EPA.650/2-74-009-b
June 1974
Environmental Protection Technology Series
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EPA-650/2-74-009-b
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
GASIFICATION; SECTION I: SYNTHANE PROCESS
by
C. D. Kalfadelis and E. M. Magee
Esso Research and Engineering Company
P.O. Box 8
Linden, New Jersey 07036
Contract No. 68-02-0629
ROAP No. 21ADD-23
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
June 1974
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This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
11
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TABLE OF CONTENTS
Page
SUMMARY 1
TABLE OF CONVERSION UNITS 2
INTRODUCTION 3
1. PROCESS DESCRIPTION AND EFFLUENTS - GENERAL 5
2. EFFLUENTS TO AIR - MAIN GASIFICATION STREAM 8
2.1 Coal Preparation and Storage 8
2.2 Coal Grinding 13
2.3 Gasification 14
2.3.1 Coal Feed System 14
2.3.2 Char Letdown 16
2.4 Dust Removal ^8
2.5 Shift Conversion 25
2.6 Waste Heat Recovery 25
2.7 Light Hydrocarbon Removal 25
2 .8 Gas Purification 26
2.9 Residual Sulfur Cleanup 27
2.10 Methanation 28
2.11 Final Methanation 30
2.12 Final Compression "30
3. EFFLUENTS TO AIR - AUXILIARY FACILITIES 31
3.1 Oxygen Plant 31
3.2 Sulfur Plant 31
3.3 Utilities 33
3.3.1 Power and Steam Generation 33
3.3.2 Cooling Water 36
3.3.3 Waste Water Treatment 37
3.3.4 Miscellaneous Facilities 39
4. LIQUIDS AND SOLIDS EFFLUENTS 40
4 .1 Coal Preparation 40
4.2 Coal Grinding 41
4.3 Gasification 41
4 .4 Dust Removal 41
4.5 Shift Conversion 47
4.6 Waste Heat Recovery 47
4.7 Gas Purification 47
4.8 Residual Sulfur Cleanup 48
4.9 Methanation 48
4.10 Gas Compression 48
4-11 Auxiliary Facilities 48
4.11.1 Oxygen Plant 48
4.11.2 Sulfur Plant • 48
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TABLE OF CONTENTS (Cont'd)
Paee
4.11.3 Power and Steam Generation 49
4.11.4 Cooling Water 49
4.1L5 Miscellaneous Facilities 50
4.12 Maintenance 40
5 • THERMAL EFFICIENCY. .. 51
6. SULFUR BALANCE 55
7. TRACE ELEMENTS 58
8- PROCESS ALTERNATIVES 66
9. ENGINEERING MODIFICATIONS 69
10. QUALIFICATIONS 72
11. RESEARCH AND DEVELOPMENT NEEDS 76
12 . BIBLIOGRAPHY 82
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LIST OF TABLES
Table
Table of Conversion Units
Stream Identifications for Revised
Synthane Process
Chars From Synthane Gasification of
Pittsburgh Seam Coals .............................. 33
3 Components in Gasifier Gas
4 Mass Spectrometric Analyses of Benzene-
Soluble Tar From Synthane Gasification
By-Product Water Analysis From
Synthane Gas
6 Thermal Efficiency ................................. 54
7 Sulfur Balance ............................ • ........
8 Trace Elements in Condensate From An
Illinois No. 6 Coal-Gasification Test .............. 60
9 Trace Components in Raw Gas and Tar ................ 61
f\7
10 Major Elements in Coal ............................. °^
11 Minor Trace Elements ............................... 63
12 Potentially Hazardous Trace Elements ............... 64-
13 Process Alternatives Considered .................... 68
14 Engineering Modifications Considered ............... 71
15 Coal and Product Analyses .......................... 73
16 Plant Utility Requirements ......................... 74
17 Coal and Product Quantities and Heat Content ....... 75
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LIST OF FIGURES
Page
Synthane Coal Gasification 6
Synthane Design Revised to Incorporate
Environmental Controls and to Include
Auxiliary Facilities 9
3 Design Basis Dust Removal 19
4 Raw Product Gas Scrubbing 21
5 Tar Scrubber Shown Integral with
Gas if ier Reactor 23
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SUMMARY
The Bureau of Mines Synthane Coal Gasification 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 pointed out.
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TABLE OF CONVERSION UNITS
To Convert From
Btu
Btu/pound
Cubic feet/day
Feet
Ga lions/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/calorieskg
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.
Phase I of the contract involved the collection and evaluation
of published information concerning trace elements in coal, crude oil and
shale. This information is contained in the report, "Potential Pollutants
in Fossil Fuels", by E. M. Magee, H, J. Hall and G. M. Varga, Jr.,
EPA-R2-73-249, June 1973 (NTIS PB #225,039). Phases II and III were con-
cerned with the collection of published information on fossil fuel conver-
sion/treatment processes and the description of selected processes. These
selected processes were evaluated for their ability to produce clean fuels
and for their possibilities for environmental pollution.
The present study, Phase IV of 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.
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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
ottsite 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, the
Bureau of Mines, and the Lutmnus Company, as well as that furnished by many
specialists in Exxon Research and Engineering Company.
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1. PROCESS DESCRIPTION AND EFFLUENTS - GENERAL
The Synthane Process being developed by the Bureau of Mines
is an intrinsically high efficiency fluidized bed coal gasification
system operating at commercial pipeline pressure and designed to produce
high-Btu content product gas. Gasification is accomplished in the
presence of steam/oxygen, whereby heat required for the gasification
reactions is supplied by the reaction of oxygen with a portion of the
coal. High pressure favors methane yield, minimizes gasifier volume,
reduces oxygen requirement and reduces product gas compression- A good
fluidized bed operation insures the homogeneous reaction system required
to avoid damage by locally high oxygen concentrations.
Development work was started in 1961 by the Bureau of Mines
on methods of pretreating caking coals in a fluidized bed. It was
found possible to pretreat any caking coal by the proper combination
of oxygen content of the fluidizing gas, temperature, and residence
time (1,2,3). Earliest gasification tests with a two-bed fluid system
incorporating gas, tar, and char recycle (4) led to the development of
a single vessel system wherein the operations of coal pretreatment,
carbonization, and gasification were combined (5).
An engineering evaluation of the Synthane Process, which by
this time incorporated Bureau of Mines methanation developments (6,7),
was prepared by The M.W. Kellogg Company in 1970 (8). Notwithstanding
the substantial extension of high-pressure technology required to com-
mercialize the process, there was found sufficient incentive in the
economies projected in terms of overall simplicity, high gasifier methane
yield, and small reaction volumes to proceed with design of a prototype
large pilot plant. The prototype pilot plant was designed by The Lummus
Company (9), and is now being constructed. It is expected to be
operational in 1974.
The process basis for our evaluation is that employed by the
Bureau of Mines in its economic evaluation of Synthane Gasification (10)
in 1971. A block flow diagram of the process and auxiliary facilities
is shown in Figure 1. This design feeds 14,250 tpd of a Pittsburgh seam
coal containing 2.5% moisture, 7.4% ash, and 1.6% sulfur to the gasifiers.
250MM scfd of product gas is produced, with a HHV of 927 Btu/scf.
The design basis for the economic evaluation was based on
laboratory investigation in a forty-atmosphere fluid-bed gasifier (11).
Although serving adequately to define the major processing hardware
and energy requirements, so that economic comparisons might be made with
other gasification processes in a similar stage of development, the basis
did not detail disposition of effluent streams which might require special
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processing to minify environmental impact. In fact, until process
stream compositions are more precisely determined for specific feed
coals, the nature of such effluent streams, and the degree of processing
required, may only be inferred. Second after achievement of primary
gasification targets, the definition of a process's pollution potential
is a major justification for the construction and operation of a
large pilot plant.
The pollution potential has not been completely defined in
the context of U.S. standards even for those 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 at a high rate. Coal compositions,
including sulfur and trace element contents, vary widely (12),
even within particular regions or mines. Stream compositions from a
particular process are generally sensitive to coal composition as
well as to specific operating conditions.
On the other hand, gross estimates of the pollution potential
may be inferred on the basis of prior art and experience with processes
which treat coal or petroleum in analogous manner. There is no direct
commercial coal" gasification prior art for the extreme pressure at which
the Synthane gasifier will operate. Synthane gasification approaches
conditions which obtain in the commercialized Lurgi system, but the
,Lurgi gasifiers are "fixed-bed" devices operating at less than half the
pressure of the Synthane fluid-bed units- The present Lurgi gasifier is
more restrictive with respect to feed coal physical properties than should
be the case with the Synthane system, which incorporates integral pretreat-
ment- But a direct comparison of the pollution potential of the two
systems must await considerable further development.
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2. EFFLUENTS TO AIR - MAIN GASIFICATION STREAM
All effluents to the air are shown in Figure 2 and Table 1. These
effluents are based on the Bureau of Mines design (10), and are to some
degree inferred by analogy with prior art. Because of the large number
of options open to Synthane development at this stage relative to
established processes, there is every probability that substantial
modification and/or improvement may be expected.
2.1 Coal Preparation and Storage
Common to all fuel coal usage, and particularly to coal
gasification 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 gasification plants
to provide back-up for continuous gasification operations. For thirty
.days storage, there might be four 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 & 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 (14). Careful management and
planning will minimize dusting and wind loss and the hazard of combustion
in storage facilities-
The feed coal employed.-in this design has low inherent moisture
content, such that a special coal drying step is not provided. It may
be possible to operate the system without such a facility with coal from
particular seams, but this indicates enclosed on-site storage. Coal of
the type and size range (-3/4 inch) indicated to be held in stockpiles
in this design might be expected to acquire and retain 6-8 weight per
cent surface moisture on exposure to rain.
Should drying be required, however, the options available are
numerous, both with respect to procedures and to the fuel or heat source
that may be employed. Comments relating to coal drying in connection
with the Koppers Process (14) are pertinent. Ideally, no additional fuel
would be combusted specifically for coal drying purposes, but rather
hot gas, as, for example, flue gas from the utility boiler, would be
used. Overall energy debits would be minor in such case. The gas
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Figure 2. SYNTHANE DESIGN REVISED TO
INCORPORATE ENVIRONMENTAL
CONTROLS AND TO INCLUDE
AUXILIARY FACILITIES
Stream Identification)
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TABLE 1
STREAM IDENTIFICATIONS FOR REVISED SYNTHANE PROCESS
(Stream Numbers Refer to Figure 2. See Text for Details)
COAL PREPARATION
o Coal Storage
o Coal Drying
o Coal Grinding
GASIFICATION
o Coal Feed Lock Hoppers
o Gasifiers
o Char Let-Down
DUST REMOVAL
o Tar Scrubber
o Aqueous Scrubber
1. Influence of weather (wind, temperature) on 20-25 acre
on-site coal storage piles-
2. Dusting and wind losses; possible odor.
3- Precipitation on 20-25 acre storage area.
4. Storm run-off estimated at 5000 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. No drying facility provided in base case. Assume
utility boiler flue-gas stream used for drying coal
if required.
6. Assume 6% moisture retained on coal stored openly
is removed, equivalent to 72,000 Ib/hr water evaporated.
Vent gas stream directed to limestone scrubbing facility
for particulate removal and desulfurization.
7. 53 MM cfd air intake to milling circuit. Nitrogen from
oxygen plant may be substituted in any proportion to
reduce fire hazard. Nitrogen from the oxygen plant
may be used to blanket storage hoppers or transport
facilities. High-pressure steam may be used as
transport medium for ground coal in pipe ducts.
8. Outflow stream includes up to 60 tpd coal fines
(removed at bag filters and returned to coal feed bins)
and up to 20,000 Ib/hr water vapor.
9. Treated C02 separated at sulfur recovery unit used as
make-up to recycled gas pressurization system, amounting
to 30-50 MM cfd.
10. No effluent to atmosphere excepting leakage at gas
storage facilities; leakage into process of 30-50 MM cfd
with coal feed.
11. 1,187,500 Ib/hr coal feed (see text for analysis):
12. 304,000 Ib/hr oxygen feed.
13. 1,169,700 Ib/hr high-pressure steam feed.
14. Boiler feed water to cooling jacket,675 gpm.
15. Low-pressure steam from cooling jacket, 335,100 Ib/hr.
16. 200 gpm boiler feed water to "dry char" cooler.
17. 100,000 Ib/hr high pressure steam directed to shift converters.
3000-6000 Ib/hr vented steam treated to remove particulates
if discharged to atmosphere; may be used to transport char to
boiler or may be directed to water treatment facilities.
18. 4350 tpd char, assumed dry. Ducted to utility boiler using
steam as transport medium.
19. Up to 3350 gph heavy tar recycled to gasifier, processed
for sale, or directed to utility boiler.
20. Up to 365,000 Ib/hr high-pressure steam generated in
external tar.cooling circuit.
21. 730 gpm boiler feed water to tar cooler.
22. 1,110,000 Ib/hr aqueous scrubber effluent, directed
to waste water treatment; depending on operating
conditions, an additional 1500 gph of tar and 6-7 .
tph of ammonia may be separated from raw gas, in
addition to phenols and oils.
23. No discharge to atmosphere; 20-30,000 scfm raw gas
evolved on depressurization of scrubber effluent
recompressed into main gasification stream ahead of
gas purification.
24. 600 gpm boiler feed water to scrubber cooling circuit.
25. 300,000'Ib/hr low-pressure steam generated in cooling
circuit.
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TABLE 1 (Cont'd)
STREAM IDENTIFICATIONS FOR REVISED SYNTHANE PROCESS
(Stream Numbers Refer to Figure 2. See Text for Details)
SHIFT CONVERSION
HEAT RECOVERY
26. Spent catalyst (3-year life normal).
27. 548,900 Ib/hr high-pressure superheated steam.
OIL SCRUBBER
GAS PURIFICATION
SUUUR GUARD
METHANATION
COMPRESSION
OXYGEN PLANT
UTILITY BOILER
COOLING WATER
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
40.
41.
42.
46.
47.
48.
49.
50.
51
52
950 gpm boiler feed water to waste heat boiler.
474,500 Ib/hr low-pressure steam.
395,000 Ib/hr condensate directed to waste water
treatment. Gases which separate on decompression
reinjected into main gasification stream via routing
for stream 23.
Up to 1000 gph naphtha in scrubbing oil stream, depending
on operation of upstream scrubbers. This system integrated
with oil recovered from aqueous scrubbing effluents
(used as scrubbing medium). Up to 25,000 Ib/hr low-
pressure steam required for distillation of naphtha.
18,000 Ib/hr high-pressure resaturation steam.
19,000 Ib/hr condensate from after-cooler directed to
waste water treatment. Spent Benfield solution and/or
blowdown (life not estimated) requires special treatment.
Gases which separate from condensates or blow-down
on depressurization directed to utility boiler.
737,600 Ib/hr low-pressure steam into regenerators.
No discharge to atmosphere. 270 MM cfd acid gas stream
directed to sulfur recovery. Up to 1.0 MM cfd product
gas lost into acid gas stream.
