006
Silver 0.05 0.0029
Zinc 5.0 0.2921
For waters supporting aquatic life the following standards exist:
pH: 6.5 to 8.6 with no discharge causing a change in pH of more
than 0.5 pH units.
Temperature: maximum temperature= 34°C = 93°F
maximum temperature increase= 2.8°C = 5°F
B-12
-------
Table 11. Standards of Performance for Petroleum
Refineries in Colorado
Participates
1 kg/kkg = 1 lb/1000 Ib
30% opacity for greater than 3 minutes in any hour is not allowed.
Failure to comply due to uncombined water is not a violation.
Carbon Monoxide
Discharge gases may not contain greater than 0.050% carbon
monoxide by volume.
Sulfur Dioxide
Emissions may not exceed those resulting from fuel gas containing
230 mg/dscm (0.10 grain/dscf) of hydrogen sulfide.
B-13
-------
Standard
Settleable Solids,
Floating Solids,
Taste, Odor, Color,
and Toxic Materials
Table 12. Colorado Water Quality Standards
Water Classification
Al_ A2 Bl
Free From Free From Free From
B2
Free From
Oil and Grease
No film or No film or No film or No film or
discoloration discoloration discoloration discoloration
Turbidity Increase
10 J.T.U.
10 J.T.U. 10 J.T.U.
10 J.T.U.
Dissolved Oxygen
(minimum)
6 mg/1 5 mg/1 6 mg/1 5 mg/1
0.35 grain/ 0.29 grain/ 0.35 grain/ 0.29 grain/
gallon gallon gallon gallon
pH Range
6.5-8.5
6.5-8.5
6.0-9.0
6.0-9.0
Temperature, Maximum 20°C
68° F
32°C
90° F
20°C
68° F
32°C
90° F
Temperature
Maximum Increase
2°F
Streams
Streams
2.8°C
5°F
Lakes
1.7°C
3°F
i.rc
2°F
2.8°C
5°F
Lakes
1.7°C
3°F
B-14
-------
Table 13. Colorado Effluent Discharge Criteria
7 day avg. 30 day avg.
Parameter mg/1 grain/gal. mg/1 grain/gal
BOD5 45 2.63 30 1.75
Suspended Solids 45 2.63 30 1.75
Residual Chlorine 0.5 mg/1 = 0.03 grain/gal.
Oil and Grease 10 mg/1 = 5.84 grain/gal.
pH range 6.0 - 9.0
B-15
-------
Table 14. Illinois Air Quality Standards
Constituent
Particulates
primary
secondary
Concentration
Metric English
75 ug/nf
260 ug/nf
60 ug/nf
«•
150 ug/nf
*>
Non-Methane Hydrocarbon 160 ug/nf
Carbon Monoxide
Nitrogen Dioxide
Photochemical Oxidants
10 ug/m3
40 ug /m3
100 ug/m
160 ug/m
8.8xlO"4grain/yd3
3.1xlO"3grain/yd3
7.1xlO"4grain/yd3
1.8xlO"3grain/yd3
1.9xlO"3grain/yd3
0.12 grain/yd0
0.47 grain/yd3
1.2xlO"3grain/yd3
1.9xlO"3grain/yd3
Remarks
A.G.M.
24 hr max*
A.G.M.
24 hr max*
3 hr max*
(6.9 A.M.)
8 hr max*
1 hr max*
A.A.M.
1 hrmax*
Reference Conditions: Temperature = 25°C = 77°F
Pressure = 760 mm Hg = 29.92 in Hg
B-16
-------
Table 15. New Process Emissions Standards in Illinois
Visible Emissions: 30% Opacity
Particules: E = 24.8 p°'16
where: E = allowable emissions rate in Ib/hr
P = process wt rate in tons/hr
for an SRC facility processing 20,000 tons/day of coal,
E = 72.7 Ib/hr = 33.1 kg/hr
Sulfur Dioxide: 2000 ppm
Hydrocarbons:
Storage: 85% control, pressurized tanks, or floating roofs for
tanks greater than 151,400 liters (40,000 gallons)
Loading: 3.6 kg/hr (8 Ib/hr) for throughputs exceeding 151,000
liters/day (40,000 gallons/day)
Hydrocarbon - Water Separators: 85% control if capacity exceeds
757 liters (200 gallons)
B-17
-------
Table 16. Selected Water Quality Standards in Illinois
Parameter
pH range
Public Supply/Food Processing
Dissolved oxygen(l)
Ammonia
Arsenic
Barium
Boron
Cadmi urn
Chloride
Chromium (hexavalent)
Chromium (trivalent)
Copper
Cyanide
Fluoride
Iron
Lead
Manganese
Mercury
Nickel
Phenol
Selenium
Silver
Sulfate
Total Dissolved
Solids
Zinc
Oil
6.5 - 9
metric (mg/1)
) 6.0
:) 5.0
1.5
0.01
1.0
1.0
0.01
250
nt) 0.05
t) 1.0
0.02
0.01
1.4
0.3
0.05
0.05
0.0005
1.0
0.001
0.01
0.005
250
500
1.0
0.1
.0
English (qrain/qal)
0.3505
0.2921
0.0876
5. 84x1 O"4
0.0584
0.0584
5. 84x1 O"4
14.6029
0.0029
0.0584
0.0012
5. 84x1 O"4
0.0818
0.0175
0.0029
0.0029
2. 92x1 O"5
0.0584
5. 84x1 O"5
5. 84x1 O"4
2. 92x1 O"4
14.6029
29.2058
0.0584
0.0058
Lake Michigan
7.0 - 9.0
metric (ma/1) .English (grain/gall
of
0.02
0.01
1.0
1.0
0.01
12.0
0.05
1.0
0.02
0.01
1.4
0.3
0.05
0.05
0.0005
1.0
0.001
0.01
0.005
24
180
1.0
0.1
90% •
saturation
0.0012
5.84xlO"]1
0.0584
0.0584
5.84x1O"4
0.7009
0.0029
0.0584
0.0012
5.84x1O"4
0.0818
0.0178
0.0029
0.0029
2.92xlO"5
0.0584
5.84xlO"5
5.84x1O"4
2.92xlO~4
1.4019
10.5141
0.0584
0.0058
B-18
-------
Table 16. Selected Uater Quality Standards in Illinois (Continued)
Temperature varies with specific stream and the month of the year. Maximum
temperatures for the Ohio River are as follows:
Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Oct. Nov. Dec.
