EPA-650/2-74-009-e
January 1975
Environmental Protection Technology Series
I
55
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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 degi-adation 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.
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EPA-650/2-74-009-e
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
LIQUEFACTION: SECTION I. COED PROCESS
by
C . D . Kalfadelis and E . M. Magee
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
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
January 1975
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EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Center - Research Triangle Park, Office of Research and Development,
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
This document is available to the public- for sale through the National
Technical Information Service, Springfield, Virginia 22161.
11
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TABLE OF CONTENTS
Page
SUMMARY 1
INTRODUCTION 3
1. PROCESS - GENERAL 4
1.1 Process History 4
1.2 Process Description 5
2. EFFLUENTS TO AIR - MAIN PROCESSING SECTIONS 13
2.1 Coal Preparation and Storage 13
2 .2 Coal Grinding 14
2.3 Coal Drying and First Stage Pyrolysis 15
2.4 Stages 2,3,4 Pyrolysis. 16
2.5 Product Recovery System 16
2.6 COED Oil Filtration 17
2.7 Hydrotreating 18
3. EFFLUENTS TO AIR - AUXILIARY FACILITIES 20
3.1 Oxygen Plant 20
3.2 Acid Gas Removal 20
3.3 Hydrogen Plant 21
3.4 Sulfur Plant 23
3.5 Utilities 24
3.5.1 Power and Steam Generation 24
3.5.2 Cooling Water 28
3.5.3 Water Treatment 29
3.5.4 Miscellaneous Facilities 32
4. LIQUID AND SOLID EFFLUENTS 33
4.1 Coal Preparation 33
4.2 Coal Grinding 34
4.3 Coal Drying and First-Stage Pyrolysis 34
4.4 Stages 2,3,4 Pyrolysis 34
4.5 Product Recovery 34
4.6 COED Oil Filtration 35
4.7 Hydrotreating 35
4.8 Auxiliary Facilities 35
4.8.1 Oxygen Plant 35
4.8.2 Acid Gas Removal 35
4.8.3 Hydrogen Plant 36
4.8.4 Sulfur Plant 36
4.8.5 Power and Steam Generation 36-
4.8.6 Cooling Water 37
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TABLE OF CONTENTS (Cont'd)
Page
4.8.7 Miscellaneous Facilities 37
4.8.8 Maintenance 37
5. THERMAL EFFICIENCY 38
6. SULFUR BALANCE 42
7 - TRACE ELEMENTS. 44
8. PROCESS AND ENGINEERING ALTERNATIVES 47
9 • QUALIFICATIONS 49
10. RESEARCH AND DEVELOPMENT NEEDS 54
APPENDIX 55
BIBLIOGRAPHY 60
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LIST OF TABLES
Table page
Table of Conversion Units 2
1 Stream Identifications for Revised COED Process. 9
2 Properties of Char Product 25
3 Properties of Process Liquors 30
4 Thermal Efficiency 40
5 Sulfur Balance 43
6 Trace Element Concentration of Pittsburgh
No. 8 Bituminous Coal at Various Stages of
Gasification 46
7 Process and Engineering Alternatives 48
8 Feed Coal and Product Char Analysis 50
9 Typical Syncrude Properties 51
10 Utilities 52
11 Plant Water Requirements 53
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LIST OF FIGURES
Figure Page
1 COED Coal Conversion 7
2 COED Design Revised to Incorporate
Environmental Controls and to Include
Auxiliary Facilities 8
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SUMMARY
The FMC Corporation's COED coal conversion process has been
reviewed from the standpoint of its potential for affecting the environment.
The quantities of solid, liquid and gaseous effluents have been estimated,
where possible, as well as the thermal efficiency of the process. A
number of possible process modifications or alternatives have been proposed
and new technology needs have been cited, with the main objective the
lessening of adverse environmental impact.
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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, kg/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
0.55552
0.028317
0.30480
0.0037854
2.5400
0.45359
1.8001
0.45359
0.070307
0.90719
0.90719
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INTRODUCTION
Along with improved control of air and water pollution, the
country is faced with urgent needs for energy sources. To improve the
energy situation, intensive efforts are under way to upgrade coal, the
most plentiful domestic fuel, to liquid and gaseous fuels which give less
pollution. Other processes are intended to convert liquid fuels to gas.
A few of the coal gasification processes are already commerically proven,
and several others are being developed in large pilot plants. These pro-
grams are extensive and will cost millions of dollars, but this is war-
ranted by the projected high cost for commercial gasification plants and.
the wide application expected in order to meet national needs. Coal con-
version is faced with potential pollution problems that are common to
coal-burning electric utility power plants in addition to pollution pro-
blems peculiar to the conversion process. It is thus important to examine
the alternate conversion processes from the standpoint of pollution and
thermal efficiencies and these should be compared with direct coal utili-
zation when applicable. This type of examination is needed well before
plans are initiated for commercial applications. Therefore, the Environ-
mental Protection Agency arranged for such a study to be made by Exxon
(formerly Esso) Research & Engineering Company under contract EPA-68-02-0629,
using all available non-proprietary information.
The present study, under the contract, involves preliminary
design work to assure the processes are free from pollution where pollution
abatement techniques are available, to determine the overall efficiency of
the processes and to point out areas where present technology and informa-
tion are not available to assure that the processes are non-polluting.
All significant input streams to the processes must be defined,
as well as all effluents and their compositions. This requires complete
mass and energy balances to define all gas, liquid, and solid streams.
With this information, facilities for control of pollution can be examined
and modified as required to meet Environmental Protection Agency objectives.
Thermal efficiency is also calculated, since it indicates the amount of
waste heat that must be rejected to ambient air and water and is related to
the total pollution necessary to produce a given quantity of clean fuel.
Alternatively, it is a way of estimating the amount of raw fuel resources
that is consumed in making the relatively pollution-free fuel. At this
time of energy shortage this is an important consideration. Suggestions
are included concerning technology gaps that exist for techniques to
control pollution or conserve energy. Maximum use was made of the
literature and information available from developers. Visits with some
of the developers were made, when it appeared warranted, to develop and
update published information. Not included in this study are such
areas as cost, economics, operability, etc. Coal mining and general
offsite facilities are not within the scope of this study.
Considerable assistance was received in making this study, and
we wish to acknowledge the help and information furnished by EPA and
FMC Corporation.
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1. PROCESS - GENERAL
1 -1 Process History
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 (1-12). Bench-scale experiments led the way to design
and construction in 1965 of a process development unit (PDU) employing
multi-stage fluidized-bed pyrolysis to process 50-100 pounds of coal
per hour (1,13). Work with the PDU was extended to other coals in
1966, and hydrotreating ot COED oil from the PDU was studied by Atlantic
Richfield Company (2). 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.
In a second contract phase, additional coals were processed
and COED economics were updated to 1970 (3). The COED char desulfurization
effort vas concluded with a recommendation to explore char gasification
alternatively (4). And a COED pilot-plant processing 36 TPD of coal
and able to hydrotreat 30 BPD of oil was designed and constructed in
1970 (5).
The pilot plant was operated successfully on a number of
coals under terms of a third contract (6) in 1971-72. This contract
phase also extended oil filtration studies on a rotary pressure
filter; and an oil absorber tower was designed to replace the aqueous
condensation system in the product recovery train. The oil absorption
system was intended to reduce or eliminate the filtration of pyrolysis
oil. The system was being installed in June, 1972.
The American Oil Company prepared an independent economic
evaluation of the COED process in 1972 (7). In this case, char was to
be gasified using the Kellogg molten salt process at low pressure
in order to conserve the sensible heat of hot char.
Development of the COED process is continuing, with major
funding provided by OCR (14). The character of the process has
changed in the course of development, and, even now, it is difficult
to characterize it completely. This is due largely to the process
variants which may be applied to treat product char, which may represent
50-60 weight percent of the coal fed to the process, and to the possible
variants relating to gas treatment and to the supply of fuel to the
process. What has remained constant in the development is the use of
multi-staged fluidized beds operated at low pressure and at successively
higher temperatures to pyrolyze a variety of high-volatile bituminous
and semi-bituminous coals continuously. The achievements of the
development program in this area of fluidized bed technology, albeit
on a relatively small physical scale, are significant.
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The process basis for our evaluation is the design study
developed by FMC Corporation in 1973 for a "25,000 tpd COED plant"
(15). Process flowsheets vere developed for the pyrolysis plant,
raw oil filtration section, and for the hydrotreating facility
(Appendix Figures 1-5). A block flow diagram of these processing
sections is shown in Figure 1. This design feeds 25,512 tpd of
an Illinois No. 6-seam coal containing 5.9% moisture, 10.67, ash,
and 3.8% sulfur. 12,512 tpd of product char is recovered, along
with 3945 tpd of hydrotreated oil (24,925bpd 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.
In the vast body of information which has been published
relative to the pilot plant work (1-19) , there is very little so far
which relates to the pollution potential of the COED process. The
thrust of the work has been directed to process development,
including hardware development and yield improvements. A recent
paper (30) does summarize an integrated scheme whereby pollution
may be held to low levels. Flue-gas treatment is avoided in the
main processing sections by firing clean product gas in dryers and
heaters. Aqueous contaminated process condensates are stripped of
H2$ and NH3 with product gas and recycled to the last pyrolyzer
(or are directed to the char gasifier, if the plant includes
char gasification), where organic contaminants may be consumed.
H2S and NH3 are removed from product gas by commercial processes,
and sulfur and ammonia are sold.
The pollution potential has not been completely defined
in the context of U.S. standards even for those coal gasification
processes which have already been commercialized elsewhere. Standards
have changed radically in recent years, and new standards continue
to be promulgated by governing agencies. Coal compositions, including
sulfur and trace element contents, vary widely (52), and stream compositions
from a particular process are generally sensitive to coal composition.
Hence, although COED does produce a low-sulfur char from Utah A-seam
coal, the coal itself is sufficiently low in sulfur to permit its
use directly. Neither is the case with an Illinois No. 6-seam coal.
Future FMC research programs may be directed to a more precise
determination of stream compositions relative to contaminant levels and
to the effects of extended recycle of recovered contaminated liquors
to pyrolysis (14)•
1.2 Process Description
The COED process being developed by the FMC Corporation is
a continuous, staged fluidized-bed coal pyrolysis operating at lov
pressure, and is designed to recover liquid, gaseous, and solid fuel
components from the pyrolysis train. Heat for the pyrolysis is generated
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by the reaction of oxygen with a portion of the char in the last
pyrolysis stage, and is carried counter-currently 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 t.o 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,
so that its ultimate utilization may largely determine process viability.
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CLEAN fliobocr C,A$
1-S.TKiP CrAS")
FIGURE I - COED COAL CONVERSION (15)
(AU rates in tph)
1. Heating nedla not specified for oxygen heaters
and steam superheaters; flue gas rates depend
on fuels consumed.
2. Analysis of gas fired In hydrotreater prahoatov
not specified; combustion air requirement and
flue-gaa rate depend on fuel consumed.
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FIGURE 2 - COED DESIGN REVISED TO
INCORPORATE ENVIRONMENTAL
CONTROLS AND TO INCLUDE
AUXILIARY FACILITIES.
(See Table 1 for Stream Identification)
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Table 1
Stream Identifications for Revised COED Process
{Stream Numbers Refer to Figure 2. See text for details)
Coal Preparation
1. Influence of weather (wind, temperature, humidity) on 40-50
acre on-site coal storage piles.