Regeneration gas or steam; inerting gas required on change-
out of bed material.
Discharges to atmosphere may include clean regeneration
or inerting gases. Dirty gas and product gas vented on
change-outs directed to utility boiler.
Spent bed media. Carbons or chars may be combusted
in utility boiler. Sulfated metal oxides will require
special treatment or burial In sealed pits (life not
estimated).
Oxygen-free gas circulated in Raney nickel activation.
Vented activation gas. Hydrogen evolved in activation
and product gas vented on change-outs directed to utility
boiler: Metal dusts generated in catalyst replacement
contained in closed filter system.
130,000 Ib/hr condensate from after-cooler directed to
waste water treatment. Catalyst replacement and activation
will generate metallic solids effluents and caustic liquid
effluents which will require special treatment.
1000 Ib/hr condensate from Inter-coolers directed to waste
water treatment.
43. 425 MM scfd air intake
44. 330 MM scfd nitrogen and other air constituents. (152 tph
oxygen to gasifier).
45. 85 gpm water condensate from inter-coolers directed to
boiler feed-water treatment.
1060 MM scfd combustion air intake.
1070 MM scfd flue gas from char combustion, including
10,900 Ib/hr S02. (C02-18.5%, 02-1.9%, N2-79.47.,
S-0.157.). Directed to coal drier, if required for
drying coal.
115-135 tpd limestone to desulfurize flue-gas from char
combustion. Scrubber placed on coal dryer exit if flue
gas used to dry coal.
1050 tpd ash and 150-200 tpd sulfated lime from flue-
gas treatment. Disposition uncertain, depending on
composition, but assume burial in mine or in sealed pits.
Chemical additives may include chromium or zinc compounds,
acids, chlorine, phosphates, phenols, copper complexes.
2600 gpm water evaporated and 300 gpm drift loss into
circulated air if air-fin usage maximized. Early
warning system required in return laterals to indicate
leakage from process train to control emissions in cooling
tower plumes.
Draw-off from cooling towers estimated at 500 gpm. May
require special treatment ahead of injection into waste-
water treatment. Can be substantially reduced by incorporation
of zeolite softening system in cooling water circuit,
assuming leakage from process train is very small.
53. 20,000 MM scfd air circulated against cooling towers.
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TABLE 1 (Cont'd)
STREAM IDENTIFICATIONS FOR REVISED SYNTHANE PROCESS
(Stream Numbers Refer to Figure 2. See Text for Details)
SULFUR RECOVERY
WATER TREATMENT
54. 5 MM scfd regeneration air for Stretford solution.
55. Vented regeneration air directed to boiler firebox.
210-220 MM scfd C02 containing up to 5 ppm H2S-
may be directed to boiler stack.
56. Make-up Stretford solution.
57. About 140 tpd elemental sulfur produced for sale.
Liquid purge from Stretford will require special
treatment.
58. Additives to system may include milk of lime
(115 tpd), anti=foam, phosphoric acid (0.5 tpd)s
sulfuric acid, char (42 tpd), oxygen or ozone,
and other agents-
59. Up to 230 tpd lime sludge, 76 tpd wet char (recycled to
utility boiler), and miscellaneous sludges from aeration,
biox and separation facilities. Sludges will require
special treatment.
60- Aqueous scrubber effluents from dust removal require
special treatment, including facilities for separation of
ammonia, tars, oils, phenols, and pyridine bases. Up
to 160 tpd of ammonia may be separated for sale.
61. Control of noxious evaporative losses in treatment
facilities may require special engineering, including
floating covers on retention ponds or tanks and/or
forced draft.
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stream would require treatment to remove particulates prior to its dis-
charge. If particulate removal were the only consideration for such a
stream, then cyclone separation/filtration or electrostatic precipitation
would generally be preferred to scrubbing to conserve water, minimize
water treatment loads, and to facilitate recovery of fines. In
this case, however, flue gas from the utility boiler will require
desulfurization (see Section 3.3.1), so that we have assumed that lime-
stone scrubbing will be used.
On the basis that tar is combusted along with char in the utility
boiler, and that flue gas from the boiler would be available at the coal
dryer at about 550°F, the utility boiler flue gas stream could dry feed
coal containing in excess of 6 weight per cent water. On the basis that
limestone scrubbing will be used thereafter to limit SO- emission,
saturated flue gas leaving the scrubber would carry some 166,000 pounds
per hour of water into the atmosphere. To limit S02 emission to an
acceptable level could require up to 230 tpd of limestone and the
net resulting SOo emission will be on the order of 5500 pounds per hour.
2.2 Coal Grinding
Approximately 53 MM cfd of atmospheric air is aspirated
into the ball-mill grinding operation, which reduces coal size
to 70 per cent through 200 mesh. The air stream is heated in a circula-
tion system and passed through the mills, where it serves both to control
moisture in the pulverizing process and as transport medium for the
pulverized material.
Close control of the milling circuit is required when air is
used in this manner to reduce to a minimum operation in the explosive
region, such as may obtain at start-up or shut-down of mills. Pre-
cautions should also be taken against accidental overheating of coal,
as may occur due to mechanical failure of a heated mill. In general,
inerting systems are provided for these devices. An alternative might
involve use of an inert or low-oxygen gas stream in place of air as,
for example, the nitrogen from the oxygen plant or a flue gas.
The coal/air mixture passes through cyclones, where separation
occurs, and the air stream is discharged to the atmosphere through bag
filters. Such arrangement is commercially proven, with acceptable
particulate emission, though load on the filters may amount to some
60 tpd in this case (15). Only trace quantities of hydrocarbons have
been detected in such commercial streams, and odor is not considered
a problem. Collected fines from the filters are recycled to mill product,
It should be noted that it is possible to effect substantial
drying of coal in the milling circuit. Such systems have been designed
to accept coals with surface moisture content ranging to 20 weight per
cent. But the overall effect is to reduce mill capacity, such that
there is normally incentive to predry coal feed to the mills.
-------
Nominal drying capability, amounting to some 2 weight per cent of the
easifier coal feed rate, is estimated for the milling circuit in tnis
design, based on indicated air heater provisions and mechanical energy
requirements in the circuit.
2.3 Gasification
2.3.1 Coal feed System
Coal is charged to the gasifiers in the Bureau of Mines design
through pressurized lock hoppers. A number of alternatives regarding
the mechanical arrangement, the pressurizing medium, and the consequent
net energy requirement and pollution potential of lock hopper operation
appear feasible.
In this design, each gasifier is provided with one lock
hopper, which discharges alternately into two feed hoppers from which
coal is passed to the gasifier using a steam/oxygen mix as transport
medium! Oxygen reacts with coal in the transfer line, liberating heat
which prevents steam condensation that might °f™ "J^^rs
coal transport. Hence, in this case, some pretreatment of coal occurs
in the transfer line.
The gasifier charging sequence involves filling the vented
lock hopper from pulverized coal storage bins, pressurizing the filled
lock hopper, and discharging its load into a feed hopper. In this
configuration, it is presumed that a feed hopper is maintained slightly
above gasifier operating pressure while on line to the gasifier, and
that pressure is allowed to drop to the gasifier pressure level as the
hopper empties. At this point, the feed hopper is ready to accept another
charge from the filled, pressurized lock hopper.
The pressurized lock hopper must be vented to essentially
atmospheric pressure when empty of coal in order to be refllled. In a
multiple gasifier system, operation may be sequenced such that initial
venting may be to a lock hopper awaiting pressurization, or to a suc-
cession of these, such that some of the energy represented by the_com-
pressed gas may be recovered directly, while simultaneously reducing
the quantity of residual gas to be vented ultimately. Alternatively, two
or more lock hoppers might be provided each gasifier specifically to
permit such sequencing, since there may be practical operating limita-
tions to the degree to which gasifier operation may be scheduled.
Another alternative that may be attractive for large systems
would involve specific energy recovery in the venting process, as by
means of turboexpanders, which may be used to drive compressors or to
generate electricity. Obviously, combinations of direct use and specific
energy recovery are possible.
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- 15 -
The choice of pressurizing medium may directly affect the main
gasification processing sequence, as well as the design and operation of
the lock hopper system. The use of steam alone as this medium is con-
sidered mechanically unacceptable due to interference expected with coal
transport from condensation, which may not be controllable.
Since some fraction of the pressurizing medium will travel
with the coal into the gasifier, the use of a nitrogen-containing inert
gas for such medium is considered unacceptable from a process viewpoint,
since it dilutes the product gas, reducing its heating value, and
occupies volume in the reaction sequence otherwise.
Direct pressurization from the gasifier, as has been done
commercially in the Lurgi system (16), or the use of any combustible
gas, as, for example, product gas, is unacceptable, inasmuch as the
pretreatment section of the Synthane gasifier must operate in an
atmosphere of steam and oxygen. On the other hand, there may be suf-
ficient compression energy credits to warrant consideration of a mechanical
arrangement which permits the use of steam only to transport coal from
feed hoppers and, additionally, to strip combustible gas from such
transferred coal before coal contacts oxygen in the pretreater. And
should coal pretreatment not be required in a particular situation, use
of raw or product gas for pressurization may be a preferred alternative
It will be necessary then to include means for purging the vented
hopper, as by use of steam or nitrogen, before the hopper is opened to
be filled.
It is believed that C02, which is separated from the main
process gas stream following shift conversion, is the preferred pres-
surization medium (8,9). Such C02 must be superheated to prevent liqui-
faction at 1000 psia, and the rate of heat loss from the pressurized
feed system must be controlled to prevent condensation. Depending
on the mode of operation of the feed system, the volume of raw
gas issuing from the gasifier may be increased some 3-5 percent
as a consequence of admission of pressurization gas with coal. This
increased volume must be handled through the acid gas removal step, but
it is presumed otherwise not to affect process operation.
The composition of gas vented from the lock hopper can only
be surmised at this point, since it will be a function of the method
of operation of the coal feed system, including the pressurization
medium employed and the properties of the coal in use. It is probable
that removal of particulate matter will be required before such gas
may be vented to the atmosphere. If combustible gas be employed, it
might be recycled to the gasification train via compression, or might
be directly combusted in the utility plant.
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- 16 -
In the method of operation of the coal feed system described
above for this design, there should be no opportunity for gasifier
gas to back through the lock hopper. ..Hence, trace quantities only of
coal-originated materials, other than coal dust, should appear in vent
gas. However, the use of a heated hopper system, as will be required
if CO? is the pressurization medium, may subject coal in contact with
heated surfaces to sufficiently high temperature to cause stripping of
volatiles or of sulfurous gas. Formation of carbon- or carbonyl sulfides
is also possible.
It is apparent that C02 obtained from the acid gas treatment
facility may contain sulfur, as well as small quantities of CO and
hydrocarbons. The form and quantity of sulfur in this gas will depend
on the sulfur recovery process employed. At Bruceton, from the output
of a Stretford sulfur recovery unit, H2S content of separated C02 is indi-
cated to be less than 5 ppm. In the Bureau of Mines prototype pilot plant,
this gas, including the lock hopper.vent stream, will be incinerated in a
thermal oxidizer before being discharged to the atmosphere. This-procedure
-may be directly applicable to the commercial design, i.e., off-gas from
'ThI sulfur recovery unit, including lock hopper vent gas, may be sent
to the uSlIty boiler where sulfur would be oxidized to S02 and the
stream would otherwise dilute flue gases from fuel combustion.
We have assumed an alternative to continuous atmospheric vent-
ing which involves containment of lock hopper vent gas, as in gas holders
from which it could be.recompressed, limiting the requirement for fresh
make-up gas to the losses (largely back into the system) from the coal
feed system. In this arrangement, it will probably be necessary to
treat or filter gas entering the holder to remove dust.
It is thus indicated that the only material which may be
discharged from the coal feed system will be C02, which gas would
otherwise have been so discharged from the sulfur recovery unit. The
rate at which such C02 will be discharged will depend on the degree to
which gas is recycled in the feed system, but the system may obviously
be arranged such that no gas is discharged to the atmosphere at this point.
\
2.3.2 Char Letdown
Ash must be removed from the Synthane gasifier, as in most
gasification processes, in a more or less continuous fashion, to main-
tain carbon concentrations in the gasification zone sufficiently high
for desired reactions to proceed. Experimental work indicates incentive
for limiting the degree of carbon gasification, and a proposed feature
of the Synthane process involves setting the carbon content of the ash
(char) removed from the gasifier such that combustion of the char will
balance the total steam and energy requirements for the process.
The high operating pressure of the Synthane gasifier imposes
special problems on the system used to extract char. At the point of
-------
- 17 -
discharge from the gasifier bed, char is indicated to be at temperatures
in excess of 1700°F.
The char in this design represents a significant sensible heat
discharge from the gasifier. Trom thermal and process points of view,
perhaps the ideal system would transfer hot char directly to the boiler
in which it is to be combusted along with any associated gas, preserving
most of this heat and avoiding use of cooling media, water or steam,
that would require additional energy to subsequently separate or treat.
The mechanical design of a throttling arrangement that would permit such
operation, however, will require substantial development.
Consideration of a variety of alternatives led the designers
of the large pilot plant (9) to a system wherein char is cooled in
situ prior to the point at which it must be passed through valves. Hoc
char is caused to flow into a separate fluidized bed cooler by regulating
the pressure differential between the gasifier bed and the cooler. Steam
is used to fluidize the bed, and water is injected into the system for
cooling. High-pressure steam is generated in the cooler, and this
steam may be used in the process (specifically in the carbon monoxide
shift converter) after it has been filtered to remove char fines. The
designers point out that this steam might be directed to the gasifier
in its contaminated state if the gasifier distributor were designed to
introduce contaminated steam and oxygen separately.
Cooled char may be fluidized out of the cooler bed into lock
hoppers, avoiding throttling valves, or may be passed from the bottom of the
cooler bed through valves into lock hoppers. Agglomerates which may come from
the gasifier could present problems with either method of cooler operation.
The preferred alternative is a "dry" system, in which a filled
char lock hopper is isolated with valves which are arranged to be blown
clean before closing. Steam is vented to atmosphere via filters arranged
within the lock hopper, ahead of the pressure-reducing valves. Char flows
out of the bottom of the lock hopper into a conveying line in which steam is
used as transport medium. The empty lock hopper is repressurized with
steam before being put on line to again receive char.
A second alternative directs a char/steam mix from the cooler
through a slide valve into a char slurry quench tank, where water sprays
cool the char and a slurry is formed. The quench tank is vented to the
char cooler. Char slurry is depressured through orifice/valve arrangements,
the char slurry is filtered to recover water, and water is recycled to the
slurry quench tank through coolers. The char filter cake is estimated to
contain 40-50 per cent water in this case.