Temp.°C 10 10 16 21 27 31 32 32 31 26 21 14
Temp.°F 50 50 60 70 80 87 89 89 87 78 70 57
B-19
-------
Table 17. Illinois Effluent Standards
Constituent mg/1 grains/gallon
Ammonia 3.0 0.175
Arsenic 0.25 0.015
Barium 2.0 0.117
Cadmium 0.15 8.76 x 10"3
Chromium (hexavalent) 3.0 0.175
Chromium (trivalent) 1.0 0.058
Copper 1.0 0.058
Cyanide 0.025 1.46 x 10"3
Fluoride 15.0 0.876
Iron (total) 2.0 0.117
Iron (dissolved) 0.5 0.030
Lead 0.1 5.84 x 10"3
Manganese 1.0 0.058
Mercury 0.0005 2.92 x 10"5
Nickel 1.0 0.058
Oil 15.0 0.876
Phenols 0.3 0.18
Phosphorous 1.0 0.058
Selenium 1.0 0.058
Silver 0.1 5.84 x 10"3
Total Suspended Solids 15.0 0.876
Zinc 1.0 - 0.058
pH (range): 5-10
B-20
-------
Table 18. Allowable Sound Pressure Levels in Illinois
Octave Band
Center Frequency
in Hertz
31.5
63
125
250
500
1000
2000
4000
3000
Allowable Octave Band Sound
Pressure Level in Decibels
Daytime (1)
75
74
69
64
58
52
47
43
40
Nightine (2)
69
67
62
54
47
41
36
32
32
(1) 7 A.M. - 10 P.M.
(2) 10 P.M. - 7 A.M.
B-21
-------
Table 19 . Indiana Ambient Air Quality Standards
Constituent
Sulfur Dioxide
primary
secondary
Particulates
primary
secondary
Carbon Monoxide
primary and
secondary
Photochemical Oxidants
primary and
secondary
Concentration
Metric
80 ug /m3
365 ug /m3
60 ug /m3
260 ug /m3
llOOug/m3
75 ug /m3
260ug/m3
60 "9 /m3
150ug/m3
English
9.4x10 grain/yd
4.3xlO"3grain/yd3
7. lx!0"3g rain/yd3
3.1xlO"3grain/yd3
1.3xlO"2grain/yd3
8.8xlO"4grain/yd3
3.1xlO~3grain/yd3
7.1xlO"4grain/yd3
1.8xlO~3grain/yd3
10 mg/nT
*
40 mg/nT
160 ug
0.12 grain/yd*
*«
0.47 grain/yd'
1.9xlO"3grain/yd3
Remarks
A.A.M.
24 hr max*
A.A.M.
24 hr max*
1 hr max*
A.6.M.
24 hr max*
A.6.M.
24 hr max*
8 hr max*
1 hr max*
1 hr max*
Hydrocarbons
primary and
secondary
160 ug/nf
1.9xlO"3grain/yd3
3 hr max*
(6-9 A.M.)
Nitrogen Dioxide
primary and
secondary
100 ug/m"
1.2xlO"3grain/yd3
A.A.M.
Reference Conditions:
Temperature » 25°C = 77°F
Pressure = 760 mmHg = 14.7 psi = 1 atmosphere
B-22
-------
Table 20. Water Quality Criteria of Indiana
pH: between 6.0 and 8.5
Toxic Substances:
Dissolved Oxygen:
Temperature:
shall not exceed one-tenth of the 96-hour median
tolerance limit
5 mg/1 daily average, never less than 4 mg/1
(equivalent to 0.2921 grain/gal and 0.2336 grain/gal
respectively)
Maximum Values Allowed
Month
January
February
March
April
May
June
July
August
September
October
November
December
Ohio River
!L
10
10
16
18
27
31
32
32
31
26
18
14
-L
50
50
60
70
80
87
89
89
87
78
20
57
St.
°c
10
10
13
18
24
29
29
29
29
18
16
10
Joseph River
1L
50
50
55
65
75
85
85
85
85
70
60
50
Others
°C °F
10
10
16
18
27
32
32
32
32
26
18
14
50
50
60
70
80
90
90
90
90
78
70
57
Maximum Temperature Rise is: 2.8 °C = 5°F for streams
1.7 °C = 3°F for lakes and reservoirs
(Note: certain parameters are more stringent for waters where natural
reproduction of trout and salmon is to be protected.
B-23
-------
Table 21. Ambient Air Quality Standards In Kentucky
Concentration
Constituent
Sulfur Dioxide
primary
secondary
Particulates
primary
secondary
Particulates
(Soiling Index)
primary
secondary
Carbon Monoxide
primary and
secondary
Photochemical
Oxidants
standard
Hydrocarbons
standard
Nitrogen Dioxide
standard
Metric
3
80 ug/m;;
365 ug/m::
1300 ug/nT
75 ug/m3
260 ug/m~
60 ug/m::
150 ug/m
19.7 COH/1000 LM
1.3 COH/1000 LM
1.6 COH/1000 LM
1.0 COH/1000 LM
10 ug/m?
40 ug/m
160 ug/m
160 ug/m3
English
9.4x10"* grain/yd3
4.3x10";; grain/yd;
1.5x10"^ grain/yd13
8.8x10"* grain/yd3
3.1x10"- grain/yd,
7.1x10": grain/yd,
1.8xlO~J grain/yd"5
6.0 COH/1000 LF
0.4 COH/1000 LF
0.5 COH/1000 LF
0.3 COH/1000 LF
0.12 grain/yd3,
0.47 grain/yd3
1.9xlO"3 grain/yd3
1.9xlO"3 grain/yd3
Remarks
A.A.M.