2. Dusting and wind losses; possible odor.
3. Precipitation on 40-50 acre storage area.
4. Storm run-off estimated at 10,000 gpm contains particulates
and may be sulfidic. Directed to oily-water retention
ponds along with run-off from processing areas for subsequent
addition to waste water treatment system.
5. 1237 tph Illinois No. 6 seam coal, 14 percent moisture.
Coal Grinding
6. Approximately 455 MM Btu per hour input to dry coal (from
14 to 5.9 percent moisture). Boiler flue-gas stream may supply
part of requirement.
7. 108 tph water removed from coal. Vent gas stream issuing
through bag filters may require treatment to limit CO
content.
8. 66 tph coal fines, 4 percent moisture, issues as fuel product.
9. 1063 tph sized coal, 5.9 percent moisture.
Coal Dryer and Stage 1 Pyrolysis
10. 366 tph purge gas requires treatment to limit CO content,
directed to boiler stack.
11. 22 tph oily wet char fines separated at fines filter
directed to coal feed.
12. 93-5 tph aqueous condensate. 83.3 tph directed to last
pyrolyzer, 10.2 tph directed to water treatment.
Stage 2,3,4 Pyrolysis
13. 156.5 tph oxygen from oxygen plant.
14. 337 tph recycled process liquors as steam to last pyrolyaer.
15. 521 tph product char stream.
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Table 1 (Cont'd)
Stream Identifications for Revised COED Process
(Stream Numbers Refer to Figure 2. See text for details)
16. 530 gpm BFW to fluidized bed char cooler and 360 gpm BFW to
char after.cooler.
17. 265,000 Ib/hr 600 psia steam and 180,000 Ib/hr 150 psia steam
from char cooling.
Product Recovery
18. 512.7 tph product gas to acid-gas removal system.
19. 236.7 tph aqueous condensate recycled to last pyrolyzer.
COED Oil Filtration
20. 1.5 tph (equivalent) filter aid supplied during filter
precoat cycle; basecoat may also be used.
21. 0.5 tph nitrogen from oxygen plant filter pressurizing
medium.
22. 0.5 tph purge gas directed to incinerator or boiler
stack.
23. 15.2 tph oily char fines removed at filters containing
1.5 tph filter aid, recycled to coal feed.
Hydrotreating
24. 28.4 tph hydrogen make-up stream from hydrogen plant.
25. 29 tph bleed gas stream directed to clean-up and hydrogen
plant for reprocessing.
26. 103 tph clean product gas used as stripping medium.
27. 107 tph contaminated gas directed to acid-gas removal
system.
28. 0.04 tph reactor coke directed to product char pile.
Spent catalysts require special treatment.
29. 16.6 tph contaminated aqueous condensate directed to
last pyrolyzer.
30. 164.4 tph syncrude product.
Oxygen Plant
31. 440 MM scfd air intake.
32. 340 MM scfd nitrogen and other air constituents.
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Table 1 (Cont'd)
Stream Identifications for Revised COED Process
(Stream Numbers Refer to Figure 2. See text for details')
33. 156.5 tph oxygen to pyrolysis.
34. 17 gpm water condensate from inter-coolers directed to
boiler feedwater treatment.
Acid-Gas Removal
35. 512.7 tph product gas from pyrolysis.
36. 381,000 Ib/hr 150 psig steam to regenerators.
37. 300 tph C02 and 14.4 tph H-S directed to sulfur plant.
38. Spent Benfield solution and/or blowdown requires special
treatment.
Sulfur Plant
39- 23 tph H2S in incoming acid-gas streams.
40. 0.7 MM scfd regeneration air stream to Stretford solution
in Beavon tail gas treatment.
41. Regeneration air stream directed to incinerator or to boiler
stack. Stretford solution blowdown requires special treatment.
42. 150 MM scfd C02 containing less than 200 ppm sulfur.
43. 510 tpd elemental sulfur product .
Hydrogen Plant
44. 25 tph clean product gas feed to reformers.
45. 29 tph bleed stream from hydrotreating fed to reformers
after clean-up.
46. 43 tph net water consumption in reformers (230 gpm
BFW to reformers).
47. 60 tph C02 removed from reformer effluent.
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Table 1 (Cont'd)
Stream Identifications for Revised COED Process
(Stream Numbers Refer to Figure 2. See text for details)
48. 28.4 tph product hydrogen stream to hydrotreating.
49. Spent catalysts and blowdown from acid-gas removal steps
require special treatment.
Power-Steam Generation
50. 2032 MM Btu/hr fuel equivalent (see Section 3.5.1).
51. Flue-gases require desulfurization if char is fired
to supply fuel shortfall. 6.4 tph ash generated if
char is fired; returned to mine for burial.
Cooling Water
52. Chemical additives may include chromium or zinc compounds, acids»
chlorine, phosphates, phenols, copper complexes; 9000 GPM make-up.
53. 6000 gpm water evaporated and 600 gpm drift loss.
54. 2400 gpm draw-off from cooling towers. May require
special treatment before injection into waste-water
treatment system.
Water Treatment
55. 2990 gpm total process water and 7590 gpm raw water
make-up for treatment.
56. 10,580 gpm to users.
57. Additives to system may include lime, anti-foam, acids, char
or activated carbon, oxygen or ozone and other agents.
58. Miscellaneous sludges from aeration, biox, and separation
facilities may require special treatment.
59. Control of noxious evaporative losses may require special
engineering, including floating covers on retention
ponds or tanks and/or forced draft systems.
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2. EFFLUENTS TO AIR - MAIN PROCESSING SECTIONS
All effluents to the air are shown in Figure 2 and Table 1.
These effluents are based on the FMC Corporation design (Ref. 15 and
Appendix Figures 1-5) and are to some degree inferred by analogy
•with prior art.
2.1 Coal Preparation and Storage
Common to all fuel coal usage, and particularly to coal
conversion processes, are the operations of coal mining, which may
include coal laundering, drying, and screening, coal transport, and
storage. This study does not include energy and/or pollution con-
siderations relative to these operations.
On-site coal storage will be required for all conversion
plants to provide back-up for continuous conversion operations. For
thirty days storage, there might be eight piles, each about 200 feet
wide, 20 feet high, and 1000 feet long. Containment of air-borne 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
and 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, although, obviously,
the coal dryer proper may be arranged to remove a larger fraction of
the original moisture.
We note that Illinois No. 6 coal is currently being supplied
with about 17 percent moisture, but that this moisture content is a
function of the operation of laundering equipment. In a commercial
conversion plant situated at the mine, closer control of the delivered
moisture would be possible, but with corresponding increase in energy
consumption.
We note also that the reactivity of coals may be markedly affected
by exposure to air, and that water serves to seal available pore volume, retarding
oxidation. Hence the desired moisture content may be related to the average
time-in-storage in a particular facility.
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2.2 Coal Grinding
We have assumed that free moisture would be removed from feed
coal by milling in a stream of hot combustion gases, as is practiced in
the FMC pilot plant (5). Coal sized 16 Tyler mesh or smaller, but with
minimum fines, is required for the pilot pl?mt, although other studies
(7) have indicated that particles up to 1/8 inch or 6-mesh may be suitable.
In either case, the mechanical size reduction of an Illinois coal is expected
to generate a considerable quantity of -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 and on the acceptable size
range, screening or separation efficiencies, and the recycle rates employed
around the mill. Some small fraction of these fines will pass through the
system with the sized coal. Additional fines will be produced in the coal
dryer proper, and the ultimate consideration is that the total fines fed
to the dryer or to the first pyrolyzer shall not overload the cyclone systems
provided to effect their separation from the respective effluent streams.
There may also be a relationship between the coal size fed to the
system and the observable filter rates on raw pyrolysis oil. The fineness
of char particles in Illinois No. 6-seam oils apparently contributed to
blinding of the filter precoat in the pilot-plant filter (6). We have,
therefore, assumed that 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.
We have assumed that clean product gas is fired in the mill
heater (the basis indicates that natural gas is used; see Section 5).
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.
Depending on water-use constraints, it may be desirable to
condense water from the vent gas for reuse. This stream could be combined
with, or treated similarly to, gas issuing from the coal drying and
first-stage pyrolysis section, wherein the gas is scrubbed in venturi
scrubber-coolers. The additional cooling requirement would be about
equal to that provided in the design basis for treating vent gas from
that section. It is presumed, however, that the additional coal fines
separated from scrubber effluent by filtration in this way could not
be recycled to the pyrolyzer, and would issue from the system as sludge.
This sludge, containing 50 percent water, would preferentially be
charged along with char to gasification, if char gasification is included,
or might be combusted with char in a char boiler. However, the dry
separation system employing bag filters would be preferred in the latter
case.
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Vent gas which issues from the bag filters from the milling
circuit may contain a significant carbon monoxide concentration, depending
on the combustion parameters employed in the mill. It may be necessary
to direct the stream to a boiler stack or incinerator to complete
the combustion. Another possibility is to employ a noble-metal catalytic
afterburner (29), which would minimize the additional fuel requirement,
to neutralize the stream.
2.3 Coal Drying and First Stage Pyrolysis
In FMC's design, clean natural gas is burned sub-stoichiometrically
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 one
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 stack(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 represents a
loss of combustible eruiv^lent to pbout 230 MM Btu/hr. It is indicated
to be sulfur-free (6, 14).
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- 16 -
2.4 Stages 2.3,4 Pyrolvsis
Coal which has undergone first-stage pyrolysis (at temperatures
of about 550-600°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 counter-currently through the
cascade, serving also as the primary fluidizing 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.
The FMC design indicates that char will be further cooled by cold-
water exchange in unspecified equipment. In the pilot plant, a two-pass
screw conveyor, in which cooling water is supplied to a hollow screw, as veil
PS to the jackets of both flights, is used to cool char to about 100°F.
About 180,000 Ib/hr of 150 psia steam may be generated in the commercial
operation if suitable equipment can be designed.
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 gas is required, along with
about 105 tons of air per hour. The combustion products should be
dischargeable directly in this case without further treatment.
2.5 Product Recovery System
Gas from the pyrolysis section is cooled and washed in two cascaded
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
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- 17 -
droplets, and is then cooled to 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 are
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 take-offs from the dehydrators, vent
flow should be minimal.
2.6 COEDJ)il Filtration
FMC has designed a filtration plant to handle the COED raw oil
output based on filtration rates demonstrated in its pilot plant (5,6).
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 make-up, is directed to an incinerator. 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 (14). Filtered
oil is directed to the hydrotreating facility.
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- 18 -
2.7 Hydrotreating
Hydrotreating is employed to upgrade the heavy pyrolysis oil
through the addition of hydrogen, vhich 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 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 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
catalyst 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 H£S 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.
The process basis includes a large cooling requirement
for hydrotreating effluent, even though preheating is supplied to hydro-
treating feed. The developers (14) have indicated that heat integration
should be possible in a commercial installation to some degree. The
concern involves possible degradation of raw oil feed in a heating
system which is not precisely controlled. We have assumed that
380,000 Ib/hr of 600 psia steam will be generated in this cooler.
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- 19 -
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. A major unresolved
process question relates to the catalyst life that may be expected in
commercial operation. Pilot plant results show that activity drops after
300-500 Ib oil/lb catalyst, but pilot-plant conditions are considered
more rigorous than should be the steady-state condition of the commercial
unit.