Gas from the gasifier will be carried into the char cooler
along with char. It is presumed that most of this gas will issue from
the char cooler along with the generated steam and be directed back into
the main gasification stream, either directly into the gasifiers or at
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- 18 -
the shift converters. It is not possible to estimate the degree of gas
contamination that may persist through the char depressurizing system
into the steam which is indicated to be vented ultimately from a dry
char" process. Some 3000 pounds per hour of steam is estimated to be
so vented if this scheme be applied to the Bureau of Mines design. Depend-
ing on its composition, some of this vent steam may be employed in the
scrubber water treating system, or may serve to transport char to the
utility boiler, in an integrated commercial plant. Although there ^
would probably be least atmospheric pollution associated with a wet char
or slurry letdown system, the water pollution generated and the energy
associated with water treatment and wet char combustion would indicate
that the slurry technique would be used only if an operable dry char
arrangement cannot be developed.
To summarize, the design basis (10) does not specify the method
by which char will be removed from the gasifiers, except to provide-
lock hoppers to receive char. The lock hopper volume provided is not
consistent with estimates of char density, so that lock hopper cycle rate
may be higher than indicated.
With the preferred dry char process, we have assumed that about
100,000 pounds per hour of high pressure steam will be generated by direct
water injection in the char cooler, and that this steam, along with as-
sociated gasifier gas, will be reintroduced into the process at the shift
converters. Some 3000 to 6000 pounds per hour of steam is estimated to be
vented from the lock hoppers, depending on cycle rate., "Dry" char is as-
sumed to be conveyed to the utility boiler using a steam transport, system.
Net atmospheric pollution associated with char let-down is therefore as-
sumed :ninor.
2.4 Dust Removal
Raw gas issuing from the gasifiers must be treated to remove
particulates and condensable matter that may interfere with subsequent
gas processing. The precise nature of materials which must be separated
from raw gas at this point is not known, except that coal or char fines
and coal-tars or oils are assumed to be present.
In the design basis, gas from the gasifiers passes firstly
through cyclones, where heavier particles (char) are removed, and then the
gas is subjected to cold-water scrubbing (see Figure 3)„ Scrubber liquor
effluent is depressured into decanters, where tar separation occurs, and
water is recirculated to the scrubbers through water-cooled heat exchangers
by high-pressure pumps, This design does not further detail the operation,
or provide for further handling of separated products or of scrubber
liquid.
This gas clean-up process has not been experimentally demons trate'd.
Laboratory procedure (17) at the Bruceton laboratories of the Pittsburgh
Energy Research Center (PERC) has generally involved passage of gasifier
effluent through dust filters and a series of water-cooled condensers,
wherein dusts, tars, and water are condensed from gas prior to pressure
reduction.
-------
FIGURE 3
DESIGN BASIS DUST REMOVAL (10)
Coal
750°F
593.75 tph
Steam
1, 169,700 Ib/hr
Oxygen ^
152 tph
{
t
( \C
A F
S
k l )
\ F /
I
E -
R
7
1 '
)85 (C}
==> Y
L
O
]
V
1,700°F
Char
181.1 tph |'
{
^
f
x^?^5^
/^V.
==£>
C
R
U
B
B
E
VjL^
r^
-f _
27 ^° T^1 "^
977 psig
Char
-------
- 20 -
Prior art would indicate that the gas clean-up procedure
outlined in the Synthane design will require substantial development from
both process and pollution view-points. As proposed, the operation is
a significant energy and cooling water consumer. The physical operation
of "dry" cyclones is by no means assured in this system.
Provision has not been made to contain and recover gas which
will be carried out of the scrubbers by the scrub liquor, and which will
separate from the liquor as this stream is depressured in the decanters.
The implied method of operation of the decanters would almost certainly
lead to emulsion formation in these vessels. And the distribution of
solid and liquid phases in these vessels otherwise is impossible to
assess. It is further not clear whether water scrubbing alone will
suffice to clean gas of all material which may affect downstream pro-
cessing.
The designers of the prototype pilot plant have accordingly pro-
vided a flexible system (18) which addresses many of these questions in
a manner by which it is hoped to obtain the experimental data required
to design a commercial plant(see Figure 4). In the pilot plant, gas from
the gasifier passes firstly through a venturi water scrubber where bulk
cooling occurs. Venturi scrubber effluent is directed into a baffled
high-pressure surge tank where gross separation of particulates takes
place. The same surge tank is arranged to serve as reservoir for a
separate high-pressure scrubber tower. Low-pressure steam may be
generated in the process of cooling recycled effluents to the venturi
scrubber and to the scrubber tower from the surge tank. The scrubber
tower is arranged so that water and/or oil may be used as scrubbing
media. Effluent from the high-pressure surge tank is depressured into
a low-pressure decanter, where final phase separation occurs.
This system resembles the processing sequence employed by Lurgi
and others in low-temperature coal carbonization plants constructed in
Germany prior to and during World War II. The Lurgi-Spulgas installation
at Offleben (49) utilized a waterspray and rotating screen to first remove
dust and heavy tar from gases leaving the carbonizing ovens. Light tars
and "middle oil" were condensed in sequence, and the removal of condensable
material was completed in mechanised wash-oil scrubbers which recovered
"benzine".
This same gas-treating sequence was adapted to the Lurgi-pressure
coal gasification process (24). Both hand-operated scrapers and water
sprays were required to maintain offtake passages through which gasifier
gas issued (at 575°F and 20 atm.) into a water spray cooler. Heavy tar
which condensed was discharged through a trap, and water was recirculated
to the sprays through external coolers. The gas stream exited the cooler
at about 300°F . Operation of the spray cooler is however indicated to
have been troublesome due to tar-water emulsification, and the spray coolers
at Bohlen, for example, had undergone four or five dasign revisions (24).
-------
FIGURE 4
RAW PRODUCT GAS SCRUBBING ( 9 )
Venturi
Scrubber
To Shift
Converter
Oil Wash
ro
f
i
I—£> Waste
Water
Tar
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- 22 -
Lurgi designs (23,24,50,61) place the direct-contact water quench
cooler immediately on the gasifier vessel, minimizing the potential for
.deposition in the gas off-takes. It is apparently not practicable to
extract high-level energy from this gas quenching process.
We believe it may be possible to adapt a"tar-scrubber" of the type
developed for petroleum fluid coking reactors (46,62) to the Synthane
coal gasifier to avoid the mechanical problems associated with tar and
solids deposition in the gas outlets. Moreover, it should be possible
to extract high-level energy from the process. The configuration for
this arrangement is shown in Figure 5.
In the fluid coker, the scrubber vessel is integral with the coker
reactor. The cyclone is internal to the reactor, with its outlet gas
discharge into the scrubber. Heavy tar condensed from the gas stream
in the scrubber is pumped through external exchangers, where high-pressure
steam is generated. The cooled tar stream separates, with the portion
not used for scrubbing being returned to the coker feed line. It is of
course necessary to control temperature of the tar pool in the bottom
of the scrubber vessel and tar velocities in the external circuit to pre-
vent coking and solids deposition.
In the Synthane design, gasifier outlet temperature is estimated
to be 800-1400°F. A steam dew-point of about 440°F is estimated for the
raw gas conditions. It is further estimated that up to 70 percent of the
heavy tar in the gas stream may be condensed by operation of the tar
Scrubber at about 560°F (63), or sufficiently high in temperature to
permit generation of 1009 psia steam in the external circuit. It is
estimated that about 365,000 pounds per hour of 1000 psia steam could be
generated in this manner, assuming gasifier output to be at 1000°F.
Removal of the bulk of the heavy tar in the gas stream at this
point should greatly reduce the emulsification problem as water is con-
densed from the gas downstream. Similarly, the tar scrubber would
serve to remove a major fraction of the char, ash, and coal fines contained
in this gas, so that loads on the downstream tar-oil separation and water
treatment systems should be reduced significantly.
From a thermal point of view, it would be desirable to return
the separated tar stream to the gasifier, as is done in the petroleum
coker. But if this is found to adversely affect gasification, such
separated tar could instead be directed to the char utility boiler (see
Section 3.3.1) or may be further processed for sale.
It is recognized that the mechanical arrangement at the coal
gasifier reactor head is more complex than is the case for a petroleum
coker, in that the coal feeding arrangement must be accommodated. It
should be possible, '-owe--er, to offset line coal feed svstom.
-------
- 23 -
FIGURE 5
TAR SCRUBBER SHOWN INTEGRAL WITH
GASIFIER REACTOR
Tar
To Process
or Storage
Scrubbed Gas
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- 24 -
It would also be possible to design a single combined scrubber-
fractionater tower which would separate tar, oil, and naphtha in sequence
up the column. Economies effected in scrubber-fractionator vessel costs
must, however, be balanced against the added structional costs associated
with the placement of a tall structure oa top of the gasifier. Hence
a succession of scrubbers, similar to the tar scrubber, but operating at
successively lower temperatures, and generating steam at successively
lower pressures, might be used to clean gas ahead of the shift converters.
What must yet be defined, however, is the limiting temperature of gas
at the outlet of such a scrubber train, or the limiting contaminant levels
in gas that will not interfere with the shift conversion. The Wes'tfield
Lurgi plant (23) was able to operate its shift reactors satisfactorily
(at 350 psig) on gas which had been cooled to 310°F.
To the extent that water vapor need not be condensed from
gasifier effluent or that gas be cooled below about 800°F in the process
of cleaning gas, there is net thermodynamic advantage to the process,
since both additional heat and water (supplied as high-pressure steam)
are otherwise required in the succeeding shift conversion reactors.
Hence an ideal system would remove contaminants in gas only by cooling
to about 800° F, generating steam in the process. Alternatively, shift
conversion catalysts and procedures might be developed to tolerate^
carbon-containing contaminants still present in gas from such "dry"
cleaning process. Gross contaminant removal would then follow shift
conversion, at which point the total product gas stream must be cooled
to effect acid gas removal in any case.
Even if a more nearly ideal system is not developed, the
commercial design will almost certainly include heat recovery facilities
at this point. Energy recovery in the depressurizing step may also be
practical, as by use of turboexpanders on gas, or hydraulic turbines or
flow-work exchangers (19) on liquids.
In this design, we have assumed that scrubbing will be used
following the tar scrubber, but that gas which separates from the scrubber
^fluent! on depressuring will be recompressed back into the main gas stream
at a point following shift conversion. Additional tar and hydrocarbons wVnch
condense along with water from the gas stream as the stream temperature is
lowered may be directed to finishing facilities to be processed for sale or
could be burned in the utility boiler. Either or both water and light hydro-
carbon might be recirculated to scrub the gas stream and steam could be
generated in the process of cooling the circulated fluids. Alternatively
at soTie point, gas would be sufficiently clean to permit direct operation
In aTonventiona8! waste heat boiler. On the assu,P"- th-t gj. tejperature
is reduced to about 300°F to effect clean-up, some 300,000 to 400,003
pounds per hour of low-pressure steam may be generated in the scrubbers.
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- 25 -
The degree of saturation of scrubber effluent with respect to
any given gas component will depend on operating parameters that have yet
to be defined. Methane, hydrogen, tkS, and carbon monoxide evolutions
from water at indicated conditions and rates could each amount to 400-
1000 scfm, for example. C02 evolution might be twenty times as much, so
that the total gas stream could amount to 20-30,000 scfm, or to 30-40 MM
scfd. Gas may also be physically entrained out of the scrubbers in the
liquid effluent streams.
Hence, although there may be mechanical and corrosion problems
associated with design of a suitable gas/liquor separator and with com- •
pression of separated gas, the net effect should be that no gas issues
to atmosphere in the dust removal process.
2.5 Shift Conversion
Scrubbed raw gas from the dust removal process is separated
into two equal streams, one of which by-passes the shift converters,
since only half of the total stream must be shifted to adjust the total
H2=CO ratio to 3:1 for purposes of methanation. In this design, a
significant quantity of high-pressure steam must be introduced to the
catalytic shift converters to achieve desired equilibrium, however.
The shift conversion is a totally-contained procedure, so
that no effluents issue to atmosphere.
2.6 Waste Heat Recovery
The raw gas streams which are split ahead of shift conversion
are recombined following the converters, and are cooled from an average
temperature of about 500°F to 300°F ahead of the gas purification system.
Low-pressure steam is generated, and there are no effluents to atmosphere.
2 .7 Light Hydrocarbonjtemoval
We have considered that it may be desirable to treat the com-
bined gas stream at this point to remove condensable hydrocarbons to minimize
contamination of the Benfield system. It may however prove practicable
to defer such treatment until acid gas has been removed, an alternative
which may be thermally preferable if the main gas stream is to be cooled
to a low temperature after acid gas removal. A number of considerations
are involved, including the ultimate disposition for hydrocarbons which
are separated (whether processed for sale or consumed as fuel), the effect
of hydrocarbon contamination on the method by which the acid gas stream
is treated, including the desulfurized residual, as well as the direct
effect on the Benfield system. There will be considerable relevant cotn-
mercial experience with the Benfield acid gas removal system to enable
a designer to assess the direct effect by the time more precise values
for the gas composition become available.
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- 26 -
For our design, we have assumed that the gas stream may be cooled
in water exchangers to about 90°F after it has been used to reboil the
Benfield regenerator and passed through light oil scrubbers to remove B-T-X
components. The scrubbing fluid would be available from the upstream
hydrocarbon separators. Gas which separates on depressurizing this scrubber
effluent could be recycled to the vapor space of the upstream separators
for recompression into the main gas stream. Downstream distillation facili-
ties would be required to separate naphtha if it were to be sold. It is
estimated that 20,000-25,000 GPD of B-T-X coald be so separated, requiring
an estimated equivalent of 25,000 pounds per hour of low-pressure steam.
Part of the heat removed in the cooling process could be returned
to the gas stream after scrubbing by exchange with the heated water leav-
ing the coolers, so that the net thermal loss might be held to the equiva-
lent of about 60,000 pounds per hour of low-pressure steam. About 18,000
pounds per hour of water would be condensed from .the gas stream on cooling,
and this (equivalent) water would have to be reintroduced oa reheating the
gas to avoid depletion of the Benfield solution. This might best be
accomplished by direct introduction of high-pressure steam, rather than by
reintroduction of the contaminated separated water, which would be directed
to the waste water treatment facility.
2.8 Gas Purification
The gas purification or acid gas removal process which is used
is the "Benfield" hot potassium carbonate system developed by the Bureau
of Mines (20;21,22). This method of removing C02 and H2S from the pro-
duced gas is indicated to have substantial thermal advantage over amine
systems at the high process pressure employed.
In the Benfield system, gas absorption takes place in a con-
centrated aqueous solution of potassium carbonate which is maintained
at above the atmospheric boiling point of the solution (225°-240°F) in
the high-pressure absorber. The high solution temperature permits high
concentrations of carbonate (alkalinity) to exist without incurring
precipitation of bicarbonate according to:
K2C03 + C02 + H20 *> 2KHC03
Partial regeneration of the rich carbonate solution is effected by
flashing as the solution is depressured into the regenerators. In this
design, sensible heat of the main gas stream is used to reboil the
regenerators, so that the gas is cooled to about 260°F in the process.
The gas is further cooled in cold-water exchangers to about 225° F before
entering the absorbers(but see Section 2.7 above).