24 hr max*
3 hr max*
A.G.M.
24 hr max*
A.G.M.
24 hr max*
24 hr max*
A.A.M.
3 month max
24 hr max*
8 hr max*
1 hr max*
1 hr max*
3 hr max*
(6-9 A.M.)
100 ug/m
1.2xlO"3 grain/yd3 A.A.M.
B-24
-------
Table 21. Ambient Air Quality Standards In Kentucky (Continued)
Constituent
Metric
Concentration
English
Remarks
Hydrogen Sulfide
standard
Gaseous Fluoride
(HF)
primary
Total Fluorides
primary
14 ug/nT
0.82
1.64
2.86
3.68 ug/m
1.7xlO"4 grain/yd3
"
ug/nc 9.7x10 j: grain/yd^
ug/m, 1.9x10"°- grain/yd,
..n/iri'J •> /l^,in~3 __.*.:_/...J1'
3.4x10". grain/yd,
4.3x10"° grain/yd
40 ppm
60 ppm
80 ppm
1 hr max*
1 month max*
1 week max*
1 day max*
12 hr max*
6 month avg.
2 month avg.
1 month avg.
Reference Conditions: Temperature - 25°C = 77°F
Pressure = 760 mm Hg = 29.92 in Hg = 1 atm.
B-25
-------
Table 22. Standards of Performance For Petroleum
Refineries in Kentucky
Particulates
1.0 kg/kkg feed
1.0 lb/1000 Ib feed
Carbon Monoxide
0.050% by volume
Sulfur Dioxide
Emissions may not exceed the equivalent of combustion of fuel gas
containing 230 mg/dscm of hydrogen sulfide.
(230 mg/dscm = 0.10 grain/dscf)
B-26
-------
Table 23. Kentucky Water Quality Standards
Concentration
Constituent mg/1 grain/gall on
Arsenic 0.05 0.0029
Barium 1.0 0.0584
Cadmium 0.01 5.84x1O"4
Chromium (hexavalent) 0.05 0.0029
Cyanide 0.025 0.0015
Fluoride 1.0 0.0584
Lead 0.05 0.0029
Selenium 0.01 5.84x1O"4
Silver 0.05 0.0029
Dissolved Oxygen: 5 mg/1 = 0.2921 grain/gallon daily average
never the less than 4 mg/1 = 0.2336 grain/gallon
Dissolved Solids: 500 mg/1 = 29.21 grain/gal monthly average
never more than 700 mg/1 = 40.89 grain/gal
Temperature: never to exceed 32°C = 89°F
Maxium Temperature Rise: 2.8°C = 5°F for streams, 1.7°C = 3°F for epilimnion
of thermally stratificated waters
Maximum Monthly Temperature:
Month Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec.
°C 10 10 16 21 27 31 32 32 31 27 21 14
°F 50 50 60 70 80 87 89 89 87 78 70 57
B-27
-------
Table 24. Ambient Air Quality Standards in Montana
Constituent
Sulfur Dioxide
Hydrogen Sulfide
Fluorides
Settled Particulates
Reactive Sulfur
(S03)
Total Suspended
Particulates
Suspended Sulfate
Sulfuric Acid Mist
Lead
Concentration
0.02 ppm
0.10
0.25
0.03 ppm
0.05 ppm
1.0 ppb
Metric
5.26 kg/km~/month
10.53 kg/km/month
0.25 mg/100cm2/day
0.50 mg/100cm /day
Metric (ug/m3)
75
200
4.0
12.0
4.0
12.0
30.0
5.0
English
15 ton/mi2/month
30 ton/mi/month
0.036 grain/fti/day
0.072 grain/ftVday
English (grain/yd2)
8.8 x
2.4 x
4.7 x
1.4 x
10
10
10
10
4.7 x 10
1.4 x
3.5 x
10
10
5.9 x 10
-4
-3
-5
-4
-5
i-4
-4
-5
Remarks
A.A.M.
(1)
(2)
(3)
(4)
24 hr max
5)
6)
A.A.M.
1 month max
A.G.M.
(7)
A.A.M.
(8)
A.A.M.
(8)
1 hr max (8)
3 day max
(1) Not to be exceeded over 1% of the days in avg. 3 month period
(2) Not to be exceeded for more than one hour in avg. 4 consecutive days
(3) Not to be exceeded more than twice in avg. five consecutive days
(4) Not to be exceeded more than twice per year
(5) 3 month average - residential areas
(6) 3 month average - industrial areas
(7) Not to be exceeded more than 1% of the days in avg. year
(8) Not to be exceeded more than 1% of the time
B-28
-------
Table 25. Selected Water Quality Criteria of Montana
Parameter
E-F Classification
Metric English
A-Closed Classification
Dissolved Oxygen
(minimum value)
3 mg/1 0.18 grain/gal
No decrease allowed
pH
6.5-9.5
No change allowed
pH variation allowed 0.5 pH units
Not allowed
Turbidity, Temperature, Shall cause no adverse
Sediments effects
No increase allowed
Toxic/Deleterious
Substances
Less than demonstrated
hazardous concentration
No increase allowed
Additionally, Montana waters shall comply with the 1962 U.S. Public Health
Service Drinking Water Standards (see Table 48).
B-29
-------
Table 26, New Mexico Emissions Standafds for Commerical Gasifiers
Consti tuent/Operation
Standard
Metric
English
Remarks
Participates
Briquetting
General Operations
Gas Burning Boilers
69 mg/scm
69 mg/scm
0.054 kg/106
Kcal
0.03 grain/scf
0.03 grain/scf
0.03 lb/106Btu
Based on heat
input to boiler
Hydrogen Sulfide,
Carbon Disulfide,
Carbon Oxysulfide
(Any Combination)
General Operations
100 ppm (Total) All ppm
10 ppm (Hydrogen Sulfide) by volume
Hydrogen Cyanide
General Operations
Hydrogen Chloride
General Operations
Ammonia
General Operations
Storage
Sulfur Dioxide
Gas Burning Boilers
Sulfur
General Operations
10 ppm
5 ppm
25 ppm
Vapor control
required
0.29 kg/106 kcal 0.16 lb/106Btu Based on heat
input to boiler
<,
0.014 kg/106kcal 0.008 lb/106Btu Based on heat
input of feed
B-30
-------
Table 26. New Mexico Emissions Standards for Commercial Gasifiers (Continued)
Hydrocarbons
2
Storage - For a Reid vapor pressure greater than 0.1055 kg/cm (1.5 psi)
a floating roof, vapor recovery and disposal system or
equivalent control technology is required.