Since high-temperatures are required generally for the regeneration.
of the cobalt molybdenum or nickel/tungsten sulfide catalysts used, 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 shut-downs. It is not clear, however,
whether Lwo vessels provided are required to treat the total stream, or
whether one represents stand-by capacity. Presumably some standby capacity
will be required to permit catalyst changeout in the event of sudden activity
loss or development of high pressure drop.
Provisions for depressuring and inerting the hydrotreater preliminary
to catalyst removal should not result in emissions to atmosphere, since
gaseous effluents may be recycled to the hydrogen plant gas treatment section,
or to the main gas-treating section. Ammonium sulfide, which is produced
in the hydrotreater, and which is stable at reaction conditions, decomposes
at low temperatures and pressure to release additional ammonia and H£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. Catalyst
presulfiding may also produce gas which must be treated, although it is
not yet certain whether and to what degree presulfiding improves catalytic
activity. 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. Presumably, more than one of these reactors
will be provided for each hydrotreater to permit coke removal and bed
replacement on the run.
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- 20 -
3. EFFLUENTS TO AIR - AUXILIARY FACILITIES
We have elected in this study to treat the main conversion
streams separately from all other facilities, which f>re thereby defined
as auxiliary facilities. The functions of these auxiliary facilities
are nonetheless required by the process, and, for economic and/or
ecologic reasons, would be constructed along with the conversion
system in an integrated plant. These effluent streams are also shown
in Figure 2, and streams are identified in Table 1.
3.1 Oxygen Plant
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, 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.
3.2 Acid Gas Removal
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 (30).
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, although this stream
contains ammonia, and 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. Hence COS, if it is present, is hydrolyzed in the
Benfield hot carbonate system to H£S (31). Similarly, mercaptans
disulfides, and thiophenes are indicated to be largely removed in
commercial installations. FMC has not reported on the quantity and
nature of the sulfurous contaminants in raw gas. COS has been found in
some streams (14), and additional work is planned to quantify this and
other trace constituents in COED streams.
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- 21 -
Choice of process will, of course, also depend on installation
and operating costs, as well as on the ease of integration into the total
facility (32, 33). Most purveyors of proprietary processes can tailor
their designs to accommodate particular conditions and requirements.
Moreover, leading processes are being continuously refined and developed.
We have elected to use the "Benfield" hot potassium carbonate
system in our basis. This method for removing C02 and H2S from process
gas streams was studied at the Bureau of Mines (34, 35, 36). In the
Benfield system, gas absorption takes place in a concentrated aqueous
solution of potassium carbonate which is maintained at above the atmos-
pheric 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. The actual pressure level that will
be employed will be a trade-off between compression costs and the
utilities consumptions required otherwise. Based on the concentration of
acid gases present in raw gas, a total scrubbing pressure between 100 and
200 psia is indicated, whether an amine or hot carbonate system is employed.
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 and as cooling water will be required to treat the
stripping gas stream.
Clean gas may be directed to the various fired heaters throughout
the plant, and to the utility boiler (see below). Product gas loss into
the regenerator off-gas stream can be held to less than 0.1 percent in
proprietary configurations of the process. Moreover, it is possible to
selectively remove H£S, if this is required to produce a suitable feed
for a Glaus sulfur plant. There should be no discharge to the atmosphere
from the acid gas removal section.
3.3 Hydrogen Plant
The COED process gas product is indicated to be the source of
hydrogen for the hydrotreating of raw COED oil. Steam reforming,
cryogenic separation, and partial oxidation were investigated by Chemical
Construction Company (5) as means for recovering the required hydrogen
from process gas. The type of hydrogen plant that may ultimately be used
will be a function of the location of the plant (or of the coal type being
processed) and of the product sales slate, as well as of the size of the
installation. For our design, we have assumed the steam reforming case as
outlined by FMC.
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- 22 -
COED process gas at 15 psia is compressed to 410 psip and
ppssed 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)
C02 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 ^ CE^ + 1^0. Resulting product
gas is available at 200 psig.
The bleed gas from the hydrotreating plant, containing about
2 percent I^S 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.
About 9.4 tph of hydrogen is indicated to be consumed in hydro-
treating 185 tph of raw oil (about 3000 ft3/bbl). It is of course not
required that initial acid gas removal be included in the hydrogen plant
if acid gas removal is otherwise provided for the total product gas
stream. Moreover, gas from the cleaning operation would be available at
pressure, so that compression is required only from that pressure level.
About a third of the hydrogen requirement can be generated from excess
CO and hydrocarbons present in the hydrotreating bleed stream. About
25 tph of clean product gas would be required additionally to be fed
to the unit, and about 43 tph of water would be consumed in the reformer.
If a hydrogen plant design as described is employed, it should
be possible to recover energy from the expansion of the hydrotreating
bleed gas through use of turboexpanders or equivalent facilities to
offset the energy required for recompression to the level required in
the hydrogen 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.
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- 23 -
3.4 Sulfur Plant
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 H^S streams may
result from treatment of sour water and stripping gas- FMC has indicated
that high-sulfur Illinois coals will yield H£S levels in the range of
10-20 percent (30).
We have assumed that acid gas will be sufficiently high in
H2S content to permit use of a Glaus recovery system. We note that,
depending on the acid gas removal process employed, I^S may be
preferentially absorbed to increase its concentration in off-gas fed
to the sulfur plant. Glaus units are operated commercially with enter-
ing H2S concentrations as low as 6 percent. But these systems generally
employ oxygen, so that some of the cost advantage relative to a process
like Stretford, which does effectively treat low concentrations, may
dissipate.
Tail gas from the Glaus unit must be desulfurized, however.
Several processes have been developed for this purpose. FMC indicates
that the Beavon or Shell Glaus Off-Gas Treating (SCOT) process may be
employed (30). It may also be feasible to employ one of the flue-gas
desulfurization variants using limestone to scrub tail gas (37-40), or
processes such as the Wellman-Lord S02 Recovery Process (41) or the IFP
Secondary Recovery Process (42) may be applied.
Most proprietary tail-gas treatment processes operate to convert
S02 to H2S, which may then be selectively removed. The Beavon system
catalytically hydrogenates the SC>2 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 I^S 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.
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- 24 -
3.5 Utilities
3.5.1 Power and Steam Generation
The choice of fuel for the generation of the auxiliary electric
power and steam required by coal gasification plants markedly affects
the overall process thermal efficiency. It is generally least efficient
to burn the clean product gas for this purpose. On the other hand,
investment in power-plant facilities, including those required to handle
the fuel and to treat the flue gas, is generally least when product
gas is so used.
COED conversion generates a carbon-containing char equivalent
to some 50-60 weight percent of the coal fed to pyrolysis. Since this
is considered a fuel product, it would appear that it should be so
used in the plant proper. However, it suffers as an acceptable fuel in
this case to about the same extent as does the feed coal, in that its
sulfur content is observed to be about the same as that of feed coal.
Table 2 lists the analyses of chars obtained by FMC from a low-sulfur
western coal and from a high-sulfur Illinois coal.
For a high-sulfur coal feed such as an Illinois-No. 6 seam,
combustion of the char produced will generate S02 flue-gas levels above
permissible discharge limitations, such that some form of flue-gas
treatment must be employed.
The char obtained from COED is also a more refractory material
than feed coal. Char from Utah A-seam coal (a low-sulfur Western coal
which can be directly combusted without recourse to sulfur controls), when
pulverized, has much the same combustion characteristics as some Pennsylvania
anthracites, and has been satisfactorily combusted in an anthracite boiler (43)
Its low sulfur content and lower grinding power requirements would in fact
command a premium over some anthracite coals.
Experience with the large-scale combustion of chars is other-
wise limited. The Bureau of Mines has reported on one investigation (44)
utilizing a specially-constructed dry bottom unit designed to simulate
the performance of an industrial steam-generating furnace. In general, it
was found that volatile matter content in excess of 20 percent was necessary
for combustion of chars in this apparatus in the absence of a more volatile
supplemental fuel (natural gas was used as supplemental fuel). Carbon
combustion efficiency was likewise found to be a function of the volatile
matter content of char, ranging from 94 to 99 percent for volatile contents
from 5 to 15 percent. More supplemental fuel was required for the least
volatile chars to maintain flame stability.
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TABLE 2
PROPERTIES OF CHAR PRODUCT (30)
Utah
111. No. 6
Proximate Analysis,
wt %s dry
Volatile Matter
Fixed Carbon
Ash
Ultimate Analysis,
wt %, dry
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Ash
Chlorine
Iron*
Higher Heating Value, Btu/lb. dry
* Included in "ash" above
6.1
80.2
13.7
2.7
77.0
20.3
81.5
1.3
1.5
0.5
1.5
13.7
0.006
0.28
12310
73-4
0.8
1.0
3-4
1.0
20.3
0.1
11040
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- 26 -
Hence, it may be assumed that combustion of COED chars will
be possible in conventional fireboxes if clean product gas is used as supple-
mental fuel. This alternative might be preferred then on the basis of
carrying the least developmental debits, and because it may be
possible to adjust S02 concentration in flue gas such that subsequent
flue gas treatment may be avoided. It has the disadvantage of adversely
affecting overall thermal efficiency.
A further study by the Bureau of Mines (45) in the same dry-
bottom unit has shown that a COED char derived from Illinois No. 6-
seam coal and containing 5 percent volatile matter could be successfully
fired without supplementary fuel if the char-primary combustion air
mixture were preheated to 450-500° F. It was estimated that the heat
required to raise the mixture from 100° to 450°F was equivalent to about
2 percent of the heating value of the char, whereas natural gas equivalent
to 15 percent of the total thermal input would be required to stabilize
combustion in the absence of preheat.
Ideally, the sensible heat of hot char discharged at the
fluidized-bed char cooler-steam generator would be conserved in any
subsequent char treatment process. Both the anthracite boiler test
referred to above and the Bureau of Mines work employed chars which had
been ground to pass 90-95 percent through 200 mesh screens. In the Bureau's
work, at least,some slight decrease of combustion efficiency and increase
in supplementary fuel requirement was noted when the degree of pulverization
was decreased from 95 to 90 percent through 200 mesh.
Conventional grinding equipment installed on coal-fired boilers
is generally designed to handle coal at less than 300°F. However, commercial
equipment is available which can operate at higher temperatures, up to
about 500°F. A system might be devised to heat air (by exchange with
800°F hot product char) that would be used as primary combustion air in
the boiler. Or equipment may be designed to generate steam if char
must be cooled for grinding.
The particular COED char employed in the Bureau's tests, although
derived from an Illinois No. 6 coal, had a volatile matter content of
5.0 percent, or about double the level reported most recently by FMC
(see Table 2) for char product from Illinois coal. Additional
supplementary fuel or higher preheat temperatures may be required as the
volatile content of char decreases.
Hence it is considered that equipment can be developed or modified
to combust COED char at carbon combustion efficiencies above 95 percent,
and that a large fraction of the sensible heat of product char may be
conserved if the combustion is performed onsite, or at the point of production.
There would, of course, be energy debits associated with the treatment
of stack gases or with the use of specialized combustion systems, as by
combustion in the presence of limestone in fluidized beds (48), to control
sulfur emissions. And combustion of all of the char might support a 1200 MW
generating station in this case.
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A Viable alternative to char combustion is its gasification,
in which case sulfur recovery and water treatment are simplified and
all fuel products produced are clean. Of course, facilities required
to gasify char will add considerably to facilities provided otherwise,
including acid gas removal systems, sulfur plant, and possible gas
conversion facilities and/or oxygen plant.
