EPA-650/2-74-009-1
October 1975
Environmental Protection Technology Series
IN FOSSIL FUEL CONVERSION
PROCESSES
ANALYTICAL TEST PLAN
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EPA-650/2-74-009-1
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
ANALYTICAL TEST PLAN
by
C. D. Kalfadelis, E. M. Magee,
G. E. Milliman, and T. D. Searl
Exxon Research and Engineering Company
P.O. Box 8
Linden. New Jersey 07036
Contract No. 68-02-0629
ROAP No. 21ADD-023
Program Element No. 1AB013
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, North Carolina 27711
Prepared for
U. S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D. C. 20460
October 1975
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EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection
Agency and approved for publication. Approval does not signify that
the contents necessarily reflect the views and policies of the Environ-
mental Protection Agency, nor does mention of trade names or commer-
cial products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These 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
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service. Springfield, Virginia 22161.
Publication No. EPA-650/2-74-009-1
11
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TABLE OF CONTENTS
Page
SUMMARY xl
vi i i
INTRODUCTION X111
1. GENERAL PHILOSOPHY AND APPROACH J-
1.1 Goals of an Analytical Test Plan !
1.2 Specific Approach 3
1.3 Operating Conditions and Flow Rates 4
1.4 Determination of Effect on Environmental
Factors of Altered Operating Conditions 5
2. COAL GASIFICATION 6
2.1 System Basis °
2.2 Process Basis °
3. GASIFICATION PROCESS DESCRIPTION 1:L
3.1 Qualifications -*-1
3.2 Coal Preparation 13
3.3 Oxygen Production 16
3.4 Coal Gasification and Gas Liquor
Separation
3.5 Shift Conversion 22
3.6 Gas Cooling 25
3.7 Gas Purification 28
3.8 Methane Synthesis 31
3.9 Product Gas Compression
and Dehydration
3.10 Sulfur Recovery
40
3.11 Gas Liquor Treatment
3.12 Fuel Gas Production
iltL
and Cooling
3.13 Fuel Gas Treating
3.14 Steam and Power G
3.15 Raw Water Treating ............. < • • • • 53
3.14 Steam and Power Generation .............. 50
111
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TABLE OF CONTENTS (Cont'd)
Page
3.16 Cooling Water System 55
3.17 Ash Disposal 59
3.18 Process Analytical Summary 62
3.19 Unit Material Balances 70
3.19.1 Coal Preparation 70
3.19.2 Gas Cooling 70
3.19.3 Gas Purification 70
3.19.4 Sulfur Recovery 70
3.19.5 Fuel Gas Treating 70
3.19.6 Cooling Water System 71
3.19.7 Ash Disposal 71
3.19.8 Special Unit Material Balances 71
4. COAL LIQUEFACTION 72
4.1 System Basis 72
4.2 Process Basis 73
4.3 Coal Preparation 76
4.4 Drying and Stage 1 Pyrolysis 79
4.5 Stages 2,3,4 Pyrolysis 82
4.6 Product Recovery 85
4.7 Oil Filtration 88
4.8 Hydrotreating 91
4.9 Oxygen Plant 95
4.10 Gas Purification 98
4.11 Hydrogen Plant 101
4.12 Sulfur Recovery 104
4.13 Power and Steam Generation 107
4.14 Water Treatment 110
4.15 Cooling Water 114
4.16 Process Analytical Summary 117
4.17 Unit Material Balances 122
5. TYPICAL AVAILABLE STREAM ANALYSES AND STANDARDS 123
6. BIBLIOGRAPHY (Section 1 through 5) 130
IV
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TABLE OF CONTENTS (Cont'd)
Page
7. ANALYTICAL CONSIDERATIONS 134
7.1 Introduction 134
7.2 Analysis of Metals 138
7.3 Alternative Analytical Techniques 139
7.4 Results Analysis 139
8. ANALYSIS OF AQUEOUS SAMPLES 141
8.1 Introduction 141
8.2 Sampling 141
8.3 Preservation of Samples 141
9. COAL AND COAL RELATED SOLID ANALYSIS 150
9.1 Introduction 150
9.2 Sampling 150
9.3 Preservation 150
10. ANALYSIS OF COAL LIQUIDS 153
10.1 Introduction 153
10.2 Sampling 154
10.3 Preservation 154
11. ANALYSIS OF ATMOSPHERIC AND GASEOUS SAMPLES 157
11.1 Introduction 157
11.2 Particulates 157
11.3 Gases and Vapors 158
11.4 Direct Reading Colorimetric Indicator Tubes 160
12. SAMPLE FORMAT FOR STREAM SAMPLING AND ANALYSIS 166
13. BIBLIOGRAPHY (Sections 7 through 12) 169
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LIST OF TABLES
(Sections 2 through 4)
No. Page
1 Navajo Sub-Bituminous Coal 9
2 Coal Preparation for Lurgi Plant 15
3 Oxygen Production 18
4 Coal Gasification 21
5 Shift Conversion 24
6 Gas Cooling 27
7 Gas Purification for Lurgi Plant 30
8 Methane Synthesis 33
9 Gas Compression and Dehydration 36
10 Sulfur Recovery 39
11 Gas Liquor Treatment 43
12 Fuel Gas Production 46
13 Fuel Gas Treating 49
14 Steam and Power Generation for Lurgi Plant 52
15 Raw Water Treating 55
16 Cooling Water System 58
17 Ash Disposal 61
18 Summary of Effluent Streams to be Analyzed
for Lurgi Plant 64
19 Coal Input to Lurgi Coal Gasification 68
20 Flue-Gas Streams from Boiler and Heater Stacks. . . 69
21 Mean Analytical Values for 82 Coals
From the Illinois Basin 75
22 Coal Preparation for COED Plant 78
VI
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LIST OF TABLES (Cont'd
No.
23 Drying and Stage 1 Pyrolysls 81
24 Stages 2,3,4 Pyrolysis 84
25 Product Recovery 87
26 Oil Filtration 90
27 Hydrotreating 94
28 Oxygen Plant 97
29 Gas Purification for COED Plant 100
30 Hydrogen Plant 103
31 Sulfur Recovery 106
32 Power and Steam Generation for COED Plant 109
33 Water Treating 113
34 Cooling Water 116
35 Summary of Effluent Streams to be Analyzed
for COED Plant 118
36 Stream Analyses for Existing Plants, Coals 124
37 Stream Analyses for Existing Plants,
Liquid Organic Products 125
38 Stream Analysis for Existing Plants, Ash 126
39 Stream Analyses for Existing Plants,
Water Effluent 127
40 Standards for Water Effluents 128
41 Air Standards 129
vii
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LIST OF TABLES (Cont'd)
No. Page
(Sections 7 through 11)
I Literature Surveyed for Selection of
Possible Pollutants 135
II Possible Pollutants from Coal Processing 136
III Other Analyses 137
IV Suggested Analytical Methods for Aqueous Samples. . 142
V Recommendation for Sampling and Preservation Of
Samples According to Measurement 147
VI Measurement Techniques Used in the Suggested Methods
for Analysis of Coal and Coal Related Solids
for Trace Elements 151
VII Suggested Methods for Gross Coal Analysis 152
VIII Suggested Methods for Determination
Of Metals in Coal Liquids 155
IX Polynuclear Aromatic Hydrocarbons Which Are
Determined in Coal Liquids Using the ISM Methods. . 156
X Other Analyses 156
XI Sampling and Analytical Methods for Particulates
in Atmospheric and Other Gaseous Samples 162
XII Sampling and Analytical Method for Atmospheric
and Other Gaseous Samples 163
XIII Some MSA Direct Reading Colorimetric Indicators . . 165
viii
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LIST OF FIGURES
No. Page
1 Lurgi Gasification 7
2 Coal Preparation for Lurgi Plant 14
3 Oxygen Production 17
4 Coal Gasification 20
5 Shift Conversion 23
6 Gas Cooling 26
7 Gas Purification for Lurgi Plant 29
8 Methane Synthesis 32
9 Gas Compression 35
10 Sulfur Recovery for Lurgi Plant 38
11 Gas Liquor Treatment 42
12 Fuel Gas Production 45
13 Fuel Gas Treating 48
14 Steam and Power Generation 51
15 Raw Water Treating 54
16 Cooling Water System 57
17 Ash Disposal 60
18 COED Liquefaction 74
19 Coal Preparation for COED Plant 77
20 Drying and Stage 1 Pyrolysis 80
21 Stages 2,3,4 Pyrolysis 83
22 Product Recovery 86
23 Oil Filtration 89
24 Hydrotreating 93
ix
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LIST OF FIGURES (Cont'd)
No. Page
25 Oxygen Plant 96
26 Gas Purification for COED Plant 99
27 Hydrogen Plant 102
28 Sulfur Recovery for COED Plant 105
29 Power and Steam Generation 108
30 Water Treatment 112
31 Cooling Water 115
I Sample Sheet for Gross Sample 167
II Sample Sheet for Detailed Sample 168
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SUMMARY
A coal gasification process (Lurgi) and a coal liquefaction pro-
cess (COED) have been used as the basis for preliminary definition of those
streams which require analysis to permit an assessment of the pollution
potential of the processes in the light of current environmental standards.
Methods for sampling indicated streams and analytical procedures which are
required to obtain the data have been defined. These summaries may be
readily modified or adapted to other processes, and expanded to include
additional polluting constituents or improvements in analytical procedures.
XI
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TABLE OF CONVERSION UNITS
To Convert From
Btu
Btu/pound
Cubic feet/day
Feet
Gallons/minute
Inches
Pounds
Pounds/Btu
Pounds/hour
Pounds/square inch
Tons
Tons/day
To
Calories , kg
Calories, kilogram
Cubic meters/day
Meters
Cubic meters/minute
Centimeters
Kilograms
Kilograms/calorie, kg
Kilograms/hour
Kilograms/square centimeter
Metric tons
Metric tons/day
Multiply By
0.25198
0.5552
0.028317
0.30480
0.0037854
2.5400
0.45359
1.8001
0.45359
0.070307
0.90719
0.90719
xii
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INTRODUCTION
The Environmental Protection Agency has anticipated the pollution
potential of fossil-fuel conversion processes and has attempted to define
the extent of controls which may have to be applied in the conversion
of naturally occurring "dirty" fuels. Thus, a particular goal is to insure
that contemplated fuel conversion plants do not themselves become sources
of environmental pollution.
Accordingly, the Environmental Protection Agency has awarded
Contract No. EPA-68-02-0629 to Exxon Research and Engineering Company
to evaluate the current status of fossil fuel conversion and/or treatment
processes with respect to pollution control and thermal efficiency.
Specifically,, Exxon Research and Engineering Company is performing a
detailed pollution control assessment of representative processes using
nonproprietary information. As a result of this study the "technology'
needs" to minimize pollution will be delineated in order to allow sufficient
time for research, development, and design of adequate pollution control
equipment for coal conversion processes.
Few developers of conversion processes have so far seriously
addressed pollution control requirements for their process, reflecting
the fact that no significant commercial system has yet been constructed
in the United States. In general, the thrust of the work which has been
reported has been directed to basic process development, including hardware
development and yield improvement. And, until recently, much of the
developmental effort had been conducted on so small a scale as to make
suspect extrapolations of analytical results to commercial systems.
A particular difficulty with fossil fuel systems, and for
coal in particular, is the complexity of the composition of streams within
the system. Coal has a very complex, vaguely defined organic structure
superposed on an equally complex mineral or inorganic base. Thermal
processing of such materials gives rise to myriad reaction products
whose form and stability are a function of the temperature of
processing and of the atmosphere in which the processing is conducted.
The coal itself and many of the primary products of coal
conversion plants are unstable in a normal atmosphere. Coal begins to
lose occluded gases, and its surface begins to oxidize as it is broken
out of the earth. The coal feeds to conversion processes and chars
obtained from conversion systems are pyrophoric to some degree. Coal
liquids require considerable processing to produce stable end products.
xiii
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The primary pollutant which most conversion processes intend to
control is sulfur. However, most other elements exist in coal, and the
opportunity to produce almost every pollutant or pollutant form for which
controls have been established is present in most integrated coal conversion
systems. It is clear that the list of controlled pollutants will grow,
and the probability that new legislation will impact on coal systems is
high.
There is, of course, no body of Federal environmental legislation
which is specifically directed to coal conversion systems. However, many
of the component operations envisioned for such systems are subject to
existing regulations, and it is probable that further specific regulations
will be enacted as systems come into existence. In fact, it is possible
that the "coal conversion industry" may represent the first instance of
an industry which is essentially regulated before any substantial industry
exists.
The purpose of this study is to establish a baseline for the
system of analysis which may be required to assess the pollution potential
of a coal conversion facility. It is, of course, geared to present
environmental standards and employs established or state-of-the-art sampling
and analytical methods. It is obvious that analysis of all relevant streams
around an integrated system will constitute a major undertaking in terms
of labor and time and will require significant investment in analytical
facilities and materials.
xiv
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1. GENERAL PHILOSOPHY AND APPROACH
!•1 Goals of an Analytical Test Plan
It should be realized at the outset that a coal gasification
or liquefaction plant is very complex. Such a plant consists of many units
in the main processing stream with numerous auxiliary units necessary for
clean, efficient operation. The nature of the central unit for coal con-
version differs from process to process. The emerging primary stream is
different in each case and this leads to major differences in subsequent
processing units.
An example of these differences is very apparent in a comparison
of the Lurgi and Koppers-Totzek gasification processes. The Lurgi process (4)
operates at intermediate pressures, relatively low temperatures and uses a
fairly large sized coal feed. The Koppers-Totzek process (17), on the other
hand, operates at low pressure and high temperature and uses a fine sized
coal feed. The higher pressure and low temperature of the Lurgi process
produces tars, oils and organic compounds containing sulfur and oxygen.
The presence of these materials in the Lurgi raw product gas introduces
complexities into the clean-up systems that are absent from the Koppers-
Totzek process. The presence of low molecular weight paraffins can have an
effect on subsequent acid gas removal; the presence of organic oxygen
and sulfur compounds introduces restrictions and requirements on dirty
process water treatment that have an effect downstream on ultimate water
disposal. The large quantity of small particulate matter in the latter
process requires special considerations for removal that are absent in
the Lurgi process. The need for larger sized feed coal in the Lurgi process
causes a special problem of fines disposal from the grinding operation.
The many alternatives existing for subsequent gas treatment and
auxiliary units leads to further overall complexity.' For example,
numerous processes exist for acid gas removal (necessary in all gasification
and liquefaction schemes). (For more details see, for example, reference 52.;
There are processes utilizing absorption and reaction of the acid gases with
a suitable basic solution (e.g., hot carbonate; amines) followed by regenera-
tion. Other processes use low temperature absorption with a suitable solvent
(e.g., methanol, propylene carbonate, etc.) followed by desorption. A third
technique involves absorption of hydrogen sulfide into an oxidizing solution
where the hydrogen sulfide is converted to sulfur. Still a further variation
involves removal of the sulfur in situ with an appropriate solid basic material
such as limestone or dolomite (25). All of these alternatives lead to further
options or requirements on subsequent treatment of the acid gases to remove
sulfur.
In the case of auxiliary units many different alternatives exist
depending on the initial gasification or liquefaction technique. An example
is the fuel to be used in steam production. Coal can be used as fuel with
appropriate stack gas scrubbing. Some processes produce chars that are
available for fuel; some processes produce liquid products that can be burned.
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Another alternative is the use of clean product gas or liquidj sulfur
removal from stack gases is thus avoided. Another example of an auxiliary unit
with many alternatives is the treatment of waste water. Alternatives such
as biox ponds, adsorption with solids, etc. again add complexity to the
subject of environmental control.
The myriad of alternatives available for coal conversion plants
makes it essentially impossible and certainly non-productive to attempt to
anticipate all permutations and combinations of process units in an analytical
test plan. Such a test package would be so large that it would confuse rather
than aid in the gathering of meaningful analytical data.
The approach taken in devising the analytical test plan presented
here was to choose "representative" processes that exemplify the three
basic requirements for obtaining a satisfactory description of the flow of
materials. These requirements are choice of process streams, choice of
stream components to be determined and method of analysis.
Two major levels of information are available from the choice of
streams: those streams may be chosen that give an overall material balance
for the plant or the streams can be chosen to give, besides an overall
balance, a balance around each major unit of the plant. For environmental
purposes it is only necessary to know what goes into the plant and what comes
out of the plant. This should offer the lowest cost assessment of the plants
effect on the environment. Realistically however, a number of factors make
such a simple determination very difficult. An example of the difficulties
is a determination of cooling tower effluents (in vaporization and drift).
Since the wind velocity and direction affect the spot concentration of
effluents, sampling and data treatment are very inaccurate. Because cooling
tower effluent is very large, errors in the determination of the composition
of the effluent can seriously affect the overall plant material balance.
In this analytical test plan, the problem of overall vs. unit
material balances has been addressed in a way that will minimize costs for
a given objective. First, those streams have been identified that would
give an overall plant material balance. Should the balance be closed on
appropriate analysis of these streams then that is sufficient. In all
probability this will not be the case. Therefore, those units around
which a material balance should then be made have been listed individually
with an indication of streams to be analyzed. This will allow a determination
of the source of errors in the overall balance and appropriate corrections
can be made. It should be pointed out that the judiciousness of the choice
of units where errors will appear can have a major effect on the costs
associated with this endeavor. Experience is invaluable in making a decision
as to what units should be examined in detail.
As indicated earlier, it is next to impossible to document all
streams for every combination of plant units. It is believed, however, that
the examples included in this test plan are sufficiently general that an
experienced person can make the necessary revisions to fit the plant under
evaluation. This analytical test plan is therefore designed for use by such
skilled personnel. Only minor modifications, together with a few added or
deleted streams, will be necessary for a specific plant.
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The choice of stream components for which analyses are necessary
is very subjective. Again, costs may be the limiting factor in making this
choice. The list of components in this test plan for which analyses are to
be made represents what is felt to be a reasonable choice that should be
determined and that can be determined without an inordinate expenditure of
funds. However, there is almost no limit to additions that can be made to
the list. (A few deletions may also be made in some cases.)
The choice of sampling and analytical techniques to be used in
determining the concentration of selected components in the streams is
somewhat arbitrary. The techniques outlined in this test plan were selected
on the basis of the five considerations detailed in Section 7.1 and the
experience and knowledge of the factors involved in such determinations.
In all such work however, the techniques may have to be changed to fit a
apecific situation. These changes may be necessary due to interference
from other components in the stream, unusual concentration ranges, or others
and can only be recommended for very specific cases by experienced personnel.
The goal of this analytical test plan is to supply sufficient
information for example process and analytical techniques to allow experienced
personnel to rapidly and easily modify the plan to fit the process of interest.
Streams comparable to those in the present test plan can be identified, and
additions and deletions can be made where appropriate. The decision should
be made as to what components are necessary for the desired material balance
and what other components are of interest, and appropriate sampling and
analyses can then be performed. A trial plant material balance should be
made. If this balance cannot be made, then individual units will have to
be investigated to determine the source of errors. Once the source and
magnitude of errors have been identified, a complete balance should be pos-
sible. Future balances are then much simplier since errors are known
before hand.
In some cases, for environmental control purposes or for other
reasons, it may be necessary to extend the analyses to include all input
and output streams from one particular unit. This could be the case, for
example, when comparisons need to be made between two types of control
technology. Then, all streams around that unit would be sampled and
analyzed according to the test plan. No attempt is made in this plan to
point out such units as they will vary from case to case.
It is anticipated that an analytical test plan, modeled along
the lines outlined in this report, will furnish accountability for all
pollutants of interest that may enter the plant in the coal, water,
chemicals, etc., or that may be formed during processing.
1.2 Specific Approach
Two processes, one for coal gasification and one for coal lique-
faction, have been chosen as representative of their respective classes for
the purpose of establishing a baseline analytical system. These processes
are the Lurgi process as representative of gasification and the COED process
of FMC for liquefaction.
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In the case of gasification, the Lurgi process was chosen because
environmental impact statements have been prepared by domestic concerns
who propose to construct integrated commercial facilities (1,2,3), because
the process was reviewed in an earlier phase of this program (4), because
a number of commercial facilities are in operation in other countries (5),
and because almost all units of gasification processes are present. This
information provided an opportunity to assess the environmental impact and
the effectiveness of controls in widely differing situations.
There is unfortunately no such clear-cut candidate for a coal
liquefaction system. The COED (pyrolysis) process was chosen because of
the large body of information which is available in the public literature
(6-15), because this process was also reviewed in an earlier phase of this
program (16), and because an integrated COED facility would probably
include most component operations required by other proposed coal lique-
faction schemes.
Each component operation of each process is described, including
the approximate composition of incoming and outgoing streams, where these
are known. The process descriptions are not intended to be taken as
definitive, and much more detailed information is available in the references
cited. Streams which may be analyzed, especially those streams which may
impact on the environment, are indicated. Sampling procedures, sample
treatment, and analytical methods are described using established or
state-of-the-art technology.
The Lurgi process streams impacting on the environment are out-
lined in detail, with quantities of material where available. Information
is included on actual analysis of some of these streams together with
analyses of comparable streams from other processes where available.
Included for information and comparison are existing or proposed state
and Federal regulations concerning quantities of pollutants allowed.
A discussion of problem areas is given with an indication of other
streams for which analytical data may be necessary for an accurate asses-
sment of environmental impact. A sample data sheet is included that will
serve as a guide in data acquisition.
The COED process streams are similarly treated as an example of
liquefaction. The amount of information available is much less for the
COED process than for the Lurgi process since no commercial plant is yet
in operation. Information in the Lurgi section can, by analogy, be
applied to the COED process.
1.3 Operating Conditions and Flow Rates
Information on typical operating conditions and flow rates are
given for each unit of interest. If more detailed information is required,
references have been given to process reports giving this information in
detail. Differences in operating conditions and flow rates will not affect
the testing procedures in most cases. If quantities of potential pollutants
are less than can be determined by the procedures outlined in this test plan,
then they may be insignificant. If it is eventually decided that extremely
low concentrations must be determined then that particular concentration
range must become a research program itself.
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1.4 Determination of Effect on Environmental Factors of Altered Operating
Conditions
In some cases it may be of interest to determine what effect,
if any, altered operating conditions may have on environmental factors.
For example, hydrogen cyanide and ammonia formation will be affected by
reactor temperature and pressure. In most cases, limits exist as to the
change in operating conditions that can be effected. These limits are set
by such factors as reaction rate, materials of construction, etc., and, for
a given design, are narrow.
To obtain a good picture of the effect of operating variables on
pollutant production, it is necessary that the conditions be changed suffi-
ciently so that the change in pollutant concentration is significantly measur-
able and that three levels of concentration be measured. It is thus suggested
that operating conditions be changed by at least - 10% and that the pollut-
ant concentrations be determined at these levels. Thus, if the reactor
normally operates at 1000°F, then data should also be collected at 900°F and
1100°F. In pilot unit operation, such changes will normally be a part of the
program in process development. In commercial plant operation, efficiency
could well be affected by changes from the design optimum.
It frequently will be necessary to change two or more variables
simultaneously when a change is desired. Thus, lowering the temperature must
usually be accompanied by a decrease in feed rate since reactions are slower.
Each such change must be examined individually and in detail to assure pro-
cess operation.
Variables that may be changed to determine the effect on pollutants
may be summarized. In the reactor, the temperature, pressure, oxygen-steam-coal
ratios and feed rate may be altered. A change in the ratio of raw gas to
quench liquid may cause a change in pollutant output. In the shift section,
changes in operating temperature, pressure, and residence time may be signif-
icant. Also, when part of the gas by-passes the shift reactors, it would be
of interest to determine the effect of changing the ratio of by-pass gas to
reacted gas. (The total CO/H2 ratio must, of course, remain approximately
the same.)
In the gas purification section, altering the temperature, pres-
sure and gas to absorbent ratio could be informative. It is doubtful if use-
ful environmental data could be obtained by varying conditions in the methana-
tion section.
It will be of definite interest to change the coal feed to the
process. At present, the prediction of sulfur forms in the raw gas seems
not to be feasible and the same may hold true for trace elements. There-
fore, predictions of the fate of these materials can only be determined
empirically. With sufficient data, a correlation might be possible.
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2. COAL GASIFICATION
2.1 System Basis
The Lurgi process has been chosen as representative of the class
of systems which may be used to produce primarily clean gaseous fuels from
coal. There is of course a very wide range of processing conditions which
may be applied to coal to generate gas. These range from virtually standard
atmosphere and temperature, as in diminution of total pressure on some
coals to recover occluded methane, to virtually complete gasification of
all organic matter at high temperature, as in the 3300°F steam-oxygen
atmosphere of a Koppers-Totzek gasifier (17). The number of proposed processing
schemes is large (18,19,20), and the range of products which may issue
from the various systems, in addition to noncondensable gases, is extremely
broad. It is in fact this broad product spectrum, common to all processing
schemes excepting those which operate at very high temperatures, which gives
rise to much of the indicated control which must be included in the processing
sequence. If an objective is to conserve or produce the high energy-density
constituents which may be derived from coal, such as coal liquids or methane
equivalent, then processing conditions must be less vigorous than those
which decompose or destroy these materials; and, in general, the processing
sequence is rendered more complex, the pollution potential is higher, and
the conversion efficiency is reduced.
There are a number of variants of the Lurgi process depending on
feed and on end-use requirements, and the processing elements,including the
gasifiers (21), are undergoing almost constant development. We have chosen
the processing scheme proposed for the El Paso Burnham complex (1,2,22) as the
particular example of an integrated Lurgi system which may be designed to
meet domestic energy/environmental standards. The system proposed by Wesco (23)
is practically identical, utilizing essentially the same feed coal and
producing the same end products. For purposes of illustration only, we
have indicated throughout Section 3 the magnitude of the streams as
indicated in El Paso's proposal.
2.2 Process Basis
Figure 1 is a schematic representation of the overall processing
scheme. The Burnham complex is designed to produce 288 MM scfd of synthetic
pipeline gas (954 Btu/scf) from Navajo coal using Lurgi coal gasification.
purification, and enrichment technology. Specifically, Lurgi supplied the"
process design basis for the operations of coal gasification, shift con-
version, gas cooling, gas purification, gas liquor treatment, and methanation.
In addition, commercial air-separation processing will be included to produce
98 percent purity oxygen for the Lurgi gasifiers, and the Stretford process
(British Gas Council) will be used to remove H2S from acid gases separated
from product gas in the gas purification section.
-------
COM.
LURG1 GVSll-iCATlON
AFTER E
TO T6*T FOR.
OET^^V.?>
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- 8 -
Analysis of the feed coal for the complex is shown in table 1
including two estimates of trace element composition.
In addition to product SNG, the complex will produce the
following byproducts:
Product Quantity
Coal Tar 239,250 GPD
Tar Oil 157,370 GPD
Naphtha 74,900 GPD
Crude Phenol 32,470 GPD
Sulfur 167 TPD
Ammonia Solution 332,550 GPD
The system is designed to be self-sufficient with respect to
utilities:
Water
Raw water will be supplied from the San Juan River at a
location approximately 40 miles from the plant site.