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- 27 -
It is nececsary in this design to admit additional low-pressure
steam into the regenerators to complete the regeneration process and to
balance heat and water requirements. Regenerated solution is pumped back
through the absorbers. The main process gas stream exits the absorbers
at 230 T, and is cooled by cold-water exchange to about 100°P before
undergoing residual sulfur cleanup. Stripped acid-gas flows to the sul-
fur recovery plant.
Most of the reported experimental work related to this process
was performed at a total absorber pressure of 300 psig (22) on clean eas
mixtures. There is therefore some degree of speculation regarding
extrapolation to the gas mix and high operating pressure of the Synthane
process. At least one successful commercial application of this process
in a Lurgi gasification plant has been reported (23). In this case,
absorption takes place at about 284 psig. Peed gas contains about
36 volume per cent C02 and about 300 grains H2S/100 ft3. C02 concentra-
tions in outlet gas is two percent and H2S concentration is about five
grains/100 ftj. Corrosion problems have been encountered with the
liquor circulating pumps in this system, but inhibiting additives have
apparently been partially successful in this regard.
The Bureau's own work indicates that methane and CO are about
one-fifth as soluble in concentrated K2C03 solution as they are in water
at comparable partial pressures and temperatures, and that hydrogen is
about one-third as soluble in carbonate (22). The loss of product gas
into the acid gas stream is a consideration in any acid gas removal
process. For this design it is estimated at about 0.5 per cent of the
plant output, assuming saturation of the absorber liquor.
The combination of high-pressure absorption and low-pressure
regeneration is a suitable case for consideration of mechanical energy
recovery. Comments relative to energy recovery at the dust removal
step (see above) are also pertinent here. Incentives for development
of such systems escalate with plant size. The economic balance in any
such attempted improvement must include factors related to development
costs and added process complexity and operating hazards, as well as
the first cost of required hardware.
There should be no discharge to the atmosphere from the gas
purification plant.
2.9 Residual Sulfur Cleanup
Methanation catalysts are adversely sensitive to very small
quantities of sulfur in feed gas. The Benfield system is reported to
be capable of operation such that sulfur present in process gas as hydrogen
sulfide and carbonyl sulfide may be virtually completely removed. Less
is known about the other forms of organic sulfur which may be present in
process gas, especially thiophenes.
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- 28 -
This design incorporates a sequence of iron oxide and char
towers for residual sulfur cleanup ahead of the methanation reactors.
There is a long history of the use of such materials to clean synthesis
gas (24,25,26). It is estimated that total sulfur in gas may be reduced
to less than 0.1 grain/100 ft3 in this arrangement.
There is, however, no clear basis for estimating the life of
these beds, and hence no indication of whether the intent is to dispose
of spent material or attempt regeneration. The designers of the proto-
type plant have elected to reverse the order of treatment, placing
the activated carbon bed ahead of the sponge iron tower. In this case,
activated carbon is meant to be regenerated regularly with steam, and
.sponge iron discarded when spent. Reported experience (24) indicates
that temperature rise may be excessive in an activated carbon bed if
. H2S content of feed gas exceeds about 650 ppm> as may occur in this
:case with an upset in the Benfield system. It is also reported
that gum formers, dienes, indene, and styrene, if present, may inter-
fere with recovery of H2S on carbon. The steam stream used to regenerate
the carbon bed may be directed back to the Benfield regenerator, or, if
contaminants are troublesome", could" be directed to the utility boiler for
disposal. Some provision will have to be made to permit change-out of the
beds in this section. Hence, the high-pressure gas in the beds will have
to be vented, and the beds will have to be inerted before being opened.
It is assumed that the vented high-pressure gas will be directed to the
utility boiler. Steam, which may be used for inerting, may be directed
back to the Benfield regenerator.
Steaming, or other inerting, will also be required to purge
the bed of oxygen when a new bed is to be put on line. It is assumed
then that the only discharge to atmosphere from this section will be
such inerting medium, and, further, that the quantity of this gas will
be very small.
2.10 Methanation
The Bureau of Mines has developed two methanation processes
for application in the Synthane system, (6, 7, 27) and both will be
tested in the prototype pilot plant being constructed at Bruceton.
This design incorporates the Tube Wall Reactor or TWR process,
in which the methanation reactor is constructed in the form of a
heat exchanger. Reaction occurs on a Raney nickel catalyst coating
applied to the exterior of the exchanger tubes, and Dowtherm is vaporized
through the tubes to remove reaction heat. High-pressure steam is
generated in a separate boiler in the process of condensing and cooling
the Dowtherm heat exchange fluid, which is then recycled to the
methanator.
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The Bureau has developed techniques for coating the inside of
tubes with catalyst, an arrangement which may be more amenable to scale-
up, simplifying catalyst replacement. At this point, the expected life
of catalyst in this system is not known. Most of the experimental data
reported (8) was obtained at 300 psig, so that additional development is
required to redefine the process at Synthane process pressure (V)30 psig).
Catalyst life targets early on in the development were set at 2000 hours.
The Hot Gas Recycle or HGR methanation process also uses Raney
nickel as a catalyst, but the catalyst in this case is deposited on an
element consisting of closely-spaced parallel plates installed in a
high-pressure shell. The Dowtherm, or separate heat-exchange fluid, is
avoided in this system by employing the process gas at very high recycle
rates through the methanator to limit temperature rise. The physical
configuration of the methanation reactors is considered more suitable for
commercial scale-up in this arrangement, but the process carries energy
debits relative to TWR methanation, and the design of compressors for gas
in this pressure-temperature regime will require development.
When on-line, there should normally be no atmospheric discharge
from the methanation section. As in the case of the fixed-bed sulfur
clean-up facilities discussed above, however, provision must be made for
taking methanation reactors out of service for catalyst replacement.
Hence, the reactor must first be vented of high-pressure gas. Depending
on the size of plant and the frequency of change-outs, it may prove
desirable to provide facilities for recompression of this gas back into
the product gas stream. Alternatively; the vented gas could be directed
to the utility boiler. Inerting of these vessels prior to opening them
might best be performed with nitrogen (supplied from the oxygen plant),
and, in this case, the inerting effluent stream would be directed to
the boiler.
If Raney nickel is employed as catalyst, it is presumed that
facilities for activating the catalyst, if not, in fact, for complete
removal and replacement of catalyst on supporting surfaces, will be pro-
vided on-site. Hence, when a tube bundle of the TWR process, or a
catalyst element in the HGR system, has been readied for reactivation,
a dilute sodium hydroxide (^2 per cent by weight) solution is passed
over the element, and the temperature is raised to about 95°C. Hydrogen
is evolved in this process, and this stream might be handled in the same
way as high-pressure vent gas. The catalyst element must then be washed
free of caustic, using quite pure (distilled) water. Finally, the catalyst
system is dried and its temperature raised by circulating hot, oxygen-free
gas, such as nitrogen. It is assumed, then, that only this last (wet)
nitrogen stream may be discharged to the atmosphere from the methanation
section.
Of course, if on-site facilities are additionally provided
to remove spent catalyst from supporting surfaces and to re-apply new
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catalyst, then suitable arrangements must be provided to contain metal
dusts that may be generated in preparing the surfaces for recoating,
applying bonding agents (nickel aluminide), and flame spraying of
new catalyst.
2.11 Unal Methanation
The design basis does not include specific equipment for
limiting CO content of product gas issuing from methanation. Depending
on the ultimate use of product, CO content may be required to be held
to less than 0.1 volume per cent.
As indicated above, the methanation process which will be
ultimately commercialized has not yet been defined. However, the
experimental data reported to date would indicate that a final treat
will be required to limit CO content in methanator effluent to specifica-
tion. In a commercial plant, some arrangement, possibly involving
standby methanators, would probably be required in any event to handle
sudden loss of activity or other malfunction in the process train at
this point.
In the prototype pilot plant, based on Bureau of Mines experiments,
the designers have included fixed bed reactors containing pelletized
methanation catalysts (nickel oxides on aluminates) to reduce CO content
to specification. Although this procedure may be amenable to scaleup,
an integrated method for adjusting temperature of feed gas, and con-
trolling temperature within the beds, must be developed. Procedures for
changing out such beds, following along lines discussed above, should
result in only small discharges of inerting gas to atmosphere.
In our design, we have assumed that specification CO levels
will be achieved in the methanation plant proper.
2.12 Final Compression
Pressure drop through the Synthane train is indicated to
amount to about 65 psi. Gas leaving the methanation plant is cooled
tc 100°F to remove water, and is then compressed to 1000 psig, the
design product delivery pressure.
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3. EFFLUENTS TO AIR - AUXILIARY FACILITIES
We have elected in this study to treat the main gasification
stream separately from all other facilities, which are 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 gasification
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 3650 tons per day of
oxygen. The only effluents to the air from this facility should be the
components of air, principally nitrogen. About 330 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.
It will be possible to generate about 900 KW of electricity by recovering
the compression energy of the nitrogen through turbo-expanders.
About 425 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 Sulfur Plant
The type of plant used for removal of E2S from the acid Sas
overhead from the Benfield regenerators has not been specified in this
design. Originally, sulfur removal was to have been accomplished by
means of a direct oxidation Claus unit incorporating a tail-gas scrubber
using lime or soda ash (18). However, the performance of the Claus
system with the relatively low H2S concentration in the feed gas (about P.-J
weight per cent) could not be guaranteed. Moreover, the desire to
use sulfur-free C02 from the sulfur plant to pressurize the coal feed
lock hoppers (see Section 2.3.1) required that residual t^S in such gas be
considerably below the level that might be achieved by the Claus system.
Hence, use of the Stretford process has been assumed for sulfur removal
(28).
In the Stretford process, sour gas is washed with an aqueous
solution containing sodium carbonate, sodium vanadate, anthraquinone
disulfonic acid, and a trace of chelated iron. The solution reaches an
equilibrium with respect to C02, such that only small amounts of C02
are removed from the gas undergoing treatment.
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In this system, H2S dissolves in the alkaline solution, and
may be removed to any desired level. The hydrosulfide formed reacts
with the 5-vale.nt state vanadium, and is oxidized to elemental sulfur.
The wash liquor is regenerated by air blowing, wherein reduced
vanadium is restored to the 5-valent state via an oxygen transfer
involving the ADA. The sulfur is removed by froth flotation and
filtration or centrifugation. The process may be effectively operated
at any pressure up to 1000 psig (29, 30).
The fate of carbonyl sulfide and other organic sulfur com-
pounds which may be contained in the main product gas stream is not now
clearly understood. Hence, although it has been indicated that COS is
removed from gas by the Benfield system, it is not certain whether and
to what degree COS and other sulfur compounds may appear in the acid
gas overhead from the regenerators. The Stretford system is indicated
to be only partially useful for the removal of organic sulfur compounds.
Hence the preferred treatment route for acid gas must await more
definitive information related to operation of the Benfield system at
high pressure, and especially to Synthane gasification of high sulfur
coals.
It should also be noted that the developers of the Stretford
system have disclosed (31, 32) processes which convert organic sulfur
compounds in hydrocarbon streams to I^S, as by treatment with steam
over U30s - containing catalyst, which I^S may then be removed in a
Stretford system. As has been indicated elsewhere, the technology of
sulfur removal is advancing rapidly, so that it may be expected that im-
proved procedures will have been demonstrated by the time coal gasification
finds much commercial application.
About 210-220 MM scfd of C02 containing less than 5 ppm H2S
will be separated at the sulfur plant. Depending on the relative
economics, the I^S content of this stream may be reduced to less than
1 ppm in the Stretford system prior to discharge to the atmosphere. We
have assumed that the stream will instead be directed to the utility boiler
to undergo incineration and treatment along with flue gas.
The air stream used for regenerating Stretford solution is
another effluent to the atmosphere from the sulfur plant. This stream
is estimated to amount to some 5 MM scfd. This stream is also directed
to a boiler firebox.
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3.3 Utilities
3.3.1 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.
Synthane gasification is one of the class of coal gasification
processes which generate a carbon-containing char. Research to date
would indicate that it is not desirable to gasify more than about 90%
of the carbon in feed coal, and that it may be preferable to limit
gasification to about 60-70 per cent of carbon for most feeds. A
particular feature of the Synthane process design, therefore, is that
the carbon content of char leaving the gasifier may be adjusted such
that the subsequent combustion of the char will balance the power and
steam requirements for the system.
Char generated by the Synthane process is a much more refractory
material than feed coal, and generally contains a significant fraction
of the sulfur in the original feed(ll). Composition of the char produced
by the present design is not specified. Several analyses for char generated
from the pilot gasification of a Pittsburgh seam coal have been reported:
Table 2
CHARS FROM SYNTHANE GASIFICATION
OF PITTSBURGH SEAM GOALS (WT- PERCENT)
No. 1 (33) No. 2 (47)
Feed Coal
Feed Coal
Carbon
Hydrogen
Oxygen
Sulfur
Nitrogen
Ash
Volatile Matter
75.7
5.3
8.3
1.6
1.5
7.6
_
Char
71. A
0.9
1.8
1.5
0.5
23.9
—
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It is otherwise indicated, however, that the composition of the
char generated may be quite variable, depending on the feed coal and on
the operation of the gasifiers (11), so that the combustion properties of
char may likewise vary.
Experience with the large-scale combustion of char is so far
limited. The Bureau of Mines has reported on one investigation (34)
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 per cent 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 per cent for volatile contents
from 5 to 15 per cent. More supplemental fuel was required for the least
volatile chars to maintain flame stability.
Hence, it may be assumed that combustion of Synthane chars will
be possible in conventional fireboxes if 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 should be
possible to adjust S02 concentration in flue gas from most chars such
that subsequent flue gas treatment may be avoided. It has the disadvantage
of adversely affecting overall thermal efficiency.
A large number of power plant fuel alternatives involving
combinations or separate use of feed coal, char, tar, raw gas, or
product gas are open to the Synthane plant designer. It would appear
that conservation would dictate that carbon contained in generated
char should be recovered, as by use of char as fuel. But an alternative
that may be available would be to gasify Synthane char in a Koppers-
Totzek gasifier (14) or its equivalent, producing a low=Btu clean gas, which
may then be consumed separately or in combination with one or more of
the other available fuels to produce power. Since all auxiliary facilities
will have been otherwise provided for the Synthane plant, the addition
of gasifier(s) for char may be a preferred alternative should char com-
bustion boiler development show particular problems, as with fouling,
corrosion, stability, or sulfur removal.
For this design, we have assumed that equipment will be developed
to combust char alone with essentially complete carbon utilization. This
may be possible, for example, in a fluidized bed boiler and, especially,
in a fluidized bed system which incorporates combustion in the presence
of limestone to remove sulfur (35). Otherwise, such char combustion
will in general require that flue gases be treated to remove sulfur.
And, as indicated above, the development of a large-scale char burning
system, as with the development of any new commercial boiler concept,
may involve appreciable effort, a long lead time, and considerable
investment.
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At least one other power plant fuel combination deserves
mention. Tar removed from the gasifier output might be combusted
along with char, providing the supplemental volatile matter that may
be required to achieve stable combustion. This alternative suffers
mainly from the sulfur removal problem presented by such combustion..