Loading Systems - Vapor collection adapters are required.
B-31
-------
Table 27. Artbient Air Quality Standards in New Mexico
Constituent
Participates
Heavy Metals
Soiling Index
Sulfur Dioxide
Hydrogen Sulfide
Total Reduced Sulfur
Carbon Monoxide
Nitrogen Dioxide
Photochemical Oxidants
Concentration
Metri c
150 ug/m3
110 ug/m3
90 ug/m
60 ug/m
10 ug/m
1.3 COH/1000 LM
0.10 ppm
0.02 ppm
0.003 ppm
0.100 ppm
0.003 ppm
8.7 ppm
13.1 ppm
0.10 ppm
0.05 ppm
0.10 ppm
0.05 ppm
English.
1.8xlO"3grain/yd3
1.3xlO"3grain/yd3
l.lxlO"3grain/yd3
7.1xlO~4grain/yd3
1.2xlO"4grain/yd3
0.4 COH/1000 LF
Remarks
1 day max
7 day max
30 day max
A.G.M.
24 hr max
A.A.M.
1 hr max
1/2 hr max (1)
1 hr max
8 hr max
1 hr max
24 hr max
A.A.M.
24 hr max
A.A.M.
(1) This standard applies to the Pecos-Permian Basin Instrastate Air Quality
Control Region.
Emissions Standards for Refineries
Constituent
Mercaptan
Carbon Monoxide
Concentration
Metric
0.11 kg/hr
500 ppm
20,000 ppm
English
0.25 Ib/hr
Remarks
new facilities
existing
facilities
B-32
-------
Tab1e28. New Mexico Water Quality Criteria
Rio Grande San Fracisco River
Basin Section Basin Section
Parameter
Dissolved Oxygen, mg/1
Dissolved Oxygen,
grain/gallon
1
5.0
0.29
_6
.6.0 (1)
0.35(1)
JO
6.0 (1)
0.35(1)
J
5.0
0.29
6.0 (1)
0.35(1)
pH Range 6.6-8.8 6.6-8.8 6.6-8.8 6.6-8.8 6.6-8.8
Temperature,°C 34 20 20 32.2 20
Temperature,°F 93.2 68 68 90 68
Total Dissolved Solids,
mg/1 2000
Total Dissolved Solids,
grain/gallon 116.8
Sulfates, mg/1 500
Sulfates,grain/gallon 29.2
Organic Carbon, mg/1 70 7.0
Organic Carbon,grain/gal 0.41 0.41
(1) denotes that 85% of saturation is alternatively allowable.
B-33
-------
Table29 . Ambient Air Quality Standards of North Dakota
Concentration
Constituent
Participates
Sulfur Dioxide
Hydrogen Sulfide
Carbon Monoxide
Photochemical Oxidants
Hydrocarbons
Nitrogen Dioxide
Particulates (dustfall)
Soiling Index
Metric
60 ug/m3
150 ug/m3
60 ug/m3
260 ug/m3
715 ug/m3
•5
45 ug/mj
75 ug/m3
10 mg/m
» A MMM /m*^
English
7. lx!0"4g rain/yd
1. 8x1 0"3g rain/yd3
7. lx!0"4g rain/yd3
3.1xlO"3grain/yd3
-3 3
8.4x10 grain/yd .
-d 3
5.3x10 Vain/yd0
8.8xlO"4grain/yd
0.12 grain/yd3
3
f\ A 7 nv»9 ^ m /\tf4
160 ug/m°
160 ug/m3
100 ug/m3
200 ug/m3
5.27 kkg/km2/month
10.53 kkg/km2/month
1.3 COH/1000 LM
1.9xlO"Jgrain/yd~
3 •:
1.9x10 Jgrain/yd"
1.2xlO"3grain/yd;
2.4xlO"3grain/yd"
2
15 ton/mi /month
2
30 ton/mi/month
0.4 COH/1000 LF
Remarks
A.G.M.
24 hr max*
A.A.M.
24 hr max
1 hr max
1/2 hr max (1)
1/2 hr max (2)
8 hr max*
1 hr max*
1 hr max*
1 hr max*
A.A.M.
1 hr max (3)
3 month max (4)
3 month max (5)
(1) denotes that the maximum concentration is not to be exceeded more than
twice in avg. five days
(2) denotes that the maximum concentration is not to be exceeded more than
twice per year
(3) denotes that the maximum concentration is not to be exceeded more than
one percent of the time in any three month period.
(4) applicable to residential areas
(5) applicable to industrial areas
Reference Conditions: Temperature = 25°C = 77°F
Pressure = 760 mmHg = 29.2 in Hg = 1 atm.
B-34
-------
Table 30. Class I Mater Quality Standards 1n North Dakota
Parameter
Ammonia
Arsenic
Barium
Boron
Cadmium
Chlorides
Chromium (Total)
Copper
Cyanides
Dissolved Oxygen (minimum)
Lead
Nitrates
Phenols
Phosphates
Selenium
Total Dissolved Solids
Zinc
Temperature Increase
Maximum Temperature
PH
Turbidity Increase
Maximum Allowable Concentration or Range
Metric (mg/1)
7.0-8.5
10 JTU
English (grain/gallon)
1.0
0.05
1.0
0.5
0.01
100.0
0.05
0.05
0.01
5.0
0.05
4.0
0.01
0.1
0.01
500.0
0.5
2.8°C
29.4°C
0.0584
0.0029
0.0584
0.0292
5.84 x
5.8
0.0029
0.0029
5.84 x
0.2921
0.0029
0.2326
5.84 x
0.0058
5.84 x
29.2
0.0292
5°F
85°F
ID'4
io-4
ID'4
io-4
Sodium: 50% of total cations as milliequivalents/liter
B-35
-------
Table 31. Ohio Ambient Air Quality Standards
Concentration
Constituent
Particulates
Sulfur Dioxide
Metric
60
150 ug/n
60
260
English Remarks
7.1xlO"4 grain/yd A.G.M.
l.SxlO"3 grain/yd3 24 hr max*
A *l
7.1x10"^ grain/yd A.G.M.