Pipeline and pumping facilities will be provided to
transfer the water to the complex where it will be stored
and used as required.
Electricity
On-site power generation will be used to supply all power
requirements for the complex. Power for the mining operations
and the river water pumping systems will be purchased.
Power required for crushing and screening of the coal will be
exported to the mine.
Steam
Steam will be used in the complex both as a motive force
and as a reactant in the gasification processes. All steam
generation will be done onsite with a combination of heat
recovery and gas-fired boilers.
Fuel Gas Production
Low Btu -content fuel gas will be produced in the complex for
use in gas turbines, process heaters, steam superheaters,
and power boilers. Airblown Lurgi gasifiers will be
utilized in the fuel gas production.
-------
- 9 -
Table 1
NAVAJO SUB-BITUMINOUS COAL (1)
Feed to Burnham Complex
Proximate Analysis Weight %
DAF coal 66.2
Ash 17.3
Moisture 16.5
Component Analysis (DAF Coal)
C 76.72
H 5.71
N 1.37
S 0.95
0 15.21
Trace compounds 0.04
HHV r.ange 7500 To 10,250 Btu/lb
Trace Elements
ppm by weight (1) IGS data*
0.3
1.3
17.
0.4
< 0.2
39.
1.6
2.
4.
0.06
5.
1.2
15.
0.2
7.
5.
22.
6.
2.
125.
< 2.
17.
Data furnished by EPA from Illinois State Geological
Survey Analyses of Navajo County Red Seam Coal.
Sb
As
Bi
B
Br
Cd
F
Ga
Ge
Pb
Hg
Ni
Se
Zn
Be
Co
Cr
Cu
Mn
Mo
P
Sn
V
TOTAL
Minimum
0.30
0.10
0.00
60.00
0.40
0.20
200.00
0.50
0.06
1.40
0.20
3.00
0.08
1.10
__.
267.3
Maximum
1.20
3.00
0.20
150.00
18.00
0.40
780.00
8.00
0.50
4.00
0.35
30.00
0.21
27.00
---
___
---
---
...
...
1023
-------
- 10 -
Miscellaneous
Other utilities, such as sewage facilities, fire protection
facilities, instrument air, etc., will all be provided in the
utility systems to ensure self-sufficiency for the complex.
The mine office will be provided potable water, fuel gas,
electricity, and sewage facilities from the complex.
-------
- 11 -
3' GASIFICATION PROCESS DESCRIPTION
3.1 Qualifications
„ , Although El Paso's design for the Burnham Coal Gasification
Complex (1) has been chosen as the basis for the coal gasification
analytical system, most gasification processes (20) will require many
of the same major and auxiliary operations provided in the integrated Lurgi
plant Relatively minor modification will be required to adapt this environ-
mental test system to many of the most well-known candidates for coal
gasification, assuming that a realistic integrated design is available.
Hence, an integrated Synthane design (24) differs primarily in the pressure
regime and mode of operation of the gasifiers, required coal communition,
and in the particular methanation procedure that is proposed. Other processes
may be less complex, especially if methanation facilities are not included
or if only low-Btu gas is produced, cf Koppers-Totzek Process (17) . And
some processes may prove more complex, requiring additions to the analytical
scheme, cf . C02 Acceptor Process (25) which requires additional facilities
for preparing and moving limestone or dolomite through the process. The
modifications to the analytical scheme which may be required for a particular
process or design will be readily apparent in most instances.
Each processing step or operation in the Lurgi/El Paso design is
briefly described below. Significant input and output streams around each
operation are described, and the particular streams requiring analysis are
designated. The suggested analytical procedures for each stream are
referenced to the Analytical Section via table 18.
t-n f» -fTt.^^^ ^ ?lant °perator w111 require other additional analyses
to facilitate his operations and insure product specifications. Our concern
is only with potential pollutants which may impact on the environment?
Each operator of a coal conversion facility may ultimately be
required to account for the disposition of elements present in feed coals
whose toxicity or ultimate impact on the environment warrants control.
Particular sanctions relating to such potentially toxic discharges, including
those relating to atmospheric discharges, discharges to waterways, disposition
of solid wastes, and limiting concentrations in work areas, are still in
process of formulation (26,27,28,29). However, it is almost certain that
the list of controlled substances will grow and that permissible levels in
effluents will continue to be limited.
We have accordingly indicated that all generated effluent streams,
including products, be analyzed for particular trace element composition,
along with feed coal, to permit a gross indication of the disposition of
such elements. Streams to be analyzed are shown in the following figures
and tables with an asterisk (*) . We caution that overall balances for parti-
cular elements may be extremely difficult and costly to obtain around an opera-
ting system of the type and size under consideration. The complexity of the
chemical system, the difficulties associated with representative sampling of
very large streams, and the imprecision of available sensors or test methods
for the monitoring of trace elements all militate against achievement of
-------
- 12 -
perfect balances. Moreover, the capacity of a large physical system
to trap out various elements or compounds, as by chemical combination
with materials of construction or through physical condensation or
deposition introduces another order of complexity, especially if process
changes can result in sudden large emissions.
The "time constant" of the contemplated systems may be very
large indeed, and the time rate of change associated with processing
conditions for a particular unit will have to be taken into consideration
by the analyst if his objective is to obtain a consistent overview of the
process. The "steady-state" condition implied in this analytical scheme
is very difficult to obtain in practice, especially if batch-type or step-
function operations, such as the step-wise addition of coal to the gasifiers,
are superposed on an otherwise continuously operating flow train. And
it may ultimately be necessary to examine the materials of construction
and to physically examine the interiors of vessels or piping for deposited
matter to close the balances in some cases.
All facilities of the type under consideration will include a
flare system to handle emergency discharges from pressurized vessels
and piping. To insure compliance with hydrocarbon emission rates in the
future, it may be necessary to size the flare system to handle the entxre
plant output. The analytical scheme assumes zero discharge at the flare.
Similarly, all such systems will include tankage for storage of
liquid byproducts. Presumably standards of performance now imposed on
storage vessels for gasoline, crude oil, or petroleum distillates (30)
to limit hydrocarbon emissions will apply.
Finally the operator of a physical plant will be aware that
there may be hundreds of valves, packing glands, seals, and other closures
through which harmful pollutants may be accidentally discharged. There
is no practical remedy for such eventualities except vigilance.
-------
- 13 -
Coal Preparation
Figure 2 and Table 2
Coal preparation for the gasification plant will consist of stock-
secondary screening, reclaiming, and sampling facilities. The mine
will have facilities, for receiving coal from trucks, crushing, and primary
screening. The facilities at the mine will be Interconnected to those *
at the gasification plant by a continuous belt conveyor.
Coal, sized at the mine to 1-3/4" x 0", will be received by a
conveyor belt connecting the mine and the gasification plant anTwlll
be distributed by stacker/reclaimer conveyors for blending and storage.
«.K •>/ u C°al samPlinS and stockpiling facilities,which operate less
than 24 hours per day, are sized for 3600 tons per hour (tph), while the
reclaiming and screening facilities are sized for 1500 tph. The gasifi-
cation plant will require 1180 tph when operating at full load, and the
fuel gas production area will require 208 tph additional.
Six storage areas, each 1750 feet long by 124 feet wide and
containing 120,000 tons of coal, will provide blending for Btu control
of gasifier feed and approximately 12 days live storage at full capacity
operation.
The original design (1) included facilities for briquetting
coal fines (<3/16") separated in the screening operations. The briquetting
plant included facilities for mixing coal fines with gasifier tar binder
and compacting the mix into briquettes which could be charged to the
gasifiers along with sized coal. This system has been deleted in the
revised design (2), and it is implied that coal fines will issue as a
saleable additional product. Fines are generated at the rate of 176 tph.
Prior to sale, the fines are (2) indicated to be directed to
a cleaning plant which will separate some 70 tph of refuse. Refuse will
be sent to the coal mines for reburial along with gasifier ash. Facilities
for collection and/or storage of the product fines has not been specified.
The original design also included emergency stockpile and
reclaiming facilities for 650,000 tons of additional sized coal; this
emergency storage has been deleted in the revised design.
Wet-scrubber dust collectors will be installed in the secondary
screening plant to eliminate dust and fume emissions. Sprays will be
used at transfer points for dust suppression.
-------
- 14 -
Influence
Of Weather On
Stockpiles
(2)
Coal
(1)
1-3/4" x 0"
\t
(3)
*Dust and Fumes
(4)
COAL
PREPARATION
AND
STORAGE
Runoff
(5) *Sized Coal
^ to Gasifiers
I Product
(6) Coal Fines
Figure 2
Coal Preparation for Lurgi Plant
-------
Table 2
Coal Preparation for Lurgi Plant
Inlet Streams
(1) Coal, Navajo Sub bituminous; 3600 tph (not used 24 hours per day)
(2) Influence of Weather on Coal Stockpiles and Open Coal Operations.
Outlet Streams
Oi
i
uet treams
(3) Precipitation Run off to Holding Ponds. May include wet scrubber aqueous effluents.
*(4) Dust and Fumes. Atmosphere in enclosed working areas to be analyzed per Table 18 for particulates
Discrete stack emissions to atmosphere from enclosed spaces and from dust collection partlCulates"
equipment to be analyzed per Table 18 for particulates. Atmosphere in vicinity of
coal stockpiles, open conveying and handling equipment, and coal fines product
collection system to be analyzed per Table 18 for particulates.
*(5) Sized Coal to Gasifiers; 1180 tph and to Fuel Gas Production, 208 tph. To be analyzed as feed coal per Table IS.
** (6) Product Coal Fines, 176 tph. 106 net tph cleaned coal fines to sales. 70 tph refuse
directed to mine for burial with gasifier ash. reruse
* Analytical samples, see Table 18.
-------
- 16 -
3.3 Oxygen Production (Figure 3 and Table 3)
The oxygen plant is designed to produce 5650 tons per day of
98% minimum purity vapor phase oxygen.
Atmospheric air will be filtered and compressed to 90 psia in
parallel low-Btu gas turbine/steam turbine-driven centrifugal compressors.
Interceding between the first and second cases and aftercooling
after the second case will be utilized and will remove approximately
130 gpm of water which will be recovered for use elsewhere. The relatively
dry air (0.570 moisture content) will be delivered to parallel cold boxes.
Air entering the cold box will be cooled to liquefaction tempera-
ture by a combination of heat exchange and expansion in a conventional
air separation cycle. Once in the liquid state, oxygen and nitrogen will
be separated by fractionation. The nitrogen (plus a small quantity of
moisture, C02, and oxygen) will be regasified in the heat exchange process
and its energy utilized before rejection to atmosphere. The liquid oxygen
will be gasified to feed the steam turbine-driven oxygen compressors.
These centrifugal units will raise the pressure level to 500 psig and
deliver 5620 tons per day of oxygen to the Lurgi coal gasifiers. The
expansion process in the cold boxes will generate a total of about 500 kW
each at full capacity.
-------
- 17 -
(8)
Atmospheric
Air
(7)
OXYGEN
PRODUCTION
(9)
98% 0,
(10)
Condensate
Figure 3
Oxygen Production
-------
Table 3
Oxygen Production
Inlet Streams
(7) Atmospheric air; 500,000 acfm.
Outlet Streams
(8) Nitrogen and other components of air; 794 tph discharged to atmosphere.
(9) 98 percent minimum purity vapor-phase oxygen to gasifiers; 235 tph.
(10) Water condensate from entering air; 125 gpm, to BFW treating.
oo
I
-------
- 19 -
3.4 Coal Gasification and Gas Liquor Separation
(Figure 4 and Table 41 _
Navajo coal will be gasified with oxygen and superheated steam
PrOC6SS WU1 Pr°dUCe S rSW 83S °f the
Component Volume %
28.03
H2S 0.37
C2H4 0.40
co 20.20
H2 38.95
CH4 11.13
C2H6 0.61
N2+AR 0.31
100.00
Coal will be conveyed from the coal preparation area to coal
bunkers located above the coal gasifiers. The coal will be fed to the
gasifiers through coal locks,which will be pressurized by a slip stream
from the gas cooling area. (Disposition of this gas is discussed later.)
<, Lurgi 8asifiers are water- jacketed vessels. Oxygen and process
steam will be mixed and introduced into the bottom of the gasifiers. The
gasifiers will be operated at about 445 psig. Raw gas leaving the gasifiers
will be cooled rapidly by quenching with a gas liquor spray in wash coolers.
Ash will be removed from the bottom of the gasifier through ash locks and
conveyed via water to the ash disposal area.
Raw gas leaving the wash coolers will be cooled to about 370°F in
the waste heat boilers which produce 112 psia steam. Some of the liquid
condensed in the waste heat boilers will be recycled to the wash coolers,
and the excess will be drawn off to the gas liquor separation unit.
In addition to this excess liquor from gasifiers, the gas liquor
separation unit will receive gas liquor from the gas cooling area. The
gas liquor at high pressure will be flashed to atmospheric pressure in an
expansion vessel to remove dissolved gases. The heavy tar will be settled
out in a subsequent settling vessel and sent to product storage. The
gas liquor, free of heavy tars, will be sent to the gas liquor treatment
area to remove dissolved phenol and ammonia.
Raw gas leaving the gasifier section will be divided into two
streams; one will be sent to shift conversion and the other will bypass
the shift conversion area and will go directly to gas cooling. Crude
gas vented from the cyclic operation of the coal locks, the expansion
gas, and small quantities of recycle gas from other areas will be compressed
and injected into the main stream in the gas cooling area. The recycled
vent gas stream from downstream sections and the lock gas stream from the
gas cooling area are not shown in Figure 4.
-------
- 20 -
(5)
* Sized Coal
Steam
To Gasifier'
(11)
(9) .
Oxygen
to Gasifter
COAL GASIFICATION
AND
GAS LIQUOR SEPARATION
(18)
Ash to
Ash Disposal
(13)
(12)
Crude Gas To Shift
•> Conversion
(14)
Crude Gas^To Gas
Cooling
(15)
Gas Liquor To
Phenosolvan (16)
(17)
Coal Tar To Storage*
Gas Liquors From
Gas Cooling and Fuel
Gas Production
Wash Liquor from
Shift Conversion
Figure 4
Coal Gasification
-------
Table 4
Coal Gasification
Inlet Streams;
*(5) Sized coal from Coal Preparation; 1180 tph.
(9) Oxygen from Oxygen Plant; 235 tph.
(11) Steam; 1,784,000 pounds per hour.
(12) Gas Liquors from Gas Cooling and Fuel Gas Production recycled to gas liquor separator.
(13) Wash Liquor from Shift Conversion recycled to gas liquor separator.
Outlet Streams;
(14) Crude Gas to Shift Conversion; 623 tph dry basis.
(15) Crude Gas to Gas Cooling; 516 tph dry basis.
(16) Gas Liquor to Phenolsolvan.
*(17) Coal Tar to Tar Product Storage, analyzed for trace elements per Table 18.
(18) Ash to Ash Disposal; 186 tph dry basis.
* Analytical Sample, See Table 18.
-------
- 22 -
3.5 Shift Conversion (Figure 5 and Table 5)
The shift conversion area is designed to produce hydrogen by the
"water gas shift" reaction:
co + H20 = C02 + H2 + 16,538 Btu per pound mole
Production of this additional hydrogen will be required to adjust the
H2:CO ratio for proper feed to the methanation plant.
Approximately one-half of the total crude gas will be subjected
to shift conversion. The balance will be bypassed directly to the gas
cooling area. The ratio of the two gas streams will be adjusted to
achieve the desired H2:CO ratio.
Crude gas feed to the shift conversion area will first be cooled
in a waste heat boiler. The cooled gas will then be heated in a series
of heat exchangers before passing through a prereactor to retain carbon-
containing residues. The heated gas will enter the first shift reactor
where the bulk of the carbon monoxide will be catalytically converted.
Condensed gas liquor will be recycled to the wash cooler in the gasification
area.
The first stage hot gas effluent will be cooled in countercurrent
exchange with the feed gas before entering the second shift reactor where
further conversion of carbon monoxide will take place. The effluent gas
from the second shift reactor will be cooled by exchange with feed gas
before leaving the shift conversion unit.
A shift startup heater will be located in a bypass between the pre-
reactor and first shift reactor. The heater is indicated to be fired with washed
crude gas taken from the main stream ahead of the prereactor.
-------
- 23 -
(22)
Crude Gas From
>
Gasification
(14)
(19)
Boiler Feed
Water
Stack Gas From
Startup Heater
SHIFT
CONVERSION
Gas Liquor to Gasification
Wash Coolers
(20)
Converted Gas
to Gas Cooling
(21)
Figure 5
Shift Conversion
-------
Table 5
Shift Conversion
Inlet Streams;
(14) Crude Gas from Gasification; 623 tph dry basis.
(19) Boiler Feed Water.
Outlet Streams:
(20) Gas Liquor recycled to Gasification area. -p-
i
(21) Converted Gas to Gas Cooling; 696 tph.
'•(22) Stack gas from Shift Startup Heater, to be analyzed as combustion stack gas
per Table 18. Note: This stream exists only during shift plant startup periods.
Analytical Sample, see Table 18.
-------
- 25 -
3.6 Gas Cooling (Figure 6 and Table 6*)
The gas cooling area will cool the hot gases from gasification and
shift conversion before they are fed to the low-temperature purification
area The cooling scheme will be arranged to recover and utilize as much
of the process heat as is practical. The gas cooling will be accomplished
in parallel trains. Each train will be further subdivided into two Unes
of exchangers, one for cooling the crude gas bypassing the shift conversion
d ""' to ^^ im^ed heat
Crude gas will first be cooled in a waste heat boiler generating
steam at about 76 psia. Further cooling will be accomplished in a low-
pressure steam generator. The gas will then be cooled in a precooler by an
air cooler. The gas will finally be cooled by cooling waterl
_ The hot gas liquor and tar which will be condensed during cooling
in the waste heat boiler and the low-pressure steam generator will be
recycled to the primary gas liquor separator in the gasification area.
The remaining condensate streams, which will be comprised of gas liquor
and a tar oil naphtha mixture, will be gathered and separated in a second
gas liquor separation unit.
Converted gas from the shift conversion will first be cooled bv
exchange wxta high-pressure boiler feedwater; then in series by generating
low-pressure steam. The gas will then be cooled by an air cooler? Final
cooling will be by cooling water.
Gas liquor and tar condensate from the converted gas in the first
three steps will be cooled with demineralized makeup feedwater and then
combined with the remaining condensate streams from subsequent air and
water cooling systems. The total stream will then be sent to the gas
liquor separator where separation of the tar- oil- naphtha mixture from gas
liquor will occur. Gas liquor will be pumped to the gas liquor treatment
area and tar oil naphtha mixture will be transported to storage. Vent gas
(not shown on Figure 6) is recycled to the gasification area where it is
recompressed into the main gas stream.
-------
- 26 -
(15)
>
Crude Gas From
Gasification
_ (21) .
Crude Gas From
Shift Conversion
GAS COOLING
(23)
Mixed Gas to
Purification
(24)
"Tar Oil Naphtha
Product to Storage
Gas Liquor to
Gas/Liquor Separator
(12)
Gas Liquor to
Phenosolvan Treating
(25)
Figure 6
Gas Cooling
-------
Table 6
Gas Cooling
Inlet Streams;
(15) Crude Gas from Gasification; 516 tph dry basis.
(21) Crude Gas from Shift Conversion; 696 tph dry basis.
Outlet Streams:
(12) Gas Liquor to Gas/Liquor Separation.
(23) Mixed cooled gas to Purification; 1225 tph dry basis.
*(24) Tar-Oil-Naphtha Product to Storage; 110 gpm, to be analyzed for trace constituents
per Table 18.
(25) Gas Liquor to Phenosolvan Treating.
* Analytical Sample, see Table 18.
-------
- 28 -
3.7 Gas Purification (Figure 7 and Table 7)
The gas purification plane is designed to remove H?S and COS to a
total sulfur concentration of 0.1 vppm (parts per million by volume)
before the methane synthesis step. After methanation and first-stage
compression, the gas will be washed further to reduce the C02 content.
The Lurgi Rectisol Process will be used for gas purification.
It is a low-temperature, rr.ethanol-vash process.
The mixed gas from the gas cooling area will be chilled before entering
the prowash tower, where water and naphtha will be removed by cold methanol
wash. Naphtha will be recovered from methanol and water by means of the
naphtha extractor. Naphtha recovery will be maximized by recycling the
naphtha-methanol mixture through the azeotrope column. The methanol will
be recovered by distillation in the methanol-water column. A small water
stream (not shown on Figure 7) will be recycled to gas/liquor separation.
'!hc naphtha-free gas will enter the H2S absorber, where H2S and COS
will be removed down to 0.1 vppra total sulfur by cold methanol wash. Heat
of absorption will be removed by refrigeration. Some of the absorbed acid
gases will be removed from methanol by nultiflash in the flash regenerator.
The remaining acid gases will be stripped in the hot regenerator. All the
acid gas streams will be combined and delivered to the sulfur recovery plant.
Vent gas from the flash regenerator will be recycled to the gasification
area for recompression into the main gas stream (not shown on Figure 7).
Upon the recovery of refrigeration, by exchange with inlet gas,
the sulfur-free gas will exit the Rectisol Unit for ntethanation. Following
methanation and first-stage compression, the methanation product gas will be
returned to the Rectisol Unit where it will again be chilled and will enter
the C02 absorber. The C02 content of the gas will be reduced by the cold
methanol wash. The heat of absorption will again be carried away by
refrigerant. The high-Btu purified dry gas will be warmed and sent to the
second-stage compression unit.
The mechanical compression refrigeration unit will provide refrigera-
tion at two temperature levels. The high-level refrigeration (32 F) will
be used to condense most of trie water out of the mixed gas and the methanation
product gas. The remaining water vapor in the gases will be prevented from
freezing by methanol injection. The low-level refrigeration (about -50 F)
will be used to achieve the low temperature required for effective methanol
wash. The makeup methanol strear. for this system is not shown on Figure 7.
-------
- 29 -
Acid Gas to
Sulfur Recovery
(27)
(23)
Mixed Gas From
Gas Cooling
(26)
Boiler Feed
Water
GAS PURIFICATION
(29)
(28)
Methanation Feed Gas
Process Condensate
to Gas Liquor
Separation
Naphtha Product
To Storage*
(30)
Figure 7
Gas Purification for Lurgi Plant
(Rectisol Plant)
-------
Table 7
Gas Purification for Lurgi Plant
Inlet Streams:
(23) Mixed Gas from Gas Cooling: 1225 tph dry basis.
(26) L.P. Boiler Feed Water; 100,000 pound per hour.
Outlet Streams:
(27) Lean and rich Acid Gases to Sulfur Recovery; 794 tph.
(28) Methanation Feed Gas; 415 tph.
(29) Process Condensate to Gas Liquor Separation.
--'--(30) Naphtha Product to Storage; 10 tph, to be analyzed per Table 18 for trace constituents,
CO
o
-'•- Analytical Sample, see Table 18.
-------
- 31 -
3.8 Methane Synthesis (Figure 8 and Table 8)
The methane synthesis area will convert low-Btu synthesis gas
to methane-rich, high-Btu gas by the following chemical reactions:
CO + 3H2 = CH4 + H20 + 94,252 per pound mole of CH4 @ 700°F
C02 + 4H2 = CH4 + 2H20 + 77,714 per pound mole of CH4 @ 700°F
Both reactions are very exothermic, as indicated by the heats
of reaction listed above. Other minor reactions which will take place
are the hydrogenation of ethylene to ethane and hydrocracking of ethane
to methane.
Fresh feed will be treated for removal of trace sulfur compounds
prior to methanation. Fixed-bed downflow reactors employing pelleted
reduced nickel catalysts will be used. A synthesis loop, in which
process gases are circulated to dilute the concentration of reactants
in the feed, will be used to establish operating conditions conducive
to equilibrium reactor operations. Reaction heat generated in the
synthesis loop will be removed by generating process steam in waste heat
boilers. This steam will ultimately be injected into the gasifiers.
A second-stage, one-pass reactor will be used for final cleanup
of the gas from the recycle methanation reactor. Methanation product
gas from this reactor will be cooled, compressed, and dahydrated before
being sent to the gas transmission line.
Feed gas, entering the unit from gas purification, will be
heated by exchange with the product gas stream leaving the recycle loop.
The hot feed gas will then enter the synthesis loop.
The synthesis loop will be composed of a recycle methanation
reactor, waste heat recovery facilities, and a recycle compressor. The
feed gas composition to the recycle methanation reactor will be set
by combining the fresh feed gas stream with the gas stream circulated
by the recycle compressor. Since the reactor has excess catalyst, the
reaction will proceed to near equilibrium. Thus, the temperature rise
across the reactor can be controlled by setting the concentration of
the reactants.
Reaction heat from the recycle methanation reactor will be
removed in the waste heat boiler. Preheated boiler feed water will be
supplied from gas cooling, with further preheat supplied by cross exchange
with the product gas from the cleanup methanation reactor.
Recycle product from the synthesis loop will enter the cleanup
methanator where the heating value of the gas will be increased to 954 Btu/scf,
Gas leaving the methanator will be cooled by heat exchange with boiler
feed water, cross exchange with fresh feed, then with softened water and
cooling water. Condensed water will be separated and reused in raw water
treatment.
-------
- 32 -
(28)
^
1'iethanation Feed
Gas from
Purification
METHANE SYNTHESIS
(31)
Methane Product
to Compression
(32)
Gas Condensate
to Raw Tlater
Treatment
V
Figure 8
Methane Synthesis
-------
Table 8
Methane Synthesis
Inlet Stream:
(28) Methanation Feed Gas from Purification; 415 tph.
Outlet Streams;
(31) Methane Product to Gas Compression; 257.5 tph. w
OJ
(32) Gas Condensate to Raw Water Treatment; 157 tph. '
-------
3.9 Product Gas Compression and Dehydration
(Figure 9 and Table 9)
The product gas compression and dehydration system will consist
of two trains of steam turbine-driven compressors, followed by a conventional
glycol system for drying the gas. Product gas will be compressed and
dried to meet pipeline specifications.
Product gas from methane synthesis will be compressed by means
of a multistage centrifugal compressor. Hot gas discharged from the
compressor will be cooled with air and cooling water to 90°F. Water
condensed in the final aftercooler will be removed before the gas enters
the dehydrator. Lean glycol, pumped to the top of the dehydrator,
contacts and dries the gas.
Rich glycol from the bottom of the dehydrator will be fed to
the glycol regenerator. Heat added to the bottom of the regenerator and
reflux added to the top will effect a separation of glycol and water.
Lean glycol is pumped back to the dehydrator and the water transferred
to the cooling water system for reuse. Glycol makeup to this system
is not shown in Figure 9.
Synthetic pipeline gas from the area will flow through a 2.3-
mile, 30" pipeline co join El ?aso Natural Gas Company's San Juan main
line.