A variety of proprietary processes have been considered for
the gasification of COED chars, including the Koppers-Totzek process (46)
and the COGAS system (47) under development by FMC. The Koppers process
employs oxygen in a low-pressure, high-temperature gasifier to avoid
nitrogen dilution of product gas, whereas COGAS maintains flue gases
from the air combustion of char (which supplies heat to the gasifier)
separate from the gasifier output. A number of other processes (49,50)
may also be applicable.
All such processes, including processes used to upgrade gasifier
output, involve thermal debits, however, such that there would be incentive
on this basis only to produce a clean fuel at the lowest thermal cost.
In a real situation, the product must be tailored to the consumer, so
that economic and ecologic credits may outweigh the thermal losses.
We have in this study considered that dirty fuels would not
be combusted in the plant, so that clean product gas would be used also
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, so that the net available gas for fuel is 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 lb/hr,
equivalent to a 1130 MM Btu/hr fuel requirement (See Table 10). 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,4874 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 per the
Bureau of Mines work cited above. 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,
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- 28 -
the sulfur emission would be such that flue-gas treatment would still be
required. About 2.1 tph of S02 would be emitted, equivalent to about
2.0 Ib/MM Btu, or above the level permitted by current standards for
solid fuels.
Flue-gas treatment might be avoided if char were combusted
with product gas throughout the plant. This would require additional
investment in char handling and grinding equipment, as well as particulate
control on all fired heaters and ash handling and disposal facilities,
and may be less attractive than installation of flue-gas treating
facilities on the main boiler. A variety of flue gas treatment processes
for particulate and SO control are under development (67,68), and significant
progress in this area may be expected by the time a commercial plant is
constructed.
We note also that the coal fines estimated to be produced in
the coal grinding operation could supply the fuel shortfall. This
alternative may be attractive in a commercial facility because there
would be no additional grinding debit and because the fines production
might be entirely consumed. However, such coal fines may command a
higher premium as a saleable fuel than char, and it may be preferred
to charge the coal fines to char gasification, dependi-ng on the system used
for that purpose.
We have assumed for the purpose of thermal efficiency calculations
that char will be combusted in the plant to make-up the fuel shortfall,
and have not debited the process for flue-gas treatment. We recognize
that char treatment (gasification) is practically required in a
commercial design, and the effect of using char-derived gas for fuel is
discussed in Section 5.
3.5.2 Cooling Water
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 wet 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 tower, 600 gpm is lost
as drift, and 2400 gpm is withdrawn as blowdown, and is directed to the
water treatment facility.
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We have not included the cooling requirement to condense water
from the coal grinding effluent gas stream. If water availability is
constrained, this may be attractive. The plant water balance is shown
in Table 11.
It is probable that environmental considerations and the
costs of water reclamation will operate to restrict industrial water
consumption in most domestic locations. Hence a commercial design might
maximize use of air-cooled heat exchangers, reserving the use of cold
water only for "trim-cooling" or low-level heat transfer applications.
The overall economic balance will consider added investments in heat-
exchange and electrical hardware associated with air-fin usage, as
well as investment in incremental electrical generation capacity. Running
costs for the generation of power and for equipment operation would be
balanced against the net reduction in water treatment and pumping costs,
as well as the net reduction in water loss.
On the basis that half of the requirement may be displaced
with forced draft air-cooled heat exchangers, the incremental electrical
power requirement is estimated to amount to 26,000 KW. Added cooling
water requirement associated with the incremental power generation would
bring the net total cooling water requirement to an estimated 100,000 gpm,
so that water loss by evaporation might be reduced to about 3025 gpm at the
cooling towers. Drift loss would amount to 300 gpm on this basis. Blow-
down, or draw-off from the system, might be held to 1200 gpm. There would
be a reduction in the power requirement for pumping cooling water. On
the other hand, direct discharge of heat to the air environment in certain
locations may be less desirable than the humidification associated with
cooling towers.
The physical environmental situation at a particular site,
including water availability, climatic conditions, and available area,
will set limits on the designer's options for heat rejection. Other
means, such as cooling ponds, may be practicable. In very special situations,
it may prove economic to recover some of the low-level heat, as by circulation
in central heating systems to nearby communities or in trade-off situations
with irrigation water supplies, where hot water may be used to extend growing
seasons. In all situations, the sociological impact of the use of the
environment will be an over-riding factor.
3.5.3 Water Treatment
Analyses of the aqueous condensates produced in the pyrolysis
and hydrotreating plants have not been specified in the FMC design.
Some characteristics of these streams have been recently reported by
FMC (See Table 3). FMC has also 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.
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Table 3
Properties of Process Liquors (30)
Cos! Illinois No. 6
First Stage Pyrolysis Liquor
weight percent
Orbon
Nitrogen 0.05
Sulfur 0.07
Phenol 0.00
Entrained Oil
Suspended Solids 0.49
pH 3.6
Second Stage Pyrolysis Liquor
Carbon
Nitrogen 0.93
Sulfur 0.18
Phenol 0.38
Entrained Oil 0.0-0.5
Suspended Solids 1.09
pH 8.8
Hydrotreating Liquor
Carbon 0.8
Nitrogen 5.0
Sulfur 8.7
pH 9.3
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Recycle to a high-temperature char gasification system should
present no difficulty (46) . 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 "by-pass" through the
fluidized bed system. Demonstration of such long-term recycle, however,
would considerably reduce investment in treatment facilities. The
question may be largely academic, however, because it would appear
that a large-scale installation, unless it were arranged to combust
char onsite or in an adjacent facility, 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 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 run-offs and for flow equalization within
the system will be required. Run-off from the paved process area could
easily exceed 15,000 gpm during rainstorms. Run-off from the unpaved
process and storage areas could exceed 80,000 gpm in a maximum one-
hour period.
Pretreatment facilities will include sour water stripping
for chemical effluents and Itnhoff 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-media filtration, or chemical
flocculation units.
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.
We consider that the COED plant may be able to take advantage
of the properties of char and of attractive incremental costs for oxygen
to assist its waste water treatment. Hence, the char produced by the
process may have some of the attributes of activated carbon (63), which
has been shown to be effective in the removal of a wide variety of the
water contaminants expected (64).
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Similarly, oxidation of contaminants in water using oxygen,
and especially ozone, is normally reserved for polishing drinking water
supplies because of high costs. Direct oxidation, however, is very
effective in reducing phenol, cyanide and thiocyanate levels in waste
water (65), and has particular advantage in that solids concentrations
are not thereby increased.
Evaporation will of course occur throughout this system, and
the concern of the designers will be to limit the co-evolution of noxious
or undesirable components which may be present. We note that it may
be necessary to cover portions of the water-treatment 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.
3.5.4 Miscellaneous Facilities
Provisions for start-up of the COED facility may generate
short-term effluents to the atmosphere. Reverse flow from the gas
product delivery line may be practicable for fuel supply, or a pressurized
gas storage facility might be provided on site.
Planned noise reduction, especially in coal handling, grinding,
and charging operations, venting, and in the operation of large compressors
and pumps, will be a requirement.
Operation of a blow down system and flare stack to which
accidental or emergency process releases may be directed will normally
produce a small emission to the atmosphere. We note that future
effluent limitations may restrict all emergency hydrocarbon emissions,
in which case the emergency flare system must be sized to handle the
entire gas output.
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4. LIQUID AND SOLID EFFLUENTS
Solid and liquid effluents based on our design are also shown
in Figure 2 and Table 1.
4.1 Coal Preparation
On-site coal storage will require that facilities for con-
taining storm run-off be provided. Hence, run-off from the 40-50 acre
area required to hold a thirty-day supply of feed coal could easily
amount to 10,000 gpm during a major precipitation event common to
almost all sections of the United States. Such run-off may be expected
to contain acidic particulate matter from most contemplated feed coals.
It is assumed minimally that effluent limitation guidelines
published by EPA for the coal mining industry under the Refuse Act
Permit Program (58) will apply to such coal storage facility. The
application of 'best practicable control technology1 would require
installation of impounding and settling facilities to be of sufficient
size to handle run-off resulting from a once-in-ten-years' storm, and
the operator would provide suitable recording analytical equipment,
including a recording rain gauge, to guarantee compliance with con-
centration schedules for discharges into waterways.
Since permissible concentration schedules are such that
impounded water will, after treatment, be of sufficient purity to be
admitted to the plant's water system, it will be advantageous to plan
for such use in the initial design. Similarly, run-off from the pyrolysis
complex otherwise will have to be contained. More than one set of
water treatment facilities will be required to handle the various water
streams coming from and going to the plant. Depending on the severity
of contamination that may be expected from the various processing areas,
storm run-off from such areas would be directed to segregated holding
facilities consistent with the expected water quality (See Section 3.5.3).
It may be necessary to provide an impermeable subsurface barrier under
certain portions of the facility, as the coal storage area, to prevent
contamination of ground water.
Although not necessarily considered a part of the conversion
facility, the coal mining operation, if it be located adjacent to the
gasification complex, would probably share treatment facilities provided
for the plant proper. Hence, typical acid mine drainage, of perhaps
300-400 gpm (59), might be treated continuously by accepted techniques
(60,61), to produce water suitable for discharge or for plant use.
Except for a separate initial holding pond and small lime addition
facility, all other components of the treatment facility would amount
to incremental increases on facilities which must be provided the parent
plant.
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If coal laundering is practiced, facilities for retention
and disposition of liquid and solid effluents become more complex.
Combinations of screening and thickening devices will generate streams
of varying solids content, some of which would be considered refuse,
and have to be returned to the mine or be buried otherwise. A properly
designed system would minimize make-up water requirement by internal
treatment and recirculation of wash water. A facility to launder feed
coal for this design might circulate 3700 gpm of wash water, and dis-
charge 3000 gpm along with thickened refuse. Such refuse would be
impounded in clarifying basins, where evaporative loss would occur.
Make-up requirements would then be held to such evaporative loss and
to an estimated 500-700 gpm lost via the laundered coal product.
4.2 Coal Grinding
The fines generated in the coal grinding operation, amounting
to 5 percent of the coal fed, issues as a separate fuel product. This
material would be preferentially charged to the char gasification system,
if this operation is included. Alternatively, it could be burned as
fuel within the plant in combination with clean product gas.
4.3 Coal Drying and First-Stage Pyrolysis
The only major liquid effluents from this section are the
aqueous streams purged from the scrubber circuit and resulting from
the filtration of fines from the scrubber liquor. These combined
streams, totalling some 93.5 tph, are indicated in the FMC basis to
be directed to the last pyrolysis stage. An analysis of this stream
has been recently reported (30), and is shown in Table 3 . it will
presumably require clarification and pH adjustment if it is not consumed
directly in pyrolysis or char gasification. Alternatively, it could
serve to scrub ammonia from hydrotreating bleed gas, and could then
be directed to waste water treatment.
The fines filtered from the scrubbing circuit are contaminated
with oil or tar. This stream, amounting to 22 tph, is indicated to be
recycled to coal feed.
4.4 Stages 2,3,4 Pyrolysis
The only major solid effluent from this section is the char
product, amounting to 521 tph. Depending on the system used to cool
char, or to recover its sensible heat, additional streams may be
generated.
4.5 Product Recovery
The major liquid effluent from this section is the waste
liquor purge from the scrubbing circuit, amounting to 237 tph. The
analysis of this stream has also been reported by FMC (see Table 3).