3.1xlO~3 grain/yd3 24 hr max*
Carbon Monoxide
Photochemical Oxidants
Hydrocarbons
Nitrogen Dioxide
10 mg/nr
119
79 ug/m"
*•
40 ug/nT
126
331
100 /m*
0.12
1.4xlO"3 grain/yd3
9.5xlO"4 grain/yd3
4.7xlO"4 grain/yd3
8 hr max*
1 hr max
4 hr max (1)
24 hr max*
1.5xlO"3 grain/yd3 3 hr max (2)
4.0xlO"3 grain/yd3 24 hr max*
1.2xlO-3 grain/yd3 A.A.M.
(1) denotes the maximum concentration shall not be exceeded more than
one consecutive four hour period per year.
(2) denotes that ambient levels are to be monitored from 6 to 9 A.M.
Reference Conditions: Temperature = 21.1°C = 70°F
(dry gas)
Pressure • 1.03 kg/cm2 = 14.7 psi
B-36
-------
Table 32. Ohio Stream Quality Criteria for Public Water Supply Use
Constituent Concentration
Metric (mg/1) English (grain/gallon)
Arsenic 0.05 0.0029
Barium 1.0 0.0584
Cadmium 0.005 2.92 x 10"4
Chromium (hexavalent) 0.05 0.0029
Cyanide 0.025 0.0015
Dissolved Oxygen (1) 5.0 0.2921
Dissolved Solids (2) 500 29.2
Fluoride 1.0 0.0584
Lead 0.05 0.0029
Mercury 0.005 2.92 x 10"4
Selenium 0.005 2.92 x 10"4
Silver 0.05 0.0029
(1) Dissolved oxygen concentration are minimum values. The given values
are averages. A value of 4.0 mg/1 (0.2336 grain/gallon) is the
minimum acceptable value. These values are for waters designated
to support aquatic life.
(2) Value given is monthly average with a maximum allowable value of
750 mg/1 (43.8 grain/gallon) never to be exceeded.
B-37
-------
Table 33. General Water Standards Applicable Within 500 Yards
of Any Public Water Supply Intake In Ohio
Constituent
Cyanide
Dissolved Iron
Dissolved Manganese
Dissolved Oxygen (1)
Dissolved Solids (2)
Hexavalent Chromium
Nitrates
Phenols
pH Range
Concentration
Metric (mg/1)
0.005
0.3
0.05
5.0
500
0.01
8.0
0.001
6.0-9.0
Limit.
English (grain/gallon)
2.92 x 10"4
0.0175
0.0029
0.2921
29.2
5.84 x 10"4
0.4673
5.84 x 10"5
(1) 5.0 mg/1 (0.2921 grain/gallon) daily minimum average, never less
than 4.0 mg/1 (0.2336 grain/gallon).
(2) Dissolved solids level may exceed (a) or (b) but not both.
(a) 500 mg/1 (29.2 grain/gallon) monthly average, never to
exceed 750 mg/1 (43.8 grain/gallon).
(b) 150 mg/1 (8.8 grain/gallon) attributable to human activities,
B-38
-------
Table34. Ambient Air Quality Standards of Pennsylvania
Concentration
Constituent Metric English Remarks
Settled Participates 0.8 ug/cnr/month grain/in2/month A.A.M.
2 2
1.5 ug/cm /month grain/in /month 30 day max
Lead 5.0 ug/m 30 day max
Sulfates 1.0 ug/m 30 day max
3
3.0 ug/m 24 hr max
Fluorides 5.0 ug/m 24 hr max
Hydrogen Sulfide 0.005 ppm 24 hr max
0.1 ppm 1 hr max
Standards for Contaminants
Particulates - unspecified process
For effluent gas discharge rates greater than 8500 m/min
(300,000 dscf/min), 458 mg/dscm (0.2 grain/dscf) is allowed.
Particulates - petroleum refineries
20 kg/kkg (40 Ib/ton) of liquid feed
Visible Emissions - unspecified process
Opacity equal to or greater than 2Q% is not allowed for aggregate
periods of more than three minutes in any hour. Additionally,
60% opacity may never be exceeded. Opacity due to uncombined
water mists is excluded in determining opacity levels.
B-39
-------
Table 35. Water Quality Standards for the
Monongahela River in Pennyslyania
Concentration
Parameter
Dissolved Oxygen (1)
Total Iron
Maximum Temperature
Temperature Increase (2)
Dissolved Solids (3)
Total Manganese
Phenols
pH Range
Metric
6.0 mg/1
1.5 mg/1
30.6°C
2.8°C
500 mg/1
1.0 mg/1
0.005 mg/1
6.0-8.5
English
0.3505 grain/gallon
0.0876 grain/gallon
87° F
5°F
29.2 grain/gallon
0.0584 grain/galIon
-4
2.92x10 grain/gallon
(1) 6.0 mg/1 (0.3505 grain/gallon) is the minimum daily average.
5.0 mg/1 (0.2921 grain/gallon) is the minimum acceptable level.
For the epilimnion of stream sections where the rural statisifcation
occurs, the minimum daily average is 5.0 mg/1 (0.2921 grain/gallon)
and the minimum acceptable level is 4.0 mg/1 (0.2336 grain/gallon)
(2) A 5°F temperature rise may not cause a resulting stream temperature
of greater than 30.6°C (87°F). Also, a maximum hounly temperature
change of l.TC (2°F) is allowed.