-------
- 35 -
(31)
->
Methane Product
from Synthesis
GAS COMPRESSION AND DEHYDRATION
(33)
Synthetic Gas
Product to
Pipeline*
(34)
Process Condensate
to Cooling Jater
System
Figure 9
Gas Compression and Dehydration
-------
Table 9
Gas Compression and Dehydration
Inlet Streams;
(31) Methane Product from Synthesis; 257.5 tph.
Outlet Streams:
*(33) Synthetic Gas Product to Pipeline; 256.9 tph. To be analyzed for
trace constituents per Table 18.
(34) Process Condensate to Cooling Water System; 715 pounds per hour.
-• Analytical Sample.
-------
- 37 -
3.10 Sulfur Recovery (Figure 10 and Table 10)
The Stretford process will be used to recover elemental sulfur
from hydrogen sulfide present in the acid gas streams. This Stretford
unit will operate at about 10 psig. A pressure Stretford absorber operating
at about 250 psig will similarly remove hydrogen sulfide from low-Btu
fuel gas in the fuel-gas treatment area.
Hydrogen sulfide will be removed by the Stretford solution.
The solution will then be regenerated by contact with air.
The overall reaction can be summarized as follows:
2H2S + 02 = 2H20 + 2S
Hydrogen sulfide content in the gases from the Stretford unit
will be 10 ppm or less by volume. The carbonyl sulfide (COS) content
will not be significantly reduced by contact with Stretford solution.
The absorption section of the plant will consist of two trains
for treating the lean H£S acid gases and a single train for the rich
K2S acid gas. A single oxidizer section will serve to regenerate the
Stretford solution from the absorbers in both the low- and high-pressure
units.
Feed to the lean ^S absorbers will be a combined stream consisting
of acid gas streams and expansion gas. Feed to the rich H2S adsorber will
be the rich H2S acid gas stream from gas purification and the coal lock
gas stream. Gases fed to the bottom of the absorber towers will be
contacted counter currently by the Stretford solution fed to the top. The
lower part of the absorbers will act as a hold tank for the completion
of chemical reactions between hydrogen sulfide and the Stretford solution.
Off-gas from the top of the lean H2S absorbers will be primarily
C02, but will contain about 10 ppm by volume of hydrogen sulfide and any
residual sulfur compounds (such as COS) not converted in the process. The
stream, combined with the oxidizer off-gas, will be vented to the atmosphere.
Off-gas from the rich H2S absorber will be incinerated.
Rich solution from the absorbers will be combined with solution
from the fuel-gas treating area and flow to the oxidizer. Air will be
blown in at the bottom, and sulfur froth will be floated to the surface.
The sulfur froth will be pumped to the sulfur separator. Sulfur will be
removed from the separator as a liquid and accumulated in a storage pit.
The regenerated Stretford solution will flow from the oxidizer
to the pumping tank. Lean solution will be pumped back to the top of
the absorbers and to the fuel-gas treating area.
-------
38 -
(37)
/t\
Absorber and Oxidizer
Off-Gases to Atmosphere*
Acid Gases From
Gas Purification
(27)
(35)
Acid Gases
From Gas
Liquor
Stripping
LOW-PRESSURE STRETFORD UNIT
7\
Rich Stretford
Solution From
Fuel Gas Treating
(35)
(40)
(39)
(38)
Absorber Off-Gas
To Incineration *
Liquid Sulfur
Product To
Rail Loading*
V
Lean Stretford
Solution to
Fuel Gas Treating
Figure 10
Sulfur Recovery for Lurgi Plant
-------
Table 10
Sulfur Recovery
Inlet Streams;
(27) Acid Gas from Gas Purification; 794 tph.
(35) Acid Gas from Gas Liquor Stripping; 9 tph.
(36) Rich Stretford solution from Fuel Gas Treating.
Outlet Streams;
*(37) Absorber and Oxidizer Off-Gas to Atmosphere; 900 tph. To be analyzed for sulfur compounds
and trace constituents per Table 18.
"'(38) Absorber Off-Gas to Incineration; 23.8 tph. Incinerator stack to be analyzed per Table 18.
*(39) Liquid Sulfur Product to Rail Loading; 7.8 tph. To be analyzed for trace
constituents per Table 18.
(40) Lean Stretford solution to Fuel Gas Treating.
* Analytical Samples.
-------
- 40 -
3.11 Gas Liquor Treatment (Figure 11 and Table 11)
The gas liquor treatment area is designed to remove ammonia
and phenol from contaminated water effluents. The phenol will be recovered
as a byproduct, and the ammonia will be recovered in aqueous solution.
In the latest design, the gas liquor treatment area has been
broken down into sub-sections which are phenol extraction and gas liquor
stripping sub-sections.
The phenol extraction area is designed to remove phenols from
the clarified gas liquors. Two parallel systems are provided for gas
liquor filtration and extraction,one each for contaminated and clean
gas liquors. Common solvent recovery and crude phenol-solvent separation
equipment is provided.
The Lurgi Phenosolvan process will be used to remove and recover
phenols from the clarified gas liquor.
The following paragraph applies to both the contaminated and
clean gas liquor systems. Gas liquor will contain phenols, ammonia, carbon
dioxide and hydrogen sulfide. Incoming gas liquor will first pass through
gravel filters for removal of suspended matter, and then through the
extractors where an organic solvent will extract the phenols (forming the
extract phase). The dephenolized gas liquor (raffinate) will then be
minmed to gas liquor stripping, where traces of solvent will be removed
by nitrogen stripping. The nitrogen stream, which comes from the oxygen
production area, is not shown on Figure 11.
The phenol-rich extracts will flow to the solvent distillation
column. Heat applied to the column will drive most of the solvent overhead.
Vapors from the tower will be condensed and the solvent recycled to the
extractors. Fresh solvent makeup will be added to the recycle solvent
stream. A water-phenol solution will be recovered from the bottom of the
solvent distillation column. This material will be combined with phenol
from the bottom of the solvent recovery scrubber and fed to the solvent
recovery stripper. There, heat will be applied to strip the solvent and
water overhead for recycle to the solvent distillation column. A crude
phenol product will be recovered from the bottom of the stripper and
transferred to storage and loading.
Solvent-rich nitrogen from stripping dephenolized gas liquor
will be returned and contacted with crude phenols to remove the solvent.
Scrubbed nitrogen from the solvent recovery scrubber will be returned to
gas liquor stripping, where the stream will be contacted with filtered
gas liquor to remove traces of phenols. A phenol-rich gas liquor stream
will be returned upstream of the extractors.
The gas liquor stripping area is designed to remove solvent,
ammonia, carbon dioxide, and hydrogen sulfide from the dephenolized gas
liquors. A separate solvent stripper will be provided for the dephenolized
contaminated gas liquor. A single train, except for two ammonia strippers,
will be used for the dephenolized clean gas liquor.
-------
- 41 -
The incoming gas liquors will be separately introduced to
solvent strippers where nitrogen will be used to strip out traces of
solvent picked up in the extraction steps. The solvent-rich nitrogen
streams will be combined for solvent recovery and returned. Makeup
nitrogen will be added to the returned gas and the combined stream will
then be compressed, washed with gas liquor to remove traces of phenol
and recycled through the solvent stripper. '
Solvent-free, contaminated liquor from the solvent stripper will
be sent to ash disposal. Solvent-free, clean gas liquor leaving the solvent
stripper will be heated in the deacidifier to remove dissolved carbon
dioxide and hydrogen sulfide. Acid gases driven off overhead will be sent
to sulfur recovery.
Ammonia removed from the clean gas liquor by steam stripping
in the ammonia stripper will be collected overhead as an ammonia solution
of about 20 weight percent. Waste liquor from the ammonia stripper will
be used directly for cooling tower makeup.
-------
- 42 -
(16)
Gas Liquors
From Gasification
_. (25)
Gas Liquors From
Gas Cooling
PHENOSOLVAN
STRIPPING
Ammonia Solution
to Storage*
(43)
(42)
(35)
7*
Acid Gases to
Sulfur Recovery
(70)
Contaminated Water
to Ash Disposal
(41)
Crude Phenol
to Storage*
Clean Vater to
Main Cooling
Vower
Figure 11
Gas Liquor Treatment
-------
Table 11
Gas Liquor Treatment
Inlet Streams;
(16) Gas Liquors from Gasification/Separation.
(25) Gas Liquors from Gas Cooling.
Outlet Streams:
(35) Acid Gases to Sulfur Recovery; 9 tph.
(70) Contaminated Water to Ash Disposal; 82 tph.
*(41) Crude Phenol to Storage; 5.6 tph. To be analyzed for trace constituents per Table 18.
(42) Clean Water to Main Cooling Tower; 600 tph.
*(43) Ammonia Solution to Storage; 53.6 tph. To be analyzed for trace constituents per Table 18.
LO
I
* Analytical Samples.
-------
- 44 -
3.12 Fuel Gas Production and Cooling
(Figure 12 and Table 12)
Basic design for the fuel-gas production area is provided by
Lurgi. Navajo coal will be gasified in airblown Lurgi gasifiers operating
at about 385 psig.
Sized coal will be conveyed from coal preparation to coal
bunkers located above the gasifiers. The coal will be fed to the gasifiers
through coal locks which will be pressurized by a slip stream of lock-
filling gas. The Lurgi gasifiers are water-jacketed vessels. Hot
compressed air and process steam will be mixed and introduced into the
gasifiers. Ash will be removed from the bottom of the gasifiers through
ash locks and transported to ash disposal.
Hot crude gas leaving the gasifiers will be cooled rapidly by
quenching with a gas liquor spray in wash coolers. Crude gas from the
wash coolers will be further cooled in waste heat boilers to produce 15 psig
steam. A purge stream of tarry gas liquor will be drawn off to gas
liquor separation. Recycle gas liquor will be injected into the wash
cooler as makeup. Boiler feed water and recycle gas liquor streams are
not shown on Figure 12.
Crude fuel gas from this area flows to fuel gas cooling. The
fuel gas cooling area is designed to cool the hot crude fuel gases to
near ambient temperature.
Crude fuel gas will first be cooled by aerial coolers. Final
cooling of the crude fuel gas will be by cooling water. Oily gas liquor
condensed in both cooling steps will be combined and sent to gas liquor
separation.
Cooled fuel gas will be sent to fuel gas treating.
-------
- 45 -
(5) .
X
* Sized Coal From
Coal Preparation
(44).
Steam to
Gasifiers
AIR-BLOWN GASIFIERS
(45)
Air to
Gasifiers
(46)
**
Crude Fuel Gas
to Treatment
(12)
Tarry Gas Liquors
to Separation
(47)
V
Ash to
Ash Disposal
Figure 12
Fuel Gas Production
-------
Table 12
Fuel Gas Production
Inlet Streams:
"'(5) Sized coal from Coal Preparation; 208 tph.
(44) Steam to Gasifiers; 130 tph.
(45) Air to Gasifiers; 266 tph.
I
Outlet Streams: .p.
(12) Tarry Gas Liquors to Gas Liquor Separation.
(46) Crude Fuel Gas to Fuel Gas Treatment; 444 tph.
(47) Ash to Ash Disposal; 42 tph.
Analytical Sample.
-------
- 47 -
3'13 Fuel Gas Treating (Figure 13 and Table 13)
The fuel gas treating area is designed to clean fuel eas by
treating with the Stretford process. This Stretford process will
operate at about 250 psig in contrast to the 10 psig operating pressure
for the mam Stretford unit. Hydrogen sulfide will be removed by the
Stretford solution. The solution will then be regenerated by contact
with air. Overall, the reaction can be summarized as follows:
2H2S + 02 = 2H20 + 2S
Hydrogen sulfide content in the gases will be less than 10 vppm.
Carbonyl sulfide (COS) content of the fuel gas will not be significantly
reduced by contact with the Stretford solution.
A single oxidizer section located in the sulfur recovery area
will serve to regenerate the rich Stretford solution from the absorbers
in this section.
Crude fuel gas is fed to the bottom of a contactor tower and
washed countercurrently with lean Stretford solution fed into the top.
The lower part of the absorber and the digester vessel downstream will
act as a hold tank for the completion of chemical reactions between hydrogen
sulfide and the Stretford solution.
Lean solution from the sulfur recovery area will be pumped to
the contactor. Energy will be extracted from the rich solution leaving
the digester by depressurizing the solution through a power recovery
turbine coupled to the booster pump. Rich solution will be transferred
to the sulfur recovery area for regeneration.
A portion of the treated fuel gas at near ambient temperature
and about 250 psig will be used to fire gas turbines in steam and power
generation. The balance of the stream will flow to gas compression where
the fuel gas will be heated and expanded to recover power, and then be
used to fire heaters and boilers.
-------
- 48 -
(46) ^
X
Crude Fuel Gas
from Production
(40)
Lean Stretford
Solution From
Sulfur Recovery
HIGH PRESSURE STRETFORD
(48)
Treated Fuel Gas
to Power Generation
and Gas Compression.
(36)
Rich Stretford
Solution to
Sulfur Recovery
Makeup
Stretford
Solution
(71)
(72)
\
/ Solution
Purge
Figure 13
Fuel Gas Treating
-------
Table 13
Fuel Gas Treating
Inlet Streams;
(40) Lean Stretford Solution from Sulfur Recovery.
(46) Crude Fuel Gas from Production; 444 tph.
(71) Makeup Stretford Solution (Quantity not specified).
Outlet Streams;
(36; Rich Stretford Solution to Sulfur Recovery.
(48) Treated Fuel Gas to Power Generation; 443 tph.
(72) Solution Purge (Quantity not defined).
I
js
-------
- 50 -
3.14 Steam and Power Generation
(Figure 14 and Table 14)
Power generation will be from four gas turbine driven generator
sets. The capacity of each generator is 33% of normal plant requirements.
Excess capacity is to assure continuous, full-load operation with one
unit removed from service for inspection or repair.
Steam generation will consist of a combination of process waste
heat boilers and heat recovery boilers on gas turbine exhaust. Generally,
low pressure steam from the process waste heat boilers will supply process
heat requirements, and high-pressure steam will provide process reaction
steam and motive power steam.
Eight gas-turbine, heat-recovery boilers will be provided; four
on power generation turbines and four on air compression turbines. Excess
capacity in the form of one spare electrical generator train plus a
free standing boiler will provide flexibility in meeting peak demands
and will assure continuous full-load operation whenever one unit is
shutdown for inspection or repair.
Steam generated at 612 psia in the methane synthesis area
will be superheated to provide motive power steam and process reaction
steam to the coal gasifiers.
Hot exhaust gases from the gas turbines will be utilized in
heat recovery boilers to generate 1150 psig superheated steam. The boilers
will be supplemental fire as required to maintain proper steam conditions.
The standing boiler will be fuel gas-fired to generate 1150 psig superheated
steam in emergency situations, for startups, and for flexibility.
-------
(48)
Treated Fuel
Gas From
Treating
(49)
Boiler Feed
Water
/v 4200 GPM
- 51 -
(51)
Deaerator
Vent *
(52)
Stack Gases *
STEAM AND POWER GENERATION
(11,44)
Superheated Steam
to Process
Electrical
Requirement to
Plant
56,700 KWH
(50)
Slowdown Streams
to Cooling Water System
Figure 14
Steam and Power Generation
-------
Table 14
Steam and Power Generation for Lurgi Plant
Inlet Streams:
(48) Treated Fuel Gas; 443 tph.
(49) Boiler Feed Water; v4200 GPM.
Outlet Streams:
(ll)+(44) Superheated Steam at 1150 and 550 psig and Saturated Steam at 15 psig to process;
(50) Boiler Blowdown to Cooling Water System; 60 GPM.
*(51) Deaerator Vent to Atmosphere; -40 GPM. To be analyzed for trace constituents per Table 18.
*(52) Stack Flue Gases to Atmosphere. To be analyzed per Table 18 as stack gases.
to
I
* Analytical Samples.
-------
- 53 -
3.15 Raw Water Treating (Figure 15 and Table 15)
The raw water treating system will receive approximately 6000 gpm
of raw water and 600 gpm of process condensate. About 2300 gpm of zeolite
softened water for makeup to the low-pressure steam generation systems
and 2200 gpm of demineralized water for boiler feedwater and gasifier jacket
water will be produced. In addition, an average of 20 gpm of potable water
for the plant's domestic water users, 129 gpm for general plant utility
water system, and about 440 gpm of treated water for cooling tower makeup
will also be produced. Condensate returns from the plant will be collected
and treated to remove trace hydrocarbon contaminants before being utilized
as makeup to the high-pressure steam generation systems. The hydrocarbon
removal system has not been detailed, nor has the disposition of separated
hydrocarbon been indicated.
Raw water will be pumped from the raw water reservoir to a lime
softener-clarifier for chemical treatment. Pebbled quicklime will be
unloaded pneumatically and conveyed to a storage silo. Lime slaking
systems will provide a lime feed to the clarifier. Alum feeder and polymer
feeder systems will provide other necessary water treating chemicals to
the clarifier. Treated water from the clarifier will drain to a clearwell
which gives a brief storage time. From the clearwell the water will be
pumped through anthracite-filled gravity filters. The filtered water will
then flow through either demineralizer sets or zeolite softener sets and
then on to the steam generation areas.
Process coidensate will be airblown to strip dissolved light
hydrocarbon gases and carbon dioxide before being combined with the zeolite
softener effluent.
A small stream of treated water will be chlorinated and piped
to an elevated potable water tank. The plant potable water system will
then be supplied from this tank by gravity.
Tankage for the water systems will be as follows:
a. Treated Water (2) 2,500,000 Gallon Tanks
b. Demineralized Water (2) 200,000 Gallon Tanks
c. Softened Water (2) 750,000 Gallon Tanks
d. Condensate (2) 1,100,000 Gallon Tanks
-------
- 54 -
(56)
Degasser Vents
to Atmosphere"
(53)
Raw Water*
(54)
Treating Chemicals
(32)
Process Condensate
from Methane
Synthesis
RAW WATER TREATING
(55)
Treated Water
Streams to Plant
(58)
Lime Treater
Sludge to
Ash Disposal
(57)
Slowdowns to
Ash Disposal
Figure 15
Raw Water Treating
-------
Table 15
Raw Water Treating
Inlet Streams;
(32) Process Condensate From Methane Synthesis; 157 tph.
*(53) Raw Water; 6000 gpm. To be analyzed as water sample per Table 18.
(54) Water Treatment chemicals, including pebbled quicklime, sodium hydroxide solution,
sulfuric acid, alum, polymer solution, chlorine, hypochlorite, demineralizer
and zeolite polymers, salt, anthracite filter media.
I
Ul
Outlet Streams;
(55) Treated Water to Plant.
*(56) Vent from condensate degasser to atmosphere; 35 gpm. To be analyzed for trace
constituents per Table 18.
(57) Blowdowns to Ash Disposal; 270 gpm.
(58) Lime Treater Sludge to Ash Disposal; 220 gpm.
* Analytical Samples.
-------
- 56 -
3.16 Cooling Water System (Figure 16 and Table 16)
Two separate cooling water systems will be provided for the
complex: (1) a clean water system which will be dedicated exclusively
to the cooling of pure oxygen streams, and (2) the main system which will
be for the remaining cooling loads within the complex. Both systems
will be designed to produce 75°F cooling water.
The clean water system will consist of one two-cell cross-flow
tower designed to reject 62 million Btu per hour at a circulation rate
of 8200 gpm. The main cooling water system will consist of three five-
cell cross-flow towers designed to reject 1144 million BTU per hour at
a circulation rate of about 153,000 gpm.
The clean cooling water system will be supplied from one two-
cell cooling tower. Each cell will be rated at 31 million Btu per hour.
The tower will be equipped with three vertical turbine pumps mounted
in the pump pit, with one pump acting as a spare. Makeup water to the
clean water system will be blowdowns from the process waste heat and
power boilers. Total flow available for makeup will be about 460 gpm.
Cold water will leave the tower at 75°7 and return at 90°F. Slowdown
from the clean cooling tower will be used as part of the makeup for the
main cooling tower.
The main cooling water system will be supplied from three five-
cell cooling towers. Each cell will be rated at 76 million BTU per
hour. The cooling towers will be erected over a concrete basin with a
pump pit to the side. Each tower will be equipped with four vertical
turbine pumps mounted in the pump pit, with one pump acting as a spare.
The main source of makeup water, approximately 2400 gpm, will be supplied
from gas liquor stripping. Other makeup streams include about 440 gpm
of treated water, about 250 gpm of blowdown from the clean cooling water
system, and 20 gpm of treated sewage. Cold water will leave the tower
at 75°F and return at 90°F.
Water treating chemicals will be added to both water systems
as required to control corrosion, scale formation, plant growth, and pH.
Sidestream filtration will be used to control the suspended solids.
-------
- 57 -
(42)
Clean Water From
Gas Liquor Treatment
(62)
Main Plant Return
(60)
Miscellaneous Additions
(61)
Oxygen Plant
Return
(59)
Water Treatment
Chemicals (65)
COOLING WATER SYSTEM
(66)
\
Evaporation
and Drift*
(63)
Main Plant
Cooling Water
(64) ^
Oxygen Plant
Cooling ^i
Cooling Tower
Slowdown to
Ash Disposal
Figure 16
Cooling Water System
-------
Table 16
Cooling Water System
Inlet Streams:
(42) Clean Water from Gas Liquor Treatment; 2400 gpm.
(59) Water Treatment Chemicals including anti-foam package, biological (growth control)
package,, inhibitor feed package, pH (sulfuric acid) package.
(50)+(60) Miscellaneous Slowdowns and Treated Water Additions; 920 gpm.
(61) Oxygen Plant Return; 8200 gpm.
(62) Main Plant Return; 153,000 gpm.
00
I
Outlet Streams:
(63) Main Plant Cooling Water Requirement; 153,000 gpm.
(64) Oxygen Plant Cooling Water Requirement; 8200 gpm.
'-(65) Evaporation from Towers; 2800 gpm and Drift from Towers; 160 gpm. Atmosphere downwind of
towers to be analyzed for trace constituents per Table 18.
(66) Blowdown from Cooling Water System to Ash Disposal; 330 gpm.
Analytical Sample.
-------
- 59 -
3.17 Ash Disposal (Figure 17 and Table 17)
Wet ash facilities will be designed to handle all of the ash
discharged from the airblown and oxygen-blown gasifiers. The equipment
will be adequately designed to allow for maximum anticipated variations
in ash rate. Coarse ash will be trucked to the mine and fine ash will
be stored in a pond.
The ash facilities at the mine and gasification area are inter-
connected by a continuous belt conveyor.
Ash will be discharged dry and hot from the individual gasifier
ash locks into a sluiceway. Water flowing in the launder will quench
and transfer the ash to classification and dewatering equipment. The
coarse dewatered ash will be transferred on a belt conveyor to the mine
ash handling area for disposal in the mine.
The fine ash from the classification step will be dewatered in
a thickener and pumped to a fine ash pond for disposal. Water from the
thickener will be reclaimed and recycled to the sluiceway. Excess water
in the system will be bled to evaporation ponds for disposal.
-------
- 60 -
Lime Treating Sludge
rFrom Raw Water Treating
(58)
(57)
Slowdown From
Raw Water Treating
(66)
Cooling Tower Blowdown
(39)
Contaminated
Gas Liquor
(18)
Dry Ash ,-rom
Main Gasifiers (47)
\'
Dry Ash From
Fuel Gas Production
ASH DISPOSAL
(69)
Wet J-'ine Ash Slurry
to Fine Ash Pond *
(68) ^
Separated ;,;ater to
Evaporation Ponds*
(67).
Wet Ash to Mine*
Figure 17
Ash Disposal
-------
Table 17
Ash Disposal
Inlet Streams;
(18) Dry Ash from Main Gasifiers; 196 tph.
(39) Contaminated Gas Liquor; 330 gpm.
(47) Dry Ash from Fuel Gas Production; 42 tph.
(57) Slowdown from Raw Water Treating; 270 gpm.
(58) Lime Treated Sludge from Raw Water Treating; 220 gpm.
(66) Cooling Tower Slowdown; 330 gpm.
Outlet Streams;
*(67) Wet Ash to Mine; 286 tph. To be analyzed for trace constituents per Table 18.
*(68) Separated Water to Evaporation Ponds; 900 gpm. To be analyzed for trace constituents per Table 18.
Atmosphere over evaporation ponds to be analyzed per Table 18.
*(69) Wet Fine Ash Slurry to Fine Ash Pond; 150 gpm. To be analyzed for trace constituents per Table 18.
Atmosphere over evaporation ponds to be analyzed per Table 18.
* Analytical Samples.
-------
- 62 -
3.18 Process Analytical Summary
The streams indicated for analysis around the Lurgi Process model
are summarized in Table 18,, along with specific references to suggested
sampling and analytical procedures described in the Analytical Sections 5-9.
Table 19 shows constituents present in coal feeds to gasification for SNG
and fuel gas production.
The gasification system as described herein will almost certainly
be modified appreciably before commercialization. The analyst is urged to
adapt the logic of this analytical scheme to his specific requirements.
It is almost certain that existing legal sanctions will have
increased by the time coal gasification systems are commercialized in
this country. The analyst may be required to extend the list of analyses,
although we have attempted to anticipate some future requirements. For
example, polynuclear aromatic (PNA) materials, which may exhibit carcino-
genic properties (31,32), may be present in almost any of the effluent
streams from this system, and may also constitute significant fractions
of the coal liquid byproducts. We have not indicated that all streams be
analzyed for PNA, although this may be a future requirement. Similarly,
we have not indicated that the coal liquid products be so analyzed, even
though they will certainly contain harmful PNA, since the potential hazards
of such materials are recognized within the industrial sector which now
manufactures and utilizes coal-derived byproducts.
We have not always indicated that particulates recovered
from gas or atmospheric samples be completely analyzed. The composition of
coal dust, for example, should approximate the feed coal composition. However,
procedures for determining the ultimate composition of particulate samples
is included in the Analytical Sections. Future restrictions may require
such definition. Moreover, it will be possible to analyze any stream in
a given sample class for any of the components for which analytical procedures
are indicated, so that the analyst may readily expand -he analytical system to
meet anticipated requirements.
We have attempted to indicate that all heater, incinerator, and
boiler stack effluents shall be analyzed, even though such heaters may
not have been specifically designated in the process scheme. Table 20 shows
constituents expected in flue gases from boiler and heater stacks. Similarly,
we intend that the atmosphere in the vicinity of all storage tankage or open
storage areas, water cooling towers, and over all holding and evaporation
ponds be analyzed for free hydrocarbons. The particular location and plant
layout, prevailing winds, and climate will be taken into consideration
in the sampling scheme.
-------
- 63 -
This plant will generate additional long-term residuals not detailed
in the processing sequence, including spent catalysts (from shift corsv-roion
and mcthanation) and spent filter media. Although such materials may
be expected to be sulfated in general, and to contain ether polluting materials
when discharged, the quantities involved should not significantly affect
overall long-term plant balances, unless the expected turnover period is
shortened due to malfunction or emergency. Analysis of such discharged
streams is indicated, however, to ascertain downstream pollution potential,
since such materials will probably be buried with ash in this case unless
metal values justify reclamation or unless future sanctions forbid such
disposition. Very little attention has so far been given to the "neutralization"
of such materials from other industrial processing.
