EPA-650/2-74-009-J
September 1975
Environmental Protection Technology Series
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
GASIFICATION: SECTION 7. U-GAS PROCESS
U.S. f
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EPA-650/2-74-009-i
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
GASIFICATION: SECTION 7. U-GAS PROCESS
by
C. E. J ah nig
Exxon Research and Engineering Company
P.O. Box 8
Linden , New Jersey 07036
Contract No. 68-02-0629
ROAP No. 21ADD-023
Program Element No. 1AB013
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D. C. 20460
September 1975
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EPA REVIEW NOTICE
This report has boon i-c-viewed by the U.S. Environmental Protection
Agency and approved for publication. Approval does not signify that
the contents necessarJly reflect the views and policies of the Environ-
mental Protection Agency, nor does mention oi' trade names or commer-
cial products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH-
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EFA-650/2-74-009~i
11
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TABLE OF CONTENTS
Page
1. SUMMARY . . 1
2. INTRODUCTION 2
3. BASIS AND BACKGROUND 3
4. PROCESS DESCRIPTION 4
5. EMISSIONS TO THE ENVIRONMENT 11
5.1 Coal Preparation and Drying . . 11
5.2 Pretreatment and Gasification 17
5.3 Gas Cooling and Dust Removal 18
5.4 Sulfur Removal 18
5.5 Auxiliary Facilities 18
6. SULFUR BALANCE 21
7. THERMAL EFFICIENCY 23
8. TRACE ELEMENTS 25
9. TECHNOLOGY NEEDS 28
10. PROCESS DETAILS 31
11. QUALIFICATIONS 37
12. BIBLIOGRAPHY 38
iii
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LIST OF TABLES
No« Page
1 RAW MATERIALS USED 7
2 STREAMS LEAVING PLANT 8
3 STREAMS ENTERING AND LEAVING SPECIFIC UNITS 13
4 SULFUR BALANCE 22
5 THERMAL EFFICIENCY 24
6 EXAMPLE OF TRACE ELEMENTS THAT MAY APPEAR IN 26
GAS CLEANING SECTION
7 STREAM COMPOSITIONS 32
8 STEAM BALANCE 33
9 ELECTRIC POWER CONSUMED 34
10 WATER BALANCE 34
11 MAKE UP CHEMICALS AND CATALYST REQUIREMENTS 35
12 POTENTIAL ODOR EMISSIONS 35
13 POTENTIAL NOISE PROBLEMS 35
IV
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LIST OF FIGURES
No. Page
1 U-GAS PROCESS FLOWPLAN 5
2 U-GAS PROCESS WITH COMBINED CYCLE FOR POWER GENERATION 6
3 U-GAS PROCESS EFFLUENTS 12
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TABLE OF CONVERSION UNITS
To Convert From
Btu
Btu/pound
Cubic feet/day
Feet
Gallons/minute
Inches
Pounds
Pounds/Btu
Pounds/hour
Pounds/square inch
Tons
Tons/day
To
Calories kg:
Calories, kg./kilogram
Cubic meters/day
Meters
Cubic meters/minute
Centimeters
Kilograms
Kilograms/calorie, kg
Kilograms/hour
Kilograms/square centimeter
Metric tons
Metric tons/day
Multiply By
0.25198
0.55552
0.028317
0.30480
0.0037854
2.5400
0.45359
1.8001
0.45359
0.070307
0.90719
0.90719
VI
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- 1 -
1. SUMMARY
The U-Gas Process being developed by the Institute of Gas Technology
has been reviewed from the standpoint of its effect on the environment. The
quantities of solid, liquid and gaseous effluents have been estimated,
where possible, as well as thermal efficiency of the process. For the
purpose of reducing environmental impact, a number of possible alternatives
are discussed, and technology needs are pointed out.
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- 2 -
2. 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 commercially 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 prob-
lems peculiar to the conversion process. It is thus important to examine
alternative 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
Research and Engineering Company under Contract No. EPA-68-02-0629,
using all available nonproprietary information.
The present study under the contract involves preliminary design
work to assure that the processes are free from pollution where pollution
abatement techniques are available, to determine the overall efficiency of
the processes, and to identify areas where present technology and informa-
tion are insufficient to assure that the processes are nonpolluting. This
is one of a series of reports on different fuel conversion processes.
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 gives an indication of
the amount of waste heat that must be rejected to ambient air and water
and is related to the total pollution caused by the production of a given
quantity of clean fuel.
Suggestions are included for filling 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
and/or contacts were made with the developers to update published informa-
tion. Not included in the studies are such areas as cost, economics,
operability, etc. Also coal mining and general offsite facilities are not
within the scope of this work.
A number of reports have been issued on individual processes
evaluated to date in the program (1,2,3,4,5,6). We wish to acknowledge
the information and help provided by EPA in making this study.
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3. BASIS AND BACKGROUND
The U-Gas Process for making clean gas fuel is based on gasifying
coal with air plus steam,, and has been referred to in the literature. Some
information is given in Reference 7 on application to electric power
generation using a combined cycle in which the gas is first burned for use
in a gas turbine, and then goes to a boiler where additional power is
generated using a steam cycle. Pretreating of coal feed is incorporated
into the design to allow using caking type coal feed by first destroying
the caking properties in a pretreating zone. Air is added to the pre-
treater to give partial oxidation at about 800°F. Composition of the com-
bined gas, including that from pretreating, is given in Reference 8, while
a general description of the system is given in Reference 9. More complete
information is given in Reference 10 for a combined cycle application to
generate electric power. Environmental controls are provided, together
with a breakdown of the overall energy balance. Our environmental evaluation
is based mainly on Reference 10, the others being used to arrive at a better
understanding of the process in order to estimate utilities and auxiliary
facilities where necessary, and to assess environmental and energy aspects
of the process.
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- 4 -
4. PROCESS DESCRIPTION
Coal feed amounts to 7346 tons/day containing 6% moisture. It is
dried, then crushed, and sent to a pretreater where caking properties are
destroyed by partial oxidation in the presence of air. The pretreated coal
is gasified with steam and air in a fluidized solids system, at 1900°F and
300 psia to make low Btu clean gas fuel suitable for use in a combined cycle
power plant.
As shown in Figure 1, dry coal crushed to 1/4 inch and smaller is
fed to the pretreater by means of lock hoppers. Gases from the pretreater
flow into the gasifier at a point above the fluid bed for the purpose of
reacting and destroying all tar and oil vapors that are evolved in pre-
treating. A residence time of 10-15 seconds is provided on the vapors (8).
Figure 2 shows the pretreater-gasifier system. Table 1 gives inputs to the
plant, while Table 2 shows outputs. Additional process details are given
in Section 10 of this report.
In the fluid bed gasifier operating at about 2 ft/sec, char is
reacted to give a carbon level of about 20% in the ash. Agglomeration of
ash particles is accomplished in a "spouting" zone or venturi throat at
the bottom of the gasifier maintained at sintering temperature by adding
air and steam. Ash agglomerates of perhaps 1/8 inch diameter pass down
through this throat, to be quenched and removed from the system. Dust
recovered by cyclones from the raw gas product is also passed through the
agglomerating zone. Further description of this type of agglomeration is
given in Reference (11).
Raw gas is cooled in a waste heat boiler to make high pressure
steam, following by additional heat recovery to preheat boiler feed water.
Air cooling is then used to bring the gas down to scrubbing temperature.
The water scrubber removes dust and ammonia primarily, together with
unreacted steam. Gas liquor from the scrubber is processed in a sour water
stripper to recover ammonia and remove I^S (12). The treated water is
recycled to the cooling tower or used to slurry the ash being returned
to the mine for disposal.