It, too, is indicated to be preferentially returned to the last pyrolysis
stage, or to char gasification if included.
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We have considered that conditions in pyrolysis may not be
sufficiently severe to consume the expected contaminants. However,
the indicated utility requirement for treatment of the combined liquor
streams, as by the application of a process such as the Chevron WWT
process (62), is very large, so that we have not included such treat-
ment in our design. FMC may develop more definitive information
regarding such recycle (14). FMC has, however, indicated that a water
treatment facility may be required to handle process upsets in any
event (30) .
4.6 COED Oil Filtration
The major effluent from the filtration plant is the filter
cake, indicated to contain about 1.5 tph of filter aid, 5.8 tph of
raw oil and 7.9 tph of char fines. This stream is now indicated to be
recycled to the coal feed stream. A small amount of basecoat would
also issue with this stream.
4.7 Hydrotreating
The major liquid effluent from this section is the waste
water stream separated from hydrotreater effluent, amounting to 16.6 tph.
The analysis of this stream is also shown in Table 3. FMC indicates
that it would preferentially be added to pyrolysis liquor and recycled
to the last pyrolyzer.
There is indicated to be a very small coke make in the guard
reactors, which is added to the char product.
Disposition of spent hydrotreating catalyst and catalyst or
packing from the guard reactors may require special procedures if
metal carbonyls are present (see Section 4.8.9.)
4.8 Auxiliary Facilities
4.8.1 Oxygen Plant
About 17 gpm of water will be condensed from entering air at
the oxygen facility. This water should be suitable for addition to
the plant's boiler feedwater treatment system.
4.8.2 Acid Gas Removal
Condensate streams will be generated as circulated gas is cooled
in the acid gas removal system. The disposition of these streams will
depend on their composition, but they may in general be directed to the
waste water treatment facility.
Facilities will be required to dispose of contaminated Benfield
solution,if this system is used, but the vendor now indicates that this
stream would normally be very small.
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4.8.3 Hydrogen Plant
Assuming that steam reforming will be used to generate the
hydrogen requirement, the only major liquid effluents will be the
excess water condensed from circulated gas. Such condensates,
depending on the point at which they are collected, may be quite pure
and can be directed to the boiler feedwater treatment system. Others
may require treatment to remove dissolved acid gases, and may then be directed
to the waste water treatment facility.
Periodic replacement of catalysts employed in this section
will generate solids streams whose disposition requires further study
(see Section 4.8.9).
4.8.4 Sulfur Plant
Elemental sulfur make from the Glaus unit is about 490 tpd.
An additional 15-20 tpd can be recovered from the Beavon tail gas
treatment facility. The precise quantity of sulfur produced is a
distinct function of the sulfur concentration in feed coal.
The Stretford system used to recover elemental sulfur from
hydrogenated tail gas in the Beavon process requires a small liquid bleed to
prevent build-up of thiosulfate and sulfate salts which may impair
recovery efficiency. The waste bleed is high in chemical oxygen demand,
and is generally incinerated. The COD of this waste stream may be
lowered by adding sodium as caustic. The caustic requirement in
this case is quite low.
4.8.5 Power and Steam Generation
Because clean fuel is indicated to be consumed in the power
plant, there should be no significant liquid or solid operating effluent
streams (see Section 5). Blow down from steam boilers may be included
as make-up to the cooling water system.
It is necessary to chemically clean the boiler and associated
piping before it is placed in service, and at an average interval of
2-3 years thereafter (24). 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 percent. The alkaline wastes would consist
of dilute sodium phosphate solutions (less than 1 percent). A large
amount of water would have to be used for flushing the system.
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For a boiler of this size, 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 power plants,
these wastes may be routed to settling ponds (ash basins) where they
may be diluted and neutralized prior to discharge. Alternatively,
contract chemical cleaning specialists may provide off-site disposal
services.
4.8.6 Cooling Water
A variety of chemical additives may be used to treat water
circulated in the cooling water system to control algae and corrosion.
These will appear in tower draw-offs, along with matter originally
present in make-up streams. Depending on the extent of facilities
provided to treat waste water effluents, such draw-offs may be treated
to precipitate or neutralize specific toxic elements such as chromium
or zinc before being directed to further treatment.
Heat exchangers in cooling service may require periodic
chemical cleaning, and facilities for disposition of chemical cleaning
wastes will be required (see Section 4.8.5).
4.8.7 Miscellaneous Facilities
A variety of materials may be required to treat waste
water effluents, including antifoam, phosphoric and sulfuric acids,
and char or activated carbon. In addition, water treatment may
require the use of lime-soda alums, ion exchange resins, caustic,
ferrous ion, and chlorine, among other agents. Ultimately, these
.additives exit the system as concentrated sludges, contaminated solids,
or in aqueous streams with high salt content. These effluents may
be concentrated, dried, and/or incinerated. Ultimate disposition
of the dry or concentrated residuals is uncertain, however, especially
if heavy metals, leachable salts, or organic contaminants are present.
Burial in sealed pits appears the only practicable method for disposal
of materials which must be prevented from leaching into ground or
surface water, although the logistics and economics of such techniques
requires extensive further study.
4.8.9 Maintenance
Normal plant operations will require the periodic replacement
or replenishment of catalysts and other chemical agents used to process
gas and oil. Such maintenance will generate contaminated solid and
liquid effluents, including shift catalyst, Benfield solution, activated
carbon, zinc oxide, and caustic streams. In general, spent materials
will be sulfidic. Metal value may justify specific reclamation, but
again, it would appear that the ultimate disposition of such solid
effluents is now uncertain. Incineration or thermal oxidation, as in
a fluid bed incinerator, might be used to remove hydrocarbon and
sulfur, but control of metallic particulates from such systems requires
further study, as does the disposition of residues.
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5. THERMAL EFFICIENCY
The determination of thermal efficiency is useful for providing
a basis on which to compare like processes, or to gauge incentives for
process improvements. Obviously, there are other equally important
bases on which processes may be compared, including the economic
efficiency, which may compare the total cost of a product or products,
and the ecologic efficiency, which may compare the net irreducible
pollution potential of a process. Obviously, all such comparisons must
be performed on a common, well-defined basis, and all such comparisons
are related to the technological state-of-an-art at a given point in
time.
In the case of fossil fuel conversion processes, the thermal
efficiency is calculated as the ratio of the heating value of product(s)
to the heating value of the (coal) feed,assuming that coal is the sole
source of raw material and energy. In the present design, the higher heating
value for coal feed is reported as 12,420 Btu per pound. Product gas (clean,
dry) has been estimated to have a heating value of 505 Btu per scf. Product
char has been reported to have a heating value of 11,040 to 11,700 Btu
per pound; we have used the higher value. Hydrotreated oil has been assigned
a heating value of 19,100 Btu per pound based on an indicated 25° API gravity.
The fuel shortfall (see Section 3.5.1) may be supplied by burning
product char. Assuming that 30 tph of product char is combusted in the
facility along with the produced gas to supply the estimated total plant fuel
requirement, a base thermal efficiency of 72.2 percent is indicated (see
Table 4).
However, char is not a "clean" product in this case and should
be discounted on some basis. If char were to be gasified in a Koppers-
Totzek gasifier, the estimated gas yield is equivalent to 69 percent of the
char heating value (46), so that the net overall efficiency is indicated
to be reduced to 57.8 percent on this basis. The incentive, therefore,
to develop an efficient char utilization process is very great.
In an integrated plant which includes char treatment, it should
be possible to arrange the system such that coal is dried with combustion
flue gases. There may also be economies possible in the treatment of
water and of acid gases. These effects have been estimated to amount to
the equivalent of about 600 MM Btu/hr, so that the net efficiency increases
to 60.2 percent.
The thermal efficiency of the Koppers-Totzek char gasification
process degrades significantly if product gas must be compressed for
delivery. For example, if product gas could not be utilized at 15 psig,
but had instead to be compressed to 150 psig, the Koppers-Totzek efficiency
would drop to 61 percent, i.e., some twelve percent of the product gas
equivalent would be consumed in the compression. The overall net efficiency
would be about 56 percent in this case.
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The developer prefers to consider that COED medium-Btu product
gas would not be consumed in the plant, but that the excess over that
required by the hydrogen plant would be sold (14). We have estimated a
total of 48 tph for the hydrogen plant (feed plus fuel). Assuming
that char is gasified in a Koppers-Totzek system, the char-derived low-
Btu gas would be fired in the plant's heaters and in the power plant
in this case. The revised product slate for this basis is shown in
Table 4A. (Note that all values for gas tonnages given in the process
description are referred to medium-Btu COED product gas). Any split between
medium and low-Btu gas products will be essentially thermally equivalent
if combustion efficiencies and delivery pressures are assumed identical.
There will be slight thermal and economic debits associated with the firing
and/or sale of low vs. medium-Btu gas.
The discrepancy in overall efficiency between the two product slates
(Tables 4 and 4A) is due to the assignment of full heating value for char that
is combusted to supply the fuel shortfall in the first case, without debiting
the system for S02 removal from stack gases or for imperfect char utilization.
In the second case, all char is converted to clean gas, and additional sulfur
is recovered in elemental form, but at a 69 percent efficiency based on char
feed to gasification.
The combustion of char in a system designed to limit S02 emissions may
likewise be a good candidate for further development. Although a large number
of flue-gas stack-treatment processes are undergoing active development, none
has so far emerged as the industry standard. We have accordingly not attempted
to apply the thermal debit to char combustion which may result from the
application of such treatment. Again, it may be more to the point to combust char
in a specialized facility, as in a fluidized bed in the presence of a limestone
sulfur acceptor, to generate electricity in a combined-cycle operation (48).
The proprietary COGAS development (47) may also show an improved
efficiency. This has been estimated to be 69 percent overall by the developers,
compared with the 60 percent value estimated here for the coupling of Koppers-
Totzek to COED.
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Table 4
Thermal Efficiency
Medium-Btu Product Gas Fired in Plant Heaters and Boiler
Thermal
Efficiency
Quantity Equivalent as Percent of
(tph) MM Btu/hr Pyrolysis Feed
Coal
1000
24,840
Hydrotreated Oil
* Product Char
Sulfur
164.4 6,280
491 11,505
20.8 160
25.3
46.3
0.6
Base Efficiency
72.2
Char Gasification (69% thermal
efficiency if low-Btu gas is
made available at 15 psig)
Net
-3565
-14.4
57.8
Fuel Economies in
Integrated Plant
Net
+600
+2.4
60.2
* Adjusted for char combustion to supply fuel requirements at 100 percent
char utilization.
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Table 4A
Thermal Efficiency
Char-Derived Gas Fired in Plant Heaters and Boiler
Thermal
Efficiency
Quantity Equivalent as Percent of
(tph) MM Btu/Hr Pyrolysis Feed
Coal Feed
* COED Product Gas (505 Btu/SCF
MW = 13.4)
Hydrotreated Oil
Gasifier Product Gas (318 Btu/SCF
MW = 20.9)
Sulfur
1000
123
164.4
364.3
40.0
24, 840
3,520 14.2
6,280 25.3
4,200 16.9
310 1.2
57.6
Fuel Economies in
Integrated Plant
+600
+2.4
Net
60.0
* 48 tph product gas fed to hydrogen plant as feed and fuel.
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6. SULFUR BALANCE
The sulfur balance for this design (See Table 5) suffers from
the imprecision associated with the absence of consistent specifications
for the sulfur content of feed coal, product char, oil, and liquor
streams. Moreover, it would appear that the sulfur content of gas
streams has not been completely specified, and may not be precisely
representative for the assumed sulfur concentration in feed coal other-
wise.