We note also that it is necessary to chemically clean the boilers
and associated piping in the power plant before these facilities are placed
in operation, and at intervals of 2-3 years thereafter (40). Other plant
facilities may require similar treatment. Both acidic and alkaline solutions
are used in chemical cleaning. The acidic wastes would typically consist
of solutions of hydroxyacetic and formic acids, or hydrochloric acid, at
concentrations of less than 5%. The alkaline wastes would typically consist
of dilute sodium phosphate solutions (less than 1%). A large amount of
water would have to be used for flushing the system.
For a boiler of the size indicated, the total amount of waste
produced could amount to several hundred thousand gallons of acidic and
alkaline solutions, and up to a million gallons of flushing water. In
this case, these wastes may be routed to settling ponds or to the ash basins,
where they may be diluted or neutralized.
Finally, although not included in the process scheme herein
presented, potential pollution from mining areas and from associated ash
disposal operations are additional aspects that will concern any process
developer and the immediate population, including plant operators, which
may be affected. Environmental guidelines for water discharges from
mining facilities already exist (33), and it: is probable that future relevant
solid waste restrictions will be promulgate-!.
-------
Table 18
Summary of Effluent Streams to be Analyzed for Lurgi Plant
COAL GASIFICATION
LURGI PROCESS MODEL
Stream No.
4
Stream Name
Dust and Fumes in Coal Preparation Area
Analysis For
17
22
24
30
Sized Coal to Gasifiers and to Fuel
Production (See Tables 1 and 19)
Coal Tar Product*
Shift Startup Heater
Stack Gas
Tar-Oil-Naphtha Product*
Naphtha Product*
Atmosphere in enclosed spaces, discrete
stack emissions from enclosed spaces
and from dust collection equipment,
and atmosphere in vicinity of coal piles,
open conveying and handling equipment, and
coal fines collection system to be analyzed
for particulates.
Complete coal analysis including
trace elements.
Trace Sulfur Compounds
Trace Elements
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
Sulfur
Trace Elements
Sulfur
Trace Elements
Analytical Section Reference
Total particulates to be determined in
enclosed spaces using a high volume sampler,
Section 9; in stacks using EPA Method
No. 5, Section 9; and the ASTM D 1739
dust fall test will be performed at various
site locations.
Coal will be analyzed for the elements
listed in Section 7, Table VI and will be
analyzed to determine its gross composition
as indicated in Section 7, Table VII.
Tar will be analyzed for total sulfur *
(Section 8, Table X); and the trace 5
elements listed in Section 8, Table VIII I
will be measured.
The stack gas will be analyzed for 802/303,
NOX, CO, C02, COS, H,S, and CH3SH and
for particulates. Refer to Section 9.
This stream will be analyzed for the metals
listed in Section 8, Table VIII and for
total sulfur as indicated in Section 8,
Table X.
This stream will be analyzed for the metals
listed in Section 8, Table VIII and for
total sulfur as indicated in Section 8,
Table X.
-------
Table 18 (Cont'd)
Summary of Effluent Streams to be Analyzed for Lurgi Plant
COAL GASIFICATION
LURGI PROCESS MODEL
Stream No.
33
37
38
39
41
43
Stream Name
Analysis For
Synthetic Gas Product
Absorber and Oxtdizer Off-Gases and
Incinerator Stack Gases
Liquid Sulfur Product*
Crude Phenol Product*
Aqueous Ammonia Solution Product*
Trace Sulfur Compounds
Metal Carbonyls
Trace Sulfur Compounds
Particulates (V, Na)
Trace Elements
Total Sulfur
Trace Elements
Trace Sulfur Compounds
Trace Elements
Analytical Section Reference
The gas will be analyzed for particulates,
COS, H2S, CH3SH and 802/803; and for iron,
nickel, and cobalt carbonyls. Refer to
Section 9.
Off-gases to be analyzed for particulates
and for COS, H2S, CH3SH and S02/S03, see
Section 9. In addition Na and V will
be determined on particulates, see (
Section 7. &
Ln
Sulfur will be analyzed for the metals '
listed in Section 8, Table VIII, by
adaptation of methods which were designed
for oil analysis.
The trace elements in Section 8, Table VIII
will be determined, and the sulfur content
will be determined.
Sulfide, thiocyanate, and sulfite will be
measured, Section 6, Table IV. The
metals which are listed in Section 6,
Table IV will be determined.
51
Deaerator Vent Gases
Particulates
Particulates will be determined.
-------
Table 18 (Cont'd)
Summary of Effluent Streams to be Analyzed for Lurgi Plant
COAL GASIFICATION
LURGI PROCESS MODEL
Stream No.
52
Stream Name
Boiler Stacks and Heaters (multiple
stacks are involved, including heaters
in shift conversion and gas compression
areas, see Table 20).
Analysis For
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
Analytical Section Reference
The stack gases will be analyzed for
S02/S03, NOX, CO, C02, COS, H2S and
CH3SH and for particulates. Refer to
Section 9.
53
56
65
Raw Water to Process
Degasser Vent Gases
Evaporation and Drift from Cooling Towers
67
Wet Ash to Mine
Complete Water Analysis
Trace Sulfur Compounds
Hydrocarbons
Atmosphere in vicinity of
cooling towers to be sampled for:
Trace Sulfur Compounds
Trace Elements
Hydrocarbons and PNA
Complete coal solids analysis
and complete water analysis.
Raw water will be analyzed for all
components listed in Section 6, Table IV.
Vent gases will be analyzed for Thiophene,
CS2, S02/S03, COS, H2s and CH3SH and for
benzene, toluene, and other volatile organics.
See Section 9.
A high volume sample will be collected and
the particulates will be analyzed for the
metals listed in Section 7, Table VI.
In addition the atmosphere will be sampled
for benzene, toluene, and other volatile
organics; polynuclear aromatics; and for
thiophene, CS2, S02/S03, COS, H2S, and
CH3SH (Section 9).
The solid material will be analyzed for the
components listed in Section 7, Tables VI
and VII. The aqueous phase will be
analyzed for the components listed in
Section 6, Table IV.
-------
Table 18 (Cont'd)
Summary of Effluent Streams to be Analyzed for Lurgi Plant
COAL GASIFICATION
LURGI PROCESS MODEL
Stream No.
68
Stream Name
69
Ash Water Effluent to Evaporation
Ponds*
Wet Fine Ash Slurry to Evaporation
Ponds*
Analysis For
As for Stream 67
As for Stream 67
Analytical Section Reference
The solid material with be analyzed for
the components listed in Section 7,
Tables VI and VII. The aqueous phase
will be analyzed for the components
listed in Section 6, Table IV.
The solid material will be analyzed for
the components listed in Section 7,
Tables VI and VII. The aqueous phase
will be analyzed for the components
listed in Section 6, Table IV. ,
Atmosphere over ail evaporation and holding ponds and vicinity of all storage tankage to be sampled and analyzed for
VivHrnearbons and trace sulfur compounds.
hydrocarbons and trace sulfur compounds
-------
Table 19
Coal Input to Lurgi Coal Gasification (2)
To To
Constituent Gas Production Fuel Gas Production
Carbon + HC
Sulfur
Ash
Moisture
(Lbs/Hr)
1,237,000
13,400
373,200
315,000
1,938,600
(Lbs/Hr)
265,200
2,900
80,000
67,500
415,600
oo
I
MMBTU/HR (H.H.V.) 16.795 3.601
-------
Table 20
Component
Water Vapor
Nitrogen
Oxygen
Carbon Dixide
Sulfur Dioxide
Nitrogen Oxides (N02)
Particulates
Flue-Gas Streams from Boiler
and Heater Stacks (2)
El Paso Complex
Gas Turbines and Boilers
234, 600
4,798,700
1,006,400
552,100
290
480
NIL
6,592,600
Lbs/Hr
Steam
Superheater
29,100
243,300
11,800
76,500
40
70
NIL
360,800
Heaters
6,400
53,300
2,600
16,800
10
15
NIL
79,100
-------
- 70 -
3.19 Unit Material Balances
As indicated in Section 1, the object of a material balance around
a coal gasification plant, from an environmental viewpoint, is to determine
all effluents to the environment and to furnish accountability for all
potential pollutants entering the plant or produced in the plant. The
analytical summary in Section 3.18 represents the simplest approach to
this balance. However, as indicated in Section 1, either a balance may
not be made or questions may arise as to the accuracy of some measure-
ments. In this case, analyses may have to be made around certain key
units. This would increase the cost considerably. If a balance could
not be established after this effort, then it would be necessary to trace
each component of interest through every unit. The cost would then be
extremely high.
In paragraphs 3.19.1 through 3.19.7 that follow, additional
streams from key units are designated as those that may have to be analyzed
to complete a balance or find a source of error. The analyses of the
streams indicated in these paragraphs require 28 to 29 more samples than
the 20 indicated in Table 18. If satisfactory results were not obtained,
then it may be necessary to analyze all 72 streams of figure 1.
3.19.1 Coal Preparation
It would be appropriate to determine the concentration of organic
and inorganic materials in the run-off from the coal area (streams 2 and
3) as a function of the quantity of rainfall.
3.19.2 Gas Cooling
Streams 15, 21, into gas cooling and streams 12, 23 and 25 from
gas cooling would have to be analyzed to check the analysis of stream 24.
3.19.3 Gas Purification
Streams 23 and 26 into gas purification and streams 27, 28 and 29
from the purification must be analyzed to check stream 30.
3.19.4 Sulfur Recovery
In order to check streams 37, 38 and 39 it will be necessary to
analyze streams 27, 35 and 36 into the Low-Pressure Stretford Unit and
stream 40 out of the unit.
3.19.5 Fuel Gas Treating
It would be wise to analyze stream 72 (solution purge) from the
high pressure Stretford unit. How this is done is difficult to predict
as this purge may be continuous, intermittent or, in some cases, none at
all.
-------
- 71 -
3.19.6 Cooling Water System
This is one of the most critical units for over-all material
balance. Good sampling of evaporation and drift losses are difficult
and other factors may make the cooling towers research projects in them-
selves. To get a material balance, it may be necessary to analyse
streams 42, 59, 60, 61, and 62 into the system and streams 63, 64 and 66
out of the system. Even this may not be sufficient as trace pollutants
can be trapped in slime in the towers. This also may have to be analyzed
and its quantity estimated. Whether or not these analyses will check the
analysis of stream 65 is uncertain due to the sampling problems mentioned
above.
3.19.7 Ash Disposal
The streams into ash disposal should probably be analyzed and
compared with effluent streams 67, 68 and 69 to be sure no air pollutants
are escaping. This would entail analyses of streams 18, 39, 47, 57, 58 and 66.
3.19.8 Special Unit Material Balances
In some cases, as indicated in Section 1, it may be desirable to
determine a material balance around a particular unit. This could arise,
for example, when it is necessary to know the contribution of a particular
unit to the total effluent/heat load of a plant. Sampling would then be
carried out on all the streams in and out of the unit and the samples would
be analyzed according to the methods outlined later in Sections 7 through
12. An example of this might be Gas Purification (Section 3.7). All
streams in figure 7, together with any others in the particular unit under
consideration (e.g., vents, liquid purges, solution makeup, etc.), would
then be sampled and analyzed. These analyses, along with heat, steam, hot
water, electrical and cooling water requirements, would allow the pollutant/
heat load of this unit to be compared with similar units in other plants.
It is anticipated that no special revisions of this analytical test plan
will be necessary to accommodate such requirements.
-------
- 72 -
4. COAL LIQUEFACTION
Liquefaction, as a term applied to coal processing, is not so
definitive as in gasification. The term has been applied generally to
processes which produce liquid products from coal, but is also used in
connection with solvent or chemical refining processes which desulfurize
or de-ash coal (34,35) and to processes such as combined gasification and
catalytic recombination, as in the Fischer-Tropsch synthesis, to produce
organic liquids (36). The primary de-ashed product from current solvent-
refined coal processes, for example, is not liquid at ambient temperatures
(37). And the major products from some "liquefaction" processes are not
liquids, but rather solid chars containing most of the ash in the original
feed coal.
The COED process chosen for the coal liquefaction model falls into
this category. Some 50-60 weight percent of the starting coal feed issues
as product char, containing about the same amount of sulfur and having
about the same heating value as the feed coal. Economic considerations
would probably require that a commercial COED facility include a char
gasification facility, and the FMC Corporation, the process developer,
is currently engaged in char gasification studies (38) .
4.1 System Basis
The COED process has been under development by FMC Corporation as
Project COED (Char-Oil-Energy Development) since 1962 under the sponsorship
of the Office of Coal Research of the U.S. Department of the Interior (6-16).
Bench-scale experiments led the way to design and construction in 1965
of a process development unit (PDU) employing multistage, fluidized-bed
pyrolysis to process 50-100 pounds of coal per hour (6). Work with the
PDU was extended to other coals in 1966, and hydrotreating of COED oil from
the PDU was studied by Atlantic Richfield Company (7). Correlated studies
included an investigation of char-oil and char-water slurry pipelining economics
high-temperature hydrogenation for char desulfurization, and an economic
appraisal of the value of synthetic crude oil produced from COED oil.
A COED pilot plant able to process 36 TPD of coal and able to hydro-
treat 30 BPD of oil was designed and constructed at Princeton, New Jersey in
1970 (10). The pilot plant was operated successfully on a number of coals
in 1971-72 (11). Development of the process is continuing, with major
funding provided by OCR.
The process basis for our process model is the design study
developed by FMC Corporation in 1973 for a "25,000 TPD COED plant" (39).
Process flowsheets were developed for the pyrolysis plant, raw oil filtration
section, and for the hydrotreating facility. This design feeds 25,512 TPD
of an Illinois No. 6-seam coal containing 5.970 moisture, 10.6% ash, and
3.8% sulfur. 12,512 TPD of product char is recovered, along with 3945 TPD
of hydrotreated oil (24,925 bpd of indicated 25° API gravity). Flowsheets
were not developed for coal preparation, gas treatment, hydrogen manufacture,
oxygen manufacture, sulfur production, water and waste treatment, or
utilities generation. We have estimated some of the auxiliary requirements (16).
-------
- 73 -
4.2 Process Basis
Figure 18 is a schematic representation of the overall processing
scheme. The COED process is a continuous, staged, fluidized-bed coal
pyrolysis operating at low pressure and is designed to recover liquid,
gaseous, and solid fuel components from the pyrolysis train. Heat for the
pyrolysis is generated by the reaction of oxygen with a portion of the
char in the last pyrolysis stage and is carried countercurrently through
the train by the circulation of hot gases and char. Heat is also introduced
by the air combustion of the gas used to dry feed coal and to heat fluidizing
gas for the first stage. The number of stages in the pyrolysis and the
operating temperatures in each may be varied to accomodate feed coals with
widely ranging caking or agglomerating tendencies.
Oil that is condensed from the released volatiles is filtered
on a rotary precoat pressure filter and catalytically hydrotreated at
high pressure to produce a synthetic crude oil. Medium-Btu gas produced
after the removal of acid gases is suitable as clean fuel, or may be
converted to hydrogen or to high-Btu gas in auxiliary facilities. Residual
char (50-60/, of feed coal) that is produced has heating value and sulfur
content about the same as feed coal.
A large sample of Illinois coals has been analyzed by Ruch and
coworkers (41) . As an approximate number, Table 21 lists the mean analytical
values of trace elements found for Illinois coals, which represent feed for
this s tudy .
This system will produce about 500 TPD of sulfur, in addition to
char and syncrude.
are
&The,?uaiifications and considerations outlined in Section 3.18
r* edification are also applicable here. It is intended that all
heater and boiler stack effluents shall be analyzed. Similarly, this plant
will generate residuals, including hydrotreating and reforming catalyses,
sulfated lime sludges from flue-gas treating, and chemical sludges and
tnat Tl 1 nrnb hf" treating> *** Purific^ion, and tail-gas treating
that will probably require special treatment before disposition by the
time a facility of this type is constructed. Currently, such materials
are commonly trucked to landfill or allowed to accumulate in evaporation
-------
COED LIQUEFACTION
A.PTER. PMC t>E^\GN (1914^
ftPW
A.PTER. PMC
TO T£XT (FOR
TOVLAHT
-------
- 75 -
Table 21
rtical Values
for 82
Coals from the Illinois Basir
C0*STIT'JENT
*S
e
BE
BR
CO
ca
CR
cu
r
GA
C£
HC
MN
Ma
HI
p
PB
SB
SE
IN
V
ZN
ZR
»U
CA
CL
FE
K
MB
NA
31
TI
e*»
PYS
JUS
T8J
3XKF
AOU
MBIS
VBU
Fixe
ASH
BTU/LB
C
H
N
e
MTA
LTA
M£AN
11.91
113.79
1.72
15,27
2,89
9.15
14.10
14.09
39,30
3.04
7.51
0,21
51,16
7.96
22.35
62,77
39,83
1.35
1.99
4.56
33.13
313.04
72,10
1.22
0,70
0,15
2, Ob
0.16
0.05
0.05
2. 39
0,06
t,5«
1,*5
0,09
3.51
3.19
T.70
10,02
39,80
48,96
11, 2«
12748,91
70, »9
«,9a
1.3»
e,i9
11.13
15.22
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
PPM
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
s
X
s
X
X
X
X
X
STD
18.94
51.72
O.S3
5.60
e.32
5.76
T.«S
6,T»
19,79
1.03
7.08
0,22
40,96
5,68
10,81
65,66
45,94
t.42
0.9J
6.6«
11.63
749,92
58,01
0,37
0,49
0,15
0,71
0,04
0,02
0.04
0,62
0,02
0.62
0,7}
0.16
1.12
1,08
3.47
4.U
3.17
1."
1.98
464,30
3.11
0,2ft
0,33
1.84
8. IT
3.22
MIN
1,70
12.00
0,50
6,00
0.10
2,00
4,00
5.00
30,00
1.60
1.00
0.03
6,00
1,00
6,00
5.00
4,00
0.20
0.43
1.00
16.00
10.00
12.00
0,43
0.05
0,01
0,48
0,04
0,01
0,03
0,58
0,02
0.17
0,29
0.01
0,85
0,79
1.40
l.iO
31,90
41,30
«,6C
11562,00
62, 4»
4,H
0.93
4.1-3
3,3»
3,»2
MAX
93,00
221,00
4,00
52,00
65.00
34,00
54.00
44.00
143.00
7.30
43.00
1,60
181.00
29.00
63,00
339,00
218.00
6.90
7,70
51,00
78,00
5310.00
133.00
3,04
2.67
0.5»
4.32
0.30
0,17
0.19
4.63
0,15
3,09
3,78
1.04
5,59
5,43
16,70
19.20
46,40
61,00
16. 00
14362,03
79,94
5,7fc
1,6*
14,36
1&.04
23,53
Note: Abbreviations, other than standard chemical symbols: organic sulfur (ORS)
pyritic sulfur (PYS), sulfate sulfur (SU3), total sulfur (TOS), sulfur by*
X-ray fluorescence (SXRiO, air-dry loss (ADL), moisture (HOIS), volatile
matter (VOL), fixed carbon (FIXC), high-temperature ash (HTA), low-
temperature ash (LTA).
-------
- 76 -
4.3 Coal Preparation (Figure 19 and Table 22)
Onsite coal storage will be required to provide backup for
continuous operations. For 30 days storage, there might be eight piles,
each about 200 feet wide, 20 feet high, and 1000 feet long. Containment
of airborne dusts is generally the only air pollution control required
for transport and storage operations, although odor may be a problem in
some instances. Covered or enclosed conveyances with dust removal equipment
may be necessary, but precautions must be taken against fire or explosion.
Circulating gas streams which may be used to inert or blanket a particular
operation or which may issue from drying operations will generally require
treatment to limit particulate content before discharge to the atmosphere.
Careful management and planning will minimize dusting, wind loss, and
the hazard of combustion in storage facilities.
The as-received feed coal employed in this design is indicated
to have 10-14 weight percent moisture content. The FMC process basis
feeds coal of about 5.9 weight percent moisture to the coal dryer ahead of
the first pyrolyzer. Hence the free or surface moisture is assumed to
be removed in the upstream coal preparation plant.
Free moisture would be removed from feed coal by milling in a
stream of hot combustion gases. The mechanical size reduction of an Illinois
coal is expected to generate a considerable quantity of minus 200 mesh fines,
especially if appreciable drying accompanies the milling operation. The quantity
of such fines has been estimated to be 5 to 8 percent of the feed, depending
on the type of equipment that may be used. The ultimate consideration is
that the total fines fed to the dryer or to the first pyrolyzer shall not
overload the cyclone systems that are provided to effect their separation from
the respective effluent streams. Therefore fines generated in coal preparation,
amounting to 5 percent of feed coal, will not be charged to pyrolysis but
will issue as a fuel product. Coal fines would probably be charged to the
char gasification system, if this facility is included.
Clean product gas is fired in the mill heater. About 110 tph of
water must be removed if coal is received with 14 percent moisture. This
may require the firing of 15-20 tph of product gas with 180-200 tph of
combustion air in the milling circuit. Assuming a dry particulate separation
system is adequate, bag filters might be used to recover fines from the
vented gas following primary classification in cyclones.
-------
- 77 -
(2)
Illinois
Coal (1)
Influence of
Weather on
Coal Stock
Piles
*Dust and/
Fumes(5)
A *Dryer
Vent Gas
(7)
COAL PREPARATION
(4)
V
Runoff
*Sized Coal
to Pyrolysis
Product Coal Fines
(8)
(3)
Clean Fuel
Gas to Dryer
Figure 19
Coal Preparation for COED Plant
-------
Table 22
Coal Preparation for COED Plant
Inlet Streams:
(1) Coal, Illinois No. 6 Seam, 14% moisture; 1237 tph.
(2) Influence of weather on coal stockpiles and open coal operations,
(3) Clean fuel gas to dryer; 455 MM Btu/Hr.
Outlet Streams:
(4) Precipitation runoff to holding ponds. May include wet scrubber aqueous effluents.
*(5) Dust and Fumes. Atmosphere in enclosed working areas to be analyzed per Table 35 for
particulates. Discrete stack emissions to atmosphere from enclosed spaces from dust
collection equipment to be analyzed per Table 35 for particulates. Atmosphere in
vicinity of coal stockpiles, open conveying and handling equipment, and coal fines
product collection system to be analyzed per Table 35 for particulates.
-(6) Sized Coal to Pyrolysis, 5.9% moisture; 1063 tph. To be analyzed as feed coal per Table 35.
*(7) Vent gas from dryer containing 108 tph water. Gas' stream may require treatment to limit CO
content. To be analyzed per Table 35 for particulates, trace sulfur compounds, and CO content.
(8) Product coal fines, 4% moisture; 66 tph.
* Analytical Sample
00
I
-------
- 79 -
4.4 Drying and Stage 1 Pyrolysis (Figure 20 and Table 23)
Clean fuel gas is burned substoichiometrically both to
dry feed coal and to heat fluidizing gas for the first stage of pyrolysis.
Both gas and air feeds to the heaters must be raised in pressure to match
the operating pressures of the coal dryer and first stage, nominally
7-8 psig.
Coal is fed from storage hoppers by mechanical feeders into
a mixing tee from which it is blown into the dryer with heated transport
(recirculated) gas.
A cascade of two internal gas cyclones is provided both the coal
dryer and the first pyrolysis reactor. Gas which issues from the first
pyrolyzer is circulated through the fluidizing-gas heater for the coal
dryer. Gas which issues from the coal dryer passes through an external
cyclone and is then scrubbed in venturi scrubber-coolers, which serve
to complete the removal of coal and char fines, as well as traces of
coal liquids from the gas stream. Fines which are recovered in the
external cyclone are passed through a mechanical feeder to a mixing
tee where they are injected into the first-stage pyrolyzer by recirculated
gas. Water equivalent to that introduced with coal and formed in the
combustion processes is condensed from the gas .in the scrubbing process.
Scrubber effluent passes into a gas-liquid separator, and
the liquor stream is decanted and filtered to remove solids. The
solids removed by filtration are indicated to amount to about 1
percent of the coal feed, and the wet filter cake is indicated to be
recycled back to coal feed. The decanted liquor, except for a purge
stream which, along with the filtrate from the fines filter, balances the
removal of water from the section, is pumped back to the venturi scrubbers
through water-cooled heat exchangers.
The gas stream which issues from the separator, except for a
purge stream which removes the nitrogen introduced in the combustion
processes, is compressed and recirculated to the gas heaters. This
purge gas stream is essentially the only gaseous release from this section.
Like the gas stream envisioned for the coal preparation section (see
above), it is indicated to contain about 3.7 percent carbon monoxide,
and will probably require further treatment before it may be released
to the atmosphere. It may be possible to inject it into a boiler stsck(s)
along with air or oxygen to reduce CO emission. Alternatively the
stream(s) may have to be incinerated in specific equipment for this
purpose with additional fuel. The gas stream in this case is indicated
to be sulfur-free.
-------
- 80 -
(9)
Sized Coal
(31)
Oily Char Fines
From Filtration
(10).
Clean Fuel
Gas
(11)
Purge Gas
to Atmosphere
DRYING AND STAGE 1 PYROLYSIS
Wet Char Fines
Recycled to
Feed (12)
(13)
(14)
Pyrolysis Steam
to Stage 2
Aqueous Condensate
to Treatment
Figure 20
Drying and Stage 1 Pyrolysis
-------
Table 23
Inlet Streams:
(9) Sized Coal; 1063 tph; plus Recycle Wet Char Fines; 22 tph.
(10) Clean Fuel Gas; 25 tph.
(31) Oily Char Fines from Filtration; 15.2 tph.
i
Outlet Streams: £2
i
*(11) Purge gas to atmosphere; 366 tph. May require treatment to limit CO content.
To be analyzed for particulates, trace sulfur compounds, and CO content per
Tcib J.G «3 j •
(12) Wet oily char fines separated at fines filter; 22 tph. Recycled to coal
feed.
(13) Aqueous condensate; 93.5 tph. 83.3 tph directed to last pyrolyzer. 10.2 tph
directed to water treatment.
(14) Pyrolysis Stream to Stage 2; 978 tph.
* Analytical Sample.
-------
-82 -
4.5 Stages 2,3,4 Pyrolysis (Figure 21 and Table 24)
Coal which has undergone first-stage pyrolysis (at temperatures
of about 550-&00°F) is passed out of the stage into a mixing tee, from
which it is transported into the second stage by heated recycle gas.
Pyrolysis stages 2,3, and 4 are cascaded such that pyrolyzed solids
pass through the stages in sequence in transport gas streams. Super-
heated steam and oxygen are injected into the last stage, where heat is
released by partial combustion. Substantial recycle of hot (.-^1550°F)
char from this last stage is used to supply heat to stages 2 and 3,
in which it otherwise serves as an inert diluent. Similarly, hot gas
which issues from the last stage is passed countercurrently through the
cascade, serving also as the primary fluldizing medium in these reactors.