In this particular design, water is indicated to be recycled to
extinction within the process, in which case there would be no net water
discharge that might cause environmental concern. However, there will be
soluble salts (e.g., sodium chloride and sulfate) introduced with the makeup
water, plus volatile elements from gasification (chlorine, fluorine, boron,
etc.) that will accumulate and must be purged from the system. It is
obvious that some water must be discharged.
Sulfur is removed from the cooled gas using the Selexol process (13)
based on a glycol type solvent, which can remove H2S and COS from the gas.
About 607» of the C02 is left in the gas, but the solvent does dehydrate the
gas.
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FIGURE 1
U-GAS PROCESS
Flowplan and Flourates for Plant Processing
7346 Tons/Day of Pittsburgh Type Coal (6.C7. Moisture)
Cons/day
670 Moisture
Pretreater
(X Offgas
Fuel Gas
and Air
to Coal
Dryer
Solids transferred from pretreater
to U-Gas reactor is 6304 tons/day
Low Btu Clean
Char
1037 (dry)
(20.37. Carbon)
Y
Note: Numbers are tons/day except as noted.
(See Table 7 for details on stream compositions.)
Generation
and
Superheat
I
Steam
Hot Gas
275'F
Air
Cooler
Cooled
Gas
150°F '
CXD
Scrubber
Cooling Water System
A
Her Feed W-iter
\
Makeuu
Wateu-
Treati:i
tekeup
8
Air
t
•*?t
Cooling
^ ^
1
1
Gas to
Selexol
Sulfur
Removal
(Selexol)
1
Steam
^
Gas Liquor H s stream
Slurry 2178
2769 (16.67. H2S)
^-»-
V
— •?•
Waste
Water
Treating
»Z(_
Product Ga
124 X 109 I
(158 Btu^CI
Ne
Ga
25
V
Plan
coal dryer
tail gas i
air. compr
elec. gene
'
Clans
Plant
Tall Gas
Cleanup
Tail Gas
Net Product
478
224
733
413
1848
Makeup U.ater
Air
r
Ammonia Water
Discharge
Sulfur
283
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- 6 -
FIGURE 2
U-GAS PROCESS WITH COMBINED
CYCLE FOR POWER GENERATION
(From Reference 8)
Gasifier
1
f&
Dus
Rem
Heat
Recovery
Pretreater
Sulfur
Removal
800°F
Agglomerated
Ash
Gas
Turbine
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TABLE 1
RAW MATERIALS USED, U-GAS PROCESS
Coal: Pittsburgh Seam (Cleaned!
6% Mois ture
Analysis, Wt. % (dry basis)
C
H
0
N
S
Ash
Pi o-V| "Hpaf- V^lllP d*rv COal - .
Coal
71.5
5.0
6.5
1.2
4.4
11.4
100.0
7346
Pretreated Coa
71.25
4.02
7.50
1.00
3.74
12.49
100.00
13,178 Btu/lb
2122
tons /day
.1
gpm
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- 8 -
TABLE 2
STREAMS LEAVING PLANT, U-GAS PROCESS
Net Product Gas
Composition, Vol. %
CO 20.16
C02 6.72
H2 13.75
CH4 4.89
N2 54.47
H2S .005
COS .01
100.00
High Heating Value : 158 Btu/SCF
Char from gasifier (dry basis)
Composition
Wt.%
c
H
N
S
Ash
20.33
1.43
1.78
0.58
75.88
100.00
Waste water discharge
Sulfur byproduct
Ammonia byproduct
25,726 tons/day
(784 MM SCFD)
1037 tons/day
(plus 156 tons/day of water)
tons/day
2000 (334 gpm)
283
2
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- 9 -
If it were possible to remove sulfur and particulates at high
temperature, the gas cleanup system might be simplified and overall efficiency
improved. However, the potential NOX emissions would then have to be evaluated
carefully, since the raw gas will contain ammonia which if not removed increases
the NOX formation in subsequent combustion. By way of illustration, a modifi-
cation of the U-Gas Process has been proposed (8), in which sulfur is removed
by contact with a suitable metal at 800°F. A practical process for removing
large amounts of sulfur at high temperature is not yet commercially available,
although trace amounts can be removed using guard beds of zinc oxide for
example. Exploratory work has been done on using iron or nickel base materials
which can be regenerated (14), making it practical to remove large amounts
of sulfur from a gas stream.
The sulfur acceptor may be regenerated by contacting it with air
to form S02, which is sent to a Glaus unit and reacted with H2S from other
sources for sulfur recovery. Instead of using a metal as the sulfur acceptor,
half calcined dolomite might be used as has been mentioned in the literature (4)
The sulfur acceptor is then regenerated by reacting with CC>2 and water at
about 200°F to form H2S which can be converted to free sulfur via a liquid
phase Glaus type operation.
Returning to a discussion of acid gas treatment, clean low Btu gas
from the Selexol unit is available to use as fuel, in conventional systems
or in a combined cycle system. The H2S stream from solvent regeneration is
indicated to contain 16.6% H2S and is sent to a Glaus unit for sulfur recovery.
Tail gas cleanup by the We1Iman-Lord process (15) is included to give 250 ppm
S02 in the final gas released to the atmosphere.
High heating value of the total gas produced is 5533 MM Btu/hr,
but part of the gas is needed to supply requirements of the process. Net
gas available from the process is 5162 MM Btu/hr, equivalent to a potential
power generation of 600,000 KW at a nominal 40% efficiency. Of the total
gas produced, 6.7% is consumed in the process to supply fuel to the coal
dryer and tail gas incinerator, on the sulfur plant, plus a combined cycle
system supplying plant electricty and power for air compression. In addition,
steam is generated from waste heat in the process, but all of this is used
within the plant, partly to drive the air compressor.
Auxiliary facilities are required in addition to the basic process,
such as coal handling and storage. Coal preparation will include drying and
crushing, as well as coal cleaning unless this is provided elsewhere. Ash
handling and disposal are also needed, with means to drain the ash slurry,
recover the water for reuse, and transport the drained ash to the mine or to
a landfill area. The Glaus plant for sulfur recovery includes tail gas
cleanup by scrubbing with sodium sulfite using the Wellman-Lord process, but
sulfur storage and shipping facilities are also needed.
Waste water treatment employs the Chevron process to recover
by-product ammonia, and makes it feasible to reuse the water (12). While
not included in the original design, a biological oxidation system (biox)
is needed to give adequate cleanup of the water for return to the cooling
water circuit. In addition, to prevent buildup of sodium salts etc., some
water will have to be discharged from the plant, although no net water
discharge was shown in the original design (10).
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- 10 -
The plant may be self sufficient in steam and power during
normal operation, but in order to start it up a furnace or other method
for heating is required, together with startup steam and power. Fuel for
startup probably should be oil rather than gas or coal, so as to avoid the
storage problem with gas, or the environmental problems with coal due to
sulfur and ash.
Makeup water must be brought in and treated to make it suitable
for use in the cooling water circuit, while further treatment and demineral-
ization are required to supply boiler feedwater makeup. Cooling towers are
used and are a major area of environmental concern.
Other facilities required are maintenance shops, fire protection,
warehouses, control laboratory, offices, cafeteria, roads, trucks, .etc.,
all of which must be taken into account in assessing total environmental
impact.
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5. EMISSIONS TO THE ENVIRONMENT
Overall flow rates for the process were shown in Figure 1.
Figure 3 and Table 3 show all of the streams entering and leaving specific
units, some of which are returned to other units within the plant. All
streams which are actually discharged to the environment are indicated
by heavy dashed lines in Figure 3 and by asterisks in Table 3. Emissions
to the environment are discussed in the following subsections, in the
order of process sequence shown in Figure 1.