Moreover, tar should be valued higher than feed coal as fuel, so that
feed coal might more properly be used as supplemental fuel if required
for char combustion. The present design assumes that produced tar will
be sold, and credits the thermal balance with the fuel equivalent. In
the light of current petroleum availability and pricing, it may well
develop that tar may be marketable. Again, it may be possible to gasify
tar along with char in a suitable gasification unit to produce clean gas
avowing stack gas treatment entirely and greatly reducing boiler investment
In the present design, 4350 tpd of char is combusted in the
utility boiler. If char of the composition (1) above is assumed,
and if combustion be effected using 10 per cent excess air, 1060 MM
scfd of combustion air will be required. The volume of flue gas from
the combustion will amount to some 1070 MM scfd, assuming feed char to
be dry, that carbon combustion efficiency is 100 per cent, and that all
of the sulfur is converted to S02, i.e., no sulfur remains in ash.
A higher heating value of 11,000 Btu per pound is estimated
for char of this composition, so that the hourly firing rate amounts to
some 3980 MM Btu. Unfortunately, there will also be emitted some 10,900
pounds per hour of S02 or about 2.7 pounds S02 per MM Btu. Hence flue
gases must be treated on the basis of current standards to reduce emitted
S02 to less than 1.2 pounds per MM Btu (36). The theoretical limestone
requirement for this purpose amounts to some 115 tpd (13,71).
A variety of flue gas treatment processes for particulate and
SOX control are in the development and demonstration stages (37,38).
Although the effectiveness of some of these processes is now being tested
in fossil-fuel-fired utility boilers, their use for char-fed boilers
has not been evaluated. It is reasonable to assume that these systems
could be adapted to provide the necessary control for the char-burning
processes. The adapted system would have to be environmentally sound
(i.e. adequate control of all air, water, and solid waste streams)
and efficient. Alternatively, development of a high-temperature char
gasification approach may prove viable.
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The emission of other gaseous pollutants from the char combustion
operation, including CO and NOX, are not now considered to present
particular technical problems. Reported work with utility boilers (39)
would indicate that careful control of the combustion process may suffice
to produce acceptable levels in flue gas.
Adequate control of particulate emissions should result from
the limestone scrubbing facility. Normal design practices would limit
liquid droplet carry-over, would reheat gas downstream of the scrubber
using, hot-flue-gas exchange to prevent condensation and formation of
visible plumes, and would insure that gas could not by-pass the scrubber
in the reheat equipment by maintenance of an appropriate pressure balance.
Use of hot flue gas to dry coal, as has been proposed in Section 2-1 above,
would reduce the quantity of water required to presaturate the gas prior
to scrubbing.
3-3.2 Cooling Water
A total of 260,000 gpm of cooling water is indicated to be required
for operating the Bureau of Mines design- About two-thirds of this requirement
is used for thermal exchange against the main high-pressure gasification
train, so that considerable mechanical design effort is foreseen to minimize
leakage losses into the cooling water system.which may otherwise preclude
use of cooling towers as heat rejection devices. Undue leakage of hydro-
carbons, CO, NH3, phenols, H2S, or sulfurous materials into the cooling
water circuit .could not be tolerated in the plumes from cooling towers.
An early warning system to indicate the presence of hydrocarbons in cooling
water return laterals will probably be required in any case to avoid noxious
discharges.
If cooling towers were used for this total plant, a minimum of
6600 gpm of water would be evaporated. Drift loss would be in excess of
500 gpm, and draw-off might be about 800 gpm. Air requirement,
would.amount to some 48,000 MM scfd. Reheat of plumes would be required
to avoid fogs in some cases •
The design basis (10) includes only minimum heat integration, consistent!
with a conservative approach to an unproven design. Moreover, some 30 percent
of the total cooling water requirement indicated for dust removal could
be materially reduced if alternative procedures can be applied (See Section
2.4 above)•
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 gasification 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.
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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 the indicated cooling water requirement for
dust removal is eliminated, and that half of the remaining requirement
may be displaced with forced draft air-cooled heat exchangers, the incremental
electrical power requirement is estimated to amount to 24,000 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 2600 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 500 gpm. There would
be a reduction in the steam usage indicated for pumping cooling water, such
that the net incremental steam requirement for power generation might
amount to 200,000 pounds per hour of 1000 psia steam, or to an equivalent
thermal efficiency debit of about 1.5 percent.
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 apecial
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.
3.3.3 Waste Water Treatment
Facilities required to treat water, including raw water, boiler
feed water, and aqueous effluents, will include separate collection facilities:
o Effluent or chemical sewer
© Oily water sewer
e Oily storm sewer
® Clean storm sewer
© Cooling tower blowdown
o Boiler blowdown
o Sanitary waste
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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 60,000 gpm in a maximum one-hour
period.
Pretreatment facilities will include sour water stripping
for chemical effluents and Imhoff tanks or septic tanks and drainage
fields for sanitary waste.
Gravity settling facilities for oily wastes will include API
separators, skim ponds, or parallel plate separators.
Secondary treatment for oily and chemical wastes will include
dissolved air flotation units, granular-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 Synthane plant will 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 should have the attributes of activated carbon, which has been
shown to be effective in the removal of a wide variety of the water
contaminants expected (65). The Bureau of Mines design basis includes
M f°rty-two tons Per day of gasifier char for water treatment
Normally, the cost of activated carbon tends to restrict its
V°ntaminated Char S° used may subsequently be fired in the
, Yf ,boller> water treatment in the Synthane system will be considerably
simplified.
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 (64), and has particular advantage in that solids concentrations
are not thereby increased. We, therefore, believe that early research should
be directed to the use of char and of oxygen or ozone to treat aqueous
scrubber effluents from the Synthane process to set the stage for an
integrated commercial design.
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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. Of particular concern
is the system which will be used to pretreat gas scrubber effluent
(See Section 4.4). 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.
3.3.4 Miscellaneous Facilities
Provisions for start-up of the gasification facility may
generate short-term effluents to the atmosphere. Effluents from start-up
heaters will depend on the fuel fired for such purpose. Product gas
combustion in a boiler and/or in gas turbines may be justified to
produce start-up steam and power requirements. In such case, 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, hopper venting, and in the operation of large
compressors and pumps, will be a requirement. Similarly, we note that
normal commercial practice for high-pressure reaction vessels, and
especially for oxygen-blown reactors, would provide barricade shielding
or blast protection to limit damage in event of rupture and to protect
personnel. Lay-out of the commercial Synthane gasification train will
require sophisticated analysis to minimize the amount and cost of such
shielding.
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.
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4. LIQUIDS AND SOLIDS 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 20-25 acre
area required to hold a thirty-day supply of feed coal could easily
amount to 5000 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 (41) will apply to such coal storage facility. The
application of 'best practicable control technology' 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 gasifica-
tion 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 gasification 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 3.3.3). 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 gasification
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 (42), might be treated continuously by accepted techniques
(43, 44, 45),- 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 2200 gpm of wash water, and dis-
charge 1800 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 500-600 gpm lost via the laundered coal product.
4.2 Coal Grinding
In this design, which incorporates bag filters on the air
stream which issues from the ball mills, there should be no solid
effluent from the coal grinding operation. Some 60 tpd of coal fines
recovered at the filters is recycled to mill product.
4.3 Gasification
There should be no major solid or liquid discharges from the
gasification section excepting the gasifier char stream. In our design,
it has been assumed that a dry char let-down system can be developed,
such that char may be ducted to the power plant using steam or inert gas
as the transport medium. Char is generated at the rate of 4350 tpd.
Facilities used to store and compress lock hopper vent gas
may generate small solids and liquid effluent streams that would require
treatment or disposition. Hence, coal fines filtered from such vent
gas are recycled to feed. Similarly, water present in such gas may be
condensed in a compression process, and would be directed to treatment
facilities. Water which may be used as sealing fluid in gas holders may
likewise require periodic treatment and replacement.
4.4 Dust Removal
The "dust removal" or gas cleaning section as envisioned
for this design has the greatest potential for pollution. It is at
this point that all materials generated in the gasification (other
than acid gas) that are not compatible with the gas product are removed.
In Synthane gasification, as with all processes which gasify coal at
intermediate temperatures, the gasifier output may contain all of the
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fines.
The particular distribution of compounds which will be present
in raw aasifier gas will of course depend on the composition of feed
S. and* '« the particular conditions of the gasification The range
of sulfur and B-T-X components which may be expected are listed m Table J
tor two types of coal (47) .
In the design basis, cyclones and water-scrubbing are provided
to remove condensable matter- Tars which may separate from such condensate
have beln partially characterized (Table 4). Similarly, aqueous condensate
(obtained by passage of gasifier output from the Bruceton 40-atmosphere
aboraSry gasifier through water-cooled condensers) from Synthane raw
gas has been analyzed, and compared with coke-plant weak ammoma liquor
(Tables)-
We note that some of the polynuclear hydrocarbons which may
be present in raw gas have exhibited carcinogenic properties in animal
studies (67,68). Control of such materials will generally be required
in connection with evaporation from the waste water treatment system,
in plumes from cooling towers if leakage from the process train occurs,
in the direct handling of separated tar or oil products, and in the flue
gases from char, coal, or tar combustion (69,70).
The over-riding consideration is that gas clean-up shall be consistent
with satisfactory operation of subsequent processing steps, especially
shift conversionyand tuethanation, and that Benfield solution contamna- .
tion be minimized.
Scrubber operation for this design has been ^""a* £ *CCtl°n
The Bureau of Mines has evaluated the operation of facilities which
may be Squired to treat waste water from this design (48) Aqueous
Affluent rrom the scrubber water decanters is fed to ammoma stills
ft the rate of 1,110,000 pounds per hour. Milk of lime is used to
spring fixed ammonia in a steam-stripped tower according to
Ca(OH)2 + 2NHA(X)
Ca(X)
Generated lime sludge is directed to holding ponds for settling at
the lite of 230 tpd (501 solids). C02, H2S, and HCN present in the
incoming decanter stream are sprung in a heated dissociator. This
las strLm is directed to the sulfur recovery unit. 160 tpd of ammonia
is produced for sale. This general treatment method and its variations
have been reviewed by Kohl and Reisenfeld (66).
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- 43 -
Table 3
COMPONENTS IN GASIFIER GAS (47)
COS
Thiophene
Methyl Thiophene
Dimethyl Thi<
Benzene
Toluene
C0 Aromatics
o
so2
cs2
Methyl Mercaptan
(ppm)
Pittsburgh
Seam Coal
860
11
42
:iene 1
Dphene 6
1,050
185
27
10
—
ntan 8
Illinois
No. 6 Coal
9,800
150
31
10
10
340
94
24
10
10
60
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- 44 -
Table 4
MASS SPECTROMETRIC ANALYSES OF
BENZENE -SOLUBLE TAR
FROM SYKTHAME GASIFICATION
(Vol. %)
Structural type; HP-118^-' HP-1— ^
includes alkyl , #118 #92
derivates _ Pittsburg Illinois
Benzenes 1.9 2.1 ,
Indenes 6. I-7 8.6^'
Indanes 2.1 1.9
Naphthalenes 16.5 11.6
Fluorenes 10.7 9.6
Acenaphthenes 15.8 13.5
3-ring aromatics 14.8 13.8
Phenylnaphthalenes 7.6 9.8
4-ring peri-condensed 7.6 7.2
4-ring cata-condensed 4.1 4.0
Phenols 3.0 2.8
Naphthols b/ b/
Indanols 0^.7 (5.9
Acenaphthenols 2.0
Phenanthrols — 2.7
Dibenzofurans 4.7 6.3
Dibenzothiophenes 2.4 3.5
Benzonaphthothiophenes — 1.7
N-heterocyclics£' (8.8) (10.8)
Average mol. wt. 202 212
a./ Spectra indicate traces of 5-ring aromatics.
b_/ Includes any naphthol present (not resolved in these spectra)
cj Data on N-free basis since isotope corrections were estimated,
-------
- 45 -
Table 5
BY-PRODUCT WATER ANALYSIS^ FROM SYNTHANE GAS (47)
PH
Suspended Solids
Phenol
COD
Thiocyanate
Cyanide
NH3
Chloride
Carbonate
Bicarbonate
Total S
I/ Mg/liter (except pH)
2] 85% free NH3
JV Not from same analysis
4V S= 400
S05 300
S0= 1,400
s2o= = 1,000
Pittsburgh
Seam
9.3
23
1,700
19,000
188
0.6
11,000
Illinois
No. 6
8.6
600
2,600
15,000
152
0.6
8,10Q2/
500_,
3/
6,0004,
W
11,0007,
Coke
Plant
9
50
2,000
7,000
1,000
100
5,000
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- 46 -
Water withdrawn from the fixed ammonia still is cooled to
100 F using air-fin exchangers, and is stored for 48 hours to permit
tars to separate. This water is then directed to aeration tanks,
along with other aqueous streams condensed from the main product stream
(see below). Antifoam, phosphoric acid, and sulfuric acid are added
to adjust pH and to promote the oxidation of organic material, including
phenols, cyanides, and thiocyanates, in the aerators.
Water from the aerators is directed to clarifying basins.
Overflow, containing 0.2 ppm phenol, flows to polishing towers where
gasifier char is used to remove phenols. Treated water is returned
to the plant's raw water supply system at the rate of 1,760,000 pounds
per hour. Wet char (about 1.75 tph of dry char is required) is
re-directed to the gasifier char stream after filtration. Underflow
from the clarifiers is filtered to remove sludge and recycled to the
aeration tanks. Sludge is filtered and combined with char fuel going
to the power plant at the rate of about 2.3 tpd. Filtrates are recycled
to the aeration tanks.
One concern with this processing sequence involves the
ultimate disposition of phenols. Particular difficulty associated with
the recovery of dihydric phenols from aqueous streams led to the
development in Europe of the so-called "Phenosolvan" process (49). In
this scheme, n- or isobutyl acetate (or other acetate. ) is used as
extraction solvent, permitting separation of phenol by-product.
It is interesting in this context to review the gas liquor
treatment scheme provided for the Burnham Coal Gasification Complex (50).
In this arrangement, incoming gas liquor is filtered and mixed with
the Phenosolvan solvent. Phenol-rich extract is distilled to recover
crude phenols, and the solvent overhead, after separation from water,
is recycled to the extractors.
Crude phenol is used to scrub fuel gas, which is used to
strip solvent traces from the extractor raffinate. Solvent-free raf-
finate is steam-stripped to remove NH3, CC^j and I^S. The C02 an^ H2S
are returned to the sulfur recovery unit. Effluent from the strippers
is directed to biological treatment to render it suitable for use as
cooling tower make-up.
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- 47 -
In recent years, the rapid development of environmental protection
requirements has outstripped environmental research and development programs-
It is likely that noxious effluent limitations will tighten in the future,
so that considerable additional research is needed to offset the very high
incremental costs foreseen for extended application of current technology.