Stages 2 and 3 operate at about 850° and 1050°F respectively.
The pyrolyzer vessels are each about 60-70 feet in diameter.
A total of eight pyrolyzers in two trains is required to process the
indicated feed coal. All fluidized vessels are equipped with internal
dual-cascade cyclone systems.
Gas which issues from the second pyrolyzer passes through an
external cyclone before being directed to the product recovery system.
Fines which are separated are directed, along with product char from
the last stage, to a fluidized bed cooler, which is used to generate
265,000 Ib/hr of 600 psia steam. First-stage recycle gas is used to
fluidize the char cooler, and the gas which issues from the cooler is
directed back to the venturi scrubbers in the first section after it
has passed through an external cyclone. Fines from this cyclone are
added to the char make from the last stage. Product char is available
at this point at 800°F. About 180,000 Ib/hr of 150 psia steam may additionally
be generated from the char if suitable equipment can be designed to abstract
its sensible heat.
Because the system is otherwise closed, the only possible
major atmospheric effluents from this section are the products of
combustion from the heaters used to superheat the steam and oxygen
feeds to the last pyrolysis stage. We have assumed clean product gas
for this service also. About 10.5 tons of g?s is required, along with
about 105 tons of air per hour. The combustion products should be
dischargeable directly in this case without further treatment.
-------
- 83 -
(18)
Clean Product Gas
(14)
Pyrolysis Stream
From Stage 1
(15) v
Oxygen
(17)
BFW
(22)
Stack Gas
From Superheater*
STAGES 2,3,4 PYROLYSIS
(13)(16)(39)
Recycled Process
Condensates
(19)
Pyrolysis Stream
to Product Recovery
(21)
Steam to Process
(20)
*Product Char
Figure 21
Stages 2,3,4 Pyrolysis
-------
Table 24
Stages 2,3,4 Pyrolysis
Inlet Streams;
(14) Pyrolysis Stream from Stage 1; 978 tph.
(15) Oxygen from Oxygen Plant; 156.5 tph.
(39)(13)(16) Recycled process liquors as steam to last pyrolyzer; 337 tph.
(17) BFW to fluidized bed char cooler and aftercooler; 900 gpm.
(18) Clean Product Gas to Superheaters; 10.5 tph.
Outlet Streams;
(19) Pyrolysis Stream to Product Recovery; 1088 tph.
•'(20) Product char; 521 tph. To be analyzed for trace sulfur and trace
elements per Table 35.
(21) 600 psia steam; 265,000 Ib/hr and 150 psia steam; 180,000 Ib/hr from char
cooling to process.
»-(22) Stack gas from superheaters; 115 tph. To be analyzed per Table 35 for particulates
and trace sulfur compounds.
Analytical Sample.
-------
- 85 -
4.6 Product Recovery (Figure 22 and Table 25)
Gas from the pyrolysis section is cooled and washed in two cascade
venturi scrubber stages to condense oil and solid components from the gas
stream. The gas which issues from the second scrubber gas-liquid separator
is passed through an electrostatic precipitator to remove microscopic
droplets, and is then cooled t-o 110°F by cold-water exchange to
condense water. About a quarter of the gas stream is compressed
and reheated for use as transport gas in the pyrolysis train. The
remainder issues from the system as raw product gas, which is to be
directed to an acid-gas removal system.
The oil and water condensed from the gas stream in the scrubber-
coolers is decanted and separates into three phases: a light oil phase,
a middle (aqueous phase), and a heavy oil phase. The oil phases are
collected separately for dehydration in steam-jacketed vessels. The
combined dehydrated oil is pumped to the COED oil filtration system.
A recycle liquor pump takes suction from the middle phase in
the decanter. Recycle liquor is cooled in cold-water exchangers before
being injected into the venturi scrubbers. Water condensed from the
incoming gas leaves the section as a purge ahead of the recycle liquor
coolers, and is indicated to be recirculated to the last pyrolysis
stage.
The only major effluents to the atmosphere from this section are
the combustion gases from the recycle transport-gas heater. Since clean
product gas is fired in this heater, the combustion gases should be
dischargeable directly.
Vents from the oil decanters and dehydrators are indicated to
be directed to an incinerator. Under normal operation, and with adequate
condensing capacity in the vapor takeoffs from the dehydrators, vent
flow should be minimal.
-------
- 86 -
(26)
A ''"Stack Gas From
Transport Gas Heater
(19)
Pryolysis Stream
From Last Pyrolyzer
(23)
Glean Fuel Gas
to Transport
Gas Heater
PRODUCT RECOVERY
(16)
Waste Liquor Stream
to Last Pyrolyzer
Product Gas to
Purification
(24)
(25),
COED Oil
to Tiltration
Figure 22
Product Recovery
-------
Table 25
Product Recovery
Inlet Streams;
(19) Pyrolysis Stream from Last Pyrolyzer; 1088 tph.
(23) clean Fuel Gas to Transport Gas Heater; 3.1 tph.
Outlet Streams;
i
(16) Waste Liquor Stream to Last Pyrolyzer; 237 tph. °°
i
(24) Product Gas to Gas Purification; 513 tph.
(25) COED oil to Oil Filtration; 200 tph.
*(26) Stack Gas from Transport Gas Heater; 35 tph, to be analyzed per Table 35
for particulates and trace sulfur compounds.
* Analytical Sample.
-------
- 88 -
4.7 Oil Filtration (Figure 23 and Table 26)
FMC has designed a filtration plant to handle the COED raw oil
output based on filtration rates demonstrated in its pilot plant.
The system employs ten 700 ft^ rotary-pressure precoat filters to remove
char fines from the raw oil ahead of hydrotreating. Each filter is operated
on a 7-hour precoat cycle, followed by a 41-hour filtration cycle.
Both the precoat and the raw oil to filtration are heated, using
steam, to about 340°F. Inert gas (nitrogen) is compressed, heated, and
recirculated for pressurizing the filters. The gas purge from the system,
equivalent to the nitrogen makeup, is directed to a boiler stack. It is
indicated to contain only trace quantities of combustibles and sulfur.
Hot filter cake (38% oil, 52% char, 10% filter aid at 350°F) is
discharged at the rate of about 15 tph, and is indicated to be added to the
plant's char output in the process basis. FMC has recently indicated
that filter cake will instead be recycled to coal feed . Filtered
oil is directed to the hydrotreating facility.
-------
- 89 -
(25),
COED Oil From
Product Recovery
(27),
Filter Aid and
Basecoat
(29)
Purge Gas
to Boiler Stack
OIL FILTRATION
(28)
(30)
Filtered Oil
to Kydrotreating
(31)
Oily Char Fines
Recycled to Coal Feed
Pressurizing Nitrogen
Figure 23
Oil Filtration
-------
Table 26
Oil Filtration
Inlet Streams:
(25) COED Oil from Product Recovery; 200 tph.
(27) Filter aid and Basecoat during filter precoat cycle; 1.5 tph.
(28) Pressurizing nitrogen from oxygen plant; 0.5 tph.
\o
o
Outlet Streams:
(29) Purge gas directed to incinerator or boiler stack; 0.5 tph.
(30) Filtered Oil to Hydrotreating; 186 tph.
(31) Oily char fines containing 1.5 tph filter aid; 15.2 tph. Recycled to coal feed,
-------
- 91 -
4.8 Hydrotreating (Figure 24 and Table 27)
Hydrotreating is employed to upgrade the heavy pyrolysis oil
through the addition of hydrogen, which serves to convert sulfur to
hydrogen sulfide, nitrogen to ammonia, and oxygen to water, as well as to
increase the oil's hydrogen content through saturation reactions. Hydro-
treating is performed catalytically in the FMC pilot plant at 750 to 800°F
and at total pressures of 2000-3000 psig; conditions which also promote
some cracking reactions.
In the FMC base design, hydrotreating is indicated to be performed
at 750°F and at a total pressure of 1710-1720 psia. Filtered oil from the
filtration plant is pumped, along with hydrogen from a reforming plant and
some recycled oil, through a gas-fired preheater into initial catalytic
guard reactors. The guard reactors are intended to prevent plugging of the
main hydrotreating reactors by providing for deposition of coke formed in
the system on low surface-to-volume packing.
The hydrotreating reactors are indicated to be three-section,
down flow devices. The gas-oil mixture from the guard bed is introduced
at the reactor head along with additional recycle hydrogen. Recycled oil
and hydrogen at low temperature (100-200°F) are introduced between the
cntalyst sections in the reactor to absorb some of the exothermic heat
of reaction.
The hydrotreated effluent is cooled and flows into a high-
pressure flash drum, where oil-water-gas separation is effected. About
60 percent of the gas which separates is recycled by compression to the
hydrotreaters. The remainder is indicated to be directed to the
hydrogen plant.
A little less than half of the oil which separates is recycled to
the hydrotreaters. The remainder, taken as product, is depressured into a
receiving tank. From the tank it is pumped into a stripping tower, where
clean product gas is used to strip hydrogen sulfide and ammonia.
Clean product gas is used also to strip ammonia and H2S from
the water which separates from hydrotreater effluent. Stripped water is
indicated to be recycled to the last pyrolysis stage. The gas effluents
from the strippers are indicated to be directed to gas clean up.
The only major effluents to atmosphere from this section are
the combustion gases from the hydrotreater preheater. About 4.5 tph of
product gas is consumed, along with about 84 tph of combustion air. The
products of combustion should be dischargeable directly without further
treatment.
-------
- 92 -
The process design basis does not provide for catalyst replacement
in this section. Nor are facilities included for presulfiding catalyst,
if this be required, or for regenerating catalyst.
We have assumed that regeneration, if it is practiced, will occur
off site. Moreover, we have assumed that the hydrotreaters will be designed
to run continuously between maintenance shutdowns.
Provisions for de-pressuring and inerting the hydrotreater preliminary
to catalyst removal should not result in ernissior.s to atmosphere, since
gaseous effluents may be recycled to the hydrogen plane gas treatment section,
or to the main gas-treating section. Arsoniurr. suiride, which is produced
in the hydrczreater and which is stable at reaction conditions, decomposes
at low^ temperatures and pressure to release additional ar^ionia and P^S
into the inerting medium. Metal carbonyls may also be present, and
special precautions may be required if these are found in significant
concentration.
Gaseous effluent which results from inerting the system after
catalyst replacement may require treatment to remove particulates. In
general, the same procedures used to replace catalyst in the hydrotreater
may also be applied to changeout of the packing or catalyst in the guard
reactors.
-------
- 93 -
A * Stack Gases
From Preheater
(30)
Filtered Oil
(32)
Hydrogen Makeup
(35)
Bleed Gas Stream
to Cleanup
and A Contaminated Strip
Hydrogen Gas to Gas
Plant Purification
(36) I (37)
HYDRO-TREATING
(34)
Preheater Gas
Fuel
(33)
(40)
*Syncrude Product
(39)
Condensate to
Last Pyrolyzer
(38)
*Reactor Coke to
Char Product
Stripping
Gas
Figure 24
Hydrotreating
-------
Table 27
Hydrotreating
Inlet Streams:
(30) Filtered Oil from Filtration; 186 tph.
(32) Hydrogen Makeup from Hydrogen Plant; 28.4 tph.
(33) Clean Product Gas Stripping Medium; 103 tph.
(34) Clean Product Gas to Preheater; H.8 tph.
Outlet Streams;
""(35) Stack Gases from Preheater; 130 tph. To be analyzed for particulates and trace sulfur
compounds per Table 35.
(36) Bleed Gas Stream to Cleanup and Hydrogen Plant; 29 tph.
(37) Contaminated Stripping Gas to Gas Purification; 107 tph.
•''(38) Reactor Coke to Product Char; 0.04 tph. To be analyzed for trace elements for Table 35.
(39) Contaminated Condensate to Last Pyrolyzer; 16.6 tph.
*(40) Syncrude Product; 164.4 tph. To be analyzed for trace sulfur compounds and trace elements
per Table 35.
* Analytical Sample.
-------
- 95 -
4.9 Oxygen Plant (Figure 25 and Table 28)
The oxygen plant provides a total of 3760 tons per day of
oxygen to the last pyrolysis stage. The only effluents to the air from
this facility should be the other components of air, principally nitrogen
About 340 MM scfd of nitrogen will be separated. Some of this nitrogen
may be used to advantage in the plant to inert vessels or conveyances,
to serve as transport medium for combustible powders or dusts, to serve as an
inert stripping agent in regeneration or distillation, or to dilute
other effluent gas streams. Nitrogen is also indicated to be used to
pressurize the rotary pressure raw-oil filters.
About 440 MM scfd of air is taken into the oxygen facility.
Placement of the oxygen facility will depend in part on the desire to
maintain the quality of the air drawn into the system and, especially,
to minimize interference from plant effluents.
-------
- 96 -
(42)
(41)
Atmospheric Air
N2 to Plant and
to Atmosphere
OXYGEN PLANT
(15)
Oxygen to Last
Pyrolyzer
(43)I Condensate to
Water Treatment
Figure 25
Oxygen Plant
-------
Table 28
Oxygen Plant
Inlet Streams:
(41) Atmospheric air intake; 440 MM SCFD.
Outlet Streams;
(15) Oxygen to Last Pyrolyzer; 156.5 tph.
(42) Nitrogen to Atmosphere and/or Plant; 340 MM SCFD.
(43) Water Condensate to BFW Treatment; 17 gpm.
-------
- 98 -
4.10 Gas Purification (Figure 26 and Table 29)
The acid-gas removal process to be used in this facility has
not been specified by FMC. Sulfinol and hot carbonate have been ten-
tatively considered.
The primary feed to this unit would be the product gas stream
separated from the product recovery system (513 tph). Contaminated
product gas used for stripping the water and oil effluents from hydro-
treating (107 tph) may also be returned to this unit; however, since this
stream contains ammonia, it may be preferable to treat it separately.
The particular choice of acid gas removal process may depend
on the nature and quantity of "trace" contaminants present in the gas
to be treated. FMC has not reported on the quantity and nature of the
sulfurous contaminants in raw gas. COS has been found in some streams.
In our basis we have assumed that the "Benfield" hot potassium
carbonate gas purification system will be used. In the Benfield system, gas
absorption takes place in a concentrated aqueous solution of potassium carbonate
which is maintained at above the atmospheric boiling point of the solution
(225-240°F) in a pressurized absorber. The high solution temperature permits
high concentrations of carbonate to exist without incurring precipitation of
bicarbonate.
Partial regeneration of the rich carbonate solution is effected
by flashing as the solution is depressured into the regenerators. Low-
pressure steam is admitted to the regenerator and/or to the reboiler to
supply the heat requirement. Regenerated solution is recirculated to the
absorbers by solution pumps. Stripped acid gas flows to the sulfur recovery
plant after condensation of excess water. Depressurization of the rich
solution from the absorber through hydraulic turbines may recover some of
the power required to circulate solution.
Raw product gas from the product recovery section must be
compressed for effective scrubbing. We have estimated that the compressor
driver will require the equivalent of 500,000 Ib/hr of high-pressure steam
to handle the primary raw gas stream. Some 1,400,000 gph of solution must
be circulated, requiring the equivalent of 5700 kW. Some 450 MM Btu/hr is
required for regeneration, supplied as steam, and about this same cooling
duty will be required. Additionally, some 100,000 Ib/hr of high-pressure
steam, 1200 kW, and 95 MM Btu/hr as low-pressure steam, as well as the
corresponding quantity of cooling water, will be required to treat the
stripping gas from hydrotreating.
Clean gas may be directed to the various fired heaters throughout
the plant, and to the utility boiler. There should be no discharge to the
atmosphere from the acid-gas removal section.
-------
- 99 -
(24)
Raw Product Gas
(37)
Contaminated
Strip Gas
(36^
Bleed Gas
from Hydrotreating
(45)
Acid Gases to
Sulfur Recovery
GAS PURIFICATION
(44)
Regeneration
Steam
(47)
(46)
Product Gas
to Plant Fuel
*Benfield
Slowdown
Figure 26
Gas Purification for COED Plant
-------
Table 29
Gas Purification /for COED Plant
Inlet Streams;
(24) Product Gas from Product Recovery; 513 tph.
(36) Bleed Gas from Hydrotreating; 29 tph.
(37) Contaminated Stripping Gas from Hydrotreating; 107 tph.
(44) 150 psia Steam to Regenerators; 381,000 Ib/hr.
o
o
Outlet Streams: ,
(45) Acid gases to Sulfur Recovery; 315 tph.
(46) Product Gas to Plant Fuel and to Hydrogen Plant; 171 tph dry basis.
*(47) Spent Benfield blowdown requires special treatment. To be analyzed per Table 35
for trace sulfur compounds and trace elements.
* Analytical Sample.
-------
- 101 -
4.11 Hydrogen Plant (Figure 27 and Table 30)
The COED process gas product is indicated to be the source of
hydrogen for the hydrotreating of raw COED oil. We have assumed that
steam reforming will be used to produce the hydrogen requirement.
COED process gas at 15 psia is compressed to 410 psif and
passed through a sulfinol system to remove C02 and H2S. Regenerated acid
gases are directed to the sulfur recovery plant. The cleaned process gas
containing about 1 ppm H2S is divided into a fuel gas stream and a process
feed gas stream. The process feed gas is passed over a zinc oxide sulfur
guard bed to remove sulfur traces, and is then heated by combustion of
the fuel gas and hydrogenated with recycle product hydrogen to remove
unsaturates. Steam is injected, and reforming and shifting occur catalyti-
cally according to:
CH4 + H20 ^ CO + 2H2 (reforming)
CO + H20 » C02 + H2 (CO shift)
CO? formed in the reactions is removed in a second scrubber-absorber
and the process gas is finally methanated catalytically to convert residual
CO to methane according to 3H2 + CO ^ CH^ + H20. Resulting product
gas is available at 200 psig.
The bleed gas from the hydrotreating plant, containing about
1 percent H2S and about 0.1 percent ammonia, is indicated to be returned
to the hydrogen plant for reprocessing. It may be preferable to first
scrub this stream with water separately to remove the ammonia trace.
About 3.5 tph of H2S must also be removed from this stream, and the H2S
residual, after water scrubbing, would be removed in an acid gas scrubber
and directed to the sulfur recovery plant.
The major gaseous effluents from the hydrogen plant will be the
products of combustion from the fired heaters and the C02 stream removed
from the processed gas after reforming. Since clean product gas is
consumed in the heaters, the products of combustion should be dischargeable
directly. Some 23 tph of gas is fired.
About 60 tph of C02 will be removed from the process gas, and
this too may be discharged, although there may be incentive to recover some
or all of this stream for sale, since its purity should be high.
-------
- 102 -
(50)
(46),
Clean Product Gas
(36),
Bleed Gas From
Hydrotreating
(48),
BFW to Reformers
-Heater Stack
Gases
(51)
/TAcid Gases to
Sulfur Recovery
HYDROGEN PLANT
A
'(49)
Clean Product
Gas to Heaters
(32)
Hydrogen Makeup
to Hydrotreating
(52)
••VCC>2 from Reformer
to Atmosphere
Figure 27
Hydrogen Plant
-------
Table 30
Hydrogen Plant
Inlet Streams;
(36) Bleed Gas from Hydrotreating; 29 tph.
(46) Clean Product Gas to Reformers; 25 tph.
(48) BFW to Reformers; 43 tph net consumption. Excess condensate returned to Water Treatment.
(49) Clean Product Gas to Fired Heaters; 23 tph.
I
M
O
Outlet Streams: '
(32) Hydrogen Makeup to Hydrotreating; 28.4 tph.
*(50) Stack Gases from Fired Heaters. To be analyzed for particulates and
trace sulfur compounds per Table 35.
(51) Acid Gases to Sulfur Recovery.
*(52) C02 from reformers; 60 tph. To be analyzed for trace elements per Table 35.
-------
- 104 -
4.12 Sulfur Recovery (Figure 28 and Table 31)
The type of sulfur plant that will be used has not been specified
by FMC. The combined acid-gas streams resulting from treatment of raw
product gas (pyrolysis gas) and hydrotreating bleed gas would appear to
yield an H2S concentration of about 7 percent based on gas analyses
presented in the FMC design. Additional concentrated H2S streams may
result from treatment of sour water and stripping gas. FMC has indicated
that high-sulfur Illinois coals will yield H2S levels in the range of
10-20 percent.
We have assumed that acid gas will be sufficiently high in
H2S content to permit use of a Claus recovery system. Tail gas from
the Claus unit must be desulfurized, however. Several processes have
been developed for this purpose. FMC indicates that the Beavon or
Shell Claus Off-Gas Treating (SCOT) process may be employed.
The Beavon system catalytically hydrogenates the S02 over cobalt-
molybdate. The catalyst is also effective for reacting CO, which may be
present, with water to form hydrogen and for the reaction of COS and
CS2 with water to form H2S.
The hydrogenated stream is cooled to condense water, and the H2S
stream is fed into a Stretford unit to recover sulfur in elemental form.
Treated tail gas may contain less than 200 ppm sulfur, with almost all
Of this being carbonyl sulfide. Condensate may be stripped of H2S and
directed to boiler feed water treatment.
About 500 tpd of elemental sulfur will be separated at the
sulfur plant, depending on the sulfur content of the feed coal and on
the processing employed. Total sulfur emission to the atmosphere may
be held to less than 200 Ibs/hr, and the treated tail gas may be
directed to a boiler stack for disposal. The small air stream used to
regenerate the Stretford solution in the tail gas treatment plant may
also be so directed.
-------
- 105 -
Incoming Acid Gas
(54)
Regeneration Air
Stream to Boiler
Stack
to Atmosphere
(57)
SULFUR RECOVERY
(53)
Regeneration Air
to Tail-Gas
Treatment
(56)
(55)
*Sulfur Product
*Stretford Slowdown
from Tail-Gas
Treatment
Figure 28
Sulfur Recovery for COED PIant
-------
Table 31
Sulfur Recovery
Inlet Streams:
(45) (51) Incoming Acid Gases (330 tph) containing 23 tph H2S.
(53) Regeneration Air to Tail-Gas Treatment; 0.7 MM SCFD.
Outlet Streams:
o
(45) Regeneration Air Stream to Boiler Stack; 0.7 MM SCFD. °"
*(55) Sulfur Product; 510 tpd. To be analyzed for trace elements per Table 35.
*(56) Stretford blowdown from tail-gas treatment, to be analyzed for trace elements and
trace sulfur compounds per Table 35. May require special treatment.
*(57) C02 stream to Atmosphere contains less than 200 ppm sulfur. To be analyzed for
trace sulfur per Table 35.
* Analytical Sample.
-------
- 107 -
4.13 Power and Steam Generation (Figure 29 and Table 32)
We have in this study considered that dirty fuels would not
be combusted in the plant; therefore, clean product gas would be used
for the generation of steam and power requirements. However, the
total utility balances require some additional fuel source. Of the
513 tph of contaminated product gas issuing from the product recovery
system, there is net 171 tph of dry gas available from the acid-gas
removal system. Some 25 tph is required as feed to the hydrogen plant,
leaving the net available gas for fuel as 146 tph. The gas is estimated
to have a higher heating value of 505 Btu per scf, so that the total available
fuel gas equivalent is about 4180 MM Btu per hour.
Net steam requirements for the facility total 783,000 Ib/hr
equivalent to a 1130 MM Btu/hr fuel requirement. Net electrical power
requirements total 93,200 kW, equivalent to 902 MM Btu/hr of additional
fuel. The plant otherwise fires fuel equivalent to 2842 MM Btu/hr in
process heaters. Hence the total requirement, 4847 MM Btu per hour,
cannot be supplied by the product gas stream alone. The shortfall/equivalent
to 694 MM Btu/hr, would presumably come from char.
We have considered that the 2032 MM Btu/hr fuel equivalent
required at the power plant could be supplied by the combinative firing
of product char and product gas in suitably designed boilers. The fuel
requirement is such that if all of the char required to supply the fuel
shortfall, about 30 tph, is fired in the power plant along with about
47 tph of product gas, the sulfur emission would be such that flue-gas
treatment would be required. About 2.1 tph of S02 would be emitted,
equivalent to about 2.0 Ib/MM Btu, which is above the level permitted by
current standards for solid fuels.
We have assumed that char will be combusted in the power plant
to make up the fuel shortfall and that flue gas will be treated with a lime-
stone process. We recognize that some char treatment process is practically
required in a commercial design, so that it is likely that clean fuel
gas of low heating value will be available from char in an integrated
facility.
We note, however, that only that portion of stack gases derived
from char burning needs be treated in our assumed case. Only a small
amount of product gas would be fired with char to stabilize the char
combustion in order to minimize the volume of stack gas which is treated.
-------
- 108 -
j Limestone to
(59) Flue-Gas Treatment
(61)
(46)
Clean Fuel Gas
(58)
3FW
(20)
Product Char
*Stack Gas
POWER AND STEAM GENERATION
(62)
*Lime Sludge
to Disposal
(60)
Steam to Process
(63)
"Char Ash
to Disposal
Plant
Electrical
Requirement
93,200 kWh
(64)
Boiler Blowdown
to Water Treatment
Figure 29
Power and Steam Generation
-------
Table 32
Power and Steam Generation for COED Plant
Inlet Streams;
(20) Product Char; 30 tph.
(46) Clean Fuel Gas; 47 tph.
(58) BFW; 783,000 Ib/hr.
(59) Limestone to Flue-Gas Treatment.
o
VD
Outlet Streams:
(60) Steam to Process; 277,000 Ib/hr 150 psia and 506,000 Ib/hr 600 psia.
*(61) Stack Gases. Complete stack gas analysis, including particulates and trace sulfur
compounds per Table 35.
"(62) Lime Sludge to Disposal. To be analyzed for trace elements and trace sulfur compounds
per Table 35. May require special treatment.
*(63) Char Ash to Disposal; 6.4 tph. To be analyzed for trace elements and trace sulfur compounds
per Table 35. May require special treatment
(64) Boiler Slowdown to Water Treatment.
* Analytical Sample.
-------
4.14 Water Treatment (Figure 30 and Table 33)
Analyses of the aqueous condensates produced in the pyrolysis
and hydrotreating plants have not been specified in the FMC design. FMC
has indicated that these streams would be preferentially recycled to the
last, or hottest pyrolyzer, or to char gasification if it be included,
after minimal processing to strip ammonia and hydrogen sulfide.
Recycle to a high-temperature char gasification system should
present no difficulty. However, the long-term recycle to pyrolysis
requires additional study, since temperatures are rather low and there
is no basis on which to estimate the degree of "bypass" through the
fluidized bed system. The question may be largely academic, however,
because it would appear that a large-scale installation, unless it
were arranged to combust char locally, would include some form of
high-temperature char gasification. We have assumed that pyrolysis
liquor may be recycled in our design.
Facilities required to treat water, including raw water,
boiler feed water, and aqueous effluents, will include the following
separate collection facilities:
Effluent or chemical sewer
Oily water sewer
Oily storm sewer
Clean storm sewer
Cooling tower blowdown
Boiler blowdown
Sanitary waste
Retention ponds for runoffs and for flow equalization within
the system will be required. Runoff from the paved process area could
easily exceed 15,000 gpra during rainstorms. Runoff from the unpaved
process and storage areas could exceed 80,000 gpm in a maximum 1-
hour period.