5. 1 Coal Preparation and Drying
The first effluent is to the air from the coal handling and
preparation area. Coal is delivered and crushed to 1/4 inch and smaller.
Such operations will normally have a dust problem, and careful considera-
tion and planning is required for control. Covered conveyers should be
provided wherever possible; even so, there may be vent streams or leaks
that could release dust. A dust collection system should be used
operating at slightly below atmospheric pressure to collect vent gas and
pass it through bag filters. Since spills from conveyers and leaks can
also create dust, facilities such as clean-up equipment and water sprays
may be needed.
The coal storage pile is also of concern in that wind can pick
up and disperse fine particles. Evaluation is needed for each specific
situation in order to provide proper control measures. Proposals for
dust control have been made such as spraying oil or asphalt on the sur-
face of the pile, or convering it with plastic. The amount of coal
handled is so large that a loss of even a small fraction of a percent
could be excessive.
A further consideration on any coal storage pile is the
possibility of fires and spontaneous combustion which would result in
evolution of odors, fumes, and volatiles. One control measure is to
compact the pile in layers as it is being formed. In any event, plans
and facilities should be available for extinguishing fires if they occur .
The coal storage and preparation area may also contribute to water
pollution. If 30 days' storage is provided, it amounts to over 200,000 tons;
so the coal storage pile will cover a large area. Rain runoff can lead to
undesirable effluents. A large part of the rain can run off quickly and
carry suspended particles, while the remainder will have a long contact
time with the coal and can pick up acids and organics. Therefore, rain
runoff from the storage area should be collected in storm sewers and sent
to a separate storm pond. With a certain amount of treatment, this water
can then be used as makeup for the process. Control of seepage may be
desirable on the pond, and particularly on the coal storage area, using
for example, a layer of concrete, plastic or clay.
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FIGURE 3
U-GAS PROCESS
Block Diagram Showing Streams In and
Out of Specific Sections of Plant
2345
M A
II 1 0 'f
ji * n 1
Raw Gas
32
Settler
133
Cyclone
1
Coal Feed,,
Coal
Prep,
Dry
Crushed
Coal
1
1
Pre- 1
treat 1
1
ft ft I \
15 16 17 18 J 20
U-Gas
\
f
Quench
-^Y
<
1 -«
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- 13 -
TABLE 3
Identification
Stream
I Coal Feed
*2 Wind
*3 Rain
*4 Dryer vent gas
Dust
6 Steam
*9 Air
10 Gas liquor
11
stream
*12 Chemicals
13 Condensate
14 Net product gas
15 Wind
16 Rain
17 Flue gas
Flow Rate t'ons/day
7346
e.g. 6" in 24 hrs,
1700
(51.4 MM SCFD)
Comments
7.752
7 Superheated steam 4,052
8 Steam 6,190
227,000
2,769
2.178
18
19
Air
Air
6,190
25,015
e.g. 6" in 24 hrs.
480
779
7,205
67» moisture, cleaned
Wind may blow dust from coal storage
and handling area.
Rain can wash fines from coal prepara-
tion and storage area, and leach
organics, sulfur, iron, trace elements
etc.
Combustion gases from coal dryer -
contain dust. Part of product gas is
burned with 10% excess air.
Coal fines entrained in drying gas,
recovered in bag filters and returned
to gasifier.
High pressure steam made from waste heat
on process.
Superheated steam fed to gasifier.
Low pressure steam made from waste heat
used for Selexol unit and sour water
stripping.
Air cooling on raw gas before Selexol
unit.
Water layer condensed from raw gas and
sent to waste water treating.
Sulfur compounds removed by Selexol unit
and sent to sulfur plant.
Makeup glycol and chemicals are added to
Selexol unit and will appear in
effluents.
Recovered from steam used for heating -
return to boiler feed water.
Clean fuel gas, produced by process
Wind action on coal storage and
preparation area.
Rain onto coal storage pile
Part of clean product gas use as fuel
in coal dryer.
Combustion air to coal dryer
Process air used in pretreater
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- 14 -
TABLE 3 (Cont'd)
Stream
Identification
20 Air
21 Char
22 Steam
23 Steam
24 Boiler feed water
25 Steam
26 Boiler feed water
27 Air
28 Chemicals
29 Steam
30
31
32
*33
Water
Slurry
Water
Char
34 Makeup water
35 Boiler feed water
*36 Sludge
*37 Chemicals
*38 Air
*39 Drift loss
40 Cooling water
*41 Blow down
42 Treated water
Flow Rate tons/day
14,987
1,037 (dry)
408
4,052
7,752
4,052
6,190
227,000
6,190
564
2,074
881
1,193
10,692
4,244
See Table 11
See Table 11
600.000
Comments
300,240
(50,000 gpm)
2,004
564
Process air added to gasifier
Char rejected from gasifier (20.3 wt. %
carbon).
Steam formed in quenching hot char -
returned to gasifier.
Steam to gasifier
To make high pressure steam from waste
heat.
Superheating of steam fed to gasifier.
To make low pressure steam from waste
heat.
Air cooling on raw gas.
Glycol and other chemicals.used in
Selexol unit.
Low pressure steam used for heating in
Selexol unit.
Makeup to char quench.
Slurry of char (50% water) to settler.
Water recovered in settler.
Char returned to mine (15% moisture on
dry char).
Makeup to cooling water circuit.
Makeup to boiler feed water supply.
From treating makeup water.
Waste chemicals from water treating.
Air from cooling tower (plus 8688
tons/day of evaporated water).
Loss of water mist from cooling tower -
not included in water balance. May
provide blowdown (see stream 41).
Circulating cooling water
Blowdown from cooling water system td
control buildup of dissolved solids, etc,
From waste water treating. Returned
to ash quench.
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- 15 -
TABLE 3 (Cont'd)
Stream Identification
43 Treated water
*44 Ammonia
45 H2S
*46 Oil
*47 Sludge
-'-48 Sludge
*49 Solids
50 Condensate
*51 Sulfur
*52 Tail gas
*53 Chemical purge
54 Makeup water
55 Chemicals
56 Air
57 Cooling water
58 Chemicals
59 Gas liquor
Flow Rate tons/day
2,205
Comments
830
283
3,171
See Table 4
14,936
See Table 11
600,000
308,928
See Table 11
2.769
60
61
62
63
Chemicals
Steam
H2S stream
Air
--
830
2,17.8
1,075
64 Fuel gas
65 Chemicals
205
Treated waste water used as makeup
water.
Recovered from sour water stripping
system; may be sold or incinerated.
Sour gas stripped from gas liquor -
returned to' Glaus unit.
Some oil, tar, phenols, etc. may be
removed from raw gas.
Cellular material from biox unit.
Sludge from chemical treatment of waste
water, if used e.g., to precipitate fluoride
Ash, coal fines, etc. removed from
raw gas in scrubber - may contain trace
elements.
Condensed steam used on sour water
stripper - returned to boiler feed water.
From sulfur plant.
After incineration and tail gas
cleanup.
From tail gas cleanup system, may contain
2 ton/day sulfur.
To makeup water treating (includes 2205
tons/day from waste water).
For water treating.
Air to cooling tower.
Cooling water to cooling tower
Additives to cooling water circuit to
control fouling and corrosion.
Water layer from scrubber sent to
waste water treating.
As may be used in waste water treatment.
To reboiler on sour water stripper.
Sulfur compounds from Selexol unit.
For oxidation of sulfur compounds in
sulfur plant (includes 382 tons/day to
incinerate tail gas for cleanup).
Part of product gas is used as fuel on
sulfur plant incinerator.
r
Make up sodium sulfite,etc,j to replace
chemicals purged on tail gas cleanup.