However, the sulfur balance, like the balances for other elements,
requires only slight adjustment in the concentrations reported for large
streams to close satisfactorily. On the other hand, the form in which
sulfur appears in gas and liquor streams may have significant impact on
the procedures and costs required to treat the streams. Only I^S has
been reported thus far, but a wide range of sulfur compounds would be
expected to appear in pyrolysis gaseous and liquor effluents (62).
Sulfur.content of Syncrude and sulfur emissions from the sulfur
plant shown in Table 5 are fairly well-defined. The sulfur content of
gas streams calculated from the FMC base design and the sulfur content
of process liquor streams reported by FMC (30) are probably in need of
adjustment to put them on a consistent basis.
Finally, a slight adjustment in the sulfur content of product
char exerts a large influence on the overall balance because of the size
of this stream. Whereas we have assumed a sulfur content for product char
of 3.2 weight percent, our balance would indicate that char would have
3-7 weight percent sulfur content. The balance reported by FMC (30)
would indicate a char sulfur content of about 3.4 percent on the same
basis.
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Table 5
Sulfur Balance (tph)
Reported Estimated
Illinois, No. 6 seam by FMC (30) Per Design
Coal (Total Input) 41.0 41.0
Syncrude 0.2 0.2
Elemental Sulfur 22.4 20.8
S02 Emissions (1) 0.1 0.1
Char (to gasifier) 18.3 19.9
(1) From sulfur-recovery plants. Sulfur emission may be mostly
in the form of carbonyl sulfide if. Beavon tail-gas treatment
is used. This balance assumes no sulfur emission in the purge
gas stream from Stage 1 pyrolysis and recycle-to-extinction
of aqueous process condensates. Additional sulfur emission
approximately equal to the 862 value given above may be
expected from the auxiliary gas cleaning facility of the
char gasification plant.
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7. TRACE ELEMENTS
Trace elements are usually defined as those elements present
to the extent of 0.1% (1000 ppm) or less. Nearly all trace elements show
an enrichment in coal ash relative to their crustal abundance (51). Manganese
and volatile elements such as mercury are exceptions. This enrichment
is attributed to concentration effects or exchange reactions during the
formation of coals. Almost every element has thus been found in coals,
but the variation in concentrations is quite broad (52).
The fate of trace elements present in the feed coal to conversion
processes has so far received little attention. To the extent that such
conversion processes approach conditions which obtain during combustion, it
may be pertinent to apply results obtained in trace element studies of
the combustion of coals (53-55). Even in such studies, however, the con-
ditions of combustion have been noted to affect element dispositions.
Coal handling and preparation methods can likewise influence results,
so that generalizations may not be meaningful. Obviously, extrapolation
to a particular conversion process or feed coal would be conjectural
in large measure..
Although very large quantities of coal are consumed in combustion
processes and the total quantities of trace materials, some of
which are highly toxic, that may be released are likewise large, it has
been only recently that concerted effort has been directed to the definition
of the real problems. This effort, of course, has been associated
with the promulgation of sanctions affecting permissible discharges to
the atmosphere and waterways of the United States. Particular sanctions
relating to toxic discharges are still in process of formulation (56).
Research is required in many cases not only to set limits and goals,
but also to develop analytical procedures that may be generally adapted.
With fossil fuels, the general problem relates to the complexity of the
chemical system, including the large number of components, the imprecision
of available sensors or test methods, and the difficulties associated
with representative sampling of very large streams. The detection and
monitoring of many trace elements requires sophisticated procedures
and equipment which cannot be practically applied commercially. In
fact, the magnitude and nature of many industrial streams is such that
direct quantification or measurement is impractical. The general nature
of the pollution problem associated with COED Conversion has been
described recently (30). At this point it is generally considered that
COED will present no insurmountable control problems. On the other
hand, additional research will be required to establish the degree of control
which may be required.
Trace element concentrations in the gaseous and liquid streams
that may be discharged to the environment from COED operations have
not been reported by FMC. Of particular concern may be the purge gas
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stream from the first stage of pyrolysis and the splits that may occur
among the oil, aqueous condensates, and gas in the product recovery
system. Toxic trace elements which may wash into the aqueous streams,
for example, may require that such streams be specially treated if
condensates are to be recycled to extinction to pyrolysis or to char
gasification.
Each developer of a coal conversion process may ultimately
be required to account for the disposition of elements present in feed
whose toxicity or ultimate impact on the environment warrants control.
He may moreover be required to guarantee the containment or neutralization
of such materials in effluent streams, and this, in turn, may influence
the adoption of particular processing alternatives. For COED this will
require additional research firstly to define the levels of these elements
through the process sequence for particular feed coals at preferred
conversion conditions. A preliminary study of this type has been
reported for a bench-scale coal gasification unit (57). Considerable amounts
of many elements may be lost from ash during pyrolysis and gasification
(See Table 6"). Such loss may be appreciable, even though the processing
temperatures employed may be relatively low. Information is required
to detail the disposition of such losses, especially as they may
appear in products and in process effluents. Moreover, the capacity of a
large system to trap out various elements, as by chemical combination with
materials of construction or through physical condensation, introduces another
order of complexity, especially if process changes can result in sudden large
emissions.
It would appear that COED does not introduce new control
problems. Rather, since the pyrolysis train and water loops, including
run-off, may be designed to be largely self-contained, emphasis of the
controls development will be directed to the purge stream from the
first pyrolysis stage, to the gas residual from acid gas treatment,
and to the concentrated residuals from water treatment. Char gasifica-
tion, if it is included, will present additional research needs (46).
The enormous current government/industry effort to define and set
effluent goals and to develop economical control procedures for coal-
fired industrial operations will have a direct bearing on the extent
of additional research that may be required, once stream compositions
have been completely defined for COED conversion.
-------
- 46 -
Table 6
Trace Element Concentration of Pittsburgh No. 8 Bituminous Coal At
Calculated on
Max .Temp. of treat °C
Element: _______
Hg
Se
As
Te
Pb
Cd
Sb
V
Ni
Be
Cr
Feed
Coal
-
0.27
1.7
9.6
0.11
5.9
0.78
0.15
33
12
0.92
15
the Raw Coal Basis (From Ref . 57)
After
After
Pretreat
430
ppm
0.19
1.0
7.5
0.07
4.4
0.59
0.13
36
11
1.0
17
After
Hydro-
Gasif ier
650
0.06
0.65
5.1
0.05
3.3
0.41
0.12
30
10
0.94
16
Electro
Thermal
Gasif ier
1000
0.01
0.44
3.4
0.04
2.2
0.30
0.10
23
9.1
0,75
15
% Overall
Loss
for Element
96
74
65
64
63
62
33
30
24
18
0
-------
- 47 -
8. PROCESS AND ENGINEERING ALTERNATIVES
Most of the process and engineering alternatives we have con-
sidered in connection with the particular design chosen as the basis for
this report have already been presented or analyzed by FMC in the course
of process development (1-6). The most far-reaching alternative involves
the choice of fuel for the facility, and closely related is the treatment
of char product. The net thermal efficiency of the process is largely a
function of the alternatives chosen, clearly indicating the need for a
definitive char treatment development.
Pyrolysis yields otherwise have been well-defined for a variety
of coal feeds, so that these are not seen to be capable of significant
change by process modification.
We consider the demonstration of long-term recycle of contam-
inated process liquors and condensates to pyrolysis to be equally impor-
tant to the char treatment development. The necessity to process these
streams with conventional sour-water stripping processes will add greatly
to the utility requirement and investment in plant.
The oil absorption plan (5) for eliminating or reducing the
oil filtration requirements could significantly affect investment, but
is not likely to greatly influence the system otherwise.
The choice of system or systems for the removal of acid gases
from the various product streams may have significant impact on utility
requirements. As discussed in Section 3.2, available commercial systems
are in continuous development, and there is every expectation that effi-
ciencies will be improved.
Similarly, the choice of sulfur recovery method may be largely
influenced by expected emission regulations, and could also bear heavily
on investment and utility requirements.
The plant location will generally dictate the preferred method
for heat rejection, which may significantly affect investment and make-
up water requirements.
Table 7 lists some of the alternatives considered in connection
with the base design.
-------
- 48 -
Table 7
Process and Engineering Alternatives
Coal Drying
• Fuel-fired vs use of hot flue gases
• Venturi-scrubbing vs bag filters
• Catalytic CO oxidation vs stack dispersion
Pyrolysis
• Purge gas dispersion vs catalytic oxidation
• Hot-char water-coo ling y_£ air-cooling
Product Recovery
• Aqueous scrubbing vs oil absorption
• Treatment of contaminated aqueous streams vs recycle to pyrolysis
Hydrotreating
• Preheat integration vs water-cooling
• Power generation on depressurization of hydrotreating bleed gas
Acid-Gas Removal
• Amine vs hot carbonate systems
• Separate treatment of main product gas stream vs combined streams
Hydrogen Plant
• Reforming vs cryogenic separation
• Amine vs hot carbonate C02 separation
Sulfur Plant
• Stretford vs modified Glaus with Beavon tail-gas treatment
Utilities
• Alternative fuel choices for power and steam generation
• Waste-water treatment variations, including use of process char
and oxygen or ozone
• Maximum air-fin usage vs cooling water for heat rejection
-------
- 49 -
9. QUALIFICATIONS
This study Is based on the process design (Tables 8 and 9 and
Appendix Figures 1-5) supplied by FMC, the process developer, with mod-
ifications as discussed and shown in Figure 2 and Table 1. Costs or
economics were not considered, except directionally.
Although mass balances presented in the flow sheets were
found to be exact, it was not possible to achieve elemental balances
overall. The flowsheets do not specify the elemental composition of
coal, char, oil, or aqueous condensate streams. A number of varying
analyses reported by FMC for Illinois No. 6-seam coal feeds, for the
chars therefrom, and for the oils recovered were used in an unsuccess-
ful attempt to achieve element balances.
Apparently, the analyses of gas streams shown reflect pilot-
plant observations, but we were unable to key the analyses to particular
pilot runs. Further, because the treatment of raw gas streams and the
possible treatment of char is not specified, it was not possible to
reconcile gas stream compositions otherwise. The relatively low total
pressure and hydrogen requirement shown for hydrotreating filtered oil
apparently reflect data obtained after December, 1972 (6).
We note that the average overall pilot-plant material balance
(5,6) closed to within less than 5 percent, but the elemental balances
were often poorer by factors of 5 or 6. In our report, we have not
adjusted the compositions reported by FMC. Discretionary adjustments
were necessary in some calculations.
Variations in feed coal and product compositions make it
difficult to compare gasification processes. Significant variation
is seen even for the "same" process on different coals. Similar
variation will extend to the pollution potential of the process.
Additional research and/or development will be required to define
pollutant levels in particular streams with the precision required
by today's standards, and so permit a more accurate assignment of
energy requirements.
-------
Table 8
FEED COAL AND PRODUCT CHAR ANALYSIS (15)
Coal
Bituminous Rank
(ASTM D386-38)
Seam
Mine
Type
Town
County
Owner
Size, as rec'd., in.
Moisture, as rec'd.,
wt. %
Proximate Analysis,
wt. %, dry
'Volatile Matter
Fixed Carbon
Ash
FEED COAL
Illinois
High-volatile
C bituminous
No. 6
Peabody No. 10
Slope
Pawnee
Christian
Peabody Coal Co.