Pretreatment facilities will include sour water stripping
for chemical effluents and Imhoff tanks or septic tanks and drainage
fields for sanitary waste.
Gravity settling facilities for oily wastes will include API
separators, skim ponds, or parallel plate separators.
Secondary treatment for oily and chemical wastes will include
dissolved air-flotation units, granular-madia filtration, or chemical
flocculation units.
-------
- Ill -
Oxygen demand reduction may be accomplished in activated sludge
units, trickling filters, natural or aerated lagoons, or by activated
carbon treatment.
Boiler feedwater treatment will in general involve use of ion-
exchange resins. Reverse osmosis, electrodialysis, and ozonation may
find special application.
Evaporation will of course occur throughout this system, and
the concern of the designers will be to limit the Devolution of noxious
or undesirable components which may be present. We note that it may
be necessary to cover portions of the watertreatment facility and/or
provide forced draft over some units to avoid undue discharge of
hydrocarbons into the atmosphere. In the latter case, as with direct
oxidation or ozonation, sweep gases would be ducted to an incinerator
or boiler, and provisions for minimizing explosive hazard would be
required.
-------
- 112 -
(57) Treating Chemicals
(59) *Degasser Vents
" Raw Water
(64)+(65)
Returned Process
Condensates
WATER
Treated Water
to Plant
••''Slowdowns and
Sludges to Disposal
Figure 30
Water Treatment
-------
Table 33
Water Treating
Inlet Streams;
*(65) Raw Water Makeup; 7600 gpm. Complete water analysis per Table 35.
(64)(66) Returned process condensates; 3000 gpm.
(67) Water Treatment chemicals,, including pebbled quicklime, sodium hydroxide solution,
sulfuric acid, alum, polymer solution, chlorine, hypochlorite, demineralizer
and zeolite polymers, salt, anthracite filter media.
Outlet Streams:
(68) Treated Water to Users; 10,600 gpm.
*(69) Vents from condensate degassers. To be analyzed for trace constituents per Table 35.
*(70) Slowdowns and chemical sludges to disposal. To be analyzed for trace sulfur compounds
and trace elements per Table 35- May require special treatment.
OJ
I
* Analytical Samples.
-------
- 114 -
4.15 Cooling Water (Figure 31 and Table 34)
A total of 200,000 gpm of cooling water is indicated to be
required for operating the FMC design. Because most ot this requirement
is used for thermal exchange against relatively low-pressure streams,
the circuit should be relatively free from process contamination leakage.
A design vet bulb temperature of 77°F and an approach to the
wet bulb temperature of 8°F was assumed, with a circulating water
temperature rise of 30°F. 9,000 gpm is required as cooling tower make-
up, equivalent to 4.5 percent of circulation. Some 3,000,000 pounds
per hour of water is evaporated at the cooling towei, 600 gpm is lost
as drift, and 2400 gpm is withdrawn as blowdown and is directed to the
water treatment facility.
-------
- 115 -
(72)
(68) ..
Makeup
(71)
Plant Returns
Water Treatment
Chemicals
(74)
*Evaporation
and Drift
COOLING WATER
(73)
Cooling Water
to Users
(75)J Slowdown to
Water Treatment
Figure 31
Cooling Water
-------
Table 34
Cooling Water
Inlet Streams:
(68) Makeup Water from Water Treatment; 9000 gpm.
(71) Plant returns; 200,000 gpm.
(72) Water Treatment chemicals including anti-foam package, biological (growth control)
package, inhibitor feed package, pH (sulfuric acid) package.
Outlet Streams:
(73) Cooling water to users; 200,000 gpm.
»(74) Evaporation from Towers; 6000 gpm and Drift from Towers; 600 gpm.
Atmosphere downwind of towers to be analyzed for trace constituents
per Table 35.
(75) Blowdown to Water Treatment; 2400 gpm.
* Analytical Sample.
-------
- 117 -
4.16 Process Analytical Summary
The streams indicated for analysis around the COED Process model
are summarized in Table 35, along with specific references to suggested
sampling and analytical procedures described in the Analytical Sections 5-9.
The qualifications applicable to the analytical scheme for coal
gasification described in Section 3.18 are likewise applicable to the
liquefaction scheme. We note again that coal liquefaction encompasses
a much wider variety of processing alternatives than does gasification,
and that the processing sequence in a particular "liquefaction" system
may differ considerably from the COED system. However, the integrated
facility, when broken down into unit operations in the manner presented
herein, will be found to differ generally only in the relative sizes
and sequence of such operations, with special differences occurring
mainly in the reactor module.
-------
Table 35
Summary of Effluent Streams to be Analyzed for COED Plant
COAL LIQUEFACTION
COED PROCESS MODEL
Stream No.
Stream Name
Dust and Fumes in Coal Preparation Area
Analysis For
11
20
22
Sized Coal to Pyrolysis
Coal Dryer Vent Gas
Purge Gas from Stage 1 Pyrolysis
Product Char
Stack Gas from Superheaters
Atmosphere in enclosed spaces, discrete
stack emissions from enclosed spaces
and from dust collection equipment,
and atmosphere in vicinity of coal piles,
open conveying and handling equipment,
and coal fines collection system to be
analyzed for particulates.
Complete coal analysis including
trace elements.
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
Complete Coal Analysis
Including Trace Elements
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
Analytical Section Reference
Total particulates to be determined in enclosed
spaces using a high volume sampler, Section 9;
in stacks using EPA Method No. 5, Section 9;
and the ASTM D 1739 dust fall test will be
performed at various site locations.
Coal will be analyzed for the elements listed
in Section 7, Table VI and will be analyzed
to determine its gross composition as indicated
in Section 7, Table VII.
The stack gas will be analyzed for
NOX, CO, C02, COS, H2S, and Ci^SH and
for particulates. Refer to Section 9.
The stack gas will be analyzed for S02/S0n,
NOX, CO, C02, COS, H2S, and CH3SH and
for particulates. Refer to Section 9.
Coal will be analyzed for the elements
listed in Section 7, Table VI and will be
analyzed to determine its gross composition
as indicated in Section 7, Table VII.
The stack gas will be analyzed for S02/SO-j,
NOX, CO, C02, COS, H2S, and Ct^SH and
for particulates. Refer to Section 9.
-------
Table 35 (Cont'd)
Summary of Effluent Streams to be Analyzed for COED Plant
COAL LIQUEFACTION
COED PROCESS MODEL
Stream No.
26
35
38
40
Stream Name
Stack Gas from Transport Gas Heater
Stack Gas From Preheater
Hydrotreating Reactor Coke Product
Syncrude Product
Analysis For
Analytical Section Reference
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
Complete Coal Analysis
Including Trace Elements
Sulfur
Trace Elements
The stack gas will be analyzed for S02/S03,
NOX, CO, C02, COS, H2S, and CH3SH and
for particulates. Refer to Section 9.
The stack gas will be analyzed for S02/S03,
NOx, CO, C02, COS, H2S, and CH3SH and
for particulates. Refer to Section 9.
Coke will be analyzed for the elements
listed in Section 7, Table VI and will be
analyzed to determine its gross composition
as indicated in Section 7, Table VII.
This stream will be analyzed for the metals
listed in Section 8, Table VIII and for
total sulfur as indicated in Section 8,
Table X.
47
Benfield Slowdown
Complete coal solids analysis
and complete water analysis.
The solid material will be analyzed for the
components listed in Section 7, Tables VI
and VII. The aqueous phase will be analyzed
for the components listed in Section 6, Table IV.
The high K,,C03 and KHC03 contsnt of this
stream may cause interferences in the analyses.
-------
Table 35 (Cont'd)
Summary of Effluent Streams to be Analyzed for COED Plant
COAL LIQUEFACTION
COED PROCESS MODEL
Stream No.
50
52
55
56
Stream Name
Analysis For
Stack Gas from Hydrogen Plant Heaters
Separated C02 from Reformed Stream
Sulfur Product
Stretford Slowdown
Analytical Section Reference
57
Sulfur Plant Off Gas
61
Boiler Stacks and Heaters
(Multiple Stacks are Involved)
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
Trace Elements
Complete coal solids analysis
and complete water analysis.
Trace Sulfur Compounds
Particulates (V, Na)
Stack Gas Analysis
Trace Sulfur Compounds
Particulates
The stack gas will be analyzed for S02/SO.,,
NOX, CO, C02, COS, H2$, and CH3SH and
for particulates. Refer to Section 9.
The stack gas will be analyzed for 802/803,
NOX, CO, C0~, COS, H2S, and CH3SH and
for particulates. Refer to Section 9.
Sulfur will be analyzed for the metals
listed in Section 8, Table VIII, by
adaptation of methods which were designed
for oil analysis.
to
o
The solid material will be analyzed for the
components listed in Section 7, Tables VI
and VII. The aqueous phase will be analyzed
for the components listed in Section 6, Table IV.
The Na, V, and carbonate content of the
stream may cause interferences in the analyses.
Off-gases to be analyzed for particulates
and for COS, H2S, CHjSH and S02/S03, see
Section 9. In addition Na and V will be
determined on particulates, see Section 7.
The stack gases will be analyzed for
S02/S03, NOX, CO, C02, COS, H2S and
CH3SH and for particulates. Refer to
Section 9.
-------
Table 35 (Cont'd)
Summary of Effluent Streams to be Analyzed for COED PI;
COAL LIQUEFACTION
COED PROCESS MODEL
Stream Name
Stream No.
62 Lime Sludge From Flue-Gas Treatment
Analysis For
63
65
69
70
Char Ash from Boilers
Raw Water to Process
Degasser Vent Gases
Sludges from Water Treatment
74
Evaporation and Drift from Cooling
Towers
Complete coal solids analysis
and complete water analysis.
Complete coal solids analysis
and complete water analysis.
Complete Water Analysis
Trace Sulfur Compounds
Hydrocarbons
Complete coal solids analysis
and complete water analysis.
Atmosphere in vicinity of cooling towers
to be sampled for:
Trace Sulfur Compounds
Trace Elements
Hydrocarbons and PNA
Analytical Section Reference
The solid material will be analyzed for the
components listed in Section 7, Tables VI
and VII. The aqueous phase will be analyzed
for the components listed in Section 6, Table IV.
The high Ca content of the stream may cause
interferences in the analyses.
The solid material will be analyzed for the
components listed in Section 7, Tables VI
and VII. The aqueous phase will be analyzed
for the components listed in Section 6, Table IV.
Raw water will be analyzed for all components
listed in Section 6, Table IV.
i
Vent gases will be analyzed for Thiophene, £
C02, S02/S03, COS, H2S, and CH3SH and for >-
benzene, toluene, and other volatile organic '
See Section 9.
The solid material will be analyzed for the
components listed in Section 7, Tables VI
and VII. The aqueous phase will be analyzed
for the components listed in Section 6, Table IV.
The chemicals used for water treatment may
cause interferences in the analyses.
A high volume sample will be collected and the
particulates will be analyzed for the metals
listed in Section 7, Table VI. In addition the
atmosphere will be sampled for benzene, toluene
and other volatile organics; polynuclear
aromatics; and for thiophene, CS2, 303/303, COS,
H?S, and CH3SH (Section 9).
-------
- 122 -
4.17 Unit Material Balances
As indicated for gasification in Section 3.19 above, further
analyses may be necessary if an over-all plant balance cannot be made
using analyses of streams in table 35. Additional streams are listed
below for critical units.
Coal Preparation - Streams 2 and 4.
Stages 2,3,4 Pyrolysis - Streams 13, 14, 15, 16, 17, 18, 19,
21, 22, and 39.
Oil Filtration - Streams 25, 27, 28, 29, 30 and 31.
Hydrotreating - Streams 30, 32, 33, 34, 36, 37, and 39.
Sulfur Recovery - 45 and 51, 53 and 54.
Power and Steam Generation - 20, 46, 58, 59, 60 and 64.
Cooling Water - Streams 68, 71, 72, 73 and 75.
The above would require 37 to 38 more streams to be analyzed than the 23
listed in Table 35.
As indicated under Gasification (in 3.19.8), it may be necessary
in some cases to make heat and material (including potential pollutants)
balances around a particular unit. An example might be Oil Filtration
(Section 4.7). Although no streams are indicated to be analyzed to make a
pollutant material balance around the plant, it may be desirable to compare
the pollution load of filtration with, for example, distillation. All
streams of figure 23, together with any other streams of the particular
unit of interest, would be sampled and analyzed according to the analytical
sections of this plan and these analyses, together with utility requirements,
would allow this unit to be compared with other units from the viewpoint of
environmental impact.
-------
- 123 -
5. TYPICAL AVAILABLE STREAM ANALYSES AND STANDARDS
Tables 36-39 list some stream analyses for existing commercial
plants, proposed plants and pilot plants for those materials that have
been suggested in the Analytical Test Plan. In some cases the rules were
"bent" to include some data that shows approximate results. For example,
results on benzene soluble tar from the Synthane process were included.
Similarily, data from a biox unit at SASOL were included even though streams
from other industries were mixed with the Sasol stream before the biox
unit.
Also included in table 36 are data ranges for analysis of U.S.
coals. To indicate ranges of interest, information has been included
on existing or proposed state and Federal standards for air and water
effluents.
It is obvious that data on most streams of interest are not
available and even for those streams about which something is known,
much of the data is lacking.
Table 40 presents some standards for water effluents and table
41 presents some air standards. These tables give some indication of
what is or will be needed in the way of stream analyses and show something
of the ranges of components to be analyzed.
-------
Table 36
Stream Analyses for Existing Plants, Coal
Stream No. From Analvtical Test Plan 5 (Gasification) ; 6 (Liquefaction)
Stream Identification
Stream Analyses
As
Ba
Be
Ca
Cd
Cr
F
Fe
Hg
Li
Mn
Na
Ni
Pb
Sb
Se
V
Fixed C, 7.
Volatile Matter, '/,
Ash, %
Moisture, '/,
C,'% SAF
H, % MAF
N, 7. MAF
S, 7, MAF
0, 7, MAF
P, % MAF
Calorific Value, Btu/lb
Fusibility of Ash, "C
Softening Point
Melting Point
Fluid Point
Sized Coal tJ Gasifiers and Liquefaction, ppm
EPNG (Ref. 1)
Navajo Coal
0.1-3
...
...
0.2-0.4
200-780
0.2-0.35
—
—
3-30
1.4-4
0.3-1.20
0.08-0.21
_—
17.3
16.5
76.72
5.71
1.37
0.95
15.21
7,500-10,250
___
Synthane (Ref. 43)
Illinois No. 6
...
...
...
...
...
...
...
...
—
—
—
43
37.5
11.2
8.3
63
5.3
1.1
3.5
15.9
—
...
Westfieid (Ref. 44)
— -
—
---
—
...
...
...
—
...
.._
...
—
...
---
13.24
16.5
56.52
3.73
0.89
1.13
7.99
—
9,810
— —
SASOL (Ref. 45)
2-5
...
2-3
-------
Table 37
Stream Analyses for Existing Plants,
Liquid Organic Products
(ppm except as noted)
Stream No. from ATP
Stream Identification
Stream Analyses
As
Ba
Be
Ca
Cd
Cr
Fe
Hg
Li
Mn
Na
Ni
Pb
Sb
Se
V
TOTAL S, %
17 (Gasification)
Synthane (Ref. 43
(Benzene Soluble)
0.7
— _
_._
---
—
_..
---
2.8
Westfield
(Ref. 44)
--_
...
-__
...
_._
_._
—
0.77
SASOL (Ref. 45)
3.1-5.0
— — —
0.6-1.0
«*• «
0,03- 0.05
...
—
0.3-0.5
— — — —
1.6-4.1
___
1.6-4.1
50
0.8-1.0
1.8-8.2
0.3
24 (Gasification)
Ta]
Westfield
(Ref. 43)
— ..
___
___
___
. — .
.
—
—
—
0.29
: uiJ., ppm
SASOL (Ref. 45)
23-30
0.06
0.3
0.1-0.15
0.2-0.3
1-1.4
0.5-1.2
0.5-0.6
0.1-0.3
0.25
30 (Gasification)
Naj
WestfieM
...
._ —
0.078
?htha. ppm
_ •»•-
0.34
ro
Ul
-------
Table 38
STREAM ANALYSIS FOR EXISTING PLANTS, ASH
Stream No. from Analytical Test Plan 67 (Gasification)
Wet Ash (Dry Basis), ppm
SASOL (44) Azot Sanayii (47)
Stream Identification Westfield (44) (Not Quenched) (Not Quenched)
Stream Analysis
As
Ba
Be
Ca
Cd
Cr
F
Fe
Hg
Li
Mn
Na
1-2
<0.5
25,600 50,000 43,000-71,000
£0.1
Trace
150
32,900 35,000 91,000-105,000
<0.1
Trace 2,000
5,000 2,200-7400
Ni Trace 150-200
Pb 50
Sb 4). 5
Se
V 1000
-------
- 127 -
Table 39
for Existing Plants, Water Effluent
Stream No. from Analytical Te~i: ?l>n 39 (Gasification) and others
Biox Unit
Stream Identification Treated Water Effluent
From SASOL (45)
- - - __ _ . mg/1 where applicable
Stream Materials ~
pH 8.5
Suspended solids 31.0
TDS 959
Frac and saline
ammonia (ae N) 7.45
As 0.05
B 4.40
Hexavalent Ct
Total Cr 0.01
Cu 0.04
Phenols (Steam volatile) °-03
Pb 0.02
or 0.11
S°
F- 5.87
Zn 0.07
Na 158
Phosphates (as P) °-29
COD 82
0* 11
Soap, Oil and Grease °'l3
Fe
Cd
Mn
Ag
Nitrates, total
, As N02
, As NH3
Phosphates, Max.
, Average
Dissolved Oxygen
Max, T. °F
Max, AT. »y
Turbidity, Max
EOD.
3
TOG
-------
- 128 -
Table 40
Standards for Water Effluents
Stream Materials
PH
Suspended
TDS
T":: -;c and saline
ammonia (as N)
As
B
Hexavalent Cr
Total Cr
Cu
Phenols (Steam volatile)
Pb
CN"
S=
Zn
Na
States, Existing
and New (Ref. 48)
mg/1 where applicable
(4. 3-7. 0)-(8. 0-10.0)
....
All toxics:
0.00-0.50
0.05-0.5
0.05-1.0
0.005-1.0
0.05-0.10
----
0.1-5.0
----
Proposed New
Standards for
Petroleum Refining (Ref. 50)
ib/iooo bbi (:?
30 Day Max. Range
6.0-9.0
0.93-4.2
•» •• *» «•
0.3-2.6
0.00046-0.0021
0.023-0.106
0.0099-0.046
____
0.0081-0.038
0.046-0.16
— - — -
lb/6, 500 M Btu)
One Day Max Range
6.0-9.0
1.2-5.2
....
0.4-3.4
0.00058-0.0026
0.030-0.132
0.014-0.065
0.013-0.059
0.058-0.21
— ™ ™"
Phosphates (as P)
COD
0\
Soap, Oil and Grease
Fe
Cd
Mn
Nitrates, total
, As N02
, As NH3
Phosphates, Max.
, Average
Dissolved Oxygen
Max, T. °F
Max, AT, °F
Turbidity, Max /\JTT;
BOD5
TOC
0.1-1.5
0.1-0.5
0.05-1.0
0.0005-0.05
0.4-45.0
5.0-50.0
0.01-5.0
1.0-4.0
.025-0.1
2.0-6.0
66-96.8
0-20
5-50
5.3-48.2
0.46-2.1
6.6-60.2
0.58-2.6
1.5-6.6
1,3-9.2
L:«5-8,2
1.6-11.4
-------
Particulates, lb/10 Btu
5,000 Btu/hr*
10,000 Btu/hr*
20,000 Btu/hr*
Process Rate, Ib/hr.
200 tph
500 tph
1000 tph
Sulfur Oxides, lb/106 Btu
Sulfur Oxides, ppm
Nitrogen Oxides, lb/106 Btu
Carbon Monoxide
N.A. -- Not Applicable
* 1 MM Btu/hr £ 1 tpd of coal
Table 41
Air Standards
Fuel Burning Equipment
(Ref 48) States Ranges
(Existing or All)
0.024-0.6
0.02-0.6
0.02-0.6
N.A.
N.A.
N.A.
(For Solid Fuel)
0.3 - 6.0
(For Liquid Fuel)
0.3 - 1.5
N.A.
(Solid Fuel)
0.3 - 1.3
(Liquid Fuel)
0.30 - 0.60
(Gaseous Fuel)
0.20 - 0.60
200 ppm
(1 entry)
Industrial
(Ref. 48)
States Ranges
(Existing or All)
N.A.
N.A.
N.A.
21.20 - 142.7
21.20 - 263.69
21.20 - 419.6
N.A.
N.A.
500 - 2000
N.A.
N.A.
N.A.
200 ppm
(1 entry)
40 mg/m3 -
1 hr Average
Concentration
Selected
New Source
Performance Standards for state of New Mexico Emissions for
Specific Sources (Ref. 50,51) Coal Gasification Plants njef. 4
-------
- 130 -
6. BIBLIOGRAPHY
(Sections 1 through 5)
1. El Paso Natural Gas Company Burnham Coal Gasification Complex-Plant
Description and Cost Estimate, Stearns-Roger Incorporated, Denver,
Colorado, August 16, 1972.
2. Application of El Paso Natural Gas Company before U.S. Federal Power
Commission, Docket No. CP 73-131, November 15, 1972 (Revised October 1973)
3. "El Paso Coal Gasification Project," Draft, Environmental Statement,
U.S. Department of Interior, Bureau of Reclamation, Jluy 16, 1974.
4. Shaw, H., and Magee, E.M., "Evaluation of Pollution Control in Fossil
Fuel Conversion Processes, Gasification, Section 1, Lurgi Process,"
EPA-650/2-74-009-C, July 1974.
5. Chemical Week, January 22, 1975, p. 36.
6. Eddinger, R. T., et al., "Char Oil Energy Development," Office of Coal
Research R & D Report No. 11, Vol. I (PB-169 562) and Vol. II
(PB-169 563), issued March 1966.
7. Jones, J. F., et al., "Char Oil Energy Development," Office of Coal
Research R & D Report No. 11, Vol. I (PB-173 916) and Vol. II
(PB-173 917), issued February 1967.
8. Jones, J. F., et al., "Char Oil Energy Development," Office of Coal
Research R & D Report No. 56, Interim Report No. 1, GPO Cat. No.
163.10:56/Int. 1, issued May 1970.
9. Sacks, M. E., et al., "Char Oil Energy Development," Office of Coal
Research Report 56, Interim Report No. 2, GPO Cat. No. 163.10:567
Int. 2, issued January 1971.
10. Jones, J.F., et al., "Char Oil Energy Development," Office of Coal
Research R & D Report No. 56-Final Report, GPO Cat. No. 163.10:56,
issued May 1972.
11. Jones, J. F., et al., "Char Oil Energy Development," Office of Coal
Research R & D Report No. 73-Interim Report No. 1, GPO Cat. No.
163.10:73/Int. 1, issued December 1972.
12. Shearer, H. A., and Conn, A. L., "Economic Evaluation of Coed Process
plus Char Gasification," Office of Coal Research R & D Report No. 72-
Final, GPO Cat. No. 163.10:72, issued December 1972.
13. Eddinger, R. T., Proc. Fourth Synthetic Pipeline Gas Symposium,
Chicago, Illinois, October 30, 1972, pp. 217-224.
14. Cochran, N. P., Proc. Fifth Synthetic Pipeline Gas Symposium, Chicago,
Illinois, October 29, 1973, pp. 247-264.
-------
- 131 -
15. Hamshar, J. A., et al., "Clean Fuels from Coal by the COED Process,"
EPA Symposium on Environmental Aspects of Fuel Conversion Technology
St. Louis, Missouri, May 1974, EPA-650/2-74-118, October 1974.
16. Kalfadelis, C. D., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Liquefaction, Section 1. COED Process," EPA-650/
2/-74-009-e. January 1975.
17. Magee, E. M., Jahnig, C. E., and Shaw, H., "Evaluation of Pollution
Control in Fossil Fuel Conversion Processes, Gasification, Section 1.
Koppers-Totzek Process," EPA-650/2-74-009a, January 1974.
18. Lowry, H. H., Chemistry of Coal Utilization. Supplementary Volume,
John Wiley & Sons, Inc., 1963, pp. 892-1040.
19. Jo«el, H. C., and Howard, J. B., New Energy Technology, The MIT Press,
20. Bodle, W.W., and Vyas, K. C., "Clean Fuels From Coal," The Oil and Gas
Journal, August 26, 1974, pp. 73-88. ~
21. Rudolph, P.D.H., "The Lurgi Process - The Route to SNG from Coal "
Proc. Fourth Synthetic Pipeline Gas Synposium, Chicago, Illinois,
October 30, 1972, American Gas Association Cat. No. L11173, pp. 175-214.
22. Cameron, D. S., et al., "Environmental Aspects of El Paso's Burnham
Coal Gasification Complex," EPA Symposium on Environmental Aspects
of Fuel Conversion Technology, St. Louis, Missouri, May 1974, EPA-650/
t-"~ I H~" J_ J.O •
23. Berty, T. E., and Moe, M. M., "Environmental Aspects of the Wesco Coal
Gasification Plant," EPA Symposium on Environmental Aspects of Fuel
Conversion Technology, St. Louis, Missouri, May 1974, EPA-650/2-74-118.
24. Kalfadelis, C. D., and Magee, E. M., "Evaluation of Pollution Control
in Fossil Fuel Conversion Processes, Gasification, Section 1, Synthane
Process," EPA-650/2-74-009b, June 1974.
25. Jahnig, C. E., and Magee, E. M., "Evaluation of Pollution Control in
Fossil Fuel Conversion, Gasification, Section 1, C00 Acceptor Process "
EPA-650/2-74-009-d, 1975. 2
26. Flynn, J. V., Chemical Engineering, January 6, 1975, p. 61.
27. Chemical Week. January 8, 1975, p. 26.
28. Chemical Week. January 15, 1975, pp. 14-15
29. Chemical Engineering. January 20, 1975, pp. 56-58.
30. "Background Information for New Source Performance Standards," EPA APTD-
1352 a, June 1973. '
-------
- 132 -
31. Hartwell, I. L., Public Health Service Publication, No. 149, 1951.
32. Sarvicki, E., and Cassel, K., National Cancer Institute, Monograph
No. 9, 1962.
33. "Coal Mining Industry - Effluent Limitation Guidelines," EPA, Sept-
ember 5, 1972.
34. "Demonstration Plant, Clean Boiler Fuels from Coal," OCR R&D Report
No. 82, Interim Report No. 1, Vol. I and Vol. II, Ralph M. Parsons Co.
35. Phinney, J. A., "Coal Liquefaction at the Cresap, W. Va. Pilot Plant,"
presented at A.I.Ch.E. Coal Conversion Pilot Plant Synposium, Pittsburgh,
Pennsylvania, June 2, 1974.