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- 16 -
Cleaning and washing of run of mine coal is not included in the
present design, assuming that this will be done elsewhere. However, it
should be pointed out that some applications of the process tnay include
cleaning and washing, which employ large amounts of water, and generate large
volumes of solid refuse to dispose of.
Noise control should be carefully considered since it is often a
serious problem-in solids handling and size reduction. If the grinding
equipment is within a building, the process area may be shielded from
undue noise, but additional precautions are needed for personnel inside
the building.
Crushed coal next goes to a dryer where essentially all of the
moisture is removed. To make the plant complete and self-sufficient, we
have included coal preparation and drying in the balances. Fuel for the
dryer is supplied by using part of the clean gas product, so that sulfur
removal is not needed on the vent gas. However, dust recovery must be
provided, using for example bag filters, scrubbing, or electrostatic pre-
cipitation. Recovered fines can be returned to the process, possibly to
the "agglomerating" zone of the gasifier to minimize entrainment. One other
concern on the dryer vent gas is possible odors, -which calls for careful
evaluation with .specific coals and drying facilities that will be used.
Regulations on coal dryers may call for a maximum dust loading in
the vent gas of .07 to .10 grains per standard cubic foot of gas, as
legislated by the State of West Virginia (Chapter 16-20 Series V, 1968).
Smoke emission must not be darker than No. 1 on the Ringelman Smoke Chart.
In the drying operation a large volume of hot gas is contacted
with the coal. Oxygen content is normally limited to about 10 Vol. 7.
by„safety considerations. Also the maximum temperature should be limited
to avoid heating the coal above 500°F, so as not to release volatile matter.
It is common practice to use a large amount of excess air, such as 100%,
in order to minimize moisture content of the drying gas and thereby
facilitate drying. In some cases effluent gas may be recycled or inert
gas added to control gas temperature and oxygen content.
With the present high price of fuel, the design of drying
facilities should be optimized to minimize fuel consumption. This subject
is discussed more fully in a previous study (4). In brief, it is desirable
to operate the dryer with minimum excess air, for example 10% excess, and
to recycle vent gas as.needed to control temperature of the hot gas. This
gives minimum fuel consumption as well as minimum volume of vent gas to be
cleaned up. Of course, the moisture content of the drying gas will be
higher than when a large amount of excess air is used, making it more
difficult to achieve the same degree of drying, although the moisture
content of the dried coal could be allowed to increase slightly. Further
details on flue gas from the dryer are given in Table 3.
In general, it will be desirable to preserve the sensible heat in
the dried coal, so as to maximize heat recovery on the pretreater. Coal
preheat temperatures as high as 500°F have been used without substantial
evolution of volatile matter from coal. This temperature has also been
considered practical from the standpoint of using lock hoppers.
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- 17 -
The coal feeding system for pressurizing the coal in this specific
design uses lock hoppers. Vent gas from depressuring the lock hoppers should
be cleaned up and returned to the process. Normally there will be no
effluent to the air from this system. Coal feeding may involve pneumatic
transport of coal, in which case recovery and cleanup of the conveying
gas is needed.
5.2 Pretreatment, and Gasification
In the pretreatment reactor, coal is contacted with air and
partially decomposed, releasing tar as well as lighter hydrocarbons. Gases
from pretreating pass to the upper zone of the gasifier above the fluidized
bed, with the intention of completely destroying all tar and hydrocarbons.
However, the temperature in this zone varies from 1900°F leaving the bed, to
1550°F outlet temperature on the combined gas stream, and it is unlikely
that refractory aromatic type compounds will be destroyed completely. There
is also a possibility that some soot may be formed by cracking at high
temperature. If these problems occur, they would complicate considerably
the cleanup and waste disposal facilities for the plant, beyond the simple
system shown.
Pretreated coal, amounting to 91.3 wt. % on dry coal, is trans-
ferred to the gasification reactor as a separate stream, to be reacted
with air and steam. All overhead gases are contained and processed for
cleanup. The only direct effluent to the environment from this section
of the plant is the char or ash removed from the bottom of the gasifier.
It is dropped into an enclosed hopper filled with water - the resulting
steam flowing back up into the gasifier - and the ash slurry is depressured
for removal via a settler. Water recovered in the settler is returned to
the quench hopper. Wet ash is then disposed of as landfill, or returned
to the mine.
A desirable feature in this design is the agglomeration of ash
provided by a sintering zone in the bottom of the gasifier. Benefits
obtained are:
o Lower carbon in ash
o Large ash particles, and less dust
o Higher density particles
Sintering to give increased ash density may be particularly desirable
so as to minimize disposal problems. If there is no sintering, particle
density of the ash may be very low, for example 5^10 Ib./cu. ft. As previ-
ously pointed out (6), when coal is gasified without change in particle
size, density of the char or ash must decrease correspondingly. The particles
also become much more friable tending.to aggravate problems of dust separa-
tion on the raw gas, and in disposing of the ash.
A potential problem is leaching of chemicals'or toxic elements
from the ash. Thus, potential contamination of natural water'must be
evaluated, and data needed for this purpose should be obtained when
developing the process.
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- 18 -
Hopefully, the sintered nature of the ash will minimize ash
disposal problems such as leaching. It should be recognized that makeup
water supplied to quenching will normally contain dissolved solids, and
that these have no way to leave except with the ash. Consequently, a
thorough evaluation of potential leaching will be needed.
5.3 Gas Cooling and Dust Removal
Raw gas leaving the gasifier passes through a cyclone to recover
dust, which is returned to the gasifier agglomerating zone. Next the gas
goes to waste heat boilers and a steam superheating exchanger to recover
useful heat. Air cooling is then used to bring the gas down to scrubbing
temperature. Normally all process streams are confined within the equip-
ment and there are no intentional emissions to the environment. However,
leaks are common, especially on exchangers, and if leaks occur on air
coolers , the emissions will be dispersed in the large volume of air used
for cooling. Consideration of this problem is needed in design, possibly
with some monitoring of operations.
Water scrubbing removes dust, soluble compounds such as ammonia,
and phenol that may also be present. This scrubber water will be saturated
with H2S and other gases. It is sent to waste water treating to clean it
for reuse in the process, as will be discussed further in Subsection 5.5
on Auxiliary Facilities. This gas liquor is expected to contain fine dust,
as well as tar, cyanides, phenols and other oxygenated compounds^ etc. to
be removed in the waste water treating operations.
5.4 Sulfur Removal
The final step in cleaning up the raw gas is sulfur removal. The
product gas is then suitable for use in a gas turbine, without requiring
stack gas cleanup to remove sulfur or particulates. It is not necessary to
remove C02 for this use, therefore the base design uses the Selexol process
which scrubs the gas with a glycol type solvent. A concentrated H2S stream
is sent to the sulfur plant, along with moisture removed by the dehydrating
effect of the solvent. Steam used to regenerate the solvent is supplied
from waste heat recovery on the hot raw gas. Some makeup of glycol, and
possibly other chemicals such as inhibitors, may be added to the system,
in which case they must also appear in one of the efficient streams and
should be considered in any detailed specific design. ' If any such materials
are carried out in the product gas, they could affect operation of turbines
etc. '
5.5 Auxiliary Facilities
In addition to the basic plant, auxiliary facilities are needed
to make the plant self-sufficient, including sulfur recovery, cooling water,
water treating, and electric power. A Glaus plant is used to recover sulfur.
In a typical Claus plant the acid gas is first burned with air to form free
sulfur which is condensed and recovered. This is followed by additional
stages using a catalyst to allow operating at lower temperature so as to give
more complete reaction between H2S aild- S02> au(* increase tne sulfur recovery.
In this case having a Claus plant feed containing 16.6 vol. % F^S, sulfur
recovery may be about 95% in a 3 stage operation. Since the resulting
15 tons/day sulfur emission would be excessive, -tail gas cleanup is provided
using the Wellman-Lord process based on incineration plus scrubbing with a
sodium sulfite solution.