On the other hand, considerable progress has already been made toward
practical treatment systems conforming with current standards in related
coking and coal operations (40).
4.5 Shift Conversion
There should normally be no liquid or solid effluents from
the shift operation. However, facilities will be required to dispose
of spent or inactive catalyst (See Section 4.12).
4.6 Waste Heat Recovery
Some 395,000 pounds per hour of condensate is generated in
the process of cooling combined gas streams prior to acid gas removal.
Condensate is further cooled, and is then directed to the aeration
tanks in the waste water treatment plant.
The depressurization of this, and all other condensates
collected from the high-pressure gas stream, will release absorbed
gas It will be advantageous to direct all such condensates
to a common expansion vessel, from which released gas may be recom-
pressed back into the main gas stream. In particular, gases recovered
from condensates ahead of methanation might be reinjected ahead of
acid gas removal.
4.7 Gas Purification.
Condensate streams are generated in the Benfield loop as
circulated gas is cooled. The disposition of these streams will depend
on their composition, but they may in general be directed to the waste
water treatment plant. Some 19,000 pounds per hour of condensate xs
separated from treated gas as this stream is cooled ahead of the
residual sulfur clean-up beds.
Additionally, facilities will be required to dispose of
contaminated Benfield solutions. (See Section 4-12).
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- 48 -
4.8 Residual Sulfur Cleanup
As previously discussed, facilities will be required to
dispose of spent material used in the cleanup beds. Activated char
or carbon may be combusted in the power plant, but disposition of
other materials, such as iron oxide, is less certain (See Section 4.11.5)
4.9 Methanation
About 130,000 pounds per hour of condensate is separated
from the main gas stream as it cools on exit from the methanation loop.
Gas which separates from such condensate on depressurization may be
compressed back into gas product, or may be consumed as fuel in the
power plant. Condensate is directed to waste water treatment.
As discussed above, on-site facilities for catalyst replace-
ment and activation may generate a variety of liquid and solid streams,
including spent catalyst, metal dusts, and caustic solutions. Dis-
position of these materials is discussed in Section 4-12.
4.10 Gas Compression
A small quantity of condensate, about 1,000 pounds per hour,
is separated from product gas in the final compression. Gas which
separates on depressurization of this stream may be combined with gas
evolved from methanation loop condensate.
4.11 Auxiliary Facilities
4.11.1 Oxygen Plant
About 85 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.
There should normally be no other liquid or solid effluents
generated in the oxygen plant. However, if a refrigerant, such as ammonia,
is employed in the refrigeration loop, facilities for disposition of
such material will be required at intervals.
4.11.2 Sulfur Plant
Elemental sulfur make is about 140 tpd from the Stretford
plant. Sulfur purity may be quite high, and product may be made
available in solid or molten form, so that marketability should be
high.
Sulfur recovery systems based on sodium, as in the Stretford
system, require that the rhodanic salt resulting from the capture of
cyanogen in the absorbent liquor, and thiosulfate and sulfate salts
-------
resulting from oxidative side reactions, be continuously removed, and
fresh alkali supplementeds to maintain recovery efficiency. The waste
liquor withdrawn is very high in chemical oxygen demand, and is generally
incinerated. The COD of this waste stream may be lowered by adding
enough sodium to change the whole sulfur content to sodium sulfate prior
to incineration. However, caustic requirement for this facility might
amount to about a ton per hour.
An incineration process (51) has been developed to incinerate
such waste liquor with a gas fuel under reducing conditions, such that
sodium salts are decomposed to carbonates which may be captured and
returned to the Stretford system. This process results in zero liquid
or solid effluent, but is high in energy cost and investment.
4.11.3 Power and Steam Generation
The largest solid effluent stream from the boiler will be
ash. Ash in the coal feed to the gasifiers amounts to about 1050 tpd.
Most of this material is removed from the gasification train with
char and, if char is burned as fuel in the power plant, this same ash
will be discharged at the boiler. There will be small ash "losses"
to tar, and ash will otherwise appear in raw gas and in scrubbing
liquors and condensates.
The quantity of ash discharged from the boiler will of
course depend on the degree of efficiency with which the fuel (char)
is combusted. Hence, a carbon combustion efficiency of 96 percent
would increase the ash rate about 10 percent above theoretical.
Similarly, it is not now known what the composition of such ash may be
otherwise, especially with regard to sulfur content and to particular
toxic trace elements which may affect the costs for ultimate disposition
of this material. It is now considered that ash effluents would be
buried in a mine in a manner that would minimize subsequent adverse
environmental impact.
If limestone is used to treat flue gas to limit S02 emissions,
about 150 tpd of sulfated lime will be generated. Long-term disposition
of such material is likewise uncertain. It may ultimately be required
that sulfur be recovered, as by regeneration of the sulfated material.
4.11.4 Cooling Water
A variety of chemical additives may be used to treat water
circulated in the cooling 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
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- 50 -
to precipitate or neutralize specific toxic elements, such as chromium
or zinc, before being directed to further treatment.
As indicated above, there may be particular problems associated
with leakage into the cooling water system from the high-pressure
gas processing train. In general, however, such leakage would be
expected to add to atmospheric emissions at the cooling towers, with only
trace quantities of condensable liquids or solids appearing in the
cooling water circuit.
4.11.5 Miscellaneous Facilities
A variety of materials is indicated to be required to treat
waste water effluents, including milk of lime, 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 residuals1 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.
4.12 Maintenance
Normal plant operations will require the periodic replacement
or replenishment of catalysts and other chemical agents used to process
coal and gas. Such maintenance will generate contaminated solid and
liquid effluents, including shift catalyst, Benfield solution, methanation
catalyst, activated carbon, iron 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.
Operation of start-up heaters will generate solid or liquid
effluents consistent with the fuel consumed. Hence, if coal is fired,
ash and stack treatment effluents may be accumulated, and subsequently
directed to the operating plant's normal treatment routing.
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- 51 -
5. THERMAL EFFICIENCY
The efficiency with which energy is utilized ranges from less
than 5 percent for the ordinary incandescent lamp to perhaps 75 percent
for a well-maintained home heating furnace. The automobile engine has
an efficiency of less than 20 percent. Modern fossil fuel power plants
are not more than twice as efficient. On the average, probably less than
35 percent of the available heat in fuels consumed in the United States
is recovered usefully (52).
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 economic and ecologic factors associated
with process improvement or increases in efficiency. In large measure, such
costs may be related to the technological state of an art. Hence,
it is unlikely that more efficient methods for converting energy
to visible light will find widespread use until a device that is as
convenient, inexpensive, and reliable as the incandescent lamp
is developed.
In the case of fossil fuel conversion processes, the thermal ef-
ficiency is calculated as the ratio of the heating value of product(s) to
the heating value of the (coal) feed. In the present design, the higher
heating value for coal feed, based on the analysis given for Pittsburgh
seam coal as fired to the gasifiers (10), has been estimated by conventional
formulas to be approximately 13,700 Btu per pound, which is at variance
with the heating value reported. Product gas is indicated to have a higher
heating value of 927 Btu per scf, a value consistent with its analysis.
Similarly, a thermal credit of 130,000 Btu per gallon is taken for recovered
tar, which is considered a saleable product. On this basis, a base thermal
efficiency of 63-5 percent is indicated (See Table 6). Since tar
is not a "clean" product, we note that its thermal value should
be discounted in the event that it is not marketable as such.
The basis otherwise assumes that char may be completely combusted
to balance the plant's steam and power requirements. If, for example, a
carbon combustion efficiency of only 96 percent is achieved in the char
combustion process, the shortfall would be equivalent to about one percent
on feed coal, so that overall efficiency would drop about the same amount.
We have assumed that a carbon combustion efficiency of 100 percent will
be achieved•
The design basis (10) does not include specific allowance for
treatment of scrubber effluent. The Bureau of Mines design (48) for waste
water treatment, including scrubber effluent, requires the energy equivalent
of 2.6 percent of gasifier feed coal for its operation, in addition to an
-------
52 -
incremental 24,000 gph of raw water which must be upgraded to boiler
feedwater. If this energy requirement were to be generated
by burning coal or tar along with char in the powerplant, so that additional
desulfurization of flue gases or its equivalent would be required, overall
process efficiency would be reduced about four percent below baseline.
However, credit might then be taken for the heating value of separated
ammonia, amounting to about 0.8 percent of feed coal equivalent.
Although recovered tar should be valued higher than feed
coal for the purpose of supplying the volatile component that may be
required to achieve stable char combustion, such tar would be combusted
if it could not be marketed. Combustion of all of the tar would balance
the utility load estimated for waste water treatment.
As discussed in Section 2.7, the base design does not include
distinct facilities for separation of oils, naphtha, or phenols. It
has been estimated that about 25,000 gpd of B-T-X may be produced (47),
in addition to 60,000 gpd of tar oil and 15,000 gpd of crude phenol in
a plant of this size, although it must be emphasized that the exact
quantities of these materials which may be extractable from gasifier
output will be distinct functions of the composition of feed coal and
of the particular conditions of the gasification. We estimate the thermal
efficiency debit associated with the removal of hydrocarbon, including
crude distillation, will be about equal to the thermal credit for the
separated material.
The design basis does not include specific provision for drying
feed coal. If moisture content of feed coal had to be reduced an incremental
five percent due to moisture accumulation on storage, the thermal require-
ment amounts to about 0-5 percent of the feed coal. We believe that flue
gas from the utility boiler may be used to effect such drying, avoiding
this energy debit (See Section 2.1).
Similarly, substitution of a Stretford sulfur recovery system
for a direct oxidation Glaus plant will significantly increase utility
requirements associated with sulfur recovery, but the effect on overall
efficiency is minor, on the order of 0.2 percent.
As discussed in preceding sections, there are numerous opportunities
in the proposed system which a designer may consider for energy recovery
or energy reduction. In all such cases, the potential energy benefit must
be weighed against the costs associated with such recovery, including not
only investment, but also factors associated with operability, increased
processing complexity or decreased overall reliability, and potential
hazards. In many cases, the technology is not straightforward, so that
additional research and development will be required. Obvious areas
for such investigation include the methods for feeding coal to the gasifiers
and for extracting char, and the potentials for energy recovery in the
dust removal and gas purification systems as proposed.
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- 53 -
We have estimated that more than 300,000 pounds per hour of high-
pressure steam may be generated if a tar scrubber can be applied to gasifier
output (Section 2.4). Further, 300,000 pounds per hour of low-pressure
steam may be additionally generated in subsequent water scrubbing/cooling
of raw gas, simultaneously reducing cooling water load and the associated
energy debit.
Similarly, we have estimated that 100,000 pounds per hour of
high-pressure steam may be generated in the char let-down process, or
that the bulk of the sensible heat of char may be conserved if a dry
char let-down process is developed.
If air-fin cooling is substituted for cold water exchange as
outlined in Section 3.3.2, the net energy debit is estimated at about 1.5
percent, but net water loss in the cooling water circuit can be reduced
by more than half.
Finally compression energy required to deliver final product gas
to commercial pipelines is conserved in the Synthane system by operation of
the gasification train at essentially pipeline pressure. It may be
desirable to consider operation of the system at some reduced pressure.
Hence, operation at the 600 psi level would bring much of the required
hardware within the realm of commercial experience and safety codes, such
that development lead times and potential process hazards may be consider-
ably reduced. The final gas compression debit in this case should amount
to no more than about one percent on overall efficiency. Such consideration,
of course, must also weigh factors related to the effect of pressure on
gasifier output and to required reaction volumes- Additional development
will be required before this effect can be properly assessed .
-------
Table 6
THERMAL EFFICIENCY
Equivalent Thermal Efficiency as
Bureau of Mines Svnthane Design Basis (10): quantity MMBTU/Hr Percent of ca,65° 59<3
Sulfur (TPH) <+Wi.- 630 3.9
5.7 /.s « -,
- Equivalent Coal Feed (TPH) 15.24
130
- Hydrocarbon Removal and Distillation ,,c
115
, nnn
1UUU 130
63.5
Bureau of Mines Water Treatment Base Case (481
-2.6
60.9
Estimated Effects of Additions and Modifications
- Incremental Flue-Gas Treatment, Sludge Dewatering
and Handling, Boiler Feedwater Treatment, Ash
Handling Associated with Power and Steam Generation
for Waste Water Treatment-
220 -!.3
+ Produced Ammonia (TPH) , ,
6.6
60.4
-0.7
+ Produced Hydrocarbon (GPH)
60-5
- Stretford Sulfur Recovery Substitution
For Claus Plant
35 -0.2
60.3
- Product Gas Loss in Acid Gas Removal
50 -0.3
60.0
+ Steam Generation in Tar Scrubber ,-, „
540 +3.3
+ Steam Generation in Water Scrubber and Credit
for Cooling Water Reduction, Less Energy
Associated with Scrubber Operation and Steam
Production. 300 +l^
+ Steam Generation in Char Let-Down 150
66.0
- Air-Fin Substitution for Cooling Water 250
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- 55 -
6. SULFUR BALANCE
The sulfur balance for this design (see Table 7) has been
estimated using a variety of sources (11,33,47) along with.the design
basis (10). The analytical results reported by the Bureau of Mines
for various laboratory gasification experiments for Pittsburgh
seam coal are not necessarily mutually consistent with the design
basis. However, the estimate is reasonable if reported values for
organic sulfur levels in raw gas are assumed (47)•
Approximately 60 percent of the sulfur in the gasifier coal
feed appears as H2S in the gasifier output (10). Essentially all
of the sulfur in this form, including that portion dissolved in
aqueous condensates, may be recovered as saleable elemental sulfur
product. Depending on relative economics, the concentration of H2S
in the C02 stream separated at the sulfur plant may be reduced
to less than 5 ppm, so that it may be practicable to dispose of
this stream by passing it up the stacks of the main boilers.
Nearly 30 percent of the incoming sulfur is retained in
the gasifier char in this case. It is probably not reasonable to
expect that all of this sulfur will be oxidized in the char combustion
process- We have arbitrarily assumed 96 percent conversion to SC>2
(equivalent to about 0-25 percent sulfur in final ash). The flue
gas scrubber on the char boiler will be required to remove at least
6100 pounds per hour of S02, so that less than 4800 pounds per hour
may issue to the atmosphere in the scrubbed flue-gas stream. If lime-
stone is used in the scrubbing system, some 12,300 pounds per hour
of sulfated lime will be generated at theoretical conversion.
In practice, the quantity of limestone required and the amount of
solid residual produced may be half again as much (13,71).
Concentrations of organic sulfur compounds in raw gas
reported for Synthane gasification of Pittsburgh seam coal (47)
appear quite low, especially with regard to carbonyl sulfide. How-
ever, it may be assumed that COS and mercaptans present in gas sub-
jected to catalytic shift conversion will be hydrolyzed to H2$ and
C02> so that organic sulfur will be thereby reduced by half (in
the shift by-pass stream). Moreover, depending on the scrubbing
procedures used to treat raw gas before shift conversion, or to
extract naphtha or oil components from the gas stream, more or less
of the organic sulfur compounds may be diverted to other streams.