(3) 500 mg/1 (29.2 grain/gallon) is the monthly average. 750 mg/1
(43.8 grain/gallon) may never be exceeded.
B-40
-------
Table 36. Ambient Air Quality Standards of South Dakota
Constituent
Sulfur Oxides
Particulates
Soil Index
Carbon Monoxide
Photochemical Oxidants
Hydrocarbons
Nitrogen Oxides
Concentration
Metric
60 mg/m
260 mg/m3
60 mg/m
150 mg/m3
Engli sh
7.1xlO"4grain/yd3
3.1xlO"3grain/yd3
7.1xlO"4grain/yd3
1.8xlO"3grain/yd3
0.66 COH/1000LM 0.20 COH/1000 LF
10 mg/nr 0.12 grain/yd'
3 "
15 mg/m 0.18 grain/yd"
125 mg/m"
125 mg/m"
100 mg/mv
250 mg/m"
1.5x10 grain/yd
1.5xlO"3grain/yd3
1.2xlO~3grain/yd3
2.9xlO"3grain/yd3
Remarks
A.A.M.
24 hr max*
A.G.M.
24 hr max*
A.G.M.
8 hr max*
1 hr max*
1 hr max*
3 hr max* (1)
A.A.M.
24 hr max*
(1) Monitored from 6-9 A.M.
Standard Conditions: Temperature = 20°C = 68°F
Pressure = 760 mmHg = 29.92 inHg = 1 atmosphere
B-41
-------
TabVe 37. Selected South Dakota Industrial Emissions Standards
Fuel Burning Installations
Particulates
0.54 kg/kcal of heat input =0.30 lb/105 Btu of heat input
Sulfur Oxides
5.4 kg/kcal of heat input = 3.0 lb/106 Btu of heat input
Nitrogen Oxides
0.36 kg/kcal of heat input = 0.2 lb/10 Btu of heat input
General Process Industries
Particulates
E = 55.0 p0'11 - 40
where E = rate of emission in Ib/hr
P = process weight rate in ton/hr
(Note: Same equation is applicable in Arizona)
B-42
-------
Table 38. Applicable Water Quality Standards of South Dakota
Concentration
w
*•
u>
Parameter
Total Dissolved
Solids
Nitrates
Nitrates
Ammonia
Chlorides (1)
Cyanides (total)
Cyanides (free)
Dissolved Oxygen
Dissolved oxygen
Hydrogen Sulfide
Suspended Solids
Total Iron
Temperature
Turbidity
Metric
1000 mg/1
2000 mg/1
10 mg/1
45 mg/1
0.6 mg/1
100 mg/1
0.02 mg/1
0.005 mg/1
6.0 mg/1
7.0 mg/1
0.002 mg/1
30 mg/1
0.2 mg/1
18.3°C
English
58.4 grain/gal
116.8 grain/gal
0.5841 grain/gal
2.6285 grain/gal
0.0350 grain/gal
5.84 grain/gal
0.0012 grain/gal
2.92 x 10"4 grain/gal
0.3505 grain/gal
0.4089 grain/gal
1.17 x TO"4 grain/gal
1.75 grain/gal
0.0117 grain/gal
65°F
Hater Use
Domestic Supply
Industrial Supply
Domestic Supply
Domestic Supply
Domestic Supply
Domestic Supply
Domestic Supply
All
Cold
Water
Fish
Propagation
Remarks
As N
As NO-
minimum concentration
Spawning season
10JTU
(1) Additionally total chlorine is limited to 0.2 mg/1 (0.0117 grain/gal).
-------
Table 39. Texas Air Regulations
Ambient Air Quality Standards for Hydrogen Fluoride
4.5 ppb- 12 hr max
3.5 ppb 24 hr max
2.0 ppb 7 day max
1.0 ppb 30 day max
Net Ground Level Concentrations for Applicable Emissions
Constituent
Hydrogen Sulfide (1)
Concentration
0.08 ppm
0.12 ppm
Remarks
30 min max
30 min max
Sulfuric Acid
Particulates
Metric (ug/m )
15
50
100
100
200
400
English (grain/yd )
1.8x10
5.9x10
1.2x10
1.2x10
2.4x10
4.7x10
-4
-4
-3
-3
-3
-3
24 hr max
1 hr max (2)
max allowed
5 hr max
3 hr max
1 hr max
(1) The first value is applicable only when residential areas are downwind
of the source of emissions.
(2) Denotes that the maximum value is not to be exceeded more than once
per 24 hour period.
B-44
-------
Table 39. Continued
Emissions Limits for Fuel Burning Steam Generators (3)
Concentration Remarks
Constituent Metric English
Particulates 0.54 kg/106kcal 0.3 lb/106 Btu 24 hr max (4)
0.18 kg/106kcal 0.1 lb/106 Btu 2 hr max (5)
Sulfur Dioxide 5.40 kg/106kcal 3.0 lb/106 Btu
Nitrogen Oxides 1.26 kg/106kcal 0.7 lb/106 Btu 2 hr max (6)
0.90 kg/106kcal 0.5 lb/106 Btu 2 hr max
0.45 kg/106kcal 0.25 lb/106Btu 2 hr max
(3) applicable for heat inputs greater than 2500 million Btu/hr.
(4) solid fuel burners
(5) gas and liquid fuel burners
(6) standards apply to opposed fired, front fired and tagential fired
steam generators respectively.