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- 19 -
A modification of the U-Gas process was mentioned earlier based on
removing sulfur from the raw gas at high temperature, for example with
molten metal. The sulfur acceptor would then be regenerated with air to
form S02. With this modification, a conventional Glaus plant could not be
used for sulfur recovery. Instead, it would be necessary to reduce S02 to
sulfur, for example using carbon as the reducing agent. Of course if
sufficient H,S were available from some other source, it could be reacted
with the S02 in a Glaus plant, in which case the environmental effects of
sulfur would be similar to the present study case. However, high temper-
ature cleanup of the gas may not remove ammonia, in which case the contribu-
tion of ammonia to NO formation in subsequent combustion would have to be
carefully evaluated.
One other consideration on the sulfur plant is to control odor
emissions due to leaks or associated with handling the product sulfur. There
is an appreciable solubility of H2S in molten sulfur, and it may escape
during handling or storage; however, there are well established techniques
for controlling this and other possible sources of contamination such as
sulfur dust.
The utility cooling tower, which has by far the largest emission
to the atmosphere of any part of the plant, is of particular concern regarding
environmental considerations. Since a very large volume of air is contacted
efficiently with cooling water, any contaminants in it such as ammonia,
H2S, phenol, cyanide, etc. can be stripped out. It might be thought that the
cooling water is perfectly clean, however, experience shows that there will
be leaks in exchangers such as those in sour water service and on acid gas
treatment. Since the process operates at elevated pressure, any leakage
is into the cooling water circuit. This source of contamination has been of
concern in petroleum refineries and on chemical plants. If the problem is
severe, monitoring for leaks may be warranted.
The volume of air passing through the cooling tower is so large
that every precaution should be taken to see that it does not inadvertently
become contaminated. On any cooling tower there are also potential problems
associated with drift loss or mist and the formation of a plume or fog.
If the cooling tower is near public highways, these may be of concern,
especially in the winter when icing may occur and condensation to form
a plume is likely. In designing the plant, careful consideration should be
given to this in placing equipment, in order to minimize or avoid potential
problems.
Some blowdown is needed from the cooling water system to purge
soluble salts that become concentrated by evaporation, and chemicals that
are added to control algae and corrosion. The blowdown goes to waste water
treating before leaving the plant as an effluent.
Waste water to be treated includes the cooling tower blowdown,
gas liquor from scrubbing the raw gas, and chemical purge from tail gas
cleanup on the sulfur plant. Boiler blowdown is relatively clean so it is
used as makeup to the cooling water system. The gas liquor may contain
considerable ammonia, as 60-70% of the nitrogen in the coal feed often
shows up in this form on gasification operations. It is also saturated with
H2S and other gases from contacting in the scrubber at elevated pressure.
When the sour water is depressured, gases which flash off must be collected
and returned to the system, for example to the Claus plant. As in other
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- 20 -
gasification processes, the gas liquor is expected to contain various other
contaminants, such as cyanides, thiocyanates, phenols, fatty acids, oil,
possibly some tar, and particulates. In any event, there will be startup
conditions and plant upsets that produce a full range of contaminants, so
provision to handle them should be provided, including such facilities as
oil separators, settlers or filters for solids, and biological oxidation
(biox) for cleanup.
In addition to the above, trace elements are of concern in that
some of them are known to be partly or highly volatile at gasification
conditions, and will be removed in the gas cleanup system. Consequently
they can appear in the gas liquor. Many of these trace elements are known
to be toxic, and the amounts involved are large, giving cause for real
concern on their satisfactory disposal. Considerable volatility has been
shown for arsenic, lead, cadmium, mercury, fluorine, chlorine, etc. The
particular subject of trace elements is discussed more completely in
Section 8.
Solid residue will be separated from the gas liquor, representing
fines and ash that remain in the raw gas and are separated in the scrubber.
Depending upon the amount and the combustible content, it may be desirable
to return them to the gasifier, or they might be included with the ash stream
for disposal. Again, the question of trace elements appears, since some of
these may be recovered as particulates and present special disposal problems.
Other solid residues will include sludge from biox treatment,
where contaminants are removed by incorporating into cellular material.
This sludge can be an odor problem and might be incinerated, buried, or sent
to the gasifier. There may also be solid wastes from treating waste water
with lime for example, to release ammonia, or to deactivate fluorides, etc.
In any case, there- will be sludge from treating makeup water, which is
innocuous and can be disposed of along with ash from the gasifier.
While not shown in the original design, there will have to be a
significant discharge of water from the process in order to purge soluble
salts and maintain an operable system. Such salts enter in the plant makeup
water and become concentrated by evaporation in the cooling tower.
Additional amounts are contributed by chemicals used in water treating,
demineralization to prepare boiler feed water, cooling water additives, etc.
In addition, sodium sulfate is purged from the tail gas cleanup system,
while chlorides in the coal feed appear to be volatile in which case they
will appear in the gas liquor. Depending upon these factors and the quality
of makeup water, the minimum amount of waste water may amount to 20-2570 of
the net makeup water used. The latter is set primarily by the amount
evaporated in the cooling tower.
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- 21 -
6. SULFUR BALANCE
Sulfur in the coal feed is mostly removed by gasification,
appearing as H2S in the raw gas. Some 10% of it may be-as carbonyl
sulfide rather than H2S, due to reaction with carbon monoxide. A small
amount of sulfur remains in the ash leaving the bottom of the gasifier.
Raw gas treatment in the Selexol unit separates 99% of the I^
entering, and about one-half of the COS, into a stream which is sent to
the Glaus plant. With tail gas cleanup, the sulfur plant gives 99+%
removal of sulfur, leaving 1 ton/day of sulfur or 250 ppm of SC>2 in the
tail gas. Details on sulfur balance are shown in Table 4.
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- 22 -
TABLE 4
SULFUR BALANCE. U-GAS PROCESS
Sulfur in Coal
Sulfur in ash
Sulfur in product gas
Sulfur to Glaus plant
Balance on sulfur plant
Sulfur in acid gas feed
Sulfur product
Sulfur in chemical purge
Sulfur in tail gas
tons/day
303
6
7
290
290
287
2 (est.)
1
290
Wt. %
100
2.0
2.3
95.7
100.0
95.7
94.7
0.7
0.3
95.7
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- 23 -
7. THERMAL EFFICIENCY
Thermal efficiency relates the useful heating value of the net
clean product gas from the process to the heating value of coal consumed,
after making full allowance for all process requirements such as fuel for
coal drying, power for compressors, and utilities such as steam, electric
power, and water. Literature values for thermal efficiency do not always
include these effects, but to be realistic, our studies give thermal
efficiency for a complete plant that is self-sufficient. On this basis,
the heating value of net available product gas from the U-Gas process is
68.1% of the heating value of coal consumed.
Details on thermal efficiency are given in Table 5, showing
that part of the clean gas product is needed within the process to supply
fuel for coal drying, for part of the power on air compression, and as
fuel in the Glaus plant incinerator prior to tail gas cleanup. Combined,
these use 6.7% of the total gas made.
The air compressor requires 132,000 BHP most of which can be
supplied by using byproduct steam. In addition, about 10,000 KW of
electric power is needed in coal preparation, for cooling tower pumps and
fans, etc. Incremental power beyond that available from byproduct steam
is supplied by a combined cycle consuming part of the product gas, at a
nominal 40% efficiency based on heating value of the gas. Thermal efficiency
from coal to electric power is less, of course.
j
The losses that occur are itemized in the lower part of the table.