Research relating to the Benfield acid gas removal process
(74) indicates that COS removal in commercial systems ranges from
75 to 99 percent,mercaptan removal ranges from 68 to 100 percent,
and disulfide removal ranges from 71 to 85 percent. And 85 percent
removal of thiophene has been reported for a commercial installation,
although this effect runs counter to expectation or to laboratory
test results. In general, most of such absorbed sulfur would
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- 56 -
appear as H2S in regenerator off-gas- Undesirable reaction products
(sulfates, thiosulfates, thipcyanates, polysulfides) appear to accumulate
in the activated hot carbonate solution only to a limited and
acceptable extent. Hence it would appear that organic sulfur levels
would be reduced by at least 70 percent on average in the Benfield
system. Such compounds which persist beyond this point would be
removed in the sulfur guard beds preceding methanation.
Sulfur which is present in aqueous condensates collected
from the gas processing train will undergo varying treatment in the
waste water treating plant depending on the overall quality of the
particular stream. l^S which separates on depressurization of such
streams, or which issues from the ammonia recovery system, will be
directed (along with C02) to the sulfur recovery plant. Although it;
is not possible to designate how much sulfur may be sprung to
atmosphere in aeration/oxidation facilities which may be provided
for water treatment, very close control of such emissions will be
required. Hence, the bulk of dissolved sulfur will issue generally in
calcium sludges or in chars (activated carbon) from the treatment
plant. These accumulated residuals would be de-watered and fed to
the main char boilers for incineration.
The concentration of sulfur in tar separated from the gas
stream is estimated, on the foregoing basis, at about 2.5 percent
This is higher, by a factor of three, than the results obtained in'a
reported laboratory gasification (47). However, the distribution of
sulfur among the various component sub-streams issuing from the
gasifier has been shown to be primarily a function of coal feed com-
position and of gasification conditions, and may be further influenced
by the manner in which the streams are separated.
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- 57 -
Table 7
SULFUR BALANCE
Lb/Hr
Percent
In Feed Coal
19,000
H S Converted to Sulfur Product 11,400 60-0
Char From Gasifier 5,435 28.6
M •
Final Ash 210 1.1
As SC"2 in Flue Gas 2,290 12.1
As Sulfated Residual from Flue-Gas Scrubber 2,935 15.4
Organic Sulfur in Raw Gas*
(Thiophene, Mercaptan, Sulfides)
Hydrolyzed in Shift Converter
Hydrolyzed in Benfield
Sulfur Guard
165
80
55
30
0.9
0.4
0-3
0.2
Total Sulfur in Aqueous Condensate*
Recovered as H2S
Oxidized/Released to Atmosphere
As Sludge to Incineration
935
270
100
565
4.9
1.4
0.5
3-0
Tar (By Difference)
1,065
5-6
100.0
* Estimated per Reference 47
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- 58 -
7, TRACE ELEMENTS
Trace elements are usually defined as those elements present to
the extent of 0. 170 (1000 ppm) or less. Nearly all trace elements show an
enrichment in coal ash relative to their crustal abundance (53). 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 (12).
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 64,55,56). 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, so that 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 (57). 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, in-
cluding the large number of components, the imprecision of available sensors
or test methods, and the difficulties associated with representative sampl-
ing 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 Synthane gasification has been described by the Supply-
Technical Advisory Task Force (58). At this point it is generally con-
sidered that gasification will present no insurmountable control problems.
On the other hand, it is seen that considerable research will be required
to establish practical and economical control procedures.
-------
- 59 -
Trace elements which have been detected by the Bureau of
Mines in condensate from the laboratory Synthane gasifier are shown
in Table 8 for an Illinois No. 6 coal (47). Similarly, toxic trace
elements which have been found in Synthane raw gas and tar are shown
in Table 9,
Literature values (12) for the elemental composition of
Pittsburgh seam coals are presented in Tables 10 through 12 . Reported
values may of course not be representative of a particular poal; but
in many eases, element levels are remarkably consistent in a particular
region.
Table 10 lists the major elements in coal (exclusive of
C,H,0,N). On the basis that reported values may apply to the feed
coal in the present design, we have calculated the quantity of each
element which daily enters the process vj.a the gasifiers. Similarly,
for the purpose of comparison, we have calculated the quantity of each
of these elements which would appear in the condensate from raw gas
if reported values (47) were to apply to the present design. Obviously,
we would expect the bulk of these materials (other than sulfur) to
exit the process via the ash residual from char combustion. But the
elements vary widely in the form in which they appear in coal and in
their reactivity, volatility, and solubility otherwise.
Table 11 similarly lists some of the minor or trace elements
in feed coal. It should be emphasized that concentrations of some
of these elements can vary by factors of ten or more within a region,
and that analytical methods employed by researchers have had high
or unmeasured inherent imprecision in many cases. Reported values may
also suffer frpm bias in some cases, in that analyses were performed
on coals which were known to contain high concentrations of particular
elements; and the original intent of the analyst has not always survived
reprinting of his data.
HCN, mercury, and arsenic have been detected in raw gas and
in tar from Synthane gasification by the Bureau of Mines (47). These
materials are listed in Table 12, a tabulation of some of the hazardous
trace elements in coal prepared on the same basis as the preceding
tables. For these elements especially, it will be important to close
the material balance. Recently reported studies indicate the difficulty
associated with the attempt to follow mercury, for example, throughout
a commercial coal-fired utility installation. But the state-of-the-art
of detection is bound to progress rapidly as attention is focused on
particular elements through legal sanctions, and as coal processes
proliferate.
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, even including the
conditions of gasification. For Synthane, this will require additional
research firstly to define the levels of these elements through the
-------
Ca
Fe
Mg
Al
Se
K.
Ba
P
?n
Mn
Ge
As
Ni
Sr
Sn
Cu
Nb
Cr
V
Co
- 60 -
Table 8
TRACE ELEMENTS IN CONDENSATE, FROM AN'
ILLINOIS NO. 6 COAL-GASIFICATION TEST (47)
No. 1
4.4
2.6
1.5
0.8
401
117
109
82
44
36
32
44
23
.33
25
16
7
4
4'
1
No. 2
3.6
2.9
1.8
Q.7
323
204
155
92
83
38
61
28
34
24
26
20
5
'8
2
2
Average
(by wt)
4 ppn)
3 ppm
2 ppm
0.8 ppm
360 ppb
160 ppb
130 ppb
90 ppb
60 ppb
40 ppb
40 ppb
30 ppb
30 ppb
30 ppb
20 ppb
20 ppb
6 ppb
6 ppb'
3 ppb
2 ppb
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- 61 -
Table 9
TRACE COMPONENTS IN RAW GAS* AND TAR (47)
COAL FEED RAW GAS TAR
HCN Hg Hg As
ppb by vol. ppm fry vol. ppm by wt. ppm by wt.
111. Char 5 r .
111. #6 Coal 20 Q.00001 0.003 0.7
W. Kentucky 11 - -
N. Dak. Lignite 3 - -
Wyoming Sul?-Bit. 2 -
It is indicated that no mercury or HCN was detected in product gas.
-------
- 62 -
Table 10
MAJOR ELEMENTS IN COAL
Si
Fe
S
Al
Ca
K
Mg
Na
Concentration
in Feed Coal
(Wt. %)
4.0
1-5
1.6
1.0
0.5
0.22
0.17
0.06,9
In Feed to
Gasifier
Ib/day
1,140,000
428,000
456,000
285,000
142,500
62,700
48,500
19,700
Concentration in
Condensate (47^
(ppm)
3
1400
0.8
4
0.16
2
- ••—
Discharge to
Water Treatment
Ib/day
--
50
22,500
13
65
3
32
-------
- 63 -
Table 11
MINOR TRACE ELEMENTS
In Feed
Goal
B
Ba
Zn
V
Li
Gr
Ni
Ge
Cu
Mn
Mo
Y
La
U
Co
Sn
ppm
165
100
44
35
25
22
14
12
12
10
8.2
7.7
5.1
5
3.8
1.5
Ib/dav
4700
2900
1250
1000
710
620
400
340
340
290
230
220
150
140
110
43
In
Condensate
ppm (47)
__
0.13
0.06
0.003
--'
0.006
0.03
0.04
0.02
0.04
—
—
--
—
0.002
0.02
Ib/day
.2
1
0.05
--
0-1
0.5
0.6
0.3
0-6
--
—
--
-1-
0-03
0.3
-------
- 64 -
Table 12
POTENTIALLY HAZARDOUS TRACE ELEMENTS
Be
F
As
Se
Cd
Hg
Pb
HCN
In
Feed
Coal
2
85
31
2.2
0.14
0.2
7.7
-
To
Gasifier
Ib/dav
60
2430
880
65
4
6
220
-
(PPM)
Condensate Raw Gas* Tar
-
-
.03 (.5)** - 0.7 (.7)
•36 (6)
-
.0001 (.04) .003 (.003)
—
20 '(1000)
* No Hg or HCN detected in product gas.
** Numbers in parentheses indicate quantities in pounds per day
appearing in design streams.
*** Units as given in Reference (28).
-------
- 65 -
process sequence for particular feed coals at preferred gasification
conditions. A preliminary study of this type has been reported for
the Hygas bench-scale unit (59) . Additional research may then be
required to indicate specific modification of the process sequence
to remove or contain these materials or to adequately plan effluent
treatment facilities.
It would appear, on the basis of results published thus
far, that Synthane gasification does not appear to introduce new
control problems. Rather, since the gasification train and water
loops,including run-off,may be designed to be largely self-contained,
emphasis of the controls development will be directed to flue gases
and ash from the combustion process that powers the system, to the
gas residual from acid gas treatment, and to the concentrated residuals
from waste water treatment. 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
Synthane gasification.
-------
- 66 -
8. PROCESS ALTERNATIVES
Most of the process alternatives which we have considered in
connection with the particular design chosen as the basis for this report
will require additional research, development, and/or evaluation. Some
would change or diffuse the character of the process. Operation of the
process at a lower pressure, for example, would influence all aspects of
the design and each such aspect would have to be evaluated for its effect
on the total design, including investment and costs. On the other hand,
most of the laboratory results published thus far relating to this process
have been obtained at pressures considerably below the 1000 psi level, so
that extrapolation to high pressure has already introduced a measure of
uncertainty. The primary process considerations which may be affected by
pressure include gasification rates, raw gas composition, dust removal
operations, and acid gas removal. In fact, there are so many such inter-
related considerations which may affect the overall efficiency, cost and
pollution potential, that it is not particularly useful to extend analysis
in the absence of real data. Operation of a prototype plant over a
range of pressures should ultimately resolve this question.
Similarly, the use of a high temperature gasification process
to gasify char and tar separated from the Synthane train to produce a
clean fuel for power generation, and so avoid flue-gas desulfurization,
appears now to be viable processing alternative. On the other hand, there
is bound to be further development of desulfurization processes, and a
continuing redefinition of applicable standards, as well as development
Of combustion processes for chars and tars, so that constraints which
face the ultimate designer may be substantially different from those that
now appear,,
Other processing alternatives which suggest themselves include:
o Use of a tar scrubber as a first element in the
dust removal operation. Incentives include
reduction in water treatment loads and thermal
efficiency credits.
o Alternative facilities for adjusting gas composition
ahead of methanation, including the possibility of
auxiliary coal gasification for this purpose.
Gasification of char and/or tar to produce a
hydrogen-rich gas may also be attractive.
-------
- 67 -
o Use of extraction processes to remove phenols, for
example, from scrubber effluent.
Even if particular alternatives are evaluated at a given stage in a process's
development and found to be marginal, it may be necessary to re-evaluate
these same options at a later stage as basic data are firmed. Hence, the
development of alternatives continues, even through the life of a commercial
plant.
Table 13 lists some of the alternatives considered in connection
with the base design.
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- 68 -
Table 13
PROCESS ALTERNATIVES CONSIDERED
Coal Drying
o Coal-fired vs^ use of boiler flue gas.
o Lime-scrubber vs_ electrostatic precipitator or bag filters-
o Flash drying in ball mills.
Gasification
o Variations on lock-hopper coal charging operations-
o Char let-down process variations.
o Operation at lower total pressure.
Dust Removal
o Inclusion of tar scrubber and internal gasifier cyclones vs_ external
cyclones and water scrubbing.
o Inclusion of facilities to remove middle and light oils from prqduct
gas-
Shift Conversion
o Alternative means for adjusting gas composition ahead of
methanation.
o Improvements in shift conversion processes.
Acid Gas Treatment
o Use of Stretford process vs_ Glaus plant and tail-gas cleanup.
o Inclusion of facilities to convert organic sulfur to H2S and to
treat Stretford blow-down.
Utilities
o Alternative fuel choices for power and steam generation.
o Waste-water treatment variations, including use of process char
and oxygen or ozone. Use of extraction for phenol removal-
o Maximum air-fin usage vs cooling water for heat rejection.
-------
- 69 -
9.. ENGINEERING MODIFICATIONS
Engineering modifications that may be advantageous will occur
to the detail designer„ Obviously, these cannot be divorced from
process considerations, but rather will reflect an attempt to optimize
energy utilization or reduce investment or operating .cost within process
constraints.
As discussed above, operation of this process at high pressure
on a commercial scale will involve development of hardware that is
currently non-existent. While reaction volumes are small, wall thick-
nesses are large and stresses are high, so that vessel costs and operating
hazards may not be optimum. The engineering, design, and operation of
this system will be considerably simplified if operating pressures are
substantially reduced, based on current technology. On the other hand,
this is not seen to imply that technology should not be extended, or that
engineering considerations should prevail over processing benefits that
may be seen for operation at high pressure.
A number of engineering alternatives involve integration of
facilities. The net increase in thermal or material efficiency that may
result must be balanced, in general, against increased process complexity
and/or costs or reduced operating reliability. Hence, the use of
hot flue gas from the utility boiler to dry feed coal has been
incorporated into our design. On the other hand, this alternative
constrains the relative placement of the coal drying and boiler
facilities, and the start-up and operation of these facilities
is made more complex, involving inter-related controls.
Similarly, attempts to minimize energy requirements for com-
pressing lock-hopper gas that depend on the scheduling of gasifier opera-
tions must be assessed on the basis of potential for decreased overall
reliability or the slowing of overall operation.
The location of a given facility within the total plant may be
optimized on the basis of one or more major considerations, but will in
general prove non-optimum from other viewpoints. Hence the air intakes
for the oxygen facility might be located to minimize interference from
plant effluents. But it will also be desired to minimize piping and
hardware required to deliver oxygen to the gasifiers.
Incentives for other modifications will depend on future process
development. There would now appear to be considerable incentive for
energy recovery on depressurization of scrubber effluent. This
processing sequence will almost certainly be improved in the
course of future research.
-------
- 70 -
A major modification that deserves attention, as with most
preliminary gasification designs, is the general substitution of air
fin cooling for the use of cooling water. This may prove especially
important in this case, since the high operating pressure increases the
possibility of leakage into the cooling water system and subsequent
emission at the cooling towers. Again, basic economics and the designer's
ingenuity will dictate whether, and to what degree, such substitution
may be practicable.