1 1/4 x 1/4
12
37.2
51.1
11.6
PRODUCT CHAR
1.0
2.5
76.3
21.3
ui
o
Ultimate Analysis,
wt. %. dry
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Ash
Gross Heating value,
Btu/lb.
66.9
4.9
1.1
4.
11.
,1
,7
11.3
12420.
73.8
0.8
1.0
3.2
0.0
21.2
117QO
-------
- 51 -
Table 9
Typical Syncrude Properties* (30)
Coal Source Illinois No. 6-seam
API, °@60°F 22
Pour Point, °F 0
Flash Point, PMCC, °F 60
Viscosity, cs. @ 100°F 5
Ultimate Analysis, wt. %
C 87.1
H 10.9
N 0.3
0 1.6
S 0.1
Ash <0.01
Moisture 0.1
ASTM Distillation
IBP 190
107o 273
307o 390
50% 518
707o 600
90% 684
EP (957o) 746
Metals, ppm
% Carbon Residue, 10% Bottoms 4.6
Hydrocarbon Type Analysis,
Liquid Vol. 7.
Paraffins 10.4
Olefins 0
N*»phthenes 41.4
Aroma tics 48.2
* Properties depend on severity of operation of hydrotreating unit.
-------
Coal Preparation
Stage 1 Pyrolysis
Stages 2,3,4
Product Recovery
Oil Filtration
Hydrotreating
Oxygen Plant
Acid Gas Removal
Hydrogen Plant
Sulfur Plant
Power Plant
Cooling Water
c<
Water Supply and
Treatment, Waste
Disposal, and Misc.
TOTAL C.W
Table
10
UTILITIES
Cooling Water
(GPM)
ww
30,700
—
79,500
1,100
600
33,000
41,500
12,000
1,000
300
300
Power
(KW)
5,850
27,650
40
4,030
1,300
30,100
—
6,900
1,700
1,300
-93,170*
7,700
4,400
Fuel Use
(MM BTU/HR)
455,0
1144.0
298.0
88.0
167.0
—
—
660.0
30.0
2032.0
(150 psi)
5,000
•180,000
19,300
461,500
-29,000
-276,800
Steam
(600 pal)
-265,000
1,000
-380,000
550,000
600,000
-506,000
Ul
M
200,000
*'2200 KW consumed internally.
-------
- 53 -
Table 11
Plant Water Requirements
Users GPM
Cooling Tower Makeup 9,000
Treated Boiler Feedwater (includes 1,550
H£ plant requirement)
Raw Process Water -40*
Potable Water 70
10,580
Streams To Waste Treating
Cooling Tower Slowdown 2,400
Boiler Slowdown 270
Oily Process Water 300
Sanitary 20
2,990
Raw Water Makeup (Assumes 100% reuse) 7,590
* Net water make.
-------
- 54 -
10. RESEARCH AND DEVELOPMENT NEEDS
FMC Corporation, in its development of Project COED), is well-
advanced in terms of demonstrable process operability on a significant
physical scale. Process yields have been well-defined for a variety of
feed coals (1-6). And extrapolation to a commercial design is on a
better basis in this case than for most other uncommercialized conver-
sion processes under development»
Perhaps the most important research need is the development
of an efficient char-utilization process. This aspect of COED de-
velopment has received considerable attention already (4), and the
COGAS developers (47) have two alternative gasification systems under
study.
Another important research need relates to the treatment of
contaminated process liquors and condensates. A large additional debit
in thermal efficiency is seen if these materials cannot be recycled to
extinction to pyrolysis, as is now assumed. This conclusion is based
on analogies drawn with other processes, and may not prove to be the
case here. More detailed analyses of the contaminants present in these
streams than has already been reported (30) will permit a more accurate
determination of overall treatment requirements. But the demonstration
of long-term total recycle in the pilot-plant will serve better as a
basis for design.
In this same connection, the "micro-structure" of gas, liquid,
and solid streams requires further definition. The forms in which sulfur
appears in these streams, and the toxic element contents may significantly
affect expected dispositions and treatments. Future pilot-plant work
should be directed to achievement of toxic trace element balances, es-
pecially for mercury, arsenic, cadmium, fluorine, and lead. Similarly,
the concentrations of the various forms of sulfur should be established
for all major gaseous streams, and for liquid streams which are, or may
be, directed to treatment facilities.
-------
PROCESS COED 24 M TON PER DAY PLANT
COAL DRYING AND STAGE I OF PYROLYSIS
FLOWSHEET SCHEME NO. I
DUAL TRAIN PLANT
D-ZOO COAL DRrER
70'* «40'
FINES FEEDER
IOTOMS/HR
P-210 riHSt STM6 PYROLYZER
64'«i( 40'
1-211, *-2l2 FIRST STME INTERNAL
CYCLONES 3BOMACFH
FROM CHAR COOLER
H-20a,H>209 VENTURI SCRUIBER
COOLERS S20 MACFM
5TS UACFlit
S-214 OAfi LIQUID SEPARATOR
''
»-2ie DECANTCR 2l>i4O'
9-KI9 FINES FILTER 110FT*
P-206 RECYCLE LKKJQR PUUP 200 H
TO A-240
WEAM GENERATION
I
Oi
TO CHAR COOLER
TO R-240
"STEAM GENERATION
WAlTfllL ST_nEAM_W
OAL 0» CMM TOW3/I1R
OIL
CO
, MJ
^Z
ttCgHOTTAGC TftAWWCBT OAJ
rffj(
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1
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04
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04
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190.91
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17,0
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<£s>
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f-kiUi^
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tl'»
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$ K,e«U4««i/< I/KI Of !
frei 9 irnr*u ruiwi AW ran TOML f
-------
PROCESS COED 24M TON PER DAY PLANT
STAGE 2,3 AND 4 PYROLYSIS
FLOW SCHEME NO. I
DUAL TRAIN PLANT
iTME PVROUUEIt
liS-<» SECOND-JIMB
R-UO
&KilT*oe "«»•*«»
S-«l" B-1JJ THinO-STMC
suuagi**
'ERHEATER
VS2J lECOKD-STME
9KSb •*"•
H-250 CHAR COOLER
" • JHHtt
17S-ZBZ CNM COOLER
CVCLONEI
S«Z~6'3"CHAR COOLER
II
• MMTU
K-ZIO
CHM COOLER
W TgW/M
^-x
5»Z21
hfa
^ r
r1
«&
M
Ul
'
tn
FROM RECYCLE G&S COMPRESSOR
MATEailT SJJ5ii!J^L
CO&L. Ofi CHAR TON'HR
OL CD
Ni
Oi
V>
CO,
CO
"l
CH4
C,M,
C,H.
t,M.
c.- G>
H,S
FIRST STAGE TRANSPORT GAS
TOTAL TONS/MR
TFMf - «F
PfltSS-PSIA
A*G MV>
MMOL/riR
UCPM
H SCFH CD
<4i>
9T725
OIG
£62
273B
940
1 13
377
OI7
04S
oie
on
03i
IS!
102431
550
2364
UTS
5«
25 O4
^
I5S437
584.37
850
&
5B4C6
005
O.75
768
2.73
033
i.oa
005
013
005
003
009
038
57821
IS4C
2414
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:M4
L3£t
<8»
8997
I9»
24393
340.43
IIOBI
I4O7
4333
1 71
446
0.94
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939
67121
1050
2364
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7221
456.61
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2.12
850
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37856
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350
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26.1 E
82.44
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19Q78
2.20
27420
37B56
131 02
is.er
3Z.or
237
620
219
152
429
IB 30
108725
890
1984
26 19
8244
321 3D
<.$>
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000
IJ5
14A6
4BT
o.sa
1.93
O.O9
023
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O16
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140854
855
27.08
23,76
2.03
(264
<^>
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l«
14.06
487
O5G
1.93
009
0.23
OOfl
O06
016
066
2417
1000
2706
2376
2.03
12.84
4>
2177.50
217750
1050
<^>
^€4.42
0.10
8.97
30.95
10.71
1.28
4Z6
019
0,51
0.18
012
035
150
id 76 a
1540
2603
2376
4/48
2832
^
173
22001
283.92
94,24
1104
1351
62459
1550
2708
21 H
56.83
359.36
"$>
319.22
51922
1550
^
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2T6.ZZ
43272
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2140
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233.7)
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15650
IOOO
3052
32 OO
*7ft
61.84
3>
33683
33663
1000
3052
ieoz
3T.3S
Z36.4S
564.66
564.ee
1550
<$'>
O.I 8
297
3093
10.71
1.28
4.26
019
0.51
0.10
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ass
1.50
S3.2C
IOOO
2606
23.T8
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28.32
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962.42
1550
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1040
5052
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4256
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42.56
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0.64
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O44
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6S75
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28 IB
23.76
562
3353
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276,22
276.22
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3052
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3066
19397
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5OI.34
501.34
800
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20.0
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5217
5217
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144.24
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270
28 ID
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6492
Q) ASSUMED OIL UN OF 300 IN CALCULATING AVG M W
© AS n-C4H« -*a-^
fSCFM-60'F.I47 PStA
CaWPMCNT SIZES 1NDKATEO ARE FDR EACH TRAIN
© TLOW RATES SHOWN ARE FOR TOTtt. PL-AW (BOTH TRAINS)
-------
- 57 -
APPENDIX
Figure 3 (15)
PROCESS COED 24 M TON PER DAY PLANT
PRODUCT RECOVERY SYSTEM
FLOW SCHEME I
DUAL TRAIN PLANT
S- 311 CAS LIOUID SEPARATOR
22' $ > 40'
265 MACFU
S-316 GAS LIOUID SEPARATOR
H-3IS CAS COOLER
337 MM BTU/HR
r-303 RECYCLE GAS HEATER
44 MM BTU/HR
13' f I
P-333 DECANTER OIL PIMP
H-3SI U6HT Of. Ifm
Tim BFU/HR
K-321 RECYCLE GAS COMPRESSOR H-341 HEAVY OIL VENT GONDETGER
Z9OO HP 34 MH BTU/HR
S-33O OIL WATER DECANTER
40- » « 48'
P-342 DEHYDRATED OIL F
10 HP
MATERIAL 5IS!*^J^
COAL OR CHAR TONS/HR
OILCD
N:
Oz
CO.