Unused carbon in the ash accounts for 4.4% of the heating value in the coal'
feed. Perhaps this could be consumed in a final "cleanup zone" to improve
thermal efficiency. The Selexol unit and sour water stripper consume
considerable steam for stripping. If this requirement could be decreased
possibly by using some .type of sulfur removal at high temperature, thermal
efficiency would be improved. Heat dissipated to the atmosphere is 13.1%
of the input, representing waste heat that is at too low a temperature level
for eonomical recovery.
oon It: should be recognized that the product gas is available at about
280 psig, so credit should be allowed for the compression power that would
have been required if the gas were produced at lower pressure. This com-
pression power is 130,000 theoretical horsepower from atmospheric pressure
corresponding to 6.0% on thermal efficiency. '
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- 24 -
TABLE 5
THERMAL EFFICIENCY, U-GAS PROCESS
MM Btu/hr
Coal feed
Net available clean product gas
Plant fuel gas
To coal dryer
For air compression
To make electric power consumed
To tail gas incinerator
Losses
Sulfur byproduct
Ammonia byproduct
Ash from gasifier
Steam to Selexol and
sour water stripper
Air cooling
Cooling tower and other
7,583
5,162
96
147
83
45
371
96
2
335
620
237
760
2,050
100
68.1
1.3
1.9
1.1
0.6
4.9
1.3
4.4
8.2
3.1
10.0
27.0
Note:
Expansion energy available from product gas at 280 psig
corresponds to a credit of 6.0% on thermal efficiency.
Although this effect should be recognized, it may not be
a realistic credit and has not been included in previous
reports of this series.
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_ 25 -
8. TRACE ELEMENTS
Coal contains many trace elements present in less than 1%
concentration that need to be carefully considered from the standpoint
of potential impact on the environment. Many of these may volatilize
to a small or large extent during processing, and many of the volatile
components can be highly toxic. This is especially true for mercury,
selenium, arsenic, molybdenum, lead, cadmium, beryllium and fluorine.
The fate of trace elements in coal conversion operations, such as gasi-
fication or liquefaction, can be very different than experienced in
conventional coal fired furnaces. One reason is that the conversion
operations take place in a reducing atmosphere, whereas in combustion
the conditions are always oxidizing. This maintains the trace elements
in an oxidized condition such that they may have more tendency to com-
bine or dissolve in the major ash components such as silica and alumina.
On the other hand, the reducing atmosphere present in coal conversion
may form compounds such as hydrides, carbonyls or sulfides which may be
more volatile. Studies on coal fired furnaces have indicated that smaller
particles in fly ash contain a higher concentration of trace elements,
presumably due to volatilization of these elements in the combustion zone
and their subsequent condensation and collection on the fly ash particles
(16). Other studies on coal fired furnaces are pertinent (17, IB, 19) and
some of these report mass balances on trace elements around the furnaces
(20).
Considerable information is available on the analyses of coal,
including trace constituents, and these data have been assembled and
evaluated (21,22,23). A few studies have been made to determine what happens.
to various trace elements during gasification (24,25). As expected, these
show a very appreciable amount of volatilization on certain elements. As
an order of magnitude, using these factors for this specific U-Gas design
would result in 147 Ibs. per day carryover for each 10 ppm of trace element
in the coal that is volatilized.
In order to make the picture on trace metals more meaningful,
the approximate degree of volatilization shown for various elementshas
been combined with their corresponding concentration in a hypothetical
coal (as typical), giving an estimate of the pounds per day of each element
that might be carried out with the hot gases leaving the gasifier. Results
are shown in Table 6 in the order of decreasing volatility. Looking at the
estimated amounts that may be carried overhead, it becomes immediately
apparent that there can be a very real problem. For each element an
evaluation must be made to determine the net amount carried overhead and the
potential problem. Where a problem exists, the constituent must be collected,
removed from the system, and disposed of in an acceptable manner. In the
case of zinc, boron and fluorine the degree of volatilization has not yet
been determined, but they would be expected to be rather volatile. Even
if only 101 of the total amount is volatile, there will be large quantities
to remove in the gas cleaning operation and to dispose of.
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- 26 -
TABLE 6
EXAMPLE OF TRACE ELEMENTS THAT
MAY APPEAR IN RAW GAS FROM GASIFIER
Element
Cl
Hg
Se
As
Pb
Cd
Sb
V
Ni
Be
Zn
B
F
Ti
Cr
Possible
ppm in Coal (a) %
1,500
0.2
2.2
31
7.7
0.14
0.15
35
14
2
44
165
85
340
22
Possible
Volatile (b)
90+
90+
74
65
63
62
33
30
24
18
(10)
(10)
(10)
(10)
nil
Estimated
In Gas
Ib/day
<19,800
3
24
296
71
1
1
154
49
5
65
243
125
500
nil
(a) Mainly based on Pittsburgh Seam Coal (2).
(b) Mainly based on reference 24, and indicated at
107» for Zn, B, and F, in absence of data.
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- 27 -
The preceding discussion has been directed primarily at trace
elements that are partially volatilized during gasification and that may
have to be recovered and diposed of in the gas cleaning section. Con-
sideration must also be given to trace elements that are not volatilized
and leave in the solid effluents from the plant, particularly the char
from gasification. Undesirable elements might be leached out of this char,
since it is slurried in water and handled as a wet solid, and will
ultimately be exposed to leaching by ground water when it is disposed of
As land fill or to the mine.
Sufficient information is not now available to adequately evaluate
the potential problems of trace elements, and the necessary information
needs to be developed in future programs so as to assure environmentally
sound planning on large scale operations.
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9. TECHNOLOGY NEEDS
From this review and examination of environmental aspects of
the U-Gas process, a number of areas have been defined where further
information is needed in order to evaluate the situation, or where
additional studies or experimental work could lead to a significant
improvement from the standpoint of environmental controls, energy
consumption, or thermal efficiency of the process. Items of this
nature will be discussed in this section of the report.
Any coal conversion operation has solid refuse to be disposed
of. Although not included in this specific design, coal cleaning must
be provided at some location. The cleaning operation will generate
solid refuse that could amount to over 2000 tons/day, for example. In
addition char is rejected from gasification at a rate of over 1000 tons/day.
Other solid residues include fines removed during gas cleanup, plus sludges
from biox and water treating. More work is needed in order to define
methods of disposal that do not create problems due to leaching of acids,metals,
organics, or sulfur which could contaminate natural water. In addition,
adequate controls are needed with regard to the potential dust nuisance
and washing away of particulates. In many cases the material may be
suitable for land fill with revegetation. Although there is- already a
lot of background on this subject, specific information is needed on each
coal and for each specific location in order to allow thorough planning
to be sure that the disposal will be environmentally* sound.
Coal drying is used on most coal conversion processes; con-
sequently, considerable effort is warranted to optimize the operation
from the standpoints of fuel consumption, dust recovery, and volume of
vent gas to be handled. It will often be attractive to burn high sulfur
coal rather than clean gas fuel for inplant use, and to include facilities
for cleaning up the vent gas.
The need for a simple, efficienct means of feeding coal to the
high pressure gasifier has been apparent and has received considerable
study. For pressure levels of 300-500 psig, lock hoppers have been used
satisfactorily although they are expensive.
One potential improvement would be to develop a way to efficiently
remove dust from gas at high temperature. An important advantage is that
particulates are then kept out of the sour water stream, and consequently
it is easier to clean up. Sand bed filters are promising for dust removal
from hot gases although they have not been fully demonstrated commercially.
In the area of acid gas removal, conventional systems based on
amine or hot carbonate leave room for improvement. Amine scrubbing is
not effective on carbonyl sulfide, while contaminants such as cyanide
interfere with regeneration of the scrubbing liquid. Hot carbonate systems
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- 29 -
partially remove carbonyl sulfide, but it is often difficult to provide a
highly -concentrated stream of H2S to send to the sulfur plant.