36. Frohning, C. D., and Cornils, B., "Chemical Feedstocks from Coal,"
Hydrocarbon Proc., November 1974, pp. 143-146.
37. U.S. Pat. No. 3,341,447, 1967.
38. Dierdoff, L. H., Jr., and Bloom, R., Jr., "The COGAS Project," SAE
West Coast Meeting, Portland, Oregon, August 1973.
39. "Char Oil Energy Development," OCR R&D Report No. 73 - Int. Rept. No. 2,
GPO Cat. No. I 63.10:73/Int. 2, July 1974.
40. Bulger, L., et.al., "Disposition of Power Plant Wastes," presented
at American Power Conference, 36th Annual Meeting, Chicago, Illinois,
May 1, 1974.
41. Ruch, R. R., Gulskoter, H. J., and Shimp, N. F., "Occurrence and Distri-
bution of Potentially Volatile Trace Elements in Coal," EPA-650/2-74-054,
July 1974.
42. Magee, E. M., Hall, H. J. and Varga, G. M. Jr., "Potential Pollutants
in Fossil Fuels," EPA-R2-73-249, June 1973, NTIS PB No. 225 039.
43. Forney, A. J., et al., "Symposium Proceedings: Environmental Aspects
of Fuel Conversion Technology," St. Louis, Missouri, May 1974, EPA-650/2-
74-118, p. 107, October 1974.
44. Communication from the Scottish Gas Board, Westfield Works, Cardenden
Fife, Scotland November 1974.
45. Communication from the South African Coal, Oil and Gas Corporation, Ltd.
(SASOL), Sasolburg, South Africa, November 1974.
46. Communication From Azot Sanayii, Kutahya, Turkey, (Koppers-Totzek and
Winkler Plants), November 1974.
47. Jahnig, C. E., "Evaluation of Pollution Control in Fossil Fuel Conver-
sion Processes - Liquefaction: Section 2 SRC Process," EPA-650/2-74-
009f, March 1975.
-------
- 133 -
48. Information collected from various sources.
49. Rubin, E. S. and McMichael, "Symposium Proceedings: Environmental
Aspects of Fuel Conversion Technology (May 1974, St. Louis, Missouri)",
EPA-650/2-74-118, October 1974.
50. ibid., (From Federal Register, Vol 38, No. 24, December 14, 1973,
pp. 34541-34558).
51. ibid., (From Federal Register, Vol. 39, No. 47, March 8, 1974).
52. Abstracts of Papers, 167th National Meeting of the American Chemical Soc-
iety, I&EC Division, Los Angeles, April 1, 1974.
-------
- 134 -
7. ANALYTICAL CONSIDERATIONS
7.1 Introduction
In selecting the possible pollutants for analysis in the selected
plant streams, five factors were considered. These were 1) the potential
impact of pollutant on the environment, 2) available data regarding the
composition of commercial coal gasification and liquefaction plant streams,
3) the minor and trace constituents of coals, 4) various process consi-
derations, and 5) lists supplied by the EPA of materials which are consi-
dered environmental hazards. Some of the literature which was consulted
to arrive at the selection of possible pollutants is given in Table I.
On the basis of this literature, the materials listed in Table II
were selected for analysis. In addition to these materials, additional
analyses were deemed desirable to include in the test plan because some envir-
onmental insight might be gaiuea into the process in eeneral; these analyses are
listed in Table III.
Many analytical procedures are potentially applicable for the
analysis of the potential pollutants and other required measurements,
listed in Tables II and III, in the various streams of the liquefaction
and gasification plants. In selecting the suggested procedures, which are
given later, consideration was given to 1) procedures which are widely
usad for analysis of the pollutants in a given matrix, 2) procedures
which have been demonstrated to be applicable for determinations of certain
components of a given matrix, 3) procedures which are potentially applicable
for the analysis of a matrix component but have not been extensively tested,
4) procedures for multicomponent analysis, and 5) the concentration
ranges at which the procedures are applicable.
It must be stressed that since the detailed compositions of the
plant streams are unknown, components may be present which will interfere
with the suggested procedures. If interferences are suspected during the
course of analysis for a pollutant or if a small quantity of a pollutant
is to be measured in the presence of a large quantity of another component,
the applicability of the procedure should be determined.
It is to be noted that the literature is frequently contradictory as
to the applicability of procedures to various components and procedures
other than the suggested procedures are available for measurement of pollu-
tants. If an alternative procedure is selected, its applicability should be
evaluated.
It is convenient to broadly classify the types of samples to be
obtained from plant streams into 1) aqueous samples, 2) coal and coal-
related solid samples, 3) gas and ambient air samples, and 4) coal
liquid samples. The analytical methods which are suggested for samples
-------
- 135 -
TABLE I
LITERATURE SURVEYED FOR SELF.P.TTnM
"Occurrence and Distribution of Potentially Volatile Trace Elements in
Coal, R. R. Ruch, H. J. Gluskoter and N. F. Shimp, Illinois State Geolo-
gical Survey, EPA-650/2-74-054, July 1974.
"Potential Pollutants in Fossil Fuels," E. M. Magee, H. J. Hall and
G. M. Varga, Jr, EPA-R2-73-249, June 1973.
FEUDick ^^1 Anal^sis ^ Mase Spectrometry," J. T. Swansiger,
F. E. Dickson, and H. T. Best, Anal. Chem. , 46, 730 (1974).
"Evaluation of Pollution Control in Fossil Fuel Conversion Processes,
>" *'
"Evaluation of Pollution Control in Fossil Fuel Conversion Processes,
EpTesO/^nnr10? i* COED1^ocess'lt C- 0- Kalfadelis and E. M. Magee,
ErA-toU/2-74-009-e Februar
1
, February 1975.
-------
- 136 -
TABLE II
POSSIBLE POLLUTANTS FROM COAL PROCESSING
Metals
As
Ba
Be
Ca
Cd
Cr
Fe
Hg
Li
Mn
Na
Ni
Pb
Sb
Se
V
Gases
AsH3
H2Se
Fe, Co and Ni Carbonyls
so2/so3
NOX
COS
H2S
CH3SH
NH3
Ho
CO
C02
CH,
Polynuclear Aromatics
)3enzo (k) f luoranthene
Benzo(b)fluoranthene
Benzo(a)pyrene
Benzo(e)pyrene
Perylene
Benzo(ghi)perylene
Coronene
Chrysene
Fluoranthene
Pyrene
Benzo(ghi)fluoranthene
Benz(a) anthracene
Triphenylene
Benzo(j)fluoranthene
Other Organic Materials
Thiophene
cs2
phenols
benzene
toluene
xylene
oil
acids
aldehydes
Inorganic Ions
CN~_
SCN
F~
S~
Cl
Phosphates
Particulates
-------
- 137 -
TABLE III
OTHER ANALYSIS
Coal Analysis
Moisture
Ash
Volatile Matter
Fixed C
S
P
C
H
N
Calorific Value
Fusibility of Ash
Water Quality Indicators
Specific Conductance
PH
COD
BOD
TOG
Residue
Dissolved Oxygen
Suspended solids
Dissolved solids
Turbidity
Color
Oils
-------
- 138 -
are discussed separately, as are sampling and preservation of samples,
for each sample type. Before these specific discussions, a general
discussion on the analysis samples for metals is presented because oi:
the rapidly developing technology in this area and the fact that many
different analytical techniques are potentially applicable for metals
analysis.
7.2 Analysis of Metals^
Much attention has recently been given to the analysis of metals
in aqueous, oil, coal, and particulate samples. Flame atomic adsorption
and heated'vaporization atomic absorption have been widely used for analysis
of samples containing small quantities of metals due to the selectivity
and high sensitivity of the techniques and to the relatively low cost of
the instrumentation involved. Neutron activation, spark source mass
spectrographic, and emission spectrographic techniques have been applied
for multielement trace analysis. X-ray fluorescence has been widely
applied for metal analysis at somewhat higher levels than the aforementioned
techniques.
The accurate analysis of trace quantities of metals in coal ,
coal ash, petroleum, and petroleum products has been the subject of much
investigation recently. The National Bureau of Standards supplied samples
of coal, fly ash, fuel oil, and gasoline to cooperating laboratories for
analysis of trace metals as part of a program to 1) assess the need for
standard reference materials of these substances, and 2) to determine
comparability of various analytical techniques. The results obtained on
these samples (1,2) indicated that there is definitely a need for standard
reference materials of these substances because of the scatter in the
results which were reported.
The Illinois Geological Survey recently published the results
of a study of the determination of trace elements in coal using a variety
of analytical techniques and found that certain techniques were better
suited than others for the analysis of certain elements in coal.
The need for methods to obtain accurate, reliable data on trace
metals content on oils is reflected in the fact that a project involving
five petroleum companies was formed to develop and evaluate the precision
and accuracy of methods for the analysis of petroleum oils for metals at
the 10 ng/g level. The undertaking was deemed to be of such significance
that when the first publication from the project appeared in Analytical
Chemistry, an editorial regarding the project appeared in the same issue (3)
The point of this discussion is that perhaps the greatest diffi-
culty and uncertainty in the analysis of the liquefaction and gasification
plant streams will probably be. with regard to their metals content. There-
fore particular attention should be given to the implementation of the
suggested procedure in the laboratory. Experiments should be performed to
validate and develop the techniques that are needed for the use of the
procedures before the analysis of the plant streams commences.
-------
- 139 -
7.3 Alternative Analytical Techniques
References have been provided, when applicable, for alternative
analytical techniques. For example, three sources have been cited for
analysis of aqueous samples (Section 6.1). What is believed to be the
best techniques have been selected for use in this analytical test plan.
These selections were made on the basis of (1) use experience in a number
of laboratories, (2) validation by independent workers, (3) methods used
by EPA, and (4) use experience in analyses of related materials. As
indicated above, the use of an alternative procedure found in the references
should be validated.
7.4 Results Analysis
Since the overall objective of the test plan is to provide a
material balance of all possible pollutants from a given plant, it is
necessary that the analyses be sufficiently accurate to give the desired
accuracy in the balance. The references cited indicate the number of
samples to be analyzed in each case. This should provide sufficient accur-
acy for the desired result. In cases where a material balance is not ob-
tained, a detailed search must be made as to the cause of the imbalance.
This cause may not be related to the sampling and analysis but may be caused
by other factors such as errors in the estimate of the delay time between
process changes and attainment of steady state conditions down stream.
Another factor may be reactions of a stream component between the unit where
it is formed to the unit where the sampling is made. (Bacterial action in
cooling towers was previously pointed out as an example of this problem.)
Another problem source is the possibility of adsorption or absorption and
desorption of trace materials when process conditions are changed. For
instance, in acid gas treatment, if a trace component concentration is in-
creased due to changes in a gasification reactor variable, the effluent
from the acid gas absorbers will not contain the steady state concentration
of that component until the absortion solution is saturated with that com-
ponent at its new partial pressure. Changes in temperature of operating
units can have similar effects. The age of absorber or catalysts can also
produce these anomalous results.
Unless otherwise indicated, the following procedure is recommended
to check sampling and analysis techniques: When a stream is to be analyzed
for the first time, five samples should be taken. Three of these should be
submitted for analysis as is. The other two should be spiked with two
different levels of the component (s) of interest. In this way, if the final
analyses correctly show the effects of spiking as well as agreement of the
unspiked analyses, then additional validity of the results is indicated.
results Th1 W°rd,°f CaUtl°n Sh°Uld be inJect^ ^ to the analysis of the
ITn ^ .i5 t0 Wlth samPlin8 streams "here the act of sampling
can change the concentration of the stream components. This is often the
case when sampling high temperature streams. Unless the sample is cooled
extremely rapidly, a shift in equilibrium of the components can take place
and reactions can take place on the sampler walls.
-------
- 140 -
In most cases of interest, samples can be taken from two or more
cool streams to give the desired information (e.g., a cool gas sample and
a condensed water sample may take the place of a hot sample containing water
vapor). Again, in all cases, experience and technical judgement are nec-
essary to produce reliable results.
-------
- 141 -
8. ANALYSIS OF AQUEOUSSAMPLES
8.1 Introduction
There are three collections of procedures for the analysis of
aqueous samples for pollutants which are in general use in this country.
These are "Methods for Chemical Analysis of Water and Wastes,"
EPA-625-/6-74-003, Environmental Protection Agency, Washington, D.C.,
1974; "Standards Methods for the Examination of Water and Waste Water,"
13th Ed., American Public Health Association, Washington, B.C. 1971; and
"Annual Book of ASTM Standards, Part 31, Water," American Society for
Testing and Materials, Philadelphia, Pa., 1974. These are abbreviated
EPA/74, W & WW/13, and ASTM/31, respectively in this section. In addition
to these collections, the chemical literature was surveyed for methods
which are applicable for the analysis of pollutants in waters.
In selecting the suggested procedures which are given in Table
IV, primary consideration was given to the methods in EPA/74 since the
procedures in this collection will be used by the agency in determining
compliance with water and effluent standards established by the agency.
Where these methods were not thought to be applicable or where methods did not
exist for potential pollutants of interest, other procedures were chosen.
For the analysis of metals as a group, neutron activation, spark
source mass spectrographic and emission spectrographic techniques have been
used. If a simultaneous determination of metals is desired, consideration
should be given to the technique of LeRoy and Lincoln (4) which was shown
to be applicable to the simultaneous determination of 36 elements, includ-
ing all of those listed in Table II, except Ba, Li, and Se.
The methods in Table IV may be used to measure both total and
dissolved constituents of samples. If the dissolved concentration is to
be determined, the sample is filtered through a 0.45 ym membrane filter
and the filtrate analyzed by the suggested procedure. Filtration in the
field is recommended; if that is -not feasible, the sample should be fil-
tered as soon as it is returned to the laboratory.
8.2 Sampling
Sampling methods which are generally applicable to industrial
waters are discussed in detail in ASTM D-510 and the use of one of these
procedures is recommended. Apparatus, frequency, and duration of sampling,
composite samples, sampling points, and preparation of sample bottles are
discussed in ASTM D-510.
8• 3 Preservation of Samples
The amount of sample that should be collected for the analysis
of each component, the method of preservation and the holding time before
analysis, where these factors have been reported, are given in Table V.
More information regarding these factors is discussed in many of the
suggested methods.
-------
- 1A2 -
TABLE IVa
SUGGESTED ANALYTICAL METHODS FOR AQUEOUS SAMPLES
Component or Measurement
Phenol
Ammonia
Sulfide
Oil and grease
Cyanide, total
Carbon dioxide
Acids, volatile
Conductance, specific
pH
Fluoride, total
Oxygen demand, chemical
Chloride
Residue, total filterable
Residue, total honfilterable
Phosphorus, total
Oicygen, dissolved
Metals by Atomic Absorption
Antimony
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chromium
Iron
Lead
Lithium
Manganese
Mercury
Nickel
Selenium
Sodium
Vanadium
Organic Carbon, total
Oxygen Demand, Biochemical
Thiocyanate
Nitrata
Sulfits
Method
EPA/74, 32730
EPA/74, 00610
EPA/74, 00745 (W&WW/13, 228)
EPA/74, 00550, 00556 or 00560
EPA/74, 00720
W&WW/13, 111
W&WW/13, 233
EPA/74, 00095 (W&WW/13, 154)
EPA/74, 00400
EPA/74, 00951
EPA/74, 00335
EPA/74, 00940
(ASTM/31 D-512 Ref. Method A)
EPA/74, 70300
EPA/74, 00530
EPA/74, 00665
EPA/74, 00299
EPA/74, 01097
EPA/74, 01002
EPA/74, 01007
EPA/74, 01012
EPA/74, 01027
EPA/74, 00916
EPA/74, 01034
EPA/74, 01045
EPA/74, 01051
Suggested Range* of Method
5 - 1000 yg/1
0.05 - 1.0 mg/1
>1 mg/1
>0.2 mg/1
>0.02 mg/1
see method
up to 5,000 mg/1
see method
oil - 100 mg/1
5-50 mg/1
"all ranges"
10 - 20,000 mg/1
10 - 20,000 mg/1
0.01 - 0.5 mg P/l
>0.05 mg/1
applicability
EPA/74, 01055
EPA/74, 71900
EPA/74, 01067
EPA/74, 01147
EPA/74, 00929
EPA/74, 01087
EPA/74, 00680
EPA/74, 00310 (W&WW/13'
J. M. Kruse and M. G. Mellon
Anal. Chem,_, _25, 446 (1953)
EPA/74, 00620
EPA/74, 00740 (W&WW/13, 158)
1-40 mg/1
>2 yg/1
1-2 mg/1
0.05 - 2 mg/1
0.05 - 2 mg/1
0.2 - 20 mg/1
0.2 - 10 mg/1
0.3 - 10 mg/1
1-20 ng/1
to be determined =
0.1 - 10 mg/1
>0.2 yg Hg/1
0.3 - 10 mg/1
2-20 yg/1
0.03 - 1.0 mg/1
1 - 100 mg/1
>1 mg/1
see method
0.5 - 20 mg/1
0.1 - 2 mg N03 (as N)/l
detection limit is
3 mg SO^/l
Ran^e may be extended upv.'ard by appropriate dilutions in many instance:;; rciur
to the, method.
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- 143 -
TABLE IVb
PRINCIPLES OF THE SUGGESTED ANALYTICAL METHODS
Phenol EPA/74, 32730, p. 241
Distillation_of the sample and reaction of the phenolic compounds in the
distillate with 4-aminoantipyrine to form a colored dye. The intensity
of the color produced in a function of the phenolic content of the sample.
Ammonia EPA/74, 00610, p. 159
nf8^1^"0" fS?m !,bUfffr and colorimetric °r titrimetric determination
of ammonia in the distillate.
Sulfide EPA/74, 00745, p. 284 (W&WW, p. 551)
SuSierthLll^
Cyanide. Total EPA/74, 00720, p. 40
joH EPA/74, 00400, p. 239
Electrometric measurement.
Fluoride. Total EPA/74, 00951, p. 65
Distillation of the sample and determination of fluoride in the distillate
using a selective ion fluoride electrode. oj-scmate
Chemical Oxygen Demand EPA/74, 00335, p. 21
Oxidation of the sample with potassium dichroaate and titration of the excess
dichromate with standard ferrous ammonium sulfate solution. For chloride
contents above 1000 mc*/1 \ifzf> F^A/TA nm/,n ~ o=. • •
<_, , . "'S/-1- Ufae c-A//i+, UUJ-+U, p. .o; minimum accepted COD
Ghloride EpA/74, 00940, p. 29 (ASTM/31 D-512, Referee Method A)
litration with mercuric nitrate.
Residue, Total Filterable EPA/74, 70300, p. 266
filtration of the sample and evaporation of the filtrate.
-------
- 144 -
TABLE IVb (Cont'd.)
Residue, Total Nonfilterable EPA/74, 00530, p. 268
Filtration of the sample and determination of the residue when dried at
105°C.
Phosphorous,. Total EPA/74, 00665, p. 249
Treatment of the sample to convert phosphorus compounds to orthophosphate
and determination of orthophosphate by formation of an antimony-phospho-
molybdate complex. For determination of orthophosphate in sample use
EPA/74 70507; from determination of total hydrolyzable phosphorus use
EPA/74, 00669; and for determination of total organic phorphorus use
EPA/74, 00666.
Oxygen. Dissolved EPA/74, 00299, p. 56
Instrumental probes which depend on electrochemical reactions are used.
Carbon Dioxide, W&WW/13, 111, p. 86
Nomagraphic and titrimetric methods are discussed.
Acids, Volatile W&WW/13, 233, p. 577
Column chromatography of the sample to separate organic acids and titration
of the acids.
Conductance, Specific EPA/74, 00095, p. 275 (W&WW/13, 154, p. 323)
Conductance cell is used.
Metals by Atomic Absorption
Refer to the general discussion on these analyses given in EPA/74 pp. 78-93.
Antimony EPA/74, 01097, p. 94
Lean air-acetylene flame is used.
Arsenic EPA/74, 01002, p. 95
Oxidation of sample followed by arsine generation. Argon/hydrogen/entrained-
air flame is used.
Barium EPA/74, 01007, p. 97
Rich nitrous oxide-acetylene flame is used.
-------
- 145 -
TABLE IVb (Cont'd.)
Beryllium EPA/ 74, 01012, p. 99
Rich nitrous oxide-acetylene flame is used.
Cadmium EPA/74, 01027, p. 101
Oxidizing air-acetylene flame is used.
Calcium EPA/74, 00916, p. 103
Reducing air-acetylene flame is used.
Chromium EPA/74, 01034, p. 107
Slightly rich air-acetylene flame is used.
Iron EPA/74, 01045, p. 110
Oxidizing air-acetylene flame is used.
Lead EPA/74, 01051, p. H2
Slightly oxidizing air-acetylene flame is used.
Lithium
Applicability of atomic absorption to be determined.
Manganese EPA/ 74, 01055, p. 116
Oxidizing air-acetylene flame is used.
Mercury EPA/74, 71900, p. 118
Nickel EPA/74, 01067, p. 141
Oxidizing air-acetylene flame is used.
Selenium EPA/74, 01147, p. 145
air flame. Details are given bv J S c ^fi*" ar§°n/h>'dro^/^t:rai
**arren. I^l^ateA|^ "shka. and E. P.
-------
_ 146 -
TABLE IVb (Cont'd.)
Sodium EPA/74, 00929, p. 147
An oxidizing air-acetylene flame is used.
Vanadium EPA/74, 01037, p. 153
A fuel rich nitrous oxide-acetylene flame is used.
Organic Carbon. Total EPA/74, 00680, p. 236
Organic carbon is converted to C02 which is measured using an IR detector
or is converted to CH^ and measured using a flame ionization detector.
Oxygen Demand. Biochemical EPA/74, 00310, p. 11 (W&WW/13, 219, p. 489)
The 5-day BOD is an biassay procedure which measures the dissolved oxygen
consumed by microbes during assimilation and oxidation of organic material.
Nitrate EPA/74, 00620, p. 197
Reaction of nitrate ion with brucine in sulfuric acid to form a colored
complex. The complex is measured colorimetrically and related to the
nitrate'concentration. See the method for interferences.
Sulfite EPA/74, 00740, p. 285 (W&WW/13, 158, p. 337)
The sample is titrated with standard potassium iodide-iodate solution.
Oxidizable material interferes. See method for a discussion of inter-
ferences.
Thiocyanate J. M. Kruse and M. G. Mellon, Anal. Chem. , 25_, 446 (1953)
The sample is treated with copper sulfate and pyridine and the dipyridine -
Copper (II) - thiocyanate complex which is formed is extracted into chloro-
form and measured colorimetrically.
Oil and Grease EPA/74, 00550, 00556 or 00560, pp. 226-235
Extraction with Freon and measurement of the Freer, extractable material
gravimetrically or by IR spectrcscopy. Refer ro methods.
-------
- 147 -
TABLE V
RECOMMENDATION FOR SAMPLING
OF SAMPLES
AND PRESERVATION
ACCORDING TO MEASUREMKNTm
(Primary Reference:
Measurement
Acids, volatile
Arsenic
Carbon dioxide
COD
Chloride
Cyanides
Dissolved Oxygen
Probe
Winkler
Fluoride
Metals
Dissolved
Suspended
Total
Mercury
Dissolved
Total
Nitrogen
Ammonia
Nitrate
Oil and Grease
Organic Carbon
PH
Phenolics
Volume
Required
(ml)
50
100
1000
100
50
50
500
300
300
300
200
100
100
100
400
100
1000
25
25
500
Container(2)
^
P, G
P, G
G only
P, G
P, G
P, G
G only
G only
P, G
P, G
P, G
P, G
P, G
P, G
G only
P, 3
P, G
G only
EPA/ 74)
Preservative
• unknown — —
HN03 to pH <2
Cool, 4°C
H2S04 to pH <2
None Req.
Cool, 4°C
NaOH to pH 12
Det. on site
Fix on site
Cool, 4°C
Filter on site
HN03 to pH <2
Filter on site
HN03 to pH <2
Filter
HNC>3 to Pa <2
HX03 to pH <2
Cool, 4°C
Cool, 4°C
Cool, 4°C
TJ - ^ ."*- *- -^ ^^-1 ^ 0
CcclT He1"'
H2SC,. to pH <2
CoolT 4°C
Det. on site
Cool, 48C
Maximum
6 Mos
6 Hrs (3)
7 Days
7 Days
24 Hrs
No Holding
No Holding
7 Days
6 Mos
6 Mos
6 Mos
38 Days (Glass)
13 Days (Hard
Plastic)
38 Days (Glass)
13 Days (Hard
Plastic)
24 Hrs (4)
24 Hrs (4)
24 Hrs
24 Hrs
24 Hrs
24 Hrs
to pH <4
1.0 g CuS04/l
-------
- 148 -
TABLE V (Cont'd.)
Volume
Requirpd
Measurement (ml)
Phosphorus
Orthophosphate,
Dissolved
Hydrolyzable
Total
Residue
Filterable
Nonfilterable
Specific Conductance
Sulfide
Sulfite
Thiocyanate
50
50
50
100
100
100
50
50
100
Container^) Preservative
P,
P,
P,
P,
P,
P,
P,
P,
•- < "
G
G
G
G
G
G
G
G
Filter on site
Cool, 4°C
H2S04 to pH <2
Cool, 4°C
Cool, 4°C
Cool, 4°C
Cool, 4°C
2 ml zinc
acetate
Cool, 4°C
*
uiitcnown • ••
Holding Time (6)
24 Hrs (4)
24 Hrs (4)
24 Hrs (4)
7 Days
7 Days
24 Hrs (5)
24 Hrs
24 Hrs
•*"
(1) More specific instructions for preservation and sampling are found with
each procedure.
(2) Plastic or Glass.
(3) If samples cannot be returned to the laboratory in less than 6 hours and
holding time exceeds this limit, the final reported data should indicate
the actual holding time.
(4) Mercuric chloride may be used as an alternate preservative at a concentra-
tion of 40 mg/1, especially if a longer holding time is required. However,
the use of mercuric chloride is discouraged whenever possible.
(5) If the sample is stabilized by cooling, it should be warmed to 25°C for
reading, or temperature correction made and results reported at 25°C.
(6) It has been shown that samples properly preserved r.ay be held for extended
periods beyond the recommended holding time.
-------
- 149 -
Where possible, analyses should be performed as soon after
sample collection as possible because as stated in EPA/74:
"Complete and unequivocal preservation of samples, either
domestic sewage, industrial wastes, or natural water, is a
practical impossibility. Regardless of the nature of the
sample, complete stability for every constituent can never
rlt-rJ1^ i, At beSt' Preservatio* techniques can only
retard the chemical and biological changes that inevitably
continue after the sample is removed from the parent source.
or biolofiL? V^! P^Ce ln 3 Sample are ei'her ch-i"l
or biological In the former case, certain changes occur
in the chemical structure of the constituents that are a
tate i0YH P ^SlCal C°nditions- Metal cations may precipi-
tate as hydroxides or form complexes with other constituents-
cations or anions may change valence states under certain
reducing or oxidizing conditions; other constituents may
dissolve or volatilize with the passage of time. Metal
cations may also adsorb onto surfaces (glass, plastic, quartz,
etc ) such as, iron and lead. Biological changes taking plac^
in a sample may change the valence of an element or a radical
to a different valence. Soluble constituents may be converted
to organically bound materials in cell structures, or cell anal
llll Ta\reSUlt.ln release of -llular material into solution.
biololi ^own nitrogen ™* Phosphorus cycles are examples of
biological influence on sample composition."