B-45
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Table 40. Water Uses and Quality Criteria for the
San Antionio River Basis
Fish and Wildlife
Domestic Supply
Chlorides, mg/1
Chlorides gr
Sulfates, mg/1
pH range
Temperature,
Temperature,
uality Parameter 1
ation N
lecreation U
life U
ly U
/I 200
rain/gal 11.7
1 150
rain/gal 8.8
ed Solids, mg/1 700
>lved Solids; qrains/gal 40.9
6.5-8.5
°C 32
°F 90
gen, mg/1 5.0
gen, grain/gal 0.29
2
0
U
U
U
200
11.7
300
17.5
900
52.6
7.0-9.0
32
90
5.0
0.29
3
U
U
U
U
40
2.3
75
4.4
400
23.4
7.0-9.0
32
90
5.0
0.29
4
U
U
U
U
120
7.0
120
7.0
700
40.9
7.0-9.0
32
90
5.0
0.29
5
U
U
U
U
50
2.9
75
4.4
400
23.4
7.0-9
32
90
5.0
0.29
N denotes not currently useable
0 denotes not currently useable, quality to be improved
U Denotes useable for given water use
(1) San Antonio River
(2) Cibolo Creek (Section 1)
(3) Cibolo Creek (Section 2)
(4) Medina River (Section 1)
(5) Medina River (Section 2)
(6) Medina Lake
(7) Medina River (Section 3)
(8) Leon Creek (Section 1)
(9) Leon Creek (Section 2)
B-46
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Table 40. (continued)
Water Use/Quality Parameter 6789
Contact Recreation
U U U U
Non-Contact Recreation
Fish and Wildlife U u U U
+• c n U U U U
Domestic Supply
Chlorides, mg/1
,.,. ..... 50 40 120 40
Chlorides grain/gal
2'9 2'3 7-° 2-3
75 100 120 75
Sulfates grain/gal ^ ^ ^ ^
Total Dissolved Solids, mg/1
. , . c , ' • . , 400 400 700 400
Total Dissolved Solids, grains/gal
23.4 23.4 40.9 23.4
PH ra"9e 7.0-9.0 7.0-9.0 7.0-9.0 7.0-9.0
Temperature, °C 3] 3] 35 ^
Temperature, °F 88 88 gg g5
Dissolved oxygen, mg/1 5_Q ^ g Q g Q
Dissolved oxygen, grain/gal
B-47
-------
Table 41. Water Criteria for Class "A" Utah Waters
(From Public Health Service Drinking Water Standards. 1962)
Turbidity: 5 JTU
Chemical Constituent
Arsenic
Chlorides
Copper
Cyanide
Fluoride (1)
Iron
Manganese
Nitrates
Phenols
Sulfates
Total Dissolved Solids
Zinc
Concentration
Metric (mg/1)
0.01
250
1.0
0.01
1.7
0.3
0.05
45
0.001
250
500
5.0
English (grain/gal)
5. 84x1 O"4
14.6
0.0584
5. 84x1 O"4
0.0993
0.0175
0.0029
2.63
5. 84x1 O"5
14.6
29.2
0.2921
(1) Fluoride concentrations is temperature dependent, the given value
being the maximum allowed at temperatures below 10°C (50°F).
B-48
-------
Table 42. Applicable Air Pollution Regulations
In West Virginia
Coal Preparation, Drying and Handling
Particulates - for volumetric flow rates greater than 14,200 scm/m
(500,000 scf/min.) the allowable emission rate is 0.18 gm/scm
(0.08 grain/scf).
Manufacturing Process Operations
Particulates - for process weight rates exceeding 45,500 kg/hr
(100,000 Ib/hr) the allowable emission rate is 9.6 kg/hr
(21.2 Ib/hr)
Smoke - No smoke darker than No. 1 on the Ringelmann Smoke Chart is
permitted. No smoke darker than No. 2 on the Ringelmann Smoke
Chart is permitted for more than five minutes in any sixty
minute period.
B-49
-------
Table 43. West Virginia Air Quality Standards
Constituent
Concentration
Metric English
Remarks
Sulfur Dioxide
primary
secondary
80 mg/m 9.4x10 grain/gal A.A.M.
3 -3
365 mg/m 4.3x10 grain/gal 24 hr max*
1300 mg/m 1.5x10 grain/gal 3 hr max*
Particulates
primary
secondary
75 mg/nT
260 mg/m2
m
60 mg/m"
^
150 mg/m"
8.8xlO"4grain/gal
_o
3.1x10 grain/gal
7.1x10" grain/gal
1.8x10 grain/gal
A.G.M.
24 hr max*
A.G.M.
24 hr max*
Carbon Monoxide
standard
10 mg/m 0.12 grain/gal 8 hr max*
3
40 mg/m 0.47 grain/gal 1 hr max*
Photochemical Oxidants
standard
Non-Methane Hydrocarbons
3 -3
160 mg/m 1.9x10 grain/gal 1 hr max*
3 3
160 mg/m 1.9x10 grain/gal 3 hr max*
(6-9 A.M.)
Standard Conditions: Temperature = 25°C - 77°F
Pressure = 760 mmHg = 29.92 in Hg = 1 atmosphere
B-50
-------
Table 44. Water Quality Criteria for the Gauley River
and Tributaries in West Virginia
Dissolved Oxygen:
pH Range :
Temperature:
never less than 5.0 mg/1 = 0.2921 grain/gallon
6.0 - 8.5
Maximum increase 2.8°C = 5°F
Maximum Temperature
27°C = 81°F (May-November)
'23°C - 73°F (December-April)
Chemical Constituent
Arsenic
Barium
Cadmium
Chloride
Chromium (hexavalent)
Cyanide
Fluoride
Lead
Nitrates
Phenol
Selenium
Silver
Maximum Concentration
Metric (mg/1) English (grain/gal)
0.01
0.50
0.01
100
0.05
0.025
1.0
0.05
45
0.001
0.01
0.05
5.84x10
0.0292
5.84x10
5.84
0.0029
0.0015
0.0584
0.0029
2.63
5.84x10
5.84x10
0.0029
-4
-4
-5
-4
B-51
-------
Table 45. Wyoming Ambient Air Standards
Concentration
Constituent
Particulates
Soiling Index
Total Settleable
Particulates
Sulfur Oxides
Hydrogen Sulfide
Photochemical Oxidants
Hydrocarbons
Nitrogen Oxides
Fluorides
Carbon Monoxide
Metric
60 mg/nT
150 mg/nf
English
7.1xlO"4grain/gal
1.8xlO~3grain/gal
1.3 COH/1000 0.4 COH/1000 LF
5 g/m /month
2
10 g/m /month
60 mg/m
260 mg/m3
1300 mg/m3
70 mg/m
40 mg/m
160 mg/m3
160 mg/m
3
100 mg/m
1 ppb
10 mg/m
40 mg/m
59 grain/yd /month
2
118 grain/yd /month
7.1x10~ grain/gal
3.1xlO"3grain/gal
1.5x10" grain/gal
-4
8.3x10 grain/gal
3
4.7x10 grain/gal
1.9x10 grain/gal
1.9xlO"3grain/gal
_o
1.2x10 grain/gal
0.12 grain/gal
0.47 grain/gal
Remarks
A.G.M.