Adsorption/oxidation systems are often not effective on carbonyl sulfide.,
and its presence may require increase liquid circulation. The Selexol process
is used in the U-Gas case. The design indicates a reasonably high H2S con-
centration in the stream to the Glaus plant, although steam requirement
and pumping rates for the operation are sizeable.
Available systems for acid gas removal have high utility
requirements, causing a significant loss in thermal efficiency for con-
version of coal to clean fuel products. In addition there is often a
waste stream of chemical scrubbing medium which may be difficult and
expensive to dispose of.
Desirable objectives for an acid gas removal process can be
summarized as follows: (a) good clean up of all forms of sulfur to
give a stream high in sulfur concentration for processing in a Glaus
sulfur plant, (b) low utility and energy consumption, (c) no waste
streams that present a disposal problem.
The need for a process to remove sulfur at high temperature
was mentioned earlier. Systems based on half calcined dolomite or iron appear
promising; however, they may give less complete sulfur removal than conven-
tional scrubbing systems and do not remove ammonia or other nitrogen compounds.
If filtering techniques could be incorporated to remove particulates at the
same time that sulfur is removed, such systems could be quite attractive.
A further need is to destroy or remove undesirable contaminants such as
carbonyl sulfide, cyanides, and possibly phenol and ammonia. This function
might also be provided by a high temperature gas cleanup system.
The need for a simple, effective method to clean up sour water
for reuse is another item that is commonfJto most fossil fuel conversion
operations. Sour water generally contains sulfur compounds, ammonia, H2S,
phenol, thicyanates, cyanides, traces of oil, etc. These are generally
present in too high a concentration to allow going directly to biological
oxidation, but their concentration is often too low to make recovery
attractive. Particulates, if present, further complicate the processing
of sour water. Usual techniques for clean up include sour water stripping
to remove H2S and ammonia, and in addition, extraction may be required
to remove phenols and similar compounds. Such operations are large con-
sumers of utilities and have a large effect on overall thermal efficiency.
One possible approach is to vaporize sour water to make steam
which can be used in the gasifier. In this case, compounds such as
phenol should be destroyed and reach equilibrium concentration in the
circulating sour water. It may not be practical to vaporize sour water
in conventional equipment such as exchangers, due to severe fouling and
corrosion problems. Therefore, new techniques may be required, and one
possibility would be to vaporize the sour water by injecting it into a
hot bed of fluidized solids.
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- 30 -
In a large scale application there will be a water effluent
from the plant,, therefore, detailed study of the facilities for clean up
will be needed. In any event, the water make-up that is brought to the plant
will contain dissolved solids including sodium and calcium salts. Calcium
l)
salts may be precipitated during the water treating operation to form a
sludge which can be disposed of with the other waste solids, but the
fate of the sodium salts in the make-up water calls for further study.
These will leave with the blowdown from the cooling tower. If the con-
centration of dissolved solids is too high in this blowdown water to allow
discharging it to the river, then some suitable method of disposal will
have to be worked out. On one proposed commercial plant, this has been
handled by using an evaporation pond where the water is evaporated to
dryness. The salts accumulate and will ultimately have to be disposed of.
If they cannot be used or sold then it would seem logical to dispose of
them in the ocean.
On trace elements information is needed on the amount vaporized
in the gasifies?, what happens to them, where they separate out and in
what form, so that techniques can be worked out for recovering or disposing
of the materials. Again specific information is needed for each coal and
for each coal conversion process since operating conditions differ. In
many cases, the trace elements may tend to recycle within the system and
build up in concentration. This offers an interesting opportunity to
perhaps recover some of them as useful by-products. The toxic nature of
many of the volatile elements should be given careful consideration from
the standpoint of emissions to the environment, as well as protection of
personnel during operation and maintenance of the plant. Carcinogenicity
of coal tar and other compounds present in trace amounts or formed during
start up or upsets must also be evaluated.
Protection of personnel, especially during maintenance operations
should be given careful attention, which will require that additional
information be obtained. Thus, toxic elements that vaporize in the gasifier
may condense in equipment such as piping and exchangers where they could
create hazards during cleaning operations.
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10. PROCESS DETAILS
Additional details on the process and information on potential
problems are given in Tables 7 through 13.
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- 32 -
TABLE 7
STREAM COMPOSITIONS
, U-GAS PROCESS
(See Figure 1 for identification)
Pretreater
Ib mol/hr Offgas
CO 735
C02 2,011
H2
H20 5,806
PTJ 11C
Ui^ 115
N2 16,311
H2S
COS
S02 176
C2H6 63
Tar 8
Raw Gas
18,595
9,609
12,686
13,148
4,516
50,246
750
24
—
—
—
Gas to
Selexol
18,593
9,601
•12,681
328
4,514
50,246
748
24
—
—
—
Selexol
Effluent
18,593
6,198
12,681
—
4,513
50,246
5
12
—
—
—
H2S to
Glaus
—
3,403
—
328
1
—
743
12
—
—
—
25,225 109,574 96,735 92,248 4,487
Note: Value reported for COS is based on calculation in absence of data -
data for some other processes show much higher proportion of sulfur
in form of COS, for example, 10% of the total sulfur in the gas may
be as COS. Amount of ammonia in raw gas is unknown but some processes
show 60-70% of the nitrogen in coal appears as ammonia in the raw
gas.
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TABLE 8
STEAM BALANCE, U-GAS PROCESS
Ib/hr
High Pressure Steam, 600 psig
From waste heat on pretreater and raw gas9
preheated to 800°F. Used in gasifier . 338,000
From waste heat on pretreater, raw gas, and
intercooler on air compressor, preheated to
900°F. Used to supply 108,000 shaft HP on
air compressor 646,000
Low Pressure Steam, 125 psig and 15 psig.
From waste heat on cooling raw gas. Used
in Selexol unit and sour water stripper 516,000
Ash Quenching
Steam from quenching ash - returned to
gasifier. . 34,000
Sulfur Plant
By product steam from waste heat recovery.
Used to supply utility requirements of
Glaus plant and tail gas cleanup 50,000
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TABLE 9
ELECTRIC POWER CONSUMED, U-GAS PROCESS
TABLE 10
WATER BALANCE. U-GAS PROCESS
KW
Coal preparation and handling 4,000
Cooling water pumps 1,500
Cooling tower fans 1,000
Air cooler fans 500
Other plant uses 3,000
10,000
Net consumed in gasifier 202
In wet ash to mine 26
Evaporated in cooling tower 1,448
Waste water discharged from plant 334
In H2S stream to Claus plant 12
Losses on steam and condensate 100
Total water makeup required 2,122
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TABLE 11
MAKE UP CHEMICALS AND CATALYST REQUIREMENTS
Chemicals
Acid Gas Removal;
- scrubbing solution
- additives
Sulfur Plant tail gas cleanup
Cooling Tower Additives
Anticorrosion, e.g., chromate
Antifouling, e.g., chlorine
Water Treating
Lime
Alum
Caustic
Sulfuric acid
Catalysts, etc.
Sulfur plant catalyst
Ion exchange resin for water treating
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TABLE 12
POTENTIAL ODOR EMISSIONS
Coal storage and handling.
Coal drying - vent gas.
Vent gas from lock hoppers.
Wet ash handling and disposal.
Sour water stripping and handling,
Sulfur plant and tail gas.
Biox pond and other ponds.
Leaks: ammonia, H2S, phenols, etc
TABLE 13
POTENTIAL NOISE PROBLEMS
Coal handling and conveyors.
Coal crushing, drying and grinding,
Air compressor.
In utilities area:
Burners on furnaces.
Stacks emitting flue gases.,
Turbo-generator etc.