CO
HI
CH4
ClH«
ClHll
CiHi
CjH«
C4» a
HtS
TOTAL TONS; HR
TEMP- -f
PRESS -PSIA
AVG M*
M MOL/riR
M GPM
M ACFM
M'SCFM S>
<4>
7.ae
190.78
2.20
37B36
131.02
13.67
5107
237
6.ZO
2.18
1 92
4.28
1830
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830
19.64
26 IB
82.44
97304
921.30'
<#>
0.47
80.27
27.79
3.32
11.04
0.50
1.32
0.47
0.32
0.91
388
13798
1000
30.38
23.76
11.61
99.74
73.41
<^
57B5
ISO
23.09
<$
1 38
3816
ZZQ
37656
I3I.O2
15,67
9Z.07
z.yr
620
2 IS
1 52
4,20
1630
991.64
190
1934
2248
88.09
52023
557.02
<$>
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192.62
586035
190
24.33
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830
ISO
3.389
<^>
1.98
35.46
867.04
165
3.SSO
<^
270
Z.20
37856
13102
19.67
5207
2 37
6.20
2.16
152
426
IS 30
934 60
195
m«4
86 21
9S409
557. 76
ty
Oil
18.44
6 37
0.76
2.53
0 12
0.3O
0.12
007
O2I
0.89
31 69
280
1140
2376
2.S7
1123
10.68
<$>
2.70
2.31
39701
137.38
16.43
54 60
249
6.SO
230
I3<»
4 49
1919
98629
110
18 10
2(71
9063
511.59
374.66
<#>
2 31
397.01
137.39
16.43
54.60
249
6.5O
2 30
1 S3
449
19 19
68233
110
17.80
2376
37.42
328 66
36309
$
2.70
303.96
110
1.227
^
0.58
93.71
34.16
4.08
13.57
062
1.62
059
0.39
1 12
IS967
HO
17 50
23-76
14.28
83.14
90-30
#
1.73
29029
103.23
12.35
41.03
1.87
4.88
1 71
I 20
337
51266
110
16.00
2376
43.14
27472
272 7S
V
1.34
3243
41.25
183
0.164
$
685L94
163
28.26
#
634
158.35
196 55
183
0.784
4
38.16
IU
O.157
4
31 67
183
OJ3I
^
694
158.35
164 89
230
0692
•^
649
183
ao«7
4>
r w
190.76
roses
25Q
O79O
^
3373
a 49
&67
4753
13 QO
i$ ao
27 3J
i-4*
7799
ltd
4
23&S4
«3
asrs
<^
£43
3*43
fT
E7vV
«|J4
WJV
l 69
(*;
^
sirs
c:s
44 re
ICC
IAS:
aiw
! «
S3»
jo.;
© ASSUMED OIL MW OF 300 IN CALCULATING AVG MW
^)'AS n-C4Hio
U) SCFM-60T. 14 T PSIA
8) EOJIPMENT SIZES INDICATED ARC FOR EACH TRAIN
® FLOW RATES SHOWN ARE FOR TOTAL PLANT (BOTH TRAINS)
-------
- 58 -
APPENDIX
Figure 4 (15)
PROCESS COED 24M TON PER DAY PLANT
COED OIL FILTRATION
SINGLE TRAIN PLANT EXCEPT AS NOTED
M-393
BUCKET ELEVATOR
5 TONS/HR
T-3S3
PRECOAT MIX BIN
15'0. 2$'
P-387
PRECOAT PUMP
IO HP
T-385
PRECOAT TANK
16'0.22'
T-388 A TO E
FILTER FEED TANK
5OOO GALS/TANK
P-392 A TO J
FILTER FEED PUMP
50 HP/PUMP
S-380 A TO J
ROTARY PRESSURE
PRECOAT FILTER
7OO FT2/FILTEH
T-381 A TO J
SOLIDS RECEIVER
50 FTV RECEIVER
T-382 F-390
FILTRATE RECEIVER PflESSUHIZING-GAS
7500 GALLONS
H-386
LIGHT OIL
PREHEATER
13 UU BTU/HR
S-384
LIGHT OIL
CONDENSATE
SEPARATOR
1000 GALLONS
T-39S
FILTRATE HOLD
K-389
RECYCLE GAS
TANK - 35,000 GAL. COMPRESSOR
P-394
FILTERED OIL
PRODUCT PUMP
30 HP
LIGHT OIL
CONDENSER
O.9 MM BTU/HR
— ..STREAM NO.
MATERIAL ^~*—— -^__ ^
OIL TONS/HR
CHAR
Nz
H20
CO
C02
CH4
Ci*
H2S
FILTERAID .
BASECOAT MATERIAL
TOTAL TONS/HH
TEMP *F
PRESSURE PSIA
AVE. M.W.
MOL/HR
GPM
ACFM
SCFM
<5>
190.78
7.88
0.99
199.65
250
790
^
190.78
7.88
0.99
199.65
340
790
^
55.85
O.4S
5630
400
6O
27.88
4039.5
10300
25500
<4>
18496
55.85
1.43
242.24
350
42
27.62
4148
673
14300
26200
CONTINUOUS FILTRATION (TONS/HOUR)
^>
175.71
175.71
350
42
639
^
9.29
55.85
1.43
66.53
350
42
27.62
4148
14300
26200
N/
9.25
O.976
10.23
SO
41
39
^
55.85
O.445
56.30
8O
41
27.88
4O39
9490
25500
^*
175.71
175.71
33O
639
184.96
0.976
185.94
300
673
S/
O.554
0.554
70
6O
28.0
396
62
250
<
5.82
7.88
1.52
,15.22 ,
350
<>
PRECOAT CYCLE (TONS/CYCLE)
PRECOAT CYCLE LENGTH • 7 HR.
<$>
63.1
G3.I
<$>
h
&
3
S
^
in
u.
O.068
0.068
<£
210.2
210.2
250
<£>
210.2
63.1
273.3
3 2O
<$>
o°
1*5
H
tix
VR
o
<>
-------
PROCESS COED 24M TON PER DAY PLANT
HYDROTREATING PLANT
R-420A.B
F-410 GUARD
PREHEATER REACTOR
167 MM BTU/HH S'8 I 25'
R-421 A,B N-450
HYOROTREATINC PRODUCT OIL
P-40S
OIL FEED
PUMP
1300 HP
K-466
MAKE-UP H2
COMPRESSOR
38,000 HP
TO STACK
REACTOR
13'0 > 90'
K-454
RECYCLE Hi
COMPRESSOR
aOOHP
T-432
PRODUCT OIL
T-458
UOUOR
P-444
LIQUOR
STRIPPER
COOLER RECEIVING TANK RECEIVING TANK FEED PUMP
43S MM BTU/HR I8'0 t SO1 T'0,IS' 29 HP
P-434
S-431 PRODUCT OIL
H-448
CONDENSER
4.7 MM BTU/HR
P-44B
WASTE WATER 5-457
RECIRCULATION PRODUCT OIL
PUMP
SHP
HIGH PRESSURE S-481
FLASH DRUM DEMISTER
9'a > 20' 1370 ACFM
STRIPPER
FEED PUMP
20 HP
P -408 RECYCLE WATER
OIL PUMP
GO HP
STRIPPING TOWER
9 JO x 25
H-43S
CONDENSER
STRIPPING TOWER
12'» 301
P-43«
PRODUCT OIL
RECIRCULATION PUMP
EM-
SYNTHETIC CRUDE OIL
IT)
TO R-240
STEAM GENERATION
-ArT^r—^^L!!!
OIL
X,
H|0
eo,
CO
»,
CH4
Cj«4
eiM.
C.M.
C5H,
C.-!D
HjS
NHj
1 TOTAL TDMS/HR I
T£MP «P
P*dSS-PSIA
AVO ua
M UOL/HH
U CPU
M ACfU
M ftCFMW
^S
18196
0.98
260
iaoo
6743
<5>
ISO
046
390
20.39
060
200
1600
272
ZO.BI
IS6
i3i. at
<2>
539
O.04
071
969
26 36
1 72
0.03
0,71
0.14
0.9T
088
1 06
0 06
200
IBOO
3,22
2742
i eo
173.3V
<£
22666
539
1 02
071
865
26 36
1 72
O.O3
0.71
0.14
OS7
066
i ae
009
690
1720
3.26
27.93
3 19
i740e
4390
0.02
0.03
100
1600
0194
1.90
0.03
025
2 14
9.97
1.23
0.04
0.72
014
O.56
087
185
0.06
200
IBOO
4.77
6.61
0 43
4190
I.9O
0.03
0.29
2.14
597
1.23
0.04
0.72
0.14
0.96
oer
1 63
0 OS
200
1800
4 77
6.61
04S
41 60
<">
580
0 06
0 90
4 26
1194
246
0.06
1.44
028
1.12
1.74
370
0 12
200
1800
477
13.22
067
83.99
29810
9.19
1799
1.21
10.38
2892
9.94
•0.18
3.47
068
Z.73
4 23
974
2.63
750
1710
5 67
34 31
4 34
216 95
9.19
0.16
1.21
JO 38
2892
594
0.18
3.4
06
Z.7
4.2
89
0 2
100
1700
4 77
3202
1 89
20247
4>
16440
0.07
0.11
100
0 72B
<'f>
17.83
063
2 14
100
0003
3.69
0.10
0.75
643
1791
368
O.tl
2.15
0.42
169
2.62
556
0.18
100
1700
4.77
19.83
1 17
25 39
<&
350
006
048
395
II 01
2.26
0.07
1.32
0.26
1.04
1 61
3.42
LP II
100
16
477
12 19
76 27
7706
^
<&
16 61
100
0 057
<&
16.61
100
0 06T
<&
62 20
100
0 363
<9>
164.40
IOO
0 727
<^
16.61
100
0 067
$>
o.ie
0.22
1 69
16.01
102
1.27
0 01
200
20
16.99
2 44
14 39
15.43
#
0 7O
086
7.55
6369
4.08
5.09
003
200
20
1689
973
57 40
61 53
^
0 88
2 30
9.44
79.90
5.10
636
074
2.25
100
16
16.97
1261
7a 89
79 74
ty
1.89
004
0 2S
2 15
597
1 22
0 03
o.n
0.14
057
0.68
186
0 06
200
iaoo
4 77
661
043
4160
<$>
o aa
1 08
9.44
79 90
510
6 36
O.O4
200
20
1669
12 17
71 79
76.93
<^
0 18
1 44
1.69
1601
1.02
1 27
064
2 14
100
17
17 21
2 86
16 85
18 09
<$>
0.70
086
7.55
6389
4 06
5.09
0.10
0.11
100
ir
16 90
9.75
57 41
61 65
<$>
I31.TO
0 06
O.O9
100
iroo
0 583
<$>
4390
0 02
0 03
100
iaoo
0 134
3>
4390
0 02
0 03
100
1600
0 194
^>
O.O4
690
-------
- 60 -
BIBLIOGRAPHY
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-------
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-------
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(32) Reisenfeld, F. C. »nd Mullovney, J. F., Petrol. Refiner, Vol. 38,
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(49) "Clean Power Generation From Coal", OCR R&D Report No. 84,
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Pollutants in Fossil Fuels", EPA-R2-73-249, June, 1973.
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p. 108, August, 1973.
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(67) "Control of Air Pollution from Fossil Fuel-Fired Steam Generators
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-------
- 65 -
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
i. REPORT NO.
EPA-650/2-74-009-6
2.
3. RECIPIENT'S ACCESSION NO.
in
Fossil Fuel Conversion Processes
Liquefaction: Section I. COED Process
5. REPORT DATE
January 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C.D. Kalfadelis andE.M. Magee
8. PERFORMING ORGANIZATION REPORT NO.
GRU.7DJ.75
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
P.O. Box 8
Linden, NJ 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
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OF. REP<
Task Final
REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
IS. SUPPLEMENTARY NOTES
16. ABSTRACT
The report gives results of a review of the FMC Corporation's COED coal
conversion process, from the standpoint of its potential for affecting the environ-
ment. It includes estimates of the quantities of solid, liquid, and gaseous effluents,
where possible, as well as the thermal efficiency of the process. It proposes a
number of possible process modifications or alternatives, and points out new
technology needs, aimed at lessening adverse environmental impact.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Coal
Liquefaction
Fossil Fuels
Thermal Efficiency
Air Pollution Control
Stationary Sources
Clean Fuels
COED Process
Research Needs
13B
21D
07D
20M
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThaReportf
Unclassified
21. NO. OF PAGES
65
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
------- |