-------
- 150 -
9. COAL AND COAL RELATED SOLID ANALYSIS
9.1 Introduction
Much attention has recently been focused on the analysis of
coal, coal ash, fly ash, and airborne particulate matter for elemental
composition. Atomic absorption spectrscopy, X-ray fluorescence, spark-
source mass spectrometry, optical emission spectroscopy, and neutron
activation have been applied for the analysis of these materials for
trace elements (5-12). There is some disagreement in the literature as
to which technique is best suited for the determination of a particular
element.
A recent comprehensive study involving the analysis of 101 coals
for trace elements, which was conducted by the Illinois Geological Survey,
has appeared (15). Because of the extensive study of sample preparation
techniques and methods of analysis given in this report, the methods des-
cribed in it have been selected as the suggested procedures for the
analysis of the coal and coal solids for trace elements where applicable.
The measurement techniques which are used in the methods are given in
Table VI. Some of the methods given in references 5-12 could be substi-
tuted for these as they have been also demonstrated to be valid. Perhaps
the most important factor, besides the inherent detection limit in the
selection of a method, is that experience with a method specifically for
analysis of coal and coal related solids for a particular element is
required before accurate, reliable results can be obtained.
In addition to the analysis of the solids for potential pollu-
tants, it is desirable to analyze coal and related samples for ultimate
and proximate compositions and to determine the ash fusion temperature.
The results of these analyses may lend insight into the influence of vari-
ous types of coals on pollutants in various plant streams. The suggested
procedures for determining the values are given in Table VII.
9.2 Sampling
A gross coal sample should be collected as indicated in ASTM D-2234.
ASTM D-2013 and D-271 describe the preparation of coal samples for analysis,
and one of these methods should be used.
It is suggested that the collection =5 samples of coal ash and
dump pit solids be performed as indicated in ir.e "Proposed Method for
Sampling Iron Ores," ASTM 1974, Part 12, p. 799.
9.3 Preservation
The literature does not contain recommendations for the preserva-
tion of coal or coal ash samples. Therefore, it is suggested that these
samples are stored in clean glass bottles equipped with polyethylene lined
caps until analyses ar« performed.
-------
- 151 -
TABLE VI
MEASUREMENT TECHNIQUES USED IN THE SUGGESTED
METHODS FOR ANALYSIS OF COAL AND COAL
RELATED SOLIDS FOR TRACE ELEMENTS
(Details are given in reference 5)
(except for Ba and Li)
uj-cmeui_
As
Ba(2)
Be
Ca
Cd
Cr
F
Fe
Hg
Li(2)
Mn
Na
Ni
Pb
Se
V
Technique (1)
NAA
Emission Spectroscopy
OE-DR
XRF
AA
OE-DR
ISE
XRF
NAA
AA
NAA
NAA
OE-DR, AA, OE-P, XRF
AA, OE-DR
NAA
OE-DR, OE-P, XRF
Detection Limit ue/e
i . . — M°' &
1.2 in ash
Unknown
1 in ash
12 in whole coal
2.5 in ash
1.5 in ash
10 in whole coal
36 in whole coal
0.01 in whole coal
Unknown
2 in whole coal
0.5 in whole coal
1 in ash
5 in ash
1.8 in ash
5 in ash
(1)
(2)
NAA signifies neutron activation analv=i=.
OE-DR signifies optical emission, direct"-ea-ing
XRF signifies X-ray fluorescence.
AA signifies atonic absorption
OE-P signifies optical emission photographic.
ISE signifies ion-selective electrode.
Experiments must be performed to validate these techniques.
-------
- 152 -
TABLE VII
SUGGESTED METHODS FOR GROSS COAL ANALYSIS
Component Method
Moisture ASTM D-271
Ash ASTM D-271
Volatile Matter ASTM D-271
Fixed C ASTM D-271
S ASTM D-271
P ASTM D-271
C ASTM D-271
H ASTM D-271
N ASTM D-271
Calorific Value ASTM D-271 or D-3286
Fusibility of Coal Ash ASTM D-1857
-------
- 153 -
10. ANALYSIS OF COAL LIQUIDS
10.1 Introduction
As was stated earlier, much attention has been focused recently
on the analysis of oils for trace quantities of metals (1-3). As the
result of studies performed in conjunction with the Trace Metals Project
involving the Atlantic Richfield Company, Chevron Research Company,
Exxon Research and Engineering Company, Mobil Research and Development
Corporation, and Phillips Petroleum Company and a study performed for the
American Petroleum Institute (13) much insight has recently been gained
on the analysis of oils for metals. These studies indicate that neutron
activation analysis is applicable for the determination Sb, As, Co, Mn,
Hg, Mo, Ni, Se, and V if they are present in oils in amounts greater
than 5-50 ng/g, depending on the element, and that emission spectroscopy
is applicable for the determination of Sb, Cd, Be, Cr. Co, Mn, Mo, Ni,
and V if they are present in amounts greater than 20-50 ng/g. In
addition to these techniques which give multielement analysis of samples,
the members of the Trace Metals Project developed specific methods for
the analysis of oils for Sb, Cd, As, Be, Cr, Co, Mn, Se, Mo, Ni, Se, and
V to 10 ng/g. The methods developed during the course of the project
have appeared in Analytical Chemistry and were the topic of an American
Chemical Society Symposium held in conjunction with the National ACS Meetine
in Philadelphia in April, 1975. The determination of trace quantities of
metals in oils, other than tnose listed, has not been exhaustively studied
but other metals probably could be determined by modification of the tech-
niques studied by the Trace Metals Project.
The selected methods for the analysis of oils for the elements
listed in Table VIII are those developed by the Trace Metals Project for
the individual elements, where available; and where unavailable, suggested
methods for investigation to determine their applicability to oils are
given. In some instances the multielement techniques may be preferable.
In addition to the analysis of coal liquids for metals, the
analysis of these materials for polynuclear aromatic hydrocarbons, PNA's,
is important because of the carcinogenic activity of some of these
compounds.
The PNA analysis of the coal liquids is carried out by a gas
chromatographic-ultraviolet spertrographic (G?,'"JV; technique. If the
level is high with few interfering substances the ISM method llinA-ns
"Tentative Method of Analysis for Polynuclear Aronatics in Coke Oven
Effluents" is employed. A 1-10 nicroliter sample of the liquid would
be injected into the GC and the appropriate peaks trapped and measured
by UV.
-------
- 154 -
If other high boiling organics are present, it is necessary
to isolate an aromatic concentrate before the GC/UV step. The technique
employed is presented in the ISM method 11104-04 73T. 0.5 grams of the
liquid would be taken in a 100 ml beaker and spiked with radioactive B(a)A
and B(a)P as directed in paragraph 7.1 of the procedure. The spiked
sample would then be chromatographed on alumina as directed in paragraph
7.6.1. The procedure would then be followed as written.
10.2 Sampling
The collection of coal liquids samples over a period of time,
and the preparation of composite samples for analysis is recommended.
10.3 Preservation
The storage, of composite samples in Teflon bottles is recommended-
-------
- 155 -
TABLE VIII
SUGGESTED METHODS FOR DETERMINATION OF
_ METALS IN COAL LIQUIDS
Technique Reference(4)
As Wet Digest/AsH3 generation/ AA
Ba Wet Ash/ES
Be Direct/HVAA TMp
Ca Wet Ash/AA
Cd Wet Ash/HVAA or AA
Cr Direct/HVAA TMp
Fe Wet Ash/AA (2)
Hg Wet Digest/CVAA (2)
Li Wet Ash/AA (2)
Mn Direct/HVAA ]4
Na Wet Ash/AA (2)
Ni Wet Ash/HVAA T>lp
Pb Wet Ash/HVAA (3) (2)
Se Wet Digest/H2Se generation/AA TMP
v Wet Ash/HVAA TMp
(1) AA signifies flame atomic absorption.
HVAA signifies heated vaporization ato-ic absorption
CVAA signifies cold vapor atomic absorption
ES signifies emission spectrospic.
(2) Methods have not been thoroughly investigated; in these instances
suggested techniques are given by the TMP which must be validated.'
(3) Contamination from ambient sources of Pb vill be a problem.
(4) TMP signifies method developed by the Trace Metals Project Meth H
has appeared in Analytical Chemistry.
-------
- 156 -
TABLE IX
POLYNUCLEAR AROMATIC HYDROCARBONS WHICH ARE DETERMINED IN
COAL LIQUIDS USING THE ISM METHODS
Benzo(k)fluoranthene
Benzo(b)fluoranthene
Benzo(a)pyrene
Benzo(e)pyrene
Perylene
Benzo(ghi)perylene
Coronene
Chrysene
Fluoranthene
Pyrene
Benzo(ghi)fluoranthene
Benz (a) anthracene
Triphenylene
Benzo(f)fluoranthene
TABLE X
OTHER ANALYSES
Total Sulfur ASTM D-129, D-2622, or D-2784
-------
- 157 -
11 • ANALYSIS OF ATMOSPHERIC AND GASEOUS SAMPLES
11.1 Introduction
-. „. A ™rie7 °f materials may be emitted to the air from coal gasi-
fication or liquefaction plants. Provision must be made to collect and anal-
yze all components of interest, from heavy particulates to the most volatile
gases and vapors . A great variety of sampling devices is needed for * ™
plete sampling. Methods for collecting, measuring characterising1 ^i-
culate matter are presented in Table XI. The best techniques for gases and
vapors are in Table XII. Table XIII lists a number of direct readfnTindi-
cator tubes. These are portable and convenient to use but at present manv
are only rangefinding and approximate in nature. present many
11.2 Particulates
The particulates in ambient air of the plant will be det-PT-m-in0H
by the EPA specified method, "Reference Method fo? the Determination oT
Suspended Particles in the Atmosphere, High Volume Method, (Mgh Vol ) " In
this method, air la drawn into a covered housing and through a filter by
60art3°min) t£; IT""'6 blowf « a flow rat* U-" to 1^0 m3/min; 40 to
fnn ?c , 10WS susPended Particles having diameters of less than
100 //m (Stokes equivalent diameter) to pass to the filter «,,%?« lesspthan 1
within the size range of 100 to O.U diameter are ordinarily oilecte "n"
glass fiber filters The mass concentration of suspended particulates in
the ambient air (mg/,.3) is computed by measuring the mass of collected Arti-
culates and the volume of air sampled. ^-i-ectea parti
Total Particulate - In all cases total particulate will be deter
mined gravxmetrically by conditioning the filter/before and after use in"
a constant humidity room and by weighing. This value will include both the
inorganic and organic portions of the sample. mciuae both the
2Qo^ Particulate Size - Particulates are to be sized according to ASTM
extraction, the benzene will be removed and
be
Characterization of Benzene Solubles - One nf H,0 ^K•
measure the concentration ot individual PNA hydrocarbon, o^ec^ves is to
(BaA), Benzo(a)pyrene (3aP), and 12 others In HH ^ ' 3S benzanthracene
obtain some overall compositional information ?HP <•*'^ isdesirable to
briefly described below. mrormation. The methods to be employed are
-------
- 158 -
Polynuclear Aromatic Hydrocarbons - Up to 14 polynuclear
aromatic hydrocarbons will be measured by either the Intersociety Methods
No. 11104-03 73T or ISM 11104-04-0473T depending on the complexity of the
material. In the latter after the Soxhlet extraction, a sample, to be
analyzed is spiked with known quantities of carbon-14 labeled BaA and
BaP. The sample is then transferred to a 100-ml beaker and evaporated»
on a steam bath under nitrogen, to dryness as described earlier for the
measurement of benzene solubles. This residue is dissolved in cyclo-
hexane and caustic treated to remove some acidic compounds. Then a PNA
hydrocarbon concentrate is obtained by solvent elution off a column of
partially deactivated alumina. The solvents are cyclohexane, cyclohexane-
benzene, benzene, and benzene-methanol. The fraction containing the PNA's
is reduced to a small volume by evaporation on a steam bath. An aliquot
of this sample is injected into a gas chromatograph and fractions are
collected for measurement by UV and, in the case of BaA and BaP peaks,
also for carbon-14 activity. These activities, compared with known
concentrations originally added, give factors by which to relate the
concentrations of each PNA to its total weight in the sample.
Other information on the nature of the benzene solubles will
be obtained by gas chromatography, mass spectrometry, and UV and IR
spectrophotometry. Elemental analysis for carbon, hydrogen, nitrogen, etc.
will be done if necessary.
11.3 Gases and Vapors
Ci-C5 Hydrocarbons - ASTM D-2820-72, page 950
G.C. analysis of a grab sample on a packed column operated
isothermally at 0°C.
Benzene, Other Volatile Organics - N10SH No.: 127
Adsorption on charcoal, desorption with carbon disulfide, G.C.
Carbon Monoxide - N10SH No.: 112
Infrared analysis of a grab sample using a 10-meter-path-length
gas cell.
Volatile Sulfur Compounds - (Hydroger. Sulfide, Carbonyl Sulfide,
Carbon Disulide, Mercap.aas, Thiopher.es, Sulfur Dioxide).
J. E. Chaney, J. of Gas Chromatograph 4, 42, (1966).
A grab sample is taken in a 250-ml glass sampling tube through
a Perma Dry tube to remove water. The compounds are separated by G.C. on a
Triton X-305 or other suitable column and detected by a flame photometer
or raicrocoulometer sulfur detector. Details on the detector are given in
ASTM D-3246.
-------
- 159 -
Total Sulfur - ASTM D-3246
Burning of sample oxygen in special tube to S02 followed by
detections with microcoulometer.
Sulfur Dioxide - N10SH No.: 163
Sulfur dioxide is absorbed and oxidized in 0.3N hydrogen
peroxide, then titrated with barium perchlorate using Thorin as indicator.
Sulfuric Acid Mist - EPA Method 8 R-490
Sulfur trioxide is separated from the sulfur dioxide in a special
collection apparatus and determined by the bariurc-thorin titration method.
Nitrogen Dioxide - 0.5-50 ppm - N10SH No.: 108
Nitrogen dioxide is absorbed in an impinger containing an azo
zye forming a stable pink color read at 550 run on a spectrophotometer.
Nitrogen Dioxide - 5-1000+ ppm - EPA No.: 487
Grab sample collected in flask with oxidant, nitrogen oxide
measured colorimetrically using the phenoldisulfonic acid procedure.
Aldehydes - MBTH Procedure
Aliphatic aldehydes are absorbed in impingers containing
3-methyl-2-benzothiazolone hydrazone hydrochloride (MBTH). The azine
is oxidized by a ferric chloride-sulfamic acid solution and measured
at 628 rim. Procedure of Hauser, T. R. et. al., Anal. Cheia. 36. 679 (1964).
Ammonia - ASTM D-1426
Ammonia absorbed in acid in impinger, distilled from alkaline
solution and determined volumetrically or colorimetrically.
Phenols - ASTM D-1783
Phenol absorbed in alkaline solutions in impinger, distilled,
reacted with 4-aminoantipyrine,and determined rolorinetrically.
Cyanide - N10SH No.: 116
The samples are taken using an impinger containing 0.1N NaOH.
The samples are then analyzed using a cyanide ion specific electrode.
-------
- 160 -
Arsine - ACGIH Method No.: 40
Arsine is collected in an impinger containing silver diethyl-
dithiocarbamate. After sampling, the concentration is determined colori-
metrically at 560 nm.
Mercury - EPA Method No.: 101 or 102, pages 512 and 521
The first method is used on samples that are primarily air,
while the second is employed for hydrogen and other reducing gas streams.
The mercury is collected in impingers containing acidic iodine monochloride
solution. It is reduced to elemental mercury, aerated from the solution,
and determined in a gas cell at 253.7 nm.
Beryllium Referee Procedure - EPA No.: 104, page 532
Sample is collected on Millipore filters and impingers containing
distilled water. It is digested with acid and analyzed by atomic absorp-
tion spectrophotometry.
Beryllium Screening Procedure - EPA No.: 102, page 530
Sample is collected on a Millipore filter and analyzed by any
acceptable method such as atomic absorption, spectrographic, fluorometric,
etc.
Fluorides and Hydrogen Fluoride - N10SH No.: 117
Samples are taken through impingers containing 0.1N NaOH,
diluted with a buffer and analyzed using the fluoride specific ion
electrode.
Nickel and Iron Carbonyls - Denshaw, et al., J_. Appl. Chem., 13_,
576, (1963).
Method could probably be extended to cobalt carbonyl.
Hydrogen Selenide - Collection in ispingers containing Na2CC>3
and measurement according to W. H. Allaway and E. E. Gary,
Anal. Chem., 38., 1359 (1964).
Total selenium would be determir.ad.
11.4 Direct Reading Colorimetric Indicator Tubes
Direct reading color indicator tubes have been used for the
measurement of hydrogen sulflde and carbon monoxide for a number of years,
and now there are more than a hundred different types in use. They are
rapid inexpensive, and are especially convenient for evaluation of toxic
materials in industrial surroundings. At present, however, results may
-------
- 161 -
be regarded as only approximate. The best accuracy that can be expected
from indicator tubes of the better types is plus and minus 20 percent.
Table XIII presents some of the tubes that may be applicable in coal
conversion plants.
-------
TABLE XI
SAMPLING AND ANALYTICAL METHODS FOR
PARTICULATES IN ATMOSPHERIC AND OTHER GASEOUS SAMPLES
Component
Method of Analysis
Particulates in Air (High Volume Sampler)
Participates in Stack Gases
Dust Fall
Benzene Soluble in Particulates
Code of Federal Regulations, Title 40, Appendix B. Environ-
mental Protection Agency, U.S. Federal Register Offie,
"Reference Method for the Determination of Suspended Particles
in the Atmosphere (High Volume Method)." ASTM D-2009-65.
ASTM D-2928; EPA Method No.: 5
ASTM D-1739 - Collection and Analysis of Dustfall
(Settleable Particles)
E. C. Tabor and D. H. Fair, J. Air Pollution Control
Assoc., 11, 403 (1961).
10
I
Analysis of Benzene Soluble Portion
of Particulate
Polynuclear Aromatic Hydrocarbons
14 compounds includlnj',
Benzanthracenc and
Benzo(a)pyrene
Gas Chromatographic Analysis
for Boiling Range
Mass Spectrometric Method
Infrared and Ultraviolet Spectra
Carbon, Hydrogen, Nitrogen
Sulfur
Intersociety Method 11104-03 73T "Tentative Method of Analysis for
Polynuclear" Aromatics in Coke Oven Effluents and ISM 11104-04 73T
"Tentative Method of Analysis for Polynuclear Aromatic Hydrocarbons
in Automobile Exhaust. Sensitivity is 1 yg/m3 for each PNA.
ASTM D-2887-72T "Boiling Range Distribution of Petroleum Fractions
by Gas Chromatography."
M. E. Fitzgerald, V. A. Cirillo, and F. J. Galbraith,
Anal. Chem. 34, 1276 (1962).
R. D. Condon. Microchem. J. 10_,408, 1966.
ASTM D-1552
-------
TABLE XII
SAMPLING AND ANALYTICAL METHOD FOR ATMOSPHERIC AND OTHER GASEOUS SAMPLES
Component
Volatile Hydrocarbons
Benzene, Toluene & Other
Volatile Organics
Carbon Monoxide
Volatile Sulfur Compounds:
H2S, S02, COS, RSH
CS2 thiophene
S02 Only
Sulfuric Acid Mist and
S02 emissions
Total Sulfur
Nitrogen Dioxide
High Levels
Low Levels
Aldehydes
Air.ir.onia
Phenols
Sample Collection
Aluminized Bag
Charcoal
Adsorption
5-liter bomb or bag
250 ml glass
sample tubes
Impinger
Special EPA Train
250-ml glass tube
Special Flask
Impinger
Impinger
Impinger
Impinger
Method of Analysis
ASTM D-2820-72 "Ci through C5 Hydro-
carbons in the atmosphere by Gas
Chromatography"
NIOSH Method No.: 127 "Organic Solvents
in Air"
NIOSH Method No.: 112
D. F. Adams and R. K. Koppe, Tappi, 42,
601 (1959); S. S. Brody and J. E. Chaney,
J. of Gas Chromatography, 4^ 42, (1966);
F. V. Wilby, Am. Gas Assoc. Oper. Sect.
Proc., Year 1965, pgs. 65-136.
EPA Method No.: 6, NIOSH No.: 163
EPA Method No.: 8
ASTM D-3246-73 "Sulfur in Petroleum Gas
by Oxidative Microcoulometry "
EPA Method No.: 8
NIOSH Method No.: 108, ASTM D-1607-69,
"Standard Method of Test for Nitrogen
Dioxide Content of Atmosphere (Griess-
Saltzman Reaction)."
EPA MBTH Procedure, Hauser, T.R. Cummins
R. L.. Anal. Chem. (36) 679 1964
ASTM D-1426, after collecting in acid ir.
impinger
ASTM D-I783 after collecting in NaOH in
impinger
Sensitivity
0.01 ppm
0.01 ing/sample
5 ppm
1 ppm
.25 ppm
5 ppm
.01 yg/litre
0.1 ppm
1 ppm
1 pprc
-------
TABLE XII (Continued)
Component
Cyanide
Arsine
Mercury
Beryllium
Hydrogen Fluoride
Nickel and Iron
Carbonyls
Sample Collection
Impinger
Silver Diethyldi-
thiocarbamate in
impinger
Impingers with
iodine
monochloride
Filter (screening)
Impinger (reference)
NaOH in Impinger
Impinger with
iod inc.
monochloride
Method of Analysis
NIOSH Method No.: 116
Manual of A.C.G.I.H. "Determination of
Arsenic in Air," NIOSH Method No.: 140
EPA Method No.: 10
EPA Method No.: 103
EPA Method No.: 104
NIOSH Method No.: 117
Fluorides and Hydrogen
Fluoride in Air
A.B. Densham, et al.
J. Appl. Chem. 13, 576 (1963)
Sensitivity
0.13 mg/m3
1 lag/sample
.03 yg/ml
.01
.01 ppm
Hydrogen Selcniide
-------
TABLE XIII
Some MSA Direct Reading Colorimetric Indicators
Substance
Ars ir.c
Carbon Disulfide
Ca rbon Monox ide
Formaldehyde
Hydrogen Chloride
Hydrogen Cyanide
Hydrogen Fluoride
Hydrogen Sulfide
Nitrogen Dioxide
Sulfur Dioxide
Measurable
Ra ng c
0.025 - 1.0 ppm
5 - 500 ppm
10 - 3000 ppm
1 - 100 ppm
2 - 500 ppm
1-65 ppm
0.5 - 5 ppm
1-800 ppm
0.1. - 50 ppm
1 - 400 ppm
Interference
Stibine, phosphine
Hydrogen
Turpentine, other
a Idehydes
HN03
Ammonia, HS
SO,,
I-LS-, Hal ides
Acetic Acid
Catalog
Nviniber
81101
95297
917.29
93963
9163 6
93262
312 13
S7414
S3G99
92623
-------
- 166 -
12. SAMPLE FORMAT FOR STREAM SAMPLING AND ANALYSIS
Sample formats to be completed for sampling and analyses are
shown in Figures I and II.
-------
Sample Size:
Container:
S tream No.:
Flow Rate of Stream:
Pressure of Stream:
- 167 -
FIGURE I
SAMPLE SHEET FOR GROSS SAMPLE
Gross Sample No.
Temperature of Stream:
Sampling Procedure:
Date Taken:
Time Taken:
Location of Sample in Stream:
Disposition of Gross Sample:
Interfering Substances:
Comments:
Name of Person Taking Sample
-------
Sample Size:
Container:
- 168 -
FIGURE II
SAMPLE SHEET FOR DETAILED SAMPLE
TO BE FILLED IN BY SAMPLER
Detailed Sample No.
(Use Gross Sample Number Followed by
a Dash and Number for Specific Sample)
Preservative:
Date Taken:
Time Taken:
Analyze For:
Date Analyzed:
Analysis Method:
To Be Filled in By Analyst
Time Analyzed:
Method of Preparation:
Component Concentration:
Comments:
Analyst:
Date:
-------
- 169 -
13. BIBLIOGRAPHY
(Sections 7 through 11)
J., Jungers, R. H., and Lee, R. E., Jr., Anal. Chem..
2. Symposium on the EPA-NBS Round Robin Analysis Results for Trace Elements
in Coal, Fly Ash, Fuel Oil and Gasoline, Research Triangle Park, North
Carolina, July 19, 1973.
3. Laitinen, H. C., Anal. Chem.. 46, 2073 (1974).
4. LeRoy, V. M., and Lincoln, A. J., Anal. Chem., 46,369 (1974).
5. Ruch, R. R., Gluskoter, H. J., and Shimp, N. F., "Occurrence and Distri-
Jul101974 P°tentlally Volatile Trace Elements in Coal," EPA-650/2-74-054,
7. Guidoboni, R. J., Anal. Chem.. 45_, 1275 (1973).
8. Sugimae, A., Anal. Chem.. 46, 1123 (1974).
9. Vijou, P. N. and Wood, G. R., At. Absorption Newslett.. 13, 33 (1974).
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- 170 -
TECHNICAL REPORT
(Please read Inunctions on ihc reverse
DATA
before completing)
1. REPORT NO.
EPA-650/2-74-009-1
2.
4. TITLE AND SUBTITLE
Evaluation of Pollution Control in Fossil Fuel
Conversion Processes (Analytical Test Plan)
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
October 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C.D. Kalfadelis, E.M. Magee,
G.E. Milliman, andT.D. Searl
8. PERFORMING ORGANIZATION REPORT NO,
Exxon/GRU.13DJ.75
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
P. O. Box 8
Linden, New Jersey 07036
1O. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-023
11. CONTRACT/GRANT NO.
68-02-0629
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
Task Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
s. ABSTRACT
repor't gives results of a preliminary definition of those streams which
require analysis to permit an assessment of the pollution potential of the processes in
the light of current environmental standards, using a coal gasification process
(Lurgi) and a coal liquefaction process (COED) as a basis. It defines methods for
sampling indicated streams and analytical procedures which are required to obtain
the data. These summaries may be readily modified or adapted to other processes ,
and expanded to include additional polluting constituents or improvements in
analytical procedures.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDEDTERMS
c. COSATI Field/Group
Air Pollution
oal
onversion
Testing
Sampling
Analyzing
Coal Gasification
Liquefaction
Air Pollution Control
Stationary Sources
Pollution Potential
Lurgi Process
COED Process
13B
2 ID
14B
13H
07D
3. DISTRIBUTION STATEMENT
Jnlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
184
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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