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11. QUALIFICATIONS
As pointed out, this study does not consider costs or economics.
Also, areas such as coal mining and general offsites are excluded, as well
as miscellaneous small utility consumers such as instruments, lighting
etc. These will be similar and common to all coal conversion operations.
The study is based on the specific process design and coal type
cited, with modifications as discussed. Plant location is an important
item of the basis and is not always specified in detail. It will affect
items such as the air and water conditions available, and the type of
pollution control needed. For example, this U-Gas study uses high sulfur
Pittsburgh seam coal. Because of variations in coal feed, moisture content,
and other basic items, great caution is needed in making comparisons
between coal gasification processes as they may not be on a completely
comparable basis.
The design for this study did not include coal cleaning and
washing, which therefore must be provided elsewhere, together with
associated energy and water requirements. Related environmental
impacts must be included to give a complete overall assessment.
Other gasification processes may make large amounts of various
by-products such as tar, naphtha, phenols, and ammonia. The disposition
and value of these must be taken into account relative to the increased
coal consumption that results and the corresponding improvement in overall
thermal efficiency. Such variability further increases the difficulty of
making meaningful comparisons between processes.
The U-Gas process as described in publications makes no appreciable
amounts of tar, naphtha, or phenols; although there is a small yield of
ammonia, amounting to about 2 tons/day which might be disposed of by incinera-
tion. It is possible, at least under some conditions such as startup or
plant upsets that ammonia yield might be very much higher, and that some
tar, oil, and/or soot may be formed in the gasification system. These
would complicate the gas cleanup facilities and require provision for
disposal, therefore such possibilities should be evaluated thoroughly in
process development and in planning commercial applications. Provision
will definitely be needed for separating trace elements and disposing
of them in a satisfactory manner, especially the portions volatilized
in gasification, but additional information is needed in order to define
the problem and to develop suitable control systems.
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12. BIBLIOGRAPHY
1. Magee, E. M., et. al., "Evaluation of Pollution Control in Fossil
Fuel Conversion Processes, Gasification; Section 1: Koppers-Totzek
Process," Report No. EPA-650/2-74-009a, January 1974.
2. Kalfadelis, C. D., et. al., "Evaluation of Pollution Control in
Fossil Fuel Conversion Processes, Gasification; Section 2:
Synthane Process," Report No. EPA-650/2-74-009b, June 1974.
3. Shaw, H., et. al., "Evaluation of Pollution Control in Fossil Fuel
Conversion Processes, Gasification; Section 3: Lurgi Process,"
Report No. EPA-650/2-74-009c, July 1974.
4. Jahnig, C. E., et. al., "Evaluation of Pollution Control in Fossil
Fuel Conversion Processes, Gasification; Section 4: C02 Acceptor
Process," Report No. EPA-650/2-74-009d, December 1974.
5. Jahnig, C. E., et. al., "Evaluation of Pollution Control in
Fossil Fuel Conversion Processes, Gasification; Section 5: BI-GAS
Process," Report No. EPA-650/2-74-009g, May 1975.
6. Jahnig, C. E., et. al., "Evaluation of Pollution Control in Fossil
Fuel Conversion Processes, Gasification; Section 6: HYGAS Process,"
Report No. EPA-650/2-74-009h, July 1975.
7. .Bodle, W. W., et. al., "Clean Fuels from Coal," Oil Gas J. August
26, 1974, p. 85.
8. Loeding, J. W., et. al., "The U-Gas Process," Chemical Engineering
Progress 71, 4:85-86 (1975).
9. Loeding, J. W., et. al., "IGT U-Gas Process," Clean Fuels from Coal
Symposium at the Institute of Gas Technology, Chicago Sept. 10-14, 1973
10. Glaser, F., et. al., "Emissions from Processes Producing Clean Fuels,"
for Environmental Protection Agency. Report BA9075-015 Section XIV
(March 1974). .
11. Goldberger, W. M., "The Union Carbide Coal Gasification Process,"
4th Synthetic Pipeline Gas Symposium, Chicago, Oct. 30-31, 1972.
12. "Profit in Processing Foul Water," Oil and Gas J., June 17, 1968,
p. 96 (see also US Patents 3,518,056 and 3,518,166).
13. "Selexol Process," Hydrocarbon Processing, April 1973 p. 100.
14. Bureau of Mines, "Removal of Hydrogen Sulfide from Hot Producer
Gas by Solid Adsorbents," RI 7947 (1974).
15. Princiotta, F. T., "Status of Flue Gas Desulfurization Technology,"
EPA Symposium on Environmental Aspects of Fuel Conversion Technology,
St. Louis, Mo., May 13-16, 1964. Report EPA 650/2-74-118.
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- 39 -
16. Lee, R. E., et. al., "Trace Metal Pollution in the Environment,"
of Air Poll. Control, 23, (10), October 1973.
17. Schultz, H., Hattman, E. A., Booker, W. B., ACS Div. of Fuel.
Chem., Vol. 8, No. 4, p. 108, August 1973.
18. Billings, C. E., Sacco, A.M., Matson, W. R., Griffin, R. M.,
Coniglio, W. R., and Harley, R. A., "Mercury Balance on a Large
Pulverized Coal-Fired Furnace," J. Air Poll. Cont. Association,
Vol. 23, No. 9, September 1973, p. 773.
19. Schultz, Hyman et. al., "The Fate of Some Trace Elements During
Coal Pre-Treatment and Combustion," ACS Div. Fuel Chem. ^, (4),
p. 108, August 1973. ~
20. Bolton, N. E., et. al., "Trace Element Mass Balance Around a
Coal-Fired Stream Plant," NCS Div. Fuel Chem., _1£, (4), p. 114,
August 1973.
21. Magee, E. M., Hall, H. J., and Varga, G. M., Jr., "Potential
Pollutants in Fossil Fuels," EPA-R2-73-249, June, 1973.
22. Trace Elements and Potential Toxic Effects in Fossil Fuels
Hall, H. J., EPA Symposium, "Environmental Aspects of Fuel
Conversion Technology," St. Louis, MO., May 1974.
23. Ruch, R. R. et. al., "Occurence and Distribution of Potentially
Volatile Trace Elements in Coal," EPA 650/2-74-054, July 1974.
24. Attari, A., "The Fate of Trace Constituents of Coal During
Gasification," EPA Report 650/2-73-004, August 1973.
25. Attari, A. et. al., "Fate of Trace Constituents of Coal During
Gasification (Part II)" presented at ACS Meeting, Philadelphia,
Pa., April 6-11, 1975 (Division of Fuel Chemistry).
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TECHNICAL REPORT DATA
(Please read Jaslructions on the reverse before completing)
1. REPORT NO. .
EPA-650/2-74-009-1
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE EvaiUation of Pollution Control in
Fossil Fuel Conversion Processes; Gasification:
Section 7. U-Gas Process
5. REPORT DATE
September 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C.E. Jahnig
8. PERFORMING ORGANIZATION REPORT NO.
Exxon/GRU.12DJ.75
9. PERFORMING OR9ANIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
P.O. Box 8
Linden, NJ 07036
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-023
11. CONTRACT/GRANT NO.
68-02-0629
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT The repOr{. gives results of B. review of the U-Gas Process being developed
by the Institute of Gas Technology, from the standpoint of its effect on the environ-
ment. The quantities of solid, liquid, and gaseous effluents have been estimated,
where possible, as well as the thermal efficiency of the process. For the purpose of
reducing environmental impact, a number of possible alternatives are discussed,
and technology needs are pointed out.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Coal Gasification
Fossil Fuels
Thermal Efficiency
Air Pollution Control
Stationary Sources
U-Gas Process
Clean Fuels
Fuel Gas
Research Needs
13B
13H
21D
20M
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
46
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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