24 hr max*
A.G.M.
(1)
A.A.M.
24 hr max*
3 hr max*
1/2 hr max (2)
1 hr max*
1 hr max*
3 hr max* (3)
A.A.M.
24 hr max
8 hr max*
1 hr max*
Standard Conditions: Temperature = 21 °C = 70°F
Pressure = 760 mmHg = 29.92 in.Hg = 1 atmosphere
(1) Values given include 1.7 g/m?/month (20.1 grain/yd2/month)
background settled particulates
(2) Hydrogen sulfide values are not to be exceeded more than twice per year.
(3) Monitored 6-9 A.M.
B-52
-------
Table 46. Applicable Wyoming Emissions Regulations
New Fuel Burning Equipment - Sulfur Dioxide
0.36 kg/106Kcal input = 0.20 lb/106 Btu input
(applicable to coal burners)
New Fuel Burning Equipment - Nitrogen Oxides
1.26 kg/106Kcal input =0.70 lb/106 Btu input
(applicable to non-lignite coal burners)
Stationary Sources - Carbon Monoxide Requirement
Stack gases shall be treated by direct flame after burner as
required to prevent ambient standards from being exceeded.
Stationary Sources - Hydrogen Sulfide Requirement
Gases containing hydrogen sulfide shall be vented, incinerated, or
flared as necessary to ambient standards from being exceeded.
New Sources - Particulates
E = 17.31 p°'16 (for P 30 tons/hr)
where E = maximum allowable rate of emissions in Ib/hr
P = process weight rate in tons/hr
For a. 50,000 bbl/day SRC plant
(22,000 ton/day) °'16
hr/day)
E = 17.31 (917)0'16 = 51.6 Ib/hr
B-53
-------
Table 47. Wyoming Water Quality Standards
Parameter Concentration Limits Remarks
Settleable Solids free from
Floating Solids free from
Toxic Materials free from
Turbidity 10 JTU increase
pH Range 6.5 - 8.5
Total Gas Pressure Not to exceed 110%
(of atmospheric pressure)
Metric English
Dissolved Oxygen 6 mg/1 0.3505 grain/gal Class I water
5 mg/1 0.2921 grain/gal Class II water
Oil/Grease 10 mg/1 0.5841 grain/gal
Temperature
*
The maximum temperature allowed is 26°C (78°F) for streams supporting
cold water fish and 32°C (90°F) for streams supporting warm water fish.
The maximum allowable temperature increase is dependent upon natural
water temperature. For streams with maximum natural temperatures of 20°C
(68°F) or less the maximum allowable temperature increase is 1.1°C (2 °F)
For streams with maximum natural temperatures exceeding 20°C (68°F) the
maximum allowable temperature increase is 2.2°C (4°F).
B-54
-------
Table 48. EPA National Interim Primary Drinking Water Standards
Maximum Concentration
Constituent
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Nitrate (as N)
Selenium
Silver
Fl uorine
Temperature
TO
12.1 & below
12.2 - 14.6
14.7 - 17.7
17.8 - 21.4
21.5 - 26.2
26.3 - 32.5
Metric (mg/1)
0.05
1.0
0.01
0.05
0.05
0.002
10
0.01
0.05
Concentration
(igTT)
2.4
2.2
2.0
1.8
1.6
1.4
English (grain/gallon)
0.0029
0.0584
5.84 x 10"4
2.92
0.0029
1.17 x-10~4
0.5841
5.84 x%70"4
0.0029
Temperature C.nnrpntratinn
(°F) (grain/gal)
53.7 & below 0.1402
53.8 - 58.3 0.1285
58.4 - 63.8 0.1168
63.9 - 70.6 0.1051
70.7 - 79.2 0.0935
79.3 - 90.5 0.0818
B-55
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TECHNICAL REPORT DATA
(Pteotr read Inumctions on the reverse bciore completing!
I. REPORT NO. ,
EPA-600/7-78-019
2.
13. RECIPIENT'S ACCESSION'NO.
1. TITLE AND SUBTITLE
Environmental Assessment of Coal Liquefaction:
Annual Report
5. REPORT DATE
February 1978
6. PERFORMING ORGANIZATION CODE
. AUTMORIS)
8. PERFORMING ORGANIZATION REPORT NO.
Ken T. Budden and Werner H. Zieger
I. PERFORMING ORGANIZATION NAME AND ADDRESS
Hittman Associates, Inc.
9190 Red Branch Road
Columbia, Maryland 21045
10. PROGRAM ELEMENT NO.
EHB623A
11. CONTRACT/GRANT NO.
68-02-2162
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Annual: 7/76-9/77
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES
919/541-2851.
project officer is William J. Rhodes, Mail Drop 61,
16. ABSTRACT
The report summarizes results of a study of the environmental aspects of 14 of the .
most prominent coal liquefaction systems, in terms of background, process descrip-
tion, major operations, input and output streams, status, and schedule of system
development. As a result of the study, four systems—SRC, H-Coal, Exxon Donor
Solvent, and Synthoil—were selected for in-depth study. The first Standards of Prac-
tice Manual, under preparation for the SRC-I system, will include descriptions of
modules, control/disposal practices, environmental emissions, and control/disposal
costs.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Croup
Pollution
Coal
Liquefaction
Assessments
Synthetic Oils
Coal Preparation
Pollution Control
Stationary Sources
Coal Liquefaction
Environmental Assess-
ments
13B
21D
07D
14B
11H
081
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
199
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (t-73)
B-56
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