Table 14 lists some of the engineering modifications considered
in connection with the base design.
-------
- 71 -
Table 14
ENGINEERING MODIFICATIONS CONSIDERED
Coal Drier
• Use of limestone scrubber to treat boiler flue gas drying medium.
Gasification Train
• Operation at lower pressure.
• Treatment of depressurized gases and condensates.
Dust Removal
• Power generation on depressurization of scrubber effluents.
• Steam generation in cooling raw gas.
Acid Gas Removal
• Power generation on depressurization of scrubber effluent,
Methanation
• Provision for limiting CO in product gas.
Utilities
• Air-fin substitution for cooling water.
• Containment of run-off and inclusion in plant water balance.
-------
- 72 -
10. QUALIFICATIONS
This study is based on the process design (Figure I and Tables 15-17)
supplied by the process developer (10,48), with modifications as discussed
and shown in Figure 2 and Table 1. Costs or economics were not considered
except dj.rectionally. Although it was not always possible to resolve
process details with assigned energy or mass consumptions, overall assignments
are considered reasonable and consistent with the data obtained at the
laboratory level (8,11,22).
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.
Considerable 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.
-------
- 73 -
Tgble 15
COAL AND PRODUCT ANALYSES
Pittsburgh Seam
Coal Feed to Gasifier (10)
c
HO
2
NO
2
So
2
00
2
Ash
Moisture
HHV
Wt. Per Cent
73.8
5.2
1.5
1.6
8.0
7.4
2.5
13,700 Btu/lb
Product Gas to Pipeline
Mol Per Cent
H2 3.6
CO 0.1
C02 3.7
CH4 90.4
N2 2.1
H20 ' 0.1
HHV 927 Btu/scf
-------
-Table 16
Unit
Coal preparation
Gasification
Dust removal
Shift conversion
Waste heat recovery
Purification
Methanation
Pipeline compression
Oxygen plant
Sulfur recovery
Subtotal
Steam plant
Powerplant
Utilities:
a. cooling water
b. plant lighting
c. sanitary water
General facilities
Miscellaneous and
contingencies
Total
Steam
1,000 psia
-------
- 75 -
Table 17
COAL AND PRODUCT QUANTITIES AND HEAT CONTENT
Coal Consumption
Equiv.
TPH MM BTU/Hr
Coal to Gasifiers (10) 593.75
16,270
Equivalent Coal to Utility 15.24 420
Boiler for Water Treatment (48)
609.0 16,690
Products and Equivalents
Product Gas (MM SCFH) 10.41 9,650
Tar (gph) 4849 630
Sulfur (tph) 5.7 45
NH (tph) 6.6 130
B-T-X (gph) 1000 130
10,590
-------
-ye-
ll- RESEARCH AND DEVELOPMENT NEEDS
The Bureau of Mines, as developers of the Synthane Process,
have, with The Lummus Company, designed a versatile pilot plant now
under construction, which is geared to the determination of many of
the basic data which will be required to design a commercial plant.
The following paragraphs discuss research and development needs that
bear on the efficiency and/or pollution potential of the process.
Paramount among the research needs will be demonstration of
the operability of the integrated gasification system. Hence the following
operations must be demonstrated simultaneously in a continuous manner:
o Coal Feeding, involving lock hopper operation
o Coal P re treatments, involving fluidized bed operation
o Gasification, involving fluidized bed operation
o Char Let-Down, involvfing continuous withdrawal from
a fluidized zone and lock hopper operation
Achievement of operability in the prototype pilot plant will almost
certainly involve developmental modifications.
Equally important will be the determination of basic gasification
parameters on gas composition and gasification rates, including the
effects of:
o Feed Coal Properties/ Pretreatment
o Total Pressure
o Temperature
o Steam/ Oxygen Ratios
o Carbon Conversion
Perhaps the most important aspect of this program will be the data which
may be used by the designer of the commercial gasification system to
optimize gasifier total pressure. Investment and operating costs for
each component of the total system, including auxiliary facilities, will
be affected by the gasification pressure level, as will the overall thermal
efficiency and pollution potential of the process. Detailed parametric
analysis based on data to be obtained at Bruceton should point the way
to an optimum design.
The third major objective of the pilot plant program
involves the ultimate selection for development of one of the two novel
Bureau of Mines methanation processes, Tube Wall Reactor (TWR) or Hot
-------
- 77 -
Gas Recycle (HGR), both of which have been included in the prototype unit.
This selection will evolve from operations on a much larger scale
than heretofore, and over a broader total pressure range. These results
may significantly affect process thermal efficiency.
Obviously, initial effort in the pilot plant program will
be heavily weighted toward achievement of primary goals. It was considered
that such achievement must precede secondary developments that may be
required to commercialize the process. Included among such developments
are:
o Development of a char-burning boiler
o Optimization of "dust removal" from raw gas
There is indicated to be no facility provided in the prototype plant for
char combustion studies. From some points of view, this may be considered
a serious deficiency. However, there are a number of coal conversion
processes undergoing development which produce similar chars, so that
progress in char conversion and combustion may be otherwise expected.
Moreover, as has been already discussed, unless significant progress is
shown for flue gas desulfurization, it may prove more attractive to gasify
char, bypassing combustion development entirely. It will of course remain
to be demonstrated that Synthane char may be gasified, but this is now
considered to be a low-risk option.
The problem of raw gas treatment, on the other hand, is
not nearly so straightforwardo There will be processing constraints
on the quality of gas that may be admitted to shift conversion and
subsequent gas treating operations^ as these processes are now
visualized„ Hence reliable operation of the catalytic shift
converter and of the Benfield acid gas removal process, both of which
have been included in the prototype plant, may prove the best
yardstick for judging the efficacy of dust removal.
Apart from processing constraints, the method of raw gas
treatment may have significant impact on overall efficiency and on
the pollution potential of the process.. Hence the degree to which
gas must be cooled to effect clean=up and the particular procedures
employed will translate to energy and water requirements and, specifically,
to the quantities of "contaminated" streams that must be further
processed for economic or ecologic reasonso The prototype plant
has been provided a flexible gas scrubbing system which should point
the way to a practicable design. We have also suggested a variation
on this design, incorporating a tar scrubber as the leading element
in the dust removal operation. This device has been commercially
proven for petroleum fluidized bed coking operations, but at
generally less severe operating conditions than will be required here.
We see considerable incentive for the development of this or some
similar technique, however, which avoids or reduces the thermal
and pollution debits of the aqueous scrubber.
-------
- 78 -
It is unfortunate that it is not possible a priori to specify
the exact quantities and nature of materials which will have to be
removed from raw gas. These will depend as much on the conditions of
gasification as on the properties of the particular feed coal. It is
similarly not possible to pre-judge how variation in pretreatment or
gasification parameters may affect such residuals. Hence the approach
taken in the pilot plant program, which will firstly optimize the
gasification on the basis of primary yields, appears to be a logical choice
Moreover, successful operation of the pilot plant will mean that
particular requirements for at least one practicable system will have been
established.
It is presumed therefore that future or secondary developments
will:
o Optimize raw gas treatment on the basis of overall
thermal efficiency. Research efforts may be directed
to "hot gas" clean-ups to improved shift conversion
catalysts or proceduress or to alternative means for
adjusting hydrogen content before methanation.
o Optimize raw gas treatment on the basis of pollution
potential. Obviouslys these developments cannot be
divorced from each other, or from the primary requirement
to deliver a clean product gas. Research may be directed
to procedures for neutralizing or recovering materials
from "contaminated" streams generated in the clean-up
process, or to operations on the main gas stream. Specific
problems may include the dephenolization of aqueous
scrubber streams, or the removal of HCN, thiophenes, or COS
from the main gas stream or from the acid gas separated
by the Benfield system.
The pilot plant will also permit evaluation of the Ben-
field acid gas removal process over a broader pressure range than
heretofore. A better definition of the kinds of treatment that may be
required for both the main product stream and for the acid gas that is
separated should evolveo Moreover, the inclusion of a Stretford
scrubber in the prototype plant should serve to flag any unwanted
interactions between the acid gas removal and sulfur recovery processes,
again establishing the basis for a practicable commercial design.
On the basis that successful operation of the pilot
plant will be achieved, it will thereafter be possible to investigate
any aspect of the process to any desired degree of precision., On the
other hand, in the current domestic energy framework, a decision to
commercialize may be required before all research or optimization studies
can be completed. It may be important finally only to know that the
process is workable, that efficiency is reasonable, and that adverse
environmental impact is within reasonable tolerances. The questions
relating to environmental impact may be the most difficult to resolve
quicklyo
-------
- 79 -
The concentrations of residuals in processing streams that
may bear on environmental impact can be very low« Even at the greatly
expanded prototype plant scale (relative to previous laboratory-
scale), it may not be practicable to resolve all possible problems.
It is considered that:
o Special effort should be made in connection with the
earliest operations of the prototype pilot plant to
instrument or to otherwise provide for analysis of
trace components known to be toxic or undesirableo
Routine analytical methods for many trace elements
and compounds are not available, and must be developed.
In many cases, sophisticated laboratory procedures
only may be applicable, and precision is poor.
Commercial plant magnitudes will be 200-300 times
greater than the prototype plant scale, so that
judgements relating to commercial design could easily
be misdirected.
o The varying composition of coals and the difficulties
associated with representative sampling of solid streams,
makes it extremely difficult to obtain balances for trace
elements around coal operations. The multiphase nature
of the output streams from many coal conversion
processes or treatments adds to the general problem.
And representative sampling becomes more difficult for
any stream as the stream size increases.
The proper interpretation of prototype pilot plant results
will be greatly simplified if clear balances are shown
around processing equipment. Sampling systems should be
designed to permit such balances to be generated with a
high degree of confidence. Special effort should be
directed to sulfur in all its forms, HCN, arsenic, mercury,
cadmium, and metal carbonyls.
o Because the Synthane process generates char which
exhibit many of the desirable properties of activated
carbon and because incremental oxygen should be available
from the Synthane oxygen plant at relatively low cost,
we consider that early research directed to the use
of these materials for treatment of Synthane effluents
may lead to greatly simplified pollution control systems
for water and gas loops. Hence research may be directed
to the use of char in fixed- or fluidized-bed units
to treat gas streams, including the main product s.tream
(65), or to treat liquid effluents, especially waste
water streams, for the removal of specific constituents.
In general, the use of char for pollution control would
be viable only if it could be demonstrated that flue
gases from the subsequent combustion of contaminated
-------
- 80 -
char were compatible with standards for atmospheric
discharges, or could readily be treated to make them
so. It would not, for example be particularly useful
to take COS from one stream and discharge it to the
atmosphere in another. Hence additional research,
which should be coupled with the char combustion
development, would be required to demonstrate overall
effectiveness.
Similarly, the use of oxygen or of ozone, especially
for the oxidation of contaminants in waste water,
warrants attention. Direct oxidation using these
materials is advantageous in many cases because
residuals which form when other oxidants such as
chlorine are used are avoided. Moreover, oxidative
reactions which go slowly or not at all with air
frequently go rapidly with ozone or oxygen, so
that the sizes of treating facilities and treat
times are reduced. Such oxidation does introduce
questions relating to corrosion, toxicity, explosive
hazard and relative costs, all of which factors may
be inherent in any treatment method, but which can
be assessed in the research program.
Finally, there is a growing need to conduct research
related to toxic or noxious materials that is not
specific to Synthane gasification, but which relates
to all fossil-fuel utilization. Obviously, toxic
elements which enter a process must concentrate or
exit the process at some point. Not only are the
quantities discharged important, but so also must
be the form in which such discharged materials
appear. There is hardly any form or compound of
mercury, for example, which may not be considered
toxic or hazardous in some sense. But there are
obviously relative degrees of toxicity associated
with its various compounds, and work is required
to define these least toxic forms, as well as to
develop technology for conversion to desired
forms within the process framework. A more realistic
approach to control of some elements or compounds
which cannot be effectively concentrated or extracted
from effluent streams may be their conversion to
the least objectionable forms in such streams.
-------
- 81 -
Zero direct discharge to atmosphere or to waterways
may be technologically possible within the gasification
process battery limits, but the desired objectives
will not be achieved if discharged ash, concentrated
sludges, or solid streams contaminate the environment
at some later time. The magnitude of this problem
is very great, but so also is the combined effort
which may be brought to bear by affected industries,
consumers, and regulatory agencies to achieve a
solution.
-------
- 82 -
12. BIBLIOGRAPHY
(1) Forney, A. J., R. T. Kenny, S. J. Gasior, and J. H. Field,
"Destruction of Caking Properties of Coal by Pretreatment in a
Huidized Bed", Ind. Eng. Chem. Prod. Res. Develop., Vol. 3,
No. 1, March, 1964, pp. 48-53.
(2) Forney, A. J. , R. F. Kenny, S. J. Gasior, and J. H. Field, "The
Production of Nonagglomerating Char from Caking Coal in a
Continuous Fluid-Bed Reactor", Preprint-Division of Fuel Chemistry,
American Chemical Society, Vol. 8, No. 3, Aug.-Sept., 1964, pp. 1-9.
(3) Gasior, S. J., A. J. Barney, and J. H. Field, Ind. Eng. Chem. Prod.
Res. Develop., Vol. 3, 1964.
(4) Ibrney, A. J., R. T. Kenney, S. J. Gasior, and J. H. Field, ".Fluid
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4. TITLL AND SUBTITLE Evaluation of Pollution Control in
Fossil Fuel Conversion Processes; Gasification:
Section 1: Synthane Process
7. AUTHOR(S)
.D. Kalfadelis and E.M. Magee
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Esso Research and Engineering Company
P.O. Box 8
Linden. NJ 07036
_ Q~7
TECHNICAL ru-Toiu
r/i'.nc read luwii<'lii>n\ mi I hi.' MTCM.
1. KU'Oli I NO.
EPA- ^50/2^74^00 9 -b_
3. H LCI I'll. N I JS ACCl:SSIuVNO.
5. REPORT DATE
June 1974
6. PERFORMING ORGANUA'I ION CODE
I. PERFORMING ORGANISATION REPORT NO
GRU. 4DJ. 74
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-23
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 REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMF.NTARY NOTES
16. ABSTRACT
The report gives results of a review of the U. S. Bureau of Mines' Synthane Coal
Gasification Process, from the standpoint of its potential for affecting the
environment. Where possible, it estimates the quantities of solid, liquid, and
gaseous effluents, as well as the thermal efficiency of the process. It proposes a
number of possible process modifications or alternates ? and points out new
technology needs.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Air Pollution
Coal Gasification
Fossil Fuels
Thermal Efficiency
Trace Elements
b.IDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Clean Fuels
Synthane Process
High-Btu Gas
Researc Needs
c. COSATI I ickl/Group
13B
13H
21D
20M
06A, 06P
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS ('lliis Report)
Unclassified
I NO. OF P
93
20. SECURITY CLASS (Thi
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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